-------
firing reduced Morgantown No. 1 NOX emissions by 27%. Comparison of
normalized baseline NOX emissions of these 3 boilers with the four
tangentially fired boilers from our previous program (2) shows an
18% NOX reduction due to cooling air.
The ranges of NOX emissions measured under normal firing
operation as a function of excess air level (% 02 in flue gas) are
shown in Figure 4-1. The code letters identifying the power station
and boiler numbers are as follows:
Code Letters
WC
M
C
G
N
B
Station
Widows Creek
Morgantown
Comanche
Ernest C. Gaston
Navajo
Barry
Boiler No.
5
1
1
1
2
2
As discussed in section 3.1, excess air level had a significant
effect on the level of NOX emissions from each boiler under normal firing
operation. These NOX vs % 02 relationships are shown in Figure 4-1. With
the exception of Comanche No. 1 unit, (which had limited excess air level
operating flexibility) the slopes (calculated by least squares) of these
lines are fairly consistent. However, the average NOX levels vary
because of boiler size, type of firing, type and composition of coal
fired, etc.
Figures 4-2 and 4-3 have been prepared to show the overall
relationship between NOX emission levels and excess air level (% Q£ in
flue gas, on a consistent basis for normal firing and modified firing
operation for the six coal fired boilers tested to date in this program.
Figure 4-2 is a plot of "normalized" NOX emissions expressed
as a % of baseline NOX emissions (full load and 20% excess air) vs
average % 02 measured in the flue gas for normal firing conditions.
The solid lines shown for each boiler are based on the least-squares,
linear regression analysis of all full load, test runs made under
normal firing operation (all burners firing coal and with closed
overfire air ports). With the exception of the Comanche boiler
mentioned above, all of the lines fit within a relatively narrow band.
Figure 4-3 is a plot of "nprmalized" NOX emissions (expressed
as a % of baseline NOX emissions at full load and 20% excess air) vs
average % oxygen measured in the flue gas for modified firing conditions.
Thus, the ordinates are identical in Figures 4-2 and 4-3. However, the
IV-97
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700
FIGURE 4-1
PPM NOX VS % OXYGEN IN FLUE GAS
(NORWL FIRING - COAL FIRED BOILERS)
600
500
400
CM
O
->< 300
200
100
O REAR WALL FIRED
D OPPOSED WALL FIRED
A TANGENTIALLY FIRED
93% COAL ~ 7% OIL MIXED FUEL FIRED
_J I I I
234
AVERAGE % OXYGEN IN FLUE GAS
IV-93
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C/)
O
CD
CS
LU
ff
CD
Uu
a
a:
CO
CO
CO
I—»
ixl
o.
o
O
00
Sen
LU
fy ey
IT LL
-I >-
a
CO
e
CL
O
o
VD
I
1
XOH (dIV SS30X3 XOZ) 3NI13SVa JO
IV-99
-------
UJ
W5
UJ i
BC.CC
-------
least squares regression lines of Figure 4-3 do not necessarily pass
through the 100% normalized NOX point at 3.6% oxygen, as they must
by definition in Figure 4-2.
Figure 4-3 indicates the importance of low excess air firing
on NOx emissions when operating under modified firing conditions such
as staged firing. The slopes of these lines are very similar except
for Morgantown No. 1 (which fired a mixture of coal and oil) and
Barry NOO 2 unit (with overfire air ports relatively far from the top
row of active burners). It should be noted that all of the boilers
tested had baseline NOX emission rates above the normalized (20% excess
air) levels used in Figure 4-3 and that optimized, modified firing
operation generally produced lower NOX operation than shown by the
least squares lines. Thus, the improvement from low excess air,
modified firing operation compared to actual baseline NOx emission
levels averaged 38% vs the 26% shown in Figure 4-3. An additional
point to recall is that three of these boilers are equipped with
overfire air ports which produced an 18% reduction of normalized
baseline NOx emission from the tangentially fired boilers tested in
our last program (2).
Initial studies on mixed fuel fired boilers indicate that
NOx emission levels increased as the % of coal in the coal-oil or
coal-gas mixture increased. However, the relationship was not linear.
We plan to test additional units to firm up the relationship.
A large (50 MW rated) General Electric gas turbine has been
tested under normal operating conditions while firing fuel oil. NOX
emissions were about 375 PPM at full load, 400 PPM at peak load (54 MW)
with reductions to about 325 and 250 PPM at 50% and 20% of full load
operation, respectively.
4.2 Side Effects of Combustion Modifications
As discussed in Section 3, the modified combustion techniques
studied for controlling NO emissions have not produced major adverse
side-effects in short-term, 300-hour sustained tests. In other words,
furnace wall corrosion, particulate mass loading and size distribution,
carbon on fly ash, and boiler efficiency have not changed significantly
when comparing "low NO " operation with baseline conditions. Long-term
demonstration is required to validate these conclusions.
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5. REFERENCES
1. W. Bartok, A. R. Crawford and G. J. Piegari, "Systematic Field
Study of NOX Emission Control Methods for Utility Boilers," Esso
Research and Engineering Company Final Report No. GRU.4G.NOS.71,
NTIS Report No. PB 210-739, December 1971.
2. A. R. Crawford, E. H. Manny and W. Bartok, "Field Testing:
Application of Combustion Modifications to Control NOx Emissions
from Utility Boilers," Exxon Research and Engineering Company,
EPA Report No. EPA-650/2-74-066, June 1974.
3. Environmental Protection Agency, "Standards of Performance for
New Stationary Sources," Method 5, Published in the Federal Register,
December 23, 1971, Vol. 36, Number 247, p. 24888.
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ACKNOWLEDGMENTS
The authors wish to acknowledge the constructive participation
of Mr. R. E. Hall, EPA Project Officer and Mr. R. C. Carr of the Electric
Power Research Institute, co-sponsors of this program, in planning the
field test programs and providing coordination with boiler operators
and manufacturers. The assistance and cooperation of the General
Electric Company and Westinghouse Electric Company personnel in
coordinating the selection of gas turbines for testing is also
appreciated and gratefully acknowledged. The helpful cooperation,
participation and advice of the major U.S. utility boiler manufacturers,
Babcock and Wilcox, Combustion Engineering Inc., Foster Wheeler Corp.
and Riley-Stoker Corp. have been essential in selecting representative
boilers for field testing and conducting the program. The voluntary
participation of electric utility boiler operators in making their
boilers available is gratefully acknowledged. These boiler operators
include the Southern Electric Generating Company, the Alabama Power
Company, the Tennessee Valley Authority, the Potomac Electric Company,
the Salt River Project and the Public Service Company of Colorado. The
authors also express their appreciation for the extensive coal analyses
services provided by Exxon Research's Coal Analysis Laboratory at
Baytown, Texas and to Messrs. A. A. Ubbens and E. C. Winegartner for
their contributions and advice on coal related matters. The invaluable
assistance of Messrs. L. W. Blanken, R. W. Schroeder, W. Petuchovas,
and Mrs. M. V. Thompson in these field studies is also acknowledged.
LEGAL NOTICE
This report was prepared by Exxon Research and Engineering
Company as an account of work sponsored by the Electric Power Research
Institute, Inc. (EPRI), and the United States Environmental Protection
Agency (EPA). Neither EPRI, members of EPRI, nor Exxon Research and
Engineering Company, nor any person acting on behalf of either:
a. Makes any warranty or representation, express or implied,
with respect to the accuracy, completeness, or usefulness of the
information contained in this report, or that the use of any information,
apparatus, method, or process disclosed in this report may not infringe
privately owned rights; or
b. Assumes any liabilities with respect to the use of, or
for damages resulting from the use of, any information, apparatus,
method or process disclosed in this report.
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APPENDIX A
CROSS SECTION DRAWINGS OF TYPICAL UTILITY BOILERS
Typical utility boiler designs representative of the types
of boilers tested in this program are shown in the cross sectional
drawings in Figures 1 through 3 of Appendix A. Typical front wall
and horizontally opposed and tangentially fired boilers are shown in
Figures 1, 2 and 3, respectively.
IV-104
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APPENDIX A
FIGURE 1
TYPICAL FRONT WALL FIRED BOILER
1O HtECIPfTATOfl \
AND A
IXDUCED-MMrT FAN I I
lU'-O"
.?
rvTy,^: .-y> *. •••>.. vsp-r,s.'-.- >»";%.. — i ..- ^.v-^^|/y.--.;:.• i/^j.; ^ , ^ Uv-
-J7'-0"-
-32'-0"-
-30'-0"
DRAWING FURNISHED THROUGH THE COURTESY OF
THE BABCOCK AND WILCOX COMPANY
IV-105
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APPENDIX A
FIGURE 2
TYPICAL HORIZONTALLY OPPOSED FIRED BOILER
- JE'-O" — -I- 13-0" -i J5'-0" 1 29'-0" 1 25-0"
- 30-0"-
DRAWING FURNISHED THROUGH THE COURTESY OF
THE BABCOCK AND WILCOX COMPANY
IV- 106
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APPENDIX A
FIGURE 3
TYPICAL TANGENTIALLY FIRED BOILER
S. I^l. T t.r7^.5
DRAWING FURNISHED THROUGH THE COURTESY OF
COMBUSTION ENGINEERING. INC.
IV-107
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APPENDIX B
CONVERS ION FACTORS
ENGLISH TO METRIC UNITS
To
Multiply By*
To Convert From
BTU
BTU/pound
Pounds/BTU
Pounds/hour
Pounds/square inch
Tons (short)
Pounds
Feet
Inches
Inches
Cubic feet
Gallons
0Fahrenheit
* Numbers expressed in power-of-ten notation using E + xx to indicate
the power of ten. For example:
1.055 056 E-06 » 1.055 056 x 10 - .000001055056
Giga joule, GJ
Gigajoule/kilogram, GJ/kg
Kilogram/ gigajoule, kg/GJ
Kilogram/hour, kg/hr
Megapascal, MPa
Metric tons, t
Kilogram, kg
Metre, m
Centimetres, era
Metre, m
( 3
1 Cubic metres, cm
\ Decimetre, dm-*
3
Decimetre, dm
°Kelvin, K
1.055 056 E-06
2.326 000 E-06
A. 299 226 E-07
4.535 924 E-01
6.894 757 E-03
9.071 847 E-01
4.535 924 E-01
3.048 000 E-01
2.540 000 E+00
2.540 000 E-02
2.831 685 E-02
2.831 685 E+01
3.785 412 E+00
(°F + 459.67) 5/9
IV- 108
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8:30 a.m.
The Effect of Combustion Modification
on Pollutants and Equipment Performance
of Power Generation Equipment
Allen R. Crawford and Erwin H. Manny
Exxon Research and Engineering
I would like to suggest that your glancing over the
CO data was, I think, a little bit too cavalier.
I realize that you were addressing yourself to NO
X
primarily but when I see factors of 10 increase in
carbon monoxide...! don't know much about your boilers
but I do know a little bit about data. I think I'd
be a little bit concerned about the "bean bag" effect.
This is something I guess we see in every combustion
system. In your table 4.1, you are talking about a
reduction in NO of about 597 to 305 parts per million,
X
but your CO goes up from 29 to 285. That is not a
small increase. Would you comment?
CO level is probably our best indication of a poor
combustion threshold. A very small change in percent
0 , below the threshold level, can increase CO
levels tremendously. For example, we often have a
condition in which changing flue gas oxygen from,
say,2% down to 1.6% can increase the CO level by
5 to 10 times or from a normal 25 ppm up to 250 to
500 ppm. Consequently, operating near the threshold
level can produce widely varying CO levels. In actual
"low NO " operation, increasing 0, levels by 0.2
X ^
to 0.4% over the threshold level will in most cases
reduce CO down to 100 ppm or lower without increasing
NO levels significantly.
It is also a question of the tradeoff. This is a
question for the OAQPS people to answer, but is that
increase in CO as important as the reduction in NO
that you achieve?
IV- 109
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Generally, in other combustion sources for which we
have gathered data to set standards of performance,
from what our Health Effects people at NERC in North
Carolina say, it is much more important to control
NO and hydrocarbons to lower levels than to control
CO. You can have rather high CO levels. Of course,
in terms of effects, at ground level, it is mass
rated emissions that are important rather than con-
centration. But still, at these low concentrations
you would not expect to even get near an ambient air
quality standard at ground level for CO. Whether
the CO level is 25, 50 to 100 ppm, it is relatively
minor compared to the nitrogen oxides that are of
much more concern. [Answered by Stan Cuffe of EPA.]
Thank you,Stan. Also, I might add that you mentioned
hydrocarbons. Hydrocarbon emissions were so low on
these tests that the values weren't reported in the
tables. But, in general,they were only 1 or 2 parts
per million.
1 haven't had a chance to read your paper too well,
but I don't see any place where you have stated the
sulfur levels of the coal which were being burned
at these stations. That would make a significant
difference as far as the corrosion data is concerned.
Right, this is important. This paper is an interim
report. However, our final report will have complete
gaseous information, as well as coal composition.
We agree with your comment.
One other problem is that this data was a summary
IV-110
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of very recent results, so all the coal analyses are not even
in for the tests. But in the final report they will be.
You can probably surmise from the location of the
station what the approximate level of sulfur is in
the coal. For those of you who are interested in
relative effects of sulfur on the corrosion testing,
I would like to refer you to a previous report that
we published in 1974 on our previous studies,which
covered a rather broad range of western, mid-western,
and eastern bituminous coals as well as a lignite coal.
One can use those results to relate the sulfur levels
of the coals fired with the corrosion rates measured
with the coupons. I think that would probably be a
useful reference to look up.
Q: One thing I noticed between the data that was presented
by TVA yesterday and yours today (it is flipping by
kind of fast so I haven't had a chance to read the papers)
TVA data looked as though it were taken after the ESP.
Your particulate data, I would guess, was taken before,
because you showed a percent efficiency required to
meet a standard,which means that you were taking
data upstream. Aside from the obvious that yours
is going to be much higher in just total mass rate
than theirs, the conclusion about whether more is
going out or not•••really, you have a classifying device
in between there. So this could account for some of
these differences in interpretation of results.
IV-111
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A: We took our particulate tests at the same location
they did and, if you remember, TVA answered your question
indicating that they have a mechanical collector. We
tested ahead of the mechanical collector.
Erv, there is a lot of data here, as a couple of people
have said. Maybe I am just pulling something off
the top, but I noticed that on the figures for Widows
Creek #5, your so-called low NO run really has about
X
the same NO level as the so-called base line. Whereas
x
in TVA's data from yesterday on Widows Creek #5,
they got about a 30% reduction in NO . So, is your
so-called NO run really a low NO run or is it just
xx
base line all over again?
Well, it was really "low NO " type of operation because
X
we were operating the boiler in a staging pattern.
Unfortunately, the oxygen levels did turn out to be
the same for both "baseline" and "low NO " operation.
X
As Al pointed out, the stoichiometric air at the active
burners with staged firing would be less than under
baseline operation because we did have burners out
of operation and on air only.
Q: As one of the few operators represented here at this
symposium, I would just like to add a comment more
than a question, and a plea for some of this longer
term corrosion data. Corrosion is a very subtle
phenomenon in a coal fire boiler. The often-mentioned
difficulty is getting test candidates because of fears.
IV-112
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And these are very real conditions. We have had
identical boilers, identical coal. One of them will
corrode and one will not. It is a very complicated
phenomenon, and long term data is needed.
A: You are right. This program is co-sponsored by
EPRI. They have advertised in their newsletter
asking for candidate boilers. So, if you or anyone
else has a candidate boiler, please let us know.
This type of testing is absolutely necessary. The
corrosion probes were used because it was a short
term, quick means of getting an indication. We won't
really know the answer until we get more actual tube
wall measurement data.
Those are the kind of things I was going to say
yesterday that were in our plans this coming fiscal
year. We would like to initiate an extension of the
corrosion work in terms of a long-term monitoring
operation. The success of that program is going to
depend very heavily on the host sites and just how
intensive a program we can get underway. I think it
is becoming very clear now that we certainly need
to better quantify the effects of these combustion
modifications on corrosion so that we are going to
have all of the facts. I think the jury is still out
on this thing right now,though.
I would like to make just one comment on corrosion.
As you saw in our slides, the corrosion differences
on coupons here were very, very nominal. On our
previous program, we had considerable scatter.
Whenever you do a corrosion probe test you recognize
that it is not a precise thing. If you get the
relatively consistent results such that we have
IV-113
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obtained on the last program, then I think you
doing very well!
are
Q: In your tests where you mix coal and oil, I was
wondering what was the basis for the percentage of
coal and oil. Whether it was Btu's, weight, or just
what?
A: Our basis was the Btu heat release for each fuel.
Q: In connection with the nitrogen, did you measure the
nitrogen in the coal to see whether that was the
contributing factor because you showed an appreciable
reduction as you went to more oil? I was wondering
if perchance that extra nitrogen was coining from the
coal?
A: No coal data is given in the report that you have
because we didn't have complete fuel analysis when
it was written. But we do measure the nitrogen
content and it will be included in the final report.
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ANALYSIS OF GAS-, OIL- AND
COAL-FIRED UTILITY BOILER
TEST DATA
By:
O.W. Dykema
THE AEROSPACE CORPORATION
Environmental and Energy Conservation Division
El Segundo, California
and
R.E. Hall
U.S. ENVIRONMENTAL PROTECTION AGENCY
Industrial Environmental Research Laboratory
Research Triangle Park, North Carolina
IV- 115
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ANALYSIS OF GAS-, OIL- AND COAL-FIRED
UTILITY BOILER TEST DATA
ABSTRACT
This study is being conducted by The Aerospace Corporation in
response to a strong need that exists today for a reliable, useful
analytical tool to guide combustion modifications in full-scale,
multi-burner utility boilers to reduce NO emissions. In the light
X
of today's understanding of the many processes controlling NO for-
A
mation, such an analytical tool must necessarily be semi-empirical.
To be reliable and directly useful it should take into account current
understanding, yet be capable of verification with data from widely
different, full-scale, multi-burner utility boilers.
Such a tool has been constructed, by use of a Zeldovich model
for thermally generated NO , a unique model for the conversion of
X
fuel-bound nitrogen and an approximate flow and mixing model first
to generate an approximate NO prediction equation. The coefficients
X
of this equation were then empirically improved by regression analysis
of data from nearly 600 tests conducted on 16 full-scale, multi-
burner utility boilers burning coal, oil or natural gas fuels in
single wall, opposed and tangential configurations. Parametric
analyses with the resulting semi-empirical equations show the inde-
pendent effects on NO emissions of load, excess air, N0x ports,
burners out of service (number and location), combustion air tem-
perature, boiler cooling rate, weight fraction of nitrogen in the
fuel and combinations of these leading to NO emissions minima.
X
Results can be used directly today as a tool to guide operating con-
ditions and hardware modifications for significant reductions in NO
emissions.
IV- 116
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SECTION 1.
SUMMARY
A semi-empirical tool has been developed which can be useful in
guiding development testing to reach practical minimum levels of NO
X
emissions from utility boilers burning coal, oil or natural gas fuels.
A detailed but approximate model describing the generation of NO in
A
large multiple-burner boilers was used to generate a single equation
which, if all of the processes involved were well known, would be
capable of predicting NO emissions. This qualitative equation, of
X
approximately the proper functional form, was then made quantitative
by regression analyses of large samples of data from a total of 575
tests of full-scale coal-, oil- and natural gas-fired utility boilers.
The details of the development of the equation and results of
application to oil- and gas-fired boilers have been reported in
"Analysis of Test Data for NOX Control in Gas- and Oil-Fired Utility
Boilers", Report No. EPA 650/2-75-012, January 1975. This work
formed much of the basis for the later analysis of coal-fired data.
Since reduction of NO emissions from coal-fired boilers is of great-
est interest today, and the results of that study have not yet been
reported, this paper is directed primarily to coal-firing. A major
modification to the previous work, which was necessary to adequately
analyze coal-fired data, involved improvements to that part of the
model describing the generation of NO from the conversion of fuel-
X
bound nitrogen.
The data sample from coal-fired utility boilers used in this
study showed that minimum emission levels between 250 and 350 ppm
were achieved in each of the boiler firing types (tangential, opposed
and single-wall), with acceptable levels of carbon monoxide emissions.
In general, the lowest levels of NO emissions under full-rated load
IV-117
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from all of the boilers in the sample were achieved with
low-combustion air (windbox) temperatures, with a high moisture coal
involving a low temperature rise due to combustion (e.g., lignite)
and/or with staged combustion by operating 20-25 percent of the
burners on air-only and located in the highest levels of the burner
array.
Parametric studies to explain and extend the effects of a number
of significant parameters on NOV emissions have indicated that levels
X
less than 250 ppm can be achieved by combinations of combustion modi-
fications which result in (1) reduction of the overall boiler excess
air to about three percent excess oxygen, (2) reduction of the effec-
tive excess air in the active burner region to less than 80-85 percent
of theoretical and (3) reduction of the maximum equilibrium combus-
tion temperature to less than about 2200K (3500 degrees F). Results of
the analyses are sufficiently general to indicate that a number of widely
different physical modifications can achieve the above three objectives
and result in further NO reductions.
x
Further testing is required under the operating conditions
representing the minima in the test data used, as well as those
representing further significant NO reductions as indicated by this
X
study to assure the lack of, or to resolve, any undesirable side
effects of operation under these conditions. Potential side effects
include excessive emissions of other air pollutants, excessive loss
in plant efficiency, unstable combustion and excessive tube wall
corrosion or erosion rates. It is side effects such as these, rather
than processes inherent to NO formation, that appear to represent
3C
the most likely limitations on ultimate NO reduction.
X
iv- 11,1
-------
SECTION 2.
DATA ANALYSIS APPROACH
Nearly all technical problems which arise in existing systems
generate a desire to achieve some sort of new operating condition or
situation. If empirical solutions are not readily achieved, and if
there is no great urgency to resolve the problem, the overall
approach can proceed through a sequence of fundamental and applied
research (and screening, developmental and full-scale testing) to an
orderly solution. In each of these steps, experimental data of var-
ious kinds are needed to confirm the solutions of the preceding step
and to feed back new information. If the urgency is great, however,
all of these steps must be undertaken concurrently. In many such
cases, the powerful tool of "cut-and-try", guided by semi-empirical
analytical tools, has created a successful solution in the shortest
possible time.
These semi-empirical tools are usually initiated by using current
technology to develop a rough prediction model. If everything were
known of these processes, experimental data would be necessary only
to confirm the analysis. If this is not the case, at least a directly
applicable, semi-empirical development tool can be generated by using
full-scale data to correct the theoretical prediction model. The
most comprehensive way to convert this imperfect analytical model to
a semi-empirical development tool is to use the theoretical model as
a correlation equation for "least squares fit" or regression analyses
of full-scale data. Such computer analysis of large quantities of
data, in which the significant independent parameters vary over wide
ranges, can correct for deficiencies in the analyses and provide an
equation which, at the very least, explains the existing data.
IV-119
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The problem of excessive NO emissions from utility boilers
X
appears to be a classical one of the urgent type discussed above.
There does not appear to be sufficient understanding of all aspects
of the problem at this time to reasonably expect accurate prediction
of NO emissions from full-scale, multiple-burner boilers, under all
operating conditions, from fundamentals alone. Considering the ex-
treme complexity but major significance of, for example, hydrocarbon/
air/nitrogen combustion and of turbulent flow/reaction phenomena, it
also appears that a fairly long, concentrated research effort may be
necessary before these and other significant aspects of the problem
are sufficiently well understood. It seems likely, therefore, that
a semi-empirical engineering approach such as described above can be
most expeditious in resolving the problem, at least for the immediate
future. While it was not known how successful such an approach might
be, The Aerospace Corporation undertook this effort with the assis-
tance and funding of EPA's Combustion Eesearch Branch, Industrial
Environmental Research Laboratory, Research Triangle Park, N.C.
In general, the approach to development of this semi-empirical
tool involved four steps: (1) development of a general, approximate
model of NO generation in full-scale, multi-burner utility boilers;
Jt
(2) development of a single equation from the model, consisting of a
series of linear terms with only approximately determined coefficients,
to predict NO emissions; (3) regression analyses of large quantities
A
of widely varying data from utility boilers to improve the coefficients
of the prediction equation; and (4) parametric analyses with the
resulting equations, and verification with selected data, to show the
effects of major variables influencing NO emissions.
A
A great deal of detail was involved in setting up the model and
generating the prediction equation. Most of this detail is described
in Reference 1, which reports the study of oil and natural gas fuels.
IV-120
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Figures 1, 2 and 3 show the gross mixing model and the various mixing
zones established for the general wall-fired configurations, and Fig-
ures 3 and 4 show the subsequent modification for tangential boilers.
Mixing in this model is of the so-called "tank-and-tube" type, where
species mixing takes place instantly at the beginning of each zone
and the resulting mixture then flows uniformly through the zone, gen-
erating NO . Although not within the scope of this project, a finite
X
rate gasification and gas mixing model has been developed but, as of
this writing, has not been incorporated in the model.
NO chemistry in the model includes a simple Zeldovich mechanism
X
for thermally-generated NO and a largely empirical model for the con-
X
version of fuel-bound nitrogen. The assumptions were made that
"prompt NO" phenomena, and mechanisms for the destruction of NO , had
only small effects on total NO emissions from these large boilers,
X
compared to the generation of NO from the simple Zeldovich and bound
X
nitrogen conversion mechanisms.
The rough prediction equation initially consisted of 22 terms
describing thermal NO generation in the different mixing zones, one
X
term to account for conversion of bound nitrogen and a constant. The
22 thermal NO terms were subsequently combined in various ways to
X
eight terms. Each of these terms is calculated, in a computer pro-
gram, from a number of highly non-linear functions but appears in the
prediction equation only as a linear term with an approximately
determined coefficient.
Further detail concerning the formulation of the model and the
prediction equation can be found in Reference 1. A report (Reference
2) describing subsequent modifications, improvements and analyses for
coal-fired boilers will be published later this year.
Table 1 summarizes the total data sample used in this study.
Without a finite-rate gasification expression to account for this
major physical difference between the coal, oil and gas fuels, it
IV- 121
-------
was considered necessary to analyze data with each of these fuels
separately. The regression analysis had to be depended upon to
correct the coefficients of the various zones representing series
gasification and mixing for the actual degree of gasification and
mixing in each of these zones.
Table 1 shows a total data sample of 575 test conditions with
coal, oil and natural gas fuels. An additional 70 test conditions
were also reduced and entered into the program, which involved
attempts to shut off the combustion air, or secondary air, to some
burners by closing the air registers. A great deal of effort was
spent attempting to establish the degree of air leakage through these
closed air registers. The effort was finally abandoned and these
tests were deleted from the data sample. It appears that in some
cases this leakage can be appreciable. Conclusions based on a
significant fraction of data from tests with closed air registers can
lead to significant errors. Overall, the effect of deleting these
tests, representing only 11 percent of the total, was minor. For
these same reasons, if at all possible, no data from any source was
entered into the data sample if the air registers on some burners
were partially closed while others were completely open. It is con-
sidered impossible to accurately estimate the distribution of
combustion air to the various burners in such cases.
Analyses of the coals burned in the boilers of this study are
reported in Reference 3. To minimize the work load in calculating
equilibrium combustion temperatures and product species, the seven
coal types fired were reduced to four more general coal types. The
analyses of these synthesized coals are shown in Table 2.
IV-122
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SECTION 3.
RESULTS
Three types of results of this study are presented. Because of
the lack of understanding of the mechanism of conversion of fuel-
bound nitrogen to NO , the formulation and the validity of the term
X
generated in this study to account for NO from this source are
considered results of significant interest.
Secondly, the results of the parametric studies show the inde-
pendent effects of some of the major variables affecting NO emissions.
X
Many of these effects have been observed before and the results of
this study serve only to confirm these previous observations and to
lend credence to this approach. The detailed effects of two-stage
combustion, burners-out-of-service and combustion air temperature in
reduction of NO emissions in full-scale, multiple-burner boilers
X
are considered significant new results and, therefore, primarily
these parametric studies are discussed.
Finally, all of the results of the studies of coal-, oil- and
natural gas-fired utility boiling data lead to some general con-
clusions regarding techniques for minimizing NO emissions from the
A
two general sources: (1) conversion of fuel-bound nitrogen; and
(2) thermal fixation of nitrogen in the air. Application of these
techniques to boilers firing each of these fuels leads to practical
conclusions regarding hardware modifications to yield minimum NO
J\
emissions.
Fuel-Bound Nitrogen Conversion
Details of the development of the model for bound nitrogen
conversion will be available in the forthcoming report cited as
Reference 2. Basically, many observers (e.g., References 4 through
8) have noted that: (1) the conversion efficiency of fuel-bound
IV- 123
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nitrogen to NO at a fixed level of excess air is some inverse
function of the weight fraction of nitrogen chemically bound in the
fuel; (2) the efficiency of conversion is directly proportional to
the local air-fuel ratio; (3) the rate of nitrogen conversion is of
the order of the hydrocarbon-air reactions themselves; and (4) the
conversion efficiency appears to be a weak function (if at all) of
local gas temperatures. These observations were used to postulate a
simple model of the conversion process in which: (1) the conversion
efficiency is inversely proportional (empirically to the two-thirds
power) to the weight fraction of nitrogen in the fuel (ash- and
moisture-free); (2) the conversion efficiency is linearly proportional
to the local air-fuel ratio, with zero NO occurring at an air-fuel
X
ratio where there is just sufficient oxygen present in the air to
oxidize the carbon to carbon monoxide and the hydrogen (other than
that already bound to oxygen in the moisture) to water; (3) the
appropriate local air-fuel ratio is the average of that in the regions
where the initial hydrocarbon reactions are taking place; and (4)
the conversion efficiency is independent of the local temperature.
Figure 5 shows a plot of data available to this study from
full-scale tests and some laboratory experiments relating conversion
efficiencies at three percent oxygen to weight fraction of nitrogen
in the fuel. Since the full-scale data may involve some thermally
generated NO , the empirical curve shown in the figure was estab-
lished to represent a lower bound of the full-scale data, but the
curve represents actual data in the case of the controlled tests
conducted in the laboratory. Much more data of this type are
available (e.g., Reference 4) but not all of the appropriate test
conditions were available to this study. In general, these additional
data confirm a curve of the type shown.
The model for the conversion of fuel-bound nitrogen to NO used
in this study is a simple linear function of the fraction of
T.V-124
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theoretical air available during the initial hydrocarbon reactions.
The intercept is set by assumption (2) above, and the slope is
determined by the weight fraction of nitrogen in the ash- and moisture-
free fuel according to Figure 5. Figure 6 shows a plot of these
curves for the four coal types and the low sulfur oil of this study.
The problem of calculating the efficiency of conversion of fuel-
bound nitrogen to NO from the above model would now be quite simple
n
and straightforward if the coal and oil gasification and the gas
mixing rates in the active burner region were well known. In that
case, the average local air-fuel ratio in the regions where the initial
hydrocarbon reactions were taking place could be accurately determined
and the average conversion efficiency calculated. Since development
of these rates was not within the scope of this study, an approximate
method was developed to take into account the effects of slow
gasification rates of coal particles on conversion efficiency.
Observations on coal flames in boilers of various firing types
indicate that luminous, reacting flames appear to extend 4.5 to 6.1
meters (15 to 20 feet) into the boiler from the burners. If the
firing configuration is such that gross mixing between burner flows
and bulk gases is forced to occur within that distance, then the
average local air-fuel ratio in the region where the initial hydro-
carbon reactions are taking place (including some further distance
for gas mixing) would approximately be the average of all burner
flows and bulk gases at that level. If such mixing does not occur
within that distance, then the appropriate average would be that of
the burner flows alone. Opposed and tangential firing configurations
are both designed to force such mixing early. The opposed, coal-fired
boiler in this study allows a maximum of about 4.3 meters (14 feet)
for mixing within the burner flows before forced mixing with opposed
burner flows begins. Mixing with bulk gases begins well before that,
at least in the higher burner levels. The tangential configuration
IV-125
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is designed to induce swirling bulk gases and more direct and early
mixing of bulk gases with burner flows and between the burner flows,
For the opposed and tangential boiler configurations the appro-
priate average air-fuel ratio for calculation of the fuel-bound
nitrogen conversion efficiency at a given burner level was taken to
be the average of all of the burner flows introduced into the boiler
up to and including that burner level. The appropriate air-fuel ratio
for all of the coal introduced into the boiler (the average for the
region of the active burners) was then taken to be the average of all
of the levels where fuel is being introduced. If all of the active
burners, and none of the air-only burners, are located below some
level (for example, all burners in the top row air-only and all burners
below the top row active) then the average air-fuel ratio of the active
burner region is equal to that of the burners. In the case where
air-only burners are mixed with active burners the average air-fuel
ratio is always higher than that of the burners. Since the efficiency
of conversion of fuel-bound nitrogen has been observed to increase
with the local effective air-fuel ratio, these higher average air-fuel
ratios always increase the NO generated from the fuel nitrogen. In
X
general, this accounts for the fact that, when air-only burners are
mixed (vertically and/or horizontally) with active burners and gross
forced mixing is early, some of the gasified fuel will initially
react in local regions of high air-fuel ratio and generate higher
levels of NO from fuel-bound nitrogen conversion. From the standpoint
X
of NO generated from conversion of fuel-bound nitrogen alone, this
X
latter case implies that minimum NO requires that air-only burners
X
be located in the highest levels of the burner array.
Single-wall-fired boilers, however, involve no direct mechanism
for creating this gross mixing. In boilers with small numbers of
burners, and limited vertical distribution of the burner array, the
IV- 126
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array begins to resemble a single burner. In a single-burner
configuration there is little or no mixing with bulk gases and, in
fact, the transition from "burner flows" to "bulk gases" is even
difficult to define. In the single-wall coal-fired boilers of this
study, the burner flows at the lowest level can proceed, with lit-
tle or no forced mixing with bulk gases, for 6.7 to 9.8 meters
(22 to 32 feet) across the boiler. In this study, therefore, the
average air-fuel ratio "seen" by the fuel in the initial reaction
period was taken as that of the active burners, regardless of the
locations of air-only burners in the burner array. Treating the con-
version of fuel-bound nitrogen in single-wall burners in this manner
implies that any effect of the vertical location of air-only burners
in these boilers must result from effects on thermally-generated NO .
X
For purposes of regression analysis of the coal data sample, the
NO contributed by conversion of fuel-bound nitrogen was calculated
X
from the model and the mixing assumptions discussed above, and
subtracted from the measured value of NO . The regression analysis,
then, was conducted only on that portion of the NO assumed to be due
X
to thermal mechanisms. Verification of this total approach will be
discussed in the following subsection.
Results of Parametric Studies
Results of parametric studies with oil and natural gas fuels are
presented and discussed in detail in Reference 1. Since NO reduction
X
in utility boilers burning coal fuels is of greater interest today,
primarily results related to coal burning will be discussed.
In developing the equation to be used for the parametric study of
coal, the entire coal-fired data sample as shown in Table 1 was used
in the regression analysis to establish the coefficients of the terms.
The correlation coefficient for this data sample was 0.82. The
resulting equation, then, is approximately applicable to any of the
IV- 127
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seven boilers in the sample and, if the sample is sufficiently typical
of coal-fired boilers in general, could be considered applicable to
any coal-fired boiler.
The most significant term in the equation is that describing the
conversion of fuel-bound nitrogen. In all of the 186 tests in the
coal-fired data sample of this study, conducted on seven widely
different boiler geometries and firing types and involving four quite
different coals, no data were found which indicated NO levels
significantly below the level calculated from the bound nitrogen term.
The same is true of the 139 test data samples on four boiler types
fired with the single low-sulfur fuel oil. Therefore, the bound
nitrogen term tends to represent a minimum NO level obtainable by
X
the combustion modification techniques represented in the data sample.
Since the bound nitrogen term is a function of the coal composition
(primarily the weight fraction of chemically bound nitrogen in the
ash- and moisture-free coal) and the effective fraction of excess air
surrounding the coal particles while they are gasifying, these are
the only parameters which can be controlled to minimize NO from this
X
source.
The second most significant source of NO in the equation used
for the parametric calculation is represented by the eight terms
describing thermal NO generation in the region of the active burners.
The majority of the analytical effort in this study was involved in
establishing these terms to adequately represent thermal NO generation
in this complex mixing and reaction region. These terms were all
important in the study of NO from natural gas-fired boilers, of course,
but will be seen to be much less significant with coal-fired boilers.
Finally, one other significant source of NO , with all fuels,
X
is represented by the constant in the equation derived by the
regression analyses. Parametric studies on the natural gas- and
oil-fired data showed that this constant represented the thermal NO
IV-123
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generated in the region above (or downstream) of the active burner
region (identified as the "NO _ Port Mixing" zone in Figure 2).
X
Figure 7 shows a parametric calculation, from Reference 1, on the
effects of large increases in NO port air flow on NO emissions
X X
with natural gas fuel. At very large values of NO port flow, when
the entire active burner region should be generating no NO , the
X
calculation becomes asymptotic to the approximate value of the constant.
The only remaining region where significant NO could be generated,
X
in such a case, is that zone above the active burners which is always
at the level of excess air of the overall boiler. This is also the
region where the final mixing of NO port air flow, or air flow from
X
air-only burners in the top burner level, is mixed with fuel-rich
combustion products coming from the active burner region below,
forcing the local air-fuel ratio of these gases to cross stoichiometric
from fuel-rich to the slightly fuel-lean mixture of the overall boiler.
Therefore, the three major sources of NO in coal-fired boilers
in the study are: (1) the conversion of fuel-bound nitrogen in the
boiler region where the initial hydrocarbon reactions are taking place;
(2) thermally-generated NO in the complex mixing and reaction zones
X
in the region of the active burners; and (3) the final mixing zone
above the active burners. Figure 8 identifies these three sources
in the data from TVA's sister boilers Widows Creek Units Nos. 5 and 6.
The figure shows that the lower bound of these data rather closely
follows the calculated line for the NO generated from conversion of
X
the fuel-bound nitrogen for this coal type, confirming both the slope
and the intercept. In general, the full-load NO data tend to
X
follow a second straight line parallel to the bound nitrogen line and
higher by about 146 ppm. This is the constant in the parametric
equation for the combustion air temperature of this boiler and the
combustion temperature rise of this coal. The thermal NO generated
X
in the active burner region is represented by the large scatter of
IV- 129
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data (for different air-only burner combinations) approximately
centered about theoretical air and added to the NO from the bound
x
nitrogen and the constant terms. This region is enclosed by a
Zeldovich-type function for a constant time.
A large number of parametric calculations were made to investigate
various methods of reducing the NO generated from coal-firing in
each of these regions. From the standpoint of practical, readily
implemented combustion modifications represented in the data, only
three significant "rules" were observed:
(1) Air-only burners should be located in the highest row(s)
of the burner array. Figure 9 shows the parametric cal-
culations of NO emissions when all burners in a given
X
vertical level are operated air-only. While the effects
vary in magnitude, all show that the top level is the
appropriate location for air-only burners to minimize NO .
X
(2) Increasing the number of air-only burners, located in the
top row(s) of the burner array, reduces NO from both
X
fuel-bound nitrogen conversion and from thermal generation
in the active burner region. This will be shown in
subsequent composite figures.
(3) Within practical limits of overall boiler excess air and
within the combustion modification techniques represented
in the data, only those modifications which reduce the
combustion gas temperatures in the final mixing zone reduce
thermal NO from this region. Data in this sample show low
X
NO emissions from this region under conditions of low-
combustion air temperature, low-combustion temperature rise
(lignite fuel) and/or long-combustion gas cooling time in
the active burner region. Other techniques to reduce the
temperature in this region, such as flue gas recirculation
IV-130
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and water spray, might also accomplish this same objective
but were not evaluated in this study. It is possible that
air pre-treatment need only be applied to the "overfire"
air rather than to all of the combustion air.
The remaining figures show all of the available data on each of
the different types of coal-fired boilers and coal types in this
sample and the parametric calculations on the effects of the above
three major parameters. This form of data confirmation was chosen
because of the large number of significant variables which affect NO .
X
Although the data sample of this study is relatively large, very little
data can be found in which only a single major parameter was varied,
with all others being held constant. In Figures 10 through 15 four
calculated NO curves are shown, superimposed on the data: (1) the
X
fuel-bound nitrogen curve; (2) the variation with numbers of air-only
burners located in the highest levels of the burner array; (3) the
same case as (2) but with the combustion air temperature reduced to
422K (300 degrees F); and (4) variation of overall boiler excess air
with all burners active (fuel plus air). The latter calculation was
made both to provide a comparison to case (2) of a configuration
not involving the final mixing zone and to show the effects of not
using the staged combustion (air-only burners) technique to reduce the
excess air to the active burners. Since reduced boiler load does not
represent a practical way to reduce NO emissions, considering the
X
demand for electricity and the limited available capacity, all
parametric calculations shown are for full-rated load operation.
Figure 10 shows the same TVA Widows Creek data as in Figure 8
with the four parametric curves superimposed. The available data
show that NO levels as low as about 380 ppm (dry, at three percent
X
0~ overall boiler excess oxygen) were tested with no undesirable
side effects (at least none noted in the field testing reported in
Reference 3). Data lying below the curve for two-stage combustion
IV- 131
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(case 2) tended to represent low load and/or cases where high carbon
monoxide emissions were measured. If the two-stage combustion curve
could be reliably extrapolated that far, no limit on NO reduction
X
would be observed per se. Of course, no data are available either to
verify this NO extrapolation or to evaluate possible undesirable side
JC
effects. Reduction of combustion air temperature to 422K (300 degrees
F) from about 606K (630 degrees F) at rated load substantially reduced
the NO thought to be thermally generated in the final mixing zone,
X
except at very low levels of excess air in the active burners. The
curve representing "normal" operation (all burners active), with
overall boiler excess air as the single variable, shows the large
increases in NO thermally generated in the active burner region
A
that are possible without two-stage combustion. All of the highest
data points (greater than 600 ppm) shown in Figure 10, with excess
air to the burners less than 115 percent of theoretical, result from
burner configurations with two air-only burners located in the bottom
level of the burner array.
Figure 11 shows the data and parametric calculations for Alabama
Power's Barry Unit No. 4. This boiler is unique in the data sample
because of the very low combustion air temperature (428K, 310 degrees
F) at rated load. In this case, the parametric calculations for two-
stage combustion and 422K (300 degrees F) combustion air temperature
are represented by the single curve shown about 75 ppm above the bound
nitrogen curve. This represents nearly a factor of two reduction in
the NO generated in the final mixing zone from the previous case.
-«V
The upper limit of the data and the parametric curve for normal
operation (with no final mixing zone) appear to be little affected
by this temperature reduction, although the three data points at the
highest fraction of excess air appear to disagree with the parametric
IV- 132
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calculation. NO levels as low as 250 pptn were tested with no
JV
evidence of excessive CO emissions (less than 177 ppm).
Shown in Figure 12 is a very similar tangential boiler,
Naughton Unit No. 3 of Utah Power and Light, firing a coal similar
in equilibrium combustion temperature rise but operated with combustion
air temperatures of about 667K (740 degrees F) (430 degrees F hotter
than Barry No. 4 and 110 degrees F hotter than Widows Creek No. 5),
The parametric calculations in this figure show evidence of higher
levels of thermally generated NO in the active burner region,
X
particularly when the excess air in the active burner region was less
than theoretical. Unfortunately, no tests were conducted on either
of the tangential boilers in this sample with air-only burners located
at any vertical level other than the top level so it is difficult to
confirm the degree of thermally generated NO originating in the active
X
burner region. The thermal NO thought to originate in the final
X
mixing zone is larger in this case (about 165 ppm) than in either the
other tangential boiler (75 ppm) or the single-wall boiler (146 ppm).
The parametric calculations indicate that the reduction in NO
generated in the active burner region by the use of a few air-only
burners located in the top levels of the burner array is more than
offset, with these high-combustion air temperatures, by that generated
in the final mixing zone (curve 2 is higher than curve 1, where they
overlap). The data imply that these air-only burners are somewhat
more effective than the calculations indicate. Operating conditions
yielding total NO emissions levels as low as 236-266 ppm were tested,
with measured CO emissions less than 91 ppm.
The parametric calculations thus far have shown the relatively
strong effect of combustion air temperature on the total NO
X
emissions. A further case of interest in this regard is the data
IV- 133
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from boilers firing coal type 1 (lignite - see Table 2). In this
coal, the moisture content is so high that the combustion temperature
rise is calculated to be more than 280K (500 degrees F) lower than the
coals fired in the boilers discussed to this point. Thus, almost
regardless of the combustion air temperatures involved, the NO
emissions should result almost totally from conversion of the
fuel-bound nitrogen. Figure 13 shows the parametric calculations for
Dave Johnson Unit No. 2 of the Pacific Power and Light Company, which
fired coal type 1. The parametric calculations for staged combustion
(curves 2 and 3) do indeed closely parallel the bound nitrogen line.
Unfortunately, of the 14 tests conducted on this boiler 11 involved
fully or partially closed air registers and were therefore deleted
from the data sample. The two tests involving air-only burners in the
top levels of the burner array (showing excessively high carbon
monoxide emissions) lie only slightly below the appropriate parametric
calculation (curve 2) and right on the fuel-bound nitrogen curve.
The one case shown in reasonable agreement with the parametric cal-
culation for normal operation represents a configuration with air-only
burners in the bottom level of the burner array. Data from the other
11 tests, involving closed air registers, tend also to verify the
calculations but show a great deal of scatter above and below the
calculated lines. Further confirmation of agreement between calculated
NO levels and data for coal type 1 will be seen later in the appli-
X
cation of the parametric calculation for a boiler which was not in
the data sample used for regression analyses.
A case similar to the previous one is represented by Four Corners
Unit No. 4 of the Arizona Public Service Company. Coal type 2 was
fired in this boiler. The very high ash content of this coal also
tends to reduce the equilibrium combustion temperature rise.
Aerospace calculations indicate that this temperature rise is about
IV- 134
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155K (280 degrees F) lower than those of coal types 3 and 4, but about
144K (260 degrees F) higher than that of coal type 1 (Johnson No, 2).
Full-load combustion air temperatures in Four Corners No. 4 were about
580K (580 degrees F), representing a relatively nominal level. The
boiler is very large (800 MW), with a divider wall, and a complicated
burner array consisting of 54 burners arranged such that some burners
are directly opposed and some are not. The potential mixing of the
burner flows and bulk gases was considered sufficiently rapid that it
was considered an "opposed" firing type (the only one of this type
in the data sample).
Figure 14 shows the data and parametric calculations for this
boiler. In this case, the data deviate considerably from the para-
metric calculations, particularly for the cases where the average
excess air in the region of the active burners was greater than about
110 percent of theoretical. Below this level the data appear to be
approaching the parametric calculation (curve 2) more closely. The
agreement between the parametric calculations and the data is best,
then, in the region of low NO emissions, where it is most important.
A.
The data in Figure 14 show that at least two operating conditions were
tested which yielded 450 to 500 ppm NO emissions with CO levels less
X
than 200 ppm. While this minimum level of NO tested seems quite high,
X
no tests were conducted with burner excess air less than about 92
percent of theoretical.
The data shown in Figure 14 represent the only case of significant
disagreement with the calculated NO levels found in this study.
Unfortunately, in the data sample of this study, it also represents
the only data available from boilers firing high ash coal. This
boiler is also the largest in the data sample and has the largest
number of burners arranged in the most complex burner array. There
was not sufficient time to further investigate the causes of the
IV- 135
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disagreement between the calculated NO levels and the data. It is
X
tempting simply to empirically increase the slope of the line describing
NO from fuel-bound nitrogen conversion for this coal type but more
X
data are needed to verify that the disagreement is indeed related to
the coal type.
All of the parametric calculations shown in Figures 10 through
14 were conducted using the same NO equation, derived from regression
analysis of all of the coal-fired data in the sample. With the
exception of the very high NO levels (greater than 600 ppm) observed
A
in the Four Corners No. 4 data, firing the very high ash coal, the
parametric calculations are reasonably well substantiated by the data.
To the extent that the boilers and coal types represented in these
figures are typical of all coal-fired boilers and coal types, this
equation might be applied with confidence to any other boiler or coal
type, simply by entering the appropriate fuel characteristics and
the operating characteristics and hardware of the boiler.
To test this hypothesis, data from Leland Olds Unit No. 1 of the
Basin Electric Power Cooperative were held out of the sample used for
regression analysis. This boiler was chosen because it appeared to
represent one of the more complex cases. It was fired with coal
type 1, the high-moisture lignite fuel with very low-equilibrium
combustion temperature. The combustion air temperatures however, are
very high (780K, 950 degrees F) at rated load. Also, this boiler is of
the opposed firing type in the bottom two levels but the top level (of
three levels) has burners on only one wall. The burner configuration is
also unique in that there are eight burners in each of the bottom two
burner levels. It was considered that these unique features (the coal
type, the combustion air temperature and the burner configuration) would
represent a reasonably severe test of application of the NO equation
X
derived semi-empirically from data from other boilers.
