EPA-600/2-77-023C
January 1977
Environmental Protection Technology Series
flflii>A
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into five series. These five broad
categories were established to facilitate further development and application of
environmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The five series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to develop and
demonstrate instrumentation, equipment, and methodology to repair or prevent
environmental degradation from point and non-point sources of pollution. This
work provides the new or improved technology required for the control and
treatment of pollution sources to meet environmental quality standards.
EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental
Protection Agency, and approved for publication. Approval
does not signify that the contents necessarily reflect the
views and policy of the Agency, nor does mention of trade
names or commercial products constitute endorsement or
recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/2-77-023c
January 1977
INDUSTRIAL PROCESS PROFILES
FOR ENVIRONMENTAL USE:
CHAPTER 3. PETROLEUM REFINING INDUSTRY
by
J.C. Dickerman, T.D. Raye, J.D. Colley, andR.H. Parsons
Radian Corporation
P.O. Box 9948
Austin, Texas 78766
Contract No. 68-02-1319, Task 34
ROAPNo. 21AFH-025
Program Element No. 1AB015
EPA Project Officer: I.A. Jefcoat
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
nt 0 "^o'c^iori Agency
K<-':-3?r>.V. I ,.)!•:.y
-;i."l'. ;rn Surest
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TABLE OF CONTENTS
CHAPTER 3
Page
INDUSTRY DESCRIPTION [[[ 1
Raw Materi al s ............................. . ......................... 2
Products [[[ 4
Compani es [[[ 8
Environmental Impact ................................................ 10
Bibliography [[[ 14
INDUSTRY ANALYSIS [[[ 15
• Crude Separati on ......................... • ................. . ......... 16
Process No. 1. Crude Storage ..................................... 18
Process No. 2. Desalting ......................................... 19
Process No. 3. Atmospheric Distillation .......................... 21
Process No. 4. H2S Removal ....................................... 24
Process No. 5. Sulfur Recovery ................................... 25
Process No. 6. Gas Processing .................................... 27
Process No. 7. Vacuum Distillation ........ . ...................... 28
Process No. 8. Hydrogen Production ............................... 30
Light Hydrocarbon Processing ........................................ 32
Process No. 9. Naphtha Hydrodesulfurization ...................... 34
Process No. 10. Catalytic Reforming ............................... 36
Process No. 11. Isomerization ..................................... 38
Process No. 12. Alkylation ........................................ 40
Process No. 13. Polymerization .................................... 43
Process No. 14. Light Hydrocarbon Storage and Blending ............ 45
Middle and Heavy Distillate Processing ......... . .................... 47
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TABLE OF CONTENTS (Continued)
CHAPTER 3
Page
Process No. 19. Hydrocracking .................................... 60
Process No. 20. Lube Oil Processing .............................. 62
Process No. 21. Lube and Wax Hydrotreating ....................... 64
Process No. 22. Middle and Heavy Distillate Storage and Blending. 66
Residual Hydrocarbon Processing ..................................... 68
Process No. 23. Deasphalting ..................................... 70
Process No. 24. Asphalt Blowing .................................. 72
Process No. 25. Residual Oil Hydrodesulfurization ................ 73
Process No. 26. Visbreaking ...................................... 75
Process No. 27. Coking ........................................... 77
Process No. 28. Residual Hydrocarbon Storage and Blending ........ 79
Auxiliary Processes ................................................. 80
Process No. 29. Wastewater Treating ................ ! ............. 81
Process No. 30. Steam Production .................................. 84
Process No. 31 . Process Heaters .................................. 86
Process No. 32. Pressure Relief and Flare Systems ................ 88
APPENDIX A - Crude Oil Analyses ..................................... 91
APPENDIX B - Properties and Characteristics of Petroleum Products... 123
APPENDIX C - Companies Comprising the Industry ...................... 137
APPENDIX D - Hazardous Chemicals Potentially Emitted from Process
Modules ................................................ 145
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LIST OF FIGURES
CHAPTER 3
Figure Page
1 Refinery Crude Separation 17
2 Refinery Light Hydrocarbon Processing 33
3 Refinery Middle and Heavy Distillate Processing 48
4 Refinery Residual Hydrocarbon Processing 69
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LIST OF TABLES
CHAPTER 3
Table Page
1 Crude Capacity of U.S. Refineries 3
2 Properties of Crude Oil 5
3 Major Petrol euro Products, 1973 6
4 Capacities of the 10 Largest Refiners 9
5 Potential Sources of Atmospheric Emissions Within
Refineries 12
6 Comparison of Emissions from Petroleum Refining with Total
U.S. Industrial Point Source Emissions for Selected Pol-
lutants During 1972 13
A-l Hydrocarbons Isolated from a Representative Petroleum (Ponca
City, Oklahoma Field) 92
A-2 Properties of United States Crude Oils 96
A-3 Trace Element Content of United States Crude Oils 103
A-4 Sulfur and Nitrogen Content of the Giant U.S. Oil Fields... 108
A-5 Sulfur and Nitrogen Content of Crude Oils from Nations
Which Export to the U.S 115
B-l Gasoline Requirements 124
B-2 Schedule for Geographical Seasonal Variations in Gasoline
Requi rements 125
B-3 Average Properties of Jet Fuels Sold in the U.S 126
B-4 Approximate Properties of 20 Representative Naphthas 127
B-5 Uses of 20 Representative Naphthas 128
B-6 Average of Selected Properties of Central Region Diesel
Fuel s 129
B-7 Characteristics of Three Grades of United States Fuel Oils. 130
B-8 Characteristics of Residual Heating Oils 130
B-9 Properties of Kerosene, Tractor Fuel, and Related Products. 131
B-10 Range of Physical Properties of Lubricating Oils 132
B-l 1 Characteristics of Greases 133
B-12 Comparison of Wax Types Produced in the United States 134
B-13 Specifications for Asphalt Cement of the Asphalt Institute.. 135
B-14 Properties of Petroleum Cokes 136
C-l Complete List of United States Refineries by Companies 138
D-l Hazardous Chemicals Potentially Emitted from Process Modules 146
VI
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PETROLEUM REFINING INDUSTRY
INDUSTRY DESCRIPTION
The petroleum refining industry is involved primarily in the conversion of
crude oil into more than 2500 products including liquefied petroleum gas,
gasoline, kerosene, aviation fuel, diesel fuel, a variety of fuel oils,
lubricating oils, and feedstocks for the petrochemical industry. By defini-
tion, petroleum refinery activities start with crude oil storage and terminate
with storage of the refined products. Production of gas and oil and trans-
portation and distribution of the products are normally considered' part of
other industries.
Crude oil is the major raw material processed in a refinery. Data published
in the 5 April 1976 Oil and Gas Journal indicated that as of 1 January, 1976
the processing capacity of the United States petroleum refining industry was
over 2.26 million cubic meters per day. The chemical composition of crude
oil varies widely depending on its source. It is largely a mixture of paraf-
finic, naphthenic, and aromatic hydrocarbons plus small amounts of sulfur,
nitrogen, oxygen, and various metals. The chemical composition of the crude
oil being processed will determine, in part, the product slate from a particu-
lar refinery. For example, a paraffinic crude will tend to produce better
lube oil stocks than will a naphthenic crude and is thus the favored feedstock
for that product.
The refining industry has been divided into four operations involving dif-
ferent types of processes. These are (1) Crude Separation, (2) Light Hydro-
carbon Processing, (3) Middle and Heavy Distillate Processing, and (4)
Residual Hydrocarbon Processing. Detailed discussions of each operation
and its component processes including flow diagrams are presented in a
later section. Auxiliary processes were not included on the process flow
sheets but are discussed as a separate segment.
Some of the processes involved in the manufacture of refinery products are
distillation, absorption, extraction, thermal and catalytic cracking, iso-
merization and polymerization. Flow diagrams have been prepared which il-
lustrate the sequence in which these processes interact to produce refinery
products. Few, if any, refineries employ all of these processes. Some of
the processes are representative of a limited size range of refineries and
are designed for a particular crude oil.
Larger refineries do, however, use most of these processes. American re-
fineries typically use more processes than foreign refineries, as they are
generally designed to maximize motor gasoline production. European refineries
generally maximize production of heating fuels. Complex American refineries
generally produce a minimum of residual oil. Fuel oil for the U.S. East
Coast is produced predominately in Caribbean refineries which have minimum
facilities for motor gasoline production.
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Gasoline accounts for about one-half of the refining industry product output.
Other fuels such as jet fuels, kerosenes, distillate fuels and residual fuels
account for most of the remaining product output. Liquefied petroleum gas
(LPG), sometimes called liquefied refinery gas (LRG), is produced widely for
industrial and domestic use in areas where natural gas is not available.
Asphalts and coke are produced in relatively small amounts. Petrochemical
feedstocks, which are generally composed of olefins, LPG's, and aromatic
hydrocarbons, account for only a small percent of the output from the industry.
The petroleum refining industry has been expanding at the rate of about four
percent by year. Table 1 presents historical data on the growth of the U.S.
petroleum refining industry. Future growth rates may largely depend on U.S.
government policy on importation of crude oil versus importation of refined
products.
One trend in this industry is the increasing dependence on imported crude oils.
In 1971 only about 270,000 cubic meters per day (1.7 million barrels per day)
of imported crude were consumed, while in 1973 over 510,000 cubic meters per
day (3.2 million barrels per day) were used. During the first six months of
1976 an average of 780,000 cubic meters per day (4.9 million barrels per day)
were imported. The imported crude oils generally contain a higher percentage
of sulfur than do domestic crude oils and tend to be more corrosive. These
and other differences in the crudes will necessitate many processing modifi-
cations before most domestic refineries can process the high sulfur imported
crudes.
Another trend is toward the production of non-leaded high octane motor gasolines,
Expansion of processing units which produce high octane blending stocks, such
as catalytic reforming units, may be anticipated to meet this growing demand.
Refineries are located in 39 states with most of the refining capacity found
near the coasts. There is considerable variation in the size of refineries,
and production rates range from 500 cubic meters per day to more than 64,000
cubic meters per day.
Energy requirements for the operation of a refinery are large. It has been
estimated that a modern U.S. refinery designed to maximize motor gasoline
production will consume energy equivalent to seven percent of the energy con-
tained in the raw crude oil*. Electricity consumption requires about two
percent of the total input energy, and process heat requirements account for
the remaining five percent.
Raw Materials
In 1973, 1.5 million cubic meters of domestic crude and 510,000 cubic meters
of imported crude were processed each day. In addition, 270,000 cubic meters
Based on a 31,800 m3/day (200,000 bpd) crude throughput with a crude heating
value of 8.9 x 106 kcal/m3 (5.6 x 106 Btu/bbl).
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TABLE 1. CRUDE CAPACITY OF U.S. REFINERIES
YEAR*
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
CAPACITY
hm3
1.662
1.771
1.832
1.932
2.016
2.081
2.128
2.260
2.360
2.397
PER CALENDAR DAY
Thousands
of Barrels
10452
11142
11523
12155
12681
13087
13383
14216
14845
15075
* as of January 1 of the year indicated
Source: Oil and Gas Journal, Annual Refining Issues
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of natural gas liquids were consumed Natural gas liquids are condensed
light hydrocarbons (Cn-C8) which come directly from the producing well. Many
other materials are used by this industry in much smaller quantities. Examples
are alkyl lead for gasoline production; additives for lube oil production, such
as detergents, viscosity index improvers, and anti-oxidants; barium compounds
for diesel fuels; and caustic, sulfuric acid, amines, hydrofluoric acid, and
clay.
It has been reported that over 3,000 different chemical compounds may be
present in crude petroleum. Petroleum is a mixture of paraffinic, naphthenic,
and aromatic hydrocarbons containing varying amounts of sulfur, nitrogen, and
oxygen along with a small amount of ash which contains inorganic materials.
While it is difficult to describe a "typical" crude due to its chemical
diversity, ranges for elemental composition and physical properties can be
determined and are presented in Table I. Detailed crude oil compositions
are shown in Appendix A.
Some of the inorganic materials contained in the ash such as iron, nickel, and
vanadium act as a poison to catalysts. As the metal accumulates on the catalyst,
the activity of the catalyst decreases. Crudes with high metal concentrations
require more frequent catalyst regeneration resulting in more frequent atmos-
pheric emissions from this source.
Sulfur in the crude is the source of all sulfur dioxide emissions from a re-
finery. Emissions of sulfur dioxide result from firing sulfur bearing fuels
(derived from the crude) in the plant boilers and furnaces and from incinera-
tion of the tail gas from the sulfur recovery plant. The trend toward a greater
use of high sulfur imported crude increases the sulfur dioxide emissions prob-
lem. Sulfur may be present as free sulfur, hydrogen sulfide, or in organic
compounds such as thiophenes, mercaptans, and alkyl sulfudes. Mercaptans
produce a strong odor and are often oxidized to disulfides to reduce the odor
v:hen sulfur removal is not practiced. Sulfur also increases the corrosive
characteristics of both the crude and its products.
Products
Approximately 2500 products are produced wholly or in part from petroleum. Most
of these products are blends of several refinery streams. In 1973 the U.S. de-
mand for refined products was a record 2.7 million cubic meters per day. Al-
though the components can vary widely, refinery products can be classified into
one of several categories: fuels, lube oils, and so forth. Table 3 lists the
major petroleum products and their production in 1973. Properties and
characteristics of the major petroleum products are shown in Appendix B.
Refinery products vary widely with location, climate, and season. For example,
winter brings a higher demand for heating fuel oils. Also winter gasoline must
contain a higher percentage of volatile products to enhance cold weather starts.
