U.S. Environmental Protection Agency Industrial Environmental Research EPA-600/7-77-073*
Office of Research and Development Laboratory *»ww tf vi*tw
Research Triangle Park, North Carolina 27/11 JUiy 1977
PROCEEDINGS OF THE SECOND
STATIONARY SOURCE
COMBUSTION SYMPOSIUM
Volume V. Addendum
Interagency
Energy-Environment
Research and Development
Program Report
EP 600/7
77-073C
-S.
X viu;--.;^
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S.
Environmental Protection Agency, have been grouped into seven series.
These'seven broad categories were established to facilitate further
development and application of environmental technology. Elimination
of traditional grouping was consciously planned to foster technology
transfer and a maximum interface in related fields. The seven series
are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and •Development
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from -
the effort funded under the 17-agehcy Federal Energy/Environment
Research and Development Program. These studies relate to EPA's
mission to protect the public health and welfare from adverse effects
of pollutants associated with energy systems. The goal of the Program
.is to assure the rapid development of domestic energy supplies in an
environmentally—compatible manner by providing the necessary
environmental data and control technology. Investigations include
analyses of the transport of energy-related pollutants and their health
and ecological effects; assessments of, and development of, control
technologies for energy systems; and integrated assessments of a wide
range of energy-related environmental issues.
REVIEW NOTICE
This report has been reviewed by the participating Federal
Agencies, and approved for publication. Approval does not
signify that the contents necessarily reflect the views and
policies of the Government, nor does mention of trade names
or commercial products constitute endorsement or recommen-
dation for use.
This document is available to the public through the National Technical
Information Service, Springfield, Virginia 22161.
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EPA-600/7-77-073e
July 1977
PROCEEDINGS OF THE SECOND
STATIONARY SOURCE
COMBUSTION SYMPOSIUM
Volume V. Addendum
o
to
Symposium Chairman Joshua S. Bowen
Vice-Chairman Robert E. Hall
Environmental Protection Agency
Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, North Carolina 27711
Program Element No. EHE624
A~P
•U.S. EiWJLlv.:: ..... .iALF
EDTS.OH, K.J.. PJSI7
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D.C. 20460
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mmm^^^
PREFACE
These proceedings document the more than 50 presentations and discus-
sions of the Second Symposium on Stationary Source Combustion held August
29 — September 1, 1977 at the Marriott Hotel in New Orleans, Louisiana.
Sponsored by the Combustion Research Branch of the EPA's Industrial
Environmental Research Laboratory-Research Triangle Park, the symposium
presented the results of recent research in the areas of combustion
processes, fuel properties, burner and furnace design, combustion
modification, and emission control technology.
Dr. Joshua S. Bowen, Chief, Combustion Research Branch, was Symposium
Chairman; Robert E. Hall, Combustion Research Branch, was Symposium Vice-
Chairman and Project Officer. The Welcoming Address was delivered by Dr.
John K. Burchard, Director of IERL-RTP; the Opening Address was delivered by
Robert P. Hangebrauck, Director, Energy Assessment and Control Division,
IERL-RTP; and Dr. Howard B. Mason, Program Manager NOX Environmental
Assessment Program, Acurex Corporation, delivered the Keynote Paper.
The symposium consisted of six sessions:
Session I:
Session II:
Session III:
Session IV:
Session V:
Session VI:
Small Industrial, Commercial and Residential Systems
Robert E. Hall, Session Chairman
Utility and Large Industrial Boilers
David 6. Lachapelle, Session Chairman
Special Topics
David G. Lachapelle, Session Chairman
Stationary Engine and Industrial Process Combustion
Systems
John H. Wasser, Session Chairman
Advanced Processes
G. Blair Martin, Session Chairman
Fundamental Combustion Research
W. Steven Lanier, Session Chairman
Volume V, Addendum, presents the Welcoming Address delivered by Dr.
John K. Burchard, abstracts of the guest panelists, and those papers not
recieved in time for the initial printing of the first three volumes.
Appendix A gives a list of all attendees present at the Second Symposium on
Stationary Source Combustion.
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TABLE OF CONTENTS
Page
Welcoming Remarks: J. K. Burchard 1
- SESSION I: SMALL INDUSTRIAL, COMMERCIAL, AND RESIDENTIAL SYSTEMS -
"Effects of Fuel and Atomization on NOx Control for Heavy Liquid
Fuel-Fired Package Boilers," J. E. Cichanowicz, M. H. Lobell,
M. P. Heap, D. W. Pershing 7
"N0x Control Techniques for Package Boilers: Comparison of Burner
Design, Fuel Modification and Combustion Modification," J. E.
Cichanowicz, C. McComis, M. P. Heap 31
- SESSION II: UTILITY AND LARGE INDUSTRIAL BOILERS -
"Design and Scale-Up of Low Emission Burners for Industrial and
Utility Boilers," R. Gershman, M. P. Heap, T. J. Tyson 65
"Statistical Considerations Important in Analyzing Measured Changes
in Water-Wall Tube Thickness," J. W. Tukey 79
- SESSION III: SPECIAL TOPICS -
Panel: Combustion Source/Air Pollution Regulations -- Present and
Projected 95
"Federal Regulations," 0- R. Farmer 97
"Existing Stationary Combustion Source Air Pollution Regulations,"
R. L. Duprey 107
ill
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TABLE OF CONTENTS (Concluded)
- SESSION IV: STATIONARY ENGINE AND INDUSTRIAL PROCESS COMBUSTION SYSTEMS -
"Emission Characteristics of Small Stationary Diesel Engines,"
J. H. Wasser, R. M. Statnick 119
- SESSION V: ADVANCED PROCESSES -
"Evaluation of Combustor Design Concepts for Advanced Energy Con-
version Systems," B. A. Folsom, T. L. Corley, M. H. Lobell, C. J.
Kau, M. P. Heap, T. J. Tyson 145
Panel: Emerging Combustion Technologies 183
"Fluidized Bed Combustion," J. M. Connell 185
"Coal-Oil Mixture Combustion Technology," C. B. Foster
"Advanced Combined Cycles," F. L. Robson
"Advanced Combustion Systems for Stationary Gas Turbines,"
S. A. Mosier 203
- APPENDIX A -
List of Attendees A-l
iv
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WELCOMING REMARKS
By:
Dr. J. K. Burchard
Director, Industrial Environmental Research Laboratory - RTF
Environmental Protection Agency
Research Triangle Park, North Carolina 27711
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Welcome to New Orleans. Some of you probably wonder —why New Orleans
in August? That's a good question, one that I have asked too! Well, it's
almost September and besides, you've got to admit, it's better than Chicago
in January. Actually, we hope you will prefer to attend the meeting during
the day and not wander outside until night when it's a little cooler.
As you know, this is the Second Symposium on Stationary Source Combustion.
The first was held in Atlanta in September 1975. We hope to have the third
one in the Spring of 1979.
Those of you who attended the last symposium will notice that the program
has expanded. This is a 4 day meeting with about 50 speakers, compared to a 3 day
meeting with about 35 speakers in Atlanta. This growth is due to the expanded
interest in controlling pollution from combustion sources.
There are two major reasons for expanding the program. One is an awareness
by EPA that to control combustion emissions for mobile sources would not be enough.
Because of future growth and difficulties associated with reducing automobile
emissions below certain levels, it will be necessary to tighten control of station-
ary combustion source emissions. The second reason relates to our country's need
for energy independence. This means we will be burning coal in the future. There-
fore, EPA must help determine how this can be done in an environmentally acceptable
manner.
I won't dwell on the program since you will be provided with details over
the next 4 days. However, I will touch on the highlights. The Combustion Research
Branch is part of the Industrial Environmental Research Laboratory - RTP. For
those of you who aren't familiar with our organization I'll describe it briefly.
I'll begin with IERL-RTP since Prank Princiotta will probably outline the
structure of EPA's Office of Research and Development, of which we are a part,
during his luncheon talk on Wednesday. He will also probably describe the
Office of Energy, Minerals, and Industry, of which we are also a part.
Within IERL-RTP, there are three divisions and the Office of Program Operations.
OPO, headed by Dr. John Smith, includes the Special Studies Staff and the Planning,
Management and Administration Staff. One of the three divisions is the Utilities
and Industrial rower Division, headed by Bill Plyler. Under it there are three
branches: the Process Technology Branch, Emissions/Effluent Technology Branch, and
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Particulate Technology Branch. The second Division is the Industrial Processes
Division, headed by Chic Craig. It includes the Chemical Processes Branch,
Metallurgical Processes Branch, and Process Measurements Branch. The third
division is the Energy Assessment and Control Division, headed by Bob Hangebrauck,
who will deliver the meeting's Opening Address. His division includes the
Fuel Process Branch, Advanced Process Branch, and the Combustion Research Branch.
It is the work of the last-mentioned branch that you are here to find out about
in more detail.
The Combustion Research Branch is headed by Dr. Josh Bowen and consists of
six engineers, four engineering technicians, and a secretary. Most of their work
is contracted to private industry; however, there is also a small, but important
in-house program. You will hear about both during the symposium.
I encourage you to read the pamphlet entitled "Controlling Pollution Through
Combustion Research" which provides more detail about CRB's program. You should
have received a copy with your registration package.
The main purpose of this meeting is to provide the public with results of
recent combustion research sponsored by CRB, and to promote the exchange of ideas
among the members of the combustion community. The agenda includes many of the
nation's experts in the area of combustion research.
This morning's schedule includes the already mentioned Opening Address by
Bob Hangebrauck of IERL and a Keynote Paper by Howard Mason of Aerotherm. This
afternoon's session will cover small industrial, commercial, and residential
combustion systems. The program for the remainder of the week includes: utility
and large industrial boilers; a session on special topics, which didn't logically
fall under any of the other sessions; a session on stationary engine and industrial
process combustion systems; a session on advanced combustion processes; and a
session on fundamental combustion research.
In order to provide comprehensive coverage, we have invited several guest
speakers who have no direct connection with CRB's program. These include repre-
sentatives from organizations such as the Electric Power Research Institute (to
describe EPRI's NO control program), representatives of the Energy Research
X
and Development Administration (part of the newly created Department of Energy)
and representatives of private industry (who will discuss emerging combustion
technologies), and representatives of EPA's Region V and the Office of Air Quality
Planning and Standards (to discuss federal regulations). Dick Stern, Chief of the
3
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Process Technology Branch of IERL, will review the status of flue gas treatment
for NO and SO control, and a representative of TRW will describe the "Emissions
X in> '
Assessment of Conventional Combustion Systems" which is being sponsored by IBRD's
Chemical Processes Branch. A highlight of the meeting will be Wednesday's
luncheon speaker, Mr. Frank Princiotta, who is Director of the Energy Processes
Division of EPA's Office of Energy, Minerals and Industry.
The schedule has been arranged to include time for Questions and Answers
dealing with the individual papers and for a General Discussion at the end of
each session. Please feel free to ask questions or comment on our program.
Preprints of most symposium papers were provided with your registration
packages. If time permits, you can look through papers of interest ahead
of time. This will give you a chance to formulate questions before you hear
the presentation.
I hope that you will enjoy the meeting and that this will be a worthwhile
and productive 4 days.
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SESSION I:
SMALL INDUSTRIAL, COMMERCIAL AND RESIDENTIAL SYSTEMS
ROBERT E. HALL
CHAIRMAN
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EFFECTS OF FUEL AND ATOMIZATION ON NOX CONTROL FOR
HEAVY LIQUID FUEL-FIRED PACKAGE BOILERS
By:
J. E. Cichanowicz, M. H. Lobell, and M. P. Heap
Energy and Environmental Research Corporation
Santa Ana, California 92705
and
D. W. Pershing
University of Arizona
Ttiscon, Arizona 85721
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SECTION 1
SCOPE OF THE RESEARCH PROGRAM
Uncontrolled emissions from stationary fossil fuel-fired boilers are
normally ranked coal-fired > oil-fired > natural gas-fired and this is
reflected by the New Source Performance Standards for this class of equip-
ment. However, if the same fuels were to be ranked either with regard to
ease of control or to demonstrated successful application of a control
technique, oil would rank below the other two fuels. Natural gas-fired com-
bustors produce thermal NO and it is well-known that depression of flame
temperature limits NO formation. Consequently, there are many successful
examples showing the successful utilization of flue gas reclrculation for
the control of NO emissions from all types of natural gas-fired combustors.
X
Coal contains significant quantities of bound nitrogen, and it is now
recognized that under uncontrolled conditions the majority of the NO emis-
X
sion from pulverized coal-fired equipment can be attributed to fuel NO
formation.
combustion modification techniques with coal firing.
NO reductions of the order of 65 percent can be claimed for
X
Residual fuels also contain bound nitrogen, normally less than coal,
but combined flue gas recirculation and combustion modifications cannot claim
consistent reductions greater than 70 percent. Staged combustion, the most
effective method of controlling fuel NO production, requires the formation of
a fuel-rich primary stage which encourages the formation of carbonaceous
participate which may not be completely burned out in the second stage with
the consequent Increase in participate emissions. In many investigations
involving staged combustion the maximum reduction in NO emissions is dictated
X
by an Increase in particulate emission. The formation of both of these
pollutants are strongly linked to the details of the combustion process and
the properties of the fuel. The program described in this paper has been
planned to establish the effect of fuel properties and fuel atotnization
8
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parameters on NO control techniques for package boilers fired with heavy
X
liquid fuels.
The temperature-time-environment history of fuel and combustion products
determines the fate of fuel-bound nitrogen, the rate of fixation of molecular
nitrogen and the rate of destruction of nitric oxide by fuel fragments. In
liquid fuel flames this history is controlled by the interaction of the liquid
spray and the flow field which is composed of combustion air and recirculat-
ing combustion products. Liquid spray properties of importance are:
dropsize distribution,
droplet trajectory;
droplet momentum, mid
spray pattern.
The characteristics of a wide range of commercial and specially designed
atomizers will be tested under well-defined flow field conditions to assess
the influence of the various parameters listed above on NO formation.
The nitrogen content of residual fuels is recognized as having a pro-
found influence upon NO production. However, two other fuel oil properties
will also have a strong effect on the final emission level, these are:
fuel oil viscosity since this will control spray characteristics;
and
nitrogen evolution rate since this will establish when nitrogen
compounds will enter the gas phase.
The total program can be divided into three distinct but interrelated
investigations:
• Combustor experiments to assess atomizer and fuel effects.
• Spray characterization under cold and hot flow.
* Small-scale experiments to be conducted under controlled conditions
to evaluate those parameters controlling fuel nitrogen formation
in liquid fuel flames.
Spray characterization nnd the small-scale experiments will be carried out to
explain and generalize the observations made in the combustor experiments.
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The overall objective of the total program is to define atotnization parameters
which lead to satisfactory combustor operation, but minimize pollutant emis-
sions. At the time of writing, results of these various studies were not
available and the following discussion will be restricted to a description of
the proposed effort and the rationale leading to the definition of the experi-
mental program.
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SECTION 2
COMBUSTOR EXPERIMENTS
Several studies have shown thnt fuel oil properties, particularly
nitrogen content, and atomizer design influence the emission of pollutants
from oil-fired combustors. The objective of the combustor experiments is
to systematically compare atomizer performance for selected air flow condi-
tions with & broad range of fuels. The fuel screening and atomizer per-
formance Investigations will be carried out in two combustors whose charac-
teristic dimensions are typical of watertube and firetube package boilers.
One important factor in the design of burners for oil firing is the compati-
bility of the air pattern and the liquid fuel spray distribution. The com-
bustor experiments will be carried out with a burner capable of providing
precisely repeatable conditions at the throat. All the atomizers selected
for screening will be tested with at least two air distributions which are
known to have different effects upon the fuel/air mixing pattern.
ATOMIZER DESIGN AND POLLUTANT FORMATION
The basic principle of disintegration of a liquid into a spray requires
that there be a continual change in the form of the liquid such that the total
surface area is increased until the liquid volume becomes unstable and disinte-
gration occurs. This instability is generated by an initial forcing function
causing extreme acceleration of portions of the liquid. The droplet size
distribution of the resulting stream depends upon the nature of flow in the
atomizer, the physical properties of the liquid, the state of the ambient
atmosphere, and the source and manner in which energy is imparted to the
liquid to provide the forcing function. It is convenient to classify
atomizers according to the source of energy used for the atomization process
and the majority of atomizers fall into liquid prssure, centrifugal or assist-
fluid energy categories. Several example of liquid pressure and assist-fluid
n
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atomizers will be tested as part of this program, together with atomizers
which fall outside these categories.
Atomizers may also be classified by the general type of spray pattern
they produce.
• Full core sprays; the whole conical volume of the spray is filled
with droplets.
• Hollow core spray; the droplets are concentrated on the outer
periphery of the conical volume and the core is relatively free
of droplets.
• Flat or fan sprays; the droplets are distributed along a narrow
wedge-shaped band.
The hollow core spray is used for most combustion applications; however,
several full core sprays will be used in this Investigation to assess the
effects of spray distribution.
Cato et al ( 1 ) reported the influence of various atomizer designs on
boiler efficiency, particulate emissions and NO emissions from a series of
^\.
field operating boilers. No systematic Influence of the type of the assist-
fluid could be ascertained, probably because any effect of the atomizer was
masked by the variations in other parameters. In one series of investiga-
tions with staged combustion the use of steam as the assist-fluid produced
lower emission levels than those obtained with air. The effect of atomizer
properties under staged combustion conditions are Illustrated by the results
presented in Figure 1. The same assist-fluid atomizer was used with a staged
burner, the second stage air was Injected from the periphery of a short
primary combustion chamber. The fuel oil contained 0.71 percent nitrogen and
there is strong evidence that with this particular system better results were
obtained with steam as the atomizing fluid.
Oil spray properties can be varied by using the same nozzle design but
different capacities and operating at a constant oil throughput (and there-
fore different delivery pressures). Figure 2 presents NO emissions as a
A
function of swirl level of the combustion air for three different nozzle
capacities. It can be seen that at low swirl levels there is a very signifi-
cant effect of fuel pressure which might be associated with either droplet
12
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size distribution or droplet penetration or a combination of these
effects.
The results presented in Figure 3 show the influence of both atomizer
design and fuel oil throughput on particulate emissions from a refinery
furnace. Particulate emissions are greatest with pressure jet atomization
with a high fuel pressure and lowest with an L-type steam atomizer.
Characteristic droplet size distributions for the same nozzles are presented
in Figure 4 showing that there is not a simple relationship between droplet
size distribution and particulate emission. Fuel/air mixing will also
influence particulate formation. It can be suggested that droplet distri-
butions which have steep maxima will tend to concentrate the fuel at a given
point. Efficient fuel/air mixing can be achieved by having a relatively
flat droplet distribution curve and relying upon their different trajectories
to distribute the fuel in the air stream.
Both of the examples of the effect of nozzle parameters on pollutant
formation presented in Figures 2 and 3 illustrate the strong coupling of fuel
spray-flow field interaction in liquid fuel oil flames.
FUEL OIL PROPERTIES AND POLLUTANT FORMATION
Fuel oil properties will influence pollutant emissions for three major
reasons; these are:
1. Bound nitrogen content — It is well-known that NO emissions Increase
with increasing fuel nitrogen content; however, the fraction of the
bound nitrogen converted to NO decreases with increasing nitrogen
content.
2. Asphaltene content — Certain workers (4 ) have reported a linear
relationship between fuel oil asphaltene content and particulate
emissions. This might well be an oversimplification resulting
from the use of fuel from the same crude source and it is unlikely
to be n universal relationship. Munroe and Watson (5 ) report a
poor correlation of particulate emissions with asphaltene content.
3. Oil viscosity —• Fuel oil viscosity will affect the fuel spray
which will affect the fuel/air mixing process which could be
reflected in a change in pollutant formation.
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Figure 5 which is similar to Figure 2 shows the effect of fuel oil
temperature on NO emissions as a function of swirl level. The results
presented in Figure 6 were obtained by Jackson and Cunningham ( 6) in a fuel
oil-fired test rig show that as the fuel temperature is decreased and the
viscosity increases, partlculate emissions increase and NO and SO, emissions
decrease. Changes in fuel oil temperature will vary the spray characteris-
tics because as the temperature changes both the viscosity and delivery pres-
sure must change for a constant oil flow. Droplet temperature may also affect
fuel vaporization rates which will affect the overall heat release profile.
There have been many examples of the effect of total fuel oil nitrogen
content on NO formation in liquid fuel-fired combustors. Although the esti-
mated fuel nitrogen conversions have similar characteristics for the various
investigations there is considerable scatter about any mean line. This
scatter may be associated with the details of the combustion system or it
may be attributable to properties other than total fuel nitrogen content
which control fuel NO production. These properties may be associated with
the source of the crude, details of the refinery process or the consequence
of blending with lighter fuels to produce a low sulfur fuel. During the con-
duct of this program we intent to test, under controlled conditions, a series
of residual fuels representative of crudes used throughout the country. Each
fuel will be tested with several atomizers and at various delivery temperatures,
14
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SECTION 3
SPRAY CHARACTERIZATION
The Interpretation of the results obtained In the combustor Investigation
will require some characterization of the sprays produced by the various
atomizers and the effect of the flow field on the spray distribution. The
atomizers used In the corabuntor experiments will be placed in a cold flow test
rig and supplied with liquid of the same viscosity as the fuel oil. The cold
flow testa will be carried out in a chamber with the nozzles fitted in a
burner throat Identical to the ones used in the combustor investigations.
Therefore, the properties of the spray will be determined under conditions
similar to those encountered under combustion conditions. The flow field will
be modified somewhat because of the different density field.
Two methods will be used to assess spray characteristics:
• Droplet size distribution will be measured by a laser diagnostic
technique developed by Swithenbank et al ( 7). The technique is
based on the Fraunhofer diffraction of a parallel beam of mono-
chromatic light by the moving droplets. A Fourier transform lens
is used to focus a stationary light pattern onto a multi-element
photo detector to measure the diffracted light energy distribu-
tion. This light energy distribution is translated into the
corresponding unique droplet size distribution and the droplets
are classified into 31 size groups spanning two decades of dia-
meter. The accuracy of the method is estimated to be approxi-
mately 2 percent of the characteristic diameter.
• Physical sampling wUl, under Isokinetic conditions, be used to
provide the general liquid mass distribution as a function of
distance from the nozzle.
15
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A limited number of measurements will be attempted under combusting
conditions to approximately evaluate the spray path to compare with the cold
flow measurements. The spray characterization tasks will be carried out at
the IFRF Research Station in Holland.
16
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SECTION 4
SMALL-SCALE EXPERIMENTS
NO emissions measured in the cotnbustor investigations will be the sum
of both fuel and thermal NO and consequently, the results will be difficult
to interpret. A series of small-scale experiments are planned to establish
those parameters which control fuel nitrogen conversion in fuel oil flames.
Three techniques can be employed in an attempt to establish the relative
contributions of fuel and thermal NO formation to the total emission, these
are:
• Addition of cooled combustion products to the combustion air
supply. This will reduce flame temperatures and minimize thermal
NO production. However, it will not positively eliminate thermal
NO production and the increased mass of oxidant plus diluent will
probably influence the fuel/air mixing process which could change
the fraction of fuel nitrogen converted to NO.
• Subtraction of NO produced by a non-nitrogen-containing fuel.
This method has the advantage of being relatively easy to set up,
but the properties of the non-nitrogen liquid fuel will very dif-
ferent from the residual fuel, and it is most unlikely that the
thermal NO production will be Identical for the two liquid fuels.
• Substitution of molecular nitrogen in the air by argon to eliminate
thermal NO production. With this method It is certain that all
the NO emitted results From the oxidation of fuel-bound nitrogen.
The majcir uncertainties In uhe assessment of fuel NO are associated
with temperature effects and any chemical effects due to
the almost complete lack of molecular nitrogen. The former diffi-
culty can be overcome by diluting the argon with C0« to provide
the same thooretJcu.l flame temperature as would be obtained with
air.
17
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The latter approach has been chosen since it is believed that the use of
argon/CCL diluent mixtures will give the most accurate assessment of the
parameters controlling fuel NO formation. The tests will be carried out
at subscale because of the prohibitive cost of argon substitution in either
of the package boiler simulators.
The overall purpose of the subscale testing is to provide information
which will improve our basic understanding of the processes associated with
the formation of fuel and thermal NO in oil-fired systems. This informa-
tion will enable the results from investigations with the package boiler
simulators to be generalized. To achieve this basic goal we believe that
two types of experimental studies will be required (see Table I).
• Phase I — NO Formation in Swirling, Turbulent Diffusion Flames
X
The overall goal of this first phase is to define the importance
of fuel nitrogen conversion to NO in residual oil flames. Use of
typical combustion hardware and direct simulation of actual practice
will be emphasized. (This is in contrast to Phase II in which the
emphasis is placed upon creating specific, ideal types of combus-
tion environments). In general, the approach in Phase I is to
conduct a relatively large number of experimental tests with air as
the oxldizer and then, based on detailed consideration of the
results, select specific conditions for testing with Ar/O-XCO,.
The work is divided Into two Tasks:
—• Spray Characteristics, and
— Fuel Chemistry.
The purpose of Task 1.1, Spray Characteristics, is to define the
influence of drop size and spray pattern on the formation of fuel
and thermal NO. Since these parameters are generally coupled,
several types of tests will be conducted. These results, together
with the spray characterization data, should allow the influence of
the controlling parameters to be ascertained. Current plans are to
Include four types of mechanical atomizers (hollow and solid cone,
wide and narrow angle) an air-assisted sonic nozzle (the same
nozzle type will be used in three sizes of combustor) and a special
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design of twin fluid nozzle. The viscosity at the nozzle will be
altered by varying the oil preheat temperature. Atomization pres-
sure will be studied in conjunction with nozzle size at a constant
fuel input rate. Most of the spray characteristics studies will
be carried out with two fuels of widely different characteristics.
The purpose of Task 1.2, Fuel Chemistry, is to establish the influ-
ence of the oil composition on the formation of fuel and thermal
NO.
At least three composition parameters (in addition to total nitrogen
content) are of potential importance:
— Hydrocarbon distribution as it influences the physical
properties of the oil, e.g., viscosity.
— Relative location of the nitrogen and hydrocarbon com-
ponents on the distillation curve.
— Amount and type of fuel sulfur present.
Several residual oils, a distillate oil, kerosine, pure hydrocarbons,
and various sulfur and nitrogen compounds will be used in this phase
of the investigation. The effect of the addition of both a light
and a heavy aliphatic primary amine to a pure compound fuel will be
studied to define the importance of relative volatilaties. Mixed
nitrogen additives will also be considered to establish whether the
presence of early formed NO inhibits the oxidation of refractory
nitrogen specie.
