-------
The simple exponential relationships
yi = (0.155)X°'905 (64)
and
Va = (0.618)X°-894 ' (65)
can be used for interpolation purposes in determining the rapping
emissions (mg/DSCM) for a given calculated mass removed by the
last field (mg/DSCM) for cold- and hot-side precipitators, respec-
tively. Figure 278 was constructed using the cal?ulated mass
removed in the last field determined by the measured overall
mass collection efficiency during normal operation of the precipi-
tator. This was done because complete traverses were made by the
mass trains during the normal tests whereas this was not the case
for the measurements made during the no-rap tests. In principle,
.the no-rap efficiencies should be used to calculate the mass removed
in the last field. Obviously, the limited amount of data obtained
thus far is not sufficient to validate in general the approach pre-
sented here. However, this approach gives reasonable agreement
with the existing data and offers a quantitative method for esti-
mating rapping losses.
The apparent size distribution of emissions attributable to
rapping at each installation was obtained by subtracting the cumu-
lative distributions during non-rapping periods from those with
rappers in operation, and dividing by the total emissions (based
on impactor measurements) resulting from rapping in order to obtain
a cumulative percent distribution. Figure 279 contains the results
of these calculations. Although the data indicate considerable
scatter, an average size distribution has been constructed in
Figure 280 for use in modeling rapping puffs.
Summary of the results of rapping studies—Pilot plant studies
indicate that, rapping emissions decrease with increasing time be-
tween raps. Also, the percentage of the collected dust removed
from the collecting.electrode increases with increased time between
raps. The buildup of a residual dust layer on the collecting elec-
trodes that could not be removed with the maximum, available normal
plate acceleration has been evidenced. By varying the rapping
frequency, the penetration due to rapping reentralnment could be
varied from 18 to 53% of the total penetration. These results
point out the need for a flexible rapping system in which the
rapping frequencies for the different sections can be varied and
in which the rapping intensities can be varied. With this type
of system, the rapping function can be optimized for specific pre-
cipitator operating conditions and ash properties in order to
minimize the-penetration of particulate out of the precipitator
due to rapping reentrainment.
493
-------
a
UJ
UJ
S
<
5
£*>
10
9
8
7
6
5
4
3
2
1
I
0
•
A
~ A
- D
~ •
-
-
_
-
-
D
1
I 1 i 1 i 1 i 1 i f i
PLANT 4 «c
PLANT 6
PLANT 2 Q» D&
PLANT 3
PLANT 5 o •K>A A
PLANT 1
• »A.A
• 0 0 44
O O • £ A
0 •& A
P *• f , , ,
111 I
£ 0 A
' A
—
-
-
-
_
-
-
I { | i
0.5 1 2 5 10 20 30 40 50 60 70 80
% LESS THAN
90 95
99 99.8 99.9
3S40-26B
Figure 279. Apparent rapping puff size distribution for six
full-scale precipitators.19
494
-------
20
I I
I J I
£
a
tr
LU
I—
Ul
10
9
8
7
6
5
J I
I 1 t
J_
_L
10 20 30 40 50 60 70 80
%LESS THAN
I ,
90 95
3S40-2S9
Figure 280.
Average rapping puff size distribution for six
full-scale precipitators.19
495
-------
The pilot plant data suggest that thicker dust layers produce
larger reentrained particles upon rapping. The majority of the
particles in the rapping puffs were agglomerates. These data
would indicate that as one proceeds from the inlet section to the
outlet section increased times are needed between raps in order
to obtain dust layers with sufficient thickness to produce large
reentrained agglomerates during rapping. The large agglomerates
can be easily recollected by the precipitator. Depending on the
rapping frequency, typical mass median diameters for reentrained
particulate from an inlet section would range from approximately
10 ym to 20 ym with very little of the mass less than 2.0 ym.
The pilot plant studies also showed significant vertical strat-
ification of particulate matter reentrained as a consequence of
rapping. All particle size bands showed a decrease in concentra-
tion with increasing distance from the bottom baffle. This was
attributed to both gravitational settling and hopper boil-up.
Emissions due to hopper boil-up were observed at some time after
observation of emissions due to particulate matter reentrained
directly into the gas stream from the collection electrodes. In these
studies, hopper boil-up contributed significantly to the reentrain-
ment emissions. This points out the need for adequate design of
hoppers and hopper regions to prevent excessive hopper boil-up.
The data obtained from the six full-scale precipitators showed
that rapping losses as a percentage of total mass emissions ranged
from over 80% for one of the hot-side units to 30% for the cold-
side units. The high rapping losses for the hot-side unit were
probably due both to reduced dust adhesivity at high temperature
and relatively short rapping intervals. It was also found that
reduction of the operating current density at Plant 2 resulted in
increased emissions due to rapping. This was due to increased mass
collected in the last field and reduced electrical holding force.
Measurements of fractional efficiency with and without elec-
trode rapping showed that losses in collection efficiency due to
rapping occur primarily for particle diameters greater than 2.0 ym.
The available mass emission data suggest a correlation between
the dust removal rate in the last rapped section of the precipi-
tator and the emissions due to rapping. Apparent rapping puff
particle size distributions measured at the outlets of the full-
scale precipitators had mass median diameters ranging from approxi-
mately 6.0 ym to 8.0 ym. Real-time monitoring of outlet emissions
also revealed sporadic emission of particulate matter due to
factors other than rapping.
Reentrainment from Factors other than Rapping—
Although it is difficult to quantify the complex mechanisms
associated with particle reentrainment due to (1) the action of
the flowing gas stream on the collected particulate layer, (2)
sweepage of particles from hoppers caused by poor gas flow con-
ditions or air inleakage into the hoppers, (3) bouncing of
496
-------
particles following, impaction on the collection surface, (4)
impaction of large particles with small particles previously de-
posited on the collection electrode, and (5) excessive sparking,
the effect of these nonideal conditions on precipitator perfor-
mance can be estimated if some simplifying assumptions are made.
If it is assumed that a fixed fraction of the collected material
of a given particle size is reentrained and that the fraction
does not vary with length through the precipitator, an expression
can be derived which is identical in form to that obtained for
gas sneakage:218
P 1/NR NR
*N = [R + (l-R)(l-n.) ] , (66)
K -L
p
where N_ is the penetration of a given particle size corrected
K
for reentrainment, R is the fraction of material reentrained, and
NR is the number of stages over which reentrainment is assumed to
occur.
Since equations (44) and (66) are of the same form, the effect
of particle reentrainment without rapping can be expected to be
similar to the effect of gas sneakage, provided that a constant
fraction of the collected material is reentrained in each stage.
It is doubtful that such a condition exists, since the gas flow
pattern changes throughout the precipitator and different holding
forces and spark rates exist in different electrical sections.
However, until detailed studies are made to quantify the losses
in collection efficiency as a function of particle size for these
types of reentrainment, equation (66) provides a means of esti-
mating the effect of particle reentrainment without rapping on
precipitator performance.
Several things should be done in order to minimize the parti-
cle reentrainraent due to factors other than rapping. The gas
velocity distribution should meet IGCI criteria as a minimum and
should have an average value of-1.5 m/sec (5 ft/sec) or less.
Hoppers should be designed with proper baffling to prevent excessive
flow in the ash holding regions and should have no air inleakage.
Excessive sparking should be avoided.
Nonuniform Temperature And Oust.Concentration
Nonuniform temperature and dust concentrations may exist in
a precipitator and may result in adverse effects. A nonuniform
temperature may result in variations in the resistivity of the
collected dust layer, variations in the electrical properties of
the gas, and corrosion in low temperature regions. The first two
effects may lead to excessive sparking in certain regions of the
precipitator. A nonuniform dust concentration may result in ex-
cessive buildups of dust on corona wires, collection plates, beams,
497
-------
etc. and excessive sparking due to particulate space charge effects.
Excessive dust buildups and possible "doughnut" formations on
corona wires tend to suppress the corona and to cause uneven corona
emission. Excessive dust buildups on the collection electrodes
between raps may result in significant particle reentrainment,
undesirable electrical conditionsf and .reduced cross-section for
gas flow.
The effects of nonuniform -temperature and dust concentration
on precipitator performance have not been analyzed or studied
extensively. Therefore, at the present time, these effects can
not be quantified. Generally, it is assumed that if a good gas
flow distribution exists, then the temperature and dust distri-
butions will also be good. This may be a poor assumption for
many precipitator arrangements that are commonly employed.
498
-------
SECTION 7
EMISSIONS FROM ELECTROSTATIC PRECIPITATORS
PARTICULATE EMISSIONS
The data required for determining the mass efficiency of
control devices collecting fly ash are obtained by sampling the
flue gas upstream and downstream of the pollution control device.
Mass concentrations of particulate matter in flue gas are measured
.by drawing a sample of gas through a probe and filter and weighing
the collected material.
Methods For Determination Of Overall Mass Efficiency
Various organizations have proposed specific procedures and
sampling train designs for mass concentration measurements. The
Environmental Protection Agency's Method 5 specifies the use of
an extractive sampler.219 Sampling trains constructed to meet
Method 5 specifications were initially designed to operate at flow
rates up to one cubic foot per minute (28.3 liters/min). Recently,
a four cubic feet per minute (113 liters/min) extractive sampler
has been developed which is claimed to comply with the requirements
of Method 5. The proposed EPA Test Method 17 specifies the use of
in situ sampling.2*0 The American Society of Mechanical Engineers
(ASMElPerformance Test Code 27 specifies the use of either an
in situ or extractive sampler.221 The ASME will soon be releasing
a new Performance Test Code 38 which will supercede the Performance
Test Code 27. The Industrial Gas Cleaning Institute (IGCI Publi-
cation No. 101) and Western Precipitation Co. (Bulletin WP 50)
have also suggested sampling methods. The American Society of
Mechanical Engineers (ASME) Performance Test Code 27 specifies
the use of either an in situ or extractive sampler.
EPA Test Method 5—-
Official performance testing of stationary sources for parti-
culate emissions from coal-fired power plants must be conducted
with the EPA Test Method 5 "Determination of Particulate Emission
from Stationary Sources".219 Method 5 relies on the removal or
extraction of a dust-laden gaseous sample from the duct or stack
followed by removal of the particles by a filter while monitoring
sample volume. With this method one obtains a measure of the
average particulate mass concentration for the cross-sectional
499
-------
area of the duct during the time of sampling. There is some dif-
ference of opinion as to how the results should be interpreted,
especially in regard to condensation of vapors in the probe and
filter box which contains the condensers. Originally the Environ-
mental Protection Agency proposed that any material collected in
the condenser portion of the sampling train (shown in Figure 281)22Z
must be added to that of the dry collector (filter) portion. After
numerous objections from people in the field, the proposed method
was altered so that compliance now is based only upon material
collected in the filter and in the probe preceding the filter.
Hemeon and Black contend, however, that even this modification
is not valid since condensation and chemical reaction occurs in
the probe prior to the filtering of the sample.223':2" Therefore,
the S02 in the gas forms sulfates which later are collected on the
filter. However, one might argue that such reactions, if they
occur, would also occur in the atmosphere and should be included
as particulate matter. Some investigators conducting performance
tests of control devices on emission sources prefer to use a sampling
train that differs from Method 5 in that the filter for collecting
particulate matter is located in the stack instead of outside the
stack at the end of the sampling probe (ASME Performance Test Code
27) .
With EPA Method 5, one obtains a sample from the duct by
using a prescribed traversing procedure which involves isokinetic
extraction from different points within the duct. This procedure
yields, in effect, an approximate integration of collected mass
and sample volume over the cross-sectional area of the duct.
Before sampling, the number of traverse points must be determined
using EPA Test Method 1, "Sample and Velocity Traverse for Sta-
tionary Sources". The EPA sampling train consists of a thermally
controlled probe, with a variety of sampling nozzles and a pitot
tube assembly, which is connected to a sampling case containing a
heated filter assembly housing, filter, and a number of impingers -
located in an ice bath (Figure 281). The control console contains
the flow meters, pressure gauges, thermal control systems, timer,
and vacuum pump required for sampling.
DESCRIPTION 0? COMPONENTS
The nozzle removes the sample from the gas stream and should
disturb the gas flow as little as possible. This means a thin
wall and sharp edge. The major requirement of the probe, which
removes the sampled stream from the stack, is that it does not
significantly alter the sample from stack conditions. The sample
temperature should be maintained at 120°C + 14°C (248°F + 25°F)
or at such other temperature as specified by an applicable subpart
of the standards or approved by the Administrator of the EPA for
a particular application. Glass probe liners are desirable over
metal probe liners, but steel probes are allowed for probe lengths
over 2.5 meters. New regulations require a thermocouple to be
attached to the probe end for monitoring the stack gas temperature.
500
-------
PROBE
J
IMPINGER TRAIN OPTIONAL:
MAY BE REPLACED BY AN
EQUIVALENT CONDENSER.
HEATED
AREA FILTER HOLDER
THERMOMETER
CHECK
VALVE
MANOMETER DRY TEST METER AIR-TIGHT PUMP
3540-270
Figure 281. The EPA Method 5 particulate sampling train.222
501
-------
Pressure drop, generated by the gas velocity in the duct, is mon-
itored by an S-type pitot tube to insure isokinetic sampling ve-
locities. The glass fiber filter should be at least 99.95%
efficient in collecting 0.3 micron dioctylpthalate smoke particles.
An optional cyclone type of collector precedes the filter and
results, when used, in the removal of larger particles. The four
impingers in the train remove water, gases, vapor, and condensable
particulate matter. -4?he EPA and some states do not require the
measurement of the condensable particulate fraction and hence the
impingers are not specifically required/7 The impinger train may
be substituted by any type condenser such as a piece of coiled
tubing immersed in an ice bath.' The condenser should be followed
by a silica gel drying tube to collect the remaining moisture and
protect the vacuum pump and dry gas meter. The sampling box holds
the probe, the filter holder, and the impinger train and its ice
bath. The filter holder is contained in a heated area of the
sampling box and the temperature of this area should be maintained
at 120°C + 14°C. Where the condensable particulate fraction is
not required by state regulation or is of no interest, the sampling
box can be simplified.
The control box contains a vacuum pump capable of maintaining
isokinetic flow during heavy filter loadings, a control valve to
vary the sample stream flow rate, a vacuum gauge for measuring the
sample stream pressure, a dry gas meter equipped for determining
the sample volume, a calibrated orifice meter which is used to
monitor the sample stream flow rate, a pressure gauge to measure
the pitot tube pressure drop, a pressure gauge to measure the
orifice meter pressure drop, a variable voltage power supply to
maintain the probe and filter box at their respective temperature
by means of their individual heaters, and a pyrometer or potentio-
meter calibrated for thermocouple measurements of the duct and
filter box temperature.
Calibration requirements are discussed in the EPA maintenance
procedures.225 Critical laboratory calibrations include the orifice
meter, dry gas meter, and pitot tube. Calibration of the orifice
meter and dry gas meter requires the use of a wet gas meter. Various
other common laboratory instruments are required for the maintenance
and calibration of the other system components.
Many commercial models for conducting Method 5 tests are avail-
able and a list of some manufacturers is given in Table 35.226
ASTM - Test Method (Figure 232)227
Both the ASTM and the ASME provide specifications for in situ
samplers. The ASTM Method is similar to the EPA Test Method 5.
The main difference is the use of an instack filter with no re-
strictions on the sampling flow rate used. However, the filter^
should be preheated by being allowed to reach temperature equili-
brium in the process stream for at least thirty minutes prior to
502
-------
TABLE 35. SAMPLING SYSTEMS FOR TESTING
BY EPA METHOD 5226
Company
Aerotherm-Acur ex
Glass Innovations, Inc.
Joy Manufacturing Co.
Lear Siegler, Inc.
Environmental Technology
Division
Misco International
Chemicals, Inc.
Research Appliance Co.
Scientific Glass &
Instruments, Inc.
Lace Engineering Co..
Bendix Corporation
Environmental & Process
Instruments Division
Address and Telephone Number
485 Clyde Avenue
Mountain View, Calif-r.-.ia 94042
(415) 964-3200
Post Office Box B
Addison, New York 14801
Commerce Road
Montgomeryville, Pennsylvania 18936
(215) 368-6100
74 Inverness Drive East
Englewood, Colorado 80110
(303) 770-3300
1021 South Noel Avenue
Wheeling, Illinois 60090
(312) 537-9400
Pioneer and Hardies Road
Gibsonia, Pennsylvania 15044
(412) 443-5935
7246 Wynnewood
Houston, Texas 77001
8 8.2 9 North Lamar
Post Office Box 9757
Austin, Texas 78766
(512) 836-5606
1400 Taylor Avenue
Baltimore, Maryland 21204
(301) 825-5200
503
-------
GLASS FIBER THIMBLE FILTER
HOLDER AND PROBE (HEATED)
SAMPLING
NOZZLE
REVERSE-TYPE
PITOT TUBE
CHECK
VALVE
, .
""^UjJ
THERMOMETERS fc
DRY TEST METER
AIR TIGHT PUMP
3540-271
Figure 282, ASTM-type particulate sampling train.227
504
-------
sampling. When inserting the filter for preheating, the nozzle
must be pointed in the downstream direction of the gas flow to
prevent accumulation of fly ash in the nozzle. Also, when in-
serting the filter into a duct which is not under ambient pressure,
the sampling lines must be closed to prevent undesirable gas flow
through the filter.
ASME Performance Test Code 27
The ASME Performance Test Code provides for the use of a
variety of instruments and methods.2 Since testing experience
has not been uniform enough to permit standardized sampler design,
this code merely gives limiting requirements whi-n past experience
has shown gives the least sources of error. The Code is designed
as a source document which provides technically sound options to
be selected and agreed upon by the contractor and the contractee
performaning the sampling. According to ASME Performance Test
Code 27, the sampling device shall consist of a tube or nozzle
• for insertion into the gas stream and through which the sample is
drawn, and a filter (thimble, flat dish, or bag type) for removing
the particles. For the purpose of the Power Test Code, 99.0% col-
lecting efficiency by weight is satisfactory, and the filter may
be made of cotton, wool, filter paper, glass wool, nylon, or orlon.
The filter arrangement may be extractive or in situ.
The main advantage of in s_itu sampling -over extractive sampling
is that substantially all of the particulate matter is deposited
directly on the filter, which means that only a small area other
than the filter contains particulate matter and requires washing.
Also, since the filter is maintained at the stack gas temperature,
auxiliary heating of the filter is not needed. The main disadvan-
tage of the in situ sampler over the extractive sampler is the fact
that the in sTtu sampler is limited to proce-ss streams where temper-
atures do not exceed the limit of the filter medium and holder. In
fact, thermal expansion of the filter holder may create gas leakage
problems. Of course, the instack filter system cannot yield data
on condensable particulate matter in the plume.
Another difference between the filtration methods is the
sampling flow rate used in each method. Sampling trains constructed
to meet EPA Method 5 specifications were initially designed to
operate at flow rates up to 28.3 £/min (1 ft3/rnin); recently a
113 £./min (4 SCFM) sampler has been developed which complies with
EPA Method 5 specifications. ASTM and ASME Methods do not define
a flow rate range. Some high volume trains can operate at flow
rates up to 1.98 m3/min.(70 ft3/min).
The main advantage in the use of a high flow rate sampler lies
in the fact that the amount of time required to sample a given volume
of stack gas is small compared to the time required to sample with a
low flow rate sampler. In a process stream where the mass concentra-
tion is constant, the time required for sampling is markedly reduced.
505
-------
In a process stream where the mass concentration is highly variable,
a large number of high volume runs would be required to obtain a
value representation of the same average mass concentration obtain-
able from one run of the low volume run. Statistically, it is more
desirable to obtain several samples of a value than just one
sample. For stable streams, this will give additional information
revealing the precision with which the method has been applied.
When using high flow rate extractive samplers the high ratio of
sample gas flow rate to probe wall area minimizes errors due to
loss of particulate matter on the tubing walls between the nozzle
and the filter, minimizes heat losses, and thus helps to prevent
the condensation of vapors in the train. The high ratio also
can be a disadvantage when cooling of the sample gas stream is
required to protect the equipment since auxiliary cooling equip-
ment may be needed.
STATUS OF RULES AND REGULATIONS GOVERNING PARTICOLATE MATTER,
SULFUR OXIDE, NITROGEN OXIDE, AND OPACITY FOR COAL-FIRED POWER
BOILERS IN THE UNITED STATES
Background
228
The Clean Air Act of 1970 gave the Environmental Protection
Agency (EPA) the responsibility and authority to control air pollu-
tion in the United States and its territories. In 1971 EPA issued
National Ambient Air Quality Standards for six pollutants — sulfur
dioxide, nitrogen dioxide, particulate matter, carbon monoxide,
hydrocarbons, and photochemical oxidants. For each pollutant both
primary and secondary standards were issued. Primary standards
were set at levels necessary to protect the public health and were
to be met no later than three years from the date of promulgation
(subject to limited extensions of up to three years). Secondary
standards were designed to protect the public from adverse effects
to their welfare. Each state was required to adopt and submit to
the Environmental Protection Agency a plan for attaining, maintaining,
and enforcing the standards in all regions of the state. The State
Implementation Plans specified all details necessary to insure
attainment and maintenance of the standards. Most of the state
implementation plans were approved by the Environmental Protection
Agency in 1972.
In addition to the state implementation plans, new source
performance standards were issued by the Federal Government. New
sources include newly constructed facilities, new equipment which
is added to existing facilities, and existing equipment which is
modified in such a way that results in an increase of pollutant
emissions. New source standards limit specific pollutant emissions
from categories of sources (such as fossil fuel-fired steam gen-
erators) which are determined to contribute significantly to the
endangerment of public health and welfare.
506
-------
Current Status Of Emission Regulations
According to the Environmental Protection Agency, particu-
late and opacity standards for new coal-fired power boilers of
25 MW or more are 0.05 g/10s cal (0.03 Ib/rnillion Btu) and 20%
(on a six minute average), respectively.230'231 Also, final
sulfur standards just released by EPA indicate a "sliding"
standard that requires scrubbing of 70 to 90 percent of the
sulfur from the flue gas, depending upon the sulfur content
of the coal.232 For coal with a sulfur content that would cause
an emission, uncontrolled, of less than 3.6 g/10s cal (2 lb/
million Btu), only 70 percent of the sulfur dioxide need be
removed from the flue gas. For uncontrolled emission levels
from 2 lb up to 6 lb the desulfurization must be sufficient to
bring the controlled emission level down to 0.27 kg (0.6 lb).
For coal-sulfur levels from 2.72 kg (6 lb) to 5.45 kg (12 lb)
the control efficiency must be 90 percent. Above 5.45 kg (12
lb), the degree of desulfurization must be enough to bring the
.emission down to no more than 2.16 g/10s cal (1.2 Ib/million
Btu), which was the old limit. The nitrogen oxides standard
is 0.90 g/106 cal (0.50 Ib/million Btu) from subbituminous coal,
shale oil, or any solids, liquids, or gaseous fuel derived from
coal.
Table 48 in the Appendix C gives a compilation of emission
limits for particulate matter, sulfur oxide, and nitrogen oxide
limits for coal-fired power boilers for every state in the United
States. Table 48a gives emission limits for California. Cali-
fornia's counties each have separate rules and regulations. There-
fore emission limits were obtained from most of the counties in
an SoRI survey. Table 49 in Appendix C gives a compilation of
opacity limits as they apply to those power plants which come
under the "existing source" category of each state's opacity
regulations. New source limits for opacity were not compiled
since they generally follow the present Federal limit of 20%.
performance Evaluation
To evaluate the performance of new stationary sources, the
Environmental Protection Agency has specified reference methods
for the manner in which tests must be conducted at each plant.
The Code of Federal Regulations 40, Part 60-Standards of Perfor-
mance for New Stationary Sources, Appendix A - Reference Methods,
contain the reference methods to be us-ed to check performance
standards. Method 9 is the reference method for visual determin-
ation of the opacity of emissions from stationary sources. This
method is basically a visual determination by a qualified observer.
There are also performance specifications and test procedures for
transmissometer systems which are used to continuously monitor
opacity of stack emissions. These specifications are found in
Appendix B of the Code of Federal Regulations 40, Part 60. Where
disagreements occur between a qualified visual observer's determin-
ation (Method 9) and a transmissometer, Method 9 takes precedence
507
-------
in the opinion of the Environmental Protection Agency.230 Method
5 is the reference method for performance testing of stationary
sources for particulate emissions. Method 5 relies on the removal
or extraction of a dust-laden gaseous sample from the duct or
stack followed by removal of the particles on a filter while
measuring sample volume. Methods 6 and 7 in Appendix A describe
the reference methods for determination of sulfur dioxide and
nitrogen oxide emissions from stationary sources, respectively.
In Method 6 a gas sample is extracted from the sampling point in
the stack. The acid mist, including sulfur trioxide is separated
from the gaseous sulfur dioxide. The sulfur dioxide fraction is
then measured by the barium-thorin titration method. In Method 7
a grab sample is collected in an evaporated flask containing a
dilute sulfuric acid-hydrogen peroxide absorbing solution, and
the nitrogen oxides, except nitrous oxide, are measured colori-
metrically using the phenoldisulfonic acid procedure. Performance
specifications and specification test procedures for monitors of
S02 and NO are given in A-ppendix .B, Performance Specification 2.
JC
A helpful procedure .for planning and implementing tests for
control device evaluation can be found in a recent SoRI publi-
cation. 5lt
Discussion And Definition Of Opacity
Suspended particles in an aerosol will scatter and absorb
radiation from a beam passing through it; the remaining portion
is transmitted. The transmittance, T, of a fluid medium con-
taining suspended particles is defined as the ratio of the trans-
mitted radiation intensity to the incident radiation intensity.
T is given by the Bouguer, or the Beer-Lambert, law:
T = exp (-EL) (67)
where L is the path length of the beam through the aerosol medium
and E, the extinction coefficient of the medium, is a complicated
function of the size, shape, total projected area, refractive
index of the particles, and the wavelength of the raidiation. Some-
times the measured transmittance is expressed in terms of optical
density defined as
O.D. = Log (1/T) (68)
instead of the transmittance. Consequently, instruments and
methods for aerosol measurement based upon light transmission
principles have been referred to as transmissometers, smoke den-
sity meters, photo-extinction measurements, or turbidimetric mea-
surements.
While transmittance is defined as the ratio of light trans-
mitted through the aerosol to the incident light, opacity is
defined as the ratio of the light attenuated from the beam by
508
-------
the aerosol to the incident light (i.e., opacity = 1-T). Aerosols
which transmit all incident light are invisible, have a trans-
mittance of 100%, and an opacity of zero. Emissions which atten-
uate all incident light are totally opaque, having an opacity of
100% and a transmittance of zero.
Many versions of transmissometers, or smoke meters, are avail-
able as stack emission monitors. If the transmissometer is used
to measure instack opacity for purposes of compliance to federal
regulations, it must meet the EPA requirements for opacity measure-
ment systems as specified in the Federal Register of September 11,
1974. The use of visible light as a light source is required
because the response of the instrument is supposed to match
that of the human eye (photopic response). The angle of view
and the angle of projection is specified, for compliance, as no
greater than 5° (see Figure 283).233
To obtain true transmittance data the collimation angles
•(angles of view and projection) for the transmitter and receiver
must be limited to reduce the sensitivity to stray light scatter
(see Figure 283). A zero degree angle is the ideal collimating
angle, whereas a non-zero angle will introduce a systematically
low reading of opacity. However, a compromise is necessary,
since as a zero degree collimation is approached, instrument
construction costs, operating stability, and optical alignment
problems increase. A transmissometer having a 5° collimating
angle applied to the emissions of a pulverized coal-fired steam
generator gave an opacity measurement that was about 5% low rela-
tive to the 0° value.231*
The error in the transmissometer measurement due to the use
of different light detection angles has been analyzed theoreti-
cally by Ensor and Pilat and shown to be a function of detection
angle and particle size.235 They showed that, in general, the
error associated with a given detector viewing angle increases
with an increase in th,e particle mean diameter.
All transmissometers require purge air systems to protect
the optical windows or reflectors. Still, regular cleaning is
required with the accumulation rate varying widely from one loca-
tion to another. Most commercial instruments have automatic zero
and span checking capabilities to verify proper functioning and
calibration between cleanings.
Transmissometers can be used to measure the instack opacity
in order to obtain an estimate of the plume opacity for compliance
testing; or they can be used to measure the in situ opacity for
process control or as an estimate of mass concentration.
When the required measurement is the opacity of the emissions
at the exit of the stack, a measurement at any other location in
the stack has to have its optical path length adjusted to the exit
509
-------
PROJECTION ANGLE ANGLE OF VIEW
SOURCE
SAMPLE VOLUME
SCHEMATIC OF A TYPICAL TRANSMISSOMETER SYSTEM
3540-272
Figure 283. Schematic of a transmissometer showing projection
and \Tiew angles which must be no greater than 5°
for EPA compliance.233
51C
-------
diameter. The calculation for this adjustment can be found in the
Federal Register.236 Figure 284 gives the relationship of effluent
transmittance at the stack exit as a function of instack transmit-
tance for various ratios of stack exit diameter to transmissometer
optical path length.237
As opacity, 1-T, approaches zero the relative error in its
measurement with a transmissometer becomes unavoidably large.
For example, a two per cent error in the transmittance measurement
gives a 100 per cent error in an opacity of two per cent. In such
cases, important during diagnostic studies of control devices, a
nephelometer as used by Ensor,238 may be a more accurate measure of
opacity although it requires a probe and sampling traverses. This
instrument when used as an opacity monitor atter.p-s to determine
E, the extinction coefficient, through a measurement of the scat-
tering coefficient alone where E = scattering coefficient + ab-
sorption coefficient. This is performed using a predetermined
relationship between E and the instrument response for a calibra-
tion aerosol. The errors in this type of opacity measurement depend
'upon the variation of the ratio, aerosol absorption coefficient
to the scattering coefficient and the errors associated with extra-
active sampling. This ratio varies from zero for non-absorbing
particles to about one for highly absorbing aerosols giving possible
errors in opacity of ~ 100 per cent depending upon the calibration
aerosol. However, if the calibration aerosol is chosen judiciously
(i.e., with optical properties close to those of the sample aerosol)
and the opacity is low, the nephelometer errors are much smaller
than those obtained with the transmissometer at low opacities.
Relationship Between Opacity And Mass Concentration And Particle
Size
Theoretical Relationship—
Because of the interrelation between particle size distribu-
tion in a stack and the opacity, it is possible to meet mass emission
standards and still have an opacity problem. In fact, some changes
in flue gas streams causing a reduction in mass emissions have pro-
duced an increase in opacity. The relevance of this particular
aspect of opacity is described below.
The dependence of opacity upon the total mass concentration,
size distribtuion, and particle composition is given by
O a.l - I/I0 = 1 - exp (-W-L/p'K) (69)
where
0 = opacity,
I = intensity of transmitted light,
Io = intensity of incident light,
511
-------
100
« 60
c
o
u
LU
U
z
LU
10
20 30 40 50 60
IWSTACK TRANSMITTANCE, percent
80 90 100
3540-273
Figure 284.
Effluent transmittance vs. in stack transmittance
for varying ratios of stack exit diameter to in
stack path length: A = 1/4, B = 1/2, C = 3/4,
D = 1, E = 4/3, F = 2, G = 4.237
512
-------
W - total particulate mass concentration,
L = illumination path length or diameter of plume,
p = particle density, and
K = specific particulate volume/extinction coefficient ratio.
The parameter K, related to the volume/surface ratio of the
aerosol, is determined by the particle size distribution and re-
fractive index through calculations using the Lorentz-Mie theory
of light scattering for each size class. Illustrative calculations
of K assuming a log-normal size distribution ani ,'arious refractive
indices have been carried out by Ensor and Filar.239 The results
for two values of the refractive index are given in Figures 285
and 286. It can be seen that K and thus opacity is very sensitive
to MMD, geometric standard deviation, and refractive index. Since
opacity increases as K decreases the minimum occurring around 0.5
-to 0.1 ym in diameter is of particular interest. This light
scattering theory is based on a homogeneous sphere model for the
particl'-fa.
Sine'"; control devices generally reduce the MMD while removing
particle a reduction in the total emitted mass will not effectively
reduce the opacity if the inlet and outlet MMD's are to the right
of the radnima in Figure 285.
For example, if an aerosol originally had an MMD of 10 ym and
a geometric standard deviation of 2 (shown in Figure 286), and a
control device removed 80% of the mass from the aerosol while reducing
the MMD to 2 ym, then there would still be no change in opacity.
On the other hand, if the inlet MMD is close to the minimum then
a further reduction in total mass and/or MMD will be much more
effective at reducing opacity. Figures 285 and 286 with equation
(69) show that the change in opacity for a given change in total
mass requires knowledge of the aerosol size distribution and re-
fractive index. While the size distribution is of greatest
.importance in determining opacity, the differences in Figures
285 and 286 show that refractive index (determined by the com-
position of the particles) is also important.
Observed Relationship—
Several plants with- which SoRI -has had experience demonstrate
the importance of particle size distribution to opacity. A
power plant in Wyoming has a cold-side electrostatic precipitator
with an SCA of about 98.5 m2/(m3/sec)(500 ft2/1000 cfm). This
plant is near the particulate emission standard but does not meet
the opacity standard. Three other western plants which have hot
precipitators with SCA's in the 59.1-69 m2/(ms/sec)(300-350 ft2/
1000 cfm) range have the same problem. This can be attributed
in large part to the generally fine particle size distribution of
513
-------
102
CM
E
P5~
U
£ 10°
10-
10-2
GEOMETRIC
STANDARD
DEVIATION, ag T
REFRACTIVE INDEX = 1.50
WAVE LENGTH OF LIGHT = 550 nm |
10'2
10'"1 10° 101
GEOMETRIC MASS MEAN RADIUS, rgw. microns
I I I I I III! I I I I Mill I I I I I Illl I I I I II II
102
3540-274
Figure 285.
Parameter K as a function of the log-normal size
distribution parameters for a white aerosol after
Ensor and Pilat.2 39
514
-------
102
f. "<
'V
10'
u
ii
CC
UJ
5
e
a.
10°
10'1
10-
I I I i !l!l| I I I I I Illl I I I I I I III I I II I
GEOMETRIC
STANDARD
DEVIATION, og
REFRACTIVE INDEX - 1.96 - 0.66i
WAVE LENGTH OF LIGHT = 550 nm
31 i i i i i nil i i i i 11 in i i i i ] i nl i i i i 1111
10° io1
GEOMETRIC MASS MEAN RADIUS, rgw, microns
102
3540-275
Figure 286. Parameter K as a function of the log-normal size
distribution parameters for a black aerosol after
Ensor and Pilat.239
515
-------
ash obtained from burning western coal. (See discussion of Figure
285.) Another interesting case in point is a northern utility
which was burning an eastern coal at one of its plants equipped
with a normal cold-side electrostatic precipitator. This plant
was meeting the opacity standard but not the emission standard.
After switching to a western coal, the plant was able to meet the
mass emission standard but could no longer meet the opacity require-
ment.
Even more dramatic is the situation at Southwest Public Service,
Harrington Station. This plant burns low sulfur coal and uses an
electrostatic precipitator/scrubber system to meet the oarticulate
standard. Measured emissions are 19.4 ng/J (0.45 lb/10 Btu) and
the opacity is around 38%. Sparks2399 has analyzed this case
and concluded that the high opacity was primarily due to the fine
aerosol produced by the precipitator/scrubber system.
For a transmissometer to be useful as a monitor of the mass
concentration, the properties of the particles (other than mass)
being monitored must remain fairly constant over the monitoring
period. Experimental data are available showing that good opacity-
mass concentration calibration can be obtained on some sources.
The sources that have been evaluated include coal-fired power
plants;2"0'2"1'2"2 lignite-fired power plants;2143 a cement plant;2"*
a Kraft pulp mill recovery furnace;21*5 petroleum refinery; asphaltic
concrete plant; and a sewage sludge incinerator. 2 "*fc
Nader reported tests that were performed over one 3-month
interval and two 2-month intervals representing different seasons
of power plant operation.2"7 Emissions were increased at various
times by cutting off one or more electrostatic precipitator stages.
Correlation curves were essentially the same for the three dif-
ferent time periods with coefficients of 0.93, 0.98, and 0.99.
The coefficient for the composite correlation curve for the data
for all three time intervals is 0.97 (see Figure 287). Mass con-
centration ranged from 55 to 360 mg/m3. No problem with window
contamination occurred with continuous operation of the trans-
missometer spanning the one year period.
For an emission source with high efficiency particulate control
equipment, the size distribution of the emitted particulate matter
may be relatively constant. Therefore, emission sources with vari-
able emission and low efficiency particulate control equipment (i.e.
cyclone and low energy scrubbers) can be expected to provide
poorer correlation of instack plume opacity to particle mass con-
centration. Transmissometers may be useful indicators of mass
emissions, once calibrated, on sources where the aerosol proper-
ties remain constant.
516
-------
30(
25
* 20
i"
a.
10
5
0.0
0.1 0.2 0-3 0.4
MASS CONCENTRATION, gm/m2
0.12
0.10
0.08
0.06
LU
o
LU
O
O
0.04 <
Z
LU
0.02 t
0.0
3540-276
Figure 287. Correlation data between opacity and mass measure-
ments of particulate matter in emissions for a
coal-faurning power plant. After Nader.21*7
517
-------
Example Of Modeling Of Opacity Versus Mass At The Exit Of An
Electrostatic Precipirator
The SoRI-EPA mathematical model of electrostatic precipitation
has been used with certain modifications to simulate the operation
of a power plant precipitator collecting fly ash from the burning
of coal under test conditions. Based on the simulation of test
conditions, the model has been employed to estimate the performance
of the precipitator as a function of current density, specific
collection area, inlet particle size distribution, arid inlet mass
loading. Performance of the precipitator has been determined in
terms of both overall mass collection efficiency and opacity.
The set of parameters used in the simulation of the test con-
ditions yielded an overall mass efficiency of 88.75%, opacities
in the range from 39 to 49%, and an outlet size distribution with
a mass median diameter (HMD) of 2.35 urn and a geometric standard
deviation (o ) of 2,91. The above values compare favorably with
the measured values. The simulation of the test conditions was
based on an inlet size distribution with an MMD of 4.0 vim and OD
of 2.45, a normalized standard deviation of the gas; velocity dis-
tribution of 0.25, 5% gas sneakage per stage, a rapping loss' size
distribution with an MMD of 4.5 ym and a ap of 2.8, and 35% of the
mass collected in the last field being reentrained in the outlet
emissions. The rapping emissions constituted approximately 40%
of the total outlet emissions for the simulation. Although the
parameters characteristic of the rapping losses will vary with
current density, specific collection area, and inl€>t mass loading
and particle size distribution, they were held fixed in making
projections since these dependences can not be quantified at the
present time.
The results of this particular application of the precipitator
model for design purposes in control of opacity are: encouraging.
It appears that inlet and outlet size distribution and opacity
measurements along with precipitator operating parameters will
provide enough information to predict the necessary modification
to the precipitator to achieve a given level of opacity.
Measurement Of Relative Stack Emission Levels And Opacity
A number of optical techniques are used to determine relative
stack emission levels. Usually these techniques involve a deter-
mination of the degree of light transmittance or light scattering.
Some of the representative instrumentation used is discussed below:*
*Southern Research Institute and the Environmental Protection
Agency bear no responsibility for the promotional claims of these
companies.
518
-------
Nephelometers, devices that attempt to measure all of the
scattered light, have recently been applied to stack monitoring.
One such instrument, call the Plant Process Visiometer (PPV), has
been developed by Meteorology Research, Inc., 464 West Woodbury Road,
Altadena, California 91001, telephone (213) 791-1901.2I*3'2 *9' 2*°
A diagram of the optical assembly is shown in Figure 288. The
sample, extracted through a probe with no dilution, is passed
through the detector view. The light source is diffused so that
light rays illuminate different portions of the sample in a wide
range of angles from near 0° to near 180° with respect to the
detector view. During operation the detector signal is calibrated
with an opal glass calibrator which has been adjusted to give a
certain scattering coefficient which corresponds to an opacity of
5.4 percent assuming no light absorption. This device gives an
acceptable measure of mass concentration if calibration is per-
formed against a direct mass technique and if the size distribution
and composition of the aerosol remain nearly constant.
An in situ monitor has been developed that is based on the
measurement of backscattered light.251 This instrument, called
PILLS V, was developed by Environmental Systems Corporation, Post
Office Box 2525, Knoxville, Tennessee, 37901, telephone (615) 637-
4741, and uses a laser as the light source. As shown in Figure
289, both the light source and detector are located within the
same enclosure.252 One of the features of the PILLS V is its
ability to determine mass concentration. The instrument optically
defines a sample of 12 cm3 (0.73 in3) at 10 cm from the end of the
probe within the process stream. Detection of the scattered light
at angles greater than 160° relative to the beam produces an elec-
trical signal that is proportional to the mass contained within
the sample volume. Since the sample volume is a constant, the
mass concentration is read directly from an appropriately labeled
scale on the instrument meter. The instrument does not possess
the capability to traverse large stacks in order to obtain multi-
point measurements. Since the particulate mass concentration is
frequently not uniform across the entire cross-sectional area of
the stack, the use of such a small sampling volume and the in-
ability to traverse creates a problem whan trying to obtain data
that is representative of the actual total mass concentration
present within the stack.
An improved version of PILLS V, the model P-5A, has been
developed. This instrument has the following specifications: a
measurement range of 0.001 to 10 grams/ACM, response that is
proportional to particle mass concentration and is relatively
independent of the particle size in the range of approximately
0.1 to 8 urn, a process gas pressure limit of +5 inches of water
from ambient (higher limits are optional); a process gas tempera-
ture limit of 260°C (500°F) (negative pressure streams permit use
at higher temperatures), an instrument response that is independent
of gas velocity, an optional automatic zero and span calibration
at preset intervals without removal from the stack, and a light
519
-------
LIGHT
SOURCE
APERTURES
DETECTOR
LIGHT TRAP
OPAL GLASS
CALIBRATOR
3540-277
Figure 288.
Optical assembly diagram of a nephelometer used in
stack monitoring. The scattering angle 6, for
any light ray from the source, is the angle
between the ray and the horizontal line a. From
Ensor and Sevan.21*8
520
-------
BACKSCATTERED
BEAM
SAMPLING
VOLUME
EMITTED
BEAM
LIGHT COLLECTION
LENS
LIGHT OMITTING
DIODE
SIGNAL
DETECTOR
3540-278
Figure 289. Optical diagram of the PILLS V instrument. From
Schmitt, et ai.252
521
-------
source consisting of a highly collimated beam of monochromatic
laser light whose wavelength is 0.9 ym.
A backscattering instrument, called an LTV monitor, has been
used in making mass measurements, but a commercial model is not
available.253 This device, illustrated in Figure 290, utilizes
a high intensity argon or xenon laser and a television camera with
telephoto lens. The camera optics image the backscattered light
of 175° from the focused view volume, intersecting the laser beam.
Particles that produce illumination above the sensitivity threshold
can be resolved as distinct flashes and the intensity of each can
be measured.
A portable opacity measurement system called RM41P has been
developed by Lear Siegler, Inc., Environmental Technology Division,
74 Inverness Drive, E., Englewood, Colorado 80110, telephone (303)
770-3300. This sytem includes a transmisspmeter to measure light
transmittance through an optical medium such as fly ash. The trans-
ceiver unit contains the light source, the detector, and electronic
circuitry. The retroreflector is housed in the end of a slotted
probe which is attached to the transceiver and is inserted into a
stack or duct through a conventional stack sampling port. The
probe causes negligible flow disturbance, and air flushing keeps
the optical window and retroreflector free of dust and dirt de-
posits. The transceiver output is transmitted to a portable
control unit that simultaneously provides an indication of optical
density and opacity corrected to stack-exit conditions. There is
a switch activated, self-contained, calibration checking of trans-
ceiver zero, instrument (with probe) zero, and instrument span.
Automatic, electronic compensation of instrument zero output is
provided whenever zero calibration is activated. The standard
stainless steel probes will withstand stack temperatures up to
1200°F, though to minimize thermal conduction into the transceiver,
care must be exercised to limit exposures at extreme temperatures.
Some of the other features of the system are as follows: optical
density output for correlation with particulate grain loading,
opacity output corrected to stack-exit conditions to comply with
emission standards, choice of ten measurement ranges and outputs,
chopped light source for total insensitivity to ambient light,
dual-beam measurement technique for maximum accuracy, double-pass
measurement system for high sensitivity and easy calibration, probe
inserts into stack or duct through a conventional 3% inch I.D.
sampling port, continuously variable adjustment on control panel
to correct opacity outputs to stack-exit conditions for any stack
or duct, choice of interchangeable one meter or five foot probe
lengths, provision for permanent installation when so desired,
and manually activated, self-contained transceiver zero, probe
zero, and instrument span calibrations.
Another Lear Siegler, Inc. product is the RM41 Visible
Emission Monitoring System which is being used successvully to
measure opacity and amount of particulate matter in effluent from
522
-------
PULSED ARGON OR
XENON LASER
_ TV CAMERA WITH
I TELEPHOTO LENS
h
PARTICLE SIZE
ANALYZER
3540-279
Figure 290. Schematic of Laser-TV monitor. After Tipton.253
523
-------
large industrial stacks. The instrument performs automatic cali-
bration and zero correction, and offers a wide choice of built-in
measurement ranges and status indicators on the remote control
unit to maximize system performance and operator effectiveness.
Unattended operation can be expected for three to six months. The
system contains a transmissometer consisting of an optical trans-
ceiver mounted on one side of a stack and a reflector mounted on
the other, a forced-air purge system, and a control room unit.
Containing only the essential optics and electronics required to
implement the dual-beam measurement technique, the transceiver
incorporates automatic continuous correction for variations in
ambient temperature, line voltage, lamp aging, detector drift, and
associated changes in component characteristic. Output from the
transceiver is interconnected to a remote control unit, which
provides simultaneous readings of opacity, corrected to stack exit
conditions, and optical density, indicating actual two-pass con-
ditions. There is an optical density output for correlation with
particulate grain loading and determination of mass emission flow
rates. In typical applications the standard system can be used
with stack temperatures up to 316°C (600°F).
The RM7A Opacity Monitor by Lear Siegler, Inc. is a trans-
missometer consisting of a transceiver mounted on one side of a
stack anJ a reflector mounted on the other side. The transceiver
unit .contains a light source, dual photocell detectors, and
electronic measuring circuitry. A special corner-cube retro-
reflector is housed in the reflector unit. Both units contain
provisions for optical alignment verification and correction.
Zero and alarm-level adjustments are built into the transceiver.
A manual zero-calibration reflector assembly and storage container
are attached to the transceiver. This system is used on small or
medium sized industrial facilities.
The Model 1100 Double Pass Opacity Monitoring System is
manufactured by Dynatron, Inc., Barnes Industrial Park, Wallingford,
Connecticut 06492, telephone (203) 265-7121. The system works by ,
measuring variations in "double pass" light transmittance. The
light source and two photo detectors are mounted on one side of
the stack and a retroreflector is mounted on the other side. The
light source projects a collimated beam of light which is split
by a beam splitter into a reference beam and a transmitted beam.
The reference beam is directed to the reference detector. The
transmitted beam is projected to a "double pass" across the stack
to a retroreflector which reflects it back across the stack to
the measurement detector. The measurement detector working on
a ratio basis with the reference detector generates; an output
signal directly related to smoke opacity. Some of the features
of the system are: 100% solid state design, a restriction of
ambient light interference, flexible air line which supplies
clean filtered air, and alignment viewing port to allow a visual
check by the operator.
524
-------
The Model 301 Opacity Monitor by Dynatron is a rugged eco-
nomical monitoring system utilizing a single pass transmissometer
which enables the operator to meet opacity monitoring regulations
and optimize combustion efficiency. Each system includes the
following design features as standard: an analog panel meter
which indicates single pass opacity at the transmissometer in 2%
increments from 0 to 100% opacity, an optional digital panel
meter is available with an easy to read numeric display, and a
fuel saving early warning system which alerts the operator prior
to a violation.
The following list gives a number of other suppliers of
smoke measuring instruments and supplies:
Bailey Meter Company
Beltram Associates, Inc.
W. N. Best Combustion Equipment Company
Catalytic Products International, Inc.
Cleveland Controls, Inc.
De-Tec-Tronic Corporation
- E. I. duPont deNemours & Company, Inc.
Dwyer Instruments, Inc.
Electronics Corporation of America
Environmental Data Corporation
GCA Technology Division
Horiba Instruments, Inc.
Institute for Research, Inc.
International Biophysics Corporation
ITT Barton
Jacoby-Tarbox Corporation
Leeds & Northrup Company
Milton Roy Company
NAPP, Inc.
Photobell Company, Inc.
Photomation, Inc.
Preferred Instruments
Process & Instruments Corporation
Reliance Instrument Manufacturing Corporation
Research Appliance Company
Royco Instruments, Inc.
Von Brand Filtering Recorders
Robert H. Wager Co., Inc.
Westinghouse Electric Corporation, Computer & Instrumentation Div.
525
-------
SECTION 8
CHOOSING AN ELECTROSTATIC PRECIPITATOR: COLD-SIDE
VERSUS HOT-SIDE VERSUS CONDITIONING AGENTS
ADVANTAGES AND DISADVANTAGES OF THE DIFFERENT PRECIPITATOR OPTIONS
General Discussion
There are presently three accepted methods of utilizing elec-
trostatic precipitators for the collection of fly ash. These
methods include cold-side operation (120-180°C), hot-side opera-
tion (315-480°C), and chemical flue gas conditioning (CFGC).
Whether or not one of these methods is preferable to the others
depends primarily on the type of ash to be collected, the space
available for control equipment, and economic considerations.
Depending on the circumstances, each of these methods may have
certain advantages and disadvantages. In this section, the ad-
vantages and disadvantages of the three precipitator options are
discussed. Also, the precipitator requirements and economics
which would be necessary to achieve a given high level of collec-
tion efficiency for high resistivity ashes are estimated for the
three options.
Cold-Side Electrostatic Precipitator
Cold-side electrostatic precipitators provide the most economi-
cal and reliable option for providing high collection efficiency
of fly ash with low-to-moderate resistivity (0.1 - 5 x 1010 ohm-cm),
The low pressure drop across the precipitator, relatively low gas
volume to treat on the cold-side of the air preheater, and good
electrical operating conditions provide significant advantages.
Figure 101 shows measured fractional efficiency data obtained from
a cold-side precipitator collecting fly ash with a measured resis-
tivity of approximately 2.2 x 1010 ohm-cm.25it This unit operated
with an average applied voltage of 51.0 kV and average current
density of 38.0 nA/cm2. A relatively high overall mass collection
efficiency of 99.6+% was measured with a relatively low specific
collection area of 43.5 m2/(m3/sec)(221 ft2/1000 ACFM). This pre-
cipitator was preceded by a mechanical collector and was treating
particulate with an inlet mass median diameter of approximately
10 ym.
The use of a cold-side precipitator becomes questionable when
the resistivity of the fly ash is high (greater than 1011 ohm-cm).
526
-------
Due to the poor electrical conditions that will be experienced
with a high resistivity fly ash, a cold-side precipitator has
to be very large in size in order to achieve high collection
efficiencies. Although there may be economic and practical draw-
backs, large cold-side precipitators have been utilized success-
fully to collect high resistivity fly ash. Figure 89 shows
measured fractional efficiency data obtained from a cold-side
precipitator collecting fly ash with a measured resistivity of
1.8 x 1011 ohm-cm.255 This unit operated with an average applied
voltage of 40.9 kV and average current density of 12.1 nA/cm .
A very high overall mass collection efficiency of 99.9+% was
measured with a relatively high specific collection area of
99.2 m2/(iti3/sec} (504 ftVlOOO ACFM) .
For sufficiently high values of fly ash resistivity, the
size of a cold-side precipitator that can attain high collection
efficiencies becomes excessively large. The large precipitator
size needed for high efficiency collection of high resistivity
ash results in large precipitator costs, increased space require-
ments, and possible impracticality of enlarging an existing pre-
cipitator which was originally designed to collect a low resistivity
fly ash. Also, for very high values of resistivity (greater than
10 3 ohm-cm), accurate cold-side precipitator design is probably
not possible due to uncertainties regarding the attainable electri-
cal operating conditions and useful operating voltage and current.
In addition to excessive precipitator size, there are other
possible disadvantages of cold-side collection of high resistivity
ash that must be considered. Due to the tendency of high resis-
tivity ash to adhere tenaciously to the collection electrodes,
high intensity impact rappers are required (120-200 g) to remove
the ash from the collection electrodes. To withstand these higher
rapping forces, more costly rigid electrode frames are desirable.
The high rapping forces increase the possibility of ash reentrain-
ment, structural collection electrode failures, and more difficult
equipment maintenance.
Hot-Side Electrostatic Precipitator
The motivation for locating the precipitator on the hot gas
side of the air preheater where temperatures are in the neighbor-
hood of 371°C (700°F) rests entirely on data which show that ash
resistivities should be very favorable. As discussed earlier, the
controlling conduction mechanism in the precipitated ash layer at
this temperature is intrinsic or volume conduction, instead of the
surface conduction mechanism which predominates on the cold gas
side of the air preheater. Thus, the fly ash resistivity at high
temperature is not sensitive to the SOs or moisture content of
the- flue gas. Most published resistivity data indicate that re-
sistivities below 2 x 1010 ohm-cm will occur above 600°F. There-
fore, high temperature operation should offer an alternative approach
for achieving high collection efficiency of fly ash which would have
a high resistivity under cold temperature operation.
527
-------
Another advantage of high temperature operation is that
fouling of the air preheater by fly ash is reduced. However, in
installations burning high sulfur coal with a basic fly ash, it
is probable that removal of this ash ahead of the air preheater
would result in increased corrosion rates of air preheater cold
end elements. For installations in which coal and oil firing
are employed, high temperature operation minimizes oil ash handling
problems.
The decrease in precipitator size that can be achieved by
hot-side collection of a fly ash which would have a high resis-
tivity at cold-side temperatures is moderated by two factors.
First, a higher gas volume must be treated due to the higher tem-
perature. The increase in gas volume dictates that the precipi-
tator be increased in size by approximately 50% in comparison to
a cold-side precipitator operating at the same applied voltage and
current in order to achieve the same collection efficiency. Second,
the decreased gas density results in lower operating voltages and
electric fields prior to sparkover than in the case of a cold-side
precipitator. Thus, additional precipitator size is needed to
compensate for the reduced operating voltages.
Certain economic disadvantages are associated with a hot-side
precipitator. Special expansion provisions, increased insulation,
increased draft fan requirements, and additional ductwork in an
unconventional configuration add increased costs as compared to a
cold-side precipitator. In addition, the hot-side operation re-
duces boiler efficiency due to heat loss through the precipitator.
Recently, it has been found that hot-side precipitators may
be sensitive to the composition of the ash.256 This sensitivity
is manifested in voltage-current characteristics which are abnormal
and unfavorable for electrostatic precipitation. Figures 203 and
204 show abnormal voltage-current characteristics obtained from a
hot-side precipitator which responded unfavorably to fly ash de-
posits on the collection electrodes. These curves should be com-
pared to those in Figures 200, 203, and 204 for normal hot-side
precipitator operation. The steep voltage-current curves and low
maximum applied voltages shown in Figures 203 and 204 are not
expected at the elevated temperatures and result in decreased
precipitator performance. In addition, the abnormal electrical
conditions could not be attributed to ash resistivity since both
in situ and laboratory measurements indicate a value of less than
ICf1 ° ohm-cm. However, these measurements were made over a
relatively short period of time, and there is reason to believe
that the resistivity of the collected dust layer may increase
with time. Due to the above discussion, the most serious dis-
advantage of a hot-side precipitator is the unpredictability of
the electrical conditions. Although adequate electrical conditions
may be obtained with certain fly ashes, inadequate electrical
conditions may result due to other fly ashes. This makes the
design of a hot-side precipitator extremely difficult and makes
hot-side operation less attractive as an option.
528
-------
Figure 104 shows measured fractional efficiency data obtained
from a hot-side precipitator collecting fly ash from a low sulfur
eastern coal.257 This unit had normal hot-side voltage-current
characteristics and operated with an average applied voltage of
31.7 kV and average current density of 35.6 nA/cm2. A relatively
high overall mass collection efficiency of 99.6+% was measured
with a moderate specific collection area of 76.8 m2/(m3/sec)
(390 ftVlOOO ACFM) .
Figure 110 shows measured fractional efficiency data obtained
from a hot-side precipitator collecting fly ash from a low sulfur
western coal.258 This unit had anomalous hot-side voltage-current
characteristics and operated with an average applied voltage of
25.1 kV and average current density of 32.2 nA/cir.- . An overall
mass collection efficiency of 98.5% was measured for the entire
unit with a specific collection area of 57.1 m2/(m3/sec)(290 ft2/
1000 ACFM). The poor performance of this unit could be attributed
primarily to the low operating voltages, especially in the outlet
electrical fields.
Cold-Side Electrostatic Precipitator With Chemical Flue Gas
Conditioning
Possible Advantages of Chemical Flue Gas Conditioning—
There are several attractive features and possible benefits
of adding chemical conditioning agents to the gas stream on the
cold or hot gas side of the air preheater and upstream from a
cold-side precipitator. First, certain chemical conditioning
agents can be used to lower the resistivity of unconditioned ash
from high values to values which are favorable for electrostatic
precipitation. One manufacturer of conditioning systems will
guarantee that the resistivity of S03 conditioned fly ash will
not exceed 4 x 1010 ohm-cm.25* Second, certain chemical condition-
ing agents can be used to increase the cohesiveness of the pre-
cipitated fly ash.156'260 This capability can be utilized to
reduce emissions due to particle reentrainment caused by rapping,
high gas velocities, or hopper boil-up. Conditioning can cause
particulate< reentrained due to -rapping to consist of large agglo-
merates which can be easily recollected. Third, certain chemical
conditioning agents can be used to introduce a beneficial space
charge effect in the precipitator.16k With a beneficial space
charge effect, higher applied voltages can be obtained at a given
current density than in the unconditioned gas. The increase in
applied voltage can be large enough to make a significant improve-
ment in precipitator performance. The three effects just described
have been substantiated and discussed earlier in this text. Fourth,
certain chemical conditioning agents can be used to increase the
resistivity of unconditioned ash from extremely low values (less
than 10* ohm-cm) to values (approximately 1010 ohm-cm) which are
more favorable for electrostatic precipitation.156'260 The in-
crease in resistivity reduces particle reentrainment due to
529
-------
scouring and rapping by increasing the electrical forces holding
the ash layer to the collection electrode. In addition, if the
low value of resistivity is due to an excess of SO3 caused by
burning high sulfur coal, the conditioning agent added in a hot
section of the boiler may remove excess SOs by neutralizing
reactions on the surfaces of the particles.2 This is signi-
ficant because high exit gas temperatures are maintained in
order to prevent condensation of excess SOa from the flue gas
which could result in corrosion and air preheater pluggage.- This
method of operation not only reduces boiler efficiency, but also
increases the gas volume and velocity through the precipitator,
thus reducing the precipitator performance. Fifth, there have
been claims that certain chemical conditioning agents can favor-
ably modify the fly ash particle size distribution by causing
agglomeration of particles.261 However, this effect has not
been substantiated. If significant agglomeration of fine
particles can be produced, a larger particle size distribution
which can more easily be collected would be produced. Due to
the wide applicability of chemical conditioning agents, one manu-
facturer of conditioning systems is now offering a performance
guarantee that its system will reduce emissions in excess of
compliance levels by a minimum of 60%, regardless of type of coal,
boiler, or precipitator.262 In order to take advantage of the
multiplicity of mechanisms of fly ash conditioning, the technique
of dual injection can be utilized.260 This technique involves
the application of one additive into a hot section of the boiler,
followed by injection of the same or a different additive into
a relatively low temperature zone, usually after the air heater.
In addition to offering improved precipitator performance,
chemical flue gas conditioning has several favorable economic
aspects. First, the capital costs of a new precipitator installa-
tion can be greatly reduced by using a conditioning system in
conjunction with a relatively small cold-side precipitator.
Second, less space is required when conditioning is; used. Third,
the retrofitting of existing precipitators can be accomplished
relatively quickly and with little or no loss in power generating
capacity.
Properties and Utilization of Well-Known Conditioning Agents—
Compounds which have been examined for use as conditioning
agents in cold-side precipitators include sulfur trioxide, ammonia,
sulfonic acid, sufamic acid, ammonium sulfate, ammonium bisulfate,
sodium carbonate, triethylamine, and several proprietary
agents. J 56' 16lT'2 6 3/26it Table 36 gives the names, chemical for-
mulas, and physical properties of some of the conditioning agents
which have been studied.263 Some are vapors or liquids that can
be volatilized without much difficulty. Others are solids that
may or may not be liquified or volatilized without decomposition.
All of the compounds'listed are highly soluble in water._ For those
that are not readily volatilized, aqueous solutions provide a
convenient method for injection into a flue-gas stream.
530
-------
TABLE 36. PHYSICAL PROPERTIES OF CONDITIONING AGENTS
en
Agent
Sulfur Trioxide
SuIfuric Acid
Ammonia
Ammonium Sulfate
Triethylaroine
Formula
S03
H2SOi,
NH3
(Nil,,) 2
(C2Hs)
TrieLhylammonium Sulfate [(C2H5)3NH]2 S0<, Solid
Sulfamic Acid HO3S-NH2
Sodium Carbonate Na2CO3
State at
21ircT70DF)
Liquid
Liquid
Gas
Solid
Liquid
Solid
Solid
Solid
°C
17
10.6
-78
Dec
-114
-
205
851
Mp,
°F
(62)
(51)
(-108)
b
(-174)
-
(401)
(1564)
Bp,
"C "F
45 (113)
326 (619)
-33 (-28)
-
89 (193)
-
Dec.b
Dec.b
a. All compounds are highly soluble in water and some are used in aqueous solution.
b. Dec. signifies thermal decomposition.
-------
The best known conditioning agent is sulfur trioxide or the
chemically equivalent compound sulfuric acid. One of the signi-
ficant properties of sulfuric acid in flue gas is its tendency
to undergo condensation from the vapor to the liquid state,
the latter consisting of a mixture of sulfuric acid and water.