Summer weather requires a reduction in the volatile components to decrease the
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Table 2. PROPERTIES OF CRUDE OIL
Elemental Composition
Carbon
Hydrogen
Sulfur
Nitrogen
Oxygen
Ash*:
Iron Copper Molydenum
Calcium Manganese Lead
Magnesium Strontium Tin
Silicon Barium Sodium
Aluminum Boron Potassium
Vanadium Cobalt Phosphorous
Nickel Zinc Lithium
Physical Properties
Specific Gravity
Typical Yields, TBP Distillation
C4 & Lighter, < 15.6°C
LSR Gasoline & Naphtha, 15.6-193°C
Kerosene, 193-288°C
Light Gas Oil, 288-343°C
Heavy Gas Oils, 343-538°C
Residuum, 538°C +
Range (%)
83-87
11-14
0-5
0-0.88
0-2
.01-. 05
°API
12-49
Volume %
0-3
25-45
10-25
5-15
20-30
5-25
Elements in the ash are presented in decreasing concentrations.
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Table 3. MAJOR PETROLEUM PRODUCTS, 1973
Product
Gasoline
Distillate Fuel Oil
Residual Fuel Oil
Liquefied Gases
Jet Fuel
Asphalt
Still Gas for Fuel
Ethane (includes ethyl ene)
Petrochemical Feedstocks
Coke
Kerosene
Lubricants
Special Naphthas
Waxes
Road Oil
Miscellaneous Products
Production
m3/day
1,068,000
490,000
444,000
178,000
167,000
79,500
77,000
52,000
57,100
41,500
34,300
25,800
14,200
3,000
3,500
8,300
2,743,200
Percent of
Total Products
39
18
16
7
6
3
3
2
2
1
1
0.9
0.5
0.1
0.1
0.4
100.0
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likelihood of carburetor vapor lock and minimize vaporization losses. Refineries
must be sufficiently flexible to meet these varying demands.
As the size of a refinery increases, the number of products increases, and the
processing operation becomes more flexible. The production rate of each of the
products can be varied significantly by making relatively minor changes in
refinery processing conditions. Hydrocarbon fractions can be shifted from one
product to another to meet product demands.
Gasoline is by far the major product of this industry. Its production rate
is nearly one-half of the total industry output, and its value is more than
one-half of the value of all products sold. Finished gasoline is a blend of
products from several refinery processes including straight run and cracked
gasolines, reformed naphthas, alkylates, isomerates and butanes. Gasoline
also includes several minor additives such as alkyl leads, dyes, antioxidants
and detergents, usually purchased from other industries. The high octane
rating necessary for good engine performance is obtained from aromatic hydro-
carbons and branched-chain paraffinic and naphthenic compounds. Butane and
isopentane have high octane ratings, but the amount of these compounds in
gasoline is limited by their high volatility. No-lead and low-lead gasoline
production requires an increased use of aromatic hydrocarbons to obtain high
octane fuels. The environmental effects of combustion of high aromatic fuels
have not been fully defined.
Light diesel oils distill in the 188-315°C range and can have a wide range of
specifications. Their performance is described by a cetane rating that refers
to the ignition characteristics of the oil in a diesel motor. Fuels with a
good cetane rating are used for diesel fuel, while those with a poor rating
are used to produce burner fuel.
Distillate fuels have boiling ranges similar to diesel oils. Any oil that can
be distilled either in the crude still or in the vacuum still and oils of
similar boiling ranges from various refinery processes are used as fuel oil.
Generally, some of the oil is treated to remove sulfur. Distillate fuel is
widely used for domestic heating.
Residual oils are the bottoms product from atmospheric or vacuum distillation.
They frequently contain high concentrations of potential pollutants. While it
is not current practice to desulfurize residuals in the U.S., some commercial
processes are available and in operation. Some residual oils are blended
with kerosene or light gas oils to reduce viscosity and sulfur concentration
and used as boiler fuel in steam and electric power generation facilities
(No. 5, No. 6, Bunker C fuel oil).
Other residuals are charged to coking, visbreaking, or asphalt processes.
Coking converts residuals into naphthas and gas oils for further processing.
The petroleum coke residue of this process is used in metallurgical processes,
if it is low sulfur, or as a fuel. Visbreaking improves viscosity without
significantly altering the boiling range. Asphaltic base crude oil residuals
are processed to recove the asphalts which are used with rock (aggregate)
as a cement in road pavement, for manufacture of roofing materials, and for
other applications.
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Liquefied petroleum gas (LPG) is a mixture of C2, C3, and d» hydrocarbons. It
is widely used for industrial heating and for domestic heating and cooking where
natural gas is unavailable or scarce. Natural gas companies frequently add
LPG to natural gas at times of peak demand. LPG is an excellent motor fuel with
a high octane rating and minimum air pollutant emissions. It is occasionally
used for truck or bus fleets. LPG is quite widely used for fork lifts, pay-
loaders, and other applications inside buildings where low engine emissions
are important. Sometimes the designation LPG is restricted to a product of
the natural gas industry. When that restriction is made, the same material
made by the petroleum industry is referred to as liquefied refinery gas (LRG).
Petrochemical feedstocks supplied by refineries include olefins, LPG, and
aromatic compounds. In addition, naphtha is cracked in a thermal cracking
process to produce ethylene. Ethylene production is performed in both re-
fineries and petrochemical plants. Petrochemical feedstocks account for only
a small percentage of the refining industry's production; only about two
percent of production in 1973 was petrochemical feedstocks.
Jet aircraft fuels are of two basic types: a kerosene type which boils in the
188-260°C range and a naphtha type boiling in the 121-260°C range. Special
quality control measures are required for jet fuels as engine failure could
be catastrophic. Wax removal is required to reduce the freezing point and
aromatic removal is employed to reduce smoking.
Kerosene is a petroleum fraction which boils in the 177-288°C range. It was
one of the first petroleum fractions to be produced and was used as lamp oil.
Various chemical sweetening processes were developed to remove mercaptans from
kerosenes to reduce odor problems. Kerosene is used today only in small-scale
applications such as domestic cooking.
Companies
As of 1 January 1974 there were 142 companies which comprised the U.S. petro-
leum refining industry. These companies operated 247 refineries in 39 states.
Table 4 lists the 10 largest refiners and the production capacity of each
along with the combined capacity of the other 169 refineries. A complete
listing by company of the production capacities of all 247 refineries is
found in Appendix C.
Many of these companies are also involved in related industries such as the
petrochemicals industry which uses refinery products as feedstocks. Petro-
chemical plants often border refineries to permit an easy exchange of products
These plants often generate by-product materials similar to refinery intermedi-
ate products which are then sold to the refinery.
As is shown in Appendix C, many refineries have crude capacities of less than
800 cubic meters per day (5,000 barrels per day). Operation of these small
refineries is generally economically favored only by production of specialty
items, lube oils, or asphalts.
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TABLE 4. CAPACITIES OF THE TEN LARGEST REFINERS
Company
Exxon
Shell
Texaco
Amoco
Standard Oil of
California
Mobil
Gulf
ARCO
Union Oil
Sun Oil
All Others
TOTAL
Number of
Refineries
5
8
12
10
12
8
8
6
4
5
169
247
Crude
Capacity
m3/day
199,068
176,331
172,197
169,335
156,456
148,188
136,835
125,578
77,433
76,956
824,448
2,262,825
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Environmental Impact
The petroleum refining industry produces gaseous, solid, and liquid pollutants.
Air emissions are by far the largest emission problem of the industry. The
major air pollutants emitted are particulates, hydrocarbons, carbon monoxide,
sulfur oxides, and nitrogen oxides.
There are very few process units which directly emit gases to the atmosphere.
The major refining process units which do emit gases directly to the atmosphere
are the catalytic cracking units, the sulfur recovery processes, and storage
tanks. Many processes employ heaters which contribute combustion emissions directly
to the atmosphere. Virtually all of the refinery's NO emissions result from
process heaters. Particulate and SO emissions from tfiese heaters are dependent
upon the chemical composition of the fuel and are generally low.
Fugitive emissions are another source of atmospheric pollutants. These sources
include pump seals, valves, relief vents, and leaks in vessels and pipe walls.
It is difficult to quantify these emissions as they do not occur at one partic-
ular source or location. Potential fugitive emissions could occur from the
thousands of valves, seals, pumps, etc., found throughout the refinery.
Attempts have been made, however, to estimate the extent of these emissions.
These estimates indicate that fugitive emissions are the largest source of air
pollution from a refinery.
Table 5 is presented to provide a listing of the main process contributors of
each atmospheric pollutant. These processes are described individually in later
sections. Table 6 presents a summary of the estimated atmospheric emissions
produces by the refining industry along with an estimate of U.S. emissions for
comparison.
The major sources of liquid effluents are oil and grease in condensed steam
from various processes, cooling water from various processes, tank cleaning
wastes, spent chemicals, waste caustics containing cresylic acids and sulfides
from gas treating, lead wastes from doctor treating and product storage, and
oil spills. The technology of treating refinery water streams is well estab-
lished. Basic water cleanup processes commonly found in refineries are oil
water separators, sour water strippers, sedimentation for suspended solids, acid
base neutralization, and biological oxidation. The objective of several
recently completed or in-progress studies is the characterization of aqueous
wastes from individual or combined process streams. The effluents from activ-
ated carbon and activated sludge water treatment processes, API separators, and
stripping units are among the liquid wastes being studied. State-of-the-art
investigations for the refinery industry have also been prepared. Analytical
methods are being developed under separate studies. Although many compounds
are present in the liquid effluent from a particular process, they are generally
either eliminated or reduced to an acceptable level before the water is dis-
charged from the refinery.
A petroleum refinery generates a wide variety of solid wastes. Catalyst fines
from cracking units; coke fines; iron sulfide; clay filtering media; and
10
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sludges from tank cleaning operations, oil-water separators, and biological
oxidation processes are typical solid wastes. These wastes are generally
land-filled or incinerated. Spent catalysts that are not worth processing for
recovery of valuable components are an intermittent solid waste stream.
Typical components of waste catalysts include aluminum, cobalt, nickel, and
titanium compounds. Spent catalysts are generally landfilled. Construction
activity also generates a large volume of solid wastes. The Office of Solid
Waste Management Programs is currently sponsoring an investigation of the
wastes and disposal methods for this industry; these results will be available
in the near future.
The refining industry is also a potential emitter of some hazardous compounds.
Studies are currently underway which attempt to define an approach for
analyzing the hazardous compounds emitted from refineries. A list of several
hazardous compounds along with their potential emission sources is presented
in Appendix D.
11
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Table 5. POTENTIAL SOURCES OF ATMOSPHERIC EMISSIONS WITHIN REFINERIES
Type of Emission
Source
Particulates
Sulfur Oxides
Nitrogen Oxides
Hydrocarbons
Carbon Monoxide
Odors
Catalytic Cracker, Fluid Coking,
Catalyst Regeneration, Process
Heaters, Boilers, Decoking Opera-
tions, Incinerators
Sulfur Recovery Unit, Catalytic
Cracking, Process Heaters, Boilers,
Decoking Operations, Unit Regenera-
tions, Treating Units, Flares
Process Heaters, Boilers, Catalyst
Regeneration, Flares
Storage Tanks, Loading Operations,
Water Treating, Catalyst Regenera-
tion. Barometric Condensers, Process
Heaters, Boilers, Pumps, Valves,
Blind Changing, Cooling Towers,
Vacuum Jets
Catalyst Regeneration, Decoking,
Compressor Engines, Incinerators
Treating Units, Drains, Tank Vents,
Barometric Condensers, Sumps, Oil
Water Separators
12
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TABLE 6. COMPARISON OF EMISSIONS FROM PETROLEUM REFINING
WITH TOTAL U.S. INDUSTRIAL POINT SOURCE
EMISSIONS FOR SELECTED POLLUTANTS DURING 1972
Total Industrial Process Total Emissions From the
Point Source Emissions Petroleum Refining Industry
Gg/yr Gg/yr
Particulate
sov
X
CO
HC
8413
6132
15862
5858
81
2015
1950
1873
.6b
a 1972 average crude run: 1,860,000 m3/day (11,696,000 bbl/day).
b based on particulate emission control factor of 60 per cent.
Compiled from data contained in:
R.D. Ross, Air Pollution and Industry, Van Nostrand
Reinhold Co., N.Y. (1972), p. 207.
American Petroleum Institute, Annual Statistical Review,
Petroleum Industry Statistics, 1965-1974, Washington D.C.
(1975). p. 31.
Environmental Protection Agency, 1972 National Emissions
Report, National Emissions Data System (NEDS) of the Aero-
metric and Emissions Reporting System (AEROS), EPA 450/2-74-012,
REsearch Triangle Park, NC (1974) p. 1.
13
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Bibliography
1. American Petroleum Institute, Annual Statistical Review, Petroleum
Industry Statistics 1964-1973, Washington, D.C., 1974.
2. "Annual Refining Survey", Oil and Gas Journal, 1 April 1974.
3. Burlingame, A. L., Private Communication, University of California,
Berkeley, May 1975.
4. Environmental Protection Agency, 1972 National Emissions Report.
National Emissions Data System (NEDS) of the Aerometric and Emissions
Reporting System (AEROS), EPA 450/2-74-012. Research Triangle Park.
N.C., (1974).
5. Gruse, W. A., and D. R. Stevens, Chemical Technology of Petroleum,
Third Edition, New York, McGraw-Hill, 1960.
6. "Hydrocarbon Processing Refining Processes Handbook", Hydrocarbon
Proc. 53(9), (1974).
7. Keith, L. H., Private Communication, EPA, Southeast Research Lab.,
8 May 1975.
8. Loop, Gary C., Refinery Effluent Water Treatment Plant Using Activated
Carbon. EPA 660/2-75-020, Ada, Oklahoma, Robert S. Kerr Environmental
Research Laboratory, NERC, EPA, 1975
9. Meyers, Leon H., Robert S Kerr Environmental Research Laboratory,
EPA, Ada, Oklahoma, Personal Communication, September 1975.
10. Nack, H., et al., Development of an Approach to Identification of
Emerging Technology and Demonstration Opportunities, EPA 650/2-74-
048, Columbus, Ohio, Battelle-Columbus Labs., 1974.
