U.S. Environmental Protection Agency Industrial Environmental Research EPA'600/
Office of Research and Development Laboratory . . -tr\-r-j
Research Triangle Park, North Carolina 27711 JUly 1977
EPA-600/7-77-073C
PROCEEDINGS OF THE SECOND
STATIONARY SOURCE
COMBUSTION SYMPOSIUM
Volume III. Stationary Engine,
Industrial Process Combustion
Systems, and Advanced Processes
Interagency
Energy-Environment
Research and Development
Program Report
•U. S. EE v'l'; o.... ^,;.i. -
|, BP 600/7
77-073C
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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-agency 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 riot
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-600/7-77-073C
July 1977
PROCEEDINGS OF THE SECOND
STATIONARY SOURCE
COMBUSTION SYMPOSIUM
Volume III. Stationary Engine, Industrial
Process Combustion Systems, and
Advanced Processes
PI
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
L-r--ir>-r^ A T^~C7"
i, :-'•<' f • V
JL_.,\ . •",. ...;..'.,
U.S. I.'.:; •.<•.:. ..L'i
.' Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D.C. 20460
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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 G. Lachapelle, Session Chairman
Special Topics
David 6. 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
m
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VOLUME III
TABLE OF CONTENTS
- SESSION IV: STATIONARY ENGINE AND INDUSTRIAL PROCESS COMBUSTION SYSTEMS -
"Application of Combustion Modifications to Industrial Combustion
Equipment," S. C. Hunter, W. A. Carter, H. J. Buening, S. S.
Cherry .................
"Boiler Burner Design Criteria for Retrofit with Low-Btu Gases,"
D. R. Shoffstall, R. T. Waibel
"Environmental Assessment of Afterburner Combustion Systems," R. E.
Barrett
"Advanced Combustion Systems for Stationary Gas Turbine Engines,"
S. A. Mosier
"Development of Emission Controls for 1C Engines,"
"Emission Characteristics of Small Stationary Diesel Engines," J. H.
Wasser
3
49
107
133
135
137
- SESSION V: ADVANCED PROCESSES -
"Investigation of Staging Parameters for NO* Control In Both Wall and
Tangentially Coal Fired Boilers," R. Brown, H. Mason, P.Neubauer
"Design Criteria for Stationary Source Catalytic Combustors," J. P.
Kesselring, W. V. Krill, R. M. Kendall ...............
"Status of Flue Gas Treatment Technology for Control of NOX and
Simultaneous Control of SOX and NOX," J. D. Mobley, R. D. Stern ...
"Evaluation of Combustor Design Concepts Applicable to Advanced Low
Btu Gas Fired Systems," B. A. Folsom ................
"Evaluation of a Prototype Surface Combuston Furnace," G. B.
Martin
"Panel: Emerging Combustion Technologies"
141
193
229
253
255
279
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SESSION IV:
STATIONARY ENGINE AND INDUSTRIAL PROCESS
COMBUSTION SYSTEMS
JOHN H. WASSER
CHAIRMAN
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APPLICATION OF COMBUSTION MODIFICATIONS TO
INDUSTRIAL COMBUSTION EQUIPMENT
By:
S. C. Hunter, W. A, Carter, H. 0. Buening, and S. S. Cherry
KVB, Incorporated
Tustin, CA 92680
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ABSTRACT
This is a report of a research program to evaluate the effectiveness
of combustion modifications as means of emissions reduction and thermal effi-
ciency improvement on industrial combustion equipment. A survey conducted to
determine important and representative industrial equipment resulted in selec-
tion of combustion devices for test in the petroleum refining, minerals, paper,
and metals industries. This report presents results of tests on petroleum
refinery heaters, mineral kilns, metal furnaces, boilers burning unconventional
fuels, internal combustion engines, and gas turbine combined cycles. Tests
results from two modified industrial boilers are also included.
The effects of process variables, excess air reduction, burner adjust-
ments, staged combustion and fuel type were the main techniques evaluated. The
results indicated that these techniques, developed primarily on conventional
steam boilers, are also effective in emissions control on certain devices but
some devices were completely unresponsive. Critical process temperatures,
chemistry and fluctuations represent the main constraints and the effectiveness
of combustion modifications is primarily dependent on process flexibility.
This report was submitted in fulfillment on Contract 68-02-2144 by
KVB, Inc. under the sponsorship of the U.S. Environmental Protection Agency.
This report covers the period January 23, 1976 to May 23, 1977.
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SECTION 1
INTRODUCTION
Combustion modifications have been applied for many years to control
emissions, primarily of NO , from large utility boilers. This paper presents
A
results of an investigation of the applicability of combustion modifications
to industrial combustion equipment other than boilers burning conventional
fuels. Twenty-two devices were tested in sixteen facilities under conditions
of practical production constraints.
The need to control nitrogen oxides (NO ) from large fossil-fuel steam
generators has resulted in the development of techniques for combustion modi-
fication to reduce gas temperatures and alter mixing rates in a manner which
reduces NO without operational disruption. These techniques are well docu-
mented and recently reviewed (Refs. 1, 2, 3). There is also a developing
technology in the use of flue gas treatment to remove NO (Refs. 4, 5).
X
The estimates of NO emissions for the major stationary sources, as
X-
shown in Table I, clearly show that steam boilers burning conventional coal,
oil and gas fuels are the predominant stationary sources of NO emissions. It
is therefore clear why the main thrust of efforts to control NO emissions
x
has been concentrated on these sources, primarily the larger size units. Further
efforts to extend controls on steam boilers to lower levels of emissions or to
smaller size units can be expected to-incur greater costs per unit of NO., ends-
Jv
sions reduced.
As indicated in Table I, there are a variety of sources other than
steam boilers that contribute significantly to national NO emissions. As
controls become more costly for steam boilers, it is important to examine the
potential for control on these other sources to determine whether more cost-
effective options for NO control can be identified. Before the cost effec-
tiveness of various control options can be firmly established, it is necessary
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to quantify the emissions at normal operating conditions and to demonstrate
the applicability and emissions reduction potential of the various control
techniques.
As indicated in Table I, comparison of the three sets of estimates
for NO emissions show fairly good agreement for the steam boiler categories.
For other categories, there are much greater differences, with some categories
completely missing. Some of the discrepancies are believed to be the result
of differences in the approach to classifying sources. Other discrepancies
are due to inadequate information on inventories, consumption rates and
emission factors. It was not the purpose of this study to resolve these dis-
crepancies, but it may provide some information that may assist in that reso-
lution. The basic purpose of this study was to begin the task of investigating
the applicability of combustion modifications for control of emissions on in-
dustrial combustion devices.
OBJECTIVE AND SCOPE
The objective of the program was to investigate the effectiveness of
combustion modifications and operating variable changes as means for emissions
control and improvement in thermal efficiency on a variety of industrial com-
bustion devices. These techniques have previously been shown to be effective
on industrial boilers and the purpose of this program was to investigate the
basic feasibility and/or limitations for application of this technology to
other industrial combustion devices.
The program scope provided for tests on about 25 industrial combustion
devices representative of kilns, ovens, dryers, process furnaces, boilers,
stationary engines and gas turbines in use. Emissions measured included NO,
NO2, SO , SO , CO, CO,, gaseous hydrocarbons, particulates, particle size dis-
tribution, smoke number, and opacity. On selected devices, samples were col-
lected for analysis of trace species and organics emissions. Combustion modi-
fications to be evaluated where possible included lowered excess air, staged
combustion, reduced air preheat, water injection, and flue gas recirculation.
In addition to tests on the selected industrial combustion devices,
two modified industrial boilers that had previously been tested for EPA (Ref.
3) were retested to develop new data on the combined effects of several com-
bustion modifications.
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SECTION 2
TEST UNIT SELECTION AND DATA SUMMARY
A survey was conducted to establish representative units in a number
of industrial activities and to prioritize the devices so that test results
would have the widest applicability and be of most significance in regard to
national emissions from stationary sources.
A prior study for EPA formed the basis for initial selection of the
industries for evaluation (Ref. 9). This was augmented with emissions data
from the NEDS system, industry energy consumption data and contact with indus-
try associations, manufacturers, and equipment users. Further information was
developed on specific designs as a basis for selection of the specific test
units. From an initial list of 25 units desired for test, all types were tested
with the exception of a glass furnace, a blast furnace gas boiler and a simple
cycle gas turbine.
The device types that were tested and a brief summary of NO emissions,
reductions and control methods are shown in Table II. In general the results
indicate that combustion modifications can be applied to industrial combustion
equipment but reductions achievable vary significantly for different 'types of
devices. Reductions in NO of up to 69% were observed but on many devices
X
reductions were less than 10%.
As a group, the devices considered number in the several thousands.
Because of the wide diversity in design approach, it was not possible to de-
fine completely representative or typical devices. The test results cannot,
therefore, be interpreted as representative in a firm statistical sense, of
emission levels or efficiency of specific device groups as a whole. Rather,
the results are intended to serve the primary program objective: investigation
of the feasibility and effectiveness of combustion modifications by definition
of those modifications that offer the most promise for further investigation
and application.
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SECTION 3
INSTRUMENTATION
The emission measurements were made using analytical instruments and
equipment contained in a government-furnished mobile instrumentation labora-
tory. Gaseous samples were extracted from exhaust stacks through two lines.
One was heat-traced and maintained at 350 °F to prevent loss of NO , SO., and
•<& £t
hydrocarbons that are soluble in water. A second unheated line supplied
sample gas to the remaining instruments. Gaseous emission measurements were
made with instruments listed in Table III. All instruments were calibrated at
regular intervals with calibration gases carried in the mobile laboratory.
On devices that had adequate stack sampling ports (3 to 4 inches I.D.),
measurements were made of particulate by EPA Method 5, and particulate size dis-
tribution with cascade impactors (Brinks Model B for high particulate loading
or an Anderson 2000 Mark III for low loadings). Samples were taken by the
Shell-Emeryville method and titrated for SO_ and SO,. Smoke numbers were
£ «J
recorded with the Bacharach Smoke Spot Sampler, and stack opacity was measured
by EPA Method 9.
All pertinent process data was recorded including data necessary to
determine thermal efficiency.
Samples were collected for analysis of trace species and organics by
the use of the EPA Source Assessment Sampling System (SASS) and procedures
defined by EPA for environmental assessment (Ref. 10). However, the current
program requirements were not specifically formulated in terms of the complete
environmental assessment objectives.
10
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SECTION 4
COMBUSTION MODIFICATIONS ON INDUSTRIAL COMBUSTION EQUIPMENT
This section summarizes the design capacities, fuels, used baseline
emissions, combustion modifications that were applied and reductions obtained
for tests on 22 industrial combustion devices. Results for common types of de-
vices are grouped together in the section in the following order:
Petroleum Process Heaters
Mineral Kilns (Clay and Cement)
Metal Furnaces (Steel and Aluminum)
Boilers Burning Unconventional Fuels
Internal Combustion Engines
Gas Turbine Combined Cycle Systems
Complete presentation of all emissions and efficiency data was not
possible in this paper because of the large amount of data obtained and the
wide diversity of equipment types represented. The results are presented
primarily in terms of the effect on NO emissions as this emissions is the one
that is most affected by combustion modifications. The test program was com-
pleted in May 1977 and a final report for the program will be issued shortly.
COMBUSTION MODIFICATIONS ON PETROLEUM PROCESS HEATERS
Natural Draft Heaters
Five of the seven heaters tested in this program were vertically fired
natural draft types of box construction. The number of burners ranged from 10
to 32 and heat input rates varied from 11 to 26 MW (36 to 87 MMBtu/hr). All
the units had burners sized at about 0.94 +_ 0.14 MW {3.2 +_ 0.5 MMBtu/hr) per
burner. Process types included flasher heating, reforming, and recycle gas
heating.
The baseline (unmodified) NO emissions expressed as NO,, for the five
X <<£
natural draft heaters firing refinery gas were 47 +_ 9 ng/J (0.11 +_ 0.02 Ib/MMBtu
or 92 + 17 ppm)l. These emission levels are consistent with other data from
1 1 Ib/MMBtu = 430 ng/J = about 840 ppm with gas fuel or 750 ppm with oil fuel,
dry volume corrected to 3% O2. All ppm values are corrected to 3% O_, dry.
11
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a recent program in which baseline emissions on 26 heaters were measured
{Ref. 11). However, these levels are significantly lower than the standard
EPA emission factor (Ref. 12) of 0.23 Ib of NC>x/MCF (0.22 Ib/MMBtu or 95
ng/J) for refinery boilers and heaters firing gaseous fuel. This factor was
based on data taken in 1958 (Ref. 13).
Modifications made to the natural draft heaters included:
1. Fuel heat content variation
2. Load variation
3. Burner air register adjustments
4. staged combustion by removal of burners from service
Fuel Heat Content Variation—
The first heater tested (Site 4) was a flasher heater of double box con-
struction. Following baseline tests the refinery fuel gas system was adjusted
to eliminate natural gas. Propane was injected to increase the heating value.
NO emissions increased about 7% to 48 ng/J (94 ppm, 3% O , dry) from a base-
x •**
line level of 45 ng/J (88 ppm). Fuel gas analysis indicated the propane con-
tent was increased from about 7% to 16% resulting in a 17% increase in heating
value. Prior work had attributed large changes in NO^ to changes in fuel gas
composition (Ref. 11), however not every unit tested exhibited that sensitivity.
The test for the current program indicates that NO increases with increase
fuel heating value but not to a significant degree. However, more study is
needed on different heaters over a wider range of heating value.
Load Variation—
Two heaters that were part of a catalytic reformer process were tested
(site 5) during process rate changes of +_ 20%. NO emissions were observed to
~™ X
decrease as load increased (Fig. 1). At the lowest load, NO emissions were
about 51 ng/J (100 ppm) for both heaters. At the highest load one heater
emitted 41 ng/J (80 ppm) and the second about 31 ng/J (60 ppm). Excess air
was reduced as load increased and that was the most probable reason for the
NO reduction.
12
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Burner Adjustments—
Air register adjustments and removal of burners from service were done
to attempt to achieve staged combustion by creating fuel-rich and fuel-lean
regions in the flames. This can reduce flame temperatures and lower the NO
formation rates. The procedure involves removing about 25% of the burners
from service and then optimizing air registers for lowest NO . Various combi-
nations of burners out of service are tested to find an optimum pattern.
Five different burner patterns were implemented on a double furnace
heater (site 4). One pattern was found that reduced NO from about 59 ng/J
(116 ppm) to 49 ng/J (95 ppm), an 18% reduction. The other patterns produced
only about a 10% reduction (Fig. 2). These reductions are not considered
particularly significant because of fluctuations in baseline levels that were
about the same magnitude as the reductions. The fluctuations were probably
due to fuel gas property changes.
The second heater tested (site 5/1) was operating at 50% load and had
only six burners, of sixteen total/ in service. Adjustment of the air registers
reduced NO by 20%. Placing two more burners in service (8 total) increased
X
NO emissions by 34% from the baseline level. The third heater tested (site
A
5/2) had only four burners (of ten total) in service. No pattern tests were
attempted but air register adjustment did not produce any change in NOX.
On the fourth heater (site 7/1), adjustment of the air registers
reduced NO about 20% but removing two burners from service had no effect.
The fifth heater (site 7/2) had badly corroded air registers so that no
register adjustments could be made.
The response of natural draft process heater NO. emissions to burner
adjustments was found to be poor compared to previous results on boilers. One
reason is that in most cases the burner removal patterns resulted in increased
excess air which could not be lowered to baseline levels because of furnace
pressure limits. Also the design of natural draft burners utilizes the fuel
flow as an aid to induce combustion air and this acts to defeat the attempt to
achieve staged combustion. Furthermore, the in-line vertically-fired burner
arrangement used for most heaters does not provide much inter-burner mixing, ._
necessary feature of staged combustion. Further work on burner hardware modi-
fications will be necessary to determine whether these limitations can be overcci.v. .
13
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Mechanical Draft Heaters
Of the two mechanical draft heaters tested, one had combustion air pre-
heat. Both were vertical cylindrical types and were tested "while firing refin-
ery gas or Number 6 fuel oil through a single combination gas and oil burner in
each heater. The only adjustment that could be made was variation of excess
air. Staged combustion could not be done because of the single burner.
Operation of the heater that had air preheat (site 12/1), while firing
refinery gas, produced NO emissions of about 163 ng/J (320 ppm) or about three
times that of natural draft heaters. Variation of excess air showed a tendency
for reduced emissions as excess air was reduced. When firing Number 6 oil, NOV
' A
emissions were 30% lower than for gas fuel. Variation of excess air, firing
oil, did not result in any significant change in NOX, as shown in Figure 3.
The mechanical draft heater without air preheat (site 12/2), operating
on refinery gas, experienced large fluctuations in NO from about 43 to 109
ng/J during initial testing. This was probably due to fuel gas property changes.
During later tests NOX stabilized at about 64 ng/J (126 ppm) with 5% excess
oxygen. Reduction of excess oxygen to 2% reduced NO to 36 ng/J, a 44% reduc-
tion. Operation of this heater with Number 6 oil resulted in NO emissions
X
of about 92 ng/J (164 ppm) and, as with the preheated unit, variation of excess
air did not result in any significant change in NO .
^ x
COMBUSTION MODIFICATION ON MINEBAL KILNS
One tunnel kiln for manufacture of clay tile pipe and two rotary kilns
for making Portland cement clinker were tested.
Clay Tile Pipe Tunnel Kiln
A tunnel kiln is a long insulated tunnel through which clay pipe is
moved on cars. Burners along the tunnel walls provide a programmed temperature
firing cycle of heating, soaking, and cooling. The kiln tested (site 1) had
34 combination gas and oil burners per side with a total rated heat input of
9.4 MW (32 MMB/h). Tests were conducted at about 80% of rated capacity.
14
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The baseline NO emission firing natural gas was 46.2 ng/J (90 ppm)
and particulate was 12.5 ng/J (0.029 Ib/MMBtu). Oxygen levels were measured
at various points within the kiln and varied from about 0.2 to 11% in the
main heating zone.
Adjustment of burner excess air was planned. However even slight
changes in burner fuel to air ratio cause significant changes in kiln tempera-
ture that adversely affect product quality. This type of kiln therefore appears
to have very little flexibility for combustion modification.
Dry Process Rotary Cement Kiln
Cement kiln processes in the U.S. are about equally divided between
dry and wet processes. In the dry process, feed materials are fed to the kiln
as a dry finely-divided powder while in the wet process the feed is mixed with
water to form a slurry. One of each process type was tested.
The dry process kiln tested (site 3) was rated at a heat input of 77.8
MW (265 MMB/hr) and was tested at full capacity while firing a mixture of coke
(68%) and natural gas (32%). Previous data (Ref. 6) were available for this
kiln firing natural gas and oil separately. The purpose of the test was to
evaluate fuel switching as an NO emission control method. Emissions of NO
X 3*
while firing natural gas were 1050 to 1800 ng/J (1680 to 2900 ppm). Operation
on oil reduced NO to 400-710 ng/J (600-1085 ppm), a reduction of 60%. Opera-
X
tion on combined coke (68%) and gas (32%) produced NO emissions of 655-710
X
ng/J (950-1014 ppm), a 50% reduction. The coke fuel burned in these tests
contained 2.4% fuel nitrogen (equivalent to 1635 ng/J for 100% conversion) at
the tested 68% of total heat input. Therefore the measured emissions are from
24 to 43% of the theoretical fuel nitrogen emission rate. Actual fuel nitrogen
conversion is probably much lower because some of the measured NO was
undoubtedly due to thermal formation.
Lower NO emissions on solid and liquid fuels compared to gas are
X
attributed to the highly adiabatic nature of the process. Many cement kilns
are currently being converted from gas to solid fuels. This conversion will be
beneficial in reducing NO and could be pursued as an NO control method that
A A
is consistent with the reduction of industrial gas consumption.
15
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Wet Process Cement Kiln
The wet process cement kiln tested (site 9) was rated at 9.44 kg/S
(185 tons/d) of cement clinker with a heat input rate of 61 MW (210 MMBtu/hr)
and only operated on natural gas. Baseline NO emissions were 1319 ng/J
(2250 ppm) and particulate emissions upstream of an electrostatic precipitator
were 11000 ng/J (26 Ib/MMBtu). Particulate sizing indicated that 17 percent was
less than 3 ym.
Combustion modifications investigated included variation of combustion
air inlet temperature and excess oxygen. Increase of combustion air tempera-
ture from 644 K (750 °F) to 767 K (920 °F) increased NO emissions to 1518 ng/J,
a 15% increase. Reduction of excess oxygen at baseline air temperature reduced
NO to 846 ng/J, a 36% reduction. The independent reductions of either excess
air or air temperature caused unacceptable reduction of kiln temperature that
can result in a process upset. The NO emission was found to be a strong func-
tion of kiln temperature, shown in Figure 4. It was found that simultaneous
reduction of excess air and increase in air temperature could produce a reduc-
tion in NO of about 14% while maintaining kiln temperature.
COMBUSTION MODIFICATIONS ON METAL FURNACES
Metal furnaces tested included a steel open hearth furnace, a steel
billet reheat furnace, a steel ingot soaking pit and a scrap aluminum melting
furnace.
Steel Mill Open Hearth Furnace
Steel mill open hearth furnaces are being gradually phased out in favor
of the basic oxygen process. However, the open hearths have more flexibility
in charge composition and may remain a significant source of NO in areas where
their use is continued. (Ref. 9).
One open hearth unit was tested (site 14) while operating on combined
natural gas (60%) and Number 6 oil (40%). The rated heat input is 57.2 MW
(195 MMBtu/hr) and steel batch production is 3 x 10 kg (335 tons) per heat
cycle of 7 hours.
16
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Gaseous emissions were measured between a waste heat boiler and an
electrostatic precipitator over a full heating cycle without modification.
Wide fluctuations in NO and CO were observed as various operations were
X
performed as shown in Figure 5. Large changes in excess air occurred as the
operators opened doors to look at the steel and to add material or adjust fuel
flow to change heating rate. NO emissions varied from 100 to 3500 ppm and
X 6
averaged about 1800 ppm or about 950 ng/J (2.2 lb/10 Btu). NO increased
somewhat linearly with excess O«. Particulates emissions were 2200 ng/J
(5.02 Ib/MMBtu), measured upstream of the precipitator. Following baseline
tests the furnace was overhauled to repair refractory, fix leaks, etc. A
second test cycle was observed on the repaired furnace and the average NO was
1094 ng/J (2070 ppm), very close to the first cycle measured. A third cycle
was observed during which the excess air was controlled to minimize large in-
creases. The average NO emission was reduced to 660 ng/J (1250 ppm), a re-
ji
duction of about 40%. During baseline tests NO frequently exceeded 2000 ppm
X
but with the excess air controlled, excursions over 2000 ppm occurred only
twice.
Steel Billet Reheat Furnace
One steel billet reheat furnace was tested (site 16/1) while firing
natural gas. The rated heat input is 35 MW (117 MMBtu/hr) and tests were
conducted at from 13 to 30 MW. Baseline NO emission at 24 MW was 56 ng/J
x
(110 ppm) and particulates were 17 ng/J (0.04 Ib/MMBtu). This furnace had two
heating zones with 13 and 14 burners, respectively. The row with 13 burners
released about 80% of the heat input. Combustion modifications included re-
duced excess air, resulting in a 24% NO reduction, and burners out of service
which produced a 43% NO reduction with 3 burners out of service in the row
of 13 burners.
Steel Ingot Soaking Pit
One steel ingot soaking pit was tested (site 16/2) while firing natural
gas. The rated heat input is about 2.9 MW (10 MMBtu/hr) fired through a single
burner. Baseline NOx emissions at 2 MW was 52 ng/J (101 ppm) and reduction of
excess air reduced NO by 69% with no adverse effect on the steel.
17
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Scrap Aluminum Melting Furnace
The furnace tested (site 6) is a 39 Mg {43 ton) batch charged unit
used to melt scrap aluminum during a four to six hour cycle. Two package burners
fire natural gas or Number 2 oil at a rated heat input of 9.8 MM (33.6 MMBtu/hr).
Baseline NO emissions were 49 ng/J (96 ppm) on natural gas and 104 ng/J (185
ppm) on Number 2 oil. Adjustment of excess air was the only modification
possible and reduction of excess air produced a slight increase of 4 to 15%
in NO on both gas and Number 2 oil.
X
COMBUSTION MODIFICATIONS ON BOILERS FIRED WITH UNCONVENTIONAL FUELS
Four boilers were tested that fire fuels other than natural gas, oil,
or coal. These included one paper mill boiler fired on black liquor, two paper
mill wood bark waste boilers, and one petroleum refinery boiler fired with
carbon monoxide gas.
Paper Mill Black Liquor Recovery Boiler
' Black liquor is the waste liquid from the wood digestion process. It
contains sodium inorganics, water and lignin organics dissolved from
the wood. The sodium is recovered for reuse by spraying the liquor into a
boiler. The organics are burned and the sodium sulfate is reduced to sodium
sulfide ash which is removed from the boiler floor. Black liquor recovery
boilers differ significantly in design from conventional boilers in requiring
a reducing atmosphere near the bottom and an oxidizing atmosphere in the upper
part of the furnace. Natural gas (or oil) is frequently used for ignition and
load stabilization.
The boiler tested (site 10/2) is rated at 97522 kg (215,000 Ib) per hour
of steam flow. The combustion analysis for black liquor is a complex chemical
balance. Data were obtained but analysis has not been completed at the time
of this paper. It is therefore possible to provide emissions only in terms of
concentrations. Baseline NO emissions were relatively low, 52 ppm, but hydro-
carbons were high, 900 to 2700 ppm and CO was up to 30,000 ppm.
Combustion modification was limited to adjustment of secondary (upper
stage) air adjustment and reduction of black liquor solids content. Secondary
air adjustment reduced NO by 33% but increase hydrocarbons by 200%. Adjust-
ment of liquor solids content had little effect on emissions.
18
-------
The intimate connection of this type of boiler to the chemical pro-
cesses in the paper mill, and the complexity of the chemical process indicate
that achievement of emissions reduction by combustion modification will be
considerably more difficult than for conventional boilers,
Wood Bark Boilers
Of two wood bark boilers tested, the first (site 10/1) was rated at
91000 kg (200,000 Ib) per hour steam flow with a traveling grate stoker firing
wood and natural gas. Difficulties were experienced with fluctuating wood
feed rates. Baseline NO was 124 ng/J (229 ppm) corrected to 3% O . Particu-
X £
late emissions upstream of the precipitator were 1334 ng/J (3.0 Ib/MMBtu).
Only 5% of the particulate is less than 3 pm. Combustion modifications includ-
ed air preheater bypass, burner adjustments, and staged combustion by burner
shut-off. Lower excess air reduced NO to 75 ng/J (138 ppm) . Air preheater
bypass did not significantly lower emissions since O_ content was increased.
Shut-off of one of the four burners reduced NO about 20%.
The second wood bark boiler (site 13) was rated at 45400 kg (100,000
Ib) per hour steam flow and fired wood and coal with an overfeed traveling
grate stoker. During the test the boiler was firing about 25% bark and 75%
Kentucky coal. At peak bark flow, baseline NO emissions were 169 ng/J (226
X
ppm). Termination of bark flow increased NO to 232 ng/J (367 ppm). Baseline
X 6
total particulate emissions were 166 ng/J (0.38 lb/10 Btu) and 40% of the
particulate was less than 3 ym aerodynamic diameter. Variation of excess air
resulted in a reduction in NO of 15% with an NO& range of 160 to 250 ng/J. The
X
unit normally operates with overfire air ports 100% open. Closing these ports
to 30% open reduced NO by 18%. This behavior is contrary to most other boilers
and was attributed to observed changes in the point in the furnace where the
bark combustion took place.
It was concluded that wood bark boilers are similar to coal fired
boilers in response to combustion modification with the exception that wide
fluctuations in bark flow make it difficult to attain steady conditions.
19
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Carbon Monoxide Boiler
The catalytic cracking process in manufacture of gasoline generates an
off gas that contains about 10% carbon monoxide. This gas is used as a fuel to
fire boilers both to control emissions of CO and to provide steam.
The one CO gas boiler tested (site 11) was rated at 136000 kg (300,000
Ib) per hour of steam flow and had four spud type gas burner. It was also
equipped with staged air ports. Baseline NO emissions were 65 ng/J (126 ppm).
Baseline particulate emissions were 129.3 ng/J (0.301 Ib/MMBtu). Lowering
excess air reduced NO by 8% for a decrease in O0 from 2.1 to 1.8%. AcVust-
X £,
ments in NO ports changed NO less than 2%. Burners out of service did not
X X
result in any decrease in NO . CO emissions were much more sensitive to excess
oxygen with large increases in CO level being measured below about 2.0% O_.
The lack of response of NO to combustion modifications is attributed to
NOX that is formed from ammonia in the CO gas feed acting similarly to fuel
nitrogen in oil or coal.
COMBUSTION MODIFICATIONS ON INTERNAL COMBUSTION ENGINES
Two reciprocating internal combustion engines were tested. One drove
a natural gas compressor in a gas processing plant and the second was a diesel
engine driving an electric generator.
Natural Gas Compressor Engine
This engine (site 2) was an eight cylinder, 2 cycle, naturally aspirated
engine rated at a shaft power of 660 kW (880 hp) at 260 RPM and fired with
natural gas. Baseline NO emissions were 1020 ng/J (1990 ppm), CO was 1150
X
ppm and hydrocarbons were about 14000 ppm (mostly unburned fuel or methane).
Combustion modifications included load and speed variation and adjust-
ment of fuel and air. Load could only be adjusted about +_ 6% and this pro-
duced a decrease in NO of about 5% for both the increase or decrease in load
X
away from baseline. Increasing speed from 260 RPM to 300 RPM reduced NO by
10%. Fuel to air ratio adjustment was difficult because each cylinder had
separate adjustments and when these adjustments were changed there was no
apparent change in excess O™. However NO was decreased by 20% and hydrocarbons
were reduced by about 50% by the adjustments made.
20
-------
Diesel Electric Generator
The diesel generator engine (site 15) was a 4-stroke cycle, turbo-
charged, aftercooled, engine with twelve cylinders and rated at 600 kW at
1200 RPM. Baseline load was 400 kW operating with No. 2 diesel fuel. NO
• X
emissions were 830 ng/J (1476 ppm) and total particulates were 49 ng/J (0.114
Ib/MMBtu). Combustion modifications included variation of engine load and
inlet air temperature. Reduction of load to 200 kW did not produce any change
in NO but, at 100 kW, NO was reduced by 14%. Reduction of the inlet air
X X
temperature, by increased turbocharger aftercooling, from the baseline of
356 K (180 °P) to 344 K (160 °F) only reduced NOv by 7%.
X
Conclusions
It was concluded that in-field modifications on internal combustion
produce only small changes in emissions, at least for engines tested.
COMBUSTION MODIFICATIONS ON GAS TURBINE COMBINED CYCLE UNITS
No gas turbines operating in industrial plants were located on which
combustion modifications could be made directly to the gas turbine. Engines
with water injection are located primarily in electric utilities and have been
extensively tested in other programs. Some industrial gas turbines are equip-
ped with fired waste heat boilers and two of these were tested to evaluate the
potential the use of staged combustion as a means of reducing total NO . A
previous laboratory scale study had indicated the potential for destruction of
NO from the gas turbine by staged combustion in the boiler (Ref. 14).
Petroleum Refinery Combined Cycle
The first combined cycle system tested (site 7/3) consisted of a 12.5
MW gas turbine with a boiler rated at 23660 kg (515,000 Ib) per hour steam
flow. Both units used refinery gas fuel. Baseline NO emissions from the gas
X
turbine at 10 MW were 96.9 ng/J (190 ppm, 3% O_) and from the boiler at 91%
steam flow were 59.2 ng/J (118 ppm, 3% O2). The heat input for "Joules" in
ng/J is based only on the gas turbine fuel for gas turbine emissions but is
based on the total fuel to both gas turbine and boiler for the boiler exit
emissions. The gas turbine fuel heat release was 20.7% of the total fuel heat
input. Therefore, the NO mass flow from the gas turbine was increased by
200% in the boiler.
21
-------
Combustion modifications performed on the boiler consisted of ^ir
register adjustments and removal of one of the eight burners from servi-—
Air register adjustment reduced boiler stack CO from 401 ppm, 3% 0_ at base-
line to 12 ppm but increased NO by 8%. Removal of the burner from service
X
decreased boiler stack NO by 14%. This translates to a 156% increase in NO
X X
mass flow by the boiler, a 22% reduction in added NO formed in the boiler.
X
Chemical Plant Combined Cycle
The second combined cycle system tested (site 8) consisted of a 35 MW
gas turbine with a boiler rated at 697500 kg (1.538 x 10 Ib) per hour steam
flow. Both units fired refinery gas and the boiler could fire oil. Baseline
NO emissions firing gas in both units from the gas turbine at 76% load were
X
83.8 ng/J (166 ppm, 3% O..) and, from the boiler at 70% load, were 52 ng/J
(103 ppm, 3% O ). On a mass flow basis the NO mass flow increased by 195% in
^ X
the boiler. These levels are nearly identical to the petroleum refinery com-
bined cycle system discussed above. When the boiler was switched to No. 2 oil
the total NO emissions increased to 64 ng/J (114 ppm, 3% O_) or a 213% addition
to NO mass flow over the gas turbine emission rate.
x
Modifications (on gas only) consisted of air register adjustments and
removal from service of 2 and 4 of the 16 boiler burners. Air register adjust-
ment had no influence. Removal of 2 burners reduced total NO by 12% and removal
of 4 burners reduced total NO by 38%. The latter represents a 91% addition
2v
to total NO mass flow over the gas turbine NO mass flow. Relative to the
x x
213% addition to NO measured at baseline, a 55% reduction was obtained in NO
• X X
created by the boiler.
Conclusions
It was not possible to determine whether any gas turbine NO was being
X
destroyed in the boiler fuel-rich regions, indicated as possible in a prior
study (Ref. 14). That study suggested the possibility that total NO mass flow
X
from the boiler stack could be reduced below the mass flow level of the gas
turbine. The present data do not support that conclusion. However the large
(55%) reduction in the N0x added by the boiler when only 4 of 16 burners were
removed from service strongly indicate that some gas turbine NO destruction
X
may have occurred.
22
-------
SECTION 5 .