The dewpoint curve given by Verhoff and Banchero265 for sulfuric
acid in flue gas containing 10% of water vapor is shown in Figure
291. If the gas stream is at a given temperature, it can contain
no more vapor than is indicated by the appropriate point on this
curve. At 138°C (280°F), for example, the maximum vapor concen-
tration that can exist is 10 ppm.
Once condensed, sulfuric acid conducts electricity readily.
Thus, if it condenses on fly-ash nuclei, it provides a conductive
surface film. If absorbed on fly ash particles under conditions
that do not allow condensation, it may again provide a conductive
surface film. Actually, little is known about the chemistry and
physics of adsorbed sulfuric acid, but there is evidence that
part of the adsorbed material may react chemically with ash con-
stituents to form non-conductive sulfate salts (such as calcium
sulfate) but that part retains its integrity as a conductive
acid.164
All available data indicate that SOs conditioning will signi-
ficantly lower the resistivity of an unconditioned, high re-
sistivity ash. In this case, SOs conditioning will result in
improved electrical operating conditions and increased collection
efficiency. The effects which can be expected from adding the
other compounds mentioned are not so well defined. The realized
effects, if any, appear to depend strongly on the gaseous envir-
onment and the chemical composition of the ash. In a certain
application, one of these compounds may improve precipitator
performance by one or more of the mechanisms discussed earlier
whereas, in another application, it may have a different or no
effect. A data base which is much larger than that existing is
needed in order to establish the effects on precipitator operation
resulting from adding the various possible conditioning agents to
flue gases of differing gaseous composition and containing par-
ticles of differing chemical composition.
Unlike sulfur trioxide and sulfuric acid, ammonia is not
recognized as an important naturally occurring constituent of flue
gas. The distinguishing feature of ammonia vapor in flue gas is
its behavior as a base. At temperatures that are not too high — say
around 149°C (300°F) — it is capable of combining with sulfuric acid
vapor to form ammonium sulfate, as shown by the following reaction:
2NH3(g) + H2S(Mg) •*• (NJU ) 2SO«, (s)
There are other acidic gases in flue gas — sulfur dioxide and
carbon dioxide — but, even though they are present at much higher
concentrations than sulfuric acid, they are unable to react with
ammonia .
532
-------
100.0
220
240
TEMPERATURE, °F
260 280
300
320
O
10.0
01
2
o
o
o
VI
M
I
1.0
T
VAPOR + LIQUID
VAPOR
0.11
I
110 120 130 140
TEMPERATURE, °C
150
160
3540-280
Figure 291.
Dewpoint curve for sulfuric acid in the presence
of 10% water vapor.
533
-------
The addition "of triethylamine to flue gas can be expected to
lead to similar reactions, for this compound is also a base. It
is stronger as a base than ammonia, however, and thus it may com-
bine with sulfuric acid at higher temperatures or it may even
react with some of the other acidic gases in flue gas.
Comparatively little is known about the chemical behavior of
addition compounds of sulfur trioxide and ammonia that are used as
conditioning agents. Such compounds as sulfamic acid and ammonium
sulfate are frequently added at temperatures around 1100 or 1200°F.
It is claimed by vendors who sell proprietary blends of these
agents that injection at high temperatures is needed to decompose
the agents to other products that are engaged in the actual con-
ditioning process. Knowledge of what decomposition processes
occur at high temperatures or what reactions of the decomposition
products occur as the gas temperature is lowered is not complete.
However, the following equations give a fairly realistic estimate
of reactions that may be expected at high injection temperatures:261*
H03S-NH2(s) -v S03(g) + NH3(g)
(NHi.) 2SOu(s) •*• S03(g) + H20(g) + 2NH3(g)
Reversal of these reactions may then occur as the temperature is
lowered.
Sodium compounds may be injected into the boiler along with
coal.266 In such an event, decomposition will occur:
Na2C03(s) •* Na20(l) + C02 (g)
The sodium oxide is incorporated in the fly ash and. increases the
sodium content of the ash. Sodium compounds may also be injected
into the gas stream near the temperature of the electrostatic
precipitator.267 In this event, no chemical change is to be ex-
pected, and solid particles of the added compound are subject to
co-precipitation with the ash.
Utility Utilization and Capital and Operating Costs of Conditioning
Systems--
Capital and operating costs for cold-side conditioning systems
will depend primarily on the type of conditioning agent and the
system used to inject the agent. One company which makes SO3 con-
ditioning systems estimates the capital costs to be between $2.00
to $2.50 per KW with operating costs of $0.02 to $0.03 per ton
of coal burned.262 As of December, 1978, this company had 85
CFGC systems on stream, under construction, or on order, at 13
utilities, serving more than 16,000 MW of generating capacity.
Another company which makes conditioning systems for injecting
proprietary compounds has a system installed with capital costs
of approximately $0.45 per KW and operating costs of less than
534
-------
$0.50 per ton of coal burned.262 As of December, 1978, this com-
pany had CFGC systems at 18 utilities with the vast majority of
the units in the range of 200 to 700 MW.
Recently, it has been reported that chemical conditioning
agents can be utilized to improve the performance of poorly oper-
ating hot-side precipitators.163'2S9'2*° Laboratory studies have
been conducted to evaluate the effectiveness of several different
conditioning agents in improving poor, hot-temperature voltage-
current characteristics which result when certain types of ashes
are deposited on the collection electrodes of a precipitator.l63
With respect to effectiveness in improving the voltage-current
characteristics, NaHSCU, NazSO,,, NaOH, NaaHOP,*, "OH, KHS04, and
NaaCOs were evaluated as good, NaCl and NaHCOs were evaluated as
moderate to good, NH3 was evaluated as moderate, triethylamine
and ferrous sulfate were evaluated as moderate to poor, and SOs,
NHs + SOs, (NHiJaSOi,, and TiOs were evaluated as poor. All these
conditioning agents were in the solid form except NHs, SOa, and
NHs + SOs. It has been reported that conditioning with sodium
carbonate and certain proprietary compounds has been successful
in improving the performance of full-scale, hot-side precipita-
tors. '2 This offers another possible option for upgrading
existing hot-side precipitators which are not performing adequately.
A particular sodium based conditioning system has been installed
with capital costs ranging between $1.75 to $2.00 per KW and ,
operating costs between $1.00 to $1.20 per ton of coal.259
Possible Disadvantages of Chemical Flue Gas Conditioning—
Although chemical flue gas conditioning offers several attrac-
tive, potential benefits, there are several possible disadvantages
which must be considered. First, a chemical injection system
must be operated and maintained. Second, certain chemical com-
pounds which are effective in improving precipitator performance
are hazardous. Third, the effects that conditioning with certain
chemical compounds will have on precipitator performance cannot
always be predicted in advance. Fourth, in certain cases, the
injection of chemical conditioning agents has resulted in an ash
which was very sticky. If this situation results, the rapping
forces might not be sufficient to remove the- material collected
on the discharge and collection electrodes. In addition, if the
conditioning agent is injected on the hot gas side of the air
preheater, pluggage and fouling of the air preheater would result.
Fifth, operating costs associated with certain chemical condition-
ing agents can be significant. Sixth, possible future regulations
concerning the emissions of chemical conditioning agents may make
flue gas conditioning more difficult to implement and less effec-
tive. Future regulations appear plausible since certain agents may
be potentially hazardous. It is inconsistent to regulate the
emissions of certain gases such as S0.2 .while allowing similar
injected gases such as SOs to escape in significant quantities.
Sufficiently high concentrations of S03 at sufficiently low
535
-------
temperatures will produce a highly visible blue plume due to the
condensation of H2SCU. It has already been emphasized by an EPA
official that any emissions of sulfuric acid, S0^l or ammonia
resulting from chemical treatment should not exceed a combined
total of 10 ppm.262 Also, it should be pointed out that only a
few parts per million of certain conditioning agents contain a
significant amount of mass. For example, 5 ppm of SO3 is equi-
valent to 20 yg/m3 (about 0.01 gr/ft3). Thus, the possibility
exists of treating the emissions due to conditioning on a mass
basis and adding this to the mass due to fly ash emissions in
order to obtain the total particulate emissions. This type of
treatment of emissions of chemical conditioning agents would
require that a high percentage of the injected agent be adsorbed
on the surfaces of the fly ash particles.
Precipitator Requirements and Economic Comparisons™
Precipitator requirements and economic comparisons for the
different precipitator options can be estimated by using the
projections obtained from a mathematical model.of electrostatic
precipitation.137'152 Figure 292 shows projected curves for over-
all mass collection efficiency as a function of specific collection
area for several cases where the different precipitator options
can be compared. The curve for an ash resistivity of 4 x 1010
ohm-cm at 148°C (300°F) corresponds to an ash with a favorable
resistivity without conditioning or to an ash with an unfavorable
resistivitv that can be conditioned to a guaranteed resistivity
of 4 x 1Q1"6 ohm-cm. The curves for ash resistivities of 1 x 1011,
5 x 1011, and 1 x 1012 ohm-cm at 148°C (300°F) correspond to
cold-side precipitator operation without conditioning. The curve
for hot-side precipitator operation with normal voltage-current
characteristics v.'as obtained based on electrical operating con-
ditions demonstrated in Figure 200. The curve for hot-side pre-
cipitator operation with anomalous voltage-current characteristics
was obtained based on electrical operating conditions demonstrated
in Figures 203 and 204 and an adjustment to these conditions, as
described elsewhere,256 in order to obtain agreement with measured
data.
All the curves were generated for an electrode geometry con-
sisting of plate-to-plate and wire-to-wire spacings of 22.86 cm
(9 in) and a corona wire diameter of 0.277 cm (0.109 in). The
cold-side precipitator calculations, the maximum allowable current
density for a given value of ash resistivity, was estimated by using
the experimental data shown in Figure 208. Although these values
of current density are probably somewhat conservative for the
higher values of ash resistivity since higher useful currents
might be obtained with the presence of limited back corona, it
is best to be conservative in design due to the lack of predictive
capabilities concerning back corona. Operating current densities
for the resistivities of 4 x 1010, 1 x 1011, 5 x 1C)11, and 1 x 1012
ohm-cm were chosen to be 22.0, 8.9, 1.7, and 0.9 nA/cm2, respectively.
536
-------
99.99
99.98 -
I I I 1 I I I I
I I I
4.0 x 1010 r-cm AT 148°C (300°F)
1.0 x 1010 r-cm AT 148°C (300°F)
5.0 x 1010 r-cm AT 148°C (300°F)
1.0 x 1012 r-cm AT 148°C (300°F)
NORMAL HOT-SIDE V-l AT 343°C -
ANOMALOUS HOT-SIDE
V-l AT 343°C (650°F)
I I I I
I I
0 100 200 300 400 500 600 700 800 900 1000 1100 1200
SPECIFIC COLLECTION AREA, ft2/{1000 ft3/min)
3540-281
Figure 292.
Effect of specific collection area on overall mass
collection efficiency (curves based on a fractional
gas sneakage of 0.05 and a normalized standard of
deviation of gas velocity distribution of 0.25).
537
-------
The applied voltage in each electrical section for a specified
current density was estimated by using the experimental voltage-
current curves shown in Figure 196. These data are representative
of a full-scale, cold-side precipitator treating an ash with a
resistivity of approximately 2 x 1010 ohm-cm. The calculations
were based on a precipitator with four electrical sections in the
direction of gas flow. An applied voltage for use in the second
and third electrical sections of the specified precipitator was
obtained by averaging the values from the experimental inlet
and outlet curves.
For all the curves, specific collection area was varied in
the calculations by changing the gas volume flow and holding the
plate area fixed. Although the voltage-current characteristics
will change to some extent with changes in gas volume flow, it
was assumed that they remain constant in making the calculations.
The number of baffled sections for gas flow redirection was
increased appropriately with increasing specific collection area
in order to account for increased precipitator size.
The measured inlet mass loading and particle size distribution
used in the calculations are typical of fly ash generated by coal-
fired boilers. The inlet mass loading was 5.7 gm/m3 (2.5 gr/acf).
The log-normal fitted inlet particle size distribution had a mass
median diameter of 25.5 urn with a geometric standard deviation of
5.1. To account for the effect of particle size distribution,
especially in the fine particle range (0.25-3.0 ym) , the measured
particle size distribution was divided into size intervals with
midpoints of 0.2, 0.4, 0.7, 1.1, 1.6, 2.5, 3.5, 4.5, 6.0, 8.5,
12.5, 20.0, and 27.5 ym.
The curves were generated based on a fractional gas sneakage
and particle reentrainment without rapping per baffled section
of 0.05 and a normalized standard deviation of the gas velocity
distribution of 0.25. These values are typical of a precipitator
which is in good mechanical condition. All overall mass collection
efficiencies have been corrected for rapping reentrainment using
an empirical procedure based on field test data from full-scale
precipitators as discussed earlier.19'137
The curves in Figure 292 do not address the problems of (1)
opacity, (2) variations in the significant parameters influencing
precipitator performance, and (3) outage of electrical sections.
Therefore, these curves are intended only for use in making
relative comparisons of the different precipitator options for
treating ashes with different resistivities and should not be
used per se for design purposes. Problems (2) and (3) can be
conservatively accounted for by designing the precipitator with
more collection area than that needed to achieve the desired col-
lection efficiency. However, problem (1) requires a somewhat
extensive analysis to determine if the opacity standard will be
met and to determine what safety margins should be included in
538
-------
the precipitator design to account for normal variations in pre-
cipitator parameters that would cause an increase in opacity. In
many cases, the mass emissions standard will be attained at
collection efficiencies well below that needed to meet the opacity
standard.
The curves in Figure 292 can be used to make a relative
economic comparison of the different precipitator options in terms
of total fixed (capital) investment for an 800 MW unit. As an
example, the total fixed investment for each of the precipitator
options can be determined based on a required overall mass col-
lection efficiency of 99.5%. The design parameters for the dif-
ferent precipitator options, cold-side ash resistivity values,
and possible hot-side electrical conditions are given in Table 37.
Estimated costs for cold-side, hot-side, and conditioned pre-
cipitators for use on an 800 MW unit have been published recent-
ly.259 These estimates will be used here for comparing the
.relative capital costs of the various precipitator options.
In this particular analysis, cold-side, hot-side, and conditioned
precipitators would cost $14.82, $15.65, and $16.62 per square
foot of collection plate area, respectively.
The quoted costs include the following items:
1. A gas volume flow for the cold-side precipitator systems which
includes 9% leakage at the air heater.
2. Base equipment.
3. Flues which are sized to provide a gas velocity of 18.3 m/sec
(60 ft/sec).
4. Plenums.
5. Necessary expansion joints for thermal motion and dampers for
isolation and gas distribution.
6. Accessories which include safety interlocks, internal walkways,
hopper heaters, hopper level indicators, remote controls, trans-
former-rectifier removal systems, weather enclosures, gas dis-
tribution devices, facilities, and typical instrumentation.
7. Support structures.
8. Erection.
9. Insulation.
10. SOs gas conditioning system in the case of the cold-side pre-
cipitator with .conditioning.
539
-------
TABLE 37. DESIGN PARAMETERS FOR DIFFERENT PPEC1PITATOR OPTIONS AND
OPERATING CONDITIONS ON AN 800 MW UNIT
Gas Volume Flow
m'/min (1,000 ACFM)
Gas Temperature °C (°F)
Collection Efficiency (%)
£ Collecting Surface Area
° 1,000 m2 (1,000 ft')
Cold F.SP
P=4xl010£2-cni
(conditioned or
Cold ESP
Cold ESP
Cold ESP
Hot ESP
unconditioned) p=lx!0''fi-cm p=5xlO''K-cm p=lxlO'2H-cm Normal V-I
78.4 (2,800)
149 (300)
99.5
61.1 (658)
78.4 (2,800) 78.4 (2,800) 78.4 (2,800) 114.5 (4,089)
149 (300) 149 (300) 149 (300) 343 (650)
99.5 99.5 99.5 99.5
98.8 (1,064) 212 (2,282) 289 (3,108) 114. (1,227)
Specific Collection Area
mMmVsec) (ft'/l,000 ACFM3 46.3 (235) 74.9 (380) 160.6 (815) 218.7(1,110) 59.1 (300)
Hot ESP
Anomalous V-I
114.5 (4,089)
343 (650)
99.5
152 (1,636)
78.8 (400)
-------
11. Ash handling system at $5,000 per hopper.
12. Capacity charge at $800/KW.
13. Required land at $10,000/acre.
Based on the above considerations, Table 38 gives a comparison
of the different precipitator options under different operating
conditions in terms of total fixed investment. The comparisons
in Table 38 and Figure 292 show several points of interest. First,
an unconditioned, cold-side precipitator is the most economically
effective option for ash resistivities of 4 x 1010 ohm-cm or less
and, in addition, should be considered seriously until the ash
resistivity is greater than 1 x 10M ohm-cm. Second, for ash re-
sistivities greater than 1 x 10:i ohm-cm, flue gas conditioning
and hot-side operation with normal voltage-current characteristics
become attractive options from an economic standpoint when compared
to unconditioned, cold-side operation. However, at best, hot-side
operation will be a factor of 1.76 times as costly as cold-side
operation with conditioning. Third, if a hot-side precipitator
is sized to account for the possibility of anomalous voltage-
current characteristics, then it will cost a factor 1.33 times
that of a hot-side precipitator with normal voltage-current char-
acteristics. This would make the hot-side option extremely
unfavorable when compared to flue gas conditioning and would
make it competitive with unconditioned, cold-side operation
treating ashes with resistivities near 5 x 10ll ohm-cm or less.
Since annual operating and overhead costs will be dominated
by amortization of the debt (including interest, taxes, and in-
surance at approximately 20% of the total fixed investment), the
relative comparison of these costs between the different pre-
cipitator options should parallel that of the total fixed invest-
ment analysis. The operating--costs include' (1) heat loss for the
hot-side options, (2) an energy charge for all the options that
depend on power input to the transformer/rectifier sets and
pressure drop across the precipitator, (3) cost of the condition-
ing agent for the flue gas conditioning option, and (4) maintenance.
These operating costs are small compared to the amortization and
at most will probably not exceed 25% of the amortization. The
heat loss penalty for the hot-side option will probably make the
estimate of its operating costs somewhat higher than the other two
options when all three options are evaluated for the collection
of high resistivity ash. Of course, the cost of the conditioning
agent can vary widely, depending on the type of agent and the
supplier. Finally, the estimation of maintenance costs is diffi-
cult and would vary significantly from one ,type of precipitator
to another.
Due to the uncertainties involved in estimating the operating
costs for the different options, this type of analysis will not be
presented here. However, estimated operating costs can be found
elsewhere.2S 9
541
-------
TABLE 38. TOTAL FIXED INVESTMENT OF PRECIP1TATOR OPTIONS UNDER
DIFFERENT OPERATING CONDITIONS FOR AN 800 MW UNIT ($1000)
Cold ESP Cold ESP Cold ESP Cold ESP Cold ESP Hot ESP Hot ESP
p=4xlO'°n-cm p=4xlO">f!-cm p=lxlO"n-cra p=5xlO"f]-cm p = lxlO' 2!7-cm Normal V-I Anomalous V-1
(unconditioned) (conditioned)
in
M Total • '•
Investment 9,752 10,936 15,769 33,819 46,061 19,203 ; 25,603
Relative
Investment
Ratio 1.00 1.12 1.62 3.47 4.72 1.97 2.63
-------
SECTION 9
SAFETY ASPECTS OF WORKING WITH
ELECTROSTATIC PRECIPITATORS
RULES AND REGULATIONS
The only regulations specified by OSHA as being applicable
to safety practices around an electrostatic precipitator are
(1) the National Electrical Code - found in 29 Code of Federal
Regulations 1910 Subpart S, and (2) Occupational Health and En-
.vironmental Control - found in 29 Code of Federal Regulations
1910.1000 Air Contaminants. Table 7-3 of the CFR gives exposure
limits to silica and coal dust, and Table 7-1 of the CFR sets an
exposure limit for ozone, which is produced during electrical
discharge, and for sulfur dioxide, which results from coal com-
bustion.
HAZARDS
268r269»270»271
Since the operation of an electrostatic precipitator involves
high voltage, extreme caution should be taken when inspecting and
troubleshooting to avoid electrical shock. Also, serious fires
and explosions have occurred, resulting in large losses and long
shut-downs. Other hazards one- encounters while inspecting pre-
cipitator internals' involve toxic gases, especially ozone and
sulfur oxides, sudden accidental activation of rapping equipment,
possible burns and heat exhaustion from working inside the shell,
eye and lung contamination from foreign particles, especially fly
ash, and the possibility of falling from areas being inspected.
These hazards and preventive measures will be discussed in detail
below.
Fire And Explosion Hazards269'272
Combustion may be defined as the rapid chemical combination
of oxygen with-the ,combustible elements of a fuel. There are just
three combustible .-chemical elements of significance - carbon,
hydrogen, and sulfur.. Sulfur is of minor significance as a source
of heat. Carbon and hydrogen when burned to completion with oxygen
unite as shown below:
C 4- 02 = C02 + 14,100 Btu/lb of C
2H2 + 02 - 2H20 + 61,100 Btu/lb of Hz
543
-------
Excess air, blown into the primary furnace of the steam
generator, is the usual source of oxygen for boiler furnaces.
The objective of good combustion is to release heat while mini-
mizing losses from combustion imperfections and superfluous air.
Adequate combustion then requires temperatures high enough for
ignition, turbulence or mixing, and sufficient time. These
factors are known as the "three T's" of combustion. If one of
these requirements is deficient incomplete combustion occurs
with its resultant unburned carbon constituents. Fires can
quickly become a problem with the presence of combustibles,
oxygen, and source of ignition (high voltage sparking}..
Some of the areas in which fires have occurred due to poor
combustion are in the electrostatic precipitator5 themselves,
air heaters, flues, ducts, coal pipes, and precipitator hoppers.
In one case where improper combustion occurred, there was ex-
cessive air in-leakage between the primary furnace and the pre-
cipitator. This air leakage, together with unburned carbon and
arcing in the precipitator, caused a fire. In another case the
formation of clinkers (large carbonaceous ash masses which adhere
to tube surfaces) produced plugged secondary superheaters which
allowed more fuel to carry over to the precipitator.
In summary, poor maintenance and poor operating practices
at the plant facility are the major causes of fires and explosions
in electrostatic precipitators. Poor combustion due mainly to
improper amounts of excess air appears to be the major operating
practice leading to fires.
Electrical Shock Hazards269
Electrical shock to operators of precipitators is due to the
failure, misuse, or faulty condition of electrostatic precipitator
equipment and may cause the following conditions: painful shock
from sudden contact, resultant action from shock contributing to
a secondary hazard (falling, dropping tools, etc.), flesh burns
at points of contact, and death if the victim cannot release him-
self from the energized conductor within a reasonable period of
time (this factor depends greatly upon one's physiological con-
dition, amount of current, resistance and path of current flow
through the body, and type of electrical energy in question).
Pure direct current produces a steady sensation of intense
heating and burning along the current path with only slight muscular
contraction. A direct current flow of ten milliamperes through the
body causes little or no sensation, but secondary hazards, such as
falls, are possible. At about 60 to 80 milliamperes the sensation
becomes unbearably painful, with no tissue damage. However, the
muscular reactions due to breaking contact may -be sufficient to
throw a person bodily. With higher currents the above effects
are increased and serious burns may be encountered. Fibrillation
appears in the range of 500 to 2000 milliamperes on contacts that
exceed a quarter of a second.
544
-------
Large, high voltage electrostatic precipitators usually have
double interlocking safety controls to prevent electrical shock
accidents. These safety controls prevent entrance into the elec-
trostatic precipitator unless the unit has been deenergized. If
the primary safety control fails and the access door is opened
while the precipitator is in operation, the secondary control
immediately grounds ou± the transformer and the unit is deenergized,
Sometimes, however, maintenance and operation personnel do not
want to take the time necessary for proper shutdown and bypass the
interlocking safety controls. When safety controls are misused in
this way, accidents often result. Another potential problem with
the safety controls occurs when they are not inspected and main-
tained periodically. An actual case of electrocution occurred
when safety controls, which operated in a corrosive atmosphere,
corroded to the point of not functioning. When a worker entered
the unit, thinking it would be deenergized, electrocution resulted.
Poking the precipitator collection hoppers with long poles
•to facilitate the flow of bridged fly ash is a common practice.
Obviously a non-conductive pole, never a metal pole, should be
used. If a metal pole makes electrical contact between the
energized parts of the unit and the hopper, electrocution could
result.
Toxic Gas Hazard
Purging the inside of the electrostatic precipitator with air
is necessary before allowing personnel to enter because of the
presence of toxic gases. Sulfur oxides and ozone are two gases
which can be present in concentration great enough to cause a
health risk. Sulfur dioxide and sulfur trioxide are common gas-
eous emissions when burning sulfur-containing coal. Sulfur
trioxide (SOs) is-not likely to be present in large quantities
(a few parts per million) but it readily combines with water
vapor to form sulfuric acid mist and' can be dangerous. Sulfur
dioxide (SOa) could be present in several hundred or even several
'thousand parts per million inside the precipitator depending upon
the sulfur content of the coal. The taste threshold for S02 is
about 0.3 ppm, and SOZ is a very unpleasant experience at 1 ppm.
A level of 5 ppm of SOa causes respiratory irritations and even
spasmodic reactions in some sensitive individuals.273 Ozone is
produced by the discharge of high tension electrical current in-
side the precipitator. The body is very sensitive to ozone,
detecting its odor as low as 0.02 ppm. Nasal and throat irrita-
tion occur at 0.3 ppm. At 1 ppm, severe restriction of respiratory
passages occurs and many persons cannot tolerate higher concentra-
tions. Ozone appears to damage lung tissue by accelerating the
aging process, making it more susceptible to infection.
Other More Minor Hazards270
The rapping area contains rotary equipment which is deener-
gized when the weather enclosure door is open. However, if the
545
-------
door is closed the equipment may operate if a padlock is not used
to lock open the disconnect on the panel feeding the rappers.
Heat exhaustion and/or severe burns can result from entering
the precipitator too soon after shut-down since the steel takes a
very long time to cool down.
Eye protection should be worn to protect eyes from fly ash
and other foreign particles.
There are areas within the precipitator from which one could
fall. Ladders should be properly secured and safety belts may be
appropriate.
546
-------
SECTION 10
MAINTENANCE PROCEDURES
Proper maintenance precautions and procedures can make the
difference between an electrostatic precipitator which operates
satisfactorily and one which is continually beset with operational
difficulties. Most of an installation's problems are mechanical
in nature and, though many of the breakdowns can be traced to poor
structural design or poor installation, poor maintenance is the
cause often enough to merit a detailed discussion. Two general
categories of precipitator maintenance problems exist: those
problems due to lack of proper preventive maintenance and those
problems associated with failure or breakdown of precipitator
components. A careful, step-by-step start-up procedure is an
invaluable preventive maintenance aid, and a typical start-up
procedure and inspection is given in Table 39. "7l* After start-up
preventive maintenance schedules should be established to conform
to the requirements for the particular installation. A typical
maintenance schedule for an electrostatic precioitator is given
in Table 40. 2 7l" 27 s' 276
Several surveys have been conducted in an effort to identify
the major sources of operating malfunctions most commonly encoun-
tered with electrostatic precipitators.277r27a'279'28° A survey
conducted by the Industrial Gas Cleaning Institute in 1969 iden-
tified problems in the order listed in Table 41.279 The number
identified with each problem is a percentage of the respondents
identifying the particular component as a maintenance problem.
Results of a 1974 Air Pollution Control Association (APCA) survey
of electrostatic precipitator maintenance are similar (Table 42).279
Discharge electrode failures are typically caused by electri-
cal arcing, corrosion, and fatigue. When a wire breaks an elec-
trical short circuit often occurs between the high-tension dis-
charge wire system and the grounded collection plate. The short
trips a circuit breaker, disabling a section of the precipitator
until the discharge wire is removed or replaced. Some of the more
common specific causes of discharge wire breakage are:277
(1) Inadequate rapping of the discharge wire which eventually
allows arcing to occur.
(2) Improperly centered wires leading to sparking at those
points too near the bracing. .. . •
547
-------
TABLE 39. INITIAL ELECTROSTATIC PRECIPITATOR
START-UP PROCEDURE AND INSPECTION27k
Ducting
1. Check all ducting for foreign material.
2. Check all welded joints for leakage.
Internals
1. Check collecting plates for straightness ar.i flatness and
give tolerances.
2. Check spacing of collecting plates and give tolerances.
3. Check pendulum movement of collecting plates.
4. Check rappers for freedom of movement.and alignment.
5. Check the spacing between the plates and discharge wires and
give tolerances.
6. Spot check discharge wires for proper tension,.
7. Check for foreign material clinging to discharge wires, col-
lecting plates, precipitator chamber bottom, and hopper area,
8. Check all welds on high voltage frames.
9. Check all motors, bearings, reducers, etc. for proper lub-
rication.
10. Check all motors for direction of rotation.
11. Check underside of insulators for cleanliness, foreign
material, and position of high voltage hanger rods.
Insulator Compartment
1. Check insulator compartment for debris.
2. Check insulator for cracks.
3. Check installation of high voltage hanger.
4. Check welds on high tension hangers.
5. Check for dryness.
Access Doors
1. Insure that door is free swinging.
2. Check latches for tightness when door is shut.
3. Check gasket for gas tight seal.
Rapper Drives
1. Check alignment of all rapper shafts.
2. Check for proper installation of insulators through casing
wall for high voltage rapper shafts.
548
-------
TABLE 39 (CONTINUED)
Hopper Conveyors
1. Check rotation of screw conveyors if used.
2. Check for binding.'
Safety Interlock System
1. Check to insure that all keys are in master keyboard.
2. Check all key-locks to insure that safety lock is operating.
Electrical
1. Inspect the control panel and insure that all motor and heater
control circuits, inter-locking arrangements, and remote con-
trols function properly.
• 2. Arrange that all time relays, end position switches, rotation
guards, etc. be set properly and that the function of all
alarm signals be checked.
3. Check that all electric heaters function and set the thermo-
stats correctly.
4. Inspect the rectifier units with regard to oil level, etc.
(follow rectifier manufacturer's instructions).
5. Inspect all transformer rectifiers.
6. Check all electrical wiring to precipitator.
7. Check wiring between control cabinet and high tension trans-
formers to be certain control cabinet is actually connected
to the proper high voltage transformer and that interlocks
are in the proper sequence. Check ground wiring.
8. Connect one rectifier unit at a time corresponding to the
emitting system of the precipitator.
9. Start the rectifier.
10. Check current and voltage at different settings and test the
signals circuits.
549
-------
TABLE 4 0 . TYPICAL MAINTENANCE SCHEDULE 2 7 ** ' 2 7 5 ' 2 7 6
1. Check for drift of meter readings away from baseline values
established when ESP was installed. Record readings for each
control unit.
2. Keep an accurate log of all aspects of precipitator operation.
In addition to the electrical data, record changes in rapper
and boiler operation and variations in fuel quality.
3. Check insulator heaters for operation mode ani record ammeter
readings of each insulator heater.
4. Check all "Push to Test" lights on panel and replace as
necessary.
5. Check all rapper timers for operation.
6. Test annunciator panel for operation and replace any bad
lights.
7. To warn of hopper ash buildup and ash conveyor stoppage, check
skin temperature of hopper.
8. Check operation of rapper and vibrator controls.
9. Check oil level of all transformer-rectifier units and record
oil temperature.
10. Note and report any leaks on tank of transformer-rectifier.
Weekly
1. Make visual inspection of rapper action and check vibrator
operation by feel.
2. Check control sets internally for deposits of dirt that may
have penetrated the filter. Accumulation of dirt can cause
false control signals and can be destructive, particularly to
large components such as printed circuits.
3. Clean all insulators.
4. Check access doors for tightness.
550
-------
TABLE 40 (CONTINUED)
Monthly
1. Shut down unit, tag switches, apply ground protectors, and
proceed with inspection and maintenance.
2. Using low pressure air, blow out rectifier compartments and
control cabinets.
3. Clean with carbon tetrachloride and check fcr chips and arc
tracks the following:
a. transformer bushings
b. stand-off insulators
c. potheads
d. rectifier rotor and cross arms
e. rectifier tubes
4. Clean or change ventilating fan air filters.
5. Check rotor and stator shoes for wear and proper adjustment.
6. Inspect on the drag motor the foundation bolts, alignment,
and rotor end play.
7. Inspect on the screw conveyor motor the foundation bolts.
Quarterly
1. Clean inside all panels.
2. Check all electrical components for signs of overheating.
3. Clean and dress electrical distribution contacts, surfaces,
and lubricate pivots.
4. Check vent fan for operation and check clearances between
blades and shroud.
5. Install new filters in control panel.
6. Routine inspection, cleaning., and lubrication of hinges and
test connections.
7. Exterior inspection for corrosion, loose insulation, exterior
damage, and loose joints.
551
-------
TABLE 40 (CONTINUED)
Annually
1. Remove dust buildup on wires and plates, and adjust intensity
of rappers and vibrators if necessary.
2. Inspect perforated diffuser screen and breeching for dust
buildup.
3. Perform maintenance and lubrication of pressurized fans and
check for leaks in pressurized system,
4. Check for loose bolts in frames, verify that suspension springs
are in good order, and examine wearing parts.
5. Inspect discharge wires for tightness and signs of burning and
measure to see if they hang midway between plates.
6. Check plates for alignment and spacing.
7. Check insulators for cracks.
8. Drain oil, wash out, and refill gear boxes.
9. Check transformer fluid and dielectric strength.
552
-------
TABLE 41
MOST COMMON MAINTENANCE PROBLEMS279
Component Percent
Discharge Electrode Failure 68
Rapper Malfunctions 40
Insulator Failures 28
General Dust Buildup Causing Shorts 28
Hopper Plugging 24
Transformer Rectifier Failures 20
553
-------
TABLE 42. POWER PLANT ELECTROSTATIC PRECIPITATOR
MAINTENANCE PROBLEMS
279
Component
Discharge
Electrodes
Dust Removal
Systems
Rappers or
Vibrators
Collecting
Plates
Insulators
Major
Maintenance
Problem, %
35.2
31.8
5.7
13.6
1.1
Component Failure Frequency, %
Frequent Infrequent Very Seldom
29.5
36.4
9.1
4.5
8.0
38.6
42.0
38.6
7.9
34.1
28.4
20.5
47.7
68.2
48.9
554
-------
(3) Clinker or a wire that bridges the collection plates and
shorts out the wire.
(4) Ash buildup under the wire, causing it to sag and short
out.
(5) Corrosion caused by condensation.
(6) Excessive localized sparking leacling to wire erosion.
(7) Fatigue leading to wire breakage, especially at those
points where wires are twisted together.
(8) Fly ash buildup in certain spots which leads to a clinkf. "
and burns off the wire.
Continuous sparking at any one location along a discharge wire will
ultimately lead to wire failure since small quantities of metal are
vaporized with each spark. Localized sparking can be caused by
misalignment of the discharge electrodes during construction or
by electric field variations caused by "edge" effects where the
discharge and collection electrodes are adjacent to each other at
the top and the bottom of the plates. Mechanical fatigue often
occurs when the discharge wire is twisted around the support collar
at the top of the discharge electrode.
Since the existence of temperatures below 121°C (250°F) may
lead to excessive corrosion and fouling of the cold-end elements
of the air heater and corrosion of cold-side precipitator elements,
the topics of corrosion and fouling are of considerable importance
and deserve proper attention. However, since proper design should
result in temperatures above 121°C (250°F) and since an adequate
coverage of the topics of corrosion and fouling requires extensive
text, a discussion of low temperature corrosion and fouling is
given in Appendix D instead of in the main text. Appendix D in-
cludes discussions of (1) sulfuric acid occurrence in flue gas
based on SOX, HaO, and HaSOu equilibria, determination'of the
sulfuric acid dew point, and condensation characteristics, (2)
factors influencing corrosion rates such as acid strength, acid
deposition rate, fly ash alkalinity, and hydrochloric acid, (3)
fouling of low temperature surfaces, (4) laboratory corrosion
studies, and (5) power plant data.
Problems with the dust removal systems are caused primarily
by hopper plugging, followed by screw conveyor and dust valve
deficiencies. Improper adjustment of hopper vibrators or complete
failure of the ash conveyor are common causes of hopper overflow.
Heaters and/or thermal insulation for the hoppers to prevent ash
agglomeration may be helpful in some cases.
Rapping is required for both discharge and collection elec-
trodes. A number of different rapping systems are used but those
555
-------
rapping systems using vibrators, either pneumatic or electric,
appear to require more maintenance than impulse-type systems.
Failures of support insulators are caused primarily by arc-overs
from accumulations of dust or moisture on the surface of the
insulator. These failures are often caused by inadequate pres-
surization of the top housing of the insulators.
Other problems which cause difficulty, but to a lesser extent,
are dust buildup in the upper outside corners of hoppers, corro-
sion in the less accessible parts of the precipitator such as
around the access doors and frames, box girders, and housing,
plugging of gas distribution plates, problems with rapping system
drives, wear of rappers and bushings, and problems of wear and
movement occurring at points of impact.
Another point of inquiry in the APCA survey involved overall
experience with electrostatic precipitators from operational
and maintenance standpoints. The utilities' responses were:
Utilities - Operation of Precipitators
Excellent Good Fair Poor
14.8% 45.5% ' 29.5% 10.2%
Utilities - Precipitator Maintenance
Excellent Good Fair Poor
13.6% 52.3% 13.6% 20.5%
Some of the data reported represent precipitator installations that
have been in service for many years and often these installations
have not received proper attention.
Proceedings from a recent specialty conference on the operation
and maintenance of precipitators would be extremely useful to
users who experience many of the problems discussed in this sec-
tion.281
556
-------
SECTION 11
TROUBLE SHOOTING
DIAGNOSIS OP ESP PROBLEMS
Causes for an electrostatic precipitator to fail to achieve
its design efficiency can be due to poor maintenance as dis-
cussed in the previous section, or they can be due to inadequate
design, electrical difficulties, improper gas flow, inadequate
rapping, installation problems, electrode misalignment, or impro-
'per operation.
Structural engineering and design considerations are frequently
overlooked by the engineer who specifies and buys electrostatic
precipitators, for he often assumes that the manufacturer's ex-
perience and engineering capability is sufficient. In the com-
petitive atmosphere which exists among precipitator manufacturers,
a manufacturer normally proposes only the equipment and features
absolutely necessary to meet contract requirements.282 Any devia-
tions from a manufacturer's standards would increase costs and
possibly cost him his competitive advantage. An example of one
of the structural problems which has occurred is the lack of
provision for expansion/ possibly stemming from a temperature
assumption that allows no' margin, thus causing excessive deflec-
tion of the substructure or the interior precipitator beams and
columns.282 Other structural problems arise from insufficient
attention to fabrication and erection tolerances, which result in
misalignment and operating difficulties.
Indications of electrical difficulties can usually be observed
from the levels of corona power input. Efficiency is generally
related to power input, and if inadequate power densities are in-
dicated, difficulties can usually be traced to:275
(1) high dust resistivity,
(2) excessive dust accumulations on the electrodes,
(3) unusually fine particle size,
(4) inadequate power supply range,
(5) inadequate s-ectionalization,
(6) improper rectifier and control operation,
(7) misalignment of the electrodes.
557
-------
Because of the importance of resistivity in the precipitation pro-
cess, in situ resistivity measurements should be one of the initial
trouble shooting steps. If resistivity exceeds 1010 ohm-cm, the
resistivity may be the blame for most of the difficulty.
Other electrical problems encountered with electrostatic
precipitators are shorting of the high tension frame by dust
accumulation in the hoppers, broken wires, insulator bushing
leakage, and leaking or broken cables.
Quality of gas flow can be determined by measurement of a
gas flow distribution profile at the precipitator inlet. The
IGCI recommends a gas quality such that 85% of the local velo-
cities is within 25% of the mean with no single reading more than
40% from the mean. Poor gas flow often results from dust accumu-
lation on turning vanes and duct work and plugging of distribution
plates. Gas "sneakage", a term describing gas flow which by-passes
the effective precipitator section, can also be a problem. "Sneak-
age" can be identified by measurement of gas flow in the suspected
areas (the dead passages above the collection plates, around the
high tension frame, or through the hoppers) during a precipitator
outage with the blowers on. Also, problems of reentrainment of
dust from the hoppers because of air inleakage or gas "sneakage"
can often be identified by an increase in dust concentration at
the bottom of the exit to the precipitator. Corrective measures
usually involve baffling to redirect gas flow into the electrified
region of the precipitator.
Improper rapping is usually the cause when excessive dust
deposits occur on the discharge and collection electrodes. Ade-
quacy of rapping can be measured by accelerometers mounted on the
electrodes. One should carefully adjust the rapping intensity and
cycle to maintain a practical thickness of dust deposit without
excessive reentrainment.
Most problems associated with hopper and ash removal systems
are usually due to improper adjustment of the hopper vibrators or
failure of the conveyor system. In some instances heat and/or
thermal insulation for the hoppers to avoid moisture condensation
may be necessary.
Severe difficulties with electrostatic precipitators are
usually caused by inadequate electrical energization or excessive
reentrainment. The following is a rather general guide which may
be useful in pinpointing the causes of severe precipitator pro-
blems:275
(1) Measure the high tension voltage, current, and spark
rate.
558
-------
(2) Measure gas flow distribution.
(3) Observe collecting plates for evidence of back corona.
(4) Use an oscilloscope to record the high tension voltage
to determine the duration of the corona current.
(5) Observe the collection plates for evidence of excessive
reentrainment (this requires construction of a glass
plate and wiper for an access port and a means for illum-
ination of the interelectrode space).
(6) Examine alignment and condition of the r.-ppers, insulators,
and other components.
(7) Measure rapping accelerations.
Table 43 is a trouble shooting chart for use in determining
the cause of common electrostatic precipitator malfunctions, with
suggestions for remedying these problems.277
AVAILABLE INSTRUMENTATION FOR ELECTROSTATIC PRECIPITATORS
Spark Rate Meters
The term "spark rate" refers to the number of times per minute
that electrical breakdown occurs between the corona wire and the
collection electrode. A spark-rate controller establishes the
applied voltage at a point where a fixed number of sparks per minute
occur (typically 50 - 150 per corona section). The sparking rate
is a function of the applied voltage for a given set of precipitator
conditions. As the spark rate increases, a greater percentage of
input power is" wasted in the spark current, and consequently less
useful power is applied to dust collection. Continued sparking to
one spot will cause errosion of the electrode and sometimes mechan-
ical failure. Therefore, to meet rapid or periodic changes in the
gas and ash composition, the rectifier should be fitted with a
spark rate controller which can automatically adapt the current to
the changing operating conditions. The precipitator is thus sup-
plied with a maximum of current at all times.
The spark rate meter may be supplied as a self-contained unit
or built into the automatic voltage control system. Some of the
companies which supply the spark rate meter and/or total voltage
control system are given below:
• Envlronecs
1654 Babcock Street
Costa Mesa, California 92627
(714) 631-3993
559
-------
TABLE 43
TROUBLESHOOTING CHART
277
cn
CT>
o
Symptom
No primary voltage
No primary current
No precipitator (ESP)
current
Vent fan on
Probable Cause
DC overload condition
No primary current
No precipitator current
Vent fan off
Alarm energized
Control unit trips out an
over current when sparking
occurs at high currents
4. High primary current
No precipitator current
Misadjustment of current limit
control
Overdrive of rectifiers
Fuse blown or circuit breaker
tripped
Loss of supply power
Circuit breaker defective or
incorrectly sized
Overload circuit incorrectly
set
Short circuit condition in
primary system
Too high precipitator voltage
for prevailing operating
conditions
High voltage circuit shorted by
dust buildup between emitting
and collecting electrodes
Remedy
Check overload relay setting
Check wiring and components
Check adjustment of current
limit control setting
Check signal from firing
circuit module
Replace fuse or reset circuit
breaker
Check supply to control unit
Check circuit breaker
Reset overload circuit
Check primary power wiring
Lower the precipitator voltage
PI 'move dust buildup
-------
Ul
5
D*
Low primary voltage
High Secondary current
6.
Abnormally low ESP current
and primary voltage with
no sparking
Slack or broken emitting
electrode wore shooting the
high "V" circuit
Circuit component failure
Trouble in ESP:
(1) Dust buildup in hopper;
check meters:
- ammeter very high
- KV meter very low (1/2 normal)
- milliamperes very high
(2) Metallic debris left in
unit during shutdown for
maintenance
(3) Unhooked collecting plate
touching emitting frame
(4) Broken support insulator
(5) Excessive dust buildup on
hopper beams or cross member
Short circuit in secondary
circuit or precipitator
Misadjustment of current and/
or voltage limit controls
Misadjustraent of firing circuit
control
Deenergize precipitator and
remove or replace broken or
slack wire
Check transformer-rectifier
and precipitator: Ground T-R
high "V" Connector to precipi-
tator
Clean off dust buildup
Deenergize ESP and remove
Repair
Repair
Clean
Check wiring and components
in high voltage circuit;
check ESP for:
interior dust buildup
full hoppers
broken wires
ground switch left on
ground jumper left on
broken insulators
fore Lgn material on high
voltage frames or wires
Check settings of current and
voltage limit controls
Turn to maximum and check
setting of current and
voltage limit controls
-------
Ul
to
10.
11,
Spark meter reads high-
off scale
Low primary voltage and
current; No spark rate
indication
Spark meter reads high
primary voltage and
current very unstable
No spark rate indication;
voltmeter and ammeter
unstable indicating
sparking
No response to voltage
limit adjustment
Does respond to current
adjustment
No response to spark rate
adjustment
Does respond to other
adjustment
cuetuxny un eiuxi.uj.ny
electrode wires
Stream of cold air entering
ESP from defective door gasket
duct opening, inlet gas system
rupture-condensation
Wet dust clinging to wires
causes extremely low
millampere readings
Severe arcing in the ESP
without tripping out the unit
Continuous conduction of spark
counting circuit
Spark counter counting 60
cycles peak
Misadjustment
Loss of limiting control
Failure of spark meter
Failure of integrating
capacitor
Spark counter sensitivity
too low
Controlling on current limit
or spark rate
Controlling on voltage or
current
eiuxuuxny xxcimt: VJ.U.LCI cj.ua
and emitting vibration shaf«-
insulator
Repair
Eliminate source of condensation
Eliminate cause of arcing
Deenergize, allowing integrating
capacitor to discharge and
reenergize
Readjust controls
Readjust
Replace control
Replace spark meter
Replace capacitor
Readjust sensitivity
None needed if unit is operating
at m.iximum current or spark rate
Reset current and spark rate
adjustment if neither is maximum
None needed if unit is operating
at maximum voltage or current
Reset voltage and current
adjustment if neither is at
maximum
-------
The Environecs spark rate meter circuit is a standard part
of their total automatic voltage control system (Figure 293^ 83).
Other standard features of this system (see Figure 294283) other
than the spark rate meter are: (1) Electronic Current Limit,
which prevents drift in the current setting; (2) Soft Start,
which prevents high in-rush current to the high voltage power
supply at start-up; (3.) Recovery Control, which adjusts the rate
at which voltage recovers from the zero level after a spark back
up to the setback point; (4) Setback Control, which determines
the reduction of output voltage after a spark is detected; (5)
Hold Control, which holds the voltage at the adjusted setback
level for a short period of time, allowing the precipitator to
stablize; (6) Rise Rate, which determines the rate at which the
output power increases to the current limit setting or until a
spark is detected; (7) Spark Detection, which senses the spark
on the first half cycle, allowing the control logic circuits to
adjust the precipitator power immediately following the spark;
(8) Automatic/Manual Control with Bumpless Transfer, allows the
operator to select the optimum operating point of the precipitator
in the manual control mode of operation and then switch to the
automatic position and have the thyristor control automatically
start operating at the same output level selected in the manual
mode, (9) Arc Quench circuit, is an added safety feature to insure
against power arcs; (10) Under-Voltage Relay, monitors the AC
voltage across the primary of the high voltage power supply and
can be a useful device for indicating potential problems when
properly adjusted for a plant's particular operation.
• Wahlco, Inc.
3600 West Segerstrom Avenue
Santa Ana, California 92704
(714) 979-7300
The Wahlco Spark Rate Meter is designed for installation in
conjunction with new or existing precipitator controls. The unit
is self-contained requiring 120 VAC input for powering and the
signal input is derived from the ground leg resistor of the trans-
former rectifier set. All detecting and conversion components are
solid state. The only mechanical component is the meter movement.
The solid state system takes the steep wavefront of the spark
signal, integrates this over a time base, and delivers an analog
signal into the meter movement. The spark sensing input signal
, is fed through a full wave bridge rectifier to eliminate polarity
sensitivity. The unit has multipole filters enabling it to respond
quickly and yet follow a spark signal without the meter bouncing
obj ectionably.
In Figure 295 is a diagram of the Wahlco automatic voltage
control unit.283 The spark detector's circuit memorizes the peak
amplitude attained fay the input signal during one half cycle,
compares it to the peak amplitude attained during the next half
cycle, and then memorizes the -value of the latter signal. From
563
-------
AUTO VOLTAGE CONTROL UNIT
L1
POWER
INPUT
L2
TRANSFORMER-RECTIFIER SET
(~~HV HIGH I
TRANSFORMER VOLTAGE |
DC BRIDGE,
CURRENT
LIMIT QUENCH |
RESISTOR f I
PRECIPITATOR
3540-282
Figure 293. Schematic of Environecs Automatic Voltage Control
Unit.283
564
-------
TYPICAL RESPONSE TO SPARK
TR
CURRENT
SPARK'
CURRENT LIMIT
SETBACK
I
QUENCH [
HOLD
RECOVERY
TIME
RISE RATE
3540-283
Figure 294. Typical response to spark.
283
565
-------
AUTO VOLTAGE CONTROL UNIT
RECTIFIER
tn
POWER
INPUT
SLOP RECOVERY
SET BACK
RAMP RATE
3MO-Z84
Figure 295. Diagram of a Wahlco automatic voltage control unit.283
-------
the controller standpoint a spark has occurred if the signal is
at least 25 instantaneous peak volts and its amplitude is at
least 5 volts greater than the previous half cycle's signal peak
amplitude. Some of the features of the system are: ramp rate
and set-back, current limit, undervoltage relay, and recovery
time control.
• A.V.C. Specialists, Inc.
2612 Croddy Way, Suite 1
Santa Ana, California 92704
(714) 540-2321
Figure 296 is a connection diagram for the external connec-
tions to the A.V.C. self-contained spark rate ir.eter.233 This unit
can be added to any TR set controller providing that the input
power and spark signal are made available. The meter mounts in
the hole pattern for General Electric "Big Look" meters, 3*s inch
type 162 (AO/D091). Depth behind the panel is 4*5 inches maximum,
.and an additional % inch minimum should be allowed for clearance
at the terminals.
A.V.C. Specialists concentrates on providing voltage controls
for precipitators, both new and existing. Much of their business
is upgrading existing units to achieve better electrical performance,
better collection efficiency, more reliable operation, the elim-
ination of maintenance problems caused by non-responsive "automatic"
controls. Some of the important standard features of the automatic
voltage controllers are: ramp rate control, set back control,
quench control, current limit control, fast acting overload pro-
tection, and manual control mode.
There are two types of voltage controls that A.V.C. Specialists,
Inc. has developed for electrostatic precipitators:
(1) Saturable Core Reactor Type Controller, which is designed
to drive the D.C. control winding of a saturable core reactor.
(See Figure 297283);
(2) Thyristor (SCR) Type Controller, which controls the phase
angle of firing of two SCRs in order to control the output of the
TR set (See Figure 298283).
Secondary Voltage And Current Meters
Most precipitator control rooms have panel meters for each TR
set which show the primary and secondary voltage and current and
the sparking rate. Secondary voltage-current relationships can
be obtained for both clean and dirty plate conditions and inter-
pretations can be made of precipitator behavior based on the V-I
data. The secondary voltage-current meters operate on the same
principle as voltage diviers which were discussed in a previous
.section. Secondary voltage-current meters are supplied by the
567
-------
T/R SET
FROM VOLTAGE
CONTROLLER
SPARK RATE METER
PRECIPITATOR
MA SHUNT RESISTOR (GROUND LEG RES)
SIZE OF RESISTOR BASED ON
T/R SET RATING 3540-285
Figure 296.
Connection diagram for the external connections
to A.V.C. self-contained spark rate meter.263
568
-------
T/R SET
1.2 •
INPUT
POWER
SATURABLE CORE
REACTOR
115 VAC
CONTROL
PRECIPITATOR
QUENCH
SET BACK
RAMP RATE
AUTOMATIC VOLTAGE CONTROLLER
3540-216
Figure 297. Block- diagram saturable core reactor type system
283
569
-------
T/R SET
L1
L2-
n
ER
fcl/"
FT
INDUCTOR
t
O«^OO
W
\/ v^
1
PRECIPITATOR
AUTOMATIC VOLTAGE CONTROLLER
9S40-287
Figure 298. Block diagram Thyristor-type system.
283
570
-------
precipitator vendor and are not considered specialty items. Usu-
ally a major manufacturer such as General Electric sells the meters
off-the-shelf, and a meter company such as Meter Master, Simpson,
Triplett, etc. makes and calibrates the meter scale to specifica-
tions.
If meters are not' installed on the transformer secondary, a
quick, temporary voltage divider network can be installed on the
precipitator side of the rectifier network as discussed previously.
Many companies sell voltage dividers and a few of these are given
below:
Beckman Instruments-Helipot Division
2500 Harbor Boulevard
Fullerton, California 92634
(714) 871-4848
CPS Inc.
110 Wolfe Road
Sunnyvale, California 94086
(408) 738-0530
Del Electronics Corporation
250 East Sandford Boulevard
Mt. Vernon, New York 10550
(914) 699-2000
EECO
1441 East Chesnut Avenue
Santa Ana, California 92701
(714) 835-6000
Electro Scientific Industries
13900 N.W. Science Park Drive
-Portland, Oregon 97229
(503) 641-4141
Genrad
300 Baker Avenue
Concord, Massachusetts
(617) 369-8770
Guideline Instruments, Inc.
2 Westchester Plaza
Elmsford, New York 10523
(914) 592-9101
Heath Company
Benton Harbor, Michigan 49-022
(616) 982-3200
571
-------
Hipotronics Inc.
Route 22
Brewster, New York 10509
(914) 279-8031
ILC Data Device Corporation .
105 Wilbur Place
Prpt. Intl. Plaza
Bohemia, New York 11716
(516) 567-5600
Kepco Inc.
131-38 Sanford Avenue
Flushing, New York 11352
(212) 461-7000
Pearson Electronics Inc.
4007 Transport Street
Palo Alto, California 94303
(415) 494-6444
Sensitive Research Instruments
25 Dock Street
Mr. Vernon, New York 10550
(914) 699-9717
A representative example of a voltage divider made by Hipo-
tronics has a guaranteed accuracy of 0.5% DC and 1.0% AC. There
are three stock models available, 50 KV, 100 KV, and 200 KV with
other models with ratings to one megavolt available on request.
Some of the specifications for the standard models are given
below:283
Model KV50A Model KV100A Model KV200A
Accuracy:
DC
AC
Tracking
Movement
Meter:
Scale
Size
Voltage Coefficient:
DC
AC
Frequency response
Connecting cable
Meter ranges (KV)
Volts Division
0.5%
1.0%
0.5%
Taut band
0.5%
1.0%
0.5%
Taut band
0.5%
1.0%
0.5%
Taut band
100 divisions 100 divisions 100 divisions
mirror scale mirror scale mirror scale
5%" 5V 5V
0.025%/C
0.025%/C
0.025%/C
DC and 40
to 1000 Hz
25 feet
0-10/25/50
100/250/500
DC and 40
to 1000 Hz
25 feet
0-20/50/100
200/500/1000
DC and 40
to 1000 Hz
25 feet
0-40/100/200
400/1000/2000
572
-------
Model KV50A Model KV100A Model KV200A
Impedance 190 megohms 380 megohms 760 megohms
§ 200 pfd. @ 100 pfd. § 50 pfd.
Size 8%" W x 8%" W x 9%" W x
10*5" D x 10%" D x 10V D x
15%" H 15%" H 40" H
Opacity Meters
Opacity meters can be used effectively in monitoring the per-
formance of emission control equipment continuously. In addition,
optical density output can be correlated with par.iculate grain
loading to allow determination of mass emissions on a continuous
basis. Opacity meters are invaluable in gauging precipitator
performance quickly when small changes are made in coal, precipi-
tator controls, or boiler conditions. Some of the more important
variables which affect performance the most are boiler load, boiler
outlet gas temperature, boiler excess air level, precipitator
operating voltage, precipitator rapping intensity and direction,
and precipitator internal condition.
A number of techniques are used to determine relative stack
emission levels. These techniques and corresponding instrumentation
were discussed in detail in Section 7 of this report.
Hopper Level Meters
Preventing precipitator hoppers from completely filling with
fly ash is extremely important. Overflow can lead to shorted
electrical systems or fly ash reentrainment, either of which
would adversely affect precipitator performance. A number of
hopper level detectors have been developed to help eliminate the
overflow problem. These detectors have been previously discussed
in Section 4. Some of the principles of operation used in de-
tection are:
Non-contacting radiation principle - a narrow beam of gamma
rays is directed across the hopper to a radiation detector located
on the opposite wall. The rays are absorbed when ash builds up
causing a relay to activate an alarm.
Rod oscillation dampening - a rod is installed at the desired
.ash level. A drive coil drives the rod into self-sustained mechan-
ical, oscillations and a signal is produced by a pick-up coil
located opposite the drive coil. When fly ash reaches the level
of the rod, a dampening of the oscillations occurs and the signal
from the pick-up coil is reduced.
Capacitance sensor assembly - the detector assembly senses
a change in ash level as a function of the capacitance change
573
-------
between the detector and the vessel wall. This change is then
transmitted to a control instrument.
Radio frequency - a low power RF signal is radiated from a
sensing probe and changes in the impedance of the probe caused by
a change in ash level are monitored.
After alarms are given indicating dangerous accumulations of
fly ash, systems for removal of the ash are activated. These
systems are discussed in detail in Section 4.
574
-------
SECTION 12
AN ELECTROSTATIC PRECIPITATOR COMPUTER MODEL
INTRODUCTION
In recent years, increasing emphasis has been placed on
developing theoretical relationships which accurately describe
the individual physical mechanisms involved in the precipitation
process and on incorporating these relationships into a complete
mathematical model for electrostatic precipitation. From'a
practical standpoint, a reliable theoretical model for electro-
static precipitation would offer several valuable applications:
(1) precipitator design could be easily and completely
performed by calculation from fundamental principles;
(2) a theoretical model could be used in conjunction with
a pilot-plant study in order to design a full-scale
precipitator;
(3) precipitator bids submitted by various manufacturers
could be evaluated by a purchaser with respect to
meeting the design efficiency and the costs necessary
to obtain the design efficiency;
(4) the optimum operating efficiency of an existing pre-
cipitator could be established and the capability to
meet particulate emissions standards could be ascer-
tained; and
(5) an existing precipitator performing below its optimum
efficiency could be analyzed with respect to the different
operating variables in a procedure to troubleshoot and
diagnose problem areas.
In addition to its many applications, a mathematical model
can be a valuable tool for analyzing precipitator performance due
to its cost- and time-savings capability. The approach is cost-
effective because it (1) allows for the analysis and projection
of precipitator operation based on a limited amount of data (ex-
tensive field testing is not necessary), (2) can predict trends
caused by changing certain, precipitator parameters and thus, in
.many cases, can prevent costly modifications to a precipitator
which will not significantly improve the performance, (3) can be
575
-------
used as a tool in sizing precipitators and prevent excessive costs
due to undersizing or significant oversizing, and (4) can be used
to obtain large amounts of information without extensive use of
manpower but, instead, with reasonable use of a computer.
The approach is time-effective because (1) large amounts of
information can be generated quickly, (2) it does not necessarily
depend on time-consuming field tests which involve travel, ex-
tensive analysis, and plant and precipitator shut-downs, (3) it
can prevent losses in time due to unnecessary or insufficient
modifications to a precipitator, and (4) it can prevent losses
in time due to the construction of an undersized precipitator.
In this section, the latest version137'152 of a mathematical
model of electrostatic precipitation developed under the sponsor-
ship of the U.S. Environmental Protection Agency is briefly des-
cribed. Since the model is described in great detail elsewhere,
the capabilities and applications of the model will be stressed
here, rather than mathematical details. In the latest version,
earlier work153 has been improved and extended. Major improvements
to the fundamental basis of the model include the capability of
generating theoretical voltage-current characteristics for wire-
plate geometries, a new method for describing the effects of
rapping reentrainment, a new procedure for accounting for the
effects of particles on the electrical conditions, and the incor-
poration of experimentally determined correction factors to account
for unmodeled effects. The computer program which performs the
calculations in the model has been made more user-oriented by
making the input data less cumbersome, by making the output data
more complete, by making modifications which save computer time,
and by providing for the construction of log-normal particle size
distributions.
CAPABILITIES OF THE MODEL
The present version of the model has the following capabilities:
(1) it predicts collection efficiency as a function of particle
diameter, electrical operating conditions, and gas properties;
(2) it can calculate clean-plate, clean-air voltage-current
characteristics for wire-plate geometries;
(3) it determines particle charging by unipolar ions as a
function of particle diameter, electrical conditions, and residence
time;
(4) it can estimate the effects of particles on the electrical
conditions under the assumption that effects due to the particulate
layer can be ignored;
(5) it accounts for electrical sectionalization;
576
-------
(6) it predicts particle capture at the collection electrode
based on the assumptions of completely random, turbulent flow,
uniform gas velocity, and particle migration velocities which are
small compared to the gas velocity?
(7) it employs empirical correction factors which adjust the
particle migration velocities obtained without rapping losses in
order to account for unmodeled effects;
(8) it accounts for the nonideal effects of nonuniform gas
velocity distribution, gas bypassage of electrified regions, and
particle reentrainraent from causes other than rapping by using
empirical correction factors to scale down the ideally calculated
particle migration velocities; and
(9) it accounts for rapping reentrainment by using empirical
relationships for the quantity and size distribution of the re-
entrained mass.
In its present form, the model has the capability of predicting
trends caused by changes in specific collection area, applied vol-
tage/ current density, mass loading, and particle size distribution.
Comparisons of the predictions of the model with laboratory-scale
precipitators138'2 2 8 5 and full-scale precipitators collecting
fly ash from coal-fired boilers19'285 indicate that the model can
be used successfully to predict precipitator performance.
