D A U.S. Environmental Protection Agency Industrial Environmental Research DA
CL r M Office of Research and Development Laboratory
Cincinnati, Ohio 45268 December 1976
ENVIRONMENTAL
CONSIDERATIONS OF
SELECTED ENERGY
CONSERVING MANUFACTURING
PROCESS OPTIONS:
Vol. VI. Olefins
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-600/7-76-034f
December 1976
ENVIRONMENTAL CONSIDERATIONS OF SELECTED
ENERGY CONSERVING MANUFACTURING PROCESS OPTIONS
Volume VI
OLEFINS 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 (lERL-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
Industry has an annual energy consumption of about 27 quads (10
which accounts for approximately 40% of the U.S. energy usage.** The energy
shortages facing this country are causing all industry to examine methods to
reduce its very large energy consumption. In some instances, methods for
saving energy may have related environmental consequences. In order to
identify these, this study examines possible methods of energy savings and
the environmental consequences resulting from introducing basic processing
changes.
Other methods of energy savings, such as by conservation (i.e., reducing
heat loss, shutting off standby furnaces, etc.)* by improved heat recovery,
by fuel switching in steam generation or electrical power generation, were not
examined in this study.
Many industries were surveyed to determine which ones would have the
greatest relevance in a study of this type. Thirteen industries were ulti-
mately selected for study and among these the olefins industry was ranked the
fourth most relevant, partially based on its purchase in 1974 of about one quad
of energy including feedstock usage.
The olefins industry, the largest segment of the industrial organic chem-
icals (SIC 2869), is categorized in this report to include facilities produc-
ing ethylene and the coproduction of propylene and the diolefin, butadiene.
The subsequent conversion of these olefins in downstream derivatives plants
to useful products is not considered to be part of the olefins industry.
U.S. production of ethylene in 1974 amounted to over 23 billion pounds
and represented a value of about $1.5 billion. The materials coproduced with
the ethylene added an additional one billion dollars to that value. Based on
estimated growth of the derivatives produced from ethylene, it is estimated
that the demand for ethylene will grow at a rate of 8% per year for the next
10 years. The cost of producing ethylene, however, will increase significantly
because of the higher cost of feedstocks and higher costs for constructing
new facilities.
Over 80% of the ethylene produced in the U.S. is produced from the pyrol-
ysis of ethane and propane which in turn are derived mainly from natural gas
sources. The remaining ethylene is produced from naphtha, from gas oil, and
to a lesser extent from butane and byproduct refinery streams. The projected
shortages of natural gas in this country will cause curtailment in the supply
*1 quad = 1015 Btu
**Purchased electricity valued at fossil fuel equivalence of 10,500 Btu/kWh.
IV
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of additional ethane and propane". Thus, to meet the increasing demand for
ethylene, most new ethylene facilities are expected to utilize heavier
feedstocks such as naphtha and atmospheric gas oil in the next six to eight
years.
The use of heavier feedstocks for ethylene production will have more of
an impact on the environment than the use of ethane-propane feedstocks since
the heavier materials almost always contain more impurities—with sulfur being
the one of most concern. The expected change in olefin plant feedstocks from
lighter materials to heavier materials is not to conserve energy per se, but
to utilize energy with a lower form value. The olefin producers are now
building and will continue to build new ethylene capacity using naphtha and
gas oil as the primary feedstocks.
The base case for this study was an ethane-propane ethylene cracker from
which comparisons could be -made with the assessments prepared for naphtha and
gas oil cracking.
Technology now exists which allows heavy liquid olefin crackers to be
operated in a manner which is expected to be environmentally acceptable. The
estimated costs for these anticipated environmental controls range from 0.5
to 1.75% of the cost of producing ethylene—a significant aggregate cost con-
sidering the large amount of ethylene produced in this country (23 billion
pounds in 1975). In addition, it should be noted that, on the basis of 1975
prices of feedstocks and byproducts and escalating plant construction costs,
the ethylene produced from naphtha and gas oil cracking is estimated to cost
about 30% more than when produced from cracking ethane and propane.
Further work is desirable to develop techniques to desulfurize the cracked
gas product more efficiently when high-sulfur naphtha or gas oil is used as
feedstock. Also, more flexibility in the choice of feedstock with subse-
quent improved economics would be possible if a viable method for desulfur-
izing pyrolysis fuel oil could be developed.
A review was also made of developing technologies for producing olefins
from heavier, more available and less costly feedstocks than ethane-propane,
naphtha or atmospheric gas oil. The feedstocks included in this review are
vacuum gas oil, vacuum residues, crude oil and coal. The technologies reviewed
include coil cracking, fluid bed cracking and autothermic cracking of heavy
petroleum-based feedstocks and plasma cracking and byproduct production from
coal.
We do not believe that this developing technology will have a significant
impact on the olefins industry until the late 1980's. Development work is
already under way on this new technology and the economic incentives for
utilizing these lower form values of feedstocks for olefins production are
v
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expected to be large enough to insure the continued development and ultimate
commercialization by industry. Industry is well aware of the environmental
constraints which are placed upon them and it is expected that during the
development of this new technology environmental controls will be developed
simultaneously.
As in all developing technology, it is difficult to predict all of the
environmental problems which may be present. It is expected, however, that
the major environmental impact of this developing technology for olefins
production will not be in new areas but will manifest itself in more severe
problems in the existing areas of environmental impact such as sulfur and
organics emissions.
The impact of energy requirements for the olefin processes considered
is shown in Table ES-1. The implication of this impact is that the
gross demand for energy for producing a pound of ethylene increases as feed-
stock quality declines. Hence, energy conservation is achieved only in terms
of form value displacement. That is, the use of these advanced thermal
cracking technologies will allow a reduction in the demand for gas liquids,
naphtha and atmospheric gas oil but increase demand for the less useful vacuum
gas oil, vacuum residue, crude oil and coal. In all cases, they will con-
sume more energy per pound of ethylene equivalent than coil cracking of the
former feedstocks. However, the energy consumption per pound of net product
will be in line with that of present technology if coproduced oils and pitches
can be utilized effectively. Coal-derived acetylene consumes about twice the
energy per pound of net product than the petroleum-based alternative but can
achieve total independence from petroleum derivatives.
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 February 9, 1976.
VI
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TABLE ES-1
FEED AND ENERGY REQUIREMENTS FOR ALTERNATIVE OLEFINS PROCESSES
Feedstock
Total Energy
Technology Feed Required l5lL?l^eJLj'Jl°.d..H.9?£3 Energy Consumption (Btu/lb net products) Consumption
Petroleum Based
E-P
Naphtha
Atmospheric Gas Oil
Vacuum Gas Oil
Vacuum Resid
Crude Oil
Coal Based
Coal
Ccal
Coil Cracking
Coil Cracking
Coil Cracking
Coil Cracking
Fluid Bed
Autothermic
Plasma Cracking
Clean Coke
(lb/]b of
ethylene')
1.56
3.05
4.95
4.95
6.17
2.54
2.90
2
32.2
(Ib/lb of
ethylene1)
1.23
2.26
3.02
3.20
4.46
1.72
1.36
n.a.
Feedstock
27,670
26,950
26,090
28,600
24,200
27,320
30,390
n.a.
Utilities
13,510
7,775
7,180
11,130
11,200
10,460
43,435
n.a.
Fuel Credit
(7,140)
(7,285)
(6,670)
(10,500)
(10,600)
(9,580)
(8,425)
n.a.
Total
34,040
27,440
26,600
29,230
23,600
28,200
65,400
n.a.
(Btu/lb
ethylene)
42,100
62,100
80,300
93,500
105,200
48,500
88,900
n.u.
or ethylene plus acetylene
2
metallurgical coke, not ethylene, is the major product from this process
3
including ethylene and other coproducts less internal fuel consumption
Sources: Proceedings of Ninth World Petroleum Congress Tokyo, 1975 Vol. 5, OCR R&D Report No. 67
(14-32-0001-1215), Hyd. Proc. Vol. 44 Nov. 4, CEP Vol. 71 Nov. 1.1.
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TABLE OF CONTENTS
FOREWORD
EXECUTIVE SUMMARY
List of Figures
List of Tables
Acknowledgments
Conversion Table
I. INTRODUCTION 1
A. BACKGROUND 1
B. CRITERIA FOR INDUSTRY SELECTION 1
C. CRITERIA FOR PROCESS SELECTION 2
D. SELECTION OF OLEFINS INDUSTRY OPTIONS 3
II. FINDINGS, CONCLUSIONS, AND RECOMMENDATIONS 6
A. IMPLICATIONS OF ENVIRONMENTAL REGULATIONS ON ALTERNATIVE
FEEDSTOCKS FOR OLEFINS PRODUCTION 7
B. ADDITIONAL RESEARCH REQUIRED 8
III. INDUSTRY OVERVIEW 10
A. OLEFIN INDUSTRY DESCRIPTION 10
B. ECONOMIC OUTLOOK 13
IV. COMPARISON OF CURRENT AND ALTERNATIVE PROCESSES 14
A. REASONS FOR SELECTING OPTIONS ANALYZED IN DEPTH 14
B. BASE LINE TECHNOLOGY: ETHANE-PROPANE CRACKING 16
1. Definition 16
2. Energy Use in E-P Crackers 16
3. Emission Profile 18
4. Technical Considerations 18
5. Products of E-P Cracking 20
6. Cost Factors 20
t
C. ETHYLENE FROM THE PYROLYSIS OF NAPHTHA 22
1. Current Status of Naphtha Cracking 22
2. Energy Use in Naphtha Crackers 22
3. Technical Considerations 24
4. Effect on Intermediate and Final Products 26
5. Economic Factors 26
ix
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TABLE OF CONTENTS (Cont.)
Page
D. ETHYLENE FROM PYROLYSIS OF GAS OIL 27
1. Current Status of Gas Oil Pyrolysis 27
2. Energy Use in Gas Oil Cracking 28
3. Technical Considerations 30
4. Effect on Products from Gas Oil Cracking 30
5. Economic Factors 31
E. ENVIRONMENTAL CONSIDERATIONS OF ETHYLENE PRODUCTION
FROM PYROLYSIS OF NAPHTHA AND GAS OIL 31
1. Emission Profile 31
F. OTHER LONG-TERM PROCESS OPTIONS 53
1. Energy Considerations 53
2. Pollution Impact 54
V. IMPLICATIONS OF POTENTIAL INDUSTRIAL/PROCESS CHANGES 56
A. IMPACT UPON POLLUTION CONTROL/ENERGY REQUIREMENTS 56
B. FACTORS AFFECTING PROBABILITY OF CHANGE 59
C. AREAS OF RESEARCH 59
APPENDIX A - INDUSTRY STRUCTURE 62
APPENDIX B - PRESENT TECHNOLOGY 78
APPENDIX C - ENERGY USE - BASE LINE PROFILE 87
APPENDIX D - CURRENT POLLUTION PROBLEMS AND EFFECTIVENESS
OF AVAILABLE POLLUTION CONTROL TECHNOLOGY - go
BASE LINE CASE
APPENDIX E - ADVANCED OLEFIN PROCESS ALTERNATIVES 108
APPENDIX F - GLOSSARY 133
x
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LIST OF FIGURES
Number Page
IV-1 Ethylene From An E/P Cracker 17
IV-2 Pollution Source Identification: Ethane-Propane Cracking 19
IV-3 Ethylene From a Naphtha Cracker 23
IV-4 Ethylene From a Gas Oil Cracker 29
IV-5 Pollution Source Identification: Naphtha/Gas Oil
Cracking 33
IV-6 Acid-Gas Treatment System (Naphtha Cracker) 46
IV-7 Acid-Gas Treatment System (Gas-Oil Cracker) 47
IV-8 Capital Cost for Stretford Process 48
IV-9 Operating Cost for Stretford Process 48
A-l Distribution of Ethylene Plants in the United States 65
A-2 U.S. Ethylene Production as a Percent of 1974 Capacity 66
A-3 U.S. vs World Ethylene Production 69
A-4 U.S. Ethylene Production vs Consumption, 1953-1974 72
A-5 Distribution of Ethylene by Derivative Products, 1974 72
A-6 U.S. Trends in Ethylene Prices and Revenues, 1953-1974 74
A-7 Trends in Feedstock Supplies 77
B-l Base Line E/P Cracker 80
B-2 Economic Analysis Boundaries 86
C-l Ethylene From An E/t Cracker (50% Propane)
1.1 Billion Pounds per Year 88
C-2 Energy Flow Diagram: E-P Cracking 89
XI
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LIST OF FIGURES (Cont.)
Number . Page
D-l Pollution Source Identification/Ethane-Propane Cracking 91
D-2 Acid-Gas Removal System (Ethane-Propane Feedstock) 103
D-3 Decoke Spray Drum 104
E-l Front-End Flow Plan 110
E-2 Back-End Simplified Flow Plan 110
E-3 Schematic Diagram of Ethylene-From-Crude Oil Process 114
E-4 Circulation System for Cracking of Heavy Oil in
Fluidized Bed Reactor 120
E-5 AVCO Arc-Coal Process Schematic 124
E-6 Clean-Coke Process 129
xi i
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LIST OF TABLES
Number Page
ES-1 Feed and Energy Requirements for Alternative Olefins
Processes vii
1-1 Summary of 1971 Energy Purchased in Selected Industry Sectors 3
II-l Summary of Results of Process Options in the Olefins Industry 7
III-l United States Ethylene Producers - 1974 11
III-2 U.S. Ethylene Production/Feed Requirements, 1974 12
IV-1 Energy Consumption in Base Line E-P Cracker 16
IV-2 Ethane-Propane Base Case Pollution Profile 20
IV-3 Net Production from Base Line E-P Cracker 21
IV-4 Estimated Ethylene Production Cost Via E-P Cracking 21
IV-5 Energy Consumption in E-P and Naphtha Crackers 24
IV-6 Net Production from E-P and Naphtha Crackers 26
IV-7 Estimated Cost of Producing Ethylene Via Naphtha Cracking 27
IV-8 Energy Consumption in Pyrolysis Ethylene Production 28
IV-9 Net Production from Pyrolysis Ethylene Plants 31
IV-10 Estimated Cost of Producing Ethylene Via Gas Oil Cracking 32
IV-11 Summary of Pollutant Emissions 34
IV-12 Comparative Wastewater Flow Rates 35
IV-13 Comparison of Wastewater Loadings 37
IV-14 Summary Comparison of Wastewater Treatment Costs 39
IV-15 Comparison of BPCTCA Wastewater Treatment Costs 40
IV-16 Comparison of BATEA Wastewater Treatment Costs 40
IV-17 Comparison of Total (BPCTCA & BATEA) Wastewater Treatment
Costs xiii
41
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LIST OF TABLES (Cont.)
Number Page
IV-18 Comparison of Wastewater Treatment Energy Consumption 41
IV-19 Summary of Air Pollution Control Factors 43
IV-20 Approximate Sulfur Balance, Ib/hr 44
IV-21 Acid Gas Sulfur Conversion Control Costs 49
IV-22 Approximate Operating Hours Per Year for Decoking and
Acetylene Converter Regeneration Scrubber System 51
IV-23 Operating Cost of Decoking Scrubber System, $/Yr 51
IV-24 Feed and Energy Requirements for Alternative Olefins Processes 55
V-l Summary of Pollution Control Costs and Energy Requirements 57
V-2 Flue Gas Sulfur Control System 61
V-3 Operating Cost for Flue Gas Sulfur Control Systems 61
A-l Ethylene Production Units in the U.S. and Puerto Rico, 1974 63
A-2 Trends in Average Ethylene Plant Capacity 1966-1974 67
A-3 U.S. Ethylene Production/Feed Requirements, 1974 67
A-4 U.S. and World Ethylene Productions 69
A-5 U.S. Ethylene and Ethylene Derivatives Trade, 1969-1974 70
A-6 U.S. Ethylene Consumption by Derivative Product, 1974 71
A-7 U.S. Ethylene Prices and Revenues 73
A-8 Future Outlook: United States Ethylene Demand 75
A-9 Major Ethylene Expansions (by 12/77) 76
B-l U.S. Gulf Coast Naphtha Value Analysis 83
B-2 Estimated Ethylene Production Cost via E-P Cracking 85
B-3 Standard Cost Factors for Ethylene Plant Economics 85
C-l Energy Consumption in Base Line E-P Cracker 89
xiv
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LIST OF TABLES (Cont.)
Number Page
D-l Summary of Pollutant Emissions 92
D-2 Base Case Ethylene Production Unit Estimated Wastewater
Flow Rates 95
D-3 Base Case Complex Waste Load Contributions from
Production Units 95
D-4 Effluent Limitation Requirements 97
D-5 Wastewater Treatment Cost Basis and Major Capital
Equipment Items Included in Treatment Facility 99
D-6 Base Case Ethylene Production from Ethane-Propane Wastewater
Treatment Costs for Entire Complex 100
D-7 Base Case Ethylene Production from Ethane-Propane Wastewater
Treatment Costs Allocated to Ethylene Production 101
D-8 Design Considerations for Decoking Control System 106
D-9 Decoking Scrubber System Costs 106
E-l Feed Characteristics 111
E-2 Furnace Outlet Yields 111
E-3 Properties of Heavy Cracked Oil 112
E-4 Yields of Autothermic Crude Cracking Ethylene from Crude Oil 116
E-5 UCC Crude Cracking Process Estimated Operating Parameters 117
E-6 Properties of Oil Used in Test Operations 121
E-7 Material Balance for an Ethylene Center with Capacity of
300,000 Tons Ethylene per Year 121
E-8 Production Costs 128
E-9 Material Balance - Clean-Coke Process 131
E-10 Compositions of Gas Products from Hydrogenation of
Illinois No. 6 (Herrin) Coal 131
E-ll Carbonization Gas Analysis (wt %) 132
xv
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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 t'lis 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. Littlefield,
Adminis trat ive 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)
xvi
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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)
Dr.. 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
xvii
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ENGLISH-METRIC (SI) CONVERSION FACTORS
To Convert From
Acre
Atmosphere (normal)
Barrel (42 gal)
British Thermal Unit
Centipoise
Degree Fahrenheit
Degree Rankine
Foot
3
Foot /minute
Foot3
Foot2
Foot/sec
Foot2/hr
Gallon (U.S. liquid)
Horsepower (550 ft-lbf/sec)
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
To
Metre2
Pascal
Metre3
Joule
Pascal-second
Degree Celsius
Degree Kelvin
Metre
Metre /sec
3
Metre
2
Metre
Metre/sec
2
Metre /sec
Metre3
Watt
Watt
Watt
Metre
Joule
Metre
Metre
Metre
Metre
Pascal-second
Newton
Kilogram
Kilogram
Kilogram
Kilogram
Kilogram
Kilogram
Multiply By
4,046
101,325
0.1589
1,055
0.001
t° = (t° -32)/1.8
CK = tR/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
Source: American National Standards Institute, "Standard Metric Practice
Guide," March 15, 1973. (ANS72101-1973) (ASTM Designation E380-72)
xviii
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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 used for chemical
processing, raising steam, drying, space cooling and heating, process stream
cooling and heating, chemical feedstock and miscellaneous other purposes.
In many industrial sectors energy consumption can be reduced significantly
by better "housekeeping" (i.e., shutting off standby furnaces, better tempera-
ture 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 dis-
charges. The EPA, therefore, is interested in identifying and quantifying the
pollution loads of new industrial practices or processes, in determining whether
available control technology is adequate, and in identifying where additional
research and development efforts are needed to more completely quantify the
effluent streams or to develop technology to control the effluents.
B. CRITERIA FOR INDUSTRY SELECTION
In the first phase of the 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,
i
• 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.
-------
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.
1971 Census figures and on information provided from industry sources.
The olefins industry purchased 0.984 quads out of the 12.14 quads
purchased in 1971 by the 13 industries selected for study, or 4%
of the 27 quads purchased by all industry (see Table 1-1).
• Qualitative criteria relating to probability and potential for
process change, and 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 olefins industry appeared in
third place among the 13 industrial sectors listed.
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
selecting those to be included in this study, we have considered the needs
and limitations 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.
Moreover, pollution control methods resulting in energy conservation have been
included within the scope of this study. Finally, emphasis has been placed on
process changes with near-term rather than long-term potential within the
8 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,
certain 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
yielding recoverable energy could be mentioned);
« Fuel substitution in fired process heaters;
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TABLE 1-1
SUMMARY OF 1971 ENERGY PURCHASED IN SELECTED INDUSTRY SECTOR
SIC Code
15 In Which
Industry Sector 10 Btu/Yr Industry Found
1. Blast furnaces and steel mills 3.49(1) 3312
2. Petroleum refining 2.96 ' 2911
3. Paper and allied products 1.59 26
4. Oleflns 0.984(3) 2818
5. Ammonia 0.63(4) 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 0.12 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 of energy from process byproducts
(FEA Project Independence Blueprint)
Olefins only, includes energy of feedstocks: ADL estimates
(4)
Araonia feedstock energy included: ADL estimates
(5)ADL estimates
Source: 1972 Census of Manufactures, EPA Project Independence Blueprint,
USGPO, November 1974, and ADL estimates.
• Mining and milling, agriculture, and animal husbandry;
• Substitution of scrap (such as iron, aluminum, glass, reclaimed
textiles, 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
transportation of raw material).
D. SELECTION OF OLEFINS INDUSTRY OPTIONS
The olefins industry sector includes broad areas of operation: feedstock
acquisition,* olefin production, and derivatives manufacturing. However, the
first of these activities, feedstock acquisition, is more properly the province
of the natural gas industry and the petroleum industry, while the last, deriva-
tives manufacturing, is better discussed as part of the petrochemical industry
and would be very difficult to assess in a study such as these. Hence, we
*The major feedstocks used by the olefins industry today are ethane, propane,
LPG, naphtha, and gas oil - all materials which are also used extensively as
fuel.
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have focused on the basic olefin operation - the manufacture of ethylene -
and the coproduct of that operation, propylene. Butenes and the diolefin,
butadiene, - to the extent that they are byproducts of the ethylene manu-
facturing operation - aldo were included in this study. The primary manu-
facture of butenes and butadiene from the dehydrogenation of butanes and
butenes was not considered.
Finally, the olefins industry is somewhat different in that more than
80% of the energy purchased by most olefins plants is attributable to the
energy contained in the feedstock. Consequently, changes in feedstock could
have a major impact on energy conservation. Furthermore, in the olefins
industry changes of feedstock usually imply changes in the impurities con-
tained in the feedstock which, in turn, can cause environmental problems.
Therefore, while we did not include feedstock acquisition in this study, we
did consider the energy conservation and environmental implications caused
by a change in feedstock.
A list of possible alternative feedstocks to be used for olefins produc-
tion was developed, along with the various process options available for
converting these alternative feedstocks into olefins. After developing this
list, we subjectively assessed the:
• probability or potential for change in feedstock;
• energy consequences of the change; and
• pollution or environmental consequences of the change.
Because of the time and scope limitations for this study, we have not
attempted to prepare a comprehensive list of process options or consider all
economic, technological, institutional, legal implementation or other factors
affecting implementation of these changes. Instead, we relied on our own
experience and contacts in the industry to select for analysis reasonably
promising process options, especially those with near-term potential (about
8 years).
After considering possible feedstocks available for producing olefins,
the state of development of the technology using these feedstocks and the
environmental consequences of the possible change, we recommended the
following options for consideration in this study:
• Naphtha coil cracking,
• Atmospheric gas oil coil cracking,
• Vacuum gas oil coil cracking,
• Hydropyrolysis of conventional feedstocks,
• Autothermic pyrolysis of heavy oils,
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• Fluid bed cracking of heavy oils,
• Plasma arc pyrolysis of coal, and
• Ethylene byproduct production from coke manufacture.
After discussing these options with the Project Officer, EPA advisors and
industry representatives, we chose the first two from this list for an in-
depth analysis. The choice of naphtha and atmospheric gas oil coil cracking
as options for in-depth analysis is based on the relative availability of
naphtha and atmospheric gas oil along with the existence of demonstrated
technology on a commercial scale for using these feedstocks for olefins
production.
To provide a basis of comparison, we also prepared an in-depth analysis
of a conventional olefins production facility using ethane-propane (E-P) as
feedstock. This is a reasonable base line since over 80% of the ethylene
produced in this country comes from ethane and propane cracking. The six
remaining options, which are longer-range possibilities (longer than 8 years)
for olefins production, are also analyzed, but to a much lesser extent,.since
the analyses are based only on information in the literature and discussion
with industry representatives.
The overview of the olefins industry is based on data for 1974, the
last representative year for the industry for which we had good statistical
information. Recognizing that capital investments and energy costs have
escalated rapidly in the past few years and have greatly distorted the tra-
ditional basis for making cost comparisons, we developed costs representative
of the first half of 1975, using constant 1975 dollars for a comparative
analysis of new and current processes.
-------
II. FINDINGS, CONCLUSIONS, AND RECOMMENDATIONS
The major impact of the current energy crisis on the olefins industry
will be to force the use of heavier feedstock in most new olefins plants.
These heavier feedstocks - naphtha and atmospheric gas oil - do not give
as high a yield of ethylene as do the lighter feedstocks - ethane and pro-
pane. Furthermore, the conversion of naphtha or gas oil to ethylene is more
complex and requires a significantly higher plant investment than is required
for an ethane-propane (E-P) plant. The heavier liquids used for olefins pro-
duction almost always contain more impurities than E-P, with sulfur being
the major impurity of environmental concern. The increased sulfur content
of the feedstocks increases the environmental controls necessary for the
olefins facility.
Counterbalancing the drawbacks associated with the use of heavier feed-
stocks is a significant increase in the production of valuable byproducts
over those produced when using an E-P feed. Thus, although the total energy
required to produce a pound of ethylene increases with heavier feedstock,
the energy required per pound of useful products decreases. Nevertheless,
the estimated cost of producing ethylene from naphtha or gas oil is about
30% higher than the cost of producing ethylene from an E-P feedstock, even
though reasonable byproduct credits are utilized.
The estimated costs for environmental controls to satisfy existing or
anticipated regulations are between 0.5 and 1.75% of the cost of producing
ethylene. The lower percentage is for E-P cracking and the higher per-
centage is for gas oil; the cost of environmental controls using naphtha
feedstock is in between. The energy requirements for environmental control
are less than 0.1% of the total energy required for the production of
ethylene.
A summary of factors for ethane-propane, naphtha and gas oil feedstocks
for producing olefins is presented in Table II-l.
Other technology is being developed for producing olefins from other
feedstocks and for utilizing conventional feedstocks more efficiently.
Developmental work is under way to utilize vacuum gas oil, vacuum residues
or resids, crude oil and coal as possible feedstocks for olefins production.
Developmental work is also being done on the thermal cracking of naphthas in
the presence of hydrogen to improve the yields of ethylene. The olefins
industry started this developmental work to give it the ability to utilize
these less desirable but more available feedstocks. It is generally believed
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TABLE II-l
SUMMARY OF RESULTS OF PROCESS OPTIONS IN THE OLEFINS INDUSTRY
(Basis 1.1 billion pounds per year of ethylene)
Units E-P Unit Naphtha Ur.it Gas Oil Ur.i;
Production Facility
Fixed Capital Investment 10 $ 149.3 132.9 207.3
Production Cost Cents/lb ethylene 9.7 ) 7.» 12 5
Energy Requirements" Btu/lb ethylene 42,100 62,100 83,20C
Energy Requirements* Btu/lb products 34,000 27,400 25,600
Useful Products Lb/lb ethylene 1.23 2.266 3.152
Environmental Control Facilities
Fixed Capital Investment 10 $ 1.1' 2.3 3.7
Operating Cost Cents/lb ethylene 0.05 0.11 0.17
Energy Requirements'" Btu/lb ethylene 16.8 43.0 80.3
*
Energy Requirements Btu/lb products 13.6 19.0 25.3
Production Plus Environmental
Control Facilities
Fixed Capital Investment 106$ 150.4 185.2 211.0
Operating Cost Cents/lb ethylene 9.75 12.91 12.67
Energy Requirements* Btu/lb ethylene 42,117 62,143 '83,381
Energy Requirements* Btu/lb products 34,014 27,419 26,626
*
Includes energy contained in feedstock.
Source: Arthur D. Little, Inc. estimates.
that this new technology will not have significant impact on the olefins
industry within the next 10 years. It is important, however, for the
industry to pursue this developmental work so that in the long range the
olefins industry can become less dependent on natural gas liquids and
premium petroleum products as feedstock materials. Although not currently
identifiable, it is probable that the new technology being developed for
olefins production from heavy feedstocks will have attendant environmental
control problems. The industry must concurrently develop technologies to
cope with these environmental problems as they proceed with the development
of new process technology.
A. IMPLICATIONS OF ENVIRONMENTAL REGULATIONS ON ALTERNATIVE FEEDSTOCKS
FOR OLEFINS PRODUCTION
Current technology can provide adequate environmental controls to meet
currently established regulations for olefins production facilities when
either naphtha or atmospheric gas oil is used as feedstock. (Survey Reports
on Atmospheric Emissions from the Petroleum Industry, Vol. II, April 1974,
EPA-PB-244 958.) The estimated costs of these environmental controls (as
shown in Table II-l) are not a large portion of total operating costs or
energy usage. However, even small variations in relative pollution control
costs or manufacturing costs will have a significant impact due to the size
and competitive nature of the industry.
