EPA-600/2-75-022
August 1975
Environmental Protection Technology Series
EFFECTS OF TRANSIENT
OPERATING CONDITIONS
ON STEAM-ELECTRIC
GENERATOR EMISSIONS
\
HI
O
U.S. Environmental Protection Agency
Office of Research and Development
Washington, D. C. 20460
-------
EPA-600/2-75-022
EFFECTS OF TRANSIENT
OPERATING CONDITIONS
ON STEAM-ELECTRIC
GENERATOR EMISSIONS
by
J.S. McKnight
Research Triangle Institute
P.O. Box 12194
Research Triangle Park, N. C. 27709
Contract No. 68-02-1325, Task 10
ROAP No. 21BAV-002
Program Element No. 1 ABO 13
EPA Project Officer: R.V. Hendriks
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, N. C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D. C. 20460
August 1975
EPA-RTF LIBRARY
-------
EPA REVIEW NOTICE
This report has been reviewed by the National Environmental Research
Center Research Triangle Park, Office of Research and Development,
EPA, and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Environmental
Protection Agency, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environ-
mental Protection Agency, have'been grouped into series. These broad
categories were established to facilitate further development and applica-
tion of environmental technology. Elimination of traditional grouping was
consciously planned to foster technology transfer and maximum interface
in related fields. These series are:
1. ENVIRONMENTAL HEALTH EFFECTS RESEARCH
2. ENVIRONMENTAL PROTECTION TECHNOLOGY
3. ECOLOGICAL RESEARCH
4. ENVIRONMENTAL MONITORING
5. SOCIOECONOMIC ENVIRONMENTAL STUDIES
6. SCIENTIFIC AND TECHNICAL ASSESSMENT REPORTS
9. MISCELLANEOUS
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to
develop and demonstrate instrumentation, equipment and methodology
to repair or prevent environmental degradation from point and non-
point sources of pollution. This work provides the new or improved
technology required for the control and treatment of pollution sources
to meet environmental quality standards.
This document is available to the public for sale through the National
Technical Information Service, Springfield, Virginia 22161.
Publication No. EPA-600/2-75-022
11
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CONTENTS
Paqe
List of Figures v
List of Tables vii
Acknowledgments ix
Conclusions 1
Recommendations 11
Sections
1.0 INTRODUCTION 13
2.0 THE FOSSIL-FUEL-FIRED STEAM-ELECTRIC GENERATION PLANT 15
2.1 Locations and Sizes of Fossil-Fuel-Fired Steam-Electric
Generation Plants 16
2.2 Fuels and Combustion 17
2.3 Equipment in the Generation Plant 21
2.4 Control of the Boiler 23
2.5 Utilization of Steam-Electric Generation Plants 24
2.6 Availability of Data on the Operation of Plants 28
3.0 NORMAL, STEADY-STATE EMISSIONS FROM FOSSIL-FUEL-FIRED
STEAM GENERATORS 29
3.1 The Mass Balance Concept 33
3.2 Particulate Emissions 35
3.3 Visible Emissions 42
3.4 Sulfur Oxide Emissions 43
3.5 Nitrogen Oxide Emissions 44
3.6 Measurement of Sulfur Oxide and Nitrogen Oxide Emissions. . 50
3.7 Relationship Between Measurements of Emissions in Parts
Per Million and Rate of Emissions in Mass Per Input
Heating Unit 50
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CONTENTS (cont.)
Page
Section
4.0 EMISSIONS DURING TRANSIENT CONDITIONS OF OPERATION AND
EQUIPMENT MALFUNCTIONS 53
4.1 Startups 55
4.2 Shutdowns 59
4.3 Load Changes 62
4.4 Fuel Quality Variations 65
4.5 Miscellaneous Operating Transient and Equipment
Malfunctions 67
Appendix A THE FOSSIL-FUEL-FIRED STEAM-ELECTRIC
GENERATION PLANT 75
A.I The Fuel-Gas Circuit 77
A.2 The Water-Steam Circuit 79
A.3 Major Components of the Fuel-Gas Circuit ... 82
A.4 Boilers 88
References 103
IV
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FIGURES
No. Page
1 System power generation and load for the Duke
Power Company 26
2 System power generation and load for the Tennessee
Valley Authority 27
3 Mass balance schematic of fuel-gas circuit 34
4 The effect of precipitator collection efficiency
on the rate of particulate emissions for several
boiler designs and coal characteristics 37
5 The dependence of fly ash resistivity on flue gas
temperature and sulfur content of the coal 39
6 Relationship between collection efficiency and
plate area to gas flow ratio with various coal
sulfur contents. 41
7 Nitrogen oxide emissions from selected tangentially
fired boilers manufactured by Combustion Engineering,
Inc 45
8 The gross electrical output and emissions of NO and
A
SCL from Unit No. 1 of the Mohave Plant of the Southern
California Edison Company 54
9 Time a boiler can operate at full load for emissions to
be the same as during a boiler startup 58
10 Efficiency of a tandem mechanical collector and
electrostatic precipitator at the Shawnee Steam
Plant of the Tennessee Valley Authority 71
11 Service history for nine types of electrostatic
precipitators on the Tennessee Valley Authority system . . 73
12 Modern boiler 73
13 Schematic diagram of the water-steam circuit 81
14 Pulverized coal preparation systems. 83
15 Stoker furnace and boiler 85
16 Schematic drawing of cyclone furnace 86
17 Configurations of fuel-firing equipment in furnaces. ... 87
18 Several designs for tubular air heaters 91
19 Rotary-type air preheater (Ljungstrom) 92
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FIGURES (cont.)
No.
20 Two types of soot blowers 94
21 The electrostatic precipitator 96
22 Diagram of cyclone dust collector 98
23 Baghouse dust collector 99
24 Venturi wet scrubber 100
VI
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TABLES
No. Page
1 The effects of transient conditions of operation on stack
emissions 2
2 Typical range of coal analyses 17
3 Typical range of fuel oil analyses 19
4 Usual Amount of Excess Air Supplied to Fuel-Burning
Equipment 21
5 Emissions from selected coal-fired electric generation
plants for 1971 30
6 Particulate emissions for coal-fired boilers of Georgia
Power Company during cold starts 60
VII
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ACKNOWLEDGMENTS
The cooperation of the electric utilities and the manufacturers
of equipment used by the utilities has made this work easier. Messers.
Joseph Greco, Robert Ezzell, and Robert Moultrie of the Tennessee
Valley Authority, AndrewWinson of Georgia Power Company, Dennis
Norton of Southern California Edison Company, Julian D'Amico of Duke
Power Company, Robert Pollock of Carolina Power and Light Company,
and Harry Lord and Lyman S. Gilbert of Environmental Data Corporation
have contributed substantial time and effort in providing information
which can be used in this report.
Dr. Jamshed A. Modi and Mr. Charles H. Gooding of RTI have done
much of the work of this study. Dr. Forest 0. Mixon has been the
overall supervisor for this study.
Mr. R. V. Hendriks of the Industrial Environmental Research
Laboratory of the Environmental Protection Agency has provided direction
for the project and coordinated this work with the other projects of the
Agency. The utility of this report is a result of his knowledge of the
problems and missions which are faced by the regulator and the regulated.
IX
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CONCLUSIONS
Data were collected from a number of steam-electric generation plant
operators to establish the relationship between atmospheric emissions and
the operation of a generation plant under transient or upset conditions.
Older, coal-fired steam generators that are equipped with a particulate-
cleaning device as the only air pollution control equipment (i.e., no
SOV flue gas desulfurization system) are considered in the study. Emissions
A
resulting from the transient operation of flue gas desulfurization systems
are being investigated in other EPA-sponsored efforts.
A study of the operations involved in a steam-electric generation
plant shows that transient conditions of operation affect the rate of
emission of pollutants from the stack. Startups, shutdowns, load changes,
fuel quality variations, electrostatic precipitator malfunctions, and
other operating transients and equipment malfunctions are reviewed in the
study. Conclusions about emission of particulates, visible emissions, and
nitrogen oxides during these conditions that can be drawn from the col-
lected data are presented in Table 1. The mass emission rate of sulfur
oxides is in proportion to the fuel supplied to the boiler and to the
sulfur content of the fuel; process variables do not affect the mass
emitted. Therefore, the effects of transient conditions on sulfur
oxide emissions are excluded from Table 1.
Adequate data obtained under carefully controlled and monitored
conditions were not found to be available for the thorough characteriza-
tion of the effect of transient conditions of operation on the rate of
gaseous emissions from a steam generation plant. Few plants have con-
tinuous monitors of stack emissions that are necessary for seeing
transient conditions. No continuous monitoring station was found that
correlated the emissions with the boiler parameters.
-------
Table 1. The effects of transient conditions of operation on stack emissions
rs>
Cause of
transient
condition
STARTUPS
Normal cold
startup pro-
ce dure ' for
c o a l-f i red
boiler (hot
startup is
similar ex-
cept oil-fired
warmup is of
shorter dura-
tion)
Delay in en-
ergizing pre-
cipitator
Effect on
process
control
system
Manual or automatic
compensation
in the process
control system
Frequency
of
occurrence
Nonoptimum
combustion
parameters;
gradual load
increase; de-
layed start of
precipitator
Fly ash is not
collected un-
til precipita-
tor is energiz-
ed
Boiler and related
equipment usually
on manual control
until fire is stabiliz-
ed; excess air usual-
ly maintained high
for better control of
fire
None
12/yr for
base-load-
ed plant
to 50/yr
for small
peaking
plant
Duration of
transient
condition
a) First step:
1/2 - 5 hr of
oil firing
b) Second
step:
0 - 8 hr oil
and coal
firing
c) Third
step:
About 1 hr
(total startup
time usually
is less than 8
hrl
Length of de-
lay
Effect on
stack emissions
Particulates
Oxides of
nitrogen
Comments
No control, essentially all
ash emitted, characteristic
dark plume with oil
No control, approximately
75% of coal ash emitted if
precipitator is not energiz-
ed, oil plume still present
Possible emission of un-
burned carbon due to non-
optimum combustion pa-
rameters
Excessive emissions occur
Low flame
temperature.
NOX proba-
bly low
Low load and
temperature.
N O x proba-
bly low
NOX proba-
bly low
None
Gradual increase in fuel and air flow
as boiler and turbine warm; unit is
paralleled with system when turbine
reaches rated speed.
Precipitator is energized when inlet
gas temperature is above 135°C. De-
laying energization until flue gas is
above dew point avoids collection of
wet ash which could foul wires and
plates or plug hoppers.
Pulverizer mills supply coal one at a
time until flame is stabilized; oil fir-
ing stops after 2 or 3 mills are in
operation.
Usual procedure is to energize precip-
itator after flue gas is above dew
point; however, at least two oper-
ating companies energize when first
coal is fired (see text).
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Table 1. The effects of transient conditions of operation on stack emissions (con.)
Cause of
transient
condition
Effect on
process
control
system
Manual or automatic
compensation
in the process
control system
Frequency
of
occurrence
Duration of
transient
condition
Effect on
stack emissions
I Oxides of
Particulates | nitrogen
Comments
SHUTDOWNS
Normal shut-
down proce-
dure
Turbine trip
(emergency
sh u t down
caused by
malfunction
in turbine.
generator,
output trans-
former, or
other equip-
ment or con-
trols)
Fuel trip
(emergency
shut down
caused by
malfunction
in the boiler.
fuel system.
or other
equipment or
controls)
Gradual de-
crease of fuel
and air to
boiler
I mmedi ate
loss of load
I mmediate
loss of fuel to
boiler
Fuel to air ratio is
kept in normal
range; precipitator
remains energized
until stack gas
reaches dew point;
rapping continues
until fly ash is re-
moved from sur-
faces
Immediate closing
of steam values
blocking steam from
turbine, fuel flow
stopped, excess
steam vented to at-
mosphere through
relief valves
Residual heat is
used to generate
steam and drive the
turbine as long as
possible, then load
is dropped. Precipi-
tator is operated as
for normal shut-
down.
12/yr for
base-load-
ed plant
to 50/yr
for small
plant
Rare, less
than one/
yr
Rare, 2/yr
a) First step:
2 -3 hours
b) Second
step:
12-14 hours
a) First step:
Steam vents
for approxi-
mately 1
m i n . Fuel
flow stops
within a few
seconds.
b) Second
step:
12 - 14 hours
a) First step:
Fuel f I ow
stops com-
pletely with-
in a few sec-
onds
b) Second
step:
12-14 hours
Emissions decrease as load
is reduced; excessive emis-
sions occur if precipitator
is deenergized too soon
If draft is used for cooling
boiler, wisps of fly ash
from boiler, duct work.
and precipitator will be
emitted from stack
Vibrations caused by vent-
ing of steam could shake
loose ash deposits causing
puffs of particulates from
stack
If draft is used for cooling
boiler, wisps of fly ash
from boiler and duct work
will be emitted from stack.
Emissions drop rapidly as
fuel flow is lost
If draft is used for cooling
boiler, wisps of f!y ash
from boiler and duct work
will be emitted from stack.
Decreases as
load is re-
duced
None
Emissions
drop rapidly
as fuel flow is
stopped
None
Emissions
drop rapidly
as fuel flow is
lost
None
Boiler gradually and stepwise is drop-
ped to about 1/3 to 1/2 load; then
fuel flow is stopped, and precipitator
is deenergized.
Precipitator is not left on during boil-
er cooling because condensation
would occur on wires and plates.
Precipitator tripped after fuel flow
stops.
Precipitator is not left on during boil-
er cooling because condensation
would occur on wires and plates.
Because fuel feed equipment occurs
in multiple units, a plant rarely is
tripped because of equipment failure
in the fuel feed system. However, a
deterioration in fuel quality, such as
high moisture content, may make it
difficult to maintain the furnace
flame.
-------
Table 1. The effects of transient conditions of operation on stack emissions (con.)
Cause of
transient
condition
Effect on
process
control
system
Manual or automatic
compensation
in the process
control system
Frequency
of
occurrence
Duration of
transient
condition
Effect on
stack emissions
Oxides of
Participates ! nitrogen
Comments
LOAD CHANGES
Normal cycli-
cal variations
in load
Load reduc-
tion caused
by disruption
of fuel sup-
ply (caused
by malfunc-
tion in feed-
e rs, burners.
or other fuel
cycle equip-
ment or con-
trols)
Failure of
coal pulver-
izer mill
Quasi -steady
state opera-
tion at slowly
varying loads
Fuel supply
inadequate
for load; ex-
cess air high-
er than nor-
mal
Reduction of
fuel supplied
to boiler; fur-
n ace tem-
perature re-
duced
Load changes grad-
ually maintaining
near optimum firing
conditions so tran-
sient effects are be-
lieved to be negligi-
ble
Load is shed; fur-
nace draft is re-
duced to normal ex-
cess-air range; oil
may be used as sup-
plementary fuel un-
til flame is stabilized
Fuel requirements
supplied by remain-
ing mills
Diurnal
May be
frequent
if low
quality
fuel is be-
ing fired
Rate is re-
lated to
fuel quali-
ty; high
moisture
causes
clogging.
rocks
cause ex-
ce s s i ve
wear
Varies -
change of
10% of maxi-
mum rated
load requires
15-30 min-
utes
Varies ac-
cording to
magnitude of
load reduc-
tion; 1-15
minutes is
typical range
a) First step:
1-15 min-
utes to stabi-
lize boiler
b) Second
step:
After boiler
is stabilized
Precipitator efficiency nor-
mally improves at reduced
load and deteriorates at
overloading
Normally no transient ef-
fect; visible plume may re-
sult if oil is fired; when
stabilized at lower load.
emissions should be de-
creased
Slight decrease in rate of
emissions because of a de-
crease in the rate of burn-
ing fuel
May increase if same rate
of fuel feed is maintained
by fewer pulverizers (effi-
ciency of one precipitator
decreased by 1%)
Reduced at
lower loads
May increase
if excess air is
high; when
stabilized at
lower load.
emissions
should be de-
creased
May decrease
because of re-
duced fur-
nace temper-
ature; may
increase be-
cause of in-
creased ex-
cess air
No change
Minimum output firing only with
coal usually is 40% full-load output;
at night, base-loaded units frequently
are reduced to 50-60% full load so
that intermediate-sized units will not
have to be shut down.
Time of transient can vary greatly
with design of boiler and control
systems. Newer electronic controls
normally are faster than pneumatic
controls.
Pulverizing mills grind coal better at
lower supply rates, and the combus-
tion of pulverized coal improves as
the particle size becomes smaller.
Therefore, the rate of fly ash emis-
sions from a furnace and, conse-
quently, the load on the precipitator
increase if fewer pulverizers are used
to grind a given amount of coal.
-------
Table 1. The effects of transient conditions of operation on stack emissions (con.)
Cause of
transient
condition
Effect on
process
control
system
Manual or automatic
compensation
in the process
control system
Frequency
of
occurrence
Duration of
transient
condition
Effect on
stack emissions
I Oxides of
Particulates | nitrogen
Comments
LOAD CHANGES (con.)
Load reduc-
tion caused
by disruption
of air supply
(caused by
malfunction
of ID fan, FD
fan, damper.
or other draft
equipment or
controls)
Forced load
reduction
caused by
other reasons
not directly
limiting fuel
or air flow
(e.g., mal-
function in
f eedwater.
steam, or
condensate
system)
Abrupt in-
crease in load
Air supply in-
adequate for
complete
combustion
Load might
be reduced
s I owly as
with normal
cyclical varia-
tions or ab-
ruptly with
resultant
nonoptimum
firing con-
ditions
Fuel, steam.
and air flow
must be in-
creased
Load is shed; fuel
flow is reduced until
normal excess air
range is achieved; oil
may be used as sup-
plementary fuel un-
til flame is stabilized
Load is shed; fuel
flow to air flow
ratio could cycle un-
til normal range is
achieved at new
load; oil may be
used as supplemen-
tary fuel until flame
is stabilized
Fuel flow to air
flow ratio could
cycle until normal
range is achieved at
new load
Rare, less
than one/
yr
Rare,
maybe
4/yr
Less than
6/yr
Varies ac-
cording to
magnitude of
load reduc-
tion; 1-15
mi n utes is
typical range
Varies
according to
magnitude of
load re-
duction; 5
minutes to 1
hour is typi-
cal range
Varies ac-
cording to
magnitude of
load change;
5 min. to 1
hour is typi-
cal range
Lower gas flow rate tends
to improve efficiency but
unburned carbon may be
emitted because of low air
level; visible plume may re-
sult if oil is fired; when sta-
bilized at lower load, emis-
sions should be decreased
Unburned carbon may be
emitted if excess air is low;
visible plume may result if
oil is fired; when stabilized
at lower load, emissions
should be decreased
Unburned carbon may be
emitted if excess air is low;
emissions will be increased
at higher load but not
necessarily in excess of
limits
Decreased
while excess
air is low;
when stabiliz-
ed at lower
load, emis-
sions should
be decreased
E m iss ions
may cycle
hi gher with
high excess
air, lower
with low ex-
cess air; when
stabilized at
lower load.
emissions
should be de-
creased
Emissions
may be high-
er with high
excess air,
lower with
low excess
air; when sta-
bi I ized at
higher load.
emissions will
be increased
Time of transient can vary widely
with design of boiler and contro
systems. Newer electronic controls
are faster than pneumatic. If unit has
only one ID fan or FD fan, a shut
down may be required. If the excess
air is low, the emission of carbon
monoxide is increased until excess air
reaches normal range.
