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

-------
                            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

-------
                       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

-------
                                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

-------
                            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

-------
                               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

-------
                            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

-------
                              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).

-------
                               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

-------
 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

-------
     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

-------
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

-------
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

-------
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

-------
              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

-------
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

-------
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

-------
(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

-------
            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

-------
     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

-------
   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

-------
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

-------
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

-------
     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

-------
 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

-------
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

-------
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

-------
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

-------
 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

-------
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

-------
   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

-------
   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

-------
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.
                                   74

-------
                                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

-------
     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

-------
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

-------
                                                  BURNERS
Figure  12.   Modern boiler.
            78

-------
     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

-------
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

-------
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

-------
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.

-------
     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

-------
                                            COAL HOPPER
Figure 15.  Stoker  furnace  and boiler.
                  85

-------
      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

-------
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

-------
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.
                                    89

-------
     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

-------
                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.

-------
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

-------
     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

-------
            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

-------
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

-------
                       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

-------
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

-------
                                         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

-------
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

-------
                              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

-------
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

-------
                                  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

-------