7
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One of the main environmental impacts of using heavier feedstocks is an
indirect one. When naphtha or gas oil is cracked to produce olefins, a signi-
ficant quantity of pyrolysis fuel oil is produced as a byproduct. If the
sulfur content of the feedstock is above a certain level, the sulfur content
of the byproduct fuel oil will be high enough to preclude its use as a fuel
without further desulfurization or flue gas desulfurization at the point of
use. Economical technology is not currently available for the direct desul-
furization of the pyrolysis fuel oil produced and flue gas desulfurization
is also not economically attractive for multiple combustion units. There-
fore, most olefin producers would prefer to choose heavy liquid feedstock
materials with a low enough sulfur content so that the sulfur content of
the byproduct fuel oil is acceptable as a fuel under present regulations.
This preference puts undesirable restrictions on the choice of feedstock.
Alternatively, the olefins producer could desulfurize the feed in a petro-
leum refinery type operation prior to cracking. This puts the non-integrated
chemical companies at some disadvantage to the petroleum companies integrated
with olefins production.
At present there are no Federal standards on the control of fugitive
emissions from an olefins facility. Since olefins, and ethylene in particu-
lar, have a very stong odor, the industry has apparently already controlled
these emissions. If very stringent controls were promulgated on fugitive
emissions, the economic impact of meeting them could be significant. Strin-
gent control of fugitive emissions would mast likely have the same type of
impact on all the process options studied as well as on the technology that
is still in the development stage.
Regulations controlling emissions from sulfur recovery facilities have
an impact on the olefins producers in their choice of sulfur recovery tech-
nology to be incorporated in the olefins production facility. The tech-
nology required to meet the current regulations is well established and is
not considered a serious economic burden.
B. ADDITIONAL RESEARCH REQUIRED
The olefins industry can benefit from additional research on the removal
of sulfur from the cracked gas stream. This stream contains hydrogen sulfide,
some carbonyl sulfides, and varying percentages of diolefins and other reac-
tive compounds which tend to foul the acid gas removal system. As indicated
in the text, this problem is now being handled by depropanizing the cracked-
gas stream before acid gas is removed by scrubbing with diethanolamine. A
method for removing the sulfur compounds and acid gases from the cracked-gas
stream in the presence of diolefins (i.e., before the depropanizer) would be
of significant economic benefit to the olefin producers.
-------
Naphtha and atmospheric gas oil feedstocks produce significant quantities
of byproduct pyrolysis fuel oil. If the feedstock material to the olefins
plant has a sulfur content above a certain concentration, the byproduct
pyrolysis fuel oil has sulfur levels too high for its environmentally
acceptable use as a fuel without flue gas desulfurization. These byproduct
fuel oils also contain substantial amounts of unsaturates as well as other
reactive materials which tend to polymerize and form gums on handling. These
present problems when attempting to desulfurize the oils. It would be
desirable to develop an economically attractive process for desulfurizing
the pyrolysis fuel oil to a level where it would be environmentally acceptable
as a fuel. At present, most olefin producers limit the sulfur content of
their feedstock to circumvent this problem. As noted earlier, however, this
limitation severely restricts their choice of feedstocks.
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III. INDUSTRY OVERVIEW
A. OLEFIN INDUSTRY DESCRIPTION
A general description of the olefins industry is presented in this
section. (More detail is given in Appendix A.) This description is based
on data for 1974, the last representative year for which we had good
statistical information.
The olefins industry can be divided into three areas of operation:
feedstock acquisition, olefins production and derivatives manufacturing.
The major feedstocks consist of natural gas liquids (ethane, propane, LPG)
and light crude oil fractions (naphtha, gas oil). The primary olefins
produced are ethylene, propylene, and frequently, the diolefin, butadiene.
Propylene and butadiene are coproduced with ethylene in most olefin plants
today. The key olefin derivatives include polyethylene, ethylene oxide,
ethylene dichloride, ethyl benzene, vinyl acetate, ethanol, polypropylene
and SBR rubber. Approximately 44% of the ethylene produced in the United
States is converted to polyethylene, 20% to ethylene oxide, 10% to ethylene
dichloride, and the remaining 26% to all other derivatives. This report
focuses only on the ethylene monomer production aspects of the olefins
industry.
Although some ethylene was produced earlier, the first commercial
production began in 1923 by Union Carbide. Today 37 ethylene plants,
representing 26 companies, operate in the United States and Puerto Rico.
Twenty-four of these plants are located in Texas and Louisiana where the
geographic proximity of raw material supplies and derivative plants permits
low-cost pipeline movements of feedstocks and ethylene. Most of the
remaining 13 plants are located in the Midwest, with a few in Puerto Rico
and on the West Coast.
The total U.S. ethylene capacity has consistently increased since
1940 and was at a level of about 26.4 billion pounds in 1974. Modern
ethylene plants are large even by U.S. standards. For example, most of
the plants recently built have nameplate capacities of at least one billion
pounds per year. Further substantial increases in plant size are not
expected since economies of scale above this size are minimal.
In Table III-l, the major U.S. producers of ethylene are shown in
two categories - those which are primarily chemically oriented and those
which are primarily petroleum oriented. The chemical type companies have
slightly more ethylene production capacity than the petroleum companies,
10
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TABLE III-l
UNITED STATES ETHYLENE PRODUCERS - 1974
Percent of 1974
U.S. Ethylene Capacity
Chemical Company
Union Carbide
Dow
Puerto Rico Olefins Co.
Monsanto
Du Pont
Other (10)
Total Chemical Company
Petroleum Company
Shell
Exxon
Gulf
Phillips
Commonwealth Oil Refining Co.
Others (6)
Total Petroleum Company
Source: Arthur D. Little, Inc. estimates.
16
14
3.8
3.0
2.8
17.0
57.2
7.8
7.1
5.9
4.3
3.8
13.9
42.8
however, committed expansions are more in evidence with the latter group.
It is not surprising that more than two-thirds of the U.S. ethylene
capacity is owned by only 10 large companies since economic production of
ethylene is best achieved in large plants requiring very large investments.
The primary feedstocks for ethylene production include natural gas
liquids such as ethane, propane and butane (LPG), and products derived from
crude oil, such as naphtha and gas oil. Although significant amounts of
ethylene were once obtained from byproduct petroleum refinery streams (40%
of U.S. production in 1956), only about 2% of the current ethylene produc-
tion is now derived from this source. In 1974, over 80% of the ethylene
produced in the United States was derived from either ethane or propane
feedstock materials (Table III-2).
Since 1965 U.S. production of ethylene has grown at an average rate of
10.5% annually while world ethylene production has increased at an average
of 15.4% annually. The United States, however, still is a major producer
of ethylene, accounting for approximately 40% of total world ethylene
production.
The United States is currently self-sufficient in ethylene production
and has recently exported somewhere between 5 and 10% of its ethylene pro-
duction capacity as derivatives while imports have been equal to less than
0.25% of capacity.
11
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TABLE III-2
U.S. ETHYLENE PRODUCTION/FEED REQUIREMENTS, 1974
Feedstock
Ethane
Propane
Butane
Naphtha
Gas Oil
Requirements
(103bbl/day)
322
218
20
58
117
% of Total
Feedstock
44
30
2
8
16
Ethylene
Production
ClQ9lb/yr)
12.6
6.4
0.7
1.5
2.2
% of Total
Production
54
27
3
7
9
Total
735
23.4
Note: Feedstock requirements are based on 1974 ethylene
production - not capacity.
Sources: "The Future of Ethylene in the U.S. Through 1980,"
Dr. Bert Struth, Chem Systems, and Arthur D. Little, Inc.
estimates.
12
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As previously mentioned, essentially all the ethylene produced is
converted into derivatives. Over 80% of the ethylene produced in the United
States is used to make polyethylene, ethylene oxide, ethylene dichloride
(the precursor to vinyl chloride) and ethyl benzene (the precursor to
styrene). The ethylene typically is used by producers in their contiguous
derivatives plants or shipped by pipeline to major consumers. A network
of pipelines has developed on the United States Gulf Coast connecting
olefins plants, derivatives plants, refineries, storage and natural gas
processing plants.
B. ECONOMIC OUTLOOK
The demand for ethylene in the United States is expected to grow from
an estimated level of 23.4 billion pounds in 1974 to approximately 54.6
billion pounds in 1984. This is an average compound growth rate of 8% per
annum. The demand for ethylene, of course, depends on the demand for
derivatives for which ethylene is a raw material.
This increased ethylene demand will be met through planned expansion
by a number of producers. About 78% of the announced expansions have been
by companies traditionally known as petroleum refiners. It is expected that
the annual United States capacity in 1980 will be greater than 37.2 billion
pounds per year. However, the steadily rising cost of feedstocks and the
increasing cost of new olefins plants will sharply increase ethylene
production costs during the next five years.
Most of the new expansion in ethylene production capacity will
utilize naphtha or gas oil as feedstocks. When these crude-oil-derived
feedstocks are used for ethylene production, there is an advantage in
integrating the olefins production facility with the petroleum refiner
because of the increased yield of petroleum type coproducts, especially
gasoline and fuel oil. This explains why a large percentage of the new
olefins production capability has been announced by the petroleum refining
industry.
Another ramification of cracking heavier feedstocks for olefins pro-
duction is the increase in chemical type coproducts during the ethylene
production. The increased supply of these coproducts - particularly
propylene, butadiene and benzene - will significantly affect the supply/
demand balance for these three products in the future. As a result,
propylene prices are not expected to increase as rapidly as ethylene prices.
Propylene derivatives such as polypropylene would then gain a cost edge
over ethylene derivatives such as polyethylene in those markets where
these materials are directly competitive and might dampen ethylene demand.
Existing butane dehydrogenation plants may not be able to compete with
butadiene available as a byproduct from olefin production facilities; some
of those butadiene plants, therefore, may be forced to close. The benzene
extracted from an olefin plant's pyrolysis gasoline stream will become
increasingly important as a source of benzene over the next decade. However,
conventional refinery sources of benzene will not be sufficient to meet
demand growth during this period, so the availability of benzene from
olefin plant pyrolysis gasoline will not be a disruptive factor in U.S.
markets but instead will be a stabilizing factor.
13
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IV. COMPARISON OF CURRENT AND ALTERNATIVE PROCESSES
A. REASONS FOR SELECTING OPTIONS ANALYZED IN DEPTH
As recently as 1974, 81% of domestic ethylene production was based on
the cracking of ethane and propane. Hence, the base line technology for an
assessment of the domestic olefin industry should be ethane and propane (E-P)
cracking. (See Appendices A, B, and C for details on Process Technology,
Energy, and Pollution.) However, the selection of alternative processes
must be predicated on the outlook for feedstocks. It is now clear that
trends will be away from E-P feedstocks because of the declining reserves
of domestic natural gas, the main source for ethane and propane. In fact,
most of the plants scheduled to come onstream in the 1975-1977 period are
based on the cracking of naptha or gas oil.
From the standpoint of using coil cracking technology, naphtha is a
preferred feedstock. Although the ethylene yields are lower than those for
E-P, they still are 25 to 35 weight percent of the feed, depending on
naphtha quality and cracking conditions. The major process difference
associated with naphtha cracking is the increased production of pyrolysis
liquids which range from C,-'s to fuel oil. Fractionation steps must be
added to the plant to accommodate this increase in liquids production.
Although other factors must be considered, such as shorter furnace cycle
periods and greater maintenance, the cracking of naphtha is still relatively
free from operating problems.
Gas oil cracking is considerably more complicated than naphtha crack-
ing. In addition, some unique problems are encountered relative to heat
recovery and sulfur removal which are discussed later in this section.
Ethylene yields from gas oil are lower (18-25%), the yield of C..+ liquid is
greater, and coil coking is more rapid than for naphtha. However, the
technology for coil cracking of atmospheric gas oil has been developed to
the point where commercial plants are operating satisfactorily.
The logical extension of the current coil cracking technology is to the
cracking of vacuum gas oil. However, serious problems develop with this feed-
stock because of rapid buildup of coke in the furnace tubes and in the down-
stream quench system. Since the embargo of 1973, much consideration has been
given to applying alternative nontubular cracking technology to the pyrolysis
of heavy feedstocks. Generically, these technologies include autothermic and
fluidized bed cracking techniques. In most cases, these technologies are not
yet fully commercialized and widespread application is not expected before the
late 1980's. The major limiting factors are uncertainty about the technology
and disposal of the large amounts of coproduced low-quality fuel oil and pitch.
14
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Thus, the shift in olefin feedstocks away from E-P guided the selection of
(1) naphtha and (2) gas oil as the first priority options for in-depth
analysis. The nonconventional cracking alternatives, ranked lower in
priority because of the minor impact they are expected to have on the
olefins industry until the mid 1980's, are assessed qualitatively in
Appendix E.
As feedstock molecular weight and gravity increase, the yield of
ethylene decreases, thereby increasing the feedstock requirements (chemical
energy) for a fixed ethylene capacity. This increase, in turn, means more
thermal energy is required for pyrolysis and product recovery. Offsetting
this added energy requirement, however, is the fact that more byproducts are
produced from the heavy feedstocks. Consequently, the total energy consumed
per pound of net useful products actually decreases. In essence, more feed
is required to produce a given amount of ethylene with an unavoidable
increase in the amount of byproducts. The cracking of naphtha or gas oil
appears to be more efficient than E-P cracking on a per pound of useful
product basis; however, the demand for petroleum derived feedstock has been
increased. Consequently, energy conservation in terms of form value is the
main benefit derived from the use of alternative heavier feedstocks. Crack-
ing naphtha decreases the demand for LPG's and, similarly, cracking gas oil
frees naphtha for other higher priority uses.
The logical extension of this concept is the use of vacuum residues
(a low-valued refinery product) for olefin production. As indicated earlier,
however, the process technology is not yet commercially available to permit
the use of vacuum residue as a feed for olefin production.
One of the major driving forces toward the use of heavier feedstocks
for olefins manufacturing is relative feedstock cost and availability. Most
foreign countries have not had the luxury of abundant supplies of low-priced
natural gas liquids. Consequently, in countries other than the United
States, naphtha cracking has been the main route to ethylene. However, the
price of naphtha is higher than that for gas oil and with the advance of
gas oil cracking technology, implementation of combination naphtha/gas oil
cracking facilities is underway. Furthermore, gas oil cracking is partic-
ularly attractive when integrated with refinery operations because of the
large quantity of liquid petroleum type products produced, especially
pyrolysis gasoline and fuel oil.
Recognizing that naphtha and gas oil have alternative outlets in gaso-
line and fuel oil, and will likely command premium prices in the future,
chemical producers have turned their attention toward the use of less
desirable petroleum fractions as feedstocks for olefin production. Hence,
price and availability are major considerations in the selection of feed-
stocks in this industry. In the near term, there is no ready alternative
to cracking naphtha or gas oil. However, the search for alternative
routes is in progress and some should be commercialized within the next
ten years.
15
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B. BASE LINE TECHNOLOGY: ETHANE-PROPANE CRACKING
1. Definition
As a base line case for this study of the olefin industry, we have
chosen a plant that annually produces 1.1 billion pounds of ethylene by
pyrolysis of a 50% ethane-50% propane feed. The plant configuration
includes downstream processing for separation of C's into propane and
polymer-grade propylene, and for hydrotreating the highly unsaturated
pyrolysis gasoline. A schematic flowsheet and mass balance for this plant
are illustrated in Figure IV-1. Details of the process are described in
Appendices B (Process Technology), C (Energy), and D (Pollution).
2. Energy Use in E-P Crackers
At the gross level, the energy requirements of an ethylene unit can
be divided into four distinct categories: feedstock, process fuel, elec-
tric power and 'import' steam or equivalent boiler fuel. The base line
E-P cracker requires 1.56 pounds of feed per pound of ethylene product,
or in terms of the feed's higher heating value, 34,200 Btu/lb of ethylene.
The pyrolysis furnaces consume fuel gas equivalent to 7,800 Btu/lb.
Approximately 900 Btu/lb of purchased electricity is needed.* Boiler fuel
for steam generation, in excess of the steam generated by heat exchange
with hot process gases, totals about 8,000 Btu/lb of ethylene. The utility
requirements would be compensated for, in part, by fuel byproduct credits, as
outlined in Table IV-1.
TABLE IV-1
ENERGY CONSUMPTION IN BASE LINE E-P CRACKER
Per Pound Ethylene Product Btu/lb
Feedstock 34,200
Utilties
Process Fuel 7,800
Electric Power 900
Net Steam•(boiler fuel) 8,000
Total Utilities . 16,700
Credit Fuel Derived from Feedstock (8,800)
Total Energy Consumption 42,100
Per Pound Net Products2
Total Energy Consumption 34,000
Feed derived fuel is the hydrogen/methane residue gas.
2
By "net product" is meant the gross plant production, less those products
returned to the plant fuel system, i.e., ethylene, propylene, butanes and
pyrolysis gasoline.
Source: Arthur D. Little, Inc. estimates.
*Assuming a typical conversion efficiency for electric power generation of
10,500 Btu/kWh. 16
-------
Propane Recycle
To Hydrocarbon
Waste Disposal
CVs
Cracked Gas
Compression,
Product
Separation
And Pyrolysis
Gasoline
Hydrotreating
Residue Gas
Ethylene
Propylene
Pyrolysis Gasoline
Waste
Heat
Recovery
Water
Treatment
And
Dilution
Steam
Generation
Flow (Thousands of Pounds/Hr)
H,
CH«
C,H4
C^H,.
Other Cj's
Butadiene
cs +
H,0
Ethane Recycle
Propane Recycle
Fresh C3H,, Feed
FreshC,H, Feed
1
58.36
77.78
97.32
2
^_^__
42.89
9.74
97.32
3
5.91
8.71
84.45
1.70
0.82
1.19
1.58
58.36
4
1.75
24.54
40.56
15.41
8.92
1.82
5.55
42.89
5
7.65
33.25
125.00
17.11
9.75
3.01
12.31
6
0.10
7
7.50
33.25
125.00
17.11
3.01
7.03
Residue Gas (H,, CH,) LHV = 553 BTU/SCF = 4724K CAL/M1
Source: Arthur D. Little, Inc. estimates.
Figure IV-1. Ethylene From An E/P Cracker
-------
3. Emission Profile
The emission profile of the base line E-P cracker, and the character
of the applicable control technology have been discussed in detail in
Appendix D. The characteristic emissions have been summarized in Figure IV-2
and Table IV-2, which identify the quantity, composition and source of
particular air, water, and solid waste effluents.
The major aqueous effluents from an E-P cracker are: dilution steam
blowdown, high pressure steam blowdown, decoking scrubber effluent, and
acid gas scrubber effluent. The major pollutant parameters associated with
these streams include: biochemical oxygen demand, chemical oxygen demand,
suspended solids and entrained hydrocarbons, dissolved salts and hydro-
carbons, and pH. The control technology chosen as most appropriate to meet
effluent limitation guidelines includes the following steps: equalization,
neutralization, aeration (with sludge recycle), final clarification, sludge
thickening, and sludge dewatering.
The major vapor emissions are hydrocarbon losses from compressor seals
and other fugitive sources and H_S from the acid-gas scrubber exhaust.
Particulate emissions are generated by decoking of furnace tubes, heat
exchangers, and catalyst. Emission controls include flares, incineration
in the pyrolysis furnace, and water scrubbing.
The two major solid wastes are: (1) coke from the various decoking
operations, recovered as a sludge in the water treatment system, and (2)
spent desiccant from the ethylene plant's process gas purification system.
Disposal of both solid wastes into approved landfills should present no
problems.
To fairly estimate the cost of controlling these various wastes, we
assumed the ethylene unit exists within a larger complex, including down-
stream production units for low-density polyethylene, ethylene glycol, and
polypropylene. It has been estimated that the cost of controlling water
pollution to BPCTCA levels (1977) will be about 0.0295c/lb of ethylene.
Achieving BATEA levels (1983) will cost an additional 0.0155<:/lb. The unit
cost of achieving air pollution control is about 0.005c/lb of ethylene.
Solid waste disposal costs only 0.005
-------
Feed
H.P. Steam
BFW
Oecoking
Scrubber
(See Figure D-31
Product Separation
and Purification
(To Decoking Scrubber)
Legend:
Air emissions
O Water effluents
Q Solid wastes
Ethylene
Figure IV-2. Pollution Source Identification: Ethane-Propane Cracking
19
-------
TABLE IV-2
ETHANE-PROPANE BASE CASE POLLUTION PROFILE
(Basis: 1.1 billion pounds of ethylene per year)
Scream No.
Water Pollution
Air Pollution
Solid Waste
Description
H.P. steam blowdoun
Coke slurry from scrubber
Dilution steam blowdown
Spent caustic
A2
A3
A6
A8
A
Boiler stack gas
Decoking exhaust
Compressor seals
Acid gas exhaust
Fi.A-t (--i.tae * '
Pollutant
BOD
COD
Regeneration exhaust
Feed & product storage
Coke & waste treatment sludge Sludge
Elemental sulfur Amorphous solid
Spent dessicants Dry solids
Estimated Emission Rate, (Ib/hr1)
Uncontrolled Controlled
54.0
215.8
Dissolved solids 100.5
SO,
3.3
78.2
100.5
Pavticulate
Hydrocarbons
H2S
Hydrocarbons
Hydrocarbons
Hydrocarbons
t.1.6^'
ii. a.
2.2
81.1
n.a.
0.9
13.4
2.2
20.3
1.3
8.1
208.3
8.1
Level of control required to meet BATEA, NSPS, etc.
Fugitives Include emergency venting, miscellaneous lea'cs and spills. Control level assumes
that all vents go to flare.
Intermittent source.
Source: Arthur D. Little, Inc. estimates.
5. Products of E-P-Cracking
As discussed in Appendix B, not all of the material produced in the pyrol-
ysis furnaces leaves the plant as product. Some of the lower valued materials
are instead burned as fuel within the plant. Some hydrogen is consumed in acet-
ylene hydrogenation within the plant and some is used in downstream hydrotreating
of the pyrolysis gasoline. The net product slate, after these recycle streams
have been taken into account, is as shown in Table IV-3. The assumed feedstock
composition is also shown.
6.
Cost Factors
The economics associated with E-P cracking, Table IV-4, are characterized
by low coproduct credits (because of high conversion of feed to ethylene). Con-
sequently, the ethylene manufacturing cost is less sensitive to the value of
individual coproduct prices.
20
-------
TABLE IV-3
NET PRODUCTION FROM BASELINE E-P CRACKER*
(Basis: 1-1 million pounds of ethylene per year)
Product lb/hr
Ethylene
Propylene
Mixed Ct,'s
Pyrolysis Gasoline
Total 166,887
*After recycle to plant fuel
COMPOSITION OF ETHANE t, PROPANE FEEDSTOCKS
(wtZ unless otherwise specified)
Methane
Ethane
Propane
CA's
Sulfur
Ethane
0.5
98.0
1.5
0.0
10 ppro 10 ppm
Source: Arthur D. Little, Inc. estimates.
TABLE IV-4
ESTIMATED ETHYLENE PRODUCTION COST VIA E-P CRACKING
Product: Ethylene
Byproducts: Propyler.e, Mixed C,'s,
Pyrolysis Gasoline"4
Annual Capacity: 1.1 Billion Ib/Yr
Annual Production: 1.1 billion Ib/Vr
Variable Costs
Raw Materials: Ethane
Propane
Byproduct Credits: Propylene
Mixed C4's
Pyrolysis Gasoline
Purchased Energy: Povcr
btean
Water: H.P. Boiler Feed
Process
Cooling
Catalyst and Chemicals
Operating Labor (excl. fringes)
Administrative Overheads
Maintenance Costs ^
Process: E/P Cracker 1975 Cost Basis
(Continuous) 340 Stream Days/Year
U.S. Cult Coast Location
Fixed Investment: S149.3 ollllon
Working Capital: S24.9 rfllion
Total 'Investment: $174.2 tilfloa
Unit Cost
SOOO/Yr
Ifl'lb
10 Ib
lo'lb
106lt.
Ifl'lb
lO^gal
10 gal
$000
•en/shite
859.7
859.7
150.88
46.09
62.89
92.60
4.23
.027
.082
42.66
776
8
90Z of Operating
3.47«/lb
2.04«/lb
8e/lb
8.125c/lb
4.97c/lb
S3.40/0001b
Sl.OO/lo'gal
$0.50/10,gal
$0.05/10 gal
$ 6. 07 /man-hour
Labor
3Z of Plant Cost
29.830
17.560
-12,070
- 3,740
- 3.130
1.260
14.390
27
41
2.133
776
2.141
1,427
4,403
Fixed Costa
Plant Overhead
Taxes and Insurance
Depreciation
Total Production Cost
Pretax Return on Total Investment
Source: Arthur D. Little, Inc. estimates.
80Z of Operating Labor
2Z of Plant Cost
11 Year Straight Line
Equivalent to ethylene
1,268
2,935
13.341
72.038
34,840
106.878
i 9.7c/lb
21
-------
Based on the unit costs discussed in Appendix B, including ethane at
3.47c/lb (16c/gal) and propane at 2.04c/lb (10c/gal), and the factors item-
ized in Table IV-4, the ethylene production cost is 9.7c/lb of ethylene.
The total cost of achieving the expected 1983 environmental standards would
add only 0.05c/lb of ethylene.
C. ETHYLENE FROM THE PYROLYSIS OF NAPHTHA
1. Current Status of Naphtha Cracking
Because of the foreseeable shortage of natural gas and hence the
declining availability of ethane and propane, more and more domestic
ethylene production is being based on heavier petroleum products. One
option is the pyrolysis of naphtha.
As mentioned in Chapter III of this report, pyrolysis of naphtha
already accounts for 7% of the ethylene produced domestically and is the
predominant technology used in Europe and Japan. The industry has acquired
considerable experience about the design and operation of such facilities,
and new plants are now being designed with ethylene production capacity in
excess of one billion pounds per year.
In a manner very similar to that used for E-P cracking, naphtha is
mixed with dilution steam and cracked at high temperature. After recovery
of heat in the transfer-line heat exchangers, the furnace effluent is
quenched in a two-stage counter-current tower system. The first stage
utilizes recycled oil and the second stage recycled process water. Dilution
steam, fuel oil, and tars are recovered in the quench section. The cool
pyrolysis gases are compressed, scrubbed free of H-S and CO-, and dried.
The product separation and purification system is similar to that in an
E-P cracker except that it is designed to handle a larger volume of heavier
hydrocarbons.
The general process outline of a naphtha cracker is illustrated in
Figure IV-3.
2. Energy Use in Naphtha Crackers
Although energy consumption is similar in naphtha and E-P crackers,
the magnitudes of energy use differ. (See Table IV-5.) The ethylene yield
is most important in a comparison of energy requirements. Whereas the
overall ethylene yield for the base line E-P cracker is 64%, the conversion
of feed to ethylene for the naphtha cracker is about half of that, or 33%.
This lower yield is equivalent to a feedstock energy requirement of 61,000
Btu/lb of ethylene. Since so much more material must be processed through
the pyrolysis furnace, the furnace fuel requirement for naphtha cracking
(10,300 Btu/lb) is greater than that for E-P cracking (7,800 Btu/lb).
Moreover, because material flows are larger, the power required by pumps
and other electrical equipment is higher (1,100 Btu/lb). However, total
steam demand within the plant (for process gas compressors, refrigeration
22
-------
Dilution
Slcam ^ Elhane
Pyrolysis
<^
G''s0'' ^ Ma,ihlh.
Dilution Pyrolysis
O
<5>
Transfer |
-_ Lino |
"" Hual
Exclude
<•>
L,,».. |
Heal "~
Quench Oil
Flow (Thouwnd* of Pounds/Hi) 1
H.
CH.
C H,
Olhoi C 's
C.H,
Olhei C.'» — —
PyrolvsuGoiolino
•100' FuulOil
H 0 19050
Eih.me Recycle
N.iphth.i Fund 3)8 19
flu due G.is III , CH(, C,'s) LHV 707 UTU/SCF *
2
•- 1 r
= k
°-i
^^^ — ^
Compulsion, Eihyleni-
Pioikici Pi(i 1 |)i)i(i
And PyiolysLs C^ s
S\ G dSol i nc p i r
Y
f ^v O
:::, 0
1 H.,,
^ B"
( )
\/
t 0,I/H,0 \ [ A,,l
"* ^ SK,,.,.,,,o,, / * * * """'""
Grn..|.lhl>n
\ (l S
3
— — 381
5603
11? 45
1563
- - 49 55
; 5 72
- - 20.20
1663
8318
12 68
86 ' 190 59
26 1
7003K CAIJM'
Flc.| Oil
Ri.i-nvi'iv
4 5 b 7
088 ' .169 ' ] ?11~
1,29 5733 1 &7.33
1255 12500 12500
1042 2605 •
! 025 4981 ' - — 49 HI
0 12 584 - - - : i.84
i 018 2038 ?D 3R
0 12 15.75 • l!i ?5
1.23 83 71 - ^ 83/1
1 i mc8 -
; 860 13 13 ! _ _ - _
- — - - j
Figure IV-3. Ethylene Front a Naphtha Cracker
-------
TABLE IV-5
ENERGY CONSUMPTION IN E-P AND NAPHTHA CRACKERS
(Btu/lb)
E-P Naphtha
Per Pound Ethylene Product:
Feedstock 34,200 61,000
Utilities
Fuel
Electric Power
Net Steam (boiler fuel)
Subtotal
Credit Fuel Derived from Feedstock (8,800) (16.500)
Total Energy Consumption 42,100 62,100
Per Pound Net Products:
Total Energy Consumption 34,000 27,400
(1) "Net Products" means the gross plant production, less those products
returned to the plant fuel system.
Source: Arthur D. Little, Inc. estimates
compressors, etc.) is about the same, and more waste heat is available in
the furnace effluent to generate steam. Therefore, the net steam demand
(6,200 Btu/lb) is smaller than for an E-P cracker.