IV- 136
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Figure 15 shows the calculations and data for this boiler. The
data are perhaps in better agreement with the calculated NO levels
X
than they were with the boiler data included in the sample used for
regression analysis. The data show a rather distinct transition, irora
the lower NO level resulting from configurations with air-only
burners located in the top levels of the burner array (curve 2) to the
higher NO level associated with normal operation (curve 1), when the
X
air-fuel ratio in the active burner region was about 105 percent of
theoretical. In general, the agreement between the data and the
calculation for this boiler, which was not in the data sample used
to derive the calculation equation, is considered good.
General Conclusions from the Study of Coal-,
Oil- jind Natural Gas-Fired Data
The semi-empirical analytical tool developed in this study has
proved to be of significant value in providing reasonable explanations
for the effects of certain boiler operating and hardware parameters
on NO emissions and for the NO emissions minima observed in the data.
x x
The greatest value of this tool, however, appears to lie in the direct,
useful guidance which it provides for development testing which,
with greater confidence, can be expected to yield minimum NO
emissions. In particular, the approach discussed herein is the only
known method, at this time, that the complex interactions between
burners in full-scale, multiple-burner boilers can be taken into
account adequately to point the way to practical, useful techniques
for significant NO reduction.
X
In general, data contained within the sample of 575 tests on 16
boilers of the single-wall, opposed and tangential configurations
firing four types of coal, a low-nitrogen (and sulfur) oil and natural
gas indicate that NO minima as low as about 250, 130 and 110 ppm
X
for the coal, oil and gas fuels, respectively, have already been
IV-137
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demonstrated under full-load conditions. A possible exception to
these low, demonstrated minima is the high-ash (25 percent) coal,
which showed NO emissions no lower than 450 ppm, but insufficient
data were available to determine if this truly represents the readily
attainable minimum with this coal.
Parametric analyses, extrapolating from this base of existing
data, indicate relatively straightforward, understandable and
apparently practical further combustion modifications to affect further
significant NO reductions. The only possibly inherent limit to
A
NO reduction which can be deduced from the data of this study (alone)
Jv
is related to the extremely fuel-rich initial combustion conditions
required to completely eliminate the NO generated from conversion of
fuel-bound nitrogen (55 to 65 percent of stoichiometric air). It is
possible that the hydrocarbon flame itself cannot be supported under
these very rich conditions, resulting in flame-out or combustion
instability. Practical limits due to other undesirable side effects
may also exist but data on these other effects were not contained in
the sample of this study.
The general technique for minimizing NO emissions from the
conversion of fuel-bound nitrogen involves maximum reduction of the
air available for combustion in the local regions of the boilers
where the solid or liquid fuel is gasifying and where the initial
hydrocarbon reactions are taking place. Without major modifications
to existing boilers, this implies the operation of large numbers of
burners on air-only, and/or NO ports, located as high as possible
in the boiler.
Techniques for minimizing thermally generated NO depend on the
concentration of nitrogen in the fuel. In high-nitrogen fuels such as
coal, the air available for combustion in the active burner region must
be maintained as low as possible, at least until the initial hydro-
carbon reactions are completed. This will also minimize NO
IV-138
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thermally generated in the active burner region. The remaining
problem area, then, is in the boiler mixing zone where the remaining
excess air must be added to the hot products of the earlier fuel-rich
combustion to bring the total for the overall boiler up to about three
percent excess oxygen. It is in this region that the local air-fuel
ratio of the bulk gases must pass through the region of high thermal
NO generation rates around stoichiometric as the remaining excess
air is added. The data of this study indicate that techniques which
reduce the gas temperature in this region (i.e., reduced combustion air
temperature or low temperature rise due to combustion) are quite
effective in minimizing NO thermally generated in this region.
X
If there is no nitrogen chemically bound in the fuel, as with
natural gas, it is not necessary to maintain fuel-rich conditions in
the early combustion regions. In fact, in order to avoid establishing
mixing zones anywhere in the boiler where the air-fuel ratio must pass
through the regions of high thermal NO generation rates, it appears
most desirable to maintain air-fuel ratio conditions in natural gas
burners well above that of the overall boiler, finally approaching the
boiler air-fuel ratio at the latest possible moment through the use of
fuel-rich burners in the top level of the burner array, or through
the use of fuel-rich "NO ports". This concept has not been tested
in full-scale utility boilers. Using more standard modifications,
involving air-only burners and/or air-only NO ports, the remaining
active burners can only be fuel-rich. With gaseous fuels, where
the intimate air-fuel mixing in the burner flows is rapid, minimum
NO emissions normally result from the same burner and NO port
x
x
configurations which minimize NO emissions in coal-fired boilers
(i.e., large numbers of air-only burners concentrated in the top
levels of the burner array, open NO ports and reduced peak combustion
X
temperatures).
rv-i39
-------
Low nitrogen-bearing oil fuels represent an intermediate case
between that of coal and natural gas. Clearly, if very low NO
X
emissions are required, the NO resulting from conversion of even
X
this low concentration of fuel-bound nitrogen must be eliminated.
This means that the optimum combustion modifications must be the same
as for coal-fired boilers. If, however, the level of NO emissions
X
resulting from conversion of the fuel-bound nitrogen at air-fuel
ratios somewhat above that of the overall boiler is acceptable, then
the optimum natural gas configuration might be appropriate. The
natural gas configuration would at least minimize thermally generated
NO , leaving only the NO resulting from the conversion of some
X X
fraction of the fuel-bound nitrogen. Since liquid fuels require
considerable time to vaporize and, therefore, intimate that air-vapor
fuel mixing is slow compared to that of natural gas, the average,
local air-fuel ratio surrounding the burning oil vapor can approximately
be maintained air-rich simply by locating air-only burners at the
lowest levels of the burner array (i.e., by maintaining air-rich
bulk gases). All of the oil-fired boiler data analyzed in Reference 1
indicated that, within the range of the configurations tested,
minimum NO emissions resulted from this latter case.
X
This entire study, of course, has concentrated on techniques for
NO reduction alone. Many of the conclusions drawn from the parametric
x
studies are extrapolations beyond the existing data (based on a
reasonably sound model and reasonable agreement with the existing data).
No analytical predictions, no matter how free of empiricism, are free
of risk, particularly as the extrapolations from known data increase.
The conclusions of this study need to be verified by test. In par-
ticular, these conditions need to be evaluated for undesirable side
effects. Among the potentially harmful side effects which need to be
evaluated, to determine limits on the maximum reduction of NO
emissions, are: (1) excessive plant efficiency losses; (2) excessive
IV- 140
-------
emissions of other air pollutants; (3) excessive boiler wall corrosion
or erosion rates; (A) combustion and flame instabilities; and (5)
practical control of boiler operation and heat flux profiles. The
questions of the effects of combustion modifications on plant
efficiencies and on combustion instabilities are currently being
addressed in a continuation of the subject study. At least within
the data of this study, it appears that hydrocarbon, carbon monoxide
and smoke emissions can be controlled to acceptable levels simply by
maintaining the boiler overall excess air greater than about three
percent excess oxygen in coal-fired boilers. No detailed data on the
effects of combustion modifications on wall corrosion or erosion
rates or on boiler controllability were available in this study.
-------
ACKNOWLEDGEMENTS
The work reported in this paper was supported by the Combustion
Research Branch, Industrial Environmental Research Laboratory (Re-
search Triangle Park, N.C.) of the U.S. Environmental Protection
Agency under Grants No. R802366 and R803283-01, R. E. Hall, Project
Officer. Most of the coal-fired utility boiler test data in the
sample of this study were obtained from the field testing of Exxon
Research and Engineering Company, as reported in Reference 3, with
some amplification by Mr. A. R. Crawford. Some additional data on
the Widows Creek facility of the Tennessee Valley Authority were
obtained from TVA, with the assistance of Dr. G. A. Hollinden and
Mr. J. R. Crooks. All of the oil and natural gas data used in this
study were obtained from records of the Los Angeles Department of
Water and Power, with the direct assistance of Messrs. R. Toda,
W, Pepper and R. Centner. Sincere appreciation is acknowledged
for the assistance of each of these organizations and personnel.
IV-H2
-------
REFERENCES
(1) Dykema, O.W., "Analysis of Test Data for NOS
Oil-Fired Utility Boilers", EPA-650/2~75-Oli
241-918/AS), Jan. 1975.
Control in Gas- and
(NTIS No. PB
(2) Dykema, O.W., "Analysis of Test Data for NOX Control in Coal-
Fired Utility Boilers" EPA Grant No. R-803283-01 (estimated
publication, Nov. 1975).
(3) Crawford, A.R., Manny, E.H. and Bartok, W., "Field Testing:
Application of Combustion Modifications to Control NOX Emissions
from Utility Boilers", EPA-650/2-74-066 (NTIS No. PB 237-344/AS),
June 1974.
(4) Sarofim, A.F., "Kinetics of Devolatilization of Nitrogen Compounds
During the High Temperature Pyrolysis of Coals", presented at the
24th Symposium (Int'l) on Combustion, the Combustion Institute,
1974.
(5) Rocketdyne Div. of Rockwell Int'l, "Pyrolysis of Model Fuel
Nitrogen Compounds and Fossil Fuels", EPA Cont. No. 68-02-0635,
presented at EPA/CRS Fundamental Combustion Research Contractors
Meeting, June 1975.
C6) Ibid, "Flat Flame Burner Studies with HCN, NH3 and NO Addition".
(7) Turner, D.W. and Siegmund, C.W. , "Staged Combustion and Flue
Gas Recycle: Potential for Minimizing NOX from Fuel Oil Com-
bustion", presented at the American Flame Research Committee
Flame Days, Chicago, Sept. 1972.
(8) Sarofim, A.F., "Sources and Control of Combustion Generated
Pollutants", Lecture Notes for Summer Course: Energy, A Unified
View, MIT, 1974.
(9) Cato, G.A., et al., "Field Testing: Application of Combustion
Modifications to Control Pollutant Emissions from Industrial
Boilers-Phase I", EPA-650/2-74-078-a (NTIS No. PB 238-920/AS),
Oct. 1974.
IV-143
-------
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IV-159
-------
-------
9:25 a.m.
Analysis of Gas -, Oil-and
Coal-Fired Utility Boiler
Test Data
O.W. Dykema and R.E. Hall
Q: In. your rate equation for the thermal formation of
NO , what rate constant did you use?
X
A: Each of the terms in the equation developed from
the model, and those in the correlating equation,
which represent increments of thermally generated
NO in particular types of mixing zones, are based
X
on an Arrhenius rate equation for NO formation.
x
The pre-exponential constant is part of the coefficient
of each of these terms. In the regression analyses
of large quantities of data these constants are de-
termined empirically. As a result, it is not necessary
to select a rate constant and no particular effort was
made to select one.
Q: Most of your parametric calculations and data appear
to show NO levels linearly related to the excess air
x J
in the burners or in the active burner region, essentially
parallel to the line for conversion of fuel-bound nitrogen.
Why do we not see the non-linear maximum around stoichio-
metric typical of thermally-generated NO ?
A: The typical rate equation for thermally generated NO
X
is contained in eight of the terms in the equation
used for the parametric calculations. If the calcula-
tions are linear with excess air in the burners, the
NO contributions from the sum of these terms must be
X
small, implying little thermally generated NO in the
X
total. Of the 6 figures showing the parametric calcula-
tions and data for different boilers and coals, 4 represent
cases of relatively low combustion temperatures, due
either to low combustion air temperature or low com-
bustion temperature rise (lignite and high-ash coals).
IV-161
-------
In these cases, it might be expected that thermally
generated NO would be a small part of the total.
In the other two cases, the non-linear effect of
thermal NO mechanisms is apparent in the figures.
In all cases, however, thermally generated NO is
X
relatively small compared to that generated by
conversion of the fuel-bound nitrogen in the coal.
The data shown in your figure on the effect of
excess air, and your related discussion, imply that
the observed reduction of NO with reduction in
x
excess air is due only to the appearance of CO, and
the subsequent direct effect of CO on the NO . Do
you mean to imply this?
No. The figure presented on the effect of excess air
was included in the presentation here largely to
illustrate an observation from the data with no
conclusions intended. All of the parametric calcu-
lations and conclusions from this study involve
excess air as an independent variable affecting NO .
X
Throughout the study, however, there consistently
appeared to be an additional effect of the appear-
ance of CO on reduction of NO over and above that
x
of excess air alone. One of the advantages of a
symposium such as this, involving specialists repre-
senting all levels of research and development, is
the opportunity for two-way communication. This
observation on the apparent effect of the appearance
of CO on NO reduction was offered here primarily
to solicit comment, rather than to present a fact.
That figure will probably not be included in the
published proceedings.
IV-162
-------
INFLUENCE OF COMBUSTION MODIFICATIONS
ON POLLUTANT EMISSIONS
FROM INDUSTRIAL BOILERS
BY
GLENN A. CATO AND LAWRENCE J. MUZIO
KVB, INC.
TUSTIN, CA 92680
AND
ROBERT E. HALL
U.S. ENVIRONMENTAL PROTECTION AGENCY
INDUSTRIAL ENVIRONMENTAL RESEARCH LABORATORY
RESEARCH TRIANGLE PARK, NC 27711
FOR
STATIONARY SOURCE COMBUSTION SYMPOSIUM
ATLANTA, GEORGIA
SEPTEMBER 24-26, 1975
LV-163
-------
TABLE OF CONTENTS
Section
1.0
2.0
3.0
4.0
5.0
PROGRAM OBJECTIVE
BASELINE TEST RESULTS
Nitrogen Oxides Emissions
Solid Particulate Emissions
Particulate Size
Hydrocarbon Emissions
Carbon Monoxide Emissions
Sulfur Oxides Emissions
Boiler Efficiency
Furnace Design
COMBUSTION MODIFICATION TEST RESULTS
Excess Combustion Air Reduction
Staged Combustion
Burner Out of Service
Burner Register Adjustment
Combustion Air Temperature Reduction
Flue Gas Recirculation
Firing Rate Reduction
Fuel Oil Viscosity
Burner Tuneup
Fuel Atomization Method
Fuel Atomization Pressure
Fuel Switching
Burner Type
Particulate Size
CONCLUSIONS
REFERENCES
APPENDIX A - GLOSSARY OF SYMBOLS
APPENDIX B - CONVERSION TABLE
Page
IV-164
IV-169
IV-169
IV-172
IV-176
IV-178
IV-178
IV-178
IV-179
IV-179
IV-180
IV-180
IV-186
IV-196
IV-198
IV-200
IV-202
IV-205
IV-206
IV-206
IV-207
IV-208
IV-208
IV-209
IV-209
IV-212
IV-213
IV-214
IV-215
This paper has been reviewed by the Environmental Protection Agency
and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Agency,
nor does mention of trade names or commercial products constitute
endorsement or recommendation for use.
TV- 164
-------
INFLUENCE OF COMBUSTION MODIFICATIONS
ON POLLUTANT EMISSIONS FROM INDUSTRIAL BOILERS
Glenn A. Cato and Lawrence J. Muzio
KVB, Inc., Tustin, CA 92680
and
Robert E. Hall
U. S. Environmental Protection Agency
Research Triangle Park, NC 27711
ABSTRACT
The possibility of reducing the total nitrogen oxides emis-
sions from existing industrial boilers by modifying the combustion
process has been investigated during a field test program. The
gaseous and particulate emissions from coal, oil, and natural gas
fuels were measured both before and after the combustion modifica-
tion. Data were taken on particulate size as well as concentration.
The principal combustion modification methods that were
investigated were: reducing the excess combustion air, adding the
combustion air in stages, recirculating flue gas, reducing the
combustion air temperature, turning off the fuel (but not the com-
bustion air) to one or more of the burners, tuning the burner, and
resetting the burner registers.
All of the combustion modification methods were effective
to varying degrees in reducing the nitrogen oxides emissions, and
reductions of as much as 50% were obtained with several of the
modifications. In most instances, the boiler efficiency was not
degraded, although the particulate emissions.increased by up to
50% in some cases. There was no substantive effect on the other
pollutant emissions.
IV- 165
-------
1.0 PROGRAM OBJECTIVE
Industrial combustion devices of all kinds contribute a
large fraction of the total air pollution from stationary sources.
Studies have found that as much as 40% of the stationary source
nitrogen oxides emissions originate from devices such as industrial
boilers (Refs. 1, 2). A similar figure was obtained for oxides of
sulfur, while particulate emissions were more than 80%. Combustion
modifications have been demonstrated for utility boilers which can
reduce pollutant emissions without degrading boiler efficiency.
Application of these modifications to industrial combustion devices,
if successful, could have a profound impact on air quality and
energy conservation.
It was the objective of this program of field testing to
determine the gaseous, particulate, and toxic element emissions and
the efficiency of industrial boilers ranging in capacity from 11 to
527 GJ/hr (10,000 to 500,000 Ib of steam/hr), and to determine the
reduction of emissions that could be achieved by modifying the com-
bustion process in a systematic and controlled manner. An additional
objective was to maintain or improve boiler efficiency.
The results of the field test program sought to establish
what design and/or operational changes that boiler manufacturers and
operators could make to reduce emissions and where future combustion
research activities should be concentrated. The measurement of
toxic emissions will be used to determine if industrial boilers as
a class are a significant source of hazardous pollutants.
The program was conducted in two phases and this paper
reports the results primarily of the Phase II, except for the
results of the toxic element emission measurements which are not
yet complete. Phase I was one year in duration and involved
IV-166
-------
the selection of 47 representative industrial boilers for testing,
construction of a mobile emissions measurement laboratory, and
field testing of the 47 boilers for emissions with the boilers
operating normally or with minor operating changes (Ref. 3).
The Phase II activities were of 14 months duration and involved
the intensive testing of 19 boilers to measure the sensitivity of
the emissions and boiler efficiency to combustion modifications that
sometimes required retrofit of the boiler {Ref. 4). Examples of
such combustion modifications were overfire air ports and flue gas
recirculation.
In Phase I, the boilers were selected to reflect the prevail-
ing geographical distribution of boilers and fuels throughout the
continental United States. Consequently, the preponderance of test
boiler sites was east of the Mississippi River. This criterion was
used in Phase II also, although not as rigorously, since certain
specific types of boilers were sought. The field test sites for
both program phases are shown in Figure 1.
The following measurements were made:
Total nitrogen oxides
Hydrocarbons
Carbon dioxide
Carbon monoxide
Sulfur dioxide
Sulfur trioxide
Total particulates
Particulate size
Plume opacity
Boiler efficiency
Toxic elements
The emissions were measured with instrumentation contained in
the 2.4 by 9.0 meter (8by29 ft) laboratory trailer of which exterior
and interior views are shown in Figure 2. The gaseous emission
measurements, except sulfur oxides, were measured with continuously
reading analyzers located in the measurement console in the
IV-167
-------
Figure 1. Field Test Site Locations, Phases I
and II.
IV-168
-------
IT ft
Gas Emission
Measurement
Console
Mobile Laboratory
Truck and Trailer
Sulfur and Particulate
Measurement Area -
Wet Chemistry
Figure 2. Interior and exterior views of mobile laboratory.
IV-169
-------
trailer. The particulate concentration, particulate size, and
sulfur oxides concentration measurements were made with instrumen-
tation prepared in the wet chemistry area of the laboratory and
taken to the sample port. The weighing and titration were done in
or near the laboratory.
The emission measurement instrumentation used for the
program was that listed in Table I below. The operation of the
instrumentation is discussed in detail in Reference 3.
Table I. EMISSION MEASUREMENT INSTRUMENTATION
Emission
Symbol
Measurement Method
Eqmt Manufacturer
Nitric oxide
Oxides of nitrogen
Carbon monoxide
Carbon dioxide
Oxygen
Hydrocarbons
Sulfur dioxide
and trioxide
Total particulate
matter
Particulate size
Smoke spot
Opacity
NO
NOx
CO
co2
°2
HC
S02,
S03
PM
K
Chemiluminescent
Chemiluminescent
Spectrometer (NDIR)
Spectrometer (NDIR)
Polarographic
Flame ionization
Absorption/
titration
EPA Std Method 5
Cascade impactor
Reflection
EPA Std Method 9
Thermo Electron
Thermo Electron
Beckman
Beckman
Teledyne
Beckman
KVB Equipment Co
Joy Mfg Co
Monsanto
Research Appliance
IV-170
-------
2.0 BASELINE TEST RESULTS
The objective of the baseline emission measurements was to
establish the general level of emissions from industrial boilers as
a class and to provide a base level from which to determine the
effect on emissions of combustion modifications. The measurements
of the total nitrogen oxides and solid (or filterable) particulate
emissions at the baseline setting of the boilers before combustion
modification are shown in Figures 3 and 4. Data from both Phase I
and Phase II are included.
Nitrogen Oxides Emissions
The total nitrogen oxides emissions were found not to be
significantly dependent upon boiler size, as is indicated in Figure
3. However/ they were strongly dependent on the type of fuel being
fired. This strong dependence is illustrated in Table II which
shows the range and average concentration of nitrogen oxides.
Table II. RANGE AND AVERAGE EMISSIONS OF TOTAL NITROGEN
OXIDES AT BASELINE AND LOW-NOx OPERATION
Fuel Type
Coal
No. 2 Oil
No. 5 Oil
No. 6 Oil
Natural Gas
Range
Baseline
NOx
g/GJ
(ppm)
100-562
(164-922)
36-101
(65-180)
112-347
(200-619)
107-196
(190-350)
26-191
(50-375)
Average
Baseline 0
NOx
g/GJ
(ppm)
290
(475)
67
(120)
164
(293)
151
(269)
71
(139)
peration
Excess
°2
8.7
5.5
5.8
5.3
4.8
Low-NOx Operation
NOx
g/GJ
(ppm)
225
(369)
59
(105)
142
(254)
121
(216)
57
(111)
Excess
O
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4.0
4.9
4.9
5.0
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Figure 3. Total oxides of nitrogen emissions at baseload
IV-172
-------
COAL FUEL
OIL FUEL
NATURAL
GAS FUEL
The length of each
horizontal bar is the
emission from an
individual test.
t
EPA New
Stationary Source
Standard
.OfiO'j .001 .COS .01 ,- .05 0.1
lb/10 Btu
.Ill i il
0.5 1.0
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SOLID PARTICULATE EMISSIONS, g/GJ
Figure 4. Solid particulate emissions at baseload.
IV- 173
-------
The "Low-NOx Operation" column entries are the average of
the emissions when the most effective combustion modification method
for that particular fuel type was used. Coal-fueled boilers were
the greatest emitters of total nitrogen oxides. All nitrogen oxides
measurements cited in this paper in parts per million (ppm) have
been normalized to dry at 3% excess oxygen.
The emissions levels at baseline for each test series are
listed in Table III. Table III also lists the pollutant emission
levels when the boiler was operated such that the total nitrogen
oxides emissions were the lowest. The shaded areas denote tests
where certain emissions were measured both before and after combus-
tion modification. The column on the extreme right entitled "Test
Type" indicates the particular combustion modification that produced
the lowest nitrogen oxides emissions. For example, in Test No. 102,
the lowest nitrogen oxides emissions occurred when the excess combus-
tion air was reduced to its lowest level. In Test No. 104, the lowest
total nitrogen oxides were found after the burner had been tuned. The
meaning of the abbreviations and symbols used is given in Appendix A.
Solid Particulate Emissions
The solid particulate emissions were not at all dependent
upon the boiler size, but were strongly dependent upon the fuel
type, as Figure 4 shows. The emissions from oil and gas fuels were
usually below the Stationary Source Standard of 43 g/GJ (0.1 lb/10
Btu) for boilers of greater than 265 GJ/hr, but the emissions from
coal always were well above it. The solid particulate concentration
includes only the solid particulate that was caught by a heated
filter and not the condensible particulate that was condensed and
collected in water-filled bubblers.
IV-174
-------
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Particulate Sizg
The size distribution of the particulate emissions was mea-
sured to determine the effect on size of fuel type, burner type,
dust collectors, and combustion modification. Thirty tests on ten
different boilers with and without combustion modification were
conducted. Sixteen of the measurements that are listed in Table IV
were made with oil fuel and 14 with coal fuel using a low-speed-flow
type cascade impactor. In some instances soot was blown to include
in the size measurements the soot that was deposited during the test.
Particulates having a diameter of 3 urn or less and listed
in the sixth column are important because the "fine" particulates
smaller than three microns in diameter are especially dangerous to
public health (Ref. 5). The proportion of the particulate catch
that was in the fine particulate range ran from about 30% to 80%
for oil fuel. For coal fuel the proportion was less, about 20% to
33% with one instance of 65%.
Oil fuel also produced more particulates in the size range
that causes reduced visibility and atmospheric haze than did coal.
As expected, the particulates from coal were larger in aerodynamic
diameter than were the particulates from oil.
Most of the oil fuel data evinced a large proportion of
particulates in the fine particulate size range. Typically, two-
thirds of the particulates were 3 pm or smaller in size. Test No.
162 was an exception, since only about 30% of the particulates were
below 3 ym. This smaller number of fine particulates probably was
due to the characteristics of the light No. 2 oil fuel. The light
oil also had a lower total concentration of particulates.
The results of two pulverized coal-fired boilers are com-
pared in Figure 5. The two upper curves are for Location Nos. 13
and 31, both of which fired pulverized coal. The coal was from
IV-177
-------
Table IV. DISTRIBUTION OF PARTICIPATE SIZE
Oil FUEL
Test
Mo.
Ill
121-9
121-10
121-11
130
162-36
171-6A
171-68
171-8
170-5
176-5
139-5
156-2
166-3
106-5
166-6
166-9
166-11
169-1
169-2
169-3
169-4
169-6
Location
27
29
26
36
20
37
30
13
35
31
Load
GJ/hr
(!O3lb/hr)
90 (85)
76 (72)
76 (72)
76 (72)
32 (30)
65 (62)
53 (SO)
53 (50)
54 (51)
68 164)
34 (32}
Burner
or Oil
Type-
PS 300
No. 6
IJo. 6
No. 6
No. 6
No. 2
No. 6
No. 6
Ho. 6
f;o. 6
Mo. 6
87 (62)
422 (400)
116 (110)
111 (105)
111 (105)
106 (100)
116 (110)
148 (140)
146 (140)
148 (140)
148 (140)
148 (140)
SpStk
Pulv.
ChGrt
Pulv.
Proportion of Total Weight of Catch
Particles
Inhaled
Then
Exhaled
<0.5 pm
«
60
10
15
3
7
1
40
37
37
32
32
0.7
2
11
46
25
5
5
1
1
1
0.4
i'artic)es
In The
"Fine"
Part iculate
Size Range
<3 urn
\
81
68
64
29
49
26
73
67
65
62
. 58
COAL FUEL
8
30
24
65
33
22
24
26
10
SO
22
Particles
Reducing
Visibility
by Hie
Scattering
0.4-0.7 pm
«
10
8
22
3
6
1
3
2
2
3
1
<1
3
6
13
3
2
4
1
2
3
1
Soot
Included
No
Yes
Yes
Yes
Ho
No
Yes
Yes
Yes
No
No
No
No
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Ves
Test Conditions
Baseline
Baseline with
light soot
Baseline with
light soot
Baseline with
light soot
Baseline
Baseline
Baseline
Baseline
Basel ine
Higher Load
Baseline
Baseline, Upstrean
of Cyclone
B
-------
100
CP
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Pulverj zed
Location
Tost .156
Location 31
Test 169
Spreader Stoker
Location 30
Test 139
0.1
1.0 10
AERODYNAMIC DIAMETER SIZE, pm
100
Figure 5.
Baseline particulate size distribution, coal fuel
IV- 179
-------
different sections of the country, but the coal particulate size dis-
tributions were similar. Figure 5 also illustrates the difference in
size that was found for pulverized-fired and spreader stoker-fired
boilers. The spreader stoker had a much lower proportion of the
smaller sized particulates.
Hydrocarbon Emissions
Hydrocarbon (HC) emissions from both natural gas and oil
fuels generally were in the zero to 14 g/GJ (zero to 75 ppm) range.
The two highest baseline values measured were 35.4 and 101.8 g/GJ
(200 and 575 ppm).
Carbon Monoxide Emissions
The baseline carbon monoxide (CO) emissions for industrial
boilers were normally near zero, although in a few test cases the
boilers were being operated with over 70 g/GJ (200 ppm) of carbon
monoxide emissions.
Sulfur Oxides Emissions
The combined sulfur dioxide and sulfur trioxide emissions
for coal- and oil-fired boilers ranged from near zero to as high as
1530 g/GJ (1800 ppm). Almost all of the sulfur present in the fuel
appeared in the stack gases and the level of sulfur oxides emissions
was directly proportional to the sulfur content of the fuel. An
exception was when the sulfur content of the coal exceeded 2%. in
these three cases the sulfur oxide content of the stack gas was below
100% conversion, indicating that about one-quarter of the sulfur was
emitted in another form, e.g. retained in the fly ash or emitted as
a sulfate in the flue gas.
IV- 180
-------
Boiler Efficiency
Boiler thermal efficiencies were determined from heat loss
calculations based on fuel composition and flue gas emissions measure-
ments. Baseline efficiencies for coal-fired boilers ranged from 72%
to 88% and averaged 81%. The oil-fired boilers exhibited efficiencies
between 72% and 88% and averaged 83%. Gas-fueled boilers had effi-
ciencies from 70% to 85% with an average of 81%.
One of the major factors affecting the efficiency of indivi-
dual boilers was the excess oxygen level. A 1% reduction in excess
O generally improved efficiency by about 0.5%. Baseline efficiencies
were also dependent upon the type of boiler equipment. Older boilers
were generally in poorer physical condition and lacked efficiency-
enhancing design features such as economizers and air preheaters.
The larger-capacity boilers were more efficient than smaller units
probably due to more efficient design. The type of burner had an
influence on efficiency in the case of coal-fired units. Cyclone
and pulverizer units had much higher efficiency levels than the chain
grate and underfed stokers.
Furnace Design
Twenty firetube furnace boilers were tested during Phase I.
Comparison of the test results showed no significant difference
between nitrogen oxides emissions from firetube and watertube boilers
when burning the same fuel (Ref. 3). The Phase II testing concen-
trated on watertube boilers only.
IV-131
-------
3.0 COMBUSTION MODIFICATION TEST RESULTS
During Phase II eleven methods of combustion modification
were investigated. They are listed on Table V and the postulated
effect of the modification of combustion which caused the lower
nitrogen oxides emissions is tabulated in the column on the right
of Table V. A total of 52 tests of the eleven combustion modifi-
cation methods were run.
The effects of combustion modification on the total nitro-
gen oxides and solid particulate emissions and on the boiler heat
loss efficiency are illustrated in Figures 6 and 7. The combus-
tion modification effect graphs are divided into quadrants. The
criterion for the "best quadrant" with solid particulate emissions
is that the effect of the modification was to reduce the emissions
of both the total nitrogen oxides and the particulates. In the
"worst quadrant", both emissions increased. In the case of boiler
heat loss efficiency, the best quadrant is when the total nitrogen
oxides emissions decreased, but the efficiency increased.
In slightly over one-half of the cases (56%), when the
nitrogen oxides were decreased the particulates were increased. In
22% of the tests, the emissions were in the best quadrant where
both decreased. The effect on boiler efficiency was more favorable,
for in over 60% of the instances the results were in or adjacent to
the best quadrant. The effect of fuel is discussed in Reference 4.
Excess Combustion Air Reduction
A combustion modification method that offered ease of imple-
mentation, emission reduction, and efficiency increase was to lower
the amount of excess air being fired. In about three-quarters of
the instances when the excess air was reduced, the nitrogen oxides
emissions decreased by up to 38% of the baseline level, and the
efficiency increased, by up to 3 percentage points. Reducing the
IV-182
-------
Table V.
COMBUSTION MODIFICATION METHODS AND EFFECTS
CATEGORY AND METHOD
EFFECT
Mixture Ratio Variation
o Excess air level
o Overfire air
o Burners-out-of-service
o Burner register
adjustment
o Varies the overall fuel/air
mixture ratio
o Creates local fuel/air ratio
stratification by bypassing air
and delays complete combustion
o Creates local fuel/air ratio
stratification by bypassing air
and delays complete combustion
o Controls swirl level and the
local rate of fuel/air mixing
Enthalpy Variation
o Combustion air temperature
o Flue gas recirculation
o Firing rate
Influences peak gas temperature
level and duration
Reduces peak gas temperature
level and duration
Affects fuel heat release rate
per unit volume, and gas heat
loss rate
3. Input Variation
o Fuel oil temperature/
viscosity
o Fuel type switching
o Burner tuneup
o Fuel oil atomization
method and pressure
Controls atomization character-
istics; e.g., drop size and
vaporization rate
Reduces sulfur and/or nitrogen
oxides emissions from the fuel
Assures performance according
to design specifications
Controls local fuel/air mixing
rates by varying drop size
distribution and overall fuel
spray shape
-------
Combustion Modification Method
50
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O Reduced Air Preheat O Overfire Air
Q Reduced Firing Rate O Burner Tuneup
A Flue Gas Recirc O Burner Out of Service
Reduced Excess Air V Atomization Method
O
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IV^
0
-200
-100 0 100
i- CHANGE IN PARTICULATES, % -i
200
Figure 6. Effect of combustion modification method on total nitrogen
oxides and solid particulate emissions.
IV-184
-------
Combustion Modification Method
Flue Gas Recirc
Air Register Adj
Oil Viscosity
Burner Tuneup
', Atomization Pressure
V Atomization Method
Reduced Excess Air
Overfire Air
Reduced Air Preheat
Burner Out of Service
-75
-10
-505
«• CHANGE IN EFFICIENCY, %
Figure 7. Effect of combustion modification method on total
nitrogen oxides emissions and boiler efficiency.
IV-185
-------
excess air suppressed the formation of thermal nitrogen oxides from
all the fuels. The greater reductions for oil and coal fuels were
due to the suppression of the conversion of fuel nitrogen to NOx also.
The effect of lowered excess air on the solid particulate
emissions was to reduce them by up to about 15% with coal fuel and
up to about 30% with No. 6 oil fuel. In only two cases out of six
did the reduction of excess air cause less complete combustion and
a slight increase in particulate emissions. The criterion for mini-
mum excess air was the appearance of carbon monoxide in the flue gas.
If the excess air had been further reduced to the point where the
smoke number had increased significantly, the particulate emissions,
then, would have increased.
The test results of changing the level of excess oxygen on
the total nitrogen oxides emissions are depicted in Figure 8. The
effect of reducing the excess oxygen was the greatest for coal fuel,
causing a reduction in NOx level of about 12% for each one percent-
age point reduction in excess oxygen.
The oil fuel data for both heated and ambient temperature
combustion air indicated a reduction in total nitrogen emission
level of about 7% for each one percentage point reduction in excess
oxygen. The reduction of the nitrogen oxides level from Nos. 5 and
6 fuel oils was about twice that from the No. 2 oil fuels.
The influence of the excess air/oxygen level on the nitro-
gen oxides emissions from natural gas-fueled boilers without pre-
heated combustion air was varied. However, the preheated combus-
tion air data evidenced a consistent decrease of emissions level
of about 5% for each one percentage point reduction in the excess
oxygen level. The variations in dependency were caused by the air-
fuel premixing characteristics of the individual burners, the heat-
absorbing characteristics of the furnace, differences in burner
design, etc.
IV- 136
-------
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IV--107
-------
Staged Combustion
Nine tests were run where the combustion air was added in
stages, three each on coal, oil, and gas fuels. In all but two
cases, staging the air reduced the nitrogen oxides emissions by up
to 47%. One exception was with natural gas fuel where the change
was zero and the other was a spreader stoker where the nitrogen
oxides emissions increased by 10%. In four cases, the boiler effi-
ciency decreased up to three percentage points and in the other five
cases it was unchanged.
Diverting some of the combustion air from the initial com-
bustion zone at the burner and injecting it farther downstream from
the burner had two principal effects on the formation of nitrogen
oxides. Firstly, the combustion process was slowed down and the
consequent delayed release of the heat of combustion resulted in a
lower temperature for the products of combustion; thus, the formation
of the thermal nitrogen oxides was suppressed. Secondly, less oxygen
was available in the initial flame zone and this suppressed the for-
mation of nitrogen oxides from the fuel nitrogen.
Three of the staged air tests were made with No. 6 oil fuel
and in all cases the particulates increased, by 12% to 75%, as indi-
cated in Figure 6. Apparently, delaying complete combustion increased
the amount of unburned carbon in the flue gas.
During Phase II, two boilers were modified to allow adding
part of the air downstream of the burner and five boilers were
tested which had been manufactured with staged air capability.
One of the staged air modifications is pictured in Figure 9
and diagrammed in Figure 10. A 36-cm diameter manifold pipe was
run along each side of the boiler and was connected to a fan mounted
on the floor. Four flexible fabric pipes were connected to the
manifold and these could be connected to the five staged air ports
that had been cut into the furnace side walls on each side.
IV- 133
-------
Port With Nozzle
Installed
Manifold
Down comer'
AIR SUPPLY MANIFOLD AND
TWO DOWNCOMERS
Downcomer
Port Nozzle
TWO PORTS WITH DOWNCOMERS ATTACHED
Port With Plug
Installed
.DETAIL OF ATTACHMENT OF
DOWNCOMERS TO PORT NOZZLE
Figure 9. Staged combustion air installation at location No. 38.
IV-189
-------
Boiler Type: Combustion Engineering, balanced-draft, Type VU-10
Boiler Capacity: 47500 GJ/hr (45,000 Ib/hr)
Burner Type: Single Peabody, steam atomized
Port
Nos.
13,15
t
183 cm
1
y
/
/
Windbox
—
»«•
Kurnace
lll— ** . . ^ -i I r\
^- - - -- - ""19 cm
^ . 166 cm ^
Port
Nos.
36 cm dia.
Manifold
(a) TOP VIEW
12,14
z
Overfire Air Fan
Windbox
320
cm
Furnace
86 cm
14,15
80 cm
S3 cm
61 cmV
-G--G--
89
cm
•Port 6,7
Nos.
8,9 10,11 12,13
366 cm
(b) SIDE VIEW
Figure 10. Sctoiatic diagram of staged combustion air systan
installed at location No. 38.
IV- 190
-------
The results of the tests on this boiler with natural gas
fuel are presented in Figure 11. For comparison with what could be
accomplished simply by reducing the amount of excess air through the
burner, the effect on the nitrogen oxides emissions with no staged
air ports open also is plotted. The data in Figure 11 indicate the
following for gas fuel: (1) for the ports located along the burner
axis [port nos. 6-13], the nitrogen oxides emissions exhibited little
sensitivity to the location of staged air addition, (2) the staged
air ports located above the burner axis [port nos. 14 and 15]
were the most effective in reducing nitrogen oxides, (3) the nitrogen
oxides reduction with staged air addition was a strong function of
the relationship of the stoichiometric fuel-to-air ratio to the actual
fuel-to-air ratio at the burner. This ratio is plotted on Figure 11
as theoretical air at the burner in percent.
The nitrogen oxides emissions were reduced from the baseline
level of 112 g/GJ to 91 g/GJ simply by decreasing the excess air.
They were reduced to about 80 g/GJ by staging the air through the
middle ports. When the air was staged through the upper rear ports,
Nos. 14 and 15, the NOx emissions were reduced to 52 g/GJ, for a
total reduction of 54%. By trimming the combustion air it was
possible to achieve this 54% reduction and limit the carbon monoxide
emissions to 11 g/GJ. Less than 32 g/GJ (100 ppm) of carbon monoxide
was the goal during the testing.
Some typical results of the staged air tests of this modi-
fied boiler with oil firing are shown in Figure 12. As with gas
firing, the burner fuel-to-air ratios were the dominant parameter
in correlating the nitrogen oxides emissions. Nitrogen oxides
reductions to about 50% of the baseline level were obtained when the
burner theoretical air was reduced from the baseline level of 114%
IV- 191
-------
en
2
M
01
CO
CL)
W
W
Q
X
O
z
W
Test Load: 42 GJ/hr (40x103 lb/hr)
Fuel: Natural Gas
Test Nos. 180 and 183
Note: The excess oxygen level in the
stack gas was held constant
during all staged air tests.
125 _
75
I.
O,
240
230
220
210
200
190
180
<— Fuel- Psich-
50
(M
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-------
dC
D
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Pi
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to below the stoichiometric level of 100%. In fact the curve of
nitrogen oxides versus the theoretical air at the burner with
staged air through ports 10, 11, 14, and 15 was essentially an
extension of that obtained merely by reducing the overall excess
air with no staged air.
There was a stronger effect of the location of adding the
air in stages on the nitrogen oxides emissions from oil fuel than
from natural gas fuel. The test results showed that the nitrogen
oxides were further reduced as the point at which the staged air
was added was moved farther away from the burner. This was caused
by the moving of the injection location away from the burner, pro-
viding a lower heat release rate and a longer residence time of
the combustion products in a fuel-rich region. The decreased heat
release rate resulted in overall lower flame zone temperature levels
and a reduction in the production of thermal nitrogen oxides.
In addition, the longer residence time under fuel-rich con-
ditions also allowed a greater fraction of the fuel nitrogen compounds
to be reduced to molecular nitrogen rather than oxidized to nitric
oxide and, thus, reduced the conversion of fuel-bound nitrogen to
nitrogen oxides. The insensitivity of the nitrogen oxides reduc-
tions to locations of staged air addition with natural gas firing
supports the contention that the major effect of staged firing with
oil in this unit was a suppression of the conversion of fuel-bound
nitrogen.
The second boiler modified for staged air was a Keeler Co.
Type DS-17.5 watertube unit rated at 18.5 GJ/hr (17,500 Ib/hr steam
flow) with a Faber Type D burner and is pictured in Figure 13. The
staged air was introduced into the furnace by four steel tubes that
were inserted through holes cut into each of the four corners of
the windbox. Flexible ducts were attached to the end of each over-
fire air tube to supply air from the staged air duct to each tube.
The tubes could be inserted up to 122 cm into the furnace.
IV-194
-------
Injection
Tubes
Inserted
Injection
Tubes Inserted
Flexible
Staged
Air Ducts
Injection
Tubes
Retracted
Windbox
Face
Figure 13. Staged combustion air installation at location No. 19 for
Test Nos. 193, 198, and 203.
IV- 195
-------
Tests were conducted for No. 6 oil, both air atomized and
steam atomized/ and natural gas. A representative effect of staged
air on nitrogen oxides emissions for steam-atomized No. 6 fuel oil
firing is shown in Figure 14. The data grouping at the upper right
is from baseline and excess air reduction tests. The lowest nitrogen
oxides emission level that could be obtained by reducing the excess
air was 69.6 g/GJ (124 ppm) with 103% theoretical air.
When part of the air was introduced into the combustion
zone only 30.5 cm downflame of the burner, there was no reduction
in nitrogen oxides emissions relative to the baseline. When
the injection point was moved 122 cm into the furnace and the theo-
retical air at the burner was reduced to 80%, the emissions dropped
to 61 g/GJ (108 ppm). This was a 36% drop from the baseline emissions
and a 13% drop from the lowest emissions obtainable by reducing the
excess air.
Staged air was more effective with No. 6 oil than with
natural gas (for natural gas the nitrogen oxides emissions were essen-
tially the same or increased above the baseline values). This indi-
cated that (1) the fuel/air mixing characteristics for this burner
may have been different for natural gas and No. 6 oil, with effective
staging being obtained 122 cm (4 ft) from the burner with oil firing;
and/or (2) the differences in fuel-air mixing were such that the
fuel-bound nitrogen conversion to nitrogen oxides was suppressed with
little effect on the thermal-NOx formation.
The nitrogen oxides reductions with the oil- and the gas-
fueled boilers where the ports were built in and not adjustable were
10% and 40%, respectively.
On stoker-fired coal units, the staged air ports conven-
tionally are located above the stokers to promote turbulence in the
vicinity of the flame zone and obtain complete carbon burnout within
IV-196
-------
Note: Ite excess oxygen level in the stock gas was held constant
during all staged air tests.
100- -
S 90-
So"
-------
the fumaoe. During the program, varying the amount of staged air
was investigated as a nitrogen oxide control technique on three
boilers. In two tests the nitrogen oxides were reduced by 8% to
25%. In the third with a chain grate, they increased by 10%, because
the additional staged air produced a more vigorous flame (but higher
grate temperature was measured).
Burner Out of Service
The combustion modification method that has been very effec-
tive with utility boilers is operation with some of the burners out
of service. In this mode, the fuel supply to selected burners was
discontinued while the air flow to the burner was maintained. The
total amount of fuel being burned was held constant by increasing
the fuel, but again not the air, to the remaining burners. As a
result, these burners were operating fuel rich and complete combus-
tion was delayed by the surplus of fuel and the scarcity of air.
With a burner out of service, the total nitrogen oxides
emissions from the industrial boilers were reduced by a minimum of
9% and a maximum of 54%. An advantage of this type of combustion
modification was that the boiler efficiency was relatively unaffected
and varied by only jf 0.5 percentage points over nine runs. A dis-
advantage was that the combustion process was disturbed such that
the particulate emissions always increased. In one case the
increase was about 54% and in another the increase was 95% for a
comparable drop in nitrogen oxides concentration.
The data shown in Figure 15 are typical of the results that
were obtained when burners were taken out of service. For example,
Test Nos. 123 and 124 were run on a 74 GJ/hr (70,000 Ib/hr) natural
gas-fired boiler that had three burners in a horizontal row. By
simply reducing the amount of excess air with no burners out of
service, it was possible to lower the nitrogen oxides emissions from
the baseline level of 108 g/GJ (211 ppm) to 85 g/GJ (166 ppm). Then
IV-198
-------
Note: The excess oxygen level on the stock gas was held constant during
all staged air tests.
2
o
H
to
W
H
S
w
W
Q
H
X
O
w
i
150..
o
2
O
100..
50..
Fuel-Rich
Combustion
Air-Rich
Combustion
*
ro
300
250
200
150
100
50
-1
Test 1 ^
141 fc,^~ ~
/"
Tests
123,124
X-
1
Symbol
D i
O ]
Open Syr
out of E
Solid S>
out of s
J-
xT,
-
9C
Fue
Natural <
Refinery
ibols : no
.ervice
'mbols: t
ervice
a
/
Qx
*'
Test
151
L
3as
Gas
burners
urnors
P
s~
•Y
^
O
80 90 100 110 120 130
THEORETICAL AIR AT BURNER, %
140
Figure 15. Effect of burners out of service on total nitrogen oxides
emissions, natural gas and refinery gas fuel.
IV-199
-------
the center burner was taken out of service, and it became possible
to enter the fuel-rich burning region and to reduce the nitrogen
oxides emissions to 49 g/GJ (96 ppm). This was a 55% reduction in
nitrogen oxides emissions. The boiler efficiency was unaffected.
Similar results were obtained with oil and coal fuels, the
reduction in nitrogen oxides ranging from 20% to 40%.
Burner Register Adjustment^
Readjusting the burner air registers succeeded in reducing
the nitrogen oxides by 6% to 22%. The efficiency was unchanged to
as much as one percentage point lower, and the particulate emissions
were unchanged. These results were from a series of tests where
the local air/fuel mixture ratio was controlled by varying the
burner air register setting and, thus, the amount and the swirl of
the air that entered the burner.
The typical effect of secondary air register position on the
nitrogen oxides emissions and smoke levels is shown by the results of
the testing of a single burner boiler presented in Figure 16. A
setting of zero % open corresponded to fully closed, while 100% open
was fully open with the register vanes radial to the burner center.
(At the fully closed position there was still a small amount of air
leakage into the burner.) In addition to the secondary damper per-
centage open, an approximate ratio of secondary to primary air flow
is noted on the ordinate. Opening the secondary damper from 10% open
to its 100% open position decreased the amount of primary air result-
ing in decreased fuel-air mixing near the burner and a 22% reduction
in nitrogen oxides emissions. However, the reduction in nitrogen
oxides was obtained at a cost of an increase of about three Bacharach
smoke numbers.
IV-200
-------
g
o
B
60__
50__
EN OXIDES
as NO
*»
o
g/GJ
30--
20__
120
20
10
20 40 60 80 100
SECONDARY AIR REGISTER, % OPEN
10/90 20/80 30/70 40/60 50/50 60/40
I 1 1 [ 1 i
APPROXIMATE RATIO, SECONDARY AIR/PRIMARY AIR
10 20 40 60 80 100
SECONDARY AIR REGISTER, % OPEN
Figure 16. Effect of secondary air register position on total nitrogen
oxides emissions and smoke level, No. 2 oil fuel.
IV-201
-------
In general, the tests involving burner air register adjust-
ments have found the following:
» The major effect of register adjustments on
multiple burner units is an alteration of the
air distribution between the individual burners,
and not a change in swirl in the burner adjusted.