The mathematical model is based on an exponential-type re-
lationship given by equation (2) . Although the previously discussed
assumptions upon which equation (2) is derived are never completely
satisfied in an industrial precipitator, they can be closely
approached with respect to the treatment of fine particles.
The assumption that the particle migration velocity near the
collection surface is constant for all particles has the most
significant' effect on the structure of the model. This assump-
tion implies two things: (1) all particles are of the same diameter
and (2) the electrical conditions are constant.
Because all particles entering a precipitator are not of the
same diameter, the assumption of uniform particle diameters creates
a problem. This problem is dealt with in the model by performing
all calculations for single-diameter particles and then summing
the results to determine the -effect of the. electrostatic precipi-
tation process on the entire particle size distribution.
Because the electrical conditions change along the length of
a precipitator, the assumption o.f constant electrical conditions
creates a problem. This problem is dealt with in the model by
dividing the precipitator into small length increments. These
577
-------
length increments can be made small enough that the electrical
conditions remain essentially constant over the increment. The
number of particles of a given diameter which are collected in
the different length increments are summed to determine the col-
lection efficiency of particles of a single diameter over the
entire length of the precipitator.
In summary, a precipitator is divided into essentially many
small precipitators in series. Equation (2) is valid in each of
these small precipitators for fine particles of a given diameter.
The collection fraction, n. ., for the ith particle size in
1' 3
the jth increment of length of the precipitator is mathematically
represented in the form
n. . = 1 - exp (-w. . A./Q)
1 / J x / J J
(70)
where w. . (m/sec) is the migration velocity near the collection
3- /1
electrode of the ith particle size in the jth increment of length
and A.(m2) is the collection plate area in the* jth increment of
length.
The collection fraction (fractional efficiency) n^ for a given
particle size over the entire length of the precipitator is deter-
mined from
where N. .is the number of particles of the ith particle size per
1 r 3
cubic meter of gas entering the jth increment.
^
Effective or length-averaged migration velocities (w^) are
calculated for the different particle diameters from
« • ln <-> ' <72)
2
where AT (m2) is the total collecting area.
The overall mass collection efficiency n for the entire poly-
disperse aerosol is obtained from
(73)
578
-------
where P^ is the percentage by mass of the ith particle size in
the inlet size distribution.
In order to determine the migration velocities for use in
equation (70) , the electrical conditions and the particle charging
process in a precipitator must be modeled. If the operating vol-
tage and current density are known, then the electric potential
and electric field distributions are determined by using a re-
laxation technique.286'287 In this numerical technique, the
appropriate partial differential equations which describe the
electrodynamic field are solved simultaneously under boundary
conditions existing in a wire-plate geometry. in order to find
the solutions for the electric potential and space charge density
distributions, the known boundary conditions on applied voltage
and current density are held fixed while the space charge density
at the wire is adjusted until all the boundary conditions are
satisfied. For each choice of space charge density at the wire,
.the procedure iterates on a grid of electric potential and space
charge density until convergence is obtained and then checks to
see if the boundary condition on the current density is met. If
the boundary condition on the current density is not met, then
the space charge density at the wire is adjusted and the iteration
procedure is repeated.
Particle charge is calculated by using a unipolar, ionic-
charging theory.3'588 Particle charge is predicted as a function
of particle diameter, exposure time, and electrical conditions.
The charging equation is derived based on concepts from kinetic
theory and determines the charging rate in terms of the probability
of collisions between particles and ions. The theory accounts
simultaneously for the effects of field and thermal charging and
accounts for the effect of the applied electric field on the ther-
mal charging process.
The nonideal effects of major importance in a precipitator
are (1) nonuniform gas velocity distribution, (2) gas bypassage
of electrified regions, and (3) particle reentrainment. These
nonideal effects will reduce the ideal collection efficiency that
may be achieved by a precipitator operating with a given specific
collection area. Since the model is structured around an ex-
ponential-type equation for individual particle diameters, it is
convenient to represent certain nonideal effects in the form of
correction factors which apply to the exponential argument. The
model employs correction factors which are used as divisors for
the ideally calculated effective migration velocities in order to
account for nonuniform gas velocity distribution, gas bypassage,
and particle reentrainment without rapping.289'290 The resulting
apparent effective migration velocities are empirical quantities.
LATEST IMPROVEMENTS TO THE MODEL
Calculation Of Voltaae-Current Characteristics
579
-------
A new technique" has been developed for theoretically cal-
culating electrical conditions in wire-plate geometries and has
been incorporated into the model. In this numerical technique,
the appropriate partial differential equations which describe the
electrodvnamic field are solved simultaneously, subject to a suit-
able choice of boundary conditions. The procedure yields the
voltage-current curve for a given wire-plate geometry and determines
the electric potential, electric field, and charge density dis-
tributions for each point on the curve.
The key element in this technique is the theoretical calcu-
lation of the space charge density near the corona wire for a
specified current density at the plate. In order to find the
solutions for the electric potential and space charge density
distributions, the known boundary conditions on space charge
density near the wire and current density are held fixed while
the electric potential at the wire is adjusted until all boundary
conditions are satisfied. For each choice of electric potential
at the wire, the procedure iterates on a grid of electric po-
tential and space charge density until convergence is obtained
and then checks to see if the boundary condition on the current
density is met. If the boundary condition on the current density
is not met, then the electric potential at the wire is adjusted
and the iteration procedure is repeated. The entire procedure
is repeated for increasing values of current density in order to
generate a voltage-current curve. Comparisons'*'291 of the pre-
dictions of this technique with experimental data show that the
agreement between theory and experiment is within 15%.
Method For Predicting Trends Due To Particulate Space Charge
A new method has been incorporated into the model in order
to provide a more comprehensive representation of the effects of
particulate space charge on the electrical operating conditions
in a precipitator. In this method, the precipitator is divided
into successive length increments which are equal to the wire-to-
wire spacing. Each of these increments is divided into several
subincrements. The first calculation in the procedure involves
the determination of a clean-gas, voltage-current curve which
terminates at some specified value of applied voltage. At the
specified applied voltage, the average electric field and ion
density are calculated in each subincrement. This allows for
the nonuniformity of the electric field and current density dis-
tributions to be taken into account.
As initially uncharged particles enter and proceed through
the precipitator, the mechanisms of particle charging and particle
collection are considered in each subincrement. In each subin-
crement, the average ion density, average particulate density,
weighted particulate mobility, and effective mobility due to both
ions and particles are determined. At the end of each increment,
the effective mobilities for the subincrements are averaged in
580
-------
order to obtain an average effective mobility for the increment.
Then, for the specified value of applied voltage, the average
effective mobility is used to determine the reduced current for
the increment by either calculating a new voltage-current curve
or using an approximation procedure. Although it is not presently
utilized, the method allows for iterations over each length in-
crement so that schemes which ensure self-consistency can be
implemented at a future date.
In its present state of development, this method provides
good estimates of reduced current due to the presence of particles.
The reduced current is a function of mass loading, particle size
distribution, gas volume flow, and position along the length of
the precipitator. However, this method does not have the capability
of predicting the redistribution of the electric field due to the
presence of particles. Work is going on at the present time to
improve the model in this respect.
Method For Estimating Effects Due To Rapping Reentrainment
As part of a program sponsored by the Electric Power Research
Institute, an approach to representing losses in collection effi-
ciency due to rapping reentrainment has been developed based on
studies performed on six different full-scale precipitators
collecting fly ash.19 These studies have been discussed earlier
in this text. In these studies, outlet mass loadings and particle
size distributions were measured both with rapping losses and without
rapping losses. Outlet mass loadings and particle size distri-
butions which can be attributed to rapping were obtained based on
the data acquired in these studies. The results of these studies
have been incorporated into the model.
The rapping emissions obtained from the measurements are
graphed in Figure 273 as a function of the amount of dust calcu-
lated to have been removed by the last electrical section. The
dust removal in the last electrical section was approximated by
using an exponential relationship for the collection process and
the overall mass collection fraction determined from mass train
measurements under normal operating conditions, as described earlier.
These data suggest a correlation between rapping losses and parti-
culate collection rate in the last electrical section. Data for
the two hot-side installations (4 and 6) which were tested show
higher rapping losses than for the cold-side units, and, thus, hot-
and cold-side units are treated differently in the model with re-
spect to rapping reentrainment.
The apparent particle size distribution of emissions attri-
butable to rapping at each installation was obtained by subtracting
the cumulative distributions during nonrapping periods from those
with rappers in operation and dividing by the total emissions
(based on impactor measurements) • resulting-from rapping in order
to obtain a cumulative percent distribution. Although the data
581
-------
indicated considerable scatter, the average particle size dis-
tribution shown in Figure 280 has been constructed for use in
modeling rapping puffs. In the model, the data are approximated
by a log-normal distribution with a mass median diameter of 6.0
um and a geometric standard deviation of 2.5 as shown in Figure
299.
In summary, the model determines a rapping puff by using the
information in Figure 278 to obtain the outlet mass loading due
to rapping and by using a log-normal approximation to the data in
Figure 280 to represent the particle size distribution of the
outlet mass loading due to rapping. This "rapping puff" is added
to the "no-rap" outlet omissions to obtain the total outlet emis-
sions as a function of mass loading and partic_e size distribution.
Empirical Corrections To No-Rap Migration Velocities
Comparisons of measured apparent effective migration velocities
for full-scale precipitators under "no-rap" conditions with those
predicted by the model indicate that the field-measured values
exceed the theoretically projected values (in the absence of back
corona, excessive sparking, or severe mechanical problems) in the
smaller size range. Based on these comparisons, a size-dependent
correction factor has been constructed and incorporated into the
model.19 This correction factor is shown in Figure 300.
The empirical correction factor accounts for those effects
which enhance particle collection efficiency but are not included
in the present model. These effects might include particle charging
near corona wires, particle charging by free electrons, particle
concentration gradients, the electric wind, and flow field pheno-
mena. In future work which is planned, efforts will be made to
develop appropriate theoretical relationships to describe the above
effects and to incorporate them into a more comprehensive model for
electrostatic precipitation.
User-Oriented Improvements
The computer program which performs the calculations in the
model has been modified to make the input data less cumbersome and
the output data more complete. The performance of a precipitator
can be analyzed as a function of particle size distribution, current
density, specific collection area, and nonideal conditions without
repetition of input data which remain fixed. All input data are
now printed out in a format which is easily utilized. A summary
table of precipitator operating conditions and performance is
printed out as the last section of data for a given set of con-
ditions.
Several modifications have been made in order to save computer
time. The particle charging algorithm has been modified, and this
has decreased the computer time required for particle charging
582
-------
tt
Ul
ttl
Log-normal approxinMtion
for MMO -6-0 um.
II I 1 I 1 !
20 30 40 50 60 70 30
%LESS THAN
90 95
3540-288
Figure 299.
Average rapping puff size distribution and log-
normal approximation for six full-scale precipi-
tators. These data are a result of work sponsored
by the Electric Power Research Institute.1
583
-------
_ 3
o
c.
c,
O
2
3^
O
UJ
cr
v>
I I | I I I
I
1
1 J I
0.2
0.3
0.4 0.5 0.6
0.8 1.0 1.5
DIAMETER, tan
2.0 Z5 3.0
5.0
3(40-219
Figure 300.
Empirical correction factors for the "no-rap"
migration velocities calculated from the mathematical
model. This work was sponsored by the Electric
Power Research Institute.19
584
-------
calculations by approximately 40%. In addition, particle charge
calculations for a given diameter will terminate in a given elec-
trical section whenever the charging rate becomes negligible. This
can reduce the time required to perform particle charging calcu-
lations by up to a factor of two or more in some cases. The
computer program has been modified so that several sets of nonideal
conditions can be analyzed in conjunction with the results of one
ideal calculation. This allows for the analysis of an extended
range of nonideal conditions with only a small increase in computer
time. As another means of saving computer time, the computer pro-
gram now contains an estimation procedure for use in analyzing
precipitator performance. This procedure results in considerable
savings in computer time since involved numerical techniques are
not employed. The estimation procedure runs approximately 20
times faster than the rigorous calculation. This procedure can
be used to good advantage to determine gross trends or to establish
a limited range of interest in which to apply the more rigorous
calculation. The procedure can also be used to good advantage for
checking the validity of input data before making extensive rigor-
ous calculations.
The computer program now has the capability of constructing
log-normal particle size distributions based on specified values
of the mass median diameter and geometric standard deviation. This-
capability can be used to construct inlet and rapping puff particle
size distributions. Thus, the effects of different log-normal
particle size distributions can be readily obtained. Also, the
program can fit any specified particle size distribution to a log-
normal distribution.
APPLICATIONS AND USEFULNESS OF THE MODEL
The different practical applications of the model have been
discussed elsewhere.3'137'153 These include the examination of
the effects of particle size distribution, electrical conditions,
specific collection area, dust resistivity, and nonideal conditions
on the performance of a precipitator. These applications have now
been incorporated into procedures for troubleshooting and sizing
precipitators.137 These procedures, which provide specific guide-
lines for applying the model to troubleshooting and sizing appli-
cations, are discussed next in order to demonstrate the usefulness
of the model.
Use Of The Model For Troubleshooting
The mathematical model of electrostatic precipitation can be
used as a tool in troubleshooting precipitators that are not meeting
the overall mass collection efficiency which is expected or antici-
pated. When using the model for troubleshooting, certain experi-
mental data should be obtained in order to properly utilize the
model. These data include operating voltages and currents in the
different electrical sections, inlet mass loading and particle
585
-------
size distribution, ash resistivity, average gas flow rate and
velocity, and average gas temperature and pressure. By using
these limited experimental data, the geometry of the precipitator,
and the mathematical model, certain steps which are given below
can be taken in an attempt to diagnose the possible reason or
reasons for the level of performance of the precipitator.
Step 1: Determine optimum collection efficiency.
The model is used to simulate the operation of the precipi-
tator under ideal, no-rap conditions (a =0 and S = 0) with the
5
actual operating parameters, where a is the normalized standard
deviation of the gas velocity distribution and S is the fraction
of the gas volume bypassing each electrical section. This calcu-
lation establishes the optimum overall mass collection efficiency
that can be expected under the given operating conditions. It
should be noted that this optimum efficiency may not always repre-
sent the best performance of the precipitator since accumulation
of material on the discharge and collection electrodes, broken
discharge electrodes, electrode misalignment, or operation of the
precipitator at lower than permissible voltages and currents would
result in less than optimum electrical operating conditions. If
possible, measures should be taken to ensure that the electrical
conditions in the precipitator are at their best when obtaining
data for use in the troubleshooting procedure. In any event, the
starting point in the troubleshooting procedure can be taken to be
the calculated optimum efficiency under the actual operating con-
ditions .
Step 2; Check to see if the calculated optimum efficiency is
equal to or less than the measured value.
If the calculated optimum value of efficiency is equal to or
less than the measured value, then the precipitator can be assumed
to be performing as well as possible for the given set of operating
conditions. Changes in the inlet particle size distribution, the
electrical operating conditions, or the gas volume flow can result
in a reduction of collection efficiency for a given precipitator
even though the precipitator is performing at its best. Thus, in
certain casese a precipitator may not be able to attain the overall
mass collection efficiency it once achieved or was designed to
achieve solely due to a change in the process variables. As a
consequence, the precipitator may no longer be sized properly for
the operating conditions encountered. The options that are avail-
able for improving the performance of the precipitator are limited
to the possible improvement of the electrical operating conditions
or a reduction in the gas flow rate through the precipitator.
Step 3: Check to see if the calculated optimum efficiency is
only a little larger than the measured value.
586
-------
If the calculated optimum value of efficiency is only a
little larger than the measured value, then the precipitator is
probably functioning well but nonideal conditions are having some
effect on the performance. In this case, calculations should be
made with the model in order to obtain NO-RAP -f RAP overall mass
collection efficiencies for various small values of a and S and
g
the rapping reentralnment parameters which are built into the
computer program. If the measured efficiency can be predicted
by the model with values of a £ 0.25 and S <_ 0.1, then it is
questionable whether or not improvements in the gas flow pro-
perties and mechanical design will result in an appreciable im-
provement in precipitator performance. A less ccstly and possibly
more profitable exercise would be to vary the rapping intensities
and frequencies in an attempt to minimize losses in collection
efficiency due to rapping reentrainment. If a > 0.25 or S > 0.1,
then these quantities should be measured. If the measured values
of a and S are consistent with those predicted by the model, then
the gas flow properties and mechanical design should be improved.
Step 4; Check to see if the calculated optimum efficiency
is significantly larger than the measured value.
If the calculated optimum value of efficiency is significantly
larger than the measured value, then the precipitator is functioning
poorly. Poor performance of a precipitator may be due to either
one or a combination of several factors that can be analyzed with
the model. These factors include the electrical operating con-
ditions, nonuniform gas velocity distribution, gas bypassage of
electrified regions, particle reentrainment without rapping, and
rapping reentrainment. In the following steps, procedures are
outlined that can be taken in an attempt to pinpoint the problem
areas.
Step 5: Determine whether or not the operating currents are
completely useful in the precipitation process.
At this point, the electrical operating conditions should be
examined in order to determine whether or not the operating cur-
rents are completely useful in the precipitation process. If
excessive sparking or back corona is occurring in the precipitator,
thea the measured currents will not be totally useful in the pre-
cipitation proces's and, in fact, the nature of the currents may
be very detrimental to precipitator performance. Use in the model
of currents measured under these conditions will result in the
prediction of much higher collection efficiencies than will be
attained, by the precipitator.
Step 5a: Check for excessive sparking.
587
-------
Sparking results in localized currents that are not very
effective in charging particles. In addition, excessive sparking
can lead to increased particle reentrainment by producing dis-
ruptions at the surface of the collected particulate layer and by
producing reduced holding forces over large regions of the col-
lected layer due to reduced currents to these regions.
If sparking is occurring, then the extent of the sparking
should be determined by using spark rate meters or other appro-
priate instrumentation. If excessive sparking "is occurring, then
the applied voltage should be lowered, until the spark rate is at
a level which is not detrimental to the performance of the pre-
cipitator. Although the operating voltages and currents will be
reduced, the performance of the precipitator will improve and the
use of these operating electrical conditions in the model will
give better agreement- between predicted and measured collection
efficiencies.
Step 5b; Check for the existence of back corona.
If excessive sparking is not occurring, then a check should
be made to determine whether or not a condition of back corona
exists in the precipitator. When back corona exists, both positive
and negative ions move in the interelectrode space and this results
in a reduction in the negative charge that can be acquired by a
particle.
Two methods can be used to check for the existence of back
corona. First, the measured value of ash resistivity and Figure
208 can be used to estimate the maximum allowable current density.
If the current density in the precipitator greatly exceeds this
value, then the precipitator is probably operating in back corona.
As a second method of checking for the existence of back corona,
the voltage-current curves for the different electrical sections
can be checked to see if at some point on the curve increased cur-
rent is obtained at a reduced applied voltage. If this is the case
and the precipitator is operating in this region of the voltage-
current curve, then back corona is occurring in the precipitator.
If back corona is occurring, then the applied voltage should
be lowered in order to obtain a current density which will not
lead to the formation of back corona. The reduced voltages and
currents will result in improved performance of the precipitator
and the use of these operating electrical conditions in the model
will give better agreement between predicted and measured col-
lection efficiencies.
Step 5c: Consider electrode misalignment.
As a further consideration concerning the electrical conditions,
the electrode alignment should be taken into account. Consideration
of electrode alignment is especially important when troubleshooting
588
-------
hot precipitators. In hot precipitators, the collection plates
may buckle if proper precautions have not been taken to allow for
the expansion of the plates at the elevated temperatures. If
buckling of the plates occurs, then higher currents will be mea-
sured but they will be localized. Currents of this type are not
desirable for treating particles. The existence of this type of
misalignment should be, evidenced by steep voltage-current curves
with a narrow voltage range from corona initiation to sparkover.
Use in the model of measured currents obtained from this type of
situation will result in predicted collection efficiencies that
are well above those which are attained.
Step 6; Estimate the effect that various nonideal conditions
could have on the performance of the precipitator.
If the poor performance of the precipitator cannot be traced
to the electrical operating conditions, then the nonideal effects
.of nonuniform gas velocity distribution, gas bypassage of elec-
trified regions, and particle reentrainment should be considered
next. The effect of a and S on the NO-RAP + RAP overall mass
9
collection efficiency of the precipitator should be analyzed in
a systematic fashion with the model.
Step 6 a; Estimate the possible effect of nonuniform velocity
distribution on the performance of the precipitator.
In order to determine whether or not a nonuniform gas velocity
distribution could be responsible for the poor performance of the
precipitator, calculations should be made for S = 0 and values of
G ranging from 0 to at least 2.0. If a certain value of a in
the chosen range produces the necessary reduction in collection
efficiency and this value is not completely out of line with
available information concerning the gas flow, interfacing of
the precipitator with the duct work, existence of gas diffusion
plates, etc., then the actual value of cr should be determined
experimentally by making a velocity traverse in a plane at the
inlet of the precipitator. If the measured value of a is greater
than 0.25, then measures should be taken to improve the gas flow
distribution.
Step 6b: Estimate the possible effect of gas sneakage and/or
particle reentrainment without rapping on the per-
formance of the precipitator.
In order to determine the extent of gas bypassage of the
electrified regions and/or particle reentrainment without rapping
that would be necessary to cause the poor performance of the pre-
cipitator, calculations should be made for a =0 and values of
S ranging from 0 to 0.9. There will be a value of S in this range
that will result in the necessary reduction in collection efficiency.
589
-------
Depending on the value of S, different interpretations can be
made. If S is not too large (S £ 0.2), then the poor performance
might be attributed to either excessive gas bypassage of the
electrified regions or- excessive particle reentralnment without
rapping or very poor gas velocity distribution or a combination
of all three of these effects where neither effect alone is very
detrimental to the performance of the precipitator. In this
case, measurements should be made under air-load conditions to
determine a and the fraction of the gas volume flow passing
through non-electrified regions in each baffled section. If the
measured values of these quantities are such that they can account
for a major part of the reduction in collection efficiency, then
the appropriate corrective measures can be made -.0 the mechanical
design of the precipitator. If the measured values of these
quantities are such that they can not account for a major part
of the reduction in collection efficiency, then it is possible
that particle reentrainment without rapping is having an adverse
effect on the performance of the precipitator. This could be due
to factors which include a high average gas velocity, a very non-
uniform gas velocity distribution, a low value of ash resistivity,
excessive sparking, low operating current densities, and hopper
problems. All of these factors can lead to particle reentrainment
from causes other than rapping and should be taken into account
in the troubleshooting analysis.
If S is large (S > 0.2), then the poor performance of the
precipitator is probably due primarily to extremely excessive
particle reenrrainment. This could be a result of one or more
of the same factors mentioned above. In this case, reentrainment
of particles from the hoppers, caused by poor gas flow qualities
or by hopper malfunctions, should receive more serious attention
as a possible cause of the poor performance. If very large values
of S are needed to predict the reduction in collection efficiency,
then it is also possible that rapping reentrainment is occurring
to a much greater extent than that predicted by the rapping re-
entrainment calculation and that this is reflected in the value
of S. If the value of S is large, then hopper operation should
be checked, outlet mass loadings should be obtained with and
without rapping, and real-time measurements of the outlet mass
loading should be made. These measures should indicate whether
the problem is due to hopper operation or rapping reentrainment
or reentrainment without rapping or some combination of the three.
The troubleshooting procedure described above can be a valu-
able tool in helping to diagnose the causes of poor performance of
a precipitator. Since the procedure involves only limited experi-
mental data, it is not costly to perform. Use of the procedure
can also result in time and cost savings by giving direction and
helping to focus on those quantities which actually need to be
measured. A further benefit of using the procedure is the possi-
bility that costly modifications to the precipitator that will not
result in significant improvement in the performance can be avoided,
590
-------
Use Of The Model For Sizing Of Precipitators
The mathematical model of electrostatic precipitation can be
used as a guide in sizing precipitators. Although this method of
sizing precipitators can be very successful, care must be taken to
ensure proper usage of the model and to prevent the use of erroneous
input data. Misuse of the model could result in a large error in
sizing a precipitator.
When using the model for the purpose of sizing a precipitator,
certain data which are used as input to the model should be obtained
from measurements made using the actual gas stream or one which will
be very similar to the actual gas stream. If a cas stream other
than the actual one is used to obtain representative data, then
steps should be taken to assure that the process variables pro-
ducing the effluent gas stream and particles are not too different.
Also, it is very important that the temperature and composition of
the gas stream be close to that which will be experienced in the
precipitator to be sized.
The following is a list and discussion of those quantities
whose values should be determined from measurements under con-
ditions similar to those which will be experienced in the precipi-
tator to be sized:
The temperature, pressure, and composition of the gas stream
should be measured.
The particle size distribution and mass loading in the gas
stream should be measured at a location from the source that would
be representative of where the gas stream would enter the precipi-
tator .
The bulk resistivity of the particles should be measured both
in situ and in the laboratory. In making these measurements, the
gaseous environment must not only be preserved but, in addition,
the electric field strength at which the measurements are made
must be 'close to that which will .be experienced in the precipitator
in order to obtain the appropriate measurement. If agreement can
not be obtained between the in situ and laboratory measurement,
then the higher of the two values should be used in order to size
the precipitator.
The effective mobility of the negative ions which would be
produced during negative corona discharge in the gas stream should
be measured.
If any or all of the above quantities are not measured or can not
be measured, then .their values can. only be. estimated by using the
best data available and prior experience for similar sets of con-
ditions. Using values of these quantities that are not obtained
from measurements with the actual or a similar gas stream is risky
and these values should be estimated in a conservative manner.
591
-------
Once the values of the quantities discussed above are de-
termined, the model can be used in a procedure to predict what
precipitator sizes are needed to attain various levels of overall
mass collection efficiency.. .The steps which should be taken in
this procedure are discussed next.
Step 1; Establish an estimate of the electrical conditions
under which the precipitator should operate.
In establishing an estimate of the electrical operating con-
ditions, a determination of the maximum allowable current density
should be made first. The maximum allowable current density can
be estimated by using the determined Value of ash resistivity
and the curve given in Figure 208. If voltage-c ,rrent data are
available for similar conditions, then these should also be used
in helping to determine the maximum allowable current density.
Once the maximum allowable current density is estimated,
then the applied voltages which will produce this current density
in the different electrical sections must be estimated. These
voltages may be obtained from voltage-current' data which are
available for similar conditions except it is not necessary that
the ash resistivity be duplicated. Alternatively, the model can
be used with the option which calculates voltage-current curves
for a wire-plate geometry in order to determine voltage-current
characteristics with the effect of resistivity being ignored.
Then, the applied voltages necessary to produce the maximum allow-
able current density can be estimated. In utilizing the voltage-
current calculation, a value for the roughness factor of the
discharge electrodes must be specified. The value of this para-
meter normally lies between 0.5 and 1.0 and small changes in-the
value lead to significantly different results. Since the value
of this parameter is difficult to project in advance and the value
changes during the operation of the precipitator, care must be
taken in specifying this value and in analyzing the results ob-
tained. Calculations used to size the precipitator should be
made for several values of the roughness factor between 0.5 and
1.0 and the most conservative prediction of precipitator per-
formance should be used as the basis for sizing the precipitator.
Also, if values of the roughness factor in a particular range
yield results that are obviously out of line with similar appli-
cations, then this range should be eliminated from consideration.
Since the ash resistivity is difficult to determine precisely
and environmental changes can produce significant changes in its
value, the size of a precipitator should be determined based on
a maximum allowable current density which is estimated based on
a somewhat higher value of resistivity than anticipated. A rea-
sonable and conservative approach might be to base the estimated
maximum allowable current density on a value of resistivity that
is one-half an order of magnitude greater than the; anticipated
value.
592
-------
Step 2; Determine the geometrical parameters to be used.
At this point, the geometrical characteristics of the pre-
cipitator should be established since these data are necessary as
input to the model. The values of the plate spacing, discharge
electrode spacing, and diameter of the discharge electrodes which
are used in the model must be the actual values. In order to
size the precipitator, it is not necessary to know the actual
values of the cross-sectional area, height, area, and number of
the plates, length of the electrical sections, or total elec-
trified length. Although the values of these quantities can be
chosen arbitrarily, they should be as representative as possible.
In the model, different overall mass collect.-.on efficiencies
can be determined for different specific collection areas and then,
based on the actual gas volume flow through the precipitator,
the total collection plate area necessary to achieve a given
efficiency can be determined. Knowing the required collection
•plate area, the precipitator can be designed with respect to
cross-sectional area, plate height, and length. In designing the
precipitator so that it will have the required collection plate
area, certain considerations should be made. First, the height
of the collection plates should not be too high since this can
lead to increased reentrainment from rapping and to greater dif-
ficulty in providing sufficient rapping force to the entire area
of the plate. In practice, the height of collection plates ranges
from approximately 3.05 (10) to 12.2 (40) meters (feet). Second,
the precipitator should be long enough so that it can contain
several baffled, independent electrical sections. Increasing
the number of baffled electrical sections leads to better operating
electrical conditions and reduced losses in collection efficiency
due to gas sneakage and hopper boil-up. Third, the gas velocity
through the precipitator should be 1.53 m/sec (5 ft/sec) or less
in order to help prevent reentrainment without rapping and to
allow sufficient residence time to recollect material reentrained
due to rapping.
5tep 3; Determine, the nonideal conditions for which the
precipitator will be sized.
Since a certain degree of a gas flow nonuniformity and gas
bypassage of electrified regions and/or particle reentrainment
without rapping can be expected to exist in a precipitator, these
factors must be considered in sizing the precipitator. Experience
in simulating the operation of full-scale, industrial precipitators
indicates that values of a =0.25 and S = 0.1 are appropriate for
modeling precipitators which are in good working condition. Losses
in overall mass collection efficiency due to rapping reentrainment
are built into the model and cannot be varied without changing the
computer program itself. Since the procedure which determines the
effect of rapping reentrainment on precipitator performance is
593
-------
based on average data acquired from six different full-scale
precipitators, the effects of rapping reentrainmerit might not
be estimated in a conservative manner.
If a conservative approach is taken in sizing the precipi-
tator, then the values of o and S should be taken to be somewhat
higher than 0.25 and 0.1, respectively. Values of a = 0.4 and
S = 0.2 should be conservative. This value of S should also
allow for above average losses in collection efficiency due to
rapping reentrainment. If the precipitator is sized in a con-
servative manner, then the chances that the precipitator will be
able to meet the particulate emissions standards once it is built
are improved even though undesirable nonideal conditions exist.
As a consequence, the process producing the emissions does not
have to be shut down until the problems with the precipitator
are diagnosed and corrected. The problems with the precipitator
can be diagnosed with the troubleshooting procedure while the
precipitator is in operation and appropriate corrective measures
can be made during a scheduled shut down. Thus, in many cases,
the added cost of a conservative design can be partially or fully
recovered.
Step 4; Consider the effect of adverse changes in particle
size distribution in sizing the precipitator.
Since any decrease in the mass median diameter or increase in
the dispersiveness of the inlet particle size distribution will
result in a fundamental reduction in precipitator performance,
this factor should be considered in sizing a precipitator. Any
changes in the process variables controlling the source of the
emissions can result in significant changes in particle size dis-
tribution. Thus, the possibility of a change from the anticipated
particle size distribution to a less favorable one should be in-
corporated into the sising procedure. In a conservative approach,
the measured or anticipated inlet particle size distribution can
be fit to a log-normal distribution and the fitted mass median
diameter and geometric standard deviation can be decreased and
increased by 25%, respectively. These new values should then be
used in the model in order to obtain the inlet particle size dis-
tribution for use in sizing the precipitator.
Step 5: Generate a curve of overall mass collection efficiency
versus specific collection area.
At this point, since all appropriate input data have been or
can be determined, the computer program for the mathematical model
can be executed in order to size the precipitator. The precipitator
can be sized by generating a curve of overall mass collection effi-
ciency versus specific collection area.
Based on the curve of overall mass collection efficiency versus
specific collection area and the particulate emissions standard,
594
-------
the precipitator size needed to attain the required efficiency
can be determined. In sizing the precipitator in a conservative
manner, the precipitator should be sized to attain an efficiency
which is somewhat higher than that which is required. This is
necessary in order to provide a margin of safety in design ir-
respective of any uncertainties in operating parameters and of
any nonidealities which might exist. In order to provide this
margin of safety, the projected collection plate area needed to
attain the required efficiency should be increased by a certain
percentage, possibly 10-15%. This added collection plate area
is also an advantage in that it offers the possibility that the
precipitator will be able to adequately treat gas flows which
are somewhat higher than the design gas flow.
Step 6; Allow for the outage of electrical sections.
In designing the precipitator, a high degree of electrical
sectionalization should be provided. As stated previously, this
leads to improved electrical operating conditions. In addition,
if certain electrical sections are not working, this condition
does not disable a large portion of the precipitator.
In sizing a precipitator, proper allowance should be made
for the possibility that from time to time certain electrical
sections will not be functioning. This can be done by increasing
the collection plate area obtained in Step 5. The additional
collection plate area should be provided in the form of added
electrical sections. If reliable data or past experiences are
not sufficinet for estimating the number of electrical sections
that might be inoperable at any given time, than a reasonable
approach might be to add an extra electrical section for approxi-
mately every four electrical sections that are required in Step 5.
The above guidelines and procedure cover the important con-
siderations which must be made in sizing an electrostatic precipi-
tator. If the guidelines and procedure are followed correctly,
then the mathematical model of electrostatic precipitation can
be a valuable tool for sizing electrostatic precipitators. Since
the procedure includes reasonable conservative measures to account
for several different uncertainties, the cumulative effect should
lead to a precipitator which is sized conservatively but not
excessively oversized.
The procedure for sizing a precipitator can be utilized by
manufacturers to assist in designing a precipitator and by pur-
chasers to assess bids submitted by the various manufacturers.
It can also be used by government regulatory agencies in helping
to establish particulate emissions standards which are economically
feasible and consistent with the best available control technology.
The troubleshooting and sizing procedures can both be utilized
in conjunction with pilot precipitator studies. The troubleshooting
595
-------
procedure can be used to characterize the performance of the pilot
precipitator and to establish the values of the parameters charac-
terizing the operation of the precipitator. This will establish
baseline information for which the model predictions and experi-
mental data are in agreement. The sizing procedure can then be
used to project full-scale precipitator performance under various
operating conditions in order to obtain the size necessary to give
the required collection efficiency.
It should be noted that care should be taken in projecting
full-scale performance based on pilot data. Normally, better
electrical conditions can be obtained in a pilot unit than a full-
scale unit because of the reduced collection electrode area. In
addition, particle reentrainment characteristics, gas velocity
distribution, and gas bypassage of electrified regions in the
pilot unit and the constructed full-scale unit may differ signi-
ficantly.
596
-------
SECTION 13
FEATURES OF A WELL-EQUIPPED ELECTROSTATIC PRECIPITATOR
There are several, important features that a well-equipped
electrostatic precipitator should possess. These features are
necessary in order to achieve high collection efficiency, opera-
tional and mechanical reliability, and ease in locating potential
problems and in troubleshooting existing problems. In this
section, these features are listed and discussed. Most of these
features have been pointed out or discussed earlier in the text.
Thus, the following list serves to bring these features together
in a single location for easy reference.
• Adjustable gas flow distribution screens (or other devices)
should be located at the inlet of an electrostatic precipi-
tator in order to reduce the turbulence in the gas stream
and to improve- the gas velocity distribution. Adjustable
devices are needed because flow model studies or other
methods of prediction may not prove to be reliable. In
some cases two or more devices may be necessary in order
to achieve good gas flow qualities. (It has been demon-
strated that this can be done without incurring excessive
pressure drops). The average gas velocity entering the
electrostatic precipitator should be no higher than 1.22
m/sec (4 ft/sec). The uniformity of the gas velocity
distribution at the inlet of the electrostatic precipitator
should, as a minimum, meet existing IGCI requirements.
• The electrostatic precipitator should have, chambers which
can be isolated for on-line maintenance and repair. It
should have an adequate number of inlet and outlet sampling
ports for each chamber. A minimum of six is necessary at
each location in order to provide proper sampling access.
The sampling ports should be of 6 in. diameter pipe instead
of the commonly used 4 in. diameter pipe. This would
facilitate the design and use of sampling instrumentation.
Thermocouples should be located at the inlet and outlet of
each chamber for proper monitoring of temperature. The use
of induced draft fans will make gas and particulate sam-
pling less difficult and less hazardous. The electrostatic
precipitator should have a totally enclosed roof penthouse.
» The electrostatic precipitator should have hopper baffles
and baffles above the electrodes to minimize gas bypassage
597
-------
of electrified regions and to prevent significant gas flow
from occurring in the hoppers.
• The electrostatic precipitator should have at least four,
and preferably six, electrical sections in the direction
of gas flow. There should be adequate electrical section-
alization with no more than between 1,861 - 2,791 m2
(20,000 - 30,000 ft2) of collection plate area per
transformer/rectifier (TR) set with two bushings per TR
set. A rigid discharge electrode system is desirable
because of its stability and reliability. The collection
electrodes should be mounted in guides for proper alignment
and stability. A dried, heated purge air system should be
provided for keeping insulator feed-thri-s free of particles
and condensed gases. Secondary current and voltage panel
meters are needed for monitoring actual precipitator elec-
trical operating conditions and for troubleshooting. The
power supplies should have controllers which can operate
in either a spark rate or current limit mode to produce
the maximum useful voltages and currents. Each electri-
cal section should be provided with access from the inlet,
outlet, top, and bottom for ease of inspection, wire re-
placement, alignment, and collection of representative ash
samples, if necessary.
• The electrostatic precipitator should have independent
discharge and collection electrode rappers. The rapping
systems should be programmable with frequency and intensity
adjustment capability so that precipitator performance can
be optimized with respect to the rapping process. The
rapping system for the collection electrodes should be
capable of producing accelerations in all parts of the
plate of over 50 times that of the gravitational accelera-
tion. The discharge electrode system should be cleaned
by impulse rappers rather than vibrators. The hoppers
should be sufficiently heated or insulated to prevent con- .
densation and resultant pluggage. Hopper level indicators
should be installed to monitor hopper performance. Ash
collected in the hoppers should be removed with a system
which minimizes air flow into or out of the hoppers and
should be conveyed away with an air transport system.
• The outlet of the precipitator should be instrumented with
an opacity meter for continuous monitoring of precipitator
performance. This will provide continuous information
which will indicate changes in precipitator operation which
could be caused by changes in the process variables or pre-
cipitator malfunctions. The opacity information is also
useful in troubleshooting.
598
-------
REFERENCES
la. Engelbrecht, H. L. Air Flow Model Studies for Electrostatic
Precipitation, p. 72-73. From: Symposium on the Transfer
and Utilization of Particulate Control Technology: Volume 1.
Electrostatic Precipitators. EPA-600/7-79-?.44a, Environmental
Protection Agency, Research Triangle Park, North Carolina,
February 1979.
b. Szabo, M. and R. Gerstle. Electrostatic Precipitator Mal-
functions in the Electric Utility Industry, section 2, p. 16.
EPA-600/2-77-006, prepared by PEDCo for the Environmental
Protection Agency, Research Triangle Park, North Carolina,
January 1977.
2. Smith, W., K. Gushing, and J. McCain. Procedures Manual for
Electrostatic Precipitator Evaluation, p.18. EPA-600/7-77-059,
prepared by Southern Research Institute for the Environmental
Protection Agency, Research Triangle Park, North Carolina,
June 1977.
3. McDonald, J. and L. Sparks. A Precipitator Performance Model:
Application to the Nonferrous Metals Industry. Proceedings:
Particulate Collection Problems Using ESPs in the Metallurgical
Industry. EPA-600/2-77-208, U.S. Environmental Protection
Agency, Raleigh Durham, North Carolina, 1977. 72 pp.
4. McDonald, J., W. Smith, H. Spencer, and L. Sparks. A Mathe-
matical Model for Calculating Electrical Conditions in Wire-
Duct Electrostatic Precipitation Devices. J. Apply. Phys.,
43(6}:2231-2246, 1977.
5. Pauthenier, M. and M. Moreau-Hanot. Charging of Spherical
Particles in an Ionizing Field. J. Phys. Radium, 3(7):590-
613, 1932.
6. White, H. Particle Charging in Electrostatic Precipitation.
Trans. Amer. Inst. Elec. Eng. Part 1, 70:1186-1191, 1951.
7. Murphy, A., F. Adler, and G. Penney. A Theoretical Analysis
of the Effects of an Electric Field on the Charging of Fine
Particles. Trans. Amer. Inst. Elec. Eng., 78:318-326, 1959.
599
-------
8. Pontius, D., L. Felix, J. McDonald, and W. Smith. Fine Par-
ticle Charging Development. EPA-600/2-77-173, U.S. Environ-
mental Protection Agency, Raleiah Durham, North Carolina,
1977.
9. Smith, W., L. Felix, D. Hussey, and D. Pontius. Experimental
Investigations of Fine Particle Charging by Unipolar Ions -
A Review, J. Aerosol Sci., 9:101-124 (1978).
10. White, H. Industrial Electrostatic Precipitation. Addison-
Wesley, Reading, Massachusetts, 1963. p. 157.
11. Fuchs, N. The Mechanics of Aerosols. Chapter 2. Macmillan,
New York, 1964.
12. White, H. Reference 10, pp. 166-170.
13. White, H. Reference 10, pp. 185-190.
14. Penney, G., and S. Craig. Pulsed Discharges Preceding Spark-
over at Low Voltage Gradients. AIEE Winter General Meeting,
New York, 1961.
15. Pottinger, J. The Collection of Difficult Materials by Elec-
trostatic Precipitation. Australian Chem. Process Eng., 20(2):
17-23, 1967.
16. Spencer, K. Electrostatic Precipitators: Relationship Between
Resistivity, Particle Size, and Sparkover. EPA-600/2-76-144,
U.S. Environmental Protection Agency, Raleigh Durham, North
Carolina, 1976.
17. White, H. Reference 10, pp. 238-293.
18. Preszler, L. and T. Lajos. Uniformity of the Velocity Distri-
bution Upon Entry into an Electrostatic Precipitator of a
Flowing Gas. Staub Reinhalt. Luft (In English), 32(11):l-7,
1972.
19. Gooch, J. P., and G. H. Marchant, Jr. Electrostatic Precipi-
tator Rapping Reentrainment and Computer Model Studies. EPRI
RP-792, Vol. 3, August 1978.
20. Spencer, H. A Study of Rapping Reentrainment in a Nearly
Full Scale Pilot Electrostatic Precipitator. EPA-600/2-76-140,
U.S. Environmental Protection Agency, Raleigh Durham, North
Carolina, 1976.
21. White, H. Electrostatic Precipitation of Fly Ash, Journal
of the Air Pollution Control Association, 27(1):15-21, January
1977.
600
-------
22. Oglesby, S. and G. Nichols. Electrostatic Precipitation.
Marcel-Dekker, Inc., New York, 1978.
23. Oglesby, S. and G. Nichols. A Manual of Electrostatic Pre-
cipitator Technology, Part 1 - Fundamentals. NTIS PB-196 380,
U.S. Environmental Protection Agency, Research Triangle Park,
North Carolina, August 25, 1970.
24. Oglesby, S. and G. Nichols. Comparison of Precipitator
Design Methods. Paper presented at the Conference on
European Electrostatic Precipitators for Controlling Par-
ticle Emissions from Pulp Mills, University of Washington,
March 5, 1974.
25. White, H. Electrostatic Precipitation of Fly Ash. Journal
of the Air Pollution Control Association, 27(4) :308-312,
April 1977.
26. Hall, H. Design and Application of High-Voltage Power
Supplies in Electrostatic Precipitation. H. J. Hall Assoc-
iates, Inc., Princeton, New Jersey.
27. Smith, W., K. Gushing, and J. McCain. Procedures Manual for
Electrostatic Precipitator Evaluation. EPA-600/7-77-059,
Environmental Protection Agency, Research Triangle Park,
North Carolina, June 1977.
28. Schummer, H. and W. Steinbauer. Siemens Rev., 34(12):458-
463, 1967.
29. Piulle, W. Precipitator Performance Hinges on Control.
Power, 119(1):23-26, January 1975.
30. Gelfand, P. Electrostatic Precipitator Voltage Control Using
Silicon-Controlled Rectifiers. IEEE Transactions on Industry
Applications, 10(5):662-665, September/October 1974.
31. Engelbrecht, H. Rigid Frame Precipitators. Proceedings:
Operation and Maintenance of Electrostatic Precipitators, Air
Pollution Control Association, April 1978.
32. Oglesby, S. and G. Nichols. Reference 15, p. 272.
33. Oglesby, S. and G. Nichols. Reference 15, p. 273.
34. Electric Light and Power, 55(6):31, June 1978.
35. Oglesby, S. and G. Nichols. Reference 15, p. 126.
36. Written communication between SoRI and Wheelabrator-Frye, Inc.
601
-------
37. Lynch, J. A Review of Rapper System Problems Associated
with Industrial Electrostatic Precipitators. Proceedings:
Operation and Maintenance of Electrostatic Precipitators,
Dearborn, Michigan, April 10-12, 1978.
38. Oglesby, S. and G. Nichols. Reference 15, p, 280.
39. Oglesby, S. and G. Nichols. Reference 15, p,. 282.
40. Smith, W., K. Gushing, and J. McCain. Reference 20, p. 33.
41. Smith, W., K. Gushing, and J. McCain. Reference 20, p. 32.
42. Information obtained from industry survey bj SoRI personnel.
43. Dumbauld, J. Electrostatic Precipitator Hopper Evaluation
Problems and Their Solutions. Proceedings: Operation and
Maintenance of Electrostatic Precipitators, Dearborn, Michigan,
April 10-12, 1978.
44. Communication from Environmental Elements Corporation.
45. AMCA Bulletin 210. Standard Test Code for Air Moving Devices.
Air Moving and Conditioning Association, Detroit, Michigan,
1960.
46. Baines, W. and E. Peterson. An Investigation of Flow Through
Screens. ASME Trans., July 1961.
47. Dryden and Schubauer. The Use of Damping Screens for the
Reduction of Turbulence. Journal of Aero. Science, 14(4),
1947.
48. Communication from WAHLCO, Inc., 3600 West Segerstrom Avenue,
Santa Ana, California 92704, phone: (714) 979-7300.
49. Southern Research Institute. A Review of Technology for
Control of Industrial Particulate Emissions. Report to Argonne
National Laboratory, Energy Research and Development Ad-
ministration, Argonne, Illinois, Mary 1977.
50. Smith, W., K. Gushing, and J. McCain. Reference 20, p. 102.
\
51. Smith, W. and J. McCain. Particle Size Measurements in
Industrial Flue Gases, Air Pollution Control, Part III.
Edited by Werner Strauss, published by John Wiley and Sons,
Inc., 1978.
52. Smith, W., K. Gushing, and J. McCain. Reference 20, p. 106.
53. Smith, W., K. Gushing, and J. McCain. Reference 20, p. 107.
602
-------
54. Smith, W., P. Cavanaugh, and R. Wilson. Technical Manual:
A Survey of Equipment and Methods for Particulate Sampling
in Industrial Process Streams. EPA-600/2-77-173, U.S.
Environmental Protection Agency, Research Triangle Park,
North Carolina, March 1978.
55. Wilson, R., Jr., P. Cavanaugh, K. Gushing, W. Farthing, and
W. Smith. Guidelines for Particulate Sampling in Gaseous
Effluents from Industrial Processes. EPA-600/7-79-028,
U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina, January 1979.
56. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54, p. 95.
57. Cohen, J. and D. Montan. Theoretical Considerations, Design,
and Evaluation of a Cascade Impactor. Amer. Ind. Hyg. Assoc.
Journal, 95-104, 1976.
58. Marple, V. and K. Willeke. Impactor Design. Atmos. Environ.,
10:891-896, 1976.
59. Mercer, T. On the Calibration of Cascade Impactors. Ann.
Occup. Hyg., 6:1-17, 1963.
60. Newton, G., 0. Raabe, and B. Mokler. Cascade Impactor Design
and Performance. J. Aerosol Sci., 8:339-347, 1977.
61. Marple, V. and B. Y. H. Liu. Characteristics of Laminar Jet
Impactors. Environ. Sci. and Tech., 3(7):648-654, 1974.
62. Rao, A. and K. Whitby. Nonideal Collection Characteristics
of Single Stage and Cascade Impactors. Amer. Ind. Hyg.
Assoc. J.-, 38:174-179, 1977.
63. Gushing, K. , G. Lacey, J. McCain, and W. Smith. Particulate
Sizing Techniques for Control Device Evaluation: Cascade
Impactor Calibrations. EPA-600/2-76-280, U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina,
1976.
64. Lundgren, D. An Aerosol Sampler for Determination of Particle
Concentration as a Function of Size and Time. J. Air Pollut.
Contr. Assoc., 17 (4) :225-259, 1967.
65. Ranz, W. and J. Wong. Impaction of Dust and Smoke Particles.
Ind. Eng. Chem., 44 (6):1371-1381, 1952.
66. Davies, C. and. M. Aylward. The Trajectories of Heavy, Solid
Particles in a Two-Dimensional Jet of Ideal Fluid Impinging
Normally Upon a Plate. Proc. Phys. Soc., 64:889-991, 1951.
67. Marple, V. A Fundamental Study of Inertial Impactors. Uni-
versity Microfilms, Ann Arbor, Michigan, 1970.
603
-------
68. Mercer, T. and R. Stafford. Impaction from Round Jets.
Ann. Occup. Hyg., 12:41-48, 1969.
69. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54,
pp. 99-104.
70. Smith, W., P..-Cavanaugh, and R. Wilson. Reference 54,
pp. 105-106.
71. Calvert, S., C Lake, and R. Parker. Cascade Impactor Cal-
ibration Guidelines. EPA-600/2-76-118. U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina,
1976.
72. McCain, J., K. Gushing and A. Bird, Jr. Field Measurements
of Particle Size Distribution with Inertial Sizing Devices.
EPA-650/2-73-035. U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina, 1973,,
73. Felix, L., G. Clinard, G. Lacey, and J. McCain. Inertial
Cascade Impactor Substrate Media for Flue Gas Sampling.
EPA-600/7-77-060. U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina, 1977.,
74. Brink, J., Jr., E. Kennedy, and H. Yu. Particle Size Mea-
surements with Cascade Impactors. 65th Annual Meeting,
AIChE, New York, New York, 1972.
75. Ragland, J., K. Gushing, J. McCain, and W. Smith. HP-25
Programmable Pocket Calculator Applied to Air Pollution
Measurement Studies: Stationary Sources. Interagency
Energy-Environment Research and Development Program Report,
EPA-600/2-77-05, June 1977.
76. Ragland, J., K. Gushing, J. McCain, and W. Smith. HP-65
Programmable Pocket Calculator Applied to Air Pollution Mea-
surement Studies: Stationary Sources. U.S. Environmental
Protection Agency Report, EPA-600/2-76-002, October 1976.
77. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54,
p. 110.
78. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54,
p. 112.
79. Chan, T. and M. Lippmann. Particle Collection Efficiencies
of Air Sampling Cyclones: An Empirical Theory. Environ.
Sci. Technol., 11(4):377-382, 1977.
80. Smith, W., and R. Wilson. Development and laboratory Eval-
uation of a Five-Stage Cyclone System. EPA-600/7-78-008,
U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina, 1978.
604
-------
81. Rusanov, A- Determination of the Basic Properties of Dusts
and Gases in "Ochistka Dymovykl Gasov V Promyshlennoy
Energtike". 405-440, 1969.
82. Smith, W., K. Gushing, G. Lacey, and J. McCain. Particulate
Sizing Techniques for Control Device Evaluation. EPA-650/
2-74-102A, U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina, 1975.
83. Haraersma, J., S. Reynolds, and R. Maddalone. Procedures
Manual for Level 1 Environmental Assessment. EPA-600/2-76-
160A, U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina, 1976.
84. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54, p. 12C.
85. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54, p. 121.
86. Whitby, K., and B. Y. H. Liu. J. Colloid Interface Science,
25:537, 1967.
87. Willeke, K., and B. Y. H. Liu. Single Particle Optical
Counter: Principle and Application. In: Fine Particles,
Aerosol Generation, Measurement, Sampling, and Analysis.
Academic Press, B. Y. H. Liu, ed., 1976. pp. 698-725.
88. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54, p. 124.
89. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54, p. 125.
90. Marple, V. The Aerodynamic Size Calibration of Optical Par-
ticle Counters by Inertial Impactors. Particle Tech. Lab.
Pub. 306J presented -at Aerosol Measurement Workshop, Uni-
versity of Florida, Gainesville, Florida, 1976.
91. McCain, J., K. Gushing, and W. Smith. Methods for Determining
Particulate Mass and Size Properties: Laboratory and Field
Measurements. J. Air Pollut. Contr. Assoc., 24(12):1172-
1176, 1974.
92. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54, p. 124.
93. Breslin, A., S. Guggenheim, and A. George. Staub (Enalish
Translation), 31(8) -.1-5, 1971.
94. Sinclair, D., and G. Hoopes. A Novel Form of Diffusion
Battery. Amer. Ind. Hyg. Assoc. J., 36(1):39-42, 1975.
95. Junge, C., and E. McLaren. Relationship of Cloud Nuclei
Spectra to Aerosol Size Distribution and Composition. J. of
Atmos. Sci., 28(3):382-390, 1971.
605
-------
96. Haberl, Jr., and S. Fusco. Condensation Nuclei Counters:
Theory and Principles of Operation. Prepared for presen-
tation at the llth Conference on Methods in Air Pollution
and Industrial Hygiene Studies at the University of Cali-
fornia, Berkeley, California, sponsored by California Air
Resources Board and California Department of Public Health,
1970.
97. Sinclair, D. A Portable Diffusion Battery: Its Application
to Measuring Aerosol Size Characteristics. Ainer. Ind. Hyg.
Assoc. J., 33 (11) :729-735, 1972.
98. Ragland, J., w. Smith, and J. McCain. Design, Construct,
and Test a Field Usable Prototype System f:. r Sizing Particles
Smaller than 0.5 ym Diameter. EPA Contract Number 68-02-2114,
U.S. Environmental Protection Agency, Research Triangle Par'.,
North Carolina, 1978.
99. Soderholm, S. Modification of a Commercial Condensation
Nuclei Counter for Steady Flow. Atmos. Environ., 10:659-
660, 1976.
100. Fuchs, N., I. Stechkina, and V. Starosselskii. On the De-
termination of Particle Size Distribution in Polydisperse
Aerosols by the Diffusion Method. Brit. J. Appl. Phys.,
16:280-281, 1962.
101. Sinclair, D., R. Countese, B. Y. H. Liu, and D. Y. H. Pui.
Experimental Verification of Diffusion Battery Theory. J.
Air Pollut. Contr. Assoc., 26(7):661-663, 1976.
102. Sinclair, D. and G. Hoopes. A Novel Form of Diffusion
Battery. Amer. Ind. Hyg. Assoc. J., 36 (1):39-42, 1975.
103. Breslin, A., S. Guggenheim, and A. George. Compact High-
Efficiency Diffusion Batteries. Staub Reinhaltung der Luft,
33(4):187-190, 1973.
104. Twomey, S. The Determination of Aerosol Size Distributions
from Diffusional Decay Measurements. J. of Franklin Inst.,
275:121-138, 1963.
105. Sansone, E., and D. Weyel. A Note on the Penetration of a
Circular Tube by an Aerosol with a Log-Normal Size Distri-
bution. J. Aerosol Sci., 2:413-415, 1971.
106. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54,
pp. 132-133.
107. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54,
p. 135.
606
-------
108. Megaw, W., and A. Wells. A High Resolution Charge and
Mobility Spectrometer for Radioactive Submicrometer Aero-
sols. J. Physics E., 1013-1016, 1969.
109. Maltoni, G., C. Melandri, V. Prodi, G. Tarroni, A.
DeZaiacomo, G. Bompane, and M. Formignani. An Improved
Parallel Plate Mobility Analyzer for Aerosol Particles.
J. Aerosol Sci., 4:447-455, 1973.
110. Krutson, E. Extended Electric Mobility Method. In: Pro-
ceedings of Symposium on Fine Particles, Minneapolis,
Minnesota, 1975.
111. Markowski, G. and D. Ensor. Development of an In-Stack
Impactor/Precipitator for Sizing Submicron Particles.
EPRI FP-501, Electric Power Research Institute, Palo Alto,
California.
112. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54,
p. 137.
113, Whitby, K., and W. Clark. Electric Aerosol Particle Counting
and Size Distribution Measuring System for the 0.015 to 1
Micron Size Range. Tellus, 18:573-586, 1966.
114. Liu, B. Y. H., K. Whitby, and p. Y. H. Pui. A Portable
Electrical Analyzer for Size Distribution Measurement of
Sub-Micron Aerosols. J. Air Pollut. Contr. Assoc., 24(11):
1067-1072, 1974.
115. Sem, G. Submicron Particle Sizing Experience on a Smoke
Stack Using the Electrical Aerosol Size Analyzer. EPA-600/
2-77-060", U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina, 1975.
116. Lacey, G., K. Gushing, and W. Smith. Compact, In-Stack,
Three-Size-Cut Particle Classifier. Report prepared by
Southern Research Institute, Contract No. 68-02-1736, for
the Environmental Protection Agency, Research Triangle Park,
North Carolina, October 5, 1976.
117. Gooch, J., and G. Marchant, Jr. Reference 19, pp. 3-13
through 3-18.
118. Cadle, R. Particle Size Measurement. Interscience
Publishers, Inc., New York,. New York, 1955.
119. Allen, T. Particle Size Measurement. Chapman and Hall
Ltd., London, England, 197.5.
120. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54, p. 144.
607
-------
121. Godridge, A., S. Badzioch, and P. Hawksley. A Particle
Size Classifier for Preparing Graded Sub-Sieve Fractions.
J. Sci. Instrum., 39:611-613, 1962.
122. Goetz, A. and T. Kallai. Instrumentation for Determining
Size and Mass Distribution of Submicron Aerosols. APCA J.,
12:479-486, 1962.
123. Goetz, A., H. Stevenson, and 0. Preining. The Design and
Performance of the Aerosol Spectrometer. APCA J., 10:378-
838, 1960.
124. Gerber, H. On the Performance of the Goetr Aerosol Spectro-
meter. Atmos. Environ., 5:1009-1031, 19~i.
125. Stober, W., and H. Flachsbart. Size-Separating Precipitation
of Aerosols in a Spinning Spiral Duct. Environ. Sci.•Technol.,
3(12):1280-1296, 1969.
126. Swayer, K. F., and W. Walton. The "Conifuge" - A Size-
Separating Sampling Device for Airborne Particles. J. Sci.
Instrum., 27:272-276, 1950.
127. Keith, C., and J. Derrick. Measurement of the Particle
Size Distribution and Concentration of Cigarette Smoke by
the "Conifuge". J. Colloid. Sci., 14:340-356, 1960.
128. Tillery, M. Design and Calibration of a Modified Conifuge.
Assessment of Airborne Radioactivity, IAEA, Vienna, 1967.
129. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54,
p. 148.
130. McCrone, W., and J. Delly. The Particle Atlas, Edition
Two. Ann Arbor Science, Ann Arbor, Michigan, 1973.
131. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54,
p. 150.
132. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54,
p. 152.
133. Kaye, B. Symposium on Particle Size Analysis Society for
Analytical Chemistry, Loughborough, England, 1966.
134. Allen-Bradley Sonic Sifter. U.S. Patent 3,045,817.
135. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54,
p. 154.
608
-------
136. Nichols, G., and J. McCain. Particulate Collection Effi-
ciency Measurements on Three Electrostatic Precipitators.
EPA-600/2-75-056, U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina, October 1975.
137. McDonald, J. A Mathematical Model of Electrostatic Pre-
cipitation (Revision 1): Volume II. User Manual. EPA-
600/7-78-lllb, U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina, June 1978. p. 60.
138. Electrostatic Precipitators for Control of Fine Particle
Emissions. Final report prepared by Southern Research
Institute for the Environmental Protection Agency, Research
Triangle Park, North Carolina under Contract: No. 68-02-2114.
139. Oglesby, S. and G. B. Nichols. Reference 23, p. 251.
140. Oglesby, S. and G. B. Nichols. Reference 23, p. 254.
141. Banks, S. M., J. R. McDonald, and L. E. Sparks. Voltage-
Current Data From Electrostatic Precipitators Under Normal
and Abnormal Conditions. Proceedings: Particulate Collec-
tion Problems Using ESPs in the Metallurgical Industry.
EPA-600/2-77-208, U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina, 1977. 129 pp.
142. McDonald, J. R. Mathematical Modelling of Electrical Con-
ditions, Particle Charging, and the Electrostatic Precipita-
tion Process. Ph.D Dissertation, Auburn University, Auburn,
AL, 1977. 186 pp.
143. White, H. Reference 10, p. 222.
144. White, H. Reference 10, p. 92.
145. Peek, F. W., Jr. Dielectric Phenomena in High Voltage
Engineering. 3rd ed. , Me G r a w - K i 11, New York. p"!§4^ 1929.
146. White, H. Reference 10, pp. 105-106.
147. White, H. Reference 10, p. 89 and p. 107.
148. Voshall, R. E., J. L. Packs, and A. V. Phelps. Mobility of
Meaative Ions in Oz at Low E/N. J. Chem. Phys. 43:1990,
1965.
149. Tassicker, 0. J. Experiences With an Electrostatic Precipi-
tation Analyzer in the Evaluation of Difficult Dusts. Pro-
ceedings International Clean Air Conference, Melbourne,
Australia, May, 1972.
609
-------
150. Spencer, H. W. Experimental Determination of the Effective
Ion Mobility of Simulated Flue Gas. In: Proceedings of
1975 IEEE-IAS Conference, Atlanta, Georgia, 1975.
151. McDonald, J. R., S, .M. Banks, and L. E. Sparks. Measure-
ment of Effective Ion Mobilities in a Corona Discharge in
Industrial Flue Gases. Proceedings: Symposium on'-the
Transfer and Utilization of Particulate Control Technology.
Volume 1, Electrostatic Precipitators, EPA-6'00/'7-79-044a,
U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina, July 1978.
152. McDonald, J. R. A Mathematical Model of Electrostatic Pre-
cipitation (Revision 1): Modeling and Programing. EPA-
600/7-78-llla, U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina, June 1978. pp. 175.
