v>EPA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
EPA-600/7-79-079
March 1979
Applicability of the
Thermal DeNOx Process
to Coal-fired Utility
Boilers
Interagency
Energy/Environment
R&D Program Report
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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 nine series. These nine broad cate-
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4. Environmental Monitoring
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RESEARCH AND DEVELOPMENT series. Reports in this series result from the
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Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
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essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
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This document is available to the public through the National Technical Informa-
tion Service, Springfield. Virginia 22161.
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EPA-600/7-79-079
March 1979
Applicability of the
Thermal DeNOx Process to
Coal-fired Utility Boilers
by
G.M. Varga Jr., M.E. Tomsho, B.H. Ruterbories,
G.J. Smith, and W. Bartok
Exxon Research and Engineering Company
Government Research Laboratories
P.O. Box 8
Linden, New Jersey 07036
Contract No. 68-02-2649
Program Element No. EHE624A
EPA Project Officer: David G. Lachapelle
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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FOREWORD
Two studies relating to Exxon's Thermal DeNOx Process for control of
NOX emissions from utility boilers have been sponsored by EPA/IERL-RTP.
One, conducted by Exxon Research and Engineering Company under EPA Contract
68-02-2649, is entitled "Applicability of the Thermal DeNOx Process to
Coal-fired Utility Boilers." The final report number is EPA-600/7-79-079,
March 1979. The other, conducted by Acurex Corporation under EPA Contract
68-02-2611, is entitled "Technical Assessment of Exxon's Thermal DeNOx
Process." Its final report number is EPA-600/7-79-111, May 1979.
The Exxon-prepared report discusses the Process background, engineer-
ing considerations, and cost estimates for application of this technology
for a number of boiler/fuel cases at various NOX control levels. Results
of recent pilot-scale tests with coal-firing, sponsored by Exxon and the
Electric Power Research Institute, are included.
The Acurex-prepa red report objectively critiques the Exxon findings
and also addresses a variety of environmental, operational, and supply/
demand considerations that are relevant to the Thermal DeNOx Process.
Together, these reports give a good overview of this technology. We
recommend that both reports be obtained, and read, by those wishing to
become better informed about the Thermal DeNOx Process.
J«bti K/ Burchard
Director
IERL-RTP
ii
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ABSTRACT
This EPA-sponsored program was undertaken to project the probable per-
formance of the Exxon Thermal DeNOx Process on selected, representative coal
fired utility boilers and to determine if Thermal DeNOx is better suited to
certain boiler types than others. Also, budget type cost estimates were
prepared for Thermal DeNOx applied to these boilers. The non-catalytic
Thermal DeNOx Process is based on selective reduction of NOx with NH3 in the
gas phase. Thermal DeNOx nas been commercially demonstrated on gas- and
oil-fired boilers and process furnaces. A pilot scale test on a coal fired
combustor produced results similar to those obtained with oil and gas firing.
In undertaking the study reported here, Exxon Research and
Engineering Co. (ER&E), selected eight typical coal-fired utility boilers,
representative of the nation's boiler population. The boilers were chosen
to permit an evaluation of the Thermal DeNOx Process on different utility
boiler sizes, firing methods and coal types. Thermal DeNOx performance
and process costs were determined for two NOX reduction targets:
a. Trimming NOX emissions to meet the proposed New Source Performance
Standards (NSPS) of 0.6 Ib. NOx/MBtu* (450 ppm NOX**) for bitu-
minous coal and lignite fired boilers and 0.5 Ib. NOx/MBtu (375 ppm
NOX) for boilers fired with subbituminous coal.
b. Deep reduction in NOx levels to 0.4 Ib./MBtu (300 ppm NOx) for
boilers fired with bituminous coal and lignite and 0.3 Ib. NOx/MBtu
(225 ppm) for subbituminous coal fired boilers.
Also considered was the:
c. Maximum practical reduction in NOx levels which could be realized
by the application of the Exxon Thermal DeNOx Process.
Two initial NOX levels were considered for each of the above NOX targets:
(i) uncontrolled and (ii) reduced by combustion modifications. Each boiler
was assumed to be equipped with two ammonia injection grids to permit load
*Certain English units, have been used in this report. A table has been
provided to facilitate conversion to the SI system.
**Throughout this report volumetric concentrations of NOX are expressed as
parts per million corrected to 3% 02, dry basis.
iii
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following. In aa'dditien to the six cases, special analyses were performed
for flue gas temperature nonuniformity and the use of hydrogen with ammonia
to permit load following. A Performance Prediction Procedure developed by
ER&E was used to project Thermal DeNOx performance. Also, the Thermal DeNOx
costs for reaching NOX levels of 0.3 to 0.4 Ib/MBtu were compared with the
costs of combustion modifications (CM) required to reach these levels.
All eight units studied were projected to reach the proposed NSPS
using Thermal DeNOx alone. Five of these units could reach this level using
CM alone. All units except a cyclone boiler firing lignite were projected
to reach the deep NOX reduction target when Thermal DeNOx was used with CM.
Four boilers were projected to reach the deep reduction target using Thermal
DeNOx alone. The Thermal DeNOx process costs to reach the proposed NSPS from
an uncontrolled base level ranged from 0.25 to 1.17 mills/KW-Hr. The costs
to reach the deep reduction target using Thermal DeNOx with CM ranged from
0.38 to 0.51 mills/KW-Hr and averaged 0.45 mills/KW-Hr for the seven boilers
reaching the target. NOX reductions from uncontrolled initial levels ranging
from 50 to 59% and costs ranging from 0.57 to 1.23 mills/KW-Hr were
projected using Thermal DeNOx at a maximum practical level without CM. With
CM, reductions ranging from 62 to 76% were projected. Costs ranging from
0.55 to 1.14 mills/KW-Hr were projected for the eight boilers studied.
The Thermal DeNQx Process was projected to be equally amenable to all
units studied. One overall judgement criteria of performance, ammonia
reagent costs/pound of NOX removed, were nearly equal for all units at
0.09 $/lb ANOX. Conventional CM which could reach NOX levels of 0.3 to 0.4
Ib/MBtu were cheaper than Thermal DeNOx, but extreme CM such as derating were
more expensive.
Thermal DeNOx performance is a function of the cress sectional tempera-
ture throughout the reaction zone. The Performance Prediction Procedure
used assumes that a range of temperatures is present in the plane of the
injection grid. This temperature range is assumed to be gradually smoothed
out downstream of the injection location. It was projected that the ammonia
injection grid location would not be affected significantly by assuming a
50°C larger temperature range in the injection plane than that used for
baseline calculations. However, a temperature range increase of this size
would reduce DeNOx performance by 5 to 10 percentage points (e.g., from 50%
to 40-45%).
Hydrogen can be used with ammonia to lower the temperature at which the
Thermal DeNOx reaction occurs. Thus, in certain cases it may be technologi-
cally possible to utilize ammonia plus hydrogen rather than dual grids to
permit effective DeNOx performance at less than full boiler loads. In one
such example considered, the use of hydrogen and ammonia fed through one
grid increased the costs of Thermal DeNOx relative to the corresponding
ammonia-only, dual grid cases considered.
The pilot plant scale test on coal firing noted earlier was sponsored
jointly by Exxon Research and Engineering Co. and by the Electric Power
Research Institute. The work was performed by KVB Inc. and their report
is included here as Appendix 2.
iv
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A full scale test of the Exxon Thermal DeNOx Process on a coal fired
utility boiler is recommended. This demonstration would be structured to
evaluate ammonia breakthrough and DeNOx performance as a function of load,
the effect of slag formation and fouling on Thermal DeNOx performance, the
formation, deposition and removal of ammonium sulfates, the effect of
ammonium sulfates on electrostatic precipitator performance, the influence
of Thermal DeNOx on particulates, and other pollutants, and the compatibility
of Thermal DeNOx system elements with coal ash levels and soot blowing equip-
ment and procedures.
This report was submitted in fulfillment of Contract No. 68-02-2649 by
Exxon Research and Engineering Company under the sponsorship of the U.S.
Environmental Protection Agency. This report covers a period from
September 30, 1977 to May 31, 1978, when the work was completed.
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CONTENTS
Page
Abstract iii
Figures vii
Tables viii
Conversion Factors ix
Acknowledgment x
1. Introduction 1
2. Conclusions 4
3. Recommendations 6
4. Process Background 7
Chemistry of the Process 7
Engineering Considerations 9
Process Costs 10
Commercial Scale Experience 11
5. Program Detail 13
Boilers Selected for Study 13
NOX Reduction Cases 13
Thermal DeNOx Performance Prediction Procedure . . 18
Cost Estimates 20
6. Results and Discussion 27
Predicted Percent NOx Reduction Levels 29
Feasibility Costs 30
Maximum Reduction of NOX Levels 33
Normalized Ammonia and Other Operating Costs ... 34
Cost Comparison of Thermal DeNOx with Combustion
Modification Techniques 37
Temperature Nonuniformity Sensitivity Study .... 40
Use of Hydrogen for Load Following 41
Appendices
1. Cost Comparison Summary 47
2. Non Catalytic NOX Removal with Ammonia 55
vi
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FIGURES
Number Page
4-1
6-1
6-2
6-3
Performance of Thermal DeNOx Systems in Commercial
Cost Comparisons for Trim Target Without Combustion
Modifications - 100 Percent Load
Comparison Cost of Injecting with and Without H2 in a
Babcock and Wilcox - 333 MW Unit
1?
3C
' 03
30
4R
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TABLES
Number Page
5-1 Boilers Selected for Study H
5-2 Initial and Final NOX Levels for Boiler/Coal Combinations ... 17
5-3 Thermal DeNOx Cost Calculations 23-24
5-4 Costs for Combustion Modifications Established by Acurex-
Aerotherm 25
5-5 Costs for Boiler Derating 26
5-6 Combustion Modifications Used to Reduce NOx Levels 26
6-1 Predicted Thermal DeNOx Performance Achievable at Full, 75% and
50% Load 30
6-2 Costs for Reducing NOX Emissions of Coal Fired Utility Boilers
Using Thermal DeNOx 32
6-3 Maximum Practical NOX Reduction Achievable Using Thermal DeNOx . 36
6-4 NOX Levels on 270 MW B&W HO Boiler 39
6-5 NOX Levels on 265 MW F-W HO Boiler 39
6-6 Examples Contrasting Single Grid-Hydrogen and Dual Grid for Load
Following 42
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CONVERSION FACTORS
To Convert From To Multiply By
Ib/Hr kg/Hr 0.4536
Ib/MBtu ng/J 43°
ppm N0₯ mg/m 1.88*
*NO expressed as N0? at 25°C
j\ £-
IX
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ACKNOWLEDGMENT
The authors acknowledge with thanks the boiler manufacturers, Babcock
and Wilcox, Combustion Engineering, Inc., Foster Wheeler Corp., and Riley
Stoker Corp., for providing technical information on their boilers
required for undertaking this study.
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SECTION 1
INTRODUCTION
Exxon Research and Engineering Company has developed a new process
called Thermal DeNOx for reducing emissions of oxides of nitrogen from
large stationary combustion sources. This non-catalytic process is based
on the selective reduction of NOX with NHs in the homogeneous gas phase
(1_,2). The Thermal DeNOx process has been commercially demonstrated on
gas-and oil-fired steam boilers and process furnaces. Exxon Research and
Engineering Company has granted licenses on this process in Japan where
NOX emission regulations are very stringent and in the U.S. where a test
was recently completed on a boiler used for the enhanced recovery of oil.
A test has also been performed on a pilot scale coal fired boiler.
The Thermal DeNOx process involves the injection of ammonia into the
hot flue gas within a narrow and critical temperature range. Maximum NOx
reductions ranging from 35% to 65% have been obtained with Thermal DeNOx
on commercial units. Although the temperature sensitivity will cause the
reaction's effectiveness to vary from one installation to another, the NOX
reduction is essentially independent of the concentration of oxides of
sulfur or particulate matter in the flue gas. The specific level achievable
is dependent upon a number of factors, including the boiler design, operating
mode, and initial NOX level.
Thermal DeNOx may be applied to boilers for additional NOX reduction
after combustion modifications such as low excess air firing, the use of
low NOX burners or overfire air ports have been implemented. As Thermal
DeNOx is a post-flame injection process, it is not affected by certain
limitations such as derating imposed on combustion modifications that may
affect the usefulness of combustion modification in retrofit applications.
Thus, the Thermal DeNOx process is viewed as an effective supplement to
available combustion modification techniques for attaining low NOX levels
for combustion installations that require a high degree of emission control.
The purpose of this EPA-sponsored program has been to project the
performance and formulate budget type cost estimates of the Exxon Thermal
DeNOx Process applied to a broad range of typical coal fired utility boilers.
Exxon Research has undertaken an assessment of utility boiler types to
determine if certain boilers as a function of firing method, size, or
manufacturer's design are more amenable to the Thermal DeNOx Process than
others. To perform this analysis, Exxon Research identified eight represent-
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ative utility boiler categories which included one or more from each of the
four major boiler manufacturers. These boilers were selected so as to
permit an assessment of different utility boiler sizes, firing methods and
coal types. In undertaking this assessment, Exxon Research consulted with
and obtained from the four major U.S. utility boiler manufacturers the
temperature, dimensions, flue gas flow and other non-proprietary boiler
design information required to undertake this assessment. Exxon Research
has also prepared budget type cost estimates of the Thermal DeNOx Process
applied to the boilers considered.
Two key NOx reduction targets were formulated in undertaking the
amenability analysis and cost estimates noted here. These were:
a. Trimming NOX emissions to meet the proposed New Source Performance
Standards (NSPS) of 0.6 lb. NOx/MBtu (450 ppm NOX) for bi< tiinous
coal and lignite fired boilers and 0.5 lb. NOx/MBtu (375 NOX)
for boilers fired with subbituminous coal.
b. Deep reduction in NOx levels to 0.4 Ib./MBtu (300 ppm NOX) for
boilers fired with bituminous coal and lignite and 0.3 lb. NOX/
MBtu (225 ppm) for subbituminous coal fired boilers.
Also considered was the:
c. Maximum practical reduction in NOX levels which could be realized
by the application of the Exxon Thermal DeNOx Process.
Two initial NOX levels were considered for each of the above MOX
targets: (i) uncontrolled and (ii) reduced by combustion modifications.
Thus, a total of 6 cases were established. This permitted a thorough
evaluation of the ability of the Thermal DeNOx Process to meet NOX target
levels and to establish a range of costs where practical.
In addition to the above six cases considered for all boilers, two
additional special analyses were performed for one boiler. One was a
temperature nonum'formity sensitivity study and the other studied the use
of hydrogen along with ammonia to achieve NOX reduction at reduced boiler
loads. The former was prepared because of the significant temperature
dependence of the Thermal DeNOx Process and the large temperature nonum'-
formity encountered in boiler flue gases. The latter was undertaken to
illustrate the functioning and costs of the Thermal DeNOx system when
hydrogen is used to accommodate load variations. An analysis comparing
the cost of Thermal DeNOx with the costs of extreme combustion modifications
in reaching NOX levels for the 0.3 to 0.4 lb. NOx/MBtu range was under-
taken. The limited availability of costs for combustion modifications for
reaching this NOX target level limited the scope of this comparison.
The following sections present the conclusions reached and our recom-
mendations for future work. This is followed by general background inform-
ation concerning the Exxon Thermal DeNOx Process including process chemistry,
engineering considerations, process costs and commercial scale experience.
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After the Process Background discussion is a section which provides Program
Detail including the boilers selected for study, initial and final DeNOx
reduction levels and cases evaluated, as well as information on the per-
formance prediction procedure used and the assumptions involved in cost esti-
mation. This is followed by a results section which provides the results and
conclusions of the six general cases studied plus results of the temperature
nonuniformity study and the hydrogen addition case. Cost data generated on
this program is presented in Appendix I. A report covering the pilot plant
scale test on coal firing, sponsored jointly by Exxon Research and Engineering
Company and the Electric Power Research Institute is presented as Appendix 2.
The work was performed by KVB Inc. which has also authored the coal study
report.
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SECTION 2
CONCLUSIONS
The performance of the Exxon Thermal DeNOx process was projected to
be essectially equivalent for all eight boiler types evaluated, even though
significant differences existed in flue gas temperature profiles and flow
path configurations among boilers. These differences resulted in the
selection of significantly different injection grid locations among the
boilers of different manufacturers. The analysis determined that the proposed
NSPS of 0.5 Ib./MBtu. for subbituminous coal and 0.6 Ib./MBtu for lignite and
bituminous coal could be met by all boilers considered using the Thermal DeNOx
Process. All boilers studied, except the cyclone boiler fired with lignite,
could meet the deep reduction targets of 0.3 and 0.4 Ib./MBtu using Thermal
DeNOx coupled with presently available combustion modifications.
It was projected that the ammonia injection grid location would not be
effected significantly by assuming a 50°C larger temperature range in the
injection plane than that used for baseline calculations. However, a temper-
ature range increase of this size would reduce DeNOx performance by 5 to 10
percentage points (e.g. from 50% to 40-45%). It was also found that overall
NOX removal costs increased when hydrogen (rather than multiple grids) was
used with only one grid to achieve effective DeNOx performance at other than
full boiler loads.
Other specific projections and conclusions were as follows:
All units could reach the proposed NOX NSPS using Thermal DeNOx
alone. Five of the eight units studied could also reach this level
using combustion modifications alone.
0 All units except one could meet the deep NOX reduction target when
Thermal DeNOx was used in combination with combustion modifications.
The one exception was the cyclone boiler fired with lignite.
Projected costs to reach the proposed NSPS from an uncontrolled base
level ranged from 0.25 mills/KW-Hr for the 250 MW CE boiler to a high
of 1.17 mills/KW-Hr for the lignite fired cyclone boiler. The average
cost for all boilers considered was 0.57 mills/KW-Hr, or 0.49 mills/
KW-Hr not including the cyclone boiler.
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Four of the eight boilers could reach the deep reduction target using
Thermal DeNOx alone. Costs ranged from 0.38 mills/KW-Hr to 0.83 mills/
KW-Hr for these boilers.
Projected costs to reach the deep reduction target using Thermal
DeNOx W1'th combusiton modifications ranged from 0.38 mills/KW-Hr
to 0.51 mills/KW-Hr, with the average being 0.44 mills/KW-Hr for the
seven boilers reaching the target level.
NOX reductions ranging from 62% to 76% and averaging 70% relative
to an uncontrolled base case could be achieved using Thermal DeNOx
at a maximum practical level in combination with combustion modifi-
cations. NOX levels in the 0.20 to 0.23 Ib. NOx/MBtu range could be
realized for most of the boilers. Costs ranged from 0.55 to 1.14
mills/KW-Hr and averaged 0.68 mills/KW-Hr for all boilers studied.
With the lignite boiler excluded, the range was 0.55 to 0.67 mills/
KW-Hr and the average was 0.61 mills/KW-Hr.
The costs for onsites and the carrier were found to be proportional
to boiler size.
The total ammonia reagent costs for all cases, normalized for the
amount of NOX removed expressed as N02 (ANOX)» were nearly equal for
all eight units studied at $0.09/lb. ANOX. This parameter was con-
sidered to be a good overall judgment criterion of the chemical
efficiency and economic efficacy of the Thermal DeNOx process.
The Exxon Thermal DeNOx Process was considered to be equally amenable
to all units studied.
The costs for reaching NOX levels in the 0.3 to 0.4 Ib./MBtu range
were compared for Thermal DeNOx and combustion modification. The
costs of most conventional combustion modifications and combinations
thereof were lower than that of Thermal DeNOx. Extreme NOX reduction
methods such as derating or staged combustion that incurred derating
would be more expensive. Derating would not generally be used as a
NOX reduction technique.
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SECTION 3
RECOMMENDATIONS
The primary recommendation resulting from this study is that the
Exxon Thermal DeNOx Process be tested on a coal fired utility boiler.
The boilers of the four major utility boiler manufacturers have been found
to be approximately equally amenable to the Thermal DeNOx Process. After
the selection of an appropriate candidate boiler, the same type of per-
formance and cost analyses presented here must be prepared. Temperature and
velocity profile measurements in the boiler heat transfer region are then
required to verify grid placement and performance estimates. After instal-
lation and startup of the Thermal DeNOx system a careful measurement and
evaluation program will be needed to assess DeNOx performance, cost and
determine any possible side effects which result from the use of the
Thermal DeNOv Process.
A
In undertaking this demonstration, a high level of attention should be
accorded to those factors which could reduce the overall effectiveness of
the Thermal DeNOx Process on coal fired utility boilers, or could have
adverse side effects on boiler operation or the environment. These factors
include:
Ammonia.and by-product emissions
Effect of slag formation and fouling on DeNOx reaction zone temper-
atures, and on resulting DeNOx performance.
Effective DeNOx performance under differing boiler load conditions.
Effect of deposition of ammonium sulfates on metal surfaces and on
electrostatic precipitator performance.
0 Compatibility of Thermal DeNOx system elements with coal ash levels
and with soot blowing equipment and procedures.
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SECTION 4
PROCESS BACKGROUND
This section provides general backgound information on the Exxon
Thermal DeNOx Process. Presented is information on the chemistry of the
process, engineering considerations, process costs discussed in general
terms and a brief summary of commercial scale experience.
CHEMISTRY OF THE PROCESS
The process chemistry relies on the selective reaction between NH3
and NOX to produce nitrogen and water. The reaction requires the presence
of oxygen and proceeds within a critical temperature range. The overall NO
reduction and production reactions are summarized in equations (1) and (2),
respectively:
NO + NH3 + 1/4 02 -» N2 + 3/2 H20 (!)
NHs + 5/4 02 + NO + 3/2 H20 (2)
In typical flue gas environments, the NOX reduction shown as equation
(1) dominates at temperatures around 950°C (1740°F). At higher temperatures,
the NOX production reaction shown as equation (2) becomes significant, and
it dominates at temperatures over about 1000°C (1830°F). As temperatures
are reduced below about 900°C (1650°F), the rates of both reactions slow,
and the ammonia flows through unreacted.
The following chain reaction cycle was proposed by Dr. R. K. Lyon of
Exxon Research for the NH3-NO-02 reaction system (2):
+ NO -» N2 + H + OH (3)
NH2 + NO -f N2 + H20 (4)
H + 02 »> OH + 0 (5)
0 + NH3 -» OH + NH2 (6)
OH + NH3 * H20 + NH2 (7)
H + NHa -» H2 + NH2 (8)
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This chain reaction mechanism is sufficient to explain qualitatively the
observed reduction of NO by NH3 in the presence of CL.
In practice, ammonia is injected into either boiler cavities or tube
banks or both. Exxon has shown that in certain applications the practical,
working potential of the Thermal DeNOx Process under varying loads and NOX
levels can be achieved through ammonia injection alone. Exxon Research has
found that hydrogen can be used to shift the DeNOx temperature window to
lower levels. The magnitude of this shift is mainly a function of the amount
of H2 injected relative to the NHs. At Hg/NHs ratios on the order of 2:1,
the NOX reduction reaction can be forced to proceed rapidly at 700°C (1290°F).
By judiciously selecting the H2/NH3 injection ratio, flue gas treatment can
be accomplished over the range of 700-1OOQOC.
In addition to temperature, the process is also sensitive to initial NOX
and NH3 concentrations. The NHs injection rate is generally expressed as a
mole ratio relative to the initial NOX concentration. Other variables
affecting performance are excess oxygen and available residence time at the
reaction temperature.
The issue of possible pollutant by-products (HCN, N20, CO, $03 and
NH4HS04) has been addressed by Exxon Research studies. Hydrogen cyanide can
be produced only if hydrocarbons are present in the Thermal DeNOx reaction
zone. Under normal conditions, hydrocarbons are absent from this zone. As
regards N20 production, it represents only one to two percent of the NOX
reduced. The Thermal DeNOx Process does not generate CO by reducing C02-
However, CO oxidation is inhibited by NHs, so tha* if CO is present, it would
be emitted unreacted into the atmosphere. This effect is of no consequence
under normal operating conditions for most boilers, as CO oxidation is com-
plete before the NH3 injection point.
Detailed laboratory experiments have shown no interaction between the
Thermal DeNOx Process and sulfur compounds in the high temperature flue gas
regions. That is, sulfur or its oxides do not interfere with the NH3-
NOX-02-H2 chemistry. Additionally, ammonia injection has been shown to
cause neither additional homogeneous nor additional heterogeneous oxidation
of S02 to S03.
To the extent that the thermal reduction of NO leaves some NH3 unreacted,
and as the combustion gases cool, NHs can react with SOs and H20 to form
ammonium sulfates. Ammonium bisulfate is a viscous liquid at air heater
temperatures. Based on laboratory and commercial tests, these sulfates do
not appear to create either severe corrosion or unacceptable air heater foul-
ing problems when Thermal DeNOx is used in accordance with its design speci-
fications. Long term tests conducted in two oil-fired boilers by Tonen
Sekiyu Kagaku K.K. in Kawasaki, Japan, revealed these highly water-soluble
deposits could be removed by waterwashing the air heaters. Although long
term data are very limited, the frequency of waterwashing in these Japanese
installations approaches two to three times per year. Of course, only
through a Thermal DeNOx demonstration on a coal fired boiler can the washing
requirement be quantified.
