&EPA
United States Industrial Environmental Research EPA-600/7-79-117
Environmental Protection Laboratory May 1979
Agency Research Triangle Park NC 27711
Technical Assessment
of Thermal DeNOx
Process
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-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
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mental issues.
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This report has been reviewed by the participating Federal Agencies, and approved
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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-600/7-79-117
May 1979
Technical Assessment of Thermal
DeNOx Process
by
C. Castaldini, K. G. Salvesen, and H. B. Mason
Acurex Corporation
Energy and Environmental Division
485 Clyde Avenue
Mountain View, California 94042
Contract No. 68-02-2611
Task No. 10
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-prepared 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.
K/ Burchard
Director
IERL-RTP
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ACKNOWLEDGEMENTS
The authors wish to acknowledge the assistance of Mr. David G.
Lachapelle, the EPA Project Officer, whose direction and evaluation
were invaluable. Acknowledgement is also given to Dr. Gideon M. Varga,
Dr. William Bartok, and Dr. Richard K. Lyon for their technical
contribution and support.
iv
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ABSTRACT
This report presents results of a technical and economic assessment
of the Exxon's Thermal DeNO Process applied to coal-fired utility boilers.
A
This assessment was performed in parallel with a study conducted by Exxon
Research and Engineering Co. (ER&E) in which the performance and cost of the
Thermal DeNO Process were estimated for eight coal-fired utility boilers
A
representative of the nation's boiler population. This report concludes that
the Thermal DeNO Process is a promising technique for control of NO
A X
emissions from utility steam generators. However, a number of limitations
need to be considered and evaluated when the Process is retrofitted to
coal-fired boilers. Flue gas temperature fluctuations caused primarily by
load following, furnace slag deposition, and tube fouling may limit NO
J\
reductions to approximately 50 percent. In addition, operational and
i
environmental impacts of NH^ emissions and ammonium bisulfate formation
could further limit the performance of the process and affect its
applicability. These limitations are best evaluated in a full-scale
demonstration. Total operating costs are estimated between 0.27 and 1.23
mills/kw-hr exclusive of license fee. Actual costs depend primarily on boiler
size, initial NO concentration, and level of control required. This
A
assessment also considered the impact of widespread process implementation on
the ammonia market, feedstock supplies, and their costs. These impacts were
found to be small.
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TABLE OF CONTENTS .
Section Page
1 INTRODUCTION 1-1
2 PAST EXPERIENCE 2-1
2.1 Subscale Testing — Gas and Oil 2-3
2.1.1 Reaction Temperature 2-4
2.1.2 Ammonia Injection Rate 2-6
2.1.3 Hydrogen and Other Additives 2-10
2.1.4 Byproduct Emissions 2-12
2.2 Subscale Testing — Coal 2-13
2.2.1 Reaction Temperature 2-14
2.2.2 Ammonia Injection Rate 2-17
2.2.3 Hydrogen Injection 2-18
2.2.4 NH3 and Byproduct Emissions 2-18
2.3 Commercial Application 2-20
3 APPLICABILITY ASSESSMENT 3-1
3.1 Correlation Procedure and Predicted Results . . . 3-2
3.2 Process Limitations 3-8
3.2.1 Selection of Injection Location 3-8
3.2.2 Flue Gas Temperature Fluctuations 3-12
3.2.3 NH3 Breakthrough and Equipment Maintenance . . . 3-21
4 COST ANALYSIS 4-1
4.1 Recent Reported Cost Estimates 4-2
4.1.1 Analysis of Assumptions and Procedures 4-7
4.1.2 Acurex Cost Analysis Procedure 4-9
4.1.3 Control Costs Using Cost Analysis Procedure . . 4-12
4.1.4 Comparison of Cost Results 4-17
4.2 Impact of Full-Scale Thermal DeNOx
Implementation on Ammonia Cost and Supply .... 4-27
4.2.1 Methods for Producing Ammonia 4-28
4.2.2 Supply and Availability of Natural Gas 4-30
4.2.3 Ammonia Requirements for Specific Boiler
Types 4-32
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TABLE OF CONTENTS (Concluded)
Section Pa9e
4.2.4 Relative Impacts of Coal vs. Natural Gas
Feedstocks on Ammonia Cost and Fuel Supply . . . 4-35
5 CONCLUSIONS AND RECOMMENDATIONS 5-1
APPENDIX A — GLOSSARY OF TERMS A-l
APPENDIX B -- COST INPUTS B-l
vni
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LIST OF ILLUSTRATIONS
Figure Page
2-1 Effect of Flue Gas Temperature on Thermal DeNOx
Performance (Reference 2-2) 2-6
2-2 Effect of NH3 Injection Rate on NO emissions
(Reference 2-2) 2-7
2-3 Effect of Initial Nitric Oxide Concentrations on
Reductions With Ammonia Injection (Reference 2-2) . . . 2-8
2-4 Effect of NH3 Injection Rate on NH3 Carryover
Emissions (Reference 2-2) 2-9
2-5 Thermal DeNOx Reaction Products as Functions of
Temperature With and Without Hydrogen Injection
(Reference 2-3) 2-10
2-6 Effect of Temperature on NO Reductions, Coal and
Natural Gas Firing (Reference 2-4) 2-15
2-7 Effect of Sulfur on NO Reduction, Oil Firing
(Reference 2-4) 2-16
2-8 Comparison of NO Reductions at the Optimum Temperature
Condition (Reference 2-4) 2-17
2-9 Comparison of the NH3 Emissions for all Fuels Tested
at the Peak NO Removal Temperature (Reference 2-4) . . 2-19
2-10 Thermal DeNOx System Performance on Commercial Units
as Functions of Temperature (Reference 2-6) 2-22
3-1 Section of the NH3 Injection Nozzle Pipe for a 375 MW
Gas-/Oil-Fired Utility Boiler in Japan
(Reference 3-4) 3-9
3-2 Concept of Nozzle Systems Location (Reference 3-4) . . 3-9
3-3 Deposition Zones in a Coal-Fired Boiler 3-14
3-4 Flue Gas Temperature Profile (Reference 3-5) 3-17
3-5 NOX Reduction Performance on 375 MW Boiler at Various
Load Operation (Reference 3-4) 3-19
3-6 Ammonium Bisulfate Formation as a Function of Sulfur
Content in the Coal 3-28
IX
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LIST OF ILLUSTRATIONS (Concluded)
Figure
3-7 On-Stream Washing of Air Preheater on a Boiler With
Dual Air Preheater Arrangement (Reference 3-10) .... 3-33
3-8 Effect of S03 Conditioning on Collection Efficiency
of a Coal-Fired Utility Boiler (Reference 3-11) .... 3-35
3-9 Collector Performance as a Function of the Amount of
Condensed Sulfuric Acid in Flue Gas (Reference 3-13). . 3.35
3-10 Collector Efficiency as a Function of Ammonia Feedrate
(Reference 3-13) 3.35
4-1 Cost of NH3 Injection for Approximately 50 Percent
Reduction in NOX Emissions 4-4
4-2 Normalized cost of NH3 Injection as a Function of
Boiler Size for Both Trim and Maximum NOX Reduction
Targets 4-5
4-3 Normalized Cost of NH3 Injection as a Function of
Initial NOX Concentration 4-6
4-4 Historical Trends of Ammonia Prices 4-29
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LIST OF TABLES
Table Page
2-1 Summary of Commercial Applications of Exxon's
Thermal DeNOx Process 2-2
3-1 Summary of Exxon Predicted Thermal DeNOx Performance
(Without Combustion Modifications) 3-5
3-2 Estimated Effect of Injection Grid Relocation on
Predicted DeNOx Rates -- NHa/NO =1.5 3-11
3-3 Estimated NH3 Emissions (100 Percent Boiler Load and
Without Combustion Modifications) 3-24
3-4 Estimated Formation of Ammonium Bisulfate in Coal-Fired
Utility Boilers Investigated ~ NHs/NO =1.0 3-27
3-5 Predicted Ammonium Bisulfate Emission Rates 3-30
3-6 Concentrations of Submicron Particles at the Widows
Creek Plant (Reference 3-14) 3-37
3-7 Effects of NH3 Emissions on ESP Performance and
Particulate Emissions 3-39
4-1 Comparison of Exxon and Acurex Cost Analyses
Procedures 4-10
4-2 Cost Analysis Calculation Algorithm 4-13
4-3 Input Data to Cost Analysis Procedure -- Exxon Case
No. 4 4-15
4-4 Cost Breakdown of NH3 Injection on 130 MW Front Wall
Coal-Fired Boiler 4-18
4-5 Cost Breakdown of NH3 Injection on 333 MW Horizontally
Opposed Coal-Fired Boiler 4-19
4-6 Cost Breakdown of NH3 Injection on 350 MW Tangential
Coal-Fired Boiler 4-20
4-7 Cost Breakdown of NH3 Injection on 800 MW Tangential
Coal-Fired Boiler 4-21
4-8 Cost Breakdown of NH3 Injection on 330 MW Front Wall
Coal-Fired Boiler 4-22
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LIST OF TABLES (Concluded)
Table
4-9 Cost Breakdown of NHs Injection on 670 MW Horizontally
Opposed Coal-Fired Boiler 4-23
4-10 Cost Breakdown of NH3 Injection on 350 MW Turbo
Coal-Fired Boiler 4-24
4-11 Total Cost of the Thermal DeNOx Process from Cost
Analysis Procedure — Case No. 4 4-25
4-12 Thermal DeNOx Cost Comparison for the Maximum NOX
Reduction ~ Case No. 4 4-26
4-13 Amount and Cost of Ammonia Usage for the Eight Coal-
Fired Utility Boilers 4-33
4-14 Total Cost Impact of Ammonia Usage on all Coal-Fired
Utility Boilers Installed by 1985 — High Coal Growth
Case 4-34
4-15 Total Cost Impact of Ammonia Usage on all Coal-Fired
Utility Boilers Installed by 1985 — Low Coal Growth
Case 4-36
4-16 Impact of increased NH3 Consumption on Natural Gas
and Coal Feedstock — Reference Case High Coal
Growth 4-38
4-17 Impact of Increased NH3 Consumption on Natural Gas
and Coal Feedstock — Reference Case Low Coal
Growth 4-39
xn
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SECTION 1
INTRODUCTION
Noncatalytic reduction of NO emissions by ammonia injection is a
A
very effective technique for stationary source NO control. This
A
technique, patented by Exxon Research and Engineering (ER&E) Co., and
known as Thermal DeNO , is operational for gas- and oil-fired boilers.
X
However, demonstration of Thermal DeNO with coal-fired systems has so
/\
far been limited only to a pilot-scale plant.
The Thermal DeNO Process is more expensive than conventional
/\
combustion modifications for NO controls. Therefore, the process is
/\
most attractive as a supplement to combustion modification to achieve
stringent emission levels.
Current and projected New Source Performance Standards (NSPS) for
NO emissions for utility and large industrial steam generators will
/\
probably not require the use of the Thermal DeNO Process. In the
/\
forseeable future, NSPS for these sources will be based on conventional
combustion modifications for all fuels. However, there is a need for the
process in certain Air Quality Control Regions (AQCR) for attainment and
maintenance of the National Ambient Air Quality Standard for N02 (NAAQS)
•5
(100 yg/m , annual average). For example, in the Los Angeles South
Coast Air Quality Management District, conventional combustion
modifications are already being implemented to near maximum extent on
-------
utility boilers. Nonetheless, the annual average N0« ambient standard
is being exceeded. State and local regulating groups are recommending
Thermal DeNO for utility boilers to aid in attainment (Reference 1-1).
A
There appears to be a further need for Thermal DeNO for
X
maintenance of the annual average NAAQS in other Air Quality Control
Regions. Projections of source emissions and ambient air quality into the
1980's and 1990's show a need for stringent controls — comparable to
Thermal DeNO — in several AQCR's (Reference 1-2 and 1-3). These
A
stringent controls will be needed to offset source growth particularly
with the increased use of coal in new and existing sources. -
In addition to attainment and maintenance of the annual average
NAAQS, Thermal DeNO may well be needed to attain the impending short
/\
term N0? ambient standard. This standard, required by the 1977 Clean Air
Act Amendments, is still in preparation. However, preliminary calculations
show a need for stringent NO control for selected point sources to prevent
A
"hotspot" violations of a one hour standard (Reference 1-3).
Furthermore, the non-attainment provisions of the recent Clean Air
Act Amendments of 1977 require individual States to assure attainment of
air quality standards for N0_ by requiring Lowest Achievable Emission
Rates (LAER) for new sources, in non-attainment areas. LAER is defined as
the lowest emission rate achievable in practice by that category of
sources and presumably would include Thermal DeNO .
** ' A
Based on the above considerations there is a definite need for
stringent NO control from coal-, oil- and gas-fired utility boilers.
A
The Thermal DeNO Process seems to be the only economic alternative
/\
control technique which could guarantee 40-50 percent NO reductions
beyond the percent controlled levels from gas- and oil-fired utility
1-2
-------
boilers. However, in the absence of a full-scale demonstration the
technology is not considered commercially available for coal-fired units.
Numerous operational and economic aspects of injecting ammonia in the
severe flue gas environment derived from coal combustion need evaluation.
Exxon Research and Engineering Company (ER&E) has recently
performed an economic and technical assessment for the EPA for retrofit of
coal-fired utility boilers with ammonia injection. Exxon's effort was
directed primarily at evaluating the performance of the process on typical
coal-fired steam generator designs and to estimate the process cost to the
utilities for retrofitting and operating the ammonia injection system.
The work presented in this report was performed in parallel with
Exxon's. The objectives of the study were to critique Exxon's results and
to conduct an independent assessment of ammonia injection for coal-fired
utility boilers. The effort was directed primarily at three areas:
• Past Experience: A literature review of current open
literature in which laboratory, pilot- and full-scale data from
use of ammonia injection with gas, oil, and coal firing are
presented (Section 2),
t Applicability Study: Assessment of the results of the Exxon
study on the applicability of this technology for coal-fired
utility boilers (Section 3),
t Cost Analysis: An analysis of how boiler capacity and design,
affect the cost of ammonia (NFL) injection as a control
technique on coal-fired utility boilers (Section 4).
The following sections discuss results of the assessment of each of these
areas.
1-3
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REFERENCES FOR SECTION 1
1-1. "Public Hearing of Rule 475.1 of the South Coast Air Quality
Management District," State of California Air Resources Board,
Docket No. 78-10-1, April 25, 1978.
1-2. Mason, H. B., et^ a^L, "Preliminary Environmental Assessment of
Combustion Modification Techniques: Volume II. Technical
Results," EPA-600/7-77-119b, NTIS-PB 276 681/AS, October 1977.
1"3' wnterland' L- R*' "Environmental Assessment of Stationary Source
NUX Control Technologies — Second Annual Report," Acurex
Report TR-78-116, July 1978.
1-4
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SECTION 2
PAST EXPERIENCE
The noncatalytic reduction of NO by the Thermal DeNO Process was
/\
discovered in August 1972 by Exxon Research and Engineering Co. (ER&E).
Since then, numerous laboratory, pilot, and full-scale tests have further
investigated the Thermal DeNO Process. These tests have been designed
X
to understand the critical process parameters and how they can be used to
control NO emissions from both stationary and mobile sources.
/\
ER&E, developer of the Process and patent holder, has done most of
the laboratory research and field studies. However, Exxon's tests were
limited to gas- and oil-fired facilities, except for full-scale tests on a
solid waste incinerator. KVB Inc., under contract to ER&E and EPRI has
recently studied the use of Thermal DeNO on a 3 x 10 Btu/hr
/\
coal-fired test boiler. KVB has also conducted the only domestic
full-scale application of NH^ injection. This was on a thermal oil
recovery steam boiler.
Table 2-1 presents a summary of all commercial installations
utilizing noncatalytic decomposition of NO by ammonia. All of these
/\
installations use Exxon's ammonia injection technology except for one
Japanese source noted. Detailed information on all installations using
Exxon's Thermal DeNO Process is not available. However, depending on
/\
the source and its operation, NO reductions as high as 70 percent have
A
been achieved.
2-1
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TABLE 2-1. SUMMARY OF COMMERCIAL APPLICATIONS OF EXXON'S THERMAL DeNOv PROCESS
x
ro
Source
Steam Boiler
45 MW heat Input
Incinerator
7 ton/hr
Crude heater
150 x 103bbl/day
Steam boiler
76 MW heat input
Utility boiler
275 MW heat input
Utility boiler
275 MW heat input
Crude heater
150 x 103bbl/day
Thermal recovery
heater
Utility boiler
375 MW
Fuel
Burned
Gas/oil
Waste
Gas/oil
Gas/oil
Gas/oil
Gas /oil
Gas/oil
Oil
Residual
oil
Location
Japan
Japan
Japan
Japan
Japan
Japan
Japan
USA-
California
Japan
Initial Nitric
Oxide Emissions
{ppm as measured)3
120-150
100-180
150
95-145
80-120
80-120
80-85
260
NA
DeNOx Rate
(Percent)
60
20-70
35-65
35-50
60
50-60
40-65
50-70
40
Additiveb
Yes
NAC
Yes
NA
NA
NA
NA
NA
No
Comments
No reduction obtained at full load
Difficult source to retrofit because
of constant change in fuel
Best reductions achieved at high
load
No details of retrofit system are
available
No details of retrofit system are
available
No details of retrofit system are
available
Best reductions achieved at high
loads
First commercial U.S.
installation
Does not use Exxon NH3 injection
technology — NHs emission limited
to 10 ppm
aExcess oxygen varied between 3-5 percent for all sources
D"Yes" indicates that hydrogen was injected together with NH3 to obtain reported NOX reduction performances
"No" indicates that no additive was used
CNA » no data are available
-------
Based on these full-scale results, Exxon has commercialized the
process and will license it upon request on gas- and oil-fired boilers.
Additionally, they are continuing to study the feasibility of full-scale
applications on coal-fired boilers. These studies are aimed at maximizing
NO reduction and cost effectiveness, and exploring and defining
/\
potential operating problems.
This section summarizes the status of Thermal DeNO Process
A
developments. Results from gas and oil combustion in laboratory and
pilot-scale studies are discussed in Section 2.1. Section 2.2 presents
results from ammonia injection in a coal-fired pilot-scale facility.
Results from ER&E's full-scale commercial demonstration of the process are
described in Section 2.3.
2.1 SUBSCALE TESTING -- GAS AND OIL
ER&E discovered a new reaction which is the basis of the Process in
research done in a laboratory flow reactor. Based on the observed
kinetics of this reaction Lyon proposed the following mechanism
(Reference 2-1) :
NH2 + NO - >- N2 + H + OH
NH2 + NO - >• N2 + H20
H + 02 - *- OH + 0
0 + NH3 - >" OH + NH2
OH + NH3 - *- H20 + NH2
H + NH3
To further explore this reaction mechanism, ER&E conducted tests on
a small 0.3 MW (10 Btu/hr commercial size boiler). These tests
investigated how key operating variables such as reaction temperature,
2-3
-------
NH, injection rate and flue gas residence time influence the N0x
O
reduction effectiveness.
Additional tests were conducted on a 9 MW (30 x 106 Btu/hr) test
furnace to optimize mixing and injection methods and to evaluate problems
such as corrosion and fouling which may be encountered during full-scale
application. ER&E also evaluated the economics of full-scale application
of the process for oil- and gas- firing. KVB Inc. has also considered the
effects of Thermal DeNO on key operating parameters. Both ammonia and
/\
a proprietary ammonia-based compound were investigated as NO reducing
agents for product gases from the combustion of gas and oil.
The Exxon and KVB test results reveal the following key operating
variables and constraints which affect the efficiency of the Thermal
DeNO Process:
X
• Reaction temperature
• Ammonia injection rate
t Mixing technique and reaction time
• Hydrogen and other additive injection
• Byproduct and ammonia emissions
The following sections briefly describe these key parameters and their
effects on the DeNO Process.
A
2.1.1 Reaction Temperature
The temperature of the flue gas at the point of NH~ injection is
a key process condition because the reaction between NO and NH. in the
presence of 02 is extremely temperature sensitive, i.e., the temperature
range in which ammonia is effective in reducing NO concentrations is
small. This characteristic, therefore, governs how the process can be
applied.
2-4
-------
Lyon reported that the reaction temperature of about 955°C
(1750°F) results in the largest NO reduction. At temperatures higher
than approximately 1100°C (2010°F), the oxygen present in the flue gas
oxidizes the injected ammonia producing a net increase in NO. Below
900°C (1650°F), the reaction of NH3 with NO is slowed considerably
causing less NO reduction and more NHL emission from unreacted gases.
Figure 2-1 shows how the reaction temperature affects the performance of
the Thermal DeNO Process.
A
This strong dependence of Thermal DeNO performance on reaction
X
temperature can limit the use on some systems. For example, the required
temperature window in gas turbines and 1C engines is located where a very
short residence time is available for reaction with NH.,. Thus, Thermal
DeNO may not be suited to these sources. In large steam generators,
A
the optimum temperatures and residence times for noncatalytic reduction of
NO are usually accessible in the boiler convective section. However,
cross-sectional temperature gradients as high as 200°C (360°F) often
exist making ammonia injection considerably less effective for some areas
of the flue gas ducts. Load variations also shift the temperature profile
causing the temperature window to move in the convective section.
These problems could theoretically be solved by installing more
than one injection stage to account for the shift in the temperature
window. However, additives have also been evaluated as methods to
accommodate temperature variations and unfavorable location of the
temperature window. For example, hydrogen additive is a demonstrated
alternative for controlling or shifting the injection points to the
optimum temperature location for the Thermal DeNO Process. Additive
/v
injection is discussed in Section 2.1.3.
2-5
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1.0
0.8
0.6
0.4
0.2
Excess oxygen: 4S
Initial NO: 300 pptn
(NH3)/(NO)
0.3
0.5
I
700 800 900
Temperature, °C
1000
1100
Figure 2-1. Effect of flue gas temperature on Thermal DeNOx
performance (Reference 2-2).
