CDA U.S. Environmental Protection Agency Industrial Environmental Research PDA fiOD/7 7fi
IZl /A Office of Research and Development Laboratory
Cincinnati.Ohio 45268 December 1976
ENVIRONMENTAL
CONSIDERATIONS OF
SELECTED ENERGY
CONSERVING MANUFACTURING
PROCESS OPTIONS:
Vol. VII. Ammonia
Industry Report
Interagency
Energy-Environment
Research and Development
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 seven series.
These seven broad categories were established to facilitate further
development and application of environmental technology. Elimination
of traditional grouping was consciously planned to foster technology
transfer and a maximum interface in related fields. The seven series
are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from
the effort funded under the 17-agency Federal Energy/Environment
Research and Development Program. These studies relate to EPA's
mission to protect the public health and welfare from adverse effects
of pollutants associated with energy systems. The goal of the Program
is to assure the rapid development of domestic energy supplies in an
environmentally—compatible manner by providing the necessary
environmental data and control technology. Investigations include
analyses of the transport of energy-related pollutants and their health
and ecological effects; assessments of, and development of, control
technologies for energy systems; and integrated assessments of a wide
range of energy-related environmental issues.
This document ""is available to the public .through the National Technical
Information Service, Springfield, Virginia 22161.
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EPA-600/7-76-034g
December 1976
ENVIRONMENTAL CONSIDERATIONS OF SELECTED
ENERGY CONSERVING MANUFACTURING PROCESS OPTIONS
Volume VII
AMMONIA INDUSTRY REPORT
EPA Contract No. 68-03-2198
Project Officer
Herbert S. Skovronek
Industrial Pollution Control Division
Industrial Environmental Research Laboratory - Cincinnati
Edison, New Jersey 08817
•INDUSTRIAL ENVIRONMENTAL RESEARCH LABORATORY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
CINCINNATI, OHIO 45268
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DISCLAIMER
This report has been reviewed by the Industrial Environmental Research
Laboratory, U.S. Environmental Protection Agency, and approved for publica-
tion. Approval does not signify that the contents necessarily reflect the
views and policies of the U.S. Environmental Protection Agency, nor does
mention of trade names or commercial products constitute endorsement or
recommendation for use.
ii
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FOREWORD
When energy and material resources are extracted, processed, converted,
and used, the related pollutional impacts on our environment and even on our
health often require that new and increasingly more efficient pollution con-
trol methods be used. The Industrial Environmental Research Laboratory -
Cincinnati (IBRL-Ci) assists in developing and demonstrating new and im-
proved methodologies that will meet these needs both efficiently and
economically.
This study, consisting of 15 reports, identifies promising industrial
processes and practices in 13 energy-intensive industries which, if imple-
mented over the coming 10 to 15 years, could result in more effective uti-
lization of energy resources. The study was carried out to assess the po-
tential environmental/energy impacts of such changes and the adequacy of
existing control technology in order to identify potential conflicts with
environmental regulations and to alert the Agency to areas where its activi-
ties and policies could influence the future choice of alternatives. The
results will be used by the EPA's Office of Research and Development to de-
fine those areas where existing pollution control technology suffices, where
current and anticipated programs adequately address the areas identified by
the contractor, and where selected program reorientation seems necessary.
Specific data will also be of considerable value to individual researchers
as industry background and in decision-making concerning project selection
and direction. The Power Technology and Conservation Branch of the Energy
Systems-Environmental Control Division should be contacted for additional
information on the program.
David G. Stephan
Director
Industrial Environmental Research Laboratory
Cincinnati
iii
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EXECUTIVE SUMMARY
Natural gas is the basic feedstock for virtually all ammonia production in
the United States. Construction of new ammonia plants to meet demand is becoming
increasingly difficult because of the shortage of natural gas. If this short-
age persists, the ammonia industry will be forced to implement the use of
alternate feedstocks, such as coal and heavy fuel oil, in 50 to 100 percent
of new plant construction from 1985 forward, and one or two new plants may
even be built prior to that time. Such plants are not commercial in the
United States at present and, thus, will constitute a major process change.
Also, such plants are likely to have pollution problems significantly greater
than present plants. Therefore, we chose to analyze the process options of:
• ammonia production based upon coal gasification; and,
• ammonia production based upon heavy oil gasification.
As a guide for interpreting the energy and pollution effects of changing
feedstocks upon the economics of manufacturing ammonia, we have estimated
typical investments and operating costs of new plants using natural gas, coal
and heavy fuel oil feedstocks, based upon conditions prevailing during March
1975. The coal and heavy oil alternatives are not economically attractive
under the conditions chosen for our evaluations in this study. If the price
of natural gas to the ammonia industry were to rise from the $0.85 per million
Btu (used in this study) to approximately $2.50 per million Btu, the calculated
ammonia costs would rise from our estimated $98 per ton of ammonia to $153
per ton. This would change the economic attractiveness of the coal- and
heavy oil-based alternatives.
Significant incremental capital investment above that of plants based
upon natural gas (which is on the order of $186 per annual ton of ammonia) is
involved in the alternative processes, as high as $111 per annual ton of
ammonia capacity for the coal alternative and $21 per annual ton for the
heavy fuel oil alternative. Incremental production costs of $17 per ton of
ammonia, which includes $8.65 per ton for pollution abatement, are expected
for the coal alternative. The corresponding incremental cost for the heavy
fuel oil alternative is $45 per ton of ammonia, which includes $3.46 for pol-
lution abatement. The investment required for a coal- or heavy oil-based
plant is higher than that for one based on natural gas. Nevertheless, when
faced with a continuing shortage of natural gas, the industry will have to
find other fuel and feedstocks.
IV
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The needed pollution control technology will mean an expenditure of
energy equivalent to 165,000 Btu per ton of ammonia for the coal alternative,
and a 0.5 percent increase in the total energy required for ammonia produc-
tion. Approximately 125,000 Btu are required for pollution control for the
heavy fuel oil alternative, corresponding to a 0.2 percent increase in energy
consumption. Thus, the relative incremental fuel use is negligible, while
the fuel form savings are significant.
While the environmental impact could be significant for these alterna-
tives, there are no unique problems which will be encountered by new ammonia
plants basing production on coal and heavy fuel oil feedstocks. Difficulties
will be no greater than those encountered in electric power generation or in
industrial boilers fired with these fuels. However, the need to address
these difficulties at industrial plants will be a new experience.
This report was submitted in partial fulfillment of contract 68-03-2198
by Arthur D. Little, Inc. under sponsorship of the U.S. Environmental Protec-
tion Agency. This report covers a period from June 9, 1975 to January 20, 1976.
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TABLE OF CONTENTS
Page
FOREWORD i:Li
EXECUTIVE SUMMARY iv
List of Figures .:
List of Tables *
Acknowledgments x±ii
Conversion Table xv
I. INTRODUCTION 1
A. BACKGROUND 1
B. CRITERIA FOR INDUSTRY SELECTION 1
C. CRITERIA FOR PROCESS SELECTION 3
D. SELECTION OF AMMONIA INDUSTRY PROCESS OPTIONS 3
II. FINDINGS, CONCLUSIONS AND RECOMMENDATIONS 6
A. AMMONIA FROM COAL 6
1. Environmental Aspects 6
2. Areas Where EPA Policies May Influence Future
Choices of Alternatives 6
3. Practices/Processes Requiring Additional Research 6
B. AMMONIA FROM HEAVY FUEL OIL 7
1. Environmental Aspects 7
2. EPA Policies and Requirements for Additional Research 7
III. OVERVIEW OF THE UNITED STATES AMMONIA INDUSTRY 10
A. DESCRIPTION OF INDUSTRY 10
1. Introduction 10
2. Plant Characteristics 13
3. Integration and Concentration 15
B. ECONOMIC OUTLOOK 16
IV. COMPARISON OF CURRENT AND ALTERNATIVE PROCESSES 20
A. REASONS FOR CHOOSING OPTIONS FOR IN-DEPTH ANALYSIS 20
B. COMPARISON OF CURRENT AND ALTERNATIVE PROCESSES 22
1. Methodology 22
2. Ammonia Production Based on Natural Gas 25
3. Ammonia Production Based on Coal Gasification 37
4. Production of Ammonia from Heavy Fuel Oil 66
vii
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TABLE OF CONTENTS (Cent.)
Page
V. IMPLICATIONS OF POTENTIAL INDUSTRY/PROCESS CHANGE 80
A. AMMONIA FROM COAL 82
1. Impact on Pollution Control 82
2. Impact on Energy 84
3. Factors Affecting Probability of Change 84
4. Areas of Research 84
B. AMMONIA FROM PETROLEUM 86
1. Impact On Pollution Control 86
2. Impact on Energy 86
3. Factors Affecting Probability of Change 86
4. Areas of Research 87
viii
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LIST OF FIGURES
Number Page
•III-l Market Share of Major U.S. Synthetic Ammonia Producers, ]974 15
IV-1 Flow Diagram for Synthesizing Ammonia by Steam-Reforming
Process 26
IV-2 Ammonia Production Based on Natural Gas Feedstock 30
IV-3 Coal Receiving and Preparation 48
IV-4 Gasification 48
IV-5 Carbon Monoxide Shift and Synthesis Gas Purification 49
IV-6 Sulfur Recovery 49
IV-7 Ammonia Synthesis 50
IV-8 Auxiliary Boiler 50
IV-9 Capital Investments - Glaus Plant 64
IV-10 Synthesis Gas Generation Including Recovery of
Unconverted Carbon 69
IV-11 Carbon Monoxide Shift and Synthesis Gas Purification 72
IV-12 Sulfur Recovery 73
IV-13 Ammonia Synthesis 73
V-l Effect of Natural Gas 'and Coal Prices Upon Ammonia Prices 85
V-2 Effect of Natural Gas and Residual Fuel Oil Prices Upon
Ammonia Prices 87
ix
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LIST OF TABLES
Number Page
1-1 Summary of 1971 Energy Purchased in Selected Industry Sectors 2
II-l Comparison of Base line and Alternative Processes 8
II-2 Air, Water, and Solid Waste Streams from Base Case and
Alternative Fuel Systems and Process Modifications 9
III-l Synthetic Ammonia - U.S. Production History 11
III-2 Uses and Sources of Ammonia - 1974 11
III-3 1973 Energy Use for Ammonia Manufacture 12
III-4 Age of Amonia Plants Operating at Beginning of 1976 13
III-5 Anhydrous Ammonia Capacity by Region in 1974 14
III-6 Fertilizer Nitrogen Consumption 16
III-7 Projected U.S. Nitrogen Supply/Demand Balance 17
III-8 Change in the Economics of Ammonia Manufacture 19
IV-1 Benchmark Energy Costs for Coal, Oil, Gas and Electric Power 24
IV-2 Benchmark Employee Earnings 24
IV-3 Estimated Production Cost of Ammonia from Natural Gas 27
IV-4 Energy Use in Ammonia Production • 29
IV-5 Natural Gas Consumption in Ammonia Production 29
IV-6 1973 Regional Fuel and Power Use: Ammonia 30
IV-7 Emissions from Ammonia Plants Based on Natural Gas 31
IV-8 Estimated Energy Impact for Ammonia Production of Current
Pollution Control Regulations 32
IV-9 Water Effluent Treatment Costs - Ammonia Plants 33
IV-10 Water Pollution Control Costs ($) Ammonia/Condensate Steam
Stripping 34
A
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LIST OP TABLES (Cont.)
Number Page
IV-11 Example Cost of Ammonia Scrubbing 36
IV-12 Ammonia Plants Based on Gasification of Coal 38
IV-13 Gasification System 40
.IV-14 Estimated Production Cost of Ammonia from Coal 46
IV-15 Analysis of Illinois No. 6 Coal 47
IV-16 Water Effluents - Ammonia from Coal Alternative 51
IV-1? Air Emissions -.Ammonia from Coal Alternative 51
IV-18 Solid Wastes - Ammonia from Coal Alternative 52
IV-19 Elemental Distribution in Coal, Slag, and Fly Ash 54
IV-20 Coal Gasification Alternative - Wastewater Treatment
Cost Estimates 59
IV-21 Summary of Air Pollution Emission Factors 61
IV-22 Capital and Operating Costs for Coal Handling Particulate
Control 63
IV-23 Approximate Sulfur Balance, TPD 64
IV-24 Sulfur Control Costs for Acid Gas Exhaust 65
IV-25 Estimated Production Cost of Ammonia from Residual Fuel Oil 70
IV-26 Water Effluents - Ammonia from Heavy Oil Alternative 74
IV-27 Air Emissions - Ammonia from Heavy Oil Alternative 74
IV-28 Solid Wastes - Ammonia from Heavy Oil Alternative 74
IV-29 Soot Recycle System Slowdown 76
IV-30 Oil Gasification Alternative Incremental Wastewater
Treatment Cost Estimates 77
IV-31 Sulfur Control Costs for Acid Gas Exhaust Oil Gasification
Alternative 79
XI
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LIST OF TABLES (Cont.)
Number Page
V-l Capital Investment Summary for Environmental Control 83
V-2 Annual Incremental Operating Cost Summary for Environmental
Control 83
V-3 Energy Consumption Summary for Environmental Control 85
xii
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ACKNOWLEDGMENTS
This study could not have been accomplished without the support of a
great number of people in government agencies, industry, trade associations
and universities. Although it would be impossible to mention each individual
by name, we would like to take this opportunity to acknowledge the particular
support of a few such people.
Dr. Herbert S. Skovronek, Project Officer, was a valuable resource to us
throughout the study. He not only supplied us with information on work
presently being done in other branches of EPA and other government agencies,
but served as an indefatigable guide and critic as the study progressed. His
advisors within EPA, FEA, DOC, and NBS also provided us with insights and
perspectives valuable for the shaping of the study.
During the course of the study we also had occasion to contact many
individuals within industry and trade associations. Where appropriate we
have made reference to these contacts within the various reports. Frequently,
however, because of the study's emphasis on future developments with compara-
tive assessments of new technology, information given to us was of a confiden-
tial nature or was supplied to us with the understanding that it was not to be
credited. Therefore, we extend a general thanks to all those whose comments
were valuable to us for their interest in and contribution to this study.
Finally, because of the broad range of industries covered in this study,
we are indebted to many people within Arthur D. Little, Inc. for their parti-
cipation. Responsible for the guidance and completion of the overall study were
Mr. Henry E. Haley, Project Manager; Dr. Charles L. Kusik, Technical Director;
Mr. James I. Stevens, Environmental Coordinator; and Ms. Anne B. Littlef ield,
Administrative Coordinator.
Members of the environmental team were Dr. Indrakumar L. Jashnani,
Mr. Edmund H. Dohnert and Dr. Richard Stephens (consultant).
Within the individual industry studies we would like to acknowledge the
contributions of the following people.
Iron and Steel: Dr. Michel R. Mounier, Principal Investigator
Dr. Krishna Parameswaran
Petroleum Refining; Mr. R. Peter Stickles, Principal Investigator
Mr. Edward Interess
Mr. Stephen A. Reber
Dr. James Kittrell (consultant)
Dr. Leigh Short (consultant)
xiii
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Pulp and Paper:
Olefins:
Ammonia:
Aluminum:
Textiles:
Cement:
Glass:
Chlor-Alkali:
Phosphorus/
Phosphoric Acid;
Primary Copper:
Fertilizers:
Mr. Fred D. Lannazzi, Principal Investigator
Mr. Donald B. Sparrow
Mr. Edward Myskowski (consultant)
Mr. Karl P. Fagans
Mr. G. E. Wong
Mr. Stanley E. Dale, Principal Investigator
Mr. R. Peter Stickles
Mr. J. Kevin O'Neill
Mr. George B. Hegeman
Mr. John L. Sherff, Principal Investigator
Ms. Nancy J. Cunningham
Mr. Harry W. Lambe
Mr. Richard W. Hyde, Principal Investigator
Ms. Anne B. Littlefield
Dr. Charles L. Kusik
Mr* Edward L. Pepper
Mr. Edwin L. Field
Mr, John W. Rafferty
Dr. Douglas Shooter, Principal Investigator
Mr* Robert M. Green (consultant)
Mr* Edward S, Shanley
Dr, John Willard (consultant)
Drs Richard F. Heitmiller
Dr. Paul A. Huska, Principal Investigator
Ms. Anne B. Littlefield
Mr.. J.. Kevin O'Neill
Dr. D. William Lee, Principal Investigator
Mr, Michael Rossetti
Mr, R, Peter Stickles
Mr * Edward Interess
Dr, Ravindra M. Nadkarni
Mr. Roger E. Shamel, Principal Investigator
Mr. Harry W. Lambe
Mr^ Richard P. Schneider
Mr. William V. Keary, Principal Investigator
Mr. Harry W. Lambe
Mr. George C. Sweeney
Dr., Krishna Parameswaran
Dr. Ravindra M. Nadkarni, Principal Investigator
Dr, Michel R. Mounier
Dr. Krishna Parameswaran
Mr. John L, Sherff, Principal Investigator
Mr. Roger Shamel
Dr. Indrakumar L. Jashnani
xiv
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ENGLISH-METRIC (SI) CONVERSION FACTORS
To Convert From
To
Metre2
Pascal
Metre3
.t Joule
Pascal-second
Degree Celsius
Degree Kelvin
Metre
Metre /sec
3
Metre
2
Metre
Metre/sec
2
Metre /sec
i) Metre3
Ibf/sec) Watt
.c) Watt
Watt
Metre
Joule
3
Metre
Metre
Metre
Metre
Pascal-second
t Newton
Kilogram
Kilogram
Kilogram
Kilogram
Kilogram
Kilogram
Multiply By
4,046
101,325
0.1589
1,055
0.001
t"c = (t° -32)/1.8
0.3048
0.0004719
0.02831
0.09290
0.3048
0.00002580
0.003785
745.7
746.0
735.5
0.02540
3.60 x 106
1.000 x 10~3
1.000 x 10~6
0.00002540
1,609
0.1000
4.448
0.4536
0.02916
1,016
1,000
907.1
1,000
Acre
Atmosphere (normal)
Barrel (42 gal)
British Thermal Unit
Centipoise
Degree Fahrenheit
Degree Rankine
Foot
Foot /minute
3
Foot
2
Foot
Foot/sec
2
Foot /hr
Gallon (U.S. liquid)
Horsepower (550 ft-1
Horsepower (electric)
Horsepower (metric)
Inch
Kilowatt-hour
Litre
Micron
Mil
Mile (U.S. statute)
Poise
Pound force (avdp)
Pound mass (avdp)
Ton (assay)
Ton (long)
Ton (metric)
Ton (short)
Tonne
Source: American National Standards Institute, "Standard Metric Practice
Guide," March 15, 1973. (ANS72101-1973) (ASTM Designation E380-72)
xv
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I. INTRODUCTION
A. BACKGROUND
Industry in the United States purchases about 27 quads* annually, approxi-
mately 40% of total national energy usage.** This energy is in the form of
feedstocks, chemical reactions, space cooling and heating, process stream heat-
ing, and miscellaneous other purposes.
In many industrial sectors energy consumption can be reduced significantly
by better "housekeeping" (i.e., shutting off standby furnaces, better thermo-
stat control, elimination of steam and heat leaks, etc.) and greater emphasis
on optimization of energy usage. In addition, however, industry can be expected
to introduce new industrial practices or processes either to conserve energy or
to take advantage of a more readily available or less costly fuel. Such
changes in industrial practices may result in changes in air, water or solid
waste discharges. The EPA is interested in identifying the pollution loads of
such new energy-conserving industrial practices or processes and in determin-
ing where additional research, development, or demonstration is needed to char-
acterize and control the effluent streams.
B. CRITERIA FOR INDUSTRY SELECTION
In the first phase of this study we identified industry sectors that have
a potential for change, emphasizing those changes which have an environmental/
energy impact.