• On single-register burners, increasing the swirl
(closing registers) tends to decrease the nitrogen
oxides emissions. The mixing of the cooler exter-
nal circulation gases with the hot combustion zone
gases suppresses the formation of the thermal
nitrogen oxides.
• On dual-register burners, the major effect of
register adjustment on nitrogen oxides emissions
appears to be the redistribution of air between
the secondary and tertiary air passages with swirl
playing a minor role.
Combustion Air Temperature Reduction
Reducing the preheating of the combustion air reduced the
total nitrogen oxides by up to 40%. However, the large decreases in
nitrogen oxides were accompanied by a decrease in the boiler heat
loss efficiency of about 2.5 percentage points per 50 K (90°F)
increase in the flue gas temperature.
The combustion air temperature was systematically varied on
three separate units by about 83 K (150°F). The results for the
three boilers are depicted in Figure 17 for both natural gas and oil
fuels. The solid symbols represent the normal air temperatures.
During Test Series 189 for example, the nitrogen oxides emissions
decreased by 20% as the combustion air temperature was reduced from
about 430 K to 350 K (320°F to 175°F). This corresponded to a change
of 23 g/GJ (941 ppm) in nitrogen oxides per 50 K (90°F) change in air
preheat temperature. The decrease with natural gas fuel in Test 182
was comparable. A comparable effect was not unexpected, since changes
in air preheat effect primarily the thermal nitrogen oxides formation,
and this effect should be similar for gas and oil firing in the same
boiler.
TV-202
-------
20O-
150
w i-t
W -H
a o
H
X VI
is ^1004.
w -
C5 CN
H
w w
Z n>
50..
0
200
400
150 _.
CO
a
o
3
4J
-------
Flue Gas Recirculation
Testing of utility-size boilers has established that the
recirculation of flue gas into the combustion air reduces flame
temperatures in the furnace and limits the formation of thermal
nitrogen oxides. Since it also reduces the oxygen concentration in
the primary combustion zone there may be a slight reduction in the
conversion of fuel-bound nitrogen.
The boiler at Location 19 also was modified by adding a
flue gas recirculation capability, and the installation is pictured
in Figure 18. The flue gas was drawn from the bottom of the smoke
stack by a flue gas recirculation fan and was pumped through the
recirculation duct and up into the right side of the windbox through
a windbox addition that had been fabricated.
The windbox had been lengthened to accommodate the flue gas
inlet and an additional set of registers was installed within the
lengthened section to impart swirl to the flue gas and promote mixing
with the combustion air. The combustion air came in through the top
of the windbox and through the original burner registers. The amount
of flue gas being recirculated was controlled by a butterfly valve
located in the recirculation duct.
Figure 19 shows that flue gas recirculation was successful
in reducing the total nitrogen oxides concentration in the flue gases
by ten percent to about 90% of the baseline level with No. 6 oil.
With natural gas alone, a seventy percent reduction was achieved to
only about 27% of the baseline level. The boiler heat loss efficiency
was unaffected. There was an increase in the solid particulate concen-
tration of about 10%, probably due to a slight increase in the
unburned carbon in the less stable flame that resulted when flue gas
was recirculated.
IV-204
-------
Burner
Stack
Windbox
Addition
Recirculation
Fan
Recirculation
Duct
Figure 18. Flue gas recirculation installation at Location No. 19
for Test Nos. 192, 197, and 202.
IV-205
-------
100
No. 6 Fuel Oil, Air Atomized
No. 6 Fuel Oil, Steam Atomized
[ | Natural Gas Fuel
/\ Natural Gas Fuel & No. 6 Fuel
^^ Oil, Air Atomized
10 20 30
% FLUE GAS RECIRCULATION
Figure 19. Effect of flue gas recirculation on total nitrogen
oxides emission level.
IV-206
-------
Recirculation was most effective in reducing nitrogen
oxides emissions from natural gas firing. This could have been
expected because nitrogen oxides emissions from gas occur solely
from the thermal fixation of atmospheric nitrogen at elevated temp-
eratures. The flame-temperature-reducing potential of the recircu-
lated combustion products is fully realized in this case.
The effectiveness of flue gas recirculation is less for
No. 6 fuel oil firing. The reason is that a significant fraction
of the total nitrogen oxides emissions is due to the conversion of
fuel nitrogen, which is not highly temperature-dependent. In
addition, oil fuel combustion is slower in relation to the intense
burning of natural gas from a highly mixed ring-type burner. In
the course of combustion, a significant amount of natural recircu-
lation of combustion products within the flame zone occurs and the
flame is self-cooled.
Firing Rate Reduction
Industrial boiler owners often have excess boiler capacity,
and it might be possible to put some of this excess capacity on
line and to reduce the firing rate of the in-service boilers.
When the combustion was modified by lowering the firing rate
or steam output of a boiler, the total nitrogen oxides emissions
increased in 16 instances and decreased in 19 instances by +_ 12% to
25%. The increases and decreases of efficiency also were evenly
divided; i.e., +_ 3 percentage points. The reason for the increased
nitrogen oxides emissions was that the amount of excess air being
fired usually was raised at the lower firing rates, and this raise
often caused an increase in the total nitrogen oxides emissions.
IV- 207
-------
Gas-fired boilers were relatively insensitive to load
changes unless they had air preheaters. Then, reductions in total
nitrogen oxides of about 20% were realized as the firing rate was
dropped from 100% of name plate capacity to 50% of capacity. Oil-
fired boilers showed little or no relationship between nitrogen
oxides emissions and firing rate. Generally, coal-fired boilers
showed an increase in nitrogen oxides emissions when operating
be-low 60% capacity, caused by the necessary increase in the excess
air level.
Fuel Oil Viscosity
Tests were conducted with No. 6 oil over an oil temperature
range of 340 K to 395 K (155°F to 250°F). No consistent relationship
was observed, although in all cases the change in the total nitrogen
oxides emissions was less than +_ 10%. The boiler efficiency ranged
from unchanged to one percentage point higher.
Burner Tuneup
Tuning the burner to the manufacturer's specifications
increased the emissions of total nitrogen oxides from natural gas
fuel and did not affect the emissions from oil fuel. In all cases
there was an increase of up to one percent in the boiler efficiency
calculated by the ASME heat loss method. No consistent trend in
the particulate emissions was observed.
The chief effect of burner tuneup with oil fuel was a reduc-
tion in carbon monoxide emissions rather than a significant reduction
of nitrogen oxides emissions. During Test No. 108 the carbon monoxide
from oil fuel was reduced from 139 to 38 g/GJ (407 to 110 ppm) and
during Test No. 112, from 40 to zero g/GJ (116 to zero ppm). During
Test No. 108, an increase in excess air and stack temperature
compensated for the decrease in carbon monoxide in the stack gases
IV-208
-------
and the heat loss efficiency did not change. After the tuneup
during Test No. 112, it was possible to operate at a lower level of
excess oxygen than originally without any measurable carbon monoxide
in the stack gases, and the efficiency increased by one percentage
point from 81% to 82%.
With natural gas fuel, if the burner was tuned to reduce
the carbon monoxide to near zero and/or to improve the flame
appearance or color, the nitrogen oxides emissions were either
unchanged or increased. However, tuneup was universally successful
in reducing carbon monoxide and increasing the heat input efficiency
by as much as one percentage point. Here, the decrease in heat loss
.due to a lesser amount of combustible carbon monoxide in the stack
gas was slightly greater than the corresponding increase in the heat
loss due to the higher temperature of the stack gases.
Fuel Atomization Method
To investigate the possibility that one type of atomization
produces less nitrogen oxides than others, steam, air, pressure-
mechanical, and rotary cup types of oil atomizers were evaluated
during the program. The total nitrogen oxides emissions were found
to be relatively independent of the fuel oil atomization method and
more dependent upon the characteristics of the individual burner.
For a given oil gun, the oil atomization method that produced
the lowest nitrogen oxides emissions also usually produced the
highest particulate emissions of the test series. The boiler effi-
ciency was unaffected to any significant degree by the type of
atomization employed. In general the test results for the atomiza-
tion methods tested during this program showed that a well-maintained
oil gun operated near its design point will produce about the same
level of nitrogen oxides and particulate emissions regardless of the
atomization method which is used.
IV-209
-------
Fuel Atomization Pressure
When the fuel oil atomization pressure was increased and the
boiler was at 80% capacity, the nitrogen oxides emissions decreased.
When the same type of test was done on another boiler at a firing rate
of only 25% of capacity, the nitrogen oxides emissions increased by 6%.
Concurrently, the Bacharach smoke number decreased by two numbers.
In the first test the increased pressure caused a smaller apex
angle of the fuel droplet cone to form. It is postulated that it took
longer for the combustion air to penetrate this tighter cone and the
combustion, consequently, was delayed. The production of nitrogen
oxides was reduced. In the low-firing-rate test, the tightening up
of the fuel droplet cone actually enhanced the burning rate of the
"lazy" flame^nd the total nitrogen oxides production was increased. The
ASME heat loss efficiency was not affected significantly by variations
in the atomization pressure.
Fuel Switching
The nitrogen oxides emissions from oil could be reduced by
switching to an oil that has a lower nitrogen content. There are two
important mechanisms for the formation of nitrogen oxides. One is
the thermal fixation of atmospheric nitrogen, and the other is the
conversion of the nitrogen compounds in the fuel. The magnitude of
the potential fuel nitrogen effect is about 730 g/GJ (1300 ppm) of
nitrogen oxides for complete conversion of 1% nitrogen (by weight) in
a residual oil. For coal, the corresponding figure is about 1200 g/GJ
(1900 ppm) of nitrogen oxides per 1% nitrogen in the coal. Actually,
only partial conversion of the fuel nitrogen to nitrogen oxides in
the products of combustion occurs and the percent conversion depends
on the fuel nitrogen content and the availability of oxygen in the
combustion zone.
IV-210
-------
The field test data indicated that the percentage conversion
was high for low-nitrogen oil and decreased with increasing nitrogen
content. It was found that for normal operating conditions, the
thermal nitrogen oxides were in the 34 to 110 g/GJ (60 to 200 ppm)
range and that the fuel nitrogen conversion averaged about 46% for
all oil fuels tested in Phases I and II.
The particulate emissions could be reduced by switching to
a fuel with a lower ash content, for example from No. 6 to No. 5 oil,
since a coal and oil fuel property that correlates reasonably well
with solid particulate emissions is the ash content.
Burner Type
It was found that the nitrogen oxides emissions were lower
from certain burners, however it was difficult to ascertain whether
the differences were due primarily to the burner or interrelated
burner-boiler characteristics and fuel properties. Pulverized
coal burners generally produced slightly more particulate than did
stoker-equipped boilers.
Particulate Size
It was found that some types of combustion modifications
affected the size of the particulates that were emitted. The distri-
butions shown on Figure 20 are representative of the effects that
were observed.
The upper two curves of Figure 20 show the effect on the
particulate size distribution of modifying the combustion of oil
fuel by reducing the amount of excess air/oxygen. Reducing the
excess oxygen from 4.3% to 4.0% reduced the proportion of fine
particulates from about 58% to 50%. [The total nitrogen oxides
concentration dropped from 109 to 98 g/GJ (195 to 174 ppm).]
Apparently the modified combustion resulted in a decrease in the
proportion of the smaller and an increase in the proportion of the
larger size particulates.
TV-211
-------
100 _
CUMULATIVE PROPORTION OF CATCH, % by weight
O O M U»
L, " ' • *"• w
o M w o o o o
'
Test No.
'Basel
Low E
Air
• Test
me
xces
Mo.
17€
n
U
s
16
Registers
Rese
j^Base
t vJ-
I
Line
Lower
"Firing L
Rate
s
J
n
>
?
_»
-
^-
r-i
»
f
'
4
J
^
i"
7<
1
r
^
1 1
II
4
±A
Us
r
k.
k
.X
u
»•-«
1
'
x
^
^
/
x
'
• —/r&
•^
^A
Tr
"^^,
31
Y
/
\
! ?vf'
/ /
/ /
/
^
^
/
/
/
>
' V -^
/
\^t^\
_u— ,,
]p>
5"-^
X1
^
n
**j—
^~ ~\_
^j~
i
'
„
r1
. 2
5. 6
1 0.3 1.0 3.0 10 30 1(
AERODYNAMIC DIAMETER, ym
Figure 20. Effect of combustion modification on particulate size
Oil Fuel.
IV-212
-------
When coal was burned on a chain grate, the effect of
reducing the excess air was different. Reducing the excess air
increased the proportion of the fine particulates in the catch,
rather than reducing them as with oil fuel.
Also shown in Figure 20 is the effect on the particulate
size distribution of modifying the fuel and air mixing by resetting
the burner registers. The upper curve for Test No. 162 was drawn
from data taken after the registers had been reset. The most strik-
ing effect was that the proportion of fine particulates rose from a
baseline value of about 26% to about 40%.
When the firing rate of a boiler was raised from 33% of
capacity to 47% of capacity and the registers reset for the lowest
nitrogen oxides emissions, the proportion of fine particulates
decreased from about 26% to about 5%. The effect of modifying
combusting by tuning the burner resulted in a larger proportion
of the fine particulate after tuning.
IV-213
-------
4.0 CONCLUSIONS
The emissions of industrial boilers as a class are not sig-
nificantly dependent upon size, but they are very dependent upon the
fuel burned. The effect of the type of burner employed is subor-
dinate to the effects of fuel and to the characteristics of the
particular burner and boiler combination.
The nitrogen oxides emissions of the boilers tested were at
or above the Stationary Source Standard [which actually applies only
to new boilers larger than 63 GJ/hr (250,000 lb/hr)} in 30% to 40%
of the cases. The particulate emission standard of 0.1 lb/10 Btu
was exceeded in 16% of the tests of oil fuel and in 100% of the tests
of coal fuel.
The combustion modification methods that have been success-
ful in reducing the nitrogen oxides emissions of utility boilers are
also effective in reducing the emissions of industrial boilers.
Reductions of 30% to 50% have been achieved with the major modifica-
tion methods. The reduction of nitrogen oxides, however, was accom-
panied by an increase in particulate emissions of 5% to 50%.
The hydrocarbon, carbon monoxides, and sulfur oxide emissions
were relatively unaffected by the combustion modifications. In 60%
of the tests, the boiler efficiency either remained unchanged or
increased by up to 4 percentage points.
The baseline emissions that are high and the increase in
particulate emissions caused by combustion modification can be
reduced by sound combustion engineering, such as
• Better boiler operation through improved instru-
mentation
• Modern low-emission, high efficiency burner and
boiler design
• Awareness of the interrelated combustion parameters
and working with them as a group.
IV- 2.14
-------
5.0 REFERENCES
1. Bartz, D.R., et al., "Control of Oxides of Nitrogen From
Stationary Sources in the South Coast Air Basin," KVB
Engineering Report No. 5800-179, 9/74 for State of California
Air Resources Board.
2. Barrett, R.E., et al., "Field Investigation of Emissions From
Combustion Equipment For Space Heating," Battelle-Coluinbus
Laboratories, EPA-R2-73-084a, June 1973.
3. Cato, G.A., et al., "Field Testing: Application of Combustion
Modifications to Control Pollutant Emissions from Industrial
Boilers - Phase I," EPA 650/2-74-078-a, NTIS No. PB 238 920/AS,
October 1974.
4. Cato, G.A., et al., "Field Testing: Application of Combustion
Modifications to Control Pollutant Emissions from Industrial
Boilers - Phase II," EPA 650/2-74-078-b, November 1975.
5. Walsh, G. , Symposium on Electrostatic Precipators at Southern
Research Institute, Birmingham, Alabama, November 1974.
-215
-------
APPENDIX A
GLOSSARY OF SYMBOLS
Burner _Type
Air
ChGrt
Pulv.
Ring
SpStk
Spud
Steam
Air Atomizer
Chain Grate
Pulverizer
Natural Gas Ring
Spreader Stoker
Natural Gas Gun
Steam Atomizer
Burner Equivalence
Ratio
Burner Theoretical Air
(A/F)
stoic
(A/F)
(A/F)
actual
actual
(A/F)
stoic
Te_st_F_uel
Coal
NG
Ref.Gas
NG/#6
#2
#5
#6
PS300
Test Type
AirReg
Atom Press.
BOOS
Base
BrTune
CombCyc
Damper
HiAir
HiLoad
LowAir
LowLoad
NrmlAir
OFA
SnglCyc
Steam Injec
TP
VPH
Viscosity
Coal
Natural Gas
Refinery Gas
Mixture, Natural Gas and No. 6 oil
No. 2 Grade Fuel Oil
No. 5 Grade Fuel Oil
No. 6 Grade Fuel Oil
Pacific Standard Fuel Oil No. 300 (similar to No. 5 oil)
Air Register Adjustment
Burner Atomizing Pressure Adjustment
Burners Out of Service
Baseline
Boiler Tuneup
Combined Cycle
Air Damper Adjustment
High Excess Air
High Load
Low Excess Air
Low Load
Normal Excess Air
Overfire Air
Single Cycle
Steam Injection
Toxic Particulate
Variable Combustion Air Preheat Temperature
Fuel Oil Viscosity Variation via Temperature Change
IV-216
-------
APPENDIX B
To Obtain
g/GJ
g/GJ
GJ/hr
m
GJ/hr
3
m
GJ/hr
m
cm
2
m
m
Kg
Kelvin
Pa
Pa
Pa
To Obtain g/GJ Of
Natural Gas Fuel
CO
HC
NO or NOx {as
S0_ or SO
CONVERSION
From
Ib/MBtu
g/Mcal
MGH
ft2
MGH
ft3
103 Ib/hr
or MBH
ft
in.
ft2
ft3
ig
Fahrenheit
psig
psia
iwg (39.2°F)
equivalent NO )
TABLE
Multiply By
430
239
11.256
37.257
1.055
0.3048
2.54
0.0929
0.02832
0.4536
T = (T + 460J/1.8
K. r
P = (P . + 14.7) (6.895 x 103)
pa psig
P = (P . ) (6.895 x 103)
pa psxa
P = (P. ) (249.1)
pa iwg
Multiply Concentration in
ppm at 3% O^ by
2
0.310
0.177
0.510
0.709
IV-217
-------
APPENDIX B (Cont)
To Obtain g/GJ Of
Oil Fuel
CO
HC
NO or NOx (as equivalent NO )
SO or SOx
Coal Fuel
CO
HC
NO or NOx (as equivalent NO )
SO or SOx
Refinery Gas Fuel (Location 33)
CO
HC
NO or NOx (as equivalent NO )
SO or SOx
Refinery Gas Fuel (Location 39)
CO
HC
NO or NOx (as equivalent NO )
SO or SOx
£i
Multiply Concentration in
ppm at 3% 0- by
0.341
0.195
0.561
0,780
0.372
0.213
0.611
0.850
0.306
0.175
0.503
0.700
0.308
0.176
0.506
0.703
IV- 218
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10:35 a.m.
Influence of Combustion Modifications
on Pollutant Emissions from Industrial
Boilers
Glenn A. Cato, KVB Engineering
Q: About what percentage of your tests were made on single
burner installations?
A: About 2/3.
Q: What percentage was below 50 million Btu input?
A: I would say about one half.
Q: In the statement about the combustion air temperature,
you indicated for every 50 degrees Kelvin, you lowered
it, losing 2 1/2% boiler efficiency. I am assuming
that this is because you were unable to use an air
preheater that was in the flue gases. If you were
not counting the loss because of the air preheater,
would the efficiency remain the same? Was the loss
due to the fact that you were unable to utilize a
portion of the flue gas temperatures?
A: Yes, the heat that was removed from the combustion
air was allowed to go into the atmosphere in the form
of a higher temperature stack gas. The higher stack
gas temperature resulted in a lower calculated ASME
heat loss efficiency.
Q: In other words, if the air was being preheated by
some separate source and you cut the separate source
out, the boiler efficiency would probably remain the
same.
A: Yes, if the stack gas temperature were unchanged, the
calculated ASME heat loss efficiency would be unchanged.
Q: There was one thing that I would like to know. You
said that generally speaking, when you add over-fire
air you compensate by cutting down burner air so that
IV- 219
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the total excess air remains the same.
A: Right, we maintained the excess oxygen at its original
level.
Q: When you added the over-fire air, you said that the
further back in the flame pattern you added it, the more
effective it was. Where would this be relative to
the visual flame pattern, right at the end of the
flame or 2/3 of the way down?
A: A little beyond where the visual portion ended. For
example, one furnace was about 10 feet long and best
air port was about 9 feet out from the burner face.
You said, I believe, the addition of over-fire air
caused the particulate emissions to increase.
Presumably that was due to the fact that the combus-
tion air at the burner decreased. Do you have any
ideas as to why the soot or coal particles did not
burn out in the over-fire zone between the end of
the flame and the end of the furnace?
No, other than it appears that once soot is formed
it is pretty hard to burn it. We didn't do any tests
that attempted to burn the soot, however, so I almost
have to talk from theory.
Did you do any tuning of the boilers before you ran the
baseline tests?
The ground rules were that we would not. We would
just ask the operator to put the boiler at 80% of
name plate capacity with all the settings normal for
that load. In some cases, however, we found that
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the excess air was so high compared to other boilers
of the same type, that it just wouldn't be logical
to call that baseline. In these instances, we asked
them to reduce the air to a little closer to a typical
level. If the CO was above 100 ppm, we tried to drive
it down to below 100 parts per million, and we then
would call that baseline, but high CO was rare.
Q: You mentioned something on the multi-burner furnace
where you redistributed the air to the air registers.
You said that you did not change the swirl to the
individual burners. Could you clarify this?
A: That is not what I intended to say. What I intended
to say was that on boilers that had multiple burners,
when we changed the air register setting, the effect
that reduced the NO was that we were forcing more
X
or less air through the other burners. This re-
distribution of the air was the chief effect and not
a change in the swirl of the air.
You mentioned that on most boilers that you tested
that there was no background CO level. I presume
that applies to the gas and the oil. I would like
you to comment on what CO levels you found with
pulverized coal.
Usually it was zero. In four cases out of a total
of 19, it was 26 to 126 ppm. Actually, there were
more instances of measurable CO with natural gas
fuel than with oil or coal.
IV-221
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Q: I would like to make a comment on the utility boiler,
then. We always have found a level of CO of around
30 parts per million.
A: I could go along with 30 parts per million on oil
or natural gas. However, with coal there was measurable
CO in less than 20% of the cases.
A: Do you recall what the range of sulfur content was in
the coals that you tested?
Q: The sulfur content of the coal ran from about 1%
to 4.5%.
Q: You kept making the point about 100% conversion
to SO or "sulfur in, sulfur out." I was going to
A
further ask with coals that had high sodium or
calcium, if you had done an ash analysis to look
at sulfur retention in ash.
A: Two cases were analyzed. One coal had a sulfur
content of about 3% and the bottom ash contained
about 2% sulfur. In another, the coal sulfur content
was about 1%, the bottom ash sulfur content was 0.5%,
and the fly ash sulfur content was 0.3%.
Q: I would like to hypothesize on why the particulates
went up when over-fire air was introduced. I do
believe that the shorter residence times characteristic
of packaged boilers did not allow complete burnout of
the coal/ash particle by the second stage air. I also
would like to comment on the relatively high levels
of excess air with baseline measurements. We believe
that it was the lack of maintenance and servicing of
the equipment that caused the very high excess air
IV- 222
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levels that were observed at baseline conditions.
We feel that significant reductions can be made by
the operators in excess air and CO and increases
in the efficiency with lower fuel consumption and
lower emissions.
A: I would certainly subscribe to that. In industry,
boilers are considered a tool. They want the operator,
who is often a foreman, to be able to walk away from
the boiler and have it start, stop and run with no
problems. So they are very conservative and they
run a lot of air through those boilers.
The "sulfur-in, sulfur-out" concept we expect for
pulverized coal and oil to hold up very well. I
have seen one or two claims that on stoker fed boilers
some of the sulfur may stay with the ash. Could you
comment on the "sulfur-in, sulfur-out"ratio on stokers?
There were five instances that differed significantly
from 100% conversion. We tested three spreader stokers
and the conversion was 36%, 76% and 137%. The pulverizers
converted at a rate of 136% and 205%. In eight other
cases it was nearly 100% conversion, or sulfur-in,
sulfur-out.
Q: On the units where you did extensive combustion modifi-
cations, would you comment on the combustion noise level
due to combustion changes, such as over-fire air?
A: In the case of the first boiler I showed you, the one
that had the over-fire air ports in the side wall, I
don't remember that the noise increased particularly.
Of course it is so noisy in those boiler rooms to
begin with, it would have to increase a lot before
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you would notice it.
How about where you re-circulated flue products
back into the burner?
When we first fired oil and recirculated flue gas
we had a lot of trouble with flame instability.
At first we thought we wouldn't be able to run it
at all. The boiler owner worked with us and we
spent about 1 1/2 days solving the problem. We
finally got rid of the instability which led me
to say earlier that, if one considered the inter-
related combustion parameters and applied sound
combustion engineering, one could get rid of a
lot of noise as well as other combustion problems.
When we had the unstable flame, of course, we had
a lot of noise. But once things were settled down
and working well, I would say that there was no
noticeable change in noise.
Q: Did you take the trouble to measure the vanadium
content in any of the fuel oils, and if you did,
could you correlate the measurement with any of
the pollutant effects? Did you get the opportunity
to substantiate some of the results from the previous
paper on the effects of additives in fuel oil in
particularly reducing particulates? Secondly, you
said that you didn't notice any difference in NO
formation whether using steam or air for atomization.
I thought on one of the graphs you presented there
IV-224
-------
it seemed that steam was giving you a better result
on NO ; maybe you would like to comment on it?
X
A: What he says is true about atomization. If you go
back to our Phase One report, you notice that in a
given burner, sometimes steam was better than air.
Then with another burner air was better than steam.
So I would say that, overall, it didn't seem to
matter too much whether you designed a burner for air
or steam. Sometimes steam is better and sometimes
air is better. It seemed to be a characteristic of
the particular boiler-burner combination and of how
well that gun was maintained.
As far as the vanadium is concerned, yes, we measured
the vanadium content of 18 of the oils that we burned
in Phase One. The vanadium content ran from a low
of 0.15 ppm to a high of 200 ppm. In Phase Two, the
vanadium content of the coal was measured in three
instances, running from 42 to 70 ppm, and we are
doing a vanadium mass balance. The results of that
correlation will be available probably about the
end of the year.
[Comment by Session Chairman:]
I might mention that the draft of the final report
on combustion modification results has been submitted,
The actual final will be available with all the
details in about eight weeks. The report that con-
tains the vanadium balance will be published this
winter.
IV-225
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IV-226
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Emission Characteristics of Small Gas Turbine Engines
Stationary Source Combustion Symposium
Atlanta, Georgia
September 24-26, 1975
By:
John H. Wasser
Environmental Protection Agency
Industrial Environmental Research Laboratory
Combustion Research Branch
Research Triangle Park, N. C.
IV-227
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EPA REVIEW NOTICE
This document has been reviewed by the U. S. Environmental
Protection Agency and approved for publication. Mention of trade
names or commercial products does not constitute endorsement or
recommendation for use.
IV-228
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INTRODUCTION
The Combustion Research Branch (CRB) of EPA's Industrial Environ-
mental Research Lab-RTP has initiated both contract and in-house
investigations for stationary engine emissions control during the
past year. This paper will describe the first phase of the in-house
research program in this field.
Two commercially available engines have been installed at the
CRB laboratory: a Solar Spartan gas turbine and a Caterpillar D334
precombustion chamber diesel. These engines and a high pressure
experimental combustion system currently at the design stage will
comprise the facility for engine emission control and other high
pressure combustion work.
EXPERIMENTAL APPROACH
Initial experimental work has concentrated efforts on the gas
turbine engine. The first phase of investigation has involved a
determination of the emission performance of the basic engine and an
evaluation of water addition effects on the emission performance at
full load. Table 1 outlines the experiments conducted.
Table 1. Experimental Program
Variable Test Range
Zero to 220 kW
Generator Load
Water Flow Rate
Zero to 11 gal./Hr
(Zero to 0.042 m /hr)
Water addition was accomplished by mixing water with distillate fuel
oil and injecting the resulting emulsion through the engine's normal
fuel pumping system.
IV-229
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ENGINE SYSTEM
The gas turbine engine used for this study is the prime element
in a standby electrical generator package. This engine is a constant-
speed (37,059 RPM), single-shaft, simple cycle, radial flow machine.
It is NEMA rated at 308 HP (230 kW) and the maximum rated electrical
output from the generator set is 225 kW.
Ambient air is drawn into the machine's air inlet by the com-
pressor section. Air is compressed to 4.2 atmospheres (425 kPa) by
the single-stage centrifugal rotor wheel and directed into the com-
bustor assembly. Air is mixed with fuel in the combustor; the mix-
ture is then ignited by a high voltage electric spark and burned.
Resulting hot combustion gases next expand through the single stage
centrifugal turbine where the gas energy is converted to rotating
shaft power. The rotating shaft is connected, through a speed
reduction gear box, to the electric generator. Exhaust gases are
subsequently passed from the turbine to the atmosphere through a
relatively short stack, approximately 9 feet (2.75 meters) above
ground level.
The air pollutant emissions from gas turbine engines originate
in the combustion process, making this section of the machine the
major item of concern. The combustion liner or "can" illustrated in
Fig. 1 is a perforated cylinder, domed at the top and open at the
bottom. A high pressure, dual orifice fuel nozzle is centered at the
top of the dome. An air swirler device is incorporated in the air
inlet annulus surrounding the nozzle. This swirler creates a ro-
tating air jet into which the fuel oil is sprayed co-currently to diffuse
the oil droplets and stabilize combustion at all firing rates. The
remaining compressed air is admitted to the combustion liner through
a number of geometrically patterned large and small holes in the
sides of the liner. Air entering through the small holes is directed
to flow along the inside wall of the liner to prevent overheating the
metal. The rest of the air injects radially through the large holes.
Air flowing through the large holes in the upper half of the liner
mixes with the burning fuel to complete combustion, while air flowing
through the lower holes dilutes the hot gases to a satisfactory
turbine inlet temperature: about 1600°F (1144K).
Engine load is provided by an AVTRON model K463 load bank. This
equipment provides electrical load demands up to 225 kW in 5 kW incre-
ments. Basically the unit is a bank of resistance heaters which con-
vert the electric power generated to heat. The heat is transferred
IV-230
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to the atmosphere by air cooling the heaters.
The fuel used in the engine is a number 2 distillate oil with
an API gravity of 34.0. This oil has a low bound-nitrogen content,
thus fuel nitrogen conversion to NO was not a major factor in this
study. The fuel was obtained from a commercial supplier and had no
special properties.
ANALYTICAL SYSTEM
Methods for determining the gaseous and particulate emissions
from the gas turbine engine were identical to those currently used
in CRB atmospheric pressure combustion or boiler studies. Table 2
contains a listing of the instruments used for each flue gas com-
ponent measured.
Table 2. Analytical Instruments
Flue Gas Constituent
°2
co2
CO
Gaseous HC
NO/NO
Particulate Mass
Particulate Size
Smoke
Analyzer
Beckman Paramagnetic
Beckman NDIR
Beckman NDIR
Beckman Flame lonization
TECO Chemiluminescent
RAC Staksamplr
Andersen Cascade Impactor
Bacharach RDC Smoke Meter
Velocity profiles were measured near the top of the ent-;'i3Ts
16 inch (0.41 meter) diameter exhaust stack. The profile, ind'cat'e
a wide variation in flue gas velocity throughout the stack cross-
section. Measured velocities ranged from 1000 to 6600 ft/- in (5.:
IV- 231
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to 33.5 meters/sec) with an average of 4230 ft/min (21.5 meters/sec)
based on 14 total sample points on two 90 degree traverses. There
were no flow reversal zones found during these measurements.
Measurements of gas composition Indicated variations with both
vertical and horizontal location in the exhaust stack. Because of
this spatial variation, a cross-rake type of sampling probe had to
be used. Single point gas sampling was not possible in these
circumstances.
The stainless steel cross type probe has 20 sampling holes
drilled in the four arms at the centers of the standard five equal
concentric areas making the sample equivalent to traverse points for
a round duct. The probe was positioned about 4 ft (1.22 meters) down
into the stack, precluding the possibility of drawing outside air
into the probe. Sample gas passes from the probe through stainless
steel and Teflon lines between the stack and analyzers. Bulk mois-
ture and condensables are removed from the sample gas steam in
Hankinson dryers (refrigerator type) which reduce temperatures to
35 F (275K). For instruments requiring very dry gas (paramagnetic
and NDIR), the sample is passed through "Drierite" before reaching
the analyzer.
An extension to the engine stack was installed to provide a
suitable location for particulate sampling. The extension is 7.5 ft
(2.3 meters) high, bringing the total stack height to 16.5 ft (5
meters) above ground level.
OPERATING CHARACTERISTICS
SOUND LEVELS
Noise levels eminating from the gas turbine were measured to
obtain an evaluation of the machine's environmental impact at the
site just outside the CRB lab. The decibel level as measured at
three different locations did not change with electrical load on the
machine. Three locations were selected for sound measurement: (1)
2 feet (0.61 meter) from the turbine's weather enclosure, directly
opposite the combustion chamber; (2) 4 feet (1.22 meters) from the
turbine enclosure, on top of the load bank; and (3) 15 feet (4.57
meters) from the exhaust stack end of the generator set. Table 3
lists the results of the survey made with a standard sound meter
using the "A" weighting mode to relate to human sound perception.
IV- 232
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Table 3. Noise Levels
Position
1
2
3
Sound Pressure, dbA
91
94
82
These measurements indicate that, in the immediate area of the
turbine, the maximum permissible noise exposure per 24 hour day
would be 4 hours and 40 minutes. All noise level measurements were
made with the acoustic enclosure panels in place. If these panels
were removed, noise levels would exceed 100 dbA, limiting exposure
to less than 2 hours per day. Since air conditioning units mounted
in the vicinity give sound levels between 85 and 90 dbA, the presence
of the turbine engine did not seriously deteriorate the environment.
NOZZLE CHARACTERISTICS
The gas turbine engine combustor fuel nozzle, a dual orifice,
high pressure type, has unique operating characteristics that could
have a significant effect on both the combustion and emission per-
formance of the engine. This nozzle has two concentric outlet
orifices with separate flow channels to each orifice. An internal,
spring loaded, flow valve divides the total oil flow between the two
orifices. Figure 2 illustrates the relative flow rates through each
orifice.
Primary fuel is used exclusively for ignition; no fuel flows
through the secondary channel until after ignition is established.
Flow through the primary (center) orifice forms a low volume, wide
angle (90 degrees) spray that gives good light-off performance (fine
atomization). As the machine speed increases to 60% of full speed,
fuel pressure increases because more fuel is pumped to the nozzle.
When the pressure reaches 255 psig (1758 kPa), the divider valve
opens and secondary oil flow begins through the annular orifice.
The secondary orifice spray angle is narrower (70 degrees) than the
primary, thus the two sprays will blend, permitting the primary
IV-233
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flow to help atomize the secondary flow at low secondary flow rates.
Combined flow increases until a flow rate is reached that will
maintain full speed operation of the engine. The atomizing pressure
reaches 360 psig (2482 kPa) at zero electrical load. As electrical
load is placed on the generator, the oil flow and pressure increase
continuously. Atomizing pressure reaches 480 psig (3309 kPa) at
rated electrical load. Thus, the droplet size distribution spectrum
would be expected to include finer droplets as load on the engine is
increased, producing the smallest droplets at full load.
LOAD PERFORMANCE
The gas turbine engine used in this study operates with large
quantities of excess air. Excess air changes with load because only
the fuel rate changes; no accompanying modulation of air flow is pos-
sible. The only changes in air quantity are the result of atmospheric
condition changes. Table 4 contains a typical set of excess air values
and exhaust temperatures over the load range of the machine.
Table 4. Excess Air Variation With Load
Load , kW
0
50
100
200
220
Excess air, %
900
775
650
515
405
375
St_ac_k Temperature, F(K)
595 (586)
665 (625)
735 (664)
815 (708)
910 (761)
955 (786)
The relatively low pressure ratio and turbine inlet temperature
are indicators of relatively low thermal efficiency operation. At full
load operation (220 kW), a typical fuel rate was measured at 245
pounds/hr (111 Kg/hr). Using a net heat value of 18,400 Btu/pound
(42.8 MJ/kg), the efficiency was computed to be 16.7%.
IV-234
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EMISSION CHARACTERISTICS
BASELINE
Nitrogen Oxides
The initial investigation for the gas turbine consisted of
measuring the emissions produced by the engine over the entire load
range of the machine. These measurements were made before any
modifications in hardware or operation were attempted to obtain the
baseline characteristics. This baseline then served as a comparator
for determining the performance of any potential control methods.
Baseline emission characteristics for oxides of nitrogen are
presented in Figure 3. Both total oxides of nitrogen (NO ) and
nitric oxide (NO) increase rapidly as load is added to the generator
set starting from the no load condition. The difference between
total NO and NO represents the amount of nitrogen dioxide (N0_).
At the no-load condition, N02 represents about 45% of the total NO ,
which contrasts with boiler operations where NO- seldom exceeds 5%
of the total.
For the zero to 80 kW range the increase in NO is actually an
increase in NO formation; the NO^ level remains essentially constant.
Since the excess air level of the machine ranges from 700 to 900%
in this load bracket, the availability of oxygen and relatively low
temperature promotes formation of a considerable amount of NO--
Increasing quantities of fuel injected into the combustor to meet
the increasing load demand create higher combustion intensity and
higher temperatures, and result in the formation of more NO.
As load increases from 80 to 130 kW, the rate of formation of
NO becomes even greater, but less N02 is formed, moderating the rise
in total NO . The ever increasing quantity of fuel being burned in
the fixed volume of the combustion chamber continually increases
the combustion intensity and temperatures involved, resulting in the
increased NO formation.
IV-235
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As the load is increased from 130 to 220 kW, the formation of
NO remains nearly constant and NO- virtually disappears. A possible
explanation rests with the discrete air injection points in the
combustion liner. When the fuel rate cannot be completely oxidized
by the air available in the primary combustor zone, combustion will
be delayed until additional air is injected. Thus the combustor
may well be "self-staging" at this point in the load range. The
staging effect would limit the peak temperatures encountered, thereby
halting the continual increase in NO.
Carbon Monoxide and Hydrocarbons
Baseline emissions of carbon monoxide (CO) and total gaseous
unburned hydrocarbons (UHC) are presented in Figure 4. By defi-
nition, gaseous hydrocarbons are those compounds which did not con-
dense at the 35 F (275K) temperature stage in the sampling system.
The data pattern is simple, both CO and UHC decrease continuously
with increased load on the machine. It is apparent that the UHC
levels are an order of magnitude lower than the CO. The CO levels
are the major gaseous pollutant problem with this machine since the
NO levels were relatively low.
A
As described in the NO discussion, the combustor conditions of
higher temperatures and combustion intensity with increasing load
that contribute to NO formation also contribute to better oxidation
of the carbonaceous pollutants. Fuel droplet size distribution
changes toward finer drops with increasing load tend to improve the
combustion of the carbonaceous pollutants.
The requirement for air film cooling the inside walls of the
combustion chamber essentially creates a quench zone along the walls
that persists at all load conditions. Inspection of the combustion
liner after the test series indicated alternate ring areas of hot
and cold (relatively) wall surface. The presence of this quench
zone provides a path for CO and UHC to pass through the combustor
without oxidizing. Since the CO oxidation reaction rate is rela-
'tively slow, the relatively short residence time available in the
small combustion chamber contributes to the high concentration in
the exhaust gases. The high levels of carbonaceous pollutants were
expected from a small gas turbine engine because the ratio of wall
area (and quench zone) to total combustor volume is relatively high.
The wall effects would be less critical in larger combustors.
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Particulates and Smoke
Smoke emissions were not visible during the operation of the
engine, except for a 2 to 3 second period at start-up. Visual
inspection of smoke spots taken at different load levels indicated
a nearly constant smoke number over the load range. All spots were
lighter than a No. 6 but darker than a No. 4, thus the smoke level
was evaluated as a Bacharach Smoke No. 5 + h.
Particulate emissions consist of: (1) solids that can be
filtered from the flue gas at high temperature, and (2) solid and
liquid material that is collected (condensed) in cold traps after
the filter. The results of particulate measurements at zero, half,
and full load are presented in Figure 5. The filtered particulate
did not vary as significantly with load as did the condensable
particulate. This would be expected because of the uniformity of the
smoke numbers which are essentially filtered particulates. As with
CO and UHC, the particulate matter decreased continuously with load.
The same conditions which promote the oxidation of CO and UHC also
promote the oxidation of filtered particulate (carbon soot) and
condensables (heavy hydrocarbons). The wall quenching and cooling
film effects are sources of particulate emissions as they were for
CO and UHC. Inspection of the inner surfaces of the combustion
liner revealed a thin, uniform carbon deposit on all areas of the
dome indicating liquid fuel contact with these cooled surfaces.
The condensable particulates were subdivided into water and
benzene soluble fractions. This data is presented in Figure 6.
Again, both the benzene soluble and water soluble particulates
decreased continuously with load. The benzene fraction is an approx-
imate measure of heavy hydrocarbons, many of which are carcinogenic
(benzo-a-pyrenes, for example) or mutagenic.
Filtered particulates were examined further to determine the
size distribution at three load levels. The particulate size range
currently considered as the most serious because of deep penetration
and retention in the human respiratory system falls below 4.0 micro-
meters. Table 5 presents particle size data in relation to this
respirable size range.
IV-237
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Table 5. Particulate Size Distribution
Mass Relative
3
Load, kW Particle Size Range, ym Fraction Fraction
Zero >4.0 0.40 0.40
" <4.0 0.60 0.60
110 >4.0 0.42 0.14
" <4.0 0.58 0.19
220 >4.0 0.71 0.07
" <4.0 0.29 0.03
relative to zero kW load total particulate = 1.0
At no load, the maximum total weight of filtered particulate
was obtained. The respirable particles were the largest fraction
at this load level. At 110 kW load, the total weight of particulate
dropped to 33% of the no load amount. There was a. small relative
decrease in the mass fraction of respirable particles at this load
condition and compared to the no load level, the actual amount
decreased. At full load, the total weight of particulate dropped to
10% of the no load amount. Large particles were predominate at the
full load condition. The respirable particles were only 29% of the
total and were greatly reduced compared to the zero and 110 kW load
conditions.
A brief note regarding the cascade impactor used in these tests:
fibrous glass mats were used on each collection plate to hold the
particles after impaction; otherwise, the carbon soot particles
would have re-entrained.
EMULSIFIED FUEL
Oxides of Nitrogen
The simplest method of introducing water into a gas turbine is
to mix the water with the fuel and inject the resultant emulsified
IV-238
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fuel because only minor hardware changes are required in the engine's
fuel system. Since water addition is a known NO control technique,
it was chosen as the first emission control method to be studied on
this small gas turbine engine. Table 6 presents the emulsified fuel
compositions used in this study with the engine operating under full
load (220 kW) conditions, and at a constant 245 Ib/hr oil rate.
Table 6.
Water Rate, gph
0.93
3.79
4.65
6.50
8.37
10.23
Emulsified Fuel
Emulsion Composition, wt,
3.1
8.7
13.7
18.1
22.2
25.8
As expected, there was a beneficial effect on NO using the
emulsified fuel. This is illustrated by Figure 7. Tn"ere is a
continuous drop in both NO and NO as the amount of water is
increased. The amount of NO- represented by the difference between
the two lines, remained virtually constant. By an addition of 26%
water, the NO was reduced about 33% at this operating condition.
The limiting factor in this method of water injection will be the
condition of the emulsion as water is increased. Batch emulsion
studies indicated that water quantities above 35% would have
stability problems even with surfactant use and that 50% or more
water would invert the emulsion to an oil in water type.
Carbon Monoxide
The fuel emulsion effect on carbonaceous pollutant emissions
was less predictable than on NO . Hydrocarbon levels at full load
were in the 10 to 30 ppm range and no trends were evident with the
water addition. The effect on CO was definite and is illustrated
in Figure 8. Initial water addition at 1 and 3 gph (0.004 and
0.0114 m /hr) reduced the CO levels by up to 4%. Continued water
IV-239
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addition, however, increased the CO levels significantly. This
obviously is making a bad problem even worse. At the present time
lab investigations are concentrating on particulate mass and size
distribution effects of emulsified fuel, but results are not yet
available.
The fuel emulsion stability was checked by withdrawing samples
from the high pressure fuel supply system. This was in the nature
of a check to be sure that a lack of emulsion uniformity was not
causing effects on the emissions. Uniform emulsions were evident
when the samples were drawn. Since a surfactant was not being used,
the emulsions were stable for only 15 to 30 seconds after with-
drawal, and significant separation of oil and water occurred within
a few minutes. However, the emulsion was easily reformed by mild
agitation. It was concluded that the fuel supply pumps were main-
taining sufficient agitation to prevent oil-water separation in the
fuel lines.
ATMOSPHERIC CONDITIONS
One of the major difficulties encountered in conducting
experiments on the gas turbine engine is the atmospheric condition
effect on emissions. The ambient temperature, pressure, and relative
humidity must be monitored and recorded continuously. Because the
gas turbine engine inducts such large quantities of air in relation
to the fuel (5 times stoichiometry at full load), the water flow
through the machine is significant. An example of this is shown in
Figure 9. When the NO vs. load baseline was first determined, the
atmospheric water ingested by the machine was over 24 gallons per
hour (0.09/ra /hr) and the NO level exceeded 200 ppm. For the
emulsion fuel tests, the baseline NO had dropped to 140 ppm and the
ingested water was nearly 31 gallons per hour (0.116 m /hr). As
previously shown in Figure 7, subsequent additions of water with
the fuel simply continue the downward trend in NO emissions.
X
Other atmospheric effects noted include the CO variation with
ambient temperature. Often, morning data could not be used because
the baseline CO levels dropped 200 to 300 ppm as temperatures
increased from 78 F (299K) to 95 F (308K). Afternoon data collection
was more consistent as temperatures varied only 2 or 3 degrees.
Summer weather conditions at RTF, N. C., are simply described as hot
and humid. A large variation in emissions would be expected when
data runs are made with the cold, dry air in winter.
IV-240
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CONCLUSIONS
Based on these results with the Solar Spartan engine, the major
air pollution problems for small gas turbines are the CO, UHC, and
fine particulate emissions. NO emissions were significant but
rather dilute (10-40 ppm, as measured) in the exhaust. Partial load
operation of these standby generator sets can create a health hazard
in the vicinity of the unit because the stacks are close to the
ground. Even though the stack gases are hot, giving a good plume
rise, the gases are often released around buildings where they can
be drawn into air conditioning systems.
Water addition by emulsifying the fuel oil did not benefit the
emissions situation for the small turbine. The CO problems became
considerably worse while the NO improvement may not be a valuable
trade-off for the CO increase. HResults of future particulate
effects from emulsion firing studies will be needed before a final
judgment can be made.
Another potential factor in the fuel emulsion use was the energy
efficiency of the machine. However, there was no measurable change
in fuel required to produce 220 kW over the range of water content
studied. Thus the water addition neither increased nor decreased
thermal efficiency.
The high levels of carbonaceous pollutants can.be traced to the
basic design of the turbine combustion chambers. These chambers
require air film cooling of the walls, creating quench zones that
prevent complete burn-out of these pollutants. The relatively short
residence times inherent in a small volume high intensity combustor
also contribute to this problem. The high excess air levels to limit
turbine temperature are also part of the problem. There are some
potential solutions for solving this problem, and a major thrust for
the CRB in-house high pressure combustion program will be to investi-
gate application of potential control methods to the small turbine
engine.
IV-241
-------
Conversion Factors
gallons/hr (0.0037854) - meters /hr
HP (0.745) • kW
atmospheres (101.3) = kPa
feet (0.3048) = meters
(°F + 460)/I.8 « Kelvin
inches (0.0254) = meters
feet/min (0.00508) = meters/second
inches of Hg (3.327) = kPa
pounds-force/inch (6.894) = kPa
pounds-mass/hour (0.4536) = kilograms/hour
Btu/pound (0.002326) = MJ/Kg.