8
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ENGINEERING CONSIDERATIONS
When applying the Thermal DeNOx Process to commercial equipment,
performance is generally limited by the extreme temperature sensitivity of
the reaction and its dependence on the local concentrations of reactants,
NH3, NOX, 02 and Ho. The Exxon technology provides a means of adapting
the chemistry requirements to industrial equipment environments, and NOx
reductions up to about 60% can be achieved by the use of Thermal
DeNOx technology in existing boilers. Application to new, grass-roots
designs is usually easier because the internal configuration of the high
temperature zone can be adjusted to complement the process demands.
The Thermal DeNOx Process utilizes proprietary Exxon gas phase mixing
technology to rapidly and efficiently mix the small volume of reagents with
the hot flue gas. Correct distribution of reactants is required because of
non-linearities in the reaction rates. Locally high concentrations of NH3
will decrease the maximum attainable NOX reduction and will also result in
the breakthrough of unreacted ammonia.
Accommodating flue gas temperature varations is important if high
DeNOx rates are to be achieved. Not only does the system have to accommo-
date flue gas temperature changes caused by normal load and operating
variations, but it also must allow for fluctuations across the reaction
zone caused by non-uniformities in flow and heat transfer. It follows,
therefore, that a case-by-case evaluation of flue gas temperatures and
local conditions is required for the application of Thermal DeNOx for each
installation considered.
Initially, ammonia was injected only into boiler cavities, boiler
regions between tube banks, which can be considered to be isothermal to a
first approximation. Subsequent experimentation by Exxon Research has
shown the feasibility of injecting ammonia into boiler tube bank regions as
well. Thus, satisfactory NOx reduction performance can be obtained by
locating the injector grid in either the boiler cavity or tube bank. The
ability to inject ammonia at virtually any post-combustion boiler location
where temperatures range from 760°C to 1000°C has substantially increased
the flexibility of the Exxon Thermal DeNOx process.
The temperature in the post-combustion zone of a boiler can be shifted
by changes in boiler load. For example, as load is reduced from full to 50%,
the temperature for optimum Thermal DeNOx will shift toward the fire box.
Depending on the magnitude of this shift, more than one ammonia injection
grid may be required in order to obtain DeNOx coverage over the range of
practical boiler loads. Thus, one grid may be adequate for boiler loads be-
tween 100% and 70% while another would cover the 70 to 50% load range. It
must be noted, however, that the use of hydrogen with its ability to lower
the effective DeNOx temperature window could permit effective DeNOx over
practical boiler loads with only one grid. In other cases, both hydrogen
addition and the use of multiple grids may be required to accommodate load
changes. A specific case was considered in which the costs of a single grid
ammonia-hydrogen system were compared with the costs of dual grids used with
ammonia alone. y
-------
PROCESS COSTS
The costs associated with the Thermal DeNOx Process are sensitive
to the particular circumstances of the application. Factors influencing
cost include initial NOX concentration, reduction target, compatibility
of the boiler design and operation, and local price and availability of
chemicals and utilities.
As an example, consider applying the process to a 300 MWe oil-fired
utility plant with an initial NOX level of 225 ppm (about 0.3 Ib. NOX/M
Btu fired). Assume the boiler geometry and operating conditions provide a
temperature in the reaction zone which does not require H2, and that for
a 50% NOx reduction target, an approximate NH3/NOX injection ratio of 1.0/1
is feasible. Thus, Thermal DeNOx will have the following estimated
operating costs:
(a) NHs @ 1.0 mole per mole NOX (assume 170 $/ton) = 0.9 t/M Btu
(b) Utility air 0 210 SCF per M Btu fired (assume 0.005
-------
are generally at target levels over the full range of operating conditions
because of the reduced NOX production at lower loads. Results from six
demonstrations are shown over their range of operating conditions as a
function of flue gas temperature in Figure 4-1. Hydrogen was used along
with" ammonia to obtain most of the data shown in Figure 4-1,
11
-------
70
60
D
50
o
\-
o
3
o
LU
X
o
40
30
20
10
700
cP
o
SIZE
25 t/hr
70 t/hr
O 120 t/hr
DESCRIPTION
Package Boiler
Industrial Boiler
A 100 MWe ) ....... D .,
T 100 MWe I Utlllty Boiler
D i en KM } Crude Heaters
v 150 kbbl/d j
1
_L
800 900
FLUE GAS TEMPERATURE, °C
Figure 4-1 Performance of Thermal DeNOx systems
in commercial applications.
1000
12
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SECTION 5
PROGRAM DETAIL
This section provides information regarding the boilers selected for
study in this program. The NOX reduction cases are discussed, and the
initial and final NOX levels for each case are noted. Also provided is
information on the Thermal DeNOx Performance Prediction Procedure utilized
in determining the effectiveness of the Thermal DeNOx Process in each case
studied. The assumptions used for formulating the cost estimates for the
Thermal DeNOx Process are noted and other cost estimation information is
provided for the Thermal DeNOx process as well as for combustion modifi-
cations.
BOILERS SELECTED FOR STUDY
This EPA-sponsored analysis has determined the applicability of Thermal
DeNOx to representative coal fired boilers of different manufacturers,
firing types, boiler sizes and coal types. The boilers/sizes/firing types
selected for study are shown in Table 5-1.
The boilers selected were within their size ranges among the most
commonly occurring in the U.S. power generation industry. Four of the
boilers fire bituminous coal, three subbituminous, and one lignite. One
or more boilers from each major boiler manufacturer has been considered.
One boiler in the 330-350 MW range from each manufacturer has been studied.
NOX REDUCTION CASES
This subsection notes the two sets of final NOX target levels which
were used as well as the two initial NOX levels which were assumed for
baseline-uncontrolled operation and for combustion modifications. The four
resulting cases plus two additional cases for maximum practical NOX
reduction are also noted.
Final NOX Levels
Two sets of final NOX reduction levels or targets were selected for
this study. One group included a trim to the proposed New Source Perform-
ance Standards (NSPS). The other, a deeper reduction to low levels of NOX,
The proposed NSPS for NOX from coal firing are categorized by coal
type. These standards are shown below in both Ibs./MBtu and in ppm. In
this case, the conversion used was NOX, Ibs./MBtu = ppm NOX (@ 3% 02)
x 0.00133 (4,5).
13
-------
TABLE 5-1. BOILERS SELECTED FOR STUDY
Boiler
Manufacturer
Babcock and
Wilcox
Babcock and
Wi 1 cox
Babcock and
Wilcox
Combustion
Engineering
Combustion
Engineering
Foster Wheeler
Foster Wheeler
Riley Stoker
Boiler Type
Front Wall
Horizontally
Opposed
Cycl one
Tangential
Single Furnace
Tangential
Front Wall
Horizontally
Opposed
Turbo Furnace
Boiler
Size, MW
130
333
400
350
800
330
670
350
Coal Type
Subbituminous
Bituminous
Lignite
Bituminous
Subbituminous
Bituminous
Subbituminous
Bituminous
Proposed NSPS
Coal Type
Bituminous
Subbituminous
Lignite*
Ibs./MBtu
0.6
0.5
0.6
450
375
450
* The proposed standard for cyclone firing of North and
South Dakota and Montana Lignite is 0.8 Ibs/MBtu (600 ppm).
This specific case will not be considered here.
The final NO targets were selected to provide an assessment of
Thermal DeNOx performance capabilities and represent a deep reduction in
NOX emission levels. These NOX levels were also assumed to be a function
of the coal type burned and were:
14
-------
Deep Reduction Targets
Coal Type Ibs./MBtu ppro
Bituminous 0.4 300
Subbituminous 0.3 225
Lignite 0.4 300
Initial NOX Levels
The initial NOX levels utilized in undertaking this study were those
which are characteristic of the selected types and sizes of boilers firing
the coal types specified. Most of the initial values were derived from
data obtained by Exxon Research and Engineering Company on the program
"Field Testing: Application of Combustion Modifications to Control
Pollutant Emissions from Power Generation Combustion Systems" sponsored
by EPA under Contract No. 68-02-1415 (4). Additional data were furnished
by the boiler manufacturers.
NOX levels were extrapolated for each boiler studied under (a) re-
duced load and (b) with the application of combustion modifications. In
formulating these NOX levels, two generalizations based on field test data
(4_) were utilized:
(1) Reducing load by 25% from full load lowers NOX emissions by 10%.
Reducing load by another 25%, to 50% load lowers NOx emissions a
total of 20% in ppm,
(2) The application of combustion modifications (CM) lowers NOX
emissions from an uncontrolled level by 40% at each load. CM
are less effective than this on cyclone boilers. For the cyclone
boiler studied, CM were assumed to reduce NOX emissions by 10%
from the base case at each load.
A variety of combustion modification techniques are available for
most boiler types considered. These generally can be used individually
or in combination to achieve the 40% NO^ reduction noted above. For
example, low NOX burners which are applicable to front wall and horizontally
opposed fired boilers have been introduced relatively recently and Exxon
Research has shown that 40% NOX reductions are possible relative to an un-
controlled case in which conventional burners are used (4_). Low excess air
firing coupled with the staging of burners are two techniques also applicable
to these boiler types. Low excess air firing can reduce NOX emissions from
cyclone fired boilers. Low excess air firing plus the use of overfire air
ports are successful in reducing NOX emissions with tangential firing, a
combustion system which is inherently a low NOX producer. Overfire air
ports plus air vane direction can be used to reduce NOX emissions in
turbofurnace boilers.
15
-------
Cases Established
As was noted above, one group of NOX reduction levels include a trim
to 450 ppm NOX (for bituminous coal and lignite firing) and 375 ppm NOX
(subbituminous). These levels are the proposed NSPS levels for coal firing.
For trimming, two cases arise:
Case 1: Combustion Modifications (CM) cannot be used and the intial NOX
level is the uncontrolled baseline NOX level.
Case 2: CM can be used with the result that the initial NOX levels would
be reduced.
The other group of NOX reduction levels specifies a deep reduction to 300 ppm
(bituminous and lignite) and 225 ppm (subbituminous). Two additional cases
arise:
Case 3: CM cannot be used.
Case 4: CM can be used thereby reducing the initial NOX level.
As can be seen, the above define the best case and the worst case for
the two general target NOX levels. Thus, the estimates produced resulted
in a range of costs rather than in one specific level of cost for the trim
cases and for many of the deep reduction cases. This should be of greater
utility than one specific cost level. (It might be argued that no boiler
of the types considered here could be so inflexible as to be totally
incapable of accommodating combustion modifications of some type. This is
probably true. However, for this evaluation we assumed this worst case.)
The actual N0« levels investigated are shown in Table 5-2. This table
illustrates that in certain cases, the target NOX levels are achievable
using combustion modifications alone.
In addition to these cases to establish a range of costs, two additional
cases have been considered. These cases represent the maximum NOX reduction
that can be achieved on a practical basis with the Thermal DeNOx Process.
(Grid placement is assumed to be the same as in the other cases studied.)
The two new cases which can be formulated are:
Case 5: Maximum NOX reduction attainable with an ammonia to initial NOX
molar ratio of 1.5.
Case 6: Maximum NO reduction attainable with NH3/NOI = 1.5 with combustion
modifications.
In both cases 5 and 6, the final NOX levels attained may be either
greater than or less than the target NOX levels in the prior cases.
Cost estimates for NOX reduction were performed for full load only.
16
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TABLE 5-2. INITIAL AND FINAL NOX LEVELS
FOR BOILER/COAL COMBINATIONS
Boiler
Firing Method
Manufacturer and Fuel
8&W FW
Subbituminous
B&W HO
Bituminous
B&W Cyclone
Lignite
CE T-Single Furnace
Bituminous
CE T-Twin Furnace
Subbituminous
FW FW
Bituminous
FW HO
Subbituminous
RS Turbo Furnace
Bituminous
MM Case
130 1
2
3
4
333 1
2
3
4
400 1
2
3
4
350 1
2
3
4
800 1
2
3
4
330 1
2
3
4
670 1
2
3
4
350 1
2
3
4
100%
Initial
500
300
500
300
700
420
700
420
1000
900
1000
900
500
450
500
450
530
375
530
375
850
510
850
510
700
420
700
420
700
420
700
420
Load
Final
Target
375
375*
225**
225
450
450*
300**
300
450**
450
300**
300**
450
450*
300
300
375
375*
225**
225
450
450
300**
300
375
375
225**
225
450
450*
300**
300
75%
Initial
450
270
450
270
630
380
630
380
900
810
900
8TO
450
400
450
400
480
340
480
340
770
460
770
460
630
380
630
380
630
380
630
380
Load
Final
Target
375
375*
225
225
450
450*
300**
300
450
450
300**
300**
450*
450*
300
300
375
375*
225**
225
450
450*
300**
300
375
375*
225**
225
450
450*
300**
300
50X
Initial
400
240
400
240
560
340
560
340
800
720
800
720
400
360
400
360
425
300
425
300
680
410
680
410
560
340
560
340
560
340
560
340
Load
Final
Target
375
375*
225
225*
450
450*
300
300
450
450
300**
300**
450*
450*
300
300
375
375*
225
225
450
450*
300**
300
375
375*
225
225
450
450*
300
300
* NOX level is either below the target level or can be reached using combustion modifi-
cations alone.
** MOX level cannot be reached with Thermal QeNOx alone, assuming 50% NOX reduction.
17
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THERMAL DeNOx PERFORMANCE PREDICTION PROCEDURE
This section provides some background information on the Performance
Prediction Procedure used to estimate the NOX reduction achievable using
the specified initial NOX levels and final NOX targets. The sequence in
applying the predictive procedure which leads up to the cost estimation
steps is also discussed. This is followed by some of the assumptions used
in undertaking the performance prediction.
The selection of the locations where ammonia will be injected is
based on a number of factors which include: flue gas temperature and
conditions, flow path geometry, the reaction time available and the suita-
bility of the reaction zone with repect to its dimensions and configuration
injector grid. A Performance Prediction Procedure developed by Exxon
Research and Engineering Company was used to determine the locations of the
ammonia injection grids.
The Exxon Performance Prediction Procedure is a multistep calculation
procedure which utilizes and/or determines the above noted factors. The cal-
culation procedure can forecast the percent reduction in initial NOX level
which would result from the location of an ammonia injection grid at any num-
ber of locations along the flue gas path. The Performance Prediction
Procedure is based on fundamentals combined with pilot and commercial scale
experience. For this EPfi-sponsored study program the required temperature
and dimensional information were supplied by the boiler manufacturers. In the
case of an actual installation, after the tentative selection of the
location(s) of one or more grids using the Exxon procedure, an experimental
program would be conducted to measure temperature, flow and concentration
distributions in the reaction zone. This information would then be used to
confirm or adjust as required the injector location selected and would be
utilized as input for the final injector design.
The sequence of events in applying the Thermal DeNOx Performance
Prediction Procedure leading up to the cost estimating steps is listed
below.
1. The Exxon Thermal DeNOx Performance Prediction Procedure was applied
using data supplied by the boiler manufacturers.
2. The effectiveness of the Thermal DeNOx process was determined for
most boilers studied at 3 loads: 100%, 75%, and 50%. For each boiler
and each load, two levels of NHa injection were considered. These
levels were expressed as a molar ratio of NHo to the initial NOX level
(NOI). The two levels possessed NH3/NOI ratios of 1.5 and 1.0.
3. Two initial NOX levels (both with and without combustion modifications)
were established from data obtained by Exxon Research and Engineering
Company on the program, "Field Testing: Application of Combustion
Modifications to Control Pollutant Emissions From Power Generation
Combustion Systems" sponsored by EPA under Contract No. 68-02-1415.
Some additional data were supplied by the boiler manufacturers.
18
-------
4. Two sets of final NOX levels were utilized. These were: the proposed
New Source Performance Standards (trimming case) and a deep reduction
case. The use of two initial and two final NOX levels permitted a range
of costs to be established for certain boilers.
5. Two ammonia injection grid locations were selected for each boiler
studied based on the results of the Performance Prediction Procedure.
Thus, for each of the two grid locations, the percent NOX reduction
resulting from the use of two levels of NH3 was determined.
6. For each grid location, a plot was made of percent NOX reduction
vs. NH3/NOI molar ratio. The third point was assumed to be the origin,
zero. Thus, for each boiler, two curves were generated, one for each
of the two injector locations. Both lines terminated at the origin.
From these plots the quantity of NH3 required to reach the specified NOX
reduction target could be determined.
Some of the assumptions used in application of the Performance Predic-
tion Procedure are noted below.*
1. There are two injector locations, one designed to serve two boiler
loads, and the other to serve one load. The combination-load grid
will operate for either the 50 percent/75 percent or the 75 percent/
100 percent.load combination, and the single load grid will operate for
either the 50 percent or the 100 percent load.
2. The combination-load grid is located where the crossover of the
performance curves is a maximum. The single-load grid is then
located where the performance curve peaks for the remaining load.
An exception was made for the CE boilers where the combination-
load grid (50/75 percent load) was placed at the exit of the firebox,
and the single-load grid (100 percent) was placed at the peak of the
performance curve. For this screening study, performance calculations
were done at the upstream boundary of each flue gas flow path
segment and a smooth curve was drawn through the predicted points.
The length of the cavity upstream of the first tube bank was set at
150 mm for the B&W 130 MW and B&W 400 MW boilers.
3. The carrier is air.
4. The carrier temperature is 80°C at the feed pipe entry point into the
flue gas duct.
5. Flue gas pressure is 1 atmosphere.
Certain aspects of the Thermal DeNOx Performance Prediction Procedure are
considered to be proprietary in nature and are not described in this
report.
19
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COST ESTIMATES
This section provides details of how the cost estimates in this pro-
gram were performed. Provided is specific information regarding ammonia
handling facilities, air compressors and the on-sites. The assumptions
used in the estimation of Thermal DeNOx costs are noted as are details for
the cost estimates formulated for combustion modifications.
Thermal DeNOx Cost Estimates
The cost estimates presented here are designed to illustrate the costs
associated with the Thermal DeNOx Process itself. The techniques and proce-
dures used in producing these cost estimates were the same as would be applied
to a more completely defined project. In the cases considered here the pro-
jects were not completely specified with respect to a number of factors which
could have an impact on costs. The Process was assumed retrofit-installed on
eight typical representative coal fired utility boilers. It should, however,
be realized that each candidate boiler for the Thermal DeNOx Process must be
considered on an individual basis from both performance and cost viewpoints.
In general, the costs presented here emphasize the costs of the Process it-
self. Certain costs which may be associated with the Process such as licens-
ing fees and certain preliminary engineering and testing are not included.
Cost estimates were prepared for three individual elements of the
DeNOx facilities: ammonia handling facilities, air compressors, and the
"on-sites" which include the ammonia injection grids. The costs are pre-
sented as of the second quarter of 1977 and assume a U.S. Gulf coast loca-
tion.
Costs for three sizes of ammonia handling facilities were estimated
and the costs for intermediate sizes were interpolated. The three examples
assumed ammonia consumption at the rates of: (Example 1) 330 lbs./hr.,
(2) 1000 lbs./hr., and (3) 3000 lbs./hr. Estimated were the costs of line
sizes, drum sizes, pump sizes, etc. with all facilities being commensurate
with the rated demand.
The first two examples assumed receipt of ammonia in pressurized tank
trucks and the use of a single storage drum. Example 3 assumed receipt in
pressurized rail cars and the use of three storage drums. The unloading
pumps and lines were similar for all cases and the storage was sized for
seven days. The ammonia storage drums were designed to operate with a mini-
mum temperature of 50°F and were uninsulated. Ammonia vapor was assumed
to be withdrawn from the storage drums at 90 psia and metered using up to
twelve lines as dictated by the case in question.
The total breakdown in terms of material and labor is presented
below in thousands of dollars for each case. To these costs were applied
a total erected cost multiplier of 1.43 which includes field labor, over-
head and burden. This value is based on our actual historical data for
construction occurring on the U.S. Gulf Coast during the second quarter of
1977, the area and period selected for all cost estimates.
20
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Example Number 1 2 3
Direct Material, k$ 147 195 422
Direct Labor, k$ 53 55 93
Total M&L, k$ 200 250 515
Total Erected Cost, k$ 286 358 736
As was noted above, the costs for intermediate sizes were interpolated from
these total erected cost values.
The use of air as a carrier requires the installation of air com-
pressors. For the same three examples noted above, sizes of compressors
required were (1) 1000 SCFM, (2) 6000 SCFM and (3) 20,000 SCFM. Compressor
costs were obtained from vendor quotes. Other material costs were associ-
ated with buildings, concrete, piping, structural steel, instruments, paint,
etc. The breakdown in terms of direct labor expressed in thousands of
dollars is presented below. Again, the total erected cost multiplier of
1.43 was applied to these values resulting in the total erected cost.
Costs for intermediate sizes were interpolated from these cost values.
Example Number 123
Direct Material, k$ 195 360 530
Direct Labor, k$ 35 45 60
Total M&L, k$ 230 405 590
Total Erected Cost, k$ 330 580 843
The costs for on-site facilities ("onsites") including the costs of
grids are based on our historical experience in the construction of such
facilities.
The assumptions used in cost estimation are noted below:
1. Fixed costs are total erected costs, 2nd quarter 1977, U.S. Gulf Coast,
no escalation and no contingency included.
2. Reagent fixed costs include NH3 storage vessel, vaporizer, and piping.
3. Carrier fixed costs include air compressor and piping.
4. Onsite fixed costs include two injector grids, instrumentation and
controls.
5. Operating costs are for DeNOx system operation at 100 percent load.
6. The NH3/NOI ratio required to obtain a specified NO,, reduction is
calculated by linear interpolation between the NHs/NQI ratios of 1.5,
1.0 and the origin, 0. These point constituted the performance curve
used. NH3/NOI =1.5 is the maximum NH3 rate considered. No extrapol-
21
-------
ation to higher rates was performed. In practice, some molar ratios
used were between 0 and 1.0 and other were between 1.0 and 1.5.
7. Calculated NH3 consumptions are based on nominal initial NOX levels
and flue gas flow rates. No adjustments have been made for variations
in excess air levels and flue gas moisture content.
8. Reagent operating cost is based on an NHs cost of $85.00 per 1000 Ib.
9. Carrier rate for cost calculations has a maximum value of 1.5% of the
flue gas rate. The total carrier rate is the sum of the operating grid
rate and the rate used for cooling the idling grid.
10. Carrier operating costs are calculated as follows: Air compressor
power requirements are 1100 HP (820.6 KW) per 10,000 SCFM. Electri-
city cost is 0.03 $/KW-Hr. Resulting carrier operating cost is $0.41
per 10,000 SCF.
11. Annual fixed charges are taken as 20% of investment. This figure
includes finance costs and maintenance. Annual service factor is
80% of full load.
12. No licensing fees or royalties are included.
13. $/MM-Hr. is equivalent to mills/KW-Hr.
$/MW-Hr. = 10 times $/MBtu assuming a heat rate of 10,000 Btu/KW-Hr.
The equations used in undertaking the Thermal DeNOx cost estimates
are shown in Table 5-3.
Combustion Modification Cost Estimates
The costs for combustion modifications were derived from information
furnished by Acurex-Aerotherm assembled under EPA contract (6). The costs
cover retrofit installation only. The three techniques based on combustion
modifications were Low NOX Burners (LNB), Overfire Air Ports (OFA), and
Low Excess Air Firing (LEA). Derating was also considered. Flue gas
recirculation was not considered as this technique is not overly compatible
with coal fired boilers. It was assumed that for all boilers, the use of
LNB or OFA coupled with LEA would be sufficient to achieve the stipulated
NOX reduction level.
For cost purposes, it was assumed that LEA firing had no net cost
since (1) this firing mode can be implemented relatively cheaply with low
capital and operating costs, (2) a fuel savings and cost credit will result
in most cases after LEA firing is implemented, and (3) many utility oper-
ators are already using LEA firing.