11. Pierce, Alan, Office of Solid Waste Management Programs, EPA,
Cincinnati, Ohio, Personal Communication, September 1975.
12. Radian Corporation, A Program to Investigate Various Factors in
Refinery Siting, Final Report, Contract No. EQC 319, Austin, Texas,
1974.
13. Reid, George W. and Leale E. Streebin, Evaluation of Waste Waters
from Petroleum and Coal Processing. EPA R2-72-001, Ada, Oklahoma,
Robert S. Kerr Environmental Research Center, EPA, 1972.
14. Sims, Anker V., Field Surveillance and Enforcement Guide for Petroleum
Refineries, Final Report, EPA 450/3-74-042, NTIS Publication No.
PB 236-669, Contract No. 68-02-0645, Pasadena, California, Ben Holt Co.,
1974.
14
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INDUSTRY ANALYSIS
Data for the industry analyses are presented in five sections. The order of
presentation is (1) Crude Separation, (2) Light Hydrocarbon Processing,
(3) Middle and Heavy Distillate Processing, (4) Residual Processing, and
(5) Auxiliary Units.
Each of the five segments is divided into component process modules, and
each module is described in detail. The Crude Separation segment describes
crude oil handling and distillation processes which split the crude into three
broad fractions: light hydrocarbons, middle and heavy distillates and residual
oils. Light hydrocarbons are defined for this report as naphtha boiling range
and lighter fractions. Residual oils are defined as crude distillation.bottoms
or residue. Middle and heavy distillates are the fractions boiling between the
naphtha range and the residuals. These distillates include kerosenes, gas oils
and lube stocks. Auxiliary units are described in a separate segment for con-
venience and clarity of presentation.
The first four areas discussed above are depicted graphically in Figures 1
through 4 with module inter-relationships schematically presented. Each figure
immediately follows its respective industry segment description. Each process
within a particular segment is discussed in the section immediately following
the figure on which it is shown. The various processes within a refinery have
been numbered consecutively from 1 to 32. The numbers assigned to the modules
on the process flow sheets correspond to the process numbers given the module
descriptions.
Within each module description, data have been presented on operating variables,
utility requirements, and associated waste streams. In most cases a range of
data is given rather than a precise figure, since variables depend on product
split desired, chemical composition of crude feedstock, product purity require-
ments, and several other factors. Therefore, ranges of data more nearly describe
the industry as a whole. The data are considered reliable and accurate.
15
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Crude Separation
Crude separation is a term used to describe those processes which directly
and indirectly separate crude oil into a variety of intermediate products.
These intermediate products are used as feedstocks for downstream refinery
processing units. There are eight process modules included in crude separa-
tion. Of these eight modules, four are directly involved with crude oil pro-
cessing and four process crude oil indirectly. These modules are shown sche-
matically in Figure 1.
The four modules which process crude oil directly are crude storage, desalt-
ing, atmospheric distillation, and vacuum distillation. These processes con-
tribute significantly to both air and water emissions from a refinery.
The four modules which process crude indirectly are H2S removal, sulfur
recovery, gas processing, and hydrogen production. Of these, only the sulfur
recovery process produces a significant emission stream. Its off gases are
considered to be the largest sulfur air emission source in a refinery. The
other three processes contribute air emissions only through process heaters
and fugitive leaks. Water emissions from these processes are not considered
significant.
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CRUDE SEPARATION PROCESS NO. 1
Crude Storage
1' Function - The purpose of crude storage is to provide a surge capacity
and reservoir during periods when crude deliveries may be irregular.
Storage is also used for segregation of varying quality crudes since
different quality crudes undergo different processing steps. Typical
storage capacities are between a two-week and a two-month supply of
crude oil. The storage tanks also provide a residence time to allow
water to settle out from the crude.
Crude oil is generally stored in large cone roof tanks with capacities
up to 40,000 m3 (250,000 bbl). Floating roof tanks are now being used
for storage of light volatile crudes. From storage, the oil is sent to
the desalters and then to crude distillation.
2. Input Materials - Raw crude oil from production wells is the feed to
crude storage operations.
3. Operating Parameters -
Temperature: Ambient
Pressure: Atmospheric
4. Utilities - Utility requirements are low.
All electricity is used in pumping the crude to and from the storage
tanks.
5. Waste Streams - Both liquid and atmospheric emissions result from
crude storage. Liquid effluents consist of about 12 liters water per
cubic meter of stored crude and contain dissolved salts. Atmospheric
emissions result from evaporative hydrocarbon losses associated with
pumping the crude into and out of the tanks. These emissions consist
predominantly of light hydrocarbons. Estimates of working losses are
0.88 kg hydrocarbon per 103 liter throughput, and breathing losses
are estimated to be 0.02 kg per 103 liter storage capacity.
6. EPA Source Classification Code - None exists.
7. References -
(1) Nack, H., et al., Development of an Approach to Identification
of Emerging Technology and Demonstration Opportunities, EPA
650/2-74-048, Columbus, Ohio, Battelle-Columbus Labs., 1974.
(2) Radian Corporation, A Program to Investigate Various Factors
in Refinery Siting, Final Report, Contract No. EQC 319, Austin,
Texas, 1974.
(3) Environmental Protection Agency, Compilation of Air Pollutant
Emission Factors, 2nd Ed., AP-42, Research Triangle Park, N.C.,
1973
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CRUDE SEPARATION PROCESS NO. 2
Desalting
1. Function - The desalting unit is generally the first processing unit
in a crude oil refining scheme. This process is used to remove salt,
water, and water soluble compounds from the crude, as these compounds
can eventually result in equipment fouling, corrosion, or possible
catalyst poisoning in downstream processing units.
Water is added to the incoming raw crude and thoroughly mixed. The
wet crude is then heated to break emulsions and the water and dis-
solved impurities are separated. Separation is accomplished by physical
decanting and electrostatic coalescing. The separated water is col-
lected and sent to the waste water treating system, and the desalted
crude is preheated and sent to the atmospheric distillation column.
2. Input Materials - The feed to the desalting unit is crude oil from
storage.
3. Operating Parameters -
Temperature: 38-155°C (100-300°F)
Pressure: 2.8+ kg/sq cm (40+ psi)
4. Utilities -
Thermal Energy: 34,800 kcal per m3 of crude charge (22,000 Btu/bbl)
may be obtained by heat exchange with a hot stream
from the distillation column or by process heaters
Electricity: .063 kWh/m3 - used to run pumps and the coalescer
Process Water: 35-60 liters per m3 of crude charged (1.5-2.5 gal/bbl)
Waste Streams - A liquid effluent composed of the feed water inlet plus
the salts picked up by the water is released from this unit. Water to
the unit is usually fresh water plus sour water from other units. The
effluent rate is about 47 liters per m3 of oil processed. The largest
waste water contaminants are dissolved solids (average concentration
3700 ppm) which are composed largely of chlorides, sulfates, and bi-
carbonates. Oil, phenols, and sul fides are also found, but in lesser
concentrations. Average concentrations for these pollutants are 169,
15, and 4 ppm, respectively. Desalter effluent is dumped to the sewer
or waste water system.
6. EPA Source Classification Code - None exists.
19
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7. References
(1) "Hydrocarbon Processing Refining Processes Handbook",
Hydrocarbon Proc. 53_(9), (1974).
(2) Nack, H., et al . , Development of an Approach to Identification
of Emerging Technology and Demonstration Opportunities. EPA
650/2-74-048, Columbus, Ohio, Battelle-Columbus Labs., 1974.
(3) Radian Corporation, A Program to Investigate Various Factors
in Refinery Siting, Final Report, Contract No. EQC 319,
Austin, Texas, 1974.
20
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CRUDE SEPARATION PROCESS NO. 3
Atmospheric Distillation
1. Function - Atmospheric distillation involves the physical separation
of hydrocarbon components into fractions or intermediates of a specified
boiling temperature range by distillation and steam stripping. The
major processing equipment items include the heat exchanger preheat
train, direct fired furnace, atmospheric fractionator, and side stream
product strippers.
Desalted crude is preheated in the heat exchanger train by recovering
process heat. The preheated crude is then charged to a direct-fired
furnace where additional heat is supplied to achieve partial vaporization
of the crude petroleum. Both the liquid and vaporized portions are
charged to the atmospheric fractionator at a temperature of about
344 to 371° C (650 to 700° F).
The crude charge is separated into several petroleum fractions within
the atmospheric fractionator. A naphtha and lighter stream is taken
from the tower overhead where it is condensed, and the non-condensable
light ends are treated and/or recovered in other refinery units. Several
liquid side-stream fractions are withdrawn from the fractionator at
different elevations within the tower. These fractions are charged
to the side-stream product strippers where lighter hydrocarbons are
stripped from these fractions and returned to the fractionation tower.
The stripping medium is either steam, light petroleum gases, or
reboiler vapors. In addition to the side-stream strippers, the
atmospheric fractionator has a bottoms stripping zone whereby lighter
hydrocarbons are steam stripped from the residual product.
The fractions withdrawn from the atmospheric tower are progressively
heavier as they are taken at successively lower points from the fraction-
ator. However, the end point of the heaviest side-stream product closely
corresponds to the crude's temperature as charged to the fractionator.
Fractionator bottoms (topped crude) is the heaviest petroleum fraction
and is the charge to the vacuum distillation unit.
The intermediate products are naphtha, kerosene, distillate or diesel
oil, gas oil and topped crude. The naphtha is blended into motor fuels
or any of several of the refinery products, or further processed to
improve octane rating and/or reduce sulfur content. The kerosene may
be chemically sweetened or hydrogen treated and sold directly or sent
to blending. The distillate or diesel oil may be sold for diesel or
fuel oil, hydrogen treated, hydrocracked, catalytically cracked, or
blended. The gas oil may be sold as fuel oil, hydrogen treated, hydro-
cracked, catalytically cracked, or blended. The topped crude is usually
the feed to the vacuum distillation process although it may be sold for
fuel, blended into fuels, hydrogen treated, or catalytically cracked.
01
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2. Input Materials - Desalted crude is the feedstock to this unit.
3. Operating Parameters - The following conditions are typical of the
fractionator:
Pressure: Atmospheric
Temperature: 120°C - at top of fractionator
370°C - at fractionator bottom
These are rather large processing units with capacities up to
39,000 m3/day (240,000 bpd).
4. Utilities -
Electricity: 2.5 kWh per m3 charge
Steam: 143 kg per m3 charge - used for stripping
Heaters: 158,000 kcal per m3 charge
Cooling Water: 690 liters per m3 charge
5. Waste Streams - Atmospheric distillation is a closed process with only
fugitive air emissions and those associated with the process heaters
which will be covered in a later section. A sour water effluent is
produced from the condensed stripping stream. The effluent rate is
dependent upon the amount of stripping steam employed. The primary
contaminants in the foul condensate are sulfides and ammonia (each
about 4000 ppm) while phenols and other soluble hydrocarbons may be
present in smaller amounts.
6. EPA Source Classification Code - None exists.
7. References -
(1) Hydrocarbon Processing Refining Processes Handbook", Hydrocarbon
Proc. 53_(9), (1974).
(2) Nack, H., et al., Development of an Approach to Identification
of Emerging Technology and Demonstration Opportunities, EPA
650/2-74-048, Columbus, Ohio, Battelle-Columbus Labs., 1974.
(3) Radian Corporation, A Program to Investigate Various Factors
in Refinery Siting, Final Report, Contract No. EQC 319, Austin,
Texas, 1974.
(4) Watkins, R. N., "How to Design Crude Distillation", Hydrocarbon
Proc. 48(12), 1969.
22
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CRUDE SEPARATION PROCESS NO. 4
H2S Removal
1. Function - The acid gas removal unit is designed to remove hydrogen
sulfide from hydrocarbon gases by absorption in some aqueous,
regenerate sorbent. A number of qas treatment processes are
available, and they are distinguished primarily by the regenera-
tive sorbent employed. Amine-based sorbents, however, are most
commonly used.
The feed to the unit is contacted with the sorbent, such as
diethanolamine, in an absorption column to selectively absorb
H2S from the hydrocarbon gases. Hydrogen sulfide is then removed
from the sorbent in a regeneration step. The products are a sweet
hydrocarbon gas and a concentrated hydrogen sulfide stream. The
sweet gas may either be further processed in light end recovery
processes or may be charged as a raw material to other refinery
or petrochemical processes. The hydrogen sulfide stream is
normally routed to a sulfur plant for recovery of its sulfur
content.
2. Input Materials^ - Sour hydrocarbon gases from various processing
units constitute the feed to the acid gas removal unit. Refinery
processes which produce substantial quantities of these gases
are: crude distillation, hydrodesulfurization, catalytic cracking,
thermal cracking and hydrocracking.
The sorbent used to remove hydrogen sulfide is also a feed to this
unit. It is generally regenerate, and make-up rates are usually
quite low.
3. Operating Parameters - The following conditions are typical of
absorber operations:
Pressure: 10.5 kg/sq cm
Temperature: 38°C
4. Utilities -
Electricity: .022 kWh/kg removed gas
Steam: 0.8-1.6 kg/kg removed gas
Cooling Water: 45-82 liters/kg removed gas
5. Waste Streams - No atmospheric emissions, other than fugitive emissions,
are produced from this unit. Liquid effluents are produced as spent
amine solutions which must be replaced; about 4 liters per 159 m3 (1 gal/
1000 bbl) for diethanolamine. Usually, a small quantity of amine solution
23
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is continuously lost from the circulating system by entrainment in
the absorber. The lost amine solution is removed from hydrocarbon
streams in knockout vessels and becomes part of the liquid effluent.
The amount of waste is proportional to the amount of hydrogen sulfide
removed from refining streams and, therefore, depends upon the amount
of sulfur in the crude and the extent to which the products are
desulfurized.
6. EPA Source Classification Code - None exists.
7. References -
(1) "Hydrocarbon Processing Refining Processes Handbook",
Hydrocarbon Proc. 53_(9), (1974).