IV-242
-------
O 0 0
0
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0
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0
OO O 0
FIGURE 1. GAS TURBINE COMBUSTION LINER
IV-243
-------
UJ
H
OC
ACTUAL FUEL RATE
INDIVIDUAL ORIFICE FUEL RATES
100
400
200 300
FUEL PRESSURE, psig
FIGURE 2. FUEL NOZZLE CHARACTERISTICS
IV-244
500
-------
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200
100
20 40
60
80 100 120 140 160 180 200 220
GENERATOR LOAD, kW
FIGURE 4. CARBON MONOXIDE AND HYDROCARBON CHARACTERISTICS
IV-246
-------
O TOTAL PARTICULATE
FILTERED PARTICULATE
O CONDENSABLE PARTICULATE
8CK 100 120 140
GENERATOR LOAD, kW
FIGURE 5. PARTICULATE CHARACTERISTICS
160 180 200 220
IV-247
-------
O CONDENSABLE PARTICULATE
A BENZENE FRACTION
O WATER FRACTION
40 60
80 100 120 140 160
GENERATOR LOAD, kW
180 200 220
FIGURE 6. CONDENSABLE PARTICULATE CHARACTERISTICS
IV-248
-------
I I I I
III
345678
H2O FLOW RATE, gal. /hr
FIGURE 7. NITROGEN OXIDES EMISSIONS- EMULSION FUEL
IV- 249
-------
1500
1200
4567
H2O FLOW RATE, gal./hr
8
10
11
FIGURE 8. CARBON MONOXIDE EMISSIONS - EMULSION FUEL
IV-250
-------
210
200
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« 180
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o
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TOTAL HaO, gal./hr
FIGURE 9. ATMOSPHERIC MOISTURE EFFECT
39 41
43
IV-251
-------
11:30 a.m.
Emission Characteristics of
Small Gas Turbine Engines
John H. Wasser, Research Chemical
Engineer, U.S. E.P.A. Combustion
Research Branch
What quality water did you use in your water injection
system ; and did you run the tests long enough to notice
any effects with regard to turbine fouling and/or
corrosion?
We used City of Durham water, which according to the
health people is fit to drink. We didn't run it
long enough to see whether the turbine engine was
going to like it or not. We have only done these
tests briefly, so I haven't worried about water
quality. I don't think it has damaged the machine
for the brief tests that we have made. This
obviously is a problem and we are going to find
out what is in the water to see if there are possible
effects on the turbine. We will try to give some
thought to that in the future but we just haven't
had time to include that in our consideration.
There has been a lot of comment on your paper and
the previous one on the CO levels and interactions
between the CO and NO. Tom Bowman and John Pohl
and I were discussing that the direct reaction of
CO plus NO is slow but it is tied in with the
oxygen atom and hydroxyl radical kinetics and
it makes sense.
Q: Just another comment about the CO. All this kinetics
is wonderful, and it governs the system; but don't forget
IV- 252
-------
that at 2200 degrees you are kinetically quenching out
your CO. If you get a cold wall you are going to get
a lot of CO; and, secondly, you have small burners
Jack, right?
A: Right, only 8 inches in diameter.
Q: So the surface is creeping in on the reaction, and
consequently you are going to get a lot more quenching
than you would otherwise.
A: That is right. It is a much more important effect in
a small machine than it is in the turbines that you are
used to working with, 25 megawatts or larger.
IV-253
-------
IV-254
-------
SYSTEMS EVALUATION OF THE USE
OF IQW-SUIfUR WESTERS GOAL IN EXISTING
SMALL AND INTEBMEDIATE-SIZED BOILEFS
BY
K. L. MALCNEY
KVB, INC.
TUSTIN, CA 92680
FOR
STRTICNAEY SOURS O3MBUSTICN SYMEKDSIUM
ATLftNTA, GEORGIA
SEPTEMBER 24-26, 1975
IV- 255
-------
INTRODUCTION
The purpose of the first two tasks of the western coal study
which this report covers was to survey and screen the small and interme-
diate sized coal-fired boilers in the United States in order to determine
the feasibility of converting a portion of them to a low-sulfur western
coal as a means of reducing sulfur oxides emissions. The American
Boiler Manufacturers Association (ABMA) sales data which included 362
units for 1965-1974 was used to obtain a more detailed geographical
distribution, both by population and capacity, of coal-fired boilers in
the range 10,000 to 300,000 Ib/hr (pph) steam. The results of this sur-
vey show that the heaviest concentration of coal-fired units is centered
in the midwest around the Great Lakes. This will then be the area where
the maximum potential SOx reduction exists.
In addition to the boiler survey, an analysis was made of the
geographical distribution of sulfur in coals used as industrial boiler
fuel. This data was then used with the boiler population to arrive at
an estimate of the maximum possible SOx reduction achievable by changing
fuel to low sulfur western coal. The impact of this reduction was demon-
strated for four different areas of the United States and with four coals
which are typical of the largest western-coal-producing regions. The
results indicate that SOx reductions in emissions from coal-fired indus-
trial boilers of 46% to 78% could theoretically be realized on a nation-
wide basis, and reductions of 53% to 81% for the midwestern-Great Lakes
region by using western coal.
An informal survey was conducted in order to determine current
western coal users. One hundred and eleven boiler owners and operators
in Minnesota, Wisconsin, Iowa, Nebraska, Michigan, Indiana, Missouri, and
Illinois were contacted. Information was gathered on the following:
o Installed boiler population and geographical distribution
o Western coal users and operational experience with parti-
cular firing eguipment
o Conversion from coal to gas and/or oil
o Potential hosts for boiler testing
IV-256
-------
A study of the supply variables made it apparent that the two
states of Wyoming and Montana are the only western states that are in a
position to supply coal to the mi dwestern and eastern parts of the country
during the next ten years. The factors that were taken into consideration
we re:
o Current production from specific sources
o Production trends and costs
o Shipping costs
o Mine capacities
Analyses of the coal from all of the major producing areas in Wyoming and
Montana have been obtained. These typical coal analyses were then com-
pared to the combustion requirements for the individual firing types to
arrive at an estimate of the difficulty that would be encountered in
switching to the western coal.
The data gathered during the first phase of the program indicate
that a conversion to western coal can be a viable SOx emission control
technique for most types of coal combustion systems. However, some penal-
ties are involved with unit performance and efficiency. Furthermore, it
seems likely that the supply of western coal, especially from Wyoming and
Montana, can be made available in midwestern markets at competitive prices.
IV-257
-------
1-1 BOILER SURVEY
Table 1.1.1 contains ABMA boiler sales data for boilers sold between
1965 and 1974. The data have been sorted according to the following
categories:
o Firing Type (pulverized, spreader stoker, overfed stoker,
underfed stoker, or other)
o Capacity (10,000 to 300,000 pph steam)
o Year of Sale (1965-1974)
o Geographical Location (1973-1974 have full zip code, 1970-
1972 have first three digits of zip code, and 1965-1970
have a one-digit zip code)
o Primary and Alternate Fuel (units that use coal or lignite
as a primary fuel or units that can fire coal or lignite
as an alternate fuel)
o Domestic Sale
o Stationary Unit
o Standard Industrial Classification Code
These boilers have been located on the map shown in Figure 1.1.1 and com-
piled in Table 1.1.2 in such a manner that the geographic impact of western
coal conversion can be seen. In a similar manner, Table 1.1.3 gives the
capacity of the coal-fired units distributed into regions and firing types.
This survey presents a more detailed look at this particular class of unit
than is available from either Walden (Ref. 1) or the Battelle studies (Ref.2).
Population of Coal-Fired.Units Surveyed
Region 3 had 157 boilers installed during the nine year period. This
represents 44% of the total population. Within Region 3, the distribution
among firing types is as follows: pulverized units account for 8.3%; spreader
stokers, 44.5%; overfed stokers, 17.2%; underfed stokers, 2.5%; and other
units, 27.4%. Regions 2 and 4 had 20% and 17% of the population respectively.
The remaining units were spread over the other regions.
Spreader stokers account for 50% of the units sold during the period
followed by 20% for other types of coal firing, 13% for overfed stokers, 9%
for pulverized, and 7% for underfed stokers.
IV-258
-------
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NEW ABMA CARD LAYOUT
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
KVB Sequence Number
ABMA Sequence Number
Date - Day, Month, Year
SIC Number (see below)
Domestic or Export
Zip Code (see below)
Region Code (see Figure 1.1.1)
Type Code: (1) Watertube
Draft Conditions: (1) pressurized furnace; (2) balanced draft
Steam (1), or Hot Water (2)
Stationary (1) or Marine (2)
Utility or Other
Packaged or Field Assembled
Number of Units
Capacity pph
Capacity kilowatts
Design Pressure psig
Operating Pressure psig
Hot Water Outlet Temperature or Saturated Steam
Superheat Temperature
First Reheat Temperature
Second Reheat Temperature
Primary Fuel: (1) Bit. Coal; (2) Oil; (3) Nat. Gas; (4) Wood Bark,
or solid wood products; (5) Bagasse; (6) Blk. Liquor; (7) Other
Fuels; (8) Waste heat; (9) Waste heat with aux. firing; (10) Lignite;
(11) Raw municipal, unsorted; (12) Raw municipal, non-combustible
removed; (13) Raw municipal, sorted and sized; (14) Other industrial
waste
24
25
Alternate Fuel:
Firing Method
Use code as in 23 (1-9); if no alt. fuel, insert "X1
IV-269
-------
RANGE OF ZIP CODES BY STATES
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Dist. of Columbia
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
AL
AK
AZ
AR
CA
CO
CT
DE
DC
FL
GA
HI
ID
IL
IN
IA
KS
KY
LA
ME
MD
MA
MI
MN
MS
MO
MT
35001-36999
99501-99999
85001-86599
71601-72999
90001-96199
80001-81699
06001-06999
19701-19999
20001-20099
32001-33999
30001-31999
96701-96899
83201-83899
60001-62999
46001-47999
50001-52899
66001-67999
40001-42799
70001-71499
03901-04992
20601-21999
01001-02799
48001-49999
55001-56799
63001-65899
63001-65899
59001-59999
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
Puerto Rico
Virgin Islands
Pacific Islands
NE
NV
NH
NJ
NM
NY
NC
ND
OK
OR
PA
RI
SC
SD
TN
TX
UT
VT
VA
WA
WV
WI
WY
PR
VI
PI
68001-69399
89001-89899
03001-03899
07001-08999
87001-88499
10001-14999
27001-28999
58001-58899
73001-74999
97001-97999
15001-19699
02801-02999
29001-29999
57001-57799
37001-38599
75001-79999
84001-84799
05001-05999
22001-24699
98001-99499
24701-26899
53001-54999
82001-83199
00600-00799 &
00900-00999
00800-00899
96900-96999
SIC CODES
15 Offices, shopping centers, 39
and malls 49
20 Food and kindred products 65
22 Textile mill products 73
24 Lumber and wood products
26 Paper and allied products 80
28 Chemical and allied products
29 Petroleum refining and related
30 Rubber products 82
33 Primary metal industries 00
37 Transportation
Miscellaneous manufacturing
Electric utilities
Apartments, housing projects
Equipment rental and leasing
companies (boiler rental co)
Hospitals, medical centers,
nursing homes, and related
facilities
Schools and colleges
Non-manufacturing
IV-270
-------
TABLE 1 . 1 - 2
NUMBER OF UNITS SOLD
FROM 1965 TO 1974 BY REGION
Categories
Other
Pulverized
Spreader Stoker
Underfed
Overfed
1 2
17
8
1 31
10
1 8
Geographic Regions
3456789
43
13
70
4
27
10
6
34
9
5
3
2
22
4
5122
1
495
2
3
Totals
83
30
176
25
48
Total
Percent of Total
2 74 157 64 31 9 12 11 2
0.6 20.4 43.4 17.7 8.5 2.5 3.3 3.0 0.6
Geographic Region (by number code)
1. New England States 5.
Connecticut, Maine, New
Hampshire, Massachusetts,
Rhode Island, Vermont
2. Mid-Atlantic States 6.
Delaware, Maryland, New
Jersey, New York, Pennsyl-
vania, Virginia, West 7.
Vi rginia
3. East-North-Central States
Illinois, Indiana, Kentucky, 8.
Michigan, Ohio, Wisconsin
4. South-Atlantic States
Alabama, Florida, Georgia, 9.
Mississippi, North Carolina,
South Carolina, Tennessee
362
West-North-Central States
Iowa,.Kansas, Minnesota,
Missouri, Nebraska, North
Dakota, South Dakota
West-South-Central States
Arkansas, Louisiana, Oklahoma,
Texas
Rocky Mountain States
Colorado, New Mexico, Utah,
Wyoming
Northwestern States
Idaho, Montana, Oregon,
Washington
Southwestern States
Arizona, California, Nevada
IV-2 71
-------
The total number of coal-fired boilers that have been sold in the
last nine years in this size category is small (362) compared to the total
number existing in the United States which are still firing coal. Ehren-
feld (Ref. 1) estimated that there were 5,239 boilers installed in the
country in the size range 10,000 to 250,000 pph steam that could burn coal.
The number of units that actually fire bituminous coal or lignite is con-
siderably smaller. For example, in 1973 36 overfed units were sold; how-
ever, 33 of these units were specifically designed to burn wood. Overfed
and spreader stoker units are two categories of firing types where there
appears to be a significant wood-burning contribution. Typically, these
units are installed in the wood and paper processing industries where the
waste wood and paper products are burned as boiler fuel. However, such
units will fire bituminous coal when there is insufficient waste wood to
meet load demands.
The pulverized coal firing type and the underfed stoker firing type
are limited to bituminous coal and lignite firing.
The "other" category includes cyclone units at the larger end of
the size range, above 200,000 pph steam. The smaller units in the "other"
category include vibrating grate, reciprocating, and oscillating grate
stokers. Some of these units may be equipped with a system whereby the
ash is blown off the water-cooled grate with either steam or air.
More detailed information about grate design is not available from
the ABMA records. For example, spreader stokers may be equipped with travel-
ing grates or dumping grates. Some smaller overfed units are equipped with
water-cooled grates; however, this is not common.
Capacity of Coal-Fired Units Surveyed
Table 1.1.3 gives the steam capacity in thousands of pounds per hour
for all of the coal-fired boilers in the size category 10,000 to 300,000 pph
steam. The data is presented in the same format as Table 1.1.2 to facilitate
comparison. Inspection of the data indicates that the capacities of the units
sold closely follows the population distribution for both firing categories
and geographic regions. In Region 3, spreader stokers account for 49.4%;
other units, 24%; pulverized, 17.1%; overfed, 8.8%; and underfed, 0.73%
of the total capacity of the region. Again the overall capacity distribu-
tion for the nine regions follows population distribution. Region 3 has
41.3% of the total followed by Region 2 at 16.8%, Region 6 at 4.7%, and
Regions 9 and 1 at 0.5% and 0.25% respectively.
IV-2 72
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IV- 2 73
-------
Sales Trends
Figure 1.1.2 contains the 1965-1974 ABMA sales data for coal-fired
units in the size range 10,000 to 300,000 pph steam. The data are plotted by
year as population and total steam capacity for the five firing types. It can
be seen that boiler sales have declined steadily from 1965 to a low point in
1971. Beginning in 1973, however, there was a general increase in sales with
spreader stokers sales approaching 1966 sales numbers. Spreader stokers
represent the largest single firing type, both by number and total capacity.
Pulverized-coal-fired units are predominantly the larger units above 200,000
pph steam. This becomes obvious when population data and capacity data for
pulverized coal units are compared. Spreader stoker units cover the entire
size range of interest for this study with units as small as 10,000 pph
steam and as large as 300,000 pph. The spreader stoker appears to be the
unit of choice for most industrial coal-fired installations. Spreader
stokers are also found in small utilities where they are used as peaking
units.
For the nine-year period, the sales of each firing type relative to
each other has remained roughly constant. During years of heavy sales, the
spreader stoker has outsold all others. Over this period, spreader stoker
sales accounted for 49% of all units by population and 53% by capacity. The
next largest category is the other firing types which account for 23% of the
units by population and 21% by capacity. Overfed and underfed units combined
represent 20% of the population, but only 9% of the capacity. Finally, the
pulverized-coal-firing category contains 8% of the population and 17% of the
capacity.
Design Trends
The versatility of the spreader stoker has made it the favorite
firing method over the years and this trend appears to be continuing with
even greater strength. The recent sales increase in coal-fired equipment
has been dominated by the spreader stoker. The data also show a trend
toward larger spreader stokers. One reason for the popularity of the
spreader stoker is that they are capable of burning a wide range of coals,
IV-274
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s g
r i
o
1
o
i
o
I
o
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Aq
IV-275
-------
from high ranked eastern bituminous to lignite, as well as many byproduct
waste fuels. Spreader-stoker firing has a very quick response to load
changes and the turndown range extends from 20% of full load to maximum
capacity. Traveling grates remain the most popular grate configuration
for spreader-stoker-fired boilers rated higher than 75,000 pph. They are
designed to handle a wide range of coals as well as process wastes and
municipal refuse. In view of this flexibility and the fluctuating coal
economy, the traveling grate is expected to be the system of choice for
at least the next five years.
New Developments
It is difficult to estimate the environmental and economic impact
of potential developments on this boiler size category. Some examples of
these new developments whose effect may be to increase the total capacity
of this size range or to decrease it are given below:
o Greatly expanded in-plant electrical generation would
increase the size range capacity
o Deregulation of natural gas prices would serve to increase
the size range capacity by a reconversion to coal-firing
O Further oil price increases would increase the size range
capacity in the same way gas deregulation would
o Legislation restricting the use of natural gas for process
units would increase the number of units and the capacity
in the size range
o Large-scale coal gasification and/or liquifaction would
tend to decrease the coal-fired capacity of the size
range; however, this development is at least ten years
in the future
o Increased commercial electrical generation with resultant
lower energy rates would not measurably affect this size
category of boiler
o Environmental legislation aimed at sulfur particulates and
NOx would probably not measurably affect this size category
due to the severity of the energy constraints
IV-276
-------
1.2
GEOGRAPHICAL SULFUR DISTRIBUTION
Boiler Capacity
The total output capacity of boilers in the size range of 10 to 250 MMB/h
was estimated by Locklin (Ref. 1) to be 1.09 x 10 MMB/h for the 10 to 100 kph
range (10 to 100 MMB/h) and 0.80 x 10 MMB/h for the 100 to 250 kph range.
These figures were based on the 2971 estimate of Ehrenfeld (Ref. 2), updated
for sales during the period of 1967 to 1974.
The percent capacity as coal-fired units was given in the same refer-
ence (1) as 10% for the 10 to 100 kph range and 19% for the 100 to 250 kph
range. Thus the total heat capacity installed for coal is estimated to be:
= °-955 x lo
100-250
For a heating value of 10,000 B/lb, the coal consumption in these
boilers is:
M
io-ioo
M
100-250
Curren t Coal Sulfur Pi stribution
The current distribution of sulfur in coal was estimated from seam
analyses given in the Keystone Coal Manual (Ref. 3) , from mine analyses in
the same source, and from mine analyses summarized by Reference 4. For
western coals only the mine analyses were used, since they were felt to
be a more reliable indication of what is available. For midwestern and
eastern coal, the seam analyses were used since the area is heavily mined
and better characterized. Where seam reserve estimates were available, the
sulfur percentage was weighted by these estimates. For the western coal,
the sulfur percentage was weighted by mine capacity.
IV-277
-------
Table 1.2.1 summarizes the results obtained by this method for the
western coal states. Table 1.2.2 summarizes the values for midwestern and
eastern states obtained from the seam analyses and reserve estimates. Table
1.2.3 (which was not used) summarizes the values for midwestern and eastern
states obtained from mine analyses and capacity.
As can be seen, the number of mine analyses available is very low for
some states, making a uniform basis for averaging by this method impossible.
Furthermore the averages for states with few mines reporting (such as Illinois
or Missouri) are quite different from the seam analyses. For these reasons
Tables 1.2.1 and 1.2.2 were used in subsequent calculations.
Coal Usage by Region and Origin
In order to determine the sulfur emissions in coal-burning boilers, it
is necessary to first estimate the consumption of coal by its origin in order
to relate the average sulfur values determined above to the total coal con-
sumed. A study by the Bureau of Mines has categorized coal consumption by
regions of consumption and origin (Ref.5). This study considered utility con-
sumption, coking operations, barge and train propulsion, and "other cate-
gories". Since most of the boilers considered in this study are smaller
than utility size, the assumption was made that the coal-burning boiler dis-
tribution was in accordance with the use distribution of coal in "other
categories". In order to check this assumption, the percentage of the total
coal burned by boilers of less than 500 kph [given by Ehrenfeld (Ref. l)]for the
Great Lakes and Central Regions was compared to the value resulting from the
method described above. A value of 51.3% was obtained from Reference 1
versus 54.5% calculated from the Bureau of Mines report. The slight dis-
agreement could be due to the somewhat heavier concentration of industrial
boilers in this region which would bias the sample more in the < 250 kph
range than if the 250 to 500 kph units are included.
Table 1.2.4 summarizes the data for coal consumption according to the
region of origin and the state of use. These data were converted to per-
centages to estimate the regional distribution of the total boiler heat
(coal) consumption. The regions of origin and average sulfur content
(derived by averaging state averages of Tables 1.2.1 and 1.2.2) are delinea-
ted in Table 1.2.5.
IV-2 78
-------
TABLE 1.2.1
WESTERN COAL SULFUR CONTENT, HEATING VALUE,
AND ASH FUSION TEMPERATURE (AVERAGED BY PRODUCTION)
(a) (a) (b) (c) (d}
State Capacity 1973 Production Sulfur AFT HV
Arizona 13.50 2.97
Colorado 9.45 6.23
Montana 25.88 9.95
New Mexico 15.77 9.95
North Dakota 12.27 9.34
Utah 10.00 5.40
Washington 12.33 3.21
Wyoming 36.74 13.60
{ a) MMT/y
(b)lb/MMB
c> OF
B/lb, as received
0.37 2180 10,900
0.79 2292 13,400
0.92 2223 8,700
0.61 2400(6) 9,800
1.50 2163 7,010
0.56 2195 13,110
0.80 2300 8,100
0.59 2209 10,100
(e)
Doesn't include Nava^o Mine
IV-279
-------
TABLE 1.2.2
MIDWESTERN AND
(AVERAGED BY
State
Alabama
Illinois
Indiana
Kansas
Kentucky (East)
Kentucky (West)
Maryland
Missouri
Ohio
Oklahoma
Pennsylvania
Tennessee
Virginia
West Virginia
EASTERN COAL
SEAM RESERVES
(a)
Sulfur
1.01
2.97
2.19
4.40
0.79
2.41
1.53
3.14
2.62
1.36
1.47
1.50
0.68
0.88
CHARACTERISTICS
VJHERE GIVEN)
No. of Seam Analyses
67
61
8
10
17
4
11
6
16
20
43
44
45
27
Ib/MMB
IV- 280
-------
TABLE 1.2.3
MIDWESTERN AND EASTERN COAL CHARACTERISTICS FROM MINE DATA
(WEIGHTED BY PRODUCTION)
State
Alabama
Illinois
Indiana
Kentucky
Maryland
Missouri
Ohio
Oklahoma
Pennsylvania
Virginia
West Virginia
Sulfur'"'
0.49
1.81
2.72
1.02
1.44
5.56
4.02
0.43
1.69
0.81
1.08
No. of Mines Reporting
5
4
1
40
3
1
14
1
39
4
39
(a)
Ib/MMB
IV- 281
-------
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IV-282
-------
TABLE 1.2.5
AVERAGE SULFUR CONTENT BY COAL-PRODUCING
Region
1
2
3 & 6
4
5
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
States
E. Perm. , Md.
W. Perm.
W. Virginia
Ohio
Michigan
W. Virginia
W . Va . , E . Ky . , Tenn .
W. Ky.
Illinois
Indiana
Iowa
Ala. , Ga. , Tenn.
Ark. , Okla.
Ky. , Tenn., Mo.( Okla.
Colorado
Col., N. Mex.
N. Mex. , Ariz.
Wyoming
Utah
N. Dak. , S. Dak.
Montana
Wash. , Oregon
Sulfur
(Ib/MBtu)
1.47
1.47
0.88
2.62
—
0.88
1.06
2.41
2.97
2.19
—
1.26
1.36
2.10
0.79
0.70
0.49
0.59
0.56
1.50
0.92
0.80
REGIONS (1973)
% of Total Coal
(Ib/MBtu)
5.49
5.15
4.96
10.33
— •
1.60'
31.99
6.91
12.49
7.33
—
2.90
0.19
3.52
0.15
0.58
0.23
1.73
1.67
0.48
0.57
1.54
IV-2 83
-------
1.3
ESTIMATE MAXIMUM POSSIBLE SULFUR REDUCTION
Present Sulfur Emissions
The data of Tables 1.2.2 through 1.2.5 were applied to calculate the
sulfur emissions from coal-burning boilers in the 10,000 to 250,000 pph
steam range. The sulfur emitted was simply:'
where
M
10-100
23
1
23
f. s,
i ]
10-100
M
100-250
f. s. Q
100-250
M
10-100
f.
s.
M
100-250
= mass of sulfur (as sulfur) emitted from boilers
in the 10 to 100 MMB/h range
= fraction of the coal originating in region i
= average sulfur content of coal in region i
= mass of sulfur (as sulfur) emitted from boilers
in the 100 to 250 MMB/h range.
Substitution of the appropriate values gives:
M
10-100
M
'100-250
0.805 MMT/y (as sulfur)
= 1.123 MMT/y (as sulfur)
When the same data was used to estimate the sulfur emissions only in the
midwestern and Great Lakes states, the following values were obtained:
M
s
10-100
(CU,GL) = 0.462 MMT/y
M
(CU,GL) = 0.645 MMT/y
100-250
It is significant that the total emissions from this district (which
is most accessible to western coal sources) are 57% of the national total.
This is because of the high concentration of boilers in this region and the
high sulfur content of the coal in these regions.
IV-284
-------
Reduction in Sulfur by Using Western Coal^
The sulfur emissions using western coal were estimated both nation-
wide and for the midwestern-Great Lakes region for two different cases:
1. Western coal characteristics were weighted according
to present mine capacity. That is, increases in pro-
duction would be met by increases in all mines propor-
tional to their present capacity.
2. Western coal characteristics of individual states were
used.
Table 1.3.1 summarizes the nationwide sulfur emissions and net savings
realized by using western coal for the boilers in the 10 to 250 MMB/h range.
TABLE 1.3.1
NATIONWIDE SULFUR EMISSIONS
Coal Source
Composite western
Arizona
Wyoming
Montana
Total Sulfur Emitted
0.85
0.42
0.67
1.05
USING WESTERN COAL
(a) Net Decrease fa)
1.08
1.51
1.25
0.88
% Decrease
56
78
65
46
(a)
MMT/y as sulfur
Table 1.3.2 summarizes the sulfur emissions and reduction possible
for the midwestern-Great Lakes region for the same conditions.
TABLE_ 1.3.2
MIDWESTERN-GREAT LAKES SULFUR EMISSIONS USING WESTERN COAL
Coal Source
Composite western
Arizona
Wyoming
Montana
Total Sulfur Emitted
0.42
0.21
0.33
0.52
Net Decrease
0.69
0.90
0.77
0.59
% Decrease
62
81
70
53
(a)
MMT/y as sulfur
IV-285
-------
In both cases, sizable reductions are seen to be possible. The
Midwestern-Great Lakes region has the potential for even larger reductions
than the nationwide average because of the higher sulfur fuels currently
being burned in this region.
These reductions are theoretical reductions and do not reflect any
problems that may occur while firing western coal. Potential problems such
as equipment derating or an increase in other emissions would adversely
impact these projections. On the positive side, an additional reduction
may be realized in SOx stack emissions due to differing sulfur forms
(organic, pyritic, or sulfates) in western coals as compared to midwestern
or eastern coals. Also, the different nature of the western coal ash (high
NaO and MgO) may act to effectively reduce SOx emissions.
IV-286
-------
2.1
DEFINE CANDIDATE WESTERN COALS
Wyoming and Montana are the two largest western coal producing
states. The geography of the western coal deposits dictate that these two
states will be the most successful in supplying midwestern and eastern coal
consumers at competitive prices to eastern coal. Therefore, the coal
resources of these two states will be the focus of this task.
Wyoming
Wyoming has 545 billion tons of coal between 0 and 6,000 ft of cover.
This is 17% of the national total and ranks Wyoming first among the states in
total coal resources. Of this resource, only 25%, or 136 billion tons, is in
a mapped and explored category within 3,000 ft of the land surface. Of that
amount, approximately 2% is lignitic, 10% is bituminous, and 88% is subbitu-
minous. One-half, or 68 billion tons, of the mapped resources are considered
recoverable. Seventeen percent, or 23.7 billion tons, of the explored
resources are classified as strippable. This strippable resource is greater
than that of any other state and represents nearly 20% of the nation's known
strippable coals. Of those 23.7 billion tons, 19 billion are termed recover-
able and 14 billion of that are classed as reserves by today's standards.
While almost 90% of Wyoming's strippable coals underlie the Powder River
basin, the Hams Fork and Green River regions each contain over 4%. The
remaining 1% to 2% of the resources lie in the Hanna field and Bighorn basin
areas. A map showing active Wyoming coal mines is shown in Figure 2.1.1.
The rank of Wyoming coal ranges from lignitic to high-volatile "A"
bituminous. Lignite occupies a very small region in the northeastern part
of the Powder River basin. Bituminous coal is restricted to the Black Hills
region and portions of the Hanna field. Green River region, and Bighorn
basin. High-volatile "B" and "A" bituminous coal is reported only in the
Hams Fork region. Subbituminous coals are found in all major coal regions
except the Black Hills region, and account for most of the state's resources
and current production.
Typical Wyoming coal analyses exhibit the following ranges and
averages:
IV-28 7
-------
t
HUCH KiNf
• 9BIG HORN'S
NO. 1
O H1
9 AH
ODAK MINE
Alf'S BE Lit AYR
* DUSKY DIAMOND K1NE
"ARONCCO .MINE
BEST'S EAST ANTELOPE
P.P. t L 'S DAVE JOHNSTON
FUEL RECOVERY PIT '
ARCH'S SOTNDE NO.
QROSEBUD'S PIT NO. S
ROSEBUD'S PIT NO.
I —_ «V IMJiLDULI a ril 11U. 1
RER'S SOSENSEN "ER&Y'S VANGUARD MO.lA\OARCH»s SEBIHOE NO. 2
iERER'S ELKOL I V«ror.v«: vrTinN in PtT-
A 6UNN OUEALY'S RAINBOW NO. 7
*GUNN OUEALY'S RAINBOW NO. 8
ENERGY;S
10 PIT-
MIRE SIZE
(TONNAGE)
<.5 MILLION
,5-2.0 MILLION ~ >2,0 MILLION
^.UNDERGROUND MINE
Q SURFACE MINE
Figure 2.1.1. Active Wyoming Coal Mines.
IV-2 88
-------
As Received
Range
Seam Reserve
Averaqe
Moisture, %
Volatile Matter, %
Fixed Carbon, %
Ash, %
Sulfur, %
Heating Value, Btu/lb
1.7 -
32.0 -
—
1.4 -
0.2 -
7, BOO -
32.8
46.0
—
17.5
5.0
13,500
14.2
39.0
41.0
5.2
0.7
10,850
In terms of quality, coals with the lowest heat values, as well as
the highest moisture and volatile contents, are found in the Powder River
basin. The higher heat values are more prevalent in the western and south-
ern portions of the state. Ash varies widely, with small isolated pockets
of high-ash content (15% to 18%, dry basis) in the Powder Riber basin, Big-
horn basin, and Hams Fork region. Sulfur contents are realtively low and
variable. The southern and eastern parts of the Green River region contain
some of the highest sulfur values. Overall, more than 99% of Wyoming's
coal contains less than 1% sulfur and about one-half of that is less than
0.7% (as-received basis). Ninety-six percent of the strippable coals con-
tain less than 1% sulfur, 3.5% is between 1% and 2%, and 0.5% is greater
than 2% sulfur (as received).
There are 25 coal seams currently being mined in Wyoming. Surface-
mined seams are between 6 and 118 ft thick, but average 32 ft. Seams mined
underground range from 3.7 to 20 ft, averaging 8.5 ft. The thickest surface
mined seams occur in the Hams Fork region and Powder River basin. The latter
basin also contains the nation's, and peihaps the world's, thickest seam of
220 ft.
Table 2.1.1 contains a listing of the active mines in Wyoming and
Montana. Also shown are the estimated reserves, estimated useful life, and
current 1973 and 1974 production of the mines.
The coal analyses of the 14 largest mines in Wyoming and Montana are
presented in Table 2.1.2.
IV- 2 89
-------
TABLE 2.1.1
COAL
Company
MONTANA :
Westmoreland
Decker
Peabody
Western Energy
WYOMING:
Amax
Wyodak
Arch Mineral
Rosebud
Kemmerer
Bighorn
Energy Development
Pacific Pwr & Light
CANDIDATES FOR
Mine
Sarpy Creek
Decker No. 1
Big Sky
Colstrip
Belle Ayr 1
Wyodak J
Seminoe 1 1
Seminoe 2 >
Rosebud J
Ekol 1
Sorenson J
Bighorn
Dave Johnston
Jim Bridger
TESTING (ACTIVE
Life
Reserves (yrs)
1500 MT 100
2240 MT 30
1440 MT 50
18,500MT 50
305 MT 15
1679. 9MT 10°
60
15
35
35
MINES)
Current Production
(Million tons/yr)
1973
4.00
4.15
1.97
4.25
0.89
0.75
2.87
1.50
1.51
0.40
2.55
0.45
2.90
1974
--
6.79
2.23
3.21
3. 30
3.14
2.59
1.96
2.44
__
2.7
IV- 290
-------
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a
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See Appendix A for Ultimate Analysis
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IV- 2 91
-------
Sulfur content of the Wyoming coal produced by these mines is all
well below 1% and the heating value is generally around 10,000 Btu/lb. The
ash softening temperature (reducing atmosphere) of these coals varies some-
what from seam to seam but is generally around 2150°F. Grindability of the
coals as measured by the Hardgrove Index indicates that they are slightly
harder to grind than comparable eastern coals. The Hardgrove Index ranges
from 0 to 100 with 100 representing good grindability. Therefore the lower
the Hardgrove Index number, the more difficult the coal is to grind. This
poorer grindability will have an effect on the performance of coal pulveriz-
ing mills in pulverized-coal-fired units. The Hardgrove Index, however,
does not give a true representative indication of the western coals grinda-
bility as received since the coal must be air dried prior to performing the
test. The higher moisture content of western coals requires higher air
temperature in the pulverizer to improve grinding performance.
Montana
Figure 2.1.2 depicts the geographical areas of Montana coal fields.
The Fort Union region of eastern Montana is presently the focus of major devel-
opment. The interest in this area is expected to continue for the foreseeable
future. Estimates place the strippable coal in this region at more than 38
billion tons. Figure 2.1.3 shows the locations of strippable subbituminous
coal and lignite fields in eastern Montana. Table 2.1.3 gives the name of
the field, the coal bed, thickness, estimated reserves, average tons/acre,
ash, sulfur, and Btu. Although coal is present in other parts of the state,
it is of less significance because recovery would require deep mine methods.
Characteristics of the topography and the thickness of the Fort Union
coal beds make possible the mining of large quantities of coal from rela-
tively small, compact areas, which facilitate reclamation. Coal beds 25 to
60 ft thick are not uncommon, and in the Decker area, the coal in a single
bed reaches a thickness of 80 ft. Matson and Blumer (Ref. 6) have surveyed
southeastern Montana and analyzed 32 coal deposits; proximate analyses, forms
of sulfur, calorific values, and major ash constituents of the coal samples
are included.
Currently, only five companies are producing coal from the Fort Union
beds of eastern Montana. They are:
IV-292
-------
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V BITUMINOUS
' COAL
CZ1
SUBBITUMINOUS LIGNITE
COAL
Figure 2.1.2. Map of Montana Coal Fields.
IV-293
-------
MONTANA BUREAU OF MINES AND GEOLOGY
OF
STRIPPABLE SUBBITUMINOUS COAL
i**cf!_zr "' I 1 ls.r\i~-i
LIGNITE FIELDS. EASTERN MONTANA
• ° J*° * * v f .*> _JuC i 4
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—2)^JO4
Figure 2.1.3. Location of Strippable Subbituminous and Lignite Coal Fields
in Eastern Montana.
IV- 294
-------
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IV-295
-------
Knife River Coal Co. has an average annual production of slightly
over 300,000 tons of lignite coal with a Btu rating of 6520 and a sulfur
content of 0.5%. This mine is dedicated to the Montana-Dakota Utilities Co.
power plant at Sidney, MT.
Western Energy Co. is a wholly-owned subsidiary of Montana Power Co.
with operations at Colstrip. Coal analyses are given in Table 2.1.2.
Decker Coal Co. is a joint venture between Pacific Power and Light
and Peter Kiewit Sons' Co; the latter being the operating partner. Table
2.1.2 gives coal analyses for this company.
Peabody Coal Co. is currently mining over 1.5 million tons annually
from the Rosebud and McKay beds near Colstrip, MT. Unit trains haul coal
800 miles to Cohassett, MN for Minnesota Power and Light.
Westmoreland Resources is a Montana-based partnership owned by
Kewanee Oil Co, Penn Virginia Corp., Morrison-Knudsen Co., Inc., and
Westmoreland Coal Co. Westmoreland's operations are located at Sarpy
Creek, MT. Westmoreland ships coal to five midwest utilities:
o Northern States Power Co., Minneapolis, MN
o Wisconsin Power and Light, Madison, WI
o Dairyland Power Cooperative, LaCrosse, WI
o Interstate Power Company, Dubuque, IA
o Central Illinois Light Company, Peoria, IL
The coal analyses of the four producing mines in Montana from Table
2.1.2 show somewhat higher sulfur content (0.8% average), and lower Btu
(8500 average) than Wyoming coals. It is this combination that could make
Montana coals of marginal value for reducing sulfur below the 1.2 Ib SO /
MBtu regulation. Ash softening temperatures and Hardgrove grindability are
comparable to Wyoming coals.
IV- 296
-------
Coal analyses for the 14 largest mines in Montana and Wyoming are
presented in Table 2.1.2. They are representative of approximately 95% of
the projected coal production capacity from these two western states through
1983. The use of any one of these coals in the test program would be valid
based on the ability of that mine to produce coal at better than present
production levels through 1983. However, all mines listed in the table have
expansion plans. Most mines project a doubling of present production by
1980 and some, such as Westmoreland Resources, expect to increase production
by a factor of five by 1982.
IV-297
-------
2-2 EXAMINATION OF SUPPLY VARIABLESOF SPECIFIC WESTERN_COALS
Intrpduction
Availability, mining and transportation costs determine the price
that must be ultimately paid by a user of western coal. Coals with desirable
properties such as relative high heating value and low sulfur content demand
a higher price as do coals in limited supply. Prices at the mine are also
subject to several factors including type of mining operation, storage and
handling facilities and the extent to which the coal is processed. Variables
affecting transportation cost are size and frequency of shipment and location
of user with respect to existing transport facilities.
The data presenting the current production from the mines in Montana
and Wyoming are presented in Table 2.1.1 (Section 2.1), along with projec-
tions of future expansion.
Table 2.2.1 gives the average value per ton of bituminous and lignite
coals at the mine for 1971 and 1972. Note that strip mining costs per ton
had risen from $1.79 to $2.01 in Montana and from $3.35 to $3.69 in Wyoming
or approximately 10%. Projected cost to maintain and expand future production
are considered confidential by the mine operators and therefore were not~
.ade available for this study. Additional increases beyond the 10% annual rate
were expected for 1973, 1974 and beyond due to inflationary pressures.
Transportation costs have the greatest influence on western coal
pr -es to potential users in the midwest due to the long distances involved.
The only feasible means of transporting western coal to users and to
distribution centers in the midwest is by rail. No other alternative exists.
Once the coal reaches the Great Lakes or Mississippi River, water trans-
portation systems become available. Early transfer to waterway shipment is
preferred over all^rail transport since the cost is lower.
Rail Transportatipn
Existing rail lines of three major carriers service the Montana-
Wyoming coal fields. These lines are illustrated in Figures 2.2.1 and 2.2.2.
The Burlington Northern has extensive rail connections in both states that
transport coal from the Powder River basin along main line connections
IV- 293
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TABLE 2.2.1
AVERAGE VALUE PER TON, F.O.B., OF
BITUMINOUS AND LIGNITE PRODUCED, BY DISTRICT
1.
2.
3.
4.
5.
G.
s!
9.
10.
11.
12.
13.
14.
15.
16.
Ifi'
20'
21.
22.
23.
"Western Pennsylvania. -- ...
Ohio
P;inh:inole . . .....
Souttiern Numbered 2 ...
West Kentucky.
Iowa....... _.
Northern Colorado . .
Southern Colorado ....
Wyoming.. ._ _
North-South Dakota
Montana ... __.__
Washington . -
Total
1971
Under-
ground
$10
9
7
6.
6
13
9
5
5
£
4
11
13
5
8
£
7
9
13
8
.08
.53
.73
.75
.60
.82
.32
.46
96
61
.82
.30
.99
.25
.18
.25
.37
.33
.55
.87
Strip
$6.49
6.09
6.12
4.75
4.56
10.22
6.31
4.50
5 05
4.54
5.83
9.13
5.16
3.9J
2.62
3.35
8.00
1.91
1.79
7.16
5.19
AUC.r
$6.26
5.61
5.53
4.35
10.02
6.67
5.25
5.05
8.50
2.20
6.57
Total
$8.12
S.78
7.36
5.24
6.55
13.21
8.18
4.83
5.46
5.18
4.66
7.97
10.53
5.16
5.25
6.71
2.62
3.39
7.37
1.91
1.82
7.27
7.07
Under-
$9.60
10.79
8.55
7.41
7.51
14.87
10.19
5.97
6.83
6.G2
4.XO
13.40
14.79
5.17
9.46
4.89
8.93
9.74
1C. 40
9.70
1972
Strip
$6.92
6. 38
C.84
5.29
6.50
11.40
6.41
4.81
5.49
5.51
4.91
6.S8
R.37
4.86
2'68
3.69
8.00
2.02
2.01
6.99
5.48
Au,
$6.
5.
6.
4.
6.
11
G
5
6.
6
:«
66
34
36
69
.50
RH
47
64
.18
.54
ToUl
$8.25
9.93
8.16
b.96
7.49
14.45
8.86
5.23
6.14
5.58
4.86
9 43
9.04
4.86
5.17
7.25
2.G8
3.74
8.93
2.02
2 03
7.07
7.66
IV- 299
-------
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to several key distribution points. Existing mining operations along the
main line of the Union Pacific through southern Wyoming ship coal to Omaha
and Kansas City. Tracks of the Chicago and Northwestern Railroad extend
into the Powder River basin in eastern Wyoming with existing facilities that
generally split the BN and UP systems to the Great Lakes. Several joint
ventures between the UP and C&NW are under way to deliver southern Wyoming
coal to the Minnesota, Wisconsin, and Chicago areas.
Figure 2.2.3 presents a geographical distribution of the various types
I of coals employed in the operations of the firms questioned during the survey
of current users of western coal {Section 1.1). Western coal is available
at reasonable shipping costs to users along major rail connections to the west.
I The coal is also transferred from existing rail to river barges for distri-
bution along the Mississippi River and from rail to lake barge in Duluth
to allow transport to other Great Lakes ports. A complete breakdown of the
firms contacted and the types of coals used are included in Appendix A
and Section 1.1.
No additional main line connections are planned for western coal
shipments; however, some track extensions and improvements have been deemed
necessary. As shown in Figure 2.2.4, a 116-mile track connecting the main lines
of the BN and the C&NW has been proposed jointly by the two railroads to open
up the central Powder River basin. Also planned for the C&NW is a complete
upgrading of the main lines from Shawnee, Wyoming, to Freemont, Nebraska.
Extensive additions and improvements to the coal-handling equipment have
also been undertaken.
Unit Train Operation
Currently the most economical means of transporting western coal to
midwestern markets is by unit train. A unit train is a set of locomotives and
cars that operate in a continuous cycle from one origin to one destination
and return. Techniques and equipment are now in use that have made the
widespread use of western coal possible. The continued application of the
unit train is a key factor in future western coal shipments.
IV- 302
-------
„ I
\,
\
\
\ A.
I
WESTERN COAL EXPERIENCE
O TESTED
O BLINDED HI1H OTHER COALS
«> USED iOOZ
Lake
Superior
A 3002 HJIMSTERH UOWA,OKLA.,KA!I.)
A.300Z LIGNITE
D IOOZ EASTERN (111.,KY..OHIO)
Figure 2.2.3. coal Users Contacted During Survey.
IV-30 3
-------
LEGEND
EXISTING B N.
PROPOSED B.N.
GILLETTE FfELD
POWDER RJVER
FIELD
I |
B.N. LINES IN MONTANA S WYOMING
BURLINGTON NORTHERN INC
PROPOSED SPURS TO COAL LEASE AREAS
STATES OF MONTANA 8 WYOMING
Scale l" = 35 Miles March 16, 1971
Engineering Division St. Paul, Minn.
fifv,4rd Mo-ch 13, I97S
Figure 2.2.4. Western Coal Fields showing Rail Lines in Area.
IV- 304
-------
Loading is generally accomplished by a high-speed conveyor system.
The coal is carried to a storage bin located at the top of a tipple and
loaded into the train as it moves continuously underneath. A typical load-
ing operation of 100 cars can be completed in approximately four hours.
The trains are multiple engine powered with the diesels generally
separated into two groups. The lead diesel, located in a group in the front
of the train, is manually operated and transmits commands to the other group
of engines located near the middle. The purpose of this group is to spread
the tractive efforts through the train so that the draw bar pull on the
front car is not excessive. Problems of stack due to the extremely heavy
trailing weights are also significantly diminished. The locomotive arrangement
also helps in overcoming potential brakeline air pressure losses which is a
serious problem in the operation of long trains. Stops during long hauls are
limited to routine maintenance and inspection.
The unloading process is accomplished by the use of either rotary or
bottom dumping cars. Rotary dumpers are equipped with swivel couplings so
that each car can be rotated about the coupling without being detached from
the train. Significant improvements to coupling designs and positioners have
greatly reduced unloading times. Bottom dump cars with specially designed
hoppers for fast unloading are employed with shakers or vibrators for complete
discharge. Unloading of an entire train to storage facilities or water
transportation can usually be accomplished in under four hours.
The unloaded coal is stored in conical piles or in bins and silos.
Covered storage is usually preferred due to the protection from the weather
and reduced handling costs; however, the increased initial capital investment
is higher than with open storage. The key factor in ground storage is to make
it possible to recover as much of the coal as possible with the minimum amount
of handling. Problems are also encountered with unsightly and dusty open
storage conditions in metropolitan areas.
Improvements in unit train performance are being made by the use of
advanced car designs and materials, along with better scheduling of equipment
employment and maintenance. The regions of long-distance hauling have
required modifications to the dynamic braking system and coupling devices.
Coal hopper cars are larger, 100 ton vs. 70 ton, and equipped with automatic
door opening and closing devices or swjvel couples for rapid unloading. It
IV-305
-------
is estimated that an additional 2800 new large coal hopper cars will be
needed to haul western coal once full production is met. Periodic inspec-
tions and maintenance are conducted at regular intervals (usually 500 miles)
for safety and improved mechanical reliability.
While the continued improvement of unit train operation has allowed
railroads to hold shipping rates down, current inflationary pressures are
requiring adjustments to shipping costs. The primary factors affecting these
costs are labor and materials. Rates over a particular route are determined
through negotiations between the railroad and the receiver. These rates are
periodically adjusted based on a mechanism established during negotiations.
These rate adjustments are usually based on the Index of Railroad, Material
Prices and Wage Rates of the Association of American Railroads.
Current unit.train shipments involving the BN, UP and C & NW are
outlined in Table 2.2.2. Listed are the location (mine) of origin, destination
(user), 1974 shipment volume and the rates as of March 1, 1975. In all cases,
shipments are made directly to utilities and are primarily used in boilers of
greater than 300,000 Ibs steam/hr. As illustrated in Table 2.2.2, shipping rates
range from $3.43 per net ton (17C/MBtu) for delivery in Sergeant's Bluff,
Iowa, to almost $9.00 per net ton (45$/MBtu) for receipt in Hammond, Indiana.
In addition to unit train deliveries, several hundred cars per month
are moved from the western coal fields to the midwest in single and multiple
car shipments, and in entire train loads on a non-unit train operation. These
shipments generally go to paper companies, industrial concerns and small
utilities in Iowa, Wisconsin and Minnesota.
Shipping rates for non-unit train deliveries as supplied by Burling-
ton Northern demonstrate the dramatic cost increases that must be absorbed
by the small users. The tariff from Colstrip, MT, to Minneapolis, MN on
shipments of train load lots on a single line haul not under unit train
operation is $5.55 p.n.t., while a single car shipment is $9.03 p.n.t. Simi-
larly in the UP system, unit train deliveries from Hanna, WY to Kansas City,
MO are shipped for $3.74 p.n.t., while lot deliveries of 1,500 tons cost
$7.99 p.n.t. A typical western coal tariff is presented in Table 2.2.3.