The general assumptions used by Acurex-Aerotherm included:
- Operation for 7000 hours/year at or near full load
- Unit five years old
22
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TABLE 5-3. THERMAL DeNOv COST CALCULATIONS
A
Initial N0«
(ppm)
(ppm)
Input from Table 5-2
t Target NOV
Input from Table 5-2
Flue Gas Rate (kL /Hr)
Input from Boiler Manufacturers
NOX Reduction Required
- Percent
= (1-Target N0x/Initial NOX) x (100)
Initial NOy-~
= [I
]05
28.8
x (1000.) x
Reagent Rate
- NH3/NOi (Molar Ratio)
- H2/NH3 (Molar Ratio)
- NH (kLb/Hr)
- H2 (kLb/Hr)
From Thermal DeNOx Performance Prediction Procedure
Flue\
te ~RF/ x \ NH7/ x VTTTo
^ Rate ~RF
Carrier Rate (Air)
- (SCFM Per Nozzle)
- (SCFM Total)
x (0.484)=(9.7)x(0.484)=4.69 fjjj
Percent
Load
(SCFM Per Nozzle) x (No. Nozzles)
Operating Cost
- MH3 ($/Hr)
- Carrier ($/Hr)
- Total Operating Cost ($/Hr)
I J it£J y ($§L\
\Rate Hr / x ULb/
_ [Carrier <-rrM\ ( 1 ^
- V Rate SCFMy x tooo7
TW SCFn
,)
= NH3 + Carrier
/0.746 KW) /$0.03)
\ HP7 x \KW-Hr/
Fixed Cost
- NH3 (k$)
- On-Sites
- Carrier (k$)
- Total (k$)
= Exxon Cost Estimating
= Exxon Cost Estimating
= Exxon Cost Estimating
= NHg + On-Sites + Carrier
NOTE: See assumptions Used in Cost Estimation for Further Details
23
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THERMAL DeNOx COST CALCULATIONS (CONT'D)
Equivalent Costs
- Cost ($/Lb AN02)
Operating Cost
Yearly Fixed Cost
Total Cost
- Cost ($/MW-Hr)
Operating Cost
Yearly Fixed Cost
Total Cost
Total Operating Cost ($/Hr)/NOx Reduction Required
(Lb AN02/Hr)
Total Fixed Cost (k$) x /oil/Sit?;2^ x N0x Reduction
(Lb AN02/Hr) (24}(365)(O.B)
Operating Cost + Yearly Fixed Cost
Total Operating Cost ($/Hr)/MW rating
Total Fixed Cost (k$) x (24)(36^(0% * M" rating
Operating Cost + Yearly Fixed Cost
24
-------
- Remaining life of 25 years for accounting purposes
Indirect operating costs include depreciation expense, taxes, cost of
capital and insurance. These costs are thus very similar to the capital
costs used by Exxon and will be designated as such. Direct operating costs
depend somewhat on the nature of the combustion modification technique
but include any extra costs for fan power where used, increased maintenance,
and a change for decreased unit efficiency where that occurs. These costs
are quite similar to the operating costs used here and will be designated
as such.
Acurex-Aerotherm established two different costs for the retrofit
installation of OFA ports. These costs depended upon the boiler firing
type and were lower for tangential than for wall fired units. For cost
estimation purposes, it was assumed that the costs of installing overfire
air ports in a Turbo furnace boiler was the same as for a wall fired
unit. The LNB and OFA costs established by Acurex-Aerotherm in units of
$/KW-Yr. were converted to mills/KVI-Hr. in order to conform to the other
data presented herein. The values in both units are presented in Table 5-4.
TABLE 5-4. COSTS FOR COMBUSTION MODIFICATIONS
ESTABLISHED BY ACUREX-AEROTHERM
Operating
Capital
Total
Overfire Air Ports
Low NOx Burners
Tangential
Turbo
$/KH-Yr mills/KM-Hr $/KM-Yr mills/KM-Hr $/KW-Yr mil is/KM-Hr
0.40
0.01
0.05
0.06
0.32
0.21
0.53
0.05
0.03
0.08
0.52
0.16
0.68
0.08
0.02
0.10
The derating of a boiler will also result in reduced emissions of NOX.
As will be apparent, derating is very expensive and consequently would be
used only as a last resort when other combustion related procedures cannot
achieve target NOX levels. Derating will not be considered for use in
association with Thermal DeNOx, although it will be utilized for comparative
purposes in a subsequent section.
The basic costs for derating were also furnished by Acurex-Aerotherm
(6). Acurex-Aerotherm considered staged combustion in which burners would
be removed from service, thereby derating the boiler by an amount equal to
20% of capicity. The operating cost thus is largely the purchase of make
up power which Acurex-Aerotherm assumed was purchased at 2.5<£/KW-Hr. Acurex-
Aerotherm believes that this value approximates the cost of generating
electricity. Transmission costs were assumed to be minimal at O.U/KW-Hr
yielding a total cost for purchased power of 2.6<£/KW/Hr. Other factors
included in the operating cost are a fuel credit for fuel not used and a
very minor loss in efficiency. Aerotherm estimated the operating cost to
be $24.78 KW/Yr.
25
-------
The capital cost figure determined by Acurex-Aerotherm reflects the
lost capacity. The boiler has been financed on the basis of full rated
output but because the boiler has been derated either, (a) a longer period
will be required to recover this financial quantity or Cb) an increased
rate of recovery over the same period must be used. The capital charge
thus represents a lost capital charge.
The Acurex-Aerotherm values were converted to the bases used here and
the results are presented in Table 5-5.
TABLE 5-5. COSTS FOR BOILER DERATING
Derate by 20% - Burners out of Service
$/KW-Yr
Operating
Capital
Total
30.12
n>ms/KH-Hr
4.30
It was assumed that either low NOX burners or the use of overfire
air, perhaps in combination with LEA firing as required, were sufficient to
reach the initial NOx level designated. The combustion modification which
was used for each boiler type is shown in Table 5-6.
TABLE 5-6. COMBUSTION MODIFICATIONS USED TO
REDUCE INITIAL NOX LEVELS
Boiler
Manufacturer
Size
Combustion Modification
B & W
CE
F-U
RS
130
333
400
350
800
330
700
700
Low NOX Burners
Low NOx Burners
Low NOX Burners
Overfire Air
Overfire Air
Low NOX Burners
Low NOX Burners
Overfire Air
26
-------
SECTION 6
RESULTS AND DISCUSSION
The feasibility and costs for using the Exxon Thermal DeNOx Process on
eight representative coal fired utility boilers was established for several
target NOV levels. These target NOX levels included:
A
a. Reduction by trimming to the proposed New Source Performance
Standards (NSPS) of 0.6 Ib NOx/MBtu (450 ppm NOX) for bituminous
and lignite fired boilers and 0.5 1b NOx/MBtu (375 ppm NOX) for
boilers fired with subbituminous coal.
b. Deep reduction in NOX levels to 0.4 Ib NOx/MBtu (300 ppm NOX)
for boilers fired with bituminous coal and lignite and to 0.3 Ib
NOx/MBtu (225 ppm) for subbituminous fired boilers.
In summary, this analysis projected that the proposed NSPS could be
met by all boilers studied using the Thermal DeNOx Process alone and that all
boilers, except the cyclone boiler fired with lignite, could meet the deep
reduction target using Thermal DeNOx coupled with combustion modifications.
The performance of the Thermal DeNOx process was considered to be essentially
equivalent for all boilers evaluated even though significant differences
existed in flue gas temperature profiles and flow path configurations among
boilers. These differences resulted in the selection of significantly
different injection grid locations among the boilers of different manu-
facturers.
It was projected that the ammonia injection grid location would not be
affected significantly hy assuming a 50°C larger temperatue range in the
injection plane than that used for baseline calculations. However, a tempera-
ture range increase of this size would reduce DeNOx performance by 5 to 10
percentage points (e.g. from 50% to 40-50%). It was also found that total
NOX removal costs increased when hydrogen (rather than dual grids) was used
with" only one grid to realize effective DeNOx at lower than full boiler loads.
Other specific projections and conclusions were as follows:
All units could reach the proposed NOX NSPS using Thermal DeNOx alone.
Some units could also reach this level using combustion modifications
alone.
27
-------
All units except one could meet the deep NOX reduction target when Thermal
DeNOx was used in combination with combustion modifications. The one ex-
ception was the cyclone boiler fired with lignite.
Projected costs to reach the proposed NSPS from an uncontrolled base level
ranged from 0.25 mills/KW-Hr for the 250 MW CE boiler to a high of 1.17
mills/KW-Hr for the lignite fired cyclone boiler. The average cost for all
boilers considered was 0.57 mills/KW-Hr, or 0.49 mills/KW-Hr not including
the cyclone boiler.
Four of the eight boilers could reach the deep reduction target using
Thermal DeNOx alone. Costs ranged from 0.38 mills/KW-Hr to 0.83 mills/KW-
Hr for these boilers.
Projected costs to reach the deep reduction target using Thermal DeNOx with
combustion modifications ranged from 0.38 mills/KW-Hr to 0.51 mills/KW-Hr
with the average being 0.44 mills/KW-Hr for the seven boilers reaching the
target level.
NOX reductions ranging from 62% to 76% and averaging 70% relative to an un-
controlled base case could be achieved using Thermal DeNOx at a maximum
practical level in combination with combustion modifications. NOX levels
in the 0.20 to 0.23 Ib. NOx/MBtu range could be realized for most of the
boilers. Costs ranged from 0.55 to 1.14 mills/KW-Hr and averaged 0.68
mills/KW-Hr for all boilers studied. With the lignite boiler excluded the
range was 0.55 to 0.67 mills/KW-Hr and the average was 0.61 mills/KW-Hr.
The costs for onsites and the carrier were found to be proportional to
boiler size.
t The total ammonia reagent costs for all cases normalized for the mass of
NOX removed expressed as N02 (ANOX) were nearly equal for all eight units
studied at 0.09 $/lb.ANOx. This parameter was considered to be a good
overall judgement criterion of the chemical efficiency and economic effis
cacy of the Thermal DeNOx process.
The Exxon Thermal DeNOx Process was considered to be equally amenable to
all units studied.
The costs for reaching NOX levels in the 0.3 to 0.4 Ib./MBtu range were
compared for Thermal DeNOx and combustion modifications. The costs of most
conventional combustion modifications and combinations thereof were lower
than that of Thermal DeNOx. Extreme NOX reduction methods such as derating
or staged combustion that incurred derating would be more expensive.
Derating would not generally be used as a NOX reduction technique.
The practical effectiveness of Exxon Thermal DeNOx process can be determined
from several evaluations which were performed during this study. These are:
1. The percent reduction in NOX levels predicted by the Thermal DeNOx
Performance Prediction Technique.
28
-------
2. The feasibility and costs for reducing NOX emissions to the specified
target NOX levels, with and without combustion modifications.
3. The maximum reduction in NOX levels achievable and the costs required
to accomplish this reduction.
4. The total ammonia operating costs normalized to the cost per pound of
NOx removed.
5. Comparison of costs for Thermal DeNO with costs for combustion
modifications to reach 0.3 to 0.4 1b. NOx/MBtu.
6. The effect of unanticipated temperature gradients in the plane of
ammonia injection on Thermal DeNOx performance and grid placement.
7. Load following using hydrogen along with ammonia rather than using
multiple grids.
The results obtained in each of these areas are presented in the
following subsections.
PREDICTED PERCENT NOX REDUCTION LEVELS
The Thermal DeNOx Performance Prediction Procedure has been discussed
above. In summary, this calculational procedure utilizes boiler dimensional
information, flue gas mass flow, temperature and critical residence times
to arrive at a predicted value for maximum percentage NOX reduction as a
function of ammonia injector grid location.
The percentage NOX reduction which could be anticipated for each of
the eight boilers as predicted using the Exxon procedure with NH3/NOX
molar ratios of 1.0 and 1.5 has been calculated. The results have been
determined for 100% load and in most cases one or more lower loads. The
results obtained are presented in Table 6-1.
The percentage NOX reductions calculated for the coal fired utility
boilers studied operating at full load averaged 44.6% at the molar ratio
of 1.0. The range for all boilers considered was 41-47%. At a molar ratio
of 1.5, the average DeNOx performance increased to about 57.5%. In this
case, the range extended from 54 to 63%. These results may be considered to
be typical of DeNOx performance.
29
-------
TABLE 6-1. PREDICTED THERMAL DeNOx PERFORMANCE ACHIEVABLE
AT FULL, 75% AND 50% LOAD
Percent NOX Reduction at Boiler
Load and NH3/NOI Ratio Indicated
Boiler 100% 75l50l
Manufacturer MW Coal Type 1.5 1.0 1.5 1.0 1.5 1.0
B&W
B&W
B&W
CE
CE
F-W
F-W
130
333
400
350
800
330
670
Subbituminous
Bituminous
Lignite
Bituminous
Subbituminous
Bituminous
Subbituminous
52
63
58
58
57
54
60
42
48
43
45
45
41
47
52
57
58
52
52
*
__
42
44
43
40
40
_ ^
-_
63
57
48*
50*
_ _
50
44
37*
38*
«
__
RS 350 Bituminous 58 46 54* 45*
*60% Load
It should be noted that the temperature profile and flow path con-
figuration for the Riley Stoker boiler differed considerably from the other
boilers considered and from the temperature patterns used in formulating
the Thermal DeNOx Performance Prediction Procedure. As a consequence, the
values for the performance of the Thermal DeNOx process on this unit and the
values of costs which derive from these should be considered to be subject
to a greater degree of uncertainty than the other boilers studied.
Application of the Performance Prediction Procedure revealed that
there are definite differences from manufacturer to manufacturer in the
flue gas temperature profiles and flow path configurations. For example, the
injection grids would be located closest to the furnace exit for the CE units
and furthest downstream for the F-W units. As was noted above and will be
stated later, the performance (and costs) were effected only minimally by
these configurational differences
FEASIBILITY AND COSTS
The feasibility of using the Exxon Thermal DeNOx process and the
resulting costs required to reach (a) a final NOX level where NOx emissions
would be "trimmed" and (b) where a significant reduction would be made in
NOy emissions have been evaluated. As noted earlier, the trim case called
30
-------
for reducing NOX emissions to 450 ppm NOX for bituminous coal and lignite
firing and 375 ppm NOX for subbituminous. These are the proposed NSPS
levels. The other group of NOX reductions required would be significant,
to 300 ppm NOX for bituminous and lignite and 225 ppm NOX for subbituminous.
In order to fully evaluate the capabilities for the Thermal DeNOx process
to meet the target levels and to establish a range of costs where practical
two initial NOX levels were considered: one in which NOX emissions were
uncontrolled and the other in which combustion modifications were used. Thus,
four cases were formulated:
Case 1: Combustion modifications (CM) cannot be used and initial NOX
level is baseline NOX level. Trim case.
Case 2: CM can be used to reduce initial NOX levels. Trim case.
Case 3: CM cannot be used. Deep NOX reduction case.
Case 4: CM can be used. Deep NOX reduction case.
By the use of this approach, a range of costs has been established
for those cases where appropriate NOX reductions could be achieved. The
nature of the combustion modification utilized for each boiler was noted
earlier. A summary of the results obtained is presented in Table 6-2.
Additional detail summarizing the costs of ammonia, carrier and the onsite
cost are presented in Appendix 1.
The costs presented here are for those representative boilers selected
for study. It should be recognized that each potential candidate boiler
for the Thermal DeNOx process must be studied on an individual basis.
Table 6-2 shows that at full boiler load and without combustion modifica-
tions, the NOX emissions from each boiler can be reduced to the NSPS NOX
target using Thermal DeNOx. The costs for the application of the Exxon Thermal
DeNOx process for the Case 1 trim cases ranged from a low of 0.25 mill/KW-Hr.
for the 250 MW CE boiler to a high of 1.17 mills/KW-Hr. for the lignite fired
cyclone boiler. The cost for this boiler was more than double that for
almost all the other boilers. Excluding the lignite boiler, the average
cost was about 0.49 mills/KW-Hr.; with the lignite boiler included, the
average cost was just over 0.57"mills/KW-Hr. The high cost for the lignite-
fired boiler can be attributed to the very high initial NOX level assumed
for this boiler. The costs of reducing NOX emissions from an uncontrolled
baseline level to the proposed NSPS depends upon a number of considerations
including initial NOX level. This will significantly influence the cost
for the ammonia used. Examination of the data in Appendix 1 reveals that
unit size can have some influence on the on-site cost and that the carrier
cost is generally proportional to the flue gas flow rate. The inherently
low NOX emissions from the CE tangentially fired boilers are responsible
for the low Thermal DeNOx costs determined for these units.
With combustion modifications, the NSPS NOX targets can also be reached.
In fact, for five of the eight boilers, this target NOX level can be achieved
31
-------
TABLE 6-2. COSTS FOR REDUCING NO,, EMISSIONS OF COAL FIRED UTILITY BOILERS USING THERMAL DeNOx1",
Trim Cases
Case 1
W/0 Comb.
Manuf .
B&W
CE
F-W
RS
*
Thermal
Target
t Thermal
Size
MW
130
333
400
350
800
330
670
350
DeNOx
, Firing
Type
FW
HO
Cyclone
Tan
Tan
FW
HO
Turbo
Case 2
Mod. With Comb. Mod.
Deep Reduction Cases
Case 3 Case 4
W/0 Comb. Mod. With Comb. Mod.
Coal Initial Cost Initial Cost Final Initial tost imnai
Type NO- "nm mm/ KW-Hr Nfl- . DOTI H11 1 s/ KW-Hr NOv. opm NO*. POTH1lls/KW-Hr NOx, ppm
Subbit.
Bit.
500
700
L1g. 1000
Bit
Subbit.
Bit
Subbit.
Bit
not required. Final
500
530
850
700
700
NOX level
0.49
0.45
1.17
0.25
0.34
0.71
0.63
0.54
attainable
300 0.06*
420
900
450
375
510
420
420
using
0.06*
0.99
0.08*
0.08*
0.33
0.31
0.10*
375
450
450
450
375
450
375
450
500 ** 300
700 0.63 420
1 000 ** 900
500 0.38 450
530 0.62 375
850 ** 51 0
700 ** 420
700 0.83 420
tost i-inai '
Mills/ KW-Hr NOx. ppm
0.47 225
0.38 300
** 300
0.42 300
0.42 225
0,50 300
0.51 225
0.45 300
Percent
Reduction
From
Jncontroll ed
Case
55
57
"*"
40
58
65
61
57
combustion modifications.
NOX level cannot be reached.
DeNOx
costs do
not include
1 icensing fees and
charges
for preliminary
engineering and testing.
-------
using combustion modifications alone. Because the cost of simple combustion
modifications is far smaller than that of Thermal DeNOx, combustion modifica-
tions would represent the preferred, cost effective approach for these boilers.
In fact, only three boilers required use of the Thermal DeNOx process, the
400 MW B&W boiler firing lignite and the two F-W boilers. As was noted
previously, the lignite boiler has a very high initial NOX level, and in all
cases studied meeting NOX target levels would be either expensive or
impossible. In this case, the use of combustion modifications lowers the
cost of Thermal DeNOx by about 16%. Still the cost of Thermal DeNOx for
this unit using Case 2 NOX levels is about three times as great as for any
of the other units studied. The combination of boiler size and coal type
selected for the F-W Boilers (resulting in the NOX levels specified) is
probably responsible for the requirement to use Thermal DeNOx in these
cases. Here, however, the use of combustion modifications serves to reduce
the cost of Thermal DeNOx by 55% for the 330 MW boiler and by 52% for the
670 MW unit.
The reduction of NOX in Case 3 is the most difficult because of (a)
the high initial NOX levels and (b) the deep reduction target. In fact,
in this case only half of the boilers studied were able to achieve the
target NOX levels. The Thermal DeNOx costs for those boilers which met the
target ranged from 0.38 to 0.83 mills/KW-Hr. Because so few boilers were
able to meet this target, additional cases were established for the maximum
reduction in NOX emissions which could be achieved. These cases are dis-
cussed in the following subsection.
Case 4 considers a deep reduction in NOX emissions achievable by
Thermal DeNOx in conjunction with combustion modifications. In this case,
all boilers except that firing lignite met the target NOX level. It is
interesting to note that the cost spread in this case was rather narrow,
ranging from 0.38 to 0.51 mills/KW-Hr. with the average being 0.44 mills/
KW-Hr. This average cost is lower than the average cost determined for
Case 1 where the NOX target was not as low and combustion modifications
were not utilized to lower the initial NOX level. The overall NOx reductions
achieved by the combination of Thermal DeNOx and combustion modifications
from an uncontrolled base case ranged from 40% to 65% with the average
reduction approximating 56%. Thus, the combination of Thermal DeNOx and
combustion modification was found capable of meeting deep reductions in NOx
emissions on existing boilers with a wide range of sizes, from all manu-
facturers, utilizing different firing types and, with the exception of
lignite fired in a cyclone boiler, all fuels.
MAXIMUM REDUCTION OF NOX LEVELS
In addition to the four cases noted previously, two additional cases
were studied in which NOX was reduced to the lowest level attainable by
Thermal DeNOx as specified by the Performance Prediction Procedure with
the injector grid at the location selected for full load (i.e., the grid
location was the same as in the cases noted previously). Thus two additional
cases are defined:
33
-------
Case 5: Maximum DeNOx without combustion modifications.
Case 6: Maximum DeNOx with combustion modifications.
Without CM, Case 5, the percent NOX reduction realized ranged from 50
to 59%. Costs ranged from 0.57 mills/KW-Hr. for the small CE boiler to
1.23 mills/KW-Hr. for the lignite boiler; most cases were in the 0.57 to
0.87 mills/KW-Hr. range, the high value for lignite again being attributable
to the high initial NOX level. The results for all boilers are presented
in Table 6-3.
Combustion modifications, plus Thermal DeNOx, Case 6, combined to reduce
NOX levels an average of 70% from the uncontrolled base case. The ranges
extended from 62 to 76% reduction in NOX. Final NOX levels in the 150 to
175 ppm range were realized for five of the eight boilers. Again the lignite
boiler was a significant NOX producer, possessing final NOX emission level
greater than twice that of the five boilers noted above.
In terms of cost, the lignite boiler had a total cost of 1.14 mills/KW-
Hr. The cost for all the other boilers fell in the rather nerrow range of
0.55 to 0.67 mills/KW-Hr., again about half the cost of the lignite boiler.
Excluding the lignite boiler, the average cost was 0.61 mills/KW-Hr. Includ-
ing the lignite boiler, the average cost increased to 0.68 mills/KW-Hr.
NORMALIZED AMMONIA AND OTHER OPERATING COSTS
The total ammonia reagent costs expressed on the basis of the quantity
of NOX removed is an excellent measure of the efficiency of the Thermal
DeNOx Process for combustion equipment. Specifically, for coal fired utility
boilers, this study found that when ammonia-related costs were normalized
with respect to the pounds of NOX removed, NOX:
Total reagent costs were nearly equal for all units in all cases at
0.09 $71b. NOX removed.
Operating costs for all units in all cases approximated 0.08 $/lb. ANO .
J\
Capital costs for all units in all cases were about 0.01 $/lb. ANO .
/\
These costs are presented in Appendix 1 for each case considered for
each boiler. The range of ammonia operating costs for each case considered
for each boiler is shown in Figure 6-1. The small differences in Thermal
DeNOx efficiency which made some units slightly lower than the average
values noted above were not considered to be significant.
Of the ammonia cost, approximately 10% represents capital investment
for the storage facilities, and the balance is the operating cost for the
ammonia supply. At lower ammonia rates (such as less than approximately
34
-------
CO
01
0.15
0.10
CM
O
00
,1
CO
o
o
o
a:
LU
0.05
o
s
S
<
COST COMPARISONS 100 PERCENT LOAD
COST RANGE)
FOR ALL CASES
TRIM TARGET
WITHOUT COMBUSTION MODIFICATIONS
1
1
RATING (MW)
MFC
COAL TYPE
130
BW
SUBBIT.
330 333 350 350 400
FW BW RS CE BW
BIT. BIT. BIT. BIT. LIG.
670 800
FW CE
SUBBIT. SUBBIT,
Figure 6-1 Ammonia operating costs for boilers studied.
-------
TABLE 6-3. MAXIMUM PRACTICAL NO^ REDUCTION ACHIEVABLE USING THERMAL DeNOxt
Case 5
Without Combustion Modifications
Boiler
Manuf .
B&W
CE
F-W
Size,
HW
130
333
400
350
800
330
670
Firing
Type
FW
HO
Cyclone
Tan
Tan
FW
HO
Coal
Type
Subt.1t.
Bit.
Lignite
Bit.
Subblt.
Bit.
Subblt.
Initial
Level ,
ppm
500
700
1000
500
530
850
700
NOx
Final
Level ,
Ppm
250
290
430
210
230
390
290
Percent
NOX
Reduction
50
59
57
58
57
54
59
Total
Cost
M^ls/KW-Hr
0.71
0.70
1.23
0,57
0,62
0.82
0.87
Case 6
With Combustion Modifications
Initial
Level,
ppm
300
420
900
450
375
510
420
NO*
Ffnal
Level ,
ppm
150
175
385
190
160
230
170
Percent
NOX
Reduction
50
58
57
58
57
55
59
Total
Cost,
Mlls/KW-Hr
0.60
0.55
1.14
0.61
0.59
0.62
0.65
Percent
Total NOx Reduction
Possible From
Uncontrolled Case
70
75
62
62
70
73
76
RS 350 Turbo Bit. 700 295 58 0.84 420 175 58
t Thermal DeNOx costs do not Include licensing fees and charges for preliminary engineering and testing.
0.67
75
-------
1000 Ib/Hr) the facilities cost is a greater fraction of the total as
expressed on a KW-Hr. basis.
Other categories of cost items (carrier cost and on-site costs) deter-
mined were considered to be related to boiler size rather than to the
efficiency of NOX removal as was the reagent cost (see Figure 6-2). The
carrier cost, for example, was found to be a function of flue gas flow rate.
The latter value was found to be roughly proportional to unit size. Normal-
ized carrier cost was found to be nearly constant for all units at 0.14
mills/KW-Hr. Approximately half of this cost was capital investment and
half was operating cost.
The on-sites costs which includes the cost of the ammonia injection
grid was found to be a function of unit size. Normalized, the on-site
capital investment was found to be in the range of 0.04 to 0.05 mi11s/KW-Hr
for all units, except for the smallest B&W boiler. The normalized cost for
this boiler was approximately double that of the average.
