United States
Department of
Commerce
United States
Environmental Protection
Agency
National Oceanic and Atmospheric Administration
Environmental Research Laboratories
Seattle, Washington 98115
Office of Energy, Minerals and Industry
Office of Research and Development
Washington, D.C. 20460
EPA-600/7-78-040
March 1978
WASHINGTON STATE
REFINERIES: PETROLEUM,
PETROLEUM DERIVATIVES,
AND WASTEWATER EFFLUENT
CHARACTERISTICS
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 nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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WASHINGTON STATE REFINERIES:
PETROLEUM, PETROLEUM
DERIVATIVES AND WASTEWATER
EFFLUENT CHARACTERISTICS
by
Joseph T. Pizzo, Thomas L. Johnson, and Gary W. Harshman
Oceanographic Institute of Washington
Washington State Commerce Building
312 First Avenue North
Seattle, Washington 98109
Prepared for the MESA (Marine Ecosystems Analysis) Puget Sound
Project, Seattle, Washington in partial fulfillment of
EPA Interagency Agreement No. D6-E693-EN
Program Element No. EHE625-A
EPA Project Officer: Clinton W. Hall (EPA/Washington, D.C.)
NOAA Project Officer: Howard S. Harris (NOAA/Seattle, WA)
This study was conducted
as part of the Federal
Interagency Energy/Environment
Research and Development Program
Prepared for
OFFICE OF ENERGY, MINERALS, AND INDUSTRY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
November 1976
UNITED STATES
DEPARTMENT OF COMMERCE
Juanita M. Kreps, Secretary
NATIONAL OCEANIC AND
ATMOSPHERIC ADMINISTRATION
Richard A. Frank. Administrator
Environmental Research
Laboratories
Wilmot N. Hess, Director
-------
Completion Report Submitted to
PU6ET SOUND ENERGY-RELATED RESEARCH PROJECT
MARINE ECOSYSTEMS ANALYSIS PROGRAM
ENVIRONMENTAL RESEARCH LABORATORIES
by
OCEANOGRAPHIC INSTITUTE OF WASHINGTON
WASHINGTON STATE COMMERCE BUILDING
312 FIRST AVENUE NORTH
SEATTLE, WASHINGTON 98109
This work is the result of research sponsored by the Environmental
Protection Agency and administered by the Environmental Research
Laboratories of the National Oceanic and Atmospheric Administration.
The Environmental Research Laboratories do not approve, recommend,
or endorse any proprietary product or proprietary material mentioned
in this publication. No reference shall be made to the Environmental
Research Laboratories or to this publication furnished by the
Environmental Research Laboratories in any advertising or sales
promotion which would indicate or imply that the Environmental
Research Laboratories approve, recommend, or endorse any proprietary
product or proprietary material mentioned herein, or which has as its
purpose an intent to cause directly or indirectly the advertised
product to be used or purchased because of this Environmental Research
Laboratories publication.
•n
-------
CONTENTS
FIGURES v
TABLES vii
ACKNOWLEDGEMENTS xii
ABSTRACT 1
I. INTRODUCTION 2
A. Purpose and Rationale 2
B. Data Collection Procedure 3
II. OVERALL PETROLEUM IMPACTS ON WASHINGTON STATE 8
A. Current Petroleum Activities: The Refineries of
Washington State 8
B. Crude Oils Utilized in Puget Sound 11
1. Introduction 11
2. Marine Transport of Crude Oil. 17
3. Pipeline Transport of Crude 20
4. Potential Crude Oil Supply 24
5. Chemical Composition and Characteristics of
Crude Oil 27
C. Refined Products Utilized or Produced in Puget Sound ... 49
1. Introduction . 49
2. Mode of Transport . 54
3. Marine Transport of Petroleum Products 58
4. Chemical Composition and Characteristics of
Refined Products - 70
D. Refinery Processes 91
1. Introduction 91
2. General Process Description 91
3. Process Configurations for Puget Sound
Refineries 96
E. Characteristics of Wastewater Entering the Treatment
Plant Ill
1. Introduction Ill
2. Characteristics of Wastewater from Refinery
Processes Ill
3. Influent Wastewater Characteristics for the
Washington Refineries 115
F. Ballast and Stormwater Flows 115
1. Introduction 115
2. Ballast Water 116
3. Stormwater 116
G. Wastewater Treatment Processes 118
1. Introduction 118
2. General Wastewater Treatment Process
Description 122
3. Wastewater Treatment Configurations for Puget
Sound Refineries 124
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CONTENTS (cont.)
H. Refinery Wastewater Effluent Characteristics I38
1. Introduction I38
2. Effluent Discharge Permits. . 14°
3. Toxic Effluent Pollutants I46
III. REFERENCES AND BIBLIOGRAPHY 161
A. References Cited in Text 161
B. Bibliography 163
APPENDICES *
A. RECENT, PAST AND PRESENT CRUDE OILS A-l
B. POTENTIAL REPLACEMENT CRUDE OILS B-l
C. MONTHLY EFFLUENT DATA C-l
* Appendices on Microfiche inside back cover.
IV
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FIGURES
Number Title Page
1 Interrelationship of Data Types Collected and
Processes Described 4
2 Sample Questionnaire 6
3 Waterborne and Pipeline Elements of the Crude Oil
Supply System in Washington 15
4 Waterborne and Pipeline Elements of the Refined
, Product Distribution System in Washington 16
5 Trans Mountain Pipe Line System 23
6 The Effects of Artificial Weathering of the Volatile
and Non-Volatile Hydrocarbons in a Kuwait Crude Oil . 48
7 Refined Products Derived From Crude Petroleum .... 52
8 Simplified Modern Refinery Process Flow Diagram ... 92
9 Refinery Process Configuration at the Mobil Refinery. 97
10 Diagram of the Layout of the ARCO Refinery at
Cherry Point 100
11 Refinery Process Configuration at the ARCO Refinery . 101
12 Refinery Process Configuration at the Shell Refinery. 104
13 Refinery Process Configuration at the Texaco
Refinery 106
14 Refinery Process Configuration at the U.S. Oil &
Refining Refinery 109
15 Refinery Process Configuration at the Sound
Refining Refinery 110
16 Wastewater Treatment Configuration at the Mobil
Refinery 126
17 Wastewater Treatment Configuration at the ARCO
Refinery 129
18 Wastewater Treatment Configuration at the Shell
Refinery 132
-------
FIGURES (cont.)
Number
19
20
21
Title
Wastewater Treatment Configuration at the Texaco
Wastewater Treatment Configuration at the U.S.
Wastewater Treatment Configuration at the Sound
Refinina Refinery
Page
135
137
139
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TABLES
Number Title Page
1 Selected Characteristics of Major Washington
Refineries, 1974 9
2 Capacity of Petroleum Refineries in the Pacific
Northwest, January I, 1976 10
3 Existing Marine Terminals for Crude Oil, State
of Washington 12
4 Bulk Petroleum Receiving Terminals, Puget Sound
and Vicinity 13
5 Total Waterborne Transport of Petroleum and
Petroleum Products (In 1000 Short Tons)
Throughout Puget Sound 14
6 Comparison of Pipeline and Marine Transport of
Crude Oil Imports to Washington Refineries 18
7 Waterborne Transport of Crude Oil (In Short Tons)
in Puget Sound 19
8 Types and Sources of Crude Oils Received from
1974-1976 by Marine Transport by Puget Sound
Refineries 21
9 The Major Crude Oils Utilized by the Puget Sound
Refineries from 1974-1976 22
10 Canadian Crudes and Other Feedstock Received via
the Trans Mountain Pipeline by the Puget Sound
Refineries 25
11 Deliveries of Canadian Crude Oil (BPD) to Washington
State Refineries via the Trans Mountain Pipeline . . 26
12 Types and Sources of Crude Oils Under Consideration
by Puget Sound Refineries for Replacement of
Canadian Crude Oils 28
13(a) Characterization of Fenn-Big Valley Crude, Taken
from 2,514-2,547 Feet 29
13(b) Characterization of Fenn-Big Valley Crude, Taken
from 2,581-2,694 Feet 30
13(c) Characterization of Fenn-Big Valley Crude, Taken
from 5,235-5,435 Feet 31
vii
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TABLES (cont.)
Number Title Page
14 Some Typical Paraffinic Hydrocarbons 33
15 Some Typical Naphthenic Hydrocarbons 35
16 Some Typical Aromatic Hydrocarbons ......... 36
17 Some Hydrocarbons in a Mid-Continent Crude Oil ... 37
18 General Chemical Classification of Crude Oils
Received from 1974-1976 by Puget Sound Refineries. . 39
19 General Chemical Classification of Crude Oils Under
Consideration by Puget Sound Refineries for Replace-
ment of Canadian Crude Oils 40
20 Relative Quantity of Volatiles and Nonvolatiles
in Crude Oils < . , . 43
21 Relative Percentages of Volatiles (Total and by
Hydrocarbon Class) in Crude Oils Received from
1974-1976 by Puget Sound Refineries 44
22 Relative Percentage of Volatiles (Total and by
Hydrocarbon Class) in Crude Oils Under Consideration
by Puget Sound Refineries for Replacement of
Canadian Crude Oils 45
23 The Effects of Crude Oil on Selected Species .... 50
24 Petroleum Products Produced by Puget Sound
Refineries 55
25 Estimated Relative Percentage of Product Output by
the Puget Sound Refineries from 1974-1976 56
26 Comparison of Land and Marine Transport of the
Products Refined by the Puget Sound Refineries ... 57
27 Waterborne Transport of Gasoline (In Short Tons) in
Puget Sound 59
28 Waterborne Transport of Jet Fuel (In Short Tons) in
Puget Sound 61
29 Waterborne Transport of Kerosene (In Short Tons) in
Puget Sound 62
vi i i
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TABLES (cont.)
Number Title Page
30 Waterborne Transport of Distillate Fuel Oil
(In Short Tons) in Puget Sound 63
31 Waterborne Transport of Residual Fuel Oil (In
Short Tons) in Puget Sound 65
32 Waterborne Transport of Lube Oils and Greases
(In Short Tons) in Puget Sound . . . 67
33 Waterborne Transport of Naphtha, Petroleum
Solvents (In Short Tons) in Puget Sound 68
34 Waterborne Transport of Asphalt, Tar and Pitches
(In Short Tons) in Puget Sound . •. 69
35 Percentage of Waterborne Transport of Petroleum
Products in 1973 on Puget Sound According to
Source or Destination 71
36 Percentage of Waterborne Transport of Petroleum
Products in 1974 on Puget Sound According to
Source or Destination 72
37 Some Typical Olefim'c Hydrocarbon Compounds 73
38 ASTM Specifications for Liquefied Petroleum Gas ... 75
39 General Characteristics of Reformate and Hydrocrackate,
Two Gasoline Blending Components, Produced at the
ARCO Cherry Point Refinery 76
40 Examples of Specific Antioxidant Additives Allowed by
Military Specifications in JP-4 and JP-5 Jet Fuel . . 78
41 ASTM Specifications for Jet A and Jet A-l Fuels ... 79
42 Military Specifications for JP-4 and JP-5 Jet Fuels . 80
43 Relative Percentages of Hydrocarbon Compounds in
Petroleum Products Transported in Puget Sound .... 86
44 Some Soluble Aromatic Compounds Isolated from
Kerosene 87
45 Summary of Aromatic Toxicity Data 89
46 Qualitative Evaluation of Wastewater Characteristics
by Refinery Process 112
ix
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TABLES (cont.)
Number Title Page
47 Average Wastewater Loadings from Petroleum
Refineries Utilizing Old, Prevalent, and New
Technology ...................... 113
48 Average and Maximum Ballast Water Flow
Allocations (in Thousand Gallons Per Day) ...... 117
49 Ballast Water Flows for 1974-1976 from the Shell
Refinery (in Thousand Gallons Per Day) ........
50 Average and Maximum Stormwater Flow Allocations
(in Million Gallons Per Day) ............. 119
51 Stormwater Flows for 1974, 1975 and the First Half
of 1976 from the Shell Refinery (in Million Gallons
Per Day) ....................... 119
52 Typical Removal Efficiencies for Oil Refinery
Treatment Processes ................. 120
53 Expected Effluents from Petroleum Treatment Processes 121
54 Effluent Discharge Water Quality from a Puget Sound
Refinery ....................... 141
55 1972 Data Collected in the EPA/API Raw Waste Load
Survey on Five Puget Sound Refineries ........ 143
56 1972 Data Collected in the EPA/API Raw Waste Load
Survey on Wastewater Treatment Processes Used at
the Shell Refinery .................. 144
57 Summary of Annual Levels of Pollutants Present in
the Wastewater Effluent of the Mobil Refinery .... 147
58 Summary of Annual Levels of Pollutants Present in
the Wastewater Effluent of the ARCO Refinery ..... 148
59 Summary of Annual Levels of Pollutants Present in
the Wastewater Effluent of the Shell Refinery .... 149
60 Summary of Annual Levels of Pollutants Present in
the Wastewater Effluent of the Texaco Refinery. ... 150
61 Summary of Annual Levels of Pollutants Present in
the Wastewater Effluent of the U.S. Oil &
Refining Refinery .................. 151
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TABLES (cont.)
Number Title Page
62 Summary of Annual Levels of Pollutants Present in
the Wastewater Effluent of the Sound Refining
Refinery 152
63 Summary of the Annual Levels of Toxic Pollutants
Present in the Wastewater Effluent at the Mobil
Refinery 155
64 Summary of the Annual Levels of Toxic Pollutants
Present in the Wastewater Effluent at the ARCO
Refinery 156
65 Summary of the Annual Levels of Toxic Pollutants
Present in the Wastewater Effluent of the Shell
Refinery 157
66 Summary of Annual Levels of Toxic Pollutants
Present in the Wastewater Effluent of the Texaco
Refinery 158
67 Summary of Annual Levels of Toxic Pollutants
Present in the Wastewater Effluent of the U.S.
Oil & Refining Refinery 159
68 Summary of Annual Levels of Toxic Pollutants
Present in the Wastewater Effluent of the Sound
Refining Refinery 160
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ACKNOWLEDGEMENTS
The contributions of the following individuals and organizations
is gratefully acknowledged. Their help in answering questions and pro-
viding access to much needed information on the oil refining industry has
helped ensure production of a comprehensive and reputable report on
wastewater effluent characteristics of the refineries in Washington State.
ACADEMIA
William Brewer, Institute for Environmental Studies, University of
Washington, Seattle, Washington
Robert Stokes, Institute for Marine Studies, University of Washington,
Seattle, Washington
STATE
Richard Burkhalter, Department of Ecology, Olympia, Washington
Edward Miller, Washington State Energy Office, Olympia, Washington
FEDERAL
Robert C, Clark, Jr., Research Oceanographer, National Marine Fisheries
Service (NOAA), Seattle, Washington
James Sweeney, Water Compliance and Permits Department, Environmental
Protection Agency, Seattle, Washington
Nick Malueg, Surveillance and Analysis Division, Environmental Protection
Agency, Seattle, Washington
E.D. Van Cleave, Chief, Spill Prevention and Control Branch, Environmental
Protection Agency, Washington, D.C.
Robert Eackman, Federal Energy Administration, Seattle, Washington
Craig L. Chase, Petroleum Regulation Branch, Federal Energy Administration,
Seattle, Washington
John Adger, Energy Resource Development Division, Federal Energy Admin-
istration, Washington, D. C.
Don F. Guier, Division of Oil, Gas and Shale Technology, Energy Research
and Development Administration, Washington, D.C.
Wade Watkins, Division of Oil, Gas, and Shale Technology, Energy Research
and Development Administration, Washington, D.C.
Lieutenant (j.g.) Robert L. Skewes, Environmental Technology Branch, Office
of Research and Development, U.S. Coast Guard, Washington, D.C.
Warren Waterman, U.S. Army, Corps of Engineers, Seattle, Washington
Leon Myers, Environmental Protection Agency Environmental Research
Laboratory, Ada, Oklahoma
James Peterson, Data Analysis Division, Federal Energy Administration,
Washington, D.C.
H.J. Coleman, Energy Research Center, Energy Research and Development
Administration, Bartlesville, Oklahoma
Cathy Coronets, Federal Energy Administration, Seattle, Washington
Ellen McCrany, Librarian, Federal Energy Administration, Seattle,
Washington
xii
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INDUSTRY
Fielding Formway, Refinery Manager, Atlantic Riehfield Company, Cherry
Point Refinery, Femdale, Washington
Gary F. Smith, Manager, Air and Water Conservation, Atlantic Richfield
Company, Cherry Point Refinery, Femdale, Washington
Phil Templeton, Refinery Manager, Texaco, Inc., Anacortes, Washington
Jack Webb, Texaco, Inc., Anacortes, Washington
Ken Brown, Refinery Engineer, Texaco, Inc., Anacortes, Washington
Jeff Holmes, Refinery Engineer, Texaco, Inc., Anacortes, Washington
A.E. Williamson, Refinery Manager, Mobil Oil Corporation, Femdale
Refinery, Femdale, Washington
James A. Mariele, Air and Water Conservation Coordinator, Mobil Oil
Corporation, Ferndale, Washington
William A. Malseed, Refinery Manager, Shell Oil Company, March Point
Refinery, Anacortes, Washington
E.A. Eenke, Shell Oil Company, March Point Refinery, Anacortes,
Washington
James H. Lopeman, Vice President - General Manager, Sound Refining,
Inc., Tacoma, Washington
Dick Uaab, Operations Manager, Sound Refining, Inc., Tacoma, Washington
Neil Taylor, Sound Refining, Inc., Tacoma, Washington
Robert Monarch, Refinery Manager, U.S. Oil and Refining Co., Tacoma,
Washington
I.I. ~K.am.ar, Manager, Olympic Pipe Line Company, Renton, Washington
D.T. Durrant, Coordinator, Planning and Economics, Trans Mountain Pipe
Line Company Ltd., Vancouver, B.C., Canada
Alex Hurika, Trans Mountain Pipe Line Company Ltd., Vancouver, B.C. Canada
R.J. Young, Refining Associate, American Petroleum Institute,
Washington, D.C.
In addition, consultant services on refinery technology and avail-
ability of data were provided by Waldemar Seton, P.E., of Seton, Johnson
& Odell, Inc., Consulting Engineers, Portland, Oregon. Consultant re-
view of the document was provided by Professor Lennart Johanson, Depart-
ment of Chemical Engineering, University of Washington.
FINAL REPORT PREPARATION
Judie Romeo, Managing Editor
Ellen Vaughn, Graphics
Cam. Mclntosh, Information Specialist
xi i i
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ABSTRACT
This report presents the results of a study of waste-
water effluent characteristics of refineries in Washington
State, compiled for the National Oceanic and Atmospheric
Administration's (NOAA) Puget Sound Energy-Related Research
Project. The purpose of this study was to describe in
detail the types of petroleum and petroleum derivatives
that potentially could reach the waters of Puget Sound.
This was achieved through the collection and summary of
available information on the chemical characteristics,
amounts processed, and final disposition of crude oils,
refined products, and wastewater effluents associated with
the six Puget Sound refineries. Sources of this informa-
tion included the literature, federal and state government
agencies, the petroleum industry, and academic institutions.
The following report describes the amounts and types of
petroleum and its derivatives handled by Puget Sound re-
fineries and the amounts typically reaching marine waters.
Further, the refining and waste treatment processes em-
ployed by the area refineries are described in detail.
This study was performed under Contract No. 03-6-022-
35189 with the National Oceanic and Atmospheric Administra-
tion (NOAA), administered through NOAA's Environmental
Research Laboratories, Marine Ecosystems Analysis (MESA)
Project Office, under an Interagency Agreement with the
U.S. Environmental Protection Agency. The six-month study
period extended from May 3rd through November 5th 1976.
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I. INTRODUCTION
A. Purpose and Rationale
This document presents the results of a study of wastewater effluent
characteristics of refineries in Washington State, compiled for the Nation-
al Oceanic and Atmospheric Administration's (NOAA) Puget Sound Energy-Re-
lated Research Project. The purpose of this study is to place some perspec-
tive upon the types of petroleum and petroleum derivatives that potentially
could reach the waters of Puget Sound. This was achieved through the collec-
tion and summary of available information on the chemical characteristics,
amounts processed, and final disposition of crude oils, refined products,
and wastewater effluents associated with the area refineries. Information
and study data were collected from the literature, federal and state govern-
ment agencies, the petroleum industry,'and academic.institutions/ The
following report describes the amounts and types of petroleum and its deriv-
atives handled by Puget Sound refineries and the amounts typically reaching
marine waters. ;Further, the refining and waste treatment processes employed
by the area refineries are described in detail.
A description of the characteristics of crude oils and products trans-
ported in Puget Sound and the wastewater effluents released to the marine
environment by the existing refineries is vital to the planning and design
of a baseline investigation of petroleum and petroleum derivatives which
may contaminate the waters of Puget Sound. The constituency and quality
of effluents are dependent directly on the types of crudes processed, the
refined products produced, refinery wastes incurred, and waste treatment
processes used at each refinery. The study presents available data on the
chemical constituents, process volumes, and characteristics of crude oils,
refined-products, and'refinery wastes produced at Puget Sound refineries
and imported into the state's marine waters.
The basic information assembled in this study (Work Unit B-3-1,
described in Project Development Plan - Puget Sound Energy-Related Research
Project, September, 1975) provides the necessary input for designing a
water quality baseline study of petroleum hydrocarbon concentrations (Work
Unit B-2-1). A combination of the outputs of Work Units B-3-1 and B-2-1
will help determine whether samples of refinery effluents adequately
characterize the contamination existing in Washington waters or whether an
analysis of refinery samples should be undertaken (Work Unit B-3-2). In
addition, analysis of effluent characteristics that affect the biota in
the area will help lay the foundation for future modeling efforts now being
planned (Work Units D-2-3 through D-2-5).
As previously mentioned this refinery effluent study is a component
of NOAA's Puget Sound Energy-Related Research (PSERR) Project. In addi-
tion, the identification and characterization of this data is useful to
state planners and regulatory agencies.
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B. Data Collection Procedure
The procedure of study consisted, essentially, of collecting, assembling
and summarizing available information and data on the six refineries in Puget
Sound. The following kinds of information were collected:
• Incoming Crude Oils: sources, volumes, chemical characteristics,
pipeline versus marine transport.
• Refining Processes: general description of process units at each
refinery.
• Refined Products Produced: product types, amounts, chemistry, and
mode of product export.
• Wastewater Influent: general character and volumes of the different
wastewater streams entering refinery treatment works.
t Wastewater Treatment Processes: general description of waste treat-
ment processes used at each refinery and relative efficiencies of
each process in treating specific wastewater constituents.
• Wastewater Effluent: characteristics and abundance of final waste^
water effluent constituents.
Figure 1 shows a process flow diagram that illustrates the kinds of infor-
mation and data collected in this study.
Sources of information for this study included public and private agencies,
firms and institutions. Data were gathered by in-person and telephone inter-
views with government and industry personnel and visitations to data-gathering
agencies and data repositories in Washington State, Oregon, Oklahoma, and
Washington, D. C. The refiners themselves were quite helpful by providing
informative tours of the process and wastewater treatment units. Additional
information was sought by the submittal of questionnaires directly to the oil
refineries.
One particular problem in our data-collection efforts appeared early
and persisted throughout the study. Most of the information currently avail-
able on refineries has been developed within the industry. Hence, all crude
characteristics, for example, tend to stress the engineering and refining
characteristics of the oils. Since the intent of this study is, in part, to
identify constituents of petroleum and its derivatives that could potentially
affect the quality of the marine environment, much of this information is not
directly applicable. This problem was alleviated in certain parts of the
study where some evaluation could be made of the relative toxicities of
crude oil, refined product, and effluent parameters, based upon in-house
interpretation of information contained in the literature. These data are
presented in appropriate sections of the report.
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Figure 1
Interrelationship of Data Types Collected and Processes Described
Imported
Crude
(Pipeline)
Imported Crude
(Marine
Transport)
Imported
Refined Products
(Marine
Transport)
Refinery
Refined
Products
Storm Water
Run-off
Waste Entering
Treatment Works
Potential Entry
Potential Entry
Potential Entry
Treatment
Works
Waste Effluent
Leaving
Treatment Works
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Some information on the sources and types of crude oils used by each
refinery was provided by the Federal Energy Administration (FEA), which
has been formulating a national allocation plan for Canadian crude oil ex-
ports to U.S. refineries. Additional information on crude sources was pro-
vided by refineries themselves. Questionnaires, consisting of a list of
needed information, were sent to refineries to gather this and other types
of information. • Figure 2 is a sample version of one of these questionnaires.
The questionnaire approach to data collection met with much success.
Shell provided good, useable data on all requested information. The responses
from Mobil, Atlantic Richfield Company (ARCO), Texaco, U.S. Oil and Refin-
ing and Sound Refining were less detailed, but provided useful information.
Response time of the refineries was variable, ranging from one to three months.
Chemical characterizations of crude oils now utilized by Washington
refineries, as well as potential future replacement crudes, were gathered
from a variety of sources, including the literature, industry publications,
(e.g., Oil & Gas Journal), and federal agencies. The key government reposi-
tory for crude characterizations is the Energy Research and Development
Administration's (ERDA) Energy Research Center in Bartlesville, Oklahoma
(formerly with the Bureau of Mines), which routinely carries out chemical
assays of foreign and domestic crude oils. During visits to the Washington,
D. C., offices of the Environmental Protection Agency (EPA), ERDA, the
American Petroleum Institute (API), and the Research and Development branch
of the U.S. Coast Guard, interviews with key personnel emphasized that the
Bartlesville facility is heavily relied upon as the major source of informa-
tion on crude oil chemistry by all these agencies.
Product information was gathered primarily from the literature and
industry sources. The availability of data on the chemical breakdown of
products is limited. ASTM (American Society for Testing and Materials)
standards were relied upon for some of this information.
The most readily available information was on the gross refining and
wastewater processes used at each of the refineries. Refineries were relied
upon to supply specific numbers on processes (e.g., process volumes and
retention times).
Specific data on the chemical composition of the various influent
streams to individual refinery wastewater treatment plants is singularly
lacking. The refiners are not required to report this kind of information
and so do not routinely analyze influent streams.
The most reliable information on refinery effluent characteristics is
the monthly effluent reports submitted by the refineries to the State Depart-
ment of Ecology (DOE). These reports provide daily and monthly figures on
levels of the following effluent parameters:
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Figure 2
Sample Questionnaire
REFINERY INFORMATION NEEDED
Waste Treatment
1. Retention times for various treatment processes.
2. Average retention time for final holding pond.
Storm and Ballast Water Volumes
1. Monthly and annual average and maximum flow.
Crude Oil
1. Any information on crudes types - sources.
2. Any information on volume of each crude.
3. Pipeline vs. marine transport.
Influent Characteristics
1. Parameters: total suspended solids, NH3, pH, sulfide,
COD, BOD, phenols, hexavalent chromium, total chromium,
fecal coliform, oil and grease.
2. Any further breakdown of oil and grease to hydrocarbon
types.
Products
1. Types of products - and amounts or relative percentages.
2. Mode of transport - relative amounts.
3. Any information on product characteristics: hydrocarbon
composition mainly; ASTM specifications.
Effluent
1. Any specific hydrocarbon breakdown of oil and grease.
2. Oil removal efficiency of treatment plant.
3. Concentration of oil and grease after final
clarification pond (prior to final holding pond).
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Total Suspended Solids (TSS) Biochemical Oxygen Demand (BOD)
Ammonia as Nitrogen Hexavalent Chromium
pH Total Chromium
Oil and Grease Fecal Coliform Bacteria
Sulfide Temperature
Chemical Oxygen Demand (COD) Phenolic Compounds
It was found, in inquiries to all Washington State refineries, that no
analyses of oil and grease are routinely performed to identify specific
hydrocarbon compounds. The industry perspective is that recovery of as
much oil as possible from the waste processing plant for re-processing in
the refinery is a major function of the waste treatment process. The oil
and grease fraction that does eventually leave the refinery via the final
effluent has no practical value for the refiner and so is not analyzed.
The following sections of -this report present the data collected for
the study and reflect the environmental implications associated with this
information.
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II. OVERALL PETROLEUM IMPACTS ON WASHINGTON STATE
A. Current Petroleum Activities: The Refineries of Washington State
The United States is divided into five Petroleum Administration for
Defense (PAD) Districts. Washington State is in PAD V, which also includes
Oregon, California, Nevada, Arizona, Alaska, and Hawaii. The Pacific North-
west includes Idaho (which is in PAD IV), Oregon, and Washington.
In 1972, the Pacific Northwest consumed petroleum at the rate of
440,000 barrels per'day (b/d). Of this, more than 60 percent was used for
transportation—mostly gasoline for cars. More than half the total energy
supply came from petroleum, and half of all the petroleum was consumed by
households (includes private vehicle fuel consumption). Petroleum for
private and public transportation accounted for one-third of all energy
used.
The Pacific Northwest has no commercially productive oil fields as of
today. The demand for petroleum products is met by refineries in Washington,
California, Montana, and Utah. Refineries in Washington must import all the
crude oil they process. Since construction of the Trans Mountain Pipeline
from Edmonton, Alberta, to the four major refineries in northern Puget Sound,
the principal source of crude oil for the Northwest has been Canada. Now,
Canada is reducing its exports of crude oil to the U.S., and Washington
refineries are becoming increasingly dependent on tankers for their crude
supply.
There are six active refineries in Washington State. Together, their
refining capacity is about 362,400 barrels per day. The four refineries in
Skagit and Whatcom counties represent about 94 percent (336,500 b/d) of
this total capacity. Two of these refineries are located near Anacortes
(Shell and Texaco) and two are in the Cherry Point-Ferndale area (ARCO
and Mobi1).
'The remaining two active refineries are in Tacoma (U.S. Oil & Refining
and Sound Refining). There is a small, inactive refinery (4,500 b/d
capacity) at Richmond Beach that is owned by Standard Oil of California
(SOCal). SOCal also owns property in the Cherry Point-Ferndale area on
which a refinery might someday be located.
The ARCO refinery at Cherry Point is unique in that it was specially built
to process North Slope crude and was designed to meet current and anticipated
environmental standards. Selected characteristics of Washington refineries
appear in Tables 1 and 2.
There are six primary marine terminals for receiving crude oil in Wash-
ington State. These are located at Anacortes, Cherry Point-Ferndale, and
8
-------
Table 1
Selected Characteristics
of
Major Washington Refineries, 1974
Item
Year Built
Acreage
Present Capacity
(1000 barrels
per calendar day)
Potential Capacity
(1000 barrels
per calendar day)
Present Crude
Storage (days of
refining capacity)
Employment
Water (Million
gallons per day)
Atlantic Mobil Shell Texaco
Richfield Oil i Oil Inc.
Co. Co. Co.
1972
•1200
96
300
20
380
3.7
1954 1955 1958
800 800 850
71.5 91 78
200 200 210
8 7 20
300 400 400
4.2 4.0
3.8
Throughout this volume references are
denoted by a one- or two-digit number in
( ). This number corresponds to a
complete reference listing in Section
III.A.
Source: (21)§
-------
Table 2
Capacity of Petroleum Refineries
in the Pacific Northwest, January 1, 1976
Company
Location
Crude
Distillation
Capacity
bbls/cal.day
Process Units and
Other Products
Atlantic Richfield Company Femdale
Mobil Oil Corporation Ferndale
Shell Oil Company
Texaco Inc.
U.S. Oil & Refining
Sound Refining
Anacortes
Anacortes
Tacoma
Tacoma
96,000 Cat. Rf., Hydro., Cok.
71,500 Cat. Ck., Cat. Rf.,
Thml. Ck.-,: Alk.
91,000 Cat. Ck., Cat. Rf.,
Alk.
78,000 Cat. Ck., Cat. Rf.,
Alk.
21,400 Cat. Rf., Asphalt
4,500 Asphalt, Lubricants
Cat. Ck.
Cat. Rf.
Hydro.
Thml. Ck.
Cok.
Alk.
Catalytic Cracking
Catalytic Reforming
Hydrocracking
Thermal Cracking
Coking
Alkylation
10
-------
Tacoma (see Table 3). There are more than 18 terminals at ten Puget Sound
ports for handling refined products (see Table 4).
Most of the maritime commerce in bulk petroleum is conducted through
Seattle, Anacortes, Cherry Point-Ferndale, and Tacoma. In 1974, for ex-
ample, Anacortes, Cherry Point-Ferndale., and Tacoma received more than 5
million short tons§ of the Washington marine total of 5.6 million short
tons of crude oil. This crude oil import activity represented nearly 12
percent of the 1974 total commodity traffic on Puget Sound. These three
ports plus Seattle imported and exported over 8 million of the 1974 marine
total of 9.2 million short tons of refined products. Table 5 presents a
breakdown of waterborne transport of bulk petroleum and petroleum products
within Puget Sound for the years 1973 and 1974.
Relative to Seattle, Tacoma handles significantly greater amounts of
crude but much less refined products. The crude serves Tacoma's refineries.
There are no refineries at Seattle, but Seattle is Western Washington's
major product-use center.