IV-306
-------
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IV- 308
-------
TABLE 2.2.3
WESTERN COAL TARIFF FOR LOCAL, JOINT, AND PROPORTIONAL RATES
BURLINGTON NORTHERN, INC.
Effective April 8, 1975
ITEM
©
200 -F
SECTION ]
SPECIFIC RATES !N CENTS PER 2,000 LBS
(For application, sec page 22 of tariff)
COMMODITY, CARLOADS
B1TU \1NOUS COAL. In open lop cars.
Minimum weight marked capacity of car,
except when loaded to full visible
capacity, actual weight will apply.
Routs: via;
GpBN- direct.
©BN-VJnneapolis, MN-CNW.
(T'BN-Minneapolis, MN-SOO.
cf/BK'-Sl Paul, MN-MILW.
OJBN-St Pau],MN-RI.
(0) B N- Mi 1 es Ci( y , MT - Ml LW .
©Expires a? indicated in Item 150.
(ML A-8G96)
REFERENCE
MARK
A B
APPLICATION
FROM
Cohuip . . . .MT
TO
Ames .... IA
lAustin. . . . MN
Burlington . . IA
Cedar Falls . IA
Cedar Rapids . IA
Clinton ... LA
Com Belt . . LA
Davenport . . IA
Dubuque. . . IA
Eau Claire . . Wi
Humbolt. . IA
lowana ... IA
Menasha .- . . wj
Milwaukee . . wi
Muscatine r . JA
Necnah . * . VV1
Neen»h-Menash*JV]
Rochester . . MN
Spencer ... LA
Waterloo . . IA
Waupun ... wi
RA.TES
<2> 1044
©(S© 1000
03 1049
(2X5> 1029
@®©(S)1044
§1029
1044
1029
@©1029
©^^©lOOO
©]044
©1029
@^]312
©a3)®1312
®@©1029
Q0®1312
©1312
0)000
©3)©1044
(2)©1044
©(3)1312
EXPLANATION OF REFERENCE MARKS
EXPLANATION
Denotes Reduction.
B-Brought forward without change.
IV- 309
-------
Multiple line haul deliveries are even more expensive. For example,
the proposed unit train tariff from Colstrip to Columbia, WI, via the BN
and C&NW is $5.30, while a single car delivery to the same area is $13.12,
or 148% higher.
The above shipping costs point out the problem facing small users
of western coal. Unit train operation for large users (primarily utilities),
has allowed shipping costs, and therefore total cost, of western coal to
become competitive with the traditional bituminous coal suppliers in the
east and midwest. In order to make western coal more attractive to non-
utility users, a method must be found to incorporate the unit train con-
cept into the small user's supply system.
Rai_l^_t £-'••• atc-r Tranpfer_Faci 1 ities and Distribution Centers
The concept of a central distribution center supplied by unit trains
and feeding several users has been proposed. All of these facilities will
be used initially to supply a large utility and will be in conjunction with
a rail-tc-water transfer system. Since many present coal users are supplied
from traditional sources in Illinois and Kentucky by water, the importance
of this transfer is obvious. Currently, western coal supply/distribution
centers are planned or under construction in the Duluth, Minneapolis, and
St. Louis areas.
A rail-to-ship coal handling facility is currently
under construction in Superior, Wisconsin, to handle western coal shipments
to Detroit Edison that will result in a 40-50% reduction in all rail shipping
costs through Chicago. Initially, this facility will handle 8,000,000
tons per year of Decker coal to Detroit Edison delivered by unit trains on
the Burlington Northern and Chicago and Northwestern systems. An additional
6,000,000 tons per year capacity that is as yet uncommitted will be available
for other users.
The C. Reise Coal Company, who will have joint ownership of this
facility, is planning an additional facility to handle primarily smaller
customers in train load lots of 50 cars on a non-unit train operation from
the Peter Kewitt operations at the Big Horn and Rosebud Mines. Significant
IV-310
-------
shipping cost reductions will be realized from single car deliveries. The
coal will be loaded on to lake barges to distribution to customers along the
Great Lakes. It may prove feasible to subsequently transfer the coal from
lake barge to other surface transportation for delivery to u^r-r.
A plan for a coal wharf to store und 1 j <;.':sfc-r <"oal f> oin trains to river
barges has been propor^'d for the Kinncapolis - -St. Paul ti'ea. The facility,
conmonly called "Pig's Eye", will be supplied by unit 'trains along the
Burlington Northern and Chicago and Northwestein Railroads fiom the r.arpy
Creek Mine in Montana. The facility is primari ly designed for ur-e by
T-brthem states Power, Dairyland Cooperative, Interstato rover Co:"], any, ;-ud
Wisconsin Power and Light. However, storage and transfer facilities for
smaller users have been p!.j.-:;,ed. The forility will hai.dlr a; i •• cy. '.-.- ^ ely
S,000,000 Ions of coal per year.
Currently the coal wharf project has .'jot b-.
State
of Minnesota due to enviroMncntal conceir.s. J-.t gu;>--jits c.-;;,; i::i: t 1 he facility
include unsightly conditions, dust and noise. Hevc-ral p* t.^-o'-.a] s to JH.pt ove
the situation including a possible dome to c:ovpr the facility, Lnve h-r.-c^n
made. None has yet been approved. Without this facility, f u; -ore
expansion of western coal to small users in the Minnesota - Wisconsin
area is in serious jeopardy.
Four other rail-to-river facilities are curiently } roj; f^sed or ur.<;»r
construction in the St. Louis ar<~-a. A 30 , 000,000-ton facility in '•'• i re.: ol i s,
Illinois, is scheduled for completion in 1976 that will be for the .vole
ui-.e of the 7-.:-,erican Electric Fowf-r Couicany, a ho] ding c-o;:.:-any t.V.nt i c-r.:. i ^. ts
of several utilities in Ohio, Michigan, West Virginia, and Tenm-; ?ee. Coal
will be delivered by unit trains from Wyoming and Utah by the Burlington
Northern and Missouri Pacific Railroads. This facility :nay (.'vent'os; ly <-xr eir>d
to 20 million tons per year.
A facility initially designed for industrial users has been proposed
for the Tri Cities HegJonril Port District. /-.gain, cr-1 i vv-1 i or. will b'... ::..ide
by unit train, stockpi 1 c-d, and su;-plied to users either by river be: r ye using
existing poit f aci ] i t i cs or by truck. The initial capacity ior thje facility
is 2-3 million tons per year but may go as high as 15 million tons.
IV-311
-------
An exi sting rai 1- to-water facility in St. Louis operated by the
Feabody Coal Corpany has been employed to transfer coal to the Anerican
Electric Tower Company for test purposes. Cnce the Metropolis, Illinois,
facility is ccinpl etod, this may be available for unit train delivery and
storage for nory-ut i ] i ty users.
A;.-< 'l.her ular.;.<-d operation to be oc. vel op^d by the An-i"! can Ccr.:'erei a 1
Rajije Co;;,; any sj ini lar t.o the Pig's Eye ceal wharf b.-is been proposed for
the St.T.ouis area. Initially, this would be employed for shipments to
utilities in the lov.-f.-r Mi «:<_•- i^sippi Kivc-r. Like the St. Paul facility,
this projc-ct is ;:;':tting 3 c-r i s;.«nce fro.Ti c-nvi ronr.^-ntal cro\i}:s ar-sd has be&n
forced to altt.-r locations. This c.-peration, once approvc-d, will >,ave a
capacity of bc-tv.s-on 10 ar>d 20 n.i 11 i on tcr:s t cr yi.-ar, the portion of
which will be avrii].-=ble for :~";al! i:rors is ai; y(.-t ,:!:,:o; i. f :• '•. :~-.ed..
'.?:.e l'--v;e?- t r..:'.s-. or: .:' i on c^s; r c"=r:ti cxi-StMig real-:..::':«! ino facili-
ties r.";V.e .^n (.arlv i r-ir:sfer to w"=i t:rv:ay shi[ :ricnt prc-icjred over c-.n all-
rail i-hlr-:i-.-.vnt. As i 11 ustr;;! ed in Figure 2.2.5, 1ht? cxistiny inland \-,<:ieiv.«
syst.em coi;ipor,cjd i:ht mills per i en
Tije "or "unit trcain .--hi ; if.-r:it s. It has boon es t i r.at r-d ihst a r>.c-t '.^.v.i^s
of ?6 to $fi per ton <-.^n be icalizeci on western c-c-al nhiv~itnts fru-:r. >;ont.Aria
to DetT'oit Edison using a combined rail and lake ship transfer ovf?r an all
rail shipment to Chicago.
J-uirbo bcMjes that are 195' x 15' and carry 1 SOO tons are used to
transport coal on river wat e rvvays. Barges are generally giouped into tows
theit can range from 15 jumbos on the upper Mississippi t.o 30 on the lower
Mississippi. These tows can be x:r-ed in areas of limited draft and allow
IV-312
-------
2. 2. S. Mi«:^i : v-::•.•.! K'i vc-:
Kt-l wc>! k .
c.nrt Gn'at Lakes Inland vratei-way
-------
coal shipments on all .inland wjit orv-.ys < >:rvpt i b(:.- upper Ohio River. It
is est.invited that, an additional 260 now j '.;;••': jo h.^-tj.-s wi 1 1 be rnquiruc:! to
haul v:r->s1 ein ooal once full prouuci ion is ::.c-t.
Expansion of :iho Soo Looks ,= t r njj
has allov.e-d the 'i:• ie on the- Gioat l.ck o-s
.:-.''• -:-:ri ~. : .::::::>. '.-'t un to f»C>,000
-.7 .:.-.c ...-<.• i;.'-:;:- -'a 1 1 y ri'^l^ciny
••! ;.- >i' •':.•.!• -m. A ri-jvnt .'••'.; r i t .i ine
!r:-.;. w.i 11 ',-.^ , uio i'or ,:j-p)'oxi-
.bc-. :•.>.•.:•.?• .:•-.•: ^ :-.-, - 1 h '• : ,3 that
An added incentive to a rai 1 - TO -w^-i «.-r
coal users are pn sc-nfly su-op]j...d by •.•.\iier. i
located on wa^ r--r,s\-;.ys to take advent ,.;y e of the
and the avail, :bi 1 i ty of w.-itcr foi o.>ol i nq ,:;-d
instances, especially with electric: ur-ility -":••
delivered dirc-ctly to the dock of the ; !^n: ;. :
Conclusion
Estimates are that the pj esorjt !">0 ;ni 1 1 i o>n 1 L n:s
western coal wi]] iri'-rnasc- to 2SO rn-ijVior i •-r.i- ,;:.•••.;.-.1 1%
and technology rc-qui i ed to mine it <-.-e :-:L: ;.•-::' i'/:. c::"
for this expansion to occur, a f avcx .:bl o c--
will encourage the development of this ooal on a l^ng •;
L- :^ot. :;,i;t ::.3ny
t i; hi:vo 1:. en
oost. wal'-r t •-t-.:-^:pcj ;.at i on
•• r. s ; ncr. In os.; r t ain
;' -: :v.j <-: ,o ic::s, ( oal is
M ; 1 i.st- it.
].-. .•-..•:.-.rii^re rail
' •'. "-.'>.••• • e .' n oo.il
IV-314
-------
i.
2.
3.
4.
5.
K!-.r'LRKNCES_
Lock 1 in, D. W. et al., "Design Trends and Operating Problems in
Combustion Hod i £ i c ,3 1 J on , July 1971.
Keilson, G. J., ed., 197-1 Xc-yst '.-nc
Hill, New York, 3974.
Irou^try .'•';-.ri;al_, >'r^r;:w-
Ctvrtnicek, J. E. et ril . , "Kval u.-.l i on of Tov -.Sul f ur V."'.-?,t orn Coal
Char.ict p-ri st.i cs , lit i 1 i?.^ t ion, ,-:nd C< •r.b'ij.-it. i on Vxv-r- r i t nee , " Final
Ktport, Contract 03-02-1-20, 1^75.
Bit uridiious Coal <:Tid i-;v}'.iie !?•: :-; > : ':••-, i~i ion - C«" r--:, ~r=r vo<-.r 1473,
M: nc-ra] Impost ri •: •;> P...!~vcys, U. S. r-oot of the Iiii.erior, Sujiau
of Mines, w.ishiiKji on, Dr, April 12, 1974.
IV- 315
-------
1:20 p.m.
Systems Evaluation of the Use
Of Low-Sulfur Western Coal in Existing
Small and Intermediate-Sized Boilers
Dr. Kenneth L. Maloney, KVB Engineering
Q: I missed the point on the 2000 ppm CO level on the
Kentucky coal. What is the host boiler owners'
approach to the high CO emissions? How are they
coping with the problem?
A: That wasn't the Kentucky coal; that was on the Montana
coal.
Q: I'm sorry; so that is not their base coal, then.
A: They will fire anything they get that comes down
the river.
Q: But is there no way to get around that problem?
A: They don't worry about CO since they don't measure
it. One can increase the excess 0- to offset the
CO emissions, but then one pays a NO penalty. We
changed the flame patterns in this unit and we, as
Mike Heap talked about the other day, can get a
long skinny (low NO) flame, but it hits the back
wall and of course you don't want that. Then,, of
course,we can get a nice short, compact flame, with
very high NO. So we did do some tuning. When we
go into a unit, we test it as we found it, if it
is not too radically off base. Then we try to do
some modifications. In a pulverized unit, this con-
sists of burner/air register modifications, where
one tries to get the 0? distribution smoothed out
in the duct and the flame shaped up nicely. We
search for a NO vs. CO tradeoff point where the
combustible losses do not impact unit efficiency.
IV-316
-------
Basically, this involves lowering the excess 0
through the unit. We then do another series of
emission tests and then we switch coals.
On the sulfur analysis, you gave 4% for Kentucky
and 1.8 for Montana, which is roughly a 2-1 ratio;
but on S02 it was 3800 for Kentucky and only 1000
for Montana, which is about A to 1, which means either
some of your sulfur is unaccounted for or maybe
that Montana number should be 18. The Montana coals
are supposed to be low sulfur and 1.8 seems kind
of high for Western. Have you looked at sulfur in
the ash?
We are analyzing the fly ash and the bottom ash for
sulfur on this unit. The completed data are not
available yet but preliminary inspection indicates
that there is some sulfur retention by the ash.
They will be happy to hear about this in Montana.
Q: Probably this question should be to Mr. Cuffe, but
during the discussions the last couple of days, CO
popped up again and again and again whenever we were
talking about NO and people are talking about the
possibility of the CO and the NO having interaction,
X
Yesterday, it was mentioned that some trade-offs
are acceptable. Some of these CO limits we are now
talking about are starting to creep up there pretty
high. Most people have mentioned that there is no
standard for that.
IV-317
-------
Well, there is no standard. I was wondering, now that
we are all here, what are the future thoughts about a potential
standard for CO? You kind of figure since they are setting
standards for everything else, it is just a matter of time
till they get around to it. I think that is a very important
question, especially in lieu of what the discussions in the
last couple of days have led to.
A: [By Stan Cuffe of EPA:]
I guess I can't say just what a standard would be
for CO. I can say, however, that in setting a new
source performance standard the Clean Air Act does
not require that you look at ground level concentra-
tions to see what the impact is. It does require
that you base the standard on the best systems of
emission reduction, taking cost into account. However,
we also have to prepare environmental impact statements.
So, for any source, large or small, for which we would
set a pollutant standard, we will do diffusion modeling
to see what effect the standard would have for a specific
pollutant on ground level concentrations. In a number
of cases, because the ambient air quality standard for
CO is quite high, we have not been that concerned.
I think that in EPA in the last several years since
the act was passed, we have looked through now and
set standards, gathered data, etc., on 30,40,45 different
sources. These have been primarily particulates and
SO . I think in the next several years, although we
will still do some particulate and S0», the emphasis
will be more on controlling sources of oxides of
nitrogen and hydrocarbons.
Today, you can probably get more information down
at RTP from Dr. Knelson, who is the Director of the
IV-318
-------
Q:
A:
Health Effects Laboratory. Still, if there is a
tradeoff>we are much more interested in controlling
nitrogen oxide and hydrocarbons than CO. Obviously,
if the CO got to an extremely high concentration,
and the types of sources were small stacks instead
of real high stacks and you could have high ground
level concentrations, then naturally we would be
concerned with it. On proposed standards that we
will have...well, they have already been proposed
for electric arc furnaces in steel mills; we did not
cover carbon monoxide I don't believe. It was
just particulates there that we were concerned with.
I can't tell you right off hand just what the level
would be, and so forth. Again, as I am sure most of
you realize, it is not just the concentration coming
out of the stack but it is the mass rate of emissions
and then what that would be on short and long term
ground level concentrations. I am sorry I can't be
more precise on that. I do know that it has a lower
priority than either of the other pollutants that
I mentioned.
I think that is a help to us, Stan, because this
tradeoff between NO and CO has been a very important
aspect of combustion research for a long time. So
this is going to be something that will have involvement
There was one interesting point that one of the turbine
representatives who just left said; that even if there
were not standards set for carbon monoxide, they would
not allow it to get too high. Because of the large
IV-319
-------
amount of excess air if you get up over 1000 ppra of CO
their turbine efficiency drops off several percent.
So, in terms of economics, they just couldn't allow
that. [Comment by Stan Cuffe.]
Q: I think indeed the data has shown that there is a
NO/CO tradeoff. I think the important thing to bear
in mind is that is for a fixed system design, for any
given piece of hardware, as you decrease excess air
you would normally decrease NO; you will then reach a
point at which the CO breaks and increases. For
specifics let's go back to Paul Combs' comments on the
residential furnace, which is not a general case, but
it is a case in point. I think some of the data has
shown, that in fact, by a different design, by changing
air fuel mixing design, you can move the point of this
tradeoff much closer to stoichiometric. In the case of
the residential system you can go from, say, a 60% break
tradeoff point, 60% excess air to 15% excess air as the point
of that tradeoff, and simultaneously lower the NO emis-
X
sions. So, this has different impacts in terms of
simple changes in the operating conditions for a
fixed configuration, modification of a design of
a fixed configuration retrofit of a hardware change,
and, finally, new unit design. The point that should
be made is where we are looking toward a new unit
design and lower excess air operation for efficiency
we are also looking to push the tradeoff point through
the design for CO,smoke,and unburned hydrocarbon much
closer to stoichiometric.
IV-320
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A SURVEY OF EMISSIONS CONTROL
AND COMBUSTION EQUIPMENT DATA
IN INDUSTRIAL PROCESS HEATING
by
P. A. Ketels
J. D. Nesbitt
D. R. Shoffstall
M. E. Fejer
IV-321
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SUMMARY
Five major industries were selected for this program for the pur-
pose of investigating the interactions between current and potential energy
conservation measures and emission control programs. The industries
investigated consumed approximately 7. 1 quadrillion Btu in 1972, which
is about 34% of all the energy consumed within industry and about 9%
of the total energy consumed in the U.S. The industries investigated
were iron and steel, cement, aluminum, glass, and petroleum, selected
on the basis of the following restraints:
Total energy used in process heating
Combustion-related uses of energy
Relative number of processes within an industry
Known and/or estimated total emissions
Potential for energy conservation
Potential for reducing emissions.
Information for this study was obtained from two sources, i.e.,
literature and field interviews. Special emphasis was placed on a series
of field interviews held within each of the selected industries to obtain
information related to current operating practice, fuel availability,
emissions control and technological advancement.
Iron and Steel
The major operations of an integrated steel plant considered in this
study are coke ovens, blast furnace, basic steelmaking and reheating.
The fuels used for heat and power are selected on the basis of cost,
availability, and combustion characteristics. In 1972, coal accounted for
67.3% of the energy requirements, purchased natural gas and oil 28.8%,
and purchased electricity 3.9%. The quantity of energy consumed per ton
of steel shipped amounted at about 32.6 x 106 Btu. By 1980, the industry
expects to decrease the total quantity of fuel consumed by about 8% to
30. 1 x 106 Btu per ton. General fuel-uee trends in the industry will be to
increase the relative amount of coal consumed per ton of steel shipped,
and to reduce dependence on natural gas and oil.
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The major technological trends which will affect coke-oven energy
requirements consists of designing larger coke ovens, predrying of coal
charge, use of formcoke, improved operation of the blast furnace, and
direct reduction of agglomerated iron ore. Any of these changes, or a
combination of them, will greatly reduce the amount of energy required
in the production of iron and/or coke. The primary fuel for underfiring
coke ovens has been coke-oven gas. About 1/3 of the gas produced is
for this purpose. Total fuel required for coke-oven underfiring has been
about 3 million Btu per ton of coke produced. A reduction in the amount
of fuel required in coke-ovens would make additional by-product fuels
available for consumption in other processes, displacing purchased fuel.
The blast furnace complex consists of the sinter plant, blast stoves
and furnace, and sizing and handling facilities. An auxiliary fuel, such
as natural gas or oil, is used in the sinter plant to ignite a mixture of
flux, coke breeze, and iron-ore fines as it passes on a traveling grate
for agglomeration of the iron-bearing particles. The process is
autogenous once the coke breeze has been ignited by the auxiliary fuel.
This sinter material is gradually being replaced by agglomerated iron
ore (taconite) which has been produced at the mine. The amount of
ignition fuel required for this process is about 0. 12 x 106 Btu per ton of
finished product.
Blast stoves are checker-brick lined vessels used to supply heated
air to the blast furnace. Each blast furnace is served by 3 or 4 blast
stoves which are operated at predetermined cycles. Current techno-
logical trends affecting blast stove design consist of improved burner
design, improved hot valve design, better refractories and checker-brick
design, automatic stove-changing equipment, and improved operation.
Increasing the temperature of the blast-air as a result of these improve-
ments reduces coke consumption in the blast furnace and increases the
output of pig iron.
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The blast furnace is a cylindrical, tapered, refractory-lined
vertical furnace. It is charged with iron ore, pellets, sinter, coke,and
limestone and discharges hot metal and slag containing mineral gangue
and other impurities. It is a counterflow process wherein the raw
materials are charged at the top and travel down through the furnace
reacting with an ascending stream of reducing gases, primarily
carbon monoxide and hydrogen. The trend in blast furnaces has been
toward larger furnace design, higher blast temperature, improved burden,
auxiliary fuel injection, and improved scheduling and firing practice.
In steelmaking, iron from the blast furnace, commonly called hot
metal, and scrap are charged along with fluxes into the process melting
equipment. This equipment consists of open hearths, basic oxygen
furnaces, and electric furnaceSj which remove impurities such as
carbon,manganese, silicon,and phosphorous to specified levels by oxi-
dation.
Fuels used in open hearths consist of residual oil, natural gas,
coke-oven gas, tar and pitch. The amount of fuel required per ton of
steel produced is in the range of 1. 5 to 4 million Btu per ton. Increased
productivity has been achieved by oxygen enrichment of combustion air,
roof-mounted oxygen lances, and utilization of roof-mounted oxygen-fuel
lances to accelerate scrap melting rates and decrease fuel consumption.
However, the use of oxygen lancing has resulted in increased dust
loading of the waste gases and has required installation of more costly
air pollution control equipment.
Much of the open-hearth steelmaking capacity has been replaced by
the basic oxygen furnace (BOF). Auxiliary fuel is not required in the BOF
because the heat generated during oxidation of the carbon, silicon, manga-
nese, and phosphorous is sufficient to bring the metal to pouring temp-
erature. In the process, oxygen is blown downward through a water-
cooled lance into a bath containing hot metal and scrap. Furnace capacities
range up to 300 tons and the time required per cycle is very short, from
45 to 60 minutes. The BOF has an inherent limitation in that the amount
TV-324
-------
of scrap in the charge is limited to 25% to 30%. Some additional
flexibility can be obtained by preheating the scrap prior to charge.
Excluding fuel use for scrap preheating, other uses are for re-
fractory dryout and keeping the BOF vessel hot between heats. These
uses amount to about 200,000 Btu per ton of steel produced.
Two technological advances which will affect energy requirements
are direct reduction and continuous casting. Direct reduction consists
of beneficiating iron ore to a higher degree of metallization (up to 95%),
which can then be charged into an electric melter without the addition of
scrap, or it can be used directly in the BOF. This process allows the
bypass of sintering and blast-furnace operations.
In the continuous-casting process, the ingot stage is bypassed, and
the molten steel is transformed directly in slabs, blooms or billets.
The energy required to reheat the ingot prior to rolling into slabs,
blooms and billets is also eliminated. The quantity of steel produced
by continuous casting is increasing.
In most cases, field interviews did not elicit much relevant information
regarding emission problems and control, except that every effort is
being made, at great expense, to comply with local standards. Attention
was drawn to the large energy requirements needed to achieve compliance
with future standards, particularly those for fugitive and NO emissions.
vv
It was generally agreed that not much is known about NO emissions
Ji
and that further research is required.
Cement
The cement industry consumes natural gas, oil, and coal in the
direct-firing of rotary kilns to produce the final cement product. The
amount of energy required ranges from 4. 3 x 106 to 7.0 x 1 O6 Btu per
ton of final product. The amount of energy consumed is dependent upon
the process employed (wet or dry), age of equipment, and the application
of waste-heat recovery systems. Users of natural gas reported curtail-
ments ranging from 10% to 100% during the coming winter season.
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Coal, on the other hand, was reported to be readily available at drama-
tically increased prices, ranging from 55% to 80% between 1972
and early 1975.
The industry is very much aware of the increasing non-availability
of natural gas and oil and increasing energy costs; it is expected that
coal will become the dominant fuel in the near term. In addition to the
conversion from other fuels to coal, the industry can reduce the quantity
of energy required per ton of cement by installation of heat recuperative
devices such as suspension preheaters, chains systems kiln feed-end
enlargement, and improved process control. Reduction in the amount of
energy consumed per ton of product can be as high as 50%, depending
upon the type of installation.
Adoption of a vertical kiln operation in place of the rotary kiln can
potentially reduce energy requirements by as much as 50%. The vertical
kiln has been used successfully in Europe and Japan. It does not appear
that vertical kilns will be favorably accepted by U.S. industry because
of capacity limitations and some problems with product quality.
The cement industry has been able to comply with local, state and
Federal emission requirements by the use of baghouses to trap particulate
matter. However, disposal of the collected particulates is becoming a
major problem since it cannot be recycled to a great extent into the raw
material stream. A revision of the ASTM standard for cement alkali
content would help alleviate this problem.
Areas of further research directed to reduced energy consumption
and more efficient pollution control include investigation into the substitut-
ability of Type Z cement for Type 1 cement, investigation of alkali reaction
problems, improved process control, and development of combustion tech-
nology to reduce NO emissions.
Glass Industry
The major uses of energy in the glass industry are glass melting
(80%) and annealing (15%). Energy for the melting process consists of
IV-326
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natural gas, oil, and electricity. Melting is carried out in continuous
melters (containers, flat glass) and batch melters (specialty glass, etc.).
Continuous melters are reverberatory furnaces equipped with checker-
brick regenerators for preheating combustion air and range in capacity
from 50 to 1400 tons, depending upon the type of glass produced. Batch
melters consist of pot or crucible furnaces fired directly or indirectly
with capacities of 1 to 50 tons.
A fuel-fired continuous glass melter consumes about 6. 0 x 106 Btu
per ton of glass melted, excluding hold-over time. However, this
estimate varies considerably and is dependent upon furnace insulation,
combustion control equipment, molten glass depth, and the type of glass
being produced. According to the industry, there are several process
modifications that can be implemented to reduce the amount of energy re-
quired per ton of product. Those which have potential for near-term
implementation are improved process monitoring and control capability,
electric melting, and electric boosting. Estimates of energy savings
range up to 18% reduction per ton of product by electric melting (exclud-
ing the energy required to generate the electricity).
Methods of air pollution control currently in use in the glass industry
are primarily electrostatic precipitators (ESP) and baghouses for parti-
culates, and the use of low-sulfur fuels for SO emissions. The quantity
jC
of NO emitted is dependent upon several factors, some not clearly
understood and currently undergoing study. Other emissions, such as
carbon monoxide and hydrocarbons, are controlled by closely monitoring
the combustion process.
Aluminum
The primary aluminum industry is heavily dependent upon electricity
as an energy source (almost 52%), followed by natural gas (..0%), an '
oil (18%). Approximately 160 x 106 Btu of energy is consumed ;v a
primary aluminum plant for heat and power in the production of 1 ton
of aluminum ingot. Additional fabrication consumes about 36 x 106 Bta
IV-327
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in transforming the ingot into finished product. Secondary recovery
of aluminum from scrap requires about 20 x 106 Btu to produce 1 ton
of ingot. Since this program is primarily concerned with the processes
involving combustion of fuels, emphasis was placed on remelting oper-
ations wherein ingot is melted prior to fabrication.
Reverberatory furnaces are used for melting aluminum ingot prior
to fabrication. Natural gas is the principal fuel used in furnace operation
and oil is used when gas becomes unavailable. The efficiency of the
burner decreases when oil is used because a minimum distance is re-
quired to achieve atomization and complete combustion of the oil. The
thermal efficiency of a reverberatory furnace under optimum operating
conditions is 25% to 35%.
In its efforts to conserve energy, the industry is continuing research
and development programs to improve existing manufacturing processes,
streamline production processes by modifying equipment, and install
energy management programs at all organizational levels. These pro-
grams are the direct result of the current decline in availability of
natural gas to industrial users. The increased use of coal for steam
generation is regarded as a near-term solution to the energy problem;
in the long-term,greater dependence will be placed on nuclear power.
Some of the most recent developments directed toward reducing energy
consumption include flash calcining, electrolytic smelting, use of pul-
verized coal, and preheating of metal charge. The use of flash calcining
reduces the amount of energy required to produce alumina by 30%, from
about 2000 Btu to 1400 Btu per pound of product. The process combines
the benefits of the fluidized bed and dispersed-phase technology to improve
heat transfer and reduce heat losses.
Electrolytic smelting reacts chlorine and alumina to produce aluminum
chloride, which is then electrolytically decomposed in a separate cell
producing chlorine and aluminum. Power requirements for this process
are 30% less than customary production processes.
LV- 328
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An experimental program is being undertaken to determine the
feasibility of using a pulverized-coal combustion system in a melting
furnace. This is being initiated because of natural gas shortages and
uncertainties in the availability of alternate fuels. Success of the pro-
gram is dependent upon successful development of a process for SO
J±
removal from the stack gases.
Baghouses are used along with stack after-burners to control par-
ticulate and gaseous emissions. The amount of energy expended to
operate emission control devices is in the range of 3000 to 6000 Btu
per pound of product. The amount of energy required to operate a
baghouse is approximately 1000 Btu per pound of product, requires
extensive maintenance, and is not effective for the control of gaseous
emissions.
Petroleum Refining
Energy consumption in a petroleum refinery amounts to around 10%
of the crude throughput. Most of this energy is consumed as fuel in
fired heaters. The fuel is derived from the product output of the refinery
Unlike the other industries included in this program, the refiner is not
dependent upon outside sources of fuel; however, the fuel consumed
reduces the amount of product available for resale. A reduction in energy
consumption of about 8% has been achieved by the industry since 1972.
This reduction has been attributed to alterations in operating practice
and closer monitoring of process stages. Fuel consumption has been
reduced by checking heater performance on a full-^rime basis. Improved
oxygen analyzer installations are employed as well as preheat of the
heater feed.
In most existing refineries the different units are operated as sep-
arate entities, each having intermediate tankage for feed and products.
The trend is toward the elimination of intermediate tankage and
reducing fuel consumption by running hot feed between process units.
IV-329
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New refineries are being designed in this manner, along with changes
in design conditions such as a reduction from 400°F to 250°F in the
lowest temperature at which heat will be recovered by exchange.
Refinery operators have been able to comply with emission standards
that have been established in the past, however, some instances of
conflict were cited between fuel conservation and anticipated stricter
emission standards. There is concern that NO standards, yet to be
established, will put the refineries above the standard as a result of
air preheat. In another instance, it was calculated that when lower
stack temperatures are achieved to improve fuel efficiency, ground level
emissions increase.
Recommendations made by refiners were directed primarily at the
establishment of emission standards. In the interest of fuel conservation
it was recommended that standards provide the flexibility of waivers
to refineries located in areas remote from cities. It was also recom-
mended that guidelines be set by environmental tolerances, rather than
a specification based on the process capability. In terms of hardware
development, it was suggested that fuel-oil burner design be improved
to allow combustion with lower excess air requirements.
IV- 330
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INTRODUCTION
The purpose of this study is to identify the significant
emission sources within the industrial process-combustion field,
to investigate the potential for effective emissions control for
industrial process combustion, and to compile information on
combustion equipment in use and future trends in process and
equipment design. This program investigated the interactions
between current and potential energy conservation measures and
emission control programs, assessed the potential for R&D work
to advance emissions control, and recommended R&D programs
to solve the problems involved.
The program was divided into 3 distinct phases for the
purpose of industry selection, data collection, and data analysis.
The first phase of this program (Phase I) was to determine
those industries and industrial processes which have a high
potential for conserving energy and reducing emissions. Their
selection was based on the relative amounts of energy consumed
and the relative emissions of pollutants. The selection process
included consideration of the potential for simultaneous energy
conservation and air pollutant emission controls.
The second phase of this program (Phase II) consisted of
an intensive series of visits to industrial plants, corporate
headquarters, trade associations, and builders of process heat-
ing equipment. The purposes of these visits were to validate
and fill the voids in the information collected in Phase I and to
assess a number of elements relating to existing and future
trends in process technology and equipment design affecting
energy consumption and air pollutant emissions.
The information obtained from the trade associations,
equipment builders, and industrial plants was correlated and
analyzed in Phase III to provide an assessment of process and
IV-331
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equipment design and operating factors which are major influ-
ences on both fuel efficiency and air pollutant emission rates.
This data analysis resulted in estimates of the potential for im-
provement in fuel-use efficiency and reduction of emissions for
existing equipment designs and for new processes and equipment
designs which may be instituted in the future. Upon completion
of the data analysis, recommendations for specific programs
aimed at reducing energy consumption and air pollution emis-
sions were made, including the identification of potential sponsors
for these programs.
IV-3 32
-------
PHASE I. INDUSTRY SELECTION
In a program of this type, it is generally not feasible to
consider all industries. Consequently, a system was developed
for selecting pertinent industries. The system relates energy
consumption, pollution emissions, and the potential for reducing
both for each industry, and then determines the relative merits
of studying each industry in terms of achieving the program
objectives. Toward this end, the following system of restraints
and weighting factors has been developed for selecting the in-
dustries to be studied in this program.
Restraints
The first step in the development of this system was to
define the restraints as determined by the problems to be solved.
The following restraints were selected:
1. Total energy use in process heating. This program is
primarily concerned with those industries which consume
large amounts of energy because it is in these industries
that the most significant results of implementation of energy
conservation technology will be realized. Some industries,
however, consume large amounts of fossil fuels for feed-
stock and steam generation — ostensibly, the paper industry,
the chemical industry, the petroleum refining industry, and
the food processing industry. In the areas of feedstock and
steam generation, little can be done to alter the energy
utilization patterns. Consequently, only those industries
that consume large amounts of energy for process heat are
being considered in this program.
2. Combustion-related uses of energy. A further refinement
of the first restraint is to limit the investigation to
combustion-related aspects of energy consumption. In so
doing, industries which consume large amounts of purchased
electricity for process heating will be eliminated from con-
sideration. Electricity consumption is not within the scope
of this program, although in-plant generation is considered
if the relative load is large enough.
IV-333
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3. Relative number of processes within an industry. In some
industries, energy is consumed by a large number of rela-
tively small-scale processes which, when added together,
show a very large total energy consumption figure for the
industry as a whole. Typical of such an industry is the
industrial chemical industry. The total amount of energy
consumed for process heating in the chemical industry in
1972 was about 2800 trillion Btu. However, most of this
energy was consumed in the manufacture of thousands of
chemicals which incorporate myriads of individual processes
with varying energy requirements. To study an industry
such as this would give minimal return toward the project
objectives in that reductions in energy consumption of a
process in. this industry would have a minimal effect on the
national energy picture. On the other hand, in an industry
with a limited number of processes, such as the cement
industry, in which more than 90% of the 581 trillion Btu of
energy consumed in 1972 was consumed in kilns, even a
small (5-10%) increase in fuel utilization efficiency of the
kiln would have a significant, widespread impact on the
entire industry as well as the national energy picture.
4. Known and/or estimated total emissions. Two of the stated
purposes of this program are to identify the significant
sources of emissions within the industrial process combus-
tion field and to determine the potential for effective emis-
sions control for industrial process combustion. Therefore,
the emissions of an industry must be a restraint in the
industry- selection process. Emissions from industrial
process combustion can be broken down into three categories:
a. Emissions directly related to combustion — typically
NO
X,
CO, and particulates .
c.
Emissions indirectly related and therefore somewhat
controllable by combustion techniques — typically such
emissions as particulates from a glass melter or cement
kiln where the combustion gases "pick up" the dust of
the raw material and carry it out the stack.
Emissions independent of the combustion process —
typically emissions from chemical reactors or electro-
lytic processes.
5. Types of emissions — NO , SO , CO, and particulates.
ya <&>
These are the emissions of primary concern in this pro-
gram as they are the emissions most closely related to the
combustion process. Secondary emissions of concern are
IV-334
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fluorides, chlorides, and other halides, although these are
only indirectly related to the combustion process.
6. Potential jor energy conservation. Energy conservation is
one of" t£e"primary purposes of this program. Consequently,
only those industries which have a high potential for reduc-
ing energy consumption should be considered. The paper
and paperboard industries, although consumers of large
amounts of energy (more than 1300 trillion Btu in 1972),
will be eliminated from consideration because 95% of this
energy is consumed as boiler fuel, an application which
already has a direct fuel utilization efficiency greater than
80%. The potential for increasing the efficiency of direct
utilization of fuel is low.
7. Potential for reducing emissions. Reducing combustion-
related air pollutant emissions is the other primary objective
of this program. Consequently, as in the case of energy
consumption, those industries with a low potential for reduc-
ing emissions will not be considered in this program.
Upon applying the restraints and a weighting system (see
Appendix A), the following industries were selected for study in
this program:
• Iron and steel (all energy-using processes)
• Cement (primarily kiln operation)
• Glass (melting, forehearth operation, annealing)
• Aluminum (primary melting, reheating, secondary production)
• Petroleum refining.
These industries ranked highest in terms of the evaluation
characteristics used in this program. That is, all of these
industries use large amounts of process heat directly from the
combustion of fossil fuels; all of these industries are relatively
large emitters of combustion-related air pollutants; and all of
these industries have a high potential for reducing energy con-
sumption and air pollutant emissions. Note that these industries
have been selected based on the combination of all of the above
factors. Consequently, there are industries, such as the paper
and paperboard manufacturing industry, that consume twice as
IV-335
-------
much energy as the cement industry and 4 times as much as the
glass industry, but, because 95% of that energy is consumed in
boilers to generate steam (a process efficiency in excess of 80%),
the potential for reducing energy consumed directly by the boilers
is very low. Thus, this industry received a low priority rating
and is not being considered in this program. Information related
to the industries considered for this study is shown in Table 1.
IV-336
-------
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IV-337
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PHASE II. DATA COLLECTION
Iron and Steel Industry —
Processes and Equipment
The major operations in an integrated steel plant are the
coke oven, blast furnace, basic steelmaking, rolling mill, and
finishing.
Coke Ovens
Coke is the product of destructive distillation of some types
of bituminous coal, commonly referred to as metallurgical coal.
It is produced in by-product coke ovens, sometimes called slot
ovens, because of their shape. Each oven is a narrow, rectangu-
lar retort closed at the top except for charging ports, with gas
off-take ports in the sides and bottom. Each end of the oven is
fitted with a tightly sealed removable door. One end is the
"pusher end" from which a ram is inserted to push out the coke;
the other end is called the "coking end" from which the hot coke
is pushed into a quenching car. Adjacent retorts are separated
from each other by heating flues and are called underfired ovens
because the air and fuel ports are located at the bottom of the
heating flues. A large number of the retorts and associated flues
are stacked together and the entire series is called a battery.
High, medium, and low-volatile coals are crushed, ground,
and blended to obtain the desired coking characteristics. About
65$ to 80$ of the charge is high-volatile coal containing 30$ to
40$ volatile matter, the remainder of the charge consists of medium
and low-volatile coal. After charging the retort, the coal is converted
into coke in approximately 16 to 18 hours in older ovens and in about
12 hours in modern, taller ovens equipped with improved combustion
and control systems.
By-products of the coking operation include coke-oven gas,
tar, ammonium sulphate and light oil products (BTX). About
60$ of the sulfur content of the coal is carried over into the
IV- 338
-------
coke. The balance goes to the coke-oven gas as hydrogen
sulfide. A representative material balance for a coke-oven
plant is shown in Table 2.
Table 2. COKE-PLANT MATERIAL BALANCE
Coke
Coke-Oven Gas
Tar
Ammonium Sulfate
Light Oil Derivatives
Total
Quantity
78.5%
10,600 cu ft
(540 Btu)
7.55 gal
21.0 Ib
2.85 gal
Ib Per Ton
of Dry Coal
1574.0
312.3
74.8
21.0
20.9
2000.0
The fuels used for heating the coke ovens are selected on
the basis of cost, availability, and combustion characteristics.
Top to bottom temperature gradients must be minimized. Coke-
oven gas and natural gas-air mixtures provide the desired high
flame temperatures, while blast-furnace gas has a much lower
heating value and lower flame temperature, but does have a high concen-
tration of inerts which act as diluents to retard combustion and
lengthen the flame. The primary fuel for underfiring coke ovens
has been coke-oven gas. About 1/3 of the coke-oven gas pro-
duced is used for this purpose. Blast furnace gas and natural
gas together account for 15% to 20% of the total input for under-
firing coke-ovens. Total fuel input for underfiring has been
about 3.0 million Btu per ton of coke produced.
The major technological trends affecting coke-oven energy
requirements are —
IV-3 39
-------
* Higher and wider ovens using high conductivity refractories.
Coking rates and productivity have increased; however,
increases anticipated in efficiency have been offset by higher
coking temperatures and greater heat losses. Thermal
efficiencies of coke ovens are reported in the range of 60%
to 70%.
• Predrying of Coal Charge. Predrying of coal increases
coke-oven productivity and reduces heat losses resulting in
a saving of about 100,000 Btu per ton of coke. Emissions
during charging of predried coal are also reduced.
• Use of Formcoke. Formcoke is a calcined agglomerate of
bituminous coals (non-caking). Pollution in formeoke pro-
cesses is also reduced.
• Improved Blast Furnace Operations. The quantity of coke
required per ton of pig iron produced is reduced by using
a higher top pressure, hotter blast air temperature, oxygen
enrichment of blast air, and increased use of fuel injection.
• Direct Reduction of Agglomerated Iron Ore. Direct reduc-
tion and electric furnace melting produce steel with no pig-
iron requirement and pre-reduction of part of the blast
furnace burden will reduce the coke requirements and
increase blast furnace output.
Blast Furnace Plant
The blast furnace and its associated stoves for preheating
blast air, the sinter plant, and storage, sizing and handling
facilities for raw materials are the major components of the
blast furnace area in an integrated steel plant.
Sinter Plant
Some of the iron ore and flue dusts are available in
particle sizes less than 1/4 inch and cannot be charged directly
to the blast furnace. These products are mixed with flux and
coke breeze and loaded onto a traveling grate-sinter ing machine.
An auxiliary fuel such as natural gas, coke-oven gas, or oil is
used to initiate combustion on the surface of the mixture and is
referred to as ignition fuel. Combustion is continued over the
IV- 340
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length of travel by forcing air through the mixture on the grates.
The mixture is heated to a fusion temperature which causes
agglomeration of the iron-bearing particles. The sinter discharged
is cooled, crushed, and screened prior to transfer to the blast
furnace charging oven.
The major source of energy used in the production of sinter
is the carbon content of coke breeze and flue dust. The amount
of ignition fuel required is about 0.12 million Btu per ton of
sinter. The total fuel requirement, including coke breeze, is
about 2.0 million Btu per ton of sinter.
Blast Stoves
Blast stoves are checker-brick-lined chambers used to
supply heated air to the blast furnace. The stoves are regen-
erative heat exchangers; during part of the cycle being heated
by combustion of blast furnace top gas and during another part
of the cycle heating the blast air. Three or four stoves are
required for each blast furnace. In operation, a stove heats
air until the air preheat temperature drops to a preset value.
The stove is then isolated from the hot blast main and reheated
by combustion of blast furnace gas to the temperature required
to heat blast air. Regenerative air preheating results in a cyclic
variation in blast-air temperature and the stoves may be used
as staged temperature preheaters in various combinations with
the objective of reducing the cyclic variations in blast temperature.
Thermal efficiency of the blast stove is quite high, about
72%, as would be expected of a regenerative heat exchanger.
However, efficiency has decreased from about 87% in I960
because of a continuous increase in blast temperature. Average
blast temperature in 1969 was in the 1500°-1600°F range and in
1960 was below 1300°F. Some installations are now approaching
a 2000°F blast temperature.
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The major reasons for increasing blast-air temperature
are to reduce coke consumption in the blast furnace and to in-
crease the output of pig iron. Auxiliary fuel injection in the
blast furnace also requires higher blast-air temperature to
maintain temperature in the melting zone. Other factors also
affect coke rate and production. These will be discussed in
the blast-furnace section of this report.
About 25% of the blast furnace top-gas is used for stove
heating. In 1969, this amounted to 165 trillion Btu. Increases
in blast-air temperature and a reduction in blast furnace gas
heating value have required the use of coke-oven gas and natural
gas for higher heat release in blast stove heating.
Current technology trends in blast stove design and operation
include —
• Improved designs for burners and combustion chambers
• Improved hot valve designs
• Better refractories and checker-brick design
• Automatic stove charging equipment
• Improved modes of stove operation.
Blast Furnace
The blast furnace is a cylindrical, tapered, refractory-lined,
vertical furnace. It is charged with the basic iron-making raw
materials, iron ore, pellets, sinter, coke and limestone, and
discharges hot metal or pig iron and a slag which contains the
mineral gangue and other impurities. It is a counterflow process
in that the iron-making materials are charged at the top through
a double-bell seal and travel down through the furnace reacting
with an ascending stream of reducing gases, primarily carbon
monoxide and hydrogen. The reducing gases are produced by
blowing preheated air through ports called tuyeres into the
bottom of the furnace, where reaction with the incandescent coke
IV- 342
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takes place. Auxiliary fuels such as fuel oil, natural gas, tar,
or powdered coal are frequently injected at the tuyeres to in-
crease iron output and decrease the coke rate. With auxiliary
fuel injection, higher blast-air temperature or oxygen enrichment
is usually required to maintain the iron melting temperature.
Exceptionally good results have been achieved on a pilot-plant
basis by injection of reformed natural gas at the tuyeres.
Theoretical calculations have shown that even better results
could have been obtained by injection of hot reformed gas above
the tuyeres in the gaseous reduction zone. Although these pro-
grams have been curtailed by reduced availability of natural gas,
the results indicate that blast-furnace injection may become a
potential application for use of low-Btu gas produced by gasifica-
tion of coal, assuming a favorable economic justification. A
suitable reducing gas can also be produced by partial oxidation
of residual oil, but the present cost and availability of low-sulfur
oil make this approach uneconomical.
Pollutants From Iron Making
The coke-oven plant has been identified as one of the major
sources of air and water pollution from integrated steel plants.
Some of the sources of emissions are —
• Coal handling, processing, and storage
• Charging the coal into the ovens
• Leakage during coking, particularly from the doors
• Discharge of incandescent coke
• Water quenching of coke
• Contaminated water discharged.
A variety of methods has been incorporated in recent coke-oven
plant designs to effectively control emission of pollutants.
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Sinter plants are inefficient as users of energy and are
major contributors to steel mill particulate and gaseous emis-
sions. Emission control is technically difficult and expensive.
Some steel plants have phased out sinter lines and pelletized
iron ore has now assumed a dominant position as a major blast
furnace charge. Pelletizing plants are located near the iron
ore sources and the emissions from the pelletizing process do
not contribute to the steel mill emission control problems.
The major pollutants from sinter plants are particulates,
sulfur oxides, and carbon monoxide. Leakage from the seals
between the exhaust ducts and the sintering furnace structure
accounts for most of the emissions.
Disposal of in-plant fines and flue dusts as process feedstocks
will be required by means other than landfill. Both pelletizing
and hot-briquetting will probably be used.
Emission of pollutants from blast furnace stoves consists
of dust carried over from the blast furnace. With properly
designed combustion systems and air-gas ratio controls, carbon
monoxide should not be considered a significant emission.
Particulate emission from blast-furnace stoves is not treated
separately in the literature, but is considered part of blast
furnace particulate emissions.