The total energy demand for a naphtha cracker is larger on a per-unit-
ethylene basis but, as noted earlier, so much more coproduct material is
produced that the energy consumption per unit net product is smaller than
for the E-P cracker.
3. Technical Considerations
Tubular cracking of naphtha is accomplished in much the same way as
E-P cracking. However, there are major differences in dilution steam
requirements, heat recovery techniques, sulfur removal methods, and liquid
handling facilities.
The dilution steam introduced to a pyrolysis furnace accomplishes two
important objectives. First, it reduces the hydrocarbon partial pressure,
shifting reaction equilibrium to increase the yield of olefins and other
light products. Second, it reduces coke formation and increases furnace
run time because steam reduces the partial pressure (concentration) of
heavy hydrocarbons; and it can react with carbon (coke) to form CO and H^.
Primarily because of the more pronounced coking tendencies of heavier feeds,
more dilution steam is used with naphtha (0.5 Ib steam/lb feed) and gas
oil (0.9 Ib/lb), than with ethane (0.33 Ib/lb) or propane (0.4 Ib/lb).
24
-------
Most of the sensible heat of the hot pyrolysis gases can be
recovered by transfer line heat exchangers in an E-P cracker, but the
high concentration of heavy hydrocarbons in the furnace effluent of
naphtha crackers limits the heat recoverable in this fashion. Conse-
quently, condensation of these hydrocarbons in the heat exchangers must
be avoided to prevent fouling. In a naphtha cracker, therefore, the
steam generation pressure and exchanger outlet temperature are considerably
higher than those in an E-P cracker (typically 1500 psig and 700°F versus
600 psig and 550°F). To further cool the furnace effluent, naphtha
crackers employ a direct oil quench. In this system, the effluent is
cooled to 450-550°F, or slightly below the adiabatic saturation temperature
of the effluent, by introducing and evaporating a quench oil whose average
boiling point is about 650°F. Heavy components are further cooled and
condensed in the tower section of the prefractionator. In this column, the
gasoline and lighter gaseous components pass overhead; net production of
pyrolysis fuel oil is withdrawn from the bottom and side of the tower.
Intermediate circulating quench-oil circuits in the tower recover heat
from the vapors as they flow up the tower. Final cooling and condensation
of most of the dilution steam is accomplished with a water quench, as in
an E-P cracker.
Naphtha feedstocks generally contain higher sulfur concentrations than
those found in ethane or propane. Today, levels of 100-150 ppm are common.
In coming years, with the refining of more high-sulfur crudes, sulfur
levels in naphtha may rise; thus, for this study, a sulfur concentration
of 500 ppm has been chosen as a high normal for naphtha. Sulfur in the
feed is later found in the pyrolysis gases (typically 80% of the total
sulfur in the C,'s and lighter), in the pyrolysis gasoline (8%) and in fuel
oil (12%). Sulfur, mostly as lUS and some COS, must be removed from the
light components to satisfy product specifications. Two methods of ELS
removal are available: simple caustic scrubbing, and regenerative amine
scrubbing followed by a caustic wash to remove the final traces of sulfur
and CO,,. For this study, a simple caustic scrubbing system was chosen since
such a system normally is used until sulfur levels in the C, fraction of
the pyrolysis gases exceed 600 ppm.
One other important difference between E-P and naphtha cracking is
caused by the difference in product yield patterns. The far greater yield
of liquid products in naphtha cracking requires a much larger gasoline
processing system, the presence of a prefractionator, and the availability
of much more product storage capacity. Each of these differences is a
potential source of increased hydrocarbon emissions.
Greater emission quantities also result from the greater coking behavior
of naphtha. Whereas each pyrolysis furnace in an E-P plant may run for
60 days between decoking periods, the run time for a naphtha furnace is
closer to 45 days. This difference significantly increases the total amount
of solid waste and wastewater generated by the plant.
25
-------
4. Effect on Intermediate and Final Products
Pyrolysis of naphtha yields a wider range and larger amounts of by-
products than E-P cracking does, particularly of heavy products such as
butadiene, pyrolysis gasoline, aromatics, and fuel oil. Typical gross
yields were tabulated in Figure IV-3.
To satisfy the ethylene plant fuel needs, both gaseous and liquid
fuels are required. Gaseous fuel is needed for the pyrolysis furnaces,
flares, and other process uses. This need can be met by burning part
of the plant's production of hydrogen, methane, propane, and some propylene
(collectively referred to as residue gas). Additional fuel demands for
steam generation can be met with gas or liquid fuels, and in the model
naphtha cracker scenario, this requirement consumes the remainder of the
residue gas and all of the fuel oil production. The net product slate,
after these fuel needs have been accounted for, is given in Table IV-6.
TABLE IV-6
NET PRODUCTION FROM E-P AND NAPHTHA CRACKERS*
(Basis: 1.1 billion pounds of ethylene per year)
(Ib/hr)
Feedstock E-P Naphtha
Ethylene 134,805 134,805
Propylene 18,451 41,037
Mixed C4's 5,636 38,962
Pyrolysis Gasoline 7,691 90,281
*After recycle to plant fuel
Source: Arthur D. Little, Inc. estimates.
5. Economic Factors
The basic yield pattern is based on a Venezuelan naphtha with a
specific gravity of 0.713, and an ASTM boiling range of 91-356°F. Com-
position of the naphtha, by weight, is: 41% n-paraffins, 32% isoparaffins,
20% naphthenes and 7% aromatics. Sulfur content of the naphtha is assumed
to be 500 ppm.
An economic analysis of a naphtha cracker is outlined in Table IV-7.
As indicated, the total capital investment for such a plant is considerable
estimated at $233.7 million for a plant (in 1975 dollars). That is $39.5
million more than an E-P cracker with the same ethylene capacity. With
current byproduct prices and operating cost factors (discussed in Appendix
B), the analysis indicates an ethylene cost of 12.8<:/lb f.o.b. plant. This
is much higher than the calculated price of 9.7
-------
TABLE IV-7
ESTIMATED COST OF PRODUCING ETHYLENE VIA NAPHTHA CRACKING
Product: Ethylene
Byproducts: Propylene, Mixed C^'s,
Pyrolysis Gasoline
Annual Capacity: 1.1 Billion Ib/Yr
Annual Production: 1.1 Billion Ib/Yr
Variable Costs
Raw Materials: Naphtha
Byproduct Credits: Propylene
Mixed C4's
Pyrolysis Gasoline
Purchased Energy: Power
Water: H.P. Boiler Feed
Process
Cooling
Catalyst and Chemicals
Operating Labor (excl. fringes)
Labor Overheads
Maintenance Costs
Process: Naphtha Cracker
(Continuous)
1975 Cost Basis
340 Stream Days/Year
U.S. Gulf Coast Location
Fixed Investceut: $182.9 million
Working Capital: J50.8 million
Total Investment :~$233. 7 raiflion
Units
10blb
Quantity/Yr
3,361.4
Unit Cost
4.27c/lb
SOOO/Yr
143,390
10*lb
10°lb
106lb
10 k'w'h
335.6
318.6
738.2
117.99
8.0c/lb
8.0?/lb
4.4c/lb
1.36c/kWh
-26,840
-25,490
-32,500
1,605
lOggal 0.0244 $1.00/10'gal 24
lOggal 0.163 $0.50/10ggal 82
10 gal 51.26 $0.05/10 gal 2,563
$000 816 816
men/shift 9 $6.07/man-hour 1,783
90% of Operating Labor
3% of Plant Cost
1,605
5,392
Fixed Costs
Plant Overhead
Taxes and Insurance
Depreciation
Total Production Cost
Pretax Return on Total Investment
TOTAL
80% of Operating Labor
2% of Plant Cost
11 Year Straight Line
20%
1,426
3,657
16,340
93,858
46,740
140,598
Equivalent to ethylene @ 12.8c/lb
Source: Arthur D. Little, Inc. estimates.
D. ETHYLENE FROM PYROLYSIS 0^ GAS OIL
1. Current Status of Gas Oil Pyrolysis
As indicated in Chapter III of this report, gas oil cracking accounted
for 9% of domestic ethylene production in 1974. Several plants now being
constructed will use gas oil as feed. The design of such plants is well
established at the commercial level, and the practice is clearly going to
become common as ethylene producers move to assure themselves of some
flexibility in their choice of feedstock.
27
-------
The technology is very similar to that of naphtha pyrolysis. However,
more dilution steam is used and less heat recovery (relative to total avail-
able heat) is possible in transfer line exchangers because of the higher dew
points of the resulting pyrolysis gas mixtures. As with naphtha pyrolysis,
gases ultimately are cooled by a two-stage quench system before they are com-
pressed. Very large quantities of fuel oil (22% of feed) and other heavy pro-
ducts are formed, and the ethylene yield is correspondingly lower. Typical mass
flows in a 1.1-billion-pound-per-year ethylene plant using gas oil cracking
are illustrated in Figure IV-4.
2. Energy Use in Gas Oil Cracking
The pattern of energy use in gas oil crackers conforms to the trends
established in the comparison of naphtha and E-P crackers. Primarily because
of the still lower ethylene yield (24.9%) and higher ratio of dilution steam to.
feed (0.9), fuel consumption in the pyrolysis furnaces is relatively high -
14,700 Btu/lb of ethylene product. Electric power requirements are also high-
1500 Btu/lb. The large volume of furnace effluent allows for increased produc-
tion of process steam and hot oil, so net steam requirements are fairly low—
5500 Btu/lb. As before, the model gas oil cracker supplies its own fuel needs
by recycling all of the residue gas produced and a significant fraction (42%)
of the fuel oil produced. The net energy consumption is given in Table IV-8.
TABLE IV-8
ENERGY CONSUMPTION IN PYROLYSIS ETHYLENE PRODUCTION
(Btu/lb)
E-P Naphtha Gas Oil
Per Pound Ethylene Product:
Feedstock 34,200 61,000 78,800
Utilities
Fuel 7,800 10,300 14,700
Electric Power 900 1,100 1,500
Net Steam (boiler fuel) 8,000 6,200 5,500
Sub total 16,700 17,600 21,700
Credit Fuel Derived from Feedstock (8,000) (16,500) (20,200)
Total Energy Consumption 42,100 62,100 80,300
Per Pound Net Products:^
Total Energy Consumption 34,000 27,400 26,600
Net Products" means the gross plant production less those products returned
to 'the plant fuel system.
Source: Arthur D. Little, Inc. estimates.
28
-------
Residue Gas
K>
Cracked Gas
Compression,
Product
Separation
And Pyrolysis
Gasoline
Hydrotreating
Flow (Thousands of Pounds/Hrt
H,
CH,
C.H,
Other C.'s
C,H,,
Other C/s
Butadiene
Other C.'s
Pyolysis Gasoline
400i Fuel Oil
H,0
Elhunu Recycle
Gas Oil Food
1
.
•16236
502.62
2
— -
.
•
8.84
2681
•
3
4.02
65.34
112.08
16.08
48.75
6.03
22.62
11 06
104.04
112.59
452.36
. .
4
0.90
1 33
12.92
10.72
0.26
0.13
0.18
0 12
0.24
884
•
5
4.92
66.67
12500
26.81
4901
6. 16
2280
11 18
10428
•
RrjSKlun Gns IH,.CH,,C,H I LHV HI'JBTU/SCF ' 7.456K CAL/M'
2 11
6667
125.00
4901
6 16
22.80
II 18
10-1 L'N
Figure IV-4. Ethylene From A Gas Oil Cracker
-------
3. Technical Considerations
In general, the technical problems associated with gas oil cracking are
identical in kind to those of naphtha cracking; they differ only in degree.
Gas oil crackers use high ratios of dilution steam to feed—0.8 to 1.0 Ib/lb
is typical; 0.9 was used for this study. A direct oil quench and prefraction-
ator are used to cool the gases exiting from the transfer line heat exchangers
at temperatures around 950°F. Much larger equipment is necessary to process
and store the larger quantities of pyrolysis gasoline and fuel oil produced.
Decoking operations are twice as frequent with gas oil compared to E-P; run
time for a gas oil pvrolysis furnace is commonly less than 30 days.
The two major technical problems confronting gas oil crackers are:
(1) how to handle high sulfur feedstocks and (2) what to do with the large
quantity of low-quality fuel oil produced in the process. These problems
interact to the extent that high sulfur concentrations in the pyrolysis
furnace feedstock will result in the production of high sulfur fuel oils
which cannot be burned directly without violating air pollution regulations.
(About 65% of feedstock sulfur comes out with the fuel oil.) Thus, excessive
sulfur must be reduced before pyrolysis by hydrotreating the gas oil either
at the ethylene plant or at the refinery. As a basis for this study, the
gas oil is assumed to have a sulfur content of 0.2 wt %. At this level,
the sulfur content of the pyrolysis fuel oil (0.58 wt %) is acceptable
under present standards. However, so much sulfur (27% of the total) is
found in the light pyrolysis gases as H2S and COS that simple caustic
scrubbing leads to uneconomically high caustic consumption. A regenerative
amine system (probably diethanolamine) would be used to remove the bulk of
the acid gases from the C^+ fraction followed by a caustic scrubber to
remove the remainder. The recovered I^S and COS are sent to a Stretford
unit for reduction to elemental sulfur and a much smaller volume of gas is
flared.
A large fraction of the fuel oil produced by a gas oil cracker (42%)
can be used for fuel within the plant. The remainder would probably be sold
to a refinery for blending with other fuel oil. At the ethylene plant, the
pyrolysis fuel oil is often split into a light and a heavy fraction with the
heavy fraction being consumed internally.
4. Effect on Products from Gas Oil Cracking
As indicated, the yield of byproducts from gas oil cracking is much
greater than that from pyrolysis of naphtha or E-P. Gross plant yields were
indicated in Figure IV-4. The net product slate is given in Table IV-9.
The yield pattern was based on a light West Texas gas oil with a
specific gravity of 0.84, an ASTM boiling range of 457-655°F, and a sulfur
content of 2000 ppm (0.2 wt %).
30
-------
TABLE IV-9
NET PRODUCTION FROM PYROLYSIS ETHYLENE PLANTS*
(Basis: 1.1 billion pounds of ethylene per year)
(Ibs/hr)
Feed
Product
Ethylene
Propylene
Other €3*8
Mixed C4's
Pyrolysis Gasoline
400+ Fuel Oil
\
*After recycle to plant fuel
E-P
134,805
18,451
5,636
7,691
Naphtha
134,805
41,037
38,962
90,281
Gas Oil
138,805
52,860
36,648
112,464
70,422
Source: Arthur D. Little, Inc. estimates.
5. Economic Factors
An economic analysis of gas oil cracking is outlined in Table IV-10. As
one would expect, because of the larger material flows that must be handled,
the capital investment for such a plant is more than that for either of the
other two types of ethylene plants. The calculated ethylene price of 12.5
-------
TABLE IV-10
ESTIMATED COST OF PRODUCING ETHYLENE VIA GAS OIL CRACKING
Product: Ethylene
Byproducts: Propylene, Mixed C^'s,
Pyrolysis Gasoline,
Fuel Oil
Annual Capacity: 1.1 Billion Lb/Yr
Annual Production: 1.1 Billion Lb/Yr
Process:
Gas Oil Cracker
(Continuous)
1975 Cost Basis
340 Stream Days Per Year
U.S. Gulf Coast Location
Fixed Investment: $207.3 million
Working Capital: $54.5 million
Units
Quantity/Yr
Unit Cost
Variable Costs
Raw Materials: Gas Oil
Byproduct Credits: Propylene
Mixed C4's
Pyrolysis Gasoline
Fuel Oil
Purchased Energy: Electricity
Water: H.P. Boiler Feed
Process
Cooling
Catalyst and Chemicals
Operating Labor (excl. fringes)
Administrative Overheads
Maintenance Costs
Fixed Costs
Plant Overhead
Taxes and Insurance
Depreciation
Total Production Cost
Pretax Return on Total Investment
TOTAL
Source: Arthur D. Little, Inc. estimates.
106lb
10 |bb
lO^lb
lO^lb
106lb
106 kWh
9
109gal
$000
men/shift
4,432
432.2
299.7
919.6
575.9
160.6
.0254
.3189
61.40
827
9 $6
90% of Operating Labor
3% of Plant Cost
80% of Operating Labor
2% of Plant Cost
11 Year Straight Line
20%
3.75
-------
Feed
H.P. Steam
BFW
Decoking
Scrubber
(See Figure D-3)
Product Separation
and Purification
(To Decoking Scrubber)
Legend:
Air emissions
O Water effluents
D Solid wastes
Ethylene
Figure IV-5. Pollution Source Identification: Naphtha/Gas Oil Cracking
33
-------
TABLE IV-11
Stream No.
Water Pollution
8
Air Pollution
"10
Solid Waste
S,
(Basis:
Description
SUMMARY OF POLLUTANT EMISSIONS
1.1 billion pounds of ethylene per year)
Estimated Emission Rate.(Ib/hr)
E-P ! Naphtha i Gas Oil
Pollutant
Uncont. ConC. Uncont. Cont. Uncont. Cont.
High-pressure steam blow- ) BOD
down /
Coke slurry from scrubber! COD
Dilution steam blowdown J
54.0 3.3
215.8 78.2
Spent caustic
Boiler stack gas
Decoking exhaust
Compressor seals
Acid gas exhaust
. 3
Fugitives
Regeneration exhaust
Prod. 6. feed storage
Coke & waste treatment
sludge
Recovered sulfur
Spent dessicants
Dissolved slds. 100.5 100.5
SO.
41.6'
Particulates
so2
Hydrocarbons
H2S 2.2
Hydrocarbons 81.1
Hydrocarbons,soot
Hydrocarbons
Sludge
Amorphous sclid
Dry solids
208.3
8.1
93.2 5.5 168.6 10.1
369.8 133.6 680.4 244.4
872.6 872.6 114.2 114.2
0.9
13.4
2.2
20.3
1.3
24.2 2
41. 6 ^ 1
0
13
165.3 8
81.1 20
2
47
.0
.3
.2
.4
.8
.3
.6
.2
707.5 12.1
41.6" 2.0
0.2
13.4
293.1 13.2
81.1 20.3
2.6
24.2
357.7
156.5
8.1
661.6
279.9
8.1
1Level of control required to meet BATEA, NSPS, etc.
Rate of SO. emission based upon combustion of fuel oil product only.
^Fugitives include emergency venting, startup, miscellaneous leaks and spills. Control level assumes
that all vents go to flare.
k
Intermittent source.
Source: Arthur D. Little, Inc. estimates.
These and other less important differences are discussed in the following sec-
tions of this report concerned with the details (emission rates, control tech-
nology, and cost of control) of water and air pollution, solid waste disposal,
and other environmental concerns such as thermal or hazardous discharges. For
comparison, the environmental control for ethane-propane based plants is dis-
cussed in Appendix D. '
I i
a. Environmental Effects Related to Water Pollution
The use of naphtha or gas oil as an alternative feedstock is expected to
have a greater potential impact on waterborne pollutants because greater volumes
34
-------
of wastewater will require treatment. The concomitant effects of increased
water usage will be higher treatment costs and greater energy consumption in
the wastewater treatment plant than those associated with the ethane-propane
feedstock base case.
(1) Comparative Wastewater Characteristics
The quantity and characteristics of wastewater from the base case
ethylene production unit are described in Appendix D. Qualitatively, the
wastewater from the naphtha or gas oil cracker is not unlike that of the
base case. No different wastewater streams are added, and no existing waste-
water streams are eliminated.
While the exact composition of the individual wastewater streams cannot
be precisely calculated on a generalized basis, the similar process sources
would be expected to result in similar compositions. Consequently, for
engineering cost estimating purposes, pollutants in the individual wastewater
streams from the naphtha and gas oil cracker were estimated to be at concentra-
tions similar to those for the E-P cracker: that is, only the wastewater flow
rates differed. This difference in flow rate results in different absolute
quantities of pollutants being discharged. A comparison of wastewater flow
rates is shown in Table IV-12.
TABLE IV-12
COMPARATIVE WASTEWATER FLOW RATES
(Basis: 1.1 billion pounds of ethylene per year)
Wastewater Flow Rate (gpd)
Wastewater Stream E-P Naphtha Gas Oil
Decoking scrubber effluent 224,000 418,000 806,400
Dilution steam blowdown 15,700 43,200 129,000
High pressure steam blowdown 79,400 71,700 75,100
Acid gas scrubber effluent 2,200 19,100 2,500
Total Wastewater Flow Rate 321,000 552,000 1,013,000
Wastewater Flow Rate/lb ethylene 198 341 626
Source: Artnur D. Little, Inc. estimates.
Appendix D discusses the wastewater regulatory constraints, treatment
technology and treatment costs associated with the ethane-propane feedstock
base case.
Briefly, two effluent treatment levels are considered:
• BPCTCA - Best Practicable Control Technology Currently Available
(by 1977), and
• BATEA - Best Available Technology Economically Achievable (by 1983).
35
-------
Four effluent characteristics are regulated:
• Biochemical oxygen demand"(BODr)
• Chemical oxygen demand (COD)
• Total suspended solids (TSS)
• pH.
Technologists generally recognize that biological treatment will be used to
attain the BPCTCA level, and biological treatment plus activated carbon
absorption for the BATEA level. The characteristics of the wastewater from
the naphtha and gas oil cracker should be close enough to those of the base
case to permit the same type of treatment to be applied.
Assuming treatment to remove pollutants to the same level for each of
the alternatives, the comparative quantity of pollutants discharged will be
roughly proportional to the volume of wastewater discharged. Thus, the
naphtha feedstock alternative, which has a wastewater flow rate 1.7 times
greater than that of the base case, will have a total effluent discharge of
BOD also 1.7 times greater. Likewise, the gas oil feedstock alternative has
a wastewater flow rate three times that of the base case.
Perhaps the most radical difference in wastewater composition is caused
by the large difference in the volume of the acid-gas scrubber water.* The
acid-gas scrubber water, when finally discharged into the wastewater treat-
ment system, contains a very high concentration of sodium sulfate. The
relative concentrations of sodium sulfate in the total ethylene wastewater
are shown below:
Ethane-Propane 90.0 mg/1
Naphtha 4500 mg/1
Gas Oil 300 mg/1
Although water discharged from the acid-gas scrubber should have the same
sodium sulfate concentration for all cases, the much larger volume of acid-
gas scrubber water from the naphtha case greatly increases the overall
sodium sulfate concentration in the combined wastewater. Being highly
soluble, sodium sulfate will not be removed by the best practicable waste-
water treatment systems. While sodium sulfate is generally not considered
a serious water pollutant, it will increase the total dissolved solids of
the wastewater stream and thus may cause localized problems for plants
discharging into small streams or lakes.
A comparison of estimated waste loadings for the alternative feedstocks
and for the two treatment levels is shown in Table IV-13.
*The section on air pollution control discusses the source of these differ-
ences, which is related to the sulfur content of the feedstock and the method
of sulfur removal.
36
-------
TABLE IV-13
COMPARISON OF WASTEWATER LOADINGS
(Basis: 1.1 billion pounds of ethylene per year)
E-P
Naphtha
Gas Oil
Wastewater Parameter
I. UNTREATED RAW WASTEWATER
Biochemical Oxygen Demand (BOD,.)
Chemical Oxygen Demand (COD)
Sodium Sulfate (from acid gas scrubber)
II. TREATED EFFLUENT AFTER APPLICATION
Biochemical Oxygen Demand (BOD-)
Chemical Oxygen Demand (COD)
Sodium Sulfate (from acid gas scrubber)
III. TREATED EFFLUENT AFTER APPLICATION
Biochemical Oxygen Demand (BOD_)
Chemical Oxygen Demand (COD)
Sodium Sulfate (from acid gas scrubber)
(Ib/day)
1296
5179
2411
OF BPCTCA*
187
2590
2411
OF BATEA**
82
1878
2411
(ib/OOOlb
product)
0.40
1.60
0.74
TREATMENT
0.058
0.80
0.74
TREATMENT
0.025
0.58
0.74
(ib/OOOlb
(Ib/day) product)
2235
8878
20940
TECHNOLOGY
324
4439
20940
TECHNOLOGY
132
3207
20940
0.69
2.74
6.46
0.10
1.37
6.46
0.041
0.99
6.46
(Ib/day)
4049
16329
2737
615
8164
2737
242
5865
2737
(Ib/OOOlb
product)
1.25
5.04
0.84
0.19
2.52
0.84
0.075
1.81
0.84
* BPCTCA - Best Practicable Control Technology Currently Available
** BATEA - Best Available Technology Economically Achievable
Source: 1)"EPA Effluent Guidelines Development Document - Organic Chemicals"
2) Effluent Guidelines - Organic Chemicals, 40 CFR 414FR, April 25, 1974
3) Arthur D. Little, Inc. Estimates.
-------
As discussed in Appendix D, an ethylene production unit is typically
part of an overall petrochemical complex where it coexists with other petro-
chemical production units. Most of the production units within such a
complex produce contaminated process wastewater streams. The usual practice
is to combine all of the wastewater streams for treatment in a common waste-
water facility. Thus, the total wastewater volume and the total quantity of
pollutants present are the result of the contribution from the individual
production units. This combined wastewater feature would hold true for the
naphtha and gas oil processing as well as for the base case.
For the purpose of comparison, the production units that accompany the
ethylene production unit are assumed to have essentially the same production
capacity and wastewater characteristics as in the base line case. Thus,
changes in the characteristics of the ethylene production wastewater are
greatly leveled out when the wastewater becomes part of the discharge from
the entire complex. In the 'ethane-propane base case, for example, the BOD^
contribution from the ethylene production unit is only about 10% of the
total BOD- load from the complex. Increasing the BODc load from the ethylene
production unit by a factor of 1.7 (as in the naphtha feedstock alternative)
would increase the total BOD 5 from the complex by only 7%.
(2) Comparative Wastewater Treatment Costs
Appendix D describes the methodology used in estimating the treatment
costs for the entire complex and in allocating portions of that cost back
to the ethylene production unit. Costs for the naphtha cracker and gas oil
cracker were estimated in a like manner. A summary comparison of the
treatment costs is presented in Table IV-14. Detailed cost breakdowns for
the various treatment levels are presented in Tables IV-15, IV-16, and IV-17.
Although the estimated costs are under $3.00 per ton of ethylene
produced (Table IV-14), the wastewater treatment cost for the naphtha case
is approximately 1.75 times that of the ethane-propane case, while the gas
oil case is approximately 2.7 times that of the ethane-propane case.
(3) Comparative Wastewater Treatment Energy Consumption
In the biological treatment recommended for the BPCTCA treatment level,
electrical energy is required for the aeration of the wastewater and the
operation of pumps, scrapers, and other mechanical equipment.
In the carbon adsorption treatment recommended for the BATEA level,
electrical energy is required for pumping and other mechanical functions,
while fuel energy is required to operate the carbon regeneration furnaces.
A comparison of the energy consumed for wastewater treatment is given
in Table IV-18.
b. Environmental Effects Related to Air Pollution
The switch to heavier feedstocks, such as naphtha and gas oil in place
of ethane and propane, is expected to have the following impacts on air
pollution control:
38
-------
TABLE IV-14
SUMMARY COMPARISON OF WASTEWATER TREATMENT COSTS
(Basis: 1.1 billion pounds of ethylene per year)
TREATMENT
LEVEL
BPCTCA (1977)
BATEA (1983)
TOTAL
(implementation
thru 1983)
E-P
Capital
Investment
($000)
714
243
957
Total
Annual
Cost
($000)
325.1
170.7
495.8
Unit Cost
($/Ton ethy-
lene)
0.59
0.31
0.90
NAPHTHA
Capital
Investment
($000)
1079
413
1492
Total
Annual
Cost
($000)
593.7
280.2
873.9
Unit Cost
($/Ton ethy-
lene)
1.08
0.51
1.59
GAS OIL
Capital
Investment
($000)
1913
739
2652
Total
Annual
Cost
($000)
864.8
479.3
1344.1
Unit Cost
($/Ton ethy-
lene)
1.57
0.87
2.44
Notes: 1. All capital costs adjusted to March 1975 level (ENR Construction Cost Index = 2126)
2. Total annual cost includes direct operating cost plus the following indirect costs:
a. depreciation @ 9.1% of capital investment (11 year straight-line)
b. return on investment @ 20% of capital investment
c. taxes and insurance @ 2% of capital investment
3. Direct operating cost includes operating labor, maintenance labor and supplies, chemicals, energy, and sludge
disposal costs
Source: Arthur D. Little, Inc. estimates
-------
TABLE IV-15
COMPARISON OF BPCTCA WASTEWATER TREATMENT COSTS
(Basis: 1.1 billion pounds of ethylene per year)
Feedstock E-P
Capital Investment $714,000
Indirect Costs
Depreciation @ 9.1% 65,000
Return on Investment @ 20% 142,800
Taxes & Insurance @ 2% 14,300
Total Indirect Cost $222,100
Direct Operating Costs
Op. Labor @ $15.78/hr (incl. ovhd.) 11,800
Maint. Labor & Supplies @ 40% of Cap. 28,600
Chemicals 44,300
Energy (see Table IV-18) 14,100
Sludge Disposal @ $5/Ton 4,200
Total Direct Operating Cost $103,000
Total Annual Cost $325,100
Unit Cost (C/1000 Ib ethylene) 29.5
Source: Arthur D. Little Inc. estimates.