2.1.2 Ammonia Injection Rate
Ammonia efficiently reduces N0x because of its ability to react
selectively with nitric oxide regardless of the amount of oxygen present
in the treated gas. Thus, the amount of ammonia required in the Thermal
DeNO Process is on the order of the initial NO concentration. Other
/\
additives, such as methane and ethane also can be used to reduce NO in hot
flue gases. However, because these reagents are nonselective, they do not
react with nitric oxide alone. That is, all the free oxygen present in
the hot gases must first be consumed by the reagents before the NO can be
reduced. Therefore, more hydrocarbons are necessary, thus causing these
additives to be economically unattractive.
2-6
-------
Experiments conducted by ER&E and KVB show that for typical
conditions, an ammonia injection rate of 2.0 (molar ratio of NH_ to
initial NO concentration, (NH3/NO)) achieves the optimum maximum process
efficiency. Figure 2-2 shows that minimal additional NO reduction is
obtained by increasing the ammonia injection rate beyond the NHL/NO
molar ratio of 2.0.
600
i i i
2% Excess Oxygen
o
(NH3)/(NO)
Figure 2-2. Effect of NH3 injection rate on NO emissions
(Reference 2-2).
Ammonia injection rates depend on the initial concentration of
nitric oxide. Experimental data illustrated in Figure 2-3 show that lower
molar ratios of NH../NO are needed to achieve a given process efficiency
when the initial NO concentration is greater than 400 ppm. These
experimental data further indicate that the percent oxygen in the flue gas
may also have some effect on required NH-j injection rates. Minimum
amount of dilution with excess air decreases the volume of flue gas to be
2-7
-------
treated and increases initial NO concentration thus possibly reducing the
amount of NH., needed.
1.0 o
EXCESS OXYGEN: 2%
TEMPERATURE: 960°C (1760°F)
INITIAL NO LEVEL (PPM)
D 100
200
O WO _
O 680
O 1050
Figure 2-3.
2 3
(NH3)/(NO)
Effect of initial nitric oxide concentrations on
reductions with ammonia injection (Reference 2-2),
The ammonia injection rate, the reaction temperature and the
residence time are critical jn maintaining ammonia emissions at minimum
levels. Test data depicted in Figure 2-4 indicate that the level of
unreacted ammonia at the injection temperature of 965°C (1770°F)
increases significantly only at NH3/NO ratios greater than 2.0, as
expected. When the reaction temperature is lowered to 870°C (1600°F)
the level of ammonia carryover is substantially increased because of the
slower chemical reaction. Therefore, the ammonia emission level can be
controlled by allowing the reaction to occur at slightly higher
temperatures than the optimum 955°C (1750°F). In fact, NH3
2-8
-------
injection, at temperatures above 1000°C (1830°F) virtually all NHL
breakthrough is eliminated.
2400
2000 -
(NH3)/(NO)
Figure 2-4. Effect of NH3 injection rate on NH3 carryover
emissions (Reference 2-2).
Poor mixing of ammonia with the flue gas may cause ammonia
carryover to occur also at NHL/NO molar ratios much lower than 2.0. In
fact, large scale applications of the Thermal DeNO Process have shown
A
that NhL/NO ratios in nonideal gas conditions generally should be lower
than 1.5 to maintain minimum NH, emissions. High levels of ammonia
breakthrough were caused by high ammonia injection rates combined with
ineffective mixing or low flue gas temperatures.
In summary, NH,/NO molar ratios can vary from 1.0 to 2.0 in large
scale applications of the Thermal DeNO Process. The actual injection
J\
rate used will depend on the desired NOY reduction and could be limited
/\
by ammonia breakthrough. Therefore, the injection rate is the result of
2-9
-------
an optimization performance study taking into account flue gas conditions
and source configurations.
2.1.3 Hydrogen and Other Additives
The Thermal DeNO Process can be applied over a greatly widened
A
range of temperatures if certain additives are injected with the ammonia.
Of the many additives investigated, hydrogen is the most effective over
the temperature range from 700 to 1010°C (1290 to 1850°F). Figure 2-5
shows the shifting effect of hydrogen injection on optimum reaction
temperature measured in a commercial size firetube boiler. The magnitude
of this shift depends on the amount of H« injected relative to the
NH_. For example, at H^/NH-j molar ratios on the order of 2:1 selective
noncatalytic reduction of NO can be made to occur at 700°C (1290°F).
/\
Thus, by carefully selecting the H~ injection rate, flue gas treatment can
be controlled over a wide temperature range.
200
150
» 100
o
50
700
NH3' w/0 H2
^njectlon
800 900
Flue Gas Temperature, °C
1000
Figure 2-5. Thermal DeNOx reaction products as functions of temperature
with and without hydrogen injection (Reference 2-3).
2-10
-------
Exxon also investigated the use of combined additives. A mixture
of 50 percent hydrogen and 50 percent methane was found to be more
effective than either hydrogen or methane alone. However, the
introduction of methane in combustion gases, especially at low excess air
levels, increased cyanide emissions by a few ppm.
Additive injection can also be used to control ammonia breakthrough
emissions to concentrations lower than 10 ppm. For example, small amounts
of H~ injection with ammonia would lower the optimum reaction temperature
from 955°C (1750°F) to 945°C (1733°F). This 10°C (18°F) temperature
differential is sufficient to deplete some excess NH_ which would otherwise
exit from the stack.
Because H_ can control the temperature of the NhL-NO-0,, reaction,
Thermal DeNO is technically feasible for most boilers provided that the
/\
hardware can be installed within the boiler configuration. However, the
cost of the DeNO Process is greatly increased because of the large
A
volumes of hydrogen needed. This is especially the case for very low
temperature such as 760°C (1400°F).
Until recently, the NH- injection was limited to boiler
cavities. Thus if the optimum reaction temperature of about 955°C did
not occur in an isothermal cavity, NH^ was injected at temperatures
below this level. This situation warranted the use of an additive to
maximize the efficiency of the DeNO Process. The in-tube bank
A
injection of NH_, recently demonstrated by Exxon, has diminished the
dependence of the process efficiency on the use of an additive. DeNO
A
rates of 60 to 70 percent were achieved by injecting NH. in tube banks
without the use of an additive.
2-11
-------
2.1.4 Byproduct Emissions
The Exxon Thermal DeNO Process may form byproduct pollutants
/\
directly or indirectly from the presence of NhL in the combustion gas.
Potential byproduct emissions suggested by ER&E are NH_, CO, HCN and
^0 and, when sulfur-bearing fuel is burned, NHg and SOg combine to
form ammonium bisulfate, NH.HSCL.
Ammonium bisulfate is a viscous liquid from 147°C to about
450°C (300-840°F). It has been known to cause corrosion of metal
surfaces. Thus far, however, no increase in metal corrosion attributable
to ammonium bisulfate has been identified when Thermal DeNO has been
X
used. The formation of NH.HSO* can be controlled by limiting the
amount of NH- carryover. This can be accomplished by NH~ injection at
a temperature slightly higher than optimum or by using an H? additive.
In general, ammonium bisulfate is considered the most serious byproduct
and one which could effect the use of the Thermal DeNO Process.
X
Carbon monoxide emissions may also be promoted by ammonia injection
because the Thermal DeNO reaction inhibits the oxidation of CO to
^
COp. Thus, if there is unburned CO at the point of NH. injection, the
CO may not be oxidized, but will be discharged to the atmosphere. Under
normal operating conditions, CO levels are not usually significant in
steam generators. Using hydrocarbons as additives to control the
NHg-NO^ reaction increases the concentration of CO in the flue gas.
Exxon reported that as much as 50 percent of the hydrocarbons may be
oxidized to CO. This CO may then be emitted to the atmosphere because the
ammonia inhibits the O^+CO—^-CO^ reaction.
HCN is formed only if hydrocarbons are present in the region in
which NH, is injected. Under normal boiler operation, gaseous
2-12
-------
hydrocarbons are not present unless they are injected along with the
NHg. KVB reported that for gas, oil and coal firing, HCN was present in
the untreated flue gas at 3 to 10 ppm concentration, depending on excess
air level. Injection of NH., did not measurably affect the HCN level.
The reduction of NO by NH, and Op forms N^O as a minor byproduct.
However, less than 2 moles are generated for every 100 moles of NO
reduced, according to ER&E experimental data. All the available evidence
indicates that N^O is relatively harmless at those levels, and does not
represent an environmental concern.
2.2 SUBSCALE TESTING ~ COAL
Recently, KVB has conducted a pilot-scale investigation of the
Thermal DeNO Process to reduce NO levels from combustion of coal
A
(Reference 2-4). The work was sponsored by the Electric Power Research
Institute (EPRI) and Exxon Research and Engineering (ER&E).
The major objective of this investigation was to determine the
level of NO reduction which is achievable in flue gas resulting from
A
coal combustion. The primary variables investigated were the injection
temperature, the NH3/NO ratio, and the coal type. Additionally, a
hydrogen additive was used to lower the temperature range for NO removal.
Four different coals were investigated; three coals were bituminous and
one subbituminous. Byproduct emissions were also measured at different
NH, injection rates.
The combustion facility consisted of a 0.9 MW (3 x 10 Btu/hr)
firetube boiler equipped with a ring-type natural gas burner and a scaled
down version of a commercial coal burner presently used in utility boilers
firing Western coal. The NH, injection system consisted of five
2-13
-------
injectors located at the end of the firetube section distributing the
ammonia and nitrogen (carrier gas) counter-flow to the flue gas stream.
The injectors were designed to be movable so that they could be positioned
axially along the length of the firebox thus providing for evaluation of
the effectiveness of different temperature profiles. The injection method
was a result of an optimization study in which the injection grid and
nozzles were designed to provide substantial NO reductions that allowed
A
a valid comparison between the various coal types and natural gas. Since
the injection method directly affects the efficiency of the Thermal
DeNO Process, the results achieved by KVB do not necessarily represent
/\
the maximum NO reductions achievable with coal combustion.
A
This section discusses the results of this investigation. These
results can be used to compare noncatalytic NO reductions and byproduct
emissions between coal and the gaseous and liquid fuels previously
investigated. Key parameters considered here are again:
t Reaction temperature
• Ammonia injection rate
• Hydrogen and other additive injection
t Byproduct emissions
2.2.1 Reaction Temperature
The temperature at which ammonia is injected into the flue gas is
the primary variable which determines the amount of NO removed with the
Thermal DeNO Process. A major objective of the KVB study was to
determine whether the additional pollutants resulting from combustion of
coal, such as SO^ and particulates, would influence the temperature
dependence of the process or reduce the process efficiency. Figure 2-6
shows the effect of reaction temperature on NO reduction for the four
2-14
-------
coals tested and for natural gas. Since temperature gradients as high as
120°C (216 F) existed radially on any one plane, an average radial
temperature was determined. The data in Figure 2-6 indicate that the
temperature at which the highest NO reduction occurs varies from 940 to
1000°C (1724 to 1832°F).
It was speculated that the higher sulfur content of the Illinois
coal might have caused the maximum NO reduction to occur at a higher
/\
temperature. Consequently, tests were conducted in the same furnace
i.o
0.8
0.6
O
I
z
0.4
0.2
(NH,/KO = 1.0. Excess 0_ ^ 5.0%) /
3 O * /
— Natural Gas
Utah Coal
• —.— Navaho Coal
'• Pittsburgh Coal
Illinois Coal
1 I I
I
815 870 925 980 1035
Average Radial Temperature, °C
1090
Figure 2-6. Effect of temperature on NO reductions, coal and natural
gas firing (Reference 2-4).
2-15
-------
furnace in which a sulfur compound was injected into a flue gas generated
from distillate oil combustion. The results of this experiment, shown in
Figure 2-7, demonstrated that sulfur dioxide has essentially no effect on
the reaction temperature required for peak NO reduction with ammonia
J\
injection. However, more experimental testing with coal combustion might
be warranted to confirm or disprove any trends of reaction temperature
with coal type. Such experiments are currently in progress at ER&E.
i.o
0.8
0.6
0.4
0.2
Excess Oxygen *v 5%
Initial NO (N00) : 350 pp*
NH./NO *fc 1
3 O
SO. « 2900 ppm
SO « 1100-ppm
O-
J_
I
0.25 0.5 0.75 1.0 1.25
Ba y Plane of NH3 Injection, Meters from Back Furnace Wall
i I 1 ' I .
815
870
925
980
Approximate Average Temperature, C
Figure 2-7. Effect of sulfur on NO reduction, oil firing
(Reference 2-4).
2-16
-------
2.2.2 Ammonia Injection Rate
The effect of ammonia injection rate on NO reduction at peak
reduction temperatures is shown in Figure 2-8 for all the fuels tested.
KVB attributed the scatter in the data to variations in radial temperature
and to ash accumulation in the firebox which hindered temperature
measurements. The data show that the NO reduction becomes quickly
asymptotic to the 80 percent level. This maximum ammonia injection
efficiency is reached at a NHL/NO molar ratio of approximately 1.5.
Very little additional NO reduction is achieved by increasing the NH~
injection rate to 2.0.
1.0
Natural Gas
Utah Coal
Navaho Coal
Illinois Coal
Pittsburgh Coal
0.5
1.0
(NH3)/(NOQ)
1.5
2.0
Figure 2-8. Comparison of NO reductions at the optimum
temperature condition (Reference 2-4).
2-17
-------
2.2.3 Hydrogen Injection
A limited number of tests were conducted with combined NHL-Ho
injection. These tests included only the combustion of the Pittsburgh
Seam No. 8 bituminous coal. Combined injection of NhL-hL produced
higher NO reduction at temperatures lower than the optimum 950°C.
Maximum DeNO rates were maintained over a temperature range of 760°C
A
to 950°C by injection of H,, at a rate ranging from 0.2 to 0.94
measured as the molar ratio of H2 to NH3. The injection of hydrogen
also contributed to lower NH, breakthrough. KVB found that at high
3
hydrogen injection rates, NO levels increase while NH- levels in the
combustion products decrease.
2.2.4 Njj3 and Byproduct Emissions
Ammonia emissions are an important consideration in evaluating the
DeNO Process for coal combustion. The importance of this consideration
/\
depends on the amount of NH4HS04 which may be formed by the NH3 +
S03 + 1^0 reaction. This in turn depends on the amount of S03 in
the flue gas which is related to the type of coal being fired and the
level of excess air. For example, subbituminous coals, such as Navaho,
contain calcium, and yield strongly basic flyash which tend to remove
S03. In fact, KVB reported only small amounts of SO- in the flue gas,
5 ppm, with combustion of this coal. Bituminous coals, such as the
Illinois or Pittsburgh, however, yielded a flue gas containing up to 21
ppm of S03y Therefore high sulfur content coals will produce high levels
of sulfur oxides emissions which in time may react with the free ammonia
to form ammonium sulfates, an undesirable byproduct. Figure 2-9 shows
that for all coals except the Illinois coal, NH3 emissions increased
when the injection rate was greater than 0.5 NHL/NO. No explanation was
2-18
-------
given for the lower NHL emissions with Illinois coal firing. However,
the higher optimum temperature when firing Illinois coal probably
contributed to the low NH_ breakthrough.
0.4
0.3
0.2
0.1
QNavaho
^Illinois
^Pittsburgh
QNatural Gas
D
i.o
2.0
(NH3o)/(HO )
3.0
Figure 2-9.
Comparison of the NH3 emissions for all fuels
tested at the peak NO removal temperature
(Reference 2-4).
KVB investigated the use of FL injection to maintain NHL
emissions at a minimum. Results from this investigation showed that NH~
emissions decreased nearly 90 percent when H^ was injected at a rate of
2.0 (measured as molar h^/NH^). The NH^ injection rate (measured as
molar NH3/NO) was approximately 1.5 during these tests.
2-19
-------
Cyanide and nitrate emissions were measured by KVB during the
combustion of all the coals and natural gas. Emission levels averaged
2 ppm for cyanide and approximately 10 ppm for nitrates at baseline and
with reduced NO conditions. No correlation was observed between the
A
amount of ammonia injected and the emission levels of these pollutants.
These results indicate that cyanide and nitrate emissions are not a
byproduct of the ammonia injection process.
Sulfate and SO, emissions were also measured during the KVB
tests. Since sulfate emissions increased on two tests, but decreased on
two others, no conclusions could be drawn. Slight decreases in SO.,
emissions during NH~ injection were observed, indicating that SO- was
not proportional to the amount of ammonia present in the flue gas.
CO emissions increased when ammonia was injected to reduce NO ,
A
but this increase was limited to 50 ppm for Pittsburgh coal. In general,
the results indicated that, reducing NO levels through noncatalytic
reaction with ammonia inhibits the oxidation of CO to CO^. However, the
CO levels were not considered to be environmentally significant or
detrimental to the efficiency of a coal-fired utility boiler.
Results from measurement of SO,, emissions were inconclusive
because sampling problems were experienced during these measurements.
These problems were caused by a loss of S02 in the sampling lines
occurring only when ammonia was injected in the flue gas. The loss of
S02 was attributed to an absorption - desorption process on the Teflon
line rather than a process occurring in the boiler.
2.3 COMMERCIAL APPLICATION
After completing and evaluating the gas and oil subscale tests, but
before the coal subscale tests, ER&E tested the Thermal DeNO Process on
A
2-20
-------
a 45 MW heat input (70 ton/hr) oil-fired steam boiler, located at Exxon
affiliates in Kawasaki, Japan. During 1975 and 1976, seven additional
full-scale units were retrofitted with the Thermal DeNO Process. These
A
units consist of two 275 MW heat input (430 ton/hr) high pressure
q
oil-fired utility boilers, two pipestill furnaces rated at 150 x 10
bbl/day, a 7 ton/hr solid waste municipal incinerator, a 76 MW heat input
(120 ton/hr) gas- and oil-fired steam boiler, and a 375 MW oil-fired
utility boiler.
All these sources are located in Japan where NO emissions
A
regulations are much more stringent than in the United States. In
addition to these sources, one full-scale application of the process was
conducted in California on a thermal oil recovery boiler. Not all
information on this sole domestic application is proprietary. NO
X
reductions of 60 and 70 percent have been disclosed (Reference 2-5).
In all these applications, the effectiveness of the DeNO Process
A
depended on the design configuration of the unit and the flue gas
conditions at the selected injection point. Figure 2-10 shows the
performance of the process on commercial installations as a function of
the flue gas temperature. The performance of the noncatalytic ammonia
injection system on the 375 MW utility boiler is not included. However,
40 percent efficiency has been reported (Reference 2-7). The performance
data in Figure 2-10 were obtained based on maximum NO reduction while
/\
maintaining NH_ breakthrough at a minimum. It can be seen that at
approximately 950°C (1740°F) optimum injection temperature, the
maximum NO emission reduction was about 60 percent. The performance of
/\
the process decreased at lower flue gas temperatures even though hydrogen
was injected in some cases to shift the optimum temperature.
2-21
-------
1 \J
60
50
v
C
01
1 40
C
o
4J
0
o
z
2
1C
r
'
V
A —
D D °
V
A 0 • -
V
d3
0
o v -
a
o
~
SIZE DESCRIPTION
• 25 t/hr Package Boiler
* 70 t/hr 1 , d , ^ ,
O 120 t/hr )
T 100 HWe } Utility Boiler
1 1
700
800
900
1000
Flue Gas Temperature, C
Figure 2-10.
Thermal DeNOx system performance on commercial units
as functions of temperature (Reference 2-6).
Long term corrosion tests on the 45 MW boiler have shown that after
1100 hours of continuous operation, boiler tube corrosion was not
significantly higher with ammonia injection than with uncontrolled
operation. However, because the regenerative preheater was fouled by
ammonia sulfate deposits, the tubes required washing at periodic intervals.
In summary, the Thermal DeNOx Process has been demonstrated to be
approximately 60 percent effective in full-scale applications over a
200°C temperature range without major operational problems. Although
these results are restricted to oil and gas units, the process has also
been successfully demonstrated on a solid waste incinerator.
2-22
-------
The process is subject to several limitations primarily resulting
from nonideal gas conditions. Nonideal gas conditions are due to lack of
cavities at desired injection temperatures and the presence of temperature
gradients at any one injection location. Nonuniform gas velocities also
limit the efficiency of the system unless sophisticated injectors are
devised.
The recently concluded work on NHL injection in tube banks
indicates that the process can also achieve NO reduction comparable to
A
cavity injection. Therefore, since Thermal DeNO is not restricted to
/\
injection in boiler cavities, it becomes adaptable to nearly all types and
sizes of steam generators. The maximum demonstrated efficiency is,
however, currently limited to approximately 60 percent due to
nonuniformity of gas velocities and temperatures found in the flue gas of
boilers.
2-23
-------
REFERENCES FOR SECTION 2
2-1. Lyon, R. K., "Communication to the Editor: The NH3-NO-0
Reaction," International Journal of Chemical Kinetics, 8_, 315-318,
1976.
2-2. Muzio, L. J., "Homogeneous Gas Phase Decomposition of Oxides of
Nitrogen, "EPRI Report FP-253, NTIS PB 257 555, August 1976.
2-3. Bartok, W., "Noncatalytic Reduction of NOX with NH3," in
Proceedings of the Second Stationary Source Combustion Symposium:
Volume II, EPA-600/7-77-073b, NTIS-PB 271 756/98E, July 1977.
2-4. Muzio, L. J., et al., "Noncatalytic NO Removal with Ammonia," EPRI
Final Report FP-735, Research Project 835-1, April 1978.
2-5. "Exxon Says Stationary NOX Emission Significantly Reduced at
Plant," Air/Water Pollution Report, p. 76, February 20, 1978.
2-6. "Performance of the Thermal DeNOx Process in Commercial
Applications" Exxon's Sales Brochure, 1979.
2-7. Wong Woo, H., and Goodley, A., "Observation of Flue Gas
Desulfurization and Denitrification Systems in Japan," State of
California Air Resources Board Report No. SS-78-004, March 1978.