Steelmaking
In steelmaking, iron from the blast furnace, commonly
called hot metal, and scrap are charged along with fluxes to
melting process equipment. Impurities such as carbon, man-
ganese, silicon and phosphorus are oxidized to or below specified
levels during the melting process. These oxidation reactions
are exothermic and contribute part of the total process energy
requirement. The fluxes and some of the oxidized impurities
IV-344
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form a slag layer and the rest of the oxidized components leave
as gases. The major types of melting process equipment are
the open-hearth, the basic oxygen furnace (EOF) and the electric
furnace.
Open-Hearth Steelmaking
The open-hearth furnace is a large reverberatory vessel
heated from the top by burners located at each end of a long,
narrow chamber. A long, luminous flame is produced so that
a high percentage of heat transfer to the bath is by radiation.
The heating process is regenerative in that refractory checker-
brick are located downstream of each firing port so that com-
bustion air is being preheated at one end, while exhaust gases
are reheating the checker-hrick at the other end. After a timed
interval the flow is reversed. Scrap metal, fluxing agents, iron
ore and hot metal are charged through doors located above the
bath level along the length of the furnace. Open-hearth furnace
capacities range from 100 to about 600 tons per heat.
The high productivity of competitive steelmaking processes
has brought about major improvements in open-hearth furnace
productivity. Some of these improvements are oxygen-enrichment
of combustion air, roof-mounted oxygen lances, roof-mounted
oxygen-fuel lances to accelerate scrap melting an higher combustion-
air preheat temperature. However, the use of oxygen lancing
has resulted in increased dust loading of the waste gases and
this has required installation of more costly air pollution control
equipment.
Fuels used in open-hearth furnaces include residual oil,
natural gas, coke-oven gas, tar and pitch. Part of the thermal
requirement is provided by exothermic oxidation of impurities
contained in the hot metal portion of the charge. Fuel required
per ton of steel produced is in the 1.5 to 4 million Btu^.range,
IV-345
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depending on the hot metal/scrap ratio and the amount of oxygen
lancing used.
Basic Oxygen Furnace (EOF) Stee breaking
In the BOF process, oxygen is blown downward through a
water-cooled lance into a bath containing scrap and hot metal.
Heat produced by oxidation of carbon, silicon, manganese and
phosphorus is sufficient to bring the metal to pouring temper-
ature and auxiliary fuel is not required. The furnace is an open
top, tiltable, refractory-lined vessel shaped somewhat like the
old fashioned glass milk bottle. Furnace capacities range up to
300 tons and time required per cycle is very short, from 45 to
60 minutes.
The BOF has displaced the open-hearth as the major steel
production process but is much less flexible because of the in-
herent limitation of 25% to 30% scrap in the charge. The
amount of BOF capacity in an integrated steel plant is, there-
fore, closely associated with hot metal availability. Additional
flexibility in scrap use can be obtained by preheating the scrap
with an oxygen-fuel burner. In many steel plants an open-hearth
shop is modernized and equipped with appropriate pollution
control equipment so that it can be used in conjunction with BOF
shops to provide the required flexibility to accommodate varia-
tions in hot metal/scrap ratio. A combination of BOF shops and
electric furnace shops provides the maximum in flexibility and
may represent the makeup of future steelmaking facilities.
Excluding fuel use for scrap preheating, other uses are for
refractory dryout and to keep the BOF vessel from cooling be-
tween heats. These uses amount to about 200,000 Btu per ton
of steel produced.
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Decarburization of the iron charged to the EOF produces
about 400, 000 Btu of carbon monoxide per ton of steel. The
off-gases also contain large amounts of particulates, which must
be removed before discharge into the atmosphere. Typical
American practice is to burn the combustible gases in water-
cooled hoods mounted above the BOF vessel, cool with excess
air or water sprays, and pass the cooled gases through high-
energy scrubbers or electrostatic precipitators. In most cases,
the BOF vessels are equipped with open hoods which admit air
for combustion of carbon monoxide on a relatively uncontrolled
basis. If additional steam can be used in the plant, the com-
bustion hood can be used as a steam generation device, although
the steam production will only be cyclic.
In Japan, a closed-hood gas collection system known as the
OG system is used, wherein the waste gases containing CO are
scrubbed, collected, and used as fuel gas. The basic OG sys-
tem is used at a few steel plants in the United States, but the
CO-rich off-gas is burned in a flame stack rather than stored
and used for fuel. A major advantage of the OG system, other
than recovering a fuel gas, is the large reduction in the volume
of waste-gas required to be handled by the scrubbing system.
Electric Furnace Steelmaking
Production of steel in electric-arc furnaces has grown
rapidly since World War II and is currently estimated to be
more than 15% of total steel production. Because of the phase-
out of open-hearth steelmaking, the increase in BOF steel pro-
duction, and the associated scrap-use limitation, the amount of
steel produced in electric-arc furnaces is expected to increase
even more.
IV- 347
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Combustion of fossil fuels currently plays a very small role
in electric steelmaking. This may change in the future as
advances in technology permit the increased use of scrap pre-
heating. Most authorities agree that scrap preheating will be
accomplished outside the electric-arc furnace in a specially
designed charging bucket probably equipped for bottom discharge.
Many of the designs use excess air burners to limit flame tem-
perature and minimize oxidation of the scrap. Associated air-
pollution problems include particulates from dirty scrap, iron
oxide, and oil vapors. The requirement for both incineration at
or above 1400°F and particulate removal has caused shutdown of
several scrap preheating installations because of economic
considerations.
Direct Reduction
A number of direct reduction processes are currently in use
to provide an alternative to the blast furnace in the production
of feed material for steelmaking furnaces. Both batch and con-
tinuous processes are in use involving such equipment as rotary
kiln, counterflow vertical shaft, traveling grate-kiln and multi-
stage fluid bed. Various types of raw materials are processed,
such as lump ore, oxide pellets, and beneficiated concentrate.
The degree of metallization ranges up to 95 % and a highly
metallized product can be charged to an electric melter without
scrap addition. Pre-reduced charge can be used in the blast
furnace and steelmaking equipment such as the BOF. Some ad-
vantages of direct reduction are —
• Lower capital requirements than for coke-oven blast
furnace ironmaking.
• Reduced dependence on hot metal for steelmaking.
* Consistent chemical analysis of the feed material to the
steelmaking process.
* Reduced dependence on scrap.
I.V- 348
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In the past, direct reduction plants in the United States have been
associated with mini-steel plants which are not fully integrated.
These plants are dependent upon a reliable supply of natural gas at
a low price. Currently, both availability and price are adverse to
the process and it seems doubtful that additional plants will be con-
structed. Natural gas consumption in the most efficient plant is in
the range of 13 to 14 million Btu per ton of product; less efficient
plants may require as much as 20 million Btu per ton.
Hot metal from the blast furnace is transferred to the steel-
making furnace in large, refractory-lined vessels or ladles. These
are also used for transferring molten steel to the various casting
operations. The refractory linings of the vessels must be cured after
replacement and preheated before each use. Typically, open-flame
burners are used for this at a very low thermal efficiency. Fuel re-
quirements for ladle drying and heating range from 200, 000 to 400, 000
Btu per ton of metal.
Ingot jind Continuous Casting
After removal from the furnace, the steel is poured into ingot
molds or transferred to the continuous caster. Forming steel into
ingots is an intermediate step prior to further processing. The steel
is cooled to a solid, whereupon the ingot mold is removed. The
finished ingot can be sent directly onto additional processing or stored
indefinitely to meet scheduling needs.
In the continuous-casting process, the ingot stage is bypassed,
and the molten steel is placed into one or more streams or strands
which are fed from a holding chamber called a tundish. The molten
steel is transformed directly into slabs, blooms, or billets and cut
to the desired length by a traveling torch. The continuoxis casting
process eliminates intermediate ingot formation, along with the energy
required to reheat the ingot prior to the formation of slabs, blooms,
or billets. The amount of steel output produced by continuoxis casting
is increasing.
IV-349
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Soaking pits are used to reheat ingots to rolling temperature
(about 2340° to 2400°F for carbon steel). Ingots are charged at a
variable temperature because of varying time intervals between
ingot pouring and charging into the soaking pits, brought about by
conflicts in rolling schedules or other delays. The amount of en-
ergy required for reheating ingots varies a great deal because of
the temperature variation in heating a cold ingot and one at inter-
mediate temperature levels.
Soaking pits are simple round, square, or rectangular-shaped
refractory-lined chambers having a retractable cover. Several pits
grouped together are referred to as batteries, having common flue
ducts and a single recuperator and stack. Fuels used in soaking
pits include mixed blast furnace gas and coke-oven gas, mixed
blast furnace gas and natural gas-air, straight coke-oven gas,
straight natural gas and residual oil. Single, nozzle or port-mixing
burners are used and the burners are used and designed to minimize
the temperature gradient between the burner wall and the back wall
of the pit. Problems in fuel utilization occur when changing from
one fuel to another, particularly from gaseous to liquid fuels, be-
cause of major variations inflame length and heat-release profiles.
Mill operating practices have a major effect on soaking pit fuel
economy. Among them are —
• Ingot charging temperature
• Percentage of cold ingots charged
• Pit loading
• Holding time at temperature.
Fuel requirements vary from 545, 000 to 2 million Btu per ton.
The national average fuel consumption in soaking pit operations is
estimated at 1 million Btu per ton.
IV- 350
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Good combustion control is essential for maintaining fuel effi-
ciency in soaking pits. These include temperature control-fuel
input, pit pressure and air/fuel ratio. Substantial fuel reductions
can be obtained by installing recuperators on soaking pits now op-
erating on cold combustion air. Improved recuperator design can
deliver combustion air preheated to higher levels than the current
range of 700° to 800°F. The potential for fuel reduction is about
15%, taking into account the large number of soaking pits operating
•with cold combustion air or inefficient recuperators.
Most of the fuel used by the steel industry in reheat furnaces is
for slab, bloom, and billet heating. The evolution of the modern,
continuous, reheat furnace has been forced by rolling-mill improve-
ments, steel quality requirement, floor space limitations, and low-
cost energy, toward the direction of increased heating rates and
higher mean effective thermal head temperatures. Most of these
furnaces are a continuous-pusher type with the load supported on
water-cooled skids over most of the furnace length, and on a refrac-
tory hearth in a final soak zone which is over fired. Both three-zone
and five-zone furnaces are in use. More of the fuel input is progres-
sively burned near the charge end to increase furnace capacity. As
a result, flue-gas temperatures have increased and this factor, as
well as the heat lost to water-cooled surfaces, has resulted in in-
creased fuel requirements per ton of steel heated. In recent furn-
ace designs the soak zone has been eliminated by using a walking beam
design wherein the load is alternately supported on stationary and
moving water-cooled supports. This furnace produces a uniformly
heated product without the cooler regions associated with the water-
cooled support skids and has the highest output per unit of floor
space, but accomplishes this at the expense of fuel economy.
Average fuel consumption for reheat furnaces with preheated
combustion air is in the range of 2. 0 to 2. 2 million Btu per ton for
3-zone furnaces and 2. 7 to 2. 8 million Btu per ton for 5-zone furnaces.
IV-351
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Fuel economy for steel mill reheat furnaces is effected by furnace
design, firing arrangement, heat losses, heat recovery, combustion
and process controls, and operating practices. Although the furnaces
are continuous, frequent delays at the rolling mill have an adverse
effect on fuel efficiency and on the temperature uniformity of the
product. Another important factor is the number of operating turns
per week.
Estimates of total fuel requirements of steel mill reheat furnaces
are frequently based on an average consumption value of 2. 5 million
Btu per ton of steel heated. Some of the rolled products may be re-
heated more than once and consequently estimates of total fuel con-
sumption for reheating range up to 300 trillion Btu per year.
Fuel conservation measures for reheat furnaces include those
previously mentioned for soaking pits:
• Retrofitting recuperators to furnaces using cold combustion
air or presently using inefficient recuperators
• Improved combustion control
• Improved operating practice
• Programmed input control.
Additional measures specifically for reheat furnaces include
the following:
• Improved maintenance of skid rail insulation
* Control of air infiltration
• Increased temperature of preheated combustion air.
Emissions from soaking pits and reheat furnaces may include
carbon monoxide and unburned hydrocarbons produced by inadequate
or poorly maintained ratio controls. These can be eliminated by the
installation of better equipment or improving maintenance practices.
The most significant emission will be NO , produced by the high
jV
flame temperatures required and combustion-air preheat.
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Annealing, heat treating, and finishing operations follow in se-
quence the reheating and rolling mill operations. The major portion
of the fuel used in the steel industry for annealing is for cold rolled
products in strip form. Approximately 35% of total United States
steel production is in the form of strip and other cold rolled products.
Estimates of the amount of energy consumed for annealing, heat
treating and finishing operations range from 50 to 60 trillion Btu
per year, including electricity. About half of this quantity is for
annealing.
Fuels used for these processes are mainly natural gas and coke-
oven-gas. Natural gas is preferred because the sulfur content of a
fuel has an adverse effect on product quality and maintenance of furn-
ace alloy components.
Temperatures employed in heat treating and finishing operations
are much lower than those required in other types of process equip-
ment and, consequently, NO levels should be correspondingly lower.
Other emissions, such as carbon monoxide and hydrocarbons, are
associated with the quality and maintenance of air-fuel ratio control
equipment. Many of the heat treating and annealing operations re-
quire the use of a protective atmosphere, primarily reformed natural
gas. Disposal or leakage of protective atmospheres can result in
locally high concentrations of carbon monoxide.
Equipment used in annealing, heat treating and finishing opera-
tions include the following:
• Batch and continuous coil and strip annealers
• Car bottom, roller hearth pusher tray, and other types
of heat treat furnaces
• Tin-plating lines
• Galvanizing lines.
IV-35'3
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Some of the energy conservation measures being used on
annealing equipment are:
* Conversion from radiant tube to direct firing
• Re cupe r ati on
* Improved combustion controls
• Use of ceramic fiber furnace linings replacing brick
refractories
* Substitution of nitrogen from oxygen plants for natural
gas based atmospheres.
Because of the relatively small percentage of total fuel use in
this area and the low level of NO produced, any conservation mea-
Ji
sures adopted will not have a material effect on overall steel plant
emission levels.
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Steel Industry Field Survey
Trends in Process and Equipment Modifications
1. Iron Making
Coke Ovens — Current and Near-Term
• Pipeline charging of predried and preheated coal
• Coke-side hood ducted to emissions control equipment
• Wider and higher coking chambers
• Improved H2S removal from coke-oven gas using
molten carbonate treatment (500 Ib steam/ton coke)
• Multistage combustion system
• Sealed container case to receive coke
• Continuous wet and dry coke quenching for emission
control and waste heat recovery.
Coke Ovens — Long-Term
• Dry coke quenching using inert gas and waste heat recovery
• Replacement by formcoke or other compacted forms of
calcined coal,
Sinter Plant — Current and Near-Term
• Improved seals to minimize infiltration and leakage.
• Waste-gas temperature control to prevent condensation
in emission control equipment,
• Gas recirculating siphon designed to minimize volume
handled by emission control equipment.
Sinter Plant — Long-Term
• Replacement by hot briquetting process,
Blast Furnace — Current and Near-Term
• Larger furnaces.
IV-35 5
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• Higher blast temperature
• Improved burden (oxide pellets, sinter)
* Higher top pressure
• Auxiliary fuel injection
* Improved stove design, scheduling and firing practice.
Blast Furnace — Long-Term
• Pre-reduced iron as part of charge,
2. Steelmaking
Open Hearth — Current and Near-Term
• Use declining because of basic oxygenfurnace and
emission-control cost
• Use required by mills having inadequate supply of
hot metal. Emission control equipment is required.
• Increased use of oxygen roof-lancing to increase output.
NO level probably increases.
Open Hearth — Long -Term
• Use will continue to decline, probably to about 10% of total
steel production by 1985.
Basic Oxygen Furnace (BQF) — Current and Near-Term
Collection and control of emission by the OG IRSID-CAFL
processes (non-combustion). The OG system uses 2-stage
venturi scrubbing for particulate removal and a flame stack
for carbon monoxide combustion
Submerged injection of oxygen (QBOP).
Basic Oxygen Furnace (EOF)— Long-Term
Recovery of carbon monoxide from EOF off-gases (about
400, 000 Btu per ton melted)
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• Improved scrap preheating system with emission controls
and fueled by recovering carbon monoxide from EOF off-gases
• Reduction in hot metal requirement.
Electric Furnace — Current and Near-Term
• Primarily improvements in emission control equipment
• Larger furnaces
• Development of practical scrap preheating systems.
Electric Furnace — Long-Term
Electric furnace melting of pre-reduced charge, pellets
or lump ore.
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Trends in Utilization of Fuels
The American Iron and Steel Institute has reported to the FEA
on the overall energy consumption by the steel industry by source
for the base year 1972 and a projection for the year 1980 as follows:
Source
Coal, %
Purchased Gas and Oil, %
Purchased Electricity, %
Btu X 106 per Net Ton Shipped
Year
1972
67.3
28.8
3.9
32.6
1980
68. 5
26.9
4.6-
30. 1
During the field interviews, various integrated steel plants
reported the following energy consumptions by source for 1974:
Plant
Coal, %
Oil, %
Natural Gas, %
Purchased Electricity, %
Other, %
A
75
10
15
B
60
22
18
C
70
5
20
4.7
0.3
General fuel-use trends in the industry will be to increase the
relative amount of coal consumed per ton of steel shipped and to
decrease dependence on purchased oil and gas. The amount of oil
used compared to natural gas will increase because of the decreased
availability of natural gas. Major shifts toward increased use of
coal will require very large amounts of capital, both for new pro-
duction facilities and for the associated emission control equipment.
Ironmaking — Current and Near-Term
• Increased use of coal as a primary fuel, both in increased
coke-oven output for blast furnace injection and for boiler
firing,
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• Increased availability of coke-oven gas.
• Decreased use of coke-oven gas for under-firing coke
ovens, partial replacement by increased use of blast-
furnace gas.
• Coal and high-sulfur oil will be used as blast-furnace
injectants.
• Use of natural gas as a blast furnace injectant, for blast
stove heating and other auxiliaries will decline sharply.
• Direct combustion of coal in pelletizing facilities, both travelling
grate and shaft type will decrease use of natural gas and oil.
Ironmaking — Long-Term
• Coke ovens will be replaced, possibly to a major extent,
by form coke or some other pyrolyzed coal product. Heating
value of the gas output may be much less than that of coke-
oven gas, possibly less than 200 Btu/CF.
•. Coal gasification plants producing low-Btu gas may be
installed in steel mills or the product gas made available
from a nearby source.
• Heating value of the low-Btu gas will be in the 175 to 300 Btu range,
depending on the process used. This gas may be a good blast furnace
injectant if the economics are favorable.
• Direct reduction to a highly metalized iron product using
solid reductants may replace part of the coke oven-blast
furnace ironmaking capacity."' The availability of low-
sulfur fuels at a competitive price will be essential and
appears to be doubtful at the present time.
Steelmaking — Current and Near-Term
• Use of oil, natural gas or in-plant gases for steelmaking
furnaces will continue to decline as additional open-hearth
furnaces are replaced by BOF and electric furnace steel-
making.
• Use of natural gas as an open-hearth fuel will decline
sharply, replaced by oil or coke-oven byproducts.
Steelmaking — Long-Term
Recovery of carbon monoxide waste gas from BOF steel-making
and possibly using it to preheat the scrap charge will enable the
industry to increase the scrap/hot metal ratio in the BOF charge.
*The fuel sulfur content must be at a low level to produce a metallized
product satisfactory for electric melting.
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Development of direct reductive processes using solid
reductant.
Application of nuclear energy to steelmaking with avail-
ability of reducing gases for direct reduction or blast
furnace injection.
Development of continuous steelmaking.
•
•
*
Soaking Pits and Reheat Furnaces — Current and Near-Term
Shift from natural gas and coke-oven gas to oil firing or
blast-furnace gas and other coke-oven byproducts.
Fuel conservation by use of techniques previously discussed.
Increased use of induction heating for slabs and billets.
Increased use of continuous casting.
Soaking Pits and Reheat Furnaces — Long-Term
Use of coal, solvent refined coal or a slurry or emulsion
of oil and solid fuel.
Major reduction in fuel requirements by development of
a process for production of steel strip directly from
molten steel.
Heat-Treating and Finishing Operations — Current and Near-Term
Available natural gas and coke-oven gas conserved in other mill
areas will be used,
Some installations will be converted to oil firing. In most cases,
distillate oil will be required because of sulfur limits.
Gas atmospheres produced from natural gas will be replaced
to a large extent by byproduct nitrogen from captive oxygen
plant s.
Electric heating will replace natural gas in cases where
alternatives are not feasible.
IV-360
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Emission Problems
In most cases, those interviewed were not disposed to discuss
specifics of emission control problems, except to state that every
effort is being made at very heavy costs to comply with local
standards. In many cases, attention was drawn to the large energy
requirements for compliance with future standards, particularly those
for fugitive emissions and building air evacuation.
It was generally agreed that not much is known about NO
3x
emissions from steel-mill equipment.
In one case, concern was expressed that flare-stack combustion
of carbon monoxide might not be effective.*
Another concern was that baghouses and precipitators or scrubbers
are not effective in the elimination of oil vapor from oily scrap. Com-
bustion of such vapors or carbon monoxide adds greatly to the volume
of gases handled in pollution control equipment.
Major combustion-related emission problem areas were
given as:
• Coke ovens
• Sinter lines
• Open-hearth furnaces
• BOF and electric furnaces
• Acid recovery from waste pickle liquor.
Research Programs Recommended
Ironmaking
• Design, construction and operation of a form-coke
demonstration plant (3000 ton/day).
• Completion of the development of direct coal injection
into the blast furnace.
• Development of an improved process for desulfurization
of coke-oven gas.
^Because of the inherent difficulty of burning CO in a cold environment.
IV- 361
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Development of a process for hot briquetting of in-plant fines
to replace sinter lines.
Development of a process for agglomeration of mill scale.
Design, construction and operation of a 3000 ton/day coke
dry-quenching demonstration plant.
Development of an improved process for treatment of
coke-oven water discharge, particularly for cyanide removal.
Development of an air recirculation process for sinter lines
to reduce the volume of stack gases and to control carbon
monoxide emissions.
Steelmaking
Development of a process for control of NO from steel-
making processes.
Development of processes to control emissions of oil vapors
from charging oily scrap to BOF or electric furnaces.
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C ement Industry
The manufacture of portland cement is accomplished in three
operations: raw material preparation, including crushing and grind-
ing; "burning" of the raw material to produce the clinker; and
clinker processing, including cooling and grinding, as required.
The primary energy-consuming process is the drying and calcining
of the raw material, which consumes about 90% of the total amount
of energy used in the entire manufacturing process.
Kilns
Two basic types of equipment are used in the burning {calcining}
process — the rotary kiln and the vertical-shaft kiln. Most of the
cement in this country is produced in rotary kilns — large refractory-
lined steel cylinders that revolve at about 1 rpm. These kilns, as
shown in Figure 1, vary in diameter from 1Z to 25 feet and are up
to several hundred feet in length. They are mounted at an angle
slightly off horizontal, so that as they rotate, the charge moves by
gravity from the high charging end to the low discharging end. The
discharge end of the kiln is also the firing end. The burners used
are similar to those used in the glass industry —high-velocity, non-
premix burners. The primary fuels used are natural gas and coal;
fuel oil accounts for only 15% of the total industry's fuel consump-
tion.
The thermal efficiency of the rotary-kiln process varies con-
siderably in practice, depending on the use of preheaters for raising
the temperature of the raw material prior to charging into the kiln.
The use of such preheaters not only reduces the energy consumption
of the burning process, but also reduces the physical length of the
kiln. Table 3 shows the effects of preheaters on energy consump-
tion by the rotary kiln.
The primary difference between the wet and dry processes is
the moisture content of the raw material charge. In spite of its
IV-363
-------
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higher energy consumption, the wet process is used because of the
raw material preparation, grinding and so on, in this form.
Table 3. ENERGY CONSUMPTION OF VARIOUS
CEMENT-MANUFACTURING PROCESSES
Energy
Consumption, Production Over
106 Btu/ton of Average Current
Process
Cement
Wet
Long Kiln
Calcinator and Short Kiln
Semiwet
Preheater and Short Kiln
Dry
Long Kiln
Suspension Preheater and
Short Kiln
Semidry
Grate Preheater and Short
Kiln
5.94
4.68
3.60
4.68
3.15
3.42'
Practice, %*
26.9
43.8
50.8
46.6
t
Includes 0.54 X 106 Btu/ton for drying.
Average current consumption is that of long kiln.
The other major type of kiln is the vertical kiln. The concept
of a vertical kiln is not new. Satisfactory performance of the verti-
cal kiln requires that the raw material be dampened and nodulized
prior to charging. In contrast to the rotary kiln, low-volatile fuels,
such as coal, are required. In the vertical kiln, the nodules and
fuel are fed continuously into the top of the kiln, and the clinker is
extracted, cold, from the bottom by a rotating grate. Fuel con-
sumption in a vertical kiln is about 3. 6 million Btu/ton of clinker
produced.
IV- 365
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Other methods of reducing energy consumption in the cement
industry include the installation of chain systems, kiln feed end enlarge-
ment, use of trefoils and kiln ledges, oxygen enrichment, increased
process control, slurry dewatering, and waste-heat utilization.
Air Pollution Emissions
The major air pollutant emissions problem in the manufacture
of portland cement is particulates, which occur in all phases of
cement manufacturing from crushing and raw material storage, to
clinker production, clinker grinding, storage, and packaging.
Emissions also include the products of combustion of the fuel used
in the rotary kilns; these are typically NO and small amounts of
j£
SO . However, many cement plants are switching fuel, from oil
X
and gas to coal and petroleum coke. These alternative fuels may
produce increased amounts of both NO and SO . However, no data
Jt ji
are currently available. Table 4 presents a summary of emissions
from cement-manufacturing processes currently in use.1
Most efforts to control air pollutant emissions focus on parti-
culates because they are not only the greatest problem, but also
the easiest to control. The most desirable method of control is to
collect the dust and recycle it by injecting it into the burning zone
of tiie kiln, thus converting it to clinker.
Combustion-related emissions are more difficult to control.
Nitrogen oxide emissions may be controlled by such techniques as
flue-gas recirculation, controlled mixing of the fuel and air, and
changes in burner block designs. The controlling factor to imple-
menting these techniques is economics. The emissions of SO , and
U.S. Environmental Protection Agency, "Compilation of Air Pollu-
tant Emission Factors," Publication No. AP-42, 2nd Ed. Research
Triangle Park, N. C. , April 1973.
IV-366
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Table 4. EMISSION FACTORS FOR CEMENT
MANUFACTURING WITHOUT CONTROLS3.b
Dry Process
Wet Process
Pollutant
Particulate
Ib/ton
kg/MT
Sulfur dioxide
Mineral source
Ib/ton
kg/MT
Gas combustion
Ib/ton
kg/MT
Oil combustion
Ib/ton
kg/MT
Coal combustion
Ib/ton
kg/MT
Nitrogen oxides
Ib/ton
kg/MT
Kilns grinders, etc.
245.0 96.0
122.0 48.0
10.2
5.1
Ne/
Neg
4 . 2 5g
2. IS
6.bS
3.4S
2.6
1.3
Kilns grinders, etc.
228.0 32.0
114.0 16.0
10.2
5.1
Neg
Neg
4.2S
2. IS
2.6
1.3
One barrel of cement weighs 376 pounds (171 kg).
These emission factors include emissions from fuel combustion,
which should not be calculated separately.
Typical collection efficiencies for kilns, dryers, grinders, etc. ,
are: rnulticyclones, 80 percent; electrostatic precipitators, 95
percent; electrostatic precipitators with rnulticyclones, 97. 5 per-
cent; and fabric filter units, 99.8 percent.
The sulfur dioxide factors presented take into account the reactions
with the alkaline dusts when no baghouses are used. With baghouses,
approximately 50 percent more SOj is removed because of reactions
with the alkaline particulate filter cake. Also note that the total SOj
from the kiln is determined by summing emission contributions from
the mineral source and the appropriate fuel.
These emissions are the result of sulfur being present in the raw
materials and are thus dependent upon source of the raw materials
used. The 10. 2 Ib/ton (5. 1 kg/MT) factors account for part of the
available sulfur remaining behind in the product because of its
alkaline nature and affinity for SO^.
Negligible.
ft
S is the prccent sulfur in fuel.
-------
the other major combustion-related emissions, are inherently con-
trolled in the burning process because most of the raw-material feed
is converted to calcium oxide, which reacts with the sulfur dioxide.
In addition, the presence of sodium and potassium compounds in the
raw material aids in the direct absorption of sulfur dioxide into the
product. Sulfur dioxide is also removed by this same mechanism
in baghouse filters, in which the sulfur-dioxide-laden gases contact
the collected cement dust. However, the degree of control by sul-
fur dioxide absorption depends upon the alkali and sulfur content of
the raw material and fuel.
Cement Industry — Field Survey
A series of interviews were made with cement manufacturers
to obtain information related to current operating practice, including
fuel availability, potential for process modification, and pollution
control problems. The companies interviewed employ both the wet
and dry cement manufacturing processes and range from limited to
widespread operations on a geographical basis, and from single to
multi-plant operations.
The amount of energy required to produce one ton of cement
ranged from a high of 7 X 106 Btu to a low of 4. 3 X 106 Btu in a
plant equipped with preheaters. Fuels consumed in kiln operation
consist of natural gas, oil and coal. Users of natural gas reported
curtailments ranging from 10% of base year (1972) use to complete
curtailment during the winter season. The range of gas curtailment
is subject to geographical location, and where intrastate supplies
are available, the curtailment is less than from interstate sources.
The price of natural gas has increased markedly from 1972 levels
of $0.32/1000 CF to $0. 50/1000 CF in early 1975. Further cur-
tailments and increased prices are expected by the firms contacted.
Coal has been available in adequate amounts although the price
has increased dramatically,in one case doubling over the period of
IV-368
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one year. One firm reported a price increase of $0. 35/106 Btu,
from $0.42/106 Btu in 1972 to $0. 77/106 Btu in 1974. In another
instance, a firm stated the contract price of coal had gone from
$17. 50/ton in 1974 to $27. 50/ton in 1975. In contrast to this, the
spot price of coal declined from $40/ton in 1974 to $31.00/ton in
early 1975. As a result, this firm is seeking coal purchases amount-
ing to 50% of its needs on the basis of a 5 year contract. In the past,
spot prices had been lower than contract prices and it was possible
to purchase coal cheaper on the open market. It is expected that this
price relationship will not occur again and greater reliance will be
placed upon contractual purchases. The sulfur content of the coal
used is 2-1/2% or less. Some of the plants not currently using coal
cannot do so because of physical limitations. Much space is re-
quired for coal-handling equipment and storage. Some older plant
sites do not have access to additional space. Other plants do not
have ready access to coal due to transportation problems, such as
distance and cost.
One of the firms contacted had some kilns equipped with air
preheaters and some without. A reduction in energy consumption
of about 20% was reported for the kilns equipped with the preheaters.
The amount of energy consumed in kilns with preheaters was about
4. 3 X 106/ton, in kilns not equipped with preheaters the energy re-
quirement is about 5. 3 X 106 Btu/ton. Another company had in-
stalled preheaters on a trial basis and found them to be unsuccess-
ful. It was found that the raw material clay contained an excessive
amount of oil which caused fires. As a result, the company re-
covers waste heat for use in the steam generation of electricity.
Suspension preheaters require additional horsepower for con-
trolling air movement within the plant. The following power re-
quirements were given as examples:
IV-369
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Process
kWhr/bbl
Wet processing plant w/o preheater
Dry processing plant w/o preheater
Wet or Dry w/preheater
5. 3bbl/ton of cement.
25-28
29-34
38-43
In addition to the increased power requirements of air suspen-
sion preheaters, it was stated that the raw materials must be
properly sized to achieve optimum utilization. The material must
be in the range of 1/2-inch to 2 inches in diameter to assure circu-
lation of the preheated air. Material smaller in diameter tends to
cake and restrict air flow. If the raw materials used have a high
level of alkali salts, the cement produced will have a high alkali
content. The raw materials can pick up the sulfur emitted in the
waste-heat stream and add to the problems of sulfur control brought
about by the sulfur content of the fuel used in firing the kiln.
As in the case of coal, some older plants can be restricted in
the application of preheaters by the amount of space available within
the plant for the installation. Such an installation could be readily
incorporated into the design of a new plant.
None of the firms interviewed had experience with the operation
of a vertical kiln. One firm had no knowledge of any experimental
testing. The other firms followed the work going on in Europe and
Japan with vertical kiln operation. From the impression given in
the course of the interviews, it does not appear that vertical kilns
will be accepted favorably by U. S. industry. Each of the firms
stressed the capacity limitations of the vertical kilns, many such
kilns would be required to equal present installed capacity. A
second disadvantage of the vertical kiln is poor product quality.
The kiln is stationery and the raw material falls by gravity through
the kiln. The raw material has a tendency to cake and block passage
because of the lack of agitation.
IV- 370
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Two of the firms contacted expressed an awareness of oxygen
enrichment as a means of reducing fuel consumption. Tests results
were unsatisfactory; in one instance the amount of fuel required was
only reduced by 5%. Oxygen enrichment is not economical in terms
of oxygen cost and does not conserve fuel when the amount of energy
required to produce the oxygen is taken into consideration.
Of the firms contacted only one had chain systems installed in
their kilns. One firm utilized waste heat for electricity generation
and the other used waste heat in the operation of preheaters. The
firm using chains reported satisfactory results and stated that the
temperature of waste gases was reduced to the lowest practical
limit.
All of the firms were able to comply with local, state, and
Federal emission requirements by the use of baghouses. These
systems trap particulate matter which evolve primarily from the
kiln and the clinker cooler. Electrostatic precipitators have been
installed on a limited basis, but were found less satisfactory than
baghouses. Corrosion of the unit and water disposal were two of
the main problems encountered.
Disposal of the particulate matter is a major problem in the
industry. One firm is faced with the problem of disposing of 650
tons of waste per day and this is expected to double in the next ten
years. The material must be hauled by truck to suitable landfill
sites. In some states the landfill site must be specially prepared
to prevent seepage of salts into sub-strata water. In many instances
the expense of equipping an older kiln with the proper dust-handling
equipment cannot be economically justified and have been phased out
of service.
The solid particulate matter cannot be recycled into the raw
material stream because of its alkaline content. The alkali content
of low-alkali cement cannot exceed 0. 6% per ASTM standard. If
IV- 371
-------
this standard were revised upward to 1. 5%, it was stated that all
of the collected particulate matter could be recycled and the land
disposal problem would be solved. The alkali salts react with the
aggregate used in the final concrete product, and fee cement manu-
facturer has no control over the type of aggregate used. The opin-
ion was given that increased alkalinity would not affect the quality of
the cement.
Emissions of SO and NO are not as large a problem to the
Jt •&
industry. SO emissions are controlled primarily by use of low-
sulfur fuels and controlled burning practice. The sulfur in the
waste-heat stream reacts with the particulates collected and the
raw materials as they are fed into the kiln. NO is not a major
JW
problem because of the absence of legislation.
Suggested areas of further research included —
• Investigation into the substirutability of Type 2 cement for
Type 1 cement.
• Investigation of alkali reaction problems that are of a local
geographical nature.
• Improved process control to monitor combustion practice to
conserve fuel.
• The development of combustion technology to reduce NO .
IV-372
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Glass Industry
The manufacture of glass involves three major energy-consuming
processes: melting the raw materials, refining the molten glass,
and finishing the formed products (as shown in Fig. 2). Typically,
about 80% of the energy consumed by the glass industry is for melting
and refining, and 15% is for annealing. The remaining 5% is for
"others" such as mechanical drives and conveyors (shown in Table 5).
Table 5. BREAKDOWN OF ENERGY CONSUMPTION
BY THE GLASS INDUSTRY IN 1971*
Flat Glass
(SIC Code iZH)
Glass Produced, 106 tons
Energy Consumption, 1012 Btu
Melting
Annealing
Other
Total Energy Consumption,
1012 Btu
Average Energy Consumption
for Melting, 1 Ok Btu/ton of
glass
Average Energy Consumption for
Entire Production, 1 O6 Btu/tnn
44. 7
8. 4
2. 8
55.9
17. 5
21.8
10. 90
104. 3
19. 6
6. 5
130.4
9. f,
12. 0
Pressed and
Blown Glass
(SIC Code 32Z9) Total
3. 50
SO, 5
9. 5
3. 2
63. 1
14, 4
1R. 0
16. 96
199. 5
37. 5
12.5
249.4
11. R
14. 7
Excludes energy consumed for electricity generation.
A-84-1402
Glass Melting and Refining
Both continuous melters and batch melters are used in the glass
industry, depending upon the output. Continuous melters are used
in the production of large-demand container glass (bottles, jars),
flat glass, and plate glass. Batch melters are used for specialty
glasses, high quality optical glass, and hand-blown glass products.
Continuous melters are normally maintained at temperature through-
out a compaign, which might extend from 4 to 6 years. Batch
melters are shut down frequently and allowed to cool off. Table 6
is a summary of the melting and refining equipment used in the
glass industry.
IV-373
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SILICA SAND
Si02
SODA ASH
NdoCCK
LIMESTONE
MgO • CaO
R20-AI203'6Si02
BATCH MIXING
MELTING
2700°F
REGENERATIVE FURNACE
SUBMERGED THROAT-
REFINING
2300°F
1472- 20I2°F
FINISHING
FABRICATION
ANNEALING
INSPECTION
PACKING |
AREHOUSING
A-83-1249
Figure 2. FLOW DIAGRAM FOR SODA-LIME
GLASS MANUFACTURE
IV- 374
-------
Table 6. GLASS-MELTING AND REFINING EQUIPMENT
Continuous Melters
Melting Tank
Refining Section With Premix Burners
Batch Melters
Unit Melters or Day Tanks
Batch Melters for Optical and Special Glass
Crucible or Pot Melters
Continuous Melters
Continuous melters in the glass industry are reverberatory
furnaces equipped with checker-brick regenerators for preheating
combustion air. Depending upon the firing arrangement used, the
melters are classified as end-port or side-port fired (shown sche-
matically in Figures 3 and 4). However, further breakdowns are
made, based on the location of the burners relative to the air inlet
ports. The burners can be placed over the air ports, through or at
the air port sidewalls, or underneath the air ports. Each firing
configuration produces a different flame geometry with different
heat-release characteristics, yet the overall thermal efficiency of
furnaces with any of these configurations is typically about
The fuels consumed in the melting process are primarily natural
gas and fuel oil. However, the use of submerged electrode electric
melting is increasing due to the air pollutant emissions and low
thermal efficiency of fuel-fired melters. Typically, a fuel-fired
melter consumes about 6. 0 million Btu/ton of glass melted, com-
pared to about 3. 0 million Btu/ton of glass melted in electric melters
(excluding energy consumed for electricity generation). However,
this figure is known to vary considerably, depending upon such fac-
tors as furnace insulation, combustion control equipment, molten
glass depth, and type of glass being produced.
IV- 375
-------
Figure 3. PLAN VIEW OF SIDE PORT FLAT GLASS FURNACE
IV- 376
-------
OJ
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IV-377
-------
Note that these fuel consumption figures apply to furnaces
during melting operations. However, data on energy utilization
(Table 5) indicate that energy consumption is actually higher be-
cause operation is suspended many times during the year for
breakdowns and holidays. During these periods, the furnaces are
idled to maintain furnace temperature while production stops. Thus,
energy is consumed but no glass is produced, thereby increasing
the overall average energy consumption per ton of glass produced.
An even greater source of discrepancy is the variation in the amount
of cullet, i. e., recycled glass, used from one glass plant to the next.
The amount of cullet charged varies from 10% to 30% of the total
raw material charged to the melter. Lower percentages of cullet
charged result in higher fuel consumption. In general, economic
considerations prevent higher percentages of cullet from being
charged.
Continuous Refineries
After completion of the melting phase, the molten glass flows
into the refining section where the glass temperature is reduced
and the glass is degassed. Refiners vary from plant to plant. In
some cases, it is an integral part of the furnace, separated from
the molten area by a wall, but taking its heat from the combustion
in the melter. In other cases, the refiner is separate from the
furnace and is heated with burners of its own, separate from the
melter. Premix burners are used in this application, and due to
strict quality control of characteristics such as color, natural gas
is the preferred fuel. The total energy consumed for melting and
refining glass represents about 80% of the total energy consumed
by a typical glass manufacturing plant.
Batch Melters
A very large amount of glass, particularly for pressed or
blown products, is produced in batch melters. These are classed
IV-378
-------
as day tanks or unit melters, and crucible or pot melters. Crucible
or pot melters are small rectangular or circular structures. Open
pots — round crucibles with capacities of 1 to 2 tons of glass —
are used in rectangular furnaces in which thick plate glass is cast
or special glass compositions are made. In circular pot furnaces,
covered pots are used for melting relatively small amounts of
special compositions, thus protecting the glass from the flames.
One advantage of pot furnaces is that different glass compositions
can be handled simultaneously, and the temperature of each pot is
controlled individually, within a limited range. Pot furnaces are
typically, although not always, provided with regenerators for fuel
economy.
Day tanks, or unit melters, are built up with refractory blocks,
thus differing from the pot, which is a single piece of refractory.
Day tanks are usually fired separately, rather than in groups, and
they have greater capacities than pots. In addition, they can be
heated to higher temperatures than pots, thus permitting the melt-
ing of compositions not particularly adaptable to pot-melting. Re-
fining of the glass in both pot melters and day tanks is carried out
as part of the melting operation in the same physical unit. The fuels
used in batch melters are natural gas and oil, although some melters
which produce optical-quality glass or colored glass may be restricted
to using natural gas because of the potential adverse effect of liquid fuels
on the quality of these glasses.
Glass Annealing
Annealing is the other major energy-consuming operation in the
glass industry, accounting for approximately 15% of the total energy
consumed. While annealing of large handmade ware may be carried
out in batch ovens, most ware from either batch or continuous-
melting operations is annealed in large tunnel-type ovens provided
with moving mesh-belt conveyors. These ovens, known as lehrs,
are temperature zoned, starting at about 1200°F, at the glass input
and decreasing in such a way that the cooling curve of the ware
IV-379
-------
precisely matches that required to obtain a strain-free product. The
size and arrangement of the lehrs depends on the characteristics of
the ware being annealed. Large ware with thick walls requires slow-
er annealing rates than small ware with thin walls.
Lehrs are heated by convection, radiation, or a combination of
the two. The most effective means, which provides the greatest
control and temperature uniformity critical to the production of
strain-free glass, is by zoned, convection lehrs with internal distri-
butors to obtain lateral temperature uniformity. External fans and
heater boxes are used in these lehrs, which makes it possible to use
either natural gas or oil as fuel. However, some lehrs are direct-
fired by atmospheric or premix burners or by excess air burners.
In this case, natural gas is the only fuel used so that the glass is not
likely to be contaminated by the "clean" combustion products.
Annealing lehrs generally operate at a thermal efficiency of only
20%. Much of the inefficiency is due to poor maintenance and oper-
ating practices. Most lehrs leak a considerable amount of unwanted
cold air into their chambers or lose heated air through unwanted
openings.
Air Pollution Emissions
In addition to being the primary consumer of energy in the glass
industry, the glass-melting furnace is also the primary source of
air pollutant emissions. The primary emissions are particulates,
sulfur oxides (SO — sulfuT dioxide and sulfur trioxide), nitrogen
3C
oxides (NO — nitric oxide and nitrogen dioxide), and carbon mono-
xide. Hydrocarbons are not a problem if proper combustion con-
ditions are maintained. Table 6 summarizes emissions from various
glass-melting tanks as measured by a number of investigators.
Air pollution emissions from annealing lehrs are not considered
to be a big problem. These emissions (CO and unburned hydro-
carbons) occur almost entirely as the result of incomplete combustion
IV-380
-------
Table 6. AIR POLLUTANT EMISSIONS FROM
VARIOUS PRODUCTION GLASS MELTERS
CO
NO
Investigators ppm-
IGT2 35-50a
Ryder and McMackin4 0-5b
Stockham5 375C
Arrandale1
Netzley3
a 8% excess air.
25-45% excess air.
c Excess air unknown.
Variable with production rate.
Natural gas fired.
490-700
450-600
340
Particulates,
Ib/hr
6-8
2-lOd
2-lOd
Halogens SO
-ppm-
1.0
7.1
28e
267
resulting from improper use of the combustion equipment. The one
exception is SO , which is emitted because of the sulfur in the fuel.
However, since oil is the only fuel containing sulfur used in lehrs and
its use is very limited, the amount of SOX emission is insignificant.
Factors Affecting Air Pollutant Emissions^
Several factors influence the emission rate of particulates
from a glass-melting furnace, including batch composition, batch
preparation, and type of fuel. The production rate of the furnace
also is a factor.
Measurements of stack emissions from a glass melter have
shown that the particulates emitted are primarily sodium sulfate,
IV-381
-------
which is a minor ingredient of most glass batch. In the furnace, it
vaporizes and decomposes to form elemental sodium and sulfate.
When these gases pass through the checker-brick and are cooled,
sodium sulfate is re-formed. Only about 40% of the sodium sulfate
charged into the furnace is vaporized; the remainder goes into the
glass. In addition to the sodium sulfate, a small amount of raw batch
that is carried out of the furnace by the flue gases is emitted. This
emission can be minimized by proper batch preparation, consisting
primarily of wetting the material before charging it into the furnace.
The amount of SO emitted from a furnace depends on 1) the
j£
sulfur content of the fuel and 2) the amount of sulfur-bearing com-
pounds in the raw materials. Consequently, natural-gas-fired fur-
naces generally exhibit lower SO emissions than oil-fired furnaces
Ji
unless the sulfur has been removed from the oil. Measurements of
SO emissions from a batch melter charged with batches of various
x
sulfur content showed a direct correlation between sulfur in the batch
and SO emitted. The greater the sulfur content of the raw batch,
3£
the higher the SO emissions.
3C
The amount of NO emitted from a glass-melting furnace de-
3£
pends upon several factors, some of which are not understood. One
important factor is flame temperature: NO formations in the fur-
3t
nace increase as flame temperature increases. For example, during
a recently completed experimental program, NO emissions were
ji.
measured during a complete firing cycle of a glass melter. NO
emissions were highest at the beginning of the firing cycle and then,
as the cycle continued, decreased by about 30%. At the beginning
of the firing cycle the combustion air is preheated to a higher tem-
perature, which results in a hotter flame than at the end of the
cycle, when the checker-brick and hence the air have cooled con-
siderably. Other major factors in NO formation in a glass melter,
such as flame velocity and recirculation patterns of flue gases, are
being studied.
IV-382
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Methods of air pollution control currently in use in the glass in-
dustry are primarily electrostatic precipitators (ESP) and baghouses
for particulates, and the use of low sulfur oil for SO emissions. In
X.
terms of equipment costs, ESP and baghouses are about the same
upon installation. However, less energy is consumed by ESP. To be
effective, baghouses require a substantial pressure differential which
creates a need for a substantial amount of horsepower to move the
particulate-laden air through the house. In addition, baghouses re-
quire more maintenance than ESP to be totally effective.
One of the problem areas faced by the glass industry in its at-
tempts to clean up their emissions is the variances in regulations that
exist from one state to the next. More than one company interviewed
indicated that because of these variances, different solutions must be
implemented to bring two plants, located in different states but other-
wise identical, into compliance. Thus in one state, baghouse systems
may adequately control a company's partic-ulate emissions, while in
a neighboring state a process modification, the use of electric melters
instead of fossil-fuel-fired melters is necessary. Such variances are
not only costly to a company, but also may dramatically effect energy
utilization as in the above example.
Other emissions, such as carbon monoxide and hydrocarbons,
can be controlled easily with proper combustion conditions. If opal
or green glass is being produced, halogens such as chlorine and
fluorine also are emitted in very large quantities from a fossil-fuel
melter. However, the industry has converted completely to electric
melting, and this swatch has eliminated these emissions.
Glass Industry-Field Survey
According to the glass industry, there exist several process
modifications for potential implementation by the industry sometime
in the future which would affect energy utilization and/or air pollu-
tion emissions. These are —
IV-383
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• Expansion of process monitoring and control capacity
• Electric melting
• Electric boosting
• Oxygen enrichment
• Raw batch preheating
• Raw batch agglomeration
• Use of low-temperature heat to drive compressors
• Augmentation of heat transfer from flames
• Submerged combustion.
Of these modifications, only the first three are considered by the
industry to have potential for implementation in the near future.
This is due primarily to the fact that such techniques are economi-
cally feasible and technical feasibility has been demonstrated to the
satisfaction of the industry, so that implementation is already occur-
ring. According to industry, the latter modifications listed are
generally considered to be economically unattractive or technically
unfeasible in spite of the published data to the contrary. The fol-
lowing discussion presents a brief description of the modifications
involved and the industry's viewpoint concerning implementation
•with respect to each.