COMBUSTION MODIFICATIONS ON MODIFIED INDUSTRIAL BOILERS
During a previous program with EPA, KVB tested two industrial boilers
that had been modified to provide staged air (in both boilers) and flue gas
recirculation (in one boiler) . Results of those tests were presented in the
report of that work in which the boilers are identified by test location
numbers 19 and 38 (Ref. 3). Additional tests have been conducted on these
boilers as part of the current program to attempt to extend the reductions
previously achieved, evaluate modifications in combination and resolve some
limitations that were found.
COMBINED COMBUSTION MODIFICATIONS AT LOCATION 19
The boiler at location 19 was a single-burner oil- and gas-fired water-
tube unit rated at 7700 kg (17000 Ib) per hour steam flow with no economizer or
air preheater. The tests were run at 83% of full load. Second-stage combus-
tion air was injected through four steel lances which were inserted through
the windbox and the refractory firing face. Flue gas was withdrawn from the
base of the stack and was added to the burner air through wide slots just up-
stream of the burner throat.
Baseline emissions of NO were as follows:
Fuel
Natural gas (Ring burner)
(Gun burner)
No. 2 oil (less than 0.01% N)
No. 6 oil (0.20% N)
i. ppm, 3%
u-^ ^•^_i,im...^M»I_ir-
96
92
110
221
Oil atomization was by high-pressure (28 psig) air. A gas ring normally
used for natural gas injection was found to be unstable with the particular
flue-gas recirculation pattern used. Therefore a gas gun was used, rather than
a ring, for most of the gas fuel tests.
23
-------
The percentage reductions in NO and resulting changes in efficiency
X
are shown in Table IV. The No. 2 oil results are unusual in that a * NO
X
reduction was achieved with flue gas recirculation alone. This may be J-^cause
the high-intensity mixing and atomization by the air atomizer, and the relative-
ly high volatility and low nitrogen content of the fuel, combined to give a
gas-like flame.
The results for combined modification with No. 6 oil are also unusual
in that NO reductions of 55% as shown have not been previously achieved with
A
fuels of this type.
It was noted that boiler efficiency was reduced by flue-gas recircula-
tion even though no increase in excess 02 was necessary. This is because the
average temperature the combustion produces is reduced, lowering the tempera-
ture-difference potential for heat transfer. The flow per unit area increases,
tending to increase heat transfer, but the reduced temperature difference
!
results in a greater offsetting tendency for reduced heat transfer.
The results were achieved with CO concentrations of less than -500
pprnV and particulates emissions of less than 0.10 Ib/million Btu.
These results are of course for one particular boiler and are not
necessarily indicative of what might be achievable on a boiler of different
size or design.
COMBUSTION MODIFICATIONS AT LOCATION 38
The industrial boiler at location 38 was a single burner oil- and gas-
fired watertube unit with combustion air preheating, rated at 20000 kg (45,000
Ib) per hour steam flow. Tests were conducted at 89% load. Second-stage com-
bustion air could be injected through- any of 10 side fire air ports. Combustion
air preheat temperature could be varied from about 338 to 450 K (150 to 350 °F).
Baseline emissions of NO were as follows:
Fuel Air Preheat K (°F)
Natural Gas 411 (280)
No. 6 oil 408 (275)
, ppm, 3%
170
270
24
-------
The effect of excess air on NO was evaluated for both natural gas and
No. 6 oil firing. The effect of O on NO for natural gas exhibited a leveling
trend above approximately 2-1/2% O . The maximum reduction, at 1.45% 0 was
£ £,
approximately 10% less than the nominal condition. With No. 6 oil a similar
trend was exhibited. The reduction was approximately 17% from the nominal
condition of 2.9% O .
£t
The effect of combustion air preheat temperature on NO was evaluated
A
and showed a considerable decrease in NO with reduced windbox temperature for
both fuels. The windbox temperature variation had a greater effect on NO with
A
natural gas firing than with No. 6 oil firing. Nominal values of NO decreases
ii
were 7.2 ppm/10 K (4 ppm/10 °F) for natural gas and 4.5 ppm/10 K (2.5 ppm/10 °F)
for No. 6 oil.
The effect of staged combustion air (SCA) on NO emissions was evaluated
A
by injecting second-stage air through various combinations of opposing ports
at five locations ranging from 100 to more than 300 cm from the furnace front.
The data for NO versus SCA port location for oil fuel indicated that the most
A
effective injection point is that most distant from the burner. The data for
natural gas firing indicate a similar trend, except that the ports nearest the
burner exhibited the same effectiveness as did the most distant ports. This
may be due to the different geometric relationship between burner fuel and air
flows (center oil gun vs. outside ring gas burner) and greater sensitivity of
the NO emissions to combustion air temperature with natural gas. At the
nominal condition of 2.8% O2 and 14% SCA flow, the NO was reduced 30% for
No. 6 oil with injection at approximately 300 cm from the furnace front.
Reducing the operating
condition. Staged combustion with natural gas resulted in a reduction of 32%
to 2.3% reduced the NO by 42% from the baseline
X
from the baseline condition with the boiler operating at 2.4% excess O and
14% SCA.
-------
SECTION 6
; TRACE SPECIES AND ORGANIC MEASUREMENTS
INTRODUCTION
Measurement of trace species and organic emissions were made o. seven
of the devices tested in this program:
Device Type
Forced draft heater
Wet process cement
kiln
Steel open hearth
furnace
Black liquor recovery
boiler
Wood bark boiler
Diesel engine
Modified boiler
Test site No.
Fuel
12/2
9
14
10/2
13
15
19
Ref . gas
Nat . gas
NG + NO. 6
Oil
Liquor
Wood+coal
No. 2 oil
No. 6 oil
Sample Position
Furnace stack
Precipitator inlet &
outlet
Precipitator inlet
Precipitator inlet &
outlet
Precipitator outlet
Engine stack
Stack at baseline &
low NO
The analysis of samples collected is not yet complete for these devices. How-
ever, an initial sampling system check run was conducted on a coal-fired boiler
in the KVB laboratory. Results of that test are presented.
SAMPLING PROCEDURE
The EPA (IERL-RTP) has developed the Source Assessment Sampling Sys-
tem (SASS) train for the collection of particulate and volatile inorganic
and organic matter with a single sampling system. ,A stainless steel heated
probe is connected to an oven module containing 3 cyclones and a filter.
Particle size fractionation is accomplished in the cyclone portion of the
SASS train, which incorporates the cyclones in series to provide large
Manufactured by Aerotherm Corporation, 485 Clyde Avenue, Mountain View,
CA, 94042, Tele. (415) 964-3200.
26
-------
quantities of particulate matter size-classified into three ranges: a) >10 ym,
b) 3 Mm to 10 ym, and c) 1 pm to 3 ym. A fourth cut, <1 yro, is obtained with
a standard 142 ram filter. Volatile organic material is collected in an organic
sorbent module. The module is an integral part of the gas treatment system
which follows the cyclone oven. The gas treatment system is composed of four
primary components: a gas temperature conditioner, an organic adsorbent trap,
the aqueous condensate collector, and a temperature controller. The organic
sorbent is XAD-2 porous polymer resin with the capability of adsorbing a broad
range of organic species. Volatile inorganic elements are collected in a
series of three liquid impingers followed by one impinger containing a
drying agent. The pumping capacity is supplied by a 10-cfm high volume vacuum
pump. Required pressure, temperature, power and flow conditions are obtained
from a main controller module.
Procedures for use of the SASS train as part of a complete environmental
assessment test program have been detailed by EPA (Ref. 10). KVB used those
procedures as the basic approach to sampling in the current program. However,
the current program was not formulated as an environmental assessment as de-
fined in Reference 10. Rather, the objective was to quantify the emissions
and mass distribution characteristics of 24 specific inorganic species, total
polycyclic organic matter (POM), eight specific POM compounds, and total poly-
chlorinated biphenyls (PCB). In addition, the general nature of emissions of
a large number of elements was to be examined. The specific list of species
to be identified is presented later in this section in the discussion of
sampling results.
The SASS train was used for sampling stack gases and samples were
also collected of all the input and output materials such as fuels, process
feed, products and wastes as necessary to establish mass distributions.
SAMPLE ANALYSIS
Sample analysis involved the use of atomic absorbtion, spark source
mass spectrometry, and wet chemistry for inorganic species. POM and PCB were
analyzed by extraction with pentane, isolation by aliphatic-aromatic separation
27
-------
with pentane and benzene elution by silica gel adsorbtion chromatography.
The benzene fraction was analyzed for POM and PCB using gas chromatography
employing combined flame ionization and electron capture detectors. Ais
analysis is being performed by Calspan Corporation, Buffalo, NY.
For selected samples indicated to have high POM content, analysis by
gas chromatography and mass spectrometry is being1 performed to more positively
quantify POM content. This analysis is being performed by the Battelle-
Columbus Laboratory.
LABORATORY BOILER SAMPLING TEST
Previous trace species and organic sampling by KVB with a modified
EPA Method 5 sampling system had indicated deficiencies in collection of vola-
tile inorganics (Ref.15). That sampling system was also very cumbersome for
use on stack platforms. For the current program, it was deemed desirable to
conduct a well-controlled laboratory test both to evaluate the sampling
ability of the SASS system and field test compatibility. Such a test was
conducted in a combustion research laboratory at KVB.
The KVB laboratory boiler is a scotch type dry back boiler with a
rated heat input of 1.2 MM (4 x 10 Btu/hr), The boiler was fitted with a
single burner for firing pulverized coal. Preheated air is supplied at
533 K (500 °F) by forced draft. The boiler exhaust is cleaned with a baghouse.
Prior to the test, the boiler was disassembled and cleaned so that ash de-
posited during the test could be recovered. The SASS train sample point was
located in the duct between the boiler and the baghouse.
The coal fuel was Pittsburg #8 West Virginia coal. Proximate and
ultimate analysis as received was:
Proximate (% weight)
Moisture 1.50
Volatile 37.89
Fixed carbon 53.15
Ash 7.46
Sulfur 2.69
Heating value,
k J/Kg 31827
(Btu/lb) 13684
Ultimate (% weight)
Moisture 1.50
Carbon 76.28
Hydrogen 5.19
Nitrogen 1.39
Sulfur 2.69
Chlorine 0.04
Ash 7.46
Oxygen (diff) 5.45
28
-------
This coal was recommended by EPA because the trace element content was known
',
to be sufficiently high to enhance SASS train evaluation.
The test plan was established on the basis of a SASS train sample
The
collection volume of 30 m (1060 ft ) as specified in Reference 10
train used had a design sampling rate of 4.0 actual wet cubic feet per minute
(0.00189 a w N m3/S) through the cyclone train at 478 K (400 °F) or 0.00111
3 3
dry N m /S (2.34 std ft /m) at standard dry conditions. Sample time to col-
lect 30 dry N m was 7.54 hours. [The SASS train has since been redesigned
for a higher flow rate of 0.00189 std N m /S (4.0 std ft /m)].
The test conditions are summarized in Table V. Total boiler operat-
ing time was 16.7 hours (continuous) of which 7.53 hours were required (inter-
mittently) for sampling. The additional 9.2 hours was required to resolve
train operational problems and to change the filters and dryerite in the
train. Three filters were used. The quantity of ash removed from the furnace
was 91% (carbon and moisture free) of the expected ash based on coal analysis.
Train operation was very stable. The isokinetic sampling rate varied from
82% to 106% with an average of 100.6%.
Conclusions from the test regarding operational capability of the
SASS train were:
1. The train functioned properly throughout the test with
respect to sample acquisition capability.
2. Mechanical problems with the cyclone assembly were ex-
perienced and attributed to the type of connecting fit-
tings used. The fittings were not well suited for re-
peated use since deformation of mating surfaces (rendering
separation difficult) is not easily avoided when a leak-
free joint is desired. The threaded parts also galled
at elevated temperatures because no lubricants could be used
to avoid contamination.
3. Ice consumption in the impinger bath was excessive, 122
kg (270 Ib) were used. Insulating the ice bath from
surrounding air may help to maximize its cooling ef-
fectiveness.
4. No condensation occurred in the XAD-2 module operated
at 328 K (130 °F). This temperature is above the dew-
point for coal fuel exhaust (IERL-PMB has specified a
29
-------
lower temperature for future tests). The XAD-2 module
satisfactorily maintained the adsorbent temperature with-
in 3 °K (5 °F) of the desired temperature.
5. Boiler ash recovered was close to 100% of expected ash.
SASS train particulate catch was within 20% of expected
collection. These results should provide a good basis
for mass balance of the trace elements.
6. Pluggage of the sampling filter necessitated renewal of
: the filter element two times during the test. Particulate
grain loadings were similar to those encountered upstream
of particulate removal devices at conventional pulverized
coal fired boilers. To minimize downtime/for filter changes,
a large filter design may be necessary to allow a 4 to 5
hour run period per filter.
RESULTS OF SAMPLE ANALYSIS
Samples were analyzed for the species listed in Table vi. Results
expressed as mass flow rates are indicated for the coal, ash retained in the
furnace, SASS train samples, and the baghouse ash.
Coal samples were taken at approximately one-half hour intervals during
that entire test period. Two composite coal samples were analyzed: one con-
sisted of equal portions from the entire amount of coal burned and the second
consisted of equal portions of only.that coal burned during actual sampling
by the SASS train. The species input rates for both coal samples are similar
with the exception of antimony, cadmium, fluoride, and total POM. These four
species were lower in the coal burned during SASS sampling. Five species were
below detection limits in both coals: selenium, tellurium, tin, nitrates, and
total PCB. Only tellurium and total PCB were below detection limits for all
collected samples.
Most of the elements with non-volatile characteristics were collected
in the solids section of the SASS train. Antimony and arsenic were expected
to be collected mainly in the impingers; however, larger amounts were collected
in the solids section. Mercury was predominantly collected by the impingers
as expected and most total POM was collected in the organic module as expected.
Results for all PCB measurements on every sample analyzed were all below detec-
tion limits. The collection of chromium and nickel was unexpectedly high in
the organic module, attributed to erosion of stainless steel from the train.
With the exception of tellurium and total PCB, every species was above detec-
tion limits for the total amount collected by the SASS train.
30
-------
Mass balances on each specie were evaluated and several criteria for
performance evaluation are presented in Table VII. The first column lists
the specie stack emission rate inyg/m as measured by the SASS train. The
amount of each species input by the coal less the amount retained in the
furnace ash is a measure of the potential emission rate assuming all unre-
tained species are emitted in the stack. In calculating the unretained
amount, the furnace ash amount was subtracted from the amount input by the
total amount of coal burned. The resulting difference was then multiplied by
the ratio of the amount measured in the coal burned only during the SASS
sampling period to the amount measured in the total coal. This result was
then used as the unretained amount for comparison with the amount collected by
the SASS train. This procedure corrects for differences in the coal samples.
The second column in Table VII gives the ratio of amount collected by
the SASS train to the unretained amount. For six elements, (antimony, barium,
cadmium, calcium, cobalt and titanium), the relative emission ratios are within
+ 14% - 7%. Barium, calcium, and titanium are elements that are most likely
to produce a good mass balance because of low volatility and absence of con-
tamination. The excellent mass balance on these elements therefore verifies
the basic acceptability of the test procedures and sample handling. There are
four elements with negative values {chromium, manganese, nickel and zinc),
indicating a larger amount was found in the furnace ash than was input from
the coal. These four elements are those for which the coal input could be
augmented by metal in the train or boiler. It is therefore difficult to
evaluate the train collection mass balance performance on these elements. Four
species (arsenic, copper, tin, and chloride) have large positive values, in-
dicating much higher SASS collection rates compared with the unretained emis-
sion. Iron is also higher by a factor of two. Elements for which the rela-
tive emission ratio was low include beryllium, lead, and selenium. Total
POM is also very low, but this is expected because POM in the coal should be
consumed in the flame. The results indicate about 98% of the POM is burned
and 2% is emitted. For vanadium and mercury the relative emission ratio is
low.
31
-------
The third column in Table VII lists the ratio of amounts collected in
the cyclone and filter section of the SASS train to that collected in the bag-
house. The SASS train should be a better collection device compared f» the
baghouse so that all ratios would be expected to be greater than unity. The
values in the table that are significantly less than unity include those for
calcium, selenium, zinc, and fluoride. The ratios for antimony and arsenic
are substantially greater than unity indicating that the SASS cyclones are
collecting unexpectedly high amounts of these two volatile elements.
The fourth column in Table VII lists the overall mass balance for each
species. The trends are similar to those of the relative emission ratic but
a value of close to one for the mass balance can be misleading in judging SASS
train performance in those cases where most of the species is retained in the
furnace. In general, the overall mass balances were within a factor of 2 to
3 which is the stated objective for initial environmental assessment tests
(Ref. 10). However, values for chromium, nickel, selenium, and chloride
exceed a factor of three.
The last column in Table VII lists mass balance values based on the
baghouse collection instead of the SASS train. These values are of use in
assessing whether the mass balance errors are the result of poor train col-
lection efficiency or are the result of experimental uncertainties.
Conclusions
The excellent mass balances obtained on the major non-volatile ele-
ments verified the basic test procedures, sample recovery, and analysis. The
fact that the major portion of the organics was collected in the organic module
and that organics downstream of the module {impingers) were below detection
limits verified that no organic breakthrough occurred and that organic collec-
tion efficiency was excellent. Results for collection of the most volatile
elements, antimony, arsenic, mercury and selenium were mixed. The amounts of
antimony and arsenic collected exceeded expected levels based on mass balances
and collection in the solids section was higher than expected. Only about 60%
32
-------
of the mercury was recovered. Selenium recovery was only about 25%. However,
the concentrations in the coal of mercury (0.03 Ug/g) and selenium (1 yg/g)
were very low and further analysis of the experimental precision is necessary
to evaluate the results.
The results of this laboratory test will be of importance in evaluat-
ing results obtained in field tests on this and other programs.
33
-------
SECTION 7
REFERENCES
10.
11.
Ricci, L. J., "EPA Sets its Sights on Nixing CPI's NOx Emissions,"
Chemical Engineering, Vol. 84, No. 4, pg. 33, February 14, 1977.
Siddiqi, A. A., et al., "Control NOx Emissions From Fixed Fireboxes,"
Hydrocarbon Processing, pg. 94, October 1976.
Cato, G. A., et al., "Field Testing: Application of Combustion Modifi-
cations to Control Pollutant Emissions From Industrial Boilers—Phase
II," EPA 600/2-76-086a, PB 254 500/AS, April 1976.
Ando, J., et al., "NOx Abatement for Stationary Sources in Japan,"
EPA 600/2-76-013b, PB 250 586, January 1976.
Muzio, L. J., et al., "Gas Phase Decomposition of Nitric Oxide in Com-
bustion Products," Presented at the EPRI NOx Control Technology Seminar,
San Francisco, California, February 1976.
Anon., "Special Project Report, Overview Matrix," Source Assessment
Contract 68-02-1874, Monsanto Research Corp., July 7, 1976 (Unpublished,
obtained from Dr. D, Denny, EPA, Research Triangle Park).
Mason, H. B., "Survey of Control Techniques for Nitrogen Oxide Emissions
From Stationary Sources," AIChE, 83rd National Meeting, March 24, 1977,
Houston, Texas. (Available from Aerotherm Division/Acurex Corp.,
Mountain View, CA.)
U.S. Environmental Protection Agency, "1973 National Emissions Report,"
EPA 450/2-76-007, May 1976.
Ketels, P. A., et al., "A Survey of Emissions Control and Combustion
Equipment Data In Industrial Process Equipment," EPA 600/7-76-022,
October 1976.
Hamersma, J. W., et al., "IERL-RTP Procedures Manual: Level I Environ-
mental Assessment," EPA 600/2-76-160a, June 1976.
Bartz, D. R., et al., "Control of Oxides of Nitrogen from Stationary
Sources in the South Coast Air Basin of California," PB 237 688/7WP,
September 1974.
34
-------
12. "Compilation of Air Pollutant Emission Factors - Second Edition,"
(Second Printing with Supplements 1-4), U.S. Environmental Protection
Agency, AP-42, March 1975.
13. Devorkin, H. and Steigerwald, B. J., "Emissions of Air Contaminants
From Boilers and Process Heaters," Joint District, Federal and State
Project for the Evaluation of Refinery Emissions, Report Number 7,
(Los Angeles Air Pollution Control District), June 1958.
14. Anon., "Reduction of NOx Through Staged Combustion in Combined Cycle
Supplemental Boilers," Electric Power Research Institute, Report
EPRI 224, February 1975. (NTIS order No. PB-241 463)
15. Cato, G. A., "Field Testing: Trace Element and Organic Emissions from
Industrial Boilers," EPA 600/2-76-086b, NTIS Order No. PB 261 263, October
1976.
35
-------
TABLE I. RANKING OF MAJOR NO STATIONARY SOURCES
ACCORDING TO THREEXDATA SETS
MQ. Source
1 Boilers, Utility, Coal
2 Engines, Reciprocating
3 Boilers, Ind/Coml, Oil
•4 Boilers, Utility, Oil
5 Boilers, Utility, Gas
6 Boilers, Ind/Coml, Coal
7 Boilers, Ind/Coml, Gas
8 Gas Turbines
9 *Heaters, Petroleum Process
10 *Kilns, Cement
11 Space Heating, Ind/Coml
12 *Furnaces, Glass
13 Catalytic Cracking, Petroleum
14 *Furnaces and Smelters, Metals
15 Coal Refuse Piles (and Mines)
16 Nitric Acid Mfg
17 *wood Waste Incin., Boilers
18 *Kilns and Dryers, Brick
19 *Mineral Wool Mfg
Others
Total
Majnr Group Totals
Boilers (coal, oil gas)
Engines, Reciprocating
Gas Turbines
*industrial Combustion
Gg/y = 1100 tons/yr
NOX
Gg/y1
(Ref. 6)
3495
2132
1245
1114
835
735
491
253
167
91
81
68
61
__
31
27
24
9
8
504
11371
7915
2132
253
350
NOX
Gg/y
(Ref. 7)
3660
1945
1040
765
860
561
487
236
—
99
—
116
47
—
—
127
—
—
—
J363
12306
7373
1945
236
215
NOX
Gg/y
(Ref. 8)
4200
245
363
955
1010
513
712
87
880
130
— —
5
36
40
—
78
137
2
0
1360
10753
7753
239
87
1154
36
-------
TABLE II. INDUSTRIAL COMBUSTION TEST UNITS SELECTED AND
SUMMARY OF RESULTS OBTAINED
Device Type
Natural Draft Process
Heater
Natural Draft Process
Heater
Natural Draft Process
Heater
Natural Draft Process
Heater
Natural Draft Process
Heater
Forced Draft Heater,
Air Preheat
Forced Draft Heater
Clay Tunnel Kiln
Rotary Cement Kiln
(Dry Process)
Rotary Cement Kiln
(Wet Process)
Steel Open Hearth
Furnace
Steel Reheat Furnace
Steel Soaking Pit
Aluminum Melter
Black Liquor Recovery
Boiler
Wood Bark Boiler
Wood Bark Boiler
CO Boiler
Natural Gas Engine
Diesel Engine
Gas Turbine Combined
Cycle
Gas Turbine Combined
Cycle
Test
Site
No.
4
5/1
5/2
7/1
7/2
12/1
12/1
12/2
12/2
1
3
9
14
16/1
16/2
6
6
10/2
10/1
13
11
2
15
7/3
8
Average
Baseline NOX
Fuel
Ref .Gas
Ref. Gas
Ref .Gas
Ref .Gas
Ref .Gas
Ref .Gas
No. 6 Oil
Ref .Gas
No. 6 Oil
Nat. Gas
Nat . Gas
NG-t-Coke
Nat. Gas
NG +
Ho. 6 Oil
Nat. Gas
Nat. Gas
Nat. Gas
No. 2 Oil
Liquor
Wood+NG
ng/J1
59
50
39
52
49
163
113
109
88
46
1425
1319
1094
56
52
49
104
__
124
Wood+Coal 188
CO Gas
Nat . Gas
No. 2 Oil
Ref .Gas
Ref .Gas
65
1020
830
59
52
ppm @
3* 0?
116
97
76
103
98
320
222
214
157
90
2300
2250
2070
(Avg)
110
101
96
185
52
229
300
126
1990
1476
118
103
Maximum
Percent
Reduction Combustion
in NOX
18
22
21
8
24
0
0
67
8
41
50
14
40
43
69
0
0
30
40
15
8
20
7
14
38
Modification
4/32 BOOS
Air Register
Adjust
High Load,
Low 02
2/16 BOOS
Air Register
Adjust
Baseline
Lowest 02
Low 02 No
Effect
Low 0
Low O
Low O2
Fuel Switch,
Gas to Coke
Low O2, High
Air Temp.
Low O
3/27 BOOS
Low 02
Low O- (NO
increased)
Low O2 (NO
incr eased )X
Secondary Air
Adjust
Low 02
Low 02
Low 02
Fuel, Air
Adjust
Low Inlet Air
Temp.
1/8 BOOS
4/16 BCOS
ll lb/106 Btu =430 ng/J
2BOOS = Burners out of service
37
-------
TABLE III. SUMMARY OF EMISSION MEASUREMENT INSTRUMENTATION
Emission Parameter
Symbol Measurement Method
Equipment
Manufacturer
Nitric oxide NO
Oxides of nitrogen NO
A
Carbon monoxide CO
Carbon dioxide C02
Oxygen 02
Hydrocarbons HC
Sulfur dioxide SO
Sulfur dioxide SO
Sulfur trioxide SO
Total particulate
matter
Particulate size
distribution
Smoke spot
Opacity
Trace species TS&O
and organics
Cheitiiluminescent
Chemiluminescent
Nondispersive infrared
Nondispersive infrared
Polarographic
Flame ionization
UV spectrometry
Absorption/titration
EPA Std. Method 5
Cascade impactor,
electro-balance
Field service type
smoke tester ASTM D-2156
EPA Std. Method 9
Source Assessment
Sampling System (SASS)
Thermo Electron
Thermo Electron
Beckman
Beckman
Teledyne
Beckman
Du Pont
Shell-Emeryville
Absorption train
Joy Mfg. Co.
Anderson, Brink,
Cahn
Aerotherm
38
-------
TABLE IV. SUMMARY OF NOX REDUCTION AND EFFICIENCY CHANGE AS A FUNCTION
OF COMBUSTION MODIFICATION TECHNIQUE FOR VARIOUS FUELS
LOCATION 19
Baseline NO , ppmV at 3% 0
Combustion Modification
Technique
Lowered 0
Staged Combustion Air (SCA) ,
Normal 02
SCA, Low 02
Flue Gas Recirculation
(FGR) , Normal O2
FGR, Low O2
FGR + SCA, Normal O
FGR + SCA, Low 02
Baseline efficiency
Combustion Modification
Technique
Lowered O
SCA, Normal O
&
SCA, Low O
FGR, Normal O_
FGR, Low O
FGR + SCA, Normal 02
FGR + SCA, Low O2
Natural Gas
Ring Gun
96 92
No. 2 Oil
(0.00% N)
110
NOV Reduction, Percent
191 3.3
32 46
42
77
79
76
2
78.2 82.6
Change in
-1.21 +0.9
+0.1 +0.3
+0.5
-0.8
-0.4
-0.5
2
20
30
44
68
73
69
77
82.5
No. 6 Oil
(0.20% N)
221
of Baseline
30
29
42
11
40
53
55
82.5
Efficiency, Percent
+1.5
+0.9
+1.1
-1.9
+0.9
-1.2
-0.8
+1.5
+0.1
+0.8
-0.7
+0.6
-0.8
+0.1
NO reduction occurred at increased 0, level.
X £
Stability limit prevented lowering 0_.
39
-------
TABLE V. KVB BOILER SASS TEST SAMPLING CONDITIONS
Operating time, min (h)
Boiler firing rate,
MW (106 Btu/h)
Coal burned, kg (Ib)
Ash collected, kg (lb)
Furnace tube
Firetubes
Stack surface
Baghouse
• Total
Total
Boiler
Operation
Period
1002 (16.7)
0.83 (2.8)
1558 (3427)
51.4 (113)
25.9 (57)
1.4 (3)
41.8 (92)
120.5 (265)
SASS
Train
Sampling
Period
452 (7.53)
0.85 (2.9)
721 (1586)
Stack conditions (average)
Velocity m/s (ft/s), diam = .28m
Flow rate N m3/s (SCFM), wet
Flow rate N m3/s (SCFM), dry
Gas temperature, K (°F)
Excess oxygen, % dry
Moisture, %
Total gas volume, m (ft-') dry
SASS train conditions
Actual cyclone flow rate,
a m3/s (ACFM), wet
Flow rate, standard, dry,
N m3/s (SCFM)
Total meter volume, m (ft3), dry
Total standard volume, m3 (ft3)/ dry
Oven temperature, K (°F)
XAD-2 module temperature, K (°F)
Isokinetic rate, %
Solid particulate collected, g
Solid particulate loading, g/DSCM (gr/DSCF)
Emission factor, ng/J (Ib/MMBtu)
12.7 (41.7)
0.358 (760)
0.3404 (721)
629 (673)
6.0
5.0
9232 (326038)
0.00189 (4.0) +10%
0.00111 (2.34)
33.4 (1180)
30.0 (1060)
(400+5)
(130+5)
478+2
328+_2
100.6
77.07
2.6 (1.12)
957 (2.23)
40
-------
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41
-------
TABLE VII. KVB BOILER SASS TEST EMISSION MASS BALANCE
Species
Antimony
Arsenic
Barium
Beryllium
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Manganese
Mercury
Nickel
Selenium
Tellurium
Tin
Titanium
Vanadium
Zinc
Chloride
Fluoride
Nitrates
Sul fates
Total POM
Total PCS
Emiss ion
by SASS,
JJg/m3
690
163<170
1800
13<16
8.3<9
310OO
4500
240
190
140000
170
730
1.3<1.7
1600
3.1<4.0
<1300
125<670
31000
640
475
94000
1100
2900
64000
220<260
<330
Relative2
Emission
Ratio
1.14
5.40
0 .97
0 .28
1.12
0.93
-13.50
0.98
13.50
2.20
0 .29
-4.19
0 .61
-4.11
0.13
-------
Test Site 5
120
100
80
s
o<
Hi
60
40
20
16 Burner
Heatter
10 Burner Heater
Refinery Gas Fuel
10
12
PROCESS RATE, 10 BARRELS PER DAY
14
Figure 1. Effect of process rate on HO emissions from a process heater.
43
-------
CO
u
u
X
a
•*?
m
co
o
tn
its
O
0)
c
aj
w
t<
CO
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O
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-------
Test No. 12/1
Preheat = 725 °F
(658 K)
Refinery Gas
No. 6 Oil
Baseline
400
x
05
Q
CN
Of
n
S
IX
&
300
200
100
o
Q
123
FLUE GAS EXCESS OXYGEN, % DRY
Figure 3. WO versus excess O for a balanced draft process heater with
combustion air preheat.
45
-------
3000
2500 —
Q 2000
df
n
s
g 1000 __
500 _
Baseline
(6.0%)
Inlet air temperature
variation
Location 9 - Rotary cement kiln
Wet process
{ ) I- Exit 02 concentration
1500 _
2100
(1422)
2300 2500 2700
(1533) (1644) {1756}
KILN TEMPERATURE, °F (K)
2900
(1867)
Figure 4. The effect of cement kiln temperature on NO emissions.
46
-------
4000.
3500
3000
250°
<*>
ft
E-i
<
S
O
•z
2000
1500
1000
500
Baseline Test
Test No. 14-1
No. 6 Oil and Gas Fuel
385 ton Heat
1200 1300 1400 1500 1600
TIME OF DAY
1700
1800
1900
Figure 5. NO emissions as a function of time for an open hearth furnace.
47
-------
-------
BOILER BURNER DESIGN CRITERIA FOR RETROFIT WITH
LOW-Btu GASES
By:
D. R. Shoffstall and R. T. Waibel
Institute of Gas Technology
Chicago, IL 60616
49
-------
-------
ABSTRACT
This research program was initiated to characterize the problems associated
with retrofitting existing utility boilers with low-Btu gases manufactured from
commercially available coal conversion processes. All the experimental results
were gathered from a pilot-scale furnace fired with a movable-vane boiler burner
at a rate of Z,250,000 Btu/hr. Low-Btu gases tested ranged in heating value from
300 Btu/SCF to 100 Btu/SCF and were synthetically produced with a natural gas
reformer-generating system.
Data were collected to permit a comparison between natural gas and low-Btu
gases in the areas of flame stability, flame length, flame emissivity, changes in
boiler efficiency, and NOX emissions* The NO emission data yielded an activation
energy of 153 kcal/mol compared to kinetic models which predict 135 kcal/mol.
This good agreement suggests that peak temperatures approaching the adabatic
flame temperature are controlling the rate of NO emissions. Thus, the use of the
adabatic flame temperature provides a good empirical method for predicting NO
emissions from low-Btu gas combustion.
51
-------
-------
INTRODUCTION
The electric power industry is caught between the Federal Government's concern
for cleaning up the environment and for decreasing (or eliminating) our depen-
dence on foreign sources for oil. The environmental concerns make the use of coal
prohibitively expensive, if not impossible, because of the necessity of decreasing
sulfur emissions. Low-sulfur oil could replace coal, but this oil must be imported,
which is against long-range government policy. Coal appears to be the only fossil
fuel available in sufficient quantities to eliminate the necessity of importing oil;
however, an environmentally acceptable and practical way must be found for its
use.
One concept that could provide a practical method for using coal is to convert it
to low-sulfur, ashless, low-Btu gas for use in boilers. This would alleviate both the
utility industry's fuel supply problem and the air pollution problem. Of particular
concern, however, are the prospects of operating problems and loss of boiler out-
put (downrating), which can occur when retrofitting a unit originally designed to
use another fuel. Accurate combustion data are needed to define the potential
magnitude of these problems and to indicate whether practical solutions are
possible.
This paper presents results from an experimental program designed to character-
ize the problems associated with retrofitting existing boilers for low- and
medium-Btu gases made from commercially available coal conversion processes.