The system for supplying crude oil to Washington's refineries is via
the Trans Mountain pipeline and by vessel (see Figure 3). The Trans Mountain
pipeline serves the four major refineries in northern Puget Sound. In rough
figures, these refineries have historically received about 200,000 barrels
per day via the pipeline and about 100,000 b/d via tanker. Now, Canada is
decreasing the pipeline flow (shut-off by 1977 for Puget Sound) and this
deficit is being made up by increased tanker traffic.
The refined products distribution system is shown in Figure 4. The
principal products consumed in the Pacific Northwest are gasoline, kerosene,
jet fuel, naphtha, distillate fuel oils (including home heating oil and
diesel), residual fuel oils (for industrial uses), asphalt, and lubricants.
The four major refineries transfer their products through the Olympic pipe-
line, which extends from Cherry Point to Eugene, Oregon, and by vessels and
barges to points within and outside Puget Sound. They ship relatively
insignificant amounts by truck or tank car. The two Tacoma refineries pro-
duce mostly asphalt and lubricants, which they ship by vessel, truck, and
tank car.
B. Crude Oils Utilized in Puget Sound
1. Introduction
The combined maximum capacity of petroleum refineries in Washington in
1976 is 362,400 barrels per calendar day (BPCD). Although it is possible
to exceed this rated capacity (the ARCO refinery has been averaging over
§There are between 5.9 and 7.7 barrels of crude oil per short ton, depending
on the crude's specific gravity.
11
-------
PO
Table 3
Existing Marine Terminals for Crude Oil, State of Washington
Owner g Location:
Exposure to weather:
Exposure to waves:
Controlling depth of
approach channel :
Depth at principal
berth :
Max vessel dwt:
Length of principal
berth :
Auxiliary berth ( s ) :
Length of trestle to
shore :
Oil transfer system:
ARCO§ Mobil t Shell
Cherry Point Ferndale Anacortes
Exposed Exposed Sheltered
Exposed On shelf Sheltered
N.A. N.A. 54'/84'ft
65' 45' 45'
125,000 60,000 60,000
970' 850' 925'
None 1 (Barge) 1 (Barge)
2,000' 2,100' 3,500'
Steel loading Hoses Hoses
arms
Texaco U.S. Oil & Refining Sound Refining
Anacortes Tacoma Tacoma
•Sheltered
Sheltered
54'/84'tt
45 '±
60,000±
1,100'
1 (Tanker)
1 (Barge)
5,600'
Hoses
Sheltered Sheltered
Sheltered Sheltered
35' 30'
40 ' 30 '
35,000 20,000
840' 840'
1 (Tanker None
100 ' o '
Hoses Hoses
§A permanent floating oil spill confinement boom is installed.
tTurning dolphin is installed to permit deberthing without tug assistance.
tt54' depth is that applicable to Guemes Channel; 84' is controlling depth east of Guemes Island.
tDesign permits dredging to 50" water depth, to accommodate vessels up to 85,000 dwt.
N.A. Not applicable
Source: (21)
-------
Table 4
CO
Bulk Petroleum Receiving Terminals, Puget Sound and Vicinity
Port
Anacortes
Bellingham
Edmonds
Everett
Ferndale
Olympia
Port Angeles
Richmond Beach
Seattle
Tacoma
Operator
Shell Oil Co.
Texaco, Inc.
Std. Oil Co. of Calif.
Union Oil Co. of Calif.
Mobil Oil Corp ,
Mobil Oil Corp.
Atlantic Richfield Co.
Std. Oil Co. of Calif.
Std. Oil Co. of Calif.
Shell Oil Co.
Std. Oil Co. of Calif.
Atlantic Richfield Co.
Mobil Oil Corp.
Phillips Petroleum Co.
Shell Oil Co.
Std. Oil Co. of Calif.
Union Oil Co. of Calif.
U.S. Oil £ -Refining Co.
Sound Refining, Inc.
Location
Fidalgo Island
Fidalgo Island
Whatcom Creek Waterway
Edwards Point
Port of Everett
Cherry Point
Cherry Point
Olympia
Port Angeles
Point Wells
Point Wells
Pier 11, Harbor Island
Pier 15, Harbor Island
Pier 34, East Waterway
Pier 19, Harbor Island
Pier 32, East Waterway
Pier 70
Blair Waterway
Hylebos Waterway
Type
Refinery /Pier /Tanks
Refinery /Pier/Tanks
Pier /Tanks §
Pier /Tanks §
Pier/Tanks §
Refinery /Pier /Tanks
Refinery/Pier/Tanks
Pier/Tanks§
Pier/Tanks §
Pier /Tanks §
Pier/Tanks §
Pier /Tanks §
Pier /Tanks §
Pier/Tanks §
Pier /Tanks §
Pier /Tanks §
Pier/Tanks §
Refinery/Pier/Tanks
Refinery /Pier /Tanks
No. Facilities
Receiving
Bulk Petroleum
5
8
3
7
2
6
11
2
23
16
§These terminals handle only refined products.
Source: (21)
-------
Table 5
Total Waterborne Transport of Petroleum and Petroleum
Products (In 1000 short tons) Throughout Puget Sound
Petroleum and Petroleum Products
Crude Oil
Total Petroleum Products
Gasoline
Jet Fuel
Kerosene
Distillate Fuel Oil
Residual Fuel Oil
Lubricating Oil and Grease
Naphtha, Petroleum Solvents
Asphalt, Tar and Pitches
Total Petroleum and Petroleum Products
1973
3,297
9,770
3,268
614
.427
3,255
1,766
171
33
236
13,067
1974
5,602
7,357
2,338
467
288
1,840
2,051
128
74
171
12,959
Source: (28, 29)
14
-------
Figure 3
Waterborne and Pipeline Elements of
the Crude Oil Supply System in Washington
PORTLAND
Source: (21)
15
-------
Figure 4
Waterborne and Pipeline Elements of
the Refined Product Distribution System in Washington
TO -~f
Grays Harbor. Wa . \
California and ~,
.Oregon
From
Washingtoi
and
California
Ffam
ifornia PO
ANGELES
Yellowstone
Pipeline
Sall
Lake (Chevron)
Pipeline
Source: (21)
-------
100,000 BPCD of crude oil feedstock for the first half of 1976) rarely
have the refineries operated at peak capacity. Due largely to cutbacks in
the supply of Canadian crude oil, Mobil, Shell and Texaco have been operat-
ing below capacity. The Shell refinery at Anacortes has occasionally operat-
ed at a low of 80 percent of capacity. Sound Refining and U.S. Oil & Refin-
ing also rarely operate at capacity. Sound Refining particularly has had
economic difficulties recently and has been operating at less than 70 per-
cent of its rated 4,500 BPCD capacity. Also due to the economics of utiliz-
ing a heavy asphaltic crude (heat must be applied to make the crude oil
flow). Sound .Refining shuts down in winter and has often been shut down
for five or six months of each year. Thus the average annual operation of
the six Washington refineries since 1974 is around 330,000 BPCD, approxi-
mately 90 percent of the rated maximum capacity.
The crude oils utilized by the refineries are received either by pipe-
line or marine transport. Mobil, ARCO, Shell, and Texaco are all connected
to the Trans Mountain pipeline which supplies Canadian crudes from Edmonton,
Alberta and other Canadian oil fields. The two small Tacoma refineries are
not connected to any crude pipeline and receive all of their crude oil by
waterborne transport. The four major refineries also receive a portion of
their crude oil supply by tanker.
2. Marine Transport of Crude Oil
Marine transport of crude oil into Puget Sound has been increasing for
a number of years. In the peak year 1972, the Trans Mountain pipeline
accounted for more than 80 percent of the crude oil received, with the re-
maining 45,000 barrels per day arriving by barge or tanker. Since then
waterborne transport of crude oil has risen to more than 60 percent with
the onset of the Canadian phase-out of crude oil exports (Table 6). By
early 1977, according to the proposed Federal Energy Administration (FEA)
allocation of Canadian crude, the Puget Sound refineries will be totally
dependent on marine transportation for crude oil.
Waterborne transport of petroleum is monitored and categorized in detail
by the U.S. Army Corps of Engineers and published in November of each follow-
ing year. Hence detailed information regarding receipts of crude oil in 1975
and 1976 is not yet available, although values for the total amount of im-
ported crude are available from the refinery effluent reports to the DOE.
Table 7 shows the receipts and shipments of crude oil in Puget Sound as a
total, and by port, with each subdivided to indicate foreign, coastal,
internal and local transport in short tons for 1973 and 1974. The "Total"
category is for all ports in Puget Sound (defined here to include the Strait
of Juan de Fuca beginning at Neah Bay) which receive crude. The Ports of
Tacoma, Seattle, Anacortes and Bellingham are the principal recipients of
crude oil in Puget Sound. Bellingham receipts are delivered actually to
the docks of ARCO and Mobil at Cherry Point and Ferndale, respectively.
Seattle has no refineries but does have a number of storage tank farms and
uses some crudes for industrial heating fuel. The subcategory "Coastal"
represents all domestic marine traffic that enters Puget Sound. As often as
possible specific states are named as shipping ports or destinations of the
crude. Movement of crude oil within Puget Sound is indicated under "Inter-
nal". "Local" transport is within an individual harbor or port and has been
17
-------
Table 6
Comparison of Pipeline and Marine Transport
of Crude Oil,Imports to Washington Refineries
Date
1974
1975
1976
First Half
Second Halfi
1977§
Mode of
Pipeline
66%
60%
37%
20%
0%
Transport
Marine
34%
40%
63%
80%
100%
^projections based on proposed FEA allocations
18
-------
Table 7
Waterborne Transport of Crude Oil
(in Short Tons) in Puget Sound
Shipping
Port or
Destination
Total
Foreign
Coastal
Internal
Local
Tacoma
Foreign
California
Alaska
Internal
Local
Seattle
Foreign
California
Internal
Anacortes
Foreign
California
Alaska
Texas
Bellingham
Foreign
California
Alaska
Receipts
1973
2,187,767
1,048,369
3,106
0
365,175
281,737
0
0
0
53,022
20,031
3,106
93,735
0
208,253
0
1,675,835
124,851
413,497
1974
4,684,330
888,550
0
6,029
201 ,451
295,332
54,000
0
6,029
57,971
4,394
0
1,429,614
74,353
89,302
24,192
2,995,294
96,442
250,545
Shipments
1973
0
58,009
3,106
-
0
4,740
0
3,106
-
0
0
0
0
30,402
0
0
0
22,867
0
1974
0
22,930
0
-
0
0
0
0
-
0
0
0
0
0
0
0
0
22,930
0
§For conversion to barrels, there are 5.9 to 7.7 barrels of crude oil per
short ton depending on the specific gravity of the particular crude.
19 Source: (28, 29)
-------
arbitrarily listed under receipts ("-" appears under shipments). No crude
originates in Washington, but some tankers unload a portion of their crude
oil in Puget Sound before proceeding to refineries in California, thus
appearing as shipments of crude.
Most of the marine imported crude is from foreign sources, with smaller
amounts from Alaska, California, and occasionally Texas or the East Coast.
The percentage of marine transport of foreign versus domestic crude oil has
risen from 67 percent in 1972 to more than 80" percent in 1974. With the
cutback of Canadian crude, local Puget Sound refineries expect to be import-
ing even more foreign crude by marine transport, although the availability
of Alaskan North Slope_crude oils may shift the dependency on foreign
sources of crudes.
The types and sources of crude oils received by marine transport for
the past three years are indicated in Table 8. Sound Refining in Tacoma
receives a mix of heavy crudes: San Joaquin and Santa Maria, from California.
-U.S. Oil & Refining utilizes two crudes also: Indonesian crude ajid a south-
ern California coastal crude. These refineries will be unaffected by the
phasing out of Canadian crude. Sound Refining has experienced a recent
change in management and is considering expansion of operations and the
utilization of different crude sources and types. The crudes imported across
the docks of the four major refineries are indicated in Table 9 by refinery.
Some crude oils are utilized by more than one refinery. This is due to the
fact that there is a strong similarity between the refineries and the pro-
cesses they employ, since all but the ARCO refinery were designed to handle
light, sweet crudes. The ARCO plant was designed to handle crudes with
higher sulfur content, specifically Alaskan North Slope crude.
The four major refineries recently have indicated they will use Alaskan
North Slope crude to at least some extent for feedstock. Both Texaco and
Mobil have previously announced the possibility of enlarging product han-
dling facilities to enable them to refine the heavier North Slope crude.
Shell also will utilize North Slope crude, with the exact input being limited
by the refinery design, which favors lighter, sweeter crudes. The maximum
percentage of the total refinery feedstock will depend on the other crudes
being processed, but Shell estimates that it will be much less than 50 per-
cent. The ARCO refinery will utilize nearly 100 percent Alaskan North Slope
crude. Some sweeter crudes may occasionally be used to produce very low
sulfur fuels. The present design of the Sound Refining refinery is not
capable of handling the Alaskan crude and U.S. Oil & Refining is also not
likely to utilize North Slope crude when it becomes available.
3. Pipeline Transport of Crude
The Trans Mountain pipeline has supplied U.S. refineries with Canadian
crude oils since the first refinery was built in 1954. The 893 miles of
pipeline, originating in Edmonton, Alberta, includes nearly 64 miles in the
U.S. which supplies the refineries at Ferndale, Cherry Point, and Anacortes
(see Figure 5). The pipeline company is solely a carrier, providing oil
producing companies with an economical means of transportation from the areas
of production to refining centers. Sixteen independent Canadian companies
20
-------
Table 8
Types and Sources of Crude Oils Received from 1974-1976 by
Marine Transport by Puget Sound Refineries
Domestic
Alaska
Cook Inlet
California
San Joaquin
Santa Maria
San Ardo
Saudi Arabia/Iran
Arabian Light
Bern"
Iranian Light
Iranian Heavy
Sassan
Abu Dhabi
Murban
Indonesia/Malaysia
Attaka
Mi nas
Arjuna
Walio Export Mix
Bekapai
Poleng
Labuan Light
Katapa
Ecuador/Venezuela
Lagomedio
Oriente
Nigeria
Brass River
Qua Iboe
Bonny Light
21
-------
Table 9
The Major Crude Oils Utilized by the
Puget Sound Refineries from 1974-1976
MOBIL
Canadian (Pipeline)
Cook Inlet
California Coastal
Murban
Waiio Export Mix
Bern'
Mi nas
Lagomedio
Iranian Light
Oriente
Attaka
Arjuna
Bonny Light
TEXACO
Canadian (Pipeline)
Mi nas
Attaka
Oriente
Lagomedio
Murban
ARCO
Canadian (Pipeline)
Iranian Light
Iranian Heavy
Murban
Arabian Light
Sassan
Cook Inlet
SHELL
Canadian (Pipeline)
Cook Inlet
Walio Export Mix
Mi nas
Bekapai
Poleng
"Labuan Light
Brass River
Qua Iboe
Murban
Oriente
SOUND REFINING
San Joaquin
Santa Maria
U.S. OIL & REFINING
Katapa
San Ardo
Cook Inlet
Attaka
22
-------
PAGE NOT
AVAILABLE
DIGITALLY
-------
produce oil which is transported by the Trans Mountain Pipe Line Company.
The U.S. refineries receive crude oil, condensates and butane via the pipe-
line (Table 10). The pipeline company receives orders from the refineries
for specific blends of available Canadian crudes, condensates and butane,
and transports them in distinct batches to the appropriate refinery. The
volume of the crude received from Canada through the pipeline reached a peak
of 277,000 BPCD in 1972. The deliveries of Canadian crude oils (including
condensates and butane) since 1973 are shown in Table 11. This volume has
been steadily declining and soon will cease entirely as the Canadian govern-
ment attempts to achieve energy self reliance by 1981.
Two major factors have caused the Canadian government to examine and
change its oil export and import policies. The Arab oil embargo forced a
revaluation of the short and long-term security of the primary energy supply
for the eastern cities of Canada. The revenue from export taxes on Canadian
crudes going to the U.S. was being used to pay for the import of crude oil
required by the eastern provinces. With imports no longer readily available,
the supply of crude oil to the eastern cities was greatly imperiled. The
second factor influencing the decision was a series of studies which eval-
uated Canada's future crude oil supply and demand balance. These studies
concluded that by 1983 the demand would be greater than the production, re-
sulting in a domestic shortage of 100,000 barrels per day. Because of these
factors, the Canadian government has decided to phase out crude oil exports
to the U.S., along with other efforts to achieve self-sufficiency in oil.
The process of phasing out exports of oil, which was originally to be com-
pleted by 1983, will be accomplished by 1981. The Canadian export plan
authorizes the U.S. to allocate the export volumes to specific U.S. refiner-
ies as it desires. Recent actions by the Federal Energy Administration (FEA)
have designated the Puget Sound refineries as second priority refiners based
on the dependency upon Canadian crude sources and their capability to replace
Canadian crude with crude from other sources. First priority refiners are
those which utilized at least 25 percent by volume of Canadian crude oils
during the period from November 1, 1974, through October 31, 1975, and
possess no current capacity to replace Canadian crudes due to a demonstrated
lack of access to domestic pipelines, storage or port facilities or any other
methods of crude supply. Second priority refiners are "those which do not
qualify as first priority refiners" (33). Because of the preestablished access
to marine importation of crude oils, the four Puget Sound refineries receiv-
ing crude oil from Canada (Mobil, ARCO, Texaco, Shell) were designated second
priority refineries. The allocation of Canadian crude proposed by FEA will
result in the complete cutoff of Canadian crude to Washington refineries by
early 1977.
4. Potential Crude Oil Supply
As the Canadian crude supply is cut back, the Puget Sound refineries must
turn to other sources of crude for feedstock. In some instances, larger
quantities of the crudes presently being utilized may be sufficient. How-
ever, new sources of light, sweet crude oil most certainly will be necessary.
Some of the crudes presently imported by the four major refineries are among
the world's top fifteen.imported crude oils. These include: Arabian Light,
Iranian Light, Lagomedio, Qua Iboe, Murban, Bonny Light and Iranian Heavy.
Thus, obtaining additional quantities of these high-demand crudes may be
24
-------
Table 10
Canadian Crudes and Other Feedstock Received via the Trans
Mountain Pipeline by the Puget Sound Refineries
Crude Oils
Rainbow
Texaco
Federated Mix
Peace River
Ellerslie
Condensates
Carson Creek
Cabob
Worsley
Windfall
Edson
Taylor
Butane
25
-------
Table 11
Deliveries of Canadian Crude Oil (BPD) to Washington
State Refineries Via the Trans Mountain Pipeline
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Annual Average
Percent Natural
Gas Liquids
1973
271,283
256,769
265,251
235,471
257,118
4.5
1974
184,108
200,478
201 ,696
220,456
201 ,784
5.2
1975
187,306
173,780
175,446
180,995
179,313
5.2
1976
(6 months)
123,899
101,733
112,816
5.1
Source: (22, 23, 25, 26)
26
-------
difficult. Furthermore, the process configuration of each refinery places
a limit on the types of crudes and blends of crudes which will yield the
desired product output. So crudes replacing the Canadian oil will have to
be similar to those already being used unless the refineries are modified
and expanded. In affidavits from the refineries to the FEA, each refinery
provided some information regarding potential replacement crude oils. A
list of the types and sources of crudes under consideration for replacing
the diminishing Canadian crude supply is shown in Table 12. Of these 34
crude oils, 10 are among the world's top 15 imported crudes: Zuetina,
Forcados, Es Sider, Cabinda, Lagomedio, Qua Iboe, Murban, Arzew, Zarzaitine
and Bonny Light, so other suitable Indonesian, N/igerian, Libyan and Algerian
crudes must also be considered. The specific blends of crude which will be
utilized will be determined by crude oil economics.
5. Chemical Composition and Characteristics of Crude Oil
Crude petroleum is a mixture of chemical compounds derived from bio-
logical material that has accumulated in an area and been subjected to
physical, chemical and biological processes for millions of years. The
physical and chemical composition of petroleum varies greatly, depending
upon where it is obtained. Even samples of crude taken at different depths
or different times from the same field may have some noticeable differences.
Note the variations in sulfur content, gravity, pour point and other character-
istics found in crude assays made in a single oil field at different depths,
shown in Tables 13(a), (b), and (c). There is tremendous variability in
physical appearance of different crude oils, which is controlled by the
chemical composition. Colors range from water-clear to black, with many
shades of red, orange, green and brown in between. Specific gravities
may vary from 0.70 to 1.00. Other physical properties also may vary greatly,
including viscosity (0.6 to over 1,000 centipoise), surface tension (20 to
27 dynes per centimeter) and pour point temperature (-65°F to +65°F).
Crude oils are often described in terms of their API gravity and sulfur
content, as heavy or light and sweet or sour. These categories are not
well defined and may be simply relative to specific crudes being described.
Generally API gravities range from 10.3 to 44-3. Light crudes are usually
those over 30-32, while heavy crudes often have gravities below 20.
Descriptions of crudes in the intermediate range of 20-32 are very sub-
jective, but the intermediates are often simply labeled medium crudes.
Sulfur content in crude oils may range from around 0.04 to 6 percent.
However, this is not totally indicative of whether a crude oil is considered
to be sweet or sour, because the hydrogen sulfide and mercaptan content is
the true basis for this type of description. Very often though, sour crudes
are categorized as having greater than three percent sulfur content and
sweet crudes as having less than one percent. The middle range crudes are
not well designated and often will vary with respect to which crude oils
are being compared. Alaskan North Slope crude has a sulfur content of
about one percent, but is usually labeled sour when compared to the sweet
Canadian and other crudes presently being used by Puget Sound refineries.
The chemical composition of crude oil also is quite complex. Crude oils
contain many tens of thousands of compounds, including hydrocarbons;
sulfur-, oxygen-, and nitrogen-containing compounds, and metallo-organic
27
-------
Table 12
Types and Sources of Crude Oils Under Consideration by Puget
Sound Refineries for Replacement of Canadian Crude Oils.
Domestic Indonesia/Malaysia
Alaska Arjuna
Cook Inlet Attaka
North Slope Bekapai
Cinta
Nigeria Labuan Light
Minas
Qua Iboe Poleng
Forcados Badak
Brass River Seppinggan
Bonny Light Bunju
Escravos Handil
Pennington
Algeria
Libya
Arzew
Zuetina Zarzaitine
Es Sider Hassi Messaoud
Bu Attifel
Brega Gabon/Angola
Sarir
Amna Gamba
Anguille
Ecuador/Venezuela Cabinda
Oriente Abu Dhabi
Lagomedio
Murban
: 28
-------
Table 13(a)
Characterization of Fenn-Big Valley Crude, Taken from
2,514-2,547 Feet
Fenn-Big Valley f is Id
0-2, Devonian
2,514-2,547 feet
Bureau of Mines BqcU«SVJ.IJa Laboratory
Sample .51.82? _ ,
IDENTIFICATION
GENERAL CHARACTERISTICS
Item 126
North America
Canada
Alberta
Gravity, specific, .Q...858..— Gravity, ° API, 33..4. pour point| o F 20
Sulfur, percent, LJffi Color, -.brflWi.si".bjack.l..
Viscosity, Saybolt Universal at ./Z.L..65_sec.;: JJXHj,,,52iec.. Nitrogen, perceni, r...
DISTILLATION, BUREAU OF MINES ROUTINE METHOD
STAOS 1—Distillation at atmospheric pressure 7$$. mm. Hg
First drop. ...SI ° F.
Fraction
No.
1
2
3
4
5
6
7
8
ft
10
Cut
temp.
°f.
122
167
312
S57
302
347
392
437
482
527
Percent
3.2
2.1
4,4
4,9...
4.,.3...
.. 3.,.?
.3...S...
4.0
4.J
. 0,1
Sum.
percent
.....3,2).;
.....5,31
... ?,.7
...1.4,,6....
...IS.,?.
...22,8
..2dA
30.3
34.4
...40,5....
Sp. a.,
80/80° F.
...9,647...
.723
......749 ...
.768.
.788
.... ,80.3 ...
.818
.830
... ,844
•API,
60' F.
87".2
64.5
...57,4
52,7
48.1
4T.5
3?*Q
"'36?f
C.I.
-
23
...26......
.. 27...
30
31
33
33
35
R«fractive
index,
n.«t20"C.
1 .388'64'
' "MW
" '.4V529
.42547
- ^43449
.44423"
1 .4&1§7
\ .45980
T.46784
Specific
dinpcrsion
. -m-r
"136.0
134.2"
"I36.T
138.5
i4i;2
""T4S~Z"
148.3
TS5V2
B. V.
viac.,
100° F.
Cloud
teat.
°F.
STAGE 2—Distillation continued at 40 mat. tig
13
Hc-Kj'diTiini
303
482
2.4
5.6
5,4...
4.7
7,3
30.5..
42.9
48.5
53.9
58.6
65.9
...?.6.4.
0,851
".862"
,877.
,?8?
,S04
.9.90..
34.8
32.7
...2?,?
27.7
2LQ
...12,?.
..34
36
....39......
42
46
1 .47564
1.48460
157.0
159.8
40
46
58
88
180
10..
"30
50
70..
85
Carbon residue, Conr«dsor: Residuum. .\\.£ percent; crude. .3.*?..- percent.
APPROXIMATE SUMMARY
L«ht uawline
Tottl g«»o ne • [>
a"°°-\ "
U • I h • f rfj fll te
Medium lubricating dbtillate
iatou» u fang
Di^tillal inn loss
Percent
9~7~
4,0..
9 5
IH
30,5...
... -3.A
o"'68i
U./4U
,8.1.8...
f-.B9\
-•MS
.980
• API
76 3
41 5
., ..35,8
.3L,7-27,3
27.3-24.3
24".3-22.6
.1.2,9
Vbeodty
50-100
100-200
Above 200
Source: (31)
29
-------
Table 13 (b)
Characterization of Fenn-Big Valley Crude, Taken from
2,581-2,694 Feet
Burenu of Mines Bart |esvi! le
Sample 51030.
Laboratory
IDENTIFICATION
Fenn-Big Valley field
D-2, Devonian
2,581 -2,694 feet
Item 128
North America
Canada
Alberta
GENERAL CHARACTERISTICS
Gravity, specific, .P..--854 Gravity, ° API, M:.?. Pour point, ° F.,...
Sulfur, percent P.-.Z.l 0 Color, ._.br.own.ish
Viscosity, Saybolt Universal at }.PQ...Fj..4.?.«f.9.;. Nitrogen, percent,
DISTILLATION, BUREAU OF MINES ROUTINE METHOD
STAGE 1—Distillation at atmospheric pressure *^C*.. mm. Hg
First drop, ...82. ° F.
35
Fraction
Njo.
2
3
5
10
Cut
-------
Table 13(c)
Characterization of Fenn-Big Valley Crude, Taken fron
5,235-5,435
Bureau of Minos
Sample .....
8or.tJgsv.iJ.ls
52037
Laboratory
Fenn-Big Valley field
D-2, Devonian
5,235 -5,435 feet
IDENTIFICATION
GENERAL CHARACTERISTICS
Gravity, ° API, 3.Q,4
Gravity, specific, .CL8Z4.....
Sulfur, percent, J..Q5. ,
Viscosity, Sayboit Universal at ..ZZ°E...9.1.Mc..;..1.0Q?.F.,.64.Me.
Item 127
North Amerii
Canada
Alberta'
Pour point, " F., .45
Color, greenish, black
Nitrogen, percent, -
DISTILLATION, BUREAU OF MINES ROUTINE METHOD
STAOE 1—Distillation st atmospheric pressure. .,74.6- mm. Hg
First drop, -9.1 ° F.
^•<" 1 4£
1 1 122
2 j Ifi7
3 i 212
4 ! M7
5 302
6 j 347
7 I 3-12
* .... 437
.' '• ,482
III ' .12-
Percent
1,3...
2.0
...4,5...
4,9
. .4,5...
4,3...
3,8...
,.4..4...
5,0...
7.3.
Sum.
percent
J..31
....3.31.
7.8
12,7
...17.2
...1L7...
....25,5.
...2.9..?..
...at.?....
...42.2..
Sp. tr.,
60/60° F.
. 0,668 ..
.,.723
,74?
..,769
.7.83..
,m...
-817...
..828-..
.Ml....
• API.
60° F.
80.3
$4,2
57,4
52,5
.....49,2....
44.9
....4.I..7....
....3S..4-.
36.8....
c. r.
-
23
26
2?
"::32""
32
...33
Refractive
index.
n.«t20° C.
1 .3"850o
1 .40158
.41538
.42553
... .,.43504
.44473
... ..45354
... ..4.«.?.0.
,46802.
Specific
dispersion
127J"
l3i .4
135.6
136.9
... ...).3S.,4.
141.7
145*5.
J.5Q,.?
1.5.6,9
8. U.
100' K.
Cloud
test,
°F.
JTACE 2— Distillation continued at 40 mm. Hg
11
12
13 ....
UrMrtiitim
392
437
482
527
572
.1.8...
5,9
. 5..5.
5.1
6.4...
32.9
:.MA...
.-4?.,.Q...
...55.4
6Q^
-.66.9.
...9.9.8.
....0..85.3...
,.86Q...
.87.2...
.88?
... ...?03...
,.9.8)..
.....34,4.-
33.0
30. 8 .
27.7
-.Z5..2....
12,7....
35
35
37 .
42
46.....
...!.,475.69
..1,4834.8
::::!1
a-
57
94
1.5.0.....
15
30"
50
70
.85....
Cartxm rrsiduc, Conradson: Residuum,
11.0
..•". percent; crude,*.'-'.... . percent.
APPROXIMATE SUMMARY
Total Caroline and naphtha
Non viscous lubricating distillate
V ' "l 1 ' ti *di rllatc
8
DiVtifiarfnii '»*>
Percent
7.8
Z5..5...
4,4
19,8....
9.,7-
7.5
.32.,?..
0.2
8p.gr.
...0,700...
0,763..
.817
,845....
,866-,892
,882- .9.11
. ...ML
• AFI
TO,*:..
54..0.....
....41 .7
36.0
.31.,?-27vl
27..1-23.S
....12,7.
Vlreo^ly
50-100
inn-300
Above 200
Source: (31)
31
-------
compounds. The extreme complexity of crude oils has prevented a complete
analysis of all the compounds present in any given crude. This complexity
is thought to result from the molecular interactions which occurred when
crude petroleum was formed. However, in general, hydrocarbon compounds
comprise more than 75 percent of most crude oils. Assays of physical and
chemical characteristics of the crude oils used in Puget Sound, or which
potentially will be used in the near future, are in Appendix A and B.
Hydrocarbons in particular have such a~wide range of molecular struc-
tures and molecular weights that no one method of analysis presently avail-
able offers an accurate assessment of all the specific compounds present.
Even more troublesome is the fact that often the characterization provided
by different analytical methods yields substantially different assessments.
In a series of experiments analyzing the composition of crude oils,
researchers at Massachusetts University found that results'from fluori-
metric analysis did not agree with the gas chromatographic results (27).
A Nigerian light crude was found to contain 15 percent more hydrocarbons
than an Iranian light crude according to the fluorimetric method^ whereas,
by gas chromatography, the Iranian light crude was indicated as having
80 percent more hydrocarbons than the Nigerian crude oil. It is highly
probable that the two analytical techniques were actually assessing differ-
ent chemical fractions of the crude oils. Thus one must be very careful
when examining characterizations of crude oils and when comparisons are
being made, to ensure that indicated differences are actual differences
and not due to variations in analytical techniques.
Hydrocarbon compounds in crude oil may have from 1 to more than 70
carbon atoms and range in molecular weight from 16 (methane) to more than
20,000. Structurally they include alkanes, cycloalkanes and aromatic ring
compounds. Olefins are generally absent in crude oils but are commonly pre-
sent in refined products. The alkane hydrocarbons include both straight and
branched carbon chains (Table 14). The cycloalkanes are a complex mixture
of compounds including substituted and unsubstituted rings, with substituted
ring compounds predominating (Table 15). The aromatic hydrocarbons in
crude oils also are a very complex mixture of compounds. These include
mono- and polyalkyl-benzenes, naphthalenes and polynuclear aromatic
hydrocarbons with multiple alkyl substitutions (Table 16). Also included
in this class of compounds are those hydrocarbons containing a mixture of
aromatic and cycloalkane subunits, sometimes designated as naphtheno-
aromatics.