COST COMPARISON OF THERMAL DeNOx WITH COMBUSTION MODIFICATION TECHNIQUES
A reliable comparison of the costs of Thermal DeNOx versus extreme
combustion modifications required to reduce NOX emissions to the 0.3 to 0.4
Ib/MBtu range would be very valuable. Unfortunately, as of this writing,
no publically disseminated information is available from the boiler manu-
facturers concerning the cost of combustion modifications to reach NOx
levels within this range. In general, combinations of several combustion
modification techniques will be required to reach the NOX levels noted above.
In section 5, the costs for several combustion modification techniques were
developed. These costs can be applied to available NOX reduction information
obtained on utility boilers.
One example presented below describes the use of low NOX burners plus
the extreme combustion modification technique of derating to reach the 0.4
Ib/MBtu NOX range. The other describes the use of two conventional combustion
modification techniques, low NOX burners combined with overfire air, to reach
the same level.
The first example considered here is that of the use of low NOX burners
plus derating. Actual performance data has been obtained under EPA contract
by Exxon Research on a 270 MW B&W boiler with horizontally opposed firing
of eastern bituminous coal (4J. Data were obtained (a) before and after the
installation of low NOX burners (LNB) and (b) using LNB in combination with
derating of the boiler by about 20% by shutting off one row of coal pul-
verizers (Run 37 in reference 4_). Table 6-4 presents the data obtained.
37
-------
CO
00
CO
o
LJ
0.40
I
a
LU
1.20
1.00
0.80
0.60
0.20
0
AMMONIA I
Operating
Capital
CARRIER
Operating
Capital
ONSITES
RATING (MW) 130
MFC BW
COAL TYPE SUBBIT.
1
m
330 333 350 350 400
FW BW RS CE BW
BIT. BIT. BIT. BIT. LIG.
670 800
FW CE
SUBBIT. SUBBIT.
Figure 6-2 Cost comparisons for trim target
without combustion modifications - 100 percent load.
-------
TABLE 6-4. NOX LEVELS ON 270 MW B&W HO BOILER
NOX Level
1b/MBtu
Uncontrolled
Low NOX burners
Low NOX burners + Derate
600
375
300
0.8
0.5
0.4
270
270
208 (23% derate)
In this case derating the boiler by 23% reduced NOX levels to the 0.4 1b/MBtu
(300 pptnj NOX. This example is very similar to that of the B&W HO 333 MW
boiler firing bituminous coal considered in this study. The initial NOX
level was 700 ppm for this boiler and in Case 4, the final level was 300 ppm.
The cost calculated for Thermal DeNOx plus combustion modifications (low NOX
burners) was 0.38 mills/KW-Hr. For low NOX burners plus derating the cost
would be: 4.30 + 0.06 mills/KW-Hr = 4.36 mills/KW-Hr. Thermal DeNOx is
obviously far cheaper than the case presented here because of the very high
cost of derating. If the staging of burners to achieve target NOX levels
results in less than full load (thus effectively derating the boiler), the
costs for staging can be expected to be similar to the derating case illus-
trated here.
Another example is that described by Vatsky (7) of a Foster-Wheeler
265 MW bituminous-fired utility boiler retrofitted with overfire air ports
and F-W low NOX burners. Even with conventional, high turbulence burners,
this boiler possessed an initial NOX level which was within the 600-650 ppm
NOX (0.8 Ib NOx/MBtu) range. This low initial level was ascribed to the
large, conservatively designed fireboxes which this unit possessed. Under
normal operating procedure for this boiler, NOX levels were in the 300-350
ppm (0.4 Ib NOx/MBtu) range using the low NOX burners and with the overfire
air ports open no more than 20%. (Still lower emissions could be attained
by this boiler - down to 200-225 ppm NOX - with overfire air ports fully
open, but unburned carbon emissions and slag deposits increased.) The
applicable NOX levels are presented in Table 6-5.
TABLE 6-5. NOX LEVELS ON 265 MW F-W HO BOILER
NOX Level
ppm 1 b/MBtu Reduction
Uncontrolled
Overfire Air Only
Low NOX Burners Only
OFA + LNB
600
425
375
300
0.83
0.56
0.50
0.40
32
40
^ rt
50
39
-------
The costs for accomplishing this reduction in NOX using previously
stated values are:
Low NOX Burners 0.06 mills/KW-Hr
Overfire Air Ports 0.10 mills/KW-Hr
Total 0.16 mills/KW-Hr
The value of 0.16 mills/KW-Hr is clearly lower than any of the Thermal
DeNOx costs required to reach the 0.4 Ib/MBtu range. It should be noted,
however, that neither of the combustion modification techniques used here
could be regarded as extreme, but were rather quite conventional.
In general, it can ,be stated that the costs required to achieve low
NOX emission levels will be dependent upon the boiler and the modifications
which can be applied on a practical basis. The examples presented here
illustrate a range of costs to reach the stated low levels of NOX, some
greater than and some less than Thermal DeNOx. Where combinations of simple
combustion modifications can be applied successfully to reach the target
levels of 0.3 to 0.4 Ib/MBtu, combustion modifications will probably be
the preferred techniques. Where boiler inflexibility or other conditions
prevent the use of most combustion modifications and derating or staging
which results in derating the boiler are the only combustion-related
approaches left to meet specified emission levels, Thermal DeNOx will be
the preferred technique. Clearly, more refined costs for combinations of
combustion modifications, including case histories, are required before
authoritative comparisons can be undertaken.
TEMPERATURE NONUNIFORMITY SENSITIVITY STUDY
The effectiveness of the Exxon Thermal DeNOx Process is critically de-
pendent on temperature. Thermal DeNOx performance is a function of the cross
sectional temperature throughout the reaction zone. Because of this signifi-
cant dependence, the level of NOX reduction attainable will depend upon
placing the ammonia injection grid in the proper location. One major variable
which is encountered in operating boilers is the nonuniformity in temperature
of the flue gas. A series of values to account for this AT are incorporated
into the Performance Prediction Procedure used. This Procedure assumes that
a range of temperatures is present in the plane of the injection grid. This
temperature range is assumed to be gradually smoothed out downstream of the
grid. If the flue gas temperature range is significantly different from
that used in the Performance Prediction Procedure, it is possible that
the grid or grids could be improperly located thereby resulting in less
than predicted DeNOx performance. As a consequence a sensitivity analysis
was undertaken for this study using one boiler in which different tempera-
ture ranges, that is different values of AT, were used in the performance
prediction technique. This sensitivity analysis is described below.
40
-------
Initial studies of the suitability of a unit to Thermal DeNO applica-
tion require that an estimate of the AT be made for each proposed injector
location based upon experience with similar units. The values of AT used
in calculating performance for this EPA study were based upon data taken in
a Japanese 160 MW utility boiler. It must, however, be realized that the
cross sectional temperature distributions may be quite different even among
units of similar design. Burner firing patterns, air leakage, flow obstruc-
tions, etc. are factors which can affect the temperature pattern.
Application of Exxon Thermal DeNOx Performance Prediction Procedure re-
vealed that the locations of the injector grids would not be influenced by a
temperature range up to 50°C larger than that used in the Performance
Prediction Procedure for the other cases presented. However, a temperature
range of this magnitude could result in DeNOx performance much differed from
the predicted values by 5 to 10 percentage points, for example, performance
could be reduced from 50% DeNOx to 40-45% DeNOx.
USE OF HYDROGEN FOR LOAD FOLLOWING
There are several approaches for using Thermal DeNOx to achieve suitable
NOX reductions with different boiler loads. One method involves the use of
multiple grids each designed to cover one or more boiler loads. Only NH3
plus carrier are used. This has been the approach studied in the other
sections of this report. In this section, the results are presented for a
second approach studied for maintaining NOX reductions during reductions in
boiler load. A single injector rather than two was installed, and hydrogen
was injected along with ammonia and carrier during periods of boiler load
reduction to maintain the NOx target. As was noted earlier in this report,
the use of hydrogen in the Thermal DeNOx Process serves to shift the critical
temperature window to lower temperature values, thereby enabling the process
to effectively accomodate reduced load. The use of hydrogen, however, does
not widen the temperature window; hydrogen merely lowers it. The necessity
for using hydrogen has been obviated to a large extent because of the
demonstration conducted at Exxon Research which showed that ammonia may be
injected into boiler tube banks and into cavities with essentially equal
success. For most ammonia-only applications more than one grid will be
required in order to have DeNOx performance at different loads. In consider-
ing the use of hydrogen, it was assumed that only one grid would be used and
the temperature lowering ability of hydrogen would permit DeNOx performance
at lower loads and thus lower temperatures. As a consequence, in these
hydrogen examples, reduced on-sites costs would be "traded off" for increased
reagent costs.
The hydrogen examples presented here are only one of several grid/
hydrogen combinations possible. Possible combinations include:
1 grid - no hydcegen
1 grid - with hydrogen
2 grids - no hydrogen
2 grids - with hydrogen
41
-------
It is the second combination which has been studied here and contrasted with
the two grid - no hydrogen combination which forms the basis for the balance
of this investigation.
The effect of hydrogen addition was calculated for the 333 MW Babcock
and Wilcox unit at 75 and 50 percent loads. The use of hydrogen permits
possible savings in two areas: (1) the installation of only a single grid
and (2) reduced carrier rates since cooling of an idling second grid is not
required. The location of this single grid is Based on the frequency of
load changes and normal operating conditions. We have assumed that maximum
target reductions must be maintained at all load variations, and costs for
each load are based on continuous operation at that load. Grid placement
was critical in that one location was required to cover the three loads
assumed.
Six different examples were studied in undertaking this analysis of
the effect of hydrogen addition on extending the useful range of a single
grid system at lower boiler loads (see Table 6-6). The first three examples
involve the use of two grids. The first example is identical to the general
Case 3 (deep NOX reductions and no combustion modifications) and considers
initial and final NOx levels of 700 ppm and 300 ppm, respectively, at full
TABLE 6-6. EXAMPLES CONTRASTING SINGLE GRID-HYDROGEN
AND DUAL GRID FOR LOAD FOLLOWING
Example
A
B
C
D
E
F
Number
of Grids
2
2
2
1
1
1
Hydrogen
Used
No
No
No
No
Yes
Yes
Boiler
Load, %
100
75
50
100
75
50
NOX Level
Initial
700
630
560
700
630
560
s, ppm
Final
300
300
252
300
300
252
loads. The second example considered here assumes 75% load and initial and
final NOX levels of 630 ppm and 300 ppm, respectively. In the third example
considered here, the boiler was assumed to be operating at 50% load with an
initial N0y level of 560 ppm and a final NOX level of 252 ppm. The latter
42
-------
NOX level represented the lowest NOX level which could be realized. In the
fourth, fifth and sixth examples, only one grid was assumed to be used. The
initial and final NOX levels as well as boiler loads for these examples are
the same for the first, second and third examples considered here, res-
pectively. Hydrogen is added as required to meet the DeNOx targets in the
fifth and sixth hydrogen examples.
The assumptions which were used in applying the Thermal DeNOx Per-
formance Prediction Procedure are listed below:
1. There is one injection location which must meet all the reductions
required of a dual injector system.
2. The grid must be located where the performance at each of the
loads without hydrogen is greater than zero.
3. The carrier is air.
4. The carrier temperature is 80°C at the feed pipe entry point into
the flue gas duct.
5. The effect that a temperature distribution would have on the
hydrogen reaction was neglected.
The assumptions used in cost estimating for the hydrogen costs are listed
below:
1. Fixed costs are total erected cost, 2nd Quarter 1977, U.S. Gulf
Coast, no escalation and no contingency included.
2. Ammonia fixed costs include NH3 storage vessel, vaporizer, and
piping. Hydrogen is supplied on truck mounted pressurized
cylinders and is fed into the same piping system used to handle
the ammonia.
3. Carrier fixed costs include air compressor and piping.
4. On-site fixed costs include one injector grid, plus instrumenta-
tion and controls for ammonia and hydrogen.
5. Operating costs are for continuous operation at 100, 75 and 50%
loads.
6. The NH3/NOI ratio is assumed to be constant at 1.5. This ratio
was determined from plots of data obtained by Exxon Research.
7. Calculated NHq and H£ consumptions are based on nominal initial
NOX levels and flue gas flow rates. No adjustments have been
made for variations in excess air levels and flue gas moisture
content.
43
-------
8. Reagent operating costs for NH3 and H2 are based on $85 and $1400
per 1000 lb., respectively.
9. Carrier rate, for cost calculations, was 6.45 kg/hr/nozzle at all
loads. Excess carrier was assumed to be vented when not needed.
10. Carrier operating costs are calculated in the same manner as the
non HZ injection studies.
11. Annual amortization is taken as 20% of investment. This figure
represents finance costs and maintenance. Annual service factor
is 80% of full load.
The costs projected are plotted in Figure 6-3 as a function of pounds
of NOX removed for the three loads. This figure shows that extensive opera-
tion at reduced loads can best be handled with a dual injector system. How-
ever, if minor variations in load are foreseen for only short durations
there may be economic incentives for the use of hydrogen with a single grid
rather than for installing a second ammonia grid.
For full load, this study projected that the overall cost for a single
grid system operating with NH3 as the only reagent (i.e. no hydrogen) would
be almost identical to that of a dual grid system. Clearly, the grid and
carrier cost for the single grid system would be lower than for the dual
grid system. However, because the grid position was selected to provide
NOx reduction coverage at all loads considered, it was not optimal for any
one load. The single grid location was a compromise and, for full load, the
ammonia operating costs were somewhat higher for the single injection system
that for the dual grid system (see Figure 6-3). Thus, the higher capital
costs of the two grid system were balanced by the higher operating costs of
the single grid system. If the operating time at each load had been
established, it should be possible to identify a single grid position which
would result in lower operating costs.
For 75 and 50 percent load, hydrogen would be used in order to main-
tain the specified DeNOx coverage. For these reduced load examples, it
was projected that the total cost of single grid operation in which hydrogen
was used were higher than the dual grid examples, but the substantially
higher operating costs for the single grid examples more than offset the
lower fixed costs.
44
-------
F
C
E
B
D
A
''2/%%//2\
'%2/%%%/A
t /
Fixed Operating
Costs Costs
1 \
%^%^
'/2/W/%\
'////A -i r*no/
_ JL UU/u
Load
5%223 1
1 I 1 1 1 1
[
50%
1 Load
75%
Load
A^C -Two injection locations -
no H2 required.
D,E,F - Single injection location -
H2 needed at loads less
than 100%.
1 1 1 1 1 1
0 .02 .04 .06 .08 0.1 0.14 0.18 0.22
TOTAL COST, $/LB NOX REMOVED
Figure 6-3 Comparison cost of injecting with and without H2 in
a Babcock and Wilcox - 333 MW Unit.
0.26
45
-------
REFERENCES
1. Lyon, R. K., "Method for the Reduction of the Concentration of NO in
Combustion Effluents Using Ammonia," U.S. Patent 3,900,554, August 9,
1975.
2. Lyon, R. K., "Communication to the Editor: the NH3-NO-02 Reaction,"
International Journal of Chemical Kinetics, IB, 315-318 (1976).
3. Lyon, R. K. and Longwell, J. P., "Selective, Non-Catalytic Reduction of
NOX by NH3," Paper presented at EPRI NOX Seminar, San Francisco,
February 1976.
4. Crawford, A. R., Manny, E. H. and Bartok, W., "Control of Utility Boiler
and Gas Turbine Pollutant Emissions by Combustion Modification - Phase 1,"
EPA-600/7-78-036a, March 1978.
5. Federal Register, Proposed Emission Monitoring and Performance Testing
Requirements for New Stationery Soruces, Vol. 39, No. 17-, Part II
(September 11, 1974).
6. Lim, K., Acurex-Aerotherm, Private communication.
7. Vatsky, J., "Attaining Low NOx Emissions by Combining Low Emission
Burners and Off-Stoichiometric Firing, presented at AIChE 70th Annual
Meeting, New York, November 14-17, 1977.
46
-------
APPENDIX 1
COST COMPARISON SUMMARY
This appendix provides a comparison of Thermal DeNOx process costs
and the costs associated with combustion modifications for each full
boiler load case studied.
47
-------
THERMAL DENOX COST COMPARISON SUMMARYt
B&W
CE
FW
RS
B&W
CE
FW
1 1*1 1 f
un 1 1
130 MW Subbl luminous
333 MW Bituminous
400 MW Lignite
350 MW Bituminous
800 MW Subbituminous
330 MW Bituminous
670 MW Subbituminous
350 MW Bituminous
Unit
130 MW Subbituminous
333 MW Bituminous
400 MW Lignite
350 MW Bituminous
800 MW Subbituminous
330 MW Bituminous
670 MW Subbituminous
Case 1 . Trim Tar
Initial Target
NOX NO* G
Jppni) (ppm). (
500
700
1000
500
530
850
700
700
Reagent
375
450
450
450
375
450
375
450
get - W1t
Flue
as Rate
k Ib/hr)
1274
2977
5046
3209
8671
3028
8176
3942
Cost - mUls/kW-hr
Operating Capital
0.16
0.24
0.89
0.05
0.16
0.48
0.42
0.06
0.03
0.07
0.02
0.02
0.05
0.03
Total
0.22
0.27
0.96
0.07
0.18
0.53
0.45
hout Combustion Modifications
NOS Reduction
Required
(Percent) (1b
25
36
55
10
29
47
46
36
Carrier Cost -
Operating Cap
0,08 0.
0.07 0.
0.10 0.
0.07 0.
0.09 0.
0.07 0.
0.10 0.
N02/nr)
254
1189
4433
256
2147
1935
4244
1575
mills/kW-hr
1ta1 Total
11 0.19
06 0.13
06 0.16
06 0.13
03 0.12
06 0.13
04 0.14
NH3/NOI
(Molar
Ratio) 0
0.63
0.76
1.41
0.20
0.56
1.24
0.98
0.76
On-Site Cost
mills/kW-hr
0.08
0.05
0.05
0.05
0.04
0.05
0.04
Reagent
perating
0.08
0.07
0.08
0.06
0.06
0.08
0.07
0.07
Total
ml
Cost, $/lbAN02
Capital
0.03
0.009
0.006
0.03
0.006
0.008
0.005
0.008
Thermal
Cost
Hs/fcW-hr
0.49
0.45
1.17
0.25
0.34
0.71
0.63
Total
0.11
0.08
0.09
0.09
0.07
0.09
0.08
0.08
DeNOx
RS 350 MW Bituminous 0.30 0.04 0.34 0.09 0.06 0.15 0.05
f Thernal DeNOx costs do not include licensing fees and charges for preliminary engineering and testing.
0.54
-------
THERMAL DEMO, COST COMPARISON SUMMARY"''
Case 2. Trim Target With Combustion Modifications
Unit
B&W
CE
FW
130 MW
333 MW
400 MW
350 MW
800 MW
330 MW
670 MW
Subbituminous
Bituminous
Lignite
Bituminous
Subbituminous
Bituminous
Subbituminous
Initial
NOX
(ppm)_
300
420
900
450
375
510
420
Target
NOX
(PPB11
375
450
450
450
375
450
375
Flue
Gas Rate
(k Ib/hr)
5046
3028
8176
NOj, Reduction
Required
(Percent) (Ib
50
-
12
11
N02/hr)
3627
-
290
588
NH3/NOr
(Molar
Ratio)
1.24
-
0.30
0.24
Reagent
Operating
0.08
-
O.OB
0.07
Cost, $/lb
Capital
0.006
-
0.03
0.02
N02
Total
0.09
- .
0.11
0.09
RS 350 MW Bituminous
420
450
BSW
CF
FW
Unit
130 KW Subbituminous
333 MW Bituminous
400 MW Lignite
350 MW Bituminous
800 MW Subbituminous
330 MW Bituminous
670 MW Subbituminous
Operating
_
0.71
.
-
0.07
0.06
Capital
.
0.06
.
-
0.02
0.01
Total
_
0.77
_
-
0.09
0.07
Operating
«
0.10
.
-
0.07
0.10
Capital
_
0.06
m
-
0.06
0.04
Total
_
0.16
_
-
0.13
0.14
mills/kW-hr
.
-
0.05
_
-
0.05
0.04
Modification
Technique
LNB
LNB
LEA
OFA
OFA
LNB
LNB
Modification Cost
mills/kW-hr
0.06
0.06
0.0
0.08
0.08
0.06
0.06
DeNO* Cost
mills/kW-hr
.
-
0.98
-
-
0.27
0.25
mills/kW-lr
0.06
0.06
0.98
0.08
0.08
0.33
0.31
RS 350 MW Bituminous
OFA
Thermal DeNOx costs do not include licensing fees and charges for preliminary engineering and testing.
0.10
0.10
-------
THERMAL DeNO COST COMPARISON SUMMARYt
en
o
Unit
B&W
CE
FW
RS
B&W
CE
130
333
400
350
800
330
670
350
130
333
400
350
800
MM Subb1tum1nous
MM Bituminous
MM Lignite
MM Bituminous
MM Subbl luminous
MM Bituminous
MM Subbl luminous
MM Bituminous
Unit
MM
MM
MM
MM
MM
Subbi luminous
Bituminous
Lignite
Bituminous
Subb1tum1nous
Case
Initial
NOX
(ppm)
3. Deep Reductlc
Target Flue
NOx Gas Rate
(ppm) (k Ib/hr)
500 225 1274
700 300 2977
1000 300 5016
500 300 3209
530 225 8671
850 300 3028
700 225 8176
700 300 3942
Reagent Cost - mllls/kM-hr
Operating
0.41
0.17
0.43
Capital
0.40
0.03
0.03
Total
0.45
0.20
0.46
x
m Target Mlthout Combustion
NOX Reduction NHa
Required (Mo
i (Percent)
(lb N0?/nr) Ra
55
57 1902 1.
70
40 1025
58 4224 1 .
65
88
57 2519 1.
Carrier Cost - m1lls/kM-hr
Operating
0.07
0.07
0.09
Capital Total
0.06 0.13
0.06 0.13
0.03 0.12
Modifications
/NOT Reaqent Cost, $/lbANO?
lar
t1o) Operating Capital Total
31 0.07
76 0.06
5 0.08
46 0.08
On-S1te Cost
m1lls/kM-hr
0.05
0.05
0.04
0.007 0.08
0.01 0.07
0.006 0.09
0.007 0.09
Total Thermal DeNOx
Cost
m1lls/kM-hr
0.63
0.38
0.62
FM 330 MM Bituminous
670.MM Subb1tum1nous
RS 350 MM Bituminous
0.58
0.05 0.63
0.09
0.06 0.15
0.05
0.83
t Thermal DeNOx costs do not include licensing fees and charges for preliminary engineering and testing.
-------
THERMAL DeNO.. COST COMPARISON
B4W
CE
FW
RS
B&W
CE
FW
Unit
130 MW Subbitunlnous
333 MW Bituminous
400 MW Lignite
350 MW Bituminous
800 MW Subbituminous
330 MW Bituminous
670 MW Subbituminous
350 MW Bituminous
Unit
130 MU Subbitufflinous
333 MW Bituminous
400 MW Lignfte
350 MW Bituminous
800 MU Subbituminous
330 MW Bituminous
670 MW Subbituminous
Initial T.
NOX 1
JjJpffl)
300
420
900
450
375
510
420
420
Reagent Cost
arget
NOX
(ppm)
225
300
300
300
225
300
225
300
Flue
Gas Rate
Case 4. Deep Reduction Target
NO* Reduction NH,/NO
Required (Molar
(k Ib/hr) (Percent) (Ib
1274
2977
5046
3209
8671
3028
8176
3942
- mills/kW-hr
Operating Capital
0.09
0.11
0.13
0.16
0.23
0.25
0.05
0.03
0.03
0.02
0.03
0.02
Total
0.14
0.14
0.16
0.18
0.26
0.27
25
29
67
33
40
41
46
29
Carrier Cost -
Operating Cap
0.08 0.
0.07 0.
0.07 0.
0.09 0.
0.07 . 0.
0.10 0.
N0,/hr) Ratio
153 0.63
571 0.61
769 0.64
2077 0.77
1016 1.00
2546 0.98
756 0.62
With Combustion Modlff cations
j Reagent Cost, $/lbANO^
1 Operating Capital Total
0.08
0.07
0.06
0.06
0.08
0.07
0.07
mllls/kW-hr On-Site Cost
ital Total mills/kW-hr
11 0.19
06 0.13
06 0.13
03 0.12
06 0.13
04 0.14
0.08
0,05
0.05
0.04
0.05
0.04
0.05 0
0.02 0
0.01 0
0.006 0
0.01 0
0.006 0
0.01 0
Combustion
Modification
Technique
im
LNB
LEA
OFA
OFA
LNB
LNB
.13
.09
.07
.07
.09
.08
.08
Combustion
Modification Cost
" mills/kW-hr
0.06
0.06
0.0
0.08
0.08
0.06
0.06
Total Thermal
DeNOx Cost
mills/kW-hr
0.4}
0.32
0.34
0.34
0.44
0.45
Total Cost
mills/kW-hr
0.47
0.38
0.42
0.42
0.50
0.51
RS 350 MW Bituminous
0.15
0.03 0.18
0.09
0.06 0.15
0.05
OFA
0.10
0.38
0.18
t Thermal DeNOx costs do not include licensing fees and charges for preliminary engineering and testing.
