-------
3.2.2.2.2 Fuel quality. Samples of bagasse taken at different
localities show almost identical analyses on a dry, ash free basis.
However, the type of cane and harvesting and processing methods can affect
the ash content, moisture content, and fuel particle size.
The harvesting and processing methods for sugar cane are affected by
geographic location. For example, in Florida approximately 70 percent of
83
the sugar cane is cut by hand and the remainder is harvested by machines.
84
In Hawaii all the sugar cane is machine harvested. Machine harvesting
increases the amount of dirt and trash mixed in with the cane. Because of
this, all Hawaiian sugar mills have cane precleaning plants to remove the
132
soil and trash from the cane. This will also reduce the soil and trash
remaining in the bagasse after the cane is processed. Some Hawaiian mills
also use bagasse dryers to reduce the moisture content of the bagasse and
133
additional bagasse dryers are planned in the future.
Differences in harvesting, processing, and cane variety cause the
bagasse moisture content at different sites to vary from 47 to 57 percent
(wet basis). The lower bagasse moisture contents are generally found in
Hawaii.134
Generally lower ash contents and moisture contents and larger fuel
particle sizes tend to decrease PM emissions due to the same factors
discussed previously for wood. Lower ash and moisture contents result in
lower undergrate air and fuel feed rate requirements while larger fuel
particle sizes are less easily entrained in the flue gas.
3.2.2.2.3 Boiler operation. Boiler operating procedures can influence
uncontrolled emissions from bagasse-fired boilers. First, like other
waste-fired boilers, bagasse boilers may use auxiliary fuels for startup.
Because fuel oil is usually the startup fuel, the initial S02 and NOX
emissions are higher than when bagasse alone is fired. The duration of
startup is up to 8 hours. During this time PM emissions may increase due to
poor combustion conditions in the boiler while it is cold. In most areas
bagasse boilers are started up once at the start of the harvest season and
are not shut down unless it is absolutely necessary. The length of the
3-34
-------
harvesting season is also affected by geographic location and ranges from
3 months (Louisiana) to 10 months (Hawaii).
In Hawaii, the boilers are operated differently in that they are shut
down on weekends unless they are cogenerating electricity for the local
utility. Cogenerating boilers must operate continuously for 11 months of
1 ^R
the year. Also, bagasse-fired boilers in Hawaii are generally more
efficient than in other areas due to generally lower fuel moisture contents,
larger boiler sizes, and the placement of the stoker feed system higher
84
above the grate to increase suspension burning.
Second, most bagasse boilers may cofire an auxiliary fuel (normally
fuel oil or natural gas) at times to produce the total energy needed for the
facility or to sustain good combustion with wet bagasse. As is the case
during startup, combined oil and bagasse firing will increase S09 and NO
£ X
emissions. Auxiliary fuel is used whenever additional heat input is
required. If the supply of bagasse to the boiler is interrupted auxiliary
fuel will be used to provide up to 100 percent of the heat input of the
boiler. During these periods the S09 and NO emissions will increase.
£~ A
Facilities burning bagasse attempt to keep auxiliary fuel use to a minimum.
Typically less than 15 percent of the total annual fuel heat input into the
pr
boiler comes from fossil fuels. Bagasse-fired boilers in Hawaii which
cogenerate electricity will generally fire the largest amounts of fossil
84
fuels because they are operated outside of the harvest season.
Third, the peak combustion temperature influences NO emissions. Since
3\
bagasse boilers are similar in design and operation to wood-fired boilers,
the furnace temperature would,be expected to be similar also. Based on
emission test data, total NOV formation is about 86 ng/J (0.2 lb/106 Btu)
oe
unless auxiliary fuel is being burned.
Other operational factors, such as excess air, should affect bagasse
boilers in the same manner as wood-fired boilers based on the similarity of
fuel and boiler design.
3-35
-------
3.2.3 General Solid Waste-Fired Boilers
This section discusses MSW-, ISW- and RDF-fired boilers. Each
subsection describes the common boiler types, fuel burned, and operational
procedures which affect uncontrolled emissions.
3.2.3.1 Municipal Solid Waste-Fired Boilers. As previously mentioned
in Section 3.1, MSW-fired boilers can be separated into two categories based
on the boiler's heat input capacity. These categories are small modular
units and large mass burning facilities.
3.2.3.1.1 Facility Description
3.2.3.1.1.1 Large "Mass Burn" MSW Facilities. Large MSW-fired boilers
have been used in Europe since World War II, and over one hundred are
currently operating there. However, this method of MSW disposal if
relatively new to the United States and most of the existing facilities have
ft?
been built since 1970. A typical large MSW-burning facility is shown in
Figure 3-8. This figure also presents material and energy balances for the
boiler facility, based on combustion and mass balance calculations.
Combustion of MSW is generally accomplished in "mass burn" firing
installations similar to that shown in Figure 3-8. This term refers to the
minimal fuel preparation prior to firing. These installations are typically
waterwall furnaces, which employ overfeed stokers. Traveling or recipro-
cating grates move the solid waste through the furnace and cause a tumbling
action on the waste which results in more rapid ignition and better burnout.
In a typical large facility burning MSW, the waste is dumped from
garbage trucks or compacted transport trucks into a large pit. An overhead
crane is then used to load the waste from the pit to the feed chute. Fuel
preparation consists of only limited mixing of the waste by the crane
operator and removal of bulky items, such as telephone poles and box
springs. The feed chute deposits solid waste on the first, or "dry-out",
grate. Ignition starts at the bottom of the dry-out grate and is concen-
trated on the second, or "combustion" grate. The third grate, a "burn-out"
grate, provides final combustion of the waste before the ash falls into the
89
flooded ash pit.
3-36
-------
C*>
MSW Fuel
Mass Input
14,000 kg/hr
(30,800 Ib/hr)
MSW Fuel
Heat Input
44 MW,
Combustion Air
98,000 kg/hr
(216,000 Ib/hr)
Steam Output
30.8 MW
(105 x 10° Btu/hr)
(150 x 10Btu/hr)
Ash Removal System
Flue Gas
109,000 kg/hr
(240,000 Ib/hr)
PM: 229 kg/hr
(504 Ib/hr)
S09: 33.5 kg/hr
z (73.8 Ib/hr)
NOV: 21.0 kg/hr
* (46.2 Ib/hr)
Radiative, Convective
and Stack Losses
13,2 MW
(45 x 10° Btu/hr)
Bottom Ash
3,490 kg/hr
7,690 Ib/hr
Mass Flow Stream
Energy Flow Stream —
Figure 3-8. Energy and Material Balances for a Representative
Large MSW-Fired Boiler88
-------
The furnace operator controls the relative speeds of the three grates
so that most of the combustion takes place on the second grate. These
speeds are dependent upon both the waste combustion characteristics and
moisture content. Ferrous metals are magnetically removed from the ash and
sold, and the residue is landfilled.
The large MSW-fired boiler in Figure 3-8 combusts 14,000 kg/hr
(30,800 Ib/hr) of solid waste. The received and ultimate analyses of the
representative MSW used in these material and energy balances are shown in
Table 3-10. The available heating value of MSW is typically around
91
10,470 kJ/kg (4,500 Btu/lb). However, since the average heating value is
expected to increase in the future, as discussed in Section 3.1.2.3, a waste
composition with a heating value of 11,340 kJ/kg (4,875 Btu/lb) from a
92
performance test at a currently operating facility was used. This
analysis of this waste compares closely with reported "typical"
93
compositions. The basi's and assumptions used to calculate the energy and
material balances are shown in Table 3-11. Excess air for this facility is
100 percent.
An energy balance for the facility is also shown in Figure 3-8. The
overall thermal efficiency of this boiler is 70 percent, which is typical
for large MSW-firing operations. ' Total heat loss is shown as loss out
the stack and is 13.2 MW (45 x 10 Btu/hr), including heat transfer through
equipment walls and heat loss in the flue gas.
The flue gas flow rate is 109,000 kg/hr (240,000 Ib/hr), including
229 kg/hr (504 Ib/hr) of PM. Uncontrolled emissions from this typical large
MSW boiler and a small controlled air MSW boiler are presented in
Table 3-12. Two size distributions of uncontrolled PM emissions for large
MSW boilers are shown in Figure 3-9.
3.2.3.1.1.2 Small Modular Incinerators (SMI) With Heat Recovery.
Combustion of MSW in small modular boilers was introduced in the late
1960's. These units are shop fabricated on a package basis and are
typically hopper and ram-fed instead of crane-fed as is the MSW boiler shown
in Figure 3-8. To provide ease of expansion in burning capacity for
small towns and industries, the modular boiler system is designed to allow
3-38
-------
TABLE 3-10. MUNICIPAL SOLID WASTE ANALYSIS SELECTED
FOR REPRESENTATIVE BOILERS90
Material
Carbon
Hydrogen
Oxygen
Ni trogen
Sulfur
Chlorine
Water
Ash
Total
Percentage
(Dry basis)
36.69
4.94
27.09
0.23
0.16
0.18
-
30.72
100.00
Percentage
(As fired)
26.73
3.60
19.74
0.17
0.12
0.13
27.14
22.38
100.00
Higher Heating Value
kJ/kg (Btu/lb) '/ 15,560(6,690) 11,340(4,875)
3-39
-------
TABLE 3-11. BASES AND ASSUMPTIONS FOR LARGE MSW-FIRED BOILERS94
Basis/Assumption Value Used
Bottom Ash 25% of fuel feed rate (mass basis)
Excess Air 100%
Boiler Efficiency 70%
Uncontrolled PM Emissions3 1.6 gr/dscf corrected to 12% C02
Uncontrolled S02 Emissions3 100% conversion of sulfur in fuel
Uncontrolled NO Emissions3 3 Ib NO /ton fuel burned
rt A
aThe PM emission rate was based on test data from a few operating
facilities. Complete conversion of fuel sulfur to SOg was assumed
so as to provide an estimate of the maximum S02 emission rate. S02
emissions are fairly low, in any case, due to the low fuel sulfur
content. The NO emission rate was based on an AP-42 emission
factor. More details about all of the bases in this table are
provided in Reference 94.
3-40
-------
TABLE 3-12. UNCONTROLLED EMISSIONS FROM REPRESENTATIVE MSW-FIRED BOILERS97
V
Boiler
Type
Modular
Controlled
Air
Overfeed
Stoker
"Mass-burn"
Capacity
(thermal input)
2.9 MW
(10x10° Btu/fir)
44 MW
(150x10° Btu/hr)
Pollutant
PM
so2
NOX
PM
S02
NOX
Mass
kg/hr (Ib/hr)
1.36 (3.0)
2.23 (4.92)
1.40 (3.08)
229 (504)
33.5 (73.8)
21.0 (46.2)
Emi ssi ons
Concentration9
ng/Nm3 (gr/dscf)
3.25 (1.42)
201 b
175b
3.66 (1.60)
201 h
175b
Heat Input
ng/J (lb/106 Btu)
129 (0.300)
211 (0.492)
132 (0.308)
1440 (3.36)
211 (0.492)
132 (0.308)
*At 12% C02.
D6aseous concentrations are in ppm.
-------
V
INJ
to
c
o
J-
o
OJ
N
CJ
4J
i-
IQ
Q.
O
•r-
ro
o
s_
o
•a:
95 90 BO 70 Hi 'in 40 311 70
0.01 0.05 01 0.2 0.5 I Z S 10 20 30 40 50 60 10 00 9O 95 96 99 99.8 99.9
Cumulative percent less than
Figure 3-9. Particle size distribution of uncontrolled PM emissions
from two large MSW-fired boilers.*°'™
-------
installation of additional units in modules as refuse generation
102
increases. These units typically have heat input capacities of 11.1 MW
(38 x 106 Btu/hr) or less.
A typical small modular incinerator is shown in Figure 3-10. The
boiler shown in this figure consists of an incinerator with a primary and
secondary combustion chamber. Units of this type are commonly referred to
as "control!ed-air" or "starved-air" boilers because the air in the primary
combustion chamber is below stoichiometric levels to minimize ash and fuel
entrainment. Energy and material balances for this boiler are also shown in
Figure 3-10 and are based on empirical data from performance tests. The
bases and assumptions used for these calculations are shown in Table 3-13.
Small modular incinerators like that shown in Figure 3-10 typically
combust refuse at around 820°C (1500°F) in the primary chamber and at 1000°C
(1900°F) in the secondary chamber. The auxiliary burner shown in
Figure 3-10 is an integral part of the controlled air boiler and is used
whenever the secondary chamber temperature is below the set point. A
plot of the size distribution for uncontrolled PM (fly ash) from three
controlled air boilers is shown in Figure 3-11.
3.2.3.1.2 Factors Influencing Uncontrolled Emissions. The factors
that influence uncontrolled emissions from wood-fired boilers also influence
the uncontrolled emissions from boilers burning MSW. Those factors are
boiler type, fuel quality, and boiler operation.
3.2.3.1.2.1 Boiler type. Two types of boilers are currently used to
combust MSW. The most common type is the mass burning stoker boiler shown
in Figure 3-8. Boilers that mass burn are capable of burning solid waste
*
fuels with large size variations. Because of this capability, normally the
only fuel preparation is removal or sizing of large bulky items (such as
furniture, etc.).
The other common boiler is the small modular boiler with muHi chamber
controlled-air combustion, which is also designed to burn the waste without
extensive fuel preparation. The small modular boiler has lower uncontrolled
PM emissions. This results from the low air feed rate to the primary
3-43
-------
Radiative, Convective,
and Stack Losses
1.3 MW
(4.5 x 10° Btu/hr)
Heat Recovery
Stack
By-pass Stack
Damper Control
Uncontrolled Emissions
Flue gas
7260 kg/hr PM: 1.4 kg/hr
( 16,000 Ib/hr) (3.0 Ibs/hr)
NO : 1.4 kg/hr
(3.1 Ibs/hr)
SO,: 2.2 kg/hr
" (4.9 Ibs/hr)
Steam Output
1.6 MW
(5.5 x 10° Btu/hr)
By-pass Stack
— Damper
Mass Flow Stream
Energy Flow Stream
Combustion Air
6,530 kg/hr
(14,400 Ibs/hr)
MSW Fuel
Mass Input
930 kg/hr
(2,050 Ibs/hr)
MSW Fuel
Heat Input
2.9 MW
10 x 10° Btu/hr)
SECONDARY
COMBUSTION
CHAMBER
PRIMARY
COMBUSTION
CHAMBER
Bottom
Ash
279 kg/hr
(615 Ib/hr)
Figure 3-10.
Energy and Material Balances for ^Represent! ve
controlled air MSW-Fired Boiler.
3-44
-------
TABLE 3-13. BASES AND ASSUMPTIONS FOR SMALL CONTROLLED AIR
MSW-FIRED BOILERS10^
Basis/Assumption Value Used
Bottom Ash 30% of fuel feed rate (mass basis)
Excess Air 100%
Boiler Efficiency 55%
Uncontrolled PM Emissions3 0.3 lb/106 Btu
Uncontrolled SOg Emissions3 100% conversion of sulfur in fuel
Uncontrolled NO Emissions3 3 Ib NO/ton fuel burned
A X
3The PM emission rate was based on a survey report of industry emission
tests. Complete conversion of fuel sulfur to S0? was assumed so as to
provide an estimate of the maximum S0« emission rate. S0? emissions
are fairly low, in any case, due to tne low fuel sulfur content. NO
emissions were based on an AP-42 emission factor. More details about
all of the basis in this table are provided in Reference 104.
3-45
-------
99.99 99.9 99.8
99 98
001
co
•p*
cri
to
c
o
o
>
T3
0.01 005 0.1 0.2 0.5 I 2
10
20 30 40 50 60 70 80 90 95 9899
Cumulative percent less than
*».» 99.9 99.99
Figure 3-11. Particle size distribution of uncontrolled PM
emissions from three small controlled air MSW-fired boilers. '
-------
combustion chamber causing reduced entrainment of ash and unburned
combustibles.
3.2.3.1.2.2 Fuel quality. Two factors related to fuel quality
influence uncontrolled emissions from MSW-fired boilers. First, there are
significant variations in the composition of MSW. For example, MSW
composition is dependent on the net waste contribution of business offices,
housefolds, and industrial waste producers. Seasonal variations are also
common in the composition of MSW. For instance, yard waste in MSW ranges
from 0.3 percent in winter to 23 percent in summer in the Northern
108
states. This seasonal variation in composition results in variations in
ash content and heating value of the fuel. Lower heating values and higher
ash contents will both increase emissions.
Cofiring of other fuels with MSW is the second fuel-related influence
on uncontrolled emission levels from MSW boilers. In situations in which
auxiliary fuels such as natural gas or fuel oil are required to augment the
MSW input, NO emissions may increase because of increased flame tempera-
/\
tures and S09 emissions may increase if the fossil fuel has a higher sulfur
109
content. PM emissions should decrease based on the lower PM emission
rate for oil or natural gas. Presently operating large MSW-fired boilers do
not normally fire fossil fuels unless required to produce steam when the
stoker system is inoperative.
3.2.3.1.2.3 Boiler operation. Three operations that influence
uncontrolled emissions from the combustion of MSW are startup, excess air
adjustments and the boiler's operating temperature. Startup of large
MSW-fired boilers is usually accomplished by igniting the GSW directly.
although in at least one fac'ility oil is used prior to startup to preheat
the PM emission control equipment. Startup for this facility is two hours
in duration. The small modular units are started by igniting the MSW in
the primary chamber with fuel oil or gas. Once combustion is started these
burners are turned off. The auxiliary burner in the second chamber is used
until the temperature reaches the set point (about 815°C). The entire
process takes 10 to 30 minutes in the primary chamber and up to one hour in
the secondary chamber. During this time, uncontrolled emissions will be
3-47
-------
affected as discussed previously for cofiring with fossil fuels. Increasing
combustion air flow above design levels can increase PM emissions by
increasing the amount of fuel entrained and carried out of the furnace area
before combustion is complete.
The third operation that influences uncontrolled emissions of NO from
A
MSW-fired boilers is the boiler's peak design combustion temperature.
MSW-fired boilers are typically designed for a peak combustion temperature
110
of 980°C (1800°F). * Because of the low temperature and the fuel's low
nitrogen content, N() emissions are low, with a level of about 130 nq/J
c 11 X
(0.30 lb/10° Btu).J
3.2.3.2 Industrial Solid Haste-Fired Boilers. ISW is presently burned
in the same type of small controlled air boilers used to burn MSW which were
described previously. The heat input capacities of these boilers ranges up
to 17.6 MW (60 x 106 Btu/hr) when firing ISW. ISW could also be burned in
the large mass burn facilities described previously. However, this has not
been done except when the ISW is collected as part of municipal solid waste.
Table 3-14 whose a representative analysis of ISW. As shown in this
table the average heating value for ISW is higher than MSW, and the ash
content is less. Based on this analysis PM emissions from ISW should be
less than those from MSW burned in the same type of boiler under similar
conditions.
3.2.3.3 Refuse Derived Fuel-Fired Boilers. As previously mentioned,
RDF can be cofired with coal or burned alone. Its heating value is
approximately 1.2 times the heating value of MSW, or 13,500 kJ/kg
(5,790 Btu/lb), due to the lower percentages of water and ash in the fuel.
Mixtures of from 0 to 100 percent RDF (heat input basis) have been tested in
coal fired spreader stoker boilers and mixtures of up to 27 percent in
suspension firing (pulverized coal) units, though usual operation in the
suspension unit is 20 percent RDF or less. To date, RDF has mostly been
fired as a substitute for a portion of the coal in coal-fired boilers. But
there are presently three facilities burning RDF alone in stoker fired
units.
3-48
-------
TABLE 3-14. REPRESENTATIVE ANALYSIS OF INDUSTRIAL SOLID WASTE
114
CO
£
CORRUGATED BOARD AND MISC. PAPER
HARDWOOD (Crates, Pallets, etc.)
TEXTILES
PLASTICS (Film and Rigid) '
METALS
MISCELLANEOUS RUBBER
FOOD WASTES
SWEEPINGS
COMPOSITE WEIGHTED ANALYSISb
CALORIFIC VALUE (HHV) ADJUSTED TO
Weigh
Perce
52
28
5
4
3
2
1
5
REFLECT
ta
nt Moisture
8
" ^12
10
1
2
2
50
25
10
COMPOSITE (10%)
Volatile
Matter
75
67
80
95
-
83
20
54
70
MOISTURE =
Sulfur
0.2
0.1
0.2
0.1
0.1
2.0
0.5
0.2
0.2
16,540
Inerts
5.0
3.0
3.0
1.5
95.0
15.0
5.0
20.0
8.0
kJ/kg (7,
HHV
kJ/kg
17,710
19,340
18,640
34,000
280
26,330
19,570
13,980
18,170
- dry
Btu/lb
7,600
8,300
8,000
14,600
120
11,300
8,400
6,000
7,800
100 Btu/lb).
aThe glass constituent in general plant waste is expected to be less than 1%.
The solid waste constituent mix and their discrete characteristics will vary from plant to plant
in the same industry and probably even within the same company.
-------
3.2.3.3.1 Facility Description. A representative RDF/coal cofired
boiler is shown in Figure 3-12 along with material and energy balances.
This boiler is a field-erected, watertube, spreader stoker unit rated at
44 MW (150 x 10 Btu/hr) of heat input. The bases and assumptions used in
the calculations of these balances are presented in Table 3-15. The
ultimate analyses of the fuel inputs are shown in Table 3-16. Uncontrolled
PM emissions for this boiler were calculated based on the emission factors
for 100 percent HSE coal firing, since the available test data did not show
a significant difference in PM emissions for coal/RDF-firing as compared to
coal alone. These emissions are compared with the emissions from a
coal-fired boiler in Table 3-17. A size distribution curve for uncontrolled
PM emissions from a boiler cofiring RDF and coal is presented in
Figure 3-13.
3.2.3.2 Factors Influencing Uncontrolled Emissions. The same three
factors influence uncontrolled emissions from boilers cofiring coal and RDF
as those burning GSW: boiler type, fuel quality, and boiler operation.
3.2.3.2.1 Boiler type. Since most coal-fired boilers can potentially
cofire RDF, the effect of boiler type on uncontrolled emissions should be
similar for boilers firing either fuel. For example, suspension fired
(pulverized coal) units cofiring RDF and coal would be expected to yield
higher emissions than spreader stoker boilers as they do when firing coal
alone.121
3.2.3.2.2 Fuel quality. RDF has a relatively uniform fuel quality.
The only major variations result from the type of RDF produced. The major
RDF fuel types are:
- Fluff from a wet pulping process,
- Fluff from dry processing-size reduction and air classification,
- Screened fluff from dry processing-size reduction, air
classification, and screening,
- d-RDF (densified RDF)-pelletization of fluff or screened fluff,
and
- Powdered RDF-proprietary commercial process, fuel characterized as
122
a fine dustlike material.
3-50
-------
Hue Gas
84,200 kg/hr
(185,700 Ib/hr)
PM:
396 (873)
214 (472)
S09: __. . .
NOJ;: 38.6 (85.0)
Radiative, Convectlve
and Stack Losses
10,6 MW
(36 x 10° Btu/hr)
STEAM OUTLET
FLY ASH
RETURN\
Steam Output
33.4 MW
(114 x 10° Btu/hr)
Fuel Mass Input
2,880 kg/hr(6,360 Ib/hr) HSE Coal
5,880 kg/hr(13,000 Ib/hr) RDF
Fuel Heat Input
44,MW
(150 x 10° Btu/hr)
Combustion Air
77,100 kg/hr
GRATE (170,000 Ib/hr)
Bottom Ash
1,050 kg/hr
(2,320 Ib/hr)
Figure 3-12.
Energy and Material Balances for a Repre^ejitive
RDF/Coal Cofired Spreader Stoker Boiler?15
(Courtesy of Babcock & Mil cox)
3-51
-------
TABLE 3-15. BASES AND ASSUMPTIONS FOR RDF/COAL COFIRED BOILER116
Basis/Assumption Value Used
Boiler Bottom Ash Difference of total ash input
and the PM mass emission rate
Excess Air 50%
Boiler Efficiency 76%
Uncontrolled PM Emissions'1 5.82 lb/106 Btu - same as 100% HSE coal
firing^
S02 Emissions9 weighted average of emissions from
firing coal alone and RDF alone -
emissions from firing RDF are based
on 100% conversion of sulfur in the
fuel
NO Emissions3 90% of rate for 100% coal firing
A ^^^^^-^»»
Uncontrolled PM emissions were set at the same rate as emissions from
coal fired boilers. This was based on limited test data which show no
clear trend in uncontrolled PM emissions for boilers co-firing RDF and
coal as compared to 100 percent coal firing. Complete conversion of
RDF sulfur to S0£ was assumed so as to provide an estimate of the
maximum SOg emission rate. The NOX emission rate was set based on
emission data from an operating facility. Emissions from 100 percent
coal firing were taken from Fossil Fuel Fired Boilers - Background
Information for Proposed Standards and were based on AP-42 emission
factors. More details about all of the bases in this table are
provided in Reference 116.
3-52
-------
TABLE 3-16. RDF AND COAL ANALYSES SELECTED FOR THE REPRESENTATIVE BOILER117'118
Material
Carbon
Hydrogen
Oxygen
Nitrogen
Sulfur
Water
Ash
Total
Higher Heating Value
kJ/kg (Btu/lb)
High Sulfur Eastern Coal
Percentage (as fired)
64.80
4.43
6.56
1.30
3.54
8.79
10.58
100.00
27,440 (11,800)
RDF
Percentage (as fired)
31.30
4.62
21.44
0.61
0.17
22.42
19.44
1UO.OO
13,460 (5,790)
3-53
-------
TABLE 3-17. UNCONTROLLED EMISSIONS FROM REPRESENTATIVE COAL/RDF-FIRED
AND COAL-FIRED SPREADER STOKER BOILERS
oo
i
en
Fuel9
50% HSE/
50% RDF
100% HSE
Capacity
(thermal input)
44 MW
(150x106 Btu/hr)
44 MW
(150x106 Btu/hr)
Pollutant
PM
S02
NOX
PM
so2
NOX
Mass
kg/hr (Ib/hr)
396 (873)
214 (472)
38.6 (85.0)
396 (873)
388 (855)
42.9 (94.5)
Emissions
Concentration^
g/Nm3 -(gr/dscf )
6.43 (2.81)
1300°
32 7C
6.80 (2.79)
2350°
364C
Heat Input
ng./J (lb/106 Btu)
2500 (5.82)
1350 (3.15)
245 (0.567)
2500 (5.82)
2450 (5.70)
271 (0.630)
Thermal input basis.
^Corrected to 12 percent
"Gaseous emissions are in parts per million (ppm)
-------
10 .
99.99
99.9 99.8
0.5 O.2 O.I O.O5 o.OI
in
VI
c
o
o
0)
N
-------
Fluff is a term used to describe the light combustible fraction of raw
MSW. The combustion properties of RDF depend upon the degree of processing
for the materials described above. Some properties of interest are given in
Table 3-18. Choice of the most appropriate type of RDF depends on the type
of boiler used. Therefore fuel characteristics which affect emission rates,
such as size distribution and moisture content, relate directly back to
boiler design. For example, powdered RDF would be combusted in a boiler
normally employed for pulverized coal combustion, such as a tangential
suspension-fired type. Densified RDF is physically similar to stoker coal
124
and would be combusted in a stoker furnace.
3.2.3.2.3 Boiler operation. The operation factors for RDF/coal
boilers that affect uncontrolled emissions are similar to those affecting
any coal -fired unit. These are boiler load and boiler excess air. An
additional factor affecting emissions for the RDF/coal units is the ratio of
RDF to coal. Because of the higher ash content of the RDF (see Table 3-16)
uncontrolled PM emissions would be expected to increase. However, no clear
trends in uncontrolled PM emission rates have been measured in the present
applications of boilers cofiring RDF and coal as compared to 100 percent
coal firing. SO, and NO emissions tend to decrease with increasing RDF
(see Table 3-17).
Boilers designed to burn 100 percent RDF are similar to standard coal
fired boilers. Although there are insufficient data to quantitatively
characterize emissions from these boilers, in general, uncontrolled PM
emissions would be expected to be higher than those from coal -fired boilers
of equal capacity because of the higher ash content of the RDF (see
Table 3-16). SOp emissions should be lower due to the lower sulfur content
of RDF compared to coal. NO emissions would also be expected to decrease
X 107
compared to coal firing based on the limited, available test data.
3.3 EXISTING STATE AND FEDERAL EMISSIONS REGULATIONS FOR NFFBs
This section presents the existing State and Federal emissions regula-
tions which are applicable to NFFBs. These regulations are used to
calculate the "average" State and Federal emissions regulation which would
3-56
-------
TABLE 3-18. TYPICAL CHARACTERISTICS OF REFUSE DERIVED FUELS123
in
As- received
refuse
derived fuel
Fluff-wp
Fluff-dp
Screened fluff
d-RDF pellets
Density, «
kg/m3 (lb/ftj)
224 (14)b
80-144 (5-9)
16-80 (1-5)
380-720 (24-45)
As- received
heating value,
kO/kg (Btu/lb)
8140 (3500)
12,090 (5200)
16,750 (7200)
12,090 (5200)
H«0
r
50
25
16
15
Ash
%
20
19
10
18
Approximate particle size
2.5 cm (1.0 in)
2.5-5.7 cm (1.0-2.5 in)
2.5-5.1 cm (1.0-2.0 in)
1.3 cm dia. x 2.5 cm long
(from fluff)
d-RDF
briquettes
(from fluff)
Powdered RDF
750-900 (47-56)D 12,090 (5200)
480
(30) 18,011 (7750)
(0.5 in dia. x 1.0 in long)
14 18 3.0 x 3.0 x 7.5 cm
(1.25 x 1.25 x 3.0 in)
10 0.15 mm (0.006 in)
aFluff is the term used for the light combustible fraction of the raw MSW.
wp = wet processed: water is used to separate the light combustible fraction from the heavier
noncombustibles.
dp = dry processed: air is used to separate the combustible and noncombustible fraction
d-RDF = densified refuse derived fuel.
Estimated.
-------
be applied to a new NFFB if no NSPS were developed. The discussion is
presented in two parts. First, a discussion of existing emissions
regulations for new NFFBs is presented. Second, the average State or
Federal emissions regulation calculation procedure is described and
calculated average levels presented along with uncontrolled PM emission
rates.
3.3.1 Existing Standards for New Nonfossil Fuel Fired Boilers
Existing Federal and State emission standards applicable to NFFBs were
obtained through review of the Environmental Reporter and from telephone
conversations with several state agencies. The existing Federal new source
performance standards for incinerators (40 CFR 60 Subpart E) were identified
as applicable to boilers firing MSW and larger than 45 Mg/day (50 tons/day)
charging capacity. State emission standards for boilers and incinerators
are often ambiguous with respect to regulation of NFFBs. However,
applicable emission standards which specify NFFBs are readily apparent in
the regulations of 10 of the 50 states. In the regulations of 34 additional
states, comparisons of fuel-burning equipment and fuel definitions reveal
emission standards that are applicable to NFFBs. The following three
subsections summarize the applicable new source emission standards for wood,
bagasse, and GSW-fired boilers.
3.3.1.1 Wood-Fired Boilers. Wood-fired boilers are regulated as a
separate category of new source emissions in only seven of the 50 states:
Alabama, Arizona, North Carolina, Oklahoma, South Dakota, Tennessee, and
Vermont. However, an additional 36 states regulate new source emissions
from wood-fired boilers under new source standards such as "particulate
matter", "fuel-burning equipment", and "indirect heating equipment"
standards. "Fuel-burning equipment" regulations are applicable to wood-
fired boilers in 23 states. Applicability is established by defining "fuel"
to include wood, bark, and wood waste. "Particulate matter" regulations are
general in nature and were used in cases where no other state regulations
would apply. Consequently, new source emission standards were found in a
total of 43 states.
3-58
-------
New source emission standards were not found for wood-fired boilers in
the remaining seven states. However these states do not have significant
wood boiler capacity and are, therefore, not included in the calculation of
baseline emission levels. State regulations concerning PM emissions from
wood-fired boilers are presented in Table 3-19.
3.3.1.2 Bagasse-Fired Boilers. Bagasse is burned as a boiler fuel in
Florida, Hawaii, Louisiana, Puerto Rico, and Texas. Hawaii regulates
bagasse boilers specifically while the other states regulate bagasse boilers
under fuel-burning equipment or mass emission limitation regulations. These
regulations were used to calculate the average of existing emission
regulations for bagasse-fired boilers. State regulations concerning PM
emissions from bagasse-fired boilers are presented in Table 3-20.
3.3.1.3 General Solid Waste-Fired Boilers. Although GSW boilers are
not specifically regulated in any state, new source emission standards
applicable to GSW-fired boilers were identified in 45 of the 50 states. In
10 of the 45 states, GSW boilers are regulated as incinerators, while 25
states classify GSW boilers under "fuel-burning equipment" regulations.
Many states have new incinerator regulations that apply to GSW boilers.
i
However, many specify "fuel-burning equipment" regulations as being
applicable to boilers and incinerators that burn GSW for the purpose of
producing steam. The remaining 10 states were found to regulate GSW boilers
under general "particulate matter" and "indirect heat exchanger"
regulations. State regulations concerning PM emissions from GSW-fired
boilers are presented in Table 3-21. GSW boilers firing municipal type
solid waste and larger than 45 Mg/day (50 tons/day) charging capacity are
also regulated by 40 CFR 60 Subpart E. The applicable emission limit for
these boilers is 0.18 g/dNm (0.08 gr/dscf) corrected to 12 percent C02.
3.3.2 Calculation of the Average of Existing Emissions Regulations
Currently, Federal new source performance standards apply to MSW-fired
boilers with over 45 Mg/day (50 tons/day) capacity, but they do not apply to
other boilers fired with 100 percent nonfossil fuels. However, state
emission limits do apply to new NFFB installations. Therefore, the average
of existing emissions regulations is selected as the applicable Federal
3-59
-------
TABLE 3-19. STATE REGULATIONS FOR PARTICULATE MATTER (EM)
EMISSIONS FROM NEW WOOD-FIRED BOILERS f^'1^
State
Alabama
Alaska
Arizona
California
Connecticut
Florida
Georgia
to
cr>
0
Idaho
Illinois
Indiana
How Regulated
wood waste boilers
fuel -burning equipment
wood waste burner
any boiler
fuel -burning equipment
fuel-burning equipment
fuel -burning equipment
fuel -burning equipment
fuel -burning equipment
fuel -combustion steam generators
Basis for Limit
0.20 gr/dscf @50* excess air
0.15 gr/scf
0.20 gr/dscf 012 C02
0.10 gr/dscf 912% C02
0.11 lb/106 BTU
0.30 lb/106 BTU
0.20 lb/106 BTU
0.50 lb/106 BTU
in °-5 fi
E=0.5(^) lb/10b BTU
0.10 lb/106 BTU
0.08 gr/dscf
0.11 lb/106 BTU
0.60 lb/106 BTU
0.35 lb/106 BTU
0.10 lb/106 BTU
(0.46 g/dNm3)
(0.34 g/Nm3)
(0.46 g/Nm3)
(0.23 g/dNm3)
(47.3 ng/J)
(129 ng/J)
(85.0 ng/J)
(215 ng/J)
in °-5
(698.3(i£)
(43.0 ng/J)
(0.18 g/dNm3)
(47.3 ng/J)
(258 ng/J)
(151 ng/J)
(43.0 ng/J)
Applicability
wood only
wood waste
wood and wood waste
steam generation
steam generation
Q <30 x 106 BTU/hr (31.7 GJ/hr)
Q ^ 30 x 106 BTU/hr (31.7 GJ/hr)
Q <_ 10 x 106 BTU/hr (10.6 GJ/hr)
ng/J) Q >. 10 x 106 BTU/hr (10.6 GJ/hr)
Q £ 250 x 106 BTU/hr (263.8 GJ/hr)
Q >250 x 106 BTU/hr (263.8 GJ/hr)
wood products
any new solid fuel burner
Q <25 x 106 BTU/hr (26.4 GJ/hr)
Q ^ 25 x 106 BTU/hr (26.4 GJ/hr)
Q <. 250 x 106 BTU/hr (263.8 GJ/hr)
Q >250 x 106 BTU/hr (263.8 GJ/hr)
See footnotes at end of table
-------
TABLE 3-19. (CONTINUED)
CO
State
Iowa
Kansas
Kentucky
How Regulated
Indirect heating equipment
Indirect heating equipment
Indirect heating equipment
Basis for Limit
0.60 lb/106 BTU
0.60 lb/106 BTU
E=1.026 Q~°-233lb/10
0.12 lb/106 BTU
0.56 lb/106 BTU
(258 ng/J)
(258 ng/J)
6 BTU (446.7 g~°-233ng/J)
(51.6 ng/J)
(241 ng/J)
E=0.9644 Q-°'2356lb/106 BTU (420.0 Q'0>2356ng/J)
Louisiana
Maine
Massachusetts
Michigan
See footnotes
fuel -burning equipment
fuel -burning equipment
fuel-burning equipment
fuel -burning equipment
at end of table
0.10 lb/106 BTU
0.60 lb/106 BTU
0.60 lb/106 BTU
E=1.08 Q-°'256lb/106
0.30 lb/106 BTU
0.10 lb/106 BTU
0.50 lb/1000 Ib 050%
(43.0 ng/J)
(258 ng/J)
(258 ng/J)
BTU (470.8 Q"°'256ng/J)
(129 ng/J)
(43.0 ng/J)
Excess air (0.50 g/kg)
Applicability
Q <4000 x 106 BTU/hr (4200 6J/hr)
Q <10 x 106 BTU/hr (10.6 GJ/hr)
Q > 10 x 106 BUT/hr (10.6 GJ/hr)
Q <10,000 x 106 BTU/hr (10,550 GJ/hr)
Q > 10,000 x 106 BTU/hr (10,550 GJ/hr)
Q < 10 x 106 BTU/hr (10.6 GJ/hr)
Q >10 x 106 BTU/hr (10.6 GJ/hr)
Q <. 250 x 106 BTU/hr (263.8 GJ/hr)
Q >250 x 106 BTU/hr (263.8 GJ/hr)
all fuels
Q <_ 10 x 106 BTU/hr (10.6 GJ/hr)
Q >10 x 106 BTU/hr (10.6 GJ/hr)
Q <. 150 x 106 BTU/hr (158 GJ/hr)
Q >150 x 106 BTU/hr (158 GJ/hr)
Q >3 x 106 BTU/hr (3.2 GJ/hr)
Hood fuel 75% of total Input
-------
TABLE 3-19. (CONTINUED)
co
CTt
ro
State
Minnesota
Mississippi
How Regulated
fossil fuel-burning direct
heating equipment
fuel-burning equipment
Basis for Limit
0.10 gr/scf
0.089 gr/scf
0.057 gr/scf
0.05 gr/scf
0.021 gr/scf
0.30 gr/dscf
(0.23 g/Nm3)
(0.200 g/Nm3)
(0.130 g/Nm3)
(0.11 g/Nm3)
(0.010 g/Nm3)
•• (0.69 g/dNm3)
Applicability
flue gas flow
flue gas flow
flue gas flow
flue gas flow
flue gas flow
spent wood
<7000 scfm (3.304 Nm3/s)
<_ 10,000 scfm (4.720 Nm3/s)
<_ 40,000 scfm (18.878 Nm3/s)
<_ 60,000 scfm (28.317 Nm3/s)
<_ 8,000,000 scfm (3775.600 Km'
Missouri
Montana
Nebraska
Nevada
fuel-burning equipment
fuel-burning equipment
fuel-burning equipment
Indirect heat transfer
0.40 lb/10° BTU
E=0.8 10 x 106 BTU/hr (10.6 GJ/hr)
Q 1 10 x 106 BTU/hr (10.6 GJ/hr)
Q >10 x 106 BTU/hr (10.6 GJ/hr)
Q <_ 100 x 106 BTU/hr (106 GJ/hr)
Q>100 x 106 BTU/hr (106 GJ/hr)
Q <_ 1000 x 106 BTU/hr (1055 GJ/hr)
Q <_ 10 x 106 BTU/hr (10.6 GJ/hr)
E=1.026 q"°'233lb/106 BTU(446.7 Q~°'Z33ng/J) Q >10 x 106 BTU/hr (10.6 GJ/hr)
Q <_ 3800 x 106 BTU/hr (4009 GJ/hr)
0.15 lb/106 BTU (65.0 ng/J) Q >3800 x 106 BTU/hr (4009 GJ/hr)
E=1.02 Q"°-231lb/106 BTU (444.0 Q"°'231ng/J) Q >. 10 x 106 BTU/hr (10.6 GJ/hr)
Q < 4000 x 106 BTU/hr (4220 GJ/hr)
E=17.0 Q"0'568lb/106 BTU (7534.9 Q"°'569ng/J) 0_>4000 x 106 BTU/hr (4220 GJ/hr)
See footnotes at end of table
-------
TABLE 3-19. (CONTINUED)
State
New Hampshire
New York
How Regulated Basis for Limit
fuel-burning equipment 0.60 1b/106 DTD
0.40 lb/106 BTU
0.35 lb/106 BTU
0.10 lb/106 BTU
stationary combustion Installations 0.60 lb/106 BTU
(258 ng/J)
(172 ng/J)
(151 ng/J)
(43.0 ng/J)
(258 ng/J)
Applicability
Q <. 10 x 106 BTU/hr (10.6 GJ/hr)
Q >10 x 106 BTU/hr (10.6 GJ/hr)
Q <50 x 106 BTU/hr (52.8 GJ/hr)
Q >50 x 106 BTU/hr (52.8 GJ/hr)
Q <. 100 x 106 BTU/hr (106 GJ/hr)
Q > 100 x 106 BTU/hr (106 GJ/hr)
Q >1 x 106 BTU/hr (1.1 GJ/hr)
co
en
co
Q <. 10 x 10° BTU/hr (10.6 GJ/hr)
E=1.0 Q'0-22lb/106 BTU (435.0 Q'°'22ng/J) Q >10 x 106 BTU/hr (10.6 GJ/hr)
North Carolina wood burning Indirect heat exhangers 0.70 lb/10 BTU
(301 ng/J)
E=1.1698 Q"°'223lb/106 BTU (509.0 Q"°'223ng/J)
Q <. 10,000 x 10° BTU/hr (10,550 GJ/hr)
Q <. 10 x 106 BTU/hr (10.6 GJ/hr)
Q >10 x 106 BTU/hr (10.6 GJ/hr)
North Dakota
Ohio
fuel-burning equipment used for
Indirect heating
fuel -burning equipment
E=0.811 Q"u-1J1lb/10°BTU
0.40 lb/106 BTU
E=0.80 10 x 106 BTU/hr (10.6 GJ/hr)
Q 1 1000 x 106 BTU/hr (1055 GJ/hr)
Q >1000 x 106 BTU/hr (1055 GJ/hr)
See footnotes at end of table
-------
TABLE 3-19. (CONTINUED)
State How Regulated
Oklahoma wood waste burning equipment
Oregon fuel -burning equipment
Pennsylvania combustion units
Puerto Rico fuel-burning equipment
Rhode Island fossil fuel-burning equipment
South Carolina fuel-burning operations
South Dakota wood burners
Basis for Limit
0.60 lb/106 BTU
0.35 lb/106 BTU
0.20 lb/106 BTU
0.10 lb/106 BTU
0.10 gr/dscf
0.40 lb/106 BTU
E=3.6 Q~°'56lb/106BTU
0.10 lb/106 BTU
0.30 lb/106 BTU
0.20 lb/106 BTU
0.10 lb/106 BTU
0.60 lb/106 BTU
E=57.84 0"°'637lb/106
0.30 lb/106 BTU
(258 ng/J)
(151 ng/J)
(86.0 ng/J)
(43.0 ng/J)
(0.23 g/dNm3)
(172 ng/J)
(1595 637ng/J)
(129 ng/J)
Applicability
Q <_ 10 x 106 BTU/hr (10.6 GJ/hr)
Q >10 x 106 BTU/hr (10.6 GJ/hr)
Q £ 100 x 106 BTU/hr (106 GJ/hr)
Q >100 x 106 BTU/hr (106 GJ/hr)
0 <. 1000 x 106 BTU/hr (1055 GJ/hr)
Q >1000 x 106 BTU/hr (1055 GJ/hr)
Q _< 10,000 x 106 BTU/hr (10,550 GJ/hr)
all fuel burning equipment
Q <_ 50 x 106 BTU/hr (52.8 GJ/hr)
Q >50 x 106 BTU/hr (52.8 GJ/hr)
Q _< 600 x 106 BTU/hr (633 GJ/hr)
Q >600 x 106 BTU/hr (633 GJ/hr)
solid fuel
Q ^ 250 x 106 BTU/hr (264 GJ/hr)
0 >250 x 106 BTU/hr (264 GJ/hr)
Q <1300 x 106 BTU/hr (1372 GJ/hr)
0 1 1300 x 106 BTU/hr (1372 GJ/hr)
solid fuel
See footnotes at end of table
-------
TABLE 3-19. (CONTINUED)
co
i
CJ1
State
Tennessee
Texas
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
How Regulated
wood fired fuel-burning equipment
participate emissions
wood fuel-burning equipment
fuel-burning equipment
combustion Incinerator sources
Indirect heat exchangers
fuel-burning Installations
fuel -burning equipment
Q = design heat Input, 106 BTU/hr (GJ/hr) E =
E1 = emission
rate, Ib/hr (kg/hr)
Basis for Limit
0.330 gr/dscf P12X COZ (0.760 g/dNm3)
E=0. 00173 Q + .0267 gr/dscf (-0.00396 Q +
.0611 g/dNm3)
@12X C02
0.20 gr/dscf 912% C0? (0.46 g/dNm3)
0.10 1b/106 BTU (43.0 ng/J)
0.20 gr/dscf P12X C02 (0.46 g/dNm3)
0.10 gr/dsr.f 312* C02 (0.23 g/dNm3)
0.60 lb/106 BTU (258 ng/J)
E=1.0906 Q-°'2594lb/106 BTU (475.5 Q'°'2594ng/J)
0.20 gr/dscf (0.46 g/dNm3)
.05 Q Ib/hr (0.022 Q kg/hr)
0.50 lb/106 BTU (215 ng/J)
0.15 lb/106 BTU (65.0 ng/J)
0.10 lb/106 BTU (43.0 ng/J)
0.10 lb/106 BTU (43.0 ng/J)
emission rate, lb/106 BTU (ng/J) F = fuel Input
Applicability
q <_ 25 x 106 BTU/hr (26.4 GJ/hr)
q >25 x 106 BTU/hr (26.4 GJ/hr)
q ^ 100 x 106 BTU/hr (106 GJ/hr)
q> 100 x 106 BTU/hr (106 GJ/hr)
general applicability
q <_ 3.3 x 106 BTU/hr (3.5 GJ/hr)
q>3.3 x 106 BTU/hr (3.5 GJ/hr)
q <_ 10 x 106 BTU/hr (10.6 GJ/hr)
q >10 x 106 BTU/hr (10.6 GJ/hr)
wood combustion for steam production
E1 <_ 1200 Ib/hr (544.3 kg/hr)
q 1 100 x 106 BTU/hr (106 GJ/hr)
q >100 x 106 BTU/hr (106 GJ/hr)
q 1 250 x 106 BTU/hr (264 GJ/hr)
q >250 x 106 BTU/hr (264 GJ/hr)
wood fuel
, Ib/hr (kg/hr)
-------
TABLE 3-20. STATE REGULATIONS FOR PARTICULATE MATTER
EMISSIONS FROM NEW BAGASSE-FIRED BOILERS.
State
How Regulated
Oasis for Limit
Applicability
Florida carbonaceous fuel-burning
Hawaii bagasse boilers
Louisiana fuel-burning equipment
Puerto Rico fuel-burning equipment
Texas partlculate natter emissions
0.30 lb/10° BTU (129 ng/J)
0.20 lb/106 BTU (86 ng/J)
0.40 lb/100 Ib bagasse (0.40 kg/100 kg)
0.60 lb/106 BTU (258 ng/J)
0.30 lb/106 BTU (129 ng/J)
0.10 lb/106 BTU (43 ng/J)
Q < 30 x 10° BTU/hr (31.7 GJ/hr)
Q >_ 30 x 106 BTU/hr (31.7 GJ/hr)
bagasse only
all fuels
solid fuels
general applicability
Q = boiler heat Input, 10° BTU/hr (GJ/hr)
-------
TABLE 3-21. STATE REGULATIONS FOR PARTICIPATE MATTER (BMl EMISSIONS
FROM NEW GENERA SOID -F 128'1^9
State
How Regulated
Basis for Limit
Applicability
Alabama fuel-burning equipment
Alaska fuel-burning equipment
Arizona fuel-burning equipment
Arkansas PM emissions
Colorado fuel-burning equipment
Connecticut fuel-burning equipment
Delaware fuel-burning equipment
Florida carbonaceous fuel-burning
equipment
Georgia fuel-burning equipment
0.50 lb/10° BTU (215 ng/J)
0.15 lb/106 BTU (64.5 ng/J)
0.12 lb/106 BTU (51.6 ng/J)
0.10 gr/scf (0.23 g/Nm3)
M=1.02 Q°-760 Ib/hr (0.44 Q°'760 kg/hr)
M=17.0 Q0-432 Ib/hr (7.31 Q°'432 kg/hr)
0.20 gr/dscf (0.45 g/dNm3) S12* CO
E=0.50 Q'°-26 lb/106 BTU (218.0 Q'°'26 ng/J)
0.10 lb/10° BTU (43.0 ng/J)
0.30 lb/106 BTU (129 ng/J)
0.30 lb/106 BTU (129 ng/J)
0.20 lb/106 BTU (86.0 ng/J)
0.50 lb/106 BTU (215 ng/J)
E=0.50 (10/Q)0-5 lb/106 BTU (698.3 (10/Q)°'5ng/J)
0.10 lb/106 BTU (43.0 ng/J)
Q=10 x lO^BTU/hr (10.6 GJ/hr)
Q=150 x 106 BTU/hr (158 GJ/hr)
0=400 x 106 BTU/hr (422 GJ/hr)
municipal waste
Q <_ 4200 x 106 BTU/hr (4431 GJ/hr)
Q >4200 x 106 Btu/hr (4431 GJ/hr)
Incinerators
Q >1.0 x 106 BTU/hr (1.1 GJ/hr)
Q <. 500 x 106 BTU/hr (528 GJ/hr)
all fuels
Q>1 x 106 BTU/hr (1.1 GJ/hr)
Q <30 x 106 BTU/hr (31.7 GJ/hr)
Q >_ 30 x 106 BTU/hr (31.7 GJ/hr)
Q <10 x 106 BTU/hr (10.6 GJ/hr)
Q ^ 10 x 106 BTU/hr (10.6 GJ/hr)
Q <. 250 x 106 BTU/hr (264 GJ/hr)
Q >250 x 106 BTU/hr (264 GJ/hr)
See footnotes at end of table
-------
TABLE 3-21. (CONTINUED)
State
How Regulated
Basis for Limit
Applicability
£
00
Hawaii
Idaho
Illinois
Indiana
Iowa
Kentucky
Louisiana
Maine
fuel-burning equipment
fuel-burning equipment
fuel-burning equipment
fuel combustion steam generators
combustion from Indirect heat
exchangers
general Indirect heat exchangers
fuel-burning equipment
fuel-burning equipment
Massachusetts
fuel-burning equipment
0.40 lb/100 Ib (0.40 kg/100 kg)
0.08 gr/dscf (0.18 g/gNm3) 08*
0.10 lb/106 BTU (43.0 ng/J)
0.60 lb/106 BTU (258 ng/J)
0.35 lb/106 BTU (151 ng/J)
0.10 1b/10° BTU (43.0 ng/J)
0.60 lb/106 BTU (258 ng/J)
0.56 lb/100 BTU (241 ng/J)
E=0.9644 q-°-236 ib/106 BTU (419.9 Q~°*236ng/J)
0.10 lb/106 BTU (43.0 ng/J)
0.60 lb/106 BTU (258 ng/J)
0.60 lb/106 BTU (258 ng/J)
E=1.08 q-°-256 lb/106 BTU (470.8 Q-°-256 ng/J)
0.30 lb/106 BTU (129 ng/J)
0.10 lb/106 BTU (43.0 ng/J)
refuse
Q >. 10 x 106 BTU/hr (10.6 GJ/hr)
sol Id-fuel combustion
Q <25 x 106 BTU/hr (26.4 GJ/hr)
Q >. 25 x 106 BTU/hr (26.4 GJ/hr)
Q ^ 250 x 106 BTU/hr (264 GJ/hr)
Q >250 x 106 Btu/hr (264 GJ/hr)
Q <4000 x 106 Btu/hr (4220 GJ/hr)
Q <_ 10 x 106 BTU/hr (10.6 GJ/hr)
Q >10 x 106 BTU/hr (10.6 GJ/hr)
Q 1 250 x 106 BTU/hr (264 GJ/hr)
Q >250 x 106 BTU/hr (264 GJ/hr)
all fuels
q < 10 x 106 BTU/hr (10.6 GJ/hr)
q >10 x 106 BTU/hr (10.6 GJ/hr)
q ^ 150 x 106 BTU/hr (158 GJ/hr)
q >150 x 106 BTU/hr (158 GJ/hr)
q >. 3 x 106 BWhr (3.2 GJ/hr)
See footnotes at end of table
-------
TABLE 3-21. (CONTINUED)
State
How Regulated
Basis for Limit
Applicability
V
s
Michigan
Minnesota
Mississippi
Missouri
Nebraska
Nevada
Incinerators
Incinerators
fuel-burning equipment
Incinerators
fuel-burning equipment
Indirect heat transfer
0.65 lb/1000 Ibs gas (0.65 kg/1000 kg gas)
0.30 lb/1000 Ibs gas (0.14 kg/1000 kg gas)
0.20 gr/dscf (0.46 g/dNm3) 912% C02
0.15 gr/dscf (0.34 g/dNm3) 012X C02
0.10 gr/dscf (0.23 g/dNm3) P12X C02
0.08 gr/dscf (0.18 g/dNm3) P12X C02
0.30 gr/dscf (0.69 g/dNm3)
0.40 lb/106 BTU (172 ng/J)
E=0.80 q-°-301 lb/106 BTU (349.6 g'0-301 ng/J)
0.60 lb/106 BTU (258 ng/J)
E=1.026 Q-°-233 lb/106 BTU (446.7 q'°-233 ng/J)
0.15 lb/106 BTU (64.5 ng/J)
R < 100 Ib/hr (45 kg/hr)
R >100 Ib/hr (45 kg/hr)
R£ 200 Ib/hr (90.7 kg/hr)
R >200 Ib/hr (90.7 kg/hr)
R < 2000 Ib/hr (907 kg/hr)
R >2000 Ib/hr (907 kg/hr)
R £ 4000 Ib/hr (1814 kg/hr)
R >4000 Ib/hr (1814 kg/hr)
waste boilers
Q <10 x 106 BTU/hr (10.6 GJ/hr)
Q >_ 10 x 106 BTU/hr (10.6 GJ/hr)
Q 1 10 x 106 BTU/hr (10.6 GJ/hr)
Q >10 x 106 BTU/hr (10.6 GJ/hr)
Q 1 3800 x 106 Btu/hr (4009 GJ/hr)
Q >3800 x 106 BTU/hr (4009 GJ/hr)
E=1.02 q-°-231 lb/106 BTU (444.0 q'0-231 ng/J) Q > 10 x 106 BTU/hr (10.6 GJ/hr)
Q <_ 4000 x 106 BTU/hr (4220 GJ/hr)
Q >4000 x 106 BTU/hr (4220 GJ/hr)
E=17.0 q-°-568 ib/106 BTU (7535 q'0-568 ng/J)
See footnotes at end of table
-------
TABLE 3-21. (CONTINUED)
State
How Regulated
Basis for Limit
Applicability
Q <. 10 x 106 BTU/hr (10.6 GJ/hr)
Q >10 x 106 BTU/hr (10.6 GJ/hr)
Q < 50 x 106 BTU/hr (52.8 GJ/hr)
Q >50 x 106 BTU/hr (52.8 GJ/hr)
Q £ 100 x 106 BTU/hr (106 GJ/hr)
Q >100 x 106 BTU/hr (106 GJ/hr)
Q=10 x 106 BTU/hr (10.6 GJ/hr)
Q=150 x 106 BTU/hr (158.3 GJ/hr)
Q=400 x 106 BTU/hr (422 GJ/hr)
Q=10 x 106 BTU/hr (10.6 GJ/hr)
Q=150 x 106 BTU/hr (158.3 GJ/hr)
Q=400 x 106 BTU/hr (422 GJ/hr)
R _< 100 Ib/hr (45.5 kg/hr)
100 Ib/hr (45.4 kg/hr) 2000 Ib/hr (907.2 kg/hr)
R <. 1000 Ib/hr (454 kg/hr)
R >1000 Ib/hr (454 kg/hr)
C*>
New Hampshire fuel-burning equipment
New Jersey
New York
North Carolina
North Dakota
Indirect heat exchangers
Incinerators
refuse burning equipment
Incinerators
0.60 lb/10D BTU (258 ng/J)
0.40 lb/106 BTU (172 ng/J)
0.35 lb/106 BTU (151 ng/J)
0.10 lb/10 BTU (43.0 ng/J)
6.0 Ib/hr (2.7 kg/hr)
18 Ib/hr (8.2 kg/hr)
40.0 Ib/hr (18.1 kg/hr)
5.0 Ib/hr (2.3 kg/hr)
52.0 Ib/hr (23.6 kg/hr)
110 Ib/hr (49.9 kg/hr)
0.2 Ib/hr (0.1 kg/hr)
M=0.002 R Ib/hr (0.0009 R kg/hr)
4.0 Ib/hr (1.8 kg/hr)
M=0.00515 R0-90 Ib/hr
M=0.0252 R0-67 Ib/hr (0.0194 R°'67 kg/hr)
M=0.00515 R0-90 Ib/hr (0.00476 R0>9° kg/hr)
See footnotes at end of table
-------
TABLE 3-21. (CONTINUED)
State
How Regulated
Basis for Limit
Applicability
Ohio
Oklahoma
Oregon
Pennsylvania
Puerto Rico
Rhode Island
South Carolina
Sough Dakota
Tennessee
Texas
Vermont
Incinerators
fuel-burning equipment
refuse-burning equipment
combustion units
fuel-burning equipment
Incinerators
fuel-burning equipment
fuel-burning equipment
Incinerators
participate matter emissions
fuel-burning equipment
0.20 lb/100 Ib refuse (0.20 kg/100 kg refuse)
0.10 lb/100 Ib refuse (0.10 kg/100 kg refuse)
E=1.09 q-°-259 lb/106 BTO (475.2 Q'0-259 ng/J)
0.10 gr/dscf (0.23 g/dNm3) 012X C02
0.30 gr/dscf (0.69 g/dNm3) 312* C02
0.40 lb/106 BTU (172 ng/J)
R <100 Ib/hr (45.4 kg/hr)
R >_ 100 Ib/hr (45.4 kg/hr)
all participate emissions
R f 200 Ib/hr (90.7 kg/hr)
R >200 Ib/hr (90.7 kg/hr)
Q ^ 50 x 106 BTU/hr (52.8 GJ/hr)
E=3.6 Q'°-56 lb/106 BTU (1595.0 Q'0'56 ng/J) Q >50 x 106 BTU/hr (52.8 6J/hr)
0.1 lb/10D BTU (43 ng/J)
0.30 lb/106 BTU (129 ng/J)
0.16 gr/scf (0.37 g/Nm3)
0.08 gr/scf (0.18 g/Nm3)
0.60 lb/106 BTU (258 ng/J)
E=57.84 q-°-637 lb/106 BTU (25731 q'0'637 ng/J)
0.30 lb/106 BTU (129 ng/J)
0.08 gr/scf (0.18 g/Nm3)
0.10 lb/106 BTU (43.0 ng/J)
0.20 gr/dscf (0.45 g/dNm3) 012% C02
0.10 gr/dscf (0.23 g/dNm3) 012X C02
Q ^ 600 x 10° BTU/hr (633 6J/hr)
Q >600 x 106 BTU/hr (633 GJ/hr)
solid fuel
R <2000 Ib/hr (907 kg/hr)
R z 2000 Ib/hr (907 kg/hr)
Q <1300 x 106 BTU/hr (1372 GJ/hr)
Q >. 1300 x 106 BTU/hr (1372 GJ/hr)
solid fuel
all new Incinerators
general regulation
Q i 0.2 x 106 BTU/hr (0.2 GJ/hr)
Q <_ 3.3 x 106 BTU/hr (3.5 GJ/hr)
Q >3.3 x 106 BTU/hr (3.5 GJ/hr)
See footnotes at end of table
-------
TABLE 3-21. (CONTINUED)
State
How Regulated
Basis for Limit
Applicability
Virginia fuel-burning equipment
Washington combustion and Incineration sources
Hest Virginia fuel-burning units
Wisconsin fuel-burning Installations
Wyoming Incinerators
0.60 lb/10° BTU (258 ng/J)
Q <10 x 10° BTU/hr (10.6 GJ/hr)
E=1.096 2594lb/106 BTU (531.0 q'0-2594 ng/J) Q >10 x 106 BTU/hr (10.6 GJ/hr)
Q <_ 10,000 x 106 BTU/hr (10550 GJ/hr)
excludes wood combustion
0.10 gr/scf (0.23 g/dNm°)
M=0.05 Q Ib/hr (0.02 Q kg/hr)
E=0.3 - 0.0006 Q lb/106 BTU
(129 - .2580 Q ng/J)
0.15 lb/106 BTU (64.5 ng/J)
0.20 lb/100 Ib (0.20 kg/100 kg)
Type A fuel burning units
Q <_ 250 x 106 BTU/hr (264 GJ/hr)
Q >250 x 106 BTU/hr (264 GJ/hr)
all Incinerators
XI
ro
Q - actual heat Input, 10° BTU/hr (GJ/hr)
E « emission rate, lb/106 BTU (ng/J)
R « refuse burned, Ib/hr (kg/hr)
H » emission rate, Ib/hr (kg/hr)
V « volumetric flow, acfm (m /s)
-------
standard or the weighted average of all the applicable state standards,
whichever was lower. Use of a weighted average causes the calculated
baseline emission level to represent a typical state emission standard for
new NFFBs in the absence of a uniform Federal standard. The average
emissions regulations derived from these sources are presented in
Table 3-22, along with uncontrolled PM emissions.
The following four subsections describe calculation of the average of
existing emission regulations based on typical new NFFB capacities and mass
balances discussed in Section 3.2 of this chapter. The average of existing
emission regulations for boilers cofiring coal with wood or RDF are assumed
to be the same as those for boilers 100 percent fired with coal.
3.3.2.1 Wood-Fired Boilers. Calculation of the average of existing
emission regulations for wood-fired boilers consisted of four steps. First,
using material balances (based on combustion calculations) developed for
selected model boilers, the state emission standards were put on a common
basis. The selected boilers ranged in size from 8.8 to 117 MW thermal input
(30-400 x 10 Btu/hr). Second, weighting factors for each state were
calculated based upon the individual state's existing wood-fired boiler
capacity divided by the existing national capacity. Third, the weighted
emission limit for each state was calculated as the product of its emission
limit for the selected boiler and its weighting factor from step 2. Fourth,
the average regulation for the selected new wood-fired boiler was determined
from summation of the weighted emission limitations. The results of these
calculations are presented in Table 3-22 along with the uncontrolled
emissions.
3.3.2.2 Bagasse-Fired Boilers. The average of existing emission
regulations level for a representative new 58.6 MW (200 x 10 Btu/hr)
thermal input bagasse-fired boiler was calculated using the same procedures
as used for wood-fired boilers. However, the weighting factor was based on
the bagasse-fired boiler capacity for each state multiplied by the fraction
of a year corresponding to the state's sugar cane processing season. The
resulting emission level is shown in Table 3-22 along with the uncontrolled
emission rate.
3-73
-------
oo
TABLE 3-22. AVERAGE OF EXISTING EMISSION REGULATIONS AND UNCONTROLLED
EMISSIONS FOR NONFOSSIL FUEL-FIRED BOILERS130
Fuel
Wood
Wood
Wood
Wood
50% Wood/
50% HSE
50% Wood/
50% HSE
MSW
MSW
MSW
50% RDF/
50% HSE
Bagasse
Representative
Boiler
, MW
(10d Btu/hr)
8.8
(30)
22
(75)
44
(150)
117
(400)
44
(150)
117
(400)
2.9
(10)
44
(150)
117
(400)
44
(150)
58.6
(200)
Uncontrolled Emissions
ng/J (lb/10° Btu)
PM S02
2090
(4.88)
2090
(4.88)
2090
(4.88)
2090
(4.88)
2300
(5.35)
2300
(5.35)
129
(0.30)
1450
(3.37)
1450
(3.37)
2500
(5.82)
2170
(5.05)
:
-
-
-
1240
(2.89)
1240
(2.89)
211
(0.492)
211
(0.492)
211
(0.492)
1350
(3.14)
-
Average State or Federal
Emission Regulations
ng/J (lb/106Btu)
PM S02
172
(0.40)
159
(0.37)
146
(0.34)
129
(0.30)
138
(0.32)
43.0
(0.10)
146
(0.34)
73.1
(0.17)
73.1
(0.17)
138
(0.32)
267
(0.62)
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
1075
(2.5)
516
(1.2)
N/A
N/A
N/A
N/A
N/A
N/A
1075
(2.5)
N/A
N/A
-------
3.3.2.3 General Solid Waste-Fired Boilers. Average emission
regulations were calculated for typical boiler sizes of 2.9, 44, and 117
MW thermal input (10, 150, and 400 x 10 Btu/hr). For the boiler sizes of
44 and 117 MW thermal input (150 and 400 x 10 Btu/hr) the emission rate
came from Subpart E of 40 CFR 60. For the boiler size of 2.9 MW
(10 x 10 Btu/hr) weighting factors, based on each state's population
(people not boilers) were calculated by dividing the state population by
the total national population. (The present GSW boiler populations are
too small to provide a reasonable basis for the baseline emission level
calculation.) The average of existing emission regulations was then
calculated using the same procedure as was used for wood-fired boilers.
The results of these calculations for the three GSW boilers are presented
in Table 3-22.
3.3.2.4 Nonfossil Fuel/Coal Cofired Boilers. Average emissions
regulation levels for PM and S0« were determined for boilers cofiring
nonfossil fuels with coal. These levels were assumed to be the same as the
levels determined for coal-fired boilers in Fossil Fuel Fired Boilers -
Background Information for Proposed Standards. These levels were based on
a weighted average of state regulations for boilers with less than 73.3 MW
(250 x 10 Btu/hr) thermal input capacity and on Subpart D of 40 CFR 60 for
larger boilers. This assumption was made since regulations are often not
clear concerning the treatment of cofired boilers. The average of existing
emission regulations for cofired boilers is presented in Table 3-22.
3-75
-------
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12. Boubel, R.W. (PEDCo Environmental, Inc.) Control of Participate
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-------
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P
P
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3-78
-------
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-------
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3-80
-------
77. Meade, E.P. and C.P- Chen. Cane Sugar Handbook, Tenth Edition.
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93. Reference 3, p. A-14.
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100. Reference 18, p. 4.
101. Reference 18, p. 7.
102. Evaluation of Small Modular Incinerators in Municipal Plants.
(Prepared for U.S. Environmental Protection Agency.) Contract No.
68-01-3171. 1976. p. 7.
103. Reference 28, pp. 13-14.
104. Reference 94, pp. 2-4.
105. Reference 18, pp. 19-20.
106. Peters, J.A. and W.H. McDonald. (Monsanto Research Corporation.)
Nonfossil Fueled Boilers: Emission Test Report for City of Salem,
Virginia. (Prepared for U.S. Environmental Protection Agency.)
Research Triangle Park, N.C. Publication No. EMB-80-WFB-1. February
1980. p. 4.
107. Reference 18, pp. 235, 262.
108. Reference 3, p. A-ll.
109. Duckett, E.J. Health Aspects of Resource Recovery Part II: Air
Pollution. NCRR Bulletin. 8(4):105-112. Fall 1978.
3-82
-------
110. Telecon. Barnett, K., Radian Corporation, with Morton, Nashville
Thermal Transfer Corporation. October 1, 1980. Startup of large
MSW-fired boilers.
111. Telecon. Barnett, K., Radian Corporation, with Harris, L., Consumat.
October 8, 1980. Startup of small modular incinerators.
112. Nashville Thermal Transfer Corporation. Nashville, Tennessee.
November 1978. 6 p.
113. Reference 94, p. 4.
114. Reference 4.
115. Reference 28, pp. 20-21.
116. Memo from Barnett, K., Radian Corporation, to file. July 23, 1980.
3 p. Compilation of RDF/Coal boiler design and fuel specifications
from industry data and reference materials.
117. Reference 116, p. 2.
118. Reference 30.
119. Reference 28, pp. 19-20.
120. Shannon, L.J., et al. (Midwest Research Institute.) St. Louis/Union
Electric Refuse Firing Demonstration Air Pollution Test Report.
(Prepared for U.S. Environmental Protection Agency.) Washington, D.C.
Publication No. EPA-650/2-74-073. August 1974. pp. 54-58.
121. Compilation of Air Pollutant Emission Factors, Third Edition.
(Prepared for U.S. Environmental Protection Agency.) Research Triangle
Park, N.C. Publication No. AP-42. August 1977. p. 1.1-3.
122. Reference 1, pp. 2-16 to 2-18.
123. Reference 1, p. 2-19.
124. Reference 1, p. 2-21.
125. Reference 109, p. 107.
126. Reference 109, p. 109.
127. Golembiewski, M.A. (Midwest Research Institute.) Environmental
Assessment of a Waste-to-Energy Process RDF Electric Power Boiler.
(Prepared for U.S. Environmental Protection Agency.) Cincinnati, Ohio.
EPA Contract No. 68-02-2166. February 1980. p. 23.
3-83
-------
128. Environment Reporter State Air Laws, Volumes I and II. Washington,
D.C. The Bureau of National Affairs, 1979. pp. 299:0001-556:0523.
129. Memo from .Piccot, S., Radian Corporation, to file. October 1980. 3 p.
Summary of telephone conversations with state environmental personnel.
130. Memo from Piccot, S., Radian Corporation, to file.
15 p. Baseline Emission Calculations.
October 1980.
131. Adams, T. N. (University of British Columbia.) Mechanisms of Particle
Entrainment and Combustion and How They Affect Emissions from
Wood-Waste Fired Boilers. In: Proceedings of the National Waste
Processing Conference. New York, American Society of Mechanical
Engineers. May 1976. p. 183.
132. Reference 84, p. 1.
133. Letter and attachments from Mounts, R. D., Hawaiian Sugar Planters'
Association, to Duffe, S. T., EPA:ISB. April 8, 1981. 3 p. Comments
on Chapters 3-9 of the draft NFFB BID and information on bagasse
dryers.
134. Reference 78.
135. Reference 133, p. 1.
136. Junge, D.C. Emissions of Oxides of Nitrogen from Boilers Fired with
Wood and Bark Residue Fuels. In: Proceedings of the Annual
Environmental Conference of TAPPI, Denver, April 9-11, 1980. Atlanta,
Technical Association of the Pulp and Paper Industry. 1980.
3-84
-------
4. EMISSION CONTROL TECHNIQUES
This chapter describes the techniques available to control emissions
from nonfossil fuel fired boilers (NFFBs). Described in this chapter are
emission control techniques for particulate matter (Section 4.1), sulfur
dioxide (Sections 4.2 and 4.3), and nitrogen oxides (Section 4.4). Descrip-
tions of each technique include discussions of the technique's basic
operation, its development status, and its applicability to nonfossil fuel-
fired boilers. Also discussed are factors which affect the performance of
the control techniques including design parameters, operating conditions,
and fuel quality. Data obtained by approved EPA test methods are presented
to substantiate control technique performance. Data describing the
performance of the best available emission controls are summarized in a
separate section (Section 4.5). Additional information on performance test
data is presented in Appendix C.
Control systems discussed in this chapter are those meeting one of the
following criteria:
- Currently used on nonfossil fuel fired boilers or large pilot-
scale installations;
- Currently applied on fossil fuel fired boilers in the industrial,
utility, or foreign sectors.
Table 4-1 shows an approximate distribution of emission controls currently
used on nonfossil fuel fired boilers.
4.1 CONTROL TECHNIQUES FOR PARTICULATE MATTER
The control of particulate matter emissions from nonfossil fuel fired
boilers can be accomplished by using one or more of the following control
methods:
- centrifugal separation
- wet scrubbing
- fabric filtration
4-1
-------
TABLE 4-1. APPROXIMATE DISTRIBUTION OF PARTICIPATE EMISSION CONTROLS
CURRENTLY APPLIED TO NONFOSSIL FUEL FIRED BOILERS.'0
Type of Parti cul ate
Matter Control
None or No Data
Centrifugal Collectors0
Wet Scrubbers
Electrostatic Precipitators
Fabric Filters
Gravel -Bed Filtersd
Otherd
Percentage of Total for Fuel Type
Wood Bagasse
53.8 29.7
36.8 50.9
7.2 19.4
0.4
0.4
0.5
0.9
MSWe RDF6
62.5 20.0
40.0
-
37.5 40.0
-
-
-
Distribution is based on National Emissions Data System (NEDS) ,
literature, and phone survey. Boilers cofiring fossil and nonfossil fuels
are included.
Sulfur dioxide and nitrogen oxide controls have generally not applied to
nonfossil fuel fired boilers.
°This includes cyclones, multitube cyclones, and dual mechanical collectors.
In many cases these controls are preceeded by a centrifugal collector used
as a precleaner.
eMSW = municipal solid waste; RDF = refuse derived fuel.
4-2
-------
- electrostatic precipitation
- gravel-bed and electrostatic gravel-bed filtration.
Sections 4.1.1 through 4.1.5 separately discuss each of these control
techniques. Section 4.1.6 presents test data substantiating the performance
of each control technique as applied to NFFBs.
4.1.1 Centrifugal Separation (Multitube Cyclones)
4.1.1.1 Process Description. Devices using centrifugal separation to
remove particulate matter from gas streams are called cyclones or mechanical
collectors. At the entrance of the cyclone a spin is imparted to the
particle-laden gas. This spin creates a centrifugal force which causes the
particulate matter to move away from the axis of rotation and towards the
walls of the cyclone. Particles which contact the walls of the cyclone tube
are directed to a dust collection hopper where they are deposited.
In a typical single cyclone the gas enters tangentially to initiate the
spinning motion. In a multitube cyclone the gas approaches the entrance
axially and has the spin imparted by a stationary "spin" vane that is in its
path. This allows the use of many small, higher efficiency cyclone tubes,
with a common inlet and outlet, in parallel to the gas flow stream.
Figure 4.1-1 illustrates the configuration of the individual tube and an
assembly of such tubes in a multitube cyclone.
One variation of the multitube cyclone is two similar mechanical
collectors placed in series. This system is often referred to as a dual or
double mechanical collector. The collection efficiency of the dual
mechanical collector is theoretically improved over that of a single
mechanical collector.
4.1.1.2 Development Status and Applicability to Nonfossil Fuel Fired
Boilers. Fly ash collection by multitube cyclones is a well established
technology, and has been used for many years to limit particulate emissions
from industrial and utility boilers. Multitube cyclones were the most
common device used for fly ash control before stricter emission regulations
were enacted. However, where a mechanical collector alone cannot meet
applicable emission levels, in many cases they are commonly used as
precleaners prior to a more efficient control device.
4-3
-------
GAS
OUTLET
PARTICLE
DISCHARGE
GAS
INLET
Figure 4.1-1. Schematic of a multiple cyclone and detail of an individual tube.'
4-4
-------
Multitube cyclones applied to wood-fired boilers are also used to
increase overall boiler efficiency. The larger fly ash particles collected
4
by cyclones on wood-fired boilers comprise 20-90% unburned carbon and can
be re-injected into the boiler for more complete combustion. Re-injecting
the large flyash particles typically increases boiler efficiency by
1-4 percent.
Although multitube cyclones are generally applicable to control
particulate matter from any of the NFFBs, their current use is limited to
the control of particulate matter from wood and bagasse boilers. Cyclones
are rarely used on MSW and RDF boilers as the sole control device or as a
precleaner because of their relative ineffectiveness in removing fine
particulate matter.
Because of their modular configuration, multitube cyclones are
applicable to all sizes of wood- and bagasse-fired boilers. There are
several operational factors associated with these boilers that affect
mechanical collector performance and limit applicability as the sole PM
control device. These and other factors are discussed in the next section.
4.1.1.3. Factors Affecting Performance. The most important design
factors affecting performance for a cyclone are the inlet gas velocity, the
diameter of the tubes, the number and angle of axial vanes, the construction
materials, and the system pressure drop.
Most multitube cyclones are axial-gas entry units designed for gas
velocities of 25.4 to 35.6 m/sec (5,000 to 7,000 ft/min) in the entry vane
region. Such high velocities require the use of hard alloy materials for
the vanes (gray or white iron or chromehard steel) to minimize vane
6
erosion.
However, when cyclones are applied to wood-fired boilers, gas
velocities are generally limited to 21.3 m/sec (4,200 ft/min) to prevent the
breakup of the particulate into smaller particles. Figure 4.1-2 is a
theoretical curve that presents the variation of the collection efficiency
resulting from the variation of the inlet gas velocity. As shown in
Figure 4.1-2, cyclone collection efficiency usually decreases with
reductions in the inlet gas velocity below the design velocity. However,
4-5
-------
100
90
80
70
I 60
^
a;
C.
u 50
Z
LU
O
u. 40
u_
UJ
30
20
10
0
0.5 1.0 1.5 2.0
VELOCITY RELATIVE TO DESIGN CONDITION
2.5
Figure 4.1-2.
Variation of a single cyclone collection
efficiency with gas velocity.7
4-6
-------
collection efficiencies may also decrease at high gas velocities due to
plugging of the tubes or to break up of the fly ash particles.
The performance of any cyclonic device is primarily a function of the
particle size distribution of the particulate matter to be collected. As
shown in Figures 4.1-3 and 4.1-4 the collection efficiency of a cyclone
increases as the percentage of larger particles increases.
Particle collection efficiency for most cyclonic devices varies
inversely with the diameter of the collecting tube. A reduction in tube
diameter increases the radial force acting upon the particles so that their
transit to the wall region and their removal is accelerated. Figure 4.1-3
illustrates comparative collection efficiencies for two axial-entry cyclones
with diameters of 15.2 and 30.5 cm (6 and 12 inches), respectively, as a
function of the percent of dust under 10 urn. Fractional efficiency data for
multitube cyclones of different tube diameters for collecting particulate
matter from coal and oil-fired boilers are presented in Figure 4.1-4. The
affect of particle size and tube diameter on mechanical collector efficiency
for NFFBs should be the same as shown for coal or oil.
Operational procedures related to the boiler/control device system that
hamper mechanical collector performance include transient operations such as
startup, shutdown, emergency upsets and load variation. In addition, air
leakage, cyclone corrosion, particle reentrainment, tube plugging, pressure
drop and the degree of fly ash reinjection will affect mechanical collector
57
outlet emissions. Large load swings significantly affect removal
efficiency. At constant load and inlet particle size distribution, outlet
emissions will be proportional to inlet mass loading. Therefore, a large
increase in fly ash loading (which could result from variations in load,
fuel ash content, soot blowing or fly ash reinjection) will increase
emissions.
Proper mechanical collector maintenance is essential to sustaining the
desired removal efficiency. To avoid efficiency losses due to corrosion of
the cyclone from acid condensation or particle abrasion, the cyclone should
be constructed of materials that will withstand the highest expected loading
4-7
-------
100
95
30
85
8C
75
70
65
(15.2cm)
6 in.DIA.
sp.gr. OF DUST = 2 to 3
PRESSURE DROP =*3 in. WATER GAUGE
I i ' i i I I |
10 20 30 40 50 60 70
percent OF DUST UNDER 10 pm
80
Figure 4.1-3.
Typical overall collection efficiency
of axial -entry cyclones. 8
4-8
-------
100 r
X
u
4)
J
t5
V
O 6 1n.
A 10 in.
D10 1n.
V 6 in.
dia., 2.5 in.AP (Coal, test data)
dia., 2.5 in.AP (Coal, test data)
dia., 2.5 in.AP (Coal, test data)
dia., 6.0 in.AP (Oil vendor
guarantee)
10 15
Particle Diameter,
20
-v-
40
Figure 4.1-4.
Fractional efficiency data for cyclone collection of
fly ash from coal- and oil-fired electric utility boilers.9
4-9
-------
of potentially corrosive flue gas components. Primary considerations to be
used in evaluating the construction materials needed are:
- Gas temperature
- Abrasiveness of the dust particles
- Corrosiveness of the gas stream
If the gas stream is corrosive or the dust particles are abrasive it may be
necessary to use a stainless steel alloy instead of carbon steel in the
construction of the cyclone.
It is important to accurately monitor the pressure drop across the
cyclone so that any plugging can be detected. In addition, the interior
should be inspected on a regular basis for corrosion damage, plugged tubes,
or defective gaskets. Another area of maintenance that is critical to
efficient mechanical collector performance is the discuovery and remedy of
air leakage into the collector. Leakage can occur at the hopper access
door, hopper discharge valve, hopper casing, or the lower tube sheet. Air
leakage into a collector hopper can result in reentrainment or collected
particles, thus reducing collector performance.
One of the most detailed sources of information on mechanical collector
performance is a study conducted jointly by the American Boiler
Manufacturer's Association (ABMA), the Department of Energy (DOE), and EPA.
This study was performed on coal-fired boilers. However, the conclusions on
factors affecting mechanical collector performance should be applicable to
NFFBs also. Several stoker-fired boilers equipped with mechanical
collectors were tested in this study and particulate emissions tests were
conducted at both the boiler and the mechanical collector outlets. Based on
a review of this data, the following conclusions can be made about the
effect of boiler operating parameters on mechanical collector
59
performance:
- Figure 4.1-4a shows that, for three similar coals, mechanical
collector efficiency remained relatively constant with changes in
boiler load above about 60 percent. However, there was
4-10
-------
*«
>-
o
os
o
s
100"
90"
80--
70--
60"
50-'
10"
O Coal A - 7.7% Ash,13320 Btu/lb
Q Coal B* - 8.1% Ash,12869 Btu/lb
A Coal C* - 7.3S Ash,12832 Btu/lb
20 40 60
BOILER LOAD(%)
80
100
Figure 4.1-4a. Mechanical collector efficiency versus boiler load
(spreader stoker boilers).59
Note: Data shown 1s from two different boiler collector systems.
Coal A was fired In one, while coals B and C were fired In
the other .
4-11
-------
significant drop in collector efficiency at loads of approximately
50 percent and less.
There was considerable scatter in the test data for some units as
a result of variable process conditions and fuel types. The
results showed that particulate matter emissions from both the
boiler and mechanical collector (in terms of lb/10 Btu) tended to
increase as the boiler load increased. This trend can be seen in
Figure 4.1-4b where boiler and mechanical collector outlet
emissions are plotted as a function of boiler load. Although
these figures illustrate emissions from a single boiler, they are
representative of the overall trends from the data set.
Figure 4.1-4c also illustrates that controlled emissions from this
boiler remained fairly steady, but showed a trend of increased
emissions at boiler loads greater than 50 percent. This trend was
also seen for other boilers. The sharp increase in emissions at
very low loads was attributed to the reduced mechanical collector
efficiency at the unusually low firing rate obtained at this one
site.
In general, no significant correlations were observed between
mechanical collector performance and overfire air levels, or
excess air levels.
The data did show that mechanical collector collection efficiency
was lower when there were relatively high percentages of small
particles (less than 10 microns in diameter) at the inlet to the
collector. However, no correlations were observed between boiler
load, excess 0?, or overfire air levels and the resulting particle
size distribution.
4-12
-------
10.0-
3
•M
CO
10
O
I/)
c
O
8.0_
6.0 -
3
O
s_
(O
n.
•o
01
O
u
4.0 -
2.0 -
Boiler Type: Spreader Stoker 75,000 Ib/hr steam
Coal Properties:
O- 8.04% Ash, 12869 Btu/lb
+- 4.42% Ash, 13860 Btu/lb
A- 7.32% Ash, 12832 Btu/lb
SHADED AREA EMPHASIZES THE DATA TREND
20
40
I
60
80
T
100
Boiler Load
(% of rated capacity)
Figure 4.1-4b. Uncontrolled particulate emissions versus boiler load.
10
4-13
-------
1.0-1
us
o
£ 0.8 J
01
4->
15
s-
.0
Q-
O
t-
0.6 H
0.4 -I
0.2 -I
Boiler Type: Spreader Stoker
Coal Properties:
75,000 Ib/hr steam
O- 8.04% Ash, 12869 Btu/lb
-t~ 4.425! Ash, 13860 Btu/lb
A- 7.32% Ash, 12832 Btu/lb
A
CD
SHADED AREA EMPHASIZES THE DATA TREND
-------
4.1.2 Wet Scrubbing
4.1.2.1 Process Description. A wet scrubber is a collection device
which uses an aqueous stream or slurry to remove particulates and/or gaseous
pollutants.
There are three basic mechanisms involved with collecting particulate
in wet scrubbers. These mechanisms include the interception, inertial
impaction and diffusion of particles on droplets. The inertial impaction
and interception effects dominate at large particle diameters, while the
diffusion effects dominate at small particle diameters.
Scrubbers are usually classified by energy consumption (in terms of
gas-phase pressure drop). Low-energy scrubbers, represented by spray
chambers and towers, have pressure drops less than 1.3 kPa (5" of water).
Medium-energy scrubbers such as impingement scrubbers have pressure drops of
1.3-3.7 kPa (5-15" of water). High-energy scrubbers such as high-pressure
drop venturi scrubbers have pressure drops exceeding 3.7 kPa (15" of water).
The most common scrubbers used for "moderate" removals of particulate matter
are medium-energy impingement and venturi scrubbers. Greater removals of
particulate matter are usually achieved with high-energy venturi scrubbers.
A typical impingement scrubber, also known as an orifice, self-induced
spray, or entrainment scrubber, is shown in Figure 4.1-5. This scrubber
features a shell that retains liquid so that gas introduced to the scrubber
impinges on and skims over the liquid surface to reach the gas exit duct.
Atomized liquid is entrained by the gas and acts as a particle collecting
and mass transfer surface. Particle collection results from inertial
impaction caused by both the gas impinging on the liquid surface and by the
gas flowing around the atomized drops.
Venturi scrubbers are rapidly gaining widespread popularity, especially
12
in view of the current emphasis on the collection of submicron particles.
In a typical venturi scrubber, which is illustrated in Figure 4.1-6, the
particle-laden gas first contacts the liquor stream in the core and throat
of the venturi section. The gas and liquor streams then pass through the
annular orifice formed by the core and throat, atomizing the liquor into
droplets which are impacted by particles in the gas stream. Impaction
4-15
-------
Clean Gas Out
Swirl Vane
Particle Laden
Gas In
Liquid Bath-
Ash Laden Liquor
ist Elimination
Chamber
iser Duct
Adjustable Slide Gates
Figure 4.1-5. Schematic.qf a typical impingement
scrubber
4-16
-------
CLEAN GAS
OUT
PARTICLE
LADEN GAS
IN
LIQUOR IN—»
VENTURI THROAT
CYCLONE SEPARATOR FOR MIST
ELIMINATION (Possibly equipped
with an internal mist eliminator)
ASH LADEN
LIQUOR
Figure 4.1-6. Variable-throat venturi scrubber.
4-17
-------
results mainly from the high differential velocity between the gas stream
and the atomized droplets. The droplets then are removed from the gas
stream by centrifugal action in a cyclone separator and (sometimes) mist
14
elimination section.
Corrosive species in the flue gas (e.g., S02, S03, and HC1) will be
absorbed to some extent into the scrubbing liquor. In some particulate
scrubbers recirculation of low pH (pH less than 3) liquors have caused
corrosion problems. Consideration must therefore be given to the construc-
tion materials used in the contactor. Fiberglass reinforced polyester or
rubber-lined steel are the most commonly-used materials. These materials
are also resistant to the errosive effects of the slurries which must be
handled in wet scrubbing systems.
A common operating technique used to prevent low pH conditions is the
addition of an alkali compound. The addition of an alkali compound to the
wet particulate scrubber for pH control results in the recirculation of a
scrubbing slurry with sufficient dissolved alkalinity to absorb significant
amounts of SCL from the flue gas, thus forming a combined particulate
matter/SO,, removal system. For example, if sodium carbonate (Na2C03) is
used as the chemical for pH neutralization, the overall chemical reaction
that occurs is the following:
Na2C03 + S02 •* Na2S03 + C02 (4.1.2-1)
Alternative flue gas desulfurization processes are described in Section 4.2.
4.1.2.2. Development Status and Applicability to Nonfossil Fuel Fired
Boilers. Particulate control by wet scrubbing is a well-established
technology. The use of wet scrubbers in Great Britain for cleaning boiler
flue gases dates back to 1933. However, this technology has only been
adapted within the last 20 years to control fly ash emissions from
industrial boilers in the U.S. Since the early 1960s, wet scrubbing has
been applied to fossil fuel-fired boilers in the U.S. for combined
particulate collection and S02 absorption. As reported in Section 4.2.1,
4-18
-------
four NFFBs cofiring wood and fossil fuels use wet scrubbing for both PM and
S02 removal.
Wet scrubbers are widely used to remove particulate matter from wood
and bagasse boiler flue gases. Scrubbers applied to these boilers are often
installed downstream of multitube cyclones. No successful scrubber
applications to MSW or RDF boilers exist: the fine particulate in these
boiler exhausts can be removed only by very high-energy scrubbers which must
be constructed of expensive corrosion-resistant materials. The only MSW
boiler that used a wet scrubber replaced the scrubber with an electrostatic
precipitator.
4.1.2.3. Factors Affecting Performance. Factors that affect the
performance of typical wet scrubbers are:
- contacting power (gas phase pressure drop and liquid nozzle
pressure drop)
- liquid to gas ratio (L/6)
- carry out of scrubber liquor
- particle size distribution
- PM grain loading in gas.
The contacting power of the wet scrubber is usually the major factor
affecting particulate removal. In most scrubber applications the
contacting power is measured by the gas phase pressure drop. As shown by
Figures 4.1-7 and 4.1-8, removal efficiency increases with increasing gas
phase pressure drop: greater pressure drops create smaller liquid drops
that are more efficient in collecting PM. In certain types of wet scrubbers
(such as ejector venturi scrubbers) atomization of the liquid is accom-
plished using a high pressure spray. For these types of scrubbers, the
contacting power is indicated by the liquid nozzle pressure drop and not the
gas phase presure drop.
High-pressure drop scrubbers may show reduced removal efficiency due to
18
carry out of particulate-laden scrubber liquor droplets. These droplets
evaporate and release the suspended particulate matter back into the flue
gas. High-pressure drop scrubbers should thus be equipped with mist
eliminators to ensure adequate separation of the gas and liquid droplets.
4-19
-------
COLLECTION EFFICIENCY VS PARTICLE SIZE
99.90
98.95
99.90
99.80
99.60
99.00
98.00
95.00
90.00
80.00
100
PARTICLE DIAMETER IN MICRONS
Figure 4.1-7.
Impingement scrubber fractional efficiency curves
(Courtesy of the Western Pricioitation Division
of Joy Manufacturing Company)11
4-20
-------
COLLECTION EFFICIENCY VS PARTICLE SIZE
10
S.O
PARTICLE DIAMETER IN MICRONS
95.00
90.00-
80.00,
10.0
Figure 4.1-8. Venturi scrubber fractional efficiency curves
(Courtesy of the Western Precipitation Division
of Joy Manufacturing Company)17
4-21
-------
Where once through scrubbing liquid is used, the efficiency reduction is not
likely to be as large since the percentage of solids in the liquor is
generally lower than when recycled scrubbing liquor is used.
If the liquid rate to the scrubber is sufficient to completely sweep
the gas stream with droplets without flooding the scrubber, scrubber
performance is relatively insensitive to variations in the liquid-to-gas
19
ratio. Increases in the L/G generally increase scrubber efficiency but
the performance increases are usually small. Figure 4.1-9 illustrates the
impact on removal efficiency of changes in L/G for a venturi scrubber
operating at a given pressure drop and two different liquid-to-gas ratios.
As shown in Figures 4.1-7 through 4.1-9, scrubber performance depends
on the particle size distribution of the PM to be collected. These figures
show that collection efficiency varies directly with particle size, with
larger particles collected at greater efficiency.
Scrubber performance'also depends on the PM grain loading. PM loadings
exceeding the scrubber design loading could overload the scrubber and reduce
PM removal efficiency. Scrubber efficiency could be improved by increasing
the gas velocity (or pressure drop) and L/G. Alternatively, precleaners
such as cyclones could be used upstream of the scrubber to reduce the PM
loadings to the scrubber.
Venturi scrubber applications generally include a variable throat
system (enabling control of pressure drop) to enable a constant efficiency
20
to be maintained at varying boiler loads. Impingement scrubbers similarly
allow control of pressure drop by adjusting the peripheral gas nozzle.
Pressure drops across venturi throats generally range from 1.5 to 7.5 kPa
(6 to 30 w.c.) in boiler applications. Gas velocities through the venturi
throat may range from 61 to 183 m/s (200 to 600 ft/s) while liquid-to-gas
ratios (L/G) vary from 1.0 to 2.0 liters/m3 (8 to 15 gal/1000 ft3).21
Pressure drops in impingement scrubbers range from about 0.8 to 4 kPa (3 to
2
16 in. w.c.) while L/Gs vary from about 0.4 to 1.3 liters/m (3 to
10 gal/1000 ft3).
4-22
-------
0.1
0.5 1234
10
o
o
£
•p
O)
O)
Q.
OJ
CO
Q-
100
50
40
30
20
10
5
4
3
2
1
L/G=0.7VrrT
(5 gal/1000
acf)
L/G=2.0Vm
(15 gal/1000
acf)
100
50
40
30
20
10
4
3
0.1
0.5 1234
10
Aerodynamic particle diameter,//m
Reference 19.
Gas phase pressure drop for both scrubbers is 2.5kPa (10 in. w.c.)
cParticle penetration is 100 - Particle removal efficiency.
Figure 4.1-9. Venturi scrubber fractional efficiency curves for
scrubbers operating at different liquid-to-gas ratios.3'
4-23
-------
4.1.3 Fabric Filtration (Baghouses)
4.1.3.1 Process Description. A typical baghouse is portrayed in
Figure 4.1-10. As the inlet gas passes through the fabric filters, dust
particles in the inlet gas are retained on the fabric filters by inertial
impaction, diffusion, direct interception, and sieving. The first three
processes prevail only briefly during the first few minutes of filtration
with new or recently cleaned fabrics, while the sieving action of the dust
layer accumulating on the fabric surface soon predominates. This is
3 3
particularly true at high dust loadings, greater than 1 g/m (0.437 gr/ft ).
The sieving mechanism leads to high efficiency collection unless defects
23
such as pinhole leaks or cracks appear in the filter cake.
In fabric filtration both the collection efficiency and the pressure
drop across the bag surface increase as the dust layer on the bag builds up.
Since the system cannot continue to operate with an increasing pressure
drop, the bags are cleaned periodically. Cleaning typically occurs in one
of three ways. In shaker cleaning, the bags are oscillated by a small
electric motor. The oscillation shakes most of the collected dust into a
hopper. In reverse flow cleaning, backwash air is introduced to the bags to
collapse them and fracture the dust cake. Both shaker cleaning and reverse
flow cleaning require a sectionalized baghouse to permit cleaning of one
section while other sections are functioning normally. The third cleaning
method, reverse pulse cleaning, does not require sectionalizing. A short
pulse of compressed air is introduced through venturi nozzles and directed
from the top to the bottom of the bags. The primary pulse of air aspirates
secondary air as it passes through the nozzles. The resulting air mass
expands the bag and fractures the cake.
4.1.3.2 Development Status and Applicability to Nonfossil Fuel Fired
Boilers. Fabric filtration is a well established technology with early
industrial process applications dating back to the late 1800s. However,
application to boiler flue gas has been a recent development with the first
successful installations designed in the later 1960s and early 1970s.
Few full-scale baghouses have been applied to nonfossil fuel fired
boilers. About seven baghouses are installed on wood-fired boilers but no
4-24
-------
Upper Nozzle or Venturi
plenum orifice nozzle
Solenoid Compressed
valve air supply
/ at 100 psig •
Exhaun
outlet.
--Collars
-Induced
Discharge
Figure 4.1-10. Schematic of a typical pulse-jet fabric filter baghouse
(Courtesy of Mikropul Corporation)22
4-25
-------
baghouse applications exist on bagasse, MSW, or RDF boilers. However, one
baghouse operates successfully on an MSW incinerator. The principal
drawback to fabric filtration, as perceived by potential users, is a fire
danger arising from the collection of a combustible carbonaceous fly
ash.24-27
Two of the seven baghouses successfully applied to wood-fired boilers
77 30
collect fly ash that is mainly salt (up to about 70%). (As described
in Chapter 3, high salt fly ash is emitted from the combustion of salt-laden
wood. Salt-laden wood or wood waste results from the storage of logs in
salt water.) This type of fly ash may pose a smaller fire threat due to a
quenching effect of the salt.
Three of the five baghouses collecting non-salty fly ash from wood-
fired boilers are operating successfully and have experienced no baghouse
fires. The other baghouses collecting non-salty, highly carbonaceous fly
ash are now operating successfully but both of these baghouses have
previously experienced baghouse fires.
One of the baghouses that has experienced fires is used on a very small
wood-fired boiler (0.1 MW or 0.4 x 10 Btu/hr on a steam out basis). The
other baghouse that has experienced fires is used on a larger spreader
stoker wood-fired boiler.
Although the baghouse on the spreader stoker is now operating
pc
successfully, two fires earlier resulted in extensive damage to the
baghouse and bags. The first fire resulted from the contact of carbonaceous
ash with air leaked into the baghouse from the pneumatic ash conveying
system. This fire hazard was eliminated by locating the air fan downstream
of the baghouse, so that the conveyor air pipe was at lower pressure at the
baghouse ash hopper valve relative to the pressure in the baghouse. The
second fire resulted from the contact of air with hot carbonaceous fly ash
accumulating in the baghouse hopper. This fire hazard has been reduced by
improved operating procedures that monitor ash buildup. The current
operation of the baghouse without fires can be atrtributed to:
4-26
-------
- water quenching the gas stream upstream of the baghouse
- minimizing the in-leakage of air to the hot carbonaceous
fly ash
- establishing a filter cleaning sequence that prevents
the build-up of a thick filter cake
- bypassing the baghouse during the intermittent operations of
sootblowing and cyclone cleaning, when sparks are likely to
reach the baghouse
- removing large burning particles of fly ash in multitube
cyclone precleaners.
A pilot baghouse formerly used on an MSW-fired boiler also had fires.
That baghouse also experienced bag blinding during startup and during
25
periods when the flue gas moisture content was unusually high. As
described below bag blinding can be avoided by careful design and operation.
In addition to the steps taken above to reduce fire hazard, a baghouse
owner may add special fire protection measures. The baghouse can be fitted
with a sprinkler system to quench the baghouse and bags when fire occurs.
Although the bags will need to be replaced after a quench, major structural
damage may be avoided. A special protection system may also be added to
quench sparks before they reach the baghouse. Such a system consists of a
flame detector and a supply of extinguishing agent such as water, steam, or
carbon dioxide. The extinquishing agent is applied only long enough to
32-33
quench sparks. Although the above measures seem likely to reduce fire
danger, they have not been demonstrated in NFFB applications.
4.1.3.3 Factors Affecting Performance. The most important design
factor for a baghouse is the air-to-cloth ratio (A/C). This parameter
relates the volume of gas filtered (m /min or acfm) to the available
2 2
filtering area (m or ft ). This is, in effect, the superficial velocity of
the gas through the filtering media. Air-to-cloth ratios for the pulse jet
cleaning systems applied to wood-fired boilers range from 0.9-1.5 m/min
(3-5 ft/min).26"30
Baghouse outlet loading does not vary greatly as a result of changes in
gas flowrate for a given boiler application. As the flowrate is reduced
4-27
-------
from the design rate (presumably the flow at rated capacity) the A/C
decreases. Filtration generally improves with decreasing A/C, especially if
the unit collects substantial quantities of small particles and the cleaning
o C
cycle is triggered by attainment of a predetermined pressure drop. Hence,
a baghouse that meets specifications at the design flowrate should have
equal or lower outlet grain loadings at reduced flowrates.
Fabric filters can operate at efficiencies greater than 99.9 percent
oc
with pressure drops of 0.5 to 1.5 kPa (2 to 6 in w.c.). Increases in the
pressure drop may imply that more frequent cleaning is needed.
During baghouse operation it is essential that baghouse temperatures be
maintained above the water dewpoint of the gas so that condensation will not
occur on the compartment walls and filter surfaces. In the latter case,
resultant plugging or blinding may restrict gas flow and cause irreversible
bag damage. This is most likely to occur during transient operations such
as startup, shutdown or fluctuating loads. If acid condensation occurs
after shutdown, the acid mist moisture eventually evaporates and
crystallization on the bag filter may occur. In this situation, the bag
filter may become brittle and subject to cracking when stress is once again
applied. Bypassing or preheating the baghouse prior to system startup,
continuous gas recirculation during brief shutdowns, and/or sufficient
34
insulation on the baghouse and duct should minimize condensation problems.
Bag material is chosen to withstand the specific flue gas environment
expected to be encountered. Mechanical strength is also an important factor
with respect to the mechanical demands exerted on the fabric by the gas flow
30
and cleaning system. Acidic species such as S02 and HC1 attack Nomex.
Although many of the baghouse applications on wood-fired boilers use Nomex
material, fiberglass or Teflon-coated fiberglass is recommended because of
27 28 30
the acidic chlorides possibly present in the flue gas. ' '
In general, although nonwoven fabrics (i.e., felt) are the most
efficient particle collectors, they are the most difficult to clean.
Texturized filament fabrics (i.e., teflon coated fiberglass) represent a
middle ground in cleanability, durability and efficiency.
4-28
-------
Most fabrics are efficient in collecting a wide range of sub-micron
particles. Emission tests conducted on a 63,100 kg steam/hr (139,000 Ib
steam/hr) spreader stoker firing coal equipped with a reverse-air fabric
filter demonstrated that for particles in the 0.02 to 2 micron range, fabric
63
filter fractional efficiency did not fall below 99.9 percent.
4.1.4 Electrostatic Precipitation
4.1.4.1 Process Description. Particulate collection in an electro-
static precipitator occurs in three steps: suspended particles are given an
electrical charge; the charged particles migrate to a collecting electrode
of opposite polarity while subjected to a diverging electric field; and the
collected particulate matter is dislodged from the collecting electrodes.
Charging of the particles to be collected is usually caused by ions
produced in a high voltage d-c corona. The electric fields and the corona
necessary for particle charging are provided by high voltage transformers
and rectifiers. Removal of the collected particulate matter is accomplished
mechanically by rapping or vibrating the collecting electrodes.
Figure 4.1-11 shows a cross-sectional view of a typical ESP.
4.1.4.2 Development Status and Applicability to Nonfossil Fuel Fired
Boilers. Electrostatic precipitator technology is commercially developed
and dates back to the early 1900s. ESPs treating flue gas flow rates as low
3 37
as 8500 m /hr (5000 acfm) are commercially available. Because of their
modular design, ESPs can be expanded to treat flue gas from even the largest
industrial boilers. ESPs have been installed on utility boilers with flue
gas flow rates as high as 10,000,000 m /hr. Application of an ESP to an
industrial boiler should have no adverse effect upon boiler operation.
However, boiler operation can have a significant impact upon ESP
performance.
The suitability of particulate collection by electrostatic precipi-
tation depends primarily on the resistivity of the particles. Particles
i s\
38
with resistivities in the range of 5 x 10 to 2 x 10 ohm cm have been shown
by experience to be the most suitable for electrostatic precipitation.'
Particles with lower resistivities will give up their charge too easily and
will be re-entrained in the gas stream. Particles with higher resistivities
4-29
-------
CO
o
BUS DUCT
RAPPER INSULATOR
HIGH 'VOLTAGTSYSTEM
SUPPORT INSULATOR
COLLECTING SURFACE
RAPPER
INSULATOR
COMPARTMENT
TRANSFORMER
RECTIFIER
GAS
DISTRIBUTION
OEVICE
DISCHARGE ELECTRODE
RAPPER
Figure 4.1-11. Typical precipitator cross section.
-------
will coat the collecting plates and will be hard to dislodge. The plates
will thus have diminished ability to attract charged particles.
Electrostatic precipitators are currently used on boilers fired with
wood, MSW, or RDF. No ESPs have been applied to bagasse-fired boilers.
ESPs applied to wood-fired boilers are sometimes used downstream of cyclone
precleaners while ESPs on MSW- or RDF-fired boilers are usually the only
particulate control device.
4.1.4.3 Factors Affecting Performance. The performance of ESPs
depends on 1) amount of available collecting surface, 2) gas flow rate,
3) particulate resistivity, 4) particle size distribution, 5) gas velocity
distribution, 6) rapping intensity and frequency, and 7) electrical field
strength. Because the individual effects of these factors on ESP perfor-
mance are difficult to model, ESP performance is typically predicted from an
empirical three-parameter equation. Classically, the performance of LSPs
has been predicted with the Deutsch-Anderson equation:
n = 1 - exp [ - We(A/V)] (4.1.4-1)
where r\ = collection efficiency
W = average migration velocity, ft/m
3
V = gas flow rate, ft /m
2
A = collecting plate area, ft .
The ratio A/V is known as the specific collection area (SCA) and is usually
23 2
expressed in m /(m /s) or ft /1000 acfm. Practical values of SCA range from
20 to 160 m2/(m3/s) (100 to 800 ft2/1000 acfm) for most field applica-
41
tions. SCA is an important design and operating parameter for an ESP.
Collection efficiency improves as SCA increases, but the ESP becomes larger
and more expensive.
The average migration velocity or precipitation rate is a function of
particle size distribution and resistivity, gas velocity distribution,
rapping intensity and frequency, and electrical field strength.
Figure 4.1-12 shows the dependence of precipitation rate on particle
4-31
-------
0.6
0.4
0.3
H 0.2
u
HI
C 0.1
a.
10"
10
10
10'
15.2 „
U
12.2 f
9.1 §
6
U
UJ
10'
RESISTIVITY, ohm-em
Figure 4.1-12.
Relationship of particle
resisijvity and precipitation
rate.1*3
0.5 1.0 1.5 2.0 2.5 3.0 3.5
COAL SULFUR, percent
Figure 4.1-13.
Fly ash resistivity versus
coal sulfur content for
severaLnflue gas temperature
bands. u
4-32
-------
resistivity. Figure 4.1-13 is an example of the dependence of fly ash
resistivity on temperature and fuel sulfur content.
Data available on the resistivities of nonfossil fuel fly ashes are
reported in Figure 4.1-14 and in Table 4.1-1. Although the resistivity data
generally support the suitability of particulate collection by electrostatic
precipitation, a few limitations exist. Wood fly ash containing a large
amount of salt could have unsuitably high resistivities at temperatures
below 506 to 533K (450-500°F) if the gas moisture content falls below
42
10 percent. Similarly, wood or RDF cofired with low sulfur fossil fuels
could have unsuitably high resistivities, depending on the resistivity of
the coal fly ash. In cofiring wood with a fossil fuel, ESP sizing depends
mainly on the fossil fuel fly ash resistivity if the fossil fuel is low in
42
sulfur since the wood fly ash is relatively easy to collect. Cofiring RDF
with low sulfur coal is potentially a more difficult precipitation
application because both the coal and the RDF have high resistivities.
In many cases, field data indicate lower ESP efficiencies than
predicted by the Deutsch-Anderson relationship. To account for the observed
43
particle collection levels, White designates the empirical relationship:
n = 1 - exp [ - (wk A/V)°'5] (4.1.4-2)
as a more realistic predictor of particulate collection efficiency. The
exponent, 0.5, is applicable when the ESP system is handling coal fly ash.
In Equation 4.1.4-2, the term w. is an "effective" migration velocity
computed from experimental measurements. Use of this parameter results in a
better estimate of SCA at high removal efficiencies.
Figure 4.1-15 shows how the precipitation rate varies with gas
temperature. The variation occurs due mainly to the effects of temperature
on fly ash resistivity. Figure 4.1-16 shows how the field strength and gas
flow affect the precipitation rate.
After the precipitation rate parameter has been determined from
resistivity and other studies, the Deutsch-Anderson equation or a modified
4-33
-------
i ] i i i r
10"
•io10
n
100 200 300 400 500 600 700
Temperature, °F
Figure 4.1-14. Electrical resistivity of fly ash from
three MSW incinerators and boilers.
4-34
-------
TABLE 4.1-1. ELECTRICAL RESISTIVITY DATA FOR NONFOSSIL FUEL FIRED BOILERS9'42'45'49
Nonfossil fuel
Bark
Bark*
Barkb
Bark
Bark
Bark
Bark
MSN
MSW
RDF
RDF
RDF
RDF
RDF
RDF
Auxiliary fuel
None
None
None
None
None
None
LSCC
None
None
LSC
LSC
LSC
LSC
LSC
HSC9
NFF-% fuel input
100
100
100
100
100
100
^50
100
100
8
10
4-5
10
9-27
-\40
Tempera ture,°F
— _
_ —
__
__
_-
212-572
300-400°Fd
__
__
__
__
__
— —
Resistivity, ohm -cm
106 - 10l
1.7 - 105
9.6 x 109
1.4 x 106
9.6 x 10s
8.4 x 107
1010- 1013
106 -5x 1012
3x 108e/5x 106f
2 x 1011
5.3 x 1010
4.2 - 17 x 1010
1.8 x 1011
4-6 x 1011
1.05 x 108
co
en
Bark entering primary mechanical collector.
Bark entering secondary collector.
cLow sulfur coal, % sulfur = 0.6 - 1.1%.
Temperature range for maximum resistivity.
eCoarse material.
Fine material.
9High sulfur coal, % sulfur = 4.15%.
-------
14
U
V
•£ ia
u
* 10
u
T
§ 8
s.
tl
& 8
g
200
300
400
900
800
Cu Temperature. *F
Figure 4.1-15.
Variation in precipitation rate
parameter with gas temperature in
European ancUU.S. MSW incinerators
and boilers.
(1)
4-1
i.
CL
m boiler firing bark and low sulfur
coal*'
4-36
-------
equation can be used to predict the SCA needed to attain desired particulate
matter removals.
The relationship between collection efficiency and SCA is illustrated
in Figures 4.1-17 and 4.1-18. Figure 4.1-17 shows the relationship between
efficiency and SCA for removing fly ash from coal-fired boiler flue gas.
Figure 4.1-18 shows the experimentally determined relationship between
efficiency and SCA for removing fly ash from a bark/coal cofired boiler flue
gas. Another boiler cofir-'ng bark and low sulfur coal (25 percent bark) is
2 3
designed to achieve 99 percent removal at an SCA of 60 m /(m /s)
(300 ft2/1000 acfm).53 Pilot tests of an ESP on a wood-fired boiler showed
2 3
a removal efficiency of 90.6 percent at an SCA of 40 m /(m s)
(200 ft2/1000 acfm).42
The actual collection area during ESP operation depends on the flue gas
flow rate which, for a particular boiler, is dependent on boiler load. The
operating SCA increases as boiler load decreases, provided all ESP fields
remain charged. Thus, the ESP must be designed to have the desired SCA at
maximum boiler load where the flue gas flow is the highest.
The configuration and type of electrodes used in an ESP directly
influence ESP performance. The electrode plate spacing, height, and length
all influence the electrostatic forces exerted on the flue gas particles and
thus influence the collection efficiency. Proper design of the ESP
electrodes assures adequate residence time to allow the particles to migrate
to a collection electrode.
Another key design variable is proper determination of the rapping
cycle. If the cycle is too short, material that collects on the plates will
not be compacted enough to settle to the bottom of the precipitation chamber
and will be reentrained. This reentrainment can be minimized by proper
design of collecting electrodes and rappers, minimizing rapping and rapping
only a small section of the total precipitator plate area at a time. If the
time between rapping is too long, however, the material on the collecting
plates will become too thick and collection efficiency will be reduced. In
addition, the rapping cycles must account for the differences in the amount
of particulate matter collected in different ESP sections. ESP's typically
4-37
-------
99.0
;M.O
580.0
s
70.0
50.0
C3AC SULfUR PSSCS.NT
3 2.5 2 1.5 1 0.5
LLL/77
11////
ii////
5080 10160 1S240
(100) (200) '3001
SCA. m> /(nr» lit (ft» /1000 cfml
20330
Figure 4.1-17. Relationship between collection
efficiency and SCA foe-various
coal sulfur contents.
O)
c
o
4J
U
OJ
*0
100.0
99.9
99.3
99.7
99.6
99. S
99.4
99.3
99.2
99.1
99.0
98.9
Swdflc coMtetlon
MO J20 140 260 380 «0 *20 "0 460 «80 500 520
I i I
900 1000 1100 1200 1300 1400 1500 1SOO 1700 1800
Specific collection artt, is2/1000 n3
Figure 4.1-18. Pilot ESP particulate matter removal
versus specific collection area for
boiler firing bark and low sulfur coal.47
4-38
-------
use multiple sections in series. The section which treats the flue gas
first will collect more particles than subsequent sections. The rapping
cycles must be adjusted to insure each section is rapped only when the
collected material is the proper thickness. This necessitates more frequent
cleaning cycles for the sections closest to the flue gas inlet.
Gas flow distribution also has a strong impact on ESP efficiency. Poor
flow distribution between the collecting electrodes results in differing gas
flow rates between each plate and therefore differing efficiencies for each
section of the ESP. In addition, high velocities in the vicinity of hoppers
and collecting electrodes can result in reentrainment of collected dust.
Another distribution consideration is the avoidance of flue gas flow through
certain areas of the ESP. The construction of an electrostatic precipitator
is such that nonelectrified regions exist in the top of the precipitator
where the electrical distribution, plate support and rapper systems are
located. Similarly, portions of the collection hopper and the bottom of the
electrode system contain nonelectrified regions. Particulate-laden gas
streams flowing through these regions will not be subjected to collection
forces and will tend to pass through the precipitator uncollected. Gas
flow distribution problems can be corrected by proper inlet design, such as
adding straighteners, plitters, vanes, and diffusion plates to the duct work
before the ESP and by internal baggies and flow restrictors.
The voltage applied to the ESP electrodes is also an important factor
affecting performance. Proper voltage assures an adequate corona for
112
charging the particles while minimizing problems of sparking. The use of
automatic power supply control is desirable in many applications because of
the varying fly ash and flue gas properties brought on by varying boiler
loads and fuel properties. Automatic controls allow the ESP to respond more
64
effectively to these changes by reducing sparking and current loss.
4.1.5 Gravel-bed and Electrostatic Gravel-bed Filtration
54"
4.1.5.1 Process Description. Gravel-bed and electrostatic
gravel-bed filters remove particulate matter from gas streams in a dry form
using a moving bed of filter media. Electrostatic filters additionally
feature an electrically-charged grid within the gravel bed to augment
4-39
-------
collection by impaction. A typical electrostatic gravel-bed filter is shown
in Figure 4.1-19.
The gravel-bed filter or electrostatic gravel-bed filter consists of
two concentric louvered cylindrical tubes contained in a cylindrical vessel.
The annular space between the tubes is filled with pea-sized gravel media.
Particulate-laden gas enters the filter through breeching and is distributed
to the filter face by a plenum section formed by the outer louvered cylinder
and the vessel wall. Particulate matter is removed from the gas stream by
impaction with the media. The PM-laden media exits the bottom of the
gravel-bed vessel and is pneumatically conveyed to a de-entrainment vessel
through a vertical lift pipe. The particulate matter is removed from the
gravel media by the abrasion of media as it is conveyed up the lift pipe, by
the scrubbing action of the air as it lifts the media, and by a rattler
section in the de-entrainment vessel. The gravel media falls from the
conveyor air stream by gravity and is returned to the filter bed. The
separated PM is air conveyed to a storage 'silo where it is removed from the
air stream by fabric filtration.
4.1.5.2 Development Status and Applicability to Nonfossil Fuel
Fired Boilers. The first gravel-bed filter was installed on a wood-fired
boiler in 1974. About 18 gravel-bed filters are now operating on wood-fired
boilers. The first electrostatic gravel-bed was a retrofit of the first
gravel-bed in 1978. Eight electrostatic gravel-bed filters are currently in
operation on nonfossil fuel fired boilers. The fuels that electrostatic
gravel-bed filters have been applied to include MSW, salt-laden wood, wood,
and wood/coal and wood/oil mixtures. Electrostatic gravel bed filters
should also be applicable to bagasse- and RDF- fired boilers. New
installations will almost certainly feature the electrically-charged grid
because of its enhanced particulate removal efficiency. The enhanced
removal due to the applied grid voltage is illustrated in Figure 4.1-20.
4.1.5.3 Factors Affecting Performance. Very little data are available
to assess the factors affecting the performance of gravel-bed filters and
4-40
-------
TO PARTIOJLATE »
SEPARATION AND STORAGE SYSTEM
CLEAN GAS
EXHAUST
DE-EXTRAINMENT
VE
ELECTRICALLY-CHARGED
MEDIA MORCULATION CONTROL VALVE
CONTROL
ADI OFF
CONTROL
A010IT.
•LVALVE
STOPS MEDIA
FLOW LIFT MR OFF
DIRTY MEDIA FROM
EtECTlOSCMIBBE*
MODULE
-DIRTY MEDIA TO
OE-ENDMINMENT
VESSEL
ELECnoSCaUBBOl
Figure 4.1-19.
TM
Schematic of an Electroscrubber , electrostatic grapular
filter (Courtesy of Combustion Power Company, Inc.)54
4-41
-------
electrostatic gravel-bed filters. The principal factors affecting
performance are:
- the grid voltage
- the particle size of the particulate matter
- the air/media ratio
- the pressure drop across the media
- the extent of particulate separation from the spent media.
The effects of the first two factors are shown in Figure 4.1-20. Particle
collection efficiency decreases with decreasing particle size and decreasing
grid voltage. Based on theoretical considerations and on data for other PM
control devices, particle collection efficiency should increase with
decreasing air/media ratios and increasing gas-phase pressure drop.