Crude oils differ mainly in the relative concentrations of the individual
members of these classes of compounds (Table 17). The varying proportions
of these compounds determine the physical, as well as the chemical proper-
ties of crude oils. An average of the gross compositional data on all
world crude yields the following approximate composition for the "average"
crude oi1:
32
-------
Table 14
Some Typical Paraffinic Hydrocarbons
Formula
Methane CH.,
Ethane QjH
-------
Table 14
Some Typical Paraffinic Hydrocarbons (cont.)
w-Octacosane
H-Nonacosane
n-Triacontane
n-Hentriacontane
H-Dotriacontane (dicetyl)
M-Tritriacontane
n-Tetratriacontane
H-Pentatrincontane
n-Hexatriacontane
w-Tetracontane
«-Pentacontane
n-H exacontane
w-Dohexaconeane
«-Tetrahexacontane
«-Heptacontane
Formula
C»HM
CooHoa
C'nH«
C-i«Ho
-------
Table 15
Some Typical Naphthenic Hydrocarbons
oo
en
Name
Cyclopropane
Methylcyclopropane
1,1 -Dimethylcy clopropane
1,12-Trimethylcyclopropane
1,2,3-TrimethyIcyclopropane
Cyclobutane
Methylcyclobutane
Ethylcyclobutane
3-Cyclobutylpentane
Cyclopentane
Methylcyclopentane
1,1-Dimethylcyclopentane
1,2-Dimethylcyclopentane
1,3-Dimethylcyclopentane
l-Methyl-2-ethylcyclopentane
l-Methyl-3-ethylcyclopentane
Cyclohexane
Methylcyclohexane
1,1 -Dimethylcy clohexane
1,2-Dimethylcyclohexane
1,3-Dimethylcy clohexane
1,4-Dimethylcy clohexane
Ethylcyclohexane
1,1,3-Trimethylcy clohexane
1,2,4-Trimethy Icy clohexane
1,3,5-Trimethylcy clohexane
1 -Methyl-2-ethylcyclohexane
1 -Methyl-3-ethylcyclohexane
l-Methyl-4-ethylcyclohexane
Propylcyclohexane
Isopropylcy clohexane
1 -Methyl-4-isopropylcyclohexane
1,3-Diethylcyclohexane
Cycloheptane
Ethylcycloheptane
Cyclooctane
Cyclononane
Melting 'Point Boiling Point at 760 mm.
Formula (°F.) (°C.)
CsH.
QH8
CsHio
CeHia
CaHia
C.H8
CSH10
C.HH,
CsHlfi
OHio
CeHia
CiHu
CrHit
GrHu
C8Hia
CeHia
CiHii
CsH*,
CsHi,
CsHle
CsH16
CsHi«
CaHis
Ct>His
C»His
CoHia
CsHis
CeHis
CsHlB
CioHao
GoH»
CrHu
C»Hi8
OH,.
CiHu
CSH,
/-'TT r+ TJ
^.ns 'wsris
(CHs)2* CsH*
(CHs)8*CaHs
(CHaja'CsHa
C*H8
Cards' dixi?
CsHs'CjH?
CSHB-CH(C4H,)-CZH5
CsHio
CHj-CsHo
(CHaVCtH,
(CH,),-C.H.
(CH»)j- CeHs
(CHs) (CaHs) • CsHs
(CH,)(CZH5)-C(SH8
C«Hii
CHs'CeHii
(CH3)j'C«Hio
( CHa) a " CeHio
(CHs)a' CeHio
(CHa)a* CeHio
CiHi'CtHu
(CHa)»"C8H>
(CHa).-QH,
(CH,),-GJI.
(CH,)(C,HB)-C^HIo
(CH») (CiHs) • CeHio
(CHa) (CiHc) • CoHio
CaHi* Caflii
CsHi'CjHja
(CHs) (C«Hi) • CgHio
(CsHs)>' CftTiio
v>?rii4
CJ^-GHa
C
-------
Table 16
Some Typical Aromatic Hydrocarbons
Name
Benzene
Toluene
Xylenes, dimethylbenzenes
0-xylene
m-xylene
/>-xylene
Ethylbenzene
Trimethylbenzenes
1,2,3-trimethylbenzene
1,2,4-trimethylbenzene
1,3,5-trimethylbenzene
Methylethylbenzenes
1 -methyl-2-ethylbenzene
(o-ethyltoluene)
1 -methyI-3-ethylbenzene
(m-ethyltoluene)
1 -methyl-4-ethylbenzene
(/>-ethyltoluene)
H-Propylbenzene
Isopropylbenzene (cutnene)
Tetramethylbenzenes
1,2,3,4-tetramethylbenzene
1,2,3,5-tetraraethylbenzene
1,2,4,5-tetramethylbenzene
Methylisopropylbenzenes
1 -methyl-2-isopropylbenzene
1 -methyl-3-isopropylbenzene
1 -methyl-4-isopropylbenzene
Pentamethylbenzene
Hexamethylbenzene
Pentaethylbenzene
Hexaethylbenzene
Formula
e Oorie
C7H8 CeH6-CH3
CeH4* (CHa) a
CeHi* (CHa) 2
CeH4' (CHa) 2
CioHu
CloHl4
CioHu
CieHas
CisHao
CaH3-(CH3)3
CJH.-(CH,)(CiH5)
(CH3) (GH5)
- (CH3) (C2H5)
CeHB-CH(CH3)2
GH4-(CH3)(C8H,)
CeliV (CHa) (CsH?)
CaH*- (CH.) (GH7)
CaH*
CaH
Ce
From CHEMICAL REFINING OF PETROLEUM
by Vladimir Kalichevsky o. 1942 by
Litton Educational Publishing, Inc.
Reprinted by permission of Van Nostrand
Reinnold Company
Melting Point
(°EJ
41.9
-139.2
-16.6
-53.3
55.8
-137.2
-13.9
-49
-61.1
C-4
-150.9
-142.4
24.8
-11.2
176
— 13
-100.3
127.4
330.8
C~ 4
258.8
(°C.)
5.5
-95.1
-27
-47.4
13.2
-94 -
-25.5
-45
-51.7
<-2Q
-101.6
-96.9
-4
-24
80
>-25 ,
-73.5
53
166
<-20
126
Boiling Point
at 760 mm.
(°F.)
176
231.1
291.2
282.6
281.1
277
349.7
336.6
328.3
329
323.6
323.6
318.2
307.4
399.2
384.8
381.2
350.6
347
350.6
446
509
530.6
S68-.4
(°C.)
80
110.6
144
139
138.4
136.1
176.1
169.2
164.6
165
162
162
159
153
204
196
194
177
175
177
230
265
277
298
Sp. Gr. at °C.
0.878 (20°)
0.867 (20°)
0.879 (20°)
0.864 (20°)
0.861 (20°)
0.867 (20°)
0.895 (20°)
0.876 (20°)
0.863 (20°)
0.882 (20°)
0.867 (20°)
0.862 (20°)
0.862 (20°)
0.862 (20°)
0.901 (20°)
0.896 (0°)
0.838 (81.3°)
0.876 (20°)
0.860 (20°)
0.857 (20°)
0.853 (100°)
0.896 (20°)
0.830 (130°)
Source: (18)
-------
Table 17
Some Hydrocarbons in a Mid-Continent Crude Oil
Purity of Estimated
Boiling Best Sample Relative
Point Isolated Amount
No. Formula Name and Type of Hydrocarbon "* ^ ^nt!" Volume •
Paraffinic
1 CH» Methane —161.7 b "
2 GHe Ethane _ gg.6 b b
3 CaHs Propane _ 42.2 b b
4 CiHu /robutane _ \2\ b "
5 GHU M-Butane — o!s " b
6 GHiz 2-Methylbutane 27^9 b "
7 GHia n-Pentane 35] i b b
8 GHw 2,3-Dimethylbutane 580 >95 0.06
9 GHi» 2-Methylpentane 603 >95 0.1
10 GH14 3-Methylpentane 63.3 >95 0.2
11 GHU n-Hexane 68'7 983 0.7
12 GHie 2,2-Dimethylpentane 78.9 54 0.04
13 GHw 2-MethyIhexane 900 999 0.3
14 GHio 3-Methylhexane 918 c 0.2
15 GHM re-Heptane 984 >998 1.1
16 GHio 2-Methylheptane 1172 97 O.S
17 GHis w-Octane 125'6 99.1 1.0
18 GHa> 2,6-Dimethylheptane 1352 >99 0.1
19 GHM Jjononane 1408 85 0.05
20 GHM 4-Methyloctane 1424 80 0,06
21 GHa 2-Methyloctane 1433 99.9 0.2
22 GHa, 3-Methyloctane 1442 95 0.06
23 GHa, w-Nonane 150.7 99.9 1.0
24 CioHa n-Decane 174.0 >99.99 0.8
Naphthenic
25 GHio Cyclopentane 49.5 " b
26 CsHu Methylcyclopentane 71.9 98.7 0.2
27 GHu Cvclohexane 80.8 99.96 0.3
28 C7Hi, 1,1-Diraethylcyclopentane 87.5 95 0.05
29 GH« Methylcyclohexane 100.8 >99.8 0.3
30 GHi« Octanaphthene 119.8 "1 n-j
31 GHw 1,3-Dimethylcyclohexane 120.3 98 ]
32 GHM Octanaphthene (1,2-dimethyl-
cyclohexane?) 123.4 91 0.04
33 GHU Ethykyclohexane 131.8 95 0.1
34 GHia Nonanaphthene (alkyl cyclo-
pentane) 136.7 >99 0.1
35 GHis Nonanaphthene 141.2 95 0.08
Aromatic
36 GH* Benzene 80.1 99.8 0.08
37 GH8 Toluene 110.6 " 0.3
38 GHio Ethylbenzene 136.2 95 0.03
39 GHio />-Xylene 138.4 >99.9 0.04
40 GHi, wz-Xylene 139.2 >99.9 0.1
41 GHio o-Xylene 144.4 >99 0.1
42 GHu /iopropy [benzene 152.4 98.4 0.03
43 GHU 1,3,5-Trimethylbenzene (mesit-
ylene) 164.6 99.95 0.02
44 GHia 1,2,4-Trimethylbenzene (pseu-
documene) 169.2 99.9 0.2
45 GHi2 1,2,3-Trimethylbenzene (hemi-
mellitene) 176.1 99.95 0.06
1 The numbers in this column give the estimated relative amounts by volume of the given
hydrocarbon in the petroleum, referred to normal octane or normal nonane (which are present in
substantially equal amounts) as unity. In order to obtain the order of magnitude of the percentage
content of the given hydrocarbon in the original crude, these figures should be multiplied by a
factor which is roughly estimated to be somewhere between 1 and 1.66
bNot determined.
" Determination not yet completed. « . _ %
Source: (18)
From CHEMICAL REFINING OF PETROLEUM
by Had-m-iT Kaliehevsky o. 1942 by
Litton Educational Publishing, Inc.
Reprinted by permission of Van Nostrand
Reinhold Company 37
-------
By molecular type:
paraffin hydrocarbons (alkanes) 30%
naphthene hydrocarbons (cycloalkanes) 50%
aromatic hydrocarbons 15%
nitrogen, sulfur and oxygen 5%
containing compounds
By molecular size:
£5 " ^10 (gasoline) 30%
Cj0- C12 (kerosene) 10%
C12- C20 (light distillate oil) 15%
C2<>- Cfo (heavy distillate oil) 25%
j
>£kj '(residual oil) 20%
Any specific crude may differ appreciably from these average values. For
example, Lagomedio crude oil from Venezuela would contain about 10 percent
paraffins (alkanes), 45 percent naphthenes (cycloalkanes), 25 percent
aromatics and 20 percent nitrogen, sulfur and oxygen-containing compounds.
In contrast a south Texas crude has a larger percentage of smaller molecular
sizes and a greater amount of paraffin-naphthene hydrocarbons than the
worldwide crude average.
Crude oils can be divided roughly into three main groups on the basis
of hydrocarbon structural predominance; paraffinic, naphthenic, and
aromatic. Paraffinic (alkanic) crude oils contain mostly saturated
straight and branch chained carbon compounds, along with lesser amounts of
cycloalkanes and aromatics. They include the lightest of all crudes.
Most of the crudes used by the Puget Sound refineries are paraffinic
crudes. Naphthenic crudes, also called cycloparaffins, contain appreciable
quantities of compounds with at least one saturated ring structure and bear
a close resemblance to paraffinic crudes. The aromatic crude oils general-
ly are heavier, with higher boiling points and contain a large concentra-
tion of unsaturated benzene ring structures. Aromatic crudes also usually
contain a high sulfur content (two percent or more).
The crude oils which have been utilized by the Puget Sound refineries
during the past three years and those which may be used to replace the
diminishing supply of Canadian crude's also can be categorized, according
to the occurrence of these three classes of hydrocarbons, as being paraf-
finic, naphthenic or aromatic crudes (Tables 18 and 19). In some instances,
however, there is no clear predominance of one class of hydrocarbons over
the others. Arabian Light crude oil, for example, is largely naphthenic,
38
-------
Table 18
General Chemical Classification of Crude Oils Received from
1974-1976 by Puget Sound Refineries
Crude Oil
Arabian Light
Berri
Iranian Light
Iranian Heavy
Sassan
Murban
Attaka
Minas
Arjuna
Walio Export Mix
Bekapi
Poleng
Labuan Light
Lagomedio
Oriente
Brass River
Qua Iboe
Bonny Light
Canadian
Cook Inlet
San Ardo
San Joaquin
Santa Maria
Predominant Chemical Characterises
Paraffinic
9
^
•
•
•
•
•
•
•
•
•
•
•
•
•
Naphthenic
•
•
•
9
•
•
•
•
•
Aromatic
•
0
*
•
•
•
9
•
39
-------
Table 19
General Chemical Classification of Crude Oils Under Consideration
by Puget Sound Refineries for Replacement of Canadian Crude Oils
Crude Oil
Qua Iboe
Forcados
Brass River
Bonny Light
Escravos
Pennington
Zuetina
Es Sider
Bu Attifel
Brega
Sarir
Amna
Oriente
Lagomedio
Arjuna
Attaka
Bekapai
Cinta
Labuan Light
Minas
Poleng
Badak
Sepinggan
Bunju
Handil
Arzew
Zarzaitine
Hassi Messaoud
Predominant Chemical Characteristic
Paraffinic
£
•
*
•
•
•
•
0
*
•
•
•
0
*
•
•
•
•
•
•
*
•
:J
•
• -
m
m
•
Naphthenic
•
Aromatic
•
%
•
40
-------
Table 19 (cont.)
General Chemical Classification of Crude Oils Under Consideration
by Puget Sound Refineries for Replacement of Canadian Crude Oils
Crude Oil
Gamba
Anguille
Cabinda
Murban
Cook Inlet
North Slope
Predominant Chemical Characteristic
Paraffinic
9
®
®
0
m
- «
Naphthenic
•
Aromatic
41
-------
but also has a fairly high aromatic content. For these cases, more than
one category is noted in Tables 18 and 19.
Petroleum in its various types and fractions has been observed to
cause mortality among marine organisms. The manner in which crude oils and
petroleum products can affect marine life is (1) directly -- by chemical,
physiological or mechanical means, or (2) indirectly -- by oxygen reduc-
tion, carbon dioxide concentrations or accumulative synergistic effects.
The chemical toxicity of a crude oil to marine life varies according to
the classification to which it belongs, the volatility of the hydrocarbons
present, and its solubility in seawater. Toxicity is a function of re-
activity; the more reactive a compound, the more likely it will interfere
with biological functions. Paraffinic compounds do not tend to mix easily
with water or biological tissues, and do not tend to react biologically.
Therefore, the toxicity of these compounds is almost always low. Highly
substituted compounds can react more easily, and their toxicities cover
a wide range depending on the nature of the substitutions. Aromatic com-
pounds are very reactive in biological systems, and have high toxicities.
So crude oils classed as aromatic, containing a predominance of aromatic
compounds, are generally more toxic than the light, waxy crudes. Even
naphthenic crudes, which contain saturated cyclic compounds are less toxic
because these ring compounds are more easily degraded than are the aro-
matic unsaturated benzene rings. Also the higher sulfur content frequently
associated with aromatic crudes increases the initial toxicity because it
tends to inhibit oxidative processes, allowing the more volatile frac-
tions to remain unoxidized in sea water.
The volatility of the hydrocarbon compounds appears to be another
factor influencing toxicity. Small, low-boiling molecules, especially
the more reactive hydrocarbons, can easily penetrate biological tissues
and are very damaging in terms of toxicity. Therefore, volatile hydro-
carbons are generally more harmful than nonvolatile compounds i.n the same
hydrocarbon class. Consequently some volatile aromatics are considered
to be the most toxic types of hydrocarbons, although other low-boiling,
non-aromatic hydrocarbons may also be highly toxic. Defining which com-
pounds are volatile and which are nonvolatile has been a subject of con-
troversy in the past. A compromise classification method defines those
hydrocarbons with boiling points of less than 457°F (236°C) as volatiles.
This includes all hydrocarbons through C15. All hydrocarbons above C13
have boiling points above 457°F and are classed as nonvolatiles. The
relative general occurrence of volatiles and nonvolatiles in crude oils is
shown in Table 20. Tables 21 and 22 present the relative percentages of
volatile compounds that occur in crudes used by Puget Sound refineries
and those crude oils which may replace the dwindling supply of Canadian
crudes. Whenever possible the breakdown of volatiles to specific hydro-
carbon classes has been indicated.
The actual effect of these potentially toxic volatile compounds on
marine organisms is generally reduced by the physical weathering processes
that exert their influence as soon as the crude oil enters the marine
environment. The volatile hydrocarbons evaporate fairly rapidly under
most conditions. Evaporation is greatly enhanced by wind and wave action,
and is most intense during the first week after the oil enters the water.
42
-------
Table 20
Relative Quantity of Volatiles and Nonvolatiles in Crude Oils
Class
Volatiles
Nonvolatiles
Boiling Point (°F)
<457
457-968
<968
Carbon Number
Volume Percent
20 - 50
35 - 50
7 - 45
Source: (12)
43
-------
Table 21
Relative Percentages of Volatiles (Total and by Hydrocarbon
Class) in Crude Oils Received from 1974-1976 by Puget Sound Refineries
Crude Oil
Arabian Light
Berri
Iranian Light
Iranian Heavy
Sassan
Murban
Attaka
Minas
Arjuna
Walio Export Mix
Bekapai
Poleng
Labuan Light
Lagomedio
Oriente
Brass River
Qua Iboe
Bonny Light
Canadian
Cook Inlet
San Ardo
San Joaquin
Santa Maria
Total
Volatiles
35
38
34
32
35
41
61
23
36
39
41
60
43
30
30
54
42
36
35-44
37-47
—
—
—
Volatile
Aromatics
4
5
6
5
7
7
16
2
8
2
—
11
9
—
4
7
5
4
—
.
—
—
—
Volatile
Naphthenes
7
7
11
11
11
8
9
7
12
14
—
22
14
—
12
27
22
17
—
—
--
—
—
Volatile
Paraffins
24
26
17
16
17
26
36
14
16
23
—
27
20
—
14
20
15
15
—
—
__
—
—
44
-------
Table 22
Relative Percentage of Volatiles (Total and by
Hydrocarbon Class) in Crude Oils Under Consideration by
Puget Sound Refineries for Replacement of Canadian Crude Oils
Crude Oil
Qua Iboe
Forcados
Brass River
Bonny Light
Escravos
Pennington
Zuetina
Es Sider
Bu Attifel
Brega
Sarir
Amna
Oriente
Lagomedio
Arjuna
Attaka
Bekapai
Cinta
Labuan Light
Minas
Poleng
Total
Volatiles
42
27
54
36
37
39
33
34
25
41
26
27
30
30
36
61
41
—
43
23
60
Volatile
Aroma tics
5
3
7
4
6
4
4
4
2
5
1
1
4
—
8
16
—
--
9
2
11
Volatile
Naphthenes
22
13
27
17
15
20
11
9
4
12
10
8
12
--
12
9
—
__
14
7
22
Volatile
Paraffins
15
11
20
15
16
15
18
21
19
24
15
18
14
--
16
36
—
—
20
14
27
45
-------
Table 22 (cont.)
Crude Oil
Badak
Sepinggan
Bunju
Handil
Arzew
Zarzaitine
Hassi Messaoud
Gamba
Anguille
Cabinda
Murban
Cook Inlet
North Slope
Total
Volatiles
--
47
44
24
42
37
47
15
27
25
41
37-47
26
Volatile
Aroma tics
--
11
—
10
3
6
6
--
2
3
7
—
4
Volatile
Naphthenes
--
—
—
—
9
12
14
--
9
7
8
—
9
Volatile
Paraffins
--
--
—
--
30
19
27
--
16
15
26
—
13
46
-------
Figure 6 shows the decrease of the volatile fractions and the relative
stability of the nonvolatile hydrocarbons during artifical laboratory
weathering of a Kuwait crude oil. Generally, even the most intense
weathering action only affects hydrocarbons with boiling points below
350°C. Thus the effect of these volatile hydrocarbons on marine organ-
isms will vary, depending on the type of volatile hydrocarbon (the aro-
matics being the most toxic) present and the rate and degree of weather-
ing, causing these hydrocarbons to evaporate from the marine environment.
The water solubilities of the hydrocarbon compounds also will effect
the toxicity of a given crude oil. For a specific class of hydrocarbons,
the solubility in water decreases as the molecular weight increases.
For the classes of hydrocarbons, solubility increases from alkanes to
cycloalkanes to aromatics. Some solubility values for the various classes
of hydrocarbons are shown below.
Class of
Hydrocarbon
•Alkanes
Hydrocarbon of
Class with Highest
Solubility in Water
Ethane
42 ppm
Cycloalkanes Cyclopentane
Olefins
Aromatics
Propene
140 ppm
Benzene
1246 ppm
Solubility of a Higher
Molecular Weight
Hydrocarbon in Class
Decane
0.035 ppm
1,2-Dimethylcyclohexane
4.2 ppm
1-Octene
2.1 ppm
Isopropylbenzene
35 ppm
These values are for sea water. In freshwater the solubility would be
somewhat greater. Crude oils in equilibrium with sea water typically have
from 10-30 ppm total dissolved hydrocarbons, of which about half may be low
molecular weight aromatic hydrocarbons. Thus the low molecular weight,
volatile aromatic hydrocarbons are not only the most toxic hydrocarbons,
they are the most soluble in water. The actual extent to which these
soluble hydrocarbons affect marine organisms will depend on the quantity
in a specific crude and the length of time required to reduce these
hydrocarbons by weathering and other degradative processes.
To further identify the effects of crude oils on the marine environ-
ment, it will be necessary in the future to have a much more detailed hydro-
carbon breakdown for each crude. Identification of specific compounds will
allow application of solubilities to determine which toxic hydrocarbons
could potentially be mixed with the marine waters. Until then, classifi-
cation according to specific hydrocarbon types and examination of the per-
centage of volatile compounds must suffice for characterizing crude oils
47
-------
CO
Figure 6
The Effects of Artificial Weathering of the Volatile and
Nonvolatile Hydrocarbons in a Kuwait Crude Oil
WCATHERINS. hours
Source: (12)
-------
as to their relative toxicities to the marine environment. On this basis,
a tentative subjective rating of the crude oils being used by the Puget
Sound refineries indicates that the following crudes are the most harmful
to marine organisms: Attaka, Poleng, Labuan Light, Arjuna, Brass River,
Sassan and Murban. Other crudes which would be expected to have very
harmful effects are: Arabian Light, Iranian Light, Iranian Heavy, San
Ardo and possibly San Joaquin, Santa Maria and Lagomedio. It is difficult
without more detailed crude assays to distinguish and rank the remaining
crudes and potential future crudes; however, they too will have toxic
effects on the marine environment.
Beyond the general lethal and sub-lethal toxic effects, crude oils can
also disrupt the marine ecosystem by (1) direct coating of organisms with
crude; (2) tainting and/or accumulation of hydrocarbons in the food chain
through incorporation of hydrocarbons in organisms, and (3) causing drastic
changes in the habitats or marine organisms. These effects would-be
possible for all of the crude oils brought to the Puget Sound refineries.
The effects of oil on a number of species have been analyzed; selected
species are shown in Table 23. Biological communities damaged by oil can
eventually recover naturally. However, the rate of recovery will depend
on the species, the season of exposure, the type and amount of crude oil,
and the frequency of exposure.
C. Refined Products Utilized-or Prodliced in Puget Sound"
1. Introduction
The production of refined products is directly-related to the type of
crude oils being used, the design of the refinery and the relative amounts
of each product the refinery management desires. Usually a refinery is
built to utilize specific types of crude oils (light, heavy, waxy, aromatic,
low sulfur, etc.), employing specific processes to yield specific types of
products. The four major refineries were designed to produce a large array
of fuel products, but predominantly motor gasoline and jet fuels. Mobil,
Shell and Texaco were designed to utilize light, sweet (low sulfur) crudes,
while ARCO employs a few additional processes to allow handling of heavier,
high sulfur crudes (specifically Alaskan North Slope crudes when they be-
come available). U.S. Oil & Refining is a smaller operation and not only
produces a variety of fuels, but also was designed to process' heavy
asphaltic crudes to yield petroleum asphalt. Sound Refining is a very
small operation and at the present is strictly capable of handling the
production of asphalt, some lubricating oils, and fuel oils.
The output of the refineries varies seasonally, and to a lesser
extent, monthly, in response to market demands. The local market has the
highest priority, followed by market demands in Oregon and California. In
general there is a seasonal shift from motor fuels in spring and summer to
domestic heating oils in fall and winter. This shift is not to the exclu-
sion of the other products; rather, it is a shifting in emphasis to accom-
modate the changing demand for heating oils. Sound Refining has a special
problem in that the market for asphalt drops drastically in winter and the
49
-------
Table 23
The Effects of Crude Oil on Selected Species
Species
Birds
Rissa tridactyla
Fishes
Alosa spp.
Clupea harengus
Fundulus heteroclitus
Gadus morhua
Micropogon undutatus
Morona saxatilis
Pseudopleuronectes americanus
Crustaceans
Acartia spp.
Ampelisca vadorum
Balanus balanoides
Calanus spp.
Crangon spp.
Emerita spp.
Homarus americanus
Paqurus longicarpus
Panda/us spp.
Mollusks
Asquipecten spp.
Crassostrea spp.
Donax spp.
Mercenaria mercenaria
Modiolus spp.
Mya arenia
Mytilus edulis
L ittorina littorea and spp.
Nassarius obsoletus
Thais lapi/lus
Worms
Arenicola marina
Nereis virens
Stroblospio benedicti
Other animals
Asterias vulgaris
Strongylocentrotus droebachiensis
Plants
Juncus gerardi
Spartina alterniflora
Spartina patens
Laminaria spp.
Common
name
Kittiwake
Alewife
Herring
Mummichog
Atlantic cod
Croaker
Striped bass
Winter flounder
Zooplankter
Amphipod
Acorrr barnacle
Zooplankter
Shrimp
Mole crab
American lobster
Hermit crab
Shrimp
Scallop
Virginia oyster
Coquina clam
Northern quahog
Horse mussel
Soft-shell clam
Edible mussel
Periwinkle
Common mud snail
Dog whelk
, Lugworm
Clam worm
Polychaete
Starfish
Sea urchin
Marsh rushes
March grasses
Cord grass
Kelp
Lethal
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Sublethal
X
X
X
X
X
X
X
X
X
X
X
X
Coating
X
X
X
Uptake
and
tainting
X
X
X
X
X
X
X
X
X
X
Habitat
change
X
X
X
1 Does not list all species for which data have been reported. Rather, an X represents reported data for those species which were
selected for special consideration. An X indicates that some data, regardless of number, have been reported.
Source: Massachusetts Institute of Technology Department of Civil Engineering, 1974, "Atlantic/Alaskan OCS Petroleum
Study: Primary Biological Effects," prepared for the Council on Environmental Quality under contract No. EQC330.
Source: (14)
50
-------
necessity of applying heat to move the heavy crude oil makes refinery
operations relatively uneconomical in winter. So the refinery has often
been shut down for five or six months of the year.
There are a number of different products that can be obtained by pro-
cessing crude oils. The nominal product yield from an average barrel of
oil is:
gasoline 45%
•kerosene 3%
jet fuel 8%
distillate fuel oil 22%
residual fuel oil 8%
other products 14%
A more specific list of refined products available from crude oil is shown
in Figure 7 and includes:
Gases (such as butane and propane)
Liquified petroleum gas (LPG)
Motor gasoline (regular, supreme, unleaded)
Aviation fuel (mainly for piston planes)
Jet fuel (JP-4, JP-5, Jet A, Jet A-l)
Kerosene
Fuel Oils
#1 high grade diesel oil
#2 diesel oil (six different grades)
#3 heating oil
#4 heating oil (for small companies, manufacturers, etc.)
#5 heating oil (used by cities, industries, etc.)
#6 bunker C (used by power plants, ships, heavy industries)
Lubricating oils, greases
Naphtha and petroleum solvents
Asphalt, tar and pitch
51
-------
Figure 7
Refined Products Derived From Crude Petroleum
HYDROCARBON J
GASES
Liquefied Gases .
Petroleum Ether
Alcohols
f Metal Cutting Gas
' *' ' \ Illumination Gas
f Laboratory Ether
' * ' ' L Motor Priming Ether
,-T , /Solvents
popropyl (Acetone
Other Synthetics
. J Secondary Butyl "1 f Lai
I Secondary Amyl f- s cnl
L Secondary Hexyll Is01
1
.acquer
H -jolvents
fBenzene Chemicals, Explosives, Pharmaceuticals
Toluene Explosives, Toluidine, Saccharin
Xylene Explosives, Dyes
Naphthalene Dyes, Perfumes
Anthracene Dyes
Resins Lacquers, Varnishes, Paints
Gas Black
Fuel Gas
l,Light Naphthas .
< Intermediate Naphthas
LIGHT
DISTILLATES
Naphthas
Refined Oils
INTERMEDIATE j~Gas °U
DISTILLATES
L Absorber Oil
{Rubber Tires ["Gas Machine Gasoline
Inks Pentane
Paints Hexane
f Light Naphthas Chemical Solvents
Aviation Gasoline
Motor Gasoline
Commercial Solvents
Blending Naphtha
Varnishmakers & Painters Naphtha
^Heavy Naphthas Dyers & Cleaners Naphtha
Turpentine Substitutes
.Soaps
fLamp Fuel
'Kerosene 4 Stove Fuel
(.Motor Fuel
c. , ,... ("Railroad Signal Oil
S'S"al Oil \ Ligh,house Oil
, c , ,-.-1 / Coach & Ship Illuminantf
al Seal Oil ( Gas Absorption Oils
Carburetion Oils
Metallurgical Fuels
Cracking Stock
I Household Heating Fuels
Light Industrial Fuels
I Diesel Fuel Oils
[ Gasoline Recovery Oil' f Technical
Domestic Illumination Naphtha
Candlepower Standardization Naphtha
Laboratory Naphtha
Drug Extraction Solvent
fRubber Solvent
j Fatty Oil Solvent (Extraction)
LLacquer Diluents
nts
J
\ Benzol Recovery Oil
>White Oils
(-Technical Heavy Ofl .
HEAVY
DISTILLATES
Wax
Medicinal
Saturating Oils
Emulsifying Oils ......... Cutting Oils
Tri.«t • i rrl f Transformer Oils
Electrical Oils ........... { Switch Oils
v Flotation Oils ............ Metal Recovery Oils
/•Candymakers Wax
Candle Wax
L-ndry Wax ............ {^Wax^
Sealing Wax
Etchers Wax fCardboard Wax
Saturating Wax .......... •( Match Wax
Chewing Gum Wax LPaper Wax
Medicinal Wax
Insulation Wax
Canning Wax
{Emulsified Spray Oils
Bakers Machinery Oil
Candymakers Oil
Fruit Packers Oil
Egg .Packers Oil
Slab Oil—Candy and Baking
""Internal Lubricant
Salves
Creams
Ointments
;Source: (18)
From CEMICAL REFINING OF PETROLEUM by Vladimir Kaliohevsky
Q. 2942 by Litton Educational Publishing, Inc.
Reprinted by permission of Van Nostrand Reinhold Company
-------
Figure 7 (cont.)
- Lubricating Oil
! Lubricating Oil . . . .
Ul
co
RESIDUES
Petrolatum Grease
Residual Fuel Oil
Still Wax
•Light Spindle Oils
Textile Oils
Transformer Oils
Household Lubricating Oils
Compressor Oils
ice Machine Oils
Meter Oils
Journal Oils
Motor Oils
Steam Cylinder Oils
Compounded Oils Water-Soluble Otis
Valve Oils
Turbine Oils
Tempering Oils Heat Treating Metals
Floor Oils
Transmission Oils
Railroad Oils
Printing Ink Oils
Black Oils Compounded Greases
Grease Oils (For General Lubrication)'
Technical
Petrolatum .1
Asphalts
{Wood 'Preservative Oils
Gas Manufacture Oils
Boiler Fuel
Metallurgical Oils
. Roofing Material
'Liquid Asphalts
Binders
Fluxes
Steam Reduced Asphalts
Coke
REFINERY
SLUDGES
[ Sulfonic Acid
| Heavy Fuel Oils
tSulfuric Acid
.Oxidized Asphalts
fCarbon Brush Coke
.< Carbon Electrode, Coke
LFuel Coke i'* V (
{Sapomfication Agents *
Demulsifying Agents
. Fertilizers
Medicinal
^Merchant Marine Fuel
I Naval Fuel
' ] Railroad Fuel
Llndustrial Fuel
'Road Oils
Roofing^ §aturan^s
^Emulsion Bases
{Briquetting Asphalts
Paying Asphalts
Shingle Saturants
Paint Bases
Flooring Saturants
rRoof Coatings
J Waterproofing Asphalts
Rubber Substitutes
_ Insulating Asphalts
/-Gear Grease
j Axle Grease
J Switch Grease
] Cable Grease
V_Cup Grease
rMetal Coating Compound
J Lubricants
[^Cable Coating Compound
f Petroleum Jelly
Compounded Products
Salves
Cold Cream
Skin Cream
Vanishing Cream
Wrinkle Remover
Massage Cream
Rouge
_ Lipstick
-------
The gases produced from crude oils are often used within the refinery,
although some may be sold locally when allowable by market economics. Motor
gasolines are a blend of different product streams, with the final product
meeting the specific qualities desired. Numerous additives, for anti-
gumming, anti-rust, etc., are also added to motor gasolines and the other
fuel products. Very little aviation fuel is produced any more, due to the
low level of demand. Jet fuels are utilized by commercial turboprop and
jet aircraft. The military also has a portion of its jet fuel produced by
the Pbget Sound refineries. There is only a 'Small demand for kerosene, so
most of this product is blended to make jet fuel. Two of the six types of
fuel oil, #1 and #3, are rarely used any more. These are old designations
and the product demand has changed sufficiently enough that there is virtu-
ally no demand for either of these fuel oils. The remaining products con-
stitute a small fraction of the product yield from the refineries except
for asphalt and lubricating oils which are important'products of U.S. Oil
& Refining and Sound Refining. The products produced by Puget Sound refin-
eries are shown in Table 24.