153. Gooch, J. P., J. R. McDonald, and S. Oglesby, Jr. A Mathe-
matical Model of Electrostatic Precipitation. EPA-650/2-75-
037, U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina, 1975. pp. 77-79.
154. Dismukes, E. B. and J. P. Gooch, Fly Ash Conditioning with
Sulfur Trioxide. EPA-600/2-77-242, U.S. Environmental Pro-
tection Agency, Research Triangle Park, North Carolina, 1977.
155. A Field Demonstration Study to Evaluate Sodium Injection for
Reducing Fly Ash Resistivity. Contract No. 68-02-2656, U.S.
Environmental Protection Agency, Research Triangle Park,
North Carolina.
156. Dismukes, E. B. Techniques for Conditioning Fly Ash. Pro-
ceedings: Conference on Particulate Collection Problems in
Converting to Low Sulfur Coals. EPA-600/7-76-016, U.S.
Environmental Protection Agency, Research Triangle Park,
pp. 107, 1976.
157. Cragle, S. H. Operating Experience with ESP Conditioning
in Relation to an Electrostatic Precipitator Upgrading Pro-
gram. Proceedings: Conference on Particulate Collection
Problems in Converting to Low Sulfur Coals. EPA-600/7-76-016,
U.S. Environmental Protection AGency, Research Triangle Park,
pp. 3, 1976.
158. Borsheim, R. and R. P. Bennett. Chemical Conditioning of
Low-Sulfur Western Coal. Presented at 39th Annual Meeting,
American Power Conference, Chicago, Illinois, April, 1977.
159. Effects of Conditioning Agents on Emissions from Coal-Fired
Boilers. Contract No. 68-02-2628, U.S. Environmental Pro-
tection Agency, Research Triangle Park, North Carolina.
610
-------
160. Flue Gas Conditioning for Enhanced Precipitation of Diffi-
cult Ashes. Contract No. RP724-2, Electric Power Research
Institute, Chattanooga, Tennessee.
161. Selle, S. J., P. H. Tufte, and G. H. Gronhovd. A Study of
the Electrical Resistivity of Fly Ashes from Low-Sulfur
Western Coals Using Various Methods. Paper 72-107 pre-
sented at the 65th Annual Meeting of the Air Pollution
Control Association, Miami Beach, Florida, 1972.
162. Bickelhaupt, R. E. Electrical Volume Conduction in Fly
Ash. APCA Journ., 24 (3) :251-255, 1974.
163. Lederman, P. B., P. P. Bibbo, and J. Bush. Chemical Con-
ditioning of Fly Ash for Hot-Side Precipitation. Proceedings:
Symposium on the Transfer and Utilization of Particulate
Control Technology. Volume 1, Electrostatic Precipitators,
EPA~600/7-79-044a, U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina, 1978, pp. 79-98.
164. Dismukes, E. B. Conditioning of Fly Ash with Sulfur Trioxide
and Ammonia. TVA No. F75 PRS-5, Tennessee Valley Authority,
Chattanooga, Tennessee and EPA No. 600/2-75-015, U.S.
Environmental Protection Agency, Washington, D.C., 1975.
165. Dalmon, J. and D. Tidy. The Cohesive Properties of Fly
Ash in Electrostatic Precipitation. Atmos. Environ.
(Oxford, England), 6(2}:81-92, 1972.
166. Dismukes, E. Conditioning of Fly Ash with Ammonia. JAPCA,
25(2):152-156, 1975.
167. McDonald, J. R. Reference 137, pp. 64-68.
168. Hall, H. J. Trends in Electrical Energization of Electro-
static Precipitators. Presented at Electrostatic Precipitator
Symposium, Birmingham, Alabama, Paper I-C, February 23-25,
1971.
169. Penney, G. W. and E. H. Klingler. Contact Potentials and
Adhesion of Dust. Trans. Amer. Inst. Elec. Eng. Part I,
81:200-204, 1962.
170. Nichols, G. B. Techniques for Measuring Fly Ash Resistivity.
EPA-650/2-74-079, NTIS PB244140, U.S. Environmental Pro-
tection Agency, Research Triangle Park, 1974. pp. 5.
171. Bickelhaupt, R. E. Surface Resistivity and the Chemical
Composition of Fly Ash. APCA Journal, 25(2):148-152, 1975.
611
-------
172. Bickelhaupt, R. E. A Technique for Predicting Fly Ash Re-
sistivity. Proceedings: Symposium on the Transfer and
Utilization of Particulate Control Technology, U.S. En-
vironmental Protection Agency, Research Triangle Park,
North Carolina, July, 1978.
173. Nichols, G. B. Reference 169, p. 8.
174. Nichols, G. B. Reference 169, p. 13.
175. Baker, J. W. and K. M. Sullivan. Reproducibility of Ash
Resistivity Determinations. Presentated at the Joint Power
Generation Conference, Long Beach, Califor-.'.a, September
18-21, 1977.
176. Personal communications with Dr. R. E. Bickelhaupt.
177. Babcock & Wilcox. Steam/its-generation and use. Chapter
6. Babcock & Wilcos, New York, New York, 1975.
178. ASME PTC-28. Determining the'Properties of Fine Particulate
Matter. Section 4.05, Method for Determination of Bulk
Electrical Resistivity, pp. 15-17, 1965.
179. Nichols, G. B. Reference 169, p. 18.
180. Nichols, G. B. Reference 169, p. 19.
181. Bickelhaupt, R. E. Measurement of Fly Ash Resistivity Using
Simulated Flue Gas Environments. EPA-600/7-78-035, U.S.
Environmental Protection Agency, Research Triangle Park,
North Carolina, March 1978.
182. Bickelhaupt, R. E. Reference 180, p. 7.
183. Bickelhaupt, R. E. Reference 180, p. 12.
184. NevenSj, T. D., et al. A Comparative Evaluation of Cells for
Ash Resistivity Measurement. Presented at IEEE-ASME Joint
Power Generation Conference, Long Beach, California, September
18-21, 1977.
185. Kanowski, S. and R. W. Coughlin. Catalytic Conditioning of
Fly Ash Without Addition of SO3 from External Sources. En-
vironmental Science and Technology, 11(1):67-70, 1977.
186. Bickelhaupt, R. E. Reference 180, p. 15.
187. Bickelhaupt, R. E. Reference 180, p. 17,
612
-------
188. Nichols, G. B. and S. M. Banks. Test Methods and Apparatus
for Conducting Resistivity Measurements. Final Report,
Contract No. 68-02-1083, U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina, September,
1977.
189. Nichols, G. B. Reference 169, p. 24.
190. Nichols, G. B. Reference 169, p. 26.
191. Nichols, G. B. and S. M. Banks. Reference 187, p. 10.
192. Cohen, L. and R. W. Dickinson. The Measurement of the
Resistivity of Power Station Fine Dust. J. Sci. Instrum.
(London), 40:72-75, 1963.
193. Nichols, G. B. Reference 169, p. 31.
194. Tassicker, 0. J., Z. Herceg, and K. J. McLean. A New Method
and Apparatus to Assist the Prediction of Electrostatic Pre-
cipitator Performance. Institution of Engineers, Australia.
Electrical Engineering Transactions (Sydney). EE5(2):277-
278, September 1969.
195. Eishold, H. G. A Measuring Device for Determining the
Specific Electrical Resistance of Dust. Staub Reinhaltung
der Luft in English (Diisseldorf) . 26(1):14-18, January
1966.
196. Nichols, G. B. and J. P. Gooch. An Electrostatic Precipi-
tator Performance Model. Report to Environmental Protection
Agency on Contract No. CPA 70-166 by Southern Research
Institute, Birmingham, Alabama. July 1972. 171 p.
197. White, H. Reference 10, pp. 238-293.
198. Burton, C. L., and D. A. Smith. Precipitator Gas Flow
Distribution. JAPCAf 25(2):139-143, February, 1975.
199. Engelbrecht, H. L. Air Flow Model Studies for Electrostatic
Precipitators. Proceedings: Symposium on the Transfer and
Utilization of Particulate Control Technology. Volume 1,
Electrostatic Precipitators, E?A-600/7-79-044a, U.S. En-
vironmental Protection Agency, Research Triangle Park,
North Carolina, February, 1979, pp. 57.
200. Industrial Gas Cleaning Institute, Inc. Criteria for Per-
formance Guarantee Determinations, Publication No. EP-3.
August 1965.
201. Gooch, J., and G. Marchant. Reference 19, pp. 5-71 to 5-72.
202. ''Gooch,'J., and G. Marchant. Reference 19, pp. 5-87 to 5-97.
613
-------
203. Gooch, J. P., J. R. McDonald, and S. Oglesby, Jr. Reference
153, pp. 48-53.
204. Gooch, J. P., J. R. McDonald, and S, Qglesay, Jr. Reference
153, pp. 54-62.
205. Gilbert, Gerald'B-. -Experimental Flow Modeling for Power
Plant Equipment. Power Engineering Magazine. May 1974.
206. Tassicker, 0. J. Some Aspects of Electrostatic Precipitator
Research in Australia. J. Air Pollution Control Assoc.,
25(2)-.122-128, 1975.
207. Tassicker, 0. J. Aspects of Forces on Cnarged Particles
in Electrostatic Precipitators. Dissertation, Wollongong
University College, University of New South Wales, Australia,
1972.
208. Sproull, W. T. Fundamentals of Electrode Rapping in Indus-
trial Electrical Precipitators. J. Air Pollution Control
Assoc., 15(2):50-55, 1965.
209. White, K. J. Reference 10, pp. 331-354.
210. Sproull, W. T. Minimizing Rapping Losses in Precipitators
at a 2000 Megawatt Coal-Fired Power Station. J. Air Pollut.
Contr. Assoc., 22:181-186, 1972.
211. Juricic, D. and G. Herrmann. Response of Collecting Plates
in Electrostatic Precipitators Due to Shear Rapping. Journal
of Mechanical Design, 100:105-112, January, 1978.
212. Juricic, D. and G. Herrmann. On the Dynamics of Electro-
statically Precipitated Fly Ash. Paper No. 78-WA/FU-3,
presented at the Winter Annual Meeting of the American
Society of Mechanical Engineers, San Francisco, Dec. 10-15,
1978.
213. Plato, H, Rapping of Collecting Plates in Electrostatic
Precipitators, Staub-Reinhalt, Luft (in English), 29(8):
22-30, 1969.
214. Sanayev, Yu. I., and I. K. Reshidov. Study of Dust Re-
entrainment Phenomena and Their Influence on Efficiency of
Industrial Electrostatic Precipitators. Promyshlennaya i
Sanitarnaya Ochistka Gazov, (Moscow), (l):l-5, 1974.
215. Schwartz, L. B., and M. Lieberstein. Effect of Rapping
Frequency on the Efficiency of an Electrostatic Precipitator
at a Municipal Incinerator. Proceedings of the Fourth Annual
Environmental Engineering and Science Conference, Louisville,
Kentucky, March 4-5, 1975.
614
-------
216. Nichols, G. B., H. W. Spencer, and J. D. McCain. Rapping
Reentrainment Study. Report SoRI-EAS-75-307 to Tennessee
Valley Authority, TVA Agreement TV36921A, November 1975.
217. Gooch, J. P. Electrostatic Precipitator Performance Pro-
ceedings: Symposium on the Transfer and Utilization of
Particulate Control Technology. Volume 1, Electrostatic
Precipitators, EPA-600/7-79-044a, U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina,
February 1979, pp. 1-18.
218. Gooch, J. P., J. R. McDonald, and S. Oglesby, Jr. Reference
153, pp. 58-61.
219. U.S. Environmental Protection Agency. Standards of Per-
formance for New Stationary Sources. Federal Register,
43(160):41776-41782, 1977.
220. U.S. Environmental Protection Agency. Standards of Per-
formance for New Stationary Sources. Federal Register,
42(187) :42020-42028, 1976.
221. American Society of Mechanical Engineers. Determining
Dust Concentrations in a Gas Stream, Power Test Code 27.
New York, New York, 1957.
222. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54, p. 5.
223. Hemeon, W. and A. Black. Stack Dust Sampling: In-Stack
Filter or EPA Train. Journal of the Air Pollution Control
Association, 22(7):516, July 1972.
224. Brenchley, D., C. Turley, and R. Yarmac. Industrial Source
Sampling. Ann Arbor Science Publishers, Inc., Ann Arbor,
Michigan, 1973.
225. Rom, J. Maintenance, Calibration, and Operation of
Isokinetic Source Sampling Equipment. U.S. Environmental
Protection AGency, Research Triangle Park, North Carolina,
1972. APTD-0576.
226. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54, p. 6.
227. Smith, W., P. Cavanaugh, and R. Wilson. Reference 54, p. 16
228. U.S. Environmental Protection Agency. State Implementation
Plan Emission Regulations for Particulate Matter: Fuel
Combustion, Strategies and Air Standards Division, August
1976. EPA-450/2-76-010.
229. Code of Federal Regulations 40, Part 60, Subpart D, Para-
graph 60.42-60.44, July 1, 1977.
615
-------
230. Discussions with EPA.
231. EPA NSPS Proposal Eyes "Full Scrubbing". Electric Light
and Power, 56(10):! and 7, October 1978.
232. EPA Sets New Sulfur Limits. Electric Light, and Power,
57(7):1 and 4, July 1979.
233. Farthing, W. E. and A. H. Dean. Summary Document on
Control Stategies for Visible Emissions. Final Report
prepared by SoRI for the FLAKT, INC., May 5, 1978.
234. Peterson, C. M. In-Stack Transmissometer Techniques for
Measuring Opacities of Particulate Emissions from Stationary
Sources, U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina, 1972. EPA-R2-72-099.
235. Ensor, D. S. and M. J. Pilat. The Effect of Particle
Size Distribution on Light Transmittance Measurement.
American Industrial Hygiene Association Journal, 32(5):
287-292, 1971.
236. U.S. Environmental Protection Agency. Appendix B, Per-
formance Specification 1 - Performance Specifications and
Specification Test Procedures for Transmissometer Systems.
237. Nader, J. S., F. Jaye, and W. Conner. Performance Speci-
fications for Stationary-Source Monitoring Systems for
Gases and Visible Emissions. U.S. Environmental Protection
Agency, Research Triangle Park, N.C., 1974. EPA-650/2-74-013.
238. Ensor, D. S. Plume Opacity Measurements. In: Proceedings
of the Symposium on the Control of Fine-particulate Emissions
from Industrial Sources, Particulate Technical Sub-Group
of the U.S.-U.S.S.R. Working Group on Stationary Source Air
Pollution Control Technology, San Francisco, California, 1974.
239. Ensor, D. S. and M. J. Pilat. Calculation of Smoke Plume
Opacity from Particulate Air Pollutant Properties. Jounral of
the Air Pollution Control Association, 21(8):496-501, 1971.
239a. Sparks, L. E. In-Stack Plume Opacity from the Electrostatic/
Scrubber System at Harrington Unit 1, May 1979. EPA 600/
7-79-118.
240. Schutz, A. Technical Dust Control Principles and Practice.
Staub-Reinhalt, Luft, 26(10):l-8, 1966.
241. Sem, G. J., et al. State of the Art, 1971 Instrumentation
for Measurement of Particulate Emissions from Combustion
Sources. Vol. II: Particulate Mass - Detail Report. En-
vironmental Protection AGency, Research Triangle Park,
North Carolina, 1971. EPA APTD-0734.
616
-------
242. Schneider, W. A. Opacity Monitoring of Stack Emissions:
A Design Tool with Promising Results. In: The 1974
Electric Utility-Generation Planbook, McGraw-Hill, New
York, N. Y., 1974.
243. Duwel, L. Latest State of Development of Control In-
struments for the Continuous Monitoring of Dust Emissions.
Staub-Reinhalt, Luft, 28(3):42-53, 1968.
244. Biihne, W. K., and L. Duwel. Recording Dust Emission Measure-
ments in the Cement Industry with the RM4 Smoke Density
Meter made by Messrs. Sick. Staub-Reinhalt, Luft, 32(8):
19-26, 1972.
245. Larssen, S., D. S. Ensor, and M. J. Pilat. Relationship
of Plume Opacity to the Properties of Particulates Emitted
from Kraft Recovery Furnaces. Tappi, 55(l):88-92, 1972.
246. Reisman, E. R., W. B. Gerber, and N. D. Potter. In Stack
Transmissometer Measurement of Particulate Opacity and
Mass Concentration. EPA-650/2-74-120, U.S. Environmental
Protection Agency, Research Triangle Park, N.C., 1975.
247. Nader, J. S. Source Monitoring. In: Air Pollution, 3rd
Edition, Vol. Ill, Measuring, Monitoring, and Surveillance
of Air Pollution, A. C. Stern, Ed. Academic Press, New
York, N. Y., 1976.
248. Ensor, D. S. and L. D. Bevan. Application of Nephelometry
to the Monitoring of Air Pollution Sources. Paper 73-AP-14,
presented at the 1977 Annual Meeting of the Air Pollution
Control Association, Pacific Northwest International Section,
Seattle, Washington, 1973.
249. Ensor, D. S. Plume Opacity Measurements. In: Proceedings
of the Symposium on Control of Fine-Particulate Emissions
from Industrial Sources, Particulate Technical Sub-Group
of the U.S.-U.S.S.R. Working Group on Stationary Source
Air Pollution Control Technology, San Francisco, California,
1974.
250. Ensor, D. S., L. D. Bevan, and G. Markowski. Application
of Nephelometry to the Monitoring of Air Pollution Sources.
In: Proceedings of the Sixty-Seventh Annual Meeting, Air
Pollution Control Association, Denver, Colorado, 1974.
251. Shofner, F., G. Kreikebaum, and H, Schmitt. Iri situ Con-
tinuous Measurement of Particulate Mass Concentration.
Presented at the 68th Annual Meeting and Exhibition of
the Air Pollution Control Association, Boston, Massachusetts,
1975.
617
-------
252. Schmitt, H., R. Nuspliger, and G. Kreikebaum. Continuous
In Situ Particulate Mass Concentration Measurement of
Industrial Discharges. Presented at the 70th Annual
Meeting of the Air Pollution Control Association, Toronto,
Ontario, Canada, 1977.
253. Tipton, D. A Particle Analyzer for Stack Emissions.
Powder Tech., 14:245-252, 1976.
254. Gooch, J. P., and G. H. Merchant. Reference 19, pp. 5-75
to 5-98.
255. Gooch, J. P., and G. H. Marchant. Referenre 19, pp.. 5-1
to 5-35.
256. Marchant, G. H., Jr. and J. P. Gooch. Performance and
Economic Evaluation of a Hot-Side Electrostatic Precipi-
tator. EPA-600/7-78-214, U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina (1978).
257. Gooch, J. P., and G. H. Marchant. Reference 19, pp. 5-98
to 5-141.
258. Gooch, J. P., and G. H. Marchant. Reference 19, pp. 5-165
to 5-212.
259. Breish, E. W. Method and Cost Analysis of Alternative
Collectors for Low Sulfur Coal Fly Ash. Proceedings:
Symposium on the Transfer and Utilization of Particulate
Control Technology. Volume 1, Electrostatic Precipitators.
EPA-600/7-79-044a, U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina, February 1979,
pp. 121-130.
260. Bennett, R. P., and A. E. Kober. Chemical Enhancement of
Electrostatic Precipitator Efficiency. Proceedings:
Symposium on the Transfer and Utilization of Particulate
Control Technology. Volume 1, Electrostatic Precipitators,
EPA-600/7-79-044a, U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina, February 1979,
pp. 113-120.
261. Potter, E. C., and C. A. J. Paulson. Improvement of Elec-
trostatic Precipitator Performance by Carrier Gas Additives.
Chem. Ind. (London) 1974:532-533, July 6, 1974.
262. Flue Gas Conditioning. Environmental Science and Technology,
12(13)-.1362-1365, December 1978.
263. Dismukes, E. Gas Conditioning for Electrostatic Precipita-
tors. Paper presented at the Western Precipitator Symposium,
Aoril 1977.
618
-------
264. Dismukes, E. B. Conditioning of Fly Ash with Sulfamic
Acid, Ammonium Sulfate, and Ammonium Bisulfate. EPA-650/
2-74-114, U.S. Environmental Protection Agency, 1974.
265. Verhoff, F. and J. Banchero. The Equilibrium Partial
Pressures above Sulfuric Acid Solutions. AIChE J., 18(8):
1265-1268 (1972).
266. Bickelhaupt, R. E. Sodium Conditioning to Reduce Fly Ash
Resistivity. EPA-650/2-74-092, Environmental Protection
Agency, 1974.
267. Selle, S. J., and L. L. Hess. Factors Affecting ESP Per-
formance on Western Coals and Experience with North Dakota
Lignites. Symposium on Particulate Control in Energy
Processes, San Francisco, May 11-13, 1976.
268. Telephone conversation with the Occupational Safety and
Health Administration, Wash. D. C.
269. Engineering and Safety Service. Special Hazards Bulletin.
American Insurance Association, New York, New York, August
1975.
270. Communication from Research-Cottrell.
271. Communication from Lodge-Cottrell.
272. Babcock & Wilcox. Steam/Its Generation and Use. 38th
Edition, New York, New York, 1975.
273. Ross, R. D., Editor. Air Pollution and Industry. Van
Nostrand Reinhold Company, New York, New York, 1972.
274. Communication from major electrostatic precipitator manu-
facturers .
275. Oglesby, S. and G. Nichols. A Manual of Electrostatic
Precipitator Technology, Part I - Fundamentals, Prepared
by Southern Research Institute under Contract CPA 22-69-73
for the National Air Pollution Control Administration,
Cincinnati, Ohio, August 25, 1970.
276. Power, 119:56-58, August 1975.
277. Szabo, M. and R. Gerst-le. Electrostatic Precipitator Mal-
functions in the Electric Utility Industry. Prepared by
PEDCo-Environmental Specialists, Inc., Cincinnati, Ohio,
under Contract No. 68-02-2105 for the Industrial Environ-
mental Research Laboratory, Research Triangle Park, North
Carolina, January 1977. EPA-600/2-77-006 or NTIS No.
PB 263 504.
619
-------
278. Engelbrecht, H. Plant Engineer's Guide to Electrostatic
Precipitator Inspection and Maintenance. Plant Engineering,
pp. 193-196, April 29,. 197$..
279. Bump, R. Electrostatic Precipitator Maintenance Survey.
Journal of the Air Pollution Control Association, 26(11):
1061-1064, 1976.
280. A Review of Technology for Control of Fly Ash Emissions
from Coal in Electric Power Generation. Prepared by
Southern Research Institute for Argonne National Laboratory
under Contract 31-109-38-3550, July 1, 1977.
281. Proceedings: Operation & Maintenance of Electrostatic
Precipitators. Michigan Chapter - East Central Section
Air Pollution Control Association, Dearborn, Michigan,
April 10-12, 1978.'
282. Scheider, G., T. Horzeila, J. Cooper, and P. Striegl.
Selecting and Specifying Electrostatic Precipitators.
Chemical Engineering, pp. 94-108, May 26, 1975.
283. Communication from vendor.
284. Gooch, J. P., and J. R. McDonald. Mathematical Modelling
of Fine Particle Collection by Electrostatic Precipitation.
Atmospheric Emissions and Energy-Source Pollution, AIChE
Symposium Series, 73(165):146, 1977.
285. Gooch, J. P., and J. R. McDonald. Mathematical Modelling
of Fine Particle Collection by Electrostatic Precipitation.
Conference on Particulate Collection Problems in Converting
to Low Sulfur Coals, Interagency Energy-Environment Research
and Development Series. EPA-600/7-76-016, U.S. Environmental
Protection Agency, 1976. 68 pp.
286. Leutert, G., and B. Bohlen. The Spatial Trend of Electric
Field Strength and Space Charge Density in Plate-Type
Electrostatic Precipitators. Staub, 32(7):27, 1972.
287. Gooch, J. P., J. R. McDonald, and S. Oglesby, Jr. Reference
153, pp. 12-19.
288. Smith, W. B., and J. R. McDonald. Development of a Theory
for the Charging of Particles by Unipolar Ions. J. Aerosol
Sci., 7:151-166, 1976.
289. Gooch, J. P., J. R. McDonald, and S. Oglesby, Jr. Reference
153, pp. 48-62.
290. McDonald, J. R. Reference 152, pp. 29-33.
620
-------
291. McDonald, J. R., and D. H. Pontius. Electrostatic Pre-
cipitators. AIChE Conference on Theory, Practice and
Process Principles for Physical Separations, Pacific Grove,
California, November, 1977. (To be published in December,
1979) .
292. Nichols, G. B., and J. P. Gooch. An Electrostatic Pre-
cipitator Performance Model. Final Report, Contract No.
CPA 70-166, U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina, 1972. pp. 112-160.
293. Hedley, A. B., in: The Mechanism of Corrosion by Fuel
Impurities (H. R. Johnson and D. L. Littler, editors),
Butterworth, London, p. 204, 1963.
294. Cuffe, S. T., Gerstle, R. W., Orning, A. A., and Schwartz,
C. H., J. Air Poll. Control Assoc., 14:353, 1964.
295. Snowden, P. N., and Ryan, M. H. Sulfuric Acid Condensation
from Flue Gases Containing Sulfur Oxides. J. Inst. Fuel,
42:188, 1969.
296. Mueller, Peter. Study of the Influence of Sulfuric Acid
on the Dew Point Temperature of the Flue Gas. Chemie -
Ing. - Tech. 31^:345, 1959.
297. Abel, Emil. The Vapor Phase Above the System Sulfuric
Acid - Water. J. Phys. Chem. 50:260, 1946.
298. Gmitro, J. I., and Vermuelen, T. Vapor-Liquid Equilibria
for Aqueous Sulfuric Acid. Univ. of California Radiation
Laboratory Report 10866, Berkeley, California, June 24,
1963.
299. Greenewalt, C. H. Partial Pressure of Water Out of
Aqueous Solutions of Sulfuric Acid. Ind. and Eng. Chem.,
17:522-523, May 1925.
300. Johnstone,'H. F. An Electrical Method for the Determination
of the Dew Point of Flue Gases. Univ. of Illinois Sng.
Exp. Station, Circular 20, 1929.
301. Flint, D. The Investigation of Dew Point and Related Con-
densation Phenomena in Flue Gases. J. Inst. Fuel, 21:248,
1948.
302. Burnside, W., W. G. Marshall, and J. M. Miller. The In-
fluence of Superheater Metal Temperature on the Acid Dew
Point of Flue Gases. J. Inst. Fuel, 29:261, 1956.
303. Corbett, P. F., and D. Flint. The Influence of Certain
Smokes and Dusts on the SO3 Content of the Flue Gases in
Power Station Boilers. J. Inst. Fuel, 25:410, 1953.
621
-------
304. Dooley, A., and G. Whittingham. The Oxidation of Sulfur
Dioxide in Gas Flames. Trans. Faraday Soc., 42:354,
1946.
305. Whittingham, G. The Influence of Carbon Smokes on the
Dew Point and Sulfur Trioxide Content of Flame Gases.
J. Appl. Chenu, 1:382, September 1951.
306. Flint, D., and R. W. Kear. The Corrosion of a Steel
Surface by Condensed Films of Sulfuric Acid. J. Appl.
Chem., 1:388, 1951.
307. Lee, G. K., F. D. Friedrich, and E. R. Mitchell. Effect
of Fuel Characteristics and Excess Combustion Air on
Sulfuric Acid Formation in a Pulverized-Coal-Fired Boiler.
Department of Energy, Mines, and Resources, Mines Branch
(Canada), 9p., 1967.
308. Friedrich, F. D., G. K. Lee, and E. R. Mitchell. Com-
bustion and Fouling Characteristics of Two Canadian
Lignites. Department of Energy, Mines, and Resources,
Mines Branch (Canada), Research Report R208, 31p., August
1969.
309. Kear, R. W. The Influence of Carbon Smokes on the Corro-
sion of Metal Surfaces Exposed to Flue Gases. J. Appl.
Chem., 1:393, September 1951.
310. Black, A. W., C. F. Stark, and W. H. Underwood. Dew Point
Meter Measurements in Boiler Flue Gases. ASME Paper No.
60-WA-285, December 1960.
311. Clark, N. D., and G. D. Childs. Boiler Flue Gas Measure-
ments Using a Dew Point Meter. Trans. ASME 87(A-1), p. 8,
1965.
312. Taylor, A. A. Relation Between Dew Point and the Con-
centration of Sulfuric Acid in Flue Gases. J. Inst. Fuel
16:25, 1942.
313, Lisle, E. S. and J. D. Sensenbaugh. The Determination of
Sulfur Trioxide and Acid Dew Point in Flue Gases. Com-
bustion, 36(1):12, 1965.
314. Taylor, H. D. The Condensation of Sulfuric Acid on Cooled
Surfaces Exposed to Hot Gases Containing Sulfur Trioxide.
Trans. Faraday Soc., 47:1114, 1951.
315. Piper, John D., and H. Van Vliet. The Effect of Tempera-
ture Variation on Composition, Fouling Tendency, and
Corrosiveness of Combustion Gas from Pulverized-Fuel-
Fired Steam Generators. Trans. ASME, 80:1251, August
1958.
622
-------
316. Fontana, M. G. Corrosion: A Compilation, The Press of
Hollenback, 1957.
317. Thurlow, G. G. An Air Cooled Metal Probe for the In-
vestigation of the Corrosive Nature of Boiler Flue Gases.
J. Inst. Fuel, 25:252-255 and 260, 1952.
318. The Boiler Availability Committee (London). Testing
Techniques for Determining the Corrosive and Fouling
Tendencies of Boiler Flue Gases. (Bulletin No. MC/316),
p. 18, March 1961.
319. Southern Research Institute, Final Report on Contract
CPA 70-149. A Study of Resistivity and Conditioning of
Fly Ash, to Division of Control Systems, Office of Air
Programs, Environmental Protection Agency.
320. Halstead, W. D. The Behavior of Sulfur and Chlorine
Compounds in Pulverized-Coal-Fired Boilers. J. Inst.
Fuel, 42:344, September 1969.
321. Kear, R. W. The Effect of Hydrochloric Acid on the
Corrosive Nature of Combustion Gases Containing Sulfur
Trioxide. J. Appl. Chem., 5:237, May 1955.
322. Canady, B. L. High Pressure Jetting of Regenerative Air
Preheaters. Combustion, p. 55, February 1955.
323. Roddy, Charles P. Sulfur and Air Heater Corrosion. Power
Engineering, p. 40, January 1968.
324. Barkley, J. F.f et al. Corrosion and Deposits in Re-
generative Air.Heaters. U.S. Bureau of Mines Report of
Investigations 4996, 23 pp., August 1953.
325. Brownell, Wayne E. Analysis of Fly Ash Deposits from
Hoot Lake-Station. Report to The Air Preheater Corp.,
Wellesville,. New York, 12 pp., December 1961.
326. IGCI/ABMA Joint Technical Committee Survey. Criteria for
the Application of Dust Collectors to Coal-Fired Boilers.
April 1965.
326a. Dismukes. E. B. The Study of Resistivity and Conditioning
of Fly Ash. U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina, Februarv 1972. EPA-R2-72-
087. NTIS PB-212 607,
327. Clark, Norman D. Higher Efficiency Through Lower Stack
Temperature. The Air Preheater Corp., Wellesville, New
York.
328. Kear, R. W. A Constant Temperature Corrosion Probe. J.
Inst. Fuel, 32:267, 1959.
623
-------
329. Alexander, P. A., R. S. Fielder, P. J. Jackson, and E.
Raask. An Air-Cooled Probe for Measuring Acid Deposition
in Boiler Flue Gases. J. Inst. Fuel, 33:31, 1960.
330. CERL (private communication).
624
-------
APPENDIX A
POWER PLANT AND AIR QUALITY DATA FOR
THOSE PLANTS WITH ELECTROSTATIC PRECIPITATORS
625
-------
TABLE 44. POWER PLANT AND AIR QUALITY DATA FOR THOSE
PLANTS WITH ELECTROSTATIC PRECIPITATORS
o\
ro
Company Name*
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
Alabama Power
Alabama Power
Alabama Power
Alabama Power
Alabama Power
Alabama Power
Allegheny Power (Monongahela)
Allegheny Power (Monongahela)
Allegheny Power (Monongahela)
Allegheny Power {Monongahela)
Allegheny Power (Monongahela)
Allegheny Power (Monongahela)
Allegheny Power (Monongahela)
Allegheny Power (West Pa.)
Allegheny Power (West Pa.)
Allegheny Power (West Pa.)
Allegheny Power (West Pa.)
Allegheny Power (West Pa.)
Allegheny Power (West Pa.)
Allegheny Power (West Pa.)
Appalachian Power
Appalachian Power
Appalachian Power
Appalachian Power
Appalachian Power
Arizona Public Service
Arizona Public Service
Big Rivers Electric
Big Rivers Electric
Big Rivers Electric
Big Rivers Electric
Cardinal Operating Co.
Cardinal Operating Co.
Carolina Power & Light
Carolina Power & Light
Carolina Power & Light
Carolina Power & Light
Plant Name
Barry
Gorgas
Gorgas
Gorgas
Gadsden
Gadsden
Albright
Fort Martin
Fort Martin
Harrison
Harrison
Harrison
Willow Island
Armstrong
Armstrong
Hatfield
Hatfield
Hatfield
Mitchell
Springdale
Cabin Creek
Cabin Creek
Clinch River
Clinch River
Clinch Rivc'i
Four Cornei.-'
Four Corners
Kenneth Col etna n
Kenneth Coleman
Kenneth Coleman
Robert Reid
Cardinal
Cardinal
Asheville
Asheville
Cape Fear
Cape Fear
Boiler
Number
5
8
9
10
1
2
3
1
2
1
2
3
2
1
2
1
2
3
33
88
81,82
91,92
1
2
3
4
5
1
2
3
1
1
2
1
2
9
10
Average Heat
Content of
Coal, Btu/lb
11,995
11,591
11,591
11,591
11,905
11,905
11,757
12,100
12,100
12,246
12,246
12,246
11,238
11,327
11,327
12,007
12,007
12,007
12,700
13,266
13,007
13,007
12,012
12,012
12,012
8,924
8,924
10,890
10,890
10,890
10,344
11,338
11,338
11,936
11,936
12,340
12,340
Average
Sulfur
Content, %
2.34
1.22
1.22
1.22
1.99
1.99
2.09
2.41
2.41
4.05
4.05
4.05
3.82
2.67
2.67
2.46
2.46
2.46
2.17
1.56
1.20
1.20
0.86
0.86
0.86
0.63
0.63
3.76
3.76
3.76
3.72
2.97
2.97
1.38
1.38
1.25
1.25
Average
Ash
Content, %
11.67
14.53
14.53
14.53
13.14
13.14
15.84
13.30
13.30
15.31
15.31
15.31
17.36
17.49
17.49
15.39
15.39
15.39
9.85
7.08
8.69
8.69
15.13
15.13
15.13
21.76
21.76
12.54
32.54
12.54
15.40
16.01
16.01
11.03
J1.03
11.80
11.80
*The numbers in the first column correspond to the same plant names in Tables 45 and 46 as they do in Table 44
-------
TABLE 44. (Continued)
Company Name*
38 Carolina Power & Light
39 Carolina Power & Light
40 Carolina Power & Light
41 Carolina Power & Light
42 Carolina Power & Light
43 Carolina Power & Light
44 Carolina Power & Light
45 Carolina Power & Light
46 Carolina Power & Light
47 Carolina Power & Light
48 Carolina Power & Light
49 Carolina Power & Light
50 Carolina Power & Light
51 Cedar Falls Utilities
52 Central Illinois Light
53 Central Illinois Light
54 Central Illinois Light
55 Central Illinois Light
56 Central Illinois Light
57 Central Illinois Light
58 Central Illinois Light
59 Central Illinois Pub. Service
60 Central Illinois Pub. Service
61 Central Illinois Pub. Service
62 Central Illinois Pub. Service
63 Central Illinois Pub. Service
64 Central Illinois Pub. Service
65 Central Illinois Pub. Service
66 Central Illinois Pub. Service
67 Central Illinois Pub. Service
68 Central Illinois Pub. Service
69 Central Operating
70 Charleston Bottoms REC
71 Cincinnati Gas & Electric
72 Cincinnati Gas & Electric
73 Cincinnati Gas & Electric
74 Cincinnati Gas & 'Electric
75 Cincinnati Gas & Electric
76 Cincinnati Gas & Electric
77 Cincinnati Gas & Electric
78 City of Colorado Springs DPU
79 City of Colorado Springs DPU
80 City of Colorado Springs DPU
81 City of Peru
Plant Name
H. B. Robinson
H. P. Lee
H. F. Lee
Louis Sutton
Louis Sutton
Louis Sutton
Roxboro
Roxboro
Roxboro
Roxboro
W. H. Weatherspoon
W. H. Weatherspoon
W. H. Weatherspoon
Streeter
E. D. Edwards
E. D. Edwards
E. D. Edwards
R. S. Wallace
R. S. Wallace
R. S. Wallace
R. S. Wallace
Coffeen
Coffeen
Grand Tower
Grand Tower
Grand Tower
Meredosia
Meredosia
Meredosia
Meredosia
Meredosi a
Philip Sporn
H. L. Spurlock
Miami Fort
W. C. Beckjord
W. C. Beckjord
W. C. Beckjord
W. C. Beckjord
W. C. Iif:«-kjord
W. C. Beokjord
Martin Drake
Martin Drake
Martin Drake
Peru
Boiler
Number
1
1
2
1
2
3
1
2
3A
3B
1
2
3
7
1
2
3
7
8
9
10
1
2
7
8
9
1
2
3
4
5
5
1
6-1
1
2
3
4
5
6
5
6
7
2
Average Heat
Content of
Coal, Btu/lb
12,170
12,702
12,702
11,832
11,832
11,832
12,488
12,488
12,488
12,488
12,668
12,668
12,668
12,085
10,376
10,376
10,376
10,338
10,338
10,338
10,338
9,367
9,367
11,252
11,252
11,252
10,826
10,826
10,826
10,826
10,826
11,453
10,918
10,561
10,561
10,561
10,561
10,561
10,561
11,501
Average
Sulfur
Content, %
2.
2.
2,
.05
.10
.10
.26
.26
.26
.10
.10
.10
.10
.13
1.13
1.13
2.73
,83
.83
.83
2.59
2.59
2.59
2.59
4.43
4.43
3.33
.33
,33
.50
.50
.50
.50
.50
3.
3.
3,
3.
3.
3.
3.
1.26
3.21
2.63
2.63
2.63
2.63
2.63
2.63
2.87
Average
Ash
Content, %
10.98
9.90
9.90
14.63
14.63
14.63
9.90
9.90
9.90
9.90
9.15
9.15
9.15
6.49
10.30
10.30
10.30
9.17
9.17
9.17
9.17
20.33
20.33
11.88
11.88
11.88
9.34
9.34
9.34
9.34
9.34
15.10
14.54
18.37
18.37
18.37
18.37
18.37
18.37
9.96
-------
TABLE 44. (Continued)
Company Name*
82 City of Springfield Lt. & Pr.
83 City of Springfield Lt. & Pr.
84 City of Springfield Lt. & Pr.
85 City of Springfield Lt. & Pr.
86 City of Springfield Lt. & Pr.
87 City of Springfield Lt. & Pr.
88 City Util. of Springfield, Mo.
89 Cleveland Electric Illumtg.
90 Cleveland Electric Illumtg.
91 Cleveland Electric Illumtg.
92 Cleveland Electric Illumtg.
93 Cleveland Electric Illumtg.
94 Cleveland Electric Illumtg.
95 Cleveland Electric Illumtg.
96 Cleveland Electric Illumtg.
97 Cleveland Electric Illumtg.
98 Cleveland Electric Illumtg.
99 Cleveland Electric Illumtg.
100 Cleveland Electric Illumtg.
101 Cleveland Electric Illumtg.
102 Cleveland Electric Illumtg.
103 Cleveland Electric Illumtg.
104 Columbus & Southern Ohio Elec.
105 Commonwealth Edison
106 Commonwealth Edison
107 Commonwealth Edison
108 Commonwealth Edison
109 Commonwealth Edison
110 Commonwealth Edison
111 Commonwealth Edison
112 Commonwealth Edison
113 Commonwealth Edison
114 Commonwealth Edison
115 Commonwealth Edison
116 Commonwealth Edison
117 Commonwealth Edison
118 Commonwealth Edison
119 Commonwealth Edison
120 Commonwealth Edison
121 Commonwealth Edison
122 Commonwealth Edison
123 Commonwealth Edison
124 Commonwealth Edison
125 Commonwealth Edison
Plant Name
Lakeside
Lakeside
Lakeside
Lakeside
V. Y. Dallman
V. Y. Dallman
James River
Ashtabula
Ashtabula
Ashtabula
Ashtabula
Ashtabula
Avon Lake
Avon Lake
Avon Lake
Avon Lake
East Lake
Lake Shore
Lake Shore
Lake Shore
Lake Shore
Lake Shore
Conesvilie
Crawford
Crawford
Dixon
Dixon
Fisk
Fisk
Fisk
Joliet
Joliet
Joliet
Joliet
Joliet
Joliet
Joliet
Kincaid
Kincaid
Powerton
Powerton
Sabrooke
Waukegan
Waukegan
Boiler
Number
Average Heat
Content of
Coal, Btu/lb
5
6
7
8
31
32
5
7
8
9
10
11
9
10
11
12
5
91
92
93
94
18
4
7
8
4
5
18-1
18-2
19
3
4
5
71
72
81
82
1
2
51
52
4
14
15
10,578
10,578
30,578
10,578
10,791
10,791
11,688
11,589
11,589
11,589
11,589
11,589
11,684
11,684
11,684
11,684
11,845
12,059
12,059
12,059
12,059
12,059
10,455
9,239
9,239
10,539
10,539
9,261
9,261
9,261
10,033
10,033
10,033
10,033
10,033
JO, 033
10,033
9,718
9,718
10,699
10,699
10,722
10,045
10,045
Average
Sulfur
Content, %
3.91
3.91
3.9]
3.91
3.83
3.83
3.74
3.20
3.20
3.20
3.20
3.20
2.96
2.96
2.96
2.96
3.50
3.32
3.32
3.32
3.32
3.32
4.91
0.42
0.42
2.89
2.89
0.40
0.40
0.40
2.89
2,89
2.89
2.89
2.89
2.89
2.89
3.99
3.99
3.63
3.63
0.92
1.21
Average
Ash
Content, %
12.39
12.39
J2.39
12.39
11.59
11.59
17.97
14.31
14.31
14.31
14.31
14.31
12.02
12.02
12.02
12.02
11.20
11.82
11.82
11 .«2
11.82
11.82
18.35
4.98
4.98
10.94
10.94
4.61
4.61
4.61
13.39
13.39
13.39
13.39
13.39
13.39
13.39
15.16
15.16
8.44
8.44
15.90
9.40
1.21
9.40
-------
TABLE 44. (Continued)
a\
to
Company Name*
126 Commonwealth Edison
127 Commonwealth Edison
128 Commonwealth Edison
129 Commonwealth Edison
130 Commonwealth Edison
131 Commonwealth Edison
132 Commonwealth Edison
133 Commonwealth Edison
134 Commonwealth Edison/Indiana
135 Commonwealth Edison/Indiana
136 Commonwealth Edison/Indiana
137 Commonwealth Edison/Indiana
138 Commonwealth Edison/Indiana
139 Commonwealth Edison/Indiana
140 Commonwealth Edison/Indiana
141 Commonwealth Edison/Indiana
142 Commonwealth Edison/Indiana
143 Commonwealth Edison/Indiana
144 Commonwealth Edison/Indiana
145 Consolidated Edison/New York
146 Consolidated Edison/New York
147 Consolidated Edison/New York
148 Consolidated Edison/New York
149 Consolidated Edison/New York
150 Consolidated Edison/New York
151 Consumers Power
152 Consumers Power
153 Consumers Power
154 Consumers Power
155 Consumers Power
156 Consumers Power
157 Consumers Power
158 Consumers Power
159 Consumers Power
160 Consumers Power
161 Consumers Power
162 Dairyland Power Cooperative
163 Dairyland Power Cooperative
164 Dairyland Power Cooperative
165 Dairyland Power Cooperative
166 Dairyland Power Cooperative
167 Dairyland Power Cooperative
168 Dairyland Power Cooperative
169 Dairyland Power Cooperative
Plant Name
Waukegan
Waukegan
Waukegan
Waukegan
Will County
Will County
Will County
Will County
State Line
State Line
State Line
State Line
State Line
State Line
State Line
State Line
State Line
State Line
State Line
Astoria
Astoria
Astoria
Astoria
Astoria
Ravenswood
B. C. Cobb
Cobb
Cobb
Cobb
Cobl-
Karn
Karn
Weadock
Weadock
Campbel1
Campbel1
C
C
C
C
E
E
C
C
I!
II
Alma
Alma
Alma
Alma
Alma
Genoa #3
Stoneman
Stoneman
Boiler
Number
16
17
7
8
1
2
3
4
1-1
2-1
3-1
4-1
5-1
6-1
1-2
2-2
3-2
1-3
1-4
10
20
30
40
50
30
1
2
3
4
5
1
2
7
8
1
2
1
2
3
4
5
1
1
2
Average Heat
Content of
Coal, Btu/lb
10,045
10,045
10,045
10,045
9,377
9,377
9,377
9,377
9,730
9,730
9,730
9,730
9,730
9,730
9,730
9,730
9,730
9,730
9,730
11,462
11,462
11,462
11,462
11,462
11 ,138
11,138
11,240
11,240
11.187
II,187
11,666
11,666
11,666
11,666
11,666
10,600
11,658
11,658
Average
Sulfur
Content, %
1.21
1.21
1.21
1.21
1.58
1.58
1.58
1.58
1.53
1.53
1.53
1.53
1.53
1.53
1.53
1.53
1.53
1.53
1.53
Average
Ash
Content, %
9.40
9.40
9.40
9.40
8.35
8.35
8.35
8.35
11.00
11.00
11.00
11.00
11.00
11.00
11.00
11.00
11.00
11.00
11.00
3.27
3.27
3.27
3.27
3.27
3.21
3.21
2.73
2.73
3.61
3.61
2.97
2.97
2.97
2.97
2.97
4.10
3.60
3.60
11 .34
11.34
11.34
11 .34
11.34
14.55
14.55
13.27
13.27
16.12
16.12
17.89
17.89
17.89
17.89
17.89
24.59
18.79
18.79
-------
TABLE 44. (Continued)
Company Name*
170 Dallas Power & Light
171 Dallas Power & Light
172 Dallas Power & Light
173 Dayton Power & Light
174 Dayton Power & Light
175 Dayton Power & Light
176 Dayton Power & Light
177 Dayton Power 6 Light
178 Dayton Power & Light
179 Dayton Power & Light
180 Dayton Power & Light
181 Dayton Power & Light
182 Dayton Power & Light
183 Dayton Power 6 Light
184 Dayton Power & Light
185 Dayton Power & Light
186 Dayton Power & Light
187 Dayton Power & Light
188 Dayton Power 6 Light
189 Delmarva Power & Light
190 Delmarva Power 6 Light
191 Delmarva Power & Light
192 Delraarva Power & Light
193 Detroit Edison
194 Detroit Edison
195 Detroit Edison
196 Detroit Edison
197 Detroit Edison
198 Detroit Edison
199 Detroit Edison
200 Detroit Edison
201 Detroit Edison
202 Detroit Edison
203 Detroit Edison
204 Detroit Edison
205 Detroit Edison
206 Detroit Edison
207 Detroit Edison
208 Detroit Edison
209 Detroit Edison
210 Detroit Edison
211 Detroit Edison
212 Detroit Edison
213 Detroit Edison
Plant Name
Big Brown
Big Brown
Monticello
Frank M. Tait
Frank M. Tait
Frank M. Tait
Frank M. Tait
Frank M. Tait
Frank M. Tait
J. M. Stuart
J. M. Stuart
J. M. Stuart
J. M. Stuart
O. M. Hutchings
O. M. Hutchings
O. M. Hutchings
O. M. Hutchings
O. M. Hutchings
0. M. Hutchings
Delaware City
Indian River
Indian River
Indian River
Conners Creek
Conners Creek
Conners Creek
Conners Creek
Harbor Beach
Marysvillp
Marysville
Marysville
Marysville
Monroe
Monroe
Monroe
Monroe
Pennsalt
Pennsalt
River I'
St. Clair
St. Clair
St. Clair
St. Clair
St. Clair
Boiler
Number
1
2
1
4
5
7-1
7-2
8-1
8-2
1
2
3
4
1
2
3
4
5
6
4
1
2
3
15
16
17
18
1
9
10
11
12
1
2
3
4
23
24
2
1
2
3
4
6
Average Heat
Content of
Coal, Btu/lb
7,000
7,000
11,465
11,465
]1,465
11,465
11,465
11,465
11,053
11,053
Jl,053
11,053
12,186
12,186
12,186
12,186
12,186
12,186
14,170
12,130
12,130
12,130
11,645
11,645
11,645
11,645
11,500
11,698
]1,698
11,698
11,698
12,475
12,475
12,475
12,475
11,635
11,635
11,999
11,790
11,790
] J ,790
11,790
11,790
Average
Sulfur
Content, %
0.60
O.GO
—
0.97
0.97
0.97
0.97
0.97
0.97
1 .68
1.68
1.68
1.68
0.86
0.86
0.86
0.86
0.86
0.86
6.70
1.63
1.63
1.63
1.81
1.81
1.81
1.81
3.03
2.87
2.87
2.87
2.87
2.77
2.77
2.77
2.77
1.44
1.44
3.37
3.01
3.01
3.01
3.01
3.01
Average
Ash
Content, %
10.40
10.40
13.67
13.67
13.67
13.67
13.67
13.67
15.88
15.88
15.88
15.88
10.71
10.71
10.71
10.71
10.71
10.71
O.TO
11.76
11.76
11.76
13.75
13.75
13.75
13.75
13.38
13.46
13.46
13.46
13.46
12.10
12.10
12.10
12.10
13.38
13.38
11.75
13.48
13.48
13.48
13.48
13.48
-------
TABLE 44. (Continued)
a\
OJ
Company Name*
214 Detroit Edison
2]5 Detroit Edison
216 Detroit Edison
217 Detroit Edison
218 Detroit Edison
219 Duke Power
220 Duke Power
221 Duke Power
222 Duke Power
223 Duke Power
224 Duke Power
225 Duke Power
226 Duke Power
227 Duke Power
228 Duke Power
229 Duke Power
230 Duke Power
231 Duke Power
232 Duke Power
233 Duke Power
234 Duke Power
235 Duke Power
236 Duke Power
237 Duke Power
238 Duke Power
239 Duke Power
240 Duke Power
241 Duke Power
242 Duke Power
243 Duke Power
244 Duke Power
245 Duke Power
246 Duke Power
247 Duke Power
248 Duquesne Light Co.
249 Duquesne Light Co.
250 Duquesne Light Co.
251 Duquesne Light Co.
252 Duquesne Light Co.
253 Duquesne Light Co.
254 Duquesne Light Co.
255 Duquesne Light Co.
256 Duquesne Light Co.
257 Duquesne Light Co.
Plant Name
St. Clair
Wyandotte
Wyandotte
Wyandotte
Wyandotte
Allen
Allen
Allen
Allen
Allen
Belews Creek
Buck
Buck
Buck
Buck
Buck
Cliffside
Cliffside
Cliffside
Cliffside
Dan River
Dan River
Dan River
Lee
Lee
Lee
Marshal 1
Marshal 1
Marshall
Marshall
Riverbend
Riverbend
Ri verbend
Riverbend
Cheswick
Elrama
Elrama
Elrama
Elrama
Phillips
Phillips
Phillips
Phillips
Phillips
Boiler
Number
7
9
10
11
12
1
2
3
4
5
1
5
6
7
8
9
1
2
3
4
1
2
3
1
2
3
1
2
3
4
7
8
9
10
1
1
2
3
4
1
2
3
4
5
Average Heat
Content of
Coal, Btu/lb
11,790
11,777
11,777
11,777
11,777
11,965
11,965
11,965
11,965
11,965
12,125
12,125
12,125
12,125
12,125
12,368
12,368
12,368
12,368
11,963
11,963
11,963
11,545
11,545
11,545
11,737
11,737
11,737
11,737
11,834
11,834
11,834
11,834
11,038
10,996
10,996
10,996
10,996
11,342
11,342
11,342
11,342
11,342
Average
Sulfur
Content, %
3.01
1.13
1.13
1.13
1.13
0.89
0.89
0.89
0.89
0.89
0.88
0.88
0.88
0.88
0.88
1.30
1.30
1.30
1 .30
0.92
0.92
0.92
1.17
1.17
1.17
0.96
0.96
0.96
0.96
0.89
0.89
0.89
0.89
2.16
2.13
2.13
2.13
2.13
1.89
1.89
1.89
1.89
1.89
Average
Ash
Content, %
13.48
12.34
12.34
12.34
12.34
12.53
12.53
12.53
12.53
12.53
11.54
11.54
11.54
11.54
11.54
13.57
13.57
13.57
13.57
12.69
12.69
12.69
14.21
14.21
14.21
13.55
13.55
13.55
13.55
13.64
13.64
13.64
13.64
20.33
20.07
20.07
20.07
20.07
16.74
16.74
16.74
16.74
16.74
-------
TABLE 44. (Continued)
Company Name*
258 Duquesne Light Co.
259 East Kentucky Power Coop.
260 East Kentucky Power Coop.
261 East Kentucky Power Coop.
262 East Kentucky Power Coop.
263 Electric Energy, Inc.
264 Electric Energy, Inc.
265 Electric Energy, Inc.
266 Empire District Electric
267 Georgia Power
268 Georgia Power
269 Georgia Power
270 Georgia Power
271 Georgia Power
272 Georgia Power
273 Georgia Power
274 Georgia Power
275 Georgia Power
276 Georgia Power
277 Georgia Power
278 Georgia Power
279 Georgia Power
280 Georgia Power
281 Georgia Power
282 Georgia Power
283 Georgia Power
284 Georgia Power
285 Georgia Power
286 Georgia Power
287 Georgia Power
288 Georgia Power
289 Georgia Power
290 Georgia Power
291 Georgia Power
292 Georgia Power
293 Georgia Power
294 Gulf Power
295 Gulf Power
296 Gulf Power
297 Gulf Power
298 Gulf Power
299 Gulf Power
300 Gulf Power
301 Gulf Power
Plant Name
Phillips
John S. Cooper
John S. Cooper
William Dale
William Dale
Joppa
Joppa
Joppa
Asbury
Arkwright
Arkwright
Arkwright
Arkwright
Hammond
Hammond
Hammond
Hammond
H. L. Bowen
H. L. Bowen
H. L. Bowen
Jack McDonough
Jack McDonough
Plant Harllee
Plant Harllee
Plant Harllee
Plant Harllee
Mitchell
Mitchell
Mitchell
Yates
Yates
Yates
Yates
Yates
Yates
Yates
Lansing Smith
Lansing Smith
Crist
Crist
Crist
Crist
Scholz
Scholz
Boiler
Number
Average Heat
Content of
Coal, Btu/lb
6
1
2
3
4
1-2
3-4
5-6
1
1
2
3
4
1
2
3
4
1
2
3
1
2
1
2
3
4
1
2
3
1
2
3
4
5
6
7
1
2
4
5
6
7
1
2
11,342
11,435
11,435
11,380
3 1 ,380
11,439
11,439
11,439
10,238
11,904
11 ,904
11,904
11,904
11,329
11,329
11,329
11,329
11,444
11,444
11,444
1] ,887
11,887
12,156
12,156
12,156
12,156
11,519
11,519
11,519
12,284
12,284
12,284
12,284
12,284
12,284
12,284
11,510
11,510
11,883
11,883
11,883
11,883
12,455
12,455
Average
Sulfur
Content, %
1.89
2.35
2.35
1.62
1.62
2.38
2.38
2.38
4.43
2.00
2.00
2.00
2.00
3.25
3.25
3.25
3.25
3.13
3.13
3.13
1.05
1.05
0.94
0.94
0.94
0.94
1.42
1.42
1.42
2.22
2.22
2.22
2.22
2.22
2.22
2.22
2.84
2.84
3.11
3.11
3.11
3.11
1.41
1.41
Average
Ash
Content, %
16.74
15.32
15.32
14.00
14.00
10.21
30.21
10,21
24.13
12.77
12.77
12.77
12.77
9.49
9.49
9.49
9.49
10.73
10.73
10.73
12.99
12.99
10.53
10.53
10.53
10.53
15.01
15.01
15.01
9.25
9.25
9,25
9.25
9.25
9.25
9.25
11.18
11.18
10.92
10.92
10.92
10.92
12.55
12.55
-------
TABLE 44. (Continued)
OJ
U>
Company Name*
302 Hartford Electric
303 Hartford Electric
304 Henderson Municipal
305 Henderson Municipal
306 Holland Board of Public Works
307 Illinois Power Company
308 Illinois Power Company
309 Illinois Power Company
310 Illinois Power Company
311 Illinois Power Company
312 Illinois Power Company
313 Illinois Power Company
314 Illinois Power Company
315 Indiana-Kentucky Elec. Corp.
316 Indiana-Kentucky Elec. Corp.
317 Indiana-Kentucky Elec. Corp.
318 Indiana-Kentucky Elec. Corp.
319 Indiana-Kentucky Elec. Corp.
320 Indiana-Kentucky Elec. Corp.
321 Indiana & Michigan Elec. Co.
322 Indianapolis Power & Light Co.
323 Indianapolis Power & Light Co.
324 Indianapolis Power & Light Co.
325 Indianapolis Power & Light Co.
326 Indianapolis Power & Light Co.
327 Indianapolis Power & Light Co.
328 Indianapolis Power & Light Co.
329 Indianapolis Power & Light Co.
330 Indianapolis Power & Light Co.
331 Indianapolis Power & Light Co.
332 Indianapolis Power & Light Co.
333 Indianapolis Power & Light Co.
334 Indianapolis Power & Light Co.
335 Indianapolis Power & Light Co.
336 Interstate Power Company
337 Interstate Power Company
338 Iowa Electric Light & Power
339 Iowa Electric Light & Power
340 Iowa Electric Light & Power
341 Iowa Electric Light & Power
342 Iowa Electric Light & Power
343 Iowa-Illinois Gas & Electric
344 Iowa-Illinois Gas & Electric
345 Iowa-Illinois Gas & Electric
Boiler
Plant Name Number
Middletown 1
Middletown 2
Station 2 1
Station 2 2
James De Young 5
Baldwin 1
Baldwin 2
llerinepin 1
Hennepin 2
Vermilion 1
Vermilion 2
Wood River 4
Wood River 5
Clifty Creek 1
Clifty Creek 2
Clifty Creek 3
Clifty Creek 4
Clifty Creek 5
Clifty Creek 6
Tanners Creek 4
C. C. Perry K 11
C. C. Perry K 32
C. C. Perry K 13
C. C. Perry K 14
C. C. Perry K 15
C. C. Perry K 16
E. W. Stout 50
E. W. Stout 60
H. T. Pr it-chard 3
H. T. Pritchard 4
H. T. Pritchard 5
H. T. Pritchard 6
Petersburg 1
Petersburg 2
Dubuque 1
M. L. Kapp 2
Prairie Creek Station 1-2-3 3
Sixth Creek Station 3-4
Sixth Creek Station 5-6
Sixth rreek Station 7-8
Sixth Creek Station 9-10
Riverside 5
Riverside 6
Riverside 7
Average Heat
Content of
Coal. Btu/lb
11,746
11,746
10,347
10,347
12,404
10,285
10,285
10,890
10,890
10,858
10,858
10,991
10,991
10,852
10,852
10,852
10,852
10,852
10,852
10,995
11,299
11,299
11,299
11,299
11,299
11,299
11,076
11,076
11,112
11,112
11.112
11,112
10,954
10,954
11,169
11,211
10,941
10,285
10,285
10,285
10,285
10,805
10,805
10,805
Average
Sulfur
Content, %
2.25
2.25
.80
.80
.22
,27
.27
.00
.00
.90
,90
2.97
2.97
3.64
3.64
3.64
3.64
3.64
3.64
3.43
2.29
2.29
2.29
2.29
2.29
2.29
2.64
2.64
2.39
2.39
2.39
2.39
2.98
2.98
2.86
2.92
2.48
2.34
2.34
2.34
2.34
2.48
2.48
2.48
Average
Ash
Content, %
15.00
15.00
15.48
15.48
7.97
12.79
12.79
10.00
10.00
11.33
11.33
10.30
10.30
11.69
11.69
11.69
11.69
11.69
11.69
13.03
9.35
9.35
9.35
9.35
9.35
9.35
9.30
9.30
9.70
9.70
9.70
9.70
9.77
9.77
13.19
10.85
9.10
8.04
8.04
8.04
8.04
8.68
8.68
8.68
-------
TABLE 44. (Continued)
Company Name*
Plant Name
346
347
348
349
350
351
352
353
354
355
356
357
358
359
360
361
362
363
364
365
366
367
368
369
370
371
372
373
374
375
376
377
378
379
380
381
382
383
384
385
386
387
388
389
Iowa-Illinois Gas & Electric
Iowa-Illinois Gas & Electric
Iowa Power & Light Company
Iowa Power & Light Company
Iowa Power & Light Company
Iowa Power & Light Company
Iowa Public Service Company
Iowa Public Service Company
Iowa Public Service Company
Iowa Southern Utilities
Kansas City Bd. of Pub. Util.
Kansas City Bd. of Pub. Util.
Kansas City Bd. of Pub. Util.
Kansas City Power & Light
Kansas City Power & Light
Kansas City Power & Light
Kansas City Power & Light
Kansas City Power & Light
Kentucky Power Company
Kentucky Power Company
Kentucky Utilities Company
Kentucky Utilities Company
Kentucky Utilities Company
Kentucky Utilities Company
Kentucky Utilities Company
Lansing Bd. of Water & Light
Lansing Bd. of Water & Light
Lansing fld. of Water & Light
Lansing Bd. of Water & Light
Lansing Bd. of Water & Light
Lansing Bd . of Water & Light
Lansing Bd. of Water s Light
Lansing Bd. of Water & Light
Lansing Bd. of Water & Light
Lansing Bd . of Water & Light
Lansing Bd. of Water 6 Light
Lansing Bd. of Water (, Light
Louisville Gas & Elec. Co.