Naphtha Gas Oil
$1,079,000 $1,913,000
98,200 174,000
215,800 382,600
21,600 38,300
$335,600 $594,900
18,800 34,100
43,200 76,500
166,200 104,800
22,600 41,000
7,300 13,500
$258,100 $269,900
$593,700 $864,800
54.1 78.6
COMPARISON OF BATEA* WASTEWATER TREATMENT COSTS
(Basis: 1.1 billion pounds of
Feedstock E-P
Capital Investment $243,000
Indirect Costs
Depreciation @ 9.1% 22,100
Return on Investment @ 20% 48,600
Taxes & Insurance @ 2% 4,900
Total Indirect Cost $75,600
Direct Operating Costs
Op. Labor @ $15.78/hr (incl. ovhd.) 34,000
Maint. Labor & Supplies @ 4% of Cap. 9,700
Chemicals 39,500
Energy (see Table IV-18) 11,900
Sludge Disposal @ $5/Ton nil
Total Direct Operating Cost $95,100
Total Annual Cost $170,700
Unit Cost (C/1000 Ib ethylene) 15.4
ethylene per year)
Naphtha Gas^Oil
$413,000 $739,000
37,600 67,200
82,600 147,800
8,300 14,800
$128,500 $229,800
43,000 54,000
16,500 29,600
67,700 124,300
24,500 41,600
nil nil
$151,700 $249,500
$280,200 $479,300
25.4 43.6
*BATEA costs are incremental to BPCTCA costs.
Source: Arthur D. Little, Inc. estimates.
40
-------
TABLE IV-17
COMPARISON OF TOTAL (BPCTCA & BATEA) WASTEWATER TREATMENT COSTS
(Basis: 1.1 billion pounds of ethylene per year)
Naphtha
$1,492,000
135,800
298,400
29,900
$464,100
61,800
Gas Oil
$2,752,000
241,200
530,400
53,100
$824,700
88,100
Feedstock E-P
Capital Investment $957,000
Indirect Costs
Depreciation @ 9.1% 87,100
Return on Investment @ 20% 191,400
Taxes & Insurance @ 2% 19,200
Total Indirect Cost $297,700
Direct Operating Costs
Op. Labor @ $15. 78/hr (ir.cl. ovhd) 45,800
Maint. Labor & Supplies
@ 4% of Capital
Chemicals
Energy (see Table IV-18)
Sludge Disposal @ $5/Ton
Total Direct Op. Cost
Total Annual Cost
Unit Cost (C/1000 Ib ethylene)
Source: Arthur D. Little, Inc. estimates
TABLE IV-18
COMPARISON OF WASTEWATER TREATMENT ENERGY CONSUMPTION
(Basis: 1.1 billion pounds of ethylene per year)
38,300
83,800
26,000
4,200
$198,100
$495,800
45
59,700
233,900
47,100
7,300
$409,800
$873,900
79.5
106,100
229,100
82,600
13,500
$519,400
$1,344,100
122.3
TREATMENT LEVEL
BPCTCA** (1977)
BATEA*** (1983)
TOTAL
(Implonentation
through 1983)
(kWh/T)
1.88
.32
2.20
E/P
(Btu/T)
-
9,328
9,328
(Btu/T)
18,816
12,510
31,326
(kWh/T)
3.02
.58
3.60
NAPHTHA
(Btu/T)
—
19,636
19,634
(Btu/T)
30,200
25,453
55,653
(kWh/T)
5.48
1.53
7.01
GAS OIL
(Btu/T)
—
29,36.3
29,363
(Btu/T i
54,800
~.63.i
99,133
*Based upon 1 kWh/10,000 Btu.
**BPCTCA - Best Practicable Control Technology Currently Available.
***BATEA - Best Available Technology Economically Achievable.
Sourcer Arthur D. Little, Inc. estimates
41
-------
• The heavier feedstocks contain considerably more sulfur than E-P
feeds, so sulfur controls will be required.
• The heavier feedstocks produce more coke per furnace per unit of
time so more frequent decoking operations will be required.
• The storage of heavier feedstocks or volatile liquid byproducts
in petroleum storage tanks, rather than in the pressurized tanks
used for ethane and propane, will be a new source of hydrocarbon
emissions.
A comparison of emission factors for each feedstock is given in Table IV-19.
Note that all plants have fugitive emission sources such as:
• Startup and emergency venting,
• Compressor, pump, and valve seals,
• Routine maintenance operations, and
• Miscellaneous leaks and spills.
Although these must be controlled to the extent possible using, for example,
flares on all vents or mechanical seals on rotary equipment, there is no
evidence to suggest that these sources are significantly larger or smaller
in either plant. For this reason, these sources are not considered in
detail here.
(1) Sulfur Emission
As an indication of what gas streams require control we have considered
the following standards (paraphrased):
• Federal New Source Performance Standards - SC>2 emissions from the
combustion of liquid fuels must not exceed 0.80 lb/10" Btu heat
input.
• Los Angeles County Rule 53.2 - A sulfur recovery unit must not
emit sulfur compounds in excess of 500 ppm, calculated as 862,
unless the process discharges less than 10 Ib/hr of sulfur
compounds, calculated as S02, in which case it may be diluted to
a concentration of 500 ppm and discharged to the atmosphere.
Sulfur balances for ethane-propane and heavy liquids feedstocks are presented
in Table IV-20. The acid-gas removal system emission to the atmosphere for
naphtha and gas oil exceeds the maximum allowable uncontrolled emission rate
of 10 Ib/hr; therefore, controls will be required. If the liquid fuels are
to be within acceptable limits, the sulfur concentration must be less than
about 7000 ppm. The example shown in Table IV-20 meets this criterion, andi,
in our opinion, controls such as flue gas desulfurization (scrubbing) will I
not be required. For illustrative purposes, however, we later present costs
for this type of control to show the order of magnitude of incentives for
the industry to purchase hydrodesulfurized feedstock.
42
-------
TABLE IV-19
SUMMARY OF AIR POLLUTION CONTROL FACTORS
(pounds per thousand pounds of ethylene)
OJ
Source
Acid Gas Removal Exhaust
Furnace Decoking Exhaust
Acetylene Converter Regeneration
Storage (14-day capacity)
- Feedstock
- Pyrolysis Gasoline
Fugitives
-Startup and Emergency Vents
- Bearing Seals
- Routine Maintenance and
Pollutant
V1
Particulate
so2
Hydrocarbons
Hydrocarbons
Hydrocarbons
Hydrocarbons
Hydrocarbons
Hydrocarbons
Ethane/Propane
2
0.01
0.007 "
Nil
0.01
—
—
0.5
0.1
0.1
Naphtha
0.07
0.010
0.001
0.01
0.24
0.11
0.5
0.1
0.1
Gas Oil
0.10
0.015
0.002
0.01
0.04
0.14
0.5
0.1
0.1
Control Technology
Stretford Process
Wet Scrubber
No control required
Wet Scrubber
Floating Roof Tanks
Floating Roof Tanks
Flare
Mechanical Seals
Miscellaneous Leaks
*Rate depends on sulfur content of feed, rates shown are based on Table IV-20.
2No control required.
Sources: EPA Report 68-02-0255, April 1974, and Arthur D. Little, Inc. estimates.
-------
TABLE IV-?20
APPROXIMATE SULFUR BALANCE, Ib/hr
(Basis: 1.1 billion pounds of ethylene per year)
Plant Stream
Fresh Feed
Gaseous Products
- Acid-Gas Removal Exhaust
- Stretford Process or Equivalent
Liquid Products
- Pyrolysis Gasoline
- Fuel Oil
Recovered Sulfur
Note: Concentration in ( ).
Ethane-Propane
2.2 (10 ppm)
2.2
(not required)
Naphtha
Gas Oil
205 (500 ppm)
1086 (2,000 ppm)
(165 before treatment) (293 before treatment)
<9 <13
15 (170 ppm)
2A (1,200 ppm)
156 (Equivalent to
550 ton/yr)
86 (765 ppm)
707 (5,800 ppm)
280 (Equivalent to
1140 ton/yr)
Source: Arthur D. Little, Inc., estimates
-------
The acid gases contain sulfur (in the form of H2S and COS) as well as
C02- For naphtha and gas oil crackers, these are removed from the com-
pressed cracked gas prior to product fractionation by caustic scrubbing or
by an amine absorption system followed by a caustic scrubber. Typical flow
schematics for acid gas treatment are provided in Figures IV-6 and IV-7 for
naphtha and gas oil, respectively. An amine system (usually diethanolamine-
DEA) is used to reduce chemical costs where high sulfur levels are encountered.
Regeneration of the DBA absorption solution yields a gas containing the
concentrated acid gases. Spent caustic is neutralized using the same system
as that described in Appendix D for the base case. This neutralization also
generates a concentrated acid gas stream.
For plants processing a stream that contains small amounts of sulfur
(2 tons sulfur/day), the most appropriate control system is oxidation as
accomplished with the Stretford process. The Stretford process contacts the
hydrogen sulfide-containing steam with an aqueous solution of sodium
carbonate, sodium vanadate, anthraquinone disulfonic acid and other minor
constituents. The hydrogen sulfide is absorbed into the solution and is
oxidized to elemental sulfur. The sulfur is removed by centrifuging or
filtering and the Stretford solution is reoxidized by air before being
recycled to absorb more hydrogen sulfide.
The Stretford process is often employed as a part of the system to
clean up the tail gas from a refinery Glaus plant. Typical capital and
operating costs for the Stretford process are given in Figures IV-8 and
IV-9, respectively. The capital and operating costs for Stretford plants
"required for sulfur conversion in a 1.1-billion-pound-per-year ethylene
plant are shown in Table IV-21. If the ethylene plant is part of a
refinery, the acid gases could conveniently be combined with sulfur streams
from other refinery processes and treated in the refinery Glaus plant.
Such a strategy takes advantage of the more favorable economics of large-
scale Glaus plants.
The elemental sulfur produced by these processes could be sold, but
because of the relatively small amounts involved, we have assumed the worst
case—the marketing efforts would not be profitable and the sulfur would
have to be landfilled at a cost of about $5.00/ton.
(2) Particulates
As with the base case, the major source of particulates during the
manufacture of ethylene from heavy feedstocks is the intermittent decoking
of process furnaces. The amount of coke built up within a process furnace
at the time decoking is required is the same for heavy feedstocks as it is
for the base case. Hence, the amount of steam required per decoking opera-
tion is the same as for the base case and, therefore, the control equipment
required will be the same as that for the system described in Appendix D.
The primary differences between the base case and decoking of furnaces
using heavy feedstocks are as follows:
45
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Clean Pyrolysis Gases
X^ "X
Pvr0'VSiS *- Caustic f MaOII frc-h Naphtha
Gases Scrubber . K
"x^^ ^7 I
Naphtha
S^\ Wash
^J
\
Final 1 ^
Compression 1
H2S04 H2S' C02-
1
ToW
Trt
COS / \
1 Afterburner
T
astewater
atment
Naphtha to Oil/Water
Separator
Figure IV-6. Acid-Gas Treatment System (Naphtha Cracker)
-------
Pyrolysis
Gases
Clean Pyrolysis Gases
K NaOH
Fresh Naphtha
I
H2S04
Naphtha
Wash
Neutralization
Naphtha to Oil/Water
Separator
Stretford
Afterburner
To Wastewater
Treatment
Figure IV-7. Acid-Gas Treatment System (Gas-Oil Cracker)
-------
.8 5
I 4
0>
Q.
1 3
C
C
<
I I I
I
7891.0 2 3456
Capacity (Tons of Sulfur per Day)
Figure IV-9. Operating Cost for Stretford Process
48
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TABLE IV-21
ACID GAS SULFUR CONVERSION CONTROL COSTS
(Basis: 1.1 billion pounds of ethylene per year)
Feedstock Naphtha Gas Oil
Capital Cost*($)
- Fixed Capital Cost (FCI) 523,100 711,500
- Offsites @ 30% of FCI 156,900 213,500
Total 680,000 925,000
Operating Costs.($/yr)
Indirect Operating Costs
- Depreciation, 11 years 61,800 84,100
- Return on Investment, @ 20% of Capital 136,000 185,000
- Insurance and Taxes, @ 2% of Capital 13,600 18,500
Total Indirect 211,400 187,600
Direct Operating Costs
- Maintenance, @ 5% of FCI 26,200 35,600
- Labor
- Direct, @ $7.89/hr (incl. Fringes) 21,400 21,400
- Labor Overhead, @ 40% of Direct 8,600 8,600
- Plant Overhead, @ 60% of Direct 12,800 12,800
- Utilities
- Steam, @ $7.50/MT 6,800 14,000
- Electric Power, <§ $0.0136/kWh 13,500 28,100
- Fuel, @ $1.87/106 Btu 3,700 7,600
- Water, @ $0.05/103gal 6,800 14,000
- Chemicals, @ $2.50/T 1,300 2,700
- Residue Disposal, @ $5/T 2.600 5,500
Total Direct ,' 103,700 250,300
TOTAL OPERATING COST,($/yr) 315,100 437,900
Unit Cost, (c/1000 Ib ethylene) 28.6 40.9
Source: Arthur D. Little, Inc. estimates
49
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• Heavy feedstock furnaces require more frequent decoking.
• An ethylene plant that processes heavy feedstocks requires more
furnaces per ton of ethylene than a comparably sized E-P plant.
With respect to the example case, a 1.1 billion pounds of ethylene per year
plant, the scrubber control with a standby system described in Appendix D
has sufficient capacity to control decoking of heavy feedstock furnaces
also. The major difference between the base case and the heavy feedstocks
case is in the number of hours which the decoking system will have to
operate per year. An estimate of the operating hours for each feedstock is
shown in Table IV-22.
In addition to decoking, a secondary source of air pollution occurs
from the regeneration of the acetylene converter. The major difference
between processing heavy feedstocks as opposed to ethane/propane is that
the heavy feedstock plants will typically have more than one acetylene
converter. Hence, two converters must be regenerated per year rather than
one. However, the additional amount of scrubber time required for
acetylene converter regeneration is easily accommodated by the decoking
control system.
The capital cost of the decoking scrubber system is estimated to be
the same for all feedstocks, i.e., $142,000. The estimated operating costs
for the decoking scrubber system are shown, by feedstock, in Table IV-23.
These costs include both decoking and the acetylene converter regeneration
operations.
(3) Hydrocarbons
Ethylene plants processing heavy feedstocks have the same hydrocarbon
emission problems as those described in Appendix D for the E-P base case.
The sources include compressor, pump and valve seals, emergency venting and
startup, periodic maintenance operations that require flushing and venting
of process equipment, and miscellaneous leaks and spills. The control of
these sources includes the judicious use of plant flares on all equipment
vents, use of mechanical seals on rotary equipment, etc. The costs for
controlling these sources could be a major environmental control cost to
the industry depending on the number of sources requiring controls and the
severity of the standards. However, these costs are expected to be similar
for processors of both heavy and light feedstocks.
A new source of hydrocarbon emissions associated with processing heavy
feedstocks is that of petroleum storage. When ethane and propane are
processed, the feedstocks arrive at the plant either in pressurized storage
tanks or via a pipeline. On the other hand, the heavier feedstocks may be
stored in petroleum storage tanks. Such tanks require floating roofs, for
example, in order to comply with Federal New Source Performance Standards
but, even so, there is a significant hydrocarbon emission as a result of
evaporative losses. The approximate rates of emission were shown in
Table IV-19.
50
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TABLE IV-22
APPROXIMATE OPERATING HOURS PER YEAR FOR DECOKING
AND ACETYLENE CONVERTER REGENERATION SCRUBBER SYSTEM
Feedstock E-P Naphtha Gas Oil
Decoking 907 1,692 3,264
Acetylene Converter Regeneration 48 96 96
Total Hours per Year 955 1,788 3,360
Source: Arthur D. Little, Inc. estimates.
TABLE IV-23
OPERATING COST OF DECOKING SCRUBBER SYSTEM, $/YR
(Basis: 1.1 billion pounds of ethylene per year)
Feedstock E-P Naphtha Gas Oil
Capital Charges,($/yr)
Depreciation 12,900 12,900 12,900
Return on Investment @ 20% 28,400 28,400 28,400
Maintenance, @ 5% of Capital Cost 7,200 7,200 7,200
Interest and Taxes, @ 2% of Capital Cost 2,800 2,800 2,800
Labor Nil Nil Nil
Utilities
- Electricity, 67.5 kWh/hr @ $0.0136/kWh 900 1,600 3,100
- Cooling Water, 1300 gal/hr @ $0.05/103gal 4,000 7,500 14,100
Residue Disposal (Included with wastewater sludge)
Total Operating Cost,($/yr) 56,200 60,400 68,500
Unit Cost (c/1000 lb ethylene) 5.0 5.4 6.4
Source: Arthur D. Little, Inc. estimates.
51
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The heavy feedstocks also yield hydrocarbon products such as pyrolysis
gasoline and fuel oil. The vapor pressure of the pyrolysis gasoline is
higher than the maximum allowed" for storage in floating roof tanks and,
therefore, pressurized storage will be required. On the other hand, the
hydrogenated pyrolysis gasoline has been reported by many of the manufac-
turers as being within the range allowed for storage in floating roof tanks
and, therefore, an emission loss would be associated with this byproduct
(Table IV-19).
c. Environmental Effects Related to Solid Wastes
The major sources of solid wastes are as follows:
Generation Rate (Ib/hr)
Source E-P Naphtha Gas Oil
Wastewater & decoking sludge 208.2 357.7 661.6
Recovered sulfur - 156.5 279.9
Spent desiccants 8.2 8.2 8.2
(e.g. molecular sieve,
silicon gel or activated
alumina)
Total 216.4 517.9 949.7
Most of the solid waste is produced by the biological treatment system used
for the BPCTCA treatment level. This waste is in the form of a sludge which
is composed of suspended solids removed from the raw wastewater and excess
microorganisms. After it is dewatered, the waste sludge is estimated to
have solids concentration of 20%. In a petrochemical complex the additional
sludge load from the petrochemical derivative plants is estimated to be
1870 Ib/hr, which is considerably greater than the waste load from any other
source. Although the sludge is not generally considered hazardous, it does
contain hydrocarbons and sulfur compounds and should therefore be disposed
of carefully in approved landfill operations.
Two other wastes are generated in a dry form—the recovered sulfur,
and spent dessicants from the dehydration step. In a large plant, the
recovered sulfur might be refined and sold but in most cases it will be
landfilled along with the desiccant and sludge. These sludges should be
disposed of in approved landfill operations.
Finally, an ethylene plant also generates spent catalysts; but these
are usually reprocessed at the catalyst manufacturer's plant to reclaim
valuable metals. Therefore, we have not included these with the wastes
requiring disposal.
The costs for solid waste disposal are estimated at $5/ton of actual
waste. The total disposal costs for a 1.1-billion-pound-per-year ethylene
plant is estimated to be $800/yr for a plant using E-P as feedstock,
$1930/yr for naphtha, and $3760/yr for gas oil.
52
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d. Environmental Effects Related to Odor
Some of the early olefin plants emitted characteristically sweet odors
typical of ethylene. Although the potential for such an emission is just
as great for heavy feedstocks, adequate control has been demonstrated using
flares on all vents. In our opinion the industry will not have significant
odor emissions because present practice adequately controls fugitive losses.
F. OTHER LONG-TERM PROCESS OPTIONS
As energy demand grows in the next 10 to 15 years, demand for petroleum
products will result in increased uncertainty about the availability of
olefins feedstocks. Consequently, the olefin industry producers and process
licensors are pursuing alternative thermal cracking processes which can
handle the less desirable petroleum residue materials. In addition, certain
processes based on producing olefins from coal are being investigated but
are unlikely to be commercialized during this period.
The more active development programs in the area of olefin pyrolysis
and the sponsoring companies are:
Cracking Technology Sponsoring Companies
• Petroleum Based
Coil Cracking of Vacuum Gas Oil Exxon Chemie, France
Hydro Pyrolysis Naphtachemie, Heurty, & Auby
Autothermic Pyrolysis Union Carbide, Kureha, Chiyoda
Fluid Bed Cracking Agency of Indus. Science & Tech. (Japan)
• Coal Based
Plasma Arc Pyrolysis AVCO Corporation
Clean Coke Process U.S. Steel Corp., ERDA
The AVCO plasma arc and the Clean Coke processes produce acetylene and
byproduct ethylene, respectively. Many olefin derivatives were initially
produced from acetylene until the more favorable economics associated with
ethylene production 'forced acetylene out of these markets. However, as the
prices of various energy forms shift, coal-based acetylene may make the
acetylene route competitive again. Each of the above cracking technology
options is discussed in more Detail in Appendix E.
1. Energy Considerations
Unit feed requirements and energy consumption are compared with the
base line in Table IV-24. Straight chain paraffins give the highest yield
of ethylene. As feedstock paraffinicity declines and molecular weight and
specific gravity increase, the yield of ethylene also declines. Hence,
more feedstock is required per pound of ethylene product. This trend is
illustrated in Table IV-24. Naturally, cracking conditions such as resi-
dence time and temperature will alter this basic trend. For example,
53
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autothermic cracking is carried out at high temperatures with very short
residence times and produces a remarkably high yield of ethylene from crude
oil.
Of course, as feedstock requirements increase, the yields of chemical
and fuel coproducts also increase; hence, energy consumption must be
related to net products to make valid comparisons. An energy index was
therefore derived which ratios the total energy consumed (including
chemical energy in the feed that appears in the product) to the pounds of
net product. This index is also shown in Table IV-24. As is seen, the
total energy consumption per pound of net products for these processes
generally is less than that for E-P cracking, except in the case of coal.
Ethane-propane cracking is characterized by a high heat of cracking and low
coproduct yields relative to the heavy liquids used with these processes.
On a per pound of ethylene basis, a reverse trend would be seen.
The conclusion that can be drawn from Table IV-24 is that the gross
demand for energy per pound of ethylene produced increases as feedstock
quality declines. Hence, energy is conserved only in terms of form value
displacement; that is, the use of these advanced thermal cracking technolo-
gies will reduce the demand for gas liquids, naphtha, and atmospheric gas
oil, in deference to vacuum gas oil, vacuum residue, crude oil and coal.
In all cases they will consume more energy per pound of ethylene equivalence
than coil cracking of the former feedstocks. However, the energy consumption
per pound of net product will be in line with present technology if
coproduct oil and pitch can be effectively utilized. Coal-derived acetylene
consumes about twice the energy per pound of net product as the petroleum
based alternatives but can achieve total independence from petroleum
derivatives.
2. Pollution Impact
Since most of these advanced technologies are being developed and
commercialized during a period when environmental regulations are in effect,
the developers recognize the need to comply with existing environmental
codes and are taking appropriate measures while developing the process.
Sulfur is an even more significant problem for these advanced technologies
than for the existing technologies because of the nature and sulfur content
of the proposed feedstocks. All gaseous sulfur, however, is in the form
of hydrogen sulfide, for which an abundance of control technology is avail-
able, although some of this technology may require modifications to be
effective. Union Carbide, for example, has had to do this to reduce the
problem of butadiene polymerization in amine scrubbing systems. Again, the
fuel oils and pitch produced as byproducts will present internal use and
marketing problems if steps are not taken to reduce their sulfur contents.
However, the problems of sulfur content in the byproducts are generally
recognized by the developers, so to be acceptable the commercial versions of
the processes must incorporate techniques for coping with this problem.
54
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Ui
Feedstock
Petroleum Based
E-P
Naphtha
AGO
VGO
Vac Resid
Crude Oil
Coal Based
Coal
Coal
TABLE IV-24
FEED AND ENERGY REQUIREMENTS FOR ALTERNATIVE OLEFINS PROCESSES
Technology
Coil Cracking
Coil Cracking
Coil Cracking
Coil Cracking
Fluid Bed
Autothermic
Plasma Cracking
Clean Coke
Feed Required/Total Net Products
(Ib/lb (Ib/lb Energy Consumption (Btu/lb net products)
of Ethylene1)
1.56
3.05
4.95
4.95
6.17
2.54
2.90
32. 22
of Ethylene1)
1.23
2.26
3.02
3.20
4.46
1.72
1.36
n.a.
Feedstock
27,670
26,950
26,090
28,600
24,200
27,320
30,390
n.a.
Utilities
13,510
7,775
7,180
11,130
11,200
10,460
43,435
n.a.
Fuel Credit
(7,140)
(7,285)
(6,670)
(10,500)
(10,600)
( 9,580)
(8,425)
n.a.
Total
34,040
27,440
26,600
29,230
23,600
28,200
65,400
n.a.
10r ethylene plus acetylene.
Metallurgical coke, not ethylene, is the major product from this process.
Including ethylene and other coproducts less internal fuel consumption.
Sources: Proceedings of Ninth World Petroleum Congress, OCR R&D Report No. 67, (14-32-0001-1215), and
Arthur D. Little, Inc. estimates.
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V. IMPLICATIONS OF POTENTIAL INDUSTRIAL/PROCESS CHANGES
A. IMPACT UPON POLLUTION CONTROL/ENERGY REQUIREMENTS
The pollution control and energy utilization consequences of expected
shifts in feedstocks for olefin production are summarized in Table V-l.
Capital investment in pollution control systems is about 1% of the base
ethylene plant investment. Total operating cost differentials above the
base line for environmental protection range from 0.05 to 0.169
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TABLE V-l
SUMMARY OF POLLUTION CONTROL COSTS AND ENERGY REQUIREMENTS
(Basis: 1.1 billion pounds of ethylene per year)
E-P
Naphtha
Gas Oil
• Cost
Wastewater Treatment
Air Pollution Control
Sulfur Control ._
Decoking Effluent Control
TOTAL ENVIRONMENTAL COSTS
Ethylene Production Unit Costs
• Energy (Btu/lb Ethylene)
Wastewater Treatment
Air Pollution Control
TOTAL
• Base Energy Consumption
Btu/lb Ethylene
Btu/lb Net Products
Fixed Operating
Investment Cost
($000) (C/lb
C2H4)
957 0.045
„_
142 0.005
1099 0.050
, 149,300 9.7
16.2
.6
16.8
42,100
34,000
Fixed
Investment
($000)
,
1492
680
142
2314
182,900
28.7
14.3
43.0
62,100
27,400
Operating
Cost
(C/lb
C2H4)
0.080
0.029
0.005
0.114
12.8
Fixed
Investment
($000)
2652
925
142
3719
207,300
51.5
29.3
80.8
83,300
26,600
Operating
Cost
(C/lb
C2H4)
0.122
0.041
0.006
0.169
12.5
1Includes steam and electric power equivalent.
Source: Arthur D. Little, Inc. estimates.
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600 ppm sulfur in the C^ and lighter gas. However, dealing with the sulfur
contained in the raw olefin rich gas is standard design practice for the
production of olefins.
Of more concern and impact is the effect of increasing feed sulfur on
pyrolysis fuel oil quality. Since two-thirds of the feed sulfur in gas oil
ends up in the pyrolysis fuel oil product, the sulfur level often exceeds
levels allowed by pollution regulations. Based on the material balance
presented for a gas oil cracker, the feed sulfur would have to be less than
0.3% in the pyrolysis,fuel oil to meet the regulations for a sulfur emission
rate of 0.8 Ib SO-/10 Btu. The alternatives for dealing with this problem
include: (1) the purchase of desulfurized gas oil at a premium feedstock
price, (2) front end hydrodesulfurization of the feedstock by the plant
owner using petroleum refining techniques, (3) hydrodesulfurization of the
pyrolysis fuel oil, or (4) direct burning of high-sulfur pyrolysis fuel oil
in conjunction with flue gas desulfurization. Direct hydrotreating of the
fuel oil product presents operational problems and today is usually not
considered because the pyrolysis fuel oil is highly unsaturated and tends
to polymerize and plug equipment. Flue gas desulfurization is generally
unattractive because of the high capital cost for the scale of equipment
encountered. The choice between the other two alternatives will depend on
specific feed supply arrangements and feedstock logistics. As is seen from
the above discussion, different factors must be considered in the selection
of sulfur treatment systems for the cracked gas as feed sulfur content
increases. The viable sulfur removal options available to the olefin pro-
ducer and where they apply are summarized below:
Option Applicable to Feed Sulfur Content
II. Alkanolamine III. Front End Desul-
I. Caustic and Caustic furization and
Feedstock Scrubbing Scrubbing Caustic Scrubbing
Naphtha* <500 500-3000 >3000
Gas Oil <1200 1200-2500 >2500
Options II and III also require a caustic scrubbing clean-up system to meet
final product specifications. The Option III sulfur limit assumes a pyroly-
sis fuel oil sulfur content equivalent to 0.8 Ib S02/106 Btu. Naturally, if
the pyrolysis fuel oil sulfur content is not a consideration, the range of
aroine scrubbing can be extended.
*Sulfur levels in naphtha are generally well below 1000 ppm.
58
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Of potential concern to the olefin industry is the application of
future regulations on fugitive emissions. Ethylene is purified through
cryogenic separation, which requires the pumping of liquid refrigerants
and cold reflux streams. At atmospheric conditions, most of the constit-
uents in these streams are gaseous. Consequently, any cold liquids leaking
through pump seals immediately vaporize into the air. Furthermore, most of
the process streams in an ethylene plant are hydrocarbons, and any leak
through valve packings, compressor seals, relief valves, etc. are poten-
tial sources of fugitive emissions. The cost impact of eliminating all
such fugitive emissions, however, would be very significant because of the
very large number of point sources required to control. However, modern
equipment design and a diligent maintenance program can go a long way
toward minimizing fugitive emissions.
The energy requirements per unit of ethylene and net products are pre-
sented for comparison (Table V-l). The energy consumed (feed and utilities)
for a given quantity of ethylene increases with declining feedstock quality;
however, on the basis of net products (ethylene and other olefins and fuels)
the energy consumed decreases. In effect, the demand for petroleum derived
feedstocks increases, however, a portion of that material returns to the
energy pool in the form of pyrolysis gasoline and fuel oil. A savings in
form value also is associated with changing feedstocks.