Industries were eliminated from further consideration within this assign-
ment if the only changes that could be envisioned were:
• energy conservation as a result of better policing or "housekeeping,"
• better waste heat utilization,
l
• fuel switching in steam raising, or
• power generation.
*1 quad = 1015 Btu
**Purchased electricity valued at an approximate fossil fuel equivalence of
10,500 Btu/kWh.
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After discussions with the EPA Project Officer and his advisors, industry
sectors were selected for further consideration and ranked using:
• Quantitative criteria based on the gross amount of energy (fossil
fuel and electric) purchased by industry sector as found in U.S.
Census figures and on information provided from industry sources.
The ammonia industry purchased 0.63 quads out of the 12.14 quads
purchased in 1971 by the 13 industries selected for study, or 2%
of the 27 quads purchased by all industry (see Table 1-1).
• Qualitative criteria relating to probability and potential for proc-
ess change, and the energy and effluent consequences of such changes.
In order to allow for as broad a coverage of technologies as possible, we
then reviewed the ranking, eliminating some industries in which the process
changes to be studied were similar to those in another industry planned for
study. We believe the final ranking resulting from these considerations identi-
fies those industry sectors which show the greatest possibility of energy con-
servation via process change. Further .details on this selection process can be
found in the Industry Priority Report prepared under this contract (Volume II).
On the basis of this ranking method, the ammonia industry appeared in
fourth place among the 13 industrial sectors listed.
TABLE 1-1
SUMMARY OF 1971 ENERGY PURCHASED IN SELECTED INDUSTRY SECTORS
SIC Code
. c In Which
Industry Sector 10 Btu/Yr Industry Found
1. Blase furnaces and steel mills 3.49(1) 3312
2. Petroleum refining 2.96(2' 2911
3. Paper and allied products 1.59 26
4. Oleflns 0.984*3' 2818
5. Ammonia 0.63**' 287
6. Aluminum 0.59 3334
7. Textiles 0.54 22
8. Cement 0.52 3241
9. Glass 0.31 3211, 3221, 3229
10. Alkalies and chlorine 0.24 2812
11. Phosphorus and phosphoric ,,,
acid production 0.12W 2819
12. Primary copper 0.081 3331
13. Fertilizers (excluding ammonia) 0.078 287
Estimate for 1967 reported by FEA Project Independence Blueprint,
p. 6-2, USGPO, November 1974.
Includes captive consumption
(FEA Project Independence Blueprint)
)
(4)
'includes captive consumption of energy from process byproducts
(
Oleflns only, includes energy of feedstocks: ADL estimates
Amonia feedstock energy included: ADL estimates
*5)AI>L estimates
Source: 1972 Census of Manufactures, EPA Project Independence Blueprint,
USGPO, November 1974, and ADL estimates.
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C. CRITERIA FOR PROCESS SELECTION
In this study we have focused on identifying changes in the primary pro-
duction processes which have clearly defined pollution consequences. In select-
ing those to be included in this study, we have considered the needs and limita-
tions of the EPA as discussed more completely in the Industry Priority Report
mentioned above. Specifically, energy conservation has been defined broadly
to include, in addition to process changes, conservation of energy or energy
form (gas, oil, coal) by a process or feedstock change. Natural gas has been
considered as having the highest energy form value followed in descending order
by oil, electric power, and coal. Thus, a switch from gas to electric power
would be considered energy conservation because electric power could be gener-
ated from coal, existing in abundant reserves in the United States in comparison
to natural gas. Moreover, pollution control methods resulting in energy con-
servation have been included within the scope of this study. Finally, emphasis
has been placed on process changes with near-term rather than long-term poten-
tial within the 15-year span of time of this study.
In addition to excluding from consideration better waste heat utilization,
"housekeeping," power generation, and fuel switching, as mentioned above, cer-
tain options have been excluded to avoid duplicating work being funded under
other contracts and to focus this study more strictly on "process changes."
Consequently, the following have also not been considered to be within the
scope of work:
• Carbon monoxide boilers (however, unique process vent streams yield-
ing recoverable energy could be mentioned);
• Fuel substitution in fired process heaters;
• Mining and'milling, agriculture, and animal husbandry;
• Substitution of scrap (such as iron, aluminum, glass, reclaimed tex-
tile, and paper) for virgin materials;
• Production of synthetic fuels from coal (low- and high-Btu gas,
synthetic crude, synthetic fuel oil, etc.); and
• All aspects of industry-related transportation (such as transporta-
tion of raw material).
(
D. SELECTION OF AMMONIA INDUSTRY PROCESS OPTIONS
Within each industry, the magnitude of energy use was an important criterion
in judging where the most significant energy savings might be realized, since
reduction in energy use reduces the amount of pollution generated in the energy
production step. Guided by this consideration, candidate options for in-depth
analysis were identified from the major energy consuming process steps with
known or potential environmental problems.
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After developing a list of candidate process options, we assessed sub-
j ectively
• pollution or environmental consequences of the process change,
• probability or potential for the change, and
>
• energy conservation consequences of the change.
Even though all of the candidate process options were large energy users,..
there was wide variation in energy use and estimated pollution loads between
options at the top and bottom of the list. A modest process change in a major
energy consuming process step could have more dramatic energy consequences
than a more technically significant process change in a process step whose
energy consumption is rather modest. For the lesser energy-using process steps
process options were selected for in-depth analysis only if a high probability
for process change and pollution consequences were perceived.
Because of the time and scope limitations for this study, we have not
attempted to prepare a comprehensive list of process options or to consider
•all economic, technological, institutional, legal or other factors affecting
implementation of these changes. Instead we have relied on our own background
experience, industry contacts, and the guidance of the Project Officer and EPA
advisors to choose promising process options.
The manufacture of ammonia is an integrated process, with subprocesses of:
• producing a hydrogen-rich stream from a hydrocarbon or carbon source
via reforming or partial oxidation,
• gas purification, and
• ammoniation.
The primary raw material for ammonia in the United. States is natural gas,
and about 95% of the ammonia manufactured in the United States is so produced.
Within the ammonia industry, our first objective was to identify major
energy issues and current and potential environmental problems. We have deter-
mined that changes are being considered to increase the efficiency of natural
gas processes and to utilize liquid hydrocarbons for a portion of the fuel
requirements. Also, because of a shortage of natural gas, several companies
are evaluating the option of producing ammonia from coal and liquid hydrocarbons.
We foresee little pollution impact as a result of the changes to improve
the conventional natural gas processes, the major one of which is preheating
the inlet air.
The major potential change will be seen in the new plants which, because'
of a shortage of natural gas, may have to use coal or heavy fuel oil both for
fuel and for feedstock. Such plants are not commercial in the United States
-------
at present, so they will constitute a major process change. Also, such plants
are likely to have pollution problems significantly greater than present
plants.
Therefore, we chose to analyze the process options:
• ammonia production based upon coal gasification, and
• ammonia production based upon heavy oil gasification.
The industry description in Chapter III is based on 1974, the last
representative year for which there was good statistical information.
For each process, we evaluated capital and operating costs to
pinpoint economic factors that would influence the adoption of new
technology. Investment costs for the base case and for pollution control
costs were also calculated on the same basis.
Recognizing that capital investment and energy costs have escalated
rapidly in the past few years and have greatly distorted the traditional
basis for making cost comparisons, we believe that the most meaningful
economic assessment of new process technology can only be made by
•using 1975 cost data. Consequently, in estimating operating costs
we developed costs representative of the first half of 1975, using
constant 1975 dollars for our comparative analysis of new and current
processes.
In each case, we estimated capital and operating costs for pollution
control systems expected to be capable of meeting existing EPA standards
for ambient air quality (S0£ and particulates) and, for aqueous
effluents, the "Best Available Technology." Our estimates were based
on the assumption that the pollution control technologies would be
adequate in achieving any standards for toxic and hazardous substances,
such as trace heavy metals, since there is little or no data available
on the probable magnitude of these problems.
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II. FINDINGS, CONCLUSIONS AND RECOMMENDATIONS
A. AMMONIA FROM COAL
1. Environmental Aspects
The problems associated with coal gasification are usually gaseous
sulfur, non-methane hydrocarbons, wastewaters, ash, and slag. In mak-
ing ammonia from gasified coal, sulfur must be removed for process reasons
and, once removed, it can be handled in an environmentally acceptable
manner by the addition of a sulfur recovery system. The hydrocarbons formed
in the gasifier are limited to small quantities of methane. The methane, and
any traces of higher hydrocarbons which do not take part in the synthesis, are
removed from the ammonia loop in a purge stream which is used as supplemental
fuel.
The wastewater volume is less in this process than in other coal gasifica-
tion processes, because the water is recycled to the reactor to provide steam.
The components of the ash and slag are similar to those produced in normal
industrial coal-fired boilers and are analogous in character, leachability,
etc.
There will be no unique problems for commercial ammonia plants based on
coal feedstock in meeting the anticipated environmental standards. Difficulties
will be no greater than those encountered in electric power generation or in
industrial coal-fired boilers.
2. Areas Where EPA Policies May Influence Future Choices of Alternatives
Use of strip-mined coal is attractive for this process alternative, because
it provides a lower cost for the feedstock and the stripped area is a potential
place in which to dispose of the large quantities of ash and slag. EPA's policy
in developing ground rules related to strip mining will influence the trend of
the ammonia industry in choosing feedstock and slag disposal methods and, thus,
in determining the overall course of the industry.
3. Practices/Processes Requiring Additional Research
In assessing the pollution aspects of the coal alternative, it is apparent
that one of the foremost areas requiring research and development efforts is
in the measurement and control of volatile materials found in coal, as well, as
arsenic, boron, fluorine, lead, mercury, and so on. In addition, the control
of volatile organic species with known or potential carcinogenic effects may
present a problem area for research and development efforts. Research and
development into the most environmentally acceptable method for the use or
-------
disposal of the large amounts of solid residues (principally coal ash) should
be undertaken to establish procedures and techniques that can be utilized to
achieve realistic costs and benefits.
B. AMMONIA FROM HEAVY FUEL OIL
1. Environmental Aspects
As with the coal alternative, the significant potential environmental
problem is associated with sulfur. Again, the sulfur must be removed for proc-
ess reasons by the addition of a sulfur recovery plant and results in byproduct
sulfur. The process wastewater is treatable in a conventional biological treat-
ment plant.
Therefore, there will be no unique problems for commercial ammonia plants
based on oil feedstock in meeting the anticipated environmental standards.
2. EPA Policies and Requirements for Additional Research
Since the cost for environmental control will not be a significant problem
and because the technology is in use, we anticipate little need for policy
changes or research on the part of EPA.
-------
TABLE II-l
COMPARISON OF BASE LINE AND ALTERNATIVE PROCESSES
Environmental
Incremental Pollution
Control costs ($/ton
of product).
Comments
Natural Gas1
(Base Case)
Costs comparable
for ammonia syn-
thesis section of
base case and each
alternative.
Coal
Gasification2
8.65
Slag disposal,
coal-pile run-
off treatment
and syngap puri-
fication wastewater.
Heavy Oil
Gasification3
3.46
Syngas purification
and soot recycle
purge wastewaters.
Energy
00
Consumption (10 Btu/
ton of product).
Comments
Process Economics Investment ($ millions)
Pollution Control and
Operating Cost ($/ton
of product)**
Comments
Details found in Tables IV-3, '4,' 5, 8, 10, and 11.
37
Includes natural
gas for feedstock
and fuel with small
amount of electrical
power. (Approximately
1% for pollution control).
63.4
98.18
Based on natural gas at
$0.85/106 Btu. (Expected
to increase to $2.50 in
future).
2.,
•Details found in Tables IV-14, £0, 22, and 24.
3 Details found in Tables IV-25, 30, and 31.
* Not determined but estimated at <$2.00/ton of product.
** Includes pretax return on investment.
36
Approximately 0.5%
increase for pol-
lution control
(0.17 x 106 Btu/ton).
101.1
146.07
Based on $15.40/
ton of coal
($0.71/106 Btu).
35.4
Approximately 0.4%
increase for pol-
lution control
(0.13 x 106 Btu/
ton) .
70.6
151.14
Based on $1.90/
106 Btu for high
sulfur fuel oil and
$2.40 for low
sulfur oil.
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TABLE II-2
AIR, WATER, AND SOLID WASTE STREAMS FROM BASE CASE AND
ALTERNATIVE FUEL SYSTEMS AND PROCESS MODIFICATIONS
Process Alternative
• Natural gas
(base case)
Air Emission
Synthesis loop purge.
Product loading emission.
Water Effluent Streams
Raw water treatment plant effluent.
Cooling tower blowdown.
Boiler blowdownT
Compressor blowdowni
Process condensate.
Solid Waste
Stiift converter catalyst,
Ammonia converter
catalyst.
• Coal gasification
Emissions as listed in base
case above.
Coal handling emissions.
Syngas purification emissions
Claus plant tail gas cleanup
vent.
Byproduct molten sulfur
storage & transfer emissions
System vents for pressure
let-down.
Effluents as listed in base case
above.
Coal, ash and slag pile runoff.
Wastewater from Rectisol Unit
Wastewater from sulfur recovery
plant tail gas cleanup.
Solid wastes as listed
in base case above.
Slag.
Catalyst from CO shift.
Molten sulfur.
Heavy oil gasification
Emissions as listed in base I Effluents as listed in base
case above. case above.
Syngas purification emissions Soot recycle system purge,
Claus plant tail gas clean- Wastewater from syngas puri-
up vent. I fication-
Byproduct molten sulfur Wastewater from sulfur recovery
storage & transfer emissions) plant tail gas cleanup .
System vents for pressure
let-down.
Solid wastes as listed
in base case above.
Catalyst from CO shift.
Molten sulfur.
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III. OVERVIEW OF THE UNITED STATES AMMONIA INDUSTRY
A. DESCRIPTION OF INDUSTRY
1. Introduction
In 1975, some 67 organizations produced anhydrous ammonia in the United
States, and operated a total of 94 ammonia plants. The rated design capacity
of the industry was approximately 16.9 million tons per year. Several addi-
tional ammonia plants are currently under construction. Ammonia production
expanded dramatically during the 1960's, almost tripling from 1960 to 1970.
Recent production increases have been far more modest, and there has been no
significant growth since 1972. (See Table III-l.)
Ammonia is the basic raw material for virtually all nitrogen fertilizers.
Furthermore, substantial quantities are also used for the production of
non-fertilizer materials, including plastics and resins, synthetic fibers,
and explosives.
Ammonia is used directly as a fertilizer and as a raw material
for other fertilizer products, including urea, ammonium nitrate, ammonium
phosphate, and complete mixed fertilizers. Non-fertilizer uses account for
about 20% of U.S. ammonia consumption. A use pattern for ammonia is provided
in Table III-2. Ammonium nitrate is used as an explosive in surface mining
applications. Urea finds significant uses outside of the fertilizer industry,
principally as an animal feed and as a component of thermo-setting resins.
Natural gas is the basic feedstock for virtually all U.S. ammonia pro-
duction, with minor amounts of ammonia being produced from such byproduct
streams as chlorine-cell hydrogen and refinery off-gas. In 1973, ammonia
manufacture required 591 x 10^ Btu of natural gas. This represented 3% of
the total U.S. natural gas supply. Energy requirements for ammonia manufac-
ture are provided in Table III-3. In view of the critically short natural
gas situation, increasing interest is being shown in the use of coal or
petroleum as a basic feedstock. However, it is not expected that plants
using such feedstocks will be in operation before the early 1980"s.
International trade in nitrogen compounds is significant for the U.S.
industry. Because supplies were needed to meet growing domestic require-
ments, exports have declines from about 1.8 million tons of ammonia equiva-
lent in 1973 to 1.0 million in 1974. Imports have been increasing and now1
are equal to exports. Because of geographical and individual company con-> '
siderations, there are generally both imports and exports of anhydrous
10
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TABLE III-l
SYNTHETIC AMMONIA - U.S. PRODUCTION HISTORY
(000 Short Tons)
1960
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975 (Est.)
4,818
8,869
10,605
12,194
12,120
12,769
13,824
14,538
15,193
15,093
15,698
'15,680
Source: U.S. Department of Commerce, Current Industrial Reports
TABLE III-2
USES AND SOURCES OF AMMONIA - 1974
OOP Short Tons _X_
Fertilizers for Domestic Use
Non-Fertilizer Uses
Ammonium Nitrate Explosives
Urea - Animal Feeds
- Resins and Other Uses
Nitric Acid (except for Ammonium Nitrate
and Fertilizers)
Caprolactam (contained in product only)
Acrylonitrile
Amines
All Other
Subtotal
Exports (Ammonia and Derivatives)
Losses, Inventory Change, & Unaccounted For
Total Uses
Production - Synthetic
- Coke Oven & Other
Imports (Ammonia and Derivatives)
Total Supply
10,800
550
350
350
450
40
410
260
800
64
3,210
19
6
11
100Z
Source: U.S. Department of Commerce, U.S. Department of Agriculture
and ADL Estimates.
11
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TABLE III-3
1973 ENERGY USE FOR AMMONIA MANUFACTURE
Fuel Use
Electric Power Use
Total
Middle Atlantic
South Atlantic
East North Central
West North Central
East South Central
West South Central
Mountain
Pacific
Alaska
Total
(1012 BTU)
20.3
36.2
36.0
83.2
62.1
280.2
14.7
42.0
17.7
(106 KWH)
34.4
41.7
41.5
96.7
71.5
327.3
19.7
50.4
20.4
1 ? 1
(10 BTTir
0.4
0.4
0.4
1.0
0.8
3.4
0.2
0.5
0.2
(1012 BTU)
20.7
36.6
36.4
84.2
62.9
283.6
14.9
42.5
17.9
592.4
703.6
7.4
599.8
At 10,500 Btu/kWh.
2 12
Of this amount, all but 1.1 (10 ) Btu was as natural gas.
Source: Arthur D. Little, Inc.,"Economic Impact of Shortages on the Fertilizer Industry,"
Report to the Federal Energy Administration, January 1975.
-------
ammonia and its derivatives. Because of the potential limited availability
of natural gas for further ammonia plant expansion, the United States may
become a major net importer in the not-too-distant future. However, the
potential for shifting to coal or petroleum as a feedstock may eliminate the
need for such import dependence.
2. Plant Characteristics
A modern ammonia plant is typical of most chemical process units with a
realistic useable life of 15 to 20 years or longer. Depreciation is usually
on the basis of an 11- to 15-year life.
There are currently 110 ammonia plants in operation in the United States,
with 11 under construction or contracted for. Following significant techno-
logical developments in the late 1950's, the size of the typical ammonia
plant increased substantially to a minimum of 600 tons per day, with most new
ones being in the range of 1,000 to 1,200 tons per day. The larger sizes
were dictated by the favorable economics of using centrifugal compressors in
place of reciprocating ones. However, plants built prior to these develop-
ments, with capacities from 50 to 300 tons per day, are still operating.
About 53 plants are over ten years old, and represent 41% of total U.S.
capacity. (See Table III-4.)
TABLE III-4
AGE OF AMMONIA PLANTS OPERATING
AT BEGINNING OF 1976
Total Capacity
Number of 000 tons
Year of First Operation Plants per year \
Prior to 1960 27 3,521 19
1960 - 1965 26 3,980 22
1966 - 1970 36 9,941 54
1971 - 1975 4 889 5_
93 18,331 100%
13
-------
Almost all U.S. ammonia capacity is based on natural gas for feedstock,
so the location of a plant depends on access to natural gas. However,
because of the nation's widespread pipeline distribution system, ammonia
plants are widely scattered. There is a great concentration of ammonia
plants along the U.S. Gulf Coast, in Texas, Louisiana, and Mississippi with
direct access to natural gas, particularly low-cost intrastate gas. In addi-
tion to having low-cost natural gas, this location has low-cost transport to
the agricultural heartland in the upper Midwest, by barge shipment up the
Mississippi, and more recently through the development of an ammonia pipe-
line running from the New Orleans area into the eastern and western Mid^
western states. The distribution of ammonia plants by region is provided in
Table III-5.