Time of transient can vary greatly
with design of boiler and control
systems. Newer electronic controls
normally are faster than pneumatic
controls; emission of carbon monox-
ide is also increased if excess air is
lower than normal.
Time of transient can vary greatly
with design of boiler and control
systems. Newer electronic controls
normally are faster than pneumatic
controls; emission of carbon monox-
ide is also increased if excess air is
lower than normal.
CJl
-------
Table 1. The effects of transient conditions of operation on stack emissions (con.)
Cause of
transient
condition
Effect on
process
control
system
Manual or automatic
compensation
in the process
control system
Frequency
of
occurrence
Duration of
transient
condition
Effect on
stack emissions
I Oxides of
Particulates I nitrogen
Comments
FUEL QUALITY VARIATIONS
Fuel supply
reaches bunk-
er turnover
point
Excessive
moisture in
coal
Excessive ash
in coal
Ash with in-
creased slag-
ging tenden-
cies
Coal quality
parameters
may change
abruptly, up-
setting opti-
mum firing
conditions
Clogging of
bunkers,
feeders, or
mills
Fuel system
may be un-
able to pro-
vide suffi-
cient fuel for
full-load
operation
Slag tends to
build up on
furnace walls
and reduce
heat transfer
to tubes
May cause transient
cycling of fuel flow
rate or excess air
Load may have to
be dropped; older
units often put on
manual control; oil
is used as supple-
mentary fuel to sta-
bilize flame
Unit may have to
operate at less than
full load if problem
is severe
May have to in-
crease excess air to
control wall depos-
its
2/day
Usually
related to
weather
conditions
such as
rainy sea-
son
Possible
with
change of
source for
fuel
Possible
with
change of
source for
fuel
Varies from
un noticeable
transition to
upset of per-
haps 15 min-
utes duration
As long as
several days
Until fuel
quality re-
turns to nor-
mal
Until fuel
quality re-
turns to nor-
mal
Probably no affect unless
ash content changes drasti-
cally; see "Excessive ash in
coal" below
Normally no effect; visible
plume may result if oil is
fired
Higher inlet particulate
loading on precipitator
may result in excessive
emissions
Emissions may be in-
creased if draft is increased
appreciably; emissions may
be increased or decreased
by changes in flue gas tem-
perature
Emissions
may cycle as
fuel to air
ratio cycles.
lower emis-
sions with
low excess air
and higher
emissions
with high ex-
cess air
Emissions
will decrease
with load re-
duction
None
Emissions
will increase
since higher
gas tempera-
ture will oc-
Coal is filled into a bunker in
batches. The bunker turnover print is
the time at which a new batch of coal
first reaches the boiler.
See also "Load reduction, disruption
of fuel supply" above.
Not likely to be noticeable as a short-
term transient problem.
cur as heat
transfer to
t u bes is re-
duced; in-
creasing ex-
cess air to
control slag-
ging will also
increase emis-
sions
-------
Table 1. The effects of transient conditions of operation on stack emissions (con.)
Cause of
transient
condition
Effect on
process
control
system
Manual or automatic
compensation
in the process
control system
FUEL QUALITY VARIATIONS (con.)
Variation in
sulfur con-
tent
Variation in
chemical con-
tent of ash
Change the
resistivity of
the fly ash
May change
the resistivity
and particle
size of fly ash
Electrostatic field
intensity in precipi-
tator for optimum
collection efficiency
may change
Electrostatic field
intensity in precipi-
tator for optimum
collection efficiency
may change
Frequency
of
occurrence
Duration of
transient
condition
Effect on
stack emissions
Particulates
Oxides of
nitrogen
Comments
Possible
with
change of
source for
fuel
Possible
with
change of
source for
fuel
Until fuel
quality re-
turns to nor-
mal
Until fuel
quality re-
turns to nor-
mal
Efficiency of collection
will change
Efficiency of collection
may change
None
None
-------
Table 1. The effects of transient conditions of operation on stack emissions (con.l
Cause of
transient
condition
Effect on
process
control
system
Manual or automatic
compensation
in the process
control system
Frequency
of
occurrence
Duration of
transient
condition
Effect on
stack emissions
I Oxides of
Particulates I nitrogen
Comments
ELECTROSTATIC PRECIPITATOR MALFUNCTIONS (frequency of occurrence given as bus section unavailability in percent of operating time)
Fa i I u re in
power supply
(transformer
or rectifier)
E I e c trode
short to
ground: (1)
at bushing,
(2) at ash
hopper
Broken elec-
trode
Inability to
remove ash
from hoppers
FaiJure of
rappers or vi-
brators
F a i 1 u re in
control cir-
cuits
Loss of ser-
vice of bus
sect i on (s)
supplied
Equivalent to
loss of power
supply; total
1 oss of per-
formance of
bus section (s)
Normally will
short out en-
tire bus sec-
tion
Reentrain-
ment of ash,
possible short
of electrode
(see above)
Buildup of
ash on wires
or plates
Loss of ser-
vice for bus
sections af-
fected
Stop power to pow-
er supply
Disconnect bus sec-
tion from power
supply
Disconnect bus sec-
tion from power
supply
Use sledgehammer
to jar hopper walls
or stir ash with rods
through access ports
None
Stop power to pre-
cipitator
1 - 25%,
but usual-
ly < 4%
for all
failures
taken to-
gether
Usually
<1%
0 - 7%,
usually
<1%
0 - 3%,
usually
<1%
1 - 10%,
usually
< 2%
0 - 1%,
usually
<03%
Replacement
may take one
week if spare
is available
Until repair
Until repair
Until ash
flow can be
restored, usu-
ally < 1 hr
Until repair,
usually sever-
al hours
Until repair,
usually sever-
al hours
Emissions increase, magni-
tude depends on configura-
tion of precipitator
Emissions increase, magni-
tude depends on configura-
tion of precipitator
Emissions increase, magni-
tude depends on configura-
tion of precipitator
Emissions increase
Emissions are reduced for a
few hours because reen-
trainment of ash is re-
duced; eventually emis-
sions increase because of
ash caking on wires or
plates
Emissions increase
None
None
None
None
None
None
Must shut down boiler to repair if
problem is internal; otherwise, repair
can be made with boiler in service.
The power supply usually is repaired
at the factory in several weeks. On
some precipitators the power supply
is difficult to reach for replacement.
(1) Must shut down boiler to repair
(2) May have to shut down boiler to
repair
Must shut down boiler to repair
May have to shut down boiler to re-
pair; problem may be caused by
burning coal with higher ash content
than precipitator was designed to
handle.
Repair can be made with the boiler
on line.
00
-------
Table 1. The effects of transient conditions of operation on stack emissions (con.)
Cause of
transient
condition
Effect on
process
control
system
Manual or automatic
compensation
in the process
control system
Frequency
of
occurrence
Duration of
transient
condition
Effect on
stack emissions
Participates
MISCELLANEOUS OPERATING TRANSIENTS AND EQUIPMENT MALFUNCTIONS
Soot blowing
Fai 1 ure of
soot blowing
system
A c c u m u 1 a-
tion of clink-
ers in bottom
arch of boiler
Malfunction
of burner tilt
mechanism
Increases par-
ticulate load
to precipita-
tor
Excessive ac-
cumulations
on surfaces
reduce heal
transfer
Heat transfer
to water wall
tubes is re-
duced
Partial loss of
steam tem-
perature con-
trol; more
limited flame
control
None
If efficiency of boil-
er is significantly af-
fected, more fuel
will be required to
maintain load
If efficiency of boil-
er is significantly af-
fected, more fuel
will be required to
maintain load
None
Every 8
h r or
more
often
1 per 3
m o n t h s
for r e-
tractable
bl owers.
1/week to
1/day for
wall blow-
ers
2/yr with
poor qual-
ity of coal
1/yr
5 - 15 min-
utes for inter-
mittent blow-
ing
Until repair
Until repair
when boiler
is out of ser-
vice
Until repair.
about 4 hr
Emissions will increase un-
less precipitator is designed
to handle the increased
loading
May increase because of
higher gas flow rate; may
increase or decrease be-
cause of higher gas temper-
ature
May increase because of
higher gas flow rate; may
increase or decrease be-
cause of higher gas temper-
ature
None
Oxides of
nitrogen
No transient
e f f ect but
cleaning sur-
faces reduces
NOX by im-
proving heat
transfer and
I owering gas
temperature
May increase
because of
higher gas
tempera tu re
May increase
because of
higher gas
temperature
Depends on
number of
burners af-
fected and
the tilt. NOX
emissions in
tangentially
fired boilers
are usually
lowest when
burners are
horizontal.
Comments
Rate varies with boiler; some blow
soot on automatic cycle almost con-
tinuously; some blow soot at the dis-
cretion of the operator.
Wail boilers can be removed and re-
paired while a boiler is in service. A
bearing failure is the most frequent
trouble with a retractable blower; on
some boilers it cannot be repaired
while the furnace is in service.
Problem exists when burning coal of
high ash content and low ash fusion
temperature. Boiler should be in-
spected for clinkers whenever out of
service.
-------
Table 1. The effects of transient conditions of operation on stack emissions (con.)
Cause of
transient
condition
Effect on
process
control
system
Manual or automatic
compensation
in the process
control system
Frequency
of
occurrence
Duration of
transient
condition
Effect on
stack emissions
Particulates
Oxides of
nitrogen
Comments
MISCELLANEOUS OPERATING TRANSIENTS AND EQUIPMENT MALFUNCTIONS (con.)
Motor failure
in rotating
( Ljungstrom)
air preheater
Movement of
personnel in
precipitator
during shut-
down
Boiler tube
failure
Primary and
secondary air
temperature
is reduced;
flame tem-
perature is re-
duced; flue
ga se s not
cooled by air
preheater
Draft blows
fly ash out
stack
Possible loss
of steam
pressure
Put spare motor in-
to operation if avail-
able, usually unit
must be shut down
None
None
Rare
Several/yr
Until spare
motor is put
into opera-
tion or main
motor is re-
paired
As long as
personnel
move about
precipitator
Until repair
Higher volumetric flow
rate through precipitator
will increase emissions; in
cold-side precipitator in-
crease in gas temperature
of 200 - 300° will tend to
increase collection ef-
ficiency
Fly ash emissions occur
with no input fuel
Possible increase because
of poor conditions of com-
bustion during shutdown
Emissions are
reduced be-
cause of low-
er flame zone
temperatures
None
If spare motor is not available, shut-
down of boiler is required to prevent
warping of air preheater from ther-
mal stress
Fly ash emissions during such an epi-
sode are unavoidable and insig-
nificant.
Small leaks in upper furnace (rehea-
ter or superheater) tubes may be
tolerated for several days. However, a
wall tube failure in the lower furnace
usually requires an immediate shut-
down.
-------
RECOMMENDATIONS
To obtain a precise knowledge of the effects of transient conditions
of operation on the emission of gaseous pollutants from a fossil-fuel-
fired steam-electric generation plant, an experimental program must be
organized that monitors both the emissions of pollutants and the param-
eters of boiler operation. Because each boiler has its own characteristic
behavior, the extrapolation of performance from one boiler to another is
difficult, especially if the boilers are different in size. Therefore,
an extensive program of continuous monitoring is necessary for the accumu-
lation of data adequate for statistical analysis of transient conditions.
Utility companies may be willing to cooperate in the establishment
of a monitoring program. The utility company would gain experience in
the operation of monitors and learn more about control of its equipment
for the creation of optimum conditions of operation with respect to energy
conversion and the emission of pollutants.
11
-------
1.0 INTRODUCTION
Air pollution standards generally are based upon control of a spe-
cified percentage of emissions during steady-state operation of a con-
trol system. Periods of startup, shutdown, and malfunctions of process
and air pollution control equipment generally are not subject to meet-
ing a prescribed standard (ref. 1).
However, these periods of transient operating conditions are be-
coming recognized as contributing to the accumulation of pollutants
in the ambient atmosphere and as the cause for short-term, localized
accumulations of high concentrations of pollutants. Regulatory agencies
are beginning to recognize the need to place greater emphasis on in-
suring that process sources minimize both the number of emission-causing
malfunctions and the emissions when malfunctions do occur (ref. 2).
This enforcement effort is being taken in one or more of the following
approaches:
1. Requirements to report malfunctions and steps taken to mini-
mize emissions during these occurrences;
2. Review of design and proposed maintenance of critical equip-
ment in proposed new plants;
3. Litigation against sources that, in the opinion of the
regulatory agency, continue to have abnormally high occurrences of mal-
functions.
In order to supplement this effort, information is required to
identify malfunctions, to determine emissions during their occurrence,
to determine how and when they occur in practice, and to identify methods
for their prevention and minimization. Uith this information, specific
strategies can be developed to reduce environmental problems created by
process and equipment malfunctions.
This report focuses on developing information on the malfunction of
fossil-fuel-fired steam-electric generators. More specifically, the re-
port focuses on older coal-fired steam generators that are equipped
with a particulate-cleaning device as the only air pollution control
equipment (i.e., no SOY flue gas desulfurization system). These generators,
/\
usually 100-500 MW in electrical output capacity, are frequently being
used to provide the cycling portion of the diurnal variation in power
13
-------
generated by electrical utilities. In such use, they are subject to
operating in a transient mode a large percentage of the time. Newer,
base-loaded generators are of more efficient and reliable design than
the older plants. However, the effects of transient conditions on
emissions from the newer plants should be similar to the effects for
the older plants.
14
-------
2.0 THE FOSSIL-FUEL-FIRED STEAM-ELECTRIC GENERATION PLANT
The stationary source of air pollution considered in this report
is the fossil-fuel-fired S':eam-electric generation plant. The fossil
fuel, either coal, oil, or natural gas, is burned in a furnace to
produce heat; the heat vaporizes water to steam in a boiler; the steam
is used to drive a turbine; and the turbine drives an alternator, which
generates electricity.
The principal emissions from a fossil-fuel-fired electric
generator are soot, particulates, and the oxides of nitrogen and
sulfur. When a generator -;s equipped with a particulate collection
device, soot is a significant emission only during conditions of
poor combination in the furnace. Particulate emissions are not a
concern when the fuel is oil or natural gas because of the negligible
ash content of these fuels. The use of coal with an ash content of
5-16 percent as a fuel requires the use of an electrostatic precipi-
tator to control the emission" of fly ash. Since 1970 most older coal-
fired electric generators have been equipped with precipitators of 95
percent collection efficiency or better. New coal-fired electric
generators are being equipped with precipitators whose collection
efficiency is better than 99 percent.
The emission of the oxides of nitrogen is a function of the
conditions of combustion in the boiler. All fossil fuels produce
about the same rate of emissions of oxides of nitrogen.
The rate of emissions of the oxides of sulfur depends upon the
sulfur content of the fuel. Natural gas contains a negligible amount
of sulfur, oil contains 0.1-4.4 percent sulfur, and coal contains
014-5.5 percent sulfur. Devices that collect sulfur oxides from
stack gases are not considered in this study.
The electric generators of principal concern in this report are
the older coal-fired generators, usually 100-500 Mw in electrical out-
put capacity, which are being used for providing the cycling portion of
the diurnal variation in power generated by electric utilities. Newer,
15
-------
base-loaded generators are of more efficient and reliable design
than the older plants. However, the effects of transient conditions
on emissions for the newer plants should be similar to the effects
for the older plants. Oil-fired and gas-fired generators are not
considered in detail because they are easier to control and are less
subject to the upset conditions found in coal-fired plants.
2.1 LOCATION AND SIZES OF FOSSIL-FUEL-FIRED STEAM-ELECTRIC GENERATION
PLANTS
Most electric generation plants in the United States are fired by
fossil fuels. The local cost of fuel and pollution abatement require-
ments determines what type of fuel is used. Throughout the Appalachians
and the Southeast, coal is used because of the availability, low
transportation costs, and lack of difficulty in meeting pollution
abatement requirements. In the Northeast, oil is the principal fuel
because of the high cost of transporting coal and the stringent
pollution abatement procedures required near large cities. In the
Southwest, natural gas is used for fuel because of the availability.
On the Pacific coast, fuel oil is used because of the pollution
problems.
The first steam-electric generation plant that used turbines
exclusively was the Fisk Street Station of the Commonwealth Edison
Company, Chicago. The plant commenced operations in 1903 with two
turbines, rated at 5 MW, each driven by eight 500 hp boilers. Upon
completion, the Station contained eighty 500 hp boilers, four turbines
rated at 5 MW, and six turbines rated at 8 MW (ref. 3). By 1925 gen-
eration units of 60 MW were being placed in service, by 1956 generation
units of 500 MW were being placed in service, and today units of 1,600
MW have been placed in service.
Boilers are designed for a lifetime of 30-40 years. Because most
generation units smaller than 100 MW were placed in service more than
40 years ago, generators in service today are 100 -1,600 MW in size.
16
-------
2.2 FUELS AND COMBUSTION
The combustion of fuel is the source of all air pollution that
comes from a plant. The amount of pollution resulting from combustion
varies considerably with the type of fuel. However, no fuel now being
used for combustion in an electric generation plant can be burned with-
out pollution of the atmosphere.
Most steam-electric generation plants burn fossil fuels. The
fossil fuels were created by the fossilization of organic matter in
the earth over a long period of time. The fossil fuels are coal, oil,
and natural gas. Coal is the fuel that is used most frequently to
fire steam-electric generators. Oil or natural gas sometimes is
used because of advantageous conditions of supply or the need for
significantly lower pollution.
Other fuels that are used to fire steam-electric generation
plants are urban wastes (usually as a supplementary fuel) and wood
wastes, especially in the wood-processing industries. Because these
fuels are used infrequently, they will not be discussed further.
2.2.1 Coal
Coals are classified under four major categories and several sub-
categories. The major categories are lignite, subbituminous, bitumi-
nous, and anthracite. Table 2 shows typical ranges of analysis of
Table 2. Typical range of coal analyses
Rank Anthracite Bituminous Subbituminous Lignite
Analysis:
Moisture, % 2-5 2-15 15-30 25-45
Volatile
matter, %
Fixed carbon, %
Ash, %
Heating Value,
103 Btu/lb
Sulfur, %
Nitrogen, %
17
5-12
70-90
8-20
12-14.5
<1
L5-1
18-40
40-75
3-25
10-14
0.5-5
1-2
30-40
35-45
3-25
8-10.5
0.5-3
1-1.5
25-30
20-30
5-30
5.5-8
0.5-2.5
0.5-1.5
-------
these four categories. Lignite has a distinct woody or clay-like
structure, a moisture content of 30-45 percent, and a low heating
value of 5,500 to 8,000 Btu per pound. Upon drying, lignite
disintegrates into flakes. Lignite is increasing in commercial
importance as supplies of high grade coal are depleted. Subbi-
tuminous coal, although of higher quality than lignite, also has a
high moisture content and a relatively low heating value. Anthracite
is a hard, smokeless coal that has less than 8 percent volatile
matter and is generally slow to ignite.