Current plans are to use a single atomizer for most of the chemistry
studies. Limited testing under alternate atomization conditions will
be conducted to demonstrate the generality of the conclusions. As
part: of this test Ing we will also examine the effects of overall
combust ton p/iramut:crs (wnlt temperature/heat loss, local gas tempera-
ture, .-UK! c.omhuHf ton mirodynamirs) but detailed consideration of
p«r;»mcl.crs will bu left until Phase II.
19
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* Phase II — ControlledMixing History Studies
The overall goal of the second phase is to define those conditions
which produce the minimum NO emissions. In this phase the focus
X
is less on simulating current practice and more on conducting com-
pletely controlled experiments. Detailed studies would be con-
ducted on the influence of:
— initial droplet heating rate,
— rate of oxidant addition,
use of aecondary fuel injection, and
~ temperature history.
These small-scale studies will be carried out in a refractory down-fired
furnace capable of firing at 100,000 Btu/hr. The furnace is constructed
from three modular sections with a central 8-inch diameter test chamber.
Wall temperature control is provided by four auxiliary heating chambers fired
by four propane burners. A schematic of the furnace system is presented in
Figure 7. The fuel and oxidant delivery system will allow preheated air or
argon C0? mixtures to be delivered to the burner which can fire oil diluted
with either or both of two dopants to vary the nitrogen and sulfur content
of the fuel.
20
-------
SECTION 5
CONCLUSION
A program has been planned which will allow the systematic investigation
of the effect of atomizer design and fiiel oil properties on the formation of
NO in package boiler combustion chambers. The total program is divided into
2t
three sections:
Combustor_Investigations — Tests will be carried out with a cross section
of available fuel oil atomizers and well-defined burner flow fields to
establish the influence atomizer design on pollutant formation. The
investigations will be carried out with various fuels in combustors
whose configurations are typical of package boilers.
Spray Ch_aract_erigation — Atomizers used in the combustor investigations
will be characterized under cold and hot flow conditions to assess
dropslze distribution on the effect of air flow on droplet penetration.
Small-Scale Experiments — A special purpose furnace is being constructed
to Investigate the factors affecting fuel NO formation.
The overall goal of this program is to specify atomizer design parameters for
use in low NO combustors i
x
with remote air injection.
use in low NO combustors using distributed air addition or staged heat release
X
21
-------
REFERENCES
I. Cato, G.A., Muzio, L.J. and Shore, P,E,, "Field Testing: Application
of Combustion Modification to Control Pollutant Emissions from Indus-
trial Boilers, Phase II", EPA Report No. 600/l-76-086a, April 1976.
2. Clr.hanowicz, J.E. and Heap, M.P., "Design Criteria for Low NO , High
Efficiency 011-Fired Firetube Package Boilers", Report in preparation,
EPA Contract 68-02-1500.
3. Van Breugal, J.W., Hasenack, H.J.A., Spink, C.D., "Soot and Solid
Emissions from Oil-Fired Heater with Swirling Air Burners", paper pre-
sented at the 4th Joint Meeting of the Gas and Oil Panel, September 1976,
IJmuiden, Holland.
4. Cheetham, H.A. and Champion, J.B., "Development of Large Burners for
Power Station Boilers, Paper 110, Deuxleme Symposium Europeen sur la
Combustion, Orleans, France, lst-5th Sept., 1975.
5. Munro, A.J.E. and Watson, C.D., "The Interaction of Fuel Oil Quality
and Equipment Performance on Emissions from Industrial Oil-Fired Steam/
Hot Water Boilers", paper presented at the 4th Joint Meeting of the
Gas and Oil Panel, September 1976, IJmuiden, Holland.
6. Jackson, P.J. and Cunningham, A.T.S., "The Combustion of Residual Fuel
Oil", paper presented at the 4th Joint Meeting of the Gas and Oil Panel,
September 1976, "IJmuiden, Holland.
7. Swithenbank, J., Beer, J.M., Taylor, D.S., Abbot, D. and McCreath, G.C.,
"A Laser Diagnostic Technique for the Measurement of Droplet and Particle
Size Distribution", paper presented at the AIAA 14th Aerospace Sciences
Meeting, Washington, D.C., January 1976.
22
-------
TABLE I. OUTLINE OF RESEARCH PLAN FOR SMALL-SCALE STUDIES
Phase I — NO Formation in Swirling, Turbulent Diffusion Flames
Jt
1.1 Spray Characteristics
— viscosity/oil temperature
— atomization pressure
— atomizer type
1.2 Fuel Chemistry
— 10 residual oils
-- distillate oil, vaporizing oil
— pure compound fuels
— nitrogen doping
— sulfur doping
Phase II — Controlled Mixing History Sutdies
— oxidant addition pattern
— fuel addition pattern
— initial heating rate
— time/temperature history
23
-------
400-
300-
8
200 •
100
Air Atomized
Steam Atomized
17% Excess Air;
Nitrogen concent of
fuel oil 0.71%;
All smoke numbers
less than No. 2 Bacharach
0.30 0.40
FRACTION OF TOTAL AIR SUPPLIED TO STAGING SYSTEM
0.50
Figure 1. The effect of atomization fluid on staged combustor
performance (2)
24
-------
600 •
o
K
O
500
400
350
Nozzle Capacity gph
O 60
D 80
A 100
10 >20 30
SWIRL NOZZLE ROTATION, DEGREES
Figure 2. The Influence of nozzle size on NO formation
' at constant oil throughout (2) (steam assist
atomizer, 3 x 10* Btu/hr Input, 17% excess
air). '. -
25
-------
0.8-
0.6-
w
0.4-
(A
a
M
i-l
0.2
200
Pressure Atomized
v (30 atmosperes)
\
\
\
\
x— Steam T Jet
s
\
\ \ \
Pressure Atomized \ *v \
(10 atmospheres) \ x^
\
\
\
\
\
Steam Atomized L-Type
400 600
FUEL LOAD, kg/hr
800
1000
Figure 3. Solid emissions from a refinery heater as a
function of fuel load (3)
26
-------
Pressure Jet
30 Atmospheres
Steam Y Jet
v. Pressure Jet
vlO Atmospheres
\ \ Steam Atomized\
100
300
DROPLET DIAMETER, y
Figure A. Dropsize distribution for the atomizers
used in Figure 3 (3).
27
-------
600 H
s
PM
500 4
400
10° 20" 30*
SWIRL NOZZLE ROTATION
40V
Figure 5. The effect of fuel oil temperature on
emissions (2).
28
-------
400
300
200
100
o
o
o
CM
CO
60
0.2-
0.15-
0.1
0.05
Oil Flowrate gs
11.3
11,0
10.7
10 15
KINETIC VISCOSITYjcSt
25
-20
15
10
w
o
H
20
Figure 6. The effect of firing rate and oil viscosity on pollutant
formation (6).
29
-------
cr\
\
0
o
0
o
0 O
/
r
\
-Burner Section
Viewing Port
Insulating Block
Insulating
Refractory
High Temperature
Refractory'
'Auxiliary Propane Burner
Flue
Figure 7. Argon Furnace.
30
-------
NOX CONTROL TECHNIQUES FOR PACKAGE BOILERS:
COMPARISON OF BURNER DESIGN, FUEL MODIFICATION AND
COMBUSTION MODIFICATION
By:
J. E. Cichanowicz, C. McComis, and M. P. Heap
Energy and Environmental Research Corporation
Santa Ana, California 92705
31
-------
SECTION 1
INTRODUCTION
An arbitrary but useful method of categorizing boilers is to assign a
nominal firing rate range to particular uses. Industrial boilers are nor-
mally considered to be those boilers with a design firing rate between 10 x
10 and 500 x 10 Btu/hr. In the upper end of the size range they are
virtually indistinguishable from utility boilers. At the opposite end of
the size range their characteristics are the same as commercial boilers.
Commercial boilers can be considered to be represented by those boilers with
a design firing rate of between 0.33 x 10 and 10 x 10 Btu/hr. Boilers
represent significant sources of three atmospheric pollutants; nitrogen
oxides (NO ), sulfur oxides (SO ) and particulates. This paper is primarily
X X
concerned with a review of those techniques available to control the emission
of one pollutant, NO , from Industrial and commercial boilers.
X
It has been estimated (1) that boilers account for greater than 60 per-
cent of the NO emitted annually by stationary sources in the U.S. Recently
A
Barrett and Putnam (2) have estimated the number of boilers in use in the
Continental United States as a function of design firing rate. Making allow-
ance for the fact that no single data source was complete, National Emissions
Data Bank (NEDS) and American Boiler Manufacturers Association data were used
together with EPA emission factors to estimate t,he annual cumulative NO
A
emissions for all boilers based upon their actual use. Figure 1 shows the
fraction of the total NO emissions attributable to boilers as a function of
x
boiler design firing rate and fuel capability. Commercial and industrial
boilers apparently account for about 50 percent of the emissions and oil
firing is the most significant producer of NO for these boilers, although
the importance of coal Increases as the boiler size increases. The data
presented in Figure 1, which is based upon information presented by Barrett
and Putnam (2), suggests that the contribution of industrial boilers to the
32
-------
total emission of nitrogen oxides is more significant than had been
indicated by other studies. Mason and Shlmizu (3) indicate that emissions
from commercial and residential, industrial and utility boilers are in the
ratio of 1:2.4:6.6, whereas Figure 1 indicates a ratio of 1:3:3. These
differences most probably reflect uncertainties in the estimates of load
factors used to derive the total emissions. Seemingly, total NO emissions
X
from industrial boilers are comparable to those from utility boilers, yet
the potential to control NO emissions from industrial boilers has not been
X
investigated as exhaustively as it has for utility boilers. This can be
readily explained by the much smaller number of sources which account for
the utility emissions making control more feasible. However, as emissions
from utility boilers are reduced by the application of control techniques,
uncontrolled emissions from industrial boilers will become more significant
and economical means should be sought to control NO emissions from this
X
class of equipment.
The industrial boiler population comprises several different design
types and includes the utilization of the complete range of fossil fuels.
They are normally classified by their design type (watertube or firetube)
and their size, which is normally described in boiler horsepower, steam
generated per hour or hourly heat output (one boiler horsepower is approxi-
mately equal to 33.5 Ibs of steam per hour or 33,500 Btu/hr heat output).
In the small boiler sizes (25M Btu/hr) gas is the dominant fuel and firetube
boilers are the dominant design type. As the name implies, the major charac-
teristic of this design is that the products of combustion pass through tubes
surrounded either by water or steam. As the firing rate increases the
dominance of gas decreases and the boilers are predominantly of the watertube
type. In this type of construction water flows through tubes thus reducing
its total volume, and the design is normally favored over firetube boilers
for pressures in excess of 150 psig. A detailed description of the design
characteristics of various commercial and industrial boilers is given by
Offen et al (4) and n breakdown of the industrial boiler population by
Locklin et al (1).
33
-------
It is well-known that nitrogen oxides can be produced from two sources
during the combustion of fossil fuels, molecular nitrogen and nitrogen
chemically bound in the fuel. The selection of an emission control techni-
que for a particular boiler type will primarily depend upon the source of
the nitrogen accounting for the major portion of the total emission of nitro-
gen oxides. Techniques which have been successfully demonstrated for the
control of thermal NO production and which depend solely on flame temperature
reduction will have a minor influence upon fuel NO production. Also, a con-
trol technique which has been optimized for fuel NO control for a given fuel
will probably not be the optimum system if the fuel were to be changed.
Three methods of controlling pollutant emissions from package boilers
are compared in the paper with respect to both thermal and fuel NO control.
These three methods are:
• Fuel seledtion
» Burner optimization
• Combustion modification.
The results Included in the following sections were obtained under three
separate contracts concerned with the development of NO control techniques
X
for package boilers (5, 6, 7 ). The reader is directed to other publications
for a complete description of the relevant hardware which will not be des-
cribed in detail below.
34
-------
SECTION 2
FUEL SELECTION TO CONTROL NO
Fuel properties will Influence the emission of NO from a given system
X
for two major reasons:
flame temperature. Thermal NO production is strongly linked to
the maximum attainable flame temperature which will be dependent
upon the fuel compowltion; and
nitrogen content. Conversion of fuel-bound nitrogen will account
for some fraction of the total NO emission from a given system;
X
thus emissions will increase as the fuel nitrogen content increases.
Alcohol fuels do not contain bound nitrogen and they have lower flame tempera-
tures than natural gas or residual fuels. Consequently, conversion to this
type of fuel would have a beneficial effect upon emissions for the two reasons
listed above.
Martin (8) compared the emissions of NO from a laboratory furnace burn-
X
ing methanol and a number of other conventional fuels and the results indicated
that methanol emissions were lower, consistent with the lower well-mixed adia-
batlc flame temperature. The effect of fuel type on NO emission from two field
X
operating Industrial boilers is shown In Figure 2. These results were obtained
in a recent series of field testn (6) from a 12K Ibm steam/hr flretube boiler
and a 25K Ibm stoam/hr watertube boiler and show the NO_ emissions (corrected
to
0.1 percent N, thus the higher emission levels and greater sensitivity to
excess air level are i\t least partially due to the presence of fuel nitrogen
compounds. Emissions from methanol. are significantly lower than those from
natural gas, although the difference Is smaller in the case of the watertube
boiler. This can probably be attributed to the lower flame temperatures in
the watertube boiler due to the higher heat extraction rates and lower
35
0_) as a function of excess oxygen level. The No. 5 fuel oil contains
-------
combustion intensities. Due to limitations of the methanol delivery flowrate
the comparative tests were carried out at a steam load that was 30 percent of
the design capacity of the watertube boiler and 80 percent capacity of the
firetube boiler.
36
-------
SECTION 3
COMBUSTION MODIFICATION FOR NO CONTROL
x
The combustion process can be modified in two ways to control the
formation of NO:
- flame temperature can be reduced by dilution of the reactants
with inerts either by adding cooled combustion products to the
combustion air supply or by the entrainment of recirculating
combustion products within the combustion chamber. Alternatively,
peak flame temperatures can be reduced by staged heat release with
interstage cooling;
conversion of fuel-bound nitrogen is most strongly dependent upon
oxygen availability. Consequently, by staging the heat release
to give a fuel-rich primary zone the formation of fuel NO is limited.
In practice this is achieved by dividing the total air supply into
two and injecting one of these streams downstream from the point of
fuel injection.
Both of these control techniques have been investigated extensively in utility
and large industrial boilers. This section discusses their application to
package boilers.
The value of flue gas recirculation (FGR) as an NO control technique is
particularly dependent upon the nitrogen content and the fuel. Figure 3 pre-
sents results comparing the NO emissions from two field operating package
X
boilers as a function of tho mass of recirculated flue gas. Significant
reductions were obtained with tlu; nitrogen-free fuels while the, reductions
with nitrogen-containing No. 5 fuel oil were marginal. The marginal reduc-
tlotiH obtained with No. 5 fuel oil nre consistent with the results of other
investigators who have demonstrated the relative ineffectiveness of FGR as a
control technique for fuels containing bound nitrogen. Figure 4 provides a
37
-------
comparison of the results achieved by several workers in different systems.
The addition of cooled combustion products to the combustion air supply
will increase burner momentum which will affect fuel/air mixing. Variations
in fuel/air mixing might well enhance fuel NO formation, thus giving a net
increase in emissions even though a reduction in thermal NO production were
to be achieved. Increases in NO emission with flue gas recirculation were
X
observed under some operating conditions with the watertube boiler during the
fittld tests described by Cichanowlc.z et al (6) and in a series of tests with
a Laboratory combuutor (7). The range of variation in the results from both
of these tests is shown In Figure 4. Figure 5 shows the effect of FGR for
non-nitrogen-containing fuels. Comparison with Figure 4 illustrates how
much more effective FGR is as a control technique for fuels which do not
contain bound nitrogen.
Figure 6 compares the results of several investigations showing the reduc-
tion in NO as a function of burner stoichiometry for a variety of combustion
X
systems and staging methods for nitrogen-free fuels. Two sets of experimental
results presented in Figure 6 show an increased NO emission under staged com-
bustion conditions. A 17.5K Ibm steam/hr watertube unit (11) was modified to
enable second stage air to be injected through movable tubes projecting
through the front face of the boiler. As burner stoichiometry was decreased
NO emissions increased from baseline values reaching a maximum at a burner
stoichiometry of approximately 80 percent; the increase was greatest when the
staged air was injected closest to the burner. A 12K Ibm steam/hr firetube
boiler (6) was modified for combustion staging by insertion of air delivery
tubes from the back of the boiler along the firetube wall to a movable staging
ring that directed the secondary air radially Inward. Minor reductions in
emissions were obtained with natural gas and in most cases emissions increased
substantially as the burner equivalence ratio decreased below stoiehiometric.
In almost all cases for a given staging ring location highest emissions were
recorded at the lowest burner stoichiometry.
The Increase in NO emission with decreasing burner stoichiometry observed
X
in n number of different staging systems suggests the simplified view of stag-
Ing does not necessarily apply to practical systems. One reasonable suggestion
which could account for the observations IB based upon the concept that NO
38
-------
formation in gaseous turbulent diffusion flames is strongly dependent upon
the rate of entrainment of bulk gases into the reacting mixture. Since
reaction zone temperatures are quenched by mixing with the cooler bulk gases,
the more vigorous the mixing process, the more rapid is the quench rate, and
residence times a high temperature are reduced. This mixing process is con-
trolled to a large extent by the burner momentum which is reduced as the per-
centage of stoichiometric air at the burner is reduced. The mixing process
occurring within the second stage is also important and acts in a similar
manner. Consider that the first stage were to be perfectly mixed, and at the
location of staged air injection it formed a uniform plug of partially oxidized
fuel. The second stage air addition could be considered as two extremes:
1. The second stage air is added and mixes instantaneously producing
fully combusted products whose temperature is adiabatic for the
reactants.
2. The second stage air is added in finite successive amounts which
also mix instantaneously and give adiabatic products. However, as
the mixture progressively becomes less rich and reaches stoichio-
metric proportions, maximum temperatures would occur far in excess
of those achieved in (1).
Thus these two extremes represent conditions that would produce high and
low NO levels. The real process must be somewhere between these extremes, but
they illustrate how the mixing processes that occur in the second stage could
influence the final NO level. An alternative hypothesis can be proposed which
would also contribute to the observed effects which depends upon oxidation of
bound nitrogen specie (HCN, CN, NCO and NH.) in the second stage. The resi-
dence time in the rich primary section should be sufficiently long to ensure
minimum exit concentration of these species.
The effect.l venuHH of staged combustion by remote air addition as a techni-
que for reducing fuel NO omJsslons I.H strongly dependent upon the same system
X
design and operating parameters thnt dictate thermal NO reduction. These are
the details of the fuel/air mixing process, particularly the "unmixedness" in
the primary zone, the residence time and heat extraction of the primary zone,
and the rate of mixing of primary zone products with secondary combustion air.
39
-------
Evidence also exists that fuel properties are important in determining the
effectiveness of staging in controlling NO emissions. Thus the control
X
effectiveness is system-dependent and an optimal system configuration developed
for one particular combustion device will not necessarily be optimal under
different conditions.
The results of several attempts to control fuel NO emissions from a
X
number of different combustion devices with remote addition of second stage
air is presented in Figure 7. Turner and Siegmund (10) demonstrated substan-
tial NO reduction with a 50 HP firetube boiler with remote air addition from
x
a boom protruding into the combustion chamber from the rear of the boiler.
These results were obtained at 40 percent of the design firing rate of the
boiler due to limitations of the secondary air injection system. Reductions of
50 percent of the total NO could only be achieved in a similar laboratory
X
system after extensive modifications were made to the burner (14). Heap et
al (5) have reported substantial reductions on the 12K Ibm/hr field-operating
firetube boiler in which the staged air was introduced from the rear of the
boiler through pipes laid along the sldewall. The effect of primary zone
residence time could be studied by varying the distance of the staging ring
from the burner. At constant primary zone stoichiometry emissions decreased
as the distance of the staging injector from the burner increased. Emissions
monotonically decreased with primary zone stoichiometry except for the largest
primary zone length suggesting an optimum burner stoichiometry for a constant
staging configuration, or emphasizing the importance of optimum mixing con-
ditions in the primary zone.
There are practical disadvantages associated with the addition of second
stage air via tubes inserted through the boiler walls. A more convenient
system would allow the total system to be constructed as part of the burner,
thus requiring minor modifications to the boiler. A staging system of this
type requires optimization of both the primary zone residence time and the
mixing conditions in the primary zone as well as the method of secondary air
injection. Clchanowtcz and Heap (7) have recently carried out a series of
inveBt.igatlons on n laboratory eomlmstor to define these parameters for an
optimal staging system for firetube boilers. The resulting burner requires
front end modification only and utilizes second stage air addition from the
40
-------
periphery of a refractory primary chamber. The primary zone fuel/air mixing
conditions were optimized for the combustion air tangential/axial momentum
distribution, fuel atomizer operating conditions, and burner exit geometry.
The individual tests carried out for the evaluation of the influence of
these parameters are described in reference (7) and the necessary conditions
for optimal staging system performance may be summarized as follows:
* Primary Zone Length - the maximum reduction in NO emissions was
obtained with maximum mean primary zone residence time and this
time was limited by excessive particulate formation.
• Primary Zone Mixedness - conditions which appeared to enhance fuel/
air mixing in the primary zone minimized final NO levels. The
combustion airflow pattern was varied by changing the burner throat
diameter, swirl vane design, and burner exit geometry. Fuel atomiza-
tion input conditions were varied by changing atomizer size (fuel
delivery pressure), and atomizing fluid type and quantity. The
maximum NO reduction was obtained with a high exit velocity, high
X
swirl level, and high atomizing fluid pressure.
• Secondary Air Mixing - staging effectiveness was not strongly
dependent upon secondary air injection velocity for the con-
figurations in which air was injected along the firetube wall.
NO emissions increased significantly when the air was directed
X
radially Inward at the exit of the primary zone.
The NO emissions produced by the optimal staged burner are shown in
Figure 8 as a function of primary zone stoichiometry for three different
residual fuel oils, together with the smoke emissions (as Bacharach Smoke
Number). Significant reductions in emissions were obtained for all fuels,
and further decreases in primary zone stoichiometry were limited by exces-
sive smoke emissions. It is interesting to note that at or above primary
zone stoichiometric conditions similar levels of NO emissions were mea-
x
sured from the intermediate and high nitrogen fuels.
41
-------
SECTION 4
CONTROLLED FUEL/AIR MIXING TO LIMIT NO EMISSIONS
Air and fuel are supplied separately to the boiler combustion chamber
and mixing and heat release take place almost simultaneously. Controlling
the rate at which the fuel and air mix can achieve a similar effect as the
staged combustion techniques discussed in the previous section - a major
portion of the fuel reacts under oxygen-deficient conditions. Even in con-
ventional staged systems the initial fuel/air mixing in the primary region
has a substantial effect upon ultimate NO levels. A recent series of labora-
tory experiments concentrated upon the variation of tangential and axial air
momentum flux at the burner throat as a means of controlling fuel/air mixing
patterns (7). The burner throat is divided into four concentric channels
and the tangential momentum in each channel can be varied independently. A
wide range of NO levels were obtained by varying the tangential velocity
across the burner throat; however, one general pattern emerged that appeared
to apply for all fuels - NO formation was very strongly dependent upon the
swirl level in the vicinity of the oil nozzle. This is illustrated by the
results presented in Figure 9 which show NO emission as a function of swirl
level for two swirl distributions and three fuels. The swirl level relates
to increasing the tangential momentum in either the inner or outer channel
while the other channel had only axial flow. The total air was divided
evenly between the two channels. Thus, the high NO levels were obtained with
a tangential momentum distribution which most closely resembed a forced vortex
(tangential velocity Inversely proportional to burner radius) or an inter-
modinte vortex (trangentln I velocity constant with radius). The low NO levels
were obtained with only nxial flow in the channel closest to the nozzle and
the tangential velocity profile more closely resembles a free vortex distri-
bution.
42
-------
The high NO pattern (referred to as Type I) produces a short, high
intensity flame which spreads rapidly toward the combustor wall. The low NO
configuration (Type II) gives a much longer flame which remains on the com-
bustor axis. Gas concentrations and temperature profiles were measured at
one axial location to determine the characteristics of these flame patterns.
Three fuels were used: kerosene, kerosene doped with pyridine to give 0.2 per-
cent by weight of nitrogen and a residual fuel oil containing 0.36 percent by
weight of nitrogen. Representative results are presented in Figures 10 and 11.
The NO/NO stack gas emissions without pyridine were 80/90 and 110/115 ppm
X
HO/NO for the Type II and Type I flames respectively; with 0.2 percent N
X
as pyridine the values were 160/170 and 215/230 respectively. Despite the
similarity in stack gas NO emissions, the data shows distinct differences
in species profiles that are consistent with the visual differences in flame
pattern. CO emissions from the Type II flame are maximum off the centerline
in the region where the flame is; the CO peak for the Type I flame is almost
on the combustor axis consistent with the observed flame pattern. Without
pyridine highest NO emissions were measured in the vicinity of the centerline
' X
with the Type I pattern. NO emissions from the Type 31 flame are maximum just
X
outside the visible flame region and decrease as the centerline is approached
due to fuel rich conditions and low temperatures. The species profiles mea-
sured with kerosene doped with pyridine show two distinct differences from the
undoped case. High concentrations of NO were detected at radial locations
corresponding to the outer edges of the flame. These regions are characterized
by excess oxygen and high flame temperatures where fuel NO formation would be
maximized. In the low NO flame 35 percent of the peak NO level is attributed
to N0_. However, it is most likely that this high apparent NO,, is due to some
conversion of fuel nitrogen compounds in the chemiluminescent N0?-N0 converter.
The results obtained with kerosene can be contrasted with those obtained
with a residual fuel oil which are presented in Figure 11. The flue gas NO/
NO emissions measured for the high and low NO conditions were 550/555 and
260/264 respectively. At this axinl distance the NO/NO and temperature
X
profiles for the high NO condition are flat which is very different from the
profiles measured in the low NO flame. With the low NO mixing pattern fuel
apparently concentrates in a region close to axis and mixes with the air
43
-------
relatively slowly reflecting the major differences between the two flames.
As indicated in many other experiments, rapid mixing of the fuel and air for
a nitrogen-containing fuel maximizes NO production. If fuel NO formation is
to be controlled, mixing must be limited to that necessary to promote heat
release, but minimize fuel nitrogen conversion in the early stages of the
flame. The design of a distributed air addition low NO burner will not only
X
require controlled air addition, but the fuel injector must be designed to
assist the process by injecting the fuel in such a way that the fuel droplets
experience the optimum time/temperature history during their lifetime.