Louisville Gas & Elec. Co.
Louisville Gas & Elec. Co.
Louisville Gas & Elec. Co.
Louisville Gas & Elec. Co.
Louisville Gas & Elec. Co.
Louisville Gas & Elec. Co.
Riverside
Riverside
Council Bluffs
Council Bluffs
Des Moines
Des Moines
Maynard
Neal
Neal
Burlington
Raw
Quindaro No. 3
Quindaro No. 3
Grand Avenue
Hawthorn
Montrose
Montrose
Montrose
Big Sandy
Big Sandy
E . W . Brown
E . W . Brown
Ghent
Green River
Tyrone
Eckert
Eckert
Eckert
Eckert
Eckert
Eckert
Erickson
Ottawa
Ottawa
Ottawa
Ottawa
Ottawa
Cane Run
Cane Hun
Cane Run
Cane Run
Cane Run
•Cane Run
Mill Creek
Boiler
Number
8
9
1
2
JO
11
14
1
2
1
3
1
2
7
5
1
2
3
1
2
1
3
1
4
5
1
2
3
4
5
6
1
1
2
3
4
5
1
2
3
4
5
6
1
Average Heat
Content of
Coal, Btu/lb
10,805
10,805
10,143
10,143
9,549
9,549
10,960
9,981
9,981
10,183
11,784
11,492
11,492
12.336
10,566
9,413
9,413
9,413
11,835
11,835
11,804
11,804
10,917
11 .364
11,570
12,319
12,319
12,319
12,319
12,319
12,319
12,270
12,437
12,437
12,437
12,437
12,437
11,075
11,075
11,075
.11,075
11,075
11,075
11,152
Average
Sulfur
Content, %
2.48
2.48
1.09
1.09
2.94
2.94
2.86
0.60
0.60
2.58
3.90
1.61
1.61
3.71
1.40
5.51
5.51
5.51
0.97
0.97
1.72
1.72
2.76
2.58
0.90
2.98
2.98
2.98
2.98
2.98
2.98
2.92
2.74
2.74
2.74
2.74
2.74
3.76
3.76
3.76
3.76
3.76
3.76
3.80
Average
Ash
Content, %
8.68
8.68
8.96
8.96
13.65
13.65
10.21
11.22
11.22
13.70
13.75
11.14
11.14
11.08
9.53
23.19
23.19
23.19
12.49
12.49
13.25
13.25
10.19
10.15
12.39
10.74
10.74
10.74
10.74
10.74
10.74
11.61
7.96
7.96
7.96
7.96
7.96
14.02
14.02
14.02
14.02
14.02
14.02
13.76
-------
TABLE 44. (Continued)
Company Name*
390
391
392
393
394
395
396
397
398
399
400
401
402
403
404
405
406
407
408
409
410
411
412
413
414
415
416
417
418
4]9
420
421
422
423
424
425
426
427
428
429
430
431
432
433
Louisville Gas & Elec. Co.
Louisville Gas & Elec. Co.
Louisville Gas & Elec. Co.
Louisville Gas & Elec. Co.
Louisville Gas & Elec. Co.
Louisville Gas & Elec. Co.
Louisville Gas & Elec. Co.
Madison Gas & Elec. Co.
Metropolitan Edison Co.
Metropolitan Edison Co.
Metropolitan Edison Co.
Metropolitan Edison Co.
Metropolitan Edison Co.
Metropolitan Edison Co.
Metropolitan Edison Co.
Michigan State Universi ty
Michigan State University
Michigan State University
Mississippi Power Company
Mississippi Power Company
Montana Power Company
Municipal Power & Light
Muscatine Power & Light
N. Y. State Elec.
Y. State Elec.
Y. State Elec.
Y. State Elec.
Y. State Elec.
Y. State Elec.
Y. State Elec.
Y. State Elec.
Y. State Elec.
Y. State Elec.
Y. State Elec.
Y. State Elec.
N.
N.
N.
N.
N.
N.
N.
N.
N.
N.
N.
No.
No.
No.
No.
No.
No.
No.
No.
No.
Indiana Pub.
Indiana Pub.
Indiana Pub.
Indiana Pub.
Indiana Pub.
Indiana Pub.
Indiana Pub.
& Gas
& Gas
& Gas
& Gas
& Gas
& Gas
& Gas
& Gas
& Gas
& Gas
& Gas
Si Gas
Service Co.
Service Co.
Service Co.
Service Co.
Service Co.
Service Co.
Service Co.
Indiana Pub. Service Co.
Indiana Pub. Service Co.
Plant Name
Mill Creek
Paddy's Run
Paddy's Run
Paddy's Run
Paddy's Run
Paddy's Run
Paddy's Run
Blount Street
Crawford
Crawford
Portland
Portland
Titus
Ti tus
Titus
Power Plant '65
Power Plant '65
Power Plant '65
Jack Watson
Jack Watson
J. E. Corette
Station One
Muscatine Municipal
Goudey
Goudey
Goudey
Greenidge
Greenidge
Greenidge
Hickling
Hickling
Hickling
Hickling
Mil liken
Milliken
Uailly
Bailly
Dean H. Mitchell
Dean H. Mitchell
Dean H. Mitchell
Dean H. Mitchell
Michigan City
Michigan City
Michigan City
Boiler
Number
2
1
2
3
4
5
6
9
7
8
1
2
1
2
3
1
2
3
4
5
1
6
8
11
12
13
4
5
6
1
2
3
4
1
2
7
8
4
5
6
11
4
5
6
Average Heat
Content of
Coal, Btu/lb
11,152
11,368
11,368
11,368
11,368
11,368
11,368
11,535
12,660
12,660
12,473
12,473
12,224
12,224
12,224
12,639
12,639
12,639
11,885
11,885
8,582
10,712
11,341
11,341
11.341
11,638
11,638
11,638
10,917
10,917
10,917
10,917
11,317
11,317
11,109
11,109
11,146
11,146
11,146
11,146
10,558
10,558
10,558
Average
Sulfur
Content, %
3.80
3.42
3.42
3.42
.42
,42
3.42
3.06
1.21
1.21
1.53
1.53
0.96
0.96
0.96
0.98
0.98
0.98
2.70
2.70
0.67
3.
2.
2.
2.
1.
1,
1,
1.
1.
1.
1.
2.
2.
3.
3.
3.
3.
3.
.09
.20
.20
,20
,98
.98
.98
.98
.98
.98
.98
.08
.08
.62
.62
.18
.18
,18
3.18
3.36
3.36
3.36
Average
Ash
Content, %
13.76
12.57
12.57
12.57
12.57
12.57
12.57
8.79
10.70
10.70
11.35
11.35
11.97
11.97
11.97
9.70
9.70
9.70
10.88
10.88
8.22
10.22
18.45
18.45
18.45
15.20
15.20
15.20
15.20
15.20
15.20
15.20
16.37
16.37
10.00
10.00
9.32
9.32
9.32
9.32
11.14
11.14
11.14
-------
TABLE 44. (Continued)
Company Name*
434 No.-Indiana Pub. Service Co.
435 No. Indiana Pub. Service Co.
436 No. Indiana Pub. Service Co.
437 No. Indiana Pub. Service Co.
438 Northern States Power Co.
439 Northern States Power Co.
440 Northern States Power Co.
441 Northern States Power Co.
442 Northern States Power Co.
443 Northern States Power Co.
444 Northern States Power Co.
445 Northern States Power Co.
446 Northern States Power Co.
447 Northern States Power Co.
448 Ohio Edison Company
449 Ohio Edison Company
450 Ohio Edison Company
451 Ohio Edison Company
452 Ohio Edison Company
453 Ohio Edison Company
454 Ohio Edison Company
455 Ohio Edison Company
456 Ohio Edison Company
457 Ohio Edison Company
458 Ohio Edison Company
459 Ohio Edison Company
460 Ohio Edison Company
461 Ohio Edison Company
462 Ohio Edison Company
463 Ohio Edison Company
464 Ohio Edison Company
465 Ohio Edison Company
466 Ohio Edison Company
467 Ohio Edison Company
468 Ohio Edison Company
469 Ohio Electric Company
470 Ohio Power Company
471 Ohio Power Company
472 Ohio Power Company
473 Ohio Power Company
474 Ohio Power Company
475 Ohio Power Company
476 Ohio Power Company
477 Ohio Valley Elec. Corp.
Plant Name
Michigan City
ADVANCE
ADVANCE
ADVANCE
A. S. King
Black Dog
Black Dog
Black Dog
Black Dog
High Bridge
High Bridge
High Bridge
High Bridge
Minnesota Valley
Edgewater
Edgewater
Edgewater
Gorge
Gorge
Norwalk
R. E. Burger
Burger
Burger
Burger
Burger
Burger
Burger
BUJ aer
Snmmis
Sammis
Sammis
Sammis
Sammis
Sammis
Sammis
E.
E.
E.
E.
E.
E.
E.
H.
H.
II.
H.
II.
H.
H.
Gavin
Mitchell
Mitchell
Muskirtqum River
Muskiii'jum River
Muskingum River
Muskingum River
Muskingum River
Kyger Creek
Boiler
Number
12
1
2
3
1
1
2
3
4
9
10
11
12
4
11
12
13
25
26
5
1
2
3
4
5
6
7
8
1
2
3
4
5
6
7
1
1
2
1
2
3
4
5
1
Average Heat
Content of
Coal, Btu/lb
10,558
12,341
]2,341
12,341
10,567
10,108
10,108
10,108
10,108
9,666
9,666
9,666
9,666
10,044
12,267
12,267
12,267
10,792
10,792
1] ,322
11,457
11,457
11,457
11,457
11,457
11,457
11,457
11,457
11,367
11,367
11,367
11,367
11,367
11,367
11,367
11,601
11,601
10,448
10,448
10,448
30,448
10,448
11,580
Average
Sulfur
Content, %
3.36
2.38
2.38
2.38
3.32
2.27
2.27
2.27
2.27
1.82
1.82
1.82
1.82
1.28
2.68
2.68
2.68
3.22
3.22
3.55
3.25
3.25
3.25
3.25
3.25
3.25
3.25
3.25
2.99
2.99
2.99
2,99
2.99
2.99
2.99
--
3,35
3.35
4.64
4.64
4.64
4.64
4.64
3.89
Average
Ash
Content, %
11.14
8.95
8.95
8.95
15.17
11.73
11.73
11.73
11.73
9.71
9.71
9.71
9.71
9.20
10.13
10.13
10.13
15.25
15.25
13.10
13.93
13.93
13.93
13.93
13.93
13.93
13.93
13.93
15.79
15.79
15.79
15.79
15.79
15.79
15.79
15.20
15.20
19.35
19.35
19.35
19.35
19.35
14.52
-------
TABLE 44. (Continued)
en
U)
-j
Company Name*
478 Ohio.Valley Elec. Corp.
479 Ohio Valley Elec. Corp.
480 Ohio Valley Elec. Corp.
481 Ohio Valley Elec. Corp.
482 Omaha Public Power Dist.
483 Omaha Public Power Dist.
484 Omaha Public Power Dist.
485 Omaha Public Power Dist.
486 Omaha Public Power Dist.
487 Otter Tail Power Company
488 Otter Tail Power Company
489 Owensboro Munic. Utilities
490 Owensboro Munic. Utilities
491 Owensboro Munic. Utililies
492 Owensboro Munic. Utilities
493 Owensboro Munic. Utilities
494 Owensboro Munic. Utilities
495 Pacific Power & Light Co.
496 Pacific Power & Light Co.
497 Pacific Power & Light Co.
498 Pella Munic. Power & Light
499 Pella Munic. Power & Light
500 Pennsylvania Electric Co.
501 Pennsylvania Electric Co.
502 Pennsylvania Electric Co.
503 Pennsylvania Electric Co.
504 Pennsylvania Electric Co.
505 Pennsylvania Electric Co.
506 Pennsylvania Electric Co.
507 Pennsylvania Electric Co.
508 Pennsylvania Electric Co.
509 Pennsylvania Electric Co.
510 Pennsylvania Electric Co.
511 Pennsylvania Electric Co.
512 Pennsylvania Electric Co.
513 Pennsylvania Electric Co.
514 Pennsylvania Electric Co.
515 Pennsylvania Electric Co.
516 Pennsylvania Electric Co.
517 Pennsylvania Electric Co.
518 Pennsylvania Electric Co.
519 Pennsylvania Electric Co.
520 Pennsylvania Electric Co.
521 Pennsylvania Power Company
Plant Name
Kyger Creek
Kyger Creek
Kyger Creek
Kyger Creek
North Omaha
North Omaha
North Omaha
North Omaha
North Omaha
Hoot Lake
Hoot Lake
Elmer Smith
Elmer Smith
Owensboro Plant 1
Owensboro Plant 1
Owensboro Plant 1
Owensboro Plant 1
Centralia
Centralia
Jim Dridger
Pella
Pella
Homer City
Homer City
Conemaugh
Conemaugh
Front Street
Front Street
Front Stre<-t
Front Street
Keystone
Keystone
Seward
Seward
Seward
Shawville
Shawville
Shawville
Shawvi1 le
Warren
Warren
Warren
Warren
New Castle
Boiler
Number
2
3
4
5
1
2
3
4
5
2
3
I
2
1
2
3
4
1
2
1
6
7
1
2
1
2
7
8
9
10
1
2
12
14
15
1
2
3
4
1
2
3
4
1
Average Heat
Content of
Coal, Btu/lb
11,586
11,586
11,586
11,586
10,953
10,953
10,953
10,953
10,953
7,093
7,093
10.993
10,993
11,027
11,027
11,027
11,027
7,552
7,552
9,410
9,410
11,766
11,766
11,437
11,437
12.101
12,101
12,101
12,101
11,640
11,640
12,076
12,076
12,076
12,461
12,461
12,461
12.461
12,196
12,196
12,196
12,196
12,462
Average
Sulfur
Content, %
89
89
89
89
48
48
48
48
48
0.72
0.72
3.11
3.11
3.12
3.12
3.12
3.12
0.49
0.49
6.43
6.43
2.40
2.40
2.29
2.29
2.12
2.12
2.12
2.12
2.24
2.24
2.97
2.97
2.97
2.06
2.06
2.06
2.06
2.12
2.12
2.12
2.12
3.24
Average
Ash
Content, %
14.52
14.52
14.52
14.52
9.12
9,12
9.12
9.12
9.12
6.16
6.16
10.48
10.48
10.35
10.35
10.35
10.35
14.88
14.88
17.24
17.24
19.30
19.30
18.68
18.68
13.17
13.17
13.17
13.17
20.36
20.36
18.16
18.16
18.16
12.53
12.53
12.53
12.53
11.92
11.92
11.92
11.92
10.70
-------
TABLE 44. (Continued)
Company Name*
522
523
524
525
526
527
528
529
530
531
532
533
534
535
536
537
538
539
540
541
542
543
544
545
546
547
548
549
550
551
552
553
554
555
556
557
558
559
560
561
562
563
564
565
Pennsylvania Power Company
Pennsylvania Power Company
Pennsylvania Power Company
Pennsylvania Power Company
Penn. Power & Light Co.
Penn. Power & Light Co.
Penn. Power & Light Co.
Penn. Power & Light Co.
Penn. Power & Light Co.
Penn. Power & Light Co.
Penn. Power & Light Co.
Penn. Power S Light Co.
Penn. Power & Light Co.
Penn. Power & Light Co.
Penn. Power 6 Light Co.
Penn. Power 6 Light Co.
Penn. Power & Light Co.
Penn. Power & Light Co.
Philadelphia Electric Co.
Philadelphia Electric Co.
Potomac Electric
Potomac Electric
Potomac Electric
Potomac Electric
Potomac Electric
Potomac Electric
Potomac Electric
Potomac Electric
Potomac Electric
Potomac Electric
Potomac Electric
Potomac Electric
Potomac Electric
Public
Public
Public
Public
Public
Public
Public
Public
Public
Public
Public
Serv.
Serv.
Serv.
Serv.
Serv.
Serv.
Serv.
Serv.
Serv.
Serv.
Serv.
Co.
Co.
Co.
Co.
Co.
Co.
Co.
Co.
Co.
Co.
Co.
of
of
of
of
of
of
of
of
of
of
of
Colorado
Colorado
Colorado
Colorado
Colorado
Colorado
Colorado
Colorado
Colorado
Colorado
Colorado
Plant Name
New Castle
New Castle
New Castle
New Castle
Brunner Island
Brunner Island
Brunner Island
Hoitwood
Martins Creek
Martins Creek
Montour
Moiitour
Suubury
Sunbury
Sunbury
Sunbury
Sunbury
Sunbury
Eddystone
Eddystone
Benning
Benning
Chalk Point
Chalk Point
Dickerson
Dickerson
Dickerson
Morgantown
Morgantown
Potomac kiver
Potomac River
Potomac River
Potomac River
Arapahoe
Arapahoe
Arapahoe
Cameo
Cherokee
Cherokee
Cherokee
Cherokee
Comanche
Valmont
. Zuni
Boiler
Number
2
3
4
5
1
2
3
17
1
2
1
2
1A
IB
2A
2B
3
4
1
2
25
26
1
2
1
2
3
1
2
1
2
3
4
2
3
4
2
1
2
3
4
1
5
3
Average Heat
Content of
Coal, Btu/lb
12,462
12,462
12,462
12,462
12,460
12,460
12,460
10,205
12,639
12,639
12,565
12,565
11,407
11,407
11,407
11,407
11,407
11,407
13,026
13,026
13,106
13,106
12,341
12,341
12,209
12,209
12,209
12,693
12,693
12,683
12,683
12,683
12,683
10,234
10,234
10,234
11,008
10,768
10,768
10,768
10,768
8,620
10,400
Average
Sulfur
Content, %
3.24
3.24
3.24
3.24
1 .99
1.99
1.99
0.70
2.07
2.07
1.79
1.79
1.99
1.99
1.99
1.99
1.99
1.99
2.37
2.37
0.90
0.90
1.70
1.70
1.64
1.64
1.64
1.78
1.78
0.84
0.84
0.84
0.84
0.73
0.73
0.73
0.52
0.51
0.51
0.51
6.51
0.30
0.82
--
Average
Ash
Content, %
10.70
10.70
10.70
10.70
13.74
13.74
13.74
19.20
1L.46
11.46
13.17
13.17
15.52
15.52
15.52
15.52
15.52
15.52
8.62
8.62
9.01
9.01
12.16
12.16
12.86
12.86
12.86
13.34
13.34
10.69
10.69
10.69
10.69
7.48
7.48
7.48
10.08
8.47
8.47
8.47
8.47
5.10
7.53
-------
TABLE 44. (Continued)
Company Name*
566
567
568
569
570
571
572
573
574
575
576
577
578
579
500
581
582
583
584
585
586
587
588
589
590
591
592
593
594
595
596
597
598
599
600
601
602
603
604
605
606
607
608
609
Public Serv. Co. of Indiana
Public Serv. Co. of Indiana
Public Serv. Co. of Indiana
Public Serv. Co. of Indiana
Public Serv. Co. of Indiana
Public Serv. Co. of Indiana
Public Serv. Co. of Indiana
Public Serv. Co. of Indiana
Public Serv. Co. of Indiana
Public Serv. Co. of Indiana
Public Serv. Co. of Indiana
Public Serv. Co. of Indiana
Public Serv. Co. of Indiana
Public Serv. Co. of Indiana
Public Serv. Co. of Indiana
Public Serv. Co. of Indiana
Public Serv. Co. of Indiana
Public Serv. Co. of Indiana
Pub. Serv. Co. of N. Hamp.
Pub. Serv. Co. of N. Hamp.
Pub. Serv. Co. of N. Mexico
Richmond Power & Light
Richmond Power & Light
Rochester Dept. of Pub. Utl
Rochester Gas & Elec. Corp.
Rochester Gas & Elec. Corp.
Rochester Gas & Elec. Corp.
Rochester Gas & Elec. Corp.
Rochester Gas & Elec. Corp.
Salt River Project
Salt River Project
S. Carolina Elec. & Gas
S. Carolina Elec. & Gas
S. Carolina Elec. & Gas
S. Carolina Elec. & Gas
S. Carolina Elec. & Gas
S. Carolina Elec. & Gas
S. Carolina Elec. & Gas
S. Carolina Elec. & Gas
S. Carolina Elec. & Gas
S. Carolina Elec. & Gas
S. Carolina Elec. & Gas
S. Carolina Elec. & Gas
S. Carolina Elec. & Gas
Plant Name
Cayuga
Cayuga
Edwardsport
Edwardsport
Edwardsport
Gallagher
Gallagher
Gallagher
Gallagher
Noblesville
Noblesvi11e
Noblesville
Wabash Ri ver
Wabash River
Wabash River
Wabash River
Wabash River
Wabash River
Merrimack
Merrimack
San Juan
Whitewater Valley
Whitewater Valley
Silver Lake
Rochester 3
Rochester 7
Rochester 7
Rochester 7
Rochestei 7
Navajo
Navajo
Canadys
Canadys
Canadys
McMeekin
McMeekin
Urquhart
Urquhart
Urquh.i rt
Water'-e
Wateree
Winyah
Grainger
Grainger
Boiler
Number
1
2
7-1
7-2
8-1
1
2
3
4
1
2
3
5
6
1
2
3
4
1
2
2
1
2
4
12
1
2
3
4
1
2
1
2
3
1
2
1
2
3
1
2
1
1
2
Average Heat
Content of
Coal, Btu/Jb
10,363
10,363
10,231
10,231
10,231
11,149
11,149
11,149
11,149
10,742
10,742
10,742
10,907
10,907
10,907
10,907
10,907
10,907
13,443
13,443
8,838
11,506
11,506
12,400
12,680
12,706
12,706
12,706
12,706
12,407
12,407
12,407
12,304
12,304
12, 378
12,378
12,378
12,179
12,179
11,655
11,655
Average
Sulfur
Content, %
2.17
2.17
2.79
2.79
2.79
3.40
3.40
3.40
3.40
2.74
2.74
2.74
2.54
2.54
2.54
2.54
2.54
2.54
2.08
2.08
0.80
3.00
3.00
1.95
1.98
2.06
2.06
2.06
2.06
—
—
1.20
1.20
1.20
1.55
1.55
1.69
1.69
1.69
1.48
1.48
—
1.33
1.33
Average
Ash
Content, %
13.38
13.38
12.56
12.56
12.56
10.73
10.73
10.73
10.73
9.87
9.87
9.87
11.58
11.58
11.58
11.58
11,58
11.58
7.09
7.09
21.20
10.00
10.00
7.20
9.75
9.78
9.78
9.78
9.78
12.68
12.68
12.68
12.44
12.44
12.79
12.79
12.79
12.29
12.29
13.51
13.51
-------
TABLE 44.
(Continued)
cr>
£>
O
Company Name*
610 S. Carolina Pub. Serv. Auth.
611 S. Carolina Pub. Serv. Auth.
612 S. Indiana Gas & Elec. Co.
613 S. Indiana Gas & Elec. Co.
614 S. Indiana Gas & Elec. Co.
615 Southern California Edison
616 Southern California Edison
617 Southern Elec. Gen. Co.
618 Southern Elec. Gen. Co.
619 Southern Elec. Gen. Co.
620 Southern Elec. Gen. Co.
621 Southern 111. Power Coop.
622 Southern 111. Power Coop.
623 Southern 111. Power Coop.
624 Tampa Electric Company
625 Tampa Electric Company
626 Tampa Electric Company
627 Tampa Electric Company
628 Tampa Electric Company
629 Tampa Electric Company
630 Tampa Electric Company
631 Tampa Electric Company
632 Tennessee Valley Authority
633 Tennessee Valley Authority
634 Tennessee Valley Authority
635 Tennessee Valley Authority
636 Tennessee Valley Authority
637 Tennessee Valley Authority
638 Tennessee Valley Authority
639 Tennessee Valley Authority
640 Tennessee Valley Authority
541 Tennessee Valley Authority
642 Tennessee Valley Authority
643 Tennessee Valley Authority
644 Tennessee Valley Authority
645 Tennessee Valley Authority
646 Tennessee Valley Authority
647 Tennessee Valley Authority
648 Tennessee Valley Authority
649 Tennessee Valley Authority
650 Tennessee Valley Authority
651 Tennessee Valley Authority
652 Tennessee Valley Authority
653 Tennessee Valley Authority
Plant Name
Jefferies
Jefferies
F. B. Culley
F. B. Culley
F. B. Culley
Mohave
Mohave
Gaston
Gaston
Gaston
Gaston
Marion
Marion
Marion
Big Bend
Big Bend
F. J. Gannon
F. J. Gannon
F. J. Gannon
F. J. Gannon
F. J. Gannon
F. J. Gannon
Allen
Allen
Allen
Bull Run
Colbert A
Colbert A
Colbert A
Colbert A
Colbert B
Cumberland
Cumberland
Gallatin
Gallatiii
Gallatin
Gallatin
John Sevier
John Si"/ier
John Sevier
John Sevier
Johnsonville
Johnsonville
Johnsonville
Boiler
Number
3
4
1
2
3
1
2
1
2
3
4
1
2
3
1
2
1
2
3
4
5
6
1
2
3
1
1
2
3
4
5
1
2
1
2
3
4
1
2
3
4
7
8
9
Average Heat
Content of
Coal, Btu/lb
11,771
11,771
10,756
10,756
10,756
12,288
12,288
11,744
11,744
11,744
11,744
10,770
10,770
10,770
11,131
11,131
11,235
11,235
11,235
11,235
11,235
11,235
11,058
11,058
11,058
11,171
11,116
11,116
11,116
11,116
11,254
10,536
10,536
10,749
10,749
10,749
10,749
11,517
11 ,517
11,517
11,517
10,970
10,970
10,970
Average
Sulfur
Content,
0.96
0.96
3.72
3.72
3.72
0.40
0.40
1.17
1.17
1.17
1.17
4.17
4.17
4.17
3.46
3.46
3.12
3.12
3.12
3.12
3.12
3.12
3.12
3.12
3.12
0.85
3.98
3.98
3.98
3.98
4.11
3.65
3.65
35
3.35
3.35
3.35
1.88
1 .88
1.88
1.88
3.63
3.63
3.63
Average
Ash
Content,
13.39
13.39
11.46
11.46
11.46
9.86
9.86
14.40
14.40
14.40
14.40
14.81
14.81
14.81
11.41
11.41
11.22
11.22
11.22
11.22
11.22
11.22
11.48
11.48
11.48
15.31
15.03
15.03
15.03
]5.03
15.02
16.27
16.27
16.25
16.25
16.25
16.25
15.10
15.10
15.10
15.10
14.28
14.28
14.28
-------
TABLE 44. (Continued)
OS
£>.
Company Name*
654 Tennessee Valley Authority
655 Tennessee Valley Authority
656 Tennessee Valley Authority
657 Tennessee Valley Authority
658 Tennessee Valley Authority
659 Tennessee Valley Authority
660 Tennessee Valley Authority
661 Tennessee Valley Authority
662 Tennessee Valley Authority
663 Tennessee Valley Authority
664 Tennessee Valley Authority
665 Tennessee Valley Authority
666 Tennessee Valley Authority
667 Tennessee Valley Authority
668 Tennessee Valley Authority
669 Tennessee Valley Authority
670 Tennessee Valley Authority
671 Tennessee Valley Authority
672 Tennessee Valley Authority
673 Tennessee Valley Authority
674 Tennessee Valley Authority
675 Tennessee Valley Authority
676 Tennessee Valley Authority
677 Tennessee Valley Authority
678 Tennessee Valley Authority
679 Tennessee Valley Authority
680 Tennessee Valley Authority
681 Tennessee Valley Authority
682 Tennessee Valley Authority
683 Toledo Edison
684 Toledo Edison
685 Toledo Edison
686 Toledo Edison
687 Toledo Edison
688 Toledo Edison
689 Toledo Edison
690 Toledo Edison
691 Toledo Edison
692 Toledo Edison
693 UGI Corp. Luzerne Electric
694 UGT Corp. Luzerne Electric
695 Union Electric
696 Union Electric
697 Union Electric
Plant Name
Johnsonville
Kingston
Kingston
Kingston
Kingston
Kingston
Kingston
Kingston
Kingston
Kingston
Paradise
Paradise
Paradise
Shawnee
Shawnee
Shawnee
Shawnee
Shawnee
Shawnee
Shawnee
Shawnee
Shawnee
Shawnee
Watts Bar
Watts Bar
Watts Bar
Watts Bar
Widows Creek "B"
Widows Cio.ek "B"
Acme
Acme
Acme
Acme
Acme
Acme
Bay Shore
Bay Shore
Bay Shore
Bay Sliore
Hunloi k Creek
Hunlock Creek
Labadie
Labadie
Labadie
Boiler
Number
10
1
2
3
4
5
6
7
8
9
1
2
3
1
2
3
4
5
6
7
8
9
10
A
B
C
D
7
8
13
14
15
16
91
92
1
2
3
4
2
6
1
2
3
Average Heat
Content of
Coal, Btu/lb
10,970
10,688
10,688
10,688
10,688
10,688
10,688
10,688
10,688
10,688
10,268
10,268
10,268
10,500
10,500
10,500
10,500
10,500
10,500
10,500
10,500
10,500
10,500
11,142
11,142
11,142
11,234
11,234
11,410
11,410
11,410
11,410
11,410
11 ,410
12,143
12,143
12,143
12,143
8,732
8,732
11,134
11.134
11,134
Average
Sulfur
Content, %
3.63
2.21
2.21
2.21
2.21
2.21
2.21
2.21
2.21
2.21
4.18
4.18
4.18
2.87
2.87
2.87
2.87
2.87
2.87
2.87
2.87
2.87
2.87
3.75
3.75
3.75
3.75
3.90
3.90
2.68
2.68
2.68
2.68
2.68
2.68
1 .93
1.93
1.93
1.93
0.70
0.70
3.07
3.07
3.07
Average
Ash
Content, %
14.28
20.35
20.35
20.35
20.35
20.35
20.35
20.35
20.35
20.35
18.66
18.66
18.66
15.51
15.51
15.51
15.51
15.51
15.51
15.51
15.51
15.51
15.51
15.62
15.62
15.62
15.62
15.01
15.01
15.19
15.19
15.19
15.19
15.19
15.19
10.78
10.78
10.78
10.78
23.55
23.55
9.80
9.80
9.80
-------
TABLE 44. (Continued)
Company Name*
698 Union Electric
699 Union Electric
700 Union Electric
701 Union Electric
702 Union Electric
703 Union Electric
704 Union Electric
705 Union Electric
706 Union Electric
707 Upper Peninsula Generating
708 Upper Peninsula Generating
709 Upper Peninsula Generating
710 Upper Peninsula Generating
711 Upper Peninsula Generating
712 Utah Power & Light
713 Utah Power & Light
714 Utah Power & Light
715 Utah Power & Light
716 Utah Power & Light
717 Utah Power & Light
718 Virginia Electric «. Power
719 Virginia Electric & Power
720 Virginia Electric & Power
721 Virginia Electric S Power
722 Virginia Electric & Power
723 Western Massachusetts
724 Western Massachusetts
725 Western Massachusetts
726 Wisconsin Electric Power
727 Wisconsin Electric Power
728 Wisconsin Electric Power
729 Wisconsin Electric Power
730 Wisconsin Electric Power
731 Wisconsin Electric Power
732 Wisconsin Electric Power
733 Wisconsin Electric Power
734 Wisconsin Electric Power
735 Wisconsin Electric Power
736 Wisconsin Electric Power
737 Wisconsin Electric Power
738 Wisconsin Electric Power
739 Wisconsin Power & Light
740 Wisconsin Power & Light
741 Wisconsin Power & Light
Plant Mame
Labadie
Meramec
Meramec
Meramec
Meramec
Sioux
Sioux
Venice
Venice
Presque Isle
Presque Isle
Presque Isle
Presque Isle
Presque Isle
Gadsby
Gadsby
Hale
Huntington No. 2
Naughton
Naughton
Bremo
Bremo
Mt. Storm
Mt. Storm
Mt. Storm
West Springfield
West Springfield
West Springfield
North Oak Creek
North Oak Creek
North Oak Creek
North Oak Creek
Port Washington
Port Washington
Port Washington
Port Washington
Port Washington
Valley
Valley
Valley
Valley
Edgewater
Edgewater
Edgewater
Boiler
Number
4
1
2
3
4
1
2
7
8
1
2
3
4
5
2
3
2
2
1
3
3
4
1
2
3
1
2
3
1
2
3
4
1
2
3
4
5
1
2
3
4
1
2
3
Average Heat
Content of
Coal, Btu/lb
11,134
11,810
11,810
11,810
11,810
10,939
10,939
11,912
11,912
12,415
12,415
12,415
12,415
12,415
12,072
12,072
12,013
9,509
9,509
12,391
12,391
11,276
11,276
11,276
11,457
11,457
11,457
11,457
12,118
12,118
12,118
12,118
12,118
11,848
11,848
11,848
11,848
10,930
10.930
10,930
Average
Sulfur
Content, %
3.07
1.53
1.53
1.53
1.53
2.99
2.99
1.31
1.31
1.30
1.30
1.30
1.30
1.30
0.50
0.50
0.53
0.50
0.50
0.89
0.89
1.95
1.95
1.95
2.09
2.09
2.09
2.09
3.43
3.43
3.43
3.43
3.43
3.22
3.22
3.22
3.22
2.53
2.53
2.53
Average
Ash
Content, %
9.80
9.39
9.39
9.39
9.39
15.27
15.27
7.90
7.90
8.20
8.20
8.20
8.20
8.20
8.51
8.51
9.80
4.50
4.50
10.99
10.99
18.77
18.77
18.77
10.71
10.71
10.71
10.71
10.56
10.56
10.56
10.56
10.56
10.39
10.39
10.39
10.39
8.94
8.94
8.94
-------
TABLE 44. (Continued)
Company Name*
742
743
744
745
746
747
748
749
750
751
752
753
754
Wisconsin
Wisconsin
Wisconsin
Wisconsin
Wisconsin
Wisconsin
wi sconsi n
Wisconsin
Wisconsin
Wisconsin
Wisconsin
Wisconsin
Wisconsin
Power & Light
Power & Light
Power & Light
Power & Light
Power & Light
Public Service
Public Service
Public Service
Public Service
Public Service
Public Service
Public Service
Public Service
Plant Name
Edgewater
Nelson Dewey
Nelson Dewey
Rock River
Rock River
J. f. Pulliam
J. P. Pulliam
J. P. Pulliam
J. P. Pulliam
J. P. Pulliam
J. P. Pulliam
Weston
Weston
Boiler
Number
4
1
2
1
2
3
4
5
6
7
8
1
2
Average Heat
Content of
Coal, Btu/lb
10,930
10,837
10,837
11,307
11,107
11,863
11,863
11,863
11,863
11,863
11,863
11,786
11,786
Average
Sulfur
Content, %
2.53
3.62
3.62
2.82
2.82
2.80
2.80
2.80
2.80
2.80
2.80
2.93
2.93
Average
Ash
Content, %
8.94
10.37
10.37
10.06
10.06
10.89
10.89
10.89
10.89
10.89
10.89
9.43
9.43
a\
*•
LJ
-------
TABLE 45.
POWER PLANT AND AIR QUALITY DATA FOR THOSE
PLANTS WITH ELECTROSTATIC PRECIPITATORS
*Co.
Name
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
Year Boiler
Placed in
Service
.1971
1956
1958
1972
1949
1949
1954
1967
1968
1972
1973
1974
1960
1958
1959
1969
1970
1971
1963
3954
1942
1943
1958
1958
1961
1969
1970
1969
1970
1972
1965
1967
1967
1964
1971
1956
1958
Generating
Capacity, MW
788.8
187.5
190.4
788.8
69.
69.
145.
552.
550.
650.
650.
650.
186.
183.
178.
576.
576.
576.
294.
142.
—
—
223.
223.
223.
818.1
818.1
170.
170.
173.
80.
590.
590.
206.635
207.00
140.625
187.85
Design Coal
Consumption,
tons/hour
250.
66.7
73.0
250.0
28.5
28.5
80.
186.
179.
250.
250.
250.
95.
80.
80.
200.
200.
200.
100.
46.
19.5 ea.
19.5 ea.
83.
83.
83.
421.
421 .
7J 5
71.5
70.0
35.9
247.5
247.5
70.
72.
48.2
59.2
Air Flow at
100% Load,
scC/min
] ,275,000
274,000
285,000
1, 275,000
140,000
140,000
440,000
1,250,000
1,250(000
1,500,000
1,500,000
1,500,000
590,000
450,000
450,000
1,169,000
1,169,000
1,169,000
630,000
265,000
93,750
93,750
317,292
317,292
317,292
1,893,000
1,893,000
319,222
319,222
365,333
169,666
800,000
800,000
600,000
576,000
222,000
280,000
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Type of
Firing
. coal/Tangential
. coal/Tangential
. coal /Tangential
. coal/Tangential
. coal /Tangential
. coal/Tangential
. coal/Tangential
. coal/Tangential
. coal/Opposed
. coal/Opposed
. coal/Opposed
. coa I/Opposed
Cyclone
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pul
Pill
. coal/Opposed
. coal/Opposed
. coal/Opposed
. coal /Opposed
. coal/Opposed
. coal/Tangential
. coal/Front
. coal/Front
. coal/Front
. coal/Front
. coal/Front
. coal /Front
. coal /Opposed
. coal/Opposed
. coal/Front
. coal/Front
. coal /Front
. coal/Front
. coal/Front
. coal/Front
. coal/Front
. coal/Front
. coal/Tangential
. coa 1 /Tangent ial
fioiler
Manufacturer
Combustion Erig.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
B & W
Foster WheeJer
Foster Wheeler
Foster Wheeler
B & W
Foster Wheeler
Foster Wheeler
B & W
B & W
B & W
Combustion Eng.
C 6, W
Foster Wheeler
B & W
B & W
B & W
B S W
B S W
B f. W
Foster Wheel er
Foster Wheoicr
Riley Stoker
Riley Stoker
B & W
1) S, W
Riley Stoker
B & W
Combu s t i on E IK; •
Combustion En'-;.
Boiler
Efficiency
at 100% Load
89.1
88.52
88.52
89.10
86.5
86^5
87.0
88.6
90.7
88.99
88.99
88.99
88.8
88.
88.
91.0
91.0
91.0
89.8
89.9
87.7
8-". 7
89.8
89.8
89.8
88.08
88.C-8
8B,fl2
88.02
87.92
B6.9
~-
--
90,00
80.60
80. 9
90.0
% Excess
Air Used
J8-
1 5.
15.
18.
20-
20.
20.
20-
20-
25-
25-
25-
20-
20-
20-
• 30-
30-
30-
7n .
20.
20.
• 20.
20.
20.
20.
16.
Ifi.
J8.
18.
18 -
22.
?0 -
2(1 -
?o.
18.
20
?n
*The numbers in the first column correspond to the same plant names in Tables 45 and 46 as they do in Table 14.
-------
TABLE 45. (Continued)
*Co.
Name
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
Year Boiler
Placed in
Service
1960
1952
1951
1954
1955
1972
1966
1968
1973
1973
1949
1950
1952
1973
1960
1968
1972
1949
1949
1952
1958
1965
1972
1950
1950
1958
1948
1948
3949
1949
1960
1960
—
1960
1952
1953
1954
1958
1962
1969
1962
1968
1974
1959
Generating
Capacity, MW
206.635
75.
75.
112.5
112.5
446.616
410.85
657.00
745.20
46.
46.
73.5
37.8
125.
250.
. 322.
35.
35.
84.
100.
388.9
636.
38.
38.
110.
34.
34.
34.
34.
239.4
450.
300.
168.
100.
100.
125.
163.
240.
434.
50.0
80.0
132.
22.
Design Coal
Consumption,
tons/hour
68.
26.
31.
48.
40.
197.
130.
223.
151.
151.
19.
19.
26.
18.
60.
J30.
153.
17.
17.
39.
50.
200.
277.
18.
18.
47.
12.
I.?.
12.
12.
91.
149.
131.
62.
38.
37.
47.
62.
86.
173.
31 .
39.
61.
12.
42
3
6
4
7
0
8
8
5
5
3,
0
9
9
5
7
75
75
1
5
5
5
5
2
5
6
0
8
0
0
6
5
Air Flow at
100% Load,
scf/min
286,
121,
127,
231,
210,
868,
700,
1,130,
733,
733,
95,
95,
121,
92,
316,
572,
827,
100,
100,
222,
270,
875,
1,310,
86,
86.
201,
67,
67,
67,
67,
397,
608,
621,
240,
361,
158,
196,
240,
351,
669,
93,
143,
228,
000
000
000
000
000
000
000
000
049
049
500
500
000
000
100
700
894
000
000
000
000
760
082
890
890
333
555
555
555
555
777
958
664
500
000
300
900
500
900
200
985
163
109
Pul.
Pul.
Pul.
Pul .
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul .
Pul.
Pul.
Pul .
Pul .
Pul .
Pul .
Pul .
Pul.
Type of
Firing
coal /Tangential
coal/Tangential
coal /Front
coal/Tangential
coal/Front
coal/Front
coal/Opposed
coal/Tangential
coal/Front
coal/Front
coal /Tangential
coal/Front
coal/Front
coal/Front
coal/Front
coal/Front
coal/Front
coal/Front
coal/Front
Cyclone
Cyclone
Pul.
Pul.
Pul.
Pul.
Pul.
Pul .
Pul.
Pu] .
Pul.
Pul .
Pul.
Pul.
Pill .
Pul.
Pul .
Pul .
Pul.
Pul.
Pul .
Pul.
Pul.
coal /Front
coal/Front
coal/Front
coal/Tangential
coal/Tangential
coal /Tangential
coal /Tangential
coal/Tangential
coal/Opposed
coal/Opposed
coal /Front
coal /Tangential
coal /Tangential
coal /Front
coal/Tangential
coal /Tangential
coa] /Tangential
coal/Front
coal/Front
coal/Front
coal/Front
Boiler
Boiler
Efficiency
Manufacturer at 100% Load
Combustion Eng.
Combustion Eng.
B & W
Combustion Eng.
B £. W
Riley Stoker
Riley Stoker
Combustion Eng.
Riley Stoker
Riley Stoker
B & W
B & W
Combustion Eng.
B & W
Riley Stoker
Riley Stoker
Foster Wheeler
Riley Stoker
Riley Stoker
Riley Stoker
Riley Stoker
B & W
B & W
B & W
B & W
B & W
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combus 1: ion Eng .
Combustion Eng.
B & W
B S, W
Combustion Eng.
Combustion Eng.
Combustion Eng.
B & W
Combustion Eng.
Combustion Eng.
Conibu s t i on Eng .
Riley Stoker
B & W
B & W
90.00
89.48
87.8
89.95
89.1
88.58
90.0
90.0
88.71
88.71
88.
88.
90.
88.1
87.2
87.4
88.1
85.
85.
85.
89.
87.93
87.58
86.6
86.6
89.05
85.2
85.2
85.2
85.2
87.24
89.7
88.88
90.05
89.4
89.4
89.33
90.05
89.99
89.01
82.7
88.1
87.7
87.0
% Excess
Air Used
20.
20.
25.
4.0
4.0
5.0
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
18.
20.
20.
20.
20.
16.
16.
25.
25.
25.
25.
25.
25.
25.
25.
20.
20.
20.
24.
24.
25.
20.
20.
20.
20.
18.
20.
25.
-------
TABLE 45. (Continued)
*Co.
Name
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
100
101
102
103
104
105
106
107
108
109
110
111
112
113
114
115
116
117
118
119
120
121
122
123
124
125
Year Boiler
Placed in
Service
1947
1951
1961
1965
1968
1972
1970
1958
1948
1948
1948
1948
1949
1949
1959
1970
1972
1941
1941
1951
1951
1962
1973
1958
1961
1945
1953
1949
1949
1959
1950
1950
1959
1965
1965
1966
1966
1967
1968
1972
1972
1961
1931
1931
Generating
Capacity, MW
20.
20.
37.5
37.5
80.
80.
105.
256.
46.
46.
46.
46.
86.
86.
233.
680.
680.
60.
60.
69.
69.
256.
787.
239.
358.
50.
69.
173.
—
374.
107.
—
360.
660.
—
660.
—
660.
660.
892.8
—
54.
115.
—
Design Coal
Consumption,
tons/hour
15.6
16.6
18.2
18.2
37.4
37.4
40.2
92.
21.5
21.5
21.5
21.5
46.
46.
85.
230.
230.
25.2
25.2
33.3
33.3
88.4
332.5
100.
145.
30.
37.
44. r.
44.'-
139.
37.
37.
144.
145.
145.
145.
145.
282.5
282.5
176.5
176.5
26.
20.
28.
Air Flow at
100% Load,
scf/min
64,700
64,700
73,000
73,000
155,800
155,800
316,000
482,000
228,000
228,000
228,000
228,000
242,620
242,620
471,520
1,106,700
1,106,700
167,120
167,120
195,150
195,150
487,340
2,257,232
433,000
545,000
110,000
120,000
152,000
152,000
464,000
128,000
128,000
470,000
578,000
578,000
578,000
578,000
1,100,000
1,100,000
1,217,000
1,217,000
86,800
92,000
116,000
Type of
Firing
Pul. coal/Front
Pul. coal/Front
Cyclone
Cyclone
Cyclone
Cyclone
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Opposed
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Cyclone
Cyclone
Pul. coal/Tangential
Cyclone
Cyclone
Cyclone
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Cyclone
Cyclone
Cyclone
Cyclone
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Boiler
Manufacturer
B S W
n & w
B & W
B & W
Riley Stoker
Combustion Eng.
B & W
B & W
B & W
B & W
Cambustion Bug.
Combustion Eng.
Combustion Eng.
B & W
B & W
B & W
B & W
8 & W
B & W
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
B & W
B & W
B & W
B & W
Combustion Enq.
B S W
B & W
S & W
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
B & W
B & W
B S W
B S W
Foster Wheeler
B & W
B S W
Boiler
Efficiency
at 100% Load
83.1
83.3
88.1
87.3
87.47
88.67
87.7
90.2
87.9
87.9
90.3
89.9
89.9
88.7
88.7
88.5
88.5
89.7
88. Ol
89.4
89.4
86.4
87.0
86.6
86.6
89.4
87.0
87.0
89.4
89.3
89.3
89.3
89.3
88.2
88.2
89.03
89.03
84.5
83.3
83.8
% Excess
Air Used
15.
15.
15.
15.
15.
15.
22.
24.
22.
22.
22.
22.
22.
22.
22.
18.
18.
20.
20.
23.
23.
22.
25.
15.
14.6
20.
25.
22.
22.
18.
20.
20.
16.
14.
14.
14.
14.
16.
]6.
15.
15.
22.
—
--
-------
TABLE 45. (Continued)
*Co.
Name
126
127
128
129
130
131
132
133
134
135
136
137
138
139
140
141
142
143
144
145
146
147
148
149
150
151
152
153
154
155
156
157
158
159
160
161
162
163
164
165
166
167
168
169
Year Boiler
Placed in
Service
1931
1952
1958
1962
1955
1955
1957
1963
1929
1929
1929
1929
1929
1929
1938
1938
1938
1955
. 1962
1953
1954
1958
1961
1961
1965
1948
1948
1950
1956
1957
1959
1961
1955
1958
1962
1967
1947
1947
1950
1957
1959
1969
1951
1952
Generating
Capacity, MW
121.
326,
355.
188.
184.
299.
598.
208.
—
—
150.
225.
389.
200.
200.
376.
387.
387,
1028.
66.
66.
66.
156.25
156.25
265.
265.
156.25
156.25
265.
385.
18.7
18.7
18.7
54.4
81 .6
345.6
19.
33.
Design Coal
Consumption,
tons/hour
28.
56.
138.
150.
80.8
80.8
125.
224.
24.
24.
24.
24.
24.
24.
25.
25.
25.
84.
124.
64.
64.
130.4
134.2
134.2
321.0
31.
31.
31.
bii.
CO.
92.
89.
88.
88.
100.
150.
10.0
10.0
12.0
25.0
37.9
137.
13.95
13.95
Air Flow at
100% Load,
scf/min
116,000
191,000
463,000
685,000
276,000
276,000
467,000
798,000
100,000
100,000
100,000
100,000
100,000
100,000
122,200
111,000
111,100
310,300
470,000
360,500
360,500
734,500
755,900
755,900
1 ,808,100
190,000
190,000
190,000
340,000
340,000
645,576
625,071
340,000
340,000
630,000
907,400
65,830
69,700
86,590
124,570
230,630
611 ,000
75,600
63,290
Type of
Firing
Pul. coal/Front
Cyclone
Pul . coal/Tangential
Pul. coal/Tangential
Cyclone
Cyclone
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Tangential
Cyclone
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul . coal/Tangential
Pul. coal /Front
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Opposed
Pul. coal /Front
Pul . coal /Front
Pul. coal/Front
Pul . coal/l-'ront
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Boiler
Boiler Efficiency
Manufacturer at 100% Load
B & W
B & W
Combustion Eng.
Combustion Eng.
B & W
B & W
Combustion Eng.
Combustion Eng.
B & W
B & W
B & W
B & W
B & W
B & W
B & W
B & W
B & W
Combustion Eng.
B & W
B & W
B & W
B & W
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng .
B & W
Combustion Enrj .
Combustion Enq.
Combustion ling.
B & W
B & W
B & W
Riley Stoker
Kiley Stoker
Riley Stoker
Combustion Eng.
Riley Stoker
Riley Stoker
83.8
88.6
89.4
89.4
89.1
89.1
89.5
89.0
75.6
75.6
75.6
75.6
75.6
75.6
82.8
82.8
82.8
89.3
89.4
90.3
90.3
90.3
90.6
90.6
90.8
88.05
88.05
88.05
89.33
89.33
88.9
88.9
88.
88.
90.26
90.47
85.6
85.6
86.0
Bfi.5
8f>. 4
B8.35
86.0
Sfi.O
% Excess
Air Used
20.
18.
24.
10.
10.
15.
20.
25.
25.
25.
25.
25.
25.
20.
20.
20.
18.
16.
25.
25.
25.
25.
25.
25.
15.
15.
15.
18.
18.
17.
17.
—
--
18.
18.
37.3
36.8
17. T
20.0
23.9
20.0
17.7
17.7
-------
TABLE 45. (Continued)
*>
00
*Co.
Name
170
171
172
173
174
175
176
177
178
179
180
181
182
183
184
185
186
187
188
189
190
191
192
193
194
195
196
197
198
199
200
201
202
203
204
205
206
207
208
209
210
211
212
213
Year Boiler
Placed in
Service
1971
1972
1974
1958
1959
1937
1937
1940
1940
1971
1970
1972
1974
1948
1949
1950
1951
1952
1953
1961
1957
1959
1970
1951
1951
1951
1951
1968
1942
1943
1947
1943
1971
1973
1973
1974
1948
1949
1957
1953
1953
1954
1954
1961
Generating
Capacity, MW
593.
593.
593.
147.
147.
37.
37.
37.
37.
610.
610.
610.
610.
69.
69.
69.
69.
69.
69.
75.
81.
81.
176.
67.
67.
67.
67.
121.
50.
50.
50.
50.
817.
822.
822.
817.
9.
9.
292.
169.
156.
156.
169.
353.
4
4
4
1
5
5
5
5
2
2
2
2
6
6
8
5
5
5
5
2
6
6
2
25
25
Design Coal
Consumption,
tons/hour
375.
375.
418.
54.
54.
21.
21.
21.
21.
250.
250.
250.
250.
24.0
24.0
23.4
23.4
23.4
23.4
23.5
32.
32.
65.
31.5
31.5
31.5
31 .5
4!..
21.
21.
21.
21.
281.
281.
281.
281.
11.55
11.55
99.
61.
61.
61.
61.
120.
Air Flow at
100% Load,
scf/min
1,189,000
1,189,000
2,600,000
240,000
240,000
94,500
94,500
94,500
94,500
1,311,656
1,311,656
1 ,311,656
1,311,656
105,777
105,777
103,333
103,333
103,333
103,333
160,000
228,000
228,000
360,000
130,000
130,000
130,000
130,000
214,000
97,000
97,000
97,000
97,000
1,530,000
1,530,000
1,530,000
1,530,000
59,000
59,000
426,250
258,000
258,000
258,000
258,000
542,000
Pul.
Pul .
Pul .
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul .
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul .
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul .
Pul.
Pul.
Pul.
Pul .
Pul .
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Type of
Firing
coal /Tangential
coal /Tangential
coal /Tangential
coal /Tangential
coal /Tangential
coal/Front
coal/Front
coal/Front
coal/Front
coal/Opposed •
coa ] /Opposed
coal/Opposed
coa I/Opposed
coal/Tangential
coal /Tangential
coal/Tangential
coal/Tangential
coal/Tangential
coal/Tangential
coal /Opposed
coal/Front
coal/Front
coal/Front
coal/Front
coal /Front
coal /Front
coal/Front
coal/Front
coal/Tangential
coal/Tangential
coal/Tangential
coal/Tangential
coal /Opposed
coal/Opposed
coal/Opposed
coal /Opposed
coal/Front
coal/Front
coal/Tangential
coal/Front
coal /Front
coal/Front
coal/Front
coal/Front
Boiler
Boiler
Efficiency
Manufacturer at 100% Load
Combustion
Combustion
Combustion
Combustion
Combustion
B & W
B & W
B & W
B & W
B & W
B S, W
B S, W
B & W
Combustion
Combustion
Combustion
Combustion
Combustion
Combust ion
Eng.
Eng.
Eng.
Eng.
Eng.
Eng.
Eng.
Eng.
Eng .
Eng.
Eng.
Foster Wheeler
B & W
B S, W
B S W
P., S W
B & W
B & W
B & H
Riley Stoker
Combustion
Combustion
Combustion
Combustion
B & W
B S W
B & W
B & W
Combustion
Combustion
Combustion
B & W
B & W
B S W
B & W
Combustion
Eng.
Eng.
Eng.
Eng.
Eng.
Eng.
Eng.
Eng.
82.58
82.58
81.5
88.6
88.6
85.2
85.2
85.2
85.2
89.9
89.9
89.9
89.9
87.9
87.9
87.7
87.7
87.7
87.7
87.
90.
90.
90.
87.3
87.3
87.3
87.3
88.4
87.7
87.7
87.7
87.7
90.92
90.92
90.92
90.92
87.6
87.6
89.17
88.4
88.4
88.4
88.4
90.16
% Excess
Air Used
20.
20.
20.
20.
20.
25.
25.
25.
25.
18.
18.
18.
18.
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
24.5
24.5
24.5
24.5
20.
22.
22.
22.
22.
18.
18.
18.
18.
22.
22.
18.
23.
23.
23.
23.
18.
-------
TABLE 45. (Continued)
*CO.
Name
214
215
216
217
218
219
220
221
222
223
224
225
226
227
228
229
230
231
232
233
234
235
236
237
238
239
240
241
242
243
244
245
246
247
248
249
250
251
252
253
254
255
256
257
Year Boiler
Placed in
Service
1969
1948
1948
1968
1968
1957
1957
1959
1960
1961
1974
1941
1941
1942
1953
1953
1940
1940
1948
1948
1949
1950
1955
1951
J951
1958
1965
3966
1969
1970
1952
1952
1954
1954
1970
1952
1953
1954
1960
1942
1942
1949
1950
1950
Generating
Capacity, MW
544.
11.4
11.4
11.4
11.4
165.
165.
275.
275.
275.
1080.
40.
40.
40.
125.
125.
40.
40.
65.
65.
70.
70.
150.
90.
90.
165.
350,
350.
650.
650.
100.
100.
133.
133.
525.
80.
80.
100.
165.
--
—
—
--
—
Design Coal
Consumption,
tons/hour
198.
15.4
15.4
15.3
15.3
56.
56.
91.
91.
91.
360.
17.4
17.4
17.4
48.
48.
17.4
17.4
27.9
27.9
30.
30.
55.
40.
40.
58.9
117.
11 /.
20!i.
208.
40.6
40.6
52.
52.
224.5
41 .5
41.5
47.8
75.0
23.8
23.8
37.6
37.6
37.6
Air Flow at
100% Load,
scf/Kiin
862,000
74,000
7 4,. 000
69,000
69,000
292,520
292,520
487,640
487,640
487,640
1,874,400
85,077
85,077
85,077
233,587
233,587
82,077
82,077
123,265
123,265
144,867
144,867
276,447
185,800
185,800
292,520
561,037
561,037
973,350
973,350
198,442
198,442
253,946
253,946
841,323
385,000
385,000
430,000
636,000
240,000
240,000
342,000
342,000
342,000
Pul.
Pul.
Pul.
Pul.
Pul .
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul .
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul .
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul .
Pul.
Pul.
Pul.
Pul.
Pul .
Pul .
Pul.
Pul.
Pul.
Pul.
Type of
Firing
coal /Tangential
coal/Front
coal/Front
coal/Front
coal/Front
coal/Tangential
coal/Tangential
coal/Tangential
coal/Tangential
coal/Tangential
coal/Opposed
coal /Tangential
coal/Tangential
coal/Tangential
coal /Tangential
coal/Tangential
coal/Tangential
coal /Tangential
coal/Tangential
coal/Tangential
coal/Tangential
coal /Tangential
coal/Tangential
coal/Tangential
coal/Tangential
coal/Tangential
coal /Tangential
coal/Tangenti al
coal /Tangential
coal /Tangential
coal/Tangential
coal /Tangential
coal /Tangential
coal/Tangent ial
coal/Tangential
coal/Front
coal /Front
coal/Front
coal/Front
coal/Front
coal/Front
coal/Front
coal/Front
coal/Front
Boiler
Manufacturer
Combustion Eng.
B & W
B & W
Foster Wheeler
Foster Wheeler
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
B & W
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
B & W
B & W
B & W
B & W
Foster Wheeler
Foster Wheeler
Foster Wheeler
Foster Wheeler
Foster Wheeler
Boiler
Efficiency
at 100% Load
90.62
87.4
87.4
87.78
87.78
88.99
88.99
89.59
89.59
89.59
90.23
86.3
86.3
86.3
88.82
88.82
86.8
86.8
87.5
87.5
88.2
88.2
88.75
88.66
88.66
88.95
89.74
89.74
90.12
90.12
88.8
8R.8
89.2
89.2
89.4
88.6
88.6
88.9
88. 4
85.5
85.5
85.5
85.5
85.5
% Excess
Air Used
18.
26.
26.
18.
18.
20.
20.
20.
20.
20.
20.
19.
19.
19.
23.
23.
23.
23.
23.
23.
22.
22.
19.
22.
22.
22.
18.
18.
18.
18.
23.
23.
20.
20.
18.
25.
25.
23.
18.
2G.
26.
26.
26.
26.
-------
TABLE 45. (Continued)
*Co.
Name
258
259
260
261
262
263
264
265
266
267
268
269
270
271
272
273
274
275
276
277
278
279
280
281
282
283
284
285
286
287
288
289
290
291
292
293
294
295
296
297
298
299
300
301
Year Boiler
Placed in
Service
1956
1964
1969
1957
1960
1953
1954
1955
1970
1941
1942
1943
1948
1954
1954
1955
1970
1971
1972
1974
1963
1964
1965
1967
1968
1969
1948
1948
1964
1950
1950
1953
1957
1958
1974
1974
1965
1967
1959
1961
1970
1973
1953
1953
Generating
Capacity, MW
125.
100.
220.85
74.
74.
180.876
180.876
180.876
200.
46.
46.
40.
40.
125.
125.
125.
578.
806.
789.
952.
245.
245.
250.0
319.0
480.7
490.0
22.
22.
125.
100.
100.
100.
125.
125.
350.
350.
149.6
190.4
93.75
93.75
370.
578.
49.
49.
Design Coal
Consumption,
tons/hour
64.0
42.5
92.5
40.
39.
75.85
75.85
75.85
100,
25.
25.
27.
27.
41.
41.
41.
195.
269.
269.
375.
94.25
94.25
97.1
122.9
185.7
185.7
12.0
TVO
89 0
50.0
50.0
50.0
55.0
55.0
139.0
139.0
56.4
71.3
32.1
32.15
125.
197.1
19.6
19.6
Air Flow at
100% Load,
scf/min
400,000
280,000
492,000
368,000
353,000
368,501
368,501
368,501
404,440
225,000
225,000
225,000
225,000
187,159
187,359
187,159
1,006,011
1,382,440
1, 382,440
1,775,706
1,050,000
1,050,000
401,600
563,500
714,200
714,200
80,000
80,000
500,000
195,041
195,041
195,041
259,426
269,436
587,087
587,087
277,300
334,200
152,705
152,705
597,294
934,100
91,405
91,405
Pul.
Pul.
Pul .
Pul.
Pul.
Pul.
Pul.
Pul.
Type of
Firing
coal /Front
coal/Front
coal/Front
coal/Front
coal/Front
coal/Tangential
coa I/Tangent ia 1
coal/Tangential
Cyclone
Pul.
Pul.
Pul .
Pul.
Pul .
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul .
Pul.
Pul.
PuJ .
Pill.
Pul.
Pul.
Pul.
Pul.
Pul.
Pu] .
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
coal /Tangential
coal/Tangential
coal/Tangential
coal/Tangential
coal/Front
coal/Front
coal/Front
coal/Opposed
coal/Tangential
coal/Tangential
coal /Tangential
coal /Tangential
coal /Tangential
coal/Opposed
coal/Opposed
coal/Opposed
coal/Opposed
coal/Front
coal/Front .
coal/Tangential
coal/Tangential
coal/Tangential
coal/Tangential
coal /Tangential
coal/Tangential
coal/Tangential
coal/Tangential
coal /Tangential
coal/Tangential
coal/Tangential
coal/Tangential
coal/Front
coal/Opposed
coal/Front
coal/Front
Boiler
Manufacturer
Foster Wheeler
B S, W
B & W
Riley Stoker
B & W
Combustion Eng .
Combustion Eng.
Combustion Eng.
B S W
Combustion Eng.
Combustion Eng.
B & W
B & W
B & W
B & W
B S W
Foster Wheeler
Combustion Enq.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
B & W
Riley Stoker
B & W
B & W
B & W
B & W
Combustion Eng.
Combustion Eng.
Combu s t ion Eng .
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng-
Combustion Eng.
Combustion Enq.