(2) Nack, H., et al., Development of an Approach to Identification
of Emerging Technology and Demonstration Opportunities, EPA
650/2-74-048, Columbus, Ohio, Battelle-Columbus Labs., 1974.
(3) Radian Corporation, A Program to Investigate Various Factors
in Refinery Siting, Final Report, Contract No. EQC 319, Austin,
Texas, 1974.
24
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CRUDE SEPARATION PROCESS NO. 5
Sulfur Recovery
1. Function - A sulfur recovery plant converts hydrogen sulfide to
elemental sulfur by controlled combustion and reactions occuring in
a series of catalytic beds. In the Claus sulfur recovery process,
the feed is first combusted with substoichiometric amounts of air
to form sulfur and water. The off gas is cooled, and sulfur is
condensed as a liquid. About sixty to seventy percent conversion
occurs in the furnace.
The remaining gases are reheated and passed through catalytic
reactors. Each reactor has an effluent condenser where the elemental
sulfur is recovered. Reheat of reactor effluent is necessary for sul-
fur recovery in subsequent reactors. The number of reactors varies
with the conversion desired and with the H2S concentration. Fifty to
sixty percent of the remaining sulfur is converted in each reactor
stage so that two to four reactors are required.
The unconverted H2S leaves the process in a tail gas stream and is
either further processed or incinerated to remove the last traces
of reduced sulfur compounds. The sulfur recovered by this process
is sold as a refinery by-product.
2. Input Streams - H2S from the acid gas removal plant and H2S from sour
water stripper systems comprise the feed to the sulfur plant. The
amount of sulfur reaching the sulfur recovery unit varies with sulfur
in the crude and the extent of desulfurization. Typically 60% of the
sulfur entering with the crude reaches the sulfur recovery plant.
3. Operating Parameters - The following conditions are typical of those
found in the reactors:
Temperature: 245°C
Pressure: 1-2 Atm
A bauxite catalyst is most commonly employed for this process.
4. Utilities
Heater: 2220 kcal/kg sulfur
Steam: 4 kg/kg sulfur - generated in a waste heat boiler. The steam
produced in a sulfur recovery plant can provide 5-30% of the total re-
finery steam requirements.
5. Waste Streams - The sulfur compounds which are not converted to
elemental sulfur in the sulfur recovery plant are possible air con-
taminants. Possible sulfur emissions are S02, H2S, COS, CS2, and
mercaptans. After incineration all sulfur compounds theoretically
25
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should be converted to S02. but in actual practice they are not.
Sulfur dioxide concentration in the effluent tail gas is approxi-
mately 15,000 ppm. A 15,900 m3/day (100,000 bpd) refinery with a
1% sulfur crude and a 95% efficient sulfur plant will produce
4500-5400 kg/day (5-6 ton/day) of sulfur emissions.
In recent years, environmental concerns have led to the installation
of tail gas cleanup units which further reduce the SOa concentration
to approximately 500 ppm, thus representing an overall sulfur re-
covery efficiency of 99.8+%. The above hypothetical refinery with
a 99.8% overall sulfur recovery plant would emit 150-180 kg/day
(0.17-0.20 ton/day) of sulfur.
There is no wastewater stream since all water formed remains in the
vapor state and is exhausted with the flue gases. There are only
minor solid wastes associated with disposal of the spent catalyst.
Catalysts are generally regenerable and require disposal only in-
frequently (once every two years).
6. EPA Source Classification Code - None exists.
7. References -
(1) Nack, H., et al., Development of an Approach to Identification
of Emerging Technology and Demonstration Opportunities, EPA
650/2-74-048, Columbus, Ohio, Battelle-Columbus Labs., 1974.
(2) Radian Corporation, A Program to Investigate Various Factors
in Refinery Siting, Final Report, Contract No. EQC 319, Austin,
Texas, 1974.
26
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CRUDE SEPARATION PROCESS NO. 6
Gas Processing
1. Function - The function of gas processing is to recover various hydro-
carbons as purity products or as mixtures of specified composition, for
use in other refinery processes, as gasoline blending components and
for sales. The separations are accomplished by absorption and/or distil-
lation. The recovery processes utilized depend on the products desired.
Gas processing units are used to produce fuel gas, methane, ethane,
propane, propylene, normal and isobutane, butylene, normal and isopen-
tane, amylene and/or a light naphtha.
2. Inout Materials - Feed to gas processing units is provided by crude
distillation, catalytic reforming, catalytic cracking, hydrocracking,
thermal cracking and, to a lesser extent, hydrodesulfurization. Many
refineries also process natural gas liquids as a separate input stream.
3. Operating Parameters - The operating parameters vary significantly
for this process depending upon the products recovered. Temperatures
as low as -73°C are required to obtain an ethane cut and high pres-
sures, 25.2 kg/sq cm (360 psi), are used in absorbing propane.
4. Utilities -
Electricty: 12.5 kWh/m3 of feed - used for compressing the gases.
5. Waste Streams - Gas processing is a closed process with no air emis-
sions except from process heaters. The possibility of fugitive leaks
always exists. Liquid effluents associated with caustic and water
scrubbing of product streams are produced. These wastes are treated
in neutralization and waste water treating facilities.
6. EPA Source Classification Code - None exists.
7. References -
(1) Nack, H., et al., Development of an Approach to Identification
of Emerging Technology and Demonstration Opportunities, EPA
650/2-74-048, Columbus, Ohio, Battelle-Columbus Labs., 1974.
(2) Radian Corporation, A Program to Investigate Various Factors
in Refinery Siting, Final Report, Contract No. EQC 319, Austin,
Texas, 1974.
27
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CRUDE SEPARATION PROCESS NO. 7
Vacuum Distillation
1. Function - Vacuum distillation separates the atmospheric residue
from the crude still into a heavy residual oil and one or more
heavy gas oil streams. Vacuum fractionation is employed to avoid
the extremely high temperatures that would be necessary to pro-
duce these heavy distillates by atmospheric fractionation.
Vacuum fractionators are maintained at approximately 30-150 mm Hg
absolute pressure by either steam ejectors or mechanical vacuum
pumps. These vacuum systems are designed to remove non-condensable
hydrocarbon vapors, which are produced by thermal cracking of the
reduced crude charge heating.
Vacuum distillation is accomplished in one or, occasionally, two
fractionation stages. Reduced crude is heated in a direct-fired
furnace and charged to the vacuum fractionator. Product specifi-
cations and dispositions will vary with crude type and refinery
design. Vacuum distillation plus stream stripping is used to pro-
duce narrow boiling range lube oil stocks for further processing.
Steam stripping is not required in the fractionation of vacuum
distillates for catalytic cracking or visbreaking feedstocks.
The intermediate product from the vacuum distillation process may
be used for several purposes. Its ultimate use will be determined
by the crude feedstocks and the subject refinery design. In some
cases it may be sent to the asphalt plant; a different crude feed
might dictate that the intermediate product be sent to a coker to
be thermally cracked into a gasoline feedstock. Still other pos-
sible routings of the intermediate product are to send it to a vis-
breaker for cracking into a distillate fuel or to send it to a
hydrotreater to remove sulfur for further upgrading. The choice
of these options may be limited by the crude characteristics and/
or the existing refinery design.
With suitable feedstocks, the residuals from vacuum distillation may
be sent to the lube oil plant either directly or through a hydrogen
treating process. Other distillates are treated similarly to the
gas oil stream from the crude still and catalytically hydrocracked,
catalytically cracked, or used as fuel oil.
2. Input Materials - Feed to this unit is topped crude from the atmos-
pheric still.
3. Operating Parameters - Typical vacuum column operating conditions
are:
-------
Pressure: 30-150 mm Hg absolute
Temperature: 400°C
4. Utilities
Steam: 22.8 kg/m3 - used for vacuum ejectors and stripping
Heaters: 79,400 kcal/m3 charge
Electricity: 0.63-1.26 kWh/m3 charge - used for pumping
5. Waste Streams - Steam vacuum ejectors create both air and liquid
emissions.The non-condensable vapors removed by these systems
must be discharged. It is reported that these non-condensable
vapor emissions may be as much as 370 kg per 1000 m3 of vacuum
unit charge. In addition hydrocarbon vapors escaping from baro-
metric condenser hot wells will also contribute to the air
pollution problem. Atmospheric emissions from process heaters
also occur and will be discussed in a later section. Modern
refineries will attempt to eliminate hydrocarbon emissions re-
sulting from the use of steam ejectors by (1) discharging
non-condensable vapors to furnace fire boxes for combustion, and
(2) replacing barometric condensers with surface condensers
when steam ejectors are used.
Aqueous wastes result from condensation of steam used for (1)
stripping during vacuum fractionation, and (2) maintaining
fractionator vacuum by ej-ectors or vacuum jets. Potential
contaminants include hydrogen sulfide, phenols, plus soluble
and emulsified oils. The quantity of the effluent is equal
to the amount of steam used during vacuum distillation, about
23 kg/m3 charge. Aqueous effluents from this process can
be eliminated if steam stripping is not utilized and if a
mechanical vacuum system rather than a steam ejector is utilized.
6. EPA Source Classification Code - None exists.
7. References -
(1) Nack, H., et al., Development of an Approach to Identification
of Emerging Technology and Demonstration Opportunities, EPA
650/2-74-048, Columbus, Ohio, Battelle-Columbus Labs., 1974.
(2) Radian Corporation, A Program to Investigate Various Factors
in Refinery Siting, Final Report, Contract No. EQC 319, Austin,
Texas.
29
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CRUDE SEPARATION PROCESS NO. 8
Hydrogen Production
1. Function - Hydrogen is a by-product from several refining processes.
One of the most common is catalytic reforming, which produces hydro-
gen that is available as feed for other processes. However, a re-
finery with a large distillate hydrotreater or gas oil hydrocracker
will require additional high purity hydrogen.
A steam-hydrocarbon reforming process is commonly used for hydrogen
production. Hydrocarbons (ranging from methane to naphtha) and steam
are catalytically reacted in a high-temperature reactor. The gas
from the reactor contains hydrogen, steam, carbon monoxide, and
carbon dioxide, and is passed through a shift reactor where CO and
H20 are catalytically reacted to form carbon dioxide and more hydrogen,
Steam-hydrocarbon reforming will probably be replaced by partial
oxidation of heavy oils as a method of hydrogen production. The
light hydrocarbons used as feed for the steam-hydrocarbon reforming
process are more economically suited for use in other processing
units such as alkylation and catalytic reforming.
2. Input Materials - Feed to this unit consists of a desulfurized
light hydrocarbon stream ranging from methane to light naphtha.
Most of the feed is produced in the naphtha hydrodesulfurization
unit and the acid gas removal unit.
3. Operating Parameters - The following conditions are typical of the
reformer section:
Temperature: 760-870°C
Pressure: 20.3 kg/sq cm
A nickel _catalyst is commonly employed in the reformer, and an
iron catalyst is used in the shift reactor.
4. Utilities -
Heaters: 475,000 kcal/m3 feed
Electricity: 25 kWh/m3 of feed - used for compression and pumping
5. Waste Streams - This closed process produces no air or liquid
emissions other than fugitive emissions from leaks. Process
heaters are employed. Air emissions from heaters will be
discussed in a separate section.
6. EPA Source Classification Code - None exists.
30
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7. References -
(1) Beavon, David K. and T. R. Roszkowski, "Modern Hydrogen Manufacture",
Proc. Amer. Chem. Soc., Div. of Petroleum C51 (1971).
(2) "Hydrocarbon Processing SNG/LNG Handbook", Hydrocarbon Proc.
52 (4), (1973).
(3) Radian Corporation, A Program to Investigate Various Factors
in Refinery Siting, Final Report, Contract No. EQC 319,
Austin, Texas.
(4) Voogd, 0. and Jack Tielrooy, "Improvements in Making Hydrogen",
Hydrocarbon Proc. 46(9), 115(1967).
31
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Light Hydrocarbon Processing
Light hydrocarbon processing is a term chosen to represent those separation
methods and molecular rearranging techniques used to upgrade the octane
ratings of naphthas and all lighter hydrocarbons. The improved products
from each of the individual processing units (or modules) are stored and then
used in gasoline blending. There are six process modules included in light
hydrocarbon processing. Of these six modules, four are direct conversion
units, one is a preparation unit, and one a storage and blending unit.
These are shown schematically in Figure 2.
The four direct conversion modules are polymerization, alkylation, isomerization,
and catalytic reforming. Of these, polymerization is being phased out since
the feedstocks to this unit are olefinic gases. In recent years, demand for
olefinic gases as a feedstock to the petrochemical industry has precluded the
use of these valuable components as a raw material in the manufacture of gasoline.
The remaining two modules are basically preparation and storage units. Naphtha
hydrodesulfurization is the preparation unit used to remove sulfur and nitrogen
from the naphtha feed since these compounds act as poisons to all downstream
catalysts. Light hydrocarbon storage and blending is the sixth and last module
considered under this segment.
32
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LIGHT HYDROCARBON PROCESSING PROCESS NO. 9
Naphtha Hydrodesulfurization
1. Function - The naphtha hydrodesulfurization (HDS) unit is used to
desulfurize and denitrogenate the naphtha split that comes directly
from crude distillation. Both sulfur and nitrogen must be removed" to
a high degree because naphtha is used as a feed~to the isomerization
unit, catalytic reforming unit, and other catalytic units which are
extremely susceptible to catalyst poisoning by sulfur and nitrogen.
Gaseous phase naphthas are mixed with a hydrogen-rich 'gas and heated
to reaction temperature. The mixture is then passed through a fixed-
bed, non-noble metal catalyst. Under catalytic influence, organic
•sulfur and nitrogen compounds break down to form hydrogen sulfide
and ammonia. Some cracking of naphthas into lighter fractions will
occur as a side reaction.