44
-------
SECTION 5
DISCUSSION
The control of pollutant emissions should not supersede our concern for
energy conservation. Thus, a primary factor in the choice of the most appro-
priate emission control technique for package boilers is its impact upon
thermal efficiency. This does not imply that capital cost nor attendant
increases in auxiliary plant power requirements can be Ignored. However, if
the application of some form of pollutant control results in fuel savings,
then these savings can be offset against other expenses.
Three control options have been discussed in the previous sections and
measurements have been made to assess their impact upon thermal efficiency.
• Fuel Selection. The significant differences in NO emissions as
X
a function of fuel type from the two industrial boilers discussed
in Section 3 are accompanied by significant differences in thermal
efficiency. Figure 12 shows the thermal efficiency as calculated
by the ASME Heat Loss Method for both Industrial boilers as a
function of excess air level for methanol, natural gas, and No. 5
fuel oil. A substantial thermal efficiency penalty is incurred
by switching from a high to a low polluting fuel and the use of
this technique would require an inexpensive source of alcohol
fuel.
* Flue Gas Recirculation. Thermal efficiency is almost Independent
of FGR as shown In Figure 13 which compares thermal efficiency of
the two industrial boilers as a function of the mass of FGR for
the three different fuels. Thermal efficiency appears to be far
more dependent on fuel type and additional data reported In Ref. (7)
shows that with FGR excess air level strongly influences thermal
efficiency. The resultant cost-effectiveness of FGR is thus
45
-------
relatively high for use with natural gas where significant
reductions in NO can be obtained and relatively low for residual
2C
fuel oil because of the ineffectiveness of FGR for nitrogen-
containing fuels.
• Combustion Air Staging. Thermal efficiency is relatively inde-
dependent of the amount of combustion air staging, thus the rela-
tive cost-effectiveness is primarily dependent on the control
effectiveness or fuel type. Figure 14 shows the thermal efficiency
of the firetube boiler as a function of burner stoichiometry for
No. 5 fuel oil and natural gas for two overall excess air levels.
As with FGR, thermal efficiency is dependent primarily on fuel
type and overall excess air level.
Fundamental considerations indicate that flue gas recirculation will not
provide adequate control possibilities for those fuels containing significant
amounts of bound nitrogen. However, for natural gas-fired package boilers
NO emissions have been reduced by very low levels (less than 20 ppm) without
attendant design problems. At present the major uncertainties associated with
the application of flue gas recirculation concern long-term maintenance and
reliability and the need for appropriate control equipment. The requirement
of dual fuel capability for most Industrial equipment and the decreased
availability of natural gas necessitates the development of other acceptable
control techniques for industrial boilers. From a cost-effectiveness view-
point it is necessary that alternative control techniques should be developed
which are equally effective with natural gas and residual fuel oils.
The potential of staged combustion techniques to control both fuel and
thermal NO emissions has been appreciated for some time. Considerable
success has been reported for utility boilers when the staging process was
achieved by biased burner operation or off-stoichiometric firing. The most
discouraging feature of all the attempts to stage the combustion process in
package boilers has been the back of generality, and therefore, applicability
of the results. Also, there can be serious questions raised as to the
practicality of the methods of staged air injection. The staging equipment
used in the firetube boiler and described earlier was considered as "experi-
mental", and although it withstood the environment within the firetube during
46
-------
the staging investigations, it could not be considered as representative of
a practical design.
The possibility of increasing NO emissions from gas-fired systems by
X
attempting to stage the combustion process have been described before, Heap
et al (16) described early results using the burner as a staging device in
which emissions from a natural gas flame were increased by a factor of three
when all the combustion air was not supplied through the primary burner
throat. Recent laboratory experiments carried out by De Soete (17) in pre-
mixed stratified systems indicate: that staging could cause an increase in NO
•' X
emissions. Therefore, the results described in Section are not without
precedent.
A low emission oil burner is currently being tested in a field operating
firetube boiler. The design of this burner was based upon extensive labora-
tory tests (7) to optimize the air distribution for staged combustion with a
particular fuel nozzle. Reductions in emission levels of greater than 50 per-
cent have been achieved without the need to modify the boiler in any way.
Future work should concentrate upon atomizer design since it is known that
the liquid spray characteristics have a strong influence upon fuel/air mixing
conditions.
47
-------
REFERENCES
1. Locklin, D.W., et al, "Design Trends and Operating Problems in Combustion
Modifications of Industrial Boilers". EPA Report No. EPA 650/1-74-032,
April 1974.
2. Barrett, R.E. and Putnam, A.A., "Boiler Emissions - An Inventory of
Emissions by Boiler Size and Use". Paper presented at the 69th Annual
Meeting of the APCA, Portland, Oregon, June 1976.
3. Mason, H-B. And Shimizu, A.B., "Definition of the Maximum Stationary
Source Technology System Program for NO Control", Quoted in Ref. 11.
A
4. Offen, G.R., KesHelring, J.P., Lee, K., Poe, G. and Wolfe, K.J., "Control
of Particulate Matter for Oil Burners and Boilers". EPA Report No.
450/3-76-005.
5. Heap, M.P., McComis, C., Tyson, T.J., McMillan, R.E., Zoldak, F.D.,
Sommerlad, R.E., "Reduction of Nitrogen Oxide Emissions from Package
Boilers". EPA Report No. 600/2-77-025.
6. Cichanowicz, J.E., Heap, M.P., McComis, C., McMillan, R.E.-, Zoldak, F.D.,
"The Control of Nitrogen Oxide Emissions from Package Boilers", Report
in preparation, EPA Contract 68-02-1498.
7. Cichanowicz, J.E. and Heap, M.P., "Design Criteria for Low NOX, High
Efficiency Oil-Fired Firetube Package Boilers", Report in preparation,
EPA Contract 68-02-1500.
8. Martin, C.B., "Evaluation of NOX Emissions Characteristics of Alcohol
Fuels for Use in Stationary Combustion Systems". Paper presented at
the AIChE Symposium on the Impact of Methanol Fuel on Urban Air Pollu-
tion, Boston, Mass., September 1975.
9. Martin, fi.B. and Berkau, E.E., "Evaluation of Various Combustion
Modification Techniques for Control of Thermal and Fuel-Related
Nitrogen Oxide Emissions". Paper presented at the 14th Symposium
(International) on Combustion, The Pennsylvania State University,
AuguHt 21-25, 1972.
10. Turner, D.W. and Slegmund, C.W., "Staged Combustion and Flue Gas Recucle:
Potential for Minimizing NOX from Fuel Oil Combustion". Paper presented
at the American IMnme Research Committee Meeting, Chicago, 111., 1972.
40
-------
11. Cato, G.A., Muzio, L.J. and Shore, P.E., "Field Testing: Application of
Combustion Modification to Control Pollutant Emissions from Industrial
Boilers, Phase II", EPA Report No. 600/l-76-086a, April 1976.
12. Brown, T.D., Mitchell, E.R. and Lee, G.K., "Low NOX Combustion: The
Effect of External Flue Gas Recirculation on Emissions from Liquid Fuel
Combustion". Proceedings of the Combustion Institute European Symposium,
September 1973, Academic Press.
13. Shoffstall, D.R., "Burner Design Criteria for Control of NOX from Natural
Gas Combustion: Volume I — Data Analysis and Summary of Conclusions".
14. Muzio, L.J., Wilson, R.P., Jr. and McComis, C., "Package Boiler Flame
Modifications for Reducing Nitric Oxide Emissions, Phase II of III",
EPA Report R2-73-292b, June 1974.
15. Siegmund, C.W. and Turner, D.W., "NOX Emissions from Industrial Boilers:
Potential Control Methods", ASME Paper No. 73 - IPWR10, 1973.
16. Heap, M.P., Walmsley, R. and Holthuysen, A.M., "The Measurement of Nitric
Oxide in Natural Cos and Pulverized Coal Flames, I.F.R.F. Document No.
C19/a/2, 1972.
17. De Soete, G.G., Paper presented at the 15th International Combustion
Symposium, Tokyo, Japan, August 1974.
49
-------
+
a> i—
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01 vi
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o c
CO i—*
tO
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OP
CM
'»!->-•
°1
§5
u
50
-------
-------
240
•U
id
200
160
120
o
SB
No . 5 Fuel Oil
Firetube
Excess 0
--- Natural Gas
--- Methanol
4.0%
Watertube
10
20
30
40
50
Flue Gas Recirculation, Mass %
Figures 3. The effect of flue gas reclrculation on NO
emissions from three fuel types from a
Ciretube and watertube boiler.
52
-------
1.1
1.0
Laboratory Combustor,(6)
least reduction
Watertube,(7) least reduction
:ato at al,(ll) air atomization
Cato et al,(ll),
steam atomitation \-. Firetube,(7),
\ \least reduction
,, * .^Watertube,
Ybest reductiot
Firetube,
beat reductlo
Martin and Berkau,(9) \
Turner and
Siegmund.(lO)
Brown et al,(12
Laboratory Coiabustor, (6 ) ,
befit reduction
10 20 30 40
Flue Gas Recirculation, (Mass %)
50
Figure 4. 'Hie effect of flue gas recirculation on NO emissions from
residual fuel oil for a variety of combustion systems.
53
-------
1.0
0.9
0.8
c 0.7
o
•i-t
•u
u
(0
1
1 0.5
0.4
\
\
\
Brown et al,<12) Distillate Oil
0.3
0.2
0.1
Heap et al,(5)
Firetube, n.g.
\
Turner and Siegmund,(10)
Distillate Oil
\ —-Propane I
Shoffstall,(13),n.g.
Cichanowicx
and Heap,(7)
Martin and Berkau, (9),
10 20 30
Flue Gas Recirculation, (Mass %)
40
50
Figure 5. The effect of flue gas recirculation on NO emissions from
nitrogen-free fuels for a variety df combustion systems.
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. o
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a
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,§
200
100
No. 6 Oil 0.71% N
— No. 6 Oil 0.38% N
No. 5 Oil 0.1% N
120 110 100 90 80 70 60
50
40
Burner Stolchionetry, (%)
Figure 8. The effect of burner stoichiometry on NO and smoke
emissions from the refractory staged burner.for three
residual fuels.
57
-------
700
600
500
o
8 400
9
s* 300
200
100
Residual Fuel Oil
(0.71% Nitrogen)
Inner Channel Swirl
Increase
Outer Channel Swirl
Increase
Natural Gas
0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9
SWIRL LEVEL (INNER OR OUTER CHANNEL)
Figure 9. The effect of tangential velocity distribution on
NOX emissions for residual fuel oil, distillate
fuel oil and natural gas.
58
-------
tJ
9)
180
160
140
| 120
* 100
*
* 80
*
—i
gX 60
i i
40
20
Type I (High NO ) Flame
Kerosene
NO
X
NO
CO
Type I (High NO ) Flame
Kerosene w/0.2%*N.
(Pyrldlne)
\
18
16
14
(0,
10 8
I
6 8
0.2 0.4 0.6 0.8 1.0
0.2 0.4 0.6 0.8
180
160
•o 140
«
§ 120
g
2 100
A
9- 80
x 60-
40
20
0
§
Type II (Low NO ) Flame
Kerosene x
^t--^
0.2 0.4 0.6 0.8 1.0
Type II (Low NO ) Flame
.Kerosene w/0.2*XN (Pyridine)
' ' \ '» \
:" \ 'O
. \
16
14
12 1
10 I
fl
8 *
*»
I
6 &
i—i
4 8
2
0.2 0.4 0.6 0.8 1.0
Uimensionless Radial Distance, r/R
o
Figure 10. NOX, NO and CO radial profiles with kerosene fuel with and
without 0.2% N (as pyridine) for the Type I and II flame
patterns.
59
-------
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«mdd
00 f» >e
"" ' ' i-N
Xjp) paansswn SB 'mdd « JXON|
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60
-------
851
801
4)
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O
I "!
70 '
Firetube
Watertube
Methanol
456
Excess Oxygen, 7.
8
Figure 12. The effect of excess oxygen level on thermal efficiency of the
firetube and watertube boilers for three fuel types.
61
-------
85
u
-------
SESSION II:
UTILITY AND LARGE INDUSTRIAL BOILERS
DAVID G. LACHAPELLE
CHAIRMAN
63
-------
-------
DESIGN AND SCALE-UP OF LOW EMISSION BURNERS FOR
INDUSTRIAL AND UTILITY BOILERS
By:
R. Gershman, M. P. Heap, and T. J. Tyson
Energy and Environmental Research Corporation
Santa Ana, California 92705
65
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SECTION 1
INTRODUCTION
NO cmiwHions J'rom coal and oil-fired industrial and utility boilers
currently cotiHtltute approximately one-quarter of nation-wide NO emis-
sions and this Fraction can bo expected to increase as more emphasis is
placed on use of coal, for power generation and tighter regulations are
imposed on automobile emissions. The EPA has established a broadly-based
program to reduce NO emissions from large boilers. As part of this program
the EPA has established goals for NO emission control technology. The
goals will require substantial improvement of the state-of-the-art, parti-
cularly the 1985 R&D goal of 100 ppm for coal-fired utility boilers.
Low NO burner technology capable of meeting these goals has been
X
investigated in pilot scale work but has not been demonstrated on a practi-
cal scale. This technology is based on the concept of distributed fuel/air
mixing. The basic purpose of the study described here (EPA Contract No.
68-02-1488) 1.8 to develop the distributed mixing burner concept to a level
where it could be of use to manufacturers and users of large boilers.
Specific objectives of the study are:
1. To design and construct a facility for large-scale burner
testing which simulates the geometry and thermal environ-
ment of practical boilers;
2. To design and build practical low NO burners and test
X
• them over a wido rangi* of operating conditions;
'>. To InvrsLl^ate application of the low NO burner concept
Lo ranif1 burner arrays; and
4. To develop .scaling Laws to assure that the low NO burner
concept can bu applied to a wide range of furnaces.
66
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SECTION 2
THE DISTRIBUTED MIXING BURNER CONCEPT
.To understand the operation of the distributed fuel/air mixing burner,
it is necessary to consider the processes of NO formation in fossil fuel
flames. NO can be formed either from molecular nitrogen in the combustion
air (thermal NO ) or from chemically-bound nitrogen in the fuel (fuel NO).
Fuel NO can be further divided between NO formed from nitrogen in the
volatiles and NO formed from nitrogen in the char.
Uncontrolled pulverized coal combustion in large utility boilers has
total NO emissions of up to 1000 ppm. Thermal NO is estimated to represent
approximately 15 percent of the total; volatile NO, 65 percent; and char
NO, 20 percent. Although volatile NO represents the major portion of the
emissions, the other two sources must also be dealt with in order to meet
the 100 ppm goal.
In the distributed mixing burner concept the approach to reducing
thermal NO is to minimize the peak flame temperature. This method has been
utilized successfully in many other applications.
Formation of NO from volatile nitrogen can be minimized by control of
flame zone stoichiometry. The key factor is competition between the follow-
ing two reaction paths:
YN + 0
YN + X.N
NO +
with the NO path domln.-it In;; undur lean conditions and the N path dominat-
ing under rich condiLlonn.
In turbulent diffusion flames, although the stoichiomtitry may be overall
rJc.li, there will be Joc.il lean zones which will result in some NO formation.
67
-------
If residence t I.m« in the rich zone is adequate, however, any such NO can
bt- r^ducfri by hydrorfirbon fragments:
NO + CH -»• YN + ...
NO may a.!HO be reduced by heterogeneous reduction by char.
In the case of char NO, no effective control methods are available.
Instead the approach used here is to maximize evolution of nitrogen with
the volatiles. Laboratory work has indicated that most of the nitrogen can
be driven out of the char by providing for adequate time at high temperature.
Figure 1 illustrates the distributed fuel/air mixing concept. The coal
and primary air are injected with a moderate axial component. This stream
is surrounded by a secondary air stream with a swirl component for stabiliza-
tion. Ttrtiary air for burnout is added axially around the periphery of the
burner. This arrangement results in a weak shear layer between primary and
secondary streams which leads to gradual mixing. This provides for a hot,
rich recirculatlon zone with adequate time at high temperature to maximize
evolution of nitrogen from the char and adequate time in the rich zone to
reduce most of the NO that may be formed.
Axial addition of the tertiary air leads to a large flame zone and
thus provides for heat extraction prior to completion of burnout. This,
along with dilution of the tertiary air by combustion products, lowers the
peak flame temperature and thus reduces thermal NO.
Burners of this type have given excellent results in pilot scale testing.
An example of the pilot data is shown in Figure 2. It can be seen that levels
as low as 100 ppm were achieved. Figure 2 also illustrates the importance of
coal injector design. (The coal spreader injector identified in Figure 2
gives a flow n.-ittorn similar to that shown in Figure 1.)
6R
-------
SECTION 3
PROGRAM DESCRIPTION
The current program has been set up to demonstrate the applicability
of the distributed mixing concept to practical systems. Specific questions
which must be addressed include:
1. Effects of scale and furnace geometry;
2. Effects of burner interactions in multiburner arrays;
3. Impact of larger flame zones on furnace capacity;
4. Potential corronlon problems due to larger rich reaction
zones; and
5. Potential slagging problems due to reduced ash softening
temperatures in the rich zones.
The test facility and experimental plan have been designed to provide
answers to these questions.
TEST FACILITY
The main features of the burner development test facility are as
follows:
Two boiler simulators
a utility boiler simulator capable of firing at
120 x 10" Btu/hr.
a watertuhe package boiler simulator capable of
firing at 12 x 10g Btu/hr.
- Capability to fire pulverized coal, residual oil, or simulated
low Utu gas in both units. (The simulated low Btu gas is pro-
duced by partially oxidizing propane and adding appropriate
quantities of nitrogenous species.)
69
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Sheet steel walls cooled by water sprays. The water sprays are
divided Into individually controlled sections.
Variable geometry for the large utility boiler simulator.
Air preheat capability to 800°F.
Independent control and measurement of numerous air streams.
An on-line pulverizer capable of producing particle size
distributions similar to those in industrial practice.
- A steam source for oil atomization.
Flexible burner positioning and probe access. Flexibility of
probe access is important for detection of reducing conditions
near the walls that could lead to excessive corrosion.
Variable geometry for the utility boiler simulator is achieved by means
of a movable back wall. Figure 3 illustrates the range of positions of the
movable wall which can provide for variation of furnace volume by up to a
factor of 3. Figure 3 also shows the range of firebox residence times that
can be obtained and compares them with existing boilers that have been tested
for NO reduction.
x
Construction of the facility is essentially complete and testing has
recently started on a 50 x 10 Btu/hr burner.
TEST PROGRAM
The first and most important element of the test program is the develop-
ment of a large-scale distributed mixing burner capable of operating with
low emissions and high efficiency under conditions typical of practical
boilers.
Other key elements of the test program include:
Testing of three burner sizes and three furnace volumes to
generate data for development of scaling procedures;
Extension nT the distributed mixing concept to multiburner arrays
including invest I gatIons of burner spacing and burner-to-burner
variations In stolchiometry;
70
-------
firing of low Btu gas, both alone and in combination with coal;
and
Detailed flame probing to provide insight into the NO formation
process.
71
-------
7
SECTION 4
TEST RESULTS
Testing of the burner illustrated in Figure 4 has recently commenced.
The burner has an annular coal injector which provides a flow pattern
similar to that shown in Figure 1. Secondary air swirl levels are variable
and tertiary air is Introduced through four axial Injectors.
The first test results obtained are compared with results from the
pilot tests for similar operating conditions in Figure 5. (Primary zone
stoichiometry is defined as the fuel/air equivalence ratio based on the sum
of the primary and secondary air flows.) The fuel in the large-scale test
was Utah high-volatile bituminous with 1.24 percent N and 0.6 percent S.
The large-scale results are seen to compare favorably with the pilot scale
results.
72
-------
SECTION 5
CONCLUSIONS
The first set of test results shown in Figure 5 is very encouraging
and at this point it appears that the distributed mixing burner has a
very promising future.
73
-------
Q.
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74
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200
100
COAL SPREADER. 25° QUARL _
JT\ LJ
COAL SPREADER, 35W QUARL
20 40 60
PERCENT OF MAXIMUM SWIRL
80
100
Figure 2. Pilot Scale Test Results
75
-------
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77
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800
600
CM
O
o
<:
o 400
0.
O
200
100
0.8
PULVERIZED COAL
SMALL-SCALE HOT TUNNEL
5 x 106 Btu/hr
LOW SWIRL O
MEDIUM SWIRL O
HIGH SWIRL A
WATER-COOLED SIMULATOR
50 x 106 Btu/hr
MEDIUM SWIRL
35% EXCESS AIR —
55% EXCESS AIR -
1.0 1.2 1.4 1.6
PRIMARY ZONE EQUIVALENCE RATIO
Figure 5. Test Results
78
1.8
-------
STATISTICAL CONSIDERATIONS IMPORTANT IN ANALYZING MEASURED
CHANGES IN WATER-WALL TUBE THICKNESS
By:
0. W. Tukey
Bell Laboratories
Princeton University
Murray Hill, New Jersey 07974
79
-------
ABSTRACT
Most measurements of tube thickness are made ultrasonicaUy. Present
ultrasonic thickness gauges require calibration. Their calibrations are not much
more accurate than their measurements. Statistical analysis of data for
significance or confidence requires identification of portions of the data deserv-
ing of being treated as having uncorrelated variations/fluctuations/errors. When
calibration variations are comparable with measurement variations this requires
that each such portion consist of one or more recalibrations (actual or poten-
tial) together with the measurements to which those calibrations apply. Placing
in separate portions individual measurements which share a calibration can,
under these circumstances, greatly bias the calculation of the apparent certainty
of the statistical analysis (usually indicating falsely high precision).
If the practice of calibrating once for each row of measurements on a
given wall is followed, the natural portion is a summary — median, mean or
rob/res estimate — of the thickness changes found for that row. Estimates of
error must then depend on variation from row to row. Using a conventional
sum of squared deviations among rows as a basis for significance or confidence
can lead to unduly wide allowance for uncertainty, because real trends — say
from top to bottom of a wall — are likely. The use of mean square successive
differences, introduced more than a century ago by Erastus deForest, and used
for eight decades in artillery statistics, can do much to obviate this difficulty.
(The needed tables are available.)
Boilers lend to huve two furnaces; furnaces tend to have four water-walls;
observed numbers are such that results for upper/lower half walls often seem
interesting. Together or separately, these facts make parallel significance tests or
parallel confidence intervals almost inevitable. Good engineering/scientific prac-
tice then leads any/all of us to focus our attention on the most striking results.
This raises problems of multiplicity, of simultaneous confidence or of parallel
significance. The simplest approach to these problems, sometimes associated
with the name of Honl'crroni, is easy to understand and use. (More recondite
approaches, when appropriate, will yield slightiy lighter results.)
I'tvuwiM in |i;in (I) 111 uiiiM-iiiiviiiT nl work :ii I'riiU'cton UnivciMly on Ihc sutlwtical anulysis of corrosion
il:ii:i on UK- \Vulp\v's l 'ivi'k No *> hnik'r. nncl (}) in I'onnccliun with research ill I'riinvion University spon-
•iorcil b» ilu- Anm KCSIMU-II (Hl'uv U)inh;ini).
-------
A. Calibration Practices And Statistical Analysis
1. No Instrument Can Be Trusted Without Calibration
In considering the statistical analysis of measurement data, it is too easy, often fatally
easy, to forget that no instrument is automatically perfect, that every instrument requires cali-
bration at one time or another.
Many measuring devices are easily calibrated to much greater precision and accuracy than
is required of them in their daily use. Familiarity with such examples, which are not as com-
mon as might be naively thought, can seduce us into treating all instrumental measurement as
only subject to the sort of "errors of measurement" that are revealed by some relatively simple
form of repeated measurement. In many areas, however, ranging from the measurement of
total atmospheric ozone by Dobson meters to the measurement of changes in tube thickness by
ultrasonic gauges, calibration is made with a precision/accuracy only comparable with that
demanded of the measurement.
2. Simple Algebra Of Variances
IF
-------
3. Consequences
But if
-------
B. Successive Differences Can Ease Our Problem
5. The Prototypical Problem
We now face a problem, which the exigencies of practical measurement are very likely to
put into the following shape:
• measurements are taken in levels across a boiler wall, with each level of measurements
sharing a calibration
• there are likely to be trends in the quantity measured, apparent change in thickness
• differences between observed row means, while reflecting both calibrations and meas-
urements correctly, also reflect differences in this trend.
This is of course a classical problem, one thai arises in many situations. One simple and
classical case arises in judging the precision (not accuracy) of artillery fire. When a gun is fired
repeatedly under as carefully consiam circumstances as possible, there will remain trends due to
(a) temperature changes for the gun and the powder, (b) changes in the wind, and (c) perhaps
other relevant circumstances. If ihe differences in point of impact — corresponding to our
level means — are to be turned into an assessment of imprecision, we will do well to minimize
the effect of trends upon our assessment.
6. Alternative Solutions
Two sorts of approach to this problem have been used, and a third sort is possible. The
most rigid approach is to choose a functional form — linear, quadratic, or what have you — and
act as if we knew thai the Irend had ihis form, fitting the unknown constants, subtracting the
filled trend from the observations to form residuals, using these residuals as a basis for assess-
ing precision. All the necessary procedures are classical (though modern robust/resistant tech-
niques may offer further advantages). Experience with many fields suggests that this approach
is often far too rigid.
The second approach is beginning its second century. Eraslus deForcst, a Yale professor,
suggested in 1874 using only differences between (physically) adjacent observations (sometimes
simple differences, sometimes higher differences) as a basis,for assessing the contributions to
variability associated with the observations (falls of shot, level means, etc.) themselves. This
procedure is quile flexible, relying upon the local properties of the trend, rather than on any
assumed overall shape. It has been used in ballistics (e.g., artillery precision) for more lhan 80
years. Il has not been used widely enough, though there is sufficient experience to be sure that
it is very often very helpful.
A third class of approach, nol yel invesligated, would be to apply modern
(robust/resistant) techniques of smoothing, either to the observations themselves or to
differences of adjacent observalions, and Ihen to work wilh the values of the rounh. where
rough •= observed MINUS smooth
For the present, we do not have the knowledge needed to judge Ihc effeciiveness of such an
approach.
Accordingly il is natural 10 plan to use Ihc second approach. What do we need to imple-
ment its use?
7. Moiin Siimiri1 Successive DlffcrcniTs-Calculallon
l-ixhibil I shows ihe basic calculations for the apparent changes in tube thickness in the
side wall of ihe B furnace of Ihe Widow's Creek No. 5 boiler. We have chosen lo summarize
cither set of successive differences by the sum of its squares.
83
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Suppose we choose lo use the 1st differences, how are we to use the sum, 1199.89, of
their squares? First, we need a divisor to convert this sum to an estimate of the contribution
of overall measurement variability to the variability of a level mean. Once we have this, divid-
ing by the number of level means will give us an estimate of the variability of the extended
mean — the grand mean of level means.