TABLE III-5
ANHYDROUS AMMONIA CAPACITY BY REGION IN 1974
Number
of Plants
Capacity
(000 Short Tons
Per Year)
Middle Atlantic
South Atlantic
East North Central
West North Central
East South Central
West South Central
Mountain
Pacific
Alaska
6
6
4
15
7
31
6
12
1
859
1,042
1,035
2,417
1,786
8,177
493
1,259
510
5
6
6
14
10
47
3
7
3
Total
88
17,578
100%
Multiple plants at the same site counted as one.
14
-------
3. Integration and Concentration
Very few ammonia producers sell ammonia strictly in the merchant market.
There is a substantial degree of integration to derivatives, both for ferti-
lizer and non-fertilizer purposes. In fact, for many producers, ammonia is
produced solely to be used for the manufacture of derivatives or to comple-
ment other fertilizer operations.
Ammonia is produced by 67 different companies: 12 companies represent
55% of the total capacity. Major companies and their proportion of the total
capacity are provided in Figure III-l.
« -
= 8
I I
8
O
»
*-
—
o S
o
O
8
£
(1) Based on Production Capacity. 12 Companies Represent 54.9% of the Total Capacity.
FIGURE III-l. MARKET SHARE OF MAJOR U.S. SYNTHETIC
AMMONIA PRODUCERS, 1974
15
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B. ECONOMIC OUTLOOK
The rate of growth in the consumption of fertilizer nitrogen in the
United States has dropped off significantly over that which prevailed for the
years prior to 1970. We have summarized prior consumption data in Table III-6
together with our estimates of the U.S. consumption in 1980 and 1985.
TABLE III-6
FERTILIZER NITROGEN CONSUMPTION
000 tons NH_
OOP tons N equivalent
1960 2,738 3,339
1965 4,639 5,657
1970 7,459 9,096
1971 8,134 9,920
1972 8,016 9,776
1973 8,339 10,170
1974 9,157 11,167
1975 8,608 10,498
1980 12,300 15,000
1985 (@ 6%/yr) 16,500 20,122
Growth in consumption for the period of 1960 to 1970 averaged 10.5% per
year. This has dropped off significantly following 1970. For the four year
period from 1970 to 1974, the average annual growth was 5.3%. The decline
in the growth rate in nitrogen consumption in recent years may in part be due
to a saturation in the market after many years of very rapid growth. More
important contributors, however, were worldwide shortages of nitrogen fer-
tilizer and very significant price increases. In 1975, consumption declined
6% from the previous year. The recent performance of nitrogen fertilizer
consumption casts some doubt on future growth rates. However, there is a
fundamental need for increasing quantities, and an average growth rate of 6%
16
-------
per year through 1985 is realistic. Therefore, in Table III-7, we have
included our estimates of fertilizer nitrogen consumption in 1980 and 1985,
on the basis of a 6% annual growth rate for the next ten years.
TABLE III-7
PROJECTED U.S. NITROGEN SUPPLY/DEMAND BALANCE
thousand short tons of ammonia
1973/74 1979/80
Uses
U.S. fertilizer consumption 11,170 15,000
Non-fertilizer uses 3,230 4,570
Losses, inventory change, etc. 1,230 1,950
Exports 1,510 600
Total 17,140 22,120
Sources
Synthetic ammonia production 15,600 20,240
Other production 240 240
Imports 1.300 1,640
Total 17,140 22,120
Projected, based on plants now in place or under construction and a 90%
operating rate.
Needs, based on other projections in the table.
Non-fertilizer uses of ammonia are likewise expected to continue their
historic growth rate of about 6% per year, reaching about 4.6 million tons of
ammonia equivalent by 1979/80. A projected balance between supply and demand
for the United States is provided in Table III-7. In 1973/74, exports
exceeded imports by a small margin. The United States has traditionally been
a significant exporter, but at the present time imports may be slightly in
excess of exports.
While domestic production is expected to expand quite significantly with
plants already under construction, those plants will not be able to keep pace
with consumption through 1980. If no existing plants are closed down, the
United States will produce slightly over 20 million tons of ammonia in 1980,
but will need more than 22 million tons, even if exports are cut back
drastically. If exports are maintained at the present level, the United States
will need more than 23 million tons of ammonia equivalent. This implies that
the United States will have to expand.either imports or domestic production
significantly.
i
17
-------
The construction of new ammonia plants is becoming increasingly difficult
because of the shortage of natural gas. It is nearly impossible at present
to build an ammonia plant based on natural gas in the interstate system. All
new ammonia plants under construction are to be based on gas produced within
the same state. Even intrastate gas is difficult to obtain, and prices are
high. For this reason, producers may begin to consider alternates to natural
gas, such as coal and petroleum, as feedstocks for ammonia plants.
The economics of ammonia manufacture are sensitive to the cost of both
feedstock and capital investment. Both of these factors have escalated very
considerably in the last few years. A plant built in 1968 to produce 1,000
tons a day cost just over $25 million. A similar size plant built today, with
only some minor improvements, would cost about $63 million. In the 1960's
it was commonplace for ammonia plants to obtain natural gas for about $0.20
per 106 Btu: today it is difficult to find gas for less than $1.00 per 10*> Btu.
The difference in the cost of manufacture, including an allowance to provide
a return on investment, is provided in Table III-8. Many plants built in the
1960's still enjoy low-cost natural gas under long-term contracts and still
have the economics shown, which indicate that ammonia could be sold profitably
at less than $45 per short ton. However, if new investment is to be
attracted, based on the higher feedstock prices, ammonia prices must be such
as to allow for profitable operations, and this price for ammonia must be
about $100 per ton. Thus, today there is a significant variation in the
profitability of ammonia plants in the United States depending both on when
they were built and the current price for natural gas.
18
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Year Built
Capacity - Tons/Stream Day
Annual Production - Tons
Fixed Capital Investment
TABLE III-8
CHANGE IN THE ECONOMICS OF AMMONIA MANUFACTURE
Plant Built in
mid-60Ts
1968
1,000
340,000
$25.6 Million
Similar
Plant Built in
1975
1975
1,000
340,000
$63.4.Million
Natural Gas Cost - $/10 Btu (HHV)
Costs
Natural Gas 35.8«10 Btu/Ton
33-106 Btu/Ton
Power & Miscellaneous Supplies
Labor, Maintenance, & Overheads
Subtotal
Investment-Related Costs
Depreciation 11 years
Local Taxes & Insurance 1.5%
Return on Investment (pretax) 20%
Subtotal
0.20
$/Short Ton %
7.16 17%
1.00
$/Short Ton
5.17
7.16
19.49
6.84
1.13
15.06
23.03
12
17
46
16
3
35
54
33.00
5.17
7.12
45.29
16.95
2.80
37.29
57.04
32%
5
7
44
17
3
36
56
TOTAL
42.52
100%
102.33
100%
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IV. COMPARISON OF CURRENT AND ALTERNATIVE PROCESSES
If the natural gas.shortage persists, the ammonia industry could be
expected to implement the use of alternate feedstocks, such as coal and heavy
fuel oil, in 50-100% of new plant construction from 1985 forward, and one or
two new plants may be built prior to that time. During this period, 5,000
tons per day of new ammonia capacity will be needed each year. Given this
needed rate of new construction, we estimate that 2,500 to 5,000 tons per day
of new capacity based on coal or heavy oil feedstocks will be built each year.
This corresponds to two to five new plants per year of 1,000 to 1,500 tons per
day capacity. New plants as described here, are to provide new capacity rather
than to replace existing plants based on natural gas.
To accomplish this for the coal alternative, incremental capital costs of
$111 per annual ton of ammonia (a 60% increase) and incremental production
costs of $17 per ton of ammonia are anticipated, including $8.65 per ton of
ammonia for pollution abatement to satisfy the environmental regulations
expected for this alternative process for producing ammonia. In addition, the
needed control technology will mean an expenditure of energy equivalent to
165 x 10^ Btu per ton of ammonia.
•>
To accomplish this for the heavy oil alternative, capital costs of $21
per annual ton of ammonia (a 24% increase) and incremental production costs of
$45 per ton of ammonia are anticipated, including $3.46 per ton of ammonia
for pollution abatement to satisfy the environmental regulations expected for
this alternative process for producing ammonia. In addition, the needed
control technology will mean an expenditure of energy equivalent to 125 x
103 Btu per ton of ammonia.
Nevertheless, these process alternatives appear promising; however, they
will require additional research to establish the pollutional character and
appropriate control technology to verify the results of this assessment.
A. REASONS FOR CHOOSING OPTIONS FOR IN-DEPTH ANALYSIS
The review of the implications of producing ammonia from coal or oil is
necessitated by the real possibility that the processes may be implemented in
the United States before 1985, and possibly as early as 1980. The use of coal
or oil will be caused by a reduced supply of natural gas, high prices for
natural gas, or both.
The United States is faced with a continuing need for increasing its
capacity to produce ammonia and is also faced with a rapid decline in the
availability of natural gas - the raw material that has been used almost
exclusively for the past 30 years. The present and projected scarcity of
natural gas has been well documented. The ammonia industry cannot count on
20
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gas as a basis for substantial future growth in this country. Those plants
now using gas are faced with stretching their supply by converting heating
applications to other fuels and by ensuring they receive proper recognition in
the setting of priorities and allocations of available gas supplies.
In addition to the problems concerning the availability of new gas, prices
have risen significantly. Until recently, ammonia plants purchased gas at as
low as $0.15 per MCF, and few paid more than $0.50. Because a natural-gas-
based ammonia plant costs less and is less expensive to operate than either
coal- or oil-based plants, ammonia plants have not been designed for operation
on coal or oil in areas where natural gas is available. Today, the price of
natural gas is much higher, particularly to new customers who are not protected
by old contracts. And it is nearly impossible for a new plant to obtain sup-
plies of natural gas from the interstate pipeline system. Thus, new plants
must be built using gas produced "in state" which is not subject to federal
regulation. Such gas is available - although not readily - and prices range
from $0.50 to $2.00 per MCF. Furthermore, contracts written today usually
have escalation clauses allowing future price increases.
An ammonia producer wishing to expand is faced with the options:
• Try to find a supply of intrastate natural gas, pay a high price, and
assume the risk of further escalation;
• Plan to import ammonia, either by contracting for it or investing
in an ammonia plant in a foreign country that has lower-cost gas; or
• Put up an ammonia plant based on.coal or petroleum.
These are not easy choices. The federal regulations concerning natural gas
may change, thus significantly affecting the price and availability of natural
gas in this country. • And some new capacity could be based on isolated pockets
of natural gas, mine drainage gas, or byproduct gases. However, these rep-
resent opportunistic situations rather than a basis for industry expansion.
Foreign investment, when it is made, must be made in countries with sur-
plus gas. By and large, such countries are poor risks for investors, for they
generally try to exact a high price for the gas, even though they have little
alternative use for it. There would also be high capital and operating costs
because of insufficient infrastructure.
i
On the other hand, before investing in a .plant based on oil or coal, one
must be confident that raw materials prices are and will continue to be suffi-
ciently lower than those for natural gas to justify the greater investment.
The technology for the partial oxidation of fuel oil is much better
established than that for using coal, and also the handling of oil is easier
than handling of coal and disposing of ash. However, the supply and price of
coal is more secure than for petroleum. On balance, it appears that in the
long run, coal will be the preferred raw material while petroleum remains a
possibility. Easing of supplies of natural gas would mitigate against either
route.
21
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B. COMPARISON OF CURRENT AND ALTERNATIVE PROCESSES
1. Methodology
a. Overview
The base case technology that we use for comparison within this study is
production of ammonia based on steam reforming using natural gas as the feed-
stock. The alternatives as defined in this study are ammonia production based
on coal and on heavy fuel oil. In each of the alternatives the feedstock is
gasified to produce a synthesis gas (syngas) which is then used to produce
ammonia. Because the changes discussed here are all prior to the actual
synthesis loop and are related to production of the synthesis gas, we have
segmented the discussion of the alternatives as follows:
• Receiving and Storage of Feedstock;
• Gasification (if needed) to produce raw syngas;
• Syngas purification; and
• Ammonia synthesis loop.
As a guide for interpreting the energy and pollution effects of chang-
ing feedstocks on the economics of manufacturing ammonia, we-have estimated
typical investments and operating costs of new plants using natural gas,
coal, and heavy fuel oil feedstocks, based on conditions prevailing during
March 1975. As the basis for our estimates, we selected the high-pressure
reforming centrifugal-compressor type of ammonia plant which has dominated
new construction for the past several years (and is expected to continue to
do so) and 1,000 tons per stream day for the rated capacity.
Including 90 days of ammonia storage (90,000 tons) we estimated that a
natural gas plant would cost $63.4 million, an oil oxidation plant $70.6
million, and a high-pressure coal oxidation plant $101.1 million.
Using high-sulfur Illinois coal (10,800 Btu/lb as mined) charged at
$0.71 per thousand Btu, gas at $0.85 per thousand Btu, and oil at $1.90 per
thousand Btu, the manufacturing costs are substantially lower for the natural-
gas-based plant than for the others because of the sizeable differences in
feedstock cost and fixed investment.
To allow for a modest return on fixed capital, an amount equivalent to
20% of the investment was added to the manufacturing cost as shown. It
appears that the coal- and oil-based plants are not very competitive under
our estimate conditions; assuming, of course, that natural gas is available
at 1975 prices.
Within Chapter V we discuss the impact of fuel availability and prices
on the cost of producing ammonia and show that - at price ranges different
from those prevalent in March 1975 - coal and oil will look attractive as
feedstocks.
22
-------
b. Cost Factors Relevant to Comparing Alternative Processes to the Base Line
The costs of raw materials and byproducts are based on costs prevailing
in the first half of 1975.
Energy costs for coal, oil, and natural gas have been based on the exist-
ing prices paid in March 1975 by electric utilities. These figures are shown
in Table IV-I for the regions considered in our comparisons. We have found
that such prices are consistent with prices reported by SIC sector in the 1972
Census. We have escalated such figures by fuel cost indices to 1975. Where-
ever we have diverged from the March 1975 cost paid by electric utilities we
have so indicated. Similarly, energy credits are taken on a consistent basis.
It should be recognized that most of the gas.and electric utility industry
is regulated and, therefore, the price prevalent in the first half of 1975
would not be indicative of what a new plant built on a greenfield site would
have to pay. (Estimates indicate that the cost of natural gas for such new
facilities might well be equal to that of the price of oil.) Also the price
of electric power, to reflect higher fuel costs, might be two or three times
higher than electric power costs in early 1975.
The cost of water used purely for cooling purposes was based on $0.03
per thousand gallons. The cost of process water is based on $0.20 per
thousand gallons.
We attempted to use the cost of labor wages published by the Bureau of
Labor Statistics for March 1975 by industry sector. However, in the ammonia
sector, such average labor costs are not generally representative, as shown
in Table IV-2. Therefore, we used a higher cost of $6.00 per hour, which
better reflects the labor rate. This discrepancy between Bureau of Labor
Statistics figures and what we feel to be the current labor rate occurs
because of the SIC code grouping used. Agricultural chemicals production,
which includes ammonia, involves many industry sections that use relatively
low-cost labor. However, ammonia production is a more highly specialized
operation.
The costs of maintenance, labor, and materials have been taken as 3%
of the initial investment costs for plants based on natural gas, and 3.5 and
4.0%, respectively, for oil- and coal-based plants. This reflects a slightly
higher maintenance requirement for such plants. Labor overhead has been taken
at 35% of the labor wages. This would account for fringe benefits, such as
vacations, holidays, and sick pay, as well as overtime pay.
Miscellaneous variable costs and credits include such items as chemicals,
catalysts, supplies, and such services as analytical services.
Under the category of fixed costs 'we have shown plant overhead at 70% of
labor and supervision, which would include items not allocated to the produc-
tion sector. Local taxes and insurance are taken as 1.5% of the initial
capital investment.
To distribute the cost of the capital assets (less salvage value if any)
over the estimated life of the facility, annual depreciation is calculated on a
straight-line basis over 11 years for the ammonia industry. In addition to
being used often in feasibility studies, such a depreciation method and period
are consistent with IRS guidelines.
23
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TABLE IV-1
BENCHMARK ENERGY COSTS FOR COAL, OIL, GAS AND ELECTRIC POWER
IN MARCH 1975
17 1 • 1 ,
Fuel prices
($/106 Btu)
Coal Oil Gas
Illinois 0.71 - 0.85
Middle West - 2.00
Gulf Coast - - 0.70
(Texas)
$/kWh2
Power
0.019
0.014
Average fuel prices paid by steam-electric plants.
2
1974 power costs updated to 1975 using factor of 1.17.
Source: Chemical Week, October 22, 1975.
TABLE IV-2
BENCHMARK EMPLOYEE EARNINGS
MARCH 1975
Hourly
Industry SIC Code Earnings*
Ammonia 287-Agricultural chemicals $4.43
Fertilizers 287-Agricultural chemicals 4.43
Petroleum Refining 291-Petroleum refining 6.75
*
Gross earnings of production or non-supervisory workers.
Source: Employment and Earnings, Vol. 21, No. 11, May 1975, Bureau
of Labor Statistics, U.S. Department of Labor.
We have shown an annual allowance for "return on investment" (pre-tax)
amounting to 20% of initial capital investment. The allowance is allocated
to a ton of product, assuming that the facility operates at 100% capacity.
24
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2. Ammonia Production Based on Natural Gas
Ammonia is used as a source of nitrogen for the production of most
fertilizers and is made by the reaction of atmospheric nitrogen with hydro-
gen. All processes manufacturing ammonia utilize atmospheric air as the
source of nitrogen. Hydrogen can be produced from almost any hydrocarbon
or carbonaceous material. Careful consideration is given to the choice of
raw material, because operating costs for ammonia production are greatly
influenced by the cost of producing hydrogen, which in turn is very dependent
on raw material cost. Possible sources of hydrogen are natural gas, LPG,
naphtha, heavy fuel oil, coal and lignite, electrolytic hydrogen, and by-
product hydrogen. As the base case, we selected the high-pressure reforming
centrifugal-compressor type of ammonia plant which has dominated new construc-
tion for the past several years.
a. Process Description
There are four major operations in manufacturing ammonia: gas prepara-
tion, carbon monoxide conversion, gas purification, and ammonia synthesis.
(1) Gas Preparation
Several variations of ammonia synthesis gas processes are available:
steam reforming, partial oxidation, the autothermal process, and gasification
of coal. The only process of importance in the United States is steam reform-
ing using natural gas as the feedstock, as shown in Figure IV-1.
The primary steam reforming of natural gas is carried out in externally
heated tubes containing a reforming catalyst. The feed consists of steam and
desulfurized natural gas. A controlled amount of air is added to the primary
reformer effluent as it enters the secondary reformer. The secondary reforming
is accomplished in a packed catalyst bed in which the heat required for reform-
ing is provided by the partial combustion of the primary reformer effluent.
Steam is produced from the flue gas out of the primary reformer and from the
process gas leaving the secondary reformer by heat recovery. Plants that have
a package boiler typically use it only during startup operations unless steam
is needed for the manufacture of derivatives. In the ammonia plant, the
steam balance is' such that little or no external steam generation is needed
during capacity or near-capacity operation.
(2) Carbon Monoxide Conversion
The gas leaving the gas preparation unit is cooled and passed through a
converter containing a Mo-Co sulfided catalyst. The carbon monoxide reacts
with steam to produce carbon dioxide and hydrogen by the water-gas shift
reaction:
CO + H0 -> C0 + H
25
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Nalural-Cai Fetd
Niphthi Fnd
Liquid Ammonia
to Proceu or Storage'
Figure IV-1. Flow Diagram for Synthesizing Ammonia
By Steam-Reforming Process
All new processes employ monoethanolamine, hot potassium carbonate,
Sulphinpl®, or Fluor® solvent to remove the carbon dioxide from the gas stream.
