U.S. Environmental Protection Agency Industrial Environmental Research CD A RClC\/7 7R.
Office of Research and Development Laboratory
Cincinnati.Ohio 45268 December 1976
ENVIRONMENTAL
CONSIDERATIONS OF
SELECTED ENERGY
CONSERVING MANUFACTURING
PROCESS OPTIONS:
Vol. IV. Petroleum
Refining Industry Report
Interagency
Energy-Environment
Research and Development
Program Report
-------
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. t;o 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.
-------
EPA-600/7-76-034d
December 1976
ENVIRONMENTAL CONSIDERATIONS OF SELECTED
ENERGY CONSERVING MANUFACTURING PROCESS OPTIONS
Volume IV
PETROLEUM REFINING 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
-------
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
-------
FOREWORD
When energy and material resources are extracted, processed, converted,
and used, the related pollutional impacts on our environment and even on our
health often require that new and increasingly more efficient pollution con-
trol methods be used. The Industrial Environmental Research Laboratory
Cincinnati (IBRL-Ci) assists in developing and demonstrating new and im-
proved methodologies that will meet these needs both efficiently and
economically.
This study, consisting of 15 reports, identifies promising industrial
processes and practices in 13 energy-intensive industries which, if imple-
mented over the coming 10 to 15 years, could result in more effective uti-
lization of energy resources. The study was carried out to assess the po-
tential environmental/energy impacts of such changes and the adequacy of
existing control technology in order to identify potential conflicts with
environmental regulations and to alert the Agency to areas where its activi-
ties and policies could influence the future choice of alternatives. The
results will be used by the EPA's Office of Research and Development to de-
fine those areas where existing pollution control technology suffices, where
current and anticipated programs adequately address the areas identified by
the contractor, and where selected program reorientation seems necessary.
Specific data will also be of considerable value to individual researchers
as industry background and in decision-making concerning project selection
and direction. The Power Technology and Conservation Branch of the Energy
Systems-Environmental Control Division should be contacted for additional
information on the program.
David G. Stephan
Director
Industrial Environmental Research Laboratory
Cincinnati
ill
-------
EXECUTIVE SUMMMARY
Industry in the United States purchases about 27 quads* annually; approxi-
mately 40% of U.S. energy usage.** This energy is used for chemical conversion
processing, steam raising, drying, space and process heating and cooling and
miscellaneous other uses. In many industrial sectors, significant reductions
in energy consumption can be achieved by either better "housekeeping" practices
or the utilization of improved processes which are more efficient or result in
upgrading of energy form values. This study focuses primarily on the latter
category of energy conserving options.
A ranking system which considered both quantitative and qualitative
factors, with emphasis on the total amount of energy utilized by an industry
and the potential for energy conservation by a process change, was applied
to various industries. Using this ranking method, the petroleum refining
industry appeared in seventh place among the 13 industry segments being studied.
The refining industry consumed about 2.96 quads in 1971 (see Table ES-1), 11%
of the 27 quads purchased by all industries.
Petroleum refining is the manufacturing step in the production of
hydrocarbon-based fuels. A large, modern refinery will produce a wide
range of fuel products and contain a host of integrated processes which
separate and convert crude petroleum into final products. As a result there
are many potential opportunities for instituting energy conserving process
changes within the overall crude oil refining process. A roster of potential
energy conserving changes is provided in Appendix E. Through interviews with
refining industry representatives, five alternatives likely to be implemented
within the time frame of interest were selected for detailed evaluation.
• A-l - Direct combustion of asphalt in process heaters and boilers
• A-2 - Hydrocracking of vacuum bottoms (H-Oil)
• A-3 - Flexicoking of vacuum bottoms
• B - Internal electrical power generation
• C - Hydrogen generation by partial oxidation
Each of the above options achieves an energy form value improvement as con-
trasted with an improvement in thermal efficiency.
*1 quad = 1015 Btu
**Purchased electricity value at an approximate fossil fuel equivalence of
10,500'Btu/kWh.
IV
-------
TABLE ES-1
SUMMARY OF 1971 ENERGY PURCHASED IN SELECTED INDUSTRY SECTOR
Industry Sector
1. Blast furnaces and steel mills
2. Petroleum refining
3. Paper and allied products
4. Olefins
5. Ammonia
6. Aluminum
7. Textiles
8. Cement
9. Glass
10. Alkalies and chlorine
11. Phosphorus and phosphoric
acid production
12. Primary copper
13. Fertilizers (excluding ammonia)
1015 Btu/Yr
3.49(1)'
2.96(2)
1.59
0.984(3)
0.63(4>
0.59
0.54
0.52
0.31
0.24
0.12(5>
0.081
0.078
SIC Code
In Which
Industry Found
3312
2911
26
2818
287
3334
22
3241
3211, 3221, 3229
2812
2819
3331
287
(1)
(2)
(3)
(4)
(5)
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
Ammonia feedstock energy included : AT1T,
ADL estimates
Source: 1972 Census of Manufactures, FEA Project Independence Blueprint,
USGPO, November 1974, and ADL estimates.
-------
These process changes were evaluated within the context of "typical"
existing refineries which were selected to take into account geographical
differences in crude runs and product demands. The comparisons were made
within the 1985 refinery environment which assumes complete phase out of
natural gas from the refinery fuel system and complete conversion to the
production of unleaded gasoline. (See Appendix C.)
The detailed assessment of these five alternatives resulted in the
following energy related conclusions.
• The alternatives are generally net consumers of energy in a strictly
thermodynamic sense. This is especially true when the energy
associated with pollution control is included.
• Except for option A-3, the reduction in refinery efficiency is
slight. For option A-3 refinery efficiency is reduced by two
percentage points.
• The principal conservation benefit of these options is in terms of
form value upgrading. This is accomplished by utilization or con-
version of refinery residue streams which results in a net increase
in the availability of higher valued fuels such as refinery gas and
distillate range products. Table ES-2 summarizes the net product
changes for each option.
The cost impact of pollution control associated with these process
changes is summarized below.
• The implementation of the above process changes will have a small
impact on the control of refinery wastewater. The alternatives
evaluated do not change the characteristics of the treated efflu-
ent, or the type of treatment required to conform with regulatory
requirements. In all cases, the wastewater loads represent incre-
ments to the treatment system, therefore the cost of treatment would
not preclude the selection of any of the alternatives. At most,
incremental wastewater treatment costs are 9% of the total oper-
ating cost (excluding feedstock and product values) for that option.
• The removal of sulfur to limits set for SOX emissions has a signifi-
cant cost impact on those options which involve the direct combustion
of asphalt, i.e., options A-l and B. In the case of option A-l,
the operating cost for flue gas desulfurization (FGD) accounts for
more than half of the total operating cost as shown in Table ES-3.
• The impact of EPA regulations on the residuum upgrading processes
(H-Oil, Flexicoking, and Partial Oxidation) evaluated is not
unreasonable in most cases. The additional control required repre-
sents an incremental change to the existing sulfur recovery system
(see Table ES-3).
vi
-------
TABLE ES-2
CHANGES TO PRODUCT SLATES RESULTING FROM PROCESS CHANGES
(BPD)
OPTIONS:
Products
Asphalt (vac. btms.)
Tar
Residual oil (atnf. btms.)
Heavy gas oil
Light gas oil
Naphtha
LPG (FOE)
Refinery gas (FOE)
Coke
Klectricity
Total 12,330 12,330 12,110 11,170 18,700 16,070 1,460 1,460 3,625 3,750
A-l
Direct Combustion
Reduction Increase
12,330
\
> 9,640
\
2,690
A-2
H-Oil
Reduction Increase
9,240
1,480
2,070
3,820
3,060
2,270
540
800
A- 3
Flexicoking
Reduction Increase
18,700
8,746
—
2,111
350
4.4891
374
B C
Power Generation Asphalt POX
Reduction Increase Reduction Increase
1,460 3,625
_._
—
—
3,750
--- 1~460-' --- ---
Includes displaced refinery gas and coker product gas.
•'1,460 (6.3 x 10*70.0105 x 10'') = 876,000 kWh/day ~ 36.5 MW of capacity.
-------
TABLE ES-3
SUMMARY OF ANNUAL POLLUTION CONTROL COSTS
($103)
Option
A-l
A-2
A-3
-------
EPA policies regarding sulfur emissions from refineries could certainly
have an effect upon how the refiners manage their internal energy require-
ments. The present approach is to blend low sulfur distillate oils with the
heavy bottoms to meet an overall sulfur specification. In so doing, the
yield of distillate oil product may be reduced. Option A-l presents an
alternative which would make more light fuel oil available to consumers, how-
ever, the FGD pollution control technology available is too costly for practial
implementation. Hence, the impact of EPA regulations upon the management of
the refinery fuel balance in this case has an affect on the choice of options.
The same problem is encountered with the integrated electrical/steam
system (option B). First, it is the only option which might be undertaken
to conserve total energy in the refinery, not just upgrade form value
or higher product value. Hence, some movement in this direction may be man-
dated by FEA, regardless of the economics. Second, with this motivation, it
underlines the great need for small source FGD developments, perhaps utilizing
typical refinery resources such as CO or H~.
The choice of alternates for heavy resid conversion is particularly
dependent upon the type of crudes processed at a given refinery and the par-
ticular markets for asphalt, coke and distillate fuels. Furthermore, the
impact of pollution regulations is not particularly great for these options,
consequently, pollution regulations are not seen as an impediment in the
application of these technologies. However, less costly small source FGD
technology would also benefit these form value upgrading schemes.
As a result of this assessment, two technology areas have been identified
which through added research could increase energy conservation in terms of
form value availability. By far the most important research area would have
as an objective improving the reliability and reducing the cost of flue gas
desulfurization, especially in the size range below 50 MW equivalent. Such
a development should make maximum use of refinery resources, such as carbon
monoxide, hydrogen, amine plants, or Glaus units. The second is concerned
with developing rugged hydrocracking catalysts which can withstand the poisons
normally present in petroleum residues, or alternatively an economical
residual demetalization process. The objective in this case would be to
increase space velocity (more activity) and yields. Technology improvements
in these areas would allow flexibility in refinery fuel management and increase
the yields of clean fuels from refineries without sacrificing environmental
quality.
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.
IX
-------
TABLE OF CONTENTS
FOREWORD ill
EXECUTIVE SUMMARY iv
List of Figures xiii
List of Tables xiv
Acknowledgments xix
Conversion Table xxi
I. INTRODUCTION 1
A. BACKGROUND 1
B. CRITERIA FOR INDUSTRY SELECTION 1
C. CRITERIA FOR PROCESS SELECTION 2
D. SELECTION OF PETROLEUM REFINING INDUSTRY PROCESS OPTIONS 3
II. FINDINGS, CONCLUSIONS, AND RECOMMENDATIONS 6
A. CHANGES STUDIED 6
B. IMPACTS ON WASTEWATER CONTROL 6
C. ENERGY CONSERVATION POSSIBILITIES 7
III. PETROLEUM REFINING INDUSTRY OVERVIEW 9
A. INDUSTRY DESCRIPTION 9
B. ECONOMIC OUTLOOK ' 11
IV. COMPARISON OF CURRENT AND ALTERNATIVE PROCESSES 14
A. CRITERIA FOR ASSESSING OPTIONS' 14
1. Probability of Implementation 14
2. Pollution Control 14
3. Energy Considerations 14
4. Feedstock Availability 15
5. Market Considerations 15
6. Process Economics 16
I
B. SELECTION OF STUDY ALTERNATIVES 16
1. Option A: Utilization of Asphalt to Increase
Yields of Higher Value Products 16
xi
-------
TABLE OF CONTENTS (Cont.)
Page
2. Option B: Internal Power Generation Using Asphalt 18
3. Option C: Alternative Methods for Hydrogen Generation 19
C. REFINERY BASE LINE AND PROCESSING ALTERNATIVES 21
1. Refinery Base Line Used for Comparison 21
2. Process Change A-l: Direct Combustion of Asphalt in
Process Heaters and Boilers 32
3. Process Change A-2: Hydrocracking of Heavy Bottoms 43
4. Process Change A-3: Flexicoking 52
5. Process Change B: On-Site Electric Power by
Combustion of Vacuum Bottoms 67
6. Process Change C: High-Purity Hydrogen Production
via Partial Oxidation of.Asphalt 78
V> IMPACTS OF POTENTIAL INDUSTRY CHANGES 90
A. IMPACT OF PROCESSING OPTIONS 90
1. Process/Pollution Control/Energy Effects 90
2. Cost Impact 92
B. SYSTEMS IMPLICATIONS 92
1. Direct Combustion of Asphalt 96
2. On-Site Power Generation 96
3. Upgrading of Heavy Residues (H—oil, Flexicoking,
Asphalt POX) 96
C. FACTORS AFFECTING PROBABILITY OF CHANGE 96
1. Direct Combustion of Asphalt 96
2. Power Generation 97
3. Upgrading of Asphalt 97
D. AREAS FOR RESEARCH 97
APPENDIX A - INDUSTRY STRUCTURE 99
APPENDIX B - PRESENT TECHNOLOGY 111
APPENDIX C - BASE LINE ENERGY USE 113
APPENDIX D - CURRENT POLLUTION PROBLEMS AND EFFECTIVENESS OF
AVAILABLE POLLUTION CONTROL TECHNOLOGY 134
APPENDIX E - ROSTER OF PROCESS OPTIONS OR CHANGES IN INDUSTRIAL
PRACTICE 162
APPENDIX F - GLOSSARY 167
xii
-------
LIST OF FIGURES
Number Page
III-l Petroleum Administration for Defense (PAD) Districts 10
IV-1 Vacuum Residue Distribution System 34
IV-2 Pollution Source Identification - Asphalt Combustion 37
IV-3 H-Oil 44
IV-4 Identification of Pollution Sources from Hydrocracking 47
IV-5 Flow Diagram and Volume Flows for Flexicoking 56
IV-6 Block Flow Diagram for Flexicoking and Identification
of Pollution Sources from Flexicoking 60
IV-7 Electric Power from Asphalt 69
IV-8 Pollution Source Identification: Electric Power from
Asphalt Combustion 72
IV-9 Hydrogen via Partial Oxidation 79
IV-10 Pollution Source Identification: Partial Oxidation 83
A-l Petroleum Administration for Defense (PAD) Districts 101
C-l .East Coast Cluster Calibration 116
C-2 Louisiana Gulf Coast Cluster Model Calibration 117
C-3 West Coast Cluster Model Calibration 118
D-l Capital Cost for a Typical Sulfur - Recovery Technology 153
D-2 Operating Costs for Typical Sulfur - Recovery Technology 154
D-3 Capital and Operating Costs vs. Heat Input Rate for
Scrubber System i 156
xiii
-------
LIST OF TABLES
Number Page
1-1 Summary of 1971 Energy Purchased in Selected Industry
Sectors 3
III-l Survey of U.S. Refining Industry by Capacity and Number
of Plants 9
III-2 Survey of Operating Refineries in the United States -
1962-1972 12
IV-1 Flexicoker Yields From Various Residua 19
IV-2 Anticipated Shifts in Refinery Energy Usage Caused
by Natural Gas and TEL Phase-Out 23
IV-3 Major Airborne Emissions From Base Line Refinery (East Coast) 24
IV-4 Major Airborne Emissions From Base Line Refinery (Gulf Coast) 25
IV-5 Major Airborne Emissions From Base Line Refinery (West Coast) 26
IV-6 Base Case Refinery - Characteristics of Raw and Treated
Process Wastewater 28
IV-7 Estimation of Base Case Solid Waste Generation 29
IV-8 Summary of Base Line Wastewater Treatment Costs 30
IV-9 Existing Refinery Capital Investments and Operating Costs 33
IV-10 Comparison of Refinery Energy Balance With and Without
Direct Combustion of Asphalt 35
IV-11 Asphalt Combustion Pollution Profile 38
IV-12 Example of S02 Control for Process Heater or Boiler 40
IV-13 Production Costs: Option A-l (Direct Combustion) 42
IV-14 Comparison of Refinery Energy Balance With and Without
Heavy-ends Hydrocracking 46
xiv
-------
LIST OF TABLES (Cent.)
Number Page
IV-15 Summary of Addition to Base Line Emissions Due to Heavy-ends
Hydrocracking 48
IV-16 West Coast Refinery With Heavy-bottoms Hydrocracking Process
Wastewater Treatment Costs 50
IV-17 Sulfur Control Costs for Base Line and With Hydrocracking
(Option A-2) 51
IV-18 Production Costs: Option A-2 (Resid Hydrocracking) 53
IV-19 Products From Heavy-ends Hydrocracking 54
IV-20 Comparison of Product Slates For the West Coast Base Line
With the Incorporation of Heavy-ends Hydrocracking (1000 BPD) 54
IV-21 Summary of Refinery Energy Balance With and Without Flexicoking 58
IV-22 Summary of Additions to Base Line Emissions Due to Flexicoking 59
IV-23 Water Analysis Flexicoking Sour Water 61
IV-24 East Coast Refiner With Flexicoking Process Wastewater
Treatment Costs 62
IV-25 East Coast Refinery With Flexicoking Cooling Tower Slowdown
Wastewater Treatment Costs 63
IV-26 Sulfur Control Costs for Flexicoking (Option A-3) 65
IV-27 Production Costs: Option A-3 (Flexicoking) 66
IV-28 Comparison of Product Slates With and Without Flexicoking 68
IV-29 Comparison of Refinery Energy Balance With and Without
On-site Power Generation 70
IV-30 Electric Power From Asphalt - Pollution Profile 73
IV-31 Gulf Coast Refinery With On-site Power Generation Cooling
Tower Slowdown Wastewater Treatment Costs 74
IV-32 Sulfur Control Costs of Electric Power Generation (Option B) 76
IV-33 Production Costs: Option B (Steam/Electric) 77
IV-34 Comparison of Refinery Energy Balance With and Without
Hydrogen Production via Partial Oxidation of Asphalt 81
xv
-------
LIST OF TABLES (Cont.)
Number Page
IV-35 Partial Oxidation for Hydrogen Production - Pollution
Profile 84
IV-36 West Coast Refinery - Hydrogen Production by Partial Oxidation
Process Wastewater Treatment Costs 85
IV-37 West Coast Refinery With Partial Oxidation Hydrogen Production
Cooling Tower Slowdown Wastewater Treatment Costs 86
IV-38 Sulfur Control Costs for Hydrotreating (Option A-2) and
Partial Oxidation (Option A-3) 87
IV-39 Production Costs: Option C (Partial Oxidation) 89
V-l Changes to Product Slates Resulting From Process Changes 91
V-2 Change in Refinery Energy Usage Resulting From Process
Changes 93
V-3 Energy Consumed by Air Pollution Control (APC) Systems 94
V-4 Summary of Annual Pollution Control Costs 95
A-l Survey of Operating Refineries in the United States -
1962-1972 100
A-2 U.S. Petroleum Refining Capacity and Actual Crude Runs
Average January 1 Capacity in Given Year and January 1
Capacity in the Following Year 102
A-3 Historical Refining Capacity Data - Total United States 104
A-4 New Refineries, Expansions and Reactivations Scheduled in
the United States by PAD Districts 105
A-5 Refineries Planned but not Constructed due to Opposition on
Environmental Grounds 108
A-6 Projection of U.S. Primary Energy Supplies with Oil as the
Balancing Fuel 110
A-7 Forecast of U.S. Product Demand 110
C-l Refineries Simulated by Cluster Models 114
C-2 Summary of East Coast Refinery Operation (1974) 119
xvi
-------
LIST OF TABLES (Cont.)
Number Page
C-3 Summary of Gulf Coast Refinery Operation 120
C-4 Summary of West Coast Refinery Operation 121
C-5 Summary of East Coast Refinery Energy Consumption (1974) 122
C-6 Summary of Gulf Coast Refinery Energy Consumption (1974) 123
C-7 Summary of West Coast Refinery Energy Consumption (1974) 124
C-8 Summary of East Coast Refinery Operation (1985) 126
C-9 Summary of Gulf Coast Refinery Operation (1985) 127
C-10 Summary of West Coast Refinery Operation (1985) 128
C-ll Summary of East Coast Refinery Energy Consumption (1985) 129
C-12 Summary of Gulf Coast Refinery Energy Consumption (1985) 130
C-13 Summary of West Coast Refinery Energy Consumption (1985) 131
C-14 Anticipated Shifts in Refinery Energy Usage Caused by
Natural Gas and TEL Phase-Out 132
C-15 Capital Investments and Operating Costs 133
D-l Typical Base Case Raw Refinery Waste Loads 136
D-2 Base Case Refinery - Characteristics of Raw and Treated
Process Wastewater 138
D-3 Process Wastewater Treatment Costs: East Coast Base Case
Refinery 141
D-4 Cooling Tower Slowdown Wastewater Treatment Costs: East
Coast Base Case Refinery 142
D-5 Process Wastewater Treatment Costs: Gulf Coast Base Case
Refinery
D-6 Cooling Tower Slowdown Wastewater Treatment Costs: Gulf
Coast Base Case Refinery
D-7 Process Wastewater Treatment Costs: West Coast Base Case
Refinery 145
XV13
-------
LIST OF TABLES (Cont.)
Number Page
D-8 Cooling Tower Slowdown Wastewater Treatment Cost: West Coast
Refinery 146
D-9 Emission Factors in Petroleum Refineries 147
D-10 Anticipated Shifts in Refinery Energy Usage Caused by
Natural Gas and TEL Phase-Out 149
D-ll Major Airborne Emissions from Base Line Refinery
Location: East Coast Year: 1985 150
D-12 Major Airborne Emissions from Base Line Refinery
Location: Gulf Coast Year: 1985 151
D-13 Air Pollution Control Cost of Large Combustion Sources 157
D-14 Petroleum Refinery Solid Wastes—Sources and Characteristics 160
D-15 Base Case Refinery - Characteristics of Raw and Treated
Process Wastewater 161
F-l Weight Conversions 169
F-2 Volume Conversions 169
F-3 Nomenclature 170
xviii
-------
ACKNOWLEDGMENTS
This study could not have been accomplished without the support of a
great number of people in government agencies, industry, trade associations
and universities. Although it would be impossible to mention each individual
by name, we would like to take this opportunity to acknowledge the particular
support of a few such people.
Dr. Herbert S. Skovronek, Project Officer, was a valuable resource to us
throughout the study. He not only supplied us with information on work
presently being done in other branches of EPA and other government agencies,
but served as an indefatigable guide and critic as the study progressed. His
advisors within EPA, FEA, DOC, and NBS also provided us with insights and
perspectives valuable for the shaping of the study.
During the course of the study we also had occasion to contact many
individuals within industry and trade associations. Where appropriate we
have made reference to these contacts within the various reports. Frequently,
however, because of the study's emphasis on future developments with compara-
tive assessments of new technology, information given to us was of a confiden-
tial nature or was supplied to us with the understanding that it was not to be
credited. Therefore, we extend a general thanks to all those whose comments
were valuable to us for their interest in and contribution to this study.
Finally, because of the broad range of industries covered in this study,
we are indebted to many people within Arthur D. Little, Inc. for their parti-
cipation. Responsible for the guidance and completion of the overall study were
Mr. Henry E. Haley, Project Manager; Dr. Charles L. Kusik, Technical Director;
Mr. James I. Stevens, Environmental Coordinator; and Ms. Anne B. Littlefield,
Administrative Coordinator.
Members of the environmental team were Dr. Indrakumar L. Jashnani,
Mr. Edmund H. Dohnert and Dr, Richard Stephens (consultant).
Within the individual industry studies we would like to acknowledge the
contributions of the following people.
Iron and Steel: Dr. Michel R. Mounier, Principal Investigator
Dr. Krishna Parameswaran
Petroleum Refining; Mr. R. Peter Stickles, Principal Investigator
Mr. Edward Interess
Mr. Stephen A. Reber
Dr. James Kittrell (consultant)
Dr. Leigh Short (consultant)
xix
-------
Pulp and Paper:
Oleflns:
Ammonia:
Aluminum:
Textiles:
Cement:
Mr. Fred D. lannazzi, Principal Investigator
Mr. Donald B. Sparrow
Mr. Edward Myskowski (consultant)
Mr. Karl P. Pagans
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
Douglas Shooter, Principal Investigator
Robert M. Green (consultant)
Edward S, Shanley
John Willard (consultant)
Dr.
Mr.
Mr.
Dr.
Dr.. Richard F. Heitmiller
Dr, Paul A. Huska, Principal Investigator
Ms. Anne B. Littlefield
Mr. J.. Kevin O'Neill
Glass:
Chlor-Alkali:
Phosphorus/
Phosphoric Acid:
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
Primary Copper:
Dr. Ravindra M. Nadkarni, Principal Investigator
Dr, Michel R. Mounier
Dr. Krishna Parameswaran
Fertilizers:
Mr. John L. Sherff, Principal Investigator
Mr. Roger Shamel
Dr. Indrakumar L. Jashnani
xx
-------
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
Foot
Foot2
Foot/sec
2
Foot /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
2
Metre
Pascal
3
Metre
Joule
Pascal-second
Degree Celsius
Degree Kelvin
Metre
Metre /sec
3
Metre
2
Metre
Metre/sec
2
Metre /sec
3
Metre
Watt
Watt
Watt
Metre
Joule
3
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'
c F
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)
xxi
-------
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
heating, and miscellaneous other purposes.
In many industrial sectors energy consumption can be reduced significantly
by better "housekeeping" (i.e., shutting off standby furnaces, better thermo-
stat control, elimination of steam and heat leaks, etc.) and greater emphasis
on optimization of energy usage. In addition, however, industry can be expected
to introduce new industrial practices of processes either to conserve energy
or to take advantage of a more readily available or less costly fuel. Such
changes in industrial practices may result in changes in air, water or solid
waste discharges. The EPA is interested in identifying the pollution loads of
such new energy-conserving industrial practices or processes and in determining
where additional research, development, or demonstration is needed to charac-
terize and control the effluent streams.
B. CRITERIA FOR INDUSTRY SELECTION
In the first phase of this study we identified industry sectors that have
a potential for change, emphasizing those changes which have an environmental/
energy impact.
Industries were eliminated from further consideration within this assign-
ment if the only changes that could be envisioned were:
• energy conservation as a result of better policing or "housekeeping,"
• better waste heat utilization,
• fuel switching in steam raising, or
• power generation.
After discussions with the EPA Project Officer and his advisors, industry
sectors were selected for further consideration and ranked using:
*1 quad = 1015 Btu
**purchased electricity valued at an approximate fossil fuel equivalent of
10,500 Btu/kWh
-------
• Quantitative criteria based on the gross amount of energy (fossil
fuel and electric) purchased by industry sector as found in U.S.
Census figures and from information provided from industry sources.
The petroleum refining industry purchased 2.96 quads out of the
12.14 quads purchased in 1971 by the 13 industries selected for study,
or 11% of the 27 quads purchased by all industry (see Table 1-1).
• Qualitative criteria relating to probability and potential for proc-
ess change, and the energy and effluent consequences of such changes.
In order to allow for as broad a coverage of technologies as possible, we
then reviewed the ranking, eliminating some industries in which the process
changes to be studied were similar to those in another industry planned for
study. We believe the final ranking resulting from these considerations identi-
fies those industry sectors which show the greatest possibility of energy con-
servation via process change. Further details on this selection process can be
found in the Industry Priority Report prepared under this contract (Volume II).
On the basis of this ranking method, the petroleum refining industry appeared
in seventh 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 select-
ing those to be included in this study, we have considered the needs and limita-
tions of the EPA as. discussed more completely in the Industry Priority Report
mentioned above. Specifically, energy conservation has been defined broadly to
include, in addition to process changes, conservation of energy or energy form
(gas, oil, coal) by a process or feedstock change. Natural gas has been con-
sidered as having the highest energy form value followed in descending order
by oil, electric power, and coal. Thus, a switch from gas to electric power
would be considered energy conservation because electric power could be gener-
ated from coal, existing in abundant reserves in the United States in compar-
ison to natural gas. 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 15-year span of time of this study.
In addition to excluding from consideration better waste heat utilization,
"housekeeping," power generation, and fuel switching, as mentioned above, cer-
tain options have been excluded to avoid duplicating work being funded under
other contracts and to focus this study more strictly on "process changes."
Consequently, the following have also not been considered to be within the
scope of work:
• Carbon monoxide boilers (however, unique process vent streams yield-
ing recoverable energy could be mentioned);
• Fuel substitution in fired process heaters;
• Mining and milling, agriculture, and animal husbandry;
-------
TABLE 1-1
SUMMARY OF 1971 ENERGY PURCHASED IN SELECTED INDUSTRY SECTORS
SIC Code
15 In Which
Industry Sector 10 8tu/Yr Industry Found
1. Blast furnaces and steel mills 3.49 3312
2. Petroleum refining 2.96 2911
3. Paper and allied products 1.59 26
4. Olefins 0.984<3^ 2818
5. Ammonia 0.63 287
6. Aluminum 0.59 3334
/. Textiles 0.54 22
8. Cement 0.52 3241
9. Glass 0.31 3211, 3221, 3229
10. Alkalies and chlorine 0.24 2812
11. Phosphorite and phosphoric
acid production u.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, USCPO, November 1974.
Includes captive consumption of energy from process byproducts
(FEA Project Independence Blueprint)
Olefins only, includes energy of feedstocks: ADL estimates
(4)
Amonia feedstock energy included: ADL estimates
ADL estimates
Source: 1972 Census of Manufactures, FEA Project Independence Blueprint,
USGPO, November 1974, and ADL estimates.
• Substitution of scrap (such as reclaimed textiles, iron, aluminum,
glass, and paper) for virgin materials;
• Production of synthetic fuels from coal (low- and high-Btu gas,
synthetic crude, synthetic fuel oil, etc.); and
• All aspects of industry-related transportation (such as transporta-
tion of raw material).
Within the refining industry, certain exceptions were considered since
fuel substitution is integrally related to and can have a significant impact
on the amount of product produced.
D. SELECTION OF PETROLEUM REFINING INDUSTRY PROCESS OPTIONS
Within each industry, the magnitude of energy use was an important crite-
rion in judging where the most significant energy savings might be realized,
since reduction in energy use reduces the amount of pollution generated in the
energy production step. Guided by this consideration, candidate options for
in-depth analysis were identified from the major energy consuming process steps
with known or potential environmental problems.
-------
After developing a list of candidate process options, we assessed
subjectively
• pollution or environmental consequences of the process change,
• probability or potential for the change, and
• energy conservation consequences of the change.
Even though all of the candidate process options were large energy users,
there was wide variation in energy use and estimated pollution loads between
options at the top and bottom of the list. A modest process change in a major
energy consuming process step could have more dramatic energy consequences
than a more technically significant process change in a process step whose
energy consumption is rather modest. For the lesser energy-using process steps
process options were selected for in-depth analysis only if a high probability
for process change and pollution consequences was perceived.
Because of the time and scope limitations for this study, we have not
attempted to prepare a comprehensive list of process options or to consider all
economic, technological, institutional, legal or other factors affecting imple-
mentation of these changes. Instead we have relied on our own background
experience, industry contacts, and the guidance of the Project Officer and EPA
advisors.
Reconciling such difficulties with the desire to cover as wide a spectrum
as possible of the consequences of process change, the following candidates
were considered within the petroleum refining industry:
• Burning asphalt in heaters and boilers.
• Generating hydrogen from asphalt by partial oxidation.
• Hydrocracking vacuum bottoms.
• Flexicoking vacuum bottoms.
• Generating electricity by burning asphalt.
• Blending methanol into gasoline.
• Computer optimization of hydrogen balance.
• Generating hydrogen from coal (Texaco POX).
• Upgrading byproduct hydrogen purity by membrane separation.
• FCC UltraCatalytic process (Amoco) .
After discussion with the EPA Project Officer, his advisors, and industry repre-
sentatives, ADL chose the first five from this list for analysis because:
-------
• high crude oil prices and limited markets for heavy bottoms will lead
to more conversion of asphalt into higher quality fuel products;
• there will be more emphasis on optimizing the allocation of fuels to
meet refinery energy needs; and
• future electricity rate structures for industrial power may favor
internal power generation.
The remaining options are only qualitatively discussed based on readily avail-
able information and discussions with industry representatives.
1. Method of Analysis
In undertaking this study, the petroleum refining industry description is
based on 1974, the latest representative year for which we had good statistical
information.
The impacts of the selected process changes were compared within the con-
text of reference refineries with 1985 operating characteristics. A 1985 time
frame was used to allow for certain fundamental changes in refining which have
already begun and will be accomplished by then. These changes include the
phase-out of natural gas as refinery fuel and the phase-out of TEL in the gaso-
line pool. Three refinery cluster models typifying East, Gulf, and West Coast
refinery operation were utilized to assess the impact of processing changes in
different regions.
Recognizing that capital costs and energy costs have escalated rapidly in
the past few years and have greatly distorted the traditional basis for making
cost comparison, we believe that the most meaningful economic assessment of
new process technology can only be made by using 1975 cost data to the extent
possible. Consequently, in estimating operating costs we have developed costs
representative of the first half of 1975 using constant 1975 dollars for our
comparative analysis of future process options.
-------
II. FINDINGS, CONCLUSIONS, AND RECOMMENDATIONS
A. CHANGES STUDIED
The five industry/process changes assessed in this study are briefly:
A-l. Direct combustion of asphalt in heaters/boilers,
A-2. Asphalt conversion by hydrocracking (H-OIL),
A-3. Asphalt conversion by flexicoking,
B. Internal power generation, and
C. Hydrogen generation by partial oxidation.
We evaluated these options within the context of "typical" existing refin-
eries representing actual refinery clusters located in the PAD districts
selected. Each of these options achieves an energy form value improvement.
B. IMPACTS ON WASTEWATER CONTROL
Within the framework of the comparisons set forth, we concluded that the
implementation of these changes will have a small impact on the control of
refinery wastewater. The effect on the characteristics of the treated effluent,
the type of treatment required to conform with regulatory requirements, and the
cost of wastewater treatment would not preclude the selection of any of the
alternatives. Option A-3 has the highest wastewater treatment cost, and the
cost penalty is about 25% of the total pollution control cost and about 7% of
total process operating costs, including pollution controls.
There are, however, some identifiable impacts in regard to air pollution
regulations, particularly S02 emissions. All of the options involve utilization
or conversion of petroleum residues which contain a disproportionate part of
the sulfur found in crude oil. Removal of this sulfur to limits set for SOX
emissions would have a significant impact on those options which involve the
direct combustion of asphalt (vacuum bottoms), viz., options A-l and B as
described above. In the case of option A-l, the operating costs for flue gas
desulfurization (FGD) accounts for more than half of the total operating cost
(see Table V-4). This is why refiners prefer to comply with sulfur dioxide
regulation by fuel blending rather than by installing FGD systems on process
heaters and boilers. The reason FGD is not generally applied in refineries
is that there are numerous small (by electric utility scale) sources within
a specific refinery which require control. FGD systems for the capacities
normally encountered with process heaters have high unit costs.
*See Appendix F, Glossary, for petroleum industry terms.
-------
A possible alternative to options A-l and B is to sell the asphalt to
an electric utility for burning in large boilers equipped with FGD systems.
This would reduce the unit cost of pollution controls due to the improved
economies of scale, but would entail transportation difficulties. Furthermore,
this poses a potential conflict with the Federal Energy Administration's (FEA)
policies aimed at reducing the amount of petroleum used by electric utilities.
The impact of EPA regulations on the residuum upgrading processes, such
as H-Oil and partial oxidation, is not unreasonable and, in most cases, the
additional control required represents an incremental change to an existing
sulfur recovery system. The pollution control cost for option A-3 is 25% of
the total operating costs, including pollution control. Seventy-five percent
of the control cost is for removal of sulfur from the flexigas and reactor gas.
EPA policies regarding sulfur emissions from refineries could certainly
have an effect upon how the refiners manage their internal energy requirements.
The present approach is to blend low-sulfur distillate oils with the heavy
bottoms to meet an overall sulfur specification. In so doing, the yield of
distillate oil product is reduced. Option A-l presents an alternative which
would make more light fuel oil available for refinery export; however, the FGD
control technology available is too costly for practical implementation.
Hence, the impact of EPA regulations upon the management of the refinery fuel
balance in this case has an effect on the choice of options.
Option B is similarly impacted by the high cost of small source FGD. A
potentially attractive modification to option B is the integration of electric
power generation with process steam generation through the use of a topping
cycle (steam pressure reduction with back pressure turbines). This approach
could conserve total energy in the refinery in contrast with the other options
which just upgrade form value. Hence, some movement in this direction may be
mandated by FEA, economics notwithstanding. Asphalt combustion would be a
natural choice of fuel for this scheme, were it not for the high cost of stack
pollution control. Again there is a case for developing small source FGD
technology, perhaps utilizing typical refinery resources such as CO, H2, amine
plants and sulfur-reduction processes.