Specific data demonstrating these effects for gravel-bed and electrostatic
gravel-bed filters are unavailable.
4.1.6 Performance of Particulate Matter Control Techniques
This section presents emission test data substantiating the performance
of particulate matter control techniques. Only data obtained by approved
EPA test methods and meeting established criteria for acceptability are
presented to substantiate control technique performance. A more detailed
discussion of each test shown is presented in Appendix C. Criteria for
determining the acceptability of test data are also presented in Appendix C.
The nonmenclature used to identify the tests consists of two letters
followed by a number. The two letters identify the facility. The number
identifies the test performed at the facility. Tests performed at the same
facility on different boilers or at different locations (i.e. before and
after a wet scrubber) on the same boiler have the same two letter designator
but followed by different numbers. The first letter of the two letter
designator also specifies the fuel type. These are as follows:
- A or B indicates wood-fired or wood/fossil fuel cofired
- D indicates bagasse-fired
- F indicates MSW-fired
- H indicates RDF-fired or RDF/coal cofired
4-42
-------
100
90
§ 80
60
SO
20 K VOLTS
15 K VOLTS
10 K VOLTS
0 VOLTS
~3 A A I?1 Z 3 4 S
PARTICLE AERODYNAMIC DIAMETER (MICRONS)
10
Figure 4.1-20. Fractional collection efficiency curves for the
Electroscrubber , electrostatic granular filter
(Courtesy of Combustion Power Company, Inc.)
4-43
-------
Each emission test consists of one or more test runs with the majority
of the tests presented consisting of three test runs. An arithmetic average
of the test runs is also presented for each test.
Also presented with the emission data are available data on the boiler,
control devices, and the fuel composition. As discussed in Chapter 3
several variables can affect uncontrolled emissions, and hence controlled
emissions. These factors are boiler type, fuel type, and boiler operation.
Information on these factors is presented for each test. All of the tests
indicate the boiler type and as much information as is available on the
fuel. Boiler operation factors shown include load factor (percent of rated
capacity) and oxygen content of the flue gas.
A NFFB with an excess air level of 50 percent would have about a
7 percent oxygen content in the flue gas assuming no leakage of air into the
flue gas. At 100 percent excess air the oxygen content would be about
10.5 percent. The oxygen contents shown in the figures provide a rough
basis of comparison of the amounts of excess air present during testing.
The comparisons are rough since the measured oxygen concentrations do not
distinguish between excess air to the furnace and air leakage into the flue
gas after the furnace.
This section presents test data on different control devices which were
designed to achieve varying emission levels. Particulate matter control
techniques representing the most efficient controls for each fuel type are
presented in Section 4.5.
4.1.6.1 Performance of Particulate Matter Control Techniques
on Wood-Fired and Wood/Fossil Fuel Cofired Boilers. This section presents
the available performance data on particulate matter emission controls
applied to boilers firing wood or cofiring wood and fossil fuels.
The most common type of wood-fired boiler is the spreader stoker, and
most of the available data shown are for this boiler type. However, data
for fluidized bed, fuel cell, Dutch oven, and firetube boilers controlled by
mechanical collectors are also included.
Data on wood fuels of various ash and moisture contents and fuel size
are shown. The fuels burned during the tests range from sanderdust,
4-44
-------
sawdust, and bark, to hog fuel. The moisture contents vary from 6 percent
for kiln dried wood up to 65 percent for bark.
4.1.6.1.1 Performance of Mechanical Collectors on VJood-fired and
Hood/Fossil Fuel Cofired Boilers. Figure 4.1-21 shows the available test
data for mechanical collectors applied to wood-fired and wood/coal cofired
boilers. The emission rates range from 4500 ng/J (10.5 lb/10 Btu) down to
less than 86 ng/J (0.20 lb/106Btu).
The highest emissions are shown by the pulverized coal (PC) boiler
(test BF1) which fires bark and sawdust in suspension in addition to coal.
This PC boiler is not typical of boilers firing wood 100 percent in
suspension. Emissions from a representative small wood-fired suspension
boiler are presented in test AS1. The lowest emissions are shown by the
fuel cell boilers shown in tests API and A01. (The effect of boiler type on
uncontrolled emissions is discussed in Chapter 3).
The spreader stoker fired boilers show widely varying emission rates.
This could be partly due to varying fuel characteristics, but is probably
mainly a function of boiler operation and maintenance. If the mechanical
collector design limits are exceeded due to improper boiler operation or if
the mechanical collector is not properly maintained the efficiency will drop
will below design levels. For tests BD1 through BC1 (except for test AMI)
the mechanical collector is used as a precleaning device.
Tests AX1 through BM1 were performed on small firetube boilers. These
boilers are located in facilities which process kiln dried wood (such as
furniture producers). As a result, the wood fuels fired in these boilers
have moisture and ash contents lower than the other wood- fired boilers
shown in Figure 4.1-21. The fact that these boilers fire a relatively clean
dry fuel could account for the lower emissions generally shown by these
boilers, even though they were generally operated at high excess air levels
(as shown by the high flue gas oxygen contents). Test AMI was performed on
a watertube spreader stoker also firing clean kiln dried wood.
The firetube boilers shown in Figure 4.1-21 generally use a "drop
chute" to feed wood dust to the grate while the larger pieces of wood fuel
are manually stoked. However, as discussed in Chapter 3, firetube boilers
4-45
-------
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9
7
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0
0
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. K*
W
II 1 II
Telt 1 BUI Ml Alt ttl BHI
Boiler 9 2 4/5*
Boiler Type SS SS SS SS PC/SS
Detlgn Capacity -
(lo'lb/hr >(«•) 25 60 70 135 140/200
Nonfoffll Fuel Type B U.S. SO IF .501 B.S ./I
I oF Hot Inpit' im 100 100 100 -/BO
Other fiel .... isc/lSC*
Load factor - «' 75 15 79 94 84/48
t Oj In flue oil' 10.2 18.0 8.2 14.9 12.7
Control Dnlce HC HC NC HC HC/HC
Fly Ash Relnjectlon H H T t H/T
Sn«l ClattlHcitlon » H 1 1 »/»
9
r
-
.
_
4500
3500
2500
1500
•
-------
Footnotes for Figure 4.1-21.
aA11 data were obtained by EPA Method 5 and meet established criteria for acceptability. The key
for the data 1s:
SS - spreader stoker
PC - pulverized coal
OF - overfeed stoker
00 - dutch oven
FB - fluldized bed
FC - fuel eel 1
FT - flretube boilers. The firing methods for the small firetube boilers shown here generally
consist of a "drop chute" for wood dust with the large fuel pieces manually stoked.
Flretube boilers can also be fired using the same firing methods as watertube boilers.
W - wood scraps
S - shavings or sawdust
SD - sanderdust
SOI - sanderdust burned using a separate sanderdust Injector system
8 - baric
HF - hog fuel (wood/bark mixture)
SHF - salt-laden hog fuel
LSC - low sulfur coal
LSO - low sulfur distillate oil
MC - mechanical col lector
Y - yes
N - no
0 - EPA-5 test data acquired in Industry tests
• - EPA-5 test data acquired In EPA tests
H - average
More detailed information on the emission test data and the data sources may be found in Appendix C.
cTwo boilers were tested at this facility. The flue gases pass through Individual mechanical collectors
and are then combined in a single duct. This duct 1s then split prior to entering two ESPs. The data
shown is the weighted average of samples taken from the two ducts prior to the ESPs.
The flue gases from boilers 1,2, and 3 pass through individual mechanical collectors. They are then combined
in a single duct prior to entering a baghouse. This test was performed on the single duct prior to the
baghouse.
eAn analysis of the coal showed the following composition: Moisture - 3.2%; Ash (dry) - 17.7%; Sulfur (dry) - 0.56X.
Average value during testing.
"These data did not come from an analysis done during emission testing. They were obtained from Industry sources
and are representative of the typical fuel burned at this facility.
Based on the conblned steam flow of all three boilers.
Two mechanical collectors in series.
•Mhis boiler fires all of the wood in suspension. The wood fuel Is finely ground until It is similar to sanderdust.
kAt this facility char from the first stage of the mechanical collector Is slurried and separated by screens into
large and small fractions. The large char fraction is ir.ixad vith the hog fuel. These values represent an
analysis of the mixture of char and hog fuel.
-------
could also use the same firing methods as the watertube boilers shown.
While the emission rate can be affected by the firing method, the boiler
tube design has. little effect on emissions.
One test is available on a dual mechanical collector used as a
precleaner applied to a wood-fired spreader stoker boiler (BE1). This test
showed average emissions of 215 ng/J (0.5 lb/10 Btu).
Based on the limited data available it is not possible to determine the
actual long term performance that would be expected for dual mechanical
collectors. The data shown for dual mechanical collectors in Figure 4.1-21
falls within the range of performance for single stage mechanical collectors
also shown in Figure 4.1-21.
4.1.6.1.2 Performance of Wet Scrubbers on Wood-fired and Wood/Fossil
Fuel Cofired Boilers. Figure 4.1-22 shows the available emission test data
for wood-fired and wood/fossil fuel cofired boilers controlled with wet
scrubbers. The scrubbers in Tests ADI through BF2 were either impingement
scrubbers or fixed throat venturi scrubbers. Tests AJ2 through AK3 were on
adjustable throat venturi scrubbers. The gas phase pressure drops for these
scrubbers ranged from 1.5 to 6.5 kPa (6 to 26 in. w.c.) and the emission
levels were 12 to 91 ng/J (0.03 to 0.21 lb/106 Btu). All the scrubbers have
a mechanical collector upstream for precleaning and sometimes for fly ash
reinjection also. Only the scrubber at Plant AA has a mist eliminator.
These emission data generally show decreasing emissions as the scrubber
pressure drop increases. However, some of the tests showed significant
deviations from the values expected at the scrubber pressure drop shown.
These tests are discussed in the following paragraphs.
Two tests performed on the lower pressure drop scrubbers (AB2 and BF2)
show significantly lower emissions that would be expected. For Test AB2
this is due to the low emissions from the mechanical collector to the
scrubber inlet (shown in Figure 4.1-21, Test AB1) compared to other spreader
stoker wood-fired boilers. Some of the factors which could contribute to
these low emissions are:
- Overall fuel moisture content is 45 percent. This is a lower
moisture content than is found in many wood fuels.
4-48
-------
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ADI AC2 AB2 AC1 AG1 All AF1 AE1 AH1 BF2 AJ2 AJ4 AJ5 AA1 B61 AK2 AK3
SS SS SS SS SS SS SS SS SS PC SS SS SS SS SS SS SS
Test t
Boiler Type
Design Capaclty-
(103lb/hr steam)
Nonfossll Fuel Type
X Heat Inputf
SAch tiirv\
nan \ojji
% Moisture
Other Fuel
Load Factor - If
I Of In flue gas
Control Device
Operating Parameter- AP
(In. w.c.)
Fly Ash Relnjectlon
Sand Classification
ADI
SS
40
B.H
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-
.
73
11.5
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Y
N
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N
N
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SS
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HF.SD1
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-
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9.5
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6-8
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100
.
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6-8
N
N
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SS SS
no no
l.S.W S.PWR
100 100
.
.
103 86
7.7 10.9
1C/WS HC/WS
6-8 6-8
Y Y
Y Y
AF1
SS
120
B.W
100
.
.
72
7.6
HC/WS
6-8
Y
Y
AE1
SS
120
B.S
100
-
-
85
9.1
HC/WS
6-8
Y
Y
AH1
SS
140
B.W
100
.
.
65
8.2
HC/WS
6-8
Y
Y
BF2
PC
350
B.S
25
-
Coal
94
9.0
HC/WS
9
N
N
AJ2
SS
110
B.S
100
2 2
48
.
91
14.0
HC/WS
8.0
Y
Y
AJ4
SS
110
B.S
100
1 9
SO
.
95
14.9
HC/WS
13.5
Y
Y
AJ5
SS
110
B.S
100
-
.
91
8.8
HC/WS
15.2
Y
Y
AA1
SS
150
HF
100
2-8d
60-65d
-
95
7.3
HC/WS
18
Y
Y
B61
SS
200
SHF
90
55d
HSO
75
6.8
HC/WS
19
N
N
AK2 AK3
SS SS
135 135
B.S B.S
100 100
17 42
45 45
_
94 100
14.5 11.8
HC/WS HC/WS
20 26
Y Y
Y Y
120
100
80
60
40
20
Figure 4.1-22.
Participate Emissions from Wood-Fired and
Wood/Fossil Fuel Cofired Boilers Controlled
by Wet Scrubbers.a'b
-------
Footnotes to Figure 4.1-22:
aAll data were obtained by EPA Method 5 and meet established criteria for acceptability. The key
for the data is:
SS - spreader stoker
PC - pulverized coal
B - bark
W - wood scraps
HF - hog fuel (wood/bark mixture)
SHF - salt-laden hog fuel
SDI - sanderdust which is burned using a separate sanderdust injector system
PWR - pulverized wood residue
S - sawdust or shavings
HSO - high sulfur residual oil
MC - mechanical collector
WS - wet scrubber
P - pressure drop
Y - yes
N - no
0 - EPA-5 data acquired in industry tests
9 - EPA-5 data acquired in EPA tests
H - average
More detailed information on the emission test data and the data sources may be found in
Appendix C.
cTwo boilers which exhaust into a single wet scrubber.
These data did not come from an analysis done during emission testing. They were obtained from industry
sources and are representative of the typical fuel burned at this facility.
Q
Based on combined steam flow of both boilers.
Average valve during testing.
-------
- The excess air level is approximately 80 percent. Many of the
other spreader1 stoker fired boilers tested had excess air levels
well over 100 percent.
- The fine fuel particles are fed through a separate sanderdust
injection system.
- The fuel at this facility is size classified and only oversize
pieces are hogged. This increases the average fuel particle size.
A discussion of how these factors can reduce uncontrolled emissions can be
found in Section 3.2.1.2.
Tests AJ2, AJ4, and AJ5 were on the same boiler and control system.
Test AJ5 was performed to determine if the boiler was in compliance with the
State emission regulation of 129 ng/J (0.3 lb/106 Btu). During this test
the measured excess air level was 70 percent at the scrubber outlet. During
Tests AJ2 and AJ4 the measured excess air levels at the scrubber outlet,
ranged from 150 to 300 percent. As discussed in Chapter 3, excess air
levels higher than those required for good combustion can cause an increase
in particulate emissions. In fact, the particulate emission simultaneously
measured at the scrubber inlet during Tests AJ2 and AJ4 were higher.than
scrubber design levels on 4 of the 6 test runs.
Because of the high excess air, the emission levels in Tests AJ2 and
AJ4 are higher than the levels expected from the boiler and control system
when properly operated. There is no reason that excess air levels on a
wood-fired boiler would have to be increased from 70 percent to 150 or
300 percent. Since these measurements were made at the same location, the
affect of air leakage into the flue gas should not affect this comparison.
- Test BG1 shows significantly higher emissions than other wet
scrubbers with similar pressure drops. This boiler fired salt-laden wood
containing 0.4 percent salt (dry basis) in the fuel during this test. The
results of the emission test showed that the particulate emitted from the
wet scrubber contained 6 percent salt. However, other reported test data
have shown a salt content of 50 percent or more in the particulate emissions
from this scrubber. Salt particulate emissions have small particle sizes
4-51
-------
making them difficult to control efficiently with a scrubber. Therefore,
the salt would contribute to the higher emissions.
Another difference in this system compared to the other high pressure
drop scrubbers (over 3.7 kPa) shown is the use of recycled scrubber water
without a mist eliminator. High pressure drop scrubbers can entrain
significant amounts of water in the exit flue gas. This water, which
contains suspended PM, can evaporate in the stack releasing the PM back into
the stack gas. Therefore, high pressure drop scrubbers should be equipped
with mist eliminators. The other high pressure drop scrubbers shown in
Figure 4.1-21 (except at Plant AA) use once through scrubber water, which
reduces the particulate matter carry over by reducing this solid content of
the scrubber liquor. The scrubber at Plant AA used recycled scrubber water,
but this scurbber has a mist eliminator.
4.1.6.1.3 Performance of ESPs, Fabric Filters, and EGBs on Wood-
Fired and Hood/Fossil Fuel Cofired Boilers. Figure 4.1-23 shows the
available emission test data for wood-fired and wood/fossil fuel cofired
boilers controlled by ESPs, fabric filters, or EGBs. All of these tests
showed emission levels below 34 ng/J (0.08 lb/10 Btu).
Five of these emission tests were performed on boilers firing wood or
mixtures of wood and coal controlled by ESPs. These tests generally show
decreasing emissions as the SCA of the ESP increases.
Two tests with fabric filters used for particulate control are shown.
Average emission levels for both facilities are about 9 ng/J (.02 lb/10 Btu)
with A/Cs ranging from 0.9 - 1.1 m/min (3.0 - 3.7 ft/min). Facility BC
fires a salt-laden wood fuel which produces a salt particulate.
Two tests were performed on an EGB. This EGB has 3 modules. Each
module cleans one third of the total flue gas and has its own stack. The
first test (BE2) was performed by EPA. The data shown are the weighted
average of the three stacks. This test was run under typical operating
conditions at this facility. The second test was performed by the boiler
operator and consisted of 15 test runs under a range of operating
conditions. The data shown are the emissions from the outlet of Module 3 of
4-52
-------
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1 1 1 1 1 1 1 1 1 1
16 BB1 BJ1 BH2 002 BC2 BE2m BE3n BE4n BE5n BE6n
'5d - - 4/5d - 1.2.3J 11 11 U 11 11
ype SS SS/SS PC/SS SS SS PC/SS SS 00 SS SS SS SS SS
Test 1
Boiler 1
i Boiler Type
CJl
Co Design Capacity
(103lb/hr steam)
Nonfossll Fuel Type
% Heat Input*1
X Ash (dry)
% Moisture
Other Fuel
Load Factor - th
X 02 In flue gash
Control Device
Operating Parameter '
Design Parameter
Fly Ash Relnjectlon
Sand Classification
BA1
-
SS
110
B.SD
100
_
_
_
66
9.4
HC/ESP
230
177
Y
N
BI1
7/8c
SS/SS
240/325
B/B
25/25
3.4
46
LSC/LSC6
87/87
10.2
MC/ESP
320
296
Y
N
BH6
4/5d
PC/SS
140/200
-/B
-/100
4.4
42
LSC/f-
48/88
12.5
MC/ESP
452
460
N/Y
N/N
BB1
-
SS
450
HF
100
4.81
42'
_
69
6.3
HC/ESP
453
298
Y
Y
BJ1
-
SS
600
B,S
64
-
.
HSO
76
6.2
HC/ESP
456
356
Y
Y
BH2
4/5d
PC/SS
140/200
-/B
-/80
-/5.9
-/28
LSC/LSC9
84/46
9.9
HC/ESP
600
460
N/Y
N/N
002
-
SS
25
B
100
5.1
47
.
75
9.9
MC/FF
3.66
4.10
N
N
BC2
1.2.3*
00
3x50
SHF
100
3.4
57
-
91
10.7
MC/FF
2.98
3.64
N
N
BE2m
11
SS
400
HF
100
9.4k
56k
..
96
9.6
HC/EGB
6.0
-
Y
Y
BE3n
11
SS
400
HF
100
3.8
49
_
101
7.9
HC/EGB
3.4
-
Y
Y
BE4n
11
SS
400
HF
100
3.8
50
_
116
7.2
HC/EGB
4.0
-
N
N
BE5n
11
SS
400
HF
100
4.8
58
_
95
8.1
HC/EGB
5.6
-
Y
Y
BE6n
11
SS
400
HF
100
4.8
59
.
107
8.7
MC/EGB
7.1
N
N
60 -o
40
20
Figure 4.1-23.
Particulate Emissions from Wood-Fired and Wood/Fossil Fuel .
Cofired Boilers Controlled by ESPs, Fabric Filters, and EGBs. '
-------
Footnotes for Figure 4.1-23.
aAll data were obtained by EPA Method 5 and meet established criteria for acceptability. The key
for the data is:
SS - spreader stoker
PC - pulverized coal
DO - dutch oven
B - bark
S - sawdust or shavings
SO - sanderdust
HF - hog fuel (wood/bark mixture)
SHF - salt-laden hog fuel
LSC - low sulfur coal
HSO - high sulfur residual oil
HC - mechanical collector
ESP - electrostatic precipita tor
FF - fabric filter
EGB - electrostatic gravel bed filter
Y -yes
N - no
0 - EPA-S data acquired In industry tests
• - EPA-5 data acquired in EPA tests
I—l - average
- More detailed Information on the emission test data and the data sources may be found in Appendix C.
c
1 The flue gas from boilers 7 and 8 passes through individual mechanical collectors. It is then
^ combined Into a single duct and then split to enter a two chamber ESP with two stacks. The
emission levels shown are the weighted average of both stacks.
The flue gas from boilers 4 and 5 passes through Individual mechanical collectors. It is then
combined into a single duct and then split to enter two separate ESPs in parallel. The emission
levels shown are the weighted average of both stacks.
eThe analysis of the coal showed the following composition: Moisture - 5.5*; ash (dry) - 12.42;
sulfur (dry) - 0.86JS.
The analysis of the coal showed the following composition: Mositu re 3.9%; ash (dry) - 7.1%;
sulfur (dry) - 0.7X.
9The analysis of the coal showed the following composition: Moisture - 3.2X; ash (dry ) - 17.71;
sulfur (dry) - 0.56J.
Average value during testing.
For ESPs this value is specific collection area in ft2/1000 acfm; for fabric filters this value is
air to cloth ratio in ft/min; for the EGB this value is pressure drop i.i Inches of water.
•^The flue gas from boilers 1,2 and 3 passes through Individual mechanical collectors. It is then
combined Into a single duct prior to entering the fabric filter.
At this facility char from the first stage of the mechanical collector is slurried and separated
by screens Into large and small fractions. The large char fraction Is mixed with the hog fuel.
These values represent an analysis of the mixture of char and hog fuel.
These data did not come from an analysis done during omission testing. They were obtained from
Industry sources and are representative of the typical fuel burned at this facility.
mThe EGB has three modules, each of which cleans one-third of the flue gas. Each module has a
separate stack. The emission levels shown are the weighted average of all three stacks.
"Emissions are from the outlet of module 3 of the EGB.
-------
the EGB only. The 15 test runs are grouped into 4 different sets. These
sets are as follows:
- Set BE3 consists of test runs 1,2,5,7 and 9. In this set "good"
hog fuel was fired and flyash was reinjected.
- Set BE4 consists of test runs 3,4,8 and 15. "Good" hog fuel was
fired and flyash was not reinjected.
- Set BE5 consists of test runs 10,11 and 13. "Poor" hog fuel was
fired and flyash was reinjected.
- Set BE6 consists of test runs 12 and 14. "Poor" hog fuel was
fired and flyash was not reinjected.
For these tests the definition of "good" hog fuel is hog fuel with moisture
content of less than 55 percent. Hog fuel with a moisture content of
55 percent or more is defined as "poor". Test run 6 was made with the
electrostatic grid turned off. Since this is not part of normal operation,
this test run was not shown. The emission rates shown by the EGB were
comparable to those shown by ESPs and fabric filters.
4.1.6.2 Performance of Particulate Matter Control Techniques On
Bagasse-Fired Boilers. Figure 4.1-24 shows the available performance data
for bagasse-fired boilers controlled by wet scrubbers and mechanical
collectors. These two types of control devices are the only types in use on
bagasse-fired boilers.
The data for bagasse-fired boilers controlled by wet scrubbers show
average emissions which range from 140 ng/J (0.33 lb/10 Btu) down to
36 ng/J (0.07 lb/10 Btu). The lowest emissions are shown in test DC1.
This is the only scrubber facility with both a cyclone for precleaning and a
mist eliminator. This wet scrubber is an ejector venturi design. Though
the flue gas pressure drop is only 0.5 kPa (2 in. w.c.), the scrubbing
liquid pressure drop is higher than for a typical venturi scrubber. This
results in better atomization of the water droplets and increased scrubber
efficiency. This scrubber would be equivalent to "standard" venturi
scrubber with a gas phase pressure drop of 1.5 kPa (6 in. w.c.). '
Plants DC1 and DD1 also fire a bagasse with a lower moisture content than
the other facilities shown.
4-55
-------
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Test f DAI DA2 DEI DE2 DE3 DH2 DH1
Boiler f 3 4 6 12 14 2 5
Boiler Type HS HS FC SS SS SS SS
Design Capacity - 125 125 125 150 150 150 200
(10J Ibs/hr steam)
Bagasse Character! stics-
X Heat Inputc 92 100 94 100 100 99 100
X Ash(dry) 1.8
X Moisture - - - - - 58.4
Other fuel HSO - HSO - - HSO
Load Factor - f 78 71 ' 96 92 98 97 82
X 02 in flue gasc 12.1 11.8 11.0 4.8 5.9 9.2 10.5
Control Device 2HSd WS WS MC/WS MC/WS 2WSd WS
Operating Parameter -APC 5-7 5-7 6 6 6 6 6
h§H
1
DGl
5
SS
160
80
_
.
HSO
103
8.4
2WSd
5-9
9 9 ~
9 MI
hH r^i
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—
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I— Y— I
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1 1
DFl DC1 D01
2 - -
HS SS SS
125 312 288
100 100 100
3.0
48 48
-
71 93 68
11.3 7.1 8.7
2WSd WC/HS 2xMCe
8-9 2T 2
- 160
L 120
_ 80
_ 40
(in. w.c.)
Figure 4.1-24. Particulate Emissions from Bagasse-Fired Boilers
Controlled by Wet Scrubbers and Mechanical Collectors.3^
-------
Footnotes to Figure 4.1-24:
aAll of the data were obtained by EPA Method 5 and meet established criteria for acceptability.
The key for the data is:
HS - horseshoe
FC - fuel cell
SS - spreader stoker
HSO - high sulfur residual oil
MC - mechanical collector
WS - wet scrubber
P - pressure drop
0 - EPA-5 test data aquired in industry tests
I - EPA-5 test data acquired in EPA tests
^—| - average
More detailed information on the emission test data and the data sources may be found in
f* Appendix C.
01 r
~^ Average value during testing. For all the wet scrubbers tested the scrubber pressure drop is
assumed to be equal to the reported design value. The pressure drops were not actually measured
during testing.
Two wet scrubbers in parallel.
eTwo mechanical collectors in series.
This wet scrubber is an ejector venturi design, therefore the gas phase pressure drop is not
a good indicator of scrubber efficiency. This scrubber would be approximately equiavalent to
a "standard" venturi with a pressure drop of 1.5 kPa (6 inches w.c.).
-------
The highest emissions are shown by Test DAI. This boiler uses two wet
scrubbers in parallel for particulate matter control. When two wet
scrubbers are used in parallel it is very difficult to maintain the same
pressure drop in both scrubbers. The flue gas tends to take the path of
least resistance through the scrubber with the lowest pressure drop. This
effectively reduces the pressure drop for this system, therefore reducing
the scrubber efficiency. A boiler identical to the boiler tested in
CO
Plants DAI had its two parallel wet scrubbers replaced for this reason.
Test DAI also shows the highest stack (L concentrations of any of these
tests shown which may be indicative of high excess air rates in the boiler.
All of the tests except DAI show average emissions below 130 ng/J
(0.30 lb/106 Btu).
4.1.6.3 Performance of Particulate Matter Control Techniques on
MSW-Fired Boilers. Figure 4.1-25 shows the available performance data for
particulate matter (PM) controls applied to the large overfeed stoker type
MSW-fired boiler described in Chapter 3. All of the facilities shown in
Figure 4.1-25 use ESPs for PM control. The ESP is used almost exclusively
fi?
on MSW-fired boilers presently in operation.
These ESPs show a range of average emissions from 86 ng/J
(0.2 lb/10 Btu) at an average specific collection area (SCA) of
28 m2/(m3/s) (140 ft2/1000 acfm) down to 21 ng/J (0.05 lb/106 Btu) at an
average SCA of 100 m2/(m3/s) (570 ft2/1000 acfm).
The facilities are shown in order of increasing SCA during testing and
follow the expected trend of decreasing emissions with increasing SCA with
average emissions below 43 ng/J (0.1 lb/10 Btu) for the three facilities
with SCAs larger than 48 m2/(m3/s) (240 ft2/1000 acfm).
4.1.6.4 Performance of Particulate Matter Control Techniques on
RDF-fired Boilers. Figure 4.1-26 shows the available performance data for
RDF/coal cofired boilers controlled with mechanical collectors. The units
tested were spreader stokers firing RDF and coal at different fuel ratios
and boiler operating conditions.
4-58
-------
0.30
5 0.25
ca
jQ
| °-2°
C/l
4->
| 0.15
o
t
IO
a.
0.10
0.05
—
0
^"
- 1 — 1
0
* &
* -
I I I
Test # FA1 FC1 FE2 FBI
Boiler Type OF OF OF OF
Design Capacity
(103lbs/hr steam) 30 175/175C 110 135
Nonfossll Fuel Type MSW MSW MSW MSW
% Heat Inputd 100 100 100 100
Load factor - ^ 160e 80/88 79 77
% 02 1n flue gasd 12.9 9.8 9.4 9.2
Control Device ESP ESP ESP MC/ESP
Operating Parameter - SCAd 139 243 278 573
(ft2/1000 acfm)
Design Parameter - SCA
(ft2/1000 acfm)
— 140
— 120
— 100
— 80
— 60
— 40
— 20
-o
O)
ai
rr
126
209
154
316
Figure 4.1-25. Particulate Emissions from MSW-Fired
Boilers Controlled by ESPs.a'D
4-59
-------
*
Footnotes for Figure 4.1-25:
aReported data were obtained with EPA Method 5 and meet established criteria for acceptability.
The key for the data is:
OF - overfeed stoker
MSW - municipal solid waste
ESP - electrostatic precipitator
MC - mechanical collector
SCA - specific collection area
0 - EPA Method 5 data acquired in industry tests
H - average
More detailed information on the emission test data and the data sources may be found in
Appendix C.
r
Two boiler/ESPs are exhausted through a common stack; each boiler has a steam generating capacity
of 175,000 Ib/hr.
Average value during testing.
<=>' eBoiler was being operated in excess of original rated capacity to determine if the required
emission standard could be maintained at an increased capacity.
-------
J l-5
**o
;S
t/»
1 1.0
V)
to
i
01
1 0.5
4->
A
O.
.
0
~M
- O
1
Test 1 HD1
Boiler Type SS
Design Capacity -
(103 Ib/hr steam) 45
Nor.fossil Fuel Type RDF
% Heat Input0 26
% Ash (dry)d 11.7
% Mo1stured 5.4
Other fuel Coal
Load Factor - «c 56
1 02 1n flue gasc 5.2
Control Device MC
KH
\
HD2
SS
45
RDF
53
15.1
5.1
Coal
54
6.0
MC
KH
KH
1 1
HD3 HE1
SS SS
45 35
RDF
100
14.2
5.9
Coal Coal
31 58
7.4 9.7
MC MC
KH
1
HE2
SS
35
RDF
20
14.8
18.4
Coal
61
9.6
MC
KH
1
HE3
SS
35
RDF
30
16.4
17.4
Coal
52
11.5
MC
-
-
KH .
.
-
~
600 |
n'
c
o>
c*
-------
The emission levels achieved range from 590 ng/J (1.4 lb/10 Btu) down
to 170 ng/J (0.40 lb/10 Btu). These data show no clear trend on the effect
of adding RDF to coal on PM emissions controlled by mechanical collectors.
Figure 4.1-27 shows the available emission data for RDF-fired and
RDF/coal cofired boilers controlled by ESPs. The data shown were obtained
from 3 different facilities. Three different types of RDF were burned at
these facilities: fluff RDF; densified RDF; and wet pulped RDF. Additional
information on these RDF types is presented in Chapter 3.
Data from two of these facilities (HC and HG) were obtained as part of
experimental programs evaluating the use of RDF as a supplementary fuel in
existing coal-fired boilers. The percentages of RDF fired ranged from 0 to
27 percent (heat input basis) at the facility firing fluff RDF (HC) and 0 to
51 percent at the facility firing densified RDF (HG). The third facility
(HF) fired 100 percent wet pulped RDF and was the only system tested that
was specifically designed 'for RDF firing.
For facilities cofiring RDF and coal the data show emission levels
during cofiring similar to these from coal fired alone. Therefore, ESPs
should be capable of controlling emissions of coal/RDF mixtures to the same
levels as coal fired alone.
Facility HC fired fluff RDF and low sulfur coal in a large pulverized
coal boiler. The percentage of RDF fired during testing ranged from 0 to
27 percent and the boiler load ranged from 64 to 96 percent of capacity.
2 3
The SCA during testing was fairly low ranging from 16 - 28 m /(m /s) (82 -
p
140 ft /1000 acfm) and the emission levels ranged from 23 - 56 ng/J (.05 -
0.13 lb/10 Btu). The emission levels for RDF/coal cofiring were similar to
those for 100 percent coal firing.
Facility HG fired densified RDF with coal in a spreader stoker. The
percentage of RDF fired during testing ranged from 0 to 51 percent and the
boiler load varied from 84 to 95 percent of rated capacity. Again, the
emission levels for RDF/coal cofiring were similar to those of 100 percent
coal firing. The SCA during testing was fairly low, with the average of
23 2
each test series ranging from about 35 - 38 m (m /s) (180 - 190 ft /1000
acfm). The average emissions for high sulfur coal fired alone were 220 ng/J
4-62
-------
I
-
O '
to 0.8«
H
I •
l_u r-
1
t-O-l 1 1 1 |"V/" 1
r\/~l i f\ i
HH " |
-------
Footnotes to Figure 4.1-27:
aAll data were obtained by EPA Method 5 and meet established criteria for acceptability. The key
for the data is:
SS - spreader stoker
PC - pulverized coal
LSC - low sulfur coal
RDF - refuse derived fuel
d-RDF - densified refuse derived fuel
MC - mechanical collector
ESP - electrostatic precipitator
SCA - specific collection area
0 - EPA-5 test data obtained from industry sources
H - average
More detailed information on the emission test data and the data sources may be
found in Appendix C.
r
Shown here are the minimum and maximum values for the test and the average of all test runs.
The number of test runs conducted for each test are as follows:
HG1 - four runs
HG2 - three runs
HG3 - six runs
HG4 - fourteen runs
The actual percentage of d-RDF varied from 23 to 51 percent with the majority of the test runs
firing 31 to 37 percent d-RDF.
eThe average composition for the coal fired during testing is as follows: Moisture - 6.34%;
Ash (dry) - 7.03%; Sulfur (dry) - 1.56%.
Analyses of the coal showed the following range of compositions: Moisture - 5.5 to 9.9%;
Ash (dry) - 15.6 to 18.2%; Sulfur (dry) - 4.2 to 6.8%.
^Analyses of the coal showed the following range of compositions: Moisture - 4.0 to 7.4%;
Ash (dry) - 9.5 to 12.9%; Sulfur (dry) - 1.7 to 2.2%.
Average value during testing.
1A fuel analysis was not done during testing. These data were obtained from industry sources and
represent the typical fuel composition for RDF fired at this facility.
-------
(0.51 lb/10 Btu), and for high sulfur coal cofired with 25 percent RDF were
220 ng/J (0.52 lb/10 Btu). The average emissions with low sulfur coal fired
alone were 64 ng/J (0.15 lb/10 Btu), and low sulfur coal cofired with RDF
were 69 ng/J (0.16 lb/10 Btu). The low sulfur coal had a considerably lower
ash content (11%) than the high sulfur coal (17%) on a dry basis. These
tests showed considerable variation in emission levels between test runs.
The reasons for this variability are unknown, but are not believed to be due
to the addition of RDF to the coal because they are highly variable for both
RDF/coal and coal fired alone.
ESPs have shown the capability of continuous control of emissions from
coal-fired boilers to levels below 43 ng/J (0.10 lb/10 Btu). Because of
the high and variable emissions shown by this particular ESP it is not
considered to be an example of a well designed and operated system.
Facility HF fired 100 percent wet pulped RDF in a spreader stoker. The
average SCA at this facility during testing was 64 m2/(m3/s) (330 ft2/1000
acfm). This SCA is more than 1.5 times the SCAs of the two RDF/coal cofired
boilers tested. The average emissions for this facility were 30 ng/J
(0.07 lb/10 Btu). These emissions are similar to levels shown for MSW-fired
boilers controlled by ESPs with similar SCAs.
4.1.6.5 Visible Emissions Data. The available visible emissions data
for control devices on nonfossil fuel fired boilers are summarized in
Table 4.1-2. Data are available for boilers fired with wood, wood/fossil
fuel, bagasse, MSW, and RDF-
Nine opacity tests were performed on boilers firing wood fuels or
cofiring wood/fossil fuels. On four of these boilers, particulate emissions
were controlled by a mechanical collector followed by a wet scrubber. These
wet scrubbers had average flue gas pressure drops of 1.5-2.5 kPa (6-10 in.
w.c.). The average opacity measured for these scrubbers ranged from 15.7 to
22.9 percent. The highest six minute average opacity ranged from 20.2 to
26.9 percent. The other five opacity tests were performed on wood-fired or
wood/fossil fuel cofired boilers with mechanical collectors followed by an
ESP or fabric filter for particulate control. In four of these tests, the
particulate emission rate was measured simultaneously with opacity. The
4-65
-------
TABLE 4.1-2. VISIBLE EMISSIONS DATA FROM NONFOSSIL FUEL FIRED BOILERS
a,b
Plant
BP
AF
AE
BO
BA
BHC
BId
BJ
BC
DD
FB
FC
HF9
Boiler Design Capacity Fuel Nonfossil Fuel
Type (103lb/hr steam) Type 5! Heat Input
SS
SS
SS
SS
SS
PC/SS
SS
SS
DO
SS
SS
SS
SS
2 x 20
120
120
180
110
140/200
240/325
600
3 x 50
288
135
2 x 175
200
HF.SD
B.W
B.S.W
HF
B
LSC/B
B.LSC
B.S.HSO
SHF
Bagasse
MSW
MSW
RDF
100
100
100
100
100
0/100
25
61
100
100
100
100
100
Operating Rate Control
% of Capacity Device(s)
95
78
88
100
78
48/88
87
78
91
68
79
82
75
MC/LWS
MC/LWS
MC/LWS
MC/LWS
MC/ESP
MC/ESP
MC/ESP
MC/ESP
MC/FF
2xMCe
MC/ESP
ESP
MC/ESP
Particulate Emission Average Opacity of Maximum Opacity
Rate, ng/J(lb/106Btu)f All Six Minute Any Six Minute
Periods, Percent Period, Percent
_
-
'
-
-
40.0(0.093)
19.8(0.046)
18.5(0.043)
19.4(0.045)
11.2(0.026)
8.7(0.020)
123(0.285)
-
-
21.5(0.05)
17.6
22.9
17.1
15.7
0.5
0.1
0.1
0.6
0.8
o-
3.8
18.6
3.0
3.9
4.0
20.2
26.9
22.1
26.7
6.5
1.7
4.6
10.2
18.8
0
13.5
21.9
14.4
5.8
12.5
-------
Footnotes for Table 4.1-2.
aA11 of the data were obtained by EPA Method 9 and meet established criteria for acceptability. The key for the data Is:
HF - hog fuel (wood/bark mixture)
SHF - salt-laden hog fuel
B - bark
W - wood
S - shavings or sawdust
LSC - low sulfur coal
HSO - high sulfur residual oil
HSW - municipal solid waste
RDF - refuse derived fuel
SS - spreader stoker
PC - pulverized coal
DO - Dutch oven
MC - mechanical collector
LWS - low pressure drop wet scrubber (less than 15 Inches of water)
ESP - electrostatic preclpitator
FF - fabric filter
.p» More detailed information on the emission test data and the data sources may be found in Appendix C.
o> cFlue gas from two boilers is combined in a single duct; flow Is split and sent to two separate ESPs, each with its own stack. The PC boiler
"^ fires 100 percent coal and the SS boiler fires 100 percent bark. Each boiler has an individual mechanical collector. Data are shown for
each ESP stack.
Flue gas from two boilers is combined in a single duct; flow is split and sent to a two chamber ESP with two stacks. Each boiler has a
individual mechanical collector and fires a mixture of wood and coal. Data are shown for each ESP stack.
eTwo mechanical collectors in series.
Particulate emission rates (where shown) were measured simultaneously with opacity.
9This test consisted of three test runs with opacity data being taken simultaneously with the partlculate emission tests. However, the
opacity data on test run one was Incomplete and therefore was not used in NSPS development. The particulate emission data show the average
of the two runs for which opacity data were available.
-------
particulate emission rates measured ranged from 8.7 to 40.0 ng/J (0.020 to
0.093 lb/10 Btu). The average opacities measured at these facilities were 0
to 0.8 percent for the boilers firing nonsalt-laden wood 3.8 percent for the
one boiler firing salt-laden wood. The highest six minute opacity 18.8
percent.
One opacity test was performed on a boiler firing bagasse which had two
mechanical collectors in series for particulate control. This boiler had an
average opacity of 18.6 percent and a maximum six minute average of
21.9 percent. Particulate emission testing conducted simultaneously with
the opacity test showed an average emission rate of 123 ng/J
(0.285 lb/106Btu).
Two opacity tests were performed on MSW-fired boilers with ESPs for
particulate control. These tests showed average opacities of 3 and
3.9 percent. The maximum opacities for any six minute period were 5.8 and
14.8 percent, respectively.
One opacity test was available on a RDF-fired boiler with a mechanical
collector and ESP in series for particulate control. The average opacity
was 3.9 percent and the maximum opacity for any six minute period was
12.5 percent. Two emission test runs conducted simultaneously with the
opacity test showed an average particulate emission rate of 21.5 ng/J
(0.05 lb/106Btu).
4.2 POST-COMBUSTION CONTROL TECHNIQUES FOR SULFUR DIOXIDE
As discussed in Chapter 3, boilers fired totally with nonfossil fuels
emit only small quantities of SO,,. Because of the low amounts of S02
emitted, these boilers employ no S02 control techniques. Boilers cofiring
nonfossil and fossil fuels, however, can have high S02 emissions. Because
of these cases, several techniques for controlling S02 emissions are
presented and discussed in this chapter.
Control of S02 emissions from these boilers can be accomplished with
either pre-combustion or post-combustion techniques. Pre-combustion
techniques are discussed in Section 4.3. Post-combustion control of S02,
4-68
-------
discussed in this section, can be accomplished by using one or more of the
following techniques:
- sodium scrubbing
- dual alkali scrubbing
- lime and limestone scrubbing (with and without adipic acid
addition)
- dry scrubbing.
Each of these F6D systems is currently being used commercially to remove S02
from industrial boiler flue gases with the exception of adipic acid enhanced
F6D. Each system relies on either a calcium- or sodium-based sorbent to
react with SCL to form sulfite and sulfate salts, thereby removing SCL from
the flue gas stream.
Sections 4.2.1 through 4.2.4 present a description of each system and a
brief evaluation of its development status, applicability, and design and
operating characteristics. Section 4.2.5 presents continuous monitoring
test data substantiating the performance of each technique. Because of the
limited application of SCL controls to nonfossil fuel fired boilers, the
reported data will describe SCL controls applied to fossil fuel fired
boilers.
4.2.1 Sodium Scrubbing
Sodium scrubbing processes are capable of achieving high SO- removal
efficiencies over a wide range of inlet S(L concentrations. However, these
processes consume a premium chemical (NaOH or NagCCL) and produce an aqueous
waste for disposal which contains sodium sulfite and sulfate salts.
4.2.1.1 Process Description. Sodium scrubbing processes currently
being used in industrial boiler FGD applications employ a wet scrubbing
solution of sodium hydroxide (NaOH) or sodium carbonate (Na2C03) to absorb
S(L from the flue gas. The operation of the scrubber is characterized by a
low liquid-to-gas ratio (1.3 to 3.4 1/m3 [10 to 25 gal/1000 ft3]), and a
sodium alkali sorbent which has a high reactivity relative to lime or
limestone sorbents. Further, the scrubbing liquid is a solution rather than
a slurry because of the high solubility of sodium salts. The S02 absorption
reactions which take place in the scrubber are:
4-69
-------
2 NaOH + S02 + Na2S03 + H20 (4.2.1-1)
Na2C03 + S02 -v Na2S03 + C02 (4.2.1-2)
Na2S03 + S02 + H20 + 2NaHS03 (4.2.1-3)
Simultaneously some sodium sulfite reacts with the oxygen in the flue gas to
produce sodium sulfate:
Na2S03 + 1/2 02 «. Na2S04 (4.2.1-4)
The scrubber effluent, therefore, consists of a mixture of sodium salts.
Solids storage and handling equipment are auxiliaries associated with
sodium scrubbing systems. Sodium reagent handling requirements include dry
storage, usually in silos'. A conveyor system is generally used to transport
the reactant from the silo to a mixing tank, where the sodium alkali is
dissolved to produce the scrubbing solution. The solution from the mix tank
is pumped to a larger hold tank where it combines with the scrubber
effluent. Most of the hold tank liquor is recycled to the scrubber with a
slip stream going to waste treatment
and disposal. A simplified process flow diagram is presented in
Figure 4.2-1.
4.2.1.2 Development Status. Sodium scrubbing systems are commer-
cialized technology; operating systems are in use on industrial boilers
ranging in size from 10 to 125 MW (35 to 430 x 10 Btu/hr) thermal input.
Table 4.2-1 .presents a summary of operating sodium scrubbing systems applied
to U.S. industrial boilers. Currently 102 sodium FGD systems are in
operation on domestic industrial boilers, and 23 are in the planning or
construction stage.
4.2.1.3 Applicability to Nonfossil Fuel Fired Boilers. Sodium
scrubbing, because it is simple both chemically and mechanically, can be
applied to boilers of varying size and type. As shown in Table 4.2-1, the
4-70
-------
STACK
FLUE GAS '
ABSORBER
•> ^
£ **-
f"~ 7
y
— i
FRESH SORBENT
MIX
TANK
MAKEUP WATER
WASTE TO
TREATMENT
WATER
Figure 4.2-1. Simplified flow diagram of a sodium scrubbing system.
-------
TABLE 4.2-1. SUMMARY OF OPERATING SODIUM SCRUBBING SYSTEMS
66
Inita J 1 at Ion/ J oca t Ion
Al yc&ka Pipe! me
Martin, NC
belrldge Oil
McKlttrlck, CA
Canton Textiles
Canton, CA
Chevron
Eakersfleld, CA
PMC
Creen River, WY
Dayton, OH
Ceneral Motors
Pontiac. HI
Ceneral Motors
St. Louis, MO
Ceneral Motors
Tonawanda, HY
Ceorgla Pacific
Orosect, Alt
Cetty Oil
Sakenfield. CA
Creat Southern
Cedar Springs, CA
ITT Rayooler
Fernandlnl. FL
Kerr-McC«e
Trona. CA
Mead Paperbo>rd
Stevenson, At
Mobil Oil
San Ardo, CA
Axhdovo. AX
Northern Ohio Sugar
Treenont. OH
St. Regis Paper
Cantonaent, TL
Teiaco
San Ardo. CA
Txxjulf
Cranger. wT
(1) C-coal
O-oll
B-bark
Sorbent
KaOH
Caustic waste
NaOH
Caustic waste
N..CO,
NaOH
NaOH
NaOH
NaOH
Caustic waste
NaiCOi
Caustic waste
Caustic waste
Na»COi
' '
Na, CO, /NaOH
NaOH
KaOH
KaOH
Ka.CO,
Type"* IS
o
Inlet (PPK)
150
500
700
800
1.4 31/10* BTU
—
2000
1I/10* BTU
500
600
1000
1200
1500
600
—
—
1000
860
Percent
Reooval
96
70
90
7ft
IV
90
9S
86
—
90
90
80
90-96
85-9C
80-85
98
95
90
90
—
80-90
73
90
(:)
Want DlspOfctl
oxldttlon/dtlucion
so fid
pond /wast* creaimrnl
pond
clarify /adjust pH/
co sewer
combine 'lib ash/
landfill
oxidise/ neutralise/ •
di»char|t
coatvine wlch ash/
landfill
to clcy cewers
pond
ash pond
?ond
pond
wakt * treatMnt
pond
clarification/
aeration
pond/well s/so.'t«nin|
and reauH
pond
(2) SO, Inlet (p?m) «nd percent SO- removll trt »s reporte
-------
process has been applied to oil-fired boilers, coal-fired boilers, and
boilers cofiring bark and oil or bark, oil, and coal.
Future applications of sodium scrubbing systems may be limited by the
need to dispose of the sodium sulfite/sulfate waste liquor. As shown in
Table 4.2-1 the majority of sodium scrubbing systems in use today are
located in the California oil fields where the wastes are disposed of in
evaporation ponds or by deep well injection. Systems in use at industrial
plant locations either reuse the waste liquor in various plant processes or
dispose of it in ponds, landfills, or city sewers. Many pulp and paper
plants may be able to re-use the waste liquor in the pulping process. If
wastes from future sodium scrubbing systems cannot be disposed of by
treating them in existing waste water or ash disposal facilities, or by use
as a plant process make-up stream, costs associated with achieving a zero
discharge waste will more than likely limit the system's application.
4.2.1.4 Avai1abi1ity/Reliabi1ity. The three indices used in the
EPA Industrial Boiler FGD Survey to reflect system performance are
availability, operability, and reliability. These indices are defined as
follows:
Availability - Hours the FGD system was available for operation
(whether operated or not) divided by the hours in
the period, expressed as a percentage.
Operability - Hours the FGD system was operated divided
by boiler operating hours in the period,
expressed as a percentage.
Reliability - Hours the FGD system operated divided by the
hours the FGD system was called upon to operate,
expressed as a percentage.
Overall reliability of sodium scrubbing systems applied to industrial
boilers has generally been quite high. Data reported in the EPA Industrial
Boiler FGD Survey indicate that of the 22 industrial boiler installations
which have operating sodium scrubbing systems, 15 reported quantitative
reliability or operability indices that ranged from 89 to 100 percent with
4-73
-------
an average of 97.8 percent. Of the 15 responses, 9 reported a 100 percent
reliability/operability and all but two reported reliabilities of greater
CQ
than 95 percent.
Of the seven installations that did not report quantitative reliability
indices, two reported that the FGD system had no problems, two reported
erosion/corrosion problems, one had down-time due to reconstruction, one had
mechanical problems with pump packings, and one installation did not report
comments.
4.2.1.5 Factors Affecting Performance. For a given set of boiler
operating conditions, the SOp removal performance of a sodium scrubber
depends on two main factors: the relative amount of scrubbing liquid
circulated through the scrubber (represented by the liquid to gas ratio or
L/G) and the sorbent feed rate. Although design L/G ratios are dependent on
the type of gas-liquid contactor used by the process vendor, sodium
scrubbing systems have relatively low L/G ratios (compared to lime or lime-
stone systems) due to the high reactivity of the sodium alkali. Sodium
scrubbing L/Gs are generally in the range of 1.3 to 3.4 1/m (10 to
o
25 gal/1000 ft ) whereas typical L/Gs for lime and limestone scrubbers are
o o 70
in the range of 5 to 15 1/nr (35 to 100 gal/1000 ft3)/
The amount of fresh sorbent added to the system should be sufficient to
replace the spent sorbent discharged with the process waste-water stream.
If insufficient sorbent is added, the SO^ removal performance of the
scrubber will decrease. If more than the required amount of sorbent is
added, its concentration will build up in the system and may eventually
result in chemical scale. In addition, adding too much fresh sorbent will
increase process operating costs. A pH controller is used to monitor the
sorbent feed rate. A pH measurement below a specified set point will result
in an increase in the sorbent rate whereas a high pH measurement will
decrease the sorbent feed rate.
4.2.2 Double Alkali
The double or dual alkali process uses a clear sodium alkali solution
for S02 removal and produces a calcium sulfite and sulfate sludge for
disposal. Although double alkali processes produce a throwaway byproduct, a
4-74
-------
regeneration step is employed to regenerate the active alkali for S02
sorption.
4.2.2.1 Process Description. The double alkali processes developed in
the U.S. use lime as the calcium alkali, but other processes developed in
Japan and still in the development stage in the U.S. use limestone. A
simplified flow diagram of a typical double alkali system is given in
Figure 4.2-2. The process can be divided into three principal areas:
absorption, regeneration, and solids separation. The principal chemical
reactions for a sodium/lime double alkali system are illustrated by the
following equations:
Absorption
2 NaOH + S0
Na2S03 + H2°
(4.2.2-1)
(4.2.2-2)
1/2 0
(4.2.2-3)
Regeneration
Ca(OH)2 + 2NaHS03
Ca(OH) + NaS0
1/2
CaS03 1/2 H20 + 3/2
2NaOH + CaS03 1/2 H2
(4.2.2-4)
(4.2.2-5)
Ca(OH)2 + Na2S04 + 2H20 -»• 2NaOH + CaS04 2H20 (4.2.2-6)
In the scrubber, S02 is removed from the flue gas by reaction with NaOH
and Na2C03, according to Equations 4.2.2-1 and 4.2.2-2. Because oxygen is
present in the flue gas, oxidation also occurs in the system, according to
Equation 4.2.2-3. Most of the scrubber effluent is recycled back to the
scrubber, but a slipstream is withdrawn and reacted with slaked lime in the
regeneration reactor according to reactions 4.2.2-4, 4.2.2-5, and 4.2.2-6.
The presence of sulfate in the system is undesirable in that it converts
4-75
-------
SCRUBBED GAS
I
-»J
CT>
SCRUBBER
FLUE GAS
LIME H2O
\ \
LIME
SLAKER
REACTOR
GAS TO STACK
SCRUBBER FEED
U THICKENER LJ
WASTE
CALCIUM
SALTS
Figure 4.2-2. Simplified flow diagram for a sodium/lime double-alkali process.
72
-------
active sodium to an inactive form, thus lowering S02 removal or increasing
sodium consumption for a fixed S02 removal.
The regeneration reactor effluent, which contains calcium sulfite and
sulfate is sent to a thickener where the solids are concentrated. The
thickener overflow is returned to the system, and the underflow containing
the calcium solids is further concentrated in a vacuum filter (or other
device) to about 50 percent solids or more. The solids are washed to reduce
the soluble sodium salts in the adherent liquor prior to disposal, and the
wash water is returned to the scrubber.
4.2.2.2 Development Status. Several process vendors currently offer
double alkali systems commercially in the United States. Double alkali
systems are currently operating or planned for use at ten industrial boiler
o
sites, with the smallest application treating 230 Mm /min (8100 scfm) and
the largest treating 8640 Nm3/min (305,000 scfm) of gas.74 Table 4.2-2
presents a summary of double alkali scrubbing systems applied to U.S.
industrial boilers.
4.2.2.3 Applicability to Nonfossil Fuel Fired Boilers. Although
double alkali scrubbing is generally applicable to boilers cofiring
nonfossil and fossil fuels, specific characteristics of the fossil and
nonfossil fuels will affect system design and performance. As described in
Section 4.2.2.5, the fuel characteristics having the greatest impact on
design and operation are the sulfur and chloride contents. Systems applied
to boilers cofiring nonfossil fuels, which are naturally low in sulfur, with
other low sulfur fuels will require the use of a dilute absorbing solution
to avoid regeneration problems. Some of the nonfossil fuels, such as RDF,
contain relatively high amounts of chlorides (over 0.1%). Cofiring these
fuels with other high chloride fuels could cause high chloride levels in the
scrubbing loop resulting in stress corrosion and possibly reducing
concentrations of active alkali. As described below, a prescrubber can be
used to remove the chlorides before the double alkali system. Another
possible design solution to the chloride problem is the specification of
construction materials that will resist chloride attack.
4-77
-------
TABLE 4.2-2. SUMMARY OF OPERATING AND PLANNED INDUSTRIAL BOILER DOUBLE ALKALI SYSTEMS.74
00
Installation/Location
ARCO Polymers
Monaca. PA
Caterpillar Tractor Co.
East Pconia, ILL
Caterpillar Tractor Co.
Juliet. ILL
Caterpillar Tractor Co.
Mapleton, ILL
Caterpillar Tractor Co.
Morton, ILL
Caterpillar Tractor Co.
Mossville, ILL
Firestone Tire and
Rubber
Potts town, NY
Genera"! Motors, Corp.
Parma, OH
Grisson Air Force Base
Rimlrav U-i 1 1 T M
uunKer MI i i , in
Santa Fe Energy Corp.
Bakersfield, CA
Vendor or
Developer
FMC
FMC
ZURN
FMC
ZURtl
ZURN
FMC
G.M.
Neptune/
Ai rpol
FMC
Size
(SCFM)
305,000
210,000
67,000
236,000
38,000
140,000
8070
128,400
oo nnn
oc ,uuu
70,000
No. of
FGD Units
3
4
2
5
2
4
1
1
i
1
Fu
Type
(2)
C
C
C
C
C
C
C 2
C
r T
0
el
%S
3
3.2
3.2
3.2
3.2
3.2
.5-3.0
2.5
n-i c
1.5
S02(1)
Inlet (ppm)
1800
2000
2000
2000
2000
2000
1000
800-1300
710
—-*, *-t . ,J^T.J -i-uj- a L f. ±.z :
SO?'1'
Removal (%)
90
90
90
90
90
90
90.5
90
96
Waste
Disposal
Landfill
Landfill
Landfill
Landfill
Landfill
Landfill
Landfill
Landfill
Landfill
Landfill
(1) Inlet SO- and percent SO- removal are as reported to PEDCo by FGD system operators. Values reported may represent
anything from single point wet chemical determinations to continuous monitoring results. Methods used to
determine the values reported may or may not be EPA approved.
(2) C = Coal
-------
A potential limitation of the double alkali technology, although not as
severe as with the once through sodium systems, is the need to dispose of
the solid waste byproduct. The waste consists of calcium sulfite and
sulfate salts and generally contains from 30 to 50 weight percent water.
Because of the high concentration of soluble species in the scrubbing
solution, the wastes will also contain soluble salts (such as Na,,S03,
Na2SO,, and NaCl) as well as the relatively insoluble calcium salts.
However, the soluble salts content of the waste can be reduced to less than
1 weight percent when the waste is washed to recover the sodium.
4.2.2.4 Reliability/Operability. Since there are few double alkali
systems with long-term operating histories in the U.S., it is difficult to
assess the overall reliability of this technology. A limited amount of data
has, however, been reported in the EPA Industrial Boiler FGD Survey for
seven different industrial boiler sites, and that data indicates that
reported double alkali system reliability averages slightly higher than
90 percent. In addition two dual alkali systems tested by the EPA showed
overall reliabilities of 89 percent and 95 percent.
4.2.2.5 Factors Affecting Performance. Fuel characteristics such as
the sulfur and chlorine content can have major impacts on the design and
operation of a double alkali system. Major operating variables include the
L/G and alkali addition rate.
Combustion of low sulfur fuels results in a higher ratio of oxygen to
sulfur dioxide in the flue gas than does combustion of high sulfur fuels.
The additional oxygen promotes the oxidation of sodium sulfite to sodium
sulfate. Since sodium sulfate does not react with hydrated lime in the
presence of concentrated sodium sulfite, some active sodium is lost in the
regeneration step. This loss has the same effect as reducing the sodium
alkali feedrate. Oxidation can be minimized in low sulfur fuel applications
by using a dilute absorbing solution (active sodium concentration less than
0.15 Molar). At the resulting low sulfite concentrations, the sulfate will
react with calcium to regenerate the scrubbing liquor. For higher sulfur
applications, oxidation can be minimized by using a concentrated absorbing
4-79
-------
solution (active sodium concentration greater than 0.15 Molar) and sulfate
can be coprecipitated with calcium sulfite.
Chlorides absorbed from the flue gas are difficult to remove and can
cause problems if they build up in the system. The only mechanism for
chlorides to leave the system is in the liquor contained with the solid
waste. However, chlorides are recovered and recycled to the absorber when
the waste is washed to recover sodium. In addition to decreasing the
concentration of active alkali in the absorber, high levels of chlorides can
result in stress corrosion. A solution proposed by one vendor is to use a
78
prescrubber to remove chlorides before the double alkali system. The use
of a prescrubber with a separate liquor loop, however, could cause water
balance problems in the system. Since all the evaporation loss would occur
in the prescrubber, the only water loss from the double alkali system would
be the water occluded with the solid waste. This small water loss would not
allow enough water addition for the normal cake washing (more than one
79
displacement wash), demister washing, pump seals, and lime slaking.
Another possible solution to the chloride problem is to carefully
select materials of construction that will withstand chloride attack. Lined
carbon steel could be used for most of the tankage, and 317 stainless steel
or plastic for scrubber internals. The 317 steel has a higher molybdenum
content than 316/316L steel and is more resistant to stress corrosion than
316L steel. Plastic may be preferred for small systems, but may present
support problems.
The effects of variable L/G, pH, and pressure drop on double alkali
process operation are shown in Figures 4.2-3 and 4.2-4 respectively.
Figure 4.2-3 illustrates the increase in S0? removal performance due to
3
increased L/G. Typical double alkali L/Gs range from about 1.3 to 3.4 1/m
(10 to 25 gal/1000 ft3). The effects of pH are shown in Figure 4.2-4. The
operating pH of the system can be adjusted by changing the sorbent feed rate
and/or adjusting the pH of the regenerated liquor. In general, as shown by
Figure 4.2-4, SO^ removals decrease rapidly below pH 6. High pH levels
(pH 9 or above) will result in calcium carbonate formation which can result
4-80
-------
2/ACTUAL m3
3 4
100
FUEL = COAL
pH = 5.8-7.1
SINGLE STAGE ABSORBER
20 30
L/G-Gal/IOOOacf
Figure 4.2-3.
SOo removal versus L/G ratio for the Envlrotech/Gadsby Pilot Plant
with a single stage polysphere absorber.**0
4-81
-------
100
90
Q
uu
§80
5'
LU
oc
«
O
CO
70
60
o o
OOo
L/G = 2.5 £/m3
AP = 4in H2O
TWO-STAGE ABSORBER
456
SCRUBBER EFFLUENT pH
Figure 4 2-4. SCL removal versus scrubber effluent |$ for the Envirotech/Gadsby
Pilot Plant with a two-stage absorber.
4-82
-------
in scale formation. Consequently, the operating pH of double alkali systems
is generally in a range of pH 6 to 8.
4.2.3 Lime and Limestone
The lime and limestone F6D processes use a slurry of calcium oxide or
calcium carbonate to absorb S02 in a wet scrubber. A byproduct calcium
sulfite/sulfate sludge is produced for disposal.
4.2.3.1 Process Description. The absorption of S02 from flue gases by
a lime or limestone slurry involves both gas-liquid, and liquid-solid mass
transfer. The chemistry is complex, involving many side reactions. The
overall reactions are those of SCL with lime (CaO) or limestone (CaC03) to
form calcium sulfite (CaSOo 1/2 HpO) with some oxidation of the sulfite to
form calcium sulfate (CaSO, 2H,,0). These reactions can be represented as
fol1ows:
Lime
S02 + CaO + 1/2 H20 ->• CaS03 1/2 H20 (4.2.3-1)
S02 + 1/2 02 + CaO + 2H20 •»• CaS04 2H20 (4.2.3-2)
Limestone
S02 + CaC03 + 1/2 H20 ->• CaSOg 1/2 H20 + C02 (4.2.3-3)
S02 + 1/2 02 + CaC03 + 2 H20 * CaS04 2H20 + C02 (4.2.3-4)
The calcium sulfite and sulfate crystals precipitate in a reaction vessel or
hold tank which is designed to provide adequate residence time for solids
precipitation as well as for dissolution of the alkaline additive. The hold
tank effluent is recycled to the scrubber to absorb additional S02. A slip
stream from the hold tank is sent to a solid- liquid separator to remove the
precipitated solids from the system. The waste solids, which may vary from
35-70 weight percent solids, are generally disposed of by ponding or
landfill. A simplified flow diagram is presented in Figure 4.2-5.
4-83
-------
I
00
SO; ABSORBER
FLUE GAS'
TO STACK
LIME ~
OR
LIME
STONE
LIME
SLAKER
CRUSHING
AND
GRINDING
SLURRY
MAKE-UP WATER
EFFLUENT HOLD TANK
SECOND STAGE
SOLID LIQUID
SEPARATOR
OR
SETTLING POND
SOLID-LIQUID
SEPARATOR
SOLID WASTE
Figure 4.2-5. Process flow diagram for a typical lime or limestone wet scrubbing system.
84
-------
Auxiliary equipment associated with this process includes a reagent
preparation system. Reagent preparation may consist of limestone grinding
and slurrying or lime slaking. However, for most industrial boilers, due to
their small size, preground lime and limestone may be purchased and the feed
preparation system will consist of storage silos and either lime slaking or
limestone slurrying equipment.
Addition of adipic acid to the FGD slurry can enhance S02 removal and
improve the reliability and economics of lime and limestone FGD systems.
Adipic acid addition provides a buffering action which limits the drop in pH
that normally occurs at the gas/liquid interface during SCL absorption.
This stablilized pH results in an increased mass transfer rate of SCL into
the liquid phase. In addition, the capacity of the scrubbing liquor
available for reaction with S09 is increased by the formation of calcium
82
adipate in solution. Adipic acid addition also increases lime or
limestone utilization. As a result, limestone grinding requirements and
solid waste generation are somewhat lower than those for a conventional
83
limestone FGD system.
4.2.3.2 Development Status. Both lime and limestone FGD technology is
established and commercially available. Lime FGD technology was first used
to control S09 emissions on commercial boiler pilot plants in England about
BC
40 years ago. As shown by Table 4.2-3, there are currently two operating
systems on industrial boilers in the U.S.; one lime system treating
3
2380 Mm /min (84,000 scfm) of gas, and one limestone system treating
1560 Nm3/min (55,000 scfm) of gas.86
In addition to industrial boiler use, some 34,000 MW of coal-fired
electrical generating capacity in the United States has been committed to
lime or limestone scrubbing. This figure includes 28 facilities in
operation, 35 under construction, and another 16 in the planning stages
(i.e., contract awarded, letter of intent signed, or requesting/evaluating
bids).85
Emission test results from an EPA test facility at the Shawnee Power
Station in Tennessee have demonstrated an average S02 removal of 97 percent
for an industrial boiler-size, adipic acid enhanced, venturi/FGD system. A
4-85
-------
TABLE 4.2-3. SUMMARY OF OPERATING LIME AND LIMESTONE^SYSTEMS
FOR U.S. INDUSTRIAL BOILERS AS OF MARCH 19788'
Process
Lime
Lime and
Limestone
Vendor
Koch Engineering
Research
Cottrell -Banco
Company/Location
Armco Steel
Middletown, OH
Rickenback Air
Force Base
Columbus, OH
New or
retrofit
R
R
Size -
scfm
84,000
55,000
Fuel
Type
Coal
Coal
Sulfur (%)
0.8
3.6
-F»
I
-------
demonstration of this technology on a full scale utility boiler is currently
underway at Springfield City Utilities' Southwest Power Plant, with the
results expected by the fall of 1981.
4.2.3.3 Applicability to Nonfossil Fuel Fired Boilers. Both lime and
limestone processes are applicable to industrial boilers as shown in
Table 4.2-3. The processes use readily available sorbents at moderate
prices. As with the double alkali process, a potential limitation of the
lime and limestone processes is the requirement for disposal of the waste
sludge byproduct. But the problem associated with the presence of highly
soluble salts in the waste is much less severe than for the double alkali or
once through sodium processes.
The presence of adipic acid on the EPA's hazardous materials list
should not exclude its use as an F6D additive. Bioassay tests run on sludge
samples from the Shawnee facility show no significant difference in toxicity
between adipic acid enhanced system sludge and sludge samples from systems
without adipic acid. Additional studies on leachate toxicity have indicated
that sludge generated from systems using adipic acid show toxicity to be
QQ
well within EPA limits.
4.2.3.4 Reliability/Operability. Reliability of lime and limestone
FGD systems for industrial boiler applications is difficult to assess since
there are only two installed systems in the U.S. and only one of those, the
Bahco system located at Rickenbacker Air Force Base (RAFB), has been
operational over a long period of time. Scrubber performance at the RAFB
facility has generally been quite good except for the early stages of
operation in which several startup problems resulted in significant amounts
of downtime. From November 1976 through December 1978, the RAFB system
illustrated that an industrial boiler FGD system can operate with high
reliability as it operated 95 percent or more of the time during that period
except for the months of January, February and March 1978. During those
three months, system downtime was caused by a severe blizzard which resulted
89
in the freeze-up of several lines. This problem can be mitigated or
avoided by insulating exposed lines and by keeping the slurry circulating
4-87
-------
through the lines whenever possible during periods of downtime in severely
cold weather.
The addition of adipic acid to the lime/limestone slurry has been shown
to improve overall utilization of the lime/limestone. This decreases the
amount of lime/limestone solids makeup required and also the amounts of
solids recirculated in the system. This should improve the overall
reliability of the lime/limestone system.
In addition to good performance levels in the U.S., Japanese lime and
limestone FGD systems have also demonstrated high reliabilities. Recent
reports on Japanese installations have documented system reliabilities of
greater than 95 percent.
4.2.3.5 Factors Affecting Performance. The removal of SCL from
industrial boiler flue gas in a lime or limestone FGD system involves a
gas-liquid-solid mass transfer process and thus is more complex than the
once through sodium or double alkali FGD systems which involve only gas-
liquid mass transfer in the scrubbing step. As a rule, a large portion of
the alkalinity required for SO^ removal in lime and limestone systems is
derived from solids dissolution in the scrubber. Since solid-liquid
reactions tend to be significantly slower than do liquid-liquid reactions,
it is advantageous to minimize the amount of solids dissolution required by
maximizing the amount of liquid phase alkalinity in the scrubber feed
liquor. For this reason systems which operate with high magnesium and
sodium concentrations but low chloride levels exhibit higher S09 removals
90
than systems which are lower in soluble alkalinity.
Gas maldistribution can be a major problem in lime and limestone FGD
systems, particularly in large units. Unlike once through sodium and double
alkali systems, lime and limestone FGD systems normally utilize "open"
contactors such as spray chambers. While this practice helps to minimize
potential scaling and plugging problems often associated with lime and
limestone systems, it encourages gas distribution problems. Portions of the
scrubber can become liquid phase alkalinity limited due to gas maldistribu-
tion even though the total alkalinity entering the scrubber is sufficient
for good SCL removal. Scrubber design should therefore incorporate
4-88
-------
straightening vanes and/or open packing to encourage good gas distribu-
tion.90
Several design and operating variables should be considered in the
design of a lime or limestone FGD process. The effects of the following
major variables on SCL absorption efficiency and/or overall process
operations are briefly discussed:
L/G Ratio - Higher SCL removal efficiences are achieved at higher
L/6 ratios up to the point where flooding and poor gas distribution
occurs.91 Typical L/Gs range from 5-15 1/m3 (35-100 gal/1000 ft3).
Slurry pH - Higher S02 removal efficiencies are achieved with
higher pH levels. Since scaling can occur at high pH's (pH greater than 9)
typical control points for a lime system are in the pH 8-9 range. Because
limestone systems are buffered, they typically operate in the pH 5-6
range.
Effects of Soluble Species - The concentration of dissolved ions
in the scrubbing slurry directly affects the liquid phase alkalinity and
hence the systems ability to remove sulfur species from flue gas. For a
given set of operating conditions, high concentrations of Na and Mg will
improve the S09 removal efficiency of a system and high concentrations of
93
Cl will reduce it. Addition of organic acids, such as adipic acid, can
also improve the performance of a limestone system by increasing the
dissolved alkalinity in the scrubbing slurry and increasing the limestone
94
utilization.
Ash Removal - Although fly ash can be removed simultaneously with
SOp, the trend has been to remove it upstream for the following reasons: to
decrease erosion in the scrubber and associated equipment such as pumps,
piping, nozzles, and fans; to provide dry fly ash for sludge fixation; and
to avoid particulate emission excursions during periods of scrubber
95
inoperation.
Oxidation - Forced oxidation systems increase the amount of
calcium sulfate (gypsum) in the waste which is produced by sparging air into
the system. A high sulfate sludge is more easily dewatered and has better
structural properties than does the more difficult to handle thixotropic
4-89
-------
calcium sulfite sludge. Application of forced oxidation to FGD systems
using adipic acid additive may result in degradation of the adipic acid in
the slurry. However, testing is still being conducted on these effects at
Springfield City Utilities' Southwest Power Plant and the final results
should be available in Fall 1981.
4.2.4 Dry Scrubbing
Dry flue gas desulfurization (FGD) processes that are generally
applicable to boilers cofiring fossil and nonfossil fuels are 1) spray
drying of a solution or slurry of alkaline material in a flue gas with
collection of the dry FGD waste product in a baghouse or ESP, and 2) dry
injection of alkaline material into a flue gas with FGD waste product
collection in an ESP or baghouse. Since spray drying is the only comrner-
cially developed dry FGD process, only spray drying is discussed below.
4.2.4.1 Process Description. In a spray drying process, flue gas is
contacted with a solution or slurry of alkaline material in a vessel of
97
relatively long residence time (5 to 10 seconds). Generally the particu-
late matter has not been removed prior to entering the absorber, and the
spray drying process acts as a combined particulate/SCL removal system. The
flue gas SCL reacts with the alkali solution or slurry to form liquid phase
salts which are dried to about one percent free moisture. These solids,
along with fly ash are entrained in the flue gas and carried out of the
dryer to a particulate collection device such as an ESP or baghouse.
Systems using a baghouse for particulate removal report additional S02
sorption occurring in the baghouse. A generalized diagram for a typical
spray drying process is shown in Figure 4.2-6.
Reaction between the alkaline material and flue gas S02 proceeds both
during and following the drying process. The mechanisms of the S02 removal
reactions are not well understood, and it has not been determined whether
SCL removal occurs predominantly in the liquid phase, by absorption into the
finely atomized droplets being dried, or by reaction between gas phase S02
and the slightly moist spray dried solids. The overall chemical reactions
99
for this process are shown below.
4-90
-------
Hot or Warm Gas Bypass
r +
lHot IWarm
1 fc '
r> Bollei Preheater |
1
Air
Combustion Air
V
^T
Spra
Drye
\y
Spent
Solids
r1
Clean Gas to
Atmosphere
A
! A
1 Clean Gas. 1 \
i /f^ w L A
1 A \$LJ) stack
I Fan
y 1
r 1 r
X* — ^
"Flue Gas" Baghouse
& Solids or ESP
V
t Partial Recycle of Solids ^
(Lime Reagent) 1
Sorbent Product Solids &
Slurry Fly Ash Disposal
Tank
]
Sorbent Storage
Figure 4.2-6. Typical spray dryer/particulate collection process flow diagram.
98
-------
S02 + Na2C03 + Na2S03 + C02 (4.2.4-1)
S02 + CaO + 1/2 H20 + CaS03 1/2 H20 (4.2.4-2)
In addition to these primary reactions, sulfate salts will be produced by
the following reactions:
Na2S03 + 1/2 02 -v Na2S04 (4.2.4-3)
S03 + Na2C03 1- Na2S04 + C02 (4.2.4-4)
S02 + CaO + 1/2 02 + 2H20 •> CaS04 2H20 (4.2.4-5)
Liquid to gas (L/G) ratios for spray drying are typically 0.03 to
0.04 1/m3 (0.2 to 0.3 gal/1,000 ft3). This low liquid rate is not
sufficient to saturate the gas. Gas exit temperatures are typically in the
65-93 C (150 to 200 F) range which provides a safe margin against water
condensation.
4.2.4.2 Development Status. Spray drying technology for removing S02
from boiler flue gas has been limited to pilot-scale testing of industrial
boiler sized systems (280 to 560 m3/min [10,000 to 20,000 acfm]) at several
utility locations burning low sulfur western coals. This technology is
being commercially offered by several vendors, and five spray drying FGD
systems have been sold for industrial boiler applications. These systems
are being applied to boilers burning coals with a fairly wide range of
sulfur contents (0.6 to 3.5 percent S). Table 4.2-4 summarizes the
commercial spray drying systems sold for application to industrial boilers.
In addition eleven full scale utility systems have been sold. The utility
systems are being applied to low sulfur (ler-s than 2 percent) coal-fired
units and S0? removal guarantees from the vendors are as high as 90 percent.
However, it still remains to be shown whether spray dryer systems will be
able to achieve high S0? removal efficiencies when applied to full scale
industrial boiler installations firing a range of coal types.
4-92
-------
TABLE 4.2-4. SUMMARY OF INDUSTRIAL BOILER SPRAY DRYING SYSTEMS101
•Company
Location
Strathmore Paper Co.
Woronoco, MA
(operating)
Celanese
Cumberland, MD
(operating)
University of
Minnesota
Minneapolis, MN
Department of Energy
Argonne, IL
Container Corp.
Pittsburgh, PA
Vendor
Mikropol
Wheel abrator-
Frye/
Rockwell Int.
Carborundum
Environmental
Systems, Inc.
Niro Atomizer,
Inc. /Joy-
Western
Precipitation
Division
Ecolaire, Inc.
Sorbent
Lime
Lime
Lime
Lime
Lime
Size
(Ib steam/hr)
85,000
110,000
2 units @
120,000 acfm
each
170,000
170,000
Fuel
Type % Sulfur
Coal 2 to 2.5
Coal 1 to 2
Coal 0.6 to
0.7
Coal 3.5
Coal 1
S02 Removal
Guarantee
(%)a
75% on 3% S coal
85% on 2% S coal
70%
80% ,
(1.2 Ib S02/10° Btu)
NA
ID
CO
NA = Not available.
aVendor design guarantees under specific operating conditions.
-------
4.2.4.3 Applicability to Nonfossil Fuel Fired Boilers. Spray drying
technology is an applicable S0~ control method for all industrial boiler
types firing low to medium sulfur fuels (less than three percent sulfur).
however, the technical and economic viability of this process is not clear
for applications requiring high SCL removals (90 percent) for high sulfur
fuels (such as coals containing more than three percent sulfur).
Some NFFBs, such as those firing mixtures of wood and fossil fuels,
will have higher moisture contents in the flue gas than boilers firing
fossil fuels alone. This could prevent the successful application of a
spray drying system. However, other nonfossil fuels, such as RDF, have
lower moisture contents than most wood fuels. Therefore, the increase in
flue gas moisture content when firing RDF/fossil mixtures will not be as
great as the increase for wood/fossil mixtures.
The potential for condensation in downstream particulate collection
equipment, especially during system upsets, is also a concern. Condensation
problems may be avoided by bypassing the fabric filter during system upsets
and by maintaining spray dryer outlet temperatures at an adequate margin
above the adiabatic saturation point. The effects of condensation on
downstream equipment, and system performance using varying quality fuels are
questions that will be resolved only after additional operating experience
is obtained in either utility or industrial boiler applications.
4.2.4.4 Re!iability/Operability. Since dry scrubbing is a relatively
recent innovation in industrial boiler FGD no data are available on the long
term reliability or operability of these systems. However, since they are
less complex mechanically and no more complex chemically than wet calcium or
sodium based scrubbing systems they should ultimately prove to be at least
as reliable and operable.
4.2.4.5 Factors Affecting Performance. The performance of a spray
dryer FGD system depends on several factors, the two most important being
the L/G ratio and the stoichiometric ratio of sorbent to SOg. Unlike a wet
scrubbing system the amount of water that can be added (measured by the L/G)
is limited by heat balance (or dew point) considerations for a given inlet
flue gas temperature and approach to saturation. Typical L/G ratios range
4-94
-------
from 0.03 to 0.04 1/m3 (0.2 to 0.3 gal/1000 ft3). The stoichiometry is
varied by raising or lowering the concentration of a solution or slurry
containing this fixed amount of water. As sorbent stoichiometry is
increased to raise the level of SO, removal, there are two potentially
i no f-
limiting factors:1^
- Sorbent utilization may decrease, raising sorbent and disposal
costs per unit of S02 removed.
- An upper limit on the solubility of the sorbent in the solution,
or on the weight percent of sorbent solids in a slurry may be
reached.
Methods of circumventing these limitations include recycling sorbent,
either from solids dropped out in the spray dryer or from the particulate
I owe
104
collection device and operating the spray dryer at a lower outlet
temperature; that is, at a closer approach to saturation.
Based upon pilot unit test results high S02 removals (up to 90 percent)
can be achieved for low-sulfur coal applications, using either lime or
sodium based sorbents. Stoichiometric ratios of 2.3 - 3.0 were required for
lime operations whereas Stoichiometric ratios of only 1.0 - 1.2 were
required to achieve the same S02 removal for sodium operations. It has also
been reported that 90 percent SO^ removal may be achieved with a Stoichio-
metric lime requirement of 1.3 - 1.7 by recycling some of the unreacted
105
sorbent. A sodium based system should be able to achieve higher S02
removals than lime based systems on high sulfur coals due to the greater
reactivity of sodium hydroxide or sodium carbonate compared to lime.
Spray dryer design can also be affected by the choice of the particu-
late collection device. Bag collectors have an inherent advantage in that
unreacted alkalinity in the collected waste on the bag surface can react
with the remaining S09 in the flue gas. Some process developers have
1 Dfi
reported S02 removal on bag surfaces on the order of 10 percent. A
disadvantage of using a bag collector is that since the fabric is somewhat
sensitive to wetting, a safe margin above saturation temperature (on the
order of 25 to 35°F) must be maintained for bag protection. Some vendors
claim that an ESP is less sensitive to condensation and hence can be
4-95
-------
operated closer to saturation (less than a 25°F approach) with associated
increase in spray dryer performance. However, they feel that S09 removal
107
within the collector is not likely to be as high as in a baghouse.
4.2.5 Performance of Sulfur Dioxide Control Techniques
This section presents continuous S(L emission monitoring data for five
wet FGD systems and a lime spray drying system. These emission data are
representative of the S02 removal capability of well designed, operated and
maintained industrial boiler wet FGD systems. All sampling and analyses
were conducted in accordance with the procedures specified in 40 CFR 60
Appendix B.
As with the particulate matter emission data, tests not considered to
be representative of well operated FGD systems are not presented in this
chapter, but are included in Appendix C along with documentation of the
reasons why they were not considered to be representative. Three such tests
of wet FGD systems are discussed in Appendix C.
4.2.5.1 Emission Reduction Data for Wet FGD Systems. This section
presents the results of five continuous SO,, emission monitoring tests of
industrial boiler wet FGD systems. All of the tests were conducted by EPA.
Data were collected for two dilute double alkali systems, one sodium
throwaway system, a lime system, and a limestone system with adipic acid
addition. Table 4.2-5 summarizes the five test programs. Figures 4.2-7 to
4.2-11 show the 24-hour average S02 removal, boiler load, and scrubbing
slurry pH. Only days with 18 hours or more of test data are presented;
missing days (days where 18 hours of data were not obtained) are indicated
by a break in data shown in Figures 4.2-7 to 4.2-11.
Table 4.2-5 shows that each system averaged more than 90 percent S02
removal over the test period. In addition, average outlet S09 concentra-
c f-
tions for each test period were 192 ng/J (0.45 lb/10 Btu) or less.
Thirty days of continuous emissions data were gathered at the sodium
throwaway scrubbing system at Location I. Figure 4.2-7 shows consistent
high S02 removal, averaging 96.2 percent for the test period. Table 4.2-5
shows that daily average inlet S02 concentrations ranged from 1961 to
2480 ng/J (4.6 to 6.3 lb/106 Btu). The scrubbing solution pH was
4-96
-------
TABLE 4.2-5. SUMMARY OF CONTINUOUS S02 EMISSION DATA
AT FIVE INDUSTRIAL BOILER WET F6D SYSTEMS
24-hr Average Results
Location
I
HI/NO, i
Ill/No. 3
•£> IV
l
vo
-J IV
System No
a Type Days
Sodium Throwaway
Double Alkali
Double Alkali
Lime
Limestone with
Adiplc Acid Addition
'of Datab
30
17
24
29
30
Inlet SO
Range
1961-2480
1235-2000
1180-2285
1927-2432
1333-2765
z (ng/J)C
Average
2348
1646
1606
2250
2125
Outlet S02 (ng/J)c
Range
54-267
81-213
37-446
94-294
56-262
. d
Average
87
138
128
192
122
x so2
Range
88-98
88-95
74-97
88-96
90-97
Removal
Average
96
92
92
91
94
Comments
Tray & quench liquid scrubber;
coal sulfur » 3.6X
Two Tray scrubber; Design
pH = 5.5 to 7.5; Design
L/G « 2.7 t/m ;
Same design as Location IH/fl.
Two "Inverted venturi " stages;
Coal Sulfur = 3.5X.
Coal sulfur 2.2 to 3.5X;
Adipic Acid concentrations of
1770 to 3000 ppm.
*More complete descriptions, data testings, and references for test reports can be found In Appendix C.
D0n1y days with 18-hrs or more of test data are reported.
cD1v1de by 430 to convert to lb/106 Btu.
'Arithmetic mean of 24-hr averages for test peri'od.
-------
10
>
o
lOOr
90
CM
O
t/1
80
Average S02 Removal = 96.2%
70
10
15
20
25
30
-o
-------
100
•3 90
8.
0~
00
80
Average S02 Removal = 91.6%
15
20
25
30
90
80
70
•o
3 60
0)
£ 50
o
CO
** 40
30
10
15
20
25
30
9
8
7
6
5
10 15 20
Test Days
25
30
Figure 4.2-8.
Daily average S02 removal, boiler load, and
slurry pH for the dual alkali scrubbing
process at Boiler No. 1, Location III.
4-99
-------
100
>
-------
lOO
cv
o
I/I
80f
^
Average S02 Removal = 91.5%
10
15
20
25
30
90r
80-
70-
60.
i 50
OD
" 40
30
10
15
20
25
30
E
10 15 20
Test Days
25
30
Figure 4.2-10. Daily average S02 removal, boiler load, and
slurry pH for lime slurry scrubbing process
at Location IV.
4-101
-------
O
I
•O
(0
O
s.
0)
100,
90
80
80
70
60
50
40
30
20
Average S0_ Removal = 94.3%
10
15
20
25
30
10
15
20
25
30
3000r
"H §. 2500
j o.
u >, 2000
t- S-
Q. S-
i ^ isoo
10
15
20
25
30
a.
7.0r
6.0-
5.C
4.0
3.0
10
15
Test Days
20
25
30
Figure 4.2-11. Daily average SO,, removal, boiler load, adipic
acid concentrati&n, and slurry pH for limestone
system at Location IV.
4-102
-------
consistently maintained at about pH 8. As discussed in Section 4.2.1.5,
proper pH control is important for maintaining the sorbent feed rate
required for the desired S02 removal.
Figures 4.2-8 and 4.2-9 show daily average results for two similar
double alkali systems at Location III. The two systems averaged 91 and
92.2 percent SCL removal over the respective 17- and 24-day test periods.
Daily average inlet S02 concentrations ranged between 1235 and 2000 ng/J
(2.9 and 4.7 lb/106 Btu) at Boiler No.l and between 1180 and 2285 ng/J
(2.8 and 5.3 lb/106 Btu) at Boiler No.3. The scrubbing slurry pH for both
systems was maintained close to pH 6 during the test periods. The desired
operating pH of most double alkali systems is pH 6 to 8 (Section 4.2.2).
The design pH for the systems at Location III is pH 5.5 to 7.5 and the
design L/G ratio is 2.7 1/m3 (20 gal/103 ft3).
The lowest S02 removals observed at Location III, Boiler No.3 (Test
days 9 and 10 in Figure 4.2-9) were during FGD system start-up after the
scrubber had been taken off-line due to low boiler load requirements at the
plant.
Figure 4.2-10 shows the daily average results of tests of a lime
scrubbing system at Location IV. Average S0« removal for the period was
91.5 percent and daily average inlet S09 concentrations ranged between 1927
6
and 2432 ng/J (4.5 and 5.7 lb/10 Btu). The lowest S02 removals were
observed during the last few days of testing when the scrubbing slurry pH
dropped below pH 6. As discussed in Section 4.2.3, typical control points
for lime systems are more often in the pH 8 to 9 range. Figure 4.2-10 shows
generally higher S0« removals for the periods during which slurry pH was
maintained near pH 8.
Figure 4.2-11 presents the results of 30-days of testing at Location IV
during which limestone reagent was used (instead of lime) and adipic acid
was added, to the scrubbing solution. These data show an average S02 removal
of 94.3 percent for the test period. High S02 removals were obtained over a
wide range of boiler loads. Adipic acid concentrations in the slurry ranged
from 1770 to 3000 ppm and slurry pH was maintained near pH 5. Inlet S02
concentrations ranged from 1333 to 2765 ng/J (3.10 to 6.43 lb/106 Btu).
4-103
-------
The data in Figure 4.2-11 indicate that adipic acid addition contri-
butes to high S02 removals and, with proper pH and adipic acid addition
control, low variability in system performance. Previous testing of the FGD
system at Location IV with limestone slurry had shown S0? removals between
50 and 70 percent. It should be noted that adipic acid addition may not
have been solely responsible for the improved S02 removal efficiency since
the limestone only tests appeared to have been conducted at conditions
outside the design range of the system (see Appendix C).
4.2.5.2 Emission Reduction Data for Lime Spray Drying System.
Figure 4.2-12 illustrates the daily average results for S02 emission
monitoring of the lime spray drying system at Location VI. S02 removal
efficiency ranged from 46 to 80 percent and averaged 68.4 percent over the
test period. S09 concentrations ranged from 1118 to 1905 ng/J (2.6 to
c £•
4.4 lb/10 Btu). Figure 4.2-12 shows S02 removal efficiencies averaging
75 percent on the days when average daily S09 concentrations were 1720 ng/J
e f-
(4.0 lb/10 Btu) or greater. The somewhat variable performance of the spray
dryer can be attributed in part to various system upsets that occurred
throughout the testing period. These upsets include slurry pump problems,
spray dryer plugging and boiler load fluctuations. Over the last six days
of the testing program, a period in which no upsets occurred, the average
daily S0? removal remained near 80 percent.
The average sulfur content of the coal fired during the test was near
2 percent, which is the coal sulfur content the system was designed for. No
data were available for spray drying systems applied to high sulfur coal-
fired boilers.
4.3 PRE-COMBUSTION CONTROL TECHNIQUES FOR SULFUR DIOXIDE
As an alternative to post-combustion controls, S02 emissions from
boilers cofiring nonfossil and fossil fuels can be controlled by pre-
combustion techniques. Pre-combustion control techniques include:
- using naturally-occurring clean fossil fuels
- using physically or chemically-cleaned fossil fuels.
4-104
-------
80
70
60
50
40
10
15
25
30
200C
^ 1800
g1
•^, 160C
o
c/)
tS 140C
*c
120C
100C
800-
10 15 20
Test Days
25
5.0
4.0
o
ro
3.0 -
o
CTl
2.0
l.C
30
Figure 4.2-12. Daily average SO- removal, inlet S02 for
lime spray system at Location VI.
4-105
-------
Both of these techniques control S02 emissions by limiting the SCL
potentially produced during fuel combustion.
Section 4.3.1 describes the use of naturally occurring clean fuels.
Sections 4.3.2 and 4.3.3 discuss fuel cleaning processes. Naturally
occurring clean fuels discussed in Section 4.3.1 are raw low sulfur coal and
raw low sulfur oil which are low enough in sulfur content to meet S02
emission limits with no additional controls. The fuel cleaning processes
discussed in Section 4.3.2 and 4.3.3 are physical coal cleaning (PCC) and
hydrodesulfurization (HDS) of oil. These processes are primarily designed
to control S02 emissions by reducing the sulfur content of the fuel.
However, they may also aid in the control of particulate emissions by
simultaneously reducing the ash content of the fuel. Oil cleaning may
result in reduced NO emissions due to reduction of fuel nitrogen content by
A •
hydrotreating. No performance data are presented for the pre-combustion SOp
emission control technique's because their performance is obvious and well
demonstrated.
4.3.1 Naturally Occurring Clean Fuels
The naturally occurring clean fuels of interest are low sulfur coal and
low sulfur crude oil. Low sulfur coal is defined as run-of-mine (ROM) coal
which can comply with a given emission standard. Where no emission standard
has been delineated, coals with sulfur contents of less than 1 percent by
114
weight are considered low sulfur coals.
The sulfur content of United States coals is quite variable. While
46 percent of the U.S. total reserve base can be identified as low sulfur
coal because its sulfur content is less than 1 percent, 21 percent ranges
between 1 percent and 3 percent in sulfur, and an additional 21 percent
contains more than 3 percent sulfur. The sulfur content of 12 percent of
the coal reserve base is unknown, largely because many coal beds have not
been mined.
Nearly 85 percent of the reserve base of less than 1 percent sulfur
coal is located in states west of the Mississippi River. The bulk of the
western coals are, however, of a lower rank than the eastern coals. On a
4-106
-------
heat content basis, it is estimated that at least 20 percent of the nation's
114
reserve of low sulfur coal is in the East.
Low sulfur western coals can be burned in underfeed and traveling grate
stokers as long as they are designed with sufficient control of undergrate
air to handle any caking that may occur. Caking causes an uneven ash layer
to form on the grate which reduces combustion efficiency unless undergrate
air can be distributed properly. It has been reported that current designs
of some spreader stokers cannot handle caking because they lack the ability
115
to control undergrate air distribution. Since design changes to incor-
porate the necessary air distribution system have not been demonstrated, the
use of those low sulfur coals which cake or have a low ash fusion tempera-
ture is not applicable to these stokers. Other low sulfur coals such as
eastern bituminous, which do not cake or have a low ash fusion temperature,
can be burned in underfeed and traveling grate stokers. The demonstrated
reserve base of low sulfur eastern bituminous coal as of January 1, 1974,
was greater than 24 billion metric tons.
Some spreader stokers of current design also cannot handle coals with
ash fusion temperatures below 1480 K (2200°F), which are typical for many
low sulfur western coals (e.g., the Wyoming subbituminous, Utah bituminous
and the lignites).
Pulverized coal boilers can be designed for almost any type of coal.
The initial choice of fuel will determine the type of pulverizer used, the
tube spacing in the boiler and superheater (low fusion temperature coals
require greater spacing), and the type of materials used in the furnace
wall.118
In 1976 domestic refinery capacity for producing fuel oil from low
sulfur crude was 231,000 m3/day (1,452,000 bbl/day), while consumption was
229,000 m3/day (1,422,000 bbl/day). However, actual U.S. production of low
sulfur fuel oil (LSFO) was 108,000 m3/day (667,000 bbl/day), with the
difference made up by imports. In contrast to low sulfur coal, LSFO derived
from naturally occurring clean crude is readily applicable to all boiler
types and sizes that burn a similar grade of fuel.119
4-107
-------
There are no factors affecting the ability of naturally occurring low
sulfur coal or oil to reduce SO,, emissions, except the actual sulfur content
of the fuel. However, the higher resistivity of the fly ash from the
combustion of low sulfur coal will affect the design of an ESP relative to
that for medium to high sulfur coal. The effect of resistivity on ESP
performance is discussed in Subsection 4.1.4.
4.3.2 Physical Coal Cleaning
Physical coal cleaning is the generic name for all processes which
remove inorganic impurities from coal, without altering the chemical nature
of the coal. Basically, a coal cleaning plant is a continuum of
120
technologies rather than one distinct technology. Each coal cleaning
plant is a uniquely-tailored combination of different unit operations
determined by the specific coal characteristics and by the commercially
dictated processing objectives.
Overall process design philosophy in coal cleaning plants is to use
step-wise separations and beneficiations, with a goal of eventually treating
small, precise fractions of the feed with the more sophisticated and
specific unit operations. In this way, the least costly technologies are
applied to large throughputs and the more costly to much smaller
throughputs. A characteristic of this design philosophy is that multiple
product streams evolve, each with its own set of size and purity properties.
In conventional cleaning plants the separate product streams are blended
prior to shipment, to produce a composite coal meeting the consumer's
specifications. Within the context of supplying industrial boilers with
small quantities of relatively low-sulfur fuel, every opportunity exists for
premium low-sulfur coals to be segregated from the final blending operation
121
and targeted for specialty markets.
4.3.2.1 Process Description. In a modern PCC plant, coal is typically
subjected to: size reduction and screening, separation of coal from its
impurities, and dewatering and drying. Commercial PCC methods are currently
limited to separation of the impurities based on differences in the specific
gravity of coal constituents (gravity separation) and on the differences in
4-108
-------
122
surface properties of the coal and its mineral matter (froth flotation).
A generalized physical coal cleaning schematic is shown in Figure 4.3-1.
Five general levels of coal cleaning are used to categorize the degree
of treatment to which a coal has been subjected. These levels are:
Level 1 -- Crushing and sizing
Level 2 -- Coarse size coal beneficiation
Level 3 -- Coarse and medium size coal beneficiation
Level 4 — Coarse, medium, and fine size coal beneficiation
Level 5 -- "Deep cleaning" coal beneficiation
Level 1 processes are generally used to size raw coal to user
specifications, and to remove overburden. No washing is done and the entire
process is dry.
Levels 2 and 3, in addition to crushing and screening raw coal also
perform a minimum of cleaning. Level 2 provides for removal of only coarse
pyritic sulfur. Level 3 is basically an extension of Level 2 in that both
the coarse and medium size fractions obtained from screening are washed
123
whereas in Level 2 only the coarse fractions are washed.
Level 4 systems provide high efficiency cleaning of both coarse and
medium coal fractions with lower efficiency cleaning of the fines. The
primary difference between Level 4 and the lower cleaning levels is the use
of heavy media processes for cleaning specific size fractions above 28 mesh.
For particles smaller than 28 mesh, cleaning by froth flotation is most
commonly used. Level 4 systems accomplish free pyrite rejection and
124
improvement of heat content.
Level 5 coal preparation systems are unique in that two products are
produced,-a high quality, low sulfur, low ash coal called "deep cleaned"
coal and a middlings product with higher sulfur and ash content. Level 5
provides the most advanced state-of-the-art in physical coal cleaning with
large reductions in pyrite and ash content and improvement of heat content
at high yields. In addition, this system is flexible relative to the types
of coal that can be processed. Variations in raw coal and product
specifications can be handled by varying the heavy medium densities and
careful control of coal sizes treated in various circuits.
4-109
-------
•P.
I
LOWEST
CLEANING
RAW COAL
CRUSHING
SCREENING
PRODUCT
REFUSE
INTERMEDIATE
CLEANING
RAW COAL
CRUSHING
SCREENING
+Y."
FLOAT
PRODUCT
GRAVITY
SEPARATION
SINK
"DEEP"
CLEANING
RAW COAL
REFUSE I FINE
REFUSE
PRODUCT
SINK
COARSE
REFUSE
Figure 4.3-1. Physical coal cleaning unit operations employed to achieve
various levels of cleaning.
-------
Level 5 coal cleaning plants use the techniques and principles utilized
in the first four levels, but combine them in unique ways to maximize mass
and energy recovery. Major operations involved are crushing, screening or
sizing, heavy media separation, secondary separation, dewatering and removal
of fines from process water. The high efficiency of Level 5 is due to the
125
repeated use of these operations to produce the desired products.
4.3.2.2 Development status. There are currently over 460 physical
coal cleaning plants in the U.S. In 1976 about 340 million tons of raw coal
was processed by these plants. This represents 58 percent of the total 1976
U.S. coal production of 590 million tons. The majority of these plants were
designed for ash removal rather than sulfur removal although many do take
out 20-30 percent of the sulfur in the raw coal. The status of coal
1 pe
cleaning plants operated in 1976 is summarized in Table 4.3-1. Some
plants use only one major cleaning process, while the majority use a series
of cleaning processes. The capacity of individual plants varies widely from
less than 200 metric tons per day to more than 25,000 metric tons per
day.127
Levels 1 through 4 are currently in use in operating commercial plants
which produce steam coal. There are examples of Level 5 systems at
metallurgical coal plants where both a low sulfur, low ash metallurgical
>
grade product and a middling (higher sulfur and ash content) combustion
grade by-product are produced. All unit operations proposed for a Level 5
plant are presently used in commercial plants. However, the unit operations
have not yet been combined to form a commercial Level 5 plant for producing
128
steam coal.
4.3.2.3 Applicability to Nonfossil Fuel Fired Boilers. Firing of
physically cleaned coal in industrial stoker-fired boilers is not expected
to have a significant effect on boiler maintenance requirements. In
industrial pulverized coal-fired boilers, firing of physically cleaned coal
129
may reduce boiler maintenance costs.
Physical cleaning of coal should improve the overall performance of a
stoker-fired boiler provided the resultant coal size is acceptable for
stoker firing (1-1/2" x 1/4" with minimal fines). Physical cleaning
4-111
-------
TABLE 4.3-1. PHYSICAL COAL CLEANING PLANTS CATEGORIZED BY STATES FOR 1976.1Z6
State
Alabama
Arkansas
Colorado
Illinois
Indiana
Kansas
Kentucky
-P> Maryland
£ Missouri
PO
New Mexico
Ohio
- Oklahoma
Pennsylvania
(Anthracite)
Pennsylvania
(Bltunlnous)
Tennessee
Utah
Virginia
Hashing ton
West Virginia
Wyoming
Ttotal
Estimated
Total
Coal Production,
1000 tons
21,425
670
0,160
59,251
24,922
560
146,900
2,792
5,035
9,242
44,502
2^770
5,090
81,950
9,295
6,600
36,500
3,700
110,000
23,595
603,055
of
Coal-
Cleaning
Plants
22
1
2
33
7
2
70
1
2
1
10
2
24
66
5
6
42
2
152
1
• 459
Total
Nuiber of Dally
Plants Capacity
for Which of
Capacity
nota
Heportcd
10
0
0
20
6
2
40
0
1
1
13
1
14
50
4
4
29
1
113
1
310 '
He porting
Plants,
Tons
40,600
-
-
136,775
42,000
3,000
245,700
-
3,500
6,000
102,750
550
13,000
205,010
0,520
23,100
143,550
20,000
577,375
600
1,652,030
KsUmobed
Annual
Cnpoc I ty
of
Reporting
Plants,!")
1000 tons
10,150
-
T
34,195
10,500
950
61,425
-
075
1,500
25,690
140
3,250
71,255
2,130
5,775
35,090
5,000
144,345
150
413,210
Nutber of Plants Using Various
Cleaning Methods
Heavy
Media
0
1
2
17
2
-
43
-
-
1
6
1
21
30
1
2
26
1
104
-
266
Jigs
10
-
-
20
5
2
27
-
2
-
11
1
4
19
1
4
15
1
55
-
177
Flotation
Units
6
-
1
4
1
-
16
-
-
1
-
-
4
16
1
2
9
-
59
-
121
Air
Tables
1
-
-
1
-
-
4
-
-
-
1
-
-
20
2
2
0
-
12
1
52
Washing
Tables
12
1
-
1
1
-
20
-
- •
-
2
-
3
15
-
-
15
-
55
-
125
,
Cyclones
6
1
-
0
3
-
24
1
-
1
5
1
2
15
*
1
2
11
-
59
-
144
(a) The estimated annual-capacity valuea for the reporting plan to were calculated from the tlnlly-cn|>aclty values by asaundng an
average plant operation oE 250 days per year (5 clays per week for 50 wccko per year).
-------
partially removes pyrites, ash, and other impurities, thus reducing both SC^
and particulate emissions. As compared to raw coal, physically cleaned coal
is easier to handle and feed, burns more uniformly with less chance for
clinkering, and reduces ash disposal problems. As an example, both a raw
and the corresponding physically cleaned coal were fired in a steam plant
spreader stoker boiler. When firing the raw coal, the boiler could operate
only at about one half capacity. The high ash content of this coal resulted
in nonuniform combustion caused by feeding problems, excessive ash buildup
and clinker formation on the fuel bed. In contrast, the physically cleaned
coal was fired at full capacity with no operational problems.
4.3.2.4 Factors Affecting Performance. Sulfur reduction by physical
cleaning varies depending upon the distribution of sulfur forms in the coal.
There are three general forms of sulfur found in coal; organic, pyritic, and
sulfate sulfur. Sulfate sulfur is present in the smallest amount
(0.1 percent by weight or less). The sulfate sulfur is usually water
soluble, orginating from in-situ pyrite oxidation, and can be removed by
washing the coal. Mineral sulfur occurs in either of the two dimorphous
forms of iron disulfide (FeS2) - pyrite or marcasite. The two minerals have
the same chemical composition, but have different crystalline forms.
Sulfide sulfur occurs as individual particles (0.1 micron to 25 cm. in
diameter) distributed through the coal matrix. Pyrite is a dense mineral
(4.5 gm/cc) compared with bituminous coal (1.3 gm/cc) and is quite
water-insoluble thus the best physical means of removal is by specific
gravity separation. The organic sulfur is chemically bonded to the organic
carbon of the coal and cannot be removed unless the chemical bonds are
broken. The amount of organic sulfur present defines the lowest limit to
which a coal can be cleaned with respect to sulfur removal by physical
methods. Chemical coal cleaning processes, currently in the developmental
stage, are designed to attack and remove up to 40 percent of the organic
sulfur. Physical cleaning typically can remove about 50 percent of the
pyritic sulfur, although the actual removal depends on the washability of
the coal, the unit processes employed and the density of the separating
medium.131
4-113
-------
A trade-off between product yield and purity exists for any one unit
operation of a physical coal cleaning process. Product yield is defined as
the ratio of the clean product heating value divided by the heating value of
the raw coal and can vary from 0 to 1. Product purity refers to the amount
of sulfur retained in the clean product - the lower the sulfur content, the
higher the purity. One unit operation cannot achieve both performance goals
-- either yield is maximized, or purity is maximized, or a compromise is
made between yield and purity. This basic limitation on performance also
applies to an entire plant if that plant only produces one clean coal
product. However, the designer of a multi-product plant may achieve both
performance goals. As an example, one unit operation may be selected for
maximizing product purity although the quantity of this clean product is
relatively small. In this case, a fine fraction (28 x 0 mesh) may be
produced with a pyritic sulfur content reduced by up to 90 percent, but with
a yield of less than 50 percent. If the rejected portions are washed again
at a relatively high specific gravity in another (sequential) unit
operation, a "middling" product with somewhat higher pyritic sulfur content
may be recovered with an overall recovery (between the two products) of the
132
majority of the original heating value.
The inherent design advantages of a multi-product plant do have special
significance for industrial boilers. Since the coal quantities used by
industrial boilers are a small fraction of the total coal demand, it might
be quite attractive for a coal cleaning plant to produce a very clean
product for new industrial boilers and a middling product suitable either
for consumers subject to less stringent emission standards or for large
133
consumers (i.e., utilities) with additional site-specific S02 controls.
4.3.3 Oil Cleaning
Hydrotreating or hydrodesulfurization (HDS) processes are used to
produce oil fuels substantially reduced in sulfur, nitrogen and ash content.
They are chemical processes, which involve contact of the oil with a
catalyst and hydrogen to convert much of the chemically-bonded sulfur and
nitrogen to gaseous hydrogen sulfide (H2S) and ammonia (NH3). These gases
are separated from the fuel and then collected.
4-114
-------
4.3.3.1 Process Description. In a typical hydrotreating process, oil
to be treated is filtered to remove rust, coke and other suspended material.
The oil is then mixed with hydrogen, heated to 340° to 450°C (650° to
850°F), and passed over one or more catalytic reaction beds. The most
widely-used catalysts are composites made up of cobalt oxide, molybdenum
oxide, and alumina, where alumina is the support and the other agents are
promoters.
Numerous chemical reactions occur which lead to removal of most of the
sulfur as H9S. Table 4.3-2 illustrates some of the types of compounds and
135
reactions involved. In an HDS process, hydrogen also reacts with other
species besides sulfur compounds. For example, nitrogen compounds break
down to liberate ammonia from the oil. This is referred to as denitrogena-
tion or denitrification. Nickel and vanadium in the oil, which are bound as
organo-metal compounds, are also liberated by reaction with hydrogen. This
is generally referred to as demetallization. Most of the liberated metals
deposit (as the sulfide) on the catalyst surface or in its pores and slowly
deactivate the catalyst. Other reactions which take place break up large
complex molecules such as asphaltenes and lead to a reduction in carbon
residue for the product oil.
Many companies are engaged in developing and using catalytic hydro-
treating or hydrodesulfurization processes. All are similar in basic
concept and vary only in specifics such as the type of catalyst employed,
the process conditions, and the process complexity. Figure 4.3-2 represents
a simplified flow diagram of an HDS process currently being commercially
marketed. Its basic elements are a feed filter, a heater, a single-stage
catalytic reactor, a gas/liquid separator, a fractionating column, and a gas
treatment section. This simple system is capable of producing fuel oil of
approximately 1 percent sulfur from a feedstock such as atmospheric residual
oil containing 2 percent sulfur. To produce a lower sulfur content product,
additional catalytic reaction stages must be added. A system with two
catalytic reaction stages can produce a fuel of approximately 0.3 percent
sulfur content from a 2 percent sulfur feedstock. A more advanced process
4-115
-------
Table 4.3-2. CHEMISTRY OF HYDRODESULFURIZATION REACTIONS IN
PETROLEUM CRUDE OIL136
Name
Structure
Typical reaction
Thiols (mercaptans)
Disulfides
Sulfides
CU
c* P* n »
— o — o — n
R-S-R'
R
R
CLJ J. LJ,
C C D
01 J
^M2
RH + H2S
* ni i <
^ pLJ ^ D'
Rft 1 i^ OLJ P
n T Zn2b
H + H2S
Thiophenes
Benzothiophenes
3H2—>> CH3CHf [ I + H2S
Di benzothiophenes
H2S
4-116
-------
HYDROGEN
r
RECYCLED HYDROGEN GAS
REDUCED |
CRUDE .
I
I-1
t-»
-»J
FILTER
HEATER
r
GAS
1 UNREACTED HYDROGEN PLUS H2S
COMPRESSOR
TALYST
ESSEL
GAS/LIQUID SEPARATOR LIQUID
FHACTIONA1
RECYCLE GAS
TREATMENT
OFF GAS
NAPHTHA
' GAS OIL
(OPTIONAL)
LOW SULFUR
FUEL
ACID GAS IH2S)
->• LIGHT H.C.
Figure 4.3-2. Basic HDS process.
137
-------
using three catalytic reactors can produce fuel oils with sulfur contents as
low as 0.1 percent.
4.3.3.2 Development status. Over 30 hydrotreating processes are
actively in use, and more than 250 processes have been described in the
138
patent literature since 1970. Many of these processes have been in
commercial existence for over 10 years. The particular process selected by
a refinery depends on the existing or planned refinery products. In
existing facilities, a fuel desulfurization process is usually chosen to
minimize modification or retrofit and/or satisfy refinery product mix goals
and feedstock purchase expectations. Hence, the desulfurization process
selected depends on the required sulfur content of the product and the
feedstock properties.
4.3.3.3 Applicability to Nonfossil Fuel Fired Boilers. Like LSFO
produced from naturally occurring low sulfur crude, oil that has been
treated by an HDS process' is readily applicable to all boiler types and
sizes that burn a similar grade of fuel. Use of this cleaned oil should not
adversely affect the operation of the boiler. In fact, boiler performance
may even be improved due to the potential for less corrosion and deposit
formation in the boiler due to the chemical composition changes in the oil
139
as a result of hydrotreating.
4.3.3.4 Factors Affecting Performance. The composition of the
feedstock to a hydrotreater strongly influences the amount of hydrogen and
catalyst consumption in the process. Major feedstock variables are density
(expressed as °API), sulfur content, and metals content.
Hydrogen consumption has been correlated with sulfur reduction for a
variety of residual oil feeds. Figure 4.3-3 illustrates these results on
feedstocks varying from 4 - 18° API gravity. It can be seen that to obtain
3
90 percent reduction in sulfur for a 18° API feedstock, about 0.1 Mm of
hydrogen are consumed per liter of oil processed (650 scf/barrel); whereas,
a 4° API feed would require 0.2 Nm3/liter (1200 scf/barrel).141
As previously discussed, removal of metals by hydrotreating results in
their deposition on the catalyst surface or in the pores. This leads to
deactivation of the catalyst, which is only overcome by a temperature or
4-118
-------
1,200
1,100
1,000
00
CO
900
2 800
g
Q.
I70n
o
o
°API OF FEED
§
cc
Q
600
500
400
300
200
10
12
14<
16
\/
30 40 50 60 70 80
SULFUR REDUCTION %
90
100
NOTE: 1. REDUCE BY 9% FOR FIXED-BED PROCESSES.
2. APPLY CORRECTION FOR HIGH-METALS FEEDS.
Figure 4.3-3. Hydrogen consumption in desulfurization of residual oil. "
4-119
-------
pressure increase to maintain acceptable processing rates. The increase in
required severity of process conditions leads to more hydro- cracking with a
142
subsequent increase in hydrogen consumption. A further complication from
the metals content of the feed is a shortening of catalyst life. Even
though some deactivation can be tolerated, the resultant increase in
hydrogen uptake means the catalyst must be changed out more frequently.
The effect of metals is shown in Figure 4.3-4. This figure shows that
for 90 percent sulfur removal from a 25 ppm metals content feedstock, about
27 barrels of oil can be processed per pound of catalyst; to achieve the
same sulfur removal with a 100 ppm metals content feedstock, only 4.5
barrels can be processed per pound of catalyst; a feedstock containing
300 ppm metals requires almost 1 pound of catalyst per barrel. Clearly,
high metal feedstocks are a problem to the refiner. Therefore, many
refiners are using a separate stage of lower cost catalyst material prior to
the special hydrodesulfurization catalysts. These separate stages may be
packed with a material such as alumina or clay, which collects the metals
and "guards" the subsequent high activity catalyst. For this reason, some
144
refiners refer to this stage as a "guard reactor" or "guard vessel".
4.4 CONTROL TECHNIQUES FOR NITROGEN OXIDES
As described in Chapter 3, emissions of nitrogen oxides (NOV) from
A
nonfossil fuel fired boilers are usually lower than NO emissions from
A
fossil fueled boilers. The lower combustion temperatures in nonfossil fuel
fired boilers reduce the formation of NO from the reaction of atmospheric
A
nitrogen and oxygen, while the lower nitrogen content of some nonfossil
fuels reduces the formation of "fuel NO ." Emissions of NO from boilers
X A
cofiring nonfossil fuels and fossil fuels approach the level of emissions
from fossil fuel boilers as the firing proportion of fossil fuel increases.
Because of the lower NO emissions, NO controls have not been applied
A A
to rionfossil fuel boilers. Limited testing of two combustion modifications
(lower excess air and staged combustion) on boilers co- firing wood and coal
145
or gas showed possible reductions of NO due to these techniques.
A
However, comprehensive test data substantiating the performance of NO
4-120
-------
30
40
50 60 70 80
PERCENTAGE OF SULFUR REMOVED
101)
Figure 4.3-4. Effect of metals content on catalyst consumption.143
4-121
-------
controls over the range of boiler types, firing conditions, and fuel types
are not available. Thus, NO controls will not be considered further in
J\
this document. NO control techniques generally applicable to fossil fuel
A
fired boilers include:
- low excess air
- staged combustion
- flue gas recirculation
- low NO burners
A
- eliminated or reduced combustion air preheat
- ammonia injection
General discussions of these techniques can be found in the Technology
Assessment Report for Industrial Boiler Applications: NO Combustion
146
Modifications.1
4.5 EMISSION TEST DATA FOR MOST EFFICIENT EMISSION CONTROL TECHNOLOGIES
This section summarizes test data for the most efficient particulate
control technologies applied to nonfossil fuel fired boilers operated near
capacity. These data were previously presented in Section 4.1.6 with the
rest of the emission test data and thus met the following criteria (detailed
in Appendix C):
- the test was conducted in accordance with EPA Method 5 procedures,
- the boiler type and rated steam capacity are known,
- the fuel type is known, and
- critical emission control system operating parameters are known
such as flue gas pressure drop for wet scrubbers, air-to-cloth
ratio for fabric filters, and specific collection area for
electrostatic precipitators.
The test data in this section also meet two additional criteria:
- the test data represent the most efficient control technologies
in use for each fuel type,
- the boiler was operated at 75 percent or more of the rated
steam capacity, and
- the boiler and control system were operated within the design
limits of the system.
4-122
-------
4.5.1 Emission Test Data For Mood And Wood/Fossil Fuel Fired Boilers
Figure 4.5-1 presents emission test data for the most efficient
participate control technologies in use on wood-fired and wood/fossil fuel
cofired boilers. For wood-fired boilers, the most efficient systems of
emission control are ESPs, adjustable throat venturi scrubbers, fabric
filters, and EGBs. Venturi scrubbers without mist eliminators are not
considered to be most efficient systems of control unless once through
scrubber liquor is used to reduce the carry over of particulate matter in
the scrubber liquor. Tests AJ2 and AJ4 are also not included because of the
high excess air levels shown during testing which affected the scrubber
outlet emission levels (see Section 4.1.6.1.2). Test runs 8,11,12 and 14
for the group of test labeled BE3 through BE6 are not shown since the design
inlet loading to the E6B was exceeded.
4.5.2 Particulate Matter Emission Test Data For Bagasse-Fired Boilers
Figure 4.5-2 presents emission test data for the most efficient
particul ate control technologies in use on bagasse-fired boilers. These
data include five boilers controlled by low pressure drop wet scrubbers and
show emission levels of 130 ng/J (0.30 lb/10 Btu) or less. Boilers with 2
parallel wet scrubbers are not considered as most efficient controls
available because of the problems discussed in Section 4.1.6.2
4.5.3 Emission Test Data For MSVI- And RDF-Fired Boilers
Figure 4.5-3 presents emission test data for the most efficient
particulate control technology in use on MSW- and RDF-fired boilers. These
data are for boilers controlled by ESPs with SCAs of 47 m /(m/s)
O
(240 ft /1000 acfm) or more. As shown in the figure, ESPs with SCAs in this
range show emission levels below 43 ng/J (0.10 lb/10 Btu).
4-123
-------
m 0.15 —
"o
|
M
1 o.m —
V)
V*
s
3
3 n.os — 1-?- 1
** C I
L. *'
»
n.
1 1
Test f AJ5 AA1
Boiler f -
Boiler Type SS SS
Design Capacity
f* (103lh/hr steam) HO 150
J-^ Nonfossll Fuel Type B.S IIF
1X3 i.