B. FACTORS AFFECTING PROBABILITY OF CHANGE
The main factor affecting the probability of shifts toward naphtha
and gas oil cracking in the United States is the unfavorable outlook for
increased supplies of gas liquids, i.e., ethane and propane. Only in special
situations will future ethylene production be based on ethane and propane
cracking. In fact, indications are that the trend toward heavier feed-
stocks for petrochemicals will not end with the cracking of naphtha and
atmospheric gas oil since availability of these products is increasingly
dependent on the vagaries of international politics. The switch to naphtha
and gas oil has begun and the probability of it continuing is very high.
The remaining question is when advanced thermal cracking technology
will become fully commercial and permit the use of even heavier feedstocks.
The major factors influencing the application of this technology are process
development and economics. In many cases the process development has
advanced to a point where process development units (PDU) are operational
or awaiting funding. Of greater uncertainty is when will energy value
differences (distillate vs resid oil vs coal) be sufficiently large to make
the processes competitive with current technology.
C. AREAS OF RESEARCH
Potential areas for further research are associated mainly with removal
of sulfur. Amine systems applied to the removal of acid gas from olefin
rich streams have experienced severe fouling problems in the solution
59
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regenerator. These problems are caused by polymerization of heavy
diolefinic constituents and occur primarily in the heat exchangers and
stripper where high temperatures are encountered. If the process sequence
is changed by incorporating a front-end depropanizer, these fouling prob-
lems can be reduced. However, this change increases the energy consump-
tion and cost of the acid gas removal system. Consequently, there is a
need to improve the design technology for amine systems in this service,
or alternatively, to evaluate other acid gas removal techniques.
Because of the high sulfur levels in pyrolysis fuel oil from gas oil
cracking, this product incurs marketing problems. It is unsaturated and
tends to polymerize, making it difficult to handle and process. Consequently,
the concept of hydrotreating pyrolysis fuel oil is usually discarded in
preference to desulfurizing the olefin plant feed. The development of
technology for desulfurizing the pyrolysis fuel oil would improve the
quality of this product from olefin manufacture. Overcoming the operating
difficulties at a cost competitive with feed desulfurization would be
advantageous to the olefin industry.
Olefin manufacturers almost universally do not want to contend with
stack gas scrubbers for heaters or boilers firing byproduct pyrolysis fuel
oil. They will, therefore, tend to purchase feedstocks with sulfur contents
low enough to prevent the resulting fuel byproducts from exceeding allow-
able S02 limits during combustion. In some cases this means purchasing
hydrodesulfurized gas-oil having sulfur contents of less than 2500 ppm.
The cost differential that an olefins producer would expect to pay
for low-sulfur feedstock is difficult to determine. Hence, for purposes
of illustrating the magnitude of such a cost, we have shown in Tables V-2
and V-3 the capital and operating costs of a comparable stack gas scrubber
system representing the maximum cost anticipated for sulfur control. These
costs are based upon a 1.1-billion-lb/yr ethylene plant yielding 495,000
tons/year of fuel oil from a gas oil feed.
Flue gas desulfurization systems are expected to have operating costs
for the gas oil feedstock of 0.43£/lb of ethylene. This is equivalent to
a feedstock cost differential of $2.58/ton ($0.32/bbl) for low-sulfur gas
oil. This cost is in the range of probability, so purchase of desulfurized
feedstock is indeed an economically reasonable and convenient alternative
to stack gas scrubbing. These would obviously shift the sulfur problem
back onto the refiners.
60
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TABLE V-2
FLUE GAS SULFUR CONTROL SYSTEM
(Basis: 1.1 billion pounds of ethylene per year)
Description:* Gas Oil
Fuel Oil Rate (Ib/hr) 121,640
Stack Gas Volume(ft /hr) 26.8 A 106
Sulfur Load (Ib/hr) 707
Capital Cost. ($1,OOP's)
Fixed Capital Investment (FCI)
- Scrubber System 5,830
- Alkali System** 663
Total 6,493
Related Auxiliaries @ 30% of FCI 1,943
TOTAL CAPITAL COST ($000) g 441
*Systems chosen to represent typical costs for sulfur control of the
fuel oil product and do not represent the actual boiler control cost
expected at a given plant.
**Based upon lime scrubbing.
Source: Arthur D. Little, Inc. estimates.
TABLE V-3
OPERATING COST FOR FLUE GAS SULFUR CONTROL SYSTEMS
(Basis: 1.1 billion pounds of ethylene per year)
Feedstock: Gas 0"
Capital Charge
- Depreciation, 11 years 767,500
- Pretax Return on Investment 20Z 1,688,200
Maintenance, @ 5Z of FCI 722,000
Insurance and Taxes, @ 2% of FCI 168,800
Labor @ $7.89/hr (incl. Fringes)
Scrubber System 64,400
Alkali System 128,800
Labor & Plant Overhead, @ 1002 of Labor 193,200
Utilities (Scrubber System)
- Electric Power, 0 Sw/m3 420,500
- Fuel, @ 49.6 Btu/ra3 573,500
Utilities (Alkali System)
- Electric Power, @ 182 kKh/Ton 7.100
Chemicals, @ 2 Ton CaO/Ton 173,300
Residue DISPOSAL, @ $5/Ton — U7t900.
TOTAL 4.725.100
Unit Cost (e/lb ethylene) °-*3
Source: Arthur D. Little, Inc. estimates.
61
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APPENDIX A
INDUSTRY STRUCTURE
1. INDUSTRY DESCRIPTION
The olefins industry can be divided into three areas of operation:
feedstock acquisition, olefin production and derivatives manufacturing.
The feedstocks consist of natural gas liquids and light crude oil fractions
(naphtha, gas oils); the primary olefins produced are ethylene, propylene,
and butadiene; key derivatives include ethylene oxide, polyethylene,
styrene, ethylene dichloride, vinyl acetate, polypropylene and ethanol.
This appendix focuses on ethylene production. Propylene and butadiene are
usually coproduced with ethylene in most olefins plants.
There are currently 37 ethylene plants operating in the United States
and Puerto Rico (Table A-l). Although some ethylene production began
earlier (i.e., Dow Chemical production of mustard gas in 1913), full-scale
production did not begin until 1923 by Union Carbide and 1936 by Dow
Chemical. Of the plants currently in production, 24 are located in Texas
and Louisiana, due to the geographic proximity of raw material supplies and
derivative plants of feedstocks and ethylene (Figure A-l).
Total ethylene capacity has consistently increased since 1940
(Figure A-2). The annual capacity in 1974 was 26.4 billion pounds. Average
plant size has also increased (Table A-2). Recently built plants have name-
plate capacities of at least one billion pounds per year. Since larger plants do
not yield important economies of scale, further substantial increases in
plant size are not expected in the near future. The facilities have fairly
long equipment lives, but a number of the original small-scale ethylene
units (one at Union Carbide in Texas City, Texas; two at Dow Chemical in
Midland, Michigan; and one at Jefferson Chemical Company in Port Neches,
Texas) have been shut down.
The primary feedstocks for ethylene production are gas liquids, such
as ethane, propane, and butane (LPG), and heavy liquids, such as condensate,
natural gasoline or crude fractions including naphtha and gas oil. (Table
A-3-) A small amount of ethylene is also obtained as byproduct from
refinery catalytic cracking operations. It is difficult to quantify this
source of feedstock for ethylene but it is probably less than 2%.
62
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TABLE A-l
ETHYLENE PRODUCTION UNITS IN THE U.S. AND PUERTO RICO, 1974
OJ
Company
1. Amoco
2. Dow
3. DuPont
4. El Paso-Dart
5. Exxon
6. Gulf
7. Gulf
8. Jefferson Chemical
(Texaco)
9. Mobil
10. Monsanto
11. Monsanto
12. Phillips
13. Shell
14. Texas Eastman
15. Union Carbide
16. Union Carbide
17. Allied Chemical/
BASF Wyandotte/
Borg-Warner
18. Cities Service
19. Conoco
20. Dow
21. Exxon
Location
Chocolate Bayou, Texas
Freeport, Texas
Orange, Texas
Odessa, Texas
Baytown, Texas
Cedar Bayou, Texas
Port Arthur, Texas
Port Neches, Texas
Beaumont, Texas
Chocolate Bayou, Texas
Texas City, Texas
Sweeny, Texas
Houston, Texas
Longview, Texas
Seadrift, Texas
Texas City, Texas
Geismar, Louisiana
Lake Charles, Louisiana
Lake Charles, Louisiana
Plaquemine, Louisiana
Baton Rouge, Louisiana
Annual Capacity
1,000
2,500
750
500
90
420
1,150
525
470
700
100
1,140
1,500
800
1,210
1,500
750
940
630
1,100
1,800
Year Unit
First Operated
1975
1940, 1973
1949, 1967
n.a.
1944, 1954, 1958, 1960
1963
1953
1948, 1959, 1966
1961
1963
1955
1957, 1961, 1967
1948, 1968
1952
1952
1952
1968
1958, 1971
1968
19h7, .U
1941
-------
TABLE A-l
ETHYLENE PRODUCTION UNITS IN THE U.S. AND PUERTO RICO, 1974 (Cont.)
Company
22. Shell
23. Union Carbide
24. Atlantic Richfield
25. Chemplex
26. Commonwealth Oil Refining Co.
27. Dow
28. Goodrich
29. Northern Petrochemical Co.
30 i Olin
31. Puerto Rico Olefins Co.
32. Stauffer Chemical Co.
33. Sun Olin
34. Union Carbide
35. Union Carbide
36. Union Carbide
37. U.S. Industrials
n.a. - not available
Location
Annual Capacity
(106lb)
Norco, Louisiana 550
Taft, Louisiana 500
Carson, California 100
Clinton, Iowa 500
Puerto Rico ' 990
Midland-Bay City, Michigan 170
Calvert City, Kentucky 350
Morris, Illinois 800
Brandenburg, Kentucky 120
Penuelas, Puerto Rico 1,000
Carson, California 100
Claymont, Delaware 225
Whiting, Indiana 150
Torrance, California 170
Penuelas, Puerto Rico 775
Tuscola, Illinois 350
Total Annual Capacity 26,420
Year Unit
First Operated
1965
1965
1968
n.a.
1930, 1936
1963
1971
1951
n.a.
n.a.
1962
n.a.
1956
n.a.
1953
Source: World Petroleum Encyclopedia and Arthur D. Little, Inc. estimates.
-------
Ui
Sources: World Petroleum Encyclopedia, and Arthur D. Little, Inc. estimates.
Figure A-l. Distribution of Ethylene Plants in the United States
-------
100
90
80
70
Industry
Growth as a
Percent of
1974
Ethylene
Capacity
40
30
20
10
1940
1945
1950
1955
1960
1965
1970
1974
Sources: U. S. Tariff Commission and Arthur D. Little, Inc. estimates.
Figure A-2, U.S. Ethylene Production as a Percent of 1974 Capacity
-------
TABLE A-2
TRENDS IN AVERAGE ETHYLENE PLANT CAPACITY 1966-1974
Ethylene Plant Size
(106 Ib/yr)
>200
201-300
301-400
401-500
501-1,000
<1,000
Total Capacity
(106lb)
Average Capacity
1966
12,100
448
1969
1972
19,900
568
21,600
540
1974
8
3
3 "
4
8
1
6
2
2
7
13
5
6
3
2
6
15
8
8
2
1
2
15
9
26,400
713
Sources: U.S. Petrochemicals, Technologies, Markets & Economies,
Arthur M. Brownstein (ed.), The Petroleum Publishing
Company, 1972, p. 268.; and Arthur D. Little, Inc. estimates,
TABLE A-3
U.S. ETHYLENE PRODUCTION/FEED REQUIREMENTS, 1974
Feedstock Requirements
(103bbl/day)
% of Total
Feedstock
Ethylene Production
(109lb/yr)
% of Total
Production
Ethane
Propane
Butane
Naphtha
Gas Oil
322
218
20
58
117
Total
735
44
30
2
,8
16
12.6
6.4
0.7
1.5
2.2
23.4
54
27
3
7
9
Note: Feedstock requirements are based on 1974 ethylene production - not
on capacity.
Sources: "The Future of Ethylene in the U.S. Through 1980," Dr. Bert Struth,
Chem Systems, and Arthur D. Little, Inc. estimates.
67
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Since 1965, world ethylene production has increased an average of
15.4% annually, while U.S. production has grown at an average of 10.5%
annually (Figure A-3 and Table A-4). Statistics for international trade
of petrochemicals are invariably reported in metric units and that
convention is maintained in this appendix.
At the present time, the United States is self-sufficient in
ethylene production (Figure A-4). Production levels shown in Figure A-4
are based on the total ethylene production reported to the U.S. Inter-
national Trade Commission. Data on ethylene consumption has been calcu-
lated from the reported totals for derivative production using a typical
ethylene consumption factor. They exclude some minor quantities of
ethylene which were consumed for miscellaneous derivatives. Production and
consumption of ethylene have been roughly equivalent since 1953. Imports
of ethylene have been negligible.
Since 1969, exports of ethylene derivatives have far exceeded imports
(Table A-5). The major sources of imports have been Canada, Brazil,
Argentina, the Western European nations, and Japan.
Ethylene is typically used by producers in their contiguous derivative
plants or shipped by pipeline to major consumers (Table A-6 and Figure A-5).
Because of its complexity, the pipeline network that has developed on the
U.S. Gulf Coast connecting olefin plants, refineries, salt dome storage,
and natural gas processing plants has often been called a "spaghetti bowl."
The primary participants in the U.S. olefin industry are mainly large
multinational chemical and oil companies for which it is difficult to break
out specific information concerning capital sources, investment costs and
returns on investment in ethylene facilities. The integration of olefin
plants with refineries and derivative plants further complicates the prob-
lem. However, since 1953, the volume sold and sales revenue for ethylene
have been reported annually by the U.S. International Trade Commission.
From this information an average selling price and the production value
of ethylene have been calculated (Table A-7 and Figure A-6).
2. ECONOMIC OUTLOOK
Demand for ethylene in the United States is expected to grow from an
estimated level of 23.4 billion pounds in 1974 to approximately 54.6 billion
pounds in 1984 (Table A-8), for an average compound growth rate of 8% per
annum. Low density polyethylene will continue to be the major ethylene
derivative, with a growth rate equal to that of total ethylene demand.
Ethylene oxide, which is currently the second most important ethylene
derivative in the United States, is expected to grow at a slower rate of
approximately 6% per annum over this period, but will retain its place next
to low density polyethylene as the second largest consumer of ethylene.
High density polyethylene, styrene and vinyl chloride are all expected to
grow at an average annual rate of 7% per year from 1974 to 1984. Acetalde-
hyde and ethanol will grow at rates of 3% and 2% per year, respectively.
68
-------
U.S and Puerto Rico
I
|
1965 66 67 68 69 70 71 72 73 74
Sources- U.S. Tanft Commission and Arthur 0. Little, Inc estimates.
Figure A-3. U.S. vs World Ethylene Production
TABLE A-4
U.S. AND WORLD ETHYLENE PRODUCTION
(thousands of metric tons)
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
U.S. and
Puerto Rico
4341
5099
5377
5965
7455
8205
8369
9458
10,163 ,
10,650
Increase
World
Increase
17
5
11
25
10
2
13
7
5
7254
8777
9932
11,737
14,844
17,336
18,512
21,428
23,898
26,179
21
13
18
26
17
7
16
11
10
*Includes Canada, the United States and Puerto Rico, Mexico, Brazil,
Belgium, France, the Federal Republic of Germany, Italy, the Netherlands,
the United Kingdom, Finland, and Japan.
Note: World production is understated in that it does not include produc-
tion by Eastern European Countries, Asia Pacific nations, and U.S.S.R.,
China, the Middle East, and other Latin American Nations. The total
capacity for ethylene production is the sum of the above nations as of
April, 1974, estimated greater than 32,191,000 metric tons. The
addition of planned expansions will bring world capacity to greater
than 49,364,000 metric tons per year.
Sources: U.S. Tariff Commission, Foreign Industrial Production Data, and
Arthur D. Little, Inc. estimates.
69
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-j
o
TABLE A-5
U.S. ETHYLENE AND ETHYLENE DERIVATIVES TRADE, 1969-1974
(thousands of metric tons)
Exports
Ethanol
Ethylene Dichloride
Ethylene Glycol
Perchloroethylene
Trichloroethylene
Polyethylene Resin
Styrene Monomer
Vinyl Acetate
Vinyl Chloride
Total
Production
Exports as % of
Production
Imports
Ethanol
Ethylene Dichloride
Ethylene Oxide
Perchloroethylene
Trichloroethylene
Polyethylene Resin
Styrene Monomer
Vinyl Chloride
Vinyl Acetate
Total
Imports as % of
Production
1974
1973
1972
1971
1970
1969
A
136
167
74
13
19
332
282
103
n.a.
B
88
52
70
2
4
351
90
38
A
174
167
79
36
18
359
261
128
191
B
n.a.
113
52
75
6
4
380
84
47
99
A
106
171
106
49
19
312
300
101
282
B
n.a.
69
53
101
9
4
331
96
37
147
A
16
158
97
n.a.
24
246
167
n.a.
281
B
n.a.
10
49
92
5
261
53
146
A
9
308
125
n.a.
15
271
258
n.a.
301
B
n.a.
6
95
119
3
287
83
157
A
36
n.a.
83
n.a.
n.a.
298
377
n.a.
n.a.
B
n.a
23
79
316
121
10,650
607
5.8
10,163
860
8.5
9,458
847
9.0
8,369
616
7.4
8,205
750
9.1
7,455
0.14
0.15
0.16
0.19
0.25
539
7.2
50
n.a.
n.a.
10
62
n.a.
n.a.
n.a.
n.a.
32
2
13
15
8
n.a.
1
20
21
n.a.
n.a.
n.a.
neg.
n.a.
5
1
4
5
15
n.a.
neg.
3.3
12
28
4
n.a.
neg.
neg.
n.a.
3
2
6
4
15
n.a.
neg.
neg.
20
4
9
n.a.
n.a.
3
n.a.
4
1
10
1
16
n.a.
n.a.
neg.
18
14
9
n.a.
neg.
14
n.a.
3
3
10
5
21
neg.
neg.
16
16
2
n.a.
neg.
19
n.a
3
4
2
7
16
0.21
Notes: A = product; B = ethylene equivalent; neg. = negligible; n.a. = not available.
Sources: United States Tariff Commission and Arthur D. Little, Inc. estimates.
-------
TABLE A-6
U.S. ETHYLENE CONSUMPTION BY DERIVATIVE PRODUCT, 1974
(millions of pounds)
Product Quantity
Polyethylene 9,290
Ethylene Oxide 4,460
Ethylene Glycol 2,545
Di- and Tri-ethylene Glycols 345
Glycol Ethers 290
Ethanol Amines 270
Nonionic Surface-Active Agents 530
Other 480
Ethylene Dichloride and Derivatives 3,210
I
Ethyl Benzene 1,810
Ethanol 1,250
Acetaldehyde 630
Linear Primary Alcohols 460
Vinyl Acetate Monomer 435
Alpha Olefins 330
Ethyl Chloride 310
Ethylene-Propylene Elastomers 165
Propionaldehyde 100
Ethylene Dibromide 55
TOTAL 22,505
Sources: U.S. Tarriff Commission; industry reports; and
Arthur D. Little, Inc. estimates.
71
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I
I
1953 1958 1963 1968
Source: U.S. Tariff Commission and Arthur D. Little. Inc estimates.
Figure A-4. U.S. Ethylene Production vs Consumption, 1953-1954
Ethyl
Benzene
Ethanol
Vinyl Acetate Monomer
Linear Primary Alcohols
Acetaldehyde
Sources: U.S. Tariff Commission; industry reports, and
Arthur D. Little, Inc. estimates.
Figure A-5. Distribution of Ethylene by Derivative Products, 1974
72
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TABLE A-7
U.S. ETHYLENE PRICES AND REVENUES
Year
1953
1954
1955
1956
1957
1958
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
n.a.
Merchant Sales
(millions of Ib)
254
320
416
594
619
I
737
2,941
3,252
3,360
3,979
2,208
2,377
2,715
3,277
3,353
3,367
3,877
5,047
4,617
5,649
6,833
n.a.
= not available
Sales
Revenues
($ million)
13
15
20
30
29
35
147
163
168
187
99
112
109
134
134
114
128
156
i
!
138
169
225
n.a.
Unit Price
(C/lb)
5.0
4.7
4.7
5.0
4.7
4.7
5.0
5.0
5.0
4.7
4.5
4.7
4.0
4.1
4.0
3.4
3.3
3.1
3.0
3.0
3.3
6.4
Reported
Production
(millions of Ib)
2,136
2,345
3,048
3,602
3,947
4,149
5,099
5,448
5,656
6,283
7,518
8,641
9,570
11,241
11,851
13,151
16,436
18,089
18,450
20,852
22,329
23,217
Production
Value
($ million)
107
110
143
180
186
195
255
272
283
295
338
406
383
461
474
447
542
561
553
626
737
1,486
Sources: U.S. Tariff Commission and Arthur D. Little, Inc. estimates.
73
-------
Unit Price
U/lb)
Sales Revenues
1500
1400
1300
1200
1100
1000
900 Merchant Sales Revenues
and Production Values
($MM)
800
700
600
500
400
300
200
100
1953 1955 1960 1965 1970
Sources: U.S. Tariff Commission and Arthur D. Little, Inc. estimates.
1974
Figure A-6. U.S. Trends in Ethylene Prices and Revenues, 1953-1974
74
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TABLE A-8
FUTURE OUTLOOK: UNITED STATES ETHYLENE DEMAND
(millions of pounds)
Demand Forecast
1974 1980 1984 Growth
(% p.a.)
Acetaldehyde 660 795 935 3
Ethanol 1,985 2,225 2,425 2
Ethylene Oxide 4,385 6,215 8,320 6
Low-Density Polyethylene 6,325 10,030 14,765 8
High-Density Polyethylene 3,020 4,540 6,390 7
Styrene 1,895 2,845 3,970 7
Vinyl Chloride 2,070 3,110 4,410 7
Other2 3,175 7,495 13,445 14
Total 23,515 37,255 54,660 8
Notes: 1) Average annual compound growth from 1974 to 1984, rounded to
nearest percent.
2) Includes Ziegler alcohols, alpha olefins, ethyl chloride, ethylene
dibromide, vinyl acetate, ethylene-propylene elastomers and others.
SOURCE: Arthur D. Little, Inc. estimates.
The capacity to meet increased ethylene demand will be met by planned
expansions by a number of producers, primarily oil companies (Table A-9).
It is expected that by 1979 annual U.S. capacity will be greater than
33.8 billion pounds, including expansions and new facilities planned and
already under construction by Amoco, Atlantic Richfield, Conoco, Dow,
Du Pont, Gulf, Mobil, Phillips, Shell, Texaco and Union Carbide. The
steadily rising cost of feedstocks and increasing cost of new olefin
plants will result in a sharp increase in ethylene production costs during
• the next five years.
As noted earlier, the primary feedstocks for ethylene production
include natural gas liquids, such as ethane, and LPH, and heavy liquids,
including crude oil fractions, such as naphtha and gas oil. A significant
change in feedstock usage is currently underway in the United States
(Figure A-7). During the next decade, the total U.S. supply of natural gas
liquid feedstocks will show no significant growth. Thus, most new olefin
expansions will be based on cracking of heavy liquids, principally those
based on crude oil fractions derived from refinery operations. Cracking
of these heavy liquids also produces a substantial volume of other chemical
intermediates as well as fuel coproducts which can most efficiently be
used by a refiner. Thus, the shift to cracking of heavy liquids has
encouraged integration of new olefin plants with refineries.
75
-------
TABLE A-9
MAJOR ETHYLENE EXPANSIONS (BY 12/77)
Company
Atlantic Richfield (ARCO)
Standard Oil (Indiana) (AMOCO)
Gulf Oil
Dow Chemical
Texaco
Phillips Petroleum
DuPont
Union Carbide
Shell Oil
Mobil Oil
Total
New
Capacity*
(million of
pounds)
1,300
1,300
1,000
1,200
1,000
1,000
1,000
825
650
600
900
450
11,225
Location
Channelview, Texas
Channelview, Texas
Chocolate Bayou, Texas
Cedar Bayou, Texas
Plaquemine, Louisiana
Port Arthur, Texas
Sweeny, Texas
Orange, Texas
Taft, Louisiana
Deer Park, Texas
Deer Park, Texas
Beaumont, Texas
On-Stream
1976
Feedstocks
mid-1976
1977
late 1977
early 1976
1977
1977
1978
1981
end 1977
1976
1976
N/GO
N/GO
E, P, N/GO
N/GO
E, P
N
E, P
E, P
E, P, N/GO
N/GO
N/GO
N
*Total ethylene capacity by the end of 1977 will be about 35 billion pounds,
ethylene capacity should approximate 41 billion pounds.
E = ethane
P = propane
RG = refinery gas
N/GO = naphtha/gas oil
Source: Company announcements as of December, 1975.
By 1980, total
-------
I I I I I I I
Ndlur.il Gdi Lf.iu.d-.
1965 67 69 71 73 75 77 79 81 83 85
Sourw1 Anhu. D Little. IM
Figure A-7- Trends in Feedstock Supplies
The use of heavier feedstocks also results in an increase in coproduct
chemical output. The increased supply of these coproducts, particularly
propylene, butadiene and benzene, will significantly affect the supply/
demand balance for these three products in the future. As a result,
propylene prices are not expected to increase as rapidly as ethylene prices,
which will provide propylene derivatives such as polypropylene with a cost
edge over ethylene derivatives such as polyethylene in those markets where
these materials are directly competitive. In the case of butadiene, exist-
ing butane dehydrogenation plants may not be able to compete in the future
with coproduct olefin supplies and these plants could be forced to close.
Benzene extracted from olefin plant pyrolysis gasoline will become
increasingly important as a source of benzene over the next decade. How-
ever, conventional refinery sources of benzene will not be sufficient to
meet demand growth during this period so the availability of benzene from
olefin plant pyrolysis gasoline will not be a disruptive factor in U.S.
markets.
77
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APPENDIX B
PRESENT TECHNOLOGY
1. FEEDSTOCKS
Feedstocks for ethylene production fall into three general categories:
light aliphatic hydrocarbons, naphthas, and gas oils. The light hydrocarbons
predominantly consumed are ethane and propane, although small amounts of other
LPG components, such as the butanes, are also consumed. These materials are
produced from refinery operations and by extraction from natural gas. The
extraction techniques are oil absorption, refrigerated oil absorption, and
cryogenic separation. The natural gas liquids extracted from the natural gas
stream are separated by distillation and purified to the required purity by
various techniques. During the 1950's and 1960's the predominant feedstocks
for producing ethylene in the United States were ethane and propane (E-P)
because of their wide availability and low cost. The cracking of E-P to ethy-
lene requires simpler facilities and produces less byproducts than the crack-
ing of heavier feedstocks. E-P can easily be desulfurized to low concentra-
tions of sulfur. For this study, ethane and propane feedstocks are assumed
to contain a nominal average sulfur concentration of 10 ppm.
In recent years naphtha (the fraction of a crude oil boiling between the
LPG cut and 350-400°F) has become a desirable feedstock for pyrolytic produc-
tion of ethylene. Because naphtha is a heavier material, the pyrolysis reac-
tions are more complex, a wider variety of product is obtained, and a smaller
fraction of the feed is converted to ethylene. Also, because it is less
amenable to pretreatment than ethane-propane, much larger quantities of sulfur
are present (typically 100-700 ppm). A value of 500 ppm was assumed for this
study, since the average sulfur content of naphthas can be expected to increase
as more high-sulfur crudes are processed.
Atmospheric gas oil—the refinery fraction boiling between the naphtha
cut and 550-650°F—is also becoming an increasingly popular feedstock because
of relative cost and availability advantages. Tubular cracking of this mater-
ial is even more difficult than for naphtha. Ethylene yields per unit of
feed are lower; large quantities of heavy byproducts are produced. The sulfur
concentrations in atmospheric gas oils are apt to be quite high (commonly
0.2-1.0 wt %). This study is based on a gas oil feed with a concentration of
0.2 wt % sulfur. High-sulfur gas oil feeds for ethylene cracking are usually
hydrodesulfurized by a refiner before being used in ethylene plants.
78
-------
Although each company offering ethylene technology uses significantly
different designs for the cracking furnace and quench systems, E-P (ethane-
propane) crackers operate generally as illustrated in Figure B-l. Ethane
and propane feed streams are mixed at low pressure with dilution steam, and
preheated in the convection section of cracking furnaces before being pyro-
lyzed at 1400-1600°F in the radiant coil sections. Heat recovery for boiler
feedwater heating and stream superheating is also carried out in the convec-
tion section of the pyrolysis furnace. The hot mixture of cracked gases and
steam leaving the furnaces is cooled in transfer line heat exchangers, gen-
erating high pressure steam in the process. Further cooling takes place in
the water quench system where most of the dilution steam and some heavy oils
and tar are condensed. Hydrocarbons are removed from the condensed water in
a water/oil separator and the water is recycled to the dilution steam boilers.
The pyrolysis gases are compressed from near atmospheric pressure to a pressure
of about 35 atm. by a four- or five-stage compressor. During this compression,
the increasing pressure combined with interstage cooling causes the condensa-
tion of higher molecular weight hydrocarbons (colloquially referred to as
"dripolene") and more water vapor.