The choice of alternates for heavy resid conversion is particularly depen-
dent upon the type of crudes processed at a given refinery and the particular
markets for asphalt, coke, and distillate fuels. Furthermore, the impact of
pollution regulations is not particularly great for these options; consequently,
pollution regulations are not seen as an impediment in the application of these
technologies.
C. ENERGY CONSERVATION POSSIBILITIES
As a result of this assessment, two technology areas have been identified,
which through added research could increase energy conservation in terms of
form value availability. The first would have improving the reliability and
reducing the cost of flue gas desulfurization as an objective, especially in
the size range below 50 MW equivalent. The second would be concerned with
developing rugged hydrocracking catalysts which can withstand the poisons
-------
normally present in petroleum residues, or alternatively, an economical
residual demetallization process. The objective in this case would be to
increase space velocities (more activity) and yields. Solvent de-asphalting
of hydrocracker feedstocks is used for this purpose, but the energy require-
ment for solvent recovery is substantial. Technology improvements in these
areas could increase refinery yields of clean fuels without sacrificing envi-
ronmental quality.
Relative to other industrial sectors, the petroleum refining industry
generally has fewer technology limitations preventing energy conservation and
pollution control. At issue is not how to do the job, but rather how can the
cost be borne?
-------
III. PETROLEUM REFINING INDUSTRY OVERVIEW
A. INDUSTRY DESCRIPTION
A general description of the petroleum refining industry is presented
in this section, with detail available in Appendix A. The petroleum refining
industry is one of the most complex and technically sophisticated industries
in the United States. There are currently about 250 U.S. refineries, rang-
ing in size from 400,000 barrels per day (BPD) to only a few hundred BPD.
Refineries vary from those which are fully integrated, highly complex plants,
capable of producing a complete range of petroleum products and some petro-
chemicals, to very simple plants, capable of producing only a small number
of products. Table III-l gives a breakdown of plant sizes and capacities.
Some refineries are modern, while others contain processing units constructed
over 40 years ago. Crude slates for refineries also vary as do product lines
and product properties. Because of all this variation, it is difficult to
describe a "typical" refinery. Each refinery is characterized by a unique
capacity, processing configuration, and product distribution.
TABLE III-l
SURVEY OF U.S. REFINING INDUSTRY BY CAPACITY AND NUMBER OF PLANTS
Plant Size, BPD:
No. of Plants
Total Refining Capacity, 1,000 BPD
% of Plants
% of Capacity
<10>000 10-100,000 >100,OOQ
74
348
28
2.3
141
6,032
55
40.7
44
8,465
17
57.0
Source: The Oil and Gas Journal, Annual Refining Survey (1975).
Although each plant is unique, there are similarities in operations
based on general location of the facility. In order to collect statistics on
the refining industry, the Bureau of Mines has divided the United States into
five refining regions, called Petroleum Administration for Defense (PAD) Dis-
tricts (see Figure III-l).
-------
PETROLEUM ADMINISTRATION FOR DEFENSE (PAD! DISTRICTS
(INCL. ALASKA V
AND HAWAII) /
'Refinery capacity, 1000 BPD.
Source: Bureau of Mines
Figure III-l. Petroleum Administration for Defense (PAD) Districts
-------
Based on the Bureau of Mines figures for 1974, total U.S. refining
capacity for 1974 was 14,486,000 BPD. District III has by far the greatest
capacity (6,086,000 BPD). The four other districts, arranged in decreasing
order of capacity, are District II (3,950,000 BPD), District V (2,289,000
BPD), District I (1,643,000 BPD), and District IV (518,000 BPD). In the
period between 1960 and 1974, Districts II, III, and V experienced the great-
est growth.
Small (<30,000 BPD), non-integrated refineries represent over half of
the total number of refineries in the United States, while their combined
capacity is less than 10% of total U.S. throughput. These facilities include
operations whose primary products are materials such as asphalt and opera-
tions that are essentially topping refineries which produce a very small
number of products. These refineries generally market their products nearby.
Since the energy requirements and processing configurations vary widely
among small refiners, and since their production comprises such a small per-
centage of total U.S. production, they are not considered for purposes of
this study. However, because of their size, EPA regulations can place an
extreme burden on small refiners and could thus alter the basic competitive
structure of the industry.
B. ECONOMIC OUTLOOK
The number of refineries in the United States has decreased in the last
few decades (see Table III-2), while the average size of a refinery has
increased. Few new grassroot refineries have been built in the past five
years; however, changes have been made in existing refineries to reflect
changing technology and product demand, largely through expansion and revamp-
ing of units of existing refineries. Although there are several new facilities
in the planning stages, many such projects have been either cancelled or
greatly delayed primarily because of the uncertainty caused by unresolved
energy and environmental issues.
Growth in petroleum product demand within the next 10 years is expected
to be lower than historical growth rates, partly due to nearly zero gasoline
growth (50% of total petroleum products). Companies interviewed in connection
with this study agreed in general that:
1. Gasoline growth between now and 1985 will be much less than it was
for the 1965-1973 period. Projections by those interviewed ranged
from zero growth to 2% per year. This is attributed to improved
fuel economy for automotive engines and the trend among consumers
to purchase smaller automobiles.
2. Major growth areas in the next decade will be petrochemicals and
fuel oils, although these represent a relatively small fraction of
total petroleum products.
3. The jet fuel market will also see a slowdown in growth from that
experienced between 1965-1973.
11
-------
N>
TABLE III-2
SURVEY OF OPERATING REFINERIES IN THE UNITED STATES - 1962-1972
Charge Capacity (MMB/SD)
Catalytic
Operating Refining
,, . Capacity1
Vacuum
Thermal
Pate Plants (HMB/CT) (HMB/SP) Distillation Operation
1/1/62 299 10.01 10.59
1/1/63 293 9.92 10.46
1/1/64 288 10.18 10.72
1/1/65 275 10.25 10.76
1/1/66 265 10.25 10.75
1/1/67 261 10.45 10.95
1/1/68 269 11.14 11.66
1/1/69 263 11.57 12.08
1/1/70 262 12.15 12.65
1/1/71 253 12.68 13.28
1/1/72 247 13.09 13.71
Incremental Change
1962-1972 3.08 3.12
Z Crude 100.0 101.3
ITPC Questionnaire
& Expansion Data (HUB/CD)
1973-1978 1.8
X Curde 100.0
HlMB = million barrels
CD =• calendar day
SD - stream day
*Aromatic and isomerization reported
Source: Oil and Gas Journal, Annual
3.67
3.58
3.75
3.76
3.76
3.89
4.08
4.12
4,55
4,74
4.85
1.18
37,8
0.50
28.0
beginning
Refining
1.81
1.75
1.72
1.64
1.69
1.64
1.66
1.60
1.64
1.56
1.53
(0.28)
(9.0)
(0.18)
(1.0)
1/1/69,
Cracking
Fresh
Feed
3.75
3.89
3.99
3.99
3.96
3.95
4.18
4.25
4.37
4.51
4.57
0.82
26.3
0.20
11.0
Reports (January 1,
Recycle
1.47
1.55
1.62
1.57
1.53
1.65
1.60
1.55
1.49
1.46
1.26
(0.21)
(6.7)
0.0
0.0
Catalytic
Reforming
2.02
1.99
2.05
2.06
2.09
2.19
2.38
2.54
2.78
2,89
3.17
1.15
36.9
0.67
37.0
1962 through January
Catalytic Catalytic Catalytic
Hydro- Hydro- Hydro-
cracking refining treating
2.37
2.54
2.75
2.93
3.10
3.35
0.41 - 3.66
0.50 0.55 3.27
0.60 0.54 3.51
0.73 0.54 3.81
0.84 0.63 4.26
0.43 0.08 1.89
13.8 2.6 60.6
0.11 0.67 0.99
6.0 37.0 55.0
Alkyla-
tlon
0.46
0.49
0.50
0.53
0.55
0.60
0.65
0.67
0.75
0,78
0.82
0.36
11.5
0.13
7.0
Production Capacity
Catalytic
Polymeriza-
tion*
0.14
0.13
0.13
0.13
0.12
0.11
0.10
+0.25
0.29
0.31
0.29
-
-
0.14
8.0
Lube
0.21
0.20
0.20
0.21
0.21
0.21
0.21
0.20
0.21
0.22
0.22
0.01
0.3
0.18
1.0
(MMB/SD)
Asphalt
0.49
0.49
0.51
0.54
0.53
0.54
0.53
0.57
0.58
0.60
0.62
0.13
4.2
0.09
5.0
Coke
(MT/SD)
18.90
19.20
20.94
21.14
23.03
25.00
23.43
29.43
35.49
38.77
41.47
22.57
-
6.4
1, 1972); NPC Refining Survey Questionnaire (1973 through 1978).
-------
Another reason for a halt in expansion of the petroleum refining industry
is the rapid increase in the construction cost of refineries. The cost, cur-
rently estimated at between $3000 and $4000 per daily barrel is up from a
figure of $2000 per daily barrel of only a few years ago. The scarcity of
capital is a major factor in inhibiting refining growth within the United
States, particularly in light of uncertainties regarding future domestic
environmental and energy policies and other governmental regulations such
as divestiture.
13
-------
IV. COMPARISON OF CURRENT AND ALTERNATIVE PROCESSES
A. CRITERIA FOR ASSESSING OPTIONS
We applied a subjective screening to arrive at the final selection of
process alternatives for detailed analysis. The factors considered in this
screening are briefly discussed in the subsections below.
1. Probability of Implementation
The timeframe of the study extends to 1990 with emphasis on the nearer
term. In assessing potential process changes, the prospect of implementation
in this period were considered. Among a list of applicable refinery technolo-
gies, there will be different degrees of attractiveness due to differences in
commercial experience, reliability, product yields, and the like. For example,
flexicoking, flue gas desulfurization, residuum hydrodesulfurization,
methanol synthesis, and slurry coal partial oxidation do not connote the same
degree of implementability within the period of interest. An appreciation of
this variability was factored into the selection.
2. Pollution Control
Pollution regulations with which future process changes must comply include
the 1983 Best Available Technology Economically Achievable (BATEA) standards
for water effluents from refineries and New Source Performance Standards
(NSPS) for water discharges and air emissions, especially those limiting sulfur
emissions. This latter regulation affects the sulfur content of the refinery
fuel which must currently comply with existing local regulations within each
region. While pollution control aspects were factored into the selection
process, the overriding consideration was the potential for energy conserva-
tion. However, once the final options were selected, pollution control
aspects became the dominant concern.
3. Energy Considerations
The unit operations carried out within a refinery are, on balance, net
consumers of energy. Since better policing and waste heat recovery were not
in the scope of the study, the major consideration in the selection of energy-
conserving changes was the amount of form value improvement obtained. Pro-
cesses that improve the yields of LPG's, light, medium and heavy distillates
in deference to atmospheric and vacuum bottoms were heavily weighted. Specu-
lations on energy trends identified by the industry interviews were also
considered. These included a feeling that on the West Coast end-use control
14
-------
of methane (pipeline gas) is a possibility. Another possibility is that
the existing electric power rate structure which favors industrial users
may be overhauled resulting in an increased electricity charge to the refiner
at some unknown time in the future. Several factors, such as its hydrophilic
nature, will apparently preclude the use of methanol as an additive to motor
fuel.
4. Feedstock Availability
Due to declining domestic production and the reduction of Canadian
imports, changes in crude slate are certain during this time period. Alter-
native sources of domestic and imported crude will be required to make up
these deficiencies. The specific sources selected will depend on the geo-
graphical region. For example, on the West Coast, Alaskan North Slope crude
will be available in this time period, while on the East Coast the major
sources would be North Africa and the Middle East. The selection of process
options was made within the context of this changing feedstock environment.
Within the timeframe of interest, ADL does not see any significant amounts of
OCS gas and oil being produced off the East Coast. Exploratory wells have
yet to be drilled, and it would take 10 years before significant production
levels could be achieved.
5. Market Considerations
Several market considerations were factored into our evaluation of pos-
sible options. Specifically, in regard to product demands, gasoline growth
is expected to be small due to improvements in engine efficiency and
decreases in automobile weight. Product demand is expected to occur mainly
for the distillate and residual fuel products, e.g., jet fuels, kerosenes,
diesel fuels, No. 2 and industrial fuels. Essentially all companies ADL
contacted forecast zero or very small gasoline growth. Petrochemicals are
expected to grow at a relatively large rate. However, the relative impact of
petrochemical growth on energy consumption within refineries is expected to
be small.
The future market for asphalt and coke is difficult to estimate. The
West Coast industry representatives contacted expect that coke will continue
to be exported. Also, industry representatives believe that more and more
asphalt (resid) will be upgraded to middle distillates and gasolines. The
ease of this upgrading is very crude-^specific, Some refiners and districts
will have great difficulty in converting asphalt (resid) to more valuable
products and will have a much higher percentage of the crude barrel to con-
vert, e.g., PAD V. In PAD I, coking is not prevalent and asphalt must be
either sold or converted. If this asphalt cannot be sold and/or upgraded,
one of the alternatives is to burn it as fuel. For example, SOCAL at
Richmond has burning capability and has burned solvent de-asphalted bottoms
(with the addition of cutter stock).
15
-------
6. Process Economics
While it is difficult to generalize on refinery process economics, cer-
tain aspects were noted in our selection. For example, a potential alterna-
tive to asphalt conversion is direct combustion in process heaters and boilers.
In view of the capital investment required for conversion processing, direct
combustion could be a more economic alternative. Another economic factor
noted was that the cost per million Btu for flue gas desulfurization and resid
hydrodesulfurization is very close and the final choice depends on the condi-
tions imposed in a specific situation.
B. SELECTION OF STUDY ALTERNATIVES
Due to the variation and complexity of the process options available for
the refining of petroleum, and the uncertainty surrounding future product
demands, the selection of appropriate study alternatives was an important
subtask of this assessment. To ensure that reasonable alternatives were
identified, we conducted a series of interviews with industry representatives.
During these interviews, various potential processing changes were introduced
to determine the potential for implementation. Based upon the results of
these interviews, we selected three scenarios and five process options for
detailed study from a list of eleven possible candidates. The complete list of
options and descriptions of those which were not evaluated in full are briefly
discussed in Appendix E. The options retained are discussed below.
1. Option A: Utilization of Asphalt to Increase Yields of Higher Value
Products
a. Direct Combustion
To conserve higher form value products, asphalt could be used for direct
combustion in process furnaces and boilers. This would displace existing
imported natural gas, internally generated refinery fuel gas, and residual
fuel oil (containing asphalt as well as higher valued, medium and heavy gas
oil to reduce its viscosity and sulfur level). However, asphalt is generally
very high in sulfur content (2-5%) and is difficult to desulfurize economic-
ally because of the high levels of asphaltenes and metals which deposit on the
catalyst of the desulfurization process and make it inoperable.
Hence, the combustion of asphalt requires the availability of a reliable
flue gas desulfurization (FGD) process. Several refineries now use the Wellman-
Lord FGD process for S02 removal from Glaus plant tail gas. Exxon has used a
sodium-based FGD process for S02 removal from catalytic cracker regenerator
flue gas and the process is apparently operating satisfactorily. Of course,
FGD has been studied extensively for the utility industry.
16
-------
It is important to note that burning high-sulfur fuel, plus FGD, is
comparable in cost to indirect desulfurization of residual fuel oil and burn-
ing the lower sulfur fuel. Hence, because of the uncertain reliability of
existing FGD processes, there is not much incentive for a company to install
an FGD process in a refinery if lower sulfur fuel oil is available. However,
the alternative of burning asphalt has not been widely investigated, but is
examined in the present study.
b. Hydrocracking
Another means by which refiners will meet future demands for light, high
form valued products is by direct hydrocracking of residuum. In this process,
hydrogen and asphalt are contacted with a catalyst at elevated pressures and
temperatures to produce refinery gases, gasoline precursors, distillates, and
a byproduct low-sulfur fuel oil. Although the hydrocracking of gas oils is
widely practiced, the energy/environmental consequences of upgrading residuum
by this means has not been widely investigated, and is included in the present
s tudy.
Nelson (The Oil & Gas Journal, December 17, 1973, p. 69) presented a cost
comparison of different routes to produce a 1.5% sulfur fuel oil and a 0.5%
sulfur fuel oil. In general, according to his study, vis-breaking produced
the lowest cost fuel oil, and heavy oil cracking the highest cost fuel oil.
M.W. Kellogg (The Oil & Gas Journal, May 27, 1974, p. 75) responded to
Nelson's article and made the following points: "Our (MWK) studies have
indicated that hydrocracking (HDC) processing for low-sulfur fuels has parti-
cular merit as compared to direct desulfurization when:
1. The feed is high in metals, i.e., greater than about 75 ppm Ni + V;
2. The sulfur specifications in fuel oil are low — less than 0.3%;
3. It is desired to produce low-viscosity rather than high-viscosity
residual fuels;
4. The high steam-producing capability of the HDC process can be inte-
grated with overall refinery requirements in grassroot refineries.
(In essence, the HDC process utilizes the poorest portion of the
crudes (asphaltenes) to satisfy the major portion of the refinery
steam requirements);
5. Flexibility to alter distribution towards gasoline and lighter
products in place of low-sulfur fuels is desired."
The above discussion illustrates that the choice of process for an
existing refinery is clearly very complex, and while the process selected by
ADL may not be the best for all situations, it does represent a reasonable
choice.
17
-------
c. Flexicoking
Coking is a process wherein asphalt can be exposed to elevated tempera-
tures to crack it to higher form-valued light products, with coke produced as
a byproduct. The use of the process is restricted to those refiners having a
market for the coke. The concept is desirable as a means to convert low-
valued asphalt, and will be more widely practiced in future decades as the
coke market permits.
Flexicoking is basically an extension of the fluid coking process with
addition of a coke gasifier. The gasifier converts the coke formed into a
clean, low-sulfur gaseous fuel. The process can convert up to 99% of a
vacuum residuum into lighter (and more valuable) liquid and gas products.
Pilot plant data have been published for flexicoking of three different
residua: Iranian heavy, Bachaquero, and West Texas sour (after propane
de-asphalting). The published yield data are shown in Table IV-1.
The first commercial flexicoker, rated at 22,000 BPSD*, is under construc-
tion at Toa Oil Company's refinery in Kawaski, Japan, and is scheduled for
startup in spring 1976. Exxon Research and Engineering Company has recently
published operating data on a 750-BPSD* flexicoking pilot plant (The Oil & Gas
Journal, March 10, 1975, p. 53).
Flexicoking is clearly a process which has strong potential to upgrade
residuum and leave a minimum of heavy products for further disposal. Its use
must be evaluated relative to alternative means of accomplishing this
upgrading, including the energy/environmental consequences.
2. Option B; Internal Power Generation Using Asphalt
The existing electric power rate structure, which favors industrial users,
may be overhauled as a result of consumer pressures, resulting in an increased
electricity charge to the refiner. Industry representatives told ADL that if
a flat rate structure is implemented (such as is advocated by Massachusetts'
consumer groups), internal power generation will be economic for large
(100,000 BPD) refineries. Furthermore, since there are parallel pressures to
upgrade asphalt and to limit sales of high-sulfur products (such as asphalt),
a case was investigated to determine the energy/environmental effects of
generating power within the refinery using asphalt as an energy source. Inter-
nal generation of electrical power is currently practiced by many refiners,
although only in large refineries and not with an asphalt fuel. This is
technically feasible and will perhaps become economic at some time in the
near future. In principle, the power plant could burn coal, oil, or asphalt.
The burning of a high-sulfur fuel is predicated on the availability of an
operable and economic flue gas desulfurization process.
*BPSD = barrels per stream day
18
-------
TABLE IV-1
FLEXICOKER YIELDS FROM VARIOUS RESIDUA
Feed Properties
"API Gravity
Con. carbon, wt
Sulfur, wt %
Nitrogen, wt %
V + Ni, ppm
Iranian
Heavy
5.1
21.4
3.43
0.77
525
Bachaquero
2.6
26.5
3.66
0.81
1,040
West Texas
sour asphalt
-0.2
34.0
4.6
0.65
137
C3 and lighter
nCi,
C5/360° F
360°/975° F
Coke
Coke gas
wt %
9.9
1.3
0.1
0.5
11.0
50.8
1.2
LV %
15.4
55.1
---
15.6*
wt %
10.5
1:4
0.1
0.6
LV %
10.
44.
1.5
14.7
48.3
---
21.1*
wt %
11.3
1.5
0.1
0.6
9.2
33.4
2.0
LV %
13.4
36.9
30.0*
*FOEB basis
LV Liquid volume
Source: Oil & Gas Journal, March 10, 1975
3. Option C: Alternative Methods for Hydrogen Generation
Hydrogen is a critical feedstock for many refinery processing steps,
such as hydrocracking of heavy feedstocks into higher form-valued products
and desulfurization of fuel oils. We feel that the availability of hydrogen
will remain critical to the industry over the next several decades.
Essentially all manufactured hydrogen within a refinery is produced by
steam methane reforming. As natural gas becomes scarce - perhaps curtailed,
and certainly more expensive - alternative sources of hydrogen will become
more attractive. Among the alternative sources considered were:
a. Partial oxidation of residuum,
b. Coal, and
c. Naphtha and similar boiling-range materials.
Five companies were interviewed extensively to obtain their viewpoints on
the likely process routes to obtain hydrogen.
19
-------
All companies agreed that in the next decade or so there would be a
switch away from steam methane reforming to alternative feedstocks. Pres-
ently, the preferred feedstock, based on economics, is naphtha. One company
in California has completed the conversion of all its steam-methane reform-
ers to allow use of naphtha as a feedstock. This company has retained
methane as the fuel, but this may also be converted to naphtha.
Several economic studies showed that light naphtha (C5-235F) is the most
economic feedstock for hydrogen production (after methane). This conclusion
stems partly from the fact that naphtha of this boiling range is a "low"
octane gasoline component with poor lead susceptibility. These same studies
also indicated that coal is a poor feedstock for hydrogen production. The
choice of other feeds is determined by the relative prices of LPG, naphtha,
and resid, plus the fact that maintenance costs, in general, increase as the
gravity of the feed increases.
Although naphtha is an attractive feedstock now, price differentials and
availability may shift the preference toward coal or residuum over the next
decade. Since residuum is available in refineries and does not exhibit the
transportation/handling problems of coal, its use as a source of hydrogen is
most likely.
Partial oxidation of hydrocarbon stocks to make hydrogen is a proven
commercial process, and more than 100 plants are in operation using either
Shell or Texaco technologies. Most installations are not in the United States,
and the feedstocks used are generally lighter than residual oil. Standard
Oil of California has installed a partial oxidation process at its El Segundo
refinery to produce hydrogen from residual. Information available to ADL
indicated that the process is not now being used, and that SOCAL makes hydro-
gen at El Segundo from other feedstocks. The technology to operate the plant
with heavy oil is available, but operating costs are greater than for other
feedstocks.
Conversion of residual oil to hydrogen is a technically feasible option,
but the price of the hydrogen is, in general, not competitive. This conclu-
sion of course is subject to the values of alternate feedstocks, and to the
availability of alternate markets for residual, such as coke or heavy fuel
blending. In California, considerable coking capacity has been installed and
large quantities of coke are exported. Market projections indicate that coke
will continue to be exported in large amounts during the 1975 to 1985 period.
20
-------
C. REFINERY BASE LINE AND PROCESSING ALTERNATIVES
1. Refinery Base Line Used for Comparison
a. Refinery Simulation
To simulate existing U.S. petroleum refineries, we used three cluster
models to describe the regional characteristics of the refining industry and
the processing configurations typical of the regions. Each of these cluster
models simulates the average operation of three similar refineries located in
the same refining region.* The refining regions selected include the East
Coast (PAD I), Gulf Coast (PAD III), and West Coast (PAD V). The development
and calibration of these computer models was accomplished under other EPA
contracts with ADL (ADL, 1975a and 1975b). The final reports are in review.
b. Validation of Model
A critical objective in developing the model was to ensure that it
effectively represented "real" refineries, as well as the section of the
United States containing the refineries. When the models were assembled, an
extensive calibration effort was undertaken by Arthur D. Little, Inc., in
collaboration with representives of the Environmental Protection Agency and
an American Petroleum Institute/National Petroleum Refiners Association task
force.
Data on raw material intake, fuel consumption, and product make for each
of the refinery clusters and for the regions of the United States containing
these clusters were obtained from the Bureau of Mines. Direct operating data on
these refineries were compiled by representatives of the EPA. Processing
information was obtained from petroleum literature sources and from individual
industry sources. Using this processing information, we ran the individual
cluster models on the computer, checked results against the refinery data,
and updated them as required. We continued this task until each cluster
model was calibrated with the industry data, assuring an accurate representa-
tion of the refinery clusters being simulated.
These cluster models, therefore, represent typical refineries in the
specific refining regions in terms of crude type, processing configuration,
and product slate, but range in crude capacity from 160,000 to 220,000 BPD.
These production characteristics, along with the energy consumed by each
process unit, are summarized for the calibration cases in Appendix C.
Although the actual calibration runs are based upon 1973 Bureau of Mines data,
we believe they are generally representative of conditions to mid-1974. The
value of these models is that refinery operating characteristics, such as unit
capacities, fuel consumption, and sulfur distribution, can be determined for
future scenarios having different crude intakes, product makes and process
configurations.
*A list of actual refineries simulated by the cluster models as well as typical
flow sheets are provided in Appendix C.
21
-------
c. Study Base Line
In assessing the impact of processing changes in the refining industry,
we used a 1985 refinery configuration (existing refineries) and energy con-
sumption base line. We selected 1985 because currently there are two broad
energy-related trends at work which will significantly alter refinery opera-
tions as characterized by the 1974 calibration cases. These trends include:
• Phasing out of natural gas as a fuel in refineries, and
• Removal of lead from gasolines.
The effects of these trends are already in evidence and were factored
into the calibration runs. However, by 1985 when future process changes would
be fully implemented, we believe these underlying trends will have reached a
steady-state condition. We forecast that this steady-state condition will
find essentially no natural gas being used in refineries and a lead-free
gasoline pool. Since these shifts in energy utilization are expected to occur
and their effect could influence the conclusion of this assessment study, we
chose a base line that characterized refinery operations in 1985 for existing
refineries.
The refinery capacity and energy consumption data for 1985 operation
are summarixed in Appendix C. The shifts in energy utilization between
1974 and 1985 are highlighted in Table IV-2. The phaseout of natural gas
by 1985 has brought about an increase in the use of blended fuel oil for
refinery fuel. In addition, the total refinery fuel requirement has
increased by 1985. This is due to the removal of lead from gasoline and
will require the U.S. refining industry to manufacture gasoline with clear
(unleaded) octane numbers about four numbers higher than when manufacturing
leaded gasoline. This increased octane will be achieved primarily by upgrad-
ing existing catalytic reformers to operate at higher severities and by build-
ing new high-severity reformer capacity. However, operation of catalytic
reformers at high severity does not yield as much gasoline as does the present
low-severity operation, so additional crude oil and fuel are consumed in making
a fixed quantity of motor gasoline (ADL, 1975a).
d. Base Line Pollution Characterization
(1) Airborne Pollutants
The major airborne pollutants emitted by refineries have previously been
identified by process step (EPA, 1973) and a compilation of emission factors
is presented in Appendix D. The daily emission rates of the primary pollutants
of concern are tabulated by process in Tables IV-3, 4, and 5 for the three
base line refinery clusters. The sulfur dioxide emissions are based on
refinery sulfur balances for each cluster. The emission quantities for the
other pollutants were determined from the emission factors cited. Sulfur '
emissions from the Glaus plant are based on 99.95% recovery of the sulfur i
in the acid gas. Vacuum ejectors are the source of hydrocarbons associated
with vacuum distillation.
22
-------
TABLE IV-2
ANTICIPATED SHIFTS IN REFINERY ENERGY USAGE
CAUSED BY NATURAL GAS AND TEL PHASE-OUT
East Coast Gulf Coast West Coast
6
*FOE = Fuel Oil Equivalent, 6.3 x 10 Btu.
1974 1985 1974 1985 1974 1985
Crude Run, 103 BPD 188 198 222 218 155 164
Purchased Natural Gas, FOE/day1 2,500 5,400 6,390
Refinery Fuel, FOE/day1
Gas _ 4,810 6,990 5,450 6,880 7,190 7,500
Oil (blended) 7,210 9,640 5,350 10.700 2,140 11.690
Total Fuel, FOE/day1 14,520 16,630 16,200 17,580 15,720 19,190
Purchased Steam, 106 Ib/day 5.6 5.7 0.5 0.5 0.7 0
Electricity, 103 kWh/day 713.7 838.7 744.2 875 766.8 897.3
-------
TABLE IV-3
MAJOR AIRBORNE EMISSIONS
FROM BASE LINE REFINERY
Location: East Coast
Year: 1985
N)
•P-
Process/Pollutants
Combustion (heaters and
boilers)
- Gas-fired
- Oil-fired
Particulates
Clb/day)
8,979
881
8,098
• Fluid catalytic cracking 2,780
• Vacuum distillation Negligib]
• Glaus plant
SOX Hydrocarbons NOX
(Ib/day) (Ib/day) (Ib/day)
45,200
52,800
egligible
2,280
2,671
1,321
1,350
13,684
8,931
38,085
10,129
27,956
4,416
Negligible
Aldehydes
(Ib/day)
373
132
241
1,182
Negligible
Ammonia
(Ib/day)
Negligible
Negligible
Negligible
3,359
Negligible
Total emissions
11,759
100,280
25,286
42,501
1,555
3,359
Source: Arthur D. Little, Inc. estimates
-------
TABLE IV-4
MAJOR AIRBORNE EMISSIONS
FROM BASE LINE REFINERY
Location: Gulf Coast
Year: 1985
Process/Pollutants
Combustion (heaters and
boilers)
- Gas -fired
- Oil-fired
Fluid catalytic cracking
Vacuum distillation
Glaus plant
Particulates
(Ib/day)
9,855
867
8,988
3,585
Negligible
SOX Hydrocarbons NOX
(Ib/day) (Ib/day) (Ib/day)
27,600
8,400
Negligible
680
2,798
1,300
1,498
17,644
9,854
40,999
9,969
31,030
5,694
Negligible
Aldehydes
(Ib/day)
398
130 ,
268
1,524
Negligible
Ammonia
(Ib/day)
Negligible
Negligible
Negligible
4,331
Negligible
Total emissions
13,440
36,680
30,296
46,693
1,922
4,331
Source: Arthur D. Little, Inc. estimates
-------
TABLE IV-5
MAJOR AIRBORNE EMISSIONS
FROM BASE LINE REFINERY
Location: West Coast
Year: 1985
Process/Pollutants
• Combustion (heaters and
boilers)
- Gas-fired
- Oil-fired
• Fluid catalytic cracking
• Vacuum distillation
• Claus plant
Particulates
(lb/day)
10,765
945
9,820
1,708
Negligible
SOX
(lb/day)
58,800
7,600
Negligible
3,680
Hydrocarbons
(lb/day)
3,055
1,418
1,637
8,404
10,309
NOX
(lb/day)
44,769
10,868
33,901
2,712
Negligible
Aldehydes
(lb/day)
434
142
292
726
Negligible
Ammonia
(lb/day)
Negligible
Negligible
Negligible
2,063
Negligible
Total emissions
12,473
70,080
21,768
47,481
1,160
2,063
Source: Arthur D. Little, Inc. estimates
-------
(2) Wastewater
The major sources of refinery wastewater in descending order of
importance are cooling water blowdown, boiler blowdown, and process water.
Many of the constituents found in petroleum appear in the wastewater,
especially for those water streams which were in contact with petroleum pro-
ducts during processing. Constituents found in the wastewater include free
oil, dissolved hydrocarbons, sulfur and nitrogen compounds, coke, and inorganic
particulates. As a result, refinery wastewater has both a chemical (COD) and
biochemical (BOD) oxygen demand.
Using a recent survey of refinery raw waste loads (EPA, 1973), we
estimated typical constituent and total waste loadings for the reference
refineries; these are shown in Table IV-6. Treated effluent waste loads
meeting BATEA (1983) treatment levels are also shown in Table IV-6. A detailed
discussion of refinery pollution sources and loadings is presented in
Appendix D.
(3) Solid Waste
The nature and quantity of solid wastes emanating from refineries are
highly variable and still the subject of investigation. Solid wastes basically
fall into two main groups; namely, those that are generated continuously and
those generated intermittently. Continuous wastes (disposal frequency < 2
weeks) are generated in process units and wastewater systems and include spent
catalyst, coke fines, and biological sludges. Intermittent wastes are
generally a result of tank and process equipment cleanings and the volume
depends greatly upon the individual refinery housekeeping practices.
Using estimates of aggregated solid-waste generation in the United
States, we estimated representative solid-waste loadings for the three base
line refineries; they are shown in Table IV-7.
e. Summary of Pollution Control Costs
Wastewater treatment costs based upon the treatment steps described in
Appendix D were determined for each base line refinery, assuming total imple-
mentation of the 1985 BATEA levels for refineries. These costs are summarized
in Table IV-8. A detailed cost breakdown of the aggregate costs appearing in
Table IV-8 is presented in Appendix D.
The costs shown in Table IV-8 are for treatment systems handling the
entire wastewater generated by the refineries. It was necessary to use this
basis in assessing the implications of anticipated process changes, because
the wastewater from individual unit operations would not normally be treated
separately, but rather combined with the rest of the refinery effluents.
Hence, the net effect of a process change is to add or subtract an
incremental load from the basic treatment facility.
27
-------
TABLE IV-6
BASE CASE REFINERY - CHARACTERISTICS OF RAW AND TREATED PROCESS WASTEWATER
Ni
00
East/Gulf Coast Refinery (200,000 BPD)
'-.'dStewater Raw Wastewater (1)
Parameter (lb/day
BOD 5,000
TSS 1,920
COD 14 , 000
Oil & grease 1,920
Phenolics 200
Ammonia (as N) 700
Sulfide 700
Total chromium Varic
(mg/1)
91
35
254
35
3.6
12.7
12.7
;s
Hexavalent chromium Varies
Treated Effluent (2)
(Ib/day
260
260
1,420
50
1.0
316
4.4
13(4)
0.22(4
(mg/1)
4.7
4.7
25.8
0.9
0.018
5.7
0.08
-
-
West Coast Refinery (175,000 BPD)
Raw Wastewater (1)
(Ib/day
4,375
1,680
12,250
1,680
175
612
612
Var
(mg/1)
91
35
254
35
3.6
12.7
12.7
ies
Varies
Treated Effluent (2)
(Ib/day
227
227
1,243
44
0.88
277
3.85
(mg/1)
4.7
4.7
25.8
0.9
0.018
5.7
0.08
11.4(4)
0.19(4
)
Flow Rate
6,600,000 gpd
5,780,000 gpd
Notes: (1) Raw wastewater characteristics derived from EPA Development Document (EPA 440/1-73/014)
(2) Raw wastewater characteristics are for wastewater downstream of the plant API oil separator.
(3) Treated effluent loadings are based °n the Best Available Technology Economically Achievable
(BATEA) treatment level for 1983, as defined in "Effluent Guidelines and Standards -
Petroleum Refining", 40 CFR 417 FR May 9, 1974.
(4) Chromium - contaminated cooling water blowdown may be discharged as a separate waste stream.
(5) Waste loads include stormwater runoff from process areas but not from offsite facilities
such as tank farms.
-------
TABLE IV-7
ESTIMATION OF BASE CASE SOLID WASTE GENERATION
Solid Waste Scream
Neutralized HF
alkylation sludge
Coke fines
FCC catalyst fines
API separator sludge
Non- leaded product
tank storage
Slop oil emulsion solids
Cooling water sludge
Waste bio sludge2
Storm water tunoff silt
Boiler feed water
lime sludge
Kerosene filter clays
Exchanger bundle
cleaning sludge
Air fjotation float
Crude tank sludge
Cooling tower sludge
Leaded tank sludge
TOTAL
Total Estima
Solid Waste
(We
tpy
18,430
3,820
34,100
76,500
91,500
37,200
41,300
89,500
33,200
858,700
4,800
1,450
66,200
830
500
1,840
1,359,870
ted U • S • Re f incrv —
Base Case Refinery Solil-Waste Generation
Generation Rate1 200.000 BPD. East and Gulf 175,000 BPD. West
t Basis) Coast Refineries Coast Refinery
Tons/106 BPD
4.25
0.88
7.85
17.6
21.1
8.57
9.5
20.6
7.65
197.9
1.1
0.33
15.25
0.19
0.12
0.42
313.3
tpy
264
54.6
487
1,091
1,308
531
589
1,277
474
12,270
68
20.4
946
11.8
7.5
26
19,425
tpy
231
47.8
426
955
1,145
465
515
1,117
415
10,736
60
17.9
828
10.3
6.6
22.8
16,700
Notes; 1. Source: "Assessment ot Industrial Hazardous Waste Practice, Petroleum Refining - Draft Report,"
U.S. Environmental Protection Agency, January 1975.