(3) Final Gas Purification
The small amounts of carbon oxides remaining in the synthesis gas must be
removed. The three processes that are available are methanation, ammoniacal
copper chloride solution absorption, and liquid nitrogen wash.
(4) Ammonia Synthesis
Ammonia is synthesized by the reaction between hydrogen and nitrogen at
elevated temperatures and pressures in the presence of a catalyst.
b. Production Cost
Table IV-3 shows typical costs of a large plant (now typical of the U.S.
industry). Based on a plant with a capacity of 1000 tons per stream day (which
would produce 340,000 tons per year), a Gulf Coast location and March 1975
energy and fuel costs, the estimated cost of producing ammonia would be $127.56
per ton. Of this total cost, $29.38, or 23% represents the cost of the energy
inputs. About 14% of the cost is attributable to the feedstock itself, in,this
case natural gas.
26
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TABLE IV-3
Product: Ammonla
ESTIMATED PRODUCTION COST OF AMMONIA
FROM NATURAL GAS (BASE CASE)
Process; Steam-methane reforming Location! Gulf Coast
.Design loop tons/stream day _. . , -,,, lnl. nnn
Capacity • Fixed Investment :$63.400.OOP
Annual Productioni 340,000 tons
Stream Days/Yr ; 340
VARIABLE COSTS
Natural Gas Feedstock
Natural Gas Fuel
Electric Power
Energy Subtotal
Catalysts & Chemicals
Cooling Water
Total
SEMI-VARIABLE COSTS
Direct Operating Labor (Wages)
Direct Supervisory Wages
Maintenance Labor, Materials &
Supplies
Labor Overhead
Total
FIXED COSTS
Plant Overhead
Local Taxes & Insurance
Depreciation
Total
TOTAL PRODUCTION COSTS
Return on Investment (Pretax)
TOTAL
Units Used in
Costing or
Annual Cost
Basis
106 Btu
106 Btu
kHh
1000 gal
24 men
4 foremen
1 superintendent
3% of investment/
yr
35% of labor &
supervision
70% of labor &
supervision
1.5X of ,'
investment/yr
11 yr; straight
line
20% of investment/
$/Unit
0.85
0.85
0.014
0.03
$12,000/yr
$18,000/yr
825,000/yr
Units Consumed
per Ton of
Product
20.4
12.6
95
108
S/Ton of
Product
17.34
10.71
1.33
29.38
0.60
3.24
33.22
0.85
0.21
0.07
5.59
0.40
7.12
0.80
2.80
16.95
20.55
60.89
37.29
98.18
27
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c. Energy Usage
Table IV-4 provides a summary of fuel use, by type, for ammonia produc-
tion. These numbers are based on typical U.S. processes. They do not provide
averages for the total industry; rather, they provide the fuel consumption
for the most typical process for producing the fertilizer in the United States.
To determine regional use, we estimated production in each of the regions,
based on the capacities of production facilities in those regions. Table' IV-6
provides a summary of energy use by region and by energy form.
To put the ammonia industry in perspective, the United States consumed
approximately 22,600 x 10^2 stu of natural gas for all purposes in 1973. The
manufacture of ammonia for fertilizers required 490 x 10^ Btu, or about 2.2%
of total U.S. natural gas use.
Regional fuel use is in accord with the regional production of the large
fuel users. Thus, the West South Central region, which has a very large
ammonia capacity, represents some 47% of the fuel used by the ammonia industry.
Ammonia plants also are major users of electric power. The most significant
electrical energy-using region is the West South Central.
d. Effluent Controls Required for the Base-Case Use of Natural Gas
The manufacture of ammonia from natural gas has associated with it very
few environmental problems. Schematic representation of the flowsheet, show-
ing the potential air, water and solid waste emissions, is given in Figure IV-2.
The nature of these emissions is summarized in Table IV-7, and a detailed
discussion of each is given in the following sections, including consideration
of emission sources and rates, available control technology, and the cost of
control. The example calculations given in this section are based on a 1000-
ton-per-stream-day ammonia plant using a natural gas feedstock that has
negligible sulfur content. The EPA established effluent limitations for the
Fertilizer Industry, 40 CFR 418, 8 April 1974. The ammonia industry portion
(subpart B) of the guidelines was based on information provided in the
Development Document.* Although typical ranges of concentrations are given
for cooling towers and boiler blowdown wastewater streams, as well as for
process condensate streams, the Development Document for the fertilizer
industry presented less quantitative data on wastewater characteristics than
is found in the Development Documents for other industries. Consequently,
it has been necessary to rely on broad estimates of capital and operating
costs for much of the pollution control costs.
*' Development Document for Effluent Limitations Guidelines and New Source
Performance Standards for the Basic Fertilizer Chemicals Segment of the
Fertilizer Manufacturing Point Source Category," U.S. Environmental Protec-
tion Agency, March 1974, EPA~440/l-74-011-a."
28
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TABLE IV-4
ENERGY USE IN AMMONIA PRODUCTION
Energy Factors (units per ton)
Natural Gas Total
Electric or Fuel Oil Steam 10^ Btu
Product or Operation (kWh) (106Btu) (103 lb) Equivalents
2
Ammonia 45.5 36.5 - 37.0
Table IV-5 describes where the natural gas is used within the process.
2
Approximately 3.5 million Btu are available from recycle of ammonia
synthesis loop purge gas.
Source: Arthur D. Little, Inc., "Economic Impact of Shortages on the
Fertilizer Industry," Report to the Federal Energy Administration,
January 1975.
TABLE IV-5
NATURAL GAS CONSUMPTION IN AMMONIA PRODUCTION*
(106 Btu/ton product)
Feedstock Reformer Fuel
20.4 12.6**
*Using centrifugal compressors
**Total consumption is 16.1 million Btu. However, 3.5
million Btu per ton are available from tail gas from the
synthesis loop.
Source: Arthur D. Little, Inc. estimates.
29
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TABLE IV-6
1973 REGIONAL FUEL AND POWER USE: AMMONIA
Capacity
New England
Middle Atlantic
South Atlantic
E.N. Central
W.N. Central
E.S. Central
W.S. Central
Mountain
Pacific
Alaska
TOTAL
Total
859
1,042
1,035
2,417
1,786
8,177
493
1,259
510
17,578
(OOP tpy)
Based on
Natural Gas
585
1,042
1,035
2,394
1,786
8,062
423
1,208
510
17,045
Production
Based on
Natural Gas
(000 TPY)
515
917
911
2,106
1,571
7,093
372
1,063
449
14,997
Natural Gas Used
Feedstock @
23.9 x 106 Btu
(1012 Btu)
12.3
21.9
21.8
50.3
37.6
169.5
8.9
25.4
10.7
Reformers &
Boilers @
15.6 x 106 Btu
(101Z Btu)
8.0
14.3
14.2
32.9
23.2
110.7
5-8
16.6
7.0
Fuel
Oil
Used
1.3
358.4
232.7
1.3
Electric Power
45.5 kWh1
106 kWh
34.4
41.7
41.5
96.7
71.5
327.3
19.7
50.4
20.4
703.6
Taken on total production—not just natural gas plants.
Source: Arthur D. Little, Inc., "Economic Impact of Shortages on the Fertilizer Industry,1'
Report to the Federal Energy Administration, January 1975.
Gas Preparation
Carbon
Monoxide
Shift
Conversion
Final
Purification
Ammonia
Synthesis
Loop
Storage
and
Loading
Figure IV-2. Ammonia Production Based on Natural Gas Feedstock
30
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TABLE IV-7
EMISSIONS FROM AMMONIA PLANTS BASED ON NATURAL GAS
WATER EFFLUENTS*
Raw water treatment plant
Cooling tower blowdown
Boiler blowdown
Compressor blowdown
Process condensate
Notes
jf luent
AIR EMISSIONS*
'!> Synthesis loop purge
Product loading emission
burned as supple-
mental fuel in
reformer
SOLID WASTES*
\T\ Shift converter catalyst
r i
2| Ammonia converter catalyst
recovered
*Keyed to Figure IV-2.
31
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(3) Energy Aspects
The best practicable control technologies required to achieve waste-
water effluent limitations by 1977 for ammonia production have a high energy
component. However, in relation to the total energy requirements for the
production of ammonia, the energy requirements for water pollution control
are estimated to result in an increase of only b.9%. These estimates are
based on the assumption that the best practicable technology is steam strip-
ping for ammonia. Process steam generated above process requirements can
be used for the treatment technology} and thus, it would not increase
requirements for scarce fuels such as natural gas in typical plants. There-
fore, these environmental requirements should not significantly affect the
production of ammonia. However, alternative fuels (i.e., fuel oil) may be
utilized to produce the steam required in the effluent control technology
in some plants if natural gas is very scarce, thus posing some additional,
but minor, problems of control. A summary of the energy aspects are pre-
sented in Table IV-8.
(4) Cost Aspects
Current pollution control regulations will have only moderate impact
on investment requirements and operating costs in the ammonia industry, as
shown in Table IV-9. The energy component of water pollution control costs
for the control of nitrogen effluent from ammonia plants is 73% of the total,
as shown in Table IV-10. However, these figures are deceiving in that it
would be more logical to compare the increased energy requirements to the
total energy requirements for the production of ammonia. On such a basis,
nitrogen effluent controls would have only a slight impact on the energy
requirements for the production of ammonia.
TABLE IV-8
ESTIMATED ENERGY IMPACT FOR AMMONIA PRODUCTION OF CURRENT
POLLUTION CONTROL REGULATIONS
Energy Requirements! Power (kwh) Fuel (1Q6 Btu) Total1 (106 Btu)
2
Production Cper ton of product) 45.5 36.5 40
Pollution control (per ton of product) 7 0.3 0.37
Percent Increase ".7 0.9
1. Assumes 10,500 Btu/KWH
2. Approximately 3.5 million Btu are available from recycle of ammonia synthesis loop
purge gas.
Source: "Development Document for Effluent Limitations Guidelines and New Source Performance
Standards for the Basic Fertilizer Chemicals", March 1974.
32
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TABLE IV-9
WATER EFFLUENT TREATMENT COSTS — AMMONIA PLANTS
4 5
152,900 134,300
30,600 26,900
13,900 12,200
2,300 2,000
33,900 1,750
17,200 7,350
$ 97,900 $ 50,200
0.77 0.33
27.4 17.3
435 275
5 - 10
Treatment Alternative* 1
Investment $302,900
Return on Investment
(pretax)** 60,600
Depreciation 27,550
Taxes and Insurance 4,550
Operating & Maintenance
Costs (excluding energy
and power) 12,100
Energy and Power Costa*** 273,600
Total Annual Costs $378,400
Energy (106 'kWh/yr) 12.3
Raw Waste Load (liters/sec) 17.6
(gpm) 280
Resulting Effluent Level
(mg/ liter) 25 NH3-N
(lb/1000 lb)-84 NH3-N
1. Ammonia/ condensate stripping
2. Integrated ammonia/condensate stripping
3. Oil/grease removal system
2
156,650
31,350
14,250
2,350
6,300
168,700
$222,950
7.5
17.6
280
25 NH3-N
84 NH3-N
3
28,400
5,700
2,600
450
1,150
7,850
$17,750
0.35
6.3
100
< 25 oil
< 30 oil
4. Biological treatment nitrification-denitrification
5. Ammonia/condensate air stripping
* Treatment Alternatives
** 20 Percent of Investment/Year
*** Energy price basis not given by the source.
This number
was updat
5 NH-N 33
Size Basis: 90 kkg/day (1000 ton/day) ammonia plant
All cost figures are March 1975.
Source: "Development Document for Effluent Limitations Guidelines and New Source Performance
Standards for the Basic Fertilizer Chemicals," EPA, March 1974.
-------
TABLE IV-10
WATER POLLUTION CONTROL COSTS1 ($) AMMONIA/CONDENSATE2 STEAM STRIPPING'
Plant Size 1000 T/D
Investment $302,900
Return on Investment (pretax) 20% $ 60,600
Depreciation (11 years, straightllne) $ 27,500
Operating and
Maintenance Cost $ 12,100
Energy and Power Costs $273,600
Total Annual Costs $373,800
% of Total Costs for Energy
and Power 73%
1. Based on 1971 costs updated by ADL to March 1975.
2. . Best practicable technology required July 1, 1977 (water effluent).
3. Energy price basis not given by the source. This number was updated from
1971 using a factor of 1.4.
Source: "Development Document for Effluent Limitations Guidelines and
New Source Performance Standards for the Basic Fertilizer
Chemicals", EPA, March 1974.
(5) Impact of Current Air Related Environmental Problems
The sources, control technology and cost of control of air pollution
emissions are described in this section. In compiling the information that
is presented, we have relied on information in our own files, industry
experts and government information.*
(6) Emissions Sources
We have considered the base case plant as divided into three areas:
Raw Material Receiving and Storage;
Synthesis Gas Production; and
Ammonia Production, Storage, and Loading.
*Air Pollutant Emission Factors, EPA Report No, APTD 0923 (Contract No.
EPA 22-69-119) prepared by TRW, Inc., April 1970.
34
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• Raw Materials Receiving and Storage - For a plant manufacturing
ammonia from natural gas, receiving and storage is very simple.
The gas is usually delivered to the plant via a pipeline and is
either used directly or a portion is stored in a pressurized
storage tank. There are no air pollutants associated with this
operation.
• Synthesis Gas Production - The production of ammonia synthesis gas
from a natural gas feedstock is usually accomplished by steam-
methane reforming using a nickel catalyst. Since the catalyst is
sensitive to sulfur, the feedstock sulfur content is usually kept
less than 2 parts per million. Therefore, no significant sulfur
emissions are expected in the base case. No particulates are pro-
duced in this process. Since the natural gas is often pressurized
prior to reforming, the system will be a pressurized one and pro-
cess leaks are expected to be nil.
• Ammonia Production. Storage and Loading - Most of the potential
air pollution emissions associated with ammonia are emitted from
the synthesis loop and from product storage and loading. These
two sources are briefly described below. There is little differ-
ence between this portion of the base case plant and the ammonia
production and storage associated with the new technologies dis-
cussed in later sections of this report.
• Synthesis Loop Purge - There is a tendency for inert material,
such as methane and argon, to concentrate within the synthesis
loop. Therefore, there is a purge stream off the ammonia converts
exit stream to remove inerts from the ammonia synthesis loop. In
early plants, the purge was often vented to the atmosphere and
was occasionally scrubbed with water to remove the ammonia, gen-
erating a wastewater stream containing ammonia which had to be
treated. Currently, the loss of hydrogen from the synthesis loop
is not total, because the purge gas can be burned in the reformer
furnace. Cryogenic purification of the synthesis gas lowers the
inerts in the loop and reduces the purge requirements. In some
plants, cryogenic techniques are used to separate methane, argon,
and residual ammonia from the purge gas into separate components,
each of which can be handled separately without environmental
problems. The above processing methods are. applicable to both the
base case technology and to new technology, so there will not be
a net impact changing from one technology to another.
• Product Storage and Loading - Leaks are associated with the han-
dling of ammonia product, with major leaks occurring during trans-
fer of product into trucks or railroad cars. Because the ammonia
leaks occur at specific locations within the plant, they can be
readily collected and removed by wet scrubbers; however, their
collection is usually for occupational safety reasons since the
preferred method for removing ammonia from waste streams is via
stripping into the air. The control of ammonia leaks from fugi-
tive leaks requires good maintenance, and such leaks rarely
occur in quantities great enough to either pose environmental
problems or warrant control.
-------
(7) Treatment and Cost of Control
To compare base case technology with new technology, we considered the
differences in the environmental control costs to be in the processing areas
of Receiving and Storage and Synthesis Gas Production. For the base case
technology, the environmental control costs associated with these two proc-
essing areas are negligible. There will be a small cost associated with
environmental control of the ammonia storage and loading area. An example
of the costs that can be expected in controlling storage and loading emis-
sions is shown in Table IV-11. The control of the ammonia emissions is
based on a packed column scrubber having a gas flow rate of approximately
2,000 scfm. The scrubber water is treated with the other process wastewaters.
The capital cost for the system is approximately $23,500 and the operating
costs are approximately $0.03 per ton of ammonia. These costs are consid-
ered to be negligible compared to the anticipated environmental control
costs associated with the control of sulfur for the new technologies using
coal and oil feedstocks. Therefore, they have not been factored into our
analysis.
The solid wastes from the process are process catalysts, the sludge
from process and wastewater treatment. The catalysts are recovered, with
the exception of the iron oxide from the ammonia converter (which is gen-
erally landfilled).
TABLE IV-11
EXAMPLE COST OF AMMONIA SCRUBBING*
Basis: 2000 scfm
Capital Investment $23,500
Operating Cost, $/¥ear
Indirect Costs
Depreciation2 2,100
Taxes and Insurance 500
Return on Investment 4,700
Direct Costs
Electric Power 500
Operating Labor
Maintenance Labor and Materials 1,200
Total Annual Cost, $/Year 9,000
Unit Cost, $/ton of ammonia ? 0.03
1March 1975 basis
11 years, straight line
2Z of investment/year
4
201 of investment/year
Negligible
5* of investment/year
36
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3. Ammonia Production Based on Coal Gasification
a. Process Description
Given the shortage of natural gas, and the need for the United States
to reduce its dependence on foreign petroleum, serious consideration should
be given to basing future ammonia plants on coal.
A small number of ammonia plants based on coal have been built over
the years (Table IV-12), but some of them have since been closed. Never-
theless, recent increases in the price of gaseous and liquid hydrocarbons
throughout the world have revived interest in using coal.
Prior to World War II, nearly all synthetic ammonia production was
based on the use of coal to produce synthesis gas (a mixture of carbon
monoxide and hydrogen) using oxygen (or air) and steam. The coal reaction
with the steam is:
C + H_0 »- CO + H
£* L*
Heat must be supplied to support the reaction, in addition to that
needed to attain reaction temperature. The heat is supplied by the combus-
tion or partial combustion of coal; the oxygen used burns some of the coal
to reach the higher temperatures needed for optimum reaction rates.
There are three categories of gasification:
• Fluidized-bed - Coal is fluidized by oxygen and steam. (The
Winkler gasifier is an example.)
a Fixed- (or slowly moving) bed - Coal is supported on a grate. (The
Lurgi gasifier is an example.)
« Entrained (or suspended) bed - Coal is suspended in the oxidant
gas stream. (The Koppers-Totzek and Texaco gasifiers are examples.)
Using coal as a feedstock from which to obtain a synthesis gas for
ammonia production, the objective is to free the hydrogen that is present
in the fuel and to react the carbon in the fuel with water vapor to release
more hydrogen. The second reaction may proceed directly or after forming
an intermediate such as carbon monoxide.
The optimum process would do the reaction simplyj_with^ a_minimum number
of reaction steps and without producing byproducts that have inherent dis-
posal problems. It should also be able to handle a relatively wide range
of coal feedstocks, because-even within a given mine-fuel properties vary
from sample to sample.