2-24
-------
SECTION 3
APPLICABILITY ASSESSMENT
The Exxon's Thermal DeNO Process can reduce NO emissions by
X X
40 to 60 percent for gas- and oil-fired boilers. Performance of the
DeNO technique can be equal to or better than conventional combustion
X
modifications. However, operating cost of the NH, injection is much
higher than combustion modifications. Hence, the process is most
cost-effective when used in conjunction with combustion modifications.
Specifically, the combined effect of NH- injection with conventional
controls is considered a viable technique for boilers which cannot meet
projected NO emissions standards with only conventional controls.
/\
Coal-fired utility boilers are the major source for which the
DeNO Process has recently been evaluated. The increased use of coal as
y\
the main fuel for utilities, combined with the high uncontrolled NO
A
levels from coal combustion and the difficulty in reducing NO emissions
/\
more than 50 percent when using combustion controls alone, make coal-fired
sources a prime candidate for Exxon's DeNOx Process.
Exxon has developed a calculation procedure which can predict
DeNO performance from all boilers — including coal-fired ones. The
/\
calculation procedure is based on proprietary and published results from
pilot- and full-scale investigations. Published reports have been briefly
described in Section 2.
3-1
-------
Using this Performance Prediction Procedure, Exxon has conducted an
analysis of the maximum NO reduction achievable in eight typical
coal-fired utility steam generators. Exxon also evaluated the combined
effects of NH_ injection with conventional combustion modifications.
These calculations estimated whether the added NO reduction from NH3
injection could reduce NO emission levels to 300 ppm for bituminous
J\
coal and lignite, and 225 ppm for subbituminous coal regardless of the
initial NO emission level.
This section presents an assessment of the applicability of NH,
injection technology to reduce NO emissions from coal-fired powerplants.
This assessment includes:
• Analysis of the correlation scheme and Exxon's predicted
results (Section 3.1)
• Review of the process limitations and potential adverse effects
(Section 3.2)
This assessment is based primarily on proprietary information furnished by
Exxon and supplemented by published data from KVB, Exxon, and EPRI.
3.1 CORRELATION PROCEDURE AND PREDICTED RESULTS
Experimental results using NH- injection in flue gas streams have
clearly shown that the efficiency of the Thermal DeNO Process depends
3\
on the NH3 injection rate, the injection temperature, and the residence
time of the flue gas. Based on these results, Exxon has correlated average
injection temperature and flue gas residence times with NO reductions
J\
at various NH3 injection rates. The correlation accounts for the flue
gas being cooled by convective tubes of boilers. Boilers with large
cavities in the temperature range of 1000°C to 760°C (1830°F to
1400°F) are most desirable because effective residence times are longer.
3-2
-------
The Exxon correlation predicts NO reductions as high as 70
A
percent for long effective residence times and an NH, injection rate of
NH^/NO = 1.5. However, cross sectional uniformity in flue gas flow and
O
temperature is necessary to achieve these performance levels. Unfortunately,
temperature and flow distributions at any one cross section of the boiler
are not uniform. The correlation accounts for nonuniformity of flue gas
temperature and flowrate. The predicted performance is reduced when
corrections reflecting temperature and velocity gradients are applied.
Gradients in NO concentration across the duct of coal-fired boilers
may also be present which are not accounted for in the Exxon Performance
Prediction Procedure. NO stratification in the ducting of coal-fired
powerplants has been measured by Exxon (Reference 3-1). The nitric oxide
concentration varied by 19 percent from the average cross sectional
value. Even though these measurements were made downstream of the air
heaters, it is possible that some NO stratification may also be present at
the convective section of large coal-fired boilers where NH_ would be
injected.
If NO stratification was found in most of the boilers, the Exxon
correlation would also need to account for this nonuniformity in flue gas
conditions in addition to the temperature and flow nonuniformities.
Considering temperature, velocity and NO concentration gradients, uniform
NH3 injection may not be feasible if significant system efficiencies are
required. Thus, for a retrofit application, the flue gas characteristics
at the injection location should be carefully mapped before selecting the
system design and operating conditions. A zoned injection system
accounting for temperature, velocity and NO concentration gradients may be
warranted if large variations exist. Each zone would have its own NH3
3-3
-------
injection rate. Such an injection system would be more sophisticated and
thus, more costly.
The Exxon empirical correlation appears to be a useful tool in
predicting an approximate NO reduction level achieved with a specific
injection system design. However, the procedure will only predict
approximate DeNO rates unless a detailed characterization of the flue
/\
gas temperature, velocity and NO concentration is made at many different
loads. Section 3.2 will show that, especially for coal combustion,
numerous boiler design operating characteristics will affect actual
performance of the Thermal DeNO system.
X
As part of the applicability assessment of the Thermal DeNO
/\
Process on coal-fired utility boilers, Exxon selected eight coal-fired
units and applied the developed correlation to estimate maximum NO
reduction (Reference 3-2). The selection of coal-fired boilers included
designs from the largest manufacturers of utility steam generators. Two
front wall and two horizontally opposed wall boilers manufactured by
Babcock and Wilcox (B&W) and Foster Wheeler (FW) were selected. These
boiler firing types represent approximately 67 percent of the current
installed units (Reference 3-3). Two tangentially fired Combustion
Engineering (CE) boilers were also selected. These boilers represent
approximately 20 percent of the total installed units in 1974
(Reference 3-3). One cyclone and one turbo/furnace boiler were also
selected.
Table 3-1 lists the results of Exxon's performance prediction
analysis of the Thermal DeNOv Process on these boilers. Percent NO
x x
reductions for the NH3/NO = 1.0 and 1.5 injection rates were reported by
Exxon. However, the percent NOX reductions for the NH3/NO = 0.5
3-4
-------
TABLE 3-1. SUMMARY OF EXXON PREDICTED THERMAL DeNOx PERFORMANCE
(WITHOUT COMBUSTION MODIFICATIONS)
co
en
Unit
B&W 333 MW
B&U 333 MM
B&W 400 MW
CE 350 MW
CE 800 MW
FW 330 MW
FW 670 MW
RS 350 MW
Boiler
Load
% MCR
100
75
50
100
75
50
100
75
50
100
75
60
100
75
60
100
75
60
100
75
50
100
75
60
Initial
NOX
ppm
500
450
400
700
630
560
1000
900
800
500
450
400
530
480
425
850
770
680
700
630
560
700
630
560
Maximum DeNOx Rate (percent)
NH3/NO =0.5
20
20
25
24
22
22
23
23 .
NA a
V
26
20
20
25
20
20
20
NAV
NAV
24
NAV
NAV
24
NAV
22
NH3/NO =1.0
38
38
49
48
44
44
45
45
NA
V
52
40
40
52
40
40
41
NAV
NAV
47
NAV
NAV
47
NAV
45
NH3/NO =1.5
48
48
63
63
56
56
57
57
NA
V
58
45
45
57
45
45
54
NAV
NAV
60
NAV
NAV
58
NAV
54
Injection
Grid
1
1
2
1
2
2
1
1
1
2
2
1
2
2
1
1
1
2
Injection
Location
Tube bank
Tube bank
Cavity
Cavity
Tube bank
Tube bank
Tube bank
Tube bank
Cavity
Cavity
Cavity
Cavity
Cavity
Cavity
Cavity
Cavity
Cavity
Cavity
aNot available
-------
injection rate were extrapolated using the Exxon Performance Prediction
Procedure. Two injection grid locations were selected to account for the
boiler heat input levels, 100, 75 and 50-60 percent of design capacity.
One grid (dual load) was located to give the best compromise performance
at two load levels, while the other grid (single load) was located to give
maximum performance at the remaining load level. Often both injection
grids were located in boiler cavities. However, on two units, one of the
grids was located directly within a tube bank. In this section a boiler
cavity is defined as the space between two subsequent tube banks, while
in-tube bank injection corresponds to injector grid location directly
within a bank of convective tubes. The DeNO rates reported in Table 3-1
/\
represent the maximum performance of the process without combustion
modifications at the respective NH. injection rates as predicted by Exxon.
At first it would seem evident that cavity injection for the B&W
wall fired units is more effective than injecting NhL directly within a
tube bank. However, the difference between the performance of the two
injection locations derives from having only two injection grids to
maximize NO reductions at three boiler loads or three flue gas
J\
temperatures. If three injection grids were available, each placed at the
desired location, the DeNO performance would somewhat improve for the
/\
two dual load points.
In retrofit application of the Thermal DeNO system, the most
/\
frequently used load (baseline load) of the unit should be emphasized in
designing injector placement. This is to insure that at least one
injection grid will maximize DeNOx performance at that particular boiler
load. That is, if a boiler operates at 90 percent of Maximum Continuous
3-6
-------
Rating (MCR) during most of its continuous operation, one injection grid
should be located to reduce NO emissions at that load.
/\
From a performance standpoint, there is no clear indication that
Thermal DeNO is more effective with any one boiler design. For equal
A
injection rates NO percent reductions are nearly the same for all
/\
boilers. However, in the case of NH3/NO equals 1.5, the performance of
the Thermal DeNO Process for the two CE units is 3 to 12 percent lower
/\
than for the B&W units. This is probably due to their lower initial NO
emission levels.
The performance values reported here include only corrections for
temperature distribution across the flue gas duct at the injection
location. A temperature range over the duct cross section was used by
Exxon for the cavity and tube bank segment at the exit of the boiler
furnace. For all other downstream cavities and tube bank segments, a
lower temperature range was assumed. These temperature ranges were partly
suggested by the boiler manufacturers and were partly based on Exxon's
field experience. Insufficient data exist to quantify these temperature
gradients in wall fired utility boilers and to determine if all
significant temperature effects caused by boiler design and operating
conditions are accounted for.
Gradients in flue gas velocity and NO concentrations in the
cross sectional plane at the injection location were not taken into
consideration by Exxon when calculating the performances reported in
Table 3-1. These gradients could be large enough to reduce actual
performance significantly, in the absence of compensating measures such as
NH3 injection zoning.
3-7
-------
3.2 PROCESS LIMITATIONS
The performance of the Thermal DeNO Process is limited by the
temperature and flow nonuniformities in the flue gas ducts. Exxon's
Performance Prediction Procedure considers these factors by lowering the
predicted DeNO results depending on the severity of both temperature
A
and flow nonuniformities. However, the effectiveness of the process can
also be significantly affected by other factors. These factors are:
• Selection of injection location
• Temperature profile fluctuations through boiler
• NH., emissions and byproducts formation
O
This section describes how each of these factors can further limit
the Exxon efficiency predictions for coal-fired boilers.
3.2.1 Selection of Injection Location
Exxon selected the injection locations for the eight coal-fired
utility boilers based on maximizing the performance of the process. In
actual retrofit application of NH- injection systems, obstructions due
to any hardware in place could force the installation of injection grids
in less desirable locations. For example, soot blowers are located in all
the cavities of the convective section of coal-fired boilers. Soot
blowers clean convective tubes of slagging or fouling, and cannot
generally be removed without causing operational problems. Therefore, the
boiler cavities where the injection grid is to be located would need to
accommodate the soot blowers as well as the injection grid.
A detailed feasibility study of retrofitting the injection grid in
any of the eight coal-fired boilers cannot be made in this report, since
the grid system is proprietary. Figures 3-1 and 3-2 show some details of
the Mitsubishi Heavy Industries (MHI) injection system retrofitted on
3-8
-------
Figure 3-1. Section of the NH3 injection nozzle pipe for a 375 MW
gas-/oil-fired utility boiler in Japan (Reference 3-4)
Figure 3-2. Concept of nozzle systems location (Reference 3-4),
3-9
-------
the 375 MW gas- and distillate oil-fired boiler .in Japan. It should be
emphasized that this injector grid design is different from the Exxon's
proprietary grid, therefore, it does not represent Exxon's technology. No
retrofit problems have been reported with this injection design. However,
soot blowers are not usually installed with gas and distillate oil-fired
boilers.
The installation of injection grids within tube banks can also
result in retrofit problems causing the relocation of the injection grid.
For example, in most cases, installation of injection grids within tube
banks would necessitate removal of rows of convective tubes. Depending on
the design of the grid, one or two rows of tubes might have to be
removed. If the removed cooling surface accounts for a significant
portion of the total surface of the tube bank, a loss in boiler efficiency
or operational problems could result.
Table 3-2 shows the effect of relocating the dual load
injection grid from the tube bank to the upstream cavity. These data were
obtained using the Exxon-developed Performance Prediction Procedure. For
the small 130 MW boiler the effect is minimal. Therefore, the injection
grid should be located in the cavity. In the case of the 333 MW
horizontally opposed (HO) boiler, the effect is highly significant for the
75 percent boiler load operation. For this boiler, a three grid injection
system might be considered if the intube injection location proves
unfeasible. For the cyclone boiler (CY), the effect is not very dramatic;
NH3 injection in the cavity might be more suitable.
It should be pointed out, however, that bending a convective tube
could also accommodate the installation of the grid at the required
location. Questions regarding the actual retrofit of the NH3 injection
3-10
-------
TABLE 3-2. ESTIMATED EFFECT OF INJECTION GRID RELOCATION
ON PREDICTED DeNOx RATES — NH3/NO =1.5
Load
Boiler ID (percent MCR)
B&W 130 MW FW 100
75
B&W 333 MW HO 75
50
B&W 400 MW Cy 100
75
Predicted DeNOx
Rate With NH3
Injection Within
Tube Bank
48
48
56
56
57
57
Estimated DeNOx
Rate With NH3
Injection Upstream
of Tube Bank
48
49
37
64
52
60
system cannot be addressed properly because of the lack of data on the
Exxon proprietary grid design. However, it is important that these
possible limitations be considered in assessing the feasibility of the
Thermal DeNO Process.
A
Another factor to be considered when installing the injection grid
is the position of the grid relative to the nearest upstream soot blower.
Soot blowers may be needed to maintain the surface of the injection grid
clean and prevent flyash accumulation and slow plugging of any of the
nozzles especially during a loss of air flow through the nozzles. In
addition, a backup NH3 delivery system might be necessary to prevent
sudden shutdown of the flow at the nozzles and also prevent the
accumulation of flyash deposits on the nozzle exit.
3-11
-------
In general, some compromise might have to be adopted when the
actual location of an injection grid is determined. This compromise is
forced by the problems in keeping nozzle and grid surfaces clean of
deposits which might interfere with NH3 injection, and problems with
tube bank modifications causing loss of efficiency or boiler operational
problems. Therefore the optimum location of NH~ injection might not be
feasible in all cases, and a reduction in DeNO rate might result when
A
an alternate location is used.
3.2.2 Flue Gas Temperature Fluctuations
The performance of the Thermal DeNO Process is extremely
X
sensitive to flue gas temperatures. In fact, pilot-scale testing under
well controlled conditions showed that the DeNO rates are rapidly
A
reduced if the flue gas temperature at the injection location varies by
more than 110°C (200°F) from the desired level of about 960°C. Flue
gas temperature fluctuations of this magnitude often occur in the
convective sections of coal-fired boilers even during constant heat input
operation. These temperature changes will cause some decrease in the
performance of the process in addition to all decreases accounted for by
Exxon. Although it is difficult to predict the magnitude of the loss in
DeNOx performance, a prospective user should be aware of the existence
of those potential problems.
The boiler design and operating characteristics which cause
fluctuations in the temperature of the flue gas exiting the furnace and
the convective passes are:
t Furnace slagging
• Tube fouling
t Soot blowing
3-12
-------
• Load variation
• Operational upsets
• Heterogeneous coal properties
Figure 3-3 shows the areas where slagging and fouling occur in a
coal-fired utility boiler. The flue gas temperature at the NH,
0
injection location is affected by both slagging and fouling. Generally,
slagging of the furnace walls will cause a larger temperature effect for
the upstream grid location (low boiler loads) than for the downstream one
(high boiler loads). When slagging is compounded with fouling the
opposite is true. The following comments refer to each of these flyash
deposition effects in coal-fired utility boilers.
3.2.2.1 Slagging
Nearly all coals will slag the furnace walls at some rate.
However, subbituminous coals usually cause higher slagging rates than
bituminous coals. As flyash is deposited on furnace walls, the heat
transfer to the water wall decreases, increasing the temperature of the
flue gas exiting the furnace. Thus, temperature is usually carefully
monitored by the boiler operator and the appropriate steps are taken to
maintain the temperature within a safe limit. This limit is dictated by
high superheater steam temperature combined with high attemperator water
flow rates. Safe temperature limits can be maintained by activation of
furnace soot blowers or lowering the burner tilt (for tangential and turbo
furnace boilers only), or both. However, before these steps are taken,
temperature at the furnace exit can easily increase by 100°C (180°F).
This temperature increase will then cause corresponding increases
in the Temperature At Point of Injection (TAPI) at the NH3 injection
locations. Although the Exxon's Performance Prediction Procedure
3-13
-------
> Burner zone
Figure 3-3. Deposition zones in a coal-fired boiler.
3-14
-------
indicates that an increase in temperature will also affect the effective
residence time of the gases, for the low load cases, the loss in DeNO
x\
performance might be as high as 20 percent.
The rate of furnace slagging is difficult to predict. Coal
properties such as the ash fusion temperature and viscosity vary
significantly among coal mines and often within one single mine.
Therefore in the case of a coal-fired boiler retrofitted with the Thermal
DeNO system, a careful characterization of flue gas temperature
/\
variations with furnace slagging is necessary before selecting the
injection location. However, fluctuations in flue gas temperatures due to
slagging rates and soot blowing cycles may lower DeNO performance below
A
the Exxon predictions.
3.2.2.2 Fouling
Another important characteristic of large coal-fired boilers is
the fouling of the convective tubes. As in the case with slagging,
fouling is most severe with Western subbituminous coals possessing special
ash characteristics such as high sodium content. Figure 3-3 indicates
that Exxon located the downstream injection grid in the fouling zone for
all eight boilers investigated. The rate of fouling of convective tubes
and the effect on flue gas temperatures are difficult to predict.
However, the increase in TAPI of the downstream NH^ injection location
can be significant within a soot blowing cycle.
Soot blowing in this case is usually initiated when the temperature
of the flue gas entering the air preheater reaches levels unsafe for the
air preheater. Temperature may increase by 100°C (180°F) at the air
preheater inlet before soot blowing is initiated.
3-15
-------
Combined slagging and fouling will affect the downstream NH~
injection grid. Therefore the injection temperature at this location can
fluctuate by 100°C within a soot blowing cycle.
Occasionally, an increased TAPI can be beneficial rather than
detrimental to the performance of the Thermal DeNO Process. In fact,
A
increasing flue gas temperature at the NH- injection location actually
simulates injecting NH3 at an upstream location where the flue gas
temperatures are higher. For example, the B&W 333 MW boiler operating at
50 percent load has an injection location temperature of approximately
930°C (see Figure 3-4). An increase in TAPI of 50°C caused by ash
deposition would simulate injecting NH~ in the cavity segment No. 3,
where flue gas temperature is 980°C. Exxon's Performance Prediction
Procedure indicates that the NO reduction rate would increase from 56
A
to 64 percent as indicated in Table 3-2. However, if the boiler were
operating at 75 percent load, the DeNO rate would decrease from 56 to
/\
approximately 40 percent.
In all cases, if the injection location is selected based on a
clean furnace and convective tubes, then lower DeNO rates can be
A
expected than the ones predicted by Exxon, if averaged over any 1-day
period. One compensation of increased flue gas temperature with fouling
or slagging is the reduced NH3 breakthrough emissions. NH3 emissions
should decrease based on the tendency of the reagent to form rather than
destroy NO at elevated temperatures.
3.2.2.3 Soot Blowing
Soot blowers operate intermittently in the furnace and convective
passes of boilers to remove ash deposits on cooling tubes. Thus, soot
blowers participate in the flue gas temperature fluctuation cycle.
3-16
-------
co
_^
-vj
1200 -
Unit - B&W 333 MW
Fuel - Eastern Bituminous Coal
Load (PCT) - HOP | 75 | 50
NOT (PPM) - ;700 J630 560
2000 4000 6000 8000
Distance from boiler furnace exit, mm
Figure 3-4. Flue gas temperature profile (Reference 3-5).
-------
Slagging and fouling affect temperature uniformly throughout the cross
section of a boiler, while soot blowers have a more localized effect due
to their sequential operating order. Thus, one zone of a boiler cross
section might be cleaned of the deposit while the rest would still be in a
dirty state. Nonuniform deposits on furnace and convective tubes could
account for large temperature gradients. Gradients of this magnitude may
have been included in Exxon's estimated temperature distributions.
However, soot blowing may affect boiler operating characteristics,
temperature, and NO reductions.
A
3.2.2.4 Load Variations
Heat input to the boiler will naturally change the flue gas
temperature profile throughout the boiler. Exxon has chosen a two grid
injection system for the Thermal DeNO Process to maximize DeNO
X A
performance at three boiler loads. However, there is no grid operating
procedure presented by Exxon when the boiler is operating at loads other
than those considered. This is an important consideration because at
intermediate loads, NH., injection by the improper grid could cause
excessive NH., breakthrough emissions.
Intermediate load operation may dictate some special grid operating
arrangement to maximize NO reduction and minimize NH., emissions.
Mitsubishi Heavy Industries (MHI) documented their application of the
Thermal DeNO Process on the 375 MW gas- and oil-fired boiler
A
(Reference 3-4). MHI's suggested Thermal DeNO procedure for their
A
special injection system during the entire boiler operating load range is
shown in Figure 3-5. It is important to note that one of two main
criteria for the NH3 injection rate and the selection of the operating
grid is the NH3 breakthrough emissions. In this particular case, the
3-18
-------
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-------
front side injection grid is operated at NH3/NO = 0.5 up to a load of 60
percent. Between 60 and 75 percent, both grids are operated with a
combined NH3 injection rate of NH3/NO = 0.5. Above 75 percent only
the rear grid is used with correspondingly increasing NH3 injection
rates. Following this procedure, NH3 emissions are monitored to less
than 25 ppm at all boiler loads, according to MHI.
If a similar procedure based on minimal NH3 emissions were
adopted for the eight coal-fired boilers, the DeNO efficiencies listed
in Table 3-1 might again reflect optimistic levels of system performance.