-------
THERMAL DeNO^. COST COMPARISON SUMMARY4
Case 5. Maximum DeNOx at N^/NOj - 1.5 Without Combustion Modifications
01
ro
B&W
CE
FW
RS
Unit
130 MW Subbituminous
333 MW Bituminous
400 MW Lignite
350 MW Bituminous
800 MW Subb1tum1nous
330 MW Bituminous
670 MW Subb1tum1nous
350 MW Bituminous
Initial
NOX
(ppm)
500
700
1000
500
530
850
700
700
Target
NOX
(ppm)
250
291
430
210
228
391
280
294
Flue
Gas Rate
(k Ib/hr)
1274
2977
5046
3209
8671
3028
8176
3942
Reagent Cost - mills/kW-hr
B&W
CE
FW
RS
130
333
400
350
800
330
670
350
Unit
MM Subbituminous
MW Bituminous
MW Lignite
MW Bituminous
MW Subbituminous
MW Bituminous
MW Subbituminous
MW Bituminous
Operating
0.37
0.47
0.95
0.35
0.43
0.59
0.64
0.59
Capital
0.07
0.04
0.07
0.04
0.03
0.05
0.05
0.05
Total
0.44
0.52
1.02
0.39
0.46
0.64
0.69
0.64
NOX Reduction
Required
i (Percent)
50
63
57
58
57
54
60
58
lib N0?/h
509
1945
4594
1486
4183
2220
5484
2556
Carrier Cost - mill
Operating
0.08
0.07
0.10
0.07
0.09
0.07
0.10
0.09
Capital
0.11
0.06
0.06
0.06
0.03
0.06
0.04
0.06
NHa/NO
(Molar
r}_ Ratio
1.5
1.5
1.5
1.5
1.5
1.5
1.5
1.5
s/kW-hr
Total
0.19
0.13
0.16
0.13
0.12
0.13
0.14
0.15
I Reagent Cost, $/1bANO?
) Operating
0.09
0.08
0.08
0.08
0.08
0.09
0.08
0.08
On-Site Cost
mills/kW-hr
0.08
0.05
0.05
0.05
0.04
0.05
0.04
0.05
Capital
0.02
0.008
0.006
0.008
0.006
0.008
0.006
0.007
Total
Total
0.11
0.09
0.09
0.09
0.09
0.10
0.09
0.09
Thermal DeNOx
Cost
mills/kW-hr
0.71
0.70
1.23
0.57
0.62
0.82
0.87
0.84
t Thermal DeNOx costs do not include licensing fees and charges for preliminary engineering and testing.
-------
THERMAL DENO,, COST COMPARISON SUMMARY*
B&W 1 30
333
400
CE 350
800
FW 330
670
RS 350
Unit.
MU Subbituminous
MW Bituminous
MW Lignite
MW Bituminous
MU Subbituminous
MW Bituminous
MU Subbituminous
MU Bituminous
Initial
NO*
(ppm)
300
420
900
450
375
510
420
420
Reaqent Cost -
Unit Operating Cap
B&W 130 MW
333 MW
400 MW
CE 350 MU
800 MW
FW 330 MW
670 MW
RS 350 MW
Subbituminous
Bituminous
Lignite
Bituminous
Subbituminous
Bituminous
Subbituminous
Bituminous
0.22 0.
0.28 0.
0,86 0.
C.31 0.
0.31 0.
0.35 0.
0.39 0.
0.35 0.
Case 6. Ma>
Target
NO* Ga
(ppm) (l<
150
175
387
189
161
234
168
176
millsAW-hr
ital Total
06 0.28
04 0.32
07 0.92
04 0.35
02 0.33
04 0.39
03 0.42
04 0.39
cimum DeNOv at NH»/NOT = 1.5 With Combust
X j 1
Flue NOX Reduction NH3
is Rate Required (Mo
: Ib/hr) (Percent) (Ib NtWhr) Rat
1274
2977
5016
3209
8671
3028
8176
3942
Carrier Cost
50
63
57
58
57
54
60
58
305 1
1165 1
4135 1
1292 1
2964 1
1335 1
3291 1
1536 1
- mills/kU-hr On-Site Cost
Operating Capital
0.08 0.11
0.07 0.05
0.10 0.06
0.07
0.09
0.07
0.10
0.09
0.06
0.03
0.06
0.04
0.06
Total mills/kW-hr
0.19 0.08
0.13 0.05
0.16 0.05'
0.13 0.05
0.12 0.04
0,13 0.05
0.14 0.04
0.15 0.05
ion Mod 11
/NO]
lar
jiL c
.5
.5
.5
.5
.5
.5
.5
.5
Fi cations
Reagent Cost, $/lb
Iperating Capital
0.10 0.03
0.08 0.01
0.08 0.006
0.08
0.08
0.09
0.08
0.08
0.009
0.007
0.01
0.006
0.009
JO,
Total
0.13
0.09
0.09
0,09
0.09
0.10
0.09
0.09
Combustion Combustion Total Thermal
Modification Modification Cost DeNOx Cost
Technique
LNB
LNB
LEA
OFA
OFA
LNB
LNB
OFA
mills/kW-hr
0.06
0.06
0.0
0.08
0.08
0.06
0.06
0.10
mills/kW-hr
0.55
0.50
1.13
0.53
0.49
0.57
0.60
0.59
Total Cost
mills/kW-hr
0.61
0.56
1.13
0.61
0.57
0.63
0.66
0.69
Thermal DeNOx costs do not include licensing fees and charges for preliminary engineering and testing.
-------
THIS PAGE INTENTIONALLY LEFT BLANK
54
-------
APPENDIX 2
Noncatalytic NOX Removal With Ammonia
FP-735
Research Project 835-1
Final Report, April 1978
Prepared by
KVB, INC.
17332 Irvine Blvd.
Tustin, California 92680
Principal Investigators
L. J. Muzio
J. K. Arand
K. L. Maloney
Prepared for
Exxon Research and Engineering Inc.
RO. Box 55
Linden, New Jersey 07036
and
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, California 94304
EPRI Project Manager
D. Teixeira
Fossil Fuel and Advanced Systems Division
- 55 -
-------
LEGAL NOTICE
This report was prepared by KVB, Inc. as an account of work sponsored by the
Electric Power Research Institute, Inc. (EPRI) and EXXON Research and Engineering,
Inc. (ERE). Neither EPRI, members of EPRI, ERE, KVB, or any person acting on behalf
of any: (a) makes any warranty or representation, express or implied, with.respect
to the accuracy, completeness, or usefulness of the information contained in this
report, or that the use of any information, apparatus, method, or process disclosed
in this report may not infringe privately owned rights; or (b) assumes any liabilities
with respect to the use of, or for damages resulting from the use of, any information,
apparatus, method, or process disclosed in this report.
-------
ABSTRACT
A potential approach to the control of nitric oxide in utility
boilers, in addition to modification of the combustion process, is the
selective homogeneous gas-phase reduction of nitric oxide with ammonia.
A laboratory study at a scale of 3,000,000 Btu/hr was conducted to evaluate
the applicability of ammonia injection for the reduction of nitric oxide in
coal-fired power plants. Four coals (Utah bituminous, New Mexico subbituminous,
Illinois bituminous, and Pittsburgh bituminous) were tested to determine
levels of NOx reductions achievable and the byproduct emissions. The
primary variables investigated (in addition to coal type) were (1) the
amount of ammonia injected, and (2) the temperature of the combustion
products at the point of injection. The effect of the simultaneous addi-
tion of hydrogen along with ammonia on the NOx removal process was also
investigated. The results of these experiments indicated that NO reductions
obtained with ammonia injection into coal-derived combustion products were
similar to those obtained with natural gas firing in the same system and were
comparable to those previously obtained in natural gas and oil-fired systems.
On the order of 65% reductions in NO were obtained at an ammonia injection
rate of one mole of ammonia per mole of NO. However, the temperature de-
pendence was found to vary from coal to coal. The Navaho exhibited peak
reductions at the lowest temperatures, 1720 °F, while the Illinois coal
showed peak reduction occurring at 1830 °F. Typically, natural gas exhibited
peak reductions at 1750 °F. The unexplained variation in optimum process
temperature with coal type indicates that evaluation testing would be prudent
in situations where maximum NOx control was desired and no previous experi-
ence was available for the coal in question. The simultaneous addition of
small quantities of hydrogen can be used to increase the NO reductions and
decrease ammonia emissions at temperatures lower than the optimum.
ill
-------
ACKNOWLE DGEMENTS
KVB, Inc., Electric Power Research Institute, and Exxon Research
and Engineering extend their appreciation to Utah International for donat-
ing the coal from its Navaho mine for use in this study. In addition,
the authors are grateful for the technical discussions and support by
S. Stahl and A. Tenner of Exxon Research and Engineering throughout this
study.
IV
-------
CONTENTS
Section
Page
1.0 INTRODUCTION AND OBJECTIVES
1.1 Background
1.2 Objectives
2.0 EXPERIMENTAL APPROACH AND APPARATUS
2.1 Approach
2.2 Combustion Facility
2.3 Instrumentation
2.4 Experimental Procedure and Test Matrix
3.0 EXPERIMENTAL RESULTS
3.1 Temperature Distributions
3.2 Coal Properties
3.3 Nitric Oxide Reductions
3.4 NH Emissions
3-5 Cyanide and Nitrate Emissions
3.6 Sulfate and SO Emissions
3.7 Carbon Monoxide Emissions
3.8 SO and NOx Measurements
3.9 Ammonia and Hydrogen Injection
4.0 CONCLUSIONS
REFERENCES
APPENDICES:
A.
B.
C.
D.
EXPERIMENTAL APPARATUS
SULFATE AND SO3 EMISSION MEASUREMENT PROCEDURE
DATA SUMMARY
FUEL ANALYSIS
1
2
4
4
8
12
15
15
17
19
30
38
38
40
41
43
49
51
A-l
B-l
C-l
D-l
-------
THIS PAGE INTENTIONALLY LEFT BLANK
vi
-------
EXECUTIVE SUMMARY
The U.S. Environmental Protection Agency has published research
goals for the emissions of nitric oxide from stationary sources which
would limit flue gas concentrations to 100 ppm from coal-fired power plants
by 1985 (Ref. 1). Numerous approaches are being evaluated for controlling
NOx emissions from stationary combustion sources. These approaches cover
the spectrum from "front end" control of the combustion process to the
physical or chemical removal of the oxides of nitrogen in the downstream
regions of the unit. One potentially attractive process for coal-fired
utility boilers entails the selective gas-phase decomposition of nitric oxide
by ammonia. In this process, ammonia is injected into the combustion pro-
ducts. If the temperature of the combustion products is between 1200 °F and
2000 °F, the ammonia will selectively react with the nitric oxide in the
presence of excess oxygen to form primarily nitrogen and water. However,
nitric oxide reductions on the order of 50% or greater occur in the vicinity
of 1750 °F (± 100 °F). Hydrogen can be used along with the ammonia to lower
the temperature at which the selective reduction occurs. A patent is held by
the Exxon Research and Engineering Company on this process (Ref. 2).
While a significant amount of data have been gathered on the selec-
tive reduction of NOx in oil- and gas-fired systems, little information is
currently available as to the applicability of the process to coal-fired sys-
tems. In particular, the levels of NOx reductions achievable, the byproduct
emissions, and the possible catalytic interaction due to the coal ash with NH
injection into coal-derived combustions have not been characterized. A labora
tory study was conducted at a scale of 3,000,000 Btu/hr to evaluate the appli
cability of NH injection to coal-firing systems. The specific objectives of
the study were to: (1) Determine the levels of NOx removal and ammonia emis-
sions with ammonia injection into the combustion products resulting
from pulverized coal combustion; (2) Determine the type and levels of
vn
-------
byproduct emissions: (SO , SO , CO, HCN, NH , unburned hydrocarbons, nitrate
particulates, and sulfate particulates); (3) Determine any effects that vary-
ing coal types might have on the process. A variety of coals were repre-
sented in the study (Utah bituminous, Navaho sibbituminous, Pittsburgh Seam
8 bituminous, and Illinois bituminous); and (4) Determine the extent to which
hydrogen can lower the temperature at which NH would remove NOx from coal-
derived combustion products.
The basis of the experimental system was a firetube boiler modified
to fire pulverized coal with preheated combustion air (600 °F) . The burner
was a geometrically scaled version of a burner currently in use in a coal-
fired utility boiler in the western United States. The ammonia was in-
jected with a carrier stream of nitrogen through five water-cooled injectors
in the main firetube (33 in. diameter). The temperature at the point of in-
jection was controlled by (1) moving the injectors axially in the firetube,
(2) changing the heat renoval rate from the main firetube with stainless
steel liners, and (3) varying firing rate.
A summary of the nitric oxide reductions obtained for all fuels
tested during this study is shown in the two figures below.
i.o
O.B
o.e
0.4
0.2
Natural Gas
- Utah Coal
.- Navaho Coal
__ Pittsburgh Coal
Illinois Coal
1500 1600 1700 1300 10 2COO
Average Radial Temperature, *r
A.
l.C
O.B
o.e
0.4
0.2
Natural Gas
Utah Coal
Navaho Coal
Pittsburgh Coal
Illinois Coal
I
I
(«H./HOo 0.5. Excess O^ A. S.0»)
1500 1600 1700 1800 1900 2000
Average Radial Temperature, *F
{NH3/NOQ - 1.0, Excess 02 -v. 5.01)
V1U
-------
NO reductions obtained with ammonia injection during this study were
similar for all fuels tested. At the optimum temperature, on the order of 65%
reductions in NO were obtained at an ammonia injection rate of one mole of am-
monia per mole of NO for all fuels. However, the temperature dependence varied
from coal to coal. The Navaho exhibited peak reductions at the lowest tempera-
ture, 1720 °F, while the Illinois coal showed peak reductions occurring at 1830
°F. The optimum temperature for natural gas was 1750 °F. A very limited series
of tests was conducted to determine the cause of the variation in optimum tem-
perature, however no definitive reason could be found to explain this tempera-
ture variation. The unexplained variation in optimum process temperature
with coal type indicates that evaluation testing would be prudent in situations
where maximum NOx control was desired and no previous experience was avail-
able for the coal in question.
In general, the ammonia breakthrough emissions- are comparable for
all the fuels tested during this program. The highest emissions of ammonia
occurred when the temperature of the combustion products at the point of in-
jection was less than that required for optimum NO removal. With judicious
selection of the temperature at the point of injection, it was possible to
achieve nitric oxide reductions of 55% while limiting NH emissions to the
range of 10 to 35 ppm (for reference purposes, the odor level of ammonia is
commonly stated to be 50 ppm).
With ammonia injection, no statistically significant changes in the
cyanide and nitrate species concentrations were measured relative to the
baseline case of no ammonia injection. This supports previous studies
(Refs. 3, 4) that cyanide and nitrates are not byproducts of the selective
homogeneous reduction process. The primary products of the NOx removal pro-
cess are molecular nitrogen (N ) and water (H~0).
The SO levels in the flue gas tended to be lower when ammonia was
injected to reduce the oxides of nitrogen; this suggests sulfate producing
reactions between NH and SO . Quantitative variations in sulfate levels
with ammonia injection were somewhat inconclusive as only small changes were
measured. However, SO levels were reduced for each of the coals tested.
Further clarification of this point would seem warranted.
IX
-------
The experiments while firing the Pittsburgh seam coal further confirmed
that the addition of small quantities of hydrogen injected along with ammonia
can be used to increase the NO reductions and decrease the ammonia emissions
at lower temperatures than observed without hydrogen injection. At a given
temperature and ammonia injection rate, there exists an optimum rate of hy-
drogen injection. Further increase in the hydrogen injection rate results
in decreases in the amount of NO removed. This optimum hydrogen rate in-
creases as the temperature at the point of injection decreases.
With the exception of the variation in optimal process temperature
with coal type, the findings with NH injection into coal-derived combustion
products are in substantial agreement with previous experimental results
for gas and oil-fired systems (Refs. 3, 4) in terms of achievable NO reduction,
ammonia emissions, and byproduct formation.
-------
SECTION 1.0
INTRODUCTION AND OBJECTIVES
1.1 BACKGROUND
Numerous approaches are being considered for controlling NOx emissions
from stationary combustion sources. These approaches cover the spectrum
from "front end" control of the combustion process to the physical or chemical
removal of the oxides of nitrogen in the downstream regions of the unit. A
process that appears to be attractive for control of NOx emissions from coal-
fired utility boilers entails the selective gas phase decomposition of nitric
oxide by ammonia. In this process, ammonia is injected into the combustion
products; if the temperature of the combustion products is between 1200 °F and
2000 °F, the ammonia will selectively react with the nitric oxide in the pre-
sence of excess oxygen to form nitrogen and water vapor. However, nitric
oxide reductions on the order of 50% or greater occur in the vicinity of 1750 °F
(+_100 °F). A patent is held by the Exxon Research and Engineering Company
on this process (Refs. 2, 3).
Previously, EPRI sponsored a program to investigate the potential
for the gas phase reduction of NOx in utility boilers (Refs. 4, 5). During
this study a small natural gas-fired combustion tunnel was used to determine
the conditions of concentration, temperature, and reducing agent type which
would result in the selective reduction of NOx in the presence of varying
amounts of oxygen and nitric oxide. A selective reduction of NOx was found
to occur when ammonia was injected into combustion products which were
at a temperature from 1300 °F to 2000 °F with peak reductions occurring in
a narrow temperature region about 1750 °F. Typical results which were ob-
tained in this gas-fired combustion tunnel in terms of the effect of tempera-
ture and the amount of ammonia which was injected are shown in Figure 1. As
can be seen from this figure, approximately 80% of the NOx is removed when
one mole of NH_ is injected for every mole of NOx initially present.
-------
1.0
0,8
~ 0,6
0.2-
1200
Figure 1.
(NH)/(NO), MOLAR
1.6
I
I
1400 1600 1800
TEMPERATURE, "F
2000
2200
Effect of temperature on NO reductions with ammonia
injection. (Excess oxygen 4%, initial NO 300 ppm, Ref. 4)
Exxon Research and Engineering (the patent holder for the process)
has also done an extensive amount of proprietary development work on this pro-
cess. In fact, the process has been applied to a number of oil- and gas-
fired industrial boilers and process heaters in Japan.
1.2
OBJECTIVES
While a significant amount of data has been gathered on the selective
reduction of NOx in oil- and gas-fired systems, little information is cur-
rently available as to the applicability of the process to coal-fired power
plants. In particular, the levels of NOx reductions which are achievable and the
-------
associated byproduct emissions, as well as the possible catalytic or other
effects due to the coal ash and the injected ammonia must be developed.
The specific objectives of the study involved the
Determination of the levels of NOx removal and ammonia emissions
with ammonia injection into the combustion products resulting
from pulverized coal combustion. The primary variables of the
study were the temperature at the point of NH3 injection, the
amount of NH^ injected, and the coal type.
Determination of the type and levels of byproduct emissions. In
particular the following were determined: SC>2, 803, CO, CM, NH3,
unburned hydrocarbons, nitrate particulates, sulfate particulates.
Determination of any effects that varying coal types might have
on the process. A variety of coals were used in the study
including: a Utah bituminous, a Navaho subbituminous, Pittsburgh
Seam 8 bituminous and an Illinois bituminous. The results are
compared to the NOx emissions obtained with natural gas.
Determination of the extent to which hydrogen can lower the
temperature at which NH3 would remove NOx from coal derived
combustion products and to determine the effect of H2 on the
ammonia emissions at various temperature levels.
-------
SECTION 2.0
EXPERIMENTAL APPROACH AND APPARATUS
2.1 APPROACH
The objectives of the present program were accomplished through a
systematic series of experiments conducted in a pulverized coal combustion
facility capable of firing at rates up to approximately 3,000,000 Btu/hr
(nominally 250 Ib/hr coal feed). A description of the combustion facility
as well as the instrumentation employed and the experimental procedure com-
prises the remainder of this section.
2.2 COMBUSTION FACILITY
The combustion facility used in this program had the capability of
firing either natural gas or pulverized coal. A schematic diagram of the
facility is shown in Figure 2.
2.2.1 Combustor
The basic combustion facility consisted of a firetube boiler which
was modified to fire pulverized coal. A detailed description of the boiler
and auxiliary equipment is contained in Appendix A.
Stainless steel liners were installed in the main firetube as a means
of varying the gas temperatures at the point of ammonia injection {e.g., lower
gas temperatures were attained by removing sections of the liners).
-------
To Baghouse
Air Preheater
Venturi
NO
0
Secondary Air
Venturi
Tempering Air
Rotameter
Primary Air
Calibrated
Feeder'
Burner
Natural
Gas
Coal
Diluent
I
Heated Sample Line
fyvyiv,,. ,-ff. **...,-*--'v
r
|.TT^y>
Water C"o6Tec[
NH Injectors \
Stainless
Steel Liner
i
}
. . . .. i j
I
SO NO/ UHC
NOx
Con-
denser
0_ NO CO CO,
NH ,HCN
Ammonia Input System
Gas Analysis
Figure 2. Schematic diagram of combustion facility.
-------
The natural gas burner was a ring-type burner with a single air
register. During some of the natural gas tests, nitric oxide was added to
the combustion air to raise the exhaust gas nitric oxide levels to approxi-
mately 500 ppm in order to provide a more direct comparison to the coal-fired
test results.
The coal burner was a scaled-down version of a commercial burner
presently being used in a utility boiler firing western coal. This burner
incorporated a single adjustable air register and the primary air/coal
stream was mixed with the secondary air by swirling the primary mix ~
ture.
2.2.2 Ammonia Injection System
The ammonia injectors were designed to (1) provide rapid dispersion
of the ammonia into the combustion products, (2) allow axial positioning in
the boiler.
The injectors were fabricated of stainless steel and water cooled.
The ammonia was injected with a nitrogen carrier gas to increase the pene-
tration and mixing of the ammonia with the combustion products.
The injector system schematic is shown in Figure 3. It was found
early in the testing that the use of five injection points was the most ef-
fective means of achieving the best NO reductions and therefore the majority
of the tests were conducted with this configuration. For a commercial appli-
cation, a more extensive optimization of the NH3 injection system is warranted.
The mass flow rate of the injected nitrogen, ammonia, and hydrogen
were measured by rotameters as shown in Figure 4. The five separate ammonia
rotameters downstream of the main ammonia rotameter were used primarily to
balance the flows to the injectors and the total ammonia flow was determined
by the most accurate single rotameter.
-------
Support S-and
i
Figure 3. 80 HP boiler ammonia injection schematic.
-------
2.3 INSTRUMENTATION
All air flows and gas flows into the combustion facility were measured
either by calibrated rotameters or venturi flow meters. A complete description
is given in Appendix A.
Since the combustion product temperature and the level of excess oxygen
level were the primary variables of interest, no effort was made to accurately
calibrate the coal feeder. Instead, the coal firing rate was deduced from the
coal analysis, flue gas oxygen concentration and combustion air flow rate.
Low temperature measurements were made using chromel-alumel thermo-
couples. Gas temperatures in the combustion section were measured using an
aspirated thermocouple probe.
2.3.1 Aspirated Temperature Probe
An aspirated Pt-Pt/10% Rh thermocouple was used to obtain the tempera-
ture profile data. The aspirated thermocouple is used to minimize radiation
losses. In this device, the thermocouple is isolated from the surroundings
through a series of concentric ceramic radiation shields. At the same time,
the convective heat transfer to the thermocouple is increased by aspirating
the hot combustion gases past the thermocouple and radiation shields. The
probe used in the study is shown in Figure 5 and is a slightly modified de-
sign as used by the International Flame Research Foundation (IFRF) (Ref. 6).
2.3.2 Gas Analysis
The chemical analysis performed during these experiments included a
wide variety of techniques. Continuous gas analyzers were used to measure >
excess oxygen (O2), oxides of nitrogen (NO/NOx), carbon monoxide (CO), carbon
dioxide (CO ) , unburned hydrocarbons (UHC), and sulfur dioxide (SO,,).
Batch techniques were utilized for the determination of ammonia
(NH ), cyanide (CN), sulfur trioxide, sulfates, and nitrates. The
ammonia, cyanide, and nitrate species were bubbled through appropriate
-------
Circuit for
Single
Injector
Rotameter
0 - 1.55 scfm
Rotameters
0-3 scfm
-Injectors
Rotameter
0-0.3 scfm
Rotameter
0-0.3 scfm
Figure 4. Ammonia injection flowmeters.
-------
Combustion Gases
to Aspirating Puir.p
Thermocouple tf
Readout *
Out In
Cooling
Water
Sheathed
Pt/Pt-30% Rb
Thermocouple
Section A-A
Radiation
Shields
Approximately
1 in. O.D.
Figure 5. Schematic Diagram of Aspirated Thermocouple Probe.
(Not to Scale.)
-------
absorbing solutions dilute sulfur acid for ammonia, sodium hydroxide for
cyanide, and distilled water for nitrates. The resultant solution and the
probe and sample line washings were then analyzed using specific ion elec-
trodes. A summary of the gas analysis instrumentation is presented in Table
1. Further details of the instrumentation and procedures for the determination
of ammonia, cyano, and nitrate is contained in Reference 4.