Data were collected to permit a comparison of natural gas and low- and medium-
Btu gases in the areas of :
• Flame stability
• Flame length
• Flame eraissivity
• Flue-gas pollutant emissions, and
• Boiler efficiency
53
-------
SUMMARY
All of the experimental results presented in this report were taken from a pilot-
scale furnace fired with a movable-vane boiler burner (MVBB) at a heat input of
2.25 million Btu/hr.* In addition to natural gas, five medium- and low-Btu gases
were tested: Lurgi oxygen, Koppers-Totzek oxygen, Winkler oxygen, Wellman-
Galusha air, and Winkler air. A synopsis of the test results for a 45-degree vane
angle is presented in Table 1. This table includes furnace operating conditions,
burner operating conditions, fuel combustion properties, and experimental data for
the MVBB with a 45-degree vane angle. The information includes gross heating
value of the fuel; adiabatic flame temperature with 3% excess oxygen and
combustion air preheat of 325°F; input velocity of fuel and combustion air at
60°F; hydrogen-to-carbon monoxide ratio of fuel; gross input enthalpy, including
combustion air preheat; chemical species analysis of flue gases; volume of flue
gases at 60°F; measured flue-gas temperature; measured furnace rear-wall tem-
perature; calculated and measured emissivity; and concentration of NO measured
in the flue at 3% excess oxygen.
Based on a detailed analysis of the experimental data, the following conclusions
were made:
1. Flame stability was established for each test fuel under the most severe oper-
ating conditions, that is, with the furnace walls, burner block, and combustion
air at ambient temperature. The flame stability was very sensitive to fuel jet
velocity leaving the fuel nozzle. An injection velocity of 100 ft/s was found to
give the best operation.
2. For all fuel gases tested, the flame length decreased with increasing movable-
vane angle (swirl of the combustion air). Medium- and low-Btu fuel gas flames
were shorter than those for natural gas with the exception of Winkler air at a
45-degree vane angle, which produced a flame 10% longer than the natural gas
flame.
3. Babcock and Wilcox used the pilot-scale test furnace data as input to their
utility boiler design calculation to evaluate overall unit output when retrofit
with medium- and low-Btu gases. The calculation technique used divided the
boiler into a radiant (furnace) section and a convective section. The IGT
experimental data were used as input conditions to the convective section. The
* It is EPA policy to use metric units; however, in this report
English units are occasionally used for convenience. See attached
conversion table.
54
-------
Table 1. SYNOPSIS OF FURNACE OPERATING CONDITIONS
(Part 1)
Fuel
Natural gas
Lurgi oxygen
Winkler oxygen
Koppers-Totzek oxygen
Wellman-Galusha air
Winkler air
Gross heating
value,
Btu/SCF
1035.0
285.4
270.2
285.0
159.4
116.3
Adlabatic
flame
temp, *F
3337
3164
3329
3578
2948
2579
H2/CO
ratio
~-—,
2.2
1.3
0.7
0.5
0.6
Fuel input
vel. ft/s
100.6
100.0
105.6
97.6
136.4
109.6
Combustion
air inlet
vel. ft/s
53.3
51.2
52.3
50.4
54.6
74.7
Table 1. SYNPOSIS OF FURNACE OPERATING CONDITIONS
(Part 2)
Fuel
Natural gas
Lurgi oxygen
Winkler oxygen
Koppers-Totzek oxygen
Wellman-Galusha air
Winkler air
Gross heat
input,
Btu/hr
2,371,265
2,356,066
2,350,940
2,348,367
2,358,036
2,358,940
Flue products
N2 CO2 H20 02
%
72.5 8.3 16.7 2.5
62.9 16.8 17.8 2.5
63.1 18.3 16.1 2.5
65.0 20.2 12.2 2.6
72.3 15.8 9.2 2.7
74.5 14.6 8.2 2.8
Volofflue
products.
CFH at 60'F
27,357
27,565
26,169
24,356
32,772
38.339
SCFair
SCF fuel
11.23
2.71
2.43
2.51
1.54
1.13
SCF flue products
SCF fuel
12.26
3.41
3.06
3.07
2.33
1.96
Table 1. SYNPOSIS OF FURNACE OPERATING CONDITIONS
(Part 3}
Fuel
Natural gas
Lurgi oxygen
Winkler oxygen
Koppers-Toizek oxygen
Wellman-Galusha air
Winkler air
Flue-gas
temp, °F
2553
2442
2523
2554
2434
2335
Rear-wall
temp, "F
2309
2300
2309
2327
2066
2012
Emissivity
Calc
0.159
0.194
0.189
0.174
0.154
0.150
Meas
0.177
0.185
0.218
0.190
0.190
0.170
Flue NO.
ppm
65
32
73
104
15
4
55
-------
design of the computer program did not allow information from the IGT tests to
be inputs for the radiant section, although a comparison between the IGT ex-
periment results and Babcock and Wilcox's predictions was made. The IGT data
were used as input conditions to the convective section. It was found that all
fuel gases tested were capable of maintaining boiler output? however, those
with a heating value below 200 Btu/SCF may require retubing in the convective
sections.
4. A second evaluation of furnace efficiency - defined for the purposes of this
report as the fraction of the total enthalpy input to the furnace that is trans-
ferred to the furnace load - was made by Babcock and Wilcox using their stan-
dard design calculation technique. The inputs required for this calculation
were: 1} fuel composition and 2) desired temperature of combustion products
leaving the air heater. The values calculated for the combustion products of the
fuel gases tested leaving the radiant section of the boiler agreed remarkablv
well with experimental values.
5. The furnace efficiency (fraction of heat transferred within the furnace) cal-
culated with the well stirred model was found to be rather insensitive to emis-
sivity, with a 10% change in emissivity producing only a 3% change in
efficiency.
6. NO concentration levels from the medium- and low-Btu gases were ordered by
adiabatic flame temperature. Only test fuels with heating values below 200
Btu/SCF had emission levels that conformed to the New Source Performance
Standard.
7. The NO emission data yielded an activation energy of 153 kcal/mol compared
to kinetic models which predict 135 kcal/mol. This good agreement suggests
that peak temperatures approaching the adiabatic flame temperature are con-
trolling the rate of NO formation. Also, the use of the adiabatic flame tem-
perature provides a good empirical method of predicting NO emmissions.
56
-------
PROCESS GASES SELECTED FOR STUDY
To ensure the immediate relevance of the program's results, only gas compositions
from commercially available coal conversion processes (Lurgi, Koppers-Totzek,
Winkler, and Wellman-Galusha) were considered. The gas properties of interest
were heating value and hydrogen-to-carbon monoxide ratio (Hj/CO). To permit
the study of a complete range of heating values and hydrogen-to-carbon monoxide
ratios five gases were selected for testing. These five gases are listed below in
Table 2, and a detailed gas composition analysis for each is given in Table 3.
Table 2. GASES SELECTED FOR TESTING
Test gas
Lurgi oxygen
Winkler oxygen
Koppers-Totzek oxygen
Wellman-Galusha air
Winkler air
Heating value,
Btu/SCF (wet)
285
269
284
160
117
H7./CO
2.2
1.3
0.6
0.5
0.6
These representative medium- and low-Btu gases are produced using the gas-
generating and fuel-preparation facility shown schematically in Figure 1. The
critical item in the gas supply system is the reformer, shown in Figure 2. This is a
special gas generator that produces varying ratios of Hj/CO. Natural gas and car-
bon dioxide are fed to the reformer through a specially designed mixing tee.
Additionally, steam may also be mixed, depending on the desired H2/CO ratio.
The resulting mixture is supplied to four reaction retorts contained in a vertical
cylindrical furnace. The catalyst-filled retorts are heated by the furnace, and the
input gases undergo endothermic chemical reactions at a temperature of 2100°F
as they pass through the retort tubes. Globally, the reaction scheme is the water-
gas shift. The gas generated within the reaction tubes passes through water-
jacketed coolers, where it is quenched to prevent deterioration of the H2/CO
ratio.
57
-------
TKe reformed gas is compressed to 30 psig and pushed through an MEA {methyl-
ethyi-amine)-CC>2 (carbon dioxide) absorbing tower. This tower is used to remove
CO2 from the reformed gas if its concentration is above what is needed to synthe-
size the desired low-Btu gas. The reformed gas then enters a mixing chamber
where it is blended with nitrogen, carbon dioxide, steam, and natural gas to reach
the desired mixture of gas to be modeled. The product gas is analyzed by a gas
chromatograph to ensure that the correct composition is attained. The syn-
thesized gas is then fed to the pilot-scale furnace for combustion testing.
Table 3. SPECIES CONCENTRATIONS. ADIABATIC FLAME TEMPERATURES,
AND GROSS HEATING VALUE (Wet) FOR MEDIUM- AND LOW-Btu GASES TESTED
Fuel
Lurgi oxygen
Winkler oxygen
Koppers-Toizek oxygen
Wellman-Galusha air
Winkler air
CO
18.5
32.9
52.1
26.3
21.1
H2
40.2
41.2
34.5
14.3
13.0
CO2
29.4
20.0
9.2
7.4
6.9
CH4
9.4
3.0
0.5
2.6
0.6
N2
0.6
1.0
1.0
46.9
56.5
H2O
1.9
1.9
1.9
1.9
1.9
Adiabatic
flame
temp, "F
3156
3327
3578
2948
2579
Heating
value,
Btu/SCF
285
269
284
160
116
58
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DESCRIPTION OF FURNACE TEST FACILITY
i
The experimental work was conducted on a rectangular furnace) with a 25-sq ft
cross-sectional area and a 13-foot length. This furnace can be end- or sidewall-
fired at a rate of 4 million Btu/hr. The furnace is equipped for in-the-flame sam-
pling, preheated air, and flue-gas recirculation. (See Figure 3.) This furnace is
capable of operating at temperatures of up to 3000°F or as low as 1600°F at a
constant (maximum) gas input of 4 million Btu/hr and up to 40% excess air. Cool-
ing is achieved with cooling coils embedded in the refractory walls. The furnace
is constructed completely of 9-inch thick cast refractories, with removable panels
in one side wall to permit insertion of sampling probes {Figure 4). The overall fur-
nace system is shown schematically in Figure 5. The system is flexible enough so
that the following operating parameters can be independently varied:
• Heat input, up to 4 million Btu/hr (8.0 million for certain burners)
• Air input, up to 40% excess
• Heat josses to the furnace walls by changing flow in water-cooling
tubes cast into the refractories
* Combustion air temperature, up to 1000°F
* Flue-gas recirculation capability, up to 35% of combustion air
* F"mace pressure, up to +0.05 inch of water.
The combustion air for the main furnace can be preheated up to a temperature of
1000°F with a separately fired radiant tube air preheater. The radiant tube fur-
nace (Figure 6) consists of an insulated airtight steel chamber 4 feet high, 4 feet
wide, and 16 feet long. As the combustion air to be preheated passes through this
chamber, it is heated by convection from three 6-inch diameter "hairpin" gas-fired
radiant tubes.
The radiant tubes and refractory flow passages inside the preheater are arranged
to provide an S-shaped flow pattern, which maximizes residence time for heating
at the maximum allowable pressure drop (20 ounces) for which the flow pattern
will provide the necessary air flow of 75,000 SCF/hr.
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COOLING WATER SYSTEM
60 gpm AT 150 psig
SPRAY MANIFOLD
AND HEADS
COOLED
FLUE
GASES
WIRE MESH LIQUID
DEMISTTER
PERFORATED
PLATE
2-in. WATER LEVEL
PACKED REFRACTORY
BED-80'/.VOIDS
HOT(2800 °F)
FLUE GASES
X
9
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HOT-WATER
COLLECTION TANK
Jif*t, •— •-
i
i 1
I ~20i
~!6in. 1
T i
TO DRAIN
D-34-460
Figure 7. Flue-gas cooler
66
-------
The temperature of the air can be regulated by changing the heat input to the
radiant tubes. Ambient temperature air can be supplied by completely shutting
down the preheater or by directing the air through the preheater bypass pipe. The
bypass pipe was installed to allow working on the preheater without shutting down
the air supply to the main furnace- Air bypass is achieved by selective switching
of valves.
Flue products for recirculation back to the burner and main furnace are obtained
from the furnace itself. Flue products can be withdrawn from the furnace flue
passage just prior to the main furnace flue damper. Up to 14,000 SCF/hr of flue
products can be withdrawn from the flue, which provides a 30% recirculation fac-
tor when the furnace is fired at 3.5 million Btu/hr with 20% excess air.
The main furnace flue products are actually pulled from the flue (Figure 5) by the
suction in the inlet side of the main furnace combustion air fan (F4). The flue
products enter the recirculation withdrawal and treatment system at about
Z800°F through a short length of internally insulated steel duct. These hot gases
are cooled to about 125°F in a packed-bed water cooler (Figure 7). Cooled city
water (about 70°F) is sprayed down on a bed of refractory packings as the hot
gases pass up through the packed bed. This cooling system lowers the water con-
tent of the flue gas from about 0.008 to about 0.007 Ib/CF, which is the dew point
of the gases at about 125°F. (The lost water content can be added again later in
the system if experimental conditions require this treatment.) The cooled gases
then pass through a flow-control shutoff valve (V25 in Figure 5). This valve con-
trols the flue-gas flow rate, which regulates the percentage of recirculated prod-
ucts. This valve is interlocked to an outlet temperature sensor on the gas cooler.
If the outlet temperature of the gases exceeds 150°F, which would damage the
combustion air fan, the control valve (V25) shuts down. This stops the flow of flue
gases. Beyond the flue-gas control valve, the flue gases are mixed with the
required amount of air for combustion. A control valve (V24) regulates the
amount of air pulled in by the fan. The total amount of air for combustion and
flue products is metered with an orifice plate (O7) at the outlet of the fan. The
flue products and air then pass into the air preheater or preheater bypass pipe.
The water used in the flue-gas cooler is clean city water, which is continuously re-
cycled. A water flow of 60 gpm is supplied at 150 psig by a turbine pump to a
67
-------
series of spray heads in the gas cooler. The hot (200<>F) spent water flows out of
the cooler into an atmospheric holding tank. This tank is equipped with a
constant-level overflow to the building drain. In this way, any condensed water
from the combustion is removed and disposed of in the sewer. The water in the
holding tank is periodically treated with sodium hydroxide to prevent acid buildup
in the water due to condensing flue-gas components. One such component
removed by the flue-gas cooler is NO2. The hot water from the water holding
tank is cycled through an American Standard heat exchanger capable of removing
1.5 million Btu/hr of heat from the water. Cooling in the heat exchanger is pro-
vided by a flow of river water at a rate of about 150 gpm at 80>psig. The river
water is supplied by a river adjacent to the test facility through a service pump
(PI in Figure 5) maintained by IGT.
Figure 8 is an overall view of furnace controls and the analytical instrumentation
package. The equipment used for concentration measurements'of chemical
species during this program is listed below; these analyzers included the following
items:
1. Beckman 742 Polarographic Oxygen (O2)
2. Beckman Paramagnetic Oxygen (02)
3. Beckman NDIR Methane (CH4)
4. Beckman NDIR Carbon Monoxide (CO)
5. Beckman NDIR Carbon Dioxide (CO2)
6'. Varian 1200 Flame lonization Chromatograph (Total HC and C2 to C9>
7. Beckman NDIR Nitric Oxide (NO)
8. Beckman UV-NO2
9. Hewlett-Packard Thermoconductivity Chromatography, Hydrogen (H),
Nitrogen (N2), Argon (A2), CO, CO2, GI to GS, Oxygen (O2)
10. Beckman Chemiluminescent NO-NO2
11. Data Integration System.
This instrumentation package allowed concentration measurements of the follow-
ing major components: 1) measurement of hydrocarbon compounds Cj to 09;
68
-------
P-15-Z5
Figure 8. Control room facility and analytical instrumentation
69
-------
Z) independent check of NO-NO2 chemiluminescent with NDIR-NO and NDUV-
N^Z; 3) independent check of paramagnetic O£, polarographic Oz, NDIR-CH4,
NDIR-CO, and NDIR-CO2 with the respective chromatographic species concentra-
tion; and 4) measurement of hydrogen (H2), argon (A2), and nitrogen (Nz).
The following sections give a general description of the measurement system used
for this program.
NO AND NO2 INSTRUMENTATION
The chemiluminescent NOX and NDUV-NO^ system was mounted in a roll-around
cabinet that could be placed out at the furnace. This was important in minimizing
sampling distances, which can affect accuracy- The chemiluminescent unit was
equipped with a carbon converter. Test work by IGT and others has demonstrated
that in a reducing environment the carbon converter maintains a better conversion
efficiency than converters made of stainless steel, quartz, or molybdenum.
The instrumentation was calibrated by using both a permeation tube with a con-
trolled known release of NOX and certified prepared cylinders of NO and NO2
gases.
The sample gas was drawn from the furnace through a special alumina probe by a
Dia-Pump Model 08-800-73 all stainless-steel and Teflon® pump delivering
approximately 0.4 CF/min. (This sample delivery rate was dictated by the
requirements of the measuring instruments.) The sample is immediately passed
through a stainless-steel large-particle filter. Both the pump and filter were kept
above 100°C to prevent condensation of the water vapor inherent to combustion
products.
CO, CH4> AND C02 MEASUREMENTS
Nondispersive infrared analyzers were used for carbon monoxide, methane, and
carbon dioxide measurements. These analyzers do not affect the sample gas and
can be operated in series. They were calibrated by using certified gases with
i
known concentrations of the species being determined. The infrared analyzers
require a completely dry sample. Therefore, the sample was first passed through
a water trap and a 3 A molecular drying sieve. A small in-line filter was placed
immediately after the drying tube to trap particles of sieve that may be carried
over by the gas stream.
70
-------
OXYGEN MEASUREMENTS
A portion of the "conditioned" sample gas is diverted from the NDIR units to a
Beckman Model 600 paramagnetic analyzer. A second oxygen analyzer, a Beck-
man Model 742 polarographic, was used as a cross-check on the oxygen concentra-
tion. The Model 742 analyzer has an advantage over the paramagnetic in time
response.
CHROMATOGRAPHIC MEASUREMENTS
Because a detailed gas analysis was required, the sample was fed to a Hewlett-
Packard 7620-A thermal conductivity chromatograph, which permitted concen-
tration evaluations of hydrogen, nitrogen, argon, oxygen, carbon monoxide, carbon
dioxide, and hydrocarbons Cj to €5. To achieve separation of these species, a
helium carrier gas was used in conjunction with a Porapak Q column. Three tem-
perature program rates were also required, ranging from —100° to 300°C. A sam-
ple loop volume of 100 ml was used to ensure linearity in the hydrogen response
for concentrations up to 60%.
For total hydrocarbon analysis, a Beckman hydrocarbon analyzer was used. A
detailed hydrocarbon analysis could be made using a Varian 1200 flame-ionization
chromatograph. All chromatographic readings were electronically integrated and
printed out as a function of resolution time.
In addition to flue-gas analysis, a major task of this program was to map profiles
of temperature, chemical species, and flame emissivity. Modified designs of the
International Flame Research Foundation (IFRF) were used to construct probes,
which enabled this type of data collection.
Figure 9 shows the assembly drawing of the gas-sampling probe used in both the
flame and the flue. To minimize NO£ reduction in the probe, an alumina tube was
inserted for the first 18 inches and was joined to Teflon tubing to carry the gas
sample to the analyzers.
Temperature data were collected using a suction pyrometer; the design is illus-
trated in Figure 10. A Pt-Pt Rh 10% thermocouple was used. The efficiency of
the pyrometer was measured at 96% with a 25-second response time.
The gas-sampling probe, suction pyrometer, and radiation cooling target were all
designed to be installed in the general probe holder shown in Figure 11.
71
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To evaluate radiation intensity, which is needed for a determination of flame
emissivity, a PR 200 Pyroelectric Radiometer, manufactured by Molectron Corp.
in Sunnyvale, California, was used. Figure 1Z shows the pyroelectric radiometer
plus radiation shield. This radiometer uses a permanently poled lithium tantalate
detector that is capable of resolving radiant power into the nanowatt range while
maintaining a continuous spectral response from the vacuum UV to 500^ m. A
built-in optical calibration system in the form of a highly stable LED (light-
emitting diode) that is calibrated against an NBS traceable standard of total irra-
diance permits a direct correlation of experimental data from different trials.
75
-------
Figure 1Z. Pyroelectric radiometer
(used for emiseivity measurements)
76
-------
EXPERIMENTAL PLAN
All test data were collected using a single-register movable-vane boiler burner
with an axial fuel injector. An assembly drawing of the MVBB tested is shown in
Figure 13. The combustion air enters perpendicular to the axes of the burner and
passes through a register of guide vanes that impart a degree of spin to the air,
dependent on the vane orientation. Figure 14 illustrates how the angle of the
movable vane is measured. The ratio of the average tangential and radial velocity
components at the exit of the movable-vane register depends only on the geo-
metric dimensions of the vanes in the axis perpendicular cross section (assuming a
negligible Reynolds number influence).
A straight pipe was used as the fuel injector, guaranteeing that the fuel had only
an axial velocity. This type of injector was used for two reasons. First, this type
of nozzle would be the most stringent test for flame stability in the cold-wall
stability tests; and, second, medium- and low-Btu gases would normally be avail-
able at relatively low pressures, dictating the use of a low-pressure injector. The
diameter of the fuel injector was varied for fuel type to maintain an injection
velocity of 100 ft/s.
The burner block used during this program had a 30-degree divergent angle with a
15.2-cm (diameter) entrance and a 48.2-cm (diameter) exit to the furnace. To
maximize flame stability the throat nozzle position was used throughout this pro-
gram. The throat nozzle position is located 2.5 cm from the burner block en-
trance within the 15.2-ctn (diameter) refractory duct connecting the burner with
the block.
Burner operating conditions used throughout the program had the level of flue
oxygen fixed at 3% with the combustion air preheated to 3Z5°F (unless specified
differently). These conditions are considered typical for utility boiler burners.
Based on the overall program objective of evaluating boiler performance changes
when retrofitting from natural gas to medium- and/or low-Btu gas, it was neces-
sary to select an operating variable to model the pilot-scale test furnace against a
field service boiler. Several parameters were considered, including operating wall
temperature, heat absorption profile, and firing density. It was decided to match
the temperature of the combustion products from natural gas at the pilot-scale
77
-------
83-1199
Figure 13. Diagram of movable-vane boiler burner
AIR FLOW
A-34-414
Figure 14. Method of measuring movable-vane angle for boiler burner
78
-------
furnace exit to the temperature measured between the boiler and the secondary
superheater section of a utility boiler. This decision was based on the complexi-
ties of multiburner interactions within a utility boiler versus the single-burner test
furnace, where several flames would not view the boiler water walls. The data of
most interest in evaluating performance changes were gas volume, temperature,
and gas emissivity entering the secondary superheater. Thus, baseline data were
collected for natural gas after the furnace load had been adjusted to give an exit-
gas temperature of Z550°F-
The first task to be conducted after the baseline furnace operating conditions had
been fixed was to determine flame stability. The stability trials were to be con-
ducted under the most stringent operating conditions, that is, with the furnace
walls, burner block, and combustion air at ambient temperature.
The second problem addressed was the relative flame length of the medium- and
low-Btu gases compared with natural gas. It was anticipated that flame length
changes could affect the rate of heat transfer from the flame to the boiler tubes
through a change in flame emissivity. If the flame length change resulted in a
lower heat removal within the boiler, the combustion products entering the sec-
ondary superheater would be at a higher than normal temperature. This condition
could result in tube damage or a loss in efficiency, because the convective section
would be undersized. Using the burner and furnace operating conditions outlined
for the baseline tests, flame length measurements were made as a function of
vane angle for each test gas. In each case, measurements were taken only after
the exit-gas and furnace-wall temperatures had stabilized. As stated above, a
straight nozzle was used with a diameter giving a fuel velocity of 100 ft/s. The
criterion for evaluating the end of the flame was when 1% of the total gas-sample
volume was combustible.
The third problem to be answered by this program was what would be the changes
in efficiency — that is, the fraction of total enthalpy input transferred to the load
- when retrofitting a unit designed for natural gas with a medium- or low-Btu gas.
Detailed temperature and emissivity data were collected for each test gas. These
measurements provide not only the information needed to evaluate changes in
efficiency within the boiler but also the data that can be used by manufacturers to
calculate any redesign that may be needed in the convective passes.
79
-------
The final question addressed by the program was the level of NO emissions from
each test fuel gas and how it compares with emissions from natural gas combus-
tion. These data are presented in detail and analyzed in the "RESULTS" section.
80
-------
RESULTS
During the flame stability trials, fuel-gas velocities from 25 ft/s up to 500 ft/s
were investigated. The optimum fuel-gas injection velocity range was 75 to 200
ft/s. Above 200 ft/s the flame began to lift (detach) from the injector, and below
75 ft/s the flame became lazy and buoyed badly (moved toward the furnace roof).
A velocity of 100 ft/s was selected for use throughout the program because the
velocity could be maintained for the spectrum of fuel gases being studied using
standard pipe sizes.
Figures 15 through 20 show photographs of the flame for each test gas.
FLAME LENGTHS
Table 4 presents the flame length data determined by radial scans at various
points down the furnace axis. The end of the flame was defined as the point
where 99% of the fuel was consumed. In general, the flame length decreased with
increasing burner vane angle, except for the 60-degree angle natural gas and
Wellman-Galusha air, which exhibited longer flames than the corresponding 45-
degree burner vane angle. All medium- and low-Btu fuel-gas flames tested were
shorter than the natural gas flames except Winkler air at a 45-degree vane angle,
which was 21 cm longer than the natural gas flame produced with a 45-degree
vane angle.
NITRIC OXIDE EMISSIONS
To determine the environmental impact of retrofitting utility boilers with
medium- and low-Btu gases, NO emissions levels were measured as a function of
secondary air-preheat temperature for each of the test fuel gases. Baseline NO
emission data were collected using natural gas. The combustion-air temperature
was varied from ambient to 800°F. Graphs of the experimental results are pre-
sented in Figure 21. For the vane orientations studied, the measured NO levels
remained relatively constant up to 400°F, above which dramatic increases
occurred for the 45-degree and 60-degree angles.
Figure 22 presents NO versus secondary air-preheat temperature test results using
Lurgi oxygen gas. The flue concentrations of NO are approximately 50% less than
81
-------
Figure 15. Natural gas flame using a 0. 5-inch axial nozzle
Figure l6. Lurgi oxygen gas flame using a 2-inch axial nozzle
82
-------
Figure 17. Winkler oxygen gas flame using a 2-inch axial nozzle
Figure 18. Koppers-Totzek oxygen gas flame using a 2-inch axial nozzle
83
-------
Figure 19. Wcllman-Galusha air gas flame using a 3-inch axial nozzle
Figure 20. Winkler air gas flame using a 3-inch axial nozzle
84
-------
Table 4. FLAME LENGTH (cm) AS A FUNCTION OF
FUEL TYPE AND VANE ROTATION
Fuel
Natural gas
Lurgi oxygen
Winkler oxygen
Koppers-Totzek oxygen
Wellman-Galusha air
Winkler air
Vane angle
15*
290
250
250
281
250
250
30'
250
227
208
208
226
250
45*
219
208
188
188
188
240
60"
226
157
146
156
198
208
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with natural gas for all test conditions. For the detailed burner operating condi-
tions (15-degree vane angle, 3Z5°F air-preheat temperature), the NO level was
reduced from 65 ppm (natural gas) to 32 ppm (Lurgi oxygen gas). These emission
reductions were expected based on an adiabatic flame temperature comparison,
because Lurgi oxygen has a 173°F lower temperature than natural gas.
Flue levels of NO measured as a function of combustion-air temperature with
Koppers-Totzek oxygen gas are shown in Figure 23. For all conditions tested, the
Koppers-Totzek gas resulted in higher NO emission levels than did natural gas.
Again, by comparing the adiabatic flame temperatures listed in Table 3, this
result was anticipated because Koppers-Totzek gas has a 241°F higher adiabatic
flame temperature than natural gas. For the 45-degree vane angle with a 3Z5°F
secondary air-preheat temperature, this is translated into a 60% increase in the
NO emission level.
Comparing the adiabatic flame temperatures of Winkler oxygen gas with natural
gas shows that the former is 9°F lower. Thus, based only on adiabatic flame tem-
perature considerations, the NO emission levels should be comparable. The NO
test results with Winkler oxygen gas are presented in Figure 24. These measured
levels were lower than those measured for natural gas, except for the 60-degree
vane rotation with secondary air-preheat temperatures below 560°F and the 45-
degree vane rotation with preheat temperatures below 400°F. These results
indicate that NO formation strongly depends on combustion aerodynamics because
the peak flame temperature and the time that the gas is subjected to this tem-
perature are controlled by aerodynamic turbulence. Although average tempera-
tures may be the same in two cases, the NOX formation can be different if the
turbulent temperature fluctuations are different. The temperature dependence of
the chemical reaction rate constant can be expressed by the Arrhenius rate law:
k(T)»koexp[-E/RT(t)]
(1)
The time-averaged value would be:
(2)
exp [~E/RT(t)]dt
88
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for an interval of time, T , while the rate constant given by the time-averaged
temperature would be:
=*_2_ exp [-E/RT],
(3)
The ratio —
K =
k(T)
(4)
is always greater than 1 because the exponential nature of the temperature depen-
dence means that the rate constant increase for an increase in temperature above
the average exceeds considerably the decrease for a similar reduction in
temperature. The value of the ratio, K, depends on the extent and the nature of
the temperature fluctuations. Thus, observing that the average temperature (the
temperature given by a suction pyrometer) is similar in two cases does not
necessarily mean that the NOX emissions will be similar if the turbulent
fluctuations are different. Unfortunately, the technology is not sufficiently
advanced to allow measurement of the extreme turbulent temperature pulsations.
An additional indication of combustion aerodynamic differences is the reordering
of the NO concentration levels as a function of vane angle, which can be seen by
comparing Figure 23 with Figure 24.
Figure 25 shows the NO emission data collected for Wellman-Galusha air. The
flue concentrations of NO are about 70% lower than those measured for natural
gas at the lower air-preheat temperatures. They show an almost linear rise with
air temperature. The lack of a dramatic increase in emissions with temperature
results in up to a 90% lower NO concentration at elevated combustion-air tem-
peratures for Wellman-Galusha air than for natural gas. Some reduction of NO
emissions could be anticipated because of the lower adiabatic flame temperature
(2948° versus 3337°F).
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The NO emission data for Winkler air are presented in Figure 26. As the low adia-
batic flame temperature would predict, the NO concentrations in the flue are the
lowest of all the gases. The emissions are 82% to 97% lower than those measured
for natural gas and show an even more gradual, nearly linear increase with
combustion-air temperature.
The NO data for Wellman-Galusha air show a systematic increase in emissions
with increased vane angle. This same relationship is not seen with Winkler air.
The 15, 45, and 60-degree angle data are all within 2 to 3 ppm of each other but
are 5 to 6 ppm lower than the 30-degree angle data.
Figure 27 is an Arrhenius plot for the fuel gases tested with the utility burner at a
45-degree vane rotation. The plot, in(NO) versus reciprocal of the adiabatic
flame, yields a linear relationship. Correlating these data to a relationship sug-
gested by Thompson, Brown, and Beer1 on the formation rate of NO which is of
the form:
Aexp(-134.7/RT)
(5)
yields an activation energy of 153 kcal/mol compared with their 134.7. This good
agreement suggests that peak temperatures approaching the adiabatic flame tem-
peratures are controlling the rate of NO formation and suggests that the use of
adiabatic flame temperature is a good empirical method of predicting NO emis-
sions.
1. Thompson, Brown, and Beer, Combust. Flame, 19, 69 (1972).
93
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94
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6.0,
5.0-
4.0
O
2
0.25
E = 153 kcal
0.30
IOOO/T
AF,
0.35
A76112524
Figure 27. Arrhenius plot of NO versus
inverse "pseudo-adiabatic" flame temperature
95
-------
DATA CORRELATION
NOX EMISSIONS
Due to the size of the gas-generating system for synthesizing the medium- and
low-Btu test gases, the firing density of the pilot-scale test furnace could not
exceed 6923 Btu/f t3«hr. To permit a better correlation as to the level of emis-
sions that could be anticipated from a utility boiler, natural gas was fired with
inputs up to 3.75 million Btu/hr. This corresponds to a firing density of 11,538
Btu/ft3«hr, which produced a NO emission level of 225 ppm compared with the
New Source Performance Standard for natural gas at 1000 Btu/SCF of 168 ppm
(0*2 pounds NO2/nniUion Btu heat input). These data are graphed in Figure Z8.
A 300-MW utility boiler with a radiant chamber 30 x 60 feet in cross section and
80 feet high is fired with 2.86 X 10? Btu/hr. The firing density for a boiler of this
size at this firing rate is 19,860 Btu/ft^-hr. Extrapolating the data of Figure 28
yields a NO emission level for the 19,860 Btu/ft3*hr firing density of 458 ppm. To
quantify the anticipated NO emission levels from this 300-MW boiler for each of
the fuel gases tested, it is assumed that an identical firing density-to-NO emission
level relationship would occur for each medium- and low-Btu gas as is represented
for natural gas in Figure 28. From this assumption, the NO emission levels pre-
sented in Table 5 were projected.
Thus, there were only two fuel gases tested that could comply with the 168-ppm
performance standard with the burner system operating normally. Both of the
fuel gases (Wellman-Galusha air and Winkler air) that comply with the standard do
so because of their low adiabatic flame temperatures, 389° and 758°F, respec-
tively, below the natural gas adiabatic flame temperature. All medium-Btu gases
that have adiabatic flame temperatures near that of natural gas would require
modifications to the burner/boiler system in order to comply with the perfor-
mance standards.