2. Waste bio-sludge estimate is on a wet basis, and therefore differs from the estimates of incinerated
sludge presented in the water pollution section.
3. Unit loads are based on a total U.S. refining capacity of 14 x 106 BPD, or 4,340 x 106 barrels per
year.
29
-------
TABLE IV-8
SUMMARY OF BASE LINE WASTEWATER TREATMENT COSTS
(Total Annual Cost Including 20% Return on Investment)
East Gulf West
Coast Refinery Coast Refinery Coast Refinery
(200,000 BPD) (200.000 BPD) (175.000 BPD)
Base Case Refinery
Process wastewater
treatment costs 4,334 4,266 3,974
Cooling tower
blowdown treatment
costs 685 653 567
Total annual
wastewater
treatment costs 5,032 4,919 4,541
Note: Wastewater treatment costs are based on total implementation (from
ground up) of the BATEA level (Best Available Technology
Economically Achievable), 1983.
The situation for airborne emissions is somewhat different. The treat-
ment systems are usually designed for specific sources and installed near the
point of discharge. Furthermore, with all of the options considered, the
primary environmental concern is that of sulfur emission control. For
example, asphalt (vacuum resid) is a high-sulfur product which, when burned,
will generate S02 in concentrations exceeding present combustion source
standards.' Similarly, if asphalt is upgraded by hydrocracking or coking,
the resulting gaseous product will contain high concentrations of HoS. In
either case, these sulfur emissions represent an increase in the total sulfur
emission of the refinery, since with the base line case the asphalt product
is sold for non-combustion uses, i.e., roofing felt, paving materials, and
so on.
30
-------
Other pollutants, such as nitrogen oxides, hydrocarbons, and particu-
lates, will remain at approximately the same emission rate level with respect
to all of the technologies. In particular, we have made the following
assumptions about each of these pollutants:
• Hydrocarbons - Present refinery practice is to vent safety valves
and emergency vents as well as startup vents to a plant flare sys-
tem, thereby minimizing the most important source of fugitive hydro-
carbon emissions within the refinery. Other sources of fugitive
emissions (valve stems, pump and compressor seals, and petroleum
storage tanks) all require standard mechanical-type controls, such
as seals, floating roof tanks, and the like. However, these sources
will be the same for both the base case and the -new technologies.
• Nitrogen Oxides - Nitrogen oxide emissions are a problem only with
combustion sources and may differ slightly from one option to the
next. This is particularly true for the combustion of West Coast
asphalt which is expected to have a slightly higher fuel nitrogen
content than other asphalts. But since the control techniques for
nitrogen oxide are limited to combustion modifications, which are
currently incorporated in new combustion installations, we judged
that NOX emissions for the base case and for the options would
be about the same.
• Particulates - In the options where asphalt replaces gas as a fuel,
there will be an increase in particulate emissions, but these will
be controlled simultaneously with S02 emissions. In cases where
asphalt replaces fuel oil, there is very little difference in the
particulate emissions. In cases where asphalt is converted directly
to higher valued products, the processes being considered do not
generate particulate emissions.
Hence, the only control technologies considered for air pollution were:
1. The use of scrubbers to control flue gas S02 and particulates; and
2 . The use of sulfur recovery processes , such as a Glaus plant with
tailgas cleanup, to control ^S emissions in fuel gas streams.
Therefore, lumped pollution control costs for the entire refinery were not
determined in assessing the impact on the process changes. However, base
line pollution costs for those emissions affected by changes were determined
for comparison purposes. These base line costs, together with the control
costs for specific process changes, are presented under those sections dealing
with the particular energy-conserving process change. General control costs
for tailgas cleanup and flue gas desulfurization systems are presented in
Appendix D. The total solid waste produced by each base line refinery is
approximately as follows:
31
-------
Solid Waste Generated
Location (tpy)
East 19,400
Gulf 19,400
West 16,700
Annual solid waste disposal costs, based upon a typical unit disposal cost of
$5/ton, are $91,000 for the East and Gulf Coast refineries and $80,000 on the
West Coast.
f. Refining Operating Cost
Typical operating costs (excluding crude costs and product values) for
existing refineries in 1985 are summarized in Table IV-9. Because there is
considerable uncertainty in projecting future escalation and energy costs,
the operating costs are presented in constant 1975 dollars. Included in the
costs are the capital and operating costs associated with fuel desulfurization
and sulfur recovery to meet the existing regulations for combustion sources
previously noted. Claus plant sulfur recovery is 99.95%.
2. Process Change A-l: Direct Combustion of Asphalt in Process Heaters
and Boilers
This alternative was evaluated within the context of the East Coast
refinery cluster model.
a. Process Description and Current Status of Commercialization
In converting process heaters from the use of refinery gas and lighter
oils to asphalt, several factors must be accounted for. First, because
asphalt is very viscous, it must be heated and kept warm to maintain reason-
able flow rates in distribution lines around the refinery. To the extent
possible, lines are recirculated to keep them open and to avoid having the
asphalt "set up" in stagnant areas. Lines that are not recirculated must be
heat traced. All asphalt lines must be insulated for heat conservation.
Although asphalt combustion is technically feasible and the tendency is
toward this direction, it is not widely practiced today, and there is yet
some question about its economic attractiveness.
Figure IV-1 shows a typical flowsheet for circulating and burning asphalt
in refinery process heaters.
b. Potential for Energy Conservation
This scheme, as are the others related to utilizing asphalt, is intended
primarily to upgrade the overall form value of refinery products rather than
actually increasing the overall thermal efficiencies within the refinery.
Table IV-10 shows the overall refinery energy balance with and without direct
32
-------
TABLE IV-9
EXISTING REFINERY
CAPITAL INVESTMENTS AND OPERATING COSTS
(Constant 1975 dollars)
Crude Capacity 103 BPD
East
Coast
200
Gulf
Coast
200
West
Coast
170
Capital Investments ($ x 106)
(1st Qtr 1975 Basis)
Approximate Book Value
200.0
200.0
170.0
Operating Costs ($ x 103/day)
Purchased steam
Electricity
Cooling water
Maintenance
Manpower
Catalysts and chemicals
21.9
18.0
16.6
30.8
53.8
20.1
1.6
12.3
17.3
31.5
44.5
16.6
16.2
12.5
29.6
71.0
16.5
Fixed Costs
Depreciation
Capital charges1
TOTAL
$/Bbl
40.3
480.4
681.9
3.40
40.3
434.5
598.6
3.00
34.3
359.6
539.7
3.17
investment and working capital.
33
-------
VACUUM
BOTTOMS
(13,900 BPD)
CONDENSATE
DAY TANK
N2/ORGANICSTO
HEATER BURNER
N2 PURGE
PROCESS HEATERS
n i n
TV
HIGH
PRESSURE
STEAM
ATOMIZER
STEAM
/\
PROCESS
HEATER
rn
BURNER
figure IV-1. Vacuum Residue Distribution System
-------
TABLE IV-10
COMPARISON OF REFINERY ENERGY BALANCE WITH
AND WITHOUT DIRECT COMBUSTION OF ASPHALT
Energy In
Crude
r ' s
C4 s
Natural gasoline
FCC feed (storage)
Reformer feed
Electricity
Steam
TOTAL
East Coast
Base Line
(109 Btu/day)
1,157.7
8.8
32.5
62.2
33.6
8.9
8.2
1,311.9
Base Line with
Asphalt Combustion
(109 Btu/day)
1,157.7
8.8
32.5
62.2
33.6
8.9
9.7
1,313.4
Energy Out
VC2
Mixed olefins
Distillate products
Resid, asphalt, coke
TOTAL
27.1
958.2
201.0
1,186.3
16.9
27.1
1,019.0
123.3
1,186.3
Input (energy out) _
(energy in )
0.904
0.903
35
-------
combustion of asphalt. The overall refinery conversion efficiency is
unchanged. In this case, refinery gas, distillate, and residual oil pro-
duction are all increased through internal consumption of asphalt.
c. Pollution Control
(1) Identification of Pollutants
The sources and quantities of pollutants for direct combustion of asphalt
are identified in Figure IV-2 and Table IV-11. The only new source of pollu-
tion is the flue gas generated by burning asphalt.
(2) Water Pollution
It is anticipated that an East Coast refinery employing direct combustion
of asphalt will have a treated process wastewater effluent and a treated cool-
ing tower blowdown that will be of the same volume and composition as that
of the base case East Coast refinery. Consequently, the wastewater treatment
costs will also be the same.
Note, however, that the purpose of this option is to replace refinery
fuels, so that they may be sold outside the refinery. Depending on the sulfur
content of the incremental residual oil produced and the regional outlets,
it is possible that S02 scrubbers will be required on the customer's boilers.
These scrubbers would produce a wastewater and/or solid-waste stream requiring
control prior to discharge.
(3) Air Pollution
This method proposes increasing the form value of refinery product outputs
by burning excess asphalt (vacuum tower bottoms) rather than fuel oil or, in
some cases, refinery gas. The result of this is that more fuel oil will be
available for sale to outside consumers.
From an environmental point of view it is important to look at this
option from two perspectives: the national emission perspective and the
local refinery perspective. The implications of this option on both of these
perspectives is discussed below.
(a) National emission perspective - From a total energy point of view, this
option results in an increase in the amount of oil per barrel of crude
which is burned in a stationary combusion source. In the base case, the
refinery fuel is supplied from refinery gas and from fuel oil; the asphalt is
sold as a product. In option A-l, some of the refinery gas and all of the
fuel oil is displaced by asphalt. The products in this case are refinery
fuel gas and fuel oil which can be sold as fuel and will eventually be
burned. The difference, then, is:
(1) Although the same amounts of refinery gas and fuel oil are burned
in both cases, the location of the combustion source is changed,
since in the base case the combustion is concentrated at the local
refinery, while with option A-l the combustion sources are distri-
buted throughout the marketing area of the refinery; and
36
-------
,820 BPD)
BOILERS
ATMOSPHERIC
DISTILLATION
HEATERS
VACUUM
DISTILLATION
HEATERS
OTHER
PROCESS
HEATERS
FLUE GASES
LEGEND
EMISSIONS
Figure IV-2. Pollution Source Identification - Asphalt Combustion
37
-------
TABLE IV-11
ASPHALT COMBUSTION POLLUTION PROFILE
(Basis: 11,820 BPD/day asphalt burned)1
Stream
No.
Description
Flue gases (collective)
Pollutant
SO
x
Particulate
Hydrocarbons
NO
x
Aldehydes
Estimated Emission
Rate O.b/br)
Uncontrolled
15,395
502
83
1,729
15
112,330 FOE I!
(2) The use of asphalt is changed from one of construction materials
(paving, roofing, etc.) in the base case to one of a fuel (for
boilers and process heaters), thereby increasing the amount of
oil burned.
The total emissions from the refinery will not only change signifi-
cantly because the uncontrolled emission from asphalt combustion is greater
than emissions from refinery fuel combustion, but emissions due to petroleum
combustion by the refinery's customers will also increase. The impact that
this will have on a region's total emissions, of course, will depend on
what fuel is used in lieu of the added available oil.
The most important emission associated with this fuel replacement is
oxides of sulfur. The control of this pollutant can be achieved either at
the combustion source using flue gas desulfurization or at the refinery
using hydrodesulfurization and fuel oil blending.
(b) Local refinery perspective - From the point of view of the local
refinery, this alternative amounts to form value upgrading through fuel
switching. Instead of selling asphalt as a product, the refinery will be
selling a higher grade fuel oil as a product. The uncontrolled emissions
at the refinery will, however, increase with the burning of asphalt because
of its higher sulfur composition and ash content.
38
-------
Under present operating practice at refineries, this option will
result in a significant increase in the amount of pollution control
required. At the present time refineries blend fuel oil with other low-
sulfur feedstocks so that the blended fuel used in the refinery remains with-
in acceptable limits for combustion without stack gas sulfur controls. This
practice may come under increasing government pressure to sell rather than
burn higher form value products.
(c) Control technology - The appropriate control technology for this option
is flue gas desulfurization (FGD) for asphalt combustion sources. The base
line comparison is hydrodesulfurization and blending (indirect desulfurization)
of fuel oil.
Specific technological considerations relating to these different control
technologies have been discussed many times in previous EPA reports and will
not be elaborated on in detail here. Examples of the cost of control of these
alternatives for a 250 million Btu/hr source are shown in Table IV-12. It is
important to point out that control costs depend on the size of the combustion
unit being controlled. But in a given refinery the number or size of process
heaters for steam boilers is widely variable and often smaller than the
example shown. For these small sources, the capital investments for FGD are
highly speculative. However, the estimate is sufficient for showing the
relative differences in the two cases being considered. In general, the unit
cost will be higher for smaller sources.
Generally, fuel oil used within the refinery is a blend of both high-
and low-sulfur feedstocks, such that the resulting mixture has a sulfur
content within the limits allowed for uncontrolled stationary combustion
sources. As an indicator of the implied environmental costs of this strategy,
we have modeled this strategy (somewhat simplistically) as follows: a portion
of each barrel of high-sulfur residual fuel oil is desulfurized so that, when
recombined, the blended oil will meet local standards. For example, consider
a 2% sulfur residual fuel oil available in a refinery, which can be desulfur-
ized to approximately 0.3% sulfur. According to the blending model, approxi-
mately 82% of the oil would have to be desulfurized before the final blend
could meet a standard of approximately 0.6% sulfur. If hydrodesulfurization
costs approximately $3.00/bbl, this amounts to a net cost of 390/10 Btu of
fuel heating value. As can be seen from Table IV-12, the cost for the hydro-
desulfurization/blending option is less than the cost for flue gas desulfuri-
zation. Clearly, these averages are only illustrative and do not represent
all refinery situations, but they do tend to show the rationale behind the
blending strategy adopted by most refineries throughout the country.
That being the case, one is inclined to believe that a more logical
strategy might be to retain the fuel oil and refinery gas within the refinery
as fuels and to export asphalt to large power plants. Although asphalt is
more difficult to burn than residual oil because of the greater viscosity, it
is easier to burn than coal, for example.
39
-------
TABLE IV-12
EXAMPLE OF S02 CONTROL FOR PROCESS HEATER OR BOILER1
Basis: 250 x 106 Btu/hr (heat input), 2% Sulfur
Flue Gas
Desulfurization
Total capital cost, $000 2,161
Operating cost, $000/yr
Variable costs:
Labor, 1 man/shift (incl. supv. & overhead) @ $14.85 130
Maintenance, @ 5% of direct capital 83
Utilities
- Electric power, 240 kWh/106 scf @ $0.03/kWh 189
- Water, 50 gpm <§ $0.35/103 gal 9
- Fuel, 2.5 x 106 Btu/ton of S @ $2.17/106 Btu 7
Total -variable costs 418
Fixed costs:
Depreciation, 16 years 135
Insurance & taxes, @ 2% of capital 43
Total fixed costs 178
Total production cost 596
Credit for Sulfuric Acid, @ $25/ton (net) (93)
Return on investment, @ 20% of capital 432
Total Annual Cost, $000/yr 935
Unit cost, $/106 Btu $0.47/106 Btu
Comparative cost for hydrodesulfurization/blending,
0.82 bbi/bbl @ $3.00/bbJ $0.39/106 Btu
Based on MgO scrubbing, sulfuric acid recovery.
40
-------
It is unlikely that utilities will rapidly (or willingly) change
over to firing a difficult fuel, like asphalt, particularly when the
Government policy is to switch electric utilities onto coal. A more
probable strategy for utilizing the heavier constituents of crude is through
further processing of the bottoms, as suggested in the other options relating
to this strategy.
(4) Solid Waste
Implementation of direct combustion of asphalt will not appreciably
alter the quantity or characteristics of the base case East Coast refinery
total solid-waste stream.
A sulfuric acid product is produced from the FGD systems, part of
which might be used to offset acid requirements for alkylation, depending on
acid purity. Alternatively the acid would presumably be marketed; however,
no credit or disposal cost was assigned to this byproduct.
d. Cost Factors
The conversion of process heaters from refinery fuel to asphalt would
entail considerable expense relative to the initial investment in heaters.
Not only would a fuel day tank and fuel pumps be required, but heaters and
traced and insulated piping would also be required. Further, steam would
be required for atomization to ensure clean burning of the fuel. Finally,
the burners themselves would have to be replaced by new combination fuel
burners, a costly investment.
The total cost, including pollution controls, to convert to asphalt
combustion on the East Coast is shown in Table IV-13. The cost of controlling
SOX emissions is clearly dominant.
e. Technical Considerations
Several technical factors would affect the decision to go to direct com-
bustion of asphalt. Since this material contains more sulfur and ash than
other fractions, and these will generally be high enough to require emission
controls, the economics of installing the controls on these dispersed,
relatively small heaters may be prohibitive. We set a criterion of a firing
rate of 35 x 10^ Btu/hr, below which asphalt would not be substituted in a
process heater, to avoid the need for small, dedicated pollution control
devices. By this method more than 98% of the refinery fuel would be asphalt
in a typical 1985 East Coast refinery.
Another consideration was that the nitrogen content of asphalt is higher
than that of natural gas and light oils, and combustion may result in
increased NOX emissions. Injection of steam or other means to moderate the
flame temperatures may be required. As mentioned earlier, atomizing steam
injection at a rate of 0.1-0.3 Ib steam/lb fuel will be required for atomiza-
tion to ensure clean burning with a minimum of soot formation.
41
-------
TABLE IV-13
PRODUCTION COSTS: OPTION A-l (DIRECT COMBUSTION)
Product: Process Heat
Dally Capacity: 77,680 x 10 Btu
Process: Direct Combustion
Fixed Investment: SI.800.OOP
Location: East Coast
Depreciation
Period (yr): 16
Year Used for
Costing Purposes: 1975
Stream Davs/Yr.: 330
338 x 10*
8000 kWh
Ib
3% of CAP
VARIABLE COSTS
Rev Materials
Byproduct Credits
Energy
• Purchased Fuel
• Purchased Steam
• Electric Power Purchased
• Miscellaneous
Energy Credits
Water
• Process (Consumption)
• Cooling (Circulating rate)
Direct Operating Labor (Wages)
Direct Supervisory Wages
Maintenance Labor
Maintenance Supervision
Maintenance Materials and Supplies
Labor Overhead
Misc. Variable Costs/Credits3
Royalty Payments
FIXED COSTS
Plant Overhead
Local Taxes and Insurance 23
Depreciation 16 yrs. S.L.
TOTAL PRODUCTION COSTS
Return on Investment (pretax) 20%
POLLUTION CONTROL (Incremental)
TOTAL
e.g., miscellaneous chemicals, catalysts, supplies, services.
Units Used in
Costing or
Annual Cost
Basis
$/Unit
3.85/10 Ib
$0.03/kWh
Annual
Cost
(103)
1,300.0
0.2
36
112.5
1,502.7
360.0
2.051.0
3,913.7
42
-------
In general, the turndown ratios of gas-fired burners are about 10-15:1
while for heavy oils they may be only 4-5:1. For most refinery equipment,
which will usually run at or near full capacity, this should not prove a
serious drawback, but it may impact on the refiner's decision to convert.
For flexibility, we have assumed that, given the option, the refiner
would install combination burners, i.e., those which would be capable of
burning gas or oil. This has been incorporated into the economics of
Section C-2d.
The need for recirculation and asphalt heating have already been
discussed in Section C-2a.
f. Effect on Intermediate and Final Products
This option is intended primarily to free up the refinery gas and blended
fuel oil utilized as refinery fuel by substituting vacuum residue as illus-
trated earlier in Table IV-10. Therefore, incremental increases in products
of higher form value are obtained while another of low form value is consumed
rather than exported.
3. Process Change A-2: Hydrocracking of Heavy Bottoms
This alternative was evaluated within the context of the West Coast
refining region.
a. Description and Current Status
The H-oil process has been chosen to exemplify heavy-ends hydrocracking
processes. Figure IV-3 is a schematic of the process. Hydrogen and heavy
oils are reacted in a novel reactor system - the ebullated bed. In this
three-phase system, solid catalyst is maintained in continuous random motion
by upflow of the liquid phase and hydrogen. Catalyst can be added to and
withdrawn from the unit without shutting it down. The overhead vapors are
quenched with direct water injection, which precludes the formation of plugs
of sulfate salts or polysulfides. The liquid products are then fractionated
to provide mostly intermediates for further processing. A small purge is
drawn from the recycle hydrogen to prevent the buildup of inerts. This
stream goes to amine scrubbing to remove H2S and is burned as refinery fuel.
The H-oil process has been implemented at four refineries worldwide, with
capacity totaling 69,000 BPD. However, an explosion in an H-oil unit at the
Exxon Bayway refinery has temporarily halted the construction of these units
until the cause is determined. Nevertheless, it is a good example of resid
hydroprocessing technology. There are other resid hydrotreating/hydrocracking
processes available (Exxon - Residfining, Chevron - Isomax), all of which
could not be examined in this study because of time limitations.
In evaluating the incremental emissions from this process change, a feed
consisting of asphalt product (2,070 BPD) and atmospheric bottoms (9,240 BPD)
which otherwise would be blended into low-sulfur product fuel oil, was chosen.
In addition, 900 BPD of asphalt feed must be burned as refinery fuel to dis-
place refinery gas, which is required for producing 12.5 x 106 scf/day of
hydrogen by steam reforming.
43
-------
OIL
CHARGE
HYDROGEN
12.5 X 106
SCF/D
RECYCLE HYDROGEN
;
H-OIL
REACTORS
X~l
^^
STEAM
GAS
2270 BPD
LOW SULFUR
FUEL OIL
8360 BPD
Figure IV-3. H-Oil
-------
b. Potential for Energy Conservation
The process has value for converting heavy ends to lighter fuels. The
net make of refinery gas is about 100 FOE/day since the fuel requirement for
high purity hydrogen production is more than half the heating value of both
the methane and ethane produced. However, the LPG and C5-650°F products are
increased by 540 BPD and 5,330 BPD, respectively. The overall thermal
efficiency (useful Btu out/Btu in) for the H-oil process is 92%. Most of
the loss in thermal efficiency is due to the hydrogen production necessary for
H-oil, which amounts to 1,200 scf/bbl of intake, or 12.5 x 106 scf/day. This
corresponds to a 24% increase in hydrogen generating capacity above that for
the base line refinery. The effect on the thermal efficiency of the refinery
is to lower it slightly, as shown by Table IV-14.
c. Pollution Control
(1) Identification of Pollutants
The major emission sources associated with Option A-2 are indicated in
Figure IV-4 and identified in Table IV-15. Two wastewater streams are generated.
One is created by the quench water injected into the vapor stream downstream
of the reactors and contains small quantities of I^S, NHg, and hydrogen
cyanide. A second wastewater stream - not indicated on Figure IV-4—is cooling
tower blowdown, approximately 57,000 gpd (1.5% of circulation rate).
The major solid emission is 3,100 Ib/day of spent cobalt-molybdate-on-
alumina catalyst (containing 20% heavy metals and 20% petroleum coke).
There are three sources of air emissions. Two are solely emissions of
SOX from burning the recycle hydrogen purge gas (purge is 1% of recycle rate)
and from burning asphalt to displace refinery gas for hydrogen production. The
remaining potential emission is hydrogen sulfide from the acid gas removal
system used to treat the product gas made. This stream will ultimately be
controlled with a Glaus plus tailgas cleanup system. All the emission rates
listed represent additions to the base line emissions created by incorporating
heavy-ends hydrocracking.
(2) Water Pollution
It is anticipated that a West Coast refinery employing heavy-bottoms hydro-
cracking will have essentially the same wastewater volume and characteristics
as the base case West Coast refinery. The only incremental (over the base
case) waste load is a small sour water (sulfide-containing) stream which
increases the total process wastewater flow rate from 5.78 to 5.795 mgd.
Due to its high concentration of hydrogen sulfide and ammonia, the sour
water stream must be subjected to stripping prior to discharge into the central
wastewater treatment facility. A certain amount of ammonia and sulfide removal
can be expected in the central treatment facility. However, there will be an
incremental residual, and it is therefore reasonable to expect that both the
ammonia and sulfide concentration of the total treated effluent will be slightly
higher than that of the base case.
45
-------
TABLE IV-14
COMPARISON OF REFINERY ENERGY BALANCE
WITH AND WITHOUT HEAVY-ENDS HYDROCRACKING
Base Line with Heavy-
West Coast Base Line Ends Hydrocracking
(109 Btu/day) (109 Btu/day)
Energy In
Crude
Vs
Natural gasoline
Fluid cat. cracker feed
Refinery feed
Electricity
Steam
Total
960.6
3.2
5.0
20.2
10.6
9.5
1,009.1
960.6
3.2
5.0
20.2
10.6
10.8
1,010.4
Energy Out
Refinery gas
Mixed olefins
Distillates
Resid, vac. bottoms, tar, coke
Total
7.6
682.6
259.6
949.8
0.6
12.0
734.2
197.8
944.6
(Energy out) _
(Energy in)
0.941
0.935
46
-------
FEED (11,310 BPD)
PRODUCT
GAS
HYDROGEN
MAKE-UP
(12.5X 106)
PURGE
ACID GAS
REMOVAL
H-OIL REACTORS
H2
RECYCLE
DISTILLATES
LEGEIMD
© rWASTEWATER
^ :AIRBORNE EMISSIONS
|T| :SOLID WASTE
SEPARATORS
FRACTIONATION
TAR
TO REFINERY FUEL
(900 BPD)
WATER
INJECTION
SOUR WATER
NAPHTHA
HEAVY GAS OIL
Figure
Identification of Pollution Sources from Hydrocracking
47
-------
TABLE IV-15
SUMMARY OF ADDITION TO BASE LINE
EMISSIONS DUE TO HEAVY-ENDS HYDROCRACKING
Stream No.
Water Pollution, gpd
Wl
W2
Air Pollution, Ib/day
A,
Description
Wa t er inj e c t ion
Cooling water
Asphalt to
refinery fuel
Purge &as to
refinery fuel
Pollutant
Sour water
Slowdown
Particulates
SO
x
SO
x
Acid gas stream Combined sulfur
Uncontrolled
Emission Rate
14,980
57,000
674
12,748
715 Ib/day
54,530 Ib/day
Solid Waste, tpd
S-,
Spent catalyst
Wet solid
1.6
48
-------
The volume and composition of the cooling tower blowdown is
expected to be nearly identical to that of the base case.
Process wastewater treatment cost estimates are presented in
Table IV-16. The total yearly process wastewater treatment cost is only
1.8% greater than that of the base case ($4,046,000/yr versus $3,974,000/yr).
In terms of both treated effluent waste loads and treatment costs, the
water pollution impact of implementing this alternative is negligible.
(3) Air Pollution
In this option, the asphalt is used as * feedstock for a hydrocracking
process such as H-oil or Isomax in which the heavy bottoms are converted to
lighter fuel oils and gaseous products. The pollutants of concern in this
option are l^S generated in the gaseous products and SC>2 generated from the
combustion of a small amount of asphalt. The gases from the H-oil reactor
will pass through an amine scrubbing system to remove H2S and C02- These are
sent to a Glaus plant for sulfur control. Since a refinery normally would
have a Claus plant, the cost of control for this option is only the incremental
cost required to expand the Claus plant to handle the additional sulfur load.
In Table IV-17, the costs of this option are compared to the costs for the
base case. Note that by 1985 a sulfur recovery of approximatley 99.9% will be
required by most states and probably federal regulation as well. The hydro-
cracking case results in a net increase in sulfur of approximately 20% and a
corresponding increase in sulfur control costs of approximately 12%.
In addition to the sulfur control costs for hydrotreating, the equivalent
of 900 BPD of asphalt also has to be burned in the process heaters to free up
refinery gas which can be used to generate the additional hydrogen needed for
the hydrotreater. Since the asphalt has a sulfur content higher than the
maximum uncontrolled sulfur content of a fuel, flue gas desulfurization will be
required. If all of the asphalt were burned in a single process heater, the
size would be approximately 240 x 10° Btu/hr and the cost of control would be
comparable to those shown previously in Table IV-12. Since the actual distri-
bution of the process equipment accepting asphalt as a fuel is not known, we
estimated the S02 control costs at approximately 50c/106 Btu. As can be seen
from Table IV-17, the estimated cost for flue gas desulfurization is about the
same as the cost for sulfur control for the hydrocracking step, even though
the former controls only one-tenth as much sulfur. The major reason for this
disproportionality is that the removal of acid gas benefits from the established
economy of scale inherent in incremental increases in Claus plant capacity;
whereas flue gas desulfurization, particularly on a scale as small as the one
considered here, cannot take advantage of any economy of scale. Therefore, the
total cost of controlling sulfur for this option is twice the base case.
The conclusions one must draw from the above analysis are similar to those
for Option A-l, i.e., flue gas desulfurization is a relatively expensive
alternative when applied to small-scale combustion sources. Consequently, low-
sulfur, blended fuel oil should be used in place of refinery gas since con-
siderably lower environmental control costs are incurred.
49
-------
TABLE IV-16
ALTERNATIVE A-2
WEST COAST REFINERY WITH HEAVY-BOTTOMS HYDROCRACKING
PROCESS WASTEWATER TREATMENT COSTS
Basis: 175,000 BPD, 330 days/year
Capital Investment: $10,680,000
Variable Cost
Operating labor (including
supervision and overhead)
Maintenance (including labor
and overhead)
Chemicals
Lime
Phosphoric acid
Chlorine
Coagulant aid
Replacement carbon
Fuel (gas)
Steam
Electrical power
Wastewater treatment sludge
Disposal
• Incinerator ash
• Stretford .purge water
Total variable cost
Fixed Costs
Depreciation @ 6.25%
Taxes & insurance @ 2%
Total fixed cost
Total annual cost
Return on investment
Total
Notes:
Yearly
Quantity
Cost Per
Unit Quantity
Yearly Cost
($/yr)
16060 m-hr/yr
795 tpy
22 tpy
75 tpy
31,800 Ib/yr
108,300 Ib/yr
6,500 MM Btu/yr
14,100 M Ib/yr
2,649,000 kWh/yr
224 tpy
5456 tpy
$17.15/m-hr
$32.50/ton
$440/ton
$140/ton
$1.00/lb
$0.40/lb
$1.31/Btu x
$4.20/lb x ]
$0.0211/kWh
$5.00/ton
$15.00/ton
275,000
427,200
24,700
9,700
11,100
31,800
, 43,300
10° 8,500
10 59,200
55,900
1,100
81,800
$1,029,300
667,500
213.600
$881,100
$1,910,400
$2.136,000
$4,046,400
1) Capital investment adjusted to the 1975 level (ENR
Construction Cost Index - 2126).
2) Wastewater treatment costs are based on total implementation
(from ground up) of the BATEA level (Best Available Tech-
nology Economically Achievable), 1983.
3) Cost estimates are for the specific examples, and are in no
way intended to represent industry-wide treatment costs.
50
-------
TABLE IV-17
SULFUR CONTROL COSTS FOR BASE LINE AND WITH HYDROCRACKING
(OPTION A-2)
with
Base Line Hydrocracking
Inlet Sulfur Load, long ton per day 159 182
Capital Cost, $000
Glaus plant
Tailgas cleanup
Total
Annual Operating Cost, $000/yr
Variable costs:
Labor
- Direct (1 man/shift @ $6.75/hr) 59 59
- Supervision
-------
(4) Solid Waste
Implementation of heavy-bottoms hydrocracking will slightly alter the
total quantity of refinery solid waste. This process will require the
disposal of a chrome-moly catalyst.
It is estimated that the waste chrome-moly catalyst will be generated at
a rate of 480 tpy, thus increasing the base case total refinery solid-waste
stream from 16,700 to 17,180 tpy, or 3%.
d. Cost Factors
The additional costs associated with heavy-ends hydrocracking are dis-
played in Table IV-18. The total - $6.9 x 106/yr or $20,700/day - corresponds
to $0.32/106 Btu of product ($2.00/FOE). No sulfur credit was taken for 25.9
tons of elemental sulfur recovered. The costs developed in Table IV-18
include facilities for increased hydrogen production.
The capital investment needed for this option is $14.7 million, of which
hydrocracking accounts for $11.1 million.
e. Technical Considerations
It was assumed, for this case, that some asphalt could be burned in
process heaters, thus freeing refinery gas for hydrogen manufacture.
Some resid hydrocracking processes incorporate a solvent de-asphalting
step prior to hydrocracking to remove heavy metals, thus prolonging catalyst
life. This process step has not been investigated here, but it would most
likely decrease only the solid catalyst purge. Additional water treatment
would be necessary since steam distillation is usually required for solvent
recovery after the de-asphalting step.
f. Effect on Intermediate and Final Products
Based on 10,410 BPD to the H-oil unit, the yield structure is as shown in
Table IV-19. Most of the C]/C2 is consumed for process heat, but all other
products, except the tar, are available for further upgrading in the refinery.
A comparison of the base line product slate with the product slate, including
heavy-ends.hydrocracking, is given in Table IV-20.
4. Process Change A-3; Flexicoking
a. Process Description and Current Status
This option was assessed within the confines of the East Coast cluster
which has a high yield of asphalt and no markets for coke. Flexicoking is the
combination of fluid coking with coke gasification. Although fluid coking
is a commercially available technology, there are no commercially operating
flexicokers. However, the process has been selected for installation by a
Japanese refiner and a process development unit has been successfully
operated by Exxon.
52
-------
TABLE IV-18
PRODUCTION COSTS: OPTION A-2 (RESID HYDROCRACKING)
Naphtha, Distillate,
Product: I.PC. Tar
Process: Rcsld HydroerncHnn
Byproducts: Sulfur
Annual/Capacity: 11,310 BPD
Batch/ContInuous:
Fixed Investment:
Stream Days/Yr.:
Location: West Coast
Depreciation
Period (yr): 16
Year Used for
Costing Purposes:
330
VARIABLE COSTS
Raw Materials
• Atm. Bottoms, BPD
• Vac. Bottoms, BPD
• Catalyst and Chemicals
Byproduct Credits
Energy
• Purchased Steam (10J Ib/day)
CkWh/day)
• Miscellaneous
Energy Credits
Water
• Process (Consumption) 10^
gal/day
• Cooling (circulating rate)
go I /day
Direct Operating -«bor (Wages)
Direct Superv. Wages 10Z of
Dlr. Labor
Maintenance Labor
Maintenance Supervision
Maintenance Materials and
Supplies
Labor Overhead, 40Z of Dlr.
Labor
Misc. Variable Costs/Credits8
Royalty Payments
FIXED COSTS
Plant Overhead, 100Z of Dlr.
Labor
Local Taxes and Insurance ,
21 of Cap. Inv.
Depreciation 6.25%/year
TOTAL PRODUCTION COSTS
Return on Investment (pretax)
20% of Cap. Inv.
POLLUTION CONTROL (Incremental)
TOTAL
Units Used In
Costing or
Annual Cost
Basis
9,240
2,070
116
1 ?Q flflrt
J.£7 jUUU
15
3,780
3 men/shift
M.A.
5/Unlt
51,310/day
S4-20/103 Ib
$0.0211
50.35/103 p,al
$0.0a/101 gal
$6.75/hr
$l,210/day
Annual
Cost
(103)
432.3
160.8
898 . 2
1.7
54.9
177.14
17.7
399.3
78.0
195.1
280.0
875.0
3,570.4
2,800.0
1,026. u
7,396.4
fle.g., mis'* i.1 ".aeons chemicals, catalysts, supplies, services.
53
-------
TABLE IV-19
PRODUCTS FROM HEAVY-ENDS HYDROCRACKING
BPD
Feed
Asphalt
Atmospheric
Total 10,410
Product
VC2
C3/C4
C -180"F
180-400°F
400-650°F
650 + gas oil
Tar
Total 11,170 (excluding
Net volume increase = U'L™ ^p0*""0 * 1°0
TABLE IV-20
COMPARISON OF PRODUCT SLATES FOR THE WEST COAST BASE LINE
WITH THE INCORPORATION OF HEAVY-ENDS HYDROCRACKING
(1000 BPD)
LPC
High-Btu gas
Unleaded gasoline
Naphtha
No. 2 distillate
Jet fuel
Kerosene
Residual fuel oil
Asphalt
Naphtha intermediate
Gas oil intermediate
Tar
Lube stocks
Coke
BTX
Petrochemicals feed
West Coast
Base Line (1985)
0.04
70.3
3.9
22.7
20.4
0.2
31.3
2.1
0.4
7.8
4.0
1.3
Base Line with
Hydrocracking
0.6
0.1 (FOE)
70.3
3.9
22.7
20.4
0.2
22.1
2.3
6.9
1.5
0.4
7.8
4.0
1.3
54
-------
Figure IV-5 is a block flow diagram of the flexicoking process.
