-------
350-
300-
Load 130-135 MWg
Fuel N 03%
Indicates Bottom
Of Range Noted
1981-88
(BOOS, FGR)
PG-DRB
(NEW)
PG-DRB
(2 YEARS)
PG-DRB
(EPRI)
35
30
25
Figure 7-9. Historical summary of Kahe 6 NOX and opacity (Kerho, 1991)
(Note: to convert ppm to Ib/MMBtu divide by 790)
a range in controlled levels from 141 to 172 ppm (0.18 to 0.22 Ib/MMBtu, second set of bars in
Figure 7-9). At the same time, opacity levels more than doubled, increasing to between 12 and
17 percent. These ranges in NOX or opacity are denoted by horizontal lines in the bars of
Figure 7-8. Two years later, performance had degraded somewhat, with NOX emissions being as
high as 180 ppm (0.23 Ib/MMBtu) and opacity levels reaching 20 percent (third set of bars in
Figure 7-9). To reduce opacity levels, additional modifications were then made to the boiler under
a program jointly sponsored by the Electric Power Research Institute (EPRI) and HECO (fourth
set of bars in Figure 7-9). New fuel atomizers were installed to reduce the size of the oil
droplets—smaller droplets burn out more completely, lowering the opacity—and the fuel and air flows
to the burners were balanced. As a result of these changes, NOX emissions were reduced to
152 ppm (0.19 Ib/MMBtu) and opacity levels were lowered to 10 percent (Kerho/ 1991).
7.4 HYDROCARBON EMISSIONS
THC emission test data are not commonly available for utility boilers. Since high CO, UBC,
and opacity levels precede THC emissions (Radak, 1991), monitoring of THC emissions is not
usually a part of the retrofit program. Table 7-10 summarizes the limited THC data collected as
part of this study for three boilers with NOX controls and seven units without controls. THC
7-21
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Table 7-10. Summary of total hydrocarbon (THC) emission data
Boiler Unit
Boilers with NOX
Controls:
Alamitos 6, CA
Ormond Beach 2, CA
Alamitos 6, CA
Ormond Beach 2, CA
Niles 1, OH
Uncontrolled Boilers:
Crist 6
Harllee Branch 3
Naughton 3
SCE Boiler
Widows Creek 6
Wood River I, IL
Wood River 4, IL
Fuel
Natural gas
Oil
Coal
Coal
Coal
Coal
Oil
Coal
Oil
Coal
THC Data (measured as
hexane)
No increase in THC
under lowest NOX
operating conditions
compared to pre-retrofit
No increase in solid
carbon or condensible
hydrocarbon under lowest
NOX conditions
Negligible THC gaseous
emissions
0.32 ppm (avg.)
0.56 ppm (avg.)
0.46 ppm (avg.)
1.75 ppm
0.39 ppm (avg.)
0.32 ppm
0.24 ppm
NOX Levels,
ppm @ 3% O2
(Ib/MMBtu)
16-90
(0.02-0.11)
90-150
(0.11-0.18)
275
(0.37)
290-681
(0.39-0.91)
148-747
(0.20-0.99)
169-569
(0.23-0.76)
NAa
290-68 1
(0.39-0.91)
63-95
(0.08-0.12)
465-490
(0.62-0.65)
Reference
Bayard de
Volo 1991
Bayard de
Volo 1991
Booth
1991
EPA 1974
EPA 1974
EPA 1974
Taback
1978
EPA 1974
EPA 1977
EPA 1977
aNA = No data available.
7-22
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emissions from these utility boilers were very low, ranging from negligible levels to less than 2 ppm
(THC as hexane), independent of fuel or boiler type.
For example, SCE reported an increase in THC emissions under the lowest NOX operating
conditions (off stoichiometric firing, low excess air, high FGR), compared to pre-retrofit conditions,
for both Alamitos Unit 6 and Ormond Beach Unit 2 when firing natural gas. There was also "no
increase in solid carbon or condensible hydrocarbons under lowest NOX conditions" when firing oil
(Bayard de Volo, 1991). Niles Unit 1, operating on coal, reported "negligible gaseous THC
emissions" (Booth, 1991). These three boilers illustrate that THC emissions from utility boilers tend
to be very low under low NOX conditions, regardless of the fuel used.
A short-term test of a SCE boiler firing No. 6 residual oil measured THC emissions of less
than 2 ppm, measured as hexane. The low level of hydrocarbon in this test was attributed to the
relatively long residence time of the combustion gases in the boiler, allowing ample time for more
complete combustion (Taback, 1978). Data are also provided on two boilers tested in the late 1970s
at Illinois Power's Wood River Power Plant. Short-term tests were conducted using oil and coal.
THC emissions were found to be less than 1 ppm for both fuels (EPA, 1977). Similar THC
emissions levels were measured at the remaining boilers, in Table 7-8, all of which were fired on
coal.
Typically, THC emissions from oil-fired utility boilers are on the order of 0.005 Ib/MMBtu,
while for natural gas-fired boilers, THC emissions are typically 1 x 10"5 Ib/MMBtu (Taback, 1978).
Three test programs on utility boilers measured hydrocarbon emissions less than 1 ppm in virtually
all tests, for both baseline and low NOX operation. It was concluded that THC emissions were
relatively unaffected by imposing NOX combustion controls on large utility boilers (EPA, 1980).