37
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TABLE IV-12
AMMONIA PLANTS BASED ON GASIFICATION OF COAL
Country
CSSR
Finland
.France
Germany
Greece
Spain
Yugoslavia
Turkey
Zambia
Paxistan
India
Thailand
Korea (South)
Japan
Location
Most (Brux)
Oulu
Mazingarbe
Leuna
Wesseling
Ptolemais
Puentes de Garcia
Rodriguez
Puertollano
Monzon
Goradze
Klitahya
Kafue near Lusaka
Oaud Khel
Neiveli
Mae Moh
Naju
Onahama
Onahama
Akita
Nagoya
Kurosaki
Toyama
Gasification Process
Winkler
Koppers-Totzek
Koppers-Totzek
Winkler
Pintsch-Hildebrand
Winkler
Rummel
Koppers-Totzek
Koppers-Totzek
Winkler *
Wellmann
Winkler
Winkler
Koppers-Totzek
Koppers-Totzek
Lurgi pressure
process
Winkler
Koppers-Totzek
Lurgi -pressure
process
Koppers-Totzek
VIAG
VIAG
Winkler
Winkler
Winkler
Winkler
Fuel
Lignite
Bituminous coal
fuel oil
Bituminous coal
Lignite
Low-temperature
coke from lignite
Briquettes made
of lignite
Lignite
Lignite
Lignite
Lignite
Bituminous coal
Anthracite
Lignite
Lignite
Lignite
Bituminous coal
Bituminouseoal
Lignite
Lignite
Anthracite
Bituminous coal
Bituminous coal
Bituminous coal
.Low temperature
coke
•Bituminous coal
Bituminous coal
Bituminous coal
Remarks
Initially built for hydrogena-
tion of lignite
In addition to revolving grate
and slag/tap gas producers
using metallurgical coke
Initially built for hydrogena-
tion of lignite
Molten slag
Revolving grate plus oxygen
. Revolving grate, no oxygen
Revolving grate, no oxygen
Source: Ammonia, Part I, Edited by A.V. Slack and G. Russel James, 1973, Marcell Pekker, Inc., N.Y.
38
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In general, equilibrium favors methane formation at low reaction tem-
perature and high pressure. However, methane cannot be utilized in ammonia
production. Hydrogen and carbon monoxide formation is favored at high
temperatures.
Winkler, Koppers-Totzek, and Lurgi gasifiers have all been demonstrated
in commercial operation and could be deemed proven and reliable. There is
a fourth gasifier not yet in full-scale commercial operation which we believe
may be very advantageous for ammonia manufacture. A high-pressure partial-
oxidation system (such as that developed by Texaco) can produce synthesis
gas, without byproducts, at pressures up to"1000 psi. Such a pro^ooo can
use almost any coal, coking or non-coking, high or low sulfur, and can be
integrated Into an energy-efficient ammonia process.
One such sequence would involve the following steps, which are outlined
in Figure IV-3 through IV-8 later in this report:
• Coal receiving and handling,
• Coal grinding,
• High pressure gasification with oxygen,
• Ash removal and handling,
• CO conversion using a sulfided catalyst,
• Heat recovery,
• Acid gas (H_S and CO-) removal,
• Low temperature purification,
• Compression, and
• Synthesis and recovery.
Apart from the high pressure gasification step, this integration employs
processes that have all been commercially used under the conditions involved
and it affords excellent energy efficiency requiring only a modest amount
of auxiliary steam for compressors in both air plant and synthesis. A
description of the inlet and outlet streams from the gasifier is presented
in Table IV-13,
An air separation plant provides oxygen for gasification and high-purity
nitrogen for the low-temperature purification section. To remove carbon
dioxide and hydrogen sulfide, the Rectisol process may be used, because it
provides a separation of the two gases into a pure carbon dioxide suitable
for urea production and a hydrogen sulfide-rich stream for conversion to
sulfur in a Claus process plant.
39
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TABLE IV-13
GASIFICATION SYSTEM
Basia: Illinois Ho. 6 Coal
1.000 'con/stream day
Gasification System Feed
Coal (ton/operating day)
Oxygen (ton/operating day)
Water (gal/hr)
Gasification System Product
Product gas (Hydrogen plus Carbon Monoxide)
(10* SCF/operating day)1 72.700
Slag2 (ton/day) 181
Ptllltlea Required per MM SCF CO + H2
Electrical Energy (kWh) 600
Stea» (pounds 9 250 pal) 6.000
Cooling water (gal) 125,000
SCF - Standard cubic fe«t neaaured at 60*F and 14.696 psla.
Carbon content. 2Z of by wt.
(1) Coal Preparation and Gasification
Ground coal is mixed with a. water slurry of recycled soot from the soot
thickener. The resulting slurry is pumped to the gasifier, where partial
combustion with oxygen takes place under pressure. The synthesis gas
(syngas) so produced along with accompanying slag and particulate matter
(soot) is quenched by direct contact with water. The slag is removed from
the bottom of the gasifier vessel by lock-hopper. The 'quenched syngas is
further scrubbed with hot water to remove the soot, which consists of uncon-
verted carbon and fly-ash. The steam content of the scrubbed gas is suffi-
cient for shift conversion without further steam addition. Condensate
return provides the make-up water for the system. It is fed first to the
scrubber where it picks up the soot, and then is stripped of dissolved
gases, which are principally hydrogen sulfide and carbon dioxide. The acid
gases are sent to a Glaus sulfur recovery unit. The stripping medium is
byproduct nitrogen from the air separation plant.
The stripped soot/water stream goes to a thickener where the soot slurry
is concentrated by settling. The clarified overflow water from the thickener.
is recycled to the gas scrubber. The thickened soot slurry is recycled to1
the slurry preparation section.
40
-------
(2) CO Shift Conversion
The product gas from the coal gaslfiers, after water scrubbing for
removal of ash and soot, contains an appreciable concentration of carbon
monoxide. For ammonia synthesis, it is necessary to react the carbon mon-
oxide with hydrogen by use of the CO shift-conversion step, as indicated in
the equation
CO + H20 J C02 + H2
This reaction is exothermic and the t^ilibrium is favored by low temperatures.
However, an active catalyst is necessary to get appreciable rates of reaction
at low temperatures. About ten years ago, an iron oxide catalyst was the
conventional shift-conversion catfiyst utilized in many ammonia plants.
Because of the relative inactivity of the iron oxide catalyst, the CO con-
version had to be carried out at higher temperatures, with a resulting
effluent carbon monoxide concentration of 3-4%. Then, a new low-temperature
CO shift catalyst was developed using copper and zinc. The catalyst allowed
a lower temperature for the CO shift reaction and allowed a more complete
conversion of carbon monoxide to hydrogen, so that the effluent carbon mon-
oxide concentration could be less than 1%. The disadvantage of the low-
temperature shift catalyst was its extreme sensitivity to sulfur contaminants,
so that extra care had to be taken to eliminate all detectable amounts of
sulfur from the feed gas to the low temperature shift catalyst bed. A
sulfided cobalt-molybdenum catalyst has been developed which is insensitive
to sulfur contaminants and allows operation temperatures to be between those
of the iron oxide and copper zinc catalysts. With the new catalyst, the
residual CO concentration leaving the CO shift converter can be 1-1.5%, with
no adverse effects.
Because of the sulfur tolerance of the sulfided cobalt-moly catalyst,
and the relatively good conversion of carbon monoxide to hydrogen, the sys-
tem has been used for the ammonia plant discussed in this report.
The synthesis gas from the gasification step contains sufficient water
so that no additional steam is required for the CO conversion step. The
feed from the synthesis gas generators is preheated by interchange with the
process gas between beds of the CO shift conversion step. Because the CO
shift reaction is exothermic and equilibrium is favored by lower temperatures,
cooling is desirable between stages of the CO shift converter. For this
reason, the reaction is carried out in two or three stages, with intercool-
ing between stages, to achieve the most favorable equilibrium conditions
and hence the lowest carbon monoxide -content in the effluent gas. Signifi-
cant quantities of heat can be recovered from the CO shift converter efflu-
ent, because it is at about 600°F and contains.a fairly large quantity of
water vapor. During this heat recovery step, a considerable amount of con-
densate is produced and is subsequently used as a feed to the gasifier scrub-
bing and quench system. Any excess condensate from the heat recovery system
is stripped of dissolved gases and used as a feed to a boiler feedwater
system.
41
-------
After heat recovery, the effluent from the CO shift conversion step is
further cooled to about 110°F before going to the carbon dioxide and hydro-
gen sulfide removal system.
(3) Acid Gas Removal System
A number of different systems can be considered for the removal of acid
gases from the effluent stream coming from the CO shift conversion step. The
acid gases that need to be removed are hydrogen sulfide, carbon dioxide and
carbonyl sulfide. For efficient operation of the ammonia plant, it is desir-
able to get the impurities down to only a few ppm. Acid gas removal systems
usually utilize either chemical absorption or physical absorption. Of the
chemical absorption systems, the amine solvent (monoethanolamine [MEA]) is
the most prevalent. One of the problems of using MEA is that is does not
efficiently remove carbonyl sulfides. Furthermore, there is no convenient
way of selectively separating the carbon dioxide and hydrogen sulfide that
are produced when the amine solution is regenerated. Separation of these
two acid gases is desirable so that: 1) a higher concentration of hydrogen
sulfide can be utilized as feedstock to a Glaus sulfur conversion plant;
and 2) a high-purity carbon dioxide byproduct stream may be made available
as feed material for on-site urea manufacture. Another disadvantage of the
amine systems is that they use relatively large amounts of energy for the
regeneration step.
Another common acid gas removal system is the hot potassium carbonate
system. However, with such a scrubbing system it is difficult to get hydro-
gen sulfide and carbon dioxide concentrations low enough in the effluent
gases to be acceptable for an ammonia plant feed. Furthermore, there is no
convenient way of separating the regenerated hydrogen sulfide from the
carbon dioxide gas stream.
The physical absorption systems appear to be more amenable to removing
acid gases for an ammonia plant utilizing coal gasification as the synthesis
gas source. One of the systems that has been used is the Rectisol system,
which utilizes cold methanol as the physical absorbent. The Rectisol sys-
tem has been used to purify synthesis gas produced from coal in South Africa.
It has also been used in Germany to remove acid gases in some heavy oil
partial oxidation processes in conjunction with ammonia and methanol synthesis.
It is an efficient method for removing hydrogen sulfide, carbon dioxide,
carbonyl sulfide, water, and other impurities from gas streams.
The Rectisol process is based on the physical absorption of impurities
in cold methanol (-20° to -40°F) by countercurrent scrubbing of the process
gas in one or two stages. The methanol stream containing the impurities
can then be readily generated in a number of stages to produce a high-purity
carbon dioxide stream suitable for urea manufacture, or the carbon dioxide
stream can be vented to the atmosphere without causing environmental
problems. A concentrated hydrogen sulfide stream containing 25-30% hydrogen
sulfide can also be produced. This concentration of hydrogen sulfide is
quite suitable for efficient conversion to elemental sulfur in a standard
Glaus conversion plant.
42
-------
The regeneration of the methanol used for scrubbing requires some inert
gas for stripping of the material and also some regeneration by stripping
of the methanol by reboiling methanol vapors. The inert gas-stripping
material can, in this instance, be readily obtained from the byproduct
nitrogen stream produced in the air separation plant associated with pro-
ducing oxygen for the gasification step.
Because water is also removed from the process gas stream by the
Rectisol process, a water-methanol separation step is required. The water
that is removed from the methanol solvent is disposed of in a conventional
biological wastewater treatment system.
Because the Rectisol process is a low-temperature physical absorption
operation, the heats of solution associated with the absorption of the acid
gases in the methanol must be removed. A system using ammonia has been
considered to satisfy the refrigeration requirement. The tail gas, which
is produced primarily from the inert gas stripping of the methanol' solvent,
will normally have a concentration of less than 1% carbon monoxide and
hydrogen, with a maximum of 5 ppm of hydrogen sulfide. This vent stream
can normally be vented to the atmosphere.
The Rectisol process normally requires five or six towers to effect
the required separation and stripping. By proper use of efficient heat
exchangers throughout the system, the energy requirements for carrying out
the removal of acid gases from the synthesis gas can be kept to reasonably
small quantities.
(4) Final Synthesis Gas Purification and Composition Adjustment
After the hydrogen sulfide and carbon dioxide have been removed from
the synthesis gas, contaminants are still present, primarily carbon monoxide,
argon and methane. For ammonia synthesis, it is necessary to remove the
carbon monoxide impurities down to only a few ppm, because carbon monoxide
and carbon dioxide are poisons for the ammonia synthesis catalyst. It is
also necessary to add nitrogen to the predominantly hydrogen stream to
achieve a 3:1 mole ratio between the materials.
A nitrogen wash system is the most logical method of removing impurities
and properly adjusting composition. In the nitrogen wash system,.the semi-
purified synthesis gas from the acid gas removal system (the Rectisol
system) is cooled in heat exchangers and is then contacted with liquid
nitrogen. The liquid nitrogen removes the carbon monoxide, methane, and
argon impurities and also allows the addition of nitrogen to the required
composition. The nitrogen is available at minimum cost from the on-site
air separation plant used for supplying the oxygen required for the gasifi-
cation step.
The low temperature required for the nitrogen scrubbing is produced
without the use of a complex refrigeration cycle.
The low temperatures required for the separation process are obtained
by mixing the cool nitrogen with the scrubbed gas inside the low-temperature
nitrogen wash facility.
43
-------
In the liquid nitrogen wash system, a residual gas is produced which
contains some nitrogen and the impurities that were present in the feed
synthesis gas. This gas, with a high enough concentration of combustibles,
is often utilized as a supplemental fuel.
The process has no external steam consumption (and no feed water treat-
ment is needed for the steam) because the coal is fed in a water slurry.
Thus, gasification steam is internally generated, but of course does require
oxygen and coal consumption to supply the heat needed. About 99% of the
carbon is gasified.
The gasifier operating pressure of 1200 psi provides a significant
savings in total ammonia process compression energy required. Most of the
plants listed in Table IV-12 operate at atmospheric pressures, with the
maximum pressure below 500 psi. Much less energy is required to compress
the oxygen to 1200 psi than to compress the greater volume of synthesis
gas to this level. Operation at this pressure level also provides advan-
tages in the synthesis .gas purification train.
The very pure synthesis gas from the gas purification train is com-
pressed to 3000-4000 psi for ammonia synthesis. Storage for three months'
production is included in the estimates.
The gas is very low in methane, no steam reformer is needed to con-
vert the methane to synthesis gas and, very importantly, the syngas con-
tains no tars, phenols, or other high-molecular-weight byproducts that
must be separated in the gas purification train and properly disposed of.
The thermal balance indicates a need for an additional input of 187
million Btu per hour. Assuming a coal-fired boiler with an 80% efficiency
(and using 10,870 Btu/lb for the raw coal), about 10 tons of coal/hr are
needed to supply the deficit. This is equivalent to 0.24 ton/ton of ammonia.
Cooling water circulation is estimated to be about 3.3 million gal/hr
or 80,000 gal/ton of ammonia. Assuming a 5% makeup to the cooling tower,
new water needs are 4,000 gal/ton.
Power requirements are estimated to be 162 kWh/ton, including coal
grinding but not mining.
Compared to a plant for producing ammonia from natural gas, a coal
plant would differ in the following respects. An air separation plant would
be required. Oxygen would be used to gasify the coal. Equipment would also
have to be added for handling the coal, grinding it finely, and storing it
as a slurry for introduction into the reactor. Ash removal and disposal
facilities would also have to be included. Essentially all of the ash would
be blown down from the quench in the bottom of the reactor. A minor amount
would carry over into the soot scrubber and be removed with the soot, which
could then be recycled to the partial-oxidation reactor. The amount of
carryover would be so small that it would not build up in the recycle stream.
44
-------
A high-sulfur coal can be utilized and the sulfur recovered in elemental
form as a possible byproduct, though probably at low value. Assuming that
one of the new sulfide-type shift catalysts is used, the hydrogen sulfide
(which is how the sulfur would be generated) is removed and separated from
the carbon dioxide by a cold methanol wash. The carbon dioxide can be
recovered in a form pure enough for urea manufacture.
b. Cost of Production
Estimates of the capital investment and operating costs were prepared
for a "grass roots" plant using a high-pressure coal partial oxidation
process, with a capacity of 1000 tons per stream day, located in Southern
Illinois where there are considerable deposits of coal near the ammonia
market. Investments and operating costs are based on March 1975 cost con-
ditions. The estimated cost of producing ammonia would be $77.95/ton, as
shown in Table IV-14. Of this total, $27.26 (35%) represents the cost of
energy inputs. About 26% of the total cost is attributable to the feed-
stock itself, in this case a high sulfur coal. The other power and fuel
inputs are needed to supply power in the air separation plant and the
ammonia plant and for pump drives.
This process can take advantage of the lower value of high sulfur
coals, because as part of the process the hydrogen sulfide form is removed
as a potentially marketable sulfur.
c. Energy Usage
The total energy consumption of this process, expressed in Btu equiv-
alents, is 35.83 million Btu/ton of ammonia', as shown below:
106 Btu/Ton
Feedstock 1.33 tons @ 10,870 Btu/lb 28.91
Fuel 0.24 tons @ 10,870 Btu/lb 5.22
Power 162 kWh @ 10,500 Btu/kWh 1.70
Total 35.83
The form of the energy used can vary considerable. We have based our
analysis on the probable optimum situation.
d. Effluent Controls Required for Coal Gasification Alternative
The schematic representation of the process' considered here is shown
in Figures IV-3 through IV-8. The nature of pollutant emissions are sum-
marized in Tables IV-16, IV-17 and IV-18. The major environmental differ-
ences between the base case and that of the partial oxidation of coal to
supply synthesis gas are:
45
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TABLE IV-14
ESTIMATED PRODUCTION COST OF AMMONIA FROM COAL
Producti
Process: High Pressure Partial Oxidation Location i Soathem TTHnoia
Capacity'-
Annual Productioni 340.000 tons
Stream Daya/Yr ! 340
VARIABLE COSTS
Coal Feedstock*
Coal Fuel*
Electric Power
Energy Subtotal
Process Water (Consumption)
Cooling (Circulating Rate).
Catalysts & Chemicals
Total
SEMI-VARIABLE COSTS
Direct Operating Labor (Wages)
Direct Supervisory Wages
Maintenance Labor, Materials &
Supplies
Labor Overhead
Total
P1XKJ) COSTS
Plant Overhead
Local Taxes & Insurance
Depreciation
Total
TOTAL PRODUCTION COSTS
Return on Investment (Pretax)
POLLUTION CONTROL
TOTAL
Units Used in
Costing or
Annual Cost
Basis
Tons
Tons
kWh
1000 gallons
1000 gallons
-
32 men
4 foremen
1 superintendent
4.5Z of invesc-
ment/yr
35Z of labor &
supervision
70Z of labor &
supervision
1.5Z of invest-
ment/yr
11 years,
straight line
20Z of invest-
ment/yr
*Coal characteristics presented in Table IV- i 5
$/nnit
$15.40
15.40
0.019
0.20
0.03
-
$12,000/yr
$18,000/yr
S25,000/yr
Dolts Consumed
per Ton of
Product
1.33
0.24
162 '
0.42
80
-
$/Ton of
Product
20.48
3.70
3.08
27.26
0.08
2.40
0.45
30.19
1.13
0.21
0.07
13.38
0.49
— . - -
iJS.28
0.99
4.46
27.03
-
32.48
77.95
59.47
8.65
146.07
46
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TABLE IV-15
ANALYSIS OF ILLINOIS NO. 6 COAL
(%)
Raw Coal
As Received Basis
Moisture 11.76
Ash 11.78
Sulfur 4.34
Btu 10,869
Dry Basis
Ash 13.35
Volatile 38.60
Fixed Carbon 48.05
Sulfur 4.92
Btu 12,317
MAF Btu 14,215
Ultimate Analysis, Dry Basis
Carbon 66.95
Hydrogen 4.79
Nitrogen 1.32
Chlorides 0.02
Sulfur 4.92
Oxygen 8.65
Mineral Analysis of Dry Ash.
P2°5 °'61
Si02 46.49
Fe203 ' 28.09
A1203 20.02
Ti02 0.87
CaO 2.96
MgO 0.71
so3 o.io
K20 0.01
Na20 0.05
Undetermined 0.09
Source: Private communication with Illinois coal company.
47.