Product specifications for high purity ethylene dictate that carbon
dioxide concentration must be reduced to 10-15 ppm and hydrogen sulfide to
1-2 ppm. This purification is accomplished by scrubbing the high pressure
process gas with a counter-current caustic solution in a multi-stage system.
The low operating temperatures of the downstream product recovery sections
also dictate a low concentration of water in the process gas. Drying is
typically accomplished first with propane refrigeration to remove a majority
of the water vapor by condensation and then with a molecular sieve or other
solid desiccant to reduce residual water concentration to 1-2 ppm.
Product is recovered in a series of low temperature distillation columns.
The demethanizer section separates hydrogen and methane from the other gases.
The deethanizer produces an ethane/ethylene overhead stream containing some
acetylene. This acetylene may be selectively hydrogenated to ethane and ethy-
lene using a palladium-based catalyst and high purity hydrogen recovered in
the demethanizer system. Alternatively, the acetylene may be absorbed by a
gas/liquid scrubbing system. The acetylene-free ethane and ethylene are then
separated by distillation; ethane is recycled to the cracking furnace. Similar
distillations in the base line plant would yield product streams of mixed C3's,
mixed C,'s, and raw pyrolysis gasoline from the de-ethanizer bottoms.
For the base case, a downstream fractionation system is provided for the
separation of propane and polymer-grade propylene. The propane would be
recycled to the cracking furnaces. Downstream processing is also provided
for the "dripolene" and raw pyrolysis gasoline recovered in the cryogenic
fractionation system. These streams contain a high proportion of unsaturated
hydrocarbons that must be hydrotreated to produce a stable gasoline product.
79
-------
co
o
II
y
Piopylene
Mixed Gojolme
P. Gdv
Hydrorfeaiing
Figure B-l. Base Line E/P Cracker
-------
In 1974, 44% of the ethylene produced in the United States was from
ethane, 32% from LPG, 8% from naphtha and 16% from gas oil.
In developing the economic analysis, we have used feedstock costs that
were representative of conditions in the fourth quarter of 1974 and the first
quarter of 1975. Significant increases in the worldwide cost of petro-
chemical feedstocks such as naphtha have occurred since the onset of the Arab
oil embargo in 1973. The release of U.S. wage and price controls on all but
petroleum products in 1974 has also contributed to rapid escalation in other
raw material costs. Prices for almost all feedstocks and raw materials
reached a peak in the third quarter of 1974 and, because of the recession in
the United States, prices stabilized during the fourth quarter. Prices
declined slightly during the first quarter of 1975 because of the continued
reduction in worldwide economic activity. However, we believe that the values
chosen are still representative of the range of raw material costs experienced
by Gulf Coast producers during the first quarter of 1975.
Because ethane prices are not controlled by either the Federal Power
Commission or the Federal Energy Administration, the costs of ethane to the
petrochemical industry have escalated rapidly during the past year. Natural
gas liquids processors who extract ethane and LPG (such as propane and
butane) from natural gas'streams have priced ethane to reflect alternative
fuel value. Thus, ethane prices (which are not published) are currently
15-17c/gallon. As with naphtha, the range of costs for ethane will vary
widely depending on contract provisions, but since ethane is not easily trans-
ported except by pipeline, the market alternatives open to producers are
limited. In fact, virtually all the ethane that is extracted is sold to the
petrochemical industry for use as a feedstock. For this analysis, we used a
value of 16
-------
The cost of naphtha on the U.S. Gulf Coast is difficult to estimate
because naptha is not a widely traded commodity within the United States.
Since most heavy liquids crackers now operating on the Gulf Coast are owned
by the major oil companies, the value for naphtha for these operations is a
matter of specific refinery economics and transfer pricing considerations.
However, it is possible to estimate the approximate value of naphtha to the
refinery by adding to the cost of crude oil a processing charge for crude
distillation or by subtracting from the value of gasoline the cost of reform-
ing naphtha (Table B-l). The latter approach establishes the value of naphtha
to the refiners based on its primary use in the United States, which is as a
raw material for gasoline.
This approach establishes a range of Gulf Coast naphtha values from
$9.11 to $11.53/bbl. Because of reduced demand there was no shortage of
crude oil, and the United States had surplus refining capacity during the
fourth quarter of 1974. Thus a value close to crude oil cost plus the pro-
cessing charge seems to be the best indicator of naphtha values. We have
chosen $10.75/bbl as a reasonable estimate of naphtha value for the Gulf
Coast at that time.
The cost of gas oil on the U.S. Gulf Coast can be closely approximated
by the cost of kerosine. In 1975, a reasonable average value was $11.00/bbl
and this value is used in the economic analysis of a model gas oil cracker.
2. DESCRIPTION OF MAJOR PROCESSES
The dominant technology in use today for domestic production of ethylene
is tubular cracking of light hydrocarbons (LPG). This method, originally
developed by Linde Air Products Company (a part of Union Carbide Corporation)
in 1920, involves the high temperature, non-catalytic pyrolysis of ethane,
propane or butane inside radiantly heated tubes at low pressure and in the
presence of steam. Although the reaction scheme for pyrolysis of these and
heavier feeds is very complex, the simplest and most important example of
ethylene formation is the following free radical reaction sequence for ethane:
(1) C0H, -»• (CH,)' + (CH,)- Initiation
z o o j
(2) (CH3)' + C2Hg -> CH4 + (C2H5)' Propagation
(3) (C2H5)' + C2H4 + (H)' Propagation
(4) (H)' + C.H + H + (C9H,.)' Propagation
/ b 2. 2. _>
etc.
Note: ()' denotes a free radical
The engineering design of systems to pyrolyze the hydrocarbon, quench the
pyrolysis gases to halt side reactions, and separate the products formed when
free radicals are present is formidable.
32
-------
TABLE B-l
U.S. GULF COAST NAPHTHA VALUE ANALYSIS
(December 1974)
I. CRUDE OIL COSTS PLUS PROCESSING CHARGES
Domestic Crude
Old Oil
New Oil
Average
Imported Crude
Composite Crude Cost
Crude Distillation Charge
Estimated Refinery Cost for Naphtha
II. GASOLINE PRICE LESS REFORMING MARGIN
Gasoline Values (@ 28-29
-------
3. COST FACTORS
The total investment, including normal offsite facilities and working
capital for a plant producing 1.1 billion pounds per year of ethylene is sub-
stantial, approximately $174.2 million for one completed in 1975 on the
U.S. Gulf Coast. When all costs for such a model E-P cracker, including a
20% pre-tax return on total investment, are included in a calculation of
ethylene production cost, an estimate of 9.7£/lb is obtained (Table B-2).
Since our economic analysis of an E-P cracker (Table B-2) serves as a
model and basis of comparison for the other types of ethylene plants considered
in this study, we have determined the important cost factors (Table B-3) as
follows. All calculations of capital investment have assumed a plant start-
up date of 1975 and a location on the U.S. Gulf Coast. Standard factors have
been assumed for: offsites (50% of battery limits cost); start-up costs (3%
of battery limits); spare parts (3% of battery limits); and working capital
(value of 60 days' production plus one month of other expenses, labor, insur-
ance, etc.). A straight-line depreciation period and investment life of 11
years is used in accordance with IRS guidelines. Profitability is set on the
basis of a 20% pretax return on the total investment. This pretax return on
total investment has been used in all of the thirteen studies proposed under
this contract and is an average return approximating what we believe is repre-
sentative of all 13 industry expectations. The olefin industry has tradition-
ally striven for a somewhat greater return on total investment which is fre-
quently considered to be 25%. This additional 5% return on investment would
add almost 0.80 to the calculated cost of a pound of ethylene produced from
an ethane-propane feed. Taxes and insurance are set at 2% of plant cost.
Operating requirements are calculated as those crossing the economic
analysis system boundary (Figure B-2). Thus, utility costs do not include
the internal transfer prices of the residue gas (and fuel oil) recycled to
the plant fuel system. Likewise, byproduct credits are based on the net
plant production.
84
-------
TABLE B-2
ESTIMATED ETHYLENE PRODUCTION COST VIA E-P CRACKING
Product: Ethylcnc Process: E/P Cracker 1975 Cost Basis
Byproducts: Propyleno, Mixed C.'s, (Continuous) 340 Stream Days/Yejr
Pyrolysis Gasoline U.S. Gulf Coast Location
Annual Capacity: 1.1 billion Ih/Vr Fixed Investment: $149.3 million
Annual Production: 1.1 Billion Ih/Yr Working Capital: 524.9 million
Variable Cants
Rau Materials: Ethane riSh/yr 359.7 3.47c/lb 29,810
Propane 0 lh/yr 859.7 2.04c/lb 17.560
Byproduct Credits: Propylcne oSh/vr 150.88 8c/lb -12,070
Mixed C^'s OTlb/yr 46.09 8.125c/lb - 3.740
Pyrolysis Gasoline 0 Ib/yr 62.89 4.97c/lb - 3.130
Purchased Energy: Power oJjkWh 92.60 ] . Viv/kMi 1,260
Steam 0 Ib 4.23 $3.40/0001b 14,390
Water: H.P. Boiler Feed O^.il .027 $ 1.OO/1 O'R.I 1 27
Process O^gal .082 SO.SO/10 Ka1 41
Cooling 0 R-il 42.t6 SO.OS/in Eal 2.133
Catalyst and Chemicals $000 77$ — 77b
Operating Ubor (excl. fringes) men/shift 8 S6.07/oan-hour 2,141
Administrative Overheads 902 o( Operating Labor 1.4J7
Maintenance Costs 32 of Plane Cost 4,403
Fixed Cos til
Plant Overhead 802 of Operating Labor 1,268
Taxes and Insurance 2% of Plant Cost 2,935
Depreciation 11 Year Straight Line 13,341
Total Production Cost 72.038
Pretax Return on Total Investment 207 14,840
TOTAL 10fi.S7fi
Fqulvalent to ethylcn* 9 9.7c/lb
TABLE B-3
STANDARD COST FACTORS FOR ETHYLENE PLANT ECONOMICS
Feed Prices:
Byproduct Values:
Operating Requirements:
Cost Element
Ethane
Propane
Naphtha
Gas Oil
Residue Gas
Other 64's
Fuel Oil
Propylene
Butadiene
Pyrolysis Gasoline
Fuel
Electricity
HP Boiler Feedwater
Process Water
Cooling Water
Operating Labor (excl.
fringes)
Unit Price
16c/gal (3.47c/lb)
10
-------
Economic Analysis System Boundary
CO
1—
r~
1
1
1
1
1
Feedstock '
1
1
1
1
l_ -
l_
Ethane and Propane Recycle
Pyrolysis
and
Quench
i
Elect
i
ricity
Comp
ar
Purifi
Proc
•ession Sepat
cation D°wn
Proce
Juct
ation
id
>tream
ssing
j
Pure
Pro
F
^ Total '
Process
Fuel
lased Purcl"
cess Ste
jel Bo
Fu
n
i
I
1
1
1
i »
i
1
1
j
1 Total
Boiler
Fuel
ased
am
ler
el
Fue
From
Derived
Feedstock
"1
» Net
Products
|
Figure B-2. Economic Analysis Boundaries
-------
APPENDIX C
ENERGY USE - BASE LINE PROFILE
Energy consumption in an ethylene plant can be divided into two cate-
gories: energy contained in the feedstock, and energy required for the
utilities. In an E-P cracker, feedstock energy (34,200 Btu/lb ethylene
produced, based on its higher heating value) accounts for more than 80% of
the total. The remaining 20% of the energy requirement is used in a number
of ways, the major ones being: firing of the pyrolysis furnaces; steam
generation for driving process gas and refrigeration compressors and major
pumps, for dilution steam, and for process heating; and electric power for
various drives. Much of this utility energy requirement can be supplied by
recycling some of the lower valued products to the plant fuel system. In
an E-P cracker, the only such recycle streams are excess hydrogen and
methane, collectively referred to as "residue gas." The net plant
production, after residue gas recycle, is given in Figure C-l.
The consumption categories and fuel derived from the feedstock have
been quantified in Table C-l. These quantities enter the stream boundary
illustrated in Figure C-2. For comparability, electric power consumption
is expressed in terms of the thermal energy needed to generate it (approxi-
mately 10,500 Btu/kWh). Similarly, the steam requirement is expressed as
the net quantity of boiler fuel necessary to generate it. Not all steam
used in the process would be generated in a direct fuel-fired boiler, some
would be generated by heat exchange with hot process gases in the transfer
line heat exchangers. However, since this heat exchange takes place within
the system boundary defined in Figure C-2, it does not enter into an energy
balance calculation.
Note that total energy consumption has been expressed both as Btu per
pound of ethylene, and as Btu per pound of net products.
37
-------
1
Elh.mr
SliMin
/\
X/
Propane
Dilution
Steam
/2\
Pyiolysi-i
PlOIMMl'
Pyolysis
Pi
0|).me Recycle
Eth,me RL-CVC
T....KI.M
Lin,.
E x chut igt;
Tl,tM-.ll'l
LlMf
H.MI
Exrh,)ii(|c
<3
X/
>
>
^
c
^
1
W,i
)!.,:
~-|
'
0
/
Separation Py,0iysft G.,M>|M,,-
'
x9 HI. ,i
^ 1 Ri'rovi'iy
/^N
V-> W..I,.,
1 1 TiiMtini'iil
Oil/H,O l\ t A""
Sf|)iil,i1inil |/ ^\^ iv mi ii mi
Tar NT/
^ Oi'Mi'i.innii
To HydroiT.nhnii
W.istr Dispns.,1
170W Kilograms/Hi
H2
CH4
C2H4
Other C2*s
C3H6
Olhei Cj's
Butadiene
Other C4's
cs^
H2O
Ethane Recycle
Propane Recycle
Fresh C2Hg Feed
FrushCjHg Feed
1
28.610
38,130
47.787
2
21.026
4.777
47.787
3
2.895
4.270
41.396
34.367
833
404
584
395
773
28.610
4
857
12.028
19,882
3,764
7,554
4.374
894
689
2,723
21,026
5
3,752
16.298
61.277
38,131
8.387
4.778
1.478
1.084
6.035
6
50
7
3,678
16.388
61.277
8,387
1.478
1.084
3,446
Residue Gas (H2. CH4I LHY - 553 BTU/SCF = 4924 K cal/M3
Source: Arthur D. Little Inc. estimates.
Figure C-l. Ethylene From An E/P Cracker (50% Ethane,
50% Propane) 1.1 Billion Pounds per Year
88
-------
TABLE C-l
ENERGY CONSUMPTION IN BASE LINE E-P CRACKER
(Per Pound Ethylene Product)
Feedstock Energy (HHV)
Utilities: Process Fuel
Electric Power
Net Steam Boiler Fuel
Total Utilities
Credit Fuel Derived from Feedstock
Total Energy Consumption
(Per Pound Net Products)
Total Energy Consumption
7,800
900
8,000
Btu/lb
34,000
16,700
(8,800)
42,100
34,000
Source: Arthur D. Little, Inc. estimates.
Energy Balance System Boundary
Ethane and Propane Recycle
Feedstock
Pyrolysis
and
Quench
Compression
and
Purification
Product
Separation
and
Downstream
Processing
Total
Boiler
Fuel
" Net
Products
Fuel Derived
From Feedstock
Electricity
Purchased
Process
Fuel
Purchased
Steam
Boiler
Fuel
Arthur D. Little, Inc. estimates
Figure C-2. Energy Flow Diagram: E-P Cracking
89
-------
APPENDIX D
CURRENT POLLUTION PROBLEMS AND EFFECTIVENESS OF AVAILABLE
POLLUTION CONTROL TECHNOLOGY - BASE LINE CASE
The manufacture of ethylene from ethane and propane is a relatively
clean process. The feedstock of the plant is typically a low-sulfur, gaseous
fuel, and the energy for the process is typically supplied in the form of
electricity and natural gas. The process has no major uncontrollable air
emissions or solid wastes, and the wastewater load is expected to be only a
small fraction of the total load of the petrochemical complex in which such
a plant would be located.
A detailed discussion of the process including a process flowsheet is
given in Appendix B. A schematic representation of the flowsheet showing
the potential air, water and solid waste emissions is shown in Figure D-l.
The nature of these emissions are summarized in Table D-l, and a detailed
discussion of each is given in the following sections including considera-
tion of emission sources and rates, available control technology, and the
cost of control. The estimated flows and calculations given in this appen-
dix are based upon a 1.1 billion pound per year ethylene plant using an
ethane-propane feedstock having an average sulfur content of about 10 ppm.
1. WATER-RELATED ENVIRONMENTAL PROBLEMS
The quantity and characteristics of the wastewaters are reasonably well
established and practicable water pollution control technology exists. In
establishing the base case wastewater parameters, use was made of ADL sources
and the EPA's Development Document for Effluent Limitation Guidelines for
the Organic Chemicals Industry (EPA-440/l-74-009-a, April 1974, page D-22).
In considering the base case, both by itself and in comparison with
alternative processes, it is extremely important to realize that an ethylene
production unit typically resides within a petrochemical complex and discharges
its wastewater to a central treatment facility which treats the wastewater
from all of the production units within the complex. This feature has
important implications with regard to the significance of water pollution
problems and the nature and cost of required pollution control.
a. Wastewater Characterization
The base case ethylene plant has the following five major sources of
contaminated wastewater: .
90
-------
Feed
H.P. Steam
8FW
Product Separation
and Purification
Ethylene
Water effluents
Solid wastes
Figure D-l. Pollution Source Identification/Ethane-Propane Cracking
91
-------
TABLE D-l
SUMMARY OF POLLUTANT EMISSIONS (Basis: 1.1 billion pounds/yr ethylene)
Estimated Emission Rate,(Ib/hr)
1
Stream No.
Water Pollution
W2
w3
W5
W8
Air Pollution
A,
A3
A6
A8
A9
A10
All
Solid Waste
S3
S8
S9
Description
High-pressure steam blow-)
down /
Coke slurry from scrubber!
Dilution steam blowdown /
Spent caustic
Boiler stack gas
Decoking exhaust
Compressor seals
Acid gas exhaust
3
Fugitives
Regeneration exhaust
Prod. & feed storage
Coke & waste treatment
sludge
Recovered sulfur
Spent dessicants
E-P ,
Pollutant Uncont. Cont.
IBOD 54.0 3.3
COD 215.8 78.2
Dissolved slds. 100.5 100.5
2
SO,
Particulates 41.6 "* 0.9
so2
Hydrocarbons - 13.4
H2S 2.2 2.2
Hydrocarbons 81.1 20.3
Hydrocarbons, soot - 1.3
Hydrocarbons
Sludge - 208.3
Amorphous sclid
Dry solids - 8.1
Naphtha i
Uncont. Cont.
93.2 5.5
369.8 133.6
872.6 872.6
24.2 2.0
41. 611 1.3
0.2
13.4
165.3 8.8
81.1 20.3
2.6
47.2
357.7
156.5
8.1
Gas Oil
Uncont. Cont,
168.6 10.1
680.4 244.4
114.2 114.2
707.5 12.1
41.6" 2.0
0.2
13.4
293.1 13.2
81.1 20.3
2.6
24.2
661.6
279.9
8.1
'Level of control required to meet BATEA, NSPS, etc.
2Rate of S02 emission based upon combustion of fuel oil product only.
^Fugitives include emergency venting, startup, miscellaneous leaks and spills. Control level assumes
that all vents go to flare.
tt
Intermittent source.
Source: Arthur D. Little, Inc. estimates.
-------
• Decoking Scrubber Effluent - To prevent dislodged carbon particulate
matter from creating an air pollution problem during decoking of the
pyrolysis furnaces, a scrubber must be used to collect the particu-
late matter. The scrubber generates a wastewater stream containing
suspended particles of carbon and represents the largest volume of
wastewater.
• Dilution Steam Slowdown - The recycle dilution steam becomes
increasingly concentrated in hydrocarbons and various pyrolysis
products; to keep equipment operable a portion of the total steam
flow is removed from the recycle system and discharged to the waste-
water system. The volume of dilution steam blowdown is estimated
to be in the area of 5% of the total wastewater flow.
• High-Pressure Steam Blowdown - To prevent the buildup of scaling
and corrosion-causing compounds in the high pressure steam system,
a portion of the flow is discharged to the wastewater system. The
volume of this blowdown is estimated to be approximately 25% of
the total wastewater 'flow.
• Acid Gas Scrubber - Pyrolysis gases must be scrubbed with an
aqueous caustic stream (in conjunction with other measures) to
remove sulfur compounds and carbon dioxide. Spent scrubber
solution becomes a wastewater stream.
• Non-Contact Cooling Water Blowdown - A very large volume of non-
contact cooling water is used in olefin plants for heat rejection.
Typically, cooling water is circulated through a cooling tower,
most of the water being recycled. A portion of the cooling water
must be blown down to control the buildup of scale- and corrosion-
causing inorganic salts. Very often, corrosion inhibitors are
used in the cooling water. Should the less environmentally
acceptable inhibitors (such as chromium) be used, some form of
treatment will have to be applied to cooling water blowdown. For
the purpose of comparison, cooling tower blowdown has not been
included in the waste streams under consideration, as the volume
will be very nearly the same for all alternatives.
Table D-2 presents the estimated flow rates of the four major process
wastewater streams from the base case ethylene production unit.
The combined wastewater stream contains a variety of hydrocarbon
pyrolysis products, carbonates, sulfates, sulfides, inorganic salts, and
suspended solids. Generally, the pollutants of greatest concern are the
hydrocarbons and various 'sulfur compounds which are characterized by non-
specific parameters such as 5-day biochemical oxygen demand (BOD^) and
chemical -oxygen demand (COD).
93
-------
Plant surveys performed in the preparation of the Effluent Guidelines
Development Document for the Organic Chemicals Industry* indicate the fol-
lowing waste loadings to be generally representative of existing ethylene
production units.
Average BOD = 0.40 lb/1000 Ib of ethylene produced
Average COD = 1.60 lb/1000 Ib of ethylene produced
As previously discussed, the ethylene unit will typically be part of a
complex containing downstream production units, most of which also generate
wastewater and contribute 6005 and COD. For the base case the downstream
production units consist of low density polyethylene, ethylene glycol, and
polypropylene. Wastewater flow rates and BOD^ contributions have also been
estimated for the production units that co-exist with the ethylene unit.
Table D-2 shows the relative waste contributions from the various production
units within the base case complex. As Table D-3 shows, the ethylene pro-
duction unit is responsible for less than 6% of the total wastewater flow
rate and 10% of the total BOD5 load.
b. Existing Regulatory Constraints
Water pollution regulatory constraints imposed upon the manufacture of
olefins and other major organic chemicals are mainly the result of Sections
304(b) and 306 of the Federal Water Pollution Control Act, as amended
(PL 92-500). The Act provides for the United States Environmental Protection
Agency to issue effluent limitation guidelines applicable to the point source
discharge of industrial wastewater. The effluent limitation guidelines for
the Organic Chemicals Industry are based on the "EPA Development Document"
pertinent to that industry.*
The Development Document is a technical study which characterizes the
industry, describes the sources of water pollution, and presents suggested
permissible effluent levels based upon recommended technology and its
associated cost. The effluent limitations guidelines, based on the Develop-
ment Document and supplemented by EPA and industry review and comment, form
the basis for establishing NPDES permits.
The effluent limitations guidelines set forth three effluent discharge
levels for the manufacture of olefins:
*"Development Document for Effluent Limitation Guidelines and New Source
Performance Standards for the Major Organic Products Segment of the Organic
Chemicals Manufacturing Point Source Category," U.S. Environmental Pro-
tection Agency, EPA-440/l-74-009-a, April 1974
94
-------
TABLE D-2
BASE CASE ETHYLENE PRODUCTION UNIT
ESTIMATED WASTEWATER FLOW RATES
Basis: • 1.1 billion pounds of ethylene product per year
• 340 days operation per year
Wastewater Stream
Decoking Scrubber Effluent
Dilution Steam Slowdown
High Pressure Steam Slowdown
Acid Gas Scrubber Effluent
Total Wastewater Flow Rate
Source: Arthur D. Little, Inc. estimates.
TABLE D-3
BASE CASE COMPLEX
WASTE LOAD CONTRIBUTIONS FROM PRODUCTION UNITS
Estimated Flow Rate
(gpd)
224,000
15,700
79,400
2,200
321,300
Product
Production
(106 Ib/yr)
Ethylene 1,100
LDPE 640
Ethylene Glycol 550
Polypropylene 140
I
Total
Wastewater Flow Rate
(gpd)
321,000
4,000,000
1,150,000
420,000
BODj. Load
(11> /day)
1,290
8,250
1,370
2,100
5,891,000
13,000
Source: Arthur D. Little, Inc. estimates.
95
-------
• BPCTCA - Best Practicable Control Technology currently Available
(to be implemented by 1977)
• BATEA - Best Available Technology Economically Achievable (to be
implemented by 1983)
• Standards of Performance for New Sources (applicable to new plants
built between 1977 and 1983; after 1983 the BATEA level applies).
It has been deemed necessary to set specific regulations for the
following pollutional parameters:
• 5-day biochemical oxygen demand (BODr)
• Chemical oxygen demand (COD)
• Total suspended solids (TSS)
• pH.
The effluent limitations, as published in the Federal Register (40 CFR 414 ER
April 25, 1974), are given in terms of the weight of the specific pollutant
per unit weight of production (Table D-4).
c. Recommended Wastewater Treatment Technology
To achieve the effluent levels stipulated in the effluent guidelines,
a variety of wastewater treatment steps have been recommended in the
Development Document. The recommended technology is based both on the
current use of such technology within the Organic Chemicals Industry and on
pilot plant treatability data.
The BPCTCA treatment level has limitations on BOD5 and suspended
solids. The most widespread method of removing BOD5 from industrial waste-
water is conventional biological treatment, in which microorganisms under
controlled conditions utilize the biodegradable organic material in the
wastewater as a food source. The Development Document recommends the
activated sludge variation of biological treatment and suggests the following
sequence of treatment steps:
(1) equalization
(2) neutralization
(3) aeration (with sludge recycle)
(4) final clarification
(5) sludge thickening
(6) sludge dewatering.
96
-------
TABLE D-4
EFFLUENT LIMITATION REQUIREMENTS
(pounds per 1000 pounds of product)
Effluent
Characteristics
Maximum
for Any 1 Day
Avg of Daily Values
for 30 Consecutive
Days Shall Not Exceed
BPCTCA Treatment Level (1977)
BOD5
TSS
PH
BATEA Treatment Level
0.13 0.058
0.20 0.088
within the range 6.0 to 9.0
COD
BOD5
TSS
PH
Standards of Performance for New Sources
0.80 0.58
0.044 0.024
0.066 0.040
within the range 6.0 to 9.0
BQD5
TSS
PH
Ref: 40 CFR 414 ER April 25, 1974
0.11
0.10
0.048
0.44
within the range 6.0 to 9.0
Based on typical raw waste loadings and the required BPCTCA BODg limitations,
the recommended biological treatment must have a BOD5 removal efficiency of
approximately 85%. Properly designed, well operated biological treatment
systems are often capable of 85% and even greater removal efficiencies.
Suspended solids are removed in the final clarification step.
The BATEA treatment level has limitations on COD, BODs, and suspended
solids. COD present in the wastewater results from both biodegradable and
non-biodegradable organic matter and from certain inorganic compounds such
as sulfides. While the biological treatment recommended for the BPCTCA
level is capable of removing biodegradable organic matter, it cannot remove
non-biodegradable organic matter. For this reason, activated carbon
adsorption has been recommended for the attainment of the more stringent
BATEA effluent limitations. The activated carbon adsorption system is
installed downstream of the biological treatment system and consists of:
I
• sand filtration (to prevent carbon fouling)
• carbon adsorption system
• carbon regeneration system.
Based on the BOD5 and COD levels in the raw waste load, the overall treatment
system (biological plus carbon adsorption) must be capable of achieving a
94% BOD removal and a 64% COD removal. These treatment levels are currently
being achieved by many wastewater treatment facilities in a variety of
97
-------
industries. While there is no reason to believe that these efficiencies
cannot be achieved in the olefin industry, no commercial activated carbon
absorption facilities are in use and some question does exist, both for
technical and economic achievability.
Wastewaters from the companion production units (polyethylene, ethylene
glycol and polyproylene) have characteristics not unlike the wastewater
from ethylene production; therefore, the same type of BPCTCA and BATEA
treatment can be applied to these units. In actuality, a complex composed
of the production units included in the base case complex would combine all
of the contaminated wastewater streams into a single stream and treat it in
one large wastewater treatment facility consisting of the previously
described biological plus carbon adsorption steps.
d. Wastewater Treatment Costs
The situation in which all of the production units within the complex
share a common wastewater treatment facility results in major economies of
scale regarding wastewater treatment costs. If a separate treatment facility
were provided for each of the production units, the overall cost would be
much higher.
To determine the wastewater treatment costs for the ethylene production
unit, we used the following procedure:
(1) Using commonly accepted industrial wastewater treatment design
practices, we sized the major pieces of wastewater treatment
equipment on the basis of the total complex waste load.
(2) We then developed capital and operating costs for the entire
complex wastewater treatment facility.
(3) An allocation method, based on a combination of wastewater flow
rate contribution and BODtj contribution, was applied to the total
complex capital and operating costs so as to assign to the
ethylene production unit its fair share of the total wastewater
treatment cost. Typically, hydraulic flowrate contribution is
responsible for approximately 67% of the total treatment costs,
while BOD5 contribution is responsible for the remainder. The
cost allocation factor was thus weighted to take these effects
into consideration.
In this way, treatment costs attributable to the ethylene production unit
were established. Costs were developed for the BPCTCA treatment level, the
BATEA treatment level incremental to BPCTCA and for full implementation
through BATEA.