Determining the exact amount of each product that a specific"refinery
is producing can be difficult, since this kind of information is often
considered to be proprietary. In some instances specific values are avail-
able, while in others, only rough estimates can be made from the informa-
tion that is available. Often instead of the full range of products, the
refinery yield is listed under terms like "middle distillates," "residual
fuel oils" and "distillate fuel oils" which are groupings of refined pro-
ducts. Also the seasonal variation of product yield makes it necessary
to consider an average annual production figure. The availability of
specific crude oils may also cause modifications of theV'average daily"
yield from a refinery. Table 25 shows an estimation of the relative per-
centages of products produced by the Puget Sound refineries. These are
based on information provided by the Federal Energy Administration, the
Washington State Department of Ecology, and from the refineries themselves.
2. Mode of Transport
Products produced at Puget Sound refineries are transported by pipe-
line, railroad car, truck, barge and tanker (Table 26). The Olympic Pipe-
line originates at the four major refineries in Ferndale and Anacortes,
and delivers the refined products to western Washington and Oregon. U.S.
Oil & Refining and Sound Refining are not connected to this product pipe-
line. Since 1972 there has been a gradual increase in the flow of products
through the Olympic Pipeline from 171,000 bbls/day to 173,000 bbls/day in
1975, and 184,000 bbls/day during the first half of 1976. This mode of
transport accounts for more than 60 percent of the total quantity of pro-
ducts from Mobil, ARCO, Shell and Texaco. These products are predominantly
gasolines, with lesser quantities of jet fuel, kerosene and distillate
fuel oil, which are all considered "pipeable" products. The pipeline
product flow reflects the seasonal shift in refinery products. Generally
in summer, gasoline, jet fuel and kerosene make up 60 percent of the
volume shipped. In winter this drops to around 50 percent, and the
distillate fuel portion (mainly heating oils) rises to 50 percent. Approx-
imately half of these pipeline shipments stay in Washington; the remainder
are consumed in Oregon.
54
-------
Table 24
Petroleum Products Produced by Puget Sound Refineries
Product
Motor Gasoline
Jet Fuel
Domestic Heating Oil
Diesel Fuel Oil (#2)
Industrial Heating Oil
Bunker C Fuel Oil
Liquefied Petroleum Gas
Petroleum Asphalt
Lubricating Oils
Coke
Mobil
•
•
•
•
•
0
•
ARCO
•
•
•
•
•
• ,
*
•
Shell
•
•
•
•
•
•
•
Texaco
•
•
•
•
•
•
•
U.S. Oil &
Refining
•
•
•
•
•
•
Sound
Refining
•
•
•
en
en
-------
Table 25
Estimated Relative Percentage of Product Output
by the Puget Sound Refineries from 1974-1976
Product
Motor Gasoline
Jet Fuel
Distillate Fuel Oil
Residual Fuel Oil
Liquefied Petroleum Gas
Lubricating Oil
Asphalt
Unfinished Distillates
Mobil
60
on
c.y
8
3
-
-
-
ARCO
44
34
12
8
2
-
-
-
Shell
66
15
13
4
2
-
-
-
Texaco
52
QQ
JO
8
2
-
_
/ _
U.S. Oil &
Refining
51
17
9
3
t
-
20
_
Sound
Refining
-
-
-
11
-
2
60
27
01
01
-------
Table 26
Comparison of Land and Marine Transport of the
Products Refined by the Puget Sound Refineries
(a) For Mobil, ARCO, Shell and Texaco:
Mode of Transport
Pipeline
Truck, Railroad Car
Marine
1974
52%
5%
43%
1975
52%
5%
43%
1976§
56%
5%
39%
First six months
(b) For U.S. Oil & Refining and Sound Refining
Mode of Transport
Truck, Railroad Car
Marine
1974
62%
38%
1975
64%
36%
1976§~
Jl%"
29%
s
First six months
57
-------
A portion of the refined products produced in Washington are shipped
around the state by truck or railroad car. This amounts to about ten per-
cent—around 33,000 bbls/day. For the major refineries, this consists of
loading tank trucks and rail cars with gasoline and other light products
for local consumption. Sound Refining transports some of its asphalt pro-
duction by truck to local paving companies, as does U.S. Oil & Refining.
The remainder of the products produced by Washington and the majority of
products consumed in western Washington are transported by tankers and barges,
3. Marine Transport of Petroleum Products
Marine transport accounted for more than 40 percent of the products
distributed by Puget Sound refineries in 1974 and 1975. For 1976, an in-
crease in the quantities of products shipped by pipeline has dropped marine
traffic to slightly below 40 percent. These marine shipments move products
internally to other ports within Puget Sound (defined here to include the
Strait of Juan de Fuca beginning at Neah Bay), coastwise to California and
other states and to some foreign countries. For 1974, Puget Sound refin-
eries shipped approximately 17.2 million barrels of gasoline, 1.8 "million
barrels of jet fuel, 0.8 million barrels of kerosene, 8.8 million barrels
of distillate fuel oil, and 8.8 million barrels of residual fuel oil, and
0.5 million barrels of other petroleum products.
This movement of petroleum products through Puget Sound accounts for
most of the waterborne transport of refined products; however, there is an
additional quantity of various products that are imported from foreign
sources and other states. Even though approximately 12,million barrels of
gasoline were shipped coastwise to other states, Washington ports also
received more than 2 million barrels of gasoline by coastwise transport
in 1974. This may seem odd, but it is easily accounted for. Petroleum
companies, other than those with refineries in the State of Washington,
also operate outlets for petroleum products in the state. Hence .they im-
port their own particular brand of products, made to their own specifica-
tions, to meet market demands. Also, in addition to refined products manu-
factured by Puget Sound refineries, the military services import a variety
of products. The relatively short Buckeye Pipeline serves to transport
refined products the seven miles from the Port of Tacoma to McChord Air
Force Base.
The total waterborne traffic of petroleum products in the waters of
Washington, including products refined in the state and products imported
from other sources for 1973 and 1974 is shown in Tables 27, 28, 29, 30,
31, 32, 33, and 34. Each table indicates the receipts and shipments in
Puget Sound as a total and by major port; each also is subdivided to dis-
tinguish foreign, coastal, internal and local transport, in short tons, of
the specific product. This type of detailed information will not be pub-
lished for 1975 until November of 1976. The "Total" category includes all
ports in Puget Sound which receive or ship products. The Ports of Tacoma,
Seattle, Anacortes and Bellingham are the principal shippers and recipients
of petroleum products. Shipments listed for Bellingham are predominantly
from the docks of ARCO and Mobil at Cherry Point and Ferndale, respectively.
Shipments listed for Anacortes are primarily from the docks of Shell and
Texaco. The sub-category "Coastal" represents all domestic marine traffic
58
-------
Table 27
Waterborne Transport of Gasoline
(in Short Tons) in Puget Sound
Shipping
Port or
Destination
Total
Foreign
Coastal
Internal
Local
Tacoma
Foreign
California
Oregon
Internal
Local
Seattle
Foreign
Coastal
Internal
Local
Anacortes
California
Alaska
Oregon
Hawaii
Internal
Receipts
1973
32,382
114,410
1,406,019
75,408
4,843
16,219
0
170,297
0
27,539
89,649
1,052,724
59,633
0
0
0
0
601
1974
47,958
254,610
602,599
59,178
5,454
0 ^
0
51 ,899
1,210
39,821
222,829
448,559
22,879
28,723
0
0
0
301
Shipments
1973
0
1,638,883
1,406,019
-
0
0
24,587
15,635 -
-
0
44,810
322,877
-
257,890
59,848
45,000
61 ,900
744,872
1974
0
,1, 374, 045
602,599
-
0
7,597
0
16,455
-
0
18,904
130,496
-
595,704
28,141
38,174
71,310
336,176
Source: (28, 29)
59
-------
Table 27 (cont.)
Waterborne Transport of Gasoline
(in Short Tons) in Puget Sound
Shipping
Port or
Destination
Bellingham
Foreign
California
Alaska
Oregon
East Coast
Internal
Local
Receipts
1973
0
3,924
0
0
0
87,318
15,775
1974
2,683
0
0
0
0
51,979
35,089
Shipments
1973
0
907,195
533
237,082
0
318,160
-
1974
0
367,975
2,719
111,523
132,718
117,929
-
60
-------
Table 28
Waterborne Transport of Jet Fuel
(in Short Tons) in Puget Sound
Shipping
Port or
Destination
Total
Foreign
Coastal
Internal
Local
Tacoma
Internal
Local
Seattle
Coastal
Internal
Local
Anacortes
California
Alaska
Oregon
Hawaii
Internal
Bellingham
California
Alaska
Oregon
Hawaii
Internal
Local
Receipts Shipments
1973
0
27,039
173,173
125,818
141,844
15,248
8,481
15,514
16,720
0
0
0
0
0
10,438
8,120
0
0
15,815
93,850
1974
0
42,375
102,714
204,128
62,519
73,983
42,375
9,373
0
0
0
0
0
0
0
0
0
0
30,822
130,145
1973
0
287,634
173,173
-
15,815
1
63,112
0
-
23,626
0
0
0
9,090
161,361
6,418
11,315
15,261
148,268
—
1974
0
117,468
102,714
-
30,822
-
695
0
-
2,112
1,910
1 ,437
162
4,385
81,972
6,399
22,781
0
67,507
—
Source: (28, 29)
61
-------
Table 29
Waterborne Transport of Kerosene
(in Short Tofis) in Puget Sound
Shipping
Port or
Destination
Total
Foreign
Coastal
Internal
Local
Tacoma
Foreign
Internal
Seattle
Foreign
Coastal
Internal
Local
Anacortes
California
Hawaii
Bellingham
Foreign
Oregon
Internal
Local
Receipts
1973
248,789
3,548
1,399
702
0
0
248,789
3,548
1,399
702
0
0
478
0
0
0
1974
152,589
24,546
7,231
0
0
0
152,589
2,641
7,231
0
21,905
0
0
0
0
0
Shipments
1973
88,643
83,507
1,399
-
8,252
-
0
17,662
0
-
17,005
292
80,391
48,548
1,399
-
1974
71,740
31,631
7,231
-
--
0
>2,125
0
449
0
-
11,627
6,607
71,740
12,948
1,274
-
Source: (28, 29)
62
-------
Table 30
Waterborne Transport of Distillate Fuel Oil
(in Short Tons) in Puget Sound
Shipping
Port or
Destination
Total
Foreign
Coastal
Internal
Local
Tacoma
Foreign
California
Alaska
Oregon
Internal
Local
Seattle
Foreign
Coastal
Internal
Local
Anacortes
California
Alaska
Oregon
Hawaii
Internal
Receipts
1973
75,846
785,733
965,441
217,647
0
2,970
0
0
319,306
1,159
7,584
624,108
457,356
206,438
22,575
0
0
0
3,690
1974
6,999
567,284
623,695
92,653
0
9,209
13,700
0
161,052
5,452
6,999
494,559
347,884
85,175
75,023
0
0
0
1,004
Shipments
1973
9,450
1,200,385
965,441
- ,
9,450
0
0
31 ,054
23,885
-
0
54,835
371,196
-
25,727
48,639
28,713
0
263,755
1974
14,943
533,958
623,695
-
2,028
0
0
0
47,745
-
0
72,329
176,138
-
22,749
10,664
21,733
6,748
282,149
Source: (28, 29)
63
-------
Table 30 (Cont.)
Waterborne Transport of Distillate Fuel Oil
(in Short Tons) in Puget Sound
Shipping
Port or
Destination
Bellingham
Foreign
California
Alaska
Oregon
Hawaii
Grays Harbor
Internal
Local
Receipts
1973
68,262
124,976
0
0
0
0
91 ,580
10,050
1974
0
0
0
0
0
0
63,180
2,026
Shipments
1973
0
800,590
6,611
194,510
9,706
0
300,183
-
1974
12,915
350,932
2,820
39,599
0
868
116,693
i
64
-------
Table 31
Waterborne Transport of Residual Fuel Oil
(in Short Tons) in Puget Sound
Shipping
Port or
Destination
Total
Foreign
Coastal
Internal
Local
Tacoma
Foreign
California
Internal
Local
Seattle
Foreign
Coastal
Internal
Local
Anacortes
California
Alaska
Oregon
Hawaii
Grays Harbor
Internal
Local
Receipts
1973
17,178
709,953
399,704
233,116
0
22,461
159,134
11,751
10,696
393,388
159,794
220,326
0
0
0
0
0
1,172
1,039
1974
t
35,469
592,216
362,845
128,954
0
0
100,593
7,075
35,469
336,697
148,986
118,402
33,302
0
0
0
0
32,833
0
Shipments
1973
66,714
339,583
399,704
-
0
0
7,717
-
4,050
92,240
141,319
-
24,645
8,132
0
2,455
0
182,886
~
1974
137,870
793,576
362,845
-
8,984
0
6,542
-
6,750
40,929
128,787
-
52,051
0
23,723
1,053
6,936
172,938
™
Source: (28, 29)
65
-------
Table 31 (Cont.)
Waterborne Transport of Residual Fuel Oil
(in Short Tons) in Puget Sound
Shipping
Port or
Destination
Bel 1 i ngham
Foreign
California
Oregon
Internal
Local
Receipts
1973
6,482
143,465
18,529
19,130
0
1974
0
131,262
0
20,077
3,477
Shipments
1973
62,664
212,111
0
67,782
-
1974
122,136
668,884
0
54,578
-
66
-------
Table 32
Waterborne Transport of Lube Oils and Greases
(in Short Tons) in Puget Sound
Shipping
Port or
Destination
Total
Foreign
Coastal
Tacoma
Foreign
Coastal
Seattle
Foreign
Coastal
Anacortes
Coastal
Bellingham
Coastal
Receipts
1973
27
142,478
0
15,012
27
89,551
37,915
0
1974
129
102,418
0
0
129
72,320
16,940
0
Shipments
1973
1,174
27,416
337
0
837
7,640
0
19,776
1974
3,203
22,669
198
0
2,998
21,052
0
1,617
Source: (28, 29)
67
-------
Table 33
Waterborne Transport of Naphtha, Petroleum Solvents
(in Short Tons) in Puget Sound
Shipping
Port or
Destination
Total
Coastal
Internal
Tacoma
Internal
Seattle
Coastal
Internal
Anacortes
Coastal
Bellingham
Internal
Receipts
1973
22,277
9,431
9,431
22,277
0
0
0
1974
39,380
6,427
5,702
19,210
0
20,170
725
Shipments
1973
1,540
9,431
0
1,540
0
0
9,431
1974
28,578
6,427
0
330
725
28,248
5,702
Source: (28, 29)
68
-------
Table 34
Waterborne Transport of Asphalt, Tar and Pitches
(in Short Tons) in Puget Sound
Shipping
Port or
Destination
Total
Coastal
Internal
Local
Tacoma
Coastal
Seattle
Coastal
Internal
Local
Anacortes
Coa.stal
Bel 1 i ngham
Internal
Receipts
1973
219,152
326
4,775
3,405
215,747
0
4,775
0
326
1974
162,799
0
0
0
162,799
0
0
0
0
Shipments
1973
11,454
326
-
0
11,454
326
-
0
0
1974
8,357
0
-
0
8,357
0
-
0
0
Source: (29, 29)
69
-------
that enters or leaves Puget Sound. As often as possible, specific states
are named as shipping ports or destinations of the refined products. Move-
ment of crude within Puget Sound is indicated under "Internal". "Local"
transport is within the confines of an individual harbor or port and has
been arbitrarily designated as a receipt (a "-" appears under shipments).
The relationship between the eight categories employed by the Army
Corps of Engineers (which publishes these data) and the actual products
produced by the refineries is:
• Gasoline: includes all grades of motor gasoline and a small
percentage of aviation gasoline used by small piston planes.
* Jet Fuel: same as refinery products.
• Kerosene: same as refinery products.
• Distillate Fuel Oil: includes fuel oils #1, #2, #3, and #4,
but is predominantly #2 diesel fuel oils with some #4 heating
oil. Also may include some stove oil and kerosenes.
* Residual Fuel Oil: includes fuel oils #5 and #6, but mostly
#6 Bunker "C" fuel oils.
• Lubricating Oils and Greases: same as refinery products.
• Naphtha, Petroleum Solvents: includes some straight run naphtha,
kerosenes, stove oil made into commercial solvents.
• Asphalt, Tar and Pitches: same as refinery products.
Most of the products refined by the Puget Sound refineries that are
transported by marine vessels are shipped coastwise to other states, mainly
California. Kerosene, which comprises about four percent of the marine-
transported petroleum products is the one notable exception. Most of the
kerosene is shipped to foreign countries. Consideration of the total water-
borne transport of refined products yields similar results. For each of
the products, most of the marine traffic moves to or from other states,
except for kerosene which is predominantly received from and delivered to,
foreign countries (Tables 35 and 36).
4. Chemical Composition and Characteristics of Refined Products
The compounds present in refined products are similar to those found
in crude oils with the addition of the olefin class of hydrocarbons. Ole-
fins are formed in refinery processes involving the cracking of the feed-
stock. Olefins are utilized as feedstock in alkylation and polymerization
processes to yield high octane blending components for motor gasoline
and some jet fuel. These compounds are partially unsaturated due to the
presence of at least one double bond, and are more reactive than paraffin
and naphthene hydrocarbons, but not as reactive for substitution as aro-
matics. Table 37 shows some of the predominant olefin hydrocarbons. Re-
fined products also contain a number of sulfur, nitrogen and oxygen-con-
taining compounds, along with various product additives designed to make
the product perform more efficiently.
70
-------
Table 35
Percentage of Waterborne Transport of Petroleum
Products in 1973 on Puget Sound According to Source or Destination
Petroleum Products
Motor Gasoline
Jet Fuel
Kerosene
Distillate Fuel Oil
Residual Fuel Oil
Lubricating Oil and Greases
Naphtha, Petroleum Solvents
Asphalt, Tar and Pitches
Foreign
1
0
79
2
5
1
0
0
Coastal
54
51
20
61
59
99
72
98
Internal
43
28
-------
Table 36
Percentage of Waterborne Transport of Petroleum
Products in 1974 on Puget Sound According to Source or Destination
Petroleum Products Foreign Coastal Internal Local
Motor Gasoline 2 69 26 3
Jet Fuel 0 34 22 44
Kerosene 77 20 30
Distillate Fuel Oil 1 60 34 5
Residual Fuel Oil 8 68 18 6
Lubricating Oil and Greases 3 97 00
Naphtha, Petroleum Solvents 0 92 80
Asphalt, Tar and Pitches 0 100 0 0
72
-------
Table 37
Some Typical Olefinic Hydrocarbon Compounds
--J
CO
Name
Ethylene
Propene
Butenes
1-Butene (ethylethylene)
2-Butene (cis and trans mixture)
2-Methylpropene (isobutene)
Pentenes
1-Pentene
2-Pentene (cw and trans mixture)
2-Methyl-l-butene
3-Methyl-l-butene
2-Methyl-2-butene
1-Hexene
1-Heptene
1-Octene
1-Nonene
1-Decene
1-Undecene
1-Dodecene
1-Tridecene
1-Tetradecene
1-Hexadecene (cetene)
1-Octadecene
Name
Propadiene (allene) GH.
1,3-Butadiene (erythrene) GH8
1,3-Pentadiene (piperylene) GH8
2-Methyl-l,3-butadiene GH8
(isoprene)
2,3-Dirnethyl-l ,3-butadiene GHM
(diisopropenyl)
l.S-Hexadiene (diallyl) GHio
2-4-Dimethyl-l i3-pentadiene GHi2
2,5-Dimethyl-l,5-hexadiene GHu
2,6-Dimethyl-l,5-heptadiene GHi«
Melting Point
Formula (°F.)
GH, CHZ=CH2 -272.9
CaH. CH2=CH— CHa -301.4
GH8 CH^CH— CHs— CHs -202
GHe CHa— CH=CH— CHa -198.6
GHa CH2=C(CH3)— CH3 -232.6
OsHio CHs^ CH — ( CHg) 2 — CHa
GHU CHs— CH=CH— GH6 -218.2
GHu, CH2=C(CH3)— CHs— CHa
GHM CH2= CH— CH (CH3) —CH3 - 21 1
C5HM CHs— C(CHa)=CH— CH3 -191.2
GH^ CH2=CH— (CH2)a— CH3
C,H14 CHa=CH— (CH2)4— CHa -182.2
C8H,8 CHa=CH— (CH^s— CH3
CoHM CH2=CH— (CH,,)^— CHa
CwHa, CH2=CH— (CH*),— CH3
CiiHa CHa== CH — ( CHs) tf — CHs
GsHsM CH2=CH— (CHz)o— CH3 -24.7
CMH» CH2=CH— (CH2),<^-CH3
CuHa, CH2=CH— (CH2)«— CH3 10.4
GeH^ CH2=CH— (CH^js— CHs 39.2
GsHse CH2=CH— (CH2)1S— CH3 64.4
Table 6. Diolefin Hydrocarbons.
(°c.)
-169.4
-185^
-130
-127
-140.7
-139
-135
-124
-119
-31.5
-12
4
18
B. P. at 760 mm.
(°F.)
-154.8
-53.9
19.9
32-^7.4
20.1
86.2
97.5
87.8
68.2
101.1
146.1
199.4
253.4
294.8
341.6
370.4
415.4
450.9
474.8
525.2
593.6
Melting Point
Formula
CH2=C=CH2
CH2=CH— CH=CH2
CH2=CH— CH=CH— CHa
CH3=C(CH3)— CH=CH2
CH2=C (CHa) — C (CHs) =CH2
CH2=CH— CH*— CH*— CH=CH2
CH2=C(CH3)— CH=CCCH3)— CH,
CH2=C(CH3)— CH.— CH.— C(CH3) =CH2
CH2=C(CH3)— CH.— CHr-CH=C(CH3)— CH
(°F.)
-213
-232.2
-104.8
-221.8
s
(°C.)
-136.1
-146.8
-76
-141
(°C.)
-103.8
-47.7
-6.7
0-3
-6.6
30.1
36.4
31
20.1
38.4
63.4
93
123
146
172
188
213
232.7
246
274
312
Sp. Gr. at °C.
0.566 (-102°)
0.610 (-47°)
0.617 (0°)
0.628 (1.7°)
0.627 (-6.6°)
0.642 (20°)
0.651 (20°)
0.650 (20°)
0.632 (15°)
0.662 (20°)
0.679 (20°)
0.698 (20°)
0.717 (20°)
0.730 (20°)
0.763 (0°)
0.763 (20°)
0.762 (15°)
0.798 (20°)
0.775 (20°)
0.784 (20°)
0.791 (20°)
B. P. at 760 mm. Sp. Gr.
(°F.)
-29.7
23
109.4
93.2
156.4
140
199.4
235.4
285.8
(°C.) at 20° C.
-34.3
-5 0.610
43 0.680
34 0.681
69.1 0.726
60 0.688
93 0.737
113 0.740
141 0.765
Source: (18)
Fvam CHEMICAL REFINING OF PETROLEUM
by Vladimir Kalichevsky c. 1942 by
Li-tton Educational Publishing, Inc.
Reprinted by permission of Van Nostrand
Reinhold Company
-------
Liquefied Petroleum Gases (LPG). Liquefied petroleum gases
are composed of those readily liquefiable hydrocarbon compounds
which are produced in the course of refining crude oil. There
are many important uses of these liquefied gases including:
commercial, domestic and industrial fuels; raw materials for
synthetic gasoline production; and petrochemical plant feedstock.
There are four basic types of'liquefied petroleum gases which
are covered by the American Society for Testing and Materials
(ASTM) specifications: commercial propane; butane; propane-
butane mixtures; and special-duty propane. Commercial propane
is preferred for domestic, commercial and industrial use in
areas where low temperatures are common. This type of LPG has
a very high volatile content. Commercial butane has a lower
volatility and is used by industrial and commercial users in
areas where low temperatures are not a serious problem. The
propane-butane mixtures provide an intermediate volatility.
Special-duty propane fuel is specifically tailored to meet the
qualifications of the proposed function. Table 38 indicates
the ASTM specifications for liquefied petroleum gases. The
hydrocarbon content of these liquefied gases are C3 and C^
hydrocarbons and are virtually 100 percent paraffinic. The
volatility of these liquefied gases is very high when compared
to the other refined products.
Motor Gasoline. Gasoline is composed of a mixture of paraffinic,
naphthenic, olefinic, and aromatic hydrocarbons which are gener-
ally distilled from crude oils at temperatures, ranging up to
300-350°F. The exact composition will vary within the specifica-
tion limits for the individual product, and will depend on the
blending components utilized to yield the product. Motor gaso-
line may be a blend of straight run gasoline, reformed gasoline,
polymerized gasoline, alkylation gasoline, hydrogenated gasoline,
and cracked gasoline fractions. Blending is important because
a fraction from a single operation usually cannot meet commercial
specifications. Many of these fractions are produced by pro-
cesses designed to upgrade the octane rating of the final product.
Examples of the composition of two typical blending components
are shown in Table 39.
The hydrocrackate fraction is used for blending both jet fuel
and motor gasoline, and the table indicates the relative yields
and properties of both products when refinery operations are
emphasizing one fuel over the other. This also provides a good
indication of the fluctuation of the hydrocarbon composition of
products resulting from variations in the refinery process opera-
tions. Straight run gasoline in general is composed of 50 per-
cent paraffins, 40 percent naphthenes, and 10 percent aromatics.
The final composition of motor gasolines varies within the specifi-
cations for the particular grade of gasoline and varies with the
amounts and types of additives utilized. Typically though,
motor gasoline contains C5-C10 compounds which are approximately
35-50 percent paraffins, 25-45 percent naphthenes, and 10-35
74
-------
Table 38
ASTM Specifications for Liquefied Petroleum Gas
Product Designation
Commercial
Propane
Vapor pressure at 100°F (37.8°C), max, psig
kPa
Volatile residue:
evaporated temperature, 95 %, max, °F
"C
or
butane and heavier, max, %
pentane and heavier, max, %
Propylene content, max, %
Residual matter:
residue on evaporation 100 ml, max, ml
oil stain observation
Relative density (specific gravity) at 60/
60°F (15.6/15.6°C)
Corrosion, copper, strip, max
Sulfur, grains/100 ft9 max at 60°F and 14.92
psia mg/m' max at I5.6°C and 101 kPa
Hydrogen sulfide content
Moisture content
Free water content
208
1430
-37
-38.3
2.5
0.05
passc
d
No. 1
15
343
pass'
Commercial
Butane
70
485
36
2.2
2.0
0.05
pass'
a
No. 1
15
343
none*
Commercial
PB Mixtures
b
36
2.2
2.0
0.05
pass"
d
No. 1
15
343
none*
ASTM Test
Special-Duty Methods
Propane" (see
Section 2)
208
1430
-37
-38.3
2.5
5.0
0.05
pass"
No. 1
10
229
pass'
pass'
D 1267 or
D2598
D 1837
D2163
D2163
D2163
D2158
D2158
D 1657 or
D2598
D 1838
D2784
D2420
• Equivalent to Propane HD-S of GPA Publication 2140.
* The permissible vapor pressures of products classified as PB mixtures must not exceed 200 psig (1380 kPa) and
additionally must not exceed that calculated from the following relationship between the observed vapor pressure and the
observed specific gravity:
Vapor pressure, max = 1167 - 1880 (sp gr 60/60°F) or 1167 - 1880 (density at 15°C)
A specific mixture shall be designated by the vapor pressure at 100°F in pounds per square inch gage. To comply with the
designation, the vapor pressure of the mixture shall be within +0 to —10 psi of the vapor pressure specified.
' An acceptable product shall not yield a persistent oil ring when 0.3 ml of solvent residue mixture is added to a filter
paper, in 0.1-ml increments and examined in daylight after 2 min as described in Method D 2158.
" Although not a specific requirement, the specific gravity must be determined for other purposes and should be
reported. Additionally, the specific gravity of PB mixture is needed to establish the permissible maximum vapor pressure
(see Footnote b).
' An acceptable product shall not show a distinct coloration.
' Use one of the alternate methods for moisture content as described in the Propane Dryness Test, Cobalt Bromide
Method, or Dew Point Method of GPA Publication 2140.
' The presence or absence of water shall be determined by visual inspection of the samples on which the gravity is
determined.
Source: (11)
Reprinted by permission of the American
Society for Testing and Materials, 1977
75
-------
Table 39
General Characteristics of Reformate and Hydrocrackate,
Two Gasoline Blending Components,
Produced at the ARCO Cherry Point Refinery
Reformate
Gravity, °API
Distillation, D-1160, °F.
Ibp
10
50
90
Ep
Sulfur, wt %
Nitrogen, ppm
Hydrocarbon type, wt %
Paraffins
Olefins
Naphthenes
Aromatics
Heterocyclics
24.3
556
680
773
870
925
0.95
1,780
17.7
5.4
28.0
35.5
13.4
Hydrocrackate
Typical
Dry gas, scf/bbl feed
Liquid products, vol % feed
nC<
CS-C*
C7-3150 F.
Jet fuel
Total C»+
Hydrogen consumption
chemical scf/bbl feed
Product properties
Cr-315° F.
Gravity, "API
Hydrocarbon type, vol %
Paraffins
Naphthenes
Aromatics
Octane, F-l + 3 ml TEL
JET FUEL
Gravity, °API ...
Aromatics, vol %
Smoke point, mm
Sulfur, ppm
*Jet-fuel yield changed by factor of almost
results
Operttiinl
62
5.6
2.3
18.9
39.0
56.0
.... 121.8
.... 1,820
57.5
39.0
56.5
4.5
80.5
45.3
11.5
25
<5
two. Typical results, pilot-plant
Operatiin2
99
8.8
4.3
26.2
55.2
30.0
124.5
2,080
56.1
360
579
6.1
81.2
467
7.5
28
<5
simulation.
Reprinted with permission from:
Aalund, Leo, 1972. "Cherry Point Refinery",
Oil and Gas Journal3 Vol. 70, No. 4
65-72.
76
Source: (1)
-------
percent aromatics and 5-15 percent olefins. A very large percent
of these hydrocarbons are highly volatile and somewhat soluble
in water.
c. Jet Fuel. Jet fuel or aviation turbine fuel is composed of straight
run naphtha and kerosene, along with some cracked stock. There
are four basic grades of jet fuel: Jet A, Jet A-l, JP-4, and JP-5.
The latter two grades are primarily for military use. Additives
may be present in these fuels in accordance with composition
specifications. These include electrical conductivity additives,
antioxidants, metal deactivators, corrosion inhibitors, fuel system
icing inhibitors and other special purpose additives (Table 40).
Generally jet fuels have boiling points ranging from approximately
400-570°F and contain hydrocarbons mainly in the Cia-C12 molecular
weight range. Jet fuels contain all four classes of hydrocarbons,
although very few olefins. Typically jet fuels are composed of
about 35 percent paraffins, 50 percent naphthenes, and 15 percent
aromatics. In general, paraffins are more desirable than other
hydrocarbon compounds because of the characteristic of cleaner
combustion. Naphthenes are the next most desirable hydrocarbons
for jet fuels in terms of combustion characteristics. Olefins
have good combustion characteristics too, but their gum stability
is poor, limiting their usefulness in aircraft turbine fuels.