Potential adverse effects of Nf-L emissions are discussed in more detail
in Section 3.2.3.
3.2.2.5 Operational Upsets
Operational upsets that might affect the temperature of the flue
gas can be mainly related to burner operation. For example, during a
pulverizer outage, the coal flow to selected burners will be terminated.
These burners, often located randomly on the furnace walls of front and
horizontally fired boilers, are on a same level in the case of
tangentially fired boilers. For wall fired boilers, the random location
of burners out of service could cause high temperature gradients. For
tangential boilers, the temperature gradient should not be affected
because of the symmetry of the shut-off burners with furnace geometry.
The increased flue gas temperature gradients reduce the DeNO
X
performance and increase NH3 breakthrough, if NH3 injection rate is
not corrected during the boiler upset. Because these outages can be
prolonged, NH3 emissions could create a temporary environmental concern.
Temperature gradients due to pulverizer outages on wall fired
boilers are difficult to estimate, because of the associated effect of
3-20
-------
load reduction. Operational upsets are not a part of the DeNO
A
Performance Prediction Procedure and cannot be really considered in any
prediction scheme. However, operational upsets could be a serious
consideration if NH3 breakthrough is intolerable.
3.2.2.6 Heterogeneous Coal Properties
During pilot-scale testing by KVB, the optimum reaction temperature
was found to be approximately the same for firing natural gas as for three
coals. A fourth coal apparently showed an optimum temperature that was
approximately 55°C higher. Experiments are now underway at Exxon to
determine whether this is a real effect or an experimental artifact. If
this possible effect of coal type is real, it will have to be considered
in implementing ammonia injection on coal-fired boilers.
3.2.3 NH0 Breakthrough and Equipment Maintenance
j
The most important precautions in preventing NH3 breakthrough are
careful design, location, and operation of the injection grid. Higher
than optimum DeNO temperatures are effective in maintaining low NH-
X O
emissions but with a slight penalty in NO reduction efficiency.
/\
Despite these precautions, NH., emissions varying from 10 to 40 ppm were
measured from the full-scale commercial application of the Thermal DeNO
A
Process on gas- and oil-fired units. By comparison, the flue gas NH^
concentration used in Industrial Environmental Research Laboratory (IERL)
environmental assessments to signify a potential environmental health
hazard is 24 ppm (Reference 3-6). This concentration is intentionally
conservative for use in screening effluent measurements to identify those
requiring further study. Nontheless, the NH- breakthrough observed in
Thermal DeNO field demonstrations is of comparable magnitude and bears
J\
further study.
3-21
-------
With fuels containing sulfur, the ammonia which did not react with
NO easily reacted with SO, and H,,0 to form ammonium sulfates. These
sulfates condense and become adhesive so lids/liquids at temperatures
typical of the air preheater section of large steam generators. Sulfate
deposits, although not occurring in all Exxon full-scale applications,
have caused some draft loss problems with two oil-fired boilers. These
boilers are a 375 MW utility steam generator firing a 0.2 percent S oil
and an industrial size steam generator firing oil with an unspecified
sulfur content. On-steam water washing was successfully used to remove
sulfate deposits from the air heater in the industrial boiler.
The possibility of NH., breakthrough and associated implications
caused by its presence in SO -laden gases, deserves further assessment
}\
in establishing the feasibility of the Thermal DeNO Process for
/\
coal-fired boilers. This section presents possible limitations based on
estimated NH3 breakthrough emissions from coal-fired boilers.
3.2.3.1 Estimated NH3 Emissions
NH_ emissions leaving the reaction zone of the DeNO Process
-------
Unfortunately NH3 breakthrough can occur with the higher NH3 injection
rates required for high DeNOx efficiency. Additives can help reduce NH3
emissions. However, additives add significantly to the cost of the
process and their use creates concerns over safety.
In general, NH3 emissions are expected with any full-scale
application of the Thermal DeNO Process. These emissions could vary
A
from a few ppm to more than 50 ppm especially for the case of maximum
required NO reduction efficiency. KVB tests showed that even under the
/\
controlled operation of pilot-scale testing, NH3 breakthrough in the
flue gas from coal combustion could measure approximately NH_ ./NH- .
*j~"OuL o~ I n
= 0.1 to 0.2 for an injection rate of NH3/NO = 1.5. (Refer to Figure 2-9
and Reference 3-7). The effective residence time in the KVB pilot-scale
coal-fired furnace was on the order of 0.85 seconds due to the cooling of
the gases by 165°C (329°F) over a distance of 0.6 meter (2 feet) in
the reaction zone. The injection system for the KVB experiments had 5
nozzles covering an approximate cross sectional area of 0.55 square meters
(6 ft2)-.
Table 3-3 presents estimated NH3 emissions for the eight coal-fired
utility boilers. Ammonia emissions of NH3_out/NH3-in = O-043 and
NH- 4./NH, . = 0.129 were selected to estimate the concentration of NH,
3-our 3-in J
breakthrough for the ammonia injection rates of NH3/NO = 1.0 and NH3/NO
=1.5 respectively. These NH3_out/NH3_in Va1ues correspond to average NH3
emission rates obtained during KVB pilot-scale tests with coal combustion. The
use of NH3/NO = 0.5 was not considered because experiments showed negligible
NH3 breakthrough emissions with this ammonia injection rate.
3-23
-------
TABLE 3-3. ESTIMATED NH3 EMISSIONS (100 PERCENT BOILER LOAD
AND WITHOUT COMBUSTION MODIFICATIONS)
Unit
B&W 130 MW
B&W 333 MW
B&W 400 MW
CE 350 MW
CE 800 MW
FW 330 MW
FW 670 MW
RS 350 MW
NO Emission
(ppm)
500
700
1000
500
530
850
700
700
NH3/NO = 1.0
NO* Reduction
(Percent)
38
48
45
52
52
41
47
47
NH3
(ppm)
500
700
1000
1500
530
850
700
700
NH3-Out
(ppm)
21
30
43
21
23
36
30
30
NH3/NO =1.5
NOv Reduction
(Percent)
48
63
57
58
57
54
60
58
NH3
(ppm)
750
1050
1500
750
795
1275
1050
1050
NH3-Out
(ppm)
64
90
129
64
68
109
90
90
-------
Table 3-3 indicates that except for three cases, NH, breakthrough
levels can easily exceed 24 ppm (the acceptable threshold limit used in
environmental assessments) (Reference 3-6). NH3 breakthrough emissions
are highest for the cyclone unit because of the initial high concentration
of injected NH-.
To reduce the amount of breakthrough, the ammonia must be injected
where the flue gas is hotter, or, injected at a reduced rate. Both
methods seem to be equally effective; however, they both decrease the
efficiency of the Thermal DeNO Process. Reducing the NH- injection
X 0
rate is much less expensive than relocating the injection grid.
In reality, NH3 emissions cannot be easily predicted because they
are affected not only by the NH, injection rate and the residence time
of the gases but also by other factors such as reagent mixing and reaction
temperature fluctuations. These NH, emission estimates are considered
very preliminary, however, they are indicative of potential NH_
breakthrough levels. The following pages will discuss potential
operational and environmental problems of ammonia breakthrough.
3.2.3.2 Major Implications
Sulfur trioxide (S03) is formed by the oxidation of SO^ in the
convective section. The quantity of SO, formed is dependent on coal
type and excess combustion air levels. Flue gases from bituminous and
subbituminous coals may contain SO, anywhere from 1 to 5 percent of the
total SO (SCL + SO,). Lignite, however, may form a significant
A £ 3
amount of SO, which quickly reacts with alkaline metals to form sulfates.
0
3-25
-------
The presence of NH3, S03 and moisture in the flue gas of
coal -fired power plants forms ammonium sulfate or ammonium bisulfate, as
shown by the following equations
2 NH3 + S03 + H20 - *-(NH4)2 S04 (sulfate)
NH3 + S03 + H2° - ^NH4 HS°4 (bisu1fate)-
NH4HS04 is a liquid above 150°C (300°F). While (NH4)2$04is a solid up
to 235°C (455°F). Liquid and solid ammonium sulfates formed in the
ducting of coal-fired boilers could represent a significant operational
problem because of fouling and potential corrosion.
Full-scale application of the Thermal DeNO Process on oil-fired
/\
heaters and steam generators has shown, in most cases, that if NH3
emissions are maintained below about 45 ppm, and the oil sulfur content is
low, air heater corrosion is insignificant. However, on two sources
discussed in Section 2, the formation of ammonium sulfates caused
increased fouling of air preheater parts and required unit shutdown for
maintenance. Exxon recommends on-stream washing of the air preheater when
the boiler is retrofitted with Thermal DeNO .
x
The amount of sulfate or bisulfate formation is difficult to
predict because it depends on the relative concentrations of SO- and
J
NH3 in the flue gas. Table 3-4 shows estimated bisulfate formation for
the eight coal-fired boilers in consideration. Coal sulfur contents were
set at 1.0, 2.0 and 0.4 for subbituminous, bituminous and lignitic coals,
respectively. The amount of S03 in the flue gas was estimated at
2 percent of total S0x for bituminous and subbituminous coals and 0.5
percent for lignite based on a sulfur emissions study (Reference 3-8).
Ammonium bisulfate formation was then predicted for varying amounts of
S03 using the data contained in Figure 3-6.
3-26
-------
TABLE 3-4. ESTIMATED FORMATION OF AMMONIUM BISULFATE IN COAL-FIRED
UTILITY BOILERS INVESTIGATED - NH3/NO = 1.0
Unit
B&W 130 MW
B&W 330 MW
B&W 400 MW
CE 350 MW
CE 800 MW
FW 330 MW
FW 670 MW
RS 350 MW
Fuel
Subbituminous
Bituminous
Lignite
Bituminous
Subbituminous
Bituminous
Subbituminous
Bituminous
% S in Fuel
1.0
2.0
0.4
2.0
1.0
2.0
1.0
2.0
NH3-Out
ng/J
5.2
7.5
13
5
6
9
7
7
S03-0uta
ng/J
15
27
2
29
14
29
14
29
NH4HS04 ng/J ( Percent of NH3 Used)
5% S03
Reaction
1
2
0.1
2
1
2
1
2
(3)
(4)
(0.2)
(6)
(6)
(3)
(2)
(4)
100% S03
Reaction
21
39
2
34b
20
42
20
42
(61)
(77)
(3)
(100)
(50)
(68)
(43)
(88)
OJ
I
ro
aAssumes S03 = 2 percent of SOX for bituminous and Subbituminous coals and
0.5 percent for lignite coals.
bOnly 80 percent of S03 is consumed by NH3.
-------
u>
PO
00
(Assumes all sulfur in the coal
converting to S02 * S03)
40 50 60 70
Percent S03 reacting with NH3
Figure 3-6. Ammonium bisulfate formation as a function of
sulfur content In the coal.
-------
Estimated NH4HS04 formation varies from 0.12 ng/J (0.0003
lb/10 Btu) for the lignitic coal to nearly 43 ng/J (0.1 lb/106 Btu)
of heat input for the bituminous and subbituminous coals.
KVB reported a decrease in S03 emissions during their pilot-scale
testing with coal combustion (Reference 3-7). This decrease, attributed
to NH4HS04 formation, ranged from 15 to approximately 50 percent of
the initial SO., emission levels measured without NH- injection.
However, the decrease was not proportional to the amount of Nf-L injected
in the flue gas. Based on these data it is doubtful that all of the SO.,
from coal-fired boilers will react with NH_. However, in another study,
Dismukes (Reference 3-9) has reported SO., reductions ranging from 50 to
90 percent when NH, was injected downstream of the air preheater.
Considering the two extreme cases of 5 and 100 percent conversion
of SOo to ammonium bisulfate, the total emission rates for the eight
coal-fired utility boilers operating at full load were calculated. These
NH.HSO. emission rates are shown in Table 3-5. Based on the above
assumptions, the large, twin-furnace 800 MW Combustion Engineering boiler
will form the largest quantities of NH.HSO* due to its size. The
smallest rate of formation will be for the lignite-fired cyclone boiler
due to the assumed low sulfur content of this coal, and the low percentage
of SOo available to react with NH^.
Even though these estimates are crude, it is evident that
substantial NH.HSO. could be formed and deposited on the regenerative
air preheaters of coal-fired boilers. These deposits can pose severe
problems to the operation of the units because of plugging and corrosion.
Studies on a Japanese boiler showed deposits of ammonium sulfates
built up to a thickness of 7 to 10 mm (0.28 to 0.39 inches) in the tubular
3-29
-------
TABLE 3-5. PREDICTED AMMONIUM BISULFATE EMISSION RATES
Unit
B&W 130 MW
B&W 330 MW
B&W 400 MW
CE 350 MW
CE 800 MW
FW 330 MW
FW 670 MW
RS 350 MW
Heat Rate
Btu/kW-hr
9,500
10,000
10,000
10,000
10,000
10,500
10,500
10,000
NH4HS04 kg/hr (Mg/year)a
5% S03
Reaction
1.36
7.18
0.55
7.64
9.18
7.18
7.68
7.64
(9.52)
(50.26)
(3.85)
(53.48)
(64.26)
(50.26)
(53.76)
(53.48)
100% S03
Reaction
26.9
143.9
10.4
125.8
177.6
147.4
149.1
155.4
(188.3)
(1007.3)
(72.8)
(880.6)
(1243.2)
1031.8)
(1043.7)
(1087.8)
aMg = 10^ grams, assumes 80% load factor
3-30
-------
air preheater after 1100 hours of uninterrupted operation. The boiler
fired a light oil containing very little sulfur. In the application of
the MHI noncatalytic ammonia injection process on the 375 MW oil/gas-fired
utility boiler at the Chita Station in Japan, fouling forced operation to
a halt twice in one year to wash the air preheater. The sulfur content
of the oil burned at the Chita station was 0.2 percent. In contrast, the
sulfur content of bituminous coal is usually around 2.0 percent.
Complicating matters, these deposits are apparently not easily removable
with soot blowers and the water washing to remove the sulfate deposits can
sometimes necessitate boiler derating or even shutdown.
Coal-fired utility boilers are typically taken "off the line" once
a year as part of their scheduled maintenance. During this time the
regenerative air preheaters are washed to remove flyash deposits. Large
boilers are often equipped with two preheaters. If the fouling of the air
preheaters caused by NH.HSO. formation is such that the yearly washing
will suffice to remove the deposits, then the operation of the boiler
should not be affected. However, with the NH4HS04 formations listed
in Table 3-5, the fouling could be severe enough to require additional
washings.
Air preheater washing is usually carried out under one of the
following conditions: out-of-service, in-service-isolated, or
in-service-on-stream (Reference 3-10). Out-of-service washing is
accomplished when the boiler is shut down for normal scheduled inspection
or for repair work. This type of washing represents the most effective
washing operation because it allows for a thorough inspection of the air
preheater parts.
3-31
-------
In-service-isolated washing is depicted in Figure 3-7. Boilers
equipped with two preheaters can continue to operate during washing cycles
by switching to one preheater operation as shown in Figure 3-7. However,
the switch to single preheater operation would mean a reduction in boiler
load for the duration of the washing.
In-service-on-stream washing is carried out while allowing both gas
and air to pass through the air preheater. On-stream washing is
applicable only in those installations where the ductwork and location of
drains are such as to eliminate or at least minimize the amount of
moisture entering the dust collectors, precipitators, windboxes, and
boilers. On-stream washing is required before ash buildup reaches the
point when any actual plugging occurs. Therefore, it usually commences
when the gas side pressure differential increases to a maximum of 0.5 inch
(W.6.) over design specifications.
Unscheduled cleaning of the air heater due to NH.HSO. deposits
could in some cases require boiler derating or even shutdown, resulting in
revenue loss for the utility and increased cost of maintenance.
In conclusion, it is reemphasized that the above discussion is only
qualitative and based on numerous assumptions. The implications of NH-
emissions in S03-laden flue gas streams should, however, be carefully
considered. Reported measurements of NH4HS04 deposits in air preheaters
have shown that fouling can occur with low sulfur oils. This problem can
intensify with combustion of high sulfur coal. Low NH- emissions may
lower the formation of NH4HS04. In most cases, however, the formation
is limited more by the S03 content of the flue gas than the NH-
O
concentration. Thus, low NH3 breakthrough, 50 ppm or less, can still
cause increased air preheater fouling and corrosion.
3-32
-------
oo
i
CO
OJ
r ." . ..fl-
i " .."-
t ,11 „"-
t ." .."-
Mill
Wind box-, I
Closed | Fan
dampers~\ | shut down j
Isolated area
I
n
T 7 "*
y
A
/
0)
u
ex u
3 (U
1/1 1/1
I
f
•*
A1r preheater
I.D. fan
Collector
' Fan shut down
Closed-damper
'Stack
I.D. fan
Figure 3-7. On-stream washing of air preheater on a boiler with
dual air preheater arrangement (Reference 3-10).
-------
3.2.3.3 Environmental Considerations
Exxon and KVB have reported that emissions of carbon monoxide,
nitrates and sulfur oxides do not increase as a result of NH3 in the
flue gas. However, the effect of NH3 on particulate emissions in the
flue gas of coal-fired boilers has probably not been addressed in
sufficient detail. The following discussion present some of the reported
findings of NHL injection effects on particulate emissions.
The presence of NH, in the flue gas definitely affects the
performance of electrostatic precipitators (ESP's). Both adverse and
beneficial effects on the performance of the collector can occur depending
on coal characteristics, ESP design, and flue gas conditions. For
example, the depletion of SO- in the flue gas by NHL can adversely
affect the ESP efficiency. The presence of SO., reduces excessively high
particle electrical resistivity, an unfavorable property of dust entering
the collector. Figure 3-8 shows how SO, flue gas concentration affects
collection efficiency. Furthermore, (NH_),,S04 formed by reaction of S03,
NH3 and water vapor can also reduce electrostatic precipitation
collection efficiency (Reference 3-12).
NH3 has also been used as a flue gas additive when injected
downstream of the air preheater. Some initial work by Reese and Greco
(Reference 3-13) demonstrated that when flue gas temperatures entering the
electrostatic precipitator are below the acid dew point (which means the
presence of condensed H2S04), NH3 injection improves ESP efficiency
by neutralizing H^. NH3 neutralizes H2S04 by forming ammonium
sulfate. Figure 3-9 shows the negative effect of condensed H?SO. and
Figure 3-10 shows how NH3 injection increases ESP performance.
3-34
-------
o 75
o
10 20 30 40 50
SO- concentration (ppm)
Figure 3-8.
Effect of 503 conditioning on collection efficiency
of a coal-fired utility boiler (Reference 3-11).
Figure 3-9.
o
i.
-------
100
u
c
CD
o
80
CD
260
OJ
o
o
40
Recommended feed rate
for 90% efficiency
(15 ppm NH3)
,1.
_L
Feed rate required to
neutralize 30 ppm
HS0 (60 ppm NH)
5 10 15 20 25
H injection flow, SCFM
Figure 3-10. Collector efficiency as a function of ammonia feedrate
(Reference 3-13).
NH, can also improve ESP efficiency by increasing the
cohesiveness of the ash. Dismukes (Reference 3-14) discovered that
ammonia conditioning was effective in overcoming the loss of collected
flyash by rapping reentrainment, a problem which occurs with very low
resistivity ash (high-sulfur coal).
Dismukes also cited some deleterious effects of ammonia in the flue
gas entering the ESP. The first of these effects is the "space-charging"
effect or enhancement of sparking between well-aligned electrodes. This
effect was noted on a few coal-fired boilers when NH., was used to
condition the flue gas. Dismukes estimates that this problem can be
serious when burning low sulfur Western coals. Space-charging would then
occur with these coals unless the high flyash resistivity is lowered.
The second of these effects is the increase in fine particulate
emissions. Table 3-6 shows data on concentration of particles smaller
than 1.0 micron as measured by a diffusion battery. The Widows Creek
plant was one of three coal-fired plants whose emissions were measured for
3-36
-------
TABLE 3-6. CONCENTRATIONS OF SUBMICRON PARTICLES AT THE
WIDOWS CREEK PLANT (Reference 3-14)
Sampling
Location3
Inlet
Inlet
Inlet
Inlet
Outlet
Outlet
Injected NH3
Concn, ppm
0
11
0
23
0
20
Minimum size
Detected, ^m
0.005
0.014
0.050
0.005
0.014
0.050
0.005
0.014
0.050
0.005
0.014
0.050
0.005
0.014
0.005
0.014
0.050
Particle
Concn,
no. /cm
6.5 x 106
5.4 x 106
2.9 x 106
19.5 x 106
16.7 x 106
11.2 x 106
12.0 x 106
10.3 x 106
6.3 x 106
30.9 x 106
29.0 x 106
17.0 x 106
0.43 x 106
0.35 x 106
1.40 x 106
0.98 x 106
0.79 x 106
No. % Above
Minimum Size
100
85
45
100
85
57
100
89
52
100
94
55
100
81
100
70
56
aGas temperature, 132°C (270°F)
3-37
-------
particle size. Similar results appear from other sources. It is evident
that concentrations of submicron particles increased as NH3 was injected
prior to the precipitator. In these experiments, the increase in small
particle concentration did not vary substantially with increasing ammonia
concentration. Dismukes assumed that only the particulate formed between
SCL and ammonia was detected in addition to the flyash particulate
The increase in fine particle emission is also detected at the outlet of
the precipitator. It was also pointed out that as submicron particles
increased, NHL reduced S03 in the flue gas. This reduced the
concentration of sulfuric acid mist formed by condensation of the plume.
In summary, NH, in the flue gas may vary ESP performance in both
a beneficial and adverse way. Table 3-7 summarizes the effects described
above. The dominant effect is unclear. Further investigation on the
effect of NH3 breakthrough on ESP performance may be warranted.