Sulfates and SO, were determined by a procedure outlined by R. K. Lyon
of Exxon Research and Engineering (Ref. 7}. The sulfate was collected by
sampling the combustion products with a heated quartz probe and collecting
the sample on a heated filter maintained at 310 °F. A gravimetric procedure
was used for the sulfate analysis. The SO concentration was determined by
using the sulfate sampling system and adding an excess of ammonia to the
probe. It was assumed that the excess ammonia injected into the probe re-
acted with the free SO., in the sample to form a sulfate. The difference between
the sulfate levels with and without ammonia injected into the sampling probe
is taken to be the SO concentration in the sample. Appendix B contains a
more detailed description of the procedure for sulfate and SO determination.
TABLE 1. GAS ANALYSIS INSTRUMENTATION
Species
Analyzer
NO/NO,
°2
CO
co2
UHC
so2
NH3
CN
so.
TECO Model 10A Chemiluminescent (molybdenum converter)
Beckman Model 742 Electrolytic
Horiba Model PIR 2000 NDIR
Horiba Model AIA 21 NDIR
Beckman Model 402 Flame lonization Detector
Du Pont Model 401 Photometric
Orion 95-10 Specific Ion Electrode (701 Meter)
Orion 94-06 Specific Ion Electrode (701 Meter)
Orion 93-07 Specific Ion Electrode (701 Meter)
Gravimetric Analysis of filter catch
Gravimetric Analysis following conversion to sulfate
11
-------
2.4 EXPERIMENTAL PROCEDURE AND TEST MATRIX
2.4.1 Experimental Procedure
One of the primary parameters of interest was the combustion product
temperature at the point of ammonia injection. It was found that in order
to obtain the temperature range of 1500 to 2000 °F within the main firetube
the boiler had to be fired at a rate of approximately 1.5 to 2.0 million Btu
per hour. At this rate it required approximately one and one-half hours for
the boiler to stabilize before sampling could begin. Temperatures at the
point of NH injection could be varied 300 °F by simply changing the axial
position of the injectors while maintaining all other test conditions con-
stant. Removal of the stainless steel heat shields from the main firetube
provided further variation in temperature. By the combination of heat shield
removal and change in axial location of the NH, injectors, the temperature
range of approximately 1600 to 1950 °F was available.
Normally, temperature measurements were made during this warm-up
period to establish the point at which the boiler was stable and also to en-
able projections of the rate of changes of the gas temperature with time.
This was necessary since ash accumulation in the combustion section acted
as insulation and resulted in a continuous increase in temperature on
the order of one-half degree per minute after the initial warm-up period.
The gas temperature was also measured after each set of data to establish the
temperature-time history during the test period. Interpolation of this
temperature time history was used to determine the combustion product tempera-
ture at the point of ammonia injection.
This increase in temperature with time complicated the determination
of the exact temperature at the point of NH injection. The following pro-
cedure was adopted. The boiler was fired and the excess air set to yield ap-
proximately 5% excess oxygen at the firing rate which produced the desired
temperature range. These conditions were not changed during a test. The
aspirated thermocouple was inserted and the temperature of the gas along
the boiler centerline, was monitored until the rate of change approached
12
-------
1/2 °F per minute. Once this condition was achieved temperatures were
recorded at the various axial locations to determine the temperature range
available. Baseline NH , HCN, and NO emissions were taken during this time.
3 j
The probe was then removed and the ammonia injectors were inserted to the axial
plane which yielded the desired test temperature. An NH-j injection
rate was then set and all sampling commenced; the NH , CN, and NO samples
were taken concurrent with the continuous analyzer data of O , NO, NOx, CO,
CO , UHC, and SO .
After all NH3 injection data had been obtained, the ammonia injectors
were removed and the temperature probe was reinserted and again tempera-
tures were recorded. The temperature during the ammonia injection test was
then determined by interpolating between the temperatures recorded at the
beginning and end of each test.
A series of preliminary tests were conducted to assess the potential
problems that might occur when using the aspirated temperature probe to
measure exit gas temperatures under coal fly ash conditions. Using the
Utah coal it was found that plugging of the probe tip occurred after a few
minutes of aspirated operation. The problem was so severe as to make it
impractical, from fuel usage and time considerations, to attempt to fully
calibrate the temperature probe when firing coal.
The basic calibration of the temperature probe was done while firing
natural gas. The optimum aspiration rate on gas firing for the probe was
used for all other tests where it was necessary to obtain "true" gas tempera-
tures.
2.4.2 Test Matrix
The scope of the testing covered the following range of variables:
primary fuel type
ammonia concentration
combustion gas temperature
hydrogen concentration.
13
-------
The actual range of the above variables which were investigated are
presented in the test matrix outlined in Table 2.
TABLE 2. TEST MATRIX
a. Ammonia Injection Tests
Variable
Excess Oxygen
Nitric Oxide Level
Temperature at
Injection Point
NH Injection Rate
Approximate number of test
conditions for each fuel
Approximate total number
of ammonia injection tests
Range
Approx. 5%
Burner Produced
(500-810 ppm) S
1330 "F - 1965 °F
NH3/NO - 0-1.5* molar
Fuel
Natural
Gas
1*
1
4
4
16
Utah
Coal
1
1
10
4
40
Navaho
Coal
1
1
6
4
24
Illinois
Coal
1
1
6
4
24
Pittsburgh
Coal
1
1
9
4
36
140
b. Ammonia/Hydrogen Tests
Excess Oxygen
NOx Level
Temperature at
Injection Point
NH. Injection Rate
H Injection Bate
Approximate number of NH,/
H_ Injection Tests
Approx . 5%
Burner Produced
(approx. 650 ppn)
1300 °F - 1700 °F
NH /NO "V 1,0, 1.5 molar
H2/NOQ =0-2.5
~
~
~
~
~
«
~
~
--
~
~
~
~
1
1
4
2
4
32
*Signifies approximate number of test conditions
Limited testing done at ratios approaching 6
the natural gas tests, NO was added to the combustion air to produce
a stack level of 500 ppm
14
-------
SECTION 3.0
EXPERIMENTAL RESULTS
3.1 TEMPERATURE DISTRIBUTIONS
3.1.1 Axial Temperature Profiles
For each fuel type, an axial centerline temperature profile was
established for determination of the proper location of the ammonia injec-
tors for each test. A comparison of typical profiles for each fuel is
given in Figure 6. In this figure, changes in the axial centerline tempera-
ture are plotted relative to the temperature two feet from the back wall.
This was done to allow a more direct comparison for the fuels tested. The
change in temperature with axial location is influenced by the firing rate,
ash content of the coal, and number of heat shields used. A common curve
for all fuels and all conditions would not be expected; however, the axial
profiles are similar from coal to coal.
3.1.2 Radial Temperature Profiles
Radial temperatures were measured for all fuel types except the high
ash Navaho coal. Two of the three coals showed flat radial temperature pro-
files with a total temperature variation of less than 200 °F. The natural
gas fuel showed a radial temperature variation of approximately 250 °F.
Typical radial variations are shown on Figure 7. The differences in the
absolute temperatures in Figure 7 result from the fact that these data were
obtained at various axial locations. The data shown for the Pittsburgh coal
were obtained with the stainless steel liners removed in order to illustrate
the range of radial temperature gradients experienced throughout the study.
15
-------
600
Natural Gas
Utah Coal
Navaho Coal
Illinois Coal
O Pittsburgh Coal
2 4
Axial Distance From Rear Furnace Wall, feet
Figure 6. Typical axial variations of centerline temperature.
16
-------
From Figure 7 it can be seen that the axial centerline temperature
represents very nearly the average temperature for all of the coal types.
However, for the natural gas fuel, the centerline temperature is approxi-
mately 100 °F higher than the average radial gas temperature.
In all of the following data presentation, the centerline gas temper-
ature has been used as representative of the average radial temperature for
the coal tests. For the natural gas tests, the average radial temperature
is taken to be 100 °F lower than the measured centerline temperature.
The differences in the radial temperature profiles between natural
gas and coal firing were attributed to the burners. The gas burner was fired
at a lower air swirl setting than the coal burner to insure flame stability.
As a result of the lower swirl, the gas burner flame was visibly longer and
further from the walls than was that of the coal burner flame.
3.2 COAL PROPERTIES
The coals chosen for the test program were intended to cover a wide
range of composition and to be representative of typical steam coals currently
in use and of potential future use by the utilities.
All coals were procured in bulk form, air dried and then pulverized.
Pulverized coal samples were obtained during the test program for each of
the coals tested. An analysis of these coal samples is contained in Appendix
D. A brief comparison of the primary coal properties is presented in
Table 3.
17
-------
1900
1800
&H 1700
-P
rt)
e leoo
1500
1400
1300
Avg
c
L
Nat.Gas Utah Coal I11.Coal Pitt.Coal
Figure 7. Typical radial temperature variations.
18
-------
TABLE 3. COAL PROPERTIES (AS FIRED)
Rank
Proximate Analysis
% Moisture
% Ash
% Volatile
$ Fixed Carbon
HHV (Btu/lb)
Ultimate Analysis (% wt)
Moisture
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Oxygen
Sulfur Forms
% Pyritic Sulfur
% Sulfate Sulfur
% Organic Sulfur
Total Sulfur
Utah Navaho
Bituminous Subbituminous
4.24
4.85
36.38
54.53
13111
4.24
71.52
5.44
1.52
0.01
0.54
11.88
0.19
0.01
0.34
0.54
8.33
17.00
34.53
40.14
10336
8.33
57.98
4.40
1.48
0.01
0.57
10.23
0.19
0.00
0.38
0.57
Illinois
Bituminous
12.02
10.24
33.27
44.48
10941
12.01
60.42
4.36
1.07
0.03
2.94
8.93
1.27
0.06
1.61
, 2.94
Pittsburgh
Bituminous
1.67
7.16
37.13
54.04
13624
1.67
76.16
5.10
1.48
0.02
1.81
6.60
0.93
0.02
0.86
1.81
Ash content varied from 4.85% for the Utah coal to 17% for the Navaho
subbituminous. The sulfur levels covered a wide range from 0.54% for the
Utah coal to 2.94% for the Illinios coal. The fuel nitrogen did not vary
greatly from one coal to another.
3.3 NITRIC OXIDE REDUCTIONS
3.3.1 Effect of Temperature^ and Coaj- Type
One of the primary variables which determines the amount of NOx removed
by the injected ammonia is temperature. Previous studies have shown that
the selective homogenous gas-phase reduction of nitric oxide occurs optimally
19
-------
at about 1750 °F in gas and oil-fired systems. One of the major objectives
of this study was to determine if comparable results would be obtained with
coal-fired systems and the extent to which varying coal properties (e.g.,
sulfur content, ash characteristics, etc.) might affect the efficiency of
the process. A summary of the results obtained during this study for all
four coals and natural gas is shown in Figures 8a and 8b at molar ratios of
ammonia to initial nitric oxide of 0.5 to 1.0 respectively. It should be
noted that the curves shown in Figures 8a and 8b are cross plots of the data,
and not curves drawn directly through the data points.
For comparison, the data from Reference 4 are shown relative to the
natural gas tests obtained during this program in Figure 9. The data from
Reference 4 represent NO reductions by ammonia in a natural gas-fired com-
bustion tunnel which was isothermal radially and provided rapid mixing of
the ammonia with the combustion products. The NO reductions obtained with
coal and gas firing during this study were not as great as those previously
obtained in the small combustion tunnel (Ref. 4). This is probably attri-
butable to the radial temperature gradients in the larger coal and gas fired
combustion tunnel.
The other point to be noted is that while the temperature retired
for peak NO reductions fell within the range of 1720 °F and 1830 °F, the
range for natural gas and the Utah, Navajo, and Pittsburg coals was between
1720 °F and 1760 °F. The temperature required for peak NO reduction on
Illinois coal was approximately 1830 °F. The levels of NO reduction on all
fuels tested were comparable.
20
-------
1.0
0.8
0.6
O
3
O
Z
0.4
0.2
0
Natural Gas
- 'Jtah Coal
- Navaho Coal
Pittsburgh Coal
Illinois Coal
1500 1600 1700 1800 1900
Average Radial Temperature, °F
2000
1.0
0.8
0.6
O
S
3
0.4
0.2
Natural Gas
Utah Coal
.. Navaho Coal
Pittsburgh Coal
Illinois Coal
I
I
I
I
1500 1600 1700 1800 1900
Average Radial Temperature, °F
2000
A.
=0.5, Excess 0^ r
o 2
5.0%)
B.
(WH /NO =1.0, Excess 0. ^ 5.0%)
3 o 2
Figure 8. Effect of temperature on NO reductions, coal and natural gas firing.
-------
1.0
0.8
0.6
0.4
0.2
i 1 r
\
\
Present Study
. Results from Ref. 4
I I
1500 1600 1700 1800 1900 2000
Temperature, °F
1.0
0.8
0.6
§
0.4
0.2
0
i r
Present Study
-~~~~~" Results from Ref. 4
i i i
1500 1600
1700 1800
Temperature, °F
1900 2000
A.
B.
[NH /NO = 0.5 (molar), Excess O ^ 5.O%]
[NH /NO =1.0 (molar), Excess O_ "a 5.0%]
3 o t-
Figure 9. Comparison of NO reductions for natural gas fuel.
-------
One possible reason for the variation of temperature required
for peak reduction might be the sulfur content of the fuel. Limited testing
was conducted to determine the possible effect of sulfur on the NO reduction
process. During these tests, the unit was fired with a distillate type oil.
Carbon disulfide (CS2> was used to vary the sulfur content of the flue gases.
Ammonia was then injected at molar ratios of NH^ to initial NO of 1.0, and
the injectors moved axially in the furnace to change the average temperature
at the point of injection. The results of these tests are shown in Figure 10
for sulfur dioxide levels in the combustion products ranging from 120 to
2900 ppm. Over the range of sulfur tested, there was no effect in terms of
the temperature at which maximum NO reductions were achieved. In Figure 10
the data have been plotted as a function of axial location at the point of
NH3 injection along with a scale showing the approximate average axial
temperature. This was done since the radial temperature gradients with oil
firing are greater than with coal, and sufficient characterization was not
made in order to establish an accurate average radial temperature. While
these tests do not conclusively eliminate sulfur as having an effect on the
NO reduction process, they suggest very strongly that the sulfur does not
interfere with the NO/NH, chemistry.
3.3.2 Effect of Ammonia Injection Rate
The effect of the amount of ammonia injected on the NO reductions is
shown in Figures 11 through 15 for the four coals and natural gas. In these
figures, the ratio of the final NO concentration to initial NO concentration
is plotted versus the ratio of the amount of ammonia injected to the initial
concentration of NO (molar basis). Two test series are shown in these
figures. The open symbols represent tests for which ammonia, cyanide, and
nitrate data were obtained. The closed symbols represent results of tests
in which only the reductions in NO were determined to establish repeatability.
23
-------
1.0.
0.8
0.6
o
I
53
0.4
0.2
T
T
Excess Oxygen ^ 5%
Initial NO (NOO) : 350 ppm
NH.YNO ^ 1
3 o
Back
Wall
ri SO = 2900 ppm
r A
so.
I
= 1100 ppm
=120 ppm
I
I
I
12 34
Plane of NH3 Injection, Ft From Back Furnace Wall
.1.1 I I
1500 1600 1700 1800
Approximate Average Temperature, °F
Figure 10. Effect of sulfur on NO reduction (oil firing.)
24
-------
1.0
0.8
O
3
NH /NO , Molar
3 o
Open Symbols - Byproduct emissions
Closed Symbols - Other Data
Avg Temperature at Injection Point
£ 1515 °F
^ 1625 °F
£ 1725 °F
£ 1780 °F
Initial NO - 500-550 ppm
Excess O - 4.7-5.3%
Figure 11. Effect of NH, injection rate on NO reductions (natural gas
fuel).
25
-------
NH./NO
3 o
2.0 3.0
Molar
Open Symbols - Byproduct Emissions
Closed Symbols - Other Data
Average Temperature at Injection Point
01600 °F
1700 °F
1730 & 1750 °F
1770 & 1780 °F
1790
1830
1870
F
°F
°F
Figure 12.
1880 & 1890 °F
^ 1925 °F
A 1945 °F
Initial NO 660-810 ppm
Excess O 4.7-5.3%
Effect of NH3 injection rate on NO reductions (Utah
coal) .
26
-------
1.0
0.8
g
0.6
0.4
0.2
o
0.5
NH /NO ,
3 o
1.0 1.5 2.0
Molar Open Symbols - Byproduct
Emissions
Closed Symbols - Other Data
Average Temperature at
Injection Point
^f 1625-1660 °F
Al685-1700 °F
1715-1740 °F
^1830-1855 °F
1880-1890 °F
01950 °F
Initial NO 570-760 ppm
Excess O 4.8-5.6%
Figure 13. Effect of NH, injection rate on NO reductions (Navaho
coal) .
27
-------
1.0
0.8
0.6
0.4
0.2
O
0.5 1.0 1.5
NH /NO , Molar
Open Symbols - Byproduct
Emissions
Closed Symbols - Other Data
Average Temperature at
Injection Point
1660 °F
1750-1780 °F
1815-1830 °F
0 1860-1865 °F
1890-1915 °F
1965 °F
Initial NO 730-790 ppm
Excess O 4.7-5.4%
Figure 14. Effect of NH injection rate on NO reductions (Illinois
coal) .
28
-------
1.0
NH_/NO , Molar
3 O
Open Symbols - Byproduct
Emissions
Closed Symbols - Other Data
Average Temperature at
Injection Point
^1330-1395 °F
91405-1490 °F
1500-1540 °F
1545-1580 °F
1615-1635 °F
^1670-1700 °F
^1725-1760 °F
1770-1815 °F
^1830-1900 °F
Figure 15,
Initial NO 550-800 ppm
Excess O2 4.6-5.8%
Effect of NH injection rate on NO reduction (Pittsburgh
coal).
29
-------
Scatter in the data is suspected to be primarily due to variations in the
radial temperature gradients in the firetube, and the ash accumulation which
made a single temperature determination difficult.
As discussed in Section 3.2, the temperature at peak NO reductions
differed somewhat from fuel to fuel. A comparison of the data obtained at
the temperature where the maximum NO reductions are achieved is shown in
Figure 16. This figure shows that although the optimum temperature varied
from coal to coal, the peak reductions in NO were within the data scatter for
all fuels tested during this study.
3.4 NH3 EMISSIONS
Ammonia emissions were measured for at least four temperatures cover-
ing the range of 1600 to 2000 °F for each coal. These measurements were made
at the same conditions at which cyano and nitrate species were determined.
The results of these tests show that the ammonia breakthrough dimi-
nishes as the gas temperature at the point of injection increases. At
approximately 1900 °F, all traces of excess ammonia in the flue gas had
disappeared. The disappearance of the excess ammonia coincides with the
diminished effectiveness of the ammonia in producing NO reductions. At the
higher temperature, the injected ammonia will begin to react with the oxygen
in the combustion products to form rather than eliminate nitric oxide.
The ammonia breakthrough data for all fuels tested are shown in
Figure 17 through 21. In these figures, the data are plotted in terms of
the ratio of the ammonia concentration in the flue gas to the initial nitric
oxide concentration. This allows a direct comparison among the various testc
where the initial nitric oxide concentration varied. The scale on the right-
hand side of Figures 17 through 21 represents the approximate absolute level
of NH3 in the stack gases based on the average initial nitric oxide level
for the test series. As with the NO reduction data, it is of interest to
compare the ammonia emissions at the temperature of peak NO reductions; this
is shown in Figure 22. This figure indicates that the ammonia emissions, when
normalized to the initial NO concentrations, were comparable except for the
Illinois coal tests. The NH3 emissions from the Illinois coal tests were
significantly lower throughout the range of ammonia injection rates tested.
30
-------
1.0
0.8
0.6
O
S3
0.4
0.2
I
|Q> Natural Gas
O Utah Coal
D Navahb Coal
Illinois Coal
Pittsburgh Coal
00
0.5
1.0
1.5
NH./NO , Molar
3 o
2.0
Figure 16. Comparison of NO reductions at the optimum temperature condition.
-------
Injected, NH /NO , Molar
Figure 17. Ammonia emissions, natural gas fuel.
*Based on the average initial nitric oxide level
level for the test series.
350
300
_ 250
200
1515 °F
1625 °F
1780 °F
Initial NO: 500 - 525 ppm
I
a,
tn
c
o
H
W
w
H
X
z
0)
4*
10
32
-------
0.7
0.6 _
0.5
o
0°0.4
in
§ 0.3
-H
H
0.2
0.1
I
O 1600 °F
Q 1700 °F
A 1725 - 1755 °F
Q 1770 °F
£} 1880 and 1890 °F
O 1945 °F
Initial NO: 660-810 ppm
Excess O : 4.8-5.4%
_ 500
0.5
1.0
400
300
200
100
1.5
Injected, NH /NO , Molar
Figure 18. Ammonia emissions, Utah coal.
*Based on the average initial nitric oxide level for
the test series.
I
04
0}
c
o
-H
W
K
2
QJ
+J
(0
-H
a
33
-------
0.7
0.6
0.5
01
O
H
03
0)
H
H
0.3
0.2 _
0.1
400
^1625-1660 °F
A 1685-1700 °F
D 1715-1740 °F
O 1830-1855 °F
O 1880-1890 °F
O 1950 °F
Initial NO 570-760 ppm
300
200
Excess
4.8-5.6%
o
-H
in
in
2
0)
4J
(0
H
X
o
M
a
ft
100
1.0
1.5
NH.YNO
3 o
Figure 19. Ammonia emissions, Navaho coal.
*Based on the average initial nitric oxide level
for the test series.
34
-------
0.7
0.6
0.5
0.4
W
c
0
B 0.3
M
-H
W
0.2
0.1
500
400
Q 1780 °F
A 1830 °F
O 1860 °F
1890 °F
300
Initial NO - 715-810 ppm
Excess O - 4.8-5.5%
200
100
NH /NO
3 o
Figure 20. Ammonia emissions, Illinois coal.
*Based on the average initial nitric oxide level for
the test series.
a
a
a
o
H
U)
01
H
ro
§
01
4J
-H
X
O
^
Ck
s-
35
-------
u
m
CD
H
W
0.7
0.6
0.5
0.4
0.3
0.2
0.1
500
OlSOO-1540 °F
Ol670-1680 °F
Ql770 °F
Q1830-1900 °F
Initial NO
Excess O_
0.5
1.0
NH./NO
3 o
400
1.5
Figure 21. Ammonia emissions, Pittsburgh coal.
*Based on the average nitric oxide level for the test
series.
36
-------
0.4
Q Utah
Q Navaho
/\ Illinois
^Pittsburgh
Natural Gas
0.3
o
i 0.2
0.1
D
a
a
1.0
2.0
NH_ /NO
3 o
o
3.0
Figure 22. Comparison of the NH3 emissions for all fuels
tested at the peak NO removal temperature.
37
-------
3.5 CYANIDE AND NITRATE EMISSIONS
Cyanide and nitrate emissions were determined at the same test points
at which ammonia breakthrough was determined.
Typical test results of the cyanide and nitrate measurements are
shown in Table 4. (The complete test results are contained in Appendix C.)
The data in this table show that (1) for the majority of the data points with
coal firing, the cyanide emissions were less than 2 ppm, and (2) the cyanide
concentrations do not correlate with the amount of ammonia injected. During
several test series, higher cyanide concentrations were measured in the combus-
tion products but again this occurred also at the baseline condition with no
ammonia injection; no correlation to ammonia injection rate was observed.
In fact, in some cases, the cyanide concentrations were less with ammonia in-
jection than without. These tests support the conclusions from previous
studies (Refs. 3, 4) that cyanide species are not a byproduct of the NO reduc-
tion process by ammonia.
The nitrate emissions also showed no change when ammonia was in-
jected as compared to the condition when no ammonia was injected, indi-
cating that nitrates are not a major byproduct of the NO reduction process.
3.6 SULFATE AND SO EMISSIONS
Table 5 contains the sulfate and SO emissions data for the four coals
tested with and without ammonia injection. The effect of the ammonia on the
sulfate emissions was not conclusive since in two cases there was no change
in the sulfate emission; in one case there was an apparent increase and in the
other case there was an apparent decrease. The fact that the data are some-
what inconclusive can be partially attributed to two factors: (1) experimental
difficulty in maintaining the probe and filter at a constant temperature, and
(2) no effort was made to determine if sulfate was retained in the boiler.
The procedure used to determine the sulfate and SO emissions was outlined in
Section 2.3 and discussed in Appendix B.
38
-------
TABLE 4. SUMMARY OF CYANIDE AND NITRATE CONCENTRATIONS
Fuel
Natural Gas
Utah Coal
Navaho Coal
Pittsburgh Coal
Illinois Coal
Ammonia In j .