The cost estimating basis and the major items included in the waste-;
water treatment facility are listed in Table D-5. The cost estimates for
the entire complex wastewater treatment facility are shown in Table D-6; the
wastewater treatment cost estimates allocated to ethylene production are
shown in Table D-7.
98
-------
TABLE D-5
WASTEWATER TREATMENT COST BASIS AND MAJOR
CAPITAL EQUIPMENT ITEMS INCLUDED IN TREATMENT FACILITY
Cost Basis
• All capital costs adjusted to March 1975 level (ENR Construction Cost
Index = 2126)
• Depreciation taken at 11 years straight-line (9.1% per year)
• Return on investment @ 20% of capital investment for effluent control systems
• Taxes and insurance @ 2% of capital investment
• Operating labor @ $7.89/hr plus 100% for overhead
• Total maintenance cost (labor, materials, etc.) @ 4% of capital
investment
• Fuel @ $1.87/106Btu
• Electricity @ $0.0136/kWh
• Sulfuric acid @ $47.67/ton (66°Be)
• Coagulant acid @ $0.50/lb
• Replacement activated carbon @ $0.45/lb
• Sludge disposal @ $5.00 per actual wet ton (20% solids)
Major Capital Equipment Items
BPCTCA Treatment Level BATEA Treatment Level
• Lift station • Mixed media filters
• Equalization basin • Carbon contactor columns
• Mixers • Carbon regeneration furnace
• Neutralization basin
• Aeration basin
• Fixed mounted aerator
• Secondary clarifiers
• Polymer feed system
• Sludge recycle
• Sludge thickener
• Vacuum filter
• Flow measurement
• Control building
Source: Arthur D. Little, Inc. estimates.
99
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TABLE D-6
BASE CASE ETHYLENE PRODUCTION FROM ETHANE-PROPANE
WASTEWATER TREATMENT COSTS FOR ENTIRE COMPLEX
o
o
Capital Investment
Indirect Costs
Depreciation @ 9.1%
Return on Investment @ 20%
Taxes & Insurance @ 2%
Total Indirect Cost
Direct Operating Costs
Operating Labor (including overhead)
Maintenance Labor & Supplies
Chemicals
Energy
Sludge Disposal
Total Direct Operating Cost
Total Annual Cost
BPCTCA*
Treatment Level
$10,344,000
941,300
2,068,800
206,900
$ 3,217,000
BATEA**
Treatment Level
$3,525,000
320,800
705,000
70,500
$1,096,300
Full Implementation
(BPCTCA & BATEA)
$13,869,000
1,262,100
2,773,800
277,400
$4,313,300
$
$
170,400
413,800
449,400
205,000
42,500
1,281,100
4,498,100
110,000
141,000
397,800
119,800
nil
$ 768,600
$1,864,900
280,400
554,800
847,200
324,800
42,500
$2,049,700
$6,362,000
Cost Per Volume Treated ($/1000 gal)
$2.25
$0.93
* BPCTCA - Best Practicable Control Technology Currently Available (1977)
** BATEA - Best Available Technology Economically Achievable (1983)
$3.18
Source: Arthur D. Little, Inc. estimates.
-------
TABLE D-7
BASE CASE ETHYLENE PRODUCTION FROM ETHANE-PROPANE
WASTEWATER TREATMENT COSTS ALLOCATED TO ETHYLENE PRODUCTION
(Basis: 1.1 billion pounds of ethylene production per year)
Capital Investment
Indirect Cos ts
Depreciation @ 9.1%
Return on Investment @ 20%
Taxes & Insurance @ 2%
Total Indirect Cost
Direct Operating Costs
Operating Labor (including overhead)
Maintenance Labor & Supplies
Chemicals
Energy.
Sludge Disposal
Total Direct Operating Cost
Total Annual Cost
BPCTCA*
Treatment Level
$714,000
65,000
142,800
14,300
$222,100
BATEA**
Treatment Level
$243,000
22,100
48,600
4,900
$ 75,600
Full Implementation
(BPCTCA & BATEA)
$957,000
87,100
191,400
19.200
$297,700
11,800
28,600
44,300
14,100
4,200
$103,000
$325,100
34,000
9,700
39,500
11,900
nil
$ 95,100
$170,700
45,800
38,300
83,800
26,000
4,200
$198,100
$495,800
Unit Cost ($/ton ethylene)
$0.59
$0.31
* BPCTCA - Best Practicable Control Technology Currently Available (1977)
** BATEA - Best Available Technology Economically Achievable (1983)
$0.90
Source: Arthur D. Little, Inc. estimates.
-------
2. AIR-RELATED ENVIRONMENTAL PROBLEMS
The sources, control technology, and cost of control of air pollution
emissions are described in the following subsection. In compiling the infor-
mation, we have relied upon information in our own files, interviews with
both designers and operators of ethylene plants, and a recently published
EPA report, Survey Reports on Atmospheric Emissions from Petrochemical
Industry, Vol. II, EPA Report No. 68-02-0255, by Air Products and Chemicals
Company, Inc., April 1974.
a. Sulfur Emissions
As a basis for our calculations, we have assumed a feedstock with a
sulfur concentration of 10 ppm, which we believe to be higher than is
typical of most ethane and propane feeds to existing ethylene plants. During
the ethylene cracking process, sulfur is produced in the form of H2S and COS.
These gases and C02 (the acid gases) are removed from the compressed cracked
gases by a caustic (sodium hydroxide) scrubber. (Figure D-2). The liquid
effluent from the caustic scrubber is contacted with naphtha to absorb
entrained hydrocarbons. The naphtha solution is decanted and then used as
a fuel. The water effluent from the naphtha wash is neutralized with
sulfuric acid, resulting in the following effects:
• Sulfides, such as Na£S or NaHS, are replaced by Na2SO^'— we have
assumed that this sulfate can be discharged from the plant as
dissolved solids in water effluents unless local conditions
prohibit.
• The acid gases are regenerated and must be incinerated to convert
H^S to S02 before venting to the atmosphere.
In our opinion, sulfur controls will not be required on the regenerated
acid gas exhaust ; our reasoning is as follows :
• In the base line case, we have assumed a feed sulfur concentration
of 10 ppm in E-P, which results in a sulfur exhaust of about
4 Ib/hr expressed as SO ;
• One of the strictest sulfur emission standards in the United States,
that of Los Angeles County, requires control on tail gas streams
whenever the sulfur rate exceeds 10 Ib/hr expressed as SO ;
• The base line case could, therefore, even meet the Los Angeles
standards without additional sulfur controls;
• Since we believe that feeds to E-P crackers will rarely contain
more than 10 ppm of sulfur, and since this is an acceptable
uncontrolled emission even in Los Angeles, it is our judgment that
sulfur controls will not be required on any E-P plant.
i
However, the exhaust will require flaring to convert H2S to S02 to prevent
serious odor problems or to prevent possible exposure to more hazardous
hydrogen sulfide.
1 102
-------
Pyrolysis
Gases
f- NaOH Fresh Naphtha
To Plant
Fuel Gas System
To Water Treatment
Naphtha to Oil/Water
Separator
Figure D-2. Acid Gas Removal System (Ethane-Propane Feedstock)
-------
The only other sulfur emission from an E-P cracker occurs during the
decoking operation. The quantities of sulfur are insignificant and would
not require controls.
b. Particulates
The only major potential source of particulate emissions in an ethylene
plant is the intermittent decoking of process furnaces. High-temperature
steam is used to react with or otherwise loosen and remove coke from the
furnace coils. Since a typical decoking cycle lasts for only 16 hours, even
the largest plants should be easily served by a single operating decoking
scrubber system. In such a control system (Figure D-3) a spray tower is
used to condense the steam and scrub out the particulates. The decoker
effluent enters the spray tower where it is contacted with cooling water
circulating at a high rate. The particulates are suspended in the water
phase and are discharged to the water treatment plant where they are
eventually combined with the wastewater treatment sludge.. The gaseous
exhaust from the decoking system contains carbon monoxide, hydrogen, traces
of H^S, residual coke particles, and steam. These are introduced to the
Decoke
Effluent'
650F
Q
A A A
A A A
-85F
130F
Case
Component
H2
CO
co2
H2S
S02
H2O
Total, Kg/hr
gpm
Steam/Air
Steam Only
1827
280
381
3.5
24,000
26,491.5
1
11
143
696,190
696,190
1,390
1827
280
381
3.5
88
2580.5
24,000
24,156
3
11
143
690,722
690,722
1,380
11
167
Source: Arthur D. Little, Inc. estimates.
Figure D-3. Decoke Spray Drum
104
-------
firing side of the process furnaces where the combustibles are completely
burned before being exhausted to the atmosphere with the other process heater
combustion products. We have estimated conditions for the decoking system as
shown in Table D-8.
To maintain a high degree of reliability, we have assumed the installa-
tion of two scrubber systems. The resulting operating costs are approximately
$55,900/yr or approximately 5C/1000 lb of ethylene (Table D-9).
A second source of particulate and tar emissions is the intermittent
regeneration of the acetylene converter. This operation is similar to furnace
decoking in that steam or air is used to burn out residual oil and carbon
deposits from the converter. The exhaust contains hydrocarbons, soot, CO,
and tar but no sulfur. The regeneration is accomplished once or twice a year
and takes approximately 48 hours. The effluent from the converter regenera-
tion operation is approximately the same magnitude as that from furnace
decoking; therefore, the same scrubber control system can be used to control
emissions for both operations. Based upon the costs shown in Table D-3, this
operation would increase the total scrubber operating cost by about $250
per year per converter.
c. Hydrocarbons
The residue gas produced during ethylene manufacturing contains hydro-
gen, methane, and some carbon monoxide. The rate of emission depends upon
the feedstock and the details of the process. Several states specify that
this waste gas stream must be burned at 1,300°F for a minimum of 0.3 second.
Since a conventional process furnace meets this criterion, the gas is
typically used as process fuel without requiring further controls.
In typical ethylene plant there are also several major fugitive
emission sources which must be considered, such as:
• Compressor, valve, and pump seals;
• Emergency venting and startup;
• Periodic maintenance operations requiring the flushing of heat
exchangers, pipes, and so on;
• Miscellaneous leaks and spills.
i
Control of these requires sound initial design practices and good maintenance.
For example, during initial design and maintenance emergency startup, the
vented exhaust from process vessels can be piped to the plant flare. This
is standard practice throughout the industry. But operators are also keenly
aware of other fugitive emissions because of the characteristically sweet
105
-------
TABLE D-8
DESIGN CONSIDERATIONS FOR DECOKING CONTROL SYSTEM
Cooling Water Requirement 1,400 gpm
Recirculation Rate (max.) 4,200 gpm
Decoking Drum Specifications
Diameter 5 ft
Height 12 ft
Baffles 3
Pump Specifications
Rating 5,600 gpm @ 50 ft
Drive 90 HP motor
Source: Arthur D. Little, Inc. estimates.
TABLE D-9
DECOKING SCRUBBER SYSTEM COSTS
(Basis: 1.1-billion-lb/yr ethylene plant)
Capital Cost, $ 142,000
Operating Cost, $
Indirect Operating Costs
Depreciation (11 years) 12,900
Return on Investment @ 20% of Capital Cost 28,400
Insurance & Taxes @ 2% of Capital Cost 2,800
Total Indirect Costs 44,100
Direct Operating Costs
Labor nil
Utilities
Electric Power, 68 kWh/hr @ $0.0136/kWh 800
Cooling Water, 85,00 gal/hr
-------
odor of ethylene. To avoid this odor, operators have attempted to control
as many other fugitive emission sources as possible by using good operating
practice and smokeless flares throughout the plant. Likewise, the industry
currently uses mechanical seals on pumps and compressors to reduce the
fugitive emissions characteristic of this type of equipment. However, the
number of small fugitive sources associated with periodic maintenance or
with miscellaneous leaks and spills is quite large so that control of all
of these sources would be prohibitively expensive.
3. SOLID WASTE-RELATED ENVIRONMENTAL PROBLEMS
The major sources of solid wastes are as follows:
Source Amount (Ib/hr)
Wastewater sludge (from petrochemical complex 1875
excluding olefin plant)
Wastewater sludge (from ethylene plant) 205
Spent desiccants 10
Total 2090
By far, the greatest solid waste problem is the wastewater sludge which
may be placed in approved sanitary landfills.
The cost for solid waste disposal is estimated to be $5/ton of actual
waste or approximately $4,300 for the ethylene plant plus $38,300 for the
rest of the petrochemical complex.
4. OTHER PROBLEMS RELATING TO THE ENVIRONMENT
One of the characteristics of ethylene manufacture discussed earlier
is the characteristic odor of ethylene—a sweet odor, which, if present in
significant concentration, could attract a substantial number of complaints
from nearby residents. The current industry practice is to use sound
operating procedures and employ smokeless flares on gaseous hydrocarbon
waste and vent streams whenever practical. In the survey report cited
previously, operators reported that these measures were sufficient to
eliminate plant odor problems.
107
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APPENDIX E
ADVANCED OLEFIN PROCESS ALTERNATIVES
Several alternative processes for producing olefins and acetylene are
either being commercially attempted or are currently in the development
stage with the expectation of commercializing the technology in the 1980-
1985 time frame. For example, consideration is being given to extending
conventional pyrolysis technology to the cracking of vacuum gas oil (VGO).
Successful operation with commercial scale equipment has been reported by
Exxon Chemie at Port Jerome, France. Advanced processes for which the
technology is being developed include:
Tubular cracking of vacuum gas oil (Exxon)
Autothermic cracking of crude oil (Union Carbide/Kureha)
Fluid bed cracking of vacuum resid (AIST)
Hydrogen pressure cracking (Auby/Naphtachemie)
Plasma pyrolysis of coal (AVCO)
In addition, byproduct ethylene is produced by the U.S. Steel's Clean Coke
Process and commercialization of this process would provide a potential
source of supplemental ethylene.
Although these technologies are expected to be commercially proven
within five years, wide application will depend on the process economics,
which are greatly influenced by price differences among alternative feed-
stocks. Consequently, these processes were ranked lower in priority than
cracking of naphtha and atmospheric gas oil in conventional pyrolysis
furnaces for ethylene production. However, process descriptions are pro-
vided herein for each process listed above. In addition, the energy
conserving potential and pollution implications are qualitatively assessed
and for those cases where process operating requirements are available,
typical economics are presented.
108
-------
1. PETROLEUM-BASED TECHNOLOGIES
a. Vacuum Gas Oil Cracking with Conventional Technology
In the current search for olefin plant feedstocks, VGO has received
serious consideration in connection with conventional tubular cracking
technology. However, extending present atmospheric gas oil cracking tech-
nology to VGO magnifies the furnace coil coking and sulfur removal problems.
(1) Process Description
In the front-end cracking and quench sections of Exxon Chemie's Port
Jerome VGO cracker (Figure E-l) the furnace effluent is cooled by a direct
oil quench and then scrubbed to remove coke particles before entering the
primary fractionator. Furthermore, the effluent from the on-line steam
decoking of the cracking furnace is discharged through the process; hence
decoking can be accomplished without isolating the furnaces or cracking
coils. The flow plan of the back end of the plant (Figure E-2) conforms to
conventional designs with a front-end depropanizer.
Feedstock properties and corresponding furnace yield patterns for a
light naphtha and a vacuum gas oil are shown in Tables E-l and E-2. The
once-through ethylene yield from VGO is only half the yield from a light
naphtha. While the yield of pyrolysis gasoline is essentially the same in
both cases, there is a considerable reduction in quantity of C. and lighter
hydrocarbon in deference to heavy cracked oil in the case of VGO. The sul-
fur content of this pyrolysis fuel oil is shown in Table E-3 for undesulfur-
ized VGO feed. Since the feed sulfur in VGO is thiophenic, it tends to
concentrate in the heavy pyrolysis fuel oil product. Pyrolysis fuel oil
sulfur contents of 3-5% are produced from VGO cracking. Clearly, this
sulfur level is unacceptable for domestic 'consumption. Since the pyrolysis
fuel oil represents a significant portion of the feed and product yield, a
method of desulfurizing the fuel is required in order to consume the fuel
internally.
Coil cracking of VGO results in rapid coke deposition on the walls of
the furnace coils. For example, furnace run lengths with atmospheric gas
oil are generally 30 days or less; however, with VGO, furnace run lengths
for certain gas oils may be only seven days.
Because of the severe coil coking encountered with VGO cracking, Exxon
Chemical developed a patented decoking technique which allows coke to be
removed from one or more furnace coils at a time while the remaining coils
of the same furnace continue in service cracking feed at normal rates.
Operating in this fashion, a furnace can be kept onstream for longer than
six months before a complete overhaul is required. Run lengths between
onstream decokings are 7-20 days. The procedure is to cut the feed out of
10% of the furnace coils and adjust steam flow to control coil temperatures.
The steam decoking effluent is combined with the process effluent and sent
to the quench and scrubbing tower before going to the primary fractionator.
109
-------
Scrubbet
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B?yf \
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pci
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i
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-^2^n
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Product
Soutce: Exxon. Pfoceedings Ninih World Peuoleum Congreis (Tokyo 19751 Vol. 5, Pg 123
Figure E-l. Front-End Flow Plan
Demethamzer De-ethanizer
Source: Exxon. Proceedings Ninth World Petroleum Congress (Tokyo 1975), Vol. 5. Pg. 123.
Figure E-2. Back-End Simplified Flow Plan
110
-------
TABLE E-l
FEED CHARACTERISTICS
Light Virgin Vacuum
Naphthas Gas Oil
Crude source Light Arabian Kuwait
Specific gravity 0.660 0.904
Sulfur (% w) 0.01 1.9
Hydrogen (% w) 16.1 12.4
Mol. wt. 80 339
ASTM dist. (°C)
Initial 43 370
10% 54 380
50% 62 410
90% 72 455
Final 84 470
Hydrocarbon type (% w)
Paraffins 89 19
Naphthenes , 9 35
Aromatics 2 46
Source: Exxon, Proceedings Ninth World Petroleum Congress (Tokyo 1975) Vol.5
TABLE E-2
FURNACE OUTLET YIELDS
(% w)
Light Virgin Vacuum
Napthas Gas Oil
Hydrogen 1.0 0.4
Methane 16.7 9.1
Acetylene 0.6 0.2
Ethylene 31.3 16.6
Ethane 4.. 3 4.4
Co and CA acetylenes 1.1 0.5
Propylene ' 16.2 13.3
Propane 0.5 1.0
Butadienes 4.7 4.1
Isobutene 2.1 1.9
n-Butenes 1«9 3.2
Butanes °-2 O-1
C, and Lighter S Compounds — 0.6
Steam cracked naphtha (C5 to 190°C) 17.9 17.3
Heavy cracked oil (190°C +) 1.5 27.3
Total 100.0 100.0
Source: Exxon, Proceedings Ninth World Petroleum Congress (Tokyo 1975) Vol.5
111
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TABLE E-3
PROPERTIES OF HEAVY CRACKED OIL
LVN VGO
Specific Gravity 1.08 1.11
Sulfur (wt %) 0.08 5.0
Viscosity @ 210°F (SUS) 10 300
Percent of Feed Sulfur in Heavy 12 72
Cracked Oil
Source: Exxon, Proceedings Ninth World Petroleum Congress (Tokyo
1975), Vol. 5.
(2) Energy Conserving Potential
As with almost all the other options for this industry, the energy-
conserving potential for coil cracking of VGO is solely one of form value
credits; i.e., substitution of VGO for atmospheric gas oil or lighter feed-
stock. The characteristic energy consumption versus that of alternative
feedstocks is as follows:
Energy Cons. Btu/lb net Prod. Energy Index
Ib feed/ product/ ' Fuel Total Btu/lb
Feed Ib C,,H, Ib C^H, Feedstock Utilities Credit net product
E-P
Naphtha
AGO
VGO
f- "t
1.56
3.05
4.03
4.95
i. H
1.23
2.26
3.02
3.20
27,670
26,950
26,090
28,600
13,510
7,775
7,180
11,130
(7,140)
(7,285)
(6,670)
(10,500)
34,040
27,440
26,600
29,230
Source: Arthur D. Little, Inc. estimates.
The energy index is high for VGO because of low ethylene yields, high dilu-
tion steam rates, and no high-level transfer line exchanger (TLX) waste
heat recovery.
112
-------
(3) Environmental Implications^
The major environmental consideration associated with cracking VGO is
the removal of sulfur. Because it is unsaturated, heavy pyrolysis fuel it
is difficult to handle and process. Consequently, potential operating
problems discourage the desulfurization of this product. The two remaining
alternatives are to desulfurize the vacuum gas oil feed or to apply flue
gas desulfurization (FGD) to combustion sources using the resulting pyroly-
sis fuel oil. The size of the steam boilers in an olefin facility will
generally result in high cost for FGD systems. Therefore, front-end hydro-
desulfurization of the feedstock is generally considered to be the more
economical route.
Front-end desulfurization of VGO at the olefin facility also presents
difficulties, primarily in regard to the olefin plant hydrogen balance.
Using byproduct hydrogen available from the cracker, it is possible to
achieve about 80% desulfurization of the feedstock. However, the sulfur
content of the pyrolysis fuel oil may still exceed 1% by weight. Various
alternative schemes have been considered by M.J. Offens and D.A.J. Samols
(1975) European Chemical News, May 23, 1975.
As the degree of hydroprocessing is increased, the demand for hydrogen
puts a strain on the internal fuel balance of the olefin cracker. In the
extreme case involving hydrocracking, insufficient fuel is generated to
satisfy the overall fuel requirements and an external source of fuel is
required. Even to achieve 95% desulfurization will require steam reforming
of part of the methane yield. This may divert enough methane to require a
portion of the cracking furnace heat to be provided by liquid fuel.
Thus, it is apparent that while cracking of vacuum gas oil with con-
ventional tubular technology is possible, it does place a considerable
strain on operability of this technology. Some of the developmental tech-
nologies such as autothermic and fluidized bed cracking are conceptually
better able to deal with heavy feedstocks which contain high sulfur and
have a propensity to coke.
b. Autothermic Crude Cracking (Kureha/Carbide)
(1) Process Description
As noted, conventional coil cracking of heavy hydrocarbon feedstocks
such as crude oil and vacuum gas oil results in short furnace cycles due to
rapid coke buildup in the coils. To avoid the excessive coil coking and
its attendant maintenance problem, cracking processes which contact the
feed directly with a hot gaseous energy carrier have been considered
(H.K. Kempter, April 1966, Hyd. Proc.. Vol. 44. No. 4, p. 187).
113
-------
An olefin manufacturing process based on this technology is currently
being developed through the joint efforts of Kureha Chemical Industry
Company, Chiyoda Chemical Engineering and Construction, and Union Carbide
Corporation. The process is based on high-temperature thermal cracking
technology developed by Kureha for the production of acetylene and ethylene
from crude oil.
Pyrolysis is accomplished by spraying de-asphalted crude oil into a
stream of superheated steam and combustion gases which have been heated to
about 4000°F (Figure E-3). To attain the high temperatures required, the
steam is first superheated in a fired heater and then further heated by being
injected into a flame in which fuel gas is burned with oxygen. Steam is
also generated by the burning of the fuel, which is primarily methane and
hydrogen. The feedstock is injected at the orifice of the reactor, where it
quickly vaporizes and passes into the reaction chamber, where adiabatic
cracking occurs within 15 to 30 milliseconds. The reactor effluent is
rapidly cooled in a specially designed cooling system employing direct
quench and integral steam generation. The net make of heavy pitch is con-
densed in the quench system and withdrawn. The raw product stream now
passes into a high-temperature primary fractionator, where quench oil and
gasoline are separated from the product gas. The cool pyrolysis gas is
compressed and acid gases are removed by a modified diethanolamine solvent
system. The process sequence beyond this point is similar to that of a
conventional naphtha or gas oil cracker.
Oxygen
Steam
Reactor
Pyrolysis "
Gasoline Water
To Recycle
Light
Tar
Gasoline
Fractionator
Sweet Gas
To Olefms
Separation
DEA
Absorber
Compression
C02
H2S
Stripper
Pitch
Source: Chemical Engineering Progress. Vol. 71, No. 11 November 1975.
Figure E-3. Schematic Diagram of Ethylene-From-Crude Oil Process
114
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The main advantages of the process are a high yield of ethylene and
acetylene from heavy feedstocks and the capability of cracking a wide range
of feedstocks (Table E-4). This latter aspect will be of increasing impor-
tance in the future as feedstock availability and pricing becomes more
erratic. Another degree of flexibility is offered by the process because
it eliminates the need for refined petroleum products for feedstock. Heavy
liquids cracking with conventional technology is most attractive when linked
to a petroleum refinery and many such configurations were in evidence in
the last round of ethylene plants constructed. However, crude cracking can
use whole or de-asphalted crude directly, avoiding the need to tie a refin-
ery to the ethylene business. This is an important aspect for a chemical
company since refinery expansions over the next decade are expected to be
slow.
(2) Energy Conservation Potential
To assess the process in terms of energy conservation relative to con-
ventional technology, we estimated the characteristic operating parameters
for the process (Table E-5). Since an appreciable amount of acetylene is
produced with this process, quantities are presented on the basis of total
useful C2*s. The reactor outlet temperature was estimated by thermal balance
assuming the heat of cracking of 650 Btu/lb of hydrocarbon feed. The cal-
culated outlet temperature is in the range of reactor exit temperatures
reported for the Hoechst High Temperature Process.
An estimate of the utility energy (other than feed) consumed by the
process is also presented in Table E-5. The burner fuel was assumed to be
byproduct methane. Energy consumed by compressors includes energy demand
for cracked gas compression, and refrigeration for ethylene purification
plus that required for oxygen production. The heat credit for TLX steam
generation is based on cooling the reactor effluent to 700°F before it
enters the primary fractionator. To achieve this heat recovery in practice
is not easy since the residue products are very prone to forming coke at
the temperatures encountered.
In the following tabulation, we compare the total energy consumption
for the crude cracking process with the requirements for conventional
technology:
Ib Net Prod/ Total Energy Consumption Energy Index
Ib C?H& Btu/lb Ethylene Equiv. __ Btu/lb Net Product
Conventional Cracking
(E-P, AGO) 1.23-3.02 42,000 - 80,300 34,000 - 26,600
Crude Cracking 1.72 48,500 28,200
115
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TABLE E-4
YIELDS OF AUTOTHERMIC CRUDE CRACKING ETHYLENE FROM CRUDE OIL
Ethylene/Acetylene Wt Ratio ,
Residence Time, msec
Hydrogen/Methane ,
Ctt
C,H6
C as CO, CO2 and H2S
Cs's-160°F
Pyrolysis Gasoline Fraction. . . .
C9-430"F
430-650°F
650°F.+
Arabian
Light Pennsylvania
Crude Crude
7.54 15.0
15 30
11.23
4.21
31.78
1.68
2.36
6.09
0.68
2.80
0.06
4.14
1.26
4.51
5.10
16.39
7.71
..11.29
.. 2.26
..34.00
.. 2.44
.. 1.32
..12.00
.. 0.51
.. 0.65
.. 5.50
.. 2.40
.. 1.5 ...,.,
.. 3.93
.. 9.56
.. 0.63
.. 3.06
. 8.95
Arabian
Light
Distillate
8.0
15
10.05
4.01
32.11
1.99
1.98
8.39....
0.25....
0.48....
3.78
0.83
1.70
2.21
9.3fl
3.341
>
15.12f---
4.45J
Light
Naphtha
9.99
16
16.70
4.34
... .43 62 ..
3.14
1.79
11.47... .
0.37
... . 0.19 ...
3.43
1.65
1.97 .
1.52
9.81
Light
Gas Oil
.... 7.45..
.15
....11.65..
.. . 4.49..
33 55
.. . 1 83.
. . 1 83..
704
.... 0.16..
0 32
.... 3.29..
.... 0.64..
1 58
. 0 94
....32.68..
Vacuum
Gas Oil
6.48
16
10.45
4 34
28 14
1 57
2 10
5 62
0.07
0 72
3.08
0.36
3 14
1 14
39.27
Source: Chemical Engineering Progress, Vol. 71, No. 11, November 1975.
-------
TABLE E-5
UCC CRUDE CRACKING PROCESS
ESTIMATED OPERATING PARAMETERS
Reactants
Crude Oil Feed, (Ib)
Process Steam (1.5:l),(lb)
Oxygen, (Ib)
Per Pound of
Ethylene Plus Acetylene
2.54
3.81
2.06
Reactor Products,(Ib)
C02 (comb.)
H20
Pyrolysis Products
Acid Gas (yield)
1.42
4.97
2.44
0.10
Cracking Conditions
Reactor Pressure,(psia)
Burner Temperature,(°F)
Reactor Outlet, (°F)
Process Steam Inlet,(°F)
20-25
3,992
2,125
1,000
Energy Consumption
• Input, (Btu)
Burner Fuel
Compressors
Process Steam11
Electric Power
• Credit, Btu
TLX Steam Generation
11,100
10,740
2,580
1,500
(7,915)
Total Consumed,(Btu)
18,005
Ethylene recovery and oxygen plant.
2
Superheat only; assumes latent heat supplied by waste heat.
Sources: Chemical Engineering Progress, Vol. 71, No. 11 (1975) and
Arthur D. Little, Inc. estimates.
117
-------
As indicated, there is no significant energy savings associated with
the crude cracking process. However, in terms of form value savings, the
process would save distillate products in place of de-asphalted crude but
not one-to-one since the de-asphalted crude contains about 30% naphtha.