CORRELATING FURNACE PERFORMANCE
The efficiencies evaluated on the pilot-scale furnace for each of the fuels tested
are listed in Table 6. These efficiencies (defined the same as previously for the
boiler, that is, the fraction of the total input enthalpy given up in the furnace by
the combustion products) can be evaluated using the flue gas temperatures in
96
-------
400 -,
- 0.3
- 0.2
£
ffl
C
O
«f-i
1
5
-0.1
4.0 8.0 12.0 16.0
FIRING DENSITY, Btu/CF x 103
20.0
24.0
A76112523
Figure 28. NO flue concentration versus firing density
97
-------
Table 5. PROJECTED NO* EMISSION
LEVELS FOR A UTILITY BOILER
Fuel
Natural gas
Lurgi oxygen
Koppers-Totzek oxygen
Winkier oxygen
Wellman-Galusha air
Winkier air
IMOX, ppm
458
225
733
514
106
28
lbNO2/106Btu
0.714
0.353
1.019
0.766
0.198
0.061
Table 6. TEST FURNACE EFFICIENCIES AND COMBUSTION PRODUCT PROPERTIES AT
THE FLUE
Fuel
Natural gas
Lurgi oxygen
Winkier oxygen
Koppers-Totzek oxygen
Wellman-Galusha air
Winkier air
n"
28.6
25.2
26.4
33.1
19.0
10.8
Tflu,.eFD
2553
2442
2523
2554
2434
2335
rh.SCF0
26,639
26,883
25,481
24,236
32,889
37.919
6., Btu /hrd
1,693,083
1,762,337
1,730,291
1,570,836
1,910,009
2.104.174
a Efficiency measured for pilot-scale test furnace.
b Temperature of combustion products at the flue.
c Volume of combustion products at 60°F.
d Heat content of combustion products at listed temperature.
98
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Table 6 and the combustion products in Table 1. Subtracting the flue gas enthalpy
from the total enthalpy input gives the amount of heat transferred in the furnace,
and dividing by the total enthalpy input gives the efficiency. The efficiencies
evaluated for natural gas and the oxygen produced low-Btu test gases (Winkler
oxygen, Koppers-Totzek oxygen, and Lurgi oxygen) are comparable within a range
of 25% to 33%. For Wellman-Galusha air with a 160 Btu/CF heating value, the
efficiency decreased to 19-0%. The lowest efficiency measured was 10.8%, for
Winkler air with a 116 Btu/ft3 heating value.
In addition to changes in the furnace efficiency when natural gas is replaced with
a low-Btu gas, the temperature and volume of combustion gas products entering
the convective section will determine the amount of heat absorbed. Using Table 6
to compare the volume of combustion products for the test fuels reveals that
Koppers-Totzek oxygen has a 9% smaller volume of combustion products than
natural gas, while Winkler air produces a 42% greater volume of combustion pro-
ducts than natural gas. These changes in combustion-product volume will result in
changes in gas velocities and will shift the heat absorption patterns within the
convective section.
To evaluate a shift in heat absorption when retrofitting a boiler with low-Btu gas
requires a method of calculation. Babcock and Wilcox Co. (B&W) agreed to take
our experimental data and use them for the input conditions to the convective
section to predict differences in overall boiler efficiency (radiant plus convective)
between natural gas and low-Btu gases. The method of calculation employed by
B&W was to use their design computer program to forecast changes in boiler per-
formance when retrofit with a low-Btu fuel gas.
The particular boiler selected for their calculations was a standard design with a
maximum rated steam flow of 2,430,500 Ib/hr at 2620 psig/1005°F at the super-
heater outlet when fired with natural gas. The unit (B&W Contract RB-455) is
installed at the Teche Station of the Central Louisiana Electric Co. and supplies
steam to a Westinghouse turbine having a maximum capacity of 361 MW. This
same unit was reported on by B&W for EPRI Project 265-2, entitled "Low Btu Gas
Study," a program designed to look at retrofitting boilers using only existing
design information.
99
-------
To update these results, the flue gas temperatures and gas compositions measured
on the IGT furnace were used as input data. These temperatures and gas composi-
tions were assumed to be identical to those entering the convective section of the
boiler. Using these experimental results, B&W calculated unit efficiencies for
natural gas, Winkler oxygen, and Winkler air fuel gases. The total required output
of Unit RB-i55 based on a Z, 198,000 Ib/hr mainsteam flow is 2652.5 X 106 Btu/hr.
Based on the experimental data and fuel analysis presented in Table 1, B&W gen-
erated the information in Table 7. The first line shows natural gas firing with the
amount of excess air that the unit was designed for at this load. The second line
shows natural gas firing with input conditions (325°F air preheat and 3% excess
oxygen) identical to those used for the pilot-scale test furnace. The actual output
from firing natural gas with the increased level of excess air is in excess of 2652.5
X 106 Btu/hr. This is because higher gas weights result from the increased volume
of combustion air creating an overabsorption in the reheater. Similar reheat
overabsorption occurs in the output for Winkler air, which is also greater than
2652.5 X 106 Btu.
Table 7. B&W CALCULATED BOILER EFFICIENCES USING IGT DATA
Fuel
Natural gas
Natural gas
Winkler oxygen
Winkler air
IGT
flue-gas
temp. °F
„
2553
2523
2335
Actual
unit
output.
106 Btu/hr
2652.5
>2652.5
2652.5
>2652.5
Unit
efficiency.
%
85.1
84.8
84.4
80.4
O2 in
flue gas.
Sbyvol
1.1
3.0
3.0
3.0
B&W
furnace
exit-gas
temp, *F
2702
2633
2583
2397
It should be noted that these calculations in no way imply that this, or any other
unit, could economically be retrofitted to burn these test fuels. Several other
factors in addition to unit efficiency must be considered in an actual retrofit
study. Two of these important factors are: 1) redistribution of heat absorption
between boiler, primary and secondary superheater, and reheat and economizer
100
-------
surface (a significant redistribution of which will affect metal temperatures,
spray flows, and circulation); and, 2) changes in combustion-air and flue gas
weight from the original design quantities, which will affect fan and air heater
performance. Both of these factors can have a significant influence on the feasi-
bility of retrofitting existing units designed for conventional fossil fuel firing.
To aid in determining the value of the experimental data, B&W reran their design
calculation without using the experimental results as input. The new inputs re-
quired for the computer program were the fuel composition and the desired tem-
perature of combustion products leaving the air heater. The results of these cal-
culations for the gas temperature and emissivity at the exit of the radiant furnace
section are listed in Table 8. The combustion-products temperature leaving the
radiant section show excellent agreement with the experimental values. This pro-
vides substantiation on how realistically the pilot-scale test furnace was able to
model the radiant section of a utility boiler.
Table 8. CALCULATED AND MEASURED
EFFICIENCIES AND GAS EMISSIVITIES
Fuel
Natural gas
Lurgi oxygen
Wink ler oxygen
Koppers-Totzek oxygen
Wellman-Galusha air
Winkler air
IGT"
Tg
2553
2442
2523
2554
2434
2335
«9
0.18
0.19
0.22
0.19
0.19
0.17
B&Wb
T«
2633
—
2583
—
—
2397
€9
0.29
—
0.35
—
—
0.31
a Experimental data collected on pilot-scale test furnace.
b Calculated values based on normal design technique.
Comparing the gas emissivities of the combustion products at the radiant section
exit as measured by IGT to those calculated by B&W reveals a large difference.
This difference can be understood by looking at the emissivities dependent vari-
ables. These variables are the partial pressure of the radiating gas, the tempera-
ture of the gas mixture, and the distance across (beam length) the radiating gas.
101
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The temperature and partial pressure of the radiating gases are similar for the
IGT test data and the B&W calculated values. Therefore the difference between
the pilot-scale furnace and the 360-MW boiler is due to the different beam
lengths, 4 feet and 22 feet, respectively. To directly compare the experimental to
the calculated emissivity would require knowing the dependence of emissivity on
path length. Adjusting the B&W calculated emissivity to the beam length of the
test furnace was not practical because B&W does not use a publicized calculation
technique for evaluating emissivities but has developed a semi-empirical method
based on years of building and measuring heat absorption rates within the radiant
boiler section. On the other hand, the width of the test furnace was fixed, thus
negating the possibility of experimentally quantifying the dependence of emis-
sivity on beam length. However, since the only difference between the IGT
measured and B&W calculated emissivities is the beam length (products of com-
bustion and furnace exit temperatures are similar), a graphical development of the
relationship between emissivity and beam length is possible. This relationship is
generated using the zero-zero data point {zero emissivity at zero path length), the
IGT measured emissivity, and the semi-empirical emissivity of B&W. The
resulting curve for natural gas is presented in Figure 29 and is labeled experi-
mental. Also shown in this figure are relationships between the calculation
technique of Hottel and Sarofim and the technique of Leckner.
As the plot shows, the calculated values are approximately proportional to the
square root of the mean beam length. Leckner developed a statistical model
based on existing spectral data to evaluate total emissivities of carbon dioxide and
water vapor in homogeneous gases. For carbon dioxide emissivity, there is good
agreement with Hottel's emissivities; however, for water vapor, Leckner1 s emis-
sivities at temperatures above 1650°F are consistently higher and show that the
partial pressure correction factor is temperature-dependent. The measured
emissivity lies between the two theoretical curves presented. At the larger path
lengths comparable to utility boilers, the experimental curve drops below both
theoretical curves.
Similar graphs have been developed showing the relationship of emissivity and the
square root of mean beam path length for Winkler oxygen and Winkler air fuel
gases. These graphs are presented in Figures 30 and 31. Conclusions similar to
those with natural gas can be drawn; the measured emissivity lies between the .
102
-------
0.6-1
0.5-
0.4-
H
t—4
>
0.3-
2
w
0.2-
0.1—
LECKNER
HOTTEL
EXPERIMENTAL
FUEL: NATURAL GAS
TEMPERATURE = 2553°F
i i r i i
10 20 30 40 50
SQUARE ROOT OF PATH LENGTH, cml/z
I
60
A76112525
Figure 29. Plot of emissivity versus square root of
path length for natural gas
103
-------
0.6 -i
0.5 -i
0.4'
H
50.3-1
0.2-
o.i-
B'&W
LECKNER
HOTTEL
EXPERIMENTAL
FUEL: WINKLER AIR
TEMPERATURE s 23350F
10
20
30
40 50
SQUARE ROOT OF PATH LENGTH, cml/Z
60
A761125Z&
Figure 30. Plot of emissivity versus square root of
path length for Winkler air
104
-------
0.6 -,
0.5-
LECKNER
HOTTEL
EXPERIMENTAL,
FUEL: WTNKLER OXYGEN
TEMPERATURE = 2523°F
10
20
30
40
SQUARE ROOT OF PATH LENGTH, cm
1/1
50
60
A76112527
Figure 31. Plot of emissivity versus square root of
path length for Winkler oxygen
105
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theoretical curves, while the semi-empirical data point lies below both theoretical
curves. These curves provide a means of estimating the emissivity of nonluminous
combustion products with CO^H^O ratios between 0.5 and 1.8. However, these
results are very restrictive because they apply only to the temperatures for which
the calculations were made. However, as stated previously, these temperatures,
approximately Z500°F, are comparable with those found at the exit of the furnace
(radiant section) in a utility boiler.
106
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ENVIRONMENTAL ASSESSMENT OF AFTERBURNER
COMBUSTION SYSTEMS
By:
R. E. Barrett
Battelle's Columbus Laboratories
Columbus, OH 43201
107
-------
-------
ABSTRACT
This research program was initiated with the overall objective of assessing
the performance of afterburner emission control devices by evaluating (1) the
potential of afterburners for reducing emissions; (2) the potential for after-
burners to generate emissions; and (3) the efficient utilization of fuel in
afterburners, as it relates to emission control.
The program is divided into two phases. Phase I includes the utilization
of available data (from the literature, from EPA source tests, from state and
local agency data, etc.) to update afterburner technology, to determine emissions
from afterburners, to determine the effectiveness of afterburners for destroy-
ing pollutants in the inlet stream, and to relate the emissions control effec-
tiveness of afterburners to their fuel consumption.
Phase II consists of 4 tasks: two that are directed at generating new
data on afterburner performance, and two that are directed at documenting the
environmental and engineering aspects of afterburner application. The experi-
mental tasks directed toward obtaining new afterburner performance data in the
field and the laboratory, respectively.
The final two tasks consist of utilizing the data generated in the ex-
perimental program to complete the environmental assessment of afterburners
begun in Phase I, and of developing a "Standard Practice Manual". The manual
will assist engineers in deciding when afterburners should be used, which types
of afterburners are best suited to specific applications, and what should the
design criteria be (in terms of emissions, afterburner efficiency, required
temperatures, fuel requirements, etc.).
109
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-------
INTRODUCTION
Afterburner combustion devices are of interest to the Environmental
Protection Agency both (1) because of their use as an emission control device
and (2) because of their potential for generating emissions.
Considering the emission control aspect of afterburners, millions of tons
per year of hydrocarbon/organic emissions are discharged by a wide variety of
industrial processes. The National Inventory of Air Pollutants Emissions -
1968 , credits industrial processes with emitting 4.6 x 10 tons/year of
hydrocarbons, 14.4 percent of the national total.
Many of the hydrocarbons, and/or organic compounds emitted by industrial
sources have been considered as major contributors to photochemical smog, and
some hydrocarbons/organics may be harmful (e.g., toxic or carcinogenic) in
themselves. Other aspects of hydrocarbon/organic emissions include the odor
associated with many such compounds and where emission levels are high, the
possibility of the occurrence of dangerous local concentrations of combustibles.
Consequently, afterburners have been used for many years and in a variety of
industries to minimize these problems by reducing emissions of combustible and/
or organic gases and vapors.
The second aspect of afterburners concerns their potential for generating
pollutants. Polycyclic organic matter (POM) has become of considerable concern
as a pollutant since some compounds that fall within this broad category have
been identified as carcinogenic. Because POM compounds are the result of in-
complete combustion, it is generally recognized that poor combustion conditions
(low temperature combustion, poor mixing, quenching) are contributors to POM
formation and emissions. It is fairly obvious that afterburners, that are de-
signed or operated in the most "economical" manner (that is, using minimum energy
for mixing and minimum fuel to raise temperature), have a potential for having
the necessary poor combustion conditions to generate POM. In a similar manner,
111
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aldehyde emissions may be generated in afterburners. Also, catalytic after-
burners may emit trace quantities of catalytic surface materials through the
action of erosion associated with thermal cycling, corrosion, and abrasion.
A more recent concern regarding afterburners involves their fuel or
energy consumption. Most afterburners are gas fired and, with curtailments
of natural gas usage by industry, the ability to operate afterburners on
alternate fuels (specially fuel oil) becomes an issue. Also, the heat released
in the afterburner is frequently lost — no attempt is made to utilize this
energy. As the cost of energy increases, greater efforts at recovering the
heat released in afterburners must be considered.
Unfortunately, afterburners have never been the subject of a broad-based
and systematic experimental study to evaluate their overall performance in such
areas as (1) Emission control; (2) Pollutant generation; (3) Effective fuel
use. Brief discussions on afterburners appear in the Air Pollution Engineering
In the 1970-1972 period,
(2) (3)
Manual and in the EPA Control Technique Document ,
EPA sponsored an "Afterburner System Study". This study included a comprehen-
sive review of the literature concering afterburners and contacts with industry
(4)
representatives. The report on that study was an impressive document, but
the authors had to conclude that there were major gaps in the available data.
Thus, they recommended various levels of further research efforts to fill
these gaps.
Through the present contract, EPA is seeking to update the previous study
to: (1) consider developments in afterburner technology since completion of
that study; (2) expand on emissions control and generation aspects to include
the latest EPA methodology for Level I, Level II, and Level III emissions
measurement; (3) consider energy aspects including alternate fuels and waste •
heat recovery; and (4) conduct experimental field and laboratory programs to
fill gaps that still exist in the knowledge of afterburner performance as it
pertains to emissions and efficiency. Products of the proposed study will
include: (1) An environmental assessment of afterburners as control devices.
(2) An environmental assessment of afterburners as pollutant generators.
(3) A Standard Practice Manual to guide application engineers, potential users,
afterburner manufacturers, and installers to the best technology for applying :
afterburners control devices.
112
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It should be reemphasized that, in addition to the environmental
aspects of afterburner designs and applications, energy considerations are
included as an important part of this study. This study recognizes that
effective fuel utilization must be an important part of our national and
industrial decision making process.
113
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AFTERBURNER TECHNOLOGY
TYPES OF AFTERBURNERS
Five different basic types of afterburners can be defined as follows:
(1) Direct flame combustion afterburners
(2) Thermal combustion afterburners
(3) Catalytic afterburners
(4) Flares
(5) Boilers, process furnaces, and heat recovery furnaces.
The first four types are primarily used for pollutant destruction and (except
for flares) may or may not include waste heat recovery. The last type usually
is designed for recovery of thermal energy from the fuel value in the gas
stream and pollutant destruction may be a secondary consideration.
Direct flame combustion afterburners and thermal combustion afterburners
are similar. Both provide for the destruction of combustible (or oxidizable)
species in a hot, oxidizing environment. The basic difference is that the
direct flame afterburners provide for destruction of the combustible species
by passing the gas stream through a flame while the thermal combustion after-
burner destroy the combustible species by exposure to a high temperature-
non flame environment for the required residence time to achieve the necessary
oxidation reactions. The thermal combustion afterburner may have a flame, but
the flame serves only as a preheater. Both the direct flame and thermal combus-
tion afterburners will usually require the use of auxiliary fuel to create the
flame environment or supply preheat energy, respectively. Both afterburner
types generally are operated at temperatures of 540 C to 815 C (1000 F to 1500 F).
The catalytic afterburner provides a catalytic surface on which the
combustible species are oxidized at temperature of about 370 C to 480 C, (700 F
to 900 F). Because the heat released by oxidization of combustibles in the
carrier gas stream may not be sufficient to maintain the catalyst temperature,
additional thermal energy may be required to maintain the catalyst temperature.
This additional energy may be in the form of preheating of the carrier gas stream,
or may involve adding fuel to the carrier stream to increase the heat release
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rate at the catalyst surface. Because lower temperatures are required in
catalytic afterburners (and heat losses should be lower), the auxiliary fuel
requirements of catalytic afterburners should be less than for the previously
mentioned types.
Flares are essentially afterburners with an unconfined flame and exhaust
gas stream. They generally require some mechanism to promote mixing and may
require the use of auxilliary fuel or continuous ignition to insure a constant
flame. Because of their unconfined nature, flares are less well controlled
than other types of combustion afterburners; that is, mixing, reaction time,
quenching, time-temperature patterns, etc., are not nearly so well controlled
in flares as in confined afterburners. Hence, emissions of incompletely
oxidized species may be higher than for confined afterburners. Also, because
the nature exhaust stream from a flare is not confined, it is difficult to
measure pollutant emissions from these units.
Boilers, process furnaces, and heat recovery furnaces are afterburning
devices used to recover the energy content of the combustible in gas streams
where the energy content is sufficiently high and sufficiently constant with
time to justify the investment in the boiler or furnace. For example, refineries
use off gases from the catalyst regenerator (associated with catalytic cracking
plants) to fire CO boilers to generate steam. Also, blast furnace gases (with
heating valves of 50 to 100 Btu/scf) are fired in blast furnace stoves.
The scope of work for the present program dictates that the major effort
be directed towards the first three types of afterburners listed above. How-
ever, because of similarities between afterburner and flares, during the Phase I
activity we will give some attention to flares.
There are major difference between afterburners and equipment and processes
for utilizing the fuel heating valve in waste gases. This fact, together with
our knowledge that EPA has other programs on industrial boilers and industrial
process furnaces, has lead us to exclude these areas from consideration in our
study.
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PERSPECTIVE ON AFTERBURNER DESIGN AND APPLICATION PROBLEMS
Afterburner pollution control systems are used to reduce combustible
pollutants carried by exhaust gas streams by incineration, frequently with an
auxiliary fuel. The pollutants may include gases, vapors, and aerosols. The
afterburner functions by exposing the pollutant to a combination of circum-
stances, involving oxygen concentration, temperature, and in catalytic units
a catalytic surface, which lead to the destruction of the pollutant. Ideally,
the pollutants are reduced to simple chemical compounds (C0_ and H_0) having
no pollution potential.
While this ideal should be achievable if the pollutants are subjected to
a sufficiently high temperature for an adequate residence time and in the
presence of oxygen, economic and engineering factors have currently restricted
the operating temperature of afterburners to less than 2000 F, commonly to
the range of 1500 F and below. Afterburners employing catalysts are frequently
restricted to still lower maximum temperatures.
Under these conditions of only moderate temperatures, mixing of the
pollutant-carrying stream with the combustion gases from the auxiliary fuel
becomes extremely important; if poor mixing exists, a portion of the pollutant
will escape the intended oxidation environment, or be exposed for less than the
intended time. The result will be emissions of unoxidized or partially oxidized
species, such as aldehydes, which may be more objectionable than the original
hydrocarbons.
Although there appears to be a limited amount of well-documented information
available concerning the conditions of temperature, oxygen concentration, and
duration of exposure required to destroy specific pollutants , information
on the mixing efficiency in typical afterburner geometries is largely lacking.
As a result, most afterburners appear to be designed by "rules of thumb" and
empirical tests. Consequently, some afterburner installations actual result in
the outlet stream containing more pollutant gas than the inlet stream
Deficiencies in performance of an installed unit are generally corrected by in-
creasing the auxiliary fuel input and, thus, the general temperature level.
Obviously, afterburner efficiency decreases when this type of a "fix" is used.
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Catalytic afterburners are generally employed to take advantage of the
lower temperature level (and correspondingly lower auxiliary fuel require-
ment) needed to achieve rapid oxidation of hydrocarbons in the gas stream
when a catalyst is present. However, catalytic afterburners can only be
applied to "clean" pollutant streams, ones that will neither poison nor blind
the catalyst, and they usually cannot be applied sucessfully to gas streams
containing particulate. Additionally, catalytic units may be particularly
prone to only partially oxidizing some types of pollutants. The resultant
oxygenated species (aldehydes) may have a greated pollutant potential than
that of the original material.
Complicating the problem of afterburner design and operation is the fact
that afterburners are used in a wide variety of industrial processes. The
following is a partial listing of equipment processes and industries using
afterburners:
Resin kettels
Varnish cookers
Sulfuric acid manufacturing
Phosphoric acid manufacturing
Paint-bake ovens
Wire-coating process
Soap and synthetic
detergent industries
Glass manufacture
Frit Smelters
Food Processing Equipment
Fish canneries
Animal-matter rendering
With afterburners being applied to such a wide variety of processes and
industries, it is doubtful that available performance data are used to the
maximum in ensuring good design and application. Generally, a particular
industry will follow "industry practice" and not take full advantage of the
opportunity to develop generic or broadly applicable data for design. Also
they may not fully recognize or exploit the fact that pertinent design and
application data exist for units serving different industries but handling
Electroplating
Insecticide manufacture
Oil and solvent refining
Chemical milling
Coffee roasting
Meat smokehouses
Fertilizer plants
Rotogravuring
Degreasing operations
Dry cleaning
Fiberboard drying and curing
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similar pollutants, carrier gases, etc. The use of generic afterburners
criteria (as discussed later) will maximize the usefulness of existing and
new data and will provide a common basis for discussion and interchange of
data among users and manufactures.
PERSPECTIVE ON AFTERBURNER OPERATION
When viewed strictly as a piece of equipment, rather than as a process,
afterburners are subject to all of the troubles and problems of any combustion
device, and these may be magnified by the fact that the afterburner is an
auxiliary device and, thus, may not receive necessary attention and maintenance.
Improper operation of controls, durability of refractories and other high tempera-
ture components, corrosion, and other similar problems may be encountered in
operating units.
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AFTERBURNER RESEARCH PROGRAM
PROGRAM OVERVIEW
Phase I of the current study is directed toward effective utilization of
all available data and technology relating to afterburners. Thus, an important
part of the Phase I effort is to determine and document what is known and un-
known about afterburner performance. The final step in Phase I will include
the preparation of detailed recommendations for R and D on afterburner control
systems that will be conducted as part of the Phase II effort.
Phase II of the current program will include experimental research to fill
voids in available data. It will include field studies of operating units and
laboratory studies (under more conditions) of afterburner performance.
PHASE I - PROBLEM ANALYSIS
Phase I consists of the Problem Analysis phase of the program. It
includes: Research Plan Preparation, Technology Review, Comprehensive
Emissions and Performance Analysis, and Preliminary Environmental Assessment.
Each of these is discussed separately below.
Research Plan Preparation
.(4).
The Afterburner Systems Study reportv-r/included a section on research
recommendations. The basis for those recommendations was to "generate the
data required to predict and improve process performance and economics and
extend the application of afterburners to additional air pollution sources".
Those research recommendations are primarily afterburner-design oriented
(including development of new afterburner designs) and give less attention
to afterburner application.
The basic purpose of the present program concerns the application of after-
burners , and specifically an environmental assessment of afterburners as polluc-
tion control systems. Other important aspects relating to afterburner application
include energy use and economics. Thus, it is necessary to review and revise
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the research plan contained in the Afterburner Systems Study to generate a
plan compatible with the overall interest of this EPA program. Certain aspects
of the earlier program will likely remain as important aspects of the new
research plan, although they might be modified in detail to place emphasis on
obtaining emissions data. Thus, laboratory and field tests would like-
ly be included in the new plan, but they would be extended to include Level I
and Level II sampling and analysis. The design oriented aspects of the former:
research plan probably would be deleted as not required to meet the objectives
of the present program (although it is acknowledged that these aspects may
provide data useful to the overall development of afterburner technology).
Research areas that might be deleted include "afterburner gun (burner) and
control system development" and "new catalyst development". Mathematical model-
ling of afterburners will probably not be recommended as it pertains to detailed
afterburner design. However, some modelling of input-output relationships may'
be useful in developing application guidelines for the manual.
Technology Review
The Technology Review consists of reviewing the present technology con-
cerning afterburner control systems and compiling background information to
suppor the environmental assessment.
The report of the previous study, Afterburner Systems Study, includes a 17
chapter "Afterburner Handbook". This handbook section compiles much of the
technology regarding afterburner design and operation. In the conduct of this
task, Battelle is updating afterburner technology as described in the earlier
report. To perform this updating, Battelle is reviewing new technical litera-
ture concerning afterburners (published since the earlier study) and is working
with IGCI and other industrial contacts (as subcontractors and consultants,
and through industry committees and trade associations) to review the previous
material and insure that the technology described is current.
One area that appears to require more extensive treatment than it received
in the previous study is afterburner application. In the Afterburner Systems j
Study, afterburner application was primarily limited to part of two chapters,
whereas afterburner construction details were discussed extensively in at least
seven chapters. The present program is weighted more heavily in the application
area. Therefore, Battelle is limiting its effort with regard to afterburner
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design details to an updating of the previous study, but is expanding upon
the areas of afterburner application.
Battelle is approaching the afterburner application technology by generic
categories and not by cataloging of industry-by-industry details. Several
generic categories that are being used in evaluating afterburner technology
include:
(1) Type of device (direct combustion, thermal, catalytic)
(2) Carrier media composition (air, flue gas, inert gas, etc.)
(3) Carrier physical conditions (temperature, pressure, etc.)
(4) Carrier pollutant type (organic, ash, trace compounds, etc.)
(5) Afterburner supplemental fuel (gas, oil, waste gas, etc.)
(6) Carrier gas combustibles content.
An additional advantage of using generic categorization of afterburner
applications is the protection of proprietary industrial data. Because of the
nature of some industries, emission characterization and concentration data may
disclose proprietary details about processes or production rates. Thus, by not
reporting data by plant name, location, or specific process, but generically,
the proprietary interest of the plant operators is protected and we will be
more likely to receive cooperation in making data available and granting
permission for testing.
Mathematical Modelling—
As part of this effort, we plan to develop simple parametric models repre-
senting generalized versions of both thermal and catalytic afterburner systems.
The availability of these models will be important for correlating the present
data on afterburner systems, for the logical development of methods for predict-
ing and improving afterburner performance, for the planning and analysis of the
results from the laboratory and field tests, and in the development of mathe-
matical relations of afterburner performance for the manual.
These models are intended to take into account the parametric interactions
among the flow processes, the chemical processes, and the thermal processes.
Idealized mechanisms will be assumed for the various parameters in each type
of process. The chemical processes will be represented by global and not
detailed chemical-kinetic mechanisms. The different processes in the models
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will be coupled in such a way mathematically so that Individual processes can
be modified or extended, if necessary, without affecting the other processes
in the model. Final output from these models will be prediction of pollutant
concentrations as a function of input and operating parameters.
Comprehensive Emissions and Performance Analysis
The Comprehensive Emissions and Performance Analysis consists of the
development of estimates of the effectiveness (efficiency) of afterburners for
reducing pollutant emissions and the levels of emissions from afterburner
systems. The scope of this task includes all emissions from afterburners.
Three categories of emissions are being considered:
(1) Pollutants that pass through the afterburner and
are unaffected, either because the afterburner does
not control these emissions (e.g., SO-), or because
the afterburner is not 100 percent efficient (e.g.,
trace emissions of input hydrocarbons).
(2) Pollutants that are altered or manufactured within
the afterburner by chemical reaction (e.g., aldehydes
and POM formation due to "poor" combustion conditions
and conversion of S07 to SO, or sulfates).
(3)
Pollutants that are released from the afterburner
itself (e.g., trace metals eroding from catalytic
combustors).
The present effort is limited to the utilization of available emissions
data and does not involve field sampling. (Field sampling is included in
Phase II.)
Although the present effort does not involve field sampling, the EPA
sampling and analysis philosophy is being kept in mind while collecting the
available emissions data. Thus, as data are assembled, judgements are being
made as to whether the data are of Level I, Level II, or Level III quality,
both from the viewpoint of completeness and accuracy.
Information sources that are being utilized will include:
(1) EPA sampling test reports - New Source Performance Standards
programs (for example Battelle has sampled afterburners at
asphalt roofing plants under the NSPS programs)
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(2) State and local agency sampling test reports
(3) Afterburner manufacturer's tests (several
particularly impressive research programs have
been conducted by Surface Combustion and
(5-9)
reported by Hensath, et al ')•
Preliminary Environmental Assessment
The culmination of Phase 1 will be the preparation of a Preliminary
Environmental Assessment. While it is expected that the data obtained in
Phase I will not permit a comprehensive environmental assessment to be completed,
the attempt to complete the environmental assessment will point out the areas
where sufficient data are lacking. The success (or lack of success) in
completing the enviornmental assessment at this point will provide direction
for the Phase II studies.
Because afterburner combustion systems are air pollution control devices,
instead of industrial emission-generating processes, the environmental assess-
ment must be approached in a somewhat different manner than one would use in
conducting an environmental assessment of a basic emission source. For one
thing, afterburners are used on a wide variety of industrial processes and a
conventional environmental assessment would require sufficient study of each
of the industrial processes to precisely define plant pollutant output (after-
burner pollutant input). Such an approach is beyond the resources available
for this program. Thus, we are approaching the environmental assessment from
the generic categories discussed above. This approach will recognize important
differences between afterburner types, carrier gases, inlet conditions, pollut-
ants, etc., but will limit the assessment to a reasonable number of cases.
This approach also will permit extension of the results of this study to the
evaluation of the use of afterburners on new processes, where afterburners are
not presently being used.
Three criteria relating to acceptable emission levels will be considered
when performing the environmental assessment. These criteria are:
(1) Permissible ambient air quality concentrations
(2) Source emission standards
(3) Application of "best available" control technology.
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Although a Federal standard exists for ambient levels of hydrocarbons, it is
*
specifically directed to the automobile-smog problem. Federal ambient
standards for hydrocarbon/organics that are directed to industrial process
emissions do not exist, nor do Federal standards exist for source emissions
from most "new" industrial processes. Hence, Battelle is conducting a. brief
evaluation of state standards in these areas. Once the proper background
information is available, EPA and Battelle can then agree to a set of values
to be used as the "baseline" criteria for the environmental assessment of
afterburner systems.
Among the important factors being considered in performing the environ-
mental assessment of afterburners are:
(1) Alternative control systems
- Are afterburners required or can some other control system
be used to control the emissions?
- What types of afterburner control systems can be used (direct
flame, catalytic, etc.)?
- What is the relative environmental impact of various afterburner
types?
(2) Selection of afterburner operating variables
- What fuels are applicable?
- What are the temperature and residence time requirements to
destroy the pollutant?
- What are the environmental impacts of the various fuels? The
various operating conditions?
(3) What are the environmental impacts of emissions generated by the
afterburner?
- Due to chemical reaction of the emission species?
: - Due to erosion of. the afterburner?
(4) What is the effect of nonstandard afterburner operation
- How are startup, shutdown, and transients handled?
- What about afterburner malfunction?
- How easily are the catalysts poisoned?
- How sensitive are afterburner effectiveness and emissions to
input stream variables?
* The Federal Standard is 160
3 hours (6 a.m. to 9 a.m.).
nonmethane-hydrocarbons/m , or 0.24 ppm/
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(5) What are the environmental impacts of
- A well designed (and presumable costlier) system?
- A more economical (and presumable less effective) system?
(6) What are the areas of needed R&D relating to
- Afterburner control system design technology?
- Control system application technology?
EXPERIMENTAL PROGRAM AND FINAL ANALYSIS
Phase II of the Research Program consists of the following:
• New data generation
Field testing
Laboratory testing
• Analysis and evaluation
Environmental assessment
Standard practice manual.
Based on Battelle's knowledge of what is known about afterburner technology
and afterburner application relative to a comprehensive environment assessment,
it is certain that the Phase I environmental assessment will contain numerous
gaps. For instance, to the best of our knowledge no thorough emissions tests
(even equivalent to Level I) have been conducted on any afterburner systems.
Unless ongoing programs show promise of gaining needed information, the comple-
tion of a thorough environmental assessment will require the conduct of the
field and laboratory programs called for in Phase II. Although the overall
program needs are generally well defined at this time, some specific needs
will await definition during Phase I and so, to some extent, are being treated
in generalities at this time.
Field Testing
Some field testing of afterburner control systems has been done for EPA.
For example, under the NSPS program, Battelle conducted a sampling program on
the afterburners applied to the blowing still on the Elk Roofing Company asphalt
roofing plant in Stevens, Arkansas
(12)
and on the saturator line at the
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Certain-Teed Products asphalt roofing plant at Shakopee, Minnesota
Two CO-boiler/afterburner units also have been sampled by Battelle ^~
It Is Likely th.it other afterburner Installations have been sampled for EPA
and many have been sampled for state and local agencies as part of compliance
tests.
However, the sampling that has been conducted to date has not been
sufficiently comprehensive to qualify as complete Level I efforts. Generally
these sampling programs have been directed toward measurements of specific
criteria pollutants (particulates, gaseous hydrocarbons, SO?,NO ) and occa-
^ X
sionally included certain trace hazardous pollutants (POM, trace metals,
sulfates). Other data are lacking; for instance, particle size measurements
were attempted on several asphalt roofing plants but were unsuccessful. No
attempt has been made to conduct toxicity studies or to broadly classify
organics by class. Thus, although the data from these sampling programs are ,
available and will be useful to this program, there are gaps between the
available data and complete Level I data.