The hot effluent from the reactor passes through cooling heat exchangers
and then to a high pressure separator where hydrogen flashes off and is
recycled to the feed stream. The liquid from the separator is sent to a
fractionator where hydrogen sulfide, ammonia, and any light hydrocarbons
boil off and are sent to an amine unit for removal of the acid gases.
The hydrotreated naphtha is split into specified boiling point frac-
tions or continues into the isomerization or reformer reactor sections.
2. Input Materials - Feed to the naphtha HDS unit is sour naphtha directly
from the crude distillation column. The normal boiling point range for
naphtha is 38-220°C.
Hydrogen is also used as a raw material in the HDS unit. Hydrogen is
produced as a by-product from other process units within the refinery
and is piped to the HDS unit to be used in removing sulfur and nitrogen
from the naphtha.
3. Operating Parameters - The operating conditions of the naphtha
hydrodesulfurization unit will vary depending on the composition
of the feed to the unit. However, the operating parameters will
fall within the following ranges:
Temperature: 315-430°C
Pressure: 2.1 to 6.9 MPa (300-1000 psi)
The catalyst used is a cobalt-molybdenum catalyst.
4. Utilities -
Heater fuel: 56,950 kcal/m3 naphtha (36,000 Btu/bbl)
Electricity: 16.4 kWh/m3 naphtha (2.6 kWh/bbl)
34
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6.
7.
Cooling water: 6300 2, water/m3 naphtha (264 gal/bbl)
Steam Usage: 86-258 kg/m3 (30-90 Ib/bbl) if steam stripper used
14 kg/m3 (5 Ib/bbl) without steam stripper.
Waste Streams - Naphtha hydroesulfurization is similar to most refinery
operations in that the system is closed. The only emissions from this
process are those associated with catalyst regeneration, which occurs
approximately twice a year. During catalyst regeneration, a steam-air
mixture is used to burn off undesirable carbon buildup on the catalyst.
This process releases copious quantities of carbon monoxide for a short
period. A liquid stream of sour water is also released during catalyst
regeneration due to condensation inside the reactor. The catalyst has
a useful life of about five years. At the end of this period, it is
either sold to a reclaimer of precious metals or disposed of as a
solid waste. There is also the potential for hydrocarbon leaks from
this unit as from all pressurized units in a refinery.
EPA Source Classification Code - None exists.
References -
(1) "Hydrocarbon Processing Refining Processes Handbook", Hydrocarbon
Proc. 53(9), (1974).
(2) Nack, H., et al., Development of an Approach to Identification of
Emerging Technology and Demonstration Opportunities, EPA 650/2-74-
048, Columbus, Ohio, Battelle - Columbus Labs., 1974.
(3) Radian Corporation, A Program to Investigate Various Factors in
Refinery Siting, Final Report, Contract No. EQC 319, Austin,
Texas, 1974.
35
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LIGHT HYDROCARBON PROCESSING PROCESS NO. 10
Catalytic Reforming
1. Function - Catalytic reforming is used to convert low octane naphthas
into high octane gasoline blending components called reformates. Some
reformates have very high concentrations of aromatics which can be
extracted for petrochemical use. Several reactions occur during the
reforming process including paraffin hydrocracking, parraffin de-
hydrocyclization, paraffin isomerization, naphthene dehydrogenation
and naphthene dehydroisomerization. Hydrogen is a by-product of
the dehydrogenation reactions.
The desulfurized naphtha feedstock is mixed with hydrogen and heated
via heat exchangers to near reaction temperatures. The mixture then
passes through a series of alternating furnaces and fixed bed catalytic
reactors (usually three or four). The furnaces maintain the reaction
temperatures between platinum-rhenium catalyst beds. In the reactors,
paraffins and naphthenes are dehydrogenated to form higher octane com-
pounds, including aromatics.
The reactor effluent is cooled in heat exchangers and passes through a
separator where hydrogen is flashed off and withdrawn. Some of the
hydrogen is recycled, but this process produces more hydrogen than it
consumes. The net production of hydrogen is available for use in
other refinery processes.
The liquid from the separator is taken to a fractionator where the
Ci - Cit fraction is removed. The reformate stream is then either
sent to storage as a gasoline blending component, or separated into
boiling ranges such as light reformate, aromatic concentrate and
heavy reformate. The aromatic concentrate or some portion of full
range reformate can be processed through a liquid-liquid aromatic ex-
traction unit.
Growing production of unleaded gasoline plus limits on the lead content
of other gasolines will increase the refining industry's dependence
on reforming as a source of high octane (100 + Rcl) gasoline.
2. Input Materials - The feedstock to a catalytic reforming unit is desul-
furized naphthas. Even though hydrogen is a by-product of this system,
it is recylced with the naptha feedstock; thus, in this sense hydrogen
is an input feed. A platinum-rhenium catalyst is used.
3. Operating Parameters -
Temperature: 427-482°C
Pressure: 7.0-14.0 kg/sq cm (100-450 psi)
36
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Pressure is the more sensitive parameter and controls the relative
amounts of dehydrogenation and hydrocracking reactions. Operating
conditions will depend on whether the product is to be used as a
petrochemical feedstock or as a gasoline blending component. The
nature of the feedstock will also affect choice for operating con-
ditions, since heavy naphthas are usually fed when making gasoline
and light naphthas when making aromatics for the petrochemical industry.
4. Utilities -
Furnaces: 408,000 kcal/m3 (258,000 Btu/bbl)
Electricity: 8.2 kWh/m3 - required for compressing feed and recycle
stream
Cooling water: 10,500 I water/m3 feed
5. Waste Streams - Again, this process unit is a closed system. The only
continuous emissions are those from the process heaters (discussed
later) and possible hydrocarbon leaks. There are emissions during the
catalyst regeneration period. However, this is an infrequent occurrence
and emissions can be considered negligible.
There are some catalytic reforming units that have a continuous catalyst
regeneration system. Emissions from this source are estimated to range
from 0.005-0.05 kg CO/m3 (0.002-0.02 Ib/bbl). This source may also be
considered negligible.
6. EPA Source Classification Code - 3-06-013-01.
7. References -
(1) "Hydrocarbon Processing Refining Processes Handbook", Hydrocarbon
Proc. 53(9). (1974).
(2) Nack, H., et al., Development of an Approach to Identification of
Emerging Technology and Demonstration Opportunities, EPA 650/2-74-
048, Columbus, Ohio, Battelle - Columbus Labs., 1974.
(3) Radian Corporation, A Program to Investigate Various Factors in
Refinery Siting, Final Report, Contract No. EQC 319, Austin,
Texas, 1974.
37
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LIGHT HYDROCARBON PROCESSING PROCESS NO. 11
Isomen'zation
1. Function - Isomerization units are used to convert n-butane, n-pentane,
and n-hexane into their respective isoparaffins. Isobutane that is
formed from this process is used as a feedstock for alkylation. Iso-
pentane and isohexane have sufficiently high octane ratings to be used
directly as blends for gasoline.
The feedstock to the isomerization unit must be both dehydrated and de-
sulfurized. The sweet, dry feedstock is mixed with hydrogen and organic
chloride. The mixture is then heated to reaction temperature and
passed over a catalyst in the hydrogenation vessel where any unsaturated
hydrocarbons (e.g., benzene, olefins) are hydrogenated. The hydrogena-
tion reaction need not occur in a separate vessel but may be a part of
the isomerization reactor vessel. A chlorinated platinum-aluminum
oxide catalyst converts the straight chain hydrocarbons into isoparaffins.
The effluent product is then cooled and passes to a high pressure
separator where recycle hydrogen flashes off. The liquid from the
separator passes to a stripper column where the organic chlorides are
removed. The product isoparraffins then pass through a neutralization
vessel. The next processing steps vary from unit to unit and result
in the separation of the normal and iso-paraffins. The normal paraffins
are generally recycled to the reactor while the isoparaffins are sent
on to alkylation (isobutane) or gasoline blending (isopentane, isohexane).
2. Input Materials - The feedstocks to these units are normal butane and
light naphtha fractions containing pentanes and hexanes. The feed must
be both desulfurized and dehydrated to prevent fouling the platinum -
aluminum oxide catalyst used in this reaction.
Hydrogen must also be considered a feedstock to the isomerization process.
The purpose of the hydrogen is to hydrogenate unsaturated compounds to
prevent polymerization. Polymerization reaction would both ruin product
quality control and possibly retard catalyst activity.
3. Operating Parameters - The desired reactions occur at the following
conditions:
Temperature: 240-255°C
Pressure: 21-28 kg/sq cm (300-400 psi)
4. Utilities -
Fired heaters: 47,000-108,000 kcal/m3 feed (30,000-68,000 Btu/bbl)
Electricity: 7.5 kWh/m3 (1.2 kWh/bbl) - required to compress feed to
operating pressure
Steam: 58-72 kg/m3 (20-25 Ib/bbl) - needed to run the stripper
column
38
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5. Waste Streams - Isomerization is a closed process with no air emis-
sions and no liquid effluents other than the aqueous wastes associated
with the neutralization step. There are atmospheric emissions from
the heaters, but these will be covered in a later section. Also, the
possibility always exists for fugitive hydrocarbon leaks.
The catalyst is generally replaced after two years' service and,
because of the intrinsic value of the platinum, is sold to salvage
dealers. Thus, the catalyst is not a solid waste disposal problem to
the refinery.
6. EPA Source Classification Code - None exists.
7. References -
(1) "Hydrocarbon Processing Refining Processes Handbood", Hydrocarbon
Proc. 53(9), (1974).
(2) Nack, H., et al., Development of an Approach to Identification of
Emerging Technology and Demonstration Opportunities, EPA 650/2-74-
048, Columbus, Ohio, Battelle - Columbus Labs., 1974.
(3) Radian Corporation, A Program to Investigate Various Factors in
Refinery Siting, Final Report, Contract No. EQC 319, Austin,
Texas, 1974.
39
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LIGHT HYDROCARBON PROCESSING PROCESS NO. 12
Alkylatlon
1. Function - Alkylation units are used to produce a high octane component
for gasoline blending. Alkylation is the chemical combination of two
hydrocarbon molecules to form one molecule of higher octane rating. An
olefin (propylene, butylene and amylene) and an isoparaffin (usually
isobutane) are catalytically reacted over either 98% sulfuric acid or
75-90% hydrofluoric acid to produce a high octane component known as
al kylate.
A dry olefinic feed is mixed with excess isobutane and contacted with
the liquid catalyst in the reaction vessel where alkylation occurs.
The reactor effluent is separated into hydrocarbon and acid phases in
a settler. The acid-is returned to the reactor. The alkylate is then
processed further.
Both the sulfuric acid and hydrofluoric acid processes include distillation
sections of varying configurations to separate the alkylate product from
excess isobutane, normal butane and propane. The isobutane is returned
to the reactor section. Normal butane and propane are removed from the
process.
Reactor effluent from the sulfuric acid process is utilized in a refrigerant
cycle to cool the reactors. Acid and organically combined sulfur in the
reactor effluent are removed by caustic scrubbing before distillation.
The alkylate, normal butane, and propane products from the distillation
section are also caustic scrubbed.
Hydrofluoric acid and organically combined fluorides appear in the propane
and alkylate streams from the HF process. A hot bauxite treatment is
commonly used to reduce combined fluorides to less than 10 ppm in the
propane stream. The use of direct-fired furnaces for deisobutanizer
column reboilers provides thermal defluorination of the alkylate product.
Propane, n-butane and alkylate product streams are also caustic scrubbed.
Hydrofluoric acid units include an acid regenerator to maintain acid
purity by fractionating acid from tar and a constant boiling mixture of
acid and water. Acid recovery processes are rarely included in sulfuric
acid units. Spent acid from the process is generally exchanged for fresh
acid from an acid supplier.
There has been some interest in the alkylation of isobutane with ethylene
using an aluminum chloride catalyst complex. However, the process is not
commercially important at the present time. The catalyst is more difficult
to handle and regenerate than HF and HzSOi* catalysts and ethylene is gen-
erally a more expensive feedstock.
40
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Since the alkylation process is required to convert by-products of
catalytic cracking to gasoline components, it is a standard unit in
refineries with catalytic crackers. Alkylate is also one of the high-
est octane components in the gasoline pool. However, the units are
expensive to build and to operate. Any future growth in alkylation
capacity will come only after significant growth in catalytic cracking
capacity or changes in cracking yields.
2. Input Materials - Isobutane is mixed with an olefin (propylene,
butylene and amylene) or mixed olefin feed to form the alkylate. The
olefins are catalytic cracking by-products. Isobutane is obtained
from crude, from NGL, and as a product of hydrocracking and isomeriza-
tion processes. The isobutane required varies from 1.0 to 1.33 vol Ci»/vo1
olefin depending on olefin and catalyst type.
Catalyst make-up requirements vary from 40-125 kg/m3 alkylate (14-44 lb/
bbl) for sulfuric acid units. Hydrofluoric acid make-up requirements
vary from 0.3-0.6 kg/m3 alkylate (0.1-0.2 Ib/bbl).
3. Operating Parameters - The two catalyst processes for alkylation differ
significantly in operating temperatures.
Temperature: 10.0-16.0°C for sulfuric acid catalyst processes
27.0-32.0°C for hydrofluoric acid catalyst processes
Pressure: 7-10.5 kg/cm2 (100-150 psi) for either system.
4. Utilities -
Steam: 286-858 kg stream/m3 product - used to fractionate the inter-
mediate product
Electricity: 3.0-30. kWh/m3 (0.5-5.0 kWh/bbl) — used to compress
feed gases. If refrigeration is required (sulfuric
acid system), the electricity requirements will be
on the high side of this range.
5. Waste Streams - Alkylation processes are generally closed systems with
no process vents to the atmosphere, except those from fired heaters which
are discussed in a following section. In some HF units, there can be a
process vent from the depropanizer accumulator for releasing non-condens-
able ethane from the system. However, it is common practice to provide
a closed system for all possible discharges containing HF, including
vents from pumps, exchangers and all equipment in acid service. This
system discharges to an alkaline scrubber where HF is removed before (ex-
hausting to atmosphere or blowdown system). Spent caustic, lime slurry,
or potassium hydroxide scrubbing is used. The recovered fluoride is
landfilled.