.£> t llpat Input 1 00 100
t Ash (dry) - z.81
I Moisture - 60-65 '
Other Fuel
load Factor - I* 91 95
I 0? In flue gash 8.8 7.3
Control Device HC/HS MC/WS
Operating Parameter11'1 15.2 in
Design Parameter'
Fly Ash Relnjectlon Y Y
Sand Classification Y Y
"I1
1
AK2
T
i
AK3
^
•f •
1
Bit Bl
i
-1
\
L/V 1
*t J*
1
6 RJI
7/8c 4/5d
SS
135
B.S
inn
1.7
45
SS
135
n.s
100
4.2
45
SS/SS PC/SS SS
240/325 140/200 600
B/B -/B B.S
25/25 -/IOO 61
3.1 4.
4
46 4?
ISC/ISC* L3C/r- (ISO
94
14.5
MC/VS
20
100
11.8
IK/WS
26
87/87 48/BH 76
10.2 I?
.5 6.2
HC/ESP HC/ESP NC/ESP
320 452 456
296 460 .156
Y
Y
Y
Y
Y N/Y Y
N N/N Y
T 1
HII2 B02
1/5d
PC/SS SS
140/200 25
-/B n
-/SO 100
-/5.9 5.1
-/28 47
ISC/ISC9
01/46 75
0.9 9.9
HC/ESP HC/FF
600 3.66
460 4. 10
N/Y N
N/N N
*
I
BC2
1.2.J1
no
3x50
SIIF
ion
3.4
57
.
91
10.7
HC/FF
2.98
3.64
N
N
III
BET"
||
SS
4nn
iir
ino
9.4k
56"
_
%
9.6
HC/EBB
6.0
Y
Y
-8,
J,
II
SS
400
IIF
100
3.8
49
_
101
7.9
HC/EGB
3.4
.
Y
Y
*
BE4n
II
SS
400
IIF
100
3.8
50
.
116
7.2
HC/EGB
4.0
_
N
N
—
i-(H
60 f
s
Of
s
ff
§
V*
» !
J,
n
ss
400
IIF
100
4.8
58
.
95
8.1
HC/EGB
5.6
.
Y
Y
Fiqure 4.5-1. Participate Emissions from Wood-Fired and Wood/Fossil
Fuel Cofired Boilers with High Efficiency Controls.
-------
Footnotes for Figure 4.5-1:
aA11 data were obtained by EPA Method 5 and meet established criteria for acceptability. The key
for the data 1s:
SS - spreader stoker
PC - pulverized coal
DO - dutch oven
B - bark
S - sawdust or shavings
SD - sanderdust
HF - hog fuel (wood/bark mixture)
SHF - salt-laden hog fuel
LSC - low sulfur coal
HSO - high sulfur residual oil
US - wet scrubber
HC - mechanical collector
ESP - electrostatic preclpltator
FF - fabric filter
EGB - electrostatic gravel bed filter
Y - yes
H - no
0 - EPA-5 data acquired In Industry tests
• - EPA-5 data acquired In EPA tests
I—| - average
More detailed Information on the emission test data and the data sources may be found In Appendix C.
eThe flue gas from boilers 7 and 8 passes through Individual mechanical collectors. It Is then
combined Into a single duct and then split to enter a two chamber ESP with two stacks. The
emission levels shown are the weighted average of both stacks.
The flue gas from boilers 4 and S passes through individual mechanical collectors. It Is then
combined Into a single duct and then split to enter two separate ESPs In parallel. The emission
levels shown are the weighted average of both stacks.
eThe analysis of the coal showed the following composition: Moisture - 5.5X; ash (dry) - 12.41;
sulfur (dry) - 0.861.
The analysis of the coal showed the following composition: Moslture 3.9X; ash (dry) - 7.IX;
sulfur (dry) - 0.7X.
9The analysis of the coal showed the following composition: Holsture - 3.2X; ash (dry ) - 17.7X;
sulfur (dry) - 0.56X.
Average value during testing.
Vor ESPs this value is specific collection area In ft2/1000 acfm; for fabric filters this value 1s
air to cloth ratio 1n ft/min; for wet scrubbers and the EGB this value is pressure drop in inches of water.
•'The flue gas from boilers 1,2 and 3 passes through Individual mechanical collectors. It is then
combined into a single duct prior to entering the fabric filter.
At this facility char from the first stage of the mechanical collector is slurrled and separated
by screens Into large and small fractions. The large char fraction 1s mixed with the hog fuel.
These values represent an analysis of the mixture of char and hog fuel.
These data did not come from an analysis done durlnq emission testinq. Thcv were obtained from
industry sources ami are representative of the typical fuel burned at this facility.
""The EGB has three modules, each of which cleans one-third of the flue qas. Each module has a
seoarate stack. The emission levels shown are the weiiihted average of all three stacks.
-------
Test f
Boiler t
Boiler Type
Design Capacity -
(10J lbs/hr steam)
Bagasse Characti
I Heat Inpi
X Ash(dry)
I Moisture
Other fuel
Load Factor - %c
X 02 1n flue gasc
Control Device
Operating Pa ran
(In. w.c.)
a
+*
n
°o
t-l
.a
«• °-20
o
M
i
01
«3
3 0.10
-
- i Q i o
1 T 1 V
i i i
i i i i •
o np
O iQj
_
O
LjLj
rOi
M_)
1 1 1 1 1
OEl DE2 OE3 DH1 DC1
160
S
120 g
!
1
in
80 §
3
IO
6 12 14 5 -
FC SS SS SS SS
125 150 150 200 312
un)
irlstlcs-
tc 94 100 100 100 100
3.3
48
HSO -
96 92 98 82 93
.c 11. 0 4.8 5.9 10.5 7.1
WS MC/WS MC/WS WS MC/WS.
•ter -APC 666 6 2
Figure 4.5-2. Particulate Emissions form Bagasse-Fired.
Boilers with High Efficiency Controls. '
4-126
-------
Footnotes to Figure 4.5-2:
aA11 of the data were obtained by EPA Method 5 and meet established criteria for acceptability.
The key for the data is:
HS - horseshoe
FC - fuel cell
SS - spreader stoker
HSO - high sulfur residual oil
MC - mechanical collector
WS - wet scrubber
P - pressure drop
0 - EPA-5 test data acquired in industry tests.
• - EPA-5 test data acquired in EPA tests.
H- average
^ More detailed information on the emission test data and the data sources may be found in
^ Appendix C.
>l cAverage value during testing. For all the wet scrubbers tested the scrubber pressure drop is
assumed to be equal to the reported design value. The pressure drops were not actually measured
during testing.
This wet scrubber is an ejector venturi design, therefore the gas phase pressure drop is not
a good indicator of scrubber efficiency. This scrubber would be approximately equivalent to
a "standard" venturi with a pressure drop of 1.5 kPa (6 inches w.c.).
-------
0.30
3 0.25
CO
U5
°
.0
1 0.20
I/I
5
| 0.15
u
Q.
0.10
0.05
•MM
^V
_
—
_ c
* * h
^•M
1 I 1
—
—
—
^^m
)
•^•H
^
[ ^
1
140
120
100 2>
-i
rr
3
at
80 S
i
M
Wl
O
a
v>
so ;
e-
40
20
Test 1 FC1 FE2 HF1 FBI
Boiler Type OF OF SS OF
Design Capacity
(103lbs/hr steam) 175/175C 110 200 135
Nonfossll Fuel Type MSW MSW RDFe MSW
% Heat Inputd 100 100 100 100
Load factor - %d 80/88 79 80 77
* 02 1n flue gasd 9.9 9.4 7.8 9.2
Control Device ESP ESP MC/ESP MC/ESP
Operating Parameter SCAd 243 278 326 573
(fr/1000 acfm)
Design Parameter - SCA
(ft2/1000 acfm)
209
154
248
316
f-igure 4.5-3. Particulate Emissions from MSW- and RDF-fired
Boilers with High Efficiency Controls. '
4-128
-------
Footnotes for Figure 4.5-3:
aAll of the data were obtained by EPA Method 5 and meet established criteria for acceptability.
The key for the data is:
OF - overfeed stoker
SS - spreader stoker
ESP - electrostatic precipitator
MSW - municipal solid waste
MC - mechanical collector
SCA - specific collection area
0 - EPA Method 5 data acquired in industry tests
|—| - average
More detailed information on the emission test data and the data sources may be found in
Appendix C.
*» °Two boiler/ESPs are exhausted through a common stack; each boiler has a steam generating capacity
^ of 175,000 Ib/hr.
i\j j
10 Average value during testing.
eAlthough fuel samples were not taken during testing, industry sources report that the typical RDF
fired at this facility contains 16.2 percent ash on a dry basis and 51 percent moisture. The RDF
is produced by a wet pulping process.
-------
4.6 REFERENCES
1. U.S. Environmental Protection Agency. National Emissions Data System.
(Computer Printout). August 12, 1980. 49 p.
2. Perry, R.H. and C.H. Chilton. (ed.). Chemical Engineers' Handbook,
Fifth Edition. New York, McGraw-Hill Book Company, 1973. p. 18-83.
3. Roeck, D.R. and R. Dennis. (6CA Corporation.) Technology Assessment
Report for Industrial Boiler Applications: Particulate Collection.
(Prepared for U.S. Environmental Protection Agency.) Research Triangle
Park, N.C. Publication No. EPA-600/7-79-178h. December 1979. p. 83.
4. Junge, D.C. (Oregon State Univeristy.) Design Guideline Handbook for
Industrial Spreader Stoker Boilers Fired with Wood and Bark Residue
Fuels. (Prepared for U.S. Department of Energy.) Washington, D.C.
Publication No. RLO-2227-T22-15. February 1979. p. 32.
5. U.S. Environmental Protection Agency. Wood Residue-Fired Steam
Generator Particulate Matter Control Technology Assessment. Research
Triangle Park, N.C. Publication No. EPA-450/2-78-044. October 1878.
p. 7.
6. Reference 3, p. 85.
7. Stern, A.C. Air Pollution, Volume IV: Engineering Control of Air
Pollution. New York, Academic Press, 1977. p. 117.
8. Reference 3, p. 88.
9. Galeski, J.B. and M.P. Schrag. (Midwest Research Institute.)
Performance of Emission Control Devices on Boilers Firing Municipal
Solid Waste and Oil. (Prepared for U.S. Environmental Protection
Agency.) Research Triangle Park, N.C. Publication No. EPA-600/2-
76-209. July 1976. p. 40.
10. American Boiler Manufacturers' Association. Emission and Efficiency
Performances of Industrial Coal Stoker Fired Boilers. (Prepared for
U.S. Department of Energy.) Washington, D.C. DOE Report
No. DOE/ET/10386-TI (Vol. I), pp. 64, 65.
11. Joy Industrial Equipment Company. Western Precipitation Gas Scrubbers:
Type "D" Tubulaire Scrubber. Los Angeles, Joy Manufacturing Company,
1978. 4 p.
12. Theodore, L. and A.J. Buonicore. Industrial Air Pollution Control
Equipment for Particulates. New Haven, Chemical Rubber Company Press,
1976. p. 232.
4-130
-------
13. Reference 12, p. 203.
14. Calvert, S., et al. (A.P.T., Inc.) Wet Scrubber System Study, Volume
I: Scrubber Handbook. (Prepared for U.S. Environmental Protection
Agency.) Research Triangle Park, N.C. Publication No. EPA-R2-72-118a.
July 1972. p. 3-8.
15. Reference 3, pp. 68-69.
16. The Mcllvaine Company. The Mcllvaine Scrubber Manual, Volume I.
Northbrook, Illinois, The Mcllvaine Company, 1974. Chapter II, p. 8.0.
17. Joy Industrial Equipment Company. Western Precipitation Gas Scrubbers:
Type "V" Turbulaire Variable Venturi Scrubber. Los Angeles, Joy
Manufacturing Company, 1978. 6 p.
18. Flick, R.A. (Simons-Eastern Company.) Pulping Industry Experience
with Control of Flue Gas Emissions from Bark and Wood Fired Boilers.
In: Energy and the Wood Products Industry. Madison, Forest Products
Research Society, November 1976. pp. 150-153.
19. Calvert, Seymour (Air Pollution Technology, Inc.) Upgrading Existing
Particulate Scrubbers. Chemical Engineering. October 24, 1977.
p. 135.
20. Reference 3, p. 68.
21. Reference 3, p. 70.
22. MikroPul Corporation. Mikro-Pulsaire Dust Collectors. Summit, New
Jersey, United States Filter Corporation, 1976. p. 2.
23. Reference 3, p. 48.
24. Trip report. Acurex Corporation to file. December 7, 1978. 4 p.
Report of visit to Resource Energy Systems Company in Saugus,
Massachusetts.
25. Trip report. Herring, J., Acurex Corporation, to file. August 13,
1979. 4 p. Report of June 26, 1979 visit to Nashville Thermal Transfer
Corporation in Nashville, Tennessee.
26. Trip report. Herring, J.V., Acurex Corporation, to file. October 19,
1979. 7 p. Report of June 12, 1979 visit to Long Lake Lumber Company
in Spokane, Washington.
27. Hoit, R.S. (Simpson Timber Company.) Baghouse Filters on Wood Fueled
Power Boilers. (Presented at the Third International Fabric
Alternatives Forum. Phoenix. September 20-21, 1978.) 12 p.
4-131
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28. Kester, R.A. (Puget Sound-APC.) Hog Fuel Boiler Particulate
Filtration. (Presented at the Air Pollution Control Association PNWIS
Meeting. Boise. November 19, 1974.) 13 p.
29. Trip report. Herring, J., Acurex Corporation, to file. July 6, 1979.
6 p. Report of June 14, 1979 visit to Simpson Timber Company in
Shelton, Washington.
30. Guidon, M.W. (Georgia-Pacific Corporation.) Pilot Studies for
Particulate Control of Hog Fuel Boilers Fired with Salt Water Stored
Logs. In: National Council of the Paper Industry for Air and Stream
Improvement Special Report No. 78-03. New York, NCASI, April 1978.
pp. 84-98.
31. Storm, P.V., Radian Corporation. Memo to Bill Arnold, Radian
Corporation, September 12, 1980. Filters on wood-fired boilers.
32. Dobson, P. Fire Protection for Bag Type Dust Collectors. Wood & Wood
Products. 82_: 34-35. January 1977.
33. Kraus, M.N. Baghouses: Separating and Collecting Industrial Dusts.
Chemical Engineering. 86(8):94-106. April 9, 1979. pp. 105-106.
34. Reference 3, p. 70.
35. McKenna, J.D., et al. (Enviro-Systems and Research, Inc.) Applying
Fabric Filtration to Coal-Fired Industrial Boilers-A Pilot Scale
Investigation. (Prepared for U.S. Environmental Protection Agency.)
Research Triangle Park, N.C. Publication No. EPA-650/2-74-058a.
August 1975. p. 2.
36. Reference 3, p. 24.
37- Reference 3, p. 27-
38. Reference 12, pp. 175-176.
39. Reference 3, p. 29.
40. Reference 3, p. 34.
41. Reference 3, p. 32.
42. Bump, R. Electrostatic Precipitators Work Well on Bark Ash. Pulp
& Paper Canada. 79(10):47-50. October 1978.
43. White, H.J. Electrostatic Precipitation of Fly Ash. Journal of Air
Pollution Control Association. 27(3):20. March 1977.
4-132
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44. The Mclllvaine Company. The Electrostatic Precipitator Manual, Volume
3. Northbrook, Illinois, The Mcllvaine Company, 1976. Chapter IX, p.
502.7.
45. PEDCo Environmental, Inc. Air Pollution Control Technology Development
for Waste as Fuel Processes. (Prepared for U.S. Environmental
Protection Agency.) Cincinnati, Ohio. EPA Contract No. 68-03- 2509.
March 1978. p. 103.
46. Humbert, C.O. and N.R. Davis. (Environmental Elements Corporation.)
Pilot Precipitator Studies on Combination Fuel Boilers. (Presented at
the 1978 TAPPI Environmental Conference. Washington, D.C.
April 12-14, 1978.) 5 p.
47. Galeano, S.F., et al. (Owens-Illinois, Inc.) Development and
Application of a New Electrostatic Precipitator for Multifuel Boilers.
In: 1979 TAPPI Environmental Proceedings. Atlanta, Technical
Association of the Pulp and Paper Industry, 1979. pp. 21-28.
48. Kleinhenz, N. (Systems Technology Corporation.) Use of Coal:dRDF
Blends in Stoker Fired Boilers. (Prepared for U.S. Environmental
Protection Agency.) Cincinnati, Ohio. EPA Contract No. 68-03- 2426.
July 1980. p. 129.
49. Bump, R.L. Handling Ash from Bark-Fired Boilers. Power.
121(2):94-95. February 1977.
50. Reference 3, p. 32.
51. Reference 44, p. 503.2.
52. Oglesby, S., et al. A Manual of Electrostatic Precipitator Technology,
Part I - Fundamentals. Birmingham, Southern Research Institute,
August 1970. p. 369.
53. Nachbar, R. and A.E. Pearce. (Westvaco Corporation.) New Approaches
to Particulate Collection at Bark Fired Power Boilers. In:
Atmospheric Pollution Technical Bulletin No. 51, Gellman, I. (ed.).
New York, NCASI, October 30, 1970. 13 p.
54. Combustion Power Company. Clean Air Just Got Cheaper: The Electro-
scrubber. California, Combustion Power Company, 1979. 6 p.
55. Telecon. Barnett, K.W., Radian Corporation, with Weber, D.
Joy/Western Precipitation Division. November 9, 1981. Mechanical
Collectors Applied to Wood-Fired Boilers.
56. Reference 3, pp. 85-86.
4-133
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57. Memo from Sedman C., EPA:ISB, to Industrial Boiler Files. Emission
control capabilities of mechanical collectors. March 2, 1982.
58. State of Florida, Department of Environmental Regulation. Application
to Operate/Construct Air Pollution Sources: Atlantic Sugar Association,
Belle Glade, Florida. July 5, 1978. 17 p.
59. Memo from Kelly, M.E., Radian Corporation, to Industrial Boiler File.
Review of ABMA/DOE/EPA study on particulate emissions from stoker-fired
boilers and mechanical collectors. April 1, 1981.
60. Trip report. Piccot, S.D., Radian Corporation, to file. July 7, 1981.
Report of visit to DuPont fabric filter.
61. The Mcllvaine Company. The Mcllvaine Fabric Filter Manual, Volume I.
Northbrook, Illinois, the Mcllvaine Company, 1979. Chapter III,
p. 40.9.
62. Reference 1.
63. Meterology Research, Inc. Determination of the Fractional Efficiency,
Opacity Characteristics, Engineering, and Economics of a Fabric Filter
Operating on a Utility Boiler. (Prepared for Electric Power Research
Institute.) Palo Alto, California. EPRI Report FP-297. p. xiv.
64. The Mcllvaine Company. The Mcllvaine Electrostatic Precipitator
Manual, Volume I. Northbrook, Illinois, The Mcllvaine Company, 1976.
Chapter III. p. 2.07.
65. Dickerman, J.C. and K.L. Johnson. (Radian Corporation.) Technology
Assessment Report for Industrial Boiler Applications: Flue Gas
Desulfurization. (Prepared for U.S. Environmental Protection Agency.)
Research Triangle Park, N.C. Publication No. EPA-600/7- 79-178i.
November 1979. p. 2-147.
66. Reference 65, p. 2-153.
67. Reference 65, p. 2-154.
68. Reference 65, p. 2-159.
69. Reference 65, pp. 2-159, 2-160.
70. Leivo, C.C. (Bechtel Corporation.) Flue Gas Desulfurization Systems:
Design and Operating Considerations, Volume I. (Prepared for U.S.
Environmental Protection Agency.) Research Triangle Park, N.C.
Publication No. EPA-600/7-78-030a. March 1978. p. 3-19.
71. Reference 65, p. 2-80.
4-134
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72. Reference 65, p. 2-81.
73. Reference 65, p. 2-82.
74. Reference 65, p. 2-84.
75. Reference 65, p. 2-88.
76. Memo from Barnett, K., Radian Corporation, to file. February 25,
1981. 2 p. A summary of information from the Industrial Boiler Study
on the reliability of FGD systems.
77. Reference 65, pp. 2-88 through 2-90.
78. Reference 65, p. 2-90.
79. Reference 65, p. 2-90 through 2-91.
80. Reference 65, p. 2-98.
81. Reference 65, p. 2-97.
82. Ayer, F.A. (Researcy Triangle Institute.) Proceedings: Symposium on
Flue Gas Desulfurization -- Las Vegas, Nevada, March 1979; Volume 1.
(Prepared for U.S. Environmental Protection Agency.) Research Triangle
Park, North Carolina. Publication No. EPA-600/7-79-167a. July 1979.
p. 342.
83. Mobley, D.J., EPA/IERL. Memo to Larry Jones, EPA/OAQPS. Memo on the
status of adipic acid enhanced FGD. February 12, 1981.
84. Reference 65, p. 2-9.
85. Reference 65, p. 2-15.
86. Reference 65, p. 2-16.
87. Reference 65, p. 2-26.
88. Reference 83, p.3.
89. Reference 65, p. 2-72.
90. Reference 65, p. 2-33.
91. Reference 65, p. 2-34.
92. Reference 65, p. 2-34 through 2-43.
4-135
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93. Reference 65, p. 2-52.
94. Reference 65, p. 2-29.
95. Reference 65, p. 2-55.
96. Reference 64, p. 2-31.
97. Blythe, 6.M., et al. (Radian Corporation.) Survey of Dry S02 Control
Systems. (Prepared for U.S. Environmental Protection Agency.;
Research Triangle Park, N.C. Publication No. EPA-600/7- 80-030.
February 1980. p. 9.
98. Reference 97, p. 11.
99. Reference 65, p. 2-162.
100. Reference 65, p. 2-163.
101. Kelly, M.E. and S.A. Shareef (Radian Corporation). Third Survey of Dry
S02 Control Systems. (Prepared for U.S. Environmental Protection
Agency.) Research Triangle Park, North Carolina. Draft Report EPA
Contract 68-02-3171. February 18, 1981. p. 15.
102. Reference 97, p, 9.
103. Reference 97, p. 10.
104. Reference 97, p. 11.
105. Reference 65, p. 2-166.
106. Reference 65, pp. 10-12.
107. Reference 65, pp. 9-11.
108. Memo from Barnett, K., Radian Corporation, to nonfossil fuel fired
boiler file. March 16, 1982. 2 p. Equivalent pressure drop of
ejector venturi.
109. The Mcllvaine Company. The Mcllvaine Scrubber Manual, Volume I.
Northbrook, Illinois, The Mcllvaine Company, 1974. Chapter III,
p. 26.0.
110. Kezerle, J.A. and S.W. Mulligan, TRW, Inc. Performance Evaluation of
an Industrial Spray Dryer for S0? Control. (Prepared for U.S. »*
Environmental Protection Agency.7 Research Triangle Park, North
Carolina. Publication No. EPA-600/7-81-143. August 1981. pp. 4-4 -
4-7.
4-136
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111. The Mcllvaine Company. The Mcllvaine Electrostatic Precipitator
Manual, Volume I. Northbrook, Illinois, The Mcllvaine Company, 1976.
Chapter II, p. 40.7.
112. Reference 111, p. 40.2.
113. Transmittal from Plum, M., Combustion Power Company, Inc., to
Sedman, C., EPAcISB™ March 1, 1982. 1 p. Summary of Applications of
the Electroscrubber electrostatic gravel bed filter.
114. Buroff, J., et al. (Versar, Inc.) Technology Assessment for
Industrial Boiler Applications: Coal Cleaning and Low Sulfur Coal.
(Prepared for U.S. Environmental Protection Agency.) Research Triangle
Park, N.C. Publication No. EPA-600/7-79-178c. December 1979. p. 43.
115. Maloney, K.L., et al. (KVB, Inc.) Low-Sulfur Western Coal Use in
Existing Small and Intermediate Size Boilers. (Prepared for U.S.
Environmental Protection Agency.) Research Triangle Park, N.C.
Publication No. EPA-600/7-78-153a. July 1978. p. 26.
116. Reference 114, p. 44.
117. Reference 114, p. 8.
118. Reference 114, p. 95.
119. Comley, E.A., et al. (Catalytic, Inc.) Technology Assessment Report
for Industrial Boiler Applications: Oil Cleaning. (Prepared for U.S.
Environmental Protection Agency.) Research Triangle Park, N.C.
Publication No. EPA-600/7-79-178b. July 1980. pp. 61-63.
120. Reference 114, p. 53.
121. Reference 114, p. 54.
122. Reference 114, p. 120.
123. Reference 114, p. 124.
124. Reference 114, p. 127.
125, Reference 114, p. 130.
126. Reference 114, p. 135.
127. Reference 114, p. 134.
128. Reference 114, p. 145.
129. Reference 114, p. 185.
4-137
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130. Reference 114, p. 184.
131. Reference 114, p. 56.
132. Reference 114, p. 142.
133. Reference 114, p. 143.
134. Reference 119, p. 41.
135. Reference 119, p. 42.
136. Reference 119, p. 44.
137. Reference 119, p. 43.
138. Ranney, M.W. Desulfurization of Petroleum. Park Ridge, New Jersey,
NOYES Data Corporation, 1975. pp. 3, 31.
139. Reference 119, p. 64.
140. Reference 119, p. 49i
141. Reference 119, p. 47.
142. Reference 119, p. 51.
143. Reference 119, p. 52.
144. Reference 119, p. 53.
145. Fisher, K.T., et al. (KVB, Inc.) Application of Combustion Modifica-
tions to Industrial Combustion Equipment (Data Supplement B).
(Prepared for U.S. Environmental Protection Agency.) Research Triangle
Park, N.C. EPA-600/7-79-015c. February 1979. pp. 491-524, 690-762.
146. Lim, K.J., et al. (Acurex Corporation.) Technology Assessment Report
for Industrial Boiler Applications: NOx Combustion Modification.
(Prepared for U.S. Environmental Protection Agency.) Research Triangle
Park, N.C. Publication No. EPA-600/7-79-178f. December 1979. 497 p.
4-138
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5. MODIFICATION AND RECONSTRUCTION
Standards of Performance are applicable to facilities whose construc-
tion, modification, or reconstruction commenced after proposal of the
standards. Such facilities are termed "affected facilities." Standards of
performance are not applicable to "existing facilities" which are facilities
whose construction, modification, or reconstruction commenced on or before
proposal of the standards. However, an existing facility may become an
affected facility and therefore subject to standards, if the facility
undergoes modification or reconstruction.
Modification and reconstruction are defined under 40 CFR 60.14 and
60.15, respectively. The definition of commenced appears in 40 CFR 60.2(i).
Modification and reconstruction provisions are summarized in Section 5.1 of
this chapter. Section 5.2 discusses the applicability of the provisions to
nonfossil fuel fired boilers.
5.1 SUMMARY OF MODIFICATION AND RECONSTRUCTION PROVISIONS
5.1.1 Modification
With certain exceptions, any physical or operational change to an
existing facility that would result in an increase in the emission rate to
the atmosphere of any pollutant to which a standard of performance applies
would be considered a modification within the meaning of Section 111 of the
Clean Air Act. Modification determinations are made on a case-by-case
basis! The key to a modification determination is whether total emissions
to the atmosphere (expressed in kg/hr) from the facility as a whole have
increased as a result of the change. For example, if the affected facility
is defined as a group of pieces of equipment, then the aggregate emissions
from all the equipment must increase before the facility will be considered
modified.
5-1
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Exceptions which allow certain changes to an existing facility without
it becoming an affected facility, irrespective of an increase in emissions
are listed below.
1. Routine maintenance, repair, and replacement.
2. An increase in production rate without a capital expenditure (as
defined in 40 CFR 60.2(bb)).
3. An increase in the hours of operation.
4. Use of an alternate fuel or raw material if, prior to the standard,
the existing facility was designed to accommodate that alternate
fuel or raw material.
5. The addition or use of any system or device whose primary function
is the reduction of air pollution, except when an emission control
system is removed or is replaced by a system determined by EPA to
be less environmentally beneficial.
6. Relocation or change in ownership of the existing facility.
Once.an existing facility is determined to be modified, all of the
emission sources of that facility are subject to the standards of perfor-
mance for the pollutant whose emission rate increased and not just the
emission source which displayed the increase in emissions. However, a
modification to one existing facility at a plant will not cause other
existing facilities at the same plant to become subject to standards.
An owner or operator of an existing facility who is planning a physical
or operational change which may increase the emission rate of a pollutant to
which a standard applies shall notify the appropriate EPA regional office
60 days prior to the change, as specified in 40 CFR 60.7(a)(4).
5.1.2 Reconstruction
An existing facility may also become subject to new source performance
standards if it is determined to be "reconstructed." As defined in
40 CFR 60.15, a reconstruction is the replacement of the components of an
existing facility to the extend that (1) the fixed capital cost of the new
components exceeds 50 percent of the fixed capital cost of a comparable new
facility and (2) it is technically and economically feasible for the
facility to meet the applicable standards. Because EPA considers
5-2
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reconstructed facilities to constitute new construction rather ....
modification, reconstruction determinations are made irrespective of change^
in emission rate. Determinations are made on a case-by-case basis. If the
facility is determined to be reconstructed, it must comply with all of the
provisions of the standards of performance applicable to that facility.
If an owner or operator of an existing facility is planning to replace
components and the fixed capital cost of the new components exceeds
50 percent of the fixed capital cost of a comparable new facility, the owner
or operator shall notify the appropriate EPA regional office 60 days before
the construction of the replacements commences.
5.2 APPLICABILITY OF MODIFICATION AND RECONSTRUCTION PROVISIONS TO
NONFOSSIL FUEL FIRED BOILERS
5.2.1 Modification
Actions which may increase emissions and therefore may be considered
modifications include changes in the type of fuel fired and changes in the
boiler components. These changes are discussed below.
5.2.1.1 Fuel Switching. The combustion of an alternate fuel will not
be deemed a modification so long as an existing boiler was designed to
accommodate the alternate fuel as discussed in 40 CFR 60.14(e)(4). Any
other switch in fuel which increases the emissions of a regulated pollutant
will constitute a modification, with the exception of fuel switches
described in Section lll(a)(8) of the Clean Air Act and those specifically
excluded by the standard.
5.2.1.2 Physical and Operational Changes. Physical changes could be
made to almost every component of a nonfossil fuel fired boiler. This
section highlights some of the changes which may result in emissions
increases.
Combustion Air System. The air flow in a boiler's draft system can be
increased by changing fans and air nozzles in order to correct combustion
problems and to reduce tubing corrosion. This change could result in
greater excess air and higher air velocities which in turn could increase PM
emissions. Other changes in air flow include altering the ratio of air
5-3
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added over (overfire air) and under (underfire air) the grates. Increasing
the velocity of underfire air may also result in increased PM carryover.
Flue Gas Handling System. Alterations can be made in the flue gas
handling system by adding an economizer and/or air heater, or by replacing
the primary fan. The addition of an economizer would not affect the
emission rate of any pollutant and thus would not be termed a modification.
The addition of an air heater, however, could increase furnace temperatures
and NO formation. The likelihood of an owner/operator installing an air
1
heater is high.
Fly Ash Reinjection. A system to reinject fly ash or unburned carbon
particulate matter from stoker-fired boilers can be added to improve the
overall fuel combustion efficiency and reduce overall operating costs. Fly
ash reinjection increases the boiler particulate loading and therefore may
increase emissions. Rapidly rising fuel costs tend to make this alternative
more attractive and may cause some existing facilities to either add
reinjection systems or increase reinjection rates in the future.
5.2.2 Reconstruction
In a reconstruction determination, when components are replaced as part
of a maintenance program the capital expenditures for each component are
first adjusted by the annual asset guideline repair allowance percentage
(Internal Revenue Service Publication 534) as specified in 40 CFR 60.2(bb).
Replacement of single boiler components would not likely require sufficient
capital to subject an existing facility to the reconstruction provisions.
On the other hand, replacement of groups of components (e.g., retubing and
rebricking) may result in sufficient expenditures to subject the facility to
these provisions. However, it does not appear likely that existing boilers
with normal repair and maintenance practices will become affected facilities
by virtue of the reconstruction provision.
While there is a difference between the terms "repair" and
"maintenance", they are most often considered together in available cost
information. The National Board Inspection Code does, however, distinguish
between repair and maintenance and as an example, defines repairs as the
2
following items:
5-4
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- Replacement of sections of boiler tubes, provided the remaining
part of the tube is not less than 75 percent of its original
thickness.
- Seal welding of tubes.
- Building-up of certain corroded surfaces.
- Repairs of cracked ligaments of drums or headers within certain
definite limits.
The types of maintenance that will usually require substantial amounts
of time are boiler cleaning and repair or replacement of various parts.
Primary maintenance areas for solid fuel fired boilers are the fuel feed
system and the fuel firing mechanism.
5.2.3 Summary
Modification and reconstruction determinations are made on a case-by-
case basis. It appears that the reconstruction provisions will probably not
cause an existing boiler to be reclassified as an affected facility.
However, there are boiler modifications which could result in an existing
boiler becoming classified as an affected facility subject to new source
performance standards. Addition of a fly ash reinjection system or of an
air preheater is indicated as likely from contacts with industry personnel.
In addition some fuel switching is anticipated. An existing facility which
makes any of these changes is potentially a modified facility.
5-5
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5.3 REFERENCES
1. Marx, W. B., President, Council of Industrial Boiler Owners, personal
correspondence with Larry D. Broz, Acurex Corporation. February 16,
1980.
2. Bornstein, M. et^ aj_. Impact of Modification/Reconstruction of Steam
Generators on S09 Emissions. GCA Corporation. Bedford, Massachusetts.
EPA-450/3-77-048: December 1977. pp. 12-14.
5-6
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6. MODEL PLANTS AND EMISSION CONTROL OPTIONS
The impacts of various emission control requirements on nonfossil fuel
fired boilers (NFFBs) are determined through an analysis of "model boilers."
Model boilers are standard boilers (which represent the new NFFB population)
in combination with emission control techniques. The model boiler evalua-
tion provides a boiler-specific analysis of the economic, environmental, and
energy impacts resulting from the application of different emission control
techniques to the standard boilers.
The selection of model boilers involves basically a three-step approach
as illustrated in Figure 6-1. The first step is to select the standard
boilers and fuel types. The rationale behind these selections is discussed
in Section 6.1. The second step, discussed in Section 6.2, involves
specifying emission control levels based on the control performance data in
Chapter 4 and identifying control technologies that will meet these levels.
The last step, discussed in Section 6.3, combines the standard boilers and
selected control technologies into a set of model boilers. Finally,
numerical emission limits and standard boilers for each fuel type and
control level are presented in Section 6.4.
6.1 SELECTION OF STANDARD BOILERS
Standard boilers are selected to represent the new NFFB population.
Factors used in their selection include fuels, firing methods, and boiler
distribution by capacity. A summary of the standard boilers selected for
evaluation is presented in Table 6-1. The selection rationale is presented
in Section 6.1.1. A complete description of the standard boilers is found
in Sections 6.1.2 and 6.1.3.
6.1.1 Selection Rationale
The boiler capacities, firing methods, and fuels reflected in the
standard boilers represent current and future designs based on the NFFB
population data presented in Chapter 3. The principal NFFB fuels are wood
6-1
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Size
(Thermal Input)
Boiler Type
Defi ne
Standard Boiler
And Fuel
Fuel Type and Properties
(Wood, MSW, RDF, Bagasse)
Emission
Control Level
(PM, NOX, S02)
Select Control
Systems for PM,
NO and S02
Technical Considerations
at
i
ro
Model Boiler
Designed to Meet
Required Control Level
Figure 6-1. Model Boiler Selection Logic Diagram
-------
TABLE 6-1. STANDARD BOILERS SELECTED FOR EVALUATION
Boiler Type
Fuel1
Heat Input
MW (106 Btu/hr)
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Spreader Stoker
Controlled A1r
Mass Burn
Mass Burn
Spreader Stoker
Mood
Wood
Wood
Wood
HAB
SLW
75% Wood/c
25% HSE
50% Wood/c
50% HSE
50% Wood/c
50% HSE
50% Wood/c
50% LSW
50% RDF/C
50% HSE
" MSW
MSW
MSW
Bagasse
8.8
22
44
117
44
44
44
44
117
44
44
2.9
44
117
58.6
(30)
(75)
(150)
(400)
(150)
(150)
(150)
(150)
(400)
(150)
(150)
(10)
(150)
(400)
(200)
Descriptions and diagrams of these boiler types are contained in Chapter 3.
3Wood - hog fuel (wood/bark mixture)
HAB - high ash bark
SLW - salt-laden wood
HSE - high sulfur eastern coal
LSW - low sulfur western coal
RDF - refuse derived fuel
MSW - municipal solid waste
"Average fuel mixture on a heat input basis.
6-3
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and bark waste, solid waste including municipal solid waste (MSW) and refuse
derived fuel (RDF), and bagasse. Boilers are selected to represent each of
these basic fuel types. Representative capacities within each fuel type are
then selected within the range of expected capacities for the new NFFB
population. Wherever practical, boiler capacities for the nonfossil fuel
types were selected to be the same as those selected for fossil fuel fired
boilers in the Background Information Document (BID) for industrial
boilers. Also, for cases involving cofiring of fossil and nonfossil fuels,
the fossil fuels selected are the same as those used in the industrial
boiler study. These selection criteria were applied to facilitate direct
comparisons between the industrial boiler and nonfossil fuel fired boiler
studies, and to allow comparison of the economic, environmental, and energy
impacts resulting from alternative regulatory options.
As discussed in Chapter 3, capacities of NFFBs range from less than
2.9 MW (10 x 106 Btu/hr) to greater than 117 MW (400 x 106 Btu/hr) thermal
input. Many boilers at the lower end of the capacity range are used for
space heating, whereas the boilers at the upper end of the capacity range
are generally used to produce process steam, to drive turbines, and in some
cases, to generate electricity. In Table 6-2, the NFFB capacity range is
segmented into five size categories with appropriate standard boilers chosen
to represent each capacity interval. Figures 6-2 and 6-3 illustrate how the
selected wood- and bagasse-fired boiler capacities compare with capacities
of these types of boilers sold between 1970 and 1978. Insufficient sales
data are available to provide similar comparisons for MSW- and RDF-fired
facilities.
Wood-fired boilers exist in all five capacity intervals. However, the
bulk of the wood-fired boiler capacity sold consists of watertube boilers
larger than 7.3 MW (25 x 10 Btu/hr) thermal input. Sales data for these
types of boilers are presented in Figure 6-2 and in Chapter 3. Smaller
boilers are generally of the firetube design and are commonly used in the
furniture industry. Similar sales data were not available for this type of
boiler. The firing mechanisms for most new wood-fired boilers for which
data are available are essentially the same, spreader or overfeed stoker,
6-4
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TABLE 6-2. REPRESENTATIVE STANDARD BOILER CAPACITIES
o>
Ol
Capacity Range - Thermal Input
Fuel'
<7.3 MW 7.3-14.7 MW 14.7-29.3 MW 29.3-73.3 MW =-73.3 MW
(<25 x 106 Btu/hr) (25-50 x 106 Btu/hr) (50-100 x 106 Btu/hr) (100-250 x 106 Btu/hr) (>250 x 106 Btu/hr)
Wood
HAB
8.8JIH
(30 x 10° Btu/hr)
22.0,MW
(75 x 10° Btu/hr)
44.0 MW
(150 x 10° Btu/hr)
44.0 MW
117 MW
(400 x 10° Btu/hr)
SLW
Mood - hog fuel (wood/bark mixture)
HAB - high ash bark
SLW - salt-laden wood
HSE - high sulfur eastern coal
LSW - low sulfur western coal
RDF - refuse derived fuel
MSW - municipal solid waste
Average fuel mixture on a heat input basis.
(150 x 10° Btu/hr)
44.0 MW
(150 x 10D Btu/hr)
75% Wood/"
25% HSE
50* Wood/b
50% HSE
50% Wood/b
50% LSW
50% RDF/b
50% HSE
MSW 2.9,MW
(10 x 10° Btu/hr)
Bagasse
44.0 MW
(150 x 10° Btu/hr)
44.0 MW
(150 x 10° Btu/hr)
44.0 MW
(150 x 10° Btu/hr
44.0 MW
(150 x 10° Btu/hr)
44.0 MW
(150 x 10° Btu/hr)
58.6 MW
(200 x 10° Btu/hr)
117 MW
(400 x 10° Btu/hr)
117 MW
(400 x 10° Btu/hr)
-------
30
25
20
15
o
m
o
t.
10
I
Standard boiler size
designated by A.
40 60 80 100 120 140 160 180
Steam output - 103 Ibs/hr
I I I
400
500
iA. i A i i
' 14.6
(50)
(100)
A i
44.0
(150)
l 1 1
(200)
1 1
73.1?
(250)
i 4
87.9 *
(300)
1
172
(600)
i j
234
(800)
I i*JUi •>
(293)
(1000)
VTfe
(1400)
Thermal Input Capacity - MW (10^ Btu/hr)
Figure 6-2. Size distribution of wood-fired watertube boilers sold from
1970 through 1978 together with the selected standard boiler
sizes, (size distribution data from Chapter 3)
-------
15 -
10 -
o
to
01
o
CO
M-
o
-------
and emission rates, while variable, are similar across the entire capacity
range. Four wood-fired boiler sizes of similar design were selected to show
the regulatory impacts on various size boilers. These sizes are 8.8, 22,
44, and 117 MW (30, 75, 150, and 400 x 106 Btu/hr) thermal input. Fuels
selected for these standard boiler sizes include a hog fuel representative
of wood fuels fired in most wood-fired boilers in the United States. Two
additional fuels were selected for the 44 MW (150 x 10 Btu/hr) boiler to
show the sensitivity of regulatory impacts on wood-fired boilers to fuels
containing additional ash or salt resulting from storage or from logging
operations. These fuels were designated high ash bark (HAB) and salt laden
wood (SLW).
Boilers that cofire wood and coal have firing mechanisms similar to
wood-fired boilers but are uncommon in the smaller capacity intervals. As a
result, two boilers were selected of the same capacities as the largest
wood-fired boilers, 44 and 117 MW (150 and 400 x 106 Btu/hr). Coals
selected for these standard boiler sizes include a high sulfur eastern coal
(HSE) and a low sulfur western coal (LSW). Various fuel mixtures were
selected for these standard boiler sizes. Wood/HSE mixtures averaging
50 percent wood were selected for each size boiler and a mixture averaging
75 percent wood was selected for the 44 MW boiler. Also selected for the
44 MW boiler was a wood/LSW mixture averaging 50 percent wood. Different
fuel mixture ratios and coal sulfur contents were selected to show the
effect of these variables on S02 and PM emissions and the associated
environmental, energy, and economic impacts. Nonfossil fuels are naturally
low in sulfur content.
RDF can generally be fired to some extent in any boiler designed to
fire coal but has mostly been cofired with coal in large industrial and
utility boilers. One standard boiler was selected of the same capacity as
most of the wood/coal cofired standard boilers, 44 MW (150 x 10 Btu/hr). A
spreader stoker was chosen as the firing mechanism since to date it has been
the preferred firing mechanism for boilers firing over 20-30 percent RDF.
Some boilers are currently being designed and built to fire RDF alone.
Little emission data are currently available for this type of boiler so no
6-8
-------
standard boiler was selected to represent this case. However, tests at one
facility firing RDF alone achieved similar emission levels as large
MSW-fired boilers with similarly designed control systems.
As discussed in Chapter 3, MSW-fired boilers are of two significantly
different designs with different emission rates. Three MSW-fired boiler
capacities were selected, 2.9, 44, and 117 MW (10, 150, and
400 x 10 Btu/hr) thermal input. The small capacity selected is typical of
small modular incinerators of controlled air design with heat recovery. The
two larger capacities are expected to cover the range of sizes for most new
MSW-fired boilers using the mass-burn design.
Bagasse-fired boilers sold in recent years have consisted of spreader
stokers and various pile burning designs. However, as discussed in
Chapter 3, most new bagasse-fired boilers are expected to be spreader
n £
stokers. One standard boiler capacity, 58.6 MW (200 x 10 Btu/hr),
representing this design was selected. As shown in Figure 6-3, most boilers
sold had a thermal input capacity of about this size or larger. A smaller
bagasse-fired boiler was not included in the analysis because few if any
smaller boilers are anticipated to be built. A larger boiler was not
evaluated since economies of scale would be expected in both boiler and
emission control costs.
6.1.2 Characterization of Standard Boilers
The firing mechanisms for the majority of new wood-fired boilers are
similar across the capacity range as shown in Table 3-1. These units are
primarily spreader or overfeed stokers with the major differences being in
3
the type of grate selected. Some other firing methods used at times to
fire wood include Dutch ovens, fuel cells, and fluidized beds. However, as
was discussed in Chapter 3, Dutch ovens have been phased out for new
construction due to high costs, low efficiencies, and inability to follow
load swings. Particulate emission rates from the other firing mechanisms
are usually less than from spreader stokers. Because of the prevalence of
spreader stokers as a firing mechanism for wood-fired boilers and because
spreader stokers have higher uncontrolled emission rates, all of the wood-
fired standard boilers were selected to be spreader stokers.
6-9
-------
Wood/coal cofired boilers are also generally spreader stokers. For
this reason and to aid in comparing the regulatory impacts among the various
standard boilers, the spreader stoker was selected as the firing mechanism
for these standard boilers.
RDF and coal have been fired together in both spreader stokers and in
pulverized coal units. Spreader stokers have been used and are planned for
boilers firing various ratios of RDF and coal from zero to 100 percent RDF.
RDF use in pulverized coal units has generally been limited to around
20 percent with some tests ranging up to 30 percent RDF. Since stoker-fired
boilers are the only types that have been used to fire fuel mixtures
containing large percentages of RDF, the spreader stoker was selected as the
firing mechanism for the standard boiler cofiring RDF and coal.
MSW-fired boilers fall into two distinct design types based on
capacity. Small municipal incinerators with heat recovery are usually
bought in modules, the number and size determined by the amount of waste to
be burned. These modular devices often use two combustion chambers with
substoichiometric air to the first chamber. This "controlled air" design
was selected as representative of small MSW-fired boilers. A "mass burn"
boiler which burns the waste as it is received on moving grates was selected
as representative of large MSW-fired boilers.
Bagasse-fired boilers use spreader stokers, fuel cells, and horseshoes
as firing methods. Horseshoes and fuel cells are pile burning designs
similar to the Dutch oven used to fire wood. They differ in the shape of
the furnace area but in other respects are similar in design and operation.
The basic design of the bagasse-fired spreader stoker is the same as that of
the wood-fired spreader stoker. Most new bagasse- fired boilers are
expected to use spreader stokers so this design was selected for the
bagasse-fired standard boiler.
6.1.3 Standard Boiler Specifications
The specifications for the standard boilers provide the basis for the
"model boiler" environmental and economic analyses. The primary parameters
specified are:
- Fuel type and quality
6-10
-------
- Design capacity and load factor
- Flue gas characteristics
Each parameter is discussed below with an explanation of the deter-
mining factors. The design parameters for all the selected standard boilers
are presented in Table 6-3. Additional design parameters required
specifically for cost analysis are presented in Chapter 8.
6.1.3.1 Fuels. The fuel specifications have been chosen to represent
currently available choices for nonfossil fuels and are presented in
Table 6-4. The fuel characteristics, including heating value and chemical
analysis, are specified to determine the combustion-related characteristics
of the standard boilers.
Three wood fuels were selected. All of the standard boilers firing
wood, except for one, use a wood fuel analysis representative of a hog
A
fuel, which is a mixture of wood and bark and is representative of wood
fuels fired in most wood-fired boilers in the United States. The fuel
moisture, sulfur, and nitrogen contents were selected as representative
values based on other literature data and test data presented in
Appendix C. To compare the effects of firing a high ash content fuel with
those of the selected fuel, a second wood composition was derived from the
first and labeled "high ash bark" (HAB). The HAB composition was derived
from the hog fuel composition by increasing the ash content from two percent
to six percent on a dry basis, keeping the fuel moisture at 50 percent, and
adjusting the other elements and fuel heating value proportionately. This
high ash content is on the high end of values reported in the literature for
bark. ' The resulting fuel heating value is still well within the range of
heating values common for wood and bark fuels.
To compare the effects of firing wood from logs that have been stored
in salt water, a third wood composition was derived from the first and
labeled "salt-laden wood" (SLW). The SLW composition was derived from the
hog fuel composition by specifying the fuel to have 1.0 percent salt on a
dry basis, keeping the fuel moisture at 50 percent, and adjusting the other
elements and fuel heating value proportionately. The salt content was based
6-11
-------
TABLE 6-3. STANDARD BOILER DESIGN SPECIFICATIONS
Model Boiler Number
Thermal Input, HW (106 Btu/hr)
Fuel"
Fuel rate, kg/s
(ton/hr)
Analysis
X sulfur
X ash
Heating value, kJ/kg
(Btu/lb)
Excess air. X
Flue gas flow rate, m /s (acfm)
Flue gas temperature, °K(°F)
Load factor, X
Flue gas constituents, kg/hr(lb/hr)
Fly ash (before mechanical collector)0
(after mechanical collector)
SO-
H0x
Ash from sand classifier,1 kg/hr(lb/hr)
Bottom ash, kg/hr(lb/hr)
Boiler Output, MM {106 Btu/hr)
Steam
Losses
Efficiency, X
Steam quality
Pressure, kPa(pslg)
Temperature, °K ("F)
Steam production,6 kg/hr(lb/hr)
1
8.8(30)
Mood
0.829
(3.29)
0.02
1.00
10,600
(4.560)
SO
6.94(14,700)
478(400)
60
66.2(146)
13.3(29.3)
3.40(7.50)
29.2(64.4)
20.1(44.4)1
5.7(19.5)
3.1(10.5)
65
1,720(250)
481(406)
8,890(19.600)
2
22.0(75)
Wood
2.07
(8.22)
0.02
1.00
10.600
(4.560)
50
17.3(36,700)
478(400)
60
166(366)
33.2(73.2)
8.53(18.8)
73.0(161)
so.sdii)3
14.3(48.7)
7.7(26.3)
65
1,720(250)
481(406)
22.200(49,000)
3
44.0(150)
Wood
4.15
(16.4)
0.02
1.00
10.600
(4,560)
50
34.7(73,500)
478(400)
60
332(732)
66.4(146)
17.0(37.5)
146(322)
101(222)1
28.6(97.5)
15.4(52.5)
65
1.720(250)
481(406)
44.500(98,200)
4
117(400)
Wood
11.1
(43.9)
0.02
1.00
10.600
(4,560)
50
92.5(196.000)
478(400)
60
885(1950)
177(390)
45.3(100)
390(859)
269(592)^
76.1(260)
41.0(140)
65
5,170(750)
672(750)
101,000(223.000)
5
44.0(150)
HAB
4.32
(17.2)
0.02
3.00
10.160
(4.370)
50
34.7(73.500)
478(400)
60
467(1030)
93.9(207)
17.0(37.5)
255(563)
292(644)
28.6(97.5)
15.4(52.5)
65
1,720(250)
481(406)
44,500(98,200)
See footnotes at end of table.
6-12
-------
TABLE 6-3. (CONTINUED)
Model Boiler Number
Thermal Input, MH(106 Btu/hr)
Fuel*
Fuel rate, kg/s
(ton/hr)
Analysis
X sulfur
X ash
Heating value, kJ/kg
(Btu/lb)
Excess air, X
Flue gas flow rate, m /s (acfm)
Flue gas temperature, °K(°F)
Load factor, X
Flue gas constituents,11 kg/hr(lb/hr)
Fly ash(before mechanical collector)0
(after mechanical collector)"
SO,
NOX2
Ash from sand classifier,1 kg/hr(lb/hr)
Bottom ash, kg/hr(1b/hr)
Boiler Output, HM (106 Btu/hr)
Steam
Losses
Efficiency, X
Steam quality
Pressure, kPa(pslg)
Temperature, °K(°F)
Steam production,6 kg/hr(lb/hr)
6
44.0(150)
SLU
4.18
(16.6)
0.02
1.49
10,490
(4510)
50
34.7(73,500)
478(400)
60
411(905)
142(314}
17.0(37.5)
147(325)
101(222)
28.6(97.5)
15.4(52.5)
65
1,720(250)
481(406)
44,500(98,200)
7
44.0(150)
75X Wood/f>g
25X HSE
3.11/0.401
(12.3/1.59)
0.02/3.54
1.00/10.58
10,600/27,440
(4,560/11,800)
50
33.3(71.300)
478(400)
60
348(767)
69.6(153)
102(224)
23.5(51.7)
189(416)
129(285)
30.4(104)
13.6(46)
69
1,720(250)
481(406)
47,600(105,000]
8
44.0(150)
SOX Wood/f >9
SOX HSE
2.07/0.801
(8.22/3.18)
0.02/3.54
1.00/10.58
10,600/27,440
(4.560/11.800)
50
32.4(69.200)
478(400)
60
364(803)
72.8(160)
197(434)
29.9(66.0)
231(510)
157(348)
32.1(110)
11.9(40)
73
1.720(250)
481(406)
50. 300 (111-. 000
9
117(400)
SOX Hood/'9
SOX HSE
5.52/2.13
(21.9/8.47)
0.02/3.54
1.00/10.58
10.600/27.440
(4.560/11.800)
50
87.1(184,500)
478(400)
60
971(2140)
194(428)
526(1160)
79.7(176)
617(1360)
421(928)
85. 4(292)
31.6(108)
73
5,170(750)
572(750)
114,000(251.000)
10
44.0(150)
BOX Wood/ t9
SOX LSW
2.07/0.985
(8.22/3.91)
0.02/0.60
1.00/5.40
10,600/22,330
(4,560/9,600)
SO
33.1(70,200)
478(400)
60
290(640)
58(128)
43.5(95.8)
29.9(66.0)
172(380)
117(259)
32.1(110)
11.9(40)
73
1,720(250)
481(406)
50,300(111.000)
See footnotes at end of table.
6-13
-------
TABLE 6-3. (CONTINUED)
Model Boiler Number
Thermal Input, HW(106 Btu/hr)
Fuel*
Fuel rate, kg/s
(ton/hr)
Analysis
X sulfur
X ash
Heating value, kj/kg
(Btu/lb)
Excess' air, X
Flue gas flow rate, m /s(acfm)
Flue gas temperature, "K(°F)
Load factor, X
Flue gas constituents, kg/hr(lb/hr)
Fly ash(before mechanical collector)0
(after mechanical collector)"
so2
Ash from sand classifier,1 kg/hr(lb/hr)
Bottom ash, kg/hr(lb/hr)
Boiler Output, HW (106 Btu/hr)
Steam
Losses
Efficiency. X
Steam quality
Pressure,*1 kPa(pslg)
Temperature, 'K('F)
Steam production,6 kg/hr(lb/hr)
11
44.0(150)
SOX RDF/f>9
SOX HSE
1.63/0.801
(6.48/3.18)
0.17/3.54
19.44/10.58
13,460/27.440
(5.790/11.800)
50
31.8(67,300)
478(400)
60
396(873)
214(472)
38.6(85.0)
.
1.050(2,320)
33.4(114)
10.6(36)
76
3.100(450)
589(600)
47.200(104,000
12
2.9(10)
HSW
0.260
(1.03)
0.12
22.38
11,340
(4.875)
100
2.79(5,920)
478(400)
60
1.36(3.00)
2.23(4.92)
1.40(3.08)
.
279(615)
1.6(5.5)
1.3(4.5)
55
1.720(250)
481(406)
2.510(5,540)
13
44.0(150)
HSU
3.88
(15.4)
0.12
22.38
11,340
(4.875)
100
41.8(88.500)
478(400)
60
229(504)
33.5(73.8)
21.0(46.2)
.
3,490(7.690)
30.8(105)
13.2(45)
70
3.100(450)
589(600)
43.600(96,000]
14
117(400)
HSW
10.3
0.12
22.38
11.340
(4.875)
100
111(236,000)
478(400)
60
608(1340)
89.3(197)
56.0(123)
.
9.310(20.500)
81.9(280)
35.1(120)
70
5,170(750)
672(750)
109,000(241.000)
15
58.6(200)
Bagasse
6.43
(25.5)
Trace
1.10
9.116
(3.920)
50
47.7(101,000)
478(400)
45
458(1.010)
18.1(40.0)
.
145(319)
35.2(120)
23.4(80)
60
1.720(250)
533(500)
51.700(114.000)
See footnotes at end of table.
6-14
-------
FOOTNOTES TO TABLE 6-3:
aWood - hog fuel (wood/bark mixture)
HAB - high ash bark
SLW - salt-laden wood
HSE - high sulfur eastern coal
LSW - low sulfur western coal
RDF - refuse derived fuel
MSW - municipal solid waste
Uncontrolled emissions.
£
Fly ash before mechanical collector means uncontrolled emissions prior to any control device
whether a mechanical collector is used or not.
Guage pressure.
T eAssuming a saturated condensate return at 10 psig.
^ Average fuel mixture on heat input basis.
^Boilers cofiring wood and coal are designed to fire wood up to 100 percent of the boiler capacity.
These boilers and their emission control systems are designed to fire coal only up to 30 percent
or 60 percent of the boiler capacity depending on whether the average cofiring ratio is 25 percent
or 50 percent. The model boiler cofiring RDF and coal is designed to fire coal up to 100 percent
of capacity and RDF up to 60 percent of capacity.
Fly ash after the mechanical collector is shown only for cases where fly ash reinjection is used.
The value shown represents a mechanical collector used as a precleaner prior to another control
device. For model boilers la - 4a, where the mechanical collector is the final control device,
this value would be the mass equivalent of an emission level of 258 ng/0 (0.6 lb/10 Btu).
classifiers are only used with systems employing fly ash reinjection (model boilers 1-10).
The value shown represents the difference in the amount of fly ash collected by the mechanical
collector and the amount of fly ash reinjected into the boiler furnace.
JThese values are for cases where the mechanical collector is used as a precleaner prior to another
control device. Where the mechanical collector is the final control device, these values would be
34.3, 85.7, 171, and 458 kg/hr (75.7, 189, 378, and 1009 Ib/hr) for model boilers la, 2a, 3a, and
4a respectively.
-------
TABLE 6-4. ULTIMATE ANALYSES OF THE FUELS SELECTED FOR THE STANDARD BOILERS
O)
I
Composition, t- by
Fuel8
Hood
HAB
SLH
RDFC
MSH°
Bagasse
HSE
LSH
Moisture
50.00
50.00
50.00
22.42
27.14
52.00
8.79
20.80
Carbon
26.95
25.85
26.68
31.30
26.73
22.60
64.80
57.60
Hydrogen
2
2
2
4
3
3
4
3
.85
.73
.82
.62
.60
.10
.43
.20
weight
N1 trogcn
0.
0.
0.
0.
0.
0.
1.
1.
08
08
08
61
17
10
30
20
Oxygen
19.10
18.32
18.91
21.44
19.74
21.10
6.56
11.20
Sulfur
0.02
0.02
0.02
0.17
0.12
Trace
3.54
0.60
Ash
1.00
3.00
1.49b
19.44
22.38
1.10
10.58
5.40
Gross
Heating Value
kJ/kg (Btu/lb)
10,600
10,160
10,490
13,460
11,340
9,116
27,440
22,330
( 4,560)
( 4,370)
( 4,510)
( 5,790)
( 4,875)
( 3,920)
(11,800)
( 9,600)
Wood - hog fuel (wood/bark mixture)
HAB - high ash bark
SLH - salt-laden wood
RDF - refuse derived fuel
HSU - municipal solid waste
HSE - high sulfur eastern coal
LSH - low sulfur western coal
Salt makes up 0.5 percent of the fuel composition and is Included here as ash.
Composition does not total 100 percent due to the presence of chlorine which is not shown here.
-------
7 8
on fuel analysis data for salt-laden wood ' and the heating value is still
well within the range of values common for wood and bark fuels.
The RDF composition was obtained by averaging RDF analyses from several
Q
facilities that have fired RDF. The MSW composition was taken from a
performance test conducted on boilers at an operating facility. The
analysis compares closely with reported "typical" compositions for MSW
except that the heating value of the selected waste is somewhat higher.
However, the heating value of MSW in the United States has been increasing
with time, and the heating value of the selected waste falls well within the
range of values predicted by several studies for the 1985 - 1990 time
12
frame.
The bagasse composition was based on an average dry composition
13
reported in the Cane Sugar Handbook. Sulfur and nitrogen concentrations
were based on values reported in various other sources. Fuel moisture was
set at an intermediate level based on values reported in the Gilmore Sugar
Manual.14
Two coal compositions were selected for the cofiring cases. All of the
cofired standard boilers except one fire a coal representative of an eastern
high sulfur, high ash coal. To consider a contrasting coal composition, one
standard boiler was also selected to fire a coal representative of a western
low sulfur, low ash coal. Analyses for these coals are identical to those
15
used in the industrial boiler study.
6.1.3.2 Boiler Capacities and Load Factors. The capacities of the
standard boilers selected in Section 6.1 are based on the maximum heat input
to the boiler. The heat input together with the heating value of the fuel
determines the fuel firing rate. Capacities of boilers, however, are often
stated on a steam output basis. To quantify the steam output, the thermal
efficiency and steam quality of the boiler must be specified. The thermal
efficiency of the boiler is the measure of the percentage of heat input
which is transferred to the steam cycle and is a function of the fuel
properties, firing method, flue gas characteristics, and boiler heat losses.
Thermal efficiencies shown in Table 6-3 are generally based on values
reported in the literature for wood,5 MSW,16'17 and bagasse-fired18 boilers.
6-1?
-------
Thermal efficiencies shown for the combination fuel boilers are adjusted to
reflect the proportion of coal fired based on values used in the industrial
19
boiler study for coal-fired boilers.
The quality of the steam is specified in terms of temperature and
pressure. The steam quality varies with the intended steam use. The steam
temperatures and pressures specified for the standard boilers are those
commonly found in various applications for the selected boiler capacities.
20
Steam qualities were selected based on watertube boiler sales data for
wood and bagasse-fired boilers, steam qualities selected for coal-fired
19
boilers in the industrial boiler study, and various literature
21 22
references. '
The capacities of the standard boilers represent maximum firing rates.
Boilers, however, seldom operate at maximum capacity year-round. To analyze
impacts on an annual operating basis, an appropriate measure of actual
boiler usage must be selected. The load factor (or capacity utilization
factor) is the actual annual fuel consumption as a percentage of the
potential annual fuel consumption at maximum firing rate. Load factors for
23
industrial boilers are estimated to range from 30 to 80 percent. Since
nonfossil fuel fired boilers provide steam for similar end uses in industry
as fossil fuel fired boilers, this range was assumed to be representative.
Load factors for MSW resource recovery plants installed by 1990 are
24
forecasted to average 60-80 percent.
Low load factors generally represent "nonprocess" boilers or boilers
used in seasonal industries, such as bagasse-fired boilers. High load
factors generally represent process or utility boilers whose output is tied
directly to plant production. Load factors can vary considerably from plant
to plant and from industry to industry and are influenced by such items as
the economic climate of the country, the availability of nonfossil fuels,
the reliability of the boiler and fuel feeding equipment, and decisions to
buy oversized boilers to allow for plant expansions. Load factors for the
standard boilers were generally set at 60 percent for each boiler and fuel
combination. Bagasse-fired boilers were assigned a lower load factor of
45 percent due to the seasonal nature of the industry. Some different load
6-18
-------
factors are used in the economic analyses for specific boiler applications
appearing in Chapter 9.
6.1.3.3 Flue Gas Characteristics. Temperature, composition, and
volumetric flow rate are the main flue gas characteristics upon which the
design of emission control systems are based. These characteristics are
mainly affected by fuel composition and boiler excess air. Fuel analyses
are presented in Table 6-4. A representative excess air value was selected
for each standard boiler and is included in Table 6-3. The pollutant
concentrations in the flue gas are calculated based on the excess air rate,
the chemical composition of the fuel, and the pollutant emission factors
25
developed in Chapter 3 for each standard boiler.
6.2 SELECTION OF CONTROL ALTERNATIVES
The environmental, energy, and economic impacts of applying various
control levels to the standard boilers are presented in Chapters 7 and 8.
In order to perform those analyses, various emission control levels and
control technologies are identified. This section presents the rationale
for the selection of both the emission control levels and control
techniques.
A baseline or reference control level provides a basis for evaluating
the incremental impacts of more stringent control levels. In addition, two
more stringent control levels are also specified in order to evaluate their
impacts. These control levels were generally selected based on the range of
emission test data presented in Chapter 4. The selections of the model
boiler control techniques used to meet each emission level are also based on
data presented in Chapter 4.
The major pollutant of concern from nonfossil fuel fired boilers is
particulate matter (PM). PM is the only pollutant for which controls are
currently being required for NFFBs under existing standards. No NO
controls are considered since control techniques for NO reduction have
typically not been applied to NFFBs. When coal or oil is fired together
with a nonfossil fuel, emissions of SO- are generally increased compared to
100 percent nonfossil fuel firing. Therefore, several cofired standard
6-19
-------
boilers were selected for analysis to show the impacts of S02 control
requirements on cofired boilers.
6.2.1 Baseline. Control Alternative
The baseline control alternative generally represents the highest level
of emissions expected under the current mix of existing regulations (SIPs
and 40 CFR 60 Subparts D and E). The control method selected to meet the
baseline alternative generally represents the least effective control method
applicable to a particular pollutant and standard boiler. In most cases,
this also represents the least expensive control method.
The control levels and control methods selected as the baseline control
alternatives for each fuel type are shown in Table 6-5. For most of the
fuel types the baseline emission level was chosen as the average of existing
State and Federal emission regulations. These regulations are presented in
Section 3.3.
For wood-fired boilers the emission level chosen was 258 ng/J
(0.6 lb/10 Btu) rather than the average of existing regulations. Existing
State particulate matter emissions for wood-fired boilers vary widely, as
shown in Table 3-19 in Chapter 3. Setting the baseline for wood-fired
boilers at the average SIP level would have excluded mechanical collectors
as a control method in the model boiler analysis. However, mechanical
collectors are still used in many states for particulate matter control.
Therefore, the baseline control alternative was set so that this technology
could be included in the model boiler analysis.
6.2.2 Emission Control Level I
Emission Control Level I represents a control level moderately more
effective than the baseline level. The emission levels and control
technologies selected for Control Level I are presented in Table 6-5.
The emission levels and control methods chosen for Control Level I for
PM are generally based on the "average" emissions shown in Chapter 4 for
each boiler and fuel type. If insufficient data were available to determine
the "average" case, the emission level and control method selected are the
average emission level and control method for a similar fuel and boiler
combination for which data are available.
6-20
-------
TABLE 6-5. EMISSION CONTROL LEVELS AND APPLICABLE CONTROL METHODS
en
ro
Baseline
Fuel Control .
Type Techniques
PH Emissions
Wood HC
HAB.SLW WS
Hood/Coal WS
RDF/Coal WS
HSWd ESP
MSHe None
Bagasse HC
SOpEmisslons
Wood/Coal FGD-WS
RDF/Coal
aWood - hog fuel (wood/bark mixture)
HAB - high ash bark
SLW - salt-laden wood
Coal - Includes high and low sulfur
RDF - refuse derived fuel
MSW - municipal solid waste
bWS - wet scrubber
FF - fabric filter
ESP - electrostatic predpitator
Control Level
Emission
Level £
ng/J(lb/10°Btu)
258
(0.60)
146
(0.34)
43.0 - 138
(0.10 - 0.32)
138
(0.32)
73.1
(0.17)
129
(0.30)
267
(0.62)
526 - 1075
(1.2 - 2.5)
coals
Control Level I
Emission
Control h Level,
Techniques ng/J(lb/10°Btu)
WS 64.5
(0.15)
WS 64.5
(0.15)
WS 43.0 - 64.5
(0.10 - 0.15)
WS 64.5
(0.15)
ESP 43.0
- (0.10)
WS 64.5
(0.15)
WS 86. 0
(0.2)
FGD-WS 70 percent
FGD-DS Control
Control Level II
Emission
Control b Level ,
Techniques ng/J(lb/10°Btu)
WS.FF zl-5
ESP, EGB (005)
FF 21.5
(0.05)
FF.ESP 21.5
(0.05)
FF.ESP 21.5
(0.05)
ESP 21.5
(0.05)
FF 21.5
(0.05)
_
FGD-WS 90 percent
Control
EGB - electrostatic gravel bed filter
MC - mechanical collector
FGO-DS - flue gas desulfurization (dry scrubbing)
FGD-WS - flue gas desulfurization (wet scrubbing)
cEmiss1on ranges reflect different baseline emission levels for different sizes of standard boilers.
Includes all MSW-fired boilers except small modular units.
elncludes only small modular MSW-fired boilers.
-------
6.2.3 Emission Control Level II
Emission Control Level II is based on the more stringent emission
levels shown achievable by the emission data in Chapter 4. The emission
limits and control techniques selected are presented in Table 6-5. Where
data are available the selection of control methods to meet Control Level II
are based on the controls used on existing NFFBs to meet more stringent
emission levels. If there is insufficient data to determine a control
method on this basis, the control method is based on control devices which
can meet stringent emission levels for other fuel categories.
Control Level II was not evaluated for bagasse-fired boilers because
data are not available for high efficiency controls for this fuel.
6.3 MODEL BOILERS
Model boilers are combinations of standard boilers and emission control
systems which are selected to allow evaluation of cost, environmental, and
energy impacts of air pollution control across a range of boiler types and
sizes for several emission control levels. Results of these evaluations are
presented in Chapters 7 and 8.
The model boiler selection process is intended to generate a set of
model boilers which represents the expected population of new NFFBs and
emission control systems utilizing Baseline, Level I, and Level II controls.
Control systems selected to achieve compliance with each control level are
discussed in Section 6.2. In many cases more than one emission control
system or combination of control systems can achieve a specified control
level, and consequently, several alternatives were evaluated to examine
their relative impacts.
There is, however, a practical limit to the number of model boilers
that can be examined. As a guideline, model boilers were generally selected
to represent what appeared to be a demonstrated and lowest cost method or
combination of methods to achieve the required control levels for each
boiler/fuel/control level combination considering technology limits and
development status.
6-22
-------
Control techniques selected for model boiler evaluations include
mechanical collectors, wet scrubbers, electrostatic precipitators, fabric
filters, and electrostatic gravel bed filters for particulate control.
Double alkali and lime wet scrubbing and lime dry scrubbing flue gas desul-
furization systems were selected as SCL control techniques. Model boilers
that include these control techniques are presented in Table 6-6. These
model boilers will serve as the basis for the cost, environmental, and
energy impact analyses.
6.4 EMISSION LEVELS
For the purpose of evaluating environmental impacts, numerical emission
levels for each pollutant have been set for each standard boiler (uncon-
trolled, Baseline, Control Level I, and Control Level II). These numerical
emission levels for the standard boilers are shown in Table 6-7 for the
different fuel types and boiler capacities.
It should be noted that many issues such as economic and environmental
impacts are not considered in the selection of Control Levels I and II. The
purpose of these numerical levels is to evaluate the impacts of various
control techniques and emission levels on the model boilers. They do not
necessarily represent final numbers which will be selected as the standard.
6-23
-------
TABLE 6-6. MODEL BOILERS
Model Boiler
Number
la
Ib
Ic
Id
le
2a
2b
2c
2d
2e
2f
3a
3b
3c
3d
3e
3f
4a
4b
4c
4d
4e
4f
5a
5b
5c
6a
6b
6c
7a
7b
7c
7d
7e
7f
79
8a
8b
8c
8d
8e
8f
8g
Boiler Capacity
(thermal Input)
8.8 MW
(30 x 106 Btu/hr)
22.0 MW
(75 x 106 Btu/hr)
44.0 MW
(150 x 106 Btu/hr)
117 MW
(400 x 106 Btu/hr)
44.0 MW
(150 x 106 Btu/hr)
44.0 MW
(150 x 106 Btu/hr)
44.0 MW
(150 x 106 Btu/hr)
44.0 MW
(150 x 106 Btu/hr)
Fuel a Control
~PH
Wood B
I
II
II
II
Wood B
I
II
II
II
II
Wood B
I
II
II
II
II
Wood B
I
II
II
II
II
HAB B
I
II
SLW B
I
II
75X Wood/d B
252 HSE I
I
II
II
II
II
50% Wood/d B
SOX HSE I
I
I
II
II
II
Level"
-§07
B
B
B
B
B
B
8
B
8
B
B
B
B
8
B
B
8
B
B
B
B
B
B
B
B
B
B
B
8
B
B
I
B
B
I
II
B
B
I
II
B
I
II
Emission Control
ffl
MC
MC.WS
MC.WS
MW.FF
MC.ESP
MC
MC.HS
MC.WS
MC.FF
MC.ESP
MC ,EGB
MC
MC.WS
MC.WS
MC.FF
MC.ESP
MC.EG8
MC
MC.WS
MC.WS
MC.FF
MC.ESP
MC.EGB
MC.WS
MC.WS
MC.FF
MC.WS
MC.WS
MC.FF
MC.WS
MC.WS
MC.FGD-WS
MC.ESP
MC.FF
MC.FF
MC.ESP
MC.FGO-WS
MC.FGD-WS
MC.FGO-WS
MC.FGD-WS
MC.FF
MC.FF
MC.ESP
Systemc
™T
—
—
.
-
.
-
_
-
-
-
.
.
-
—
-
-
-
-
—
-
.
-
FGD-WS
_
_
FGD-DS
FGO-WS
FGD-WS
FGD-WS
FGD-HS
FGD-WS,,
FGD-DS8
FGD-DS
FGD-WS
See footnotes at end of table.
6-24
-------
TABLE 6-6. (CONTINUED)
Model Boiler
Number
9a
9b
9c
9d
lOa
lOb
lOc
lOd
lOe
lOf
lOg
lOh
lla
lib
lie
lid
lie
12a
12b
12c
13a
13b
13c
14a
14b
14c
15a
15b
Boiler Capacity
(thermal Input)
117 MW
(400 x 106 Btu/hr)
44.0 MW
(150 x 106 Btu/hr)
44.0 MW
(150 x 106 Btu/hr)
2.9 MW
(10 x 106 Btu/hr)
44.0 MW
(150 x 106 Btu/hr)
117 MW
(400 x 106 Btu/hr)
58.6 MW
(200 x 106 Btu/hr)
Fuel3 Control
PM
50% Wood/d B
502 HSE I
II
II
50* Wood/d B
50% LSW I
I
I
II
II
II
II
50% ROF/d B
50% HSE I
I
II
II
MSW B
I
II
MSW B
I
II
MSW B
I
II
Bagasse B
I
Level b
-§07
B
I
I
II
B
B
I
II
B
B
I
II
8
I
II
I
II
B
B
B
B
B
B
B
B
B
B
B
Emission Control
PM
MC .FGD-WS
MC.FGD-WS
MC.FF
MC ,ESP
MC.WS
MC.WS
MC .FGD-WS
MC .FGD-WS
MC.FF
MC.ESP
MC.FF
MC ,ESP
FGD-WS
FSO-WS
FGO-WS
ESP
ESP
WS
FF
ESP
ESP
ESP
ESP
ESP
ESP
MC
WS
System0
sd2
FGD-WS
FGD-WS
FGD-DS
FGD-WS
FGD-WS
FGD-WS
.
.
FGD-DS
FGD-WS
FGD-WS
FGD-WS
FGD-WS
FGD-WS
FGD-WS
-
-
-
-
- hog fuel (wood/bark mixture)
HAS - high ash bark
SLW - salt-laden wood
HSE - high sulfur eastern coal
LSW - low sulfur western coal
RDF - refuse derived fuel
MSW - municipal solid waste
B refers to Baseline control level.
I refers to Control Level I.
II refers to Control Level II.
SlC.- mechanical collector
WS - wet scrubber
FF - fabric filter
ESP - electrostatic predpltator
EGB - electrostatic gravel bed filter
FGD-WS - flue gas desulfurlzatlon; double alkali or lime wet scrubber
FGD-DS - flue gas desulfurlzatlon; Hme dry scrubber
Control systems separated by a comma mean that both are used at the same time, not that either may be used
Independently. Mechanical collectors are Included for fly ash re1nject1on on all of the boilers flrfnq
wood.
Average fuel mixture on a heat Input basis.
eOnly a portion of the flue gas Is scrubbed.
6-25
-------
TABLE 6-7. EMISSION LEVELS FOR THE MODEL BOILERS
Standard
Model *°"er
Boiler ™
Number Fuel (10°Btu/hr)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
Wood
Mood
Mood
Mood
HAB
SIM
75t Mood/b
25t HSE
SOt Hood/b
SOt HSE
SOt Hood/b
SOt HSE
SOt Wood/6
SOt LSM
501 ROF/b
SOt HSE
MSM
MSH
MSW
Bagasse
8.8
(30)
22.0
(75)
44. 01
(150)
117
(400)
44.0
(ISO)
44.0
(150)
44.0
(150)
44.0
(150)
117
(400)
44.0
(150)
44.0
(150)
2.9
(10)
44. 01
(ISO)
117
(400)
58.6
(200)
See footnotes on second
Baseline d
Uncontrolled Emissions Control Level
ng/J (lb/106 Btu) ng/J (lb/106 Btu)
PM-BMCC
2100
(4.88)
2100
(4.88)
2100
(4.88)
2100
(4.88)
2950
(6.87)
2590
(6.03)
2200
(5.11)
2300
(5.35)
2300
(5.35)
1840
(4.27)
2500
(5.82)
129
(0.30)
1440
(3.36)
1440
(3.36)
2170
(5.05)
page.
PM-AMCC
418
(0.973)
418
(0.973)
418
(0.973)
418
(0.973)
593
(1.38)
899
(2.09)
440
(1.02)
460
(1.07)
460
(1.07)
367
(0.853)
-
-
-
.
-
S°29
-
-
641
(1.49)
1240
(2.89)
1240
(2.89)
275
(0.639)
1350
(3.15)
212
(0.49)
212
(0.49)
212
(0.49)
-
PM
258
(0.6)
258
10.6)
258
(0.6)
258
(0.6)
146
(0.34)
146
(0.34)
138
(0.32)
138
(0.32)
43.0
(0.10)
138
(0.32)
138
(0.32)
129
(0.30)
'73.1
(0.17)
73.1
(0.17)
267
(0.62)
so2
-
-
641
(1.49)
1075
(2.50)
516
(1.2)
275
(0.639)
1075
(2.50)
212
(0.49)
212
(0.49)
212
(0.49)
-
Control Level I
ng/J (lb/106 Btu)
PM
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
43.0
(0.10)
64.5
(0.15)
64.5
(0.15)
64. 5
(0.15)
43.0
(0.10)
43.0
(0.10)
86.0
(0.20)
so2e
-
-
194
(0.45)
374
(0.87)
374
(0.87)
81.7
(0.19)
405
(0.94)
212
(0.49)
212
(0.49)
212
(0.49)
-
Control Level II
ng/J (lb/106 Btu)
PM
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
_h
so2f
-
-
64.5
(0.15)
125
(0.29)
125
(0.29)
27.5
(0.06)
135
(0.31)
212
(0.49)
212
(0.49)
212
(0.49)
-
6-26
-------
FOOTNOTES TO TABLE 6-7.
aWood - hog fuel (wood/bark mixture)
HAB - high ash bark
SLW - salt-laden wood
RDF - refuse derived fuel
MSVI -municipal solid waste
HSE - high sulfur eastern coal
LSW - low sulfur western coal
Average fuel mixture on a heat input basis.
CBMC - before mechanical collector or any other control equipment.
AMC - after mechanical collector when the mechanical collector is not the final control device.
Both values are included only for cases with fly ash reinjection.
Emission level equivalent to the uncontrolled emission rate, or to the highest emission rate
expected under the current mix of State and Federal Regulations. For model boilers 1-4 the level
also represents emissions after the mechnical collector when the mechanical collector is the final
control device.
eThe emission level shown represents a 70 percent reduction from uncontrolled S02 emissions for the
combination fuel boilers and no control for the others.
The emission level shown represents a 90 percent reduction from uncontrolled S02 emissions for the
combination fuel boilers and no control for the others.
^SOy emissions for boilers firing bagasse of 100 percent wood are low and have not been quantified
for this analysis.
A level more stringent than Control Level I was not evaluated.
-------
6.5 REFERENCES
1. Emission Standards and Engineering Division. Fossil Fuel Fired
Industrial. Boilers-Background Information for Proposed Standards:
Chapters 6-10. (Prepared for U.S. Environmental Protection
Agency.) Research Triangle Park, N.C. June 1980. p. 6-3.
2. Memo from Barnett, K., Radian Corporation, to file. January 27, 1982.
22 p. Projections of new nonfossil fuel fired boilers (NFFBs).
3. Schwleger, B. Power from Wood. Power. _124:S.22-S.23. February 1980.
4. Hall, E.H., et al. (Battelle-Columbus Laboratories.) Comparison of
Fossil and Wood Fuels. (Prepared for U.S. Environmental Protection
Agency.) Research Triangle Park, N.C. Publication No. EPA-600/2-
76-056. March 1976. p. 39.
5. Reference 3, pp. S.4 and S.5.
6. Junge, D.C. (Oregon State University.) Design Guideline Handbook for
Industrial Spreader Stoker Boilers Fired with Wood and Bark Residue
Fuels. (Prepared for U.S. Department of Energy.) Washington, D.C.
Publication No. RLO-2227-T22-15. February 1979. p. 15.
7. Walther, J.E. and A.S. Rosenfeld. Projections on the Application of
Venturi Scrubbers to the Control of Emissions from Bark Boilers Fired
on Residues from Salt Water-Borne Logs. In: Proceedings of the 1975
NCASI West Coast and Central-Lake States Regional Meetings. Special
Report No. 76-08. New York, National Council of the Paper Industry for
Air and Stream Improvement. December 1976. p. 67.
8. Sanderson, J.G. Performance of a Pilot Dry Scrubber for Control of
Particulate Emissions from a Boiler Fired on Hog Fuel Derived from Logs
Exposed to Salt Water. In: Proceedings of the 1975 NCASI West Coast
and Central-Lake States Regional Meetings. Special Report No. 76-08.
New York, National Council of the Paper Industry for Air and Stream
Improvement. December 1976. p. 71.
9. Brown, R.A. and C.F. Busch. (Acurex Corporation.) Pilot Scale Combus-
tion Evaluation of Waste and Alternate Fuels: Phase III Final Report.
(Prepared for U.S. Environmental Protection Agency.) Research Triangle
Park, N.C. Publication No. EPA-600/7-80-043. March 1980. p. 116.
10. Bozeka, C.G. Nashville Incinerator Performance Tests. In: 1976
National Waste Processing Conference Proceedings. New York, The
American Society of Mechanical Engineers. 1976. p. 223.
6-28
-------
11. Wilson, E.M., et al. (The Ralph M. Parsons Company.) Engineering and
Economic Analysis of Waste to Energy Systems. (Prepared for
U.S. Environmental Protection Agency.) Cincinnati, Ohio. Publication
No. EPA-600/7-78-086. May 1978. p. A-14.
12. Reference 11, p. A-21.
13. Bagasse and Its Uses. In: Cane Sugar Handbook, Meade-Chen (ed.).
New York, John Wiley and Sons. p. 68.
14. McKay, C.M. (ed.). The Gilmore Sugar Manual. Fargo, North Dakota,
Sugar Publications, 1978. 169 p.
15. Reference 1, p. 6-17.
16. Reference 10, p. 224.
17. Frounfelker, R. Small Modular Incinerator Systems with Heat Recovery:
A Technical, Environmental and Economic Evaluation, Executive Summary.
(Prepared for U.S. Environmental Protection Agency.) Cincinnati, Ohio.
Publication No. SW-797. 1979. p. 3.
18. Baker, R. (Environmental Science and Engineering, Inc.) Background
Document: Bagasse Combustion in Sugar Mills. (Prepared for
U.S. Environmental Protection Agency.) Research Triangle Park, N.C.
Publication No. EPA-450/3-77-007. January 1977. p. 3.
19. Reference 1, pp. 6-11 through 6-15.
20. Memo from Barnett, K. and Murin, P., Radian Corporation, to file.
June 2, 1981. 31 p. Compilation of sales data for water tube boilers
for 1970 through 1978 from ABMA and other sources.
21. Scaramelli, A.B., et al. (MITRE Corporation.) Resource Recovery
Research, Development and Demonstration Plan. (Prepared for
U.S. Department of Energy.) Washington, D.C. DOE Contract No.
EM-78-C- 01-4241. October 1979. p. 137.
22. Reference 10, p. 221.
23. Devitt, T., et al. (PEDCo Environmental, Inc.) Population and
Characteristics of Industrial/Commercial Boilers in the U.S. (Prepared
for U.S. Environmental Protection Agency.) Research Triangle
Park, N.C. Publication No. EPA-600/7-79-178a. August 1979. p. 110.
24. Franklin, W.E., et al. Solid Waste Management and the Paper Industry.
(Prepared for the Solid Waste Council of the Paper Industry.)
Washington, D.C., American Paper Institute, 1979. pp. 73-75.
6-29
-------
25. Memo from Barnett, K., Radian Corporation, to file. September 29,
1981. 47 p. Calculation of material and energy balances for non-
fossil fuel fired boilers.
6-30
-------
7. ENVIRONMENTAL AND ENERGY IMPACTS
An analysis of the environmental and energy impacts that result from
applying various emission control technologies to nonfossil fuel fired
boilers (NFFBs) is presented in this chapter. This environmental and energy
impact analysis is based on an evaluation of the model boilers presented in
Chapter 6. The focus of the model boiler impact analysis is to determine
the incremental increase or decrease over the baseline control level, of air
pollution, water pollution, solid waste, and energy impacts for two alterna-
tive control levels. The baseline control level corresponds to no change in
existing regulations and represents the controls required under current
State and NSPS regulations (40 CFR 60 Subparts D and E) as discussed in
Chapter 6. The national impacts of applying these control levels to new
NFFBs were evaluated based on projections of boiler population growth and
are presented in this chapter. Table 7-1 lists the emission limits for the
baseline and alternative control levels which serve as the basis for the
analysis of environmental and energy impacts. The technologies that can be
used to meet these limits are specified in Chapter 6 and described in
Chapter 4.
7.1 AIR POLLUTION IMPACTS
Emissions from NFFBs include particulate matter (PM) and sulfur dioxide
(S02). Particulate matter is the predominant air pollutant from boilers
fired with 100 percent nonfossil fuel. Emissions of S02 are emitted in much
smaller quantities than particulates due to the low sulfur content of
nonfossil fuels. For this reason, the impacts of controlling S02 emissions
from boilers firing 100 percent nonfossil fuel are not considered. However,
S02 emissions are of concern from combination fuel boilers cofiring fossil
and nonfossil fuels. The following analysis deals with PM emissions for
boilers fired with 100 percent nonfossil fuel and with PM and S02 emissions
for boilers cofiring fossil and nonfossil fuels.
7-1
-------
TABLE 7-1. EMISSION LEVELS FOR MODEL BOILERS
Model
Boiler
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
Standard'
Boiler
MW
Fuel3 (106Btu/hr)
Wood
Mood
Mood
Mood
HAB
SLM
75J Hood/b
251 HSE
501 Mood/b
501 HSE
501 Mood/b
502 HSE
501 Wood/b
501 LSW
501 RDF/b
501 HSE
MSH
HSW
MSM
Bagasse
8.8
(30)
22.0
(75)
44. 01
(150)
117
(400)
44.0
(150)
44.0
(150)
44.0
(150)
44.0
(150)
117
(400)
44.0
(150)
44.0
(150)
2.9
(10)
44. 01
(ISO)
117
(400)
58.6
(200)
Uncontrolled Emissions
ng/J (lb/106 Btu)
PM-BMCC
2100
(4.88)
2100
(4.88)
2100
(4.88)
2100
(4.88)
2950
(6.87)
2590
(6.03)
2200
(5.11)
2300
(5.35)
2300
(5.35)
1840
(4.27)
2500
(5.82)
129
(0.30)
1440
(3.36)
1440
(3.36)
2170
(5.05)
PM-AMCC
418
(0.973)
418
(0.973)
418
(0.973)
418
(0.973)
593
(1.38)
899
(2.09)
440
(1.02)
460
(1.07)
460
(1.07)
367
(0.853)
-
-
-
-
-
S02«
-
-
-
-
-
641
(1.49)
1240
(2.89)
1240
(2.89)
275
(0.639)
1350
(3.15)
212
(0.49)
212
(0.49)
212
(0.49)
-
Baseline d
Control Level
ng/J (lb/106 Btu)
PM
258
(0.6)
258
(0.6)
258
(0.6)
258
(0.6)
146
(0.34)
146
(0.34)
138
(0.32)
138
(0.32)
43.0
(0.10)
138
(0.32)
138
(0.32)
129
(0.30)
73.1
(0.17)
73.1
(0.17)
267
(0.62)
SO,
-
-
-
-
-
-
641
(1.49)
1075
(2.50)
516
(1.2)
275
(0.639)
1075
(2.50)
212
(0.49)
212
(0.49)
212
(0.49)
-
Control Level I
ng/J (lb/106 Btu)
PM
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
43.0
(0.10)
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
43.0
(0.10)
43.0
(0.10)
86.0
(0.20)
so2e
-
-
-
-
-
-
194
(0.45)
374
(0.87)
374
(0.87)
81.7
(0.19)
405
(0.94)
212
(0.49)
212
(0.49)
212
(0.49)
-
Control Level II
ng/J (lb/106 Btu)
PM
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
;h
so2f
-
-
-
-
-
-
64.5
(0.15)
125
(0.29)
125
(0.29)
27.5
(0.06)
135
(0.31)
212
(0.49)
212
(0.49)
212
(0.49)
-
See footnotes on second page.
7-2
-------
FOOTNOTES TO TABLE 7-1.
aWood - hog fuel (wood/bark mixture)
HAB - high ash bark
SLW - salt-laden wood
RDF - refuse derived fuel
MSW - municipal solid waste
HSE - high sulfur eastern coal
LSW - low sulfur western coal
Average fuel mixture on a heat input basis.
CBMC - before mechanical collector or any other control equipment.
AMC - after mechanical collector when the mechanical collector is not the final control device.
Both values are included only for cases with fly ash reinjection.
Emission level equivalent to the uncontrolled emission rate, or to the highest emission rate
expected under the current mix of State and Federal Regulations. For model boilers 1-4 the level
also represents emissions after the mechnical collector when the mechanical collector is the final
control device.
eThe emission level shown represents a 70 percent reduction from uncontrolled SOg emissions for the
combination fuel boilers and no control for the others.
The emission level shown represents a 90 percent reduction from uncontrolled S0£ emissions for the
combination fuel boilers and no control for the others.
9SO£ emissions for boilers firing bagasse of 100 percent wood are low and have not been quantified
for this analysis.
A level more stringent than Control Level I was not evaluated.
-------
7.1.1 Primary Air Impacts
7.1.1.1 Model boiler emissions. The annual model boiler emissions for
PM and S02 are presented in Table 7-2. This table presents annual emissions
in megagrams per year (Mg/yr) and tons per year (tons/yr) for uncontrolled
boilers along with emissions for boilers controlled to the Baseline Level
and Control Levels I and II. The table illustrates the relative emission
levels that can be achieved by applying more efficient controls.
The emission reduction impacts of the various control levels are better
shown in Tables 7-3 and 7-4 for each of the model boilers. Table 7-3 shows
the annual emission reductions of PM and S02 for the Baseline Control Level
and Control Levels I and II over the uncontrolled emission level. Table 7-4
shows the incremental annual emission reductions of Control Levels I and II
over the Baseline Control Level. The reductions shown in Table 7-4 are
presented graphically in Figures 7-1 and 7-2.
As shown in Table 7-3 baseline controls have a large impact on annual
PM emissions from most of the model boilers. The amount of emission
reductions for the range of model boiler sizes and fuel types generally
varies from 87.7 to 95.0 percent for the baseline case. The 2.9 MW
MSW-fired boiler does not fall in this range because uncontrolled emissions
for this boiler are below the current mix of regulations which apply to
these boilers. The Baseline Control Level for the 117 MW 50% Wood/50% HSE
fired boiler requires a 98.1 percent reduction in uncontrolled PM emissions.
The baseline emissions for this boiler are significantly lower than for the
other model boilers. This is because fossil fuel and wood residue fired
boilers, which are capable of firing fossil fuel at a heat input rate
greater than 250 million Btu/hr, are already subject to standards of
performance, Fossil-Fuel Fired Steam Generators (40 CFR 60 Subpart D).
The Baseline Control Level does not have as large an impact on S02
emissions for the model boilers. The range of emission reductions varies
from 0 to 58.5 percent for the cofired model boilers. The 117 MW 50 percent
Wood/50 percent HSE fired boiler has a lower baseline emission level than
the other model boilers thus requiring a higher percent reduction in
uncontrolled S02 emissions.
7-4
-------
TABLE 7-2. ANNUAL MODEL BOILER PM AND S09 EMISSIONS'
Model
Boiler
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
Boiler .
Capacity"
HN(106Btu/hr)
8.8
(30)
22.0
(75)
44.0
: (150)
117
(400)
44.0
(ISO)
44.0
(150)
44.0
(150)
44.0
(150)
117
(400)
44.0
(150)
44.0
(ISO)
2.9
(10)
44.0
(150)
117
(400)
58.6
(200)
Fuelc
Hood
Hood
Hood
Hood
HAB
SLW
75S wood/6
251 HSE
SOS wood/6
SOS HSt
SOS wood/6
SOS HSE
SOS wood/6
SOS LSH
SOS RDF/6
SOS HSE
MSH
HSW
HSH
Bagasse
Uncontrolled
Hq/yr(tons/yr)
m3 ay
349
(385)
873
(962)
1745
(1924)
4654
(5130)
2457
(2708)
2156
(2377)
1827
(2014)
1913
(2109)
5102
(5624)
1527
(1683)
2081
(2294)
7.15
(7.88)
1202
(1325)
3204
(3532)
1806
(1991)
aThe capacity factor for bagasse-fired
Based on thermal input
Stood - hog fuel (wood/bark mixture)
HAS high ash bark
SLW salt-laden wood
RDF refuse derived fuel
HSW municipal solid waste
HSE high sulfur eastern coal
LSW low sulfur western coal
•
-
-
-
-
-
533
(587)
1033
(1139)
2756
(3038)
229
(252)
1127
(1242)
11.7
(12.9)
175
(193)
467
(515)
»
boilers is
Baseline
Ha/yr(tqns/yr)
PM S02
42.9
(47.3)
107
(118)
215
(?37)
572
(631)
122
(134)
122
(134)
114
(126)
114
(126)
95.3
(105)
114
(126)
114
(126)
7.15
(7.88)
60.8
(67.0)
162
(179)
221
(244)
0.45 and for
-
-
-
-
-
-
533
(587)
894
(986)
1144
(1261)
229
(252)
894
(986)
11.7
(12.9)
175
(193)
467
(515)
-
all other
Control Level I
Ha/vr(tons/yr)
m so2
10.7
(11.8)
26.9
(29.6)
53.6
(59.1)
143
(158)
53.6
(59.1)
53.6
(59.1)
53.6
(59.1)
53.6
(59.1)
95.3
(105)
53.6
(59.1)
53.6
(59.1)
3.57
(3.94)
35.7
(39.4)
95.3
(105)
71.5
(78.8)
boilers 1s
-
-
-
-
-
-
160
(176)
310
(342)
826
(911)
68.6
(75.6)
338
(373)
11.7
(12.9)
175
(193)
467
(515)
-
0.60.
Control Level II
Hq/yr(tons/yr)
m so2
3.57
(3.94)
8.94
(9.86)
17.9
(19.7)
47.7
(52.6)
17.9
(19.7)
17.9
(19.7)
17.9
(19.7)
17.9
(19.7)
47.7
(52.6)
17.9
(19.7)
17.9
(19.7)
1.19
(1.31)
17.9
(19.7)
47.7
(52.6)
.9
-
-
-
-
-
-
53.3
(58.7)
103
(114)
276
(304)
22.9
(25.2)
113
(124)
11.7
(12.9)
175
(193)
467
(515)
-
For boilers with flyash relnjectlon this value 1s for emissions prior to the mult Icy clone.
6Average fuel mixture on a heat Input basis.
'S0g emissions for boilers firing bagasse or 100 percent wood are low and have not been quantified for this analysis.
^Control level II was not evaluated for bagasse-fired boilers.
7-5
-------
TABLE 7-3. ANNUAL EMISSION REDUCTIONS ACHIEVED BY BASELINE AND CONTROL
LEVELS I AND II OVER UNCONTROLLED EMISSION LEVELS
Baseline Control Level
A H
Cdpidty
HW(106Btu/hr) Fuelb Reduction
8.8 (30)
22.0 (75)
44.0 (150)
117 (400)
44.0 (150)
44.0 (150)
44.0 (150)
44.0 (150)
^j 11? (400)
1
01 44.0 (150)
44.0 (150)
2.9 (10)
44.0 (150)
117 (400)
58.6 (200)
Wood
Wood
Wood
Wood
HAB
SLW
75X Wood/c
25X HSE
SOX Wood/c
SOX HSE
SOX Wood/c
SOX HSE
SOX Wood/c
SOX LSW
SOX RDF/C
SOX HSE
HSW
HSW
HSW
Bagasse
306
766
1530
4082
2335
2034
1713
1799
5007
1413
1967
0
1141
3042
1585
»
Reduction
87.7
87.7
87.7
87.7
95.0
94.3
93.8
94.0
98.1
92.5
94.5
0
94.9
94.9
87.8
soz
Hg/yr Percent
Reduction Reduction
0
0
0
0
0
0
0
139
1612
0
233
0
0
0
0
0
0
0
0
0
0
0
13.5
58.5
0
20.7
0
0
0
0
Control
m
Hg/yr Percent
Reduction Reduction
338
846
1691
4511
2403
2102
1773
1859
5007
1473
2027
3.58
1166
3109
1734
96.9
96.9
96.9
96.9
97.8
97.5
97.0
97.2
98.1
96.5
97.4
50.1
97.0
97.0
96.0
Level I
SO.
Hg/yr Percent
Reduction Reduction
0
0
0
0
0
0
373
723
1930
160
789
0
0
0
0
0
0
0
0
0
0
70.0
70.0
70.0
70.0
70.0
0
0
0
0
Control
m
Hg/yr Percent
Reduction Reduction
345
864
1727
4606
2439
2138
1809
1895
5054
1509
2063
5.96
1184
3156
_d
99.0
99.0
99.0
99.0
99.3
99.2
99.0
99.1
99.1
98.8
99.1
83.4
99.0
99.0
_d
Level II
so2
Hg/yr Percent
Reduction Reduction
0
0
0
0
0
0
480
930
2480
206
1014
0
0
0
0
0
0
0
0
0
0
90.0
90.0
90.0
90.0
90.0
0
0
0
0
'Based on thermal Input
Vod - hog ftiel (wood/bark mixture)
HAB - high ash bark
SLW - salt-laden wood
RDF - refuse derived fuel
HSW - Municipal sol Id Haste
HSE - high sulfur eastern coal
LSW - low sulfur western coal
°Average fuel grixture on a heat Input basis
Control level II was not evaluated for bagasse-fired boilers
-------
TABLE 7-4. INCREMENTAL ANNUAL EMISSION REDUCTIONS ACHIEVED BY
CONTROL LEVELS I AND II OVER BASELINE EMISSION LEVELS
Control Level I
Boiler ,
Capacity
HH(106 Btu/hr)
8.8 (30)
220 (75)
44.0 (150)
117 (400)
44.0 (150)
44.0 (150)
44.0 (150)
44.0 (150)
117 (400)
44.0 (150)
44.0 (150)
2.9 (10)
44.0 (150)
117 (400)
58.6 (200)
Fuelb
Hood
Hood
Hood
Hood
HAB
SLH
75X Hood/0
25X HSE
SOX Hood/0
SOX HSE
SOX Hood/0
SOX HSE
SOX Hood/0
SOX LSW
SOX RDF/C
SOX HSE
HSH
HSH
HSH
Bagasse
PM
Hg/yr
Reduction
32.2
80.1
161.4
429.0
68.4
68.4
60.4
60.4
0
60.4
60.4
3.58
25.1
66.7
149.5
Percent
Reduction
75.0
75.0
75.0
75.0
56.1
56.1
53.0
53.0
0
53.0
53.0
50.1
41.2
41.2
67.6
so2
Hg/yr
Reduction
0
0
0
0
0
0
373.0
584.0
318.0
160.4
556.0
0
0
0
0
Percent
Reduction
0
0
0
0
0
0
70.0
65.3
27.8
70.0
62.2
0
0
0
0
PH
Hg/yr
Reduction
39.3
98.1
197.1
524.3
104.1
104.1
96.1
96.1
47.6
96.1
96.1
5.96
42.9
114.3
_d
Control Level II
Percent
Reduction
91.7
91.7
91.7
91.7
85.3
85.3
84.3
84.3
49.9
84.3
84.3
83.4
70.6
70.6
_d
Hg/yr
Reduction
0
0
0
0
0
0
479.7
791.0
868.0
206.1
781.0
0
0
0
0
soz
Percent
Reduction
0
0
0
0
0
0
90.0
88.5
75.9
90.0
87.4
0
0
0
0
*Based on thermal Input
Ttood - hog fuel (wood/bark mixture)
HAB - high ash bark
SLH - salt-laden wood
RDF - refuse derived fuel
HSH - municipal solid waste
HSE - high sulfur eastern coal
LSH - low sulfur western coal
°Average fuel mixture on a heat Input basis.
^Control level II was not evaluated for bagasse-fired boilers.
-------
I
00
500
450
400
£ 350
"a!
m
fc 3°0
O
*5 250
o
01
a
200
150
100
50
MW
(106Btu/hr)
Fuel Type
Control Level II
Control Level I
n
n
8.8
(30)
Wood
22.0 44.0 117 44.0 44.0
- n
44.0 44.0 2.9 44.0 117
(75)
Hood
44.0 44.0
(150) (400) (150) (150) (150) (150) (400) (150) (150) (10)
Wood Wood HAB SLW 755Mood 50%Wood SOXWood SOXHood 50XRDF HSW
252HSE 50JHSE 50XHSE 50S.SW 50ZHSE
58.6
(150) (400) (200)
HSW HSH Bagasse
Figure 7-1.
Incremental Annual PM Emission Reductions Achieved by Control Levels I
and II Over Baseline Emission Levels.
-------
S
I
g
900
800
700
600
500
400
I
M
| 3°°
200
100
Mi
(106Btu/hr)
Fuel Type
Control Level Il
Control Level I
8.8 22.0 44.0 117 44.0 44.0 44.0 44.0 117 44.0 44.0 2.9 44.0
(30) (75) (150) (400) (150) (150) (150) (150) (400) (150) (150) (10) (150)
Hood Wood Hood Mood HAB SLU 75»ood SOMood SOXUood SOlHood 50SRDF HSW HSH
25JHSE 50XHSE 50JHSE 50SLSW 50SHSE
117 58.6
(200)
Bagasse
(400)
HSW
Figure 7-2. Incremental Annual SOp Emission Reductions
Achieved By Control Levels I and II Over
Baseline Emission Levels
7-9
-------
The incremental PM emission reductions achieved at Control Levels I and
II over the Baseline Control Level are presented in Table 7-4. These
reductions are .shown graphically in Figure 7-1. The 117 MW
(400 x 10 Btu/hr) wood/HSE boiler shows no reduction for Control Level I
because the Baseline Control Level for this boiler is as stringent as
Control Level I. The lower baseline emission level for this boiler also
results in the lower 49.9 percent reduction requirement for Control Level II
over baseline. The rest of the model boilers show a range of 41.2 to 75.0
percent reduction at Control Level I and a range of 70.6 to 91.7 percent
reduction at Control Level II.
Table 7-4 and Figure 7-2 show the incremental S02 emission reductions
achieved at Control Levels I and II over the baseline controls for the model
boilers cofiring coal (HSE or LSW) with nonfossil fuel. S02 Control Levels
I and II for the cofiring cases are based on 70 percent and 90 percent
reductions in uncontrolled S02 emissions respectively. The 117 MW wood/HSE
boiler shows only a 27.8 percent incremental reduction at Control Level I
and a 75.9 percent incremental reduction at Control Level II because the
Baseline Control Level for this boiler already requires substantial S02
emission reductions. Reductions over the Baseline Control Level for the
other cofired cases range from 62.2 to 70.0 percent for Control Level I and
from 87.4 to 90.0 percent for Control Level II.
The nationwide impact on air pollution for applying PM Control Levels I
and II to new NFFBs is shown in Table 7-5 and presented graphically in
Figure 7-3. Nationwide annual emissions were calculated based on projected
capacity growth of NFFBs in each fuel category. These projections were used
to calculate the total capacity in 1990 of NFFBs affected by potential New
Source Performance Standards. The size distribution of these boilers was
determined from American Boiler Manufacturers Association (ABMA) sales data
from 1970 to 1978 for wood- and bagasse-fired boilers, and from projections
of plant capacities for MSW- and RDF-fired boilers. The total capacity and
size distributions were then used, along with model boiler emission rates
and capacity factors to calculate the total annual particulate emission rate
from affected NFFBs nationwide. The results are shown for each control
7-10
-------
TABLE 7-5. NATIONAL PM EMISSIONS FROM NFFBs AFFECTED BY
POTENTIAL NSPS IN 1990
Ye»r
1990
Fuelc
Uoo4d
MSk*
Total Installed*
Heat Input Capacity
Qf(109Btu/hr)
13.7
(46.6)
2.54
(8.68)
MSW. ISHf 1.22
(4.16)
RDF"
Bagasse
Total
2.69
(9.17)
2.79
(9.52)
22.9
(78.1)
Baseline Annual*
Emissions
6g/yr(103ton/yr)
36.7
(40.4)
3.52
(3.88)
2.98
(3.28)
3.72
(4.10)
10.5
(11.6)
57.4
(63.3)
Control
Annual Emissions
Gg/yr(103ton/yr)
16.7
(18.4)
2.07
(2.28)
1.49
(1.64)
2.19
(2.41)
3.40
(3.75)
25.9
(28.5)
Level I*
Percent Reduction
Over Baseline
54.5
41.2
50.0
41.2
67.7
55.0
Control Level
Annual Emissions
Gg/yr(103ton/yr)
5.5S
(6.12)
1.03
(1.14)
0.495
(0.546)
1.09
(1.20)
_h
8.17
(9.01)
II*
Percent Reduction
OVer Baseline
84.8
70.7
83.4
70.7
-
82.6
'Annual PM emissions are based on the maximum hourly boiler emission rates, annual capacity factors, and the total NFFB population affected by
potential New Source Performance Standards 1n 1990.
blncludes only NFFBs affected by potential New Source Performance Standards. Shown here is the projected NFFB caoaclty Installed In 1984
through 1990.
cUood - all types of wood fuels
HSU - municipal solid waste
RDF - refuse derived fuel
ISU - Industrial solid waste
The Man ash bark and salt-laden wood fuels were evaluated as model boiler cases to determine the sensitivity of emission control costs for
wood-fired boilers to the ash and salt contents of wood fuels. For calculatlna the national environmental Inoacts of wood-fired boilers
the wood fuel cateoory Is used to represent boilers burning all types of wood fuels.
Includes all HSH-flred hollers exceot small modular units.
Includes only small modular MSH-flred and ISW-fired boilers.
^Based on RDF supplying 100 percent of the boiler heat input. For boilers firing 100 percent RDF the baseline control level and Control
Level I are the saws as the levels for a similar size MSW-flred boiler.
A second control level was not evaluated for bagasse-fired boilers.
Vor calculating national Impacts, the Baseline Control Level Is the average of State regulations shown in Chapter 3.
-------
50
30
t9 4
l
3 20
c
o
I/)
to
•r—
E 15
c
10
5
Type
r
I— . Basel ine Control
>
-
.
-
^
§i
So5
w\
rW
88^
5o6
88S
88?
88?
88?
88?
88?
88?
88?
88?
88?
H
^
8»
__. Control Level I
&2 Control Level II
§~—
Wood MSWa MSW,ISWb RDF Bagasse
1990
alncludes all MSW-f1red boilers except small modular units.
blncludes only small modular MSW- and ISW-fired boilers.
Fiqure 7-3. National PM emissions from NFFBs affected
bv potential NSPS in 1990.
7-12
-------
level as total annual emissions and the percent reduction of these emissions
over baseline. The baseline control level used for wood to calculate
nationwide impacts for wood-fired boilers is the average of existing State
regulations shown in Chapter 3. This average level was used because it
would more accurately represent the nationwide emissions than the 258 ng/J
(0.6 lb/106 Btu) Baseline Control Level used to calculate individual model
boiler impacts.
The boiler capacity projections are based simply on projections of the
future use of nonfossil fuels. Sufficient data were not available to
distinguish on a nationwide basis between the proportion of nonfossil fuel
fired alone and that fired in combination with fossil fuel. Therefore, this
analysis only includes the impacts of controlling emissions of particulate
from the firing of nonfossil fuels. Since the future population of combina-
tion fuel boilers is not known, no national impacts for controlling S02 were
estimated.
In this analysis, the wood fuel category was used to represent all
types of wood fuels including high ash bark and salt-laden wood. The latter
two fuels were Only used as model boiler fuels to show the sensitivity of
emission control costs to the ash and salt content of wood fuels. The
inclusion of these fuels does not complicate the national emission impact
analysis since the same control levels were evaluated for each of these
fuels. Control Level I would reduce annual PM emissions from all nonfossil
o
fuel fired boilers by 31.5 Gg/yr (34.7 x 10 tons/yr) below the Baseline
Control Level by 1990. Control Level II would reduce the same annual PM
emissions by 49.2 Gg/yr (54.2 x 10 tons/yr).
7.1.1.2 Dispersion Analysis. A dispersion analysis was performed to
determine the ambient air impacts of the baseline and two alternate control
levels on the model boilers. The dispersion analysis used the single source
(CRSTER) model, which has generally been shown to be accurate within a
2
factor of 2, for both urban and rural plants. All model boilers were
considered to be single point sources. The stack parameters for the model
boilers used in the dispersion analysis are shown in Table 7-6. Model
boilers 11, 12, 13, and 14 were analyzed assuming they were located in urban
7-13
-------
TABLE 7-6. MODEL BOILER STACK PARAMETERS
Model Control $tack
Number (thermal Input) Fuel3 m S0? m
la 8.8 MW Hood B B 15.2
£ (30 x 106Btu/hr) ,{ " }|;|
Id II B 15.2
le II B 15.2
2a 22.0HH Hood B B 24.4
H (75 x 106Btu/hr) ,| B |};J
2d II B 24^4
2e II B 24.4
2f II B 24.4
Stack Parameters Emissions From Stack0
t Flow Rate Temp (W S02
(ft) m3/s (acfm) °C(°F) kg/hr (Ib/hr) kg/hr (Ib/hr)
(50
(50
50
(50
6.23 (13,200) 162.8 (325) 8.16 (18.00)
5.24 (11,100) 65.6 (ISO) 2.04
5.24 (11,100) 65.6 (ISO) 0.680
6.23 (13*200) 162.8 (325) 0.680
(50) 6.23 (13,200) 162.8 (325) 0.680
(80) 15.6 (
80
(80
80
(80
(80
3a 44.0HU Hood B B 38.1 (125
3bc (150 x 106Btu/hr) ,j | »;}
3d II 8 38.1
3e II B 38.1
3f II B 38.1
125
125
125
125
13.2
13.2
15.6
15.6
15.6
31.2 I
26.3
26.3
31.2
31.2 1
125) 31.2
4a 117 HW Wood B B 76.2 (250
4b /400 in^Btu/hrl ' 8 ^'2 '2'"
4c l*°° * l° Btu'nr» n B 76.2
4d II B 76.?
4e II B 76.2
4f II B 76.2
250
250
250
250
4.50
1.50
1.50
1.50
33,100) 162.8 (325) 20.41 (45.00
27.900
27.900
33.100
33,100
33,100
66.100
55.700
55.700
66.100
66,100
66.100
83.2 (176.200
70.1 (148.500
70.1 (1
48.500
83.2 (176.200
83.2 (1
76.200
65.5 (150
65.6 (150
162.8 (325
162.8 (325
162.8 (325
5.10 (11.25
1.70 (3.75
1.70 (3.75
1.70 (3.75
1.70 (3.75
-
-
** ~
_
_ _
-
) 162.8 (325) 40.82 (90.00)
65.5 (ISO
65.6 (ISO
162.8 (325
162.8 (325
162.8 (325
10.21 (22.50
3.40 (7.50
3.40
3.40
3.40
7.50
7.50
7.50
162.8 (325) 108.86(240.0)
65.6 (150
65.6 (150
162.8 (325
162.8 (325
27.22 (6
9.07 (2
9.07 (2
9.07 (2
0.0
0.0
0.0
0.0
83.2 (176,200) 162.8 (325) 9.07 (20.0
5a 44.0 MH HAB B B 38.1 (125) 26.3
5» /iw . in6Rt,,/h,.\ * B 38-1 I125 26-3
5c t150 x 10 Btu'np' II B 38.1 (125) 31.2
55.700) 65.6 (150
55,700 65.6 (ISO
66.100) 162.8 (325
6a 44.0 MH SLW B B 38.1 (125) 26.3 (55.700
6b M,n „ I06ntll/ll_, I B 38.1 125) 26.3 (55.700
6c (150 x 10 Btu/hr) ,, B 38.1(125) 31.2 (66.100
7a 44.0 HW 75X Hood/d B B 61.0
£ (150 x 106Btu/nr) **HSE I B 61.0
7d II B 6l!o
7e II B 61.0
200
200
200
200
200
7f II I 61.0 (200
7g II II 61.0 (200
25.4
25.4
25.4
30.4
30.4
26.3
25.4
23.13 (51.00
10.21 (2
2.50
3.40 (7.50
65.6 (150) 23.13 (51.00
65.6 (ISO) 10.21 (22.50
162.8 (325) 3.40 (7.50
(53.900) 62.8 (145
53.900) 62.8 (145
53,900) 62.8 (145
64.400
64.400
55.800
53,900
162.8 (325
162.8 (325
79.4 (175
62.8 (145
21.77 (48.00
10.21 (22.50
10.21 (22.50
3.40
3.40
3.40
3.40
7.50
7.50
7.50
7.50
1
-
-
'
_
-
-
-
-
"
.
-
~ ~
-
I 101.6 (224)
101.6 (224)
30.5 (67.2)
101.6 (224)
101.6 (224)
30.5 (67.2)
10.2 (22.4)
See footnotes at end of table.
-------
TABLE 7-6. (CONTINUED)
r
i-«
01
Model * _„_< Stacl
Number (thermal Input) Fuel3 FH S02 m
Ba 44.0 HH SOX Hood/d B B 61.0
* (150 x 10« Btu/nr) 5« HSE { » «;«
8d I II 61.0
Be II B 61.0
8f II I 61.0
8g II II 61.0
9a 117 HH SOXHood/d B B 91.4
9b mt\n w ifWDt»/l*.«l !>U% Hot 1 I y 1."
q (400 X 10 Btu/nr/ I, 1 01 4
t
(ft
200
200
200
200
200
200
200
Stack Parameters
Emissions Fran Stack0
now Rate Temp m S02
) m3/s (acfm) °C(°F) kg/hr (Ib/hr) kg/hr (Ib/hr)
24.6 (52,100
24.6
24.6
24.6
29.6
25.7
52.100
52.100
52,100
62.700
54,400
24.6 (52,100
300) 65.6 (]
300) 65.6 11
300) 68. 5 11
9d II II 9lU (300) 65.6 (1
lOa 44.0 HH SOX Hood/d B 8 61.0
{I* (150 x loWnr) 5MLSH { B «};°
200
200
200
lOd I II 6LO (200
10e II B 61.0 (200
lOf II B 61.0 (200
25.0
25.0
25.0
25.0
30.0
30.0
10g II I 61.0 (200) 26.2
10h II II 61.0 (200) 25.0
Ua 44.0 HH SOX RDF/d B B 61.0 (200
Hb ,,-n _ in6R»../h..1 5M HSE ' ' 61-°
He (150 x 10 Btu/hr) , ,, 6, „
lid II I 61.0
He II II 61.0
12a 2.9 HH HSH B B 12.2
12b 6 IB 12.2
12c (1° x Btu/ r) II B 12.2
200
200
200
200
(40
40
40
13a 44.0HH HSH B B 38.1 (125
"c (150x lo6Btu/hr) II B 38:1 (125
23.8
23.8
23.6
23.8
23.8
2.59
2.10
2.59
38.9
38.9
39.000
39.000
45.000
60.0
60.0
60.0
60.0
157.2
79.4
140
140
140
140
315
175
21.77 (48.00
10.21 (22.50
10.21 (22.50
10.21 (22.50
3.40 (7.50
3.40 (7.50
170.1 (375)
170.1 (375)
59.4 (131)
19.7 (43.
5)
170.1 (375)
59.4 (131
60.0 (140) 3.40 (7.50) 19.7 (43.
60
60
79.4
39.000) 60
53.000
53,000
53,000
53.000
63,500
63,500
55,600
53,000
50,400
50,400
50,400
50,400
50,400
5.480
4.460
5,480
60
60
60
140
140
175
140
140
140
140
60 (140
162.8
162.8
79.4
60
57.2
57.2
57.2
57.2
57.2
|325
325
175
18.14 (40.00
18.14 (40.00
9.07 (20.00
9.07 (20.00
21.77 (48.00
10.21 (22.50
10.21 (22.50
10.21 (22.50
3.40 (7.50
3.40 (7.50
3.40 (7.50
140) 3.40 (7.50
135
135
135
135
135
21.77 (48.00
10.21 (22.50
10.21 (22.50
3.40 (7.50
3.40 (7.50
176.7 (350) 1.36 (3.00
60.0 (140) 0.680 (1.50
176.7 (350) 0.227 (0.50
S2.400 176.7
2,400) 176.7
38.9 (82.400) 176.7
217.7 (480
157.9 (348
157.9 (348!