Aromatic hydrocarbons have the least desirable combustion character-
istics, tending to be smoky and leave a carbon deposit. According
to the ASTM specifications (D 1655-75), it is desirable to have
no more than 20 percent aromatics in Jet A and Jet A-l fuel (Table
41). Military specifications for JP-4 and JP-5 jet fuels allow
up to 25 percent aromatics (Table 42). Olefin hydrocarbon content
usually is only one percent, although it can be as high as three
percent of a jet fuel.
d. Kerosene. Kerosene is employed primarily for heating and lighting
purposes. Its average boiling point is above that of gasoline and
ranges from 300-600°F. The burning quality of kerosene is adversely
affected by aromatic hydrocarbons, so it is desirable to keep the
percentage of aromatics low. The typical hydrocarbon composition
of these C10-C12 compounds is 40 percent paraffins, 45 percent
naphthenes and 15 percent aromatics. In general though, the demand
for kerosene and similar products has not kept pace with the amount
of kerosene stock produced. Therefore, much of the stock is con-
verted into petroleum solvents or processed through cracking opera-
tions into lower-boiling hydrocarbons suitable for motor gasoline
or jet fuel blending stocks.
e. Fuel Oils. Fuel oils include both distillates and residual fractions
and serve a wide variety of purposes. The specifications vary with
the type of fuel oil and the expected performance desired. In
general, the volatility decreases and the viscosity increases when
comparing fuel oils #1 through #6. Additives found in fuel oils
77
-------
Table 40
Examples of Specific Antioxidant Additives Allowed by
Military Specifications in JP-4 and JP-5 Jet Fuel
Antioxidants. The following active inhibitors may be blended
separately or in combination into the fuel ±n total concentration not in
excess of 8.4 pounds of inhibitor (not including weight of solvent) per
1,000 barrels of fuel (.9.1 g/100 gal (US), 24 nig/liter or 109 rag/gal (UK))
in order to prevent the formation of gum:
a. N,N' d11sopropyl-p_-phenyl enedi ami ne
b. N ,N' -d1 -sec_-butyl -p_-phenyl enedi ami ne
c. 2,6-d1-tert-butyl-4-methylphenol
d« 6-tert-butyl-2,4-dimethylphenol
e. 2,6ni1-tert-butyl phenol
f. 75 percent min-2,6-di-tert-butylphenol
25 percent max tert-butylphenols and tri-tert-butylphenols
g. 72 percent m1n 6-tert-butyl-2,4-d1methypheno1
28 percent max tert-butyl-methylphenols and tert-butyl-dimethylphenol s
h. 55 percent min 6-tert-butyl-2,4-dimethylphenol
45 percent max mixture of tert-butylphenols and di-tert-butylphenol s
1. 65 percent N,N'-di-sec-butyl-p-phenylenedi ami ne
35 percent N»N'-d1-sec-butyl-o-phenylenediamine
j. 60 to 80 percent 2,6-dialkylphenols
20 to 40 percent mixture of 2,3,6-trialkylphenols and 2,4,6-trialkyl-
phenols
k. 35 percent min 2,6-di-tert-butyl-4-methylphenol
65 percent max mixture of methyl-, ethyl-, and dimethyl-tert-butylphenols
1. 60 percent min 2,4-di-tert-butylphenol
40 percent max mixture of tert-butylphenols
m. 30 percent min mixture of 2,3,6-trimethylphenol and 2,4,6,-trimethylphenol
70 percent max mixture of dimethyl phenols
n. 65 percent mixture of 2,4,5-triisopropylphenol and 2,4,6-triisopropylphenol
35 percent max mixture of other isopropylphenols and biphenols
Source: (30)
78
-------
Table 41
ASTM Specifications for Jet A and Jet A-l Fuels
Property
Jet A or Jel A-l
JetB
ASTM Test Method"
Acidity, total max, mg KOH/g
Aromatics, vol. max, %
Sulfur, Mercaptan,'' wt, max, %
Sulfur, total wt, max, %
Distillation temperature, °F(°C):
10% recovered, max. temp
20% recovered, max, temp
50% recovered, max, temp
90% recovered, max, temp
Final boiling point, max, °F (°C)
Distillation residue, max, %
Distillation loss, max, %
Flash point, min, °F(°C)
Gravity, max, "API (min, sp gr) at 60°F
Gravity, min, "API (max, sp gr) at 60°F
Vapor pressure, max, Ib
Freezing point, max, °C
Viscosity -30°F(-34.4°C) max. cSt
Net heat of combustion, min, Btu/ ID
O.I
20
0.003
0.3
400 (204.4)
report
report
572 (300)
1.5
1.5
100(37.8)
51(0.7753)
37 (0.8398)
-40" Jet A
-50aJetA-l
15
18.400"
20
0.003
0.3
290(143.3)
370(187.8)
470 (243.3)
1.5
1.5
57 (0.7507)
45(0.8017)
3
-50«
18.400-
D 974 or D 3242
D13I9
DI323orD 1219
DI266
D86
D 56 or D 3243
DI298
D1298
D323
D2386
D445
D 1405 or D 2382
Combustion properties: one of the following
requirements shall be met:
(/) Luminometer number, min or 45
(2) Smoke point, min or 25
(3) Smoke point, min 20
Naphthalenes, vol, max, % or 3
Corrosion, copper strip 2 h at 2I2°F(100°C) No. 1
min
Thermal stability: one of the following require-
ments shall be met:
(/) Filter pressure drop, max, in. Hg 3
Preheater deposit less than Code 3
(2) Filter pressure drop, max, mm Hg 25
Tube deposit less than Code 3
Existent gum, mg/100 ml, max 7
Water reaction:
Separation rating, max 2
Interface rating, max Ib
Additives
Electrical conductivity, pS/m *
45
25
20
No. 1
3
Code 3
25
Code 3
7
2
Ib
See 4.2
DI740
D1322
D 1322
DI840
DI30
D 1660'
D324I"
D38I
D 1094
DI094
D 2624 or D 3114
" The requirements herein are absolute and are not subject to correction for tolerance of the test methods. If multiple
determinations are made, average results shall be used.
'The test methods indicated in this table are referred to in Section 9.
'The mercaptan sulfur determination may be waived if the fuel is considered sweet by the doctor test described in 4.2 of
Specification D484, for Hydrocarbon Drycleaning Solvents.'
* Other freezing points may be agreed upon between supplier and purchaser.
' Use for Jets A and A-l the value calculated from Table 8 or Eqs 5, and 9 in Method D 1405. Use for Jet B the value
calculated from Table 6 or Eqs 5, and 7 in Method D 1405. Method D 2382 may be used as an alternative. In case of dispute,
Method D 2382 must be used.
'Thermal stability test shall be conducted for 5 h at 300°F (I48.9°C) preheater temperature 400°F (204.4°C) filter
temperature, and at a flow rate of 6 Ib/h.
' Thermal stability test (JFTOT) shall be conducted for 2.5 h at a control temperature of 260°C but if the requirements of
Table I are not met. the test may be conducted for 2.5 h at a control temperature of 245°C. Results at both test temperatures
shall be reported in this case. Tube deposits shall always be reported by the Visual Method: a rating by the Tube Deposit
Rating (TDK) optical density method is desirable but not mandatory.
* A limit of 50 to 300 conductivity units (pS/m) applies only when an electrical conductivity additive is used and under the
condition at point of use:
I pS/m = I x I0-"fl ' m '
Source: (11)
Reprinted by permission of the American
Society for Testing and Materials., 1977
79
-------
Table 42
Military Specifications for GP-4 and JP-5 Jet Fuels
Requirements
Color , Saybolt
Total acid number, mg KOH/g, max
Aromatics, vol percent, max
Olefins, vol perceat max
Mercaptan sulfur, weight percent, max 2)
Sulfur, total weight percent, max
Distillation temperature, deg C,
(D 2887 limits in parentheses)
Initial boiling point
10 percent recovered, max temp
20 percent recovered, max temp
50 percent recovered, max temp
90 percent recovered, max temp
End point, max temp
Residue, vol percent, max (for D 86)
Loss, vol percent, max (for D 86)
Explosiveness percent, max
Flash point, deg C (deg F) , min
Density, kg/m3, min ( API, max) at 15°C
Density, kg/m3, max O°API, min) at 15°C
Vapor pressure, 37.8 C (100 F) , kPa (psi) , min
Vapor pressure, 37.8 C (100°F), kPa (psi), max
Freezing point, deg C (deg F) , max
Viscosity, at -20 C, max, mm2/s(centistokes)
leating value, Aniline-gravity product,
min, or Net heat of combustion,
MJ/jcg (Btu/lb) min
Hydrogen content, wt percent, min
or Smoke point, mm, min
Fuel
Grade JP-4
I/
0.015
25.0
5.0
0.001
0.40
11
11
145 (130)
190 (185)
245 (250)
270 (320)
1.5
1.5
—
—
751 (57.0)
-802 (45.0)
14 (2.0)
21 (3.0)
-58 (-72)
5,250
42.8 (18,400)
13.6
20.0
Grade JP-5
I/
0.015
25.0
5.0
0.001
0.40
I/
205 (185)
I/
i/
i/
290 (320)
1.5
1.5
50
60 (140)
788 (48.0)
845 (36.0)
—
—
-46 (-51)
8.5 (8.5)
4,500 .
42.6 (18,300)
13.5
19.0
Test Method
ASTM Standards
D 156
D 3242
D 1319
D 1319
D 1323
D 1266, D 1552, D 2622
D 86 3/ or
D 2887
4/
D 93
D 1298
D 1298
D 323 or D 2551
D 323 or D 2551
D 2386
D 445
D 1405
D 240, D 2382
or D 3338 5/
D 1018 or 3343 6/
D 1322
-------
Table 42 (cont.)
00
Requirements
Copper strip corrosion, 2 hr at 100 C
(212°F) max
Thermal stability:
Change in pressure drop , mm of Hg . , max
Preheater deposit code, less than
Existent gum, mg/100 ml, max
Particulate matter, mg/liter, max
Filtration time, minutes, max
Water reaction
Interface rating, max
Separation rating, max
Water separation index, modified, min
Fuel system icing inhibitor, vol
percent min
Fuel system icing inhibitor, vol
percent max
I/ To be reported - not limited.
Fuel
Grade JP-4
Ib
25
3
7.0
1.0
15
Ib
1
70
0.10
0.15
Grade JP-5
Ib
25
3
7.0
1.0
—
—
—
85
0.10
0.15
\
Test Method
ASTM Standards
D 130
D 3241 T-l
D 381
D 2276 8/
I/
D 1094
D 2550
'!/
I/
2/ The mercaptan sulfur determination may be waived at the option of the inspector if the fuel
is "doctor sweet" when tested in accordance with the doctor test of ASTM D 484.
_3_/ A condenser temperature of 32 to 40 F (0 to 4°C) shall be "used for the distillation of grade
JP-5. For JP-4, use group 3 test conditions. Distillation shall not be corrected to 760 mm pressure.
4/ Test shall be performed in accordance with method 1151 Federal Standard 791.
3/ ASTM D 3338, for calculating the heat of combustion, is only allowed for use with JP-4 fuel.
~ When the fuel distillation test is also performed using ASTM D 2887, the average distillation
temperature, for use in ASTM D 3338, shall be calculated as follows:
V =
10% + 50% + 95%
-------
Table 42 (cont.)
j6/ ASTM D 3343, for calculating the hydrogen content of the fuel, is only allowed for
use with JP-4 fuel. When the fuel distillation test is also performed using ASTM D 2887,
the average distillation temperature for use in D 3343 shall be calculated as follows:
10% +'50% + 95%
3
]_/ See 4.7.1.1 for ASTM D 3241 test conditions and test limits.
8/ A minimum sample size of one gallon shall be filtered. Filtration time will be determined
in accordance with the procedure of Appendix A. The procedure in Appendix A may also be
used for the determination of particulate matter as an alternate to ASTM D 2276.
9/ Test shall be performed with method 5327 of Federal Standard 791.
Source: (30)
oo
no
-------
vary, but may include metal deactivates, stabilizers, dispersants,
cetane improvers, flow improvers, and conductivity improvers.
The distillate fuel oils, #1 (rare), #2, #3 (rare), and #4, are a
middle fraction of crude petroleum with some mixture of catalytic
or thermally cracked components. Chemically these fuel oils are
composed almost entirely of hydrocarbons within the range of C. -
C25 with the greatest abundance at C,5-C16. Generally these
fuels contain about 30 percent paraffins, 45 percent naphthenes
and 25 percent aromatics. When blended, there are fewer naphthenes
and paraffins and more olefins and aromatics. In some diesel fuel
oils (#2), the aromatic content may be as high as 40 percent. In
general, however, the aromatic content does not vary greatly from
one distillate fuel oil to another.
For three major grades of diesel fuel oil, #1-D, #2-D, and #4-D,
the ASTM specifications are less concerned with hydrocarbon content;
instead, the volatility is a more important factor in the perform-
ance of the fuel. The fuel volatility requirements vary with en-
gine design, size, nature of speed and load variations and on
starting conditions. Diesel fuel oil #1-D is made from kerosene
and intermediate distillates to provide the desired high amount
of volatiles. This fuel is used widely by buses and trucks.
Grade #2-D is made from distillate gas oils and has a correspond-
ing lower quantity of volatiles. The lower distillates are blended
with some residual fractions to yield grade #4-D diesel fuel, which
is highly viscous and much lower in volatiles.
Residual fuel oils #5 and #6 are high viscosity oils and often
require preheating to permit pumping. Most of the contaminants
that are in crude oils which are not removed during the refining
process can be found in these heavy oils. Nickel, vanadium, sulfur
and heavy metals are much more abundant than in other products.
Specific percentages will depend on the nature of the crude oils
and the processes involved. Additional refining may be necessary
to accommodate areas with air quality problems, particularly re-
garding sulfur content. Chemically the majority of hydrocarbon
compounds are above C for #5 fuel oil and above C30 for #6 fuel
oil (Bunker C). Typicllly, residual fuel oils contain approximately
15 percent paraffins, 45 percent naphthenes, 25 percent aromatics,
and 15 percent polar non-hydrocarbon compounds. These non-hydro-
carbon nitrogen, oxygen and sulfur-containing compounds are very
easily dissolved in seawater because of their polarity. The rate
of solution will depend on the gravity, viscosity, pour point,
surface tension and other factors. In general, the specifica-
tions for fuel oils of all types are not concerned with hydro-
carbon content beyond the percentage of volatiles. Viscosity,
pour point, and sulfur content are more important factors affecting
the functioning of the fuel and these are more closely examined
when fuel oils are analyzed.
83
-------
f. Lubricating Oils and Greases. Lubricating oils serve a variety
of different purposes, including lubricating machinery. Lubricat-
ing oil stock is usually considered to include distillates obtain-
able from crude oil after the gas oil fractions have been expelled,
as well as some of the residual fractions from light crude oils.
These residuals are particularly common in the manufacture of
motor and airplane engine oils. When a heavy asp.haltic crude is
refined, distillates provide the stock for lubricating oils.
Lubricating oils which are rendered-semi-solid or solid by addi-
tion of soaps and similar materials are classified as greases.
Thus the hydrocarbon composition of lubricating oils and greases
is highly variable, depending on which refined fractions are in-
volved, but generally lies within the range C -C2S. No specifi-
cations regarding the quantities of specific classes of hydro-
carbons are made for these products. Some estimations of hydro-
carbon content indicate 20-40 percent paraffins, 30-55 percent
naphthenes, and 15-45 percent aromatics.
g. Naphtha and Petroleum Solvents. Certain petroleum fractions boil-
ing in the range of 200-600T, which includes straight run naphtha
and kerosene, are utilized as commercial solvents. These petroleum
fractions are used in the manufacture of cleaners' naphtha,
Stoddard's solvent, rubber solvent, lacquer, paint thinner, and
other refined products. Generally, the range of molecular weights
is C10-c12, the same as kerosene. In contrast to a desirable
kerosene, such solvents often contain aromatic hydrocarbons to
enhance their solubility characteristics. Frequently, these
petroleum solvents are made from aromatic material extracted
from kerosene stock during the course of refining. The hydrocarbon
content of these different types of solvents is variable but gen-
erally ranges from 20-35 percent paraffins, 30-45 percent naphthenes,
and 20-50 percent aromatics. These solvents also have a relatively
high portion of volatile compounds.
h. Asphalt and Coke. The term "asphalt" in the petroleum industry
applies to the semi-solid or solid residuum left after the volatile
fractions have been removed. If distillation is carried to comple-
tion, with sufficient time, the residue becomes coke. Petroleum
asphalt is used in the manufacture of paving asphalt, for impregnat-
ing roofing paper, and for other similar purposes. Coke is often
used for industrial processing in making steel. The hydrocarbon
content of asphalt depends on the type of crude that is processed
initially. The majority of compounds have a molecular size of C^
or higher. Asphalt also contains very few volatiles, due to the
repeated distillation of lighter products. Coke is essentially
solid carbon, with some hydrogen and other impurities. It also
has virtaully no volatile compounds.
i. Relative Toxicities of Refined Products. Although non-hydrocarbon
substances occur in petroleum products, the predominant constituents
are hydrocarbons and these compounds are responsible for virtually
all the biological effects attributed to refined products. As
84
-------
with crude oils, the relative toxicity of the classes of hydro-
carbons increases from paraffins to naphthenes to olefins to
aromatics. Table 43 summarizes the relative percentages of hydro-
carbon compounds found in refined products. The water solubility
and the presence of volatiles also influence the toxicity of pe-
troleum products. In general the more soluble and volatile a
particular hydrocarbon is, within a given chemical class, the
greater the toxicity of the compound. A number of researchers
have provided evidence that the lower boiling, more soluble
aromatic hydrocarbons are consistently the primary cause of the
mortality of marine organisms exposed to refined products. Other
aromatic compounds, and naphthenic and paraffinic hydrocarbons
also contribute to the toxic effects of petroleum products.
Table 44 indicates some of the aromatic compounds isolated after
exposing kerosene to seawater. Such detailed breakdowns of
hydrocarbons are rarely performed, and even this particular one
is incomplete. In addition these specific compounds are not
necessarily present in all kerosenes. The exact composition de-
pends on the types and composition of the crude oil feedstock, the
refinery processes employed, and the components used in product
blending. This is true for all the petroleum products. The large
number of individual hydrocarbon compounds precludes the identifica-
tion and consideration of each one separately. Further assessments
of the toxicity of particular products should concentrate on the
identification of aromatic compounds present, particularly those
with high volatility and solubility.
In general the content of low molecular weight aromatics (which are
usually more volatile and soluble) in refined products is greater
than in crude oils because refining may include thermal and cata-
lytic cracking in addition to distillation. Cracking yields a
blending component which has a highervaromatic content than the
original feedstock. Because of this higher aromatic content,
petroleum products are often more toxic than many crude oils. Light
and middle distillates almost always are more toxic to marine life
than most crude oils. Table 45 indicates the levels of aromatics
capable to causing harmful effects to marine organisms and the
quantities of #2 fuel oil and crude oil which contain these toxic
levels of aromatics. It is evident that even fuel oils are more
toxic than crude oils. However, volatiles in some crude oils may
be 20-30 percent of their volumes, whereas often only one percent
of Bunker C fuel oil contains volatile hydrocarbons; thus the
crude oils would tend to have a greater direct toxicity.
Petroleum products themselves have different relative toxicities.
Liquefied petroleum gases, gasoline, jet fuel, and kerosene are
often composed totally of volatile hydrocarbons which evaporate
rapidly upon exposure to seawater. More than 75 percent of the
hydrocarbons in distillate fuels frequently will evaporate within
a few days. Heavier products, including asphalt and Bunker C
fuel oil, often contain less than 10 percent volatile hydrocarbons
85
-------
Table 43
Relative Percentages of Hydrocarbon Compounds in
Petroleum Products Transported in Puget Sound
Petroleum Product
LPG
Motor Gasoline
Jet Fuel
Kerosene
Distillate Fuel Oils
Residual Fuel Oils§
Naphtha, Petroleum Solvents
Lubricating Oils & Greases
Asphalt
Paraffins
" 100
40-50
35
40
30
15
20-35
20-40
—
Naphthenes
0
30-40
50
45
45
45
30-45
30-55
—
Aromatics
0
10-35
15
15
25-40
25
20-50
15-45
—
§ includes 15%non-hydrocarbon compounds containing oxygen, nitrogen or
sulfur.
NOTE: Olefins are often not measured, although they are present in most
products to some degree.
86
-------
Table 44
Some Soluble Aromatic Compounds Isolated from Kerosene
COMPOUND
BEN7ENFS
1-METHYL-2-ETHYL BENZENE
l-METHYL-'l-ETHYL BENZENE
1:3:5-TRIMETHYL BENZENE
1-METHYL-2-ETHYL BENZENE
l:2:
-------
Table 44 (cont.)
NAPTHALENES
NAPTHALENE
2-HETHYL NAPTHALENE
1-METHYL NAPTHALENE
B1PHENYL
1:2-DIMETHYL NAPTHALENE
1-.6-DIHETHYL NAPTHALENE
2i6-DIHETHYL NAPTHALENE
TOTAL AROMATICS
88
-------
Table 45
Summary of Aromatic Toxi'city Data
CLASS OF ORGANISM
FLORA
GASTROPODS
(SNAILS, etc.)
FINFISH
BIVALVES
(OYSTERS, CLAMS, etc.)
PELAGIC
CRUSTACEANS
BENTHIC CRUSTACEANS
(LOBSTERS, CRABS, etc.)
OTHER BENTHIC
INVERTEBRATES
(WORMS, etc.)
LARVAE
(ALL SPECIES)
ESTIMATED CON-
CENTRATION (ppm)
OF SOLUBLE ARO-
MATICS CAUSING
TOXICITY
10-100
10-100
5-50
5-50
1-10
1-10
1-10
0.1-1.0
ESTIMATED AMOUNT (ppm)
OF PETROLEUM SUBSTANCES
CONTAINING EQUIVALENT
AMOUNT OF AROMATICS
#2 FUEL OIL
50-500
50-500
25-250
25-250
5-50
5-50
5-50
0.5-5
FRESH CRUDE
10*-105
10*-105
10*-105
lO^-lO5
103-10*
lOMO*
lOMO*
102-103
00
IO
Source: (14)
-------
which will be evaporated by weathering processes. Thus on the
basis of volatile hydrocarbon content alone, gasoline and other
light products will usually be more toxic than heavier products.
However, examination of the classes of hydrocarbon compounds
present is more important. Liquefied petroleum gas is essentially
100 percent paraffinic. This high content of volatile paraffins
may be toxic to marine organisms. However, other refined products,
containing aromatic compounds, have more soluble toxic hydrocarbons
and will have a longer period of exposure in the marine environ-
ment. Distillate fuel oils usually have the greatest average
aromatic content, followed by some motor gasolines and jet fuels.
Thus, on the basis of aromatic content, these products are prob-
ably the most toxic. Closer examination provides evidence that
#2 fuel oil has a greater amount of volatile, soluble aromatic
hydrocarbons than the other petroleum products. Ranking the
remaining products is difficult due to the interplay of the main
factors determining toxicity; aromatic content, solubility and
volatility.
Another significant factor controlling the lethal effects of
refined products is the effect of weathering. Evaporation acts
fairly rapidly on the volatile fractions of a spilled petroleum
product. The interactions of dissolution and evaporation will
determine how much exposure to toxic hydrocarbon compounds marine
organisms will have. For many of the products, particularly
the light distillate products, a large percentage of toxic com-
ponents are lost within two to four days after spillage.
Mortality rates from direct lethal toxicity are lessened as the
products are weathered. Still, as indicated previously in
Table 45, very low concentrations of soluble aromatic hydro-
carbons may cause lethal effects to marine organisms. Larval
stages appear to be considerably more sensitive than adults.
Concentration of soluble aromatics be|ow 0.1 ppm may be toxic
to certain marine larvae. In general, crustaceans and burrowing
animals are the most sensitive to refined products; fish and
bivalves are moderately sensitive, and gastropods and plants are
the least sensitive.
While #2 fuel oil has the greatest short-term effect on marine
life, causing high rates of direct mortality and sublethal effects,
#6 fuel oil, Bunker C, probably has the greatest long-term effect,
particularly regarding coating of organisms and changes in marine
habitats. Light aromatic hydrocarbons will be evaporated or
enter into solution fairly rapidly. The high molecular weight
aromatics are less soluble and less volatile and will remain
unchanged for a long period of time. Crude oils, particularly
heavy ones, also have long-term direct and indirect lethal effects.
In general, the coating and smothering of organisms by crude oil
and heavy products is a major cause of mortality only after the
toxic soluble aromatic hydrocarbons have evaporated. The organ-
isms most susceptible to coating are those organisms unable to
leave the area in which the oil is spilled. Heavy products like
Bunker C may also drastically alter the marine habitat once the
90
-------
oil is incorporated into the sediments. The amount of product
that gets into the sediments is a function of the particle size
distribution in the sediment, the strength of vertical mixing,
the water depth and, the extent to which the product has weathered.
Further assessment and characterization of the toxic components
of petroleum products in the future is necessary to better define
the particular compounds which occur in products and cause harm-
ful effects. These efforts should be directed primarily at
analyzing the aromatic hydrocarbons present in refined products,
particularly soluble naphthalene aromatic compounds. Attempts
at a complete tabulation of hydrocarbon compounds present in
individual petroleum products are difficult and may be comparative-
ly meaningless due to wide variations in product constituency.
Instead, characterizations should include information on the rela-
tive percentages of aromatics, percentages of volatiles and vola-
tile aromatics, and solubilities for benzene and naphthalene
aromatic hydrocarbons.
D. Refinery Processes
1. Introduction
The six refineries located on Puget Sound in Washington are very
representative of the diversity which can be found among petroleum refin-
eries, while concurrently they share numerous commonalities. The actual
process configuration of an individual refinery will depend on the range
and type of products desired and the sources and types of available crude
oils for feedstock. When these considerations have been made, a number of
different processes for treating the crude must be examined regarding their
functions and capabilities. Then a decision as to the refinery design can
be reached. Some of the major processes available for consideration are:
crude desalting, atmospheric distillation, vacuum fractionation, thermal
cracking, catalytic cracking, hydrocracking, polymerization, alkylation,
isomerization, catalytic reforming, hydrotreating and product blending.
A simplified refinery process diagram is shown in Figure 8.
2. General Process Description
a. Crude Desalting. When crude oil is taken from the ground it con-
tains much water and salts, along with the oil, which are detri-
mental to most refining processes. Removal of this salty water
is called crude desalting. Two basic methods of desalting are
available, one involving gravity separation and the other an
electrostatic field. In the first method chemical emulsifiers
which will remove the specific types of salt present are added
with the wash water. The mixture is heated while the emulsifier
separates the salty water from the crude oil. A settling tank
allows gravity separation of the crude and water, and the de-
salted crude is withdrawn from the upper portion of the tank.
The other major method utilizes an electrostatic field to separate
91
-------
Figure 8 Simplified Modern Refinery Process Flow Diagram
Refinery Fuel
Crude Oil
to
ro
RESIDUAL FUEL
AND ASPHALT
Reprinted with permission from:
Environmental Conservation; The Oil
and Gas Indus triesf 1971T.National
Petroleum Council,, Washington, D.C.
Vol. 2.
Source: (16)
-------
the crude and salty wash water, instead of gravity seoaration.
The influence of the high voltage field causes the dispersed
droplets to agglomerate, aiding separation. The contaminated
wash water is discharged into the wastewater stream and the
relatively clean, desalted crude is withdrawn to the fractiona-
tion facilities.
Crude Fractionation. The rest of the crude unit in a refinery
consists of fractionation and distillation apparatus. Fractiona-
tion separates the various fractions of the crude oil into several
specified classes, according to boiling point ranges. This separa-
tion is necessary to allow further treatment in the refinery to
produce the desired products. Atmospheric distillation and vacuum
fractionation are the two most common methods, and are often
employed in series. Atmospheric distillation involves heating
the crude up to around 650°F. As the various intermediate frac-
tions reach their boiling points, they tend to rise in the distilla-
tion tower. The lightest products (C5 and lighter) will rise to
the top of the tower. The rest of the distilled fractions; gaso-
line, kerosene, naphtha and diesel separate according to boiling
point ranges and are drawn off from the tower by sidestreams at
the appropriate height. The residual crude oil is removed from
the bottom of the tower. This heavy material serves as feedstock
for vacuum fractionation or flashing. Again heat is applied;
often the temperature in this unit is above 900°F. Separation
occurs under low pressure in the unit, yielding light and heavy
vacuum oil for catalytic cracking feedstock and a residuum
fraction. Some refineries use a barometric condenser to create
the reduced pressures in the vacuum unit, although surface con-
densers are more common, especially in large refineries. The
heavy residuum may receive a number of different treatments,
including delayed coking, catalytic cracking and deasphalting.
Often the deasphalting unit is found'Within the crude unit,
whereas the other treatments are major processes. Deasphalting
uses propane or butane to further separate the crude by extraction
and yields two streams: deasphalted oil and petroleum asphalt.
Cracking Processes. There are three types of cracking processes:
thermal cracking, catalytic cracking and hydrocracking. The
purpose of these processes is to take distillate fractions heavier
than naphtha and "crack" them, producing lighter distillates,
particularly gasoline and naphtha.
i. Thermal Cracking. This category includes visbreaking
and delayed coking as well as regular thermal cracking.
In each of these operations, heavy fractions from the
vacuum fractionation unit or the catalytic cracker are
broken down into lower molecular weight fractions utiliz-
ing heat, but no chemical catalyst. Typical conditions
found with thermal cracking operations are temperatures
of 900°-1100°F and pressures of 40-70 atm. This process
yields some lighter blending stocks, feedstock for other
cracking units and a very heavy residue used for bunker
93
-------
fuels and heavy fuel oils. Thermal cracking processes
are gradually being phased out as catalytic cracking
and hydrocracking gain predominance, largely for eco-
nomic and efficiency reasons.
ii. Catalytic Cracking. Catalytic cracking also breaks
heavy fractions, usually from the vacuum fractionator,
into lower molecular weight fractions. This is probably
the most important process in the production of high-
octane gasoline stocks. The use of a catalyst allows
cracking operations at lower pressures and temperatures
than thermal cracking processes. It also inhibits the
formation of undesirable polymerized products. Cata-
lytic crackers may be fluid catalytic cracking (FCC)
units or Thermofor catalytic cracking (TCC) units.
Fluid catalytic crackers utilize a finely powdered
catalyst which is handled as an aerated "fluid" and is
easily circulated by pressure differentials in the unit.
Thermofor catalytic crackers use the catalyst in the
form of small spheres - the bead catalyst. These small
beads are well suited for circulation by low air pressure,
which raises the regenerated catalyst to a hopper above
the reactor.
A catalytic cracking unit is composed of three sections -
cracking, regeneration and fractionation. Regenerated
catalyst is constantly being supplied to the cracking
reactor, while spent catalyst is being continually re-
moved to the regenerator. The hot spent catalyst con-
tains a deposit of coke which must be removed in order
to restore the activity of the catalyst. The coke is
burned off with air and the regenerated catalyst, pass-
ing out of the regenerator, is mixed with the oil feed
and returns to the reactor. The oil is cracked in the
reactor, the vapor passes upward, and then through a
fractionating column, where the desired fractions are
drawn off. With fluid catalytic crackers a portion of
the bottoms of the fractionating tower must be passed
through a settler to remove small amounts of fine catalyst.
This is not a problem with a Thermofor catalytic cracker.
The small catalyst beads are handled differently and
there is less tendency for catalyst entrainment. Operat-
ing conditions are also slightly different; the tempera-
tures in a fluid catalytic cracker are normally 1050°
to 1125°F, while they are only 840° to 920°F in a
Thermofor catalytic cracking unit.
iii. Hydrocracking. This process is basically the same as
catalytic cracking, except that it is performed in the
presence of hydrogen, at lower temperatures (400°-800°F)
and higher pressures. Hydrocracking offers a greater
flexibility, cleaner products and reduced formation of
olefins.
94
-------
d. Polymerization. Polymerization units are used to convert olefin
feedstocks (primarily propylene) into high octane rating polymer
units. The polymerization unit generally consists of a feed
treatment unit (applying heat and removing sulfides, mercaptans
and nitrogen compounds), a catalytic reactor, an acid removal
section and a gas stabilizer. The feedstock, rich in olefins, is
passed through the feed treatment unit and is brought up to re-
action temperature. It passes through the reactor at 300°-425°F
and goes to fractionating equipment. There it is first depro-
panized, then debutanized and the polymer product is drawn off
from the bottom of the fractionator. The catalyst employed is
usually phosphoric acid, although sulfuric acid is used in some
older units. The catalyst is recovered in the acid removal section
and regenerated for reuse in the reactor. Polymerization is
actually only a marginal process since the product octane rating
is not too much higher than other gasoline blending stocks. Thus,
there is a downward trend in employing this process in new
refineries.
e. Alkylation. Alkylation involves the reaction of an olefin
(propylene, butylene, amylene) and an isoparaffin (usually
isobutane) in the presence of a catalyst at controlled tempera-
tures and pressure to produce a high octane alkylate as a gaso-
line blending stock. Sulfuric acid is the most widely used
catalyst, although hydrofluoric acid is also used. The iso-
butane and olefin feedstock are mixed in the reactor which
contains strong sulfuric acid. An acid hydrocarbon emulsion is
formed, part of which is recycled to the reactor along with fresh
feedstock. The remaining emulsion flows into a settling chamber
where the acid separates out. Part of the acid is recycled and
the rest is discarded. The hydrocarbon product is washed with
caustic and water and fractionated. The fractionation yields
isobutane (for recycling), normal butane and alkylate. This
process may have increasing importance as the demand for low lead,
high octane gasoline increases.
f. Isomerization. This process is used to obtain higher octane motor
fuel by converting light gasoline stocks into their higher octane
isomers. The greatest application of this technique has been
in the conversion of normal butane to isobutane, for use as a
feedstock for the alkylation process. Liquid normal butane is
passed through a drying tower and vaporized. The vapor is
passed to a reactor, where, in the presence of a catalyst (usually
aluminum chloride) nearly 40 percent becomes isobutane. The
vapor is stripped from the catalyst and fractionated, with the
unconverted normal butane being recycled.
g. Catalytic Reforming. Reforming converts low octane naphtha, heavy
gasoline and naphthene-rich stocks to high octane gasoline blend-
ing stock that is high in aromatics. Hydrogen is a significant
by-product of the process. The predominant reaction during
catalytic reforming is the dehydrogenation of naphthenes.