(3) Environmental Implications
Acid gas removal from the raw pyrolysis effluent becomes a significant
process consideration due to the possible high sulfur content of the feed,
residual nitrogen in the oxygen, and CO- produced in the submerged burner.
Caustic scrubbing is unacceptable due to unfavorable economics and the large
quantity of waste caustic that would be produced. Amine solvent systems
have a history of operating problems due to the polymerization of butadiene
contained in the raw pyrolysis gas. To avoid plugging of the system, the
polymer must be continuously removed, which presents a disposal problem.
The developers of the crude cracking process have made certain modifications
to the standard diethanolamine scrubbing system which they claim avoid this
operating problem. Details regarding the exact changes are proprietary.
The concentrated acid gas (containing hydrogen sulfide) leaving the dietha-
nolamine solution regeneration system is treated in a conventional Claus
reduction plant for elemental sulfur recovery. In general, the pollution
problems associated with crude oil cracking are the same as for gas oil
cracking except that the problems associated with sulfur removal can be
significantly increased due to the need of desulfurizing the pyrolysis fuel
oil.
c. Fluid Bed Cracking of Petroleum Residues
Fluidized bed technology is another approach which has beer applied to
the production of olefins with varying degrees of commercial success. One
of the oldest known processes of this type is the Lurgi Ruhrgas Process,*
which has been applied to ethylene production. BASF has also developed
technology for a single fluid bed configuration which used oxygen for com-
bustion of coke inside the bed. In general, commercial plants based on this
technology has been characterized by a history of operating problems. Coupled
with heretofore unfavorable economics, these have kept the technology from
widespread use.
The Japanese Agency of Industrial Science and Technology (AIST)** is
now sponsoring a five-year research program to develop a process for the
production of olefins from vacuum residues which utilizes fluidized bed
reactors. Design and construction of a 120 ton/day pilot plant is scheduled
for completion for the first half of 1978, with test operations from then
until the end of 1979.
*Kirk-Othmer Encyclopedia of Chemical Technical, Vol. 8, pp. 507, second Ed.
**European Chemical News, October 1975, p. 38. '
118
-------
(1) Process Description
The process employs a twin fluidized-bed reactor system (Figure E-4).
The thermal cracking of heavy oils is accomplished in a fluidized bed of
coke particles. After providing the heat for cracking, the coke is trans-
ferred to the regenerator where a portion of the coke is burned with air
to reheat the fluid bed before it is returned to the reaction vessel. The
cracking reactor operates at 1290-1560°F and the coke regenerator at 1470-
1700°F; both units are operated under atmospheric pressure conditions.
Emphasis will be on the cracking of vacuum residues as a result of the
encouraging published yields obtained with the 5 ton/day pilot plant (Tables
E-6 and E-7). About 30% of the feedstock is consumed as fuel or lost as
acid gas (such as hydrogen sulfide). Principal olefin yields represent
only 23-25% of the feed for vacuum resid as compared with 50% for naphtha
cracking.
(2) Energy Conserving Potential
The published information* on the AIST-sponsored process indicates that
about 27-29% of the feed is consumed as fuel by the cracker ("cracker" in
this context refers to,the reactor and coke heater). This corresponds to
33,700 Btu/lb ethylene product. It is assumed that energy for gas compres-
sion and refrigeration is required in addition to this amount. An estimate
of the total energy requirement compared with E-P and VGO coil cracking
follows:
Technology
Coil Cracking
Coil Cracking
Fluid Bed
Feed
Ib Feed/
Ib CoH/,
E-P 1.56
VGO 4.95
Vac. Resid 6.17
Ib Net
Product/
Ib CoH/.
1.23
3.2
4.46
Total Energy
Consumption
(Btu/lb C2H4)
42,100
93,540
105,250
Energy Index
(Btu/lb Net
Product)
34,000
29,230
23,600
Allowing for information gaps in the fluid bed data, the energy index is
about the same as for VGO cracking. However, the conversion of vacuum resid
to useful chemicals represents a significant upgrading of a low valued
petroleum product, which could be substituted for naphtha or gas oils. Hence,
a desirable form value benefit is possible.
*Proceedings, Ninth World Petroleum Congress (Tokyo 1975), Vol. 5.
119
-------
Flue Gas
Cracked Gas
Feed Oil
Heavy Fraction
of Cracked Oil
Steam
Regenerator Cracking Reactor
Source: Proceedings Ninth World Petroleum Congress (Tokyo 1975) Vol. 5.
Figure E-4.
Circulation System for Cracking of Heavy Oil
in Fluidized Bed Reactor
120
-------
TABLE E-6
PROPERTIES OF OIL USED IN TEST OPERATIONS
Feed oil
Specific weight
(15/4CC)
Water (%v)
Sulphur (%w)
Residual carbon
( °'o W)
Salt (ppm)
Distillation test*
Aruhian
Unlit
crude
0-856
0-2
1-77
3-99
30-8
Klui/ii
crude
0-S86
0-05
2-94
8-55
35-2
I'uciiiiin residue
from Kliafji crude
1-03(25 C)
5-5
24-5
IBP
5 %v
10 %v
15 %v
20 %v
25 %v
30 %v
35 %v
40 %v
27
78
110
138
163
185
211
237
261
25
85
121
152
183
216
247
Inflammable point 316°C
Softening point 47°C
* ASTM.
Source: Proceedings Ninth World Petroleum Congress
(Tokyo 1975), Vol. 5
TABLE E-7
MATERIAL BALANCE FOR AN ETHYLENE CENTER WITH
CAPACITY OF 300,000 TONS ETHYLENE PER YEAR
Heavy Oil Fluid Bed Cracker
Feed oil
(cracking temperature) —
Feed
Product
Dry gas
Ethane fraction
Ethylene
Propylene
Propane fraction
BB fraction
Gasoline
Kerosene
Coke
Total
Arabian light
crude
(750=C)
(,,,,^'ycar)
1471000
211000
64000
303000
152000
0
76000
191000
154000
0
1152000
Source: Proceedings Ninth
(%»•)
100-0
14-4
4-4
, 20-6
' 10-3
0-0
5-2
13-0
10-5
0-0
78-4
World
Khafji crude
(750 C)
(tonsjyear) (
1655000
233000
72000
302000
152000
4000
78000
186000
231000
0
1259000
Vacuum residue from
%•")
1 00-0
14-1
4-3
18-3
9-2
0-2
4-7
11-3
14-0
o-o
76-1
Petroleum Congress (Tokyo
(750°C)
(ton.il year)
2172000
236000
62000
302000
152000
2000
86000
220000
245000
279000
15S4000
1975), Vol.
Khafji crude
(»;,»•)
100-0
10-9
2-9
13-9
7-0
0-1
4-0
10-1
11-3
12-8
73-0
5
121
-------
(3) Environmental Implications
The significant changes in pollutant emissions will be associated only
with the cracking portion of the process. Depending on the crude source,
vacuum residues will generally have sulfur concentrations greater than 1%.
This sulfur ultimately ends up either in the raw pyrolysis gas or coke
regenerator off-gas. The sulfur in the raw pyrolysis gas must be removed
to meet product specifications and this will be accomplished presumably by
an amine solvent system. The sulfur in the coke regenerator off-gas (air
blown) will be in the form of sulfur dioxide and will require control to
meet air pollution regulations. In addition, coke particulates and NO may
be present in the stream since the regeneration is done at high temperatures
with nitrogen (from the air) present. Flue gas desulfurization will ade-
quately remove SO and particulates; however, for NO emissions, no adequate
control technology has been demonstrated.
d. Hydropyrolysis
Another modification of conventional coil cracking technology that is
under development is hydropyrolysis or cracking under a hydrogen atmosphere
rather than a steam atmosphere. Pilot plant testing of this process is
being undertaken by three French companies: Pierrefitte Auby, Naphtachimie
and Heurtey. A 3-ton/day pilot plant is being built at Naphtachimie's
Lavera complex.
(1) Process Description
The process employs basic hydrocracking technology except that no cat-
alyst is used, the temperatures are higher, and residence times shorter.
Feedstock is brought into contact with hydrogen in the reactor at a temper-
ature between 1470°F and 1650°F. Operating pressure is 10 to 30 atmospheres.
Process advantages include improvement in ethylene yield (reportedly
as much as 30% for naphtha) and a reduced cracked gas compression ratio.
However, potential energy savings are offset by the large hydrogen recycle
required. This latter aspect is seen by many as a major disadvantage to
commercial scale application, since large quantities of hydrogen gas per
unit of product must be recovered and recycled. Both Lummus and KTI are of
the opinion that the process is uneconomical because of high hydrogen
separation costs.
(2) Energy Conservation Potential
The French developers claim that considerable energy savings are pos-
sible with the process. They have conducted experiments with naphtha that
supposedly confirm energy savings of 10-15% over that required for conven-
tional steam crackers. Test results from the new pilot plant are being
obtained to confirm this advantage.
122
-------
(3) Environmental Implications
Because of the increased amount of hydrogen gas being processed,
fugitive emissions are likely to increase. Otherwise, the pollution pro-
file for the process would be similar to that of conventional steam crackers.
2. COAL-BASED TECHNOLOGIES
Two coal-based technologies, one which produces acetylene, an olefin
substitute, and the other ethylene as a byproduct are discussed in this
section.
a. AVCO Arc-Coal Process
The Arc-Coal Process is a coal-based acetylene process which employs
a plasma arc to pyrolyze the coal (Figure E-5).
(1) Process Description
Coal is unloaded at the power plant facility and distributed onto the
coal storage pile. The run-of-mine coal is crushed, pulverized, and dried
to 2% moisture and then pneumatically conveyed into the storage bins. The
pulverized coal is pneumatically conveyed from storage to the coal weigh
hoppers, which feed the reactor system. A screw feeder is used to convey
the pulverized coal into the reactor. The reactor is a water-jacketed
vessel containing a rotating electric arc through which the coal must pass.
The conversion reaction takes place in the arc at approximately 3900°F and
6.5 psia. The hot gas leaving the arc is immediately quenched with
recycled gas, cooling the mixture to 850°F to prevent decomposition of the
acetylene formed. Quench gas has the same dry composition as the gas that
leaves the arc. The reactor gas effluent passes through the char cyclone
separator where the char is removed. The gas, together with the gas from
the other char separators, flows through the waste heat recovery boiler.
The temperature of the gas is reduced to 365°F and steam at both 160 psig
•and 50 psig is generated from the recovered heat. The cooled gas then
flows to the carbon black bag filters, where the carbon black particles
are separated from the gas.
The gas is then cooled to 160°F in a fin-fan gas cooler. The cooled
gas is then compressed to 9.5 psia by gas compressor No. 1, further cooled
and the flow split, with half going back to the reactors as quench gas.
Before introduction into the reactor, the quench gas is dried to 0.6%
moisture (by volume) in the quench gas dryers. The remainder of the gas
is compressed to 36 psia in gas compressor No. 2 and cooled; then it flows to
the acid gas absorber.
Char removed by the char cyclones at 850°F is pneumatically conveyed
by an inert gas stream to the char cooler. The cool char stream leaving
the cooler flows to the cool char separator where the char is separated
123
-------
N>
Coal
Source: Review and Evaluation of 300" 106 Ib/yr Acetylene Plant
Avco Arc-Coal Process, OCR Content No. 14-32-0001-1215 R&D Dept.
no. 67
Nov. 30, 1971
Carbon Black
CO Rich Product
Figure E-5. AVCO Arc-Coal Process Schematic
-------
out of the inert gas. CO-rich fuel gas is combined with the t^-rich fuel
gas to provide a pneumatic system for conveying the char from the char
separator to the power plant.
Carbon black produced by the process is collected by bag filters and
fed into the carbon black airveying system, which cools and delivers it to
the carbon black pelletizing plant.
The compressed and cooled process gas enters the acid gas absorber at
about 115°F, where hydrogen cyanide, carbon disulfide, and carbon dioxide
are absorbed in a 6 to 7% solution of soda ash in water. The absorber off-
gas, virtually free of acid gases, is directed toward the acetylene recov-
ery area.
The acid gases are stripped from the alkaline solution and these gases
enter the HCN absorber for recovery of HCN. After removal of HCN and
entrained liquid, the acid gases go to Glaus plant for conversion to ele-
mental sulfur.
The process gas leaving the acid gas removal system enters the acety-
lene absorber, where acetylene is absorbed in liquid ammonia. Rich ammonia
from the bottom of the acetylene absorber is pumped through heat inter-
changers and a chiller to the acetylene stripper, operating at high
pressure, where crude acetylene is released. The stripper process gas,
containing acetylene, carbon disulfide, higher acetylenes, and water
vapors, goes to the acetylene purification system.
The acetylene-free off-gas from the acetylene absorber is split and
a portion of it is scrubbed with water to recover ammonia. This portion
of the off-gas is then compressed and returned to char processing as H£-
rich fuel gas. The major part of the acetylene absorber off-gas is
directed to CO removal.
The crude acetylene is scrubbed with methanol to remove carbon disul-
fide and part of the higher acetylenes. The purified acetylene leaving
the methanol wash column is cooled and scrubbed with water in the acety-
lene product scrubber to remove methanol vapors. The acetylene product
scrubber overhead is the final acetylene product.
Approximately four-fifths of the acetylene absorber off-gas is recycled
to the reactors after removal of CO. Partial CO removal from the recycle
gas is necessary to maintain a sufficiently low carbon monoxide concentra-
tion in the reactor. Recycle gas returning from the CO-removal system is
used as carrier gas, to convey the pulverized coal to the reactor; sheath
gas, to sweep the reactor wall to minimize char buildup on the wall; and
arc gas, for the revolving arc.
125
-------
(2) Energy Conserving Potential
The energy consumed by the process is characterized below:
Btu/lb C?H Energy Index
^ (Btu/lb
Net Products)
Coal 41,330 30,390
Utilities* 59,100 43,435
Energy Credit (Char) (11,458) ( 8,425)
Total 88,972 65,400
The energy index is 65,400 Btu/lb net products, including feed based on
1.36 pounds of net product per pound of acetylene assuming that char is
used as power plant fuel. This energy index is the highest of any of the
advanced thermal cracking processes reviewed.
In regard to energy form conservation, the process provides an all
coal route to acetylene; a fundamental petrochemical building block which
is competitive with ethylene for many derivatives. For some petrochemicals,
acetylene is superior to ethylene as a raw material. Hence, this tech-
nology provides a route to plastics and fibers through coal, thereby free-
ing the chemical industry from total dependence on petroleum. However,
the attractiveness of this alternative will depend on the price of coal
relative to petroleum-derived feedstocks over the coming years.
(3) Environmental Implications
Liquid waste streams from the HCN and acetylene recovery areas con-
taining trace amounts of HCN and C$2 are processed by the liquid wastes
recovery system. Steam stripped HCN and CS£ are vented to the SC>2
generator. The recovered process water is cooled and stored in the process
water system. A very small portion of the recovered process water is
sewered, and make-up water is added only on demand.
The C$2-rich gas stream from acetylene purification enters an S02 gen-
erator where it is chilled to recover "crude carbon disulfide." An exact
amount of CS£ and residual acetylene is combusted in a burner using atmo-
spheric air for the source of oxygen to produce an SC^-rich gas. The S02
volume is one-half the ^S volume in the ^S-rich gas stream from acid gas
recovery. Both streams are processed by the Glaus plant followed by the
Claus tail gas unit. Elemental sulfur is recovered and sold at the cost
required for handling. Crude carbon disulfide is handled in the same manner.
*Includes electric power at 10,500 Btu per kWh.
126
-------
The vent gas from the Glaus tail gas unit and catalyst regeneration
off-gas from the Claus plant flow through the stack and into the atmosphere
but are not considered a significant pollutant.
(4) Typical Economics
The required selling price of acetylene produced by the Arc-Coal
process route is very dependent on the price of coal and the carbon black
byproduct value. In fact, at current general purpose carbon black prices,
the byproduct credit pays for the raw coal feed. Hence, the major manu-
facturing costs are energy and capital related. Based on coal at $30/ton,
the estimated acetylene price is 20.6c/lb (Table E-8). This is nearly
equivalent to the projected 1980 price of ethylene from new grass roots
steam crackers. If carbon black is assigned only fuel value, the price
increases to 23.6c/lb.
b. U.S Steel Clean Coke Process
In the late 1960's and early 1970's, U.S. Steel developed the concept
of an integrated coal processing facility that would produce blast furnace-
grade coke from non-coking coals, and simultaneously large quantities of
valuable coal-based chemicals. The "Clean Coke" process* is intended to
be a non-polluting replacement for existing coke oven technology. In 1973,
USS received a $6.6 million contract from the OCR (now Office of Fossil
Energy - ER.DA) to develop this concept through bench-scale work to the
design of a 240 tpd pilot plant.
(1) Process Description
The Clean Coke process (Figure E-6) basically integrates low-temper-
ature carbonization and hydrogenation of coal to produce metallurgical
coke and basic chemicals while making optimum use of energy and raw
materials. The principal product is metallurgical grade coke; however, a
wide range of chemical coproducts, including ethylene, is possible.
The coal feed is split, part of it goes to the carbonization unit,
where it is devolatilized and partially desulfurized to produce the char
that is the base material for the metallurgical coke; the remainder is
slurried with a recycle solvent and hydrogenated to form coal-derived
liquids.
Liquid products from carbonization and hydrogenation are combined and
processed in a central liquids treatment unit. In this unit the coal-
liquids are separated into chemical feedstocks and fuel, a recycle solvent
and a heavy oil binder for the "formed" coke. The gaseous products from
various operations are processed through a common system that produces fuel
*Chemical Engineering Progress, Vol. 70, No. 6 (1974) pp. 76-82.
127
-------
TABLE E-8
PRODUCTION COSTS
Product: Acetylene
Byproducts: Carbon Blk., Char
Annual Capacity: 300 x 106 Ibs
Annual Production: 300 x 10° Ibs
Process: ARC-Coal
Fixed Investment: $75 MM
Working Capital: $1.1 MM
1975 Cost Basis
333 Stream Days/Year
Variable Costs
Raw Materials: Coal, Tons
Cat & Chem
Byproduct Credits: Carbon Blk., tons
Char, Tons
HCN
Energy: Purchased Fuel
[Details on Table B] Purchased Steam, Mlbs
Electric Power Purchas
Misc.
Energy Credits: (Specify form)
Water, Mgal: Process (Consumption)
Cooling (Circulating rate)
Direct Operating Labor (Wages)
Direct Supervisory Wages
Maintenance Labor & Supervision 2%
Maintenance Materials 2%
Labor Overhead 35% D-L
Misc. Variable Costs/Credits
Royalty Payments
Total Variable Costs
Units Used in
Costing or
Annual Cost
Basis
438,712
54,400
142,580
10,424
3.072 x 106
1.421 x 109
$/Unit
$30
$195
$25.60
$230
$1.75
$0.0192
Units Consumed
per Ib or ton
of Product
2.92
20.5
9,476
$/lb or
Ton of
Product
87.60
35.84
181.95
Annual
Costs
13,161
865
(10,608)
(3,650)
(2,398)
5,376
27,292
265
14 men/shift
9 men
$6.10/hr
18,000/yr
198.96
nil
748
162
1,500
1,500
844
34,792
Fixed Costs
Plant Overhead 80% T-L
Local Txes & Insurance 2% ...
Capital Recovery 30% of CIU'
Miscellaneous Fixed Costs/Credits
Total Fixed Costs
Total Costs
2,604
1,500
22,830
179.56 26,934
378.52 61,726
20.6e/lb
23.6c/lb
(2)
(1)
Incl. deprec. + ROI
(2)
With carbon black at fuel value.
128
-------
Source: Coal Age, Oct 1973. Page 142
Figure E-6. Clean-Coke Process
129
-------
gas, recycle hydrogen and ethylene plant feedstock (C-jtf.,, C- and LPG) . For
a plant producing 2.2 million tons of coke, (Table E-9) according to the
latest published information the annual ethylene byproduct yield is 723
million pounds.
In February 1975, an interim report on progress under the OCR contract
was released covering test results between March 1972 and April 1974. The
data reported at that time were used to corroborate the process yields
shown in Table E-9. If one assumes a typical conversion ratio of 73% for
formed coke manufacture, the production of 2.2 million tpy of coke would
require 3.0 million tpy of char, pitch coke, and tar binder. At the 1973
ACS meeting, U.S. Steel spokesmen reported a form coke formula of 60% char,
10% pitch coke, and 30% binder. To produce the required char (1.8 million
tpy), a carbonizer, typically-yielding 65% char, would require 2.77 million
tpy of coal feed. If the total coal feed is 5.79 million tpy, as indicated
in Table E-9, this leaves about 3 million tpy for feed to the hydrogenation
unit. With this indication of the feed split to the two major process
units, it is possible to estimate roughly the maximum ethylene yield. Since
the liquid products of the Clean Coke process are all highly aromatic, the
only reasonable sources of ethylene are the gas streams from the carboni-
zer and the hydrogenation unit. A small amount of ethane and LPG is also
obtained from the coal liquids hydrotreated.
The highest hydrogenation gas yield reported in the interim report
was 15%. Of course, not all of the gas produced in the hydrogenation unit
is ethylene feedstock. In fact, the interim report indicated that about
60 wt % of the gas consisted of CH^, COo, CO and I^S (Table E-10). The
remainder of the gas was composed of C2 s, Cg's, and C4*s, so the maximum
yield potential from hydrogenation gas is about 215 million Ib/yr (60%
overall ethylene from C2?s - C^'s).
A small amount of ethylene may also be produced from the carbonizer
gases, but most of these gases are not ethylene source material (Table
E-ll). If 2.77 million tpy of coal are fed to the carbonizer, and the
ethane and butane gases produced are'pyrolyzed, 50 million Ib/yr of ethy-
lene could possibly be obtained. In addition, assuming a 4% gas yield,
about 15 million Ib/yr equivalent ethylene is available in the hydrotreater
gas.
Thus, the maximum ethylene yield based on the available experimental
data is about 280 million Ib/yr (215 + 50 + 15). Hence, there is a dis-
crepancy between the ethylene yield derived using 1-1/2 year old data from
the interim report and that reported in CEP. Our inquiry regarding the
reason for this difference was explained as being due to the preliminary
nature of the yield data on many of the process steps.
130
-------
TABLE E-9
MATERIAL BALANCE - CLEAN-COKE PROCESS
Basis: 17,000-ton/day washed and sized coal, 3.5% moisture,
35% volnlilo matter, 340 operating day/yr,
coal feed, 6.79 million ton/yr
Products
Annual production
Coke
Hydrogenation residue
Chemicals
Ammonia . .
Sulfur
Ethylcne
Propylenc . .
Phenol ...
o-cresol
m-, p-cresol
Xylcnols .
Pyridine . .
o.Picolme ...
Aniline ...
Benzene
Naphthalene
Total chemicals . . .
Tar products
Creosote blcnrl stock
Carbon black (ecdslock. . 3,700.000 gal.
Total tar products . .
Process loss, and fuels consumed
TOTAL
. . . 2.223.000 to.n . .
. . . 669.000 tons . .
34.000 tons . . .
19,000 tons . . .
. 723.000.000 Ib
119.000.000 Ib
152.000,00011)
38 400.000 ll>.
. 1-12.000.000 Ib
. 150.000.00011)
. 14,600.000 Ib
6.100,000 Ib
29.200.000 II) . . .
. 80.400.000 gal
. 229.000.000 Ib
4.130,000 gal.
Wt.-X
.in 39
. . 11.55
. . 0.59
. . 0.85
. 6.25
. . 1.03
. . 1.31
. . 0.33
. 1.23
1.30
. 0.13
. . 0.05
. 025
. 4.97
. . 1.98
. . 20.27
. . 0.32
. . 0.29
, . 0.61
..29 18
. 100.00
Source: Coal Processing Technology, CEP Technical Manual
Vol. 2 (1975)
TABLE E-10
COMPOSITIONS OF GAS PRODUCTS FROM
HYDROGENATION OF ILLINOIS NO. 6 (HERRIN) COAL
Time
(min)
5
15
15
5
5
15
15
5
Temp
(°F)
825
825
825
880
880
880
880
925
Pressure
(psiq)
3200
3200
4500
3200
4500
3200
4500
3500
Yield
(V.'t ?, )
3.1
5.0
4.6
5.5
5.0
9.4
7.8
10.0
Analysis (r.\olc porconl*)
C1-C4**
79
85
87
88
80
91
90
93
co,:
11
6
11
6
7
5
5
C
CO
8
G
3
5
3
4
H2S
2
3
2
2
->
1
1
1
*0n hydrogen-free basis.
**Mass Spectroscopy results: C1-C4 consists of 60% methane, 24% ethane-
ethylene, 11% propane-propylene, and 5% butanes.
Source: Clean Coke Process Summary of Bench Scale Studies OCR 14-32-0001-12^0
August 1974 ~ '
131
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TABLE E-ll
CARBONIZATION GAS ANALYSIS (wt %)
1-Stage 2-Stage
Carbonization Carbonization
Component
Hydrogen 5-11 3.7
Carbon Monoxide 14-32 8.2
Carbon Dioxide 2.1
Methane 57-80 81.6
Ethane trace 3.3
Propylene trace 0.4
n-Butane trace 0.6
Total Gas Yield *»33% of carbonizer feed.
Source: Clean Coke Process Summary of Bench Scale Studies OCR 14-32-0001-
1220, August 1974.
We believe that in the next decade the impact of ethylene from the
TJSS-OCR Clean Coke process upon domestic ethylene supply, energy demand,
or national emissions will be small. The project is now at the 500 Ib/day
scale. It is doubtful that it will reach a commercial status much before
1985. About 15 million tpy of coke capacity will be required domestically
between 1980 and 1985. If all of this growth were based upon the Clean
Coke process (very unlikely), about seven 2.2 million tpy plants would
be required. At 200 million Ib/yr of ethylene each, the incremental ethy-
lene production from this source would be 1.4 million Ib/yr, or only about
3.5% of the projected North American demand for ethylene in 1980. The
process would replace an almost insignificant fraction of the olefins
industry demand on natural gas and petroleum feedstocks through 1990. Since
it is designed to be less polluting than the coke ovens it will replace,
the introduction of this process should have adequate environmental
safeguards.
132
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APPENDIX F
GLOSSARY FOR OLEFINS REPORT
LPG - liquefied petroleum gas; usually mixtures of propane and butane.
Naphtha - the fraction of crude oil boiling between the LPG cut and
350-400°F.
Gas Oil - the fraction of crude oil boiling between the naphtha cut and
550-650°F.
Transfer line exchanger (TLX) - the indirect heat exchanger used to quench the
effluent from the cracking furnace and generated high pressure span.
Pyrolysis - chemical decomposition by the action of heat.
Coil cracking or tubular cracking - the pyrolysis or cracking of a material
carried out inside a tube with heat being supplied through the tube wall.
Autothermal cracking - the pyrolysis of a material when the heat required for
the pyrolysis is produced by the internal partial combustion of the feedstock
or a supplemental fuel.
Fluid bed cracking - the pyrolysis of a material carried out in a fluid bed.
Fractionation - the separation of two or more liquids having different vapor
pressures by repetitive vaporization and condensation of the material.
Hydrotreating - the treating of a petroleum product with hydrogen usually in
the presences of a catalyst, to remove impurities or to cause hydrogen satura-
tion of some of the materials or to generally upgrade the material.
Hydrogenation - the reaction of hydrogen with some compound.
Glaus plant - a type of recovery plant to convert hydrogen sulfide gas to
elemental sulfur by partial combustion of the hydrogen sulfide with air.
Stretford unit - a unit to convert hydrogen sulfide to elemental sulfur in an
aqueous system using air as an oxidizing medium.
133
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TECHNICAL REPC'.T DATA
(7Vc..'.9r ri'ihl luxtnu'tii'im on the ivi M' hrjorc I'u
. REPORT NO.
EPA-600/7-76-034f
2.
4. TI.LE AND SUBTITLE ENVIRONMENTAL CONSIDERATIONS OF
SELECTED ENERGY CONSERVING MANUFACTURING PROCESS
OPTIONS. Vol. VI. Olefins Industry Report
3. RECIPIENT'S ACCESSI ON-NO.
5. 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
13. TYPE OF REPORT AND PERIOD COVERED
Industrial Environmental Research Laboratory
Office of Research and Development
U.S. Environmental Protection Agency
Cincinnati, Ohio 45268
14. SPONSORING AGENCY CODE
EPA-ORD
15. SUPPLEMENTARY NOTI vol. III-V, EPA-600/7-76~034c through EPA-600/7_7g_o34ej refer to
studies of other industries as noted below; Vol. I, EPA-600/7-76-034a, is the Industry
Summary Report and Vol. II, EPA-600/7-76-034b is the Industry Priority
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. VI deals with the Olefins Industry and the utilization of naphtha
and atmospheric gas oil as alternative feedstocks to ethane-propane. Relative process
economics and environmental energy consequences- of both naphtha and atmospheric gas
oil coil cracking are examined and compared with a base line plant using ethane-
propane as a feedstock. A brief analysis is also made of the emerging technologies
for producing olefins. Vol. III-V and Vol. VII-XV deal with the following industries:
iron and steel, petroleum refining, pulp and paper, ammonia, aluminum, textiles,
cement, glass, chlor-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.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI 1'icld/Group
Energy
Pollution
Industrial Wastes
Olefins
Ethylene
Manufacturing Processes
Energy Conservation
Organic Chemicals
Environmental Impact
13B
3. DISTRIBUTION STATEMENT
Release to public
19. SECURITY CLASS (This Report/
unclassified
21. NO OF PAGES
152
20. SECURITY CLASS (Thispage)
unclassified
22. PRICE
EPA Form 2220-1 (9-73)
134
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