41
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HF units also produce a waste stream from the acid regenerator, usually
in the form of a sludge. This material is either incinerated or treated
with alkaline solution to recover the fluoride as a solid waste to be
landfilled.
The sulfuric acid process produces liquid wastes associated with water
and caustic scrubbing of feed and product streams. These wastes are
generally processed in the refinery's neutralization and waste water
treating facilities.
6. EPA Source Classification Code - None exists.
7. References -
(1) Anderson, R. F., "Changes Keep HF Alkylation Up-To-Date," OiJ
and Gas Journal. 72(2). 78 (1974).
(2) "Hydrocarbon Processing Refining Processes Handbook", Hydrocarbon
Proc. 53(9), (1974).
(3) Nack, H., et al., Development of an Approach to Identification of
Emerging Technology and Demonstration Opportunities, EPA 650/2-
74-048, Columbus, Ohio, Battelle - Columbus Labs., 1974.
(4) Nelson, W. L., Petroleum Refinery Engineering, McGraw-Hill,
Fourth Edition, 1958.
(5) Radian Corporation, A Program to Investigate Various Factors in
Refinery Siting, Final Report, Contract No. EQC 319, Austin,
Texas, 1974.
(6) Sims, Anker V., Field Surveillance and Enforcement Guide for
Petroleum Refineries, Final Report, EPA 450/3-74-042, Contract
No. 68-02-0645, Pasadena, California, Ben Holt Co., 1974.
PB 236-669.
42
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LIGHT HYDROCARBON PROCESSING PROCESS NO. Jl
Polymerization
"i • Function - The polymerization unit is used to produce a high octane
gasoline or petrochemical feedstock from olefin gases. It performs
essentially the same function as an alkylation unit. However, the
major difference between the two units is that alkylation requires an
olefin and an isoparaffin feed while polymerization requires two olefin
gases as feed. With the rising importance of olefins as feedstock to
the petrochemical industry, polymerization is being phased out as a
refining process. In other words, there are more economical means to
upgrade octane ratings of gasoline components.
Poly gasolines (the polymerization product) are formed by passing two
olefin gases over a catalyst where the polymerization reaction occurs.
The most common catalyst used is phosphoric acid. The reaction is exo-
thermic so outside energy is required only on start-up. After the
reaction, the gases pass through a heat exchanger with incoming gases.
The gases are then sent to a fractionator to be split into various compo-
nents.
2. Input Materials - The feedstock to the polymerization unit is any
combination of olefins such as ethylene, propylene, butylene, and
amylene. These gases are usually products of gas processing within the
refinery.
3. Operating Parameters - Conditions inside the reactor are as follows:
Temperature: 135-190°C
Pressure: 35 kg/sq cm (500 psi)
The catalyst most commonly employed is phosphoric acid or phosphoric
acid-impregnated pellets.
4. Utilities - Utility requirements are low for this unit.
Steam - 57 kg/m3 feed (20 Ib/bbl) - required for fractionation of the
product.
Electricity - 7.5 kWh/m3 (1.2 kWh/bbl) - required to pump the liquid
feed.
5. Waste Streams - The polymerization unit is similar to other process units
in a refinery in that it is a closed system with no atmospheric emissions.
The only liquid emission is the phosphoric acid catalyst which may be
washed out during maintenance periods. Maintenance periods are infrequent,
occurring about once every two years. If the phosphoric acid is supported
on a solid, there will be a solid waste disposal problem which must be
dealt with during the maintenance periods.
6. EPA Source Classification Code - None exists.
43
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7. References -
(1) Nack, H., et al., Development of an Approach to Identification
of Emerging Technology and Demonstration Opportunities, EPA-650/2-74-
048, Columbus, Ohio, Battelle-Columbus Labs., 1974.
(2) Nelson, W. I., Petrol euro Refi nery Engi neeri ng, McGraw-Hill, Fourth
Edition, 1958.
44
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LIGHT HYDROCARBON PROCESSING PROCESS NO. 14
Light Hydrocarbon Storage and Blending
1. Function - The purpose of light hydrocarbon storage and blending is to
store the various products of the light hydrocarbon processing section
until blending requirements are determined. Then blending commences by
mixing various components in a header to achieve a product of desired
characteristics. The product flows from the blending header to separate
storage to await sale.
The most common blending operation involves the final step in gasoline
manufacture. All the products of the light hydrocarbon processing sec-
tion are components of gasoline. The various individual products such
as catalytic gasoline, alkylates, isomerates, aromatics, reformates, and butane
are stored separately until they are blended together along with purchased
materials such as tetraethyl lead and dye to form marketable gasoline.
All the intermediate products and the final product have sufficiently
high vapor pressure that they must be stored in floating roof tanks
or vapor recovery tanks. Of course, the very light ends such as butane,
propane, and ethane are stored in pressure vessels.
2. Input Materials - Separate storage facilities are required for each of
the products of the various light hydrocarbon processing units. There
must be storage available for butane, propane, catalytic gasoline,
alkylates, isomerates, aromatics, reformates, and final products such
as the various grades of gasoline.
3. Operating Parameters - All light hydrocarbon storage must be carried out
in vapor control tanks. These tanks are most generally floating roof
tanks but may involve vapor recovery tanks. The products that are gases
at ambient temperatures must be stored in pressure vessels.
Temperature: Ambient temperature
Pressure: Ambient pressure unless stored in pressure vessels in which
case pressure* will be vapor pressure of stored product.
4. Utilities - Utility requirements are simply those needed to pump the
liquid products. These are negligible when compared to other refinery
operations.
5. Waste Streams - The waste stream from light hydrocarbon storage occurs
as a result of liquid evaporation from wetted walls and evaporation around
the roof seals. This value averages about 0.004 kg hydrocarbon per
day per 1000 liters storage capacity.
6. EPA Source Classification Code
Gasoline storage 4-03-002-01
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7. References -
(1) Environmental Protection Agency, Compilation of Air Pollutant
Emission Factors, 2nd Ed., AP-42, Research Triangle Park, N.C.,
1973.
(2) Radian Corporation, A Program to Investigate Various Factors in
Refinery Siting, Final Report, Contract No. EQC 319, Austin,
Texas, 1974.
46
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Middle and Heavy Distillate Processing
Middle and heavy distillate processing refers to the treatment of kerosenes,
virgin and cracked gas oils and lube oils. These oils cover a wide boiling
range, 230-560°C (450-1050°F). Seven modules are considered in this segment.
Two modules are concerned with reducing sulfur levels in fuels, two with
catalytic cracking, two with lube oil and wax processing and one with the
storage operation. These are shown schematically in Figure 3.
The two sulfur treating modules are chemical sweetening and hydrodesulfurization,
Chemical sweetening processes are utilized to remove odiferous sulfur compounds
like mercaptans from relatively low sulfur content streams such as kerosene
and catalytic gasoline. Catalytic hydrodesulfurization is a process used ex-
tensively to make high quality, low sulfur fuels. The process removes up to
90% of the sulfur in the feed, which is generally kerosenes or virgin and
cracked light gas oils. The process is also used to pretreat catalytic crack-
ing feedstocks.
Catalytic cracking processes convert gas oils to lighter products, primarily
gasoline. Fluid bed catalytic cracking is the most widely used process. Mov-
ing bed catalytic cracking is a variation of the same process. Hydrocracking
is a high severity process which combines cracking and hydrogenation, handles
a broad range of feeds, and produces varying ratios of gasoline and light fuel
oils.
The lube oil processing module describes the processes used to make high quality
lubricating oils and waxes.
47
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0
55
co
UJ
O
O
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MIDDLE AND HEAVY DISTILLATE PROCESSING PROCESS NO. 15
Chemical Sweetening
1. Function - Chemical sweetening is used to remove mercaptans, hydrogen
sulfide and elemental sulfur from catalytic gasolines and light distil-
lates. Mercaptans impart a foul odor to petroleum products, increase
requirements for tetraethyllead additions to achieve octane specifica-
tions in gasoline, and, in the presence of elemental sulfur, cause
corrosion. There are at least eleven different processes for sweetening
hydrocarbons. Three of the most widely used proprietary processes
are Merox, Locap and Bender sweetening.
Some processes remove the mercaptans from the hydrocarbon stream by ex-
traction with caustic. The caustic solution often contains solubility
promoters such as alky! phenols, cresols and naphthenic acids. Extrac-
tion is generally confined to lighter mercaptans (methyl and ethyl
mercaptan). Conversion processes oxidize higher molecular weight mer-
captans to the less odiferous disulfide in the presence of air, alkali
and a catalyst. Many processes combine an extraction step with a con-
version step. Oxidizing agents and catalysts include lead sulfide and
oxide, copper chloride, and hypochlorites.
2. Input Materials - Straight run and catalytic gasolines, kerosene, jet
fuels and other light distillates are the hydrocarbon streams generally
charged to sweetening units. Treating materials include caustic, various
solubility promoting chemicals, oxidizing agents and catalysts, and
catalyst regenerants.
3. Operating Parameters - The operating conditions will depend on the product
being processed but should be approximately:
Temperature: Ambient - 65°C
Pressure: 1.4 kg/sq cm
4. Utilities - Pumping costs only
Electricity: 0.06 (1) - 0.25 kWh/m3
5. Waste Streams - Emissions vary depending on the process. Some sweetening
processes utilize air blowing to regenerate extraction/oxidation solutions.
No appreciable hydrocarbon emissions result. Aqueous emissions are common.
Water washing is frequently employed after contacting hydrocarbons with
caustic. The use of some oxidizing agents, hypochlorite for example, re-
sults in waste water discharges. However, these sources are usually handled
without significant problems by waste water treating facilities.
49
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6. EPA Source Classification Code - None exists.
7. References -
(1) "Hydrocarbon Processing Refining Processes Handbook", Hydrocarbon
Proc. 53(9), (1974).
(2) Nack, H., et al., Development of an Approach to Identification of
Emerging Technology and Demonstration Opportunities, EPA 650/2-74-048,
Columbus, Ohio, Battelle - Columbus Labs., 1974.
50
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MIDDLE AND HEAVY DISTILLATE PROCESSING PROCESS No. 16
Hydrodesul furization
1. Function - The hydrodesulfurization process is used for desulfurization,
denitrogenation, olefinic and aromatic hydrogenation and demetallization
of distillates and gas oils. The process is used extensively to produce
high quality, low sulfur kerosene and light gas oils for the production
of jet fuels, diesel fuels and heating oils. The process is also used
to a lesser extent to treat heavy gas oils for blending low sulfur
heavy fuel oils or for high quality catalytic cracking feed.
The oil is mixed with make-up and recycle hydrogen, heated, and charged
to a fixed bed reactor containing a non-noble metal catalyst. The re-
actions occur in an essentially liquid phase. Sulfur and nitrogen
react with hydrogen to form H2S and NH3. A hydrogen-rich stream is
flashed from the reactor product in a high pressure separator and is
recycled. Reactor product flows to a low pressure separator where
most of the HaS, NH3 and light ends are recovered. The oil product is
then stream stripped or fractionated to remove the remaining impurities.
2. Input Materials - Feed to a hydrodesulfurization unit may be kerosene,
light gas oil or distillates (including cracked gas oils) or heavy gas
oils (straight-run or cracked).
Hydrogen requirements vary with the feed type and degree of desulfurization
desired. Kerosene hydrotreating requires around 70 m3H2/m3 (400 SCF/BBL)
while gas oils require up to 300 m3H2/m3 (1700 SCF/BBL).
The catalyst is generally a non-noble metal catalyst such as nickel or
cobalt molybdenum.
3. Operating Parameters - The operating conditions in the reactor are:
Temperature: 205-416°C (390-800°F)
Pressure: 35-56 kg/cm2 (500-800 psi)
4. Utilities -
Electricity: 3-58 kWh/m3 (pumping and compression)
Heater Fuel: 0-110,000 kcal/m3 (0-70,000 Btu/bbl)
Steam: 2.8-29 kg/m3 (1-10 Ib/bbl)
Cooling Water: 400 liters/m3 (160 gal/bbl)
51
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5. Waste Streams - Hydrodesulfurization is similar to most refinery
operations in that the system is closed. The only atmospheric
emissions associated with those processes are from the fired heaters
(discussed in a later module) and those from catalyst regeneration.
Catalyst regeneration occurs about twice each year.
Other emissions include hydrocarbon leaks from flanges and valves
(fugitive emissions) and a sour water stream from the steam stripping
operation.
6. EPA Source Classification Code - None exists.
7. References -
(1) "Hydrocarbon Processing Refining Processes Handbook", Hydrocarbon
Proc. 53(9), 1974.
(2) Nack, H., et al., Development of an Approach to_ Identification
of Emerging Technology and Demonstration Opportunities, EPA
650/2-74-048, Columbus, Ohio, Battelle-Columbus Labs., 1974.
(3) Radian Corporation, A Program to Investigate Various Factors in
Refinery Siting, Final Report, Contract No. EQC 319, Austin,
Texas, 1974.
52
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MIDDLE AND HEAVY DISTILLATE PROCESSING PROCESS NO. 17
Fluid Bed Catalytic Cracker
Function - The fluid bed catalytic cracking process is one of the most
versatile and widely used in the refining industry. The process uses a
solid, finely powdered zeolitic catalyst that when mixed with a gas
has transport properties similar to those of a liquid. Feedstocks can
vary from naphtha boiling-range materials to vacuum residuals. Products
include, but are not limited to, LPG, olefins, high octane gasoline,
petrochemical raw materials, distillate blending components, and carbon
black oil. The process is commonly used to convert heavy virgin, vacuum,
and coker gas oils to lighter products, with an emphasis on gasoline and
distillate blending components in most refineries.