95
-------
Secondary reactions which are also important are the isomeriza-
tion and dehydrocyclization of paraffins. All three of these
reactions result in higher octane products. The feedstocks are
usually hydrotreated to remove sulfur and nitrogen compounds
that would poison the catalyst. The vaporized feedstock is
passed through a reactor containing the catalyst and then is
cooled. Next it is released to a gas separator, where hydrogen
is removed, then passed to a stabilizer from which the final
product is withdrawn.
h. Hydrotreating. Hydrotreating processes are used to saturate
olefins, and to remove sulfur and nitrogen compounds. Hydro-
treating processes are used to reduce the sulfur content of
product streams from sour crudes by 90 percent while nitrogen
is reduced by 80 to 90 percent. Generally the feedstock is
mixed with hydrogen, heated and charged to the catalytic reactor.
The reactor products are cooled and the hydrogen, impurities and
high grade product are separated out. The primary variables
influencing hydrotreating are the type of catalyst, hydrogen
partial pressure, process temperature and contact time. Hydro-
treating is commonly applied to catalytic reformer feedstock,
catalytic cracking feedstock and for desulfurization of naphtha,
heavy gas oil and residuals. Hydrorefining and hydrofinishing
are very similar to hydrotreating. Each provides desulfuriza-
tion with hydrogen, to varying degrees. Hydrofinishing is the
least extensive treatment, with hydrorefining providing a middle
range of treatment. Which level of treatment utilized will
depend on the types of crudes being used and the desired
cleanliness of the products.
i. Product Fin_ish.i_ng.. Blending is the final step in producing
finished products to meet market demands and quality specifica-
tions. The largest operations involve blending the various gaso-
line stocks and additives (including anti-knock and anti-icing
compounds). Diesel fuels and other products also involve blend-
ing of components and additives. This process is usually highly
automated and is often controlled by computer.
3. Process Configurations for Puget Sound Refineries
a. Mobil. Since 1955 when the Mobil refinery went into operation,
an almost continuous expansion has taken place to modernize
the plant and maintain a high degree of process efficiency.
The major processes and processing units utilized at the re-
finery are: crude desalting, atmospheric distillation, vacuum
fractionation, Thermofor catalytic cracking, catalytic reforming,
visbreaking, polymerization, alkylation, hydrofinishing, chemical
treating and product blending (Figure 9). The refinery was
designed primarily to handle light, sweet crudes and therefore
has no sulfur recovery plant at the present time. To meet the
possibility of utilizing crude oils with a higher sulfur content
and to reduce sulfur levels in emissions-, a sulfur recovery unit
is being constructed, and is expected to be in operation by early
1977.
96
-------
Figure 9
Refinery Process Configuration at the Mobil Refinery
if*
jl
1st. Cut
2nd. Cut
Q3rd. Cut
from Pipeline
F-^ "
Crude
I r* Unit
^ ^ Still
Crude Oil Tanks
T
Fuel Gas to
Boilers and
Refinery Furnaces
*
A r
jndenser 1
_
Gas Plant
Propane
Butane Alkylaton
L/N W«-"i^>^. ^J 1
I Naphtha | 1 c
^ I • Kerosine • • Q ^
1 Diesel Oil flc? »
' T» -
(Straight Rur
Naph
Topped Crude ___
Recovered Oil
from Waste Water Plant
i Gasoline 1 I
tha ' Catalytic 1 Hi9h Octane
Reformer . Gasoline
tn 1
to 1
(1 1 . B
1 I
High Octane Gasoline)
TCC Unit 1
(Catalytic Light Gas Oil _|
Chemical
Treating
and
Product
Blending
Units
•
(Heavy Bottoms Vis Breaker
Propane
Butane
Butane
" Jet Fuels ^
>~\ Stove Oil
••^•Furnace Oil
•v Diesel Oil
Mobil
Gasolines
Heavy
Fuel
Oil
"8
o
CO
0>
c
o>
c
Source: (20)
-------
As with most refineries the crude oil is first pumped to the
electrostatic crude desalting unit where the salts present are
removed to prevent corrosion and to produce a cleaner feedstock
for the main process units. The crude passes on to the atmospheric
distillation unit where it is heated under pressure, then re-
leased into the low pressure distillation tower. In the tower
the oil is separated by boiling point into different fractions.
The light end products rise to the top of the tower and are
withdrawn for additional fractionation in the gas plant. Some
of this fraction condenses in a condenser as straight run gasoline
and goes directly to the chemical treating and blending units.
Also the next three fractions in the distillation tower, naphtha,
kerosene and diesel oil, are withdrawn and blended, and receive
chemical treating. A portion of the naphtha fraction from the
tower passes on to the catalytic reformer. The heaviest fractions
are withdrawn from the tower to a tar separator, then are broken
down further in the vacuum fractionation unit. The output from
the vacuum unit is charged directly to the Thermofor catalytic
cracker (TCC). Here, in the presence of a catalyst and high
temperatures, the heavy fraction is broken down into four major
fractions: gases, high octane gasoline, light gas oil and
residual oil.
The gases go to the gas plant where propane and heavier gases are
recovered. These pass on to the alkylation unit or are sold.
Gases lighter than propane are used as fuel gas for the boilers
and furnaces at the refineries. The light gas oil receives
chemical treatment and is blended to yield furnace oil. The high
octane gasoline from the TCC unit is blended with other qasoline
streams for production of three grades of Mobil motor gasoline.
The heavy residual oil can be heated to high temperatures at high
pressure in the visbreaker. This would convert it to heavy fuel
oil for use in industrial power generation plants and as bunker
fuel for ships. However, the energy cost of operating this
visbreaker versus the actual improvement in quality of the heavy
oils has not proved to be economical for Mobil. So, since 1972,
this process has not been utilized and the heavy residual oil
is sold as Bunker C fuel.
The catalytic reformer, also known as a Sovaformer, receives
middle fractions of naphtha from the crude unit as feedstock and
produces high octane reformate for gasoline blending, turbine
fuels and heating oil. This occurs at high temperature and
pressure in the presence of a bimetallic catalyst. A portion of
the feedstock undergoes hydrofinishing to remove mercaptans and
other sulfur compounds which could reduce the efficiency of the
catalytic reformer.
The alkylation unit receives the propane-butane fraction from
the gas plant and converts it in part to a high octane ingredient.
This alkylate is blended with the other gasoline streams to
produce motor gasolines. A polymerization unit is also available
98
-------
but it is a marginal process because the product octane is not
significantly higher than the other gasoline blending stocks
and so does not provide much upgrading of the overall motor fuel
pool. Alkylation produces a high octane alkylate and has a
higher yield per unit of feedstock than does polymerization.
So at Mobil, the polymerization unit is only used when the
alkylation unit is shut down for maintenance or repair. Besides
yielding high octane alkylate, the alkylation unit produces
some butane, which is reused.
Additives are blended into the three gasoline grades to provide
higher performance for the motorist. Among them are compounds
that maintain the quality of gasoline in storage, inhibit rust,
assure uniform combustion and clean vital engine parts.
A portion of the wastewater generated in the refinery receives
in-plant treatment. Desalter effluent waters, polymerization
feed wash waters and sour waters from the overhead accumulator
and knockout drums are all steam stripped. This is primarily
for removal of sulfides, but may also strip ammonia, phenols,
and cyanide. Bottom waters from the stripper go to an API
separator, then into the phenolic water surge tank. Gases
produced are condensed and burned in an incinerator. Spent
caustic is stored in a surge tank and is treated by a flue-gas
stripper. The stripped and diluted caustic solution is continuous-
ly bled to the wastewater treatment plant.
ARCO. The major processes and processing units utilized at the
ARCO refinery are: crude desalting, atmospheric distillation,
vacuum fractionation, delayed coking, hydrotreating, hydrocrack-
ing, hydrogen production, catalytic reforming, chemical treating,
gasoline blending and sulfur recovery (Figures 10 and 11). The
refinery is very different from the other Puget Sound refineries
and was specifically built to handle Alaskan North Slope crudes.
It is an "all-hydrogen" refinery, with all process streams being
substantially hydrotreated, producing cleaner products. There
is a great deal of flexibility of operations, allowing the re-
finery to run other crude types, prior to the availability of
North Slope crude, while maintaining a high degree of process
integration, yielding high quality products.
Initially the crude is washed to remove salt and prevent corrosion,
then is heated to its boiling point in the atmospheric distilla-
tion towers. The light end products are drawn off the light end
unit. The naphtha fractions are withdrawn and are hydrotreated
prior to being reformed. Fractions in the general range of
390°-525°F are withdrawn directly to the chemical treating unit.
Potential jet fuel fractions are removed and hydrotreated. The
heaviest hydrocarbon fraction, the gas oils, passes on to the
vacuum fractionation unit, for further breakdown. After addi-
tional treatment, a portion of the stream from the vacuum unit
goes to the hydrocracker and the residuum goes to the delayed coker.
99
-------
Figure 10
Diagram of the Layout of the ARCO Refinery
at Cherry Point
Preprinted with permission from:
Aalund, Leo, 1972. "Cherry Point He finery",
Oil and Gas Journal., Vol. 70, No. 4. 65-72
Source: (1)
ion
-------
Figure 11
Refinery Process Configuration at the ARCO Refinery
• WhenTwnlng Ntotrap TOW ~
t texlnram gasoline, minimum [si-fuel cose
I, 1M KM/%
»fmi JW
?. 4- Ha^tf
.,
° J^
S2-
— O
.£ °.
It. li^rnnduh
1 (
(«?,» !>«
I
|| ^»>J
w I °- HI
rn
{*> :
Source: (1)
Reprinted with permission from:
Aalund, Leo, 1972, "Cherry Point Refinery",
Oil and Gas Journal., Vol. 70, No. 4. 65-72
101
-------
The residuum is heated and injected into the four available
coke drums to be cracked down to lighter molecules. The
light hydrocarbons formed in the delayed coker pass on to
the naphtha hydrotreater, the diesel hydrotreater and the
hydrocracker. The solid residue of carbon, called coke, is
removed from the drums, crushed and loaded into railroad cars
for shipment to Japan. The two hydrotreating units, receiv-
ing fractions from the distillation unit and the delayed coker,
use hydrogen to remove sulfur compounds from the crude. These
units and the hydrocracker and sour water strippers remove
97 percent of all the sulfur compounds present. In the sulfur
recovery plant these compounds are converted to pure sulfur
by two parallel units. The sulfur is stored above ground
in storage tanks in a liquid form prior to being sold.
The four hydrocracker reactors receive streams of gas oil
from the vacuum fractionation unit and the delayed coker.
These large hydrocarbon compounds are broken down, or cracked,
to lighter compounds for later blending of jet fuels and .gaso-
line. Hydrogen is combined with the cracked molecules while
under high pressure and in the presence of a catalyst, pro-
viding hydrotreating of the streams and providing cleaner
products. The cracked products are separated into fractions
and then pass on to various parts of the plant. The light
and middle hydrocrackate fractions are kept separate but
are made available for gasoline blending. The heavy hydro-
crackate is shunted to the catalytic reforming unit. The
jet fraction joins the chemically treated straight run and
hydrotreated jet fractions from the crude unit and the diesel
hydrotreating unit to yield top quality Jet-A fuel. The
light ends from the hydrocracker, along with light fractions
from the catalytic reformer, furnishes the feed for the
hydrogen unit, which in turn supplies the diesel and naphtha
hydrotreating units, the catalytic reformer and the hydro-
cracker with hydrogen.
The catalytic reforming unit, also called a magnaformer, has
three radial and one spherical reactors, a fairly recent
innovation in catalytic reformer design. Here, the low
octane gasoline from the distillation tower, the delayed
coker and hydrocracker is processed to yield high octane
gasoline. Although the magnaformer is designed to utilize
a platinum/rhenium catalyst when North Slope crudes are being
reformed, presently a conventional noble-metal catalyst is
being used. Under high temperature and pressure, and the
influence of the catalyst, the molecules are rearranged,
providing a high octane reformate available as a blending
component for low lead and no-lead gasolines. The reformate
is separated into two fractions which are blended in the
gasoline blending unit with light and middle hydrocrackate
102
-------
and a butane stream from the light ends unit, yielding a
variety of motor gasolines.
Diesel fuel and some light end products are the only other
products produced at Cherry Point. The diesel fuel is of
fairly high quality and is sold as motor diesel fuel. The
process arrangement allows for the option of making some
bunker fuels but no fuel oils. The light ends unit yields
butane, some of which goes for gasoline blending and fuel
gas. The fuel gas is composed of propane and lighter gases,
although in the future, propane may be recovered and sold
on the liquefied petroleum gas market.
Water use in the refinery and its processes has been mini-
mized wherever possible. Boiler blowddwn has been reduced
by demineralizing the boiler feedwater. Sour water, from
the crude-vacuum unit, naphtha and diesel hydrotreating units,
the hydrocracker and the delayed coker, are all treated prior
to discharge to the wastewater treatment plant. This in-
plant facility removes hydrogen sulfide, ammonia and small
amounts of mercaptans, and separates dissolved and suspended
oil. The sour water is steam stripped and the H2S and NH3
removed passes on to the sulfur recovery plant. Phenolic
water is also fed to a steam stripper, but is kept separate
so that the water can be used as desalter water in the crude
desalting unit, for further removal of phenols. Waste acids
and caustic solutions also receive in-plant pretreatment and
are neutralized before being released to the waste treatment
plant.
Shell. The Shell refinery employs the following processes
and processing units: crude desalting, atmospheric distilla-
tion, vacuum fractional on, deasphalting, hydrotreating,
catalytic cracking, catalytic reformeV, gas recovery plant,
butane isomerization, alkylation, caustic treating and prod-
ucts blending (Figure 12). Crude oil received from tankers
and crude pipeline first is treated in the crude desalter,
then passes on to the atmospheric distillation tower. Here,
the crude is fractionated into a number of streams each re-
ceiving varying degrees of treatment.
The lightest gases are withdrawn and used for refinery fuel
gas. Butane goes to the butane isomerization unit where
normal butane is converted to isobutane for the alkylation
unit. Straight run gasoline receives chemical treating and
becomes a blending component for motor gasoline. Some low
octane straight run naphtha and the light gas oil fraction
receive hydrotreating in separate units and are blended for
aviation turbine (jet) fuel. The heavy gas oil fraction is
chemically treated and blended with hydrotreated naphtha to
produce furnace oil. The majority of the hydrotreated naphtha
passes on to the catalytic reformer where the octane is raised.
The high octane reformate is used as a gasoline blending stock.
103
-------
Figure 12
Refinery Process Configuration at the Shell Refinery
o
-£»
HDTDR GASOLINE^
DIESEL FUEL
FURNACE OIL
-------
The extra heavy gas oil cut from the distillation tower goes
to the catalytic cracker* The residual oil passes to the vacuum
fractionating unit. Two fractions are removed and become feed-
stock for the catalytic cracker. The remaining heavy residue
is called pitch and passes through a deasphalting unit which
produces asphalt and some heavy oil. The asphalt is used in
blending heavy fuel oils for industrial use. The remaining
heavy oil is hydrotreated to remove sulfur and is fed to the
catalytic cracker.
The fluid catalytic cracker (FCC) receives these heavy gas oils
and residuals as feedstocks and yields four major fractions:
clarified oil, heavy gas oil, naphtha and gasoline. The
clarified oil and heavy gas oil are blended to yield heavy
industrial fuel oil. The naphtha is chemically treated and
serves as a gasoline blending component.
The gasoline from the catalytic cracker and most gases generated
in the plant go to the gas recovery unit. The gasoline receives
some initial treatment, is chemically treated further and be-
comes a part of the gasoline blending pool. The gases are
recovered and separated for additional usage. Some become
refinery fuel gas. Propane is stored and sold commercially.
Isobutane goes directly to the alkylation unit. Normal butane,
butylene, propane, propylene and some isobutane are treated
for sulfur removal, then pass on to the alkylation unit. The
alkylation unit puts these components together, yielding a high
octane gasoline blending component. All of these various blend-
ing components are utilized to yield three grades of motor gasoline.
The refinery has two steam-stripping units for removing hydrogen
sulfide and ammonia from sour process waters. This eliminates
any hazard to personnel and reduces objectional odors. Additional
benefits of the steam-strippers are the reduction of loading on
the biological treatment processes, the.release of excess heat
and an adjustment of the pH of the oily-water stream. Waste
acids and caustic solutions also receive some in-plant pretreat-
ment prior to release to the wastewater treatment plant.
Texaco. The Texaco refinery was completed in 1958 and expanded
in 1974 to provide additional processing capacity and octane
improvement facilities. The major processes at the refinery are:
crude desalting, atmospheric and vacuum distillation, butane
deasphalting, hydrotreating, catalytic reforming, catalytic
cracking, polymerization, alkylation and product finishing (see
Figure 13).
Crude oil entering the refinery is processed first at the crude
distillation unit composed of the crude desalter and the atmos-
pheric distillation process. In the desalter, excess water and
salts are removed from the crude oil. The crude is then heated
and passed to the distillation tower where it is fractionated.
105
-------
o
cr>
Figure 13
Refining Process Configuration at the Texaco Refinery
REFINERY FUEL GAS
HEAVY FUEL OILS
-------
Light gases are removed and used as refinery fuel. Straight
run gasoline is withdrawn from the tower and used as a blending
component for motor gasoline. Naphtha and kerosene are hydro-
treated and a portion of each fraction serves as feedstock for
the catalytic reformer. The remaining portions of each fraction
are blended to make aviation fuels. The catalytic reformer
receives low octane feedstocks and utilizes a platinum or
platinum/rhenium catalyst to raise the octane rating. This
high octane reformate is used as a blending stock for motor
gasolines.
A small portion of the hydrotreated naphtha fraction is com-
bined with the remaining distillate fraction to make burner oil.
The remaining heavy residual fractions go either directly to
the catalytic cracker or to the vacuum fractionation unit.
The vacuum unit produces three fractions, including a heavy
pitch residue. The two lighter fractions are passed on to the
catalytic cracker. The pitch is extracted in a deasphalting
unit utilizing butane as a solvent. The deasphalted oil passes
on to the catalytic cracker, while the petroleum asphalt fraction
is blended with other heavy fractions (from the catalytic cracker)
to yield heavy industrial fuel oil and some refinery fuel oil.
The fluid catalytic cracker uses a catalyst composed pre-
dominantly of alumina and silica to further refine the heavy
feedstock fractions and produce the desired naphtha and distillate
fractions. The naphtha is used as a blending component for motor
gasoline. The distillate fraction is used to produce diesel
fuels. The heaviest fraction is blended with asphalt to pro-
duce heavy industrial fuel oils. The gases produced in the
catalytic cracker join with all other gases produced in the
refinery and pass to the gas recovery unit. This unit supplies
the alkylation and polymerization units.
Propylene and other olefin feedstocks are "hooked together" in
the polymerization unit to yield a higher octane blending com-
ponent for gasoline. The alkylation unit utilizes iso- and
normal butane, propylene and butylene to produce a high octane blend-
ing component for motor gasoline and jet fuel. Texaco has two
alkylation units; however, only one is presently operating.
The second unit was built to allow production of unleaded
gasoline, but presently this additional product is not being
produced.
The spent acid from the alkylation unit is reconstituted at
the nearby Allied Chemical Company plant. Sour water from the
crude desalter and catalytic cracker is steam stripped in the
refinery to remove sulfides and ammonia. After stripping, the
wastewater streams are fed to an oxidation unit for removal of
remaining sulfides and thiosulfates. The gases obtained from
these two in-plant processes are burned in a crude oil unit
107
-------
furnace. The stripped and oxidized condensates are discharged
to the process wastewater sewer for final treatment in the
wastewater treatment plant.
e. U.S. Oil & Refining. The refinery operated by U.S. Oil & Re-
fining receives two very different types of crudes and keeps
them separated throughout most of the process units. A heavy
crude is used in the production of asphalt and a lighter crude
is used for producing distillate fuels. The processes employed
for treatment of heavy crude are atmospheric and vacuum
distillation. The light crude passes through both atmospheric
and vacuum distillation, and catalytic reforming (Figure 14).
The heavy crude is kept heated so that its viscosity is low
enough to allow pumping. It passes into the atmospheric
distillation tower and is separated into distillates and a
heavy residual fraction. The heavy residue is used for making
asphalt and goes to the asphalt tankage area for future blend-
ing. The distillate fractions are sold as diesel fuel oils.
The light crude also undergoes atmospheric and vacuum distilla-
tion, but in facilities separate from those used for the heavy
crude. This yields four major fractions; gasoline, naphtha,
kerosene and diesel fuel oil. A portion of these distillates,
primarily low octane gasoline and naphtha from the vacuum
unit, serves as feedstock for the catalytic reformer. The
remainder of the distillates and the high octane reformate
produced by the catalytic reformer are used as blending stocks
for gasoline, jet fuel, and diesel fuel oil.
f. Sound Refining. Sound Refining operates a small 4,500 BPD
capacity refinery in Tacoma, Washington. It is a simple
refinery, producing predominantly petroleum asphalt (Figure 15).
Heavy crude oil is pre-heated (it must be heated to move it)
and injected into an atmospheric distillation tower, where
fractionation occurs. Seven fractions are withdrawn from the
tower. Gasoline and overhead gases are treated to remove water
vapor, then join the withdrawn naphtha, kerosene, diesel and
gas oil fractions in the distillate storage tanks, and are
used to make heavy fuel oils and blending stocks for the pro-
duction of special asphalt.
The heaviest fraction of the reduced crude is again heated and
passes on to a vacuum distillation unit. The overhead vapors
are treated for removal and condensation of water vapor. The
treated gases go on to the distillate storage tanks along with
two other fractions, the light and heavy lubricating oils.
The remaining fraction from the vacuum unit is petroleum asphalt
and is withdrawn to the asphalt storage tanks.
The new management of Sound Refining, which assumed control of
the refinery on 1 July 1976, is not entirely satisfied with the
108
-------
Figure 14
Refinery Process Configuration at the U.S. Oil & Refining Refinery
Light
Crude
Crude
Unit
Gasoline
Naphtha
Kerosene
k '
Diesel k
f' f"
Catalytic
Reformer
Product
Blending
t
Gasoline
Jet Fuel
Diesel Fuel
Heavy
Crude
Atmospheric
Distil'
Heavy
Fraction
Distil'
Asphalt
Barometric
Condenser
Product
Blending
Asphalt
Tankage
-------
Figure 15
Refinery Process Configuration at the Sound Refining Refinery
Crude Oil
Heater
gases
, gasoline
Atmospheric
Distillation
naphl
I^_
;ha
kerosene
diesel oil
gas oil
Distillate
Storage
reduced crude
Heater
I
Vacuum
Distillation
gases
light lube oil
(Separator
, ^•^•••••••••^•••H
heavy lube oil
Distillate
Storage
asphalt
Asphalt
Storage
-------
present scheme of operations and is considering revising the
refinery processes and utilizing different crude oils than
have been used in the past.
E. Characteristics of Wastewater Entering
the Treatment Plant
1. Introduction
Each process employed in a petroleum refinery yields a fairly character-
istic wastewater. Observations from other refineries provide good indica-
tions of the types of contaminants to expect from the processes utilized
in a given refinery. Knowledge of the overall types of pollutants to be
found in the wastewater is essential fqr design !of the waste treatment
plant and the selection of treatment processes. In general, the para-
meters found in the influent to the wastewater treatment plant are:
phenols, sulfides, BOD, COD, ammonia, oil, chlorides, alkalinity or acidity,
suspended solids and a variable pH. Which of these pollutants are present
and in what quantities depends on the processes in the refinery (see
Table 46). Some general ranges of quantities of BOD, phenols and sulfide
for petroleum refineries are shown in Table 47.
2. Characteristics of Wastewater from Refinery Processes
a. Crude Desalting. Hash water from the crude desalter units will
contain ammonia, phenols, sulfides and suspended solids. All
of these pollutants combine to produce a high BOD and COD. Some
free oil is present, along with emulsified oil. The salts present,
particularly chlorides, contribute to the high dissolved solids
content of the process wastewater.
b. Crude Fractionation. The wastewater produced by atmospheric
distillation and vacuum fractionation is generally a major '
source of ammonia and sulfides, especially when sour (high sulfur)
crudes are being distilled. It also contains phenols, oil,
mercaptans and chlorides.
c. Thermal Cracking. The major source of wastewater in thermal
cracking is the overhead accumulator on the fractionator, where
water is separated from hydrocarbon vapors, and is passed along
to the sewer system. This wagtewater usually contains ammonia,
phenols, sulfides and oil. These cause high BOD and COD values.
Alkalinity may also b^ high in wastewaters from thermal cracking
units.
d. Catalytic Cracking. Catalytic cracking units are one of the
largest sources of sour and phenolic wastewaters in a refinery.
Wastewater comes from the steam strippers and overhead accumu-
lators on the fractionators used to recover and separate the
various hydrocarbon fractions produced in the reactor. The
major pollutants are oil, phenols, sulfides, ammonia and cyanide.
Ill
-------
Table 46
Qualitative Evaluation of Wastewater Characteristics
by Refinery Process
ro
Production
Piocesses
Crude 01 1 and
Product Storage
Crude Desalting
Crude Distill-
ation
Thermal Cracking
Catalytic Cracking
Hydrocracklng
Polymerization
Alkylatlon
Isomerlzatlon
Reforming
Solvent Refining
Asphalt Blowing
Dewaxtng
Hydrotreatlng
Drying and
Sweete ing
Flow BOD COO
XX • X XXX
XX XX XX
XXX X X
XXX
XXX XX XX
X
X XX
XX X X
X
X 0 0
X X
XXX XXX XXX
X XXX XXX
XXX
XXX XXX X
Phenol Sulflde Oil
X XXX
X XXX X
XX XXX XX
XXX
XXX XXX X
XX XX
OX X
0 XX X
XX X
X 0
X XXX
X 0 X
XX
XX 0 0
Emulsified Am-
Oil oH Temp. monla Chloride Acidity
XX 0 0 0 0
XXX X XXX XX XXX 0
XXX X XX XXX X 0
XX XX X X 0
X XXX XX XXX X 0
XX XX
0 X X X X X
0 XX Z X XX XX
0 0 Z X 0 0
X X 0 0
0
0 XX XX 0 0
Z XX 0 X 0 X
Alkalinity
X
X
XX
XXX
0
0
0
X
X
X
Suso. Sc
XX
sax
X
X
X
X
XX
0
0
XX
XXX - Major Contribution.
XX • Moderate Contribution.
X - Minor Contribution,
0 - Mo Problem .
— No tot*
Source: (32)
-------
Table 47
Average Wastewater Loadings from Petroleum Refineries Utilizing
Old, Prevalent, and New Technology
Flow,
gal/bbl
Type of Technology
Older
Typical
Newer
Avg
250
100
50
Range
170-374
80-155
20-60
Avg
0.40
0.10
0.05
liters/bbl
945
378
189
644-1410
301-586
76-227
181
45.4
22.7
BOD,
Ib/bbl
Range
0.31-0.45
0.08-0.16
0.02-0.06
g/bbl
141-204
37.3-72.5
9.1-27.2
Avg
0.030
0.01
0.005
13.6
4.5
2.3
Phenol,
Ib/bbl
Range
0.028-0.033
0.009-0.013
0.001-0.006
g/bbl
12.7-15
4.1-5.9
0.45-2.7
Avg
0.01
0.003
0.003
4.5
1.4
1.4
Suir.de,
Ib/bbl
Range
0.008
0.0028
0.0015
g/bbl
Source: (15)
Reprinted with permission from?
Eckenf'elder, W. W. Jr., Water Quality
Engineering for Practicing Engineers.
Barnes & Noble. 1970.
-------
The phenol and sulfide concentration will vary with the type
of crude being processed. All of these contaminants contri^
bute to a wastewater with high alkalinity, BOD and COD.
e. Hydrocracking. Wastewater from this unit contains sulfides,
phenols, and ammonia, since one purpose of hydrocracking is to
yield a clean product relatively free of sulfur and nitrogen.
Most of these compounds are in the gas products which are sent
to a treating unit for removal and recovery of sulfur and
nitrogen. However, some of these contaminants will be found
in the process wastewater stream.
f. Polymerization. Even though this process utilizes acid catalysts,
the wastewater stream is alkaline because most of the catalyst
is recycled and any remaining acid is removed by caustic wash-
ing. Most of the contaminants arise from the pretreatment
of the feedstock. The wastewater is high in mercaptans, sul-
fides and ammonia.
g.i Alkylation. The major discharge from this process is the spent
caustic from the neutralization of the hydrocarbon stream leav-
ing the reactor. These wastewaters contain dissolved and sus-
pended solids, oils, sulfides, chlorides and ammonia. Water
drawn off from the overhead accumulators contribute to BOD, COD,
oil and sulfide levels, but is not a major source of wastewater
from this process.
h. Isomerization. This is a fairly clean process and the wastewater
from this unit contains no major pollutants, only minor contribu-
tions of phenols and BOD.
i- Reforming. Reforming is also a relatively clean process. Very
little water is used in the process and none of the wastewater
streams have a significant amount of contaminants. The waste-
water is generally alkaline and contains some sulfides, ammonia,
oils and mercaptans from the overhead accumulator of the strip-
ping tower.
j. Hydrotreating. The quantity of wastewater generated by hydro-
treating, hydrorefining and hydrofinishing depends on which
process is used and the type of crude employed as a feedstock.
Ammonia and sulfides are the major pollutants, but phenols m,ay
also be a problem.
k. Product Finishing. Generally much care is taken to prevent any
loss of product, so the blending of products produces no major
contaminants. The main source of wastewater results from the
washing of tanks and railroad tank cars prior to storage or
loading of finished products. These wash waters afe particular-
ly high in emulsified oils.
114
-------
3. Influent Wastewater Characteristics for the Washington Refineries
On the whole, no consistent monitoring of the wastewater entering
the treatment plant is made at any of the six refineries. The refineries
are more concerned with measuring pollutants in the final effluent from
the wastewater treatment plant. Furthermore, in many cases it would be
difficult to make any meaningful assessment of influent characteristics
because the wastewater streams are separated into different collection
systems. Each separate stream would have to be analyzed for the quantity
of each pollutant. The sum of these assessments could tentatively be
used to represent the quality of the refinery wastewater. However, this
would involve numerous difficulties and procedures which are of no im-
pact on the actual running of the refinery. Possibly measurement of the
influent wastewater would be more appropriate after the first treatment
process of the main wastewater stream. Such measurements have been
made at the Shell refinery on occasion, using the effluent from the API
separator. A typical analysis is shown below. No breakdown of oil and
grease into hydrocarbon types is available.
Influent Characteristics - API Separator Outfall
Concentration (mg/1)
Parameter
Total Suspended Solids (TSS)
Ammonia (as Nitrogen)
Sulfide
Chemical Oxygen Demand (COD)
Biological Oxygen Demand (BOD)
Phenols
Hexavalent Chromium
Total Chromium
Oil and Grease
Fecal Col iform
PH
Maximum
216
161
37
583
228
12
2.6
60
11.5
Minimum
19
98
11
190
70
1
0.8
11
10.3
Mean
68
123
23
281
118
10
0.88
31
10.9
the
This also may be indicative of the levels of pollutants entering
wastewater treatment plants at Texaco and Mobil which employ similar
crude oils and refinery processes. However, no definite statement can
be made regarding the pollutants entering the wastewater treatment plants
beyond a general qualitative assessment based on the refinery processes
being utilized.
F. Ballast and Stormwater Flows
1. Introduction
Ballast and stormwater flows are difficult to assess in a refinery
for two reasons. First of all, in the major refineries, the wastewater
streams are separated into separate sewer systems. Secondly, flow measure-
115
-------
ments of these parameters are of relatively little concern for those
operating a refinery. So, little consideration is given to ballast and
stormwater volumes; instead the total effluent discharge is monitored.
2. Ballast Water
Ballast water is received at the refinery from ships which are load-
ing refined products. This water is kept in storage tanks prior to its
release to the wastewater treatment plant. Often ballast water is
released to the treatment system primarily to equalize wastewater flows
and smooth out low flow periods. In some instances the water may be
skimmed for oil removal while in the ballast water storage tank. However,
treatment of the water is usually accomplished within the wastewater
treatment plant itself (described in Section II-G).
Neither U.S. Oil & Refining or Sound Refining receive ballast water
from incoming or outgoing ships. The remaining four refineries are
allocated certain average and maximum volumes of ballast water in their
National Pollutant Discharge Elimination System (NPDES) discharge alloca-
tions regarding total effluent discharge. The ballast water flow
allocations are based on either the actual discharge from the ship or
the flow from the ballast water storage tank. The average ballast water
flow allocation is based on an assumed processing of one ship's ballast
discharge every ten days. The maximum flow allocation is based on the
actual daily rate of flow from the ballast water storage tank. These
allocations are shown in Table 48. Actual ballast water flows for 1974,
1975 and the first half of 1976 from the Shell refinery are shown in
Table 49. The averages are offloading values and the maximum values are
the volume of ballast water discharged from the ballast water storage
tank.