52.6 (116
5)
43.5 (95.8)
43.5 (95.8)
13.0 (28.7)
4.35 (9
43.5 (95
43.5 (95
58)
8)
8
13.0 (28.7)
4.35 (9
58)
170.1 (375)
63.5 (140)
21.2 (46.7)
63.5 (140)
21.2 (46
2.23 (4
2.23 (4
2.23 (4
350) 11.57 (25.50) 33.5 (73
350) 6.80 (15.00) 33.5 (73
350) 3.40 (7.50) 33.5 (73
14a 117 HH HSH B B 76.2(250) 103.5 (219,400) 176.7(350) 30.84(68.00) 89.4(197
14b ,.„„ , ,06Rtll/hp, I B 76.2 (250) 103.5 (219,400) 176.7 (350) 18.14 (40.00) 89.4 (197
14c (400 x 10 Btu/hrj ,, 8 76.2(250) 103.5 (219.400) 176.7(350) 9.07(20.00) 89.4(197
15a 58.6 HH Bagasse B B 38.1 (125 44.3 (93,800) 176 (350) 56.25(124.00
15b (200 x 106Btu/hr) ' B 38.1(125) 37.4 (79.200) 68.3(155) 18.14(40.00
.
•* "*
7)
92)
92)
92J
9)
9)
9)
See footnotes at end of table.
-------
Footnotes to Table 7-6:
aNood - hog fuel (wood/bark mixture)
HAD - high ash hart
SLW - salt-laden wood
HSE - high sulfur eastern coal
LSW - low sulfur western coal
RDF - refuse derived fuel
HSU - municipal sol Id waste
B refers to Ba'sel Ine Control Level.
I refers to Control Level I.
II refers to Control Level II.
GBased on emission levels specified In Table 7-1.
Average fuel mixture on a heat Input basis.
en
-------
areas whereas model plants 1 through 10 and 15 were assumed to be located in
rural areas.
In this model 360 receptors were used to determine the downwind concen-
tration of emissions. Ten receptors each were placed every 10 degrees
around the emission point. The receptors on each radial were placed at
varying distances from the emission source with three of the ten receptors
located at 0.1, 1.0, and 10.0 km. The concentration at each receptor was
calculated to determine the point of maximum concentration. Meteorological
data for Baton Rouge, Louisiana, were used in this analysis. Because this
dispersion analysis is based on meteorological data from one area it will
not necessarily reflect the pollutant concentrations to be expected in all
areas where NFFBs may be installed. However, this analysis is useful for
showing relative impacts of alternative control levels.
For particulate matter the averaging times used were annual and 24-
hours. For annual averages the highest concentrations at any receptor were
determined. This is the "max mean concentration". For 24-hour averages the
highest second-highest concentrations were determined. The "second max
concentration" is derived by determining the second highest concentration at
each receptor and selecting the highest of these second highest concentra-
tions. In addition, the highest concentrations in any direction at 0.1,
1.0, and 10.0 km for annual averages and highest second-highest concentra-
tions for 24-hour averages were determined. All averages are arithmetic
means. The geometric mean concentrations can be assumed to be similar to
the arithmetic mean. Sulfur dioxide concentrations are determined by the
same method as PM concentrations except that the S02 analysis also used a
3-hour averaging time. The emission limits for model boilers la-4a and
13b-14b shown are not the same as the emission limits used in the dispersion
analysis. Therefore, the ambient concentrations in the dispersion analysis
were changed to correspond to the emission rates shown in Table 7-6.
Table 7-7 presents the annual maximum mean and the "second max concen-
tration" for each model boiler for the different control levels and the
distance downwind that they occur. The predicted concentrations are the
7-17
-------
TABLE 7-7. DISPERSION MODELING RESULTS
-4
I
00
Aoblent Concentration of Pollutant
Hodel
Boiler
Ho.
la
Ib
1C
Id
le
2a
a>
2c
2d
2e
2f
3a
3>
3c
3d
3e
3f
Control Lever-
Emission Control
Fuel*
Hood
Hood
Hood
Hood
Hood
Hood
Hood
Hood
Hood
Hood
Hood
Hood
Hood
Hood
Hood
Hood
Hood
Pollutant
PH
soz
PH
so2
PH
so2
PH
so2
PH
so2
PM
so2
PM
soz
PH
so2
PH
soz
PM
soz
PH
so2
PH
so2
PH
so2
PH
so2
PH
soz
PH
so2
PH
soz
System0
B
B
I
B
II
B
II
B
II
B
8
B
I
B
II
B
II
8
II
B
II
B
B
B
I
B
II
B
II
B
II
B
II
B
.
-
.
-
.
-
_
-
.
-
_
-
.
-
.
-
_
-
.
-
.
-
.
-
_
-
.
-
.
-
-
-
_
~
MC
None
MC.MS
Hone
HC.HS
Hone
HC.FF
None
HC.ESP
None
MC
None
MC.MS
None
HC.HS
None
HC.FF
None
HC.ESP
None
HC.EGB
None
HC
None
HC.MS
None
MC.MS
None
HC.FF
None
HC.ESP
None
HC.E68
None
Annual Maximum Mean/
Distance Downwind
M9/»3
1.6R
-
0.96
-
0.32
' -
0.14
i -
0.14
-
0.96
0.52
-
0.17
-
0.08
-
0.08
-
0.08
0.72
0.45
1 -
0.15
• -
0.06
i -
0.06
1 "
0.06
— t —
km
0.6
-
0.4
-
0.4
-
0.6
-
0.6
-
1.0
0.8
-
0.8
-
1.0
-
1.0
-
1.0
-
1.8
1.0
-
1.0
-
1.8
"
1.8
~
1.8
"
2nd Highest Haxinun/Ootmwind Distance
24 Hour Average
M9/n3
17.0
8.72
-
2.91
-
1.42
-
1.42
-
9.48
4.67
-
1.56
-
0.79
-
0.79
-
0.79
-
7.32
4.20
-
1.40
-
0.61
•
0.61
"
0.61
"
kn
0.5
0.4
-
0.4
-
0.5
•
0.5
•
1.0
0.8
-
0.8
-
1.0
•
1.0
-
1.0
-
1.8
1.2
-
1.2
-
1.8
~
1.8
"•
i.a
'
3 Hour Average
pg/rt3 km
.,
*
_
-
_
-
_
- ~
.
" -
.
-
-
—
-
_
-
.
-
_
-
_
-
_
-
_
-
.
•• **
-
_ —
.
See footnotes at end of table.
-------
TABLE 7-7. (CONTINUED)
t—•
10
Art) lent Concentration of Pollutant
Hodel
Boiler
No.
4a
4>
4c
4d
4e
4f
Sa
3>
5c
6a
6b
6c
7a
7b
7c
7d
Fuel"
Hood
Hood
Hood
Hood
Hood
Hood
HAB
HAB
HAB
SLH
SLH
SLH
75t Hood/1
25* HSE
75* Hood/1
25* HSE
75* Hood/1
25* HSE
75* Hood
25* HSE
Pollutant
PH
so2
PH
so2
PH
soz
PH
so2
PM
so2
PH
so2
PH
so2
PH
soz
PH
soz
PH
soz
PH
so2
PN
soz
PH
soz
PH
soz
PH
soz
PH
soz -
Control Level -
Emission Control
System0
B - HC
B - None
I - HC.HS
B - None
II - HC.HS
B - None
II - HC.FF
B - None
II - HC.ESP
B - None
II - HC.EGB
B - None
B - HC.HS
B - None
I - MC.HS
B - None
II - HC.FF
B - None
B - HC.HS
B - None
I - HC.HS
B - None
II - MC.FF
B - None
B - HC.HS
B - None
I - HC.HS
B - None
I - HC.HS
I - FGD
II - HC.ESP
B - None
Annual Haxlnum Mean/
Distance Downwind
pg/rn3 km
0.36 4.5
•1* —
0.19 2.5
-
0.06 2.5
-
0.03 4.2
-
0.03 4.5
-
0.03 4.2
-
1.03 1.0
f —
0.45 1.0
-
0.06 1.8
*
1.03 1.0
-
0.45 1.0
*• -
0.06 1.8
-
0.42 1.8
1.96 1.8
0.20 1.8
1.96 1.8
0.20 1.8
0.59 1.8
0.03 2.0
0.97 2.0
2nd Highest HaxInum/DoMiwtnd Distance
24 Hour
4.32
-
2.58
-
0.86
-
0.36
-
0.36
-
0.36
-
9.53
-
4.20
-
0.61
-
9.53
-
4.20
~
0.61
-
4.98
23.2
2.33
23.2
2.33
6.98
0.34
10.1
Average
km
1.5
1.1
-
1.1
-
1.5
-
1.5
-
1.5
-
1.2
-
1.2
-
1.8
-
1.2
-
1.2
-
1.8
-
0.6
0.6
0.6
0.6
0.6
0.6
0.9
0.9
3 Hour Average
wg/»3 km
.
-
_
-
.
-
„
-
„
-
_
-
_
-
_
-
_
-
.
-
.
~
_
-
..
107 0.5
_
107 0.5
_
32.2 0.5
-
51.1 0.6
-------
TABLE 7-7. (CONTINUED)
T4
ro
o
Ambient Concentration of Pollutant
Model
Boiler
No.
7e
7f
?9
8a
a>
8c
8d
8e
8f
8g
9a
9b
9c
9d
lOa
lOb
Fuel3
75X Hood/d
25X HSE
75X Hood/d
25X HSE
75X Hood
25X HSE
SOX Hood/d
SOX HSE
SOX Hood/1
SOX HSE
SOX Hood/d
SOX HSE
SOX Hood/d
SOX HSE
SOX Hood/d
SOX HSE
SOX Hood/d
SOX HSE
SOX Hood/d '
SOX HSE
SOX Hood/d
. SOX HSE
SOX Hood/1
SOX HSE
SOX Hood/1
SOX HSE
SOX Hood
SOX HSE
SOX Hood/d
SOX LSH
SOX Hood/1
SOX LSH
Pollutant
PM
so2
PH
so2
PH
so2
PM
so2
PH
so2
PH
so2
PH
SO,
PM
so2
PH
soz
PH
so2
PH
so2
PH
so2
PH
so2
PH
so2
PH
so2
PM"
so2
Control Level -
Emission Control
System0
II
B
II
I
II
II
B
B
I
B
I
I
I
II
II
B
II
I
II
II
B
B
I
B
II
I
II
II
B
B
I
B
- HC.FF
- None
- HC.FF
- FGD-DS
- HC.ESP
- F6D-WS
- HC \
- FGD ) K
~* "^ I UC
- FGD J HS
•* Hi* 1 tip
- FGD|MS
- HC » u<:
- FGDJHS
- MC.FF
- FGD-DS6
- HC.FF
. FGD-DS
- HC.ESP
- FGD-HS
- HC ly-
- F6DI
- HC jus
- FGDl"5
- HC.FF
- FGD-DS
- HC.ESP
- FGD.HS
- HC.HS
- None
- HC.HS
- None
Annual Maximum Mean/
Distance Downwind
09/in km
0.03
0.97
0.06
0.50
0.07
0.20
0.44
3.46
0.21
3.46
0.21
1.21
0.21
0.40
0.03
1.73
0.03
1.73
0.07
0.40
0.90
1.12
0.09
0.81
0.04
0.70
0.05
0.27
0.43
0.87
0.20
0.87
2.0
2.0
1.6
1.6
1.8 ,
1.8
1.6
1.6
1.6
1.6
1.6
1.6
1.6
1.6
2.4
2.4
2.4
2.4
1.6
1.6
2.3
2.3
2.3
2.3
4.0
4.0
2.3
2.3
1.4
1.4
1.4
1.4
2nd Highest Maximum/Downwind Distance
24 Hour
ug/n
0.34
10.1
0.64
5.70
0.78
2.33
5.25
41.0
2.46
41.0
2.46
14.3
2.46
4.75
0.35
17.5
0.35
17.5
0.82
4.75
1.62
19.4
1.62
14.1
0.58
10.2
0.81
4.69
5.24
10.5
2.46
10.5
Average
km
0.9
0.9
0.8
0.8
0.6
0.6
0.7
0.7
0.7
0.7
0.7
0.7
0.7
0.7
0.9
0.9
0.9
0.9
0.7
0.7
1.0
1.0
1.0
1.0
1.3
1.3
1.0
1.0
0.6
0.6
0.6
0.6
3 Hour
ng/rn3
.
51.1
26.0
..
10.8
_
186
-
186
65.0
_
21.6
89.2
_
89.2
_
21.6
_
91.2
66.1
51.5
-
22.0
47.4
..
47.4
Average
km
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
6
5
5
5
5
5
5
6
6
5
7
7
7
7
5
5
-------
TABLE 7-7. (CONTINUED)
ro
Ambient Concentration of Pollutant
Hodel
Boiler
No.
lOc
lOd
lOe
lOf
lOg
IDh
lla
lib
lie
lid
lie
12a
12b
12c
13a
13b
13c
Fuel*
SOS Hood/1
SOS LSW
SOS Hood/1
SOS LSW
SOS Hood/1
SOS LSW
SOS Wood/d
SOS LSW
SOS Mood/1
SOS LSM
SOS Hood/1
SOS LSW
SOS RDF/d
SOS HSE
SOS RDF/1
SOS HSE
SOS RDF/d
SOS HSE
SOS RDF/d
SOS HSE
SOS RDF/1
SOS HSE
HSW
HSW
HSW
HSW
HSW
HSW
Pollutant
PH
so2
PH
so2
PH
so2
PH
so2
PH
so2
PH
so2
PH
so2
PH
so2
PH
so2
PH
soz
PM
so2
PH
so2
PH
so2
PH
so2
PH
so2
•PH
so2
PH
so2
Control Level -
Emission Control
System6
1
I
I
II
II
B
II
B
II
1
II
II
8
B
I
I
I
II
II
I
II
II
B
B
I
B
II
B
B
B
' I
B
II
B
I reo !MS
- "C tuc
- FGD j"5
- HC.FF
- None
- HC.ESP
- None
- HC.FF
- FGD-DS
- HC.ESP
- FGD-US
- FGDJ"5
»
- FGD}
I FGD }"S
- ESP
- FGD-HS
- ESP
- FGD-WS
- None
- None
- WS
- None
- FF
- None
- ESP
- None
- ESP
- None
- ESP
- None
Annual Haxlaun Hean/
Distance Downwlrid
ug/m3 km
0.20
0.26
0.20
0.09
0.03
0.42
0.03
0.42
0.05
0.21
0.07
0.09
0.63
4.89
0.29
1.82
0.29
0.61
0.10
1.82
0.10
0.61
0.09
1.54
1.06
3.47
0.15
1.54
0.18
0.52
0.11
0.52
0.05
0.52
1.4
1.4
1.4
1.4
2.0
2.0
2.0
2.0
1.5
1.5
1.4
1.4
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
0.4
0.4
0.3
0.3
0.4
0.4
2.4
2.4
2.4
2.4
2.4
2.4
2nd Highest HaxInw/DoMWtnd Distance
24 Hour
pg/i»3
2.46
3.13
2.46
1.05
0.34
4.35
0.34
4.35
0.64
2.43
0.82
1.05
5.48
42.8
2.57
16.0
2.57
5.34
0.86
16.0
0.86
5.34
7.61
12.5
7.06
23.1
1.23
12.5
1.90
S.50
1.12
5.50
0.56
5.50
Average
kn
0.6
0.6
0.6
0.6
0.9
0.9
0.9
0.9
0.8
0.8
0.6
0.6
0.7
0.7
0.7
0.7
0.7
0.7
0.7
0.7
0.7
0.7
0.3
0.3
0.3
0.3
0.3
0.3
2.2
2.2
2.2
2.2
2.2
2.2
3 Hour
ug/m3
14*2
.
4.74
..
22.1
.
22.1
..
11.1
4.74
192
71.7
23.9
71.7
23.9
.
29.3
75.6
.
29.3
.
18.9
„
18.9
..
18.9
Average
kn
0.5
0.5
0.6
0.6
0.5
0.5
0.5
0.5
0.5
0.5
O.S
0.2
0.5
0.2
0.8
0.8
0.8
-------
TABLE 7-7. (CONTINUED)
Ambient Concentration of Pollutant
ro
ro
Model
Boiler
No.
14a
14b
14c
15a
15b
Fuel8
HSU
HSH
HSH
Bagasse
Bagasse
Pollutant
PH
so2
m
so2
PH
so2
PH
so2
PH
so2
Control Level -
Emission Control
System0
B
B
I
B
II
B
B
B
I
B
- ESP
- None
- ESP
- None
- ESP
- None
- HC
- None
- US
- None
Annual Maximum Mean/
Distance Downwind
ug/n3
0.09
0.27
0.05
0.27
0.03
0.27
0.65
"
0.59
"
5.
5.
5.
5.
5.
5.
2.
1.
0
0
0
0
0
0
4
3
2nd Highest Maximum/Downwind Distance
24 Hour
ug/n3
1.05
3.02
0.61
3.02
0.31
3.02
6.80
5.78
Average
km
1.6
1.6
1.6
1.6
1.6
1.6
1.7
1.3
3 Hour Average
wg/rn km
..
15.0 1.4
_
15.0 1.4
_
15.0 1.4
.
"
.
-
aUood - hog fuel (wood/bark mixture)
HAB - high ash bark
SLU - salt-laden wood
HSE - high sulfur eastern coal
ISM - low sulfur western coal
RDF - refuse derived fuel
HSW - municipal solid waste
bB refers to Baseline Control Level.
1 refers to Control Level I.
II refers to Control Level II.
CHC - nutlcyclone
US - wet scrubber
FF - fabric filter
ESP - electrostatic precipltator
EG8 - electrostatic gravel bed filter
FGD-HS - flue gas desulfurlzatlon; double alkali or lime wet scrubber
F6D-DS - flue gas desulfurlzatlon; lime dry scrubber
Control systems separated by a coma mean that both are used at the same time, not that either may be used Independently. Mechanical collectors are
Included for fly ash relnjectlon on all of the boilers firing wood.
dAverage fuel mixture on a heat Input basis.
eThe dry scrubber Is sized to scrub only a portion of the flue gas.
-------
concentrations which would occur in a pristine atmosphere and represent
increases in ambient concentrations over background levels.
The primary national ambient air quality standards for particulate
3 3
matter are 75 yg/m for the annual geometric mean and 260 vg/m for the
3
maximum 24-hour concentration. The secondary standards are 60 yg/m for the
2
annual geometric mean and 150 yg/m for the maximum 24-hour concentration.
The annual mean cannot be exceeded, and the 24-hour average cannot be
exceeded more than once a year.
The particulate matter annual maximum arithmetic mean concentration
from the dispersion analysis ranged from 0.03 to 1.68 yg/m . Since the
secondary standard stipulates the 24 hour maximum can be exceeded once a
year, the dispersion analysis was used to determine the second highest
24-hour concentration to compare to the secondary standard. The second
highest maximum 24 hour concentration of particulates ranged from 0.34 to
17.0 yg/m3.
For particulate matter the annual maximum arithmetic mean ranges from
o 3
0.09 to 1.68 yg/m for Baseline Controls, 0.05 to 1.06 yg/m for Control
Level I, and 0.03 to 0.32 yg/m for Control Level II. These data show the
ambient air benefits achieved by the addition of more efficient controls.
Since S0« control levels are only being evaluated for boilers cofiring
nonfossil and fossil fuels, only model boilers 7 thru 11 are of interest in
this analysis. Table 7-7 shows the annual "max mean concentration" and the
"second max concentration" for 24-hour and 3-hour averaging times.
The primary national ambient air quality standards for sulfur oxides
3 ^
(S02) are 80 yg/m for the annual arithmetic mean and 365 yg/m for the
24-hour concentration which is not to be exceeded more than once a year.
3
The secondary standard is 1300 yg/m for the 3-hour maximum concentration
which is not to be exceeded more than once a year.
The dispersion analysis shows that the max mean concentration varies
from 0.81 to 4.89 yg/m3 at Baseline Control, 0.21 to 1.82 yg/m3 at Control
Level I, and 0.09 to 0.61 yg/m at Control Level II. These data show the
favorable ambient air impact of S02 controls on the cofired model boilers.
7-23
-------
These data show a definite beneficial impact on ambient air quality due
to more efficient controls for PM and S02- These data also show that for
similar control levels, dry control systems such as baghouses, ESPs, and
EGBs, result in smaller ground level pollutant concentrations than do wet
control systems. This is caused by the increased plume rise resulting from
dry control systems. In some cases part of the difference in ambient
concentrations for alternative control levels is attributable to this
phenomenon.
The values presented were determined assuming no background concentra-
tion of pollutants. Therefore, any background concentration of pollutants
at the emission source should be added to the reported concentrations to
obtain the ambient pollutant concentrations after installation of a
nonfossil fuel fired boiler. However, application of an efficient control
system will result in the NFFB having a small ambient pollutant impact.
7.1.2 Secondary Air Impacts
Secondary air emissions will result from power plant boilers supplying
electricity to the nonfossil fuel boiler control devices, since the power
required to operate the control equipment will ultimately result in greater
emissions at the electric power generation facility. For NFFBs used to
cogenerate steam and electricity, power requirements of the control systems
will result in increased emissions from the NFFB itself. For each model
boiler, Table 7-8 presents the estimated incremental amounts of PM and SOg
emissions generated at a coal-fired electric power generation facility. PM
and S(L emissions at the power generating facility were calculated assuming
that the power boilers comply with the New Source Performance Standard for
o
utility boilers. Table 7-8 shows that the incremental emissions caused by
power requirements of the control systems are small when compared to the
emission reductions caused by those control systems.
For example, a 44 MW (150 x 106 Btu/hr) NFFB burning 50% wood/50% HSE
with PM and S02 emissions controlled to Control Level II would have a 291 kW
electrical demand for pollution control equipment. This demand would result
in the following incremental air emissions from the power boiler; PM -
0.21 Mg/yr, S02 - 5.20 Mg/yr, and NOX - 4.16 Mg/yr. However, these
7-24
-------
TABLE 7-8. SECONDARY AIR EMISSIONS DUE TO ELECTRICAL DEMANDS OF CONTROL SYSTEMS
ro
01
Model
Boiler
Number
la
Ib
Ic
Id
le
2a
2b
2c
2d
2e
2f
3a
3b
3c
3d
3e
3f
4a
4b
4c
4d
4e
4f
5a
5b
5c
6a
6b
6c
7a
7b
7c
7d
7e
7f
79
Boiler Capacity
(thermal Input)
8.8 HU
(30 x 106Btu/hr)
22.0 HH
(75 x 106Btu/hr)
44.0 HU
(150 x 106Btu/hr)
117 HH
(400 x 106Btu/hr)
44.0 HH
(150 x 106Btu/hr)
44.0 HH
(150 x 106Btu/hr)
44.0 HU
(150 x 106Btu/hr)
Control
Level
Fuel3 PM
Hood B
I
II
II
II
Hood B
I
II
II
II
II
Hood B
I
II
II
II
II
Hood B
I
II
II
II
II
HAB B
I
II
SLH B
I
II
75* Hood/d B
25S HSE I
I
II
II
II
II
b
so2
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
I
B
B
I
II
Emission6
Control
System
HC
HC.HS
HC.HS
HC.FF
HC.ESP
HC
HC.HS
HC.HS
HC.FF
HC.ESP
HC.EGB
HC
HC.US
HC.HS
HC.FF
HC.ESP
HC.EGB
HC
HC.HS
HC.US
HC.FF
HC.ESP
HC.EGB
MC.HS
HC.HS
HC.FF
HC.HS
HC.HS
HC.FF
HC.HS
HC.HS
HC.FGD-HS
HC.ESP
HC.FF
HC.FGD-DS.FF
HC.ESP.FGD-HS
Electr1calf
Energy
Consumed
kH
18>.4
64.9
102
41.3
42.0
42.8
159
252
101
102
113
92.9
314
500
201
197
219
241.1
834
1330
534
524
601
206
336
209
314
500
201
177
303
306
180
195
251
311
Power Generating Source
SEr'SEiIr Emissions From"
Power Boiler power Bo11er(Mg/yr)
HH(10bBtu/hr) PM S02 NOX
0.05 (0.18) 0.01
0.19 (0.65
0.30 1.02
0.12 (0.41
0.12 (0.42
0.13 (0.43
0.47 (1.59
0.74 (2.52
0.30 (1.01
0.30 (1.02
0.33 (1.13
0.05
0.07
0.03
0.03
0.03
0.11
0.18
0.07
0.07
0.08
0.27 (0.93) 0.07
0.92 (3.14
1.47 (5.00
0.59 (2.01
0.58 (1.97
0.64 (2.19
0.22
0.36
0.14
0.14
0.16
0.71 (2.41) 0.17
2.44 (8.34
3.90(13.30
1.57 (5.34
1.54 (5.24
1.76 (6.01
0.60 (2.06
0.98 (3.36
0.61 (2.09
0.92 (3.14
1.47 (5.00
0.59 (2.01
0.52 (1.77
0.89 (3.03
0.90 (3.06
0.53 (1.80
0.57 (1.95
0.74 (2.51
0.91 (3.11
0.60
0.95
0.38
0.37
0.43
0.15
0.24
0.15
0.22
0.36
0.14
0.13
0.22
0.22
0.13
0.14
0.18
0.22
0.32
1.16
1.82
0.73
0.75
0.77
2.84
4.51
1.81
1.82
2.02
1.66
5.61
8.94
3.59
3.52
3.92
4.31
14.9
23.8
9.55
9.37
10.8
3.68
6.01
3.74
5.61
8.94
3.59
3.16
5.42
5.47
3.22
3.49
4.49
5.56
0.26
0.93
1.46
0.59
0.60
0.62
2.27
3.60
1.44
1.46
1.62
1.33
4.49
7.15
2.87
2.82
3.13
3.45
11.9
19.0
7.64
7.49
8.60
2.95
4.81
2.99
4.49
7.15
2.87
2.53
4.33
4.38
2.57
2.79
3.59
4.45
Emsslons Reduced
From Uncontrolled
NFFB(Mg/yr)
PH S02
306
338
345
345
345
766
846
864
864
864
864
1530
1690
1730
1730
1730
1730
4080
4510
4610
4610
4610
4610
2340
2400
2440
2030
2100
2140
1710
1770
1770 373
1810
1810
1810 373
1810 480
See footnotes at end of table.
-------
TABLE 7-8. (CONTINUED)
T4
ro
Model
Boiler
Number
8a
8b
8c
8d
8e
8f
8g
9a
9b
9e
9d
lOa
lOb
lOc
lOd
lOe
lOf
lOg
lOh
lla
lib
lie
lid
lie
12a
12b
12c
13a
13b
13c
14a
14b
14c
15a
15b
Boiler Capacity
(thermal Input)
44.0 MM
(150 x 106 Btu/hr)
117 MM
(400 x 106Btu/hr)
44.0 MM
(150 x 106Btu/hr)
44.0 MM
(150 x lO^tu/hr)
2.9 MM
(10 x lO^tu/hr)
44.0 MW
(150 x lO^tu/hr)
117 MM
(400 x 106Btu/hr)
58.6 MM
(200 x lO^Btu/hr)
Fuel"
SOS Mood/d
SOS HSE
SOS Mood/d
SOS HSE
SOS Mood/d
SOS LSH
SOS RDF/d
SOS HSE
HSH
MSM
HSM
Bagasse
Control
Level
m
B
I
I
I
II
II
II
B
I
II
II
B
I
I
I
II
II
II
II
B
I
I
II
II
B
I
II
B
I
II
B
I
II
B
I
b
SO,
B
B
I
II
B
I
II
B
I
I
II
B
B
I
II
B
B
I
II
B
I
II
II
B
B
B
B
B
B
B
B
B
B
B
Emission0
Control
System
MC .FGD-MS
MC, FGD-MS
MC.FGD-HS
MC ,FGD-MS
MC.FGD-DS,FFe
MC.FGD-DS.FF
HC.ESP.FGO-MS
HC. FGD-MS
MC. FGD-MS
HC,FGD-DS,FF
HC,ESP,FGD-HS
HC.HS
HC.HS
MC, FGD-MS
MC.FGD-HS
HC.FF
HC .ESP
HC.FGD-DS.FF
HC.ESP.FGD-US
FGD-MS
FGD-MS
FGD-MS
ESP .FGD-MS
ESP .FGD-MS
MS
FF
ESP
ESP
ESP
ESP
ESP
ESP
MC
MS
Electr1calf
Energy
Consumed
kW
178
296
303
306
218
254
291
831
834
601
762
161
288
288
288
193
199
246
325
201
277
279
223
226
28.0
11.1
93.7
128
192
248
338
509
136
183
Power Generating Source
XSr'HSSr Emissions Fr«nh
Power Boiler Power Bo11er(Mg/yr)
MMdoVu/hr) PM S02 NOX
0.52 (1.78
0.87 (2.96
0.89 13.03
0.90 (3.06
0.64 (2.18
0.74 12.54
0.85 (2.91
2.44 (8.31
2.44 (8.34
1.76 (6.01
2.23 (7.62
0.13
0.21
0.22
0.22
0.16
0.18
0.21
0.59
0.60
0.43
0.54
0.47 (1.61) 0.12
0.84 (2.88
0.84 (2.88
0.84 (2.88
0.57 (1.93
0.58 (1.99
0.72 (2.46
0.95 (3.25
0.59 (2.01
0.81 (2.77
0.81 (2.79
0.65 (2.23
0.66 (2.26
0.21
0.21
0.21
0.14
0.14
0.18
0.23
| 0.14
0.20
0.20
0.16
0.16
0.08 (0.28) 0.02
0.03 (0.11) 0.01
o.3i (i.os;
0.38 (1.28
0.51 (1.75
0.81 (2.78
0.99 (3.38
1.36 (4.63
0.40 (1.36
0.54 (1.83
0.08
0.09
0.13
0.20
0.34
0.33
f 0.07
| 0.10
3.18
5.29
5.42
5.47
3.90
4.54
5.20
14.9
14.9
10.7
13.6
2.88
5.15
5.15
5.15
3.45
3.56
4.40
5.81
3.59
4.95
4.99
3.99
4.04
.
0.05
0.20
1.88
2.29
3.13
4.97
6.04
8.28
1.82
2.45
2.55
4.23
4.33
4.37
3.12
3.63
4.16
11.9
11.9
8.60
10.9
2.30
4.12
4.12
4.12
2.76
2.85
3.52
4.65
2.87
3.96
3.99
3.19
3.23
.
0.40
0.16
1.50
1.83
2.50
3.98
4.83
6.62
1.46
1.96
Emsslons Reduced
From Uncontrolled
NFFB(Mg/yr)
PM S02
1800 139
1860 139
1860 723
1860 930
1900 139
1900 723
1900 930
5010 1610
5010 1930
5050 1930
5050 2480
1410
1470
1470 160
1470 206
1510
1510
1510 160
1510 206
1970 233
2030 789
2030 1015
2060 789
2060 1010
.
3.58
5.96
1140
1160
1190
3040
3110
3170
1580
1730
See footnotes at end of table.
-------
Footnotes to Table 7-8:
*Wood - hog fuel (wood/bar* Mixture)
HAB . high ash bark
SIM - salt-laden Mod
HSE - high sulfur eastern coal
LSW - low sulfur western coal
RDF - refuse derived fuel
HSU - municipal solid waste
8 refers to Baseline Control Level.
I refers to Control Level I.
II refers to Control Level II.
StC - nulticyclone
MS - wet scrubber
FF - fabric filter
ESP - electrostatic preclpitator
EGB - electrostatic gravel bed filter
F60-HS - flue gas desulfurizatton; double alkali or lime wet scrubber
FGO-DS - flue gas desulfurlzation; lime dry scrubber
Control systems separated by a coma mean that both are used at the same time, not that either may be used Independently. Mechanical collectors are
Included for fly ash relnjectlon on all of the boilers firing mod.
Average fuel mixture on a heat Input basis.
eThe dry scrubber Is sized to scrub only a portion of the flue gas.
Amount of electrical energy consumed by the control equipment
9Heat Input required at the utility power boiler to produce the electrical energy consumed by the NFFB control equipment. Calculations are based on a
fuel thermal input of 10.000 Btu to produce one KHH of electricity.
hAssumes a coal,f1red utility boiler In compliance with the utility NSPS (Subpart Da). Emission Knits are as follows: PH-0.03 ]b/106Btu,
NO -0.60 Ib/NTBtu, S02-9« removal with 1.2 lb/10°Btu ceiling (assume 0.75 lb/10°Btu is average control level). A 45* load factor is
assumed for the bagasse boiler and a 60S load factor for all other nonfossil fuel fired boilers.
The nonfossil fuel fired boiler emission reductions are taken from Table 7-3.
-------
incremental emissions are far less than the 1900 Mg/yr of PM and 930 Mg/yr
of S02 reduced by the NFFB control equipment. The same boiler firing
100 percent wood and controlled to Control Level II would, for the most
energy demanding case considered, result in the following incremental air
emissions from the utility power boiler; PM-0.36 Mg/yr, S02 - 8.94 Mg/yr,
and NO - 7.15 Mg/yr. These incremental emissions are also smaller in
/\
magnitude than the 1730 Mg/yr of PM controlled by the NFFB control
equipment.
7.2 LIQUID UASTE IMPACTS
Water pollution impacts or the need for additional water treatment can
result from controlling nonfossil fuel boiler air emissions if the control
technologies used to achieve the various control levels examined produce
aqueous discharge streams.
Dry particulate controls (ESP, FF, EGB, MC) do not result in water
discharges, but incremental water pollution impacts from PM controls can
result if the collected particulate material is sluiced to disposal ponds.
However, the sluiced ash stream from a PM control device can be treated in
existing facilities, along with the boiler bottom ash stream, to remove the
suspended solids and the water reused.
Wet scrubbers used for particulate control will also produce an aqueous
stream. The water in a wet scrubbing system is usually recycled with
provisions for make-up and blowdown to prevent the suspended solids concen-
tration from becoming high enough to plug the scrubber nozzles or erode the
internal components. However, this blowdown stream may be treated in a
thickener or settling pond and the water reused. The solids are removed
from the system in the form of a sludge. In any case there need not be an
aqueous discharge to the environment as a result of PM emission control.
The control of S02 by FGD can result in liquid waste discharges, though
dry scrubbing processes are designed not to generate liquid wastes.
However, even wet scrubbing processes such as dual alkali (DA), lime, and
limestone systems can be designed on a closed loop basis so that the only
water losses during normal operation occur with the sludge going to
A
landfill. Any purging of these systems due to water imbalances or other
7-28
-------
operating upsets, system blowdown to prevent scaling, or operator error will
result in discharge of an aqueous waste stream which can be contained and
treated. However, during normal operation, there should be no water
pollution impact from lime, limestone, or double alkali FGD systems designed
on a closed loop basis. Some FGD systems, such as sodium scrubbing
systems, may result in an aqueous discharge stream which must be treated and
disposed of properly. The situation is not discussed any further in this
document since an S02 regulation need not result in a liquid waste impact.
7.3 SOLID WASTE IMPACTS
Nonfossil and combination fuel boiler air pollution control techniques
produce two main types of solid wastes: fly ash collected by the PM control
devices, and waste solids (both sludge and dry scrubbing products) from the
control of SCL emissions. In this section the impacts of the incremental
solid wastes produced from PM and S02 controls are discussed by considering
the following:
- solid waste quantities and characteristics,
- waste treatment and disposal,
- applicable regulations,
- national solid waste impacts of potential NSPS.
7.3.1 Solid Waste Quantities and Characteristics
The fly ash from NFFBs is commonly over 50 percent unburned combus-
tibles, mainly carbon. Because of this high combustible content the fly ash
from NFFBs will burn more easily than fly ash from fossil fuel boilers.
Care must be taken when handling this fly ash to prevent fires. In addition
the fly ash contains inorganic compounds. These compounds include elements
such as barium, iron, magnesium, titanium, sodium, phosphorus, sulfur,
silicon, and traces of 50 to 100 other elements. The amounts of these
elements will vary with the source and type of fuel burned.
The sludges from wet scrubbers used for particulate control may contain
over 50 percent moisture. Dry particulate controls such as ESPs, FFs, and
EGBs result in a collected fly ash containing little moisture.
Dual alkali scrubber sludges are composed primarily of calcium
sulfite/sulfate solids. Also present are dissolved sodium salts and trace
7-29
-------
elements (e.g., lead, arsenic and cadmium), which may contaminate the
groundwaters and surface waters due to runoff and leaching from sludge
disposal sites .(see Section 7.3.2). The chemical composition and concentra-
tion of F6D sludge liquors vary with the different fuel types used in
cofired NFFBs. When a particulate collection device is not used upstream of
the FGD system and the F6D system is being used to control both S02 and PM
emissions, the trace element concentrations in the scrubber sludge are
increased due to the addition of fly ash to the sludge.
The dry solid waste produced from spray-drying FGD processes consists
primarily of calcium or sodium salts, depending upon the type of alkali used
as the S02 sorbent. Significant quantities of fly ash will also be present
because the PM collection device is located downstream of the spray dryer
and removes fly ash along with the spray dried solids.
Table 7-9 shows the quantities of solid wastes produced at different
control levels for each of the model boilers. Also shown on this table are
the types of PM and S02 control techniques used to achieve the indicated
control levels. For PM control, the MC, ESP, FF, and EGB control techniques
result in the collection of a dry particulate fly ash. The WS control
technique results in the production of a particulate sludge. In Table 7-9
the sludge from particulate scrubbers contains 30 percent solids. For S02
control with a lime or double alkali FGD system, the sludge concentration is
50 percent solids. Solid wastes shown for the cases involving dry scrubbing
control are the combined amounts of fly ash, sulfate/sulfite salts, and
unreacted sorbent collected by the PM control device downstream of the S02
dry scrubbing system. Sludge quantities presented for the combined S02/PM
systems are based on a sludge concentration of 50 percent solids. For
example, data presented in this table show that for the 44 MW
(150 x 106Btu/hr) 50% wood/50% HSE fired boiler, solid wastes (combined dry
solids and sludge) increase by 2990 Mg/yr in going from the baseline to
Control Level II for PM and S02 control.
7.3.2 Waste Treatment and Disposal
Ponding and landfill ing are currently the primary methods of disposal
for collected fly ash (including dry solids and sludge). Current State and
7-30
-------
TABLE 7-9. QUANTITIES OF SOLID WASTE GENERATED
FROM MODEL BOILER CONTROL SYSTEMS
Model
Boiler
Number
la
Ib
Ic
Id
le
2a
2b
2c
2d
2e
2f
3a
3b
3c
3d
3e
3f
4a
4b
4c
4d
4e
4f
5a
5b
5c
6a
6b
6c
7a
7b
7c
7d
7e
7f
7g
8a
3b
8c
8d
8e
8f
8g
9a
9b
9c
9d
Boiler Capacity
(thermal Input)
8.8 HH
(30 x 106Btu/hr)
22.0 MW
(75 x lO^tu/hr)
•
44.0 HW
(150 x 106Btu/hr)
117 HW
(400 x 106Btu/hr)
44.0 MM
(150 x 106Btu/hr)
44.0 MW
(150 x 106Btu/hr)
44.0 MM
(150 x 106Btu/hr)
44.0 MW
(150 x 106Btu/hr)
117 MW
(400 x 106Btu/hr)
Control5
Level
Fuel8 PM
Wood 8
I
II
II
II
Wood B
I
II
II
II
II
Wood B
I
II
II
II
II
Wood B
I
II
II
II
II
HAB B
I
II
SLW B
I
II
75X Wood/ B
25X HSE I
I
II
II
II
II
SOX Wood/d 8
SOX HSE I
I
I
II
II
II
SOX Wood/d B
SOX HSE I
II
II
so2
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
I
B
B
I
II
B
B
I
II
B
I
II
8
I
I
11
Amount of Solid Waste Generated
Emi.c4onc Solids From. Dry f , Sludge From Wet
emission p»rtl<-ul4te Controls 'J Scrubber3
System Mg/yr
HC 180
MC.WS 154
MC.WS 154
MC.FF 219
MC.ESP 219
MC 451
MC.HS 384
MC.WS 384
MC.FF 548
MC.ESP 548
MC.EGB 548
MC 901
MC.WS 768
MC.WS 768
MC.FF 1100
MC.ESP 1100
MC.EGB 1100
MC 2406
MC.MS 2050
MC .MS 2050
MC.FF 2930
MC.ESP 2930
MC.EGB 2930
MC.WS 1340
MC.HS 1340
MC.FF 1810
.MC.WS 775
MC.WS 775
MC.FF 1510
MC.WS 994
HC.WS 994
MC.FGD-WS 994
MC.ESP 1340
MC.FF 1340,
MC.FGD-DS.FF 23801
MC.ESP.FGO-WS 1340
MC.FGO-WS 1220
HC.FGO-WS 1220
MC.FGD-HS 1220
MC.FGD-WS . 1220,
MC.FGD-DS.FF8 197oJ
MC.FGD-OS.FF 36001
MC.ESP.FGD-WS 1580
MC.FGD-HS 3240
MC.FGD-HS 3240,
HC.FGO-OS.FF 96101
MC.ESP.FGD-HS 4470
tons/yr
199
169
169
242
242
497
423
423
604
604
604
993
846
846
1210
1210
1210
2652
2260
2260
3220
3220
3220
1480
1480
2000
854
854
1670
1100
1100
1100
1480
1480,
26301
1480
1340
1340
1340
1340,
2170]
39701
1740
3570
3570,
106001
4930
Mg/yr
-
195
219
-
"
„
489
548
-
-
-
977
1100
.
.
-
_
2610
2930
_
_
-
1220
1450
2110
2340
834
1030,
2110"
_
—
1920h
1090?!
1220?
3550"
4380n
_
3720h
8300j!
9560"
11900h
tons/yr
-
215
242
-
~
539
604
-
.
-
1080
1210
«
.
-
.
2870
3220
_
_
-
1350
1600
2330
2580
920
1140h
2320h
_
2iioh
134o!l
3910JJ
4100h
9150*;
10500"
13100h
7-31
-------
TABLE 7-9. (CONTINUED)
Model
Boiler
Number
oooooooo
=ria -h re o. n v at
Control b
Level
(thermal Input) Fuel* R1
44.0 HH 501 Wood/d 8
(150 x lohtu/hr) 50t LSH {
I
II"
II
II
II
soz
B
B
A
B
I
II
Amount of Sol Id 1
cv.iceJ Scrubber9
Hg/yr
632
834,
1140*
1330h
830h
tons/yr
696
920h
1260*
1470"
915h
lla
lib
lie
lid
lie
44.0 MW
(150 x 106Btu/hr)
50» RDF/°
SOS HSE
I
I
II
II
I
II
I
II
FGD-HS
FGD-HS
FGD-HS
ESP,FGD-HS
ESP .FGO-HS
2060
2060
2270
2270
3470
4460
12a
12b
12c
13a
13b
13c
14a
14b
14c
154
15b
2.9 MW MSH
(10 x 1068tu/hr)
44.0 MH HSH
(150 x 106Btu/nr)
117 MW MSW
(400 x 106Btu/hr)
58.6 MH Bagasse
(200 x 106Btu/hr)
B
I
II
B
I
II
B
I
II
B
I
B
8
8
B
B
B
B
B
B
B
B
.
WS
FF
ESP
ESP
ESP
ESP
ESP
ESP
MC
WS
.
5.96
1140
1160
1190
3040
3110
3170
1580
-
.
6.57
1260
1280
1310
3350
3430
3490
1750
-
.
35.8 39.4
— —
-
.
' "
„ m
5780 6370
aUood - hog fuel (wood/bark mixture)
HAB - high ash bark
SLH - salt-laden wood
HSE - high sulfur eastern coal
LSH - low sulfur western coal
RDF - refuse derived fuel
MSW - municipal solid waste
B refers to Baseline control level.
I refers to Control Level I.
II refers to Control Level II.
°MC - mechanical collector
WS - wet scrubber
FF - fabric filter
ESP - electrostatic predpltator
EGB - electrostatic gravel bed filter
FGD-WS - flue gas desulfurlzatlon; double alkali or lime wet scrubber
FGD-OS - flue gas desulfurlzatlon; lime dry scrubber
Control systems separated by a comma mean that both are used at the same time, not that either may be used
Independently, mechanical collectors are Included for fly ash relnjectlon on all of the boilers firing wood.
Average fuel mixture on a heat Input basis.
"The dry scrubber 1s sized to scrub only a portion of the flue gas.
fHeight on a dry basis.
'Weight based on 30 percent sol Ids (except as noted). Sludge from systems designed to remove partlculate matter
only 1s designed to comprise 30 percent solids.
hHe1ght based on 50 percent solids. Sludge from systems using an SO. wet scrubber or a combined SO.-m wet scrubber
1s designed to comprise 50 percent solids.
11ncludes desulfurlzatlon products from dry scrubber.
•^For wood-fired boilers a portion of the fly ash collected by the mechanical collector Is burned by relnjectlon. This
decreases the amount of solid waste generated.
7-32
-------
local regulations govern the disposal practices at the landfills and pond
sites. Solid wastes from spray dryers (dry scrubbing) are handled in the
same manner as fly ash. Off-site landfill ing has been selected as the
disposal method for the first two dry scrubbing systems installed at
industrial boiler sites.5
The main sludge disposal options for wet FGD systems include ponding
and landfill ing. Ponding is the simpler of the two methods, but is
potentially more harmful to the environment. Ponding involves slurrying the
sludge to a pond, allowing it to settle, and pumping the supernatant liquor
either to a treatment process or back to the facility for reuse. Because
there is always a hydraulic head on the waste in the bottom of the pond, the
potential for leachates reaching ground water sources beneath the pond is
greater than for a landfill. Use of the pond area may be limited after
disposal ceases, mainly because of the poor load bearing capabilities of the
sludge compared to the original soil structure.
Landfill disposal of FGD wastes in a specially prepared site requires
some processing of the wet scrubber sludge (either stabilization or
fixation) to obtain a soil-like material that may be loaded, transported,
and placed as fill. Stabilization refers to the addition of fly ash or
other similar material to the sludge to produce only physical changes
without any chemical reactions. Fixation is a type of stabilization which
involves the addition of reagents (such as lime) to cause chemical reactions
with the sludge. The objective of these treatment methods is to increase
the load bearing capacity of the raw sludge and to decrease the permeability
of the sludge, and correspondingly, the mass transport rate of contaminants
Q
leaching out of the sludge.
Proper design of both ponds and landfills is required to assure minimal
environmental impact of solid waste disposal. Contaminants that are
contained in ponds and landfills or accidentally spilled on the surface can
enter ground-water systems as a result of two processes: leakage and
leaching. As the term implies, leakage refers to migration to the
subsurface of fluids that are deposited on the surface. Leakage is of more
concern for ponds and spills than landfills. Leaching, on the other hand,
7-33
-------
denotes the introduction of water (usually infiltrating precipitation) into
the waste after it has been landfilled so that contaminants are dissolved
and elutriated.or leached out of the solid material.
Transport of trace elements and other potential pollutants from the
disposal site via leaching or run off is determined by many factors,
including: (1) the chemical form and concentration of the potential
pollutant in the waste, (2) the permeability, sorption capacity, and
porosity of the substrate, (3) soil and leachate pH, (4) the permeability
and porosity of the waste, (5) the proximity of the disposal site to the
ground-water table and/or surface water, (6) the presence or absence of clay
or plastic liners or other methods of enclosing the wastes in materials of
low permeability, and (7) climatic factors such as precipitation,
g
temperature, and relative humidity. However, if a landfill site is
properly designed and operated, these leaching and runoff problems can be
averted and the landfill area eventually reused either for recreational or
building use purposes.
7.3.3 Waste Disposal Regulations
At the present time the federal regulations governing solid waste
disposal are not fully defined. EPA recently (May 2, 1980) issued Phase I
final Resource Conservation and Recovery Act (RCRA) regulations covering the
framework for management of solid wastes. In addition, Congress is
currently considering legislation that would exempt certain "special wastes"
(as defined in the proposed regulations) from the possibility of being
classified as hazardous until more data are gathered about their
characteristics.
The Phase I RCRA regulations exempt fly ash, bottom ash, slag, and air
pollutant emission control sludge produced in the combustion of fossil fuels
from consideration as hazardous wastes. This exemption also applies to
industrial boiler F6D sludges.
Non-hazardous waste disposal management and techniques will be governed
by Section 4004 of RCRA. This section requires states to implement disposal
programs that will protect the environment (especially ground water) from
contamination. EPA has also published Landfill Disposal of Solid Waste,
7-34
-------
Proposed Guidelines that will act as a guide to the states as to what their
^2
disposal management programs should contain.
Disposal of non-hazardous wastes will require at a minimum that a clay
liner be used at the disposal site, that the waste be covered at the end of
each operating day, that access to the site be controlled, that ground-water
quality at the site boundary be monitored, and that a final impermeable
12
cover be placed and revegetation occur. These activities are required,
primarily, to protect ground water in the disposal area.
7.3.4 National Solid Waste Impact
Table 7-10 shows the national solid waste impacts in 1990 of applying
Baseline and Control Levels I and II to boilers affected by a potential
NSPS. As was done in Section 7.1.1 for the national air impact analysis,
this analysis is of the solid waste impacts resulting from nonfossil fuel
firing only. Any associated impacts resulting from the firing of fossil
fuels are not included. The amounts of solid waste are on a dry basis
because the specific types of control devices which might be used could not
be determined. The amounts of dry solid waste generated at the Baseline
Control Level and Control Levels I and II are shown. The emission level
used to calculate the national solid waste impact of the Baseline Control
Level is the average of existing State emission regulations shown in
Chapter 3. The increase of dry solid waste from emission control alone
above the baseline control for Control Level II ranges from approximately
2 percent for RDF to 10 percent for wood. The increase in total solid waste
generated by the boiler, including the boiler bottom ash and solid waste
generated by emission controls, shows a range of increase of less than one
percent for MSW up to 7 percent for wood.
Table 7-10 also shows the annual nonfossil fuel consumption rates which
will be achieved by the end of 1990 by boilers affected by a potential NSPS.
This fuel usage represents a positive national solid waste impact because if
the fuel was not burned it would have to be disposed of. As shown in the
table this benefit is reduced only slightly by the solid waste increase due
to air pollution control requirements for the various control levels.
7-35
-------
TABLE 7-10. NATIONAL SOLID WASTE IMPACT OF BASELINE AND
CONTROL LEVELS I AND II IN 1990
7°
CO
Year Fuel0
Uoodd
MSHe
1990 HSW.ISHf
RDF'
Bagasse
Annual Amount of^'
Nonfossll Fuel
Fired In NFFBs
6g/yr(103tons/yr)
24.300
(26,800)
4.250
(4.680)
1.670
(1.840)
3.770
(4.160)
4.350
(4.790)
Annual Amount of
Boiler Bottom
Ash Produced
6g/yr(103tons/yr)
164
(181)
1.060
(1.170)
500
(552)
607
(669)
27.1
(29.9)
Annual Amounts of Solid Waste1
Generated Due to Emission Control
Sg/yr(103tons/yr)
Basel 1neJ
310
(342)
66.0
(72.8)
0
123
(136)
75.2
(82.9)
Level I
330
, (364)
67.5
(74.4)
1.49
(1-64)
125
(138)
82.4
(90.8)
Level II
341
(376)
68.5
(75.5)
2.48
(2.73)
126
(139)
h
Annual Reduction of Solid Haste
Achieved by Firing Nonfossll Fuels
-Gg/yr(103tons/yr)
Baseline
23.900
(26.300)
3.120
(3.440)
1.170
(1.290)
3,050
(3,360)
4,250
(4.680)
Level I
23.900
(26.300)
3.120
(3.440)
1.170
(1.290)
3.040
(3.350)
4.240
(4.670)
Level II
23,800
(26.200)
3.110
(3.430)
1.170
(1.290)
3.040
(3.350)
h
'includes only NFFBs affected by potential New Source Performance Standards (NSPS). This will be the NFFBs Installed In 1984 through 1990.
bBased on the population of NFFBs affected by NSPS. their hourly fuel feed rates, and annual capacity factors of 0.45 for bagasse and 0.60 for all
other NFFBs.
Stood - all types of wood fuels.
HSU - municipal solid waste.
RDF - refuse derived fuel.
ISW - Industrial solid waste
dThe high ash bark and salt-laden wood fuel were evaluated as model boiler cases to determine the sensitivity of emission control costs for wood-fired
boilers to the ash and salt contents of wood fuels. For calculating national environmental Impacts of wood-fired boilers the wood fuel category 1s
used to represent boiler burning all types of wood fuels.
'includes all MSH-flred boilers except small modular units.
Includes only small modular MSH-flred boilers and ISH-flred boilers.
Assuming RDF supplies 100 percent of the boiler heat Input. For boilers firing 100 percent RDF the baseline control level Is the same as the baseline
level for a similar size HSH-flred boiler.
hA second control level Is not being evaluated for bagasse-fired boilers.
1Dry basis.
jFor calculating national Inpacts the Baseline Control Level Is the average of existing State regulations shown In Chapter 3.
-------
7.4 ENERGY IMPACT OF CONTROL TECHNOLOGIES
All of the alternative control systems installed for PM and S02
emission control require electrical energy. Major electrical energy
consumers are the fans required to overcome the pressure drop across the
control systems. For ESPs energy is also required to create the corona
discharge and to run auxiliary equipment such as collection plate rappers.
Lesser amounts of electrical energy are needed for motors that operate the
pumps in wet scrubbing systems and bag cleaning mechanisms in fabric
filters.
Table 7-8 shows the energy demand of the control devices associated
with each model boiler. The energy demand is expressed in both kilowatts
and in thermal megawatts of heat input to the power boiler supplying the
electrical energy. Energy requirements for the systems with a MC upstream
of a secondary control device, such as a WS or ESP, were calculated based on
energy usage of both devices. Also included was the energy usage of
associated operations such as slurry pumping and sludge handling. The
significant result of these calculations, shown in Table 7-11, is that the
model boiler control system energy requirements associated with each of the
control levels varies from less than one percent to 3.4 percent of the heat
input to the model boilers.
Table 7-11 shows predicted quantities of nonfossil fuels which will be
burned in 1990 in boilers affected by potential New Source Performance
Standards. For example, this table shows that by the end of 1990 nonfossil
fuel will be burned at the rate of 420 PJ/yr (398 x 1012 Btu/yr) in these
boilers. However, the electrical demands of the emission controls lead to
increased fossil fuel use at the utility power boiler (see Table 7-8). This
increase in fossil fuel at the power boiler is shown in Table 7-11 as a
percentage of the heating input of nonfossil fuel consumed by the NFFBs
being controlled. The percentages expressed show the range of energy
demands for the various types of control systems considered at each control
1evel.
7-37
-------
TABLE 7-11. NATIONAL ENERGY IMPACTS OF NFFB EMISSION CONTROL SYSTEMS
FOR BASELINE CONTROL AND CONTROL LEVELS I AND II IN 1990
Year Fue1b
Hoodc
MSHd
1990 MSH.ISH*
RDFf
Bagasse
Total
Annual Energy Input9
To NFFBs
PJ/yr (1012Btu/yr)
258
(245)
48.1
(45.6)
23.1
(21.9)
50.9
(48.2)
39.6
(37.5)
420
(398)
Control System Energy Demands Expressed
As a Percent of the Amount Heat Input to NFFBs
Baseline Control Level I Control Level II
0.6 - 1.8j 2.09 - 2.179 1.31 - 3.409
0.70 0.85 1.17
0 2.80 1.10
h h h
0.68 0.92 1
I
CO
00
"includes only NFFBs controlled by potential New Source Performance Standards.
Hood - all types of mod fuels.
HSW - municipal solid waste
RDF - refuse derived fuel
ISW - Industrial solid waste
°The high ash bark and salt-laden wood fuels were evaluated as model boiler cases to determine the sensitivity of emissions control costs for wood-fired
boilers to the ash and salt contents of wood fuels. For calculating national environmental Impacts of wood-fired boilers the wood fuel category Is
used to represent boilers burning all types of wood fuels.
Includes all MSM-flred boilers except small modular units.
elncludes only small modular MSH-flred boilers and ISH-flred boilers.
Based on RDF supplying 100 percent of the boiler heat Input.
9Values shown represent the range of energy demands based on the different types of control systems considered for each level (example: ESP, US, FF)
hThe energy demands of control systems for 100J firing of RDF are not known since a model boiler was not evaluated for this case. However, they
are similar to those shown for large NSU-flred boilers.
1A second control level Is not being evaluated for bagasse-fired boilers.
''values shown represent the range of energy demands of the different types of control systems commonly used to meet existing State regulations.
-------
7.5 OTHER IMPACTS
An increase in noise at the industrial boiler site is expected as a
result of the operation of the various control techniques but the increase
is expected to be small compared to background noise levels. For FGD
systems the higher level of noise would result from fans, pumps, and
agitators. For ESPs, the higher noise levels are due to the fans, pumps,
compressors, electrode rappers, etc. For FFs, the bag cleaning mechanisms
result in increased noise levels. However, equipment which emit high noise
levels will be used at industrial sites regardless of any NSPS. Therefore
this standard is not expected to cause a significant increase in total noise
levels.
7.6 OTHER ENVIRONMENTAL CONCERNS
7.6.1 Long-Term Gains/Losses
Increased emission control of the air pollutants resulting from the
operation of nonfossil and combination fuel fired boilers would result in
reduced air emissions and increased energy, water (if sodium scrubbing
systems are used), and solid waste impacts. The solid waste impact would be
mitigated by other EPA regulatory programs. The long-term gains achieved
would result from reducing PM and S02 emissions to the ambient air. Another
important long-term benefit would be the application of control technology
which makes possible the use of nonfossil fuels in an environmentally
acceptable manner. The use of these fuels will serve to reduce the use of
non-renewable fossil fuels for steam generation.
7.6.2 Environmental Impact of Delayed Standard
As analyzed in Section 7.1, there are significant air quality benefits
achieved by emission reductions at control levels I and II compared to
baseline emissions. Large quantities of pollutants are reduced and
incremental ambient air quality benefits are achieved. Therefore, the
impact of a delayed standard would be a negative one since the incremental
benefit discussed in Section 7.1 would not be achieved as long as the
standard was delayed.
7-39
-------
7.7 REFERENCES
1. Memo from Barnett, K., Radian Corporation, to file. January 27, 1982.
22 p. Projections of new nonfossil fuel fired boilers.
2. Environmental Protection Agency: User's manual for single source
(CRSTER) model. EPA Report No. EPA-450/2-77-013. U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina.
3. U.S. Environmental Protection Agency. New Stationary Sources Perfor-
mance Standards; Electric Utility Steam Generating Units. Federal
Register 44(113);33580-33624. June 11, 1979.
4. Dickerman, J.C. and K.L. Johnson. (Radian Corporation.) Technology
Assessment Report for Industrial Boiler Applications: Flue Gas
Desulfurization. (Prepared for U.S. Environmental Protection Agency.)
Research Triangle Park, N.C. Publication No. EPA-600/7- 79-178i.
November 1979. p. 6-14.
5. Reference 4, p. 6-24.
6. Duvel, W.A., et al. 'FGD Sludge Disposal Manual. Publication No.
FP-977. Palo Alto, Electric Power Research Institute, January 1979.
pp. 5-1 to 5-5.
7. Reference 6, p. 2-21.
8. Reference 6, pp. 5-5 to 5-7.
9. Reference 6, pp. 7-19 to 7-29.
10. Reference 6, pp. 8-128 to 8-133.
11. Telecon. McCloskey, M., Radian Corporation, with Corson, A., EPA:
Washington, D.C. May 14, 1980. Information about new RCRA
regulations.
12. U.S. Environmental Protection Agency. Landfill Disposal of Solid
Waste; Proposed Guidelines. Federal Register. 44(59): 18138-18148.
March 26, 1979.
13. Roeck, D.R. and R. Dennis. (GCA Corporation.) Technology Assessment
Report for Industrial Boiler Applications: Particulate Control.
(Prepared for U.S. Environmental Protection Agency.) Research Triangle
Park, N.C. Publication No. EPA-600/7-79-178h. December 1979. p. 207.
7-40
-------
8. COSTS
In Chapter 8 is an analysis of the costs of alternative emission
control techniques potentially applied to nonfossil fuel fired boilers.
This analysis is organized into two major sections. Section 8.1 presents
the costs of alternative emission control techniques applied in the "model"
NFFBs that are developed in Chapter 6. Other costs that need to be
considered during the development of NSPS, such as costs already incurred by
NFFB operators to comply with existing wastewater and solid waste
regulations, are discussed in Section 8.2. The costs presented in this
chapter are subsequently used in Chapter 9 to assess the economic impacts of
alternative emission control measures on NFFB users.
8.1 COST ANALYSIS OF MODEL BOILERS
The analysis of model boiler costs is presented in four sections.
Section 8.1.1 provides background information for the cost analysis.
Section 8.1.2 presents the costs for new boiler/emission control systems.
Section 8.1.3 discusses factors affecting the costs of modified or
reconstructed facilities. Section 8.1.4 presents the national cost impacts
of alternative NFFB emission control requirements.
8.1.1 Background Information
Capital and operating estimates were developed for the various model
NFFBs presented in Chapter 6. The general approach used in developing these
costs consisted of several main steps. First, a series of material and
energy balance calculations were performed to establish flue gas flow rates
and PM and S02 emission rates for each boiler/emission control system.
Second, emission data and associated control system design and operating
data were obtained on a number of operating NFFB facilities around the
country. Third, various equipment sizes and operating parameters were
developed based on results of the material and energy balances and an
evaluation of the emission and control system data. Finally, capital cost
8-1
-------
estimates were prepared by contacting boiler owners and process equipment
vendors for price quotations in the applicable equipment size ranges and by
reference to various literature cost sources. Operating costs were
developed based on the material and energy balance calculations and the
developed control system operating parameters.
8.1.1.1 Summary of Model Boilers. Tables 8-1 and 8-2 summarize the
model boilers and emission control levels analyzed in this document.
Chapter 6 contains the rationale for selecting model boiler sizes, types,
fuels, emission control techniques, and emission control levels.
The selected model boilers emphasize the firing of wood fuels since
nearly three-fifths of the new NFFB capacity potentially affected by NSPS
will be fired with wood. The model wood-fired boilers are used to analyze
the firing of three different types of wood and three potential wood/coal
cofiring arrangements. Four different capacities ranging from 8.8 to 117 MW
(30 to 400 x 10 Btu/hr) on a thermal input basis are represented by model
wood-fired boilers.
The model boilers are also used to analyze the firing of two types of
GSW fuels: MSW and RDF. Model boilers for MSW firing represent two
different boiler types and a range of boiler capacity of 2.9 to 117 MW
(10 to 400 x 10 Btu/hr) on a thermal input basis. Model boilers for RDF
firing analyze one potential RDF/coal cofiring arrangement and capacity.
Model boilers firing bagasse represent the most typical capacity and
boiler type of new bagasse-fired boilers.
The model boilers are used to analyze the impacts of three different
levels of emission control. The baseline control level is the highest level
of emissions expected based on the present mix of State and Federal
Regulations. The second control level, Control Level I, is a more stringent
level of control that is widely demonstrated in existing NFFB facilities.
Control Level II, the most stringent control level analyzed, represents a
level of control demonstrated in only a few existing NFFB facilities.
The model boilers are used to analyze the control of both PM and S02
emissions. The control of PM emissions is accomplished with mechanical
collectors, wet scrubbers, electrostatic precipitators, fabric filters, or
8-2
-------
TABLE 8-1. MODEL BOILERS
Model Boiler
Number
la
Ib
Ic
Id
le
2a
2b
2c
2d
2e
2f
3a
3b
3c
3d
3e
3f
4a
4b
4c
4d
4e
4f
5a
5b
5c
6a
6b
6c
7a
7b
7c
7d
7e
7f
7g
8a
8b
8c
8d
8e
8f
8g
Boiler Capacity
(Thermal Input Basis)
8.8 MW
(30 x 106 Btu/hr)
22.0 MM
(75 x 106 Btu/hr)
44.0 MW
(150 x 106 Btu/hr)
117 MM
(400 x 106 Btu/hr)
44.0 MW
(150 x 106 Btu/hr)
44.0 MW
(150 x 106 Btu/hr)
44.0 MM
(150 x 106 Btu/hr)
44.0 MM
(150 x 1C6 Btu/hr)
Fuel4 Control
PM
Wood B
I
II
II
II
Wood B
I
II
II
II
II
Wood B
I
II
II
II
II
Wood B
I
II
II
II
I!
HAB B
I
II
SLW B
I
II
75% Wood/d B
25* HSE I
I
II
II
II
II
502 Wood/d B
50* HSE I
I
I
II
II
II
Level b
!>02
B
B
B
B
B
8
B
3
B
B
B
B
B
B
B
B
B
B
B
8
B
B
B
3
B
3
3
B
B
B
B
I
8
B
I
II
B
B
I
II
3
I
II
Emission Control
PM
MC
MC.WS
MC.WS
MW.FF
MC ,ESP
MC
MC.WS
MC,WS
MC.FF
MC ,ESP
MC ,EGB
MC
MC.WS
MC.WS
MC.FF
MC.ESP
MC.EGB
MC
MC.WS
MC.WS
MC.FF
MC ,ESP
MC ,E6B
MC.WS
MC.WS
MC.FF
MC,WS
MC.WS
MC.FF
MC.WS
MC.WS
MC .FGD-HS
MC ,ESP
MC.FF
MC.FF
MC.ESP
MC .FGD-WS
MC .FGO-WS
MC .FGD-WS
MC .FGD-WS
MC.FF
MC.FF
MC.ESP
System0
iU2
-
-
"
-
.
-
-
—
—
-
—
_
_
-
-
-
.
-
-
FGD-WS
_
.
FGD-OS
FGD-WS
FGD-WS
FGD-WS
FGD-WS
FGD-WSa
FGD-OSe
FGD-DS
FGD-WS
See footnotes at end of table.
8-3
-------
TABLE 8-1. (CONTINUED)
Model Boiler Boiler Capacity
Fuel" Control
Number (Thermal Input Basis) PM
9a
9b
9c
9d
lOa
lOb
lOc
lOd
lOe
lOf
lOg
lOh
lla
lib
lie
lid
lie
12a
12b
12c
13a
13b
13c
14a
14b
14c
15a
15b
aWood -
HAB
SLU
HSE
LSW
ROF
117 MW
(400 x 105 Btu/hr)
44.0 MW
(150 x 106 Btu/hr)
44.0 MW
(150 x 106 Btu/hr)
2.9 MW
(10 x 106 Btu/hr)
44.0 MW
(150 x 106 Btu/hr)
117 MW
(400 x 106 Btu/hr)
58.6 MW
(200 x 106 Btu/hr)
hog fuel (wood/bark mixture)
high ash bark
salt-laden wood
ligh sulfur eastern coal
low sulfur western coal
refuse derived fuel
SOS Wood/d B
50% HSE I
II
II
SOX Wood/d B
SOS LSW I
I
I
II
II
II
II
501 ROF/d B
SOS HSE I
I
II
II
MSW B
I
II
MSW B
I
II
MSW B
I
II
Bagasse B
I
Level"
J!02
B
I
I
II
8
B
I
II
B
B
I
II
B
I
II
I
II
3
B
B
B
B
B
B
B
B
B
B
Emission Control
ffl
MC .FGD-WS
MC.FGD-WS
MC.FF
MC ,ESP
MC.WS
MC.WS
MC, FGD-WS
MC, FGD-WS
MC.FF
MC.ESP
MC.FF
MC.ESP
FGO-WS
FGD-WS
FGD-WS
ESP
ESP
.
ws
FF
ESP
ESP
ESP
ESP
ESP
ESP
MC
WS
System6
~^T
FGD-WS
FGD-WS
FGD-DS
FGD-WS
.
FGD-WS
FGD-WS
.
.
FGD-DS
FGD-WS
FGD-WS
FGD-WS
FGD-WS
FGD-WS
FGD-WS
_
-
—
-
m
-
.
m
MSW - municipal solid waste
B refers to Baseline Control level.
I refers to Control Level I.
II refers to Control Level II.
CMC - mechanical collector
WS - wet scrubber
FF - fabric filter
ESP - electrostatic predpltator
EGB - electrostatic gravel bed filter
FGD-WS - flue gas desulfurization; double alkali or lime wet scrubber
FGD-DS - flue gas desulfurization; Hme dry scrubber
Control systems separated by a comma mean that both are used at the same time, not that either may be used
Independently. Mechanical collectors are Included for fly ash relnjectlon on all of the boilers firing
wood.
Average fuel mixture on a heat Input basis.
eOnly a portion of the flue gas 1s scrubbed.
8-4
-------
TABLE 8-2. EMISSION LEVELS FOR THE MODEL BOILERS
Model
Boiler
Number
1
2
3
4
S
6
7
8
9
10
11
12
13
14
IS
Fuel*
Mood
Mood
Hood
Mood
HAB
SLH
751 Mood/b
25t HSE
501 Mood/b
SOX HSE
501 Hood/b
501 HSE
50* Mood/b
SOS ISM
SOI RDF/b
SOS HSE
MSU
MSM
MSM
Bagasse
Standard
Boiler
MM
(106Btu/hr)
8.8
(30)
22.0
(75)
44. 01
(150)
117
(400)
44.0
(150)
44.0
(150)
44.0
(150)
44.0
(150)
117
(400)
44.0
(ISO)
44.0
(150)
2.9
(10)
44. 01
(150)
117
(400)
58.6
(200)
Uncontrolled Emissions
ng/J (lb/106 Btu)
PH-BHCC
2100
(4.88)
2100
(4.88)
2100
(4.88)
2100
(4.88)
2950
(6.87)
2590
(6.03)
2200
(5.11)
2300
(5.35)
2300
(5.35)
1840
(4.27)
2500
(5.82)
129
(0.30)
1440
(3.36)
1440
(3.36)
2170
(5.05)
PM-AMCC
418
(0.973)
418
(0.973)
418
(0.973)
418
(0.973)
593
(1.38)
899
(2.09)
440
(1-02)
460
(1.07)
460
(1.07)
367
(0.853)
-
-
-
-
-
so2'
-
-
-
-
641
(1.49)
1240
(2.89)
1240
(2.89)
275
(0.639)
1350
(3.15)
212
(0.49)
212
(0.49)
212
(0.49)
-
Baseline d
Control Level
ng/J (lb/106 Btu)
PM
258
(0.6)
258
10.6)
258
(0.6)
258
(0.6)
146
(0.34)
146
(0.34)
138
(0.32)
138
(0.32)
43.0
(0.10)
138
(0.32)
138
(0.32)
129
(0.30)
73.1
(0.17)
73.1
(0.17)
267
(0.62)
so2
-
'-
-
641
(1.49)
1075
(2.50)
516
(1.2)
275
(0.639)
1075
(2.50)
212
(0.49)
212
(0.49)
212
(0.49)
-
Control Level I
ng/0 (lb/106 Btu)
PM
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
43.0
(0.10)
64.5
(0.15)
64.5
(0.15)
64.5
(0.15)
43.0
(0.10)
43.0
(0.10)
86.0
(0.20)
*>26
-
-
-
-
194
(0.45)
374
(0.87)
374
(0.87)
81.7
(0.19)
405
(0.94)
212
(0.49)
212
(0.49)
212
(0.49)
-
Control Level II
ng/J (lb/106 Btu)
PM
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.5
(0.05)
21.?
(0.05)
21.5
(0.05)
21.5
(0.05)
h
SO/
-
-
64.5
(0.15)
125
(0.29)
125
(0.29)
27.5
(0.06)
135
(0.31)
212
(0.49)
212
(0.49)
212
(0.49)
-
See footnotes on second page.
8-5
-------
FOOTNOTES TO TABLE 8-2.
Wood - hog fuel (wood/bark mixture)
HAB - high ash bark
SLW - salt-laden wood
RDF - refuse derived fuel
MSW - municipal solid waste
HSE - high sulfur eastern coal
LSW - low sulfur western coal
Average fuel mixture on a heat input basis.
BMC - before mechanical collector or any other control equipment.
AMC - after mechanical collector when the mechanical collector is not the final control device.
Both values are included only for cases with fly ash reinjection.
Emission level equivalent to the uncontrolled emission rate, or to the highest emission rate
expected under the current mix of State and Federal Regulations. For model boilers 1-4 the level
°° also represents emissions after the mechnical collector when the mechanical collector is the final
m control device.
p
The emission level shown represents a 70 percent reduction from uncontrolled S02 emissions for the
combination fuel boilers and no control for the others.
The emission level shown represents a 90 percent reduction from uncontrolled S02 emissions for the
combination fuel boilers and no control for the others.
emissions for boilers firing bagasse of 100 percent wood are low and have not been quantified
for this analysis.
A level more stringent than Control Level I was not evaluated.
-------
electrostatic gravel-bed filters. Control of S02 emissions is analyzed only
for model boilers cofiring nonfossil and fossil fuels and is accomplished
with either wet scrubbing or dry scrubbing techniques.
8.1.1.2 Model Boiler Design Specifications. Boiler design and fuel
specifications are summarized in Tables 8-3 and 8-4. These specifications
are discussed in Chapter 6.
Emission control system design specifications are detailed in Table
8-5. These specifications are mainly based on emission test data and design
data from existing NFFB facilities. Specifications for wet scrubbers
applied to RDF/coal cofired and MSW-fired boilers are based on conceptual
analyses since no scrubber emission test data are available for these
applications.1'29
8.1.1.3 Cost Estimating Sources. Equipment costs and operating costs
for the model boilers specified in Tables 8-3, 8-4, and 8-5 are estimated
from the sources listed in Table 8-6. Equipment costs estimated from these
sources are preliminary or budget authorization estimates developed in terms
of mid-1978 dollars and generally accurate to ±30 percent.
8.1.1.4 Capital Cost Bases. The capital cost is the total investment
required to supply a complete boiler/emission control system. Components of
the capital costs, itemized in Table 8-7, include total direct and indirect
investment costs, contingencies, land, and working capital.
The equipment costs determined from the sources listed in Table 8-6 are
the basis of the other capital cost components listed in Table 8-7. The
cost of equipment installation, for example, is estimated as a fraction of
the equipment cost. Other cost components such as engineering are then
estimated as fractions of the sum of the equipment and installation costs.1
The capital costs include the following boiler equipment items:
- fuel handling and storage systems,
- feedwater and condensate treatment systems,
- boiler and auxiliaries (feed pumps, chemical feed system,
soot blowers, instrumentation, and FD and ID fans), and
- bottom ash disposal systems
8-7
-------
TABLE 8-3. MODEL BOILER DESIGN SPECIFICATIONS
Model Boiler Number
Thermal Input, MW (106 Btu/hr)
Fuel*
Fuel rate, kg/s
(ton/hr)
Analysis
X sulfur
X ash
Heating value, kJ/kg
(Btu/lb)
Excess air, X
Flue gas flow rate, m /s (acfm)
Flue gas temperature, °K(°F)
Load factor, I
Flue gas constituents, kg/hr(lb/hr)
Fly ash (before mechanical collector)0
(after mechanical collector)
so2
N0x
Ash from sand classifier,1 kg/hr(lb/hr)
Bottom ash, kg/hr(lb/hr)
Boiler Output, MW (106 Btu/hr)
Steam
Losses
Efficiency, X
Steam quality
Pressure, kPa(pslg)
Temperature, "K (°F)
Steam production, e kg/hr(lb/hr)
1
8.8(30)
Wood
0.829
(3.29)
0.02
1.00
10,600
(4.560)
50
6.94(14,700)
478(400)
60
66.2(146)
13.3(29.3)
3.40(7.50)
29.2(64.4)
20.1(44.4)1
5.7(19.5)
3.1(10.5)
65
1,720(250)
481(406)
8,890(19,600)
2
22.0(75)
Wood
2.07
(8.22)
0.02
1.00
10,600
(4.560)
50
17.3(36,700)
478(400)
60
166(366)
33.2(73.2)
8.53(18.8)
73.0(161)
50.3(111)^
14.3(48.7)
7.7(26.3)
65
1,720(250)
481(406)
22,200(49,000)
3
44.0(150)
Wood
4.15
(16.4)
0.02
1.00
10.600
(4.560)
50
34.7(73.500)
478(400)
60
332(732)
66.4(146)
17.0(37.5)
146(322)
10K222)3
28.6(97.5)
15.4(52.5)
65
1,720(250)
481(406)
44,500(98,200)
4
117(400)
Wood
11.1
(43.9)
0.02
1.00
10,600
(4.560)
50
92.5(196.000)
478(400)
60
885(1950)
177(390)
45.3(100)
390(859)
269 ( 592 J3
76.1(260)
41.0(140)
65
5,170(750)
672(750)
101,000(223.000)
5
44.0(150)
HAB
4.32
(17.2)
0.02
3.00
10,160
(4.370)
50
34.7(73,500)
478(400)
60
467(1030)
93.9(207)
17.0(37.5)
255(563)
292(644)
28.6(97.5)
15.4(52.5)
65
1,720(250)
481(406)
44.500(98,200)
See footnotes at end of table.
8-8
-------
TABLE 8-3. (CONTINUED)
Model Boiler Number
Thermal Input, VH(106 Btu/hr)
Fuel"
Fuel rate, kg/s
(ton/hr)
Analysis
X sulfur
X ash
Heating value, kJ/kg
(8tu/lb)
Excess air, X
Flue gas flow rate, m /s (acfm)
Flue gas temperature, °K(°F)
Load factor, X
Flue gas constituents, kg/hr(lb/hr)
Fly ash (before mechanical collector)0
(after mechanical collector)"
SO,
NOX2
Ash from sand classifier,1 kg/hr(lb/hr)
Bottom ash, kg/hr(lb/hr)
Boiler Output, MM (106 Btu/hr)
Steam
Losses
Efficiency, X
Steam quality
Pressure, kPa(pslg)
Temperature, "KCF)
Steam production,6 kg/hr(lb/hr)
6
44.0(150)
SLW
4.18
(16.6)
0.02
1.49
10,490
(4510)
50
34.7(73,500)
478(400)
60
411(905)
142(314)
17.0(37.5)
147(325)
101(222)
28.6(97.5)
15.4(52.5)
65
1,720(250)
481(406)
44,500(98,200)
7
44.0(150)
75X Wood/f >9
25X HSE
3.11/0.401
(12.3/1.59)
0.02/3.54
1.00/10.58
10,600/27.440
(4.560/11.800)
50
33.3(71,300)
478(400)
60
348(767)
69.6(153)
102(224)
23.5(51.7)
189(416)
129(285)
30.4(104)
13.6(46)
69
1,720(250)
481(406)
47,600(105,000]
8
44.0(150)
50* Wood/ >g
50% HSE
2.07/0.801
(8.22/3.18)
0.02/3.54
1.00/10.58
10,600/27,440
(4,560/11,800)
50
32.4(69,200)
478(400)
60
364(803)
72.8(160)
197(434)
29.9(66.0)
231(510)
157(348)
32.1(110)
11.9(40)
73
1,720(250)
481(406)
50,300(1U.OOO
9
117(400)
SOX Wood/'9
SOX HSE
5.52/2.13
(21.9/8.47)
0.02/3.54
1.00/10.58
10,600/27,440
(4,560/11,800)
50
87.1(184,500)
478(400)
60
971(2140)
194(428)
526(1160)
79.7(176)
617(1360)
421(928)
85.4(292)
31.6(108)
73
5,170(750)
572(750)
114,000(251.000)
10
44.0(150)
SOX Wood/f '9
SOX LSW
2.07/0.985
(8.22/3.91)
0.02/0.60
1.00/5.40
10,600/22,330
(4,560/9,600)
50
33.1(70,200)
478(400)
60
290(640)
58(128)
43.5(95.8)
29.9(66.0)
172(380)
117(259)
32.1(110)
11.9(40)
73
1,720(250)
481(406)
50,300(111,000)
See footnotes at end of table.
8-9
-------
TABLE 8-3. (CONTINUED)
Model Boiler Number
Thermal Input, MW(106 Btu/hr)
Fuel3
Fuel rate, kg/s
(ton/hr)
Analysis
t sulfur
X ash
Heating value, kj/kg
(Btu/lb)
Excess air, %
Flue gas flow rate, m /s(acfm)
Flue gas temperature, °K(°F)
Load factor, t
Flue gas constituents, kg/hr(lb/hr)
Fly ashfbefore mechanical collector}6
(after mechanical collector)
SO,
N°x
Ash from sand classifier,1 kg/hr(lb/hr)
Bottom ash, kg/hr(lb/hr)
Boiler Output, HH (106 8tu/hr)
Steam
Losses
Efficiency, %
Steam quality
Pressure, kPa(pslg)
Temperature, °K(°F)
Steam production,6 kg/hr(lb/hr)
n
44.0(150)
50J RDF/f>9
50t HSE
1.63/0.801
(6.48/3.18)
0.17/3.54
19.44/10.58
13,460/27,440
(5,790/11,800)
50
31.8(67,300)
478(400)
60
396(873)
214(472)
38.6(85.0)
-
1,050(2,320)
33.4(114)
10.6(36)
76
3,100(450)
589(600)
47.200(104.000
12
2.9(10)
MSW
0.260
(1.03)
0.12
22.38
11.340
(4,875)
100
2.79(5,920)
478(400)
60
1.36(3.00)
2.23(4.92)
1.40(3.08)
-
279(615)
1.6(5.5)
1.3(4.5)
55
1,720(250)
481(406)
2,510(5,540)
13
44.0(150)
MSW
3.88
(15.4)
0.12
22.38
11,340
(4,875)
100
41.8(88,500)
478(400)
60
229(504)
33.5(73.8)
21.0(46.2)
-
3,490(7,690)
30.8(105)
13.2(45)
70
3,100(450)
589(600)
43.600(96.000)
14
117(400)
MSW
10.3
(41.0)
0.12
22.38
11,340
(4,875)
100
111(236,000)
478(400)
60
608(1340)
89.3(197)
56.0(123)
-
9,310(20,500)
81.9(280)
35.1(120)
70
5,170(750)
672(750)
109.000(241.000)
15
58.6(200)
Bagasse
6.43
(25.5)
Trace
1.10
9,116
(3,920)
SO
47.7(101,000)
478(400)
45
458(1.010)
18.1(40.0)
.
145(319)
35.2(120)
23.4(80)
60
1,720(250)
533(500)
51,700(114.000)
See footnotes at end of table.
8-10
-------
FOOTNOTES TO TABLE 8-3:
aWood - hog fuel (wood/bark mixture)
HAB - high ash bark
SLW - salt-laden wood
HSE - high sulfur eastern coal
LSW - low sulfur western coal
RDF - refuse derived fuel
MSW - municipal solid waste
Uncontrolled emissions.
Fly ash before mechanical collector means uncontrolled emissions prior to any control device
whether a mechanical collector is used or not.
Guage pressure.
eAssuming a saturated condensate return at 10 psig.
f
Average fuel mixture on heat input basis.
9Boilers cofiring wood and coal are designed to fire wood up to 100 percent of the boiler capacity.
These boilers and their emission control systems are designed to fire coal only up to 30 percent
or 60 percent of the boiler capacity depending on whether the average cofiring ratio is 25 percent
or 50 percent. The model boiler cofiring RDF and coal is designed to fire coal up to 100 percent
of capacity and RDF up to 60 percent of capacity.
Fly ash after the mechanical collector is shown only for cases where fly ash reinjection is used.
The value shown represents a mechanical collector used as a precleaner prior to another control
device. For model boilers la - 4a, where the mechanical collector is the final control device,
this value would be the mass equivalent of an emission level of 258 ng/J (0.6 lb/10 Btu).
^and classifiers are only used with systems employing fly ash reinjection (model boilers 1-10).
The value shown represents the difference in the amount of fly ash collected by the mechanical
collector and the amount of fly ash reinjected into the boiler furnace.
JThese values are for cases where the mechanical collector is used as a precleaner prior to another
control device. Where the mechanical collector is the final control device, these values would be
34.3, 85.7, 171, and 458 kg/hr (75.7, 189, 378, and 1009 Ib/hr) for model boilers la, 2a, 3a, and
4a respectively.
-------
TABLE 8-4. ULTIMATE ANALYSES OF THE FUELS SELECTED
FOR THE MODEL BOILERS
oo
1
ro
Composition, X by weight
Fuel8
Hood
HAB
SLW
ROFC
MSHC
Bagasse
HSE
LSW
Moisture
50.00
50.00
50.00
22.42
27.14
52.00
8.79
20.80
Carbon
26.95
25.85
26.68
31.30
26.73
22.60
64.80
57.60
Hydrogen
2.85
2.73
2.82
4.62
3.60
3.10
4.43
3.20
N1 trogen
0.08
0.08
0.08
0.61
0.17
0.10
1.30
1.20
Oxygen
19.10
18.32
18.91
21.44
19.74
21.10
6.56
11.20
Sulfur
0.02
0.02
0.02
0.17
0.12
Trace
3.54
0.60
Ash
1.00
3.00
1.49b
19.44
22.38
1.10
10.58
5.40
Gross
Heating Value
kJ/kg (Btu/lb)
10,600 ( 4,560)
10,160 ( 4,370)
10,500 ( 4,510)
13,460 ( 5,790)
11,340 ( 4,875)
9,116 ( 3,920)
27,440 (11,800)
22,330 ( 9,600)
aHood - hog fuel (wood/bark mixture)
HAB - high ash bark
SLW - salt-laden wood
RDF - refuse derived fuel
MSW - municipal solid waste
HSE - high sulfur eastern coal
LSH - low sulfur western coal
Salt makes up 0.5 percent of the fuel composition and 1s Included here as ash.
Composition does not total 100 percent due to the presence of chlorine which Is not shown here.
-------
TABLE 8-5. EMISSION CONTROL SYSTEM DESIGN SPECIFICATIONS3
Control System
It™
Specification
Multiple cyclone
Wet scrubbers
03
i
i—1
CO
Material of construction
Tube diameter
Pressure drop
Design PH removal efficiency
Carbon steel
23 cm (9 In.)
750 Pa (3 In. w.c.)
Model boilers la-4a: 88X
Ib-e, 2b-f, 3b-f, 4b-f, 5, 7-10: BOX
6: 651
15: 881
Material of construction
Scrubber type
Liquid-to-gas ratio (L/G)
Liquid discharge pressure
Liquid punplng height
Length of piping
Sludge handling equipment/characteristics
Model boilers 1-5, 12. 15: FRP-lined carbon steel
6-11: stainless steel type 316
Model boilers l-5a, 7-8a, lOa: Impingement
l-4b,c; 5b; 6a,b; 7b,c; 8b-d; 9a,b; lOb-d;
lla-c; 12b; 15b: variable-throat venturl
7f; 8e,fi 9c; lOg: spray dryer
7-8g; 9d; lOh; lld-e: tray tower
Impingement scrubbers: 0.4 dm Iquld/m gas (3 gal/1000 acf)
Venturl scrubbers: 1.3 dm3/m3 (10 gal/1000 acf)
Spray dryers: 0.04 dm3/m3 (0.3 gal/1000 acf)
Tray towers: 1.3 dm3/m3 (10 gal/1000 acf)
170 kPa (lOpslg)
6m (20 ft.)
30m (100 ft.)
PH removal: clarlfler; sludge conpHses 30X solids (except for . ,
12b where no clarlfler Is used and a 10X solids slurry Is produced) '
SO. removal and combined PM/SO, removal: clarlfler/vacuum filter;
Sludge comprises SOX solids
-------
TABLE 8-5. (CONTINUED)
Control System
Item
Specification
Wet scrubber
00
i
Pressure drop (gas-phase) and design
PH removal efficiency
Wood-fired and wood/coal coflred boilers:
Model boilers 7-8a, lOa: 1 kPa (4 1n. w.c.); 60-70*
l-4b; 6a; Tb.c; 8b-d: 2.2 kPa (9 1n. H.C.); 84-86*
l-4c, 6b: 5 kPa (20 In. w.c.); 93-951
5a: 1.2 kPa (5 1n. H.C.); 75*
5b: 2.7 kPa (11 In. w.c.); 89*
7-8g, 9d. lOh: 1.5 kPa (6 1n. w.c.); SO, scrubbing only
9a,b: 3.2 kPa (13 In. w.c.); 911 c
lOb-d: 2 kPa (8 1n. w.c.); 82*
RDF/coal coflred, HSW- and bagasse-fired boilers:
Model boilers lla: 2.2 kPa (9 1n. w.c.); 95*
llb-c: 3.5 kPa (14 In. w.c.); 97*
lld-e: 1.5 kPa (6 In. w.c.); SO, scrubbing only
1?J>: 3.7 kPa (15 In. w.c.); 50r
15b: 2.5 kPa (10 In. w.c.); 96X
Design SOg removal efficiency
Venturl scrubber separator pressure drop
Mist eliminator pressure drop
70S
Model boilers 7c,f; Sc.f; 9b,c; lOc.g; Ub.d:
7g; 8d,g; 9d; lOd.h; llc.e: 901
Sa.b.e: 13.5*
9a: 58*
lla: 20*
750 Pa (3 In. w.c.)
250-500 Pa (1-2 In. w.c.) (Hist eliminators are Installed only on
scrubbers with gas-phase pressure drops exceeding 1.2 kPa or 5 In. w.c.)
Fabric filter
Material of construction
Cleaning method
Design alr-to-cloth ratio
Pressure drop
Filter material
Filter life
Power demand
Fire extinguishing system
Carbon steel (Insulated)
Pulse-jet
2 cm/s (4 ft/m)
1.5 kPa (6 1n. w.c.)
Teflon-coated glass felt
2 years
4 W/m2 filter area (0.5 hp/1000 ft2)
Steam
-------
TABLE 8-5. (CONTINUED)
Control Systen
Item
Specification
Electrostatic preclpltator
00
i
i—»
01
Material of construction
Design specific collection area and
removal efficiency
Pressure drop
Power demand (average)
Carbon steel (Insulated)
Model boilers l-4e; 7d.g; 8g; 9d: 65 m2/(m3/s)(330 ft2/1000 acfm); 95.0-95.3%
lOf.h: 73 m2/(n3/s)(370 ft2/1000 acfm); 94.11
Ud.e: 52 m2/(m3/s)(265 ft2/1000 acfm); 99.IX
13-14a: 24 m2/(m3/s)(160 ft2/1000 acfm); 94.9J
13-14b: 47 m2/(m3/s)(240 ft2/1000 acfm); 97.0X
13-14c: 93 m2/(m3/s)(«10 ftZ/1000 acfm); 98.5X
250 Pa (1 In. w.c.)
Model boilers l-4e; lOf.h; lld-e; 13a-c; 14a-c: 32 H/m2 plate area (3 W/ft2)
7d,g: 27 K/m2(2.5 H/ft2)
8g. 9d: 18 W/ra2(1.6 H/ft2)
Electrostatic gravel-bed
filter
Material of construction
Pressure drop
Power demand
Carbon steel
1 kPa (4 1n. w.c.)
Model boiler 2f: 25 kW (33 hp)
3f: 49 kH (66 hp)
4f: 148 kH (198 hp)
Overall system
Pressure drop
Duct features
250-750 Pa (1-3 1n. w.c.) plus pressure drops from Individual control equipment
Main duct length: 20-30 m (60-100 ft)
Expansion joints for duct connecting two pieces of control equipment
Elbows
Bypass ducting (Including duct, tees, elbows, dampers) for fabric filters
and partial scrubbing FGD
Transition ducting for ESPs
-------
TABLE 8-6. COST ESTIMATING SOURCES
1
Cost Item
Cost Estimating Source
Boiler Capital Costs
Wood
Wood/coaI
RDF/coal
MSH
Bagasse
Owner data
Owner data and PEDCo's Final Cost Equations for Industrial Boilers'
4
PEDCo's Final Cost Equations for Industrial Boilers
Owner and vendor data
Owner data
Boiler Annual Costs
Owner and vendor data, and PEDCo's Final Cost Equations for
Industrial Boilers
00
i
Emission Control Equipment Costs
Multiple cyclone
Baghouse and filter bags
Electrostatic preclpltator
Scrubber
- Impingement
- v»ntur1
- spray dryer and tray tower
- Auxiliaries (circulation pumps (2), circulation
tank, piping, mixer (S02 scrubbing only))
Vendor data (Joy Manufacturing Co.)
Vendor data (Flex-Kleen Corp., Wheelabrator - Frye, Inc., Standard Havens Co.)6'7'8
and GARD's Capital and Operating Costs of Selected Air Pollution Control
Systems9
PEDCo's Capital and Operating Costs of Participate Controls on Coal- and
011-Flred Industrial Boilers10
Vendor data (Joy Manufacturing Co.)1* ..
GARD's Capital and Operating Costs of Selected Air Pollution Control Systems1'
Radian's Technology Assessment Report for Industrial Boiler Applications:
Flue Gas Desulfurlzatlon
Radian's Technology Assessment Report for Industrial Boiler Applications:
Flue Gas Desulfurlzatlon, K.M. Guthrle's Data and Techniques for Preliminary
Capital Costs Estimating, Guthrle's Process Plant Estimating, Evaluation
and Control, and Peters and Tlmnerhaus' Plant Design and Economics for
Chemical Engineers""16
-------
TABLE 8-6. (CONTINUED)
00
I
Cost I ton
Electrostatic gravel -bed filter
Fan/Motor
Raw material handling and regeneration
(SOp scrubbing only) and solids separation
Ducting
Ash removal
Screen for sand classification
Emission Contrsl Annual Costs
Cost Estimating Source
Vendor data (Combustion Power Company, Inc.)
18
GARD's Capital and Operating Costs of Selected Air Pollution Control Systems
Radian's Technology Assessment Report for Industrial Boiler Applications:
Flue Gas Desulfur1zat1onlJ
GARD's Capital and Operating Costs of Selected Air Pollution Control Systems19
and PEDCo's Capital and Operat1nq.Xosts of Partlculate Controls on Coal-
and Oil-Fired Industrial Boilers'111
PEDCo's Capital and Operating Costs,,ff Partlculate Controls on Coal-
and 011-Flred Industrial Boilers10
Richardson Engineering Services' Rapid Construction Cost Estimating System
Radian's Technology Assessment Report for Industrial Boiler Applications:
Flue Gas Desulfurlzatlon, PEDCo's Capital and Operating Costs of Partlculate
Controls on Coal- and 011-Flred Industrial Boilers, GARD's Capital and
Operating Costs of Selected Air Pollution Control £vstere , and EEA's Estimated
Landfill Credit for Non-Fossil -Fueled Boilers ™i««"«w
-------
TABLE 8-7. CAPITAL COST COMPONENTS
(1) DIRECT INVESTMENT COSTS
Equipment
Installation
TOTAL DIRECT INVESTMENT COSTS (TDI)
(2) INDIRECT INVESTMENT COSTS
Engineering3 .
Construction and field Expense
Construction Fees
Start Up Costs0 .
Performance Tests
TOTAL INDIRECT INVESTMENT COSTS (Til)
(3) CONTINGENCIES6
TOTAL TURNKEY COSTS (TTC)f
(4) Land9
(5) Working Capitalh
TOTAL CAPITAL COST (Total Turnkey Costs + Land + Working Capital)
Estimated as 10% of Total Direct Investment Costs (TDI) for boiler and
PM control systems. For S02 control systems, engineering costs are the
following: fi
(1) wet systems up to 59 MW (200 x 10jBtu/hr) $105,000
over 59 MW (200 x 10°Btu/hr) $155,000
(2) dry systems up to 59 MW (200 x 10°Btu/hr) $90,000
over 59 MW (200 x 10°Btu/hr) $160,000
For systems removing both S02 and PM, engineering costs are the sum of the
above S02 control engineering costs and PM control engineering costs.
bEstimated as 10% of TDI.
Estimated as 2% of TDI.
8-18
-------
Estimated as greater of 1% of TDI or $3000.
Estimated as 20% of the sum of TDI and TIL
Sum of TDI, Til, and Contingencies.
9Est1mated as: $1000 for boilers with heat Input capacities -^22 MW
(75 x 10gBtu/hr); $2000 for boilers with heat input capacities ^22 MW
(75 x 10 Btu/hr); 0.084% of TTC for emission control systems.
Estimated as 25% of Total Direct Operating Costs.
Note: Estimating factors are based on PEDCo's Population and Characteristics
of Industrial/Commercial Boilers in the U.S. and Radian's Technology 13 23
Assessment Report for Industrial Boiler Applications Flue Gas Desulfurization. '
8-19
-------
Equipment included in the costs attributed to the emission control system
include:
- control equipment and auxiliaries,
- ducting (from the boiler system to the emission control
system to the stack),
- fans (increased costs for overcoming control system pressure
drop),
- solids separation systems, and
- fly ash disposal systems.
In all model boilers, the bottom ash disposal system is combined with
the fly ash disposal system. In allocating the capital cost of the ash
disposal system, only the incremental cost of the combined system over the
cost of a bottom ash disposal system is allocated to the emission control
capital cost.
8.1.1.5 Annualized Cost Bases. The annualized cost includes all the
costs incurred in the yearly production of steam. These costs include
direct and indirect operating costs and annual charges attributed to the
initial capital expenditure. Components of the annualized cost are itemized
in Table 8-8.
The capital recovery factors used in this document are based on an
interest rate of 10 percent and the following equipment lives:
- 20 years for small controlled-air MSW-fired boilers,
- 30 years for all other boilers,
- 15 years for scrubbing systems used for PM or S02 control
(WS, FGD-WS, FGD-DS), and
- 20 years for all other emission control systems.
The 10 percent interest rate should not be considered as the actual cost of
borrowing capital since this analysis is not intended as an economic
feasibility study. Rather, 10 percent is selected as the minimum attractive
rate of return to provide a basis for calculating capital charges.
Different interest rates are used in the economic impact analysis presented
in Chapter 9.
8-20
-------
TABLE 8-8, ANNUALIZED COST COMPONENTS
(1) DIRECT OPERATING COSTS
Operating Labor
Supervision
Maintenance Labor
Maintenance Materials
Electricity
Chemi cals
Waste Disposal
Solids (fly ash and bottom ash)
Sludge
Fuel
TOTAL DIRECT OPERATING COSTS
(2) INDIRECT OPERATING COSTS
Payroll Overhead3
Plant Overhead
TOTAL INDIRECT OPERATING COSTS
(3) CAPITAL CHARGES
G & A, Taxes, and Insurance*:
Interest on Working Capital
Capital Recovery Charges
TOTAL CAPITAL CHARGES
TOTAL ANNUALIZED COSTS (Direct Operating Costs + Indirect Operating
Costs + Capital Charges)
Estimated as 30% of the sum of Direct Labor and Supervision.
Estimated as 26% of the total of Direct Labor, Supervision, Maintenance
Labor, and Maintenance Materials.
Estimated as 4% of the Total Capital Cost.
Estimated as i% of the Working Capital where i is the interest rate.
Estimated as Capital Recovery Factor (CRF) x Total Capital Cost with the CRF
calculated as follows: ./, . .*n . . . .. . ^
CRF = 'd + 1) where i is the interest rate and
(1 + i)n-l n 1S the useful llfe of tne equipment.
8-21
-------
Utility and unit operating costs used in this document are presented in
Table 8-9. The fossil fuel prices listed in this table do not include
transportation costs; however, the impact of transportation costs is
analyzed in Section 8.1.2. The fuel prices reflect 1978 prices in 1978
dollars.
8.1.2 New Facilities
This section presents the costs for new boiler/emission control
systems. Sections 8.1.2.1 and 8.1,2.2 respectively discuss capital costs
and annualized costs.
8.1.2.1 Capital Costs. Capital costs for the model boilers are
summarized in Table 8-10 and are graphically portrayed in Figures 8-1, 8-2,
and 8-3. The capital costs are reported both in total dollars and in
dollars per unit capacity. These costs are discussed below by fuel type.
The discussion emphasizes the comparison of costs for alternative control
levels to costs for the baseline control level.
8.1.2.1.1 Wood-Fired Boilers. Capital costs for wood-, HAB-, or
SLW-fired boilers controlled to PM Control Level I are 1.8 to 3.8 percent
greater than costs for boilers controlled to the baseline level. Boilers
controlled to PM Control Level II are 3.2 to 21.8 percent more costly than
boilers controlled to the baseline level.
As shown in Figure 8-1, model boiler costs on a unit capacity basis
decrease with system size due to boiler and emission control economies of
scale.
Figure 8-2 shows that HAB-fired boilers and SLW-fired boilers are
slightly more expensive than wood-fired boilers of similar sizes. Both
HAB-fired and SLW-fired boilers have higher uncontrolled PM emissions than
wood-fired boilers and thus require more efficient and expensive control
systems. SLW-fired boilers also have greater costs because of their
requirement for corrosion-resistant construction materials and high scrubber
pressure drops.
Wet scrubbing systems generally have the lowest capital costs unless
corrosion-resistant construction materials are required. Fabric filters
have the next lowest capital costs for small boilers (<32 MW on a heat input
8-22
-------
TABLE 8-9. UTILITY AND UNIT OPERATING COSTS, MID-1978 $ BASIS
(1) Utility Costs
- Electricity $0.0258/kwh
-Water $0.040/m3($0.15/103 gal)
(2) Raw Material and Labor Costs
- Sodium carbonate $0.10/kg ($ 90/ton)
- Lime $0.04/kg ($ 35/ton)
- Operating labor $12.02/man-hour
- Supervision $15.63/nan-hour
- Maintenance labor $14.63/man-hour
(3) Fuel Costs5
- No.2 Distillate Oil $2.8/GJ ($3/106Btu>
- High Sulfur Eastern Coal $0.70/GJ ($0.74/10gBtu)
- Low Sulfur Western Coal $0.40/GJ ($0.42/10fiBtu)
- Refuse Derived Fuel $0.47/GJ ($0.50/10°Btur
- Other Nonfossil Fuels no cost
(4) Solid and Sludge Disposal Costs (Landfill)6
- Wood-fired boilers (all sizes) $0.022/kg ($20/ton)
- Wood/coal cofired boilers $0.022/kg ($20/ton)
(44 MW or 150 x 106Btu/hr)
- Wood/coal cofired boilers $0.Oil/kg ($107ton)
(117 MW or 400 x 106Btu/hr)
- RDF/coal cofired boilers $0.014/kg ($12.50/ton)
(44 MW or 150 x 106Btu/hr)
- MSW-fired boilers fi $0.025/kg ($22.507ton)
(2.9 MW or 10 x 10°Btu/hr)
- MSW-fired boilers fi $0.014/kg ($12.50/ton)
(44 MW or 150 x 10°Btu/hr)
- MSW-fired boilers fi $0.010/kg ($9/ton)
(117 MW or 400 x 10°Btu/hr)
- Bagasse-fired boilers $0.Oil/kg ($10/ton)
(200 x 106Btu/hr)
8-23
-------
TABLE 8-9. (CONTINUFD)
(5) Credits for Not Landfill ing MSWe
- 2.9 MW or 10 x 106 Btu/hr
- 44 MW or 150 x 106 Btu/hr
- 117 MW or 400 x 106 Btu/hr
$0.014/kg ($12.50/ton)
$0.010/kg ($9/ton)
$0.010/kg ($9/ton)
Except as noted, costs are based on PEDCo's Population and Characteristics
of Industrial/Commercial Boilers in the U.S.
bFuel prices do not include transportation costs; the impact of transportation
costs is analyzed in Section 8.1.2.
cThe assumed RDF sale price is insufficient to cover expected production
costs. The assumed RDF sale price is based on the sale price of high
sulfur eastern coal, discounted at 30 percent, as discussed in Refuse-
Derived Fuel and Densified Refuse-Derived Fuel.
For many companies nonfossil fuels may have a value greater than zero.
However, for this analysis the conservative approach is to assign no cost
to the fuel. This approach reduces the uncontrolled boiler cost thereby
increasing the impact of emission control costs.
eUnit landfill costs and credits are based on the unit costs and credits
in EEA's Estimated Landfill Credit for Non-Fossil Fueled Boilers. The
costs for each boiler are based on the smallest-size landfill capable of
absorbing ash and sludge from each model boiler. On-site landfills are
assumed for all boilers except MSW-fired and RDF/coal cofired boilers. MSW
and RDF/coal boilers feature off-site disposal 25 miles from the boiler
operation.
8-24
-------
TABLE 8-10. CAPITAL COSTS OF MODEL BOILERS, MID-1978 $ BASIS
Mil tolltr
•nktr
U
It
le
Id
|
3c
3d
3f
4i
4c
4d
4o
4f
51
a,
Sc
fc
a
6e
7.
7c
7d
7.
7f
'9
81
01
8c
ft)
Bt
8f
>9
tolltr Cituclty
Ml
8.8
22.0
44.0
117
44.0
44.0
44.0
44.0
loHtv/nr
30
75
150
400
ISO
150
ISO
150
r»i'
Hood
Hood
Hood
HOOd
KM
SLH
751 Hood/
25SH5E
501 Hood/
SOI Hit
Coatn*1 ' ••••i"
8
I
II
II
U
II
II
11
II
(
II
II
II
II
8
II
11
II
II
,
I
II
B
I
II
B
1
I
11
II
II
II
B
I
1
1
II
II
II
%
1
I
II
billion
Control Syito.1
NC
K,HS
"C .US
NC.FF
NC4S»
NC
NCJB
NC.W5
NC.FF
xcjcsr
NC.ECB
NC
NCJIS
NCJB
rtssr
icila
NC
NCJIS
NCJS
NC.Ff
NCJESP
mjta
NC.HS
NCJIS
NC.FF
NCJIS
NC.FF
NCJIS
NCJIS
NC.FCO-HS
NC.FF
NC.FCO-DS.FF
MC.ESf.FOMf
HC.FCO-HS
NC.FCO-HS
NC.F6B-HS
MC.F60-KS
HC.FSO-OS'.FI
NC.F60-OS.FF
NC.ESr.FBMC
tolltr
1800
1800
1900
1800
1800
3660
16(0
1660
3660
3660
1660
CI10
(130
(130
6130
6130
6130
3.500
3,500
3.500
13,500
11,500
3.500
6210
6230
6210
6110
(110
(110
6870
6870
6870
6870
6870
6870
(870
7510
7510
7510
7510
7S10
7510
7510
m»»iv»
Control
98.3
164
399
91
512
158
565
619
771
978
990
111
890
1039
1169
1109
1092
(71
1701
1029
1044
2634
2470
922
951
1380
1147
1420
1193
921
1077
18(1
1311
1171
1884
2591
1(44
1797
2002
2061
1748
1958
2718
00
roui
1999
2164
2189
2191
2112
1818
4225
4279
4411
4(18
4550
6441
7010
7169
7498
7419
7222
14.171
15.201
15.429)
16.544
16. 114
15.970
7052
7181
7610
7277
7550
7511
7791
7947
8711
8181
8241
8754
94(3
9154
9107
9512
9571
9258
9469
0.248
Unit T
S/(!OW)
TI.'OOO
71.000
77.100
50.900
56.100
57.100
59.100
(1.800
60.700
42.900
46.700
47.800
50.000
49,600
48.100
15.400
18.000
18,600
41.400
40.100
19.900
47.000
47.900
50.700
48.500
50.300
50.100
51.900
53.000
59.200
54.500
54.900
59.400
63.100
61.100
62.000
61,400
63,900
61.700
63.1CO
68.JCO
XII
SAX
ill
249
249
263
174
192
195
202
211
207
144
159
163
170
1(9
164
121
129
112
141
138
116
160
161
171
165
172
171
177
181
198
186
187
199
215
208
212
216
218
210
215
231
Ul Cwlul C
S/(IoStu/h)
97.000
111.000
112.000
112,000
119.000
78 400
86.800
87,900
91,000
95,200
91.400
(6,100
71,900
76! 300
74,100
51 500
St. 500
59.100
(3,600
62,100
61,400
72,100
71,700
79.100
74,600
77,400
77.100
74.900
76,400
94.000
78.700
79.200
84,200
91,000
81.200
84. (00
86.500
87,000
84,200
86.100
91,200
J/UI
113
180
384
184
406
267
296
299
310
124
318
225
245
251
262
2(0
251
186
200
201
217
212
210
247
251
266
254
2(4
261
256
2(1
287
2(9
271
788
311
285
290
296
298
288
295
319
""" —
J/llo'lbl ItOM/l)
97.000
110,000
112.000
112.000
118,000
77.900
86.200
87.300
90,500
94,700
92,900
65. (00
71.400
73,000
76.400
75.800
73.500
(3.600
68,200
(9.200
74,200
72.300
71.600
71.800
73,100
77,500
74.100
76,900
76,500
74.200
75.700
81.200
77.900
78.500
81.400
90.100
82.500
81,800
85.700
96.200
83.400
95.100
92,100
Increnmul
I Over
Uncontrollid tollir
5.4
20.2
21. (
21.7
29.4
4.3
15.4
15.9
21.1
26.7
24.1
5.1
14.4
16.9
22.1
21.4
17.9
5.0
12.6
14.1
22.5
19.5
18.3
13.2
15.3
22.2
18.7
23.2
22. (
13.4
15.7
27.1
19.1
20.0
27.4
37.7
21.9
21.9
26.7
27.4
23.3
26.1
J6.S
Costs
I 0»o.
Bisillno Bolltr
0
14.0
15.1
15.4
21 8
0
10.7
12 1
16.1
21.5
19.2
0
8 8
11.3
16.4
15.5
12.1
0
7.3
8.9
15. 7
13.8
12.7
0
1.8
7.9
0
3.8
3.2
0
2.0
12.1
5.0
5.8
12.4
21.5
0
1.7
3.9
4.6
1.1
1.4
12.0
00
I
in
SM footnout it ond of tibli.
-------
TABLE 8-10. (CONTINUED)
*xkl Bolllr
tattr
91
9b
9e
9d
101
lOb
Idc
lOd
IM
lOf
lOg
ion
111
lib
lie
1U
111
I2>
la
I2c
111
13)
13e
141
1*
14c
IS.
ISb
Bolltr Cipicltr
(Thlmll Input Bull)
Ml
117
44.0
44.Q
2.9
44.0
117
S8.6
tOBBtu/nr
100
ISO
ISO
10
ISO
400
200
Full*
SOIttooV
SOt HSC
SOI Hood/*
SOI 19
WIH*/4
MI USE
KSV
KSK
IBH
BlglSfO
Contre
PH
1
1
11
11
I
1
|
1
II
11
II
11
I
I
1
II
11
1
1
II
B
I
11
I
|
II
B
1 Lm1b
T»2
B
I
I
11
B
I
|
II
B
B
I
II
B
I
11
1
II
>
B
B
B
B
B
B
B
B
B
B
billion
Control Syttor
nx.FHMis
HC,FCD-HS
KC.FGO-DS.FF
HC.ESP .FED-US
HC,»S
HC.US
NC.FCIMIS
HC.FHHIS
IC.FF
1C, ESP
HC.FSO-OS.FF
K.tsp/eo-ws
rMMIS
F6D-US
FSMIS
ESP.FCD-VS
ESP.FKMIS
.
US
FF
ESP
ESP
ESP
ESP
ESP
ESP
1C
US
, Up til Colt. 11000
Bollir
1C. 700
16,700
16.700
K.700
7780
7780
7780
7780
7780
7780
7780
7780
10.900
10.900
10,900
10,900
10,900
762
762
762
16,500
16.500
16,900
35,100
15,300
35,300
S450
S4SO
Wills..
Control
3355
3893
3733
SOU
907
1065
1709
1741
1165
1279
1614
2191
1B17
217]
2211
2537
2609
101
15B
1050
U3C
1167
1696
2181
29BS
402
1019
Totll
20,555
20,593
20.411
21.719
86B7
BB4S
9499
9521
9145
9059
9594
10.171
12,717
13,071
13.111
11.437
13,509
7U
B63
920
17. 510
17,63*
17,867
16.9*6
17.481
38.265
58S2
6469
Unit lotll ClDUll Cott
• Full In 1
I/lloHu/h)
51.400
51,500
51.100
54.300
57,900
59,000
61,300
61,500
61,000
60,400
64,000
67.800
B4.800
87,200
87,600
89.600
90.100
76,200
84.300
92,000
117,000
117.600
119.100
92.500
91.700
95.700
29.300
32, WO
ill
»/»»
176
176
175
1B6
197
201
216
216
208
206
218
231
289
297
299
105
»7
263
94
111
399
401
406
11<
120
327
100
111
Ste« Out till!
l/doSta/h)
70,400
70,500
70.000
74,400
79.000
80.400
86.300
86.600
83,100
82,400
87,200
92, SOD
112,000
115,000
115.000
118.000
119.000
119.000
157,000
167,000
167,000
168.000
170.000
132.000
114,000
117.000
48.800
54.100
1AW
241
241
239
254
271
276
296
297
285
282
299
317
381
393
391
402
405
476
539
575
570
573
SO)
4S2
4S8
467
166
1B4
l/(103lt>I ItlM/h)
61.900
82,000
81,400
86,500
78.300
79.700
85.500
85.800
62.400
81,600
86.400
91,600
122,000
128.000
126,000
129.000
130.000
138.000
156.000
166,000
183,000
164,000
186,0)0
154.000
1S6.0DO
159,000
51,300
St. MO
IncmtnU
<0»tr
Uncontrolled Bollir
23.1
23.3
22.4
10.1
11.7
11.7
22.0
22.4
17.5
16.4
23.3
10.8
16.7
19.9
20.5
21.1
21.9
0
11.1
20.7
6.4
6.9
8.1
4.8
6.2
B.I
7.4
19.1
Cottl
I Over
BKillne Bolltr
0
0.2
-0.6
5.7
0
1.8
9.2
9.6
5.1
4.1
10.4
17.1
0
2.8
1.1
5.7
6.2
0
11.1
20.7
0
0.5
1 8
0
1.1
l.S
0
10.9
00
ro
•wood - bog foil (md/birk oriitura)
HAB - Men iin birt
SU - utt-l«dtn «>od
HSE - high wlfur ontora coll
LSV - Ion sulfur ntsttrn coil
IDF - nfuit dtrlnd full
HSU - Mnlclpil solid mitt
bB nfin to biellnf Control Lml.
I nftn to Control Lntl I.
II nftn to Control Lntl II.
CK - oKhulctl colltctor
US - Mt scntttr
FF - fibrlc rilttr
ESP - tltctmuttc prtcloltltor
£68 - tltctraiUtlc (•«•! bti rilttr
FBMIS - flM 911 dtmirurliitlon; doubll ilktll or 1lM Mt scnMtr
FCO-OS . flul 9" dmUtrllitlon: 1IM dry scrabbtr
Control nsttM llpiraUd by t COMI Min Hut both in lotd It Hit SIM tlM, not thtt tlthtr My bt in« li
Htckulul nlltcton m Includtd for fly iih nlujtctlon on ill of Hit bo 11 in firing nood.
'*mngt full itibin on i hut Input bisls.
*0nly t portion of Hit flM tjs Is scrubbtd.
illy.
-------
- 80.000
00
ro
10 Btu/hr 50
Model Boiler No. 1
Figure 8-1. Unit total capital costs of wood-fired boilers,
mid-1978 $ basis.
- 70iOOO
- 60,000
O = UNCONTROLLED BOILER
O • "C
O " HC/WS
MC/FF
HC/ESP
HC/EGB
CONTROL LEVEL I
CONTROL LEVEL II
BASELINE
- 50,000
- 40,000 i
- 30,000
-------
275
250
•2 225
= Uncontrolled Boiler
O" MC
O = HC/HS
• - MC/FF
~~ O • HC/EW
• • MC/FGD-HS
A- MC/ESP
A-MC/FGD-DS/FF /( , ||/||V -
V • HC/ESP/FGD-WS
0 = Baseline Control Level |/||B All/1
| = Control Level 1 rj iilii 1 1/I^E1^1 l/HHl/l
|| -Control Level 11 VI I/ II '^B/B
X/Y: X = PH Control Level ^ H;!^ "/^M/B
Y - S0? Control Level I'/1*,/, I/B§B^~
HAB « High Ash Bark •'/' UtyP
SLH - Salt-Laden Hood • I I/ft
HSE • High Sulfur Eastern Coal II/BA
LSW - Low Sulfur Western Coal OI/B
E/BO O
•II/B !!/&• I/BQ A» O ~
1 1 /H fTt j >< I/O
* >< 1 /n R/R^J
°
QB/B
o o o
-
70,000
—1
|
f-
o
eo.ooo q
?
O
O
w
*•««.
°°
50,000 ^
3-
-1
-n
r-
TO
40,000 5
Fuel Type
Model Boiler No.
Wood
3
HAB
5
SLW
6
75* Wood/25* HSE
7
SOt Wood/SOT HSE
8
50% Hood/50% LSW
10
Figure 8-2. Unit total capital costs of 44 MW (150 x 10 Btu/hr) boilers
firing various wood fuels and wood/coal combinations,
mid-1978 $ basis.
-------
400--
375
S
350
I
325
300
275
250
X/Y
O Uncontrolled Boiler
O- FGD-WS
•* ESP/FGD-WS
D= WS
•~ FF
Aa ESP
8 Baseline Control Level
I - Control Level I
II = Control Level II
X = PM Control Level
Y = S02 Control Level
MSW = Municipal Solid Waste
RDF = Refuse Derived Fuel
HSE - High Sulfur Eastern Coal
i
1/1
'11/11
l/ll
I-II/B
DI/B
A !/£>
A B/B
>
O
i
120,000
110,000
S
100,000 2
o
tn
90,000
?
80,000
Model
Boiler No.
Fuel Type
Capacity,MW
lO^Btu/h
11
50* RDF/
50% HSE
44
150
12
MSH
2.9
10
13
MSW
44
150
14
MSW
77
400
Figure 8-3. Unit total capital costs of model MSW-fired and
RDF/coal cofired boilers, mid-1978 $ basis.
8-29
-------
basis) while electrostatic gravel-bed filters have the next lowest capital
costs for larger boilers (>32 MW). Electrostatic precipitators are less
expensive than fabric filters for larger boilers (>32 MW).
8.1.2.1.2 Wood/Coal Cofired Boilers. Wood/coal cofired boilers
controlled to PM Control Level I (with S(L controlled to the baseline level)
show incremental capital cost impacts similar to those discussed above for
wood-fired boilers. Boilers controlled to PM Control Level I are 1.7 to
2 percent more expensive than boilers controlled to the baseline level.
Boilers controlled to PM Control Level II (with SOp controlled to the
baseline level), are 1.1 to 5.8 percent more costly than boilers controlled
to the baseline level, depending on the type of emission control system
employed.
Boilers controlled to Control Level I for both S02 and PM are 0.2 -
12.1 percent more costly than boilers controlled to the baseline level.
Boilers controlled to Control Level II for both SOp and PM have capital
costs 5.7 to 21.5 percent greater than boilers controlled to the baseline
level. For both of these control situations, the greatest incremental
capital costs occur when the baseline control level requires no control of
SOp. The high incremental cost is thus due to the installation of equipment
not needed to achieve baseline levels (e.g., raw material handling and
regeneration modules).