T
AVg
<°F)
1780
1780
1725
1620
1700
1770
1700
1740
1840
1880
1730
1750
1760
1770
1850
1870
1830
1830
1830
1830
1860
1860
1860
Condition
NH3/N00
Molar
0
0.55
1.23
1.21
2.5
0
1.14
3
0
1.04
1.14
1.28
1.5
0
0.6
1.0
1.26
1.5
1.0
1.5
0
0.5
1.0
1.3
1.6
1.0
1.25
1.57
Flue
NO/N00
1.0
0.53
0.24
0.29
0.3
1.0
0.27
0.07
1.0
0.31
0.35
0.41
0.79
1.0
0.59
0.41
0.27
0.21
0.54
0.38
1.0
0.55
0.39
0.32
0.27
0.41
0.27
0.20
Gas Composition
CN
ppm
<1
<1
<1
<1
<1
-------
TABLE 5. SULFATE AND SO3 EMISSIONS WITH
AND WITHOUT AMMONIA IN THE FLUE GAS
Coal
Utah
Navaho
Illinois
Pittsburgh
ppm, uncorrected
NH3 S04 S03
0
77
108
0
32
0
22
0
18
5
5
4
7
7
20
26
32
31
1
1
1
5
3
21
18
19
10
However, the SO emissions were observed to decrease when ammonia
was injected into the boiler for each coal tested and suggests that reac-
tions between NH, and SO, are occurring. The decrease, however, was not in
proportion to the amount of excess ammonia present in the flue qas.
Within the accuracy of the experimental measurements, it was not pos-
sible to detect a significant change in neutral sulfate emissions, although
a slight reduction in SO emissions with ammonia injection was observed- Further
work to clarify this matter would seem warranted.
3.7 CARBON MONOXIDE EMISSIONS
The emissions of carbon monoxide from coal fired utility boilers while
not of primary concern from the standpoint of pollution can have an impact on
the efficiency of the unit. R. K. Lyon of Exxon Research and Engineering has
indicated that the selective NO reduction process will inhibit the oxidation
of CO to CO . Thus if CO is still present at the point of ammonia injection
its oxidation could be prevented and it could be emitted to the atmosphere.
40
-------
The test results from the present program on coal fired systems
indicate that while there does appear to be some inhibition of the oxidation
of CO to CO this is not a problem over the range of ammonia concentrations
of interest. Typical baseline CO emissions for the four coals tested are
shown in Table 6 along with the CO levels over a range of ammonia injection
rates at various temperature rates. As can be seen from the results of
these tests, incremental emissions of CO with ammonia injection are slight
and should not be a problem in coal-fired systems (further data can be found
in the data summary sheets in Appendix C).
3.8 SO AND NOx MEASUREMENTS
During the test program both SO and NOx were measured to determine
(1) if any excess ammonia reacted with the SO and (2) if there was a change
in the NO/NOx ratio (e.g. did the ammonia selectively react with NO or both
NO and NO ). For the case of the Utah and Navaho coals the NOx to NO ratio
did not change upon the addition of ammonia indicating that the total oxides
of nitrogen were reduced during the process.
Some difficulty was experienced in measuring the NO and NOx through
the heated line under conditions where the flue gas contained high concen-
trations of NH and SO ; in particular for the tests with the Illinois and
Pittsburgh coal. Reactions occurred in the heated sample line which resulted
in a net loss of NOx. For instance, the dew point of the combustion products
from the Illinois coal was on the order of 270 °F. Unfortunately the heated
sampling line was only capable of operation to 260 °F. Thus some condensation
was expected with subsequent reaction with the ammonia and NOx in the sample.
Ideally it would be desirable to operate the sampling line above the dew
point and temperature at which the ammonia/sulfur compounds form (i.e.,
approximately 320 °F).
41
-------
TABLE 6. EFFECT OF AMMONIA INJECTION ON CO EMISSIONS
Fuel
Utah
Navaho
Illinois
Pittsburgh
Ammonia Iniection Condition
T
OF
1770
1770
1700
1715
1725
1740
1735
1830
1830
1830
1730
1750
1770
NH /NO
3 o
0
1.17
0
1.14
2.93
0
0.4
0.92
1.14
1.04
0
0.51
1.02
1.57
0
0.56
1.0
1.5
Flue Gas Composition
NO/NO
o
1.0
0.36
1.0
0.21
0.08
1.0
0.7
0.43
0.35
1.0
0.31
1.0
0.55
0.39
0.27
1
0.59
0.41
0.21
NH3
ppm
0
108
0
178
1008
32
13
22
3
12
112
5
41
100
CO
ppm
55
65
60
85
90
75
75
75
65
50
70
50
50
50
50
50
80
100
iqo
42
-------
A similar situation was encountered with the continuous measurement
of SO . When the ammonia content of the sampled combustion products was on
the order of a third of the SO concentration a loss of SO was observed in
£ £
the sampling lines. This was a sampling line phenomena and not occurring in
the boiler since when the ammonia was turned off the heated line took approxi-
mately 20 to 30 minutes to stabilize. This suggests an adsorption-desorption
process on the teflon sampling line rather than a process occurring in the
boiler. At lower SO to NH ratios in the flue gases there appeared to be
^ *J
no significant change in the SO levels with ammonia injection. The observed
changes were as much associated with sulfur variability in the coal fed to
the boiler as any reaction with the excess ammonia. The sulfate and SO
measurements tend to support this observation.
3.9 AMMONIA AND HYDROGEN INJECTION
A limited number of tests were conducted to determine the effect of
combined ammonia and hydrogen injection upon the NO reductions in coal-
derived combustion products. The Pittsburgh seam #8 coal was used for these
experiments .
Exxon studies with oil and gas fuels had shown that at a given tempera-
ture, hydrogen had the effect of increasing the NO reduction and simultaneously
reducing the ammonia breakthrough. That is, the hydrogen can be used to pro-
duce higher nitric oxide reductions at lower temperatures.
The data collected during this study confirms that the hydrogen allows
the reduction of NO with ammonia to occur at a lower temperature. A typical
representation of the NO reduction effect is shown on Figure 23. It can be
seen from this figure that the addition of hydrogen is beneficial in the low
temperature range.
When the data such as that shown in Figure 23 are cross plotted against
the amount of hydrogen injected (H2/NH3 molar ratio) for a given temperature,
the resulting curve will exhibit a minimum (or maximum in terms of NO removal).
43
-------
1.0
0.8
0.6
o
2:
1300
1400
I
I
985
1500 1600 1700
Centerline Temp. °F
1800
1
1900
2000
Figure 23. typical NO reduction with ammonia and hydrogen injection - Pittsburgh coal.
-------
The locus of all maximum NO reductions plotted versus temperature are then
plotted in Figure 24. This shows the maximum NO reductions achievable over
the temperature range for a given amount of injected ammonia. Figure 24
clearly shows that at temperatures below the optimum, the NO reductions can
be significantly better with H /NH injection than with ammonia alone.
The ammonia emissions were measured for three temperature levels
with H /NH injection. The corresponding NO and NH data are shown in
Figures 25 and 26 respectively. These tests show that along with an
increase in NO reductions, hydrogen also results in lower ammonia emissions.
At high hydrogen injection rates, the NO levels begin to increase while the
NH levels in the combustion products continue to decrease.
The experimental results presented in this section are drawn from
data summarized for each fuel type in Appendix C.
45
-------
1.0
0.8
0.6
I
0.4
0.2
NH /NO % 1.0
3 o
No Hydrogen Injection
Maximum Reduction
Obtainable with Hydrogen
Injection
I
I
I
1300 1400 1500 1600 1700
Centerline Temperature, °F
1800
1900
Figure 24. Cross plot of the optimum NO reduction for NH /NO = 1.0 (variable
hydrogen injection), Pittsburgh coal. °
46
-------
0.2
0
c
ppm Temp. Range
655 1395-1445
610 1540-1640
680 1700-1705
680 1710-1715
1.0
2.0
3.0
H2/NH3, Molar
Figure 25. NO reductions with ammonia and hydrogen injection - Pittsburgh coal.
47
-------
oo
0.2
2.0
H /NH , Molar
600
_ 500
_ 400
300
200
a
in
o
H
w
en
H
0)
+J
<0
H
X
o
_ 100 ft
3.0
Figure 26. Ammonia emissions for ammonia and hydrogen injection - Pittsburgh coal.
*Based on the average initial NO level (See Figure 25.)
-------
SECTION 4.0
CONCLUSIONS
1. NO reductions obtained with ammonia injection into coal-derived
combustion products were comparable to those previously obtained
in natural gas and oil-fired systems. On the order of 65% reduc-
tions in NO were obtained at an ammonia injection rate of one
mole of ammonia per mole of NO.
2. The temperature dependence varied from coal to coal. The Navaho
coal exhibited peak reductions at the lowest temperature, 1720 °F,
while the Illinois coal showed peak reductions occurring at
1830 °F. No definitive reason could be found to explain this
variation in temperature. The unexplained variation in optimum
process temperature with coal type indicates that evaluation test-
ing would be prudent in situations where maximum NOx control was
desired and no previous experience was available for the coal in
question.
3. In general, the ammonia emissions (or breakthrough) are comparable
for all fuels tested during this program. The highest emissions
of ammonia occur when the temperature of the combustion products
at the point of injection was less than that required for optimum
NO removal. With judicious selection of the temperature at the
point of injection, nitric oxide reductions of 55% were achieved
while limiting NH emissions to the range 11 to 34 ppm.
4. Using injection rates of ammonia less than 2:1 NH /NO, no stati-
stically significant changes in the cyanide or nitrate species
concentrations were measured relative to the baseline case of no
no ammonia injection. It was concluded that they are not by-
products of the deNOx process in coal-fired systems.
49
-------
5. Within the accuracy of the experimental measurements, there was a
tendency to reduce the SO level in the combustion products during
ammonia injection. However, due to the small changes in the sulfate
levels with and without ammonia injection, the question of sulfate
formation is inconclusive.
6. The addition of small quantities of hydrogen can be used to increase
the NO reductions and decrease the ammonia emissions at temperatures
lower than optimum.
7. At a given temperature and ammonia injection rate there exists an
optimum rate of hydrogen injection. Further increase in this
optimum rate results in decreases in the amount of NO removed.
This optimum hydrogen injection rate increases as the temperature
at the point of injection decreases.
8. These findings with NH injection into coal-derived combustion pro-
ducts were in substantial agreement with previous experimental re-
sults with gas- and oil-fired systems (Refs. 2, 3) in terms of
achievable NO reductions, ammonia emissions, and byproduct formation.
50
-------
REFERENCES
1. Proceedings of the Stationary Source Combustion Symposium, Volume
I - Fundamental Research, EPA-600/2-76-152a, p. 1-14, June 1976.
2. Lyon, R. K., "Method for the Reduction of the Concentration of
NO in Combustion Effluents using Ammonia," U.S. Patent No.
3,900,554, assigned to Exxon Research and Engineering Company,
New Jersey, August 1975.
3. Lyon, R. K. and Longwell, J. P., "Selective, Non-Catalytic Reduction
of NOx with NH3," EPRI NOx Control Technology Seminar, San Francisco,
California, February 5 and 6, 1976 (EPRI Special Report SR-39) .
4. Muzio, L. J. and Arand, J. K., "Homogeneous Gas Phase Decomposition
of Oxides of Nitrogen," EPRI Report FP-253, August 1976.
5. Muzio, L. J., Arand, J. K., and Teixeira D. P., "Gas Phase Decompo-
sition of Nitric Oxide in Combustion Products," EPRI NOx Control
Technology Seminar, San Francisco, California, February 5 and 6,
1976
6. Chedaille, J. and Braud, Y., Industrial Flames, Volume 1; Measure-
ments in Flames, Edward Arnold Ltd., London, 1972.
7. Lyon, R. K., personal communication, 1977.
51
-------
THIS PAGE INTENTIONALLY LEFT BLANK
52
-------
APPENDIX A
EXPERIMENTAL APPARATUS
A-l
-------
SECTION A-1.0
EXPERIMENTAL APPARATUS AND PROCEDURE
The test equipment, shown in Figures A-l through A-4, can be divided
into five categories: (1) burners, (2) air supply, (3) fuel supply, (4)
boiler furance, and (5) instrumentation. Each of these categories is dis-
cussed separately below.
A-l.l TEST BURNER DESIGN
A Foster Wheeler burner currently being used in a modern coal-fired
utility boiler was chosen as the basis for the laboratory scaled burner.
The modeling approach used was to preserve the temperature, velocities,
and volumetric heat release rate of the full size unit as well as geometrical
similiarity of the burner. The scaled-down version of the full-size burner
is shown schematically in Figure A-4.
A-l.2 AIR SUPPLY
The air supply system is shown schematically in Figure A-5.
Three venturi meters and one rotameter were used to measure the
various air flows into the boiler. The total air flow was the sum of the
flows measured by the "main air flow" venturi and the "tempering air"
rotameter. Air from an indirect-fired preheater passed through the main
air flow venturi, where the total mass flow of preheated air was measured.
The preheated air was then split into two streams: one to supply part of
the primary combustion air, and the other to furnish secondary air to the
burner.
The solid fuel was added to the conditioned primary air just upstream
of the burner. The primary air-coal mixture entered the burner tube tangen-
tially, forming a vortex.
A-2
-------
LEGEND - For Figures A-l - A-3
1. Primary Air Duct
2. Primary Air Valve
3. NOx-Port Air Duct
4. NOx-Port Air Valve
5. NOx-Port Air Venturi
6. NOx-Port Air Flexible Hose
7. NOx-Port Air Injection
Torus and Inlet Pipe,
Variable Position
8. Water Injection Nozzle
9. Burner Support Cylinder
10. Air Register
11. Flame Detector
12. Ignitor
13. Burner
14. Ceramic Quarl - 5-1/2"
Throat Diameter
15. Observation Door
16. Fire Brick 25" Inside
Diameter
17. View Ports
18. Water Wall of Scotch Boiler
Steam Vent
19.
20.
Stainless Steel Liner
34" Inside Diameter
21. Fire Tubes (62 with
Diameter 2-7/8")
22. Recirculation Gas Duct
23. Recirculation Gas Venturi
24. Damper
25. Stack
Instrumentation
Temperature s:
26. Windbox
27. Hot End
28. Stack
29. Secondary Venturi
30. Recirc. Venturi (Not Shown)
31. Primary Air
Pressures:
32. Windbox
33. Secondary Venturi
34. Recirc. Venturi (Not Shown)
Gas Sample:
35. Hot End
A-3
-------
From Preheatei_j^f~~^
and Fan
Burner
Air
I
iner Combustion
33" Chamber l
h-
2*7"
Solid Fuel »
K\\\\\\\\\\\\\\\\\\\\\V\V\\
9'3"
22"
t
Primary
Air
Second-Stage
Air
Figure A-l. Schematic of eighty-horsepower boiler.
-------
o©
Figure A-2. Cross section through windbox.
Figure A-3. Cross section through firebox.
-------
Castable
Refrac-
tory
2.3
Castable
Refrac-
tory (High
Purity
Alumina)
Primary Inlet 2x2 inside diam.
Ignitor Gas *- Air
Coal
1
H'l
T
t 1.675
condary Air
1 1
8.0
dia.
J Ter
*
tiary
1
t
.70 I.D.
All dimensions in inches
Figure A-4. Small-scale version of a full-scale coal burner.
-------
Gr
V_y Re
Tempering Air
Rotameter
Steam Fuel
i I
Primary Air
Secondary Air
NOx Port Air
To Burner's
Fuel Annulus
To Burner's
Air Register
To Torus
Venturi
Figure A-5. Schematic of combustion air supply.
-------
The remainder of the preheated air passed through an insulated duct
to a point about ten feet upstream of the windbox where two valves were
used to regulate the flow split between burner secondary and second-stage
(NOx-port) air. This feature was not used in the current study and the
second-stage air torus (#7, Fig. A-l) was removed.
The secondary air (delivered to the burner) was split into two
streams which entered the windbox from opposite sides. This air flowed
into the combustion chamber through the burner's air register vanes, which
imparted a swirl to the flow in the same direction as the primary mixture's
swirl.
The second-stage, air passes through a venturi meter, then into a
pipe leading to a perforated torus inside the combustion chamber. The air
can be injected from the torus radially toward the axis of the combustion
chamber through 32 orifices, each 9/16" in diameter.
A-1.3 FUEL SUPPLY
The solid fuels were fed into the primary air stream by a Vibra-Screw
feeder with a vibrating-bottom bin. The feed rate of the 1-1/2" diameter
spring-type screw was continuously variable.
The feed flow included fluctuations which varied with each fuel.
Fluctuations in flue gas excess O indicated fuel-flow variations of as
much as +^ 5% in some cases.
The natural gas fuel was supplied by the high-pressure supply from
the meter (5 psig). Flow rate was varied manually by a gate valve downstream
of a rotameter.
A-l.4 BOILER FURNACE
The boiler shell is an 80 horsepower Scotch dry-back type boiler
originally designed for low combustion intensity. The steam produced was
vented at one atmosphere. Schematics of the boiler and burner were given
in Figures A-l through A-4.
A-8
-------
The boiler's combustion chamber was fitted with a stainless steel
liner to give wall temperatures of approximately 800 °F, which is typical
for the combustion chambers of utility and large industrial boilers.
The fly ash was removed from the flue gas by a reverse-pulse
baghouse. Sulfur oxides were dispersed by discharging the ash-free
products (through an induced-draft fan) to a 42-ft high stack.
A valve at the baghouse inlet was used to maintain the boiler
pressure within 0.1 IWG of atmospheric pressure, thus minimizing leakage
into or out of the system.
A-1.5 INSTRUMENTATION
Flue gas samples were withdrawn by a diaphragm-type vacuum pump
at three points just upstream of the boiler's draft damper. Each of these
sample lines had a porous metal filter at its end to prevent fly ash from
being drawn into the sample line. The lines were periodically backflushed
to prevent blockage of the filter.
One of the sample lines was used for the supply to the SO , NOx,
and UHC analyzers. The other two sample lines were fed to water-filled
bubblers where the sample flow rate from each line were approximately
balanced by adjusting the bubbling rates to be approximately equal. The
samples were then blended into a single stream which was passed through a
filter and a Hankison Series E refrigerator-type drier to remove water
vapor.
Concentrations on a dry basis of NO, O , CO, and CO were measured
continuously using a Thermo Electron Corp. chemiluminescent nitric oxide
analyzer with a NO converter, a Beckman Model 742 oxygen electrolytic
analyzer, a Horiba Model PIR2000 nondispersive infrared carbon monoxide
analyzer, and a Horiba Model AIA-21 nondispersive infrared carbon dioxide
analyzer. These instruments were calibrated several times per hour using
known calibration gases. The outputs of these instruments were monitored
continuously on a Texas Instruments recorder.
A-9
-------
Sulfur dioxide was measured using a Dupont Model 411 photometric
analyzer. The Thermo Electron NOx analyzer was used with a NO moly
converter to obtain total NOx. The converter was necessary to prevent
catalytic conversion of NH to NO in the converter- which can occur with
a stainless steel converter.
Ammonia, cyanide, and nitrates were collected and analyzed with
specific ion electrodes as discussed in Reference 4.
A Beckman Model 402 hydrocarbon analyzer was used to measure
unburned hydrocarbons.
Temperature measurements other than the gas temperature in the main
firetube were made using chromel-alumel thermocouples. The temperature
probe used to determine the gas temperatures at the point of ammonia injec-
tion were described previously in Section 2.3.1.
A-1.6 AMMONIA INJECTORS
The basic schematics and a detailed design of the ammonia injectors
are given in Figures A-6 through A-8. With the arrangement shown, the
ammonia can be injected at either a single location on the boiler center-
line (with six tip injection points) or at five locations as shown in
Figure A-6 (each with six tip injection points). All injection orifices
are located perpendicular to the average flue gas streamlines (radial
injection).
To maintain the integrity of the injectors, they were fabricated
from stainless steel and water cooled. They were sized for 2 gpm per
injector flow rate at the most adverse temperature conditions with a maxi-
mum of 4 ft of each injector exposed to the hot gases.
Nitrogen was used as a carrier gas for the ammonia to assist in
optimum penetration and mixing. Each injector ammonia flow rate as well
as the total ammonia and nitrogen flow rates were measured as shown in Figure
A-8-
A-10
-------
Support Stand
Combustion
Products
Figure A-6- Eighty-horsepower boiler ammonia injection schematic.
-------
to
3.25-
2.0
- 1.0
0.06
Washer Weld *"|
to Both v
Tubes >| *
I
See View A
3/16 x 0.029 wall
321 SS tubing
2.50
3.75
5/8 x 0.035 wall
321 SS tubing
3/8 x 0.016 wall
321 SS tubing
96.0
, .38
rr
, 1
I
, -14
Kiz-
0.04 ^-\
0.03
View A
1
i
-
/
i-«
i
s 180 dec
r orific
Ilnje
Inje
ODQ
~ ' 0.08
0.13
0.12
0.25
0.24
Six orifices equally spaced with two orifices
180 deg. apart in line with Swagelok fittings
Injector #1 - 0.029-0.030
Injector #2 - 0.012-0.013
Fab only 1 injector
Fab 5 injectors
Figure A-7. Water cooled ammonia injection system.
-------
Circuit for
Single
Injector
I
T
Rotam.
0-0.3
scfm
Rotameter CO
0-1.5 scfm
N,
Injectors
Rotameter
0-3 scfm
Figure A-8 . Ammonia injection flow metering system.
A-13
-------
The ammonia injector orifices were sized to give sonic flow at
maximum ammonia flow rates. The calculated pressure drop through a single
injector is 7.9 psi for the maximum combined flow rate of nitrogen and
ammonia. The maximum ammonia flow rate per injector is 0.3 scfm (air
equivalent) .
A-14
-------
APPENDIX B
SULFATE AND SO EMISSION MEASUREMENT PROCEDURE
B-l
-------
SECTION B-1.0
SAMPLING TRAIN AND SAMPLING PROCEDURES
Figure B-l shows a schematic of the sulfate and SO sampling system.
It consisted of a heated quartz probe, a glass tube adapter for introducing
ammonia in the probe, a heated box which contains the filter holder, acid
washed asbestos fiber filter, impinger train, ice bath, dry gas meter, and
a pump.
Probe
Duct
Probe Adaptor (2nd Sample Use "T")
'Heated Filter Box
Pump
Impingers 1st, 2nd, 3rd
thermometer 50 ml each
3% H202
Ice Bath
Figure B-l. Sulfate sampling equipment.
A 30 cfm sample was collected at 1 cfm from the stack during which
time the probe was maintained at 205 °F, the heated box was maintained at
310 °F, and the impingers at 70 °F. The impingers contain a solution of 3%
hydrogen peroxide in water.
Two sampling modes were used. One mode collects the sample directly
from the stack without any dilution or additions to the probe. In the second
mode, ammonia is bled into the probe before the heated filter to react with
any free SO that might be present to form (NH.) SO. which would then be
collected on the filter. Table B-l contains a list of compounds and their
melting points that potentially could be formed with the ammonia.
B-2
-------
TABLE B-l. AMMONIUM COMPOUNDS
Compound
ammonium sulfate (NH ) SO
ammonium bi sulfate (NH.)HSO,
4 4
ammonium sulfamate NH.NH_SO
ammonium sulfite (NH_)SO HO
£ 3 £.
ammonium bisulfite NH HSO
ammonium hydrosulfide NH HS
ammonium monosialfide (NH .) S
rap (°F)
d 454
295.8
256.4
d 139.4 - 157.4
sub 301.4 in N
244
150 atm
d
bp (°F)
d
d 319.4
sub 301.4
1623
19 atm
d = decomposes; sub = sublimes
Following the sample collection, the .probe, connections, and front
half of the filter holder were washed with distilled water. The filter was
added to these washes and reduced to pulp to dissolve all of the collected
sulfate. The back half of the filter holder and connections were washed
with distilled water and added to the impinger condensate. The impingers
contain the SO component and the filter contained either the SO or SO
reacted to NH.SO with added probe ammonia.
B-l.l SO AND NEUTRAL SULFATE ANALYSIS
The gravimetric procedure was used to determine the neutral sulfates.
In this technique, the initial filter wash is filtered through a Whatman #4
filter paper. The filtrate is heated to near boiling and concentrated ammo-
nium hydroxide is added. This solution is then filtered again to remove
iron and aluminum and made acidic with concentrated hydrochloric. Ten milli-
liters of a 10% barium chloride solution is added to the warm acidic solution
and allowed to stand overnight to precipitate BaSO . This solution is then
passed through a tare-weighed Gooch crucible. The crucible is then baked
at 800 °C for 1 hour, cooled, and weighed to determine the resultant
The amount of SO equivalent sulfate is calculated using the following
expression:
B-3
-------
10,400 (weight sulfate as SO )
SO ,wet standard cubic feet of sampled gas
The level of sulfur trioxide in the flue gas was obtained by assum-
ing that the ammonia injected into the probe reacted with all of the SO .
Thus the difference between the sulfate determined with and without NH,
injected into the probe is the concentration of SO .