Besides providing a ballast water flow allocation, the NPDES permit
allows an additional pollutant loading in the final effluent, based on
the ballast water discharge. Allocation factors have been established
for each individual refinery by the Department of Ecology for specific
parameters; oil and grease, BOD, COD and suspended solids. These alloca-
tion factors (in Ibs/gal) are multiplied by the ballast water flow alloca-
tion to yield the additional allowable quantities of pollutants in the
refinery's final effluent discharge.
3. Stormwater
Stormwater is the precipitation that falls on the refinery grounds.
In the four major refineries this water may enter two different sewer
systems, depending on where in the plant it fell. Stormwater that is
from non-oily, non-process areas is collected in a clean water sewer
system at Mobil, ARCO, Texaco and Shell. This relatively uncontaminated
water receives a minimum of treatment in the wastewater treatment plant,
although it is always possible to shunt the stormwater into the main
process stream to receive more extensive treatment if contamination occurs,
Stormwater that falls on oily, process areas is collected along with
other contaminated wastewater and receives a full range of physical and
biological treatment. There are usually large holding basins to contain
116
-------
Table 48
Average and Maximum Ballast Water Flow
Allocations (in Thousands Gallons Per Day)
Average
Maximum
Mobil
185
550
ARCO
330
800
Shell
60
NA
Texaco
NA§
NA
§Not Available
Table 49
Ballast Water Flows for 1974-1976 from the
Shell Refinery (in Thousands Gallons Per Day)
Average
Maximum
1974
30.4
618
1975
40.4
872
1976
(Six Months)
.57.1
907
Source: (19)
117
-------
the stormwater flows and to prevent surges in the wastewater flow. The
water is released for treatment according to the flow levels in the
treatment plant. U.S. Oil & Refining and Sound Refining do not have
separate sewer systems; all wastewater, including stormwater, receives
the same treatment.
Like ballast water, the NPDES discharge permits allocate certain
average and maximum volumes of stormwater. The stormwater flow alloca-
tions are based on an average precipitation figure or a single day peak
rainfall. The average stormwater allocation is based on an annual average
of 35 inches of precipitation per year. The maximum stormwater flow is
based on a peak rainfall of 2.5 inches per twenty-four hour period.
These rainfall values are multiplied by the storm sewer collection area
to yield the average and maximum allocations. These allocations will
vary from refinery to refinery because of differences in land area.
The stormwater flow allocations for the Puget Sound refineries are shown
in Table 50. These values assume total runoff of rainfall; with no
losses to ground water or evaporation. It is often difficult to
accurately distinguish and account for the actual volumes of stormwater
received. This is especially true when stormwater goes to separate
systems and is mixed in with other types of wastewater. However, some
measurements are possible, and the stormwater flows for 1974-1976 from
the Shell refinery are shown in Table 51.
Besides providing a flow allocation, the NPDES discharge permit allows
an additional pollutant loading, based on the stormwater discharge. As
with ballast water, allocation factors have been established for each
refinery for specific parameters: oil and grease, BOD, COD, and sus-
pended solids. These allocation factors (in Ibs/gal) are multiplied by
the stormwater flow allocation to yield the additional allowable
quantities of pollutants in the refinery's final effluent discharge.
G. Wastewater Treatment Processes
1. Introduction
In general, the types of wastewater produced in a refinery depend
on the crudes and processes utilized. Each refinery process yields waste-
water which has fairly specific chemical contaminants and characteristics.
It is these parameters and the required degree of treatment to fulfill
effluent standards which are considered in the design and operation of a
refinery wastewater treatment plant. The major types of waste treatment
processes available for consideration are: API separators, oxidation
ponds, air flotation, clarification, coagulation and flocculation,
aeration basins, activated sludge, trickling filter, rotating biological
surface units, polisher units and activated carbon. Typical removal
efficiencies of these processes and the expected effluent from each
process are shown in Tables 52 and 53.
118
-------
Table 50
Average and Maximum Stormwater Flow
Allocations (in Million Gallons Per Day)
Average
Maximum
Mobil
0.31
7.1
ARCO
0.55
8.0
Shell
0.72
18.8
Texaco
NA§
NA
U.S. Oil &
Refining
NA
NA
Sound
Refining
0.03
NA
§
Not available
Table 51
Stormwater Flows for 1974, 1975 and the First
Half of 1976 from the Shell Refinery (in Million Gallons Per Day)
Average
Maximum
1974
0.41
11.0
1975
0.62
10.1
1976
(Six Months)
0.53
6.3
Source: (19)
119
-------
ro
o
Table 52
Typical Removal Efficiencies for Oil Refinery Treatment Processes
REMOVAL EFFTCIH»CT. t
FBO
1.
2.
3.
k.
5.
6.
T.
8.
9.
10.
11.
12.
CESS
tn Separator
Clarifter
Diaaolved Mr
notation
nilwr
Oxidation Food
Aerated Lagoon
Activated Sludge
Trickling
Filter
Cooling Tower
Activated
Carbon
Filter
Granular Media
Activated
Carbon
IXtWBtt
Rav Waste
1
1
1
1
'2,3,*
2,3.1>
1
2,3.li
2.3,li
5-9
5-9'plua 11
BODc
.5-kO
30-60
20-70
to-70
fcO-95
T5-95
80-99
60-85.
50-90
70-95
HA
91-98
COD
5-30
20-50
10-60
20-55
3CN65
60-65
50-95
30-70
1)0-90
70-90
HA
86-9U
TOC
•A
•A
•A
•A
60
•A
to-90
HA
10-70
50-60
50-65
50-80
SS
10-50
50-80
50-85
75-95
20-70
40-65
60-85
60-85
50-85
60-90
75-95
60-90
OIL
60-99
60-95
10-85
65-90
50-90
70-90
80-99
50-80
60-75
75-95
65-95
70-95
PHENOL
0-50
0-50
10-75
5-20
60-99
90-99
95-99+
70-98
75-99+
90-100
5-20
90-99
AMMONIA
HA
HA
HA
XA
0-15
10-45
33-99
15-90
60-95
7-33
HA
33-87
SULFIVE
HA
HA
HA
HA
70-100
95-100
97-100
70-100
HA
HA
HA
HA
•A - Data lot Available
Source: (32)
-------
Table 53
Expected Effluents from Petroleum Treatment Processes
ro
PROCESS
1. API Separator
2. Ciarltler
3. Dissolved Air
Flotation
U. Granular Media
Filter
5. Oxidation Pond
6. Aerated Lagoon
r. Activated Sludge
1. Trickling Filter
1. Cooling Tower
>. Activated Carbon
L. Granular Media Filter
!. Activated Carbon
EFFLUENT CONCENTRATION
PROCESS
XNFLUGHT
Rear Waste
1
1
1
1
2.3.U
2.3,.
1
2.3.1.
2.3.U
5-9
5-9 and 11
BODj
250-350
1(5-200
U5-200
Uo-170
10-60
10-50
5-50
25-50
25-50
5-100 j.
HA
3-10
COD
260-700
130-lt50
130-1(50
100-ltOO
50-300
50-200
30-200
80-350
U7-350
30-200
HA
30-100
TOC
NA
NA
NA
HA
HA
HA
20-80
NA
70-150
NA
25-61
1-17
ss
50-200
25-60
25-60
5-25
20-100
10-80
5-50
20-70
U. 5-100
10-20
3-20
1-15
. ziK/L
OIL
20-100
5-35
5-20
6-20
1.6-50
5-20
1-15
10-80
20-75
2-20
3-17
6.8-2.5
PHENOL
6-100
10-UO
10-UO
3-35
o.oi-ia
0.1-25
0.01-2.0
0.5-10
.1-2.0
-------
2. General Wastewater Treatment Process Description
a. Gravity Separation. The API separator is the most common type
of gravity separator and is used as primary treatment for the
removal of oil and grease. Most or all of the water from the
separate refinery sewer systems passes through an API separator
in a refinery. For some types of effluent, such as uncontaminated
stormwater, this process may be the sole treatment which the
wastewater undergoes. Available performance data indicates a
range of 60-99 percent removal of the oil content of influent
water. Some removal of phenols, BOD and COD is also accom-
plished, along with suspended solids which settle to the
bottom of the separator.
The basic design of an API separator is a long rectangular
basin with a long enough retention time of the wastewater to
allow the oil to float to the surface and be removed. Most
separators are divided into more than one bay, to make the
process more effective. Scrapers are provided to move the oil
downstream to a slotted pipe or a drum where the oil is collected.
On their return upstream, the scrapers travel along the bottom
and move settled solids to a collection trough.
A modification of this basic design is the parallel plate
separator. The separator chamber is subdivided by parallel
plates set at 45° angle with horizontal and less than 6 inches
apart. This increases the overall surface area of the unit
and decreases the separation depth, thus allowing a decrease
in size of the unit. Some separators use corrugated plates to
increase the area even more. As water flows through the separator,
oil droplets coalesce on the underside of the plates and travel
upward to where the oil is collected.
b. Clarification. Clarifiers are often used in both primary and
secondary treatment. Clarifiers use gravitational separation
to remove oil and suspended solids from the wastewater stream.
Surface skimmers are usually provided for more efficient re-
moval of oil. Phenols, BOD, COD, suspended solids, ammonia,
sulfides and oil are all removed by this process. Often chemical
coagulants are employed to enhance flocculation and sedimenta-
tion of suspended materials. This may raise the removal effi-
ciency of simple clarification as shown in Table 53.
c. Oxidation Ponds. Oxidation ponds are often used as a major
treatment process, providing secondary treatment of wastewater
after gravity separation. Some refineries use ponds as a final
polishing process after all other treatment processes. The
ponds are shallow and unaerated, but remain aerobic. The
bacteria and algae present serve to reduce BOD, COD, suspended
solids and inorganic nutrient levels. Ponds are usually sealed
with clay, asphalt or polyethylene to prevent seepage. The
retention time, depth and surface area are all factors which
affect the removal efficiency of this process.
122
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Air Flotation. The primary purpose of this process is the
clarification of wastewater by the removal of suspended matter,
including oil and grease. Air bubbles under pressure in the
basin allow suspended material to adhere to the bubbles. The
material rises to the surface where it is removed by skimming.
This process also reduces BOD and COD by the removal of the sus-
pended matter. The addition of air acts to lower the oxygen
demand of the wastewater. Chemical flocculating agents may
also be added to improve the effectiveness of air flotation
and to obtain a higher degree of clarification. Mechanical
equipment is necessary in the basin for continuous removal of
the upper froth and the bottom sludge. Comparisons of the per-
formances of clarifiers using chemical coagulation and the air
flotation process indicate that flotation performs somewhat
better.
Aeration Basins. Aeration basins are essentially upgraded oxida-
tion basins. The use of surface aerators permits deeper ponds,
shorter retention periods and less surface area. The retention
times are reduced from the 20-110 days for oxidation ponds to
1-12 days when mechanical aerators are employed, and the removal
efficiencies are usually higher.
Biological Treatment. Processes involving the use of bacteria
or other microbes for the oxidation of wastes are called bio-
logical treatment. The overall biochemical reaction can be
considered as occurring in two phases: (1) the synthesis of
new microbial sludge or protoplasm, and (2) the auto-oxidation
of part of the microbial sludge, which is referred to as
endogenous metabolism. In the synthesis phase, nutrients in
the wastewater are utilized in producing new microbial cells.
In the endogenous metabolism phase, nutrients are released and
either reused or oxidized.
i. Activated Sludge. There are many types of activated
sludge processes. Although they vary in detail, the
basic method is fairly uniform among various modifica-
tions. The wastewater is mixed with previously synthe-
sized microbial organisms in a system supplied with
air or mechanically aerated. Much of the colloidal
and suspended material in the influent is adsorbed by
the microbial sludge, greatly reducing BOD, COD, sus-
pended solids, oil, phenols, sulfides and ammonia.
Usually the aeration basin, where wastewater is con-
tacted with microorganisms, is followed by a clarifica-
tion basin. Here, the water is withdrawn while sludge
containing microorganisms and contaminants settles to
the bottom. A portion of the sludge is recycled to
the aeration basin, while the remainder is collected
and discarded.
123
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ii. Trickling Filter. A trickling (trickle) filter con-
sists of a fixed bed of rocks, slag or plastic media
which has a thin layer of microbial slime covering it.
The wastewater flows over the media and contacts the
microbes for biological treatment. Aerobic condi-
tions are maintained by air flowing through the bed.
As the water trickles through the media, contaminants
are removed by the microorganism population. For
more efficient removal, the wastewater is recycled over
the media bed. This process has good removal effi-
ciencies for BOD. COD, sulfides. ammonia, phenols.
oil and suspended solids, but as indicated in Table
53, activated sludge produces better results if prop-
erly maintained.
iii. Rotating Biological Surface Units (RBS). These units
consist of horizontal cylindrical tanks which are
filled with wastewater. A series of corrugated disks
rotate about a central axis in the tank. Bacteria and
other microbes are allowed to grow on the disks and
provide biological treatment as they are rotated
through the wastewater. The rotation of the disks
exposes the microorganisms both to air and the waste-
water, thus constantly renewing the bacteria-nutrient-
oxygen interface. General removal efficiencies are
not available for these units; however, they are highly
rated for removal of phenols and they reduce BOD, COD,
oil and sulfides. A polisher unit consisting of a
media filter and a coalescer filter is usually linked
with a rotating biological surface unit. Its purpose
is to remove the material degraded in the RBS unit
and provide a final clarification of the treated waste-
water. Neither of these units is commonly employed by
large refineries, due to flow limitations, size of the
unit and the availability of other more efficient
treatment processes. Usually they are limited to
refineries of less than 30,000 BPD capacity.
g. Activated Carbon. The activated carbon process utilizes granular
activated carbon to adsorb pollutants from the wastewater. The
water flows through banks of carbon columns arranged in series
or parallel. As the water moves past the columns, pollutants
are adsorbed by the activated carbon, gradually filling the pores.
At intervals portions of the carbon are removed to a furnace
where the adsorbed substances are burned off, and the carbon is
reused. Activated carbon reduces BOD, COD, oil, phenols, sus-
pended solids, ammonia and sulfides, but is not yet widely uti-
lized by the refining industry.
3. Wastewater Treatment Configurations For Puget Sound Refineries
a. Mobi1. The wastewater treatment plant at Mobil's Ferndale re-
finery receives untreated water from five separate sewer systems
124
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and one drainage system. Many additions have been made since the
initial plant construction in 1954, in a continuing effort to
meet Federal and state regulations and minimize the effluent
effects on the receiving waters. The most recent addition was
in 1973, further upgrading the plant capacity and treatment abili-
ties. The six different inputs of wastewater are kept separate
to allow the adequate and appropriate treatment of each particular
type of wastewater. Thus, all wastewater produced in the refinery
and its operations are collected in one of the following systems:
(1) storm, (2) ballast, (3) phenolic, (4) oily, (5) sanitary and
(6) tank farm spillage. (See Figure 16).
Stormwater is collected from all areas of the refinery. Treat-
ment depends on the degree of oil contamination. Stormwater
from non-contaminated run-off areas flows through an observa-
tion channel where any oil present tends to float to the sur-
face and is skimmed off. Since oil from the ground surface is
the only contaminant in this water, no further treatment is
given. The water flows to the final holding pond, which receives
all of the treated wastewater from the refinery, and is sub-
sequently discharged. Stormwater from areas of the refinery
where oil is present on the ground receives additional treat-
ment. The contaminated Stormwater is detected in the observa-
tional channel and is diverted into an 11 million gallon con-
taminated Stormwater surge pond. Subsequently it passes into
the oily water surge basin and receives the same treatment as
the water collected in the oily water sewer system.
Ballast water is pumped from tankers and held in a 1.3 million
gallon storage tank. From here the ballast water flows by
gravity to an API separator, for removal of floating oil and oily
sludge material. The effluent from the API separator passes
through hay filters and is pumped into a 0.35 million gallon
beach head runoff basin. The ballast water is then pumped to the
oily.water surge basin and processed along with contaminated
Stormwater and oily water.
Phenolic water and storm runoff from the product treating area
of the refinery flows into an API separator in the phenolic
equalization basin. Oil skimmed in this separator is stored in
a 0.01 million gallon storage tank and transferred on a batch
basis to the slop oil recovery system. The sediment from the
API separator is disposed of in a sludge pit. The phenolic
water is discharged from the separator into the phenolic equal-
ization basin. Subsurface mixers are present to minimize the
extreme fluctuations in the concentration of chemical contaminants
contained in the water. When the contaminants are in a relative-
ly high concentration, the phenolic waters are diverted from
the separator to the 0.6 million gallon bad phenolic water basin.
It is pumped back into the system at a limited rate to reduce_
the level of contaminants present. From the equalization basin,
the phenolic water is pumped to the oily water treatment facili-
ties.
125
-------
ro
01
Figure 16
Wastewater Treatment Configuration at the Mobil Refinery
OBSERVATION CHANNEL
WITH SKIMMER
SKIMMED OIL
- SLOP OIL SYSTB1
- SLUDGE PIT,, DISPOSAL
-------
Slowdown from treatment processes, which treat the raw water
taken from the Nooksack River for various functions in the
refinery, is collected in a 0.7 million gallon blowdown pit
for clarification. From there the water is pumped to the oily.
water sewer.
Thus, after varying degrees of separate treatment, contaminated
stormwater, ballast water, phenolic water and raw water treat-
ment blowdown water all eventually empty into the oily water
sewer for further treatment. These waters combine with oily
water and stormwater runoff from the process areas and pass
through a pH control sump, Sulfuric acid or spent caustic is
added to the water to control the pH of the water for optimum
biological treatment. Phosphoric acid is also added at this
point to provide a necessary nutrient for the biological system.
The combined water next flows into two large API separators.
These separators are in parallel so that one can be shut down
for maintenance and repair, without affecting the treatment
facility. Any excessive flow which cannot be handled by the
remaining separator can be temporarily held in the oily surge
basin, to be treated later. Skimmed oil from these separators
is pumped to the slop oil system and the bottom solids are
diverted to the sludge pit for storage until final disposal.
The water effluent from the API separators passes on to two
parallel air flotation tanks for additional oil recovery. The
oily froth from these units is recycled to the slop oil re-
covery unit.
The wastewater is joined here by sanitary wastes from the various
septic tanks at the refinery and is pumped to the trickling
filter. If the flow volume is too great, some of the water can
be diverted to two 0.42 million gallon surge tanks. A pumping
station is present to recycle water for the trickling filter and
to move the water to the next state of biological treatment.
Four parallel activated sludge units provide additional biological
treatment of the combined wastewater flow. Two of the units
are equipped with a recycle stream for additional aeration and
to provide a constant source of microorganisms for the activated
sludge units in case of any loss of the bacteriological popula-
tion.
The final effluent from the activated sludge tanks is pumped to
a 5.0 million gallon clarification pond for sedimentation of
biological-flocculent carry-over. A skimmer is present in the
pond to remove any floating oil or other material. This water
is then pumped to the 10.0 million gallon final holding pond
prior to discharge into Puget Sound. The clarification pond
can be bypassed during periods of maintenance and repair with
the effluent from the activated sludge units being pumped
directly to the final holding pond. In case the effluent
quality does not meet the allowable levels of contaminants, the
flow is diverted to the oily surge basin for retreatment. The
127
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uncontaminated storm runoff also enters the final holding pond
and is mixed with the treated wastewater. The total plant
effluent is then pumped through the outfall line and diffuser
into the Strait of Georgia.
ARCO. Atlantic Richfield's wastewater treatment plant at Cherry
Point was specifically designed to comply with the strict Washing-
ton State Standards for water quality. Extensive effort was made
to employ the best process available to treat the newly con-
structed refinery's wastewater. The facility was designed for
twice the expected dry weather flow, to provide surge capacity
to handle peak flows and to allow shutdown of equipment for main-
tenance and cleaning without affecting the treatment plant opera-
tion. Four separate systems handle all of the wastewater occurr-
ing at the plant. Each system involves wastewater from different
sources, requiring different types and degrees of treatment, but
are set up in such a manner that wastewater volumes may be shunt-
ed to other systems for additional treatment. The four collection
and treatment systems are for the following types of wastewater:
clean, ballast, process and sanitary (see Figure 17).
The clean water system includes clean water from the refinery
processes and stormwater from uncontaminated areas of the
refinery. The sewer system which collects the stormwater from
all non-process areas and receives water from the boiler and
cooling tower blowdown streams is equipped with a trash rack to
remove debris and a floating oil skimmer to remove any oil pre-
sent in the waters. The effluent from this channel is monitored
for total organic carbon content and oil and grease concentra-
tions and is discharged to the 7.5 million gallon stormwater
surge pond. If the water is considered clean enough, it is dis-
charged to the 7.5 million gallon final holding pond or directly
to the outfall diffuser at the refinery dock. If the water is
determined to need further treatment, it is shunted from the
observation channel or the stormwater surge pond to the process
water treatment system prior to the initial treatment stage
(the API separators).
Ballast water from arriving product ships is pumped to a 4.2
million gallon tank equipped with a floating oil skimmer. The
oil recovered is de-watered and reused in the refinery processes.
The ballast water in the tank is monitored and if it is uncon-
taminated it may be routed directly to the final holding pond
and/or to the outfall diffuser. Normally, though, the ballast
water is passed over to the process water treatment system, prior
to the API separators.
The process or oily water system collects all wastewater which
may be contaminated from the refinery processes or other sources.
All water from the vehicle garage drains, process area washdown,
sample flush drains, laboratory sinks, stormwater from oily
process areas, product wash water, stripped process sour water,
128
-------
Figure 17
Wastewater Treatment Configuration at the ARCO Refinery
Activated Sludge
Unit
Chlorinator
ro
ocm i uary
Stormwater
Process \
Observation
Channel
m*m
r
St
**•
••Ml
API
Separators
Water ,
i
Process
Water
Surge Pond
Storage Tank
Ballast ( }
Water \ j
Holding
ormwater Surge Basin Pon
Trickling
Filter
C^>
(J
Aeration Clarifier i
Basins T
>( } ,
( )
Clarification
Ponds
Discharge
-------
spent caustic, spent water from the crude desalter and con-
taminated ballast water flows into the oily water collection
system. The spent caustic will have already undergone pre-
treatment in the chemical treating unit, where most acidic
materials are neutralized. The crude desalter water, con-
taminated with crude oil and salt, contributes a large portion
to the loading of the process water treatment system. This
may be reduced by reusing stripped sour water for some of the
desalter water requirement. The overall process water system
is designed to have a normal operating holdup equivalent to
6-7 days of dry weather operation. The 2.4 million gallon
oily water surge pond adds an additional holding capacity of
one day ahead of the treatment system.
The initial treatment steps are primarily concerned with
smoothing the rate of flow and the most efficient removal of
oil. The oily water surge pond is available at the head of
the system to limit flow rates to values within the capacities
of the treatment equipment. The pH is controlled by metered
injections of sulfuric acid and caustic soda based on values
indicated by instruments continuously monitoring the pH. Two
API separators, operating in parallel, remove floatable oil.
In the forebay of the separators, first stage oil skimming is
provided. The main bays of the separators are also fitted
with skimmers, along with a sludge removal system. The skimmed
oil is collected in a sump for recovery and re-use in the
refinery. The sludge is de-oiled and de-watered for disposal.
From the API separator the wastewater passes into the trickling
filter.
The trickling filter makes up the first stage of the two stage
biological treatment unit. Effluent from the API separators
and a recycled flow from the filter itself are distributed
over the media bed. The air supply is obtained by natural
circulation. The effluent from the trickling filter is pumped
into the aeration basin. This is the first half of the activated
sludge unit. The effluent is aerated and mixed by three sur-
face aerators and digested by the microorganisms present. The
wastewater next flows into the clarifier for sedimentation of
contaminants. Some of the clarifier contents are recycled to
the aeration basin, while the clarified effluent passes on to a
pair of clarification ponds which provide additional settling.
Each pond has a capacity of 2.5 million gallons or more. The
two earthern ponds may be utilized in parallel or series and
minimize the solids content of the water entering the final
holding pond. The effluent flows from the clarification pond through
a baffled sluiceway to entrain air and increase the dissolved
oxygen content, prior to discharge to the final holding pond and
the outfall diffuser.
The sanitary water collection system carries wastes from all of
the sanitary facilities within the refinery to a completely
130
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separate treatment plant. The system is designed with a 200%
safety factor over the normal design criteria employed for
municipal waste treatment facilities and can handle any potential
peak flows. Physical treatment is supplied by a comminutor,
which grinds up the wastes. An activated sludge unit, com-
posed of an aeration basin and a clarifier, provides biological
treatment. Two aerators supply the tank where the wastes are
biologically consumed. The treated, clarified sanitary waste-
water is then chlorinated for disinfection and discharged into
the final holding pond with the rest of the refinery's treated
wastewater effluent.
The final holding pond serves as equalization basin for peak
flows and also provides an additional clarification of the
effluent. The effluent is then pumped about 2 1/2 miles through
pipe to the outfall diffuser. The diffuser lies under the re-
finery dock, over 2,100 feet offshore, 55 feet below the mean
lower low water level of the Strait of Georgia. The diffuser
is designed to mix the wastewater effluent in a ratio of one
part effluent to 99-139 parts of seawater, effectively dispersing
the effluent.
She!1. Shell's Anacortes refinery also has a large degree of com-
plexity for dealing with the wastewater generated in the plant
area and petroleum processes. Four major sewer systems handle
the wastewater and deliver it to the treatment facility. These
separate systems are: stormwater, chemical, sanitary and oily
process water. Each system contains wastewater with various
types and amounts of contaminants and receives different degrees
of treatment to insure the most efficient removal of the con-
taminants (see Figure 18).
The stormwater sewer system collects all surface runoff from
areas not subject to oil spillage. This uncontaminated water
does not require biological treatment and simply undergoes
physical treatment. The flow passes through a bar screen to
remove trash and debris and then enters an oil skimming basin.
The water is then discharged into the detention ponds, prior
to release to the marine environment. The chemical sewer system
receives dilute acid and caustic wash waters from the demineral-
izers used to soften the boiler feed water. These waters are
held in a pond for neutralization and are used for pH control in
the biological treatment processes. All of the sanitary wastes
go to a large septic tank where bacteria digest the solid
material present. The effluent from the septic tank is shock
treated with acid for coliform control, then joins the oily
water system prior to biological treatment.
The oily water sewer receives any water that is subject to
possible oil contamination. It also receives the skimmed and
steam stripped sour steam condensate from the boilers in the
steam system. Process wash water is treated in-plant and is
then routed to the oily water collection system. Cooling water
131
-------
ho
Figure 18
Wastewater Configuration at the Shell Refinery
Oily
Water'
Stonnwatei
Spent _
Caustic
^Disposal in Sea
""By Tanker
Discharge
-------
which is recycled in the cooling towers and ballast water from
tankers is processed in the oily water system. All precipita-
tion and surface washing from the refinery process areas are
also collected in the oily water sewers. "All of these contam-
inated waterwaters receive extensive treatment, both physical
and biological.
The oily water sewer empties into a two-channel API separator
for oil removal. The floatable oils are skimmed off and sedi-
ments settle into the sludge handling system. The skimmed oil
is collected in a sump where some of the water is removed and
returned to the separator. Periodically the oil in the sump
is passed on to the de-emulsifying tank and later to the slop
oil collection tank for two stages of settling. Eventually
the treated oil is returned to the refinery for reprocessing.
The*"retention time of the wastewater in the API separator is
about thirty-five minutes.
The skimmed water leaves the separator and passes on to the
primary clarifiers, for initial sedimentation of suspended
materials. The bottom sludge is removed frequently to maintain
efficient settling. The pH is also adjusted at this stage, by
the addition of waste dilute acid and caustic water. This
aids flocculation and later biological treatment. After forty
minutes, the wastewater leaves the clarifier and is joined by
the effluent from the septic tank for biological treatment.
The water entering the biological treatment processes has
diammonium phosphate added as a nutrient for the activated
sludge. For;fifteen minutes the wastewater is sprayed over the
media bed of the trickling filter. This aerates the water
enough to provide sufficient oxygen for the aerobic bacteria
residing on the media. From the trickling filter the waste-
water passes,on to the aeration basin. The basin itself is
divided into:four large sections with a retention time of
almost three hours. Jet nozzles aerate the basin, mixing the
air, water and activated sludge to provide maximum treatment.
The effluent from the aeration basin passes on to two final
clarifiers. These remove activated sludge and allow remaining
suspended solids to settle out. Thirty percent of the settled
material is recycled to the activated sludge basin for addi-
tional treatment and maintenance of the biological culture.
The remaining settled sludge is removed to the sludge handling
system for later disposal.
After three and a half hours the treated effluent leaves the
final, clarifiers for two large detention ponds, with a total
capacity of 11.5 million gallons. Over 96 percent of the BOD
has been removed, 99.6 percent of the phenols, 100 percent of
the sulfides, around 99 percent of the oil and an oxygen
residual of 7.5 ppm is established after the final treatment
processes. In the detention ponds the treated effluent is
joined by skimmed stormwater and analyzed for its water quality.
133
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If necessary the water is returned to the plant for additional
treatment. Otherwise the basin water passes through a hay
filter and is discharged into the bay 34 feet below low mean
tide during outgoing tides, to insure rapid dispersion of the
effluent.
Spent caustic containing around 15 percent NaOH is separated
and stored in a tank for later chemical recovery. Lower
strength caustic, usually less than 2 percent NaOH, is separated
and is either passed through the treatment plant or is disposed
of at sea. Sludge is collected from the API separator, pri-
mary clarifiers and the final clarifier for treatment and dis-
posal. The sludge is dewatered, filtered and incinerated.
d. Texaco. Wastewater at Texaco's March Point refinery is separated
into three sewer collection systems (see Figure 19). The storm-
water sewers receive water from boiler and steam generator blow-
down, backwash from the softening equipment and plant surface
runoff, all of which are relatively uncontaminated. Ballast
water from incoming vessels is collected in the ballast water
system. The process water sewers collect contaminated water
from the sour water strippers, cooling tower blowdown, sanitary
wastewater and other contaminants which have been neutralized
prior to release to the system.
The uncontaminated waters in the stormwater system receive
relatively simple treatment. A flume is used for trash removal
and an emergency oil skimmer is used to remove any oil that
might be present. The water then passes on to a 7.5 million
gallon storage pond prior to chlorination and final discharge.
Ballast water is released to the process water system or to
the stormwater sewers depending on the degree of treatment required.
All of the contaminated wastewater at the refinery is collected
in the process water sewers and receives extensive treatment.
The first treatment process is a two-bay API separator. It is
designed to handle peak flows and provides oil and sediment
removal. The sludge collected is periodically removed for
further treatment. The skimmed oil is pumped to the bottom
sediment and water (BS & W) tank for oil recovery and subsequent
reuse in the refinery. The discharge from the API separator
goes to the chemical clarifiers. A 0.12 million gallon surge
basin is available, along with a 2.2 million gallon overflow
basin, to handle any excessive peak or heavy flows. Lime, alum
and activated silica are normally added in the two clarifiers
to assist coagulation and sedimentation of suspended material.
Settled sludge is removed and pumped to the sludge thickener for
further treatment, while oily water skimmed from the surface is
returned to the API separator for more efficient oil removal.
Biological treatment of the wastewater is accomplished in two
stages. The effluent from the clarifier flows to a trickling
filter. Here, bacteria serve to remove organic material from
134
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00
01
Figure 19
Wastewater Treatment Configuration at the Texaco Refinery
-------
the water as it passes through the media bed. Oxygen is supplied
by the natural circulation of air through the filter bed. The
wastewater is usually recycled over the bed at least three times.
Two activated sludge units, operating in parallel, serve as the
second stage of biological treatment. The units are different
from conventional activated sludge units in that the aeration and
clarification are performed in a single unit. Here again,
microbiological organisms are used to treat the wastewater and
remove contaminants. During periods when nutrients are low in
the wastewater, ammonium phosphate is fed ahead of the biological
units to maintain the organisms in the two treatment processes.
Discharge from the activated sludge units passes on to two re-
tention ponds. These serve two major functions; continued oxida-
tion of phenols and isolation of the wastewater in case an upset
occurs in the treatment system and retreatment is necessary.
The water is retained in these ponds for about twelve hours.
The treated wastewater passes on to the storage pond, where it
is joined by the uncontaminated storm and ballast water. In
case of heavy flows, the treated water can be shunted to the over-
flow and surge basins. From the storage pond the treated effluent
flows through a hay filter to remove any remaining oil and is
chlorinated automatically prior to disposal at the refinery dock
during outgoing tides.
Sludge from various treatment units is thickened and filtered,
with the resulting sludge cake being incinerated. Oil from the
separators, from the ballast water tank and slop oil from the
refinery is collected in the emulsion-breaking and BS & W tanks
for oil recovery. Spent caustics are collected and regularly
pumped to a petrochemical plant for processing.
e. U.S. Oil & Refining. Wastewater from cooling tower blowdown,
boiler blowdown, asphalt process cooling water overflow system,
equipment cleaning water, process waters and stormwater are re-
ceived by the wastewater treatment system at the U.S. Oil & Re-
fining refinery. These are collected in a single sewer system
and delivered to the head of the wastewater treatment system
(see Figure 20). Drainage from tank areas enters a temporary
holding pond prior to entering the treatment processes. At the
present time sanitary wastewater is handled by septic tanks.