-------
Coal
-o
Surface Run Off
Figure IV-3. Coal Receiving and Preparation
Crushed
Coal to
Gasification
Oxygen from Air Separation Plant
Product Gas to Shift Conversion
(H,, CO. HjS, COj, CH4. H,0,
Acid Gas to Sulfur Recovery
Figure .,IV-4. Gasification
Nitrogen
48
-------
Product
Gas From
Scrubber
BFW. Tail H5S Rich Tail
c°! Gas Gas Gas
i
1
-<3>
Carbon
Monoxide
i
^
Steam
'• ;,
^^^ ~SX ~\X ~X^ "v' Synthesis
Gas to Compression
Carbon Dioxide " ^nd Ammon.a
_ Heat Recovery and H,S Nitrooen SynthBB
Shift ^no" Cooling (~Y~Y-I
\
"LLI r
BFW
, 1 Steam .
Spent
Removal Wash
(Rectisol)
li
~^D
Nitrogen , , Water with
Catalyst ' Condensate to For Str'PP'"9 Methanol
Boiler Feed SepJ™m p,an, ^^
Water Treatment
For Recycle
"Boiler Feed Water
Figure IV-5. Carbon Monoxide Shift and Synthesis Gas Purification
BFW*
Sulfur Rich
Gas Stream
Sulfur
Recovery
(Claus Plant)
Steam
Tail Gas
Clean Up
(Beaven or IFP)
*Boiler Feed Water
Molten Sulfur
To Storage
Figure IV-6. Sulfur Recovery
49
-------
BFW
Purge
used as
Supplemental
Fuel
Synthesis Gas
^^^k 1
V1x
I
Condenser
Waste
Heat
uJ
Steam
Boiler
1
T
Compressor
Circulator
Ammonia
Catalytic
Converter
Iron Oxide Catalyst
Figure IV-7. Ammonia Synthesis
Solids
Scrubber
Raw Water
Purification
(Ion Exchange)
Recycle from Process
Coal-Fired
Boiler
To Process
Ash Boiler Slowdown
Figure IV-8. Auxiliary Boiler
50
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TABLE IV-16
WATER EFFLUENTS - Ammonia from Coal Alternative
Coal pile runoff
T) Ash & slag pile runoff
3) Wastewater from Rectisol unit
4) Wastewater from sulfur recovery plant tail-gas cleanup
Boiler blowdown
(6) Boiler feedwater purification wastes
(2) Coal-fired boiler stack gas scrubber water
Method of
Handling
collected and
treated
treated
treated
3
4
5,
£
TABLE IV-17
AIR EMISSIONS - Ammonia from Coal Alternative
Coal unloading facility emissions
Coal grinding
Inplant handling of coal
System vents for pressure let-down
Byproduct CO-
Tail gas from Rectisol
Sulfur-rich stream from Rectisol
Tail gas from nitrogen wash
Method of
Handling
Claus plant tail gas clean-up vent
infrequent; flared
potential for urea manufacture
vented
to sulfur recovery
burned in boiler as
supplemental fuel
vented
Byproduct molten sulfur (storage & transfer facilities) marketed
Synthesis loop purge gas burned as supplemental fuel
Stack gas from auxiliary coal-fired boiler
scrubbed
51
-------
TABLE IV-18
Method of
SOLID WASTES - Ammonia from Coal Alternative Handling
(T| Slag
|2| Catalyst from CO shift recovered
|3| Molten sulfur marketed
|4| Ash from auxiliary coal-fired boiler
\5\ Scrubber water solids from auxiliary coal-fired boiler
161 Catalyst from ammonia converter
• The use of a coal feedstock introduces the new source of particu-
late emissions associated with coal-handling;
• Surface runoff from the coal and slag piles must be collected
and treated;
• The slag generated must be disposed of in an acceptable manner;
• The use of a coal feedstock will produce a sulfur-laden gas
exhaust in synthesis gas purification which must be controlled
using, for example, a Glaus plant with tail gas cleanup; and
• The sulfur recovery plant will generate additional wastewater
that must be treated.
'An additional and indirect environmental impact suggested by the change
in feedstocks is that an auxiliary boiler used during startup and operation
will be based on coal. (For the natural gas reforming process, the startup
boiler would be based on natural gas.) The environmental impact of a coal-
fired boiler is greater than that of a gas-fired boiler. However, because
auxiliary boilers are not an integral part of the manufacturing process,
they are not considered in detail under the scope of this study. Discharges
would be those common to such boilers in any other facility.
The details (emission rates, control technology, and cost of control) of
water and air pollution, solid waste disposal, and other environmental concerns
are discussed in the following sections of this report. For comparison, the
environmental impact of the base case, use of natural gas in steam-methane
reforming, is considered to be negligible.
52
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(1) Slag Pile Runoff
Slag removed from the gasification unit would present a disposal problem.
If the ammonia plant is not located within close proximity of the coal mine
(where the ash can possibly be returned) it must be held on-site' in slag
piles.
As in the case of the coal storage pile runoff, the slag pile may pre-
sent a water pollution problem. As shown in Table IV-19, both ash and slag
contain a variety of heavy metals, many of which are leachable in water.
The runoff would also contain large quantities of suspended solids result-
ing from fine ash particles being carried away with the water. Again, the
composition of the runoff is very difficult to predict.
Slag would be generated at a rate of 62,000 tons per year. A storage
area capable of containing a 15-year accumulation would occupy an area of
approximately 26.5 acres. A yearly rainfall rate of 33 inches per year
would result in an estimated average runoff flowrate of 81,000 gallons per
day (including 25% additional capacity), and the treatment system would
require appropriate retention basins.
(2> Cooling Tower Slowdown
The coal-gasification-based ammonia plant has a cooling water circula-
tion rate of 80 million gpd. Typically, cooling water is recirculated in
a tight recycle loop. Based on a cooling water blowdown rate of 1%, the
cooling tower blowdown flowrate is 800,000 gpd. Due to the concentrating
effect of the whole cooling circuit, inorganic salts present in the water
supply would be greatly concentrated. Also, and more important from a
pollutional point of view, there would be the presence of cooling water
corrosion inhibitors. In particular, if chromate corrosion inhibitors are
used, the cooling tower blowdown would have to be treated prior to discharge.
e. Environmental Effects Related to Water Pollution
The coal gasification alternative generates the following wastewater
streams (excluding mining):
• Coal pile runoff,
• Slag and ash pile runoff,
• Cooling tower blowdown, and
• Wastewater from the synthesis gas purification system.
53
-------
TABLE IV-19
ELEMENTAL DISTRIBUTION IN COAL, SLAG, AND FLY ASH
Element concentration, ppm
Coal
10,440
4.45
65
3.7
4,340
0.47
8.2
914
2.9
18
1.1
8.3
0.1
10,850
4.5
0.4
0.122
1,540
3.8
1,210
33.8
696
16
4.9
15.5
0.5
2.2
2.2
23,100
1.0
23
0.11
2.1
506
2.18
28.5
46
Slag
102,300
18
500
2
46,000
1.1
84
<100
20.8
152
7.7
20
1.1
112,000
5
4.6
0.028
15,800
42
12,400
295
5,000
85
6.2
102
0.64
20.8
.080
229,000
8.2
170
0.95
15
4,100
14.9
260
100
Outlet Fly Ash
76,000
440
750
32,000
51
120
65
900
27
1.3
150,000
5.0
24,000
42
430
11,300
650
190
55
36
88
9
1.8
26
10,000
1,180
5,900
Al
As
Ba
Br
Ca
Cd
Ce
Cl
Co
Cr
Cs
Cu
Eu
Fe
Ga
Hf
Hg
K
La
Mg
Mn
Na
Ni
Pb
Kb
Sb
Sc
Se
Si
Sm
Sr
Ta
Th
Ti
U
V
Zn
Source: Klein, D.H. et al, "Pathways of Thirty-seven Trace
Elements Through Coal-Fired Power Plants", Environ.
Sci. & Tech., 9^: 10, pp 973-978, 1975
54
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(1) Coal Pile Runoff
In the coal gasification alternative, approximately 122,000 tons of
coal (a three month supply) are stockpiled on site. Rainwater runoff from
the coal pile would contain coal particulates, organic and inorganic com-
pounds leached out of the coal by the rainwater, and oxidation reaction
products.* The exact composition of the coal pile runoff is difficult to
predict, as it is heavily dependent on the type of coal, rainfall occurence,
and type of storage. However, there are a variety of heavy metals and sul-
fur compounds present in coal. Bacterial action taking place within the
wet coal pile very likely would oxidize some of the sulfur compounds into
sulfates, thus causing the runoff water to be slight acidic, not unlike
acidic mine drainage. The presence of leached heavy metals and acidity in
the runoff water would require that the runoff water be collected and treated
prior to discharge.
Based on a coal pile occupying 6.3 acres, and an average yearly'rain-
fall of 33 inches per year, the estimated average daily flow of coal pile
runoff water would be approximately 19,000 gpd (including 25% additional
capacity).
The system for treating runoff water is based on using a retention
lagoon to contain the high flow rates that would result from heavy rains
and pumping from the lagoon through the wastewater treatment plant at a
lower average rate. In this way, capital investment cost for the waste-
water treatment would be lowered.
(2) Synthesis Gas Purification System Wastewater
The carbon dioxide a-*d hydrogen sulfide removal system (Rectisol) and
the sulfur recovery plant: t:..il gas cleanup system produce wastewater streams
that must be treated.
The Rectisol unit will enerate a wastewater stream containing an
estimated 2% concentration o.: methanol.
The sulfur-recovery tail gas cleanup unit will generate a wastewater
stream containing hydrogen sulfide (at approximately 50 mg/1 concentration),
carbon dioxide, and possibly small quantities of organic material.
*"Potential Pollutants from Fossil Fuel Conversion Processes" by the Exxon
Government Research Laboratory, EPA Contract No. 68-02-0629.
55
-------
An estimate of the volume and composition of these streams is:
Wastewater from
Wastewater from Sulfur Recovery
C02 and H2S Plant Tail Gas
Removal System Cleanup Total
Flowrate (gpd) 10,000 8,000 18,000
Methanol (Ib/day) 1,680 - 1,680
Hydrogen sulfide (Ib/day) - 3.4 3.4
Estimated BOD5 (Ib/day) 1,350 650 2,000
(including misc. organics)
(3) Other Ammonia Production System Wastewaters
There are a number of wastewater streams from the ammonia production unit
(described earlier in this report under the base case technology), including
process water treatment plant effluent, boiler blowdown, and process con-
densate. Because the same ammonia production units are used for each of the
process alternatives, there will be no significant difference in either waste-
water flowrate or composition. Thus, comparing effluent loadings and waste-
water treatment costs, the ammonia production unit essentially cancels out.
In the comparisons that follow, effluent loadings and wastewater treatment
costs are incremental to those of the base case — natural gas as feedstock
for ammonia production.
(4) Miscellaneous Wastewater Streams
In addition to the above, the coal gasification alternative will produce
from an auxiliary coal-fired boiler a boiler blowdown streamt an ion-
exchange spent-regenerant brine stream and a stack gas scrubber water stream.
Study of these streams is outside the scope of this study. As noted earlier,
these wastes are those generated by such a boiler system at any facility.
f. Wastewater Treatment Technology
(1) Runoff and Cooling Tower Blowdown Treatment
The coal pile runoff contains acid, soluble heavy metals and organics;
the slag pile contains heavy metals; and the cooling tower blowdown may
contain chromium. Because all three of the wastewaters can be treated with
lime to both neutralize the acidity and precipitate the heavy metals, they
can be combined in a single wastewater stream with a 900,000 gpd flowrate.
56
-------
A conceptual process configuration of the coal storage and slag pile
runoff collection system would consist of,
• An earthen dike around the perimeter of the storage areas;
• Collection pumps with pumping equipment;
• Piping;
• A retention basin capable of containing the short-term runoff
from a severe storm; and
• A pumping system capable of feeding water from the retention basin
to the treatment plant at a controlled rate.
The coal storage area and the slag disposal area each would have their own
runoff collection system. The total runoff water would be combined with the
cooling tower blowdown stream and then sent to the wastewater treatment plant.
The wastewater treatment plant would consist of:
• A 24-hour equalization basin,
• A solids recirculation clarifier, and
• A chemical feed system.
The chemical feed system would consist of a sulfur dioxide feeder (for
the reduction of hexavalent chromium to trivalent chromium) and a lime feeder.
The precipitated metals would be removed as a sludge from the clarifier.
The wastewater treatment system would have the following estimated chemi-
cal and energy consumption:
Hydrated lime - 255 ton/yr
Sulfur dioxide - 75 ton/yr
Electricity - 342,120 kWh/yr
and would generate an estimated 17,800 tons per year of wet sludge containing
10 percent solids.
(2) Synthesis Gas Purification Wastewater Treatment
Wastewaters from the units contain biodegradable material (methanol is
highly biodegradable, while hydrogen sulfide is somewhat biodegradable in low
concentrations), and as such can be treated in a conventional biological
treatment system. A biological treatment system capable of treating this
wastewater is envisioned to consist of the following:
57
-------
• A 24-hour equalization basin;
• A 15-day aerated lagoon;
• A 15-day non-aerated lagoon; and
• A nutrient feed system.
Ammonia and phosphoric acid would have to be fed to the wastewater system
to supply nutrients to the microorganisms. Excess microorganisms accumulating
in the non-aerated basin would be periodically removed as a sludge.
The wastewater treatment system would have the following estimated chemi-
cal and energy consumption:
Ammonia - 2.05 ton/yr
Phosphoric acid - 1.1 ton/yr
Electricity - 304,400 kWh/yr
and would produce 365 tons per year of wet sludge.
With proper operation, the wastewater treatment facility should be able
to effect a 90% BOD^ removal, because no unusual biotoxicants are believed to
be present, in which case the effluent BOD5 loading is estimated to be
200 pounds per day.
g. Wastewater Treatment Cost
Estimated wastewater treatment costs are presented in Table IV-21. As
can be seen from Table IV-20, 95% of the wastewater treatment cost is asso-
ciated with runoff treatment. The capital investment for this portion of the
treatment breaks down as follows:
Coal storage diking and collection system $1,358,000
Slag pile diking and collection system 2,789,000
Wastewater treatment plant 582,000
Total $4,429,000
Thus over 60% of the total treatment cost is associated with controlling
runoff from the disposal of slag. If specific conditions permit the slag to
be disposed of without a runoff collection and treatment system, the estimated
cost of wastewater treatment would be lowered considerably.
-------
TABLE IV-20
COAL GASIFICATION ALTERNATIVE-
WASTEWATER TREATMENT COST ESTIMATES
(BASIS: 1000 TPD AMMONIA PRODUCTION)
CAPITAL INVESTMENT
INDIRECT COSTS
Depreciation (@9.1%)
Return on Investment (@2D%)
Taxes and Insurance (@2%)
TOTAL INDIRECT COST
DIRECT OPERATING COST
Treatment of
Wastewater from
Runoff
$4,429,000
403,000
886,000
89,000
$1,378,000
Treatment
of Wastewater
from Synthesis
Gas Purification
System
$200,000
18,200
40,000
4,000
$ 62,200
Total
Wastewater
Treatment
Cost
$4,629,000
421,200
926,000
93.000
$1,440,200
Operating Labor (plus OHD)
Maintenance (Labor & Supplies)
Chemicals
Electric Power (@ $0.02/kwh)
Sludge Disposal (@ $5.00/ton)
TOTAL DIRECT OPERATING COST
TOTAL ANNUAL COST
UNIT COST C$/ton of ammonia)
66,300
67,600
40,500
8,000
89,000
$ 271,400
$1,649,400
$4.85
16,500
8,000
900
6,100
1,800
$ 33,300
$ 95,500
$0.28
82,800
75,600
41,400
14,100
90,800
$ 304,700
$1,744,900
$5.13
SOURCE: ADL Estimates
59
-------
h. Environmental Effects Related to Air Pollution
The switch to partial oxidation using a coal feedstock, rather than
steam reforming using natural gas, is expected to have the following impacts
on air pollution control (excluding mining and transportation):
• Coal receiving and storage - the use of coal as a feedstock will
require facilities for unloading and storage, coal grinding, and
conveying to the process, all of which generate particulate
emissions;
• Synthesis gas^preduction - the use of coal as a feedstock introduces
significant sulfur which is removed from the synthesis gas and which
is then removed from exhausts venting to the atmosphere;
• Ammonia production, storage, and loading - the emissions from the
ammonia manufacturing operations are the same for the partial
oxidation process as those described earlier in this report under
the base case technology. There is no significant difference in
the environmental impact of the two cases.
A comparison of the emission factors for each feedstock is given in
Table IV-21. The switch to a coal feedstock introduces a new pollutant
emission in most cases,, as opposed to an increase or reduction in an existing
pollutant.. The ammonia synthesis loop, storage and loading are considered
to be equivalent for technologies based on natural gas or coal. While the
sources must be controlled using, for example, scrubbers on ammonia leaks
from storage and loading, flares or afterburners for intermittent plant
residue gas, and so on, there is no evidence to suggest that these sources
are significantly larger or smaller than comparable sources in plants using
natural gas feedstock and, for this reason, these sources are not considered
in detail here. Additional information is provided under the base case.
(1) Receiving and Storage
One of the common air pollution problems associated with the use of coal
is its tendency to form a fine dust. Operations within a plant specifically
causing this problem are:
• Unloading of railroad cars,
• Coal storage,
• Coal grinding, and
• Coal conveying.
60
-------
TABLE IV-21
SUMMARY OF AIR POLLUTION EMISSION FACTORS
Emission E.ate (Ib/ton)
Source
Receiving and Storage
- Coal Unloading
- Coal Storage
- Coal Grinding
- Material Handling
Synthesis Gas Production
- Tail Gas
- Pressure Let Down
Ammonia Production, Storage, Loading
- Purge Gas
- Storage and Loading
Pollutant
particulate
fugitive particulate
particulate
particulate
Natural Gas
CO,
CH4
NH,,
3
90
Coal
unk.
unk.
unk.
unk.
<0.2
Control
Technology
Fabric Filter
Fabric Filter
Fabric Filter
Sulfur recovery plant
with tail gas cleanup
unk. Flare
Wet scrubber or use as
90f fuel
2 Wet scrubber
-------
In the case of car dumping and coal grinding, the source is at a
single point in the plant where it can be controlled using an appropriate
hood and fabric filter. The capital costs for such systems are not related
to the size of the plant, but rather to the size of a typical railroad car
itself. The estimated capital and annualized operating costs for the two
control requirements are shown in Table IV-22.
The control of dusting associated with the coal storage piles is much
more difficult, because coal piles can spread over as much as six acres,
making hooding or collection of particular emissions virtually impossible.
In this case, the industry has resorted to the use of sprays to wet down
the surface coal piles to minimize dusting. The costs of such systems are
only a minor part of the equipment found within a coal yard and are generally
included as a part of the coal handling apparatus.
Dust emission during conveying of coal to different parts of the plant is
also a fugitive emission source which is not confined to a single spot in
the plant and is therefore difficult to collect. In most cases, the control
of such emissions is limited to the use of covered conveying belts to minimize
dust losses. The cost of such a system would depend also entirely on the
length of the conveyor and the corresponding cost for fabrication and erec-
tion of the ducting required to collect the emissions. At the present time,
control of this type of fugitive emission is not required, and we have not
included the costs of such controls in our estimate of the environmental
costs for the ammonia industry.
(2) Synthesis Gas Production
The major emission associated with the production of synthesis is the
highly concentrated, sulfur-laden exhaust from the acid gas removal system.
An approximate sulfur balance for the synthesis gas production is shown in
Table IV-23. The amount of sulfur in the acid gas exhaust is about 60 long
tons/day, which is large enough to require sulfur control using, for example,
a Glaus process. Because several states have emission standards regulating
the tailgas from sulfur recovery plants, we have assumed that tail gas cleanup
will also be required. The combination is expected to reduce the plant sulfur
emissions to about 150 ppm.