For boilers of similar size, unit capital costs are greater for model
boilers cofiring a 50/50 mixture of wood and high-sulfur eastern coal (HSE)
than for model boilers firing a 75/25 mixture. The cost difference is
mainly due to the increased cost of SOp control when more coal is fired.
Despite their lower emission control costs, boilers cofiring a 50/50
mixture of wood and low-sulfur western coal (LSW) are only slightly less
expensive than boilers firing a 50/50 mixture of wood and HSE, and are more
expensive than boilers firing a 75/25 mixture of wood and HSE. The
relatively higher costs for boilers firing LSW and wood are due to higher
uncontrolled boiler costs.
The model cofired boilers controlling both PM and S02 are more
expensive than wood-fired boilers of similar size due to multiple fuel
8-30
-------
feeding systems and the use of S(L control systems. Cofired boilers
controlling only PM are more expensive than their wood-fired counterparts
due to multiple fuel feeding systems and the use of corrosion-resistant
construction materials (for scrubbers).
8.1.2.1.3 RDF/Coal Cofired Boilers. RDF/coal cofired boilers
controlled to Control Level I for both SCL and PM have capital costs
2.8 percent greater than boilers controlled to the baseline control level.
Boilers controlled to Control Level II for both S0? and PM have capital
costs 6.2 percent greater than boilers controlled to the baseline control
level.
The model RDF/coal cofired boilers have higher emission control costs
than MSW-fired boilers of similar size due to the use of SC^ control systems
in the cofired boilers. The uncontrolled RDF/coal boilers are less
expensive than the uncontrolled MSW-fired boilers due to differences in
facility scope: The RDF/coal cofired boilers are used in industrial
settings and share support facility costs with other plant operations.
Costs for the MSW-fired boilers do not allow a similar sharing of support
facility costs and additionally include equipment not used in an RDF/coal
cofired facility.
8.1.2.1.4 MSW-Fired Boilers. Large mass-burn type MSW boilers
controlled to PM Control Level I have capital costs 0.5 to 1.3 percent
greater than boilers controlled to the baseline level. Mass-burn boilers
controlled to Control Level II have capital costs 1.8 to 3.5 percent greater
than baseline boilers.
Small modular boilers show more significant impacts, with boilers
controlled to PM Control Level I costing 13.3 percent more than boilers
controlled to the baseline control level. Small modular boilers controlled
to PM Control Level II cost 20.7 percent more than boilers controlled to the
baseline level. These boilers can achieve the baseline level without any
particulate matter controls. The high incremental costs are thus due to the
installation of equipment not needed to achieve baseline levels.
The small modular boilers have lower unit capital costs than the large
mass-burn type boilers due to differences in facility scope and to
8-31
-------
differences in boiler design. The large mass-burn boilers, for example,
feature more heat exchange surface than the modular boilers to achieve
greater heat recoveries.
8.1.2.1.5 Bagasse-Fired Boilers. Bagasse-fired boilers controlled to
PM Control Level I have capital costs 10.9 percent greater than the baseline
boilers. Control Level I requires the use of a wet scrubber while the
baseline control level can be attained through the use of a mechanical
collector.
8.1.2.2 Annualized Costs. Annualized costs for the model boilers are
summarized in Table 8-11 and graphically portrayed in Figures 8-4, 8-5, and
8-6. The annualized costs are reported both in total dollars per year and
in dollars per unit energy input or output. These costs are discussed below
by fuel type.
8.1.2.2.1 Wood-Fired Boilers. Annualized costs for wood-, HAB-, or
SLW-fired boilers controlled to PM Control Level I are 2.0 to 8.9 percent
greater than costs for boilers controlled to the baseline level. The
incremental costs for Control Level I for wood-fired boilers are higher than
those for HAB- or SLW-fired boilers. This is because wood-fired boilers use
mechanical collectors for baseline control and HAB- and SLW-fired boilers
use wet scrubbers. Wood- and HAB-fired boilers controlled to PM Control
Level II are 3.0 to 12.0 percent more costly than boilers controlled to the
baseline control level; the incremental costs vary with boiler size and type
of emission control.
SLW-fired boilers controlled to PM Control Level II have annualized
costs 0.7 percent less than boilers controlled to the baseline level.
Because of the high pressure drop needed for particulate removal and because
the scrubbers must be constructed of expensive, corrosion- resistant SS316,
fabric filters achieving the stringent control level are less expensive than
scrubbers used for baseline. This outcome explains the growing use of
fabric filters on boilers firing this type of wood.
As shown in Figure 8-4, model boiler costs on a unit energy basis
decrease with system size due to boiler and emission control economies of
scale. Figure 8-5 also shows that HAB-fired and SLW-fired boilers produce
8-32
-------
TABLE 8-11. ANNUALIZED COSTS OF MODEL BOILERS, MID-1978 $ BASIS
Hadji JolIlT
Ii
ft
1C
Id
21
2c
2o
2f
U
A
k
M
lo
3T
4l
41
Sc
to
(c
7.
ft
7c
7d
7<
7f
7l
(i
(b
(c
(d
8t
8f
89
(ollor C«o»c1tj
HI
1.8
22.0
44.0
117
44.0
44.0
44.0
44.0
toHtg/hr
30
75
ISO
400
ISO
ISO
ISO
ISO
FW1*
Hood
Hood
Hood
Hood
HM
SU
TSIHood/
251 IBE
50( Hood/
SOI IBE
Wl1
ij
1
II
1
Ii
,i
,1
I
U
b
"1
1
II
(
II
billion
Control Syite**
nc
IC.KS
K.FF
K.ES>
K
IfJK
PC.FF
tcjesr
icjea
1C
KM
SJFF
K.ESP
K.ECB
K
KM
KM
K.FF
K.ESP
K.EC1
KM
PCJIS
IC.FF
KM
PCM
PC.FF
KM
W.HS
K.FOMIS
1C .ESP
PC.FF
K.FCO-OS.FF
HC^IP.FSO-W
K.FOMO
K.FBD-HS
K.FOMIS
K.FOMIS.
IC.FSO-05*.FF
NCJTO-OS.FF
VlMll
(oiler
Ml
Ml
Ml
Ml
Ml
14(9
14(9
1469
14(9
1469
2171
2171
2173
2173
2173
2171
45(1
45(1
4561
45(1
4S61
4S61
2210
2210
'2210
2171
2171
2173
24(7
2467
2467
2467
24(7
24(7
24(7
2712
2712
2712
2712
Z712
2712
2712
od Colt.'
Control
SS.8
116
147
127
140
(7.1
240
256
241
129
111
92
1(0
J36
303
2(8
70S
827
8(8
701
(92
323
373
399
411
498
323
377
786
319
385
753
968
695
746
868
907
69S
816
10(1
1008
ToUl
897
977
988
9(8
981
1S56
1721
1709
172S
1712
2302
2504
2565
2551
2509
2476
4(51
5268
SMO
5431
5271
5255
2533
2809
2SM
2(71
2S6S
2790
2844
1253
2806
2852
3220
343S
1407
1458
35(0
1619
3407
3S28
1771
Unit Tout Anmillttd Cost
5.69.
(.20
(.27
(.14
(.22
1.95
4.10
4.37
4.M
4.38
4.34
2.92
l.U
1.2S
3.24
1.18
1.14
2.11
t.Sl
2.S6
2.S8
2.51
2. SO
1.21
1.28
3.11
3.28
3.19
1.25
1.54
1.61
4.13
3. 56
3.62
4.08
4.36
4.32
4.39
4.S4
4.59
4.32
4.47
4.79
I/U
5.J9
5.87
5.94
5.82
5.90
3.74
4.08
4.14
4.11
4. IS
4.12
2.77
1.01
1.08
1.07
1.02
2.98
2.19
2.38
2.43
2.4S
2.38
2.17
1.0S
1.11
1.14
1.11
3.21
1.08
1.15
3.42
3.91
1.37
1.41
1.87
4.11
4.10
4.16
4.10
4.35
4.10
4.24
4.54
s/lioHto)
8.75
9.S3
9.M
9.44
9.57
(.08
(.(2
(.72
6.68
(.74
(.69
4,45
4.89
5.01
4.98
4.90
4.83
3.S5
3.8S
3.94
1.97
1.86
1.8S
4.94
5.04
5.09
S.04
S.21
5.01
5.10
5.20
S.9S
5.11
S.22
5.89
(.28
S.89
5.98
6.19
6.26
5.89
(.10
6.51
»/SJ
(.10
9.04
9.14
8.95
9.07
5.76
(.28
(.37
(.11
(.19
(.14
4 26
4.63
4.74
4.72
4.64
4.58
1.36
3.65
3./4
1.77
1.66
3.64
4.69
4.76
4.81
4.78
4.94
4.74
4.84
4.93
5.64
4.87
4.95
S.58
5.96
S.S9
S.67
5.87
5.93
5.59
5.78
6.19
(.71
9.48
9.S9
9.40
9.52
6.M
6.58
6.68
6.64
(.70
t.65
4.46
4.85
4.97
4.95
4.86
4.80
4.14
4.49
4.60
4.63
4.50
4.48
4.91
5.00
5.05
S.01
S.17
497
S.06
S.IS
S.89
5.08
S.17
5.81
6.22
5.M
5.93
(.14
(.20
S.M
(.05
6.47
IllU OMt»l COItl
I Onr
UKontrollod (ollor
6.7
16.2
17.5
1S.1
16.6
S.9
U.4
17.2
16.3
17.4
16.5
S.9
1S.2
11.0
17. S
15.5
13.9
6.3
IS. 5
U.I
19.0
1S.S
1S.2
14.1
16.9
18.1
18.9
22.9
18.0
13.1
IS. 3
11.9
13.7
15.6
JO. 5
19.2
25.6
27.5
32.0
13.4
25.6
30.1
19.1
I0nr
(•ultno (ollor
(°,
10.1
7.9
9.4
0
8.9
10.6
9.1
10.1
10.0
8°.
11.4
10.9
9.0
76
ll.l
12.0
8.7
8.3
0
2.0
1.0
0
1.4
-0.7
0
1.9
16.6
0.6
2.2
IS. 4
21.1
0
l.S
S.I
(.2
0
3.6
10.7
c»
I
CO
CO
SM fooMoto it md of uolt.
-------
TABLE 8-11. (CONTINUED)
Model Boiler
Nurcer
9«
9b
9c
9d
lOa
ICb
lOc
lOd
lOe
lor
10,
lOh
til
lib
lie
lid
lie
12i
1%
I2c
131
III
l!c
1*1
I4b
I4c
151
156
Qoiler Capacity
(Them*) nput 9asls)
tw
11?
44.0
44.0
2.9
44.0
117
SO. 6
lO^lu/hr
400
ISO
150
10
ISO
400
200
Fuel'
so: uood/d
SO! KSE
SOt Uood/d
so: LSU
505 HOF/"
so: HSE
HSU
HSU
HSU
Blgisse
Contro Le»olb
PTI
B
[
II
II
9
I
I
II
II
II
II
„
1
1
11
11
9
1
II
a
i
11
«
I
II
e
1
S'J;
9
1
|
II
9
«
1
II
9
9
1
II
8
1
II
1
II
9
9
9
9
9
9
9
9
9
e
9
tiUtlon f
Control jrltf-i
HC .FI50-US
tit .F5D-US
HC.FHO-OS.FF
HC .ESP .FCD-WS
MC.US
HC.US
HC .FGO-US
HC .FGO-US
HC.FF
KC.ESP
HC.FGO-OS.FF
HC.ESP.FGO-WS
fCO-WS
FCO-WS
FCO-WS
ESP.FCO-US
ESP .FGO-US
US
FF
ES'
ESP
ESP
ESP
ESP
ESP
KC
US
Annual 17
Roller
5899
58"9
5899
SS99
2517
2617
2617
Ml 7
2611
2617
2617
2617
3468
3168
1468
3468
3'68
212
212
212
1667
1667
1667
3056
30S6
3056
1597
1S97
rd Cost,' <1"00
l-itislon
Control
1190
1416
1313
1741
311
365
720
733
381
333
709
890
755
896
931
964
1002
71
7«
171
269
134
4«6
574
723
its
370
Total
7279
7315
7212
7640
2928
2982
3337
3350
2998
»50
3326
3507
4223
4364
AW9
4432
4471
212
283
288
1939
1956
2031
i!ir
•ejo
3779
17JO
1967
Unit Total nnnu*M:*d Colt
Fuel In Basil
!/(l06Btu)
3.46
1.48
3.43
3.63
3.71
1.78
4.23
4.25
3.80
3.74
4.22
4.45
5.36
S.S4
5.59
5.62
5.67
4.03
S.38
5.48
2.46
2.48
2.54
i.ca
1.7;
1.00
2.21
2.4}
t/GJ
1.2B
3.30
3.25
3.44
1.52
3.59
4.01
4.03
3.60
3.55
4.00
4.22
S.08
5.25
5.29
S.33
5.37
3.82
5.10
5.19
2.33
2.35
2.41
1 «0
1.54
1.70
2.09
2.36
5t*ar, Out Basil
i/lio'lla)
4.74
4 77
4.10
4.93
S.06
5.16
5.77
5. 79
5.19
S.10
5.75
6.07
7.05
7.28
7.34
7.40
7.46
7.33
9.79
9.96
3.51
3.54
3.61
2.41
2.47
2.57
1.68
4.16
!/<••>
4.50
4.S2
4.45
4.72
1.80
4.89
5.47
5.49
4.92
4.84
5.45
5.75
6.68
6.90
6.96
7.01
7.07
6.95
9.28
9.44
3.33
1.36
3.44
2 28
2.34
2.43
3.49
3.94
S/llo'lbi SUM)
5. 52
5.54
5.47
5.79
5.02
S.ll
5.72
5.74
5.14
5.06
5.70
6.01
7.73
7.98
8.05
8.11
8.18
7.28
9.72
9.89
3 84
3.88
3.J7
2.80
2.B7
2.W
1.87
4.18
IncrenentJll Coll!
I Over
Uncontrolled Boiler
23.4
24.0
22.3
29.5
11.9
13.9
27.5
28.0
14.6
12.7
27.1
34.0
21.8
25.8
26.8
27.8
28.9
0
33.5
35.8
16 3
17. J
20 0
15.9
18.8
23.7
9.0
23.2
: O.er
Baseline Boiler
0
0.5
•0.9
5.0
0
1.8
14.0
14.4
2.4
0.8
13.6
19.8
0
3.3
4.2
4.9
5.8
0
33.5
15.8
0
0 9
2 2
0
2 S
5.7
0
11.0
00
CO
"Mood - nog fuel (mod/blrk •liturc)
H«B . h!5h ish bart
SlU - silt-laden
-------
00
I
co
in
8 4
£ 3
o
Boiler Capacity
Model Boiler No.
HW
106Btu/hr
II I
14.fi
50
-L
29.3
100
0 - Uncontrolled Boiler
O - MC
O - HC/WS
• - MC/FF
A - MC/ESP
D - NC/EGB
| - Control Level I
II - Control Level II
g - Baseline
J_
_L
4-
44
150
58.6
200
73.3
250
88
300
_L
103
350
_L
117
400
o
|
r-j
m
8
Figure 8-4. Unit total annualized costs for wood-fired boilers,
mid-1978 $ basis.
-------
4.5
4.0
CO
I
05 3.S
fe
s
I-
i
3.0
Fuel Type
Model Boiler Ho.
V 11/11
^•Uncontrolled Boiler
A-
A-
y-
B -
I •
II
X/t
HAB
SLU
HSE
LSU
MC/FF
HC/ESP
MC/K6
K/FGO-US
NC/FGO-DS/FF
NC/ESP/FGD-US
' Baseline Control Level
Control Level I
- Control Level 11
X • PH Control Level
T - S0? Control Level
• High Ash Bark
• S*lt4.aden Wood
- High Sulfur Eastern Coal
• LOM Sulfur Western Coal
I/IIB
I I/I A
U/B
V 11/11
H/ljgl/U
l/I -
|/| •
A
"f>
"B?"7?
All/6
B/B©
• II/B
oafe
OB/6
o
o
4.0
3.5
3.0
2.5
Wood
3
1MB
5
751 Uood/ZSXHSE
7
501 Hood/501 HSE
50XWood/S.nLSH
10
Figure 8-5.
Unit total annualized costs of 44 MW (150 x 10 Btu/hr) boilers
firing various wood fuels and wood/coal combinations, mid-1978
$ basis.
-------
5.5
5.0
4.5
* 4.0
UJ
£
3
~ 3.5
5 3.0
1
2.5
2.0
1.5
^
I I/I
<||/l
OB/B
X/Y
O UNCONTROLLED BOILER
O- FGD-WS
• « ESP/FGO-WS
• • FF
A" ESP
B » Baseline Control Level
I • Control Level I
II • Control Level II
: X - PM Control Level
Y = S02 Control Level
MSW = Municipal Solid Waste
RDF - Refuse Derived Fuel
HSE - High Sulfur Eastern Coal
OB/B
A "'&
A ll&
,.
O
5.5
5.0
4.5
3.0
2.5
2.0
1.5
1
Model Boiler No.
Fuel Type
Boiler Capacity MM
(106Btu/h)
11
SOX RDF/
SOS HSE
44
150
12
MSW
2.9
10
13
MSW
44
150
14
MSW
117
400
<
>
Figure 8-6. Unit total annualized costs of model MSW-fired and
RDF/coal cofired boilers, mid-1978 $ basis.
8-37
-------
steam at only slightly higher cost than wood-fired boilers controlled to
similar control levels.
Of the four emission control systems capable of achieving PM Control
Level II (WS, FF, ESP, EGB), fabric filters are the least expensive option
for small boilers (<32 MW on a thermal input basis). Electrostatic
gravel-bed filters appear to be the least expensive control option for the
larger systems, but the reader should recognize that electrostatic
gravel-bed filtration is a developing technology whose costs and performance
are less certain than for the other technologies. Electrostatic precipi-
tators are the next least expensive control option for the larger systems.
8.1.2.2.2 Wood/Coal Cofired Boilers. Wood/coal cofired boilers
controlled to PM Control Level I (with SCL controlled to the baseline level)
show incremental annualized cost impacts less than those discussed for wood-
fired boilers because of the difference in the baseline control level.
Boilers controlled to PM Control Level I are 1.5 to 1.9 percent more
expensive than boilers controlled to the baseline level. Boilers controlled
to PM Control Level II (with SCL controlled to the baseline level) are 0 to
2.4 percent more expensive than boilers controlled to the baseline level,
depending on the type of emission control system employed. (The boiler
system achieving PM Control Level II at no incremental annualized cost uses
a dry scrubbing system for SCL removal to the baseline level. Since the dry
scrubbing system is less expensive than the wet scrubbing system used for
baseline SCL control, a more expensive PM control system can be used with
the dry scrubbing system without increasing the annualized cost relative to
the base case.)
Boilers controlled to Control Level I for both S02 and PM are 0.5 to
16.6 percent more costly than boilers controlled to the baseline level.
Boilers controlled to Control Level II for both S02 and PM are 5.0 to
23.1 percent more expensive than boilers controlled to the baseline level.
For both of these control situations, the greatest incremental annualized
costs occur when the baseline level requires no control of SO^. The high
incremental cost is thus due to the installation and operation of equipment
not needed to achieve baseline levels. The low incremental costs are
8-38
-------
associated with the 117 MW boilers which are subject to the existing NSPS
(40 CFR 60 Subpart D) which requires efficient S02 and PM controls at
baseline.
For the model wood/coal cofired boilers of similar size, unit
annualized costs are greatest for boilers cofiring a 50/50 mixture of wood
and HSE, mainly due to the cost of SO^ control. Of the model wood/coal
cofired boilers, boilers cofiring a 50/50 mixture of wood and LSW have the
lowest annualized control costs although total annualized costs are slightly
higher than the boilers cofiring a 75/25 mixture of wood and HSE.
8.1.2.2.3 RDF/Coal Cofired Boilers. RDF/coal cofired boilers
controlled to Control Level I for both S02 and PM have annualized costs
3.3 percent greater than boilers controlled to the baseline control level.
Boilers controlled to Control Level II for both pollutants have annualized
costs 5.8 percent greater than boilers controlled to the baseline control
level.
8.1.2.2.4 MSW-Fired Boilers. Large mass-burn type MSW boilers
controlled to PM Control Level I have annualized costs 0.9 to 2.5 percent
greater than boilers controlled to the baseline level. Mass-burn boilers
controlled to PM Control Level II have annualized costs 3.2 to 6.7 percent
greater than baseline boilers.
Again, small modular boilers show more significant cost impacts than
the large mass-burn boilers, with boilers controlled to PM Control Level I
costing 33.5 percent more than boilers controlled to the baseline level.
Boilers controlled to PM Control Level II have annualized costs 35.8 percent
greater than boilers controlled to the baseline level.
8.1.2.2.5 Bagasse-Fired Boilers. Bagasse-fired boilers controlled to
PM Control Level I have annualized costs 13.0 percent greater than the
baseline boilers.
8.1.2.2.6 Variability of Annualized Costs of Wet Scrubbers. The costs
presented in Table 8-11 for wet scrubbers are based on conservatively
designed systems. Therefore, the actual costs for new installations could
be considerably less than the costs shown in Table 8-11. For example, the
annualized cost of the wet scrubber emission control system for model boiler
8-39
-------
15b could potentially be 32 percent less than the cost shown if waste water
?fi
treatment is already available on-site. The annualized costs for the
combined mechanical collector/wet scrubber systems shown for model boilers
1-4 could potentially be 19 to 23 percent less depending on cost of waste
water treatment, solid waste disposal, and the type of mechanical collector
?fi
precleaner used. Some of these factors could also affect the costs of the
other types of controls shown in Table 8-11.
8.1.3 Modified/Reconstructed Facilities
Under the provisions of 40 CFR 60.14 and 60.15, an "existing facility"
may become subject to standards of performance if deemed modified or
reconstructed. In such situations control devices would have to be
installed for compliance with new source performance standards.
Due to special considerations, the cost for installing a control system
in an existing boiler facility is generally greater than the cost of
installing the control system on a new facility. However, since retrofit
costs are highly site-specific, they are difficult to estimate. Examples of
these site-specific factors are availability of space and the potential need
for additional ducting.
Configuration of equipment in the plant governs the location of the
control system. For instance, if the boiler stack is on the roof of the
boiler house, the control system may have to be placed at ground level,
requiring long ducting runs from the ground level to the stack. If the
available space at the plant is inadequate to accommodate the control
equipment, it may be necessary to install the equipment on the roof of an
adjacent building, thus requiring the addition of structural steel support.
It has been estimated that roof top installation can double the structural
costs for installation of the control system. Foundations and structural
support costs typically amount to 2-3 percent of the control system capital
costs.27
Other capital cost components that may increase because of space
restrictions and plant configurations are contractor and engineering fees
27
(typically 15-25 percent of the control system capital cost), construction
8-40
-------
and labor expenses, and interest charges during construction (because of
longer construction periods).
8.1.4 National Cost Impacts
Table 8-12 summarizes the nationwide cost impact in 1990 of applying PM
emission controls to new NFFBs to meet each of the PM emission control
levels. The cost impact resulting from any NSPS for nonfossil fuel-fired
boilers will be dependent on the control level required and the boiler
population affected. The boiler population growth estimates are based on
28
estimates of the growth of potential NFFB user categories.
As discussed in Chapter 6, the current PM emission regulations for
wood-fired boilers vary considerably from state to state. Therefore, a
varying mix of control methods will be used to meet existing regulations in
the absence of an NSPS. The two control methods typically used for wood-
fired boilers are mechanical collectors (MC) or mechanical collector/wet
scrubbers in series (MC/WS). The national cost of the Baseline Control
Level is based on the weighted average cost of these two systems.
The mix of these two systems is based on the percentage of each
required to produce a national emission level equal to the average of the
existing State regulations. To determine this mix, the MC systems were
assumed to have emission rates of 258 ng/J (0.6 lb/106Btu). A "typical"
MC/WS system used to meet existing state regulations is assumed to have an
emission rate of 86 ng/J (0.2 lb/10 Btu) and a pressure drop of 1.7 kPa
(7 inches w.c.) based on the data for low pressure drop scurbbers shown in
Figure 4.1-22 in Chapter 4. The costs of these MC/WS systems were developed
from the same cost bases used for the MC/WS costs shown in Table 8-11.
The national costs for Control Levels other than baseline for wood and
bagasse are based on MC/WS and WS control systems, respectively. The cost
ranges are due to the variability in scrubber costs discussed in
Section 8.1.2.2.6. For wood, the national costs for ESPs and fabric filters
would be expected to fall with the ranges shown for wet scrubbers.
8-41
-------
TABLE 8-12. NATIONAL EMISSION CONTROL ANNUALIZED COSTS FOR
NONFOSSIL FUEL FIRED BOILERS IN 1990a
Annualized Cost of Control Systems - 10 $
Fuel
Wood
GSWC
GSWC
b,f
,d
>e
f
Bagasse
Basel
60.6 -
26.
0
6.
ine
75.3
1
3
Control
74
10
.7
.9
_
30
29
™*
Level I
97
.2
.5
15
.3
.5
Control
88.3 -
37
31
~
Level I
112.6
.1
.6
I
The reported costs are the annualized costs of control for nonfossil
fuel-fired boilers potentially affected by New Source Performance
Standards. This would be the cumulative nonfossil fuel fired boiler
capacity installed in 1984 to the end of 1990. The costs are for the
emission control system only and are in mid-1978 dollars.
The national impact of emission control on wood-fired boiler costs is
estimated from the costs for model boilers firing "typical" wood fuels.
(The firing of other wood fuel types was evaluated in the model boiler
analysis to determine the sensitivity of emission control costs to wood
ash and salt contents.)
CGSW - general solid waste. This includes all municipal-type solid waste
fuels and refuse derived fuels.
Includes all MSW- and RDF-fired boilers except small modular units.
RDF-fired boilers are assumed to fire 100 percent RDF. The costs of
control for 100 percent RDF-fired boilers are assumed to be similar to
those for MSW-fired boilers based on the similarity of control equipment
design.
elncludes only small modular GSW-fired boilers.
fThe cost ranges are due to the variability in wet scrubber costs discussed
in Section 8.1.2.2.6.
8-42
-------
8.2 OTHER COST CONSIDERATIONS
This section addresses additional cost considerations that may be
incurred by boiler operators and/or regulatory agencies that have not been
addressed in Section 8.1. Additional cost impacts are likely in two areas:
- liquid and solid waste disposal, and
- impact of compliance and reporting requirements.
The major liquid and solid waste streams from an uncontrolled boiler
are: water softening sludge, condensate blowdown, bottom ash disposal, and
coal pile runoff. Bottom ash collection, handling, and disposal costs have
been incorporated into the uncontrolled boiler cost estimates. Bottom ash
disposal costs were estimated based on a non-hazardous waste classification
and RCRA regulations. If boiler wastes are classified as hazardous material
in the future, then the disposal costs and overall boiler control costs
could increase significantly.
Costs for treating the other three waste streams were not quantita-
tively evaluated in this study. The costs associated with the disposal
problems are highly site-specific, with the following parameters being
important:
- Water softening sludge - raw water quality, steam quality,
water makeup rate.
- Condensate blowdown - effluent discharge quality requirements,
raw water quality, condensate blowdown quantity.
- Coal pile runoff - coal quality, meterological conditions,
effluent discharge quality requirements.
However, these costs would be associated with the boiler itself and would
not affect the analysis of incremental cost impacts of air pollution
controls.
8-43
-------
8.3 REFERENCES
1. Draft memo from Murin, P., Radian Corporation, to file.
August 10, 1981. 61 p. Emission control specifications and model
boiler cost estimating.
2. Mcllvaine Scrubber Manual. 1974. Ch. VIII, p. 29.0.
3. Balakrishman, N.S. and Gregory Cheng. Particulate Control on Bark and
Bagasse Fired Boilers by Wet Scrubbers. Presented at the 73rd Annual
Meeting of the Air Pollution Control Association. June 22- 27, 1980.
13 p.
4. PEDCo Environmental, Inc. Cost Equations for Industrial Boilers.
Prepared for U.S. Environmental Protection Agency under Contract
No. 68-02-3074. January, 1980. 23 p.
5. Telecon, Murin, P., Radian Corporation with Dick Weber, Joy/Western
Precipitation Div. September 11, 1980. Multiple cyclone costs.
6. Telecon, Murin, P., Radian Corporation with Al Liepins, Flex-Kleen
Corp. September 19, 1980. Baghouse costs.
7- Telecon, Piccot, S., Radian Corporation with Steve Babiuch, Standard
Havens Co. September 11, 1980. Baghouse costs.
8. Telecon, Piccot, S., Radian Corporation with Wheelabrator-Frye, Inc.
September 12, 1980. Baghouse costs.
9. Neveril, R.B. (GARD, Inc.) Capital and Operating Costs of Selected
Air Pollution Control Systems. Prepared for U.S. Environmental
Protection Agency. Research Triangle Park, N.C. Publication
No. EPA-450/5-80-002. December 1978. p. 5-19 to 5-31.
10. PEDCo Environmental, Inc. Capital and Operating Costs of Particulate
Controls on Coal- and Oil-Fired Industrial Boilers. Prepared for
U.S. Environmental Protection Agency under contract No. 68-02-3074.
August, 1980. 129 p.
11. Letter, Pilcher, L., GCA to Jack Podhorski, Joy/Western Precipitation
Div. July 26, 1979. Impingement scrubber costs.
12. Reference 9, p. 5-9 to 5-18.
13. Dickerman, J.C. and K.L. Johnson. (Radian Corporation.) Technology
Assessment Report for Industrial Boiler Applications: Flue Gas
Desulfurization. Prepared for U.S. Environmental Protection Agency.
Research Triangle Park, N.C. Publication No. EPA-600/7-79-178i.
November, 1979. p. 5-5 to 5-10, Appendices A and B.
8-44
-------
14. Guthrie, K.M. (W.R. Grace & Company.) Data and Techniques for
Preliminary Capital Cost Estimating. Chemical Engineering. Reprint
from March 24, 1969 issue. 29 p.
15. Guthrie, K.M. Process Plant Estimating Evaluation and Control. Solana
Beach, California, Craftsman Book Company of America, 1974. pp. 157,
163, 169, 170, 176, 355-360.
16. Peters, M.S. and K.D. Timmerhaus. Plant Design and Economics for
Chemical Engineers, Second Edition. New York, McGraw-Hill Book
Company, 1958. p. 477.
17. Telecon, Murin, P., Radian Corporation with Heywood Bellamy for
Combustion Power Company, September 25, 1980. Electrostatic gravel -
bed filter costs.
18. Reference 9, p. 4-57 to 4-71.
19. Reference 9, p. 4-15 to 4-24, 4-28.
20. Richardson Engineering Services, Inc. Process Plant Construction
Estimating Standards, Volume 4. San Marcos, California, Richardson
Engineering Services, Inc., 1980. File 100-65. p. 1-11.
21. Reference 9, p. 3-12 to 3-18.
22. Energy and Environmental Analysis, Inc. Estimated Landfill Credit for
NonFossil-Fueled Boilers. Prepared for U.S. Environmental Protection
Agency. October 3, 1980. 38 p.
23. Devitt, T., P. Spaite, and L. Gibbs. (PEDCo Environmental, Inc.)
"Population and Characteristics of Industrial/Commercial Boilers in the
U.S." Prepared for U.S. Environmental Protection Agency, Research
Triangle Park, N.C. EPA-600/7-79-789a. August 1979. p. 116.
24. Reference 23, p. 124.
25. Renard, Marc L. Refuse-Derived Fuel (RDF) and Densified Refuse-
Derived Fuel (d-RDF). The National Center for Resource Recovery, Inc.
June 1978. p. 14.
26. Memo from Barnett, K., Radian Corporation, to file. March 24, 1982.
Costs of emission control systems.
27. Reference 9, p. 3-11, 3-7, 3-8.
28. Memo from Barnett, K., Radian Corporation, to file. January 27, 1982.
22 p. Projections of new nonfossil fuel fired boilers.
8-45
-------
29. Memo from Keller, L., and K. Barnett, Radian Corporation, to file.
March 17, 1982. 14 p. Statistical Correlation of Available MSW-Fired
Boiler Emission Data.
8-46
-------
9. ECONOMIC IMPACT
This chapter presents the background information and methodology for
determining the economic impact of a Federal emission standard on new
nonfossil fuel fired boilers (NFFB's).
The impact analysis focuses on the economic effects of Control Levels I
and II on selected industrial and municipal users. As it is not possible to
examine all the industries and municipalities that could exhibit an impact,
the users chosen for the analysis are the result of a screening process
designed to determine the industries and municipalities that could
experience the greatest potential adverse economic effects due to required
emission control.
This chapter is divided into two parts. The first section (9.1)
profiles the industries and municipalities that will be covered in the
economic impact analysis. The second section (9.2) covers the methodology
of the analysis as well as the results of the economic impact analysis.
9-1
-------
9.1 NFFB USERS
9.1.1 Industrial Users
This section profiles the five manufacturing industries selected for
analysis. These industries may experience product cost and profitability
impacts and capital availability constraints.
The change in producer price analysis compares the producer price of a
product under Control Levels I and II and under the existing State Imple-
mentation Plans (SIP's). Similarly, the change in profitability analysis,
return on sales and return on assets, measures these indicators under
Control Levels I and II and under the existing SIP's. Capital availability
constraints can occur when the costs of acquiring funds is so high that a
firm considers a project to be uneconomic or financially unattractive.
The following industries are profiled in Section 9.1:
• Wooden furniture manufacturing
• Sawmill lumber products
• Plywood panel products
• Paper and allied products manufacturing
• Raw sugar cane manufacturing.
Each of the industries selected presently burns nonfossil fuels for
part or all of its steam requirements. The selection of the waste-fired
industries is based on the amount of nonfossil fuel consumed relative to
total fuel consumption and the steam intensity of their production proces-
ses.
9.1.1.1 Furniture Manufacturing Industry.
9.1.1.1.1 Industry description. The wooden furniture industry seg-
ments considered in this description are wood household furniture (SIC
2511) and wood office furniture (SIC 2521). Primary emphasis will be
placed on household furniture since it constitutes the major share of
wooden furniture produced.
The wooden furniture industry consists of approximately 3,000 case-
goods plants out of a total of 5,000 wood and upholstered (with wooden
frames) household furniture plants. Of these 3,000 plants, no one plant
represents more than three percent of the market share. Approximately 50
percent of production capacity is concentrated in North Carolina, eastern
Tennessee, and southeastern Virginia. Tables 9-la and 9-lb list the lead-
9-2
-------
TABLE 9-la. WOOD HOUSEHOLD FURNITURE MANUFACTURING INDUSTRY
Firm ownership
Location of plants0
Sales in 1979 ($106) d
Furniture segment sales Total company sales
10
u>
American Furniture Co., Inc.
Armstrong Cork
Bassett Furniture Industries
Bernhardt Furniture Co.
Broyhill Furniture Industries
Burlington Industries
Dixie Furniture Co. Inc.
Drexel Heritage Furnishings, Inc.
(Champion International)
Ethan Allen
(Interco, Inc.)
Henredon
Lane Co.
Mohasco
Singer Co.
Virginia (9)
Mississippi, North
Carolina (19), Virginia (2)
Virginia (7), Georgia
NAe
NA
NA
NA
NA
California, Illinois,
Maine, Massachusetts (2),
New York (3), North
Carolina (4), Ohio,
Oklahoma, Pennsylvania (3),
Vermont (5), Virginia
NA
NA
NA
NA
71.4
201.2
272.1
NA
NA
151.9
NA
NA
160.8
NA
321.3
155.9
71.4
1341.0
272.1
NA
NA
2676.3
NA
3751.0
201.1
158.9
747.1
2599.0
-------
TABLE 9-la (Continued). WOOD HOUSEHOLD FURNITURE MANUFACTURING INDUSTRY3
b Sales In 1979 ($106) .
Firm ownership Location of plants0 Furniture segment sales Total company sales
Sperry & Hutchinson California, Illinois, 436.0 821.0
Minnesota, New York,
North Carolina (6),
Tennessee, Texas,
Virginia (4)
Stanley Furniture NA NA NA
(Stanley Interiors Corp.)
Southern Furniture Manufacturer's Association; Securities and Exchange Commission.
03 b
,iL Firms listed represent 15-20 percent of total sales. The top 30 companies manufacture $50-$60 million of
furniture.
c
The number in parentheses following State names denotes number of plants.
Sales may include some upholstered and metal furniture, home lighting, carpet, and yarn.
o
NA denotes not available.
-------
TABLE 9-lb. WOOD OFFICE FURNITURE MANUFACTURING INDUSTRY*
Firm ownership
Location of plants
Sales in 1979 ($10 )
Furniture segment sales0
Total company sales
10
01
Alma Desk
American Furniture Co., Inc.
Baker Furniture Co.
Bassett Furniture Industries
Drexel Heritage
(Champion International)
Ethan Allen
(Interco, Inc.)
Kimbel International
Mohasco
Stow & Davis
NAU
Virginia (9)
NA
Virginia (7), Georgia
NA
California, Illinois,
Maine, Massachusetts (2),
New York (3), North
Carolina (4), Ohio,
Oklahoma, Pennsylvania (3),
Vermont (5), Virginia
NA
NA
NA
NA
NA
272.1
NA
86.0
231.3
NA
NA
71.4
NA
272.1
3751.0
211.1
747.1
NA
aBusiness and Institutional Furniture Manufacturer's Association; Securities and Exchange Commission.
The number in parentheses following State names denotes number of plants.
°Sales may include some upholstered and metal furniture.
NA denotes not available.
-------
ing wooden furniture companies (both household and office), plant locations,
and sales. There are no accurate statistics collected on production of
wooden household furniture due to the amount of product differentiation and
the fragmentation of the industry as seen in Table 9-2a.
Table 9-2b shows production for all five groups of office furniture.
With the exception of modular service units in 1977, production of office
furniture has been increasing since 1975. Production figures are lower in
1975 than in the previous year due to the recession's impact on the furni-
ture industry. Production of tables has increased the most between 1975
and 1979. Forecasts estimate the compounded annual real growth rate for
2
the furniture industry from 1980 to 1985 will be 7.8 percent.
9.1.1.1.2 Economic characteristics.
Employment. Casegood furniture production is a labor-intensive pro-
cess. The maximum employment level per plant for optimal production is
400. Total employment for the household furniture industry was 308,400 in
1979.
Average hourly earnings for production workers in the household furni-
ture industry have increased consistently from $3.30 in 1974 to $4.39 in
1978. For production workers in the office furniture industry, average
hourly earnings in 1978 were approximately 15 percent higher than those in
the household furniture industry. Even though production workers in the
office furniture manufacturing industry receive higher average hourly
earnings, they are still low in relation to the average hourly earnings of
$6.17 for manufacturing as a whole.
Imports/exports. U.S. household furniture imports were $750 million
in 1979, up 21 percent over 1978 imports. During the period 1975 to 1979,
imports have been increasing annually by 17.6 percent, indicating a trend
toward increased import penetration in the domestic market.
Time series data. The financial analysis of the wooden furniture
industry is shown on Table 9-3. The leading manufacturers of wooden furni-
ture had an annual average sales of $787 million. The "average" casegood
plant is a much smaller, closely held company with sales of $5 million.
Profits for the industry ranged from a low of $12.5 million in 1975 to
a high of $27.9 million in 1976. The impact of the recession on consumer
spending can be seen in 1975. This drop is because furniture is a post-
ponable purchase.
9-6
-------
TABLE 9-2a. HISTORIC TRENDS OF PRODUCTION FOR WOOD HOUSEHOLD FURNITURE*
vo
Indicator
Producer price index
(1967 = 100)
Total value of shipments0
($10b)
Value of shipments/plant0
($10b)
1974
136.6
3381.0
NAd
1975
146.3
3095.4
NA
1976
153.6
3780. 1
NA
1977
162.2
4154.8
NA
1978
173.5
4820.0
1607.0
1979
186.3
5400.0
1800.0
aU.S. Department of Commerce. Bureau of Census. Bureau of Labor Statistics. Production figures for 1977 are
available but are partial and estimates.
The producer price index is the only valid indicator of price change since there are too many categories
and subcategories of furniture to quote.
""Dollar amounts are in nominal terms.
NA denotes information not available.
-------
TABLE 9-2b. HISTORIC TRENDS OF PRODUCTION FOR WOOD OFFICE FURNITURE*
ID
CD
Indicator
Production (103)
Chairs
Sofa group
Desks
MSUb
Table group
Producer price index
(1967 = 100)
Sales ($106)e
1974
1097.2
74.5
519.1
242.1
263.6
152.4
313.0
1975
983.3
55.2
384.9
219.8
244.6
166.7
292.0
1976
1191.6
60.1
457.2
276.3
283.1
173.5
335.0
1977
1355.9
88.1
644.0
204.9
566.0
185.9
551.0
1978
1360.9
98.4
689.6
191.4
648.8
201.5
687.0
1979
NAC
NA
NA
NA
NA
221.8
802.0
Business and Institutional Furniture Manufacturer's Association. U.S. Department of Commerce. Bureau of Census.
Bureau of Labor Statistics.
MSU denotes modular service units.
"NA denotes not available.
rt
The producer price index is the only valid indicator of price change since there are too many categories
and subcategories of furniture to quote.
Dollar amounts are in nominal terms.
-------
TABLE 9-3. FINANCIAL ANALYSIS — WOODEN HOUSEHOLD AND OFFICE FURNITURE
MANUFACTURING INDUSTRY
(Nominal Terms)
Financial
indicator
Capital expenditures
Total assets (106$)
Capital expenditures/
firm (10b$)
Capital expenditures/
total assets (%)
Profitability
Net profit after
taxes (10°$)
Return on assets (%)
Return on equity (%)
Return on sales (%)
Dividends ($/share)
Net earnings before
interest and taxes
(106$)
Capitalization
Interest on fixedfi
obligations (10D$)
Coverage ratio
Rating on bonds
Long-term debt (106$)
Stockholders' equity
(10b$)
Debt/capi tal i zati on
(%)
Debt/equity (%)
1974
NAb
NA
NA
NA
NA
NA
NA
1.16
NA
NA
NA
NA
NA
NA
NA
NA
1975
536.00
23.90
4.46
12.50
2.33
NA
1.61
0.67
36.40
12.21
2.98
NA
65.51
NA
NA
NA
1976
540.30
33.70
6.23
27.90
5.16
17.46
3.58
0.73
71.40
12.23
5.84
NA
65.89
159.79
29.90
41.24
1977
481. 80
40.50
8.41
26.70
5.54
16.04
3.48
0.84
71.67
12.85
5.58
NA
69.40
166.43
29.43
41.70
1978
444.60
43.40
9.76
27.50
6.19
15.44
3.33
0.98
81.70
13.64
5.99
NA
66.06
178.08
27.06
37.90
1979
NA
NA
NA
NA
NA
NA
NA
1.03
NA
NA
NA
Baa
NA
NA
NA
NA
Average
(1974-1979
501.70
36.40
7.26
23.70
4.81
16.31
3.00
0.90
66.29
12.73
5.21
Baa
66.72
168.10
28.41
39.97
'Average/firm estimates for model household and
Exchange Commission; EEA estimates).
JNA denotes not available.
office furniture (Securities and
9-9
-------
The net profit margin increased from a low of 1.6 percent in 1975 to a
high of 3.6 percent in 1976. Return on total assets has been increasing
since 1975 from a low of 2.3 to a high of 6.2 in 1978. Return on total
assets and return on net worth were approximately 2.2 percent lower for
A
wood household furniture as compared with wood office furniture. Capital
expenditures have remained fairly stable over the 1974 to 1979 period.
Return on equity has been decreasing since 1975, when it was 17.5.
Return on equity for wood household furniture was approximately half of
that for wood office furniture.
Stockholders' equity has been increasing from $160 million in 1976 to
$178 million in 1978. Long-term debt has remained relatively stable. The
furniture industry would finance future investments primarily with debt.
Ratings on bonds have averaged Baa, which represents a medium grade.
The value of shipments for wood household furniture has been increas-
ing steadily over the past six years, with only one exception in 1975. In
1979, value of shipments' for wood household furniture was $5,400 million, a
12 percent increase from the 1978 figures. However value of shipments
estimates for 1980 are targeted at $5,238 million, a three percent decrease
from last year. This decrease in value of shipments applies to all seg-
ments of the household furniture industry, and reflects inflation's effect
in reducing real personal income. The percentage decline in furniture
shipments is not as great, given the state of the economy, since furniture
prices during 1979 rose less than the general price level. Producer prices
for all finished goods rose 13 percent during 1979 and furniture rose 6
percent. The typical market share for the average casegood's plant is 0.05
percent.
Five-year projections. The outlook for wooden furniture sales is
encouraging. The stimulus to buy during the next five years will be from
the large number of persons in the 25-44 age group. In addition, a sub-
stantial number of families have two incomes and thus generate more avail-
able disposable income. This increase in income will help boost wooden
furniture which has traditionally been more expensive than furniture made
of other materials. Due to the high cost of fuel, travel has been reduced.
Families are spending more on home purchases which will help increase sales
of furniture in general.
9-10
-------
9.1.1.1.3 Steam use. The most intensive steam requirements are for
makeup air and for drying (at the drying/curing kilns and wood finish
driers). Makeup air is the process where airborne wood particles, produced
from the routers, planers, saws, and sanders in the rough end section, are
continually removed from the working environment by a combination of vacuum
attachments. These wood particles are then collected for use as fuel.
Other steam processes include hot pressing (gluing) and humidifiers.
The furniture industry generates 50 to 100 percent of its energy from
wood waste.7 The leading casegoods manufacturers indicate they use 100
percent waste wood when it is available. An "average" casegood plant burns
approximately 907-1814 megagrams (1,000-2,000 tons)/year in its boilers
and incinerates the remaining 1,814-2,721 megagrams (2,000-3,000 tons).
Wood waste is incinerated or sold since construction of storage bins is
expensive. Since purchasing fossil fuels is less expensive than storing
wood waste during the winter months, most manufacturers supplement their
wood waste with oil and coal from December through February.
Approximately 25 percent of total purchased and captive energy, in-
cluding electricity, fossil fuel, and waste fuel, is typically used to
Q
generate steam. The major manufacturing processes are described below.
• Drying. Lumber is first air-dried, reducing moisture to 14-20 per-
cent, and then kiln-dried to achieve a 6-8 percent moisture content.
The drying time varies according to the thickness, species, and ini-
tial moisture content of the wood, the location of the yard, and time
of year.
• Rough end. The dried lumber is cut into strips of wood and defects
removed. The veneers are cut to size and pressed. Lumber panels from
rough ending particleboard and hardboard are used for interior layers.
• Machining parts. The blanks and panels are converted to furniture
parts with machining operations.
• Assembly and finishing. Furniture parts are assembled and stains,
lacquers, and varnishes are applied and dried. Furniture may be
rubbed and trimmed. Comoleted units are packed and sent to the ware-
house to await shipping.
9.1.1.2 Lumber Products Industry.
9.1.1.2.1 Industry description. The lumber products industry (SIC
24) is divided into several sub-industries characterized by product. This
description of the lumber industry will focus on sawmills and planing mills
9-11
-------
(primarily sawmills) (SIC 2421), hardwood veneer and plywood (SIC 2435),
and softwood veneer and plywood (SIC 2436). These sub-industries are the
most significant users of wood waste for their steam needs. For the pur-
poses of this industry description, sawmills will include both soft and
hardwood lumber and the panel industry will include both soft and hardwood
plywood and veneer.
Sawmills. The sawmill industry consists of approximately 3,133 mills
throughout the U.S. producing 37 billion board feet of lumber in 1979.
Approximately 80 percent of this total production is softwoods, and the
remaining 20 percent is hardwoods.
Sawmills, closely integrated with the paper and allied products indus-
try, are located primarily in the southern and western United States. The
largest concentration of sawmills is in Washington (299), Missouri (229),
Oregon (221) and North Carolina (211).10 Table 9-4 lists the leading
lumber producers, locations of their mills, and production.
The western States produce 60 percent or more of the softwood output.
Of this total western production figure, California, Oregon, and Washington
produced more than 70 percent in 1979.
Production of softwoods has increased every year with the exception of
1975 and 1979. Since residential construction is the largest market for
softwood, the production decline in these years reflect the decrease in
housing starts. More than 58 percent of the sawmills in the western U.S.
have been forced to close or curtail production since March 1980.
Growth in the industry over the last ten years has been predominantly
in the South, where average sawmill output increased 79 percent from 1966
to 1976. As indicated in Table 9-5, hardwood production did not decline in
1979. Hardwood lumber is primarily of southeastern origin. The principal
markets for hardwood lumber are the furniture, materials handling, and
flooring industries.
Presently, there is an increase in the consumption of lower grades of
hardwood lumber by the furniture industry for "character marked" furniture.
Use of these grades saves materials and money by increasing the total
12
lumber supply.
Over the last ten years, there has been a trend toward greater pro-
duction concentration among large lumber companies. This trend is indi-
9-12
-------
TABLE 9-4. SAWMILL AND PLANING MILL INDUSTRY
a
Firm ownership
Total number
of mills
Location of mills0
fi1979 Production:
10 board feet lumber
(rank)
CO
Boise Cascade Corp.
Champion International Corp.
Crown Zellerbach
Diamond International
Edward Nines Lumber Co.
Georgia-Pacific Corp
14
16
8
3
9
36
Idaho (5), Minnesota,
North Carolina, Oregon
(6), Washington
Alabama, California (2),
Georgia, Idaho, Louisiana,
Montana (4), North
Carolina, Oregon (2),
South Carolina, Texas,
Washington
Louisiana (2), Oregon (3),
Washington (3)
California (3)
Arizona, Colorado (2),
Idaho, Mississippi,
Oregon (2), South Dakota,
Wyoming
Alabama (2), Arkansas (5),
California, Florida,
Georgia (5), Kentucky,
Maine, Mississippi (4),
North Carolina (6), Oregon
(2), South Carolina (4),
West Virginia (4)
752 (5)
746 (6)
819
424
349
(4)
(14)
(20)
1,448 (3)
-------
TABLE 9-4 (Continued). SAWMILL AND PLANING MILL INDUSTRY0
Firm ownership
Total number
of mills
Location of mills
-1979 Production:
10 board feet lumber
(rank)
I
K
ITT Rayonier Inc.
International Paper Co.
Louisiana-Pacific Corp.
Mead
Pope & Talbot Inc.
Potlatch Corp.
Publishers Paper Co.
Roseburg Lumber Co.
10
15
48
10
2
9
4
4
Florida (2), Georgia,
Washington (2), Alabama,
Kentucky, South Carolina (3)
Arkansas (5), Arizona (3),
Georgia, Louisiana,
Oregon, Mississippi, South
Carolina, Texas (2)
Alaska (3), California (19),
Florida (3), Idaho (5),
Washington (2), Wisconsin
(2), Louisiana (2),
Michigan (2), Montana,
Oregon (5), Texas (4)
Alabama, Massachusetts,
Michigan (2), Ohio (3),
Tennessee, Virginia,
Wisconsin
Oregon, Washington
Arizona (2), Idaho (6),
Minnesota
Oregon (4)
California (2), Oregon (2)
473 (12)
555 (9)
2,193 (2)
611 (7)
378
587
403
402
(17)
(8)
(15)
(16)
-------
TABLE 9-4 (Continued). SAWMILL AND PLANING MILL INDUSTRY0
Firm ownership
Willamette Industries
Total number
of mills
Location of mills
g!979 Production:
10 board feet lumber
(rank)
St. Regis Paper Co.
Sierra Pacific Ind.
Simpson Timber Co.
Weyerhaeuser Co.
7
8
2
20
Georgia (2), Maine,
Montana, South Dakota,
Washington (2)
California (8)
California (2)
Alabama, Arkansas (3),
540
472
502
2,955
(10)
(13)
(11)
(1)
Mississippi (2), North
Carolina (3), Oregon (4),
Washington (7)
Arkansas, Louisiana (2),
Oregon (6)
355 (19)
aForest Industries Annual Review. Forest Industries Magazine. May 1980. Lockwood's Directory 1980.
'Firms listed represent 27 percent of total board feet produced in 1979.
:The number in parentheses following the State names denotes number of plants.
-------
TABLE 9-5. HISTORIC TRENDS OF PRODUCTION FOR SAWMILLS AND PLANING MILLS'
Indicator
Production
(10 bd ft/yr)
Total softwoods
Total hardwoods
Total lumber
Production/mill
(10 bd ft/yr)
Producer price index
(1967 = 100)
Softwood
Hardwood
Total value of shipments
($106)
Value of shipments/mill
($10b)
1974
27,193
6,904
34,097
4.32
211.4
189.5
7,365.2
0.932
1975
25,711
5,872
31,583
4.08
200.6
160.3
6,634.8
0.856
1976
29,343
6,417
35,760
4.67
248.1
176.0
8,744.2
1.143
1977
30,987
6,680
37,667
5.03
297.4
200.3
10,692.1
1.427
1978
30,899
6,758
37,657
5.38
346.0
235.8
12,400.0
1.771
1979
29,674
7,291
36,965
11.80
380.0
260.0
13,400.0
4.277
Fingertip Facts & Figures, 1980. National Forest Products Association. U.S. Department of Commerce. Bureau of
Census. Bureau of Labor Statistics.
Dollar amounts are in nominal terms.
-------
cated in Table 9-5 under production per mill. In 1979, the top 14 lumber
companies accounted for 27 percent of all lumber production and an esti-
mated 50 percent of all U.S. plywood and particle board production.
Softwood plywood. In 1979 there were approximately 189 softwood
plywood mills and 99 softwood veneer mills throughout the U.S. producing
19.7 billion square feet on a 3/8-inch basis. Since March of 1980, the
plywood industry (both soft and hardwood) has fallen to 45 percent of
operating capacity with close to 68 percent of its mills closed or running
only partially and 20,000 workers idled. The largest concentration of
softwood plywood mills is in the West and South. The largest producing
States are Oregon (70), Washington (27), and Louisiana (15). Table 9-6
lists leading plywood producers, both softwood and hardwood, their mill
locations, and production.
Production of softwood plywood was down in 1979 from 1978 due to the
national economic situation. Competition is on the rise from other wood-
based panels products such as waferboard, particleboard, fiberboard, hard-
board, and composite panels. Many of these competitors are new but experi-
encing rapid growth. Production of softwood plywood is shown in Table
9-7a.
Hardwood plywood. In 1979 there were approximately 136 hardwood
plywood plants and 156 hardwood veneer mills throughout the U.S. producing
1.5 billion square-feet on a 3/8-inch basis. The largest concentration of
these mills is in the South. The States with the greatest concentration of
mills are North Carolina (52), South Carolina (31), and Wisconsin (24).
These three States represent 37 percent of the total number of hardwood
plywood mills in the U.S.
The production trend for hardwood plywood and veneer resembles that
for softwood plywood and veneer. Except for a two percent decrease in
1979, production has been increasing steadily since 1975. Production of
hardwood plywood is shown in Table 9-7b.
9.1.1.2.2 Economic characteristics.
Employment. Average hourly earnings for sawmill and planing mill
workers were up to $6.71 in June 1979, compared with $5.83 in December
1978. Earnings for workers in the panel industry are only slightly lower.
In mid-1979, there were an estimated 190,000 employees in the lumber indus-
9-17
-------
try, an increase of three percent over 1978 figures. Of this total, 165,000
were production workers, a four percent increase over 1978 figures. How-
ever, since March 1980, the recession has curtailed production, affecting
61,000 workers. Of this total, 20,000 were plywood workers. In the wood
products industry, 28 percent of the employees work in sawmills and planing
mills.
Substitutes. The major substitutes for softwood lumber are aluminum
and various panels such as plywood. Major substitutes for hardwood also
include plywood and other panels. For the plywood industry, substitute
products include panels such as particleboard, hardboard, insulation board,
medium density fiberboard, thin panel board, waferboard, and composite
board.
Imports/exports. U.S. lumber imports, which consist almost entirely
of softwoods from Canada, declined more than six percent below the 1978
level in 1979 to 11.2 billion board feet as housing demand slowed. Lumber
imports from Canada in 1979 represented 24 percent of total lumber consump-
tion.
U.S. producers, who do not normally sell heavily overseas, used export
sales to offset expected declines in the U.S. market. Exports of lumber
increased nearly 20 percent during the first half of 1979 and then leveled
off during the last half. The total amount of lumber exported in 1979 was
estimated at 1.9 billion board feet, an increase of 12 percent over 1978.
The U.S. is the second largest lumber-producing country in the world and
ranks fourth in lumber exports. These exports represent less than six
13
percent of total domestic production.
Time series data. The financial profile for the leading wood products
producers (including lumber and panels) is indicated in Table 9-8. This
financial profile will vary only slightly from the profile of the leading
paper and allied products companies since the two industries overlap great-
ly.
Total assets have been increasing steadily since 1974 to $3 billion in
1979. Capital expenditures have also been increasing steadily. Recently,
capital spending commitments have jumped to a greater percentage than in
the past. In Table 9-8 this percentage for the leading producers is esti-
mated at 20 percent. Estimates show that solid wood producers in general
9-18
-------
TABLE 9-6. PLYWOOD AND VENEER INDUSTRY
a
Firm ownership
Total number
of mills
Location of plywood
and veneer mills
Production In 1979
(10° sq. ft. ,
3/8" basis)
u>
Boise Cascade Corp.
Champion International Corp.
Crown Zellerbach
Edward Mines Lumber Co.
Georgia Pacific Corp.
International Paper Co.
Louisiana-Pacific Corp.
Potlatch Corp.
Publishers Paper Co.
Roseburg Lumber Co.
13
12
1
1
25
4
5
6
1
4
Idaho, Louisiana,
North Carolina, Oregon (8),
Washington (2)
Alabama, California, Georgia,
Louisiana, Montana, Oregon (4),
South Carolina, Texas, Washington
Washington
Oregon
Alabama (2), Arizona (2),
Florida (5), Georgia (4),
Louisiana, Mississippi (3),
North Carolina, Oregon (4),
South Carolina (2), Virginia
Mississippi, Oregon (2), Texas
California (2), Louisiana,
Oregon, Texas
Idaho (3)
Washington
Oregon
1,498
1,710
114
64
4,623
545U
698
447C
95
822C
-------
TABLE 9-6 (Continued). PLYWOOD AND VENEER INDUSTRY*
Firm ownership
Wi11amette Industries
Total number
of mills
Location of plywood
and veneer mills
Production in 1979
(10b sq. ft.,
3/8" basis)
Southwest Forest Industries
Tempi e-Eastex, Inc.
Weyerhauser Co.
1
2
19
Oregon (3)
Texas (2)
Mississippi, North Carolina,
344C
474C
2,942C
11
Oregon (3), Vermont, Washington,
Arizona, Louisiana (3), Kentucky,
Oregon (6)
IS>
o
Panel Review. Forest Industries Magazine. April 1980. Lockwood's Directory 1980.
Firms listed represent 73 percent of total plywood and veneer production.
°The number in parentheses following the State names denotes number of plants.
Annual capacity, no production data supplied.
-------
TABLE 9-7a. HISTORIC TRENDS OF PRODUCTION FOR SOFTWOOD VENEER AND PLYWOOD INDUSTRY3
to
M
Indicator
Production
(10b sq. ft. , 3/8" basis)
Production/mill
(10b sq. ft., 3/8" basis)
Producer price index -
softwood plywood
(1967 = 100)
Total value of shipments
($10&)
Value of shipments/mill
($106) .
1974
15,878
85.99
186.8
2,124
11.9
1975
16,050
90.79
200.6
2,244
12.97
1976
18,400
101.74
247.6
3,164
17.98
1977
19,300
108.49
295.8
3,783
21.74
1978
19,760
114.66
326.4
4,214
24.79
1979
19,750
111. 00
322.3
4,121
23.15
aPanel Review, 1980. Forest Industries Magazine. April 1980. U.S. Department of Commerce. Bureau of Census.
Bureau of Labor Statistics.
Dollar amounts are in nominal terms.
-------
TABLE 9-7b. HISTORIC TRENDS OF PRODUCTION FOR HARDWOOD VENEER AND PLYWOOD INDUSTRY'
Indicator
Production
(10 sq. ft. , 3/8" basis)
Production/mill
(10b sq. ft., 3/8" basis)
Producer price index -
hardwood plywood
(1967 = 100)
Total value of shipments
($105)
Value of shipments/mill
($106)
1974
1644.0
8.84
130.2
393.6
2.12
1975
1280.0
7.19
119.5
347.2
1.95
1976
1463.0
8.76
122.5
416.5
2.49
1977
1478.0
8.69
127.7
477.4
2.81
1978
1481.0
8.92
140.2
521.5
3.14
1979
1450.0
8.53
169.1
NAC
NA
Panel Review 1980. Forest Industries Magazine. April 1980. U.S. Department of Commerce. Bureau of Census.
Bureau of Labor Statistics. *
Dollar amounts are in nominal terms.
«s
"NA denotes not available.
-------
TABLE 9-8. FINANCIAL ANALYSIS — LUMBER PRODUCTS INDUSTRY
(Nominal Terms)
a
Financial
indicator
Capital expenditures
Total assets (106$)
Capital expenditures/
firm (10°$)
Capital expenditures/
total assets (%)
Profitability
Net profit after
taxes (10b$)
Return on assets (%)
Return on equity (%)
Return on sales (%)
Dividends ($/share)
Net earnings before
interest and taxes
(10B$)
Capitalization
Interest on fixed-
obligations (10 $)
Coverage ratio
Rating on bonds
Long-term debt (106$)
Stockholders' equity
(10b$)
Debt/capi tal i zati on
Debt/equity (%)
1974
1683.
330.
19.
137.
8.
16.
8.
0.
262.
36.
40
80
66
77
18
97
43
91
60
40
7.21
NAb
507.96
812.
38.
62.
06
48
55
1975
1830.30
302.10
16.51
103.47
5.65
11.51
5.86
1.00
210.19
43.52
4.83
NA
559.51
899.01
38.36
62.24
1976
2018.
351.
17.
139.
6.
13.
6.
1.
242.
43.
00
90
44
11
89
34
46
06
30
26
5.60
NA
585.92
1043.
35.
56.
00
97
18
1977
2350.70
395.90
16.84
157.31
6.69
13.37
6.48
1.17
282.83
45.52
6.21
Aa/Baa
575.32
1176.59
32.84
48.90
1978
2505.40
428. 30
17.11
185.90
7.42
14.32
6.70
1.28
351. 19
47.67
7.37
Aa/Baa
632.77
1298.46
32.77
48.73
1979
3035.
592.
19.
250.
8.
16.
7.
1.
390.
55.
Average
(1974-1979)
00
90
54
67
26
98
99
43
69
67
7.02
Aa/Baa
689.11
1475.
31.
46.
93
83
69
2236.
400.
17.
162.
7.
14.
7.
1.
298.
45.
70
40
90
37
26
53
01
14
97
34
6.40
Aa/Baa
591.77
1117.
34.
52.
51
62
95
Average/firm estimates for model firms (Securities and Exchange Commission;
EEA estimates).
NA denotes not available.
9-23
-------
increased capital spending by over 65 percent from 1978. The South aggre-
gated the biggest regional share of these expenditures.
Profits for the industry range from a low of $103 million in 1975 to a
high of $251 million in 1979. The net profit margin was highest in 1974 at
8.4 percent, averaging 7.0 percent for the six years. Return on assets
averaged 7.3 percent and return on equity averaged 14.5 percent.
The debt-to-equity ratio has been decreasing since 1974, indicating
these companies would probably finance new investments with debt. An
average of several bond ratings ranged between Aa and Baa, representing an
above average rating of credit worth.
Five-year projections (sawmills). Lumber output during the next five
years will be largely influenced by the general economy and trend in con-
struction, especially residential. Construction accounts for 80 percent of
lumber and 42 percent of softwood plywood. In October 1979, the Federal
Reserve Board tightened credit which accelerated the slide that was already
occurring in construction activity. Housing starts in 1979 declined to
1.75 million, down from more than 2 million in 1978, resulting in real
production declines of 1.2 percent in lumber and 4 percent in softwood
plywood production. However, the value of shipments for lumber increased
about 9 percent in 1979 because prices remained high.
The number of housing starts is estimated to average slightly less
than two million units through 1984. Other types of construction should
realize a demand similar to housing.
Two major factors that will influence the lumber industry are competi-
tion for raw material supplies and competition in the market with other
building materials. The South is estimated to produce one-half of the
nation's future wood products. Currently the South supplies slightly over
34 percent of the nation's wood, so its share is expected to increase
substantially.
Five-year projections (panel industry). The outlook for wood-based
structural panels is favorable through the mid-1980's. There should be a
shift to consumption of reconstituted board, which primarily consists of
particleboard, hardboard and insulation board, from the traditional soft-
wood plywood markets. However, the softwood plywood manufacturers will not
suffer greatly since they produce most of the reconstituted board.
9-24
-------
Capacity in 1980 for softwood plywood should reach over 22 billion
square feet. Most new capital expenditures will be directed towards com-
posite wood panels. This segment of the industry should increase to cap-
ture 18 percent of the wood panel market by 1984. The price of softwood
plywood is projected to increase about 10 percent per year until 1984 due
to rising raw material costs.16 Forecasts estimate the compounded annual
real growth rate for the lumber products industry from 1980-1985 will be
5.3 percent.
9.1.1.2.3 Steam use. As indicated in Table 9-9, over 70 percent of
the leading companies' total fuel consumption is from wood waste. These
companies accounted for 27 percent of all lumber production.
Most of the steam required in a sawmill is for drying, which consumes
18
approximately 75 to 85 percent of total steam required. The major manu-
facturing processes for sawmills are described below.
• Debarking. Logs in raw form are debarked and cut to various lengths,
the maximum of which is 20 feet.
• Sawing. In this process the log is cut further by the head saw which
is a carriage powered by a steam cylinder. The log is turned, weigh-
ted, edged, and trimmed to desired lengths. The result is a green
end, which is an undried piece of lumber.
• Drying. Approximately 65 percent of all cut lumber is kiln dried.
The kiln is heated by steam or other means. Energy required for
softwood drying range from 1,055 kJ (1,000 Btu)/foot of Douglas
fir to 3,690 kJ (3,500 Btu)/board foot of pine, depending on the
cut and moisture of the wood.
• Planing. Dried lumber moves to a planer where it is finished and
smoothed. Lumber..end products are either rough or dressed (planed)
boards and chips.
Manufacturing plywood involves the assembly of layers of veneer joined
together by an adhesive. Of the major plywood manufacturing processes
listed below, log conditioning is the most steam-intensive. Approximately
25 percent of the total purchased and captive energy is used to generate
steam.
• Log conditioning. Logs are heated to improve the cutting properties
of wood. Heating may be accomplished by directing steam onto the logs
in a steam vat or by heating the logs in a hot water vat, heated by
steam.
9-25
-------
• Veneer cutting. More than 90 percent of all veneer is rotary cut.
The log is turned against a knife and a thin sheet of veneer is pulled
from the log.
• Veneer drying. Veneers are usually dried to a moisture content of
less than 10 percent to make them suitable for gluing. The majority
of high temperature veneer dryers (above 212°F) use steam or forced
hot air. Plywood drying and glue heating consume about 25 x 10 kJ/
square meter (2.2 x 10 Btu/MSF).
• Gluing and pressing. One of three main types of glues is applied to
the veneers, depending on the end use of the plywood (indoor or out-
door). Glues may be applied by a spreader, roller, or sprayer. The
veneer is then pressed to ensure proper alignment.
• Finishing. Finishing may include redrying, trimming, sanding, sort-
ing, molding, and storing.
9.1.1.3 Paper and Allied Products Manufacturing Industry.
9.1.1.3.1 Industry description. The segments of the paper and allied
products industry (SIC 26) considered in this industry description are pulp
mills (2611), paper mills (SIC 2621), and paperboard mills (SIC 2631).
The paper and allied industries consists of 917 establishments through-
out the United States, producing 61.5 million tons of paper and paperboard
in 1979. There are a total of 405 companies operating 725 paper and/or
paperboard mills and 426 pulp mills in the United States. Pulp, paper, and
board mills are primarily located in the Northeast (231), South (185)> and
North Central (176) States.21
Table 9-10 shows the largest producers of paper and allied products
the location of their plants, and their sales. The sales of these top 19
companies account for $28 billion of paper-related sales. This is approxi-
mately 52 percent of total paper sales in 1979. Production figures for
22
paper and allied products are shown in Table 9-11.
Economies of scale have encouraged the growth of integrated mills,
especially in the South and the West. The elimination of drying and re-
pulping of pulp in integrated mills helps to reduce the costs of energy
capital, labor, and transportation. About 75 percent of the pulp used by
paper mills and 97 percent of the pulp used by paperboard mills were pro-
23
duced at the same location in 1975.
Pulp mills. Pulp mills follow the economic trends for the paper and
paperboard and related products industry. Total U.S. production capacity
9-26
-------
TABLE 9-9. ENERGY CONSUMPTION OF MAJOR LUMBER PRODUCERS IN 1978-79e
ro
Estimated
Sources Units fuel use
Purchased electricity 106 kWh 4899.7
Purchased steam 10?. kg 884.8
(10° Ibs) (1950.9)
Purchased fossil fuel — —
Total purchased fossil
fuel and energy
Self-generated hogged 10^ Mg 9,364.2
fuel, wood and bark (10 tons) (10, 324. 4)
Purchased hogged fuel, 10^ Mg 384.7
wood and bark (10 tons) (424.1)
Other self-generated — —
and waste fuels
Total hogged fuel ,
wood, and waste fuels
Total all energy
1978
10r;KJ % of Estimated
(10 *Btu) total fuel use
17.6 10.0 4852.6
(16.7)
2.5 1.4 972.3
(2.3) (2,143.8)
34.3 19.7
(32.5)
54.4
(51.5) 31.1
114.7 65.5 9,459.3
(108.7) (10,428.9)
3.7 2.1 555.2
(3.5) (612.1)
2.4 1.4
(2.3)
120.7
(114.4) 68.9
175.1
(166.0) 100.0
1979
loJ'KJ
(lO^Btu)
17.6
(16.7)
2.7
(2.6)
32.2
(30.5)
52.5
(49.7)
116.6
(110.5)
5.2
(4.9)
2.2
(2.0)
123.9
(117.4)
176.4
(167.2)
% of
total
10.0
1.5
18.3
29.8
66.1
2.9
1.2
70.2
100.0
National Forest Products Association Report to DOE on Energy Consumption by SIC 24. June 30, 1980. The
14 companies represented in this table account for 27 percent of all lumber production and an estimated
50 percent of all U.S. plywood and particle board production.
-------
TABLE 9-10. PAPER AND ALLIED PRODUCTS INDUSTRY
a,b
Firm ownership
Number of
mills
Location of mills
Sales in 1979°($1Q )
Paper (Rank)
Total Percent of
company total
sales company sales
N>
00
Boise Cascade Corp. 13
Champion International
Container Corp. of America 13
(Mobil Oil)
Continental Group
(Continental Forest
Industries)
Crown-Zel1erbach
Diamond International
15
12
Massachusetts, Maine, 1,652 (8) 2,916 56
Minnesota, New York (2),
Oregon (3), Vermont,
Washington (3), Louisiana
Alabama, Illinois, Ohio, 1,870 (5) 3,751 50
Oregon, South Carolina,
North Carolina, Texas
Alabama, California (2), 1,462 (10) 44,721 3
Delaware, Florida, Indiana (2),
Ohio (2), Pennsylvania,
Tennessee, Washington,
Illinois
Georgia (2), Louisiana, 1,043 (15) 4,370 24
Virginia
California (3), Louisiana (2), 1,500 (9) 2,807 53
New York (2), Ohio, Oregon (3)
Washington (4)
California, Illinois, Maine, 663 (19) 1,284 52
Massachusetts (2), Mississippi,
New York (2), Ohio (2), New
Hampshire (2)
-------
TABLE 9-10 (Continued). PAPER AND ALLIED PRODUCTS INDUSTRY
a,b
tO
ro
ID
Firm ownership
Georgia-Pacific
Number of
mi 1 1 s
22
Location of mills0
Arizona, Connecticut,
Sales in 19796($10 )
Paper (Rank)
Florida, 1,269 (12)
Total Percent of
company total
sales company sales
5,207 24
Great Northern Nekoosa Corp.
Hammermill Paper Co.
International Paper Co.
Kimberly-Clark
Mead Corp.
Georgia, Illinois, Indiana,
Louisiana, Maine, Michigan,
New Jersey, New York (3),
North Carolina, Ohio, Oklahoma,
Oregon (2), Pennsylvania,
Vermont, Virginia, Washington,
Wisconsin
Maine (2), Arkansas, 832 (16)
Wisconsin (3), Georgia
4 Alabama, Pennsylvania (3)
14 Alabama (2), Arkansas (2)
Louisiana, Maine, Mississippi
(3), New York (2), Oregon,
South Carolina, Texas
12 Alabama, California, Connec- 2,028 (4)
ticut, Maine, Michigan, New
Jersey (2), Pennsylvania,
South Carolina, Tennessee,
Wisconsin
7 Alabama, Massachusetts, 1,774 (7)
Michigan, Ohio (2), Tennessee,
Virginia
1,158
2,218
2,570
71
927
3,694
(14)
(1)
1,077
4,534
86
81
91
70
-------
TABLE 9-10 (Continued). PAPER AND ALLIED PRODUCTS INDUSTRY3'5
u>
o
Number of
Firm ownership mills
Owens Illinois, Inc. 5
St. Regis 14
Scott Paper 9
Time, Inc. 5
(Inland/Temple Eastex)
Union Camp Corp. 5
Westvaco 5
Weyerhaeuser Co. 15
Sales in 19796($10 )
Location of millsc Paper (Rank)
Georgia, Maine, Texas, 684 (18)
Virginia, Wisconsin
Florida (3), Maine, Michigan, 2,085 (3)
Minnesota, Mississippi, New
York (2), Ohio (2), Pennsyl-
vania, Texas, Washington
Alabama, Maine (2), Michigan, 1,811 (6)
New York, Pennsylvania, Wash-
ington, Wisconsin (2)
California, Indiana, 717 (17)
Tennessee, Texas (2)
Alabama, Georgia, Michigan, 1,277 (11)
New Jersey, Virginia
Kentucky, Maryland, Pennsyl- 1,087 (13)
vania, South Carolina,
Virginia
Arkansas, North Carolina (3), 2,385 (2)
Oklahoma (2), Oregon (2),
Pennsylvania, Washington (4),
Wisconsin (2)
Total Percent of
company total
sales company sales
3,504 20
2,499 83
1,908 95
2,504 27
1,389 92
1,200 89
4,423 54
aLockwood's Directory, 1980; Post's Directory 1980; Miller Freeman Publications; Federal Trade Commission.
Only domestically owned firms are listed. Firms listed represent 52 percent of total paper sales.
cNumbers in parentheses following the State names denotes number of plants.
-------
TABLE 9-11. HISTORIC TRENDS OF PRODUCTION FOR PAPER AND ALLIED PRODUCTS
a
Indicator
Production ~
(10J Mg/yr (104 st/yr))
Paper
Board
Paper and board
Pulp
Total
Production/mill _
(101* Mg/yr (10"3 st/yr))
c 3
Average-price ($/10 Mg/yr
(I/10-* st/yr)
Producer price index
(1967 = 100)
Paper and allied products
Wood pulp
Paper
Paper board
1974
24,194
(26,674)
25,412
(28.017)
49,606
(54,691)
43,854
(48.349)
93,460
(103,040)
118.00
(130.26)
0.15
(0.16)
151.70
217.80
148.60
152.20
1975
21,152
(23,320)
22,179
(24.452)
43,331
(47,772)
39,078
(43.084)
82,409
(90,856)
54.00
(59.38)
0.16
(0.18)
170.40
283.40
175.90
170.30
1976
24,138
(26,612)
25,252
(27.840)
49,390
(54,452)
43,284
(47.721)
92,674
(102,173)
118.00
(129.50)
0.17
(0.19)
179.40
286.00
182.30
176.00
1977
24,935
(27,491)
26,056
(28.727)
50,991
(56,218)
45,355
(50.004)
96,346
(106,222)
125.00
(137.24)
0.17
(0.19)
186.40
281.10
194.30
176.20
1978
25,151
(27,729)
26,053
(28.723)
51,204
(56,452)
45,782
(50.475)
96,986
(106,927)
127.00
(139.77)
0.20
(0.22)
195.60
266.50
206.10
179.60
1979
-
27,076
(29,851)
NAb
(NA)
NA
(NA)
45,118
(49.743)
NA
(NA)
NA
(NA)
NA
(NA)
219.00
314.30
229.60
202.10
-------
TABLE 9-11 (Continued). HISTORIC TRENDS OF PRODUCTION FOR PAPER AND ALLIED PRODUCTS
Indicator
Total val
ue of shipments0 ($10 )
Paper and board
Pulp
Total
Value of
($10b)
shipments/mill0
1974
15,079
1,525
16,604
20.99
1975
14,621
1,630
16,251
10.62
1976
17,570
2,055
19,625
24.87
1977
18,579
2,071
20,650
26.68
1978
21,784
2,200
23,984
31.35
1979
23,984
2,644
26,628
35.04
Statistics of Paper & Paperboard 1979, American Paper Institute. Lockwood's Directory, 1979. U.S. Department
of Commerce. Bureau of Census. Bureau of Labor Statistics.
u> NA denotes not available.
ro Dollar amounts in nominal terms.
-------
or pulp mills was 6.2 million short tons for pulp mills in 1979 with an
annual production figure of 5.7 million short tons. In 1980, annual pro-
duction capacity is estimated to be 6.5 million short tons with production
at 5.8 million short tons. Capacity utilization in the pulp mills has
ranged from 79.5 percent in 1975 to 94.3 percent in 1978.
Growth in the pulp industry, as with lumber, has occurred primarily in
the South where land has been converted from cotton to timber. Half of
pulp production is in the South, with the remaining half in the Northeast,
North Central, and Pacific regions.
The increased scale of pulp mill production capacity (indicated by the
decrease in number of establishments with a simultaneous increase in capa-
city), together with labor-saving and cost-saving efficiencies, has enhanced
productivity in U.S. pulp mills.
Paper mills. Paper and board mill operating rates averaged 94.5
percent of rated capacity in 1979. Total paper and board capacity is
estimated to be 74 million tons in 1980 and 75 million tons in 1981. Total
paper and board capacity has ranged from 66 million tons in 1974 to 72
24
million tons in 1979, with only increasing capacity throughout those years.
9.1.1.3.2 Economic characteristics.
Employment. Total employment within the pulp mills is expected to
grow less than one percent in 1980. Total employment in this highly auto-
mated industry will remain within the 16,000-plus range. The hourly wage
for pulp mill production workers in 1979 averaged close to $8.18 an hour.
Total employment in the paper and board industry was estimated at
211,000 in 1979. The average hourly earnings for production workers in
paperboard mills has been about three percent higher than that of the paper
and pulp mill production worker over the last six years.
Paper and paperboard were faced in 1978 by more than 50 strikes. Most
strike activity was centered in the Northwest. Provisions for cost-of-
living adjustments represented a significant departure from the standard
paper industry settlements and introduced an additional long-term cost to
the industry's cost structure.
Substitutes. The major substitutes for domestic paper and allied
products are imports, some types of wood panels (for paperboard), and waste
paper for virgin pulp grades.
9-33
-------
Imports/exports (pulp). The U.S. has always been a large net Importer
of pulp. In 1979, the amount of imports as a percent of apparent consump-
tion was 59.5 percent. Pulp imports for 1980 are estimated at 4,013,605
megagrams (4,425,000 tons) exceeding exports of 2,752,835 megagrams
(3,035,000 tons) by 46 percent.
Imports/exports (paper and board). In 1980, import volume is expected
to drop 10 percent to 7,256,238 megagrams (8,000,000 tons). Imports as a
percent of apparent consumption were 11 percent in 1979. Imports should
drop in 1980 due to expanded U.S. capacity in printing papers. The value
of imports should hold at $2.8 billion because of price increases.
Paper and board exports should climb by 10 percent, reaching $1.4
billion in value and 3 million megagrams (3.3 million tons) in volume in
1980. The climb in exports is a result of producers seeking to maintain
favorable operating rates by offsetting slowed domestic demand. The de-
cline in the monetary exchange rate of the dollar has also improved the
competitive position of U.S. paper and board producers in foreign markets,
95
especially in Japan.
Time series data. Despite the slowing of the general economy, paper
and board should post new gains in 1980. The paper industry has had record
sales and earning throughout most of the 1970's. Sales have climbed from
an average of $1.9 billion for the top 10 companies in 1974 to an average
of $3.1 billion in 1979. The only exception was a slight dip in 1975.
Value of shipments from the paperboard establishments should be about 7
percent above the estimated figure for 1979.
The financial profile of the leading paper and allied products com-
panies is shown on Table 9-12 from 1974 to 1979. Profits range from a high
of $260 million in 1979 to a low of $103 million in 1975, reflecting the
industry's sensitivity to the change in GNP. Profits were high in 1979
despite labor strikes.
Total assets have increased steadily since 1974. Capital expenditures
have been fairly constant between 1974 and 1979, showing an increase in
1979. The paper industry had estimated increasing capital outlays by 40
percent in 1979, which is high compared to the 13 percent annual average
increase for all business.
9-34
-------
TABLE 9-12. FINANCIAL ANALYSIS - PAPER AND ALLIED PRODUCTS INDUSTRY3
(Nominal terms)
Financial
indicator
1974
1975 1976 1977
1978
Average
1979 (1974-1979)
Capital expenditures
Total assets (106 $)
Capital expenditures/
firm (NT $)
Capital expenditures/
total assets (%)
Profitability
Net profits,after
taxes (10° $)
Return on assets (%)
Return on equity (%)
Return on sales (%)
Dividends ($/share)
Net earnings before
interest and taxes
(10e $)
Capitalization
Interest on fixed-
obligations (10° $)
Coverage ratio
Rating on bonds
Long-term debt
(106 $)
Stockholders' equity
(HT $)
Debt/capi tal i zati on
Debt/equity (%)
1702.80 1858.60 2053.10 2293.90 2488.30 2793.60 2198.40
311.40 301.50 344.70 370.50 390.30 493.50 368.60
18.29 16.22 16.79 16.15 15.69 17.67 16.77
135.60 102.88 136.88 147.01 176.52 260.46 159.89
7.96 5.54 6.67 6.41 7.09 9.32 7.27
15.88 11.00 12.85 12.39 13.75 17.73 14.12
7.04 5.59 6.24 6.08 6.43 8.49 6.76
1.07 1.19 1.26 1.38 1.50 1.71 1.35
259.37 208.39 255.29 277.07 342.02 390.93 288.85
33.47 39.59 41.97 46.83 48.97 50.62 43.57
7.75 5.26 6.08 5.92 6.98 7.72 6.63
NAb NA NA NA Aa/Baa Aa/Baa Aa/Baa
467.70 525.83 545.04 605.88 626.55 649.86 570.14
854.11 935.68 1064.98 1186.57 1284.14 1469.44 1132.49
35.38 35.98 33.85 33.80 32.79 30.66 33.48
54.76 56.20 51.18 51.06 48.79 44.23 50.34
Average/firm estimates for model firms (Securities and Exchange Commission;
EEA estimates).
3NA denotes not available.
9-35
-------
From 1974 to 1977, the net profit margin ranged from about 5.6 percent
to 8.5 percent. Return on total assets averaged 7.3 percent and return on
equity averaged 14.1 percent.
An average of several paper companies' bond ratings was Aa to Baa,
which represents an above average rating of credit worth.
Five-year projections (pulp). Market pulp production, domestic demand
and shipments, and export shipments should maintain their proportional
positions in relation to total U.S. pulp production. U.S. pulp production
is estimated to reach 5,986,395 megagrams (6,600,000 tons) or 12 percent of
total pulp production in 1984, compared with the current 10 to 11 percent.
Five-year projections (paper and board). The U.S. paper and board
industry has a large domestic market and the potential to increase its
share in the world markets.
An improved capital investment framework, accompanied by advancing
technology, will provide this industry with increased growth in the future.
Forecasts estimate a 4.8 percent compounded annual real growth rate for the
26
paper and allied products industry from 1980-1985.
9.1.1.3.3 Steam use. As indicated in Table 9-13, total self-gener-
ated and waste fuels are 47.3 percent of total energy consumed by the paper
and allied industry in 1979. Of this, 9.2 percent is hogged and bark fuel.
Approximately two thirds of total purchased and captive energy, including
electricity, fossil fuel, and waste fuel, are typically used to generate
steam.
Pulp is produced from wood by mechanical or chemical means. The
process described below depicts the Kraft process, which is a chemical
process. Because chemical pulping generates 68 percent of total paper
production and because the Kraft process accounts for 90 percent of all
chemical pulping, this method represents a significant portion of the
industry. Pulping consumes 17 percent of the total steam requirements for
27
producing paper.
• Debarking and chipping. Bark is removed from the logs in a steel drum
or hydraulic barker. These logs are then reduced to chips by a rotat-
ing knife device to help improve the rate of cooking liquor penetra-
tion during pulping.
• Digesting. Wood chips are cooked under pressure in a digester to
dissolve lignin and release cellulose. Spent pulping liquor is re-
covered in this process.
«
9-36
-------
TABLE 9-13. ENERGY CONSUMPTION IN THE PULP, PAPER AND PAPERBOARO INDUSTRY IN 1978-79
a
Sources
Purchased electricity
Purchased steam
Purchased fossil fuel
Total purchased fossil
fuel and energy
^ Hogged fuel
**•* (50% moisture content)
Bark
(50% moisture content)
Spent liquor
(solids)
Other self-generated
energy
Total self-generated
and waste fuels
Total all energy
Units
106 kWh
10* kg
(10° Ibs)
—
10* Mg
(10J tons)
10* Mg
(10 tons)
10* Mg
(10J tons)
—
Estimated
fuel use
35,344.0
7,302.5
(16,102.0)
—
10,599.8
(11,686.7)
9,679.0
(10,671.4)
59,478.2
(65,576.8)
—
1978
(1012Btu)
126.8
(120.2)
20.4
(19.3)
1,059.3
(1,004.1)
1,206.4
(1,143.5)
101.1
(95.8)
100.2
(95.0)
860.1
(815.3)
20.0
(19.0)
1,081.3
(1,025.0)
2,329.0
(2,207.1)
% of
total
5.5
0.9
46.8
53.2
4.4
4.3
37.2
0.9
46.8
100.0
Estimated
fuel use
38,387.3
5,994.4
(13,217.6)
12,048.2
(13,283.6)
9,651.1
(10,640.7)
60,871.3
(67,112.8)
—
1979
(1012Btu)
137.7
(130.5)
16.7
(15.9)
1,061.9
(1,006.5)
1,216.3
(1,152.9)
(108.9)
99.9
(94.7)
878.0
(832.2)
19.4
(18.4)
1,112.2
(1,054.2)
2,328.5
(2,207.1)
% of
total
5.9
0.7
46.1
52.7
114.9
4.9
4.3
37.3
0.8
47.3
100.0
aAmerican Paper Institute - Raw Materials and Energy Division. Based on sample 86 percent of total dried
pulp, paper, and paperboard production for 1979, 83 percent for 1978. Determined by using "Total energy"
+ "Energy sold" as denominator.
-------
• Bleaching. After screening, pulp may be bleached. Bleaching produces
a whiter pulp stock by removing residual lignins. Most paper is
bleached, most paperboard is not, or only partially. Bleaching con-
sumes 33 percent of total paper-making steam requirements. Pulp goes
from the pulp mill to the paper-making mill in the form of slurry
whenever possible.
If the pulp continues to be made into a final paper product, the
following steps occur. Actual paper making consumes 40 percent of total
steam requirements.
• Refining. Pulp is mechanically pounded in a "hoilander" to increase
the strength of the paper and lower the porosity. The pulp is then
suspended in water and fed to a paper machine.
• Forming. Paper is formed with a Foudrinier or cylinder machine. The
slurry is discharged into a "head box" onto a screen that moves be-
tween two rolls.
• Pressing. Presses remove water by mechanical action. At this stage
the water content is reduced to 65-70 percent.
• Drying. Drying the wet sheet consumes one-half of the heat require-
ments for paper making. The sheet is passed between steam-heated
cylinders.
• Finishing. Dried paper may be further processed by embossing, impreg-
nating, laminating, and coating. Paper surfaces can be^gassed between
rolls under high pressure to improve shine and density.
9.1.1.4 Raw Sugar Cane Manufacturing Industry.
9.1.1.4.1 Industry description. The raw sugar cane manufacturing
industry (SIC 2061) consists of 44 companies with 47 mills in the domestic
U.S. and seven mills in Puerto Rico, owned or leased by a government agency.
Sugar cane is milled in four States and one territory: Louisiana leads in
the number of mills (25), followed by Hawaii (14), Florida (7), Puerto Rico
(7), and Texas (1). Table 9-14 lists the sugar milling companies in the
U.S., their mill locations, and production. There are predominantly four
types of mill operations in the sugar cane industry: closely held companies
(usually family operations), large diversified corporations, government
29
owned corporations, and farmer's cooperatives.
U.S. raw sugar production for 1979 was close to 2,780,000 megagrams
(3,065,000 tons); U.S. per capita consumption of sugar was 199.54 kilograms
(90.7 pounds) refined. Production between 1974-1979 has ranged from
9-38
-------
TABLE 9-14. RAW CANE SUGAR MANUFACTURING INDUSTRY1
Firm ownership
Aguirre
Alma Plantation, Ltd.
Atlantic Sugar Assoc.
Beaux Bridge Coop. , Inc.
Caire & Graugnard
*? Cajun Sugar Coop. , Inc.
<£>
Caldwell Sugars Coop, Inc.
Cambalache
Coloso
Cora-Texas Manuf . Co. , Inc.
Davies Hamakua Sugar Co.
Davies Honokaa Sugar Co.
(Theo H. Davies & Co.)
Dugas & LeBlanc, Ltd.
Evan Hall Sugar Corp.
Glenwood Coop. , Inc.
Number of
mills
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Location of
mills
Puerto Rico
Louisiana
Florida
Louisiana
Louisiana
Louisiana
Louisiana
Puerto Rico
Puerto Rico
Louisiana
Hawai i
Hawai i
Louisiana
Louisiana
Louisiana
Metric
tons ground/day0
in 1979
7,500
2,400
7,200
2,400
2,000
6,000
5,000
4,000
6,000
3,500
4,300
4,300
4,200
5,000
4,200
-------
TABLE 9-14 (Continued). RAW CANE SUGAR MANUFACTURING INDUSTRY1
Firm ownership
Guanica
Gulf & Western Food Products Co.
Harry L. Laws & Co. , Inc.
Hawaiian Commercial & Sugar Co.
Helvetia Sugar Coop. , Inc.
Hilo Coast Processing Co.
(Papaikou factory closed in 1980)
(IU International Corp.)
Iberia Sugar Cooperative, Inc.
Jeanerette Sugar Co. , Inc.
Ka'u Sugar Co. , Inc.
(IU International Corp.)
Kekaha Sugar Co.
(Amfac, Inc.)
Lafourche Sugar Co.
M.A. Partout & Son, Ltd.
Meeker Sugar Coop. , Inc.
Number of
mills
1
1
1
2
1
2
1
1
1
1
1
1
1
Location of
mi 1 1 s
Puerto Rico
Florida
Louisiana
Hawai i
Louisiana
Hawai i
Louisiana
Louisiana
Hawaii
Hawai i
Louisiana
Louisiana
Louisiana
Metric
tons ground/day
in 1979
8,000
18,000
4,200
9,500
3,000
6,950
4,250
2,720
2,800
3,000
6,500
5,000
3,500
-------
TABLE 9-14 (Continued). RAW CANE SUGAR MANUFACTURING INDUSTRY3
Firm ownership
Mercedita
McBryde Sugar Co. , Ltd.
(Alexander & Baldwin)
Oahu Sugar Co. , Ltd.
(Amfac, Inc.)
Olokele Sugar Co. , Ltd.
(IU International)
ID
M Osceola Farm Co.
Pioneer Mill Co.
(Amfac, Inc.)
Plata
Puna Sugar Co.
(Amfac, Inc.)
Rio Grande Valley Sugar Growers, Inc.
Roig
St. James Sugar Coop. , Inc.
St. Martin Sugar Coop.
Number of
mills
1
1
1
1
1
1
1
1
1
1
1
1
Location of
mills
Puerto Rico
Hawaii
Hawaii
Hawaii
Florida
Hawaii
Puerto Rico
Hawai i
Texas
Puerto Rico
Louisiana
Louisiana
Metric
tons ground/day
in 1979
4,500
2,600
3,200
2,700
7,200
2,700
5,000
4,500
8,500
4,500
5,000
4,000
-------
TABLE 9-14 (Continued). RAW CANE SUGAR MANUFACTURING INDUSTRY0
u>
Firm ownership
St. Mary Sugar Coop. , Inc.
Savoie Industries
Smithfield Sugar Coop. , Inc.
South Coast Sugars, Inc.
Sterling Sugars Inc.
Sugar Cane Growers
Coop, of Florida
Supreme Sugar Co, Inc.
(Archer Daniels Midland Co.)
Talisman Sugar Corp.
The Li hue Sugar Corp.
United States Sugar Corp.
Waialua Sugar Co. , Inc.
(Castle & Cooke, Inc.)
Wailuku Sugar Co.
(Closed in 1980)
(IU International Corp.)
Number of
mills
1
1
1
1
1
1
1
1
1
2
1
Location of
mills
Louisiana
Louisiana
Louisiana
Louisiana
Louisiana
Florida
Louisiana
Florida
Hawai i
Florida
Hawai i
Metric
tons ground/day
in 1979
3,500
3,800
3,500
4,535
7,500
18,000
4,000
7,200
3,800
24,400
5,000
Sugar y Azucar Yearbook, 1980.
U.S. Mainland and Hawaii centrifugal sugar factories grinding more than 500 tons of cane per day.
Represents input per day.
-------
2,806,000 megagrams (3,094,000 tons) in 1974 to 3,209,000 megagrams
(3,538,000 tons) in 1975. - Approximately 37 percent of 1979 production was
from Florida, 36 percent from Hawaii, 18 percent from Louisiana, 6 percent
from Puerto Rico, and 3 percent from Texas.30 Both Hawaii's and Florida's
production increased in 1978 and 1979, while Texas', Louisiana's, and
Puerto Rico's production decreased. Table 9-15 lists production statis-
tics.31
Florida has two cooperatives and five privately owned companies loca-
ted in the southeastern Lake Okeechobee area. The harvesting season for
sugar cane in Florida averages five months, from November to April. The
majority of the raw sugar produced is sent to refineries, with only 20-25
percent of total production refined locally. Florida currently is experi-
encing dramatic growth in its sugar cane industry, although it will become
increasingly expensive for the Florida industry to expand its capacity in
the future, since the soils surrounding the lake region are not as fer-
tile.32
Hawaii is unique among sugar cane growing areas because it has a
year-round growing and harvesting season and the age of the sugar cane crop
at harvest averages two years. Hawaiian sugar mills are similar in capac-
ity size to the Louisiana mills; however they are more similar to the
Florida industry in terms of efficiency in production.
Louisiana sugar cane production has been characterized by a rapid
decline in the number of" farms producing cane and an increase in the output
of the remaining farms on which the crop is grown. Most of the sugar cane
millers still operate small-scale farms and cannot realize the economies of
scale that the other three sugar-producing States achieve. Louisiana has a
shorter harvest season of 2.5 to 3 months. Due to freezing weather, Louisi-
ana has less cane yields per acre and sugar yields per megagram of cane.
Sugar mills tend to be old and relatively inefficient.
The Texas sugar industry harvested its first crop in 1973. There is "
one grower-owned raw sugar mill in Texas, similar in size and efficiency to
the Florida mills. In 1979, Texas' seventh harvest, the cooperative estab-
lished a new record of a 10.80 yield percent cane of 773,000 metric tons
net cane in a harvest season of 5.5 months.
All seven Puerto Rico sugar mills are owned or leased by the Sugar
Corporation of Puerto Rico, an agency of the government of the Commonwealth
9-43
-------
of Puerto Rico. The industry is characterized by small-scale poducers.
Increasing wage rates, together with increasing industrialization and
urbanization, have been credited for the decline in sugar production over
the last 28 years.
9.1.1.4.2 Economic characteristics.
Employment. Production workers in 1973 totaled 5,600 in 83 mills,
with total employment at 7,100. Industry sources indicate that the number
of employees averages about 100/plant. Based on this estimate for the
35
54 U.S. cane mills in 1979, total employees averaged 5,400 in 1979.
Annual hourly earnings for production workers in the sugar and confec-
36
tionary products industry averaged $5.62 in 1978.
Substitutes. The major substitutes for cane sugar are beet sugar,
corn syrup, imported cane sugar, molasses, and brown sugar.
Imports/exports. Raw sugar, produced from sugar cane, is produced in
some 38 countries. Imported raw sugar receipts in 1979 were 4,444,000
megagrams (4,900,000 tons) raw value, an increase of over seven percent
from 1978. Brazil, the leading shipper of raw sugar to the U.S., more than
doubled its 1978 shipments. Twelve other countries shipped more than
91,000 megagrams (100,000 tons) total to the U.S. in 1979.
U.S. exports of raw sugar in 1979 were 2,541 megagrams (2,802 tons).
The largest importer of U.S. sugar was Canada with approximately 2,157
38
megagrams (2,378 tons).
Time series data. The financial analysis of the sugar cane industry
is shown on Table 9-16. Profits were high during 1974 and 1975 as a result
of the sugar shortage during those years. Profits then declined from 1976
until last year when sugar prices rose and production increased.
Profits reflect sugar mill locations within the U.S. From 1971 to
1977, Hawaii experienced an unprecedented period of drought that reduced
production significantly. This was alleviated in 1978 and 1979. However,
production in 1978 was negatively affected by some early harvesting due to
such factors as smut disease and strikes. Since 1976, the net profit of
the sugar cane industry has been low, with capital expenditures to total
assets averaging 43 percent.
Information on financing investments is not complete due to the large
number of closely held companies and diversified large companies. The
9-44
-------
TABLE 9-15. HISTORIC TRENDS OF PRODUCTION FOR RAW CANE SUGAR MANUFACTURING INDUSTRY3
VD
Indicator
Production -
10 Mg (10 st)
Production/mill
10d Mg (10J st)
Producer price index
(1967 = 100)
Average price0 '
$/kg (
-------
TABLE 9-16.
FINANCIAL ANALYSIS ~ RAW SUGAR CANE MANUFACTURING INDUSTRY1
(Nominal terms)
Financial
indicator
1974 1975
1976
1977
Average
1978 1979 (1974-1979)
Capital expenditures
Total assets (106$) 77.20 92.70 90.10 89.30 90.70 101.10
Capital expenditures/
firm (10b$) 30.80
Capital expenditures/
total assets (%) 39.85
36.80 40.70 39.40 40.90 46.70
39.67 45.14 44.18 45.09 46.22
90.20
39.20
43.48
Profitability
taxes (10°$)
Return on assets (%)
Return on equity (%)
Return on sales (%)
Dividends ($/share)
Net earnings before
interest and taxes
(106$)
Capitalization
Interest on fixedfi
obligations (10°$)
Coverage ratio
Rating on bonds
Long-term debt (106$)
Stockholders' equity
(10b$)
Debt/capitalization
fQS\
\^* /
Debt/equity (%)
20.26
26.25
21.95
26.20
2.41
62.47
NAb
NA
NA
NA
92.29
NA
NA
24.76
26.72
22.73
27.94
2.19
46.29
NA
NA
NA
NA
108. 94
NA
NA
10.14
11.25
9.29
16.43
1.93
17.17
NA
NA
NA
NA
109.13
NA
NA
7.16
8.02
6.33
12.64
1.40
12.30
NA
NA
NA
NA
113.09
18.96
23.40
4.75
5.24
6.14
8.46
1.47
7.39
1.63
4.54
NA
24.42
77.47
23.97
31.52
9.78
9.67
10.85
14.53
1.59
14.82
2.75
5.38
A/Baa
45.11
90.14
33.35
50.04
12.81
14.53
12.88
17.70
1.83
26.74
2.19
5.00
A/Baa
32.00
98.51
24.52
32.48
aAverage/firm estimates for model firms (Securities and Exchange Commission;
EEA estimates).
NA denotes not available.
9-46
-------
family held companies and farmers cooperatives finance predominantly from
debt. The sugar corporations have been showing a similar trend over the
last few years.
Sugar cane prices reached an all time high of $1.58/kilogram ($0.72/
pound) on the spot market in 1974-1975. The value of shipments was also at
a high of $1.3 billion during 1974. Since that time, the value of shipments
has been gradually decreasing and production has been decreasing with the
exception of 1975 and 1976.
Internationally, world sugar consumption has been on the rise since
1974. Prior to 1974, the U.S. sugar market was regulated by legislation
designed to keep supply and demand in balance. In November 1979, the
International Sugar Agreement was ratified to maintain world sugar prices
within the $0.26 to $0.48/kilogram ($0.12 to $0.22/pound) range. However,
due to the current reduction in world supply, prices will probably climb in
1980. Speculators are anticipating $0.99/kilogram ($0.45/pound) on the
spot market. Sugar users believe these high prices will sap the sugar
39
market share and lead to the substitution of other sweeteners.
Five-year projections. Domestic sugar usage has been on the decline
since the early 1970's. It is likely that per capita consumption will
decline to around 187 kilograms (85 pounds) in the current decade, due to
the increased use of high fructose corn syrup.
Several raw sugar companies have entered into the substitute market.
The main concern of the raw sugar producers both now and in the future is
increasing competition from imported raw sugar. The compounded annual
real growth rate for 1980-1985 is forecasted at 3.3 percent.41
9.1.1.4.3 Steam use. Approximately 90 to 100 percent of bagasse
produced from the milling operation is burned as fuel. It is estimated
that approximately 67.52 x 1012 KJ (64 x 1012 Btu) gross heat value was
supplied by bagasse in 1979, producing 40.51 x 1012 KJ (38.4 x 1012 Btu) of
42
heat. Both Hawaiian and some Florida sugar mills generate electricity
from bagasse. In 1978, the Hawaiian plantations generated a total of 669
million kWh and sold 187 million kWh to local electric utilities. In
total, the Hawaiian plantations have roughly 180 megawatts of electrical
generating capability. The Hawaiian sugar industry produced 2.87 million
tons of bagasse in 1978 and burned 2.71 million tons as fuel.43 The U.S.
9-47
-------
Sugar Corporation, Florida's largest sugar cane producer, can generate 12 to
20 megawatts of electricity daily by burning up to 800 tons of bagasse.
Most of the steam required is used for machine drive. The major
manufacturing processes are described below.
• Milling. After the cane stalk enters the plant the juice is extracted
with knives, shredders, crushers, and mills.
• Clarification and filtration. Remaining impurities in the juice are
removed by a refining process. Clarification produces clarified juice
(which is sent to the evaporators) and precipitated sludge (which is
thickened by rotary vacuum filters).
• Evaporation. This is the most steam-intensive step in the milling
process. Evaporators concentrate the juice to obtain a syrup which is
about 60 percent solids.
• Crystallization. The sugar solution is super saturated to form crys-
tals in vacuum pans which are then placed in centrifugals, washed, and
discharged to storage.
• Packaging. The crystalline sugar is weighed, packaged, and moved to
storage on belt or screw conveyors. From bulk storage in the ware-
house, the sugar moves to refineries or is sent direct to market if
"refining" is done in-house.
9.1.2 Municipal Users
This section profiles four municipalities selected for analysis.
These municipalities operate nonfossil fuel fired boilers or are planning
to operate them in the near future. They are:
t Albany, New York
t Harrisburg, Pennsylvania
• Peekskill, New York
• Saugus, Massachusetts.
The selected municipalities represent four categories that could
exhibit different economic impacts: category one, publicly owned NFFB's in
economically distressed cities financed by State funds; category two,
publicly-owned NFFB's in economically distressed cities financed by munic-
ipal funds; category three, publicly owned NFFB's in economically stable
cities; and category four, privately run NFFB's. Albany, New York, falls
into the first category; Harrisburg, Pennsylvania, fits into the second
category; Peekskill, New York, into the third; and Saugus, Massachusetts,
into the last category.
9-48
-------
Table 9-17 lists the 44 municipalities that are currently operating
NFFB's or are planning to operate them. This list was employed for select-
ing members in each user category.
To select the municipalities in categories one and two, the U.S.
Department of Housing and Urban Development's (HUD) Urban Development
Assistance Grant (UDAG) Eligibility List (December 1978), which lists
economically distressed cities, was used. The list contains six indicators
of economic well-being which are:
• The percent of population change between 1960 and 1975
• The unemployment rate in 1977
• The ratio of retail and manufacturing jobs in 1972 to jobs in 1967
• Nominal growth in per capita income between 1969 and 1974
• The poverty factor — 1970 poverty level as a ratio of 1975 total
population
• The ratio of housing built before 1939 to total housing in 1970.
The list specifies a median value of all municipalities. Only cities
failing at least three of the six median values, that is, exceeding or
falling short of the median, depending on the specific indicator, are
included in the eligibility list. Municipalities that vary the most from
the national median values for the greatest number of indicators can be
considered the most economically distressed areas. Municipalities on the
UDAG list that are firing or considering firing nonfossil fuels were ranked
by the amount by which they failed each median. Albany and Harrisburg,
which failed all six indicators, had the the highest rankings; they were
chosen to represent marginal cities that operate NFFB's.
It is assumed that economically unstable municipalities may be more
sensitive to changes in project costs than are other municipalities.
Resource recovery projects are usually not high priority municipal expendi-
ture items and, as such, higher costs of pollution control may lead to
re-evaluation of a project more by municipalities that have unstable econo-
mic .bases than by cities that have stable infrastructures. Furthermore,
marginal cities typically have lower municipal bond ratings and conse-
quently may have more difficulty acquiring incremental capital under alter-
native control levels.
9-49
-------
The municipality in the third category was chosen because it is not on
the UDAG list. As such, it is an economically stable city and may have
impacts that differ from those users in the first and second categories.
This municipality was also chosen because it is planning NFFB's for 1984
and therefore may be an actual facility affected by the alternative control
level. The municipality in the last category is studied to analyze pri-
vately owned and operated facilities.
9.1.2.1 Albany. New York.
9.1.2.1.1 Municipality description. Albany, the capital of New York
State, located in Federal Region 2, is comprised of approximately 110,300
people (1975 estimate). Between 1960 and 1975 Albany's population declined
15 percent from 129,700 to 110,300.46
As explained in Section 9.1.2, HUD's UDAG Eligibility List (December
1978) ranks municipalities by indicators of economic well-being such as the
unemployment rate, change in retail and manufacturing employment, growth in
per capital income, poverty level, and age of housing. Compared to the
median national unemployment rate of 6.98 percent in 1977, Albany experi-
enced 8.16 percent unemployment. The ratio of retail and manufacturing
jobs in 1972 to 1967 was slightly lower in Albany than in the nation as a
whole — 0.94 in Albany as compared to 1.07 overall. Per capita income
between 1969 and 1974 grew $1,276 (nominal dollars) in Albany while it
increased $1,424 (nominal dollars) on average in all other municipalities.
The poverty level in 1970 as a percent of total population in 1975, showed
a similar trend. The median national factor was 11.24 percent; Albany's
was 13.94 percent. Finally, 75 percent of housing in Albany was built
before 1939 compared to 34 percent for all other municipalities. The age
of housing can affect the municipal tax base as older units are normally
assessed lower than newer units.
9.1.2.1.2 NFFB facility description. Albany's resource recovery
system, which is expected to come fully on-line by the end of 1981, is a
cooperative effort between New York State and Albany. The two parties have
separate responsibilities: the city will collect the garbage, convert it
into RDF, a more usable form of raw garbage, and transport it to the State's
boiler plant; the State will then burn the RDF in two new boilers and
produce steam for space conditioning in State office buildings. The city
will then take care of the disposal of post-combustion ash.
9-50
-------
TABLE 9-17. MUNICIPAL USERS OF NONFOSSIL FUEL FIRED BOILERS
a
Location
Process
Output
Nonfossil fuel
capacity
(tons per day)
Status
(on-line)
Akron, OH
Burns RDF
Steam for urban
and industrial
heating and
cooli ng
1,000
1980
ID
Ul
Albany, NY
State Energy Office
Auburn, ME
To burn RDF
Mass combustion
of MSW in small
modular combustion
units
Steam for 750
heating and
cooling State
office buildings
Steam 200
1981
11/1980
Baltimore, MD
Pyrolysis
Steam for use by
city utility
600
Operational
Batesvilie, AR
Mass combustion of
MSW
Steam
50
1981
Blytheville, AR
Mass burning of
of MSW
Steam
75
Unknown
-------
TABLE 9-17 (Continued). MUNICIPAL USERS OF NONFOSSIL FUEL FIRED BOILERS1
Location
Braintree, MA
Burley, ID
Chicago, IL
(Northwest
Incinerator)
VD
1
(Jl
ro
Columbus, OH
Process
Mass burning
Mass combustion
Waterwal 1
incineration
To burn shredded
refuse with coal
in boiler
Output
Steam, sells
half to industry
Steam
Steam for
industrial use
Electricity
for city
customers
Nonfossil fuel
capacity
(tons per day)
250
50
1,600
2,000
Status
(on-line)
1971
1980
1971
1982
Crossville, TN
Mass combustion
of MSW
Steam
60
Unknown
Dade County, FL
Unknown
Steam for 3,000
electric utility
1981
Detroit, MI
Burning in dedi-
cated boilers
Steam and/or
electricity
for Detroit
Edison
3,000
Unknown
-------
TABLE 9-17 (Continued). MUNICIPAL USERS OF NONFOSSIL FUEL FIRED BOILERS
a
Location
Process
Output
Nonfossil fuel
capacity
(tons per day)
Status
(on-line)
Duluth, MN
Fluidized bed
incineration of
RDF and sludge
RDF; steam for
heating and
cooling plant
and to run
equipment
400 MSW;
340 sludge
1980
10
en
Durham, NH
& Dyersburg, TN
Mass combustion Steam
of MSW
Mass combustion Steam
of MSW
108
100
1980
1980
Gal latin, TN
Mass burning in
waterwall combus-
tion
Steam for indus-
trial use and
electricity gene-
ration
200
1981
Gatesville, TX
Genessee Township, MI
Mass combustion Steam
Mass combustion Steam
of MSW
7
100
1981
1980
-------
TABLE 9-17 (Continued). MUNICIPAL USERS OF NONFOSSIL FUEL FIRED BOILERS*
Location
Process
Output
Nonfossil fuel
capacity
(tons per day)
Status
(on-line)
Glen Cove, NY
Mass burning
Steam for elec-
tricity for use
at sewage plant
225
Unknown
Groveton, NH
Mass combustion
of MSW
Steam
24
1975
to
i
Ut
Hampton, VA
Waterwal1
incineration
Steam for
use by NASA
Langley Research
Center
200
1980
Harrisburg, PA
Waterwal1
combustion
Steam for
utility*owned
district heating
system and city-
owned sludge
drying system
750
1972
Lakeland, FL
To burn RDF
with coal
Steam to produce
electricity for
use by city of
Lakeland and
Orlando Utility
Commission
300
1981
-------
TABLE 9-17 (Continued). MUNICIPAL USERS OF NONFOSSIL FUEL FIRED BOILERS'
Location
Lewisburg, TN
Nashville, TN
Process
Mass combustion
of MSW
Thermal
combustion
Output
Steam
Steam for urban
heating and
Nonfossil fuel
capacity
(tons per day)
60
400
Status
(on-line)
1981
1974
cooling
Ol
Newport News, VA
Niagara Falls, NY
Mass combustion
of MSW
Burns shredded
refuse
Steam
Steam/electri-
city for
industrial
use
40
2,200
1981
1980
Norfolk, VA
(U.S. Naval Station)
Mass burning in
waterwall furnace
Steam for use
by Naval Station
360
Operational
North Little Rock, AR
Mass combustion
of MSW
Steam
100
Operational
Oceanside, NY
Mass burning in
waterwall furnace
Steam for
electricity
generation
750
1965
-------
TABLE 9-17 (Continued). MUNICIPAL USERS OF NONFOSSIL FUEL FIRED BOILERS3
Location
Process
Output
Nonfossil fuel
capacity
(tons per day)
Status
(on-line)
Orange County, FL
(Walt Disney World)
Pyrolysis
incineration
High temper-
ature water
for heating
and cooling
100
Unknown
Osceola, AR
Mass coabustion
of NSW
Stec
50
1980
• Palestine, TX
o« •
o>
Mass coabustion
of NSW
Stee
28
1981
Peekskill, NY
Mass burning in
waterwall furnaces
Steaa and
electricity
for sale to
utility
1,500
1984
Pine11as County, FL
Mass burning
Electricity
to be sold to
Florida Power
& Light
2,000
1983
Pittsfield, MA
Mass combustion
of NSW
Steaa
240
9/1380
-------
TABLE 9-17 (Continued). MUNICIPAL USERS OF NONFOSSIL FUEL FIRED BOILERS3
Location
Process
Output
Nonfossil fuel
capacity
(tons per day)
Status
(on-line)
Portsmouth, VA
(Norfolk Naval Shipyard)
Mass burning in
vaterwall furnace
Steaa for use
use by facilities
at Naval Ship-
yards
160
1976
«£>
U>
-4
Portsmouth. VA
(Southeastern Tidewater
Energy Project)
Sale*, VA
To burn RDF
Mass combustion
of KSW
RDF, steam 2,000
and electricity
for shipyard
Steaa 100
1981
1979
Saugus, NA
Vaterwall
combustion
Steam for
electricity
generation and
industrial use
1,200
1975
Siloam Springs, AR
Mass combustion
Steam
16
1975
-------
TABLE 9-17 (Continued). MUNICIPAL USERS OF NONFOSSIL FUEL FIRED BOILERS0
Location
Process
Output
Nonfossil fuel
capacity
(tons per day)
Status
(on-1ine)
ID
Ol
oo
Waukesha, WI
Windham, CN
Mass burning in
refractory furnace
Mass combustion
of MSW
Steam for local
industry and
sewage treatment
plant
Steam
120
108
1981
1981
National Center for Resource Recovery. Resource Recovery Bulletin (10:3). September 1980.
-------
The RDF NFFB system will be mutually beneficial to both the city and
the State. The city, foreseeing insufficient landfill space in the near
future, needed a reliable long-term means with which to dispose of munici-
pal garbage. New York State, presently using oil-generated steam to heat
and cool State office buildings, foresaw the burning of RDF as a major
savings in fuel oil expenses.
The State and the city will share the costs of the project: the State
will own and operate the two new refuse burning boilers, while the city
will fund the refuse shredding equipment and the ash removal equipment.
Total capital costs of the project are reported at $26.6 million -- $15
million for the steam plant and $11.6 for the RDF processing plant.
Tables 9-18 and 9-19 present brief fiscal profiles of Albany and New
York State, respectively. While Albany's profile is included only as back-
ground material, New York's is depicted because it is financing the two new
boilers. Several expenditure indicators from the State profile will be
related to incremental costs from alternative control levels presented in
Section 9.2.
New York State is building the new RDF-fired plant adjacent to its six
existing oil-fired boilers that have a total heat input capacity of approx-
imately 176 MW (600 MMBtu/hr). The two new NFFB's will add another 94 MW
(320 MMBtu/hr) approximately for a total plant capacity of 270 MW (920
MMBtu/hr). The NFFB's will operate continuously (24 hours/day, 365
days/year) and will satisfy baseload steam needs. The existing, more
expensive oil-fired plant will then primarily satisfy peakload steam re-
quirements. By relying less on its oil-fired plant, and more on the new
RDF boilers, the State anticipates savings of $2 million to $2.5 million by
reducing fuel oil consumption by about 6.1 million gallons a year.
Table 9-20 depicts the boiler facility that is under construction in
Albany. By 1981 it is projected that two RDF boilers, each rated at ap-
proximately 42.9 MW (144.8 MMBtu/hr) heat input, will be operational. Each
boiler will be designed to consume a maximum of 272 megagrams (300 tons) of
refuse derived fuel per day. Particulate matter emissions will be curtailed
through use of an electrostatic precipitator on each boiler.
The following are some salient points regarding resource recovery at
the Albany NFFB facility:
9-59
-------
• RDF will be collected from the municipal waste processing center and
stored in pits at the steam generating plant. A supply of oil is kept
on hand in case there are inadequate refuse quantities or if refuse
for some reason becomes uneconomical.
• RDF will be fired in two boilers that are each capable of handling 272
megagrams (300 tons) of RDF per day.
• Each NFFB will have an electrostatic precipitator to control emissions
of particulate matter.
• Post-combustion ash will be collected and used as a substitute for
gravel.
9.1.2.2 Harrisburg. Pennsylvania.
9.1.2.2.1 Municipality description. Harrisburg, the capital of
Pennsylvania, located in Federal Region 3, comprises approximately 58,300
people (1975 estimate). The major industries in the area include steel
works and rolling mills, blast furnaces, railroad repair shops, printing
49
and publishing, slaughtering and meat packing.
In recent years the city of Harrisburg has faced various social and
economic problems, including declining population, mediocre bond rating,
unemployment at a rate higher than the national average, declining manufac-
turing base, small growth in per capita income, and a high poverty level.
Between 1960 and 1975, the population of Harrisburg declined 27 percent
from 79,700 to 58,300. In Moody's Municipal and Government Manual 1980.
Harrisburg received an average credit rating of Baa (on a scale of Aaa to
C) on its general debt obligations.
Harrisburg performed below the national average in all UDAG indicators
of municipal economic well-being. Harrisburg's unemployment rate was 7.6
percent in 1977 while the median national rate was approximately 6.98
percent. Retail and manufacturing jobs in 1972 as a percentage of 1967 was
much lower in Harrisburg than in the entire nation; the nation's median
ratio was 1.07, while Harrisburg's fraction was only 0.84. Per capita
income growth between 1969 and 1974 showed a similar trend. The national
median change during that period was $1,424 (nominal dollars), yet the
change in Harrisburg was only $1,180 (nominal dollars). Relating the
poverty level in 1970 to total population in 1975, Harrisburg experienced
23.83 percent poverty compared to the national median of 11.24 percent.
Finally, 74 percent of Harrisburg's buildings were constructed prior to
1939, compared to 34 percent nationally.