Bituminous coals are the principal fuels for power generation
in the United States because of their availability and favorable price.
These coals have a wide variation in volatile matter content. The
bituminous coals of low volatility have a low moisture content and
high heating value and produce little smoke when burned, whereas
the bituminous coals of high volatility have a high moisture content
and can produce an objectionable amount of smoke unless properly
burned in a furnace of sufficient size to burn the volatile gases.
The ash residue remaining after the combustion of coal may be in
a variety of forms: small, dry particles; chunks of slag; or a pool
of molten ash. The form of the ash residue depends on the fusion
characteristics of the ash and on the temperature and method of
combustion.
Coal used for fuel commonly is analyzed by two methods, the
proximate analysis and the ultimate analysis. The proximate analysis
determines the energy content and the percent by mass of moisture,
ash, volatile matter, and a fixed carbon. The ultimate analysis de-
termines the mass percent of carbon, hydrogen, nitrogen, oxygen,
sulfur, and ash. In the ultimate analysis, the hydrogen and oxygen
contained in the moisture in the fuel may be reported separately as
moisture.
2.2.2 Fuel Oil
Fuel oils are divided into five standard grades on the basis of
specific gravity and viscosity. Analysis results often report
specific gravity, viscosity, heating value, and percent by mass of
18
-------
sulfur, hydrogen, carbon, and ash. Table 3 reports typical analyses
for the five grades. Numbers 1 and 2 fuel oils are distillates.
Because the distillate oils are obtained by the condensation of the
hydrocarbon vapors from crude stills, they are essentially free of
ash. The distillate oils are used as fuel in domestic and light
industrial applications and for starting a boiler that burns coal.
Numbers 4, 5, and 6 fuel oils are the residual oils obtained after
distillation that contain the ash that was present in the crude oil.
Number 6 oil, also called Bunker C oil, is the primary fuel oil used
in large-scale power generation. Compared to coal, number 6 fuel
oil contains a small amount of ash, but it may be high in sulfur
content.
2.2.3 Natural Gas
Natural gas is a generic term applied to underground accumulations
of gaseous fuels of widely varying composition. Typical constituents
are 85-95 percent methane, 0-5 percent nitrogen, and negligible sulfur,
Table 3. Typical range of fuel oil analyses
Distillate oil
Residual oil
Grade
No.l
No.2
No.4
No.5
No.6
Analysis
Gravity. °API
Viscosity,
Saybolt sec.
Heating value,
103 Btu/gal
Sulfur, %
Hydrogen, %
Carbon, %
Nitrogen, %
Ash, %
35-42
30-35
33-37
23-25
18-22
12-16
45-125 150-700 900-9000
134-138
0.1-0.3
12-14
86-88
<0.01
0.01
136-144
0.2-0.8
12-14
86-88
<0.01
0.01
143-146
1-3
11-12
86-88
0.1-0.5
0.01-0.1
145-149
1-3
10-12
86-88
0.1-0.5
0.01-0.1
149-152
1-5
10-12
85-88
0.1-0.5
0.01-0.3
19
-------
with the remainder consisting of ethane, propane, and other hydro-
carbons. The specific gravity of natural gas relative to air varies
from about 0.6 to 0.7, and the heat content is typically 1,000 to
1,100 Btu/ft3.
Of all fossil fuels, natural gas is the cleanest and easiest to
burn in a steam generator. The gas is piped directly to the plant,
where storage and handling are minimal. Complete combustion can be
obtained with a low level of excess air and no smoke emissions.
However, natural gas now is in very short supply, and the cost of
firing with natural gas is prohibitively high for electric utilities
except under unusual conditions of a favorable supply or requirements
for low emissions.
2.2.4 Combustion Parameters
Depending on the conditions of combustion and its completeness,
mixtures of complex hydrocarbon compounds contained in fossil fuels
are converted to a series of intermediate substances and combustion
products. Under ideal conditions of complete combustion, carbon is
converted to carbon dioxide (CO^), hydrogen to water vapor (H20), and
sulfur primarily to sulfur dioxide (S02). These combinations of carbon,
hydrogen, and sulfur with oxygen occur in definite proportions, with the
oxygen being provided in the air supplied to the boiler. In theory, the
amount of air required to burn a given amount of a particular fuel can be
predicted from an analysis of the fuel. This amount of air, called
"theoretical air," is the minimum amount of air required to burn the
fuel completely. In practice, because of inadequate mixing and
insufficient time for the chemical reactions to reach equilibrium,
boilers are supplied with excess air to insure a close approach to
complete combustion. Excess air normally is expressed as a percentage
of theoretical air. Table 4 shows the amount of excess air required
by various fuels when burned in a furnace designed for the particular
fuel. The amount of excess air must be restricted to the minimum
amount necessary to insure essentially complete combustion because
the flow of hot gases up the stack represents a loss of thermal energy
and a consequent decrease in the efficiency of the boiler.
20
-------
Table 4. Usual amount of excess air supplied to
fuel-burning equipment
Fuel
Type of furnace
or burners
Normal excess air
% by weight
Pulverized coal
Crushed coal
Coal
Fuel oil
Natural gas
Completely water-cooled furnace
for slag-tap or dry-ash
removal
Partially water-cooled furnace
for dry-ash removal
Cyclone furnace
Spreader Stoker
Water-cooled vibrating-grate
stoker
Chain-grate and traveling-
grate stokers
Underfeed stoker
Oil burners, register-type
Multifuel burners and flat-
flame
Register-type burners
Multifuel burners
15-20
15-40
10-15
30-60
30-60
15-50
20-50
5-10
10-20
5-10
7-12
2.3 EQUIPMENT IN THE GENERATION PLANT
Three types of coal handling are used in coal-fired generators.
First, in the stoker-fired furnace, coal is burned on a moving grate.
Because of the limitations in the capacity of the grate, stoker firing
is not used on boilers larger than 200,000 kg steam/hr. Most electric
utilities use a boiler much larger than 200,000 kg steam/hr. Second,
in the pulverized coal-fired furnace, coal is ground in a pulverizing
mill so that 70 percent will pass through a screen of 200 mesh. The
disadvantages of the pulverized coal-fired furnace are that: the pul-
verizers require a large amount of power to pulverize the coal, there
21
-------
is a large fly ash discharge into the stack, and a large furnace
volume is required for good combustion. However, pulverized coal
firing is used rather than stoker firing because of the flexibility
in type of coal that can be burned, the larger capacity of furnace
which can be constructed, the improvement in response to a change
in load, the ease of firing a combination of oil or gas with coal,
the increase in thermal efficiency gained from the lower excess
air required for combustion, and the lower carbon loss. Third,
cyclone firing was adopted as a method to eliminate the requirement
for pulverizing coal. In the cyclone furnace crushed coal, 95 per-
cent of which will pass through a screen of 4 mesh, is burned quickly
in a high-temperature combustion chamber called the cyclone. Then
the hot gases pass into the main furnace for cooling. Most of the
ash in the fuel is melted in the combustion chamber and is removed
as molten slag.
In the pulverized coal-fired furnace, coal from a storage pile
is fed to a hopper which has a storage capacity of about 10 hr. From
the hopper the coal is fed to the pulverizers as needed. In the pul-
verizer the coal is dried, pulverized, and blown into the furnace.
Depending on the design, pulverizers store from 100 to 1,000 kg of
pulverized coal. A pulverizer storing a large amount of coal may
explode if the coal is high in volatile content.
In the cyclone furnace coal either is crushed and stored in a
central bin or is crushed and mixed with hot air at each cyclone.
Crushing the coal at the cyclone and mixing with hot gases has the
advantage of drying the coal which improves the crusher performance
and provides better ignition of coals with a high moisture content.
Station auxiliaries either are driven by electric motors or
steam turbines. For small power requirements electric motors
usually are preferred because of the ease of control, lower main-
tenance requirements, and lower capital investment. However, tur-
bines frequently are used because of the better overall efficiency
gained when the intermediate step of generating electricity is avoided,
especially when a large size of motor is required for an induced draft fan.
22
-------
Mechanical collectors were installed in many older plants for
the collection of fly ash. The efficiency of collection for these
mechanical collectors was 80-85 percent. Later, electrostatic
precipitators were added, either in addition to the mechanical
collector or in place of it. The efficiency of collection of these
devices was 90-95 percent. Today the new source performance standards
require a collector, usually an electrostatic precipitator, with an
efficiency of at least 99 percent.
Additional5 more specific information on the equipment used in
electric generation plants is given in the appendix.
2.4 CONTROL OF THE BOILER
The fuel feed, air supply, and internal pressure are the three
independent variables that must be controlled simultaneously in a
furnace. Each furnace consists of three control loops that regulate
these variables, and these loops are coupled to keep the controlled
variables constant at a set value or to maintain a desired ratio be-
tween two variables.
In drum boilers the steam pressure in the drum is monitored for
the control of the rate of fuel feed, and the steam flow from the boiler
can be monitored to determine the desired rate of change of fuel feed.
The oxygen content of the flue gas can be used to regulate the air supply.
The speeds of the forced draft fans and of the induced draft fans or the
dampers on each fan are used to regulate the internal pressure.
In a once-through boiler, which does not have a large amount of
water stored in a drum, the furnace must be controlled by the rate of
change of steam consumption or turbine control oil pressure to improve
the response time of the boiler. The fuel feed can be held at a
constant ratio with respect to the water feed.
Differential expansion or contraction of components caused by
thermal gradients places a limit on the rate of change of boiler
conditions. Frequently, the turbine is the component most sensitive
to thermal stress, especially in the larger units, which are 500 - 1,600
Mw in size.
23
-------
The dry-bottom, pulverized coal-fired furnace has a more rapid
transient response than other types of boilers because of the small
capacity for the storage of heat. In the stoker-fired furnace, energy
is stored in the fuel being burned on the grate, and in the wet-bottom,
slag-tap furnace, heat is stored in the slag on the bottom and walls.
The most important factor affecting the response time of the
boiler is the rate at which the feed of fuel can be changed. Ball-
and-race or rod types of pulverizers store several thousand kilograms
of pulverized coal, and this stored coal can be fed to the furnace
quickly. High speed, impact pulverizers only store a hundred kilo-
grams of coal. The rate of feeding fuel to the furnace cannot be
changed rapidly because of the 20-30 sec response time required to
feed additional coal into the pulverizers.
The amount of control of a furnace is measured in terms of steam
pressure variation. On large boilers controls usually are designed
to maintain the steam pressure within about 2 percent during a
steady-state condition. During changes of load a wider tolerance in
steam pressure may be allowed. For instance, for a rate of change
of load of 10 percent/min a deviation of 10 percent may be allowed
in steam pressure.
2.5 UTILIZATION OF STEAM-ELECTRIC GENERATION PLANTS
The diurnal variation in load for an electric utility system
may be 40 percent of the peak requirement. To accommodate this
variation in load, many electric utilities have constructed fossil-
fuel-fired plants, predominantly coal, to maintain the steady "base"
load and have used, when available, hydroelectric or internal
combustion gas turbine generators to generate the varying part of
the power. Both types of generators can respond rapidly to changes
in load, whereas the fossil-fuel-fired boiler responds slowly.
Unfortunately, with the rapid growth in demand for electricity,
the available hydroelectric power is becoming a smaller part of the
total power generated. Because the demand for natural gas far
exceeds the supply, gas turbines are expensive to operate and have a
24
-------
limited potential for future application. Therefore, the fossil-
fuel -fired plants are being required to absorb a larger part of the
variations in load for a utility system, especially now that nuclear
plants are being constructed. Nuclear plants operate most efficiently
as base-loaded plants.
The variation in load and power generation of two utilities
during an entire week is shown in Figures 1 and 2. The distribution
for Duke Power Company shown in Figure 1 is typical for the operation
of many companies. The nuclear plants are base loaded. The gas
turbines and hydroelectric plants make as wide a swing as possible,
and the coal-fired plants take the difference. At night, where
breakdown by type of generation equipment is shown, the power gen-
erated is greater than the system load. During this time, power was
being sold to another utility. In August, the amount of hydroelectric
power capacity usually is lower than the nominal capacity of the
generators because of the limited amount of water that is available
in the streams.
Another pattern of generation is shown for the Tennessee Valley
Authority (TVA) in Figure 2. During November, TVA had more water in
the streams available for use than they had generation capacity, and
a shortage of coal was being encountered. Therefore, the hydroelectric
plants were operated at full output all day, and the coal-fired plants
were cycled to reduce the consumption of coal.
Both of the above cases show that the coal-fired plants must
cycle. Usually, the larger, more efficient plants are base loaded,
and the older, smaller, and less efficient plants are cycled. Both
Duke Power and TVA have relatively favorable conditions for cycling
because of the amount of hydroelectric power available in their
operating territories. Many operating companies have little or no
hydroelectric power available.
Many older plants operate with inefficient pollution control
devices because they were constructed at a time when there was
little public concern about pollution. Most of the past effort
in pollution control has been directed toward the collection of fly
25
-------
ro
COMBUSTION TURBINES
6 PURCHASES
6 12 18 24
SUNDAY |
6 12 18 24
MONDAY I
6 12 18 24
TUESDAY I
6 12 IB 24
WEDNESDAY I
6 12 18 24 6 12 18 24 6 12 18 24
THURSDAY I FRIDAY I SATURDAY I
HOUR AND DAY, AUGUST 25-31, 1974
Figure 1. System power generation and load for the Duke Power Company. Power generated
in excess of load demand was sold to other operating companies.
-------
o
-------
ash. A plant 15 years old may have a precipitator with an efficiency
of 80-95 percent. Occasionally, a high efficiency (that is, better
than 99 percent) electrostatic precipitator has been installed recently
on an older boiler.
2.6 AVAILABILITY OF DATA ON THE OPERATION OF PLANTS
Because boilers have been operated successfully for many years,
utility companies today have little concern about the failure modes
of their boilers. Although logs are kept on each boiler, these
records tend to be brief, at best making it difficult to obtain infor-
mation on transient conditions of operation. Frequently, if a failure
occurs, all manpower in the plant is directed toward correction of
the fault. Then, after the fault is corrected, most personnel will
turn their attention to some other problem, often forgetting even to
enter the upset condition into the log.
By contrast, utility companies have lacked experience in the opera-
tion of equipment such as electrostatic precipitators, and some opera-
ting companies have kept detailed records on the performance of various
classes of units in their system. For instance, the Tennessee Valley
Authority has kept extensive records on the performance of precipitators.
Other companies, however, have not kept detailed records of performance,
especially when keeping the records has no obvious benefit, such as an
improved efficiency of operation or a reduction in costs.
Even when emissions data are available, the conditions of operation
are so complex that little can be inferred because of unknown conditions
of operation. For instance, in emissions data for a coal-fired plant
from Southern California Edison Company presented later in this report the
excess air was measured before the air preheater. The leakage of air into
the flue gases at the air preheater, however, significantly affects the
concentration of pollutants in the stack gases. Even though the fuel char-
acteristics, fuel feed rate, excess air rate, and pollutant concentrations
are known, the emission rate per input unit of heat cannot be determined.
28
-------
3.0 NORMAL, STEADY-STATE EMISSIONS FROM FOSSIL-
FUEL-FIRED STEAM GENERATORS
Because of the multitude of variables involved in the operation
of steam generators, normal, steady-state operation is difficult to
describe. Differences commonly are observed in the operating charac-
teristics of two units of identical design in the same plant and even
in the day-to-day operations of the same unit. Meaningful comparison
of different units is even more difficult because of design variations.
Nevertheless, in order to assess the effects of transient conditions
of operation on the emissions from a fossil-fuel-fired steam generator,
baseline conditions need to be established.
Contract acceptance tests for equipment and compliance tests for
pollution control regulations usually are performed with a rigorously
defined set of conditions of operation imposed on the steam generator.
Typical specifications may include the following:
1. Constant load on the generator (generally at or near
the rated full-load capacity);
2. Constant steam flow, temperature, and pressure,
3. Constant fuel and air flow (that is, the percent excess
air is held constant);
4. Constant burner tilt position, if applicable;
5. Constant high voltage supply to the electrostatic
precipitator.
With skillful operation and no large perturbations in the plant or
load, the parameters of operation can be held nearly steady. Fuel
samples are collected frequently during a test, and a composite
sample is prepared and analyzed to determine the average characteristics
of the fuel.
Using the operating data, acceptance tests, and compliance tests,
the emissions from a generation plant can be estimated. Estimated
emissions for 15 representative coal-fired generation plants are pre-
sented in Table 5. The data, based on the latest published report of
the Federal Power Commission, are given for each entire plant which
29
-------
Table 5. Emissions from selected coal-fired electric generation plants for 1971a
Plant
capac-
ity" '
Mw
2.558
2,000
1,510
1.315
1.155
1.125
950
623
533
450
439
240
210
182
138
48
Plant
effi-
ciency.
percent
36.1
39.2
27.5
32.5
37.0
35.6
37.7
35.0
30.7
32.5
37.1
27.1
293
31.7
28.2
24.0
1
No.
of
boil-
ers
3
4
2
6
5
2
1
1
9
1
2
4
4
2
2
4
i
Total generation i
Per-
' cent
of
Amount. . capac -
Gw-hr ! it£c
123413 i 58
13,682.7 78
1 ,204.7 9
4.736.7
8,153.4
53073
5,640.4
3394.1
2321.7
1.4583
3,226.7
2073
1.388.0
41
81
57
68
62
63
37
84
10
75
9763 ; 61
705.5 58
1 18.4 28
1
Estimated h
effi-
ciency
Coal consumed
Per-
of
panic-
ulate
coitec-
Per- cent tion
Heat
Amount. con-
giga- tent,f
gram6
5.529
4,632
861
2,008
2364
2,106
1382
1,520
1,077
612
1,201
66
ioute/g
23,596
26338
28.027
26341
26,771
25,706
26361
22.691
27373
26,436
25331
25.438
595 28,094
441 25.192
232 ! 27,690
38 25,722
cent
ash
con-
tent
193
14.5
10.8
12.4
15.5
17.1
sul- from
fur stack
con- gases.
tent percent
i
4.1
03
0.4
3.4
1.1
3.2
15.2 ! 1.6
183
13.0
12.1
183
18.7
4.0
0.9
3.4
03
23
14.1 1.1
103
11.5
73
23
1.2
23
95.0
90.0-95.0
97.0
943-99.5
90.0-95.0
50.0-95.0
81.0
983
88.0
98.7
95.0
95.0
88.0
86.^87.0
75.0-85.0
80.0
"Data obtained from the Federal Power Commission (13).
^"he plant capacity is the sum of the nameplate ratings for all generators.
cStation losses, usually 3-4%, are neglected.
Oil and gas used for starting fire are neglected.
e1 kiloton = 030718 gigagram.
f1 Btu/»b = Z326 }oules/k9.
9AJaP - Alabama Power Company, App - Appalachian Power Company. CIL -
Central Illinois Light Company, OPCo - Duke Power Company, IPCo - Illinois
Power Company, SoCalEd - Southern California Edison Company, TECo - Tampa
Electric Company. TV A - Tennessee Valley Authority
estimation of efficiency is based on measured performance and accounts
for time a unit has been out of service.