The cost of sulfur recovery plant plus tail gas cleanup is shown in
Figure IV-9. These costs, which appear to be high, are based on information
obtained by EPA.* The operating costs for such a plant are shown in
Table IV-24. With sulfur credited at $25/long ton, the cost for control
is $2.97/ton of ammonia.
*Standard Support and Environmental Impact Document, April 1975.
62
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TABLE IV-22
CAPITAL AND OPERATING COSTS FOR COAL HANDLING PARTICIPATE CONTROL
Coal Gasification Alternative
(534,000 ton/yr of coal)
CAPITAL COSTS $460,000
ANNUAL OPERATING COST, $/Yr
Indirect Operating Costs
- Depreciation 41,800
- Return on Investment (@ 20%) 92,000
- Insurances and Taxes (@ 2%) 9,200
TOTAL INDIRECT COSTS $143,000
Direct Operating Costs
- Labor
Direct (@ 450 Man-Hours/Yr, $6.00/hr 2,700
Supervision (@ 15% of Direct) 400
Labor Overhead (@ 35% of Direct and Supervision) 1,100
Plant Overhead (@ 70% of Direct and Supervision) 2,200
- Maintenance «? 5% of Capital) 23,000
Electric Power (@ $0.02/Kwh, 240,000 Kwh/Yr) 4,800
Fabric Replacement 8,000
TOTAL DIRECT COSTS $42,200
TOTAL ANNUAL COST, $/Yr $185,200
UNIT COST, $/Ton of Ammonia ' $0.54
SOURCE: ADL Estimates
63
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TABLE IV-23
APPROXIMATE SULFUR BALANCE, TPD
(BASIS: 1000 TPD AMMONIA)
Plant Stream
Coal Feed
Acid Gas Removal Exhaust
(to Sulfur Recovery)
Sulfur Recovery Plant Exhaust
- Glaus Plant Exhaust
- Tailgas Cleanup Exhaust
(to Flare)
Molten Sulfur Product
Total Weight
TPD
1350
187
66.3
Sulfur Load
4.92%
35.5
2000 ppm
150 ppm
100%
Sulfur Weight
TPD
66.4
(66.4)
( 3.3)
66.3
10.0
8.0
6.0
4.0
Capital
Investment,
$ Millions
1.0
O.B
0.6
0.4
0.2
J 1 1 I I l I l I
10
I I I
Long Ton/Day Sulfur Capacity
Figure iy-9. Capital Investment — Glaus Plant (Including Tail Gas Cleanup)
SOURCE: Arthur D. Little, Inc., estimates
64
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TABLE IV-24
SULFUR CONTROL COSTS FOR ACID GAS EXHAUST
Coal Gasification Alternative
(BASIS: 1000 TPD of Ammonia, 60 LT/D of Sulfur)
CAPITAL COSTS. ($1.OOP's) $3,600
ANNUAL OPERATING COST. $l,QOO's/Yr
Indirect Operating Costs
- Depreciation, 11 years $327
- Return on Investment (@ 20%) 720
- Insurance and Taxes (@ 2%) 72
TOTAL INDIRECT COSTS $1,119
Direct Operating Costs
- Labor
Direct (@ $6.00/Hr, 1 Man/Shift) 50
Supervision (@ 15% of Direct Labor) 7
Labor Overhead (@ 35% of Direct and Supervision) 20
Plant Overhead (@ 70% of Direct and Supervision) 39
- Maintenance Ǥ 5 %) 180
- Utilities
Electric Power (@ 140 kWh/LT, $0.02/kWh) 57
Fuel (@ 0.8 x 106 Btu/LT, $2.00/106 Btu) 33
Cooling Water (@ 20,000 gal/LT, $0.03/103 gal) 12
- Chemicals (@ $2.50/LT in tailgas) 3
TOTAL DIRECT COSTS $401
Byproduct Sulfur Credit (@ $25/LT , 60 LT/D) (510)
TOTAL ANNUAL COST, $l,000's/Yr $1,010
UNIT COST, $/Ton NH3 $2.97
SOURCE: ADL Estimates
65
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(3) Ammonia Production, Storage and Loading
The environmental problems associated with ammonia production, storage,
and loading are described earlier under the base-case techology. The
problems associated with partial oxidation are identical and the costs will
be the same. We have not included here a quantitative estimate of the
pollutant loads or environmental costs, because they do not result in a net
change between the two technologies. However, to place the costs in per-
spective, we would estimate that the costs for the miscellaneous scrubbers
or flares necessary to control a typical 1,000 ton/day ammonia plant would
amount to less than 5% of the control costs for other air pollution emission
sources.
i. Environmental Effects Related to Solid Waste Disposal
As discussed previously, the major solid waste stream is slag. Added
to this are smaller quantities of sludges from the wastewater treatment plant.
The total annual quantities of solid waste are:
Slag - 62,000 ton/yr
Runoff treatment plant sludge - 17,800 ton/yr
Synthesis gas purification wastewater plant sludge - 365 ton/yr
The cost for disposal of these wastes is included as part of the wastewater
control costs. In addition the catalysts occasionally replaced are:
CO shift conversion catalyst - recovered
Acid gas removal system catalyst - recovered
Ammonia converter catalyst (iron oxid - not recovered
4. Production of Ammonia from Heavy Fuel Oil
a. Process Description
In the early 1950*s, industrial processes were developed for producing a
synthesis gas, carbon monoxide and hydrogen by the partial oxidation of
hydrocarbons, a process which is applicable to materials ranging from
methane to heavy petroleum residuals. The basic concept consists of
reacting the hydrocarbon with oxygen in the presence of steam at a tempera-
ture of 2000 6 - 2500°F. The following reactions take place:
C H + (m/2)00 - nCO + (m/2)H0
n m 2. i
C H + nH,0 = nCO + (n + m/2)H_
n m 2. 2.
66
-------
Carbon dioxide is also formed and the entire reaction mixture ±s
essentially at thermodynamic equilibrium at the temperature involved. Minor
amounts of methane are present in the product gas, corresponding to equilib-
rium conditions, and - depending on the composition of the hydrocarbons - some
amounts of hydrogen sulfide, carbonyl sulfide, and ammonia will be present.
In carrying out the reaction, the ratio of oxygen to hydrocarbon is
optimized to achieve the desired temperature under adiabatic conditions which
will give maximum conversion to CO and H2. These conditions usually result in
1-3% of the carbon in the hydrocarbon being converted to solid carbon (soot)
in the reaction.
The hot gas from the reactor is rapidly quenched to 350°-400°F to "freeze"
the composition and to cool it for further processing. The suspended carbon
is then removed and the crude synthesis gas is processed in a manner identical
to that described in the preceeding section for the coal-based plant. Major
steps in the process are:
• Shift Reaction - The carbon monoxide is used to convert water to
hydrogen over an Mo-Co sulfide catalyst.
CO + H20 •*• C02 + H2
• Heat Recovery - Thermal energy is recovered from hot process gas,
leaving the shift converter in the form of steam and pre-heated
boiler feedwater.
• Acid Gas Removal - Hydrogen sulfide and carbon dioxide are removed
by a process such as the Rectisol, which uses methanol to absorb
the gases and separate them into a C02 stream containing 5 ppm
H2S and a hydrogen sulfide-rich stream containing about 35% H2S
and 65% COo. As a pollution conttol measure, the hydrogen sulfide
is converted to elemental sulfur in a Glaus plant.
• Final Gas Purification - Small amounts of CO and CH* are removed
from the gas by scrubbing with liquid nitrogen. Sufficient nitro-
gen is vaporized to produce a 3:1 hydrogen-to-nitrogen mixture in
the purified gas.
• Compression and Synthesis - The hydrogen-nitrogen mixture is- com-
pressed to 2500-3500 psig and introduced into the synthesis loop
where ammonia is catalytically formed as described earlier.
3H2 + N2 -»• 2NH3
• Air Separation - An air separation plant is necessary to provide
the oxygen and nitrogen used in the process.
67
-------
There are two commercial versions of the oil gasification process which
have been adequately proven in many refinery applications for hydrogen pro-
duction so that they can be considered for ammonia plant use. One has been
developed by Texaco, and the other by the Shell Oil Company. Both can operate
at pressures ranging from atmospheric to over 1500 psi, the higher pressures
being of interest for ammonia synthesis to minimize overall power consumption,
and both can handle a wide range of feedstocks. The major differences between
the two lie in the manner in which the gas is quenched and in the manner in
which the soot is handled.
In the Shell process, a unique type of heat exchanger, designed to prevent
soot deposition, is used to quench the gas and generate high pressure steam.
The cooled gas is further quenched with water, then scrubbed to remove the
soot. The water/carbon slurry is flashed to atmospheric pressure and mixed
with fuel oil which agglomerates the carbon. The mixture is pelletized,
separated from the water,and the pellets are mixed with the fuel oil feed to
the burner-reactor. Thus, the carbon is recycled to extinction.
In the Texaco version, shown schematically in Figure IV-10, the hot burner
gas is quenched by direct injection of water. A large part of the water is
converted to steam which is needed in the shift conversion section of the
plant. The latent heat of the surplus steam is recovered in the heat
recovery section. It is also possible to use a heat exchanger for high-
pressure steam generation and to quench the gas in the Texaco process, but
this technique is not normally used if the gas is to be shifted to form
hydrogen.
Most of the carbon is removed in the quench operation and the final traces
are separated in a high-shear venturi scrubber. The sooty water is contacted
with naphtha, which preferentially wets the carbon so that a decanter will
produce a carbon-free water and a naphtha layer containing the carbon. The
naphtha/carbon mixture is mixed with a part of the heavy oil feed and the
naphtha is then distilled off for recycle leaving the carbon in the fuel oil.
The oil/carbon mixture is normally recycled to the reactor, but can be burned
as boiler fuel if low sulfur oil is used. Naphtha makeup is 0.1-0.2% of the
total heavy oil feed to the process.
The water from the decanter is recycled to the scrubber but to prevent
buildup of ash and soluble inorganic materials introduced as impurities in
the heavy oil feed, a purge or blowdown is necessary.
b. Cost of Production
Based on a plant with a capacity of 1000 tons/stream day which would
produce 340,000 tons of ammonia per year; a mid-west location; and March
1975 energy and fuel costs; the estimated cost of producing ammonia would
be $106.15/ton, as shown in Table IV-25. Of this total cost, $70.36 (66%)
represents the cost of energy inputs. About 48% of the cost is attributed to
the feedstock itself, in this case a high sulfur residual oil. The other fuel
and power inputs are needed to supply motive steam for turbine drives in the
air separation plant and the ammonia plant and for pump drives.
68
-------
Source: Texaco Development Corporation
Oxygen
A
Water
Preheater
Heavy Oil
Naphtha
A
Generator
T
Preheater
Water and Carbon
Naphtha
Naphtha
and Carbon
Steam
Separator
Water
Water
Stripper
-»- Product Gas
Oil
Stripper
Recycle to
Generator "]
Process Feed | '
Preheaters i
Oil and
Carbon
Plant
Boiler
Water
Slowdown
Figure IV-10. Synthesis Gas Generation Including Recovery of Unconverted Carbon
-------
TABLE IV-25
ESTIMATED PRODUCTION COST OF AMMONIA
FROM RESIDUAL FUEL OIL
Product: Ammonia
Partial Oxidation of Residual
Process; FuelOil Location! Mid-West
„ . Fixed Investment! $70,600,000
Annual/ *" • 100° ton /stream day
Capacity'
Annual Productioni 340.000 tons stream Davs/Yr.: 340
VARIABLE COSTS
Residual Fuel Oil
Feedstock (6.2%S)
Fuel, Low Sulfur
Naptha
Power
Energy Subtotal
Catalysts & Chemicals
Cooling Water Circulation
Process Water
Total
SEMI-VARIABLE COSTS
Operating Labor
Supervision
Labor Overhead
Maintenance
Total
FIXED COSTS
Plant Overhead
.Local Taxes & Insurance
Depreciation
Total
TOTAL PRODUCTION COST
Return on Investment (Pretax)
POLLUTION CONTROL
TOTAL
/i •*
Units Used
or Anual
Basis
Bbl
Bbl
Gal
Kwh
thousands of
gallons
thousands of
gallons
28 men
4 foremen
1 superintendent
35% of labor &
supervision
4% of investment/
yr
1 1
70% of labor &
supervision
1.5% of investment/
yr
11 years, straight
line
20% of investment/
yr
$/Unit
(i ^
11.97U)
15.12
0.35
0.0165
0.03
0.20
$12,000/yr.
$18,000/yr.
$25,000/yr.
Units/Ton
of NH3
4.27
1.08
3.5
103
76
0.74
$/Ton NH3
51.11
16.33
1.22
1.70
70.36
0.45
2.28
0.15
73.24
0.99
0.21
0.07
0.45
8.31
10.03
0.89
3.11
18.88
22.88
106.15
41.53
3.46
151.14
Based on $1.90/million BTU for high sulfur fuel oil, $2.40 for low sulfur oil and 6.3 million Btu/bbl.
70
-------
The makeup naphtha used for the soot removal cycle is considered as an
energy input because this makeup replaces that left in the heavy oil sent to
the reactor.
This process can take advantage of the lower cost of high sulfur residual
oil, because (as part of the process) the hydrogen sulfide formed is removed
in a form amenable to conversion to marketable sulfur in a Glaus process plant.
However, supplemental steam must be based on higher cost low sulfur oil,
because removal of sulfur oxides from the stack gas of the boiler.is not
economically feasible with the current alternatives for this size unit. Con-
sideration has been given to incorporating the flue gas into the Glaus plant
feed, but the dilution effects of the low sulfur oxide gas, combined with the
power consumption of blowers, make this alternative uneconomical compared to
purchasing low sulfur fuel.
c. Energy Usage
The total energy consumption of the process, expressed in equivalent
British thermal units is 35.24 million Btu/ton of ammonia, as shown below:
106 Btu/ton
Feedstock 4.27 bbl @ 6.3 x 106 Btu/bbl 26.90
Fuel 1.08 bbl @ 6.3 x 106 Btu/bbl 6.80
Naphtha 3.5 gal at 130,000 Btu/gal 0.46
Power 103 kWh @ 10,500 Btu/kWh 1.08
Total 35.24
The form of energy used can be varied considerably depending on the
relative value of the energy forms and the cost of capital. For example,
instead of using a boiler fired with low sulfur oil to generate steam for
turbine drives, some turbines could be replaced with electric motors to the
extent that essentially no fuel would be needed except for startup steam.
Power consumption, of course, would increase drastically and total production
costs would also increase, as would total energy, expressed as Btu, using
10,500 Btu as the fuel input to produce 1 kWh. The probable optimum situation
is as developed above.
d. Effluent Controls Required for Heavy Oil Gasification Alternative
The schematic representation of the process considered here is shown in
Figures IV-10, -11, -12, and -13. The nature of the pollutant emissions are
summarized in Tables IV-26, IV-27, and IV-28.
71
-------
BFW
CO2
Tail
Gas
Product
Gas From
Scrubber
(See Figure
IV-10)
Carbon
Monoxide
Shift
Steam
to
Heat Recovery
And Cooling
-m
BFW
Spent
Catalyst
*Boiler Feed Water
Steam
H2SRich
Gas
Tail
Gas
Carbon Dioxide
and H2S
Removal
(Rectisol)
Condensate to
Boiler Feed
Water Treatment
For Recycle
Nitrogen
For Stripping
From Air
Separation Plant
Nitrogen
Wash
Water with
Methanol
Synthesis
Gas to Compression
And Ammonia
Synthesis
Nitrogen
from Air
Separation
Plant
Figure IV-11. Carbon Monoxide Shift and Synthesis Gas Purification
-------
BFW
Sulfur Rich
Gas Stream
Sulfur
Recovery
(Glaus Plant)
Steam
2 -
Tail Gas
Clean Up
(Beaven or IFP)
Molten Sulfur
To Storage
"Boiler Feed Water
Figure IV-12. Sulfur Recovery
BFW
Purge
used as
Supplemental
Fuel
Synthesis Gas
Condenser
Waste
Heat
Boiler
Steam
Compressor
and
Circulator
Ammonia
Catalytic
Converter
Iron Oxide Catalyst
Figure TV-13. Ammonia Synthesis
73
-------
TABLE IV-26
, , , 'Method of
WATER EFFLUENTS* -AMMONIA-FROM-HEAVY OIL ALTERNATIVE Handling
Soot recycle system purge treated
Waste water from Rectisol unit treated
Waste water from sulfur recovery plant tail-gas cleanup treated
TABLE IV-27
AIR EMISSIONS* - AMMONIA-FROM-HEAVY OIL ALTERNATIVE
System vents for pressure let-down
Byproduct CO
Tail gas from Rectisol
Sulfur-rich stream from Rectisol
Tail gas from nitrogen wash
Glaus plant tail gas cleanup vent
Method of
Handling
infrequent; flared
potential for urea
manufacture
vented
to sulfur recovery
burned in boiler as
supplemental fuel
vented
Byproduct molten sulfur (storage & transfer facilities) marketed
Synthesis loop purge gas
TABLE IV-28
SOLID WASTES* - AMMONIA-FROM-HEAVY OIL ALTERNATIVE
T] Catalyst from CO shift
2| Molten sulfur
burned as supple-
mental fuel
Method of
Handling
recovered
marketed
*Keyed to Figures IV-10, 11, 12 and 13
74
-------
The gasification of heavy oil results in the following changes in
environmental input from those discussed in the corresponding section for the
natural gas base case:
• A sulfur recovery plant will be required, though it will be somewhat
smaller than the one for the coal alternative; and
• An additional wastewater stream, the soot recycle system blowdown,
must be treated.
These specific changes are discussed below.
e. Environmental Effects Related to Watery pollution
The gasification of heavy oil can be compared to gasification of coal in
the following ways:
• The synthesis gas purification system waste stream has the same
flows and approximate characteristics;
• There is no runoff in the oil alternative; and
• The wastewater from the sulfur recovery process is about
70% of the flow from the coal unit.
In addition, the oil gasification unit must treat the purge from the
soot recycle system. The characteristics of this stream are presented in
Table IV-29-
The total wastewater load (gallons per day) for the oil alternative is:
Cooling Tower Blowdown 800,000
Rectisol Purge 10,000
Tail Gas Cleanup Purge 6,000
Soot Recycle System Purge 41,000
There would also be a wastewater load associated with the ammonia produc-
tion unit. The stream is the same for all alternatives, so it has not been
included in the comparison.
• Wastewater Treatment Technology - While the biochemical oxygen demand
of the wastewater has not been determined, the wastewater contains
biodegradable substances and can be subjected to biological treat-
ment. Most likely, a treatment system quite similar to that used
to treat the wastewater from the synthesis gas purification waste-
water treatment in the coal gasification alternative could be
employed. The treatment system would consist of:
75
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TABLE IV-29
SOOT RECYCLE SYSTEM SLOWDOWN
Volume ,-jv 41,000 gpd
Composition ppm
Ash 0.1
H2S 25
TDS 5000
NH3 300
Hydrocarbons 10
(1)0il basis used
Sulfur 6.2 percent
NaCl 30 ppm
Ash 200 ppm
Source: Schlinger, W.G. and Slater, W.L., Application of the Texaco
Synthesis Gas Generation Process Using High Sulfur Residual
Oils as Feedstock. Paper No. 1542, Texaco Inc., Montebello
Research Laboratory, Montebello, California.
• A 24-hour equalization basin;
• A 15-day aerated lagoon;
• A 15-day non-aerated (anaerobic) lagoon; and
• A chemical feed system.