The field program will be designed to take advantage of the generic
classifications defined earlier, thus avoiding unnecessary repetitive sampling
at many industries. Basically, the sampling will be built around the EPA Level
I sampling and analysis philosophy and methodology. However, it is recognized
that Level I sampling and analysis are not adequate to define emissions of
certain important pollutants (e.g., specific organic compounds such as alde-
hydes and POM compounds). Thus, some Level II work will be required..
Laboratory Testing
Although field testing is an excellent method for determining emissions
from afterburners and afterburner effectiveness for controlling emissions, field
testing is expensive and it may be difficult to locate plants to provide the
complete range of desired operating conditions (input emission types, input
emission levels, etc.). Therefore, laboratory testing of afterburners and/or
afterburner simulation rigs under conditions simulating real afterburner
operation may be necessary to obtained needed data.
The use of laboratory testing of afterburners provides a means of studying
the effect on emissions of variations in:
(1) Input pollutant types (hydrocarbons, aldehydes, ketones, etc.)
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(2) Input pollutant concentrations
(3) Operating conditions (temperature, residence time, etc.)
(4) Carrier gas (oxidizing, reducing, inert, moisture
content, etc.)
(5) Afterburner design
(6) Supplement fuel (natural gas, fuel oil, other).
The actual laboratory rig(s) used for these studies might include an optimum
or ideal afterburner (to define the limits of what can be accomplished with
afterburning) and one or more simulations of commercial afterburners or new
afterburner concepts. Measurements that would be made would include at least:
(1) Temperature, pressure drops, air and fuel inputs per unit
gas flow, etc., to define the afterburner operating conditions
(2) Input pollutant concentrations with appropriate methods
including Level I and Level II methods
(3) Output pollutant concentrations with Level I and Level II
sampling and anlysis procedures
(4) Fuel consumption.
Results would be expressed in terms of:
(1) Emissions from the afterburner
(a) Hydrocarbons
(b) Oxygenated organics (aldehydes, ketones, esters)
(c) Criteria pollutants
(d) Trace metals
(e) Other
(2)
(3)
(4)
(5)
Afterburner effectiveness or efficiency (
lnPu-°utPut
^
Pollutant destruction per unit of fuel consumed
Afterburner efficiency as a function of temperature and
residence time
Others, as appropriate.
Typical of the laboratory testing that might be conducted is the research
(5-9)
performed by Hemsath of Surface Combustion . Hemsath studied the conditions
required to destroy certain hydrocarbons under ideal conditions (thorough mixing,
all input carrier gas at minimum required temperature, etc.).
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By consulting industry (IGCI and afterburner manufacturers) during the
planning and conduct of the laboratory program, Battelle believes that they can
insure that the design and operation of the laboratory afterburner rigs repre-
sentative of industry practice. Thus, we will avoid the possibility of
acquiring extensive laboratory data that the industry regards with a skeptical
eye.
Final Environmental Assessment
At the conclusion of the experimental program, the data should be available
to complete a comprehensive environmental assessment. This environmental
assessment will answer questions left unanswered in the Prelininary Environ-
mental Assessment due to gaps in available data.
Standard Practice Manual
To insure the technology transfer from the Battelle staff conducting this
study and their reports to the industry (and specifically to those concerned
with the application of afterburners), Battelle will prepare a "Standard Prac-
tice Manual" on afterburner application. This manual or guideline will present
informations on how afterburners can be applied to control emissions from
various industrial sources. It will provide step-by-step directions for deter-
mining when and how afterburners should be used and for selection of the best
afterburner systems for various applications.
A generic approach will be used with regard to afterburner design and
pollutant sources. That is, the application of types of afterburners will be
presented and the use of specific brand names or mention of manufacturers will
be avoided. The generic afterburner types will be as specific as possible and
will not be limited to "direct flame" and "catalytic" types. Thus, as far as
possible, units with different design approaches will be considered as separate
subtypes within the overall "direct flame" and "catalytic" classification.
Likewise, instead of considering each industrial source separately, the
generic source categorization described earlier will be used as the basis for
describing pollutant input streams. To the extent that data are available
(either in the literature, from EPA source tests, from manufacturers and trade
associations, or from field testing conducted on this study) specific industrial
sources will be categorized within the generic classifications used in this
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report. Hence, a particular Industrial user would have minimum difficulty
in considering afterburner application to his specific emissions problems.
A major aspect of this manual will be the material relating afterburner
application technology to the meeting of pollutant standards. Prime considera-
tion will be given to meeting emission standards and "best practice" control
technology. Because of the almost limitless variety of combinations of indus-
trial sources for which afterburners should be considered and local conditions
(other sources, terrain, meteorology, etc.), the meeting of ambient air quality
standards will not be treated extensively. It will be presumed that, for most
cases, state implementation plans will translate the meeting of ambient standards
into acceptable emission values for the specific local situation.
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REFERENCES
1. "National Inventory of Air Pollutant Emissions, 1968", U. S. Department
of Health, Education and Welfare, National Air Pollution Control
Administration, Publication No. AP-73, August, 1970.
2. Danielson, J. A., "Air Pollution Engineering Manual", second edition
EPA Publication No. AP-40, May, 1973.
3. "Control Techniques for Hydrocarbon and Organic Solvent Emissions from
Stationary Sources", EPA Publication No. AP-68, March, 1970.
4. Rolke, R. W., et al, "Afterburner System Study", Final report on EPA
Contract EHSD-71-3, NTIS Report No. PB-212560, 1972.
5. Hemsath, K. H., and Susey, P. E., "Fume Incineration Kinetics and Its
Application", AICHE Symposium Series, Vol. 70, No. 137.
6. Hemsath, K. H., Thekdi, A. C., and Lewis, F. M. , "Effects of Mixing and
Temperature on Reaction Rates During Fume Incineration", Presented at
22nd Canadian Chemical Engineering Conference, Toronto, Canada September
18, 1973.
7. Hemsath, K. H., Thekdi, A. C., and Lewis, F. M, "Application of Reaction
Kinetics and Mixing Studies in Design of a Fume Incineration", APCA
Paper No. 73-299, June, 1973.
8. Hemsath, K. H. and Thekdi, A. C., "Rich Fume Incineration", Surface
Combustion Div. Paper.
9. Hemsath, K. H., and Thekdi, A. C., "Air Pollution Control in the Carlon
Baking Process", APCA Journal, Vol. 24, No. 1, January, 1974.
10. Miller, M. R., and Wilhoyte, H. J.,"A Study of Catalyst Support Systems
for Fume Abatement of Hydrocarbon Solvents, APCA Journal, Vol. 17,
No. 12, December, 1967, p 791-795.
11. Wallach, A., "Some Data and Observations on Combustion of Gaseous
Effluents from Oaked Lithograph Coatings", APCA Journal, Vol. 12, No. 3,
March, 1962, p 109-110.
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12. Webb, P. R., Barrett, R. E., Baytos, W. C., and Miller, S. E.,
"Particulate and Gaseous Emissions from the Asphalt Roofing Process
Blowing Still at the Elk Roofing Plant, Stevens, Arkansas", EPA
Report No. 76-ARM-ll, May, 1977.
13. Webb, P. R., Baytos, W. C., Miller, S. E., and Barrett, R. E.,
"Particulate and Gaseous Emissions from the Asphalt Roofing Process
Saturation at the Certain-Teed Products Plant, Shakopee, Minnesota",
EPA Report No. 76-ARM-13, May 31, 1977.
14. Schulz, E. J., Hillenbrand, L. J., and Engdahl, R. B., "Source
Sampling of Fluid Catalytic Cracking Plant (Electrostatic Precipitators
and CO Boiler) of Standard Oil of California, Richmond, CA", Research
report on Contract 68-02-0230, Task 3, July, 1972.
15. Schulz, E. J., Hillenbrand, L. J., and Engdahl, R. B., "Source Sampling
of Fluid Catalytic Cracking, CO Boiler, and Electrostatic Precipitators
at the Atlantic Richfield Company, Houston, Texas", Research report on
Contract 68-02-0230, Task 3, July, 1972.
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ADVANCED COMBUSTION SYSTEMS FOR STATIONARY
GAS TURBINE ENGINES
By:
S. A. Mosier
Pratt & Whitney Aircraft Group
West Palm Beach, FL 33402
This paper was not received in time for publication, and therefore will be
included in Volume V.
133
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DEVELOPMENT OF EMISSION CONTROLS FOR
1C ENGINES
Contract not awarded in time for paper submittal, see Volume V.
135
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EMISSION CHARACTERISTICS OF SMALL STATIONARY
DIESEL ENGINES
By:
0. H. Wasser
Industrial Environmental Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
This paper was not received in time for publication, and therefore will be
included in Volume V.
137
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SESSION V:
ADVANCED PROCESSES
G. BLAIR MARTIN
CHAIRMAN
139
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INVESTIGATION OF STAGING PARAMETER FOR NOX CONTROL
IN BOTH WALL AND TANGENTIALLY COAL FIRED BOILERS
By:
R. A. Brown, H. B. Mason and P. Neubauer
Acurex Corporation/Aerotherm Division
Mountain View, California 94042
141
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ABSTRACT
Tests on an EPA 1 to 1.5 x 106 Btu/hr pilot scale pulverized coal fur-
nace show that NOX emissions of 100 to 150 ppm (zero percent 03) are achieve-
able with the use of two stage combustion. Comparable NOX emission levels
were obtained with three different coal types fired in either the single-wall
or tangential configuration. On the basis of these tests, the combustion
conditions leading to minimum NOX appear to be (1) operation of the primary
flame zone at 75 to 85 percent of stoichiometric air, (2) complete separation
of stage air from the first stage, (3) first stage mean residence time of
3 to 5 seconds, (4) high first stage volumetric heat release rate and/or high
first stage combustion air preheat. Additionally, the minimum NOX condition
was achieved using the same burners as were used in uncontrolled operation to
simulate full scale equipment.
Tests to date have explored the effects of first and second stage com-
bustion conditions on NOX production with three types of coal: fired in a
five-burner, single-wall configuration, in a four-burner tangential configura-
tion and in a four-burner horizontal tunnel configuration. First stage con-
ditions varied were: stoichiometry; residence time to injection of stage air;
volumetric heat release rate; combustion air preheat; and fuel/air mixing
(swirl, injector design). Second stage variables were residence time to the
convective section, stage air preheat and stage air injector design. Ini-
tially, the furnace was operated in the baseline, uncontrolled condition to
compare emissions to full-scale equipment. Good simulation of both the level
of NOX emissions and the variation of emissions with excess air was demon-
strated for both the wall-fired and tangentially-fired configurations.
The first stage stoichiometry was the most significant variable in NOx
reduction. Emissions of 100 to 150 ppm (zero percent 03) were achieved at a
first stage stoichiometric ratio of 0.75 to 0.85. This corresponds to about
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an 85 percent reduction for the wall-fired configuration and an 80 percent
reduction for the tangential configuration. Below 0.8, the NOX levels were
higher presumably due to increased second-stage NO formation. At the 0.8
minimum NOX condition, the emissions were relatively insensitive to first
stage mixing. That is, similar emissions were achieved for both the wall-
fired and tangential-fired configurations using several different burner
settings and/or injector designs. Operation at a stoichiometric ratio of
0.9 or higher, however, showed a strong effect of first stage mixing. Here,
the lowest NOX was seen for tangential-firing and for wall-firing with the
use of a slow-mix axial injector. These results suggest that combined burner
modification and staged combustion will yield the best NOX reduction if oper-
ation below a stoichiometric ratio of 0.9 is precluded by operational con-
straints. In general, increasing the first stage residence time for all con-
figurations decreased NOX emissions. Staging test and hot sampling in the
first stage of the horizontal extension configuration showed that NO decays
from high peak levels generated during the first second. This peak is depen-
dent on the stoichiometric ratio of the first stage. Also, for a fixed resi-
dence time, increasing the volumetric heat release rate or the combustion air
preheat decreased NOX at the low stoichiometric ratios.
The only second stage variable significantly affecting the minimum NOX
emission was the stage air injector design. Here, it was found that leakage
of stage air back into the first stage increased NOx over the levels attained
with complete separation. These results suggest that the dramatic NOX reduc-
tion achieved with the facility are in large part due to the isolation of
the stage air from the first stage. The second stage residence time had
little effect on NOX, but did affect CO emissions. Operation at a residence
time of 1.0 second or larger and rapid mixing of stage air with the combus-
tion products generally yielded CO emissions of 100 ppm or lower.
A possible design for a 500 MW boiler is presented which shows that
utilizing a long first stage residence time under fuel rich conditions
increases the boiler size by only 5 percent. Of course, the practical appli-
cation of this design is dependent upon the availability of cost effective
materials for the fuel-rich first stage.
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SECTION 1
INTRODUCTION
Utility and industrial boilers are the two largest stationary emitters
of NOX. Together they comprise about 65 percent of nationwide stationary NOX
emissions for the year 1974 (1). Because of this, control of NOX from utility
and industrial boilers has been given high priority in the Federal, state
and local NOX abatement programs to attain and maintain the National Ambient
Air Quality Standard for N02 (100 mg/m3). Standards of performance for New
Stationary Sources were set in 1971 for gas, oil and bituminous coal-fired
steam generators with a heat input greater than 250 MM Btu/hr2. The standard
for bituminous coal units (0.7 Ib NOj/lO6 Btu, -580 ppm at zero percent 03)
is being revised to 0.6 Ib NOg/lO6 Btu, -500 ppm, to reflect advances in con-
trol technology (3). The same standard has been recommended for lignite-fired
units (4). Standards for new industrial boilers are in preparation by EPA's
Office of Air Quality Planning and Standards. Additionally, emission stan-
dards for new or existing utility and large industrial boilers has been set
as part of State Implementation Plans to maintain air quality in N02-critical
regions (5).
Despite this concerted regulatory activity, a number of air quality
planning studies (6-9) have determined that additional stationary source con-
trol technology will be needed in the 1980s and 1990s to meet projected N0£
air quality needs. These studies have also concluded that, where possible,
the additional technology should focus on application to advanced design of
new equipment. In response to the need for additional technology, the EPA
is developing and demonstrating advanced controls for utility and industrial
boilers and other sources (10, 11). The near term emphasis is on use of major
hardware modifications for new or'existing sources. The far-term emphasis is
on major redesign of new sources. The ppm emission goals (at zero percent 03)
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for the near and far term R&D programs for coal-fired utility and industrial
j
boilers are as follows (10, 11):
Utility
Industrial
1980 Goal
230
175
1985 Goal
115
115
The R&D program discussed in this paper is a component in the Combus-
tion Research Branch of lERL-RTP's effort to generate advanced NOX controls
for utility and industrial boilers firing conventional and alternate fuels
(12). To date, the testing has concentrated on utility boiler configurations.
The overall goal of these tests is to identify low NOX operating conditions
for the staged combustion of pulverized coal. The results of the program are
intended to support both the near-term and far-term efforts mentioned above.
To support the near-term application of major hardware modifications on units
of conventional design, the test facility was designed with a fairly realistic
modeling of the geometry and aerodynamics of large multiburner boilers. This
modeling will aid in translating the present pilot scale results to field
demonstration or design of major hardware changes. To support the far term
application of control through major redesign of new sources, the facility
was designed with the flexibility to give a wide variation of the combustion
process modifications important in NOX control. This flexibility offers the
capability of identifying combined low NOX process modifications which are
beyond the range of field units of conventional design but which may relate
to advanced design. Although the facility was designed to simulate either the
front wall-fired or tangentially-fired configurations, a horizontal extension
section allowed additional study of the combustion parameters in an axisymmet-
ric flow configuration.
The combustion process modifications investigated in the current test
program are as follows:
• Baseline (uncontrolled) burner aerodynamics and wall cooling
• Primary flame zone stoichiometry (stoichiometric ratio, SR)
• First Stage Mixing
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• Method of stage air injection
• First stage residence time
• Second stage residence time
t First stage heat release rate and combustion air preheat
These parameters were investigated for the various configurations with the
following test objectives as a guide:
• Verify that baseline NOX emissions and trends with excess air are
representative of full scale equipment
• Identify the best combination of low NOX combustion conditions for
- Application to conventional designs (SR >0.95)
- Application to major redesign (SR <0.95)
• Identify second stage residence time requirements to achieve CO
and carbon burnout at the low NOX conditions
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SECTION 2
EQUIPMENT DESCRIPTION
The experimental facility shown in Figure 1 and described in detail in
detail elsewhere (12, 13} was designed to simulate the aerodynamics of either
a front wall-fired or tangentially-fired boiler. The basic firebox is a
39-inch refractory lined cube which exits to a refractory lined heat exchange
section. Movable heat exchanger drawers allow the variation of the combus-
tion gas quench rate, the furnace residence time or the combustion volume.
The primary emphasis in the design of the hardware was to be able to explore
staged combustion for NOX control. Staging ports are provided in each of the
heat exchanger sections allowing a variety of first and second stage residence
times to be explored. The furnace exhibits the typical heat release per unit
volume of coal-fired furnaces at about 1.0 x 106 Btu/hr to 1.5 x 106 Btu/hr.
This firing rate is distributed between five variable swirl burners .for the
front wall-fired configuration and four corner burners for the tangential
configuration. A coal spreader was used to produce the well mixed bulbous
flame in the front wall-fired burners and an open tube was used for the
delayed mixed axial flames.
Additional hardware utilized for generating some of the data in this
paper included horizontal extension sections. These sections, 33-inch inside
diameter, shown in Figure 2, allowed for axisymmetric flow and staging at
residence times shorter than those feasible with the firebox configuration.
Four of the research swirl block front wall-fired burners were used in this
configuration at the same combustion intensity as in the firebox configura-
tion. A 16-inch diameter movable refractory choke was used to achieve stage
separation when staging.
The various stage air locations referred to in the following text for
the firebox configuration are shown in Figure 3.
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SECTION 3
EXPERIMENTAL RESULTS
The combustion process modifications investigated in the current test
program are as follows:
t Baseline (uncontrolled) burner aerodynamics and wall cooling
• Primary flame zone stoichiometry
• First stage mixing
• Method of stage air injection
• First stage residence time
• Second stage residence time
• First stage heat release rate and combustion air preheat
These parameters were investigated for both the front wall-fired and tangen-
tial ly, corner-fired configurations with three coal types. Emissions of CO
and carbon particulate were monitored for all tests so that the impact of com-
bined low NO modifications on unit efficiency could be determined.
A
Some initial results using an axisymmetric tunnel configuration (hori-
zontal extensions) are also presented. The primary objectives of this later
series of tests were to further explore the effects of residence time, first
and second stage temperature as well as stoichiometry.
Several definitions need to be emphasized before discussing the data.
These are:
Primary Air
- Air used to convey the coal to the burner, ex-
pressed as percent of total at 15-percent ex-
cess air
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Secondary Air -
First Stage Air -
Stage Air -
Total Air
Stoichiometric Ratio -
Air introduced through the burners into the
first stage exclusive of the primary air
Secondary + primary air
Air introduced into the second stage
Primary + secondary stage air
First Stage Air
= SR
Stoichiometric Air
Residence Time
— Mean volumetric residence time of the mass flow
using a measured temperature to calculate an
average density
3.1
BASELINE CONDITIONS
Since NO emissions from coal combustion are highly sensitive to the com-
bustion conditions, the relevance to practical equipment of the low NOV condi-
A
tions identified in this facility is reinforced by establishing that the pilot
scale baseline emissions simulate results of field tests on full scale equip-
ment.
The first objectives of the present test series were, therefore, to es-
tablish a baseline operation representative of full scale equipment. The base-
line series of tests consisted of varying the burner settings and the degree of
wall cooling to identify the conditions which best represented baseline emis-
sion levels and trends with excess air. The base conditions should also cor-
respond to conventional utility practice for fuel/air velocities, primary stoi-
chiometry, air preheat, etc.
Baseline NO emissions were determined for the five front wall-fired IFRF
burners using the B&W type coal spreader and for the four tangentially-fired
burners. The results are compared in Figure 4 with the pilot scale tests of
Armento (14), McCann (15), and Pershing (16) and with the full scale tests of
Crawford (17) and Selker (18). Both the front wall-fired and the tangential
emissions data compare quite well in overall level and trend with the respec-
tive field data. The tangential plot also shows the baseline data for the
axial injector in the five front wall burners. Although the axial emissions
fall slightly below the resluts with the tangential burner, they are within
the range of tangential field data.
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The baseline tests discussed above were taken with refractory walls
with only natural conductive losses. A number of tests were performed with
additional wall cooling but the emissions did not change more than about 7
percent with 300,000 Btu/hr of additional cooling. These results agree with
those of other investigators (19, 20, 21). They also found that temperature
has little direct effect on fuel N conversion, which accounts for about 80
percent of the total NOX from coal combustion (19, 20, 22).
3.2 STOICHIOMETRY
NOX control by staged air combustion has been widely tested since its
initial development in the late 1950's (23). Operation with a near or sub-
stoichiometric first stage effectively suppresses both thermal and fuel NOX
formation. The degree of NOX control achieved by increasing fuel-rich stoi-
chiometry may be limited, however, by both practical and theoretical consid-
erations. First, from a practical standpoint there is concern that operations
of conventional design boilers at a first stage stoichiometric ratio (SR) be-
low about 0.95 may yield unacceptable rates of water wall corrosion. One
objective of the present program was therefore to identify low NOX conditions
for SR ^ 0.95 for potential application to conventional design boilers. Lower
SR may be acceptable for new unit redesign, however, so a second objective
was to identify the minimum achievable NOX emission at low SR. Here, funda-
mental considerations suggest a limit to NOX reductions. Numerous studies
have shown that reduced first stage SR reduces the conversion of fuel N to
NO. However, part of the ,fuel N remains in an intermediary form, primarily
HCN, which largely oxidizes to NO in the second stage (24, 25, 26). Addition-
ally, under fuel-rich conditions, hydrocarbon combustion, even in the absence
of fuel N, yields bound intermediaries from molecular nitrogen (24, 27, 28).
Staging tests were performed with the stage air introduced into a num-
ber of positions in the heat exchange tower while varying the first stage
stoichiometric ratio. NO versus the first stage stoichiometric ratio (SR) is
shown for both the front wall-fired and tangential configuration in Figure 5
for the second staging position (see Figure 3). The effects of the staging
position, i.e., first stage residence time will be discussed later. As seen
from the curve, NO is a strong function of the first stage stoichiometric
ratio. For the front wall-fired configuration, a 52-percent reduction in NO
*
151
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was achieved at a stoichiometric first stage and an overall excess air of 15
percent. A minimum NO level of 160 ppm was achieved (82-percent reduction)
at an SR of 0.80 to 0.85.
! For the tangential case, a 31-percent reduction was achieved at a stoi-
chiometric first stage and a minimum of 125 ppm (71-percent reduction) at an
SR of 0.85. Further reductions in SR showed a corresponding rise in NO for
both configurations at this staging position. Similar results were obtained
for the horizontal extension configuration.
The speculation is that above an SR of about 0.85, the majority, if not
all, NO is generated in the first stage. Below an SR of 0.85, NO very likely
decreases in the first stage with decreasing SR. Armento (14) suggests that
first stage NO decreases to zero at a first stage equivalence ratio of about
0.65. Figure 5 then suggests that an increasing amount of second stage NO is
formed as the SR decreases. This increase also corresponds to an increased
h'eat release in the second stage.
These results are at least in qualitative agreement with equilibrium con-
straints. For example, Sarofim (Reference 28) has shown that the equilibrium
concentration of the bound nitrogen intermediaries in fuel-rich combustion
reaches a minimum at an SR dependent on temperature and fuel and increases as
the SR is further reduced. Although the equilibrium concentration is low
(<100 ppm) at normal coal combustion temperatures, the oxidation of these inter-
mediaries in the second stage can constitute a lower limit to NOX reduction
achievable by staging. Another limiting condition could arise from the fraction
of the fuel nitrogen which remains in the coal char after pyrolysis (16, 26).
Pershing (16) has estimated that 100 to 200 ppm of total NOX emissions are due
to char NOX under fuel-lean conditions. Furthermore, the oxidation of the char
nitrogen to char NOX proceeds slowly and is relatively insensitive to first
stage conditions. The formation of char NOX in the second stage could thus
limit the effectiveness of staged combustion for NOX control.
The difference in the minimum achieved between the two firing configura-
tions is believed to be attributable to bulk residence time effects as opposed
to localized burner mixing. This will be further discussed in the sections on
mixing and residence time. Tests were also conducted to determine the effects
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of second stage stoichiometry on the overall NO levels. Figure 6 shows several
typical curves of NO versus overall excess air at various stoichiometric ratios.
As seen here, the overall NO does not seem to be a strong function of excess air
under staged conditions. Similar results were obtained for the front wall-fired
configuration, for other loads, coals, and staging positions. The only signi-
ficant effect is noted at SR = 0.65 between 15 and 5 percent excess air. At
this SR, the NO decreased by 50 ppm at the lower excess air level. Excess air
had a significant effect on CO and carbon loss if the second stage residence
time was less than 1 second. In this case, 20- to 25-percent excess air was re-
quired to achieve CO levels below 100 ppm at SRs below 0.95. However, when the
second stage residence time was at least 1 second, the CO was always under 100
ppm and carbon loss was less than 0.5 percent of fuel input on a Btu basis.
It has been shown NO levels as low as 125 ppm can be achieved with the
first stage stoichiometry between an SR = 0.75 to 0.85 and an overall excess
air of at least 15 percent to achieve CO and carbon burnout. No significant
effect of excess air was seen on NO emissions for most first stage stoichio-
metries.
3.3 FIRST STAGE MIXING
NO emissions from unstaged combustion and from staged combustion at
A.
near stoichiometric F/A ratios and above are dominated by burner mixing (17, 19,
22, 29). Detailed study of NOX control by burner modification is beyond the
scope of this program and is covered elsewhere (30). However, the combined ef-
fect of mixing and staging was carried through the tests for two reasons. First,
burner mixing is important in staging of boilers of conventional design where
operation at SR < 0.95 is precluded by operational problems (17, 18). Thus the
study of low NO conditions for application to conventional designs considered
A
both the front wall-fired and corner-fired configuration with conventional bur-
ner designs. Additionally, front wall tests were run with a delayed mix axial
injection to bracket effects of high and low rate of mixing with staging. Sec-
ond, fundamental considerations indicate that burner mixing may be less signif-
icant at the low SR potentially achievable with major redesign. As noted above,
it is suspected that NOX emissions at low SR are limited by the chemistry of
bound N intermediaries and by the oxidation of char N. From available data and
calculations, it is conceivable that under fuel-rich conditions, these limits
153
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are controlled more by the overall kinetic and equilibrium condition (bulk tem-
perature, residence time, fuel composition, stoichiometry) than by the micro-
scopic mixing.
The effect of delayed mixed flames under baseline conditions is evident
by comparing the results of the spreader nozzle to the results of the axial
i j
nozzle as seen in Figure 4. As expected a rather dramatic effect is seen under
baseline conditions with the slow mixed flames producing only about 55 percent
of the NO of the well-mixed spreader flames.
i
A comparison of mixing under staged conditions is seen in Figure 7 for
the front wall fired spreader and axial configurations at 1.0 and 1.5 x 106
Btu/hr load. The influence of first-stage mixing can be seen even under staged
conditions where decreased mixing in the first stage produced lower NO for a
given stoichiometric ratio, at an SR of 0.85 or greater.
' Similarly, the higher load conditions, where more rapid mixing occurs,
also produced higher NO than the 1.0 x 106 Btu/hr condition over the entire
stoichiometric ratio range. However, both temperature and mixing contribute
to this increased NO. Again, it should be noted that the role of first-stage
mixing decreases as the stoichiometric ratio decreases. It appears that below
an SR = 0.75 (0.85 for 1.0 x 106 Btu/hr) first stage mixing ceases to have any
influence.
3.4 STAGE AIR MIXING
Nearly all prior studies of staged combustion have injected the stage
air so that a portion backmixes with the fuel-rich first stage. This backmixing
makes it difficult to determine the independent effects on NO of first stage
J\
stoichiometry, residence time and local fuel/air mixing. Limited results have
shown that directing stage air away from the primary flame zone has a substan-
tial effect on NOX reduction (15, 18). The present facility was therefore de-
signed to achieve a minimum of backmixing into the first stage. The stage air
mixing technique was qualitatively studied using cold flow smoke tests. Little
backmixing was observed provided the opposed stage air jet impinged at the cen-
ter of the duct. If the jets impinged on the opposite wall considerable downmix-
ing was observed. Backmixing may account for some of the differences seen in the
shape of the curves of stoichiometry versus NO in Figures 5 and 7 for the two
154
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staging positions. However, to further illustrate the effect of stage separa-
tion, tests were run with biased burner firing using the same primary flame
stoichiometry as the staged tests. Also, the method of staged air injection
was perturbed to cause backnrixing into the first stage and thereby reveal the
consequences of backmixing on NOX emissions. The stage air injection technique
was varied to study the effects of second stage mixing on CO and carbon burnout
as well as any effect it may have on potential second stage NO. The results of
mixing in the second stage are shown in Figure 11.
Three mixing types were explored, fast, slow and downmixing (backmixing}.
The fast mixing condition uses the normal four 1-inch diameter ports in which
the opposing jets meet at the center of the duct under all conditions. The slow
mixing case utilized eight 2-inch diameter ports located in two vacant heat ex-
changer drawer windows as close to the first staging position as possible. Back-
mixing was achieved by introducing the stage air from one side only at the first
staging position.
Figure 8 shows that at a stoichiometric ratio of 0.85, there was virtu-
ally no affect of the 3-second stage mixing conditions. However, at an equiva-
lence ratio of 1.02, the slow mix condition gave consistently higher NO levels
with the spread in the data being greater with higher excess air. This result
is belived attributable to greater backmixing into the first stage. It can
be seen that a similar result was obtained for the purposely backmixed condi-
tion. It should also be noted that NO is more sensitive to slight changes in
the first stage stoichiometric ratio at a SR = 1.02. The conclusion then is
that within the staging techniques and SR's tested, the second-stage mixing
technique has very little influence on the NO except as it influences the first
stage. This effect can also be seen from the biased-fired data point also
shown on Figure 8. This case represents the extreme in backmixing where the
lower three burners were operated at a SR = 0.85, with the excess air de-
livered through the upper burners. An effect of the second-stage mixing tech-
nique was noted on CO and carbon loss, with the slower mix conditions producing
higher CO and carbon (200 to 500 ppm CO and 1 to 2 percent carbon loss). It is
therefore critical that a high degree of stage separation be achieved in order
to obtain the lowest possible NO for any first stage stoichiometric ratio.
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3.5 COAL COMPOSITION
Three different coals were tested to determine the effect, if any, of;
coal composition on NO emissions for baseline and staged conditions. Table I
lists the principal properties, nitrogen content and the rationale behind se-
lection of each of these coals.
Although these are some differences between the three coals, the base-
line NO emissions for the three coals are not radically different as seen in
Figure 9. Emissions with the Montana coal tend to be slightly higher for both
the front wall-fired spreader and the tangential configurations. :
The effect of coal composition on NO under staged conditions is shown
in Figure 10 for the front wall-fired and tangential configurations. For the
tangential configuration the Western Kentucky and Pittsburgh data agree closely.
The Montana data is higher at baseline but is lower below SR = 0.90. At the
rich condition the NO emissions with the Pittsburgh coal did not increase with
decreasing equivalence ratio to the same extent as the Western Kentucky coal.
The NO from the Montana coal reaches a lower minimum and does not exhibit as
much second-stage NO as the Pittsburgh coal below as SR of 0.85. This suggests
that at the low stoichiometric ratios the fuel N intermediary products may be
.different for the three coals.
The staging data for the front wall fired configuration at 1.0 x 106
Btu/hr shows a similar trend to the tangential data. However, for the front
Wall-fired configuration the NO levels of the Western Kentucky and the Pitts-
burgh No. 8 coals differed at stoichiometric ratios of 1.0 to 0.85. On the
other hand, at a firing rate of 1.5 x 106 Btu/hr no appreciable difference was
observed between the NO levels of these two coals. It is possible that the
difference in the 1.0 x 106 Btu/hr data was due to changes in mixing patterns
caused by buildup of a sticky ash deposit on the fuel tip frequently encountered
during the Pittsburgh No. 8 firing. The trend of the NO data for the Montana
coal was consistent for all configurations and firing rates. That is, for the
Montana coal the NO levels were higher at baseline conditions and SR's greater
than 0.80 to 0.85 but achieved a lower minimum at an SR < 0.85.
It appears then that the combustion of Western Kentucky and Pittsburgh
No. 8 coals yield quite similar results, The Montana coal acts differently
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under both baseline and staged conditions. This difference may be attributed
to the lack of sulfur and/or water content of this coal.
3.6 LOAD REDUCTION
Under normal operation, reduced load (volumetric heat release rate) and,
reduced air preheat tend to reduce NOX emissions by suppressing thermal NOX-
Indeed, new boiler designs are using enlarged fireboxes partly to meet NOx
emissions standards (3). Under fuel-rich conditions, however, opposite effects
may prevail. The work of Sarofim, et al. (26, 28, 31) has suggested that high
heat release rate and/or high preheat may reduce NOX in two ways. First, high
bulk temperature can accelerate the decay of superequilibrium concentrations of
bound N intermediaries in the first stage and thus reduce the conversion to NO
in the second stage or accelerate the decay of superequilibrium levels of NO.
Second, high first stage temperature can reduce the amount of bound nitrogen
carried into the second stage in the char.
First, the effect of load was determined at baseline condition for the
front wall and tangentially-fired configurations. This is shown in Figure 11.
The trend with excess air is similar for the two configurations but the higher
load yields a 25-percent increase for front wall firing and a 40-percent in-
crease for tangential firing. This increase is attributable to both aerodynamic
effects and temperature. The high load firing produced more intense sharply
defined flames for both tangential and wall firing.
The differences in load under staged conditions are seen in Figure 12.
High load firing yielded lower N0¥ below SR = 0.75. This result is in line with
A
the mechanisms suggested above. Further evidence for these mechanisms will be
covered in the subsection on residence time and preheat.