Foster Wheeler
Foster Wheeler
B & W
B & W
Boiler
Efficiency
at 100% Load
88.0
89.07
87.14
87.27
89.21
88.22
88.22
88.22
87.15
85.0
85.0
86.0
87.0
88.6
88.6
88.6
89.01
89.10
89.10
88.70
89.3
89.3
89.08
89.10
89.09
89.09
80.0
80.0
89.0
88.5
88.5
88.5
88.3
88.3
89.1
89.1
89.2
89.1
89.4
89.4
88.8
89.01
87.2
87.2
% Excess
Air Used
26.
20.0
20.0
20.0
20.0
18.0
18.0
18.0
13.0
22.0
22.0
22.0
22.0
23.0
23.0
23.0
18.0
18.0
38.0
18.0
18.0
18.0
18.0
20.0
18.0
18.0
20.0
20.0
18.0
20.0
20.0
20.0
20.0
20.0
18.0
18.0
18.0
18.0
17.0
17.0
38.0
18.0
25.0
25.0
-------
TABLF 45. (Continued)
*Co.
Name
302
303
304
305
306
307
308
309
310
311
312
313
314
315
316
317
318
319
320
321
322
323
324
325
326
327
328
329
330
331
332
333
334
335
336
337
338
339
340
3-11
342
343
344
345
Year Boiler
Placed in
Service
1954
1958
1973
1974
1969
1970
1973
1953
1959
1955
1956
1954
1964
1955
1955
1955
1955
1955
1956
1964
1938
1938
1946
1947
1953
1953
1958
1961
1951
1953
1953
1956
1967
1969
1959
1967
1958
1941
1944
1945
1950
1937
1944
1949
Generating
Capacity, MW
69.
113.636
175.
175.
28.7
623.
634.5
75.
231.25
73.5
108.8
103.
387.
217.26
217.26
217.26
217.26
217.26
217.26
113.64
113.64
50.
69.
690.
113.64
253.44
471.00
37.5
218.45
50.0
•
12.15
12.15
24.15
Design Coal
Consumption,
tons/hour
26.9
40.3
70.
70.
14.5
267.
267.
34.
93.
30.8
44.0
42.7
151.
89.
89.
89.
89.
89.
89.
232.
18.
18.
18.3
18.3
42.
42.
38.1,
37. y
37.9
46.5
96.
199.
25.15
92.
25.5
15.0
15.0
15.0
19.5
13.1
14.75
14.35
Air Flow at
100% Load,
scf/min
151,120
224,221
365,333
365,333
75,000
1,730,000
1,730,000
140,900
389,900
141,100
201,900
202,800
647,600
400,000
400,000
400,000
400,000
400,000
400,000
800,000
180,000
180,000
170,000
170,000
150,000
150,000
387,000
387,000
482,000
963,000
114,000
410,000
104,200
59,200
59,900
59,900
79,800
47,000
52,000
51,000
Type of
Firing
Pul . coal/Front
Pul. coal/Front
Pul . coal/Front
Pul. coal/Front
Pul. coal/Front
Cyclone
Cyclone
Pul . coal/Tangential
Pul. coal/Tangential
Pul . coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Cyclone
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Spreader Stoker
Spreader Stoker
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal /Tangential
Pul. coal/Tangential
Pul. coal /Tangential
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Tangential
Pul . coal /Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Front
Pul. coal /Front
Boiler
Manufacturer
B & W
Riley Stoker
Riley Stoker
Riley Stoker
General Electric
B & W
B & W
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
B & W
B & W
B & W
B & W
B & W
B & W
B & W
Foster Wheeler
Foster Wheeler
B & W
B & W
B & W
B & W
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combu stion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Riley Stoker
Combustion Eng.
Riley Stoker
B & W
Combustion Eng.
Riley Stoker
Riley Stoker
Boiler
Efficiency
at 100% Load
88.9
90.0
87.92
87.92
90.
89.1
89.1
87.0
87.3
87.2
87.2
87.0
88.8
88.8
88.8
88.8
88.8
88.8
88.8
90.1
85.5
85.5
86.2
86.2
79.
79.
87.1
87.1
85.44
85.82
85.82
87.15
89.06
89.06
85.5
87.0
85.0
80.56
81.04
82.89
85.52
84.2
83.8
85.0
% Excess
Air Used
15.
18.
18.
18.
1.5
16.
16.
25.
31.
24.
24.
25.
20.
17. -18.
17. -18.
17. -18.
17. -18.
17. -18.
17. -18.
20.
id.
20.
13.
13.
33.
33.
—
--
—
--
--
--
—
--
25.
18.
22.
20.
20.
20.
25.
5.
5.
5.
-------
TABLE 45. (Continued)
*CO.
Name
346
347
348
349
350
351
352
353
354
355
356
357
358
359
360
361
362
363
SI 364
w 365
366
367
368
369
370
371
372
373
374
375
376
377
378
379
380
381
382
383
384
385
386
387
388
389
Year Boiler
Placed in
Service
1949
1961
1954
1958
1954
1964
1958
1964
1972
1968
1962
1966
1971
1950
1969
1958
I960
1964
1963
1969
1957
1971
1973
1954
1953
1954
1958
1961
1964
1968
1970
1973
1939
1939
1949
1951
1951
1954
1956
1958
1962
1966
1969
1972
Generating
Capacity, MW
24.15
125.
49.
81.6
70.
110.
50.0
138.7
349.2
212.
65.28
81.6
157.5
514.8
187.5
187.5
188.1
265.
737.6
100.
438.
511.
75.
75.
50.
46.
50.
75.
80.
80.
165.
81.5
__-
___
— _—
112.5
112.5
147.1
163.2
209.44
272.0
355.5
Design Coal
Consumption,
tons/hour
14.35
61.5
24.8
40.9
42.
50.
27.0
55.
145.
89.22
24.5
33.
51.1
21.
204.8
84.4
84.4
83.0
100.
291.5
38.7
167.0
219.5
36.85
33,8
17.9
20.15
20.15
31 .35
31.35
31.35
78.4
10.25
10.25
12.60
12.60
12.60
55.0
56.0
65.0
78.8
91.0
105.75
136.5
Air Flow at
100% Load,
scf/min
50,600
221,000
151,209
246,957
79,500
109,000
135,321
42] ,670
500,000
504,148
114,000
178,000
287,000
1,196,073
581,600
581,600
573,000
395,833
1,100,000
203,111
810,810
1,640,000
282,000
274,000
77,700
91,200
91,200
144,700
144,700
144,700
383,597
47,600
47,600
50,800
50,800
50,800
221,221
230,384
265,727
295,616
378,083
467,749
609,000
Type of
Firing
Pul . coal/front
Pul . coal/Tangential
Pul. coal/Front
Pul. coal/Front
Pul . coal/Front
Pul. coal/Front
Pul. coal/Front
Cyclone
Pul. coal/Front
Pul. coal/Tangential
Cyclone
Cyclone
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coa] /Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal /Front
Pul. coal/Front
Pul . coal/Front
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Front
Pul . coal/Front
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Fiont
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front .
Pul. coal/Front
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Tangential
Boiler
Boiler
Efficiency
Manufacturer at 100% Load
PiJey Stoker
Combustion Knq.
D f, W
Combustion Eng.
I! & W
B & w
Riley Stoker
B S W
Foster Wheeler
Combustion Eng.
B & W
B S W
Riley Stoker
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combus t ion Eng .
Combustion Eng.
B (, W
Foster Wheeler
B 5. W
Combustion Eng.
Combustion Eng.
B S W
B S. W
B & W
Combustion Enq.
Combustion Eng.
B & W
B S W
B S W
B & W
B & W
B & W
B & W
B & W
B & W
Foster Wheeler
Foster Wheeler
Foster Wheeler
Foster Wheeler
niley Stoker
Combustion Enq.
Combustion Eng.
85.0
87.4
88.5
89.22
86.5
88.4
87.5
89.0
87.99
86.39
88.7
87.61
88.5
85.7
89.1
88.68
88.6
88.68
89.4
89.3
88.8
89.1
88.67
88.2
90.
88.1
88.0
88.0
88.4
88-4
88.4
89.61
88.2
88.2
88.0
88.0
88.0
86.3
86.2
86.1
86.8
87.2
88.2
88.28
% Excess
Air Used
5.
5.
23.
22.
23.
19.
25.
10.4
20.
20.
16.
16.
2.0.
12.5
20.
20.
20.
20.
20.
20.
25.
20.
20.
25.
25.
18.
18.
18.
18.
18.
18.
25.0
18.
18.
18.
18.
18.
25.
21.
21.
25.
21.
21.
2] .
-------
TABLE 45. (Continued)
Oi
Ul
*Co.
Name
390
391
392
393
394
395
396
397
398
399
400
401
402
403
404
405
406
407
408
409
410
411
412
413
414
4]5
416
417
418
419
420
421
422
423
424
425
426
427
428
429
430
431
432
433
Year Boiler
Placed in
Service
1974
1942
1942
1947
1949
1950
1952
1961
1947
1947
1958
1962
1951
1951
1953
1965
1966
1974
1968
1973
1968
1968
1969
1943
1943
1951
1950
1950
1953
1948
1948
1952
1952
1955
1958
1962
1968
1956
1959
1959
1970
1950
1950
1951
Generating
Capacity, MW
355.5
25.
25.
69.
69.
74.75
74.75
44.
26.
26.
171.7
255.
75.
75.
75.
12.5
12.5
15.0
299.2
578.
172.8
26.
66.
21.875
21 .875
60.
29.4
29.4
100.
15.
15.
20.
20.
135.
135.
194.
421.6
138.1
138.1
138.1
115.1
140.03
Design Coal
Consumption,
tons/hour
136.5
18.6
18.6
39.7
39.7
39.7
39.7
20.7
12.
12.
55.
79.
26.8
26.8
26.8
12.
12.
19.6
97.
197.1
91.
18.1
45.
9.03
9.0-3
29.4
1T.7
1 i 7
33.1
10.45
10.45
12.75
12.75
43.9
43.9
90.
182.
55.8
55.8
55.8
49.
20.
20.
20.
Air Flow at
100% Load,
scf/rain
609,000
72,050
72,050
158,000
158,000
158,000
158,000
82,400
76,527
76,527
330,000
382,000
114,500
114,500
134,500
73,000
73,000
83,400
474,000
951,556
318,000
164,300
150,192
55,000
55,000
200,000
103,500
103,500
250,000
131 ,000
131,000
155,000
155,000
312,800
312,800
317,778
646,667
242,200
242,200
242,200
220,000
398,000
398,000
398,000
Type of
Firing
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Opposed
Pul. coal/Opposed
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Opposed
Pul. coal/Opposed
Pul. coal/Tangential
Spreader Stoker
Cyclone
Pul. coal/Opposed
Pul. coal/Opposed
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Pul. coal/Tangential
Stoker
Stoker
Stoker
Stoker
Pul. coal/Tangential
Pul. coal/Tangential
Cyclone
Cyclone
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Front
Cyclone
Cyclone
Cyclone
Boiler
Manufacturer
Combustion Eng.
Combustion Eng.
Combustion Eng.
Poster Wheeler
Foster Wheeler
Foster Wheeler
Foster Wheeler
B & W
Foster Wheeler
Foster Wheeler
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Erie City Iron
Riley Stoker
Foster Wheeler
Combustion Eng.
Erie City Iron
B & W
Foster Wheeler
Foster Wheeler
Combustion Eng.
B & W
B & W
Combustion Eng.
Combustion Eng.
Combustion Eng.
B & W
B & W
Combustion Eng.
Combustion F.ng.
B & W
B & W
Combustion Eng.
Combustion Eng.
Combustion Eng.
B & W
B & W
B & W
B & W
Boiler
Efficiency
at 100% Load
88.28
85.2
85.2
86.0
86.0
86.0
86.0
87.4
87.
87.
89.47
90.57
89.0
89.0
89.0
86.0
86.0
86.9
88.9
89.0
86.46
82.88
88.
86.67
86.67
89.10
87.5
87.5
89.6
83.9
83.9
84 .6
84.6
89.34
89.34
88.6
88.4
87. 74
87.74
87.74
88.3
87.3
87.3
87.3
% Excess
Air Used
21.
25.
25.
25.
25.
25.
25.
25.
26.
26.
22.
22.
23.
23.
23.
19. -22.
19. -22.
15. -31.
20.
18.
21.
40.
12.
31.
31.
—
25.
25.
22.
25.
25.
28.
28.
24.
24.
17.
16.
18.
18.
18.
19.
20.
20.
20.
-------
TABLE 45. (Continued)
*Co.
Name
434
435
436
437
438
439
440
441
442
443
444
445
446
447
448
449
450
451
S «2
*• 453
454
455
456
457
458
459
460
461
462
463
464
465
466
467
468
469
470
471
472
473
474
475
476
477
Year Boiler
Placed in
Service
1974
1953
1953
1967
1968
3952
1954
1955
1960
1942
1944
1956
1959
1953
1949
1949
1957
1943
1948
1969
1944
1944
1947
1947
1950
1950
1955
1955
1959
1960
1961
1962
1967
1963
1971
1974
1971
1971
1953
1954
1957
1958
1968
1955
Generating
Capacity, MW
520.968
7.5
7.5
22.
598,4
81.0
112.5
113.635
179.52
57.5
62.5
113.635
163.2
46.
87.87
87.87
105.
43.75
43.75
18.328
31.25
31.25
31.25
31.25
50.0
50.0
159.5
159.5
185.
185.
185.
185.
317.5
623.
623.
1300.
816.3
816.3
213.
213.
225.
225.
590.8
217.26
Design Coal
Consumption,
tons/hour
226.
4.6
4.6
10.3
246.
51.
56.
58.
94.
40.
40.
67.
93.
30.
17.3
17.8
42.5
26.5
26.4
8.93
17.85
17.85
17.85
17.85
26.1
26.1
62.5
6^.5
72.5
72.5
72.5
72.5
117.95
234.5
234.5
480.
291.6
291.6
77.
77.
81.4
81.4
247.5
89.
Air Flow at
100% Load,
scf/min
1,214,000
21,700
21,700
45,960
910,000
124,480
169,750
183,330
304,530
102,000
102,000
195,470
277,160
83,000
84,204
84,204
161,010
94,604
97,650
40,100
74,064
74,064
74,064
74,064
107,920
107,920
257,833
257,033
350,087
350,087
350,087
350,087
548,520
1 ,092,254
1,092,254
2,500,000
975,000
975,000
278,125
278,125
317,292
317,292
800,000
400,000
Type of
Firing
Cyclone
Ful . coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Pul . coal/Front
Pul. coal/Front
Pul. coal/Front
Pu] . coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal /Front
Pul. coal/Front
Pul . coal /Front
Pul . coal/Front
Pul. coal/Front
Pul. coal /Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Opposed
Pui. coal/Opposed
Pul. coal/Opposed
Pul. coal/Opposed
Pul. coal/Opposed
Pul. coal/Opposed
Pul. coal/Front
Pul. coal/Front
Cyclone
Cyclone
Pul. coal/Front
Pul. coal/Front
Boiler
Boiler Efficiency % Excess
Manufacturer at 100% Load Air Used
B & W
B S W
B S W
Combustion Eng .
Foster Wheeler
B & W
B & W
B & W
B & W
B & W
B & W
Riley Stoker
B & W
B & W
B & W
B & W
B & W
B & W
B S W
B S W
B & W
B & W
B & W
B & W
B & W
B & W
Foster Wheeler
Foster Wheeler
Foster Wheeler
Foster Wheeler
B & W
(I & W
B & W
B s w
Foster Wheeler
Foster Wheeler
B & W
B & W
B & W
B & W
B & W
B S W
88. 3
86.98
86.98
88.5
88.
85.
87.
87.
87.
86.
86.
87.
84.
86.
86.98
86.98
89.1
85.9
86.2
87.0
85.05
85.05
85.05
85.05
87.48
87.48
89.1
89.1
88.88
88.88
88.88
88.88
89.13
88.99
88.99
88.45
88.8
88.8
88.8
88.8
89.3
89.3
87.4
88.8
15.
20.
20.
19.
16.
23.
25.
23.
23.
25.
25.
20.
20.
20.
25.
25.
27.
25.
30.
18.
25.
25.
25.
25.
25.
25.
25.
25.
20.
20.
20.
20.
18.
18.
18.
20.
18.
18.
15.
] 5.
17.
17.
20.
17. -18.
-------
TABLE 45. (Continued)
*Co.
Name
478
479
480
481
482
483
484
485
486
487
488
489
490
491
492
493
494
« 495
u< 496
01 497
498
499
500
501
502
503
504
505
506
507
508
509
510
511
512
513
514
515
516
517
518
519
520
521
Year Boiler
Placed in
Service
1955
1955
1955
1955
1954
1957
1959
1963
1968
1959
1964
1964
1974
1939
1939
1948
1954
1971
1972
1974
1964
1972
1969
1969
1970
1971
1944
1944
1952
1952
1967
1968
1942
1950
1957
1954
1954
1959
1960
1948
1948
1949
1949
1967
Generating
Capacity, MW
217.26
217.26
217.26
217.26
77.4
104.5
104.5
134.0
225.6
54.4
75.
151.
265.
7.5
7.5
7.5
30.
665.
665.
508.6
38.
38.
660.
660.
936.
936.
12.5
12.5
46.9
46.9
936.
936.
35.
50.
156.2
133.
133.
187.
187.
21.2
21.1
21.2
21.1
42.5
Design Coal
Consumption,
tons/hour
89.
89.
89.
89.
34.5
44.85
44.85
57.
84.75
41.1
60.5
70.
116.
7.75
7.75
6.92
20.5
400.
400.
255.
9.25
11.75
255.
255.
325.
325.
8.85
R.85
21 1
21.1
316.
316.
15.4
15.4
56.
47.
41.
62.8
62.8
8.7
8.7
8.7
8.7
20.5
Air Flow at
100% Load,
scf/min
400,000
400,000
400,000
400,000
150,000
199,000
199,000
246,000
440,000
167,000
275,000
279,200
2,325,500
26,100
26,100
26,000
78,200
1,524,000
1,524,000
2,313,300'
38,000
46,000
1,114,012
1,114,012
1,412,472
1,412,472
46,363
46,364
94,685
94,685
1 ,412,472
1,412,472
57,680
57,680
230,737
215,665
215,665
328,951
328,951
45,300
45,300
45,300
45,300
107,550
Type of
Firing
Pul. coal/Front
Pul. coal/Front
Pul . coal/Front
Pul. coal/Front
Pul . coal/Tangential
Pul. coal/Tangential
Pu 1 . coa I/Tangent ia 1
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Front
Cyclone
Pul. coal/Tangential
Pul. coal/Front
Pul . coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Spreader Stoker
Spreader Stoker
Pul. coal/Opposed
Pul. coal/Opposed
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Pul. coal/Tangential
Pul . coal/Front
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Pul . coal/Front
Pul. coal/Front
Pul. coal/Front
Boiler
Manufacturer
B £ W
B & W
B & W
B & W
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Foster Wheeler
Combustion Eng.
B & W
B & W
Combustion Eng.
B & W
B & W
B & W
Riley Stoker
Combustion Eng.
Combustion Eng.
Combustion Eng.
Erie City Iron
Erie City Iron
Foster Wheeler
Foster Wheeler
Combustion Eng.
Combustion Eng.
Erie City Iron
Erie City Iron
Erie City Iron
Erie City Iron
Combustion Eng.
Combustion Eng.
B & W
B & W
Combustion Eng.
B & W
B & W
Combustion Enq .
Combustion Eng.
Erie City Iron
Erie City Iron
Erie City Iron
Erie City Iron
Foster Wheeler
Boiler
Efficiency
at 100% Load
88.8
88.8
88.8
88.8
88.66
88.18
88.18
88.20
88.79
82.69
83.28
90.2
87.4
77.6
77.6
84.1
86.7
85.5
85.5
88.39
79.
78.
89.69
89.69
90.41
90.41
83.41
83.41
88.0
88.0
90.41
90.41
87.3
87. 3
88.59
89.88
89.88
89.73
89.73
85.9
85.9
85.9
85.9
88.6
% Excess
Air Used
17. -18.
17. -18.
17. -18.
17. -18.
25.
22.
22.
22.
20.
23.
17.
16.
20.
20.
20.
20.
22.
20.
20.
20.
~tu .
35.
20.
20.
20.
20.
15.5
15.5
15.0
15.0
20.
20.
25.
25.
22.
15.
15.
15.
15.
15.
15.
15.
15.
20.
-------
TABLE 45. (Continued)
*Co.
Name
522
523
524
525
526
527
528
529
530
531
532
533
534
535
536
537
538
o, 539
$ 540
«" 541
542
543
544
545
546
547
548
549
550
551
552
553
554
555
556
557
558
559
560
561
562
563
564
565
Year Boiler
Placed in
Service
1967
1966
1958
1964
1961
1965
1969
1954
1954
1956
1971
1973
1949
1949
1949
1949
1951
1953
1959
1960
1947
1952
1964
1965
1959
1960
1962
1970
1971
1949
1950
1954
1956
1951
1951
1955
1960
1957
1959
1962
1968
1973
1964
1954
Generating
Capacity, MW
42.5
J03.0
105.0
132.8
363.
405.
790.
75.
156.25
156.25
734.
800.
40.
40.
40.
40.
107.
156.
353.6
353.6
55.
82.
364.
364.
190.
190.
190.
573.
575.
95.
95.
108.
108.
44.
44.
100.
44.
100.
110.
150.
350.
382.5
166.
66.
Design Coal
Consumption,
tons/hour
26.4
42.5
42.5
58.4
135.
150.
281.
44.
57.5
57.5
279.
279.
20.7
20.7
20.7
20.7
38.7
48.6
100.8
104.5
23.
31.
116.
116.
55.
55.
55.
ID*.
186.
55.
55.
55.
55,
30.85
30.85
60.25
20.9
61.35
61.35
62.4
151.1
214.
94.25
45.9
Air Flow at
100% Load,
scf/min
139,050
223,610
223,610
325,060
625,000
711,000
1,463,000
248,000
417,780
414,670
1 ,540,000
1,510,000
125,000
125,000
125,000
125,000
243,000
376,000
480,000
500,000
126,447
144,076
466,000
466,000
318,400
318,400
318,400
1,000,000
] ,000,000
220,000
220,000
222,000
222,000
160,000
155,500
312,000
132,000
288,000
292,000
330,000
810,000
791,000
240,000
151,000
Pul .
Pul.
Pu] .
Pul.
Pul .
Pul.
Pul .
Pul.
Ful.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Pul .
Pul.
Pul.
Pill.
Pul.
Pul.
Pul.
Pill.
Pul .
Pul.
Pul .
Pul.
Pul.
Pul.
Pul.
Pul.
Pul.
Type of
Firing
coal /Front
coal/Front
coa] /Front
coal/Front
coa] /Tangential
coal/Tangential
coal /Tangential
coal/Front
coal/Front
coal/Front
coal/Tangential
coal/Tangential
coal/Opposed
coal/Opposed
coal/Opposed
coal/Opposed
coal/Front
coal/Front
coa ] /Tangent i a 1
coal/Tangential
coal/Front
coal /Tangential
coal/Opposed
coal /Opposed
coal/Tangential
coal/Tangential
coa 1 /Tangen t i a 1
coal/Tangential
coal/Tangentia 1
coal/Tangential
coa 1/Tangen t ia 1
coal/Tangential
coal/Tangential
coal/Front
coal/Front
coal/Tangential
coa 1 /Tangent ia 1
coal /Tangential
Boiler
Manufacturer
B & W
B & W
B S W
B & W
Combustion Eng.
Combustion Eng.
Combustion Eng.
Foster Wheeler
Foster Wheeler
Foster Wheeler
Combu s t ion Eng .
Combustion Eng.
Foster Wheeler
Foster Wheeler
Foster Wheeler
Foster Wheeler
Foster Wheeler
Foster Wheeler
Combustion Eng.
Combustion Eng.
B & W
Combustion Eng.
B S W
B & W
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion F.ng .
Combustion Eng.
Combustion Eng.
Combustion Cng .
B & W
B & W
B S W
B & W
B & W
B & W
n s w
Combustion Eng.
Combustion Eng.
Combustion Eng.
B & W
Boiler
Efficiency
at 100% Load
86.5
89.1
89.1
89.1
88.9
89.
90.
84.2
88.
88.
90.
90.
83.4
83.4
83.4
83.4
88.0
88.0
89.77
89.91
88.6
89.0
91.2
91.2
92.1
92.1
92.1
91.8
91.8
88.9
88.9
91 .18
91. 18
84.0
84.0
65.97
87.78
86.33
86.39
87.69
88.29
84.65
86.66
84.4
% Excess
Air Used
20.
20.
20.
20.
20.
20.
20.
40.
20.
20.
20.
20-
40.
40.
40.
40.
20.
20.
15.
15.
20.
23.
38.
18.
20.
20-
20.
18.
18.
18.
18.
18.
IS.
28.5
28.5
26.3
23.
27. 5
?6.5
18.
27.
27.
27.
28. 5
-------
TABLE 45. (Continued)
*CO,
Name
566
567
568
569
570
571
572
573
574
575
576
577
578
579
580
581
582
m 583
01 584
-1 585
586
587
588
589
590
591
592
593
594
595
596
597
598
599
600
601
602
603
604
605
606
607
608
609
Year Boiler
Placed in
Service
1970
1972
1949
1949
1951
1959
1959
1960
1961
1950
1950
1950
1956
1968
1953
1953
1954
1954
1960
1968
1973
1955
1973
1969
1959
1949
1951
1953
1957
1974
1974
1962
1964
1967
1958
1958
1953
1954
1955
1970
1971
1974
1966
1966
Generating
Capacity, MW
531.
531.
43.3
43.3
43.3
150.
150.
150.
150.
33.3
33.3
33.3
125.
387.
99.
99.
99.
99.
113.63fa
345.6
330.0
33,
60.
54.4
81.6
46.0
62.5
62.5
81.6
750.
750.
139.
139.
220.
125.
125.
75.
75.
100.
355.8
355.8
315.
81.6
81.6
Design Coal
Consumption.
tons/hour
237.
237.
25.82
25.82
25.82
64.
64.
64.
64.
17.9
17.9
17.9
49.6
160.0
42.5
42.5
42.5
42.5
43.5
112. 5
200.
17.5
28.0
23.9
29.3
18.7
23.0
?T.O
211 0
32b.
326.
43.
43.
70.5
43.1
43.1
26.8
26.8
36.75
120.
320.
120.5
31.15
31.15
Air Flow at
100% toad.
scf/min
1,292,000
1,292,000
100,000
100,000
100,000
266,000
266,000
266,000
266,000
130,000
130,000
130,000
226,000
610,000
191,000
191,000
191,000
191,000
221,000
573,000
824,827
102,500
196,000
103,652
222,000
137,000
155,000
155,000
222,000
1,317,000
1,317,000
336,000
336,000
550,000
336,000
336,000
164,500
164,500
229,000
738,933
738,933
524,000
182,900
182,900
Type of
Firing
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul . coal/Front
Pu 1 . ooa I /Front
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Pul. coal /Front
Pul. coal/Front
Cyclone
Cyclone
Pul. coal/Front
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Tangential
Pul . coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Opposed
Pul . coal/Tangential
Pu] . coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul . coal/Tangential
Pul . coal/Opposed
Pul. coal/Opposed
Pul . coal/Front
Pul. coal/Front
Pul. coal/Front
Boiler
Manufacturer
Combustion Eng.
Combustion Eng.
Riley Stoker
Riley Stoker
Riley Stoker
Riley Stoker
Riley Stoker
Riley Stoker
Riley Stoker
Riley Stoker
Riley Stoker
Riley Stoker
Riley Stoker
Combustion Eng.
Foster Wheeler
Foster Wheeler
Foster Wheeler
Foster Wheeler
B & W
B s. W
Foster Wheeler
Riley Stoker
Combustion Eng.
B & W
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Foster Wheeler
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion ling.
Combustion Eng.
Riley Stoker
Riley Stoker
Riley Stoker
Riley Stoker
Riley Stoker
Boiler
Efficiency
at 100% Load
88.85
88.85
87.1
87.1
87.1
88.9
88. 9
88.9
88.9
87.4
87.4
87.4
88.
89.
88.11
88.11
88.11
88.11
90.45
89.66
88.05
87.
87.5
91.7
89.0
87.7
88.0
88.0
89.0
88.77
88.77
89.6
89.6
89.2
89.55
89.55
88.99
88.99
89.25
89.8
89.8
89.1
88.5
88.5
% Excess
Air Used
20.
20.
20.
20.
20.
20.
20.
20.
20.
25.
25.
25.
24.
20.
24.
24.
24.
24.
16.
16.
18.
17.
30.
18.
25.
25.
25.
25.
25.
18.
18 .
22.5
22.5
22.5
22.5
22.5
22.5
22.5
22.5
20.
20.
20.
23.
23.
-------
TABLE 45. (Continued)
*Co.
Name
610
611
612
613
614
615
616
617
618
619
620
621
622
623
624
625
626
627
£ 628
00 629
630
631
632
633
634
635
636
637
638
639
640
641
642
643
644
645
646
647
648
649
650
651
652
653
Year Boiler
Placed in
Service
1969
1970
1955
1966
1973
1970
1971
1960
1960
1961
1962
1963
1963
1963
1970
1973
1957
1958
1960
1963
1965
1967
1958
1959
1959
1966
1954
1955
1955
1955
1962
1972
1973
1956
1957
1959
1959
1955
1955
1956
1957
1958
1959
1959
Generating
Capacity, MW
172.8
172.8
46.
103.7
265.23
718.1
718.1
272.
272.
272.
244.8
33.0
33.0
33.0
335.
325.
125.
125.
179.52
187.5
239.36
414.0
330.
330.
330.
950.
200.
200.
223.25
223.25
550.
1300.
1300.
300.
300.
327.6
327.6
223.25
223.25
200.
200.
172.8
172.8
172.8
Design Coal
Consumption ,
tons/hour
55.4
55.4
23.85
47.5
110.
392.5
392.5
100.
100.
100.
100.
19.0
19.0
19.0
182.3
182.1
49.7
49.7
64.9
71.3
93.4
151.4
98.
98.
98.
316.5
76.1
If, .1
7f, I
76.1
213.5
509.
509.
99.5
99.5
111.5
111.5
69.85
69.85
69.85
69.85
61.75
61.75
61.75
Air Flow at
100% Load,
scf/min
312,000
312,000
183,816
403,774
1,020,633
1,492,583
1,492,583
550,000
550,000
550,000
550,000
121,560
121,560
121,560
680,000
680,000
222,000
222,000
296,500
325,000
423,500
696,500
1,512,770
305,610
305,610
305,610
305,610
780,800
2,234,600
2,234,600
392,927
392,927
468,238
468,238
308,230
308,230
308,230
308,230
264,575
264,575
264,571
Type of
Firing
Pul. coal/Front
Pul . coal/Front
Till . coal/Front
Tul . coal/Front
Tul. coal/Front
Tul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Opposed
Pul. coal/Opposed
Pul. coal/Opposed
Pul. coal/Opposed
Cyclone
Cyclone
Cyclone
Pul . coal/Opposed
Pul . coal/Opposed
Cyclone
Cyclone
Cyclone
Cyclone
Pul. coal/Opposed
Pul. coal/Opposed
Cyclone
Cyclone
Cyclone
Pul. coal/Tangential
Pul . coal/Opposed
Pul. coal/Opposed
Pul . coal/Tangential
Pul . coal/Tangential
Pul. coal /Tangential
Pul. coal /Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Boiler
Manufacturer
Rilcy Stoker
Riley Stoker
B & W
B S W
B & W
Combust ion F.ng .
Combustion dig .
B & W
B & W
B & W
B S W
B 6 W
B & W
B & W
Riley Stoker
Riley Stoker
B & W
B & W
B S W
B & W
Riley Stoker
Riley Stoker
B & to
B & W
B S W
Combustion Eng.
B & W
B s w
B S W
B & W
B 6 W.
B & W
B & W
Combustion Etig .
Combustion Eng .
Combu s t ion Eng .
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Foster Wheeler
Foster Wheeler
Foster Wheeler
Boiler
Efficiency
at 100% Load
88.4
80.4
86.4
86.96
88.04
87.46
87.46
89.66
89.66
89.66
89.66
88.6
88.6
88.6
88.3
88.3
88.7
88.7
89.6
89.2
88.7
88.7
—
—
—
90.08
•88.5
88.5
88.5
98. S
89.59
88.87
88.87
88.5
88.5
89.8
89.8
88.85
88.85
88.85
88.85
89.66
89.66
89.66
% Excess
Air Used
23.
23.
24.
26.
20.
18.
18.
23.
23.
23.
23.
10.
10.
10.
15.
15.
13.
13.
16.
16.
15.
15.
13.
13.
13.
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
21.
-------
TABLE 45. (Continued)
*Co.
Name
654
655
656
657
658
659
660
661
662
663
664
665
666
667
668
669
670
ot 671
in 672
10 673
674
675
676
677
678
679
600
681
682
683
684
685
686
687
688
689
690
691
692
693
694
695
696
697
Year Boiler
Placed in
Service
1959
1954
1954
1954
1954
1954
1955
1955
1955
1955
1963
1963
1969
1953
J953
1953
1954
1954
1954
1954
1955
1955
1956
1942
1942
1943
1945
1960
1964
1938
1941
1941
1951
1949
1949
1955
1959
1963
1968
1947
1959
1970
1971
1972
Generating
Capacity, MW
172.8
175.
175.
175.
175.
200.
200.
200.
200.
200.
704.
704.
1150.2
175.
175.
175.
175.
175.
175.
175.
175.
175.
175.
60.
60.
60.
60.
575.01
550.
71.
71.
71.
72.
132.5
112.5
140.
140.
140.
218.
15.
50.
555.
555.
555.
Design Coal
Consumption,
tons/hour
61.75
57.9
57.9
57.9
57.9
76.5
76.5
76.5
76.5
76.5
306.
306.
434.5
58.15
58.15
58.15
58.15
58.15
58.15
58.15
58.15
58.15
58.15
26.2
26.2
26.2
26.2
206.
22b.25
11.
15.
15.
31.
23.
23.
49.
49.
50.
75.
12.
31.
238.
238.
238.
Air Flow at
100% Load,
scf/min
264,571
220,476
220,476
220,476
220,476
308,230
308,230
308,230
308,230
308,230
1,166,120
1,166,120
1,829,000
238,158
238,158
238,158
238,158
238,158
238,158
238,158
238,158
238.158
238,158
117,442
117,442
317,442
117,442
877,538
846,977
89,000
126,000
126,000
262,000
192,000
192,000
249,400
249,400
250,000
380,500
78,000
160,000
1,023,530
1,023,530
1 ,023,530
Type of
Firing
—_ _
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. eoal/T'angential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Cyclone
Cyclone
Cyclone
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Boiler
Manufacturer
Foster Wheeler
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combu s t i on Eng .
Combustion Eng.
Combustion Eng.
Combustion Eng.
B (. W
B & W
B & W
B & W
B & W
B & W
B & W
B & W
B & W
B & W
B & W
B & W
B & W
B & W
B & W
B 4 W
B & W
Combustion Eng.
Combustion Eng.
B & W
B & W
B & W
B & W
B & W
B & W
B & W
B & W
B & W
B 6, W
Foster Wheeler
Foster Wheeler
Combustion Enq.
Combustion Eng.
Combustion Eng.
Boiler
Efficiency
at 100% Load
89.66
88.64
88.64
88.64
88.64
88.64
88.64
88.64
88.64
88.64
89.66
89.66
89.22
88.33
88.33
88.33
88.33
88.33
88.33
88.33
88.33
88.33
88.33
88.03
88.03
88.03
88.03
89.62
89.83
86.1
84.2
84.2
87.6
87.3
87.3
89.51
89.51
90.38
90.43
73
79.
88.44
88.44
88.44
% Excess
Air Used
20.
16.
16.
16.
16.
20.
20.
20.
20.
20.
16.
16.
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
20.
25.
25.
25.
25.
25.
25.
23.
23.
18.
17.
40.
4n.
23.
23.
23.
-------
TABLE 45. (Continued)
*CO.
Name
698
699
700
701
702
703
704
705
706
707
708
709
710
711
712
713
714
715
3 716
S 717
718
719
720
721
722
723
724
725
726
727
728
729
730
731
732
733
734
735
736
737
738
739
740
741
Year Boiler
Placed in
Service
1973
1953
1954
1959
1961
1967
1968
1950
1950
1955
1962
1964
1966
1974
1952
1955
1950
1974
1958
1971
1950
1958
1965
1966
1973
1949
1952
1957
1953
1954
1955
1957
1935
1943
1948
1949
1950
1968
1968
1969
1969
1931
1941
1951
Generating
Capacity, MW
555.
137.5
137.5
289.
359.
549.8
549.8
25.0
37.5
57.8
57.8
90.
69.
113.636
44.
411.
152.6
306.
69.
185.277
570.24
570.24
522.0
46.
50.
113.636
120.
120.
130.
130.
80.
80.
80.
80.
80.
70.
70.
70.
70.
30.
30.
60.
Design Coal
Consumption,
tons/hour
238.
54.
54.
109.7
133.5
193.5
193.5
50.4
50.4
12.7
19.6
23.0
23.0
37.0
29.8
38.9
21.3
175.
62.
175.
30.
55.8
215.
215.
214.
18.75
18.75
4 .'. . 4
44 5
44.5
45.25
45.25
39.3
39.6
37.9
38.3
36.3
32.89
32.89
32.89
32.89
21.6
21.6
48.
Air Flow at
100% Load,
scf/min
1,023,530
230,000
230,000
471,000
574,000
830,000
830,000
217,000
217,000
59,800
91,900
97,500
97,500
162,000
149,500
191,000
112,800
— _
258,000
690,000
134,114
265,826
953,872
953,872
1,278,000
94,806
94,806
225,000
222,500
222,500
228,100
228,100
209,600
' 214,500
205,200
207,500
207,500
164,500
364,500
164,500
164,500
150,000
150,000
240,000
Typp of
Fi ring
Tul. coal/Tangential
Pul. coal/Tangential
Pu] . coal/Tangential
Pu]. coal/Front
Pul. coal/Front
Cyclone
Cyclone
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Pul. coal/Tangential
Pul. coal/Tangential
Pu]. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Pul. coal/Tangential
Pu]. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Tangential
Pul. coal/Front
Pul. coal/Front
Pul. coa]/Front
Pul. coa]/Front
Pul. coal/Front
Pul. coal/Front
Cyclone
Boiler
Manufacturer
Combustion Eng.
Combustion Eng.
Combustion Eng.
Foster Wlioeler
Fostor Wheeler
B S, W
B S W
B 6 W
B S W
Riley Stoker
Combustion Eng.
Combustion Eng.
Combustion Eng.
Riley Stoker
Piley Stoker
Combustion Eng.
Riley Stoker
Combustion Eng .
Combustion Eng.
Combustion Eng.
B & W
B S W
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Kng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Eng.
Combustion Enq .
Combustion Enq.
Combustion Eng.
Combustion Eng.
Riley Stoker
Riley Stokor
Riley Stoker
Riley Stoker
D s W
B S W
B & W
Boiler
Efficiency
at 100% Load
88.4-1
88.1
88.1
88.82
86.77
89.12
89.12
86.05
86.05
85.6
86.7
88.7
88.7
87.3
87.5
88.6
81.4
89.18
87.9
86.63
87.6
89.3
90.04
90.04
89.72
88.
88.
88.2
88.76
98.76
88.68
88.68
on on
87.71
87.49
88.78
90.21
87.85
87.85
8 7 . 8 ">
87.85
"4
84.
89.7
% Excess
Air Used
23.
23.
23.
23.
23.
23.
23.
23.
23.
23.
21.
18.
18.
20.
18.
18.
20.
--
21 .0
21.'l
25.
18.
23.
23.
23.
20.
20.
20.
20.
20.
20.
20.
28.
30.
30.
30.
30.
20.
20.
20.
20.
J2.
J2.
12.
-------
TABLE 45. (Continued)
Year Boiler
Generating
Capacity, HW
330.
113.6
113.6
79.6
79,6
30.
30.
50.
60.
75.
125.
60.
75.
*Co.
Name
742
743
744
745
746
747
748
749
750
751
752
753
754
Placed in
Service
1969
1960
1962
1954
1955
1943
1947
1949
1951
1958
1964
1954
1960
Design Coal
Consumption,
tons/hour
133.
45.
45.
49.
49.
18.5
20.5
34.5
42.0
45.6
68.0
38.7
36.0
Air Flow at
100% Load,
scf/min
650,000
220,000
220,000
250,000
250,000
130,000
142,000
227,000
227,000
223,000
371,000
258,000
252,000
Type of
Firing
Cyclone
Cyclone
Cyclone
Cyclone
Cyclone
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul. coal/Front
Pul . coal/Front
Pul. coal/Front
Pul. coal/Front
Boiler
Boiler
Efficiency
Manufacturer at 100% Load
B &
B &
B &
B I,
B &
B f,
B &
B £
B &
B &
B &
B &
W
W
W
W
W
W
W
W
W
W
W
W
Combustion Eng.
88
90
90
89
89
86
86
86
85
88
87
86
87
.8
.0
.0
.8
.8
.3
.2
.2
.8
.05
.6
.2
.7
% Excess
Air Used
12.
15.
15.
15.
15.
24.
22,
25.
25.
18.
22.
?3.
23.
-------
TABLE 46.
POWER PLANT AND AIR QUALITY DATA FOR THOSE
PLANTS WITH ELECTROSTATIC PRECIPITATORS
*Co. Type Fly Ash ESP
Name Collector** Manufacturer
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
i.™i — -
E
E
E
E
E
E
C
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
C
E
E
E
E
E
E
. — r— —
Buell
Western
Western
Buell
American
UOP
UOP
American
American
American
Koppers
Koppers
Buell
Research
Research
Research
Standard/UOP
Standard
Standard
Standard
Cottrell
Cottrell
Cottrell
Buell/American Standard
Koppers
Koppers
Koppers
Research
Research
Research
Researcli
Research
Western
Western
Research
Research
Buell
Buell
. ._ f j . — __ _ t _
Cottrell
Cottrell
Cottrell
Cottrel 1 '
Cottrell
Cottrell
Cottrell
Year ESP
Placed in ESP Design
Service Efficiency, %
1971
1972
1972
1972
1954/1957
1967
1968
1972
1973
1974
1960
1958
1959
1969
1970
1971
1963/1973
1954/1968
1970
1970
1975
1974
1974
1969
1970
1969
1970
1972
1972
1967
1967
1973
1971
1973
1974
.—..„.-,—..— — - - - - — _-
98.
99.
99.
99.
97.
97.
97.
99.
99.
99.
99.
99.
90.
95.
95.
99.
99.
99.
99.
98.
97.
97.
99.
99.
99.
97.
97.
99.
99.
99.
99.
95.
95.
99.
99.
99.
99.
" L- — rr
5
0
0
5
0
0
5
5
5
5
00
5
5
5
7
7
7
9
21
0
43
48
" m-i. -i
ESP Tested
i Efficiency, %
93.00
99.4
99.4
73.00
96.3-96.4
96.3-96.4
99.5
83.00
97. -98. 4
97. -98. 4
___
97.6-99.9
97.6-99.9
97.6-99.9
9B.40
~ TT= — — * Tf TT
Mass Emission
Rate, Ibs/hr
634.
440.
440.
313.
313.
313.
350.
900.
900.
450.
450.
450.
53.
650.
950. cacl.
971. each
73.6
73.6
73.6
4080.
4080.
183.
183.
166.
51.7
2424.
2401.
]80.
381.
91.9
J04.
-i 1 — — . — • '•••" i .
Installed Cost,
$l,000's***
2,
2,
2,
3,
1,
2,
2,
2,
2,
1,
1,
1,
2,
4 ,
4,
1,
1,
2,
1,
2,
550.
301.
301.
728.
673.
668
453
025
700
700
407
632
706
958
401
417
167
934
C5:
650
__
__
--
172
172
579
597
480
396
351
351
389
525
832
178
,
.
_
,
.
_
_
.
.
_
_
-
_
.7
.9
.0
,7
_
.
.
**Some plants have a combination mechanical collector - electrostatic precipitator. Those with an ESP only are designated
as "E" under this heading, and those with a combination collector are designated as "C".
***Costs are reported as the original costs recorded on the utility's books of accounts and unitized as prescribed in the
FPC List of Units of Property effective January 1, 1961. Certain items called for in this report are not specifically
unitized in the referenced list of property units. In this case the most accurate figure available is desired. In the
case of stacks without foundation, the stack cost plus those added costs essential to the stack operation and support
are included.
-------
TABLE 46. (Continued)
*Co.
Name
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
Type Fly Ash
Collector**
E
E
C
E
C
C
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
C
E
E
E
C
E
E
C
C
E
E
ESP
Manufacturer
Buell
Research Cottrell
Buell
Research Cottrell
Buell
UOP
Buell
Buell
UOP
UOP
Buell
Buell
Research Cottrell
Research Cottrell
Koppers
Koppers
Koppers
Koppers
Western
Buell
Western
Western
Research Cottrell
Western
Western
Western
Western
Koppers
Research Cottrell
UOP
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Researcli Cottrell
Buell
Buell
American Standard
UOP
American Standard
Year ESP
Placed in
Service
1974
1974
1974
1973
1975
1973
1974
1974
1973
1973
1975
1975
1974
1973
ESP Design
Efficiency, S
99.43
99.33
99.24
99.44
99.46
99.00
99.59
99.53
99.
99.
99.27
99.27
99.25
99.5
ESP Tested
Efficiency, *
-__
99.5
Mass Emission
Rate, Ibs/hr
920.
49.6
65.
75.
87.
208.
380.
39.
39.
51.
12.0
Installed Cost,
$l,000's***
884.
___
3,050.
-_-
2,580.
5,100.8
7,788.4
1,448.4
575.
1949
1949
1952
1958
1973
1972
1969
1969
1970
1972
1972
1972
1972
1961
1960
1976
1960
1974
1974
1973
1958
1962
1969
1971
1968
1974
95.
95.
96.
97.
99.0
99.0
97.1
97.1
97.1
98.0
98.0
98.0
98.0
97.0
95.
99.5
96.00
99.5
99.5
99.5
96.
96.
98.
96.0
99.5
99.35
97.7-98.7
97.7-98.7
97.7-98.7
99.6
83.2
107.
107.
244.
125.
444.
569.
77.5
77.5
239.6
36.0
30.2
40.3
41.1
749.5
2423.
290.
400.
437.7
670.1
246.1
76.5
256.0
133.7
66,250.
66,250.
110,700.
163,500.
7,991.
5,031.
640.5
640.5
992.
569.
569.
569.
569.
1,396.
2,987.
535.
3,129.
3,257 .
3,647.
627.
454 .
1,006.
500.
224.1
1,9^2.
-------
TABLE 46. (Continued)
*CO.
Name
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
100
101
102
103
104
105
106
107
108
109
110
111
112
113
114
115
116
117
118
119
120
121
122
123
124
125
Type Fly Ash
Collector**
E
E
E
E
C
E
E
E
C
C
C
C
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
C
C
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
ESP
Manufacturer
American
American
American
American
American
American
Research
Buell
Research
Research
Research
Research
Research
Buell
Research
Research
Research
Research
Research
Research
Koppers
Research
Research
Research
Research
Research
Western
Western
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
Western
Western
Western
Standard
Standard
Standard
Standard
Standard
Standard
Cottrell
Cottrell/Koppers
CottrelJ/Koppers
Cottrel1/Koppers
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell/Koppers
Cottrell/Koppers
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottreil
Cottrell
Cottrell
Cottrell
Cottrell
Cottr*>ll
Cottrell
Cottrell
Year ESP
Placed in
Service
1971
1971
1971
1971
1968
—
1970
1958
1958
1958
1958
1958
1949
1949
1959
1970
1972
1941
1941
1951
1951
1962
1973
1958
1961
1945
1953
1949
1949
1959
1971
1971
1966
1965
1965
1966
1966
1967
1968
1972
1972
1961
1955
1955
ESP Design
Efficiency, %
97.5
97.5
97.5
97.5
97.5
97.5
98.0
95.
96.
96.
96.
96.
95.
95.
97.
99.5
99.5
90.
90.
95.
95.
99.4
99.3
99.0
98.0
92.
95.
98.
98.
98.5
98.0
98.0
98.0
99.
99.
99.
99.
98.
98.
99.5
99.5
98.
95.
95.
ESP Tested
Efficiency, %
93.00
93.00
93.00
93.00
93.2
93.2
93.2
93.2
97.1
99.5
98.00
99.3
97.5
95.8
93.4
95.8
90.9
94.3
94.3
93.9
Mass Emission
Rate, Ibs/hr
84.
84.
84.
84.
13.8
27.55
81.
576.
200. 3
200.3
200.3
200.3
355.
355.
608.
224.
224.
292.
292.
238.
238.
110.
408.6
374.5
500.4
221.1
171.6
32.0
32.0
558.3
33.3
33.3
147.5
309.2
309.4
283.5
283.6
235
235.
74.
74.
141.1
120. 3
120.3
Installed Cost,
$l,000's***
259.1
259.1
259.1
259.1
128.9
94.6
200.
424.
480.
468.
543.
888.
1,311.4
151.
149.
403.
402.
705.
2,752.
1 ,041.
1,359.
122.
306.
715.
715.
1,588.
365.
365.
2,327.
2,135.
1 ,992.
2,25).
2.089.
179.
977.
919.
-------
TABLE 46. (Continued)
*Co.
Name
126
127
128
129
130
131
132
133
134
135
136
137
138
139
140
141
142
143
144
1 45
146
147
148
149
150
151
152
153
154
155
156
157
358
159
160
161
162
163
164
165
166
167
168
169
Type Fly Ash
Collector**
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
-
-
-
-
-
-
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
ESP
Manufacturer
Western
Research
Koppers
Koppers
Western
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
Western
Western
Research
Research
Research
Research
Western
Western
Western
Western
Western
Koppers
Koppers
Western
Western
Koppers
Buell
UOP
UOP
OOP
UOP
UOP
Research
UOP
OOP
Cottrell
Cottrel I
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Year ESP
Placed in
Service
1955
1971
1958
1962
1955
1973
1973
1963
1929
1929
1929
1929
1929
1929
1938
1938
1938
1955
1962
1953
1953
1955
1957
1957
1965
1969
1969
1969
1968
1969
1959
1961
1971
1971
1967
3967
1974
1974
1974
1974
1974
1969
1974
1974
ESP Design
Efficiency, %
95.
98.
98.
98.
90.
99.0
98.5
98.
96.
96.
96.
97.
97.
97.
96.6
96.6
96.6
98.
98.
97.
97.
99.
99.
99.
99.
99.
99.
99.
99.
99.
95.
95.
99.
99.
95.
98.
99.5
99.5
99.5
99.5
99.5
99.0
99.5
99.5
ESP Tested
Efficiency. %
__ _
— -
95.2-98.6
95.2-98.6
95.2-98.6
95.2-98.6
95.2-98.6
59. -88.
59. -88.
96.9-97.6
96.9-97.6
89.9
95.5
Mass Emission
Rate, Ibs/hr
120.3
39.2
405.
401.7
380.5
35.79
316.25
840.8
100.5
100.5
100.5
72.9
72.9
72.9
74.5
74.5
74.5
297.6
124.1
286.6
286.6
184.6
192.0
192.0
4944.
63.87
63.87
63.87
127.75
127.75
1328.26
1307.32
168.
168.
670.8
981. 3
3.27
1) .95
1 .39
c.63
8.08
224.
3.763
5.825
Installed Cost,
$1.000's***
._.
1,800.
1,205.
1,438.
394.
3,500.
7,000
1,560.
- —
— _
519.
1,807.
962.
962.
2,187.
2,022.
2,079.
10,300.
470.
470.
470.
1,115.
1,115.
486.5
527.5
1,311.
1 ,311.
374.9
595.7
981. 5
983.5
983.5
] ,610.
2,212.8
811.
929.0
929.0
-------
TABLE 46. (Continued)
*CO.
Name
170
171
172
173
174
175
176
177
178
179
180
181
182
183
184
185
186
187
188
189
190
191
192
193
194
195
196
197
198
199
200
201
202
203
204
205
206
207
208
209
210
211
212
213
Type Fly Ash
Collector**
E
E
E
C
C
C
C
C
C
E
E
E
E
E
E
E
E
E
E
E
C
C
C
C
C
C
C
E
E
E
E
E
E
E
E
E
C
C
C
C
C
C
C
C
ESP
Manufacturer
Research
Research
Research
Buell
Buell
Research
Research
Research
Research
Buell
Buell
Buell
Buell
Research
Research
Research
Research
Research
Research
Research
Research
Research
UOP
Western
Western
Western
Western
American
Research
Research
Research
Research
Research
Research
Research
Research
Western
Western
Western
Western
Western
Western
Western
Research
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Standard
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Year ESP
Placed in
Service
1971
1972
1974
1958
1958
1937
1954
1940
1954
1971
1970
1972
1974
1973
1973
1973
1972
1972
1972
1969
1957
1959
1970
1951
1951
1951
1951
1968
1942
1943
1947
1948
1971
1973
1973
1974
19C7
1967
1957
1953
1953
1954
1954
1961
ESP Desiqn
Efficiency, %
97.3
97.3
98.6
97.5
97.5
95.0
95.0
97.0
97.0
98.
98.
99.5
99.5
99.5
99.5
99.5
99.5
99.5
99.5
97.5
98.
98.
99.5
98.
98.
98.
98.
99.6
99.6
99.6
99.6
99.6
97.66
97.66
97.6
98.1
98.1
98.1
98.1
98.3
ESP Tested
Efficiency, %
97.5-97.9
97.5-97.9
67.9-93.2
67.9-93.2
67.9-93.2
67.9-93.2
67.9-93.2
67.9-93.2
99.8-99.9
99.8-99.9
99.8-99.9
99.8-99.9
99.8-99.9
99.8-99.9
98.6
98.6-98.9
98.6-98.9
98.6-98.9
98.6-98.9
99.4
98. -99.
98. -99.
98. -99.
96.5-98.5
96.5-98.5
.
Mass Emission
Rate, Ibs/hr
1707.
1707.
1570.
393.
393.
873.
873.
873.
873.
1286.
1286.
321.
321.
321.
321.
321.
5.
129.2
129.2
65.0
88.
88.
88.
88.
33.
237.
237.
237.
237.
224.
41.
41.
390.
200..
200.
200.
200.
330.
Installed Cost,
$l,000's***
1,726.
1,725.
1,887.
412.
384.
135.
135.
134.
134.
1,251.
1,486.
4,259.
2,720.
803.
838.
857.
862.
827.
996.
260.
275.
461.
566.
566.
565.
565.
455.
204.
203.
258.
235.
4,564.
4,431.
4,826.
4,377.
.548.
548.
1 ,746.
789.
789.
789.
789.
1 ,943.
-------
TABLE 46. (Continued)
01
-J
*Co.
Name
214
215
216
217
218
219
220
221
222
223
224
225
226
227
228
229
230
231
232
233
234
235
236
237
238
239
240
241
242
243
244
245
246
247
248
249
250
251
252
253
254
255
256
257
Type Fly Ash
Collector**
E
C
C
E
E
C
C
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
C
C
E
E
E
E
E
E
E
C
C
C
C
C
C
C
C
C
ESP
Manufacturer
American Standard
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research CottrelI/Western
Research CottrelI/Western
Research Cottrell/Western
Research Cottrell
Buell
Buell
Buell
Buell
Buell
Buell
Buell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Buell
Research Cottrell '
Research Cottrell
Buell
UOP/Bueil
UOP/Buel1
Research Cottrell
Research Cottrell
Buell
Buell
Buoll
Buell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research
Research
Research
Research
Research
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Year ESP
Placed in
Service
1969
1968
1968
1967
1967
1971
1971
1973/1959
1972/1960
1973/1961
1974
1972
1972
1972
1973
1973
1972
1972
1973
1973
1971
1971
1972
1970
1970
1973
1972
1971
1972
1972
1973
1972
1972
1973
1970
1952
3953
1954
1960
1942
1942
1949
1950
1950
ESP Design
Efficiency, %
99.6
99.6
99.6
99.0
99.0
99.0
99.0
99.5
99.5
99.5
99.7
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.
99.
99.2
99. ,
99.
99.
99.0
99.0
99.7
99.7
99.03
99.03
99.06
99.06
99.5
98.1
97.9
97.9
98.3
95.0
95.0
97.5
97.5
97.5
ESP Tested
Efficiency, %
98.7
98.5-98.9
98.5-98.9
98.5-98.9
98.5-98,9
— _
___
___
— _
98.73
98.73
99.55
99.4
Mass Emission
Rate, Ibs/hr
140.
12.
12.
30.
30.
91.
91.
107.
107.
107.
280.2
43.3
43.3
43.3
110.
110.
43.3
43.3
65.0
65.0
69.
69.
91.7
93.
93.
141 .
187.
187.
124.5
124.5
82.7
82.7
92.5
92.5
285.7
215.7
238.3
282.
351.
235.
235.
300.
300.
300.
Installed Cost,
$l,000's***
3,910.
497.
497.
585.
585.
681.
582.
4.359./4S8.
4,359./458.
4,359./458.
-.__
2,369.
2,369.
2,369.
2,175.
2,175.
2,517.
2,517.
1,382.
1,382.
1,008.
1,008.
2,322.
1,191.
1,191.
3,508.
222. /2, 114.
222. /2. 114.
4,298.
4,298.
2,619.
2,619.
2,619.
2,619.
1,473.
378.6
370.6
501 .7
552.6
185.4
175.1
442.9
477.6
493.3
-------
TABLE 46. (Continued)
*CO.
Name
258
259
260
261
262
263
264
265
266
267
268
269
270
271
272
273
274
275
276
277
278
279
280
281
282
283
284
285
286
287
288
289
290
291
292
293
294
295
296
297
298
299
300
301
Type Fly Ash
Collector**
C
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
ESP
Manufacturer
Research
American
American
American
American
Research
Research
Research
OOP
Research
Research
Western
Research
Due 11
Western
Western
Buell
Research
Research
Buell
Buell
Buell
American
Research
Research
Buell
Research
Research
American
Buell
Buell
Buell
Buell
Buell
Buell
Buell
American
American
Buell
Buell
Buell
Buell
Buell
Buell
Cottrell
Standard
Standard
Standard
Standard
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Standard
Cottrell
Cottrell
Cottrell
Cottrell
Standard
Standard
Standard
Year ESP
Placed in
Service
1956
1973
1973
197-1
1974
1971/1972
1972/1972
1972/1972
1970
1945
1945
1973
1948
1971
1969
1969
1970
1971
1972
1974
1972
1972
1965
1967
1968
1969
1948
1948
1964
1971
1968
1969
1970
1968
1974
1974
1965
1967
1968
1969
1970
1973
1974
1974
ESP Design
Efficiency, %
98.2
98.0
98.0
96.0
96.0
98.6
98.6
98.6
98.2
90.0
90.0
99.4
90.0
98.7
98.0
98.0
98.4
98.0
98.0
99.0
99.0
99.0
98.0
98.0
98.5
98.3
98.0
98.0
98.0
98.3
98.3
98.3
98.3
98.3
99.0
99.0
98.0
98.0
98.2
98.2
98.0
98.2
99.5
99.5
ESP Tested
Efficiency, %
98.7-98.9
98.7-98.9
98.7-98.9
98.0
_ —
98.12
98.12
99.3-99.5
99.3-99.5
78.0-94.0
78.0-94.0
78.0-94.0
___
94.5
94.5
93.06
94.5
Mass Emission
Rate, Ibs/hr
450.
50.1
94.5
146. /157.
151. /151.
151. /151.
3240.
220.
220.
26.
220.
_ —
72.
72.
260.
260.
300.
360.
540.
540.
143.
144.
266.
340.
340.
340.
374.
374.
622.
622.
153.
170.
106.9
106.9
430.
544.
14.0
14.0
Installed Cost,
$l,000's***
711.3
820.
] ,396.
1,100.
1,100.
561.962
59.
59.
1,063.
51.
1,032.
510.
535.
1,535.
1,270.
1,167.
4,103.
3,496.
3,496.
331.
510.
650.
658.
80.
80.
212.
1,006.
665.
902.
824.
816.
2,247,
2,241.
283.
306.
522.
462.
690.
2,191.
1,472.7
1,327.6
-------
TABLE 46. (Continued)
*CO.
Name
302
303
304
305
306
307
308
309
310
311
312
313
314
315
316
317
318
319
320
321
322
323
324
325
326
327
328
329
330
311
332
333
334
335
336
337
338
339
340
343
342
343
344
345
Type Fly Ash
Collector**
C
E
E
E
C
E
E
E
E
E
E
C
E
C
C
C
C
C
C
E
E
E
E
E
C
C
C
C
E
C
C
E
E
E
E
E
C
E
E
E
E
E
E
E
ESP
Manufacturer
Western
Research Cottrell
Research Cottrell
Research Cottrell
OOP
Western
Western
Buell
Quell
Buell
Buell
Research Cottrell
Buell
Western
Western
Western
Western
Western
Western
Western
Research Cottrell
Research Cottrell
Research Cottrell/UOP
Research CottrelI/OOP
American Standard/Research Cottrell
American Standard/Research Cottrell
Western/Research Cottrell
Western/Buell
Buell
Western/Research Cottrell
Western/Research Cottrell
Buell
Research CottrelI/OOP
Western
American Standard
American Standard -
Western
OOP
OOP
UOP
OOP
Buell
Buell
Buell
Year ESP
Placed in
Service
1954
1958
1973
1974
1969
1970
1973
1974
1972
1973
1974
1972 ,
1970
1955
1955
1955
1955
1955
1956
1964
1969
1968
1974
1974
1 1973
11 1973
1969
1971
1974
1973
1972
1971
1968/1974
1969
1973
1967
1972
1969
1970
1970
1974
1973
1973
1973
ESP Design
Efficiency, %
97.
98.5
99.
99.
97.
99.
99.
99.5
99.
99.5
99.5
99.67
99.
96.1
96.1
96.1
96.1
96.1
96.1
90.
97.
97.
90./98.93
90./98.93
99.78
99.78
98.9
99.5
99.25
99.0
99.0
99.0
98.4
97.00
99.
98.
99.
98.
98.
98.
99.3
99.1
99.1
99.2
ESP Tested
Efficiency, %
___
— _
97.