Atmospheric and vacuum bottoms can be converted to high-Btu reactor gas,
low-Btu gas from the coke (flexigas), coker naphtha, and gas oil. Essen-
tially three units comprise the flexicoker - a reactor, a coke heater-
devolatizer, and a coke gasifier - all of which are operated as fluidized
beds.
The resid feed is injected into the reactor, where it is thermally
cracked to vapor products and coke. The vapors are quenched and scrubbed
overhead to remove entrained coke. The lighter fractions proceed overhead to
a fractionating section.
Coke from the reactor circulates to the heater, where it is devolatilized
to yield hydrocarbon gas and residual coke. The residual coke is sent to a
gasifier where greater than 90% is gasified at elevated temperatures with
steam and air.
The gasifier offgas is directed back to the heater-devolatilizer for
recovery of heat and then is cooled further before fines removal. The gas
passes to a Stretford unit for sulfur recovery.
The flexigas has a low-Btu value (~100-130 Btu/scf), and is used to dis-
place high-Btu refinery gas from process heaters. The reactor gas from the
fluid coker is a high-Btu gas which could be sold after sulfur removal.
A small coke purge is withdrawn from the system, containing about 2% of
the feed sulfur and 99% of the feed metals. The combined solids from the
coke purge and fines removal amount to 2% (by weight) of the fresh feed.
The entire East Coast base line asphalt product - 18,700 BPD - was routed
to the flexicoker for conversion to light liquids and gas. As shown in
Figure IV-5, the products are 2,315 FOE/day of low-Btu flexigas, 2,077 FOE/day
reactor gas, 348 BPD of LPG, 2,111 BPD of coker naphtha, and 8,843 BPD of
coker oil (360°-950°F). The coker naphtha and gas oil are desulfurized to
10 ppm and 0.2 wt. %, respectively; gas oil desulfurization yields another
97 FOE of fuel gas. This fuel gas is combined with the reactor gas for I^S
removal.
b. Potential for Energy Conservation
A major contribution of the Flexicoking option lies in freeing high-Btu
refinery gas for higher priority us'es. In the case chosen here (see Figure
IV-5), a net of 4,298 FOE/day, or about 27 million scf/day, of high-Btu gas
are available for export. This total is due to roughly equal contributions
from high-Btu reactor gas and from refinery gas displaced by coke gas
(flexigas).
A second contribution to energy conservation lies in the conversion of
the asphalt feed to naphtha and gas oil intermediates which become available
for refining. The total yield of these distillates is 10,857 BPD, about
5% of the crude feed to the refinery. This represents a portion of crude
which otherwise would not be a saleable fuel product.
55
-------
FUEL GAS (2174 FOE)
LPG (348 BPD)
Ui
ACID GAS
REMOVAL
DESULFURIZED
GAS OIL
(8746 BPD)
DESULFURIZED
NAPHTHA
(12111 BPD)
COS CONVERTER LOW-SULFUR
COKE GAS
SCRUBBER/
FRACTIONATOR
2315 FOE/DAV
SULFUR
(49.25T/D)
STEAM
AIR
REACTOR
COKE PURGE
STEAM
CONVENTIONAL FLUID COKING
FLEXICOKING ADDITIONS
Figure IV-5. Flow Diagram and Volume Flows for Flexicoking
-------
The thermal efficiency of the Flexicoking process (net Btu out/Btu
in), excluding the heating values of the coke purge, coke fines, and pro-
duct sulfur, is 96%. The effect of the low thermal efficiency is to lower
the refinery efficiency, as indicated in Table IV-21.
c. Pollution Control
(1) Identification of Pollutants
Table IV-22 summarizes the incremental refinery emissions due to Flexi-
coking. Three wastewater streams are involved: 1) a purge from the Stretford
unit, 2) sour water from steam injected into the fluid coker to strip coke
particles of residual oil before they are withdrawn, and 3) 216,000 gpd of
additional cooling tower blowdown (not indicated on Figure IV-6). A typical
analysis of the sour water is shown in Table IV-23.
The solid coke stream, which consists of coke fines removed from the
coke gas and the coke purge from the coke heater section containing 99% of the
feed metals, totals 133,600 Ib/day.
Airborne emissions are produced by the burning of flexigas, which was
substituted for refinery gas. The emission of SOX is in compliance with NSPS
of 0.2 Ib SOX/106 Btu by virtue of the Stretford operating conditions. Due to
the lower flame temperature of low Btu gas, NOX emissions are lower than the
refinery gas emissions, and Exxon claims complete removal of particulates.
The acid gas removed from the coker gas (C^ -gas) represents a gaseous
pollution stream which requires treatment in a Claus/Beavon/Stretford system.
(2) Water Pollution
It is anticipated that an East Coast refinery employing Flexicoking will
have a treated process wastewater stream very nearly the same as that of the
base case East Coast refinery. The total waste load will be somewhat increased
due to the presence of additional sour water, Stretford process purge water,
and increased cooling tower blowdown.
The additional sour water stream will introduce increased quantities of
hydrogen sulfide and ammonia into the total wastewater stream. The sour
water stream must be subjected to steam stripping prior to discharge into the
central wastewater treatment facility. The additional sour water stream will
increase the process wastewater flow rate from 6.6 to 6.654 mgd.
Although there is a certain amount of removal in the central wastewater
treatment facility, a sulfide and ammonia residual will result, thereby
slightly increasing the sulfide and ammonia load over the base case.
The Stretford purge stream associated with the Flexicoking alternative
will be increased by almost a factor of 10 over that of the base case. Since
it is envisioned that the Stretford purge will be disposed of on land (via
chemical fixation), this increase constitutes an increased solid-waste disposal
problem rather than a water pollution problem.
57
-------
TABLE IV-21
SUMMARY OF REFINERY ENERGY BALANCE
WITH AND WITHOUT FLEXICOKING
Energy In
Crude
Vs
Natural gasoline
Fluid cat cracker feed
Refinery .feed
Electricity
Steam
Energy Out
Refinery gas
Mixed olefins
Distillates
Resid, vac. bottoms
Energy Factor
10 Btu/Bbl
5.85
6.3
5.6
5.6
5.6
10,500 Btu/kWh
1.45 x 106 Btu/103 Ib
6.3
6.3
5.6
6.3
East Coast
Base line
10 Btu/day
1,157.7
8.8
32.5
62.2
33.6
8.9
8.2
1,311.9
27.1
958.2
201.0
1,186.3
Baseline with
Flexicoking
10 Btu/day
1,157.7
8.8
32.5
62.2
33.6
9.6
7.6
1,312.0
27.1
29.6
1,019.2
83.2
1,159.1
(Energy out)
(Energy in)
0.904
0.883
58
-------
TABLE IV-22
SUMMARY OF ADDITIONS TO BASE LINE EMISSIONS DUE TO FLEXICOKING
Stream No.
Water Pollution, gpd
W,,
Air Pollution, Ib/day
Solid Waste, tpd
Description Pollutant
Stretford purge
Coker ateam injection Sour water
Cooling water
Slowdown
Combustion of flexigas SO
Acid gas stream
Coke fines
Dry solid
High metal coke purge Dry solid
Uncontrolled
Emission
Rate
21,670
54,000
216,000
New Stretford unit
Elemental sulfur
2,920
Combined sulfur 159,580
66.8
49.2
59
-------
BFW
FLEXIGAS
FUEL GAS
&
LPG
^-DESULFURIZED NAPHTHA
^DESULFURIZED GAS OIL
LEGEND
© :WASTEWATER
/^. :AIRBORNE EMISSIONS
[S] :SOLID WASTE
Figure IV-6.
Block Flow Diagram for Flexicoking and Identification
of Pollution Sources from Flexicoking
60
-------
TABLE IV-23
WATER ANALYSIS
FLEXICOKING SOUR WATER
Concentration
Contaminants (mg/1)
NH3 1,000
H2S 1,500
pH 8.5
CN (free) 0.3
SCN 9
S203 300
Suspended solids 3
Phenols 20-30
Fe 1
Ni 1
COD (by perm.) 775
V nil
Source: Exxon R&E
The cooling water blowdown stream is increased over that of the base
case by 4% (5.88 mgd versus 5.66 mgd).
All of the increases in wastewater flow rate result in a slight increase
in treatment cost. It is estimated that the total treatment cost (process
wastewater treatment plus cooling tower blowdown treatment) will be increased
by 13% over that of the base case ($5.663 x 10 /yr versus $5.001 x 106/yr).
Treatment costs are presented in Tables IV-24 and IV-25. The costs are
dependent on the type of prime mover used with the Flexicoking process. The
cost increase would be less with electric motors or extraction turbines
since less cooling water would be needed.
In terms of both treated effluent waste loads and wastewater treatment
cost, the Flexicoking alternative does not present major water pollution
implications. i
(3) Air Pollution
The major air pollution problem associated with the Flexicoking process
is in controlling sulfur in the following streams: a) fuel gas - light hydro-
carbons containing E^S; and b) flexigas - a low-Btu fuel gas containing N£,
CO, C02, H2 and S.
61
-------
TABLE IV-24
ALTERNATIVE A-3
EAST COAST REFINERY WITH FLEXICOKING
PROCESS WASTEWATER TREATMENT COSTS
(Basis: 200,000 BPD, 330 days/year)
Capital Investment: $11,700,000
Variable Costs
Operating labor (including
supervision overhead)
Maintenance (including
labor and materials)
Chemicals
Lime
Phosphoric acid
Chlorine
Coagulant aid
Replacement carbon
Fuel (gas)
Steam
Electrical power
Wastewater treatment sludge
disposal
• Incinerator ash
• Stretford Purge water
Total variable cost
Fixed Cost
Depreciation @ 6.25%
Taxes & insurance @ 2%
Total fixed cost
Total annual cost
Return on investment
Total
Yearly
Quantity
17,520 m-h/yr
909 tpy
26 tpy
90 tpy
36,400 Ib/yr
123,750 Ib/yr
Cost per
Unit Quantity
$17.15/m-h
$32.50/ton
$440/ton
$140/ton
$1.00/lb
.40/lb
±£-j9ij\j JLU / y j. yu.HU/JLU
7,425 x 106 Btu/yrSl.35/106
50,670 x 103 lb/yr$3.85/103
3,026,400 kWh/yr $0.030/kWh
255 tpy
33,750 tpy
$5.00/ton
$15.00/ton
Yearly Cost
($/Yr)
300,000
468,000
29,500
11,400
12,600
36,400
49,500
10,000
195,100
90,800
1,300
506,300
$1,710,900
731,300
234,000
$965,300
$2,676,200
$2,340,000
$5,016,200
Notes: 1) Capital investment adjusted to the 1975 level (ENR
Construction Cost Index - 2126).
2) Wastewater treatment costs are based on total implementation
(from ground up) of the BATEA level (Best Available Tech-
nology Economically Achievable), 1983.
3) Cost estimates are for the specific examples, and are in no
way intended to represent industry-wide treatment costs.
62
-------
TABLE IV-25
ALTERNATIVE A-3
EAST COAST REFINERY WITH FLEXICOKING
COOLING TOWER SLOWDOWN WASTEWATER TREATMENT COSTS
(Basis: 200,000 BPD, 330 days/year)
Capital Investment: $1,417,000
Variable Costs
Operating labor (including super.
vision & overhead)
Maintenance (including labor &
materials)
Chemicals
• Sulfur dioxide
• Lime
• Sulfuric acid
Fuel
Electrical power
Wastewater treatment Sludge
•isposal
Total variable cost
Fixed Costs
Depreciation @ 6.25%
Taxes & insurance @ 2%
Total fixed cost
Total annual cost
Return on investment @ 20%
Total
Yearly Cost Per
Quantity Unit Quantity
2200 m-hr/yr $17.15/m-hr
490 tpy
522 tpy
245 tpy
$340/ton
$32.50/ton
$51.15/ton
122,800 kWh/yr $0.03/kWh
'4,790 tpy $5.00/ton
(@10% solids)
Yearly Cost
($/Yr)
37,700
56,700
166,600
17,000
12,500
3,700
24,000
$318,200
88,600
28,300
$116,900
$435,100
$283,400
$718,500
Notes: 1) Capital investment adjusted to the 1975 level (ENR Construction
Cost Index - 2126).
2) Wastewater treatment costs are based on a chrome reduction/
precipitation system consisting of reaction vessels, clarifiers,
chemical feed system and controls.
3) Chromium concentration in untreated cooling tower blowdown is
assumed to be 30 mg/1.
4) Cost estimates are for separate treatment of chromium-contaminated
cooling tower blowdown. Not all refineries treat cooling tower
blowdown separately, and the amount of chromate used varies
considerably.
63
-------
The sulfur in the high-Btu fuel gas is removed using an amine scrubbing
system, and the exhaust of that scrubbing system is sent to the refinery
Glaus plant. The hydrogen sulfide in the low-Btu flexigas is too low in
concentration to be economically scrubbed out, and therefore this process
comes with an integral Stretford unit for sulfur removal. The sulfur
concentration in the product flexigas is approximately 170 ppm, which is
within allowable standards for combustion without sulfur control. The cost
for the Stretford unit is usually included in the cost of the Flexicoking
unit. We have, however, shown estimated costs for the Stretford unit in
Table IV-26 as part of pollution control, for purposes of comparison with the
base case.
(4) Solid Waste
Implementation of the Flexicoking process will result in a significant
increase in total refinery solid-waste generation.
The volume of the Stretford purge stream will be greatly increased over
that of the base case. In addition, significant quantities of waste coke
will be produced. An estimation of these increases is shown below:
Solid Waste Generation (tpy)
Base case total refinery
solid-waste stream 19,425
Increase in Stretford purge
stream 28,500
Waste coke 20,700
Total 68,625
Thus, the toal refinery solid-waste volume, and hence its disposal
cost at $230,000/yr, is more than three times that of the base case.
d. Cost Factors
Table IV-27 provides a breakdown of the incremental costs associated with
incorporating Flexicoking into the East Coast base line - naphtha and gas oil
desulfurization and 95% sulfur recovery are included. The total -
$10.0 x 106/yr or $30,350/day - corresponds to approximately $0.33/106 Btu
of Flexicoker products. Since the gas, oil, and naphtha are intermediates,
an additional cost for upgrading would be incurred. (Note that no credit
was taken for 121 tons of recovered elemental sulfur.)
The required capital investment is $22.8 million; $16.4 million of this
is for the Flexicoker section alone.
64
-------
TABLE IV-26
SULFUR CONTROL COSTS FOR FLEXICOKING (OPTION A-3)
(Basis: East Coast, 1985)
Reactor
Gas Flexigas
Baseline Glaus Stretford
Inlet Sulfur Load, long ton per day
Capital Cost, $1000's
Claus plant
Tailgas cleanup
Total
Annual Operating Cost, $000/yr
Variable costs:
Labor
- Direct @ $6.75/hr
Supervision @ 10% of direct
Labor overhead @ 40% of labor
Maintenance @ 5% of capital
Utilities
- Electric power @ $0.03/kWh
- Fuel @ $2.17/106 Btu
- Cooling water @ $0.044/103 gal
Chemicals @ $2.50/ton of S in tailgas
Total variable costs
Fixed costs:
Plant overhead @ 100% of labor
Depreciation, 16 years
Insurance & taxes @ 2% of capital
Total fixed costs
Total Production Cost
Return on Investment @ 20% of Capital
Less Sulfur Credit @ $25/ton (Net)
Total Annual Cost, $000/yr
99
168
2,600 3,650
2,100 3.550 3,800
4,700 6,200 3,800
19
2
8
190
499
122
874
21
238
76
335
1,209
760
(346)
1,130 1,217 1,623
59
6
26
235
137
56
29
5
553
65
294
94
453
1,006
940
(816)
59
6
26
310
233
96
49
7
786
65
388
124
577
1,363
1,240
(1,386)
65
-------
TABLE IV-27
PRODUCTION COSTS: OPTION A-3 (FLEXICOKING)
High-Btu Cns, I.ow-Btu Gas,
Produce: Naphtha, fias Oil Process: Flc-xlcoktng (A-1)
Batch/Contimious: Continuous
Fixed Invcstpont: $18.0 Million
Annual/Capacity; 18.700 BPD
Location: East Const
PepreciatIon
Period (yr): 16
Year Used for
Costing Purposes: 1975
Stream Davs/Vr.; 330
VARIABLE COSTS
Rav Materials
• Asphalt, BPD
• Catalyst and Chemicals
Energy
• Purchased Fuel
• Purchased Steam
• Misc.
Energy Credits
• Steam, 10 Ib/day
Water
• Boiler Feed Water, (10 stpd)
• Cooling (Circulating rate)
Direct Operating '.ibor (Wages)
Direct Supervisory Wages
Maintenance Labor \
Maintenance Materials and Supplies /
Labor Overhead
Misc. Variable Costs/Credits
Royalty Payments S/yr
FIXED COSTS
Plant Overhead
Local Taxes and Insurance
Depreciation
TOTAL PRODUCTION COSTS
Return on Investment (pretax)
Subtotal
POLLUTION CONTROL (incremental)
TOTAL
Units L'scd In
Costing or
Annual Cost
Basis
18,700
,
49 f 780 kWh/day
451
673
14. 430x10 J gal/day
6 men/shift
10% of Dir. Lab.
SI 280/day
4051 of Dir. Lab.
106,900
100Z of Dir.
Labor/yr
22 of C.I.
6.25X/yr
S/Unlt
S215/Jay
$0.60/103 gal
SO.044/103 gal
S..75/hr
20% of C.I.
Annual
Cost
S103
71.0
492.8
133.3
209.5
354. R
35.5
422 .$
156.1
108.9
390.3
360.0
1 .12S.U
3,859.6
3,600.0
2.643.0
10.102.6
e.g., miscellaneous chemicals, catalysts, supplies, services
66
-------
e. ^Technological Considerations
It has been assumed that low-Btu gas could replace refinery gas. Flexi-
gas is autogeneous and Exxon has test-fired low-Btu flexigas in process heaters.
However, larger breechings or induced draft fans may be necessary to handle
the greater volumes of gas produced. Condensing steam turbine drives were
assumed for the gasifier air blowers, which accounts for the large cooling
water requirement.
f. jSffect on Intermediate and Final Products
As described above, the asphalt feed is converted to low- or high-Btu gas,
naphtha, and gas oil. Hence, Flexicoking provides one means for processing
asphalt (which is not a fuel) into fuel products. More than 60% of the feed
heating value is converted to liquid intermediates — naphtha and gas oil.
Approximately 23% of the feed heating value becomes available as high-Btu gas.
Table IV-28 compares the product structure for the base line case with the pro-
duct structure with Flexicoking of the asphalt included.
5. Process Change B: On-Site Electric Power by Combustion of
Vacuum Bottoms
This alternative was evaluated using the Gulf Coast refinery base line.
a. Process Description and Current Status of Technology
In this process option, electric power is generated internally within
the refinery rather than purchased from the local power utility. The fuel for
this Gulf Coast option is assumed to be asphalt which will require flue gas
desulfurization with subsequent sludge disposal.
Figure IV-7 shows a simplified flowsheet of the generating system.
Basically the fuel is burned to generate high-pressure steam which is expanded
through a conventional steam turbine which provides the motive power for
electricity generation.
b. Potential for Energy Conservation
The internal generation of electric power within the refinery does not
conserve energy overall — nor does it consume more energy than when power is
purchased, assuming that the internal and external power plants would operate
at the same efficiencies. In effect, the form value of the asphalt product
is upgraded to a higher form of electric power for refinery use. Table IV-29
shows the net refinery energy balance after implementing option B. Although
the ratio of input Btu to output Btu decreases slightly, there is no real net
energy cost. This occurs simply because both the energy input decreases (no
purchase of electricity) and the output also decreases by the same quantity
(asphalt consumed internally).
67
-------
TABLE IV-28
COMPARISON OF PRODUCT SLATES
WITH AND WITHOUT FLEXICOKING
(103 BPD)
East Coast Base Line Base Line with Asphalt
(1985) Flexicoking
LPG 6.2 6.5
High-Btu gas - 4.3 (FOE)
Unleaded gasoline 106.9 106.9
Naphtha 1.3 1.3
No. 2 distillate 47.0 47.0
Jet fuel 5.9 5.9
Kerosene 3.5 3.5
Low sulfur fuel oil 13.2 13.2
Asphalt 18.7
Naphtha intermediate - 2.1
Gas oil intermediate - 8.7
Lube stocks 5.1 5.1
BTX 1.4 1.4
Petrochemical feed 4.3 4.3
TOTAL 213.5 210.2
68
-------
CLEAN FLUE GAS
I I
I FLUE GAS I
I DESULFURIZATION I
ASPHALT
FROM STORAGE
(1460 BPD)
BOILER
HIGH-PRESSURE STEAM
STEAM TURBINE
BOILER
FEEDWATER SYSTEM
MAKE-UP SLOWDOWN
WATER
ELECTRIC
POWER
Figure IV-7. Electric Power from Asphalt
-------
TABLE IV-29
COMPARISON OF REFINERY ENERGY BALANCE
WITH AND WITHOUT ON-SITE POWER GENERATION
Energy In
Crude
C4'8
Natural gasoline
FCC feed (storage)
Reformer feed
Electricity
Steam
Total
Gulf Coast Base Line
1275.5
56.1
16.8
9.2
0.7
1358.3
Base Line with Onsite
Power Generation
1275.5
56.1
16.8
0.7
1349.1
Energy Out
Mixed olefins
Distillates
Resid, asphalt, coke
Total
14.5
1117.8
65.5
1197.8
14.5
1117.8
56.3
1188.6
(Energy out)
(Energy in)
0.882
0.881
70
-------
We considered the option of a dual-purpose powerplant in which steam is
generated at a high pressure and expanded through a topping turbine for
power generation before it is sent to process. The particular ratio of
steam-to-electric-power demand for the example refinery, however, would have
required that some additional steam be generated and let down through a
parallel condensing turbine. In part, for this reason, we chose to consider
only an all-condensing power plant.
The other reasons we chose the all-condensing plant relate to the fact
that we were considering modification(s) to an existing refinery rather than
the grassroots design of a new refinery. Since the existing refinery has
in place a steam network of sufficiently high reliability, it would be
redundant — and costly from a capital point of view — to install new gener-
ating capacity for providing steam for the entire refinery instead of that
required specifically for electric power generation. Admittedly, this choice
precludes the energy savings of the dual-purpose concept, but the capital
versus energy cost tradeoffs for an existing refinery will depend on the
specific situation which we could not prejudge. Furthermore, vis-a-vis incre-
mental pollution, this option provides a conservative estimate; i.e., more
pollution and consequent controls. Nevertheless, further evaluation of
integrated energy systems is warranted.
c. Pollution Control
(1) Identification of Pollutants
The pollutants emitted by process change B are indicated on the block flow
diagram in Figure IV-8 and described in Table IV-30. Uncontrolled water
effluents include cooling water and boiler blowdown. Flue gas from the boiler
is the major airborne pollutant.
(2) Water Pollution
The only water pollutional implications of a Gulf Coast refinery employing
on-site power generation via asphalt combustion will be an increased cooling
tower and boiler blowdown flow rates. The process wastewater flow rate and
composition will be essentially the same as the base case. Therefore, the
process wastewater treatment cost will be identical to that of the base case.
The cooling tower and boiler blowdown will be increased from 5.19 to
5.71 mgd, and this increase will result in an increase in a total (process
plus cooling tower blowdown) wastewater treatment cost of less than 1%
($4.937 x 106/yr versus $4.895 x 106/yr). Cooling tower blowdown treatment
costs are shown in Table IV-31.
In terms of both treated effluent waste load and wastewater treatment
cost, the implications of implementing on-site power generation via asphalt
combustion are negligible.
71
-------
VACUUM SYSTEM
ASPHALT
(1460 BPD)
FLUE
GAS
POWER
PLANT
COOLING
WATER
SUPPLY
COOLING
WATER
BLOWDOWN
MAKE-UP WATER
LEGEND
AiAIRBORNE EMISSIONS
O:WASTEWATER
Figure IV^-8, Pollution Source Identification: Electric Power
from Asphalt Combustion
-------
TABLE IV-30
ELECTRIC POWER FROM ASPHALT - POLLUTION PROFILE
Stream No. Description
3
Water pollution 10 gpd
W. Steam system
blowdown
W_ Cooling Water
blowdown
Air Dilution lb/day
An Flue gas
Vacuum off gas
(air, steam)
Estimated Emission Rate
Pollutant Ib/hr. Uncontrolled
Dissolved solids
Dissolved solids
192
333
SO
x
Particulate
Hydrocarbons
NO
x
Aldehydes
27,456-
1,226
204
4,234
36
73
-------
TABLE IV-31
ALTERNATIVE B
GULF COAST REFINERY WITH ON-SITE POWER GENERATION
COOLING TOTTER SLOWDOWN WASTEWATER TREATMENT COSTS
(Basis: 200,000 BPD, 330 days/yr)
Capital Investment: $1,390,900
Yearly
Quantity
Cost per
Unit Quantity
Yearly cost
($/yr)
Variable Cost
Operating labor (including
supervision overhead)
Maintenance (including
labor and materials)
Chemicals
• Sulfur dioxide
• Lime
• Sulfuric acid
Fuel
Electrical power
Wastewater treatment sludge
.isposal
Total variable cost
Fixed Cost
Depreciation @ 6.25%
Taxes & insurance @ 2%
Total fixed cost
Total annual cost
Return on investment @ 20%
Total
2200 m-hr/yr $17.15/m-hr
473 tpy $340/ton
505 tpy $32.50/ton
236 tpy $51.15/ton
119,200 kWh/yr $0.0145/kWh
4,660 tpy $5.00/ton
(@10% solids)
37,700
52,200
160,800
16,400
12,100
1,700
23,300
$304,200
86,900
27,800
$114,700
$418,900
$278,200
$697,100
Notes: 1) Capital investment adjusted to the 1975 level (ENR
Construction Cost Index 2126).
2) Wastewater treatment costs are based on a chrome reduction/
precipitation system consisting of reaction vessels, clarifiers,
chemical feed system and controls.
3) Chromium concentration in untreated cooling tower blowdown
is assumed to be 30 mg/1.
4) Cost estimates are for separate treatment of chromium-contaminated
cooling tower blowdown. Not all refineries treat cooling tower
blowdown separately, and the amount of chromate used varies
considerably.
74
-------
(3) Air Pollution
The major pollutant of concern for option B is the SC>2 emission in
the exhaust from the boiler. The cost of sulfur control for on-site electric
power generation is shown in Table IV--32. In comparison to the costs shown
in Appendix D for flue gas desulfurization of large combustion sources, these
costs appear to be somewhat high.
The economy of scale associated with gas desulfurization was discussed
with respect to the direct firing of asphalt in process heaters (Option A-l).
In the context of that particular option, it appeared to be more economical
to sell asphalt as a fuel to large utilities rather than to burn asphalt
within the refinery and export fuel oil. Since one might expect the utilities
to resist the burning of a difficult fuel such as asphalt, another alternative
might be to burn the asphalt at the refinery within a single boiler which
would generate both process steam and electricity for the refinery. However,
the decision on the part of the refiner to pursue this option, as opposed to
purchasing electric power, will be made based upon such factors as prevailing
electric rates, reliability of power supplies, and markets for asphalt and
coke - and not upon incremental differences for environmental control.
(4) Solid Waste
The solid waste stream for Alternative B - On-site Power Generation - is
essentially of the same volume and compositon as that of the base case.
d. Cost Factors
Table IV-33 shows the estimated annual cost of operating the steam/
electric system, excluding the cost of fuel. When the cost of pollution con-
trol equipment is included, the cost of operation, maintenance, and capital
for the power is l.lC/kWh not including the fuel charge. This does
include a demand charge of $1.86/kW for the Gulf Coast in 1975, which would
be paid monthly to the local utility to provide backup electric service in the
event of a refinery power failure.
e. Technical Considerations
Since the power generating base of a refinery producing its own power
would be much smaller than that of a typical electric utility, the reliability
of service would be similarly lower. This is because the utility would norm-
ally have several generating stations within its system, each with more than
one boiler. The total generating capacity of the utility would exceed the
normal expected maximum instantaneous demands and therefore there is a normal
built-in reserve. Further, a utility is free to purchase power from the
local grid system in the event that demand is unusually high or when several
of its generators are out of service.
To assure itself the same general level of reliability of power supply
as is available from the utility, the refinery would pay a monthly demand
75
-------
TABLE IV-32
SULFUR CONTROL COSTS OF ELECTRIC POWER GENERATION (OPTION B)
(Basis: Gulf Coast, 1975 - 383 x 106 Btu/hr)
On-site Electric
Generation
Capital cost, $000
Direct Costs:
Scrubber
Regeneration
Total direct costs
Indirect costs, @ 30% of direct
Total capital ost, $000 3,271
Annual operating cost, $000/yr
Variable costs:
Labor, 1 man/shift (incl. supv. & overhead)
@ $14.85/hr 130
Maintenance, @ 5% of direct capital 126
Utilities
- Electric 'power, 240 kWi/105 scf
@ $0.0145/kWh 127
- Water, 75 gpm @ $0.35/103 gal 13
- Fuel, 2.5 x 106 Btu/ton of S
@ $1.73/106 Btu 10
Total variable cssts 406
Fixed costs:
Depreciation, 16 years 205
Insurance & 'taxes, @ 2% of capital 65
Total fixed costs 269
Total production cost 675
Return on investment, @ 20% of capital 654
Credit for recovered sulfuric acid, @ $25/ton (net) (184)
TOTAL ANNUAL COST, $000/yr 1,145
Unit cost, $/106 Btu 0-38
Based on MgO scrubbing, sulfuric acid recovery.
76
-------
TABLE IV-33
PRODUCTION COSTS: OPTION B (STEAM/ELECTRIC)
Product: Electric Power
•Design . 36.5 M«
Process: Steam/Electric (B)
Fixed Investment: ?15'8 "'lllon
Location: fiulfCoast
Scream Days/Yr. :__22°_
Dpprec Lit Ion
Period (yr): 16
Year Used for
Costing Purposes:
VARIABLE COSTS
Raw Materials
• Asphalt
Byproduct Credits
Energy
• Purchased Fuel
• Purchased Steam
• Electric Power Purchased
• Miscellaneous
Energy Credits
Water
• Process (Consumption) BKW
• Cooling
Direct Operating Labor (Wages)
Direct Supervisory Wages
Maintenance Labor
Maintenance Supervision
Maintenance Materials and Supplies
Labor Overhead
Misc. Variable Costs/Credits*3'
• Demand Charge
Royalty Payments
FIXED COSTS
Plant Overhead
Local Taxes and Insurance
Depreciation
TOTAL PRODUCTION CDSTS
Return on Investment (pretax)
POLLUTION CONTROL (Incremental)
TOTAL
Units Used in
Costing or
Annual Cost
Basis
T
70,000 10* sal
7.38 x 109 R.-il
35,040 hrs
10* of Dlr. Lab.
l.SZ Fixed Inv.
10 J Main. I.nb.
1.5Z Fixed Inv.
403: of Dlr. Lab.
36,500 kW
100Z of Dlr. Lab.
S/Unlt
50.03/kW)i
•»
0.35/10* n.il
SO. 044/103 gal
56.76/hr
$1.86/kU/CK>.
Annual
Cost
(sioJ)
:A.S
325.0
23f>. 1
23.7
237.0
23.7
237.0
lf>4.2
815.0
260. 6
316.0
988.0
3,591.6
3.160.0
1.189.0
7,940.6
e.g., miscellaneous chemicals, catalysts, supplies, services.
77
-------
charge to the power company which would serve as a rental fee for reserve
capacity maintained in the event that it was needed on short notice. This
demand charge is included in the economics of Section 5d above.
In addition to paying the demand charge, the refinery would probably
hedge its position internally by installing more than one item of smaller
equipment in parallel rather than a single, large item to minimize the effect
of an outage. Also, some redundancy would be introduced. For example, two
boilers of 60-75% capacity each might be installed — or perhaps three 50%
boilers. Because the turbines and generators are typically more reliable than
boilers, less overall redundancy would be installed in these areas.
f. Effect on Intermediate and Final Products
Option B has the net effect of reducing the availability for sale of a
refinery product (asphalt), while at the same time eliminating the need for
normal purchase of a utility (electric power). Otherwise there is no impact
on the mix of refinery products.
6. Process Change C: High-Purity Hydrogen Production
via Partial Oxidation of Asphalt
This process change was performed for the West Coast refinery cluster.
a. Process Description and Current Status of Technology
This alternative is based on the production of high-purity hydrogen for
hydrotreating from vacuum bottoms, using a partial oxidation process such as
those offered by Shell and Texaco. The feedstocks freed up by this approach
would then be available for sale outside the refinery in the form of pipeline
gas or naphtha.
As shown in Figure IV-9, the partial oxidation system consists of several
steps. Oil and oxygen are fed to a series of burners in the partial oxidation
reactor where, in the presence of steam, a mixture of gaseous hydrogen,
carbon monoxide, carbon dioxide, and solid carbon (soot) are produced by the
following reactions:
C H + (n/2 + m/4)0_ •* nCO + m/2 H.O
n m 2 2
C H + (n + m/4)00 -»• nCO. + m/2 H.O
n m 2 2. 2.
CO + H20 + C02 + H2
2CO + CO- + C
78
-------
STEAK
TUR
I
CLAUSTAIL GAS
t
1
1
1FROM HP STEAM MAKE-UP WASTE CLAUS
3INES TO TURBINES WATER WATER SULFUR
PLANT
L_ _J
m it o
M fi^o
| C02
AIR OXYGEN PARTIAL WASTE ACID GAS
otrAnAiiuiM »- UXIUAMUN ^- IICAT *- SCRUBBER »- rnNVFR^mN REMOVAL
PLANT REACTOR BOILER CONVERSION REMOVAL
/fv^ HEAVY OIL FEED
N<£/ 3625 BPD
>fv^ NAPHTHA
1
OIL/SOOT SLURRY
SOOT
RECOVERY
1
HIGH PURITY
HYDROGEN
(51.5 X 106SCFD
Figure IV-9. Hydrogen via Partial Oxidation
-------
The hot reactor effluent gases are cooled by generating high-pressure
steam. They then pass through a water scrubber which accomplishes further
cooling and saturates the gas with water vapor for the subsequent shift-
conversion reaction. Simultaneously, the soot particles are removed from the
gas into the liquid phase. By addition of feed oil to the soot/water slurry,
the soot leaves the water phase as agglomerates or pellets which may be
recycled to the partial oxidation reactor.
The downstream gas processing consists of three additional steps. First,
the carbon monoxide is reacted with water to produce hydrogen by the water-gas
shift reaction:
CO + H20 •*• C02 + H .
Second, the carbon dioxide is removed by physical absorption, for example, in
a hot potassium carbonate solution or chilled methanol (Rectisol). At the
same time, ELS produced from sulfur in the reactor is also absorbed. Upon
regeneration, the absorbent releases the CO. and H_S which pass to the existing
Glaus plant to produce elemental sulfur. TKird, tne final traces of carbon
monoxide are removed by conversion with hydrogen to methane in the methanator.
Partial oxidation (as licensed by Shell and Texaco) has been practiced
widely over the past 15 years on feedstocks ranging from natural gas through
vacuum bottoms. The systems, usually geared to hydrogen production, have
generally proven reliable with availabilities often in excess of 95% for light
feedstocks. In short, we do not feel that a refinery would be taking an
unwarranted risk in the reliability of its hydrogen supply by installing a
partial oxidation unit.
b. Potential for Energy Conservation
The production of hydrogen by partial oxidation of asphalt, as compared
with steam reforming of light hydrocarbons (i.e., naphtha or refinery gas.), is
aimed primarily toward upgrading the overall form values of the refinery output.
Converting some of the "bottom of the barrel" for hydrogen production frees
up some of the more valuable, lighter fractions for sale.