3.7 FIRST STAGE RESIDENCE TIME
Conventional applications of staged combustion inject the staged air di-
rectly over the primary flow with a resulting first stage residence time of less
than 1 second. This is done both for convenience and to ensure adequate second
stage residence time for CO and carbon burnout. Several studies have suggested,
however, that increased first stage residence time enhances NOX reduction (15,
18, 25, 32-34). This is consistent with fundamentals since increased residence
time at fuel-rich conditions should promote the reducing reactions involving
157
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bound nitrogen intermediaries and should also promote the driving off of the
char-bound nitrogen prior to oxidation in the second stage. At very rich con-
ditions, however, there could conceivably be compensating effects due to in-
creased formation of bound nitrogen from molecular nitrogen.
Tests were conducted in the front wall-fired configuration, the tangen-
tially-fired configuration and the horizontal extension mode to explore the
effects of residence time. With the main firebox, three stage air injection
positions (see Figure 3 for location) and two loads, 1.0 and 1.5 x 106 Btu/hr,
were investigated. With the horizontal extension configuration (Figure 2) much
shorter residence times were explored at loads of 85 and 1,3 x 106 Btu/hr. The
reduced loads were used in order to maintain approximately the same heat release
per unit volume as with the firebox configuration. Also four burners were used
instead of five in order to maintain constant burner aerodynamics. Baseline
tests in this horizontal extension mode revealed near identical NO versus ex-
cess air curves as compared to the front wall-fired firebox data.
The variation of NO with residence time* is shown in Figures 13 and 14
at various first-stage stoichiometric ratios for the front wall and tangentially-
fired configurations, respectively. The variation in NO with residence time
for the horizontal extension over a much broader range of residence times is
shown in Figure 15.
This data leads to the following conclusions:
• At 1.65 < SR <: 0.95 NO decreases with increasing residence time
with the rate of decreasing leveling off after 3 to 3.5 seconds
• To achieve a lower overall NO value for a given residence time the
stoichiometric ratio must be lowered. However at low SR's and at
;The residence times here are volumetric bulk residence times determined by the
,mass flowrate and flue gas density calculated at an average temperature of
2,200°F assuming a well stirred reaction over the furnace volume. It should
be remembered that the first stage residence time at a SR = 0.75 will be con-
jSiderably longer for a given configuration than at the baseline stoichiometry
with 15- to 30-percent excess air as experienced in conventional boilers.
158
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the longer residence times, .it appears that sufficient intermediary
species are formed and then converted to NO in the second sltage to
cause the overall NO to increase.again.
• In the firebox configuration and at a low stoichiometric ratio an
increase in combustion intensity could be traded for longer resi-
dence times. However, this was not clearly demonstrated in the
horizontal extension configuration.
• Taking all the data into consideration and using the staging tech-
niques employed here, it does not appear that NO levels below 100
ppm can be achieved just be extending the residence time alone
• The lower NO exhibited by tangential firing at low stoichiometries
may be due to a longer bulk residence time compared to wall firing.
If the tangential data at SR = 0.85 were shifted by an increase in
residence time of 0.9 seconds, the tangential and front wall-fired
data would coincide. The rationale behind this 1s that the burner
is located physically lower in the firebox and the tangential
rotation may result in an effective longer residence time.
To gain additional insight into the formation and decay of NO in the
first stage, sampling in the hot fuel-rich first stage in the horizontal
extension configurations was performed using the probe shown in Figure 16.
This is a water cooled, water injection probe which rapidly quenches the hot
gases and coal or char particles sampled from the first stage. The horizontal
extensions were set up with the stage air introduced at the longest possible
residence time and with samples taken at various distances (or residence times)
from the burner. Figure 17 shows the NO levels as a function of residence time
and stoichiometric ratio. These data show that the NO levels reach a peak early
in the first stage and then decay with increasing residence time. At suffi-
ciently low SR (^0.65) the NO appears to nearly vanish; thus adding further
evidence that particularly for the long residence time configurations, second
stage NO is probably being formed from the intermediary XN species. These
data also show that the peak is dependent on the stoichiometric ratio. Sam-
pling for other XN species is needed to determine if the fuel nitrogen is be-
ing converted to N2 or other XN's, which are eventually converted to NO in the
second stage.
159
-------
3.8 SECOND STAGE RESIDENCE TIME
The effect of second stage residence time was explored by keeping the
stage air location constant and moving the heat exchange surface. Figure 18
shows the effect of second stage residence time as a function of stoichiomet-
ric ratio and second stage mixing technique. As can be seen, no effect was
observed indicating that for these equivalence ratios second stage NO is being
formed very rapidly.
However, one practical limitation to staged combustion has been the
occurence of CO and carbon-in-flyash emissions at low stoichiometric and/or
low second stage residence times (15, 18, 32-34). One objective of the present
program associated with the identification of the best combined low NOX oper-
ating condition was the identification of the second stage residence time
required for CO and carbon burnout. This requirement impacts the feasibility
of the present results for application to both conventional designs and
advanced designs. It was found that with 15 percent excess air and a second
stage residence time of 1 second or longer, CO levels were below 100 ppm and
carbon losses were below 0.5 percent of the heat input. The minimum second
stage residence time was reduced at high levels of excess air.
3.9
TEMPERATURE
As mentioned in the section on load reductions, theoretical considera-
tions indicate that higher temperature or load may drive the NO and XN reducing
reactions at a faster rate if a superequilibrium condition exists in a fuel-
rich environment. Therefore, it would be expected that under fuel-rich con-
ditions increased air preheat would also lower the NO levels. Under the fuel-
lean environment, the NO emissions should be higher for the higher preheat.
Indeed the data (Figure 19) reflects these trends although the effect is not
strong for the fuel-rich condition. The higher NO emissions for SR's >_ 0.90
are attributed both to a higher thermal portion and to a significant change
:in the aerodynamics as the burner exit velocities change with preheat. That
•is, for the cold conditions, the flame begins to resemble a delayed mixed
flame.
160
-------
Figures 12 and .19 show that for reducing conditions increased preheat
and or load is marginally desirable. However, there may be a limit to this
temperature effect. That is, it is also possible that if the temperatures are
sufficiently high (near adiabatic) the equilibrium levels will increase as
shown by Sarofim in Figure 20, such that the driving function for the decay
reaction is less or even in the wrong direction. Thus, if the gas tempera-
tures are near adiabatic conditions, the NO levels may be subequilibrium
resulting in higher NO with additional preheat. Thus, although some preheat
may be desirable, very high temperature conditions could be undesirable.
3.10 SUMMARY
A summary of the major findings of this work is presented by major
test parameters in Table II. The results are categorized into low and medium
stoichiometric first stage. An indication is given for each test parameter
whether it has a major, moderate or minor effect on NO and the preferred
value or direction for that parameter. A brief reiteration of the findings
are discussed below for each test parameter:
t Stoichiometry - First stage
NO is a strong function of Stoichiometry with a minimum occuring
at an SR of 0.75 to 0.85. This minimum SR is also a function of
residence time with the minimum SR point decreasing with decreas-
ing residence time.
• Excess air
Following the fuel rich regime, the amount of excess air does not
affect the NO levels except at SRs below 0.75. This implies
second stage NO is formed very rapidly with a minimum of excess air.
Excess air does affect CO and carbon burnout. A minimum of 15
percent is required if the second stage residence time is about
1 second.
* Burner mixing
The effect of burner mixing under the configurations tested
(spreader versus axial nozzle and tangential) showed that burner
161
-------
mixing became less important as the stoichiometric ratio decreased.
Below a stoichiometry of 0.8, no difference in the NO levels was
observed.
Stage separation
It was observed taht backmixing into the first stage from the
second stage increased the NO levels. The method of stage air
mixing had no effect on the total NO levels unless it influenced
the first stage stoichiometry. Good stage separation is recom-
mended.
First stage residence time
Hot sampling and residence time studies revealed that the NO levels
reach a peak early in the flame history and decay with residence
time under fuel-rich conditions. The peak is dependent on the
stoichiometric ratio of the first stage and the decay rate may be
proportional to the temperature level. Using conventional staging
technology, it takes 3 to 3.5 seconds to get to 100 ppm at a
stoichiometric ratio of 0.75 to 0.85. Lower stoichiometric ratios
result in the generation of second stage NO, probably from XNs
formed in the first stage.
Combustbr air preheat and heat release rate
It appears that increased temperature in the first stage either by
increasing combustion air preheat or heat release rate increases
the decay rate of NO in a fuel rich environment. This effect was
much more noticeable with increased heat release rate than with
air preheat. The higher heat release rate produced similar NO
levels but at shorter residence times than the lower heat release
rate. Theoretical considerations indicate though that there may
be a limit to this effect as the temperatures approach adiabatic
levels. At adiabatic conditions, the equilibrium levels, even
under fuel rich conditions, are on the order of 1000 ppm.
162
-------
Second stage residence time
No effect of second stage residence time on NO was observed. This
evidence together with the lack of effect of excess air (fuel-rich
in the first stage) and second stage mixing technique indicated
that second stage NO when it is formed (at SR <_ 0.75) is formed
very rapidly. At least 1 second at 15-percent excess air is needed
for CO and carbon burnout.
163
-------
SECTION 4
DISCUSSION AND PRACTICAL IMPLICATIONS
Perhaps the most significant concept that has come out of this study
is that one technique of achieving low NO emission is through an optimum low
stoichiometric ratio held for sufficiently long residence times to allow for
NO and XN decay. Although it is realized that this concept may not be prac-
tical for retrofit of existing boilers, it may be applicable to new boiler
design where there is more freedom to consider radical design alternatives.
The principle problem of using this design concept even for new boilers
will be in finding materials to withstand the reducing, sulfer-laden high
temperature atmosphere. Slagging and corrosion from the ash are also likely
to be significant problem areas. Assuming for the moment that these problems
can be solved at reasonable cost, the boiler would have the following general
specifications:
• First stage stoichiometry of 0.75 to 0.85
• First stage residence time 3 to 3.5 seconds
t Combustion air preheat of 600°F or greater
• If possible, low heat absorption in the first stage
• Separation of the first and second stage through the use of a
baffle or overhang
• Rapid mixing of the second stage air, possibly at the baffle
• Second stage residence time of at least 1 second with 15 percent
, excess air
Figure 21 shows these general specifications applied to the design of
a 500 MW boiler in comparison to a conventional boiler. In this design, a
164
-------
first stage bulk residence time of about 3.5 seconds has been assumed at a
stoichiometric ratio of 0.75. A second stage residence time of 1.3 second
was chosen to the superheater tubes with an overall excess air of 15 percent.
This results in an overall height of 131 feet compared to 125 feet for the
conventional uncontrolled design where a 14,000 Btu/hr-ft3 heat release per
unit volume was assumed. This advanced design has about a 5 percent increase
in side wall area. For a new unit, this increase in area would probably not
represent a significant cost increase to the power plant. However, with
2/3 of the boiler operating in a fuel rich environment, expensive exotic
materials and more sophisticated control and flame safeguard equipment may
be required. This new design should be able to achieve NO emission as low
as 100 ppm. Considerably shorter periods in the fuel rich zone would result
in slightly higher NO levels and less surface area would be exposed to the
fuel rich atmosphere. The desired NO level will, therefore, dictate how much
volume will be needed in the fuel rich zone as illustrated in the design
curves, Figures 13 to 15 in Section 3.
If a low stoichiometric ratio cannot be achieved, such as in retrofit-
ting an existing boiler, then the design will change slightly.
If a first stage equivalence ratio of 0.95 to 1.0 is selected, the
first stage mixing becomes important. It is desirable in this case to select
delayed mixed burners which produce an axial flame. Also, under these con-
ditions low preheat or low combustion intensity is desirable as seen in
Figure 19 for the tangential configuration. Introduction of the stage air
should be delayed again as long as practically possible, while maintaining CO
and carbon burnout. That is, the stage air ports should again be as far as
possible from the burners. In addition, some mechanism should be employed to
prevent backmixing into the first stage whether it be the injection technique
or an overhang or baffle. Rapid mixing of the second stage air is desirable
to enable burnout of CO and carbon.
In summary, then, considerable data have been presented outlining the
effects of first and second stage parameters on NO emissions for both front
wall-fired and tangential configurations. And it has been shown how these
data may be applied to the practical design of a new boiler or to the retrofit
of existing hardware.
165
-------
However, it appears that achieving low NO emission (100 to 200 ppm) in
relatively short residence times (1 to 2 seconds) and at stoichiometric
ratios j»0.95 is not feasible with conventional staging technology. It will
probably be necessary to combine staging with a delayed mix burner design to
achieve these low levels.
In order to gain a better understanding of the formation and fate of
NO under staged conditions, additional hot sampling in the fuel-rich first
stage is needed. Not only should NO be mapped, but the time history of the
intermediary compounds (NH3, HCN, etc.) should be determined. If it is
feasible to obtain this data then it should provide a clearer understanding
of the role of each of these compounds and the fate of NO, and may provide
some insight into the proper times and methods for fuel air mixing.
In addition to the above, the materials under the reducing conditions in
the first stage over long periods of time needs investigation to insure that
this staging concept is indeed a viable technology.
166
-------
REFERENCES
1. "Control Techniques for Nitrogen Oxide Emissions from Stationary
Sources," Draft second edition of AP-67 prepared by Aerotherm Division
of Acurex Corporation for the Office of Air Quality Planning and Stan-
dards.
2. Federal Register, 36 FR 24877, December 23, 1971.
3. Copeland, J. D., "An Investigation of the Best System of Emission Reduc-
tion for Nitrogen Oxides from Large Coal-Fired Steam Generators," Stan-
dards Support and Environmental Impact Statement, Office of Air Quality
Planning and Standards, October 1976.
4. "Standard Support and Environmental Impact Statement for Standards of
Performance: Lignite-Fixed Steam Generators," (Draft), A. D. Little,
Incorporated, EPA, March 1975.
5. Environment Reporter, State Air Laws (2V.) Bureau of National Affairs,
Incorporated, Washington, D.C.
6. Crenshaw, J. and A. Basala, "Analysis of Control Strategies to Attain
the National Ambient Air Quality Standard for Nitrogen Dioxide." Pre-
sented at the Washington Operation Research Council's Third Cost Effec-
tiveness Seminar, Gaithersburg, MD, March 18-19, 1974.
7. "Air Quality, Noise and Health - Report of a Panel of the Interagency
Task Force on Motor Vehicle Goals Beyond 1980." Department of Transpor-
tation, March, 1976.
8. McCutchen, G. D., "NOX Emission Trends and Federal Regulation," pre-
sented at AIChE 69th Annual Meeting, Chicago, November 28-December 2,
1976.
9. "Air Program Strategy for Attainment and Maintenance of Ambient Air
Quality Standards and Control of Other Pollutants," Draft Report, U.S.
EPA, Washington, D.C., October 8, 1976.
10. Lachapelle, D. G., et a!., "Overview of Environmental Protection Agency's
NOx Control Technology for Stationary sources." Presented at b/tn Annual
Meeting, AIChE, December 4, 1974.
167
-------
11. Martin, G. 8. and J. S. Bowen, "Development of Combustion Modification
Technology for Stationary Source NOX Control," EPA-600/7-76-002, 1975,
February, 1976.
12. Brown, R. A., et al., "Pilot Scale Investigation of Combustion Modifica-
tion Techniques for NOx Control in Industrial and Utility Boilers," In
Proceedings of the Stationary Source Combustion Symposium, Volume II,
EPA-600/2-76-1526, June, 1976.
13. Brown, R. A., et al., "Investigation of First and Second Stage Variables
on Control of NOx Emissions in a Pulverized Coal Furnace," presented at
83rd National Meeting AIChE, March 24, 1977.
14. Armento, W. J., "Effects of Design and Operating Variables on NOX from
Coal Fired Furnaces -Phase II," EPA-650/2-74-002-b, February, 1975.
15. McCann, C., et al., "Combustion Control of Pollutants from Multiburner
Coal-Fired Systems," U.S. Bureau of Mines, EPA-650/2-74-038, May 1974.
16. Pershing, D. W. and J. 0. L. Wendt, "Pulverized Coal Combustion: The
Influence of Flame Temperatures and Coal Composition on Thermal and
Fuel N0x»" presented at the Sixteenth Symposium (International) on Com-
bustion, M.I.T., August 15, 1976.
17. Crawford, A. R., et al., "The Effect of Combustion Modification on Pol-
lutants and Equipment Performance of Power Generation Equipment," Exxon
Research and Engineering Co., EPA-600/2-76-152c, prepared for the Sta-
tionary Source Combustion Symposium, September 24-26, 1975.
18. Selker, A. P., "Program for Reduction of NOX from Tangential Coal-Fired
Boilers, Phase II and Ha," EPA 650/2-73-005a and b, June 1975.
19. Martin, G. B., and E. E. Berkau, "An Investigation of the Conversion of
Various Fuel Nitrogen Compounds to Nitrogen Oxides in Oil Combustion,"
presented at 70th National AIChE Meeting, Atlantic City, N.J., August,
1971.
20. Pershing, D. W. and J. 0. L. Wendt, "The Effect of Coal Combustion on
Thermal and Fuel NOx Production from Pulverized Coal Combustion," pre-
sented at Central States Section, The Combustion Institute, Columbus,
Ohio, April 1976.
21. Thompson, R. E., et al., "Effectiveness of Gas Recirculation and Staged
Combustion in Reducing NOX on a 560.
i
22. Pershing, D. W., et al., "Influence of Design Variables on the Production
of Thermal and Fuel NO from Residual Oil and Coal Combustion," AIChE
Symposium Series, No. 148, Vol. 71, 1975, pp. 19-29.
23. Hardgrove, R. M., "Method for Burning Fuel," U.S. Patent 3,048,131,
August 7, 1962.
168
-------
24. Axworthy, A. E., et al., "Chemical Reactions in the Conversion of Fuel
Nitrogen to NOX," in proceedings of the Stationary Source Combustion
Symposium. Volume I. EPA 600/2-76-152a, June 1976.
25. Yamagishi, K., et al., "A Study of NOX Emission Characteristics in Two
Stage Combustion," Fifteenth Symposium (International) on Combustion,
The Combustion Institute, p. 1156, 1974.
26. Pohl, J. H. and A. F. Sarofim, "Devolatilization and Oxidation of Coal
Nitrogen," presented at 16th International Symposium on Combustion,
M.I.T., August 1976.
27. Fenimore, C. P., "Formation of Fuel Nitrogen in Ethylene Flames," Com-
bustion and Flame, Vol. 19, p. 289, 1972.
28. Sarofim, A. F,, et al., "Mechanisms and Kinetics of NOX Formation:
Recent Developments," presented at 69th Annual Meeting, AIChE, Chicago,
November 30, 1976.
29. Heap, M. P., et al., "Burner Criteria for NOX Control -Volume I. Influ-
ence of Burner Variables on NOX in Pulverized Coal Flames," EPA-600/2-
76-061 a, March 1976.
30. Heap, M. P., et al., "The Optimization of Burner Design Parameters to
Control NOX Formation in Pulverized Coal and Heavy Oil Flames," in
Proceedings of the Stationary SourceCombustion Symposium, Volume II,
EPA 600/2-76-152b, June 1976.
31. Pohl, J. H. and A. F. Sarofim, "Fate of Coal Nitrogen During Pyrolysis
and Oxidation," in Proceedings of the Stationary Source Combustion
Symposium, Volume I. Fundamental Research, EPA 600/2-76-152a. June 1976.
32. Heap, M. P., et al., "The Control of Pollutant Emissions from Package
Boilers," ASME paper 75-WA/F4-4, December 4, 1975.
33. Siegmund, C. W. and D. W. Turner, "NQX Emissions from Industrial Boilers:
Potential Control Methods," ASME Journal of Engineering for Power, p. 1,
January 1974.
34. Cato, G. A., et al., "Field Testing: Application of Combustion Modifi-
cation to Control Pollutant Emissions from Industrial Boilers — Phase 2,"
KVB Engineering, Environmental Protection Technology Series, EPA 600/
2-76-086a, April 1976.
169
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TABLE I. PULVERIZED COAL COMPOSITIONS
Ultimate Analysis
(%, Dry)
C
H
N
S
0
Ash
Heating Value
(Btu/lb, Wet)
Proximate Analysis
(%, Wet)
Volatile
Fixed Carbon
Mositure
Ash
Rationale
for Selection
Pittsburgh
#8
77.2
5.2
1.19
2.6
5.9
7.9
13,700
37.0
54.0
1.2
7.8
• Most important gen-
eral class of U.S.
steam raising coals
• Highest quality U.S.
steam coals
• Standard against
which others are
usual ly compared
• Wide distribution
• Expanded production
• likely
Western
Kentucky
73.0
5.0
1.40
3.1
9.3
8.2
12,450
36.1
51.2
4.8
7.8
• Extensively used
for steam genera-
tion in Ohio and
Mississippi Val-
ley areas
• Good quality steam
coal
• Wide distribution
• Some publ ished Esso
full-scale data for
comparison
Montana- Powder
River Region
67.2
4.4
1.10
0.9
14.0
11.7
8,900
30.5
39.0
21.2
9.2
t Current local
importance; future
national signifi-
cance
• "Typical" Western
subbmituminous in
abundant supply
en
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500 MW -» 4.376 x 109 Btu/hr
13T
90'
Staged air
* 50'D
Staged
SR. = 0.75
EA =15 percent
T-J ^3.5 seconds
T =1.3 seconds
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Conventional
HR = 14000 Btu/hr-ft3
EA = 15 percent
Figure 21. Candidate advanced staging design compared to conventional
192
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DESIGN CRITERIA FOR STATIONARY SOURCE
CATALYTIC COMBUSTORS
By:
J. P. Kesselring, W. V. Krill, R. M. Kendall
Acurex Corporation/Aerotherm Division
Mountain View, CA 94042
193
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ABSTRACT
The use of catalysts in place of conventional burners for promoting
hydrocarbon oxidation reactions appears to have advantages in the control
of emissions. In addition, it is possible to achieve high system efficiency
through appropriate system design, while holding the catalyst bed tempera-
ture to its operating limit. The objective of this program is to produce a
new combustion system capable of extremely low emissions performance at the
highest system efficiency achievable.
Design criteria for catalytic combustors include information on the
catalyst/washcoat/substrate, the catalyst life, the preheat requirement for
combustion air, and the maximum flow velocity and bed temperature that can
be achieved in the system. Based on the results of an extensive catalyst
screening program, an extremely active and durable catalyst system has been
developed. The system, called the graded cell catalyst, incorporates three
1-inch long sections of alumina with warying cell diameters in a 3-inch bed.
The catalyst used was platinum with a loading varying from 5 percent to
1.7 percent by weight. This system was tested at bed temperatures between
2,000°F and 2,700°F with four fuels (natural gas, propane, indolene, and
methanol) under both rich and lean combustion conditions for a total test
time of nearly 80 hours. Excellent performance was obtained throughout the
test period; typical emissions at 217 percent theoretical air and space
velocity of 97,600 ft3hr/ft3 are 17 ppm CO, 10 ppm UHC, and 2 ppm NO . The
graded cell catalyst system is now being incorporated into several combus-
tion system designs.
195
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INTRODUCTION
Using catalysts in place of conventional burners to promote hydro-
carbon oxidation reactions appears to help control emissions. The operating
conditions of these catalytic coinbustors are limited by the catalyst bed tem-
perature capability. The temperature obtained with normal one-stage, low-
excess air operation (necessary for efficiency reasons) is above the tempera-
ture capability of current catalyst systems. Even if catalyst materials
could withstand these temperatures, excessive NO emissions would be expected.
A
It is therefore necessary to consider system techniques such as bed cooling,
exhaust gas recirculation, or staged combustion to hold the bed temperature
down. Appropriate system design will produce the two principle benefits of
catalytic combustion: reduced emissions and increased system efficiency.
In this paper we describe the research and development program to es-
tablish catalyst and combustion system design criteria for the application of
catalytic combustors to low emission, high efficiency stationary combustion
systems. This program reviews available catalyst materials and ongoing re-
search programs, and develops a basic understanding of the operation of cata-
lytic combustion systems, small-scale catalyst screening experiments, and sys-
tem concept tests. Based on these results, scale-up of the catalyst and
catalytic combustion system will be accomplished. Prototype hardware designs
utilizing catalytic combustors will be based on the design criteria established
in this program.
AVAILABLE CATALYST MATERIALS
The materials considered for a catalytic combustion system are those
associated with the support, the washcoat, and the catalyst itself. The im-
portance of each of these elements in the system is described below.
197
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Support Materials
The catalytic support serves two important functions in a catalyst
system:
• It increases surface area of the active metal or metal oxide by
providing a matrix that stabilizes the formation of very small
particles
• It increases thermal stability of these very small particles, thus
preventing agglomeration and sintering with consequent loss of
active surface area.
Monolith supports were developed for catalysts to provide a high geometrical
surface area and a low pressure drop during operation. Monolithic supports
are composed of small parallel channels of a variety of shapes and sizes.
These structures may be in the form of honeycomb ceramics extruded in one
piece, oxidized aluminum alloys in rigid cellular configurations, or multi-
layered ceramic corrugations. The channels in honeycomb-like structures have
tubular diameters from 1 to 7 mm. Materials of fabrication are usually low
surface area ceramics such as alumina (Al_0_), mullite (3A190 • 2SiO ), or
^- -J £* J . £
cordierite (2MgO • 5SiO • 2A120 ). The refractory monolith is produced
with macropores (1 — lOu), and may be coated with thin layers of washcoat and/
or catalytic materials. Figure 1 shows square-celled extruded monolith struc-
tures produced by Corning Glass Works.
Washcoat Materials
For conventional catalytic applications, the low surface area of the
monolith structure requires the application of a thin oxide washcoat such
as Al-0~. This washcoat, which strongly adheres to the ceramic or refractory
support, provides a uniform high surface area while still insuring that the
catalytic material subsequently impregnated on the washcoat is close to the
imain flow of reactants.
: Under the high temperature (1100°C — 1500°C) conditions associated with
'catalytic combustors, a significant loss in washcoat surface area is
This loss in surface area results in pore closure, and can bury active
198
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catalytic sites. To minimize this problem, it is possible to work with cata-
lysts which are deposited on presintered Al_0 . Alternatively, more thermally
resistant washcoats, such as ZrO? or ThO , can be investigated. Finally, it
may be possible to use no washcoat, if catalytic activity can be maintained
when the catalyst is deposited directly on the monolith.
Catalyst Materials
Two broad classes of catalyst materials are available: metals and
metal oxides. The metals of catalytic interest are listed in Table 1. Of
these metals, the only ones which will remain in the metallic state in a high-
temperature oxidizing environment are the noble metals; the others readily
form oxides. Of the noble metals, a large volume of data and correlations are
available for platinum and palladium at temperatures below 1000°C because of
their use as automotive oxidation catalysts. They are among the most active
catalysts for the oxidation of a number of fuels, including methane, methanol,
and hydrogen. Palladium and platinum are readily prepared in a highly dis-
persed form on support materials. The use of the other noble metals is re-
stricted to small quantities in multimetallic systems.
There has been much research on the catalytic properties of nonnoble
metal oxides. As for noble metals, it has been found that the activity for
hydrocarbon oxidation is increased at high-temperature operation. The most
active single oxides are Co 0, , MnO , NiO, CuO, Co?0 , Fe_0_, and V 0 . SiO
and
^
have also been shown to have good activity at high temperature.
Multicomponent metal oxides are also of interest.
The choice of an optimum catalyst/washcoat/support combination requires
a consideration of the system's temperature capability. The low temperature
limit is dictated by the lightoff temperature. Noble metal catalysts generally
exhibit good lightoff characteristics for most fuels of interest, and would
therefore be included in the lightoff system.
The major limitation for catalytic combustion is the high temperature
of operation. Loss of catalytic activity through sustained operation at high
temperature will occur with all catalysts, but this activity degradation should
decay with time until a steady-state catalytic activity is reached. The support
material is chosen to minimize thermal expansion problems at high temperatures,
and to provide a high use temperature.
199
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FUNDAMENTALS OF OPERATION
Catalytic combustion in a monolith bed is a complex interaction of
chemical reactions (surface and gas phase), diffusive heat and mass transport
(laminar or turbulent), convection, bed conduction, and radiation. These
phenomena are depicted schematically in Figure 2. During steady operation,
this process can best be described as follows:
• Premixed fuel and air are introduced into the combustor
• These gases diffuse to the surface of the combustor and react
on the active sites at and within the surface
• Heat is generated and transferred by conduction, radiation, and con-
vection. Part of this heat will be transferred to the main flow of
gases and thermally support gas phase reactions.
• Surface reaction products diffuse back to the main flow of gases
and are carried downstream
If the heat release rate due to reaction at the surface is sufficiently
great compared to convective, conductive and radiative heat losses, then the
catalyst bed will operate in the "hot" mode. This type of operation gives
significant fuel conversion whose magnitude is primarily controlled by mass
transfer to the surface. However, if the surface reaction heat release is
less than the heat losses, little temperature rise and fuel conversion is
noted and the bed is said to be in a "blowout" condition. It is very important
to know when this blowout condition occurs for a given catalyst system.
The overall fuel conversion within the catalyst bed is also very impor-
tant. It is vital that sufficient residence time be given to the fuel/air
mixture to allow diffusion and nearly complete reaction at the catalyst surface.
This can usually be achieved by lengthening the catalyst bed or by decreasing
the space velocity of the mixture. Gas phase reactions also contribute to the
fuel conversion efficiency. These gas phase reactions are most efficient at
high gas phase temperatures.
200
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Graphical Determination of Stable Surface Combustion States
For the purpose of understanding system characteristics, considerable
simplification of the catalytic combustion process can be made if it is assumed
that:
• No conductive or radiative heat transfer occurs
• The Lewis number is unity for all species
• The combustion reaction can be described by an Arrhenius law
equation
Once these assumptions are made, it is possible to perform a simple mass
balance on the lean reactant at the wall of the monolith bed; that is, the mass
of lean reactant transported to the wall is equal to the mass of lean reactant
consumed at the wall. In equation form this can be written as
A - NU £ W, - V - AKT^B
where m = mass of lean reactant transported to and consumed at the wall, per
unit area
Nu ~ Nusselt number for mass transfer (Sherwood number)
p = gas density
V = diffusion coefficient
D = diameter of one channel of monolith bed
K_ = mass fraction of lean reactant at boundary layer edge
iL, = mass fraction of lean reactant at monolith wall
A = preexponential factor
AE = activation energy
R = universal gas constant
temperature at monolith wall*
Based on the first two assumptions, this temperature can be related to the
residual concentration of lean reactant at the surface,
201
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Each of these expressions for the mass flux can be shown graphically
by plotting the mass flux vs. the mass fraction of lean reactant at the mono-
lith wall (i.e., plot m vs. K,,). This is shown in Figure 3.
By combining the two curves on a single graph, solutions to the prob-
lem may be identified as intersections of the two curves. The blowout con-
dition may also be identified from this graphical solution.
The Graded Cell Concept
As shown in Figure 4, there are generally three solutions that can exist;
a hot stable solution, an unstable solution, and a cold stable solution. The
blowout point can be considered as that value of m where the hot stable solu-
tion and the unstable solution coincide; any increase in mass throughput above
this value will cause the combustion reaction to be extinguished, i.e., the
reaction is "blown out." A large value of m at blowout is desirable; it allows
the monolith bed to operate at a large value of volumetric heat release rate,
thereby minimizing the combustion volume required. As shown in Figure 4, to
avoid blowout the intercept NuCpP/D)!^ should be low. For a given surface
activity of the monolith, blowout can therefore be avoided by:
• Using large diameter cells in the bed
» Operating at a high value of boundary layer edge temperature
• Operating at a small value of Nusselt number
The simplest of these to implement is the use of large diameter cells. These
large cells operate at a low transfer coefficient and should be effective for
•both lightoff and sustained operation.
'• However, using large cells throughout the bed would result in poor con-
version of combustibles to products. The amount of conversion is directly
related to the number of transfer units in the bed, where the length of each
transfer unit is equal to Pr • Re/4 Nu • D,
'where Pr = Prandtl number
Re = Reynolds number
!
, Nu = Nusselt number
1 D = cell diameter
202
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Thus, to get complete conversion, it is necessary to have many transfer units
available by minimizing the length of each transfer unit. This suggests use
of small diameter cells. The small cells will also accelerate homogeneous
reactions, which are helpful for full conversion.
As a consequence of these operational fundamentals, it appears that a
catalytic monolith bed used for the purpose of combustion should use large
diameter cells at the front of the bed to prevent blowout, and small diameter
cells at the back of the bed to maximize the number of transfer units in a
given length of bed. Therefore, for a given catalyst, it was postulated that
superior performance can be obtained by using that catalyst in a graded cell
configuration, with large cells at the front end, small cells at the back end,
and perhaps one or more intermediate sized cells between.
CATALYST SCREENING TEST PROGRAM
The initial series of combustion screening tests were conducted at the
Jet Propulsion Laboratory in Pasadena, California. The objective of these tests
was to evaluate the ability of a variety of catalyst/washcoat/support combina-
tions to combust both gaseous and liquid fuels. Suitable combustion catalysts
were identified based on the following characteristics:
• Low lightoff temperature
» Low preheat requirement for sustained operation
• Uniform catalyst bed temperature for a variety of test conditions
• High heat release capability
• Low pollutant potential
• High operational temperature capability
• Operation with both gaseous and liquid fuels
• Sufficient life for testing purposes
The initial screening tests identified catalyst properties which are important
to each of these combustion characteristics. These tests utilized single-
component supports that were 9.3 cm in diameter and 7.6 cm in length.
203
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A screening test matrix was developed to compare monolith material,
monolith cell size, washcoat material, washcoat application technique, cata-
lyst, catalyst loading, and catalyst preparation technique. The primary test
fuel used for this matrix was natural gas, with propane serving as a secondary
test fuel. Table 2 gives a summary of the materials tested during the screen-
ing program.
Prior to combustion testing, all catalysts were characterized in a
high vacuum gas adsorption system in terms of total and selected (precious
metal dispersion) surface area. The catalyst characterization system is shown
in Figure 5. The system consists of three major components: (1) the pumping
and vacuum control system, (2) the gas delivery, storage, and cleaning system,
and (3) the working volume and characterization cells. Catalyst total surface
area is determined by the BET gas adsorption procedure.