7.5 SUMMARY AND CONCLUSIONS
CO emissions data- for 25 coal-fired, 9 natural gas-fueled, and 12 oil-fired boilers were
examined in this study. These data are summarized in Table 7-11. Although the listed NOX
reduction ranges are very wide in general, when NOX combustion controls were used, there was
relatively little increase in CO emissions until 40 to 50 percent NOX reduction—referenced to
baseline levels—was achieved, beyond which CO levels begin to increase rapidly. The magnitude
of this increase varies widely from boiler to boiler, and is affected by fuel type, furnace volume, heat
release rate, burner configuration, NOX control technique, uncontrolled NOX level and control
target, and fuel/oxygen balance, as well as the condition of existing boiler equipment.
For PC wall-fired boilers, firing bituminous coal, CO was found to increase once greater
than 33 to 56 percent NOX reduction was reached. Corresponding NOX levels ranged from 280 to
390 ppm (0.37 to 0.52 Ib/MMBtu), while CO ranged from 8 to 60 ppm. For the natural gas wall-
fired boilers, the available data show that baseline CO values were not exceeded across a wide range
of NOX reductions, from 7 to 83 percent. The 7-percent reduction in NOX without CO increase was
due to NOX reduction efforts from an already controlled California utility boiler with an initial NOX
level of only 60 ppm (0.007 Ib/MMBtu). Test results on oil-fired boilers indicated a marked
increase in CO when greater than 26 to 57 percent NOX reduction was reached via combustion
modification. For some boilers, increases in CO from baseline were relatively minor, with CO
emissions never exceeding 40 to 50 ppm. Emissions data for one application of urea injection did
not show any noticeable effect on CO.
Combustion control retrofit experience to date has revealed that fuel/air imbalances can
cause large increases in CO emissions even at small NOX reduction levels. Modifications may be
7-23
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Table 7-11. Summary of NOX reduction levels achieved when
low-NOx CO = baseline (uncontrolled) CO
Fuel Type
Bituminous coal
Natural gas
Heavy (residual) oil
Boiler
Type
Wall-fired
Tangential
Cyclone
Wall-fired
Tangential
Wall-fired
Tangential
NOX Reduction Achieved,
CO = baseline CO
33 to 56
43 to 57
61a
7 to 83
17a
26 to 67
48a
*Data for one unit only.
necessary to adjust burner performance to balance air and fuel as part of the NOX control retrofit.
Therefore, CO versus NOX response in these cases cannot be predicted using the results of this
section and must await site-specific evaluation. This may be especially true for certain coal-fired
units, since coal-fired systems generally suffer more air/fuel imbalance than oil or natural gas-fired
units. However, the data suggest that on the average, 40 to 50 percent NOX reduction is possible
from existing baseline levels without markedly affecting baseline CO emissions. Often, when NOX
controls are applied, the excess oxygen level of the burner must be increased to maintain CO at
acceptable levels, limiting the amount of NOX reduction that is feasible and resulting in some
thermal efficiency loss.
Retrofit NOX controls had little effect on UBC in flyash levels when burning highly reactive
coal, as shown by data for eight boilers. Of the other wall-fired boiler data examined, post-retrofit
UBC values did not increase markedly from baseline levels until greater than 29 to 57 percent NOX
reduction was achieved. The coal particle fineness also affects the UBC level to a certain
degree—increasing fineness can offset some loss in combustion efficiency.
Although the data base on THC is too sparse to draw any definitive conclusions, limited test
data available indicate that THC emissions from utility boilers are very low, less than 2 ppm for the
boilers discussed in this section. This emission level was reported regardless of fuel type and
whether operating under baseline or low NOX conditions. The available data suggest minimal
impact of combustion controls on THC.
7-24
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R-7
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EXPLANATION OF APPENDICES A AND B
Appendices A and B contain data extracted from the EPA NURF data base on utility boiler
NOX emissions in the NESCAUM region, supplemented with revised utility data on unit size, age,
furnace design, firing type, heat rate, NOX emission factor, capacity factor, total 1987 NOX
emissions, and 1987 fuel consumption. The revised data were obtained from the ESEERCO1 study
and the following utilities/organizations:
Northeast States for Coordinated Air Use Management (NESCAUM)
United Illuminating Company
Consolidated Edison Company of New York, Inc. (Con Edison)
New York State Electric & Gas Corporation (NYSEG)
Niagara Mohawk Power Corporation (NMPC)
Public Service Electric and Gas Company (PSE&G)
Appendices A and B contain the NESCAUM boiler inventory for coal-fired units and oil-/gas-fired
units, respectively. Two spreadsheets are included in each appendix.
In the first spreadsheet, the information is sorted according to age, furnace design, and firing
type. Weighted average NOX emission factors (WANEFs) and weighted average capacity factors
are calculated for each furnace design/firing type category within each specified age group (0 to
20 years, 21 to 30 years, 31 to 40 years, and greater than 40 years). The WANEFs, in units of
"Ib/MBtu," are calculated using the individual NOX emission factors (NEF)-and boiler sizes (MW)
as follows:
WANEF =
The weighted average capacity factors (WACFs) are calculated with the individual factors (CF) and
boiler sizes (MW) as follows:
CF MW.
WACF =
Hunter, S. C, "NOX Emissions from Fossil Fuel Power Plants in New York State,"
KVB Report No. EP85-6, prepared for the Empire State Electric Energy Research
Corporation, August 1989.
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The data can be used to identify the units within a specific age and design group and the
representative capacity and NOX emission factors.
In the second spreadsheet, the information is sorted alphabetically according to the state,
utility, and plant names. The organization of the data facilitates the location of specific boilers of
interest.
At the end of each spreadsheet is a total for the 1987 NOX emissions, in tons; the capacity,
in MW; and the number of units used for that spreadsheet.
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APPENDIX A
NESCAUM BOILER INVENTORY-COAL-FIRED UNITS
A-1