In terms of actual energy utilization, there is essentially a standoff,
between the two options. As shown in Table IV-34, a total of about 17 x 10
equivalent Btu/day can be saved by going to partial oxidation. This is less
than 0.01% of the total energy equivalent of the energy-related utilities in
the refinery, fuel, steam, and electricity. Clearly, this is an even smaller
fraction of the total refinery throughput. This very modest energy saving is
essentially the result of the fact that, in the base line steam reforming case,
C02 removal was accomplished by hot potassium carbonate scrubbing which
requires process steam for solvent regeneration. In the partial oxidation
scheme, the regeneration utilizes the nitrogen byproduct of air separation as
the stripping gas.
80
-------
TABLE IV-34
COMPARISON OF REFINERY ENERGY BALANCE WITH AND WITHOUT
HYDROGEN PRODUCTION VIA PARTIAL OXIDATION OF ASPHALT
West Coast - 109 Btu/Day
Base line with
Base line Asphalt POX
Energy In
Crude 960.6 960.6
C4's 3.2 3.2
Natural gasoline 5.0 5.0
FCC feed (storage) 20.2 20.2
Reformer feed 10.6 10.6
Electricity 9.5 10.3
Steam ^_ (0.1)
Total 1009.1 1009.8
Energy Out
C:/C2 - 23.3
Mixed olefins 7.6 7.6
Distillate products 682.6 682.6
Resid, asphalt, coke 259.6 236.9
Total 949.8 950.4
(Energy out) _ 0.941 0.941
(Energy in)
81
-------
c. Pollution Control
(1) Identification of Pollutants
Additional pollutants emitted as a result of adding asphalt partial
oxidation to the refinery operations are indicated in Figure IV-10 and Table
IV-35. The major pollutant is I^S contained in the acid gas removed from the
raw hydrogen stream.
(2) Water Pollution
It is anticipated that a West Coast refinery employing hydrogen production
via partial oxidation will have a treated process wastewater effluent and a
treated cooling tower blowdown that will be slightly greater than that of the
base case West Coast refinery.
The untreated process wastewater will contain appreciably greater sus-
pended solids; however, these will be easily removed in the existing treatment
system, and the suspended solids concentration of the treated effluent will
be essentially the same as that of the base case. The increased suspended
solids will slightly increase the quantity of wastewater treatment sludge for
disposal.
The process wastewater flow rate for the partial oxidation alternative
is 5.80 mgd versus 5.78 mgd for the base case and the cooling tower blowdown
flow rate is increased from 4.25 mgd to 4.34 mgd. These increased flow rates
result in a 2% increase in total wastewater treatment cost over the base
case ($4.607 x 10^/yr versus $4.512 x 106/yr).
The wastewater treatment cost estimates are presented in Tables IV-36
and IV-37.
In terms of both treated effluent waste loads and wastewater treatment
costs, the water pollution implications of implementing the partial oxidation
alternative are essentially negligible.
(3) Air Pollution
The major emission associated with this process change is the sulfur
removed from the raw syngas in the form of H2S. This is removed from the
gas using an amine scrubber system. The exhaust from the amine regenerator,
which contains the sulfur as well as C02, is sent to a Glaus plant for sulfur
recovery and air pollution control. Because several states have emissions
standards regulating tailgas for sulfur recovery plants, we have assumed that
tailgas cleanup will be required, such that emissions from the plant will be
limited to 250 ppm or less. The cost of the sulfur recovery for this option
is compared with the base case and the hydrotreating option in Table IV-38.
With the partial oxidation case, the sulfur load is increased by only 6%,
resulting in a corresponding increase in costs of less than 4%. The matjor
difference between the partial oxidation case and the hydrotreating case is
that the partial oxidation process does not use any asphalt as a refinery fuel
and, therefore, avoids the high cost of fuel gas desulfurization.
82
-------
CLAUS TAIL GAS
00
HYDROGEN GAS
51.5 X 106SCFD
RETURN SUPPLY
COOLING WATER
LEGEND
:WASTEWATER
AIR EMISSIONS
:SOLID WASTE
SLOWDOWN
Figure IV-10. Pollution Source Identification: Partial Oxidation
-------
TABLE IV-35
PARTIAL OXIDATION FOR HYDROGEN PRODUCTION - POLLUTION PROFILE
(Basis: 3625 BPD asphalt)
Description
,3
Stream No.
Water Pollution - 10"
W1 Steam hlowdown
W~ Quench purge
Cooling water
blowdown
Air Pollution - Ib/day
A,
Acid gas
Estimated Emission Rate
Pollutant Uncontrolled
(Ib/hr)
Dissolved solids
Slurry
22
Dissolved solids (leached from ash)
Suspended solids
Acidity
HCN
Phenolics
Dissolved solids
H2S
Solid Waste - tpy (intermittent)
S HT shift cat. Fe, Cr, S
LT shift cat. Cu, Zn, S
Methanation cat. Ni
3180 Ib/day
slight (formic acid)
Tr
Tr
93
21,200 (S equiv.)
36.8
42.5
1.5
84
-------
TABLE IV-36
ALTERNATIVE C
WEST COAST REFINERY - HYDROGEN PRODUCTION BY PARTIAL
OXIDATION PROCESS WASTEWATER TREATMENT COSTS
(Basis: 175,000 BPD,. 330 days/yr)
Capital Investment: $10,660,000
Variable Cost
Operating labor (including
supervision and overhead)
Maintenance (including labor
and materials)
Chemicals
Lime
Phosphoric acid
Chlorine
Coagulant aid
Replacement carbon
Fuel (gas)
Electricl power
Wastewater treatment sludge
Disposal
• Incinerator ash
• Stretford purge water
Total -variable cost
Fixed Costs
Depreciation @ 6.25%
Taxes & insurance @ 2%
Total fixed cost
Total annual cost
Return on ^investment
Total
Yearly
Quantity
Cost Per
Unit Quantity
16,060 m-hr/yr $17.15/m-hr
795 tpy
22 tpy
79 tpy
31,800 Ib/yr
108,300 Ib/yr
$32.50/ton
$440/ton
$140/ton
$1.00/lb
$0.40/lb
6,500 106 Btu/yr $1.31/106 Btu
2,648,500 kWh/yr $0.0211/kWh
Yearly Cost
($/yr)
275,000
426,400
25,800
9,700
11,100
31,800
43,300
8,500
55,900
354 tpy
5456 tpy
$5.00/ton
$15.00/ton
1,800
81,800
$971,100
666,300
213,200
$879,500
$1,850,600
$2,132,000
$3,982,600
Notes: 1) Capital investment adjusted to the 1975 level (ENR
Construction Cost Index - 2126).
2) Wastewater treatment costs are based on total imple-
mentation (from ground up) of the BATEA level (Best
Available Technology Economically Achievable), 1983.
3) Cost estimates are for the specific example, and are
in no way intended to represent industry-wide treat-
ment costs.
85
-------
TABLE IV-37
ALTERNATIVE C
WEST COAST REFINERY WITH PARTIAL OXIDATION HYDROGEN PRODUCTION
COOLING TOWER SLOWDOWN WASTEWATER TREATMENT COSTS
(Basis: 175,000 BPD, 330 days/yr)
Capital Investment: $1,308,000
Variable Cost
Operating labor (including super.
and overhead)
Maintenance (including labor
and materials)
Chemicals
• Sulfur dioxide
• Lime
• Sulfuric acid
Fuel
Electrical power
Wastewater treatment sludge
disposal
Total variable cost
Fixed Costs
Depreciation @ 6.25%
Taxes & Insurance @ 27,
Total fixed cost
Total annual cost
Return on investment @ 20%
Total
Notes: 1)
Yearly
Quantity
Cost Per
Unit Quantity
2200 m-hr/yr $17.15/m-hr
429 tpy
456 tpy
213 tpy
$340/ton
$32.50/ton
$51.15/ton
108,200 kWh/yr $0.0211/kWh
4,230 tpy $5.00/ton
(@10% solids)
Yearly Cost
($/yr)
37,700
52,300
154,900
14,800
10,900
2,300
21,200
$294,100
81,800
26,200
$108,000
$402,100
$261,600
$663,700
Capital investment adjusted to the 1975 level (ENR Construction
Cost Index - 2126).
2) Wastewater treatment costs are based on a chrome reduction/
precipitation system consisting of reaction vessels, clarifiers,
chemical feed system and controls.
3) Chromium concentration in untreated cooling tower blowdown is
assumed to be 30 mg/1.
4) Cost estimates are for separate treatment of chromium-contaminated
cooling tower blowdown. Not all refineries treat cooling tower
blowdown separately, and the amount of chromate used varies
considerably.
86
-------
TABLE IV-38*
SULFUR CONTROL COSTS FOR HYDROTREATING (OPTION A-2)
AND PARTIAL OXIDATION (OPTION A-3)
Partial
Base line Hydrotreating Oxidation
Inlet Sulfur Load, long ton per day 159 182 169
Capital Cost. $000
Glaus plant
Tailgas cleanup
Total
Annual Operating Cost, $000/yr
Variable costs:
Labor
- Direct (1 man/shift @ $6.75/hr) 59 59 59
Supervision @ 10% of direct labor 666
Labor overhead @ 40% of labor 26 26 26
Maintenance @ 5% of capital 300 325 310
Utilities
- Electric power @ 140 kWh/long ton per day,
$.0211/kWh 156 178 165
- Fuel @ 0.8 x 106 Btu/long ton per day,
$2.41/106 Btu 101 116 108
Cooling water @ $2.50/long ton per day
in tailgas 46 52 49
Total variable costs: 699 762 723
Fixed costs, $000/yr
Plant overhead @ 100% of labor 65
Depreciation, 16 years 375
Insurance & taxes @ 2% of capital 120
Total fixed costs 560
Total production cost, $000/yr 1,259
Credit for recovered sulfur, @ $25/ton (net) (1,312)
Return on investment @ 20% of capital 1,200
Total annual cost, $000/yr 1,147
Estimated incremental cost for
flue gas desulfurization @ $0.50/10° Btu — 936
Total sulfur control cost 1,147 2,097 1,146
87
-------
(4) Solid Waste
Implementation of hydrogen production via partial oxidation at
the base case West Coast refinery will slightly increase the volume of the
total solid-waste stream due to the slightly increased quantity of wastewater
treatment sludge. In addition, there will be waste catalyst in the amount
of approximately 80 tpy.
d. Cost Factors
Table IV-39 shows the net effect on the economics of hydrogen production
(excluding feedstock values) caused by shutting down the base line steam
reformer and installing a partial oxidation unit. No salvage value is claimed
for the reformer which would actually remain on standby for emergency service
in the event of a partial oxidation unit outage. Only the savings in actual
operating costs are credited to give the net operating cost figures.
e. Technical Considerations
As indicated earlier, the level of overall reliability of partial oxida-
tion of asphalt for hydrogen production will depend largely upon the quality
of the feedstock and, at best, will be comparable with steam reforming. As a
practical issue, however, we would expect that if a refiner were to shut down
his reformer in favor of a partial oxidation unit, he would retain the
reformer in a standby mode to effectively increase the overall reliability of
hydrogen production. In fact, to some extent these would probably be equip-
ment common to both units. For example, much of the shift conversion, acid
gas removal and methanation equipment could be common to both plants. Further,
some of the heat recovery equipment could be common. Although in our capital
cost estimate we did not account for these factors, they may be valid consider-
ations in a refinery where additional capital investment were to be minimized.
f. Effect on Intermediate and Final Products
Option C is one where, in effect, one refinery product is being substi-
tuted for another for the production of an intermediate. The substitution of
vacuum bottoms for refinery gas to produce hydrogen is the net effect in this
case. The overall refinery energy balance for this option was shown in
Table IV-34 in contrast with the base line.
88
-------
TABLE IV-39
PRODUCTION COSTS: OPTION C (PARTIAL OXIDATION)
Process: Partial Oxidation
Product: Hydrogen
Dally Capacity: SI.47 x 10 scfd
Batch/Continuous:
Fixed Investment:
539.1 x 10°
Location: Wpst Coast
Depreciation
Period (yr):_
16
Stream Davs/Yr.: 330
Year Used for
Costing Purposes:
1975
VARIABLE COSTS
Raw Materials 3750-3625
Byproduct Credits
Energy
• Purchased Fuel
• Purchased Steam
• Electric Power Purchased
• Misc.
Energy Credits
Water
• Process (Consumption)
• Cooling (Circulating rate)
Direct Operating Labor (Wages)
Direct Supervisory Wages
Maintenance Labor
HaltUcnur.ce Supervision
Maintenance Materials and Supplies
Labor Overhead
Misc. Variable Costs/Credits
Royalty Payments
FIXED COSTS
Plant Overhead
Local Taxes and Insurance
Depreciation 16 yrs. - S.L.
TOTAL PRODUCTION COSTS
Return on Investment (pretax) 207,
POLLUTION CONTROL
TOTAL
Units Used in
Costing or
Annual Cost
Basis
(125) FOE/day
(17.200 Ib x 103)
29.9 x 106 Mfh
219 x 106 gal
2.06 x 109
1 n.Wshlft
10Z Dlr. Op. Lab.
K of C.I.
40Z Dir. Lab.
24.000
$/Unlt
4.20
0.0211
0.35/103 Kal
0.044/103 g.il
$6.75/hr
Annual
Cost
($103)
72.2
630.9
33.7
90.6
59.1
5.9
624.0
26.0
24.0
64.6
782.0
2.444.0
4,907.0
7,820.0
110.0
7,930.0
"e.g., miscellaneous chemicals, catalysts, supplies, services.
89
-------
V. IMPACTS OF POTENTIAL INDUSTRY CHANGES
A. IMPACT OF PROCESSING OPTIONS
The five energy conservation alternatives considered in this report
focus on internal fuel allocation within the refinery and upgrading of heavy
products. In some cases, asphalt is used as a fuel, replacing refinery gas,
fuel oil, or purchased power. In other cases, the asphalt is directly con-
verted into a higher fuel form, such as naphtha, gas oil and combustible gas.
The products of these conversions are generally available for sale and in
one case (Flexicoking) used to replace internal fuel requirements. The
impacts these changes have in regard to energy conservation and pollution
control costs are assessed in this chapter.
1. Process/Pollution Control Energy Effects
In the previous chapter, frequent reference was made to the fact that
none of the options conserves energy in real terms, i.e., the overall thermal
efficiency of the refinery is not increased. However, all of the options
considered exhibit significant form value conservation by increasing the
yields of light petroleum products (refinery gas, distillate products) with \
a commensurate reduction in heavy-ends (asphalt, residual oil). The net
result of these changes on the refinery product slates is summarized in
Table V-l.
The large increase in refinery gas available from option A-3 is a result
of displacing refinery gas with low calorific value flexigas and the simul-
taneous production of high-Btu coker gas. The gas available is equivalent
to 28 million scf/day of pipeline gas, which could be sold locally, over the
fence, to a gas—dependent industrial consumer. This holds for options A—1 and C
as well. Options B and C essentially trade asphalt for another energy form,
viz., electricity and refinery gas.
The effectiveness of these changes on the overall refinery energy balance
is generally slight, as indicated in Table V-2. As one might expect, the H-oil
and Flexicoking conversion processes have the most impact upon energy con-
sumption. In these two cases, there is a net loss in available energy, as
contrasted with the other options, where only the form of the energy consumed
changes. The ratios presented in Table V-2 are exclusive of energy consumed
by pollution control systems.
For all of the options assessed, we concluded that the control of waste-
water effluents has a negligible impact. As indicated in Appendix D, the
incremental wastewater loads associated with these process changes are sma'll
90
-------
TABLE V-l
CHANGES TO PRODUCT SLATES RESULTING FROM PROCESS CHANGES
(BPD)
A-l A-2 A-3 B C
OPTIONS: Direct Combustion H-Oil Flexicoking Power Generation Asphalt POX
Reduction Increase Reduction Increase Reduction Increase Reduction Increase Reduction Increase
Products
Asphalt (vac. bcms.) 12,330 9,240 18,700 1,460 3,625
Tar 1,480
Residual oil (atm. btms.) \ 2,070
Heavy gas oil > 9,640 3,820 8,746
Light gas oil ) 3,060
Naphtha 2,270 2,111
LPG (FOE) 540 350
Refinery gas (FOE) 2,690 800 — 4,489' 3,750
Coke 374
Electricity 1.4602
Total 12,330 12,330 12,110 11,170 18,700 16,070 1,460 1,460 3,625 3,750
'includes displaced refinery gas and coker product gas.
21,460 (6.3 x 106/0.0105 x 106) = 876,000 kWh/day = 36.5 MW of capacity.
-------
relative to the base line cases. Consequently, there is an insignificant effect
on the characteristics of the treated effluents, the type of treatment required
to conform with regulatory requirements and the incremental energy consumed.
None of the process changes introduces new and different substances into
the wastewater, and none of the process changes significantly alters the
volumes of wastewater that must be treated. In essence, we anticipate that
the nature of the treated effluent will be very nearly the same as that
delineated for the base case.
Conversely, the control of airborne emissions, in this case SOX, has an
identifiable impact in terms of both energy consumption and cost. A summary
of the energy consumed by the air pollution control (APC) systems is presented
in Table V-3 and compared to the energy (utilities/fuel) consumed by the base
line refineries. Except for option A-l, the APC system energy consumption is
a very small percentage of the total refinery utility and fuel energy con-
sumption. Option A-l requires the installation of several small-scale flue
gas desulfurization (FGD) systems on process heaters and boilers which results
in a relatively higher energy consumption than expected for the other options.
2. Cost Impact
The net cost of pollution controls for each option based upon the cost
estimates of Chapter IV is presented in Table V-4. The differential cost for
controlling water, air, and solid-waste pollution is developed for each case.
The total cost of pollution control is then compared to the operating costs
(less feedstock and product values) associated with the process option. The
cost impact of pollution controls on option A-l is substantial, amounting to
over 50% of the total operating cost of this alternative. This result is
perhaps indicative of why refiners prefer to control refinery sulfur emission
by blending high/low sulfur fuels rather than retrofitting FGD systems and
burning high sulfur oil.
Pollution controls add about 25 percent to the costs for Flexicoking.
In this case, about 30% of the pollution differential is for wastewater
treatment. This is mainly associated with increased cooling tower blowdown
resulting from the use of condensing steam turbine drives on the air blowers.
The remainder is primarily the operating cost for the Stretford system used
to treat the flexigas before combustion. The pollution costs associated with
option C are small since the increased amount of acid gas generated repre-
sented only a small increment on the existing Claus plant.
It should be recalled that these options were analyzed within the context
of geographically and functionally different refinery clusters, so that the
costs are only broadly comparable with each other.
B. SYSTEMS IMPLICATIONS
j
In broad terms, the objective of these process changes is to obtaintmore
usable clean energy out of a barrel of crude oil. In some cases, the imple-
mentation of these changes has implications beyond the confines of the refinery.
92
-------
TABLE V-2
CHANGE IN.REFINERY ENERGY USAGE
RESULTING FROM PROCESS CHANGES
Refinery Energy Ratio
Base line with
Option Location Base line Process Change
A-l East Coast 0.904 0.903
A-2 West Coast 0.941 0.935
A-3 East Coast 0.904 0.883
B Gulf Coast 0.882 0.881
C West Coast 0.941 0.941
Heating value of products/feed plus utilities.
2
Refinery fuel in compliance with state regulations, 99.5% overall
sulfur recovery from acid gas streams and no SO control FCC catalyst
regenerator.
93
-------
TABLE V-3
ENERGY CONSUMED BY AIR POLLUTION CONTROL (APC) SYSTEMS
Options
Electricity
Fuel
Total
Baseline utilities and fuel
APC energy, % of base line
10 9 Btu/day
A-l
2.60
0.13
2.73
116.1
2.3
A- 2
0.04
0.02
0.06
127.1
0.05
, A-3
0.70
0.25
0.95
116.1
0.8
B
0.31
0.02
0.33
118.7
0.3
C
0.02
0.01
0.03
127.1
0.02
10,500 Btu/kWh used to convert to heat equivalency.
-------
VO
Ul
Option
TABLE V-4
SUMMARY OF ANNUAL POLLUTION CONTROL COSTS
. ($000)
A-2
A-l
A-3
Water Pollution
With option change
Base line
Differential
Air Pollution
With option change
Base line
Differential
Solid Waste
Differential
Total differential
Cost of pollution control,
$000/day
Operating costs for options,
$000/day
Total PC & operating cost,
$000/day
Control cost , % of total
5032
(5032)
0
12,04s1
9,9972
2,051
2051
6.2
5.6
11.8
53
4613
(4541)
74
2097
(1147)
950
2
1026
3.1
19.3
22.4
14
5735
(5032)
703
2840
(1130)
1710
230
2643
8.0
22.6
30.6
26
4963
(4919)
44
1145
-
1145
1189
3.6
20.4
24.0
15
4647
(4541
106
1145
(1145!
0
4
110
0.3
38.6
38.9
<1
Assumes pollution control by FGD <§ $0.47/106 Btu.
2Assumes pollution control by HDS and blending @ $0.39/10° Btu.
-------
1. Direct Combustion of Asphalt
The burning of heavy, high-sulfur residues in the refinery would increase
the availability of high-Btu gas and low-sulfur oil to products. The con-
sequence of this approach is to place the cost of pollution control on the
refiners, who are by virtue of available technology in the best position to
deal with it". However, the refiner must have an incentive to make this
change, viz., the prospect of recovering the additional cost in the sale of
products; consequently, the end-user must expect to pay a higher price for
fuel. Otherwise the refiner will stay with the present approach of blending
fuels.
Another alternative is to sell asphalt to a large energy user such as
an electric utility. The burning of asphalt in large boilers with pollution
controls would thereby achieve lower unit costs as a result of the improved
economies of scale. However, this presents a potential conflict with the
nation's implied energy policy to require utilities to burn coal instead of
oil.
2. On-Site Power Generation
By choosing this option, the refinery is competing with the large inte-
grated system of the electric utility. The implications of this high-sulfur
fuel burning option are basically similar to those of direct combustion dis-
cussed above, with the exception of the integrated steam/elecferical system.
3. Upgrading of Heavy Residues (H-oil, Flexicoking, Asphalt POX)
The options included in this category appear to be the most practical in
terms of implementation and pollution impact. Because these options convert
low-quality petroleum residues to higher quality and value intermediate and
final products, a refiner has an incentive to apply these alternatives,
providing there is sufficient product demand. In addition, the pollution
control requirements for these options are not unreasonably expensive and,
in general, represent only small incremental changes to already existing
facilities.
C. FACTORS AFFECTING PROBABILITY OF CHANGE
1. Direct Combustion of Asphalt
It was clear from our interviews with industry representatives that
refiners place a relatively high value on refinery gas, and selling it for
outside consumption is an alternative which generates little enthusiasm.
There are two possible situations which could bring about a change in this
attitude.
• Increased gas prices allowed by deregulation, due to severe shortages;
and
• End-use controls on methane gas.
96
-------
While such occurrences are possible, it appears that the cost of FGD would,
in most cases, discourage direct combustion of asphalt as a means of increasing
gas availability.
2. Power Generation
The most important factor affecting the implementation of this option
would be the setting of utility rates for industrial uses. Recently there
has been a lot of public consternation regarding the present inverted rate
structure which favors large industrial users. Pressure is building, par-
ticularly on the East and West Coasts, to adopt a uniform rate structure.
Depending on the outcome, this option could be selected by refiners.
Again, the cost of FGD has an identifiable impact on combustion of
asphalt for this purpose. Consequently, internal generation of electricity
would most likely be implemented by integrating a topping cycle into the
refinery high-pressure steam/waste heat recovery system, since the refinery
has many uses for process steam.
3. Upgrading of Asphalt
The factors affecting the choice of upgrading processes for heavy resi-
dues are many and complex (as indicated in section IV-B). Important factors
include the quality of the crudes processed by the refinery and the demands
for the various products, recognizing that the product yields from the avail-
able processes also vary widely. With crude quality in U.S. refineries gen-
erally on the decline, and with unimpressive growth prospects for asphalt
and coke, we expect that more heavy residue conversion will be practiced.
D. AREAS FOR RESEARCH
In the petroleum refining sector, there are two main technology research
areas which could produce benefits for the nation in terms of energy avail-
ability and improved environmental quality. The first is improving the
reliability and reducing the cost of flue gas desulfurization systems,
especially in the size range below 50 MW equivalent. The second is to develop
rugged hydrocracking catalysts capable of withstanding the poisonous metals
which concentrate in petroleum residues or, alternatively, developing a low-
cost residual demetallizing process which would, in effect, have the same
result, viz., increased catalyst activity and product yields. Technology
improvements in either area would increase the yield of clean fuels by
permitting greater flexibility in the use of petroleum heavy-ends, and
simultaneously ensuring environmental quality.
97
-------
REFERENCES
Bryant, H. S., "Environment Needs Guide Refinery Sulfur Recovery," The Oil &
Gas Journal, March 1973.
Burchard, J. K., Some General Economics Considerations of Flue Gas Scrubbing
for Utilities, Control Systems Division, EPA.
U.S. Environmental Protection Agency, Compilation of Air Pollution Emission
Factors, AP-42 EPA, 3nd ed., April 1973.
U.S. Environmental Protection Agency, Development Document for Proposed
Effluent Limitations Guidelines and New Source Performance Standards for
Petroleum Refining, Effluent Guidelines Div., EPA. 440/1-73/014.
Goar, B. G., "Cost, Air Regulations Affect Process Choice," The Oil & Gas
Journal, August 1975.
Arthur D. Little, Inc., The Impact of Lead Additive Regulations on the
Petroleum Refining Industry, EPA Contract 68-02-1332, Task Order No. 7,
Final Report, 1975. (ADL, 1975a)
Arthur D. Little, Inc., The Impact of Producing Low-Sulfur, Unleaded
Motor Gasoline on the Petroleum Refining Industry, Contract 68-02-1332,
Task Order No. 8, Final Report, 1975. (ADL, 1975b)
Effluent Guidelines and Standards - Petroleum Refining, 40 CFR 419
Fed. Reg., May 1974.
98
-------
APPENDIX A
INDUSTRY STRUCTURE
1. DESCRIPTION
The petroleum refining industry is perhaps one of the most complex and
technically sophisticated industries in the United States. There are some
250 to 300 refineries in the United States ranging in size from about
400,000 BPD to only a. few hundred BPD. These refineries vary from a fully
integrated, high-complexity plant capable of producing a complete range of
petroleum products and some petrochemicals to very simple plants capable of
producing only a very small number of products. Also some refineries are
modern and of recent construction, while others contain at least some oper-
ating process units constructed 40 or more years ago. A survey of operating
refineries in the United States between 1962 and 1972 is presented in
Table A-l. The crude slates for refineries vary widely and the product mixes
and, to some extent, product properties also vary from refinery to refinery.
Because of this, each refinery is characterized by a unique capacity, pro-
cessing configuration, and product distribution.
For the purpose of collecting statistics on the refining industry, the
United States has been divided into several refining regions called Petroleum
Administration for Defense (PAD) districts. Figure A-l indicates which states
are included in each region. A breakdown of refining capacities and actual
crude runs by PAD districts for the period I960 through 1974 are shown in
Table A-2. The major growth in capacity over this period has been in PAD's II,
III, and V, as one might expect.
It is apparent that the refining industry is characterized by a diver-
sity of operations; however, within a given PAD district, there are similarities.
ADL has developed a computer simulation of the refining industry based
upon six cluster models which represent geographic regions (PAD's) in the
United States having refineries with similar characteristics. These six models
have been successfully used to simulate the 250 to 300 individual refineries
and hence the U.S. refinery industry (EPA 68-02-1332 Task Order No. 7). Gen-
erally each cluster model corresponds to a PAD district; however, PAD III,
representing 40% of the U.S. total refining capacity, was simulated by two
models, while PAD IV (Rocky Mountains) represented such a small percent of
the refining industry (less than 5% of the total) that it was not simulated
at all.
99
-------
TABLE A-l
SURVEY OF OPERATING REFINERIES IN THE UNITED STATES - 1962-1972
Charge Capacity (BPSD x 10s)
M
O
O
Operating Refining
Number Capacity
Date Plants BPCD x 106 BPSD x 10'
1/1/62 299 10.01 10.59
1/1/63 293 9.92 10.46
1/1/64 288 10.18 10.72
1/1/65 275 10.25 10.76
1/1/66 265 10.25 10.75
1/1/67 261 10.45 10.95
1/1/68 269 11.14 11.66
1/1/69 263 11.57 12.08
1/1/70 262 12.15 12.65
1/1/71 253 12.68 13.28
l/l/'2 247 13.09 13.71
Increnental Change
1962-1972 3.08 3.12
I crude 100.0 101.3
NPC Questionnaire
S Expansion Data (HUB/CD)
1973-1978 1.8
Z Crude 100.0
Vacuum
Distillation
3.67
3.58
3.75
3.76
3.76
3.89
4.08
4.12
4.55
4.74
4.85
1.18
37.8
0.50
28.0
Thermal
Operation
1.81
1.75
1.72
1.64
1.69
1.64
1.66
1.60
1.64
1.56
1.53
(0.28)
(9.0)
(0.18)
(1.0)
Catalytic
Fresh
Feed
3.75
3.89
3.99
3.99
3.96
3.95
4.18
4.25
4.37
4.51
4.57
0.82
26.3
0.20
11.0
Cracking
Recycle
1.47
1.55
1.62
1.57
1.53
1.65
i.60
1.55
1.49
1.46
1.26
(0.21)
(6.7)
0.0
0.0
Catalytic
Reforming
2.02
1.99
2.05
2.06
2.09
2.19
2.38
2.54
2.78
2.89
3.17
1.15
36.9
0.67
37.0
Catalytic
Hydro-
-
-
-
-
-
-
0.41
0.50
0.60
0.73
0.84
0.43
13.8
0.11
6.0
Catalytic
Hydro-
-
-
-
-
-
0.55
0.54
0.54
0.63
0.08
2.6
0.67
37.0
Catalytic
Hydro-
2.37
2.54
2.75
2.93
3.10
3.35
3.66
3.27
3.51
3.81
4.26
1,89
60.6
0.99
55.0
Alkyla-
0.46
0.49
O.JO
0.53
0.55
0.60
0.65
0.67
0.75
0.78
0.82
0.36
11.5
0.13
7.0
Catalytic
Polynerlza-
0.14
0.13
0.13
0.13
0.12
0.11
0.10
+0.25
0.29
0.31
0.29
-
-
0.14
8.0
Lube
0.21
0.20
0.20
0.21
0.21
0.21
0.21
0.20
0.21
0.22
0.22
0.01
0.3
o.ia
1.0
Asphalt
0.49
0.49
0.51
0.54
0.53
0.54
0.53
0.57
0.58
0.60
0.62
0.13
4.2
0.09
5.0
Coke
(MT/SD)
18.90
19.20
20.94
21.14
23.03
25.00
28.43
29.43
35.49
38.77
41.47
22. S7
-
6.4
-
Aromatic and isomerization reported beginning 1/1/69.
Source: Oil and Gas Journal, Annual Refining Reports (January 1, 1962 through January 1, 1972); NPC Reflnlni; Survu-y Quustlnnnii.ro C197"J through 1978).
-------
(INC L.ALASKA
AiMD HAWAII]
Ri-hiii'iV C.IIMI-IIV. 1000 BPD
Source: Hiin'.iu ul Mini's
Figure A-l. Petroleum Administration for Defense (PAD) Districts
-------
TABLE A-2
U.S. PETROLEUM REFINING CAPACITY AND ACTUAL CRUDE RUNS
AVERAGE JANUARY 1 CAPACITY IN GIVEN YEAR AND JANUARY 1 CAPACITY IN THE FOLLOWING YEAR
(BPCD x 103)
Year
District I
CAP RUNS
District II
CAP RUNS
District III
CAP RUNS
District IV
CAP RUNS
District V
CAP RUNS
Total U.S.
CAP RUNS PERCENT
o
to
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1,537
1,558
1,543
1,493
1,464
1,420
1,400
1,416
1,452
1,477
1,487
1,515
1,566
1,638
1,643
1,217
1,223
1,214
1,246
1,212
1,200
1,259
1,267
1,303
1,309
1,290
1,330
1,318
1,501
1,409
2,766
2,784
2,809
2,847
2,870
2,896
2,951
3,049
3,161
3,220
3,360
3,482
3,567
3,777
3,950
2,415
2,433
2,463
2,541
2,570
2,645
2,790
2,849
2,959
3,013
3,154
3,230
3,311
3,485
3,333
3,464
3,520
3,584
3,671
3,805
3,864
3,906
4,228
4,581
4,737
5,027
5,345
5,498
5,733
6,086
2,983
3,026
3,178
3,325
3,410
3,506
3,665
3,903
4,118
4,264
4,357
4,492
4,817
5,054
5,103
330
345
360
375
385
386
386
394
413
422
424
424
438
479
518
285
284
304
307
319
330
338
344
366
385
393
405
397
415
421
1,488
1,515
1,519
1,555
1,589
1,600
1,649
1,707
1,770
1,875
1,974
2,081
2,178
2,212
2,289
1,166
1,219
1,252
1,268
1,295
1,362
1,392
1,452
1,567
1,658
1,676
1,742
1,853
1,975
1,869
9,585
9,722
9,815
9,941
10,113
10,166
10,292
10,794
11,377
11,731
12,272
12,847
13,247
13,839
14,486
8,066
8,185
8,411
8,687
8,806
9,043
9,444
9,815
10,313
10,629
10,870
11,199
11,696
12,430
12,135
84.2
84.2
85.7
87.4
87.1
89.0
91.8
90.9
90.6
90.6
88.6
87.2
88.3
89.8
83.8
CAP — Capacity of operating refineries. Source: U.S. Bureau of Mines. Data for 1975 and later obtained by adding
known projects from Table A-ll.
RUNS — Crude runs for year indicated from U.S. Bureau of Mines...1975 per Office of Oil and Gas estimate. 1975
and later at 90 percent utilization is illustrative and not a forecast.
Source: FEA
-------
The major factor used by ADL in selecting the refineries in a cluster
was the process configuration. Hence these clusters are indicative of the
types of refineries in the different PAD regions of the United States today,
except for small (less than 30,000 BPD) atypical plants. These are discussed
later.
In addition to the typical refineries, there are a large number of small,
non-integrated, essentially unique refineries in the United States. These
small refineries represent well over one half of the total number of those in
the United States. However, their combined process capacity is less than 10%
of the total U.S. throughput. The plants range from those whose "primary"
product is asphalt to those that are essentially topping refineries producing
a very small number of products. Often these refining configurations are
designed to enable them to produce products for marketing in the immediate
geographic area. Thes'e can be viewed as specialty refineries. These refin-
eries are essentially incapable of simulation or easy description, except on
a case-by-case basis. Their energy consumption per barrel of feed or product
will vary widely as will their pollution emissions.
2. ECONOMIC OUTLOOK
Historically, the number of refineries in the United States has decreased
over the last few decades, and the average size has increased dramatically
during the same time period as indicated in Table A-3. During the past
4-5 years or so, there have been few new grass root refineries built in the
United States. There have been several major expansions to existing refin-
eries and, of course, many revamps of existing units to reflect changing
technology. There are currently no new refineries under construction in the
United States, although there are several in the planning stage, including at
least one in the northeast (Table A-4). There have also been several refinery
projects, both grass roots and modernization, cancelled or greatly delayed in
the last few years (Table A-5), because of environmental constraints. Many
of these were in the northeast where environmental concern is great.
The companies interviewed by ADL did not anticipate rapid growth in the
U.S. refining capacity between now and 1985. Some companies interviewed even
expected no refinery growth (in crude capacity) before 1985 within the
United States. They expected the growth to occur outside the United States.
There would be downstream (of the crude unit) additions, alterations, and
the like. One reason for the anticipated limited growth in capacity was
forecast of nearly zero growth in gaspline demand (see later). A second rea-
son was the rapid increase in cost of a modern refinery - from $2000/bbl of
daily capacity a few years ago to $3000 to $4000/bbl now, i.e., a 100,000-BPD
refinery, perhaps the smallest practical size, would cost $400,000,000. Each
103
-------
TABLE A-3
HISTORICAL REFINING CAPACITY DATA - TOTAL UNITED STATES
ND. of Beginning
Operating Operating
Refineries Capacity Shutdown Capacity
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
10-Yr Summary**
Compounded
Annual
Rate of Increase
B£D BEE.