8. Mean Square Successive Differences-Denominators
The first of these problems was solved by deForest, and independently by many other
later writers. The appropriate divisor is always the product of
• Ihc number of squares summed
• the sum nf squares of Ihc coefficients when Ihe difference is written nut in detail.
I'or the first lew orders of difference we have the following coefficient!! und sums of squares:
I'irsi (.I/HI-™.*,): +1.-I; l;+l?-2
Second (y,, , ~2y,, i+.y(): I, -2,1; lJ+2?+l'-6
Third (.v,,r-3.i;,1,+3.>',(|-.v,): I.-3.3.-1; !2+32+32+l7-2()
Fourth: !2+(-4)2+62+(-4)2+l ~70
Thus if we wished lo base an estimate of overall measurement variability (more or less
increased by contributions from the trend) on the information in the individual columns of
Exhibit 1 we would obtain the following alternative results:
2597.81 --~-(-76.43)2
(level means) 206.72 =
11-1
1 1QQ CO
(first diffs) 59.99 - 20 where 20 -(10) (2)
(second difls) 59.76 - where 54- (9) (6)
54
The agreement belween Ihc latter two is shockingly — and accidentally — close. The real point
is that both of the values arc less than 30% of the value based oh the level means themselves.
The only appropriate conclusion is that basing our estimate of variability of the wall mean on
206.72
11
rather than on
59.99
11
or
involves an unaeceptably large, quite inappropriate contribution from trends up or down the
wall.
9. The Widow's Creek Experience
The example jusl discussed is Ihc most extreme of the eighl arising in Ihe analysis of the
Widow's Crock No. 5 duUi. Kxhibil 2 shows Ihe alternative estimates of overall measuremeni
variability for all eight walls.
Which estimates of overall measurement variance for level means lo take in practice has
to be a matter of judgement. If we have no adequate basis for final choice, we should choose
Ihe lower of the two orders of differences involved, for reasons to be explained below.
The writer would consider any of the following choices clearly defensible for the set of
data illustrated:
84
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Exhibit 2
Alternative Estimates of Overall Variance of Measurement
(of level means) for Walls of Widow's Creek No. 5
Estimates Based Upon
Furnace
A
B
(mean)
(median )
Wall
Side
Division
Front
Burner
Side
Division
Fron I
Burner
Row
Means
37.06
34.92
43.57
68.56
206.72
35.76
96.14
36.24
(69.9)
(40.3)
First
Differences
18.83
31.68
11.09
46.97
59.99
23.77
65.44
46.17
(36.7)
(39.3)
Second
Differences
16.26
27.58
5.71
28.80
59.76
25.50
46.17
58.03
(33.5)
(28.2)
(A) always use 1st differences,
(B) always use 1st differences, except use 2nd differences for the burner wall of A furnace
(C) always use 2nd differences, except use 1st differences for the front wall of A furnace
(The value of 5.71 for 2nd differences and the front wall of A furnace seems quite sure to be
artificially small. Its use would not be defensible.)
Rather less well defensible, though reasonably plausible, would be to combine estimates
of variability across walls, using either of:
(D) The mean estimate based on 1st differences, 36,7, for alt walls,
(E) The mean estimate based on 2nd differences, 33.5, for all walls.
Until we have a clearer understanding of the variability to be expected in the individual esti-
mates, the writer would be a little reluctant to use such pooled estimates in highly controversial
situations, even though he might regard one of their values as his best personal guess of the
overall measurement variability involved in a typical level mean.
Ml. Equivalent Degrees Of Freedom
Before we ciin use our cstiunites of overall measurement variability effectively, we need a
moderiiiely good idea of how much variability is intrinsic in such estimates. The distribution of
such estimates is not one of the most manageable of distributions, even under the most Utopian
assumptions. (It look ihc com hi mil ion of World War II and the involvement of (he great
mathematician John von Neumann to start its mathematical investigation.) Accordingly it
should be no surprise that our approach to the question of stability is today a little indirect.
The reason why we have lo consider the "degrees of freedom" of a variability estimate in
carrying out significance tests and finding confidence intervals is a simple one. if we have an
estimate of variance that, like :ill real esiimales, is subject to fluctuation, we must be prepared
85
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degrees of freedom
for the fact that the number we have before us may be either too large or too small. If we want
to make statements with small probability of error, the consequences of our apparent variability
being too small are very much more drastic than those of its being too large. Accordingly we
have to increase somewhat the critical /-value (or the critical value of another appropriate
statistic) in order to compensate for this.
For estimates based upon the sum of squares of deviations from a mean (or fitted trend)
ihe well-founded practice is to count the number of linearly independent residuals, and use the
resulting number of degrees of freedom in entering tables of critical values.
For the 5% point of Student's /, ihe effect of such care is fortunately not too large, the
critical values being
2.57 for 5 degrees of freedom (—30%)
2.23 for 10 degrees of freedom (--15%)
1.96 for very many degrees of freedom
It is, however, large enough that we dare not neglect it.
For estimates based on a conventional sum of squares of deviations, the relation
2 (Gaussian-average)2
Gaussian-variance
holds exactly where "Gaussian-average" means the average, of our variability estimate, when
the values that enter into it have a Gaussian distribution, and "Gaussian-variance1" means the
corresponding variance of our variability estimate. Accordingly, we do relatively well to define
2 (Gaussian-average)2
Gaussian-variance
for other estimates of variability and to plan to use the resulting "degrees of freedom" in
entering / -tables, etc.
The weakest link in this process is easily identified. We need to increase t because our
estimate of variability may be too small. The greatest contribution to the Gaussian-variance of
our estimates comes from situations where the estimate of variability is too large. However, to
the best of today's insight, it appears likely that this loose linkage contributes more to excess
conservatism than to excess liberality, especially in the case of mean square successive
differences. So we tolerate it for the moment.
11. Equivalent-*// For MSSD's
Since we can calculate equivalent-*//for mean square successive differences from Table 1
of Morse and Grubbs (1947) in the form (expressed in their notation)
eq-df/' -{«-!)• W(n\p)
with the results shown in Kxhibit 3, and since we have today no better basis for incorporating
information about the stability/instability of our variance estimates based on mean square suc-
cessive difference, the recommended best practice, for the present, is to use values from Exhi-
bit 3 in entering our /-table.
In the case of Hxhinit I, then, if we had chosen 1st differences we would have
estimated variance of a level mean: 59.99
59.99
equivalent-*// i
esiimatcd variance of grand mean: 5.45 —
11
estimated standard deviation of same: 2.33 «*
equivalent-c//'(from Exhibit 3): 6.90
corresponding /-value (by interpolation): 2.37
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Exhibit 3
Values of en-df for Mean Square Successive Differences
of Orders 1 to 4, Based on 3 to 15 Successive Values
(based on Morse and Grubbs, 1947)
Order or Successive Differences
#of
Values first Second Third Fourth
4
5
6
7
8
9
10
II
12
13
14
15
1.60
2.25
2.91
3.57
4.24
4.90
5.57
6.23
6,90
7.56
8.23
8.90
9.56
1.00
1.38
1.86
2.36
2.87
3.37
3.84
4.40
4.9!
5.42
5.93
6.45
6.96
xxxx
1.00
1.28
1.66
2.07
2.49
2.91
3.34
3.77
4.20
4.62
5.06
5.49
xxxx
xxxx
1.00
1.22
1.53
1.88
2.25
2.62
2.99
3.29
3.74
4.12
4.50
so that the ± associated with a 95% confidence interval, calculated as usual as
± (critical value of t)(estimated standard deviation)
would be
±(2.37X2.33) = ±5.54
We have thus completed an illustration of how we can use mean square successive
differences to yield ;i confidence interval Tor a grand mean more appropriate than one based on
a//the differences among level means.
Note also (hut in our case we got 6.9 equivalent-*//Tor 1st differences, but would get only
4.9 for 2nd differences. This is an example of the general reason for the maxim stated earlier,
when in doubt use the lesser order of differencing.
C. Problems Of Multiplicity
12. The Root Of The Problem
In the situation arising in studying boiler corrosion, as in so many situations of science or
engineering, we have to look at u number of more or less parallel results, where any one result
may be trying to lei! us about tin important fuel. Good engineering or scientific practice will
87
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direct our attention most heavily to the result that seems most important, something that would
cause no additional difficulty if the precision of our result is very high.
The appropriate allowance to be made for uncertainty in a measurement depends on both
an honestly-assessed measurement variance and the degree of selection for apparent importance
involved. To know that Mr. X has a coin which has come up heads 10 times in a row is quite a
different thing if:
(a) this is the only coin he ever flipped
(b) this is the 987th coin he Hipped, each 10 times, and the only one to give 10 heads
(c) this is the 15,234th coin he flipped, each 10 times, and the only one to give 10 heads.
The chance of 10 heads, for a "fair" coin, independently flipped is one in 1024 («-2'°).
Under circumstances (a) 10 heads is quite unlikely for a fair coin, and we have strong evidence
thai the coin is not fair. I'br 9N7 fair coins, all fair and independently Hipped 10 times, the
expected number of 10-head observations is 987/1024 — .96, and one 10-head result is just
what we might expect. In situation (b), then, there is no evidence against fairness. For 15,234
fair coins, all fair and independently flipped 10 times, the expected number of 10-head observa-
tions is 15,234/1024 = 14.9; to have seen only one is a shocking deficit, and we have strong
evidence that the successive flips, or successive coins, are not independent.
The data was the same, the selection situation was very different, and the answers were
quite different.
13. The Confidence-Interval Case
In setting confidence intervals, in the usual situation where we have parallel results and
must be interested in the apparently largest result, it is thus not satisfactory to merely set indi-
vidual confidence intervals, each of which has, say, 5% chance of failing to cover the true value
of what has been measured.
The simplest solution, which is not all that much more conservative than the other plausi-
ble solutions, is to set, in addition to individual confidence intervals, sinntttaneons; confidence
intervals so chosen that the average number of failures of any/all of the collection is .05. (Just
as the average number of failures of any one individual 95% confidence interval is .05.)
This can be easily attained, when we have k parallel quantities, for each of which a
confidence limit is desired, by looking up the critical value of the appropriate statistic, not for
5%, but for 5%/A. Once the average rale of failure of each confidence interval to cover what it
should is set at .OS/A, the average number of failures (of any confidence interval) is A times as
large, namely .05. (No question of dependence or independence arises, because we are dealing
with averages, and the average of a sum is the sum of the averages, willy-nilly.)
In the case of Widow's Creek No. 5, we have the ±'s for individual and simultaneous
confidence limits shown in I'xhibit 4. The change due to admitting that we must look at the
largest value is large, but not so large as to be unreasonable.
I). Closing Comments
14. What Wt> Haw faced Up Tit
All the points we huvc so fur discussed
-------
* all differences among results for the given wall are allowed to contribute equally to the
assessment of overall variability
• the resulting measurement variance is divided by the total number of observations
• no allowance is made for the parallel analysis of several walls and half-waits.
We have alternately widened and narrowed our confidence intervals.
When we recognized the importance of calibration, we inevitably widened our confidence
intervals. In particular, if, both before and after, 11 calibrations and 99 measurements are
involved in the corresponding grand mean for some hypothetical wall the variance of the grand
mean difference ( — difference of grand means) is
-i -2
- .182
i
99
11
Vm_
99
i
9
so that if a~f is anywhere nearly as large as o-£ the variance of the change will be dominated by
the calibration variance — and we are stuck with the limited number of independent calibra-
tions made.
When we recognized that there may be — in fact, almost inevitably are — trends from
level to level in the time changes in thickness, and accordingly gave up s2 (among level means)
in favor of overall-measurement variance estimates based on mean square successive
difference, we inevitably narrowed the confidence intervals for wall means. In Exhibit 2, the
estimated variances were reduced by a factor of roughly 2, indeed once greater than three, thus
narrowing the confidence limit to not quite about 70% — in one instance, not quite about 55%
— of their former length. ("Not quite" because of loss of degrees of freedom.)
When we recognized the inevitability of looking at the most important of several results,
and complemented our individual confidence intervals by simultaneous confidence intervals, we
inevitably widened our confidence intervals.
Through all these changes of building in greater usefulness and honesty in our estimates
of uncertainty — it is important to notice — the grand mean for each wall was Jeft unchanged.
This we took as given, and tried to do as well as we could in fitting it out with an appropriate
measure of uncertainty.
15. Auxilliary Comment
In practice, especially on the burner wall, the number of measurements made in a level is
not the same for all levels. We have abstained from recognizing this explicitly. Instead we
have treated alike the level means for any given wall, making no explicit allowance for how
many observations were made on each Jevel. Beside simplicity and clarity of analysis, there are
a number of reasons why this is reasonable, and perhaps even necessary. In particular:
(A) The variability of any one level mean is dominated by the variance of the associated cali-
bration (since with roughly 4 to 10 measures per level we are dealing with something
between cr,24• — w2B and rr<2^ Tjr0"^ anc* s'nce b°tn reason and data analysis indicate
rr2 > o-2w/2). Thus the variances of the level means are much nearer to being equal than
they are to be inversely proportional to the number of measurements.
(B) Differences of the variances by factors of less than two rarely have important repercus-
sions of any sort,
(C) The relation
—
n
applies so long as the averages of the y's are the same, and the /s are uncorrelaled, how-
ever alike or different the variances may be. (The similar relation for mean-square-
successive differences will be only approximate, but its approximateness arises mainly
89
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because of the behavior of the first and last levels, which levels play distinctive roles —
and which levels usually have plenty of measurements.)
(D) An analysis based on estimating cr,2 and o-,?, separately, and then using the ratio of these
estimates to assign weights to the different levels would be (a) at best complex, (b) less
resistant and more subject to perturbation by oddities, (c) less well understood.
In view of alt these points, choosing the equally-weighted mean of level means seems the
course of wisdom and conservatism.
We could here have replaced, and might often need elsewhere to replace, means by
modem robust/resistant estimates of location. All the same considerations would apply.
16. Calibration Checking
When is u "calibration" rcully a calibration for statistical purposes? Is putting the gauge
on the test block and saying "Ahh, it's still the same!" a calibration? This depends on what is
written down, and on how what is written down is used.
A calibration, statistically speaking, occurs when something'is done which can shift all the
measurements that follow — or precede. If we spin away the adjusting knob, and use the test
block to help us set it back where it should be, that is surely a calibration, if we put the gage
on the test block, and say "it's reading 0.3 mils high," this is a calibration if and only if we
subtract the +0.3 mils from all the measurements to which this "calibration" applies. If we
merely check the gauge on the test block, and.say "it checks closely enough" we dare not con-
sider this an independent calibration. For no one would: argue that following a setting-
adjustment calibration, taking 8 such checks would reduce the variance of our calibration by
division by a factor of 9.
To measure better, when calibrations are needed and calibration variance is an important
contributor to overall measurement, we have to have more .calibrations that are independently
arrived-at calibrations.
Reference
Morse, A. P. and Grubbs, K (1947). "The estimation of dispersion by differences," Annals of
Mathematical Siatistk-.s 18: 193-214.
Rather more details of the analysis of the Widow's Creek No, 5 data will appear in the
appendix of a forthcoming R.P.A. report.
90
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Exhibit 1
Row Means and Two Successive Differences
For Apparent Thickness Change: Side Walt of B Furnace,
Widow's Creek No. 5
Level
1
2
3
4
5
6
7
8
9
10
11
Row
Mean
2.86
-2.86
10.00
4.29
2.14
11.43
-15.71
-14.29
-20.71
-29.29
-24.29
First
Difference
5.71
-12.86
5.71
2.41
-9.29
27.14
-1.43
6.43
8.57
-5.00
Second
Difference
18.57
-18.57
3.57
11.43
-36.43
28.57
-7.85
-2.14
13.57
:
Sum of
Squares 2597.81
(sum) (-76.43)
1199.89
3226.82
Hxamples: 5.71 =» 2.86~(-~2.86), -12.86 - -2.86-UO.OO), ...
18.75 - 5.71- (-12.86), -18.57 12.86-(5.7I), ...
Note: The choice of algebraic sign for the differences can be arbitrary, so long as ii is
consistent.
91
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Exhibit 4
Illustration of Effect of Changing from Individual to Simultaneous
Confidence Intervals, Apparent Changes in Tube Thickness,
Widow's Creek No. 5
A) FULL-WALL MEANS
± for Confidence Interval
Furnace
A
B
Wall
Side
Division
Front
Burner
Side
Division
Front
Burner
Individual
±3.1
±3.8
±2.6
±5.2*
±5.6
±3.3
±5.5
±4.3
Simultaneous
±'*1
.±6.1
±4.3
±8.8**
±9.0
±5.3
±8.8
±6.9
Note: Simultaneous intervals are for k—%,
* ±4.6 if second successive differences used.
** ±8.3 if second successive differences used.
B) A few HALF-WALL MEANS
± for Confidence Interval
Furnace
A
B
Wall
Side
Front
Side
Half
Top
Top
Bottom
Bottom
Top
Individual
±4.6
±3.4
±3.4
±8.2
±5.0
Simultaneous
±7.4
±5.7
±5.7
±13.0
±7.5
Note: Simultaneous intervals arc lor A-16.
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SESSION III:
SPECIAL TOPICS
DAVID G. LACHAPELLE
CHAIRMAN
93
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-------
PANEL:
COMBUSTION SOURCE/AIR POLLUTION REGULATIONS — PRESENT AND PROJECTED
1 -- Federal Regulations
Jack R. Fanner
2 -- Regional Regulations
Robert Duprey
95
-------
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FEDERAL REGULATIONS
By:
J. R. Farmer
Environmental Protection Agency
Office of Air Quality Planning and Standards
Standards Development Branch
Research Triangle Park, North Carolina 27711
97
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ABSTRACT
The key provisions of the Clean Air Act which affect stationary
sources of combustion are discussed. Primary emphasis Is placed on
section 111, standards of performance for new stationary sources. The
current standards and plans for future standards are also discussed.
98
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INTRODUCTION
It's a pleasure to have this opportunity to discuss EPA's regulatory
program for combustion type stationary sources. EPA gives high priority
to regulating emissions from these types of sources, because they are
major sources of emissions of sulfur dioxide, particulate matter, and
nitrogen oxides.
The Clean Air Act contains several regulatory provisions; however,
sections 110 and 111 are the most applicable to combustion type stationary
sources. Section 110 pertains to State Implementation Plans and section
111 pertains to new source standards of performance. I will limit my
comments to new source standards of performance, and Mr. Duprey, the
next speaker, will discuss the State Implementation Plans. I will
discuss the recent amendments to section 111 of the Act, the current
standards of performance, and the future standards of performance.
CLEAN AIR ACT AMENDMENTS OF 1977
On August 7, 1977, President Carter signed into law the Clean Air Act
Amendments of 1977. The amendments represent two and one-half years of
effort by the Congress. Extensive amendments to the Act were last
enacted in 1970. At that time, Congress established a broad program to
achieve steady reduction of pollutants from both stationary and mobile
sources. The 1977 Amendments are designed to continue that program, and,
at the same time, provide n mechanism to continue economic growth.
The 1977 Amendments address many complex and controversial issues
which have developed as a result of Implementing the 1970 Amendments.
I will briefly review the amendments pertaining to section 111, new
source standards of performance.
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In presenting the amendments to the Senate, Senator Muskie said:
"Under the Clean Air Act Amendments of 1971 [1970],
section 111 requires that EPA promulgate performance
standards reflecting the best system of emission limita-
tion for new sources. Congress had several reasons for
including this requirement. First, standards with a
degree of uniformity are needed to avoid situations where
some States may attract industries by relaxing standards
relative to other States. Second, stringent standards
enhance the potential for long term growth. Third,
stringent standards may help achieve long-term cost
savings by avoiding the need for more expensive retro-
fitting when pollution ceilings may be reduced in the
future. Fourth, certain types of standards for coal
burning sources can adversely affect the coal market by
driving up the price of low-sulfur coal or effectively
excluding certain coals from the reserve base because
their untreated pollution potentials are high. Congress
does not intend that new source performance standards
contribute to these problems. Fifth, the standard-setting
process should create incentives for improved technology."
The 1977 Amendments made the following important changes to section 111:
1. By August 7, 1978, EPA is required to list the categories of major
stationary sources which have not already been listed and regulated under
standards of performance. Regulations must be promulgated for these new
categories on the following schedule:
25 percent of the listed categories by August 7, 1980
75 percent of the listed categories by August 7, 1981
100 percent of the listed categories by August 7, 1982
A Governor of a State may apply to the Administrator to add a category which
is not on the list or to revise an existing standard of performance.
2. EPA is required to review the standards of performance every four
years, and if appropriate, revise them. A separate provision requires EPA
to promulgate revised standards of performance for fossil-fuel fired
steam generators by August 7, 1978.
3. EPA is authorized to promulgate a design, equipment, work practice,
or operational standard when .-in emission standard Is not feasible.
4. The term "standard of performance" is redefined and a new term
"technological system of continuous emission reduction" is defined. The new
100
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definitions clarify that the control system must be continuous and may
include a low-polluting or nonpolluting process or operation. They also
require that standards for fossil-fuel fired stationary sources include
both an allowable emission limit and a percentage reduction. Any cleaning
of the fuel or reduction in the pollution characteristics of the fuel
after extraction and prior to combustion may be credited in meeting the
standards.
5. The Administrator is authorized to grant waivers from the require-
ments of standards of performance when innovative technology is used.
To receive a waiver, an owner or operator must demonstrate to the
Administrator that the proposed control system has not been adequately
demonstrated; that its operation will not contribute to an unreasonable
risk to public health, welfare, or safety; and that there is a substantial
likelihood that the system will work effectively.
6. Regulations established by a State or EPA which cover designated
pollutants (e.g. fluorides and sulfuric acid mist) must Include consideration
of the remaining useful lives of the sources.
7. Country grain elevators having a storage capacity of less than two
and one-half million bushels are exempt from standards of performance.
8. Units that are ordered to convert to coal are exempt from the
requirements of standards of performance.
9. States are authorized to enforce standards of performance against
sources owned or operated by the U. S. Government.
We are reviewing our current program in light of these amendments
and are planning the actions needed to implement the new requirements.
CURRENT STANDARDS
To date standards of performance have been promulgated for 24 source
3
categories and have been proposed for three additional source
456
categories. ' ' Emissions from five combustion type stationary sources
are affected by these standards:
(1) Fossil-fuel fired steam generators.
(2) Municipal Incinerators.
101
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(1) Sewage sludge incinerators.
(4) Waste heat boilers and fuel gas combustion devices in petroleum
refineries.
(5) Recovery furnaces in kraft pulp mills.
Standards of performance for fossil-fuel fired steam generators
and municipal incinerators were promulgated in December, 1971. Several
revisions have been made to the standards for fossil-fuel fired steam
generators over the years. Most recently, a standard was proposed to
limit nitrogen oxides emissions from the combustion of lignite. A final
standard for lignite should be promulgated around November, 1977.
The standards for sewage sludge incinerators and combustion devices in
petroleum refineries were promulgated in March, 1974. Standards for
recovery furnaces in kraft pulp mills were proposed September, 1976, and
should be promulgated around November, 1977.
In terms of legal actions against EPA, six of the 24 standards have
been litigated. The six are (1) fossil-fuel fired steam generators,
(2) sulfuric acid plants, (3) portland cement plants, (4) asphalt concrete
plants, (5) primary copper smelters, and (6) primary aluminum reduction
plants. Only two of these cases, portland cement plants and asphalt
concrete plants, have been completely resolved.
In the case involving the fossil-fuel fired steam generator standard,
the U. S. Court of Appeals for the District of Columbia found that the
record generally supported the standards, but remanded the following
three issues for further consideration:
(1) the need for provisions that unavoidable excesses of the standards
during startup, shutdown or malfunction not be considered violations;
(2) the adverse environmental effects of setting a standard that
requires coal-fired power plants to use a lime slurry scrubbing
system; and
(3) the reasonableness of the opacity standards.
The startup, shutdown, and malfunction issue was resolved in October,
1973, when EPA promulgated regulations which, in effect, suspend the
standards during startups, shutdowns, and malfunctions. EPA's final
102
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response to the Issue concerning the adverse environmental effects of dis-
posing of thR «1iidgc generated by the use of lime slurry scrubbing systems
will !><-• publlahod l.n lbo very ncur future. Part of the opacity issue la
similar to one raised in the suit on the portland cement plant
standards, where the court upheld EPA's position on opacity. The
other part of the opacity issue Involves the specific standard for
fossil-fuel fired steam generators. We will address this issue along
with the scrubber issue and promulgate a final opacity standard for
fossil-fuel fired steam generators.
EPA has a Compliance Data System which is used to keep a record
of the sources subject to Agency and State regulations. According to the
information in this system, there are 1742 sources covered by the 24 final
standards of performance. About 78 percent of these are in compliance
with the standards. The remaining 22 percent are in various stages of
compliance or noncompliance. The number of combustion type stationary
sources covered are as follows:
141 fossil-fuel fired steam generators.
12 municipal incinerators.
29 sewage sludge incinerators.
10 waste heat boilers or fuel gas combustion devices.
FUTURE ACTIONS
Although 27 source categories have been listed, there are many other
major stationary sources which will be listed and covered by standards of
performance. As indicated earlier, the Clean Air Act Amendments of 1977
require EPA to establish standards of performance for all major stationary
sources by August 7, 1982, and to review all existing standards at four
year intervals and revise them if appropriate.
For stationary source combustion categories, our immediate plans are to
liet and develop standards for gas turbines, stationary internal combustion
engines, and industrial boilers.
Standards of performance for gas turbines will be proposed in the
Federal Register within the next few days. Standards for stationary
internal combustion engines are scheduled to be proposed in the summer
103
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of 1978. Standards for industrial boilers are in the preliminary stages
of development and a definite date has not been established for their
proposal.
One of our most important projects is revision of the fossil-fuel
fired steam generator standards. In addition to being required by the
Clean Air Act Amendments of 1977, the Sierra Club and the Navajo Tribe
petitioned EPA on August 6, 1976, to tighten the standards to require
90 percent reduction in SO- emissions from new power plants. We have begun
a study to complete the technological, economic, and other documentation
needed to make appropriate revisions to the standards for SO., particulate
matter, and nitrogen oxides. Several contractors and EPA personnel are
working on this project, and we plan to propose the revisions by early 1978.
The major areas of investigation are: (1) assessment of the SO- removal
efficiencies of flue gas desulfurization systems (FGD); (2) collection
of continuous SO- emission data at the inlets and outlets of one to three FGD
systems installed at domestic power plants over periods ranging from one
to three months; (3) investigation of methods of sludge disposal and fixation,
and techniques to treat waste water or reuse it within the power plant; (4)
determination of the effectiveness of particulate matter control systems;
(5) determination of the costs and economic impact of alternative standards
and control systems; (6) assessment of the secondary environmental impacts
of alternative control systems on energy and solid waste, water, and air
pollution; and (7) assessment of the Impact of alternative control systems
on coal marketing. The necessary information on nitrogen oxides control
systems has already been collected.