Following surface characterization, the catalysts were instrumented
with in-depth thermocouples placed within monolith cells, as shown in Figure 6.
Cells containing thermocouples were blocked off so the thermocouple would read
ceramic surface temperature. Catalysts were then placed in a quartz reactor,
as shown in Figure 7, and tested at JPL. The test procedure involved establish-
ing initial lightoff temperature, operating the catalyst at minimum required
preheat for flow conditions between 50 and 300 percent theoretical air, re-
peating data points periodically to check for catalyst degradation, and record-
ing lightoff temperature as a function of time. Diluent nitrogen was introduced
•to maintain bed temperature constant at 1100°C. Data for test model JPL-010X,
a platinum/alumina/cordierite catalyst system, are given in Table 3 and Figure 8.
As shown in Figure 8, the catalyst lightoff temperature increased from
330°C to 470°C after 10 hours of operation at a bed temperature of 1100°C. In
addition, after 8 hours of testing, the preheat required at 150 percent theoreti-
cal air to sustain combustion reactions in the bed had increased from 50°C to
410°C. The increase in both lightoff and required preheat temperature indicates
a significant decrease in catalyst activity. Further, from Table 3, a decrease
in total surface area by a factor of twenty and a loss in platinum surface
area to nearly zero shows significant sintering of both washcoat and catalyst.
204
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To overcome performance degradation with time, higher catalyst loadings
were used. These high loadings gave much higher catalytic-activity after opera-
tion at high temperatures, allowing good performance even in the "degraded"
state.
Based upon the results obtained from the screening test matrix, direction
was gained to develop a catalytic combustion system with good combustion charac-
teristics. Results from the screening tests showed that:
• Most catalysts tested had good initial activity, as compared to
their activity after testing
• Degradation occurred rapidly at high temperature operation, resulting
in higher required preheat to prevent blowout at a given value of
theoretical air and fuel flowrate
• Increasing platinum loading gave significantly greater activity,
even after high temperature operation
• Stabilizing the platinum by exposure to hydrogen sulfide during
preparation gave improved performance
• Using presintered Y~alumina or a-alumina washcoats improved performance
• Alumina monoliths survived high temperature (1500°C) operation with
minimal thermal shock
• Large diameter cells passed many unburned hydrocarbons but could
not be blown out at the facility flowrate limits
• Small diameter cells provided excellent cleanup of CO and UHC
GRADED CELL CATALYST DEVELOPMENT
The graded cell catalyst was developed by combining the basic understand-
ing of catalyst-coated monolith operation with the results of the initial
screening tests. It combines features which result in high throughput capabil-
ity without blowing out, and has consistent lightoff temperature, low emissions,
and long life. The graded cell catalyst consists of three 2.5 cm long segments
of ceramic with varying cell diameters. The largest cells are placed in the
205
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front of the bed to initiate surface reactions, intermediate cells in the center
of the bed allow gas phase reactions to begin, and small cells at the back end
perform cleanup of CO and UHC to extremely low levels. A photograph of a graded
cell catalyst (Model 019) is shown in Figure 9. Table 4 summarizes the composi-
tion of Model 019.
Model 019 was initially tested at JPL in the 1-atmosphere quartz reac-
tor. Natural gas, indolene, propane, and methanol fuels were tested under lean
conditions at bed temperatures of 1100°C, followed by tests with natural gas
and propane at 1320°C. This testing was quite successful; the catalyst was
operated at the maximum flow capacity of the JPL system throughout the 50-hour
test period. Table 5 summarizes data from the multifuel tests.
Following the multifuel tests, pressure and simulated fuel nitrogen
conversion tests were run in the Aerotherm test facility shown in Figure 10.
This facility can operate at up to 10 atmospheres pressure and 917 m3/hr airflow.
Combustion tests up to 6 atmospheres pressure were run successfully. Ammonia
dopant was added to the methane fuel to simulate fuel nitrogen compounds, and
tests run at 1100°C and 1320°C bed temperature to examine the conversion of
ammonia to nitrogen oxide under both fuel-rich and fuel-lean conditions. On
the rich side, most NH,, was passed directly through the combustor unchanged.
At 200 percent theoretical air, however, it was noted that increasing pressure
through the bed (while maintaining flowrate constant) resulted in an increase
in NH conversion to NO from 25 percent to 70 percent of the dopant. This is
j X
attributed to a change in the dominant oxidation reactions from surface to gas
phase at the lower pressure. Thus, a combustor which maximizes surface reactions
may be capable of controlling the conversion of fuel-bound nitrogen to nitrogen
oxides.
Test Model 019 was also operated with natural gas fuel to a maximum bed
temperature of 1490°C. The catalyst performed well throughout the 78 hours of
testing. Post-test analysis showed the catalyst had no measurable surface area
or platinum dispersion, but identifiable platinum was found on the front segment
using the scanning electron microscope and X-ray diffraction. Platinum on the
back segment had agglomerated into large particles at the exit end of the secvu
206
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Lightoff temperature for this catalyst was very consistent at 455°C under fuel-
rich conditions.
Additional graded cell catalysts are now being tested. W. R. Grace and
Co. prepared a platinum/iridium catalyst which was tested at 1320°C and 1480°C
bed temperatures. This catalyst was tested with natural gas fuel at 1 atmos-
phere pressure for a 20-hour period. Blowout tests demonstrated the catalysts'
ability to accept high mass flowrate; a maximum volumetric heat release rate
of 6.07 x 105 joules/hr-cm3 was achieved at 1480°C bed temperature and 400°C
preheat temperature. Again, post-test analysis showed no measurable surface
area or precious metal dispersion.
Based upon the testing conducted to date, the graded cell catalyst sys-
tem shows promise for operation at high bed temperatures for significant lengths
of time. It appears suitable for the combustion of natural gas, propane, meth-
anol, and indolene (distillate oil) with low emissions and high combustion
efficiency. Limited data indicate that under certain operating conditions,
the graded cell catalyst may help in controlling the conversion of bound nitro-
gen to nitrogen oxide. Testing of this system will be continued.
SYSTEM CONCEPTS
For most stationary source combustion systems, high system efficiency
can only be achieved by operating at stoichiometric conditions. In order to
hold temperatures below the allowable maximum for the catalyst, and to minimize
the formation of nitrogen oxides through gas phase oxidation reactions, it is
necessary to devise a system that minimizes operating temperatures and still
provides highly efficient combustion with low emissions. Such systems as
staged combustors or exhaust gas recirculation systems are complicated and
somewhat expensive. The most effective method of heat removal from a catalytic
combustor is by radiation, and the system described here is termed the radiative
catalytic/watertube system.
Radiative Catalytic/Watertube System
The radiative catalytic/watertube system was disigned to operate at
stoichiometric conditions without exceeding the maximum operating temperature
of the catalyst. A schematic of the system concept is shown in Figure 11.
A stoichiometric fuel/air mixture enters the radiative section, where
207
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catalyst-coated cylinders are surrounded by watertubes. Reactions will begin
at the surface of the catalytic cylinders, and as the cylinder temperature
increases, it will begin to radiate energy to the watertubes. Some of the
fuel will pass entirely through the bed unchanged; the degree of combustion
in the radiative section is dependent on the number of transfer units in the
bed. The partially-combusted gases are then mixed to provide a uniform mix-
ture before they enter a graded cell catalyst adiabatic combustion section,
and final heat removal is achieved in a downstream convective section before
exhausting to the stack. This concept thus provides for "staged".combustion
with no necessity of adding additional fuel or air downstream.
The radiative section was designed, constructed, and tested with natural
gas at Aerotherm. System pressure was 1 atmosphere, and data were taken to
establish the effects of changes in load on radiant heat extraction, the mini-
mum preheat required for operation, and the gas composition at the exit of
the radiative section. The test apparatus is shown in Figure 12. The catalyst
used was platinum on alumina-washcoated alumina cylinders.
Figure fa compares the heat removed in the radiative section with the
total energy available for different fuel flowrates. The system was designed
to operate at a fuel flowrate of 4.3 kg/hr, to combust 40 percent of the fuel
entering and to remove 30 percent of the total available energy by the water-
tubes. At the design condition, the amount of combustion was measured as
41.8 percent, with 25-percent energy removal in the watertubes.
' Figure 14 shows the variation in catalyst surface temperature with
distance in the radiative section. Even with the adiabatic flame temperature
of the fuel/air mixture above 2000°C, the maximum surface temperature of the
cylinders was only 1044°C. By maintaining the catalyst surface at a low tem-
perature, catalyst life is significantly prolonged. No NO emissions existed
A
in the combustion gases. Typical emissions which would enter the graded cell
catalyst for total combustion include 17.4 percent CL, 1.5 percent CH,,
3000 ppm CO, and <0.2 percent CO-,.
The radiative catalytic/watertube system was successfully tested as a
viable concept for direct bed heat removal. Such a system has application in
commercial and industrial boilers, where low excess air is needed for high
208
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system efficiency. This concept will be further tested with the graded cell
monolith, to establish a stoichiometric combustion system with minimal NO
X
emissions.
SUHMARY
Significant progress has been made toward developing design criteria
for stationary source catalytic combustors. Both the graded cell catalyst
system and the radiative catalytic/watertube system have been tested and
appear effective in controlling NO emissions. These devices have potential
X
application in gas turbines and commercial and industrial boilers.
Further testing will be done with additional fuels and at higher catalyst
surface temperatures. The formation of NO under high temperature heterogeneous
X
combustion conditions is currently speculative, and needs to be examined.
209
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TABLE I. NOBLE METALS OF INTEREST FOR CATALYTIC COMBUSTION
Group VIII* Group IB1
Fe Co
Ru Rh
Os Ir
N± Cu
Pd
Pt
Ag
Au
*Enclosed metals are considered noble.
210
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TABLE II. SUMMARY OF MATERIALS TESTED IN SCREENING TESTS
Component
Variable.Tested
Monolith
Washcoat
Cell size
Cell shape
Catalyst
Platinum loading
Cordierite, mullite, alumina
y-Al 0 (two types), presintered y-AlJ) ,
stabilized Y-Al.,0 (two types), a-Al 0
7 nun, 5 ram, 3 mm, 1.5 mm
Hexagonal, circular, square
Platinum, platinum/palladium, oxide
0.3%, 0.7%, 1.5%, 2%,
211
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TABLE III. CHARACTERIZATION SUMMARY - TEST MODEL JPL-010X
Support: General Refractories cordierite, 31 circular cells
per square centimeter
Washcoat: Oxy-Catalyst 10 wt percent y-Al-0,
Catalyst: Aerotherm 0.75 wt percent platinum
Pretest characterization: Total (BET) surface area = 7.9 m2/g
Dispersion = 94.1%
Post-test characterization: Total (BET) surface area = 0.4 m2/g
Dispersion = 0.1%
212
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TABLE IV, GRADED CELL CATALYST MODEL 019 COMPOSITION
Support: Three segments of DuPont Alumina, cell sizes
7 mm, 5 mm, 3 mm, hexagonal cells
Washcoat: DuPont alumina AA
Catalyst: Aerotherm platinum
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STATUS OF FLUE GAS TREATMENT TECHNOLOGY FOR CONTROL OF NOX
AND SIMULTANEOUS CONTROL OF SOX AND NO*
By:
J. David Mobley and Richard D. Stern
Industrial Environmental Research Laboratory
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
229
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ABSTRACT
The status of flue gas treatment technology for control of NOX and
simultaneous control of NOX and SO applicable to stationary combustion
sources is presented. Dry processes and wet processes are described and
applications discussed with respect to performance, operating experience,
and economics.
As a result of a very stringent NOX ambient standard in Japan, the
Japanese NOX flue gas treatment technology appears to be the most advanced
in the world. For this reason, Japanese technology is emphasized in the
paper. EPA's past, current, and planned flue gas treatment program is also
discussed.
231
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INTRODUCTION
Nitrogen oxides (NOX) in the atmosphere have been determined to have
adverse effects on human health and welfare. To aid in preventing these
adverse effects, the Industrial Environmental Research Laboratory at Research
Triangle Park, N. C. (IERL-RTP) is leading the U.S. Environmental Protection
Agency's (EPA) efforts to develop and demonstrate NOX control technologies
for stationary combustion sources. There are two main technologies being
developed: combustion modification and flue gas treatment.
(CM) technology attempts
NOX during the combustion
Combustion modification
to minimize the formation of
process. CM techniques include staged combustion, low
excess air operation, flue gas recirculation, water in-
jection, and burner redesign. CM technology should be
able to reduce NOX emissions from stationary combustion
sources by 50% or more in a relatively cost effective manner.
CM technology will not be discussed in this paper; however,
additional information is available from other sources.
Flue gas treatment (FGT) technology attempts to
remove NOX from the gaseous products of combustion.
FGT techniques include dry selective catalytic reduction
processes and wet scrubbing processes. FGT technology
should be able to reduce NOX emissions by 90% and has
the potential for
emissions.
control of both NOX and SOX
NOX FGT research and development programs have received a relatively
low level of funding by EPA since it has not been determined conclusively
that high NOX removal efficiencies will be required to achieve and main-
tain the current National Ambient Air Quality Standards (NAAQS). However,
there are significant uncertainties which may affect the required level of
NOX control. Due to these uncertainties, EPA is proceeding with small scale
NOX FGT experimental projects in parallel with control strategy and technolog;
assessment studies. One phase of the assessment is an evaluation of
Japanese FGT technology which has progressed to the point of being commer-
cially applied to gas- and oil-fired sources. In addition, the Japanese are
developing processes for application to flue gas from coal-fired sources.
EPA is investigating the Japanese and other worldwide technologies for poten-
tial application to the U.S. coal-fired situation to save both development
time and money. Through these actions, the basic foundation will be estab-
lished if the technology is required in the United States and acceleration
of the development program becomes necessary.
233
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FLUE GAS TREATMENT PROCESSES
There are two main categories of flue gas treatment QFGTi processes for
the control of NO^ and the simultaneous control of NQx and SOX emissions from
stationary combustion sources; dry processes and wet processes. A descrip-
tion of the most promising processes in each, category and their developmental
status in Japan is discussed below.
DRY PROCESSES
The following dry process types are being developed:
Selective catalytic reduction
Selective noncatalytic reduction
Adsorption
Nonselective catalytic reduction
Catalytic decomposition
Electron beam radiation
Of these, only selective catalytic reduction CSCR) has achieved notable
success in treating combustion flue gas for removal of NO^. and has progressed
to the point of being commercially applied. The other process types are much
less attractive at this time. Selective noncatalytic reduction processes do
not achieve high NOX removal efficiences and adsorption processes are not
applicable to combustion sources. Nonselective catalytic reduction, catalytic
decomposition, and electron beam radiation processes are at a very low level
of development. These process types will not be discussed in this paper, but
additional information is available from other sources.2»3,4,5
Dry NO.,,. Processes
Selective catalytic reduction processes are based on the preference
of ammonia (N!^) for NOX over other flue gas constituents. Since the oxygen
enhances the reduction, the reactions can best be expressed as:
4NH
3 + 4NO + 02
4NH
2N0
02
catalyst
catalyst
3N
6H20
6H20
CD
(2)
234
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Reaction (1) predominates since approximately 90-95% of the NOX in
combustion flue gas is in the form of NO. Since 1 mole of NHj is required
per mole of NO, most processes operate with an NH3/NO mole ratio of 0.9 to 1.1.
The reaction temperature is usually in the range of 300 to 450°C, but space
velocities vary considerably depending on the process. Under these operating
conditions, NOX removal efficiencies of 90% or greater are typical.4
The catalysts used in SCR processes vary with process developer. How-
ever, there are some general traits known about the catalysts. The catalyst
carrier or substrate is usually alumina, silica, or titanium dioxide. Alumina
is satisfactory for application to flue gases without SOX such as from natural
gas firing. However, alumina tends to react with SOX, particularly 803, to
form aluminum sulfate. This "poisons" the catalyst by decreasing the avail-
able surface area and the catalyst activity. Titanium dioxide and silica are
less susceptible to attack by 803 and are applicable to flue gas from heavy
oil or coal firing. The active metal on the substrate may include Co, Cr, Cu,
Fe, Mn, Ni, Pt, and V or combinations thereof, but the exact composition of
the catalyst is usually proprietary. These metals or their oxides can also
react with the SOX to form sulfates. Many of these sulfates are also cataly-
tic in the reduction of NO with NH3, and therefore, can be tolerated. The
catalysts are normally designed to have a life of at least 1
The formation of ammonium sulfate and bisulfate is a major concern with
SCR processes. Ammonium bisulfate will form downstream of the reactor if NH3
and 503 are present in sufficient quantities and if the gas temperature drops
sufficiently. It is very difficult to avoid the conditions for formation; for
example, ammonium bisulfate will form if the gas contains 10 ppm of NH3 and
10 ppm of 803 at a temperature of 210°C. Ammonium sulfate will form at lower
temperatures. Fine particulate emissions of these compounds are a concern, but
the major problem with ammonium sulfate and bisulfate is deposition on heat
exchanger surfaces. Since these compounds are very corrosive and interfere
with heat transfer, the heat exchanger must be made of corrosion resistant
material and must be cleaned periodically by soot blowing or water washing.
Approaches to preventing this formation entail use of an ammonia decomposition
catalyst or operation at lower NH3/NO ratios.4,5
Another concern with SCR processes is catalyst plugging. Significant
progress has been made in avoiding plugging problems through reactor and
catalyst design. Fixed bed reactors, such as parallel passage, tube, and
honeycomb, are being designed which can tolerate particle loadings typical of
coal firing. Moving bed reactors are also being developed which can tolerate
and remove moderate amounts of particles. »-* However, the particle con-
centrations acceptable to a moving bed reactor are approximately an order of
magnitude less than those tolerated by a fixed bed system. The space velo-
city through a moving bed reactor is expected to be about double that of a
fixed bed reactor, but the pressure drop across the moving bed reactor should
be less.
Published information on the cost of SCR processes is limited and
estimates available are based on different design premises. The reported
estimates of the required capital investment range from $10 to $80/kW with an
average of about $30/kW. The revenue requirements range from 0.2 to 3.3
mills/kWh with an average of about 1.7 mills/kWh.2,5
235
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A list of Japanese SCR process developers Is given in Table I along with
information on their developmental status. There are 16 commercial scale
plants in operation treating 100,000 to 750,000 Nm^/hr of flue gas (33 to
250 MW). In addition, there are 11 prototype plants treating from 15,000 to
99,999 Nm^/hr of flue gas and numerous pilot and bench scale plants in opera-
tion. 6 The prototype and commercial scale plants are achieving 90% control of
the NOX from flue gas derived primarily from gas- and oil-fired sources. The
operating experience in Japan qualifies NOX control by SCR as a viable control
technique in the U.S. when high NOX removal efficiencies are required from
gas- and oil-fired sources. SCR technology has not been demonstrated in Japan
on coal-fired sources although several of the pilot plants are currently
evaluating such an application and larger scale demonstrations are expected in
the near future. In fact, a northern utility in Japan in considering installa-
tion of a 90 MW SCR system on a coal-fired boiler which will begin operation
in I960.6
Dry Simultaneous N0_./S0_, Processes
i tL-jpf x
There are two noteworthy variations of SCR processes which have the
capability to simultaneously remove NOX and SOX: the activated carbon process
and the Shell copper oxide process.
The activated carbon process requires a special carbon bed which acts as
an adsorbent for SOX and as a catalyst in the reduction of NOX with NH3.
When the bed is saturated with SOX, flue gas is switched to a fresh bed, the
carbon is regenerated, and a concentrated S02 stream is produced which can be
used to generate a salable byproduct. The process has the potential for
removing 90% of both pollutants, but its application may be limited to flue
gas containing relatively equal concentrations of NOX and SOX.^ The economic
projections for the process are about $65/kW for the capital investment and
6.3 mills/kWh in revenue requirements. The activated carbon process is being
evaluated on a pilot plant scale in Japan by Takeda, Unitika, and Sumitomo
Heavy Industries.5
In the Shell process, copper oxide reacts with S02 to form copper sul-
fate. The copper sulfate and, to a lesser extent, the copper oxide act as
catalysts in the reduction of NOX with NH3. As in the activated carbon pro-
cess, a multiple bed system is required so that a bed is available for
acceptance while regeneration takes place. In the regeneration cycle, hydro-
gen is used to reduce the copper sulfate and a concentrated S02 stream is
produced which can be used to generate a salable byproduct.^ The economic
projections for the process are $131/kW for the capital investment and
5 mills/kWh for the revenue requirements.^ The process has been installed at
the Showa Yokkaichi Sekiyu Company (SYS) plant in Yokkaichi, Japan on a com-
mercial scale (120,000 Nm3/hr) and has removed 90% of the SOX and 70% of the
NO *
236
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WET PROCESSES
The following wet process types are being developed:
Oxidation-Absorption Processes
Absorption-Oxidation Processes
Oxidation-Absorption-Reduction Processes
Absorption-Reduction Processes
Wet NOV Processes
The first two process types are generally for NOX control only. In
oxidation-absorption processes, the relatively insoluble NO is oxidized in
the gas phase to N02 which is absorbed into the liquid phase. The typical
oxidizing agents used are ozone and chlorine dioxide. The absorbents vary
with process developer. The process seems more feasible for flue gas con-
taining equimolar mixtures of NO and N02 which is not typical of combustion
flue gas. Much of the absorbed N02 remains in the liquid phase in the form
of nitrate salts which are water pollutants.^
In absorption-oxidation processes, NO is absorbed directly into the
liquid phase and then oxidized. Liquid oxidizing agents such as sodium
hypochlorate or hydrogen peroxide are used to convert the NO to a nitrate
salt. Due to the insolubility of NO, relatively large absorbers are re-
quired. In addition, the process is not applicable to flue gas containing
S02 since the more soluble S02 would consume the liquid oxidizing agent by
converting the absorbed sulfite ion into sulfate.4
Due to their complexity, limited applicability, and water pollution
problems, wet processes cannot compete economically with dry selective
catalytic reduction processes for control of NOX in combustion flue gas.
Therefore, these process types will not be addressed further in this paper,
but additional information is available from other sources.2,3,4,5
Wet Simultaneous NOY/SOy Processes
The attractiveness of wet processes is their potential for simultaneous
removal of NOX and SOX. Oxidation-absorption-reduction processes and ab-
sorption-reduction processes are designed for this type of control.
The oxidation-absorption-reduction processes basically evolved from flue
gas desulfurization (FGD) systems. A gas phase oxidant is injected before
the scrubber to convert NO to the more soluble N02- The M>2 is then absorbs
into an aqueous solution with S02- The absorbent varies with the type of ?Gi.
system being modified. The absorbed S02 forms a sulfite ion which reduces i.
portion of the absorbed nitrogen oxides to molecular nitrogen. The remair.•
237
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nitrogen oxides are removed from the waste water as nitrate salts. The
remaining sulfite ions are oxidized into sulfate by air and removed as
gypsum. The percentage of nitrogen oxides going either to the preferred
molecular nitrogen or to the troublesome nitrate salts is uncertain; however,
it is estimated to be about 50-50, but this can vary considerably.^
The oxidation-absorption-reduction processes have the potential to
remove 90% of both SOX and NOX from combustion flue gas.4 However, there are
several drawbacks remaining to be overcome before the processes can be widely
applied. The process chemistry is complex and use of a gas phase oxidant,
such as ozone or chlorine dioxide, is expensive. Chlorine dioxide, although
cheaper than ozone, adds to the waste water problems created by the nitrate
salts. Chlorine dioxide also causes concern due to the possibility for
chlorination of organics in the waste water to produce carcinogenic compounds.
Despite these drawbacks, the potential of a simultaneous removal pro-
cess warrants further research and development. Table II lists the process
developers evaluating oxidation-absorption-reduction technology. One small
commercial scale plant (33 MW), three prototype, and three pilot plants are
currently being operated in Japan.6 As with SCR processes, published econo-
mic data are limited, but the average reported capital investment is about
$110/kW and the average revenue requirement is about 7.5 mills/kWh.5
The absorption-reduction processes were seemingly developed to avoid the
use of a gas phase oxidant. A chelating compound, such as ferrous-EDTA
(ethylenediamine tetraacetic acid) which has an affinity for the relatively
insoluble NO, is added to the scrubbing solution. The NO is absorbed into a
complex with the ferrous ion and the S02 is absorbed as the sulfite ion. The
NO complex is reduced to molecular nitrogen by reaction with the sulfite ion.
A regeneration step recovers the ferrous chelating compound and oxidizes the
sulfite ion into sulfate which is removed as gypsum.^
The absorption-reduction processes also have the potential to remove 90%
of both the NOX and SOX in combustion flue gas.4 Although the processes seem
to have advantages over the oxidation-absorption-reduction processes, there
are obstacles to be overcome before the processes can be widely applied.
Even with the addition of the chelating compounds, a large absorber is re-
quired to absorb the NO. The replacement, recovery, and regeneration costs
of the chelating compounds, although potentially less than the gas phase
oxidants, are still significant. The process chemistry is complex and is
sensitive to the flue gas composition of S02, NOX, and oxygen. The molar
ratio of SO2 to NOX must remain above approximately 2.5 and the oxygen con-
centration must remain low.-*
Table II also lists the process developers evaluating absorption-reduc-
tion technology in Japan. There are four pilot or bench scale plants cur-
rently being operated.6 The average reported capital investment is about
$96/kW and the revenue requirements are about 6.3 mills/kWh.5
238
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Table III summarizes the status, cost, and performance of the dry and
wet processes for control of NO and simultaneous control of NO and SOX-
CONTROL OF NO,,, S0,r, AND PARTICLES .
Over 90% control of NOX, SOX, and particles may eventually be required
in the U.S. for stationary combustion sources, especially for new, large,
coal-fired sources. Schematics of some of the alternatives for such an
overall control system are shown in Figure 1.
Perhaps the ideal situation would be represented by one control device
that simultaneously removes NOX, SOX, and particles. Such a control device
is not yet available, but it is conceivable that a wet scrubber system could
remove all three pollutants. Such a system is represented in Schematic A of
Figure 1. Since the recovery of heat from the flue gas is important, a heat
exchanger is shown in the schematic. A reheater is also shown since most
wet scrubber systems require reheat of the flue gas prior to its discharge
from the stack.
The most developed overall control system is NOX control by selective
catalytic reduction (SCR), SOX control by flue gas desulfurization (FGD), and
particle control by an electrostatic precipitator (ESP). The sequence of
these control devices is variable as illustrated in Schematics B, C, and D.
Schematic B shows particle control first, followed by NOX control, and then
S02 control. In this configuration, the SCR system could be a moving bed
type which would require most of the particles to be removed first. To
maintain high temperatures needed by the SCR system, a hot-ESP would be
necessary. The requirement for a hot-ESP could be avoided by use of a fixed
bed SCR system which could tolerate high particle concentrations. This
configuration is illustrated in Schematic C.
Since the sulfur compounds in the flue gas lower the resistivity of the
fly ash and improve the collection efficiency of the ESP, it is not deemed
advantageous to have the ESP follow the FGD system. However, it is uncertain
if ammonia, ammonium sulfate, or ammonium bisulfate will leave the SCR system
and adversely affect the performance of the FGD system. To avoid this possi-
bility, the SCR system could follow the FGD system as shown in Schematic D.
However, the disadvantage of this configuration is the extensive reheat that
would be required to raise the flue gas temperature to a level suitable for
the SCR system.
The simultaneous NOX/SOX systems present an apparent simplification of
the control systems as shown in Schematics E, F, and G of Figure 1.
239
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Schematic E depicts the activated carbon process and Schematic F illustrates
the Shell process for dry simultaneous NOX/SOX control. Two configurations
are presented due to the different tolerance of particle concentrations
and to the different operating temperatures of the processes. The wet
simultaneous NOX/SOX control systems are shown in Schematic G and can be
represented by either the oxidation-absorption-reduction processes or by
the absorption-reduction processes.
At this time it is mere speculation as to which configuration will
emerge as the optimum overall control system from a technical and economic
standpoint. In all probability, the optimum system will be dependent on
specific flue gas and site considerations as well as user preference.
240
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EPA'S NOV FLUE GAS TREATMENT PROGRAM
A.
High NO removal efficiencies may not be required to achieve and
maintain theXcurrent National Ambient Air Quality Standards (NAAQS). Further,
the current New Source Performance Standards (NSPS) for NOX can be achieved
by implementation of combustion modification techniques which are more econo-
mical than FGT processes. However, there are significant factors which may
cause the NAAQS and the NSPS to become more stringent. These include: the
alarming increase in NOX emissions from stationary combustion sources pro-
jected for the next decade, the possibility of a short-term N02 NAAQS, the
relationship of NOX emissions to levels of photochemical oxidants, the impact
of increased use of coal resources, the impact of relaxing mobile source
emission standards, the role of NOX emissions as precursors to other pol-
lutants of concern such as PAN (peroxyacyl nitrates), other nitrates, nitro-
samines, and nitric acid, and the health effects of NOX and related pol-
lutants.
If more stringent standards are promulgated, then NOX FGT technology may
be required to meet the standards to protect human health and welfare.
Therefore, the NOX FGT program is proceeding with experimental projects pro-
gressing toward full scale demonstration of highly efficient NOX and simul-
taneous NOX/SOX control technology in parallel with control strategy and
technology assessment studies. The results of these studies will assist in
determining the appropriate scale of the experimental projects. EPA's past,
current, and planned activities in these areas are summarized below.
CONTROL STRATEGY AND TECHNOLOGY ASSESSMENT STUDIES
The control strategy and technology assessment studies are mainly
research projects to examine various aspects of NO control technology and to
determine if and when NOX FGT technology will be needed in the U.S.
Assessment of Japanese Technology
Since Japanese technology in this field is more advanced than any ocr.ar
country's, EPA has sponsored the publication of periodic reports and papers
to facilitate the transfer of information on NOX and NOX/SOX abatement tech-
nology from Japan. These documents have been mainly prepared by Dr. Jumpe.
Ando of Chuo University in Tokyo, Japan.2,3,4,7,8 Dr. Ando is also assists..-.>
EPA in activities associated with the Stationary Source Pollution Control
Project of the US/Japan Environmental Agreement which includes a subprojec;
on NO and NO /SOX FGT technology.
241
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In addition to monitoring published information from Japanese sources,'
EPA personnel have made periodic trips to Japan to observe testing facilities
and to discuss the technology with process developers and operating person-
nel. The most recent trip was in March 1977.
9
Ozone Oxidation of NO
Gas phase oxidation of NO to N02 is essential for wet oxidation-absorp-
tion-reduction processes. Therefore, a task order was issued by IERL-RTP to
the Research Triangle Institute to analyze the supply, demand, production
economics, and energy consumption of this key FGT process step. The results
of the study indicate that only a stoichiometric amount of ozone is required
to achieve essentially complete conversion of NO to N©2 which may be sub-
sequently scrubbed from the gas stream.
The energy requirements and the capital and operating costs were exam-
ined for ozone generation with both air and oxygen as input to the ozone
generator. Approximately 13% more energy is required for ozone generation
from oxygen than from air. The capital investment for ozone generation from
oxygen is about 3 times as large as that required from air, and operating
costs are about twice as large. For a 500 MW plant with air as input to the
ozone generator, the estimates for oxidizing 200 ppm of NO were: energy
requirement, 1.1 X 10° kWh/yr or 3.1% of station capacity; capital invest-
ment, $17.60/kW; and operating costs, 2.0 mills/kWh. The 200 ppm concentra-
tion is representative of a coal-fired source with combustion modification
techniques applied or an oil-fired source without supplementary NOX control
applied. The estimates are for oxidation of NO only; the energy requirements
and cost of control for N02 would be additive.
The report indicates that unless there is a significant improvement in
ozone generation technology, wet processes using ozone for oxidation of NO to
N02 will be very expensive. However, since these processes have potential
for simultaneous NOX/SOX control, the energy and cost impacts may be more
acceptable.
NOX Control Strategy Assessment
IERL-RTP contracted with Radian Corporation to determine the potential
effectiveness of applying NOX controls to large stationary combustion sources.
The Chicago Air Quality Control Region (AQCR) was selected for a modeling
study of emissions from point, area, and mobile sources to determine the
relative impact of each category on ambient NOX concentrations. The cali-
brated dispersion model predictions of annual average concentrations indicate
that the major point sources, which contributed nearly 40% of the total NOX
emissions in Chicago, accounted for less than 10% of the ambient N02 levels
in 1974. Preliminary investigation of expected short-term concentrations of
total NOX shows that major point sources may contribute as much as 80% of
measured NOX levels. Therefore, it appears that stringent NOX control for
large point sources may be required to meet a potential short-term M>2
standard, but cannot be justified currently on the basis of the existing
annual average N02 standard.10 However, NOX emissions from stationary com-
bustion sources are expected to increase significantly in the next decade.
242
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As a result of these findings, the Chicago AQCR modeling study was expanded
to determine more accurately the short-term ambient NC>2 levels, to project
the annual and short-term N02 concentrations to 1985, and to assess the use of
NOX emission control on stationary combustion sources to attain or maintain
compliance with possible N02 ambient short-term and annual average standards.
The results of this study should be available by early 1978.
Another Radian Corporation study is seeking to determine the key factors
relating to "if" and "when" NOX FGT technology will be needed in the U.S.
Since research and development of a technology should lead its application by
several years, it is necessary to monitor factors which could require imple-
mentation of NOX FGT technology in the near future. By these efforts, the
decision to emphasize, maintain, or terminate the research, development, and
demonstration of NOX FGT technology can be made on the best available infor-
mation. This study should also be available in early 1978.
Economic Assessments of NOY FGT Processes
The Tennessee Valley Authority (TVA), through an interagency agreement
with EPA, is developing comparative economics of NOX and NOX/SOX FGT emission
control processes. This state-of-the-art review will be conducted in two
phases. Phase I will evaluate and summarize the technical feasibility of all
candidate NOX control processes being offered in the U.S. and Japan. The
Phase I report, which includes descriptions of about 45 processes, should be
published in the summer of 1977. •* Phase II will concentrate on the most
promising processes identified in Phase I and will perform a preliminary economic
assessment of each, including development of material and energy balances.
In addition, a direct comparison of the economic and technical feasibility of
the dry and wet processes will be made to determine the most effective method
to remove NOX and SOX from combustion flue gas. The project is cofunded by
IIRL-RTP and the Electric Power Research Institute.