287 9,793,748* 292,899
287 9,814,791 303,530
282 10,063,164 322,210
273 10,161,311 613,284
267 10,171,159 321,580
260 10,412,447 347,160
270 11,172,594 360,160
264 11,575,829 163,680
262 11,882,393 191,930
253 12,658,248 361,730
9,793,748
or (Decrease)
Capacity Lost
Through
Total or Partial Capacity Lost
t
3.0
3.1
3.2
6.0
3.2
3.3
3.2
1.4
1.6
2.9
Refinery Shutdowns Through Consolidations
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
10-Yr
Summary**
Compounded
No
5
8
14
4
6
2
10
6
11
_7
73
Annual
_._ BPD X No. BPD
57,300 .6 3 10,250
49,900 .5 1 1,100
113,044 1.1 9 273,280
44,300 .4 2 7,000
57,200 .6 2 40,500
3,500 .0 2 80,400
46,650 .3 1 2,000
40,600 .4 1 20,600
102,300 .9 2 120,900
58.300 .5 _1 72.000
573,094 5.9 24 628,030
Rate of Increase or (Decrease) . S
Z
.1
.0
2.7
.1
.4
.8
.0
.2
.1
.6
6.4
.6
No.
31
21
28
19
21
18
19
22
18
29
226
Additions
HO^_ BPD
64 211,119
61 233,775
54 357,731
56 139,596
82 428,663
91 665,313
88 492,114
73 412,146
81 814,149
54 418.250
704 4,172,856
Other Declines
in Capacity
BPD %
149,026 1.5
76,502 .8
71,210 .7
79,148 .8
90,675 .9
23,416 .2
41,129 .4
133,382 1.2
95,094 .8
183.880 1.4
943,462 9.6
.9
% No.
2.2 4
2.4 3
3.6 6
1.4 1
4.2 1
6.4 12
4.4 1
3.6 1
6.9 3
3.3 5
42.7 38
3.6
No.
39
30
51
25
29
22
30
29
31
37
323
Grassroots
BPD
26,500
142,100 1
197,950 2
700
1,000
202,250 1
800
89,000
280,000 2
272.500 _2
1,212,800 12
1
Total Declines
BPD
216,576
127,502
457,534
130,448
188,375
107,316
89,779
194,582
318,294
314.180
2,144.586
Total Additions
Z No.
.3 68
.4 64
.0 60
.0 57
.0 83
.9 103
.0 89
.8 74
.4 84
.2 59
.4 742
.2
BPD
237,619
375,875
555,681
140,296
429,663
867,563
492, 914
501,146
1,094,149
690,750
5,385,656
Net Increa
£
2.4
3.8
5.6
1.4
4.2
8.3
4.4
4.3
9.2
5.5
55.0
4.5
se
or (Decrease)
Z
2.2
1.3
4.5
1.3
1.9
1.0
.7
1.7
2.7
2.5
21.8
2.0
BPD
21,043
248,373
98,147
9,848 -
241,288
760,247
403,135
306,564
775,855
376,570
3,241,070
Z
.2
2.5
1.0
.1
2.4
7.3
3.6
2.7
6.5
3.0
33.1
2.9
Ending
Operating
Capacity
BPD
9,814,791
10,063,164
10,161,311
10,171,159
10,412,447
11,172,694
11,575,829
11,882,393
12,658,248
13,034.818
13,034,818
1/1/62 capacity later revised by Bureau of Mines to 9,812,248 BFD.
**
10-year summary percentages are based on 1962 beginning operating capacity.
Source: U.S. Bureau of Mines, "Petroleum Refineries in the United States", Mineral Industries Survey, published annually.
NPC
-------
TABLE A-4
NEW REFINERIES, EXPANSIONS AND REACTIVATIONS SCHEDULED IN THE UNITED STATES BY PAD DISTRICTS
(BPCD x 103 of Crude Distillation)
Type
Code*
E
E
E
E
E
E
E
E
E
E
E
R
N
E
E
E
E
E
E
R
N
E
E
Company /Location
1975
Socal (Perth Amboy, NJ)
Standard of Indiana (Baltimore, MD)
Clark (Hartford, IL)
CRA (Phillipsburg, KS)
Bay Refining (Bay City, MI)
Conoco (Ponca City, OK)
Kerr McGee (Wynnewood, OK)
Gladieux (Fort Wayne, IN)
Vickers (Ardmore, OK)
United Refining (West Branch, MI)
Lakeside Refining (Kalamazoo, MI)
Saber (Corpus Christi, TX)
Sigmor (Three Rivers, TX)
Good Hope (Good Hope , LA)
Marion (Theodore, AL)
Exxon (Baton Rouge, LA)
Socal (Pascagoula, MS)
Tesoro (Carizzo Springs, TX)
South Hampton (Silsbee, TX)
Wickett Ref. (Wickett, TX)
Louisiana Land & Exploration
(Mobile, AL)
Hunt (Tuscalossa, AL)
Thriftway (Graham, TX)
PAD Districts
I II III IV V
80.0
4.0
22.0
4.5
10.0
7.5
15.1
3.5
32.5
8.5
1.6
10.5
5.0
20.1
2.8
10.0
40.0
12.0
12.5
8.0
30.0
12.0
0.3
Total
80.0
4.0
22.0
4.5
10.0
7.5
15.1
3.5
32.5
8.5
1.6
10.5
5.0
20.1
2.8
10.0
40.0
12.0
12.5
8.0
30.0
12.0
0.3
Source: Trends in Refining Capacity and Utilizations, FEA
-------
TABLE A-4
NEW REFINERIES, EXPANSIONS AND REACTIVATIONS SCHEDULED IN THE UNITED STATES BY PAD DISTRICTS (Cont.)
(BPCD x 103 of Crude Distillation)
Type
Code*
E
N
E
E
N
E
Company /Location
Conoco (Commerce City, CO)
V-l Oil Co. (Glenrock, WY)
Conoco (Paramount , CA)
U.S. Oil & Refining (Tacoma, WA)
United Ind. (Tacoma, WA)
HIRI (Oahu, HI)
PAD Districts
I II III IV
2.0
1.0
—
—
—
™~ """• — — • — —
V
__
—
11.0
3.0
1.0
15.0
Total
2.0
1.0
11.0
3.0
1.0
15.0
Total (1975)
84.0 105.2 163.2
3.0
30.0
385.4
1976
E Exxon (Bayway, NJ) 20.0
E Midland Coop. (Gushing, OK)
E American Petrofina (Port Arthur, TX)
E Arco (Houston, TX)
N Ecol (Garyville, LA)
N Gulf Energy Refining (Luling, TX)
E Champlin (Corpus Christi, TX)
E Exxon (Baton Rouge, LA)
E J & W Refining (Tucker, TX)
E Thagard Oil (SouthGate, CA)
N California Oil Pur.
(Ventura County, CA) —
E Socal (Richmond, CA)
E Socal (El Segunda, CA),
N Pima (Phoenix, AZ)
Misc. Net Additions 22.0
Totar~(1976) 42.0
16.0
34.0
92.0
200.0
30.0
60.0
5.0
5.1
3.3
15.0
175.0
175.0
3.3
32.0
20.0
16.0
34.0
92.0
200.0
30.0
60.0
5.0
5.1
3.3
15.0
175.0
175.0
3.3
200.0
403.6 1,033.7
-------
TABLE A-4
NEW REFINERIES, EXPANSIONS AND REACTIVATIONS SCHEDULED IN THE UNITED STATES BY PAD DISTRICTS (Cont.)
(BPCD x 103 of Crude Distillation)
Type
Code*
E
11
Company /Location
1977
Exxon (Bay town, TX)
Energy Co. of Alaska
(Fairbanks, AK)
Misc. Net Additions
Total (1977)
E
N
1978
Texaco (Convent, LA)
Dow (Freeport, TX)
Misc. Net Additions
Total (1978)
1979
PAD Districts
I II III IV V
250.0
15.0
22.0 54.0 85.0 7.0 32.0
22.0 54.0 335.0 7.0 47.0
200.0
200.0
22.0 54.0 85.0 7.0 32.0
22.0 54.0 485.0 7.0 32.0
Pittston Co. (Eastport, ME) 250.0
Total (
Misc. Net Additions
22.0 54.0 85.0 7.0 32.0
1979) 272.0 54.0 85.0 7.0 32.0
Total
250.0
15.0
200.0
465.0
200.0
200.0
200.0
600.0
250.0
200.0
450.0
*Type Code:
E—Expansion
N—New
R—Rehabilitation
-------
TABLE A-5
REFINERIES PLANNED BUT NOT CONSTRUCTED DUE TO OPPOSITION ON ENVIRONMENTAL GROUNDS
Company
Location
Size-BPD
Final Action Blocking Project
O
00
Shell Oil Co.
Fuels Desulfurization
Maine Clean Fuels
Maine Clean Fuels
Georgia Refining Co.
Northeast Petroleum
Supermarine, Inc.
Commerce Oil
Steuart Petroleum
C. H. Sprague & Son
Belcher Oil Co.
Delaware Bay, DE 150,000
Riverhead, L.I. 200,000
South Portland, ME 200,000
Searsport, ME 200,000
Brunswick, GA 200,000
Tiverton, RI 65,000
Hoboken, NJ 100,000
Jamestown Island, RI 50,000
Piney Point, MD
Olympic Oil Refineries, Durham, NH
Inc.
Newington, NH
Manatee County, FL
100,000
400,000
50,000
200,000
• State reacted by legislature passing bill
forbidding refineries in Coastal Area.
City Council opposed project and would
not change zoning.
City Council rejected proposal.
Maine Environmental Protection Board
rejected proposal.
Blocked through actions of Office of State
Environmental Director.
City Council rejected proposal.
Hoboken Project withdrawn under pressure
from environmental groups.
Opposed by local organizations and con-
tested in court.
Rejected by St. Mary's County voters by
referendum on July 23, 1974.
Withdrawn after rejection by local refer-
endum.
Voted down in community vote on June 28, 1974.
Voted against in referendum September 10, 1974.
Maine Clean Fuels and Georgia Refining Company are subsidiaries of Fuels Desulfurization and the refinery in
question is the same in each case, so the capacity in barrels per day is not additive, but the incidents are
independent and additive.
2
Olympic is still considering other nearby sites.
-------
company interviewed commented in detail on the scarcity of capital being
one of the oil companies' major problems and one of the major inhibiting
factors in refinery growth.
Manufacturing facilities, in general, have a shorter technical life now
than a few decades ago, but the life is dependent upon the process. There
are several operating crude units which were first constructed before World
War II; they have, of course, undergone several modifications. On the other
hand, "high" technology processes, such as hydrocracking, tend to have a
shorter technical life, before some alterations, revamp, etc., have to be made.
This is particularly true of the petrochemical complexes contained within
several refineries.
The key variable in projecting the number and type of refineries is
supply/demand projections. As a component of a recently published EPA report,
ADL has just completed a major study in this area. Also, as part of this
current task, several companies were interviewed to obtain their growth pro-
jections in several critical areas. The companies interviewed agreed in
general that:
a. The gasoline growth rate between now and 1985 will be much less than
for the 1965-1973 period. Some companies, in fact, project no growth
at all; others about 2% per year maximum. The rationale used by all
companies is based on improved fuel economy for automotive engines,
coupled with a fairly rapid trend on the part of the consumer to
purchase smaller (lighter) cars.
b. The major growth areas will be petrochemicals and fuel oils.
c. Jet fuel will probably not grow nearly as rapidly as was the case
for 1965-1973.
ADL's product demand forecast has been described in detail in a recent
EPA report (EPA 68-02-1332, Task Order No. 7). The methodology and assumptions
used are also described in this report. The results of this forecast are shown
in Table A-6, which shows the projected total U.S. energy demand for 1980
and 1985, and Table A-7, which projects the U.S. hydrocarbon product demand
for 1977, 1980 and 1985. The latter table also shows the (estimated) con-
sumption for the year 1975. As these tables show, the ADL forecasts are in
general agreement with the views expressed by the companies interviewed for
this task.
109
-------
TABLE A-6
PROJECTION OF U.S. PRIMARY ENERGY SUPPLIES
WITH OIL AS THE BALANCING FUEL
(Btu x 1012)
Base Year
1972
12.3
25.1
2.8
0.6
32.5
73.3
i
High
19.6
23.9
3.2
5.8
0.1
42.5
95.1
,»ou
Low
19.8
23.9
3.2
5.8
0.1
39.2
92.0
l
High
23.6
24.7
3.3
17.5
0.2
44.7
114.0
»»:>
Low
21.5
24.7
3.2
14.7
0.2
40.9
105.2
Coal
Natural gas
Hydro
Nuclear
Non-conventional
Oil
TOTAL
Source: U.S. Bureau of Mines and Arthur D. Little, Inc. estimates
TABLE A-7
FORECAST OF U.S. PRODUCT DEMAND
(BPD x 103)
1977 1980 1985
1975 Higl
LPG & refinery gas
Naphtha & other
Gasoline
Kerosene & jet fuel
Distillate fuel oil
Residual fuel oil
Lubes, waxes, & coke
Asphalt
Refinery fuel & losses 1.28
TOTAL
1975
1.49
0.49
6.56
1.17
2.70
2.52
0.41
0.47
1.28
L7.09
High
1.68
0.56
7.37
1.32
3.42
3.14
0.45
0.53
1.43
19.90
Low
1.62
0.53
7.19
1.30
3.04
2.79
0.42
0.52
1.41
18.82
High
1.84
0.60
8.16
1.47
3.87
4.03
0.49
0.59
1.62
22.67
Low
1.75
0.58
7.52
1.39
3.11
3.24
0.47
0.55
1.53
20.14
High
2.03
0.81
9.01
1.79
4.27
3.02
0.54
0.66
1.78
23.91
Low
1.93
0.76
7.52
1.60
3.40
2.75
0.52
0.61
1.69
20.78
110
-------
APPENDIX B
PRESENT TECHNOLOGY
1. FEEDSTOCKS
There are literally thousands of different crude oils produced in the
world today, a large number of which are processed in U.S. refineries. The
crudes can be described by such terms as light, heavy, sweet, soiir, domestic,
foreign, lube stock, waxy, paraffinic, and the like. Any one refinery, other
than the smallest and most simple, will process perhaps one or two dozen dif-
ferent crudes, in blends of varying composition. In some cases, crudes will
be segregated (blocked) so' that they can be processed separately. Yet another
possibility is sending a particular crude to a dedicated process unit - e.g.,
to produce lube oils, petrochemical precursors, and the like.
The crude slate and process configuration impose limitations on the pro-
duct mix that a refinery can produce. In the extreme, a change in crude type
can downgrade refinery capacity and hence product output^ Similarly, a refinery
designed to run on sweet (low sulfur) crude may be incapable of processing
sour (high sulfur) crude. There are two major reasons for this:
a. The sour crude is more corrosive and the metallurgy of the crude
unit may not be adequate; and
b. The higher sulfur crude produces more pollutants (l^S, S02, etc.)
which the refinery may be incapable of removing without major
alterations.
Another important factor is that each crude has different distillation
properties, different yields of products, and products with different blending
properties. To further make description of crude slates more difficult, two
other factors must be considered.
a. Crude production and properties for a given oil field vary with time
and location in the field. For example, not only has California
crude production declined over the past few years, but the gravity
of the crude oil has also become heavier. This tends to make the
crude less valuable to a refinery because processing is more diffi-
cult and the yield of light products per barrel will go down.
b. Forecasting of crude production is extremely hard; yet to design new
refineries, and make intelligent alterations to existing refineries,
a major variable is the knowledge of the crude slate.
Ill
-------
2. DESCRIPTION OF MAJOR REFINING PROCESSES
A modern, large, integrated refinery will use most of the following pro-
cesses. (There are several types listed for some categories, such as catalytic
cracking).
• Crude distillation;
• Vacuum distillation:
• Thermal processes, including gas oil cracking, vis-breaking, fluid
coking, and delayed coking;
• Catalytic cracking, including fluid, thermoform, and houdriflow;
• Reforming, including catalytic (semiregenerative, conventional or
bimetallic catalyst) and cyclic (both catalyst types);
• Hydrocracking, including distillate, residual, lubes, and other;
• Hydrorefining, including residual, heavy gas oil, residual, vis-
breaking, catalytic feed, and distillate;
- • Hydrotreating, including reformer feed, naphtha, olefin/aromatics
saturation, straight run distillate, lubes, and other distillates;
• Alkylation;
• Aromatic/Isomerization (BTX);
• Lube oil production; and
• Asphalt production.
In addition to these processes, there are units, such as desalters, sour
water strippers, Glaus plants, API separators, etc., within a refinery which do
not process crude directly, but are vital components for pollution control or
feed preparation. Also, a refinery will contain a large cooling tower with
attendant blowdown water and washer treating facilities, plus a boiler for
steam generation and perhaps power generation.
For process description of all of these refinery technologies, the reader
is referred to the Refining Handbook Issue of Hydrocarbon Processing (1974).
3. COST FACTORS
In developing the cluster models referred to in Appendices A and C, a com-
plete characterization of the economics for the processes listed above was made.
A detailed description of these cost factors is contained in Appendix H (pp. H-37>
42) of our report to EPA on impact of lead additive regulation. The comparative
economics in the present study were developed on an incremental basis and did
not require the evaluation of economics for every process in the refinery.
112
-------
APPENDIX C
BASE LINE ENERGY USE
1. REFINERY SIMULATION
The U.S. refining industry is composed of nearly 300 individual refin-
eries scattered throughout the country, each characterized by a unique capacity,
processing configuration, and product distribution. There are, however, logi-
cal regional groupings of major refineries with similar crude supply patterns,
processing configurations, and product outputs. Therefore, the cluster model
approach was used in developing base lines for this study. The existing U.S.
refinery industry was simulated by the average operation of three similar
refineries located in each of three selected regions, namely, East Coast (PAD I),
Gulf Coast (PAD III), and West Coast (PAD V).
The selection of three representative refineries within each of the
selected regions was accomplished with the assistance of the API/NPRA Task
Force cooperating in a previous ADL study for EPA. (The Impact of Lead Addi-
tive Regulations on the Petroleum Refining Industry Contract No. 68-02-1332,
T.O. No. 7). The most important criteria guiding the selection of these
cluster models were: (1) each cluster model was to represent, as closely as
possible, a realistic mode of operation, in that processing units were to be
of normal commercial size, and that plants would be allowed normal flexibility
in regard to raw material selection and product mix; (2) the cluster model
crude slate, processing configurations, and product outputs were to bracket,
as best as possible, those variations peculiar to each geographic region.
The final selection of refineries to be represented by the cluster models
is shown in Table C-l.
PAD District I was simulated by three refineries in the Philadelphia-
New Jersey area with capacities ranging from 160,000 to 255,000 BPD. In PAD
District III, which represents about 40% of the U.S. refining capacity, dif-
fering types of refinery configurations can be identified. The Texas Gulf
cluster is typified by a crude capacity exceeding 300,000 BPD and heavy invole-
ment in petrochemicals, lubes, and other specialty products. The Louisiana
Gulf Coast cluster represents refineries between 174,000 and 240,000 BPD and
which process a single source of sweet crude. Since the olefin industry was
one of the 13 industry segments being studied, we chose the Louisiana cluster
to represent the Gulf Coast region to avoid redundancy. PAD District V was
simulated by a West Coast cluster model and was represented by refineries in
the Southern California area.
113
-------
TABLE C-l
REFINERIES SIMULATED BY CLUSTER MODELS
PAD
District
III
III
Cluster
Identification
East Coast
Texas Gulf
Louisiana Gulf
West Coast
Refineries Simulated
Arco - Philadelphia, Pa.
Sun Oil - Marcus Hook, Pa.
Exxon - Linden, New Jersey
Exxon - Baytown, Texas
Gulf Oil - Port Arthur, Texas
Mobil - Beaumont, Texas
Gulf Oil - Alliance, La.
Shell Oil - Norco, La.
Cities Service - Lake Charles, La.
Mobil - Torrance, California
Arco - Carson City, California
Socal - El Segundo, California
1973
Crude
Capacity,
1Q3 BPCD
160.0
163.0
255.0
350.0
312.1
335.0
174.0
240.0
240.0
123.5
165.0
220.0
After completion of the cluster refinery modeling, an extensive calibration/
validation effort was undertaken by ADL with the assistance of the Bureau of
Mines, Environmental Protection Agency and the API/NPRA Task Force. A complete
discussion of the calibration/validation effort is contained in the referenced
report. Only the highlights of this effort will be summarized here.
The annual refining surveys published in The Oil and Gas Journal were
used as the basic reference source for determining the cluster model processing
configurations, allowing simulation of those refineries listed in Table C-l.
This source also provided the processing unit capacity available in these
cluster refineries, used to limit the available capacity in the cluster models.
The input and output data required for each of these cluster models were
obtained from the Bureau of Mines as 1973 annual data, for the aggregate of the
three specific refineries comprising each individual cluster model (Table C-l).
These data included the crude oil and other raw materials fed to the refineries,
broken down by individual state or origin for domestic crudes and by country
of origin for foreign sources. These data also included statistics on fuel
consumed for all purposes in the refineries for the year 1973. Also included
were all petroleum products from the cluster refineries for this base year.
114
-------
The EPA and the API/NPRA Task Force obtained from each individual oil
company the average gasoline grade distribution for the calendar year 1973
and the associated octane levels and lead levels for each grade. The EPA
averaged their data to obtain information representing the cluster models,
and supplied these data to ADL. Also obtained were total gasoline volumes
and average sulfur contents as supplied by the individual companies and com-
piled by the EPA. Other key product specifications were obtained in a
similar fashion and used in the calibration runs.
Four main areas were considered to compare the degree of calibration to
the cluster models. These were: (1) overall refinery material balance
(i.e., volume of the crude intake required to balance specified product
demands and internal fuel requirements), (2) refinery energy consumption,
(3) processing configuration, throughputs and operating severities, and
(4) key product properties (e.g., gasoline clear pool octanes, lead levels,
etc.). The refinery configurations and capacities are shown in Figures C-l,
C-2, and C-3 for the East Coast, Gulf Coast, and West Coast calibration cases.
The refinery characteristics associated with the calibration cases are
presented in Tables C-2 through C-7. Crude intakes and product slates for the
three representative refineries are summarized in Tables C-2, C-3, and C-4.
The refinery fuel balances are also shown in these tables. Although the
basic refinery input/output data are based upon 1973 Bureau of Mines statis-
tics, the information generated is also representative of operations until
mid-1974, as little change occurred in the industry over that period.
A petroleum refinery is comprised of many integrated processing steps.
The energy consumed by each processing unit within the refinery is summarized
in Tables C-5, C-6, and C-7. The capacity of each unit process is also indi-
cated. Purchased energy in the form of fuel, steam, and electricity is tabu-
lated at the bottom of each table.
The major advantage of the calibrated models is that they can be used to
determine refinery volume, energy and sulfur balances in future time, based on
projected changes in crude intakes, product demands, and process configuration.
2. STUDY BASE LINE
There are certain established energy-related influences that will cause
fundamental changes in petroleum refining operations, and thereby significantly
alter refinery energy-consumption profiles within the next decade. Two impor-
tant influences will be the phase-out of natural gas as refinery fuel and the
phase-out of tetraethyl (TEL) lead in the gasoline pool. Our forecasts indicate
that by 1985 both of these trends will have been accomplished. The implica-
tions of these trends should be quantified and taken into account in establishing
a base line for comparing future process changes within the refining industry.
Therefore, a 1985 refinery configuration and energy consumption profile was
selected as the appropriate base line for comparing process changes within this
industry. This approach reduces the aberrations associated with declining
natural gas and TEL use and provides a more representative base line against
which future process changes can be compared.
115
-------
i n i r, Tn inn F
f| SPI™T« [359 ' DESULFURIZED NAPHTHA 45
$ 84 II 1
i'"* "H NAPHTHA
1SS9 C^T0200"F 11 i REFORMATE 3073
2fl M 200.340' F _ ' J4 ^{T^^ »•» llcAl ALYTIcll ? 1 HAFI INATE
CRUDES sfL'GHUH 1 »L,TTER| ^ , jf IL^J| b98FROM „, |["EFORMER|| lUnoMMicsJ^, \ ^
ARABIAN 14.24 g -J §
LGERIAN 40.48 < 5
AJUANA 50. lil
8
g BOT
65C
70 OS
»•
" " ' —
44.7? FULL RANGE NAPHTHA 128
55.38 GASOIL J'5 TO G50"F ?.1 10
^ GASOIL
3?28 SPLITTER
TOMS
i r
VACUUM OVHO
COO 1050 F
G.I .1
VACUUM
•1 DISTILLATION
TOWER
01
1
(D
1 HUTIO'IS
f 1050- F
84 || ljr... || OESULFURIZED LIGHT GAS OIL B 3-1
LIGHT GAS OIL 376 500'F| '' • ' LIGHT GASOIL 6 5(>
^^ II HYDRO I 5.23 j HEAVY HYDROfFlACKATF.
^^| CRACK EH jl 77 HYnRO(.,lfACKl.rJ JL 1 TUL L /?
HEAVY GAS OIL 500 050 F 1^^— J (H-AVY tlASOIL '» Wi
A | MO1, UO1 ItJMS 1 »>'
VACU .'f'.1 OVEHHi: AD 7 O'l
^ 11 10 FROM
- o , TRANSFER
>LO ^ | i Ob'.UI f LJHI/FIl ; i)([
,,.,„ CRACKER LIGHT CYLLE OIL | F '1 301
' 1. .1 AIKVIAIT /'III
,.3C4 " | ||..LI.VLATKN|[ ^^^
.86 REFINERY GAS TO PETROCHEMICALS
g
NC
9703
785
GASOLIfJE
POOL
30 22 PREMIUM
68 10 REGULAR
GGI UNLEADED
1 36 BTX
1 28NAHH1HA
n
|| || DESULFURIJED VACUUM OVI.RHI AU ?M
^ ' ID" " r, fl-i
CL«RITIEOOIL5'jl ( *~
1
DISTILLATE
POOL
b7(,JET FUEL
3 W KFHOSLNE
•l6b?DISTILI.AlE FUEL Oil
4 (M LUBES
1? H'J HESIUUAL FUEL Oil.
TO PT IROCHEMK-AL'i
li 10
V\ J GA'.f. IfiEi 01.1.
VAC BOT lOV •, ?4 'JL *^
HEFIMEHY
FUEL
IB 1J A'.I'HAI 1
.35 PURCHASED IL . ton ALKYLATION
;l :.o/ Fftor 11 c f.
I 76 PURCHASED Ni. (
2.5PURCHASED NATURAL l
H J\> '..'I, F r>UI I UH HM.U"t-H Y
.1:1 i)8 :.<-V T U! i I'.t ' - I UU
B REFORMER Ff ED FRO^ TRANSFF H
OS.72 ELCMENTAt
SULFUR if
67 ?.s '.rj/i-r-.issi
11 inCAT. FEED FROM IBAKSflR
Figure C-1. East Coast Cluster Calibration
-------
PURCHASED
NATURAL GASOLINE
LOUISIANA
^
13720
TEXAS
2500
c TO 160 F
2IGCAT FEED TO TRANSFER
C5TO
200 F
SPUTTER
1 22
C5 160200 f
81
C5 TO 200 F I486
1C 88 C6TO200 F
?00 340 f
I IS TO
TRANSFER
FULL RANGE NAPHTHA
85 70 GAS OIL 375 TO 650 f
DESULFURIZEO
BOTTOMS 650
-------
H
00
CjTOIOOF
3 CP!) LPC.
REFINERY_GASTO
.45 PETRO'C"HEMICALS~OE'?
36.5? PREMIUM
CRUDES
CALIF.
WILMINGTON 58.00
CALIF"
VENTURA 21.38
CANADIAN 11.02
INDONESIAN 10.20
ARABIAN 48.60.
.50 PURCHASED IC4 FOR ALKYLATION
16 PURCHASED NC,j
6.39 PURCHASED NATURAL CAS
1.94 REFORMER FEED FROMTRANSFER_
3.60 CAT FEEOFROMTRANSFER
9.62 EOv FROM FCC
I3554JJJ.EMENTAL
SULFUR (TONSI
1.1.23 SOX F/SULFUR RECOVERY
21,43 SOX F/REFINERY FUEL
4548SOX
EMISSIONS ITONSI
Figure C-3. West Coast Cluster Model Calibration
-------
TABLE C-2
SUMMARY OF EAST COAST REFINERY OPERATION
(1974)
Refinery Location
Nominal Capacity
East Coast
200
BPD
Year 1974
Refinery Intakes 1QJ BPD
Crudes
1. Louisiana 28.9
2. Nigerian 30.4
3. Arabian Lt. 14.2
4. W. Texas Sour 14.4
5. Algerian 40.5
6. Tiajuana 59.6
Purchased IC^ 0.4
Purchased NC^ 1.8
Purchased nat. gasoline 5.8
Purchased nat. gas 2.5
Cat. feed from storage 11.1
Reform, feed from storage 6.0
Total 215.6
Refinery Fuel Balance
Sources FOE1/day
Isomerization
Atm. distillation 10
Cat. reforming 2760
Cat. cracking 2010
Hydrocracking -30
Coker gas
Imported natural gas 2500
LPG or fuel oil (blend) 7210
Total 14,520
*FOE = 6.3 x 10b Btu (HHV)
Refinery Products
Regular gasoline
Premium gasoline
Unleaded gasoline
Naphtha
No. 2 distillate
Jet fuel
Kerosene
Low S F.O.
Residual F.O.
Asphalt
Lube stocks
Coke
BTX
Mixed olefins (FOE)
Total
Consumers
Hydrogen production
feedstock
fuel
Fuel to petrochemicals
Steam generation
Process heater
Total
103 BPD
68.1
30.2
6.6
45.5
5.8
3.4
12.8
18.1
4.9
1.4
4.1
200.9
FOE/day
119
-------
TABLE C-3
SUMMARY OF GULF COAST REFINERY OPERATION
Refinery Location
Nominal. Capacity
Gulf Coast
Year
200
Refinery Intakes
Crudes
1. Louisiana Sweet
2. W. Texas Sour
103 BPD
103 BPD
197
25
Purchased
Purchased NC^
Purchased nat. gasoline
Purchased nat . gas
Cat. feed from storage
Reform, feed from storage
Total
Refinery Fuel Balance
Sources
Isoraerization
Atm. distillation
Cat. reforming
Cat. cracking
Hydrocracking
Coker gas
Imported natural gas
LPG or fuel oil (blend)
Total
= 6.3 x 106 Btu (HHV)
6
6
4.3
5.4
243.7
FOE1/day
Refinery Products
Regular gasoline
Premium gasoline
Unleaded gasoline
Naphtha
No. 2 distillate
Jet fuel
Kerosene
Low S F.O.
Residual F.O.
Asphalt
Lube stocks
Coke
BTX
Mixed olefins (FOE)
Total
Consumers
Hydrogen production
feedstock
fuel
Fuel to petrochemicals
Steam generation
Process heaters
Total
1974
103 BPD
69
41
8.8
67.8
67.8
18.5
5.5
5.4
1.6
4.1
2.4
224.1
FOE/day
120
-------
TABLE C-A
SUMMARY OF WEST COAST REFINERY OPERATION
Refinery Location West Coast
Nominal Capacity 175
Refinery Intakes
Crudes
1 . Wilmington
2. Ventura
3 . Canadian
4. Imported sour
5. Indonesia-Mines
Purchased IC^
Purchased NC^
Purchased nat. gasoline
Purchased nat- gas
Cat. feed from storage
Reform, feed from storage
Total
Refinery Fuel Balance
Sources
10 3 BPD
10 BPD
58.0
21.4
11.0
48.6
16.2
0.5
0.2
1.3
6.4
3.6
1.9
169.1
FOE1 /day
Year
Refinery Products
Regular gasoline
Premium gasoline
Unleaded gasoline
Naphtha
No. 2 distillate
Jet fuel
Kerosene
Low S F.O.
Residual F.O.
Asphalt
Lube stocks
Coke
BTX
Mixed olefins (FOE)
Total
Consumers
1974
10 3 BPD
30.7
36.5
0.5
22.2
19.9
0.2
30.6
2.0
0.4
9.6
3.9
1.3
157.8
FOE/ day.
Isomerization
Atm. distillation
Cat. reforming
Cat. cracking
Hydrocracking
Coker gas
Imported natural gas
LPG or fuel oil (blend)
Total
= 6.3 x 10b Btu (HHV)
Hydrogen production
feedstock 1,739
fuel I-289
Fuel to petrochemicals 130
Steam generation 3,373
Process heaters 9,189
Total 15,720
121
-------
TABLE C-5
SUMMARY OF EAST COAST REFINERY ENERGY CONSUMPTION
(1974)
Unit Capacity
Refinery Fuel Steam Electricity
Process Unit
Atmospheric distillation
Vacuum distillation
Cat. cracking
Alkylation (product
basis)
Isomerization
Cat. reforming
Hydrocracking
Coking
H- production (feed &
fuel)
Sulfur recovery1
Naphtha splitter
Atm. G.O. splitter
Aromatics extraction
Naphtha desulf urization'
Gas oil desulf urization3
Cycle oil desulf urization
Coker naphtha desulfuri-
zation
Steam boilers
Total Consumed
BPD x 103
188
79.1
72.4
8.0
-
39.5
7.5
-
23 106 scfpd
93.8 tpd
43.4
32.3
2.7
34.3
8.4
7.6
-
™
106 Btu/day
23,732
5,097
8,694
4,624
-
14,421
1,399
-
10,603
1,688
384
410
36
2,363
712
560
11,296
86,069
10 3 Ib/da
8,098
2,425
68
220
-
46
111
23
447
-
-
1,088
375
113
89
_
(7,472)
5,631
235.4
16.2
138.0
27.2
150.3
74.0
4.0
8.9
5.4
39.0
14.4
11.6
3.7
713.7
Purchased Energy
15,750
5,631
713.7
Sulfur plant steam used to boil up amine stripper.
2Includes light and heavy naphtha.
3Includes light and heavy gas oil.
122
-------
TABLE C-6
SUMMARY OF GULF COAST REFINERY ENERGY CONSUMPTION
(1974)
Unit Capacity Refinery Fuel Steam Electricity
Process Unit BPD x 103 _106 Btu/day 103 Ib/day 103 kWh/day
Atmospheric distillation 222.2 27,997 9 555 277 8
Vacuumdistillation 85.3 5,368 2,558 17.1
Cat. cracking 82.2 12,764 82 172.1
Alkylation (product
basis) 17.5 10,994 524 64.6
Isomerization
Cat. reforming 28.3 8,915 28 84.8
Hydrocracking 6.6 1,172 96 60.3
Coking 15.8 2,986 474 23.7
H~ production (feed &
fuel) 13.6 10G scfpd 6,243 14 2.3
Sulfur recovery1 61.7 tPd 806 213 4.3
Naphtha splitter 44.7 284
Atm. G.O. splitter 33.9 428
Aromatics extraction
Naphtha desulfurization2 24.7 1,556 247 24.7
Gas oil desulfurization3 2.4 151 24 2.9
Cycle oil desulfurization
Coker naphtha desulfuri-
zation 3.0 189 30 2.9
Steam boilers — 20,172 (13,340) 6.7
Total Consumed 100,025 505 744.2
Purchased Energy 34,020 505 744.2
1Sulfur plant steam used to boil up amine stripper.
2Includes light and heavy naphtha.
3Includes light and heavy gas oil.
123
-------
TABLE C-7
SUMMARY OF WEST COAST REFINERY ENERGY CONSUMPTION
(1974)
Process Unit
Atmospheric distillation
Vacuum distillation
Cat. cracking
Alkylation (product
basis)
Isomerization
Cat. reforming
Hydrocracking
Coking
H- production (feed &
fuel)
Sulfur recovery
Naphtha splitter
Atm. G.O. splitter
Aromatics extraction
Naphtha desulfurization2
Gas oil desulfurization3
Cycle oil desulfurization
Coker naphtha desulfuri-
zation
Steam boilers
Total Consumed
Purchased Energy
Unit Capacity Refinery Fuel
BPD x 103 10G Btu/day_
155.2
82.2
35.0
5.5
37.3
22.1
39.4
41.6 106 scfpd
139.5 tpd
31.5
30.9
-
24.7
7.4
7.4
19,555
5,179
4,410.
3,484
12,153
3,900
3,200
19,076
2,615
258
391
284
1,525
466
466
21,250
98,212
40,257
Steam Electricity
10 3 Ib/dav 10 3 kWh/day
6,674
2,464
35
166
37
322
508
42
691
-
-
3,560
242
74
74
(15,570)
( 682)
682
194.0
16.4
70.0
20.5
120.2
199.0
59.1
7.1
13.8
-
17.8
24.8
8.9
7.4
7.8
766.8
766.8
^Sulfur plant steam used to boil up amine stripper.
2Includes light and heavy naphtha.
^Includes light and heavy gas oil.