Another important but complicated project under development involves
defining the requirements of the current SO- standards for fossil-
fuel fired steam generators when low sulfur coal rather than a FGD system
is used. The standard docs not specify the sampling and analysis
procedures or the averaging times to use with low sulfur coal. We plan
to propose regulations in the next few months which will establish
requirements for these areas. This project addresses the current
standard and is not directly Involved in the project to revise the
standards.
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SUMMARY
In Humtwiry, new wourc.u Htandards of performance are an integral part
of the olr quality management approach established by the Clean Air Act.
Basically, the air quality management approach Is required for the attainment
and maintenance of national ambient air quality standards. Although
State Implementation Plans based on current knowledge must be pursued under
the Act, mastery of air pollution caused by pollutants such as partlculate
matter and oxldants may be a longer term affair and may eventually
depend simply on widespread application of good source control. In this
regard, new source standards of performance operate like automobile
standards. They are the least costly way of applying source controls
over the long term. They allow consideration of economic Impact at the
time standards are set, they minimize the possibility of continually
changing emission limitations, and they provide information on control
needs at the time industry makes decisions.
105
.
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REFERENCES
1. Conference Report on H. R. 6161. (H, R. ept. 95-564), "Congressional
Record - House", August 3, 1977. pp H 8507 - H 8559.
2. "Congressional Record - Senate", August 4, 1977. pp S13701.
3. Chaput, L. S., Federal Standards of Performance for New Stationary
Sources of Air Pollution, A Summary of Regulations, "APCA Journal,
November 1976. pp 1055 - 1060.
4. Standards of Performance for New Stationary Sources, Kraft Pulp Hills.
Federal Register. Vol. 41, No. 187, September 24, 1976. pp 42012 - 42028.
5. Standards of Performance for New Stationary Sources, Grain Elevator.
Federal Register. Vol. 42, No. 9, January 13, 1977. pp 2842 - 2848.
6. Standards of Performance for New Stationary Sources, Lime Manufacturing
Plants. Federal Register. Vol. 42, No. 85, May 3, 1977. pp 22506 -
22510.
106
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EXISTING STATIONARY COMBUSTION SOURCE
AIR POLLUTION REGULATIONS
By:
R. L. Duprey
Region V
U.S. Environmental Protection Agency
Chicago, Illinois 60604
107
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This is an opportune time to review the present and projected air pollution
control regulations that affect combustion operations. On August 7, 1977,
President James Carter signed into law the 1977 amendments to the Clean Air
Act. These amendments will have far-reaching implications for combustion
sources and fuel usage in this country. Some major shifts in policy as well
as confirmation of present direction in policy is evident in the 1977 amend-
ments. This paper reviews the past efforts at air pollution regulation of
combustion operations and outlines how the amendments will affect stationary
combustion sources.
1970 CLEAN AIR ACT AMENDMENTS
In order to explain the basis for U.S. Environmental Protection Agency (USEPA)
policies affecting emission control requirements for stationary combustion
sources, I would like to spend a few moments reviewing some of the provisions
of the 1970 Clean Air Act as amended, because those amendments laid the founda-
tion for cooperative Federal-state air pollution control programs as we know
them today.
The Act directed the Administrator of the USEPA to establish ambient air
quality standards for pollutants which were known to adversely affect human
health and welfare, these standards were to reflect the maximum amount of
specific pollutants which could be present in the air we breathe. National
ambient air quality standards were set for sulfur dioxide (S02>, total suspended
particulates (TSP), carbon monoxide, (CO), photochemical oxidants (Ox), and nitro-
gen oxide (NOX) in August of 1971. This paper is limited to regulatory programs
aimed at controlling S02, TSP, and NOX, since these are the pollutants of primary
concern from stationary combustion operations.
108
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The Clean Air Act went on to require each state to adopt, after public
hearing, State Implementation Flans containing detailed strategies and emission
control regulations designed to meet and maintain the National Ambient Air
Quality Standards (NAAQS). Each plan had to be submitted to USEPA for review
and approval. Most plans were approved by July of 1972. With respect to
combustion operation, these state plans called for compliance with particulate
matter and sulfur dioxide restrictions by July 1975, with provision for exten-
sions to be granted up to July 1977. Except for the Los Angeles and Chicago
areas, no NOX regulations were required for existing sources, since all other
areas were attaining the NOX ambient standard.
CURRENT PARTICULATE AND SULFUR DIOXIDE REGULATIONS
For particulate matter, current emission regulations range from about 0.8 pounds
per million BTU of heat input to 0.05 pounds per million BTU, depending on
the state, specific geographic area, and capacity of the combustion operation*
For large power plants, high performance electrostatic precipitators or wet
scrubbers are required to meet these limits.
For sulfur dioxide, emission limits vary considerably more from state to
state for existing facilities. As examples, current Illinois regulations allow
emission of 1.8 Ibs. of sulfur dioxide per million BTU actual heat input in
the major metropolitan areas of Chicago, Peorla, and St. Louis. In other areas
of the State, maximum emissions limits are generated by a formula based on plant
characteristics. The average emission limit is 5.0 Ibs. of sulfur dioxide per
million BTU with a maximum of 6 Ibs. Pennsylvania, second only to Ohio in
total coal consumption, allows 0.6 Ibs. sulfur dioxide per million BTU in
Pittsburgh and Philadelphia, and 1.8 Ibs. per million BTU in medium size cities.
Other areas of the State are limited to 4.0 Ibs. per million BTU. West Virginia
109
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allows 1.6 Ibs. per million BTU in Charleston and 3.1 Ibs, per million BTU
statewide. Regulations newly developed by USEFA for the State of Ohio allow
1.0 to 1.9 Ibs. per million BTU in the Cleveland area and 2.0 Ibs. per million
BTU in Youngstown. Other areas of the State have allowable emissions which
range between 1.2 and 6.0 Ibs. per million BTU. Effective next year, the
State of Michigan will allow a maximum of 1.91 Ibs. sulfur dioxide per million
BTU statewide. The emission limit (New Source Performance Standard) for new
coal-fired power plants constructed after December 1971 is 1.2 Ibs. sulfur
dioxide per million BTU nationwide. This is a Federal requirement which does
not vary state by state.
COMPLIANCE STATUS
Compliance with these emission restrictions has been characterized by
mixed success. Within the midwest region of USEPA,. where over 30% of the
nation's industrial capacity is located, compliance by industry with partlculate
and sulfur dioxide restrictions is 85%. However, in the State of Ohio, overall
compliance is only 60%. Many utility and industrial boilers are currently in
violation of both particulate and sulfur dioxide requirements in certain areas.
The situation with respect to improvement in air quality is also mixed.
The trend for both particulate matter and sulfur oxides is definitely Improved.
The population exposed to levels above the national particulate standards has
been reduced from 45% to under 30% from 1970 to 1974. About 50% of the total
suspended particulate Hites, however, still remain above the standards. For
sulfur dioxide, the annual ambient standard has been nearly attained in most
areas of the country. A significant exception area is the State of Ohio, where
annual averages violations are experienced in several major cities. Isolated
no
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short-term (24-hr.) violations also still exist near some major sources in
various states. Overall violations of sulfur dioxide standards have decreased
by an average of 30% since 1970. NOX ambient levels have generally been below
the annual ambient standard of 100 micrograms per cubic meter, but are approach-
ing the standard in several major cities.
THE 1977 AMENDMENTS TO THE CLEAN AIR ACT
The 1977 amendments to the Clean Air Act will have far-reaching effects
on air pollution regulation of industry, including the utility and industrial
combustion operations. Areas cleaner than the national standards are governed
by a system of air quality Increments designed to prevent significant deteriora-
tion of air quality. Non-attainment areas will be subject to provisions calling
for tightening of current emission restrictions while permitting growth only if
the new facility can offset its Increased emissions by providing for controlling
existing facilities (known as the USEPA Offset Policy).
PREVENTION OF SIGNIFICANT DETERIORATION
The amendments require plan revisions by the states to prevent significant
deterioration. The amendments establish three land classifications related to
specific allowable increases in total suspended particulates and sulfur dioxide
over background concentrations.
Class I increment** are set to protect pristine areas, Class II to allow
some development, and Class III to permit more intensive growth.
The amendments prescribe the following specific Increments:
m
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(b)(1) For any class I area, the maximum allowable increase of sulfur
dioxide and particulate matter over the baseline concentration of such pollutants
shall not exceed the following amounts:
Pollutants
Farticulate matter:
Annual geometric mean
Twenty-four-hour maximum
Sulfur dioxide:
Annual arithmetic mean
Twenty-four-hour maximum
Three-hour maximum
Maximum allowable Increase (in
micrograms per cubic meter)
5
10
2
5
25
(2) For any class II area, the maximum allowable increase of sulfur
dioxide and particulate matter over the baseline concentration of such pollu-
tants shall not exceed the following amounts:
Particulate matter:
Annual geometric mean
Twenty-four-hour maximum
Sulfur dioxide:
Annual arithmetic mean
Twenty-four-hour maximum
Three-hour maximum
19
31
20
91
512
(3) For each class III area, the maximum allowable Increase in concen-
trations of sulfur dioxide and particulate matter over the baseline concentration
of such pollutants shall not exceed the following amounts:
Particulate matter:
Annual geometric mean
Twenty-four-hour maximum
Su3fur dioxide:
Annual arithmetic mean
Twenty-four-hour maximum
Three-hour maximum
37
75
40
182
700
112
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The law establishes as mandatory Class I areas all international parks,
national wilderness areas and national memorial parks over 5,000 acres;
national parks over 6,000 acres in existence upon enactment, and any Class I
area established through USEFA redesignation procedures before enactment.
Fossil fuel-fired steam generating plants and boilers greater than 250
million BTU per hour heat input are subject to the Act's significant deteriora-
tion provisions.
NON-ATTAINMENT AREAS
With respect to areas exceeding particulate matter and sulfur dioxide
national ambient standards, a state may approve new construction permits prior
to July 1979 only if the source applies USEPA's offset policy. That is, the
increased emissions from the new facility must be offset by further reduction
in emissions from existing facilities below the levels currently specified in the
approved State Implementation Plan.
No later than January 1979, each state must submit to the USEPA a revision
to their state plan to provide for attainment of the national ambient standards
for particulate matter and sulfur dioxide and nitrogen dioxide, if required, no
later than December 31, 1982. After July 1979, a state must have in effect an
approved plan revision from USEPA in order to issue new construction permits
in non-attainment areas. Provisions for carbon monoxide and hydrocarbon-
sources are somewhat different but are not discussed here, since these contami-
nants fall outside the purview of this paper.
SPECIAL PROVISIONS AFFECTING FUEL COMBUSTION
The amendments settle a number of controversial Issues affecting fuel-burning
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sources. The amendments limit credit allowed sources for stack height and
require existing combustion sources to use continuous emission control
rather than Intermittent or supplemental controls as final control strategies.
Congress, In effect, has determined that flue gas desulfurization is feasible
and demonstrated technology to meet required emission reductions for sulfur dioxide.
A most novel provision in the amendments gives a Governor .or the
President the authority to require compliance with State Implementation Flan
requirements by continuing to use local or regional available coal. The pur-
pose of this amendment is to prevent regional economic disruption or unemploy-
ment. The effect again is to require the use of flue gas desulfurization or
equivalent technology rather than allow importation of natural lower sulfur
fuel as the means of compliance.
It should be clear that the 1977 amendments will provide new impetus and
direction to the national air pollution control effort. Greater technological
innovation will be necessary to meet these new Requirements. This can be best
stated by a quote from Senator Muskle in commenting on these amendments as
follows:
"This conference report is a composite that meets the public
!
interest test. Most important of its provisions are, in my
opinion, Senate requirements applicable to stationary sources.
These provisions seek to put an end to the first round of
efforts to circumvent emission control efforts by establishing
new deadlines for existing Industrial sources and penalties
for failure to meet these new deadlines. There are clear
messages In this Bill. The first message is to the Nation's
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major industries. It can be taken from the amendment to
which I just referred. That message is that the time for
talk is over - the time for compliance is here. The health
of the people can wait no longer."
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SESSION IV:
STATIONARY ENGINE AND INDUSTRIAL PROCESS COMBUSTION SYSTEMS
JOHN H. WASSER
CHAIRMAN
117
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EMISSION CHARACTERISTICS
OF
SMALL STATIONARY DIESEL ENGINES
By:
J. H. Wasser and R. M. Statnick
Industrial Environmental Research Laboratory-RTP
Environmental Protection Agency
Research Triangle Park, North Carolina 27711
119
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INTRODUCTION
The Combustion Research Branch (CRB) of EPA's Indus-
trial Environmental Research Laboratory-RTF has recently
initiated both contract and in-house investigations for
stationary reciprocating internal combustion engines. This
paper will describe the initial phase of the in-house re-
search program in this field. The work was directed at
increasing understanding of air pollutant emissions from
small stationary diesel engines and involved the use of
emulsified fuel and a catalytic reactor as emission control
methods to be evaluated.
EXPERIMENTAL APPROACH
A series of experiments were designed to evaluate the
emissions from a small diesel engine, the effects of emulsi-
fied fuel on these emissions, and the emission characteris-
tics of a catalytic reactor incorporated in the engine
exhaust system. Table I outlines the experiments conducted.
All experiments were run in random order and daily baselines
were determined to eliminate atmospheric condition effects
on emission levels.
EXPERIMENTAL SYSTEM COMPONENTS
The diesel engine used for this study is the prime
element in an electrical generator package. This engine is
a Caterpillar model D334, indirect injection, turbocharged
and aftercooled, 4 stroke cycle, six cylinder diesel with
638 in.3 (1.045 X 10~2 m3) displacement rated at 165 kW
electrical output for continuous service. Other pertinent
data includes:
Bore: 4.75 in. (120.6 mm)
Stroke: 6.00 in. (152.4 mm)
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Compression Ratio: 17 to 1
Dry Weight: 2390 pounds (1084 kg)
Standard Timing: 14* BTDC
From the combustion standpoint, the important design
characteristic is the precombustion chamber. The prechamber
to total TDC volume ratio is approximately 0.3. In addition,
the fuel injection pump output is controlled to maintain a
constant engine speed (1800 PPM) under varying work loads.
There are four in-head valves (two inlet - two exhaust) per
cylinder. The engine is water cooled.
The catalytic reactor used in this study is an Engelhard
Industries PTX-643D. This unit is a platinum metal catalyst
deposited on a unitary porous ceramic support with a honey-
comb construction. The catalyst is enclosed by an Inconel
band and a stainless steel outer housing.
Ambient air is drawn into the machine's air inlet by
the cylinder action and by the turbocharger. The turbo-
charger maintains an inlet manifold pressure of 16 psig
(110.3 kPa) when operating at the rated full load, and is
powered by the engine exhaust flow. Air is compressed by
the piston action to approximately 250 psig (1723.5 kPa).
Fuel is injected at approximately 650 psig (4481.1 kPa).
Combustion gases flow from the cylinder chamber through the
turbocharger and a muffler (either conventional or cata-
lytic) to the exhaust stack.
Engine load is provided by an AVTRON model K463 load
bank connected to the electric generator. This equipment
provides electric load demands up to 225 kW in 5 kW incre-
ments .
The fuel used in the engine is a No. 2 diesel oil with
an API gravity of 34.5 degrees. The bound nitrogen content
of this fuel IB only 0.04% {wt), thus fuel nitrogen con-
version to NO is not a major factor in the emission levels
f-
measured in this study. The sulfur content is 0.12% (wt) ,
sufficient to create the potential for significant sulfate
121
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(SO,, SO ) emissions when a catalytic reactor is used with
the engine to control CO and hydrocarbons. Other fuel
properties were:
Carbon: 87.05% (wt)
Hydrogen: 12.71% (wt)
Ash: Trace
Higher Heating Value: 19,663 BTU/lb (45.74 MJ/fcg)
Density: 0.8354 gm/cm3 @ 100* P (311.IK)
Viscosity: 2.24 centipoise (2.24 mPa • s)
0 100° F (311.IK)
ANALYTICAL SYSTEM
Methods for determining the gaseous and particulate
emissions from the diesel engine were identical to those
previously used by the author in gas turbine, boiler, and
experimental combustor studies. Table II lists the instru-
ments used for each flue gas component measured.
In addition to these methods, sulfates were determined
using the Goksoyr-Poss controlled condensation coil. This
method collects both SO and sulfates. The total sulfur
accountability with this method ranged between 80 and 85%
based on the fuel sulfur content of 0.12% (wt). These
sulfate measurements were made for CRB by lERL-RTP's Process
Measurements Branch personnel.
The original, small-diameter, horizontal exhaust pipe
on the engine was replaced by a larger-diameter stack exten-
sion downstream from the muffler. The extension was a 12 ft
(3.66 m) high, 12 in. (304.8 mm) diameter vertical pipe. A
sampling port in the extension was used for all particulate
and sulfate traverse samples.
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IMPORTANT OPERATING CHARACTERISTICS
SOUND LEVELS
Noise levels emanating from the diesel were measured to
determine the sound exposure that would be experienced by
personnel operating the engine and sampling equipment. The
decibel level was found to change with electrical load on
the machine. Two locations were selected for sound measure-
ment: (1) 4 ft (1.22 m) from the diesel's weather enclosure
with the access doors closed, and (2) at the surface of the
enclosure with the access doors open. Table III lists the
results of the survey made with a standard sound meter using
the "A" weighting to relate to human sound perception.
These measurements indicate that, in the immediate area
of the engine, the maximum permissible personnel noise
exposure time per 24 hour day would only be 27 minutes
without ear protection. In view of these levels, all per-
sonnel in the area are required to wear ear protection at
all times when the engine is running.
PRECOMBUSTION CHAMBER
The precombustion chambers incorporated in this engine
are a unique feature that could have a significant effect on
emission performance. Each of the six cylinders has a small
cylindrical chamber mounted above and connected to the main
chamber by a nozzle-like passage. The fuel injection nozzle
and glow plug for each cylinder are mounted with their
functional sections inserted in the precombustion chamber.
This prechamber design essentially performs the same func-
tion as staged combustion hardware in a boiler. All of the
fuel for each firing cycle is injected into the precombus-
tion chamber. Since only a fraction (3/10) of the combus-
tion air is available in the prechamber, ignition and
initial burning take place under fuel-rich conditions. As
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the rich burning mixture expands through the nozzle into the
main chamber, the rest of the combustion air becomes avail-
able and combustion continues until quenched by gas expan-
sion or wall effects. The primary effect of the prechamber
system is 'a moderation of the peak pressures and tempera-
tures generated in the engine, both of which influence
emission levels.
LOAD PERFORMANCE
The diesel engine used in this study operates with
large quantities of excess air. Excess air changes with
load because both the air and fuel rates change. Atmos-
pheric conditions (ambient temperature, pressure, and
humidity) also affect the mass of air inducted by the
engine, resulting in daily variations in excess air levels.
Table IV contains a typical set of excess air values and
exhaust temperatures recorded over the load range of the
engine.
At full load (165 kW), a typical fuel rate was measured
at 100.6 Ib/hr (45.6 kg/hr). Using the net heat value of
the No. 2 diesel fuel 18,400 BTU/lb (42.8 MJ/kg), the effi-
ciency of the generator set was computed to be 38.8%.
EMISSION CHARACTERISTICS
BASELINE
Nitrogen Oxides
The initial investigation of the diesel engine con-
sisted of measuring the emissions produced by the engine
over its entire load range. These measurements .were made
before any operation or hardware modifications were attempted
to establish the baseline characteristics. This baseline
then served ae a comparator for determining the performance
of any potential emission control methods.
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Baseline emission characteristics for oxides of nitro-
gen (NO ) are presented in Figure 1. The actual data curve
Jt
indicates that, as load is added to the machine, NO in-
creases rapidly, experiencing a 104% rise as it reaches a
peak at 40 kW. With further load increase, the NO emission
rate decreases rapidly, reaching a minimum at 120 kVJ that is
approximately 35% higher than the zero load level. As load
is increased to the full load condition (165 kW), the NOy
emission rate increases slightly to a level that is 27%
higher than the zero load condition. The full load NO
X
level is 38% below the peak value measured at 40 kW.
This NO emission pattern presents a different situa-
X
tion than would normally be expected in that most combustion
systems tend to produce NO maximums at or near full load.
3C
The increasing quantity of fuel being burned in the fixed
volume of the combustion chamber continually increases the
combustion intensity and temperatures involved, usually
resulting in increased NO formation. However, in this
engine, the two stage combustion mechanism changes the MO
pattern.
To gain a better understanding of these results, a
multiple linear regression curve fit was calculated using
equivalence ratio (E.R.) and exhaust temperature as the
independent variables. This two-variable regression line is
shown on Figure 1 for comparison with the actual data points
2
The correlation coefficient (R ) for this regression line
was calculated to be 0.68, indicating a reasonable fit but
certainly leaving room for improvement. The equation for
this regression line is
[NO ] - 63.0 - 0.0568 [T ] - 4.54 [E.R.] ,
X 6 X
where INO ] is the NO concentration in grams/kg of fuel,
JT ] is the exhaust gan temperature in Kelvin, and E.R.
is the equivalence ratio based on actual air divided by
stoichiometric air requirements.
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Another multiple linear regression curve fit was cal-
culated adding the specific humidity (H) as an independent
variable in the form of the natural antilog of the recip-
1/H
rocal of the humidity (e ' ). This three-variable regres-
2
sion line is also shown on Figure 1 for comparison. The R
for this regression line was calculated at 0.967 indicating
a significant improvement in fit. The equation for this
regression line is
[NO ] = 78.53 - 0.0983 [T 1 - 4.834 [E.R.] + 2.43 [e
X 6 X
1/H,
where H ie in kg of water/kg of fuel.
By way of analysis, the use of these three variables
has led to a reasonable HO prediction equation for this
engine. However, the exhaust temperature and E.R. are only
"stand-ins" for the real controlling factors. The exhaust
temperature continually increases with load and thus is a
reflection of the thermal regime in the cylinder combustion
chamber. That is, the exhaust temperature has a mathe-
matical function response to load comparable to the com-
bustion zone thermal regime which is actually responsible
for the NO formation. E.R. continually decreases with load
A
and in that response is mathematically comparable to the
effect of staged combustion created by the precombustion
chamber design.
Referring again to the actual data curve, the rapid
increase in NOy from Zero to 40 kW can be considered the
result of the thermal regime's being in control of NO
X
formation. This is plausible in that the relatively small
quantity of fuel injected is finding sufficient oxygen in
the prechamber to burn fuel lean or near stoichiometric. As
the fuel injected per firing cycle increases, there is no
longer sufficient oxygen available in the prechamber and the
staged combustion effect begins to reduce the NO formation.
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The fraction of the total air charge per firing cycle
required for Btoichiometric combustion was calculated for
each load setting. This data is listed in Table V. An
engine prechamber was also measured: its volume is approxi-
mately 30% of the total volume of the combustion chamber at
maximum compression. From this data, a stoichiometric
quantity of air is available in a prechamber up to about 30
kW. This fact tends to support the postulated effect of
staging previously discussed.
The effect of humidity is an inverse relationship with
peak flame temperature, which in turn directly effects NOX
1 /H
emission; thus, the use of e gives a reasonably realistic
mathematical response for this factor in NO formation.
X
Carbon Monoxide and Hydrocarbons
Baseline emission characteristics for CO are presented
in Figure 2. The actual data points indicate that CO levels
are a maximum at zero load and decrease rapidly as load is
added to the machine, until 60 kW is reached. From that
point the CO emissions are nearly constant to the full load
point.
A regression curve was calculated using the natural log
of E.R. as the independent variable. This regression line
is shown on Figure 2 for comparison with the actual data
2
points. The R for this regression line is 0.99, indicating
a close fit. The equation for the line is:
[CO] = 0.853 [E.R.]1'74.
The combustion conditions of higher temperatures and
combustion intensity with Increasing load contribute to
better oxidation of CO. Wall quenching effects and rela-
tively short residence times contribute to the continuing
emission even at high load.
Baseline emission characteristics for gaseous hydro-
carbons (defined as organic compounds that do not condense
at 3D° F C275K)) are presented in Figure 3. The actual data
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points follow a pattern similar to the CO data. Again, a In
vs. In regression curve using E.R. as the independent vari-
able resulted in a satisfactory curve fit. The R was 0.946
for the equation
IHC] = 0.127 [E.R.J
1.133
Basically, the same conditions that control CO emissions are
also responsible for the hydrocarbon emissions. The hydro-
carbon emissions are significantly lower than the CO emis-
sions and do not constitute a major emission problem for
this engine.
Particulates
Particulate data was available for only full load
operation of the diesel engine. The average filtered
particulate loading was measured as 1.9235 gin/kg of fuel. In
addition, condensable particulates amounted to 0.605 gm/kg
in the benzene soluble fraction and 0.489 gm/kg in the water
soluble fraction. The benzene soluble fraction is a rough
estimator for potential emission of high molecular weight
hydrocarbons, many of which are carcinogenic. Cascade im-
pactor tests revealed that 65.35% of the particulate is less
than 3pm, which is in the critical respirable range. Par-
ticulates remain a subject for further study with this
diesel engine.
EMULSIFIED FUEL
Nitrogen Oxides
Because water addition to a combustion process is a
known MO control technique, it was the first emission
control method to be studied on this small diesel engine.
water and fuel were metered separately before mixing and
emulsification in a gear pump. The emulsified fuel was
injected into the engine through the standard fuel system;
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no other modifications were needed. A surfactant was not
used in these tests because emulsion stability was adequate
without one.
The effect of water-fuel emulsification is presented in
Figure 4. In general, the reduction in NO has a 1 to 1
relationship with the water to fuel (W/F) volume ratio. That
is, an increase in W/F produces an equivalent decrease in
the observed NO to base NO ratio (designated R). The
X A
amount of water that the engine would tolerate varied with
load. The maximum W/F for a given load is given in Table
VI.
At each load level, significant reductions in NO can
be achieved by the water addition. At the peak NO emission
load, 40 kw, the NO was reduced by almost 68%. At higher
loads, 80 and 120 kW, the NO was reduced by over 80%. At
X
full load, the machine would only tolerate sufficient water
to reduce the NO level by about 45%.
x
In all likelihood, the NO reduction mechanism is the
X
same for this engine as for other combustion systems. Tem-
peratures are reduced, particularly the peak temperatures in
the combustion zone, resulting in the reduction in NO forma-
tion.
Carbon Monoxide
Water injection with the fuel also affects the emission
levels of CO. This data is given in Table VII.