30
-------
Table 5. Emissions from selected coal-fired electric generation plants for 1971'
Rate of emissions
With respect to heat input.
With respect to electrical output.
gram/megajoale ' kg/Mwr-hr
Particulates
0.04
0.46
0.07
0.13
042
157
033
0.01
1.75
0.11
031
O24
134
0.49
0.71
0.40
Oxides
of
nitrogen
1.17
034
035
031
034
035
034
1.21
032
057
035
0.29
032
036
0.39
032
Oxides
of
sulfur
3.41
0.66
0.27
253
030
2.45
1.22
3.47
066
251
058
2.16
O77
2.28
034
2.18
Particulates
2.0
42
1.5
15
4.1
16.2
8.6
O1 .
18.0
1.2
23
13
22.2
55
6.5
33
Oxides
of
nitrogen
11.7
3.1
7.1
9.1
33
3.4
3.2
123
33
63
3.4
2.4
33
4.1
35
2.7
Oxides
of
sulfur
34.4
6.0
53
283
73
235
113
353
63
273
65
17.4
93
253
75
18^
Plant name
Paradise
Marshall
Mohave
Gannon
Allen
Operator9
TVA
DPCo
SoCalEd
TECo
DPCo
Widows Creek B ! TVA
Bull Run
Baldwin
Buck
Big Bend
Kanawha River
Wans Bar
CJiffsiae
Vermilion
Gadsden
Keystone
TVA
IPCo
DPCo
TECo
Apo
TVA
DPCo
IPCo
AlaP
CIL
31
-------
consists of one to nine boilers as noted. Even though data were not
available for making the calculation for each boiler, the emissions
data can be considered representative of the emissions from an
individual unit. During more recent years, many precipitators have
been replaced with more efficient units, and there should be a de-
crease in the emissions of particulates. Fuel oil and natural gas
burned during startups were neglected in the calculation of the rate
of emissions.
The rate of particulate emissions can be affected dramatically
by the reliability of the precipitator. For instance, as shown in
Table 5, one boiler at the Widows Creek B plant of TVA has a precipi-
tator with an effective collection efficiency of only 50 percent,
while the other boiler has a precipitator with an effective collection
efficiency of 95 percent.
The trend in the electric utility industry is to construct larger,
more efficient boilers that are base loaded and to use the older, less
efficient boilers for cycling. To reduce particulate emissions,
precipitators with collection efficiencies of 99 percent or greater at
full load are used on the large boilers. The older boilers, now used
for cycling, originally were equipped with precipitators having a
collection efficiency of 80-95 percent. Most of these boilers
now have been equipped with new precipitators of high efficiency.
The trend toward the construction of large boilers with high
efficiency precipitators results in a population of boilers in the
United States in which the rate of particulate emissions tends to
decrease as the size of the boiler increases, as shown in Table 5.
With the current construction of boilers of 1,000 Mw size, many of
the large existing plants are being used for some cycling. For in-
stance, Plant Allen, the second largest plant on the Duke Power
system in 1971 and presently the third largest plant, now is being
cycled. The five units at Plant Allen are capable of producing about
10 percent of the expected peak system load for 1975.
32
-------
The magnitude of the diurnal fluctuation in load for a power
system determines the amount which the large generation units need
in order to be cycled. Sometimes it is more economical to reduce
the output of the large units so that the small units can be kept
in service and cycled the next day.
Estimates of the baseline emissions sometimes can be made from
a knowledge of certain general relationships. The following sec-
tions discuss the estimation of the steady-state rates of emissions
of pollutants from a steam generator operating in a steady-state
condition. The estimations are based on a consideration of the
mass balance concept and the primary variables that affect the
emissions of pollutants. The estimations are useful for qualitative
assessments. To obtain a quantitative prediction of the effect
of transient conditions of operation on emissions from a particular
boiler, thorough tests must be conducted on that boiler under
steady-state conditions.
3.1 THE MASS BALANCE CONCEPT
The fundamental law of the conservation of mass can be applied
to the fuel-gas circuit in the following form:
/Rate of mass\ (1)
\accumulation/
In combustion processes, equation (1) commonly is called the mass
balance equation. When no significant flow variations with respect
to time exist and no mass is accumulated, the system is said to be
at steady-state with respect to mass transport, and equation (1)
states that what goes into the circuit comes out. This concept of
mass balance is valid for the total mass of material entering and
leaving the circuit and-for the individual chemical elements consid-
ered separately. Because of the chemical processes that occur during
combustion, the mass of each chemical compound is not conserved,
and equation (1) can not be applied to chemical compounds.
Referring to Figure 3, the inputs of the fuel-gas circuit are
the fuel and air, and the outputs are the bottom ash, the collected
(Rate of \ /Rate of \ /
mass input/ \mass output/ "*
33
-------
EMISSIONS
FUEL
AIR
FURNACE
FLUE GAS
GAS
CLEANING
DEVICE
CLEANED GAS
BOTTOM ASH
FLY ASH
Figure 3. Mass balance schematic of fuel-gas circuit,
-------
fly ash, and the stack gases. In equation (1) the accumulation of
ash in the circuit is neglected, all flow rates are assumed constant,
operational parameters such as power to the precipitator and burner
tilt are held constant, and the fuel quality is assumed constant.
With these assumptions, equation (1) can be used to estimate the
particulate and sulfur dioxide emission rates. The nitrogen oxide
emission rates can be determined only in a qualitative fashion.
These estimations are discussed in the following paragraphs.
3.2 PARTICULATE EMISSIONS
Particulate emissions are derived from the noncombustible
elements in the fuel. Of the three fossil fuels, coal in particular
contains a significant amount of mineral matter that remains in
solid or liquid form even though it may be partially oxidized in the
furnace. A laboratory analysis is used to determine the ash content
of a particular coal sample. After combustion occurs, part of the
ash from the fuel falls or flows to the bottom of the furnace, and
the remainder of the ash is carried upward with the flue gases. The
percentage of the total ash that is entrained in the gases is a func-
tion of the boiler design and combustion parameters. In dry-bottom,
pulverized coal boilers, about 75-85 percent of the ash is entrained
in the flue gases; in slag tap furnaces burning pulverized coal,
about 50 percent is entrained; and in cyclone furnaces, about 20-30
percent is entrained. A relatively small amount of ash falls into
hoppers located near the economizer. The percentage of entrained ash
leaving a particular boiler can be determined from a coal analysis
and the sampling of the flue gas upstream of the gas-cleaning device.
Part of the entrained ash is removed by the gas-cleaning device,
the percentage depending on the design and operating characteristics
of the device. The percentage of particulate collection can be
determined only by testing, although estimates can be made from
experience, bench-scale modeling, and theoretical calculations (which
are the techniques by which such devices are designed).
The ash not removed in the boiler or by the gas-cleaning device
is emitted from the stack with the flue gas. Thus, the steady-state
35
-------
mass balance equation for ash may be written as
P = (F)(a)(l - 3)(1 - n)
where
P = particulate emission rate, kg/hr
F = fuel flow rate, kg/hr
a = fraction of ash in fuel, a mass to mass ratio
3 = fraction of ash removed as bottom ash
n = fractional efficiency of gas-cleaning device.
To facilitate application of equivalent regulatory limitations to
boilers of different size, the mass emission rate frequently is norm-
alized by dividing by the rate of heat input to the boiler, as shown
in equation (3).
n _ P . _ a(l - 3)0 - n) (3)
PN " (HHV)F ~ HHV
where
PN = normalized mass emission rate, kg/joule
HHV = higher heating value of fuel, joule/kg.
Figure 4 illustrates the relationship of the variables in equation (3)
for two hypothetical coals burned in each of the three major types of
boilers. For the dry-bottom, pulverized-coal boiler 3 = 0.02, for the
slag tap, pulverized-coal boiler 3 = 0.50, and for the cyclone
furnace 3 = 0.75.
Because the gas-cleaning efficiency can vary significantly during
the normal operation of any boiler and precipitator, equation (3) must
be used with care. As seen in figure 4, even a 1 percent decrease in
n in a high efficiency precipitator can cause a large increase in the
mass emission rate.
The efficiency for the collection by an electrostatic precipitator
of fly ash from the exhaust gases is given by the Deutsch-Anderson
equation (ref. 4)
n = 1 - exp(-Aw/v ) (4)
where
36
-------
92
94 96
COLLECTION EFFICIENCY, percent
98
100
Figure 4. The effect of precipitator collection efficiency on the rate of
particulate emissions for several boiler designs and coal char-
acteristics. The coal with 10 percent ash content has a heating
value of 30 MJ/kg (13,000 Btu/lb), and the coal with 20 percent
ash content had a heating value of 27 MJ/kg (11,500 Btu/lb).
One gram/megajoule is 2.33 Ib/MBtu.
37
-------
n = fraction by mass of precipitates collected
A = collector plate area in square meters (square feet)
w = particle migration velocity in meters per minute
(feet per minute)
v = gas flow rate in cubic meters per minute (cubic feet
^ per minute).
The units given in parentheses often are used by electric utilities.
The Deutsch-Anderson equation applies directly to the collection of
particles of uniform size and volume distribution, but does not take
into account the reentrainment of particles due to rapping. However,
an effective migration velocity, sometimes called the precipitation
rate parameter, often is determined empirically for a particular
unit. This empirical migration velocity does account for reentrain-
ment. However, the Deutsch-Anderson equation still must be used with
care because of many effects that are not included, such as the
dependence of the effective migration velocity on the rate of gas flow.
The overall effective migration velocity depends upon the rate of gas
flow because the volumetric distribution of particles is dependent up-
on the total gas flow rate.
The collector plate area is the basic design parameter of the
precipitator, but a gas flow rate must be chosen before a precipitator
is designed.
In an electrostatic precipitator this precipitation rate parameter
is influenced strongly by the electrical resistivity of the ash. The
higher the resistivity of a fly ash particle, the more difficult ash
is to collect. Resistivity is influenced most significantly by the
flue gas temperature and the fuel sulfur content. Basically, tempera-
ture affects resistivity by its influence on the transfer of electrical
charges through the particles. The fuel sulfur effect relates to
changes in surface electrical characteristics due to adsorption of
sulfuric acid on the particle. Figure 5 shows typical trends in
resistivity of fly ash with variations in flue gas temperature and
sulfur content in coal (ref. 5). Of particular interest in Figure 5
38
-------
IN-SITU RESITIVITY
MEASUREMENTS'
Ol-2%S
OO-8%S
A2.3%S
Q2.9%S
X 2.5%S
g
I
E
^ iolwh
to
LU
200
250
Figure 5.
TEMPERATURE OF FLUE GAS, °C
The dependence of fly ash resistivity on flue gas temperature and
sulfur content of the coal. These curves represent average values
of resistivity. The actual resistivity can vary considerably for
any particular temperature and sulfur content. The curve is
reprinted in a new format from reference.
39
-------
is the trend of highest resistivity from about 135 to 165° C.
Unfortunately this temperature range is normal for the flue gas
temperature downstream from the air preheater in many units. In
recent years, to combat this problem many precipitators have been
installed upstream of the air preheater where gas temperatures are
about 320 to 440° C. This technique of design involves a tradeoff
because the gas flow rate, v , is larger at higher temperatures,
and the precipitator must be larger to achieve a reasonable gas
velocity.
Figure 6 illustrates the relative effects of plate area, gas
flow rate, and coal sulfur content on the efficiency of an electro-
static precipitator at a constant gas temperature. The Figure 6,
adapted from Reference 6, is based on data obtained from a perform-
ance study of several precipitators and is consistent with the form
of equation (4).
The precipitation rate parameter is strongly affected by the
particle size distribution of the ash and weakly affected by the
dust loading or concentration of the ash. These variables, which
are determined by the fuel burned, must be taken into account during
the design of a precipitator. Variations in the characteristics of
the fuel which is burned may have a marked effect on the performance
of the precipitator.
Multicyclone collectors still are used in the utility industry,
although many have been replaced by higher efficiency electrostatic
precipitators. Unlike electrostatic precipitators where a low gas
velocity is necessary, multicyclone collectors require a high gas
velocity through the cyclones for good efficiency. For this reason,
tandem installations of an electrostatic precipitator following a
series of cyclones do not react the same to changes in gas flow as
do precipitators alone. Decreasing the gas flow rate increases the
precipitator efficiency but decreases the cyclone efficiency so that
the overall efficiency typically increases, but to a lesser extent
than would be indicated by the Deutsch-Anders on equation.
40
-------
tt)
u
CJ
z
UJ
o
C
u.
UJ
z
g
»-
u
UJ
_j
d
O
0,2 0.4 0.6 0.8 1.0
RATIO OF PLATE AREA TO GAS FLOW, min/m
Figure 6. Relationship between collection efficiency and plate
area to gas flow ratio with various coal sulfur con-
tents (constant gas temperature).
41
-------
3.3 VISIBLE EMISSIONS
The visible emissions from the stack of a fossil-fuel-fired
electric generation plant consist of soot, which is unburned carbon,
and fly ash. The emission of unburned carbon during a startup of a
boiler with a distillate oil occurs because of the unfavorable
conditions for combustion. The emissions of fly ash arise from the
ash content of the coal. The fly ash is the portion of ash which
remains suspended in the furnace gases; the remainder of the ash,
called bottom ash, is collected on the bottom of the furnace as
dry ash or as molten slag.
Fly ash is the most important visible emission from a fossil-
fuel-fired steam-electric generation plant. Soot, blown from the
walls during each wall-cleaning cycle, is collected by the electro-
static precipitation. Normally, a significant amount of soot is
emitted only during the initial firing of the boiler when the pre-
cipitator is not energized.
Visible emissions are measured by the determination of the opacity
of the stack gases. The traditional method for the measurement of the
opacity of stack gases has been the determination of the Ringelmann
number. To determine the Ringelmann number, the stack plume is compared
to reference shades of gray that are numbered from light to dark.
The current trend in the measurement of opacity is to measure the
attenuation of a beam of visible light which is directed across the
stack. Usually, filters eliminate portions of the spectral output
of the light source which would be affected by moisture and carbon
dioxide, and special techniques commonly applied in spectroscopy are
used to improve the sensitivity and maintain the calibration of the
instrument.
An in situ instrument for the measurement of opacity commonly
is used by the electric utility industry to monitor stack emissions.
Calibration tests are conducted each 6 to 12 months by using the EPA
reference method. However, variations in the ash content of the coal
being burned and variations in the performance of the electrostatic
42
-------
precipitator, such as the loss of a bus section, can have a signifi-
cant effect on the accuracy of the determination of particulate
emissions by monitoring opacity.
3.4 SULFUR OXIDE EMISSIONS
As indicated in Tables 2 and 3, sulfur is a common component of
fuel oils and coals. In the combustion of a fuel, sulfur is con-
verted rapidly to sulfur dioxide (S02) and sulfur trioxide (SOO
(ref. 7), but the theoretical concentration of S03 is only about 0.5
percent of the SO,, concentration (ref. 8). As the gases cool, S02
is oxidized slowly to SO., by homogeneous gas-phase reactions and by
catalytic oxidation near iron oxide surfaces of the fly ash and the
boiler tubes (ref. 8). The equilibrium concentration of S03 is not
obtained, but the final concentration does reach about 1-4 percent
of the S02 concentration (ref. 9). Within this range the final S03
concentration is roughly proportional to the excess air percentage
(ref. 9). Sulfur trioxide combines with moisture in the flue gas to
form sulfuric acid and is adsorbed on the fly ash and on metal surfaces,
particularly in the air preheater where it can become a corrosion
problem. The ash may retain a small amount of other sulfur compounds
that were not evaporated during combustion. Although the S03 concen-
tration is important with respect to corrosion and fly ash resistivity,
the total mass of sulfur retained in the ash or boiler is negligible
in comparison to the total mass in the fuel. Thus, the rate of sulfur
oxide emissions is given by equation (5).
SOXG = 2(F)(S) (5)
where
SOX~ = emission rate of sulfur oxides, kg/hr
b
2 = stoichiometric ratio of S0« to S
F = fuel flow rate, kg/hr
S = fraction of sulfur in fuel.
43
-------
Normalizing the emission rate by dividing the heat input to the boiler
yields equation (6).
SOXG + 2S (6)
(F)(HHV) HHV
where ,
SOXN = normalized sulfur oxide emission rate, kg/joule.
As indicated by equations (5) and (6) the only factors that have a
significant effect on the gross emission rate of sulfur oxides are the
rate of fuel fired and the sulfur content of the fuel. The normalized
emission rate is directly proportional to the fuel sulfur content and
inversely proportional to the heating value of the fuel.
3.5 NITROGEN OXIDE EMISSIONS
The oxides of nitrogen, which occur in the stack emissions from a
fossil -fuel -fired generator, arise from the interaction of oxygen in
the air supplied to the furnace for combustion with nitrogen, which is
found free in the combustion air and bound in fuel. Molecular nitrogen
(N2) constitutes approximately 79 percent of normal air, and nitrogen
is found bound chemically in small but significant concentrations in
all fossil fuels.
The nitrogen reactions in the combustion are complex, and the
nitrogen oxide emissions are the most difficult to predict. During
combustion of the fuel, part of the fuel and atmospheric nitrogen are
converted to nitrogen oxides (noted collectively as NO ). In utility
boilers, N0x is typically about 95 percent nitric oxide (NO) and about 5
percent nitrogen dioxide (N02). The mass balance concept is valid, but
without extensive measurements it can not be determined whether the
nitrogen that enters the boiler leaves as N2, NO, N02, or as some other
even less prevalent nitrogen compound.
The approximate range of NO emissions from tangentially fired
^
boilers manufactured by Combustion Engineering is illustrated in
Figure 7. However, boilers of different design and origin of
manufacture may exhibit NO emission levels significantly different
A
from those illustrated.
44
-------
A
20.3
^
i02
to
CO
S 0.1
LU
§
GAS -FIRED
O
o ° 0 °
. oO <*> 0 0° •
a *" •• ""*"
J, .1, . i i i i
-
o
-
"
=T=ft STD —
i
0.5
m
100 250 300 400 500 «X>700 80O
FURNACE SIZE, Mw
£
1. 0.3
(O
i
0.1
UJ
OIL - FIRED
--^ _-,, , __, mm —____ _-, />^T- ._^e
-—_*.-•- V^~™' *~" E
_
-------
NO emissions, while significant as a pollution problem, account
for less than 0.1 percent of the total nitrogen entering the boiler.
The balance leaves as N2 or other trace compounds that appear in
even smaller concentration than N0x_ The total emissions of nitrogen
oxides frequently are reported as "N02" although the predominant form
is NO.
The amount of atmospheric nitrogen that is oxidized is determined
by the rate at which various chemical reactions occur and the time that
the reactants stay in the combustion zone. The reaction rates have
been shown to be dependent on the amount of excess air, incoming air
temperature, the design of burners and heat transfer surfaces, the
extent of slag deposition on the walls, and the extent of flue gas
recirculation, if applicable. A special technique called two-stage
combustion (also called off-stoichiometric combustion or overfire air
addition) has been shown to reduce the formation of nitrogen oxides.