Expansion of Process Monitoring^jj.nd Control Capacity
There are several modifications which can be made in the area
of process monitoring and control which will favorably influence the
utilization of energy in a downward direction, according to persons
interviewed within the industry. One such modification is the use
of improved temperature-sensing devices for continuous-process
monitoring. For example, infrared sensors focused on critical
areas of the melter, such as the optical block on the bridgewall,
which are used to gauge melter performance, can be used not only
to continuously monitor melter temperature, but also the signal
from such a unit can be used to control fuel input based on melter
temperature. Another such modification is the use of flue-gas analyses
to monitor excess air and maintain it at a minimum level. None of
IV- 384
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these monitoring techniques are expensive and all of them would con-
tribute to improving the efficiency of operation,
Electric Melting (and Boosting)
Primarily for purposes of reducing air pollutant emissions, the
glass industry strongly supports the implementation of electric
melting and boosting. Electric melting, as a method of producing
glass, has been proven technically and, in most cases, economically
feasible by virtue of its relatively widespread usage within the in-
dustry. (Actually, electric boosting, wherein a fuel-fired melter is
supplemented by electric melting, is very popular and more preva-
lent within the industry than pure electric melting. )
Oxygen Enrichment
Oxygen enrichment is a technique whereby pure oxygen is added
to the combustion air of a fuel-fired melter, resulting in an increase
in flame temperature, which in turn results in a reduction in fuel
required to melt a ton of glass, or alternatively allows a melter
operating at design capacity to boost its production above design
capacity. Based on the results of the interviews with glass manu-
facturers, oxygen enrichment is a long term goal, primarily because
acceptance by the industry requires substantial changes in fuel and
oxygen costs to economically justify implementation.
Raw Batch Pretreatment
The area of raw batch pretreatment inclxides batch agglomeration,
or compaction, and preheating of the batch prior to charging into the
furnace. Most companies interviewed feel that batch agglomeration
is not economically justified within the near term for reasons of re-
duced energy utilization or reduced particulate emissions. However,
at least one major glass manufacturer has recently put into operation
several pelletizing lines to supply pelletized batch to the melters.
At the present time, there are no data available regarding the spe-
cifics of this operation.
IV-385
-------
Coupled with the compaction of glass batch is the idea of pre-
heating it prior to charging into the melter. It is clear that such
a process must be coupled with a batch-compaction process in order
to minimize batch losses during preheating and to minimize partic-
ulate emissions from the batching operation. The industry contends
that preheating of the batch will cause it to become sticky, making
the charging operation next to impossible.
Submerged Combustion
Submerged combustion is a melting process whereby the fossil-
fuel burner is located beneath the molten glass surface and the hot
combustion products pass through the glass resulting in a very high
rate of heat transfer from the gases to the glass. Because the pro-
duct from this type of melter is foam glass, that is, it contains
millions of air bubbles, it is unacceptable to the industry as such
for use without substantial refining. The only possible use for sub-
merged combustion would be in a premelter, which at least one com-
pany has implemented. Because the refining step requires a sub-
stantial amount of energy (more than usual), it is not clear that
there is a reduction in the overall amount of energy consumed to melt
the glass. Consequently, substantial development is still required
before it will become acceptable to the industry, making implementa-
tion long-term at best.
Augmentation of Heat Transfer From Flames
This is a rather nebulous area for consideration in that there
are potentially numerous things which can be done to improve heat
transfer from the flame to the molten glass. One such example is
the use of devices which allow an operator to accurately and precisely
position the burners. A second example is the injection of water
vapor into the flame which theoretically increases the radiative pro-
perties of the flame, resulting in an increase in heat-transfer rate.
The entire area of augmenting heat transfer has great potential,
IV- 386
-------
according to the industry, but implementation of most of the develop-
ments is deemed to be long term.
Use of Low Grade Thermal Energy
At least one company interviewed expressed the opinion that
waste heat from the melting process, most of which is below 1000°F
and consists of 20% of the energy that goes into melting the glass,
could be used to directly drive turbines for air compressors which
•would then be used in the blowing operations. Alternatively, but not
as efficient, was the suggestion that this heat be used to drive tur-
bines in the generation of electricity. While such practices are not
currently used, with some development, usage might increase in
the long term.
Improvements in Equipment Design
Because of the rate at which equipment is replaced within the
glass industry, implementation of improvements in equipment design
are considered long term. Improved energy utilization is expected
from the application of better insulating techniques, improved regen-
erator design, and improved firing patterns by burner placement.
Annealing lehr efficiency is effected by numerous design considera-
tions. Among the most prominent considerations are the use of light-
weight lehr belts, method of belt return, proper insulation of the
heating zone, use of radiant burners in the heating roof section, and
design to prevent forward drift. Plant layout to minimize transit time
of the glass between the forming machine and lehr is also important.
As indicated, most of'these design modifications are considered long
term in terms of implementation and impact.
1 V- 337
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Aluminum Industry
Primary aluminum, manufacture is divided into four basic
operations: mining the bauxite; refining the bauxite into alumina;
smelting the alumina into aluminum; and melting and reheating of
the aluminum for forming, casting, rolling, and shaping. Since this
program is concerned with the combustion processes in aluminum
manufacture, this categorization will only deal with the bauxite re-
fining process in primary aluminum manufacturing and all of the
heating processes in secondary aluminum manufacturing.
Bauxite Refining
The refining of bauxite to obtain alumina is accomplished in the
Bayer Process. The objective of this process is to separate out the
impurities, which include iron oxide, silica, and titanium dioxide.
The first step in the Bayer Process is digestion of the bauxite
into a solution of hot caustic soda. The product of the digestion pro-
cess is a liquid containing dissolved alumina. This liquid is cooled
and hydrate alumina is allowed to precipitate out of the solution.
The precipitate is filtered, washed, and then heated in rotary kilns
at 1800°F, resulting in commercially pure, dry alumina. The rotary
kiln equipment and technology are similar to that used in the cement
industry.
Smelting
The smelting process, wherein alumina is converted to aluminum,
is an electrolytic process, and thus does not concern this program-
However, the process depends on the production of carbon anodes for
use in the pots and this production requires large amounts of fuel,
not only as a source of carbon, but also for drying and baking the
anodes once they are formed. The drying is done in rotary kilns or
vertical-shaft kilns, similar to those used in the cement industry.
V- .588
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Baking is done in batch-type box furnaces or continuous ring-type
furnaces.
Batch-Type Furnaces
Batch-type furnaces are, typically, box furnaces, fired pri-
marily -with gas or oil and varying load capacity from 100 Ib to
over 200, 000 Ib. Because they are batch-type furnaces there is
a considerable amount of energy wasted during a typical cycle,
•which includes charging the material, heating up the furnace for
baking, and then cooling down the furnace for unpacking and reload-
ing with fresh charge. Fig. 5 shows a typical cycle, relating the
time and temperature for baking carbon. The cycle varies accord-
ing to such parameters as type and size of electrodes processed and
the size of the furnace being used. Typically, a box-type furnace
consumes about 18 million Btu/ton of carbon baked.
Ring-Type Baking Furnaces
Most of the furnaces used for anode baking are of this type. The
operation of a ring furnace is cyclical and can be broken down into
five steps: loading, preheating, heating, cooling, and unloading.
Most ring furnaces are gas-fired, using either natural gas
or producer gas. They are also regenerative furnaces, thus afford-
ing economies in fuel consumption. Additionally, the waste heat of
the combustion products is used in the preheating step. Such eco-
nomies result in a typical fuel consumption rate of 9 million Btu/ton
of carbon baked — about 50% less than the box-type furnaces,
Primary Aluminum Melting
Aluminum melting is accomplished in furnaces at temperatures
of about 2000°F. The types of furnaces used for melting are —
IV-389
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o
o
UJ
£C
o:
uj
a
2
UJ
i-
UJ
o
<
z
oc
1000
900
800
700
600
500
400
300
200
100
COOL
05 tO 15
TIME, days
20
25
A-124-2238
Figures. TYPICAL OPERA TION AND
THERMAL CYCLE FOR BAKING CARBON
IV- 390
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* Large and small stationary tilting reverberatories
• Holding furnaces (reverberatories)
• Tilting, barrel-type furnaces
• Stationary and tilting crucible furnaces
• Dry-hearth mclters.
The type of furnace used depends on a number of parameters in-
cluding —
• Quantity of metal required
• Type and form of charged materials
• Desired melting rate and temperature control
• Type of product.
Of the various possible types of furnaces, batch-type reverberatory
furnaces are the most commonly used. They are usually rectangu-
lar, refractory-lined boxes with burners at one sidewall and charg-
ing doors above the metal line along one side. These melters vary
in capacity from less than 5 tons to over 80 tons. Aluminum mel-
ters, considering only melting, are designed for melting rates as
high as 65 Ib/sq ft-hr. If charging, holding, and discharging are
also considered, the melting rate decreases to about 35 Ib/sq ft-hr.
Fuel efficiency for these melters is about 30%. Dry-hearth furnaces,
another type of reverberatory furnace, can melt at a rate of 100 lb/
sq ft-hr, but are not used for high-quality aluminum-alloy production.
Crucible or Pot^ Furnaces
Crucible or pot furnaces are used in cases where the required
capacity, generally 30 to 1000 lb? is low and the need for flexibility
is high. Crucible furnaces are used for melting as well as holding.
They may be stationary or tilting, or the crucible may be removed
and transferred to the casting area. Heat transfer in a crucible
furnace is through the crucible walls. Burners are situated tangen-
tially around the furnace to supply tiniform heating to the crucible.
The modes of heat transfer to the- pot are primarily convection and
IV-391
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radiation; however, in the case of convection, direct impingement
is avoided as hot spots will reduce crucible life and interfere with
the control of the metal temperatures. Use of these modes of heat
transfer results in an average fuel efficiency of about 15% to 20%,
as opposed to 30% in reverberatory furnaces where heat is trans-
ferred directly from the flame and surrounding refractories to the
metal surface.
Burner Equipment and Firing Arrangement
Both premix and nozzle-mix burner equipment are used for
aluminum melting. Premix burners, both the aspirator and inspir-
ator types, are used primarily on small crucible melters, parti-
cularly those that are fired tangentially. Only nozzle-mix burners
are used on the large-scale melters because of the longer, more
luminous flame and adaptability to dual fuel firing. Normal prac-
tice is to use a few large burners (10 to 20 million Btti/hr) rather
than several smaller burners. Some burner designs are quite
similar to those used on steel-mill soaking pits having the capability
of adjusting the flame geometry to suit melting-chamber require-
ments. Roof-firing with radiant burners, although theoretically ideal
for heating aluminum where flame impingement on the bath surface
is undesirable because of high oxidation loss, is not used on the
large, side-charged melters because of the severe splashing pro-
blems encountered. Radiant burners are, however, used on smal-
ler reverbs that are charged through endwall charging wells and on
holding furnaces where a relatively quiescent atmosphere is very
desirable.
One of the preferred firing arrangements for large reverbs is
the W-flame, two-pass geometry. In this arrangement, two burners
are located in one endwall, with the flue port located below the burn-
ers on the furnace centerline just above the metal line. The high-
velocity, hottest flue products are well above the bath and transfer
IV- 392
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heat directly to the arch, while the cooler, low-velocity combustion
products are distributed over the entire bath surface area and trans-
fer heat to the bath with a minimum of flame impingement.
For the holding furnace, which requires a much lower input,
single-pass firing is more desirable. The burners are at one end
of the furnace and the flue is at the other, avoiding the danger of
short-circuiting to the flue that is inherent with the W-flame design
at low burner input.
Natural gas, LP gases, distillate and residual fuel oils, and
electricity can all be used satisfactorily to heat the large reverbera-
tory melters, although natural gas has been preferred because of
low cost, cleanliness, and controllability. Induction melters have
reached the 15-ton melter-capacity level. However, the interest in
induction melting in the program is low and will not be considered
in detail.
Aluminum Reheating for Forging and Extrusion
Almost all of the fuel-fired furnaces used for heating aluminum
and aluminum alloys for forging and extrusion are of the convection
type and are indirectly heated. Indirect heating with radiant tubes
is preferred, particularly for alloys sensitive to surface reactions
with combustion products. The heating furnaces are typically con-
tinuous, using chain or slot conveyors and distributing the heated
air through ported or slotted tubes or through plenum chambers.
The wind-flow distribution systems can be transverse, longitudinal,
or vertical, depending on the mass, size, shape, and loading of
the stock being heated; allowable tempe rature drop in the circulating
wind; required heating rate; and allowable temperature variation
in the heated stock. Heating-wind temperatures is normally about
75°F hotter than the final stock tempe rat ure.
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A flame-impingement furnace is frequently used for heating
"soft" aluminum alloys for extrusion but not for heating the "hard"
alloys because of adverse effects on surface metallurgy and the in-
ability to control billet temperature within required limits. In this
furnace, the billets are conveyed on alloy brackets fastened to a
heavy-duty conveyor chain that runs cold below the bottom of the
furnace. The alloy brackets extend through a slot in the bottom
of the furnace and support the billets on the centerline of the heating
chamber. A row of premix "blast" burner tips fire horizontally
at the billet centerline. Heating rates of about 2 to 3 minutes per
inch of billet thickness are normally maintained. The lower half
of the furnace is made up of two separate, sequented, cast-
refractory sections individually supported by the furnace structural
elements. The top part of the furnace is made up of a number of
half-circular cast refractory sections with flue ports at the top.
The flow of ambient air up through the conveyor slot, by draft
effect, cools the chamber walls to approximately the local billet
temperature. This minimizes the risk of billet overheating, or
even melting, during production delays. These gas-fired, rapid,
billet heaters represent major competition to 60-cycle induction
heaters for aluminum extrusion. Input to each furnace zone is con-
trolled by a radiation-type, temperature - me asurement instrument
sighting at the billets through an open tube between the furnace zones.
Unfortunately, if a billet is not loaded onto each conveyor fixture,
the instrument sights on an open space and calls for maximum in-
put, incurring the danger of overheating or melting the billets.
Typical operating problems with the impingement billet heaters are
a) poor billet temperature control after a production delay or a change
in production rate, b) overheating or melting of billets if a gap is
left on the conveyor, c) conveyor maintenance, and d) refractory
failure.
IV- 394
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Forging or extrusion temperatures for aluminum and for most
aluminum alloys are usually 750° to 850°F. Some of the "hard"
alloys are forged at 900° to 920°F. The heat content of aluminum
above ?00°F and corresponding fuel-input requirements in millions
of Btu/ton for various efficiency levels are shown in Table 7.
Table 7. HEAT CONTENT OF ALUMINUM WITH FUEL-
INPUT REQUIREMENTS FOR VARIOUS EFFICIENCY LEVELS
Heat Contents
Gross Efficiency, %
Temperature,
op
700
800
850
900
1000
Btu/lb
146
172
185
199
277
Net, 1000
Btu/ton
292
344
371
398
454
10
2.92
3.44
3.71
3.98
4. 54
20
-106 Btu/toi
1.46
1.72
1.85
1.99
2.27
30
0.97
1. 15
1. 24
1.33
1.51
Almost all convection reheat furnaces use natural gas because
of favorable price, controllability, and freedom from carbon depo-
sition or pollution-control problems. Atmosphere control is ini-
tially important for direct-fired furnaces, and the atmosphere is
most readily controlled with natural gas firing. In indirect heating
with radiant tubes, application of residual oil firing is extremely
difficult.
From the available data, it appears that the convection heaters
for forging and extrusion operate at very low efficiency level, pro-
bably averaging 10% to 15% overall. The major reasons for the low
efficiency level appear to be conveyor reheating, excessive air in-
filtration, and high flue-gas temperature from radiant-tube firing.
The most important single factor affecting efficiency is air infiltra-
tion. Convection-heating furnace designers estimate that 100% excess
air is heated because of leakage losses.
IV- 395
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About the only effective means for improving the efficiency of
existing convection-furnace designs using radiant-tube heating is
to install recuperative radiant-tube burner systems. A fuel saving
of 20% to 25% can be attained by preheating combustion air to the
650°to 750°F range.
Air Pollution Emissions From Primary Aluminum Manufacture
Information regarding air pollution emissions is very limited,
and then it is restricted primarily to discussions of fluorides and
particulates. No data are currently available on combustion-related
emissions from primary aluminum manufacturing processes. How-
ever, there is no reason to believe that these emissions will be any
different than those from similar processes in other industries.
Thus, it can be presumed that CO, hydrocarbons, nitrogen oxides,
and sulfur oxides are being emitted. The extent to which these
emissions are a problem remains to be determined.
The product of the secondary aluminum industry is a metallic
aluminum alloy in the form of 15 and 30-lb ingots, 1000-lb sows,
or hot molten alloy. Some scrap is melted to produce a deoxidizer
for steel mills in the form of a notched bar or shot.
The scrap raw material is purchased on the open market in
various forms. The scrap can be divided into two categories:
residues and solids. Residues include dross and skimmings from
melting operations in the primary aluminum industry, from fabri-
cators, and from foundaries. Dross, the scum that forms on the
surface of molten metal, is high in aluminum content. Solids con-
sist of borings, turnings, new clippings and forgings, old castings,
sheet, and castings containing iron.
The quantity of energy required to melt 1 pound of secondary
aluminum is about 5% of the amount required to produce the same
quantity of virgin aluminum from bauxite in the primary industry.
Depending upon the size and condition of the melting furnace,
IV- 396
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approximately 10, 000 Btu of energy is required per pound of product
produced, excluding the energy required to operate pollution control
devices.
Three basic operations are employed in recovering aluminum
from scrap materials: preparation prior to smelting; charging,
smelting, and refining; and pouring the product. The operations
vary among different smelters and result in a variance in the quan-
tity of energy required.
Presmelting varies according to the type of scrap. Solids are
sorted, sweated, dried, and reduced in size, and residues are reduced
in size and screened to separate the metal values from the conta-
minants. High-quality scrap consisting of forgings and new clippings
has very little contamination and usually is sorted only to remove
foreign metal.
Borings and turnings are heavily contaminated with cutting oils.
The material is received in intertwined pieces that are crushed in
ring crushers or hammermills. After crushing, the material is fed
into gas- or oil-fired rotary dryers to burn off oils, grease, and
moisture. The material then is screened to remove fines and passed
through a magnetic separator to remove available iron.
After pretreatment, the aluminum scrap is charged into rever-
beratory furnaces in a series of seven steps: 1} charging the scrap
into the furnace, 2) adding fluxing agents, 3) adding the required
alloy materials, 4) mixing, 5) removing magnesium, 6) degassing,
and 7) skimming. All these steps are not practiced by all smelting
operators, and the choice of steps depends upon the desired end
product.
The amount of time required to fully charge a furnace depends
upon its size, which can range from 10 to 90 tons. It takes from 4
to 75 hours to fully charge a furnace, the average time being 24 hours.
The time required to complete a smelting cycle depends upon the
size and design of the furnace, fluxing procedures, alloy require-
ments, and heat input.
TV- 397
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A typical secondary aluminum recovery plant consists of two to
four — sometimes as many as 10 — reverberatory furnaces which
are predominantly natural gas-fired. A furnace with a 40-ton name-
plate capacity rating may actually produce 20 tons of product per
heating cycle. Approximately one-third of the 10, 000 Btu/lb re-
quired in the smelting operation, as previously mentioned, powers
the auxiliaries, such as pretreatment of the scrap. The thermal
efficiency of a reverberatory furnace under optimum operating con-
ditions is 25$ to 35$ .
Although natural gas is the principal fuel in furnace operation,
oil can be an alternative with some modification in operating prac-
tices. The efficiency of the burner decreases when oil is used. The
reverberatory furnace operates by deflecting the flame onto the
charge by a sloping-roof arch. The burner is fired diagonally down-
ward toward the melter bottom against, or just over, the metal bath.
Combustion products vent at the opposite end of the furnace through
a combination hopper and flue. Much of the heat transfer occurs by
radiation from the roof and sidewalls of the furnace. The furnaces
can be fixed, tilting, or rotary, and a luminous flame is desirable,
although flame length can be a limiting factor, depending on burner
placement and furnace geometry. The efficiency decreases when oil
is used because a minimum distance is required to achieve atomiz-
ation and complete combustion.
Aluminum. Industry-Field Survey
The companies contacted during the course of this study con-
sisted of two primary producers and one secondary producer. The
major energy conservation steps undertaken by these firms can be
summarized as follows:
• Continuing research and development programs to improve
existing manufacturing processes
IV- 398
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• Streamlining production processes by modifying equipment
and operating practices
• Installation of energy management programs at all organiz-
ational levels.
These programs are the direct result of the current decreasing
availability of natural gas supplies to industrial users and increasing
oil prices. The increased use of coal, particularly for steam gene-
ration, is regarded as a near-term solution to the problem. A pros-
pective development anticipated for the long-term time frame is in-
creased development of nuclear power.
Approximately 52$ of the energy requirements within the pri-
mary aluminum industry is the form of electric power. This power
is generated internally as well as purchased from outside sources.
The two primary producers interviewed produced a major portion of
their power requirements internally.
The average power consumption of an aluminum smelter is about
8 kWhr per pound of aluminum produced from alumina. The most
efficient smelter requires about 6. 5 kWhr per pound.
Some of the newest developments within the industry include
the following:
• Flash calcining
• Electrolytic smelting
• Pulverized coal
• Preheating metal charge.
A flash calcining unit has been developed on a proprietary basis.
This system combines the benefits of the fluidized bed and dispersed-
phase technology to improve both heat exchange rates and to reduce
heat losses. The amount of energy consumed in a rotary calciner
to produce alumina is approximately 2000 Btu per pound of product.
Reportedly, the flash calciner requires 1400 Btu per pound of pro-
duct.
IV-399
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Electrolytic smelting, another process of a proprietary nature,
has been developed and reduces power requirements within the smelting
step by 307°. The process includes a reactor to react chlorine and
alumina to produce aluminum chloride. The aluminum chloride is then
electrolytic ally decomposed in a separate cell producing chlorine and
aluminum. The chlorine is then recycled back to the first stage reac-
tor.
Reverberatory melting furnaces are used both in primary and
secondary producing industries to remelt mixtures of scrap and pri-
mary aluminum. In the past, these furnaces have been fired with
natural gas and have been recently converted to residual oil because
of the natural gas shortage and uncertainties concerning future pro-
pane availability.
One of the firms is about to embark on an experimental program
wherein a pulverized coal combustion system will be installed on a
melting furnace. Successful development of a compact, efficient
process for SO2 removal from the stack gases would lend itself to
the establishment of coal as a primary fuel within the aluminum in-
dustry.
The average efficiency of fuel fired melters is in the range of
25% to 35%, dependent upon operating practice, age, and condition.
Preheating the metal charge and combustion air can increase fuel
efficiency up to as high as 50%. Melters fired with natural gas, pro-
pane or oil with an acceptable sulfur level do not require stack-gas
cleaning or scrubbing to meet existing pollution legislation. Conver-
sion to coal firing would require the installation of a stack-gas clean-
ing device for fly-ash removal. Solvent refined coal (SRC) which
has a very low ash content, could be used as a fuel in reverberatory
furnaces, if its price is competitive with the cost of residual oil or
coal, including the expense of stack-gas cleaning devices.
IV- 400
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From a practical sense, No. 2 fuel oil is easier for the furnace
operator to use than No. 6 oil. However, No. 2 oil is at the mercy
of fuel allocation programs, as is natural gas, and is subject to
extreme swings in availability.
The composition of No. 6 oil makes it difficult to handle in a
reverberatory furnace. The No. 6 oil available today is a blend of
tars and fluidizing agents that render it incompatible with good com-
bustion practice. The oil must be preheated to 190° to 200°F to
make it flow, and in this temperature range the blending agents
flash out. In addition, No. 6 oil must be used under high pressure
to achieve atomization; it has a high ash and sulfur content, is high
in particulates produced, and is costly in terms of storage require-
ments. The general availability of No. 6 oil also is of concern to
the secondary aluminum industry because it must compete for avail-
able supplies with the electric utilities. Moreover, refineries are
producing less residual oil because of higher yields of gasoline and
other light oils.
The cost of electricity as a fuel is 3 to 8 times greater than the
cost of natural gas or fuel oil. The average price paid for natural
gas in 1970 was 50«f to 60«!/1000 CF. Present natural gas prices
range from a low of 90^1000 CF in the Southeast to as much as $2. OO/
1000 CF in the Pacific region. The opinion was stated that the large-
volume industrial user is losing his favored position in the switch
from wholesale to retail natural gas pricing. During 1971-72, the
price of No. 2 fuel oil was 8tff/gal; currently, it is 32^/gal, with
further increases anticipated.
The primary means of controlling stack emissions within this
firm, and for many others in the industry, is stack afterburners.
The afterburners, which are fired with natural gas, consume appro-
ximately 2000 Btu/lb of product produced, in addition to the 10, 000
Btu required to produce 1 pound of aluminum. No. 2 fuel oil can be
used in the afterburner if natural gas is not available; however,
TV-401
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the Btu requirement of fuel oil is greater: 5000 Btu/lb of product
produced.
In applications requiring additional control, venturi scrubbers
or baghouses may be installed after the afterburner. The type of
unit depends upon the emissions. The scrubbers are used to remove
chloride and fluoride contaminants. After the material from the
scrubber has been evaporated, the product is a dry salt. The salt
presents an additional solid waste problem because many states do
not allow disposal in landfills without expensive preparation to pre-
vent leaching into substrata water. Some states do not allow the dis-
posal of salts of any kind in spite of extensive preparation steps.
The recycling of aluminum cans has become a growing source
of scrap for aluminum melters, amounting to 68 million pounds in
1973. Associated pollution control problems include the lacquer
coatings used on beverage containers and oil or lubricants on rolling
mill and die casting scrap. One of the firms interviewed proposes
the development of a selective oxygen injection system for melters
to provide a low energy system for pollution control.
Baghouses are used along with afterburners to control particulate
emissions. The amount of energy required to operate a baghouse
is equivalent to approximately one-half of the energy required to
operate the afterburner, or about 1000 Btu/lb of product produced.
Baghouses require extensive maintenance and are not effective for
the control of gaseous emissions. In addition, a potential fire hazard
exists in the use of a baghouse because of the high organic content of
the material collected. Disposal of the particulate matter collected
in a baghouse presents the same problem as the disposal of salts.
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Petroleum Refining
Petroleum refining is largely accomplished by distillation separa-
tion into intermediate feedstocks and products. The intermediate
feedstocks require heating and thermal cracking or catalytic treat-
ing before separation of the desired products. This separation usu-
ally requires additional heating after the catalytic treatment or
thermal cracking.
Total refinery energy consumption amounts to around 10% of the
crude throughput. Most of this energy is consumed as fuel in fired
heaters. The amount of energy consumption depends largely on the
complexity of processing which takes place after the initial crude
distillation separation. Generally a gasoline oriented refinery will
have fuel consumption considerably greater than a distillate oriented
refinery. In the long run, the refinery output is controlled to meet
consumers demand. This demand is for high gasoline production
in the summer and fall seasons with high distillate fuel production
during the winter season.
Petroleum refining involves the use of fired heaters in many
operations beginning with initial crude distillation unit. On this unit,
separation is made by distillation of the crude oil into the fractions
which become the charging stock for the other operating units in the
refineries. In a typical fuels refinery these units are as described
briefly below:
Reforming Unit; On this unit the fraction of straight run gasoline
boiling above 160°-180°F is vaporized in a fired heater, desulfurized
over a catalyst, and relieved of the sulfur and light fractions. The
straight run gasoline is vaporized in another fired heater and routed
over a platinum-containing catalyst which reforms the approximately
45% naphthenes to aromatic s, which have a high octane. This gaso-
line is relieved of the light hydrocarbons, making it a finished gaso-
line.
Catalytic Cracker; The material boiling above kerosene in the crude
unit is routed to a cat cracker where it is cracked at 875°-9Z5°F to
make a variety of materials including gasoline, olefins for alkylation,
and distillate fuel.
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Delayed Coker; This unit is a high fuel consumer employing fired
heaters to heat the charge oil for distillation. The distillation bot-
toms are routed through another heater to coke drums where the
heavy fractions remain while coking. The unit produces gas, ole-
fins for alkylation, gasoline, distillate fuel and coke.
AUcylation Unit; The three and four carbon olefins and isobutane
are reacted in this unit to make alkylate, a mixture of seven, eight,
and nine carbon-atom compounds, which are widely branched to
give a very high octane gasoline. Separation of the reaction products
is by distillation towers reboiled by a fired heater.
Distillate Hydrotreaters: These units are supplied with hydrogen
and the feedstocks heated in fired heaters to 650°-750°F before
routing over a fixed bed of catalyst for desulfurizing and upgrading
the burning qualities of the distillate fuels.
In most existing refineries the different units are operated as
separate entities having intermediate tankage for charge and products.
This provides both operating and maintenance flexibility. Trends
have been to eliminate the intermediate tankage and reduce fuel con-
sumption by running hot feed from one unit to another. New refiner-
ies can be designed in this manner to effect savings in fuel consump-
tion while accepting the risks of intermediate processing bottlenecks
or reduced stream factors. The completely integrated refinery can
have no greater on-stream factor than the lowest of the stream fac-
tors of the individual units.
The approach to developing information on trends in refinery
fuels consumption was to interview the fuels and emission coordina-
tors in the central office of the refining companies. Two of the
largest refiners were interviewed. These refiners have fourteen
refineries running a total of 1.7 million barrels per day of crude
oil. Also interviewed was the director of refining of the American
Petroleum Institute (API), who is responsible for setting up a fuel-
conservation program involving more than 80% of the U.S. refinery
capacity.
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His program resulted in the naming of a fuel-conservation
coordinator *or each of the refining companies. A program for fuel
conservation was implemented for which results have become avail-
able.
These results have been reported as follows:
Energy Consumption,
weighted average for
37 companies,
1000 Btu/bbl input
1972 Base Period Total Energy
Consumption
1972 Base Period Adjustment to
1974
Adjusted 1972 Base Period Total
Energy Consumption
Less 1974 Last Half Year Total
Measured Energy Consumption
Energy Conservation Improvement
for last half of 1974
% Reduction from 1972 Base
667
+9
676
624
52
It is generally accepted that the greatest single factor affecting
the refining industries' improvement in fuel consumption was the
response of the industry to the economics of the high price of crude
which occurred during the last quarter of 1973 and the resultant
higher price of fuel consumed. One of the companies interviewed
arbitrarily set a fuel price for conservation economics to reflect
its selling price as fuel oil rather than the price of purchased
natural gas, which continued to be much below the more realistic
price of refinery fuel oil.
Effort to improve fuel consumption involved giving increased
attention to the current practices in firing the process heaters and
boiler house. In the larger refineries, checking of heating
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performances and assisting the operators to achieve correction to
proper firing conditions is a full time job for one man. Firing to
10% excess air was accepted as a goal for furnaces firing gaseous
fuel, with 7.0% excess air for furnaces firing predominantly oil fuel.
Improved oxygen analyzer installations are being employed to monitor
this. These goals were not being attained, and it was felt that im-
proved fuel oil burner design would be required to accomplish this.
They feel that most existing furnaces lack the combustion space to
burn predominantly oil without a reduction of furnace throughput.
Preheat of the heater feeds is being given increased attention
in both existing and new installations. Cleaning of heat transfer sur-
faces in exchangers and heaters both on-stream and off-stream is
getting increased attention. Some novel techniques being applied to
fired heaters are:
1. Use of water lance for shock cooling and flaking deposits from
outside of tubes
2. Use of walnut shells for blasting of powdery deposits from out-
side of furnace tubes.
Increased maintenance of insulation on hot lines and increased
attention to required operating reflux ratios on distillation columns
are being employed in existing installations.
Refining organizations hope for continued improvements in fuel
conservation by long-range projects, both of a replacement nature
for existing equipment and in the installation of new units having the
benefit of improved design.
A comparison of past practice with future design practice shows
how the furnace design conditions will be tightened up.
Lowest temperature for heat
removal by exchange
Furnace stack-temperature
Past
Practice
400°F
800°F
Future
Designs
250°F
400°F
V- 406
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They recognize that furnace tube outside skin temperature will
be a consideration for the future designs as they will have to keep
surfaces above the dewpoint of the furnace gases.
Conservation coordinators feel that retrofit installations of air
heaters and steam, coils can be justified at current high fuel prices.
In completely new installations they will expect to have a greater
ratio of convection surface to radiant surface. Increased use of ex-
tended surface convection furnace tubes is expected. One group
favored a furnace design that will eliminate the damper in the
breeching to the stack, using instead an air supply box servicing
multiple burners. Such installation would provide dampers on the
forced air supply to the windboxes. They do not expect to be
going to flue-gas recirculation for emissions control.
The API refinery survey showed that 31% of the refinery fuel
consumed was purchased natural gas. Replacement of this gas with
liquid fuels will require more furnace volume, as mentioned above.
Some instances of conflicts between lower emissions and fuel
conservation were cited. In the interest of improving heater effi-
ciency they are going to air preheat. However, they are concerned
that NO standards which might be set in the future will put them
above the NO standard. In another instance, when lower stack
2C
temperature is achieved in the interest of improved fuel efficiency,
it can be calculated that ground-level emissions will increase. It
makes no sense to forego such installations in order to meet ground-
level emissions standards. In another instance, installation and
operation of Claus tail-age cleanup units unquestionably results in
high energy consumption but with no compensating improvement in
overall efficiency.
The refineries arc removing H2S from their major fuel-gas
streams. In so doing they are eliminating SOa emissions from the
heater stacks. By installing a Claus unit to convert the H2S to free
V- 407
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sulfur, they undertake a large expenditure for which, there is little
or no return. This is accepted without question as they recognize
that 95% of the sulfur emission is thus eliminated. However, the
remaining 5% of the sulfur is now going up a single stack. It re-
quires an expenditure equal to or exceeding the Glaus unit expenditure
to recover the remaining 5% of the sulfur. Furthermore, the Glaus
stack-gas recovery unit adds increased investment and labor costs
with practically zero return.
Recommendation by Refiner s
1. That emission guidelines be sufficiently flexible so as to allow
waivers for refineries in areas remote from cities. This prac-
tice is in the interest of fuel conservation.
2. That guidelines be set by environment tolerances rather than a
specification based on the refiners or a process1 capability.
3. That fuel oil burners be improved so as to allow combustion with
lower excess air.
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APPENDIX A
Weighting Factors
The next step in the selection process is the assigning of weight-
ing factors to each of the restraints in terms of their relative import-
ance. In developing the weighting factors, the following assumptions
have been made:
1. All air pollutants arc equal in importance.
2. Conservation of energy and reduction of emissions are equal
in importance.
3. Industries with no potential for energy conservation or reduction
of emissions will be excluded from consideration.
Given these assumptions, the weighting factors are assigned based
on a scale of 1 to 1 0 where 1 is a low-priority and 10 is a high-
priority rating. To determing the suitability of a particular industry,
the following set of numerical operations would be performed:
1. Base energy consumption X emission index number — emission
weighted base number.
2. Estimated potential for energy conservation X emission weighted
base number.
3. Estimated potential for reducing emissions X emission weighted
base number.
4. Items 2 + 3 — conservation and emission weighted number.
Based on the value obtained in 4 above, the industries for study have
been selected with the highest value given the highest priority.
Table A-l defines the weighting system we used to arrive at the
numbers used in the above set of equations.
i V- 4()9
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Table A-l. WEIGHTING SYSTEM FACTORS
1. Base energy number
The base energy number is arrived at by summing the weighting
factors for restraints Nos. 1, 2, and 3, where the following values
are assigned (scale 1 -> 10).
Restraint No. 1. Energy use in process heat
1 = Low usage; 10 = High usage
Restraint No. Z. Combustion-related uses
1 = No combustion-related uses; 10 = All combustion-related uses
Restraint No. 3. Number of processes
1 = Numerous processes; 10 = One process only
Z. Emission index number
The emission index number is arrived at by summing the
weighting factors for restraints Nos. 4 and 5. However, since the
primary emissions of concern as indicated in restraint No. 5 are
generally directly combustion-related, the emission index number
can be based on restraint No. 4 alone with values assigned as follows:
1 = Mostly independent emissions; 10 = mostly combustion-
related emissions
3. Potential for energy conservation
1 = Low potential; 10 = High potential
4. Potential for reducing emissions
1 = Low potential; 10 = High potential
1V-410
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POM AND PARTICULATE EMISSIONS FROM
SMALL COMMERCIAL STOKER-PLRED BOILERS
By
R. D. Giammar, R. B. Engdahl, and
R. E. Barrett
BATTELLE
Columbus Laboratories
Columbus, Ohio
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POM AND PARTICULATE EMISSIONS FROM
SMALL COMMERCIAL STOKER-FIRED BOILERS
By
R. D. Giammar, R. B. Engdahl, and
R. E. Barrett
ABSTRACT
This paper describes a program to evaluate emissions, including POM
from residential and small commercial stokers. The program consists
of: (1) a survey to identify processes for manufacturing smokeless
coal and to evaluate the suitability of these fuels for stoker-
firing; (2) a survey to identify the manufacturers and designs of
small stokers currently being marketed; and (3) an experimental
laboratory program to measure emissions while firing a small stoker
with several candidate stoker fuels. In the experimental program,
a 20-horsepower stoker-fired boiler is fired with anthracite,
bituminous, Western and "smokeless" coals over several operating
cycles. From the results of these experiments and the survey, a
program will be recommended to increase environmental acceptability
and to improve the economics of residential and small commercial
stoker boilers. The experimental portion of this program is
currently being conducted and, as a result, data are not available
for discussion.
TV-4 12
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POM AND PARTICULATE EMISSIONS FROM
SMALL COMMERCIAL STOKER-FIRED BOILERS
By
R. D. Giammar, R. B. Engdahl, and
R. E. Barrett
INTRODUCTION
Coal was still a major fuel fired in residential and small
commercial heating systems as late as the 1950's. Coal usage then
rapidly declined as the market area of the less expensive and more
conveniently fired fuels, gas and oil, expanded. Even in certain geo-
graphical locations where coal was cheaper than oil or gas, the high
maintenance costs and labor associated with firing coal coupled with
an increased awareness of the environment virtually eliminated the
use of coal for residential and small commercial space heating appli-
cations by the 1960's.
However, the uncertainty in both the short- and long-term
availability of oil and gas has created renewed interest in burning
coal to meet our nation's energy needs. In order to technically assess
the environmental impact of burning coal, specifically in residential
and small commercial applications, the EPA has funded a program to
evaluate the emissions from these units under smokeless operation.
This program consists of:
(1) A survey to identify the manufacturers and designs of stokers cur-
rently being marketed. Because the design and operation of small
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stokers is almost a lost art, a discussion of design and opera-
tional aspects are included in this survey.
(2) A survey to identify processes for the manufacturing of smokeless
coal and to evaluate the suitability of this fuel for stoker firing.
(3) An experimental laboratory program to measure emissions while
firing a small stoker with several candidate fuels.
This program is ongoing as experimental data are currently being ob-
tained. Accordingly, the results of the laboratory work are unavail-
able for publication at this time, but will be included in the final
report on EPA Contract No. 68-02-1848-
OBJECTIVES AND SCOPE
The overall objectives of this program are:
(1) To evaluate emissions from residential and small commercial stoker-
fired boilers under typical boiler operation, including smokeless
operation.
(2) To assess the advisability of increased utilization of coal for
residential and small commercial applications including considera-
tion of operating efficiency, fuel type and availability, economics,
and environmental impact.
A 20-hp stoker-fired boiler system is being used to evaluate
emissions from the combustion of anthracite, Western, processed "smoke-
less", and high- and low-volatile coals under several boiler operating
cycles. Pollutants of interest include NO, S02> smoke, particulate,
and the polycyclic compounds.
IV- 414
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TECHNICAL BACKGROUND ON STOKERS
To provide a basis for an assessment of the increased utili-
zation of stokers, a description of the design and operation of stokers
is given to identify the complexity (in contrast to oil and gas) of
burning coal in small units. Also, a summary of the survey of stoker
manufacturers is included.
Stoker Design and Operation
Smoke evolved when burning high-volatile coal has always
been a problem for residential and small commercial heating units.
Development of the residential underfeed stokers, such as the inverted-
underfeed stoker designed in the 1940's, made it possible to burn high-
volatile coal smokelessly. However, recent attention has focused on
all emissions which includes not only smoke, but NO , SO , CO, particu-
X X
late, and POM. Levels of these emissions are related to stoker design,
stoker operation and firing procedure, and the type of coal burned.
These aspects are discussed below.
Stoker Design
The small mechanical stokers in the range of interest are of
the underfeed type. The underfeed stoker with a worm-feed mechanism
is normally used to feed coal at rates up to 1200 Ib/hr. In contrast
to handfiring or spreader stokers, underfeed stokers supply fresh coal
IV- 415
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to the boiler or furnace by feeding it underneath the hot coals. This
stoker consists of a retort, fan, motor, transmission, air duct, air
duct control, hopper and feed screw. Figure 1 is an illustration of a
typical stoker assembly.
Motor and Transmission. The underfeed stoker is driven by an
electrical motor, usually mounted on top of the transmission. The motor
drives the transmission through V-belts. Various electrical devices
control the operation of the motor including room thermostat, boiler
limit switch, and the hold-fire timing relay. The transmission rotates
the coal-feed screw at a speed determined by the capacity of the heat-
ing system. Feed rates can be varied by changing the motor or trans-
mission pulleys.
Feed Screw. The feed screw conveys the coal from the hopper
to the retort, or with a bin-fed type, directly from the coal bin to
the retort. The feed screw extends from the coal supply (hopper or
bin) through the worm-tube into the retort, where it discharges the
coal it conveys.
Retort. The retort is a cast-iron chamber in the shape of a
cup or trough in which the coal is ignited and the volatile gases are
driven off. The retort is surrounded by a windbox and contains slotted
holes for admitting air under slight pressure to the fire. These slot-
ted holes, or air admitting ports, are often referred to as the tuyeres.
IV-416
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Because anthracite differs in combustion characteristics from
bituminous coals, a different retort design is required to burn this
coal successfully. The bituminous retort is built to burn a coal re-
latively high in volatile matter and to fuse ash into a removable
clinker; the anthracite stoker retort, on the other hand, is built to
burn coal of low volatile content and to spill ash into a pit or to the
receiver for the ash. Also because anthracite burns with a slow uni-
form flame, it requires less combustion space than bituminous coals.
Fan and Air Control. Fans for supplying combustion air in
the underfed stokers are usually squirrel-cage types that provide
relatively high pressures and low volumes. The fan is equipped with
either a manual or automatic damper to regulate air flow. The fan
develops sufficient static pressure to overcome a series of resistance
generated by flow through the fuel bed, tuyeres, air ducts and regu-
lating damper.
Stoker Operation
The residential and small commercial stoker-boiler operate
basically the same in principle although their operating cycles can be
different depending upon application. Characterization of the opera-
tion of these units is complicated because they seldom operate with a
steady-state heat-release rate.
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Off-On Cycle. Figure 2, a plot of CO levels as a function
of time, illustrates the nonsteady heat-release rate of stokers. Units
of this size operate in an off-on cycle, the time in each mode related
to the load. During the on-cycle, fresh coal is fed underneath the hot
coals and air is admitted through the tuyeres. The heat-released rate
increases substantially as the coal bed temperatures gradually increase,
but often not reaching a steady-state temperature before the thermostat
stops the stoker screw and fan. The heat-release rate is then reduced
drastically, but the bed continues to burn, being supplied by minimal
quantities of air by the natural draft. At this time unburned hydro-
carbons can be released because of insufficient air. Figure 3 shows a
typical plot of retort and stack temperatures during an overnight run
of a stoker on a 10-minute on and 50-minute off cycle.
Full-Load and Hold-Fire Operating Cycles. There are two ex-
tremes in stoker-boiler operation, namely, full-load and no-load.
During full-load operation, the stoker is running continuously; however,
the stoker is stopped for at least 5 minutes in every 30-minute cycle
so that bed temperatures cool and the ash fuses*. If not given an op-
portunity to cool, certain coals will remain fluid and sticky with re-
sulting nonuniform feeding and irregular burning of the large caked
masses.
* This off cycle can vary with ash content composition of the fuel.
Anthracite with a low ash content and high fusion temperature can
be burned continuously with no off period.
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During the no-load period, the boiler operates in a hold-fire
period of operation. Thus, the stoker is kept alive by short starts
to keep the fuel bed sufficiently alive to respond quickly when the
boiler load increases. The typical hold-fire period for bituminous
coal is approximately a 5-minute operation of the stoker in each 30-
minutes;* otherwise the fuel bed temperature will be too low to ignite
fuel that enters the retort during the on-period.
Partial load operation falls in between these extremes. The
stoker always feeds at a constant rate and adjusts to varying loads by
varying the on time in each cycle of operation.
Coal Classifications
Selection of stoker coals is of paramount importance in suc-
cessful stoker operation. Proper stoker adjustments for smokeless
operation are largely dependent on the coal analysis and coal size.
For instance, unsatisfactory stoker operations occur if
• a large percentage of fines restricts the amount
of air that reaches the fuel bed
• a high percentage of ash results in troublesome
clinker formation
• a low ash-fusion point coal creates clinkers that are
difficult to remove from the stoker as the ash may
melt and fuse or stick to the tuyeres.
* The hold-fire period for anthracite can be as low as one minute
every half hour.
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Accordingly, the most desirable coals for small stoker opera-
tion are relatively free-burning, low-volatile, and low-sulfur coals
that are sized 3/4 x 1/4. The free-burning coals include all coals
that neither cake nor coke.* These coals burn to a fine ash and do not
restrict air flow through the fuel bed. Low-volatile coals tend to
burn slowly with a uniform flame and as a consequence do not generate
appreciable levels of smoke over the entire stoker operating cycle.
Finally, sulfur oxide levels are related to the sulfur content of the
fuel, and thus, the low-sulfur coals are the most desirable.
Among coals that have been commonly marketed in the United
States for residential and small commercial stoker applications include
anthracite, bituminous and Western or sub-bituminous. In addition, a
smokeless coal has been commercially developed and has been used in
England, although not for mechanical stoker firing, A brief discussion
of these coals as related to stoker firing is given below.
Anthracite. Anthracite is a desirable coal for coal firing
because it is a free-burning, low-volatile, and low-sulfur coal.
Host anthracites have ash-fusion temperatures above 2700 F which per-
mits the ash to spill over the retort into a pit or into a conveyor
trough for ash removal. This property makes anthracite stokers adapt-
able to a continuous modulation mode of operation rather than an off-
on cycle. Being low in volatile content, it burns slowly and uniformly
* Caking coals emit tars and swell when heated; coking coals do not
swell when heated but emit tars.
IV-420
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with a compact flame allowing a smaller combustion chamber than bitumi-
nous coal. In addition, because anthracite is a hard coal, it does
not degrade (in size) during handling and shipping.
Bituminous. Bituminous has been a widely used coal for
stoker firing because it is found near population centers. There is a
wide range in the analysis of bituminous coals but it generally con-
tains 25 to 50 percent volatile matter, 7 to 15 percent ash, and 2 to
4 percent sulfur. This coal has been fired successfully in stokers
but requires precise air adjustments and routine maintenance.
Western Subbituminous. Western subbituminous coals have not
been widely used for stoker application; although in some local regions,
like Salt Lake City where it is readily available, significant quantities
have been burned for residential heating. In general, these coals
have high moisture (frequently as much as 50 percent), high ash (10
percent), and low ash fusion temperatures. Because Western subbitumi-
nous coals tend to degrade easily and have low heat content, their
market area has been restricted to regional usage. However, they do
have low sulfur content which makes them environmentally attractive.
Processed Smokeless Coal. The analysis of processed smokeless
coal indicates that its composition is ideally suited to stoker firing.
This coal, however, as manufactured would present problems in feeding
with conventional stokers; the coal is extremely hard and was produced
in sizes typical of the present day charcoal briquet.
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Smokeless Combustion
Smoke is a suspension of small solid particles in flue gases
discharged during the burning of fuel. The particles are of two types--
unburned residues of carbon formed by decomposed volatile material from
the fuel, and ash remaining after the fuel is burned.
Any fuel may be burned smokelessly at suitable temperatures
with enough oxygen, good mixing, and sufficient time to complete the
combustion. It is important to burn the volatile matter completely and
rapidly to avoid soot or carbon formation. Carbon smoke particles formed
by decomposition without oxygen are difficult to burn, and usually are
lost as smoke.
A high volatile coal may give off as much as 35 percent of
its weight as combustible vapors and gases when it is heated. Rapid
heating causes rapid evolution of volatiles which then requires a high
rate of air supply and rapid mixing to permit complete combustion.
Even with sufficient air and complete mixing, there are situations in
which the temperature is too low to ignite the combustible mixture.