There is an increase in CO at all load levels, although
this increase is only 10% at full load. At other load
levels, the CO increase ranges from double to 5 times the
level without water addition. This increase is significant
in the load range around 40 kW where the NO peak would most
X
require water injection for control. Again, the reduced
temperatures (which are beneficial in reducing NO ) result
X
in increased CO levels.
129
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CATALYTIC CONVERTER
Effects of the catalytic reactor on engine emissions
are presented in Figure 5. NO emissions were increased by
12 to 20% with a slight rising tendency with load. Emis-
sions of both CO and gaseous hydrocarbons were drastically
reduced. Hydrocarbons were reduced over 80% and CO over 90%
from the baseline at each load condition except zero. At
zero load the temperature averaged about 345 F (447K).
This is below the effective operating temperature of the
catalyst.
In addition to the increase in total NO , the NO to
X *••
NO ratio increased. This data is listed in Table VIII.
x
With the exception of zero load, there was a substantial
increase in the proportion of NO., in the total NO emission.
2 X
Since the function of the catalytic reactor is to promote
oxidation of the combustible flue gas components, it is not
too surprising to find that NO and NO2 were formed also.
Experience with automotive catalyst formation of sul-
furic acid in exhaust effluents mandated a determination of
sulfate emissions from the diesel because the diesel fuel
contains substantially more sulfur than does gasoline. The
sulfate tests were made only at full load operation. Base-
line (without catalyst) sulfate level was near the detection
limit of the procedure and was determined to be 2.5 mg/m
(0.025 gm/hp-hr). The sulfate level with the catalyst was
measured at 123.1 mg/m (1.23 gm/hp-hr), indicating a sig-
nificant increase. Without the catalyst, only 1.1% of the
total sulfur oxides was in sulfate form; the remainder was
SO . With the catalyst, 59.15% of the sulfur oxides was in
Rulfate form. Again this is not unexpected because the
oxidation catalyst should readily convert SO to SO,.
130
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CONCLUSIONS
Based on these results with the Caterpillar D334 engine,
the major air pollution problems for small diesel engines
are the NOX» CO, and fine particulate emissions. The pre-
combustion chamber design was effective in controlling
thermal NO^ emissions above the 40 kW load point.
Water-fuel emulsification had a mixed effect on the
emissions: NO was dramatically reduced (60-80%), but CO
emissions were increased by factors of 2 to 5. Further
study of effects on particulates and fuel consumption is
needed.
The catalytic converter reduced CO emissions by over
90% and hydrocarbons by over 80%. The averse effects of the
converter included a 15 to 20% increase in NO and the
3v
creation of a significant sulfate emission that was not
present in the unmodified engine.
131
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TABLE I. EXPERIMENTAL PROGRAM
Experiment Set
Variables
Study Range
Baseline
Fuel Emulsion
Generator Load
Generator Load
Water/Fuel Ratio
Catalytic Reactor Generator Load
zero to 165 kW at ^ 20 kW interva
zero to 165 kw at «v 40 kW interva
zero to engine limit at 1 gph
(3.785 Lph) water intervals
zero to 165 kW at
40 kW interva
TABLE II. ANALYTICAL INSTRUMENTS
Flue Gas Constituent
Analyzer
co2
CO
Gaseous HC
NO/NO
?t
Particulate Mass
Particulate Size
Beckman Paramagnetic
Beckman NDIR
Beckman NDIR
Beckman Flame lonization
TECO Chemiluminescent
RAC Staksamplr
Andersen Cascade Impactor
132
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TABLE III. NOISE LEVELS
Load, kW
zero
40
80
120
165
dbA @ Location 1 dbA @ Location 2
92
94
94
94
95 111
TABLE IV. EXCESS AIR AND EXHAUST TEMPERATURE WITH LOAD
Load, kW
zero
20
40
60
80
100
120
140
165
Excess Air, %
520.
287.
180.
152.
133.
121.
112.
105.
84.
4
2
4
2
9
5
8
5
7
Exhaust Temperature, °F (K)
345
458
565
662
760
818
860
900
935
(447)
(510)
(569)
(623)
(678)
(710)
(733)
(755)
(775)
133
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TABLE V. STOICHIOMETRIC AIR FRACTION WITH LOAD
Load, kW
Stoichioroetric Air Fraction
zero
20
40
60
80
100
120
140
165
0.161
0.258
0.357
0.397
0.428
0.451
0.471
0.487
0.542
TABLE VI. MAXIMUM WATER/FUEL RATIO WITH LOAD
Load, kw Maximum W/F
zero 0
40 0
80 0
120 0
165 0
.459
.589
.875
.642
.353
134
-------
TABLE VII. EMULSION EFFECT ON CO
Load, kW
zero
40
80
120
165
Maximum W/F
0.
0.
0.
0.
0.
459
589
875
642
353
CO/CO Base Ratio
1.86
3.67
4.94
2.10
1.10
TABLE VIII. CATALYST EFFECT ON N00/NOV RATIO
£ X
Load, kW
zero
40
80
120
165
Baseline NO2/NOX
0.
0.
0.
0.
0.
2105
0361
0244
0180
0471
Catalyst NO2/KOX
0.1214
0.1667
0.3218
0.2342
0.1682
135
-------
CONVERSION FACTORS
cubic inches X 1.6387 X 10
inches X 25.4 - mm
pounds X 4.536 X lo"1 « kg
psi X 6.894 • kPa
-5
m
BTU/lb X 2.326 X 10
-3
MJ/kg
gin/cm x 1000 « kg/m
(°P 4- 460)/1.8 - K
centipoise X 1.0 = mPa-S
gallons X 3.7854 - L
feet X 0.3048 « m
136
-------
V
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&
E
o
1
J3
O
a.
CD
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8
u
2
CO
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01
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I I I I I I I I I I I 1 I I I I I I I I II I I
1 I I I I 1 I II I I 1 I 1
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I
as-
u>
v
O
j, o
8
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fe
CM
130
-------
0 20 40 60 80 100 120 140 160 180 200
LOAD, kW
Figure 3. HC emission characteristics of a precombustion chamber diesel engine.
139
-------
tn
O
01
X
O
z
O
ai
o
o
of
OX
ON/!XON = a
140
-------
01
T>
i_
en
OUVU NOIiVHlN30NODlNVirmOd
141
-------
-------
SESSION V:
ADVANCED PROCESSES
6. BLAIR MARTIN
CHAIRMAN
143
-------
-------
EVALUATION OF COMBUSTOR DESIGN CONCEPTS FOR
ADVANCED ENERGY CONVERSION SYSTEMS
By:
B. A. Folsom, T. L. Corley, M. H. Lobell, C. J. Kau,
M. P. Heap and T. J. Tyson
Energy and Environmental Research Corporation
Santa Ana, California 92705
145
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SECTION 1
INTRODUCTION
This paper addresses the question of optimum combustor design for
advanced power-generating systems incorporating an Integrated coal gasifier.
The utilization of coal via the production of a fuel gas is one alternative
to conventional direct coal-fired steam boilers with stack gas cleanup.
Environmental considerations and improved overall thermal efficiency are two
of the attractive features of coal gasification when compared with conventional
direct firing:
• Sulfur can be removed more readily from the fuel gas as hydrogen
sulflde than can sulfur dioxide from the lean combustion products.
• Gasification of coal produces a fuel which can be utilized con-
veniently in a combined cycle giving an improved overall thermal
efficiency even though there are energy losses associated with
the gasification and fuel cleaning processes.
The improvement in plant performance offered by a gas turbine steam cycle
power plant over a conventional steam cycle is associated with the ability of
the combined cycle to utilize high temperature heat in the gas turbine and
the exhaust heat rejected by the turbine to drive the steam cycle.
Figure 1 presents a simplified schematic of a basic coal gasifier, gas
turbine topping, steam turbine bottoming (COGAS) cycle. Only the major heat,
work and mass transfer paths have been shown for clarity. The single most
important factor in the overall cycle efficiency is the turbine inlet tempera-
ture (TIT). Current maximum allowable TIT for industrial turbines is around
2200 F; however, Improvements in design are expected to extend this limit to
2600 F within a few years. The exhaust temperature from a typical state-of-
the-art stationary gas turbine In approximately 1000 F. This exhaust gas
enthalpy Is used to generate steam in a waste heat boiler in the basic COGAS
146
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cycle. The fuel burned in the gas generator is produced by a pressurized
gasifier and cleanup system. The properties of the fuel gas will depend
strongly upon the gasifier design and cleanup process and less strongly
upon the properties of the input coal. Neglecting the auxiliary steam raising
plant required by the gasification process, the major gaseous emissions are
nitrogen oxides and sulfur oxides. The level of the sulfur oxides are
directly related to efficiency of hydrogen sulfide removal. Nitrogen oxide
emissions are associated both with the product gas cleanup procedures and the
gas generator (combustor) design.
Table I presents the results of a recent EGAS study to illustrate the
projected NO emissions from COGAS systems. Estimates are also presented for
A.
a combined cycle burning a coal-derived liquid fuel. It should be noted that
a fixed thermal efficiency of 74 percent was ascribed to the plant processing
coal to manufacture a liquid fuel. The coal-derived liquid fuel was assumed
to contain 1.3 percent by weight of nitrogen and both low Btu fuels contained
ammonia. The fuel gas for Cycle 3 was produced in a multistage fluidized bed
gasifier with in-bed desulfurization. It was estimated that approximately
15 percent of the nitrogen In the parent coal would appear in the product fuel
gas in the form of ammonia. Cycle 2 utilized an advanced fixed bed gasifier
and a cold gas cleanup system and produced a fuel which contained 0.04 per-
cent by weight of ammonia. A similar plant designed to meet New Source Per-
formance Standards (NSPS) for gaseous fuels would require a complex cleanup
system to reduce considerably the H_S and NH_ content of the fuel gas. It
should be remembered that the emissions listed in Table I are estimates and
that three of them are lower than the NSPS for coal-fired steam plants. How-
ever, the NO emissions are considerably higher than advanced technical
targets for power plants (3) Note that the Westinghouse efficiency estimates
for Cycles 3 and 4 are considerably more optimistic than the General Electric
estimates for Cycles 1 and 2. This is a consequence of different assumptions
regarding component efficiencies and energy losses (gasifier, H_S cleanup,
compressor, turbine, blade cooling, cooling tower, etc.).
Two factors Inherent in the design of high-efficiency COGAS systems tend
to increase nitrogen oxide emissions.
147
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• The use of high turbine inlet temperatures provide conditions
conducive to thermal NO formation and techniques to lower flame
temperature must be included in the combustor design.
• The use of high temperature sulfur cleanup processes does not
remove the major portion of the ammonia from the fuel gas.
Some fraction of this ammonia will be converted to NO during the
combustion process.
The work discussed in this paper represents initial analytical studies which
are the prelude to an experimental program designed to define optimum com-
bustor designs for advanced power generation systems burning low Btu coal-
derived fuel gases. The combustor designs are to be optimized to minimize
pollutant emissions, but maximize overall plant efficiency. A series of
limit-case studies have been carried out to establish the range of combustor
conditions which are likely to minimize NO emissions and the effect on
X
overall combined cycle efficiency of various combustor parameters has been
assessed using a simplified cycle analysis program. The combustor parameters
considered were those which would enable the emission of NO to be minimized
x
either because NO formation was limited by the use of delayed mixing techni-
ques to reduce fuel NO conversion or NO produced in a primary combustor was
reduced in a secondary combustion system. Minimization of the Impact of NO
emission control on overall thermal efficiency or even enhanced thermal
efficiency due to the application of control techniques were the main goals
of the study. Inherent in this total approach is the belief that combustor
\
design optimization offers an fit tractive NO control option to fuel
denltrification for advanced power plants burning coal-derived fuels.
148
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SECTION 2
LIMIT-CASE ANALYSIS TO DEFINE LOW NOY COMBUSTOR DESIGN APPROACHES
A.
It is well-known that the formation of NO by the oxidation of nitrogen
compounds contained in the fuel can be restricted by causing the initial heat
release to occur in fuel-rich regions. This is normally accomplished either
by delaying the mixing of the fuel and air or by dividing the total air into
two streams, one of which is injected downstram of the point of fuel injection.
There are many practical examples of the use of these techniques to reduce
emissions from existing coal, and oil-fired equipment. However, many of these
examples utilized some ad hoc tuning method (biased firing, burners out of
services, etc.) and do not necessarily represent the lower limit of NO pro-
duction achievable with that particular combustion system. The limit-case
studies being carried out as part of this project are planned to aid in the
establishment of a lower limit of NO formation for a given set of combustor
design constraints (e.g., size, pressure, heat extraction and firing low
Btu fuel gas).
Limit-case situations are those in which some single aspect of the
physics or the chemistry dominates and the remaining phenomena can either be
ignored or modeled by simple idealized processes. The term is used in the
context of this study to describe the methodology used to search for the lower
bounds on NO emissions which are set by chemistry. Implicit in this approach
A
is the assumption that all physical processes associated with fuel-air-product
contacting and heat transfer can be accomplished in an ideal and optimum manner
dictated by the chemistry. Having established this chemical-lower-bound the
question then remains of how close one can approach the optimum physical trans-
port behavior in real systems in order to achieve this lower bound.
Fundamental to the success of this approach is an authoritative descrip-
tion of the finite rntc chemistry pertinent to the formation of nitric oxide,
149
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both from molecular nitrogen and nitrogen compounds such as ammonia contained
in the fuel. Therefore, it is particularly important to describe both the
generation and destruction of nitrogen species and their equilibration paths
in rich mixtures. Nitrogen specie formation cannot be decoupled from the heat
release mechanism and the kinetic mechanism used in the limit-case studies
must adequately describe the mechanism of fuel oxidation and the reactions
between hydrocarbon radicals and species containing nitrogen. Since low Btu
fuel gases contain sulfur species allowance should be made for fuel NO /SO
X A
interaction.
The amount of ammonia contained in coal-derived low Btu fuel gases will
depend upon the gasifier design, the coal-to-steam ratio, and upon the fuel
gas cleanup system (1, 2), and this ammonia might well be the major source
of NO. The parameters controlling the conversion of NH_ to NO in combustion
systems are:
- reaction zone stoichiometry,
- flame type, and
fuel type.
Experiments with premixed flat flames tend to indicate that fuel NO conversion
is relatively insensitive to flame temperature (4). Comparison of various
experiments suggests that for fuel/air mixtures close to stoichiometric fuel
nitrogen conversion is greatest with premixed flames and least in laminar dif-
fusion flames. Fuel nitrogen conversion in turbulent diffusion flames and
well-stirred reactors tend to fall between these two extremes illustrating the
importance of the fuel/air contacting process to fuel NO formation.
The calculations discussed later in this section were carried out with a
mechanism that had been compared with data on the production of thermal and
fuel NO conversion in a .let-stirred reactor (5). However, it cannot be
claimed that this mechanism Ls a complete description of nitric oxide forma-
tion and destruction In combustion systems since all the specie concentra-
tions necessary to validate the mechanism were not available. Before discus-
sing some of the initial limit-case analyses it ie informative to describe,
in qualitative terms, the sequence of events which are likely to occur during
150
-------
combustion of fuels containing ammonia, particularly under fuel-rich
conditions. Summarizing the experimental observations It appears that:
nitrogen compounds (even NO) added to hydrocarbon flames are
converted to HCN, and the fraction converted is probably
dependent upon temperature; and
rich combustion products contain HCN, NH. and NO.
A plausible, but not necessarily correct, mechanism includes the Initial
breakdown of NH« via
NH + H + NH + H, (x = 1, 2, 3) (1)
X j\ \. £t
allowing NO production by such reactions as
N + OH -»• NO + H (2)
and CN compounds can be produced by reactions Involving hydrocarbon fragments
and molecular nitrogen or NO:
NO + CH -»• HCN + 0 (3)
N2 + CH •* HCN + N (4)
thus, accounting for the presence of HCN. The oxidation of HCN is most likely
to occur in post-flame gases via the intermediate compound NCO
HCN + H ->• CN + H2 (5)
CN 4- OH •* NCO + H (6)
NCO + H -»• NH + CO (7)
thus, allowing the synthesis of ammonia. The final level of NO and N appears
to be dependent upon competition between two reactions, one forming NO by
oxidation of a nitrogen specie and the other forming nitrogen from the same
specie. Two possible candidates for this competitive path are:
N + OH + NO + H (8)
or
N + NO -»• N2 + 0 (9)
The design of the minimum NO emission staged combustor will attempt to
minimize the total concentration of nitrogen specie (NO, NCO, HCN, CN, NH.)
151
-------
in the rich combustion products. The intent would be to drive the system to
equilibrium which would give a low nitrogen specie concentration. Equilibra-
tion times might be excessive unless the reactant temperature is high. An
alternative approach might well be to use parallel staged systems involving
the mixing of two rich streams under optimum conditions. Another alterna-
tive could involve the production of NO in one combustor which then supplies
vitiated air containing NO to a secondary combustor. If, as is suggested by
reactions (8) and (9), NO itself is a necessary precursor to N« production
partial reburning might well reduce nitrogen specie concentrations to a low
level, but perhaps not to their minimum value, relatively quickly. The
presence of NO during the initial NH~ breakdown might well enhance N_ pro-
duction in the initial reaction zone at the expense of HCN production under
optimum temperature conditions.
An illustration of limit-case analysis is provided by a series of
calculations carried out to define the range of conditions most likely to
minimize NO production in two types of combustors burning low Btu gas. The
combustors were:
a 10 atmosphere gas generator feeding combustion products at
2800 F to a gas turbine, the high temperature low Btu fuel was
assumed to contain 4000 ppm of ammonia; and
a supercharged steam generator operating at 10 atmospheres pro-
viding exhaust products to a low temperature (2000°F) gas turbine.
The fuel for this boiler was assumed to contain 500 ppm NH .
The reactor analogue used in the limit-case calculations for the adiabatic
gas generator is presented in Figure 2. The primary stage consists of a
short, well-stirred ignition reactor followed by a long residence time,
rich hold-up zone to allow time to minimize the concentration of nitrogen
species at the exit. The primary zone is followed by a secondary burnout
zone to give the desired turbine inlet temperature. Temperature control in
the primary zone is achieved by heat transfer to the tertiary air stream
which is fed into the second burnout zone as dilution air.
One aspect of the limit-case calculations carried out with the reactor
analogue shown in Figure 2 was to define those conditions which would minimize
152
-------
the bound nitrogen specie concentration at the exit of the rich primary hold-
up zone. It was found that this minimum value was achieved with equivalence
ratios between 1.3 and 1.45. Also, the nitrogen specie concentration was
independent of the initial bound nitrogen content of the fuel. Consider the
results presented in Figure 3 which show the effective NH« conversion for
adiabatic primary reactors with equivalence ratios varying from 0.45 to 2.0.
The effective NH_ conversion is defined as the difference between the sum of
the nitrogen specie concentration at a given reactor residence time for a
fuel with and without NH_ normalized by the NH_ content of the initial doped
mixture. When this ratio is zero the exit conditions of the primary adiabatic
reactor are independent of the initial NH» content of the fuel. These condi-
tions occur for residence time t, 5200 ms and 0.8 ^ <(> * 1.7. Thus an optimum
rich combustor would operate at an equivalence ratio of approximately 1.35
and have a residence time greater than 200 ms.
Having minimized nitrogen specie concentration at the exit of the primary
hold-up section, the major design challenge involves the addition of second
stage and dilution air without the production of thermal NO. Figure 4 presents
the results of a series of calculations investigating the influence of various
secondary air mixing schemes on NO production. The curves drawn with long
dashes represent the temperature and NO levels associated with instantaneous
mixing, the NO rises rapidly in the first few milliseconds as the nitrogen
specie are converted to NO as the mixture becomes fuel lean. After the initial
rise NO increases slowly due to thermal NO production. The solid line repre-
sents secondary air addition over a 50 ms time period. A temperature excur-
sion to 2300 K occurs and the NO concentration exceeds 1000 ppm before
decreasing back to 850 ppm by final dilution, precisely those conditions which
should be avoided. If the rich products were to be added to the air over a
50 ms period the dot-dash curve is the calculated result. Since fuel is
added to air the mixture temperature increases slowly until the auto-ignition
temperature IB reached nt approximately 40 ms. High temperatures do not occur
and the final NO is the name as the instantaneously mixed case. The short
dashed curves in Figure 4 simulate NO production in a turbulent diffusion
flame with the second stage heat release distributed over a range of equiva-
lence ratios.
153
-------
The limit-case analogue used for a series of staged supercharge boiler
calculations is presented in Figure 5. Heat transfer to raise steam provides
an additional degree of freedom over the adiabatic gas generator since it
allows simultaneous heat release and heat loss in the secondary zone, thus
minimizing residence times at higher temperatures. Figure 6 illustrates the
calculated NO concentration for three limit conditions. Curve 'a1 represents
a system with a 1 ms stirred reactor for ignition followed by a plug flow
section with a heat lose distribution as shown. The fuel and air are pre-
mixed. Curves 'b1 and 'c1 show the effect of operating under staged combus-
tion conditions. The calculated NO concentration shown by curve 'b1 was
obtained with a short residence time stirred reactor feeding a plug flow
section with the secondary air addition distributed over the first 500 ms or
the burnout reactor. In curve 'c1 the rich products are held at an equiva-
lence ratio of 1.15 in a plug flow reactor for 500 ms before secondary air
is added. The increase in NO level associated with the addition of second
stage air is due to NO formation from the bound nitrogen species that exit
the rich reactor. This conversion occurs at the 800 ms station where the
system becomes lean. The difference in the final NO concentration shown
for curves 'b' and 'c' is due to the reduction in bound nitrogen specie
associated with the increased residence time in the rich zone of system 'c'.
154
-------
SECTION 3
COMBUSTOR PARAMETERS AND COMBINED CYCLE PERFORMANCE
In addition to the basic COCAS cycle shown in Figure 1, the performance
of three other variants has been assessed; these :are:
• COGAS Cycle with Duct Heater. Heat is added to the exhaust of
the gas turbine increasing its temperature and allowing the
performance of the steam cycle to improve. From an NO emis-
X
sion control viewpoint it provides an opportunity to pass NO
formed in the gas generator through a reaction zone causing
some reduction in the exhaust NO level. This reaction zone may
be that associated with a diffusion flame or it may be a staged
system encompassing a rich primary zone followed by dilution.
The potential level of reduction is dependent upon the relative
firing rate of the duct heater to the main coinbustor.
• COGAS Cycle with Nonadiabatic Gas Generator. Steam is raised in
the primary gas generator to improve the efficiency of the steam
bottoming cycle. Simultaneous heat extraction, through steam
raising and secondary air staging can suppress peak secondary
zone diffusion flame temperatures thereby reducing thermal NO
generation. In addition, if it should become apparent that the
optimum primary zone temperature is below adiabatic, then steam
raising in this zone could result In lower fuel nitrogen conversion,
• COGAS Cycle with Reheat Combustor. Figure 7 shows a schematic of
a reheat coinbustor COGAS cycle. Reheating increases the power
produced by tlie gas turbine while raising the turbine exhaust
temperature to improve cycle performance. This system offers
several possibilities for NO control.
155
-------
The primary combustor may be operated with minimum
control and the NO reduced in the reheat combustor much
as in the duct heater above.
- Both the primary and reheat combustors can be designed as
staged systems, but as they operate under different condi-
tions their design will undoubtedly be different.
The fuel used by the reheat combustor (produced by a
separate mid-pressure gasifier) could be tailored for low
NO production by maximizing the hydrocarbon content and
minimizing the bound nitrogen content.
A generalized combustor concept wae used for the assessment of the cycle
performance. Each comhuntor Is assumed to have its own separate gasifier
and associated cleanup system operating at combustor pressure, thus allow-
ing the relationship between all inlet and outlet streams to be calculated
without specifying the design details of the gasifier. Coal with composition
CH 0 , steam and air flow into the gasifier which operates at an equivalence
ratio .>1.0 where $ is the mass ratio of coal to air divided by the same
ratio at stoichiometric conditions. The dirty fuel gas flows through a
cleanup system where heat is lost and contaminants are removed. The clean
fuel gas is burned in the combustor at ty~
-------
A simple steam cycle with no reheat or interstage bleed feedwater
heating was used in the analysis of the various COGAS cycles. The steam
cycle was optimized to produce maximum efficiency for a given gas turbine
exhaust temperature. Steam for gasifier injection is bled from the steam
cycle at maximum temperature and throttled to gasifier pressure before
injection. Feedwater makeup was supplied at condenser temperature and blow-
down was neglected. This steam cycle is not necessarily optimum for this
application; however, since the purpose of this analysis was to specify com-
bustor operating parameters and not to predict precise overall cycle effi-
ciency, the details of the steam cycle are of second order importance.
The influence of the following parameters on the performance of the
basic COGAS cycle were assessed initially:
• Turbine inlet temperature (TIT)
• Pressure ratio
• Gas turbine component efficiencies
* Combustor pressure drop
• Coal properties
• Gasifier steam injection
• Gasifier intercooling (low temperature versus high temperature
cleanup)
The first three parameters primarily determine the gas turbine operating
point and their variation demonstrates the tradeoffs in gas turbine and
steam turbine performance. The last four parameters are related to gasi-
fier and combustor design. The analysis was carried out by independently
varying specific parameters and calculating cycle performance while maintain-
ing all other parameters constant. Table II lists the values used for the
various cycle parameters unless the influence of that parameter was being
determined and was varied as part of the analysis.
Figure 8 shows the effect of TIT and gas turbine pressure ratio on the
performance of the basic COGAS cycle. Two extremes were chosen for TIT;
2000°F, typical of current state-of-the-art stationary gas turbines, and
2600°F which is projected for advanced systems. Since increasing TIT
increases both gas turbine cycle efficiency and turbine exhaust temperature
157
-------
(which increases steam cycle efficiency) there is an increase in overall
cycle performance. Figure 8 also shows that in the combined cycle there is
not a strong effect of pressure ratio on overall cycle performance. Although
the gas turbine efficiency is strongly affected by pressure ratio, the trade-
off between gas turbine and steam turbine efficiencies tends to flatten the
performance curve for the combined cycle.
Table III shows the influence of component efficiencies on combined
cycle performance. A base case pressure ratio of 24 was selected, and as
expected decreasing component efficiencies from 85 to 75 percent decreased
the gas turbine cycle efficiency and increased the turbine exhaust tempera-
ture. The increase in steam cycle efficiency and relative power level was
sufficient to substantially counter the decrease in gas turbine efficiency.
Thus, the combined cycle is less sensitive to component efficiency than a
conventional stand-alone gas turbine.