3-38
-------
TABLE 3-7. EFFECTS OF NH3 EMISSIONS ON ESP PERFORMANCE AND
PARTICULATE EMISSIONS
Beneficial
Effect
Increased ESP
efficiency
Increased ESP
efficiency
Reduced fine
par ticu late
emissions
Mechanism
Neutralization of
condensed $03 by
reaction with NH3
Increased cohesive-
ness of flyash from
high sulfur coal
Acid mist elimina-
tion by depletion
of $03 in the flue
gas with NH3
Adverse
Effect
Reduced ESP
efficiency
Reduced ESP
efficiency
Increased
fine
particle
emissions
Mechanism
Increased flyash
resistivity by
depletion of gaseous
$03 reacting with
NH3 and formation of
(NH3)2S04
Space charge effect
when burning low
sulfur Western coals
unless particle
resistivity is
reduced
Reaction of NH3
with 503 and fine
particle formation
3-39
-------
REFERENCES FOR SECTION 3
3-1 Gregory, M. W., et a_L» "Determination of the Magnitude of S02,
NO, CO? and 02 Stratification in the Ducting of Fossil Fuel
Fired Power Plants," Exxon Research and Engineering Company, APCA
76-35.6, July 1976.
3-2 Varga, G., et al., "Applicability of the Thermal DeNOx Process to
Coal-Fired Utility Boilers," EPA-600/7-79-079, March 1979.
3-3. Salvesen, K. G., et^ a_L» "Emission Characterization of Stationary
NOX Sources," Acurex Final Draft Report TR-77-72, April 1978.
3-4. "Non-Catalytic NOX Reduction Process Applied to Large Utility
Boiler," Mitsubishi Heavy Industries, November 1977.
3-5. Varga, G., Unpublished data, Exxon Research and Engineering Co.,
August 1978.
3-6. "Schalit, L. M., et a]_._, "SAM/IA: A Rapid Screening Method for
Environmental Assessment of Fossil Energy Process Effluents,"
EPA-600/7-78-0315, February 1978.
3-7. Muzio, L. J., et^ a]_^, "Noncatalytic NO Removal with Ammonia," EPRI
Final Report FP-735, Research Project 835-1, April 1978.
3-8. Castaldini, C., "Boiler Design and Operating Variables Affecting
Uncontrolled Sulfur Emissions from Pulverized Coal-Fired Steam
Generators," Acurex Corporation, EPA 450/3-77-047, September 1977.
3-9. Dismukes, Edward B., "Conditioning of Fly Ash with Ammonia,"
Journal of the Air Pollution Control Association, Volume 25, No. 2,
February 1975.
3-10. Combustion Engineering "Soot Blowing and Water Washing Equipment &
Procedures," CE brochures supplied by Robert L. Hinton, June 1978.
3-11. Cook, R. E., "Sulfur Trioxide Conditioning," Journal of the Air
Pollution Control Association, Volume 25, No. 2, February 1975.
3-12 Brown, T. D. et a]^, "Modification of Electrostatic Precipitator
Performance by Use of Fly-Ash Conditioning Agents," ASME Winter
Meeting, ASME 78-WA/APC-3, December 1978.
3-13. Reese, J. T., and Greco, J., "Electrostatic Precipitation -
Experience," Mechanical Engineering, October 1968.
3-14. Dismukes, Edward B., "Conditioning of Fly Ash with Sulfur Trioxide
and Ammonia," Southern Research Institute, EPA-600/2-75-015
NTIS PB -247 231, August 1975.
3-40
-------
SECTION 4
COST ANALYSIS
The retrofit costs of NO controls for utility boilers depend on
/\
numerous site-specific factors such as boiler design configuration,
operational and installation problems, and the amount of design
engineering required prior to retrofit. For the Thermal DeNO Process,
A
cost estimates are further affected by variations in ammonia and carrier
gas cost and variations in temperature, flowrate, and NO profiles in the
convective section. Finally, control cost projections are dominated by
projections of ammonia supply and cost.
Recently, Exxon has reported that the total operating cost of the
Thermal DeNO Process can vary widely, depending on the level of
/\
control, between $1.75 and $8.61/kW-yr for retrofit application on utility
boilers (Reference 4-1). These costs compare with $0.26 to $3.04/kW-yr
for combustion modifications (Reference 4-2). Based on these costs, NH_
injection is, in most cases, more expensive than combustion
modifications. Therefore, the process becomes most attractive when used
to augment combustion modifications in order to reach stringent emission
levels.
Section 4.1 reviews the costs of the Thermal DeNO Process
A
reported by Exxon for the eight utility coal-fired boilers. These results
are then compared with costs developed by Acurex using a standardized cost
analysis procedure. Section 4.2 considers future cost projections and
4-1
-------
presents the impact of implementing the Thermal DeNOx Process on the
ammonia market, feedstock supplies, and their costs.
4.1 RECENT REPORTED COST ESTIMATES
The following section discusses Exxon's cost analysis of Thermal
DeNO for eight coal-fired boilers which represent the range of utility
boilers presently manufactured. The following assumptions were made by
Exxon in developing these costs (Reference 4-1):
• Fixed costs are Total Erected Costs (TEC), 2nd quarter, 1977,
U.S. Gulf coast. TEC was obtained by multiplying the installed
cost by a cost factor of 1.43. TEC includes contractor
engineering charges and fees, field labor overhead and burden.
Burden includes labor benefits such as health insurance,
holidays, etc.
t Reagent fixed costs include the NH, storage vessel,
vaporizer, and piping
• Carrier fixed costs include air compressors and piping
• Onsite fixed costs include two injector grids, instrumentation
and controls
• Operating costs are for the 100 percent load condition
• Ammonia operating cost is based on an NH., cost of $187/Mg
($170/ton)
t Carrier operating cost is $14.48/10,000 SCM ($0.41/10,000 SCF)
for an air compressor power requirement of 820.6 kW (1100 HP)
per 10,000 SCFM and electricity cost of $0.03/kW-hr.
4-2
-------
• Annual amortization of the capital cost is taken as 20 percent
of the initial investment which accounts for finance costs
depreciation and maintenance.
• The annual service factor is 80 percent
Figure 4-1 shows the cost of DeNO ($/MW-hr) for seven boilers as
A
a function of initial NO level in ppm for approximately 50 percent
A
reduction. For some units two data points are plotted for the same
initial NO level because of two different percent NO reductions.
x x
This figure indicates that DeNO cost is essentially independent of
A
boiler type even though flue gas temperature profiles and flow path
configurations cause differences in optimum DeNO locations among
/\
boilers. Additionally, the cost of DeNO increases with increasing
X
initial NO level for a given percent reduction.
A
Figure 4-2, which displays the cost of DeNO normalized by the
A
ppm reduction as a function of unit size, shows that except for the small
size boilers, the cost of DeNO decreases with unit size. The data
X
shown in Figure 4-2 include normalized costs for both trim NO reduction
A
cases as well as maximum NO reduction cases considered by Exxon. The
A
trim cases involve reducing emissions to the proposed NSPS standards of
285 ng/J (450 ppm) for bituminous and lignitic coals and 215 ng/J (375
ppm) for subbituminous coal. The maximum reduction cases, instead,
require NOV reduction to 72 ng/J (300 ppm) and 129 ng/J (225 ppm)
X
respectively.
Figure 4-3 presents the cost of DeNO normalized for the ppm
A
reduction as a function of the initial NO concentration. Clearly, as
A
the initial NO concentration is reduced, the cost per unit NO
x x
removed is higher. This is primarily because the DeNO efficiency
A
4-3
-------
•Fa
I
1.20 ~
1.00 -
0.80 -
*> 0.60 -
0.40 -
0.20 -
0 *
_
o
0
0 0
0 A 4>° 9
£3 0
1 1 1 1 1 1 1 1 1 1
Legend: Unit
Q130 MW
D333 MW
O400 MW
A 350 MW
£800 MW
0 330 MW
Q670 MW
100 200 300 400 500 600 700 800 900 1000
Initial NOX - ppm
Figure 4-1. Cost of NH3 injection for approximately 50 percent
reduction in NOX emissions.
-------
tn
0.6
0.5
< 0.4
0.3
60
100 200 300 400 500
Unit Size - MW
600
700
800
Figure 4-2. Normalized cost of NHg injection as a function of boiler size for
both trim and maximum NO reduction targets.
x\
-------
0.6
0.5
0.4
I 0.3
•»->
u
3
•o
e
~»
g 0.2
0.1
1 1
O
1 1
®
1 1
100 200 300 400 500 600 700 800 900 1000
Initial N0x - ppm
Figure 4-3. Normalized cost of NH3 injection as a function of initial NOX concentration.
-------
decreases with lower initial NO concentration. Some of the effects
A
noted may also be associated with unit size.
The total cost of the Thermal DeNO Process as reported by Exxon
X
was in the range of $1.75 to $6.1/kW-yr for all cases considered except
for lignite where the costs were $6.86 to $8.61/kW-yr. The following
sections highlight areas that should be addressed to represent more
realistic costs.
4.1.1 Analysis of Assumptions and Procedures
The costing methodology used by Exxon does not clearly consider
several costs which must be absorbed by the utility. Particularly,
indirect capital costs, which cannot be attributable to specific hardware
items, were not fully considered in this methodology. Most importantly,
engineering, design, startup and contingencies, and license fee were not
considered.
Allowance is not specifically made for engineering costs which must
be considered because the retrofit design of the injection system is very
site-specific. That is, the injection system must be developed to the
needs of each unit and the intended mode of operation. Although
preliminary estimates of applicability and NO reducing capability can
A
be provided by reviewing the original equipment design specifications,
accurate measurements should be made of flue gas temperatures and local
conditions. Then, individual process designs must be developed based on
such data. Accommodating flue gas temperature variations is important if
high NO reductions are to be achieved. The system must accommodate
A
flue gas temperature changes caused by load and operating variables and
allow for fluctuations across the reaction zone caused by nonuniformities
in flow and heat transfer. Money, must also be alloted for training of
4-7
-------
operating personnel. These costs have not been included in Exxon's
engineering costs.
The cost methodology should also include a construction contingency
to account for uncertainties in the cost estimation including unforeseen
escalation in cost terms, malfunctions, equipment design alterations, and
other similar sources. The Total Erected Cost multiplier of 1.43 included
in Exxon's installed cost estimates should account for field labor and
construction field expenses, and field facilities for construction,
services and utilities. However, this multiplier is probably not
sufficient to account for system startup and shakedown and performance
tests to ensure compliance with equipment performance guarantees. A
license fee for the use of the patented process has also not been included
in Exxon's reported costs. Information on these costs was not available
at the time this report was written.
The annual costs of the DeNO system is comprised of two
A
components: operation and maintenance charges with associated overhead
and capital charges. Exxon accounts for annual costs for ammonia, the
compressed air carrier and the electricity required to operate the
compressor. However, an additional part of the operational cost includes
maintenance of the DeNOx process facility, cost of additional operating
personnel to operate the facility, possible waste disposal from additional
boiler water-washing, additional chemical analyses for byproduct and
carryover, and support utilities for these functions. It is expected that
the annual 20 percent of the initial investment should cover the cost of
capital (depreciation taxes, insurance and interest) and some
maintenance. However, it most likely will not cover all the indirect
annual costs. Finally, administrative and plant overhead should be
4-8
-------
included in the DeNOx estimates to account for additional expenses such
as payroll, employee benefits, safety, and legal services.
These additional expenditures suggest a need for a systematic cost
analysis procedure to account for all of the costs that the utility must
face in installing a DeNO facility. Acurex has developed such a
A
procedure to include indirect costs such as engineering design and
supervision and license fees which must be borne by the utility.
Table 4-1 compares the cost items included in the Exxon and Acurex
procedures respectively. The following section briefly describes some of
the main features of this cost analysis procedure.
4.1.2 Acurex Cost Analysis Procedure
In an attempt to standardize costing for representative boiler
design/fuel classifications, a standard cost analysis procedure was
developed which attempts to account for all the costs a utility must bear
in installing any NO control facility (Reference 4-2). This
/\
standardization facilitates comparisons from boiler to boiler for both
conventional combustion modifications and Thermal DeNO . This cost
X
analysis uses accepted estimation procedures based on advice from boiler
manufacturers, utilities and equipment vendors.
To analyze control costs, regulated public utility economics were
used. This was based on (Reference 4-3).
• Revenue Requirement ~ (current operating disbursements +
depreciation + interest paid on debt) = taxable income
• Taxable income x effective tax rate = income taxes
• Revenue Requirement = current operating disbursements +
depreciation + income taxes + (fair return x rate base)
4-9
-------
TABLE 4-1. COMPARISON OF EXXON AND ACUREX COST ANALYSES PROCEDURES
Cost Factor
Exxon Cost Estimating Procedure
Acurex Cost Analysis Procedure
Initial investment
Direct annual
operating costs
Annual indirect
operating costs
Hardware requirements
Installation labor and supervision
Construction field expense
Contractor's fee
Construction facilities
Service facilities
Utility facilities
• Raw materials
• Utilities (electricity for
air compressors)
Capital charges for:'3
- Depreciation
- Insurance
- Replacements
- Cost of capital and taxes
Hardware requirements
Installation labor and supervision
Construction field expense
Contractor's fee
Construction facilities
Service facilities
Utility facilities
Engineering design and supervision
Engineering fee
Construction contingency
Initial charges (license costs)
Startup and performance tests
Raw materials
Utilities (electricity for air
compressors)
Additional operating personnel
Additional maintenance
Required analyses
Additional utilities
Capital charges for:
- Depreciation
- Insurance
- Replacements
- Cost of capital and taxes
Administrative overhead
Plant overhead
aCost multiplier: 1.43 times materials and labor = Total Erected Cost
^Annual capital charge is 20% of initial investment
-------
An annualized cost methodology was developed, based on the revenue
requirement approach, adapted from that used by the Tennessee Valley
Authority in evaluating for EPA and EPRI, the cost of powerplant projects
(References 4-4 and 4-5). This procedure has generally been accepted by
industry (References 4-6 to 4-8). The revenue requirement for NO
control is the incremental cost of operating the boiler under controlled
conditions from the base conditions. This incremental cost includes the
initial investment and the annual operating charges. After establishing
the revenue requirement for each year (n) that the control is operated, up
to N total years (where N is the remaining lifetime of the boiler), the
annual cost can be evaluated. Basic economics defines the Annualized
Revenue Requirements (ARR) as:
N
_ J
RR (n)
I
n=l
The first term is the capital recovery factor which discounts the money at
the annual cost of capital (effective interest rate). The effective
interest rate j is defined as
j = bi + (l-b)r
where b is the debt/equity ratio, i is the interest on borrowed money and
r is the rate of return to equity. The debt/equity ratio for the utility
industry has been fairly constant over the past few years with b = 0.5 as
a representative value, according to the Edison Electric Institute
(Reference 4-9). Interest rates i and r are given as 0.08 and 0.12
respectively for the year 1977 (References 4-4 and 4-5). The revenue
requirements for each year (n) are the sum of the direct and indirect
operating costs:
RR(n) = DOC + IOC(n)
4-11
-------
Table 4-2 describes the components of the direct and indirect
operating costs and the appropriate equations or estimating procedures for
calculating all of these cost factors. Lim et _a_K give a more detailed
description of this cost analysis procedure (Reference 4-2).
4.1.3 Control Costs Using Cost Analysis Procedure
To allow for comparison between Exxon's boiler cost estimates and
the estimates derived from the cost analysis procedure, the same boiler
designs and input conditions were assumed. It should be noted here that
the actual hardware used for injecting the ammonia into the boiler was
considered proprietary by Exxon. Thus, the cost of the original hardware
could not be examined. This has limited our evaluation to indirect
investment and annual costs.
The initial investment could vary significantly if there were
problems such as poor access to the flue gas flow path, severe
stratification or severe load following requirements and startup
difficulties.
Table 4-3 lists the boiler design, NO reductions required,
A
total hardware and labor costs, and raw materials needed for this cost
analysis. Again, the maximum target was assumed with the assistance of
combustion modifications (Exxon Case No. 4). Although the Exxon estimates
of total hardware and labor for DeNOx installation were used in our
analysis, the Total Erected Costs were not determined by multiplying
material and labor by 1.43 as in the Exxon analysis, but rather, by
considering each cost component separately (such as construction field
expense and contractor fees). Additional initial costs considered
separately were engineering design and supervision and fee, initial
startup and performance testing and license fees. Standard estimating
4-12
-------
TABLE 4-2. COST ANALYSIS CALCULATION ALGORITHM*
Cost Factor
Calculation Equation
Reference
co
Initial Investment, II
Engineering Design & Supervision, OS
Engineering Fee, EFEE
Hardware, TM
Installation Labor & Supervision, TL
Construction Facilities, CF
Service Facilities, SF
Utilities Facilities, UF
Construction Field Expense, CFE
Contractor's Fee, CON
Construction Contingency, CTN
Initial Charges. 1C
Startup Costs, SC
Indirect Operating Costs, IOC(n)
Capital Charge. CC(n)
Depreciation, D
Insurance, IN
Replacements, RE
Cost of Capital and Taxes, CCT(n)
II « (DI + IND + SC + 1C), as per below
DS estimated from preliminary design work
EFEE * 0.08 x DS
TM from preliminary design work
TL from preliminary design work and engineering estimate
CF « 0.05 x (TL + TM + UF + SF)
SF » 0.05 x (TL + TM)
UF =• 0.03 x (TL + TM)
CFE =• 0.13 x (TL + TM + CF + SF + UF) = 0.13 x 01
CON <* 0.07 x DI
CTN = 0.11 x DI
1C from input data (e.g., licensing fees, usually none)
SC - 0.10 x (DI + DS * EFEE + CFE + CON + CTN)
- 0.10 x (01 + IND)
IOC(n) - CC(n) + CCLOST(n) + OH
CC(n) • D + IN + RE + CCT(n)
D - II/N
IN - 0.005 x II
RE = 0.004 x II
CCT(n). ' [ib + r(l - b) + ^-^ (1 - b)r] . ODB(n)
where t * effective tax rate
- s * (l-s)f
and s * state tax rate
f - federal tax rate
and OOB - II - (n-l)D
Lira et al. (Reference 4-2)
Engineering Estimate
Vendor quotes
Lim et al. (Reference 4-2)
TVA (References 4-4, 4-5)
TVA (References 4-4, 4-5)
TVA (References 4-4, 4-5)
TVA (References 4-4, 4-5)
TVA (References 4-4, 4-5)
TVA (References 4-4, 4-5)
LIM et al_ (Reference 4-2)
TVA (References 4-4, 4-5)
Straight line depreciation
TVA (References 4-4, 4-5)
Lim et tf_._ (Reference 4-2)
aA glossary of terms appears in Appendix A.
-------
TABLE 4-2. Concluded
Cost Factor
Calculation Equation
Reference
-pi
I
Capital charges of Lost Capacity,
CCLOST (n)
Overhead
Administrative overhead, OHA
Plant overhead, OHP
Direct Operating Costs, OOC
Fuel Penalty, AF
Fuel Credit. FC
Raw materials, RM
Conversions Costs
Additional operating personnel,
Additional utilities, UC
Additional maintenance, H
Required analyses, A
Annual royalties, AROY
Purchased Power, PP
OLS
Calculated analogously to CC(n), only use
/HO x 55ATEJ 1n p1ace of II
where 110 = Initial investment of boiler
DRATE « Power derate with controls, 1f necessary
KW • Power rating of boiler before control
OHA » 0.10 x OLS
OHP » 0.20 x (OLS + UC + M
A), as indicated below
AF = HYR x HRATE x (KW - DRATE) x FCOST
x FPEN
where HYR = Annual operating hours
FC - HYR x HRATE x DRATE x FCOST
RM from input data
where HRATE * Heat rate of boiler
FCOST » Fuel cost
OLS from engineering estimate
UC from engineering estimate
M = 0.05 x TLM
A from engineering estimate
AROY from Input data
PP « ORATE x HYR x PPR
where PPR • purchased power rate
Lim e_t al. (Reference 4-2)
TVA (References 4-4, 4-5)
TVA (References 4-4, 4-5)
Engineering estimate
Engineering estimate
Engineering estimate
TVA (References 4-4, 4-5)
Reference 4-10
Reference 4-10
Engineering estimate
Annual!zed Cost to Control, ARRU
ARRU
. JM *
j)N-l
DOC * IQC(n)
n=l
1
(KW - DRATE)
Lim et al. (Reference 4-2)
-------
TABLE 4-3. INPUT DATA TO COST ANALYSIS PROCEDURE (EXXON CASE NO. 4)
Unit CM
B&W 130 MW
subbituminous
B&U 333 MW
bituminous
B&W 400 MW
lignite
CE 350 MW
bituminous
CE 800 MW
subbituminous
FW 330 MW
bituminous
FW 670 MW
subbituminous
RS 350 MW
bituminous
Controlled NO Final NOX
Level (PPM) Level (PPM)
300
420
900
450
375
510
420
420
225
300
300
300
225
300
225
300
Flue Ga<;
Rate (Mg/hr)
579
1,353
2.294
1,459
3,941
1,376
3,716
1,792
NH3 Rate Carrier Rate NHi Cost Carrier Cost Hardware and
(Mg/yr)a (MSCM/yr) ($7yr)b ($/yr)c Labor Cost
452 50.25
1,432 117.48
84,490
267,750
TARGET CANNOT BE
1.736 126.64
4,703 342.17
2.900 119.49
6,319 332.62
1,929 155.56
324.570
879,410
542,402
1,181.670
360,510
72,750
170,100
MET
183,360
495,419
173.007
467,113
225.238
778.300
1,128,000
1,171,400
1,715,400
1.190.200
1.690,900
1.206,300
a80% load factor.
b$187/ton
C$14.48/10,000 SCM
-------
procedure suggests a construction contingency of up to 30 percent of the
direct investment costs (Reference 4-11). A conservative estimate of
20 percent for construction contingency was used for the Acurex cost
analysis. It is reasonable to include this cost to allow for
uncertainties such as escalation in cost items, equipment design
alterations, and other unforeseen costs.
The direct operating cost for ammonia was again costed as $187/Mg
($170/ton) and carrier cost at $14.48/10,000 SCM ($0.41/10,000 SCF).