96.63
96.63
99.16
99.50
99.30
99.10
65.30
99.2
99.4
99. -99. 5
99. -99. 5
99. -99. 5
99. -99. 5
97.00
92.00
99.70
99.10
99.4
99.4
99.8
Mass Emission
Rate, Ibs/hr
100.
53.
112.
112.
304.
69.
19.
175.
15.5
22.38
___
285.
642.8
642.8
642.8
642.8
642.8
642.8
3564.
72.2
72.2
109./21.B6
108./21.86
51.43
51.43
51.7
168.
36.3
57.6
57.6
167.5
801.0
26.7
326.
32.17
96.
107.
60.
41.
20.67
22.29
23.17
Installed Cost,
$l,000's***
— —
1,500.
1,500.
150.
2,900.
1,752.7
1,697.
2.690.
1,418.
1,528.
980.
2,200.
565.
565.
565.
565.
565.
565.
10,004.
308.8
214.2
139.2/2,522.6
---
2,228.7
415.5
840.89
1,168.5
706.6
606.
633.
718.1/1 ,559.
836.0
1 ,314.7
365.
602.
323.
386.
381.
1,126.
850.
850.
970.
-------
TABLE 46. (Continued)
*Co.
Name
346
347
348
349
350
351
352
353
354
355
356
357
358
359
360
361
362
<* 363
3 364
0 365
366
367
368
369
370
371
372
373
374
375
376
377
378
379
380
381
382
383
384
385
386
387
388
389
Type Fly Ash
Collector**
E
E
E
E
E
E
E
E
E
E
E
E
E
C
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
ESP
Manufacturer
Buell
Buell
OOP
HOP
UOP
UOP
Western
Research
Research
UOP
American
Research
UOP
Koppers
Duell
Research
Research
Research
Koppers
Research
Buell
Research
Western
Buell
Research
UOP
UOP
Western
American
American
UOP
UOP
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
Buell
Western
Cottrell
Cottrell
Standard
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Standard
Standard
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Year ESP
Placed in
Service
1973
1972
1973
1973
1974
1974
1973
1972
1972
1968
1968
1966
1971
1969
1969
1964
1972
1972
1970
1969
1973
1971
1973
1973
1974
1954
1958
1961
1964
1968
1970
1973
1939
1939
1949
1951
1951
1954
1956
1958
1962
1966
1969
1972
ESP Design
Efficiency, %
99.2
99.2
99.3
99.3
99.3
99.3
99.0
99.
99.
98.
97.
97.
99.35
97.
99.
95.
99.5
99.5
98.5
98.5
98.5
98.0
98.5
98.5
99.5
97.5
97.5
97.5
97.5
97.5
97.5
99.5
97.5
97.5
97.5
97.5
97.5
97.5
97.5
97.5
98.5
98.5
99.40
99.4
ESP Tested
Efficiency, %
99.8
99.8
99.51
98.82
99.5
99.5
97.40
97.70
97.70
97.40
98.5
96.9-98.0
96.9-98.0
96.9-98.0
96.9-98.0
96.9-98.0
96.9-98.0
99.5
T-
99.5
99.5
99.5
97.5
97.5
97.5
97.5-99.7
97.5-99.7
99.70
99.5
Mass Emission
Rate, Ibs/hr
23.17
87.5
27.
43.
30.9/73.5
48.3/115.5
38.2
47.4
183.0
257.
50.2
150.8
63.8
77.
290.
1527.
219.
219.
477.
1306.
166.
1036.
345.
43.12
49.4
57.5
GO. 5
60.5
94.5
94.5
94.5
75.0
20.1
20.1
26.8
26.8
26.6
282.
286.
333.
248.
303.
103.
192.
Installed Cost,
Sl.OOO's***
970.
1,960.
1,324.4
1 ,603.8
1,596.8
2,036.1
1,375.
2,454.
1,597.
367.
247.
245.
350.
852.
1,294,
440.
1 ,453.
1,641.
1,675.1
759.9
756.
1,687.36
1,460.5
105.0
144.1
116.3
108.0
332.0
162.0
326.21
66.3
66.3
64.2
82.5
82.5
340.
339.
433.
489.
503.
899.
1,486.
-------
TABLE 46. (Continued)
*Co.
Name
390
391
392
393
394
395
396
397
398
399
400
401
402
403
404
405
406
407
408
409
410
411
412
413
414
415
416
417
418
419
420
421
422
423
424
425
426
427
428
429
430
431
432
433
Type Fly Ash
Collector**
E
E
E
E
E
E
E
C
E
E
C
C
E
E
E'
C
C
E
E
E
E
C
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
ESP
Manufacturer
Western
Research
Research
Research
Research
Research
Research
American
Research
Research
Buell
Hue 11
Buell
Buell
Buell
American
American
American
Western
Western
Research
Western
Research
Western
Western
Western
Buell
Buell
Research
Koppers
Koppers
Koppers
Koppers
Research
Research
Western
Western
American
American
American
American
Western
Western
Western
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Standard
Cottrell
Cottrell
Standard
Standard
Standard
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Standard
Standai >1
Standard
Standard
Year ESP
Placed in
Service
1974
1942
1942
1947
1949
1950
1952
1961
1947
1947
1958
1962
1974
1965
1974
1965
1966
1975
1968
1973
1968
1968
1969
1973
1973
1973
1971
1971
1953
1974
1974
1974
1974
1955
1958
1962
1968
1968
1969
1969
1970
1969
1970
1970
ESP Design
Efficiency, %
99.4
96.0
96.0
97.5
97.5
97.5
97.5
99.5
94.00
94.00
99.00
99.00
98.5
99.0
98.7
97.
97.
99.8
98.
99.0
97.
98.5
94.5
99.8
99.8
99.8
98.
98.
98.
99.5
99.5
99.5
99.5
98.
98.
99.0
99.0
98.0
98.0
98.0
98.0
98.0
98.0
98.0
ESP Tested
Efficiency, %
99.5
98.1
98.1
99.5
99.5
99.5
99.5
85.90
93.50
97.3-98.2
97.3-98.2
93.0
97.3
95.2
95.14
Mass Emission
Rate, Ibs/hr
192.
91.
91.
169.
169.
169.
169.
17.7
1350.
1350.
185.
299.6
60.
121.
60.
89.
89.
12.
202.
257.2
426.14
75.98
149.
28.0
28.0
17.0
93.3
93.3
78.5
8.
9.
166.
99.5
CO. 8
128.5
191.
200.
193.
166.
44.9
44.9
44.9
Installed Coat,
Sl.OOO's***
1,709.
56.
56.
188.
213.
230.
247.
810.
60.
60.
637.
794.
1280.
280.
1280.
75.
75.
555.
393.5
1728.2
1030.
75.
136.
1500.
1500.
3000.
218.2
218.2
218.2
357.5
419.8
650.
860.
650.
712.
665.
401.
620.
583.
584.
-------
TAIU.E 46. (Continued)
*Co.
Name
434
435
436
437
438
439
440
441
442
443
444
445
446
447
448
449
450
« 451
•J 452
M 453
454
455
456
457
458
459
460
461
462
463
464
465
466
467
468
469
470
471
472
473
474
475
476
477
Type Fly Ash
Collector**
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
C
C
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
C
ESP
Manufacturer
Koppers
Research CottreJl
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
UOP
Western
Western
Western
Western
Western
UOP
Western
Western
Western
Western
Western
Western
Buell
Buell
Buell
Buell
American Standard
Western
Western
Koppers
Research Cottrell
Research Cottrell
Western
Western
Western
Western
Western
Western
Year ESP
Placed in
Service
1974
1971
1971
1972
1968
1952
1954
1955
1960
1972
1972
1972
1972
1972
1970
1970
1957
1969
1969
1969
1971
1972
1971
1971
1971
1971
1955
1955
1959
1960
1961
1962
1967
1969
1971
1974
1971
1971
1972
1972
1972
1971
1968
1955
ESP Design
Efficiency, %
99.75
94.
94.
94.
99.
97.
97.
97.8
97.
99.
99.
99.
99.
99.
99.
99.
99.
98.
98.
98.
99.
99.
99.
99.
99.
99.
97.
97.
97.
97.
97.
97.
99.
99.
99.
99.75
98.5
98.5
99.5
99.5
98.5
98.5
96.5
96.1
ESP Tested
Efficiency, %
98.00
89.1
89.1
95.2
89.1
99.00
— _
94.4-97.5
94.4-97.5
---
99.8
99.8
99.8
99.8
99.8
99.8
67.8
67.8
81.3
81.3
81.3
fll.3
87.6
87.6
S7.6
94.7-97.7
94.7-97.7
94.7-97.7
94.7-97.7
94.7-97.7
Mass Emission
'Rate, Ibs/hr
52.3
42.
42.
56.
599.
265.
580.
713.
991.
30.
28.
45.
88.
66.
43.
43.
193.
130.
129.
30.
48.3
48.3
48.3
48.3
70.6
70.6
506.8
506.8
617.
617.
617.
617.
333.
666.
666.
370.
1511.
1497.
95.
95.
293.
295.
2969.
642.8
Installed Cost,
$l,000's***
1,630.
185.
185.
372.
1,370.
233.
385.
342.
346.
1,4*4.
1,444.
1,789.
2,257.
772.
473.
473.
335.
512.
463.
1,198.
1,198.
1,198,
1,198,
1,869.
1,869.
362.
362.
396.
390.
414.
435.
671.
1,239.
1,238.
6,000.
3,426.
3,426.
4,213.
4,213.
4,213.
4,213.
1,885.
535.
-------
TABLE 46. (Continued)
*Co.
Name
478
479
480
481
482
483
484
485
486
487
488
489
490
491
492
493
494
495
496
497
498
499
500
501
502
503
504
505
506
507
508
509
510
511
512
513
514
515
516
517
518
519
520
521
Type Fly Ash
Collector**
C
C
C
C
C
C
C
E
E
E
E
E
E
E
E
E
E
E/E
E/E
E
E
E
E
E
E .
E
E
E
E
E
E
E
C
C
C
C
C
C
C
E
E
E
E
E
ESP
Manufacturer
Western
Western
Western
Western
Buell
Buell
Buell
Buell
Buell
Research Cottrell
Research Cottrell
UOP
American Standard
Buell
Buell
Buell
Buell
Koppers/
Koppers/
American Standard
American Standard
Buell
Buell
Buell
Buell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrel 1
Research Cottrel 1
Researcli Cottrel 1
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottroll
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Year ESP
Placed in
Service
1955
1955
1955
1955
1954
1957
1959
1963
1968
1972
1972
1964
1974
1955
1955
1955
1955
1971/1974
1972/1974
1974
1972
1972
1969
1969
1970
1971
1944
1944
1952
1952
1967
1968
1950
1950
1957
1954
1954
1959
1959
1948
1948
1949
1949
1967
ESP Design
Efficiency, %
96.1
96.1
96.1
96.1
96.
96.
96.
96.
98.
99.
99.
97.0
98.0
90.
90.
90.
90.
99.4/95.
99.4/95.
99.33
95.
95.
99.5
99.5
99.5
99.5
83.
83.
98.
98.
99.5
99.5
98.
98.
98.
95.
95.
95.
95.
94.
94.
94.
94.
98.
ESP Tested
Efficiency, %
— __
95.6
95.6
95.6
95.6
96.10
99.4-99.7
99.4-99.7
97.4
— -
99.5
99.5
99.6
99.6
89. -99. 1
89. -99.1
89. -99.1
89. -99.1
93.3
93.3
97.6-98.4
97.6-98.4
97.6-98.4
89.6-96.4
89.6-96.4
89.6-96.4
89.6-96.4
80.9-94.
80.9-94.
80.9-94.
80.9-94.
Mass Emission
Rate, Ibs/hr
642.8
642.8
642.8
642.8
156.8
204.6
204.6
259.1
204.8
41.7
26.5
214.
1196.6
866. /577.
866. /577.
. 400.
23.77
23.96
509.6
509.6
430.
430.
434.
434.
150.
150.
430.
430.
112.8
112.8
358.
805.
805.
1170.
1170
131.2
131.2
1/U.2
131.2
143.8
Installed Cost,
$l,000's***
535.
535.
535.
535.
226.
218.
332.
259.
388.
890.
1,060.
610.
363.
43.0
43.0
43.0
43.0
-_-
16,720.
115.
115.
2,579.8
2,579.8
3,406.8
3,417.4
68.3
68.3
331.3
331 .3
2,754.1
2,738.6
379.3
379.3
565. 1
895.4
895.4
627.2
627.2
61.6
61 .6
61.6
61.6
322.
-------
TABLE 46. (Continued)
*CO.
Name
522
523
524
525
526
527
528
529
530
531
532
533
534
535
536
537
538
539
3 540
*• 541
542
543
544
545
546
547
548
549
550
551
552
553
554
555
556
557
558
559
560
561
562
563
564
565
Type Fly Ash
Collector**
E
E
E
E
E
E
E
C
E
E
E
E
C
C
C
C
E
E
C
C
E
C
E
E
E
E
E
E
E
C
C
C
C
C
C
C
E
E
E
E
E
E
E
E
ESP
Manufacturer
Research
Due 11
Buell
Buell
Research
Research
Western
Research
Buell
Buell
Western
Western
Western
Western
Western
Western
Research
Research
American
American
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
UOP
OOP
UOP
UOP
Western
Research
Western
Koppers
Research
Research
Buell
Cottrell
Cottrell/Buell
Cottrell
Cottrell
Cottrell
Cottrell
Standard/Western
S tandard/Wes tern
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
CottreJ 1.
Cottrell
Cottrell
Year ESP
Placed in
Service
1967
1966
1958
1954
1961/1966
1965
1969
1954
1970
1970
1971
1973
1949
1949
1949
1949
1951
1953
1959
1960
1947
1952
1964
1965
1959
1960
1962
1970
1971
1949
1950
1954
1956
1969
1966
1965
1965
1965
1968
1964
1968
1973
1964
1962
ESP Design
Efficiency, %
98.
98.
95.
98.
99.
98.
99.5
94.3
99.5
99.5
99.5
99.5
70.
70.
70.
70.
96.
96.
95.
95.
96.0
98.4
97.5
97.5
97.5
97.5
97.5
99.5
99.5
99.3
99.3
99.7
99.7
97.5
90.0
87.0
87.0
90.0
94.2
87.0
87.0
87.0
97.0
ESP Tested
Efficiency, %
99. -99. 4
99. -99. 4
95.6
96.1
94.9-96.6
94.9-96.6
90.9-95.9
90.9-95.9
90.9-95.9
98.84
98.84
87.6
87.6
98.1
98.1
93. 2-97.5
93.2-97.5
93.2-97.5
61.85
Mass Emission
Rate, Ibs/lir
185.9
298.8
747.4
385.
387.
2438.
811.
277.
118.
67.
2129.
388.
— -
442.
777.
J73.
179.
166.3
56.0
847.
847.
1759.
1759.
1759.
1096.
1096.
1096.
1096.
270.
778.
1200.
315.
1260.
1135.
900.
1615.
3457.
567.0
842.
Installed Cost,
$l,000's***
293.
434.
162.
300.
1,426.
1,052.
1,100.
1,035.
2,388.
2,337.
439.6
439.6
439.6
439.6
910.
910.
990.
990.
116.
177.
456.
451.
465.
466.
378.
695.
695.
215.
215.
250.
243.
416.5
244.6
425.6
237.12
349.73
720.01
340.53
744.01
7,000.
518.98
198.5
-------
TABLE 46. (Continued)
*Co.
Name
566
567
568
569
570
571
572
573
574
575
576
577
578
579
580
581
582
583
5 584
01 585
586
587
588
589
590
591
592
593
594
595
596
597
598
599
600
601
602
603
604
605
606
607
608
609
Type Fly Ash
Collector**
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
ESP
Manufacturer
Western
Western
Buell
Quell
Buell
Western
Western
Western
Western
Western
Western
Western
Research
Research
Research
Research
Research
Research
UOP
OOP
Western
Research
Research
Research
Research
Research
Research
Western
Western
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
American
American
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
CottreJl
Cottrell
Cottrell
Cottrell
Cottrell
Cottrel1
Cottrell
Cottrell
CoLtrell
Cottrel1
Cottroil
CottreJ1
Cottrell
Standard/PCW
Standard/PCW
Year ESP
Placed in
Service
1970
1972
1973
1973
1973
1969
1969
1968
1968
1972
1972
1972
1969
1968
1971
1970
1971
1969
1960
1968
1973
1974
1973
1969
1959
1949
1951
1953
1957
1974
1974
1972
1972
1970
1971
1970
1968
1968
1969
1970
1971
1974
1966/1975
1966/1975
ESP Design
Efficiency, %
99.
99.
98.6
98.6
98.6
99.
99.
99.
99.
98.
98.
98.
98.5
98.
98.5
98.5
98,5
98.5
90.0
92.4
99.5
99.8
99.8
99.
97.5
97.5
97.5
97.5
97.5
99.5
99.5
99.6
99.6
99.6
99.9
99.9
99.6
99.6
99.6
99.
99.
99.
98.
98.
ESP Tested
Efficiency, %
91.15-93.78
91.15-93.78
98.8
98.8
98.8
99.
99.
99.
99.
98. -98. 6
98. -98. 6
98. -98. 6
98.5
98.0
98.5
98.5
98.5
98.5
88.9
97.5
___
95.0
90.4-95.3
90.4-95.3
90.4-95.3
90.4-95.3
99.0-99.12
99.0-99.12
99.0-99.12
39.-50./
39.-50./
Mass Emission
Rate, Ibs/hr
7031.8
7229.8
64.94
64.94
64.94
172.
172.
172.
172.
42.82
42.82
42.82
147.
407.
121.
121.
121.
121.
537.
194.
47.0
___
_ —
27.5
405.
39.4
42.3
42.3
102.2
420.
420.
2055.
3263.
11801.
8.2
8.9
31.5
48.1
66.5
234.39
234.39
330.
170.
170.
Installed Cost,
$1,OOP's***
1,035,
1,000.
874.
874.
874.
1,493.
1,493.
1,493.
1,493.
1,354.
819.
1,133.
1,181.
1,133.
1,130.
259.
1,172.
4,185.
200.
300.
192.
358.8
142.5
169.7
182.4
217.9
13,000.
13,000.
494.8
476.8
360.15
388.69
447.91
736.60
620.62
1,298.
211.5/600.
211.5/600.
-------
TABLE 46. (Continued)
*Co.
Name
610
611
612
613
614
615
616
617
618
619
620
621
622
623
624
625
626
627
628
629
630
631
632
633
634
635
636
637
638
639
640
641
642
643
644
645
646
647
648
649
650
651
652
653
Type Fly Ash
Collector**
E
E
C
E
E
E
E
E
E
E
E
C
C
C
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
ESP
Manufacturer
Buell
Buell
Western
Western
Research Cottrell
Research Cottrell
Western
Western
Research Cottrell
Research Cottrell
American Standard
American Standard
American Standard
Western
Western
Research Cottrell
Research Cottrell
Research Cottrell
American Standard
Research Cottrell
American Standard/Research Cottrell
American Standard
Koppers
American
American
Research
Research
Research
Research
Standard
Standard
Cottrell
Cottrell
Cottrell
Cottrell
Year ESP
Placed in
Service
1969
1970
1973
1974
1973
1970
1971
1960
1960
1974
1973
1974
1974
1974
1970
1973
1957
1958
1960
1963
1965
1 1967/1974
1972
1971
1972
1966
1971
1972
1972
1972
1962
1972
1973
1969
1970
1970
1969
1973
1973
1974
1974
1974
1974
1974
ESP Design
Efficiency, %
95.
95.
97.6
99.28
99.0
98.6
98.6
95.
95.
99.
99.
96.
96.
96.
99.0
99.78
90.
90.
93.
95.5
98.5
98.5/99.78
99.0
99.0
99.0
99.0
97.0
97.0
97.0
97.0
90.0
99.0
99.0
95.
95.
95.
95.
98.5
98.5
98.5
98.5
98.5
98.5
98.5
ESP Tested
Efficiency, %
92.1-94.5
92.1-94.5
99.0
99. -99. 8
99. -99. 8
99.6
99.6
98.4
97.2 *
97.5
97.5
97.5
81.00
__ _
_ — •
80.00
99.06-99.1
99.06-99.1
99.2-99.3
99.2-99.3
Mass Emission
Rate, Ibs/hr
662.
662.
50.1
101.6
300.1
600.
600.
800.
800.
714.
714.
9.5
13.0
10.6
504.
219.
354.
354.
220.2
174.7
291.
484. /183.
216.9
216.9
216.9
616.
155.3
155.1
J55.3
155.3
4804.
805.4
805.4
150.
150.
295.
295.
157.7
157.7
157.7
157.7
180.
180.
180.
Installed Cost,
$l,000's***
177.
177.
733.
1,611.
1,535.
2,317.
2,317.
___
720.34
720.34
720.34
540.
250.
216.
325.
249.
J94.
567. n, 113.
3,261.
3,261.
3,261.
1,606.
1,982.5
1,982.5
1,982.5
1,982.5
625.
3,887.5
3,887.5
1,323.8
1,323.8
1,323.8
1,323.8
3,269.4
3,269.4
3,269.4
3,269.4
1,327.3
1,327.3
1,327.3
-------
TABLE 46. (Continued)
*Co.
Name
654
655
656
657
658
659
660
661
662
663
664
665
666
667
668
669
670
671
3 672
-J 673
674
675
676
677
678
679
680
681
682
683
684
685
686
687
688
689
690
691
692
693
694
695
696
697
Type Ply Ash
Collector**
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
. E
E
E
E
E
E
E
E
E
C
C
C
C
C
E
E
C
C
E
E
E
ESP
Manufacturer -
Research
Research
Research
Research
Research
Research
Research
Research
Research•
American
American
American
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
Research
Western
Hoppers
Western
Western
Western
Research
Research
Researcli
UOP
OOP
Western
Western
Research
Research
Research
Research
Research
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Standard
Standard
Standard
Cottrel1
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrel1
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
Cottrell
CottrelI
Cottreli
Cottrell
Cottrell
Cottrell
Cottrell
Year ESP
Placed in
Service
1974
1960
1960
1960
1960
1959
1960
1960
1960
1960
1967
1967
1969
1970
1969
1969
1969
1970
1969
1970
1970
1969
1969
1969
1969
1969
1969
1960
1964
1970
1971
1970
1951
1950
3950
1955
1959
1963
1968
3969
1959
1970
1971
1972
ESP Design
Efficiency, %
98.5
95.
95.
95.
95.
95.
95.
95.
95.
95.
98.
98.
98.
90.
90.
90.
90.
90.
90.
90.
90.
90.
90.
95.00
95.00
95.00
95.00
95.00
90.0
99.5
99.5
99.5
98.7
97.4
97.4
98.5
98.8
98.5
99.5
93.8
95.0
99.5
99.5
99.5
ESP Tested
Efficiency, %
— _
_ —
___
_ —
— _
95.00
95.00
95.00
95.00
50.00
99.00
97.4-98.7
97.4-98.7
97.4-98.7
97.4-98.7
97.4-98.7
97.4-98.7
95.1
91.0
96.
96.
96.
Mass Emission
Rate, Ibs/hr
180.
84.6
84.6
84.6
84.6
112.
112.
112.
112.
112.
672.
672.
829.
170.
170.
170.
170.
170.
170.
370.
170.
170.
170.
117.
117.
117.
117.
4017.
5119.
12.
18.
18.
151.
248.
248.
156.
161.
101 .
101.
1250.
1700.
161.6
161.6
161.6
Installed Cost,
$l,000's***
1,327.3
155.2
155.2
155.2
155.2
217.6
217.6
217.6
217.6
217.6
1,441.8
1,428.2
2,901.3
710.6
710.6
710.6
710.6
710.6
710.6
710.6
710.6
710.6
710.6
460.
460.
460.
460.
1,809.
648.
457.
64).
421 .
310.
245.
245.
578.
642.
419.
688.
1,325.
353.
2,169.
2,669.
2,900.
-------
TABLE 46. (Continued)
*Co.
Name
698
699
700
701
702
703
704
705
706
707
708
709
710
711
712
713
714
715
* 716
» 717
" 718
719
720
721
722
723
724
725
726
727
728
729
730
731
732
733
734
735
736
737
738
739
740
741
Type Fly Ash
Collector**
E
E
E
E
E
E
E
E
E
E
E
E
E .
E
C
C
C
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
ESP
Manufacturer
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Buell
Buell
Buell
Buell
Buell
Western
Western
Western
Buell
lodge Cottrell
Buell
Western
Western
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrel1
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Year ESP
Placed in
Service
1973
1953
1954
1959
1961
1973
1973
1950
1950
1972
1972
1972
1972
1974
1952
1955
1950
1974
1974
1971
1973
1973
1973
1973
1973
1949
1952
1957
1970
1970
1967
1967
1967
1968
1967
1965
1966
1968
1968
1969
1969
1951
1951
1973
ESP Design
Efficiency, %
99.5
97.5
97.5
98.0
97.5
99.6
99.6
95.
95.
95.
95.
95.
95.
99.6
97.0
97.0
97.0
99.5
97.0
96.0
99.38
99.38
99.83
99.83
99.2
95.0
95.0
97.5
99.5
99.5
99.0
99.0
99.2
99.2
99.2
99.2
99.2
99.0
99.0
99.0
99.0
90.0
90.0
99.5
ESP Tested
Efficiency, %
96.
97.4
88.5-90.5
88.5-90.5
97.0
99.7-99.75
99.7-99.75
85.00
98.73
98.73
98.4
98.4
98.43-99.36
98.43-99.36
98.43-99.36
98.43-99.36
Mass Emission
Rate, Ibs/hr
161.6
200.
200.
233.
465.
52.
52.
502.
502.
27.
46.
47.
47.
72.
— _
446.
226.9
74.2
158.
47.6
79.0
110.5
110.5
660.0
9.88
9.88
19.76
72.
72.
72.
72.
42,
42.
42.
42.
42.
47.
47.
47.
47.
150.
. 150.
9.3
Installed Cost,
$1,OOP's***
4,538.
425.
470.
981.
1,097.
2,973.
2,912.
263.
263.
666.
1,038.
1,026.
1,017.
1,045.
298.6
382.2
148.399
5,000.
7,000.
814.
1,595.
2,193.
9,748.
9,374.
4,608.
184.
140.
310.
1,575.
583,
600.
534.
486.
513.
474.
510.
643.
586.
126.
126.
2,000.
-------
TABLE 46. (Continued)
*Co.
Name
742
743
744
745
746
747
748
749
750
751
752
753
754
Type Ply Ash
Collector**
E
E
E
E
E
E
E
E
E
£
E
E
E
ESP
Manufacturer
Buell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrell
Research Cottrel1
Research Cottrell
Western
Western
Western
Western
Year ESP
Placed in
Service
1969
1974
1974
1971
1972
1973
1974
1974
1951
1958
1974
1972
1972
ESP Design
Efficiency, %
99.0
99.5
99.5
99.5
99.5
98.0
98.0
97.0
90.0
92.0
97.0
99.0
99.0
ESP Tested
Efficiency, %
— _
— __
88.3
___
99.7-99.8
99.7-99.8
Mass Emission
Rate, Ibs/hr
118.
114.0
114.0
8.6
8.6
76.1
37.9
205.7
258.6
98.5
220.1
10.8
9.9
Installed Cost,
$l,000's***
854.
2,400.
2,400.
1,350.
1,350.
713.
760.
970.
237.
296.
1,632.2
1,857.
1,220.
-------
APPENDIX B
CASCADE IMPACTOR STAGE PARAMETERS —
ANDERSEN MARK III STACK SAMPLER, MODIFIED
BRINK MODEL B, MRI MODEL 1502, SIERRA
MODEL 226, AND UNIVERSITY OF WASHINGTON
MARK III
680
-------
TABLE 47.
CASCADE IMPACTOR STAGE PARAMETERS
ANDERSEN MARK III STACK SAMPLER
Stage
NC-..
CD
H
1
2
3
4
5
6
7
8
No. of
Jets
264
264
264
264
264
264
264
156
D.-Jet
Diameter
(cm)
.1636-
.1253
.0948
.0759
.0567
.0359
.0261
.0251
S-Jet
to Plate
Distance
(cm)
.254
.254
.254
.254
.254
.254
.254
.254
S
°3
1
2
2
3
4
7
9
10
.55
.03
.68
.35
.48
.08
.73
.12
Reynolds
Number
45
59
78
98
131
206
284
500
Jet
Velocity
(ra/sec)
0
0
1
2
1
9
17
31
.4
.8
.3
.0
.6
.0
.1
.5
Cumulative Frac-
tion of Impac-
tor Pressure Drop
at each stage
0
0
0
0
0
0
0
1
.0
.0
,0
.0
.0
.2
.3
.0
-------
TABLE 47. (Continued)
CASCADE IMPACTOR STAGE PARAMETERS
MODIFIED BRINK MODEL B CASCADE IMPACTOR
00
N)
Stage
No.
0
1
2
3
4
5
6
No. of
Jets
1
1
1
1
1
1
1
D.-Jet
Diameter
(cm)
.3598
.2439
.1755
.1375
.0930
.0726
.0573
S-Jet
to Plate
Distance
(cm)
1.016
0.749
0.544
0.424
0,277
0.213
0.191
S
D.
3
2.82
3.07
3.10
3.08
2.98
2.93
3.33
Reynolds
Number
326
481
669
853
1263
1617
2049
Jet
Velocity
(m/sec)
1.4
3.0
6.0
9.7
21.2
35.3
58.8
Cumulative Frac-
tion of Impac-
tor Pressure Drop
at each stage
0.0
0.0
0.0
0.0
0.065
0.255
1.000
-------
TABLE 47. (Continued)
CASCADE IMPACTOR STAGE PARAMETERS
MRI MODEL 1502 INERTIAL CASCADE IMPACTORS
Stage
No.
cr. .'. .
u>
1
2
3
''• *
5
6
7
No. Of
Jets
8
12
24
24
24
24
12
D.-Jet
Diameter
(cm)
0.870
0.476
0.205
0.118
0.084
0.052
0.052
S-Jet
to Plate
Distance
(cm)
0.767
0.419
0.191
0.191
0.191
0.191
0.191
S_
D.
D
.88
.88
.96
1.61
2.27
3.60
3.60
Reynolds
Number
281
341
411
684
973
1530
3059
Jet
Velocity
(m/sec)
0.5
1.1
3.2
8.9
18.2
45.9
102.3
Cumulative Frac-
tion of Impac-
tor Pressure Drop
at each stage
0.0
0.0
0.0
0.0
0.045
0.216
1.000
-------
00
TABLE 47. (Continued)
CASCADE IMPACTOR STAGE PARAMETERS
SIERRA MODEL 226 SOURCE SAMPLER
Stage
No.
1
2
3
4
5
6
W-Jet
Slit
Width
(cm)
0.3590
0.1988
0.1147
0.0627
0,0358
0.0288
Jet
Slit
Length
(cm)
5.156
5,152
3.882
3.844
3.869
2.301
S-Jet
to Plate
Distance
(cm)
0.635
0.318
0.239
0.239
0.239
0.239
Reynolds
S Number
W (§14.16 1pm)
1.77
1.60
2.08
3.81
6.68
8.30
602
602
800
808
802
1348
Jet Cumulative Frac-
Velocity tion of Impac-
(m/sec) tor Pressure Drop
(014.16 1pm) at each Stage
1.3
2.3
5.4
10.0
17.4
36.9
0.0
0.0
o.o
0.154
0.308
1.000
-------
TABLE 47. (Continued)
CASCADE IMPACTOR STAGE PARAMETERS
UNIVERSITY OF WASHINGTON MARK III SOURCE TEST CASCADE IMPACTOR
Stage
en No.
00
in
1
2
3
4
5
6
7
No. of
Jets
1
6
12
90
110
110
90
D.-Jet
Diameter
(cm)
1.842
0.577
0.250
0.0808
0.0524
0.0333
0.0245
S-Jet
to Plate
Distance
(cm)
1.422
0.648
0.318
0.318
0.318
0.318
0.318
S
°j
.78
1.12
1.27
3.94
6.07
9.55
12.98
Reynolds
Number
1073
565
653
269
340
535
929
Cumulative Frac-
Jet tion of Impac-
Velocity tor Pressure Drop
(m/sec) at each Stage
0.9
1.5
4.1
5.2
10.2
25.4
60.0
0.0
0.0
0.0
0.019
0.057
0.189
1.000
-------
APPENDIX C
PARTICULATE MATTER, SULFUR OXIDE, AND
NITROGEN OXIDE EMISSION LIMITS FOR COAL-
FIRED POWER BOILERS IN THE UNITED STATES.
REGULATIONS APPLICABLE TO VISIBLE EMISSION
ALLOWED FOR FUEL-FIRED BOILERS.
686
-------
TABLE 48. PARTICIPATE MATTER, SULFUR OXIDE, AND NITROGEN OXIDE EMISSION
LIMITS FOR COAL-FIRED POWER BOILERS IN THE UNITED STATES1'2
a\
oo
State
Alabama
Alaska
Ari zona
Arkansas
California
Colorado
Connecticut
Particulate Matter
Sulfur Oxides
0.12 lb/10* Btu for existing sources
with input > 250 x 10* Btu/hr
0.10 Jb/10* Btu for new sources
with input > 250 x 10' Btu/hr
0.05 grains/set except 0.10 grains/
scf prior to 7/1/72
Nitrogen Oxides
Emission Rate = 17.0Q0'"
input > 4200x10' Btu/hr
Emission Rate = 1.02Q0-'
input < 4200x10' Btu/hr
for
for
Emission Rate = 17.31P0'1' for input
> 60,000 Ibs/hr after July, 1973
where P = process weight, tons/hr
Category I Counties/1.8 Ib SO2/106 0.7 Ib NOx/10' Btu
Btu heat input-existing, J.2 Ib-new for new >_ 250 x 10* Btu/hr
Category II Counties/4.0 Ib SOZ/10*
Btu heat input-existing, 1.2 Ib-new
500 ppm as SO2
0.80 Ib S02/106 Btu heat input -
new
1.0 Ib S0i,/106 Btu heat input -
existing
0.2 ppm SOz for any 30 min. avg.
beyond source premises
No standards
0.7 Ib NOx/10* Btu heat input
for new sources (maximum 2 hour
average)
No standards
Each county has own regulations. See Table 4a for summary from counties responding to SoRI survey.
500 ppm 0.7 Ib NOx/106 Btu heat input
0.10 lb/10' Btu for units with input
>_ 500 x 106 Btu/hr
0.10 lb/106 Btu heat input - new
0.20 lb/10' Btu heat input - existing
Fuels restricted to maximum S
Content of 0.5% by weight
0.7 Ib NOx/10' Btu - new
above 250 x 10' Btu/hr input
0.9 Ib NOx/106 Btu - existing
above 250 x 106 Btu/hr input
'The Electrostatic Precipitator Manual by the Mcllvaine Co., Chapter XIII, Section 4.1, pp. 53.1-54.0, August, 1977.
2Survey of all state air pollution agencies by Southern Research Institute in 1978.
-------
TABLE 48. (Continued)
State
Delaware
Florida
Georgia
Hawaii
Particulate Matter
ON
oo Idaho
Illinois
Indiana
Iowa
0.10 lb/106 Btu heat input for new
sources > 250 x 106 Btu/hr
0.1 lb/106 Btu for new sources >
250 x 106 Btu/hr (maximum 2 hour
average)
0.1 lb/10* Btu for new sources >
250 x 10s Btu/hr
No standards
0.10 lb/106 Btu for new sources >
250 x 10* Btu/hr
0.12 lb/106 Btu for existing (before
12/5/74) sources > 10,000 x 106 Btu/hr
0.10 lb/106 Btu for new and existing
sources > 250 x 106 Btu/hr in any
one hour
0.10 lb/10' Btu for new sources >
250 x 106 Btu/hr
0.6 lb/106 Btu for new sources <
250 x 10* Btu/hr
0.6 lb/106 Btu for new sources
0.8 lb/106 Btu for existing outside
SMS A*
0.6 lb/10* Btu for existing inside
SMSA*
Sulfur Oxides
Fuel restricted to 1% S by weight
.8 Ib SOj/106 Btu for sources >
250 x 106 Btu/hr
1.2 lb/106 Btu for new sources > -
250 x 106 Btu/hr (maximum 2 hour
average)
1.5 lb/106 Btu for existing > 250
x 106 Btu/hr
1.2 lb/106 Btu for new sources >
250 x 10s Btu/hr (maximum 2 hour
average)
No standards for coal
Coal limited to 1% sulfur by
weight - existing
1.2 lb/106 Btu for new sources >
250 x 106 Btu/hr
1.8 Ib SOj/106 Btu in any one hour
for major metro areas - existing
1.2 Ib SOz/106 Btu new sources >
250 x 106 Btu/hr
1.2 Ib S02/106 Btu for new sources
> 250 x 10s Btu/hr
1.2 Ib SO2/106 Btu for new sources
> 250 x 106 Btu/hr
Nitrogen Oxides
0.7 Ib NOx/106 Btu for new sources
> 250 x 106 Btu/hr
0.7 Ib NOx/106 Btu heat input
(maximum 2 hour average)
0.7 Ib NOx/106 Btu heat input for
sources > 250 x 106 Btu/hr
No standards
0.7 lb/106 Btu for new sources >
250 x 106 Btu/hr
0.7 lb/106 Btu new sources > 250
x 106 Btu/hr (maximum 1 hour period)
0.7 lb/106 Btu new sources > 250
x 10" Btu/hr
No standards
•Standard metropolitan statistical area.
-------
State
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Particulate Matter
0.12 lb/hr/10* Btu for input ?_ 10,000
X 10* Btu/hr
0.10 lb/10* Btu for input > 250 x 10s
Btu/hr
0.6 lb/10* Btu heat input for new
and existing not subject to Federal
Regulations
0.1 lb/10* Btu for input > 250 x 10*
Btu/hr
0.03 grains/scf for input > 250 x 106
Btu/hr (new and existing sources)
0.05 lb/10* Btu for new sources >
250 x 10s Btu/hr
0.15 lb/10* Btu for existing
For pulverized coal equipment rated
larger than 10* Ib steam/hr or other
modes of firing coal rated larger
than 3 x 10s Ib steam/hr, one must
apply to commission for specific limits
0.1 lb/106 Btu for new sources > 250
x 10* Btu/hr for most of the state
0.19 lb/10* Btu for input > 10,000 x
10* Btu/hr
0.18 lb/10* Btu for sources > 10,000
x 10* Btu/hr
TABLE 48. (Continued)
Sulfur Oxides
1.5 lb/10* Btu/hr for input >_ 250
x 10* Btu/hr
1.2 lb/10* Btu/hr for input of
250 x 10* Btu/hr
2000 ppm by volume
0.8 lb/10' Btu for input > 250 x
10* Btu/hr
Fuel limited to 1% sulfur in Areas
I, III, IV
3.5 lb/10' Btu for input of 100 x
10* Btu/hr for Areas II, V, VI
0.28 Ib SOx/10* Btu in some areas,
0.55 Ib sulfur/10* Btu in others
1% sulfur coal as of 7/1/78
1.2 Ib SOx/106 Btu for new sources
> 250 x 106 Btu/hr for most of
state
4.8 Ib SOx/106 Btu heat input for
sources > 250 x JO6 Btu/hr
1000 Ib S02/hr
Nitrogen Oxides
0.90 lb/10* Btu/hr for input >_ 250
x 10' Btu/hr
0.7 lb/10' Btu/hr for input >_ 250
x 10* Btu/hr
No standards
No standards
0.5 lb/10* Btu (maximum 2 hour
average) for new sources > 250 x
10* Btu/hr
0.3 Ib NOx/10* Btu for new sources
> 250 x 10* Btu/hr
No standards
0.7 Ib NOx/10* Btu for new sources
> 250 x 10* Btu/hr
No standards
No standards
-------
TABLE 48. (Continued)
State
Montana
Nebraska
Nevada
Particulate Matter
0.1 lb/106 Btu for new sources
(maximum 2 hour average)
0.1 lb/106 Btu for new sources
(maximum 2 hour average)
0.1 lb/106 Btu for new sources >
250 x 10s Btu/hr
Sulfur Oxides
New Hampshire 0.10 lb/106 Btu for new sources >
250 x 10s Btu/hr and 0.19 for
existing sources > 10,000 x 10s
Btu/hr
New Jersey 1000 Ib/hr for source of 10,000 x
106 Btu/hr
New Mexico 0.05 lb/10s Btu for new sources >
250 x 106 Btu/hr
Fine particulate emissions (<2
microns) cannot exceed 0.02 lb/
10" Btu
New York 0.1 lb/10s Btu for new sources
(maximum 2 hour average)
North Carolina 0.10 lb/10* Btu for sources >
10,000 x 10s Btu/hr
North Dakota 0.8 lb/10* Bta for existing
0.1 lb/10s Btu for new sources >
250 x 10* Btu/hr
Ohio
0.1 lb/10 s Btu for new and existing
> 1,000 x 10* Btu/hr in Priority 1
regions, .15 lb/106 Btu in Priority
2 and 3 regions
1.2 lb SO2/106 Btu
(maximum 2 hour average)
1.2 lb SO2/106 Btu
(maximum 2 hour average)
0.6 lb sulfur/106 Btu for new
sources > 250 x 106 Btu/hr
1.5 lb sulfur/106 Btu for new
2.8 lb sulfur/106 Btu for existing
0.2% by weight of sulfur in coal
with several exceptions
0.34 lb S02/106 Btu for new and
1.0 lb SOz/106 Btu for existing
> 250 x 106 Btu/hr input
0.60 lb sulfur/106 Btu for new
sources > 250 x 106 Btu/hr for
most areas
1.6 lb SOj/106 Btu for new sources
2.3 lb SO,/10s Btu for existing
1.2 lb SOi/lO6 Btu for new sources
> 250 x 10s Btu/hr
1.0 lb SOz/106 Btu, new and
existing
Nitrogen Oxides
0.7 Ib NOx/106 Btu
0.7 lb NOx/106 Btu
0.7 lb NOx/106 Btu for new sources
> 250 x 106 Btu/hr
Ho standards
Ho standards
0.45 lb HOj/106 Btu for new sources
> 250 x ID8 Btu/hr and 0.7 lb NO*/
10s Btu for existing
0.7 lb NOx/106 Btu for new sources
> 250 x 106 Btu/hr
1.3 lb NOj/JO6 Btu for sources
>_ 250 x JO6 Btu/hr
No standards
0.9 lb NOx/106 Btu for new sources
> 250 x 106 Btu/hr
-------
State
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
Soutli Dakota
Tennessee
Texas
Utah
Participate Ma.tter
0.1 lb/106 Btu for new and existing
> 1,000 x 10s Btu/hr
0.1 lb/10* Btu for new sources
0.2 lb/10' Btu for existing
0.1 lb/10* Btu for new sources
>_ 600 x 10* Btu/hr
0.10 lb/10s Btu for sources >
250 x 106 Btu/hr
For sources - 1.300 x 106 Btu/hr •
E = 57.84P-"-63', where E = emission
rate, P = 106 Btu heat input/hr
0.1 lb/106 Btu,for new sources >
250 x 106 Btu/hr
0.1 lb/106 Btu for existing sources
i 10,000 x 10s Btu/hr
0.1 lb/108 Btu for new sources >.
250 x 10' Btu/hr
0.1 lb/106 Btu for new sources >
250 x 106 Btu/hr
0.3 lb/106 Btu for existing sources
0.1 lb/106 Btu for new sources >
250 x 10s Btu/hr
85% control and 40% opacity for
existing
TABLE 48. (Continued)
Sulfur Oxides
1.2 Ib SOx/106 Btu, new
1% by weight sulfur limit
in fuel
1.8 Ib SO2/10£ Btu for sources
i. 2,000 x 106 Btu/hr (for most
areas)
0.55 Ib sulfur/106 Btu in fuel
or emissions of 1.1 Ib SOx/10*
Btu
Most counties are 3.5 Ib SOz/
106 Btu
1.2 Ib SO2/106 Btu for sources
> 250 x 106 Btu/hr
1.2 Ib SOz/106 Btu for new
sources > 250 x 10'
3.0 lb/106 Btu for existing
1.2 Ib SO2/106 Btu for new
1.2 Ib SO2/106 Btu for new
1% sulfur coal by weight
Nitrogen Oxides
0.7 Ib NOx/106 Btu for new sources
>_ 50 x 10* Btu/hr
No standards
0.7 Ib NOx/10s Btu
No standards
No standards
0.7 Ib NOx/106 Btu
0.7 Ib NOx/106 Btu for new sources
> 250 x 10s Btu/hr
0.7 Ib NOx/106 Btu for opposed-
fired units, 0.5 for front-fired,
0.25 for tangentially-fired
0.7 Ib NOx/106 Btu for new sources
> 250 x 106 Btu/hr
-------
State
Vermont
Virginia
Washington
Particulate Matter
TABLE 48. (Continued)
Sulfur Oxides
0.1 lb/106 Btu for new and existing
sources ^> 250 x 10s Btu/hr
0.1 lb/106 Btu for new sources >
250 x 10s Btu/hr
0.1 lb/10s Btu for existing sources
> 10,000 x 10s Btu/hr
0.1 grains/scf for new and existing
sources
West Virginia .05 lb/10* Btu
Wisconsin
Wyoming
0.10 lb/10* Btu for new sources
> 250 x 10* Btu/hr
0.10 lb/10s Btu for all sizes of
new units
1.2 Ib SOj/106 ntu for new sources
> 250 x 10s Btu/hr
1.2 Ib SOz/lO* Btu for new sources
> 250 x 106 Btu/hr
1000 ppm SOi for new and existing
sources
Nitrogen Oxides
0.3 Ib NOx/106 Btu for new sources
> 250 x 10s Btu/hr
Mo standards
No standards
2.0 Ib SOz/106 Btu/hr as of 6/30/78 No standards
1.2 Ib SOz/106 Btu for new sources
> 250 x 10s Btu/hr
0.2 Ib SOj/106 Btu for new sources
> 250 x 106 Btu/hr
0.7 Ib NOx/105 Btu for new sources
> 250 x 10s Btu/hr
0.7 Ib NOx/106 Btu for new sources
> 250 x 10s Btu/hr •
-------
TABLE 48a. COUNTIES OP CALIFORNIA - EMISSION
REGULATIONS FOR POWER PLANTS*
Santa Barbara
Merced
Tehama
u Placet
Parttculate Hatter
0.2 grains/ft' for 1,000
cfm source '
0.0635 grains/ft1 for
20,000 eta source
0.0122 grains/ft* for
1,500,000 Of* source
0.1 grains/scf
0.3 grains/ft1
0.3 grains/scf for existing
0.1 grains/scf for new and
10 Ibs/hr of combustion
contaminants
Opacity
Sulfur Oxides
Nitrogen Oxides
North Coast Air Basin -
Del Norte \
Humboldt I
Trinity >
Mendocino I
Sonoma /
Plumas
.23 grains/SCM
(.10 grains/scf)
20%
20%
40% (no more than 3
minutes in any hour)
20% (no more than 3
minutes in any hour)
for new sources •
40% for existing
40% opacity (no more
than 3 minutes in any
one hour except 20% in
Mendocino County
40% for existing, 20%
for new sources
0.2% by volume SO»
0.2% by volume and 200
Ibs/hr of sulfur com-
pounds
225 ppm for source input
> 1,775 x 10* Btu/hr
140 Ibs/hr of nitrogen
oxides -
*Regulations were obtained from most of the Air Pollution Control District in California and summarized in this table as an
indication of the emission limits experienced across the state. Each district has its own regulations. This survey was
conducted in 1978.
-------
Fresno
Kings
Monterey
Hadera
Ventura
South Coast -
San Bernadino
Cone
Glenn
Shasta
Tulare
Particulate Matter
0.10 grains/scf (0.23
grains/SCM)
10 Ibs/hr of combustion
contaminants
0.1 grains/scf
0.10 lb/10* Btu for new
sources > 250 x 10* Btu/
hr
0.1 grains/scf and 10
Ibs/hr of combustion
contaminants
O.I grains/scf
combustion contaminants
which exceed both 11 Ibs/
hr (5 kg/hr) and 0.01
gfains/scf
(23 mg/m') for new sources
> 50 x 10* Btu/hr
0.$ grains/scf
0.10 grains/scf for new
sources (.05 gr/scf for
particulate matter < 10
microns)
0.1 grains/scf
TABLE 48a. (Continued)
Opacity Sulfur Oxides •
20%
20%
0.2% by volume SO:
and 200 Ibs/hr of sulfur
compounds
20% except 40% allowed 1.2 lb/10* Btu
for 2 minutes in any
one hour
20% except 40% for no 1.2 lb/10* Btu
more than 2 minutes in
any one hour
20%
20%
40%
0.5% sulfur by weight
0.2% by volume (2.000 ppm)
1,000 ppm for new sources
Nitrogen Oxides
140 Ibs/hr of nitrogen
oxides
0.70 lb/10* Btu
0.70 lb/10* Btu
225 ppm NOx
20%
-------
El Dorado
Butte
Sacramento
Imperial
Siskiyou
San Diego
Lake
Yolo-Solano
Kern
Particulate Matter
0.3 grains/scf and 10 Ibs/
hr of combustion contaminants
0,10 grains/scf and 10 Ibs/
hr of combustion contaminants
6.30 grains/scf
0.30 grains/scf (expected to
be changed to 0.10 grains/
scf for new sources)
0.3 grains/scf existing
0.2 grains/scf new (after
July 1, 1972)
0.3 grains/scf ;
0.1 lbs/10' Btu for sources
> 250 x 10' Btu/hr (after
August 17, 1971)
TABLE 48a. (Continued)
Opacity Sulfur Oxides
40%
40%
40% (expected to be
changed to 20% for new
sources)
40% existing
20% new (after July 1,
1972)
40%
20% except 40% for no
more than 2 minutes in
any hour
No fuel-fired power boilers or associated regulations.
0.3 grains/scf and 40 Ibs/
hr of combustion parti-
culates - existing
existing - 0.1 grains/scf.
Valley Basin
existing - 0.2 grains/scf,
Desert Basin
new - 0.1 grains/scf (3/19/74)
40% - existing
20% for more than 3
minutes in any one
hour
0.21 sulfur compounds and
200 Ibs/hr sulfur compounds
200 Ibs/hr sulfur compounds
0.2% by volume (expected to
be changed to 0.5% sulfur
in fuels)
Nitrogen Oxides
1.2 lb/106 Btu
0.2% SO2 and 200 Ibs/hr
of sulfur compounds -
existing
0.2% SO2 by volume
140 Ibs/hr nitrogen oxides
140 Ibs/hr nitrogen oxides
0.70 lb/106 Btu
140 Ibs/hr of nitrogen
oxides - existing
140 Ibs/hr NOx, Valley
Basin
0.7 lb/106 Btu, Desert
Basin (after 8/17/71)
-------
San Joaquin
Bay Area -
Alameda
Contra Costa
Harin
Napa
San Francisco
San Mateo
Santa Clara
Solano
Sonoma
250 x
10s Btu/hr
0.10 grains/scf and 10 Ibs
of combustion contaminants
TABLE 48a. (Continued)
Opacity Sulfur Oxides
20% except 40% for 2
minutes in any one
hour
20% except 40% for
not more than 2
minutes in any one
hour
20% for more than 3
minutes in any one
hour
0.2% SOz by volume -
existing
1.2 lbs/106 Btu - new
1.2 lbs/10s Btu for
new sources
200 Ibs of sulfur com-
pounds (calculated as
SOt)
Nitrogen Oxides
225 ppm - existing
0.7 lb/106 Btu - new
0.70 lb/10s Btu for
new sources
140 Ibs of nili~gcn
oxides (calculated as
NOZ)
-------
TABLE 49.
REGULATIONS APPLICABLE TO VISIBLE EMISSION ALLOWED FOR FUEL-FIRED BOILERS
Existing Sources - Limits
1. Alabama
2. Alaska
3. Arkansas
4. Arizona
5. California
6. Colorado
7. Connecticut
8. Delaware
9. Florida
10. Georgia
20% opacity or No. 1 on the Rlngelmann chart except 60% or
No. 3 on the Ringelmann chart for not more than 3 minutes in
any 60 minutes.
may not exceed 20% opacity for a period or periods aggregating
more than 3 minutes in any hour.
may not be equal to or exceed 40% except for not more than five
minutes in a 60 minute period (3 times in 24 hour maximum).
may not exceed No. 2 Ringelmann (equivalent to 40% opacity).
each county has its own regulations.
may not exceed 20% except 40% for no more than 3 minutes in any
one hour.
may not exceed 20% except 40% for a period aggregating not more
than 5 minutes in any 60 minutes.
may not exceed either No. 1 on the Ringelinujin chart or 20%
opacity for more than 3 minutes in any one hour or more than
15 minutes in any 24 hour period.
may not exceed No. 1 of the Ringelmann chart (20% opacity) except
No. 2 of the Ringelmann chart (40%) shall be permissible for not
more than 2 minutes in any hour.
may not have emissions equal to or greater than Ringelmann chart
(20% opacity) except for emissions up to Ringelmann No. 2 for
-------
Existing Sources - Limits (continued)
VD
oo
(Georgia,
cont'd.)
11. Hawaii
12. Idaho
13. Illinois
14. Indiana
15. Iowa
16. Kansas
17. Kentucky
18. Louisiana
19, Maine
20. Maryland
two minutes in any one hour. This is for fuel burning equipment
constructed after January 1, 1972. Opacity requirements for
equipment constructed prior to January 1, 1972, is 40%.
may not exceed 40%.
may not exceed No. 2 on the Ringelmann chart (40% opacity).
The new source standard for Idaho does not allow the emission's
aggregating more than 3 minutes in any one hour which is greater
than 20% opacity.
may not exceed 30% opacity except may have opacity greater than
30% but not greater than 60% for a period or periods aggregating
8 minutes in any 60 minute period (limit to 3 times in any
24 hours).
may not exceed 40% opacity for more than a cumulative total of
15 minutes in a 24 hour period.
may not exceed 40% opacity except for a period or periods aggregat-
ing not more than 6 minutes in any 60 minute period.
may not be equal to or greater than 40% opacity.
may not be equal to or greater than 40% opacity except for 60%
for 6 minutes in any 60 minute period.
may not exceed 20% opacity.
may not exceed 40% opacity except for periods of not exceeding
5 minutes in any one hour or 15 minutes in any continuous 3
hour period.
may not exceed 20% opacity except for 40% for a period or periods
aggregating no more than 4 minutes in any sixty minutes.
21. Massachusetts emissions may not be equal to or greater than 20% except 40% for
a period or aggregate period of time in excess of 6 minutes
during any one hour.
-------
Existing Sources - Limits (continued)
10
22. Michigan
23. Minnesota
24. Mississippi
25. Missouri
26. Montana
27. Nebraska
28. Nevada
may not exceed 20% except 40% for not more than 3 minutes in any
60 minute period for no more than 3 occasions during any 24
hour period.
may not exceed 20% except 60% for 4 minutes in any 60 minute
period and 40% for 4 additional minutes in any 60 minute period.
may not exceed 40% except 60% for no more than 10 minutes per
billion Btu gross heating value of fuel in any one hour per
24 hours.
may not be equal to or greater than 40% except 60% for a period
or periods aggregating not more than 6 minutes in any 60 minutes.
Kansas City's opacity limit is 20% except 60% for 6 minutes in
any 60 minutes.
for equipment built before 1969, may not exceed 40%; after 1969,
may not exceed 20%. Exception - 60% for 4 minutes in any 60
minutes.
may not be equal to or exceed 20%.
may not be equal to or exceed 20% for a period or periods aggregat-
ing more than 3 minutes in any one hour.
29. New Hampshire may not exceed 40%.
30. New Jersey
31. New Mexico
32. New York
may not exceed 20% except for smoke which is visible for a period
of not longer than 3 minutes in any consecutive 30 minute period.
may not exceed 20%.
may not exceed 20% except for 3 minutes during any continuous
60 minute period.
33. North Carolina may not exceed 40% for an aggregate of more than 5 minutes in
any one hour or more than 20 minutes in any 24 hour period.
-------
Existing Sources - Limits (continued)
34. North Dakota maximum allowable is 40%.
35. Ohio may not exceed 20% except 60% for no more than 3 minutes in
any 60 minutes.
36. Oklahoma may nob exceed 20% except 60% for no more than 5 minutes in any
60 minutes or more than 20 minutes in any 24 hour period.
37. Oregon may not be equal to or greater than 40% for a period aggregating
more than 3 minutes in any one hour except more stringent for
special control areas.
38. Pennsylvania may not be equal to or greater than 20% for more than 3 minutes
in any one hour or equal to or greater than 60% at any time.
39. Puerto Rico may not be equal to or greater than 20% except 60% for not more
than 4 minutes in any 30 minutes
-•> 40. Rhode Island may not be equal to or exceed 20%-
o
41. South Carolina may not be equal to or exceed 40% except 60% for 5 minutes in
one hour or 20 minutes in a 24 hour period.
42. South Dakota may not exceed 20% except 40% is permissible for not more than
2 minutes in any hour.
43. Tennessee may not exceed 40% for more than 5 minutes aggregate in any one
hour or more than 20 minutes in any 24 hour period
44. Texas may not exceed an opacity of 30% averaged over a 5 minute
period.
45. Utah may not exceed 40%.
46, Vermont may not exceed 40% for more than 6 minutes in any hour. Opacity
may never exceed 60%.
-------
Existing Sources - Limits (continued)
47. Virgin Islands may not be equal to or greater than 40%.
48. Virginia
49. Washington
may not exceed 20% except for brief periods when starting a
new fire, blowing tubes, or cleaning a fire box.
may not exceed 40% except for 15 minutes in any consecutive
8 hours.
50. Washington, D.C. no visible emissions except less than 20% for 2 minutes in
any 60 minute period and for an aggregate of 12 minutes in any
24 hour period.
51. West Virginia may not be equal to or exceed 20% except 10% after June 30, 1975.
52. Wisconsin
O
may not be equal to or exceed 40% except 20% in Milwaukee and
Lake Micigan AQCR's. Also 80% for 5 minutes in any one hour
for cleaning or starting new fire in combustion equipment
(3 times a day maximum).
53. Wyoming
may not exceed 40%.
-------
APPENDIX D
702
-------
LOW TEMPERATURE CORROSION AND FOULING292
INTRODUCTION
Flue gas temperatures which are in the range of 104-121°C
(220-250°F) may result in corrosion and fouling of air heater
elements and corrosion of precipitator elements. Operation at
such low temperatures has caused corrosion and fouling of air
heater elements in some installations, while others have exper-
ienced no difficulty with air heater exit temperatures as low as
104°C (220°F) . An understanding of the factors which cause cor-
rosion and fouling problems is important when operating with flue
gases at low temperatures. The purpose of this appendix is to
relate corrosion and fouling to fly ash and flue gas composition,
fly ash resistivity, and temperature.
SULFURIC ACID OCCURRENCE IN FLUE GAS
SOx, H2O, and H2SOtt Equilibria
A knowledge of the SO 3 concentration in the air heater and
precipitator region of power plant exhaust systems is important
from a standpoint of both corrosion and fly ash resistivity. The
principal cause of corrosion in air heaters, and the most im-
portant factor. in determining fly ash resistivity, is sulfuric
acid, which results from the reaction of SO 3 with water vapor.
Most of the sulfur in power plant flue gases appears as SO2,
with typical S03 levels ranging from 1 to 2.5% of the S02. However,
as Figure 301 shows/ the equilibrium constant for the reaction
S02(g) + h02 (g) = SOj(g)
strongly favors the formation of S03 at temperatures below 537°C
(1000 °F) with 3% oxygen. This graph was calculated from data cited by
Hedley.293 The kinetics of the reaction are, of course, unfavorable
in the absence of a catalyst, but it is thermodynamically feasible
for SO 3 concentrations to exist at levels much greater than those
normally encountered. Ratios of S03 to S02 as high as 0.1 have
been reported. 29 *" Thus, since the formation of SOs is controlled
by catalytic effects as well as the amount of excess air present,
the concentration of SO 3 resulting from the combustion of a
particular fuel can only be .estimated in the absence of direct
measurements.
703
-------
100
90
O
tn
D
E
m
O
ai
80
70
M
O
CO
u.
O
2 60
g
j/3
ce
!J! 50
40
30
20
10
3% O2
_L
_L
_L
600
(315.0)
700
(370.6)
800
(481.7)
900
(481.7)
1000
(537.3)
1100
(592.8)
TEMPERATURE, °C (°F)
1200
(648.4)
8640-250
Figure 301. Equilibrium conversion of
to
704
-------
The reaction between water vapor and SO 3 is given by
H20(g) + S03(g) = H2S(Mg).
Figure 302 shows the equilibrium conversion of SOs to HzSO., as a
function of temperature for a typical flue gas water concentration
of 8%. At temperatures below 204°C (400°F) , essentially all of
the SOs present is converted to H2SCU at equilibrium. In contrast
to the formation of S03, the formation of HaSOn occurs rapidly in
the thermodynamically feasible temperature range.295 Thus, all
SOs below the air heater in a power plant will exist as HaSOn,
either in the vapor or liquid state. Since corrc-ion problems
are associated with the presence of liquid phase sulfuric acid, the
determination of the condensation characteristics of sulfuric acid
from flue gas containing sulfuric acid and water vapor is a neces-
sary step in evaluating the corrosion potential of a particular
stack gas.
Determination Of The Sulfuric Acid Dew Point
Fly ash particles can influence the apparent dew point, or
saturation temperature of HaSOi* in flue gas, but experience has
shown that one commits practically no error by neglecting the
presence of other gases and considering only the system sulfuric
acid - water.295 A thermodynamic analysis of the sulfuric acid -
water - flue gas system, ignoring for the present the effect of
fly ash, provides a theoretical basis for predicting acid dew
points and condensate composition from vapor-liquid equilibria
data.
For the case of ideal or quasi-ideal binary solutions, dew
points of vapor mixtures composed of the binary solution vapor
and noncondensable gases can easily be calculated from a knowledge
of the pure component vapor pressures as a function of temperature.
The H2SOit-H2O system presents special problems because:
the H2SOi, and water undergo chemical reaction to form
the various hydrates of sulfuric acid, and therefore
the equilibrium relationships are strongly composition-
dependent, and
has a very low pure component vapor pressure, thus
making direct measurements extremely difficult.