Combustor pressure drop will affect the performance of the gas turbine
cycle and the analysis carried out as part of this study indicated that a
10 percent pressure loss caused a 2.5 percent decrease in gas turbine effi-
ciency. However, the pressure drop across the turbine also decreases and
this increases turbine exhaust temperature and improves steam cycle efficiency.
The net effect is a much smaller drop in overall combined cycle efficiency.
Thus the corresponding decrease in overall cycle efficiency to the 10 percent
pressure loss is only 1.2 percent. This decreased sensitivity to pressure
drop gives considerably more flexibility in combustor design and any incre-
mental increase in pressure drop caused by a low NO design will have a mini-
mum influence upon overall cycle efficiency.
In the previous calculations the sulfur products in the gasifier offgas
were assumed to be removed in a high temperature cleanup process with heat
loss equivalent to 10 percent of the heating value of the parent coal. If a
low temperature cleanup process were to be used, the sensible heat in the low
Btu gas must either be lost to the environment or transferred to other portions
of the combined cycle. Since gasifier offgas temperatures are usually well in
excess of 1200°F, it is wasteful to dissipate the Interceding heat in the
environment. A more economical alternative is to generate steam from the hot
LEG and either inject the steam into the gasifier or operate a steam turbine
158
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power cycle. Figure 9 shows the effects of interceding at 2000 TIT and
pressure ratio 12,0. The best alternative would be to use the intercooling
heat to operate a steam cycle. Such a cycle could operate at 36.9 percent
efficiency, and since this is less than the combined cycle efficiency without
intercooling, overall efficiency decreases with intercooling. A decrease in
overall efficiency of 1.6 percentage points will result if the sensible heat
in the gas is 20 percent of the total coal heat input. If the intercooling
heat is used to raise steam for gasifier injection, overall efficiency drops
3.8 percentage points, and if intercooling heat is wasted it drops 8.9 per-
centage points.
The effects of intercooling at 2600°F TIT and pressure ratio 12.0 are
shown in Figure 10. Using intercooling heat to operate a steam turbine cycle
is again the best alternative, but the minimum losses due to intercooling are
increased to 2.3 percentage points at sensible heat/total heat equal to
20 percent. Intercooling and low temperature cleanup may introduce other
losses including additional process steam, auxiliary power requirements and
the removal of water vapor through condensation.
The previous discussion demonstrated that basic COGAS cycle optimization
requires degrading gas turbine cycle efficiency to improve steam turbine cycle
efficiency. The turbine exhaust temperature from an optimized gas turbine
cycle is too low to raise 1000°F steam. However, since the gas turbine cycle
efficiency is only slightly reduced as pressure ratio varies from the optimum
value, pressure ratio may be reduced increasing turbine exhaust temperature,
steam cycle efficiency and overall combined cycle efficiency.
Heating the gas turbine exhaust in a direct-fired duct heater is an
alternative to reducing pressure ratio. This allows the gas turbine cycle to
operate at its optimum pressure ratio and the steam cycle to operate with
high efficiency. The disadvantage is that fuel burned in a duct heater
bypasses the gas turbine cycle.
Figure 11 shows the estimated performance of two COGAS cycles with duct
healers and high and low turbine Inlet temperatures. The efficiencies are
plot'tad as functiunH of duct heater firing rate normalized to total heat
input. AH the fraction of! he«t used in the duct heater increases from zero
159
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there is an initial decrease in the overall efficiency associated with
bypassing the gas turbine. This is followed by an increase in overall
efficiency associated with the rapid rise in steam cycle efficiency. The
results for a 2600°F TIT are similar to the 2000°F TIT except that less heat
oust be released in the duct heater to reach otpimum conditions for overall
cycle efficiency.
A nonadiabatic combustor supplying hot gas to the turbine and raising
steam for the steam cycle provides an alternative to the use of a duct heater.
The performance of a supercharged boiler 2000°F gas turbine combination is
compared in Figure 12 with a basic COGAS as a function of pressure ratio. At
a pressure ratio of 6.0 the turbine exhaust temperature without supercharging
is sufficient to operate a 1000°F steam cycle and this is the optimum
nonsupercharged pressure ratio. As pressure ratio is increased turbine
exhaust temperature drops and supercharging is required to maintain steam
temperature. Overall efficiency rises to a maximum of 41.42 percent at a
pressure ratio of 10. This is 1.32 percentage points more than that achieved
with a duct heater. The equivalence ratio at optimum is 0.328 which is very
lean compared to previous low excess air supercharged boiler concepts.
Furthermore, the heat transferred through the supercharged boiler to the
steam cycle is only 7.7 percent of the total heat input to the cycle. Thus
the optimum supercharged boiler could be designed much like an adiabatic gas
turbine combustor with additional coils to raise steam.
Figure 13 is similar to Figure 12 except that the TIT has been increased
to 2600 F. The optimum efficiency is achieved with almost zero supercharging
and is only 0.1 percentage points higher than without supercharging. Thus
the desirability of supercharging decreases at high TIT.
A reheat combustor functions much like a duct heater except it is moved
upstream between turbine stages. Figure 7 presents a schematic diagram of
a COGAS cycle with rehuat. The reheat combustor has its own gasifier and .
cleanup system supplied with air bled off the appropriate compressor stage.
The two major vnrlnbleB associated with a reheat combustor are the reheat
pressure and temperature. For a given reheat pressure, Increasing the reheat
temperature Incrteases the mean temperature of heat addition to the gas
160
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turbine (and hence its efficiency). However, reheat temperature is limited
by the same material constraints that limit TIT.
In this analysis a COGAS cycle with 2000°F TIT, a reheat temperature
equal to TIT and a reheat combustor pressure drop of five percent was investi-
gated. Figure 14 shows the effects of reheat pressure with pressure ratio
held constant at 16.0. The performance of a nonreheat cycle is also shown
and is the limit as reheat pressure approaches main combustor pressure. How-
ever, since the pressure drop of the reheat combustor is zero in the limit,
the extrapolation of the reheat curves gives sightly different performance
than the nonreheat case. As reheat pressure is decreased from main combustor
pressure, the turbine exhaust temperature rises improving steam cycle effi-
ciency. Gas turbine cycle efficiency also rises because the increase in mean
temperature of heat addition to the gas turbine cycle overshadows the increase
in turbine exhaust temperature. As reheat pressure is decreased further, the
relative importance of these two effects interchange and gas turbine cycle
efficiency reaches a maximum at a reheat pressure of 7.6 atm and then declines.
Steam cycle efficiency continues to increase with turbine exhaust temperature
reaching a maximum (at the same point as overall efficiency) at a reheat pres-
sure of 6.85 atm.
Figure 15 compares the performance of basic COGAS and COGAS with reheat
cycles as functions of pressure ratio. The reheat pressure selected was the
lowest which produced a 1000 F steam cycle (6.85 atm). Reheat improves both
steam cycle and gas turbine cycle efficiency and the maximum overall efficiency
is 44.60 percent at a pressure ratio of 20. This represents an improvement
of 4.4 percentage points over the non-reheat cycle.
161
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SECTION 4
CONCLUSION
This paper has been concerned with the Initial tasks in a project
designed to assess the possibilities of combustor design to control emis-
sions from advance power plants burning low Btu gas. Gasification allows
coal to be used in an environmentally acceptable manner and when the gasi-
fier is integrated with a combined cycle power plant it also represents an
extremely thermally efficient conversion system. It is known that NO
formation can be limited by combustion modification techniques. This paper
has reviewed the types of control techniques that might be used and also
assessed the Influence of combustor design parameters on cycle performance.
A simplified cycle analysis program has been used to assess the tolerance
of COGAS cycle performance to variations in cotnbustor design. The types of
combustor considered in the analysis were:
- an adiabatic gas generator,
- a reheat combustor,
- a nonadlabatic gas generator raising steam, and
a duct heater for supplementary firing the waste heat boiler.
The study indicates that COGAS cycle performance is not strongly dependent
upon such design parameters as:
combustor pressure drop,
- combustor pressure,
combustor stoio.hiometry (corresponds to the amount of steam raised
in the supercharged boiler, the degree of reheat, or the fraction
of total heat released in the duct heater).
Indeed, cycle performance can be enhanced by the use of a reheat combustor or
a nonadiabatic gas generator which raises steam. The combined cycle perfor-
mance is tolarent of these combustor parameters because heat lost from
162
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the gas turbine is not completely lost to the overall cycle since it can be
used to raise steam in the bottoming cycle which is one of the inherent
advantages of the COGAS cycle.
Low Btu coal gas will probably contain ammonia, some of which will be
converted to NO during combustion. The tolerance of the overall cycle per-
formance to variation in combustor design parameters allows several combustion
modification techniques to be explored to limit NO emissions from advanced
X
COGAS power plants to minimal levels. These techniques include:
- staged main gas generator with temperature control via steam
generation;
staged reheat combustor for minimum fuel nitrogen conversion and
incineration of NO formed in the main combustor; and
- staged or diffusion flame duct burners for minimization of fuel
nitrogen combustion and incineration of NO formed in the main
combustor.
163
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REFERENCES
1. Gorman, J.C. and Fox, G.R., "Energy Conversion Alternatives Study",
General Electric Phase II Final Report, NASA-CR134949, Vol. I,
December 1976.
2. Beecher, O.T. et al, Energy Conversion Alternative Study, Westinghouse
Phase II Final Report, NASA 134942.
3. Martin, G.B. and Bown, J.S., Development of Combustion Modification
Technology for Stationary Source NOX Control Proceedings of National
Conference on Health, Environmental Effects and Control Technology
of Energy Use, EPA Report 600/7-76-002.
4. De Soete, G.G., "La Formation Des Oxydes, D1 Azote dans la Zone
D' Oxidation des Flammes D' Hydrocarbures, IFF, June 1975.
5. Heap, M.P., et al, paper presented at the 16th Symposium (International)
on Combustion, Boston, August 1976.
164
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TABLE I. SUMMARY OK NOX EMISSIONS AND OVERALL CYCLE EFFICIENCY
FOR OPEN CYCLE GAS TURBINE SYSTEMS (AFTER ECAS (1,2))
Cycle Description
NOX Emissions
g/MJ (lb/M Btu)
Overall
Cycle
Efficiency
1. Water-cooled gas turbine
TIT 1922K using coal-
derived liquid fuel (G.E.)
2. Air-cooled gas turbine
TIT 1589K integrated
low Btu gasifier (G.E.)
3. Air-cooled gas turbine
TIT 1644K integrated
gasifier (Westinghouse)
4. Ceramic gas turbine
components TIT 1644K
coal-derived liquid
fuel (Westinghouse)
0.73 (1.7)
0.15 (0.35)
0.18 (0.65)
0.26 (0,6)
37.5
40.0
46.8
38.5
165
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TABLE II. CYCLE ANALYSIS CONSTANTS
Gas Turbine (Topping Cycle)
Inlet temperature/pressure - 59 F/1.0 atm
Coal - CHQ 800 L, 14,704.5 Btu/lb (dry, ash-free)
Constant gas specific heats
Integrated gasifier
Gasifier: mass steam/mass coal = 1.0
Gasifier steam supplied from steam cycle
Gasifier (j> - 2.0
Gasifier and cleanup system heat loss - 10% coal H.H.V.
Generalized combustor pressure loss =• 5%
Compressor and turbine efficiencies « 85%
Waste Heat Recovery Boiler
Exhaust side inlet pressure - 1.1 atm
Pinch point temperature difference = 50 F
Stack temperature - 300°F
Steam Turbine (Bottoming Cycle)
No feedwater heating
No reheat ing
Condensor temperature/pressure - 101°F/1.0 psia
Maximum steam temperature = 1000 F
Maximum turbine moisture = 15%
Turbine efficiency » 85%
166
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TABLE III. VARIATION OF SYSTEM BEHAVIOR WITH CHANGE
IN COMPONENT EFFICIENCIES FOR BASIC COGAS
CYCLE (TIT = 2600°F, PRESSURE RATIO = 24)
Parameter
Lower
Base Component
Case Efficiencies
Units
Turbine and Compressor Efficiencies
85.0
75.0
Steam Cycle Efficiency
Can Turbine Cycle Efficiency
Overall Efficiency
Equivalence RntLo
Turbine Exhaust Temperature (°F)
33.79
35.37
47.00
0.371
1122
36.89
21.58
39.26
0.342
1296
167
-------
M
0)
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4J
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4J
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3
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eg
-------
1.0
T
0.5
1.0 115
EQUIVALENCE RATIO,
2 0
Figure 3. Effective NH? conversion ratio for premixed primary
reactor - adiabatlc gaa turbine combuator.
170
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1000-
Alr addition
over 50 msec
Simulated diffusion
flame
Instantaneous.
mixing
—•— Products added
over SO msec
2000
-1500
- -1000
- 500
0 50 100
TIME AFTER INITIATION OF SECONDARY AIR INJECTION
(MSEC)
Figure 4. NO concentration and temperature for alternative secondary
stage configurations - adiabatic gas turbine combustor
(10 atmospheres).
171
-------
M
(0
-------
300-
200-
100'
400
SR
0.95
SR
>- 1.15
0.95
AIR
00.95
800
TIME, MS
1200
1600
Figure 6.
NO concentration for various reactor simulations of a
supercharged boiler,
173
-------
co
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O
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to
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u
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u
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r*.
01
174
-------
45-
40'
Overall
30-
12
— TIT 2600F
— TIT 2000F
N
\
\
Gas Turbine
16 20 24 28
PRESSURE RATIO
36
Figure 8. The Influence of pressure ratio on cycle performance basic
COCAS cycle.
175
-------
40 -
35
B
H
U
30
25
Overall Efficiency
TIT - 2000P
Pressure Ratio - 12.on
. -. .,.. intercooling Heat
Runs Steam Cycle
O Intercooling Steam
Injected into Gaeifier
D Intercooling
Heat Wasted
Steam Bottoming Cycle Efficiency
Gaa Turbine Cycle Efficiency
O—
0 0.1 0.2
HEAT LOSS TO INTERCOOLING/TOTAL HEAT RELEASE
Figure 9. Basic COCAS cycle with gasifier intercooling
TIT - 2000°?.
176
-------
46
45
40
w
u
M
30
25
Overall Efficiency
TIT - 2600K
Pressure Ratio
-*— Intercooling H«
Runs Steam Cycle
O Intercoolinj.
Injected into Gaslfier
Q Intercooling
Heat Wasted
Steam Cycle
Efficiency
-O
o-
Gas Turbine Cycle"
Efficiency
•—-o
60
55
0 0.1 0.2
HEAT LOSS TO INTERCOOL/TOTAL HEAT RELEASE
o
M
H
50.
M
I
45
42
10. Basic COGAS cycle with gaslfier intercooling
TIT * 2600°F.
177
-------
6
fi
45-
Overall
40-
35-
30-
25
TIT 2000F
TIT 2600F
0.0 0.1 0.2
HEAT INPUT TO DUCT HEATER/TOTAL HEAT INPUT
0.3
Figure It. Basic COCAS cycle with duct heater (supplementary
11 red wastu heat boiler).
178
-------
o 35
0.3
Overall Supercharged Boiler
Overall Basic
COCAS Cycle
I
H
CO
8
S
Cfa
CO
0 2 4 6 8 10 12 14 16 18 20
PRESSURE RATIO
Figure 12. Comparison of basic COGAS cycle with the
optimum supercharged boiler - TIT - 2000°F.
179
-------
50
45
a
40
35
8 10 12 14 16 18 20 22 24 26 28 30
PRESSURE RATIO
Figure II. Comparison of basic COCAS cycle with the
optimum supercharged boiler - TIT »
2600"F.
180
-------
45-
40
35
30
25
With Recouperation
Steam Cycle
TIT - 2000F
Pressure Ratio - 16.(
Reheat Temp. - 2000F
Overall Efficiency
Mo
Reheat
5 10
REHEAT PRESSURE
15
Figure 14. COCAS cycle with reheat-effIciency as function of
reheat pressure.
181
-------
45-
40
Ed
M
3
H
U
35
30
25
•Overall Efficiency
2000F
• Basic Cycle
2000F Reheat
to Produce
1000F Steam
x.
Steam Cycle
Efficiency
Gas Turbine >
Cycle Efficiency
4 6 8 10 12 14 16 18 20 22 24 26 28 30
PRESSURE RATIO
Ft gun- I1). Comparison of hasir COCAS cycle with reheat
cycle ns n function of pressure ratio.
182
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PANEL:
EMERGING COMBUSTION TECHNOLOGIES
1 — Fluidized Bed Combustion
John M. Connell
2 — Coal-Oil Mixture Combustion Technology
Casters B. Foster
3 — Advanced Combined Cycles
Fred L. Robson
183
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FLUIDIZED BED COMBUSTION
By:
J. M. Cornell
Foster-Wheeler Energy Corporation
Livingston, New Jersey 07039
185
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FLUIDIZED BED STEAM GENERATOR
The fluidized combustion of coal in a limestone bed is a promising, near time
method for burning high sulfur coal in a utility plant while meeting present
environmental standards. A 150 MW capacity plant is presently in the initial
design phases and should present plans be implemented, the construction of
the first large demonstration unit will start in 1981.
Coal and limestone fed onto a grid plate is burned in a fluidized condition
and the sulfur oxide produced combines with the calcium to form calcium sul-
fate, a solid, which is removed with the ash. Since the temperature of the
burning of the products of combustion is held to 1550F by the inclusion of
heating surface within the bed the maximum conversion of sulfur dioxide to
calcium Bulfate is accomplished with a mir''*"Tim conversion of nitrogen to
During the last few years this technology has emerged from the laboratory
and there is now the largest fluidized bed steam generator in service that
has been built under the auspices of .the Environmental Protection Agency at
Mvesville, West Virginia. This unit is designed to produce 300,000 Ib/hr
of steam at 92£F and 1350 psi for a rated electrical capacity of 30 Mtf.
Data obtained from this installation is being used for design criteria as-
surance on the 150 MW Demonstration Unit now being designed.
This 150 MW Demonstration Plant includes four (1+) main fluidized beds, each
including heating surface within the bed and the gases emitted therein pass
over additional heating surfaces in the economizer and air heater. Farti-
culate matter is captured in dust collectors and is to be reinjected in a
carbon burn up cell to complete the combustion of carbon particles elutriated
186
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from the main colls. A baghouse located after the air preheater will cap-
ture virtually all of the particulate matter before the gasses are discharged
to the atmosphere.
The unit was designed by Poster Wheeler Energy Corporation for 1,100,000
Ib/hr of steam at the supercritical pressure of 3800 psi and 1000F at the
superheater outlet. Additionally there is 960,000 Ib/hr of steam reheated
to a 1005?. The unit will bum 133,000 Ib/hr of coal (10,1^90 BTU/lb, k*9fi
sulfur) using 57>000 Ib of limestone per hour to capture as a solid over
90$ of the sulfur in the fuel. The 30 MW Demonstration plant at Hivesville
and the new 150 MW Demonstration plant described above will provide industry
with a high confidence level for building still larger atmospheric fluidized
bed steam generators in the 600 MW - 800 MW capacity range during the next
decade•
187'
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COAL-OIL MIXTURE COMBUSTION TECHNOLOGY
By:
Casters B. Foster
Department of Energy
'Fossil Energy/Advanced Power Systems
Washington, D.C. 20545
188
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COAL-OIL MIXTURE COMBUSTION TECHNOLOGY
C. B. Foster
Manager, ERDA Coal-Oil Mixture Combustion Program
Energy Research and Development Administration
Washington, D.C. 20545
The Energy Research and Development Administration (ERDA) has undertaken
in a cost-sharing partnership with industry and the utilities, an extensive
coal-oil mixture combustion program in a number of promising applications.
These applications currently include utility steam generators, industrial
steam generators, and blast furnace injection, and can be expected to expand
to other applications in the future. The objectives of ERDA's program are to
modify and retrofit, operate and test existing boilers and blast furnaces, and
to design, construct, operate and test prototype coal-oil mixture preparation
facilities to demonstrate coal-oil mixture technology. The intent is to
substitute coal for an appreciable fraction of oil in the near-term time frame
and determine the economics of coal-oil mixture preparation, transportation
and combustion. The coal-oil mixture combustion program is still in the early
stages of development. However, some test results have been obtained and will
be discussed as well as the economics of implementation and plans for future
testing.
189
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AVANCED COMBINED CYCLES
By:
Dr. F. L. Robson
United Technologies Research Center
East Hartford, Connecticut 06108
191
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EMERGING COMBUSTION TECHNOLOGIES: ADVANCED COMBINED CYCLES
The increased use of coal 1n utility power systems has become a part of the
national energy policy. To do this in an environmentally acceptable manner will
require some type of pre- or post-combustion treatment. When advanced power sys-
tems such as gas turbine-based combined-cycle systems are considered, one poten-
tially attractive method of coal treatment is the gasification of coal followed
by desulfurizatlon with the clean fuel gas being burned 1n the gas turbine.
A schematic of the combined gas-steam turbine system is given in Fig. 1.
Fuel gas from the gasifler 1s burned 1n gas turbine and the combustion products
expanded through the turbine which drives a generator. The hot exhaust products
are then sent to a waste-heat recovery boiler which generates steam for a steam
turbogenerator set. When operating at temperatures of 1425 C (2600 F) overall
system efficiencies of 42-44 percent could be realized.
Such power systems would, of course, have to meet environmental standards.
At this time, the only standards which have been promulgated are those for coal-
fired steam stations (Fig. 2). However, standards for gas turbine-based power
systems have been suggested and are Included 1n F1g. 2 for comparison purposes.
Because the sulfur bearing compounds are removed in the fuel gas cleanup
system prior to combustion, the major pollutant of interest is NO . In order to
better understand the potential for NOX pollution, the Power Systems Division of
UTC and the Texaco Development Company carried out joint tests at the Texaco test
facilities in Montlbello, California. A small gasifier using residual oil, coal,
and mixtures of the two was used to provide fuel to a small-scale gas turbine
combustor (1/8 of a 30-MW gas turbine). Both air and oxygen were used in the
gasifier so that fuel gases of approximately 900 kcal/M3 (IQO Btu/ft3) and 2700 kcal/
M (300 Btu/ft3) respectively, were produced.
The results of these tests using conventional combustor nozzles are shown
In F1g. 3. Also shown, for comparison, are the NOX emissions from natural gas
(8900 kcal/M3). It 1s apparent that at the burner temperature rise required for
high-temperature turbine operations, i.e., 800 C and beyond, the emissions from
the medium-heating value fuels could very well exceed proposed future regulations.
The emissions from the low-heating value fuel appear acceptable, but further
192
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reduction would make the concept even more attractive.
One method of reducing NOX Involves shortening the time at which the fuel/air
mixture 1s at high temperature. Since mixing time 1s the governing time (-10 msec
for turbulent mixing vs 0.3-0.5 msec for combustion) 1n the conventional combus-
tor, significant reduction 1n time would be achieved 1f the fuel and air were mixed
prior to introduction into the combustor. This also would allow combustion at other
than stoichlometric conditions usually present in conventional burners. These advan-
tages are shown in Fig. 4 where emissions are shown as a function of equivalence ra-
tio ,f/a actual . anj residence time in the primary zone of the combustor.
^f/a stoichiometric'
Here it is seen that combustion at a lean equivalence ratio (0'.4 to 0.5) results in
extremely low NOX emissions, less than 25 ppm with low-heating value gas.
This was borne out in tests in which the medium-heating value gas was burned
in a premix combustor (Fig. 5). Here the emissions with a premix combustor are
from one-quarter to one-half that of the conventional combustor. When steam is
Injected as a NOX suppressant, an even greater reduction 1s obtained.
A potential configuration of a pre-mixed combustor is shown in Fig. 6. Be-
cause of combustor cooling considerations Inherent when the gasifler is integrated
with the gas turbine (15-17 percent of the air goes to the gaslfier) a combustor
having a low surface to volume ratio is necessary This results in the minimum
amount of combustor wall to be cooled. An annular combustor, i.e., a single com-
bustor wrapped around and concentric to the frame of the gas turbine, appears at-
tractive. The combustor head is comprised of many small tubes through which the
air is admitted to the combustor. Each tube has holes located radially around them
through whi-ch fuel gas is admitted to the tube. Mixing takes place in the remainder
of the tube prior to admission to the primary zone of the combustor.
Based upon the forgoing combustor concept, estimates of NOX emissions have
been made and are shown in Fig. 7. Here it 1s seen that the NOX emissions are
well below the current coal-fired power system rule, which is just met by well de-
signed conventional steam systems.
Because SOg rules have been proposed for gas turbines, the projected emis-
sions of SOg are given 1n F1g. 8. The emissions from the combined cycle vary as a
function of the cleanup method, but are still significantly lower than the regula-
tions, both current and projected, as well as lower than conventional steam with
fuel gas desulfurlzatlon.
193
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ADVANCED COMBUSTION SYSTEMS FOR STATIONARY GAS TURBINES
By:
S. A. Mosier
Pratt & Whitney Aircraft Group
West Palm Beach, Florida 33402
203
-------
This paper was not received in time for publication,
204
-------
APPENDIX A:
LIST OF ATTENDEES
A-l
-------
LIST OF ATTENDEES
EPA SECOND SYMPOSIUM ON STATIONARY
SOURCE COMBUSTION
INDUSTRIAL ENVIRONMENTAL RESEARCH
LABORATORY-RTP
New Orleans, Louisiana
August 29 - September 1, 1977
- A -
D. G. Adams
Ford, Bacon & Davis
P.O. Box 1762
Monroe, Louisiana 71201
Robert N. Allen
Florida Power & Light Co.
P.O. Box 013100
Miami, Florida 33101
Larry W. Anderson
Acurex/Aerotherm
485 Clyde Avenue
Mountain View, California 94042
Mi 11i am Axtman
ABMA
Arlington, Virginia
Arthur Axworthy
Rocketdyne
6633 Canoga Avenue
Canoga Park, California 91304
Kenneth N. Arledge
TRW, Inc.
One Space Park Drive
Redondo Beach, California 90278
- B -
Raymond G. Buergin
Kansas State Dept. of Health
Environment
Topeka, Kansas
and
Sushil K. Batra
New England Power Service Co.
20 Turnpike Rd.
Westhorough, Massachusetts 01581
Richard L. Burrington
Combustion Engineering Inc.
1000 Prospect Hill Rd.
Windsor, Connecticut 06095
Janos Beer
Massachusetts Institute of Technology
77 Massachusetts Avenue
Cambridge, Massachusetts 02139
Ooe Bars in
Babcock & Wilcox
Barberton, Ohio 44203
Alfred T, Barnard
Florida Power & Light Co.
P.O. Box 013100
Miami, Florida 33101
Charles E. Branning
Florida Power & Light Co.
P.O. Box 013100
Miami, Florida 33101
Thomas A. Burnett
Tennessee Valley Authority
EC DP
Muscle Shoals, Alabama 35660
Myron Becker
Mobil Research & Development Co.