However, additional direct operating cost components such as maintenance,
operating personnel and royalties were considered separately in the
costing procedure. Capital charges were based on a straight annual charge
of 20 percent of the initial investment, but rather, calculated as follows:
Taxable Income = (Return on Equity) + (Tax Deductable Interest on
Borrowed Money) + (Tax Deductable Depreciation)
+ (Money for Taxes).
Where the cost of capital and taxes in year n is given by:
CCT(n) = ib + r (1-b) + -— (l-b)r ODB(n)
and should be annualized as
ACCT = N
^i)N-l nti
-------
For further discussion of these procedures and their derivation,
see Reference 4-2.
Finally, indirect operating costs for plant and administrative
overhead were included to account for expenses such as payroll, benefits,
and safety programs. Appendix B lists the cost input data for the eight
coal-fired boiler types for the case of maximum reduction with combustion
modifications. These costs result from the Exxon inputs for hardware,
labor, and raw materials shown in Table 4-3 and the assumptions made in
the cost analysis procedure of Section 4.1.2. A glossary of terms used in
the procedure are given in Appendix A. Tables 4-4 to 4-10 list the
annualized control costs for the eight coal-fired boiler types using the
cost inputs listed in Appendix B and the cost procedure. It is assumed
that retrofit applications are completed during normal outage periods so
that additional downtime is not required.
For control cost projections purposes, the results shown are only
valid at best to two significant figures. These control costs shown in
Tables 4-4 to 4-10 do not include the cost of annual royalties and cost of
combustion modifications. Annual royalties are not known and thus were
not included. Table 4-11 lists the total cost of the Thermal DeNO
A
Process including the cost of combustion modifications.
4.1.4 Comparison of Cost Results
A comparison was made between the retrofit costs obtained by Exxon
and costs obtained by Acurex for the deep NOV reduction case. Table
/\
4-12 lists the direct and indirect operating costs for all the coal-fired
boilers considered except for the lignite-fired cyclone for which deep
reductions could not be reached. As indicated by the data in the cost
column the contingency costs considered by Acurex increased Exxon's
4-17
-------
TABLE 4-4. COST BREAKDOWN OF NH3 INJECTION ON 130 MW
FRONT WALL COAL-FIRED BOILER
MAXIMUM CONTINUOUS RATING (HU) : 130.
TYPICAL BASELINE NOX EMISSION (PPM AT 3« 02) : 300.
TYPICAL CONTROLLED NOX EMISSION (PPfl AT 3S 02) : 225.
DERATE REOUlPEn (MW) t NONE
FUEL PENALTY (PERCENT) : .000(1
ANNUALIZEO LOST CAPACITY CAPITAL CHARGE •S/KW-YR) : NONE
ANNUALIZED PURCHASED POWER PENALTY (t/KW-YR) : NONE
INITIAL INVESTMENT (*/KW) : 10.H«t
ANNUALTZEO INDIRECT OPERATING COST (S/KW-YR) : 1.78H
ANNUALIZEO DIRECT OPERATING COST (*/KW-YR) : 1.573
ANNUALIZED COST TO CONTROL (S/KU-YR) : 3.357
INITIAL INVESTMENT (S)
ENGINEERING DESIGN « SUPERVISION
ENGINEERING FEE
HARDWARE
INSTALLATION LABOR s SUPERVISION
CONSTRUCTION FACILITIES
SERVICE FACILITIES
UTILITIES FACILITIES
CONSTRUCTION FIELD EXPENSE
CONTRACTORS FEE
CONSTRUCTION CONTINGENCY
INITIAL CHARGES
STARTUP COSTS
TOTAL INITIAL INVESTMENT
39717.
3177.
77B300.
0.
K202B.
38915.
233"»9.
11<»737.
61761.
132369.
0.
123U39.
1357633.
ANhUALlZFD OPERATING COST (S/YR)
INDIRECT OPERATING COSTS
CAPITAL CHARGES
DEPRECIATION
INSURANCE
REPLACEMENT COSTS
COST OF CAPITAL & TAXES
CAPITAL CHARGES OF LOST CAPACITY (IF DERATE)
DEPRECIATION
INSURANCE
REPLACEMENT COSTS
COST OF CAPITAL S. TAXES
OVERHEAD
ADMINISTRATIVE OVERHEAD
PLANT OVERHEAD
DIRECT OPERATING COSTS
FUEL COST PENALTY
FUEL CRF.UIT (FOR UNUSED FUEL IF DERATE)
RAW MATERIALS
CONVEHSIOK' COSTS
ADDITIONAL OPERATING PERSONNEL
ADDITIONAL UTILITIES REQUIREMENTS
ADDITIONAL MAINTENANCE
REUIJItiFD ANALYSES
ANNUAL ROYALTIES
PURCHASED POWER (IF DERATE)
TOTAL ANNUALIZED OPERATING COSTS
ANNUALT7EO COST To CONTROL (S/KW-YR)
5*313.
67S9.
5431.
155062.
B33.
9M9.
0.
0. )
1572MO.
0330.
0.
36915.
0.
0.
0.
43M63.
3.36
4-18
-------
TABLE 4-5. COST BREAKDOWN OF NH3 INJECTION ON 333 MW
HORIZONTALLY OPPOSED COAL-FIRED BOILER
MAXIMUM CONTINUOUS RATING (MW) : 333.
TYPICAL BASELINE NOX EMISSION (PPM AT 3S 02) : i»20.
TYPICAL CONTROLLED NOX EMISSION (PPM AT 3* 02) : 300.
DERATE REQUIRED (MW) : NONE
FUEL PENALTY (PERCENT) : .0000
ANNUALIZED LOST CAPACITY CAPITAL CHARGE (t/KW-YR) : NONE
ANNUALIZEO PURCHASED POWER PENALTY (S/KW-YR) ! NONE
INITIAL INVLSTHENT (*/KW) : 5.910
AMNUALIZEO INDIRECT OPERATING COST (S/KW-YR) : 1.006
ANNUALIZEO DIRECT OPERATING COST (S/KU-YR) : 1.509
ANNUALIZEO COST TO CONTROL (S/KW-YR) : 2.515
INITIAL INVESTMENT (S)
ENGINEERING DESIGN t SUPERVISION
ENGINEERING FEE
HARPWARE
INSTALLATION LABOR I SUPERVISION
CONSTHUCTION FACILITIES
SERVICE FACILITIES
UTILITIES FACILITIES
CONSTRUCTION FIELD EXPENSE
CONTRACTORS FEE
CONSTRUCTION CONTINGENCY
INITIAL CHARGES
STARTUP COSTS
TOTAL INITIAL INVESTMENT
«"»
57562.
4605.
1126000.
0.
60912.
56>*00.
33840.
166290.
89541.
191873.
0>
176902.
1967921.
ANNUALIZED OPERATING COST (S/YK)
INDIRECT OPERATING COSTS
CAPITAL CHARGES
DEPRECIATION
INSURANCE
REPLACFMENT COSTS
COST OF CAPITAL 4 TAXES
CAPITAL CHARGES OF LOST CAPACITY (IF DERATE)
DEPRECIATION
INSURANCE
REPLACEMENT COSTS
COST OF CAPITAL S TAXES
OVERHEAD
ADMINISTRATIVE OVERHEAD
PLANT OVERHEAD
DIRECT OPERATING COSTS
76717.
9840.
7872.
22*»733.
0.
0.
0.
0.
833.
12946.
FUEL COST PENALTY
FUEL CREDIT (FOR UNUSED FUEL IF DERATE)
RAW MATERIALS
CONVERSION COSTS
ADDITIONAL OPERATING PERSONNEL
ADDITIONAL UTILITIES REQUIREMENTS
ADDITIONAL MAINTENANCE
REOUIREU ANALYSES
ANNUAL ROYALTIES
PURCHASED POUEH (IF DERATE)
TOTAL Af>'NUALIZED OPERATING COSTS
ANNUALIZEO COST TO CONTROL (S/KU-YR)
0-
( 0.)
437850.
8330.
0.
56400.
0.
0.
0.
637521.
2.52
4-19
-------
TARLE 4-6 COST BREAKDOWN OF NH3
' TANGENTIAL COAL-FIRED BOILER
---- .,
MAXIMUf CONTINUOUS RATING (MW) : 350.
TYPICAL BASELINE NOX EMISSION (PPM AT 3S 02) :
TYPICAL CONTROLLED NOX EMISSION (PPM AT 3K 02) :
450.
300.
DERATE REOUIREO (HWI : NONE
FUEL PENALTY (PERCENT) : .0000
ANNUALIZED LOST CAPACITY CAPITAL CHARGE (S/KW-YR) : NONE
ANNUALIZED PURCHASED POWER PENALTY Il/KW-YR) : NONE
INITIAL INVESTrENT (S/KW) : b.839
ANNUALIZED INDIRECT OPERATING COST (*/KH-YH) : .9935
ANNUALIZED DIRECT OPERATING COST (l/KW-YR) : .1.612
ANNUALIZED COST TO CONTROL (*/KW-YR) : 2.636
INITIAL INVESTMENT (S)
ENGINEERING DESIGN i SUPERVISION
ENGINEERING FEE
HARDWARE
INSTALLATION LABOR 4 SUPERVISION
CONSTRUCTION FACILITIES
SERVICE FACILITIES
UTILITIES FACILITIES
CONSTRUCTION FIELD EXPENSE
CONTK&CTORS FEE
CONSTRUCTION CONTINGENCY
INITIAL CHARGES
STARTUP COSTS
TOTAL INITIAL INVESTMENT
59777.
4762.
U7i4on.
0.
63256.
58570.
35142.
172686.
92986.
199255.
0.
1B5785.
2043640.
ANNUALIZED OPERATING COST (S/YR)
INDIRECT OPERATING COSTS
CAPITAL CHARGES
DEPRECIATION
INSURANCE
REPLACEMENT COSTS
COST OF CAPITAL & TAXES
CAPITAL CHARGES OF LOST CAPACITY IIF DERATE)
DEPRECIATION
REPLACEMENT COSTS
COST OF CAPITAL X TAXES
OVERHEAD
ADMINISTRATIVE OVERHEAD
PLANT OVERHEAD
DIRECT OPERATING COSTS
FUEL COST PENALTY
FUEL CREDIT (FOR UNUSED FUEL IF DERATE)
RAM MATERIALS
CONVERSION COSTS
ADDITIONAL OPERATING PERSONNEL
ADDITIONAL UTILITIES REQUIREMENTS
ADDITIONAL MAINTENANCE
REQUIRED ANALYSES
ANNIJAL ROYALTIES
PURCHASED POWER (IF DERATE)
TOTAL ANNUALIZED OPERATING COSTS
ANNUALIZED COST TO CONTROL (S/KW-YR)
81746.
10218.
8175.
233380.
833.
13360.
0.
( 0.)
507930.
8330.
0.
58570.
0.
0.
0.
922561.
" 2^64
4-20
-------
TABLE 4-7. COST BREAKDOWN OF NH3 INJECTION ON 800 MW
TANGENTIAL COAL-FIRED BOILER
MAXIMUM CONTINUOUS RATING (MM) ! 800.
TYPICAL BASELINE NOX EMISSION (PPM AT 3» 021 I 375.
TYPICAL CONTROLLED NOX EMISSION (PPM AT 311 02) ! 225.
DERATE REQUIRED (MU) : NONE
FUEL PENALTY (PERCENT) : .0000
ANNUALIZED LOST CAPACITY CAPITAL CHARGE (S/KW-YR) : NONE
ANNUALIZED PURCHASED POWER PENALTY (S/KW-YR) : NONE
INITIAL INVESTMENT (S/KW) : 3.711
ANNUALIZED INDIKECT OPERATING COST (S/KW-YR) : .6351
ANNUALIZED DIRECT OPERATING COST (S/KW-YR) : 1.836
ANNUALIZED COST TO CONTROL (S/KW-YR) I 2."»71
ANNUALIZED OPERATING COST (S/YR)
INDIRECT OPERATING COSTS
CAPITAL CHARGES
DEPRECIATION 119708.
INSURANCE 1M96<«.
REPLACEMENT COSTS 11971.
COST OF CAPITAL < TAXES SH1762.
CAPITAL CHARGES OF LOST CAPACITY CIF DERATE.)
DEPRECIATION ".
INSURANCE °>
REPLACEMENT COSTS °«
COST OF CAPITAL I TAXES 0.
OVERHEAD
ADMINISTRATIVE OVERHEAD 655.
PLANT OVERHEAD 16820.
DIRECT OPERATING COSTS
FUEL COST PENALTT 0.
FUEL CREDIT (FOR UNUSED FUEL IF DERATE) ( 0.)
RAW MATERIALS 1374629.
CONVERSION COSTS
ADDITIONAL OPERATING PERSONNEL 6330.
ADDITIONAL UTILITIES REBUIREHENTS 0.
ADDITIONAL MAINTENANCE 65770.
REQUIRED ANALYSES 0.
ANNUAL ROYALTIES 0.
PURCHASED POWER I IF DERATE) 0.
DATE
INITIAL INVESTMENT cs>
ENGINEERING DESIGN I SUPERVISION
ENGINEERING FEE
HARDWARE
INSTALLATION LABOR X SUPERVISION
CONSTRUCTION FACILITIES
SERVICE FACILITIES
UTILITIES FACILITIES
CONSTRUCTION FIELD EXPENSE
CONTRACTORS FEE
CONSTRUCTION CONTINGENCY
INITIAL CHARGES
STARTUP COSTS
TOTAL INITIAL INVESTMENT
67537.
7003.
1715400.
0.
92632.
65770.
51*62.
252881.
136166.
291790.
0.
272065.
2992710.
TOTAL ANNUALIZED OPERATING COSTS 1976967.
ANNUALIZED COST TO CONTROL (S/KU-YR) "" """"""" 2<
4-21
-------
TABLE 4-8. COST BREAKDOWN OF NH3 INJECTION ON 330 MW
FRONT WALL COAL-FIRED BOILER
MAXIMUM CONTINUOUS RATING : NONE
FUEL PENALTY (PERCENT) : .0000
AMNUALTZED LOST CAPACITY CAPITAL CHARGE (*/KH-YR) : NONE
ANNUALIZED PURCHASED POWER PENALTY IS/KW-YK) : NONE
INITIAL INVESTMENT I*/KW) : 6.292
ANNUALIZEO INDIRECT OPERATING COST (*/KW-YR) : 1.071
ANN'UALIZED DIRECT OPERATING COST (S/KW-YR) : 2.373
AIJNUAHZED COST TO CONTROL (S/KW-YR) : 3.111
INITIAL INVESTMENT (S)
{.NGINCERU'G DESIGN g SUPERVISION
ENGINEER ING FEE
HARDWARE
INSTALLATION LABOR * SUPERVISION
CONSTRUCTION FACILITIES
SERVICE FACILITIES
UTIlITIES FACILITIES
CONSTRUC'ION FIELD EXPENSE
CONTRACTORS FEE
CONSTRUCTION CONTINGENCY
INITIAL CHARGES
STARTUP COSTS
TOTAL INITIAL INVESTMENT
ANNUALIZED OPERATING COST (S/YR)
INDIRECT OPERATING COSTS
CAPITAL CHARGES
DEPRECIATION
INSURANCE
REPLACEMENT COSTS
COST OF CAPITAL J TAXES
CAPITAL CHARGES OF LOST CAPACITY (IF DERATE)
DEPRECIATION
INSURANCE
REPLACEMENT COSTS
COST OF CAPITAL & TAXES
OVERHEAT
ADMINISTRATIVE OVERHEAD
PLANT OVERHEAD
DIRECT OPERATING COSTS
FUEL COST PENALTY
FUEL CREDIT (FOR UNUSED FUEL IF DERATE)
RAW MATERIALS
CONVERSION COSTS
ADDITIONAL OPERATING PERSONNEL
ADDITIONAL UTILITIES REQUIREMENTS
ADDITIONAL MAINTENANCE
REOUIKfD ANALYSIS
ANNUAL ROYALTIES
PURCHASED POWER (IF DERATE)
TOTAL ANNUALIZED
60736.
1659.
1190200.
0.
61271.
59510.
35706.
175159.
91178.
202153.
0.
188767.
2076139.
83058.
10362.
6306.
237126.
833.
13568-.
0.
0.)
715109.
SS30.
0.
59510.
0.
0.
0.
1136521.
3.11
ANNUALIZED COST To CONTROL (*/KW-YR)
4-22
-------
TABLE 4-9.
COST BREAKDOWN OF NHs INJECTION ON 670 MW
HORIZONTALLY OPPOSED COAL-FIRED BOILER
CONTINUOUS RATING I 1*20.
TYPICAL CONTROLLED NOX EMISSION (PPM AT 3S 02> : 225.
DERATE REQUIRED (MW) : NONE
FUEL PENALTY IPERCENT) : .0000
ANNUALIZED LOST CAPACITY CAPITAL CHARGE (i/Kk-YR) : NONE
ANNUALIZED PURCHASED POWER PENALTY (t/KU-YR) : NONE
INITIAL INVESTMENT U/KWI : «.to3
ANNUAL T7ED HDIRECT OPERATING COST (S/KW-YR) : .7<»75
ANMUALIZEO DIRECT OPERATING COST (S/KW-YRI :. 2.599
ANNUALIZED COST TO CONTROL <*/KN-YR> : 3.317
INITIAL INVESTMENT (i)
ENGINEERING DESIGN & SUPERVISION
ENGINEERING FEE
HARDWARE
INSTALLATION LABOR R SUPERVISION
CONSTRUCTION FACILITIES
SERVICE FACILITIES
UTILITIES FACILITIES
CONSTRUCTION FIELD EXPENSE
CONTRACTORS FEE
CONSTRUCTION CONTINGENCY
INITIAL CHARGES
STARTUP COSTS
TOTAL INITIAL INVESTMENT
ANNUALIZED OPERATING COST <*/YH>
INDIRECT OPERATING COSTS
CAPITAL CHAIibES
DEPRECIATION
INSURANCE
REPLACrMEHT COSTS
COST OF CAPITAL I TAXES
CAPITAL CHftHGES OF LOST CAPACITY (IF DERATE!
DEPRECIATION
INSURANCE
REPLACEMENT COSTS
COST OF CAPITAL & TAXES
OVERHEAD
ADMINISTRATIVE OVERHEAD
PLANT OVERHEAD
DIRECT OPERATING COSTS
FUEL COST PENALTY
FULL CREUIT (FOR UNUSED FUEL IF DERATE)
RAW MATERIALS
CONVERSION COSTS
AOniTIrhAL OPERATING PERSOIvNrl
ADDITIONAL UTILITIES REQUIREMENTS
ADDITIONAL MAINTENANCE
REQUIRED ANALYSES
ANNUAL ROYALTIES
PURCHASED POWER (IF DERATE)
TOTAL ANNUALIZED OPERATING COSTS
ANNUALIZEO COST TO CONTROL (*/KW-YR)
66267.
6903.
1690900.
0.
91309.
B»750.
11600.
3366S1.
0.
0.
0.
0.
633.
16575.
0.
( 0.)
16H6763.
6330.
0.
6
-------
TABLE-4-10. COST BREAKDOWN OF NHs INJECTION ON 350 MW
TURBO COAL-FIRED BOILER
MAXIMUM CONTINUOUS RATING (MU) : 350.
TYPICAL BASELINE NOX EMISSION (PPK AT 3* 02) : *Sl>,
TYPICAL CONTROLLED NOX EMISSION (PPM AT 3* 02) : 300.
DERATE RECUIRED (MH> : NONE
FUEL PENALTY (PERCENT) : .0000
ANNLALJZED LOST CAPACITY CAPITAL CHARGE (*/KW-YK) : NONE
ANNUALIZED PURCHASED POWER PENALTY (S/KW-YR) : NONE
IMT1AL INVESTMENT (J/KW) : 6.013
ANNUALIZED INDIRECT OPERATING COST ($/KU-YR> : 1.023
ANNUALIZED DIRECT OPERATING COST (*/KW-YH) : 1.670
ANNUALIZED COST TO CONTROL (1/KU-YR) : «*.693
INITIAL INVESTMENT ($)
ENGINEERING. DFSIGTJ g SUPERVISION
ENGINEERING FEE
HARDWARE
INSTALLATION LAROH f. SUPERVISION
CONSTRUCT IOU FACILITIES
SERVICE FACILITIES
UTILITIES FACILITIES
CONSTRUCTION FIELD EXPENSE
CONTRACTORS FEE
CONSTRUCTION CONTINGENCY
INITIAL CHAPGES
STAHTUP COSTS
TOTAL INITIAL INVESTMENT
ANNUALIZED'OPERATING COST ~(¥/YR")
61557.
1925.
1206300.
0.
651tO.
60315.
36189.
177833.
95756.
205192.
0.
191321.
210MS27.
OPERATING COSTS
CAPITAL CHARGES
DEPRECIATION 8H1B1.
INSURANCE 10523.
REPLACEMENT COSTS 8M1B.
COST OF CAPITAL & TAXES 2t0333.
CAPITAL CHARGES OF LOST CAPACITY UF DERATE)
DEPRECIATION "•
INSUR/^^CE 0.
REPLACEMENT COSTS 0.
COST OF CAPITAL * TAXES 0.
OVERHEAD
AOMIMSTPATIVE OVERHEAD 633.
PLANT OVERHEAD 13729.
DIRECT OPERATINu COSTS
FUEL COST PENALTY 0.
FUEl CREDIT (FOR UNUSEP FUEL IF DERATE) ( 0.)
RAW MKTFRIALS 565718.
CONVERSION COSTS
ADDITIONAL OPERATING PERSONNEL 6330.
ADDITIONAL UTILITIES RE&UIREhLNTS 0.
ADDITIONAL MAINTENANCE 60315.
REQUIRED ANALYSES 0.
ANNUAL ROYALTIES 0.
PURCHASED PC1WER I IF DERATE) 0.
TOTAL ANNUALIZED OPERATING COSTS 1012110.