Basically, two-state combustion is accomplished by admitting a rich
mixture of air and fuel in the lower burners while maintaining the
overall excess air level by admitting a lean mixture of air and fuel
through upper burners. Overfire air refers to the condition occurring
when part of the combustion air is admitted at the upper portion of
the furnace. Overfire air appears to work better on tangentially
fired boilers where fuel burns over a long path after entering the
furnace.
The result of two-stage combustion is that a shortage of oxygen
occurs in the fuel-rich regions and the oxygen reacts preferentially
with hydrogen, carbon, and sulfur rather than with nitrogen (ref. 10).
In the area where the remaining oxygen is admitted, combustion
temperatures are lower and the oxidation of Np occurs more slowly.
The overall effect of two-stage combustion with low excess air has
been shown to reduce NO emissions 55 to 64 percent compared to
A
normal operation (ref. 10).
Complex theoretical models and experimental data correlations
have been developed to predict nitrogen oxide emissions for various
types of boilers under different operating conditions. A full
46
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presentation of these models and correlations is far beyond the scope
of this report, but qualified generalizations can be made for several
important factors.
1. Excess Air—The excess air is the amount of air supplied to the
furnace in excess of what is required stoichiometrically for complete
combustion. Generally, increasing the excess air increases the formation
of N0x during combustion and reduces the efficiency of the boiler because
of the loss of energy to the oxygen gas leaving the combustion chamber.
Operation with a high level of excess air tends to create a more
stable flame. However, the excess air in a well-controlled furnace
can be reduced until the carbon monoxide emissions are about 50 ppm,
which results in a minimum of NO emissions and a maximum efficiency
A
of generation. A further reduction of excess air would increase the
carbon monoxide emissions and the danger of a furnace explosion due
to unstable conditions of combustion. Investigations have shown that a
10 percent increase of excess air 10 percent above the normal level of
operation will increase NO emissions about 20 percent with all fuels
/\
(refs. 10, 11). Similarly, a reduction in the amount of excess air to
half of the normal level decreases NO emissions about 20-30 percent
A
(refs. 10, 12), but may cause excessive smoke and CO emissions.
2. Air Flow Distribution—Increasing the percentage of air
flow through the fuel compartments of a burner increases "early"
mixing of fuel and air and has been observed to increase NO emissions
A
in tangentially fired coal and oil units. With gas firing, increases
in NO emissions have been observed when the distribution of air flow
through either fuel or air compartments is changed (ref. 11).
3. Two-Stage Combustion--Two-stage combustion has been achieved
in tests on existing boilers by omitting fuel flow to some of the
upper parts in the windbox while maintaining air flow. In some cases
a load reduction was required because the burners were not sufficiently
oversized to maintain full load under these conditions. Figure 7
illustrates the effect of this method of operation. Some new boilers
are being designed with overfire air systems.
47
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4. Flue Gas Recircul at ion—Reductions in NO emissions of 35
^
percent with oil and 60 percent with gas have been achieved by the
recirculation of 30 percent of the flue gas to the primary combustion
zone (ref. 11).
5. Combustion Air Temperature—A reduction in the temperature of
the combustion air reduces the flame temperature and, thus, reduces
the formation of NO . Full-sized boiler tests have shown about a 20
/\
percent reduction in NO emission with a 40° C reduction in combus-
tion air temperature. However, the efficiency of the boiler is reduced
with this technique.
6. Burner Design and Configuration--Many different burner designs
and configurations are used by the various manufacturers of steam
generation equipment. Burner designs range from those that promote
high turbulence for the rapid mixing of fuel and air to those that
promote comparatively slow mixing with diffusion flames. Generally,
N0x emission levels are higher from boilers equipped with highly
turbulent burners, but different conclusions can be drawn from
alternative methods of presenting experimental data. For example,
plotting N0x emissions versus gross load per furnace firing wall may
lead to a significantly different correlation than plotting emissions
versus burning area heat release or steam flow. Because the correlation
methods have not been standarized among different research groups, a
conclusive, quantitative comparison of particular burner designs
nas not been established.
7. Burner Tilt—With respect to NO emission, adjustment of
A
burner tilt in tangentially fired boilers appears to have offsetting
beneficial and detrimental effects related to excess air level and
effective high temperature residence time. Minimum NO emissions are
generally achieved with the burners at a horizontal or slightly upward
tilt (refs. 10, 11).
8- Heat Release Rate—The heat release rate is a design parameter
that can be qualitatively considered as the "concentration" of heat
in the furnace. It is measured in terms of the heat generated per unit
48
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area of water-cooled surface in the furance. This parameter is quite
inportant to NOX emissions because it is related to the time-tempera-
ture history of the combustion mixture. Because the rate of oxidation
of nitrogen increases rapidly at higher temperatures, high heat
release rates generally result in higher NO emission levels. Cyclone
furnaces and wet-bottom, pulverized-coal furnaces usually have highe*-
heat release rates than dry-bottom, pulverized-coal furnaces.
9- Furnace Slagging—Excessive wall deposits in coal-fired
furnaces tend to increase NO emissions by reducing heat transfer
^
rates, thus raising the bulk temperature in the flame zone. Operation
with higher excess air helps to control heavy slagging but also increases
NO emissions as previously ciscussed.
s\
10. Load—A reduction of the load on a boiler tends to reduce the
NO emission level by decreasing the bulk flame temperature and re-
A
ducing turbulence in the primary flame zone. In tests performed on
tangentially fired boilers, a 25 percent reduction in load resulted In
a 50 percent NO reduction with gas firing and 25 percent NO reduction
A. X
with gas firing and 25 percent NO reduction with oil and coal firing
(ref. 11).
11. Fuel Nitrogen—The oxidation of fuel nitrogen is essentially
a separate phenomenon from the oxidation of atmospheric nitrogen
except in natural gas where nitrogen appears as N,,. The effect of
fuel nitrogen on NO emissions is known to be an important factor
,A
with oil and coal firing, but quantitative trends are still subject to
controversy. A conversion rate of 20 percent of fuel nitrogen to NOX
has been reported as a reasonable approximation for fuels with average
fuel nitrogen content (ref. 12). This conversion rate produces
emissions of 0.3 g N0?/M0 for coal containing 1 percent nitrogen
or 0.05 g NO?/MJ for number 6 fuel oil containing 0.3 percent nitrogen.
Referring to Figure 7, the subtraction of these calculated amounts of
fuel NO emission from the reported coal and oil-fired data would
A
leave the NO emission level attributable to oxidation of atmospheric
nitrogen. Although the data shown considerable scatter and the actual
fuel nitrogen may have varied from these assumed values, this simple
manipulation reduces the data spread for the three fuels to
49
-------
approximately the same range, indicating that 20 percent oxidation of
fuel nitrogen is probably a reasonable estimate. It is thus
apparent that fuel nitrogen could account for over 50 percent of the
NO emitted from boilers burning coal or oil with a high nitrogen
/\
content.
3.6 MEASUREMENT OF SULFUR OXIDE AND NITROGEN OXIDE EMISSIONS
Emissions of the sulfur oxides and nitrogen oxides are measured
by two methods, ir. s'l~u and extraction. In situ monitors use the
techniques of absorption spectroscopy to determine the concentration
of the pollutant in the stack gas. The extractive monitors extract
a representating sample of flue gas from the stack and measure the
concentration of the pollutant by spectroscopic techniques or wet
chemical techniques.
j>. 3-lru monitors measure the absorption of radiation which has
passed through the flue gases in the stack. Visible, ultraviolet,
or infrared radiation is used, depending upon what is being measured.
For local calibration a know concentration of the pollutant gas is
kept in a reference cell. For the pollutants NO, N02, SO,,, and CO
the Lambert-Beer law is used. The ratio of a resonant absorption to
a nonresonant absorption determines the concentration of the pollutant.
In an extractive monitor the sample must be handled with care.
Some extractive monitors keep the flue gas sample hot and analyze the
gas while hot, after removing the particulates. Other extractive
monitors dry the flue gas sample, remove the particulate, let the gas
cool, and then analyze the gas at ambient temperature.
3.7 RELATIONSHIP BETWEEN MEASUREMENTS OF EMISSIONS IN PARTS PER
MILLION AND RATE OF EMISSIONS IN MASS PER INPUT HEATING UNIT
Standards for emissions are given in terms of mass of emissions out-
put per input heating unit, usually g/MJ or lb/106 Btu. However, NO
A
and S0x measurements are made in terms of the ratio of volumes of the
pollutant gas to the total stack gas, usually ppm (liter of pollutant
gas to million liters of flue gas). The following formula can be
used to determine the mass emission rate if the volume emission rate
50
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is known:
Em = (2.68 x 10'3) Vg M Ey (7)
where *
Em = mass emissions rate of pollutant, g/m
V = volumetric flow rate of stack gas, standard m3/min
M = molecular weight of pollutant
E = volumetric rate of emissions, ppm.
The emissions can be compared to the input heat rate which is a
characteristic of the fuel being burned by use of the following
formula:
En = (Em x 106)(HHV) F (8)
where
EM = emissions per input heating unit, g/megajoule
HHV = higher heating value of the fuel, joule/g
F = rate of fuel feed = g/hr.
The rate of emissions per unit heating unit can be determined by
combining the above equations.
Eu = 2.68 x 103 Vg M Ey/(HHV) F. (9)
Sometimes, all the parameters needed to determine EH from Ey are
not known. Suppose, for instance, that V is not known. V can be
estimated using design data (11) in the following equation:
V = 2.38 x 10"6 AT ( 1 + EA)(HHV) F (10)
where
= theoretical air required for complete combustion, g/joule
E. = fractional rate of excess air
and there are 10.17 standard cubic meters per mole and 1315 g dry air
per mole. For coal, heavy oil, and natural gas, let A-j- be 327, 321,
51
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and 309 g/J, respectively; and, EA = 0.20, 0.12, and 0.08. Then
EH(coal) = 9-3xl°~4MEV ft
EH(oil) = 8'6 x 10~4MEv
EH(gas) = 7.9 x ID'4 MEV. (13)
52
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4.0 EMISSIONS DURING TRANSIENT CONDITIONS OF
OPERATION AND EQUIPMENT MALFUNCTIONS
The normal, steady-state operation of a fossil-fuel-fired steam
generator at the rated full-load capacity with no change in fuel or
air flow or fuel quality already has been discussed in this report.
Basic relationships among pollutant emissions and operating parameters
were developed and discussed, and the difficulty in achieving a
characterization of "typical" emissions from a steam generator even
under these stringent conditions was emphasized. Under transient con-
ditions of operation, the variability of emissions in a particular
boiler or between two or more boilers is even greater than under
steady-state operations.
Figure 8 shows a chart recording of the gross generator elec-
trical output an S0? and NO emissions during 2 days for the Mohave
£• /\
Plant of the Southern California Edison Company. The chart recording
demonstrates the fluctuations which can be expected in the operation
of a coal-fired generation plant. The emissions data have not been
adjusted to the equivalent emissions for a constant 3 percent level
of excess oxygen. The excess oxygen varied during the period of re-
cording from 5.5 to 8 percent. The coordination of the recorders of
boiler parameters and stack emissions was not adequate for an analysis
of the data.
Very little has been published in the scientific literature on
the effects of transient conditions of operation on boiler emissions.
The relationships between emissions and operating parameters already
developed in this report are useful in a discussion of the trends of
emission levels during transient conditions of operation, but no reli-
able quantitative relationships have been developed.
A qualitative appraisal of the effects of transient conditions of
operation on the emissions of particulates and the oxides of nitrogen
is presented in Table 1. The remainder of this chapter consists of a
discussion of the trends presented in this table. Table 1 reflects
practical experience of operations learned through reviews and discus-
sions which were held with personnel from Duke Power Company, Carolina
53
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S
TO>oiiy,«ontMei« 77,
- H
\^. _. -- f - *--—
. -j ._.j ^
"iATuRtMf.'jci'tCMnrn m. nr«i
-"V^-
-t A -• —
DATE AND HOUR
Figure 8. The gross electrical output and emissions of NOX and 862 from Unit No. 1 of
the Mohave Plant of the Southern California Edison Company. The emission
rates shown are not adjusted to a constant 3 percent level of excess oxygen.
Excess oxygen varied during the period of recording from 5.5 to 8 percent.
The chart, a reconstruction of several charts provided by Southern California
Edison, is presented only to illustrate the normal variations in output and
emissions; no careful control was maintained to assure the validity of the
data.
-------
Power and Light Company, the Tennessee Valley Authority, Georgia
Power and Light Company, the American Electric Power Services Cor-
poration, Southern Services Company, Riley Stoker Corporation, the
Southern California Edison Company, Combustion Engineering, Incorp-
orated, and Environmental Data Corporation. While the conclusions
do not necessarily reflect the opinions of any one of these organiza-
tions, neither is any of them markedly out of agreement.
Transient conditions of operation have no effect on the mass
emission rate of the oxides of sulfur. Theoretically, the principle
of the conservation of mass requires that all sulfur entering the
boiler in the fuel must leave either as a component of the bottom ash
or fly ash or as an oxide component in the stack gas. The emissions
of the oxides of sulfur then should correspond directly to the sulfur
input to the boiler. No datum was found adequate to confirm or refute
directly the expected relationship between fuel feed and sulfur oxide
effluents. However, in conversations with several persons who had
monitored sulfur oxide emissions from steam generation plants for
reasons other than to correlate the sulfur oxide emissions with the
rate of feeding fuel , it was found that the sulfur oxide emissions had
followed the load and, by inference, the rate of feeding fuel.
For want of data or contradictory theories, no further consideration
was given the emissions of the oxides of sulfur.
4.1 STARTUPS
A cold startup procedure for a coal-fired boiler requires 4 or
more hours during which the boiler and related equipment are on
manual control. The procedure begins with ignition of No. 2 fuel
oil or an alternate light fuel in the boiler. The flow of fuel oil
and air are increased gradually as the boiler is wanned. The
temperature and pressure of water in the tubes gradually rise.
Steam forms and is admitted slowly to the steam chest to warm the
turbine. When the temperature of the steam reaches a level sufficient
to prevent condensation of water on the blades, the turbine is
allowed to roll, being gradually brought to operating speed (normally
1,800 or 3,600 rpm). When the turbine is rotating at the proper
55
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operating speed, the electrical output is paralleled with the
system.
The low flame temperature during a startup tends to suppress
formation of nitrogen oxides, but the low temperature operation
may be offset somewhat by a higher level of excess air, which is
used to maintain the flame. The net effect is that the nitrogen
oxide emissions are lower during startup than at full load
operation. The emissions of sulfur oxides usually are less during
this startup period because the normal startup fuels, No. 2 fuel
oil or natural gas, are low in sulfur.
When the generation is connected to the electrical system, the
electrical load is very low, typically less than 5 percent of
capacity. The first pulverizer mill is put into service, and coal
is delivered to the boiler. (In some installations, the normal
operating procedure calls for putting one pulverizer mill into service
before paralleling the unit. Sometimes on generation units used for
providing power during peak periods of load, all burners are fired
and burned at a low output so that an increase in load can be
assumed more rapidly.) The coal flow is increased by putting addi-
tional pulverizer mills into service, one at a time. The electrical
load of the unit gradually is increased. To maintain flame stability,
firing of the startup fuel is sometimes continued until two or three
pulverizing mills are in operation.
The electrostatic precipitator is energized when the gas tempera-
ture at the inlet to the precipitator reaches a specified value,
commonly 90 to 135° C. The delay in energization of the precipitator
until the gas temperature is above the dew point reduces condensation
on the high voltage insulators and avoids the collection of wet ash,
which would foul and corrode the wires and plate or plug the ash
hoppers.
The recommended gas temperature and corresponding fractional
load attained before energization of the precipitator varies among
different plant operators, but the practice of waiting until the flue
gas temperature is higher than the dew point is considered to be
necessary for preventive maintenance. The Tennessee Valley Authority
56
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(TVA) and Pennsylvania Power and Light Company (PP&L), however, »
have a policy that the electrostatic precipitator should be energized
before any coal is fired. Both companies have operated successfully
with this policy. To reduce condensation of stack gas on surfaces
during startups, the precipitator bushings are heated by TVA and oil
is fired longer by PP&L than would be required just to maintain the
flame in the furnace.
The magnitude of particulate emissions, which occur during a
startup period when coal is fired with no ash collection, is shown in
Figure 9. Particulate emissions from the combustion of oil or gas
during the startup are neglected. The emissions are expressed in
Figure 9 as the time the boiler can operate at full load with the
precipitator in service for equal total emissions. The graph is
plotted in units of total startup time, which usually is between 4
and 8 hours. A linear rate of firing coal from the beginning of the
startup period to full load is assumed. As an illustration, suppose
the startup time for a boiler is 6 hours and the efficiency of the
precipitator at full load is 99 percent, which is common for a cycling
plant. If the precipitator is energized after 2.4 hours, which is
40 percent of the startup period, the amount of emissions during the
first 2.4 hours of operation would be the same as the total emissions
during 48 hours (8x6 hours) of operation at full load. Futhermore,
assuming a daily cycle between half load and full load, which would
be an average load of three-fourths full load, the total emissions
during the first 2.4 hours would equal 64 hours' or 2.7 days' opera-
tion of the boiler. The more efficient the precipitator and the
longer the startup time, the more desirable it is to energize the
precipitator when coal first is fired.
In Figure 9 the fraction of total ash reaching the precipitator
is assumed not to vary as a function of the load. The fallout of ash
in the economizer hoppers is a function of particle size and gas
velocity, and the fraction of bottom ash is influenced by the flame
zone temperature and turbulence. However, a more careful analysis
taking these effects into consideration would cause no significant
change in Figure 9.
57
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PRECIPITATOR
EFFICIENCY 99.50/0
UJ
Figure 9.
0.2 0.4 0.6 0.8
TIME DURING STARTUP THAT PRECIPITATOR IS
ENERGIZED, (total startup time equals one unit )
Time a boiler can operate at full load for emissions to be the
same as during a boiler startup. Normal startup time is 4 to
8 hours. The load is assumed to increase linearly to full
capacity at the end of the startup period.
58
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Estimates of particulate emissions from coal-fired boilers during
cold starts are shown in Table 6. The estimates were calculated by
Georgia Power Company from the amount of fuel consumption measured
during cold starts between January and March of 1975. Complete combus-
tion was assumed to have occurred. The number of cold starts that
occurred in 1973 is given for each boiler. The practice of Georgia
Power Company is to wait until an air heater gas outlet temperature
of 135° C is reached before energizing a precipitator, so that acid
condensation on the precipitator surfaces can be avoided.
After the electrostatic precipitator is energized, the load con-
tinues to be increased until full load is achieved or the load on
the unit is maintained at some load less than full capacity. During
this portion of the startup transient, the level of particulate
emissions is less than the normal steady-state emission rate because
the gas velocity is less than the full load design value and, there-
fore, the precipitator efficiency is greater than the full-load
design value. The emission of nitrogen oxides is less than the full
load emission rate during this transient period because of the lower
flame temperatures. The emission rate of sulfur oxide is unaffected
by the reduced load because it depends only on the amount of sulfur
in the fuel.