In the treatment process, ammonia would be removed by 'a combination
of air stripping and biological oxidation to nitrate followed by
denitrification. To effect denitrification, sufficient carbon must
be present; so it is possible that supplementary methanol would have
to be added to the non-aerated lagoon.
With proper operation, it should be possible to achieve a 90%
removal of ammonia and hydrogen sulfide, thus producing an effluent
containing 30 ppm ammonia and 2.5 ppm hydrogen sulfide.
Wastewater'Treatment Costs - Treatment costs are presented in
Table IV-30.
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TABLE IV- 30
OIL GASIFICATION ALTERNATIVE
INCREMENTAL WASTEWATER TREATMENT COST ESTIMATES
(BASIS: 1000 TPD AMMONIA PRODUCTION)
CAPITAL INVESTMENT. $
ANNUAL OPERATING COSTS
INDIRECT COSTS
Depreciation
Return on Investment (@ 202)
Taxes and Insurance (@ 2%)
TOTAL INDIRECT COSTS
DIRECT COSTS
Operating Labor
Maintenance
Chemicals
Electric Power
Sludge Disposal
TOTAL DIRECT COSTS
TOTAL ANNUAL COST
UNIT COST, ($/Ton)
Synthesis Gas
Purification System
Wastewater
$186,000
Soot Recycle
System
Slowdown
$350,000
Total
$536,000
16,900
37,200
3,700
$57,800
14,700
7,100
800
5,400
1,600
$29,600
$87,400
$0.26
31,800
70,000
7,000
$108,800
16,500
14,000
2,500
13,900
1,000
$47,900
$156,800
$0.46
48,700
107 , 200
10,700
$166,600
31,200
21,100
3,300
19,300
2,600
$77,500
$244,200
$0.72
SOURCE: ADL Estimates
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f. Environmental Effects Relating to Air Pollution
The air pollution associated with oil gasification is less than that
associated with coal in that there is no coal-related dust source. The only
air emission of significance is the sulfur-laden exhaust from the carbon
dioxide and hydrogen sulfide removal exhaust. The stream must be controlled
using a sulfur recovery plant with a tail gas cleanup plant. The capital costs
of, the sulfur recovery process were shown in Figure IV-9. For an oil feed-
stock, the plant would produce about 42 tons of sulfur per day as opposed to
60 tpd produced with coal. The operating costs are shown in detail in
Table IV-31. The resulting cost of $2.74/ton of ammonia is only slightly less
than the cost of sulfur control relating to the coal alternative.
g. Environmental Effects Relating to Soj.id Wastg Disposal
The wastewater treatment system will produce very little sludge because
of the low quantity of BOD present. We estimate that less than 200 tons per
year of wet sludge would be generated by the wastewater treatment plant. The
cost of disposal is included in the wastewater treatment costs.
78
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TABLE IV-31
SULFUR CONTROL COSTS FOR ACID GAS EXHAUST
OIL GASIFICATION ALTERNATIVE
(Basis: 1000 TPD of Ammonia, 42 long ton/day Sulfur)
CAPITAL COSTS. $1.000*3 $3,050
ANNUAL. OPERATING COST. $l,000's/Yr
Indirect Operating Costs
- Depreciation, 11 years 277
- Return on Investment (@ 202) 610
- Insurance and Taxes (@ 2%) 61
TOTAL INDIRECT COSTS $948
Direct Operating Costs
- Labor
Direct (@ $6.00/Hr, 1 Man/Shift) 50
Supervision (@ 15% of Labor) 7
Labor Overhead (@ 35% of Direct and Supervision) 20
Plant Overhead (@ 70% of Direct and Supervision) 39
- Maintenance (@ 5%) 153
- Utility
Electric Power (@ 140 kWh/LT, $0.02/kWh) 40
Fuel (@ 0.08 106 Btu/LT, $2.00/106 Btu) 23
Cooling Water (@ 20,000 gal/LT, $0.03/103 gal) 8
- Chemicals (@ $2.50/LT in tailgas) 2
TOTAL DIRECT COSTS $342
Byproduct Sulfur Credit (@ $25/LT, 42 LT/D) (357)
i
TOTAL ANNUAL COST, $l,000"s/Yr $933
UNIT COST, $/ton NH3 $2,74
SOURCE: ADL Estimates
79
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V. IMPLICATIONS OF POTENTIAL INDUSTRY/PROCESS CHANGE
Several changes in practice will occur in ammonia manufacture due to
both the shortage of natural gas and environmental regulations. These
changes include the addition of air preheaters to new and existing ammonia
plants to decrease fuel consumption; conversion from natural gas to fuel
oil in firing ammonia reformers, boilers, and dryers; the separation of
hydrogen from the purge gas in the ammonia synthesis loop; and the building
of new ammonia plants based on petroleum or coal both for fuel and for feed-
stock. Of these, the only changes that meet the criteria of this study are
the production of ammonia from coal or petroleum in new plants.
Ammonia manufacturers are among the largest energy users in the country.
We estimate that in 1973, ammonia plants consumed 590 billion cubic feet of
natural gas, or 2.4% of total U.S. natural gas use. Ammonia forms the basis
for nearly all nitrogen fertilizers and is also used along with its deriva-
tives for the manufacture of other basic nitrogenous chemicals. About 20% of
the ammonia production is for non-fertilizer uses. In the United States, its
manufacture depends on natural gas, both as a raw material and as a fuel.
The ammonia industry in the United States and worldwide has seen
tremendous growth over the years. Output in 1973 was almost ten times that
of 1950 for an average annual growth rate over the 23-year period of over 10%
per year. This reflects almost exactly the growth rate in nitrogen fertilizers
in the United States, which has had a dynamic long term growth.
The shortage of natural gas has contributed to the problems of the United
States ammonia industry. While the gas shortage is a nationwide phenomenon,
each gas pipeline or supplier has his own unique problems, and these problems
are of differing severity. A Fertilizer Institute survey indicates that only
231,000 tons of ammonia production were lost because of gas cutbacks in fiscal
year 1973/74; about 1.5% of total production capability. Today, however,
several ammonia plants are closed because of the inability to get natural gas,
and the situation is worsening.
While existing plants have been able to get gas supplies, it is difficult
for a new plant to obtain gas. Unless natural gas can be made available, new
plants to supply increased requirements in the future will have to use fuel
oil or coal both for feedstock and for process heat. Many existing plants
may have to convert their reformers to fire fuel oil. However, this latter
change is a fuel switch and would not involve a change in the chemistry of
the process, because gas would still be used as a feedstock. Basing new
plants on liquid or solid feeds, however, implies new processes. Using fuel
oil as a raw material for ammonia plants would require new technology for the
United States. This technology is commonplace in other parts of the world,
but not here. Similarly, the use of coal as a raw material for the manufacture
80
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of ammonia will require new technology. There are a few coal-based
ammonia plants in the world, but in the past coal-based plants generally
have not been economical.
The use of fuel oil and coal for the manufacture of ammonia will require
partial oxidation processes. These will require oxygen, which in turn will
require large amounts of electric power. Associated with the generation of
power is additional pollution. The fuels for electric power generation are
significantly higher in sulfur than is natural gas, and it will be necessary
to remove this sulfur. This in turn could imply increased sulfur contents of
waste streams, either liquid or solid.
The use of coal as a feedstock will result in increased mining, transport-
ing, and handling of coal, again with associated pollution problems. About
1.3 tons of coal are required per ton of ammonia.
An additional consideration in the manufacture of ammonia from coal would
be the potential need to develop improved water pollution control technology
if plants are to be located near western coal. Generally, they are located
in arid areas where rivers and streams have less tolerance for pollutants.
Thus, water pollution restrictions on ammonia plants located in the West may
have to be even more severe than for those located in other parts of the
country.
Western coal may not be a preferable starting material for ammonia
plants -because it is not near potential markets. Also, the ability of an
ammonia plant to use high sulfur coal would encourage ammonia producers to
use high sulfur coal because of its lower value. Nonetheless, low-sulfur
western coals can be made available fairly cheaply, and they conceivably
could be used as raw materials.
The alternates to natural gas, if arranged in order of capital invest-
ment and proven, reliable, processes, would be naphtha or LPG's, residual
fuel oils, and (by most rankings, a very distant third) coal.
Naphtha and LPG's do not represent a viable alternate solution because
of their very limited future incremental availability and high value for
alternative uses, essentially the same situation as projected for natural
gas. Also, the dramatic changes in the value of convenience energy place a
different emphasis on the relative value of capital investment and associated
charges. For example, with natural gas at 25
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This large difference in projected value between gas and oil, and
coal, certainly justifies a careful consideration of coal as a feedstock
for ammonia production.
A. AMMONIA FROM COAL
1. Impact on Pollution Control
The following additional emissions must be controlled when producing
aamonia using coal feedstock:
• Water
- Coal and slag pile runoff,
- Wastewater from syngas purification processes;
• Air
- Coal handling and grinding,
Sulfur-rich stream from syngas purification; and
• Solid
Slag,
- Sulfur, and
- Wastewater treatment sludge.
To control the above emissions, an additional $8.7 million is required
in capital investment for a plant, equivalent to 8.6% additional investment
(Table V-l). About 53% is related to control of runoff arid the remainder
to control of air emissions, the most significant cost being for the removal
of sulfur from syngas purification emissions. Also associated with environ-
mental control for the 1,000-ton-per-day plant are annual operating costs
totalling $2.9 million ($8.65 per ton of ammonia). About 59% of these costs
are for control of water effluents from runoff and, to a lesser degree, the
synthesis gas purification processes. The air control costs are for coal
handling emissions and recovery of sulfur from the syngas purification process.
The costs associated with slag disposal are factored into the water cost as
runoff control, assuming onsite disposal of the slag. This can be translated
to an offsite disposal by using an estimated charge of $15 per ton of slag.
There will be no unique problems meeting the environmental standards
which may be associated with producing ammonia from a coal feedstock. The
difficulties are expected to be similar to those encountered in electric power
generation and in industrial use of coal-fired boilers. In addition, because
the quantities of coal required are large enough to justify location near an
existing mine or the opening of a new mine, there will be the additional
pollution aspects related to mining.
82
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TABLE V-l
CAPITAL INVESTMENT SUMMARY FOR ENVIRONMENTAL CONTROL
(Basis: 1000 TPD Ammonia Plant)
Alternative Feedstock
Oil Coal
Water Pollution Control Costs, $1000's
Runoff Control and Treatment 4,429
Synthesis Gas Purification 186 200
Solids Purge 350
Total 536 4,629
Air-Pollution Control Costs, ?1000's
Feedstock Handling 460
Synthesis Gas Production 3,050 3,600
Total 3,050 4,060
TOTAL EMVIRDNMENTAL COSTS, $1000's 3,585 8,689
Source: ADL Estimates
TABLE V-2
ANNUAL INCREMENTAL OPERATING COST SUMMARY
FOR ENVIRONMENTAL CONTROL
(Basis: 1000 TPD Ammonia Plant)
Alternative Feedstock
Oil Coal
Water Pollution Control Coats. $1000's/yr
Runoff Control and Treatment 1,649
Synthesis Gas Purification 87 96
Solid Purge 157
Total 244 1,745
Air Pollution Control Costs. $1000's/yr
Feedstock Handling 185
Synthesis Gas Production 933 1010
Total 933 f!95
TOTAL. $1000's/yr 1"7 2,940
Unit Cost. $/ton of Ammonia 3.46 8.65
Source: ADL Estimates
, 83
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2. Impact on Energy
In controlling the emissions from an ammonia plant based on coal, which
are incremental to those for the same plant based on natural gas, 166 x 10
Btu per ton of ammonia are consumed. This amounts to approximately 56 billion
Btu per year (Table V-3). This is only an increment of 0.5% over that needed
for production. About 71% of the energy is in the form of electrical power
(3.8 billion kWh/year).
Ammonia production has a significant energy requirement. The amount
required for environmental control is an incremental 0.5%.
3. Factors Affecting Probability of Change
A few ammonia-from-coal plants have been built in the world, but further
process improvements will be required before such plants can become viable for
the United States. Significant environmental impact may be felt by the manu-
facture of ammonia from coal. Such plants would probably be located near coal
mines and may in fact justify the opening of new mines. Because ammonia
plants based on coal can normally use high sulfur coal, it would probably be
to their advantage to do so. High sulfur coal (3-5%) will have an intrinsi-
cally lower value than low sulfur coal, and since it is possible to use the
lower value material, ammonia producers probably would do so. This may
result in the manufacture of significant quantities of byproduct sulfur but
could alternatively result.in sulfur discharges in the form of a solid waste
stream. The cost of manufacturing ammonia from coal would also have to be
competitive. Figure V-l provides a comparison of the ammonia production costs
for various coal and natural gas prices. Note that, until the price of natural
gase reaches $2.50/10 Btu and coal remains at $0.95/106 Btu or less ($17.20/
ton), the new feedstock is not attractive unless there are overriding factors
in a specific area — such as the unavailability of natural gas.
The investment required for a coal-based plant is higher than that for
one based on liquid or gaseous hydrocarbons. Nevertheless, when faced with
a continuing shortage of natural gas, the industry will have to find other
fuels and feedstocks. Thus, coal must be considerably cheaper on a Btu basis
than competing fuels to make investment attractive. A plant constructed to
handle coal can be switched to either natural gas or heavy oil essentially
while on-stream, thus taking advantage of the price differentials among
these fuels as they change from tinie to time. However, the penalties
associated with the higher investment required for the coal-based plant will
remain.
4. Areas of Research
Investigations are advisable to identify the path of the metals present
in coal through the gasification process to determine their presence in the
solid wastes such as slag, in the air and water emissions, and in process
recycle streams.
84
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TABLE V-3
ENERGY CONSUMPTION SUMMARY FOR ENVIRONMENTAL CONTROL
Water Pollution Control
Electric Power (106 kwh/yr)
Fuel (106 Btu/yr)
Total Fuel Equivalent 8 10,500 Btu/kWh
Air Pollution Control
Electric Power (106 kWh/yr)
Fuel (106 Btu/yr)
Total Fuel Equivalent U 10,500 Btu/kHh
(10' Btu/yr)
TOTAL ELECTRIC POWER (lO6 kWh/yr)
TOTAL FUEL (106 Btu/yr)
TOTAL FUEL EQUIVALENT » 10,500 Btu/kWh
(106 Btu/yr)
Source: Arthur D. Little, Inc. estimates.
Alternative Feedstock
Oil Coal
10,130 7,402
2.000 3.090
11,500 16,500
32,500 48,945
2.965
11,500
42,630
125,400
3.795
16,500
56,347
165,700
0.25 O.SO 0.75 1.00 1.25 1.50 1.75 2.OD 2.26 2-50
F«ditockPrl«S/106Bu
Figure V-l:. Effect of Natural Gas and Coal Prices Upon Ammonia Prices
85
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B. AMMONIA FROM PETROLEUM
1. Impact On Pollution Control
The following additional emmisions must be controlled when producing
ammonia using oil feedstock:
• Water
Wastewater from syngas purification processes;
• Air
Sulfur-rich stream from syngas purification; and
• Solid
- Sulfur, and
- Wastewater treatment sludge.
To control the above emissions, an additional $3.6 million will be required in
capital investment for plant, equivalent to 5.1% additional investment
(Table V-l). About 85% of 'this additional investment is required for control
of air emissions with the major portion required on the sulfur-rich exhaust
from the syngas purification process. The annual operating costs associated
with environmental control for the 1,000-ton-per-day plant are $1.2 million.
About 79% of this annual cost is for control of sulfur emissions from the
syngas purification process. The remainder is for treatment of wastewater
streams from oil gasification and from syngas purification. These combined
capital related and direct operating costs can be translated to $3.46 per ton
of ammonia. No unique problems are expected in meeting the environmental
standards which may be associated with producing ammonia from heavy fuel oil
feedstock. The difficulties are expected to be similar to other industrial
applications of residual fuel oil.
2. Impact on Energy
In controlling the emissions from an ammonia plant based on oil, which
are incremental to those for the same plant based on natural gas, 125 x 1CH
Btu per ton of ammonia are consumed. This amounts to approximately 43 billion
Btu per year (Table V-3), and about 72% of this energy is in the form of
electrical power (3.0 million kWh/year). Since ammonia production has a
significant energy requirement, the amount required for environmental control
is only an incremental 0.2%.
3. Factors Affecting Probability of Change
This technology is commonplace in countries outside the western hemisphere
but no plants in the United States produce ammonia from' petroleum. New
plants built to manufacture ammonia from petroleum will probably be based on
the heavier petroleum fractions, because over the long term they will probably
be less expensive than lighter fractibns such as LPG and naphtha. There will
86
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be environmental problems associated with these plants, however, tech-
nology already exists to overcome many of the problems. It remains only
to translate this technology to specific applications.
The cost of manufacturing ammonia from petroleum would also have to be
competitive. Figure V-2 provides a comparison of the ammonia production costs
for various petroleum and natural gas prices. Note that, if the price of
natural gas reaches $2.65/million Btu, residual fuel oil will be an attractive
new feedstock if it is available for less than $2.00/million Btu.
4. Areas of Research
The process is well documented. Little research is required and the
companies involved are pursuing those areas.
200 -I
190-
180-
170-
.a
c
< lee-
's
I '50-
S 140-
130
120-
110-
100-
90 -
80
Residual Fuel Oil
Natural Gas
0.25 0.50 0.75 1.00 1.25 1.50 1.75 2.00 2.25 2.50 2.75
Feed, ck Price S/106 Btu
•Figure V-2. Effect of Natural Gas and Residual Fuel Oil
Prices Upon Ammonia Prices
87
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
HPA-6Dfl/7-76-Q34g
2.
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
5NVIRONMENTAL CONSIDERATIONS OF SELECTED ENERGY CONSERV-
ING MANUFACTURING PROCESS OPTIONS. Vol. VII. Ammonia
[ndustry Report
S. REPORT DATE
December 1976 issuing date
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Arthur D. Little, Inc.
Acorn Park
Cambridge, Massachusetts 02140
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-03-2198
12. SPONSORING AGENCY NAME AND ADDRESS
Industrial Environmental Research Laboratory
Office of Research and Development
U.S. Environmental Protection Agency
Cincinnati, Ohio 45268
13. TYPE OF REPORT AND PERIOD COVERED
FINAL
14. SPONSORING AGENCY CODE
EPA-ORD
15. SUPPLEMENTARY NOTES
Vol. IV-XV, EPA-600/7-76-034d through. EPA-600/7-76-034o, refer to
studies of other industries as noted below; .Vol I, EPA-600/7-76-034a, is the Industry
Summary Re-port and Vol. TT F.PA-fifln/7— 7ft—
-is t-1-ig TnHiigf-T-u Pi--irvr-i t-
y
16. ABSTRACT
This study assesses the likelihood of new process technology and new practices being
introduced by energy intensive industries and explores the environmental impacts of
such changes.
Specifically, Vol. VII deals with the ammonia industry and analyzes the production
of ammonia based on coal gasification and the production of ammonia based on heavy
oil gasification in terms of process economics and environmental/energy consequences.
Vol. III-XI and Vol. XIII-XV deal with the following industries: iron and steel,
petroleum refining, pulp and paper, olefins, aluminum, textiles, cement, glass,
chlo'r-alkali»phosphorus and phosphoric acid, copper, and fertilizers. Vol. I presents
the overall summation and identification of research needs and areas of highest
overall priority. Vol. II, prepared early in the study, presents and describes the
overview of the industries considered and presents the methodology used to select
industries.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
COSATI Field/Group
Energy
Pollution
Industrial Wastes
Ammonia
Manufacturing Processes;
Energy Conservation;
Coal Gasification;
Syngas
13B
18. DISTRIBUTION STATEMENT
Release to public
19. SECURITY CLASS (ThisReport)'
unclassified
21. NO. OF PAGES
104
20. SECURITY CLASS (This page)
unclassified
22. PRICE
EPA Form 2220-1 (9-73)
88
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