ANNUALTZED COST TO CONTROL (t/KW-YR) 2.69
4-24
-------
TABLE 4-11. TOTAL COST OF THE THERMAL DeNOx PROCESS FROM COST
ANALYSIS PROCEDURE — CASE NO. 4
IN3
tn
alnformation from Reference 4-2
b80 percent load factor
CLNB = low NOX burners
dOFA = overfire air injection
Unit
B&W 130 MW
B&W 333 mw
B&W 400 MW
CE 350 MW
CE 800 MW
FW 330 MW
FW 670 MW
RS 350 MW
Thermal DeNOx Cost
W/0 License Fee
$/kw-yr
3.36
2.52
2.64
2.47
3.44
3.35
2.89
Combustion3
Modification
LNBC
LNB
Cost of Combustion3
Modification
$/kw-yr
0.40
0.40
Total Cost
$/kw-yr mills/kw-hrb
3.76 0.53
2.92 0.42
Target not achievable — this unit excluded
OFAd
OFA
LNB
LNB
OFA
0.53
0.53
0.40
0.40
0.69
3.17 0.45
3.00 0.43
3.84 0.55
3.75 0.54
3.58 0.52
-------
TABLE 4-12. THERMAL DeNOx COST COMPARISON FOR THE MAXIMUM NOX
REDUCTION -- CASE NO. 4
-p.
I
ro
Unit
B&W 130 MW
B&W 333 MW
CE 350 MW
CE 800 MW
FW 300 MW
FW 670 MW
RS 350 MW
Average
Exxon Cost
mil Is/kw-hr
Direct
Operating
0.17
0.18
0.20
0.25
0.30
0.35
0.24
0.24
Indirect
Operating
0.24
0.14
0.14
0.09
0.14
0.10
0.14
0.14
Acurex Cost
mills/kw-hr
Direct
Operating
0.22
0.22
0.23
0.26
0.34
0.37
0.27
0.27
Indirect
Operating
0.25
0.14
0.14
0.09
0.15
0.11
0.15
0.15
Acurex Cost
of Combustion
Modification
mills/kw-hr
0.06
0.06
0.08
0.08
0.06
0.06
0.10
0.07
Total Cost
mills/kw-hr
Exxon
0.47
0.38
0.42
0.42
0.50
0.51
0.48
0.45
Acurex
0.53
0.42
0.45
0.43
0.55
0.54
0.52
0.49
Percent
Increase
13
11
7
2
10
6
8
9
-------
estimated cost by approximately 9 percent on the average. The largest
differences are evidenced in the direct operating cost. This increase is
specifically caused by consideration of such factors as:
• Additional maintenance
• Additional operating personnel
• Required analysis
• Plant and administrative overhead.
These factors increased the direct operating cost estimated by
Acurex by approximately 13 percent on the average. Annual royalties
should also be added to these costs; thus the total operating cost would
further increase above the level reported here. The average indirect
operating cost estimated here is only approximately 7 percent larger than
the cost calculated by Exxon. This increase is primarily due to startup
and performance costs.
In general, the total operating cost (direct and indirect) reported
here is probably more representative of the actual cost incurred by
utilities in retrofitting Thermal DeNO on coal-fired utility boilers.
/\
The data in Table 4-12 also indicates that the cost of NhL injection
ranges from 80 to 90 percent of the total combined control cost.
Combustion modifications account for the remaining 10 to 20 percent.
4.2 IMPACT OF FULL SCALE THERMAL DeNOx IMPLEMENTATION ON AMMONIA
COST AND SUPPLY
The cost of the DeNO Process is highly sensitive to the cost of
A
ammonia. This section evaluates factors which may perturb the cost of
ammonia and considers the impact on national fuel supply.
Approximately 64 percent of the current world ammonia is being
produced from natural gas, 13 percent from naptha, 12 percent from coal or
4-27
-------
coke, with the remaining 11 percent divided among other feedstock
sources. Typically, 75 percent of ammonia is used for fertilizer and
feeds, 9 percent for fiber and plastic intermediates, 4 percent for
explosives and 11 percent for other miscellaneous industries
(Reference 4-12).
Production of synthetic ammonia in the United States during the
year ending 30 June 1976 was estimated at 15.9 x 10 Mg (17.5 million
tons) (Reference 4-13). However, capacity additions during the past 2
years should raise the domestic capacity to almost 17.3 x 10 Mg (19.0
million tons) annually. This increase is largely being brought about by
the construction of plants in the range of 900 to 1360 Mg/day (1000 to
1500 tons/day) which use a light hydrocarbon feedstock with the partial
oxidation process. U.S. ammonia demand in 1980 is estimated to reach 19.4
x 10 Mg (21.3 million tons). Ammonia for agriculture will be
responsible for 70 percent of that demand (Reference 4-14).
In 1976 ammonia was available at about $132/Mg ($129/ton). However,
that ammonia price may vary by as much as 50 percent by region. This cost
is lower than the current list price of $187/Mg ($170/ton) and well below
the price of up to $290/Mg ($264/ton) in 1975. Figure 4-4 shows that the
historical price of ammonia has been highly unstable primarily because of
governing supply and demand and other influences such as the cost of
feedstock fuels.
4.2.1 Methods for Producing Ammonia
Based on raw material availability, the choice of a process design
is between catalytic steam reforming of light hydrocarbons and partial
oxidation of heavy hydrocarbons. In exceptional cases, where hydrogen
4-28
-------
300
CT)
200
i
ro
vo
(O
c
o
10
3
O
T3
100
1971
1972
1973
1974
1975
Year
1976
1977
1978
Figure 4-4. Historical trends of ammonia prices.
-------
rich gas is available, cryogenic processing or some alternate process for
purifying hydrogen is used.
Catalytic Steam Reforming
This process consists of desulfurization, primary and secondary
reforming to generate raw gas, CO shift conversion, CO^ removal,
methanation of residual CO, and finally, conversion to ammonia.
Partial Oxidation
Reforming requires catalysts for the raw gas generation step. With
the partial oxidation processes, raw synthesis gas is generated
noncatalytically at relatively high temperature and pressure in
conjunction with use of high purity oxygen in the combustion step. Two
major processes are available: one from Shell Development Company, and
the other from Texaco Development Corporation. The partial oxidation
process can be used for both gaseous and liquid feedstocks (Reference 4-15)
Several raw gas treating techniques can be employed with the
partial oxidation process including cryogenic treatment, gas generation at
lower pressure, and catalytic procedures. The decision to employ one of
these methods is based on gas generation pressure, the energy balance, and
whether cryogenic or gas treatment is used for the gas purification step.
These alternatives can all be adapted to both the Shell and Texaco
processes.
4.2.2 Supply and Availability of Natural Gas
As mentioned earlier in this section, the majority of ammonia is
currently synthesized from natural gas. However, natural gas reserves
will become increasingly scarce in the future, and naptha and fuel oil,
which could replace natural gas, are either too scarce or expensive.
Thus, coal has the best potential as an alternate feedstock for ammonia
4-30
-------
synthesis. Several other factors that are responsible for this
development are:
• Present cutbacks in natural gas: Ammonia manufacturers are
experiencing natural gas cutbacks during the winter months.
The risks of even larger cutbacks threaten the profitability of
natural gas based ammonia plants.
• Long term coal supplies: Long term coal supplies can be
secured at a relatively stable price. Thus, the effects of
inflation and price escalation are minimized.
• Coal can increase natural gas supply: It is more economical to
increase available natural gas supplies by building coal-based
ammonia plants than by building coal-based Substitute Natural
Gas (SNG) plants.
However, it has been estimated that using ammonia to reduce NO
A
would require a 20 to 30 percent increase in ammonia production (Reference
4-16). Moreover, switching to coal may impact the price of ammonia and
the coal supply picture. To address these concerns, the following
discussion considers how much ammonia is needed for specific boiler types
to reach the low NSPS target. Then, the amount and comparative costs of
natural gas and coal feedstocks are evaluated and its impact on national
fuel consumption is considered.
Hydrogen injection is not seen as a tenable solution for control of
DeNO reaction temperature because of cost considerations, safety
A
factors and storage requirements, and thus, this option is not
considered. Since ammonia injection is nearly an order of magnitude more
expensive than conventional combustion controls for most cases, hydrogen
injection would further increase this disparity in costs. However,
4-31
-------
hydrogen may prove to be an effective tuning technique for nonconventional
combustion configurations which cannot be adapted to isothermal cavity or
in-tube-bank injection.
4.2.3 Ammonia Requirements for Specific Boiler Types
Exxon's ammonia injection rate estimates were used to determine the
amount of ammonia needed for each boiler type. An ammonia cost of $187/Mg
($170/ton) was assumed to arrive at the cost estimates. The NO
A
reductions were based on the low NSPS targets (172 ng/J for bituminous and
129 ng/J for subbituminous coal) in conjunction with conventional
combustion modification controls. The low NO targets were employed
A
since by the time DeNO would be fully implemented, these low targets
A
would be reasonable standards (1980-85 timeframe) (Reference 4-17).
However, this is a worst-case analysis since it is unlikely that all new,
as well as existing, boilers will have to meet this standard.
Table 4-13 shows the ammonia required and cost per MW-hr for the
four boiler types. The amount of ammonia required does not appear to be a
function of the equipment type (tangential, wall fired, etc.) but rather,
a function of the relative levels of initial and final NO emission
A
levels. That is, if the difference between the combustion modification
controlled N0x level and the final emission level is large, then the
ammonia required (kg/MW-hr) is also large.
Based on representative costs from Table 4-13, the national ammonia
supply and total costs for 1985 were determined using high and low coal
energy scenarios and the low emissions target (Reference 4-17). Table 4-14
shows that for the high coal consumption cases, as much as $650 million
would be spent for ammonia if all coal-fired utility boilers were retrofit
with DeNOx controls. In addition, about 3.8 x 106 Mg of ammonia would
4-32
-------
TABLE 4-13. AMOUNT AND COST OF AMMONIA USAGE FOR THE EIGHT
COAL-FIRED UTILITY BOILERS
Boiler
Type
Tangential
Single Wall
Opposed
Wall and
Turbo
Furnace
o , b
Cyclone
Manufacturer
CE
CE
B&W
FW
B&W
FW
RS
B&W
Capacity
(MW)
350
800
130
330
333
670
350
400
Baseline
Emissions
(ppm)
500
530
500
850
700
700
700
1000
CMa
Controlled
(ppm)
450
375
300
510
420
420
420
1000
CM+
DeNOx
Controlled
(ppm)
300
225
225
300
300
225
300
430
NH3
kgs/
hr
248
672
65
414
204
903
275
2031
NH3
kgs/
MW-hr
0.70
0.84
0.50
1.25
0.61
1.35
0.79
5.08
Cost of Ammonia
$/hr
46.4
125.6
13.07
77.5
38.3
168.8
51.5
(379.8
$/MW-hr
0.13
0.16
0.09
0.23
0.12
0.25
0.15
0.95
I
GO
OJ
aCM = Combustion modification
Assume no combustion modifications, max NO reduction of 57% with DeNO .
" A
-------
TABLE 4-14. TOTAL COST IMPACT OF AMMONIA USAGE ON ALL
COAL-FIRED UTILITY BOILERS INSTALLED BY
1985 — HIGH COAL GROWTH CASE
Boiler Type
Tangential
Single Wall
Opposed Wall
and Turbo
Furnace
Cyclone3
Vertical
and
Stoker
All Boilers
Coal Consumption
EJ
17.875
10.243
2.924
2.222
0.472
33.74
Ammonia
Consumption
Rate ng/J
73.1
83.0
86.4
480.3
103. 2b
Total
Ammonia
Consumption
106 Mg/yr
1.44
0.938
0.278
1.177
negligible
3.833
Ammonia Cost
103 $/yr
244,800
159,460
47,260
200,080
negligible
652,975
aAssume no combustion modifications, maximum NOX reduction of
57 percent with DeNOx.
^Weighted average.
4-34
-------
be required, which represents about a 20 percent increase in ammonia
supply. For the low coal growth case, Table 4-15 shows that about $370
million would be expended to meet the low emissions targets. Also about
2 x 10 Mg of ammonia would be required, representing over a 10 percent
increase in total ammonia supply.
4.2.4 Relative Impacts of Coal vs. Natural Gas Feedstocks on Ammonia
Cost and Fuel Supply~"
Switching the feedstock from natural gas to coal will clearly
impact the cost of ammonia. The synthesis of ammonia from coal will raise
the cost per ton. For example, the cost of ammonia is $165/ton when
produced from a typical bituminous coal, but only $150/ton when produced
from natural gas feedstock (Reference 4-15). Although this incremental
cost may be significant on a national scale, there are positive aspects
derived from switching from a natural gas to a coal feedstock. In fact, a
switch to coal could give U.S. producers a competitive edge because they
will be able to get a premium on ammonia prices over prices charged by
firms with interruptable gas supplies. For example, if natural gas
supplies are interrupted, each day's lost production is likely to cost the
operator (of a 1,000 metric ton/day ammonia plant) about $100,000,
including loss of profit and built-up capital charges.
It has been suggested that coal-fired power plants could be
combined with the production of ammonia. Such schemes could be based on
well known synthesis gas generation processes. One modern variation of
this process has been developed by Texaco Development Corporation and
another by Union Carbide Corporation.
In addition to the cost impact, the fuel feedstocks needed to
produce the additional ammonia will impact the national consumption of
4-35
-------
TABLE 4-15. TOTAL COST IMPACT OF AMMONIA USAGE ON ALL
COAL-FIRED UTILITY BOILERS INSTALLED BY
1985 -- LOW COAL GROWTH CASE
Boiler Type
Tangential
Single Wall
Opposed Wall
and Turbo
Furnace
Cyclone9
Vertical
and
Stoker
All Boilers
Coal Consumption
EJ
10.214
5.853
1.671
1.270
0.270
19.278
Ammonia
Consumption
Rate
ng/J
73.1
83.0
86.4
480.3
103. 2b
Total
Ammon i a
Consumption
106 Mg/yr
0.824
0.536
0.159
0.673
negligible
2.192
Ammonia Cost
103 $/yr
140,515
91,071
27,110
114,469
negligible
373,165
aAssume no combustion modifications, maximum NOX reduction of
57 percent with DeNOx.
^Weighted average.
4-36
-------
coal and natural gas. Tables 4-16 and 4-17 show the impact of increased
NH-, consumption on coal and natural gas consumpted directly or
indirectly by utilities in the year 1985. Assuming high coal growth,
natural gas consumption or coal consumption would increase by either 0.9
percent or 0.5 percent to meet the requirement for the ammonia feedstock.
For low coal growth, natural gas or coal consumption would have to
increase by about 0.5 percent in either case to meet the need for the
additional ammonia feedstock. Although small nationally, this impact
could be significant regionally.
In summary, switching from a natural gas to a coal feedstock should
not significantly impact either the cost or national energy consumption.
Moreover, if long-term contractual agreements for coal resources can be
obtained, the ammonia producers will have a major incentive to switch to
coal resources, particularly if they face increasing natural gas cutoffs
and decreasing supplies.
4-37
-------
TABLE 4-16. IMPACT OF INCREASED NH3 CONSUMPTION ON NATURAL GAS
AND COAL FEEDSTOCK — REFERENCE CASE HIGH COAL GROWTH
Boiler Type
Tangential
Single Wall
Opposed Wall
and Turbo
Furnace
Cyclone3
Vertical
and
Stoker
All Boilers
Coal
Consumption
EJ
17.875
10.243
2.924
2.222
0.472
33.736
NHs Needed
106 Mg/yr
1.44
0.938
0.278
1.177
Negligible
3.833
Natural Gas
Needed for
Synthesis
Ejb
0.053
0.035
0.010
0.043
0.141
(0.86)d
Coal Needed
For Synthesis
EJC
0.063
0.041
0.012
0.052
0.168
(0.45)d
aAssume no combustion modifications, maximum NOX reduction of
57 percent with DeNOx
bl.l x 106 SCM natural gas needed to make 10^ grams of ammonia
(37.26 MJ/SCM)
ci.18 Mg of coal needed to make 0.68 Mg of NH3 (27,900 J/g)
dPercent of total fuel used in 1985
4-38
-------
TABLE 4-17. IMPACT OF INCREASED NHa CONSUMPTION ON NATURAL GAS
AND COAL FEEDSTOCK -- REFERENCE CASE LOW COAL GROWTH
Boiler Type
Tangential
Single Wall
Opposed Wall
and Turbo
Furnace
Cyclone9
Vertical
and
Stoker
All Boilers
Coal
Consumption
EJ
10.214
5.853
1.671
1.270
0.270
19.278
NH3 Needed
106 Mg/yr
0.824
0.536
0.159
0.673
Negligible
2.192
Natural
Gas Needed
EJb
0.030
(0.029)
0.020
(0.019)
0.006
(0.006)
0.025
(0.024)
0.081
(0.50)d
Coal Needed
EJC
0.036
0.023
0.007
0.030
0.096
(0.45)d
aAssume no combustion modifications, maximum NOX reduction of
57 percent with DeNOx.
bl.l x 10^ SCM natural gas needed to make 106 grams of ammonia
(37.26 MJ/SCM)
C1.18 Mg of coal needed to make 0.68 Mg of NHa (27,900 J/g)
dPercent of total fuel used in 1985
4-39
-------
REFERENCES FOR SECTION 4
4-1 Varqa, 6. M., et al., "Applicability of the Thermal DeNOx Process
to Coal-Fired UtiTTty Boilers," EPA-600/7-79-079, March 1979.
4-2 Lim, K. J., et al., "Environmental Assessment of Utility Boiler
Combustion Modification NOX Controls," Acurex Draft Report
TR-78-105, April, 1978.
4-3 Grant, E. L., et al., Principles of Engineering Economy. Sixth
Edition, Ronald Press Co., New York, 1976.
4-4 McGlamery, G. G., ejb al-, "Detailed Cost Estimates for Advanced
Estimates for Advanced Effluent Desulfurization Process,"
EPA-600/2-75-006, January, 1975.
4-5 Waitzman, D. A., et a\_., "Evaluation of Fixed-Bed Low-Btu Coal
Gasification Systems for Retrofitting Power Plants," EPRI Report
203-1, February 1975.
4-6 Ponder, W. H., Stern, R. D. and McGlamery, G. G., "S02 Control
Methods Compound," The Oil and Gas Journal, pp. 60 to 66, December,
1976.
4-7 Engdahl, R. B., "The Status of Flue Gas Desulfurization," ASME Air
Pollution Control Division News, April, 1977.
4-8 Princiotta, F. T., "Advances in S02 Stack Gas Scrubbing,"
Chemical Engineering Process, pp. 58 to 64, February, 1978.
4-9 Edison Electric Institute, "Statistical Year Book of the Electric
Utility Industry for 1976," New York, EEI, October, 1977,
4-10 Personal communication, Pepper, W., Los Angeles Department of Water
and Power, Los Angeles, September, 1977.
4-11 Vilbrandt, F. C., and Dryden, C. E., Chemical Engineering Plant
Design. Fourth Edition, pg 191, McGrow-Hill, 1959.
4-12 Waitzman, D. A., "Ammonia from coal: A Technical/Economic Review,"
Process Technology, Chemical Engineering. January 30, 1978.
4-13 Ammonia Outlook Brightens Considerably, C&EN, May 24, 1976.
4r14 Hampton, G. C., et ^1_., "Production Economics for Hydrogen, Ammonia
and Methanol During 1980-2000", NTIS BNL-50663, April 1977.
4-15 Buividas, L. J., "Alternate Ammonia Feedstocks, Chemical
Engineering Progress. Vol. 70, No. 10, October,
4-40
-------
4-16 Texiera, D. P., "Status of Utility Application of Homogeneous NOX
Reduction," Proceedings of the NOX Control Technology Seminar,
EPRI SR-39, February, 1976.
4-17 Salvesen, K. J., et al. "Emission Characterization of Stationary
NOX Sources", EPA^6W7-78-120a, June 1978.
4-41
-------
SECTION 5
CONCLUSIONS AND RECOMMENDATIONS
1. Current NO regulatory strategy may require Thermal DeNO for'
A x
gas- and oil-fired utility boilers in the South Coast Air Basin of
Southern California. Projected regulation strategy for the 1980 's shows
a probable need for Thermal DeNO for coal-fired utility boilers.
/\
2. The Thermal DeNO Process is commercially available for gas- and
A
oil-fired boilers. NO reductions in the range of 40-70 percent can
A
often be achieved.
3. The Thermal DeNO Process is not demonstrated for full-scale
A
coal-fired boilers. Process conditions which could affect DeNO
A
performance and equipment operation need to be investigated. These
include:
• Coal type on reaction temperature
• Coal fired utility boilers operating characteristics on flue
gas temperature fluctuations and DeNO performance
A
• NH3 emissions on corrosion and fouling
• NH3 emissions on S03 depletion and ESP efficiency
• Flue gas particulate loading on system performance and
re 1 i ab i 1 i ty
4. These effects cannot be easily quantified with the present data
base. Currently ER&E is investigating the effect of coal type on reaction
5-1
-------
temperature. However, it is recommended that further studies be performed
to:
• Quantify ammonium sulfate and bisulfate formation and
deposition with various coal types
• Assess the effect of NH3 on S03 depletion and ESP
performance with various coal and ESP types
• Monitor the ongoing efforts in Japan in the above areas.
Results from these three efforts will be beneficial to guide full-scale
tests and aid in interpreting the results.
5. Furthermore, it is recommended that the Thermal DeNO Process be
A
installed on a full-scale coal-fired utility boiler equipped with
combustion modifications to assess:
• The effectiveness of Thermal DeNO used singly and in
A
conjunction with combustion modifications
• The performance of the process at various loads and during a
full operating cycle of the boiler, including slagging and
fouling of furnace tubes which cause temperature fluctuations
• Sulfate formation, corrosion and plugging of boiler parts due
to deposits of ammonia sulfates, especially air heaters and
associated ducting
• Effect on ESP performance and resultant emissions of fine
particles to the atmosphere
• Reliability of the injection system over extended operation
• Incremental maintenance due to the operation of the process
• Emissions of byproduct species in full-scale operation.