When the local sewer system is expanded, the refinery will tie
into it, in accordance with state permits. The sanitary facil-
ities at the refinery dock are already tied in to the sewer
system. No ballast water is received by the refinery from ships.
Wastewater from the process areas is all treated with emulsion
breaking chemicals and heat to enhance oil removal prior to
entering the API separators for seven hours for removal of oil
and particulates. A new corrugated plate separator is the
next step of wastewater treatment. This removes more oil, then
the water passes on to two rotating biological surface (RBS)
units where BOD is reduced and phenols are removed. The effluent
136
-------
Figure 20
Wastewater Treatment Configuration at the U.S. Oil and Refining Refinery
Sanitary
-^•Septic Tanks
Cooling Tower
Blowdown
Boiler
Slowdown
Stormwater
Process Water
Holding Pond
API
Separator
Corrugated
Plate
Separator
Rotating
Biological
Surface Units
"^"Discharge
Final Holding Ponds
-------
from these biological treatment units is clarified in two ponds
used as settling and holding ponds prior to discharge of the
final effluent into Blair Waterway. Water in these ponds can
also be returned to the head of the system should further treat-
ment be considered necessary.
f. Sound Refining. The wastewater treatment plant for Sound Refining,
Inc. receives wastewater from process areas, loading racks, storm
drains throughout the refinery and all tank area drains. Sani-
tary wastewater is not treated at the refinery site; instead it
is collected in the Tacoma sewer system and treated by the city's
municipal waste treatment plant. All other wastewater generated
at the refinery is collected in a single system and is treated
identically, regardless of source (see Figure 21). No ballast
water is received from ships.
The initial step of the treatment system is a holding pond into
which the various wastewaters flow by gravity. A portion of the
holding pond is divided into two separating chambers in which
oil is removed from the wastewater. The oil removed is collected
and stored in a tank for further treatment. The wastewater
passes on to the API separator, where additional oil removal
occurs. This oil is also collected in a small storage tank. The
recovered oil is heated to a low temperature for more oil and
water separation. The water from this procedure is returned to
the API separator for continued treatment with the rest of the
wastewater. The oil recovered in the storage tank is moved to
another area for further separation and is eventually returned
to the crude storage tanks for reprocessing. The effluent from
the API separator passes through a straw filter and is discharged
into Hylebos Waterway.
The refinery had been considering the addition of biological treat-
ment in the form of rotating biological surface units and polisher
units (providing final clarification). But a change in management
has halted the upgrading of the refinery wastewater treatment
methods. Potential changes in the refinery operations under the
new management will delay the addition of new treatment processes.
Consideration is being given to aerating the existing pond, add-
ing a corrugated plate API separator, rotating biological surface
units and a final clarifier to remove biological sludge, but no
definite plans have been made.
H. Refinery Wastewater Effluent Characteristics
1. Introduction.
The final treated effluent discharge from refineries still contains a
wide variety of chemical constituents and characteristics, despite the high-
ly efficient wastewater treatment processes employed. It is virtually
impossible for a treatment plant, utilizing physical and biological treat-
138
-------
Figure 21
Wastewater Treatment Configuration at the Sound Refining Refinery
Sanitary
City of Tacoma Municipal Sewer System
Process Units
Holding Pond
API
Straw
Filter
Loading Rack
Storm Drains
Tank Area Drains
separator
Discharge^
Seperating
Chambers
-------
ment processes (primary and secondary treatment), to eliminate completely
the particular pollutants arising from crude oil refining operations.
Even the most efficient processes will leave a low level concentration of
pollutants which will affect the water quality of the marine receiving
waters. Because a number of these chemical constituents may contribute a
significant quantity of pollutants to the marine environment, regulations
exist governing permissable levels of these parameters. Table 54 con-
tains a relatively detailed analysis of the effluent characteristics from
one of the Puget Sound refineries. Such in-depth reporting of effluent
water quality is not performed regularly. Each refinery is responsible
for monitoring its own effluent discharge and is principally concerned
with those parameters for which regulations exist.
2. Effluent Discharge Permits.
Regulations regarding allowable levels of specific water quality para-
meters are contained in National Pollutant Discharge Elimination System
(NPDES) discharge permits issued every three to five years to individual
refineries. The issuance of these NPDES permits formerly was handled by
the U. S. Army Corps of Engineers and is now under the control of the
Washington State Department of Ecology. Permit allocation levels for
specific pollutants in petroleum refinery wastewater effluent are estab-
lished in accordance with the refinery effluent limitation guidelines
developed and promulgated by EPA's Office of Air and Water Programs.
The Petroleum Industry Raw Waste Load Survey of 1972 (EPA/API Raw
Waste Load Survey) (10) was instrumental in the formulation of these
guidelines. Approximately 135 refineries nationwide were surveyed during
the 1972 study. In addition, five refineries utilizing activated sludge
treatment units were subjected to intensive sampling for identification
of wastewater treatment plant effluent performance. Five refineries in the
state of Washington (Sound Refining was not involved) were included in the
overall survey and the Shell refinery was subjected to an intensive exam-
ination of its wastewater treatment processes (which includes an activated
sludge unit).
Table 55 presents the data collected by the EPA survey team during March
and April of 1972 at the five Washington State refineries. Refineries are
classed by EPA according to the type of refining processes they employ.
Simple refineries which do not involve cracking processes, such as U.S. Oil
& Refining, are categorized as class "A" or "topping" refineries. Those
non-petrochemical refineries utilizing cracking processes are labeled class
"B"' refineries. Table 56 presents the results of the 14-day data and
sample collection and analyses of composite effluent samples from the Shell
refinery. This analysis shows pollutant levels after each of three treat-
ment processes: API separator, trickling filter, and activated sludge.
Minimum, average and maximum concentrations (in mg/1) are given, along with
the percent removal efficiency of the collective treatment processes.
Permit allocations are developed for each parameter on the basis of the
results of this survey, established toxicity levels for a particular pollu-
tant, the type of refining processes involved and the volume of the effluent
140
-------
Table 54
Effluent 0-ischarge Water Quality from a Puget Sound Refinery
Ave. Max.
pH 6.5 - 8.5 6.0 - 9.0
Temperature 70-75 °F 60-80 °F
Phenols, ppm 0.4 3.8 (Norm. Max. 1.0)
Total Oils, ppm 5-10 15
Sulfides, ppm 0 1
Mercaptans, ppm 0 0.5
Total Chromium, ppm 0.1 0.5
From Single Sampling
Alkalinity (as CaCOg), ppm 33
BOD 5-day, ppm 84
COD, ppm 10
Total Solids, ppm 600
Total Dissolved Solids, ppm 545
Total Suspended Solids, ppm 31
Total Volatile Solids, ppm 65
Ammonia, ppm 4.25
Kjeldahl Nitrogen, ppm 6.4
Nitrate, ppm 1.52
Phosphorus Total, ppm 0.01
Color, Pt-Co Units 4.5
Turbidity, Jackson Units 17
Total Organic Carbon, ppm 79
Total Hardness, ppm 104
Organic Nitrogen, ppm 3
Sulfate, ppm 38
Chloride, ppm 438
Cyanide, ppm <0.01
Fluoride, ppm 6
Aluminum-Total, ppb 400
Arsenic-Total, ppb <1
Cadmium-ota1, ppb <1
Calcium-Total, ppm 56
Copper-Total, ppb 48
Iron-Total, ppb 2000
Lead-Total, ppb <15
Nickel-Total, ppb <50
141
-------
Table 54 (cont.)
Potassium-Total, ppm 13
Sodium-Total, ppm 95
Zinc-Total, ppb 47
Fecal Streptococci Bacteria/100ml 270
Total Coliform Bacteria/100ml 52,000
142
-------
PARAMETER
Crude Capacity
(thousand barrels/day)
Crude Capacity on Day
of Sampling
(thousand barrels/day)
Water Discharged
(million gallons/day)
Gallons of Water
Discharged per Barrel
of Crude
BOD§
COD
TOC
Oil & Grease
Phenols
Suspended Solids
issolved Solids
Sul fides
Hexavalent Chromium
Ammonia
Organic Nitrogen
Nitrate Nitrogen
Acidity
Alkalinity
Phosphates
Cyanide
Chloride
Iron
Copper
Lead
Zinc
CLASS A:
U.S. Oil
20.0
24.5
0.9
3.67
1.43
3.37
1.36
1.21
0.1
3.9
16.3
.03
0.00
.01
.04
0.00
.92
3.06
.04
0.00
4.07
.06
0.00
0.00
0.00
CLASS B REFINERIES:
100.0
90.0
1.4
15.56
16.2
25.5
—
6.18
0.00
2.6
133.7
0.26
0.00
.16
.18
.24
1.75
3.85
.33
—
52.9
.04
0.00
.02
.027
Mobil
58.4
63.9
1.20
18.78
10.2
105.0
—
9.5
4.4
18.8
51.1
—
0.00
2.63
6.32
3.69
0.00
4.27
.08
.23
32.60
—
—
—
Shell
90.0
87.0
2.2
25.3
29.5
135.7
6.11
11.9
1.5
3.9
345.6
2.99
,10
.15
21.7
.14
0.00
41.8
.03
0.00
127.00
.06
.01
0.00
.01
Texaco
65.0
66.18
2.88
43.5
20.2
135.5
12.5
3.7
1.4
2.37
195.2
.07
.02
• 82.02
11.45
.40
10.1
126.1
.3
2.25
60.24
.5
.01
.22
.01
NATIONAL AVERAGES
(MEDIAN VALUES)
CLASS A
REFINERIES
—
18.0
2.9
13.3
2.5
3.13
.01
4.4
103.5
.03
0.00
.34
.04
.01
.96
.53
.02
.00
15.75
.06
0.00
0.00
0.0
CLASS B
REFINERIES
—
_ __
—
40.44
38.29
105.8
17.8
13.8
1.5
11.8
210.7
.34
.03
7.8
2.4
0.00
0.00
12.4
.08
.00
65.34
.22
0.00
0.00
.07
-f=-
CO
3Units for all chemical parameters are mg/1.
Table 55
1972 Data Collected in the
EPA/API Raw Waste Load Survey
on Five Puget Sound Refineries
Source: (10)
-------
Effluent**^^
Parameters ^s*>Vs^
BOD
COD
TOC
Oil and Grease
Suspended Solids
Dissolved Solids
Sul fides
Hexayalent Chromium
Ammonia
Organic Nitrogen
Nitrate Nitrogen
Acidity
Alkalinity
Phenols
Phosphates
Cyanide
Chloride
Iron
Copper
Lead
Zinc
Wastewater Treatment Processes
API Separator5
70-83-228
191-243-583
44-57-180
16-31-60
19-56-261
1050-1490-1860
17-24.3-31
1.5-1.8-2.6
98-127-160
.05-2.8-46.9
.03-. 48-. 95
.00-. 00-. 00
575-708-820
7.5-10.5-16
.08-. 16-. 57
1.2-1.5-2.5
374-556-796
.5 -.97- 44
.02-. 03-. 05
.00-.1-.2
.13-. 22-. 82
Trickling Filter
38-47-- 69
154-184-411
42-49-112
12-23-45
25-39-66
1230-1590-1840
.00 -.75-4. 8
0.9-1.3-2.7
89-108-140
.05-5.4-36.1
.4-. 53-. 75
.00-. 00- 22
158-201.5-340
.44-. 99-2. 6
.22-.3-.9
.17-. 25-. 62
333-431-650
1.0-1.5-28.5
0.02-.03-.03
.03-. 11-. 18
.16-. 29-1. 24
Activated Sludge§
16-19-26
102-130-201
29-37-62
9.0-17-31
6.0-25-83
1370-1615-1820
.00-. 275-. 8
.18-. 5~. 9
84-106-124
.05-6.0-26.0
.28-.38-.61
.00-. 00-26
166-191-227
.02-.035-.47
0. 09-. 16-. 36
.06-. 07-. 280
334-409-616
.44-. 88-1. 4
.02-. 03-. 045
.09-. 11-. 16
.07-. 16-1. 84
Percent Removal Efficiency
77.7%
44.7%
33.0%
44.8%
58.1%
L__ -17.7%
98.7%
73.0%
16.5% j
22.7% I
17.5% |
0.0%
72.2%
99.6% I
-1.4% 1
95.1%
19.2%
36.6%
00.0%
-12.4%
22.0%
Values are listed in the following order: minimum, average and maximum (in mg/1)
Source: (10)
Table 56
1972 Data Collected in the EPA/API Raw Waste
Load Survey on Wastewater Treatment Processes
Used at the Shell Refinery
-------
discharge. Each wastewater constituent which is considered to be harmful
is assigned an average and maximum level which is not to be exceeded in
the refinery effluent. Additional pollutant allocations are based on the
ballast and stormwater flows. Specific factors have been established for
certain water quality parameters (usually total suspended solids, biological
oxygen demand, chemical oxygen demand and oil and grease), which are then
multiplied by-the volume of ballast and stormwater flows to yield the
additional allowable levels of pollutants in the refinery effluent dis-
charge.
The parameters considered to be important by the state have been
modified and expanded within the past few years, and the new pollutant
allocations have been incorporated as the old permits expired and new ones
were issued. In the past, the parameters monitored in accordance with the
NPDES discharge permits included:
• Oil and Grease
• pH
• Sulfide
• Phenols
• Mercaptans
• Hexavalent Chromium
Sound Refining and U.S. Oil & Refining were exempted from reporting
levels of mercaptans. The new permits require that the following parameters
are monitored:
• Oil and Grease
• Total Suspended Solids (TSS)
• Ammonia (as Nitrogen)
• pH
• Sulfide
• Chemical Oxygen Demand (COD)
• Biological Oxygen Demand (BOD)
• Phenolic Compounds
• Hexavalent Chromium
• Total Chromium
145
-------
• Fecal Coliform
• Temperature
• Discharge Rate
Some of these parameters have gone unreported in the recent past;
however, modifications to the discharge permits in 1976 now assure the
monitoring of each parameter by Mobil, ARCO, Shell and Texaco. U.S. Oil
& Refining is also responsible for all of these parameters with the excep-
tion of temperature and fecal coliform. The quantity of oil and grease is
not always reported; however, it can be calculated from the reported con-
centration and the discharge rate. Sound Refining is the smallest refinery
and is essentially just a topping refinery--the crude oil is distilled
with very little additional processing. Hence it is not responsible for
all the same water quality parameters that the larger, more complex refin-
eries are.
In addition to changes concerning which parameters are measured, the
method of reporting pollutant levels has been altered. Prior to 1975,
permit allocations were totally concerned with the concentration of the
various pollutants. These were reported in mg/1. Since that time, emphasis
has shifted towards limiting the total amount of each pollutant dis-
charged by a refinery each day. The newly issued permits call for para-
meters to be reported in pounds per day. Oil and grease is the only para-
meter for which a concentration is also reported.
The NPDES discharge permits require each refinery to report the level
of pollutants measured in the refinery effluent at the end of each month.
Occasional spot-checks are made by representatives of the Department of
Ecology to ensure proper reporting of pollutant quantities. Tables 57, 58,
59, 60, 61, and 62 are summaries of the annual average and maximum levels
of pollutants for 1974, 1975, and 1976 in the effluent discharge from each
of the six Puget Sound refineries. Monthly average and maximum levels for
1974, 1975, and 1976, as reported in accordance with individual discharge
permits, are in tables in Appendix C.
3. Toxic Effluent Pollutants.
Five major harmful pollutants can be found in the effluent discharge
from petroleum refineries. These are phenols, sulfides, mercaptans,
hexavalent chromium, and oil. Phenols and phenolic compounds are both
acutely and chronically toxic to fish and other marine organisms. Many
phenolic compounds are more toxic than pure phenol, depending on which
combinations of compounds are present in the effluent. Phenols and pheno-
lic compounds have been reported to be toxic under some circumstances in
concentrations ranging from 1.0 to 10.0 mg/1. Lower concentrations may not
be lethal, but impart an unpleasant taste to fish flesh (tainting), de-
stroying its recreational and commercial value.
When present in water, sulfides can reduce pH, react with metallic
compounds forming precipitates, cause odor problems, and can be toxic to
marine life. The toxicity of sulfides increases as the pH decreases.
146
-------
Table 57
9
Summary of Annual Levels of Pollutants Present in the Wastewater Effluent of the Mobil Refinery
Parameter
Oil and Grease (cone.)
(quant.)
Total Suspended Solids
Ammonia (as Nitrogen)
pH
Sulfide
Chemical Oxygen Demand
Biological Oxygen Demand
Phenolic Compounds
Hexavalent Chromium
Total Chromium
Fecal Col i form
Temperature
Discharge Rate
1974
Average
12.9
108
27
0.8
4.0
0
167
52
0.19
<0.01
0.04t
5978
76
1.01
Maximum
I47t
1074
780
2.9
8.6
0
1040
426
2.5t
0.11
0.29t
32000
92
2.71
1975 1976
Average
8.1
71
266
7.2
6.9
0
829
179
1.04t
0.02
0.51t
2018
64
1.08
Maximum
26t
450
1800
22
8.5
0
2250
680
6.4t
6.9
2.7t
35000
80
3.51
Average
6.2
80
210
5.2
6.8
0
1097
m
0.89
0.01
0.52
206
55
1.36
Maximum
10
220
796t
27
7.7
0
4400t
340
6.2t
0.24t
2.72
700
70
2.93
f
'Exceeded appropriate permit levels
For 1974 all units are in mg/1 and for 1975-1976 all units are in Ibs/day, except; pH
temperature in °F), fecal coliform (in most probable number/100 ml) and discharge rate
gallons per day). Oil and grease concentration is reported in mg/1. Also pH is given
maximum, with no average value.
Source: (35)
(in pH units),
(in million
as minimum and
-------
Table 58
Summary of Annual Levels of Pollutants Present in the Wastewater Effluent of the Arco Refinery
§
Parameter
Oil and Grease (cone.)
(quant.)
Total Suspended Solids
Ammonia (as Nitrogen)
pH
Sulfide
Chemical Oxygen Demand
Biological Oxygen Demand
Phenolic Compounds
Hexavalent Chromium
Total Chromium
Fecal Col i form
Temperature
Discharge Rate
1974
Average
2.1
-
-
-
6.4
<0.1
-
-
<0.1
<0.02
-
-
-
2.38
Maximum
5
-
-
-
8.6
<0.1
-
-
<0.1
<0.02
-
-
-
7.64
1975
Average
-
50
459
118
5.9
0
659
256
0
0
0
0
46
4.07
Maximum
10.1
276
2665
884
8.8
0
4017
1313
0
0
0
0
62
9.1
1976
Average
-
55. .
288
21
6.5
0
404
187
0
0
0
0
51
2.08
Maximum
11.0
345
1637
225
8.4
0
4023
949
0
0
0
0
73
5.32
00
Source: (34)
3For 1974 all units are in mg/1 and for 1975-1976 all units are in Ibs/day, except; pH (in pH units),
temperature (in F), fecal coliform (in most probable number/100 ml) and discharge rate (in million
gallons per day). Oil and grease concentration is reported in mg/1. Also pH and temperature are
given as minimum and maximum, with no average value.
-------
Table 59
§
Summary of Annual Levels of Pollutants Present in the Wastewater Effluent of the Shell Refinery
Parameter
Oil and Grease (cone.)
(quant. )
Total Suspended Solids
Ammonia (as Nitrogen)
pH
Sulfide
Chemical Oxygen Demand
Biological Oxygen Demand
Phenolic Compounds
Hexavalent Chromium
Total Chromium
Fecal Col i form
Temperature
Discharge Rate
1974
Average
2.3
-
-
-
6.5
<0.1
-
-
0.06
0.005
-
-
-
1.85
Maximum
7.
-
-
-
8.1
<0.1
-
-
0.14
0.06
-
-
-
12.60
1975
Average
1.2
20
214
1330
6.4
<0.1
3537
291
0.51
0.08
0.79
42
63
1.99
Maximum
6
304
2752
5000t
9.0
<0.1
16394
1130
5.60
0.33
3.19
382
81
9.70
1976
Average
1.1
19.6
280
1314
6.0
<0.1
3882
345
0.50
0.07
0.71
29
58
2.08
Maximum
2
60
1970
5540t
8.6
<0.1
14900
1100
4.15
0.36
2.70
200
79
7.20
§
Source: (36)
For 1974 all units are in mg/1 and for 1976-1976 all units are in Ibs/day, except; pH (in pH units),
temperature (in °F), fecal coliform (in most probable number/100 ml) and discharge rate (in million
gallons per day). Oil and grease concentration is reported in mg/1. Also pH is given as minimum and
maximum, with no average value.
Exceeded approriate permit levels
-------
Table 60
I
Summary of Annual Levels of Pollutants Present in the Wastewater Effluent of the Texaco Refinery'
Parameter
Oil and Grease (cone.)
(quant. )
Total Suspended Solids
Ammonia (as Nitrogen)
PH
Sulfide
Chemical Oxygen Demand
Biological Oxygen Demand
Phenolic Compounds
Hexavalent Chromium
Total Chromium
Fecal Coli form
Temperature
Discharge Rate
1974
Average
4.8
-
-
-
6.5
<0.1
-
-
0.12
<0.1
-
-
-
3.41
Maximum
15
-
-
-
10. 5t
<0.1
-
-
2.0t
0.2t
-
-
-
12.38
1975
Average
2.6
66
423
970
6.3
0.4
1910
195
1.6
0.1
3.9
490t
53
2.93
Maximum
12
496t
6276t
3609t
9.0
5.1
11556
1565
10. 8t
1.9
13.1
2100t
85
4.31
1976
Average
2.8
70
327
187 .
6.0
0.4
1443
161
1.5
<0.1
3.2
0
55
2.94
Maximum
10
238
201 5t
1303
11. 7t
5.2t
4714
2549t
35. Ot
1.3t
19. 2t
10
77
-
tn
o
Source: (38)
^Exceeded appropriate permit levels
For 1974 all units are in mg/1 and for 1975-1976 all units are in Ibs/day, except; pH (in pH units),
temperature (in °F), fecal coliform (in most probable number/100 ml) and discharge rate (in million
gallons per day). Oil and grease concentration is reported in mg/1. Also pH and temperature are
given as minimum and maximum, with no average"value.
-------
Table 61
Summary of Annual Levels of Pollutants Present in the Wastewater Effluent of U.S. Oil & Refining
§
Parameter
Oil and Grease (cone.)
(quant.)
Total Suspended Solids
Ammonia (as Nitrogen)
pH
Sulfide
Chemical Oxygen Demand
Biological Oxygen Demand
Phenolic Compounds
Hexavalent Chromium
Total Chromium
Fecal Col i form
Temperature
Discharge Rate
1974
Average
13.1
-
-
-
6.5
< 0.1
-
-
0.64 ;
-
-
-
-
0.16
Maximum
38.8
-
-
-
8.0
0.1
-
-
1.73
-
-
-
-
0.18
1975
Average
13.9
-
61.7
2.1
6.5
0.11
117
63
0.27
< 0.015
0.25
-
-
0.16
Maximum
39. 7t
-
122.7
2.1
8.3
0.18
229
126
1.13
<0.015
0.25
-
-
0.22
1976
Average
13. 8t
-
32.8
1.6
6.5
0.14
107
40
0.31
0.013
0.49
-
-
0.17
Maximum
38. 6t
-
46.2
3.4
8.1
0.16
170
95
1.35t
0.015
1.14
-
-
0.19
t
Source: (39)
Exceeded appropriate permit levels
!A11 units for 1974 and 1975 (except December 1975) are in mg/1 and for 1976 (including December 1975)
all units are in Ibs/day, except; pH (in pH units) and discharge rate (in thousand gallons per day).
Also pH is given as minimum and maximum, with no average value.
-------
Table 62
Summary of Annual Levels of Pollutants Present in the Wastewater Effluent of the Sound Refining Refinery
§
Parameter
Oil and grease
PH
Sulfide
Phenols
Chemical Oxygen Demand
Biological Oxygen Demand
Discharge Rate
1974
Average
5.5
6.7
0.2
0.35
-
-
47.8
Maximum
11.8
8.4
0.5
0.86
-
-
99.4
1975
Average
6.1
6.8
0.3
0.41
195
39
41.4
Maximum
32. 6T
8.2
I.*
1.2
-
-
99.4
1976
Average
3.9
-
0.2
0.26
123
37
36.4
Maximum
12.0
-
0.6
0.92
-
-
107.8
en
Source: (37)
Exceeded permit levels
?\11 units are in mg/1, except; pH (in pH units) and discharge rate (in thousand gallons per day).
Also pH is given as minimum and maximum, with no average value.
-------
Studies have shown that sulfide concentrations of 1.0-6.0 mg/1 are toxic
to some species of fish. Mercaptans also lower the pH of the receiving
waters and cause extreme odor problems. Toxicity levels for mercaptans
have been found to be as low as 1.0-2.0 mg/1 in some studies.
Chromium may exist in refinery effluent in both the hexavalent and
trivalent state. The toxicity of chromium salts to marine organisms varies
greatly with the individual species, temperature, pH and specific inter-
actions with other water characteristics, particularly hardness. Hexavalent
chromium is the more toxic form of the chromium oxidation states. Fish are
relatively tolerant of chromium salts, but fish food organisms and other
forms of marine life are extremely sensitive. Marine planktonic algae
are also inhibited by hexavalent chromium. Generally, toxic levels of
hexavalent chromium are 5,0 mg/1 or less.
Oil and" grease compounds make their presence felt in the COD and BOD
because of the oxygen demand of these hydrocarbon compounds. Oil emulsions
adhere to the gills of fish or coat algae and other plankton, causing
death. Deposition of effluent oil content in the bottom sediments can
adversely affect benthic organisms and habitats. The water insoluble
components may exert toxic action on fish and other species, at concentra-
tions ranging from 1.0-20 mg/1 depending on the exact composition of the
oil and grease fraction.
No breakdown of this oil and grease measurement into specific hydro-
carbons or hydrocarbon classes is performed. The refineries are not re-
quired to monitor specific hydrocarbons, and the state agencies do not
make a detailed analysis of the oil and grease constituents when they spot-
check the refinery effluent. The standard analysis for oil and grease
was developed as a gross measure of potential water quality and sanitary
engineering problems. Originally, it was aimed at assessing the quantities
of animal fats and oils in municipal wastewater. The test is based on
solvent extraction by use of an organic solvent, such as hexane, petroleum
ether, carbon tetrachloride, chloroform, benzene or freon, and is pre-
dominantly for determining grease content. The analysis is further
complicated by the fact that low-boiling fractions are lost in the usual
oil and grease analysis. For example, kerosene and gasoline content cannot
be determined by the normal petroleum ether extraction method which is
used for measurements in natural waters, and is the most common method
used by the refineries. Thus, the accuracy of the report values for oil
and grease content in refinery effluent discharges is not necessarily high
and probably does not reflect the actual hydrocarbon content.
The effects of refinery effluents depend on many factors other than
the obvious ones of effluent constituents and volume. The siting of the
outfall, the type of receiving area (rock, mud, sand or saltmarsh) and
its associated community of plants and animals, and the movements and
quality of the receiving water all must be considered. Different eco-
systems differ in their capacity to receive and degrade effluents, and
the speed of dispersion and dilution is a major factor determining the
amount of biological damage. Changes in distribution and abundance of
species are often very localized and in some cases may result from
behavioral responses rather than direct toxic effects. Most undiluted
153
-------
refinery effluents can be shown to be harmful in the long term; however,
they are not usually acutely toxic. They can cause sub-lethal effects
such as changes in metabolic rate or behavior. Such effects over a long
period of time may help to explain population changes near effluent dis-
charges.
Bioassays utilizing undiluted effluent and water samples from the area
of discharge have been performed since 1971 by the Washington Department
of Fisheries and in recent years by the refineries themselves. These have
yielded widely variable results, although most frequently there have been
no indications of lethality to the test organisms (Coho and Chinook salmon
and oyster embryos). However, it should be noted that the refinery
effluents constitute a chronic discharge of hydrocarbons, regardless of
the fact that oil removal efficiencies of different refinery wastewater
treatments plants range from 95 to 99.99 percent. Most of these wastewater
treatment processes are not effective in removing soluble hydrocarbons,
particularly aromatics. Thus, an apparently efficient system which reduces
the total oil content to as little as 5-20 mg/1 could still contain greater
than 1.0 mg/1 of soluble aromatic hydrocarbons, a sufficient concentration
to cause sub-lethal effects and, for the most sensitive organisms, direct
lethal effects. Tables 63, 64, 65, 66, 67, and 68 are summaries of the
annual average and maximum levels of these five toxic pollutants which
are present in the wastewater discharges from the six Puget Sound refineries,
154
-------
Table 63
Summary of the Annual Levels of Toxic Pollutants Present in
the Wastewater Effluent at the Mobil Refinery
Parameter
Oil and Grease (cone. )
(quant. )
Phenols
Sul fides
Mercaptans
Hexavalent Chromium
1974
Average
12.9
108
1.63
0
0
0.02
Maximum
147
1074
16. 8t
0
0
0.78t
1975
Average
8.1
71
1.04
0
0
0.02
Maximum
26
450
6.4t
0
0
6.9t
1976
Average
6.2
80
0.89
0
0
0.01
Maximum
10
220
6.2t
0
0
0.24t
en
en
t
Exceeded NPDES permit levels.
All units are in Ibs/day, except oil and grease concentrations (mg/1).
-------
Table 64
Summary of the Annual Levels of Toxic Pollutants Present in
the Wastewater Effluent of the ARCO Refinery
Parameter
Oil and Grease (cone.)
(quant. )
Phenols
Sul fides
Mercaptans
Hexavalent Chromium
1974
Average
2.1
§
<0.1
<0.1
<0.1
<0.02
Maximum
5
§
<0.1
<0.1
3.2
<0.02
1975
Average
§
50
0
0
5
0
Maximum
10.1
276
0
0
§
0
1976
Average
§
55
0
0
§
0
Maximum
11.0
345
0
0
§
0
tn
Ov
Values not reported.
Units for 1974 are in mg/1, while all units for 1975 and 1976 are in Ibs/day.
-------
Table 65
Summary of the Annual Levels of Toxic Pollutants Present in
the Wastewater Effluent of the Shell Refinery
Paramater
Oil and Grease (cone.)
(quant.)
Phenols
Sul fides
Mercaptans
Hexavalent Chromium
1974
Average
2.3
§
0.06
.< 0.1
< 0.1
0.005
Maximum
7
§
0.04
<0.1
<0.1
0.06
1975
Average
1.2
20
0.51
<0.1
§
0.08
Maximum
6
304
5.50
<0.1
1
0.33
1976
Average
1.1
19.6
0.50
<0.1
§
0.07
Maximum
2
60
4.15
<0.1
§
€.36
en
v-J
§-,
Values not reported.
Units for 1974 are in mg/1, while all units for 1975 and 1976 are in Ibs/day.
-------
Table 66
Summary of Annual Levels of Toxic Pollutants Present in
the Wastewater Effluent of the Texaco Refinery
Parameter
Oil and Grease (cone.)
(quant.)
Phenols
Sul fides
Mercaptans
Hexavalent Chromium
1974
Average
4.8
§
0.12
<0.1
<0.1
<0.1
Maximum
15
§
2.0
<0.1
0.5
0.2
1975
Average
216
66
1.6
0.4
§
0.1
Maximum
12
496t
10. 8t
5.1
§
1.9
1976
Average
2.8
70
1.5
0.4
§
<0.1
Maximum
10
238
35. Of
5.2t
§
1.3t
tn
OO
^Values not reported
Exceeded NPDES permit levels.
Units for 1974 are in mg/1, while all units for 1975 and 1976 are in Ibs/day.
-------
Table 67
Summary of Annual Levels of Toxic Pollutants Present in
the Wastewater Effluent of the U.S. Oil & Refining Refinery
Parameter
Oil and Grease (cone.)
(quant.)
Phenol s
Sul fides
Mercaptans
Hexavalent Chromium
1974
Average
13.1
§
0.64
<0.1
§
§
Maximum
38.8
§
1.73
0.1
§
§
1975
Average
13.9
§
0.27
0.11
§
<0.015
Maximum
39. 7t
§
1.13
0.18
§
<0.015
1976
Average
13. 8t
§
0.31
0.14
§
0.013
Maximum
38. 6t
§
1.35t
0.16
§
0.015
01
10
§
Values not reported
Exceeded NPDES permit levels.
Units for 1974 and 1975 are in mg/1, while all units for 1976 are in Ibs/day.
-------
Table 68
Summary of Annual Levels of Toxic Pollutants Present in
the Wastewater Effluent of the Sound Refining Refinery
Parameter
Oil and Grease (cone.)
(quant.)
Phenols
Sul fides
Mercaptans
Hexavalent Chromium
1974
Average
5.5
§
0.35
0.2
§
§
Maximum
11.8
§
0.86
0.5
§
§
1975
Average
6.1
§
0.41
0.3
§
§
Maximum
32. 6t
§
1.2f
1.4t
§ '
§
1976
Average
3.9
§
0.26
0.2
§
§
Maximum
12.0
§
0.92
0.6
§
§
^Values not reported
TExceeded NPDES permit levels.
All units are in mg/1.
-------
III. REFERENCES AND BIBLIOGRAPHY
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