Preheated feed is introduced into the bottom of a vertical transfer line,
or riser, and mixed with hot, regenerated catalyst. The catalyst-oil
mixture flows up the riser into a reactor/separator with cracking re-
actions occuring in both the riser and reactor/separator. Cyclones
inside the reactor separate the gaseous reaction products from the
catalyst. Reaction products flow from the top of the reactor section
to a fractionation section while spent catalyst flows from the bottom
of the reactor to the regenerator.
The spent catalyst is steam stripped to remove residual hydrocarbon as it
leaves the reactor for the regenerator. Inside the regenerator, the
coke deposited on the catalyst as a by-product of the cracking reactions
is burned off in a controlled combustion process with preheated air. The
degree of combustion varies with unit design from essentially complete
combustion to C02 to some desired ratio of C02/C0. The hot, regenerated
catalyst then flows to the bottom of the riser to mix with incoming feed
and complete the catalyst cycle.
The hot flue gas leaves the regenerator, passing through several sets of
cyclones and/or an electrostatic precipitator to remove entrained catalyst
fines. Most refiners make an effort to recover the energy in the flue
gas. The heat of the gas is recovered by producing steam. Flue gas con-
taining appreciable quantities of CO is burned in a steam producing
furnace called a CO boiler. Some refiners utilize the pressure energy of
the gas to drive rotating equipment, the regenerator air blower for
example.
The reaction products are generally separated by distillation into an
overhead product of gasoline boiling range and lighter components, a
middle product of light cycle oil and a bottoms product of heavy cycle
oil. The overhead product is fractionated further to yield LPG, olefins
and debutanized gasoline. The light cycle oil can be hydrotreated and
used as a distillate blending component or used as feed to a hydrocrack-
ing unit. The heavy cycle oil is processed to concentrate entrained
catalyst in one portion which is recycled to the riser. The clarified
remainder is a highly unsaturated, aromatic oil that can be used in a
variety of ways; carbon black oil is one example.
53
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Operating variables for this process cover a wide range of conditions,
depending on feed type and quality, desired product mix and individual
unit design. The latest designs maximize cracking reactions in the
riser, utilizing the reactor section strictly as a separator for rapid
disengagement of the catalyst-oil mixture. Riser-cracking promotes
maximum gasoline production.
There is a high level of interest in hydrotreating feedstocks before
charging to the cracking unit. Hydrotreating the feed reduces sulfur
and improves gasoline yields and quality. The need to reduce sulfur
emissions and increase unleaded gasoline production indicates that
hydrotreating may be more widely used in the future. Another possible
future trend is charging residuals, either atmospheric or vacuum or
even whole crude oil. A significant limitation here is short catalyst
life and unsatisfactory yields due to poisoning of the catalyst by metals.
2. Input Materials - The feed to the fluid bed catalytic cracker may range
from naphtha boiling range material to vacuum residuals. The most common
feed is composed of virgin and cracked gas oils with a boiling range of
345-570°C.
3. Operating Parameters - There is a range of products produced. The
amount of each can be varied by changing the operating conditions.
Some typical conditions are as follows:
Reactor -
Temperature: 475-550°C (887-1022°F)
Pressure: 0.7-2.1 kg/sq cm (10-30 psig)
Regenerator -
Temperature: 675-760°C
Pressure: 1.0-2.5 kg/sq cm (15-35 psig)
4. Utilities -
Furnace: 230,000 kcal/m3 feed (143,000 Btu/bbl)
Electricity: 2.6 kWh/m3
Steam: if CO boiler is used, the net production of steam is 210 kg/m3
(73 lb/bbl).
5. Waste Streams - The fluid bed catalytic cracker is one of only three
units in a refinery from which there are continuous process emissions.
These emissions emanate from the catalyst regenerator and are as follows:
54
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Atmospheric emissions - uncontrolled
Participates 0.267-0.976 kq/m3 fresh feed
Sulfur oxides 0.898-1.505 kg/m3 fresh feed
Carbon monoxide 39.2 kg/m3 fresh feed
Hydrocarbons 0.630 kg/m3 fresh feed
Nitrogen oxides 0.107-0.416 kg/m3 fresh feed
Aldehydes 0.054 kg/m3 fresh feed
Ammonia 0.155 kg/m3
Atmospheric emissions - controlled by CO boiler and/or electrostatic
preci pita tor
Particulates 0.036-0.175 kg/m3 fresh feed
Sulfur oxides 0.898-1.505 kc/m3 fresh feed
Carbon monoxide - negligible
Hydrocarbons 0.630 kg/m3 fresh feed
Nitrogen oxides 0.107-0.416 kg/m3 fresh feed
Aldehydes 0.054 kg/m3 fresh feed
Ammonia 0.155 kg/m3 fresh feed
Note that the CO boiler is fired at a low temperature (fWOO°C) and thus
is not hot enough to consume the other combustibles in the waste stream.
Aqueous wastes include condensed steam from the catalyst steam
stripping section. This stream contains hydrogen sulfide, mercaptans,
ammonia, and phenols. The reported volume is 120 I water/m3 feed
(5 gal/bbl).
Solid waste consists of spent catalyst and catalyst fines. Catalyst
fines captured by the electrostatic precipitator or cyclones amount
to 0.23-0.80 kg/m3 fresh feed (0.08-0.28 Ib/bbl). The volume of spent
catalyst displaced from circulating inventory is the difference between
the catalyst make-up rate and catalyst lost with the flue gas.
Furnace combustion products are discussed in a later section.
6. EPA Source Classification Code - 3-06-002-01.
55
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7. References -
(1) Environmental Protection Agency, Compilation of Air Pollutant
Emission Factors, 2nd Ed. with Supplements, AP-42, Research
Triangle Park, N.C., 1973.
(2) "Hydrocarbon Processing Refining Processes Handbook", Hydrocarbon
Proc. 53(9), 1974.
(3) Nack, H., et'al., Development of an Approach to Identification
of Emerging Technology and Demonstration Opportunities, E"PA
650/2-74-048, Columbus, Ohio, Battelle-Colurnbus Labs., 1974.
(4) Radian Corporation, A Program to Investigate Various Factors
in Refinery Siting, Final Report, Contract No. EQC 319, Austin,
Texas, 1974.
56
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MIDDLE AND HEAVY DISTILLATE PROCESSING PROCESS NO. 18
Moving Bed Catalytic Cracker
1' 'Function - The function of a moving bed catalytic cracker (also called
Thermofor Catalytic Cracking Units, TCCU) is the same as that of the
fluid bed unit. The process uses a synthetic bead catalyst to crack
gas oils into a wide variety of lighter hydrocarbons such as LPG, ole-
fins, gasoline, and distillate blending components.
The rather large catalyst beads ('v.O.S cm) flow by gravity into the top
of the reactor where they contact a mixed vapor - liquid feed. The oil-
catalyst mix flows down through the reactor to a disengaging zone where
catalyst and oil separate. The gaseous reaction products flow out of
the reactor to the fractionation section. The catalyst continues down-
ward through a purge zone where it is steam stripped of residual hydro-
carbon. The purged spend catalyst then flows by gravity through the
kiln, or regenerator, where coke is burned from the catalyst. After
regeneration, the catalyst is cooled to remove excess heat, then
flows into a lift pot where it is forced up a riser by low pressure
air to a separator. Catalyst from the separator is returned to the
reactor to complete the catalyst cycle.
Reaction products are separated into wet gas, gasoline, and light and
heavy cycle fractions. The wet gas is eventually processed in a gas
plant. The gasoline stream is debutanized, sweetened and sent to
storage. The light cycle can be hydrotreated for use as a distillate
blending stock or used as hydrocracker feed. Some portion of the
heavy cycle fraction will be recycled to the reactor while the re-
mainder is generally used as a heavy fuel oil blending component.
The moving bed process is no longer competitive with the fluid process
in most refining applications. It is doubtful that any new units will
be constructed except under special circumstances. However, there are
many moving bed units in operation, particularly in older or smaller
refineries, that will not be replaced in the immediate future. This
process, like the fluid process, is very versatile and there is wide-
spread interest in using these units to process residuals and whole
crude.
2. Input Materials - Feed to the moving bed catalytic cracker is the same
as feed to a fluid bed catalytic cracker. Usually the feedstock is gas
oils from the crude and vacuum stills, but it may range from kerosene
to residual oils.
A typical boiling range for the feed is 345-570°C.
57
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3. Operating Parameters - The operating conditions should be similar to
those of a fluidized bed system. Fluidized bed conditions are:
Reactor -
Temperature: 475-550°C
Pressure: 0.7-2.1 kg/sq cm (10-30 psig)
Regenerator -
Temperature: 675-760°C
Pressure: 1.0-2.5 kg/sq cm (15-35 psig)
4 . Utilities -
Furnace: 158,000-475,000 kcal/m3 (100,000-300,000 Btu/bbl)
Electricity: 0.6-9.4 kWh/m3 (0.1-1.5 kWh/bbl) for air blowing
and pumping requirements
Steam: 285 kg/m3 feed (100 Ib/bbl) for steam fractionation
456 kg/m3 feed may be generated by the hot off gases from the
regenerator
5. Waste Streams - The moving bed catalytic cracker has a continuous process
emission from the catalyst regenerator and catalyst surge separator with
the following atmospheric emissions:
Particulates 0.049 kg/m3 fresh feed
Sulfur oxides 0.171 kg/m3 fresh feed
Carbon monoxide 10.8 kg/m3 fresh feed
Hydrocarbons 0.250 kg/m3 fresh feed
Nitrogen oxides 0.014 kg/m3 fresh feed
Aldehydes 0.034 kg/m3 fresh feed
Ammonia 0.017 kg/m3 fresh feed
Other waste streams are:
Aqueous emissions: 285 kg/m3 fresh feed - this is the sour
water stream from the steam stripper
Solid wastes: 0.28-0.56 kg/m3 fresh feed - this is the replace-
ment rate of spent catalyst.
6. EPA Source Classification Code - 3-06-003-01
58
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7. References -
(1) Environmental Protection Agency, Compilation of Air Pollutant
Emission Factors. 2nd Ed., AP-42, Research Triangle Park, N.C.,
1973.
(2) "Hydrocarbon Processing Refining Processes Handbook", Hydrocarbon
Proc . 53_(9), 1974.
(3) Nack, H., et al . , Development of an Approach to Identification
of Emerging Technology and Demonstration Opportunities,
EPA 650/2-74-048, Columbus, Ohio, Battelle-Columbus Labs., 1974.
(4) Radian Corporation, A Program to Investigate Various Factors in
Refinery Siting, Final Report, Contract No. EQC 319, Austin, Texas,
1974.
59
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MIDDLE AND HEAVY DISTILLATE PROCESSING PROCESS NO. 19
Hydrocracking
1. Function - Hydrocracking is a combination of catalytic cracking and
hydrogenation. Heavy feedstocks are converted into lighter fractions
in a high temperature reaction in the presence of high pressure hydrogen
and a catalyst. Hydrocracking is generally used to supplement the catalytic
cracking process. A hydrocracker costs more to build and operate than a
fluid bed catalytic cracker. However, the hydrocracker can handle heavier
fractions and cracked gas oils better and the products contain no unsaturated
hydrocarbons. Many refiners use light cycle oil from the catalytic cracking
process as a primary feed to the hydrocracking unit.
The hydrocracker can employ either one or two reactor stages. A unit
designed to treat a feed of relatively low sulfur and nitrogen content
and low unsaturate or aromatic composition can utilize a single reactor.
If the feed is relatively high in sulfur, nitrogen, unsaturates and
aromatics, two reactors are required. The first reactor functions as a
hydrodesulfurizer, converting sulfur and nitrogen into HzS and NH3 which
are removed in a separator before charging the feed to the second stage.
Reactor effluent passes through high and low pressure separators to remove
\\2> which is recycled, and light components. The product stream is then
fractionated into various components. The hydrocracking process can yield
a variety of products. Many refiners utilize the process to produce
saturated light ends like normal and iso butane, a light gasoline fraction
for blending, a naphtha fraction for reformer feed, a high quality kerosene
for jet fuel, or distillate for diesel/home heating fuel. Heavier material
is recycled. Some refiners recycle anything heavier than naptha to extinction,
2. Input Materials - Virgin and/or cracked gas oils containing some sulfur
and nitrogen impurities is the usual feed to a catalytic hydrocracker.
The boiling range is 345-570°C. Hydrogen is needed at the rate of 250 to
375 cubic meters per cubic meter nf feed (1,400 to 2,100 scf/bbl). In
extreme cases, up to 4000 scf/bbl is required. The catalyst used is cobalt-
molybdenum or nickel-molybdenum.
3. Operating Parameters - The operating conditions of a first stage
reactor on a typical catalytic hydrocracker are:
Temperature: 370°C (700°F)
Pressure: 210 kg/sq cm (3000 psi)
Operating conditions for the second stage are:
Temperature: 315°C (600°F)
Pressure: 105 kg/sq cm (1,500 psi)
60
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4. Utilities -
Electricity: 48 to 88 kWh/m3 of feed (8.2 to 15 kWh/bbl)
Steam: 28.6 to 46.1 kg/m3 of feed (10 to 16.1 Ib/bbl)
Heater Fuel: 230,000 to 400,000 kcal/m3 of feed (145,000 to 250,000
Btu/bbl)
Cooling Water: 290 to 1450 liters/m3 of feed (120 to 600 gal/bbl)
Process Water: 10 liters/m3 of feed (4 gal/bbl)
5. Waste Streams - There are three sources of emissions to the atmo-
sphere from a catalytic hydrocracker. The major source is the process
heaters used in the unit. These emissions are described in a separate
module which includes process heaters. Another source of air emissions
is the catalyst regeneration operations. This cleaning process re-
leases large quantities of carbon monoxide over a short period of time.
The third source of air emissions in the fugitive hydrocarbon leaks
which occur around pump seals, relief valves, flanges, valve stems,
and compressor seals.