5-2
-------
6. Based on potential limitations of the Thermal DeNOx Process
identified in this report, the effectiveness forecast by Exxon for coal
firing may prove to be optimistic. Significant reductions in DeNO
s\
performance could occur if, for example, NH- emissions cannot be
maintained at a minimum level.
7. Costs reported by Exxon should in general be increased by 9 percent
on the average to include additional expenditures not considered.
Licensing costs should also be added once they have been specified by
Exxon.
8. If all existing and new coal-fired utility boilers were to meet low
NSPS targets (172-129 ng/J) by 1985 with combined combustion modifications
and Thermal DeNO , the increase in NHL consumption would range from
X «J
2.2 to 3.8 million Mg/year. The cost of this additional NHL to the
utilities would range from 370 to 650 million dollars per year. The
impact of this increase in ammonia production on feedstock fuels would be
less than one percent of the total national gas and coal consumption
in 1985.
5-3
-------
APPENDIX A
GLOSSARY OF TERMS
A-l
-------
TABLE A-l. GLOSSARY OF TERMS USED IN COST ANALYSIS CALCULATION PROCEDURE
AKW = Additional Fan Requirements, kW
AROY = Annual Royalties, $/yr
Bl = Debt/Equity Ratio, fraction
CANAL = Cost of Analysis, $
CFE1 = Construction Field Expense Factor, fraction
CF1 = Construction Facilities Factor, fraction
CGA = Construction General & Administrative Expense, fraction
CON1 = Contractor's Fee, fraction
CRATE = Composite Construction Crew Rate, $/h
CSUPV = Construction Supervision Factor, fraction
CTN1 = Construction Contingency Factor, fraction
DESRAT = Designer's Rate, $/h
DHRS = Design Hours, h
DRATE = Derate of Boiler, kW
DS1 = Design and Supervision Factor , fraction
EGA = Engineering and Design G&A, fraction
EHRS = Engineering Hours, h
EOHD = Engineering and Design Overhead, fraction
EOOS = Equipment Out of Service, $
ER = Electric Power Rate, $/kW
ERAT - Engineering Rate, $/hr
ESUPV = Engineering Supervision Factor, fraction
FCOST = Fuel Cost, $/106 Btu (1 Btu = 1.055 kJ)
FEER = Engineering Fee, fraction
FPEN = Fuel Penalty, fraction
A-2
-------
TABLE A-l. Continued
Fl = Federal Tax Rate, fraction
HRATE = Heat Rate of Boiler, Btu/kWh (1 Btu = 1.055 kJ)
HRINST = Installation Time, h
HYR = Annual Operating Time, h
1C = Initial Charges, $
110 = Initial Investment of Boiler, $
ILAST = Computer Code Counter
INI = Insurance Factor, fraction
101 = Interest on Borrowed Money, Original Investment, fraction
II = Interest on Borrowed Money, Present Investment, fraction.
K = Age of Existing Boiler, yr
KW = Power Rating of Boiler, kW
Ml = Maintenance Factor, fraction
N = Remaining Lifetime of Boiler, yr
NANAL = Number of Analyses Required
NLOST = Total Lifetime of Boiler, yr
NOBASE = Baseline NO Emissions, ppm
^
NOCONT = Controlled NO Emissions, ppm
A
MOP = Number of Operators
OHA1 = Administrative Overhead Operating Labor Factor, fraction
OHP1 = Power Plant Overhead, fraction
RE1 = Replacement Equipment Factor, fraction
RM = Raw Materials, $/yr
R01 = Return to Equity, Original Investment, fraction
A-3
-------
TABLE A-l. Concluded
Rl = Return to Equity, Present Investment, fraction
SCI = Startup Cost Factor, fraction
SF1 = Service Facilities Factor, fraction
SI = State Tax Rate, fraction
PPR = Purchased Power Rate, $/kWh
TM = Total Materials (Hardware) Required, $
UF1 = Utilities Facilities Factor, fraction
WAGE = Operating Labor Rate, $/h
A-4
-------
APPENDIX B
COST INPUTS
B-l
-------
TABLE B-l. COST INPUTS FOR RETROFIT OF NH3 INJECTION ON
130 MW FRONT WALL COAL-FIRED BOILER
SINPUT
AKW
AROY
Bl
CANAL
CFE1
CF1
CGA
CON!
CRATE
CSUPV
CTN1
DESKAT
DHRS
DRATE
DS1
EGA
EHRS
EOHD
EOOS
ER
ERAT
ESUP\/
FCOST
FEER
FPEN
Fl
HRATL
HRINST
HYR
.ooooooooE+on
.noooooooE+oo
.50000000E+00
.OOOOOOOOE+OO
.13000000E+00
.50000000E-U1
.2500noOOE+00
.70000000E-01
.15300000F+02
.1000MOOOE+00
,15UnOOOOE+00
.90000000E+01
.OOOOOOOOE+00
.OOOOOOOOE+00
.^bOOnOOOE-01
. 2 5 0 0 0 0 0 0 FT + 0 0
.OOOOOOOOE+00
.11000000F. + 01
.OOOOOCOOF. + OO
.25000000F-OI
.12000000E+0?
.10000000E+00
. 13000000 E +01
.80000000F-01
.OOOOPOOOE+00
.^HOUOOUOE+UO
1C
no
ILAST
INI
101
II
K
K'W
Ml
fvl
NATJAL
IMLOST
NOBASE
NOCONT
.OOOOOOOOE+00
. 7 C 0 0 0 0 0 0 E + 0 4
OHA1
OHP1
RE1
RM
R01
Rl
SCI
SF1
SI
PPK
UF1
WAGE
OOCiOOOOOE + GO
OOOOOOOOE+00
+ 0
5flOOOOOOE-02
«OOOOOOOE-04
euonooocE-oi
.50UOOOOOE-C1
.oooooooor+co
.30000UOOE+0?
.30000000E+03
.22300000E+03
.10000000E+00
.2COOUOUOF+00
.Honoouoor -02
.1200000 OF. + 00
.120 000 ODE +00
.lOOOOOUOL+00
.5UOOCOOOE-01
.f,OOOOOOOE-Ol
.26000000E-01
.778-600001". + 06
.30000000E-01
.1UOOOOOOE+02
B-2
-------
TABLE B-2. COST INPUTS FOR RETROFIT OF NH3 INJECTION ON
333 HORIZONTALLY OPPOSED COAL-FIRED BOILER
SINPUT
AKW
AROY
Bl
CANAL
CFE1
CF1
C(>A
Com
CRATE
CSUPV
CTM1
DESRAT
DHRS
ORATE
DS1
EGA
EHRS
EOHD
EOOS
EK
FRAT
ESUPV
FCOST
PEER
FPEN
Fl
HRATE
HRINiJT
HYR
.OOOOCOOOF «nc
.OOOOOOOOE ^on
.bOOOUOOOF+00
.OOOOGOOOF+00
,i3onnoooE+oo
.50000000E-01
.P5000000E+00
.70000000F-01
.15300000E+02
.ioonooooE+no
.ibooonooe+oo
.90000000F+01
.nooooooor+on
.OOOOOOOUFI + 00
.IbOOOOOOt-Ol
,25000000F+On
.OOOOOOOOE+CO
.110000UOF+-U1
.ooooooocE+on
,2bOOOOOOE-01
.12UOOOOOF-t-02
.1000000CE+00
.ISOOOOuOE+Cl
.60000000E-Q1
.noooooooE-t-on
.oooconoor. + oo
1C
110
ILAST
INI
101
II
K
KW
Ml
N
NANAL
NLOST
NOBASE
NOCOfJT
IMOP
OHA1
OHP1
RE1
Rr';
R01
Rl
SCI
SF1
51
PPR
TH
UF1
WAGE
.0000000 OF +00
.OOUOOOUGF+00
+ 0
.50000000F-02
.ftOOOCOOOE-0^
.eooouoooF-oi
+ 5
.33300000E+06
.5UOOOOOOE-U1
.OOOOOOOOE+00
. -JliOOOOOOE + 0?
.H2000000E+03
.30000000F+03
.nynooooE+oo
.lOOOOOOOH+00
,2oonooooE+oo
.HOOOOOOCE-0?
.43785'OOOE + Of,
.12000000E+00
.12000000F.+00
.50COOOOOF-01
.feOOOOOOOE-01
,?t>OOOOOOF-0]
.112POOOOE+C7
,3U 000 00 Of -01
.10000000E+02
B-3
-------
TABLE B-3. COST INPUTS FOR RETROFIT OF NH? INJECTION ON
350 MW TANGENTIAL COAL-FIRED BOILER
S1NPUT
AKW
AROY
Bl
CANAL
CFE1
CF1
CGA
CON1
CRATE
CSUPV
CTN1
DESRAT
DHKS
CRATE
OS1
EGA
EHRS
EOHP
EOOS
ER
ERAT
ESUPV
FCOST
PEER
FPEN
Fl
HKA7E
HRIUST
HYR
.OOOOOOOUE-MIO
.OOOOOOOOE+00
.50000000E+00
.OOOOOOOOE+OO
.13000000E+00
.50000000R-01
.25000000E+00
.70000000E-01
.15300000E+02
.10000000E+00
.IbOOOOOOE+OO
.90000000F. + 01
.ononooooE+uo
.OOOQOOOOF+00
.nooocoooF+on
.iioonouoE+oi
.OOOOOOOOF+00
.25000000E-01
.12000000E+OP
. 1 C 0 0 0 0 0 U £ + 0 0
. 1300nOOOE + 01
.800000UOF-01
.OOODOOOOE+00
.40000000F+00
.92000000E+Q4
.OOOOOOOOE+00
.70000000E+04
1C
110
ILAST
INI
101
ii
K
KU
Ml
N
NANAL
MOST
NODASE
NOP
OHA1
OHP1
PE1
Rf'l
R01
Rl
SCI
SF1
SI
PPR
Til
UF1
WAGE
.OOUOCOOOE+GD
.OOOOOOOOF+CU
+ 0
.5CnnooonF-02
.flOOOOOOOF -04
.8ooo'oooor-oi
.5000DOOOE-01
+ 25
.ooooooooF+no
,3000nOOOF+02
.4500C10JOE + 03
.3000UOOOF+03
.IISOOOUOE+OO
.iooonoooE+oo
.2000UUOOE+UO
.HOOOOOOUE-02
.50793000E+06
.12000000E+00
.10000000F+00
.50000000E-01
.60000000E-01
.26000000E-U1
.11714000E+07
.3000 000 OF -01
.10000000E+02
B-4
-------
TABLE B-4. COST INPUTS FOR RETROFIT OF NH3 INJECTION ON
800 MW TANGENTIAL COAL-FIRED BOILER
SINPUT
AKU
AROY
Bl
CANAL
CFE1
CF1
CGA
CON1
CRATE
CSUPV
CTNl
DESRAT
DHRS
DRATE
DS1
EGA
EHRS
EOHD
EOOS
ER
ERAT-
ESUPV
FCOST
PEER
FPEN
Fl
HRATE
HRINST
HYR
.OOOOOOOOE+00
.OOOOOOOOE+00
.50000000E+00
.OOOOOOOOE+00
.13000000E+00
.50000000E-01
.25000000E+00
.70000000E-01
.15300000E+02
.lOOOOOOOE+00
.150DOOOOE+00
.90000000E-I-01
.OOOOOOOOE+00
.OOOOOOOOE+00
.45000000E-01
.25000000E+00
.OOOOOOOOE+00
.11000000E+01
.OOOOOOOOE+00
.250000DOE-01
.12000000E+02
.lOOOOOOOE+00
.13000000E+01
.BOOOOOOOE-01
.OOOOOOOOE+00
,«t8000000E + 00
.92000000E+04
.OOOOOOOOE+00
.70000000E+04
1C
no
ILAST
INI
101
II
K
KW
Ml
N
NANAL
NLOST
NOBASE
NOCONT
NOP
OHA1
OHP1
RE1
RM
R01
Rl
SCI
SF1
SI
PPR
T"
UF1
WAGE
.OOOOOOOOE+00
.OOOOOOOOE+00
+ 1
.50000000E-02
.80000000E-04
.BOOOOOOOE-01
+ 5
.80000000E+06
.50000000E-01
+ 25
.OOOOOOOOE+00
.30000000E+02
.37500000E+03
.22500000E+03
.11900000E+00
.1000UOOOF+00
.20000000E+00
.HOOnoODOE-02
.13748290E+07
.12000000E+00
.12000000E+00
.lOOOOOOOE+00
.50000000L-01
.60000GOOE-01
.26000000E-01
.17154000E+07
,30000000E:-01
.10000000E+02
B-5
-------
TABLE B-5. COST INPUTS FOR RETROFIT OF NH3 INJECTION ON
350 MW FRONT WALL COAL-FIRED BOILER
IINPUT
AKW
AROY
Bl
CANAL
CFE1
CF1
CGA
CON1
CRATE
CSUPV
CTN1
DESRAT
DHRS
DRATE
DS1
EGA
EHRS
EOHD
EOOS
EK
ERAT
ESUPV
FCOST
PEER
FPEINj
Fl
HRATE
HRINST
HYR
.OOOOOOOOE+00
.OOOOOOOOE+00
.5GOOOOOOE+00
.ooonooooE+oo
.13000000E+00
.5000000OF-01
.2bOOOOOOE+00
.70000000E-01
.153000GOE+02
.10000000F+UO
.IbOOOOOOE-t-OO
.90000000E+01
.OGOUCOOOF+00
.oooonoooc+oo
,t»5000000E-01
.25ooooour+oo
. (J 0 0 0 0 0 0 0 E + 0 0
.iioonuuoE+oi
.OOOOUOOOE+CO
.P5000UOOE-01
.12000000E+0?
.lOOOOOOOE+00
.liOOOOOOF+03
.flOOOOOOOE-01
.noooooooE+oo
.MBOOOOOOE400
.92000000E+04
.oooooooor. + on
.70000000E+04
1C
110
It-AST
INI
101
II
K
KU
Ml
N
fJANAL
NLOST
NOBASE
NOCONT
NOP
OHA1
OHP1
RE1
Rl',
R01
Rl
SCI
Sf-1
SI
PPR
TH
UF1
WAGE
.ooono
.oocoo
.50000
.flOCOO
.80000
.33000
.50000
.ooono
.30000
.51000
.30000
.11900
.10000
.20000
. 4 0 0 0 f I
.71540
.12000
.12000
.10000
.50000
.60000
.26000
.11902
.30000
.10000
OOOE+00
OOOEH-00
+ 0
OOOE-02
OOOE-OU
OOOF-01
+ 5
OOOE+06
OOOE-01
+ 25
0 0 0 F + 0 0
OUOE+U2
OOCF+03
CO OF. +03
OOOE+00
0 0 0 L + 0 0
OOOE+00
OUUF-02
OOOF+00
0 0 Of + 0 0
0 0 0 F + 0 0
OOOE-OI
OOOE-01
OOOF-0]
OOOE+07
OOOE-01
OOOE+02
B-6
-------
TABLE B-6. COST INPUTS FOR RETROFIT OF NH3 INJECTION ON
670 MW HORIZONTALLY OPPOSED COAL-FIRED BOILER
MNPUT
AKW
AKOY
Rl
CANAL
CFE1
CK1.
CGA
CON1
CRATE
CSUPV
CTN1
PESRAT
DHRS
DRATE
DS1
EGA
EHRS
EOHD
ECO?
ER
ERAT
ESUPV
FCOST
FEER
FP£N
F3
HRATE
HRINST
HYK
=
=
—
—
=
—
=
—
=
—
=
—
=
—
—
—
—
—
-
—
—
~
—
—
—
-
—
—
—
.oonooooo. +00
.ooonooooE+oo
.5000000UE+00
.OOOOOOOOE+00
.13000000F+00
,?oonooooE-oi
.25000000E+00
.70000000E-01
,a5300000E+02
.10000000E+00
.1 500000 OE+OO
.SOOOOOOOF. + U1
.000 i) 000 OE + OO
.OOOOOOUOE+OO
.45000000E-01
. 2 5 0 0 0 0 0 0 E -t- (3 0
.OOOOOOOOE+00
.110DOOOOF. + 01
.OOOUOOCOE+00
.25000000E-01
.12000000E+0?
.loonooooE+oo
.13000C'JOF + 01
.^OOOOOOOE-Ol
.ooonoooot+uo
.HBOOflOOOF + OO
.92000000E+04
.O&OOOOOOE+OO
.70000000E+OU
1C
110
ILAST
INI
101
11
K
KW
Ml
N
NAT\)AL
r-jLOs r
NOBASE
IVOCGNT
r.'OP
OHAl
OHP1
RE1
RN
P01
Rl
SCI
SF1
SI
PPR
lh
UF1
UAGE
.oouoconoF+oo
.OOOOOOOOF+00
+ 0
.5 000000 OF -02
.POOOOOOOE-Oi4
. t no on o OOF -01
.bOOOOOOOE-01
.onoonoooE+oo
.?OOOOOOOEt02
.42000000E+03
,?250i)OOOF+03
. 11900 OOOE + 00
.luonooooF-rOo
.12000000E+00
.120 POO OOF + 00
.loonoooof+oo
.500UOOOUE-01
.f,ooonoooE-oi
,2oOOOUOOE-01
.16909000F+C7
.300PUOOOE-G1
.10000000F+0?
B-7
-------
TABLE B-7. COST INPUTS FOR RETROFIT OF NH3 INJECTION ON
350 MW TURBO COAL-FIRED BOILER
AKW
AROY
Bl
CAf\jAL
CFE1
CF1
CGA
CON1
CRATE
CSUPV
CTWl
DESRAT
DHRS
DRATE
DS1
EGA
EHHS
EOHD
•EOOS
ER
ERAT
ESUFV
FCOST
FEEH
FPEN
Fl
HKA1L
HR1NST
HYR
.OOOOUOOGF+UO
.ooonooooE-t-uo
.50000000E+00
.OOOOOOUOE+00
.13000000F+00
.5UGOOUOOE-01
.250000UUF+UO
.7UOOOOOOE-U1
,lb300000F+U2
.1UOOOOOOE+00
.1500000GE+00
.9GOOOOOOE+01
.OOOOOOOOE+00
.onunooooE+oo
.45000000E-G1
,25onoooor+oo
.OCOilUOOOE + CO
.11000000E+01
.COOOOOOOE-i-00
,?bOOCOOOE-01
. IUOOOUOOF400
.liOnOOOGF-t-01
.tooonooor-Gi
.OOOOOUOOE' + OO
. 4 Ji! 0 0 0 0 0 0 E + 0 0
.OOGOOOOOE+00
1C
no
ILAST
INI
101
II
K
KW
Ml
N
NATJAL
NLOST
NOB/\SE
NOCONT
NUP
OHA1
OHP1
RE1
RM
R01
Rl
SCI
SFl
SI
PPR
TM
UF1
WAGE
.OOOOOOOOf + 0.0
.onooooooE-t-co
+ 1
.50000 00 UF-02
.oOOnOOOGF-Cq
.aoonouooE-oi
+ 5
.boonnoooE-oi
.oonnooooF+on
.3UUOOOOOF. + 02
10000000F+UO
PGOOCGOOF. + OO
u o o o n o o o F. - o ?
120000'OCJE + OO
1200CIUOOF+00
ioonouooF+oo
500nOOOOF-Ol
enoooooun-0]
2bOOCGOOF-01
120f,300nF-i-C7
30000000F-03
lOOOnOOOE+02
B-8
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
REPORT NO.
EPA-600/7-79-117
3. RECIPIENT'S ACCESSION NO.
.TITLE AND SUBTITLE
Technical Assessment of Thermal DeNOx Process
5. REPORT DATE
May 1979
6. PERFORMING ORGANIZATION CODE
AUTHOR(S)
C.Castaldini, K. G.Salvesen, and
H.B. Mason
8. PERFORMING ORGANIZATION REPORT NO.
PERFORMING ORGANIZATION NAME AND ADDRESS"
Acurex Corporation
Energy and Environmental Division
485 Clyde Avenue
Mountain View, California' 94042
10. PROGRAM ELEMENT NO.
E HE 62 4 A
11. CONTRACT/GRANT NO.
68-02-2611, Task 10
2. SPONSORING AGENCY NAME AND ADfiRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final; 11/77 - 12/78
14. SPONSORING AGENCY CODE
EPA/600/13
5. SUPPLEMENTARY NOTES
541-2236.
project officer is David G. Lachapelle, MD-65, 919/-
s. ABSTRACT The report gi7es results of a technical/economic assessment of Exxon's
Thermal DeNOx Process, applied to coal-fired utility boilers. The assessment was
performed in parallel with a study in which the performance/cost of the process was
estimated for eight coal-fired utility boilers representative of the Nation's boiler
population. The report concludes that the process is a promising technique for
controlling NOx emissions from utility steam generators. However, a number of
limitations need to be evaluated when the process is retrofitted to coal-fired boilers.
Flue gas temperature fluctuations (caused primarily by load following, furnace slag
deposition, and tube fouling) may limit NOx reductions to approximately 50%. In
addition, operational and environmental impacts of NH3 emissions and ammonium
bisulfate formation could further limit the performance of the process and affect its
applicability. These limitations are best evaluated on full scale. Total operating
costs are estimated between 0.27 and 1.23 mills/kWhr, exclusive of license fee.
Actual costs depend primarily on boiler size, initial NOx concentration, and level
of control required. The assessment also considered the impact of widespread pro-
cess implementation on the ammonia market, feedstock supplies, and their costs.
The impacts were found to be small.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Assessment
Ammonia
Performance
Cost Estimates
Nitrogen Oxides
Utilities
Boilers
Coal
Ammonium Com-
pounds
Pollution Control
Stationary Sources
NH3 Injection
Thermal DeNOx Process
Utility Boilers
Ammonium Bisulfate
13B
14B
07B
14A
13A
21B
13. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
138
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
B-9
------- |