Paulsboro, New Jersey 08066
Craig T. Bowman
Associate Professor
Stanford University
Stanford, California 94305
Atly Brasher
Louisiana Air Control Comm.
New Orleans, Louisiana 70160
K. A. Bueters
Combustion Engineering, Inc.
1000 Prospect Hill Road
Windsor, Connecticut 06095
Stephen D. Bailey
Columbia Gas System
20 Montchanin Road
Wilmington, Delaware 19807
A-2
-------
Herbert L. Berman
Caltex Petroleum Corp.
380 Madison Ave.
New York, NY 10017
Joshua S. Bowen
Environmental Protection Agency
Industrial Environmental Research
Laboratory-RTP
(MD-65)
Research Triangle Park
North Carolina 27711
John K, Burchard
Environmental Protection Agency
Director, Industrial Environmental
Research Laboratory-RTP
(MD-60)
Research Triangle Park
North Carolina 27711
Richard A. Brown
Acurex/Aerotherm Corp.
485 Clyde Avenue
Mountain View, California 94042
William Bartok
Exxon Research & Engineering Co.
P.O. Box 8
Linden, New Jersey 07036
James D. Bittner
77 Massachusetts Ave.
Massachusetts Institute of Technology
Rm. 31-213
Cambridge, Massachusetts 02139
Donald R. Bartz
KVB, Inc.
17332 Irvine Blvd.
Tustin, California 92680
Mark Bergman
Pomrad
Northwestern University, Technological
Institute
Dept. of Industrial Engineering
Evanston, Illinois
Joseph R. Binder
Chief, Env. Branch
USDA, REA, PSESD
12th & Independence
South Blvd., Rm 3323
Washington, D.C. 20250
W. S. Bullpit
KVB, Inc.
6624 Hornwood
Houston, Texas 77074
Richard E. Barrett
Battelle Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
Bimal K. Biswas
Foster Wheeler Corp.
John Blizard Research Center
12 Peach Tree Hill Road
Livingston, New Jersey 07039
Beuford M. Bunnell
Mine & Smelter Corp.
P.O. Box 16067
Denver, Colorado 80216
$id Bourgeois
Lockheed
Huntsville, Alabama
- C -
William N. Cantrell
Tampa Electric Co.
P.O. Box 111
Tampa, Florida 33601
Ed Campodenedetto
Babcock & Wilcox
Barberton, Ohio 44203
Kimble J. Clark
Acurex/Aerotherm
485 Clyde Avenue
Mountain View, California 94042
A-3
-------
Wi lliam C. Cain
Environmental Protection Agency
Industrial Environmental Research
Laboratory-Cincinnati
5555 Ridge Avenue
Cincinnati, Ohio 45268
H. B. Childs
Ford, Bacon & Davis
P.O. Box 1762
Monroe, Louisiana 71201
John M. Connell
Foster Wheeler Energy Corp.
110 S, Orange Avenue
Livingston, New Jersey 07039
Allen R. Crawford
Exxon Research & Engineering Co.
P.O. Box 8
Linden, New Jersey 07036
L. Paul Combs
Rocketdyne
6633 Canoga Av.
Canoga Park, California 91304
J. Edward Cichanowicz
E & ER
8001 Irvine Blvd.
Santa Ana, California 92705
Tom Ctvrtnicek
Monsanto Corp.
Dayton, Ohio 45407
W. Ray Cunningham
Environmental Protection Agency
Region IV Office
345 Courtland Street, N.E.
Altanta, Georgia 30308
John D. Carter
Texas Eastern Transmission Corp.
P.O. Box 2521
Houston, Texas 77001
Woodrow Crouch
Power Authority
New York State
10 Columbus Circle
New York City, New York 10019
- D -
Robert Duthie
Bechtel Corp.
P.O. Box 3965
San Francisco, California
94119
E. A. DeZubay
Westinghouse Electric Corp.
1310 Beulah Road
Pittsburgh, Pennsylvania 15235
Owen W. Dykema
The Aerospace Corp.
P.O. Box 92957
Los Angeles, California
Robert Duprey
Director, Air & Hazardous Materials
Div.
Environmental Protection Agency
Region V Office
Chicago, Illinois 60604
S. Mario DeCorso
Westinghouse Electric Corp.
A-703
P.O. Box 9175
Lester, Pennsylvania 19029
- E -
B. E. Enga
Johnson-Matthey Res. Center
Blounts Court, Sonning Common
Reading R64 9HN
England
- f -
Bryan W. Ferguson
Texas Power & Light Co.
P.O. Box 6331
Dallas, Texas 75222
R. J. Fletcher
Peabody Engineering Corp.
835 Hope Street
Stamford, Connecticut 06907
A-4
-------
Mark S. Freas
North American Manufacturing Co.
4455 E. 71st Street
Cleveland, Ohio 44105
Paul Fredette
Midland Ross
2375 Dorr Street
P.O. Box 907
Toledo, Ohio 43691
Jack R. Farmer
Chief, Standards Dev. Branch
Environmental Protection Agency
Research Triangle Park
North Carolina 27711
Blair A. Folsom
E & ER
8001 Irvine Blvd.
Santa Ana, California 92705
Ted Fuhrman
Zurn Industries
Envery Division
1422 East Avenue
Erie, Pennsylvania 16530
Casters B. Foster
ERDA-Fossil Energy
20 Massachusetts Ave.
Washington, D.C. 20545
Robert E. Griffith
Peabody Engineering Corp.
835 Hope Street
Stamford, Connecticut 06907
Michael P. Gardner
TRW, Inc.
One Space Park
Redondo Beach,
Dr.
California
90278
Everett F. Grubb
Owens-Illinois, Inc.
P.O. Box 1035
Toledo, Ohio 43666
Fred C. Greer, Or.
CEA, Combustion, Inc.
61 Taylor-Reed PI.
Stamford, Connecticut 06906
K, T. Geoca
Shell Development co.
1126 One Shell Plaza
P.O. Box 2463
Houston, Texas 77001
Marvin H. Green
N. J. Dept. of Environmental Protection
Labor & Industry Bldg., Rm 1108
Trenton, N. J. 08625
*
James Gabriel son
KVB, Inc.
Suite 1375
600 S. County Rd. 18
Minneapolis, Minnesota 55426
Robert Gershman
E & ER
8001 Irvine Blvd.
Santa Ana, California 92705
Robert Giammar
Battelle Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
David Graham
Environmental Protection Agency
Office of Energy, Minerals & Industry
Waterside Mall (RD-681)
401 M Street, S.W.
Washington, D.C. 20460
Jack H. Greene
Administrative Officer
Industrial Environmental Research
Laboratory-RTP
(MD-60)
Environmental Protection Agency
Research Triangle Park
North Carolina 27711
- H -
E. A. Holden
General Foods Corp.
c/o Tech. Center
250 North Street
White Plains, New York 10625
A-5
-------
Hann S. Huang
Argonne National Laboratories
9700 S. Cass Avenue
Argonne, Illinois 60439
Donald R. Hardesty
Sandia Labs
Comb. Res. Div. (8351)
Bldg. 9921, Rm 12
Livermore, California 94550
ton. W. Habelt
Combustion Engineering
1000 Prospect Hill Road
Windsor, Connecticut
Kenneth A. Hanson
Turbodyne Corp.
711 Anderson Ave.
St. Cloud, Minnesota 56301
James M. Henry
Energy & Environment Labs
Dept. of Chemical Engr.
Tulane University
New Orleans, Louisiana 70118
Eric Hughes
Rolls-Royce, Ltd.
P.O. Box 72
Ansty, Conventry
U. Midlands
England
Thomas E. Hensel
United Technologies
Power Systems Div.
1690 New Britain Ave.
Farmington, Connecticut 06032
Geoffrey M. Hal ley
Kewanee Boiler Corp.
101 Franklin St.
Kewanee, Illinois 61443
Robert L. Himnell
American Gas Assoc. Lab.
8501 E. Pleasant Valley Rd.
Cleveland, Ohio 44131
Robert P. Hangebrauck
Director, Energy Assessment & Control
Div.
Industrial Environmental Research
Laboratory-RTP
Environmental Protection Agency
Mail Drop 61
Research Triangle Park
North Carolina 27711
Robert E. Hall
Environmental Protection Agency
Industrial Environmental Research
Laboratory-RTP
Mail Drop 65
Research Triangle Park
North Carolina 27711
Ottfried J. Hahn
University of Kentucky
Lexington, Kentucky 40506
Werner Henke, P.E.
President
Nitrogen Corporation of America
Box 53622
Oil Center Station
Lafayette, Louisiana 70505
Skillman C. Hunter
KVB, Inc.
17332 Irvine Blvd.
Tustin, California 92680
Michael P. Heap
E & ER
8001 Irvine Blvd.
Santa Ana, California
- J -
Stephen A. Johnson
Babcock & Wilcox
1562 Beeson St.
Alliance, Ohio 44601
Gary D. Jones
Radian Corp.
P.O. Box 9948
Austin, Texas 78766
92705
A-6
-------
Larry Jeffers
Babcock & Wilcox Co.
1562 Beeson Street
Alliance, Ohio 44601
Richard F. Oastrzebski
Consolidated Edison of New York
4 Irving Place, Rm 1026
New York, New York 10003
Dr. A. W, Jackson
Ontario-Hydro
800 Kipling Ave.
Toronto, Ontario, Canada
M82 554
John E. Janssen
Honeywell, Energy Research Cntr,
2600 Ridgeway Parkway
Minneapolis, Minnesota 55413
- K -
Charles W. Knowles
Standard Oil of California
555 Market Street
San Francisco, California 94105
Gary S. Kapp
Arthur G. McKee & Co.
6200 Oak Tree Blvd.
Independence, Ohio 44131
Norm Kulujian
Environmental Protection Agency
Technology Transfer
26 W. St. Clalr
Cincinnati, Ohio 45238
Robert Klancko
CEA Combustion, Inc.
61 Taylor-Reed PI.
Stamford, Connecticut 06906
Wayne V. Krill
Acurex/Aerotherm
485 Clyde Avenue
Mountain View, California 94042
C. W. Kauffman
University of Michigan
Aero. Eng.
Ann Arbor, Michigan 48109
William B. Kuykendal
Environmental Protection Agency
Industrial Environmental Research
Laboratory-RTP
(MD-62)
Research Triangle Park
North Carolina 27711
Alexander Korosi
Stone & Webster
P.O. Box 2325
Boston, Massachusetts
02107
H. E. Knowlton
Chevron Research Co.
P.O. Box 1627
Richmond, California 94802
Metro. D. Kulik
Conoco Coal Development Co.
Research Division
Library, Pennsylvania 15129
Nobuo Kido
National Research Institute for
Pollution & Resources
Kawaguchi-Saitama 332
Japan
John P. Kesselring
Acurex/Aerotherm
485 Clyde Avenue
Mountain View, California 94042
John T. Kelly
Acurex/Aerotherm
485 Clyde Avenue
Mountain View, California 94042
John F. Kircher
Battelle Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
Arthur Kesten
UTRC
400 Main St.
East Hartford, Connecticut
06108
A-7
-------
Richard R. Keppler
Environmental Protection Agency
Region I Office
Boston, Massachusetts 02203
C. R. Krishna
Brookhaven National Laboratory
Bldg. 835
Upton, New York 11973
Eugene P. Krug
Federal Energy Administration
12th & Pennsylvania, N.W.
Washington, D.C. 20461
- L -
Vincent D. Lajines
American Natural Gas Service Co.
Detroit, Michigan
Donald J. L. L1n
Forney Engineering Co.
Addison, Texas
Richard Lippeatt
Blueray Systems, Inc.
22 Jericho Turnpike
Minealo, New York 11501
David W. Locklin
Battelle Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
Joseph 8. Landwehr
Burns & McDonnell Eng.
P.O. Box 173
Kansas, Missouri 64141
William W. Lemmon
Middle South Service, Inc.
P.O. Box 61000
New Orleans, Louisiana 70160
Leonard Little
Riley-Stoker Corp.
P.O. Box 547
Worcester, Massachusetts 01613
Arthur Levy
Battelle Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
W. Steven Lanier
Environmental Protection Agency
Industrial Environmental Research
Laboratory-RTP
(MD-65)
Research Triangle Park
North Carolina 27711
David G. Lachapelle
Environmental Protection Agency
Industrial Environmental Research
Laboratory-RTP
(MD-65)
Research Triangle Park
North Carolina 27711
- M -
Fred Manhart
Louisiana Power & Light
New Orleans, Louisiana
Co.
Arthur Melor
Purdue University
School of Mechanical Eng.
West Lafayette, Indiana 47907
John 6. Meier
Solar Turbines Intl.
2200 Pacific Highway
San Diego, California 92138
Dave Marshall
Babcock & WiIcox
Barberton, Ohio 44203
Donald A. Mitchell
Lone Star Steel Co.
Highway 259, South
Lone Star, Texas 75668
Mary E. Malotke
Proctor & Gamble Co.
7162 Reading Road
Cincinnati, Ohio 45222
A-8
-------
M. B. Marton
IBM Corp.
1000 Westchester Ave.
White Plains, New York
10604
David I. McBrayer
Southern Natural Gas Co.
P.O. Box 2563
Birmingham, Alabama 35202
Arun K. Mehta
Combustion Engineering, Inc.
1000 Prospect Hill Road
Windsor, Connecticut 06095
Dr. Ing. S. Michelfelder
Int. Flame Res. Foundation
c/o Hoogovens IJmuiden BV
Adrescone 3G20
IJmuiden/The Netherlands
J. David Mobley
Environmental Protection Agency
Industrial Environmental Research
Uboratory-RTP
(MD-61)
Research Triangle Park
North Carolina 27711
Albert L. Myerson
Exxon Research & Engineering Co.
P.O. Box 45
Linden, New Jersey 07036
N. D. Moore
Tennessee Valley Authority
1340 Commerce Union Bank Bldg.
Chattanooga, Tennessee 37401
Lawrence Muzio
KVB, Inc.
17332 Irvine Blvd.
Tustin, California 92680
6. Blair Martin
Environmental Protection Agency
Industrial Environmental Research
Laboratory-RTP
(MD-65)
Research Triangle Park
North Carolina 27711
Stanley A. Hosier
Pratt & Whitney Aircraft
P.O. Box 2691
West Palm Beach, Florida 33402
Mike W. McElroy
Electric Power Reserach Institute
P.O. Box 10412
3412 Hillview Avenue
Palo Alto, California
Howard Mason
Acurex/Aerotherm
485 Clyde Avenue
Mountain View, California 94042
Kenneth L. Maloney
KVB, Inc.
17332 Irvine Blvd.
Tustin, California 92680
E. H. Manny
Exxon Research & Engineering Co.
P.O. Box 8
Linden, New Jersey 07036
Zane E. Murphy, P.E.
Chief, Div. of Coal
Bureau of Mines
U.S. Dept. of Interior
2401 E Street, N.W.
Washington, D.C. 20241
Henry McDonald
Scientific Research Associates
P.O. Box 498
Glastonbury, Connecticut 06033
- N -
Charles L. Newton
Colt Industries Operating Corp.
701 Lawton Avenue
Beloit, Wisconsin 53511
Wm. H. Nurick
E & ER
8001 Irvine Blvd.
Santa Ana, California
92705
A-9
-------
Frans M. Nooy
UOP
Process Div.
20 UOP Plaza
Oes Plaines, Illinois 60016
Arakel R. Naroian
Riley-Stoker Corp.
P.O. Box 547
Worcester, Massachusetts
01613
S, K. Nayak
Florida State Dept. of Env.
Regulation
Koger 'Center
Tallahassee, Florida 32X1
Dennis Norton
Southern California Edison
P.O. Box 800
Rosemead, California 91770
E. J. Niederbuehl
GMC Tech. Center
Warren, Michigan 48092
- 0 -
Daniel J. O'Leary
Rohm & Haas Co.
Bristol, Pennsylvania
Juri Otsason
Canadian Gas Res. Inst.
55 Scarsdale Road
Don Mills, Ontario, Canada
M3B 2R3
Boris J. Osheroff
U.S. Public Health
Dept. of Health, Education & Welfare
5600 Fishers Lane, 17A46
Rockvilie, Maryland 20857
- P -
David W. Pershing
University of Utah
Salt Lake City, Utah
Steven L. Plee
Purdue University
School of Mechanical Eng.
West Lafayette, Indiana 47906
Robert Pai
Foster Wheeler Energy Corp.
110 S. Orange Ave.
Livingston, New Jersey 07039
John H. Pohl
Sandia Labs
Combustion Res. Div. (8351)
Bldg. 9921, Rm 132
Livermore, California 94550
Edward L. Poitras
McBurney Corp.
4690 Old Peachtree Road
Doraville, Georgia 30362
Roger 0. Pfaff
Environmental Protection Agency
Region IV Office
345 Courtland Street
Atlanta, Georgia 30308
Arthur R. Paine
Army Env. Hygiene Agency
HSE-EA-S
Aberdeen Proving Ground
Maryland 21010
Doug Paul
PEDCo Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
Lester Y. Pilcher
Commander
U.S. Army Env. Hygiene Agency
Air Pollution Eng. Div.
Aberdeen Proving Ground
Maryland 21010
Robert Parkinson
Air Pollution Control Dist.
915 Chesapeake Drive
San Diego, California 92123
84112
A-10
-------
Robert M. Pierce
Pratt & Whitney Aircraft
P.O. Box 2691
West Palm Beach, Florida 34402
Frank T. Princiotta
Director, Energy Processes Div.
Office of Energy, Minerals & Industry
Environmental Protection Agency
Waterside Mall (RO-681)
401 M Street, S.W.
Washington, D.C. 20460
- R -
Gerald Roffe
General Applied Science Labs.
425 Merrick Avenue
Westbury, Connecticut 11590
J. E. Radway
Basic Chemicals
2532 St. Clair Avenue
Cleveland, Ohio 44114
Matthew J. Reilly
Energy Research & Development
Administration
Div. of Env. & Socioeconomic Prog.
20 Massachusetts Ave.
Washington, D.C. 20545
J. E. Robert
Fisheries & Environment Canada
12th Floor, Place Vincent Massey
Ottawa, Ontario, Canada
K1A 1C8
Albert H, Rawdon
Riley-Stoker Corp.
P.O. Box 547
Worcester, Massachusetts 01613
Roy M. Rulseh
Cleaver-Brooks
3707 N. Richards St.
Milwaukee, Wisconsin 53212
As 1m Ray
Research Cottrell
P.O. Box 750
Bound Brook, New Jersey 08805
Fred Robson
UTRC
400 Main Street
East Hartford, Connecticut 06040
B. Clark Smith
Caterpillar Tractor Co.
Peoria, Illinois
*r
Kenneth C. Stevens
Preferred Utilities Mfg. Co.
Danbury, Connecticut
Wm. E. Swearingen
Koppers Co., Inc.
Koppers Bldg., Rm 2050
Pittsburgh, Pennsylvania 15219
M. H. Schwartz
Shell Development Co.
P.O. Box 1380
Houston, Texas 77001
James H. Stone
Environmental Protection Agency
1306 Calhoun
New Orleans, Louisiana 70118
Walter E. Starnes
Dept. Env. Res.
2562 Executive Center Circle, E
Montgomery Bldg.
Tallahassee, Florida 32301
Donald E. Slyer, Jr.
Consumers Power Co.
1945 Parnall Road
Jackson, Michigan 49201
B. R. Seckington
Ontario Hydro
700 University Ave.
Toronto, Ontario, Canada
M56 1X6
David A. Skiven
GMC Fisher Body Div.
30001 Van Dyke
Warren, Michigan 48090
A-ll
-------
Jerry J. Savoy
Texaco, Inc.
P.O. Box 37
Convent, Louisiana 70723
Robert Sneddon
Research Cottrell
P.O. Box 750
Bound'Brook, New Jersey 08805
Edwin R. Strong
Amoco Oil Company
P.O. Box 400
Naperville, Illionis
60540
Mike Schuck
Southern California Edison
2244 Walnut Grove Ave.
Rosemead, California 91770
Norman C. Samish
Shell Development Co.
P.O. Box 1380
Houston, Texas 77035
Donald A. Smith
Combustion Engineering, Inc.
1000 Prospect Hill Road
Windsor, Connecticut 06095
John D. Stamm
Burns & McDonnell Engineering
P.O. Box 173
Kansas City, Missouri 64141
David A. Smith
Atlantic-Richfleld
400 E. Sibley Blvd.
Harvey, Illinois 60426
Charles W. Siegmund
Exxon Research & Engineering
P.O. Box 51
Linden, New Jersey 07036
Dr. D. Smith
International Research & Dev. Co. Ltd.
Fossway
Newcast1e-Upon-Tyne
NE6 2YD
England
Richard D. Stern
Environmental Protection Agency
Industrial Environmental Research
Laboratory-RTP
Mail Drop 61
Research Triangle Park
North Carolina 27711
Donald Shoffstall
Institute of Gas Technology
3424 S. State Street
Chicago, Illinois 60616
Yih H. Song
Massachusetts Institute of Technology
Rm 66-125
77 Massachusetts Ave.
Cambridge, Massachusetts 02139
Robert M. Statnick
Environmental Protection Agency
Office of Energy, Minerals & Industry
Waterside Mall (RD-681)
401 M Street, S.W.
Washington, D.C. 20460
Lowell Smith
KVB, Inc.
6624 Hornwood
Houston, Texas 77074
Ambrose P. Selker
Combustion Engineering
1000 Prospect Hill Road
Windsor, Connecticut 06095
Daniel J. Seery
United Technologies Research Center
400 Main St.
East Hartford, Connecticut 06108
Ben C. Severs
ABMA, Apt. 209A
325 Charlemagne Blvd.
Naples, Florida
Adel F. Sarofim
Massachusetts Institute of Technology
Rm 66-466
Cambridge, Massachusetts 02139
A-12
-------
Ben Y. Su .
United Engineers & Constructors, Inc.
100 Rummer St.
Boston, Massachusetts 02110
Henry D. Sento
Riley Stoker Corp.
7266 Torn Drive
Baton Rouge, Louisiana
- T -
Bernard E. Turlinski
Environmental Protection Agency
Region III
6th & Walnut Sts.
Philadelphia, Pennsylvania 19106
Wm. E. Thompson
Research Triangle Institute
P.O. Box 12194
Research Triangle Park
North Carolina 27709
Kenneth B. Tanner, Jr.
Brockway Glass Co., Inc.
E/R Bldg.
Brockway, Pennsylvania 15824
A. L. Thomas
Continental Oil Co.
P.O. Drawer 1267
Rm 50, W.O.B.
Ponca City, Oklahoma 74601
John Tukey
Bell Laboratories
Princeton University
Murray Hill, New Jersey 07974
E. R. Tucci
Matthey-Bishop, Inc.
Malvern, Pennsylvania 19355
Edward Taylor
Con. Edison of New York
4 Irving Place
New York, New York 10003
B. L. Tuffly
Rocketdyne
6633 Canoga Ave.
Canoga Park, California 91304
0. C. Tong
Atlantic-Richfield
400 East Sibley Blvd.
Harvey, Illinois 60426
T. J. Tyson
EER
8001 Irvine Blvd.
Santa Ana, California 92705
- U -
Paul Utterback
Babcock & Wilcox Co.
P.O. Box 2423
North Canton, Ohio
- W -
Larry Waterland
Acurex/Aerotherm
485 Clyde Avenue
Mountain View, California 94042
Richard T. Waibel
Institute of Gas Technology
3424 S. State Street
Chicago, Illinois 60616
David J. White
Solar Turbines Intl.
2200 Pacific Highway
San Diego, California 92138
Clifford A. Webb, Jr.
S. Mississippi Electric Power
Association
P.O. Box 1589
Hattiesburg, Mississippi 39401
Ralph S. Wilcox
Chevron Research Co.
576 Standard Road
Richmond, California 94802
A-13
-------
Charles E. Wallace
SMC Fisher Body Div.
900 Baldwin Ave.
Pontiac, Michigan 48055
John H. Wasser
Environmental Protection Agency
Industrial Environmental Research
Laboratory-RTP
(MD-65)
Research Triangle Park
North Carolina 27711
Arvel B. Witte
TRW Systems
RI, Room 1032
One Space Park Dr.
Redondo Beach, California
90278
Jost 0. I. Wendt
University of Arizona
Tucson, Arizona 85721
Charles S. White
Dravo Lime
650 Smithfield Street
Pittsburgh, Pennsylvania
15222
- I -
Melvin Zwillenberg
Public Service Electric & Gas Co.
80 Park Place, Rm 12330
Newark, New Jersey 07101
A-14
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-77-073e
2.
3. RECIPIENTS ACCESSION NO.
4. TITLE AND SUBTITLE PROCEEDINGS OF THE SECOND
STATIONARY SOURCE COMBUSTION SYMPOSIUM
Volume V. Addendum
5. REPORT DATE
July 1977
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Symposium Chairman J.S. Bowen, Vice-
Chair man R.E. Hall
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
10. PROGRAM ELEMENT NO.
EHE624
11. CONTRACT/GRANT NO.
NA (Inhouse)'
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Proceedings; 8/29-10/1/77
14. SPONSORING AGENCY CODE
EPA/600/13
15.SUPPLEMENTARY NOTES ffiRL-RTP project officer for these proceedings is R.E. Hall,
Mail Drop 65, 919/541-2477.
is. ABSTRACT
proceedings document the 50 presentations made during the Second
Stationary Source Combustion Symposium held in New Orleans, LA, August 29-
September 1, 1977. Sponsored by the Combustion Research Branch of EPA's Indus-
trial Environmental Research Laboratory- -RTP, the symposium dealt with subjects
relating 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 six parts , and the proceedings were issued in five
volumes: Volume I—Small Industrial, Commercial, and Residential Systems; Volume
n — Utility and Large Industrial Boilers; Volume m — Stationary Engine, Industrial
Process Combustion Systems , and Advanced Processes; Volume IV— Fundamental
Combustion Research; and Volume V--Addendum. The symposium was intended to
provide contractor, industrial, and Government representatives with the latest infor-
mation on EPA inhouse and contract combustion research projects related to
pollution control, with emphasis on reducing nitrogen oxides while controlling other
emissions and improving efficiency.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
:. COSATI Field/Group
Air Pollution, Combustion, Field Tests
Combustion Control, Coal, Oils
Natural Gas, Nitrogen Oxides, Carbon
Carbon 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
21D UH
07B
07C 13A
13G 14A
18, DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
223
30. SECURITY CLASS (TillJpage)
Unclassified
22. PRICE
BPA Form 1220-1 (1-73)
A-15
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BP 600/7 EPA
-073ft Ind. Env. Rt»s. Lab.
AUTHOR
Proc. af the second stationar
TITLE source combustion symposium.
v«5: Addendum
OAVLORD 45
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