The presence of free SO was detected by adding a few drops of methyl
orange to the filter wash solution. If the indicator turned the solution red,
then free SO was present and a standard acid-base titration procedure using
0.01 N sodium hydroxide titrant was performed.
B-4
-------
APPENDIX C
DATA SUMMARY'
C-l
-------
NATURAL GAS FUEL
Test
Date
i-tt-n
Time
I014S
(US'
IZoS
^IS"
1430
IS2o
2A
scfm
32 l(o
irao : . o
HN3 ; 0
14Z8 15
i&ss" zr
1611 * 35"
nat
1«4HC»
7o
o
Ifcft : ir
it-^o 2r
1703 sr
1130 70
14,3^ ! 0
ie«j( i it
1867
1^0^
zr
?r
\&ta i 75*
C-2
-------
NATURAL GAS FUEL
Test
Date
l-H-77
1-23-77
Time
1053
I2oo
I3o5
\52S~
I5S5T
loiS"
scfm
3Z
r
3S5"
i
»
3^o
>
3^
>
t
°2
Pet
H.5
^
-
5.S
i
r
S.-aj
«
F
6.1
t
r
7.q
*
Temp. Probe
Location
Axial
2
>
r
3
>
r
14
'
t
4 4
I
f
z
\
2
\
r
Radial
c^
1
f
O_
1
8
M
6
2
<^
Temperature
mzc,
i»0
O
20
7S
o
2o
70
O
nn i 20
nio
15QO
n&7
1 ^ ^.*3
1 TO J^
10
0
2o
7o
Itoq ; o
nil ] 20
I6S3
7o
l3C*i ; O
m£iQ j
ni^ t
143o
ISR4
i
C-3
-------
NATURAL GAS FUEL
Test
Date
1-31-77
2-/-77
Time
leSS-
IC^S
1135
scfm
332
i
31o
!
J
°2
Pet
7.o
)
/
SI
P
62
1
f
Temp. Probe
Location
Axial
1}
^
3
r
2.
X'/2
3
M
H'4
Radial
c^
4
8
^
5
(b
7
e
3
c^
CL
>
H
^
H'-i
8
8'/2_
2.
i)/*}
v?
T
G'4
^
i
(
Temperature Aspi^r
°F PC
IMlM 1
isii
i3«ie
less
1716
IM3I
151Z
lU7o
N73
iMol
1^03 7
ISBl
160-8
1734,
nto
\i^
ittr
\4«41
t-/^
[74,4,
147 e
Wftl
15-3^
1733
I6i|
11*21
n**r
ife^fc
l^f/M :
./
C-4
-------
NATURAL GAS FUEL
Test
Date
2-1-17
a-7-n
Time
1015
12MO
132.0
scfm
390
i
1
i
3SI
4
?
Pet
s.
e
i
i
j
;
!
]
-
5,0
5,1
5
.or
Temp. Probe
Location
Axial
H
i
1
2.
3
M-
a
3
14
3
i
T
Radial
Q.
8
^
M
5
G
7
2
3
Q.
1
i
Ci.
i
i
Temperature
op
1S4G
Hft5
UTI
1851
ITte
H85
l4M*i
16^5
1^90
n^o
\1T(
134,1
mw
icia
nzs
1^2S
fl^,-
10
o
1
1
/^7I
lobo
161 S
I
I
C-5
-------
NATURAL GAS FUEL
Test
Date
Time
scfm
Pet
Temp. Probe
Location
Axial
Radial
Temperatvire
°F
looo
3 £5"
3'4.
S
1
16S5"
1513
C-6
-------
UTAH COAL A
Test
Date
Time
scfm
°2
Pet
Temp . Probe
Location
Axial
Radial
Temper at lire
3-q-n
LlCUT
IS'IO
1325
isvr
tSSB
IGZo
H.fc
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Test
Date
3-2$- -17
5-IZ-T7
Time
1330
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Date
3-31-17
Time
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C-9
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Date
4-ZO-T7
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-------
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-------
APPENDIX D
FUEL ANALYSIS
D-l
-------
COMMERCIAL TESTING & ENGINEERING CO.
GENERAL OFFICES: 91* NORTH L> SALLE STREET, CHICAOO. ILLINOIS SOS01 AREA CODE 311 7J8-84S4
PLE"E ADDRESS ALL CORRESPONDENCE TO
1« \N DRUNEN ROAO. SOUTH HOLLAND. ILLINOIS 60«73
SIMCE 1*O*
OFFICE TEL |313) H4-1173
March 15, 1977
KVB, INC.
17332 Irvine Blvd.
Tustin, CA 92680
Kind c? sample
reported to us
Sample taken at __
Sample taken by KVB/ Inc>
Date sampled ____
Sample identification
by
KVB, Inc.
P. O. # 12 121
Project # 15500
P.C 12
Coal sample
Analysis report no. 71-461882
PROXIMATE ANALYSIS As received Dry basis ULTIMATE ANALYSIS
% Moisture
%Ash
% Volatile
% Fixed Carbon
4.24
4.85
36.38
54.53
JQOCXX
5.06
37.99
56.95
Btu
% Sulfur
% Alk. as Na,O
SULFUR FORMS
% Pyritic Sulfur
% Sulfate Sulfur
% Organic Sulfur
WATER SOLUBLE ALKALIES
% Na-.O =
100.00
13111
0.19
0.01
0.34
0.54
xxxxx
xxxxx
100.00
13692
0.56
1.97
0.20
0.01
0.35
0.56
xxxxx
xxxxx
Moisture
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Oxygen (diff)
4.24
71.52
5.44
1.52
0.01
0.54
4.85
11.88
% Weight
As received Dry basis
XXXXX
74.69
5.68
1.59
0.01
0.56
5.06
12.41
100.00
100.00
FUSION TEMPERATURE OF ASH Reducing Oxidizing
Initial Deformation 2130 °F 2200 °F
Softening (H = W) 2310 °F 2400 °F
Softening (H - %W) 2360 °F 2440 °F
Fluid 2700+ F 2700+°F
% EQUILIBRIUM MOISTURE - xx
HARDGROVE GRINDABILITY INDEX = xx
FREE SWELLING INDEX = xx
H i. co~ H.ISM
w .. coo. width
MINERAL ANALYSIS OF ASH
Silica; SiO,
Alumina, AI,O,
Titania, TiO,
Ferric oxide, Fe,Oi
Lime, CaO
Magnesia, MgO
Potassium oxide, K,O
Sodium oxide, Na,O
Sulfur trioxide, SO3
Phos. pentoxide. P,OS
Undetermined
SILICA VALUE = 84.84
BASE: ACID RATIO
T250 Temperature = 2890
% Weight Ignited Basis
60.46
18.88
1.10
4.60
5.30
0.90
1.15
3.14
Respectfully submitted,
COMMERCIAL TESTING & ENGINEERING CO.
R A HOUSER. Min.g.r Mldo.lt Dlvi.lon
°~: RAH:hs Ch.
OMCMO. ftlMM CM«JIL£tTOM. W VA. CLAflKIKJM. W.V*. CLCVfeANO. OHIO MOMFOLK. VA HENDERSON. KT TOLEDO. OHtO OENVCN. COLORADO * ittMift&MAM. ALABAMA * VANCOUVER. B C
-------
COMMERCIAL TESTING & ENGINEERING CO.
GENERAL OFFICES: 998 NORTH LA SALLE STREET, CHICAGO. ILLINOIS 80601 AREA CODE 81* ?26-»*3*
"E ADDRESS ALL CORRESPONDENCE TO
'AN ORUNEN ROAD. SOUTH HOLLAND. ILLINOIS 60473
KVB, INC.
1306 E. Edinger
Suite B
Santa Ana, CA 92705
OFFICE TEL (312) M« 1173
April 20, 1977
Sample identification
by
Kind of sample
reported to us Coal
Sample taken at
KVB, INC.
P. O. f 12311
Project # 15500
P.C. 12
Utah Coal "A"
Taken: 1340 Hrs.
3-23-77
Sample taken by KVB, INC.
Date sampled
Analysis report no. 71-458638
SULFUR FORMS
Dry
Pyritic Sulfur 0.15
Sulfate Sulfur 0.00
Organic Sulfur(dif) 0.38
Total Sulfur 0.53
Respectfully submitted,
COMMERCIAL TESTING & ENGINEERING CO.
..
R A HOUSER. Manager Midwasl Oivliidrt"^-^"1 '
D"3 RAH:hs
Charter M«mt>«f
CHICAGO. ILLIHOtt CHARLESTON. W VA CLARKSBURG. W VA CLEVELAND. OHIO - NORFOLK. VA HENDERSON. KV TOLEDO. OHIO DENVER. COLORADO BIRMINGHAM ALABAMA . VANCOUVER. B C
-------
COMMERCIAL TESTING & ENGINEERING CO.
GENERAL OFFICES: » NORTH LA SALLE STREET. CHICAaO, ILLINOIS 60601 AREA CODE (19 73I-I434
PI - - *E ADDRESS ALL CORRESPONDENCE TO
1 'AN DRUNEN ROAD. SOUTH HOLLAND, ILLINOIS £0473
, f KVB, INC.
1306 E. Bdinger
Suite B
Santa Ana, CA 92705
Kind of sample
reported to us Coal
Sample taken at
Sample taken by ^ JNC'
^^^ OFFICE TEL 1312)264-117!
^^Ifcfc. April 20, 1977
SINCE 1306
Sample identification
by
KVB, INC.
P. 0. # 12311
Projcet # 15500
P.C. 12
Utah Coal "A"
Taken 1520 Hrs. 3-23-77
Date sampled
Analysis report no. 71-458639
SULFUR FORMS
Dry
Pyritic Sulfur 0.12
Sulfate Sulfur Q.OO
Organic Sulfur(dif) 0.42
Total Sulfur 0.54
Respectfully submitted.
COMMERCIAL TESTING 4 ENGINEERING CO
R A HOUSER Minig.r M.dwtll Divition
D-4
RAH:hs
j
CMCAOO. KXHIOt* - CHAALESTOM. W VA CLAHKSMIHG. W VA - CLEVELAND. OMtO HOW OIK. VA . HENDERSON. «V - TOLEDO. OMlO OENVEH. COLOBADO »IMMINGMAM. ALABAMA - V/ANCOUVEB. C
-------
COMMERCIAL TESTING & ENGINEERING CO.
BENERAL OFFICES: >» NORTH LA SALLE STREET, CHICAOO, ILLINOIS IOS01 AREA CODE 813 79S-S43*
>l ' -E ADDRESS AIL CORRESPONDENCE TO
I' AN DRUNEN ROAD. SOUTH HOLLAND. ILLINOIS 60473
KVB, INC.
1306 E. Edinger
Suite B
Santa Ana, CA 92705
Kind of sample
reported to us
Sample taken at
Coal
April 20, 1977
Sample identification
by
KVB, INC.
P. O. # 12311
Project i 15500
P.C. 12
Utah Coal "A"
Sample taken 1000 Hrs.
OFFICE TEL (31J) M4-1U3
3-24-77
Sample taken by KVB' 3NC>
Date sampled
Analysis report no. 71-458640
SULFUR FORMS
Pyritic Sulfur
Sulfate Sulfur
Organic Sulfur(dif)
Total Sulfur
Dry
0.08
0.00
0.46
0.54
Respectfully submitted,
COMMERCIAL TESTING i ENGINEERING CO
R A HOUSER Minag«r Midmit Oivulon
D-5
FAII:hs
Ch.rt.r M«inb«r
> CHARLESTON. W VA CLARKMURG. W VA CLEVELAND. OHIO NOWOIK. V* «ENDE«SON. KV . TOiEOO. 0«10 - OEHVER. CO1.DMADO tlBMIHOHAM. ALABAMA . VANCOUVER. C
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COMMERCIAL TESTING & ENGINEERING CO.
GENERAL OFFICE*: 11* NOKTH LA SALLE STREET, CHICAGO, ILLINOIS (0*01 AKEA CODE »1J 7M-14J4
<!' -E AOODESS ALL COIMES'ONDENCE TO
II AN DIIUNEN dOAO. »OUTM HOLLAND. ILLINOIS
KVB, INC.
1306 E. Edinger
Suite B
Santa Ana, CA 92705
Kind of sample
reported to us
Sample taken at
Coal
OFFICE TEL (311) JM 1173
April 20, 1977
Sample identification
BY
KVB, INC.
P. O. I 12311
Project # 15500
P.C. 12
Utah Coal "A"
Sample taken 1230 hrs.
3-24-77
Sample taken by
KVB. INC.
Date sampled
Analysis report no. 71458641
SUIFUR POEMS
Pyritic Sulfur
Sulfate Sulfur
Organic Sulfur (dif)
Total Sulfur
Dry
0.12
0.00
0.42
0.54
Respectfully submitted.
COMMERCIAL TESTING & ENGINEERING CO.
R A HOUSER. Manager, Midw«st Division
CMMUSTON. w VA CLAAKMUM, W.VA. CLEVELAND. OHIO
. V* HENOEHKM. «v »
RAHlhS
O. OM»Q * MNW£H. CO«.OMAOO » »I«M»IGMAM, ALABAMA
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COMMERCIAL TESTING & ENGINEERING CO.
SENERAL OFFICES: 21* NORTH LA SAILE STREET, CHICAGO. ILLINOIS »0«0t AREA CODE 311 72S-B434
L
t
< ADDRESS ALL CORRESPONDENCE TO
N OnuNEN DOAD. SOUTH HOLLAND. ILLINOIS (0473
KVB, INC.
1306 E. Edinger, Suite B
Santa Ana, CA 92705
OFFICE TEL (312) 264-1173
SlNCC 1»OB
April 22, 1977
Kind of sample Coal
reported to us
Sample taken at xxxxx
Sample taken by KVB, Inc
Date sampled 4/6/77
PROXIMATE ANALYSIS
% Moisture
% Ash
% Volatile
% Fixed Carbon
Btu
% Sulfur
% Alk. as Na,O
SULFUR FORMS
% Pyritic Sulfur
% Sulfate Sulfur
% Organic Sulfur
WATER SOLUBLE ALKALIES
% Na30 =
%K30 =
FUSION TEMPERATURE OF ASH
Initial Deformation
1 1. con. H*ight Softening (H - W)
v i. co« width Softening (H = % W)
Fluid
% EQUILIBRIUM MOISTURE -
iARDGROVE GRINDABILITY INDEX -
FREE SWELLING INDEX =
*
Analysis
As received
8.33
17.00
34.53
40.14
100.00
10336
0.57
xxxxx
0.19
0.00
0.38
xxxxx
xxxxx
Reducing
2400
2700+
2700+
2700+
xxxxx
xxxxx
xxxxx
uaiupiu luaiiiiii^aiiwti
* John Arand
"Navaho" Coal B"
on 4/6/77
reportno. 71-458643
Dry basis
xxxxx
18.54
37.67
43.79
100.00
11275
0.62
0.56
0.21
0.00
0.41
xxxxx
xxxxx
Oxidizing
2540
2700+
2700+
2700+
ULTIMATE ANALYSIS
Moisture
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Oxygen (diff)
MINERAL ANALYSIS OF ASH
Silica; SiO;
Alumina, AI3O3
Titania, TiO,
Ferric oxide, Fe,O,
Lime, CaO
Magnesia, MgO
Potassium oxide, K,O
Sodium oxide, Na3O
Sulfur trioxide, SO,
Phos. pentoxide, PjOs
Undetermined
SILICA VALUE =
BASE: ACID RATIO
^250 Temperature =
taken 1130 hrs
% Weight
.
As received Dry basis
8.33 xxxxx
57.98 63.
4.40 4.
1.48 1.
0.01 0.
0.57 0 .
17.00 18.
10.23 11.
100.00 100.
25
80
61
01
62
54
17
00
% Weight Ignited Basis
57.53
26.93
1.17
3.51
3.92
0.98
0.81
2.48
2.20
0.09
0.38
100.00
87.25
0.14
2900+
RAH/dh
Respectfully submitted,
COMMERCIAL1 TESTING & ENGINEERING CO.
R A HOUSER. Manigec Mid»«t Division
D-7
CHKMO. ftXMO* CMMLESTOft. W V* CLAMUWWa, W V* CLEVELAND. OMK> HOHFOLK. V* HENDERSON. KV . TOLEDO OHIO DENVER. COLORADO »IRM)N&MAM. ALABAMA - VANCOUVER. C
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COMMERCIAL TESTING & ENGINEERING CO.
OENERAL OFFICES: $3S NORTH LA SAtLE STREET, CHICAGO, ILLINOIS 606O1 AREA CODE S13 728-8434
.PI " *£ ADDRESS ALL CORRESPONDENCE TO
1 'AN ORUNEN ROAD, SOUTH HOLLAND. ILLINOIS 60473
KVB, INC.
1306 E. Edinger
Suite B
Santa Ana, CA 92705
Kind of sample
reported to us Coal
Sample taken at
Sample taken by KVB, INC.
Date sampled
OFFICE TEL (J12> 2M-1173
April 20, 1977
Sample identification
by
KVB,INC.
P. O. # 12311
Project # 15500
P.C. 12
"Navaho B"
Taken: 1000 Hrs. on
4-6-77
Analysis report no. 71-458642
SUITOR FORMS
Pyritic Sulfur 0.18
Sulfate Sulfur 0.00
Organic Sulfur(dif) 0.46
Total Sulfur 0.64
Respectfully submitted.
COMMERCIAL TESTING & ENGINEERING CO.
R A HOUSER Manager. MidWMt Division
D-8
RAH:hs
f M«mb«r
V* CLARKSAUHG. W V* CLEVELAND. OHIO MCMVOLK VA - HENDERSON K* . TOLEDO. OHIO DENVER. COLORADO BIRMINGHAM ALABAMA VANCOUVER. B C
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COMMERCIAL TESTING & ENGINEERING CO.
GENERAL OFFICE*! 198 NORTH LA SALLE STREET, CHICAGO. ILLINOIS SOS01 AREA CODE 311 724-S434
SE ADDRESS ALL CORRESPONDENCE TO
VAN DRUNEN ROAD. SOUTH HOLLAND. ILLINOIS 60473
KVB, INC.
17332 Irvine Blvd.
Tustin, CA 92680
OFFICE TEL (312)264-1173
May 25, 1977
SINCE 1»OB
Kind of sample
reported to us Coal
Sample taken at
Sample taken by KVBt Inc0
Date sampled 4/27/77
PROXIMATE ANALYSIS
% Moisture
% Ash
% Volatile
% Fixed Carbon
Btu
% Sulfur
% Alk. as Na,O
SULFUR FORMS
% Pyritic Sulfur
% Sulfate Sulfur
% Organic Sulfur
WATER SOLUBLE ALKALIES
% Na,O =
% K,O -
FUSION TEMPERATURE OF ASH
Initial Deformation
H i, coo. Might Softening (H = W)
w i« COM width Softening (H - % W)
Ruid
% EQUILIBRIUM MOISTURE -
HARDGROVE GRINDABILITY INDEX =
FREE SWELLING INDEX -
Analysis
As received
12.02
10.24
33.27
44.48
100.00
10941
2.94
xxxxx
1.27
0.06
1.61
2.94
xxxxx
xxxxx
Reducing
I960 »F
2090 *F
2130°F
2350»F
XX
XX
XX
Sample Identification
by
KVB, Inc.
P. 0. # 12393
Project # 15500
Illinois Coal C
Taken 1325 hrs4
report no. 71-1163
Dry basis
xxxxx
11.64
37.81
50.55
lOOoOO
12434
3.34
0.31
1.44
0.07
1.83
3
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COMMERCIAL TESTING & ENGINEERING CO.
SENEDAL OFFICE*: « MORTH LA SAILE STUEET, CHICAGO. ILLINOIS SOtOI A»EA CODE 112 7J«-«4»4
AODMESS ALL COMMCSPONOENCE TO
. <*N DRUNCH HOAO. SOUTH HOLLAND. ILLINOIS 60473
KVB, INC.
1306 E. Edinger
Suite B
Santa Ana, CA 92705
Kind of sample
reported to us Coal
Sample taken at
Sample taken by KVB, Inc.
Date sampled
OFFICE TEL (312)2*4-1173
May 20, 1977
Sample identification
by
KVB, Inc.
P.O. # 12393
Project # 15500
Illinois Coal C
Taken 1115 hrs on 4/27/77
Analysis report no. 71-1164
SULFUR FORMS
Pyritic Sulfur
Sulfate Sulfur
Organic Sulfur(diff)
Total Sulfur
% Wt. - DRY
1.40
0.09
2.80
4.29
Respectfully submitted. ,
COMMERCIAL ,1E?1I%G & e^GINEERING CO
R A HOUSER Mmag«r. Midwvsl D
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COMMERCIAL TESTING & ENGINEERING CO.
4ENERAL OFFICES: « NORTH LA SALLE STREET, CHICAGO. ILLINOIS 60(01 AREA CODE 313 726-8434
« ADDRESS «U COftRESPONDENCE TO
VAN DRUNEN-ROAD. SOUTH HOLLAND. ILLINOIS 6047}
KVB, INC.
1306 E. Edinger, Suite B
Santa Ana, CA 92705
OFFICE TEl (312) 264-1173
June 16, 1977
Kind of sample
reported to us
Sample taken at
Sample taken by KVB, Inc.
Date sampled
Analysis report no.
PROXIMATE ANALYSIS As received Dry basis
% Moisture 1-67 xxxxx
%Ash 7.16 7.28
% Volatile 37.13 37.76
% Fixed Carbon 54.04 54.96
100.00 100.00
Btu 13624 13855
% Sulfur 1-81 1-84
% Alk. as Na,0 xxxxx 0.10
SULFUR FORMS
% Pyritic Sulfur 0.93 0.95
% Sulfate Sulfur 0.02 0' . 0 2
%. Organic Sulfur 0.86 0.87
WATER SOLUBLE ALKALIES
% Na,O = xxxxx xxxxx
% K,O = xxxxx xxxxx
FUSION TEMPERATURE OF ASH Reducing Oxidizing
Initial Deformation 212 0°F 2445°F
H,.con.H.iBh, Softening
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COMMERCIAL TESTING & ENGINEERING CO.
8ENERAL OFFICES: »l-MOUTH LA SALIC STREET, CHICAGO, ILLINOIS (0101 AREA CODE 111 79S-(4a«
f I ADDDESS All COBKESPONDENCE TO
111.. VAN DRUMEH KOAO. SOUTH HOLLAND. ILLINOIS «M73
KVB, INC.
1306 E. Edinger, Suite B
Santa Ana, CA 92705
Kind of sample
reported to us
SINCE WOO
OFFICE TEL (312) M4-I1T1
Sample taken at
June 16, 1977
Sample identification
by
KVB, Inc.
Purchase order 12439
Pittsburgh #8 fired @1010
5/26/77
Sample taken by KVB, Inc.
Date sampled
Analysis report no. 71-1835
DRY SULFUR FORMS
% Pyritic Sulfur 1.05
% Sulfa'te Sulfur 0.01
% Organic Sulfur 0.91
% Total Sulfur 1.97
RA H:ljd
Respectfully submitted.
R A HOUSER bUnag«rMidw*»t Div
D-12
CHARLESTON. W V* . CLANKMuMQ. W V* " CLEVELAND. OH*O MOHFOLK. VA - MCNOf ««OM. KT TOLEDO. OHIO DENVER. COLORADO IIMMIMGHAM ALABAMA VANCOUVER. C
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing}
. REPORT NO.
EPA-600/7-79-079
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Applicability of the Thermal DeNOx Process to
Coal-fired Utility Boilers
5. REPORT DATE
March 1979
6. PERFORMING ORGANIZATION CODE
G.M. Varga Jr. ,M.E.Tomsho, B.H.Ruter-
bories, G. J.Smith, and W. Bartok
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Exxon Research and Engineering Company
Government Research Laboratories
P.O. Box 8
Linden, New Jersey 07036
10. PROGRAM ELEMENT NO.
EHE624A
11. CONTRACT/GRANT NO.
68-02-2649
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
Final; 9/77 - 5/78
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES IERL-RTP project officer is David G. Lachapelle, MD-65, 919/
541-2236.
16. ABSTRACT Tne report gives a. projection of the performance and cost of the Exxon
Thermal DeNOx Process applied to coal-fired utility boilers. Eight units were selec-
ted, representing different boiler manufacturers, sizes, firing methods, and coal
types. Thermal DeNOx performance was projected both with and without combustion
modifications for all boilers at full load and at one or more loads down to 50%. Three
NOx reduction targets were used: the proposed New Source Performance Standards
(NSPS), reduction to about two-thirds of the proposed NSPS, and the maximum prac-
tical NOx reduction that could be achieved. All costs are for full load. Thermal
DeNOx was projected to be equally applicable for all boilers studied, despite signi-
ficant differences in flue gas temperatures and flow paths. Maximum Thermal DeNOx
performance ranged from 50 to 59% for the boilers studied. Costs ranged from 0.25
to 1.23 millsAWh, excluding preliminary engineering costs and licensing royalties.
A full-scale demonstration of Thermal DeNOx on a coal-fired utility boiler is
recommended, including investigation of potential downstream effects of the process.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
COS AT I Field/Group
Pollution
Ammonia
Performance
Cost Estimates
Nitrogen Oxides
Boilers
Coal
Pollution Control
Stationary Sources
NH3 Injection
Thermal DeNOx Process
Utility Boilers
Denitrification
13B
07 B
14B
05A,14A
13A
21D
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReportj
Unclassified
1. NO. OF PAGES
191
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
D-13
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