9-60
-------
TABLE 9-18. FISCAL PROFILE OF ALBANY, NEW YORK*
1962
Item
Population
General revenue:6
From federal/state
From city
Utility revenue6
General expenditures:6
Education
Transportation
Health & safety9
Sewerage & sanitation
Interest on debt
All other
Utility expenditure6
Long-term debt6
Amount
129,726b
18,676
4,157
14,519
1,845
17,942
8,093
1,375
2,930
754
797
4,001
1,445
29,250
%
100.0
22.3
77.7
—
100.0
45.1
7.7
16.3
4.2
4.4
22.3
—
1967
Amount
129,726b
25,222
8,340
16,882
1,792
33,655
10,852
1,999
3,546
954
1,204
15,111
1,910
33,298
%
—
100.0
33.1
66.9
—
100.0
32.3
5.9
10.5
2.8
3.6
44.9
—
—
1972
Amount
115,781C
44,621
20,669
23,952
2,288
51,358
20,350
3,758
6,646
5,958
3,212
11,453
2,351
20,166
%
—
100.0
46.3
53.7
—
100.0
39.6
7.3
12.9
11.6
6.3
22.3
—
1977
Amount
110,311d
43,554
18,539
25,015
797
48,460
835
3,482
11,744
7,622
3,329
21,468
3,975
55,099
%
100.0
42.6
57.4
100.0
1.7
7.2
24.2
15.7
6.9
44.3
—
—
Department of Commerce. Bureau of the Census. 1967, 1972, 1977 Census of Governments.
b!960 Census.
C1970 Census.
d!975 estimate.
6103 dollars.
Includes education and libraries.
Includes health, hospital, police, and fire protection.
-------
TABLE 9-19. FISCAL PROFILE OF NEW YORK STATE*
Item
Population
Revenue
Taxes:
Income tax
Business
Sales
Other taxes
Other
Total expenditures
Local assistance:
Education
Social welfare
General assistance
Health
Housing
Other
State purposes:
Education
Health
Executive
Transportation
Other
Capital construction
Debt service
1974
Amount
18,111,000
8,635.3
8,102.1
3,352.0
1,296.1
1,863.2
1,590.8
533.2
8,508.0
5,110.8
2,817.9
1,250.0
548.6
226.8
68.4
195.7
2,741.7
707.1
599.7
267.1
207.2
969.9
360.2
295.3
%
100.0
93.8
38.8
15.0
21.6
18.4
6.2
100.0
60.0
33.1
14.7
6.4
2.7
0.8
2.3
32.2
8.3
7.0
3.1
2.4
11.4
4.2
3.5
1978
Amount
17,748,000
11,148.2
10,475.4
4,476.2
1,998.8
2,412.3
1,588.1
672.8
11,146.8
6,633.5
3,512.1
1,716.5
718.6
242.2
61.6
379.0
3,651.8
855.6
758.5
326.9
239.9
1,471.4
445.2
416.2
%
100.0
94.0
40.2
17.9
21.6
14.2
6.0
100.0
59.5
31.5
15.4
6.4
2.2
0.6
3.4
32.8
7.7
6.8
2.9
2.2
13.2
4.0
3.7
aMoody's Municipal and Government Manual 1980; The Statistical Abstract,
1975; The Statistical Abstract, 1979.
b!03 dollars.
9-62
-------
TABLE 9-20. BOILER CONFIGURATION OF THE
ALBANY, NEW YORK, NFFB FACILITY
Boiler plant
Total firing rate in MW
(MMBtu/hr) heat input: 71.6 (244)
Total number of boilers: 2
Characteristics of individual boilers
Boiler #
Heat input capacity 42.9 (144.8)a 42.9 (144.8)a
MW (MMBtu/hr)
Megagrams of RDF/day 272 (300) 272 (300)
capacity (tons/day)
Fuel design type RDF RDF
Process employed Direct firing Direct firing
of RDF of RDF
Conversion from tons/day to MMBtu/hour assumes 5790 Btu/lb of RDF.
9-63
-------
Table 9-21 presents the fiscal characteristics of the city over the
years 1962, 1967, 1972, and 1977. As the table shows, shifts have occurred
in the shares of the items that comprise general revenue. In 1977, a
greater share of revenues came from State and Federal revenues and less
from the city of Harrisburg itself than in any of the three previous years
shown. This has meant a greater reliance on outside sources to carry the
city through its expenditure needs. Shares of general expenditures have
fluctuated through the years. By 1977, health and safety (hospitals,
police, and fire protection), sewerage and sanitation, and transportation
expenses comprised the largest expenses.
9.1.2.2.2 NFFB facility description. The city of Harrisburg has been
operating two solid waste heat recovery (waterwall combustion) units since
1972. Municipal, commercial, and industrial wastes are collected from
nearby areas and converted to steam energy. Each steam unit is capable of
processing 379 megagrams (360 tons) of refuse daily or, assuming 4,875
Btu's per pound of refuse, 3,703.1 million GJ (3,510 million Btu's). The
facility had functioned previously as a municipal incinerator but was
retrofitted in the early 1970's to produce steam energy. The boilers serve
two needs: they dispose of accumulated wastes and they produce steam to
heat and cool city buildings, a savings in fuel expenses.
Table 9-22 outlines the configuration of the Harrisburg NFFB facility.
The plant consists of two boilers, each of which has a design heat input
rating of 42.8 MW (146 MMBtu/hr). Correspondingly, each boiler is capable
of consuming 327 megagrams (360 tons) of refuse per day. The plant is
functioning continuously. Each furnace is equipped with an electrostatic
precipitator (ESP) to control emissions of particulate matter.
The steam generated at the NFFB plant has a variety of uses. One
share of the steam produced is channeled through a downtown Harrisburg
heating system of Pennsylvania Power & Light Company. A two-mile steam
pipe was completed in 1978 and steam sales to that system began by the end
of the year. Steam serves in-house needs also -- to power the refuse
shredder turbine, heat the steam plant in the winter, and serve some nearby
municipal buildings.
In the near future, steam will be used in a sludge drying process at
the plant. The NFFB's are being modified to accept dried sewage sludge
9-64
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TABLE 9-21. FISCAL PROFILE OF HARRISBURG, PENNSYLVANIA'
(£>
Ul
1962
Item
Population
General revenue:6
From federal/state
From city
Utility revenue6
General expenditures:6
Education
Transportation
Health & safety9
Sewerage & sanitation
Interest on debt
All other
Utility expenditure
Long-term debt
Amount
79,697b
6,850
1,824
5,026
881
5,999
5
932
1,436
1,133
123
2,376
568
2,505
%
—
100.0
26.6
73.4
100.0
15.5
23.9
18.9
2.1
39.6
1967
Amount
79,697b
7,484
927
6,557
912
6,912
10
1,400
1,871
1,285
118
2,233
775
3,675
%
100.0
12.4
87.6
100.0
20.3
27.1
18.6
1.7
32.3
—
—
1972
Amount
68,061C
11,419
3,110
8,309
1,064
13,140
1,304
3,100
1,851
166
6,715
479
4,286
*
—
100.0
27.2
72.8
—
100.0
—
9.9
23.6
14.1
1.3
51.1
—
—
1977
Amount
58,274d
17,258
5,554
11,704
1,857
15,352
20
1,647
4,578
2,720
542
5,880
752
8,157
%
100.0
32.2
67.8
100.0
10.7
29.8
17.7
3.5
38.3
Department of Commerce. Bureau of the Census. 1962, 1967, 1972, 1977 Census of Governments.
1960 Census.
C1970 Census.
d!975 estimate.
e!03 dollars.
Includes education and libraries.
^Includes health, hospital, police and fire protection.
-------
TABLE 9-22. EXISTING BOILER CONFIGURATION
OF THE HARRISBURG, PENNSYLVANIA, NFFB FACILITY
Boiler plant
Total firing rate in MW
(MMBtu/hr) heat input: 85.6 (292)
Total number of boilers: 2
Characteristics of individual boilers
Boiler #
Heat input capacity MW 42.8 (146) 42.8 (146)
(MMBtu/hr)a
Megagrams of refuse/day capacity 327 (360) 327 (360)
(tons/day)
Fuel design type Refuse Refuse
Process employed Incineration Incineration
aAssumes 4875 Btu/lb of refuse.
9-66
-------
along with municipal solid waste. Wet sludge must first be pumped in from
a wastewater treatment plant and then dewatered in filters and dried in
steam-heated dryers.
The plant cost approximately $8.3 million to build and convert. Pro-
ject financing came primarily from a municipal bond issue and a Federal
grant. This cost estimate does not include land and the more recent steam
pipeline and sludge drying systems.
The following briefly outlines important points about the resource
recovery at the Harrisburg plant:
• Private refuse haulers deliver truckloads of municipal garbage to the
processing site. A tipping fee of $8 to $12/megagram ($9 to $13/ton)
is charged.
• Refuse is delivered to the site at a daily rate of approximately 454
megagrams (500 tons).
• Usually one boiler is in operation at a time; however, when accumu-
lations of refuse are high, both boilers may operate simultaneously.
• Only bulky items are shredded before combustion in the furnaces.
• The furnaces have electrostatic precipitators to control particulate
matter emissions.
9.1.2.3 Peekskill. New York.
9.1.2.3.1 Municipality description. Peekskill, New York, situated in
Federal Region 2, comprises 20,552 people (1975 estimate). Table 9-23
shows a brief fiscal profile of Peekskill. In each year studied, succes-
sively greater shares of revenues have come from Federal and State sources
and less from the city of Peekskill itself. In 1962, approximately 87
percent of revenue sources come from the city and 13 percent from New York
State and Federal funds; however, in 1977, the shares of total revenues
were almost equally split between city sources and State and Federal sources.
At the same time, the size of the overall budget almost quadrupled during
the 16-year period studied. On the municipal expenditure side, health and
safety, transportation, and sewerage and sanitation took the largest shares
of city funds in the four years presented.
Peekskill was selected for analysis because it is not economically
distressed as were several of the other municipalities chosen. As a more
economically stable city, it should be able to afford an NFFB even under a
9-67
-------
more stringent control level. Furthermore, economic factors may be less
important than is the need to alleviate a potential waste disposal problem.
Therefore, Peekskill represents a different NSPS impact candidate.
9.1.2.3.2 NFFB facility description. The city of Peekskill and the
county of Westchester are the two main participants in planning the NFFB
facility. The city will house the steam producing plant. The county
presently manages Westchester1s waste disposal. As the plant is expected
to begin producing steam in 1984, specific details on its eventual opera-
tion are unknown.
It is reported that the facility could consume annually between
453,500 and 498,850 megagrams (500,000 and 550,000 tons) of garbage to
generate steam primarily for electricity. Table 9-24 depicts salient
characteristics of the New York plant at completion according to present
plans. The plant is expected to contain two MSW boilers each capable of
firing 85.7 MW (292 MMBtu) heat input.
The new plant is expected to burn eventually more than half the gar-
bage now generated in Westchester County. Thirty-four nearby communities
are planning to supply garbage to the plant. The energy that is to be
produced will fulfill the electricity needs of Peekskill and several nearby
cities and may be sold at a later date to electric utilities such as Con-
solidated Edison and the Power Authority of the State of New York.
It is estimated that the new plant will cost approximately $80 mil-
52
lion. Project financing may come from several sources — project revenue
bonds issued by the County's Industrial Development Agency and $27 million
in New York State Environmental Quality Bond Act funds. A $17/ton tipping
fee charged in the first five years of operation is expected to offset some
of the project costs.
9.1.2.4 Saugus. Massachusetts.
9.1.2.4.1 Municipality description. Saugus, Massachusetts, ten miles
north of Boston, is located in Federal Regiton 1. It is a small residential
suburb of approximately 24,600 people (1975 estimate) whose population
54
increased over 19 percent between 1960 and 1975.
9.1.2.4.2 NFFB facility description. The Saugus, Massachusetts
resource recovery facility has been collecting municipal refuse and gener-
ating steam continuously since 1975. Presently, waste products are re-
9-68
-------
TABLE 9-23. FISCAL PROFILE OF PEEKSKILL, NEW YORK*
CD
1962
Item
Population
Genera] revenue:6
From federal /state
From city
Utility revenue6
General expenditures:
Education
Transportation
Health & safety9
Sewerage & sanitation
Interest on debt
All other
Utility expenditure6
Long-term debt
Amount
18,337b
1,537
206
1,331
373
1,530
28
296
399
320
73
415
352
4,905
%
100.0
13.4
86.6
—
100.0
1.8
19.3
26.1
20.9
4.8
27.1
—
1967
Amount
18,337b
1,839
381
1,457
393
2,353
37
271
532
688
53
772
366
857
%
—
100.0
20.7
79.2
—
100.0
1.6
11.5
22.6
29.2
2.3
32.8
—
—
1972
Amount
19,283C
3,516
1,137
2,379
475
3,578
56
290
917
357
185
1,771
704
2,390
%
—
100.0
32.3
67.7
100.0
1.6
8.1
25.6
10.0
5.2
49.5
—
—
1977
Amount
20,552d
7,154
3,466
3,688
849
7,310
110
1,312
1,595
411
344
3,545
733
4,420
%
100.0
48.4
51.6
10.6
100.0
1.5
17.9
21.8
5.6
4.7
48.5
—
Department of Commerce. Bureau of the Census. 1962, 1967, 1972, 1977 Census of Governments.
b!960 Census.
C1970 Census.
1975 estimate.
6103 dollars.
Includes education and libraries.
Includes health, hospital, police, and fire protection.
-------
TABLE 9-24. BOILER CONFIGURATION OF THE
PEEKSKILL, NEW YORK, NFFB FACILITY
Boiler plant
Total firing rate 171.4 (584)
in MW (MMBtu/hr)
Total number of boilers: 2
Characteristics of individual boilers
Boiler #
Heat input capacity3 85.7 (292) 85.7 (292)
MW (MMBtu/hr)
Megagrams of refuse/day
capacity (tons/day) 652.3 (719) 652.3 .(719)
Fuel design type MSW MSW
Process employed Mass combus- Mass combus-
tion tion
aAssumes 4875 Btu/lb of refuse.
9-70
-------
ceived from nearby communities and burned in boilers to provide steam
solely for local industrial use.
Although it burns municipal wastes, the plant is not owned and oper-
ated by the city of Saugus. Rather, the Refuse Energy Systems Co. (RESCO),
a private company formed by the joint venture of Wheelabrator-Frye, Inc.
and M. DeMatteo Construction Company, owns and operates the Saugus plant.
DeMatteo Construction Co. had been the owner of a major landfill servicing
many communities in the area that was closed for environmental reasons.
The company still wanted to provide the waste disposal service and there-
fore pursued the RESCO project along with Wheelabrator Frye.
The Saugus facility cost approximately $40 million (1975 dollars),
$30 million of which came from solid waste disposal revenue bonds and $10
million resulting from equity of the two parties.
Two factors ensure a constant revenue base for the plant. First,
long-term contractual arrangements with local municipalities guarantee an
adequate supply of refuse and tipping fees. Second, a contractual indus-
trial purchaser of steam ensures a regular flow of revenues.
Refuse is received from 18 nearby communities that currently pay $17.I/
megagram ($15.5/ton) to dispose of their municipal refuse. In the near
future the number of these contractual arrangements is expected to rise as
the tipping fees charged to the municipalities become more competitive with
the costs of alternative waste disposal.
A General Electric (GE) plant located directly across from the Saugus
facility purchases 100 percent of the steam generated via a steam pipe.
Coincidentally, when RESCO was considering building the resource recovery
plant several years ago, GE needed to replace two boilers to satisfy its
steam needs. Instead of purchasing new boilers, GE agreed to buy its steam
requirements from the resource recovery facility. GE saved the costs of
new boilers and RESCO gained a steam customer.
Table 9-25 shows the basic configurations of the refuse-fired boilers
in Saugus. Two MSW-fired boilers each rated at 89.4 MW (305 MMBtu/hr) heat
input are operating. Each boiler is capable of processing daily 680 mega-
grams (750 tons) of refuse.
The Saugus facility employs the waterwall combustion technology for
converting municipal wastes to steam energy. The following briefly out-
lines the flow of refuse to energy at the plant:
9-71
-------
• Refuse collection trucks haul municipal waste to the plant's receiving
pit, a container capable of holding 6,349 megagrams (7,000 tons) of
garbage or approximately a five-day supply of refuse for the two
boilers.
• Normally refuse as-received is charged into the boilers. Only overly
large items are shredded.
• An electrostatic precipitator controls air emissions.
• 100 percent of the steam generated is conveyed to the nearby GE plant.
• Two standby oil-fired boilers of the same general capacity are main-
tained to guarantee a reliable supply of steam.
9.2 ECONOMIC IMPACT ANALYSIS
9.2.1 Introduction
This section discusses the economic impacts on industrial and munici-
pal users of nonfossil fuel fired boilers (NFFB) resulting from a New
Source Performance Standard (NSPS) and the methodology used to determine
those impacts. Presently, NFFB's are subject to emission regulations
required by the State Implementation Plans (SIPs). These emission regula-
tions constitute the base case level of pollution control and serve as a
baseline for comparison to alternative pollution control levels. This
analysis assumes that in the base case all NFFB's are covered under the
applicable SIP. The ensuing analysis seeks to identify the incremental
pollution control costs and the economic impacts that could result from
requiring controls that are more stringent than those employed in response
to State regulations.
9.2.2 Impact on Selected Industrial Users
This section outlines the methodology used to assess economic impact,
discusses the potential impacts on the five manufacturing industries, and
presents the model plant parameters and selected control level results for
each of the five industries.
9.2.2.1 Methodology of Economic Impact Analysis. The economic impact
analysis of selected industries focuses on the effect Control Levels I and
II have on product cost and price, profitability, and capital availability.
9.2.2.1.1 Product cost impacts. To estimate the impact of alterna-
tive control levels on production costs, three determinations are made: a
model plant for the selected industry is defined, cost impacts for the
9-72
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TABLE 9-25. EXISTING BOILER CONFIGURATION OF THE
SAUGUS, MASSACHUSETTS, PLANT
Boiler plant
Total firing rate in MW
(MMBtu/hr) heat input: 178.8 (610)
Total number of boilers: 2
Characteristics of individual boilers
Boiler #
Heat input capacity3
MW (MMBtu/hr)
Megagrams of refuse/day
1
89.4 (305)
680 (750)
2
89.4 (305)
680 (750)
capacity (tons/day)
Fuel design type MSW MSW
Process employed Mass burning Mass burning
Conversion from tons/day to MMBtu/hr assumes 4875 Btu/lb of refuse.
9-73
-------
model plant are determined, and the ability of the firm to either absorb
the incremental costs incurred by the alternative control levels or pass on
the additional costs is discussed.
The selected industries analysis uses model plants to measure the
economic impact of alternative control levels on each industry. A model
plant is used because it is difficult to obtain precise details about the
expansion and replacement plans of actual industries. The model firm and
plant/mill configurations were based on the following indicators:
• The firm represents that portion of the industry most likely
to invest in a new boiler due to its market share.
• The plant/mill represents what is "typical" for that portion
of the industry.
• The boiler expansion or replacement decision is based on both
the economics of the industry and its projected growth rate
for the next five years.
For this analysis, 'each plant within the industry is assumed to be
identical with regard to steam use relative to product output. The fuel
type burned in the existing boiler(s) of the model plant is determined by
industry survey.
The following production characteristics of the model plant are sup-
plied:
• Plant output/year. Average product output per year in those
plants most likely to invest in new boilers.
• Producer price/unit of output. The historic average selling
price per unit, in 1978 dollars.
• Plant sales/year. Plant output per year multiplied by price
per unit of output.
• Plant earnings/year. Plant sales per year multiplied by a
derived profit margin. This figure estimates the profit-
ability of the model plant.
The effect of alternative emission control levels on product cost is
calculated from the new cost of steam, the share of steam affected by the
regulation, and the amount of steam consumed per dollar of output. The
cost impacts are stated in real 1978 terms. All other production costs are
held constant.
9-74
-------
In this analysis, wholesale prices are used as a proxy for production
cost. Retail prices are not used since they are subject to variables, such
as price markups, that would not occur as a direct result of the alterna-
tive control levels.
The ability of an industry to pass on the additional costs of alter-
native emission regulations is evaluated. The competitive market position
of an industry's product determines the extent to which an industry can
pass on additional costs.
9.2.2.1.2 Profitability impacts. The financial well-being of the
industry determines its ability to absorb additional costs. The second
consideration, therefore, is profitability impacts; that is, how incre-
mental costs of emission control affect two profitability indicators —
return on sales and return on total assets. To determine this impact, a
new net profit figure is calculated. The percent change in producer price
due to the control level is multiplied by base case income statement ex-
penses to yield a total dollar change. This dollar change is then added to
base case expenses and a net profit under the alternative control level is
calculated. Sales are assumed to be constant for all selected control
levels and expenses increase only as a result of the new boiler investments.
A new return on sales and return on assets due to the regulation can then
be calculated and compared to the same ratios in the base case.
9.2.2.1.3 Capital availability. Capital availability constraints may
result if alternative emission regulations create a need for financing
additional pollution control investments. The following steps are used to
evaluate whether capital availability will be a constraint for a selected
industry: one, define financial indicators for the model firm; and two,
evaluate the ability of a firm to finance pollution control investments.
The firm is the focus of the financial analysis because decisions
involving large capital expenditures are made at the corporate level.
Depending upon the state of corporate cash reserves and the relative costs
of various financing tools, a firm will choose a combination of internal
and external financing instruments to meet the additional investments re-
quired to comply with alternative regulations.
The capital availability analysis focuses on the following two finan-
cial indicators that measure each industry's financing ability:
9-75
-------
• Cash flow coverage ratio. The number of times operating
income (earnings before taxes and interest expenses) covers
fixed obligations (annual interest on debt instruments and
long-term leases).
• Book debt/equity ratio. A measure of the relative proportions
of two types of external financing.
These two indicators are analyzed under the base case and under the
alternative control cases. The change in indicators due to alternative
control levels is analyzed to determine how difficult it might be for the
firm to meet financial requirements for the pollution control equipment
investment.
The cash flow coverage ratio is calculated by dividing operating in-
come by fixed obligations. Both the operating income and fixed obligations
could change as a result of alternative control levels. If the coverage
ratio remains above 3.0, a standard benchmark, the cost of capital can be
assumed to be above "acceptable" levels. Note, however, that as the cover-
age ratio falls, the cost of obtaining capital will rise.
The debt/equity ratio is calculated by dividing total long-term debt
by total equity of the firm (book values). The incremental debt incurred
from financing the pollution control required by alternatives is added to
the base case debt; the incremental equity issued to finance the remainder
of the investment is added to the base case equity. A new debt/equity
ratio then is calculated. The change in the debt/equity ratio is analyzed
to see how the alternatives will affect the firm's capital structure.
To determine the coverage and debt/equity ratios under the alterna-
tives, five financing strategies are considered, which differ by the per-
centages of the investment financed by new debt versus new equity. (Note
that for the changes in coverage ratios and debt/equity ratios, 100 percent
external financing is assumed.) These external financing scenarios are:
1) zero percent new debt, 100 percent new equity; 2) 25 percent new debt,
75 percent new equity; 3) 50 percent new debt, 50 percent new equity; 4) 75
percent new debt, 25 percent new equity; and 5) 100 percent new debt, zero
percent new equity.
The financial indicators generated for this analysis were derived from
a variety of published sources. Robert Morris Associates' Annual Statement
Studies was consulted for composite industry financial data. More specific
9-76
-------
corporate figures were collected from Moody's Industrial Manuals. Form 10-K's.
and Annual Reports on file at the Securities and Exchange Commission.
9.2.2.2 Summary of Results. The results of the economic analysis
indicate that the alternative control levels examined do not significantly
affect the selected industrial users. Any impact resulting from the alter-
native control levels is summarized in Table 9-26 and explained in more
detail in the following sections, which describe the model plant/mill and
selected control level results for each industry. As seen in Table 9-26,
all industries experience a product price increase of less than one percent.
This is significantly lower than the five percent benchmark established by
EPA. In the change in profit margin analysis, no industry experiences a
significant decline in net income due to increased expenditures from the
boiler investment. The return on assets percentage decline is also insig-
nificant under the Level II alternative. The capital availability analy-
sis, which assumes that the most stringent control level is required at 100
percent new debt financing, indicates that all industries can obtain addi-
tional capital.
9.2.2.3 Furniture Manufacturing Industry.
9.2.2.3.1 Model plant description. The major characteristics of the
model firm are listed in Table 9-27. Financial characteristics are based
on 1978 data taken from Table 9-3 in Section 9.1.
This model plant is located in the southern United States (Federal
Region 4) where the furniture industry concentration is greatest. The
plant is run continuously.
Total annual plant sales of furniture average $5 million. Production
figures are not commonly used as a basis for comparison in the furniture
industry since there are so many different categories of furniture (such as
bedroom and dining room) and varying types within those categories (such as
tables and chairs). Net profits for the model firm are assumed to be 3.3
percent of total sales or about $167,000. With industry sales estimated at
$9.3 billion, this firm represents approximately 0.05 percent of the furni-
ture market.
The model plant boiler house consists of three wood-fired boilers with
a total heat input capacity of 26.4 MW (90 MMBtu/hr). Model boiler #1,
found in Section 6, is closest in size to the furniture industry's existing
9-77
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two wood-fired boilers of 4.7 MW (16 MMBtu/hr) at 100 and 50 percent
capacity utilization. Table 9-27 describes the individual boilers. The
first boiler is operated at capacity the entire year. The second boiler is
operated as a supplemental boiler during the winter months. Coal and fuel
oil are used as a supplemental fuel during three months in the winter.
Since these fossil fuels only contribute approximately 6 percent during the
entire year, the two boilers are still classified as wood-fired. During the
summer months, all of the steam is generated for process use. During the
winter, only 40 percent of total steam is generated for process use and the
remaining 60 percent is generated for space heat. The boiler investment
decision is to replace the standby boiler. This new wood-fired boiler would
generate one-third of total steam at the plant. The furniture industry is
interested in generating its electricity through cogeneration; however, this
would require a change in the present electric rate structure.
9.2.2.3.2 Selected control level results. The model plant replacement
boiler is assumed to be a wood-fired boiler requiring PM control at all
selected control levels. The price impacts of the selected control levels
for the furniture industry cannot be assessed due to the absence of price
and production figures. Lacking this information, the change in product
price and the change in profit margin is not calculated.
Table 9-28 shows the pre-tax 1978 boiler and pollution control costs
for the two selected control levels for the furniture industry. The two
selected control levels, explained in Chapter 6, are represented by model
boiler #lb, which requires 97 percent PM reduction [64.5 ng/J
(0.15 Ib/MMBtu) ceiling] and model boiler #le, which requires 99 percent PM
reduction [21.5 ng/J (0.05 Ib/MMBtu) ceiling]. Boiler and pollution control
costs for the boiler investment range from about $1.9 million in the base
case to $2.3 million in the 99 percent PM reduction level.
As seen in Table 9-29, the steam requirement per unit of output is
estimated at 0.95 GJ (0.90 MMBtu). Since there are no price or production
figures for furniture, the increase in the cost of new steam per dollar
output cannot be calculated.
9-78
-------
TABLE 9-26. ECONOMIC IMPACT ANALYSIS SUMMARY — INDUSTRIAL USERS
to
Increase .
in product price '
Selected
industries
Furniture
Sawmi 1 1
Plywood
Paper
Sugar cane
Percent
NAf
0.58
0.32
0.06
0.38
Absolute
(I/unit)
NAf
0.00
0.00
0.00
0.00
Decrease .
in profit margin ' '
Net income
(106$)
NAf
0.02
0.03
0.04
0.08
Return on
assets
NAf
0.29
0.15
0.02
0.09
Range of capital
availability ratios
Debt
coverage
5.99-5.88
7.38-7.33
7.38-7.33
6.98-6.76
4.54-3.16
Debt/equity
0.37-0.38
0.49-0.49
0.49-0.49
0.48-0.50
0.29-0.40
-------
Baa
6.0
37.9
TABLE 9-27. MODEL FIRM AND PLANT CONFIGURATION —
FURNITURE MANUFACTURING INDUSTRY3
Model firm
Financial data
Average bond rating:
Coverage ratio:
Debt/equity ratio (%):
Model plant
Production data
Plant output/year:
Price/unit output:
Plant sales/year:
Plant earnings/year:
Boiler configuration
Total firing rate:
Number of boilers:
Characteristics of individual boilers
NAL
NA
$5.0 million0
$167.0 thousand
26.4 MW (90 MMBtu/hr)
3
Capacity (MW [MMBtu/hr
heat input])
Fuel type (base case)
Annual capacity utilization (%)
Replacement, expansion
or existing
1
8.8
(30)
Wood
60
Boiler #
2
8.8
(30)
Wood
60
— Existing —
3
t
8.8
(30)
Wood
60
Replacement
Based upon 1978 values.
NA denotes not available.
cBased upon the average production of the firm most likely to invest in
a new boiler.
Based upon the 1978 return on sales ratio of 3.3 percent.
9-80
-------
TABLE 9-28. BOILER COSTS — FURNITURE MANUFACTURING INDUSTRY
ID
00
Model boiler #
Total boiler & pollution
capital costs ($10b)a
Annuali zed total boiler and
pollution control cost
$/GJ ($/MMBtu)a
Capital
0&Mb
Total
Control technology
PM emission rate
ng/J
(Ib/MMBtu)
la (base case)
1.9
1.24
(1.31)
4.17
(4.40)
5.41
(5.71)
MC
258.00
(0.60)
Ib
2.2
1.45
(1.53)
4.44
(4.68)
5.89
(6.21)
MC/WS
64.50
(0.15)
le
2,3
1.57
(1.66)
4.48
(4.73)
6.05
(6.39)
MC/ESP
21.50
(0.05)
*1978 dollars.
Includes general and administrative expenses, taxes, insurance, interest on working capital, and
capital recovery. Assumes a 10.15 percent discount rate.
-------
TABLE 9-29. CHANGE IN PRODUCT PRICE — FURNITURE MANUFACTURING INDUSTRY
00
ro
Model boiler #
GJ Steam/unit output3
(MMBtu steam/unit
output)
Percent of new.steam/
unit product
Cost of new steamc'd
($/GJ [MMBtu])
la (base case)
0.95
(0.90)
33.3
5.41
(5.71)
Ib
0.95
(0.90)
33.3
5.89
(6.21)
le
0.95
(0.90)
33.3
6.05
(6.39)
Cost of new steam ($/ 1.71 1.87 1.92
unit output)
Average product price/unit NA NA NA
Percent increase in product
price over the base case NA NA
aEstimated from industry contacts.
Based on the model plant configuration, the new boiler represents one-third of total steam.
cSteam costs are from Chapter 8.
d!978 dollars.
-------
Table 9-30 presents comparative coverage and debt/equity ratios for the
selected control levels. The coverage ratio declined insignificantly from
5.99 to 5.88 over the five financing options and shows no significant
difference between selected control levels. The debt/equity ratio increased
from 0.37 to 0.38. Neither of these ratios suggest problems in obtaining
capital for industry in any of the selected control options. The coverage
ratios for all financing options fall above the 3.0 coverage benchmark.
9.2.2.4 Lumber Products Industry.
9.2.2.4.1 Sawmill industry.
Model plant description. The model firm and mill configuration for the
sawmill industry is presented in Table 9-31. The model mill is one of two
mills depicting the lumber products industry. The mill is assumed to be
part of a 14 mill firm. Financial data are taken from Table 9-8 in
Section 9.1 and are based on 1978 data.
This model is located in southern United States (Federal Region 4), the
area of greatest potential growth for the lumber industry. The mill is run
continuously throughout the year.
9-83
-------
Total annual mill production is estimated at 30 to 40 million board
feet which represents the average production for a 30 to 46 MMBtu bark
boiler. Annual sales are $9.6 million and usually represent only one
segment of a wood products company. Annual profits are 6.7 percent of
sales or about $643,000.
A significant number of mills owned by large corporations may include
an additional plywood or reconstituted board mill at the same site, sharing
the steam produced. Data for this model mill represent only the sawmill
operation. This mill accounts for 0.11 percent of the lumber market, based
on production figures.
The model mill boiler house consists of two wood waste-fired boilers
with a total heat input capacity of 17.6 MW (60 MMBtu). Model boiler #1,
found in Section 6, is closest in size to the existing wood boiler in the
sawmill industry at 80 percent capacity. Table 9-31 describes the indivi-
dual boilers. The first boiler provides all the steam for the sawmill
operation. The boiler investment decision is to replace this boiler with
the second boiler of the same capacity. This boiler provides one half of
total steam at the mill.
Selected control level results. The model plant replacement boiler is
assumed to be a wood-fired boiler requiring PM control at all selected
control levels. The two selected control levels are represented by model
boiler #lb, which requires 97 percent PM reduction (64.5 ng/J [0.15 Ib/MMBtu]
ceiling) and model boiler #le, which requires 99 percent PM reduction (21.5
ng/J [0.05 Ib/MMBtu] ceiling).
Table 9-32 shows the pre-tax 1978 boiler and pollution control costs
for the two selected control levels for the sawmill industry. Boiler and
pollution control costs for the boiler investment range from about $1.9
million in the base case to $2.3 million in the 99 percent PM reduction
level.
On the basis of these total steam costs, the cost of new steam per
unit of output for the industry can be calculated. As can be seen in
Table 9-33, the steam requirement per board foot is 0.0042 GJ (0.0040
MMBtu). Given an average price of $0.24/board foot, the increase in the
cost of new steam per unit output for the 97 percent PM reduction level
represents a 0.43 percent increase over the base case level, and a 0.58
percent increase for the 99 percent PM reduction level.
Q-QA
-------
TABLE 9-30. CAPITAL AVAILABILITY INDICATORS -
FURNITURE MANUFACTURING INDUSTRY
Model boiler #
la (base case)
Ib
le
Percent financed by debt
0
25
50
75
100
Coverage ratio
5.99
5.97
5.95
5.93
5.91
5.99
5.96
5.94
5.91
5.89
5.99
5.96
5.93
5.91
5.88
Percent financed by debt
0
25
50
75
100
Debt-equity ratio
0.37
0.37
0.37
0.38
0.38
0.37
0.37
0.37
0.38
0.38
0.37
0.37
0.38
0.38
0.38
9-8b
-------
TABLE 9-31. MODEL FIRM AND MILL CONFIGURATION-
SAWMILL INDUSTRY3
Model firm
Financial data
Average bond rating:
Coverage ratio:
Debt/equity ratio (%):
Model Bill
Production data
Mill output/year:
Price/unit output: •
Mill sales/year:
Mill earnings/year:
Boiler configuration
Total firing rate:
Number of boilers:
Baa
7.4
48.7
40 million board feet
$0.24/board feetc
$9.6 million .
$643.0 thousand
17.6 MW (60 MMBtu)
2
Characteristics of individual boilers
Boiler #
Capacity (MW [MMBtu/hr
heat input])
Fuel type (base case)
Annual capacity utilization (%)
Replacement, expansion or
existing
8.8
(30)
Wood
60
Existing
8.8
(30)
Wood
60
Replacement
aBased upon 1978 values.
Based upon the average production of the firm most likely to invest in
a new boiler.
CF.O.B. mill basis.
upon the 1978 return on sales ratio of 6.7 percent.
9-86
-------
TABLE 9-32. BOILER COSTS ~ SAWMILL INDUSTRY
oo
Model boiler #
Total boiler & pollution g
control capital costs ($10 )
Annual 1 zed total boiler and
pollution control cost
$/GJ ($/MMBtu)a
Capital
0&Mb
Total
Control technology
PM emission rate
ng/J
(Ib/MMBtu)
la (base case)
1.9
1.24
(1.31)
4.17
(4.40)
5.41
(5.71)
MC
258.00
(0.60)
lb
2.2
1.45
(1.53)
4.44
(4.68)
5.89
(6.21)
MC/WS
64.50
(0.15)
le
2.3
1.57
(1.66)
4.48
(4.73)
6.05
(6.39)
MC/ESP
21.50
(0.05)
a!978 dollars.
Includes general and administrative expenses, taxes, Insurance, Interest on working capital, and
capital recovery. Assumes a 10.15 discount rate.
-------
TABLE 9-33. CHANGE IN PRODUCT PRICE — SAWMILL INDUSTRY
Model boiler #
GJ Steam/board foot output3
(MMBtu steam/board
foot output)
Percent of new steam/
board foot
Cost of new steam ($/
GJ [MMBtu])c'a
Cost of new steam ($/
board foot output)
Average product price ($/
board foot)
Cost of new steam ($/
$ output)
la (base case)
0.0042
(0.0040)
50
5.41
(5.71)
0.0114
0.24
0.0475
Ib
0.0042
(0.0040)
50
5.89
(6.21)
0.0124
0.24
0.0518
le
0.0042
(0.0040)
50
6.05
(6.39)
0.0129
0.24
0.0533
Percent increase in product 0.43
price over the base case
Absolute $ increase in product 0.00
price over the base case
aEstimated from industry contacts.
Based on model plant configuration, the new boiler represents one half of total steam.
GSteam costs are from Chapter 8.
d!978 dollars.
0.58
0.00
-------
Table 9-34 illustrates the changes in profitability levels due to the
new boiler investment. Given the negligible price effects, sales are
assumed to be constant for all selected control levels and expenses increase
only as a result of the new boiler investment. The decline in net income
is almost three percent from the base case to the 97 percent PM reduction
level and four percent from the base case to the 99 percent PM reduction
level. The return on assets decreases by the same percentages as the
decline in net profits.
Table 9-35 presents comparative coverage and debt/equity ratios for
the selected control levels. The coverage ratio declined insignificantly
from 7.4 to 7.3 under the five financing options and shows no significant
difference between selected control levels. The debt/equity ratio remains
around 0.5. Neither of these ratios suggest problems in obtaining capital
for the industry in any of the selected control options.
The results of the analysis indicated that product price is expected
to increase by at most 0.58 percent. New steam costs for the selected
control levels comprise a relatively small portion of average product
price. Profitability shows a slight decline as a result of the selected
control levels when compared to the base case. The analysis of coverage
ratios indicate that the new boiler investment can be funded totally by
debt while still meeting the 3.0 coverage benchmark.
9.2.2.4.2 Plywood industry.
Model mill description. The major characteristics of the model mill
are listed in Table 9-36. The mill is assumed to be part of a firm with
seven plywood plants. Financial data are taken from Table 9-8 in Section
9.1 and are based on 1978 figures.
This model mill is located in southern United States (Federal Region
4). The mill is run almost continuously throughout the year. Total annual
mill production is estimated at 90 million square feet. Annual sales are
$19.8 million and profits are 6.70 percent of sales, or about $1.33 mil-
lion. This mill accounts for approximately eight percent of the hardwood
plywood market (concentrated in the southeastern United States) and 0.6
percent of the total plywood market.
The model mill boiler house consists of two wood waste-fired boilers
and one gas and oil-fired boiler with total heat input capacity of 26.4 MW
9-89
-------
TABLE 9-34. CHANGE IN PROFIT MARGIN DUE TO NEW BOILER INVESTMENT —
SAWMILL INDUSTRY (Mid-1978 $)
vo
I
vo
o
Model boiler #
Sales/plant
Expenses
Gross profit
Taxes
Net income
Return on
assets (%)
aBase case assumes
O&M costs.
la
106 $
9.02
7.90
1.12
0.56
0.56
(base case)3
% of
sales
100.00
87.65
12.39
6^19
6.19
6.46
new boiler investment reflecting
Ib
106 $
9.02
7.93
1.09
0.54
0.55
new annual i zed
% of
sales
100.00
87.92
12.08
6.04
6.04
6.28
capital
106 $
9.02
7.95
1.07
0.53
0.54
costs with no
le
% of
sales
100.00
88.14
11.86
5.93
5.93
6.17
change in
-------
TABLE 9-35- CAPITAL AVAILABILITY INDICATORS ~ SAWMILL INDUSTRY
Model boiler #
la (base case)
Ib
le
Percent financed by debt
0
25
50
75
100
7.38
7.37
7.37
7.36
7.35
Coverage ratio
7.37
7.36
7.35
7.34
7.33
7.37
7.36
7.35
7.34
7.33
Percent financed by debt
0
25
50
75
100
Debt-equity ratio
0.49
0.49
0.49
0.49
0.49
0.49
0.49
0.49
0.49
0.49
0.49
0.49
0.49
0.49
0.49
9-91
-------
TABLE 9-36. MODEL FIRM AND MILL CONFIGURATION-
PLYWOOD INDUSTRY3
Model firm
Financial data
Average bond rating: Baa
Coverage ratio: 7.4
Debt/equity ratio (%): 48.7
Model mill
Production data
Mill output/year: 90 million square feet
Price/unit output: $0.22/square foot
Mill sales year: $19.8 million
Mill earnings/year: $1.3 million
Boiler configuration
Total firing rate: 26.4 MW (90 MMBtu/hr)
Number of boilers: 3
Characteristics of individual boilers
Capacity (MW [MMBtu/hr
heat input])
Fuel type (base case)
Annual capacity utilization (%)
Replacement, expansion
or existing
1
8.8
(30)
Wood
60
Boiler #
2
8.8
(30)
Natural gas/
fuel oil
40
-Existing
3
8.8
(30)
Wood
60
Expansion
aBased upon 1978 values.
Based upon the average production of the firm most likely to invest in
a new boiler.
d
CF.O.B. mill basis.
Based upon the 1978 return on sales ratio of 6.7 percent.
9-92
-------
(90 MMBtu/hr). The model wood-fired boiler of 8.8 MW (30 MMBtu/hr) heat
input is closest in size to the plywood industry's existing two boilers of
5.9 MW (20 MMBtu) at 60 and 40 percent annual capacity. Table 9-36 des-
cribes the individual boilers. The first boiler provides over 60 percent
of the steam for the plywood mill. The independent plywood mill operation
usually fires wood dust instead of bark, occasionally using natural gas for
start-up or when wood is not available. The second boiler fires natural
gas and fuel oil. All the steam generated is for process use. The boiler
investment decision is to expand operations with a wood waste-fired boiler
of the same capacity.
Selected control level results. The model plant replacement boiler is
assumed to be a wood-fired boiler requiring PM control at all selected
control levels. Table 9-37 shows the pre-tax 1978 boiler and pollution
control costs for the two selected control levels for the plywood industry.
The two selected control levels are represented by model boiler #lb, which
requires 97 percent PM reduction (64.5 ng/J [0.15 Ib/MMBtu] ceiling) and
model boiler le, which requires 99 percent PM reduction (21.5 ng/J [0.05
Ib/MMBtu] ceiling). Boiler and pollution control costs for the boiler
investment range from about $1.9 million in the base case to $2.3 million
in the 99 percent PM reduction level.
On the basis of these total steam costs the cost of new steam per unit
of output for the industry can be calculated. As seen in Table 9-38, the
steam requirement per square foot is 0.003 GJ (0.002 MMBtu). Given an
average price of $0.22 per square foot, the increase in the cost of new
steam per unit output for the 97 percent PM reduction level represents a
0.24 percent increase over the base case level and a 0.32 percent increase
for the 99 percent PM reduction level.
Table 9-39 illustrates the changes in profitability levels due to the
new boiler investment. Given the negligible price effects, sales are
assumed to be constant for all selected control levels and expenses in-
crease only as a result of the new boiler investment. The decline in net
income is almost two percent from the base case to the 97 percent PM reduc-
tion level and nearly three percent from the base case to the 99 percent PM
reduction level. The return on assets figures decrease by approximately
the same percentages.
9-93
-------
TABLE 9-37. BOILER COSTS — PLYWOOD INDUSTRY
-------
TABLE 9-38. CHANGE IN PRODUCT PRICE — PLYWOOD INDUSTRY
cn
Model boiler #
GJ (MMBtu) steam/square foot9
(3/8") output
Percent of new steam/
square foot (3/8")
product
Cost of new steam ($/
GJ [MMBtu])c'a
Cost of new steam (I/square
foot (3/8") output)0
Average product price .($/
square foot [3/8" ])a
Cost of new steam ($/
$ output)
Percent increase in product
price over the base case
Absolute $ increase
in product price
la (base case)
0.003
(0.002)
37.5
5.41
(5.71)
0.0061
0.22
0.0277
Ib
0.003
(0.002)
37.5
5.89
(6.21)
0.0066
0.22
0.0301
0.24
0.00
le
0.003
(0.002)
37.5
6.05
(6.39)
0.0068
0.22
0.0309
0.32
0.00
Estimated from industry contacts.
Based on model plant configuration, the new boiler represents approximately 38 percent of total steam.
cSteam costs are from Chapter 8.
d!978 dollars.
-------
10
I
CTi
TABLE 9-39. CHANGE IN PROFIT MARGIN DUE TO NEW BOILER INVESTMENT —
PLYWOOD INDUSTRY (Mid-1978 $)
Model boiler #
Sales/plant
Expenses
Gross profit
Taxes
Net income
Return on
assets (%)
la (base
106 $
18.61
16.22
2.40
1.20
1.20
case)3
% of
sales
100.00
87.14
12.86
6.43
6.43
6.68
Ib
106 $
18.61
16.25
2.36
1.18
1.18
% of
sales
100.00
87.32
12.68
6.34
6.34
6.58
le
106 $
18.61
16.27
2.34
1.17
1.17
% of
sales
100.00
87.25
12.75
6.23
6.23
6.53
aBase case assumes new boiler investment reflecting new annualized capital costs with no change in
O&M costs.
Incremental increase in expenses is based on percentage increase in product price.
-------
Table 9-40 presents comparative coverage and debt/equity ratios for
the selected control levels, which are the same as the sawmill industry.
The coverage ratio declined insignificantly from 7.4 to 7.3 under the five
financing options and shows no significant difference between selected
control levels. The debt/equity ratio remains around 0.5. Neither of
these ratios suggest problems in obtaining capital for the industry in any
of the selected control options.
The results of the analysis indicated that product price is expected
to increase by at most 0.32 percent. New steam costs for the selected
control levels comprise a relatively small portion of average product
price. Profitability shows a slight decline as a result of the selected
control levels when compared to the base case. The analysis of coverage
ratios indicate that the new boiler investment can be funded totally by
debt while still meeting the 3.0 coverage benchmark.
9.2.2.5 Paper and Allied Products Manufacturing Industry
9.2.2.5.1 Model mill description. The model firm and mill configura-
tion is presented in Table 9-4-1. The mill is assumed to be part of a 15
mill firm. Financial data are taken from Table 9-12 in Section 9.1 and are
based on 1978 data.
This model mill is located in southern United States (Federal Region
4). The mill is run almost continually throughout the year. Total annual
mill production is estimated at 280 thousand tons. Annual sales are $179
million and profits are 6.4 percent of sales or about $11.5 million. This
mill accounts for approximately 1.0 percent of the paper market.
The model mill boiler house consists of two wood-fired boilers, one
black liquor boiler and one fuel oil boiler with a total heat input cap-
acity of 454 MW (1550 MMBtu/hr). Model boiler #4, found in Section 6, is
closest in size to the paper industry's existing wood-fired boiler of
137 MW (536 MMBtu/hr) at 60 percent annual capacity utilization. Table
9-41 describes the individual boilers. The first boiler is a bark boiler.
The investment decision is to purchase a new bark boiler, boiler #4, to
expand present capacity. Boiler #2 is the recovery or black liquor boiler.
Although black liquor is considered a waste product, this boiler is covered
under the recovery boiler NSPS. The third boiler is a fuel oil standby
boiler primarily used for start-up.
9-97
-------
TABLE 9-40. CAPITAL AVAILABILITY INDICATORS — PLYWOOD INDUSTRY
Model boiler
la (base case)
Ib
le
Percent financed by debt
0
25
50
75
100
7.38
7.37
7.37
7.36
7.35
Coverage ratio
7.37
7.36
7.35
7.34
7.33
7.37
7.36
7.35
7.34
7.33
Percent financed by debt
0
25
50
75
100
Debt-equity ratio
0.49 0.49
0.49 0.49
0.49 0.49
0.49 0.49
0.49 0.49
0.49
0.49
0.49
0.49
0.49
9-98
-------
TABLE 9-41. MODEL FIRM AND MILL CONFIGURATION
PAPER MANUFACTURING INDUSTRY
Model firm
Financial data
Average bond rating:
Coverage ratio:
Debt/equity ratio (%):
Aa/Baa
7.0
48.8
Model mill
Production data
Mill output/year:
Price/unit output:
Mill sales/year:
Mill earnings/year:
Boiler configuration
Total firing rate:
Number of boilers:
280 thousand tons
$0.71/kg. ($.32/lb)
$179 million
$11.5 millionc
454 MW (1550 MMBtu/hr)
4
Characteristics of individual boilers
Capacity (MW [MMBtu/hr
heat input])
Fuel type (base case)
Annual capacity
utilization (%)
Replacement, expansion
or existing
1
117
(400)
Wood
60
Boi
2
176
(600)
Black
liquor
100
•-Existing —
ler #
1
44
(150)
Fuel
oil
0
4
117
(400)
Wood
60
Expansion
Based upon 1978 values.
Based upon the average production of the firm most likely to invest in
a new boiler.
i*
"Based upon the 1978 return on sales ratio of 6.4 percent.
9-99
-------
Approximately 50-70 percent of total steam is generated from bark. In
the winter months approximately 80 percent of all steam is generated for
process use, 10 percent is for space heat, and 10 percent is for electric-
ity generation. This mill generates 90 percent of its own electricity.
9.2.2.5.2 Selected control level results. The model plant replace-
ment boiler is assumed to be a wood-fired boiler requiring PM control at
all selected control levels. Table 9-42 shows the pre-tax 1978 boiler and
pollution control costs for the two selected control levels for the paper
industry. The two selected control levels are represented by model boiler
#4b, which requires 97 percent PM reduction (64.5 ng/J [0.15 Ib/MMBtu]
ceiling) and model boiler #4e, which requires 99 percent PM reduction (21.5
ng/J [0.05 Ib/MMBtu] ceiling). Boiler and pollution control costs for the
boiler investment range from about $14.2 million in the base case to $16.1
million in the 99 percent PM reduction level.
On the basis of these total steam costs, the cost of new steam per
unit of output for the industry, as can be seen in Table 9-43, can be
calculated. The steam requirement of paper production per Kg (Ib) is 0.02
GJ (0.01 MMBtu).
Given an average price of $0.71/Kg ($0.32/lb), the increase in the
cost of new steam per dollar output for the 97 percent PM reduction level
represents a 0.03 percent increase over the base case level and a 0.06
percent increase for the 99 percent PM reduction level. -
Table 9-44 illustrates the changes in profitability levels due to the
new boiler investment. Given the negligible price effects, sales are
assumed to be constant for all selected control levels and expenses in-
crease only as a result of the new boiler investment. The-decline in net
income is 0.20 percent from the base case to the 97 percent PM reduction
level and 0.48 percent from the base case to the 99 percent PM reduction
level.
Table 9-45 presents comparative coverage and debt/equity ratios for
the selected control levels. The coverage ratio declined insignificantly
from 6.98 to 6.76 under the five financing options and shows no significant
difference between selected control levels. The debt/equity ratio increased
from 0.48 to 0.50. Neither of these ratios suggest problems in obtaining
capital for the industry in any of the selected control options.
9-100
-------
The results of the analysis indicated that product price is expected
to increase by at most 0.06 percent. New steam costs for the selected
control levels comprise a relatively small portion of average produce
price. Profitability shows a slight decline as a result of the selected
control levels when compared to the base case. The analysis of coverage
ratios indicate that the new boiler investment can be funded totally by
debt while still meeting the 3.0 coverage benchmark.
9.2.2.6 Raw Sugar Cane Manufacturing Industry.
9.2.2.6.1 Model mill description. The major characteristics of the
model firm are used in Table 9-46. Financial figures are taken from Table
9-16 in Section 9.1.
This model mill represents a large independent sugar milling operation
in the southern United States (Federal Region 4). Total annual mill pro-
duction of raw sugar is estimated at.181,406 megagrams (20,000 tons)/season.
Ttie milling season lasts for five months. Production of actual raw sugar,
which is sugar ready to be sold or refined, is approximately 10.3 percent
of total sugar cane production, or cane harvested specifically for use as
sugar, not seed. The mill's market share in the industry is approximately
seven percent of domestic raw sugar.
The price of raw sugar is $0.31/kilogram ($0.14/pound). Annual sales
of raw sugar are $56 million and profits are 8.5 percent of sales, or about
$4.7 million.
The model mill boiler house configuration consists of five bagasse-
fired boilers with a total heat input capacity of 293 MW (1,000 MMBtu/hr).
Model boiler #14, found in Section 6, is closest in size to the sugar cane
industry's existing bagasse-fired boiler of 62 MW (210 MMBtu/hr) at 100
percent capacity utilization. This mill also has the capacity to begin
production of related products, such as gasohol or sugar refining. Approx-
imately 98 percent of total steam generated is for process use. The re-
maining two percent accounts for electricity generation. In this model
mill, bagasse supplies 100 percent of total generated steam. Approximately
10,000 pounds of steam are required for one ton of sugar produced.
9.2.2.6.2 Selected control level results. The model plant replace-
ment boiler is assumed to be a bagasse-fired boiler requiring PM control at
all selected control levels. Table 9-47 shows the pre-tax 1978 boiler and
9-101
-------
TABLE 9-4£ BOILER COSTS — PAPER MANUFACTURING INDUSTRY
10
i
Model boiler #
Total boiler & pollution g
control capital costs ($10 )a
Annual i zed total boiler
and pollution control
cost $/GJ ($/MMBtu)a
Capital
0&Mb
Total
Control technology
PM emission rate
ng/J
(Ib/MMBtu)
4a (base case)
14.2
0.69
(0.73)
1.51
(1.59)
2.20
(2.32)
MC
258.00
(0.60)
4b
15.2
0.76
(0.80)
1.63
(1.72)
2.39
(2.52)
MC/WS
64.50
(0.15)
4e
16.1
0.82
(0.86)
1.59
(1.68)
2.41
(2.54)
MC/ESP
21.50
(0.05)
a!978 dollars.
Includes general and administrative expenses, taxes, insurance, interest on working capital, and
capital recovery. Assumes a 10.15 discount rate.
-------
TABLE 9-43. CHANGE IN PRODUCT PRICE — PAPER MANUFACTURING INDUSTRY
o
GO
Model boiler #
GJ steam/kg output3
(MMBtu steam/1 b
output)
Percent of new steam/
kg (lb) product
Cost of new steam ($/
GJ [MMBtu] )c'a
Cost of new steam .($/
kg (lb) output)0
Average product price
($/kg [lb])a
Cost of new steam ($/
$ output)
Percent increase in
product price
Absolute $ increase
in product price/
kg (lb)
4a (Base Case)
0.02
(0.01)
27.3
2.20
(2.32)
0.0120
(0.0054)
0.71
(0.32)
0.01690
4b
0.02
(0.01)
27.3
2.39
(2.52)
0.0122
(0.0055)
0.71
(0.32)
0.01720
0.03
0.00
(0.00)
4e
0.02
(0.01)
27.3
2.41
(2.54)
0.0123
(0.0056)
0.71
(0.32)
0.01734
0.06
0.00
(0.00)
Estimated from industry contacts.
}Based on model plant configuration, the new boiler represents approximately 27 percent of total steam.
«
'Steam costs are from Chapter 8.
J1978 dollars.
-------
TABLE 9-44. CHANGE IN PROFIT MARGIN DUE TO NEW BOILER INVESTMENT —
PAPER MANUFACTURING INDUSTRY (Mid-1978 $)
Model boiler #
Sales/plant
Expenses
4a (base case)3
*; % of
10° $ sales
168.26 100.00
147.40 87.60
4b
106 $
168.26
147.44
% of
sales
100.00
87.63
4e
106 $
168.26
147.50
% of
sales
100.00
87.66
Gross profit 20.90 12.40 20.82 12.37 20.77 12.34
Taxes 10.43 6.20 10.41 6.19 10.40 6.17
Net income 10.43 6.20 10.41 6.19 10.39 6.17
Return on
assets (X) 6.42 6.41 6.40
aBase case assumes new boiler investment reflecting new annualized capital costs with no change in
O&M costs.
Incremental increase in expenses is based on percentage increase in product price.
-------
TABLE 9-45. CAPITAL AVAILABILITY INDICATORS —
PAPER MANUFACTURING INDUSTRY
Model boiler £
4a (base case)
4b
4e
Percent financed by debt
0
25
50
75
100
6.98
6.93
6.88
6.83
6.78
Coverage ratio
6.98
6.93
6.88
6.82
6.77
6.98
6.93
6.87
6.81
6.76
Percent financed by debt
0
25
50
75
100
Debt-equity ratio
0.48
0.49
0.49
0.50
0.50
0.48
0.49
0.49
0.50
0.50
0.48
0.49
0.49
0.50
0.50
9-105
-------
TABLE 9-46. MODEL FIRM AND MILL CONFIGURATION ~
SUGAR CANE MANUFACTURING INDUSTRY3
Model firm
Financial data
Average bond rating:
Coverage ratio:
Debt/equity ratio (%):
Model mill
Production data
Mill output/year:
Price/unit output:
Mill sales/year:
Mill earnings/year:
Boiler configuration
Total firing rate:
Number of boilers:
A/Baa
4.5
32.0
181,406 megagrams (200,000 tons)0
$0.31/kilogram ($0.14/pound wt.)
$56.0 million
$4.7 million0
293 MW (1000 MMBtu/hr)
5
Characteristics of individual boilers
Capacity (MW [MMBtu/hr
heat input])
Fuel type (base case)
Annual capacity utili-
zation (%)
Replacement, expansion
or existing
1
58.6
(200)
Bagasse
45
2
58.6
(200)
Bagasse
Boiler
3
58.6
(200)
Bagasse
45 45
#
4
58.6
(200)
Bagasse
45
5
58.6
(200)
Bagasse
45
Repl ace-
men t
aBased upon 1978 values.
Based upon a five month average season.
GBased upon the average production of the firm most likely to invest in
a new boiler.
Based upon the 1978 return on sales of 8.5 percent.
9-106
-------
TABLE 9-47. BOILER COSTS — SUGAR CANE MANUFACTURING INDUSTRY
10
i
Model boiler # 15a (base case) 15b
Total boiler & pollution control 5.9 6.5
capital costs ($10°)a
Annual1zed total boiler and
pollution control cost $/GJ
($/MMBtu)a
Capital
0&Mb
Total
Control technology
PM emission rate
ng/J
(Ib/MMBtu)
0.82
(0.86)
1.34
(1.41)
2.16
(2.27)
MC
267.00
(0.62)
0.93
(0.98)
1.51
(1.59)
2.44
(2.57)
WS
86.00
(0.20)
a!978 dollars.
Includes general and administrative expenses, taxes, Insurance, Interest on working capital, and
capital recovery. Assumes an 11 percent discount rate.
-------
pollution control costs for the only selected control level for the sugar
cane industry. Represented by model boiler #15b, the regulatory alterna-
tive requires 96 percent PM reduction (86.0 ng/J [0.20 Ib/MMBtu] celling).
Boiler and pollution control costs for the boiler investment range from
about $5.9 million in the base case to $6.5 million in the 96 percent PM
reduction level.
On the basis of these total steam costs the resultant cost of steam
per unit of output for the industry, shown in Table 9-48, can be calcu-
lated. The steam requirement/Kg (Ib) is 0.02 GJ (0.01 MMBtu). Given an
average price of $0.31/Kg ($0.14/lb), the increase in the cost of new steam
per unit output for the 96 percent PM reduction level represents a 0.38
percent increase over the base case level.
Table 9-49 illustrates the changes in profitability levels due to the
new boiler investment. Given the negligible price effects, sales are
assumed to be constant for all selected control levels and expenses in-
crease only as a result of the new boiler investment. The decline in net
income is almost two percent from the base case to the 97 percent PM reduc-
tion level. The return on assets figure only decreases by 1.9 percent from
the base case to the control level.
Table 9- 50 presents comparative coverage and debt/equity ratios for-
the selected control levels. The coverage ratio declined from 4.54 to 3.16
under the five financing options, a relatively greater decrease than the
other NFFB industries. The debt/equity ratio increased from 0.29 to 0.40.
Neither of these ratios suggests problems in obtaining capital for the
industry in any of the selected control options. Since these ratios show a
low percentage of debt, future investments could be funded largely from
debt depending upon the interest rate and the industry's inclination toward
debt financing.
The coverage ratios for all financing options used for all of the
selected control levels fall above the 3.0 coverage benchmark. The sugar
cane industry, however, falls closest to this benchmark number than any of
the NFFB industries. This ratio becomes 3.16 as can be seen in Table 9-50
under control level 15 with 100 percent debt financing.
The results of the analysis indicated that product price is expected
to increase by at most 0.38 percent. Although the sugar cane industry is
9-108
-------
price sensitive, the alternative emission regulation produces an insignifi-
cant increase ($0.001) in product price per pound. New steam costs for the
selected control levels comprise a relatively small portion of average
product price. Profitability shows a slight decline as a result of the
selected control levels when compared to the base case. The analysis of
coverage ratios indicates that the new boiler investment can be funded
totally by debt while still meeting the 3.0 coverage benchmark.
9.2.3 Impact on Selected Municipal Users
The following presents the economic impact associated with alternative
control levels on selected municipal operators of NFFB's. This section
outlines the methodology used to determine economic impact and discusses
the potential impacts on the four selected municipalities.
9.2.3.1 Methodology of Economic Impact Analysis. The economic impact
analysis of selected municipalities centers on the change in the cost of
producing new steam and capital availability.
9.2.3.1.1 Cost of producing steam. In calculating the change in the
cost of producing new steam, a twofold approach is used. First, the par-
ticular municipality's NFFB size is defined, and capital, operating, and
maintenance costs are determined from the model boilers in Section 8.
Second, capital costs are annualized using a discount rate relevant for
each municipality and added to operating and maintenance costs and fuel
costs, where applicable, to yield a total annualized cost per GJ (MMBtu)
heat input under the base case and the selected control levels. Then, a
percent change in these annualized costs over the base case is calculated.
9.2.3.1.2 Capital availability. Municipal resource recovery projects
have been financed typically out of current revenues and long-term borrow-
ings such as municipal and State revenue bonds, general obligation bonds,
pollution control revenue bonds and Federal and State grants. No single
financing source, however, supplies all resource recovery funds. In fact,
more than one source can finance a single resource recovery plant and
thereby spread out the costs and risks associated with the project.
The following briefly discusses some of the more popular methods of
financing resource recovery projects: '
• Current revenue capital financing. This method has been used
often in waste disposal systems to finance small capital
expenditures. However, current revenue financing depends upon
9-109
-------
TABLE 9-48. CHANGE IN PRODUCT PRICE — SUGAR CANE MANUFACTURING INDUSTRY
vo
i
Model boiler #
GJ steam/kg output3
(MMBtu steam/1 b
output)
Percent of new steam/
kg (lb) product
Cost of new steam ($/
GJ [MMBtu] )c'a
Cost of new steam .($/
kg (lb) output)
Average product price
($/kg [lb])a
Cost of new steam ($/
$ output)
Percent Increase in
product price
Absolute $ increase
in product price/
kg (lb)
15a (base case)
0.02
(0.01)
20
2.16
(2.27)
0.0088
(0.0040)
0.31
(0.14)
0.02838
15b
0.02
(0.01)
20
2.44
(2.57)
0.0100
(0.0045)
0.31
(0.14)
0.03213
0.38
0.00
(0.00)
Estimated from industry contacts.
}Based on model plant configuration, the new boiler represents one fifth of total steam.
'Steam costs are from Chapter 8.
^1978 dollars.
-------
TABLE 9-49. CHANGE IN PROFIT MARGIN DUE TO NEW BOILER INVESTMENT —
SUGAR CANE MANUFACTURING INDUSTRY (Mid-1978 $)
Model boiler #
/** ""
Sales/plant
Expenses
Gross profit
Taxes
Net income
Return on
assets (%)
15a (base
106 $
52.64
44.20
8.44
4.22
4.22
case)3
% of
sales
100.00
83.97
16.03
8.01
8.01
4.70
106 $
52.64
44.37
8.27
4.14
4.14
15b
% of
sales
100.00
84.29
15.71
7.J5
7.85
4.61
aBase case assumes new boiler investment reflecting new annualized capital costs with no change in
O&M costs.
Incremental increase in expenses is based on increase in product price.
-------
TABLE 9-50. CAPITAL AVAILABILITY INDICATORS —
SUGAR CANE MANUFACTURING INDUSTRY
Model boiler #
15a (base case)
15b
Percent financed by debt
0
25
50
75
100
4.54
4.13
3.79
3.50
3.25
Coverage ratio
4.54
4.08
3.71
3.40
3.16
Percent financed by debt
0
25
50
75
100
Debt^equity ratio
0.29
0.32
0.34
0.36
0.39
0.29
0.32
0.34
0.37
0.40
9-112
-------
the ability of the local government to generate surplus funds.
Municipalities that are implementing capital-intensive pro-
jects usually need to tap. other sources of capital such as
long-term borrowings or private company financing.
• Public long-term borrowing — general obligation bonds. In
this financing method the issuing municipality guarantees the
general obligation bond with its "full faith and credit," that
is, its ability to repay the principal and interest out of
general tax revenues. In this type of bond financing, two
requirements must usually be met: voters must approve the
issue and municipal legal debt ceilings must not be exceeded.
This-bond issue does not require an economic or technical
analysis of the particular project(s) to be financed. Often-
times, groups of small projects are funded under one bond
issue. General obligation bond financing is more economic
when the debt issue exceeds $500,000 due to the transaction
cost and its effect on the effective interest rate. Because
they have a municipal guarantee and risk of default is lowest,
these bonds carry the lowest interest rates of any municipal
bonds.
• Public long-term borrowing — municipal revenue bonds. This
method of financing pledges the revenues generated from the
project to guarantee repayment of the principal and interest.
The general "faith and credit" of the municipality is not
pledged and voter approval is not required. The bond's in-
terest rate is a function of the revenue-generating capacity
of the particular project and is usually higher due to greater
risks than the rate for general obligation bonds. Revenue
bond financing is economic when the debt issue is at least
$1 million due to the transaction cost which helps determine
the effective interest rate.
• Private financing. In this financing alternative, the munici-
pality contracts a private firm to handle the resource recovery
project. The firm then raises the capital to buy the equipment
and operates the system. .In this manner, the municipality
does not need to allocate its own capital to operate the
plant. Industrial revenue and pollution control revenue bonds
are two examples of private financing.
The above illustrates that there are several ways to fund municipal
resource recovery projects. If one financing source is infeasible, there
are other sources that can be tapped.
In the following section, the capital availability issue discusses the
ability to fund the incremental capital costs associated with the control
levels. As it is assumed that the base case investment is affordable, only
the question of funding the increment is addressed. The additional costs
9-113
-------
of complying with selected control levels is related to annual government
expenditures, assuming a worse case whereby incremental funds could come
from the annual budget. This ratio is calculated for publicly financed
NFFB projects only.
9.2.3.2 Summary of Results. The selected municipality economic ana-
lysis of selected control levels indicates that no major economic impacts
are expected. The percent change in annualized costs from the base case to
Control Level II in no case exceeds 3.1 percent for the MSW-fired boilers
and 5.4 percent for the 50 percent RDF/50 percent coal cofired .boiler. The
dollar change in annualized costs from the base case ranges from $10,000
(Level I) to $88,900 (Level II) for the MSW-fired boilers analyzed and
$131,300 (Level I) to $222,700 (Level II) for the RDF/coal cofired boiler
studied. Related to total government expenditures, these dollar increments
are less than one percent. The capital availability analysis shows that no
problems in financing the incremental capital costs are expected. The
following sections explain these costs more fully.
The case studies discuss other factors that should be considered when
evaluating potential economic impacts. The share of new NFFB's to the
total number of boilers providing steam would reduce the overall percent
change in annualized costs from the base case. Moreover, revenues received
from selling steam would also reduce the effective costs. Savings incurred
from not burning more expensive fossil fuels would also effectively reduce
costs.
9.2.3.3 Albany. New York.
9.2.3.3.1 New NFFB configuration. As discussed in 9.1.2, Albany is
in the process of building two new NFFB's. It is assumed that if the State
of New York decided at a later date to replace an existing boiler or to
expand with a new unit, the NFFB chosen would be similar in size to each
NFFB presently being built. Model boiler #11, a 44 MW (150 MMBtu/hr) heat
input RDF/coal cofired boiler, is closest in size and fuel to the actual
facility's existing RDF boilers of 42.9 MW (144.8 MMBtu/hr) heat input
each. Table 9-51 shows the basic configurations of a new NFFB. The exist-
ing boiler house was discussed in Section 9.1.2.
In the base case, all new NFFB's are subject to the applicable SIP
emission regulation. Table 9-52 shows the capital, O&M and fuel costs
9-114
-------
associated with operating a new 44 MW (150 MMBtu/hr) heat input RDF/coal
cofired boiler in the base case. Total annualized costs are $4.99/GJ
($5.27/MMBtu). However, by operating NFFB's, Albany is relying less on its
oil-fired boilers, thereby reducing fuel oil expenses. The amount of the
annual fuel savings would reduce the annualized cost of operating the new
NFFB. These base case costs assume a PM emission limit of 138 ng/J (0.32
Ib/MMBtu) for 94.5 percent control and an S02 ceiling of 1075 ng/J (2.5
Ib/MMBtu) achieving 20 percent control.
9.2.3.3.2 Selected control level results. Table 9-52 also outlines
the cost of a new boiler under the following more stringent pollution
control scenarios relative to the base case: one, 97.4 percent PM control
(64.5 ng/J [0.15 Ib PM/MMBtu] limit) and 70 percent S02 control (405 ng/J
[0.93 Ib S02/MMBtu] ceiling); two, 97.4 percent PM control (64.5 ng/J [0.15
Ib PM/MMBtu] limit) and 90 percent S02 control (135 ng/J [0.31 Ib S02/
MMBtu] ceiling); three, 99.1 percent PM control (21.5 ng/J [0.05 Ib PM/
MMBtu] ceiling) and 70 percent S02 control (405 ng/J [0.94 Ib S02/MMBtu]
limit); and four, 99.1 percent PM control (21.5 ng/J [0.05 Ib PM/MMBtu]
ceiling) and 90 percent S02 control (135 ng/J [0.31 Ib S02/MMBtu] limit).
Capital availability to fund the incremental pollution control capital
costs does not appear to pose a problem. In the base case, pollution
control capital of $1.8 million represents 14.2 percent of the total capi-
tal cost of $12.8 million. In the most stringent control case, the capital
cost of pollution control of $2.6 million comprises 19.2 percent of the
total capital cost of $13.6 million. Assuming that the base case invest-
ment is affordable, the incremental capital cost due to the more stringent
control level would add, at most, 5.8 percent to the total capital cost of
the project. When compared to New York State appropriations which are
financing the existing Albany NFFB's, this increment is too small to deem
the project unaffordable.
As boiler costs do not change from base case to impact case, annual-
ized boiler capital and O&M costs remain at $4.15/GJ ($4.38/MMBtu). An-
nual ized pollution control capital and annual pollution control O&M, how-
ever, range from $1.00/GJ ($1.06/MMBtu) under a less stringent control case
to $1.11/GJ ($1.17/MMBtu) under a more stringent control level for a total
boiler and pollution control cost of from $5.15/GJ ($5.44/MMBtu) to $5.26/
GJ ($5.55/MMBtu).
9-115
-------
TABLE 9-51. NEW NFFB CONFIGURATION,3 ALBANY, NEW YORK
Heat input capacity, MW (MMBtu/hr) 44 (150)
Fuel design type RDF/coal
Annual capacity utilization(%) 60
aAssumes new boiler configuration based on model boiler #11.
High sulfur eastern coal. Fifty percent RDF/50 percent coal
firing.
9-116
-------
TABLE 9^52- BOILER AND POLLUTION CONTROL COSTS OF A 44 MW (150 MMBTU/HR) HEAT INPUT
RDF/£QAt BOILER (MODEL BOILER #11)
ALBANY, NEW YORK
^
(1978
$)
10
i
Capital cost
Boiler5
Pollution
Level
PM SO-
B~ ~BZ
I I
I II
II I
II II
control
Type
FGD-WS
FGD-WS
FGD-WS
ESP, FGD-WS
ESP, FGD-WS
10,955.
1,816.
2,173.
2,233.
2,536.
2,609.
7
5
4
1
7
3
Annual! zed
capital charges3
1,280.
268.
321.
330.
357.
368.
1
2
1
2
4
4
Annual direct
and indirect
operating costs
(incl. fuel)
2,174.
434.
513.
537.
532.
557.
9C
7
1
1
5
2
Total
Annual i zed costs
3,455.
702.
834.
867.
889.
925.
0
*
9
2
3
9
6
Total
annual ized
costs/GJ
(MMBtu)
4.15
0.84
1.00
1.04
1.07
1.11
(4.38)
(0.89)
(1.06)
(1.10)
(1-13)
(1-17)
Total boiler and
pollution
Level
PM Sp_2
B B
I I
II II
II I
II II
control
12,772.
13,129.
13,188.
13,492.
13,565.
2
1
8
4
0
1,548.
1,601.
1,610.
1,637.
1,648.
3
2
3
5
5
2,609.
2,688.
2,712.
2,707.
2,732.
6
0
0
4
1
4,157.
4,289.
4,322.
4,344.
4,380.
9
2
3
9
6
4.99
5.15
5.19
5.22
5.26
(5.27)
(5.44)
(5.48)
(5.51)
(5.55)
aAssumes an interest rate of 6 percent based upon a weighted average interest rate of New York State's bonded debt
outstanding as stated in Moody1s Municipal and Government Manual 1980.
Boiler capital cost is annualized over a 30-year life.
^Transportation costs of $197,100 for coal and $137,970 for RDF are added to model boiler #11's fuel costs.
FGD-WS capital costs are annualized over a 15-year life. The capital costs of ESP, FGD-WS, having different
service lives, are annualized using weighing factors for 15- and 20-year lives.
-------
Table 9-53 shows the change froa the base case in the annualized cost
of producing new steaa. The range of changes in annualized cost is 3.2 to
5.4 percent. In dollar terms, the change froa base case annualized costs
ranges froa $131,300 to $222,700. Relative to appropriations for State
purposes of $3,652 aillion (see Section 9.1.2), the increaental aaount is
saall. However, a new NFFB would be one of nine boilers at the Albany
steaa-producing plant. The percent change froa the base case would then be
reduced by the share of new steaa froa the NFFB to total steaa generated at
the plant. Therefore, the overall percent change in the cost of producing
steaa would be signfiicantly less than what Table 9-53 indicates.
It should be noted that Tables 9-52 and 9*53 present costs of a new
NFFB that fires 50 percent coal and 50 percent RDF, while the actual Albany
facilities will fire 100 percent RDF (refer to Table 9-20). Due to S02
controls, the costs for a cofired boiler are significantly higher than
costs for a 100 percent RDF-fired unit which would not have SO. controls.
However, the aaount by which costs for the two NFFB's differ has not been
determined. Therefore, Table 9-53 is overstating the actual percent change
over the base case for a 100 percent RDF-fired facility.
9.2.3.4 Harrisburg. Pennsylvania.
9.2.3.4.1 New boiler house configuration. It is assumed that if
Harrisburg replaced an existing boiler or expanded with a new unit, the
NFFB chosen would be siailar in size and fuel to each existing boiler.
Model boiler #13, a 44 HW (150 MMBtu/hr) heat input MSW boiler, is nearest
in size to the facility's existing MSW boilers of 42.8 HW (146 MM8tu/hr)
heat input. The existing boiler house is outlined in Section 9.1.2.
Table 9-54 shows the basic configurations of a new NFFB.
In the base case, the plant's boiler replacements are subject to
existing SIP eaission regulations. Table 9-55 outlines capital and 04M
costs of a new 44 MW (150 MMBtu) heat input MSW boiler under the base case
which specifies an ESP to achieve 92.9 percent PM control. Capital costs
are annualized and added to 0AM costs. To promote comparisons, these costs
are then converted to a per GJ (MMBtu) basis.
9.2.3.4.2 Selected control level results. Table 9-55 delineates
costs under two selected control levels: Level I using an ESP to achieve
95.5 percent PM control (43.0 ng/J [0.10 Ib PM/MMBtu] ceiling); and Level
9-118
-------
II employing an ESP to attain 98.5 percent PM control (21.5 ng/J [0.05 Ib
PM/MBtu] Halt). The annualized costs of these additional pollution
controls range fro* $0.31/6J ($0.33/MMBtu) to $0.35/GJ ($0.37/ltetu); the
total cost ranges from $1.82/GJ ($1.92/MMBtu) to S1.86/6J ($1.96/ltetu).
Capital availability to fund the incremental pollution control capital
costs does not see* to pose a problem. In the base case pollution control
capital of $1.1 Billion represents 6.3 percent of the total capital cost of
$17.6 Billion. In the Level II control case the capital cost of pollution
control is $1.3 Billion or 7.3 percent of the total capital cost of $17.8
•illion. Assuring that the base case investment is affordable, the incre-
mental capital cost due to the control levels would add only 1.1 percent,
at aost, to the total capital cost of the project.
Table 9-56 depicts the annualized costs of producing steam under
Levels I and II as opposed to the base case before and after accounting for
a waste disposal credit. The cost of producing steam under Level I is 0.24
percent greater than under the base case before accounting for the credit
and 1.10 percent greater after subtracting the credit. In Level II, achiev-
ing the most stringent pollution reductions, the cost of generating steam
is 0.97 percent greater than in the base case without a landfill credit and
2.20 percent greater with a credit. However, a new NFFB would be one of
three boilers at the Harrisburg steam plant. The percent change from the
base case would then be reduced by the share of steam from the new NFFB to
total steam generated at the plant. The overall change from the base case
would be small.
In dollar terms, the change in annualized costs from the base case
ranges from $10,000 in Level I to $33,200 in Level II. When compared to
overall municipal expenditures of $15.4 million (see Section 9.1.2), these
Increments are less than one percent of the total. As a ratio of sewerage
and sanitation expenditures of $2.7 million (see Section 9.1.2), this
amount is less than three percent. However, it should be noted that higher
costs of producing steam could be recovered partially from revenues gener-
ated from selling steam.
9.2.3.5 Peekskill. New York.
9.2.3.5.1 New NFFB configuration. Since the Peekskill plant is to be
constructed by 1984 it could possibly show an impact under an alternative
9-119
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TABLE 9-53. CHANGE IN ANNUALIZED COST OF PRODUCING STEAM
ALBANY, NEW YORK, NFFB
44 MW (150 MMBtu) RDF/coal coflred
boiler (model boiler #11)
Cost/
GJ (MMBtu)
% A over
base case
Base case PM and SO,
Level I PM and SO,
Level I PM, Level II S02
Level II PM, Level I S0£
Level II PM and SO,
4.99 (5.27)
5.15 (5.44)
5.19 (5.48)
5.22 (5.51)
5.26 (5.55)
3.2
4.0
4.6
5.4
9-120.
-------
TABLE 9-54. NEW NFFB CONFIGURATION,3
HARRISBURG, PENNSYLVANIA
Heat input capacity, MW (MMBtu/hr) 44 (150)
Fuel design type MSW
Annual capacity utilization (%) 60
aAssumes new boiler configuration based on model boilers.
9-121
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TABLE 9- 5& BOILER AND POLLUTION CONTROL COSTS OF A 44 MW (150 MMBTU/HR) HEAT INPUT MSW BOILER
(MODEL BOILER #13)
HARRISBURG, PENNSYLVANIA, NFFB
(1978
$)
ro
ro
Boiler0
Pollution
PM level
B
I
II
Total boi
pollution
Level
B
I
II
Annual izeda
Capital cost capital charges
16,500.0 2,011.9
control6
Type
ESP 1,112.9 151.8
ESP 1,168.7 159.2
ESP 1,298.2 176.9
ler and
control
17,612.9 1,163.7
17,668.7 2,171.1
17,798.2 2,188.8
Annual direct Total
and indirect annual ized
operating costs Total . costs/GJ
(incl. fuel) annual ized costs (MMBtu)
1,148.0 l,245.9d 1.51 (1.59)d
108.8 260.6 0.31 (0.33)
111.4 270.6 0.33 (0.34)
116.9 293.8 0.35 (0.37)
1,256.8 1,506.5 1.82 (1.92)
1,259.4 1,516.5 1.84 (1.93)
1,264.9 1,539.7 1.86 (1.96)
Assumes an interest rate of 7 percent based upon a weighted average interest rate on Harrisburg's bonded
debt outstanding as delineated in Moody's Municipal and Government Manual 1980.
Includes annualized capital costs, interest on working capital, general and administrative expenses, taxes
and insurance.
Boiler capital cost is annualized over a 30-year life.
Includes waste disposal credit of $1,914,000 or $2.43/MMBtu.
ePo11ution control capital costs are annualized over a 20-year life.
-------
TABLE 9-56. CHANGE IN ANNUALIZED COST OF PRODUCING STEAM
HARRISBURG, PENNSYLVANIA NFFB
Base case
Level I
Level II
44 MW
Cost/GJ
(MMBtu) before
landfill credit
4.11 (4.34)
4.12 (4.35)
4.15 (4.38)
(150 MMBtu/hr) MSW
Net cost/
GJ (MMBtu)
1.82 (1.92)
1.84 (1.93)
1.86 (1.96)
boiler (model boiler #13)
%A over base
case before
landfill credit
—
0.24
0.97
Net %A over
base case
—
1.10
2.20
to
al_andfill credit equals $2.43/MMBtu.
CO
-------
control level. Therefore, this analysis will present the costs of operat-
ing these 85.7 MW (292 MMBtu/hr) MSW boilers under the base case and Con-
trol Levels I and II. The costs of this boiler are determined by inter-
polating between model MSW boilers #13 of 44 MW (150 MMBtu/hr) and #14 of
117 MW (400 MMBtu/hr). Table 9-5? shows the basic configurations of the
new NFFBs.
In the base case all new NFFB's are subject to the applicable SIP
emission regulation. Table 9-58 depicts the capital and O&M costs asso-
ciated with operating a new 86 MW (292 MMBtu/hr) heat input MSW boiler in
the base case. Annualized capital and O&M costs associated with the boiler
equal $1.03/GJ ($1.09/MMBtu), net of a landfill credit. Annualized pollu-
tion control (capital and O&M add another $0.26/GJ ($0.27/MMBtu) in the
base case for a total annualized cost of $1.29/GJ ($1.36/MMBtu).
9.2.3.5.2 Selected control level results. Table 9- 58 also outlines
the costs of a new NFFB under two more stringent pollution control levels;
Level I achieving 95.5 percent PM control (43.0 ng/J [0.10 Ib PM/MMBtu]
limit) and Level II attaining 98.5 percent control (21.5 ng/J [0.05 Ib
PM/MMBtu] limit). The annualized costs of these additional pollution
controls range from $0.27 per GJ ($0.28/MMBtu) under Level I to $0.30/GJ
($0.31/MMBtu) under Level II for a total annualized cost ranging from
$1.30/GJ ($1.37/MMBtu) to $1.33/GJ ($1.40/MMBtu).
Capital availability to fund the incremental pollution control capital
costs does not seem to be a problem. In the base case pollution control
capital cost of $1.8 million for one boiler represents 6.2 percent of the
total capital cost of $29.5 million. The Level II capital cost of $2.2
million represents 7.5 percent of the total'capital cost of $29.9 million.
The incremental cost due to the control levels would add, at most, 1.4 per-
cent to the total capital cost of each boiler. As discussed in Section
9.1.2, State, county, and municipal sources are planning to fund the NFFB's.
The total financing package can be distributed, thereby rendering incremen-
tal costs affordable to any one party.
Table 9-59 shows how the costs of producing steam under the selected
control levels differ from the base case before and after accounting for a
waste disposal credit. Before subtracting the credit, the cost of produc-
ing steam under the first control level is 0.28 percent greater than the
9-124
-------
base case, while the cost under the second control level is 1.40 percent
greater. After subtracting the credit, the net cost of producing new steam
under Level I is 0.78 percent greater than the base case, while the net
cost under Level II is 3.10 percent greater. In dollar terms this change
from the base case ranges from $20,600 to $72,200 for each boiler. It
should be noted that increased costs due to the standard could be recouped
in part through revenues generated from selling steam.
A comparison can be made between the increment in total annualized
costs and expenditures on the municipal, county, and State levels. All
three levels are considered because the exact shares of each level in
financing the NFFB project are uncertain. When compared to total 1977
municipal expenditures of $7.3 million (inflated to 1978 terms), these
increments represent less than one percent of the total. However, as a
ratio of 1977 municipal sewerage and sanitation expenditures of $0.4 mil-
lion (inflated to 1978 terms), the increment ranges from 3.0 percent in
Level I to 15.0 percent in Level II. Comparing the increment to total
county and to State expenditures would show an even smaller ratio.
9.2.3.6 Saugus. Massachusetts.
9.2.3.6.1 New boiler house configuration. It is possible that RESCO
will operate a third boiler. As alternative waste disposal costs climb,
more communities may find dumping at the Saugus facility to be economically
sound. This higher volume of recoverable refuse coupled with the likeli-
hood of selling more steam to local industry could make a third boiler
investment financially attractive. Therefore this analysis will evaluate
the costs of operating a new unit configured similar to the existing units.
RESCO is considering installing a new 680 megagrams/day (750 tons/day) unit
with a heat input capacity of 89.4 MW (305 MMBtu/hr). The costs of this
boiler are determined by interpolating between model MSW boilers #13 of 44
MW (150 MMBtu/hr) and #14 of 117 MW (400 MMBtu/hr). Table 9-60 shows the
basic configurations of the new NFFB.
In the base case all new NFFB's are subject to the applicable SIP
emission regulation. Table 9-61 shows the capital and O&M costs associated
with operating a new 89 MW (305 MMBtu/hr) heat input MSW boiler in the base
case. Annualized boiler capital and O&M costs net of a landfill credit
equal $1.55/GJ ($1.63/MMBtu). Annualized pollution control capital and O&M
9-125
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TABLE 9-57 NEW NFFB CONFIGURATION
PEEKSKILL, NEW YORK
Heat input capacity,
Fuel design type
Annual capacity util
MW (MMBtu/hr)a
ization (%)
Boiler #1
85.7 (292)
MSW
60
Boiler #2
85.7 (292)
MSW
60
aCosts for this boiler size are derived by interpolating between
the MSW model boiler #13 (44 MW [150 MMBtu/hr]) and the MSW model
boiler #14 (117 MW [400 MMBtu/hr]).
9-126
-------
TABLE 9-58- BOILER AND POLLUTION CONTROL COSTS OF A 86 MW (292 MMBTU/HR) HEAT INPUT MSW BOILER
PEEKSKILL, NEW YORK
(1978 10J $)
Annualized 'c
Capital cost capital charges
Annual direct
and indirect
operating costs
(incl. fuel)
Total
annualized costs
Total
annuali zed
costs/GJ
(MMBtu)
10
I
Boiler
Pollution control
PM level Type
B ESP
I ESP
II ESP
Total boiler and
pollution control
27,656.7
1,836.1
1,922.8
2,243.5
3,159.7
237.0
248.2
289.3
2,230.1
174.2
183.5
194.2
1,675.7*
411.2
431.8
483.4
1.03 (1.09)*
0.26 (0.27)
0.27 (0.28)
0.30 (0.31)
Level
B
I
II
29,492.8
29,579.5
29,900.2
3,396.7
3,407.9
3,449.0
2,404.3
2,413.6
2,424.3
2.086.9
2,107.5
2,159.1
1.29 (1.36)
1.30 (1.37)
1.33 (1.40)
aCosts for this boiler size are interpolated from model boilers #13 (44 MW [150 MMBtu/hr MSW]) and #14
(117 MW [400 MMBtu/hr MSW]).
Assumes a 6 percent interest rate.
clncludes annualized capital costs, interest on working capital, general and administrative expenses, taxes
and insurance.
Boiler capital costs annualized over a 30-year life.
Includes waste disposal credit of 3,714,100 or $2.42/MMBtu.
Pollution control capital costs annualized over a 20-year life.
-------
TABLE 9-59. CHANGE IN ANNUALIZED COST OF PRODUCING STEAM
PEEKSKILL, NEW YORK, NFFB
Cost/GJ
(MMBtu) before
landfill credit
86 MW (292.MMBtu/hr)
MSW boiler
Base case 3.58 (3.78)
Level I 3.59 (3.79)
Level II 3.63 (3.83)
Net cost/
GJ (MMBtu)
1.29 (1.36)
1.30 (1.37)
1.33 (1.40)
% A over base
case before
landfill credit
0.28
1.40
Net % A over
base case
0.78
3.10
£ aLandfill credit equals $2.42/MMBtu.
<» Costs are derived by interpolating between the MSW model boilers #13 (44 MW [150 MMBtu/hr]) and
#14 (117 MW [400 MMBtu/hr]).
-------
TABLE 9-60. NEW NFFB CONFIGURATION
SAUGUS, MASSACHUSETTS
Heat input capacity,3 MW (MMBtu/hr) 89.4 (305)
Fuel design type MSW
Annual capacity utilization (%) 60
aCosts for this boiler size will be derived by interpolating between
the MSW model boiler # 13 (44 MW [150 MMBtu/hr]) and the MSW model
boiler #14 (117 MW [400 MMBtu/hr]).
9-129
-------
TABLE 9-61. BOILER AND POLLUTION CONTROL COSTS OF A 89 MW (305 MMBTU/HR) MSW BOILER1
SAUGUS, MASSACHUSETTS
(1978 10* $)
Annualized '
Capital cost capital charges
Annual direct
and indirect
operating costs
(incl. fuel)
Total
annualized costs
Total
annualized
costs/GJ
(MMBtu)
to
I
CO
o
Boiler
Pollution control
PM level Type
B ESP
I ESP
II ESP
Total boiler and
pollution control
Level
28,599.1
1,897.2
1,986.4
2,325.4
4,182.8
2,314.2
302.4
316.7
370.3
180.4
190.0
201.2
2,617.4
482.7
506.7
571.6
1.55 (1.63)1
0.29 (0.30)
0.30 (0.32)
0.34 (0.36)
B
I
II
30,496.3
30,585.5
30,924.5
4,485.2
4,499.5
4,553.1
2,494.6
2,504.2
2,515.4
3,100.1
3,124.1
3,189.0
1.83 (1.93)
1.85 (1.95)
1.89 (1.99)
a
Costs for this boiler size interpolated from the MSW model boilers #13 (44 MW (150 MMBtu/hr)) and #14
(400 MMBtu/hr).
3Assumes an interest rate of 10 percent.
'Includes annualized capital costs, interest on working capital, general and administrative expenses, taxes,
and insurance.
Boiler capital costs annual!zed over a 30-year life.
^Includes landfill credit of $3,879,500 or $2.42/MMBtu.
Pollution control capital costs annualized over a 20-year life.
-------
costs add another $0.29/GJ ($0.30/MMBtu) for a total boiler and pollution
control cost of $1.83/GJ ($1.93/MMBtu).
9.2.3.6.2 Selected control level results. Table 9-61 shows the cost
of a new NFFB under two more stringent pollution control options: one
level using an ESP to attain 95.5 percent PM control (43.0 ng/J [0.10 Ib
PM/MMBtu] ceiling) and another level operating an ESP to achieve 98.5
percent PM control (21.5 ng/J [0.05 Ib PM/MMBtu] limit).
In the base case, pollution control capital costs of $1.9 million
represents 6.2 percent of the total capital cost of $30.5 million. In the
most expensive pollution control option (Level II), pollution control
capital costs of $2.3 million comprises 7.5 percent of the total capital
cost of $30.9 million. The incremental capital cost due to the control
levels would add, at most, 1.4 percent to the total capital cost of the
NFFB project. Since it is assumed that the base case investment is afford-
able, the 1.4 percent maximum increase in capital costs due to the more
stringent control level-appears equally affordable. Furthermore, any
increase in costs could be recouped from revenues generated from selling
steam.
Table 9-62 shows how the costs of producing new steam under the se-
lected control levels differ from the base case. The cost of producing
steam under the first selected control level is 0.49 percent greater than
the base case before subtracting a landfill credit and 1.09 percent greater
after subtracting the credit. The second control level is 1.46 percent
greater than the base case without the credit and 3.28 with the credit. In
dollar terms this change from the base case ranges from $24,000 to $88,900.
A new NFFB would be one of three boilers operated at the RESCO steam plant.
The percent change from the base case would then be reduced by the share of
steam from the new boiler to steam from the entire plant. The overall
change from the base case would thereby be reduced.
9-131
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TABLE 9-62. CHANGE IN ANNUALIZED COST OF PRODUCING STEAM,
SAUGUS, MASSACHUSETTS NFFB
10
i
co
ro
89 MW heat input
(305 MMBtu/hr)
MSW Boiler0
Base case
Level I
Level II
Cost/GJ
(MMBtu) before
landfill credit3
4.12 (4.35)
4.14 (4.37)
4.18 (4.41)
Net cost/
GJ (MMBtu)
1.83 (1.93)
1.85 (1.95)
1.89 (1.99)
% A over base
case before
landfill credit
—
0.49
1.46
Net % A over
base case
—
1.09
3.28
Landfill credit equals $2.42/MMBtu.
Costs for this boiler size are derived by interpolating between MSW model boilers #13 (44 MW [150
MMBtu/hr]) and #14 (117 MW [400 MMBtu/hr]).
-------
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9-137
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APPENDIX A - EVOLUTION OF THE PROPOSED STANDARDS
A screening study of nonfossll fuel fired boilers was begun on
August 31, 1978 by Acurex Corporation under the direction of the Office
of Air Quality Planning and Standards (OAQPS), Emission Standards and
Engineering Division (ESED). The screening study was concluded in
February 1979, with the recommendation that New Source Performance
Standards be developed for nonfossil fuel fired boilers. Work then
began on Phase II of the study. Radian Corporation took over the project
in February 1980.
The chronology which follows lists important events which have
occurred in the development of this background information document for
New Source Performance Standards for nonfossil fuel fired boilers.
A-l
-------
DATE
ACTIVITY
July 28, 1978
December 7, 1978
January 4, 1979
January 10, 1979
April 19, 1979
June 4, 1979
June 5, 1979
June 12, 1979
June 13, 1979
June 13, 1979
June 14, 1979
June 22, 1979
June 26, 1979
June 27, 1979
July 12, 1979
July 25, 1979
Meeting with DuPont Company representatives
Visit to Resource Energy Systems Company
in Saugus, Massachusetts
Visit to Weyerhaeuser Company pulp mill
in New Bern, North Carolina
Visit to National Center for Resource
Recovery in Washington, D.C.
Visit to General Electric in Erie,
Pennsylvania
Visit to Westvaco paper mill in Covlngton,
Virginia
Visit to Owens-Illinois paper mill in
Big Island, Virginia
Visit to Long Lake Lumber Company sawmill
in Spokane, Washington
Visit to Georgia-Pacific pulp & paper mill
in Bellingham, Washington
Visit to Weyerhaeuser Company sawmill in
Snoqualmie Falls, Washington
Visit to Simpson Timber Company sawmill in
Shelton, Washington
Visit to Union Camp pulp and paper mill in
Franklin, Virginia
Visit to Nashville Thermal Transfer Corpora-
tion in Nashville, Tennessee
Visit to municipal incinerator in Salem,
Virginia
Meeting with Council of Industrial Boiler
Owners representatives
Visit to General Motors Corporation in
Pontiac, Michigan
A-2
-------
DATE
ACTIVITY
July 26, 1979
August 22, 1979
September 5, 1979
September 13, 1979
September 17, 1979
September 18, 1979
September 19, 1979
November 5-7. 1979
December 10-15, 1979
December 17-19, 1979
December 21, 1979
January 9, 1980
January 16-24, 1980
January 29-31, 1980
February 12-13, 1980
March 11, 1980
Meeting with R.E. Frounfelker of Systems
Technology Corporation
Survey of small municipal incinerators
completed
Meeting with American Plywood Association
representatives
Visit to Champion International paper mill
in Roanoke Rapids, North Carolina
Visit to U.S. Sugar Corporation mill in
Pahokee, Florida
Visit to St. Regis Paper Company paper mill
in Jacksonville, Florida
Visit to St. Joe Paper Company paper mill
in Port St. Joe, Florida
Emission testing visit to municipal incin-
erator in Salem, Virginia
Emission testing visit to Owens-Illinois
paper mill in Big Island, Virginia
Emission testing visit to U.S. Sugar
Corporation mill in Pahokee, Florida
Section 114 letters sent to industries
Meeting with Chemical Manufacturers
Association representatives
Emission testing visit to St. Joe Paper
Company paper mill in Port St. Joe, Florida
Emission testing visit to St. Regis Paper
Company mill in Jacksonville, Florida
Emission testing visit to Westvaco pulp
and paper mill in Covington, Virginia
Meeting with Florida Sugar Cane League
representatives
A-3
-------
DATE
ACTIVITY
March 25, 1980
March 25, 1980
March 25, 1980
June 23-27, 1980
July 29, 1980
August 28, 1980
September 22-26, 1980
October 7, 1980
October 8, 1980
October 9, 1980
November 7, 1980
November 10, 1980
November 11, 1980
November 12, 1980
November 14, 1980
November 17, 1980
Visit to Gulf & Western Food Products
Company in South Bay, Florida
Visit to Sugar Cane Growers Cooperative
of Florida in Belle Glade, Florida
Visit to Atlantic Sugar Association in
Belle Glade, Florida
Emission testing visit to St. Regis Paper
Company paper mill in Jacksonville, Florida
Meeting with National Council of the Paper
Industry for Air and Stream Improvement
Visit to Owens-Illinois paper mill in
Big Island, Virginia
Emission testing visit to Owens-Illinois
paper mill in Big Island, Virginia
Visit to Georgia-Pacific Corporation in
Bellingham, Washington
Visit to Weyerhaeuser Company in
Longview, Washington
Visit to Long Lake Lumber Company in
Spokane, Washington
Opacity testing visit to Nashville Thermal
Transfer Corporation in Nashville, Tennessee
Opacity testing visit to Georgia-Pacific
Corporation in Emporia, Virginia
Opacity testing visit to Champion International
Corporation in Corrigan, Texas
Opacity testing visit to Georgia-Pacific
Corporation in Warm Springs, Virginia
Meeting with Hawaii Sugar Planters Associa-
tion representatives
Meeting with D. Junge, Director of the Energy
Research & Development Institute at Oregon
State University
A-4
-------
DATE
ACTIVITY
November 17-22, 1980
December 8-12, 1980
December 15-19, 1980
January 19, 1981
January 21, 1981
February 10, 1981
June 2, 1981
July 14, 1981
February 9, 1982
Emission testing visit to Georgia-Pacific
pulp & paper mill in Bellingham, Washington
Emission testing visit to Weyerhaeuser
Company in Longview, Washington
Emission testing visit to Long Lake Lumber
Company in Spokane, Washington
Opacity testing visit to Champion Inter-
national paper mill in Roanoke Rapids,
North Carolina
Opacity testing visit to Research Energy
Systems Company in Saugus, Massachusetts
Meeting with representatives of
Weyerhaeuser Company to discuss test data
from the ELECTROSCRUBBER filter.
Meeting with representatives of the American
Boiler Manufacturers' Association
Meeting with representatives of the National
Council of the Paper Industry for Air and
Stream Improvement
Meeting with representatives of the National
Council of the Paper Industry for Air and
Steam Improvement, the Council of Industrial
Boiler Owners, the American Boiler Manufacturers'
Association and the Chemical Manufacturers'
Association.
A-5
-------
APPENDIX B
INDEX TO ENVIRONMENTAL CONSIDERATIONS
This appendix consists of a reference system which is cross indexed
with the October 21, 1974, Federal Register (30 FR 37419) containing EPA
guidelines for the preparation of Environmental Impact Statements. This
index can be used to identify sections of the document which contain data
and information germane to any portion of the Federal Register guidelines.
There are, however, other documents and docket entries which also
contain data and information, of both a policy and a technical nature, used
in developing the proposed standards. This appendix specifies only the
portions of this document that are relevant to the indexed items.
B-l
-------
TABLE B-l. INDEX TO ENVIRONMENTAL CONSIDERATIONS
Agency Guideline for Preparing Regulatory
Action Environmental Impact Statements
_ (39 FR 37419) _
(1) Background and summary of regulatory
alternatives
Regulatory alternatives
Statutory basis for proposing standards
Source category and affected industries
Emission control technologies
Location Within the Background Information Document
The regulatory alternatives are summarized in
Chapter 6.
The statutory basis for the proposed standards
is summarized in Chapter 2, Section 2.1.
A discussion of the nonfossil fuel fired boiler source
category is presented in Chapter 3. Details of the
"business/economic" nature of the industries affected
are presented in Chapter 9.
A discussion of emission control technologies is
presented in Chapter 4.
-------
TABLE B-l. (CONTINUED)
CD
I
co
Agency Guideline for Preparing Regulatory
Action Environmental Impact Statements
(39 FR 37419)
(2) Environmental, Energy, and Economic
Impacts of Regulatory Alternatives
Regulatory alternatives
Environmental impacts
(Individual boilers)
Energy impacts
(Individual boilers)
Cost impacts
(Individual boilers)
Economic impacts
(Individual boilers)
National Environmental
and energy impacts
Locations Within the Background Information Document
Various regulatory alternatives are discussed in
Chapter 6.
The environmental impacts of various regulatory
alternatives are presented in Chapter 7, Sections
7.1, 7.2 and 7.3.
The energy impacts of various regulatory
alternatives are discussed in Chapter 7, Section 7.4
Cost impacts of various regulatory alternatives
are discussed in Chapter 8.
The economic impacts of various regulatory
alternatives are presented in Chapter 9.
The national Environmental and energy impacts of
regulatory alternatives are presented in Chapter 7.
National and regional
cost impacts
The national and regional cost impacts of
regulatory alternatives are presented in
Chapters 8 and 9.
-------
TABLE B-l. (CONTINUED)
Agency Guideline for Preparing Regulatory
Action Environmental Impact Statements
(39 FR 37419)
Location Within.the Background Information Document
ro
i
(3) Environmental impact of the
regulatory alternatives
Air pollution
(Individual boilers)
Water pollution
(Individual boilers)
Solid waste disposal
(Individual boilers)
The impact of the proposed standards on air
pollution is presented in Chapter 7, Section 7.1.
The impact of the proposed standards on water
pollution is presented in Chapter 7, Section 7.2.
The impact of the proposed standards on solid
waste disposal is presented in Chapter 7, Section 7.3,
-------
APPENDIX C
Available emission data illustrating the performance levels achievable
by various control systems evaluated in this study are presented in this
appendix. The data are analyzed and discussed in Chapter 4. The data
base is organized as follows:
Section C.I - Particulate Emission Data
Section C.2 - Visible Emission Data
Section C.3 - SQy Emission Data
Section C.4 - References
For each data set presented in this Appendix, a brief description
of the test site is provided which includes data (when available) such as:
- Boiler type and rated capacity
- Boiler load factor during testing
- Type of emission control system
- Emission control system design specifications
- Emission control system operating parameters during testing
- Emission control system outlet emission level
All particulate and visible emission test sites are given a letter
designation (example, Plant AB). All SCL emission test sites are given
a roman numeral designation (example, Location I).
C-l
-------
C.I PARTICULATE EMISSION DATA
A majority of the participate emission data presented here was
obtained from industry sources or from State and local air pollution
control agencies. Other tests were conducted by nonfossil fuel fired
boiler owners/operators or by the EPA.
Because the test data came from many different sources, a set of
test review criteria were developed in order to insure only valid test
data would be used in this study. A discussion of these criteria follows.
The first part of these criteria was to insure the test was conducted
in accordance with EPA Method 5 procedures. All the emission test data
(with one exception discussed below) obtained for this study were submitted
to the Emissions Measurement Branch (EMB) of EPA and reviewed to determine
that Method 5 procedures were followed. Tests with insufficient documentation
to show that proper procedures were followed, or tests which showed
deviations from Method 5 procedures which could have significantly
affected the test results, were not used in NSPS development and are not
presented in this document. One additional emission test was accepted
for this study without EMB review. There was insufficient documentation
with this test which prevented a complete review; however, this test was
performed under EPA supervision and therefore proper Method 5 procedures
were assumed to have been followed.
The second part of the test review consisted of determining the
critical design and operation parameters of the boiler and emission
control system. These minimum design and operation parameters required
were as follows:
C-2
-------
- boiler firing method and rated steam capacity
- fuel type(s) fired during testing
- boiler load during testing
- control device operation parameters during testing such as pressure
drop for wet scrubbers, air-to-cloth ratio of fabric filters, and
specific collection area for electrostatic precipitators.
Any emission test performed on a boiler and control system for
which the above data were unavailable was not used in this study or
presented in this document.
Finally, the design and operation of the boiler and control system
were reviewed to determine if there were design deficiencies or examples
of improper operation during testing which could have affected the
control device performance. If design or operation problems were found
the test was generally not used in this study or presented in this
document. However, the test was used if sufficient data were available
(such as control device inlet emission data) to show that the control
device was still able to achieve the design removal efficiency under
these conditions. The exception to this is testing done by EPA specifically
for this study. All the data from EPA emission tests done for this
study are presented in Appendix C. However, if the results are not
considered representative of well designed and operated systems, the EPA
data are not presented in Chapter 4 and are not used in NSPS development.
Each site is given a letter designation according to the fuel type.
The fuel type is indicated by the first letter (A or B for wood, D for
bagasse, F for MSW, and H for RDF). Cofired boilers are listed with
other plants firing the same nonfossil fuel. Each site is briefly
described and is followed by a presentation of the test data.
C-3
-------
The site descriptions include boiler type and rated capacity. The
type of participate control equipment is also identified. Since these
tests were conducted by different individuals, some of the tests have
more detailed information on the control devices, fuel, and test conditions
than others.
A test summary sheet follows each site description. Date, percent
isokinetic, boiler load, and sample point location during testing are
presented. Stack gas data presented include: flow rate, temperature,
and percent moisture, oxygen, and carbon dioxide. Information is also
presented concerning control equipment type and important operating
parameters. Only the control equipment through which the flue gas has
passed is listed. For example, if the sampling location is at the inlet
to a wet scrubber, the control equipment listed may include a mechanical
collector but not the wet scrubber. Fuel analyses are included when
available.
The particulate emissions expressed in ng/J Ob/million Btu) were
determined by the following procedure:
E = CF [20.9 - percent 02)]
where:
(1) E = pollutant emission ng/J (Ib/million Btu).
(2) C = pollutant concentration, ng/dscm (Ib/dscf).
(3) Percent Op = oxygen content by volume (expressed as percent),
dry basis.
(4) F = a factor representing a ratio of the volume of dry flue
gases generated to the calorific value of the fuel combusted.
C-4
-------
The following F factors were used in this report.
(i) For bark F = 2.589 x 10~7 dscm/J (9,640 dscf/million Btu).
For wood residue other than bark F = 2.492 x 10~7 dscm/J (9,280 dscf/million Btu),
For hogged wood F = 2.524 x 10"7 dscm/J (9,400 dscf/million Btu).
(ii) For municipal solid waste (MSW) F = 2.589 x 10 dscm/J
(iii) For refuse derived fuel (RDF) F = 2.551 x 10"7 dscm/J
(9,640 dscf/million Btu).
(iii) For refuse der
(9,500 dscf/million Btu).
(iv) For bagasse F = 2.479 x 10"7 dscm/J (9,230 dscf/million Btu).
(v) For coal F = 2.627 x 10 dscm/J (9,780 dscf/million Btu).
(vi) For oil F = 2.476 x 10"7 dscm/J (9,220 dscf/million Btu).
-------
c - 10"6[227.2(%H) + 95.5(%C) + 35.6(%S) + 8.7(%N) - 28.7(%0)
6CV
(SI units)
c = 106[3.64(%H) + 1.53(%C) + 0.57(XS) + 0.14(%N) 0.46(%0)]
r GCV
(English units)
(i) H, C, S, N, and 0 are content by weight of hydrogen, carbon,
sulfur, nitrogen, and oxygen (expressed as percent), respectively, as
determined on the same basis as GCV by ultimate analysis of the fuel
fired, using A.S.T.M. method D3178-74 or D3176 (solid fuels), or computed
from results using A.S.T.M. methods 01137-53(70), 01945-64(73), or
01946-67(72) (gaseous fuels) as applicable.
(ii) GCV is the gross calorific value (kJ/kg, Btu/lb) of the fuel
combusted, determined by the A.S.T.M. test methods 0201566(72) for solid
fuels and 01826-64(70) for gaseous fuels as applicable.
(iii) For facilities which fire both fossil fuels and nonfossil
fuels, the F value is based on the total heat input of all fuels fired.
This section is organized as follows:
Section C.I.I - Wood-Fired Boilers and Wood/Fossil Fuel
Cofired Boilers
Section C.I.2 - Bagasse-Fired Boilers
Section C.I.3 - MSW-Fired Boilers
Section C.I.4 - RDF-Fired Boilers and RDF/Fossil Fuel
Cofired Boilers
C-6
-------
C.I.I Wood-Fired Boilers and Wood/Fossil Fuel Cofired Boilers
The following facility descriptions and participate emission data
are for wood-fired and wood/fossil fuel cofired boilers. Each site is
given a 2-letter plant designation beginning with the letter A or B.
This letter indicates the facility has a wood-fired boiler or a wood/fossil
fuel boiler. A number after the plant designation distinguishes between
different tests at the same plant.
C-7
-------
PLANT AA1"5
An emissions test was performed on the No. 5 boiler at plant AA to
determine if it was in compliance with the State of Washington emission
standards. The No. 5 boiler is a traveling grate spreader stoker boiler
rated at 150,000 pounds per hour of steam. The boiler uses hog fuel of
which no more than 5 percent comes from wood stored in salt water. The
fuel ash content varies from 2 to 8 percent (dry basis). The fuel
moisture content is 50-55 percent in the summer and 60-65 percent in
winter. The species of wood fired are hemlock, fir, and spruce.
A mechanical collector and wet scrubber in series are used for
particulate emission control. The flue gas from the boiler passes
through the air heater, the mechanical collector, and the wet scrubber.
The wet scrubber is a variable throat venturi with a demister. The
fly ash collected by the mechanical collector passes through a sand
classifier and the large fraction is reinjected into the boiler furnace.
Two EPA Method 5 test runs were performed. The boiler operated at
an average of 95 percent of rated capacity. The scrubber pressure drop
during testing was 18 inches of water. The average particulate emissions
were 0.048 pounds per million Btu which is less than the State allowable
emissions level of 0.093 pounds per million Btu.
C-8
-------
PLANT AA1
TEST SUMMARY SHEETS
(Particuiates only;
Test Number One Two Three Average
General Data
Date 11/7/79 11/7/79
% Isokinetlc 98.5 100.4
Boiler Load (% of design) 95 95 95
Sample Point Location Outlet of scrubber
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nnu-dry 0.0595 0.0458 0.0526
g/Nm -dry e 12% C02 OBT6 O4l2 O469
gr/dscf 0.026 0.020 p.023
gr/dscf 3 12? CO- 0.023 0.018 p.020
ng/J c g37T" 17.8 20.5
lb/10° Btu OP" 0.0413 O477
Average Opacity
Control Device
Type MC/WS
Operating Parameter1 18
Design Parameter —
Design Flow Rate (ACFM) HHZZZZZZH
For MS, pressure drop = "H90.For ESP, SCA = ftZ/1000 ACFM.
For FF, A/C = ft/min. z
C-9
-------
PLANT AB6'10
An emission test was run at plant AB to determine compliance with
the Oregon particulate emission standard. The boiler is a spreader
stoker rated at 70,000 pounds per hour of steam. The primary fuel is a
hogged wood/bark mixture of douglas fir and hemlock. This wood fuel is
size classified and only the pieces too large for the feed system are
hogged. This results in a larger average fuel particle size than if all
the fuel was hogged. The secondary fuels are hardboard wastes, consisting
of pulverized fiber dust and sanderdust which are burned in a separate
sanderdust burner in the boiler. The estimated moisture content of the
combined fuels is 45 percent. Particulate emissions are controlled by a
mechanical collector followed by an impingement wet scrubber. Fly ash
collected by the mechanical collector passes through a sand classifier
and large particles are reinjected into the boiler furnace. The normal
operating scrubber pressure drop is 6 to 8 inches of water.
Three EPA Method 5 test runs were made on both the inlet and outlet
to the wet scrubber. The third test run was done while firing a fuel
with higher fines and moisture contents than normal. The excess air
rate was also higher on the third test run than on the first two runs.
These factors caused the particulate loading at the scrubber inlet to be
higher during the third test run, although there was no significant
increase in emissions from the scrubber outlet. Average emissions were
0.0678 pounds per million Btu, which was within the allowable emission
rate of 0.21 pounds per million Btu. The boiler operated at an average
of 79 percent of rated capacity during the test. The scrubber pressure
drop during testing was normal. ,
-------
PLANT AB1°
TEST SUMMARY SHEETS
(^articulates only;
Test Number
One
Two
Three
Average
General Data
Date 3/28/78 3/28/78
% Isokinetic 108.9 106.8
Boiler Load (% of design) 79 79
Sample Point Location Inlet of scrubber
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
7.8
16,600
195.0
383
15.6
7.4
12.2
Particulate Emissions
g/NmLdry 0.249
g/Nm-dry @ 12% CO, OT23T
gr/dscf i OTIOT
gr/dscf @ 12% CO, 0.103
ng/J ,. <• 1QT7TT
lb/10b Btu OT?3T
Average Opacity
0.247
OTTOS"
0.106
"9O"
OT2241
0.382
TT357
1TT67
"67254
ISO
0.293
IOTF
ITT28"
0.138
I257F
0.2992
Control Device
1
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
MC
T
For WS, pressure drop
For FF, A/C = ft/min.
*Estimated
"H20. For ESP, SCA
C-ll
ftc/1000 ACFM.
-------
PLANT AB2
TEST SUMMARY SHEETS
(i-arncuiates unly)
Test Number
General Data
Date
% Isokinetic
One
3/28/78
102.5
Boiler Load (% of design) 79
Sample Point Location
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
3
g/Niru-dry
g/Nm -dry @ 12% C02
gr/dscf
gr/dscf @ 12% C02
ng/J -
lb/106 Btu
Average Opacity
Outlet
7.4
15.600
167
22.3
^8.2
11.4
0.073
0.0778
0.032
0.034
30.4
0.0707
Two
3/28/78
100.4
79
of scrubber
7.8
16.600
72
161,._.,
20.4
8.4_
11.2
0. 0549
0.0595
0702T
0.026
23". 2
0.0539
Three
3/28/78
95.4
79
10.2
15.650
69
157
22.4
12.0
8.8
0.0572
070775
0.025
0.034
33". 9
070788
Average
79
13.2
15.950
72
162
21.7
9.5
10.5
0.0617
0.0717
07027^
0703TT
z9. 2
0.0678
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
MC/WS
6-8
I
For WS, pressure drop
For FF, A/C = ft/min.
"H20.
For ESP, SCA = ft2/1000 ACFM
C-12
-------
1112
PLANT AC11'1
Plant AC was tested by the operator to determine the participate
emission rate. Two sets of tests were performed, one on the combined
flue gases from boilers No.l and 2 and one on boiler No.3. Boilers No.1
and 2 are identical wood-fired spreader stokers, each rated at 37,000
pounds per hour of steam. Their flue gases pass through individual
mechanical collectors and then are sent to a common impingement wet
scrubber and exhausted through a common stack. Boiler No.3 is a wood-
fired spreader stoker rated at 55,000 pounds per hour of steam. Boiler
No. 3 is also controlled with a mechanical collector and an impingement
wet scrubber. The normal operating pressure drop for both scrubbers is
6 to 8 inches of water. Fly ash collected by the mechanical collectors
is not reinjected.
Three EPA Method 5 test runs were made on each wet scrubber outlet.
The boiler load on No.s 1 and 2 averaged 63 percent of rated capacity.
The load on boiler No.3 averaged 47 percent of rated capacity. During
the test, the boilers burned 20 percent wood trim and 80 percent bark.
The emission rate for boilers No.l and 2 averaged 0.182 pounds per
million Btu. The particulate emission rate for boiler No.3 averaged
0.170 pounds per million Btu. The scrubber pressure drop during the
tests was normal.
C-13
-------
PLANT AC1
11
TEST SUMMARY SHEETS
(fdrticuiaces Only;
Test Number
One
Two
Three
Average
General Data
Date
% Isokinetic
12/17/78
100.6
Boiler Load (% of design) 72
Sample Point Location Outlet of scrubber - 1 & 2
12/17/78
99.4
61
63
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
8.9
157300
66.1
Particulate Emissions
3
g/Nm~-dry
g/Nm -dry @ 12% CO,
gr/dscf c
gr/dscf @ 12% C09
lb/10 Btu
Average Opacity
0.114
0.160
0.05
0.07
71.4
0.166
0.069
0.114
0.03
0.05
49.9
0.116
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
MC/WS
6-8
T
For WS, pressure drop
For FF, A/C = ft/min.
"H20.
For ESP, SCA = ftT/1000 ACFM.
C-14
-------
PLANT AC2
11
TEST SUMMARY SHEETS
(r'amcuiaies Oniy)
Test Number
One
Two
Three
Average
General Data
Date 12/17/78 12/17/78
% Isokinetic 1Q1T5 TUO
Boiler Load (% of design)"TJ~ 48
Sample Point Location Outlet of scrubber - 3
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
7.5
16.000
75.6
168
19.5
12.5
8.0
7.5
15T350
77.2
171
22.8
12.5
8.1
12/17/78
103.7
47
Particulate Emissions
g/Nm.-dry
g/Nm-dry @ 12% CO,
gr/dscf i
gr/dscf @ 12% C09
ng/J 6 z
lb/10b Btu
Average Opacity
0.092
OTI3F
0.04
0.059
58.5
0.136
Control Device
Type
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
MC/WS
T
6-8
For WS, pressure drop
For FF, A/C = ft/min.
"H20. For ESP, SCA = fr/1000 ACFM.
C-15
-------
PLANT AD12'13
Plant AD was tested by the operator to determine the particulate
emission rate. Plant AD has a spreader stoker boiler rated at 40,000
pounds per hour of steam. The boiler has a mechanical collector and a
venturi wet scrubber- The normal operating scrubber pressure drop is 6
to 8 inches of water. All of the fly ash collected by the mechanical
collector is reinjected into the boiler furnace.