124
-------
The calibrated cluster models were utilized to characterize the 1985
operations with the above constraints in effect. Information on refinery
intake and outputs, fuel balances, and energy consumption by unit process
are summarized in Tables C-8 to C-18 and C-ll to C-13 for the 1985 time-
frame. These base line scenarios assume no natural gas component in the
refinery fuel and the production of only lead-free gasoline. The important
shifts in refinery energy usage occurring over this period (1974-1985) are
presented in Table C-14. In 1985, the total refinery fuel requirement must
be furnished from internal energy sources. This is accomplished through
increased consumption of refinery gas (methane/ethane) and blended fuel oil
fractions. Restrictions were imposed on the refinery fuel oil sulfur level
in each region. These restrictions comply with the existing legislated
limits as outlined below:
Region Maximum Sulfur, wt.%
East Coast 0.6
Louisiana Gulf 0.9
West Coast 0.7
As indicated in Table C-14, fuel and electric power consumption will be
about 18% higher in 1985. Refinery energy consumption will generally be
higher due primarily to catalytic reformer severity upgrading to meet unleaded
gasoline RON values (see discussion in Chapter IV-C).
3. ENERGY CONSIDERATIONS
Historically, the refinery fuel balance was made up of purchased natural
gas, refinery fuel gas, and oil. In the Gulf Coast and West Coast regions,
natural gas furnished from one-third to one-half of the refinery fuel balance.
The fuel consumed by a refinery in the processing of crude to finished pro-
duct is in the order of 8 to 11% of crude runs. Since the management of the
refinery fuel system is an integral part of the refinery operation, the allo-
cation of intermediate product streams can have an effect on the final product
slates. For example, switching large process heaters and boilers from gas to
liquid fuels is technically feasible and the displaced C^ gas could be
exported for higher priority uses. Consequently, changes in the refinery fuel
blend can result in energy conservation in terms of form value.
Changes in processing, particularly upgrading, also have important energy
implications. While these processes in general may result in an increase in
overall refinery energy consumption, they produce higher valued light products
from petroleum residues and thereby result in a form value benefit.
In summary, the operation of a refinery is moderately energy-intensive
and the potential form value conservation is relatively high due to the ability
to modify the product slate through management of the fuel system and modifica-
tion of the process sequences. Reductions in the 6-10% of crude consumed as
fuel are also possible through better heat recovery and "energy" auditing;
however, these methods are excluded from the scope of this study.
125
-------
TABLE C-8
SUMMARY OF EAST COAST REFINERY OPERATION
(1985)
Refinery Location
Nominal Capacity _
East Coast
Year 1985
200
103 BPD
Refinery Intakes
Crudes
1• Tiaj uana
2« Nigerian
3. Arabian Light
4. Algerian
Purchased IC^
Purchased NC^
Purchased nat. gasoline
Purchased nat. gas
Cat. feed from storage
Reform, feed from storage
Total
Refinery Fuel Balance
Sources
Isomerization
Atm. distillation
Cat. reforming
Cat. cracking
Hydrocracking
Coker gas
Imported natural gas
LPG or fuel oil (blend)
Total
'FOE = 6.3 x 106 Btu (HHV)
BPD
32.7
38.0
90.4
36.8
0.2
1.2
5.8
FOE1/day
270
60
3,740
2,880
40
Refinery Products 103 BPD
Regular gasoline
Premium gasoline
Unleaded gasoline 106.9
Naphtha 1.3
No. 2 distillate 47.0
Jet fuel 5.9
Kerosene 3.5
Low S F.O. 13.2
Residual F.O.
Asphalt 18.7
Lube stocks 5.1
Coke
BTX 1-4
Mixed olefins (FOE) 4.3
Total 207.3
Consumers FOE/day
Hydrogen production 1,580
feedstock 907
fuel 673
Fuel to petrochemicals 890
Steam generation 1,920
Process heaters 12,240
Total 16,630
126
-------
TABLE C-9
SUMMARY OF GULF COAST REFINERY OPERATION
(1985)
Refinery Location
Nominal, Capacity
Gulf Coast
200
1CT BPD
Year 1985
Refinery Intakes
Crudes
1. Texas Sour
2. Louisiana Sweet
Purchased
Purchased
Purchased nat . gasoline
Purchased nat. gas
Cat. feed from storage
Reform, feed from storage
Total
Refinery Fuel Balance
Sources
Isomerization
Atm. distillation
Cat. reforming
Cat. cracking
Hydrocracking
Coker gas
Imported natural gas
LPG or fuel oil (blend)
Total
= 6.3 x 10b Btu (HHV)
10 BPD
25.7
192.3
4.7
4.2
3.0
229.9
FOE1/day
230
10
2,880
2,160
30
1,570
Refinery Products 10 BPD
Regular gasoline
Premium gasoline
Unleaded gasoline 112.5
Naphtha 0.7
No. 2 distillate 63.8
Jet fuel 17.4
Kerosene 5.2
Low S F.O. 5.0
Residual F.O.
Asphalt 1.5
Lube stocks
Coke 3.9
BTX
Mixed olefins (FOE) 2.3
Total 212.3
Consumers _
Hydrogen production 1,270
feedstock 729
fuel 541
Fuel to petrochemicals 300
Steam generation 3,250
Process heaters 12,760
Total 17,580
127
-------
TABLE C-10
SUMMARY OF WEST COAST REFINERY OPERATION
(1985)
Refinery Location West Coast
Nominal Capacity 175
10 BPD
Year 1985
Refinery Intakes 103 BPD
Crudes
1. California Wilmington 65.7
2. California Ventura 21.7
3. Alaskan-North Slope 76.8
Purchased IC^
Purchased NC^
Purchased nat. gasoline
Purchased nat. gas
Cat. feed from storage
Reform, feed from storage
Total
Refinery Fuel Balance
>• Sources
Isomerization
Atm. distillation
Cat. reforming
Cat. cracking
Hydrocracking
Coker gas
Imported natural gas
LPG or fuel oil (blend)
Total
JFOE = 6.3 x 106 Btu (HHV)
0.4
0.1
0.9
3.6
1.9
171.1
FOE1/day
60
50
3,100
1,100
110
3,080
Refinery Products
Regular gasoline
Premium gasoline
Unleaded gasoline
Naphtha
No. 2 distillate
Jet fuel
Kerosene
Low S F.O.
Residual F.O.
Asphalt
Lube stocks
Coke
BTX
Mixed olefins (FOE)
Total
Consumers
Hydrogen production
feedstock
fuel
Fuel to petrochemicals
Steam generation
Process heaters
Total
103 BPD
70.3
3.9
22.7
20.4
0.2
FOE/day
3,750
2,153
1,597
128
-------
TABLE C-ll
SUMMARY OF EAST COAST llEFINERY ENERGY CONSUMPTION
(1985)
Process Unit
Atmospheric distillation
Vacuum distillation
Cat. cracking
Alkylation (product
basis)
Isomerization
Cat. reforming
Hydrocracking
Coking
H~ production (feed &
fuel)
Sulfur recovery1
Naphtha splitter
Atm. G.O. splitter
Aromatics extraction
Naphtha.desulfurization2
Gas oil desulfurization^
Cycle oil desulfurization
Coker naphtha desulfuri-
zation
Steam boilers
Total Consumed
Unit Capacity Refinery Fuel
BPD x 10 3 10G Btu/day
197.9
68.7
62.2
12.9
7.6
46.5
9.4
^20.7
10s scfpcd
56.8 stpcd
75.0
33.2
2.8
49.6
15.9
i 4.1
—
25,439
4,568
14,515
7,629
1,581
15,145
1,688
9,941
1,676
473
416
88
3,219
677
—
12,096
99,151
Steam
10 3 Ib/day
8,510
2,174
58
363
84
47
136
23
443
—
—
1,122
511
197
—
(8,001)
5,669
Electricity
10 3 kWh/dav
247.4
14.5
138.2
44.8
35.4
168.3
87.7
3.9
8.9
—
—
5.6
51.1
23.9
—
4.0
833.7
Purchased Energy
5,669
833.7
Sulfur plant steam used to boil up amine stripper.
2Includes light and heavy naphtha.
3Includes light and heavy gas oil.
129
-------
TABLE C-12
SUMMARY OF GULF COAST REFINERY ENERGY CONSUMPTION
(1985)
Unit Capacity Refinery Fuel Steam Electricity
Process Unit BPD x 103 106 Btu/day 103 lb/day_ 103 kWh/day
Atmospheric distillation 218.0 27,468 9,374 272.5
Vacuum distillation 75.8 4,775 2,273 15.2
Cat. cracking 80.2 12,795 80 166.6
Alkylation (product
basis) 18.1 11,422 544 67.1
Isomerization 8.1 1.537 81 27.9
Cat. reforming 35.5 11,164 35 124.1
Hydrocracking 8.8 1,562 128 79.6
Coking 17.6 3,333 529 26.4
H7 production (feed & 17.5 8,026 18 3.0
fuel) 106 scfpcd
Sulfur recovery1 30.2 stpd 914 242 4.8
Naphtha splitter 60-4 359
Arm. G.O. splitter 36.8 466
Aromatics extraction
Naphtha desulfurization2 38.1 2,400 381 31.4
Gas oil desulfurization3 31.7 1,997 317 46.7
Cycle oil desulfurization — — — —
Coker naphtha desulfuri-
zation 3.1 189 30 3.0
Steam boilers — 20,462 (13.532) 6.8
Total Consumed 108,869 500 875.1
Purchased Energy — 500 875.1
1Sulfur plant steam used to boil up amine stripper.
2Includes light and heavy naphtha.
3Includes light and heavy gas oil.
130
-------
TABLE C-13
SUMMARY OF WEST COAST REFINERY ENERGY CONSUMPTION
(1985)
Process Unit
Atmospheric distillation
Vacuum distillation
Cat. cracking
Alkylation (product
basis)
Isomerization
Cat. reforming
Hydrocracking
Coking
H_ production (feed &
2 fuel)
Sulfur recovery1
Naphtha splitter
Atm. G.O. splitter
Aromatics extraction
Naphtha desulfurization2
Gas oil desulfurization3
Cycle oil desulfurization
Coker naphtha desulfuri-
zation
Steam boilers
Total Consumed
Unit Capacity
BPD x 10 3
164.2
79.3
38.2
7.9
5.1
38.0
27.4
33.0
51.5
106 scfpcd
85.4
38.5
40.6
12.7
29.8
14.9
7.8
6.1
Refinery Fuel
106 Btu/day
20,689
4,996
5,676
5,002
964
11,939
4,830
6,237
23,600
2,583
239
510
397
1,877
980
445
381
26,580
117,925
Steam
10 3 Ib/day
7,060
2,378
38
238
51
38
397
990
52
684
—
—
5,068
298
156
71
61
(17.578)
0
Electricity
10 3 kWh/dav
205.2
15.9
79.1
29.4
18.4
133.1
246.4
49.5
8.8
13.7
—
—
25.3
29.8
18.7
9.2
6.0
8.8
897.3
Purchased Energy
897.3
1Sulfur plant steam used to boil up amine stripper.
2Includes light and heavy naphtha.
3Includes light and heavy gas oil.
131
-------
TABLE C-14
ANTICIPATED SHIFTS IN REFINERY ENERGY USAGE
CAUSED BY NATURAL GAS AND TEL PHASE-OUT
East Coast Gulf Coast Vest Coast
1974 1985 1974 1985 1974 1985
Crude Run, 103 BPD 188 198 222 218 155 164
Purchased Natural Gasoline, FOE/day 2,500 5,400 6,390
Refinery Fuel, FOE/day
Gas
Oil (Blended)
TOTAL FUEL, FOE/day
Purchased Steam, 10 lb/day
Electricity, MWh/day
4,810
7,210
14,520
5.6
713.7
6,990
9,640
16,630
5.7
838.7
5,450
5,350
16,200
0.5
744.2
6,880
10,700
17,580
0.5
875.1
7,190
2,140
15,720
0.7
766.8
7,500
11,690
19,190
0
897.3
4. TYPICAL REFINERY OPERATING COST
Refinery operating costs can vary considerably depending upon the size,
efficiency and age of a given facility. The simulation models applied in
this study are more representative of large, modern refineries.
Typical operating costs for the 1985 base line refineries are summarized
in Table C-15. The costs are presented in dollars per stream day based on
constant 1975 dollars. Capital charges on existing investment were based on
an estimated book balue of $l,000/bbl of daily capacity. Working capital was
estimated on the basis of three months' supply of crude oil and products, with
crude valued at $7.66/bbl and $12.50/bbl for domestic and imported, respectively.
132
-------
TABLE C-15
CAPITAL INVESTMENTS AND OPERATING COSTS
(Constant 1975 dollars)
East Gulf West
Coast Coast Coast
Capital Investments ($109)
(1st Q 1975 Basis)
Reforming: existing capacity 1.8 5.2
severity upgrade 6.0 1.8 0.1
new capacity 0.8
Hydrocracking: existing capacity
new capacity 0.1
Isomerization: once through upgrading 1.9 7.3 4.8
new capacity 5.3
Alkylation: new capacity 0.4 0.7 0.4
Light naphtha desulfurization: new capacity 1.4 2.6 1.6
Subtotals 15.1 15.0 12.1
Off sites and working capital at 40% 6.0 6.0 4.8
Subtotals 21.1 21.0 16.9
Approximate book value 200.0 200.0 170.0
Operating Costs ($103/day)
Purchased steam 21.9 1.6
Electricity 18.0 12.3 16.2
Cooling water 16.6 17.3 12.5
Maintenance 30.8 31.5 29.6
Manpower 53.8 44.5 71.0
Catalysts and chemicals 20.1 16.6 16.5
Fixed Costs
Depreciation 40.3 40.3 34.3
Capital charges1 480.4 434.5 359.6
TOTAL 681.9 598.6 539.7
10n investment and working capital.
133
-------
APPENDIX D
CURRENT POLLUTION PROBLEMS AND EFFECTIVENESS
OF AVAILABLE POLLUTION CONTROL TECHNOLOGY
(Base Line Characterization)
1. WATER POLLUTION
To assess the water pollution implications of anticipated energy-saving
process changes within the petroleum refining industry, it was deemed necessary
to first delineate the base case petroleum refinery in terms of the sources
and characteristics of wastewater and wastewater treatment technology and
economics.
a. Sources of Wastewater
The major use of water in petroleum refining is for steam generation and
heat transfer. The volume of water coming in direct contact with process
streams is small when compared with water for indirect cooling and heat trans-
fer. Nevertheless, almost every one of the major refining operations produces
a wastewater stream containing various pollutants. For example, ballast water
pumped out from incoming tankers is contaminated with previously stored petro-
leum products. Tank farms used for refinery product storage produce waste-
water streams due to stormwater run-off contacting petroleum-contaminated exposed
areas. Within the confines of the refinery itself, there are numerous process-
ing steps in which steam, condensate, or cooling water comes in contact with
petroleum and/or petroleum products. Superimposed over these major, rather
continuous, wastewater generation points are countless leaks and spills which
eventually drain into the central refinery sewer system. Stormwater run-off
from process areas is another significant source of wastewater.
All petroleum refineries use large amounts of non-contact cooling water.
Due to the large volumes required, it is an almost universal practice to
install a cooling tower circuit and reuse most of the water. To prevent the
buildup of naturally occurring salts in the cooling water circuit, it is neces-
sary to purge a portion of the total cooling water flow. Since it is a common
practice to use corrosion inhibitors in the cooling circuit, cooling tower
blowdown will contain such substances.
A number of attempts have been made to quantify both the flow rates and
characteristics of wastewater associated with the various refining operations.
("The Cost of Clean Water-Petroleum Refining," Federal Water Pollution Control
Administration, 14-12-100, 1967, U.S. Government Printing Office.) Since it
is a typical practice in most refineries to collect all contaminated process
134
-------
wastewater and to combine it into a single wastewater stream and to then treat
it in a central treatment facility, it is often unnecessary to deal with the
volume and characteristics of each of the component wastewater streams. Also,
the nature of the energy-saving process changes considered in this study do
not in themselves alter the major wastewater-generating refinery operations.
Thus, in assessing the water pollutional implications of alterations to the
base case refinery, it is not necessary to examine the individual wastewater
sources. Rather, it is necessary to deal with the volume and characteristics
of the total refinery wastewater effluent.
b. Wastewater Characteristics
Since petroleum and petroleum products are the major source of pollutants
in refinery wastewater, it is not surprising that chemical constituents found
in petroleum appear in the wastewater.
Raw refinery wastewater contains large quantities of oil. The oil is
present both as free oil (floatable) and as emulsified oil. In addition,
water-soluble hydrocarbons, such as phenolic compounds, which are present in
the petroleum will also be present in the wastewater.
Crude petroleum contains a variety of sulfur compounds which are removed
from the finished product in varying degrees depending on product specifica-
tions. Due to the oil/water contacting at various stages of the refining oper-
ation, a significant quantity of sulfur compounds enters the wastewater stream.
The most objectionable of these sulfur compounds are sulfides, which are typi-
cally present in the wastewater as sulfide ions.
Petroleum also contains a number of nitrogenous compounds, and therefore
refinery wastewater is typically contaminated with appreciable quantities of
ammonia. Small amounts of cyanide compounds are also present.
Carbonaceous and inorganic particulate matter from a variety of sources
(e.g., incomplete combustion, soil, and the like) are also present in refinery
wastewater, thus contributing to the suspended solids level.
Most of the above-mentioned compounds are oxidizable, and therefore
refinery wastewater will exert a chemical oxygen demand (COD).
A certain fraction of the same compounds are biodegradable, and therefore
refinery wastewater will also exert a biochemical oxygen demand (BOD^).
Petroleum also contains a variety of trace heavy metals, e.g., mercury,
cadmium, lead, etc., which vary greatly from crude to crude and have not been
extensively quantified.
Depending on the type and quantity of corrosion inhibitor used in the non-
contact cooling water circuit, the cooling tower blowdown can present pollu-
tional problems of varying significance. The most common types of corrosion
inhibitors contain chromate salts. Thus, blowdown from cooling towers can^
often contain chromium in the form of hexavalent chromium—the more objection-
able form.
135
-------
In the petroleum refining industry, there has been a continuing trend
toward wastewater volume reduction. On a gallon per barrel basis, large
modern refineries generate far less wastewater than older, smaller refineries.
Process improvements, partially motivated by a desire to decrease the volume
of wastewater that must be treated, have been largely responsible for this
decrease. Improved leak and spill management, coupled with other preventive
measures, has also contributed to the overall volume reduction. There has
also been a trend toward tighter, non-contact cooling water circuits in addi-
tion to more widespread use of air cooling.
Since the free oil fraction of refinery wastewater is readily removable,
the first step in any refinery wastewater treatment facility is an oil/water
separator, typically referred to as an "API" (American Petroleum Institute)
separator. Because of this universal feature, raw wastewater characteristics
are almost always measured after the API separator.
Based on a survey of refinery raw waste loads (". . .EPA Development Docu-
ment - Petroleum Refining ..." [EPA 440/1-73/014]), a typical unit loading
and total waste loadings for the base case refineries are tabulated in Table
D-l.
TABLE D-l
TYPICAL BASE CASE RAW REFINERY WASTE LOADS
Wastewater
Parameter
BOD 5
COD
Suspended solids
Oil & grease
Phenols
Ammonia (as N)
Sulfide
Typical
Unit Raw
Waste Loads
(Ib/Bbl)
0.025
0.070
0.0096
0.0096
0.001
0.0035
0.0035
Base Case East
and Gulf Coast
Raw Waste Load
(200,000 BPD)
(Ib/day)
5,000
14,000
1,920
1,920
200
700
700
Base Case
West Coast
Raw Waste Load
(175,000 BPD)
(Ib/day)
4,375
12,250
1,680
1,680
175
612
612
Flow
33 gal/Bbl
6,600,000 gpd
5,780,000 gpd
Notes: 1) Source: "... EPA Development Document - Petroleum
Refining ..." EPA 440/1-73/014.
2) Unit raw waste load is based on the 50% median value for a
survey of "low cracking" refineries.
136
-------
c. Regulatory Constraints
The recommended effluent guidelines for the petroleum refining industry
("Effluent Guidelines and Standards - Petroleum Refining," 40CFR 419 FR,
May 9, 1974) place limitations on the following wastewater parameters:
• BOD,-, • Ammonia,
• Total suspended solids, • Sulfide,
• Chemical oxygen demand, • Chromium (total and hexavalent), and
• Oil and grease, » pH.
• Phenolics,
The guidelines are based on a formula that takes into consideration the refinery
process configuration (e.g., "high cracking" vs. "low cracking," etc.) and the
refinery size.
Since the basis of comparison used in this study is within the 1985 time-
frame, the applicable effluent guideline treatment level is the proposed BATEA
(Best Available Technology Economically Achievable) level to be implemented
(pending comment and revision) by 1983.
Based on the appropriately adjusted BATEA limitations, treated effluent
waste loads have been computed for the base case refineries and are presented
in Table D-2.
d. Treatment Technology and Treatment Economics
To achieve the effluent waste loads presented in Table D-2, the following
treatment steps are generally considered necessary. These include:
• API oil/water separator,
• Dissolved air flotation,
• Equalization/neutralization,
• Activated sludge system (including aeration basins, clarifiers, and
sludge recycle),
• Granular media filtration,
• Carbon adsorption (with thermal regeneration),
• Stormwater collection (from process areas), and
• Chemical feed system (neutralizing chemicals and nutrients for acti-
vated sludge system).
137
-------
TABLE D-2
BASE CASE REFINERY - CHARACTERISTICS OF RAW AND TREATED PROCESS WASTEWATER
East/Gulf Coast Refinery (200,000 BPD)
Hastewater Raw Wastewater (1)
Parameter (lb/day)
BOD5 5,000
TSS 1,920
COD 14,000
Oil & grease 1,920
Phenolics 200
Ammonia (as N) 700
Sulfide 700
Total chromium Varie
(mg/ft)
91
35
254
35
3.6
12.7
12.7
!S
Hexavalent chromium Varies
Treated Effluent (2)
(Ib/day)
260
260
1,420
50
1.0
316
4.4
13(4)
0.22(4
(mg/JO
4.7
4.7
25.8
0.9
0.018
5.7
0.08
-
-
West Coast Refinery (175,000 BPD)
Raw Wastewater (1)
(Ib/day)
4,375
1,680
12,250
1,680
175
612
612
Var
(mg/«.)
91
35
254
35
3.6
12.7
12.7
ies
Varies
Treated Effluent (2)
(Ib/day)
227
227
1,243
44
0.88
277
3.85
(mg/Jl )
4.7
4.7
25.8
0.9
0.018
5.7
0.08
11.4(4)
0.19(4)
u>
oo
Flow Rate
6,600,000 gpd
5,780,000 gpd
Notes: (1) Raw wastewater characteristics derived from EPA Development Document (EPA 440/1-73/014)
(2) Raw wastewater characteristics are for wastewater downstream of the plant is API oil separator.
(3) Treated effluent loadings are based on the Best Available Technology Economically Achievable
(BATEA) treatment level for 1983, as defined in "Effluent Guidelines and Standards -
Petroleum Refining", 40 CFR 417 FR, May 9, 1974.
(4) Chromium-contaminated cooling water blowdown may be discharged as a separate waste stream.
(5) Waste loads include stormwater runoff from process areas but not from offsite facilities
such as tank farms.
-------
To process the sludge produced by the above treatment steps, the following
sludge-handling steps can be applied prior to land disposal:
• Sludge thickening,
• Vacuum filtration, and
• Fluid-bed incineration.
While chromium-contaminated cooling tower blowdown is sometimes treated
within the central process wastewater treatment facility, separate treatment
is becoming more common, because of the effluent limitations placed on chromium.
In addition, some of the anticipated energy-saving process changes increase
the quantity of cooling water. Thus, by choosing separate treatment for the
cooling tower blowdown; these differences will be more clearly highlighted.
The chromium removal system typically consists of the following steps:
• Chromium reduction via sulfur dioxide addition,
• Chromium precipitation (with lime), and
• Landfill -of chrome hydroxide sludge.
The chromium reduction takes place in a reaction vessel, while the precipita-
tion is performed in a clarifier. The necessary chemical feed and control
equipment are included.
A low-volume, but potentially troublesome, wastewater stream is the purge
stream from the Stretford process sulfur recovery system (described under the
air pollution control section). This stream contains sodium metavanadate and
a diverse collection of organic and sulfur compounds. Its typical composition
is shown below:
Constituent Concentrations
(tng/1)
Sodium carbonate 4700
Sodium anthraquinone disulfonate 700
Sodium metavanadate 300
Sodium citrate 300
Sodium thiosulfate 6000
Sodium thiocyanate 6000
While the stream is sometimes mixed with the total process wastewater
stream, the presence of vanadium suggests that this is a questionable practice,
in terms of potential heavy metals pollution. Since there appears to be no
easy way to remove the highly soluble sodium metavanadate, one feasible and
relatively foolproof disposal method is chemical fixation, i.e., mixing with a
cement-like substance to form a stable solid material. Since the quantity
is relatively small, it is reasonable to expect that the cemented material would
be disposed of on or near the refinery site.
139
-------
Wastewater treatment cost estimates, based on the treatment steps pre-
viously described have been developed and are presented in Tables D-3 through
D-8.
2. AIR POLLUTION
a. Airborne Pollutant Sources and Quantities
The refinery airborne emissions of major consequence are generated by
four types of sources:
• Combustion sources - process heaters and boilers;
• Process units - FCC catalyst regenerator and fluid coke;
• Effluent control systems - Glaus plant; and
• Storage facilities - gasoline, naphtha, and BTX.
Air emission surveys on refineries have identified the primary pollutants of
concern by types of process (Compilation of Air Pollution Emission Factor,
Environmental Protection Agency, AP-42, 2nd ed. [1973]). Average emission rates
for the principal sources are summarized in Table D-9. Emissions from storage
facilities are not included in this tabulation; however, the process changes
considered have a negligible effect on storage emissions. Consequently, stor-
age emissions were eliminated from the base line pollutant profiles. Using the
emission factor of Table D-9, we determined daily emission rates from major
sources within the base line refineries; they are summarized in Tables D-10
through D-12. The sulfur emissions are based upon the actual sulfur balance
for each cluster model instead of the representative emission factor. Restric-
tions were imposed on the refinery fuel oil sulfur level in each base line
refinery. These restrictions comply with current regulations for each region
represented by the cluster of refineries. The maximum sulfur levels imposed
are listed below for each region being studied:
Region Maximum Sulfur, Wt. %
East Coast 0.6
Gulf Coast 0.9
West Coast 0.7
The sulfur emissions from the Glaus unit are based upon 95% recovery of
the sulfur in the acid gas. In developing the base line pollution control
costs, the control level was increased to 99.5% recovery of sulfur. FCC cata-
lyst regenerator SOX emissions were not controlled and were not affected by
the process changes studied.
b. Pollution Control Costs
The main air pollution control cost assoicated with the base line refiner-
ies is for sulfur recovery. Since the refinery fuel sulfur concentration was
achieved through gas treating and fuel oil blending to meet existing regulations,
140
-------
TABLE D-3
PROCESS WASTEWATER TREATMENT COSTS: EAST COAST BASE CASE REFINERY
(Basis: 200,000 BPC, 330 day/yr)
CAPITAL INVESTMENT - $11,600.000
VARIABLE COSTS
Operating labor (including
supervisory & OVHD)
Maintenance (including
labor & materials)
Chemicals
Lime
Phosphoric acid
Chlorine
Coagulant acid
Replacement carbon
Fuel (gas)
Electrical power
Wastewater treatment
sludge disposal
• Incinerator ash
• Stretford purge water
TOTAL VARIABLE COST
FIXED COSTS
Depreciation @ 6.25%
Taxes & insurance @ 2%
TOTAL FIXED COST
TOTAL ANNUAL COST
RETURN ON INVESTMENT @ 20%
TOTAL
Yearly Cost Per
Quantity Unit Quantity
17,520 man-hr/yr $17.15/man-hr
__ ._
909 tpy $32.50/ton
26 tpy $440/ton
90 tpy $140/ton
36,400 Ib/yr $1.00/lb
123,750 Ib/yr $0.40/lb
7,425 Btu/yr x 106 $1.35/Btu x 106
3,026,000 kWh/yr $0.030/kWh
255 tpy $5.00/ton
3,400 tpy $15.00/ton
Yearly Cost
($/yr)
300,000
464,000
29,500
11,400
12,600
36,400
49,500
10,000
90,800
1,300
51,000
$1,056,500
725,000
232,000
$ 957,000
$2,013,500
2,320,000
$4,333,500
Notes: 1. Capital investment adjusted to the 1975 level (ENR Construction
Cost Index = 2126)
2. Wastewater treatment costs are based on total implementation (from
ground up) of the BATEA level (Best Available Technology Economically
Achievable), 1983.
3. Cost estimates are for the specific example, and are in no way
intended to represent industry-wide treatment costs.
141
-------
TABLE D-4
COOLING TOWER SLOWDOWN WASTEWATER TREATMENT COSTS:
EAST COAST BASE CASE REFINERY
(Basis: 200,000 BPD, 330 day/yr)
CAPITAL INVESTMENT - $1.382,000
Yearly
Quantity
Cost Per
Unit Quantity
VARIABLE COSTS
Operating labor (including
supervisory & OVHD)
Maintenance (including
labor & materials)
Chemicals
• Sulfur dioxide
• Lime
• Sulfuric acid
Fuel (gas)
Electrical power
Wastewater treatment
sludge disposal
TOTAL VARIABLE COST
2,200 man-hr/yr $17.15/man-hr
470 tpy
500 tpy
234 tpy
118,200 kWh/yr
4,620 tpy
(@ 10% solids)
$340/ton
$32.50/ton
$51.15/ton
$0.03/kWh
$5.00/ton
Yearly Cost
($/yr)
37,700
55,300
159,800
16,300
12,000
3,500
23,100
$307,700
FIXED COSTS
Depreciation @ 6.25%
Taxes & insurance @ 2%
TOTAL FIXED COST
TOTAL ANNUAL COST
RETURN ON INVESTMENT @ 20%
86,400
27,600
$114,000
$421,700
$276,400
TOTAL
$698,100
Notes: 1. Capital investment adjusted to the 1975 level (ENR Construction
Cost Index = 2126)
2. Wastewater treatment costs are based on a chrome reduction/precip-
itation system consisting of reaction vessels, clarifiers, chem-
ical feed system and controls.
3. Chromium concentration in untreated cooling tower blowdown is
assumed to be 30 mg/1.
4. Cost estimates are for separate treatment of chromium-contaminated
cooling tower blowdown. Not all refineries treat cooling tower
blowdown separately, and the amount of chrotnate used varies consid-
erably.
142
-------
TABLE D-5
PROCESS WASTEWATER TREATMENT COSTS: GULF COAST BASE CASE REFINERY
(Basis: 200,000 BPD, 330 day/yr)
CAPITAL INVESTMENT - $11.600.000
VARIABLE COSTS
Operating labor
(including superv.
+ OHD)
Maintenance
(including labor +
materials)
Yearly
Quantity
17,520 raan-hr/yr
Cost Per
Unit Quantity
$17.15/man-hr
Yearly Cost
($/yr)
300,000
464,000
Chemicals
• Lime 909
• Phosphoric acid 26
• Chlorine 90
• Coagulant acid 36,400
• Replacement carbon 123,750
Fuel (gas) 7,425
Electrical power 3,026,000
Wastewater treatment
sludge disposal
• Incinerator ash 255
• Stretford purge
water 2,086
TOTAL VARIABLE COST
FIXED COSTS
Depreciation @ 6.25%
Taxes & insurance
-------
TABLE D-6
COOLING TOWER SLOWDOWN WASTEWATER TREATMENT COSTS:
GULF COAST BASE CASE REFINERY
(Basis: 200,000 BPD, 330 day/yr)
CAPITAL INVESTMENT - $1,306.000
VARIABLE COST
Operating' labor
(including superv .
+ OHD)
Maintenance
(including labor +
materials)
Chemicals
• Sulfur dioxide
• Lime
• Sulfuric acid
Fuel
TOTAL VARIABLE COST
FIXED COST
Depreciation @ 6.25%
Taxes & insurance @ 2%
Yearly
Quantity
Cost Per
Unit Quantity
2,200 raan-hr/yr $17.IVraan-hr
429 tpy
458 tpy
215 tpy
$340/ton
$32.50/ton
$51.15/ton
Yearly Cost
($/vr)
37,700
52,200
145,900
14,900
11,000
Electrical power
Wastewater treatment
sludge disposal
108,400 kWh/yr
4,240 tpy
(@ 10% solids)
$0.0145/kWh
$5.00/ton
1,600
21,200
$284,500
81,600
26,100
TOTAL FIXED COST
$107,700
TOTAL ANNUAL COST
RETURN ON INVESTMENT
-------
TABLE D-7
PROCESS WASTEWATER TREATMENT COSTS: WEST COAST BASE CASE REFINERY
(Basis: 175,000 BPD, 330 day/yr)
CAPITAL INVESTMENT - $10.636.000
Yearly
Quantity
Cost Per
Unit Quantity
Yearly Cost
($/yr)
VARIABLE COSTS
Operating labor
(including superv.
+ OHD) 16,060 man-hr/yr
Maintenance
(including labor +
materials)
Chemicals
• Lime 795 tpy
• Phosphoric acid 22 tpy
• Chlorine 79 tpy
• Coagulant acid 31 ,800 Ib/yr
• Replacement carbon 108,300 Ib/yr
Fuel (gas) 6,500 Btu/yr x 106
Electrical power 2,648,500 kWh/yr
Wastewater treatment
sludge disposal
• Incinerator ash 224 tpy
• Stretford purge
water 5,460 tpy
TOTAL VARIABLE COST
FIXED COSTS
Depreciation @ 6.25%
Taxes & insurance 1? 2%
TOTAL FIXED COST
TOTAL ANNUAL COST
RETURN ON INVESTMENT @ 20%
TOTAL
$17.15/man-hr
$32.50/ton
$440.007ton
$140.00/ton
$1.00/lb
$0.40/lb
$1.31/Btu x 106
$0.0211/
$5.00/ton
$15.00/ ton
275,000
425,000
25,800
9,700
11,100
31,800
43,300
8,500
55,900
1,100
81,900
$969,100
664,800
212,700
$877,500
$1,846,600
$2,127,000
33,973,600
Notes: 1. Capital investment adjusted to the 1975 level
(ENR Construction Cost Index = 2126)
2. Wastewater treatment costs are based on total implementation
(from ground up) of the BATEA level (Best Available Technology
Economically Achievable) 1983
3. Cost estimates are for the specific examples, and are in no way
intended to represent industry-wide treatment costs
145
-------
TABLE D-8
COOLING TOWER SLOWDOWN WASTEWATER TREATMENT COST:
TOST COAST BASE CASE REFINERY
(Basis: 175,000 BPD, 330 day/yr)
CAPITAL INVESTMENT - $1,147,000
VARIABLE COST
Operating labor
(including superv.
+ OHD)
Maintenance
(including labor
+ materials)
Yearly
Quantity
Cost Per
Unit Quantity
Yearly Cost
($/yr)
2,200 man-hr/yr $17.15/man-hr
37,700
45,900
Chemicals
• Sulfur dioxide 351 tpy
• Lime 373 tpy
• Sulfuric acid 176 tpy
Fuel
Electrical power 88,700 kWh/yr
Wastewater treatment
sludge disposal 3,465 tpy
(@10% solids)
TOTAL VARIABLE COST
FIXED COST
Depreciation @ 6.25%
Taxes & insurance @ 2%
TOTAL FIXED COST
TOTAL ANNUAL COST
RETURN ON INVESTMENT @ 20%
$340/ton 119,300
$32.50/ton 12,100
$51.15/ton 9,000
-
$0.0211/kWh 1,900
$5.00/ton 17,300
$243,200
71,700
22,900
$94,600
$337,800
$229,400
TOTAL
$567,200
Notes: 1. Capital investment adjusted to the 1975 level
(ENR Construction Cost Index 2126)
2. Wastewater treatment costs are based on a chrome reduction/
precipitation system consisting of reaction vessels, clarifiers,
chemical feed system and controls.
3. Chromium concentration in estimated cooling tower blowdown is assumed
to be 30 rag/liter.
4. Cost estimates are for separate treatment of chromium-contaminated
cooling tower blowdown. Not all refineries treat cooling tower
blowdown separately, and the amount of chromate used varies
considerably.