The total vapor pressure of H2SCK at low temperature is essentially
the partial pressure of water above the acid solution, and this is
available from the existing literature. In order to determine the
dew point, however, the HjSOit partial pressure at low temperature
must be known, and the literature ladks such data.295
705
-------
O
c/5
O
100
90
80
70
60
50
P 40
e 30
O 20
UJ
10
200
(93.3)
I
I
300
(148.91
400
(205)
500
(260)
600
(315.0)
TEMPERATURE, °F (°C)
700
(371)
3*40-291
Figure 302. Equilibrium conversion of S03 to H2 SOt> at 8.0
volume % H20 in flue gas.
706
-------
As a result of the experimental difficulties encountered in
low temperature vapor pressure measurements, efforts have been
made to calculate the partial pressure from liquid phase thermo-
dynamic data, Abel297 was the first to derive a relationship en-
abling the calculation of HaSCK, HaO, and SOa partial pressures
from standard state values of enthalpy, entropy, and heat capacity;
and partial molal values of enthalpy, entropy, free energy, and
heat capacity. Muller,296 using Abel's calculated data/ computed
dew points of gases with low H2SOi» concentrations. Gmitro and
Vermuelen298 utilized thermodynamic data, which are claimed to be
more recent and more complete, to calculate HsSCH, SOs/ and H20
partial pressures from -50 to 400°C with solutions ranging from
10 to 100 weight percent H2SOi». Snowden and Ryan""5 have used
Gmitro and Vermulen's partial pressure data to construct a chart
which gives the dew point temperature of a gas as a function of
H2SOi, and EzO partial pressures. The composition of the acid
condensate occurring at a given dew point is also provided.
The dew points predicted from Abel's data are about 30°F
higher than those arrived at with Gmitro and Vermuelen's data.
The difference in these two works lies mainly in the data avail-
able for the calculation of the partial pressures. Gmitro and
Vermuelen had access to much more accurate data and should have
obtained the more accurate results. However, their results do
not agree with direct dew point measurements by the condensation
technique, whereas Abel's partial pressures have been verified
in part by use of this method.
A suspect assumption common to predictions of acid dew
points based on both the Abel and Gmitro calculations is that
the vapor state is an ideal gas, and that the vapor solution is
also ideal. A gas mixture may behave nearly ideally volumetri-
cally, but a component present in small amounts may exhibit
significant departure from ideality if that component is assoc-
iated in the vapor state.
Among the limitations of some presentations in the literature
of the Muller correlation with 10% water vapor is that they do
not indicate the effect of variations in the water vapor concen-
tration on sulfuric acid dew points. The concentration of the
condensate is also not provided. Figures 303 and 304 were pre-
pared to present this information.
Figure 303 is a sulfuric acid - water dew point chart pre-
pared from Abel's H^SO.* partial pressures and Greenewalt' s 9
water partial pressures above sulfuric acid solutions. The
partial pressure data were calculated by computer from the fol-
lowing equations:
+ E • T) ] (74)
707
-------
::,*,. j-:.. v :,.::. ,:VT..I::~™
...... 4 .... .TV ..... . .\.-.,
:M^:M=i^iaHny:::=j:;;- ;;*K^:
;a:,:a:;y . 1L rj,.::] .. i:::a, -
;••-:F,H-\i:':T::-i'--:^
6 8 10
WATER VAPOR, VOL %
Figure 303. Dew point and condensate composition for vapor
mixtures of H2O and Jfe SOi, at 760 mm Hg total
pressure (Abel and Greenewalt),299
708
-------
220
(103.9)
240
(115.0)
260
(126.1)
280
(137.3)
300
(148.4)
DEW POINT, °F (°C)
320
(159.5)
3540-293
Figure 304.
HiSOi, dew points for typical flue gas moisture
concentrations.
709
-------
and
PH,0 = 6XP [2'303{A' - p)l , (75)
where T is in degrees Kelvin and partial pressures are in mm Hg.
The constants in these equations are given by Abel and Greenewalt
for various sulfuric acid concentrations. It should be noted that
the range of uncertainty indicated by Abel for the constant B in
equation 301 results in a dew point uncertainty of 4.45°C (24°F)
at 10% water vapor.
The information contained in Figure 303, if it were accurate,
would be of value in assessing the corrosion poz~ntial of a flue
gas. The dew point temperature can be predicted from an analysis
of HsSCH and water vapor content, and if the gas is cooled to sore
temperature below the dew point, the equilibrium concentration of
condensate and the amount condensed can be obtained. It should
be pointed out, however, that the amount of condensate predicted
from the use of a dew point chart such as Figure 303 is actually
a prediction of the amount available for condensation. The amount
of condensate depositing on a metal surface may differ from the
chart prediction because of mass transfer considerations.
As an example of the use of the chart, consider a flue gas
containing 10 ppm HjSOu and 10% HsO. Condensation would occur
at about 275°F, and the condensate composition at that point
would be about 79% H2SOi, by weight. If the gas were cooled to
250CF, 85% of the H2SOii should be removed from the gas phase, and
an insignificant amount of the water vapor would also be condensed,
The condensation, therefore, follows the 10% water line, result-
ing in a condensate which would be the equilibrium composition of
the condensate at 121°C (250°F), assuming the vapor phase is in
equilibrium with the total liquid condensed. The composition
change of the liquid is small over the temperature interval given
as an example, ranging from 79% at 135°C (275°F) to 75% at 121°C
(250°F).
It is apparent from Figure 303 that a knowledge of water
vapor concentration is of fundamental importance. Appreciable
changes in this variable can have a rather significant effect on
the predicted sulfuric acid dew point, and if a gas is saturated
with H2SOi4, the condensate composition is determined by the water
vapor content and temperature. Thus, if a surface is maintained
at a known temperature lower than the sulfuric acid dew point,
but higher than the water dew point, the concentration of acid
condensate which occurs can be predicted from Figure 303 if the
water vapor content of the gas is known.
In addition to the procedure based on calculated partial
pressures, a number of efforts have been made to determine sul-
furic acid dew points using instrumental and chemical procedures.
710
-------
Two methods will be discussed briefly: the condensation method
and an electrical conductivity method.
The problem of measuring SO3 concentration and acid dew
point has been studied since Johnstone300 examined the pro-
blem in 1929. Many papers3°1-3l2 have been presented which employ
the electrical conductivity method which Johnstone originated.
The British Coal Utilization Research Association (BCURA) designed
an instrument which has found widespread usage employing Johnstone's
concept. This instrument, known as BCURA dew point meter, has
been described in detail by Flint.301 It is a portable instru-
ment which measures the conductivity of a condensing film. The
detector element is glass and contains two electr:des mounted
flush with the surface. A tube inside the glass probe transports
compressed air which is used to maintain the glass surface of the
probe at the desired temperature. A thermocouple provides a read-
out of the glass surface temperature.
If an electrically conductive film forms on the detector
element, a current will flow that is proportional to the magnitude .
of the externally impressed voltage and the conductivity of the
condensing film. The current flow is measured with a microammeter.
A dew point is determined by inserting the detector element into
a gas stream with the instrument temperature held at some value
above the dew point. The element temperature is then alternately
increased and decreased slowly to establish the exact temperature
'at which the increase in conductivity, and thus the dew point,
occurs.
The condensation method is widely used for determinations of
SOa in stack gases. The basic procedure employed consists of
pumping the flue gas through a condenser coil maintained below
the dew point of sulfuric acid, but above the normal water dew
point. A heated sampling probe is used to obtain the flue gas
samples, and a filter is inserted at the probe entrance to exclude
particulate matter. A fritted glass filter follows the condenser
to serve as a spray trap. When the sampling period is concluded,
the HaSOt* is washed from the condenser, . and the washings are col-
lected and titrated.313
The condensation of a binary vapor mixture from a noncon-
densable gas is normally path-dependent, • and the composition of
the vapor leaving a condenser is not fixed merely by stating that
the gas is saturated at a particular temperature. This is true
because the degree of fractionation occurring during condensation
depends on conditions which exist in the condenser. For the case
of H2SCU-H20 vapor mixtures in flue gas, however, the water vapor
is in large excess, and no appreciable change in its concentration
occurs until the water dew point is reached. The composition of
the gas is, therefore, not path-dependent, and the state of the
system is fixed if the gas is saturated with HaSCK at a certain
temperature and water vapor content. As a result, the condensation
711
-------
method can be used to obtain dew points of H2SOit-flue gas mixtures.
Since the gas leaving the condenser is saturated with H2SCU at
the condenser exit temperature, the concentration of the exit
vapor represents the dew point', or saturation- 'temperature, of
the gas.
Figure 305 presents the results obtained for flue gas dew
points as a function of KzSOt, (g) content by various investigators.
To make an exact comparison, all of the curves should be for a
gas of the same volume percent water vapor. However, reference
to Figure 303 will indicate that a variation in water vapor concen-
trations from 7 to 10% can cause only about a 2.78 to 4.45°C (37 to
40°F) change in the dew point. Taylor's result? --ere obtained with
the BCURA dew point meter in a mixture of air, water vapor, and
sulfuric acid.312 Lisle's data were obtained using the condensa-
tion method, again with a mixture of air, water vapor, and sulfuric
acid.313 The dew point curves of Gmitro, Muller, and from Figure
303, are based on the previously discussed calculated partial
pressures.
It is obvious from Figure 305 that, except for Lisle and
Sensenbaugh1s checks of the data based on Abel's sulfuric acid
partial pressures (Muller's data and Figures 303 and 304), there
is little agreement between the results of the various investi-
gators. The data obtained from calculated partial pressures agree
in form, which is to be expected since the equations used to calcu-
late the partial pressures are also of the same form. The nature
of the disagreement between the calculated dew point and those
obtained with the dew point meter suggest there is a sensitivity
problem with the instrument at low sulfuric acid partial pressures.
In view of the difficulties with calculations based on liquid
phase thermodynamic properties and the probable inaccuracy of dew
point meters at low acid partial pressure, it can be concluded
that the only reliable method of correlating sulfuric acid dew
points with water and H2SOi, vapor concentration is a carefully
planned experimental program based on the condensation method
employed by Lisle and Sensenbaugh. In the absence of such data,
the dew points based on Abel's partial pressure data can be used,
since they have been verified in part by experiment and by the
operational experience of several power plants.
Condensation Characteristics
As stated previously, the amount of acid condensate predicted
from the use of a chart such as Figure 303 as a result of cooling
to a temperature below the sulfuric acid dew point is a prediction
of the amount available for condensation. Figure 306 shows that
the predicted percentage of H2SOi» condensed increases and asymp-
totically approaches 100% as the temperature is lowered below the
dew point. However, peak values of acid deposition rates at temper-
atures between the water and acid dew points have been observed by
numerous investigators.
712
-------
ou
50
40
30
20
c ig
O
0.
< 8
-------
100,
TEMPERATURE, °F (°C)
3S40-295
Figure 306.
Percent H2SO^ available for condensation for flue
gas of 100 ppm H2 SOi, and 10% H20 vapor (calculated
from Figure 303).
714
-------
The occurrence of such a peak in the condensation rate may
be caused by a change in the diffusivity of the H2SOi» in the
region close to the condensing surface. The rate of condensation
is dependent on the diffusion rate of HjSOi, and water vapor to the
surface. Small droplets of HaSO., will form in the cooled gas ad-
jacent to the surface, and the size of these droplets is likely to
increase with decreasing temperature. The growth of the droplets
would slow their diffusion to the surface and increase the prob-
ability that they would be carried forward in the gas stream. Thus,
a temperature can be reached at which the slowed diffusion becomes
dominant over the increased amount of condensate available for
collision with the surface. This explanation is similar to one
offered by Flint and Kear.306 A typical condense-3 rate curve,
obtained in a spiral condenser with a vapor mixcure consisting of
7.5 vol % HaO, 69 ppm H2S04, and the balance air, is shown in Figure
SO?.31"
FACTORS INFLUENCING CORROSION RATES
Acid Strength
If a flue gas is known to be saturated with HaSOi* vapor at
a temperature below the acid dew point, it is possible to predict
the initial condensate composition as a function of the water
vapor partial pressure and temperature. Since data are available
in the literature concerning the corrosion rates of various ma-
terials as a function of acid concentrations, it is of interest
to determine whether there is any relationship between corrosion
rates measured in flue gas and the acid condensate strength pre-
dicted from a gas analysis.
A study of flue gas corrosion of low alloy steels by Piper
and Van Vliet315 provides data which illustrate the difficulty
encountered in predicting corrosion rates of metals from acid
condensate strength alone. The compositions of the low alloy
steel specimens used in this study are given in Table 50. The
corrosion tests were conducted by inserting specimens maintained
at known temperatures into stack gas produced from a pulverized-
fuel-fired steam generator. The average E2SOtt content of the
stack gas was about 30 ppm. Figure 308 gives the predicted sul-
furic acid condensate compositions for the range of stack gas
water vapor concentrations experienced during the study.
Figure 309 shows the average corrosion rate of selected
steel specimens as a function of predicted HaSOu condensate
strength. The condensate strengths shown in Figures 308 and
309 were obtained from the computer printout of partial pressure
for the HzSO^-HzO system, using Greenewalt's equation (equation
75) for the partial pressure of water over sulfuric acid solu-
tions. The widths .of the surface in Figure 309 indicate the
possible acid concentrations at each temperature over the range
of water vapor partial pressures encountered in the stack gas.
715
-------
48
o
o
o
O
to
tM
32
50
75
100 125
TEMPERATURE, °C
150
175
3540-296
Figure 307.
Variation in condensation rate with surface
temperature (From H. D. Taylor).31lf
716
-------
TABLE 50. COMPOSITION, PERCENT BY WEIGHT, SPECTROGRAPHIC
ANALYSIS OF SPECIMENS TESTED (from Piper and
Van Vliet)3*5
Name
Cor- ten
NAX-A
NAX-B
NAX-C
Mn
0.
0.
0.
0.
40
85
82
53
0
0
0
0
Si
.38
.90
.79
.54
0
0
0
0
Cu Ni
.23 0.29
.07 <0.1
.29 <0.1
.07 <0.1
Cr
0.
0.
0.
<0.
61
59
60
!
Zr
—
Present
Present
Present
717
-------
154
(310)
143
(290)
132
(270)
121
_ (250)
u.
£- 110
g (230)
£ 99
3 (210)
a 88
S (190)
1
£ 77
(170)
66
(150)
54
(130)
43
(110)
•
_ — •
^-
7.5
^
*f
VOL "A
^
^
H20
X^
-------
Ui
I 3
O
cc
O
O
LU
o
<
cc
2
45.6°C
7.5 VOL % H2O
I
5.1 VOL % H2O
-------
Figure 310 is a plot of corrosion rates of steel given by
M. G. Fontana316 at 2.3.4°C (75°F) as a function of acid concen-
tration. The corrosion rates for steel specimens immersed in
acid are orders of magnitude higher than those observed by Piper.
Since corrosion increases with temperature, the differences be-
tween the Fontana and Piper data are even greater than indicated
because the latter's data were obtained at high temperatures.
The low alloy steels used in the Piper study would not be
expected to exhibit greatly different corrosion rates in sulfuric
acid solution than the ordinary carbon steel on which Fontana's
data are based. Therefore, the orders of magnitude differences
in corrosion rates indicated are largely a reflection of the
differences in environment between the two situations. Another
contributing factor is the parabolic nature of the corrosion-time
relationship usually found in corrosion work. Thus, because of
the effects of fly ash and condensate deposition rates, it is not
practical to predict or correlate corrosi'on rates of materials in
flue gas solely on the basis of equilibrium condensate compositions,
Acid Deposition Rate
The corrosion rate of metal surfaces in flue gas at tempera-
tures well above the water dew point is more strongly related to
the amount of condensate deposited than to the concentration of
the condensate. Consider, for example, a steel surface at 126.1°C
(260°F) exposed to a flue gas with a bulk gas phase concentration
of 10 ppm sulfuric acid vapor and 10% water vapor.. A condensate
strength of 77% H2SOi» would be expected, and if fly ash neutral-
izing ability is ignored, some nonzero rate of corrosion would be
expected. If the same steel surface were exposed to a similar
flue gas with 80 ppm sulfuric acid vapor, the predicted conden-
sate strength would remain at 77% H2SOi», but the corrosion rate
would be greater because of the increased quantity of acid conden-
sate depositing on the metal. In both cases, decreasing the metal
surface temperatures to a value approaching the water dew point
[37.3 to 42.8°C (100 to 110°F)] of the flue gas would result in
increased corrosion rates because of the highly corrosive dilute
acid formed at these temperatures.
The temperature at which the maximum condenscttion rate of
acid occurs has been correlated with the temperature of maximum
corrosion in flue gases. Figure 311 was taken from a study by
G. G. Thurlow, in which an air-cooled corrosion probe was exposed
to flue gas produced from burning a 0.8% sulfur coal.317 The
rate of sulfate deposition shows a peak at the same surface tem-
perature as the corrosion rate. This peak rate effect is often
not observed with coal firing, but Black310 and Clark311 have
found this phenomenon quite useful in correlating corrosion of
air preheaters in oil fired units. The sulfur content of the
fuel used in these studies ranged from 1.4 to 4.0%.
720
-------
10*
103
>
1
uT
H
102
C/3
O
cc
cc
O
O
10
I I IT I
I I I M
_L
10 30 50 60 70
WEIGHT PERCENT
80
90
100
3540-299
Figure 310,
Corrosion of steel as a function of H2S(\ concen-
tration at 23.4°C (75°F).316
721
-------
20
o>
•2.
O
c
O!
LU
H
<
Li.
_l
3
10
fc 20
10
0!
160
(71)
200
(93)
I
240
(116)
280
(138)
320
(160)
SURFACE TEMPERATURE, °F (°C)
360
(182)
3540-300
Figure 311,
Variation of condensation and corrosion with
surface temperature (data from Thurlow).3l7
722
-------
Black and Clark's work was done with the BCURA dew point
meter, and the peak rate of acid deposition was indicated by a
peak rate of increase in current, measured as microamps per
minute. The maximum corrosion rate is expected to occur in a
regenerative air preheater at the point where the average metal
temperature corresponds to the peak rate temperature indicated by
the BCURA meter. By superimposing a plot of the dew point meter
readings in the region of the peak over lines of average metal
temperature, it was possible to match the peak rate temperatures
with actual corrosion experience.
The above authors also found that the BCURA indication of
the acid dew point was a poor indicator of flue gr.s corrosion
potential, particularly when oil and gas mixtures are fired. This
observation is not surprising since, as Figure 303 indicates, the
dew point alone does not specify how much acid is available for
condensation. The accuracy of the dew point meter may also be an
important factor, because instructions for use of the meter state318
that changes in dew point readings of less than 11°C (52°F) are not
to be regarded as significant. Referring again to Figure 303, a
change of dew point at 10% water vapor from 132 to 143°C (270 to
290°F) indicates a 370% increase in the HaSOi* vapor content of
the flue gas.
Studies conducted by Lee, Freidrich and Mitchell,309 in
which the BCURA meter was employed with flue gas produced from
burning low sulfur lignite, showed that the meter was unable to
detect acid dew points with low sulfur coals. In one experiment,
no acid dew point was detected by the meter in the presence of
sulfuric acid vapor levels as high as 27 ppm. The author's ex-
plantation for this is that the condensed acid was completely
neutralized by. basic constituents in the fly ash.
Thus, since high fly ash resistivity is associated with low
sulfuric acid vapor concentrations, the BCURA meter is not likely
to be of value in assessing the low corrosion potential associated
with a flue gas containing high resistivity fly ash.
Fly Ash Alkalinity
Although fly ash can cause severe plugging problems in air
heaters, it is well established that alkaline ashes can neutralize
a portion of the SOs and HaSOt, occurring in stack gases, thereby
acting to reduce corrosion. Lee provides data which illustrate
the interaction of acid condensate with fly ash. Figure 312 illus-
trates the effect of surface temperature on acid condensation rate
when burning a 7% sulfur coal with 3% excess oxygen. The RBU
plotted on the y axis in the upper graph is a measure of the rate
of acid condensation when the BCURA dew point meter is maintained
at the indicated temperatures. Data for the lower graph were
obtained by isokinetically sampling the-flue gas and collecting
the fly ash and acid condensate in a Teflon vial maintained at
723
-------
600
500
400 r-
300 -
D
El
O.
c.
tfl
Z
UJ
I-
O
U
2
O
O
CO
w
LU
O
X
LU
Figure 312.
SURFACE TEMPERATURE, °F (°C)
1540-301
Variation in rate of acid buildup (RBU) and excess
cation content of fly ash as a function of surface
temperature. Coal contains 7% sulfur with 3%
excess Oj (data from Lee).307
724
-------
82, 100, 118, and 135°C (180, 212, 245, and 275°F) . The contents
of the vial were then extracted, and the extract was analyzed for
acid or base content. If the extract pH was less than 7, the
solution was titrated with sodium hydroxide, and the results were
reported as a negative cation content. If the extract was basic,
the solution was titrated with HCl, and the results were reported
as an excess cation content, indicating that the condensed sul-
fur ic acid had been completely neutralized.
The acid neutralizing ability of fly ash with various base
contents is illustrated in Figure 313 for a flue gas with a typical
dust loading of 11.4 gm/scm (5 gr/scf ) . The parallel lines each
represent a base content of fly ash, expressed as milliequivalents
reactive base per gram fly ash. Data obtained on Contract CPA 70-
149 (A Study of Resistivity and Conditioning of Fly Ash) indicate
that fly ash produced from burning a high sulfur coal has as much
as 0.6 milliequivalents soluble base (1.7% CaO) per gram fly ash.319
This quantity of base is capable of neutralizing 80 ppm H2SOi, in
'the gas phase, assuming that the flue gas has an ash concentration
of 11.4 gm/scm (5 gr/scf) . This is not to say that complete neu-
tralization will occur, since the degree of neutralization obtained
in the flue gas is a function of the rate of transfer of HaSOi,
to the fly ash particles and the rate of reaction occurring on
the particle surface.
Hydrochloric Acid
Sulfur, chlorine, and alkali metal compounds are associated
with high temperature corrosion in coal-fired boilers, but low
temperature corrosion is usually thought of only in terms of sul-
furic acid. However, metals with surface temperature below the
moisture dew point would be subjected to HCl attack if the chlorine
content of the coal is converted to HCl. Although not all of
the chlorine in coal appears as NaCl, it is of interest to examine
the chemical reactions undergone by NaCl in the combustion process.
The following discussion is taken from a study by Halstead3"50 in
which chloride and sulfate deposit formations were examined with
probe tests and by thermodynamic calculations.
In pulverized coal firing, the NaCl can be expected to evapo-
rate and undergo some degree of vapor phase hydrolysis.
NaCl(g) + H20(g) = NaOH(g) + HCl(g)
The reactions of the chloride and NaOH with S02 to form Na2SOi+ are,
however, of greater importance. They are
2NaCl(g) + H20(g) + S02 (g) + *502 (g) = Na2SOu(g) + 2HCl(g)
2NaOH(g) + S02(g) + h02 (g) = Na2S0lt (g) + H20(g)
725
-------
100
0.1
Figure 313,
Consumption of the available base on fly ash as a
function of the concentration of neutralizing acid
in flue gas with 5 gr/scf fly ash.
726
-------
Halstead calculated the equilibrium partial pressures of
and NaCl in flue gases produced from burning the coals
listed in Table 51 at 5% Oa excess, stoichiometric Os, and 2%
Oz deficient. These calculations, together with deposition
studies conducted with a cooled probe, indicate that almost
total conversion of NaCl to NazSOt* takes place with 3 to 5% ex-
cess oxygen in large boilers with good mixing of fuel and air.
With lower oxygen levels, and when poor mixing and short resi-
dence times are encountered, the conversion of NaCl to NajSOi*
may be incomplete.
Thus, it can be seen that significant concentrations of HCl
are likely to result from the combustion of chlorine-containing
coal. The subject of HCl corrosion in flue gases has received
comparatively little attention in the literature because it is
not likely to occur unless temperatures near the water dew point
are encountered. Air preheater elements, however, can drop below
the moisture dew point if excessive water vapor, such as would
occur from a steam leak, is present.
Figure 314,' taken from a study by R. W. Kear,321 illustrates
the effect of HCl in a flue gas on corrosion of a test probe.
This experiment was conducted using an apparatus which produced
a synthetic flue gas by addition of SOj and Clz to the fuel supply
of a small laboratory burner. Analysis of the flue gas indicated
that all chlorine was converted to HCl, resulting in 400 ppm HCl
by volume. It should be noted, however, that corrosion could be
caused by the presence of chlorine gas. The assumption that
Figure 314 is an illustration of the effect of HCl gas is there-
fore dependent upon Kear's conclusion that all chlorine is con-
verted to HCl in the burner flame. The SOa, or HaSOu, content of
this gas was reported as 36 ppm. The temperature at which the
corrosion rate-accelerates corresponds to the water dew point of
the synthetic flue gas, which is about 7% by volume water vapor.
When the metal surface temperature is above the water dew point,
the presence of HCl has no effect on corrosion, but it can be
seen from Figure 314 that drastic increases in corrosion occur
due to HCl as the metal surface falls below the water dew-point.
The corrosion probe was exposed for a 30-minute period in each
experiment.
Data obtained by Piper and Van Vliet315 confirm Kear's re-
sults. Piper's data were obtained by exposing metal condensers,
which could be cooled to selected temperatures, to flue gas pro-
duced from burning a 0.066% chloride coal. Analysis of the flue
gas showed that HCl concentrations ranged from 16 to 82 ppm, and
the sulfuric acid vapor concentration averaged 30 ppm. The re-
lative rates of corrosion of low alloy steel specimens maintained
at 71, 60, 46, and-.3Q°C (161, 141, 115, and 87*F) for 2-month
exposures were 1., 1,- 3, and 66, respectively. The water dew
point of the flue gas during the exposure period ranged from
32 to 40°C (91 to 104°F). It is thus apparent that the rate of
727
-------
TABLE 51. SULFUR AND CHLORINE CONCENTRATIONS
IN FLUE GAS (from Halstead)32°
Sulfur in Chlorine in Sulfur compounds Chlorine compounds'
coal coal in flue gas ir flue gas
vol ppm vol ppm
0. 8
1.2
1.8
0. 8
0.4
0.07
750
1100
1700
680
340
60
a. Calculated by assuming complete volatilization of all sulfur
and chlorine in coal and one atom of sulfur or chlorine present
in each gas molecule.
728
-------
0.1% OF S02 + 0.02% OF C!2 !N
FLUE GAS
0.1% OF SO2 IN FLUE GAS
30 40 50 60 70 80 90 100 110 120 130 140 150
SURFACE TEMPERATURE, °C 3540-303
Figure 314. The effect of chlorine addition or corrosion
of mild steel in a synthetic flue gas (from
R. W. Kear).321
729
-------
attack greatly accelerated below the water dew point. This cor-
rosion is a result of both H2SOi, and HCl, but the importance of
the effect of HCl is indicated by the fact that at the water
dew point, the chemical equivalents of chloride exceeded those
of sulphate. Another important observation of the Piper study
was that a vitreous enamel coating on Cor-Ten, which was used
in a pilot-plant air preheater, was considerably attacked at
temperatures below the water dew point.
Since high resistivity fly ash usually occurs in the absence
of sulfuric acid vapor, it is of interest to consider such a
situation in which appreciable concentrations of HCl exist. Piper
analyzed the vapor-liquid equilibria data for the system HCl-HaO,
and concluded that, with an HCl vapor concentration of 82 ppm,
the hydrochloric acid dew point would be 3.9°C (39°F) above the
water dew point. A similar analysis of the water-SOa system in-
dicated that the sulfurous acid dew point, for a stack gas with
about 1900 ppm SO2 and typical water vapor concentrations, would
be the same as the water dew point.
FOULING OF LOW TEMPERATURE SURFACES
Deposit formation, or fouling, in air heater elements is a
combination of chemical and physical processes. At 600 to 700°F,
which is the range of temperature normally encountered at the hot
end of regenerative air heaters, the saturation partial pressure
of the mineral components of fly ash is extremely low. Thus
deposit formation in this region is not a result of condensation
from the vapor phase, but is instead a mechanical process in which
slag and refractory material are carried by the flue gas into the
air heater elements. These particles can lodge within the passages
of hot end elements and thereby accumulate additional deposits of
finer dust particles.322 Procedures are reported in the literature
for removing such deposits.
If the flue gas contains appreciable amounts of HaSOt*, corrosion
and deposit buildup will occur simultaneously in the cooler regions
of the air heater. 23 The following reaction will occur on steel
surfaces which are below the HaSOi, dew point.
Fe + HaSOn ->• FeSOu 4- H2
The ferrous sulfate can then oxidize to form ferric sulfate.
+ 2H2SO^ + 02 -* 2Fe2(SOi,)3 + 2H?O
An extensive study of regenerative air heater deposits by the
Bureau of Mines32" found that deposits built up in thickness at
the cold end of the air heater, and that this area was the prin-
cipal region of corrosion and destruction of the element. All
deposits found in this area exhibited the following characteristics
partial solubility in water, presence of sulfates, and acidity.
730
-------
The solubilities in water of these deposits varied over a wide
range—13 to 98%. Deposits with highest solubilities were found
on preheater test plates which were most severely attacked by
acid. Some of the variations in deposit solubility were attri-
buted to variations in the ability of the deposits to trap fly
ash.
Reaction of the ferrous and ferric salts formed during cor-
rosion with alkaline compounds sometimes used in washing air heaters
can produce compounds that will result in additional fouling.
Ferric sulfate, for example, can undergo the following reactions.323
Fe2(SOl»)3 + 3Ca(OH)2 (lime) -»• 2Fe(OH) 3 -r 3CaS04
Fe2(SOn)3 + 6NaOH ->• 2Fe(OH)3 + 3Na2SOu
Pe2(SOi,)3 + 3Na2C03(soda ash) + 3H20 -»• 2Fe(OH)3 + 3Na2SCU
+ 3C02
The Fe(OH)a (ferric hydroxide) is undesirable because it is a
sticky, gelatinous precipitate which can cause severe fouling.
The above reactions indicate that, in washing air heater elements
or tubes, removing the soluble sulfates with a neutral water wash
is desirable prior to a caustic wash.
It is important to note that deposit formation can occur in
air heater elements in the absence of significant amounts of H2SOit.
Chemical analysis of deposits from air heaters installed in some
lignite-burnina power stations has revealed no chemical evidence
of deposition. In one instance, moisture from steam cleaning
action was found to be responsible for trapping ash deposits. De-
posits formed in this manner are similar to cement and very difficult
to remove.
In the absence of moisture and acid condensate problems, the
nature of the fouling mechanisms discussed herein suggests that
lowered cold end temperature would not result in increased deposit
formation.
LABORATORY CORROSION STUDIES319
Samples of fly ash were obtained for corrosion studies from
the precipitator hoppers of two plants with high dust resistivity
problems. These ash samples have widely different soluble base
contents, as can be seen from Table 52. Sulfur contents of the
coal burned in the two plants range from 0.6 to 1.0%. Laboratory
experiments were conducted to determine whether deposited layers
of these ashes exhibit differing capabilities for neutralising
acid and inhibiting corrosion.
731
-------
TABLE 52. FLY ASH PROPERTIES
ro
Neutral (from Plant 1)
As received
Following experiment
(Experiment 4, Table
Basic (from Plant 6)
6.4)
As received
Following experiment
(Experiment 3, Table 6.4)
pH of
suspension
6.70
1.69
12.
8.
25
72
Soluble
sulfate
wt %
0
23
1
23
. 31
. 4
.2
.1
Soluble
base
as CaO
meg/g wt %
0
0
2.7
Not de
mined
0
0
7.6
ter-
particle
diameter, y
38
18
-------
A schematic diagram of the apparatus used for the experiments
is given in Figure 315, and the data obtained are presented in Tables
52 and 53. The corrosion specimen was a 2.54 cm (1 in.) diameter
mild steel disc, and the amount of corrosion occurring as a result
of exposure to HaSOt, was determined by measuring the weight loss.
The experiments in Table 53 can be divided into two groups.
In Experiments 1 through 4, the acid condensation rate on the disc
was relatively low, but high condensation rates were achieved in
Experiments 5 through 10 by increasing the strength of oleum used
as an SO3 vapor source and by lowering the temperature of the
water bath. Water vapor concentrations of 2 - 2.5% by volume were
provided by the water spargers. Since the air streams bearing
H20 and SOs vapor mix in the heated glass "T", a saturated mixture
of air and HaSOi, is formed, and the condensation rate will depend
on the temperature of the condensing surface and the concentration
of H2SOi» in the gas phase. For both sets of experimental con-
ditions, an examination of the corrosion rates (meq basis) and
acid deposition rates in Table 53 shows that an excess of acid
was present with respect to the amount of iron corroded in all
experiments.
For the experiments with fly ash, the ash was deposited in
the sample container in such a manner that the disc was covered
to a thickness of approximately 0.2 mm. Acid did not sufficiently
penetrate the ash to reach the underside of the disc in Experiments
3 and 4, and the penetration rates were calculated on the basis of
one side only. Corrosion was observed on both sides in all other
experiments; therefore, the total area of both disc surfaces was
used as a basis of calculation.
A comparison of data from Experiment 3 with those from Ex-
periment 4 indicates that the basic fly ash was more effective in
reducing corrosion than the neutral ash. The equilibrium pH values
of the ash samples prior to and following these experiments are
given in Table 52. As would be expected, the neutral ash slurry
is much more acidic than that of the basic ash after both have
experienced an equivalent sulfate gain due to HzSOu condensation.
The fact that the basic ash produced a pH greater than 7 following
the experiment shows that it was capable of neutralizing all of
the condensed acid. Complete neutralization did not occur until
the acid-ash mixture was slurried in water, however, as evidenced
by the measurable degree of corrosion which occurred in Experiment
3.
For the experiments with low acid condensation rates, both
the neutral and basic ash deposits reduced the weight loss rate of
the disc, but the penetration rate calculated for Experiment 4
(neutral ash) is not significantly different from those of Ex-
periments 1 and 2 (no ash). These results are to be expected,
since the neutral character of the material from Plant 1 indicates
that any corrosion inhibiting value which it exhibits is likely
to be the result of physical rather than chemical factors.
733
-------
,ROTOMETER
ROTOMETER
ROOM AIR
3 x 3/4 IN. DIA x 6 IN. DRYING
TUBES WITH 8-MESH DRIERITE
CHARCOAL TEST
METER
MAGNETIC STIRRERS AT LOW SPEED
(=120 rpm)
HEATING
TAPE
THERMOCOUPLE
LEAD
THERMOSTATED
H-,0 BATH
MIST ELIMINATOR
"^THERMOCOUPLE
, THERMOMETER
ROOM AIR
VACUUM PUMP
•STEEL DISC
3640-304
Figure 315. Schematic diagram of apparatus used in corrosion
experiments.
734
-------
TABLE 53. CORROSION RATE EXPERIMENTS
II 2 SO,,
Vapor Condensate
Temperature, °C
Experiment Generator, Duration Composition
No. % Acid Used Ilr Wt % H2SOi. Gas
1 104
2 104
3 104
4 104
5 107
6 107
7 107
8 107
9 107
] 0 107
2
1
2
2
1
1
1
]
1
1
.0
.9
.1
.0
.0
.0
.0
.0
.0
.0
56 195
52 193
198
212
36 176
40 190
198
200
199
198
(383)
(379)
(388)
(412)
(349)
(374)
(388)
(392)
(390)
(388)
Water
Bath
25
29
26
26
2.8
3.9
2.8
2.8
2.2
3.9
(78)
(84)
(79)
(79)
(37)
(39)
(37)
(37)
(36)
(39)
HaSO,,
(°F) Condensate
Disc
Surface
--
--
--
—
32
25
35
30
30
27
—
--
--
—
(90)
(77)
(95)
(86)
(86)
(81)
Rate
meg/hr
--
1 .
1.
1.
P *
6.
10.
8.
12.
12.
3
5
6
0
0
1
6
4
4
Apparent Corrosion Rate
rng/hr
1.05
0.90
0.20
0.40
32
32
18
17
53
41
meg/hr"
0.056
0.048
0.011
0.022
1.7
1.7
0.97
0.91
2.8
2.2
nuls/yr
46
39
17a
34a
1400
1400
790
740
2300
1800
H2SO.,
Reacting
Ash With Disc
Layer
None
" None
Basic
Neutral
None
None
Basic
Basic
Neutral
Neutral
Wt %
—
3.7
0.7
1.4
34
28
10
11
23
18
a. Based on exposure of one side of disc to acid rather than both sides as in all other runs.
b. Assuming formation of Fe2(SOi,)3.
-------
High corrosion rates were obtained in Experiments 5 through
10 due to increased acid condensation rates and decreased conden-
sate composition. The high percentage of H2SOu reacting with the
disc in these experiments is an indication of the greater corrosive-
ness of acid in the 36 - 40 wt % range. Some difficulty was en-
countered in maintaining constant experimental conditions, as
indicated by variations in the disc surface temperatures and the
acid condensation rate's. Once again, the data suggest that the
neutral ash has little corrosion inhibiting value, but signifi-
cantly lower corrosion rates were obtained with the basic ash.
In contrast to the conditions of Experiment 3, an excess of acid
was present with respect to the base content of the ash layer for
Experiments 7 and 8. If it is assumed that the same amount of
base reacts per unit weight of basic ash in both sets of experi-
ments, it can be shown that less than 30% of the condensing acid
could have been neutralized in Experiments 7 and 8. The principa,
mechanism by which corrosion rates were reduced in Experiments 7 .
and 8 appeared to be the formation of a cement-like deposit which
reduced the amount of acid reaching the metal surface. Such de-
posits would be likely to cause plugging of air heater elements
in plant operation.
Generalizations concerning the direct effect of basic and
neutral fly ashes on corrosion rates from these experiments are
hazardous because of the complex nature of the corrosion process.
However, it is possible to draw some conclusions regarding the
interaction of the fly ash with condensing acid.
The reduced corrosion rate obtained in Experiment 3 indicates
that the basic fly ash from Plant 6 neutralized a major portion
of the acid a_s .it condensed. This is an important observation
because the data obtained has revealed the presence of unreacted
acid on the surface of fly ash containing amounts of water soluble
base substantially in excess of the apparent surface acidity. Thus,
basic ash deposited on metal surfaces could conceivably present an
acidic, and hence corrosive, environment to a metal surface and
exhibit little or no neutralizing capability. A layer of CaSOi, ,
formed by reaction between H2SOi, and CaO, apparently can prevent
the underlying soluble base from being utilized. The ash from
Plant 6 contained appreciable sulfate when received from the pre-
cipitator hoppers (1.2%), but the experimental data presented here
indicate that the sulfate did not present an impermeable barrier
to the liquid condensate.
The neutral ash from Plant 1 would not be expected to pro-
vide a significant degree of protection from condensing acid, and
the experimental data tend to confirm this. However, even a
neutral ash can reduce the amount of acid available for corrosion
in a flue gas by adsorbing SOa. The small amount of sulfate (0.31%)
present on the ash from Plant 1 when received indicates that some
adsorption of SO3 at high temperatures occurred. The operating
temperature of the precipitator at Plant 1 is about 160°C (320 F),
which is well above the HaSOi, dew point.
736
-------
In conclusion, then, the data from these experiments indicate
that a basic ash such as that from Plant 6 can be of significant
value in neutralizing condensed acid and reducing air heater cor-
rosion rates. However, in the presence of an excess of condensing
acid, serious deposit formation problems could be expected. The
neutral ash was of little or no apparent value in reducing corrosion
rates, but it exhibited a lesser tendency to form cement-like
deposits than did the basic material. The most important benefit
to be expected from the presence of a basic fly ash from the stand-
point of corrosion is the consumption of SO 3 by the basic material
in the high temperature region prior to the air heater. Unfortunately,
this also creates a high resistivity problem for precipitators op-
erating in the 148°C (300°F) range.
SUMMARY OF FIELD EXPERIENCE AND PLANT DATA292
Table 54 is a compilation of available data from a number of
power plants concerning fly ash, flue gas and coal composition, and
fly ash resistivity. The data reported in this table were either
obtained by SoRI personnel under Contracts CPA 70-149 and CPA 70-166
sponsored by the U.S. Environmental Protection Agency or made avail-
able to SoRI by the utility companies.
Of all the plants listed in Table 54, only Plants 10 and 9
have experienced significant air heater corrosion problems. As the
following discussion will indicate, the factors that result in
high resistivity fly ash usually indicate that no corrosion pro-
blems are to be expected.
The ash samples for which analyses are given in Table 54 were
either collected from the precipitator hoppers or obtained with a
resistivity apparatus at the precipitator inlet. The values of
pH and free acid obtained in a 95% ethanol slurry, which are given
for selected samples, are an indiation of acid present on the sur-
face of the ash. Samples which show an acidic pH in 95% ethanol
generally exhibit a minimum pH in water, followed by a rise to a
basic equilibrium value as fehe water soluble base is dissolved.
The presence of significant amounts of unreacted acid on the ash
surface is thought to be an indication that the fly ash has been
"conditioned" by sulfuric acid.
- SOa were obtained by SoRI personnel using
procedures described elsewhere.319 Resistivity data were also
obtained by SoRI using either a point-plane or cyclone resistivity
apparatus, with the exceptions of Plants 6 and 11. For these two
plants, the data were given to SoRI by the operating utilities.
Plant 6 has successfully overcome a high dust resistivity
problem by lowering the precipitator operating temperature to
about 104 °C (220°F) at full load. An inspection of the low temper-
ature zone of this installation was conducted while the unit was
off the line for routine maintenance. This plant had nine months
of operation with low gas temperatures.
737
-------
TABLE 5-1 .
PROPERTIES OF FLUE GAS AND Ft,Y ASH
FOR VARIOUS COAL-FIRED BOILERS
Fly Ash Analysis
Flue Gas Analysis
Coal Analysis
Water Slurry
(Dry Basis)
Plant Sulfur
Designation
6 0.
1.
1 0.
2a 0.
11 0.
8-3a 0.
5 0.
1.
7a 2.
4 3.
9a,b ,3
10a'b 3.
%
7-
0
6
5
5
5
95-
90
1
6
5
2
Ash
%
8.5
12
5.9
15-25
8.6
15.8-
16.0
21.9
16.4
~14
11.2
p!l
12.2
Sol base
as CaO
%
7.6
Sol
1.
8.2 Negligible 0.
11.1
11.2
9.4
9.4
5.1
11.0
9.8
6.4
2.10
1.50
0.35
0.19
0
1.65
0.35
0
1.
0.
0.
0.
0.
0.
0.
1.
0.
Ethanol Slurry Precipitntor Inlet
F-'roc acid
(Wet Basis)
SOu as HjSOt, SO2 HjSCK vapor II?O Typical Fly Asft Resistivity
% pH ? vol ppm
2 >9.1 0
23 4.6 0.008 375
50 8.1 0 387
17
77 -- — 365
41- — — 610-
47 1030
36 -- -- 1650
77 3.8 0.037 2680
15 3.9 0.088
40 4.4 0.02
vol ppm vol *
10.7 1
1
<1 7.7 1
'I 8.93
4
<1 7.71
0.8- 7.0 3
4.4 1
8.7 5.7 1
2
15 8.0 1
j^
— —
Si-cm
.9
.0
.9
.8
.5
.0
X
.5
.0
.0
.0
.0
X
X
X
X
X
X
10
X
X
X
X
X
— —
10"
10'°-
1012
101?
10"
1012
1 1 _
1012
10"
10"
1010
10'
temp
150
104
160
135
110
154
124-
160
160
149
142
143
_ —
c CF)
(302)
(220)
(320)
(275)
(230)
(309)
(256-)
(319)
(319)
(300)
(287)
(290)
"
a. Precipitat.or preceded by mechanical collector.
b. Corrosion of air heater has occurred.
-------
The areas examined for evidence of corrosion were the cold
and intermediate zones of the air heater elements, the plates and
wires in the precipitator, and the sides of the duct encompassing
the precipitator assembly. No evidence of corrosion was found in
the air heater elements. Thin deposits were noted in some areas
ofthe cold-end elements, but these were insufficient to cause
measurable draft losses. Minor corrosion was observed on the
perforated plate distributors at the precipitator inlet. The
rusted areas corresponded to regions of low gas velocity caused
by duct geometry. The only significant corrosion in the entire
assembly was found on the under side of the top plate of the
precipitator housing. The top side of this plate is exposed to
streams of low temperature bleed air from the plant exterior,
and it is probable that temperatures below the wa-.er dew point
were reached. The purpose of the bleed air is to maintain a
positive pressure for prevention of dust buildup on the rapper
bushings.
There as no direct measurement of SO 3 at Plant 6, but mea-
surements from Plant 2, which us-es a similar fuel, show that SOs
levels above and below the air heater are less than 1 ppm. The
soluble sulfate content of fly ash taken from the precipitator
hoppers of Plant 6, if a dust concentration of 3.4 gm/m (1.5
gr/ft3) is assumed, is equivalent to an SO3 concentration of 10
ppm. It is possible, however, that a 'portion of the sulfate
originated from oxidation of S02 on the ash surface rather than
from SO3 in the bulk gas phase. Figure 303 shows that the dew
point of a flue gas with 10 ppm SO3 and 10.7% water vapor is
estimated as 135°C (275°F). The minimum cold end average
temperature of the air heater at Plant 6 is 60°C (140°F). It
is therefore probable that some acid condensation, and possibly
corrosion, would have occurred if the basic ash had not been
present to combine with the SO3 in the high temperature zone
prior to the air heater, thus preventing the formation of HaSOi*
vapor in the air heater region. Furthermore, the data in Tables
52 and 53 and the lack of surface acidity indicated in Table 54
show that any HaSOt, which may form in the air heater region is
likely to be neutralized.
In view of the known dependence of fly ash resistivity on
temperature and the presence of H2SOt, on the fly ash surface,
the hypothesis of negligible H2SOt, in the low temperature zone
at Plant 6 may seem inconsistent with the decrease in resistivity
with temperature which occurs at this installation. This apparent
inconsistency can be qualitatively resolved by attributing the
resistivity behavior to increasing adsorption of water vapor on
the fly ash surface with decreasing temperature. It is also
possible that oxidation of SOa to SOs occurs on the ash surface,
and provides surface HzSOi^ for conditioning for a brief time
period, after which the acid is neutralized. The following re-
action sequence may be used to represent this hypothesis.
739
-------
so2(g) + ho2 (g) + so3(g)
SO3(g) + H20(g) + E2SOn (g) --*• H2SO!, (1)
H2SCMg or 1) -f CaO(s) -*• CaSOu(s) + H20(g)
Thus, by adsorption of. water and/or surface formation of S0s,~it
is possible to explain the lowering of resistivity with decreasing
temperature in the absence of appreciable SOs concentrations in
the bulk gas phase.
Plant 11 and Plant 10 are the other plants listed in Table
54 with lowered cold-end temperatures. Plant 11 operates with
a low sulfur coal which produced a highly basic fly ash with a
high resistivity. No corrosion problems have been experienced at
this installation, as would be expected. Precipitator inlet
temperatures range from 110-122°C (230-253°F).
Plant 10 has operated with precipitator inlet temperatures
from 108-118°C (228-246°F). Excessive deterioration of air heater
cold end elements occurred when gas temperatures were lowered to
108°C (228°F), and as a result, operating temperature has now been
raised to 117-118°C (243-246°F). The reason for lowering the exit
temperature was said to be a desire to increase boiler efficiency
rather than a need to lower fly ash resistivity. Fly ash and coal
samples supplied to SoRI were analyzed and are reported in Table
54 * However, the sulfur content of the coal normally used was
reported by the utility to be 1.2-1.35%. Analysis of the fly ash
indicates a neutral ash similar to that from Plant 1, and little
or no acid neutralizing ability would be expected,. The low sulfate
content indicates that, in spite of the high sulfur content of the
coal and the relatively low temperature at which the ash was col-
lected, a comparatively small amount of H2SOi, is collected by the
ash. From the ash content of the coal, the mass loading at Plant
10 is estimated, prior to the mechanical collector, as 6.9 gm/scm
(3 gr/scf),326 and the sulfate content of the fly ash is equivalent
to only 6.4 ppm HaSOu- It is therefore probable that most of the
H2SOi» formed from the combustion of this relatively high sulfur-
coal remained in the gas phase and was available for condensation.
Although there'are no resistivity measurements from Plant 10,
it is possible to infer from the coal and fly ash analysis that
a low resistivity fly ash (significantly less than 2 x 1010 fl-cm)
is probable at this installation at the precipitator operating
temperatures. It has been shown from studies of H2SOi, conditioning
under EPA Contract CPA 70-149 at Plant 1 that a sulfate gain of only
0.1-0.2% due to adsorption or condensation of H2SOu is sufficient
to lower resistivity by two orders of magnitude for a neutral fly
ash.3263
Plants 9 and 4 normally operate with a high sulfur coal, and
typical air heater exit temperatures for both units range from
740
-------
135-140°C (275-285°F). These plants have low fly ash resistivities
at normal operating temperatures, and at times the resistivity value
at Plant 4 has been too low for proper precipitator operation with
high gas velocity. The cold-end portion of the air heaters at
bojth of these installations operates below the acid dew point, but
the corrosion experience has been somewhat different. Plant 4 has
an average cold-end temperature of about 93°C (200°F), and Figure
303 shows that most of the H2SOi» vapor is available for condensation
at this temperature. Furthermore, measurements of SO3 before and
after the air heater have indicated, on at least one occasion, a
significant drop in SO3 concentration across the heater. It is
therefore probable that significant amounts of HaSCK are condensed,
either on the ash in the cool boundary layer adja?ent to the metal
surface, or on the metal surface itself. In spite of this fact,
the cold-end baskets (made of low-alloy steel) have been in service
for at least ten years at Plant 4 without requiring replacement.
Table 54 shows that the fly ash at this unit is highly basic, and
would be expected to have significant acid neutralizing ability.
However, the presence of surface acidity, as indicated by data
obtained in a 95% ethanol slurry, suggests that a sulfate layer
on the ash is preventing a portion of the water soluble base from
being utilized.
Plant 9 has required some replacement of cold-end air heater
elements, but not at an excessive rate. The data in Table 54
indicate that the fly ash from Plant 9 is less basic than that
from Plant 4, but the presence of a mechanical collector at Plant
9 makes a direct comparison of the two fly ash analyses difficult
because of the difference in particle size distribution. It is,
however, reasonable to conclude that without the presence of the
basic fly ashes at both installations, corrosion would have been
more severe.
Plant 7 operates at high air heater exit temperatures with
an intermediate sulfur coal. The resistivity values indicated
in Table 54 for this plant would be classified as high, but the
near-neutral character of the ash, together with the presence of
appreciable concentrations of HaSOi* vapor in the gas pnase and
the slope of the resistivity temperature curve, suggest that
acceptable resistivity values would occur at about 137°C (280°F).
With an 26°C (80°F) inlet air side temperature, this would give
a cold-end average of 82°C (180°F) for the air heater. The Air
Preheater Company's cold-end temperature and material selection
guide gives a suggested minimum average cold-end temperature of
about 71°C (160°F) for a coal of 2.1% sulfur content and corrosion-
resistant, low-alloy steel cold end elements.327 Some degree of
corrosion may occur because the cold-end metal temperatures fall
appreciably below the acid dew point, and because the neutral ash
at Plant 7 could be expected to have no significant acid neutralizing
ability. However, the experience of the Air Preheater Company as
represented by their materials and temperature guide, and the lack
of excessive H2SOi,. vapor concentrations found at 148-160°C (300-320°F)
741
-------
are indications that a severe corrosion problem should not occur
at Plant 7 with the presently used fuel if air heater exit tem-
peratures as low as 137°C (280°F) were employed.
The corrosion experience of Plant 5 (Unit 1) is of interest
because the average air heater exit temperature is about 126°C
(260°F). Sulfur content of the coal normally burned at this unit
is approximately 1%, and a typical dust load would be 8.5 gm/scm
(3.7 gr/scf). Coal composition varied during the time period in
which resistivity data were taken, and possibly as a result, the
resistivity data show considerable scatter and no strong variation
with temperature. Nonetheless, the relatively high resistivity
values are to be expected on the basis of the co=l sulfur content
and the moderately basic character of the fly ash. No corrosion
problems have occurred at this unit, and none would be expected
with the relatively low f^SOi, vapor concentrations which were
measured.
Plants 8-3 and 2 are typical of installations burning very
low sulfur coal; that is, no appreciable HzSO^ vapor concentrations
are found in the bulk gas phase, the fly ash produces a basic water
slurry, and the resistivity is unfavorably high in the normal oper-
ating temperature range of 135-148°C (275-3005F) .
If the design of these plants were such that operation in the
104-115°C (220-240°F) range were possible, no corrosion problems
would be expected because of the absence of H2SOi* vapor. Unfor-
tunately, there is not a sufficient quantitative knowledge of the
relationship between resistivity and temperature to predict with
confidence that low temperature operation at these installations
would produce resistivity below the critical value of 2 x 1010 fl-cm.
The fact that the flue gas water concentrations at Plants 2 and 8-3
are about 30% "lower than that at Plant 6 is an unfavorable condition
for achieving lowered resistivity. However, the fly ashes from
Plants 2 and 8-3, and in particular, that from Plant 8-3, are less
basic than the ash produced at Plant 6. Data obtained under Con-
tract CPA 70-149 indicate that a highly basic ash requires a
greater gain of HzSOu, either by condensation or adsorption, to
lower resistivity than does a neutral ash. Thus, if lowering of
resistivity is due to the combined effects of water adsorption and
the formation of SO3 on a fly ash surface discussed earlier, it
could be argued that the resistivity of the extremely basic ash
of Plant 6 would show less sensitivity to decreasing temperature
than the fly ash at Plants 2 and 8-3. Since the variables of ash
composition and flue gas water concentrations indicate opposing
effects when comparing Plant 6 with Plants 2 and 8-3, it would
be hazardous to equate the resistivity-temperature experience of
Plant 6 with the other two installations.
METHODS OF ASSESSING CORROSION TENDENCIES OF FLUE GASES
Introduction
742
-------
A comprehensive discussion of methods developed in England
for assessing the corrosion and fouling potential of flue gases
is given in a bulletin entitled, "Testing Techniques for Deter-
mining the Corrosive and Fouling Tendencies of Boiler Flue Gases"
published by the Boiler Availability Committee.318 The following
discussion is a brief summary of the purpose and method of oper-
ation of those procedures which relate to low temperature corrosion
and fouling.
Corrosion Probes
The purpose of corrosion probes is to measure the amount of
corrosion produced by acid condensed on metal surfaces in a flue
gas environment. These probes provide a means of supporting a
prepared metal test specimen in flue gas streams at a selected
temperature. The BCURA probe is an air-cooled device in which
the surface temperature of the test specimen is monitored with a
thermocouple brazed to the body of the probe. Exposure periods
of 15-30 minutes are recommended, and the amount of corrosion is
determined by measuring weight loss of the specimen.
Probes designed for short term experiments are of value for
comparing relative effects of variations in operating parameters,
such as temperature and fuel composition. However, for prediction
of actual corrosion rates over extended periods, long term tests
of 100 hours or more are desirable. A liquid-cooled probe has
been designed by the Sheel Petroleum Company, Ltd., for such ex-
tended exper iment s.3 2 8
Acid Deposition Probes
An indirect measurement of the rate of acid deposition on a
cooled surface is given by the BCURA dew point meter, which has
been described previously. Since the conductivity readings of
the dew point meter can be influenced by substances other than
sulfuric acid, it is of interest to consider a direct means of
measuring acid deposition rates.
Alexander329 has described an air-cooled deposition probe
which accomplishes this purpose. The probe consists of an air-
cooled, one-inch diameter stainless steel tube in which the cooling
air passes through the tube and discharges into the flue gas. The
amount of acid depositing on test areas of the probe, the surface
temperature of which is known, is determined by analysis of de-
posits obtained from the test surfaces.
Gas And Ash Analysis
An analysis of flue gas for SOa, S02, HzO, and dust loading,
along with analysis of the fly ash for soluble components, is
necessary for a qualitative assessment of the flue gas corrosion
potential. Procedures used by SoRI for these analyses are described
in the final report from Contract CPA 70-149.319
743
-------
SUMMARY AND CONCLUSIONS
It has been established that the principal cause of corrosion
in the low temperature zone of power plant exhaust systems is
condensation of sulfuric acid, either directly onto metal sur-
faces or onto fly ash particles which subsequently come in contact
with the metal. Other, acids, in particular hydrochloric acid, can
be responsible for corrosion at temperatures approaching the water
dew point of flue gas, but such temperatures are not normally en-
countered.
Fouling in the low temperature zone of air heaters is primarily
caused by reaction of sulfuric acid with fly ash -jnd the metal
surfaces of the heat exchanger. A basic fly ash ::an neutralize
appreciable quantities of S03 upstream from the air heater region
but laboratory experiments suggest that reaction of highly basic
fly ashes with high concentrations of EzSO* in the low temperature
zone can result in problems with deposit formation. This conclusion
is supported by the experience of the Central Electricity Generating
Board of England, in which medium sulfur coals with alkaline ashes
have produced fouling,330 but little air heater wastage accompanied
the deposit formation. It is also possible to have deposit for-
mation in the low temperature zone in the absence of sulfuric acid
if excessive moisture from steam leaks or soot blowing is present.
Severe corrosion and fouling problems in regenerative air
heaters are associated with the temperature at which peak rates
in acid deposition occur. These peak rates often are not observed
with coal firing due to the presence of fly ash, but in any case,
the existence of such a peak is a manifestation of relatively
high concentrations of free H2SOt4 vapor. Thus, the resistivity
of fly ash, due to the presence of excessive H^SOi,., would be ex-
pected to be lower than desirable for proper precipitator operation
with high gas velocity under these conditions. Resistivity data
taken at plants burning high sulfur coals with alkaline fly ashes
have demonstrated that resistivity values below the critical 2 x
1010 il-cm are obtained at temperatures above 137°C (280°F). There-
fore, lowering precipitator operating temperatures is neither
necessary nor desirable for the case of high sulfur coals, which
produce relatively high concentrations of H2SOi, vapor.
An analysis of the factors which cause corrosion, and the
operating experience of at least two power plants, have demonstrated
that low temperature operation of precipitators [104-121°C (220-
250°F)] will not cause low temperature corrosion and fouling pro-
blems with a flue gas containing a basic fly ash and no appreciable
concentrations of sulfuric acid vapor. The occurrence of corrosion
and high fly ash resistivity thus tend to be mutually exclusive
phenomena. A possible exception to the rule would be a stack gas
with high (over 100 ppm) HCl concentration.
For the case of a plant burning a low to medium sulfur coal
which produces a near-neutral, high resistivity ash at approximately
744
-------
148°C (300°F) and low concentrations of H23Oi, vapor, the occurrence
of some degree of corrosion as a result of lowered cold-end tem-
"\ peratures cannot be rigorously excluded. However, data obtained
hav^ shown that amounts of sulfuric acid sufficient to "condition"
a neutral ash can he. adsorbed at temperatures >-',.-!i above the
sulfuric acid, df.v; pr.inr,31* It is ther^v.v,;, ..;.:ooai'.l.= that an
acceptable fly a^ :.-; ' j' .',-• j i:y could Lc ,, .,,,;.,c,d <•> t -A temperature
sufficiently high to avoid appreciable coruicausation of sulfuric
acid on the cold-end elements of an air prehsater. A quantitative
evaluation of resisrivity and corrosion under such circumstances
would require fly ash resistivity data and relative corrosion rates
(obtained with a corrosion probe such as described earlier) as a
function of temperature in the flue gas.,
'45
-------
TECHNICAL REPORT DATA
P'cssf read luarjcituns 01 the re\ene setorr comnicrng
EFA-600/8-80-025
12
!3 RECIr '
CC = SS>O*i NC
- TITLE AND SJSTITI.E
A Manual for the Use of Electrostatic Precipitators
to Collect Fly Ash Particles
(5. REPORT DATE:
iMav 1980
jo PERFORMING ORGANIZATION CODE
~ AL'Tl-iORIS/
Jack R. McDonald and Alan. H. Dean
£ PERFORMING ORGAN, C
REPORT IMC
SORI-EAS- 80-066 (3540-7)
9 PERFORMING ORGANIZATION NAME AND ADDRESS
Southern Research Institute . .
2000 Ninth Avenue, South
Birmingham, Alabama 35205
10. PROGRAM Ei-EMENT NO.
EHE624
111 CONTRACT/GRANT NO.
168-02-2114, Task 7
12 SPONSORING AGENCN NAWE AND ADDRESS
EPA. Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park. NC 27711
na. TYPE o^ REPORT AND PERIOD COVERED
|Task Final; 12/78-2/80
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTES IERL-RTP prolect officer is Leslie E. Sparks, Mail Drop 61,
919/541-2925.
r£ incorp0rates the results of many studies into a manual oriented
toward the collection of fly ash particles (produced by the combustion of pulverized
coal) by electrostatic precipitation (ESP). It presents concepts, measurement tech-
niques, factors influencing ESP performance, data, and data .analysis from a prac-
tical standpoint. Extensive use of data from full-size ESPs should familiarize the
user with what to expect in actual field operation. The manual covers fundamentals
of ESP, mechanical and electrical components of ESPs, factors influencing ESP per-
formance, measurement of important parameters, advantages and disadvantages of
cold-side, hot-side, and flue -gas -conditioned ESPs . safety aspects , maintenance.
troubleshooting, the use of a computer model for ESP, and features of a well-
equipped ESP. Studies considered in this report include those,, by various individ-
uals and organizations, on comprehensive performance evaluations of full-scale
ESPs, in situ and laboratory measurement of fly ash resistivity, rapping reentrain-
ment, evaluations of the effects of flue gas conditioning agents on ESP performance,
fundamental operation of hot-side ESPs, basic laboratory experiments, and develop-
ment of a mathematical model of ESP. Information from these studies can be used
by power plant personnel to select, size, maintain, and troubleshoot ESPs.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
COSATI 1 icid'Groap
Pollution
Electrostatic Precipitation
Fly Ash
Measurement
Maintenance
Mathematical Models
.Electrical Resistivity
Pollution Control
Stationary Sources
Operation
Troubles hooting
13B
13H
21B
14B
15E
12A
20C
13 DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (Tnu Report/
Unclassified
I 21. NO. Or F-AGES
i 782
20 SECURITY CLASS (Thupagef
Unclassified
22. PRICE
EPA Form 2220-1 (9-73J
746
-------