EPA is planning a third phase of the project to prepare detailed economic
projections of as many as four of the most promising processes. This activity
should be complete in late 1978. Further, it is contemplated that a study
will be conducted during this phase to determine the impact of ammonia utiliza-
tion by SCR processes. The cost and energy requirements of ammonia generation
for a typical utility application will be examined. In addition, the impact
on the supply, demand, and cost of ammonia worldwide will be analyzed. This
study may be available by the end of 1977.
EXPERIMENTAL PROJECTS
EPA's experimental projects have been directed toward enhancing the
evolution of FGT technology from bench scale research to full scale demon-
stration on coal-fired sources by the mid-19801s. The technology must be
applicable to utility and large industrial combustion sources and must achiave
highly efficient NOX and simultaneous NOX/SOX control in a relatively energy
efficient and economical manner.
243
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Bench Scale Catalyst Research^-!
In 1975, a research grant was awarded to the University of California at
Los Angeles (UCLA), School of Engineering and Applied Sciences to further the
development of promising catalysts. The study extended the catalyst screen-
ing work performed earlier by UCLA under an IERL-RTP contract with TRW,
Inc. 12 The objectives of the grant were to optimize the compositions of
vanadium and iron-chromium catalysts for selective reduction of NOX with
ammonia and to perform long-term durability studies of the optimum catalyst
compositions in flue gas containing sulfur dioxide. The results of the
study, completed in mid-1976, indicated that a 15% loading of vanadium oxide
on alumina support material and a 10% loading of iron oxide-chromium oxide on
alumina support material with an iron/chronium ratio of 9:1 were the optimum
catalyst formulations.
Parametric tests showed that both catalysts were selective, in that only
the NOX was reduced. The tests also showed strong enchancement of NOX
conversion rates due to the presence of 02 under typical operating conditions.
C02, H20, and S02 did not affect the NOX reduction in the concentration
ranges applicable to power plant exhaust. Both catalysts were most active
between 400°C and 425 °C and required excess NH3 for maximum activity. Long-
term durability tests of both catalysts in the presence of SOX indicated no
degradation in catalyst performance. Typical conversion levels for the
vanadium and iron-chromium catalysts operating at 400°C in simulated flue gas
were about 90% and 80%, respectively, at 20,000 hr~l space velocity. In
addition, preliminary tests of iron- vanadium and iron-chromium-vanadium
catalysts indicated 99% removal of NOX from the simulated flue gas.
Pilot Plant Evaluation of Gas and Oil Firing
In 1973, a contract was awarded to Environics, Inc. to evaluate the
performance, reliability, and practicality of a SCR system with ammonia and
a platinum catalyst on alumina support material. A pilot plant, treating a
slipstream from an operating utility boiler, was designed, installed, and
tested on gas and oil firing. Laboratory testing was conducted to supplement
the pilot plant testing. Satisfactory results were found on gas-fired opera-
tion with 85-90% NOX removal achieved for over 4000 hrs at a space velocity
of 50,000 hr"1. Results on oil-fired operation indicate that the catalyst
system was not suitable for flue gas containing SOX. The maximum NOX removal
efficiency achieved was 65% with the average only 50%. Fluctuation in flue
gas temperature and catalyst plugging with soot and ammonium sulfate caused
problems on oil-fired operation.
Pilot Plant Evaluation on Coal Firing
The next phase of the experimental program is evaluation of FGT processes
on a coal-fired application. A request for proposal was issued in September
1976, and best and final offers are currently being evaluated. Contract
award is anticipated by the end of September 1977. It is contemplated that
two contracts will result from this procurement process. One will be for a
pilot plant to evaluate removal of NOX emissions, and the other will be to
evaluate simultaneous removal of NOX and SOX. However, budgetary constrained
and technical considerations may impact on the final decision in this regard.
244
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The pilot plants must treat a flue gas volume equivalent to 0.5 MW and
achieve a NO removal efficiency of 90%. For the simultaneous control of NOX
and SOX, 90%Xremoval of both pollutants must be achieved. The pilot plant
projects will each consist of a 24 month program which will be conducted in
four phases. Phase I includes the preparation of a detailed process design
and an estimation of capital and operating costs for the pilot plant. Fol-
lowing erection of the pilot plant and mechanical acceptance testing in Phase
II, the contractor will perform system start-up and debugging, parametric
testing, and optimization testing over a wide range of flue gas conditions
during Phase III. Phase IV provides for testing and evaluation of the plant
during 90 days of continuous operation. It is currently anticipated that
final reports will be published on the results of the pilot plant operations
in early 1980. A project manual conveying the total concept of the proposed
plant is planned for early 1978. In addition to these projects, there is the
possibility of a pilot plant project being initiated in 1977 with the
Tennessee Valley Authority.
The pilot plant projects will enable an assessment of the technical,
environmental, energy, and economic aspects of applying NOX and NOX/SOX FGT
technology to the U.S. coal-fired situation. This information, in conjunc-
tion with the control strategy and technology assessment studies, will pro-
vide technical and budgetary direction and emphasis for EPA's NOX and NOX/SOX
FGT program.
245
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Schematic
/^
A /Boiler
Wet Scrubber
for NOX, SOX, &
Participates
ESP - Electrostatic Preciitator for Particle Control
FGD - Flue Gas Desulfurization for S02 Control
SCR - Selective Catalytic Reduction for NOX Control
FIGURE 1 - POTENTIAL EQUIPMENT CONFIGURATION FOR NO , SO ,
AND PARTICLE CONTROL X X
249
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REFERENCES
4.
5.
6.
7.
1. Bowen, J. S., G. B. Martin, R. D. Stern, and J. D. Mobley.
"Stationary Source Control Technology for NOX." The Second National
Conference on the Interagency Energy/Environment R&D Program, Washington,
D.C., June 6 and 7, 1977.
2. Ando, J., R. D. Stern, and J. D. Mobley. "Status of Flue Gas Treatment
Technology for Control of NOX and Simultaneous Control of SOX and NOX
in the United States and Japan." American Institute of Chemical
Engineers, 69th Annual Meeting, Chicago, Illinois, November 28 -
December 2, 1976.
3. Ando, J., H. Tohata, and G. A. Isaacs. NOX Abatement for Stationary
Sources in Japan. PEDCo-Environmental Specialists, Inc. EPA-600/2-76-
013b (NTIS No. PB 250 586/AS), January 1976. Tl.S. Environmental
Protection Agency, Research Triangle Park, N.C.
Ando, J., H. Tohata, and K. Nagata. "NOX Abatement for Stationary
Sources in Japan - August 1976." PEDCo-Environmental Specialists, Inc.,
(Draft Report, to be published Summer 1977 by EPA).
Faucett, H. L., J. D. Maxwell, and T. A. Burnett. "State-of-the-Art Review
of Processes for Removal of Nitrogen Oxides from Power Plant Stack Gas."
Tennessee Valley Authority (Draft Report, to be published Summer 1977
by EPA).
Ando, J., personal communication with J. D. Mobley, 06/25/77.
Ando, J., and H. Tohata. Nitrogen Oxide Abatement Technology in
Japan - 1973. Processes Research Inc., EPA-R2-73-284 (NTIS No. PB 222
143), June 1973. U. S. Environmental Protection Agency, Research
Triangle Park, N. C.
8. Ando, J. "Status of Flue Gas Desulfurization and Simultaneous Removal
of S02 and NOX in Japan." In Proceedings; Symposium on Flue Gas
Desulfurization, New Orleans, March, 1976, Vol. I, EPA-600/2-76-136a
(NTIS No. PB 255 317), May 1976, pp 53-78. U.S. Environmental
Protection Agency, Research Triangle Park, N. C.
9. Harrison, J. W. Technology and Economics of Flue Gas N0y Oxidation
by Ozone, Research Triangle Institute, EPA-600/7-76-033 (NTIS No. 261
917/AS), December 1976. U.S. Environmental Protection Agency, Research
Triangle Park, N.C.
250
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10.
11.
12.
13.
Eppright, B. R., personal communication ijith-J. D. Jtfohley, 09/27/76.
Nobe, K., G. L. Bauerle, and S. C. Wu. Parametric Studies of Catalysts
for NO.,,. Control from Stationary- Power Plants, University of California,
Los Angeles, EPA-6QQ/7-76-026 (NTIS No. PB 261 289/AS), October 1976.
U.S. Environmental Protection Agency, Research. Triangle Park, N.C.
Koutsoukos, E. P., J. L. Blumenthal, M. Ghassemi, and G. L. Bauerle.
Assessment of Catalysts for Control of NOy from Stationary Power Plants,
Phase I, Volume I, Final Report, TRW, Inc., EPA-65Q/2-75-OQl-a, (NTIS No.
PB 239 745/AS, January 1975. U. S. Environmental Protection Agency,
Research. Triangle Park, N.C.
Kline, J. M., P. H. Owen, and Y. C. Lee. Catalytic Reduction of Nitrogen
Oxides with. Ammonia: Utility Pilot Plant Operation, Environics, Inc.,
EPA-600/7-76-031 CNTIS No. PB 261 265/AS}, October 1976.
U.S. Environmental Protection Agency, Research. Triangle Park, N.C.
251
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EVALUATION OF COMBUSTOR DESIGN CONCEPTS APPLICABLE TO
ADVANCED LOW-Btu GAS FIRED SYSTEMS
By:
B. A. Folsom
Energy and Environmental Research Corporation
Santa Ana, CA 92705
This paper was not received in time for publication, and therefore will be
inlcuded in Volume V.
253
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EVALUATION OF A PROTOTYPE SURFACE
COMBUSTION FURNACE
By:
G. B. Martin
Combustion Research Branch
Energy Assessment and Control Division
Industrial Environmental Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
255
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ABSTRACT
Evaluation of a Prototype Surface Combustion Furnace
by G. Blair Martin
The emissions characteristics of a prototype surface combustion
residential furnace have been evaluated using both propane and natural gas.
The combustion of premixed fuel and air takes place on a refractory surface
without a visible flame. Heat is transferred from the surface to an air
cooled firebox wall by radiation. This maintains a relatively low surface
temperature and reduces the oxides of nitrogen (NO ).
The furnace was operated over a range of excess air from 5 to 45% and
with heat input from 16,000 to 24,000 watts. For a nominal operating point
for natural gas at 10% excess air, NO emissions were less than 15 ppm (as
measured). CO and HC emissions were also low. Furnace efficiency calculated
from flue losses was greater than 80%. Performance on propane was similar.
257
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INTRODUCTION
The Combustion Research Branch (CRB) of the EPA's Industrial Environ-
mental Research Laboratory at Research Triangle Park, N.C., has the responsi-
bility for carrying out a combustion modification R&D program directed toward
control of nitrogen oxides and other pollutants from stationary combustion
sources. In addition to pollutant emission control it appears that the
technology can also lead to equal or improved efficiency of energy utiliza-
tion compared to current practice. The majority of the R&D is carried out
under EPA contracts initiated and directed by CRB and performed by private
organizations. However, CRB also maintains an in-house research program in
a number of areas. This in-house activity provides direct project officer
expertise in combustion research and provides the capability for initial
evaluation of potential control techniques or promising novel concepts
applicable to combustion systems. The results of many of these studies are
well documented.
A continuing activity is the evaluation of novel combustion devices
which may have the potential for very low pollutant emissions. One such
device is a prototype of a residential gas fired furnace using surface
combustion to promote fuel oxidation. The purpose of this paper is to
describe the performance of that prototype.
BACKGROUND
Stationary combustion equipment used in residential heating can be
classified as area sources. Pollutant emissions from an individual unit are
259
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relatively small, the discharge into the atmosphere is near ground level in
populated areas, the emissions are concentrated in the heating season and
the number of sources is large (i.e., about 55 x 10 units). Although the
residential sources contribute only about 3% of the mass emissions of
nitrogen oxides (NO ), the environmental impact may be much more significant.
A.
In addition, these sources require relatively clean fuels (e.g., natural
gas and distillate oil) and account for over 10% of the stationary source
energy usage (ref. 1). In 1974, residential warm air furnaces used
12
over 4.5 x 10 kJ of fuel with natural gas and propane providing about
60% and fuel oil providing the balance. Based on these factors, it
appears that both emission control and energy conservation in this source
class is required. The emission levels for distillate oil fired residential
furnaces have been characterized (ref. 2) and there has been some tech-
nology development for reducing emissions and increasing efficiencies (ref. 3).
Much less work has been done on gas fired residential furnaces because of
less flexibility in adjusting operating conditions and relatively simpler
equipment design. The normal residential gas furnace does not have a "burner"
as such, but rather relies on natural draft to provide combustion air and to
accomplish fuel and air mixing. The available gas pressure is used to entrain
some air and to form a primary air and fuel mixture that is admitted to the
combustion chamber through one or more log manifolds. Secondary air to
complete combustion is admitted to the combustion chamber around the manifolds.
Although the primary air can be controlled to a degree, there is essentially
no way to control secondary air. Therefore, the overall excess air cannot
be controlled to a significant degree.
The available emission data on gas fired furnaces are very limited.
Hall (ref. 3) reported data for three gas furnaces with NO emissions
6 x
ranging from 0.084 to 0.115 gm of NO (as NO) per 10 cal [i.e., 0.32 to
1 ft ^
(K42 kg NO (as N09) per 10 j]. Any given furnace could only be operated
X i*
over a narrow range of excess air; however, the three different designs
operated at levels in the range of 20 to 60% excess air. The emissions of
carbon monoxide (CO) and hydrocarbon (HC) were low for all three furnaces
at the normal operating point. DeWerth (ref. 4) measured emissions from
260
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38 forced warm air gas furnaces in the AGA laboratory and reports an average
NO value of 0.097 Ibs NO (as N00) per 106 Btu [i.e., 0.415 kg NO (as N0_)
X X / X L
per 10 j] with a small effect of furnace design. Decreasing the primary
air setting to the point of yellow flame operation decreased the NO level
by about 10%; however, CO emissions increased by a factor of 20 and the N0_
component increased from about 5% of the total NO to the range of 10 to 17%.
X
Data for other gas appliances and for modified furnace design also showed
high fractions of NO™ associated with higher CO levels. Several modifications
of furnace design were examined with the most successful one achieving 37 ppm of NO
[i.e., 0.172 kg NO (as N02> per 10 J] at low CO levels by putting a screen
in the flame zone to increase radiant heat transfer. Finally, Brookman
(ref. 5) performed field measurements on 50 residential gas fired furnaces
and boilers and reported average NO emissions of 112 Ibs (as N0_) per 10
3 x 10
ft of gas [i.e., about 0.455 kg NO (as NO,) per 10 J].
X Z
The efficiency of the furnace is dependent on the extent of heat loss
from the system by various avenues. The predominant energy losses are the
following:
1. Latent heat of vaporization of the water formed during
combustion which cannot be recovered without a condensing
heat exchanger. About 10% of the gross heat input of
natural gas is irretrievably lost in this form using current
technology.
2. Sensible heat in the combustion products which is dependent
on the amount of excess air used for combustion, the amount
of dilution air and the temperature of the gas in the flue.
This loss can be reduced by low excess air operation,
elimination of dilution air and/or reduction of stack
temperature.
3. Draft losses, which remove residual heat from the firebox
during the off-cycle. This loss can be reduced by minimizing
or eliminating air flow through the furnace during off-cycle.
261
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4. Miscellaneous casing losses. These losses are normally held
to a minimum by proper insulation of the furnace enclosure.
The significant features of these losses are discussed for fuel oil
in reference 3. The general discussion also holds for natural gas, although
differences in latent heat losses and system design will change the
quantitative levels. DeWerth (ref. 4) reported that the average of
furnaces tested in the AGA Lab had 5.8% C02 in the flue products (approxi-
mately 100% excess air); however, no flue temperatures were given. Flue
losses for two units tested were reported to be 20.1 and 26.6%, based on
steady state operation. The cycle average efficiency will be further reduced
by the draft and casing losses.
EXPERIMENTAL APPROACH
This section provides information on several aspects of the experi-
mental approach including: 1) the fuel supply system; 2) the Bratko prototype
furnace; 3) the analytical instrumentation; and 4) the range of variables
examined.
Fuel Supply
Natural gas was provided from a laboratory gas line at a pressure
4
of 3.45 x 10 pascal gage [5 psig]. Propane was provided from a pressurized
A
gas bottle and the line pressure was controlled at 4.83 x 10 pascal gage
[7 psig]. The gas supply was passed through a dry gas meter to obtain a
volumetric flow rate. Following this the pressure was regulated to
3
3.'45 x 10 pascal gage [0.5 psig] and the gas passed through an ASTM orifice
meter. The pressure drop across the orifice was used to adjust the gas flow
to a constant value during a test series. The gas supply was connected to
the fuel inlet system of the furnace.
262
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Bratko Prototype Furnace
The furnace tested was a prototype of a surface combustion concept for
use in residential gas furnaces. The concept is based on combustion of
premixed fuel and air on the surface of a refractory matrix without visible
flame. The glowing refractory surface radiates to a surrounding air cooled
combustion chamber and, thereby, maintains the surface temperature at a
relatively low value (i.e., below about 1250 K). A schematic of the surface
combustor and firebox is shown in Figure 1. The combustion chamber was
enclosed in a conventional upright furnace body and used a three speed
circulating air fan to pass air over the heat exchange surface. The speed
of the fan increased stepwise as the pressure drop across the system
increased.
The combustion air was supplied with an external centrifugal fan that
was considerably oversized in capacity, but was necessary to supply the
required pressure. [This arrangement would not be practical in a production
furnace; however, Bratko stated that a small fan with the necessary pressure
capability has been developed (ref. 6).] A regulator drops the natural gas
supply pressure to 3450 pascals gage (0.5 psig), then the gas is piped
through solenoid valves to both a pilot burner and to the main furnace.
The pilot burner premixes the gas with part of the combustion air and the
mixture is ignited with a spark. A flame rod is used to prove the pilot
flame prior to the burner gas solenoid valve opening. The burner gas supply
is premixed with combustion air with a mixing device (in the prototype
furnace the amounts of both air and fuel could be controlled independently,
although in practice, relatively fixed flow rates would be expected). The
premixed gas and air is fed to a plenum inside the surface combustor at a
pressure of about 895 pascals gage (0.13 psig) and is forced through the
refractory pad to burn on the surface. The refractory is selected to be
sufficiently insulating that the plenum temperature remains essentially at
ambient, thereby eliminating preignition due to heat feedback.
263
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Analytical Instrumentation
The gas sample for analysis was withdrawn from the flue after the gas
had been cooled to 422-475 K in the convective pass of the heat exchanger.
The samples are conditioned and analyzed with a similar system to that
described earlier (ref. 7). To summarize, the analytical Instruments are:
1) oxygen by paramagnetic resonance; 2) CO and C0_ by non-dispersive
infrared (NDIR); 3) hydrocarbon by flame ionization detector; 4) NO by a
long path NDIR; and 5) NO and NO by chemiluminescence analyzer. The
j£
temperature of the flue gas was measured with a dial thermometer and cross
checked with a thermocouple.
Range of Variables
The tests were planned to screen the furnace combustion and emission
performance over the permissible range of operation. The two variables
were fuel flow and excess air level. Since there was some interaction
between fuel and air flow in the mixer it was not possible to attain
completely comparable input levels. Therefore, three nominal values were
used: 16,000, 19,000 and 22,000 watts (55,000, 65,000, and 75,000 Btu/hr,
respectively). The excess air range for the first two fuel flows was from
45% down to the point where excessive CO (i.e., > 200 ppm) was formed. For
the highest rate the maximum excess air was 25%.
In addition a limited number of tests were run with propane to establish
the multi-fuel capability of the unit.
EXPERIMENTAL RESULTS
This section presents a discussion of two specific aspects of the
results: 1) emissions; and 2) efficiency.
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Emissions Measurements
The primary evaluation of the furnace performance was based on measure-
ments of pollutant species in the flue gases as a function of operating
condition. To fully characterize the operating range the excess air level
was varied from a high value (i.e., > 25%) down to the point that excessive
CO (i.e., > 200 ppm) was being emitted. No hydrocarbons or smoke were
observed during the test. The effects of excess air and fuel input are
discussed below.
Excess Air. The effect of excess air level on emissions is shown in
Figure 2 for a thermal input of 16,000 watts (55,000 Btu/hr) . The data shown
here were obtained during five different experimental periods covering 4 months
and the small scatter in the points shows that the performance was quite
repeatable. At 40% excess air, the CO emissions are quite low (i.e., 20-30 ppm)
and remain low as the excess air is reduced to 10%. When the excess air is
reduced below 10% the CO begins to rise sharply and at 5% excess air is greater
than 1500 ppm. The results for oxides of nitrogen are shown as measured for
both NO and NO and corrected to zero % excess air for both NO and NO . The
X 3C
NO concentration to zero % excess air gives a direct indication of the trend
of mass emissions as a function of excess air and will be used as the primary
basis of discussion. The NO is low (i.e., 7.5 ppm) at 40% excess air and
rises slowly to 10 ppm as excess air is decreased to about 15%. Then as
excess air is reduced further, the NO rises sharply to about 19 ppm at
X
7.5% excess air. Comparison of the as measured values of NO and NO
X
(where the difference is interpreted as being N0?) shows that the amount
of N0~ increases as the excess air is decreased; however, the ratio of
NO^ to NO is approximately constant. This holds true even when high CO
levels are observed.
Fuel Input. The effect of fuel input on emission performance was
examined. The furnace design condition was taken as a nominal 16,000 watts
(55,000 Btu/hr) and two higher levels were evaluated: 19,000 and 22,000
watts (65,000 and 75,000 Btu/hr, respectively). The data for these higher
levels are shown in Figures 3 and 4. The emission trends are essentially
265
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the same as the baseline case with only small changes. The point at which
CO emissions increase sharply is moved down to 5% excess air for both higher
heat inputs. The NO emissions are increased slightly as heat input
X
increases for excess air levels of 10 to 30%; however, the ends of the
range do show minor differences. Finally, the ratio of IH^ to NO decreases
as the heat input increases.
Fuel Type. A limited series of runs were performed using propane as
the fuel. In general, the effect of excess air on emissions was similar
to that for natural gas, except that the onset of excessive CO occurred at
somewhat higher excess air (i.e., 10-15%). A run with propane at a
nominal 26,000 watts (90,000 Btu/hr) heat input gave a different trend as
shown in Figure 5. The onset of CO formation occurs at a higher excess air
and, of more interest, the ratio of N0« to NO increases significantly as
the CO begins to increase.
Thermal Efficiency
The data gathered for evaluation of the furnace emission performance
can also be used to gain some insight into the thermal efficiency of the
furnace. In addition, several measurements of furnace warm air output were
made. These two indications of the furnace thermal performance are
discussed.
Stack Heat Loss. The main energy loss from a furnace is in the
sensible and latent heat associated with the flue gas components, principally
N2, C02, 0- and H_0. The latent heat loss is determined by the carbon
to hydrogen ratio of the fuel and is irretrievable unless a condensing
heat exchanger is used. It should be noted that condensing heat exchangers
for this application are not currently available. For natural gas the
latent heat is equivalent to about 10% of the gross heating value. The
sensible heat losses can be minimized by low excess air operation and
266
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the lowest stack temperature consistent with avoiding condensation
(i.e., about 180 K net). A generalized plot of efficiency versus excess
air with stack temperature as a parameter is shown in Figure 6 for natural
gas.
The flue gas temperature taken during the experimental runs were
relatively independent of excess air for a given firing rate; however, the
temperatures increased with increased firing rate. The average flue gas
temperatures were 447, 475 and 498 K, at 16,000, 19,000 and 22,000 watts,
respectively. An operating excess air of 15% is selected based on the
emission curves, giving steady state furnace efficiencies for the three
firing rates of 83.4, 82, and 81%, respectively. When the casing losses
are taken into consideration, the actual heat loss would be about 2% greater.
At the low firing rate, the stack temperature was below the value required
to prevent condensation and a production furnace would require less con-
vective heat transfer surface. For the high firing rate, the stack
temperature potentially could be reduced by about 22 K. If heat exchanger
design was changed to achieve a 475 K stack temperature for each firing
rate, the theoretical efficiencies would be the same as that for the 19,000-
watt heat input. However, a given furnace is normally designed to be
capable of a range of firing rates, and the existing design represents a
reasonable compromise for input over 19,000 watts.
Some measurements of output air velocity and temperature rise were
made at the output of the plenum on top of the furnace. As an extended duct
run was not used to smooth the flow, the stratification of flow due to the
heat exchanger was significant. Measured exit velocities were 1.25 to
11.5 m per sec (250 to 2300 ft/min) across the exit face of the plenum, and
low temperature rises were normally associated with low velocity areas. These
stratifications also strongly influence the accuracy of the measurements;
however, they can be taken as semi-quantitative. The warm air flow was about
0.45 m /sec for two firing rates, with average temperature rises of 24 and
31 K for heat inputs of 19,000 and 24,000 watts, respectively.
267
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Discussion of Results
Examination of the experimental results raises several points that
merit further discussion. It is obvious that some additional measurements
within the combustion chamber would greatly assist in explanation of the
phenomena involved; however, the fact that the furnace was a prototype
inhibited making the modifications required for sampling.
Operating Principle. The inventor of the furnace stated (ref. 6) that
the furnace was designed to operate with a hot refractory surface as a means
of increasing the radiative heat transfer to the heat exchanger. The use of
radiative heat transfer for combustion zone heat removal is a common
feature of large conventional boilers with diffusion flame burners
(especially the water-tube type); however, in general residential
systems do not have heat transfer surface in the combustion zone. It
appears that the key features of the design are: 1) the insulating
properties of the refractory used to form the surface combustor; and 2)
the use of radiative heat transfer to reduce the refractory surface
temperature to a level where degradation does not occur. The refractory
material was selected to have a low thermal conductivity and, therefore,
a very slow soakback of heat from the reacting surface to the plenum
containing the premixed fuel and air. It appears that this has a two-
fold benefit: 1) the heat release is maintained in a thin zone close to
the outside of the refractory surface; and 2) radiative heat transfer
reduces the refractory surface temperature to a level where degradation
does not occur. The degradation of the refractory with time, and the
attendant increase in probability of autoignition, needs to be evaluated.
The use of radiative heat transfer allows a high rate of energy removal
and apparently maintains the surface temperature well below the adiabatic
temperature for the fuel and air stoichiometry being used. This allows the
use of fuel/air ratios near stoichiometric where the adiabatic temperature
is about 2200 K (3500°F), and yet the reaction zone temperature is maintained
268
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below the level where degradation of the refractory would occur. In
addition, the temperature is low enough to reduce thermal NO formation.
The observations of the effect of heat input on combustor performance
indicate that some increase in surface temperature may occur with increased
fuel.input as indicated by the lower excess air capability. This is a
relatively small effect that may be associated with either the temperature
or the thickness of the heat release zone. The small increase in NO level
X
suggests that the change is relatively small. It appears that the increased
heat release is balanced by increased radiative transfer and/or an increased
convective removal of energy due to the larger volume of combustion gases at
a given excess air level. The effects could be explained either on the basis
of complete reaction of the fuel within the surface or on the basis of partial
reaction in the surface with oxidation being completed by homogeneous
reactions in the space between the surface and the firebox wall. To answer
these questions fully would require measurement of: 1) surface temperatures
for the heat exchanger and the refractory material; 2) gas temperature at
the firebox exit; and 3) gas phase species measurements within the firebox.
Based on the foregoing discussion and operating experience with two
different combustor and firebox configurations in Bratko prototype furnaces,
it appears that proper matching of the combustor and radiative heat transfer
surface does significantly influence the performance.
NOg Emissions. As noted in the background section, above, instances
where the NO, is greater than 25% of the NO have been observed by several
L, X
investigators for natural gas combustion under conditions where CO levels
are high. This same trend was observed for an earlier version of the Bratko
prototype tested for both methane and propane at low excess air (i.e., < 20%).
Due to the fuel/air mixer configuration of the earlier furnace, excess
air was changed by increasing fuel flow at a relatively constant air flow.
With the new furnace, propane at a high fuel rate exhibited a high N0» to NO
ratio at low excess air. This effect was not noted with the new furnace
burning methane even at relatively high firing rates; however, the excess
air level at which CO increased was significantly lower (i.e., < 6%).
269
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Although there is some controversy over his interpretation, Merryraan (ref. 8)
has reported "flame front N0»" for flat flames. His data show conditions
within the reaction zone where NO- is a large percentage of the NO . This is
f- X
also the zone in which significant amounts of CO were present. Although a
flat flame is difficult to relate directly to a surface combustor, these
results give a possible basis for explaining the furnace data. It can be
postulated that for a given combustor surface and heat exchanger area, the
total oxidation occurs in or very near the surface until some critical fuel
flow rate is reached and the final oxidation of fuel fragments (e.g., CO)
begins to occur in the gas phase above the surface. At low excess air
levels, the combustion may not be completed fast enough by these gas phase
reactions, thereby allowing some pockets of gases containing CO and high N0?
to NO ratios to escape and be quenched before the NO, can relax back to NO.
If this is the case, the data would tend to indicate that this phenomenon
is sensitive to the relationship between the surface combustor and the
radiant heat exchanger firebox.
Efficiency. Although the furnace efficiency is good for all the cases
tested, the potential exists for optimizing the furnace for each heat input
value by fine tuning the convective section of the heat exchanger to get
minimum allowable stack temperature. Other features of the furnace may
provide an increase of cycle average efficiency, particularly by reducing
or eliminating off-cycle losses. One source of such loss is the continued
flow of draft air through the firebox during the off-cycle. This not only
removes accumulated heat from the furnace components, but may also cause a
loss of heated air from the furnace space. The Bratko design provides a
positive air shut off, which should reduce off-cycle losses significantly.
CONCLUSIONS
Based on the furnace evaluation the following conclusions can be drawn:
1. The surface combustion concept shows clear potential for
NO emissions significantly below previously reported
values, while also giving low levels of CO and HC.
270
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2. The Bratko furnace represents an application of surface
combustion to a practical system once a satisfactory
combustion air source is incorporated.
3. The low excess air capability gives the potential for
high efficiency. Other furnace features which limit off-
cycle losses also have the potential for increasing
cycle average efficiencies.
4. The concept appears to lend itself to a wide range of
firing rates. In fact, performance improved with natural
gas at the higher firing rates tested.
271
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REFERENCES
1. Barrett,.R. E., S. E. Miller, and D. W. Locklin, "Field Investigation
of Emissions from Combustion Equipment for Space Heating," Battelle
Columbus Laboratories, EPA-R2-73-084a, NTIS No. PB 223-148, June 1973.
2. Combs, L. P., and A. S. Okuda, "Residential Oil Furnace System Optimi-
zation - Phase II," Rockwell International, EPA-600/2-77-028,
NTIS No. PB 264-202/AS, January 1977.
3. Hall, R. E., J. H. Wasser, and E. E. Berkau, "A Study of Air Pollutant
Emissions from Residential Heating Systems," U. S. EPA, ORD, Control
Systems Laboratory, EPA-650/2-74-003, NTIS No. PB 229-697/AS, January
1974.
DeWerth, D. W., and R. L. Himmel, "An Investigation of Emissions from
Domestic Natural Gas-Fired Appliances." Presented at the 67th APCA
Annual Meeting, June 14, 1974, Denver, Colorado.
Brookman, G. T., and P. W. Kalika, "Measuring the Environmental Impact
of Domestic Gas-Fired Heating Systems." Presented at the 67th APCA
Annual Meeting, June 14, 1974, Denver, Colorado.
R. Bratko, Bratko Corporation, Cleveland, Ohio, private communication,
August 1976.
Pershing, D. W., J. W. Brown, and E. E. Berkau, "Relationship of Burner
Design to the Control of NO Emissions Through Combustion Modification."
X
In Proceedings, Coal Combustion Seminar, EPA-650/2-73-021, NTIS No.
PB 224-210/AS, September 1973.
Merryman, E. L., and A. Levy, "Nitrogen Oxide Formation in Flames:
The Roles of N02 and Fuel Nitrogen," 15tl
on Combustion, Tokyo, Japan, August 1974.
The Roles of NO- and Fuel Nitrogen," 15th Symposium (International)
272
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273
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- NOX (CORRECTED TO 0% EXCESS AIW
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Figure 2. Emissions characteristics at a nominal heat input of 16,000 watts of natural gas.
274
-------
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Figure 3. Emission characteristics at a nominal heat input of 19,000 watts of natural gas.
275
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Figure 5. Emission characteristics at a nominal heat input of 26,000 watts of propane.
277
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75
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Figure 6. Gross efficiency as a function of operating conditions for natural gas.
278
80
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PANEL: EMERGING COMBUSTION TECHNOLOGIES
1 -- Fluidized Bed Combustion
John M. Connell
2 -- Magnetohydrodynamics
William Jackson
3 — Coal-Oil Slurries
Casters B. Foster
4 -- Advanced Combined Cycles
Fred Robson
Panel discussion abstracts will be included in Volume V,
279
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TECHNICAL REPORT DATA
(Please read Inanitions on the reverse before completing)
. REPORT NO.
EPA-600/7-77-073C
2.
3. RECIPIENT'S ACCESSION NO.
4-TITLE AND SUST.TLE PROCEEDINGS OF THE SECOND
STATIONARY SOURCE COMBUSTION SYMPOSIUM
Volume TH. Stationary Engine, Industrial Process
Combustion Svstems. and Advanced Processes
6. REPORT DATE
July 1977
6. PERFORMING ORGANIZATION CODE
7'AUTHOR(S> Symposium Chairman J.S. Bowen, Vice-
Chairman 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
is. SUPPLEMENTARY NOTES JERL-RTP project officer for these proceedings is R.E. Hall,
Mail Drop 65, 919/541-2477.
16. ABSTRACT rp|ie 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
II—Utility and Large Industrial Boilers; Volume UJ—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.IDENTIFIERS/OPEN ENDED TERMS C. 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
2 IB 14B
2 ID 11H
07B
07C 13A
13G 14A
18. DISTRIBUTION STATEMENT
Unlimited
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Unclassified
21. NO. OF PAGES
285
20. SECURITY CLASS (Thispage)
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22. PRICE
EPA Form 2220-1 (9-731
280
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ISP 600/7 EPA
r?-073c Ind» Env. Res. Lab*
AUTHOR
ProCo of the second stationa
TITLE source combustion symposium
V.3: Stationary engine,*.*
DATE DUE
CAYLOWO 48
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