Three EPA Method 5 test runs were conducted. During the test the
wood fuel was 90 percent bark and 10 percent wood trim. The particulate
emissions averaged 0.182 pounds per million Btu. The scrubber pressure
drop during the tests was normal. The steam meter was not working so an
exact steam flow rate could not be determined but it was reported by
plant personnel as normal. Based on the mass emission rate and the F-
factor, the estimated boiler operating rate is below 75 percent capacity.
The steam flow rate is calculated to be approximately 27,000 to 32,300
pounds per hour.
C-16
-------
PLANT ADI13
TEST SUMMARY SHEETS
(f-'articuldtes Only)
Test Number One Two Three Average
General Data
Date 12/19/78 12/19/78 12/19/78
% Isokinetic 96.1 "ISO lOTTO"
Boiler Load (% of design)"*6T" r*7$~ *5D~ ^73
Sample Point Location Outlet of scrubber
Stack Gas Data
Flow (Nm3/s-dry) ,8.3 7.9 7.g 7.Q
Flow (dscfm) 17,500 16,700 16,500 16,700
Temperature (°C) 60.0 63.9 66.7 63.5
Temperature (°F) l"4T~ 14T~ TBT~ T?5~
Moisture (%) "IO" ~ZTT TO" "2175"
Oxygen, dry (%) "TO" 10" "TO" "TTTs"
C02, dry (%) ~O" "?ir "TOTTJ
Particulate Emissions
g/Nnidry 0.114 0.137 0.160 0.137
g/Nm-dry @ 12% C02 OTW OTTsT" "OS? ITTTB"
grjdscf 0.05 0.06 0.07
gr/dscf @ 12% C02 Q.07 Q.Q8 Q.08
ng/J fi 7l« — "
lb/10° Btu 0.157
Average Opacity
Control Device
Type MC/HS
Operating Parameter1 K_R
Design Parameter
Design Flow Rate (ACFM)
For WS, pressure drop = "H«0.For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/min. L
*Estimated, based on mass emission rate and F-factor.
C-17
-------
PLANT AE12'14
Plant AE was tested by the operator to determine the participate
emission rate. The plant has a wood-fired spreader stoker rated at
120,000 pounds per hour of steam. Particulate emissions are controlled
by a mechanical collector and a venturi wet scrubber in series. The
normal operating scrubber pressure drop is 6 to 8 inches of water. Fly
ash collected by the mechanical collector passes through a sand classifier
and large particles are reinjected into the boiler furnace.
Three EPA Method 5 test runs were made. The wood fuel during
testing was 80 percent bark and 20 percent sawdust and wood trim. The
boiler operated at 85 percent of rated capacity during the test. The
average particulate emissions were 0.131 pounds per million Btu. The
scrubber pressure drop during the test was normal.
C-18
-------
PLANT AE114
TEST SUMMARY SHEETS
(ramcuiates Uniy)
Test Number One Two Three Average
General Data
Date 11/28/78 11/28/78 11/28/78
% Isokinetic 104.6 105.2 104.6
Boiler Load (% of design) 92 88 74 85
Sample Point Location Outlet of scrubber
Stack Gas Data
Flow (Nm /s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/NmLdry
g/Nm -dry @ 12% CO?
gr/dscf *
gr/dscf (? M% CO
6
lb/10° Btu
Average Opacity
Control Device
Type MC/WS
Operating Parameter1 Z~ ~~ 6-8
Design Parameter ~~~~~ ^
Design Flow Rate (ACFM) ZZHIZZIZIII
For WS, pressure drop = "H20. For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/min. i
C-19
-------
PLANT AF12'15'16
Plant AF was tested by the operator to determine the particulate
emission rate. This plant has a wood-fired spreader stoker rated at
120,000 pounds per hour of steam. Particulate emissions are controlled
by a mechanical collector followed by an impingement wet scrubber. The
normal operating scrubber pressure drop is 6 to 8 inches of water. Fly
ash collected by the mechanical collector passes through a sand classifier
and large particles are reinjected into the boiler furnace.
Three EPA Method 5 test runs were made. During the test the boiler
averaged 72 percent of rated capacity. The wood fuel was 90 percent
bark and 10 percent wood trim. The particulate emissions averaged 0.100
pounds per million Btu. The scrubber pressure drop during the test was
normal.
C-20
-------
PLANT AF115
TEST SUMMARY SHEETS
(f-articuiates uniyj
Test Number
One
Two
Three
Average
General Data
Date
% Isokinetic
Boiler Load (% of design)
Sample Point Location
Outlet of scrubber
72
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
13.2
1?-Q
Particulate Emissions
g/Nm^-dry
g/Nm -dry @ 12% CO,
gr/dscf i
gr/dscf @ 12% CO,
ng/J , Z
lb/10b Btu
Average Opacity
Control Device
Type
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
MC/HS
T
6-8
For WS, pressure drop
For FF, A/C = ft/min.
"H20. For ESP, SCA = ft2/1000 ACFM.
C-21
-------
PLANT
Plant AG was tested by its operator to determine the participate
emission rate. The plant has a wood-fired spreader stoker boiler rated
at 110,000 pounds per hour of steam. The particulate emissions from the
boiler are controlled by a mechanical collector followed by a venturi
wet scrubber. The normal operating scrubber pressure drop is 6 to 8
inches of water. Fly ash collected by the mechanical collector passes
through a sand classifier and large particles are reinjected into the
boiler furnace.
Three EPA Method 5 test runs were made. The boiler operated at an
average of 103 percent of rated capacity during the test. The wood fuel
during the test was 90 percent bark and 10 percent sawdust. The average
particulate emissions were 0.169 pounds per million Btu. The scrubber
pressure drop during the test was normal.
C-22
-------
PLANT A61
17
TEST SUMMARY SHEETS
(^articulates Only)
Test Number
One
Two
Three
Average
General Data
Date 10/31/78 10/31/78
% Isokinetic 99.1 103.6
Boiler Load (% of design) 104 101
Sample Point Location Outlet of scrubber
10/31/78
100.0
103
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
Particulate Emissions
3
g/Nnu-dry
g/NmJ-dry
12% C0
gr/dscf
gr/dscf @ 12% CO
ng/J 6
lb/10b Btu
Average Opacity
Control Device
Type
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
MC/WS
T
6-8
For WS, pressure drop
For FF, A/C = ft/min.
"H20.
For ESP, SCA = ft2/1000 ACFM.
C-23
-------
PLANT AH12'18
Plant AH was tested by the operator to determine the particulate
emission rate. This plant has a wood-fired spreader stoker rated at
140,000 pounds per hour of steam. The particulate emissions are controlled
by a mechanical collector followed by a venturi wet scrubber. The
normal operating scrubber pressure drop is 6 to 8 inches of water. Fly
ash collected by the mechanical collector passes through a sand classifier
and large particles are reinjected into the boiler furnace.
Three EPA Method 5 test runs were made. The average boiler load
during testing was 65 percent of rated capacity. The wood fuel was 85
percent bark and 15 percent wood trim. The average particulate emission
rate was 0.148 pounds per million Btu. The scrubber pressure drop
during the test was normal.
C-24
-------
PLANT AMI18
TEST SUMMARY SHEETS
(particuiates unly)
Test Number One Two Three Average
General Data
Date 11/14/78 11/14/78 11/14/78
% Isokinetic 106.6 102.2 104.1
Boiler Load (% of design) 66 64 66 65
Sample Point Location Outlet of scrubber
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%) 20.6 16.8 18.4 18.6
Oxygen, dry (%) 7.5 8.4 8.8 8.2
C02, dry (%)
Particulate Emissions
g/NmLdry 0.183 0.092 0.19
g/Nm-dry @ 12% C02 "OTTS9 07092" "09"
gr/dscf 0.08 Q.Q4 0.08
gr/dscf 9 12% CO, 0.074 OT04~ "O82
ng/J fi * T2TT 38T7~ ^O~
lb/10° Btu 0.168 0.090 0.186
Average Opacity ~^~ ... '.
Control Device
Type MC/WS
Operating Parameter1 ^^ ZZZ 6-8
Design Parameter
Design Flow Rate (ACFM) ZZZZHZUZZ
For WS, pressure drop = "H90.For ESP, SCA = ftz/1000 ACFM.
For FF, A/C = ft/min. 2
C-25
-------
PLANT AI12'16'19
Plant AI was tested to determine compliance with North Carolina
participate emissions standards. This plant has a wood-fired spreader
stoker boiler rated at 110,000 pounds per hour of steam. Particulate
emissions are controlled by a mechanical collector followed by a venturi
wet scrubber. The normal operating scrubber pressure drop is 6 to 8
inches of water. Fly ash collected by the mechanical collector passes
through a sand classifier and large particles are reinjected into the
boiler furnace.
Three EPA Method 5 test runs, were made. The average boiler load
during testing was 86 percent of rated capacity. The wood fuel fired
was sawdust and pulverized wood residue. The average particulate emissions
were 0.212 pounds per million Btu. This was below the State allowable
emissions of 0.34 pounds per million Btu. The scrubber pressure drop
during testing was normal.
C-26
-------
PLANT All
19
TEST SUMMARY SHEETS
(Parcicuiates Uniy)
Test Number
One
Two
Three
Average
General Data
6/30/79
90.8
Date 6/30/79
% Isokinetlc 89
Boiler Load (% of desiqn)~91~ _^__
Sample Point Location Outlet of scrubber
6/30/79
93.6
86
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02> dry (X)
Particulate Emissions
g/Nnu-dry 0.233
g/Nm-dry @ 12% CO? "OS9
gr/dscf c 0.102
gr/dscf @ 12% C02 p.157
ng/J fi 122.6
lb/10° Btu Q.285
Average Opacity
0.172
0.270
0.075
0.118
107.1
0.249
Control Device
Type
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
MC/US
T
6-8
For WS, pressure drop
For FF, A/C = ft/min.
"H20. For ESP, SCA = ftVlOOO ACFM.
C-27
-------
PLANT AJ20'21'22
Plant AJ was tested to determine compliance with Florida participate
emission standards and later by the EPA as a part of the standards
development program. The plant has a wood-fired spreader stoker boiler
rated at 110,000 pounds per hour of steam. The wood fuel is fired at
90 percent bark and 10 percent sawdust on the average. Particulate
emissions are controlled by a mechanical collector followed by a variable
throat venturi wet scrubber. Fly ash collected by the mechanical collector
passes through a sand classifier and the larger particles are reinjected
into the boiler furnace. The normal scrubber pressure drop is 8 to
10 inches of water.
One test (AJ5) was conducted in July 1978 to determine compliance
with Florida particulate emissions standards. During this test, the
average boiler load was 91 percent of rated capacity. The average
particulate emissions at the scrubber outlet were 0.057 pounds per
million Btu which was less than the allowable emissions of 0.3 pounds
per million Btu. The scrubber pressure drop was 15.2 inches of water.
Two additional EPA method 5 tests were performed by the EPA during
January 1980. Each test consisted of 3 simultaneous test runs at the
inlet (AJ1 and AJ3) and outlet (AJ2 and AJ4) of the wet scrubber. The
scrubber pressure drop during testing was 8 inches of water for the
first test and 13.5 inches of water for the second test.
During test AJ5 the measured excess air level at the scrubber
outlet was 70 percent, but during the two EPA tests the measured excess
C-28
-------
air level ranged from 150 to 300 percent. Based on this information,
this boiler was being operated at excess air levels much higher than
those required for proper operation during the EPA tests. As discussed
in Chapters 3 and 4, the higher excess air levels would tend to increase
uncontrolled emissions. Also, if the design gas flow through the mechanical
collector was exceeded, the mechanical collector efficiency would be
reduced well below design levels. Both of these factors could cause an
increase in emissions at the scrubber inlet. During the EPA tests, the
scrubber design inlet grain loading of 0.42 gr/dscf was exceeded on four
of the six test runs.
Though apparently the scrubber removal efficiency was not adversely
*•
affected by the higher inlet emissions, the scrubber outlet emissions
would still be higher than would be expected if inlet emissions had been
at the proper levels. Therefore these outlet emissions would not be
representative of the emissions expected from a venturi scrubber with a
pressure drop of 8 to 13.5 inches applied to a well designed and operated
wood-fired boiler.
The inlet emissions for the EPA tests (AJ1 and AJ3), are not shown
in Chapter 4 because the orsat analyses were questionable. This prevents
an accurate conversion of grain loading (gr/dscf) to mass per unit heat
input, (pounds per million Btu). The outlet emissions are shown in
section 4.1.6 but not in section 4.5 due to the operation problems
previously discussed.
C-29
-------
For tests AJ1, AJ2, AJ3, and AJ4, the fuel analyses were as follows:1
Test AJ1/AJ2:
% H20
% Ash .
d
Q
Q
HHVd(Btu/lb)
HHVd(kJ/kg)
Test AJ3/AJ4:
% H20
% Ash .
d
% S.
a
% Nd
HHV.(Btu/lb)
a
HHVd(kJ/kg)
Run 1
48.51
0.92
0.04
0.15
9,280
21,600
Run 1
47.57
1.17
0.02
0.11
9,159
21,300
Run 2
48.04
1.23
0.03
0.10
9,490
22,070
Run 2
51.95
2.17
0.01
0.08
9,218
21,440
Run 3
48.54
4.47
0.02
0.14
9,040
21,020
Run 3
49.90
2.42
0.01
0.13
9,907
23,040
Subscript 'd' designates dry basis.
C-30
-------
PLANT AJ1
20
TEST SUMMARY SHEETS
(Pamcuiates Uniy)
Test Number
One
Two
Three
Average
General Data
Date 1/17/an 1/21/so
% Isokinetic so. l 87.q
Boiler Load (% of design)_22__ 90
Sample Point Location Inlet of scrubber
1/22/80
101.5
92
91
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
21.3
Particulate Emissions
g/Nm,-dry
12% C0
gr/dscf
gr/dscf @ 12% CO,
lb/10 Btu
Average Opacity
1.098
1.464
0.480
0.640
860.0
1.384
1.940
0.605
0.848
1.170
2.72
Control Device
Type .
Operating Parameter11
Design Parameter
Design Flow Rate (ACFM)
MC
For WS, pressure drop
For FF, A/C = ft/min.
"H90. For ESP, SCA = ft2/1000 ACFM
C-31
-------
20
PLANT AJ2
TEST SUMMARY SHEETS
(rdrticuiates unly)
Design Flow Rate (ACFM) 110.000
Test Number One Two Three Average
General Data
Date 1/17/80 1/21/80
% Isokinetic 99.6 95.2
Boiler Load (% of design) 92 .90 92 91
Sample Point Location Outlet of scrubber
Stack Gas Data
Flow (Nm3/s-dry) 28.4
Flow (dscfm) 60.200
Temperature (°C) 61.7
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/NmLdry 0.057 0.60 0.053 0.056
g/Nm -dry (P 12% CO, 0.085 0.092 0.098 OT59l"
gr/dscf 0.025 0.026 0.023 0.025
gr/dscf @ 12% CO, 0.037 0.040 0.043 0.040
ng/J , L 3O~ "4TT 1O" "4TT"
lb/10° Btu 0.089 0.110 0.113 07I54~
Average Opacity
Control Device
Type x MC/WS
Operating Parameter
Design Parameter
WS, pressure drop = "H^O. For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/min. c
C-32
-------
PLANT AJ3
20
TEST SUMMARY SHEETS
(Varticulates Only)
Test Number
One
Two
Three
Average
General Data
Date 1/22/80 U23/80
% Isokinetic 101.4 104.9
Boiler Load (% of design) 93 95
Sample Point Location Inlet of scrubber
U22/SO
104. Q
98
95
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (*)
15.3
Particulate Emissions
g/NmLdry 2.391
g/NmJ-dry @ 12% CO? 3.153
gr/dscf 6 1.045
gr/dscf @ 12« C07 1.378
ng/J r 2.352
lb/10° Btu 5'.47
Average Opacity
0.968
1.306
0.423
0.571
817
1.533
2.Q46
Q.67Q
Q.fi94
3.78
1.631
2. 16Q
0.713
Q.Q4fi
3.72
Control Device
Type .
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
MC
For WS, pressure drop
For FF, A/C = ft/min.
"H20.
For ESP, SCA = fr/1000 ACFM.
C-33
-------
PLANT AJ420
TEST SUMMARY SHEETS
v'Haruculates imiy)
Test Number One Two Three Average
General Data
Date 1/22/80 1/23/80 1/23/80
% Isokinetic 100.1 97.3 99.3
Boiler Load (% of design) 93 94.5 98.2 95
Sample Point Location Outlet of scrubber
Stack Gas Data
Flow (Nm3/s-dry) 28.4 27.0 25.6
Flow (dscfm) 60,300 57.200 54,200
Temperature (°C) 61.7 62.2 63.3
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/NmLdry 0.092 0.057 0.053 0.067
g/NmJ-dry 9 12% C0? 07131" ~™ ~~ "
gr/dscf 0.040 •
gr/dscf 9 12% C09 0.059 0.050 0.045
ng/J c fc 82.6 48.6 49.0
lb/10& Btu -0.183- 0.113 0.114
Average Opacity
Control Device
Type , MC/US
Operating Parameter 13.5
Design Parameter
Design Flow Rate (ACFM) 110.000
*For WS, pressure drop - "H90.For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/nrin. c
C-34
-------
PLANT AJ5
22
TEST SUMMARY SHEETS
(Particuiates Uniy)
Test Number
One
Two
Three
Average
General Data
Date
% Isokinetic
7/10/78 7/10/78
93.4 101.2
Boiler Load (% of design)_gj 91
Sample Point Location Outlet of scrubber
7/10/78
104.4
91
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C09, dry («)
Particulate Emissions
3
g/Nnu-dry
g/Nm -dry @ 12* CO-
gr/dscf £
gr/dscf 9 12* C09
ng/J 6 i
lb/10b Btu
Average Opacity
0.057
OTP5T
0.025
O2T
OTTJ5T
0.055
0.055
"O21
17074
TO"
0.057
0.055
U.Ubb
"O2T
0.024
24.6
0.057
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
MC/WS
110.000
For WS, pressure drop
For FF, A/C = ft/min.
"H20.
For ESP, SCA = ft2/1000 ACFM
C-35
-------
PLANT AK23'24'25
Plant AK was tested by the EPA as part of the standards development
program. Plant AK has a wood-fired traveling grate spreader stoker
rated at 135,000 pounds per hour of steam. The wood fuel consists of 90
percent bark and approximately 10 percent sawdust on the average. Fuel
oil is used as a supplementary fuel. Particulate emissions are controlled
with a multicyclone followed by a venturi wet scrubber. The normal
operating scrubber pressure drop is 20 inches of water. Fly ash collected
by the multicyclone passes through a sand classifier and the large
particles are reinjected into the boiler furnace.
One test was conducted by the EPA in January, 1980 at both inlet
(AK1) and outlet (AK2) of the wet scrubber. During all three test runs
the design gas flow rate for the wet scrubber was exceeded. This is
believed to be due to the high excess air levels (200, 190, and 320
percent for runs 1,2, and 3 respectively) measured during the test.
During the first two runs the scrubber was still able to effectively
control particulate emissions and the scrubber collection efficiency on
both runs exceeded 98 percent. During the last run the scrubber particulate
inlet loading, excess air, and gas flow rates were higher than the first
two runs. Under these conditions the scrubber could no longer effectively
control particulate emissions and the scrubber efficiency decreased to
93 percent. Due to the increased inlet loading and reduced scrubber
efficiency the emissions at the scrubber outlet were six times higher
than outlet emissions for runs 1 and 2.
C-36
-------
The increased scrubber inlet participate loading during test run 3
was most likely due to the measured increase in excess air levels.
Though excess air levels may vary due to changing fuel properties, there
is no operational requirement for changes in excess air levels of the
magnitude shown in test run 3. Also, there is no oxygen analyzer on the
boiler. Therefore the boiler operator has no indication of the amount
of excess air present in the furnace.
Due to these previously discussed factors, the results of test run
3 are not considered representative of the performance of a venturi wet
scrubber operating at a high pressure drop. Therefore this test run is
not presented in Chapter 4 and was not used in NSPS development.
Based on test runs 1 and 2 the average emission rate for the January
1980 test was 0.0736 pounds per million Btu. The average boiler load
during testing was 94 percent. The scrubber pressure drop monitor was
inoperative during testing. However, plant personnel indicated the
venturi throat was set for a pressure drop of approximately 20 inches of
water.
This plant was later retested by the EPA (AK3) and the particulate
emissions at the scrubber outlet averaged 0.0627 pounds per million Btu.
The average boiler load was 96 percent of rated capacity during this
test. The scrubber pressure drop averaged 26 inches of water. The flue
gas flow rates during this test were lower than the previous test, as
shown by the lower scrubber outlet flow rates and lower oxygen contents
of the flue gas.
C-37
-------
For tests AK1, AK2, and AK3, the fuel analyses were as follows:
Test AK1/AK2:
*H20
% Ash .
d
d
d
HHVd(Btu/lb)
HHVd(kJ/kg)
Test AK3
jo n A w
% Ashd
Q
Q
HHVd(Btu/lb)
HHVd(kJ/kg)
Run 1
44.9
1.70
0.04
0.19
8,980
20,880
Run 1
38.3
6.49
0.110
0.1
8,420
19,580
Run 2
45.9
1.32
0.04
0.17
9,290
21,610
Run 2
54.2
2.69
0.276
0.1
9,590
22,310
Run 3
43.7
2.17
0.04
0.14
8,980
20,880
Run 3
42.4
3.55
0.131
0.1
8,520
19,820
Subscript 'd' designates dry basis.
C-38
-------
PLANT AK124
TEST SUMMARY SHEETS
(rarticuiates Uniy)
Test Number One Two Three Average
General Data
Date 1/29/80 1/30/80 1/31/80
% Isokinetic 107.0 101.0 102.5
Boiler Load (X of design) 81 106 99 95
Sample Point Location Inlet of scrubber
Stack Gas Data
Flow (Hro3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (?)
Oxygen, dry (%)
C02, dry (*)
Particulate Emissions
g/NmLdry
g/NnT-dry @ 12* CO-
gr/dscf *
gr/dscf § 12X CO,
ng/J R £
lb/10b Btu
Average Opacity
Control Device
Type i MC
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
_
For MS, pressure drop = "H,0. For ESP, SCA = ft /1000 ACFM.
For FF, A/C = ft/mi n. £
* Thermocouple was broken on this run, stack temperature could
not he determined accurately. -_,„
-------
PLANT AK2
24
TEST SUMMARY SHEETS
(^articulates only)
Test Number
General Data
Date
One
1/22/BO
% Isokinetic 93.5
Boiler Load (% of design) 81
Sample Point Location
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Tarperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nm,-dry
g/Nm -dry @ 12% C02
gr/dscf
gr/dscf @ 12% C02
ng/J g
lb/10° Btu
Average Opacity
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
Two
i/30/ao
99.6
106
*Three
11/31/80
99.3
99,
Average
94
Outlet of scrubber
33.1
757250
55.6
132
-m
5.6
0.034
O76
OI5~
0.033
28.1
0.0653
MC/WS
136
33.1
70,250
55.6
132
-££
5.8
0.046
07695"
O20"
0.042
35.2
0.0819
.000
33.1
"5576"
132
12.9
7.0
0.229
0.391
0.100
0.17L
230
0,5357
33.1
70.250
55.6
132
iH-
5.7
0.040
0.086
0.045
0.082
31.7
0.0736
20
For MS, pressure drop
For FF, A/C = ft/min.
"H20. For ESP, SCA = ftZ/1000 ACFM.
*Run 3 is not included in averages.
C-40
-------
PLANT AK3
25
TEST SUMMARY SHEETS
(Particuiates Only;
Test Number
General Data
Date
One
6/25/80
% Isokinetic 103.1
Boiler Load (% of design) 93
Sample Point Location
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
c.
Particulate Emissions
3
g/Nm,-dry
g/NnT-dry & 12% C02
gr/dscf
gr/dscf @ 12? CO,
ng/J f
lb/106 Btu
Average Opacity
Control Device
Type .
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
Two
6/26/80
100.5
106^
Three
6/26/80
105.9
_i02_
Average
100
Outlet of scrubber
28.9
61.340
60.2
140.3
19.2
11.9
8.3
0.0739
0. 1068
0.0323
0.0462
35.43
0.0824
MC/WS
25
136,000
32.3
"5979"
139.9
TO~
TO"
0.0533
670764
0.0233
0.0334
MpHMBMI^^*
zTTOT
0.0512
25.5
31.9
67,610
63T3~
146.8
7O~
T0~
"0~
0.0476
OlfTTZ
070208
0.0311
23. 48
0705l6
27.5
31.0
65779U
6TTJ~
142.3
19.8
T0~
"872^
0.0583
0. 0848
OZ54
O371
26.98
O5?7
26
For WS, pressure drop = "H,0. For ESP, SCA = ft /1000 ACFM.
For FF, A/C = ft/min. L
C-41
-------
PLANT AL26'27'28
The boiler at Plant AL was tested to determine the parti oil ate
emission rate. The boiler is a wood-fired fluidized bed rated at
15,000 pounds of steam per hour fired with bark, sawdust, and shavings.
Particulate emissions are controlled by a mechanical collector. Fly ash
collected by the mechanical collector is not reinjected.
One EPA Method 5 test consisting of two test runs was performed.
The average particulate emission rate was 0.476 pounds per million Btu
at an average operating rate of 92 percent of the rated capacity. No
steam generation rates were included in the report, so the percent
boiler load was based on the mass emission rate and the F-factor.
C-42
-------
PLANT All26
TEST SUMMARY SHEETS
(farlieu laces Oniy;
Test Number One Two Three Average
General Data
Date 8/31/77 9/11/77
% Isokinetic 106.9 107.1
Boiler Load (% of design) ^92 /^92 ^92
Sample Point Location Outlet of MC
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%}
C09, dry (%) 8.4
Particulate Emissions
g/Nm«-dry
g/Nm -dry @ 12% CO,
gr/dscf *
gr/dscf @ 12% CO,
ng/J c *
lb/10b Btu
Average Opacity
Control Device
Type l MC_
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
For WS, pressure drop = "H90. For ESP, SCA = ft /1000 ACFM.
For FF, A/C = ft/min. i
C-43
-------
PLANT AM29'30'31
The boiler at plant AM was tested to determine if it is in compliance
with the State of North Carolina emission standards. The waterwall
wood-coal combination fuel boiler has a rated steam capacity of 60,000 pounds
of steam per hour. Particulates are controlled with one 128 tube
mechanical collector. Fly ash collected by the mechanical collector is
not reinjected. The boiler's wood fuel consists of kiln dried wood
scraps, shavings, and sanderdust. The estimated moisture content of the
wood fuel is 6 to 7 percent. The wood scraps are hogged to approximately
1/2 square inch.
One test consisting of three test runs was performed. The average
boiler load during testing was 15 percent of rated capacity. The
boiler was fired with 100 percent wood during the test. The average
particulate emission rate was 0.53 pounds per million Btu.
C-44
-------
PLANT AM]29
TEST SUMMARY SHEETS
(^arcicuiates Only)
Test Number
Genera] Data
One
Date R/17/7Q
% Isokinetic g» 7
Boiler Load (% of design)
Sample Point Location
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nm.,-dry
g/Nm -dry @ 12% CO,
gr/dscf i
gr/dscf 9 12% C0«
ng/J c
lb/106 Btu
Outlpf
6.6
14.012
153
308
3.8
18.0
2.7
0.130
0.577
0.057
0.252
232.2
0.54
Two
ft/1 7/7Q
IDfi 5
nf Mr
6.6
13.966
159
318
4.0
17.6
3.1
0.135
07529"
0.059
0723T
215.0
0.50
Three
fi/17/79
in? Q
6.4
13.489
154_
309
3.2
18.3
2.6
0.114
0.529
0.050
07Z3T
232.2
0.54
Average
6.5
13.822
155
312
3.7
18.0
2.8
0.126
0.545
0.055
TT218"
"22675
0.53
Average Opacity
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
MC
L2
Tor WS, pressure drop = "H90. For ESP, SCA = ft^/lOOO ACFM.
For FF, A/C = ft/min. '
C-45
-------
PLANT AN32
The boiler at Plant AN was tested to determine the particulate
emission rate. The boiler is a wood-fired fluidized bed rated at 36,000 pounds
per hour of steam. Particulate emissions are controlled by a mechanical
collector. Fly ash collected by the mechanical collector is not reinjected.
Approximately 75 percent of the hogged fuel is a mixture of red fir
bark, ponderosa pine bark, and white fir bark. The remaining 25 percent
of the fuel consists of shavings and sawdust. The average fuel moisture
content is 45 percent.
Three EPA Method 5 test runs were performed. The average boiler
load was 78 percent of rated capacity during testing. The average
particulate emission rate was 0.329 pounds per million Btu.
C-46
-------
PLANT AN I32
TEST SUMMARY SHEETS
(rarticulates unly)
Test Number
General Data
Date
% Isokinetic
One
3/27/79
100.9
Boiler Load (% of design) 73.3
Sample Point Location
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)*
C02, dry (%)
Particulate Emissions
3
g/Nm--dry
g/Nm -dry @ 12% C02
gr/dscf
gr/dscf 0 12% C02
ng/J f.
lb/10° Btu
Average Opacity
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
Outlet of
5.9
12.630
254
489
"TO"
~IO"
"97T
0.297
0.368
O3~
0.161
147.9
O4T
TflT
MC
Two
3/27/79
101.5
83.3
MC
6.2
13.090
257
495
"TO"
"UTT
HZ
0.265
0.332
0.116
0.145
133. 3
OTO~
T20~
Three
3/27/79
99.9
78.6
6.3
13.330
~^to
500"
TO"
TO"
0.281
"OBI
"07121
"QTTsB
142. 8
0.332
Tar
Average
78.4
13^20"
~T57
~~?9T
TOT
TOTT
0.281
"OB?
0.123
"O5?
141. 3
0 329
T?o~
For WS, pressure drop = "H«0. For ESP, SCA
For FF, A/C - ft/rain.
= ft /1000 ACFM.
*02 Estimated
G-47
-------
PLANT AO33'34
The boiler at Plant AO was tested to determine the particulate
emission rate. The boiler is a wood-fired fuel cell rated at 25,000 pounds
per hour of steam. Particulate emissions are controlled by a mechanical
collector. Fly ash collected by the mechanical collector is not reinjected.
Bark and hog fuel are used to fire the boiler.
Three EPA Method 5 test runs were made. The average boiler load
was 80 percent of rated capacity during testing. The average particulate
emission rate was 0.125 pounds per million Btu. During testing, a
combination of bark and hog fuel were used to fire the boiler, with the
majority of the fuel being bark.
C-48
-------
PLANT A0134
TEST SUMMARY SHEETS
(r'arcicuiaies Oniy)
Test Number One Two Three Average
General Data
Date 7/25/79 7/25/79 7/25/79
% Isokinetic 103.7 103.2 106.0
Boiler Load (% of design) 79.6 75.6 86.4 80.5
Sample Point Location Outlet of MC
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nm~-dry 0.101 0.116 0.096 0.104
g/Nm -dry @ 12% CO- 0.124 0.135 0.110 0.123
gr/dscf ' 0.044 0.0506 0.0421 0.0456
gr/dscf @ 12% CO? 0.054 0.059 0.048 0.0537
ng/J fi 52.85 60.24 48.33 52.81
lb/10° Btu OTT2T 0.140 0.112 0.125
Average Opacity 3.5 4.5 5 4.3
Control Device
Type , MC_
Operating Parameter
Design Parameter
Design Flow Rate (ACFM) ~~~~~~
For WS, pressure drop = "H,0. For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/min. * _
C-49
-------
PLANT AP35
The boiler at Plant AP was tested to determine the participate
emission rate. The boiler is a wood-fired fuel cell rated at 20,000 pounds
per hour of steam. Particulate emissions are controlled by a mechanical
collector. Fly ash collected by the mechanical collector is not reinjected.
Two EPA Method 5 test runs were made. The average boiler load was
35 percent of rated capacity during testing. The average particulate
emission rate was 0.142 pounds per million Btu. The moisture content of
the wood fuel was 47 percent. The wood fuel was 95 percent sawdust and
5 percent bark.
C-50
-------
PLANT API35
TEST SUMMARY SHEETS
(rarticuiates Uniy)
Test Number One Two Three Average
General Data
Date 7/27/79
% Isokinetlc 102.7
Boiler Load (% of design) 40 30 35
Sample Point Location Outlet of MC
Stack Gas Data
Flow (Nm /s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/NmLdry 0.108 0.124 0.116
g/Nm -dry @ 12% CO- 0.142 0.144 0.143
gr/dscf £ 0.047 0.054 0.051
gr/dscf @ 12% C0? 0.062 0.063 0.062
ng/J K * 58.5 63.2 60.9
lb/10° Btu 0.136 0.147
Average Opacity
Control Device
Type . MC_
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
For WS, pressure drop = "H90. For ESP, SCA = ftZ/1000 ACFM.
For FF, A/C = ft/min. i
C-51
-------
PLANT AS36'37
Plant AS was tested to determine compliance with North Carolina
participate emission standards. This plant has a scotch marine type
packaged boiler rated at 5,200 pounds of steam per hour. The boiler
fires finely ground wood waste 100 percent in suspension. Particulate
emissions are controlled with a mechanical collector. All the fly ash
collected by the mechanical collector is reinjected into the boiler
furnace.
Three EPA Method 5 test runs were made. The boiler was operated at
60 percent of rated capacity during testing. The average particulate
emission rate was 0.759 pounds per million Btu.
C-52
-------
PLANT AS1
37
TEST SUMMARY SHEETS
(rarticuiates only)
Test Number
One
Two
Three
Average
General Data
Date 8/11/76
% Isokinetic 97.2
Boiler Load (% of design) 60
Sample Point Location Outlet of MC
60
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
Particulate Emissions
3
g/Nnu-dry
g/Mm -dry @ 12% C09
gr/dscf *
gr/dscf
-------
PLANT
The boiler at Plant All was tested to determine if it is in compliance
with the State of North Carolina participate emission standards. The
firetube boiler is fired with wood waste. The boiler is rated at 7,400 pounds
of steam per hour. Particulate emissions are controlled with a mechanical
collector. Fly ash collected by the mechanical collector is not reinjected.
Three EPA Method 5 test runs were performed. The boiler was operated
at an average of 124 percent of rated capacity during testing. The
average particulate emission rate was 0.539 pounds per million Btu which
is less than the state allowable emission level of 0.56 pounds per
mil lion Btu.
C-54
-------
PLANT AU139
TEST SUMMARY SHEETS
((-articulates Unly)
Test Number
General Data
Date
% Isokinetic
One
3/26/80
106
Boiler Load (% of design) 138
Sample Point Location
Stack Gas Data
2
Flow (Nm /s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
3
g/Nm.-dry
g/Nm -dry @ 12% C0?
gr/dscf
gr/dscf @ 12% C02
ng/o K
lb/10° Btu
Average Opacity
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
Outlet of
4.1
87605"
254
489
5.9
~I3T§~
~67T
0.293
0.524
0.128
0.229
2267T
O26"
MC
Two
3/26/80
104
124
MC
4.1
8.693
256
493
6 8
14TT
_§,!_
0.270
0.51L
0.118
0.225
2357T
0.548
Three
3/26/80
105
111
"pfe
243
469
~B7Z
"IBT?
5.1
0.231
0.542
0.101
0.237
"23371
"07542
Average
124
57760
"TBT
AQA
D • U
14.6
o • 0
0.265
0.5Z7
0.116
0.230
O39
lFor WS, pressure drop
For FF, A/C = ft/min.
= "H90. For ESP, SCA = frVlOOO ACFM
C-55
-------
PLANT AX40'41
The boiler at Plant AX was tested to determine 1f it is in compliance
with the State of North Carolina emission standards. The firetube
boiler is rated at 2,600 pounds of steam per hour. Particulate emissions
are controlled with a mechanical collector. Fly ash collected by the
mechanical collector is not reinjected. The boiler is hand fired with
wood dust and wood blocks. The boiler also has an auxiliary No.2 fuel
oil burner.
Three EPA Method 5 test runs were conducted. The average boiler
load was 86 percent of rated capacity during testing. The average
particulate emission rate was 0.205 pounds per million Btu which is less
than the State allowable emission level of 0.70 pounds per million Btu.
Fuel oil provided approximately 19 percent of the heat input during
testing.
C-56
-------
PLANT AX1
41
TEST SUMMARY SHEETS
(^articulates Only)
Test Number
One
Two
Three
Average
General Data
Date 6/7/77 6/8/77
% Isokinetlc im .a 101.3
Boiler Load (% of design) a? 87
Sample Point Location Outlet of MC
6/8/77
101.3
84
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%}
Oxygen, dry (%)
C09, dry (%}
Particulate Emissions
g/Nm?-dry Q.Q281 0.0686
g/Nm -dry @ 12% C02 0.1357 0.3054
gr/dscf 0.0123 0.030
gr/dscf @ 12% C0« 0.0593 0.1335
ng/0 6 47.3 112.4
lb/10° Btu 0.1099 0.2614
Average Opacity
0.0613
672614
0.0268
0.1147
104.8
0.2438
0.0527
TT73T5
0.0230
0.1025
""887Z
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
MP.
For WS, pressure drop
For FF, A/C = ft/m1n.
"H20.
For ESP, SCA = ft/WOO ACFM
C-57
-------
PLANT AY42'43
The boiler at plant AY was tested to determine if it is in compliance
with the State of North Carolina emission standards. The firetube
boiler is rated at 6,040 pounds of steam per hour. Particulate emissions
are controlled with a mechanical collector. Fly ash collected by the
mechanical collector is not reinjected. The boiler is fueled with wood
dust which is dropped into the boiler by means of drop chute. The
boiler is also fueled with wood blocks which are hand fed into the
boiler-
Three EPA Method 5 test runs were made. The average boiler load
was 53 percent of rated capacity during testing. The average particulate
emission rate was 0.499 pounds per million Btu which 1s less than the
State allowable emission level of 0.64 pounds per million Btu.
C-58
-------
PLANT AY1
43
TEST SUMMARY SHEETS
(^articulates Unly)
Test Number
One
Two
Three
Average
General Data
Date 10/5/77
% Isokinetic 104.0
Boiler Load (% of design)
Sample Point Location Outlet of MC
53
Stack Gas Data
Flow (Nm /s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
3
g/Nm--dry
g/Nm -dry @ 12% C02
gr/dscf
gr/dscf @ 12% CO,
lb/10 Btu
Average Opacity
0.082
0.494
O3T
ie"
0.096
OeT
OT154T
0.202
2TBTT
0.076
OT475"
OT20T
2257T
OT531T
0.085
"O77
0.037
"005
214.6
0.499
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
MC
For WS, pressure drop = "H90. For ESP, SCA
For FF, A/C = ft/min. i
ft/1000 ACFM.
C-59
-------
PLANT BA44'45
Plant BA was tested to determine the efficiency of its electrostatic
precipitator (ESP). Plant BA has a wood-fired spreader stoker boiler
rated at 110,000 pounds per hour of steam. Bark is the principal fuel
supplemented with sanderdust as available. Normal operating load is
70,000 to 75,000 pounds per hour. Particulate emissions are controlled
with a mechanical collector followed by an ESP. The ESP has a design
SCA of 177 ft2/1000 ACFM. All of the flyash collected by the mechanical
collector is reinjected into the boiler furnace.
Three EPA Method 5 test runs were performed. The average boiler
load was 66 percent of capacity during testing. The average particulate
emissions were 0.0724 pounds per million Btu. The average SCA during
the test was 230 ft2/1000 ACFM.
C-60
-------
45
PLANT BA1
TEST SUMMARY SHEETS
(Particuiates only)
Test Number One Two Three Average
General Data
Date 12/18-19/79 12/18-19/79 12/18-19/79
% Isokinetic 97 R QR fi Q3.fi
Boiler Load (% of design) RA RR 67 66
Sample Point Location Outlet of ESP
Stack Gas Data
Flow (Nm3/s-dry) 19.2 19.4 19.3 .
Flow (dscfm) 4fl^£aa /n ,iin 41 ,050 411930
Temperature (°C) is? IR? IRA 1R3
Temperature (°F) ^n 359 364 361
Moisture (%) i? g is.? n.g 13.1
Oxygen, dry (%) inn Q R R a. Q.4
C02, dry (%) Q 3 Q n 9.4 9.2
Particulate Emissions
g/Nm3-dry n.039 Q.Q62 0.101 0.067
g/Nm-dry @ 1256 C02 n.nsn n.Q82 0.128 0.087
gr/dscf n m? OJ322_ Q.Q44 0.029
gr/dscf @ 12% C02 n.022 Q.Q36 0.056 0.038
ng/J 6 19.7 30.5 43.0 31.1
lb/10 Btu n n459 0.0710 o.ioo 0.0724
Average Opacity
Control Device
Type j MC/ESP
Operating Parameter1 235 ??& 230 230
Design Parameter 177
Design Flow Rate (ACFM) Q3,A9n
XFor WS, pressure drop = "H90.For ESP, SCA = ftZ/1000 ACFM.
For FF, A/C = ft/min. *
C-61
-------
PLANT BB46'47
Plant BB was tested to determine compliance with State emission
standards. Plant BB has a wood-fired spreader stoker boiler rated at
450,000 pounds per hour of steam. Particulate emissions are controlled
by a Zurn multiclone followed by an ESP. The ESP has a design collection
area of 95,806 ft2 and is sized for a gas flow up to 322,000 ACFM. The
fly ash collected by the multiclone passes through a sand classifier and
the large fraction is reinjected into the boiler furnace.
Three EPA Method 5 test runs were performed. The average boiler
load during testing was 69 percent of rated capacity, and the average
2
SCA for the ESP was 453 ft /100 ACFM based on an operating collection
2
area of 87,696 ft . Natural gas provided an average of 1.8 percent of
the heat input during testing. The average particulate emission rate
was 0.0571 pounds per million Btu.
No fuel sampling was done during testing, however, a typical analysis
of the wood fuel is as follows:
% H20 - 42.5
% Ashd - 4.8
HHVd(Btu/lb) - 8250
HHVd(kJ/kg) - 19,190
Subscript 'd' denotes dry basis.
C-62
-------
PLANT BB
47
TEST SUMMARY SHEETS
(Particulates Only)
Test Number
One
Two
Three
Average
General Data
Date 6/10/80 6/11/80
% Isokinetlc "ToT" T5T"
Boiler Load (% of design) 74 68
Sample Point Location Outlet of ESP
6/12/80
104
-55"
69
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C
Temperature (°F
Moisture (*)
Oxygen, dry (%)
C09, dry (%)
JLL
111.307
152
323
48.4
TOO39
13.2
48.7
Particulate Emissions
g/Nm?-dry 0.0519 0.0817
g/Nm -dry @ 1235 C09 0.0403 0.0744
gr/dscf * 0.0227 0.0357
gr/dscf @ 1235 C09 0.0176 O3T5
ng/J fi i TTb" 3T7T
lb/10° Btu 0.0396 0.0726
Average Opacity
0.0668
OBT?
Mr./ESP
Control Device
Type .
Operating Parameter1 475
Design Parameter 298
Design Flow Rate (ACFM) 322.000
424
453
For WS, pressure drop « "H90. For ESP, SCA
For FF, A/C » ft/mln. *
fr/1000 ACFM.
C-63
-------
48,49
PLANT BC
Plant BC was tested by the EPA as part of the standards development
program. Plant BC has three dutch oven type wood-fired boilers. Each
boiler was originally rated at 55,000 pounds per hour of steam. However,
due to their age (over 40 years), their maximum steam capacity 1s now
approximately 50,000 pounds per hour. The boilers are fired with wood
waste and bark from Canadian limber mills, local sawmills, and the
plant's debarking operations. Approximately 80 percent of the fuel
comes from logs stored in salt water.
Each boiler has an individual mechanical collector. After exiting
the mechanical collector, the flue gases are combined into a single duct
and enter a baghouse. Fly ash collected by the mechanical collectors is
not reinjected.
A particulate emission test was conducted simultaneously at the inlet
(BC1) and outlet (BC2) of the baghouse. The boilers were operated at an
average of 91 percent of capacity during testing. The average A/C for
the fabric filter during testing was 2.98 ft/min. The average particulate
emission rate was 0.020 pounds per million Btu at the fabric filter
outlet.
C-64
-------
The average analysis of fuel samples collected during testing 1s as
fol1ows •
% H20 - 56.7
% Ash. - 3.4
d
* Sd - 0.1
% Nd - 0.2
% Chlorides. - 0.4
d
HHVd (Btu/lb) - 8,619
HHVd (kJ/kg) - 20,050
Subscript 'd' denotes dry basis.
C-65
-------
PLANT BC149
TEST SUMMARY SHEETS
(Particulates Only)
Test Number
General Data
Date
% Isokinetic
One
11/19/80
99.6
Boiler Load (% of design) 89
Sample Point Location
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nm,-dry
g/Nm -dry @ 12% CO,
gr/dscf
gr/dscf @ 12% CO,
ng/J R
lb/ 10° Btu
Average Opacity
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
Inlet to
35.8
75.917
207
405
UTT
-U.
1.05
1.65
0.458
0.723
650
1.51
MC
180.000
Two
11/20/80
TOO
86
FabrfcTilter
36.4
777217
201
393
17.0
11.7
ZE
0.993
1T4T"
0.434
O20"
576
1.34
Three
11/22/80
W77
99
33.8
7T761C
209
"~109
"TO
9.4
no
1.36
T75T"
"OP
"O5D
521
"OT
— — —
Average
91
35.4
74,915
"20BT7
~4TJT"
"TO"
11.7
nn
1.13
T757"
"O9T
0.668
BT?
"OT"
__
For WS, pressure drop
For FF, A/C = ft/m1n.
"H20.
For ESP, SCA » ftZ/1000 ACFM.
C-66
-------
PLANT
TEST SUMMARY SHEETS
(Particulatss Only)
Test Number One Two Three Average
General Data
Date 11/19/80 11/2Q/8Q 11/22/80
% Isokinetlc _lfl{L£ 99.7 108.2
Boiler Load (% of design) 89 JJ6 99 91
Sample Point Location Outlet of Fabric Filter
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C
Temperature (°F
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
Tor WS, pressure drop = %0. For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/min. *
C-67
3
g/Nnu-dry
g/Nm -dry 9 12% C0«
gr/dscf
gr/dscf @ 12% C0«
ng/J K
lb/10° Btu
Average Opacity
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
0.0267
0.0297
0.0117
PIT
12.1
O25I
9.2.
MC/FF
2.97
3.64
180.000
0.0128
0.0197
0.0056
0.0086
7.86
"OT83
2.2
2.98
0.0119
0.0149
0.0052
0.0065
6.09
0.0142
Q.I
3.00
0.0171
0.0214
0.0075
0.0094
8.68
0.0202
4-3
2.98
-------
PLANT BD50'51
Plant BD was tested by the EPA as part of the standards development
program. Plant BD has a wood-fired spreader stoker boiler rated at
25,000 pounds steam per hour. The wood fuel consists of hogged bark.
The flue gas from the boiler passes through a knockout box, a
cyclone, a second knockout box, and finally a fabric filter with a
design air-to-cloth ratio of 4.1 ft/min. The knockout boxes are used to
collect large carbon particles which can cause fires in the baghouse.
Fly ash collected by the cyclone is not reinjected.
Particulate testing was performed prior to the second knockout box
(BD1) and after the fabric filter (BD2). The boiler was estimated to
operate at 75 percent of rated capacity during emission testing. There
is no steam flow meter on the boiler, so operating rate was estimated by
using heat input calculated using the F-factor and the heat input
required to produce steam at rated capacity. The average air-to-cloth
ratio for the fabric filter during testing was 3.66 feet per minute.
The average emission rate was 0.016 pounds per million Btu at the fabric
filter outlet.
C-68
-------
Fuel samples collected during testing showed the following average
1
composition:
% H20 - 46.6
% Ashd - 5.1
% S . - 0.06
d
% Nd - 0.6
HHVd (Btu/lb) - 8325
HHVd (kJ/kg) - 19,364
Subscript 'd1 denotes dry basis.
C-69
-------
PLANT BD151
TEST SUMMARY SHEETS
(Partlculates Only)
Test Number
General Data
Date
% Isok1net1c
One
12/16/80
99.2
Two
12/17/80
104.3
Boiler Load (% of design) 75 73
Sample Point Location
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%}
Oxygen, dry (%)
C02, dry (%)
Partlculate Emissions
3
g/Nm,-dry
g/Nm-dry @ 12% CO,
gr/dscf *
gr/dscf @ 12% C02
ng/J c
1b/10° Btu
Inlet to
4.04
8563
191
~^75~
TO"
TO~
-9TT
0.796
1.03
0.348
0.449
395
0.919
Fabric Filter
3.82
8091
199
~39lT
16.8
TO-2
-Q-2
0.856
1.15
0.374
0.504
45g
1.06
Three
12/18/80
101.6
77
3.83
8121
200
392
18.9
10.0
"TTT
0.899
1-19
0.393
0.518
446
1.04
Average
75
3.90
8259
197
386
16.7
T7T~
Q.85Q
1.12
0.372
0.490
431
1.01
Average Opacity
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
MC
24.600
"H?0.
For ESP, SCA = ftZ/1000 ACFM.
WS, pressure drop =
For FF, A/C = ft/min.
^These values are for the gas analysis of the fabric filter outlet for run 2.
The values obtained during testing were considered to be inaccurate.
C-70
-------
PLANT BD2
51
TEST SUMMARY SHEETS
(Partlculates Only)
Test Number One Two Three
Average
General Data
Date 12/16/80
% Isok1net1c DisTf"
Boiler Load (% of design)^ _
Sample Point Location nut. lot,
73
FahHr mtt»r
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°CJ
Temperature (°F)
Moisture (%)
Oxygen, dry (%}
C02, dry (%}
Partlculate Emissions
g/Nnu-dry
g/Nm -dry @ 12X C02
gr/dscf
gr/dscf 0 12X C0«
ng/J ,.
lb/106 Btu
Average Opacity
Control Device
Type
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
4.26
9026
121
250
13.2
10.0
JL3_
0.0121
"OT56
O553
"O558
"OF
TTTOTo
MC/FF
3.53
24,600
4.36
9232
124
255
16.2
10.7
9.9
0.0144
0.0194
0.0063
0.0085
7.64
OITs
3.81
3.97
8414
126
259
19.6
9 . Q
11-1
0.0158
0.0172
0.0069
0.0075
7, 18
OJ0167
3.64
4.?n
RR91
124
255
16.3
9.9
9-8
0.0142
0.0174
0.0062
"O076
6 95
"070162
3.66
For WS, pressure drop » "H,0. For ESP, SCA
For FF, A/C - ft/m1n.
ftVlOOO ACFM.
C-71
-------
PLANT BE52'53
Plant BE was tested by the EPA as part of the standards development
program. Plant BE has a wood-fired spreader stoker boiler rated at
400,000 pounds per hour steam when firing hog fuel with a 55 percent
moisture content. Particulate emissions are controlled by two multiclones
and a electrostatic granular filter (EGB) with three modules.
The flyash collected by the first multiclone is slurried and passed
over screens. The larger particles are then mixed with the hog fuel.
The fuel samples were taken after the flyash had been mixed with the hog
fuel.
The flue gas from the boiler passes through the two multiclones in
series and is then split into three ducts. Each duct enters one module
of the EGB and each module has a separate stack. Particulate emissions
were measured at the inlet of module three and on all three stacks
simultaneously. The emission data presented as test BE1 is the data
collected on the inlet to module 3. The emission data presented as test
BE2 is the weighted average of all three stacks, except for the gas flow
which is the sum of the three stacks.
The average boiler load during testing was 96 percent of capacity
and the pressure drop across the EGB averaged 6 inches of water. The
average emission rate was 0.0275 lb/10 Btu at the EGB outlet.
C-72
-------
The analyses of the fuel samples taken during testing were as
follows:
% H20
%Ashd
Q
Q
HHVd (Btu/lb)
HHVd (kJ/kg)
Run 1
54.9
4.8
0.06
0.14
8224
19129
Run 2
57.1
8.4
0.06
0.16
8541
19866
Run 3
55.9
12.8
0.08
0.12
8039
18699
Subscript 'd' denotes dry basis.
Plant BE was also tested by the company to determine the performance
of the E6B over a variety of operating conditions. The data presented
were collected at the outlet of module 3 of the E6B. The test consisted
of 15 test runs. During one test run, number 6, the electrostatic grid
was turned off. This test run would not be representative of normal
operation and is not presented. The remaining data were separated into
four groups:
Test BE3 - test runs made with "good" fuel and fly ash reinjection
Test BE4 - test runs made with "good" fuel without fly ash reinjection
Test BE5 - test runs made with "poor" fuel and fly ash reinjection
Test BE6 - test runs made with "poor" fuel without fly ash reinjection
"Good" fuel was defined as fuel with a moisture content of less than 55
percent (wet basis). "Poor" fuel had a moisture content over 55 percent.
C-73
-------
During runs 8, 11, 12, and 14 the Inlet loading to the E6B exceeded
design specifications. Though outlet emissions were low, there is a
possibility that the EGB could not continuously control PM emissions to
the levels shown if the inlet loading remained above the design limit.
The pressure drop across module 3 ranged from 1.2 to 7.9 inches of
water during testing. The emission rate ranged from 0.017 to 0.068 lb/10 Btu.
The boiler operating rate varied from 62 to 140 percent of rated capacity.
The average analyses of the fuel samples collected during testing
were as follows:
%H20
SAshd
% Nd
HHVd (Btu/lb)
HHVd (kJ/kg)
Test BE3
48.6
3.84
0.12
8,970
20,860
Test BE4
49.8
3.82
0.18
8,910
20,725
Test BE5
58.2
4.80
0.13
8,780
20,430
Test BE6
59.0
4.85
0.15
8,830
20,550
Subscript 'd1 denotes dry basis.
C-74
-------
PLANT BE152
TEST SUMMARY SHEETS
(Participates Only)
Test Number
One
Two
Three
Average
General Data
Date
rlsokinetic
12/9/80 12/10/80 12/11/81
89.7 102.7 150
Boiler Load (% of design) 100 101 87
Sample Point Location Inlet to Module 3 of electroscrubber
96
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%}
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nnu-dry
g/Nm -dry 0 12% C02
gr/dscf
gr/dscf @ 12% C02
ng/J fi
lb/10° Btu
Average Opacity
Control Device
Type
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
33.9
717510
158
334
-T9T7
~IO
"~O
0.362
"07556
~O5B
0.243
1S5
0.430
2 x MC
420.000
32.6
657U7S
~~T72
352
~^7L
—tt
8.3
0.604
"OT8T?
0.264
0.382
287
0.668
29.2
6T^2T
~TM
""335"
~55TT
~^8
10.2
0.428
O87
0.220
^204
0.473
31.9
6775TO
169
337
"7277"
10.1
8.8
0.465
0.644
0.203
0,282
225
0.524
For WS, pressure drop = "H90. For ESP, SCA = ft /1000 ACFM.
For FF, A/C = ft/min. L
C-75
-------
PLANT BE2
52
TEST SUMMARY SHEETS
(Participates Only)
Test Number
One
Two
Three
Average
General Data
Date 12/9/80 12/10/80
% Isokinetic 98.9 105
Boiler Load (% of design) 100 1Q1
Sample Point Location Outlet of EGB
12/11/80
98.6
87
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
3
g/Nnu-dry
g/Nm-dry 0 12% C09
gr/dscf *
gr/dscf 0 12* C09
ng/J 6 2
lb/10b Btu
Average Opacity
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
83.5
176.939
156
313
21.2
9.7
10.3
0.0229
0.0268
0.0100
0.0117
10.8
0.0251
2 x MC/EGB
5.5
4?n,nnn
89.6
lSi*SZO
111
322
23.2
9.1
10.9
0.0272
0.0300
0.0119
0.0131
12.1
0.0283
6.6
79.0
152*401
158
317
21.3
10.0
10.1
0.0259
0.0307
0.0113
0.0134
12.5
0.0291
5.8
84.0
178r07Q
158
317
21.9
9.6
10.4
0.0253
0.0292
0.0111
0.0127
11.8
0.0275
6.0
LFor WS, pressure drop = "H?0. For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/min. For EGB, pressure drop ="H20.
C-76
-------
PLANT BE3
53
TEST SUMMARY SHEETS
(Particulates Only)
Test Number
One
1
Two
2
Three
5
Average
Date 9/22/80 9/23/80
% Isokinetic nn in?
Boiler Load (% of design)in2 ins
Sample Point Location Outlet of EGB Module 3
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
3
g/Nm--dry
g/Nm -dry @ 12% CO-
gr/dscf
gr/dscf @ 12% CO-
ng/J 6
lb/10° Btu
Average Opacity
9/24/80
25.7
54.449
172
342
22.4
7.3
13.6
0.022
n.mg
n.mn
n.nns
8.53
0.020
27.4
58.051
168
334
2TT
7.1
13.1
0.031
n.02R
0.014
0.012
11.8
0.027
0.032
0.036
0.014
0.016
15.1
0.035
Control Device
Type
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
2xMC/FGB
2,9
3.3
140.000
1.2
Tor WS, pressure drop = "H20. For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/m1n. For EGB, pressure drop="H20
C-77
-------
PLANT BE3
53
TEST SUMMARY SHEETS
(Particulates Only)
Test Number
General Data
One
7
Two
9
Three Average
Date 9/26/80 9/29/80
% Isokinetlc 99 101
Boiler Load (% of design) ne 118
Sample Point Location Outlet of EGB Module 3
101
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
Particulate Emissions
g/NmiJ-dry 0.026
g/Nm-dry @ 12% C02 0.024
gr/dscf 0.011
gr/dscf @ 12% C0? 0.010
ng/J K c 9.66
lb/10° Btu 0.022
Average Opacity
0.021
0.021
0.009
0.009
8.93
0.021
0.026
0.026
0.011
0.011
10.8
0.025
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
2xMC/EGB
off
140,000
6.6
3.4
WS, pressure drop = "H«0. For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/min. For^ EGB, Pressure drop="H20
C-78
-------
PLANT BE453
TEST SUMMARY SHEETS
(Partlculates Only)
Test Number
General Data
Date
% Isokinetlc
Boiler Load (% of
One
3
9/23/80
92.7
design) 108
Sample Point Location Outlet of
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
26.9
56.992
168
33T"
19.4
"7T"
T7T5"
Two
4
9/24/80
96
EGBlioduie 3
23.8
50.424
TsT~
20. 7~"
12*. 9
Three Average
8
9/26/80
102
140
34.5
73.093
557""""
23.8""
1*3. 8" ZZZ
Partlculate Emissions
g/Nm?-dry 0.034 0.020 0.033
g/Nm -dry @ 12% CO, 0.032 0.018 0.028
gr/dscf ' 0.015 0.009 0.014
gr/dscf @ 12% CO, 0.014 0.008 0.012
ng/J fi ' 13.6 7.48 12.5
lb/10° BtU 0.032 0.017 0.029
Average Opacity
Control Device
Type . 2xMC/EGB
Operating Parameter1 2.9 2.1 7.0
Design Parameter
Design Flow Rate (ACFM) 140.000
lFor WS, pressure drop = "H,0. For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/m1n. For'EGB, pressure drop="H20
C-79
-------
PLANT BE453
TEST SUMMARY SHEETS
(Partlculates Only)
Test Number
General Data
Date
% Isok1net1c
One Two Three
15
10/3/80
'00
Boiler Load (% of design) 118
Sample Point Location
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Partlculate Emissions
g/Nm,-dry
g/Nm -dry @ 12% C09
gr/dscf *
gr/dscf @ 12% C0«
ng/J 6
lb/106 Btu
Average Opacity
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
Outlet of EGB Module 3
30.7
6?T04T
169
336
21.8
7.5
12.4
Q.02Q
0.019
0.009
0.008
7. 87
0.018
2xMC/EGB
4.1
140,000
Average
116
29.0
61,441
!7JL_
338
21.4
7.2
12.9
0.027
QiQ24
OJ)12
OJIJL
10. ^
0.024
4.0
LFor WS, pressure drop » %0. For ESP, SCA - ftVlOOO ACFM,
For FF, A/C - ft/m1n. For ' EGB,pressure drop="H20
C-80
-------
PLANT BE553
TEST SUMMARY SHEETS
(Participates Only)
Test Number
General Data
Date
% Isok1net1c
One
10
9/30/80
91.8
Boiler Load (% of design )1 02
Sample Point Location
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (35)
C02, dry (35)
Partlculate Emissions
g/Nnu-dry
g/Nm -dry @ 1235 CO,
gr/dscf *
gr/dscf @ 1235 CO,
ng/J c
lb/10° Btu
Average Opacity
Control Device
Type
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
Outlet of
31.2
667T02"
T8T~
HV
0—
11.8
Q.Q37
0.037
0.016
0.016
15.7
0.037
2xMC/EGB
7.9
140,000
Two
1 1
10/1/80
' 02
102
EGB Module 3
31.0
65275"
T83"
361
2375"
8.0
11.3
0.049
0.052
0.021
0.023
20.0
0.047
5.9
Three
i^
10/2/80
102
81
24.0
50^547"
T73
345
25.1
7.8
12.2
0.035
0.0?5.
0.015
0.0'5
14.1
0.033
2.9
Average
95
28.7
T5T-
TBTT
"571
11.8
OJ340
0.041
0.018
0.018
16.6
0.039
5.6
XFor WS, pressure drop » "H,0. For ESP, SCA - ft2/1000 ACFM.
For FF, A/C - ft/m1n. For CEGB,pressure drop="H90
C-81
-------
PLANT BE653
TEST SUMMARY SHEETS
(Particulates Only)
Test Number
General Data
One
12
Date 10/1/80
% Isokinetic 98.7
Boiler Load (% of design)! 02
Sample Point Location Outlet of
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (35)
C02, dry (*)
Particulate Emissions
g/Nnu-dry
g/Nnr-dry 9 1235 C09
gr/dscf *
gr/dscf @ 12% C0?
ng/J fi
lb/10° Btu
Average Opacity
Control Device
Type ,
Operating Parameter*
Design Parameter
Design Flow Rate (ACFM)
34.8
73.729
189
372
23.3
9.2
JL1
0.065
0.069
0.028
0.030
29.3
0.068
2xMC/EGB
7.1
Two Three
14
10/2/80
TT2
EGB Module 3
34.0
72.034
196
385
24.9
8.2
12.0
0.035
0.035
0.015
0.015
OsT
7.1
Average
107
34.4
72.881
192
175~~
"2T7T
"8TT
TTT
0.050
0.052
0.022
OT02T"
TTF
oTosT
7_J
WS, pressure drop = "H90. For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/min. For^EGB, pressure drop-"H20
C-82
-------
54 55 56
PLANT BF0*'00'50
Plant BF was tested to determine the participate emission rate.
Plant BF has a tangentially fired boiler rated at 350,000 pounds per
hour of steam. The fuel is 75 percent coal and 25 percent wood on a
heat input basis. Particulate emissions are controlled by a 290 tube
mechanical collector followed by two venturi wet scrubbers in parallel.
The wet scrubbers vent through a common stack. The normal operating
scrubber pressure drop is 9 inches of water. Fly ash collected by the
mechanical collector is not reinjected.
This boiler is an unusual design. In this boiler there are no
grates so the bark and sawdust are fired in suspension with the coal.
The original purpose of having wood firing capabilities in this boiler
was to dispense of wood waste rather than to recover energy from the
wood. According to plant personnel, no new boilers of this type are
expected.
This boiler design would not be typical of boilers firing wood in
suspension. Typical suspension wood-fired boilers fire dry fine fuels
such as sanderdust.
Three EPA Method 5 test runs were performed. Emissions were measured
at the inlet (BF1) and outlet (BF2) of the wet scrubbers so that their
efficiency could be calculated. The average boiler load during testing
was 94 percent of rated capacity. The average emissions were 0.028 pounds
per million Btu. The average collector efficiency was 99.7 percent.
The scrubber pressure drop during the tests was normal.
C-83
-------
54 56
PLANT BF1 '
TEST SUMMARY SHEETS
(Hartleyidues Only)
Test Number One Two Three Average
General Data
Date 5/5/77
% Isok1net1c inn i
Boiler Load (% of design) qfi n g-^.i gs.2 94
Sample Point Location TniPt
Stack Gas Data
Flow (Nm3/s-dry) 60.3
Flow (dscfm) i?7 flnn
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%) in a in ft
Partlculate Emissions
g/Nm--dry g »fi g.A3 8.88 9.39
g/Nm°-dry @ 12% CO- in gfi in Aft g.86
gr/dscf ' d..^1 4.12 3.88
gr/dscf @ 12% C02 i 10 4.M 4.31
ng/J 6 ' 4r532 4.334 4.081
lb/10° Btu 10.54 10.08 9.49
Average Opacity
Control Device
Type . Mr
Operating Parameter11
Design Parameter
Design Flow Rate (ACFM)
WS, pressure drop = "H«0. For ESP, SCA = ft2/1000 ACFM.
For FF, A/C * ft/mln. *
C-84
-------
PLANT BF254'56
TEST SUMMARY SHEETS
{^articulates Only)
Test Number One Two Three Average
General Data
Date t(f 5/77 S/fi/77 5/5/77
% Isok1net1c g« n Q3.1 95.2
Boiler Load (% of design) 94
Sample Point Location rintiPt of
Stack Gas Data
Flow (Nm3/s-dry) 71.1
Flow (dscfm) iscuiflfl.
Temperature (°C) ay •>
Temperature (°F) UA
Moisture (%) 19.7
Oxygen, dry (%)
C02, dry U)
Partlculate Emissions
g/Nm3-dry o.tes 0.028 0.025
g/Nm -dry @ 12% C0? p MQ p mn n n?ft
gr/dscf * ff KII n.oi? 0.011
gr/dscf 0 12« C02 OlT 0.013 0.012
"9/J 6 il fi 12.5 11^6
lb/10 Btu n n?7 n.n29 0.027
Average Opacity .
Control Device
mir/uc
i
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
For WS, pressure drop = "H-O.For ESP, SCA « ftz/1000 ACFM.
For FF, A/C » ft/m1n. t
C-85
-------
PLANT BG57'58
An emission test was performed at plant BG to determine compliance
with the State of Washington emission standards. The boiler fires hog
fuel and oil. Sludge can also be burned. The boiler is rated at 200,000 pounds
per hour of steam. Particulates are controlled with a 600 tube multicyclone
and a venturi wet scrubber. The design scrubber pressure drop is 15 to
20 inches of water. Fly ash collected by the mechanical collector is
not reinjected.
Three test runs were made in accordance with EPA Method 5. During
testing the boiler load was steady at 75 percent of rated capacity and
10 percent of the heat input was from No. 6 fuel oil. The wet scrubber
had a pressure drop of 19 inches of water during testing. The average
emissions were 0.15 pounds per million Btu which is below the State
allowable emissions of 0.216 pounds per million Btu. The fuel contained
approximately 0.4 percent salt (dry basis) and the particulate measured
at the outlet of the scrubber contained 13.3 percent salt.
C-86
-------
PUNT BG1
58
TEST SUMMARY SHEETS
(Hdrticulates 0*vyJ
Test Hunter
One
Two
Three
Average
General Data
Date 2787 7ff 2/877»
% Isokinetic 99 99.7
Boiler Load (% of design )_75 75
Sample Point Location Outlet of scrubber
75
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (X)
Oxygen, dry (%)
CO,, dry (*)
Participate Emissions
g/NmLdry
g/Hm -dry § 122 CO,
gr/dscf *
gr/dscf § 12S CO,
ng/J g z
lb/10D Btu
Average Opacity
0.174
0.162
0.076
0.071
65.4
0.152
0.167
0.156
0.073
0.068
63.6
0.148
0.172
0.158
0.075
0.069
64.4
0.150
Control Device
Type
Operating Parameter
Design Parameter
Design How Rate (ACFM)
MC7HS
8-10
174.000
T
19
For MS, pressure drop
For FF, A/C = ft/min.
"H20. For ESP, SCA = ftVlOOO ACFM.
C-87
-------
PLANT
Boilers No. 4 and 5 were tested to determine the efficiency of
their ESPs and to obtain participate emission rate data for the development
of New Source Performance Standards. Boiler No. 4 is a pulverized coal
unit rated at 140,000 pounds per hour of steam. Boiler No. 5 is a wood-
fired spreader stoker rated at 200,000 pounds per hour of steam. The
flue gases from each boiler pass through individual mechanical collectors.
The flue gases are then combined into a single duct and then split and
sent to identical ESPs. Each ESP has a separate stack. The design SCA
for each ESP is 460 ft2/1000 ACFM. All of the fly ash collected by the
mechanical collector on boiler No. 5 is reinjected into the No. 5 boiler
furnace.
Three EPA Method 5 tests were run; two were performed by the EPA.
The first EPA test was performed at the inlet of each cyclone (BH7, BH8)
and the outlet of both ESPs (BH9) on December 12-14, 1979. This test
showed emission rates at the ESP outlets (0.454 pounds per million Btu)
that were 10 times higher than previous industry tests. Opacity readings
taken during testing also indicated much higher emission rates than
would be expected for an ESP. Discussions with plant personnel and the
ESP vendor indicated that emissions this high were in no way normal for
this facility. A possible explanation is that the ash in the ESP hoppers
had "bridged over" and was being re-entrained in the flue gas. This
problem had occurred at this facility before but is not considered part
of normal operation. This facility was retested on September 23, 1980
C-i
-------
and the results were similar to the industry data. This tended to
confirm that the results of the December 12-14, 1979 test were not
indicative of normal operation. Therefore, the Method 5 and opacity
results of the first test were not used in NSPS development.
The industry test had average particulate emissions of 0.008 pounds
per million Btu. The test was conducted at the inlets (BH1) and outlets
(BH2) of the ESPs. Boiler No.4 was operated at 84 percent of rated
capacity and Boiler No.5 was operated at 46 percent of rated capacity.
Wood fuel provided an average of 80 percent of the total heat input to
boiler No.5 during this test. The average SCA during this test based on
the combined air flow of each ESP unit was 600 ft2/1000 ACFM.
The second EPA test, conducted on September, 1980 showed an average
emission rate from each ESP of 0.0675 pounds per million Btu. The test
was conducted at the inlet of both mechanical collectors (BH3, BH4),
and the outlets of the ESPs (BH6). Boiler No. 4 was operated at 48
percent of rated capacity and boiler No.5 was operated at 88 percent of
rated capacity. Wood fuel provided over 99 percent of the heat input
for boiler No.5 during testing. The average SCA during testing based on
the combined air flow of each ESP unit was 452 ft2/1000 ACFM.
The test data presented for the inlet and outlet of the ESPs is the
weighted average of both ESPs, except for the gas flow rate which is the
sum of both ESPs.
C-89
-------
For test BH1/BH2, the fuel analyses were as follows:
Test BH1/BH2
Ash
% N.
d
HHVd(Btu/lb)
HHVd(kJ/kg)
1
Run 1
coal /bark
2.88/31.66
12.89/6.89
0. 47/0. 25
1. 37/0. 02
Run 2
coal /bark
2. 55/32. 43
23.98/6.21
0.80/0.11
0. 89/0. 03
Run 3
coal /bark
4. 03/21. 20
16. 26/4. 55
0. 41/0. 18
0.94/0.02
13,080/8,370 11,320/8,210 12,590/7,880
30,420/19,460 26,320/19,100 29,280/18,330
For test BH3/BH4/BH6 fuel analyses were as follows:
; BH3/BH4/BH6
% H20
% Ash .
d
% S .
d
% Nd
Run 1
coal /bark
3. 15/43. 1
6. 38/4. 83
0. 58/0. 02
1. 41/0. 17
Run 2
coal /bark
3.91/43.9
7. 79/4. 59
0.94/0.03
1. 26/0. 21
Run 3
coal /bark
4.54/39.5
7. 14/3. 85
0. 60/0. 04
1. 42/0. 26
HHVd(Btu/lb)
HHVd(kJ/kg)
14,235/7,980 14,009/7,995 14,134/8,179
33,111/18,561 32,585/18,596 32,876/19,024
C-90
-------
For test BH7/BH8/BH9, the fuel analyses were as follows:1
Tests BH7/BH8/BH9
%H20
%Ashd
%Sd
% N .
d
HHVd(Btu/lb)
HHVd(kJ/kg)
Run 1
coal /bark
6. 02/43. 60
20.96/3.84
0. 60/0. 03
1. 00/0. 21
11,820/8,180
27,490/19,030
Run 2
coal /bark
6. 35/43. 88
11.23/3.98
1. 16/0. 03
1. 63/0. 26
11,320/8,330
30,840/19,380
Run 3
coal /bark
4.11/45.23
16.98/5.14
1. 01/0. 02
1. 24/0. 24
12,120/8,260
28,190/19,210
Subscript 'd' designates dry basis.
C-91
-------
PLANT BH161
TEST SUMMARY SHEETS
OP ' u '
Test Number
One
Two
Three
Average
General Data
Date 7/25/78
% Isokinetic 102
Boiler Load (% of design)76/45
Sample Point Location Inlet of ESP
7/26/78
99.4
88/52
7/27/78
99.2
87/41
84/46
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
Particulate Emissions
g/Nnu-dry
g/Nm -dry @ 12% CO-
gr/dscf c
gr/dscf 9 12* CO-
lb/10 Btu
Average Opacity
Control Device
Type ,
Operating ParameterA
Design Parameter
Design Flow Rate (ACFM)
MC
For WS, pressure drop
For FF, A/C = ft/min.
"H20. For ESP, SCA = ft'/lOOO ACFM.
C-92
-------
PLANT BH261
TEST SUMMARY SHEETS
(HartleuIstss On1.*')
Test Number
General Data
Date
% Isokinetic
One
7/25/78
95.1
Boiler Load (% of design) 76/45
Sample Point Location
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nm--dry
g/Nm -dry @ 12% CO,
gr/dscf *
gr/dscf @ 12% CO,
ng/J K
lb/10b Btu
Average Opacity
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
T—
Outlet
55.4
117,500
161
321
-9 76
10.4
9.4
0.007
0.008
Q.QQ2Q
0.004
3.4
0.0080
MC/ESP
biz
l60~
260,000
Two
7/26/78
94.4
88752"
of ESP
58.0
123,000
157
314
~TOT5~
_LA
10.4
0.012
0.014
0.0053
0.006
5-8
0.0134
584
Three
7/26/78
96.8
87/41
56.7
119,000
156
313
~rr
!*fl-
9.8
0.008
0.009
n. 0033
0.004
0.0026
605
Average
84/46
56.5
119,800
158
316~
TOT
9.9
9.9
0.009
0.010
0.0038
0.005-
3^4
0.0080
600
For WS, pressure drop = "H90. For ESP, SCA
For FF, A/C = ft/min. *
ftfc/1000 ACFM.
-------
PLANT BH362
TEST SUMMARY SHEETS
f Martini I a toe On i %/ \
v ^. ...*.._....*» •* t, j 4
Test Number One Two Three Average
General Data
Date 9/24/an g/25/80 g/25/80
% Isokinetic 103.9 100.9 101.3
Boiler Load (% of design) 48 49 48 48
Sample Point Location Inlet of MC-trackside
Stack Gas Data
Flow (Nm3/s-dry) 17.1
Flow (dscfm) 36,300
Temperature (°C) 205
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C0r_dry
Particulate Emissions
g/Nnu-dry
g/Nm -dry 9 12% C09
gr/dscf *
gr/dscf @ 12% C0?
6
lb/10° Btu
Average Opacity
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
XFor WS, pressure drop = "H90. For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/min. c
C-94
-------
PLANT BH462
TEST SUMMARY SHEETS
i'Mai"t-irij latgc (.'Ply!
Test Number
One
Two
Three
Average
General Data
Date 9/24/80 9/25/80
% Isokinetic 96.3 101.0
Boiler Load (% of design)87 88
Sample Point Location Inlet of MC-RTverside
88
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nm~-dry
g/NmJ-dry 0 12% C0«
gr/dscf *
gr/dscf @ 12% CO,
ng/J 6 z
lb/10b Btu
Average Opacity
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
Y 5
For WS, pressure drop = "H,0. For ESP, SCA = ft /1000 ACFM.
For FF, A/C = ft/min. . *
C-95
-------
PLANT BH6
62
TEST SUMMARY SHEETS
i I atoc On i u I
Test Number
One
Two
Three
Average
General Data
Date
% Isokinetic
9/24/80
106.2
Boiler Load (% of design)
Sample Point Location Outlet of ESP
9/24/80
losl
9/25/80
103.8
48/88
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C09, dry (%)
75.5
15JU120
1Z3
343
12-1
8.5
Particulate Emissions
g/Nm,-dry
g/Nm -dry @ 12% C0?
gr/dscf
gr/dscf @ 12% C09
ng/J 6 *
lb/10° Btu
Average Opacity
0.071
0.114
0.031
0.050
50.65
OT78
0.0297
0.0412
0.013
0.018
17.84
OTTOS
0.0316
0.0583
0.0138
0.0255
18.53
TTTOl
0.0441
0.0713
0.0193
0.0312
OTT5575
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
For WS, pressure drop =
For FF, A/C = ft/min.
MC/ESP
481
460
261,000
"H20. For
430 444
ESP, SCA = ft2/1000 ACFM.
452
C-96
-------
PLANT BH7
.63
TEST SUMMARY SHEETS
'
Test Number
One
Two
Three
Average
General Data
Date 12/12/79 12/14779 12715/79
% Isokinetic 96.5 105.0 96.4
Boiler Load (% of design) aa ag 104 .34
Sample Point Location Inlet of MC-trackside
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nm,-dry
g/Nm -dry @ 12% C09
gr/dscf *
gr/dscf 9 12% CO,
lb/10 Btu
Average Opacity
8.83
12.93
3.86
5.65
4709
10.95
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
MC
T
For WS, pressure drop = "H,0.
For FF, A/C = ft/min. *•
For ESP, SCA = ftZ/1000 ACFM
C-97
-------
PLANT BH863
TEST SUMMARY SHEETS
ii I a toe fin i w t
Test Number One Two Three Average
General Data
Date 12/12/79 12/.14/79 12/15/79
% Isokinetic 9j8.1 106.4 96.1
Boiler Load (% of design) 48 52 40.5 45.8
Sample Point Location Inlet of MC-riverside
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02*±dry
Particulate Emissions
g/NmLdry
g/NmJ-dry 0 12% C09
gr/dscf ^ 1535° ~2TDT TH?" LRQ
gr/dscf @ 12% C09 ~T^B "OO" XST 3.34
ng/j fi z nnrrs "2>;rn- "2752- 2759
lb/10° Btu ^3.29 9.63 6.40 6.44
Average Opacity
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
W WS, pressure drop = "H?0. For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/min.
C-98
-------
PUNT BH9
63
TEST SUMMARY SHEETS
{Parti crates (Jr.>»)
Test Number
One
Two
Three
Average
General Data
Date
% Isokinetic
12Z12/79
97.4
Boiler Load (% of design)f
Sample Point Location
fet of ESP
12714/79
89/52
12/1S/J9
97.7
104/40
94/46
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nnu-dry 0.249
g/NnT-dry @ 12% C02 p.554
gr/dscf * Q.1Q9
gr/dscf @ 12% CO,, 0.242
ng/J 6 c 225
lb/10° Btu 0.524
Average Opacity
0.279
Q.632
n.i??
0.276
222
0.517
0.224
n.3Qn
n.nga
0.170
13B
0.320
n. ^PR
n iin
195
D.454
Control Device
Type .
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
ESP
479
460
429
260.000
T
442
450
For WS, pressure drop = "H,0. For ESP, SCA
For FF, A/C = ft/min. i
ft2/1000 ACFM.
C-99
-------
PLANT BI64
Boilers No. 7 and 8 at Plant BI were tested by the EPA to obtain
participate emission data for the development of New Source Performance
Standards. Both boilers are wood/coal cofired spreader stokers with a
combined capacity of 565,000 pounds per hour of steam. The particulate
emissions from each boiler are separately controlled by a mechanical
collector followed by an ESP with two separate chambers, each chamber
has one stack. The design SCA for the ESP is 300 ft2/1000 ACFM. Fly
ash collected by the mechanical collector is not reinjected.
Three EPA Method 5 test runs were performed. The average boiler
load was 87 percent of rated capacity during testing. Wood supplied 25
percent of the heat input during the tests with the rest from coal. The
average particulate emission rate of the two stacks was 0.0418 pounds
per million Btu. The average SCA during testing based on the total air
2
flow to the ESP unit was 320 ft /1000 ACFM. The data presented is the
weighted average of both stacks, except for the gas flow rate which is
the sum of both stacks.
C-100
-------
The fuel analyses during testing were as follows:
Test BI1
% H20
% Ash .
d
Q
Q
HHVd(Btu/lb)
HHVd(kJ/kg)
Run 1
coal /bark
4. 8/45. 8
15.12/3.08
0.81/0.01
1. 19/0. 28
12,530/8,480
29,140/19,720
Run 2
coal /bark
5. 2/48. 0
15. 37/4. 49
1. 01/0. 01
1. 18/0. 31
12,840/8,130
29,870/18,910
Run 3
coal /bark
6. 4/44. 5
6. 59/2. 48
0. 77/0. 01
1. 43/0. 33
13,990/8,510
32,540/19,790
Subscript 'd1 designates dry basis.
C-101
-------
PLANT BIT
,64
TEST SUMMARY SHEETS
(Particmates Uniyj
Test Number
One
Two
Three
Average
General Data
Date 2/12/fiU 2£L2Z8J)
% Isokinetic QQ n 93.5
Boiler Load (% of design)^ 81
Sample Point Location Outlet of ESP
2/13/80
96.9
90
.az
Stack Gas Data
Flow (Nm /s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
100.7
191
375
11.6
n.o
9.2
9.7
Particulate Emissions
g/Nm--dry n.n.RQ
g/Nm°-dry @ 12% C02 n.n?n
gr/dscf o_025fl_
gr/dscf @ 12% C02 n n.^nd
ng/J g PR.fi
1b/10 Btu
Average Opacity
n.033
O.HL4S_
n.nifig
17.7
0.021
0.026
0.0092
0.0114
10.7
0.0248
0.038
0.047
0.0165
0.0204
18.0
0.0418
Control Device
Type , MC/ESP
Operating Parameter _335 312
Design Parameter ?gfi'
Design Flow Rate (ACFM) 415.000
314
320
.2
WS, pressure drop = "H90. For ESP, SCA = ftfc/1000 ACFM.
For FF, A/C = ft/min. * _
C-102
-------
PLANT BJ65'66
The boiler at Plant BJ was tested to determine compliance with
State emission standards. The boiler is a spreader stoker rated at
600,000 pounds per hour of steam. The boiler cofires bark, sawdust, and
number 6 fuel oil. Particulate emissions are controlled by a mechanical
2
collector followed by an ESP. The ESP has a design SCA of 355 ft /1000
ACFM. Fly ash collected by the mechanical collector passes through a
sand classifier and large particles are reinjected into the boiler
furnace.
The average emission rate during testing was 0.0260 pounds per
million Btu. The boiler was operated at 76 percent of rated capacity.
Wood provided 64 percent of the heat input. The SCA during the test
averaged 456 ft2/1000 ACFM.
C-103
-------
PLANT BJ1
66
TEST SUMMARY SHEETS
(^articulates Uniy)
Test Number
One
Two
Three
Average
General Data
Date 6/P7/7Q 6/22/79
% Isokinetic ins 106
Boiler Load (% of design)
Sample Point Location Outlet of FSP
6/27/79
106
76
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
69.1
146.400
_ 156
385
15.0
66.2
12.1
Particulate Emissions
g/Nm,-dry
g/NnT-dry @ 12% CO-
gr/dscf
gr/dscf @ 12% CO-
ng/J 6 ^
lb/10b Btu
Average Opacity
Q.Q3Q
0.032
n ni3
0.014
10.fi
n.025
Q.Q3Q
Q.Q3Q
0.013
0.013
10.3
0.024
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
For WS, pressure drop =
For FF, A/C = ft/min.
MC/ESP
443
356
"H20. For
463
ESP, SCA
462
= ft2/1000 ACFM.
456
C-104
-------
PLANT BK67'68
Plant BK was tested to determine compliance with North Carolina
particulate emission standards. This plant has a firetube boiler and is
rated at 3,400 pounds of steam per hour- Participates are controlled
with a mechanical collector. Fly ash collected by the mechanical collector
is not reinjected. Wood chips and dust are fed by an automatic drop-
chute into the boiler and large scraps are manually stoked.
Three EPA Method 5 test runs were performed. Run 3 is not shown
because test difficulties were incurred during Run 3 and consequently
the results for that run are not representative of the facility. The
average particulate emission rate for Plant BK was 0.448 pounds per
million Btu.
C-105
-------
PLANT BK168
TEST SUMMARY SHEETS
f Pa rt 1 ry ! at»? Op !y ,l
Test Number One Two Three Average
General Data
Date 5/2/78
% Isokinetic 97.4
Boiler Load (% of design) 39
Sample Point Location
i
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nm?-dry 0.117 0.048 0.082
g/Nm -dry 9 12% CO- 0.636 0.261 0.448
gr/dscf * 0.051 0.021 0.036
gr/dscf 9 12% CO, 0.278 0.114 0.196
ng/J - * 276.9 108.4 192.6
lb/10° Btu "O53 O5T -0.448
Average Opacity
Control Device
LFor WS, pressure drop = "H-O. For ESP, SCA = fr/1000 ACFM.
For FF, A/C = ft/min. *
C-106
-------
PLANT BL69'70
Plant BL was tested to determine compliance with State emission
regulations. Plant BL has an overfeed inclined grate wood-fired stoker
boiler. The boiler fires a mixture of bark, shavings, and sawdust.
Particulate emissions are controlled by a multiclone. Fly ash collected
by the multiclone is not reinjected.
The boiler was operated at an average of 42 percent of capacity
during testing. The average emission rate was 0.742 pounds per million
Btu.
G-107
-------
PLANT BLI
70
TEST SUMMARY SHEETS
(Participates Only)
Test Number
One
Two
Three
Average
General Data
Date 7/24/79 7/24/79
% Isokinetic IQS 99
Boiler Load (% of design) 43 39
Sample Point Location outlet of MC
7/24/79
42
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%}
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/NmLdry 0.448
g/Nm -dry 9 12% CO, 0,769
gr/dscf * 0.196
gr/dscf @ 12% C09 0.336
ng/J , * 299
lb/10° Btu 0.696
Average Opacity
0.771
_0_.508
JL812
_0.222
0.355
0.467
0.806
OJ04
0.352
"3l9~
07742
Control Device
Type .
Operating Parameter-1
Design Parameter
Design Flow Rate (ACFM)
MC
1
For WS, pressure drop
For FF, A/C = ft/min.
"H20.
For ESP, SCA = ft2/1000 ACFM.
C-108
-------
PLANT BM71'72'73
Plant BM was tested to determine compliance with State emission
regulations. Plant BM has a wood/coal cofired firetube boiler rated at
8,200 pounds per hour of steam. Particulate emissions are controlled by
a mechanical collector. All of the flyash collected by the mechanical
collector is reinjected into the boiler furnace.
The boiler was operated at an average of 102 percent of capacity
during testing. The operation rate was determined from the calculated
heat input and the rated heat input since no steam flow data were available.
Particulate emissions averaged 0.208 pounds per million Btu. Coal
provided 9 percent of the heat input during testing.
C-109
-------
PLANT BM1
73
TEST SUMMARY SHEETS
(Particulates Only)
Test Number
General Data
Date
% Isokinetlc
One
11/29/78
"TUT
Boiler Load (% of design) 97
Sample Point Location
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)'
Temperature (°C)
Temperature (°F)
Moisture (X)
Oxygen, dry (%)
C02, dry (X)
Particulate Emissions
3
g/Nnu-dry
g/Nm -dry 9 12% C0?
gr/dscf
gr/dscf 9 12% C09
ng/J 6 i
lb/10° Btu
Average Opacity
outlet
3.17
6.714
260
500
5^6
14.8
__JLS
0.109
0.224
n.nA77
n.ngan
95^5
0.222
^^1^_^^^—
Two
11/29/78
108
103
of MC
3.11
6.584
261
502
5.5
14.3
6i4
0.106
0.198
0.04fi1
n.n»fi4
B7..?
0.203
^•^•^•^^^^B
Three
11/29/78
105
106
3.15
6.680
263
506
6^.4
14.1
677
0.108
0.193
0.0471
0.0844
85.1
0.198
^ ^^^^^
Average
102
3.14
6,659
262
"~50T
5.8
14,4
6,3
0.108
0.205
Q.Q47Q
Q.Q896
89.3
0.208
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
MC
1
For WS, pressure drop
For FF, A/C = ft/min.
"H20.
For ESP, SCA = ft2/1000 ACFM
C-110
-------
PLANT BN74'75
Plant BN was tested to determine compliance with State emission
standards. Plant BN has a wood-fired firetube boiler rated at 26,000
pounds per hour of steam. The fuel is scraps of kiln dried wood.
Particulate emissions are controlled by a mechanical collector. All of
the fly ash collected by the mechanical collector is reinjected into the
boiler furnace. The boiler was operated at an average of 50 percent of
capacity during testing. The operating rate was determined by the heat
input calculated using the F-factor and the rated heat input. No steam
flow data was available. The average emission rate was 0.434 pounds per
million Btu.
C-lll
-------
PLANT BN75
TEST SUMMARY SHEETS
(Particulates Only)
Test Number
General Data
Date
% Isokinetic
One
3/18/80
~I02~
Boiler Load (% of design) 54
Sample Point Location
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%}
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nnu-dry
g/Nm -dry @ 12% C0«
gr/dscf
gr/dscf @ 12% C09
ng/J 6
lb/10b Btu
Average Opacity
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
For WS, pressure drop
For FF, A/C = ft/min.
outlet of
6.38
13.513
261
502
4.0
15.1
4.8
0.160
0,400
0.0701
0.175
141
0.327
MC
= %0. For
&
Two
3/18/80
-W
50
MC
6.56
13.886
246
474
3_».6
16.5
3.8
0.216
0*683
0*0944
0.298
242
0.563
ESP, SCA = ft2
Three
3/18/80
~~~IU3~
45
6.46
13.967
.240
464
3^.4
16.8
3.7
0.141
0.458
Q.Q618
(L2QQ.
177
0.412
/1000 ACFM.
Average
50
6.51
13.789
249
480
U
16.1
O
0.172
0.512
0.0754
n.PPA
187.
0.434
C-112
-------
C.I.2 Bagasse-Fired Boilers
The following facility descriptions are particulate emission data
for bagasse-fired boilers. Each site is given a 2-letter plant designation
beginning with the letter D. This letter indicates the facility has a
bagasse-fired boiler. A number after the plant description distinguishes
between different tests at the same plant. Most of the tests were
performed on bagasse-fired boilers in Florida. However, the method of
calculation of pounds per million Btu for the State of Florida is different
from the F factor method used in this report. Thus calculated emission
rates in this report for the tests from Florida do not necessarily
indicate compliance or noncompliance with the Florida standards.
C-113
-------
PLANT DA76'77
Boiler No. 3 at Plant DA was tested to determine compliance with
Florida emission standards. Boiler No. 3 is a bagasse-fired horseshoe
boiler rated at 125,000 pounds per hour of steam. Particulate emissions
are controlled by two impingement wet scrubbers in parallel. The normal
pressure drop is 5 to 7 inches of water.
Three EPA Method 5 test runs were performed. The average boiler
load was 78 percent of rated capacity. During the test, bagasse supplied
an average of 92 percent of the total heat input. The average particulate
emissions were 0.330 pounds per million Btu. The pressure drop during
the test was normal. Results for this test are shown under the designation
DAI.
Boiler No.4 at Plant DA was tested to determine the compliance with
Flordia emission standards. Boiler No. 4 is a bagasse-fired horseshoe
boiler rated at 125,000 pounds per hour of steam. Particulate emissions
are controlled by an impingement wet scrubber. The normal operating
pressure drop is 5 to 7 inches of water.
Three EPA Method 5 test runs were performed. The average boiler
load during the tests was 71 percent of rated capacity. The average
particulate emission rate was 0.263 pounds per mil lion Btu. The scrubber
pressure drop during testing was normal. Results for this test are
shown under the designation DA2.
C-114
-------
PLANT DAI
76
TEST SUMMARY SHEETS
(Hdrticuidtes Only)
Test Number
One
Two
Three
Average
General Data
Date 1/22/19 1/29/79
% Isokinetic 98.7 97.9
Boiler Load (% of design) 79 74
Sample Point Location Outlet of Scrubber
1/29/79
100.2
80
78
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
Particulate Emissions
g/Nm?-dry 0.270
g/NmJ-dry @ 12% C02 0.359
gr/dscf c 0.118
gr/dscf @ 12$ C02 0.157
ng/J 6 c 128.1
lb/10b Btu 0.298
Average Opacity
0.231
0.439
0.101
0.192
161.7
0.376
0.213
0.364
0.093
0.159
J3579
0.316
0.238
O8T
OTTOT
141.9
O3TT
Control Device
Type .
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
2WS
5-7
5-7
For WS, pressure drop
For FF, A/C = ft/min.
= "H20. For ESP, SCA = ftVlOOO ACFM.
C-115
-------
PLANT DA277
TEST SUMMARY SHEETS
(Particuiates only)
Test Number
General Data
Date
% Isokinetic
Boiler Load (% of
One
12/20/78
101.7
design) 70
Two
12/2U/J8
95.4
74
Three
12^1/78
103.8
69
Average
71
Sample Point Location JXitlet of Scrubber
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
Particulate Emissions
g/NmLdry 0.190 0.220 0.185 0.198
g/Nm -dry @ 12% CO,, "OTl
gr/dscf c Q.Q83 0.096 0.081 "OS7
gr/dscf @ 12% CO- 0.149 0.128 0.110 "pTT?9
ng/J K * 129.4 112.7 98.9 TT3T7
lb/10° Btu 0.301 0.262 0.230 "O61
Average Opacity
Control Device
Type , MS
Operating Parameter 5-7
Design Parameter 5-7
Design Flow Rate (ACFM)
W WS, pressure drop = "H,,0. For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/min. *
C-116
-------
PLANT DC78'79
Plant DC was tested to determine particulate emissions levels.
Plant DC has a bagasse-fired spreader stoker boiler rated at 312,000 pounds
per hour of steam. Particulate emissions are controlled by a mechanical
collector followed by a variable throat ejector venturi wet scrubber
equipped with a demister. The normal scrubber flue gas pressure drop is
2 inches of water. However, for this scrubber type gas phase pressure
drop is not a good indicator of scrubber efficiency (see Section 4.1.2.3).
This scrubber would be equivalent in removal efficiency to a standard
venturi scrubber with a flue gas pressure drop of 6 inches of water.
Three EPA Method 5 test runs were performed. The average boiler
load during the test was 93 percent of rated capacity. The average
emissions were 0.084 pounds per million Btu. The scrubber pressure drop
during testing was normal.
For test DC1, the fuel analyses were as follows:
Test DC1 Run 1 Run 2 Run 3
% H20 48.25 47.05 48.83
% Ashd 3.40 3.08 2.61
Subscript 'd' designates dry basis.
C-117
-------
PLANT DC179
TEST SUMMARY SHEETS
(^articulates Only)
Test Number One Two Three Average
General Data
Date 5/24/79 5/24/79
% Isokinetic 92.7 97.1
Boiler Load (% of design) 92 94 93 93
Sample Point Location Outlet of Scrubber
Stack Gas Data
Flow (Nm3/s-dry) 45.6 dfi.2
Flow (dscfm) gfi,72n 9?,afin
Temperature (°C) TJ 7?
Temperature (°F) IKR ifii
Moisture (%) 33.7 33.6
Oxygen, dry (%) 5 a R.fi
C02, dry (%) 14.2 11.4
Particulate Emissions
g/NmLdry 0.082 0.089 0.119
g/Nm -dry (a 12% C02 0.071 0.094 ~OP6
gr/dscf n.n36 0.039 0.052
gr/dscf @ 12% C0? Q.Q31 0.041 0.046
ng/J fi 28.4 37.4 43.4
lb/10° Btu 0.066 Q.087 0.101
Average Opacity
Control Device
Type , MC/WS
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
WS, pressure drop = "H90. For ESP, SCA = ftZ/1000 ACFM.
For FF, A/C = ft/min. c
C-118
-------
PLANT DD80
Boiler Noi, 2 at Plant DD was tested to determine the participate
emission rate. Boiler No. 2 is a bagasse-fired spreader stoker boiler
rated at 288,000 pounds per hour of steam. Particulate emissions are
controlled by two mechanical collectors in series.
Three EPA Method 5 test runs were performed. The average boiler
load was 68 percent of rated capacity during testing. The average
particulate emissions were 0.285 pounds per million Btu.
For test DD1, the fuel analyses were as follows:
Test DD1 Run 1 Run 2 Run 3
% H20 48.7 48.2 48.8
C-119
-------
PLANT DDT80
TEST SUMMARY SHEETS
(ParticuI aces unlyj
Test Number One Two Three Average
General Data
Date 12/16/78 12/16/78
% Isokinetic 98.9 102.8
Boiler Load (% of design) 67 70 .68 68
Sample Point Location Outlet of MC
Stack Gas Data
o
Flow (Nm /s-dry) 39.7
Flow (dscfm) 84.200
Temperature (°C) IM
Temperature (°F) 327
Moisture (%) 23.9 25.6 25.3 24.9
Oxygen, dry (%) 7.3
C02, dry (%) 11.9
Particulate Emissions
g/Nm^-dry 0.316 0.307 0.242 0.288
g/Nm -dry @ 12% C0? Q.318 0.350 0.286 0.318
gr/dscf c n.138 0.134 0.106 0.126
gr/dscf @ 12% C02 n no n.isa 0.125 0.139
ng/J 6 i9n n n? ? nn.s 122.6
lb/10 Btu n ?7Q n.TlQ n.257 Q.285
Average Opacity ?n 3 i« fi 17.o 18.6
Control Device
Type , ?MC
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
WS, pressure drop = "hLO. For ESP, SCA = ftZ/1000 ACFM.
For FF, A/C = ft/min. c
C-120
-------
PLANT DE81'84
Boiler No. 6 at Plant DE was tested to determine compliance with
Florida emission standards. Boiler No. 6 is a bagasse-fired fuel cell
rated at 125,000 pounds per hour of steam. Particulate emissions are
controlled with an impingement wet scrubber. The normal scrubber pressure
drop is 6 inches of water.
Three EPA Method 5 test runs were performed. The average boiler
load was 96 percent of rated capacity. During the test, bagasse supplied
an average of 94 percent of the heat input. The average particulate
emissions were 0.29 pounds per million Btu. During the tests, the
scrubber pressure drop was normal. These test results are summarized
under the designation DEI.
Boiler No. 12 at Plant DE was tested to determine compliance with
Florida emission standards. Boiler No. 12 is a bagasse-fired spreader
stoker -ated at 150,000 pounds per hour of steam. Particulate emissions
are controlled by a mechanical collector followed by an impingement wet
scrubber. The normal scrubber pressure drop is 6 inches of water.
Three EPA Method 5 test runs were performed. The average boiler
load was 92 percent of rated capacity during testing. The average
particulate emissions were 0.269 pounds per million Btu. The scrubber
pressure drop was normal. These test results are summarized under the
designation DE2.
Boiler No. 14 at Plant DE3 was tested to determine compliance with
Florida emission standards. Boiler No. 14 is a bagasse-fired spreader
C-121
-------
stoker boiler rated at 150,000 pounds per hour of steam. Particulate
emissions are controlled by a mechanical collector followed by an impinge-
ment wet scrubber. The normal pressure drop is 6 inches of water.
Three EPA Method 5 test runs were performed. The average boiler
load was 98 percent of rated capacity during testing. The average
particulate emission rate was 0.236 pounds per million Btu. The scrubber
pressure drop was normal during the tests. The results of this test are
summarized under the designation DE3.
C-122
-------
PLANT DEI
82
TEST SUMMARY SHEETS
(r'drticuiates Only)
Test Number
One
Two
Three
Average
General Data
Date 11/19/J9 11/19/79
% Isokinetic 96.4 94.9
Boiler Load (% of design) 93 96
Sample Point Location Outlet of Scrubber
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
Particulate Emissions
g/Nnu-dry
g/Nm -dry @ 12% C0
gr/dscf
gr/dscf
-------
PLANT DE2 83
TEST SUMMARY SHEETS
(Particulars Only)
Test Number One Two Three Average
General Data
Date 2/7/80 2/7/80
% Isok1net1c 92.8 91.6
Boiler Load (% of design) 03 91 93 92
Sample Point Location Outlet of Scrubber
Stack Gas Data
Flow (Nm3/s-dry) 25.1 26.fi 30.0
Flow (dscfm) 53.200 56.300 55.000
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C0, dry
Particulate Emissions
g/NmLdry 0.396 0.332 0.352
g/Nm -dry @ 12% rn ~ ~~~ ~
gr/dscf 0.173 0.145 0.15'
gr/dscf @ 12% C02 n in n.13? 0.137
ng/J fi ipft fi infi ? 112.7
lb/10° Btu n PQQ n.?A7 0.262
Average Opacity
Control Device
Type , MC/WS
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
JFor WS, pressure drop = "H90. For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/min. i
C-124
-------
PLANT DE3
84
TEST SUMMARY SHEETS
(f-ar-cicuidces only)
Test Number
One
Two
Three
Average
General Data
Date W3/80 1/3/80
% Isok1net1c ins.n QS.Q
Boiler Load (% of design) QR oa
Sample Point Location Outlet of Scrubber
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry
C02, dry (%)
Particulate Emissions
3
g/Nnu-dry
g/NmJ-dry @ 12% CO,
gr/dscf *•
gr/dscf 9 12% C09
lb/10 Btu
Average Opacity
23.7
50.200
7J
160.5
32.8
5.8
14.0
0.284
0.242
0.124
0.106
97.2
0.226
24.2
51 .400
n
__LL2
32.5
6.5
13.8
0.295
0.256
0.129
0.112
105.8
0.246
1/3/80
99.4
100
98
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
MC/WS
T
For WS, pressure drop
For FF, A/C = ft/min.
"H20. For ESP, SCA = ft2/1000 ACFM.
C-125
-------
PLANT DF85
Boiler No. 2 at Plant DF was tested to determine compliance with
Florida emission standards. Boiler No. 2 is a bagasse-fired horseshoe
r
boiler rated at 125,000 pounds per hour of steam. Particulate emissions
are controlled by two impingement wet scrubbers in parallel. The normal
scrubber pressure drop is 8 to 9 inches of water.
Three EPA Method 5 test runs were performed. The average boiler
load was 71 percent of rated capacity during testing. The average
particulate emission rate was 0.279 pounds per million Btu. The scrubber
pressure drop was normal.
C-126
-------
PLANT DPI
85
TEST SUMMARY SHEETS
(rarticuiates Dmy)
Test Number
Genera] Data
Date
% Isokinetic
One
1?/1Q/7Q
99.1
Boiler Load (% of design) 73
Sample Point Location
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (X)
Particulate Emissions
g/Nnu-dry
g/Nm-dry @ 12% C09
gr/dscf £
gr/dscf 8 12% C0?
ng/J 6 *
lb/10& Btu
Average Opacity
Control Device
Type .
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
For WS, pressure drop
Pnv> CC A /r - -C4- /m,' n
Outlet
35.0
74,100
70.0
158
26.6
12.1
8.6
0.220
U.dU/
0.096
0.134
129.0
0.300
2WS
= "H20. For
Two
12/1 Q/79
99.6
72
of Scrubber
28.9
61.300
71.1
160
26.7
11.0
9.1
0.263
0.348
0.115
0.152
137.6
0.320
ESP, SCA =
Three
12/19/79
97.1
69
31.7
67.200
66.9
152.4
25.2
10.2
8.1
0.190
0.281
0.083
0.123
92.4
0.215
ft2/1000 ACFM.
Average
71
31.9
67,600
69.3
156.8
26.2
11.3
8_.6
0.224
0.-12
0.098
0.136
~TT9~.7
^279
8-9
C-127
-------
PLANT DG86
Boiler No. 5 at Plant DG was tested to determine compliance with
Florida participate emissions standards. Boiler No.5 is a bagasse-fired
spreader stoker rated at 160,000 pounds per hour of steam. Particulate
emissions are controlled with two impingement wet scrubbers in parallel.
The normal pressure drop is 5 to 9 inches of water.
Three EPA Method 5 test runs were performed. The average boiler
load was 103 percent of rated capacity. During the test, bagasse supplied
80 percent of the heat input. The average particulate emission rate was
0.108 pounds per million Btu. The scrubber pressure drop during the
test was normal.
C-128
-------
PLANT DG1
86
TEST SUMMARY SHEETS
(r'amcuiates unly)
Test Number
One
Two
Three
Average
General Data
10/25/79
TOO
Date 10/25/79
% Isokinetic "TOO
Boiler Load (% of design)T03~ 101
Sample Point Location n.itipt nf scrubber
10/26/79
102.1
106
101.7
103
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
28.3
Particulate Emissions
g/NmLdry
g/NmJ-dry
12% C0
gr/dscf
gr/dscf @ 12% C0
lb/106 Btu
Average Opacity
n 19*
0.135
0.054
0.059
n IIQ
n.135
0.052
0.059
48.2
0.112
0.094
0.101
0.041
0.044
40.0
0.093
0.112
0.124
0.049
0.054
46.. 3
0.108
Control Device
Type
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
.1
T
5-9
For WS, pressure drop
For FF, A/C = ft/min.
= "H,,0.For ESP, SCA = ftZ/1000 ACFM
C-129
-------
PLANT DH87'88
Boiler No.5 at plant DH was tested to determine compliance with
Florida participate emissions standards. Boiler No.5 is a spreader
stoker rated at 200,000 pounds per hour of steam. Bagasse is the
principal fuel supplemented with No.6 fuel oil. Particulate emissions
are controlled by an impingement wet scrubber. The normal scrubber
pressure drop is 6 inches of water.
Three EPA Method 5 test runs were performed. The average boiler
load was 82 percent of rated capacity. The average particulate emission
rate was 0.140 pounds per million Btu. The scrubber pressure drop
during the test was normal. The results of this test are summarized
under the designation DHL
Boiler No. 2 at plant DH was tested by the EPA to obtain particulate
emission data for the development of New Source Performance Standards.
Boiler No. 2 is a spreader stoker rated at 150,000 pounds per hour of
steam. Particulate emissions are controlled by an impingement wet
scrubber. The normal scrubber pressure drop is 6 inches of water.
Three EPA Method 5 test runs were performed. The average boiler
load was 97 percent of rated capacity. The average particulate emission
rate was 0.270 pounds per million Btu. During the test the scrubber
pressure drop was normal. The results of this test are summarized under
the designation DH2.
C-130
-------
The fuel analyses during testing were as follows:
Test DH2
%H20
% Ashd
%sd
% Nd
HHVd(Btu/lb)
HVVd(kJ/kg)
Run 1
57.1
1.09
0.01
0.36
7,939
18,470
Run 2
60.4
2.85
0.01
0.39
8,101
18,840
Run 3
57.7
1.58
0.01
0.40
8,233
19,150
Subscript 'd' designates dry basis.
C-131
-------
PLANT DH1
TEST SUMMARY SHEETS
(rarticuiates umy)
Test Number
One
Two
Three
Average
General Data
Date _2Z22/80 2/29/80
% Isokinetic 91.8 99.4
Boiler Load (% of design) 85 78
Sample Point Location
Outl et of scruBber
82
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
,.49 .,7
105,300
10.4
55.5
117.700
6O
53.8
114,000
66.0
10.0
Particulate Emissions
g/Nnu-dry 0.149
g/Nm -dry @ 12% C0? 0.172
gr/dscf ' 0.065
gr/dscf @ 12% CO,, 0.075
ng/J R *• 71.0
lb/10b Btu 0.165
Average Opacity
Q.Q9S
0.124
0.043
0.054
51.6
0.120
0.117
0.140
Q.Q51
Q.Q61
58.5
0.136
n.121
L45
Q.Q53
0.063
fiH.4
0.140
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
WS
Tor WS, pressure drop = "H90. For ESP, SCA = ftZ/1000 ACFM.
For FF, A/C = ft/min. *
C-132
-------
PLANT DH288
TEST SUMMARY SHEETS
(rarticulaies Only)
Test Number
One
Two
Three
Average
General Data
Date 12/17/79 12/18/79
% Isokinetic 106 106
Boiler Load (% of design) gs im
Sample Point Location Outlet of scrubber
97
Stack Gas Data
Flow (Nm /s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
10.8
27.7
Particulate Emissions
3
g/Nm,-dry
g/Nm -dry @ 12% CO,
gr/dscf i
gr/dscf @ 12% CO,
ng/J 6 *
lb/10b Btu
Average Opacity
0.261
"O75
0.114
0.120
117.0
0.272
0.262
DT284
OJ14
QJ24
U6.1
0.270
Control Device
Type .
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
2WS
T
For WS, pressure drop = "H90. For ESP, SCA
For FF, A/C = ft/min. i
ft2/1000 ACFM.
C-133
-------
C.I.3 MSW-Fired Boilers
The following facility descriptions and participate emission data
are for MSW-fired boilers. Each site is given a 2-letter plant designation
beginning with the letter F. This letter indicates the facility has a
MSW-fired boiler. A number after the plant designation distinguishes
between different tests at the same plant.
C-134
-------
PLANT FA89'90
Plant FA was tested to determine if it was able to meet Massachusetts'
participate emissions standards when the fuel feed rate to one of the
boilers was increased beyond the design capacity. Plant FA has two
overfeed water wall MSW-fired boilers rated at 30,000 pounds per hour of
steam capacity and 5 tons per hour of refuse feed rate each. Each
boiler is equipped with its own ESP- The ESPs are exhausted through a
common stack. The design SCA of the ESPs is 126 ft2/1000 ACFM.
Three EPA Method 5 test runs were made. During the test, boiler
No.2 was operated with a feed rate of 8 tons per hour of refuse and the
boiler load was 88 percent of rated steam capacity. Boiler No.l was
shutdown. The load factor for the boiler was based on the fuel fired
rate because it was being operated outside its design range. The average
particulate emissions were 0.200 pounds per million Btu. The average
SCA during the tests was 139 ft2/1000 ACFM.
0135
-------
PLANT FA1
90
TEST SUMMARY SHEETS
(^articulates unly;
Test Number
One
Two
Three
Average
General Data
Date 8/17/78
% Isokinetic 104.2
Boiler Load (% of design) isn
Sample Point Location
Outlet of ESP
8/17/78
101.8
160
isn*
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
Particulate Emissions
g/Nnu-dry
g/NnT-dry @ 12% C02
gr/dscf
gr/dscf 9 12% CO,
lb/10 Btu
Average Opacity
0.167
~O56
0.073
0.125
114.4
_IL2fi6
0.103
"DTTFl
0.108
0.178
Q.Q47
0.078
71.8
n ifi?
0.126
0.215
0.055
0.094
86.0
n ?nn
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
ESP
138
126
32.000
145
134
139
For WS, pressure drop = "H«0.
For FF, A/C = ft/min. *
*Based on fuel feed rate.
For ESP, SCA = ft2/1000 ACFM
C-136
-------
PLANT FB91"93
Boiler No. 1 at Plant FB was tested to determine the participate
emission rate. Boiler No. 1 is an overfeed stoker fired by 100 percent
municipal solid waste and is rated at 135,000 pounds per hour of steam.
Particulate emissions are controlled by an ESP. The design SCA of the
ESP is 316 ft2/1000 ACFM.
Three EPA Method 5 test runs were performed. The average boiler
load was 77 percent of rated capacity during testing. The average
particulate emission rate was 0.0465 pounds per million Btu. The SCA
2
during the test averaged 573 ft /I000 ACFM.
C-137
-------
PLANT FBI 93
TEST SUMMARY SHEETS
(^articulates Only)
Test Number
One
Two
Three
Average
General Data
Date g/22/76
% Isokinetic 103.6
Boiler Load (% of design) 78
Sample Point Location Outlet of ESP
9/22/76
102
9/23/76
98.5
76
77
Stack Gas Data
2
Flow (Nm /s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nm,-dry
g/Nm -dry 9 12% CO-
gr/dscf *
gr/dscf @ 12% C09
lb/10u Btu
Average Opacity
0.053
0.062
0.023
0.027
21-5
0.050
0.053
0.064
_QJ223
0.028
22,8
0.053
0.044
~O56
JLQL9
0.024
19.9
0.046
Control Device
Type ,
Operating Parameter fi^n
Design Parameter 316
Design Flow Rate (ACFM)
MC/ESP
filfi
140.000
474
573
LFor WS, pressure drop = "H,,0. For ESP, SCA = fr/1000 ACFM.
For FF, A/C = ft/min. c __
C-138
-------
PLANT FC94'95
Plant FC was tested to determine compliance with State and Federal
participate emissions standards. Plant FC has two identical overfeed
stoker boilers rated at 175,000 pounds per hour of steam each. They are
designed to burn 1200 tons per day of municipal solid waste. The flue
gases from the boilers pass through individual ESPs and are combined in
a single stack. The design SCA of the ESPs is 209 ft2/1000 ACFM.
Three EPA Method 5 test runs were performed at the stack. The
first run was deleted due to a bad leak check. Both boilers were operating
and the average load was 84 percent of rated capacity. The average
particulate emission rate was 0.087 pounds per million Btu which was
below both the State allowable of 0.0915 pounds per million Btu and the
Federal allowable (40 CFR 60 Subpart E) of 0.146 pounds per million Btu.
2
The average SCA during the test was 243 ft /1000 ACFM.
C-139
-------
PLANT FC195
TEST SUMMARY SHEETS
(Particulates Only)
Test Number
One
Two
Three
Average
General Data
Date 6/8/76 6/8/76
% Isokinetic 99 99
Boiler Load (% of design) 81/90 80/85
Sample Point Location Combined outlet of ESPs
80/88
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (X)
Oxygen, dry (%}
CO,, dry (X)
Particulate Emissions
3
g/Nm--dry
g/Nm -dry 9 12% C09
gr/dscf '
gr/dscf 9 12% CO,
ng/J 6 2
lb/10° Btu
Average Opacity
0.080
0.112
0.035
0.049
39.6
0.092
0.073
0.101
0.032
0.044
35.3
0.082
0.076
0.106
0.034
0.046
37.4
0.087
2 ESPs
Control Device
Type .
Operating Parameter
Design Parameter
Design Flow Rate (ACFM) 2 x 200.000
209
240
246
1
For WS, pressure drop
For FF, A/C » ft/min.
"H20. For ESP, SCA
ft2/1000 ACFM.
C-140
-------
PLANT FD96'98
The East and West boilers at Plant FD were tested to determine the
participate emission rate. Both are MSW-fired ram-fed controlled air
boilers. They are rated at 10,000 pounds per hour of steam each. No
add-on controls are used.
Two EPA Method 5 tests were run on the East boiler. No steam
generation rates were reported, so the steam generation rate was estimated
based on the mass emission rate and the emission rate calculated using
the F-factor. The average particulate emission rate for the East boiler
was 0.195 pounds per million Btu for the first test (FD1) and 0.259
pounds per million Btu for the second test (FD2). During test FD1 the
composite moisture of the fuel was 15.2 percent and the fuel heating
value was 4,670 Btu/lb.
This plant was later retested by the EPA as part of the standards
development program. The West boiler operated at an average of 76 percent
of rated capacity during testing. The average particulate emission rate
for the West boiler was 0.251 pounds per million Btu.
C-141
-------
PLANT FDl9fi
TEST SUMMARY SHEETS
(Farticulaces Unly)
Test Number
One
Two
Three
Average
General Data
Date 2/22/79 2/22/79
% Isokinetic 108.6 101.5
Boiler Load (% of design) 85 95
Sample Point Location East Stack
Stack Gas Data
2
Flow (Nm /s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
3,0
6.300
384
15.1
12.3
6.4
3.2
6.750
191
376
13.3
11.8
7.0
88
Particulate Emissions
g/Nm,-dry
g/Nm -dry @ 12% C02
gr/dscf
gr/dscf 9 12% C09
ng/J fi
lb/10D Btu
Average Opacity
0.094
0.174
0.130
O.Z22
0.057
Q.Q97
77.4
0-180
0.190
0.323
0.083
0.141
115.2
0.268
0.138
~O50
Q.06Q
0.105
83.8
0.195
Control Device
Type ,
Operating Parameter"1
Design Parameter
Design Flow Rate (ACFM)
NONE
For WS, pressure drop
For FF, A/C = ft/min.
"H20.
For ESP, SCA
C-142
ftZ/1000 ACFM.
-------
PLANT FD297
TEST SUMMARY SHEETS
(particuiates Uniy;
Test Number
One
Two
Three
Average
General Data
Date .6/15/79 6/15/79
% Isokinetic 98.6 106.9
Boiler Load (% of design) 78 62
Sample Point Location «• East Stack
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nnu-dry
g/Nm -dry 0 12% C0«
gr/dscf i
gr/dscf 0 12% CO,
ng/J 6 Z
lb/10b Btu
Average Opacity
3.4
7.340
197
387
5.9
14.2
5.8
0.119
0.247
0.052
0.108
96.3
0.224
2.9
6.240
L9.6
385
12.0
14.6
5.4
0.153
0.341
0.067
0.149
131.6
0.306
6/15/79
105.0
87
0.149
0.264
Q.Q65
0.116
105.8
0.246
76
0.140
0.284
0.061
0.124
111.2
0.259
Control Device
Type .
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
NONE
T
For WS, pressure drop
For FF, A/C = ft/min.
"H20.
For ESP, SCA = ftVlOOO ACFM.
C-143
-------
PLANT FD398
TEST SUMMARY SHEETS
(rarticuiaces Uniy)
Test Number One Two Three Average
General Data
Date 11/6/79 11/7/79 11/7/79
% Isokinetic 100.3 102.3 101.6
Boiler Load (% of design) 74 73 80 76
Sample Point Location West Stack
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nm3-dry 0.238 0.172 0.121 0.177
g/Nm-dry @ 12% C0? 0.366 0.332 0.201 0.300
gr/dscf c 0.104 0.075 0.053 Q."07T"
gr/dscf @ 12% CO,, 0.160 0.145 0.088 0.131
ng/J fi c 130.3 120.4 73.5 108.1
lb/10° Btu Q.3Q3 0.280 0.171 0.251
Average Opacity 13.3 17.7 16.3 15.8
Control Device
Type . ^
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
W WS, pressure drop = "H?0. For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/min.