In some electric power stations, small units on peaking or
cycling duty may be taken off line overnight while their generation
capacity is not needed and then returned to service the next day.
During this period the boiler can be kept warm by stopping the fans
and closing the boiler to reduce heat loss. When returned to service,
the boiler can undergo a hot startup in which the startup time may be
reduced by one half.
4.2 SHUTDOWNS
A normal shutdown of a steam-electric generator from full load
requires approximately 1 to 3 hours. The electrical load gradually
is dropped, and the fuel and air flows are decreased simultaneously.
The fuel-to-air ratio is kept within the normal range for complete
combustion. As the load is decreased, the emissions of particulate
59
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Table 6. Particulate emissions for coal-fired boilers of Georgia Power Company during cold starts,
Plant/units (s)
Arkwright/1-4
Bowen/1,2
Hammond/1-3
Hammond/ 4
Branch/1
Branch/ 2
Branch/ 3, 4
Mitchell/1,2
Mitchell/3
Yates/1-3
Yates/4, 5
Unit rating,
MW
45
700
112
500
250
319
480/490
22.5
165
105
145
Oil consumed,
liters
3,800
378,500
4,500
45,400
11,400
15,100
11,400
950
17,800
26,500
34,100
Coal consumed ,
kg
8,000
454,000
77,000
454,000
73,000
73,000
445,000
1,000
118,000
16,000
39,000
Particulate
emissions,
kg
980
54,000
9,300
54,000
8,690
5,500
54,000
160
14,200
1,900
4,600
Number of
cold starts
in 1973
52
27
18
11
10
13
29
35
8
11
19
*The starting period lasts until the air heater gas outlet temperature of 135° C is reached
when the precipitator is energized. The estimates were calculated by Georgia Power Company from
measured values of fuel consumption under the assumption that complete combustion occurred, the
ash content of the oil was 0.06 percent and the ash content of the coal was 0.12 percent.
-------
matter drop with the fuel flow, and the normalized particulate
emission rate decreases because of the lower gas flow and the
increased collection efficiency of the electrostatic precipitators.
The emission of nitrogen oxides is reduced because of lower flame
temperatures. The normalized emission of sulfur dioxide is
unaffected. When the boiler load has been reduced to approximately
one-third to one-half of its full capacity, the fuel flow is
stopped, and the emission of nitrogen oxides and sulfur oxides
ceases. Then the electrostatic precipitator is deenergized, but
rapping continues as long as dust settles into the precipitator's
ash hopper. While the draft fans continue to circulate air through
the furnace, particulates will be carried out the stack with no heat
input to the boiler. This situation, mathematically an infinite
rate of emissions per unit of heat input, is unavoidable and negligible.
If maintenance work is to be done inside the boiler or a hot
restart is not desired, the forced draft and induced draft fans
continue to circulate air through the boiler for cooling. Cooling
of the boiler to a temperature at which internal work can be accomlished
requires 12 to 14 hours. During this cooling period wisps of fly ash
released from the internal surfaces of the boiler are emitted from
the stack. The electrostatic precipitator is not energized during
boiler cooling because gases would condense on the surfaces of the
wires and plates and combine with the fly ash already present to form
a hard residue. This residue is difficult to remove, and it would
have a detrimental effect on the precipitator efficiency when the
unit was restarted.
A turbine trip is an emergency shutdown caused by a malfunction
in the turbine, generator, output transformer, or other equipment or
controls. The trip requires a sudden removal of the electrical load
and an immediate stop in operation. The steam valves are closed
immediately, blocking steam from the turbine; the fuel flow is
stopped; and the excess steam generated in the boiler is vented to the
atmosphere through pressure relief valves. The ventilation of steam
depressurizes the boiler in about 1 to 2 minutes. The process of
61
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steam ventilation can cause vibrations of the boiler, which could
shake loose ash deposits from the internal surfaces of the boiler
and cause puffs of fly ash to pass through the precipitator and out
the stack. Emissions of nitrogen oxides and sulfur oxides decrease
rapidly to zero as the fuel flow is stopped. The electrostatic
precipitator is tripped manually or automatically soon after the
turbine trip. If boiler maintenance must be accomplished or a hot
startup is not planned for another reason, the boiler cooling
procedure described above will follow a turbine trip.
Another type of emergency shutdown is a fuel trip caused by
a malfunction in the boiler, fuel system, or other related equip-
ment or controls. This type of emergency shutdown is character-
ized by an immediate loss of fuel flowing to the boiler. The fuel
flow stops completely within a few seconds, and the electrostatic
precipitator is then tripped. Because operation of the turbine
presents no hazards to the equipment or plant personnel, the residual
heat in the boiler normally is used to generate steam and drive the
turbine as long as possible. As the steam pressure decreases, the
electrical load 1s dropped. With a fuel trip, the emission of
particulate matter, nitrogen oxides, and sulfur oxides decreases
rapidly as the fuel flow is lost. If the boiler cooling procedure is
followed, wisps of fly ash will be emitted from the boiler for 12 to
14 hours.
4.3 LOAD CHANGES
Peaking, cycling, and in some cases, base-loaded steam-electric
generators undergo controlled, cyclical load variations. These load
changes are accomplished gradually while maintaining near optimum
firing conditions. During cycling, transient effects probably are
negligible. The duration of the cycling transient can vary consider-
ably. A typical scheduled change of 10 percent reduction or increase
in the maximum rated load might take 15 to 30 minutes. During this
transient period, the emission rates of particulates, nitrogen oxides,
and sulfur oxides should be approximately the same as the steady-state
emission rate characteristic of the instantaneous load. If a boiler is
62
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cycled too rapidly, there may be inadequate control of the fire,
creating nonoptimum conditions of combustion. These poor conditions
of combustion may result in excessive emissions or a loss of service
if the flame in the furnace cannot be maintained.
For normal cycling the rate of particulate emissions with respect
to input heat decreases with a drop in load and increases with an
increase in load because an electrostatic precipitator efficiency
increases with a reduction in gas flow. Because of the changes in the
time-temperature history of the flue gases, nitrogen oxide emissions
are reduced at lower loads and increased above the normal, steady-
state value at overload. Sulfur oxide emissions are affected only
by the fuel sulfur content, and the normalized SO emission rate
A
remains constant during load variations.
Forced load reductions can be categorized according to the system
which is affected first. A reduction caused by disruption of the fuel
supply is associated with a malfunction in a feeder, pulverizer mill,
burner, or other fuel-cycle equipment or control. This type of tran-
sient is created by a fuel supply that is inadequate for the load and,
consequently, by a temporary excess air level which is higher than
normal. To compensate for the loss of fuel, the electrical load is
reduced, and the furnace draft is reduced to the normal excess air
range by manual or automatic controls. Oil or natural gas may be
admitted to the boiler to assist in flame stabilization. The time of
this type of transient can vary greatly with the design of the boiler
and its control systems. Newer electronic controls normally are
faster than pneumatic controls in correcting imbalances between fuel
and air. The duration of the transient is dependent on the magnitude
of the required load reduction. With respect to particulate emissions,
a load reduction caused by a fuel supply disruption normally has no
transient effect other than to increase precipitator efficiency at
lower gas flow rate. The emission of nitrogen oxides would be in-
creased while the excess air is at a higher than normal level. When
the load is stabilized at a lower setting, N0x emissions should be
decreased. The normalized emission rate of sulfur oxide is unaffected.
63
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Forced load reductions can be caused by malfunctions in components
not directly limiting fuel or air flow, such as a failure in the feed-
water, steam, or condensate system. Depending on the cause and severity
of the problem, the load might be reduced slowly in a controlled fashion
or abruptly with a resultant loss of optimum firing conditions. The
transient condition can exist from as little as a few seconds to as
long as several hours for severe upsets. The electrical load is re-
duced, and the fuel flow-to-air flow ratio is adjusted until the normal
range is achieved at the new reduced load. Particulate emissions will
be increased temporarily by the presence of unburned carbon if the
excess air level drops more than a few percent below the normal value.
When the unit is stabilized at a lower load, the normalized particulate
emission rate will be decreased because of the lower gas velocity. The
emission of nitrogen oxides may cycle with a disruption in the balance
of fuel and air with higher NO emissions resulting from high excess
A
air and lower NO emissions resulting from low excess air. When the
A
unit is stabilized at a lower load, the NO emissions will be decreased.
A
Sulfur oxide emissions are unaffected.
An abrupt increase in load may be caused by the sudden demand for
electricity by a large industrial customer or by the loss of a large
generation unit elsewhere in the utility system. The fuel and air
flow must be increased suddenly to satisfy the increased load. The
fuel-to-air ratio may cycle about the normal range until the control
system brings the unit back to optimum operating conditions at the
increased load. The time of the transient condition will vary
according to the design of the boiler and process control system and
the magnitude of the load increase. If the excess air level drops
more than a few percent below the normal range, unburned carbon may
be emitted. At the higher load, the particulate emission rate will be
increased because of the higher gas flow rate and a resultant lower
collection efficiency in the precipitator, but the emission rate may
not be in excess of the normal full load steady-state level. The
emission of nitrogen oxides may exhibit a cyclic variation until the
excess air level is returned to the usual range. When the unit is
64
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stabilized the NOX emission rate will be higher than at the lower
load, but not necessarily higher than the full load steady-state rate.
Normalized sulfur oxide emissions are unaffected by this type of
transient.
With respect to load changes in general, a particular boiler
manufacturer has observed that transient NO emissions are a function
A
of instantaneous load and excess air. This manufacturer reports that
in most utility boilers, the oxygen leads the fuel during a load
increase and lags the fuel during a load decrease (ref. 13). This
situation would result in increased NO emission rates during load
A
increases and a decreased NO emission rate during load decreases.
A
These observations have not been confirmed for all types of boilers and
boiler control systems.
4.4 FUEL QUALITY VARIATIONS
Short-term variations (those that last only a few minutes) in the
quality of fuel fed to the boiler are not detected by normal fuel
analysis techniques. With respect to coal, the "as burned" analysis
usually is conducted on a composite sample collected during the
filling of the bunker. These composite samples tell only what the
average quality is during the filling interval. Composite samples
may be collected between the bunker and the boiler. In this case, the
samples reflect the average quality during the sample interval but
still do not detect short-term variations. Short-term variations in
fuel quality are noticeable when they are severe enough to upset the
balanced combustion parameters in the boiler. Variations may be
detected by continuous monitoring of emissions, provided the monitoring
system has sufficient precision and response characteristics and the
residence time and mixing of the gases in the boiler do mask the
variations. No reports of studies pertaining to the monitoring of
short-term fuel quality variations have been found the the literature
surveyed for this project.
Operators of steam-electric generating plants normally like to
maintain a supply of fuel on site which is sufficient for several weeks
operation. The quantity of fuel stored may be limited by the available
area. With respect to coal, placing the incoming coal on the storage
65
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pile reduces the daily variations in fuel quality. The bunkers of a
particular boiler normally are filled batchwise; e.g., the bunker is
loaded in a few hours with a fuel supply sufficient to run 1 or more
days. Before the next bunker filling, the quality of coal on the stor-
age pile could be changed by unloading of incoming coal, rainy weather,
or a storage pile fire. (Fires are uncommon when bulldozers are used
to pack piles. If they occur, they have the effect of increasing the
ash content and decreasing the heating value of the coal.) If coal is
unloaded directly from the incoming supply to the bunkers, a rapid change
in quality can occur. If the coal quality changes significantly between
filling, the firing condition of the boiler may be upset, and flame
instability may be experienced when the bunker turnover point is reached.
The fuel flow and air flow will undergo transient adjustments in an effort
to return the firing conditions to optimum. As discussed previously,
the emissions of particulate matter and oxides of nitrogen generally will
be decreased when air flow is reduced and increased when air flow is
increased. Sulfur oxide emissions will be affected only to the extent
that the percentage of sulfur in the coal is changed.
Excessive moisture in coal can create a transient condition of
extended duration. The primary effect of excessive moisture is the clog-
ging of the bunkers, feeders, and pulverizer mills. Coal can leave the
pulverizers on the way to the boiler only in a dry form. When the coal
is very wet, the pulverizer output is reduced and, consequently, the
boiler load must be reduced. Fuel oil or natural gas may be admitted to
the boiler as a supplementary fuel to assist in flame stabilization.
Excessive moisture in coal, therefore, has essentially the same effect
on emissions as any other load reduction caused by a disruption of the
fuel supply.
A transient emission effect may be created by the burning of coal
or oil with increased ash slagging tendencies. Slag will tend to build
up on the furnace walls and reduce the transfer of heat to the tubes.
This has the effect of increasing the gas temperature. Excess slagging
can be controlled partially by increasing the amount of excess air. The
level of particulate emissions may be increased or decreased by this con-
dition depending on the starting point and the magnitude of variations in
66
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gas flow and gas temperature. Increasing gas flow tends to decrease
electrostatic precipitator efficiency, but the efficiency can be in-
creased or decreased by a rise in the flue gas temperature (see Fig-
ure 5). Excessive slagging tends to increase the formation and emission
of nitrogen oxides.
Although short-term fuel quality variations are not often noticed by
operators as a transient problem, the emission of particulate matter,
nitrogen oxides, and sulfur oxides is theoretically a function of the in-
stantaneous ash content, fuel nitrogen content, and fuel sulfur content.
The normalized rate of sulfur oxide emissions is directly proportional to
the percentage of sulfur in the fuel and inversely proportional to the
heating value. Equation 3 given above in the section entitled "Particu-
late Emissions" indicates that the normalized particulate emission rate
is directly proportional to the percentage of ash in the fuel. The influ-
ence of ash concentration in the gas stream on the precipitation rate
parameter probably alters this direct proportionality, but no quantitative
experimental correlation has been reported. The normalized particulate
emission rate is inversely proportional to the heating value of the fuel.
The effect of the instantaneous fuel nitrogen content on the emissions
of nitrogen oxide varies with the three types of fuel. Nitrogen concen-
tration in natural gas is relatively unimportant, but the fuel nitrogen
in coal and oil can account for up to 50 percent of the total NO emissions.
J\
4.5 MISCELLANEOUS OPERATING TRANSIENT AND EQUIPMENT MALFUNCTIONS
4.5.1 Soot Blowing
Soot blowing is a routine procedure of operation, which removes ash
deposits from the heat transfer surfaces. The boiler efficiency is im-
proved by soot blowing, and the emission of nitrogen oxides is reduced
because of improved flame cooling and lowered gas temperatures. The
transient effects on nitrogen oxide during the soot-blowing operation are
unknown. Soot blowing creates an increase in particulate load on the
electrostatic precipitator during the 15 minutes to 1 hour that normally
is required to complete a total boiler-blowing cycle. Because many elec-
trostatic precipitators are not designed to handle the increased loading
67
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soot blowing, an increase in the level of particulate and visible emis-
sions is observed.
The failure of a soot-blowing system normally would not be thought
of as a transient emission phenomenon, but it has a theoretical transient
effect on the emission of nitrogen oxides and particulate matter. If
the deposition of ash on heat transfer surfaces is considered to be a
gradual, continuous process, failure of the soot-blowing system will
allow this process to continue until the system is repaired. During this
time, heat transfer efficiency will continually decrease causing a corres-
ponding increase in the gas temperature. To maintain full load on the
boiler, an increased fuel and air flow is required. Thus, nitrogen oxide
emissions are increased because of the higher gas temperature and parti-
culate emissions may be increased or decreased depending on the additive
or offsetting effects of a higher gas flow rate and a higher gas tempera-
ture.
4.5.2 Bottom Ash
In some boiler designs, the accumulation of clinkers in the bottom
arch of the boiler can reduce heat transfer to the water wall tubes. Until
the clinkers are removed, this condition will create a decrease in heat
transfer efficiency similar to the deposition of ash on the walls and will
have a similar effect on emissions of particulate matter and nitrogen
oxides. If the clinker accumulation problem becomes severe, shutdown of
the boiler may be required. The normal shutdown procedure would be fol-
lowed because the problem would be foreseen ahead of time.
4.5.3 Burner Mechanism
A malfunction of the burner tilt mechanism on boilers equipped with
variable-tilt burners may create problems in maintaining proper steam
temperature from the boiler. This equipment malfunction has a transient
emission effect to the extent that burner tilt position influences the
nitrogen oxide emission rate. A quantitative correlation of the effect
of burner tilt position on NO emissions is not now available.
X
4.5.4 Ljungstrom Air Preheater
The failure of a rotary (Ljungstrom) air preheater motor can create
serious problems with respect to boiler operation. Many units are
68
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equipped with a spare motor that can be put into operation quick-
ly to maintain boiler service. However, most Ljungstrom pre-
heaters will be damaged if rotation is stopped even for as short a
period of time as several minutes. If a spare motor is not available,
or both motors fail, heat transfer between the incoming air and the
flue gas is reduced drastically. The pulverizer mills in a coal-fired
plant cannot operate normally without preheated primary air, and clogging
of the mills may occur, causing a forced load reduction (disruption of
fuel supply). If the boiler has only one preheater, shutdown may be
necessary to prevent warping of the preheater due to the thermal stress
created by the two gas streams of different temperature. In a unit with
more than one preheater, the affected heater can be isolated by closing
fan dampers, and only a load reduction is required. With respect to
emissions, the important effects of an air preheater motor failure are
changes in the gas temperature and gas flow rate. Cooler incoming air
will result in a lower temperature in the flame zone, and nitrogen oxide
emissions will be decreased. Hotter flue gas temperatures may increase
or decrease the electrostatic precipitator efficiency, depending on the
ash resistivity-temperature relationship. An increase or decrease in the
gas volumetric flow will cause a corresponding decrease or increase in
precipitator efficiency, as previously discussed.
4.5.5 Electrostatic Precipitator
There are several types of malfunctions which can occur in the opera-
tion of an electrostatic precipitator, all of which generally have the
effect of increasing the emission of particulate matter. Nitrogen oxide
and sulfur oxide emissions are not affected by electrostatic precipitators.
Electrostatic precipitators are subdivided into independent bus sec-
tions so that an electrical failure in one part of the precipitator will
not result in a complete loss of efficiency. The effect of the loss of
service of a particular bus section depends on the location of the section
and the total number of sections in the precipitator. A theoretical model
can be constructed by considering that the total precipitator consists of
several independent units in a combined series-parallel configuration.
The Deutsch-Anderson equation can be applied to each independent bus sec-
tion, and a model for the total precipitator can be formulated. With the
69
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model, the change in participate emissions resulting from the loss of
service of any particular bus section can be predicted. This modeling
technique has been used in studies by the Tennessee Valley Authority.
Figure 10 shows performance curves for a unit of the Shawnee Plant
when various bus sections are not in service. Field tests have confirmed
these predictions. However, at another plant, TVA has not been able to
confirm predictions calculated in similar manner.
Loss of service of one or more precipitator bus sections will result
from the following malfunctions.
1. Failure in the power supply transformer or rectifier.
Either the unit is repaired on site or replaced by a spare
while being repaired at the factory. Shipment to the factory
usually is required for repairs. Delays of 4-5 days may occur
if equipment is not available on site for lifting and handling
the power supply units.