In one such instance the coal may be added to a cool fuel bed where
there is no hot spot to ignite the tars and gases as they slowly dis-
till. In another, the vapors and air may be adequately mixed at a suf-
ficient temperature, but they may pass out of the combustion zone
IV-422
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and be quenched by the cool surfaces in the boiler and flue. Any of
these deficiencies result in carbon particles and condensed tar drop-
lets that appear as smoke. In summary, the requirements for smokeless
combustion are temperature for ignition, turbulence for mixing, and
time for completion of combustion reactions.
Any fuel with a volatile content of up to 25 percent by
weight will burn smokelessly when a few precautions are taken to pro-
vide the necessary temperature, turbulence, and time in the combustion
zone. This tendency for smokeless combustion follows from the lower
requirements for combustion air to burn the volatiles. Higher pro-
portions of air are available to burn the solid carbon in the fuel bed
(which produces a hotter bed) and less mixing and time are required
for complete combustion in the gas phase above the solid fuel bed.
POM Generation
The term POM, polycyclic organic matter, is used variously,
depending on the scope of the material compositions being considered.
Thus, chemically, the term POM includes all polycyclic compounds; hydro-
carbons, heterocyclic compounds, and chemical derivatives such as acids
and alcohols that can be derived from them. Among these are several
compounds of great concern because of their potential carcinogenicity.
IV-423
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Available data are not suffucient to provide an accurate
quantitative statement of POM emissions from residential and small
commercial stoker-fired units. However, the potential exists for sub-
stantial yields of POM because of the chemical composition of stoker
coal and the manner in which these stokers are typically operated,
particularly during the first phase of the "off" period.
Chemical Composition of Coal. Coal is composed of high-
molecular-weight compounds that are more difficult to burn out than in
the lower molecular hydrocarbons found in the fluid fuels. These higher
molecular weight compounds if only partially destroyed by the flame
provide a "building block" from which the large ring structure hydro-
carbon can be formed, some of which are carcinogenic.
Stoker Operation. It has been observed that POM are gener-
ated by pyrolysis in the preflame zone of a burner at above 550 C, and
the concentration of individual POM rise with increasing pyrolysis
temperatures up to a critical value of about 750 to 800 C. With further
increases in temperatures, the concentration falls again due to the
onset of the decomposition process. The POM formed by pyrolysis in
the preflame zone is destroyed as the vapors enter the hottest portion
of the flame and then gradually reformed in the falling temperature
portion. As described early, the off-on cycle of stoker operation with
low fuel-bed temperature gradually building up to a peak and then fall-
ing again appears conducive to POM generation.
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Stoker Survey
The findings from the survey of over twenty present or past
manufacturers (or their representatives) of residential and small com-
mercial stoker-fired space heating equipment include:
• Residential and small commercial stoker-boilers are
similar in design as systems components are scaled
(up or down) to match the desired range of operation.
The stokers are of the underfeed type.
• The conventional underfeed bituminous stokers are
capable of firing most coals except anthracite.
• The conventional underfeed anthracite stokers are
designed to fire anthracite only. There is a pos-
sibility that this stoker could fire "smokeless" or
processed coal if properly sized.
• There is only one manufacturer of the conventional
bituminous stoker in the size ranges of interest.
Domestic sales are about 500 units/year.
• There is only one manufacturer of the conventional
anthracite stoker. Sales are less than 20 units/year.
One additional manufacturer makes an anthracite stoker
that is an integral part of the boiler system.
IV-425
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• There are only three major manufacturers (H. B. Smith,
Kewanee, and Weil McLain) of boilers for stoker firing.
Of these, only Weil McLain currently manufactures a
boiler in the residential size range.
• There are over 200,000 living units heated by anthracite
coal. Most of these units are hand-fired.
• There has been renewed interest in stoker firing in the
size ranges of interest. The majority of activity has
been for small commercial applications rather than
residential.
t The majority of the new stoker-boiler systems are de-
signed for hot water, while most replacements are for
steam systems. There has been some renewed interest in
residential stoker-fired warm air furnaces.
IV-426
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EXPERIMENTAL PROGRAM
A 20-bhp stoker-boiler facility including provision for
stack sampling was installed. Initially, emissions will be measured
utilizing the bituminous stoker capable of firing high- and low-vola-
tile bituminous coal, a processed smokeless coal,* and a Western sub-
bituminous coal. Later in the program, an anthracite stoker will be
installed to fire the anthracite and possibly the processed smokeless
coal.
includes:
Experimental Facility
Figure 4 is a photograph of the overall system layout that
• Kewanee 3R-5 20-bhp (200 kw), fire-tube, hot-water boiler
• Will-Hurt 75 Ib/hr (34 kg/hr) bituminous stoker
• 14-inch (0.35 m) diameter stack section
• Sampling platform.
* The processed smokeless coal is a lignite char briquet with a corn-
flour binder.
IV-427
-------
A Van Wert 60 Ib/hr (27 kg/hr) anthracite stoker (not shown) can also
be mated to the boiler.
Approximately 10 pipe diameters above the boiler stack-gas
outlet, 4 sampling ports are installed. These ports are utilized to
sample over the discrete time periods of stoker-boiler operation.
Approximately 5 feet above the sampling ports a damper is installed
to provide a control of the draft at boiler outlet. Provision for
smoke and gaseous-emission sampling ports are provided at the base of
the stack in addition to several ports for temperature and pressure
measurements.
Fuel Analysis
Table 1 lists some properties of the coals that will be
fired during this program. The analysis are reported on an "as received"
basis and included the moisture content of the coals. This moisture
content, can vary randomly from day-to-day depending on climatic con-
dition, and is also dependent upon washing procedures used at the mine.
IV-428
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In general, however, the moisture content gives a measure of the inherent
moisture content of the coal. The free swelling index is a measure of
the caking properties of the coal as indicated by high values of the
caking bituminous coals. The processed smokeless fuel is a lignite
char briquette.
Characterization of Boiler Operation and POM Sampling
The operating cycle of a stoker-boiler creates a unique
problem in obtaining meaningful emissions data. As discussed earlier,
the stoker seldom operates at a steady-state condition. Transients
occur not only during the starting and stopping of the stoker but
throughout each "on" and "off" period of operation. In addition, and
most importantly, during the "off" period, the fuel bed continues to
burn as a sufficient amount of air is supplied by the natural draft of
the stoker-boiler system.
potential Experimental Runs
Initially, the stokers will be fired on several coals and at
several boiler loads to establish potential operating conditions for
the POM and particulate sampling. Listed below are 6 potential coal-
stoker combinations to be investigated. In addition, the boiler will
be operated at four loads for each of the coal-stoker combinations.
Possible boiler loads to consider for a 60-minute operating cycle include:
IV-430
-------
On
10 min
20 min
40 min
50 min
Continuous
Off
50 min
40 min
20 min
10 min
(Anthracite only)
Accordingly, there is a potential of 24 operating conditions of which
8 will be selected for POM and particulate measurements. In an investi-
gation of emissions from small commercial oil- and gas-fired furnaces
a load factor of 1/3 was used (10-minute on/20-minute off cycle). Ac-
cordingly for comparison purposes, the 20-minute on/40-minute off cycle
could be selected as the basic cycle to evaluate the emissions from
the firing of each coal.
Stack Probing
For the 8 conditions, the boiler stack will be probed to
generate transient temperature and velocity profiles. In addition,
for the bituminous-coal stoker combination, transient velocity and
temperature profiles will be generated for several boiler loads.
IV-431
-------
Hot wire anemometry will be used to characterize stack flow
as a function of time. Two probes will be used simultaneously. Probe
1 will be located approximately 2 feet (.6m) between the sampling port
and contain a hot wire sensor set stationary on the centerline to
monitor axial flow velocity with time. In addition, a thermocouple
will be attached to Probe 1 to monitor temperature with time. These
data will be used as a baseline measurement.
Probe 2, to be located at the sampling port, will contain a
traversing hot wire sensor used to determine the radial velocity pro-
file as a function of time. Initial traversing measurements will be
made to establish the importance of swirl and temperature with respect
to radial position. An existing traversing mechanism is currently being
modified to accommodate the needs of this specific task.
Also, a correlation will be established to relate measure-
ments of Probe 1 with Probe 2 so that meaningful undisrupted flow
monitoring can be conducted during sampling. All hot wire sensors are
quartz-coated hot film sensors, Model No. 1210-20 with an instantaneous
response time.
POM Sampling
The transient stack-probe data will be analyzed to relate
these profiles to stoker cycle operation. The transient stack-probe
, data will be integrated to determine an appropriate POM probe position
(within the stack) and pumping rate for the time segment under con-
sideration .
IV- 432
-------
Analysis of the POM samples will include, for example, the
( 2 )
three- and four-star compounds assessed by NAS as carcinogenic:
9,10 - Ditnethylbenz(a)anthracene
3 - Methyl chloanthrene
Benz(a)pyrene
Dibenz(a)anthracene
Benz(c)phenanthrene
Dibenz (c ,g)carbazole
Dibenz (a,i)pyrene
Dibenz(a,h)pyrene.
After analysis of these samples, data will be compiled into
a composite picture of transient POM emission and integrated to yield
the gross out-put levels. On-line gaseous and smoke emission data will
be taken during these evaluation runs to assure a degree of repeat-
ability in the experimental program. These data will also be compiled
and integrated to yield the transient and time-averaged emissions.
Analytical Procedures
Partlculate and POM sampling and analytical procedures (modi-
fied EPA Method 5 train with an adsorbent column) have been described
( 3 )
by Jones and Giammar . Gaseous emissions were determined by: para-
magnetic analysis for oxygen; flame ionization detection for unburned
hydrocarbons; nondispersive infrared for carbon monoxide, carbon
dioxide, and nitrogen oxide; and a dry electrochemical analyzer for
IV-433
-------
sulfur dioxide. Smoke emissions were determined with a Bacharach smoke
tester according to the ASTM filter-paper method for smoke measure-
ments .
REFERENCES
(1) Barrett, R. E., Miller, S. E., and Locklin, D. W., "Field
Investigation of Emissions from Combustion Equipment for Space
Heating", EPA-R2-73-0846 and API Publication 4180 (1973).
(2) "Polycylic Particulate Organic Matter", National Academy of
Sciences, Washington, D.C. (1972).
(3) Jones, P. W. , Giammar, R. D., Strup, P. E., and Stanford, T. B,,
"Efficient Collection of Polycyclic Organic Compounds from
Combustion Effluents", presented at the 68th Annual Meeting of
the Air Pollution Control Association, Paper No. 75-33.3,
Boston, June 15-20, 1975.
(4) Standard Method of Test for Smoke Density in the Flue Gases
from Distillate Fuels, ASTM Designation: D 2156-65
(Reapproved 1970).
IV-434
-------
FIGURE 1. CONVENTIONAL STOKER ASSEMBLY
(Side illustration showing
various parts:
1. Hopper
2. Electric motor
3. Transmission
4. Coal feed tube
5. Feed worm
6. Retort
7. Clean out opening
8. Retort air chamber. Fan is partially
hidden by the transmission and motor
IV-435
-------
CL
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CVJ
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6
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OT iJ
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Cti FH
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oi
IV-436
-------
Time
c
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55
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.
o
GO
c
6
Tl
lOmin
50m in
10 min
50min
10 min
JU
200
\
\
Retort temperature
Stack temperature
300
400 500
Temperature, F
600
700
FIGURE 3. TYPICAL PLOT OF RETORT AND STACK TEMPERATURES
DURING AN OVERNIGHT RUN OF A STOKER
IV-437
-------
FIGURE 4. STOKER-FIRED BOILER FACILITY
IV-438
-------
2: 20 p.m.
POM and Particulate Emissions
from Small Commercial Stoker-
Fired Boilers
Robert D. Giammar, Battelle, Columbus Laboratories
Yesterday you presented some data on POM in gas and
oil combustion systems and today in coal. Have you
done any detailed analysis on any of your samples
for distribution among the different species? Have
you seen any differences between the three types of
fuels?
Yes. We have. We are looking at 13 POM species.
Some of these as rated by the National Academy of
Science are ranked as 1-4 stars, where the 4 star
has the highest potential for cancer-forming hydro-
carbon. On the other question, the distribu-
tion of the POM species is different for coal in
comparison to oil or gas. For oil and gas, appreciable
quantities of pyrene and fluoranthene, both considered
innocuous, were observed while very little B(a)P and
other 3 and 4 star compounds were observed. With the
oil and gas, we see essentially four innocuous
species that comprise 99% of the total POM catch.
With coal we have seen a wider distribution. We
have identified 10 species, some of which are 3- and
4-star compounds contained in significant levels.
About the report you gave yesterday, and it is
probably appropriate here,would you comment about the
sampling technique that you used and how that
technique differs from the normal method five?
The sampling technique used is quite similar, if
you are familiar with the method 5. We insert
IV- 439
-------
what we call an absorbent sampling device or a column
packed with Tenax material in between the hot filter
and the impingers. We then can use the probe wash
and the filter catch to measure a total particulate;
and we use the probe wash, the filter catch, and
what is found in the packed column for our POM
determination. Earlier studies indicated most of
the POM was found in the packed column rather
than in method 5 components. Another co-worker
at Battelle and I presented a paper at APCA in
Boston in June, describing the technique.
IV- 440
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CONCLUDING REMARKS FOR
STATIONARY SOURCE COMBUSTION SYMPOSIUM
by
Joshua S. Bowen
Environmental Protection Agency
Combustion Research Branch
Industrial Environmental Research Laboratory-RTP
Research Triangle Park, N. C.
IV-441
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CONCLUDING REMARKS FOR
STATIONARY SOURCE COMBUSTION SYMPOSIUM
The Combustion Research Branch of EPA's Industrial Environmental
Research Laboratory, RTF has sponsored this symposium on stationary
source combustion as one of a series of similar meetings aimed at infor-
mation exchange or transfer.
Early emphasis of our Combustion Control Program was directed
to research and development of economical and efficient combustion modi-
fication techniques for controlling air polluting emissions of nitrogen
oxides, combustibles (e.g., carbon, carbon monoxide, unburned hydrocarbons),
smoke and particulate matter from major stationary combustion sources
burning a variety of conventional and alternate fuels. More recently with
the structuring of our Utility and Industrial Power Program, the emphasis,
although still strongly aimed at control of NO and combustibles, has been
expanded to encompass consideration of pollution from a multi-media view-
point and to look at a broader range of potential pollutants, including
hazardous pollutants, trace materials and others.
An earlier seminar in June 1973 was devoted entirely to coal combustion
discussions. During the intervening period significant technical
advances have been made on so many fronts that it appeared worthwhile to
cover our entire program in the present meeting. Consequently, an agenda
was arranged in which investigators on most of the research and development
projects comprising the NO Control portion of the overall program were
X
IV-442
-------
asked to present their up-to-date results. Since the meeting was intended
not only for the dissemination of technical information among the investiga-
tors involved in our program, but was also planned for the exchange of
ideas concerning the technical experience and related data of others,
many representatives of industry, Government and the academic community
were asked to attend.
The specific purpose of the meeting then has been to review and to
exchange information on the Combustion Research Branch's in-house and
contracted studies aimed toward the development of practical combustion
modification technology for the control of NO and other combustion-
generated pollutant emissions from major stationary combustion sources.
For purposes of presentation the papers were grouped into sessions
corresponding to the major subheadings of the NO Control program.
X
These categories were: fundamental research, fuels research and develop-
ment, process research and development, and field testing and surveys.
To recapitulate very quickly the symposium has included the following
subjects.
Discussions in the fundamental research area have covered the
study of the mechanisms and kinetics of the formation of NO during
X
methane-air combustion by Exxon Research and Engineering and the inves-
tigation of chemical reactions in the conversion of fuel nitrogen to
NO by Rocketdyne. The Jet Propulsion Laboratory has reported on the
IV-443
-------
role of flame interactions in pollutant formation. United Technology
Research Center has discussed the effect of the interactions between
fluid dynamics and chemistry in pollutant formation as well as two
dimensional combustor modeling. Aerotherm has reviewed their work on
prediction of the kinetics of premixed laminar flat flames and Stanford
Research Institute has reported on the estimation of rate constants. MIT
has described their research on the fate of fuel nitrogen during the pyrolysis
and oxidation of coal and on the formation of soot and polycyclic aromatic
hydrocarbons during combustion. The University of Arizona has reported on
investigations of the effect of fuel sulfur on NO emissions.
In the area of fuels R&D the Institute of Gas Technology has
reported on burner design criteria to control pollutant emissions from
natural gas flames, while Ultrasystems has discussed their investigations
to optimize burner design to reduce NO emissions from pulverized coal
and residual oil flames, along with their work to control emissions
from packaged boiler systems. Rocketdyne has reviewed their work on
an integrated low emission residential furnace system. Aerotherm has
discussed investigations they are initiating to study a pilot scale
combustion modification technique applicable to industrial and utility
boilers and also catalytic combustion concepts for residential and
industrial applications. EPA's in-house study on the assessment of the
combustion and emission characteristics of alcohols and other alternate
fuels has been summarized.
IV-444
-------
The process R&D work which involves studies with commercial or
prototype combustion systems to develop cost and design information for
the application of NO control technology to classical combustion systems
A
and which form the basis for future demonstrations were reported yester-
day. Combustion Engineering reported on their investigations of the
use of overfire air as a means of controlling NO in tangential coal-
fired utility boilers. TVA described their investigations of staged
combustion as a technique for controlling NO formation in wall coal-fired
utility boilers. Ultrasystems reviewed their study addressing pollutant
formation and furnace design in low Btu gas fired boilers. Battelle-
Columbus has discussed the effectiveness of fuel additives as a means
of reducing pollutant emissions.
The field testing and surveys are studies designed to determine
what can be achieved currently to control NO emissions with state-of-the-art
control technology. Among the papers in this area, Exxon has presented
their findings on the effect of combustion modifications on pollutant
emissions and on the performance of utility boilers. KVB, Inc. has reported
on the effect of combustion modification on pollutant emissions from
industrial boilers and on the use of Western coals in small and inter-
mediate size boilers. Aerospace Corporation has reviewed their analysis
of test data for utility boilers burning gas, oil and coal. EPA's
in-house assessment of the emission characteristics of small gas turbine
engines has been discussed. Battelle-Columbus has told us of the emissions
from small commercial stoker-fired coal-burning boilers;
IV-445
-------
and IGT has presented their survey findings on industrial process
heating combustion equipment data and emissions control.
The goal of all of these studies (even indirectly of the funda-
mental research is ultimately the development and assessment of economical
and efficient combustion modification techniques which will find practical
application for the control of NO and other combustion-generated
X
pollutants. Our real purpose is to effectively solve the problems of
pollution of the environment. To accomplish this we need data and in-
formation which will guide us to the development and application of
practical and effective control methods. Many of the results reported
here are quite informative and show that good progress is being made in
some areas toward abating NO and other pollutants without adversely
X
affecting the performance of the energy conversion systems in other
critical respects. On the other hand a number of the R&D efforts,
while obtaining answers to some of the questions and providing data for
some of the unknowns, are opening up new questions which will require
answers. In fact, we see that some of the data, at least on first
scrutiny, appear to be in conflict or saying different things. There
are many areas, I feel sure, where the information presented here will
indicate directions which will be carefully considered by us in planning
future work. I feel we are making good progress, both in the basic
research and modeling of the combusiton processes and pollutant reactions
and in the development and assessment of practical control techniques.
There has been great evidence of the interest on the part of the various
TV-446
-------
investigators and the participants as shown by the large number of ques-
tions and the enthusiasm of the follow-up discussions. I really believe
the main purpose of our meeting which was information exchange has to a
large degree been achieved. We must conclude however that much work
remains to be done and we need to move ahead vigorously with our R&D
activities in order to solve the many stationary combustion source
pollution problems which still remain.
We want to express our appreciation to the authors and especially
to the speakers for their efforts in preparing and presenting the highly
informative papers. Also, we want to thank the featured speakers and
participants in the panel discussions, including Adel Sarofin, Tom Tyson,
Stan Cuffe, Tom Helms, Bob Collon, T. T. Kason and Bob Rosenberg, for
their thought-provoking presentations. For all of the attendees, we
are particularly gratified that you were able to take the time to meet
with us and that you were responsive in participating in the discussion
periods. That is what really makes a meeting of this type successful.
We also would like to commend the staff of A. D. Little, particularly
Marjorie Maws and Anita Lord, and Mr. Robert Hall of the CRB staff who
was project officer and vice-chairman of the symposium, and all of the
others who have been instrumental in planning and arranging the details
of the program and facilities for the meeting. Special mention should
be made of the outstanding facilities and services provided by the
Fairmont Colony Square.
IV-447
-------
It is planned that the papers presented here and the related discus-
sions will be compiled and issued as proceedings of the symposium. This
EPA report, which will include a list of attendees, will be sent to
each of you. However, because of the effort involved in preparing the
documentation, you may not receive it until late November or December.
Additional copies will be available through the NTIS.
This meeting has provided an additional opportunity for participa-
tion by industry and other Government agencies in our program activities.
We shall welcome any further comments or recommendations you may have
regarding the technical activities as well as future meetings. With
regard to available technical information, our studies generate a large
number of reports and related documents. A listing of the Industrial
Environmental Research Laboratory reports is issued in a Report Abstracts
document which is published monthly and may be obtained by contacting
W. W. Whelan of IERL-RTP. Although future meetings have not yet been
planned, it is anticipated that we will continue our practice of holding
symposia as a means of exchanging technical information at appropriate
times in the future. In order to help us improve our meetings and make
them more responsive to all our needs, I would like to remind you of
the Meeting Rating Form which was placed in your program schedule. Would
you please take the few minutes needed, perhaps on your trip home, to
fill out responses to the various questions and send the form to us.
In this way perhaps we can uncover suggestions which will improve the
quality of future meetings.
IV-448
-------
Again, let me thank each of you for coming here and taking part in
this meeting. I hope it has proved for each of you to be a worthwhile
experience. I wish you a safe and pleasant journey home and on that
note we shall consider the meeting adjourned.
IV-449
-------
IV-450
-------
SPEAKERS LIST
(NOTE: To facilitate their identification, speakers are listed alphabetically
together with the name of the organization they represent. The complete address
of each organization represented at the conference appears at the end of the list
of attendees.)
LIST OF SPEAKERS
Matne
Axworthy, Dr. Arthur E.
Mttner, James D.
Bowen, Dr. Joshua A.
Bowman, Dr. Craig T.
trown, Richard A.
Eurchard, Dr. John 1C.
Cato, Glenn A.
Collom, Jr., Robert H.
Combs, L. Paul
Crawford, Allen R.
Cuffe, Stanley T.
Dykeraa, Owen W.
England, Dr. Christopher
Erigleman, Dr. Victor S.
Giammar, Robert P.
Hsll, Robert E.
Heap, Dr. Michael P.
Helms, G. Thomas
Hollinden, Dr. Gerald A.
Kason, T.T.
Kendall, Dr. Robert M
Keisselring, Dr. John P.
Ker.els, Peter
Lachapelle, David G.
Lanier, W. Steven
Mclonald, Henry
Maloney, Dr. Kenneth L.
Manny, Erwin H.
Martin, G. Blair
Muzio, Dr. Lawrence J.
Poh.l, John H.
Poszon, H. Wallace
Princiotta, Frank
Rosenberg, Dr. Robert B.
Sarofim, Dr. Adel F.
Selk.er, Ambrose P.
Shav, Dr. Robert
Shoffstall, Dr. Donald R.
Tyson, Dr. Thomas J.
Wasser, John H.
Wends, Dr. Jost O.L.
Representing
Rockwell International, Rocketdyne Division
Massachusetts Institute of Technology
EPA, IERL, Combustion Research Branch
United Technology Research Center
Acurex, Aerotherm Division
EPA, IERL
KVB, Inc.
State of Georgia, Department of Natural Resources
Rockwell International, Rocketdyne Division
Exxon Research and Engineering
EPA, Office of Air Quality Planning and Standards
The Aerospace Corporation
Jet Propulsion Laboratory
Exxon Research and Engineering
Battelle-Columbus Laboratories
EPA, IERL, Combustion Research Branch
Ultrasystems
EPA, Region IV, Air and Hazardous Materials Division|
Tennessee Valley Authority
City of Chicago, Department of Environmental Control|
Acurex, Aerotherm Division
Acurex, Aerotherm Division
Institute of Gas Technology
EPA, IERL, Combustion Research Branch
EPA, IERL, Combustion Research Branch
United Technology Research Center
KVB, Inc.
Exxon Research and Engineering
EPA, IERL, Combustion Research Branch
KVB, Inc.
Massachusetts Institute of Technology
City of Chicago, Department of Environmental Control|
EPA, Energy Processes Division
Institute of Gas Technology
Massachusetts Institute of Technology
Combustion Engineering
Stanford Research Institute
Institute of Gas Technology
Ultrasystems
EPA, IERL, Combustion Research Branch
University of Arizona
A-l
-------
PARTICIPANTS LIST
(NOTE: To facilitate their identification, participants are listed alphabetically
together with the name of the organization they represent. The complete address
of each organization represented at the conference appears at the end of the list
of attendees.)
LIST OF PARTICIPANTS
Name
Alvey, Courtney D.
Anderson, Dr. Larry W.
Axtman, William H.
Bagwell, Fred A.
Baker, Burke
Ban, Stephen D.
Barrett, Richard E.
Barsln, Joseph
Bartok, William
Batra, Sushil K.
Bauman, Robert D.
Beals, Rixford A.
Beatty, James D.
Bennett, Dr. Robert
Blandford, Jr., J.B.
Blythe, R. Allen
Buechler, Lester
Bonne, Ulrich
Booth, Michael R.
Bowman, Barry R.
Bueters, K.A.
Carpenter, Ronald C.
Cernansfcy, Dr. Nicholas P.
Christiano, John P.
Chu, Richard R.
Clark, Norman D.
Cleverdon, R.F.
Cotton, Ernest
Creekmore, Andrew T.
Daughtridge, Jimmy T.
Degler, Gerald H.
Demetri, E.P.
DeWerth, D.W.
Dingo, T.T.
)onaldson, Thomas M.
Dowling, Daniel J.
)owney, Thomas A.
Dyer, T. Michael
Dygert, J.C.
Representing
Baltimore Gas & Electric
Acurex, Aerotherm Division
American Boiler Manufacturers Association
South California Edison
Shell Development Company
Battelle-Columbus Laboratories
Battelle-Columbus Laboratories
Babcock & Wilcox
Exxon Research & Engineering
New England Electric Systems
EPA, Office of Air Quality, Planning & Standards
NOFI
Procter & Gamble
Apollo Chemical
Englehard Industries
International Boiler Works
Systems Research Labs
Honeywell
Ontario Hydro
Lawrence Livermore Laboratories
Combustion Engineering
Armstrong Cork
Drexel University
EPA, Office of Air Quality, Planning & Standards
EBASCO
C-E Air Preheater
Chevron Research Company
American Petroleum Institute
EPA, Control Programs Development Division
Pratt & Whitney Aircraft
Systems Research Labs
Northern Research and Engineering Corporation
American Gas Association Labs
General Motors
EPA, Office of Air Quality, Planning & Standards
Union Carbide
Gamlen Chemical Company
Sandia Laboratories
Shell Development Company
A-2
-------
LIST OF PARTICIPANTS (CONT'D)
Name
Dzuna, Eugene R.
Erskine, George
Feng, C.L.
Fennelly, Paul F.
Fletcher, James
Fletcher, Roy J.
Freelain, Kenneth
Frisch, Dr. N.W.
Fuhrman, Jr., Theodore
Gibbs, Thomas
Goetz, Gary
Soodley, Allan R.
Graham, David J.
Greene, Jack H.
Grimshaw, Vincent C.
Gr o s sman, Ralph
Eangebrauck, Robert P.
Heck, Ronald
Hensel, Thomas E.
Halden, Edward A.
Honea, Dr. Franklin I.
Howard, Jack B.
Hudson, Jr., James L.
Jsickson, Dr. A.W.
Jepson, Dr. A.F.
Karas, Dennis T.
Kemmerer, Jeffrey
Khan, M. Ali
KhDO, Dr. S.W.
Kloecker, J.F.
Kykendal, William
Lahre, Thomas
Large, Dr. Howard
Lavoie, Raymond C.
Lee, James E.
Lenney, Ronald J.
Levy, Arthur
Lewis, F. Michael
Lii. Dr. C.C.
Lin, Donald J.L.
Locklin, David W.
Lord, Harry C.
Loweth, Carl
Marshall, David
Marshall, John H.
Representing
Gulf Research & Development Company
Mitre Corporation
Selas Corporation of America
GCA/Technology Division
Industrial Combustion
Peabody Engineering Corporation
Federal Energy Administration
Research-Cottrell
Erie City Energy Division
EPA, Region IV
Combustion Engineering
California Air Resources Board
EPA, Office of Research and Development
EPA, Administrative Office
Process Combustion
Ralph Grossman, Ltd.
EPA, Energy Assessment and Control Division
Englehard Industries
Turbo Power and Marine Systems
General Foods Corporation
Midwest Research Institute
Massachusetts Institute of Technology
Tampa Electric Company
Ontario Hydro
Environmental Measurements, Inc.
East Chicago Air Quality Control
Fuller Company
East Chicago Air Quality Control
Canadian Gas Research Institute
Erie City Energy Division
EPA, Process Measurement Branch
EPA, Office of Air Quality, Planning & Standards
Babcock & Wilcox
Rohm & Haas Company
Facilities Engineering Command (U.S. Navy)
Ronald J. Lenney Associates
Battelle-Columbus Laboratories
Stanford Research Institute
EPA, Combustion Research Branch
Forney Engineering Company
Battelle-Columbus Laboratories
Environmental Data Corporation
The Trane Company
Babcock & Wilcox
Combustion Engineering
A-3
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LIST OF PARTICIPANTS (CONT'D)
Name
Marton, Miklos B.
Mayfield, D. Randell
Meier, John G.
Moore, Douglas S.
Moore, Edward E.
Morton, William J.
Moscowitz, Charles
Mosier, Stanley A.
Newton, Charles L.
Nurick, W.H.
Pantzer, Karl
Pershing, David W.
Pertel, Dr. Richard
Renner, Ted
Riley, Joseph
Robert, J.
Roberts, Dr. George
Robertson, J.F.
Roffe, Gerald
Rosen, Meyer
Ross, Marvin
Rulseh, Roy
Sadowski, R.S.
Samples, J.R.
Scott, Donald R.
Sheffield, E.W.
Slack, A.V,
Smith, Lowell L.
Spadaccini, L.J.
Sterman, Sam
Sullivan, Robert E.
Swearingen, W.E.
Takacs, Dr. L.
Taylor, Barry R.
Utterback, Paul M.
Van Grouw, Sam J.
Vatsky, Joel
Vershaw, Jim
Watson, Raymond A.
Webb, R.
Weiland, J.H.
Weinberger, Dr. Lawrence
White, David J.
White, James H.
White, Phil
Representing
IBM
EPA, Region IV
International Harvester, Solar Division
Chevron Research Company
Eclipse, Inc.
E. Keeler Company
Monsanto Research Corporation
Pratt & Whitney
Colt Industries
Rockwell International, Rocketdyne Division
Babcock & Wilcox
University of Arizona
Institute of Gas Technology
Fuel Merchants Association of New Jersey
EPA, Region IV
Canadian Department of Environment
Englehard Industries
Crystal Petroleum Company
General Applied Science Laboratories
Union Carbide
Lawrence Livermore Laboratory
Cleaver-Brooks
Riley Stoker Corporation
Union Carbide
Columbia Gas System Service Corporation
TRW
SAS Corporation
KVB, Inc.
United Technology Research Center
Union Carbide
General Motors
Koppers Company
General Motors
Massachusetts Institute of Technology
Babcock & Wilcox
KVB, Inc.
Foster-Wheeler Energy Corporation
The Trane Company
Florida Power & Light Company
The Trane Company
Texaco, Inc.
Mitre Corporation
International Harvester, Solar Division
Coen Company
Ventura Company
_
A-4
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Name
Wiedersum, George C.
Wilhelm, Ronald
Wilson, Jr., P..P.
Winters, Harry K.
Wittig, Dr. Sigmar L.K.
Woolfolk, Dr. Robert
Wright, Richard
Young, Dexter E.
Ziarkowski, Stanley
Zielke, Robert L.
Zirkel, Eric C.
LIST OF PARTICIPANTS (CONT'D)
Representing
Philadelphia Electric Company
Aqua-Chem, Inc.
Arthur D. Little, Inc.
Ray Burner Company
Purdue University
Stanford Research Institute
Industrial Combustion
EPA, Control Programs Development Division
Garnien Chemical Company
Tennessee Valley Authority
Armstrong Cork
A-5
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LIST OF ORGANIZATIONS REPRESENTED
Name (Represented By)
Acurex Corporation, Aerotherm Division
(Mr. Anderson)
American Boiler Manufacturers Association
(Mr. Axtman)
American Gas Association Labs
(Mr. De Werth)
American Petroleum Institute
(Mr. Cotton)
Apollo Chemical
(Dr. Bennett)
Aqua-Chem, Inc.
(Mr. Wilhelm)
Armstrong Cork Company
(Mr. Carpenter, Mr. Zirkel)
Babcock & Wilcox
(Mr. Bartin, Mr. Lange, Mr. Moore)
(Mr. Utterback, Mr. Pantzer,
Mr. Marshall)
Baltimore Gas and Electric Company
(Mr. Alvey)
Battelle-Columbus Labs
(Mr. Ban, Mr. Barrett,
Mr. Levy, Mr. Locklin)
C-E Air Preheater
(Mr. Clark)
California Air Resources Board
(Mr. Goodley)
Canadian Department of Environment
(Mr. Robert)
Canadian Gas Research Institute
(Dr. Khoo)
Chevron Research Company
(Mr. Cleverdon, Mr. D. Moore)
Address
485 Clyde Avenue
Mountain View, California 94042
1500 Wilson Boulevard, Suite 317
Arlington, Virginia 22209
8501 East Pleasant Valley Road
Cleveland, Ohio 44131
1801 K Street, N.W.
Washington, D.C. 20006
35 South Jefferson Road
Whippany, New Jersey 07981
P.O. Box 421
Milwaukee, Wisconsin 53201
Liberty & Charlotte Streets
Lancaster, Pennsylvania 17604
20 South Van Buren Avenue
Barberton, Ohio 44203
P.O. Box 2423
North Canton, Ohio 44720
2012 Gas and Electric Building
Baltimore, Maryland 21203
505 King Avenue
Columbus, Ohio 43201
Andover Road
Wellsville, New York 14895
1709 llth Street
Sacramento, California 95814
351 St. Joseph Boulevard
Houll, Quebec, Canada
55 Scarsdale Road, Don Mills
Ontario, M3B2R3, Canada
P.O. Box 1627
Richmond, California 94802
A-6
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LIST OF ORGANIZATIONS (CONT'D)
Name (Represented By)
Cleaver-Brooks
(Mr. Rulseh)
Coen Company
(Mr. J.H. White)
Colt Industries
(Mr. Newton)
Columbia Gas System Service Corporation
(Mr. Scott)
Combustion Engineering
(Mr. Bueters, Mr. Goetz, Mr. Marshall)
Crystal Petroleum Company
(Mr. Robertson)
Drexel University
(Dr. Cernansky)
EBASCO
(Mr. Chu)
East Chicago Air Quality Control
(Mr. Karas, Mr. Khan)
Eclipse, Inc.
(Mr. E. Moore)
Englehard Industries
(Mr. Blandford, Dr. Heck, Dr. Roberts)
Environmental Data Corporation
(Mr. Lord)
Environmental Measurements, Inc.
(Dr. Jepsen)
Environmental Protection Agency
EPA - Administrative Office
(Mr. Greene)
Address
3707 North Richards Street
Milwaukee, Wisconsin 53201
1510 Rollins Road
Burlingame, California 9401C
701 Lawton Avenue
Beloit, Wisconsin 53511
1600 Dublin Road
Columbus, Ohio 43215
1000 Prospect Hill Road
Windsor, Connecticut 06095
P.O. Box 4180
Corpus Christi, Texas 78408
Philadelphia
Pennsylvania 19104
145 Technology Park
Norcross, Georgia 30071
900 East Chicago Avenue
East Chicago, Indiana 45312
1100 Buchanan
Rockford, Illinois 61101
Middlesex Turnpike, Wood AvenJ
Edison, New Jersey 08876
608 Fig Avenue
Monrovia, California 91016
2 Lincoln Court
Annapolis, Maryland 21401
Research Triangle Park
North Carolina 27711
A-7
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LIST OF ORGANIZATIONS (CONT'D)
flame (Represented By)
EPA - Combustion Research Branch
(Dr. Bowen, Mr. Hall, Mr. Lachapelle,
Mr. Lanier, Dr. Lii, Mr. Martin, Mr. Wasser)
SPA - Control Programs Development Division
(Mr. Creekmore, Mr. Young)
EPA - Energy Assessment & Control Division
(Mr. Hangebrauck)
EPA - Office of Air Quality, Planning,
and Standards
(Mr. Bauman, Mr. Christiano,
Mr. Donaldson, Mr. Lahre)
EPA - Office of Research and Development
(Mr. Graham)
EPA - Process Measurement Branch
(Mr. Kuykendal)
EPA - Region IV
(Mr. Biggs, Mr. Mayfield, Mr. Riley)
Erie City Energy Division
(Mr. Fuhrman, Mr. Kloecher)
Exxon Research & Engineering Company
(Mr. Bartok)
Federal Energy Administration
(Mr. Freelain)
Florida Power & Light Company
(Mr. Watson)
Forney Engineering Company
(Mr. Lin)
Foster Wheeler Energy Corporation
(Mr. Vatsky)
Fuel Merchants Association of New Jersey
(Mr. Renner)
Address
Research Triangle Park
North Carolina 27711
Research Triangle Park
North Carolina 27711
Research Triangle Park
North Carolina 27711
Research Triangle Park
North Carolina 27711
Washington, D.C. 20460
Research Triangle Park
North Carolina 27711
1421 Peachtree Street, N.E.
Atlanta, Georgia 30309
1422 East Avenue
Erie, Pennsylvania 16502
P.O. Box 8
Linden, New Jersey 07036
1200 Pennsylvania Avenue, N.W.
Washington, D.C. 20461
P.O. Box 013100
Miami, Florida 33101
P.O. Box 189
Addison, Texas 75001
10 South Orange Avenue
Livingston, New Jersey 07039
66 Morris Avenue
Springfield, New Jersey 07081
A-8
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LIST OF ORGANIZATIONS (CONT'D)
Name (Represented By)
Fvller Company
(Mr. K.fi'juerer)
GC A/Technology Division
(Dr. Fennelly)
Gainlen Chemical Company
(Nr. Downey, Mr. Ziarkowski)
Ger.eral Applied Science Laboratories
(Mr. Roffe)
Genera? Foods - Technical Center
(Mr. Holden)
General Motors Corporation
(Mr. Sullivan)
(Mr. Dingo, Mr. Takacs)
Gulf Research and Development Company
(Mr. Dzuna)
, Inc.
(Mr . Bonne)
IBM
(Mr. Marton)
Industrial Combustion
(Mr. Wright, Mr. Fletcher)
Instiuute ot G:?s Technology
(Dr. Pertel)
International Boiler Works
(Mr. Ely the)
International Harvester, Solar Division
(Mr. Meier, Mr. D.G. White)
124 Bridge Street
Catasauqua, Pennsylvania 18032
Burlington Road
Bedford, Massachusetts 01730
299 Market Street
Saddle Brook, New Jersey 07662
Merrick & Stewart Avenues
Westbury, New York 11790
250 North Street
White Plains, New York 10625
5735 West 25th Street
Indianapolis, Indiana 46224
Technical Center
Warren, Michigan 48090
P.O. Box 2038
Pittsburgh, Pennsylvania 15230
Bloomington
Minnesota 55420
1000 Westchester Avenue
White Plains, New York 10604
4465 North Oakland
Milwaukee, Wisconsin 53211
3424 South State Street
Chicago, Illinois 60616
P.O. Box 498
East Stroudsburg, Pennsylvania 18301
2200 Pacific Highway
San Diego, California 92119
A-9
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LIST OF ORGANIZATIONS (CONT'D)
I Name (Represented By)
Engineering, Inc.
(Mr. L. Smith, Mr. Van Grouw)
|E. Keeler Company
(Mr. Morton)
|Koppers Company, Inc.
(Mr . Swearingen)
| Ronald J. Lenney Associates
(Mr . Lenney)
(Arthur D. Little, Inc.
(Mr. R.D. Wilson)
I Lawrence Livermore Laboratories
(Mr. Bowman, Mr. Ross)
(Massachusetts Institute of Technology
(Mr. Howard, Mr. Taylor)
[Midwest Research Institute
(Dr . Honea)
[Mitre Corporation
(Dr. Weinberger, Mr. Erskine)
Monsanto Research Corporation
(Mr. Moscowitz)
NOFI
(Mr. Seals)
Naval Facilities Engineering Command,
Southern Division
(Mr. J. Lee)
New England Electric Systems
(Mr. Batra)
Northern Research & Engineering Corporation
(Mr. Demetri)
Address
6624 Hornwood Drive
Houston, Texas 77036
Williamsport
Pennsylvania 17701
Koppers Building
Pittsburgh, Pennsylvania 15219
2001 Palmer Avenue
Larchmont, New York 10538
Acorn Park
Cambridge, Massachusetts 02140
P.O. Box 808
Livermore, California 94550
Massachusetts Avenue
Cambridge, Massachusetts 02139
425 Volker Boulevard
Kansas City, Missouri 64110
Westgate Research Park
1820 Dolly Madison Boulevard
McLean, Virginia 22101
Station B. Box 8
Dayton, Ohio 45407
New York, New York
2144 Melbourne Street
P.O. Box 10068
Charleston, South Carolina 29411
20 Turnpike Road
Weston, Massachusetts 01581
219 Vassar Street
Cambridge, Massachusetts 02139
A-10
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LIST OF ORGANIZATIONS (CONT'D)
Name (Represented By)
Ontario Hydro Corporation
(Mr. Booth, Dr. Jackson)
Peabody Engineering Corporation
(Mr. R. Fletcher)
Philadelphia Electric Company
(Mr. Wiedersom)
Pratt & Whitney Aircraft
(Mr. Daughtridge, Mr. Mosier)
Process Combustion Corporation
(Mr. Grimshaw)
Procter & Gamble Company
(Mr. Beatty)
Purdue University
(Mr. Wittig)
Ralph Grossman, Ltd.
(Mr. Grossman)
Ray Burner Company
(Mr. Winters)
Research-Cottrell, Inc.
(Dr. Frisch)
Riley Stoker Corporation
(Mr. Saclowski)
Rockwell International Corporation,
Roc-tetdyne Division
(Mr. Nurick)
Rohm & Haas Company
(Mr. Lavoie)
SAS Corporation
(Ar. Slack)
Address
620 Union Avenue
Toronto, Ontario, Canada M561X6
835 Hope Street
Stamford, Connecticut 06907
2301 Market Street, S10-1
Philadelphia, Pennsylvania 19101
P.O. Box 2691
West Palm Beach, Florida 33402
1675 Washington Road
Pittsburgh, Pennsylvania 15228
610 South Center Hill Road
Cincinnati, Ohio 45224
West Lafayette
Indiana 47907
P.O. Box 70, Town of Mt. Royal
Montreal, Canada H3P 3B8
1301 San Jose Avenue
San Francisco, California 94112
P.O. Box 750
Boundbrook, New Jersey 08805
9 Neponset Street
Worcester, Massachusetts 01613
6633 Canoga Avenue
Canoga Park, California 91304
P.O. Box 584
Bristol, Pennsylvania 19007
RFD #1
Sheffield, Alabama 35660
A-ll
-------
LIST OF ORGANIZATIONS (CONT'D)
Name (Represented By)
Sandia Laboratories
(Mr. Dyer)
Selas Corporation of America
(Mr. Feng)
Shell Development Company
(Mr. Dygert, Mr. Baker)
South California Edison
(Mr. Bagwell)
Stanford Research Institute
(Dr. Woolfolk, Mr. Lewis)
Systems Research Labs
(Mr. Buechler, Mr. Degler)
TRW, Inc.
(Mr. Sheffield)
Tampa Electric Company
(Mr. Hudson)
Tennessee Valley Authority
(Mr. Zielke)
Texaco, Inc.
(Mr. Weiland)
The Trane Company
(Mr. Loweth, Mr. Vershaw, Mr. Webb)
Turbo Power and Marine Systems
(Mr. Hensel)
Union Carbide Corporation
(Mr. Rosen, Mr. Sterman)
(Mr. Dowling)
Address
Livermore
California 94550
Dresher
Pennsylvania 19025
P.O. Box 481
Houston, Texas 77001
P.O. Box 800
Rosemead, California 91770
1611 North Kent Street
Arlington, Virginia 22209
2800 Indian Ripple Road
Dayton, Ohio 45440
1 Space Park - R4/2020
Redondo Beach, California 90278
P.O. Box 111
Tampa, Florida 33601
524 Power Building
Chattanooga, Tennessee 37401
P.O. Box 509
Beacon, New York 12508
3600 Pammel Creek Road
La Crosse, Wisconsin 54601
1690 New Britain Avenue
Farmington, Connecticut 06032
Tarrytown Technical Center
Tarrytown, New York 10591
Box 180
Sistersville, West Virginia 26175
A-12
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LIST OF ORGANIZATIONS (CONT'D)
Hame (Represented By)
Union Carbide Corporation
(M:r. Samples)
United Technologies Research Center
(Mr. Spadacclni)
University of Arizona
(Mr. Pershing)
Ventura County A.P.C.D.
(Mr. P. White)
Address
Box 4361
South Charleston, West Virginia 25353
400 Main Street
East Hartford, Connecticut 06040
Tucson
Arizona 85721
740 East Main Street
Ventura, California 93001
A-13
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TECHNICAL REPORT DATA
(Pirate rrad InOsuciions On the rei'crtc before completing)
1. REPORT NO.
EPA-600/2-76-152c
2.
3. RECIPIENT'S ACCESSION*NO.
4. T.TLE AND SUBTITLE proceedings o{ the stationary Source
Combustion Symposium; Volume HI—Field Testing
and Surveys
5. REPORT DATE
June 1976
6. PERFORMING ORGANIZATION CODE
7. AUTMOR(S)
Miscellaneous
B. PERFORMING ORGANIZATION REPORT NO
9. PERFORMING OR9ANIZATION NAME AND ADDRESS
NA
10. PROGRAM ELEMENT NO.
1AB014; ROAP 21BCC
11: CONTRACT/GRANT NO.
NA (In-house)
2. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Proceedings: 9/24-26/75
14. SPONSORING AGENCY CODE
EPA-ORD
5.SUPPLEMENTARYNOTEsSymposium Chairman J.S. Bowen, Vice-Chair man R.E. Hall,
Mail Drop 65, Ext. 2470/2477.
s. ABSTRACT
proceedings document the 37 presentations made during the Stationary
Source Combustion Symposium held in Atlanta, Ga. , September 24-26, 1975. Spon-
sored by the Combustion Research Branch of EPA's Industrial Environmental Resea-
rch Laboratory- -RTP, the symposium dealt with subjects related both to developing
improved combustion technology for the reduction of air pollutant emissions from
stationary sources , and to improving equipment efficiency. The symposium was
divided into four parts and the proceedings were issued in three volumes: Volume I —
Fundamental Research, Volume U--Fuels and Process Research and Development,
and Volume m--Field Testing and Surveys. The symposium was intended to provide
contractor, industrial, and Government representatives with the latest information
on EPA in-house and contract combustion research projects related to pollution
control, with emphasis on reducing nitrogen oxides.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTlFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution, Combustion, Field Tests
ombustion Control, Coal, Oils
Natural Gas, Nitrogen Oxides, Carbon
arbon Monoxide, Hydrocarbons, Boilers
Pulverized Fuels, Fossil Fuels, Utilities
Gas Turbines, Efficiency
Air Pollution Control
Stationary Sources
Combustion Modification
Unburned Hydrocarbons
Fundamental Research
Fuel Nitrogen
Burner Tests
13B 21B 14B
2 ID 11H
07B
07C 13A
13G 14A
8. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport}
Unclassified
21. NO. OF PAGES
474
2O. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 222O-\ (9-73)
A-14
•U.S. GOVERNMENT PRINTING OFFKS: 1976-641-317/SS12 Region He. 4
-------
I HP 6QO/2 ;;?A
|76-152c Industrial ICnv Rr.s Lab
AUTHOR
Proceedings of the stationary
T'TLEsourr.e combust, ior. symDosium
_V . 3: b'icld testing :•. surveys
OATE DiJE
BORROWERS NAME
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DATE DUE i
BORHOWtH'S NAME
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r
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DATE DUE
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