C-144
-------
PLANT FE99
Boiler No. 1 at Plant FE was tested to determine the participate
emission rate. Boiler No. 1 is an overfeed stoker rated at 110,000 pounds
per hour of steam. The boiler is fueled with 100 percent municipal
solid waste. Particulate emissions are controlled by an ESP. The
design SCA of the ESP is 154 ft2/1000 ACFM.
Three EPA Method 5 test runs were performed simultaneously at both
the inlet and outlet of the ESP. Two additional test runs were run at
the outlet of the ESP only. Three of the outlet runs are not presented
for reasons discussed below. The average boiler load during testing was
79 percent of rated capacity. The average outlet particulate emission
rate for the two good runs was 0.077 pounds per million Btu. The fuel
burned during the test had an ash content of 31.2 percent and a moisture
2
content of 26.4 percent. The average SCA during the test was 278 ft /1000
ACFM.
The measured emissions at the ESP outlet on Run 1, using EPA Method 5,
were much higher than for Runs 2 and 3. Since the measured ESP inlet
emissions for this run were significantly lower than Runs 2 and 3 and
the SCA was significantly higher, this test run should have resulted in
lower emissions than Runs 2 and 3. When the EPA results were compared
to data obtained simultaneously using an ASME test method, the ASME test
data showed more consistent emissions for all three runs. Therefore the
high results obtained during Run 1 using the EPA sampling method are
believed to be questionable. Because of this, Run 1 is not presented and
was not used in NSPS development.
C-145
-------
Two preliminary test runs were also performed at the ESP outlet
only. One of these runs was not performed in accordance with proper EPA
Method 5 procedures. The other preliminary emission test run at the ESP
outlet had an inconsistency in the oxygen content and gas flow rate when
compared to the last two test runs. However, the run was consistent
with Run 1 oxygen content and flue gas flow. Since the results of Run
1 are believed to be in error, whatever caused the error in Run 1 is
also believed to have caused this run to be in error. Therefore, neither
of these preliminary outlet test runs are presented here or were used in
NSPS development.
C-146
-------
PLANT FE1 99
TEST SUMMARY SHEETS
(Pdrucuidtes uniy)
Test Number One Two Three Average
General Data
Date 5/12/71 5/13/71 5/13/71
% Isokinetic 92 102 99.6
Boiler Load (% of design) 78 79 79 79
Sample Point Location Inlet of ESP
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
3
g/Nm,-dry
g/Nm -dry (P 12% CO,
gr/dscf £
gr/dscf @ 12% CO,
ng/J c
lb/10b Btu
Average Opacity
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
For WS, pressure drop = "H?0.For ESP, SCA = ftZ/1000 ACFM.
For FF, A/C = ft/min.
C-147
-------
PLANT FE299
TEST SUMMARY SHEETS
(rart'icuiates uniy)
Test Number One
General Data
Date
% Isokinetic
Boiler Load (% of design)
Sample Point Location Outlet of
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C00, dry (%)
Particulate Emissions
3
g/Nm?-dry
g/NmJ-dry @ 12% C00
gr/dscf
gr/dscf @ 12% COo
ng/J ,
lb/10D Btu
Average Opacity -
Control Device
Type , ESP
Operating Parameter
Design Parameter 154
Design Flow Rate (ACFM) 143,000
Two
5/13/71
90
79
ESP
22.9
48.600
358
9.65
9.4
10.0
0.076
0.092
0.033
0.040
35.6
0.0828
260
Three
5/13/71
99.9
79
20.5
43.400
180
356
8.45
9.4
10.0
0.064
0.078
0.028
0.034
30.4
0.0708
297
Average
79
21.7
46.000
180
357
9.0
9.4
10.0
0.070
07085
0.030
0.037"
33.0
0.077"
278
lFor WS, pressure drop = "H?0. For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/min.
C-148
-------
C.I.4 RDF-Fired Boilers
The following facility descriptions and participate emission data
are for RDF-fired boilers. Each site is given a 2-letter plant designation.
The first letter, H, indicates the facility has an RDF-fired boiler.
The second letter indicates the plant. The number after the plant
designation distinguishes between different tests at the same plant.
C-149
-------
PLANT HC100
Tests at boiler No. 1 at Plant HC were conducted by the EPA and MRI
(Midwest Research Institute) to determine the particulate emission rate.
Boiler No. 1 burns mixtures of coal and air classified refuse derived
fuel (RDF) in a pulverized coal-fired boiler rated at 925,000 pounds per
hour of steam. Particulate emissions are controlled by an ESP with a
design SCA of 135 ft2/1000 ACFM.
A total of 10 EPA Method 5 test runs were performed both at the
inlet and outlet of the ESP. These test runs are numbered HC1 through
HC20. The odd numbered test runs were performed at the ESP inlet and
the even test runs at the ESP outlet. The steam production rate during
testing ranged from 64 percent to 96 percent of rated capacity. The
amount of RDF burned ranged from 0 percent to 27 percent by heat input.
The particulate emission rates ranged from 0.054 pounds per million Btu
to 0.115 pounds per million Btu. The SCA during the tests ranged from
82 to 142 ft2/1000 ACFM.
C-150
-------
For tests HC1 through HC20, the fuel analyses were as follows:
Test HC1 & HC2
Coal/RDF
Run 1
Test HC3 & HC4
Coal/RDF
Run 1
Test HC5 & HC6
Coal/RDF
Run 1 Run 2
Test HC7 & HC8
Coal/RDF
Run 1
% H20
%Ashd
% sd
HHVd(Btu/lb)
HHVd(kJ/kg)
% RDF
% H20
% Ashd
% sd
HHVd(Btu/lb)
HHVd(kJ/kg)
% RDF
6.35
6.70
1.35
13,480
31,350
0
Test HC9 &
Coal
Run 1
6.49
6.54
1.33
13,420
31,220
0
6.02/23.2 6.51/39.0 6.48/49.0
7.56/18.5 6.55/12.1 7.87/12.9
1.59/0.17 1.56/0.12 1.61/0.09
13,330/6,830 13,470/7,400 13,240/7,010
31,010/15,890 31,330/17,210 30,800/16,300
9 18 18
6.27/37.8
6.76/13.3
1.47/0.10
13,440/7,050
31,260/16,400
27
HC10 Test HC11 & HC12 Test HC13 & HC14
Coal /RDF Coal /RDF
Run 1 Run 2 Run 3 Run 1
5.96/34.4 6.17/22.3 6.37/34.5
6.86/13.7 7.57/15.7 7.06/14.9
1.46/0.09 1.73/0.12 1.50/0.14
13,400/7,320 13,340/7,120 13,440/7,390
31,220/17,030 31,030/16,560 31,260/17,190
999
6.28/23.6
8.33/17.9
2.80/0.11
13,220/6,950
30,750/16,170
18
-------
% H20
% Ashd
% S
HHVd(Btu/lb)
HHVd(kJ/kg)
% RDF
Test HC15 & HC16
Coal
Run 1
6.60
7.13
1.25
13,410
31,190
0
Test HC17 & HC18
Coal/RDF
Run 1
6.62/22.2
6.26/17.5
1.36/0.16
13,580/7,140
31,590/16,610
9
Test HC19 & HC20
Coal/RDF
Run 1
6.28/20.0
6.78/17.1
1.52/0.11
13,490/7,260
31,380/16,890
18
C-152
-------
PLANT HC1 10°
TEST SUMMARY SHEETS
(farticuiates Only)
Test Number
One
Two
Three
Average
General Data
Date 12/10/73
% Isokinetic 101 _
Boiler Load (% of design) 64_
Sample Point Location Inlet of ESP
% RDF £L
64
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
119.6
2537TO
Particulate Emissions
g/Nm~-dry
g/NmJ-dry 8 12% CO,
gr/dscf i
gr/dscf 8 12% C0«
lb/10 Btu
Average Opacity
3.57
Control Device
Type .
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
1
For WS, pressure drop
For FF, A/C = ft/min.
-K -
"H90, For ESP, SCA = ft /1000 ACFM.
L
C-153
-------
PLANT HC2 10°
TEST SUMMARY SHEETS
(Particuiates Uniy)
Test Number One Two Three Average
General Data
Date 12/10/73
% Isokinetic 102
Boiler Load (% of design) 64 64
Sample Point Location Outlet of ESP
% RDF ~5 ~5 0 Q_
Stack Gas Data
Flow (Nm3/s-dry) 110.G 110.0
Flow (dscfm) 23"Q40 233,040
Temperature (°C) 150 150
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nnu-dry p. 098 0.098
g/Nm^-dry @ 12% C0? Q.Q87 ~O87
gr/dscf * 0.043 ~OJ3
gr/dscf @ 12% C02 0.038 0^038
ny/u c 37.8 37.8
lb/10D Btu O.Q88 ~O88
Average Opacity
Control Device
Type i ESP
Operating Parameter 142
Design Parameter 135
Design Flow Rate (ACFM) 411,500
JFor WS, pressure drop = "FLO. For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/min.
C-154
-------
PLANT HC3100
TEST SUMMARY SHEETS
(farticulates Uniy;
Test Number One Two Three Average
General Data
Date i?/u
% Isokinetic 99.4
Boiler Load (% of design)_64 6*
Sample Point Location Inlet of ESP
% RDF _2 9
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nnu-dry
g/Nm -dry @ 12% CO,
gr/dscf £
gr/dscf 9 12% CO,
ng/J 6
lb/10° Btu
Average Opacity
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
For WS, pressure drop = "H,0. For ESP, SCA = ftZ/1000 ACFM.
For FF, A/C = ft/min. i
C-155
-------
PLANT HC4100
TEST SUMMARY SHEETS
(Particulates Only)
Test Number
One
Two
Three
Average
General Data
Date 12/14
% Isokinefic 100.7
Boiler Load (% of design) 67 I
Sample Point Location Outlet of ESP"
% RDF 9
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C
Temperature (°F
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
106.9
226.506
15?
"Wfi
fi n
Partlculate Emissions
g/Nm^-dry 0.092
g/Nm -dry § 12% C02 0.073
gr/dscf 0.040
gr/dscf @ 12% C0? 0.032
ng/J f. 33.5
lb/10° Btu 0.078
Average Opacity
Q.Q92
0.073
0.040
0.032
33.5
0.078
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
ESP
135
139
411.500
WS, pressure drop = "H,,0. For ESP, SCA = fr/1000 ACFM.
For FF, A/C = ft/min.
C-156
-------
PLANT HC5 10°
TEST SUMMARY SHEETS
(ran.ieuiaces Uniy)
Test Number
General Data
Date
% Isokinetlc
One
12/9/73
~JW
Two Three
12/9/73
97
Boiler Load (% of design)
Sample Point Location
% RDF
Stack Gas Data
Flow (Nm3/s-dry)
Inlet of
_18_
no. 3
Flow (dscfm) 233, /bU
Temperature (°C) isft
Temperature (°F) 317
Moisture (%) IQ.Q
Oxygen, dry (%) 7.0
C02, dry (X)
Particulate Emissions
3
g/Nm.-dry
g/Nm -dry @ 12% CO-
gr/dscf
gr/dscf @ 12% C09
ng/J fi
lb/10° Btu
Average Opacity
Control Device
Tynp
'JHC 1
Operating Parameter*
Design Parameter
Design Flow Rate (ACFM)
i — •
14.5
^51
1.Q7
1 .M
1 .772
41?
ESP
18
175.3
265ZEQBT
ifin
3?n
10.0
6,0
Id.R
4.35
1 Of)
1.S7
1 *5Q1
a.?n
Average
64
18
117.8
249Z5SDZ
159
318
in R
fi.5
14 ,S
4.43
1 94
i fin
1 fiR?
3 91
For WS, pressure drop = UH~Q.For ESP, SCA = ft/1000 ACFM.
For FF, A/C = ft/min. i
C-157
-------
PLANT HC6
100
TEST SUMMARY SHEETS
(Parcicuiates only)
Test Number
One
Two
Three
Average
General Data
Date 12/9/73
% Isokinetic IQQ
Boiler Load (% of design) 64 64
Sample Point Location Outlet nf ESP
% RDF 18 18
fi4
18
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C09> dry (%)
103.6
219.570
158
316
9.0
6.0
14.5
Particulate Emissions
g/Nm?-dry 0.055
g/Nm -dry 9 12% C02 n.Q45
gr/dscf n.n?4
gr/dscf (P 12% C02 n.02n
ng/J 6 c ?1.5
lb/10° Btu n.nsn
Average Opacity
0.069
0.057
n.n.?n
0.025
24.9
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
ESP
135
134
For WS, pressure drop
For FF, A/C = ft/min.
"H20.
For ESP, SCA = ftVlOOO ACFM.
C-158
-------
PLANT HC7 10°
TEST SUMMARY SHEETS
(^articulates Only)
Test Number One Two Three Average
General Data
Date 12/10/73
% Isokinetic 105
Boiler Load (% of design) 64_ 64
Sample Point Location Inlet of ESP
% RDF 27_ 27
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%}
C02> dry (%)
Particulate Emissions
3
g/Nnu-dry
g/Nm -dry 9 12% CO,
gr/dscf *
gr/dscf @ 12% CO,
6
lb/10b Btu
Average Opacity
Control Device
Type .
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
• *
For WS, pressure drop = "H«0. For ESP, SCA = ft /1000 ACFM.
For FF, A/C = ft/min. * -^
C-159
-------
PLANT HC8 10°
TEST SUMMARY SHEETS
{Participates Uniy;
Test Number
One
Two
Three
Average
General Data
Date 12/10/73
% Isokinetic 105 _
Boiler Load (% of design) 64 _
Sample Point Location Outlet of ESP
% RDF 27
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
104.6
221,720
152
Particulate Emissions
g/NmLdry 0.073
g/Nm -dry @ 12% C02 0.060
gr/dscf 0.032
gr/dscf (P 12% C0? 0.026
ng/J 6 26.2
lb/10° Btu 0.061
Average Opacity
0.073
Q.Q6Q
n.03?
n.n?6
26.2
n.nei
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
ESP
T35
140
For WS, pressure drop
For FF, A/C = ft/min.
"H20.
For ESP, SCA = fr/1000 ACFM.
C-160
-------
PLANT HC910°
TEST SUMMARY SHEETS
(Pdrticuiai.es unly)
Test Number One Two Three Average
General Data
Date 12/6/73
% Isokinetic 97.7
Boiler Load (% of design) 80 80
Sample Point Location Inlet
% RDF 0 0_
Stack Gas Data
Flow (Mm /s-dry) 155.0
Flow (dscfm) 309.900
Temperature (°C) 154 2ZZI
Temperature (°F) 309
Moisture (%) 7.-»5
Oxygen, dry (%) 6.6
C02> dry (%) 13.6
Particulate Emissions
g/Nnidry 4.12 _ _ 4.12
g/NmJ-dry @ 12% C02 T63 -
gr/dscf @ 12% C0 ~
R, -¥§1 _ —
Btu 3.68 _ _ 3.fifi
Average Opacity _ _
Control Device
Type
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
por WS, pressure drop = "H«0.For ESP, SCA = ftz/1000 ACFM.
For FF, A/C = ft/min. L
C-161
-------
PLANT HC10100
TEST SUMMARY SHEETS
(Particuiates Uniy)
Test Number One Two Three Average
General Data
Date i?/fi/73
% Isokinetic _LCLL.3
Boiler Load (% of design) Rn 80
Sample Point Location Outlet of ESP
Stack Gas Data
o
Flow (Nm /s-dry) 125.2 125.2
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/NmLdry 0.114 0.114
g/Nm -dry @ 12% C02 n.im 0.101
gr/dscf _JLH50 0.050
gr/dscf 0 12% C02 n.n44 0.044
ng/J K 43. Q 41.9
lb/10° Btu 0.102 0.102
Average Opacity
Control Device
Type , ESP
Operating Parameter1 _
Design Parameter 135
Design Flow Rate (ACFM)
XFor WS, pressure drop = "H«0. For ESP, SCA = ftZ/1000 ACFM.
For FF, A/C = ft/nrfn. * _ ,„
1-lOc
-------
PLANT HC11100
TEST SUMMARY SHEETS
(farucmates Uniy)
Test Number
General Data
Date
% Isokinetic
One
12/13/73
99.1
Two
12/5/73
Three
12/5/73
101
Average
Boiler Load (% of design)
Sample Point Location Inlet of ESP
Stack Gas Data
Flow (Nm3/s-dry) 138.5 149.9 137.4
Flow (dscfm) 29375?0~ 317.530 291,03CT~.
Temperature (°C) 156 158~" 157 ~
Temperature (°F) "3"IT~ "3l5~ "3l4~
Moisture (%) 8.9 O ~"
Oxygen, dry (%) R.Q K n
C02, dry (%) IR.? id.R U.R
Particulate Emissions
3
g/Nm3-drJ « 12% C02 ~3J9 "HI ~Hs "HI
9r/dscf 1.82 1.95 1.84 1.87
gr/dscf 9 12% C02 1.44 1-61 1.52 1.52
lb906Btu
Average Opacity
Control Device
Type
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
For WS, pressure drop = "H,0. For ESP, SCA = ft2/1000 ACFM.
, ,
For FF, A/C = ft/min. z
-------
PLANT HC12 10°
TEST SUMMARY SHEETS
(particuiaces umy)
Test Number
One
Two
Three
Average
General Data
Date 12/13/73 12/5/7.?
% Isokinetic 99.1 99.5
Boiler Load (X of design)_80 80
Sample Point Location Outlet of ESP
% RDF
Stack Gas Data
0
Flow (Nm /s-dry)
Flow (dscfm) 269.
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nm,-dry
g/Nm -dry 9 12% C02
gr/dscf
gr/dscf 9 12% C02
ng/J 6
lb/10D Btu
Average Opacity
-2—
127.2
.620
159
313
8.0
5.9
15.2
0.112
0.008
0.049
0.039
40.8
0.095
_9
121. Q
25g.31Q
153
308
9.3
6.0
14.5
0.128
0.106
0.056
0.046
46.9
0.109
80
122.7
260,1ZQ__
156
313
5.8
14.7
0.136
0.111
0.060
0.049
49.3
0.115
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
ESP
135
"H20.For ESP, SCA = ft2/1000 ACFM.
C-164
113
T
For WS, pressure drop
For FF, A/C = ft/min.
-------
PLANT HC13100
TEST SUMMARY SHEETS
l
tirij latoc flniyl
Test Number One Two Three Average
General Data
Date 12/13/73
% Isokinetic 100.2
Boiler Load (% of design) 80
Sample Point Location Inlet of ESP
% RDF "T5
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%}
Particulate Emissions
3
g/Nnu-dry
g/Nm -dry @ 12% C0?
gr/dscf
gr/dscf 0 12% CO,
ng/J 6 d
lb/10° Btu
Average Opacity
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
For WS, pressure drop = "H.,0. For ESP, SCA = ftZ/1000 ACFM.
C/\M CC A If _ £JL. /_J _ t.
For FF, A/C = ft/min.
C-165
-------
PLANT HC14 10°
TEST SUMMARY SHEETS
'' '•'?. rti cu! 2tss On!w'
Test Number One Two Three Average
General Data
Date 12/13/73
% Isokinetic "ISO
Boiler Load (% of design)~5D~
Sample Point Location Outlet of ESP
% RDF 18
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nm^-dry 0.146 0.146
g/Nm -dry @ 12% C0? 0.132 IE22
gr/dscf 0.064 ~OS4
gr/dscf @ 12% CO, 0.058 ~O?8
ng/J , ^ 53.8 ZSI8
lb/10° Btu 0.125 HTTZ5
Average Opacity
Control Device
Type l —
Operating Parameter1 110
Design Parameter 135
Design Flow Rate (ACFM)
WS, pressure drop = "H^O.For ESP, SCA = ft/1000 ACFM.
For FF, A/C = ft/min. c
C-166
-------
PLANT HC15 10°
TEST SUMMARY SHEETS
i' Paffiri' latoc fin i \/ 1
— • w-Vrw •* ^ *• — i* • * • •
Test Number
One
Two
Three
Average
General Data
Date 12/13/73
% Isoldnetic 96.8
Boiler Load (% of design) 96
Sample Point Location Inlet of ESP
% RDF 0
96
Stack Gas Data
Flow (Nm /s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
Particulate Emissions
g/Nm?-dry 4.39
g/NmJ-dry @ 12% C02 3.61
gr/dscf 1.92
gr/dscf @ 12% C02 1.58
ng/J fi 1.600
lb/10b Btu 3.72
Average Opacity -
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
For WS, pressure drop
For FF, A/C - ft/min.
"H20. For ESP, SCA
C-167
fr/iooo ACFM.
-------
PLANT HC16100
TEST SUMMARY SHEETS
I Pa rfi ni I a toe On i >/l
.. _..._a, '••
-------
PLANT HC17100
TEST SUMMARY SHEETS
(ParticuIstss Oniy)
Type .
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
Test Number One Two Three Average
General Data
Date 12/11/73
% Isokinetic 95.5
Boiler Load (% of design) 96
Sample Point Location Inlet of ESP
% RDF 9
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C09, dry (%}
Particulate Emissions
g/Nm--dry
g/NmJ-dry @ 12% C09
gr/dscf i
gr/dscf @ 12% CO,
ng/J s Z
lb/10b Btu
Average Opacity
Control Device
For WS, pressure drop = "H90. For ESP, SCA = ft /1000 ACFM.
For FF, A/C = ft/min. *
C-169
-------
PLANT HC18100
TEST SUMMARY SHEETS
('Pa^tirij IgfJS Op!vl
Test Number
General Data
Date
% Isokinetic
Boiler Load (% of design)^
Sample Point Location
% RDF
One Two
12/11/73
99.0
96
Outlet of ESP
Three Average
96
9
Stack Gas Data
Flow (Mm /s-dry) U/LR 144 3
Flow (dscfm) 30fi^68JL 2Q6^£BQ-
Temperature (°C) ififi i^
Temperature (°F) 312 3|?
Moisture (%) 8.0 R n
Oxygen, dry (%) 5.R * R
C02, dry (%) 13.5 13.s
Particulate Emissions
g/NmLdry 0.100 0.100
g/Nm -dry
-------
PLANT HC19100
TEST SUMMARY SHEETS
''•'artleuIstss Oniy,1
Test Number One Two Three Average
General Data
Date 12/12/73
% Isokinetic 97.4
Boiler Load (% of design) 96 96
Sample Point Location Inlet of ESP
% RDF 18 18
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
3
g/Nm~-dry
g/Nm -dry @ 12% C02
gr/dscf
gr/dscf § 12% CO,
ng/J 6 i
lb/10b Btu
Average Opacity
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
y 5
For WS, pressure drop * "H«0. For ESP, SCA = ft /1000 ACFM.
For FF, A/C = ft/min. i
C-171
-------
PLANT HC20
100
TEST SUMMARY SHEETS
r'ti ci!! 2tss On!wt
Test Number
One
Two
Three
Average
General Data
Date 12/12/73
% Isokinetic 98.4 ~
Boiler Load (% of design) 96
Sample Point Location Outlet of ESP"
% RDF ~~I8
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
Particulate Emissions
3
g/Nnu-dry
g/Nm -dry @ 12% CO,
gr/dscf *
gr/dscf @ 12% C09
lb/10 Btu
Average Opacity
0.142
Q.I 09
0.062
0.048
49.4
0/L
n IA?
n ino
n nfi9
n OAR
O.Q a.
n.ns
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
ESP
135
97
For WS, pressure drop
For FF, A/C = ft/min.
"H20. For ESP, SCA = ft'/lOOO ACFM.
C-172
-------
PLANT HD101
Boiler #1 at Plant HD was tested to determine the participate
emission rate. Boiler No. 1 is a spreader stoker cofired with coal and
pelletized RDF. The boiler rated capacity is 45,000 pounds per hour of
steam. Particulate emissions are controlled by a mechanical collector.
Five EPA Method 5 test runs were performed at four levels of RDF
usage ranging from 26 percent to 100 percent. One test run is not
presented due to incomplete data. The boiler load ranged from 31 percent
to 56 percent of rated capacity. The particulate emission rate ranged
from 0.43 to 1.0 pounds per million Btu.
1 2
For tests HD1, HD2, and HD3, the fuel analyses were as follows: '
%H20
%Ashd
Q
Q
HHVd(Btu/lb)
HHVd(kJ/kg)
% RDF
Test
Run 1
5.37
11.57
0.98
1.15
11,169
25,980
28
HD1
Run 2
5.44
11.90
0.86
1.00
10,785
25,090
24
Test HD2
Run 1
5.10
15.12
0.63
1.07
10,433
24,270
53
Test HD3
Run 1
5.93
14.16
0.35
0.72
8,649
20,120
100
Subscript 'd1 designates dry basis.
2
The fuel analyses are combined averages of coal and RDF.
C-173
-------
PLANT HD1101
TEST SUMMARY SHEETS
(^articulates Oniy)
Test Number One Two Three Average
General Data
Date 8/10/76 8/11/76
% Isokinetic 103 ipg
Boiler Load (% of design) 59 52 5fi
Sample Point Location Outlet of MC
% RDF 2£ 24 26
Stack Gas Data
Flow (Nm3/s-dry) 4.6
Flow (dscfm) 9.830
Temperature (°C) 250
Temperature (°F) 482
Moisture (%) 6.5
Oxygen, dry (%) 5.0
C02, dry (%) 12.4
Particulate Emissions
g/Nm^-dry 1.711 0.643 1.177
g/NmJ-dry 9 12% C02 1.656 0.613 1.134
gr/dscf *- n.748 0.281 0.514
gr/dscf (P 12% C0? Q.724 0.268 0.496
ng/J fi ' 584.8 227.5 406.1
lb/10° Btu 1.36 0.529 0.945
Average Opacity
Control Device
Type , MC.
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
For WS, pressure drop = "H«0. For ESP, SCA = ft /1000 ACFM.
For FF, A/C = ft/min. *
C-174
-------
PLANT HD2 101
TEST SUMMARY SHEETS
lates Oni1
Test Number
General Data
One Two
Date 8/10/76
% Isokinetic 107
Boiler Load (% of design) 54
Sample Point Location Outlet of MC
% RDF
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm) i
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/Nm~-dry
g/Nm -dry 9 12% C02
gr/dscf
gr/dscf @ 12* C02
ng/J K
lb/10D Btu
Average Opacity
Control Device
Type .
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
••i
53_
4.9
o.wi
?Rn
aa?
fi.n
11.6
0.972
ITOOT"
0.440
352.6
0.82
MC
Three Average
ZZZ 54
53
4.9
lo^
482
7.2
6.0
0.972
1.007
0.425
0.440
352.6
0.82
For WS, pressure drop
For FF, A/C = ft/min.
"H.,0. For ESP, SCA
i
C-175
ftZ/1000 ACFM.
-------
PLANT HD3 101
TEST SUMMARY SHEETS
(^articulates Oniy)
Test Number One Two Three Average
General Data
Date 8/10/76
% Isokinetic 107
Boiler Load (% of design) 31
Sample Point Location Outlet of MC
% RDF "TOT
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%) __i__
C02, dry (%) 10.0 TO"
Particulate Emissions
g/Nm--dry 0.439 0.439
g/Mm -dry @ 12% C02 Q.526 OT52T"
gr/dscf * n.192 OTT9T"
gr/dscf @ 12% C0? 0.230 0.230
ng/J 6 c 173.3
lb/10° Btu 0.403
Average Opacity
Control Device
Type . MC_
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
Tor WS, pressure drop = "H«0. For ESP, SCA = ft2/1000 ACFM.
For FF, A/C = ft/min. *
C-176
-------
PLANT HE102
Boiler No. 3 at Plant HE was tested to determine the participate
emission rate. Boiler No. 3 is a spreader stoker rated at 35,000 pounds
per hour of steam. It burns coal and pelletized RDF. Particulate
emissions are controlled with a mechanical collector.
Four EPA Method 5 tests were run at four levels of RDF ranging from
0 percent to 40 percent (heat input basis). The particulate emission
rate ranged from 0.494 to 1.22 pounds per million Btu. The RDF had an
average composition of 6.36 percent moisture, 28.54 percent ash and a
heating value of 6068 Btu/lb.
For tests HE1, HE2, HE3, and HE4, the fuel analyses were as follows:1'2
Test HE1 Test HE2 Test HE3 Test HE4
% H20
%Ashd
Q
Q
HHVd (Btu/lb)
HHVd(kJ/kg)
T
% RDF
24.89
9.97
0.93
0.96
11,948
27,790
' 0
18.40
14.85
0.80
0.94
10,482
24,380
20
17.42
16.42
0.92
0.92
10,023
23,300
30
11.86
23.64
0.57
0.88
8,237
19,160
40
Subscript 'd' designates dry basis.
The fuel analyses are combined averages of coal and RDF.
C-177
-------
PUNT HE!
102
TEST SUMMARY SHEETS
I a foe On i v \
Test Number
One
Two
Three
Average
General Data
Date 6/4/76
% Isokinetic loo
Boiler Load (% of design) 58
Sample Point Location Outlet of MC
% RDF 0
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%}
Oxygen, dry (%)
CO,, dry (%)
7.3
15.400
268
Particulate Emissions
g/Nm--dry
g/NirT-dry @ 12% C09
gr/dscf *
gr/dscf 9 12% CO-
ng/J 6 *
lb/10° Btu
Average Opacity
0.496
07627"
072TT^
0.274
243.4
0.566
0.496
0.62/
0.217
0.274
243.4
0.566
Control Device
Type ,
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
MC
For WS, pressure drop
For FF, A/C = ft/min.
"H20. For ESP, SCA = fr/1000 ACFM.
C-178
-------
PLANT HE2 102
TEST SUMMARY SHEETS
i* PA rrinj I atac On i \/ i
\ • -*• -•—-*• — - — - -* • • w /
Test Number One Two Three Average
General Data
Date 6/3/76
% Isokinetic 105
Boiler Load (% of design)6T"
Sample Point Location Outlet of MC
% RDF 20
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/NmLdry 0.616 0.616
g/Nm°-dry @ 12% C02 0.778 0.778~
gr/dscf 0.269 Q.269
gr/dscf @ 12% C02 0.340 0.340
ng/J fi 297 297
lb/10° Btu 0.691 Q.W"
Average Opacity
Control Device
Type . M£
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
T "-—' ! 5
For WS, pressure drop = "H90. For ESP, SCA = ft /1000 ACFM.
For FF, A/C = ft/min. ^
C-179
-------
PLANT HE3 102
TEST SUMMARY SHEETS
latgc (In i y I
Test Number
One
Two
Three
Average
General Data
Date 6/4/76
% Isokinetic 96
Boiler Load (% of design)~5T"
Sample Point Location Outlet of MC
% RDF 30
52
30
Stack Gas Data
Flow (Nm /s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
Particulate Emissions
g/Nnu-dry
g/NmJ-dry @ 12% CO,
gr/dscf *
gr/dscf @ 12% CO,
ng/J 6
lb/10° Btu
Average Opacity
0.366
0.531
n.160
0.232
212.4
0.494
0.366
0.531
0.160
0.232
212.4
0.494
Control Device
Type .
Operating Parameter*
Design Parameter
Design Flow Rate (ACFM)
MC
LFor WS, pressure drop = "H«0.
For FF, A/C = ft/min. ^
For ESP, SCA
L-IoU
= ftVlOOO ACFM.
-------
PLANT HE4
102
TEST SUMMARY SHEETS
(^articulates OniyJ
Test Number
. One
Two
Three
Average
General Data
Date 6/3/76
% Isokinetic 102
Boiler Load (% of design) 61
Sample Point Location Outlet of MC
% RDF 40
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
Particulate Emissions
g/NmLdry 1.QQ9
g/Nm^-dry 9 12% C02 1.361
gr/dscf n.44i
gr/dscf @ 12% C02 p.595
lb/106 Btu 1.22
Average Opacity
Control Device
Type .
Operating Parameter
Design Parameter
Design Flow Rate (ACFM)
MC
T
For WS, pressure drop
For FF, A/C = ft/min.
"H20. For ESP, SCA
C-181
ft2/1000 ACFM.
-------
PLANT HF103-105
Boiler No.l at Plant HF was tested to determine compliance with the
state of New York emission standards. Boiler No.l is a RDF-fired spreader
stoker rated at 200,000 pounds per hour of steam. Particulate emissions
are controlled by a bank of 12 cyclones followed by an electrostatic
p
precipitator. The ESP has 49,600 ft of collection area and is sized
for a gas flow rate of 200,000 ACFM.
The boiler fuel is RDF produced by a wet pulping process. This
fuel provided 100 percent of the heat input during testing. The fuel
was not analyzed during testing. However, analyses of fuel samples
collected monthly showed the following average composition:
% H20 - 50-52
% Ash. - 16.2
d
% S . - 0.97
d
% N . - 0. 66
d
% HHVd (Btu/lb) - 8138
% HHVd (kJ/kg) - 18,930
Three EPA Method 5 particulate test runs were performed. The average
boiler load during testing was 80.4 percent. The average particulate
emission rate for the three runs was 0.066 pounds per million Btu.
Subscript 'd1 designates dry basis.
C-182
-------
PLANT HF1
105
TEST SUMMARY SHEETS
(Participates Only)
Test Number
One
Two
Three
Average
General Data
Date 4/30/79
% Isok1net1c 102.7
Boiler Load (% of design) 91.5
Sample Point Location ESP Outlet
5/1/79
107.6
77.2
80.4
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
CO,, dry (%)
Particulate Emissions
g/Nm?-dry 0.125 0.038
g/Nm -dry (? 12% C0« 0.143 0.054
gr/dscf * 0.0548 0.0168
gr/dscf @ 12% CO, 0.0626 0.0237
ng/J f. * 42.6 17.2
lb/10° Btu 0.099 0.040
Average Opacity
0.056
0.080
0.0244
0.0349
25.4
0.059
0.073
0.092
0.0320
0.0404
28.4
0.066
Control Device
Type
Operating Parameter-1
Design Parameter
ESP
288
248
Design Flow Rate (ACFM) 200.QQQ
343
347
326
For WS, pressure drop
For FF, A/C = ft/min.
"H20.
For ESP, SCA = fr/1000 ACFM.
C-183
-------
PUNT HG106'107
Plant HG was tested as part of an experimental program to determine
the effects of cofiring densified RDF and coal in a boiler originally
designed to fire coal alone. The boiler is a traveling grate spreader
stoker rated at 150,000 pounds per hour of steam. The particulate
emissions are controlled by a multiclone followed by an ESP- Flyash
collected by the multiclone is reinjected into the boiler. The ESP was
2
designed for a gas flow of 133,000 acfm and has 25,056 ft of collection
area.
The test data shown is the emission rate after the ESP. The test
runs have been grouped into four sets (HG1 - HG4).
Test HG1 consisted of 4 Method 5 runs while firing 100 percent
coal. The average load factor was 95 percent. Particulate emissions
were extremely variable, and averaged 0.51 pounds per million Btu. The
2
average SCA for the ESP was 184 ft /I000 acfm.
During Test HG2 densified RDF was cofired with the same type of
coal fired in test HG1 at an average load factor of 84 percent. There
were three Method 5 runs in this test. The percentage of RDF was 25-
26 percent (heat input basis). Particulate emissions were again variable
but averaged 0.52 pounds per million Btu. The average SCA for the ESP
was 186 ft2/1000 acfm.
C-184.
-------
During Test HG3 the boiler fired coal with a lower ash and sulfur
content than the coal fired in tests HG1 and HG2. A total of six Method
5 runs were performed. Particulate emissions were not as variable
during this test and averaged 0.15 pounds per million Btu.
Test HG4 consisted of fourteen Method 5 runs. Densified RDF was
cofired with the same type of coal fired in test HG3. The RDF was from
a different source and had a lower ash and sulfur content than the RDF
fired in Test HG2. The percentage of RDF varied from 23 to 51 percent
of the fuel heat input. Particulate emissions were again extremely
variable but averaged 0.16 pounds per million Btu. The average load
2
factor during testing was 91 percent and the average SCA was 192 ft /1000
acfm.
The average compositions of the fuels fired during testing were:
Tests HG1 & HG2 Tests HG3 & HG4
Coal/RDF Coal/RDF
% H20 8.0/21.7 5.4/32.8
% Ashd 16.9/30.7 10.8/13.8
% Sd 5.46/0.43 1.98/0.23
% Nd 1.04/0.59 1.24/0.37
HHVd (Btu/lb) 12,098/6,755 12,866/8,123
HHVd (kJ/kg) 28,140/15,712 29,926/18,894
Subscript 'd1 denotes dry basis.
C-185
-------
PLANT HG1106'107
TEST SUMMARY SHEETS
(Participates Only)
Test Number
General Data
Date
% Isokinetic
One
3/8/79
Two
3/8/79
Boiler Load (% of design) 96 95
Sample Point Location Outlet of FSP
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%}
Oxygen, dry (%}
C02, dry (%)
Particulate Emissions
g/Nm~-dry
g/Nm -dry 9 12% C07
gr/dscf c
gr/dscf 9 12* C02
ng/J *
lb/10° Btu
Average Opacity
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
38.6
81.799
209
408
4.2
inr"
HH
0.650
0.876
0.284
0.383
301
0.70
MC/ESP
181
188
133,000
38.6
81.765
209
409
47T~
9.0
Q 1
O • X
0.270
0.400
0.118
0.175
133
0.31
181
Three Average
3/9/79
94
36.9
78.103
211
412
4.8
9.1
8.9
Q44R
0.604
0.196
0-264
219
0.51
192
lFor WS, pressure drop - "H«0. For ESP, SCA
For FF, A/C = ft/min. L
ftz/1000 ACFM.
C-186
-------
PLANT HG1
106,107
TEST SUMMARY SHEETS
(Particulates Only)
Test Number
One
Two
Three
Average
General Data
Date 3/9/79
% Isokinetic
Boiler Load (% of design
Sample Point Location Outlet of ES
95
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
g/NmLdry
g/Nm -dry @ 12% C02
gr/dscf
gr/dscf @ 12% C0«
ng/J fi
lb/10° Btu
Average Opacity
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
39.0
82.645
217
422
3.3
9.8
~O"
0.432
0.583
0.189
0.255
~22T
0.52
MC/ESP
1BU
188
133,000
,.
38.3
81.078
212
413
4.2
9.1
8.7
0.451
0.622
0.197
0.272
219
0.51
184
lFor WS, pressure drop - "H,0. For ESP, SCA
For FF, A/C = ft/min.
= ft/1000 ACFM.
C-187
-------
PLANT H62 106>107
TEST SUMMARY SHEETS
f pa v*-f"i/*ii1 a 4-p** rt« 1 »»\
^ t a i w 11* u i d w c o vti • jr /
Test Number
General Data
Date
% Isokinetic
One
3/15/79
Two
3/16/79
Boiler Load (% of design) 89 81
Sample Point Location
% RDF
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
3
g/Nm--dry
g/Nm -dry § 12% C07
gr/dscf c
gr/dscf @ 12% CO,
ng/J 6 z
lb/10b Btu
Average Opacity
Control Device
Type .
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM)
Outlet of
26
37.4
79.235
192
377
1.7
10.7
a.n
0.108
0.160
0.047
0.070
60.2
0.14
MC/ESP
182
188
133,000
ESP
25
35.6
75.509
194
381
6-1
11.0
7.8
0.414
0.636
0.181
0.278
245
0.57
194
Three
3/16/79
82
25
38.5
81.490
196
384
5.7
10. 9
7.8
0.616
0.947
0.269
0.414
361
0.84
182
Average
84
25
37.2
78,745
194
381
4-5
10.9
7.9
0.380
0.577
0.166
0.252
224
0.52
186
!
For WS, pressure drop = "H^O. For ESP, SCA
For FF, A/C = ft/min. c
ftVlOOO ACFM.
C-188
-------
PLANT HG3106'107
TEST SUMMARY SHEETS
(Participates Only)
Test Number
General Data
Date
% Isokinetic
One
5/16/79
Two
5/16/79
Boiler Load (% of design) 92 96
Sample Point Location Outlet of ESP
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
3
g/Nnu-dry
g/Nm-dry 0 12% C02
gr/dscf
gr/dscf @ 12% C0?
ng/J 6
lb/10° Btu
Average Opacity
Control Device
Type .
Operating Parameter-
Design Parameter
Design Flow Rate (ACFM)
For WS, pressure drop
CAM CC A IT — £4-/»J«
44.8
94T944
207
405
37?
11.1
~ O
0.130
0.185
0.057
0.081
73.1
0.17
MC/ESP
158
188
133,000
= "H20. For
44.6
94,488
201
3~9l
4.0
ITT
mr
0.133
0.188
0.058
0.082
77.4
0.18
161
ESP, SCA
Three Average
5/17/79
»
93
37.2
78.843
206
40T~
4.8
TO
"""O
0.108
0.144
0.047
0.063
60.2
0.14
182
= ft2/ 1000 ACFM.
C-189
-------
PLANT H63 106'107
TEST SUMMARY SHEETS
(Participates Only)
Test Number
One
Two
Three
Average
General Data
Date
% Isokinetic
Boiler Load (% of design) 95
Sample Point Location Outlet of ESP
9.4
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Particulate Emissions
3
g/Nnu-dry
g/Nm-dry @ 12% CO-
gr/dscf
gr/dscf @ 12% CO,
ng/J fi i
lb/10b Btu
Average Opacity
n.ii7
0.158
0.051
0.069
60.2
0.14
Q.Q98
0.043
0.058
55.9
0.13
MC/ESP
Control Device
Type .
Operating Parameter-1
Design Parameter .„„
Design Flow Rate (ACFM) 133.000
isi
191
185
176
1For WS, pressure drop = "H?0. For ESP, SCA
For FF, A/C = ft/m1n.
ftz/1000 ACFM.
C-190
-------
PLANT HG4106*107
TEST SUMMARY SHEETS
(Particulates Only)
Test Number One
General Data
Date 4/19/79
% Isoklnetic
Boiler Load (% of design)lJ7. _
Two
4/19/79
84
Three Average
4/20/79
80
Sample Point Location Outlet of ESP
% RDF 34
Stack Gas Data
Flow (Nm3/s-dry) 35.5
Flow (dscfm) 75,269
Temperature (°C) 209
Temperature (°F) 409
Moisture (%) 5.8
Oxygen, dry (%) 9.9
C02, dry (%) 9.1
Particulate Emissions
g/Nm«-dry (L032
g/NmJ-dry 9 12% CO, n.04i
gr/dscf 0.014
gr/dscf (P 12% C0« 0.018
nq/J f " 17.2
lb/10u Btu 0.04
Average Opacity _
Control Device
Type MC/ESP
Operating Parameter1 197
Desiqn Parameter
Design Flow Rate (ACFM)
34
32.5
68,920
216
420
7.2
9.7
_L-1
0.021
Q.Q2B
0.009
0.012
12.2
0.03
191
34
35.1
74,433
207
404
7.9
11.0
_M.
0.028
0.039
0.012
0.017
17.2
0.04
205
For WS, pressure drop - "H,0. For ESP, SCA
For FF, A/C = ft/m1n.
ftVlOOO ACFM.
C-191
-------
PLANT HG4106'107
TEST SUMMARY SHEETS
(Participates Only)
Test Number
General Data
Date
% Isok1net1c
One
4/20/79
Boiler Load (% of design) 91
Sample Point Location
% RDF
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (%)
C02, dry (%)
Partlculate Emissions
g/Nnu-dry
g/Nm -dry 0 12% CO,
gr/dscf
gr/dscf i 12% C0«
ng/J g
lb/10° Btu
Average Opacity
Control Device
Type ,
Operating Parameter-1
Design Parameter
Design Flow Rate (ACFM)
Two
4/24/79
80
Three Average
4/24/79
96
Outlet of £SP
31
36.8
77,988
ZOO"
392
7.2
"ToTT
-grr
0.037
JLQ48
0.016
0.021
17.2
0.04
MC/ESP
193
188
36
3fi n
76.283
199
390
7.5
10.6
"O"
JLQ23
JLD30
0.010
0.013
JL2.9
0.03
202
32
-VLSI
80.519
204
399
7.4
10.3
9.2
GJ121
o.n?a
0.009
muz
12.9
0.03
197
WS, pressure drop - "H70. For ESP, SCA - ft2/1000 ACFM.
For FF, A/C - ft/m1n. c
C-192
-------
PLANT HG4 106,107
TEST SUMMARY SHEETS
(Participates Only)
Test Number
One
Two
Three
Average
General Data
Date 4/25/79
% Isok1net1c
Boiler Load (% of designPST" 95
Sample Point Location Outlet of ESP
% RDF -~32W
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry («)
CO,, dry («)
35.6
75.515
189
373
8.2
9.2
3Q.i
82rQ?3
191
376
6.4
11.2
8.4
191
376
6-Q
10.2
9.3
Partlculate Emissions
g/Nm,-dry
g/Nm-dry 9 12% CO,
gr/dscf i
gr/dscf § 12% CO,
ng/J 6 z
lb/10& Btu
Average Opacity
0.032
0.041
JLlfiJ
0.238
0.073
98.9
0.23
0.076
Q.QQft
0.033
0.043
38.7
0.09
Control Device
Type
Operating Parameter1
Design Parameter
Design Flow Rate (ACFM) 133.000
HC/ESP
207
188
176
181
T
For HS, pressure drop • "H,0. For ESP, SCA
For FF, A/C - ft/nrin. i
ft2/1000 ACFM.
C-193
-------
PLANT HG4 106'107
TEST SUMMARY SHEETS
(Participates Only)
Test Number
General Data
Date
% Isoklnetic
One
5/9/79
Boiler Load (% of design) 104
Sample Point Location
% RDF
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (%)
Oxygen, dry (?)
C02, dry («)
Participate Emissions
g/NmLdry
g/Nm -dry % 12% C07
gr/dscf £
gr/dscf 0 12Z CO,
ng/J 6 Z
lb/10° Btu
Average Opacity
Control Device
Type .
Operating Parameter*
Design Parameter
Design Flow Rate (ACFM)
1For WS, pressure drop •
•» - r-»- * if* f*. t—^A—.
Outlet of
35
30 .0
8?, 61?
198
388
7.9
10.2
9.1
0.044
0.057
0.019
0.025
2L.5
0.05
MC/ESP
181
iftfl
133.000
"H20. For
Two
5/10/79
86
ESP
37
•^R a
82,273
201
394
.7,0
10.1
8.5
0.060
0.085
0.026
0.037
34.4
0.08
182
ESP, SCA «
Three Average
5/10/79
100
23
37 R
79,545
201
394
7.2
9.6
9.2
0.172
GL224_
0.075
0.098
86.0
0.20
184
ft2/1000 ACFM.
C-194
-------
PLANT HG4106.10?
TEST SUMMARY SHEETS
(Partlculates Only)
Test Number
One
Two
Three
Average
General Data
Date 5/11/79 5/11/79
% Isokinetlc
Boiler Load (% of design) 95 92
Sample Point Location Outlet of ESP
% RDF 51 51
91
36
Stack Gas Data
Flow (Nm3/s-dry)
Flow (dscfm)
Temperature (°C)
Temperature (°F)
Moisture (Z)
Oxygen, dry (%)
CO,, dry (%)
Partlculate Emissions
g/NmLdry
g/NmJ-dry 9 12% CO-
gr/dscf c
gr/dscf 3 12* CO,
ng/J , z
lb/10b Btu
Average Opacity
0.126
0.167
0.055
0.073
68.8
0.16
Control Device
Type MC/ESP
Operating Parameter1 igg
Design Parameter isft
Design Flow Rate (ACFM) 133.000
18ft
1Q?
For HS, pressure drop « "H,0. For ESP, SCA
For FF, A/C = ft/nrin. c
ft/1000 ACFM.
C-195
-------
C.2 VISIBLE EMISSIONS DATA
In this section opacity data collected in accordance with EPA Method 9
procedures from various nonfossil fuel fired facilities are presented. Most
of the data are from tests conducted by EPA to aid in the development of New
Source Performance Standards. The data are summarized by six minute
averages. For each facility, general data such as boiler type, rated steam
capacity, and control device type and operating parameters are presented
with the opacity data.
Some of the following Method 9 tests were conducted simultaneously with
the Method 5 tests reported in Section C.I. When this is the case the
Method 5 test is identified in the footnotes of the data tables. If no
corresponding Method 5 test is identified, the Method 9 test was not
conducted simultaneously with the Method 5 test shown in Section C.I, or no
Method 5 test data is available for this site.
-------
SUMMARY OF VISIBLE EMISSIONS
PLANT AEa'b
Test Date: 11/12/80
Boiler Type
Boiler Capacity (Ib steam/hr)
Boiler Load (% of capacity)
Control Devi ce
Design Pressure Drop ("H20")
Operating Pressure Drop ("H20")
Fuel
Spreader Stoker
120,000
88
Venturi Wet Scrubber
6-8
6-8
80% bark/20% sawdust and wood trim
Average Opacity (%)
Time Period
(minutes)
0-5
6-11
12-17
18-23
24-29
30-35
36-41
42-47
48-53
54-59
Average all sets:
Set 1
13.8
14.8
15.0
15.4
16.5
15.6
16.0
16.7
17.7
17.9
17.1
Set 1
(cont'd)
17.3
16.2
17.9
18.3
15.6
16.3
17.7
17.3
15.4
15.0
Set 1
(cont'd)
19.0
22.1
19.6
16.9
16.3
17.5
16.3
20.0
17.7
20.0
Tested by the EPA.
Reference 108-110.
C-197
-------
SUMMARY OF VISIBLE EMISSIONS
PLANT AFa'b
Test Date: 11/10/80
Boiler Type
Boiler Capacity (Ib steam/hr)
Boiler Load (% of capacity)
Control Device
Design Pressure Drop ("H20")
Operating Pressure Drop ("HgO
Fuel
Spreader Stoker
120,000
78
Impingement Wet Scrubber
6-8
5.2
90% bark/10% wood trim
Average Opacity (%)
Time Period
(minutes)
0-55
6-11
12-17
18-23
24-29
30-35
36-41
42-47
48-53
54-59
Average all sets:
Set 1
25.0
24.6
23.5
22.7
24.8
25.0
24.2
24.2
19.8
19.4
22.9
Set 1
(cont'd)
19.2
19.8
19.4
19.4
20.0
24.0
25.0
26.9
24.8
24.0
Set 1
(cont'd)
24.4
24.4
22.7
20.2
25.6
24.6
24.8
22.1
20.8
21.3
aTested by the EPA.
Reference 111-113.
C-198
-------
SUMMARY OF VISIBLE EMISSIONS
PLANT BAa'b
Test Date: 11/11/80
Boiler Type - Spreader Stoker
Boiler Capacity (15 steam/hr) - 110,000
Boiler Load (% of capacity) - 78
Control Device - ESP
Design SCA (ft2/1000 ACFM) - 177
Fuel - Bark
Average Opacity (%)
Time Period
(minutes) Set 1 Set 1 Set 1
(cont'd) (cont'd)
0-5 0.0 0.0 0.0
6-11 0.0 0.0 0.0
12-17 0.0 3.3 0.0
18-23 0.0 0.0 0.4
24-29 0.0 3.5 3.3
30-35 0.0 0.0 0.0
36-41 0.0 0.8 0.0
42-47 0.0 1.3 0.0
48-53 0.6 1.7 0.0
54-59 0.0 0.6 6.5
Average all sets: 0.5
aTested by the EPA.
Reference 114-115.
C-199
-------
SUMMARY OF VISIBLE EMISSIONS
PLANT BCa'b
ro
o
o
Emission Source: Stack
Test Date: 11/19-22/80
Boiler Type
Boiler Capacity (Ib steam/hr)
Boiler Load (% of capacity)
Control Devices
Design Air-to-Cloth Ratio
Air-to-Cloth Radio During Testing
Fuel
- Dutch Oven
- 150,000 (three 50,000 units)
- 91
- MC/FF
- 3.64
- 2.98
- Salt-laden Hog Fuel
Average Opacity (%)
Time Period
(minutes)
0-5
6-11
12-17
18-23
24-29
30-35
36-41
42-47
48-53
54-59
Average of all
Set 1
7.7
9.0
8.8
7.9
9.4
6.5
5.4
9.6
10.0
13.5
sets:
Set 1
(cont'd)
11.5
12.5
11.0
9.8
10.0
8.8
9.4
9.4
8.8
11.9
3.8
Set 1
(cont'd)
10.6
6.9
11.3
11.7
10.4
6.5
8.3
5.2
6.3
7.3
Set 2
1.5
2.1
2.3
2.1
1.7
0.8
0.0
0.6
0.2
2.1
Set 2
(cont'd)
0.6
0.6
2.9
2.9
2.1
1.9
0.8
0.0
4.2
2.3
Set 2
(cont'd)
1.7
1.9
1.7
6.0
8.8
7.7
4.2
0.6
1.9
0.0
Set 3
0.0
0.0
0.0
0.0
0.0
0.0
0.6
0.0
2.5
0.0
Set 3
(cont'd)
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Set 3
(cont'd)
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Tested by the EPA simultaneously with test BC2.
Reference 116.
-------
SUMMARY OF VISIBLE EMISSIONS
PLANT BH
,a,b
o
Emission Point: Riverside ESP
Test Date: 9/24-25/80
Boiler Type
Boiler Capacity (Ib steam/hr)
Boiler Load (% of capacity)
Control Devices ,
Design SCA (ft2/1000 ACFM)
Operating SCA during testing (ft2/1000 ACFM)
Fuel
Boiler #4
- Pulverized Coal
- 140,000
- 48
- MC/fSP
- 460
- 486
- Coal
Boiler #5
- Spreader Stoker
- 200,000
- 88
- MC/ESP
- 460
- 420
- Bark
Average Opacity (%}
Time Period
(minutes)
0-5
6-11
12-17
18-23
24-29
30-35
36-41
42-47
48-53
54-59
Average of all
Set 1
0.0
0.0
0.0
0.0
0.4
0.0
0.0
0.0
0.0
0.0
sets : 0. 1
Set 1
(cont'd)
0.0
0.0
0.0
1.6
0.0
0.0
0.0
0.0
0.0
0.0
Set 1
(cont'd)
0.0
0.0
Set 2
1.7
1.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Set 2
(cont'd)
0.0
0.0
0.0
0.0
0.0
Set 3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Set 3
(cont'd)
0.0
1.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Set 3
(cont'd)
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
aTested by the EPA simultaneously with test BH6.
bReference 117.
-------
SUMMARY OF VISIBLE EMISSIONS
PLANT BH
a,b
o
ro
o
ro
Emission Point: Trackside ESP
Test Date: 9/24-25/80
Boiler Type
Boiler Capacity (Ib steam/hr)
Boiler Load (% of capacity)
Control Devices
Design SCA (ft2/1000 ACFM)
Operating SCA during testing (ft2/1000 ACFM)
Fuel
Boiler #4
- Pulverized Coal
- 140,000
- 48
- MC/ESP
- 460
- 486
- Coal
Boiler #5
- Spreader Stoker
- 200,000
- 88
- MC/ESP
- 460
- 420
- Bark
Average Opacity (%)
Time Period
(minutes)
0-5
6-11
12-17
18-23
24-29
30-35
36-41
42-47
48-53
54-59
Average of all
Set 1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1.5
0.0
0.2
sets : 0. 1
Set 1
(cont'd)
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Set 2
4.6
0.2
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Set 2
(cont'd)
0.0
0.0
0.0
0.0
0.0
Set 3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Set 3
(cont'd)
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Set 3
(cont'd)
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Tested by the EPA simultaneously with test BH6.
k
Reference 117.
-------
SUMMARY OF VISIBLE EMISSIONS
PLANT BHa'b'C
o
ro
o
CO
.Emission Point: Riverside Stack
Test Date: 12/12-15/79
Boiler Type
Boiler Capacity (Ib steam/hr)
Boiler Load (% of capacity)
Control Device
Design SCA (ft2/1000 ACFM)
Operating SCA (ft2/1000 ACFM) (during testing)
Fuel
Boiler #4
- Pulverized Coal
- 140,000
- 94
- ESP
- 460
- 486
- 100% Coal
Boiler #5
- Spreader Stoker
- 200,000
- 46
- ESP
- 460
- 499
- 100% Bark
Average Opacity (%)
Time Period
(minutes)
0-5
6-11
12-17
18-23
24-29
30-35
36-41
42-47
48-53
54-59
Average all
Set
14.
15.
15.
15.
17.
15.
14.
15.
12.
21.
sets:
1
2
0
0
4
9
2
6
0
7
3
14.5
Set 1
(cont'd)
15.2
23.1
14.0
18.1
15.0
14.6
15.0
13.5
15.0
15.4
Set 1
(cont'd)
15.2
15.0
15.0
Set 2
15.0
15.0
19.0
15.0
15.0
16.5
15.0
15.0
15.0
17.5
Set
(cont
15.
15.
15.
15.
22.
15.
15.
15.
15.
15.
2 Set 2
'd) (cont'd)
0 15.0
0
0
0
3
0
0
0
0
0
Set 3
10.4
17.9
14.0
11.0
10.6
10.2
21.0
10.0
10.0
11.7
Set
(cont
12.
10.
14.
10.
12.
12.
11.
11.
10.
11.
3
'd)
7
6
0
6
7
3
9
5
6
5
Set 3
(cont'd)
20.4
11.9
10.0
11.9
&T*~4-nJ k» +UA CD A
„„ simultaneously with the Method 5 test designated B7, B8, B9,
considered representative for the reasons discussed in Section C.I.
'Reference 118.
and
were not
-------
SUMMARY OF VISIBLE EMISSIONS
PLANT BHa'b'c
o
I
ro
o
Emission Point: Trackside Stack
Test Date: 12/12-15/79
Boiler Type
Boiler Capacity (Ib steam/hr)
Boiler Load (% of capacity)
Control Device
Design SCA (ft2/1000 ACFM)
Operating SCA (ft2/1000 ACFM)(during testing)
Boiler #4
- Pulverized
- 140,000
- 94
- MC/ESP
- 460
- 486
Coal
Primary Fuel
- Coal
Average Opacity (%)
Boiler #5
- Spreader Stoker
- 200,000
- 46
- MC/ESP
- 460
- 499
- 100% Bark
Time Period
(minutes)
0-5
6-11
12-17
18-23
24-29
30-35
36-41
42-47
48-53
54-59
Average of al 1
Set 1
14.2
15.0
15.0
15.4
14.0
14.6
14.6
19.6
13.1
15.0
sets:
Set 1
(cont'd)
15.0
15.0
14.0
15.0
19.0
14.2
15.0
15.0
15.0
15.4
14.0
Set 2
15.0
15.4
15.0
15.0
15.0
15.8
15.0
15.0
15.0
15.0
Set 2
(cont'd)
15.0
15.0
15.0
16.7
15.0
15.0
15.0
15.0
15.0
15.0
Set 2
(cont'd)
20.4
15.0
15.0
15.0
15.0
Set 3
10.2
12.7
10.4
10.0
17.9
10.8
10.2
10.0
10.0
10.4
Set 3
(cont'd)
11.7
10.6
10.6
10.4
13.3
10.0
12.3
12.7
21.0
14.0
Set 3
(cont'd)
10.6
10.0
10.8
10.6
aTested by the EPA.
bThe test was conducted simultaneously with the Method 5 test designated B7, B8, 89 and the data were
not considered representative for reasons discussed in Section C.I.
'Reference 118.
-------
SUMMARY OF VISIBLE EMISSIONS
PLANT BIa'b'C
Emission Point: #7 Precipitator
Test Date: 12/6/79, 2/12-13/80
Boiler Type.
Boiler Capacity (Ib steam/hr)
Boiler Load (% of capacity)
Control Device
Design SCA (ft2/1000 ACFM)
Operating SCA (ft2/!000 ACFM)
(during testing)
Boiler #7
- Spreader Stoker/
Traveling Grate
- 240,000
- 87
- ESP
- 300
- 321
Boiler #8
- Spreader Stoker/
Traveling Grate
- 325,000
- 87
- ESP
- 300
- 320
? Fuel
ro
o
in
Time Period
(minutes)
0-5
6-11
12-17
18-23
24-29
30-35
36-41
42-47
48-53
54-59
- 25$ Bark/75% Coal
Average Opacity (%)
Set 1
0
0
0
0
0
0
0
4.4
1.7
1.9
Set 1
(cont'd)
0.8
0
1.0
8.8
10.2
5.4
0
0
0
0
Set 1
(cont'd)
0
0
0
0
0
0
0
0
0
0
Set 1
(cont'd)
0
0
0
0
0
0
Set 2
0
0
0.6
2.1
2.7
0
0.4
0
0
3.1
Set 2
(cont'd)
2.3
0.4
2.9
0
0
0
0
0
0
- 25% Bark/75% Coal
Set 3
0
0
0
0
0
0
0
0
0
0
Set 3
(cont'd)
0.21
1.8
0
0
0
0
0
0
0
Set 4
0
0
0
0
0
0
0
0
0
0
Set 4
(cont'd)
0
0
0
Average of al1 sets: 0.6
aTested by the EPA.
bReference 119.
Conducted simultaneously with test BI1.
-------
SUMMARY OF VISIBLE EMISSIONS
PLANT BI
a,b,c
ro
O
Emission Point: #8 Precipitator
Test Date: 2/12-13/80
Boiler Type
Boiler Capacity (Ib steam/hr)
Boiler Load (% of capacity)
Control Device
Design SCA (ft2/1000 ACFM)
Operating SCA (ft*/1000 ACFM)
(during testing)
Boiler #7
- Spreader Stoker/
Traveling Grate
- 240,000
- 87
- ESP
- 300
- 321
Boiler #8
- Spreader Stoker/
Traveling Grate
- 325,000
- 87
- ESP
- 300
- 320
Fuel
Time Period
(minutes)
0-5
6-11
12-17
18-23
24-29
30-35
36-41
42-47
48-53
54-59
Average of all
- 25% Bark/75% Coal
Average Opacity (%)
Set 1
0
0
0
0
0
0
0
2.5
0.3
18.8
sets:
Set 1
(cont'd)
1.0
0
1.0
12.5
14.8
7.5
0
0
0
0
0.8
Set 1 Set 1
(cont'd) (cont'd)
0 0
0 0
0 0
0
0
0
0
0
0
0
Set 2
0
0.2
0
0.8
0.6
0
0
0
0
1.7
Set 2
(cont'd)
1.5
0.4
1.5
0
0
0
0
0
0
- 25% Bark/75% Coal
Set 3
0
0
0
0
0
0
0
0
0
0
Set 3
(cont'd)
0
0.6
0
0
0
0
0
0
0
Set 4 Set 4
(cont'd)
0 0
0 0
0 0
0
0
0
0
0
0
0
"Tested by the EPA.
Reference 119.
cConducted simultaneously with test BI1.
-------
SUMMARY OF VISIBLE EMISSIONS
PLANT BJ120'121
Test Dates: 5/14-17/80, 6/27/79
Boiler Type
Boiler Capacity (Ibs steam/hr)
Boiler Load (% of capacity)
Control Device
Design SCA (ft2/1000 ACFM)
Operating SCA (ft2/1000 ACFM)
Fuel
- Spreader Stoker
- 600,000
- 75% - 82%
- ESP
- 356
- 460
- 60% Bark and sawdust/40% Oil
Time Period
(minutes)
0-5
6-11
12-17
Set 1
0
0
0
Average
Set 2
0
0
0
Opacity
Set 3
0
0
0
Set 4
0
0
0
Set 5a
0
0
0
Set 5 was conducted simultaneously with test BJ1.
C-207
-------
SUMMARY OF VISIBLE EMISSIONS
PLANT BO122
Test date: 5/26/76
Boiler Type - Spreader Stoker
Boiler Capacity - 180,000 Ib/hr steam
Boiler Load (% of capacity) - 96
Control Device - Impingement Wet Scrubber
Pressure drop during testing - 6-8
Fuel - Hog Fuel
Average Opacity (%)
Test Period
(minutes) Set 1 Set 2 Set 3 Set 4
0-5 9.6 10.2 21.1 20.8
6-11 10.2 11.5 20.0 26.7
12-17 11.5
Average of all sets: 15.7
C-208
-------
SUMMARY OF VISIBLE EMISSIONS
PLANT BP123
Test Date: 2/7/78
Boiler Type - Spreader Stoker
Boiler Capacity (Ib steam/hr) - 40,000 (two 20,000 Ib/hr units)
Boiler Load (% of capacity) - 95
Control Device - Impingement Wet Scrubber
Pressure drop during testing - 7-13 in H?0
Fuel - Hog Fuel and Sanderdust
Average Opacity (%)
Time Period
(minutes)
0-5
6-10
Set 1
15.8
20.2
Set 2
15.4
19.0
Average of all sets: 17.6
C-209
-------
SUMMARY OF VISIBLE EMISSIONS
PLANT DD124
Emission Point: Stack of Boiler No. 2
Test Date: 12/16-17/789
Boiler Type - Spreader Stoker
Boiler Capacity (Ib steam/hr) - 288,000
Boiler Load (% of Capacity) - 68
Control Device - MC
Fuel - Bagasse
Time Interval Average Opacity
(minutes) (%)
Set 1
Set 2
Set 3
Set 4
Set 5
Set 6
Average of all sets: 18.6
6
6
6
6
6
6
21.9
18.7
16.6
20.6
17.7
16.4
Conducted simultaneously with test DDL
C-210
-------
SUMMARY OF VISIBLE EMISSIONS
PLANT FBa'b
Test Date: 11/7/80
Boiler Type
Boiler Capacity (Ib steam/hr)
Boiler Load (% of capacity)
Control Devices
Design SCA (ft2/1000 ACFM)
Fuel
- Overfeed Stoker
- 135,000
- 79
- MC/ESP
- 316
- Municipal Solid Waste
Average Opacity (%)
Time Period
(minutes)
0-5
6-11
12-17
18-23
24-29
30-35
36-41
42-47
48-53
54-59
Average of all
Set 1
0.2
1.7
11.9
10.6
4.2
0.0
1.9
0.4
1.7
0.2
sets:
r
Set 1
(cont'd)
2.2
4.6
11.3
10.6
6.9
14.4
0.4
0.0
0.0
0.0
3.0
Set 1
(cont'd)
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
4.2
1.9
'Tested by the EPA.
Reference 125,126.
C-211
-------
SUMMARY OF VISIBLE EMISSIONS
PLANT FCa'b
Test Date: 1/21/81
Boiler Type
Boiler Capacity (Ib steam/hr)
Boiler Load (% of capacity)
Control Device
Design SCA (ft2/1000 ACFM)
Fuel
Overfeed Stoker
175,000
82
ESP
209
Municipal Solid Waste
Time Period
(minutes)
Average Opacity (%)
Set 1 Set 1 Set 1
(cont'd) (cont'd)
0-5
6-11
12-17
18-23
24-29
30-35
36-41
42-47
48-53
54-59
Average of all
4.2
4.6
5.0
4.8
5.2
6.3
5.2
5.0
4.4
5.0
sets : 3. 9
2.7
3.3
2.9
3.5
4.4
3.3
5.6
4.6
2.3
3.1
5.2
4.2
2.3
1.3
1.9
1.7
3.3
5.8
4.6
1.7
'Tested by the EPA.
Reference 127,128.
C-212
-------
SUMMARY OF VISIBLE EMISSIONS
PLANT FDa'b
o
ro
I-*
CO
Emission Point: West Stack
Test Date: 11/6-7/79
Boiler Type
Boiler Capacity (Ib steam/hr)
Boiler Load (% of capacity)
Control Device
Fuel
- Ram-fed Controlled Air
- 10,000
- 76
- None
- Municipal Solid Waste
Average Opacity (%)
Time Period
(mi nutes )
0-5
6-11
12-17
18-23
24-29
30-35
36-41
42-47
48-53
54-59
Average of all
Set 1
14.4
15.6
10.0
12.3
11.9
13.5
14.4
10.6
11.9
13.5
sets:
Set 1
(cont'd)
15.4
14.4
12.3
12.5
14.0
16.0
14.0
16.3
14.2
12.7
15.1
Set 1
(cont'd)
12.3
13.5
15.4
12.9
14.2
13.3
12.3
12.3
12.9
12.1
Set 1
(cont'd)
13.3
12.9
12.9
12.3
12.9
Set 2
13.8
16.3
17.9
20.2
17.5
17.8
17.3
17.7
16.7
17.5
Set 2
(cont'd)
17.5
21.9
19.2
16.7
18.5
18.8
Set 3
15.0
14.6
12.9
14.8
19.6
22.9
17.3
15.0
17.9
16.5
Set 3
(cont'd)
16.9
16.5
14.0
14.4
aTested by the EPA simultaneously with test FD3.
^Reference 129.
-------
SUMMARY OF VISIBLE EMISSIONS
PLANT HFa'b>C
Test Dates: 4/30/79 - 5/1/79
Boiler Type
Boiler Capacity (Ib steam/hr)
Boiler Load (% of capacity)
Control Devices
Design SCA (ft2/1000 ACFM)
Fuel
Spreader Stoker
200,000
80
Mechanical Collector/ESP
248
Wet pulped RDF
Average Opacity (%)
Time Period
(minutes) Set 1
0-5
6-11
12-17
18-23
24-29
30-35
36-41
42-47
48-53
54-59
Average of all sets: 4.0
Set 2 Set 3
5.8 0
5.8 0
6.7 0
9.2 0
7.5 0
9.2 0
12.5 0
7.5 0
7.5 0
7.5 0
Reference 130-131.
Data was obtained concurrently with test HF1. The set number corresponds
to the Method 5 test run number.
cThe average opacity for set 1 was shown in the test reports as 29 percent
for one hour of readings. However, the data showing the actual readings
was illegible so six minute averages could not be calculated for set 1.
Also, data shown indicated proper Method 9 methods might not have been
followed during this test run. Because of the doubts about the accuracy
of the data, and the fact that data were not available to calculate the
six minute averages, the opacity data from Run 1 were not used in NSPS
development.
C-214
-------
C.3 S02 EMISSION REDUCTION DATA
This section presents continuous monitoring data for eight industrial
boiler wet FGD systems, one lime spray drying F6D system, and one fluidized-
bed combustion system. The test data for five of the wet FGD systems and
the lime spray drying systems were presented and discussed in Chapter 4
with regard to the level of S02 removal achievable with well designed,
operated, and maintained FGD systems, as is the fluidized-bed system. This
section contains daily test results for each of these sites as well as the
continuous monitoring data for three wet FGD systems that were, for various
reasons, not considered to be representative of well designed and operated
FGD systems. The reasons why these latter sites were not considered to be
representative are documented in their respective site descriptions.
All the continuous monitoring tests of FGD systems were conducted
by EPA. At the start of each test program, the continuous monitors
were subjected to performance specification tests as delineated in
40 CFR 60, Appendix B (proposed revisions as of 10 October 1979). All
sampling and analysis during the performance tests were performed
according to EPA 40 CFR 60 Appendix A, Methods 1 through 6. S02
emission rates in ng/J (lb/10 Btu) were calculated from measured gas
stream concentrations combined with ultimate analyses and heating values
of the fuel fired at each site. The S02 removal efficiencies were then
determined by comparison of inlet and outlet emission rates. Only test
days with more than 18 hours of test data are reported.
Each site description that follows provides a brief process description
and daily average monitoring results in both tabular and graphical form.
C-215
-------
132
Location I
The FGD system monitored at plant location I is a Peabody tray and
quench water scrubber. The scrubbing medium is a 50 weight percent
sodium hydroxide (NaOH) aqueous solution with a 35 gallon per minute
make up. A scrubber handling flue gases from a 150,000 Ibs. steam/hr
capacity Babcock and Wilcox (B&W) pulverized coal boiler was monitored.
The boiler is fired using Southern Illinois subbituminous coal with a
sulfur content between 3.55 to 3.73 weight percent.
The daily averaged test results are presented in Table C.3-1 to
C.3-3. Continuous monitoring data were obtained for 30 test days.
The hourly averaged boiler loadings ranged from 55,000 to 120,000 Ibs/hr.
with an average of about 72,000 Ibs/hr during the test period.
Figure C.3-1 illustrates daily average SO^ removal efficiency, boiler
load, and scrubbing solution pH.
C-216
-------
TABLE C.3-1. DAILY AVERAGE SO, REMOVAL RESULTS
SODIUM SCRUBBING PROCESS -LOCATION Ia»b
a
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
30 Day
Average
S02 Emission
Scrubber
ng/J mi 1
2380
2377
2403
2385
2274
2341
2406
2420
2396
2404
2392
2433
2450
2372
2433
2461
2420
2421
2376
2365
2354
2335
2480
2724
2229
2132
2109
2125
2072
1961
2348
Rate at
Inlet
i i
Ib
lion/Btu
5.5
5.5
5.6
5.5
5.3
5.4
5.6
5.6
5.6
5.6
5.6
5.7
5.7
5.5
5.7
5.7
5.6
5.6
5.5
5.5
5.5
5.4
5.8
6.3
5.2
5.0
4.9
4.9
4.8
4.6
5.5
S02 Emission Rate at
Scrubber Outlet
ng/J
55
58
59
64
54
69
83
96
108
81
74
85
90
83
87
96
83
99
81
91
90
92
80
112
267
90
85
86
62
62
87
"1 i_
Ib
million/Btu
0.1
0.1
0.1
0.1
0.1
0.2
0.2
0.2
0.3
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.3
0.6
0.2
0.2
0.2
0.1
0.1
0.2
Percent
S02
Removal
97.7
97.6
97.6
97.3
97.3
97.0
96.5
96.1
95.5
96.7
96.9
96.5
96.3
96.5
96.4
96.1
96.6
95.9
96.6
96.2
96.2
96.1
96.7
95.4
88.3
95.7
96.0
96.0
96.9
96.8
96.2
18 Hours/day minimum test time.
b Reference 133.
C-217
-------
TABLE C.3-2. DAILY SUMMARY OF HOURLY BOILER LOADS
SODIUM SCRUBBING PROCESS - LOCATION I
a,b
Test Daye
Minimum Hourly
Boiler Load
(1000 Ib steam/hr)
24-Hour Average
Boiler Load
(1000 Ib steam/hr)
Maximum Hourly
Boiler Load
(1000 Ib steam/hr)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
77
70
75
73
73
81
66
61
70
67
70
61
60
70
55
55
55
60
78
65
65
70
78
70
70
65
60
60
65
50
81
77
79
83
77
84
68
69
73
70
73
67
66
70
58
55
55
73
81
67
71
79
80
78
77
65
76
70
65
62
86
81
98
120
80
90
75
80
75
73
77
72
68
70
60
55
55
80
85
70
80
82
82
80
80
70
80
85
65
110
a!8 Hours/day minimum test time.
bReference 133.
C-218
-------
TABLE C.3-3.
DAILY SUMMARY OF pH LEVELS
SODIUM SCRUBBING PROCESS -
LOCATION Ia»D
Test Day3
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Minimum pH
Reading
7.8
7.7
7.8
7.7
7.8
7.8
7.9
8.2
7.9
8.1
7.8
8.2
8.0
8.0
8-0
8.1
8.0
7.8
-
-
8.0
7.8
-
_
_
8.0
-
_
8.0
7.8
Daily Average
pH Level
8.0
8.1
7.9
8.0
8.0
7.9
8.0
8.2
8.0
8.1
8.1
8.8
8.1
8.0
8.0
8.1
8.0
7.8
7.9
8.5
8.1
8.0
8.0
8.3 •
8.2
8.4
8.2
8.2
8.2
8.1
Maximum pH
Reading
8.2
8.3
8.2
8.3
8.1
8.0
8.2
8.2
8.1
8.2
8.7
9.4
8.1
8.0
8.0
8.1
8.0
7.9
_
_
8.1
8.3
_
_
_
8.8
_
_
8.4
8.4
aNo minimum or maximum readings are given on those test days for which only
one reading was taken.
Reference 134.
C-219
-------
100
£
cf
in
VI
90
80
70
10
15
Average S02 Removal = 96.2%
20
25
30
90
80
70
•o
3 60
s.
Ol
i 50
CO
** 40-
30-
10
15
20
25
30
g,,
8
7
6-
5
10
15
Test Days
20
25
30
Figure C.3-1. Daily average S02 removal, boiler load, slurry
pH for the sodium scrubbing process at Location I.
C-220
-------
135
Location II
The FGD system monitored at plant location II is an Airpol Venturi
scrubber. The scrubbing medium is an aqueous solution of sodium hydroxide
(NaOH) and sodium carbonate (N32C03). The scrubber handles flue gases from
two oil-fired steam generators, a hog fuel-fired steam generator and a
recovery boiler. The boilers are fired with No. 6 fuel oil containing four
percent sulfur with Gross Calorific Value (GCV) of 39,929 kJ/kg (17,167 Btu/lb),
Each unit produces 100,000 Ib of steam/hour. These units operate in tandem
with the hog-fueled unit which supplied up to 50 percent of the total process
steam demand. The amount of steam produced by the hog-fired unit depended on
the supply of the hog fuel. Therefore, under normal operating conditions,
there were large and unpredictable fluctuations in the steam demand on the
two oil-fired units.
The daily averaged test results are presented in Table C.3-4. Continuous
monitoring data was obtained for 22 test days. The hourly combined averaged
boiler loadings ranged from 35,000 to 265,000 Ibs/hr with an average of
about 103,000 Ibs/hr during the test period.
Despite the fact that average S02 removal for the test period was greater
than 90 percent, the wide fluctuations in removal efficiency are not
136
considered to be representative of a well-operated FGD system.
C-221
-------
TABLE C.3-4. DAILY AVERAGE SOo REMOVAL RESULTS-SODIUM
SCRUBBING PROCESS-COCATION
Test
Day
1
2
3
4
5
6
7
8
9
10
n
12
13
14
15
16
17
18
19
20
21
22
22 Day
Average
S02 Emission Rate
at Scrubber Inlet
ng/J
1827
1830
1829
1986
2088
2334
2220
1960
2116
2224
2089
1882
1591
1429
1692
1532
2101
1670
1803
1889
1627
2818
1934
Ib
Million Btu
4.3
4.3
4.3
4.6
4.9
5.4
5.2
4.6
4.9
5.2
4.9
4.4
3.7
3.3
3.9
3.6
4.9
3.9
4.2
4.4
3.8
6.6
4.5
SO? Emission Rate
at Scrubber Outlet
ng/J
52
27
480
46
149
67
140
119
28
109
99
544
12
23
15
347
28
24
43
752
338
69
160
Ib
Million Btu
0.1
0.1
1.1
0.1
0.3
0.2
0.3
0.3
0.1
0.3
0.2
1.3
0.0
0.1
0.0
0.8
0.1
0.1
0.1
1.7
0.8
0.2
0.4
Percent
S02
Removal
97.2
98.5
73.7
97.7
92.9
97.1
93.7
93.9
98.7
95.1
95.3
71.1
99.3
98.4
99.1
77.3
98.7
98.6
97.6
60.2
79.2
97.6
91.7
18 hours/day minimum test time
^Reference 137
C-222
-------
138
Location III
Two F6D systems were monitored at plant location III. Both systems
consist of dilute double alkali scrubbing in valve tray type absorbers
supplied by Koch Engineering Company. SO^ in the flue gas is absorbed
by a regenerated caustic soda solution (0.1 M NaOH), forming a solution
of soluble sodium salts. The absorber has a quench spray section at the
inlet and full diameter chevron mist eliminators at the outlet. A portion
of the circulating liquor containing a mixture of sodium sulfate is bled
to a reactor/clarifier system where active alkali is regenerated by
reacting the solution with a slurry of lime. The precipitated solids
are further reacted and'concentrated in a clarifier.
The individual scrubbers handle flue gases from coal-fired boilers
No. 1 and No. 3. Each boiler is a spreader-stoker unit with a maximum
rated capacity of 100,000 and 60,000 Ibs/hour of steam,, respectively, for
boilers No. 1 and No. 3. Normal burning of eastern coal containing
1.7 to 2.7 percent sulfur, plus occasional lower sulfur waste oil results
in flue gas generally containing 800 to 1,300 ppm of SOg.
The daily average test results are presented in Tables C.3-5 through
C.3-10. Continuous monitoring data was obtained for 17 and 24 test days
for the F6D systems on boiler No. 1 and No. 3, respectively. Figures
C.3-2 and C.3-3 present daily S0« removal boiler load, and slurry pH
for the two boilers.
C-223
-------
TABLE C.3-5. DAILY AVERAGE S0? REMOVAL RESULTS
DUAL ALKALI PROCESS
LOCATION III (BOILER NO. 1)139
Test
Daya
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
17 Day
Average
S02 Emission Rate
at Scrubber Inlet
ng/J
1659
1720
1698
1634
1594
1320
1235
1539
1806
2000
1680
1670
1619
1722
1811
1564
1706
1646
16
Million Btu
3.8
4.0
4.0
3.8
3.7
3.1
2.9
3.6
4.2
4.7
3.9
3.9
3.8
4.0
4.2
3.6
4.0
3.8
S02 Emission Rate
at Scrubber Outlet
ng/J
194
165
163
117
97
134
93
138
101
137
156
81
172
213
134
no
135
138
Ib
Million Btu
0.5
0.4
0.4
0.3
0.2
0.3
0.2
0.3
0.2
0.3
0.4
0.2
0.4
0.5
0.3
0.3
0.3
0.3
Percent
S02
Removal
88.2
90.3
90.4
92.8
93.6
89.9
92.4
90.8
94.6
93.0
90.6
95.2
89.4
87.6
92.6
93.0
92.1
91.6
18 Hours/day minimum test time.
C-224
-------
TABLE C.3- 6 DAILY AVERAGE S02 REMOVAL RESULTS
DUAL ALKALI PROCESS
LOCATION III (BOILER NO. 3)139
Test
Day3
1
2
3
4
5
6
7
8
9
10
n
12
13
14
15
16
17
18
19
20
21
22
23
24
24 Day
Average
SOg Emission Rate
at Scrubber Inlet
ng/J
1534
1223
1246
1247
1180
1275
1284
1215
1634
1678
1892
1631
1647
1715
1934
1997
2285
2084
1648
1652
1707
1628
1561
1647
1606
" Ib
Million Btu
3.6
2.9
2.9
2.9
2.8
3.0
3.0
2.8
3.8
3.9
4.4
3.8
3.8
4.0
4.5
4.6
5.3
4.8
3.8
3.8
4.0
3.8
3.6
3.8
3.7
SO? Emission Rate
at Scrubber Outlet
ng/J
62
64
78
70
82
73
37
40
446
342
201
85
61
70
153
177
no
137
133
139
132
108
128
150
.
128
..
Ib '
Million Btu
0.1
0.1
0.2
0.2
0.2
0.2
0.1
0.1
1.0
0.8
0.5
0.2
0.1
0.2
0.4
0.4
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
Percent
S02
Removal
95.9
94.8
93.7
94.5
93.0
94.1
97.1
96.7
73.6
79.2
89.3
94.9
96.3
95.9
92.2
91.1
95.1
93.2
92.0
91.6
92.3
93.4
91.9
91.1
92.2
J18 Hours/day minimum test time.
C-225
-------
TABLE C.3-7. DAILY SUMMARY OF HOURLY BOILER LOADS
DUAL ALKALI PROCESS . h
LOCATION III (BOILER NO. 1) '
Test Daya
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Minimum Hourly
Boiler Load
(1000 Ib steam/hr)
60
60
65
67
60
55
53
52
55
52
47
60
53
42
49
53
50
24-Hour Average
Boiler Load
(1000 Ib steam/hr)
74
80
73
74
76
68
67
68
66
56
53
71
67
65
54
67
65
Maximum Hourly
Boiler Load
(1000 Ib steam/hr)
88
96
80
80
93
84
76
89
76
63
60
86
83
82
59
81
76
18 Hours/day minimum test time.
Reference 139.
C-226
-------
TABLE C.3-8. DAILY SUMMARY OF pH LEVELS
DUAL ALKALI PROCESS
LOCATION III (BOILER NO. 1)
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Minimum pH
Reading
6.0
6.0
6.0
6.0
5.6
5.8
6.0
6.0
5.7
5.8
5.9
5.7
5.9
6.0
6.0
6.0
6.0
Dally Average
pH Level
6.0
6.0
6.0
6.0
5.8
5.9
6.0
6.0
6.0
5.9
6.1
6.0
6.1
6.0
6.0
6.1
6.0
Maximum pH
Reading
6.0
6.0
6.0
6.0
6.0
6.0
6.0
6.0
6.0
6.0
6.3
6.2
6.3
6.0
6.0
6.5
6.0
C-227
-------
TABLE C.3-9. DAILT SUMMARY OF HOURLY BOILER LOADS
DUAL ALKALI PROCESS _ h
LOCATION III CBOILER NO. 3)'
Minimum Hourly 24-Hour Average Maximum Hourly
Boiler Load Boiler Load Boiler Load
Test Day* (1000 Ib steam/hr) (1000 Ib steam/hr) (1000 Ib steam/hr)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
3
22
25
26
34
37
36
38
30
28
27
5
38
19
38
34
29
27
29
25
24
20
28
24
32
34
34
36
39
40
40
41
41
37
38
42
43
38
46
42
39
39
35
32
32
31
35
32
43
48
40
46
43
43
42
42
56
47
49
53
50
45
57
50
50
50
45
42
41
39
43
42
a!8 Hours/day minimum test time.
bReference 139.
C-228
-------
TABLE C.3-10. DAILY SUMMARY OF pH LEVELS
DUAL ALKALI PROCESS , h
LOCATION III (BOILER NO. 3)a'D
Test Day3
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Minimum pH
Reading
5.2
5.0
5.8
5.8
5.8
5.8
5.9
5.8
6.0
-
_
-
-
_
5.9
5.9
6.0
6.0
6.0
4.7
6.0
6.0
6.0
6.0
Daily Average
pH Level
5.8
6.0
6.0
6.0
6.0
5.9
6.0
6.0
6.0
-
_
_
_
-
6.0
6.0
6.1
6.0
6.0
5.8
6.0
6.0
6.0
6.0
Maximum pH
Reading
6.2
6.5
6.1
6.0
6.2
6.0
6.2
6.2
6.0
_
_
_
_
_
6.1
6.2
6.1
6.0
6.0
6.1
6.1
6.1
6.0
6.0
aNo pH data available for test days 10 through 14.
Reference 140.
C-229
-------
loop
•= 90
80
Average S02 Removal * 91.6%
10
15
20
25
30
90
80
70
•o
(O
3 60
s_
0)
~ 50
a
CO
** 40
30
10
15
20
25
30
9
8
7
6
5
4
• • •
10
20
25
15
Test Days
Figure C.3-2 Daily average S0? removal, boiler load, and
slurry pH for the dual alkali scrubbing
process at Boiler #1, Location III.
C-230
30
-------
100
5 90
80
Average S02 Removal * 92.2%
10
15
20
25
30
80
70
60
0)
i so
CD
40
30
10
15
20
25
30
9
8
7
3
tS>
5
4
• • +
10 15 20
Test Days
25
30
Figure Q.3-3 Dally average SO- removal, boiler load, and
slurry pH for scrubbing proces-s at Boiler #3
Location- III.
C-231
-------
14.1
Location IV - Lime System
Three data sets were taken on a lime/limestone FGD system at location
IV. One of the tests monitored the system under lime sorbent operations
and the two other tests monitored the system while it operated using limestone
as a sorbent; in one of the two limestone tests, adipic acid was added
to improve S02 removal efficiency.
Particulates are removed from the flue gas in a mechanical collector
upstream of the absorber. The absorber is a two-stage unit with fresh
solvent make-up being introduced at the second stage. Flue gas from the
absorber enters a cyclonic mist eliminator before going to the stack.
The scrubber system was designed to treat the combined flue gas from
seven small stoker boilers at the peak winter load of approximately
210 x 10 Btu/hr. Typical fuel burned at the facility is mid-west
coal with a sulfur content of about 3.5 percent. The system has essentially
unlimited turndown capability since it mixes air with flue gas to maintain
a constant flue gas rate at low boiler loads. Consequently, S02
concentrations will vary from about 200 to 2000 ppm depending upon the
boiler load. S02 emissions averaged 194 ng/J during the tests.
The daily average test results for operation with lime sorbent
are presented in Tables C.3-11 through C.3-13. Continuous monitoring
data was obtained for 29 days with overall average S02 removal of 91.2.
•i
Figure C.3-4 shows the daily S02 removal boiler load, and slurry
pH levels.
C-232
-------
TABLE C.3-11.
DAILY AVERAGE S02 REMOVAL RESULTS
LIME SLURRY PROCESS
LOCATION IV14?
502 Emission Rate
at Scrubber Inlet
Test
Day a
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
IS
19
20
21
22
23
24
25
26
27
28
29
29 Day
Average
ng/J
2021
2175
2293
2277
2245
2344
2333
2310
2355
2318
2220
2334
2432
2418
2390
2255
2272
2318
2299
2262
2145
2273
2359
2116
2207
2245
2125
1990
1927
2250
Ib
Million Btu
4.7
5.1
5.3
5.3
5.2
5.5
5.4
5.4
5.5
5.4
5.2
5.4
5.7
5.6
5.6
5.2
5.3
5.4
5.4
5.3
5.0
5.3
5.5
4.9
5.1
5.2
4.9
4.6
4.5
5.2
S02 Emission Rate
at Scrubber Outlet
ng/J
211
230
160
179
237
194
260
186
146
189
124
94
194
127
128
205
201
218
216
l!99
131
185
213
150
294
279
285
149
190
192
Ib
Million Btu
0.5
0.5
0.4
0.4
0.6
0.5
0.6
0.4
0.3
0.4
0.3
0.2
0.5
0.3
0.3
0.5
0.5
0.5
0.5
0.5
0.3
0.4
0.5
0.4
0.7
0.6
0.7
0.3
0.4
0.4
Percent
t*f\
SO?
M ^
Removal
89.7
89.4
93.0
92.2
89.4
91.6
88.8
92.0
93.8
91.8
94.4
96.0
92.0
94.7
94.6
91.0
91.2
90.6
90.6
91.3
93.8
91.9
90.9
93.4
86.7
87,6
86.8
92.4
90.6
91.5
18 Hours/day minimum test time.
C-233
-------
TABLE C.3-12.
DAILY SUMMARY OF HOURLY BOILER LOADS
LIME SLURRY PROCESS LOCATION IVa»b
Test Day
Minimum Hourly
Boiler Load
(million Btu/hr)
24-Hour Average
Boiler Load
(million Btu/hr)
Maximum Hourly
Boiler Load
(million Btu/hr)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
99
98
102
100
104
106
103
94
102
99
99
97
99
78
72
111
96
98
106
109
90
81
105
90
86
88
90
72
78
106
107
110
108
113
113
116
110
112
113
112
109
113
112
93
120
115
113
121
125
no
102
116
104
107
99
97
82
93
118
119
120
120
125
127
131
118
119
122
123
118
129
126
109
132
127
132
134
136
128
117
134
127
127
109
106
95
105
a!8 Hours/day minimum test time.
bReference 142.
C-234
-------
TABLE C.3-13.
DAILY SUMMARY OF pH LEVELS
LIME SLURRY PROCESS
LOCATION IVa
Test Day
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
Minimum pH
Reading
7.8
7.9
4.6
7.6
5.8
8.0
7.2
7.5
7.1
7.0
7.4
8.0
7.4
7.2
7.6
6.2
6.8
7.8
6.6
7.8
7.8
7.8
8.0
7.8
5.6
4.8
3.8
6.3
4.7
Daily Average
pH Level
7.9
8.3
6.3
7.7
6.6
8.2
7.4
7.9
7.4
7.3
7.5
8.5
7.5
7.3
8.4
6.5
6.8
8.3
7.4
7.9
7.9
7.9
8.1
7.9
6.3
5.3
4.3
6.6
5.6
Maximum pH
Reading
8.0
8.5
8.0
7.8
7 6
i * \j
8 4
\j • ~
7 6
/ • w
8 2
\J • tut
8.0
7 8
1 * \J
7.6
9.2
7.6
7.4
9.9
7 0
/ • \j
6 9
w » j
8 8
\* • \j
8.3
8.0
8.0
7 9
I • J
8 2
\j • b
8.0
6 8
w • w
6.0
4.7
7 o
/ • w
6.1
Reference 143.
C-235
-------
TOO
5 90
o
80
10
15
Average S02 Removal = 91.5%
20
25
30
90r
80-
70-
•o
«
2 60.
&.
o>
=5 50'
CD
" 40-
30-
10
15
20
25
30
£ 6
10
15
Test Days
20
25
Figure C.3-4. Daily average $03 removal, boiler load, and
slurry pH for lime slurry scrubbing process
at Location IV.
C-236
30
-------
Location IV - Limestone (with and without Adi pic Acid Addition)
The FGD system at Location IV was also monitored during limestone
operation. Tests were conducted both with and without adipic acid
addition.
In 36 days of testing without adipic acid addition, S02 removal
averaged 58.7 percent (Table C.3-14). This relatively low S02 removal
is attributed to two factors: (1) the system is not designed for high
144
SOp removal with limestone and (2) evidence that the system was
operated at gas flows of about 20 percent greater than the design
136
value. For these reasons, the results from limestone only tests
are not considered representative of a well designed and operated
industrial boiler wet FGD system.
As shown in Table C.3-15, SOg removal averaged 94.3 percent
during 30 days of testing with adipic acid addition. This higher removal
was attributed to the effects of adipic acid as well as the effort
during the test program to maintain higher limestone feed rates than
144
those used during limestone only testing. Table C.3-16 presents
daily average outlet SOg, boiler load, adipic acid concentration, and
slurry pH for the test period. Figure C,3-5 shows daily average
SO removal, boiler load, adipic acid concentration and slurry pH.
C-237
-------
TABLE C.3-14.
DAILY AVERAGE S02 REMOVAL RESULTS
LIMESTONE SLURRY PROCESS
LOCATION IVl45
a
Test Day
1
2
3
4
5
6
7
8
9
10
11
1-2
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
36 Day
Average
Emission
Scrubber
ng/ J Mi 1
2351
2705
2792
2590
2670
2652
2681
2705
2691
2762
2983
2922
2740
2551
2764
2744
3043
2897
3038
2435
2340
2484
2686
2672
2662
2882
3197
3646
3349
3386
3296
3484
3446
3227
3219
2991
2880
Rate at
Inlet
Ib
lion Btu
5.5
6.3
6.5
6.0
6.2
6.2
6.2
6.3
6.3
6.4
6.9
6.8
6.4
5.9
6.4
6.4
7.1
6.7
7.1
5.7
5.4
5.8
6.2
6.2
6.2
6.7
7.4
8.5
7.8
7.9
7.7
8.1
8.0
7.5
7.5
7.0
6.7
Emission
Rate at
Scrubber Outlet
ng/J Mi
1334
1290
912
945
1189
1283
1318
1549
1635
1627
1723
1496
1300
1298
1285
1471
1237
1218
1417
1253
1013
928
994
1102
989
1101
832
806
903
1040
946
1002
764
758
1012
1256
1173
Ib
Hi on Btu
3.1
3.0
2.1
2.2
2.8
3.0
3.0
3.6
3.8
3.8
4.0
3.5
3.0
3.0
3.0
3.4
2.8
2.8
3.3
2.9
2.4
2.2
2.3
2.6
2.3
2.6
1.9
1.9
2.1
2.4
2.2
2.3
1.8
1.8
2.4
2.9
2.7
Percent
SO?
•* ^
Removal
43.3
51.9
66.8
63.6
55.3
51.5
50.9
42.7
39.4
41.1
42.5
48.8
52.4
49.0
53.5
46.5
59.6
57.9
52.9
48.4
56.5
62.5
63.0
58,7
62.8
61.1
72.5
76.4
73.1
68.9
71.2
71.4
77.8
76.5
68.3
57.9
58.2
a!8 Hours/day minimum test time.
C-238
-------
TABLE C.3-15.
DAILY AVERAGE S(>2 REMOVAL RESULTS
FOR LIMESTONE SLURRY PROCESS WITH ADIPIC
ACID ADDITION - LOCATION IV144
Test Daya
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
30 Day
Average
Emission
Scrubber
ng/o Mi
1720
1333
1767
1642
1789
1793
2098
1879
1913
2661
2240
2128
2244
1995
2356
2137
2644
2085
1943
2765
2313
2077
2180
2060
2266
2214
2322
2365
2648
2176
2125
Rate at
Inlet
Ib
11 ion Btu
4.0
3.1
4.1
3.8
4.2
4.2
4.9
4.4
4.5
6.2
5.2
5.0
5.2
4.6
5.5
5.0
6.2
4.9
4.5
6.4
5.4
4.8
5.1
4.8
5.3
5.2
5.4
5.5
6.2
5.1
4.9
Emission
Scrubber
v*n t 1
ng/J Mi
129
60
103
129
159
116
116
90
95
194
129
138
65
108
237
138
138
125
165
262
155
60
56
77
142
82
73
90
146
69
122
Rate at
Outlet
Ib
11 ion Btu
0.3
0.1
0.2
0.3
0.4
0.3
0.3
0.2
0.2
0.5
0.3
0.3
0.2
0.3
0.6
0.3
0.3
0.3
0.4
0.6
0.4
0.1
0.1
0.2
0.3
0.2
0.2
0.2
0.3
0.2
0.3
Percent S02
Removal
92.5
95.5
94.2
92.1
91.1
93.5
94.5
95.2
95.1
92.7
94.2
93.5
97.1
94.6
90.0
93.6
94.8
94.0
90.5
90.5
93.3
97.1
97.4
96.2
93.7
96.3
96.9
96.2
94.5
96.8
94.3
18 Hours/day minimum test time.
C-239
-------
TABLE C.3-16. DAILY AVERAGE BOILER LOAD,
ADI PIC ACID CONCENTRATION .AND SLURRY pH
LOCATION IV144
Test Day
Boiler Load
Adi pic Acid Cone.
(ppm)
Slurry pH
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
30 day average
Minimum
Maximum
49
55
64
64
67
60
59
49
46
50
49
62
55
48
48
48
46
48
46
38
34
37
30
30
36
33
33
32
31
36
46
30
67
2305
2920
2090
2290
2150
1770
2165
1890
1855
1870
2050
3000
2680
2420
2200
2240
2150
2130
-
_
1920
1950
2040
2160
2200
2170
2820
2850
2510
2400
2257
1770
3000
4.7
4.9
4.7
4.9
-
5.0
5.0
5.0
4.8
4.9
4.7
-
5.2
5.4
5.4
4.7
5.2
5.3
5.0
-
-
4.9
5.5
4.8
4.7
4.6
5.1
5.1
4.6
4.7
5.0
4.6
5.5
18 Hours/day minimum test time.
C-240
-------
ra
•o
A3
O
S_
0)
O
C3
TOO
90
Average SO. Removal = 94.355
3000
2500
2000
a s-
il 1500
•o s
f- &
U Q.
10
15
20
25
30
z.o
6.0
5.C-
4.0
3.0
Figure C.3-5
10 15 20
Test Days
25
30
Daily average S02 removal, boiler load, adipic
acid concentration, and slurry pH for limestone
system at Location IV.
C-241
-------
Location V
The FGD system monitored at plant location V is a turbulent contact
absorber (TCA) prototype installation. The TCA unit, constructed by
Universal Oil Products, uses a fluid bed of low density plastic spheres
that migrate between retaining grids. The scrubbing medium is a lime
slurry. The pilot plant scale wet scrubber handles a side stream of the
flue gases from a coal-fired boiler power station having 10 turbines.
The daily averaged test results are presented in Table C.3-17.
Continuous monitoring data was obtained for 42 test days.
Because this unit is designed and operated as pilot plant, it is
not considered to be representative of industrial boiler wet FGD
systems designed a.id operated for maximum S02 removal.
C-242
-------
TABLE C.3-17.
DAILY AVERAGE S02 REMOVAL RESULTS
LIME SLURRY PROCESS
LOCATION V147
S02 Emission- Rate
at Scrubber Inlet
Test
Day3
1
2
3
4
5
6
7
8
9
10
n
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
42 Day
Average
rig/J
2541
2566
2549
2331
2270
2589
2588
2572
2449
2460
2266
2393
2274
2546
2711
2616
2322
2532
2250
2365
1961
2150
2440
2295
2313
1680
2163
2053
2132
2360
2635
2617
2594
2580
2579
2580
2315
2365
2486
2549
2225
2061
2389
Lb
Million Btu
5.9
6.0
5.9
5.4
5.3
6.0
6.0
6.0
5.7
5.7
5.3
5.6
5.3
6.0
6.3
6.1
5.4
5.9
5.2
5.5
4.6
5.0
5.7
5.4
5.4
3.9
5.0
4.8
5.0
5.5
6.1
6.1
6.0
6.0
6.0
6.0
5.4
5.5
5.8
5.9
5.2
5.6
SO* Emission Rate
at Scrubber Outlet
ng/J
264
289
306
283
237
354
380
395
347
331
247
215
240
326
314
301
227
255
194
233
160
200
253
229
331
164
270
222
351
415
367
350
309
295
319.
375
258
255
280
308
210
172
282
Lb
Million Btu
0.6
0.7
0.7
0.7
0.6
0.8
0.9
0.9
0.8
0.8
0.6
0.5
0.6
0.8
0.7
0.7
0.5
0.6
0.5
0.5
0.4
0.5
0.6
0.5
0.8
0.4
0.6
0.5
0.8
1.0
0.9
0.8
0.7
0.7
0.7
0.9
0.6
0.6
0.7
0.7
0.5
0.4
0.7
Percent
S02
Removal
89.6
88.8
88.0
88.0
89.7
86.4
85.5
84.6
85.8
86.5
89.1
91.0
89.5
87.2
88.4
88.5
90.5
90.1
91.4
90.3
92.1
91.1
89.7
90.0
85.9
90.2
88.0
89.2
83.7
82.5
86.1
86.6
88.1
88.5
87.6
85.5
88.9
89.2
88.8
88.0
90.9
91.7 '
88.4
'18 Hours/day minimum test time.
C-243
-------
Location VI148
The FGD system monitored at plant location VI is a spray drying
scrubber. The scrubbing sorbent is a 26 percent high quality lime
(90-94% calcium oxide) slurry. Approximately 2 percent sulfur coal
was burned during most of the test period. Efficiencies found when
the daily inlet S02 concentrations are high (above 4.0 lb/10 Btu)
average 75 percent.
The daily averaged test results are presented in Table C.3-18 for the
23 test days. During this period, boiler load averaged 114 million
149
Btu/hr, with hourly loads ranging from 12 to 152 million Btu/hr. Figure
C.3-6 illustrates S02 removal and inlet S02 emissions for each test day
at this site.
C-244
-------
TABLE C.3-18. DAILY AVERAGE SO? REMOVAL RESULTS
SPRAY DRYING PROCESS
LOCATION VI149
S02 Emission Rate
at Scrubber Inlet
Test
Day a
1
2
3
4
5
6
7
8
.9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
23 Day
Average
ng/J
1471
1316
1230
1613
1312
1436
1178
1118
1269
1372
1475
1449
1122
1578
1810
1557
1905
1888
1711
1608
1578
1578
1746
1492
Lb
Million Btu
3.4
3.1
2.9
3.8
3.1
3.3
2.7
2.6
3.0
3.2
3.4
3.4
2.6
3.7
4.2
3.6
4.4
4.4
4.0
3.7
3.7
3.7
4.1
3.5
SO. Emission Rate
at Scrubber Outlet
ng/J
400
390
517
634
702
568
415
452
433
638
347
393
397
460
473
627
530
418
340
340
375
339.
387
460
Lb
Million Btu
0.9
0.9
1.2
1.5
1.6
1.3
1.0
1.1
1.0
1.5
0.8
0.9
0.9
1.1
1.1
1.5
1.2
1.0
0.8
0.8
0.9
0.8
0.9
1.1
Percent
SO-
iUg
Removal
72.7
70.3
58.0
60.7
46.4
60.4
64.8
59.5
65.9
53.5
76.5
72.8
64.6
70.9
73.8
59.8
72.2
77.9
80.1
78.9
76.2
78.5
77.9
68.4
18 Hours/day minimum test time.
C-245
-------
80
70
I 60
CM
o
10
15
25
30
200C
1800
•£• isoof
o
120C
100C
80
10 15
Test Days
20
25
'5.0
4.0 S-
ro
3.0 I
o
01
2.0 2
e?
1.0
30
Figure C.3-6. Daily average SOp removal, inieu ou« tor
lime spray drying system at Location VI.
. C-246
-------
. ,. ,,TT150
Location VII
The location monitored is a 100,000 Ib steam/hr coal/limestone feed
fluidized-bed boiler (FBB).* The coal sulfur content of the bituminous coal
burned during testing ranged from 1.5 - 2.5 weight percent. The boiler load
during the period ranged from 50 to 60 percent.
The SOp control used at this location was coal/limestone injection.
The design limestone flow rate was 3,133 Ib/hr, with actual conditions
ranging from 1,500 to 4,500 Ib/hr. The Ca/S ratio varied from
2 10 compared to a design value of 3. Low fly ash reinjection rates may
have increased SO^ emissions by decreasing sorbent residence times.
*
The plant was being operated in an extended shakedown phase so that
operating conditions were not always in the intended design range.
C-247
-------
TABLE C.3-19.
DAILY AVERAGE SO, REMOVAL RESULTS
FLUIDIZED-BEkCOHBUSTION PROCESS
LOCATION VIIlbU
Test Day3
1
2
3
4
5
6
7
8
9
10
11
12
13
14
14 Day
Average
S0? Emission
Rate - Inlet
ng/J
1030
1030
1030
1090
1030
1030
1030
1030
1120
1236
1245
1439
1477
1679
1178
Ib
million Btu
2.4
2.4
2.4
2.5
2.4
2.4
2.4
2.4
2.6
2.9
2.9
3.3
3.4
3.9
2.7
S09 Emission
Rate - Inlet
ng/J
197
256
220
171
62
55
47
88
78
49
178
242
215
224
149
Ib
million Btu
0.5
0.6
0.5
0.4
0.1
0.1
0.1
0.2
0.2
0.1
0.4
0.6
0.5
0.5
0.3
Percent S02
Removal
80.9
75.1
78.7
84.3
94.0
94.7
95.4
91.4
93.1
96.2
85.7
83.2
85.4
86.3
87.5
18 Hours/day minimum test time.
C-248
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C.4 REFERENCES
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8. Telecon. Payne, J., Champion International, with Barnett, K., Radian
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9. Telecon. Barnett, K., Radian Corporation, with Daniels, V., Champion
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14. Reference 11, pp. 104-133.
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28. Letter and attachment from Murphy, M.L., Energy Products of Idaho, to
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37. North Carolina Department of Natural and Economic Resources. Particu-
late Emission Test Report for a Woodwaste Boiler Stack at Chatham
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41. North Carolina Department of Natural and Economic Resources. Particu-
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52. Peters, J.A. and W.H. McDonald. (Monsanto Research Corporation.)
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58. Washington State Department of Ecology. Emission Source Test: Crown
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63. Peters, J.A. and W.H. McDonald. (Monsanto Research Corporation.)
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68. North Carolina Department of Natural Resources and Community Develop-
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74. Telecon. Lackey, T., Burlington Industries, with Barnett, K., Radian
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125. Trip Report. Storm, P., Radian Corporation, to file. December 31,
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Report: Continuous Sulfur Dioxide Monitoring at Steam Generators,
Volume I: Summary of Results. Research Triangle Park, N. C. EMB
Report No. 77-SPP-23B. March 1979. pp. 6 to 7.
147. Letter and attachments from Kelly, W. E., EPA:EMB, to Dennison, L. L.,
Radian Corporation. May 1980. Continuous SCL Monitoring.
148. Memo and attachment from Sedman, C. B., EPA-.ISB, to Industrial Boiler
Files. September 10, 1982. pp. 1 to 4. Trip Report to Celanese Dry
Scrubbing System.
149. Letter and attachments from Brna, T., EPA-.IERL, to Kelly, M. E., Radian
Corporation. October 1980. Raw test data from continuous S0~
monitoring tests program at Celanese Fiber Company's Amcelle plant,
Cumberland, Maryland.
150. Young, C. W., E. F. Peduto, P. H. Anderson, and P. F. Pennelly. (GCA
Corporation.) Continuous Emission Monitoring at the Georgetown
University Fluidized-Bed Boiler. (Prepared for U. S. Environmental
Protection Agency.) Research Triangle Park, N. C. EPA Contract No.
68-02-2693. September 1981. p. 48.
C-261
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APPENDIX D: EMISSION MEASUREMENT
METHODS AND CONTINUOUS MONITORING
D.I EMISSION MEASUREMENT METHODS
Since the characteristics of the emissions from nonfossil fuel fired
boilers (NFFB) are similar to those from source categories for which new
source performance standards (NSPS) have been promulgated (e.g., Subparts D
and Da 40 CFR Part 60, Fossil-Fuel Fired Steam Generators and Electric
Utility Steam Generators), it was not necessary to develop new or modified
reference test methods for the data collection phase of this study. The
emissions measured are criteria pollutants—particulate matter, oxides of
nitrogen, and sulfur dioxide—and applicable manual reference test methods
have been promulgated in Appendix A, 40 CFR Part 60. In addition, EPA has
promulgated specifications and operating requirements for continuous
monitoring of opacity in Appendix B, 40 CFR Part 60 and proposed revisions to
the monitoring performance specifications in the Federal Register on
October 10, 1979. The procedures used in the data collection study are
described below by pollutant.
D.I.I Particulates
EPA performed tests at nine facilities for particulate matter in accor-
dance with EPA Reference Method 5 at elevated probe and filter temperatures
as presently provided for in 40 CFR Part 60, Subparts D and Da. Two of the
sources tested were controlled by electrostatic precipitators, three by wet
scrubbers, one by controlled air combustion, two by fabric filters, and one
by an electrostatic gravel bed filter.
D-l
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Under the Fossil-Fuel Fired Steam Generator and Electric Utility Steam
Generator Standards, the best systems of participate control were not con-
sidered effective for sulfuric acid mist and EPA promulgated modifications of
Method 5 to minimize the measurement of acid mist as particulate matter.
These modifications allowed probe and filter sampling temperatures up to
160°C (320°F). Since the best systems of particulate control for NFFBs do
not effectively collect sulfuric acid mist, similar provisions are
recommended for this standard.
The remaining particulate emission data base was obtained from reports
submitted by state agencies or industries operating nonfossil fuel fired
boilers and were evaluated with respect to the testing methodology employed.
Out of 144 particulate emission test reports reviewed, 68 were considered as
properly conducted according to the EPA Methods. The other 76 either lacked
sufficient information for a proper review, or were not considered to be
tested according to EPA Methods.
The emission test reports were also reviewed to determine if the boiler
and control equipment were operated properly during testing or if there were
factors present in the system design or operation which would bias the test
results. This review indicated that an additional six test reports could not
be used due to abnormal conditions.
D.I.2 Sulfur Dioxide
Six of the NFFB sites tested by EPA for particulate emissions were also
tested to determine the SO,, emission rate. These tests were performed in
accordance with EPA Reference Method 6.
D-2
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D.I.3 Nitrogen Oxides
All nine of the NFFB sites tested by EPA for participate were also
tested to determine NO emission levels. These tests were performed in
A
accordance with EPA Reference Method 7.
D.I.4 Visible Emissions
EPA conducted visible emission tests at nine facilities. At four
facilities, visible emission tests were conducted simultaneously with EPA
particulate sampling tests. In addition to the EPA tests, five of the
particulate emission tests obtained from state and industry sources also
contained visible emissions data which were used in this study. All visible
emission data were obtained in accordance with EPA Reference Method 9.
D.2 COMPLIANCE TEST METHODS
The reference test methods and procedures available for determination of
compliance with an emission limitation, along with the costs of each pro-
cedure, are discussed in this section. Standards for nitrogen oxides and
sulfur dioxides which would require a reduction in the uncontrolled emissions
of these pollutants are not being considered for nonfossil fuel fired
boilers. Therefore, no compliance test methods are recommended for these
pollutants. Boilers firing mixtures of fossil and nonfossil fuels may
require S09 and NO reductions. The test methods applicable to these cases
£• A
are EPA Reference Methods 6 and 7, as discussed in Appendix D of the
Industrial Boiler Background Information Document.
D.2.1 Partic.ulate Matter
The recommended performance test method for particulate matter for
nonfossil fuel fired boilers is Method 5 modified to allow probe and filter
D-3
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temperatures up to 160°C (320°F). This is also the recommended test method
for fossil fuel fired industrial steam generators. The particulate matter
emissions from nonfossil fuel fired boilers are similar to those from fossil
fuel fired industrial boilers. Also, nonfossil fuel fired boilers may fire
significant amounts of fossil fuels under certain conditions. Therefore, it
is recommended that the performance test method for particulate emissions for
both industrial boilers and nonfossil fuel fired boilers be the same. In
addition, the use of Method 17 is recommended as an alternative to Method 5
whenever the average stack gas temperature at the sampling location does not
exceed 160°C (320°F).
Emission standards for nonfossil fuel fired boilers are expressed in
terms of pollutant mass per unit of heat input. The F factor procedure is
recommended for the determination of emission rates. The F factor is the
ratio of the quantity of dry effluent gas (F.) or of carbon dioxide (F )
generated by combustion to the gross calorific value of the fuel and is
constant for a given fuel. Used with a dilution correction value, the F
factor can be used to correct pollutant concentration data to units of
pollutant mass per unit of heat input. Method 19 (Appendix A, 40 CFR 60)
includes the calculation procedures necessary for the emission rate determi-
nation using the F factors.
F factor values for the fuels fired in NFFBs can be determined from
analyses of fuel samples and the calculation procedures in Method 19.
However, obtaining representative samples of fuels is difficult and time-con-
suming and the analyses required are expensive. It is recommended that the
published values for F factors be used where available. The F factors
D-4
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calculated for the representative fuels used in this study are shown in
Section C.I of Appendix C.
A combined fuel F factor can be calculated for the combined combustion
of waste fuels and fossil fuels or for combinations of different waste fuels.
These calculations procedures are included in Method 19. The calculations
require a knowledge of the F factors for the fuels and the heat input rate
attributable to each fuel. It is not critical that the fractions of heat
input rate be precisely known for each fuel as the F factors for most waste
materials and fossil fuels are similar.
Subpart A of 40 CFR 60 requires that facilities which are subject to
standards of performance for new stationary sources must be constructed so
that sampling ports adequate for the required performance tests are provided.
Platforms, access, and utilities necessary to perform testing at those ports
must also be provided.
Sampling costs for performing a test consisting of three Method 5 runs
are estimated to be $10,000. If in-plant personnel are used to conduct
tests, the costs will be somewhat less.
D.2.2 Opacity
Method 9, "Visual Determination of the Opacity of Emissions from
Stationary Sources," is recommended as the compliance test method for
opacity. This method is applicable for the determination of opacity of
effluent streams emitted from stacks.
Continuous monitors for opacity are not recommended for use in deter-
mining compliance with this regulation because an absolute accuracy check is
not possible with the current state-of-the-art opacity monitoring systems.
D-5
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D.3 MONITORING SYSTEMS
Though continuous opacity monitors are jiot recommended for use in deter-
mining compliance with this regulation, they can be used to monitor control
system performance. The opacity monitoring systems that are adequate for
other stationary sources, such as fossil fuel fired steam generators, covered
by performance specifications contained in Appendix B of 40 CFR 60 Federal
Register, October 6, 1975, should also be applicable to nonfossil fuel fired
boilers except where condensed moisture is present in the exhaust stream.
When wet scrubbers are used for emission reduction, monitoring of opacity is
not applicable and another parameter such as pressure drop may be monitored
as an indicator of emission control.
Equipment and installation costs for visible emissions monitoring are
2
estimated to be $40,000 per site. Annualized costs, which include an
automated data reduction system, are estimated to be $10,800 per year per
o
site. Some economics in operating costs may be achieved if multiple systems
are required at a given facility.
D-6
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D.4 REFERENCES
1. Dickerman, J.C., and M.E. Kelly. (Radian Corporation.) Compliance
Monitoring Costs. (Prepared for U.S. Environmental Protection Agency.)
Research Triangle Park, N.C. EPA Contract Number 68-02-3058.
September 25, 1980. p. 15.
2. Reference 1, p.4.
3. Reference 1.
D-7
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO. ' 2.
EPA 450/3-82-007
4. TITLE AND SUBTITLE
Nonfossil Fuel Fired Industrial Boilers - Background
Information
7. AUThORlS)
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Office of Air Quality Planning and Standards
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
12. SPONSORING AGENCY NAME AND ADDRESS
DAA for Air Quality Planning and Standards
Office of Air, Noise, and Radiation
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
3. RECIPIENT'S ACCESSION NO.
S. REPORT DATE
March 1982
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-3058
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/200/04
IS. SUPPLEMENTARY NOTES
16. ABSTRACT
i
This document provides background information about air emissions and ;
controlling these emissions for the nonfossil fuel fired boiler (NFFB)
source category. This source category includes boilers firing wood, bagasse
(sugar cane residue), municipal type solid waste, and refuse derived fuels.
This document identifies the industries which use NFFBs and the numbers of
new NFFBs expected to be built in 1982 through 1990. The uncontrolled
emissions of particulate matter, sulfur dioxide, and nitrogen oxides are
quantified and factors affecting these emissions are discussed. State and
Federal regulations which apply to the NFFB source category are summarized.
Control technologies to reduce these emissions are identified and emission
test data are presented. Factors which affect the performance of emission
control technologies are also discussed. Finally, environmental, energy and
cost impacts of applying these control technologies to nonfossil fuel fired
boilers are presented and discussed. This information was developed in
support of a potential new source performance standard for nonfossil fuel
fired boilers.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b. IDENTIFIERS/OPEN ENDED TERMS
c. COSATl Field/Group
Air pollution
Pollution control
Standards of Performance
dood-fired boilers
Jagasse-fired boilers
Solid waste-fired boilers
Nonfossil fuel fired boile
Air pollution control
118. O'ST3I3UT, ON STATEMENT ., , _ _„ .
Release unlimited. Available from EPA
Library (MD-35), Research Triangle Park,
North Carolina 27711
19. SECURITY CLASS (Tliis Report/
unclassified
21. NO. OF PAGES
789
20. SECURITY CLASS /This page I
unclassified
22. PRICE
EPA Form 2220-1 (Rev. 4-77)
=viOUS EC' T'ON IS OBSOLETE
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