2. Electrode short to ground at a bushing or at the ash hopper.
If the short is at a bushing, the boiler must be shut down to
repair the bushing. Shorts to the ash hopper sometimes can be
eliminated by correcting the ash flow difficulties that created
the problem.
3. Broken Electrode. A broken electrode normally will short an
entire bus section to ground. To repair the electrodes, the
boiler must be shut down.
Clogging of an ash line or ash hopper can prevent ash removal and
cause an accumulation of ash above the normal hopper level. This mal-
function initially will cause reentrainment of ash in the gas stream and
eventually can cause an electrode short at the ash hopper. Ash flow
sometimes can be restored without bringing the unit off line, but shut-
down may be necessary.
A failure of a rapper or vibrator in the electrostatic precipitator
will result in an accumulation of ash or the wire or plate. Particulate
emissions generally will be reduced for a few hours because reentrainment
of ash is reduced. Eventually, however, the caked ash on the wire or
70
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100
98
96
92-
60 Wv
\/ i
91 Mw
V
KOMw
V
147 M«
LV
FLUE GAS FLOW, KrrrVmin
Figure 10. Efficiency of a tandem mechanical collector and electrostatic precipitator at
the Shawnee Steam Plant of the Tennessee Valley Authority. The precipitator
consists of two parallel sections with three fields each. The conditions are
(1) all bus sections in service, (2) one bus out in third field, (3) one bus
out in first ur second field, (4) two buses out in third field, (5)
-------
plate will affect the collection process adversely, and the emission
level will increase. Rapper and vibrator failures sometimes can be
repaired during operation if the problem is external to the precipitator.
Otherwise, the boiler must be shut down to accomplish repair.
The service history for electrostatic precipitators on the TVA
system is shown in Figure 11. This data is given in terms of bus unavail-
ability, that is, the percent of time that the average bus section of
a given type of precipitator has been available for service. TVA has
been able to isolate some of the problems that caused these failures
and make corrections, which improve the reliability of the precipitators.
The major problems TVA has encountered with electrostatic precipitators
are discussed below (ref. 14).
Ash removal problems were caused by insufficient capacity of the ash
hopper and a lack of flexibility of the removal and disposal systems. All
electrostatic precipitators except one on the Tennessee Valley Authority
System have sequentially operated, dry ash-removal systems. With good
design and adequate maintenance, these systems have given good performance.
The failure of discharge wires has been a problem for TVA. A severe
incidence of wire failures occurred on precipitators serving cyclone fur-
naces burning coal with 4 percent sulfur content. The failures, occurring
immediately below the corona shield, were believed to be the result of
acid corrosion and localized arcing between the wire and the corona shield.
To reduce the wire deterioration, heated purge air was supplied to the
high voltage support insulators from an intermediate section of the tubu-
lar air preheater.
The rate of failure of the transformer-rectifier sets has been low
for TVA. However, some difficulty has been experienced in replacing a
unit with a spare because of handling problems. Specifications for new
units now require a means for lifting and handling the transformer-recti-
fier sets.
The high voltage insulators that support the electrode system in
the precipitators of TVA are of two types: the cylindrical-tube type and
the post or stacked type. Excessive failures due to surface cracks have
72
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23
22
21
i
i e
si
g
o
/
\
\
\
INSULATORS
FLY ASH
INTERNAL SHORTS
UNKNOWN
SLUICE SYSTEM
CONTROLS
WIRES
\
\
\
\
A
\
\
\
\
N
\
N
\
\
N
B
H
I
D E F G
PRECIPITATOR
Figure 11. Service history for nine types of electrostatic precipitators on
the Tennessee Valley Authority system.
73
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been experienced with the cylindrical-tube type, but no failures have
been experienced with the port type of insulator.
TVA has had trouble with the binding or rapper rods. Each rod
passes through a sleeve as it penetrates the exterior wall of the
precipitator. Ash tend to work into the sleeve and prevent a free
motion of the rod.
The current practice of TVA is to write specifications for new
precipitators so that the equipment will operate with improved effi-
ciency, reliability, and maintenance cost. The performance tests and
maintenance records for the existing units are used as the basis for new
modifications in the equipment.
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APPENDIX A
THE FOSSIL-FUEL-FIRED STEAM-ELECTRIC GENERATION PLANT
Three predominant energy conversion systems are used for the genera-
tion of electricity. First, in the conventional steam-electric generation
plant, chemical energy stored in a fossil fuel is released as thermal
energy through combustion. The thermal energy, which is stored in steam,
is converted into the mechanical energy of a rotating shaft by a turbine,
and the mechanical energy is converted into electricity by an alternator.
Second, in the hydroelectric generation plant, potential energy stored
in elevated water is converted into mechanical energy by a turbine and
thence to electrical energy by an alternator. Third, in the nuclear-
electric generation plant, molecular energy is released as thermal energy
during fission. The thermal energy is stored as steam and converted into
electricity as in the conventional steam-electric generation plant. The
internal combustion turbine is & variation of the first system described
above where the intermediate generation of steam is omitted; instead, the
combustion of natural gas occurs in the turbine.
Of the three methods of energy conversion, which are used for the
generation of electricity, only the conventional steam-electric generation
plant is discussed in this report. Unless otherwise noted, any reference
to a steam-electric generation plant refers to the conventional plant,
which is fired with a fossil fuel: that is, with coal, oil or natural gas.
With respect to gaseous emissions that are the result of the com-
bustion of fuel, the coal-fired generation plant is of principal interest
for several reasons. First, coal is the fuel most frequently used in the
generation of electricity; second, the emission products created from
combustion of coal generally contain higher pollution concentrations than
the products resulting from the combustion of oil or natural gas; and
third, the combustion of coal cannot be controlled as well as that of oil
or natural gas. Most of this report concerns the coal-fired steam-elec-
tric generation plant because any problem that is found in a gas- or oil-
fired steam-electric generation plant usually is encountered to a greater
degree in a coal-fired plant.
75
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A steam-electric generation plant usually consists of several
parallel unitary plants fed from a common supply of fuel and connected
to a common electrical load. In each unit, chemical energy stored in
the fuel is released by combustion in a furnace and is converted to
thermal energy in the boiler by boiling water to produce steam. The
thermal energy contained in the steam is then converted to mechanical
energy as the steam passes through a turbine, causing it to rotate. The
rotating turbine drives the alternator that generates electricity for
distribution to customers. The products of combustion, including some
of the heat, are released to the atmosphere through a stack after pass-
ing through gas-cleaning equipment, such as a mechanical collector,
electrostatic precipitator, or gas scrubber.
Many variations occur in the design of generation plants. Sometimes
two boilers supply steam to a single turbine, and both boilers are served
by a single stack. In older plants, all furnaces may be served by a
single stack, with ducts, called breeching, carrying the gases from each
furnace to the stack.
Each of the energy conversion steps is accompanied by a characteris-
tic loss of energy. Although the overall energy conversion of a steam-
electric generation plant is less than 40 percent and some loss occurs
in transmission lines, the electrical energy produced in central genera-
tion plants and distributed through an electrical network is more versa-
tile and useful to consumers than the original fuel. Minimizing the
loss of energy is a major concern in the design and operation of a
fossil-fuel-fired steam-electric generation unit.
Many factors affect the design and operation of a steam-electric
generation unit. Important factors include the magnitude and time
variation of the electrical load to be handled, the size of existing
units that will be operated in parallel, the costs and chemical composi-
tion of available fuels, the type and amount of cooling water available,
and the location of the plant. A typical steam-electric generation plant
has many complex components and a comprehensive control system. Because
generation units in existence today represent various eras of engineering
7fi
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development, only the most common major components will be discussed,
and their performance will be related to the gaseous emissions from the
stack.
Each steam-electric generation plant consists of two major pro-
cesses, commonly known as the fuel-gas circuit and the water-steam
circuit. Details of these processes are given below. The fuel-gas
circuit is especially important because all of the significant air pollu-
tants emitted from a steam-electric generation plant emanate from the
fuel-gas circuit. The fuel, the input to the fuel-gas process, is dis-
cussed in a separate section.
A.I The Fuel-Gas Circuit
The fuel, when received at a plant, first enters the preparation
and storage facilities. In a coal-fired plant, these facilities normally
consist of a system of components to receive, transfer, store, crush,
clean, and pulverize the coal. With oil or gas-fired units, less prepar-
ation is required and the system normally includes only tanks and other
storage vessels with the associated equipment for heating, pumping and
regulating the pressure of the fluid fuel.
Fuel taken from the preparation and storage system is forced into
the furnace, where combustion occurs. A modern furnace is a large struc-
ture as tall as 200 feet (see Figure 12). The fuel enters the furnace
through a set of burners located in windboxes in the sides or corners of
the furnace. Forced draft fans blow air through the windboxes, and com-
bustion occurs, producing hot gases. The inside walls of the boiler are
covered by water-filled tubes that are part of the water-steam circuit.
The water circulating through the tubes absorbs part of the heat released
by combustion.
After combustion of the coal, the ash residue (called "bottom ash")
is collected as a solid or liquid, depending upon the physical proper-
ties of the coal. When coal with a high ash-fusion temperature is burned,
the lower section of the furnace is funnel-shaped and leads to an ash pit
where the solid ash is collected. In furnaces designed to burn coals with
a low ash-fusion temperature, the residue is a liquid; hence, the bottom
of the boiler is a flat surface on which a pool of liquid slag is main-
tained and tapped periodically into a slag tank containing water.
77
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BURNERS
Figure 12. Modern boiler.
78
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Hot furnace gases containing small particles of ash (called "fly
ash") travel upward from the region of the furnace flame and pass over
several heat recovery devices that are part of the water-steam circuit.
In order, these usually are the secondary superheater, the reheater, the
primary superheater, and the economizer. In some installations part of
the exhaust leaving the economizer is fed back into the bottom of the
boiler in a process that is called gas recirculation. This feedback of
furnace gases can control the superheat or reheat temperature and the
heat absorption pattern under varying conditions of operation.
The last heat recovery device usually encountered by the hot gases is
the air preheater through which heat is tranferred from the hot exhaust
gases to the air coming into the furnace. The use of an air preheater per-
mits a higher furnace flame temperature and a consequent reduction in heat
transfer surface and enables the fuel to be burned more completely.
An exhaust gas cleaner normally is placed after the air preheater to
remove the entrained fly ash. Four different types of exhaust gas cleaners
are available: electrostatic precipitators, mechanical collectors, fabric
filters, and wet scrubbers. Each has a characteristic efficiency, advan-
tage, and limitation, which determine the appropriate choice in a given
situation. In some installations that utilize electrostatic precipitators,
the exhaust gases pass through the air preheater so that the precipitator
can operate at a higher temperature. A precipitator operates better at
a high temperature when coal with a low sulfur content is burned because
the fly ash has a lower resistivity at the higher temperature.
The cleaned gases are vented to the atmosphere through the stack.
The exhaust gases are typically in the range of 250 to 350° F. The stack
provides a certain amount of natural draft to help move the gases through
the furnace. Supplementary fans, called induced draft fans, often are
placed between the exhaust gas cleaner and the stack to increase the draft.
Individual components of the fuel-gas circuit are discussed further in
Section A.4.
A.2 The Water-Steam Circuit
The water-steam circuit is the medium through which thermal energy
released by combustion of the fuel is converted into rotational mechanical
79
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energy in the turbine. Industrial boilers usually are rated by the amount
of steam that is produced per hour and the temperature and pressure of the
steam. However, electric utility boilers are designed as part of a gener-
ation unit, and the entire unit is rated in megawatts of capacity. Utility
generation units now in service range in capacity from less than 100 MW to
over 1,200 MW output power. Maximum steam pressures range from about 1,000
psi in small boilers to over 4,000 psi in large modern boilers.
A working knowledge of the relationship of steam and water is impor-
tant to the discussion of the water-steam circuit. At a given temperature
and pressure, water boils or vaporizes to steam. The latent heat of vapor-
ization is the energy released when steam is condensed to water. As the
pressure is increased, the boiling temperature of water increases, and the
increment of stored energy per pound of steam decreases. Above the "criti-
cal pressure" (about 3,200 psi) there is no demarcation between water and
steam. Boilers that operate above the critical pressure are called super-
critical boilers, and those that operate below the critical pressure are
called subcritical boilers.
A schematic diagram of the water-steam circuit is shown in Figure 13.
The inside of the furnace walls are lined with tubes containing water (see
Figure 12). The pressurized water circulating through the wall tubes is
heated by the furnace gases. The tubes are interconnected in some sub-
critical boilers with large drums located at the top of the boiler. Steam
forms in these drums and is separated from the circulating water. After
separation in the drum, the steam is piped through the superheater sections
to acquire more energy before entering the turbine. In supercritical
boilers and once-through subcritical boilers, boiling and superheating are
accomplished during one continuous passage through the tubes, and there
is no steam drum.
In a unit with a multiple-stage turbine, the steam may pass back to
the boiler between the stages of the turbine to flow through a reheater
and gain additional energy. After leaving the last turbine, the low pres-
sure steam is converted back to water in a condenser. The energy released
by condensation is absorbed by a constant flow of cool water, which nor-
mally is drawn from and returned to a lake or river. Where a suitable
80
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oo
SUPERHEATER
REHEATER
HIGH PRESSURE
TURBINE
ELECTRIC
GENERATOR
LOW
PRESSURE TURBINE
WALL
TUBES
CONDENSER
RIVER,
LAKE, OR
COOLING
TOWER
Figure 13. Schematic diagram of the watrr-stenm circuit.
-------
lake or river is not available, cooling towers or manmade ponds may be
used to dissipate the unused heat.
The high purity condensate is returned to the boiler as feedwater.
On its way back to the wall tubes, it is preheated by feedwater heaters
in the economizer section of the boiler. A small amount of makeup water
is added to the feedwater to compensate for losses through leakage and
ventilation. With the return of the feedwater to the boiler, the water-
steam circuit is completed.
A.3 Major Components of the Fuel-Gas Circuit
Since all of the significant air pollutants emitted from a fossil-
fuel -fired steam generator are associated with fuel combustion, the
design and operation of the fuel-gas circuit is of primary importance in
air pollution control. The following discussion of the major components
associated with the fuel-gas circuit is directed toward an understanding
of the variables of operation and the constraints of the system. The
material will provide a background for consideration of the paramenters
which affect the emissions of air pollutants.
A.3.1 Fuel Preparation Equipment.
With oil- or gas-fired units, fuel preparation normally involves
only the storage and transportation of the fuel to the boiler with no signi-
ficant effect on air pollutant emissions. Coal, however, requires consider-
able preparation before it is fired, especially in the more modern boilers.
Ordinarily, coal is partially cleaned, dustproofed, and dried
before it arrives at the steam-electric generation plant. These processes
reduce the ash and moisture content of the coal and enable the coal to be
handled more easily. At the generation plant the coal is unloaded and
stored in a large pile. Large bulldozers often are used to pack the piles
and reduce the potential for spontaneous combustion or partial oxidation
(with a loss of heating value) during storage. The coal is later crushed
and transferred to large storage vessels, called bunkers, near the boil-
ers. When coal is burned in a boiler, it is usually pulverized first,
and clinkers (chunks of noncombustible materials) are removed. Hot air
is forced into the pulverizers to dry the coal and carry it into the
boiler. Figure 14 shows a typical coal preparation system for a system
utilizing pulverized coal.
82
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00
CO
COAL
BREAKER
COLD (TEMPERING) AIR
FROM FORCED DAFT FAN"
TEMPERING AIR
DAMPER
PULVERIZED FUEL
BURNE
HOT AIR FROM
BOILED AIR HEATER
BOILER
FRONT WALL
BURNER
'WINDBOX
PULVERIZED FUEL
AND AIR PIPING
CONVENOR-BELT
HOUSING
PRIMARY
AIR FAN
Figure 14. Pulverized coal preparation system.
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A.3.2 Fuel-Firing Equipment
Whether the unit fires pulverized coal, oil, or natural gas, the
design objectives are to mix intimately the fuel and air, to provide
sufficient air to burn the fuel completely, to maintain a temperature
high enough to ignite the fuel-air mixture, and to allow the residence
time needed for complete combustion.
Fuel-firing equipment can be divided into five general categories:
a) stoker furnaces, B) cyclone furnaces, c) pulverized coal furnaces,
d) oil-fired furnaces, and e) gas-fired furnaces.
Stoker-fired furnaces now are found only in small and, usually, old
boilers. The typical stoker shown in Figure 15 consists of a flat, moving
grate carrying a bed of crushed, burning coal several inches thick. A
motor-driven feeder moves coal from the bunker or hopper to the moving
grate, which is the width of the furnace. Air is admitted from below the
bed, and the ash not entrained by the air is dumped into a hopper as the
grate passes out of the furnace.
In the cyclone furnace, illustrated in Figure 16, finely crushed
coal and primary air are admitted tangentially at one end of a water-
cooled, horizontal, cylindrical chamber. Secondary air enters tangent-
ially along the length of the cyclone and imparts a whirling motion to the
air-fuel mass. Finer particles burn in suspension, and the coarser par-
ticles are thrown to the circumference of the furnace by centrifugal force.
Molten slag on the furnace walls retains the coal particles while combus-
tion continues. The slag drains continuously down the walls into a
quenching tank. Hot combustion gases leave the furnace through the throat
to the additional tube-lined heat transfer area of the boiler.
The remaining three types of fuel-firing equipment differ primarily
in the burner design, which is dependent on the type of fuel fired.
Figure 17 illustrates some configurations of fuel-firing equipment.
In pulverized coal furnaces, the air used to transport the coal from
the pulverizers to the burners is called "primary air." The remaining
air, called "secondary air," is supplied through apertures in the windbox
and mixes with the coal and primary air. The burners normally are
equipped with small oil nozzles, and ignition is achieved with the aid
of a light fuel oil. Once combustion is initiated, coal gradually is
84
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COAL HOPPER
Figure 15. Stoker furnace and boiler.
85
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TANGENTIAL SECONDARY
AIR
PRIMARY AIR
COAL
PRIMARY FURNACE
HOT GASES
CYCLONE SLAG-
TAP HOLE
-PRIMARY FURNACE
SLAG-TAP HOLE
Figure 16. Schematic drawing of cyclone furnace. Usually several
cyclones are used on a single primary furnace.
86
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PRIMARY AIR
AND COAL
SECONDARY
AIR >
FANTAIL
SECONDARY
AIR
PRIMARY AIR
COAL
MULTIPLE INTERTUBE
PRIMARY AIR
AND COAL
SECONDARY AIR
PLAN VIEW OF FURNACE
OPPOSED-INCLINED FIRING
SECONDARY
AIR
PRIMARY AIR
AND COAL
PRIMARY AIR
AND COAL
SECONDARY AIR
MULTIPLE INTERTUBE
PRIMARY AIR
AND COAL
SECONDARY AIR
CIRCULOR
Figure 17. Configurations of fuel-firing equipment in furnaces.
87
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admitted and the pulverized coal allows burning of the coal in a sus-
pended state, a more efficient process than the bed firing that is pre-
dominant in stokers. Depending on the type of coal to be fired, pulver-
ized coal furnaces can be designed to remove bottom ash as solid clinkers
(dry-bottom boiler) or as a molten slag (wet-bottom boiler).