146
-------
TABLE D-9
EMISSION FACTORS IN PETROLEUM REFINERIES
Type of Process
Boilers and Process Heaters
lb/103 Bbl oil burned
kR/103 liters oil burned
lb/103 f3 K.IS burned
kg/10* m3 gas burned
Fluid Catalylc Cracking
Units
Uncontrolled
lb/103 Bbl fresh feed
-I
kg/10 liters fresh
feed
Electrostatic preclpltator
and CO boiler
. lb/103 Bbl fresh feed
•1
kg/10 liters fresh
feed
Moving-Bed Catalytic
Cracking Units
lb/103 Bbl fresh feed
kg/103 liters fresh feed
Fluid Coking Units
Uncontrolled
lb/103 Bbl fresh feed
kg/103 liters fresh
feed
Electrostatic prcclplt.itor
lb/103 Bbl fri_-sh fpcd
kg/103 liters fresh
feed
Compressor Internal
Corabusi It... Lr.^inc.-
lb/103 ft3 gas burned
kg/103 m3 gas burned
Bloudovn Systems
Uncontrolled
lb/103 Bbl refinery
capacity
kg/103 liters refinery
capacity
Vapor Recovery System
or Flaring
lb/103 Bbl refinery
capacity
kg/103 liters refinery
capacity
Process Drains
Uncontrolled
lb/103 Bbl wastcwatcr
kg/103 liters uasceuatcr
Vapor recovery or
separator covers
lb/103 Bbl uascewater
kg/103 liters wascewater
Partlcul.ites
840
2.4
0.02
0.32
242
(93 to 340)
0.695
(0.267 to 0.976)
44.7
(12.5 to 61.0)
0.128
(0.036 to 0.175)
17
0.049
523
1.50
6.85
0.0196
Neg
Neg
Neg
Ncg
Neg
Ncg
Neg
."eg
Meg
Neg
Sulfur
OxldCS
(sop
6.720S
19.25
2s
32s
493
(313 to 525)
1.413
(0.898 to 1.505)
493
(313 to 525)
1.413
(0.898 to 1.505)
60
0.171
NA
NA
NA
MA
2s
32s
Neg
Keg
Neg
Ncg
Neg
Ncg
Ncg
Neg
Carbon
Monoxide
Neg
Ncg
Nog
NeE
13,700
39.2
NO£
Neg
3,800
10.8
Neg
Neg
Keg
Neg
Xcg
Neg
Neg
Neg
Neg
See
Neg
Nef.
Neg
Neg
Hydro-
carbons
140
0.4
0.03
0.48
220
0.630
220
0.630
87
0.250
Neg
Ncg
Ncg
Neg
1.2
19.3
300
0.860
5
0.014
210
0.600
8
0.023
Nitrogen
Oxides
(••••ox)
2, .900
8.3
0.23
3.7
71.0
(17.1 to 145.0)
0.204
(0.107 to 0.416)
71.0
(37.1 to 145.0)
0.204
(0.107 to 0.416)
5
0.014
Ncg
Neg
Nes
Nog
0.9
14.4
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Alde-
hydes
i f i • »»_
25
0.071
0.003
0.048
19
0.054
19
0.054
12
0.034
Neg
Neg
Neg
Neg
0.1
1.61
Neg
Neg
Neg
Neg
Neg
Ncg
Neg
Neg
Amoonla
Neg
Neg
Ncg
Neg
54
0.155
54
0.155
6
0.017
Neg
Neg
Neg
Neg
0.2
3.2
Neg
Neg
Seg
Neg
Neg
Neg
Neg
Neg
147
-------
TABLE D-9
EMISSION FACTORS PETROLEUM REFINERIES (Cont.)
Type of Process
Vacuum Jets
Uncontrolled
lb/103 Bbl vacuum
distillate
kg/103 liters vacuum
distillate
boiler
lb/103 Bbl vacuum
distillate
kg/103 liters vacuum
distillate
Cooling Towcra
lb/106 gal cooling water
kg/106 liters cooling uater
Pipeline Valves and
Flanges
lb/103 Bbl refining capacity
kg/103 liter refining
capacity
Vessel Relief Valves
lb/103 Bbl refining capacity
kg/103 liter refining
capacity
Pump Seals
lb/103 Bbl refining capacity
kg/103 liter refining
capac ity
Compressor Seals
lb/103 Bbl refining capacity
kg/103 liter refining
capaci ty
Miscellaneous (air blowing,
sampling, etc.)
lb/103 Bbl refining capacity
kg/103 liter refining
Partlculates
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Heg
Neg
Neg
Neg
Neg
Sulfur
Oxides
(sop
Neg
Neg
Neg
Neg
Neg
Neg
NCR
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Carbon
Monoxide
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Hydro-
carbons
130
0.370
Neg
Neg
6
0.72
28
0.080
11
0.031
17
0.049
5
0.014
10
0.029
Nitrogen
Oxides
Neg
Neg
Neg
Nog
Neg
Neg
Neg
Neg
Nee
Keg
;;t,B
Xcg
Neg
Neg
Neg
Neg
Aldc-
hydes
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Ammonia
Neg
Neg
Neg
Neg
Neg
Keg
Neg
Neg
Neg
Neg
Neg
Neg
Xcg
Neg
Neg
Neg
Source: "Compilation of Air Pollution Emission Factors," AP-42, Office of Air Quality Planning and Standards, EPA
2nd Edition, April 1973.
148
-------
•c-
VO
TABLE D-10
ANTICIPATED SHIFTS IN REFINERY ENERGY USAGE
CAUSED BY NATURAL GAS AND TEL PHASEOUT
East Coast Gulf Coast West Coast
Crude Run, 103 BPD
Purchased Natural Gas, FOE/day1
Refinery Fuel, FOE/day1
Gas
Oil (blended)
Total Fuel, FOE/day1
Purchased Steam, 10 lb/"day
Electricity,mWh/day
1974
188
2,500
4,810
7,210
14,520
5.6
713.7
1985
198
6,990
9,640
16,630
5.7
838.7
1974
222
5,400
5,450
5,350
16,200
0.5
744.2
1985
218
6,880
10,700
17,580
0.5
875
1974
155
6,390
7,190
2,140
15,720
0.7
766.8
1985
164
7,500
11,690
19,190
0
897.3
= Fuel Oil Equivalent, 6.3 x 10 Btu.
-------
TABLE D-ll
MAJOR AIRBORNE EMISSIONS FROM BASE LINE REFINERY
Location: East Coast
Year: 1985
Process/Pollutants
Particulates
Clb/day)
SOX Hydrocarbons
(Ib/day) (Ib/day)
NOX Aldehydes Ammonia
(Ib/day) (Ib/day) (Ib/day)
•
•
•
•
Combustion (heaters and
boilers)
- Gas -fired
- Oil-fired
Fluid catalytic cracking
Vacuum distillation
Glaus plant
8,979 45,200
881
8,098
2,780 52,800
Negligible Negligible
2,280
2,671
1,321
1,350
13,684
8,931
38,085
10,129
27,956
4,416
Negligible
373
132
241
1,182
Negligible
Negligible
Negligible
Negligible
3,359
Negligible
Total Emissions
11,759
100,280
25,286
42,501
1,555
3,359
-------
TABLE D-12
MAJOR AIRBORNE EMISSIONS FROM BASE LINE REFINERY
Location: Gulf Coast
Year: 1985
Process/Pollutants
• Combustion (heaters and
boilers)
- Gas-fired
- Oil-fired
• Fluid catalytic cracking
• Vacuum distillation
• Glaus plant
Particulates
(Ib/day)
SO Hydrocarbons NOX Aldehydes Ammonia
(Ib/day) (Ib/day) (Ib/day) (Ib/day) (Ib/day)
9,855
867
8,988
3,585
Negligible
27,600
8,400
Negligible
680
2,798
1,300
1,498
17,644
9,854
40,999
9,969
31,030
5,694
Negligible
398
130
268
1,524
Negligible
Negligible
Negligible
Negligible
4,331
Negligible
Total emissions
13,440
36,680
30,296
46,693
1,922
4,331
-------
there are no segregated costs associated with the control of sulfur oxides from
combustion sources. The true cost is contained in the overall refinery operat-
ing costs presented in Chapter IV-C of the report.
To assess the impact of pollution control costs on the implementability
of the various process changes, base line air pollution control costs were
developed in conjunction with the specific process alternative being assessed.
This avoided redundancy in determining base line control costs for sources
which were not affected by the process changes.
Since sulfur is the pollutant of greatest consequence and control of this
pollutant was required for all options, a range of representative control
costs were developed for the two basic control systems—Glaus tailgas cleanup
and flue gas desulfurization.
(1) Tailgas Sulfur Recovery
In many refinery operations, residue gases containing large quantities
of H2S and SC>2 are generated. A large number of processes have been developed
for treating these residue gases and recovering saleable byproducts. For
details on these processes, the reader is referred to several of the recent
journal publications on this subject. (Cost, Air Regulations Affect Process
Choice, B.C. Goar, The Oil & Gas Journal, August 1975.) (Environment Needs Guide
Refinery Sulfur Recovery, H.S. Bryant, The Oil & Gas Journal, March 1973.)
Almost all of the refineries in the United States currently operate Glaus
plants designed to recover sulfur from residue gases. The residue gas is
first scrubbed with an amine-type scrubbing system to remove the H2S. The
amine scrubbing solutions are then regenerated to give off a concentrated H2S
stream which is sent to the Glaus plant. The Glaus plant recovers approximately
95% of the sulfur, the rest typically being flared and vented to the atmosphere.
In more recent times, both the Federal EPA and State environmental protection
agencies have become concerned with the sulfur emissions from Glaus plants
and have adopted, or are considering the adoption of, standards for the cleanup
of tailgases for Glaus plants greater than about 20 tpd of sulfur. This reg-
ulation would apply to almost all of the refineries in the United States.
The capital cost for a typical sulfur-recovery technology is shown in
Figure D-l. The operating costs for this technology are shown in Figure D-2.
These data are based upon the Standards Support and Environmental Impact Docu-
ment (March 1974) to be published by EPA in the near future. The costs shown
in these figures are believed to be representative of the whole class of
sulfur recovery processes applicable to refinery tailgases.
Since most refineries already have Glaus plants, the costs for recovery
of additional sulfur due to increased H^S generation are the incremental costs
of building a slightly larger Glaus plant than required under today's refinery
strategy. This is the approach we have adopted in considering the new tech-
nologies for energy conservation.
152
-------
Ul
107 1
7
5
106
CAPITAL COST FOR REFINERY
SULFUR CONTROL
I
TOTAL COST
CLAUS PLANT
TAILGAS
CLEANUP
MARCH 1975
10 100
SULFUR CAPACITY, LONG TONS PER DAY
Figure D-l. Capital Cost for a Typical Sulfur - Recovery Technology.
-------
700K
600K
ANALYTICAL OPERATING COST OF
CLAUS PLANT INDICATING
TAILGAS CLEANUP
Ln
BOOK
400K
300K
200K
100K
10
100
HEAT INPUT
[106Btu/hr)
Figure D-2. Operating Costs for Typical Sulfur - Recovery Technology
-------
(2) Flue Gas Desulfurization
One of the greatest environmental problems facing utilities today is the
control of SC>2 emissions from boiler stack gases. In recent years several
processes have been demonstrated for removing the SC>2 by scrubbing the stack
gas with an alkali solution, such as caustic or sodium bisulfite, magnesium
hydroxide, lime, and limestone. The more advanced technologies include regen-
eration of the scrubbing solution by reacting it with limestone or lime to
generate calcium sulfite. In other cases, the scrubbing solution is treated
to recover sulfur or sulfuric acid using thermal or electrolytic means. The
details of these scrubbing systems appear in numerous EPA reports and will
not be covered here.
The capital and operating costs for SC>2 scrubbing systems can be calcu-
lated from equations reported by Burchard. (Some General Economic Considera-
tions of Flue Gas Scrubbing for Utilities, J.K. Burchard, Control Systems
Division, EPA.) For a clear solution (as opposed to lime or limestone) venturi
scrubber, the capital cost for controling a new installation using a single
scrubber is given by the equation:
Cc = 21,600 Q°-65
O
where
(1)
Cq = scrubber cost
Q = heat input 106 Btu's/hr
The alkali system necessary for regeneration (based upon a single regeneration
system recovering sulfuric acid) is given by the equation:
CD = 3.3 x 106 [S]°-67
K
where
(2)
C_ = regenerations system cost ($), and
R
S = sulfur rate (ton/hr).
The total direct cost for this scrubber system would be the sum of costs from
Equations (1) and (2). The total system cost would be the direct costs plus
indirect costs, estimated at approximately 30% of the direct cost.
Equations (1) and (2) form the basis for calculating the cost for scrubber
systems on boilers and process heaters. The capital and operating costs are
shown as a function of heat input rate in Figure D-3. A breakdown of the
operating costs is shown in Table D-13- Note that refinery process heaters
are typically in the range of 50 to 100 million Btu per hour heating rate.
Boilers, on the other hand, are usually larger, but rarely are they greater
than 500 x 106 Btu/hr (less than 50 MW).
155
-------
Ln
107 1
7
5
106 1
7
5
10
CAPITAL COST OF
FLUE GAS DESULFURIZATION
4 MODULES
3 MODULES
2 MODULES
1 MODULE
OPERATING COST $106 Btu
100
1000
30
HEAT INPUT
[106Btu/hrl
100
1000
Figure D-3. Capital and Operating Costs vs. Heat Input Rate for Scrubber System
-------
TABLE D-13
AIR POLLUTION CONTROL COST OF LARGE COMBUSTION SOURCES
(Basis: 2% Sulfur)
Heat rate, 106 Btu/hr 250 5,250
Modules 1 4
Capital cost, $1000's
- Scrubber system 782 9,189
- Regeneration system 880 6,770
Total direct cost 1,662 15,959
Indirect costs, @ 30% of direct 499 4,788
Total capital cost, $1000's/yr 2,161 20,747
Operating cost, $1000's/yr
Variable costs:
Labor, 1 man/shift (incl. supv. & overhead
@ $14.85/hr) 130 130
Maintenance, @ 5% of direct capital 83 798
Utilities
- Electric power, 240 kWh/106 scf
@ $0.03/kWh 189 1,656
- Water, 1 gal/103 scf @ $0.35/103 gal / 9 80
- Fuel, 2.5 x 106 Btu/ton of S
@ $2.17/106 Btu 7 139
Total variable costs 478 2,803
Fixed costs :
Depreciation, 16 years 135 1,297
Insurance & taxes @ 2% of capital 43 415
Total fixed costs 178 1,712
Total production cost 656 4,515
:<.etarn on investment @ 20% of capital 432 4,149
TOTAL ANNUAL COST, $1000's/yr 1,088 8,664
Unit Cost, $/106 Btu 0.55 0.20
157
-------
3. SOLID WASTE
A petroleum refinery generates a wide variety of solid waste streams,
many of which contain materials on the EPA toxic substances list.
While the total combined treated wastewater effluent from modern refiner-
ies is of "relatively" uniform composition and has been extensively quantified,
the nature and quantity of solid wastes emanating from refineries are highly
variable and still the subject of investigation.
Basically, refinery solid waste streams fall into two main groups: those
that are intermittently generated and those that are continuously generated.
Intermittent wastes are generally those that result from cleaning within
the process areas and off-site facilities of the refinery. The following are
typical intermittent waste streams:
• Process vessel sludges, vessel scale, and other deposits generally
removed during plant turnarounds;
• Storage tank sediments; and
• Product treatment wastes, such as spent filter clay and spent cata-
lysts from certain processing units.
The annual volume of refinery intermittent wastes is strongly a function of
the individual refinery waste management and housekeeping practices.
Continuous wastes (those requiring disposal at less than 2-week intervals)
can be further broken down into two groups: process unit wastes and waste-
water treatment wastes.
Major process unit wastes include:
• Coker wastes, such as coke fines from delayed or fluidized cokers,
and spilled coke from unloading facilities;
• Spent catalysts and catalyst fines from the fluid catalytic cracking
units; and
• Spent and spilled grease and wax wastes from lube oil processing
plants.
Wastewater treatment wastes can include:
• Waste biological sludges from activated sludge units; and
• Dissolved air flotation float.
Typically such wastes are dewatered by means of sludge thickeners, coupled
with vacuum filters or centrifuges. The dewater sludge can then either be
158
-------
land-disposed or incinerated. Low concentrations of heavy metals are usually
present in the sludges, which could affect the level of control required.
A summary description of major refinery solid waste streams is presented
in Table D-14.
Using estimates for the total refinery solid waste generation in the
these are presented in Table D-15. As can be seen from Table D-15, the base
case East and Gulf Coast refineries produce a total solid waste stream that
is estimated to be 19,400 tpy. The West Coast refinery produces a total solid
waste stream estimated to be 16,700 tpy.
Excluding wastewater treatment sludges (which are included under water
pollution control costs), the total yearly solid waste disposal costs, based
on a typical unit disposal cost of $5.00/ton, are $91,000/yr for the East and
Gulf Coast base case refineries and $80,000/yr for the base case West Coast
refinery. It should be stressed that these are very rough estimates and that
actual values can vary considerably from plant to plant.
159
-------
TABLE D-14
PETROLEUM REFINERY SOLID WASTES—SOURCES AND CHARACTERISTICS
Type of Waste
Sources
Process solids Crude oil storage,
desalter
Catalytic cracking
Coker
Alkylation
Lube oil treatment
Drying and sweet-
ening
Storage tanks
. Slop oil treatment
Effluent treat- API separator
ment solids
Chemical treatment
Air flotation
General waste Water treatment
plant
Maintenance
Description
Basic sediment and
water
Catalyst fines
Coker fines
Spent sludges
Spent clay sludges,
press dumps
Copper sweetening
residues
Tank bottoms
Precoat vacuum filter
sludges
Separator sludge
Flocculant aided
precipitates
Scums or froth
Biological treatment Waste sludges
Water treatment
sludges
Heat exchanger
bundle cleaning
General
Characteristics
Iron rust, iron sulfides,
clay, sand, water, oil
Inert solids, catalyst
particles, carbon
Carbon particles, hydro-
carbons
Calcium fluoride, bauxite,
aluminum chloride
Clay, acid sludges, oil
Copper compounds, sulfides,
hydrocarbons
Oil, water, solids
Oil, diatomaceous earth,
solids
Oil, sand, and any of the
above process solids
Aluminum or ferric hydrox-
ides, calcium carbonate
Oil, solids, flocculants
(if used)
Water, biological solids,
inerts
Calcium carbonate, alumina
ferric oxide, silica
Iron rust, sediment, oil
Source: "Assessment of Industrial Hazardous Waste Practices, Petroleum Refining—Draft
Report," U.S. Environmental Protection Agency, January 1975.
160
-------
TABLE D-15
BASE CASE REFINERY - CHARACTERISTICS OF RAW AND TREATED PROCESS WASTEWATER
East/Gulf Coast Refinery (200,000 BPD)
Hcistewater Raw Wastewater (1)
Parameter (ib/day
BOD, 5,000
TSS 1,920
COD 14,000
Oil & grease 1,920
Phenolics 200
Ammonia (as N) 700
Sulfide 700
Total chromium Varie
(mg/1)
91
35
254
35
3.6
12.7
12.7
!S
Hexavalent chromium Varies
Treated Effluent (2)
(Ib./day
260
260
1,420
50
1.0
316
4.4
13(4)
0.22(4
(mg/1)
4.7
4.7
25.8
0.9
0.018
5.7
0.08
-
-
West Coast Refinery (175,000 BPD)
Raw Wastewater (1)
(Ib/day
4,375
1,680
12,250
1,630
175
612
612
Var
(mg/1)
91
35
254
35
3.6
12.7
12.7
ies
Varies
Treated Effluent (2)
(Ib/day
227
227
1,243
44
0.88
277
3.85
11.4(4)
0.19(4
(mg/1)
4.7
4.7
25.8
0.9
0.018
5.7
0.08
Flow Rate
6,600,000 gpd
5,780,000 gpd
Notes: (1) Raw wastewater characteristics derived from EPA Development Document (EPA 440/1-73/014)
(2) Raw wastewater characteristics are for wastewater downstream of the plant API oil separator.
(3) Treated effluent loadings are based on the Best Available Technology Economically Achievable
(BATEA) treatment level for 1983, as defined in "Effluent Guidelines and Standards -
Petroleum Refining", 40 CFR 417 FR May 9, 1974.
(4) Chromium - contaminated cooling water blowdown may be discharged as a separate waste stream.
(5) Waste loads include stormwater runoff from process areas but not from offsite facilities
such as tank farms.
-------
APPENDIX E
ROSTER OF PROCESS OPTIONS OR CHANGES IN INDUSTRIAL PRACTICE
The main body of the report describes in detail the options investigated,
the criteria for their implementation, and the base line technology for
comparison.
As an initial point in the refinery study ADL interviewed major oil com-
panies and process licensors to discuss with them their views concerning proc-
ess changes which will be made in existing refineries during the 1975 to 1985
period. Using information obtained from these interviews plus other sources
of technical information available to ADL, we selected the process options
described in the main body of the report as those most likely to be implemented
into existing refineries.
A complete list of the major process options considered is given below.
1. Upgrading of asphaltic materials (heavy residium):
a. via partial oxidation to make hydrogen,
b. via Flexicoking, and
c. via residual desulfurizing;
2. Complete internal power generation, i.e., no purchased power;
3. New sources of hydrogen manufacture from:
a. residual material via partial oxidation (same as l(a) above),
b. coal, and
c. naphtha;
4. Use of a high-sulfur fuel, plus flue gas desulfurization;
5. Exporting methane, ethane, and larger quantities of LPG from the
refinery, coupled with increased internal consumption of heavier
material for refinery fuel;
6. Conversion of LPG to gasoline;
162
-------
7. Upgrading of hydrogen purity via:
a. installation of the DuPont membrane separation process, and
b. installation of a computer-controlled hydrogen makeup bleed
system;
8. Conversion of some sulfuric acid alkylation plants to HF alkylation
plants;
9. Blending of methanol into the gasoline pool;
10. Larger market penetration of diesel automobiles and, hence, larger
demand for diesel fuel; and
11. Use of coal as refinery fuel for internal power generation.
The first four alternatives were finally selected for detailed evaluation,
excepting alternatives 3b and 3c. The remaining options are briefly discussed
below.
5. Exporting Methane, Ethane, and LPG
One possible scenario discussed during the interviews was the question:
"Would decontrol of natural gas pricing or end-use restrictions ultimately
result in the sale of refinery gas to utilities?" It is conceivable that the
price of natural gas could rise to such a level as to appear to make it
attractive for a refinery to export natural gas. In general, we would not
expect this to happen. Natural gas and/or light fuel is essential to the con-
trol of many process furnaces, e.g., the catalytic reformer furnaces. If all
the fuel gas were exported, it would have to be replaced (presumably) with
fuel oil. This would present the refiner with difficult temperature control
problems in a good many furnaces.
An additional comment made to ADL during the interviews was that, if export
of refinery gas becomes economic, then SNG will become economic at the same
time and would be the preferred route. A further difficulty with export of
refinery gas for pipeline use is its variability in heating value—from 550
to 1100 Btu over relatively short time spans. However, over the fence arrange-
ments to supply gas to gas-dependent industries would be feasible.
6. Conversion of LPG to gasoline
This process has been suggested several times in the past as a method for
gasoline production, and is under active consideration by some companies,
particularly in Australia. The economics do not appear attractive in the
United States at this time.
7. Upgrading of Hydrogen Purity
Considerable quantities of hydrogen are manufactured within the refinery,
particularly in the catalytic reformers. This hydrogen is typically low purity,
163
-------
relative to purity of manufactured hydrogen. Hydrogen purity in the hydro-
treating hydrodesulfurizing reactors is one of the key variables affecting
throughput, conversions, etc. Upgrading of the low-purity hydrogen produced
by the catalytic reformers would potentially improve the performance of an
existing hydrotreater/hydrodesulfurizer. For example, heavier stocks could
be fed to an existing unit, the conversion could be altered, etc. Three
methods have been studied to upgrade hydrogen purity:
a. Cryogenic separation,
b. DuPont's permasep process (membrane), and
c. Palladium diffusion.
The palladium diffusion process is not likely to be applied in a refinery,
because the process operation is sensitive to sulfur in the feed. Most com-
panies interviewed expected a demonstration unit of the DuPont process to be
installed within the next year or so. The choice between this process
(assuming satisfactory operation) and cryogenic separation is one of economics.
The membrane separation process could have a significant energy advantage.
To date, hydrogen purity upgrading is not widely practiced.
The control of the hydrogen bleed rate (to prevent the buildup of inerts)
and the hydrogen production rate and purity are critical to minimizing costs.
As the price of hydrogen increases, more companies will likely opt for com-
puter control of this system. At least one company now has such a system
installed. The net result is not any direct process change, but can represent
a significant savings in costs and energy.
8. Conversion of Existing Sulfuric Acid Alkylation Plants to HF Alkylation
Alkylation is an important process for the manufacture of high octane
gasoline blending components. Alkylation is the reaction between olefins
(C3, C4, C5) produced from the FCC unit and isobutane to produce alkylate. A
catalyst, either sulfuric acid or HF acid, is required. If sulfuric acid is
used, the reactor temperature is below ambient; hence, refrigeration is
required. HF alkylation does not require refrigeration. Because refrigera-
tion is energy-intensive, there might be a potential for energy savings by
switching from sulfuric to HF alkylation.
The companies interviewed did not think this switch would be likely to
occur, particularly because HF is a very dangerous chemical and plant operation/
safety is more difficult.
9. Blending of Methanol into the Gasoline Pool
Methanol is a. high-octane material which could potentially be used as ah
automotive fuel, either in the gasoline pool as a blending component, or 'as a
separate (pure) fuel.
164
-------
Some of the properties of methanol and a typical gasoline are shown below
for comparative purposes (The Oil & Gas Journal, December 17, 1973, pg 71).
Property Methanol Gasoline
Energy Content (gross) Btu/gal 64,700 120,000
Octane number 100+ 100
Stoichiometric air/fuel
ratio (Ib/lb) 6.5 15.05
Vapor Pressure, 60°F, psi 4.6 3-4
Heat of Vaporization, Btu/lb 473 130
Density, Ib/gal at 60°F 6.64 6.2
Estimated mileage % of gasoline 55-60 100
The same article presented estimated emission performance results for a
Gremlin automobile, showing methanol and gasoline to be roughly comparable.
The use of methanol as a blending component in gasoline has been exten-
sively studied by the companies interviewed. They were almost unanimous in
the view that methanol is not an economic choice. If water is present anywhere
in the distribution system, even in part per million quantities, phase separa-
tion can easily occur. The practical difficulties in guaranteeing the almost
total absence of water are, in the opinion of the companies interviewed, too
great to allow use of methanol. Even humid air entering the tank during
filling/emptying is too much water.
Also because of the vapor pressure characteristics of methanol in a typical
gasoline pool, butanes/pentanes must be removed. These latter compounds have
a higher energy content per gallon than methanol and are less costly.
Methanol can be very corrosive to parts of the fuel system in the auto-
mobiles—the carburetor and plastic parts in particular. In addition, the
carburetors would have to be modified for methanol operation.
Another objection raised is that formaldehyde is one of the combustion
products of methanol.
Several of the companies did point out that pure methanol can be used in
fleet service—taxis, etc., but questioned whether OSHA standards could be met.
Methanol can also be burned in turbines.
However, all the companies interviewed stated that their studies indicate
the cost of methanol to be too high (except for production in the Mid-East
from excess methane) to be competitive. Feedstocks investigated included
coal, waste, and cellulose conversion. Most studies reported that it is cheaper
to ship LNG rather than methanol at distances greater than 5000 miles.
10. Increased Market Penetration of Diesel Autos
The Department of Transportation is currently funding a study in this area,
the results of which should be published in 1976. The oil companies do not
believe that diesel-powered automobiles will be a significant market factor
before 1985.
165
-------
11. Use of Coal as a Refinery Fuel
Except for possible use in a utility boiler within the refinery, coal is
not likely to be used as a fuel source in refineries. The oil companies do
not believe the technology is available to ensure adequate temperature control
of a process furnace when coal is used as the heat source. However, many
companies are continuing to study this problem.
166
-------
APPENDIX F
GLOSSARY
Alkylation. A refinery process which reacts light C3/C4 olefins with isobu-
tane (both of which are in the gas phase at ambient conditions) to produce
high octane gasoline blending components. This process uses either sulfuric
acid or hydrofluoric acid as a catalyst.
Amine Sulfur Removal. DBA or MEA scrubbing for removal of acid gases from
refinery fuel gas prior to combustion.
Atmospheric bottoms. The first stage in refinery processing is normally
distillation of the crude oil at atmospheric pressure into its natural
boiling point components. The bottoms product from this distillation is
referred to as "atmospheric bottoms" and normally has an initial boiling
point of approximately 650°F. This product is usually suitable for residual
fuel oil blending or can be a feedstock to subsequent processes for conversion
into lighter fractions.
Aromatics. A class of hydrocarbons whose structure contains at least one
unsaturated ring compound containing six carbon atoms. Benzene is the
simplest hydrocarbon within this category, and toluene/xylenes are other
common aromatics. This class of hydrocarbons exhibits very high gasoline
octane numbers.
Asphalt. Bottoms from vacuum flashing, 975-1050°F IBP.
Beavon/Stretford Process. A sulfur removal process generally applied to
Glaus plant tailgas streams. The process involves catalytic conversion of
SOX to H2S prior to reduction to elemental sulfur.
Bunker fuel. A grade of residual fuel oil used to power ships.
Catalytic cracking. A refinery process widely practiced in the United States
in which heavy petroleum fractions are converted into light components by
contact with a catalyst at high temperatures (nearly 1,000°F). This process
primarily produces high-octane gasoline blending components. It is a cheaper
process than "hydrocracking" defined below, but produces a less attractive
yield of products.
Glaus Process. A sulfur recovery process which employs thermal and
catalytic conversion of SO and H2S to elemental sulfur; widely employed
for refining sulfur recovery.
167
-------
Coking. A refinery process which converts heavy residual petroleum fractions
(such as the bottoms product from vacuum distillation) into lighter products
and petroleum coke. The petroleum coke yield typically represents about 25%
of the feed.
Crude unit overhead stream. The lightest boiling components in crude oil which
are recovered in the overhead product by the atmospheric distillation of crude
oil. Normally, this stream will contain all the very light boiling hydro-
carbons, up through the gasoline boiling range. The distillation end point
for this stream can vary between 200° - 400°F.
Deep vacuum flashing. Often the second stage in refinery processing (particu-
larly in the United States) is distillation of the atmospheric bottoms
defined above under low pressure (vacuum) conditions. The term "deep vacuum
flashing" refers to this process at severe conditions of high temperature/
low pressure operation to produce the maximum yield of distillate products
from this process.
Distillate fuel. A class of petroleum products with boiling ranges between
approximately 350°F and 700°F which have been produced as an overhead
(or distillate) stream in a refinery distillation process. The major products
within this category are: aviation turbine fuel, kerosene, No. 2 fuel oil,
and diesel fuel.
Flexi-coking.®*A refinery process which is more severe than "coking." In this
process, the petroleum coke is "gasified," by a reaction with steam and air
to reduce the net coke production to a very small percentage of the original
feedstock.
H-Oil.® A proprietory residual hydrocracking process, licensed by Cities
Service and HRI, which uses an ebullating catalyst bed. The advantage of
this process is that it allows catalyst additions and withdrawals to be
made to the system during operation and thus allows processing of poorer
quality (such as high metal) feedstocks without excessive catalyst
deterioration.
Hydrocracking. A refinery process which reacts heavy liquid petroleum
fractions in the presence of a catalyst, in a hydrogen-rich environment.
This is a more severe processing operation than "hydrotreating" in that high
yields of lighter boiling products are obtained in addition to sulfur removal.
The process is characterized by high operating pressures (2,000 psig), high
hydrogen consumption, and high capital costs, but it produces very good
yields of high quality products.
168
-------
Hydroskimming. A class of refineries which contain no conversion
processes to convert intermediate streams to different boiling fractions
Crude oil is separated by distillation into its "natural" yield boiling
components. The refinery can include extensive processing to improve
product qualities.
Hydrotreated. (Hydro desulfurization) A refinery process in which a
hydrocarbon stream is "treated" by chemical reaction caused by contact with
a catalyst in a hydrogen atmosphere. The main purpose of this process is to
reduce the sulfur content of the hydrocarbon stream, but the process also
removes nitrogen and improves other product qualities.
Refinery Gas. A mixture of gases, including carbon monoxide, hydrogen,
methane and ethane, produced as byproducts in the conversion of crude
petroleum.
TABLE F-l
WEIGHT CONVERSIONS
Unit
One short ton
One metric ton
One long ton
One cubic centimeter lead (TEL)
Equivalent value
2,000 pounds
2,204.6 pounds
2,240.0 pounds
1.06 grams
TABLE F-2
VOLUME CONVERSIONS
Unit
One imperial gallon
One liter
One U.S. barrel
One cubic meter
One cubic foot
Equivalent value
.1.201 U.S. gallons
0.264 U.S. gallons
42.000 U.S. gallons
264.173 U.S. gallons
7.481 U.S. gallons
169
-------
TABLE F-3
NOMENCLATURE
B/SD
Bbls/SD
BTU
FGD
FOE
IBP
LV
103 B
103 bb/s
103 B/GD
10J B/SD
103 BPY
nnS
10-
KWH
KWH/CD
103 Ib
106 B
106 B/CD
106 BPY
103 SCF
106 SCF
PAD
POX
PPM
SCF
TEL
$/B/SD
$106
FCC
HT
LT
HDU
TEL
OCS
Barrels per stream day
British Thermal Unit
Flue gas desulfurization
Fuel oil equivalent
Initial Boiling Point
Liquid volume
Thousands of barrels
Thousands of barrels per calendar day
Thousands of barrels per stream day
Thousands of barrels per year
Thousands of kilowatt hours
Thousands of kilowatt hours per calendar day
Thousands of pounds
Millions of barrels
Millions of barrels per calendar day
Millions of barrels per year
Thousands of standard cubic feet
Millions of standard cubic feet
Petroleum Administration for Defense (Districts)
Partial Oxidation
Parts per million
Standard cubic feet
Tetra Ethyl lead
Dollars per barrel per stream day
Millions of dollars
Fluid catalytic cracker
High temperature
Low temperature
Hydrodesulfurization unit
Tetraethyl lead
Outer continental shelf
170
-------
TECHNICAL REPORT DATA
incase read Instructions on the reverse before completing!
1 REPORT NO.
'EPA-600/7-76-034d
2.
4. TITLE AND SUBTITLE
ENVIRONMENTAL CONSIDERATIONS OF SELECTED ENERGY
CONSERVING MANUFACTURING PROCESS OPTIONS. Vol. IV,
Petroleum Refining Industry Report.
7. AUTHOR(S)
9. PERFORMING ORGANIZATION NAME Al>
Arthur D. Little, Inc.
Acorn Park
Cambridge, Massachusetts 02!
12. SPONSORING AGENCY NAME AND ADC
Industrial Environmental Re
Office of Research and Devel
U.S. Environmental Protecti
Cincinnati, Ohio 45268
JO ADDRESS
L40
)RESS
search Laboratory
Lopment
Dn Aeencv
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
December 1976 (Issuing Date)
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-03-2198
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
EPA-ORD
15. SUPPLEMENTARY NOTES Vol. Ill, EPA-600/ 7-7 6-034c , and V-XV, EPA-600/7-76-034e through
EPA-600/7-76-034o, refer to studies of other industries as noted below; Vol.1, EPA-
600/7-76-034a is the Industry Summary Report and Vol. II. EPA-600/ 7-76-034b is the
16. ABSTRACT Industry Priority Keport.
This study assesses the likelihood of new process technology and new practices being
introduced by energy intensive industries and explores the environmental impact of
such changes.
Specifically Vol. IV deals with the petroleum refining industry and examines five
options: (!) direct combustion of asphalt in process heaters and boilers, (2) hydro-
cracking of vacuum bottoms, (3) flexicoking of vacuum bottoms, (4) internal electrical
power generation, (5) hydrogen generation by partial oxidation, all in terms of process
economics and environmental/energy consequences. Vol. Ill and Vol. V-XV deal
with the following industries: iron and steel, pulp and paper, olefins, ammonia,
aluminum, textiles, glass, cement, 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 the methodology used to select industries.
17.
a- DESCRIPTORS
KEY WORDS AND DOCUMENT ANALYSIS
b.lDENTIFIERS/OPEN ENDED TERMS
Energy; Pollution; Industrial Wastes; Manufacturing Processes
Petroleum Refining Energy Conservation
Asphalt
H-oil
il8. DISTRIBUTION STATEMENT
Release to public
19. SECURITY CLASS (This Report)
unclassified
20. SECURITY CLASS (This page)
unclassified
c. COSATI Field/Group
13B
21. NO. OF PAGES
193
22. PRICE
EPA Form 2220-1 (9-73)
171
------- |