Fuel oil must be atomized, that is, dispersed into a thin film or
mist, to achieve proper combustion with low excess air. Atomization can
be accomplished by mechanical devices and pressurized flow or with the aid
of auxiliary fluids, either steam or air. Heavier oils must also be pre-
heated to enhance flow and atomization. Combustion air enters the furnace
through and around the fuel spray nozzles.
Natural gas combustion can be accomplished with premixing of air and
gas as in a carburetor, but this practice is normally not used in steam-
electric generators. Common gas burners propagate a diffusion flame, that
is, the air and gas remain separated until they are brought into intimate
contact at the burners. Various burner designs are available to enhance
mixing of the air and gas and to control the release of heat to the trans-
fer surfaces.
By the incorporation of burner design modifications and of the neces-
sary ash-handling facilities, most cyclone furnaces, as well as those
illustrated in Figure 17, can be equipped to burn combinations of the
three fossil fuels.
A.4 Boilers
The term "boiler" has two general connotations, depending on the
context in which it is used. In general discussions regarding major
subsystems in a large plant, the term "boiler" ususally refers to the
entire structure where steam is generated and includes the furnace,
superheater, preheater, economizer, and auxiliary equipment. In more
precise discussions of components within the steam-generating units, the
boiler is the package of tubes and drums in which water is vaporized
into steam. Sometimes the term "boiler proper" is used to eliminate am-
biguity. The following discussion is concerned with the boiler proper.
There are many names used to classify modern boilers. The general
class of interest here is the water-tube boilers of the bent-tube type.
Other names are given to various subclasses within this category, such as
the Radiant, two-drum Sterling, and universal pressure. These boilers
-------
are distinguished from one another by one or more special design features.
It is not necessary here to give detailed descriptions by type. In most
modern steam generation units, the entire passage for the hot gases from
the burners to the economizer normally has water tubes on the walls. The
water-cooled tubes line the furnace, the enclosure around the superheater,
and sometimes even the economizer. A bank of tubes, known as the convec-
tion boiler surface or convection bank, may be suspended higher in the
path of the hot gases beyond the superheater. Steam is generated by the
heating of the water in the tubes that line the furnace walls. This sec-
tion of the water-steam circuit is the boiler proper. The steam generated
in the boiler proper is saturated, and any reduction of temperature or
increase in pressure will initiate condensation of the steam back into
water.
A.4.1 Superheaters and Reheaters
When steam leaves the boiler proper, it passes through the superheater
before going to the first stage of the turbine. In the superheater the
temperature of the steam is raised above the temperature of boiling
water, and the steam can pass through the first stage of the turbine and
release energy with no condensation of moisture which would cause excessive
wear in the turbine.
The reheater, sometimes called the reheat superheater, is an addi-
tional superheater located in the path of steam flow between sections of
the turbine or turbines. The reheater superheats the steam after its
passage through the high-pressure turbine. Then the steam entering the
intermediate or low-pressure turbines can be utilized further, improving
the efficiency of the cycle. In recent years a steam temperature of
540 to 600° C has been regarded as a good compromise between increased
efficiency and the technical and economic problems associated with mater-
ial requirements to accommodate the higher steam temperatures.
Physically, superheaters and reheaters are banks of tubes suspended
in the path of the hot gases (see Figure 12). Two major categories of
each device are the convection type and the radiant type. The convection
type is located around a bend in the path of the gases, and the energy
to superheat the steam is transferred by convection. The radiant type is
transferred for superheating the steam by radiation as well as convection.
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A.4.2. Economizers
The economizer is a device designed to recover some of the energy
present as heat in the exhaust gases (which would otherwise be partially
lost out the stack) by preheating the boiler feedwater. The economizer
usually is located after the superheater in the gas flow, and it consists
of a bank of tubes set counter-cross-current to the flow of the hot
exhaust gases (see Figure 12). Feedwater enters the economizer at the
bottom, rises as it passes back and forth across the gas duct through
the tubes, and exits through a header at the top.
A.4.3 Air Preheaters
Additional heat is recovered from the flue gases in the air preheater.
The air supplied to the combustion zone of the boiler usually is heated
to a temperature of 150 to 320° C by the flue gas leaving the boiler.
There is a considerable diversity of designs for preheaters. Several
tubular types are shown in Figure 18. Another popular preheater is the
rotary regenerative (Ljungstrom) type illustrated in Figure 19. Corrugated
metal "baskets" are supported in a circular frame and rotated to pass
progressively through the gas stream where they are heated and then
through the air stream where they give up their heat.
A few installations use other sources of heat for preheating the air.
Some units operating with steam heat, and other utilize a separate refrac-
tory furnace.
A.4.4 Ash-Removal and Gas-Cleaning Equipment for Particulates.
Ash removal and flue gas cleaning are important functions when coal
is burned. The amount of ash in fuel oils and in natural gas is negli-
gible by comparison. Gas-cleaning devices sometimes are employed to
remove sulfur dioxide, but the following discussion is limited to the
removal of particulate matter.
Coal ash is a complex mixture of mineral compounds, chiefly those of
silicon, aluminum, and iron, with smaller amounts of the oxides of titan-
ium, calcium, magnesium, sodium, potassium, and other elements. Oil ashes
frequently contain large proportions of sulfur trioxide, vanadium pentox-
ide, and various alkalies. Besides inhibiting heat transfer and reducing
boiler efficiency, ash depositions can be severely corrosive to heat
transfer surfaces.
90
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GAS INLET
GAS OUTLET
AIR
OUTLET
GAS OUTLET
GAS DOWNFLOW
AIR AND GAS COUNTER FLOW
SINGLE WSS
GAS INLET
GAS UPFLOW
AIR COUNTER FLOW, THREE PASS
GAS UPFLOW AND DOWNFLOW
AIR COUNTERFLOW, SINGLE PASS
GAS INLET
_j_
OUTLET" -*
GAS OUTLET
GAS NLET
GAS UPFLOW AND DOWNFLOW
AIR COUNTERFLOW, SINGLE PASS
GAS INLET
GAS UPFLOW
AIR COUNTERFLOW, TWO PASS
AIR
OUTLET"
AIR
INLET
GAS OUTLET
GAS DOWNFLOW
AIR PARALLEL FLOW, THREE PASS
Figure 1K. Several designs for tubular air heaters.
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AIR SECTOR
AIR SECTOR
SECION AA
GAS OUT
AIR IN
PLATE GROUPS
IN AIR OUT
TOP VIEW
Figure 19. Rotary-type air preheater (Ljungstrom).
92
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Ash deposition in the boiler is an ever-present problem in coal-
fired units, regardless of the design of firing equipment and quality
of operation. Equipment and procedures therefore are provided for per-
iodic removal of ash deposits. Typically, soot blowers of the type
illustrated in Figure 20 are located at strategic points in the boiler,
and jets of air or steam are directed on the heat transfer surfaces
while the combustion equipment is in operation. During soot blowing, the
flow of air through the boiler should be adequate to remove dust, soot,
and fly ash without allowing the formation of an explosive mixture. Burn-
ers are adjusted for good stability, and furnace draft and air flow are
increased slightly to avoid smothering or loosing fires. Soot-blowing
operations may be carried out on a regular schedule varying from almost
continuously to about once per day. Sometimes, soot blowing occurs "as
needed" at the discretion of the operator. When ash is removed from the
heat transfer surfaces by soot blowing, the particulate load of the flue
gas is increased.
The ash not deposited on the interior surfaces of the boiler is
carried immediately up with the flue gases or falls down to the bottom of
the furnace as a solid or as a molten slag. The form of the bottom ash
is determined by the combustion temperature and the ash-fusion character-
istics. The percentage of the total ash that remains as bottom ash varies
with the type of fuel-firing equipment. In stoker furnaces only a small
percentage of the ash is normally entrained in the combustion gases. In
boilers using pulverized coal, roughly 70 to 80 percent of the ash in
coal is entrained in flue gases, if the furnace is the dry-bottom type,
and about 50 percent is entrained with a slag-tap furnace. A slag-tap
furnace with cyclone burners may emit only 20 percent to 30 percent of
the ash in the flue gases. However, a slag-tap furnace with its hot,
sticky, liquid slag is difficult to operate, particularly during periods
of low-load operation when furnace temperatures may not be high enough
to maintain the fluidity necessary for tapping. Once it is removed from
the furnace, bottom ash is either conveyed dry or by sluiced water to a
disposal site.
Most of the ash that is carried out of the boiler by the flue gases
can be recovered by gas-cleaning devices. Four types of air cleaners
93
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MOTOR
FURNACE WALL
STEAM OR
AIR INLET
(a) Wall Blower
FURNACE WALL>
STEAM OR
AIR INLET
CARRIAGE LANCE
TUBE
NOZZLES-
(b) Upper furnace blower
Figure 20. Two types of soot blowers. Both types shown are
retractable.
94
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commonly are used for participate removal: electrostatic precipitators,
mechanical collectors, fabric filters, and wet scrubbers. Of these
types, the electrostatic precipitator is used predominantly in large
steam generators, either by itself or in conjunction with one of the
other types of devices. In an electrostatic precipitator, dust suspended
in the gas stream is electrically charged and passed through an electric
field where electrical forces cause the particles to migrate toward a
collection electrode. The dust, separated from the gas by being retained
on the collection electrode, is subsequently removed from the device.
Usually, the dust is removed mechanically. In some designs, the dust is
removed by a continuous washing of the collection electrode.
The construction of an electrostatic precipitator is illustrated in
Figure 21. A large steel enclosure containes a bank of parallel, ribbed
steel plates. These plates form gas passages about 15 to 35 cm wide and
constitute the positive electrodes on which the precipitate is collected.
In the middle of these gas passages, a series of vertical wires is fas-
tened to form the negative electrodes. The particles are collected on
the steel plates and, to a lesser extent, on the wires. They are removed
periodically by a mechanical rap or vibration. Some of the precipitate
is reentrained, but most falls into hoppers underneath the electrodes.
The cleaned gas passes from the precipitator into the stack. The collec-
ted ash is removed from the hoppers and conveyed to a disposal site
usually by water sluicing.
Electrostatic precipitators find frequent use in coal-fired power
plants because of their ability to handle large rates of gas flow at high
temperatures with very little pressure drop. In this application, they
are capable of particulate mass removal efficiencies better then 99.5
percent. Most units now being installed are designed to have a removal
efficiency greater than 99 percent.
Mechanical collectors have a great variety in design. The most
common type for power plants is the dry centrifugal type, sometimes called
a cyclone collector. The basic principle behind cyclone collectors is
that, with a rapid rotary motion of the dust-laden gases, the particles
95
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BUSHING
WEIGHTED WIRE
PLATE
cr.
POWER SUPPLY
RAPPER
AIR INLET
ASH HOPPER
ACCESS PORT
21. The electrostatic precipitator,
-------
are forced by centrifugal force to the periphery of the device where
they slide downward into a collection hopper at the bottom.
The construction of a cyclone collector is illustrated in Figure 22.
The gases are introduced tangentially at the upper periphery at a high
velocity. Vortices are established, and the particles are separated to
the side of the hopper by centrifugal force as the gases circle to the
outlet tube. Removal efficiencies of cyclone collectors are usually less
than 85 percent. Most of the smaller particles of fly ash are not col-
lected. A series of cyclones sometimes has been used as a precleaner
before the use of an electrostatic precipitator. However, electrostatic
precipitators remove large particles easily, and the combination of a cy-
clone collector and electrostatic precipitator usually cannot be justified
in a new installation.
Fabric filters usually are placed in a parallel set of tubes, a few
inches in diameter and several feet long. The entire structure housing a
bank of these fabric tubes is called a baghouse and is illustrated in
Figure 23. The particle-laden gases are directed inside the tubes, and
the cleaned gases pass through the fabric and out of the baghouse. The
tubes are suspended from the roof over a dust-collection hopper. The bags
are emptied periodically by mechanical shaking or by a reverse flow of
clean air, which drops the dust into the collection hopper for subsequent
disposal. Moisture and high gas temperatures have particularly deleterious
effects on fabric filters.
Wet scrubbers are devices which remove particles by trapping them in
water. A great diversity of designs exists, some of them combining the
whirling action of cyclones with the wetting principle. A schematic dia-
gram of a venturi wet scrubber is shown in Figure 24. The dust-laden gas
passes through a venturi throat when it is wet by the scrubbing liquid.
the wet, dust-laden gas then enters a centrifugal mist separator which
separates the wet dust from the gas. The scrubbing liquid with the
entrapped dust falls to the bottom of the separator tank. The cleaned
gas is vented through the top.
Fabric filters and wet scrubbers are not discussed further because of
their limited present use as a particulate control device by the electric
97
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DUST LADEN AIR
CLEAN AIR EXHAUST
DUST TRAP
DUST OUTLET
Figure 22. Diagram of cyclone dust collector,
-------
SHAKER UNIT
GAS OUTLET
FABRIC FILTER TUBE
COLLECTED FLY ASH
Figure 23. Baghouse dust collector.
99
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GAS OUTLET-
GAS INLET
VENTURI
THROAT
SCRUBBING LIQUID INLET
CENTIFUGAL MIST
SEPARATOR
GAS OUTLET
Figure 24. Venturi wet scrubber. The scrubbing liquid is
atomized when it is introduced at the Venturi throat.
The f]y ash particles are trapped in the mist and then
separated from the gas in the centrifugal mist
separator.
TOO
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utility industry. However, filters and scrubbers are being used more
often now than they were in the past because a combination of filter
and scrubber can be used to meet the current new source performance
standards.
A.4.5 Stacks
The effect of the stack is to create a natural draft, which forces the
flue gases upward because the weight of the column of hot flue gases is
less than an equal column of ambient air. This difference increases
with increasing height; hence, the greater the height of the stack, the
greater the draft.
In a power plant, many considerations act to reduce the theoretical
draft available from a stack. These include resistance to flow due to
heat recovery devices and other frictional losses. Fans are used to
supplement the stack-induced draft. A fan is called a forced-draft fan
if it takes in air at atmospheric pressure and forces it into the windbox
of the boiler; it is called an induced-draft fan if it takes in flue gases
and pushes them through the stack. Most large boilers have both forced-
draft and induced-draft fans.
Besides serving to create draft, the stack has an important part in
the dispersal of pollutants. Increasing the stack height decreases the
average ground level concentration of pollutants. Electric utility
stack heights range from about 100 feet above ground to over 1,000 feet.
101
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REFERENCES
1. "Part 60 - Standards of Performance for New Stationary Sources,"
Federal Register 36. 24867 (December 23, 1971).
2. "Standards of Performance for New Stationary Sources: Emissions
During Startup, Shutdown, and Malfunction," Federal Register 38,
1082Q (May 2, 1973).
3. Private communication with Clarence Hall, Commonwealth Edison
Company, Chicago (August 1975).
4. Air Pollution Control, Part I, Werner Strauss (Editor), Wiley
Interscience, New York, 1971, p. 266.
5. A Manual of Electrostatic Precipitator Technology (Part II -
Application Areas), Southern Research Institute, 1970, p. 361.
6. Ramsdell, R., "Design Criteria for Precipitators," presented to the
American Power Conference (April 1968).
7. Skorik, L. D., and L. M.M Tsirul'nikov, "The Part Played by Atomic
and Molecular Oxygen in the Formation of SO, when Burning Natural
Gas of High Sulfur Content," Thermal Engineering 1973, 2p_ (March),
pp. 115-117 (H.V.R.A.Translation), p. 115.
8. Wilson, J. S. and M. W. Redifer, "Equilibrium Composition of Simu-
lated Coal Combustion Products: Relationship to Fireside Corrosion
and Ash Fouling," Journal of Engineering for Power, Transactions of
the ASME, April 1974, pp. 145-152.
9. Chaikivsky, M. and C. W. Seigmund, "Low-Excess-Air Combustion of
Heavy Fuel-High-Temperature Deposits and Corrosion," Journal of
Engineering for Power, Transactions of the ASME, October 1965, pp.
379-388.
10. Crawford, A. R. , E. H. Manny, and W. Bartok, "Field Testing:
Application of Combustion Modifications to Control NO Emissions
from Utility Boilers," EPA-650/2-74-066 (June 1974), pp. 43, 5, 14, 46.
11. Bueters, K. A., W. W. Habelt, C. E. Blakeslee, and H. E. Burbach,
"NO Emissions from Tangentially Fired Utility Boilers," presented
at &6th Annual AICHE Meeting, Philadelphia, Pa., 1973 (courtesy of
Combustion Engineering), p. 17.
12. Rowden, A. H. and R. S. Sadowski, "An Experimental Correlation of
Oxides of Nitrogen from Power Boilers Based on Field Data," Journal
of Engineering for Power, Transactions of the ASME, July 1973,
pp. 165-170.
103
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13. Johnson, S. A., Chemical Research Engineer, Riley Stoker Corpora-
tion, Worcester, Massachusetts, Personal Communication, October 4,
1974.
14. Greco, Joseph, "Electrostatic Precipitators-An Operator's View,"
presented at the Air Pollution Control Association Conference on
the Design, Operation, and Maintenance of High Efficiency Parti -
culate Contol Equipment, St. Louis, Missouri (May 29-30, 1973).
104
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TECHNICAL REPORT DATA
Iflease read Inxrvctions on the reverse before completing)
1. REPORT NO.
EPA-600/2-75-022
2.
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITI
Effects of Transient Operating Conditions on
Steam-Electric Generator Emissions
5. REPORT DATE
August 1975
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
J.S. McKnight
8. PERFORMING ORGANIZATION REPORT NO
9. PERFORMING ORQANIZATION NAME AND ADDRESS
Research Triangle Institute
P.O. Box 12194
Research Triangle Park, NC 27709
10. PROGRAM ELEMENT NO.
1AB013; ROAP 21BAV-002
11. CONTRACT/GRANT NO.
68-02-1325, Task 10
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND I
Final; 1/74 - 1/75
D PERIOD COVERED
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
is. ABSTRACT
repOrf gjves results of B. review of information currently available on
the effects of transient operating conditions on gaseous emissions from fossil-fuel-
fired steam-electric generating plants. Information was obtained from scientific
literature, personal visits to utility companies, and correspondence with utility
companies and manufacturers of generating plant equipment. Emissions of concern
are nitrogen oxides, sulfur oxides, particulates , and visible emissions. Particular
attention was given to older coal-fired generators, used to provide the cycling portion
of the diurnal variation in electricity generated by electric utilities. No consideration
is given to flue gas desulfurization processes used to remove sulfur oxides. Tran-
sient conditions included in this study are starts, stops, cycling, and upset conditions
caused by equipment malfunctions or changes in fuel characteristics or load.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COS AT I Field/Group
Air Pollution
Steam Electric Power
Generation
Fossil Fuels
Nitrogen Oxides
Sulfur Oxides
Flue Dust
Air Pollution Control
Stationary Sources
Transient Operating
Conditions
Particulates
Visible Emissions
13B 21B
10A
21D
07B
8. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport}
Unclassified
21. NO. OF PAGES
114
20. SECURITY CLASS -(Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
105
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