Two liquid waste streams result from this unit: one during periodic
catalyst regeneration and the other continuously. The waste stream
resulting from regeneration is a sour water stream which is equal to
the amount of steam that condenses in the reactor during this time.
The continuous, liquid waste stream comes from the high pressure
separator, the low pressure separator, and the stabilizer accumulator.
This stream contains dissolved H2S and NH3. It is treated by a
sour water stripper before being discharged or reused.
The catalyst in the first stage has a useful life of a couple of
years. At the end of its usefulness it is either sold to a reclaimer
of precious metals or disposed of as a solid waste.
6. EPA Source Classification Code - None exists.
7. References -
(1) "Hydrocarbon Processing Refining Processes Handbook", Hydrocarbon
Proc. 53(9). (1974).
(2) Sims, Anker V., Field Surveillance and Enforcement Guide for
Petroleum Refineries, Final Report, EPA 450-3-74-042, Contract
No. 68-02-0645, PB 236 669, Pasadena, CA., Ben Holt Co., 1974.
61
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MIDDLE AND HEAVY DISTILLATE PROCESSING PROCESS NO. 20
Lube Oil Processing
1. Function - Narrow bdiling-range cuts from the vacuum distillation of
reduced crude are used for lubricating oil base stocks. These fractions
are refined to increase viscosity indexes, oxidation stability, and
resistance to sludge and gum formation by removing aromatics, unsatu-
rates, naphthenes and asphalts. Some lube oil stocks are then dewaxed
and the wax deoiled. Solvent treating processes are the most effective
and widely used for lube oil refining, oil dewaxing and wax deoiling.
The most common lube oil refining processes are single solvent processes
using furfural or phenol as solvents. The Duo-Sol process uses dual
solvents, propane and selecto, a cresylic acid-phenol mixture. Generally,
the oil and solvent are contacted in counterflow towers or multistage con-
tactors. Distillation is used to recover the solvent remaining in the
lube oil and to separate solvent from the extract. The solvent is re-
cycled and the extract is used as catalytic cracking feed. The lube oil
might be used as blending stock or processed through an oil dewaxing unit.
The dewaxing process removes wax from lube oils which improves the low
temperature fluidity characteristics of the oil. The oil is contacted
with solvent and chilled, causing the wax to precipitate. The precipi-
tated wax is separated from the mixture by filtration or centrifuging.
The dewaxed oil and solvent are separated by distillation and steam
stripping. Solvent is recycled. The wax, usually containing at least
10% oil, is solvent treated again under different conditions to obtain
a described wax product of the desired specifications. Refrigeration
and filtration are used to recover the wax and solvent. The most widely
used solvent for oil dewaxing and wax deoiling is methyl ethyl ketone
(MEK) or a mixture of MEK and toluene or benzene. Both operations are
frequently combined in one unit using a MEK solvent. Other solvents
used in oil dewaxing and wax deoiling are methyl butyl ketone, either
alone or mixed with toluene or benzene, and propane.
Some refiners also solvent treat vacuum resid to recover microcrystalline
waxes (petrolatum) which have different crystalline structures and pro-
perties than paraffin waxes.
An old process for treating lube oils, still used to some extent, is to
contact the oil with sulfuric acid. The acid reacts with unsaturates
and polyaromatics to form a sludge. Clay filtration is used to remove
the sludge from the oil.
2. Input Materials - Lubricating oils are narrow boiling - range cuts obtained
from vacuum distillation of atmospheric residuum. They are generally
fractionated from the 350-540°C portion of the residuum.
62
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3. Operating Parameters - Lube oil refining processes are generally low
pressure (<14 kgYcm*), low temperature (38-120°C) processes. Oil dewaxing
and wax deoiling processes are low pressure, (<14 kg/cm2} low temperature
(-40°C to +38°C) processes. Solvent-oil ratios vary with the process type,
solvent, and charge properties. The volume ratio is generally in the range
from 1.0 to 5.0.
4- Utilities - Oil dewaxing and wax deoiling processes are major energy con-
sumers due to refrigeration and filtration requirements.
Electricity: 10-60 kWh/m3 feed (2-10 kWh/bbl)
Steam: 300-1,000 kg/m3 feed (100-400 Ib/bbl)
i
5. Waste Streams - Atmospheric emissions are negligible. Lube oil processing
can contribute significant BOD loads to refinery waste water treating
systems if solvent-rich waste streams enter sewers. However, this contri-
bution has not been quantified.
If the acid treating/clay filtration process is used, the sludge can be
a solid waste problem. Again, the amount of acid sludge and waste clay
is unknown.
6. EPA Source Classification - None Exists.
7. References -
(1) Bland, Jdilliam F., and Robert L. Davidson, eds., Petroleum Processing
Handbook. N.Y., McGraw-Hill, 1967.
(2) Nack, H., et al., Development of an Approach to Identification
of Emerging Technology and Demonstration Opportunities,
EPA 650/2-74-048, Columbus, Ohio, Battelle-Columbus Labs., 1974.
(3) Soudek, M., Hydrocarbon Processing, Vol. 53, No. 12, December
(1974).
63
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MIDDLE AND HEAVY DISTILLATE PROCESSING PROCESS NO. 21
Lube and Wax Hydrotreating
1- Function - Lube oil and wax stocks are hydrotreated to improve product
quality. The hydrotreating process is used for viscosity index improve-
ment, desulfurization, denitrogenation, dimetallization, removal of gum
forming compounds, and color improvement.
The oil feed is mixed with make-up and recycle hydrogen and charged to
a fixed catalyst bed reactor. Reactor effluent flows through high and
low pressure separators to remove first hydrogen for recycle then light
ends. The product is then stream stripped to remove any remaining im-
purities.
This process can be utilized to improve the quality of refined lube oils
and waxes or to treat raw distillates and deasphalted oils. The latter
function can replace conventional lube oil processes like solvent re-
fining processes.
2. Input Materials - The feed to a hydrotreating unit can be either solvent
refined lube oils and waxes or raw distillates and deasphalted oils.
Hydrogen requirements vary from 20 to 30 m3H2/m3 oil (100-200 ft3/bbl).
The catalyst is generally a cobalt or nickel-molybdenum base.
3. Operating Parameters - The operating conditions within the reactor
are:
Temperature: 320 to 400°C (600 to 750°F)
Pressure: 35 to 50 kg/sq cm (500 to 700 psi)
4. Utilities -
Electricity: 15 kWh/m3 of feed (2.5 kWh/bbl)
Steam: 43 to 86 kg/m3 of feed (15 to 30 Ibs/bbl)
Heater Fuel: 55,500 to"222,000 kcal/m3 of feed (35,000 to 140,000
Btu/bbl)
5. Waste Streams - Atmospheric emissions which result from the operation
of this unit originate from the process heaters, periodic catalyst
regeneration, and fugitive hydrocarbon leaks in equipment. The emis-
sions from the process heaters will be discussed in a separate module.
Catalyst regeneration involves burning off deposited coke by passing
a steam and air mixture through the bed. The resulting gaseous
emissions include significant quantities of carbon monoxide. As with
all high pressure refinery equipment, a fugitive hydrocarbon emis-
sion problem exists. Emissions occur at relief valves, valve stems,
flanges, pump seals, and compressor seals.
64
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• Liquid waste streams which contain H2S result from the high and low
pressure separators. These streams are passed to a sour water stripper
which removes the contaminants from the water. The steam which
condenses within the reactor during catalyst regeneration operations
is contaminated with H2S and must be treated in a sour water stripper.
Spent catalyst is either sold to a precious metals reclaimer or
disposed of as a solid waste. Catalyst life may be as long as five
years, so this disposal problem is not significant.
6. EPA Source Classification Code - None exists.
7. References -
(1) "Hydrocarbon Processing Refining Processes Handbook", Hydro-
carbon Proc. 53(9), 1974.
(2; Nack, H., et al., Development of an Approachto Identification
of Emerging Technology and Demonstration Opportunities, EPA
650/2-74-028, Columbus, Ohio, Battelle-Columbus Labs, (1974).
65
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MIDDLE AND HEAVY DISTILLATE PROCESSING PROCESS NO. 22
Middle and Heavy Distillate Storage and Blending
1- Function - The purpose of storage is to segregate various hydrocarbon
fractions so that they can be blended to desired feedstock characteristics
or product specifications. The blending operation can be accomplished by
blending individual components in a single tank or by mixing the components
in a header. The first method is commonly used to mix feedstocks, while
the second method, often called inline blending, is generally used for
product blending. Finished products also require some storage capacity.
Storage capacity in a refinery might be dedicated to a particular service
or switched from one service to another. For instance, some gas oils are
stored in gas blanketed tanks to prevent quality degradation by oxidation.
These tanks remain in the same service year-round. Other tankage might
be used to store distillates in gasoline season and gasoline in distillatei
season.
2. Input Materials - The inputs to middle and heavy distillate storage in-
clude untreated kerosenes; light, heavy, and vacuum gas oils; and lube
distillates from crude distillation. Treated kerosenes, gas oils, lube
oils, and waxes from the hydrodesulfurization, cracking and lube re-
fining processes are also stored.
3. Operating Parameters - The operating conditions are usually ambient
temperature and pressure.
4. Utilities - A negligible amount of pumping energy is needed. No
other utilities are used.
5. Waste Streams - Blending and storage operations potentially represent •
the largest single source of hydrocarbon emissions from refineries.
Hydrocarbon atmospheric emissions result from the tank batteries used
in middle distillate storage. There are three mechanisms by which
hydrocarbon emissions occur during storage: breathing losses, work-
ing losses, and standing storage losses.
Breathing and working losses are associated with fixed- or coned-roof
tanks and standing storage losses are associated with floating-roof
tanks. Regulations require that tanks storing a liquid hydrocarbon
with a true vapor pressure from 1.1 to 7.8 mg/m2 (1.5 to 11.0 psia)
be equipped with a floating roof tank. Those tanks storing a hydro-
carbon with a vapor pressure below this range may use a fixed roof tank.
For this reason, probably only cat gasoline storage will require
a floating roof tank.
66
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However, a serious problem occurs when refineries, particularly those in
warmer climates, store finished winter gasolines destined for northern
markets. Winter gasolines generally have a high vapor pressure component
(usually butane) and this mixture would exceed the regulation vapor
pressure of 7.8 mg/m2 (11.0 psia) for floating root tanks. The end re-
sult is reduced blending flexibility for the refinery. Finished gasoline
is sometimes shipped with less butane than specifications permit in order
to comply with environmental constraints.
Assuming "new tank" conditions, the rate of hydrocarbon emissions
from gasoline storage in a floating roof tank is 0.0040 kg per day-
103 liters stored (0.033 lb/day-103 gal). For kerosene and fuel oil
storage in a fixed roof tank ("new condition"), the hydrocarbon
breathing loss amounts to 0.0043 kg per day-103 liters stored (0.036
lb/day-103 gal). Working losses total 0.12 kg per 103 liters
throughput (1.0 lb/103 gal).
There are no liquid wastes or solid wastes associated with the storage
and blending operation.
6. EPA Source Classification Code -
Fixed Roof Tanks:
Hydrocarbon Stored SCC Number
Kerosene (Breathing losses) 4-03-001-06
Distillate Fuel (Breathing 4-03-001-07
losses)
Kerosene (Working losses) 4-03-001-51
Distillate Fuel (Working 4-03-001-52
losses)
Floating Roof Tanks:
Hydrocarbon Stored SCC Number
Gasoline (Standing losses) 4-03-002-01
References -
~ ~J J ~r" ~ " •
(1) Environmental Protection Agency, Compilation of Air Pollutant
Emission Factors, 2nd Ed. with Supplements, AP-42, Research
Triangle Park, N.C., 1973.
(2) Nack, H., et al., Development of an Approach to Identification of
Emerging Technology and Demonstration Opportunities, EPA 650/2-74-
048, Columbus, Ohio, Battelle - Columbus Labs., 1974.
67
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Residual Hydrocarbon Processing
There are six process modules in the residual hydrocarbon processing segment.
These are shown schematically in Figure 4.
Residuum is the bottoms product of atmospheric or vacuum distillation of crude
oil. Residuum can be blended with gas oil or kerosene to a viscosity specifi-
cation producing a heavy fuel oil (No. 6 Fuel). This fuel is generally used
to fire industrial and ship boilers.
Most refiners upgrade the value of residuum by utilizing processes like de-
asphalting/asphalt blowing, visbreaking, coking, and catalytic hydrodesul-
furization.
6C
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LEGEND
O GASEOUS EMISSIONS
& LIQUID EMISSIONS
O SOLID EMISSIONS
COKINQ
v_y
v_y
FIGURE 4. REFINERY RESIDUAL HYDROCARBON PROCESSING
69
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RESIDUAL HYDROCARBON PROCESSING PROCESS NO. 23
Deasphalting
1- Function - Deasphalting is applied primarily for the separation of
asphaltic materials from heavy oil and residual fractions. This separ-
ation (sometimes called decarbonizing) recovers an oil for use as a feed
to catalytic processes and also produces a raw asphalt material.
Deasphalting is usually accomplished by a solvent extraction technique
using propane or other light hydrocarbon as the solvent. The vacuum
residue and liquid propane are pumped to an extraction tower at con-
trolled ratio and temperature. A separation based on difference in
solubility takes place producing a deasphalted oil solution and an
asphalt solution. The exit solutions are processed through evaporation
and steam stripping to recover the propane from the oil and asphalt
products.
2. Input Materials - The feed to a deasphalting unit is usually a vacuum
residue. A small amount of propane is required as makeup for that
which is consumed in the process. This amounts to about 0.2 m3/m3 of
feed (1.2 ftVbbl).
3. Operating Parameters - The operating conditions for the extraction
column are:
Temperature: 70 to 105°C (160 to 220°F)
Pressure: 32 to 42 kg/sq cm (450 to 600 psi)
Typical sizes of equipment range from an operating capacity of 17,000
to 28,000 m3/day (2700 - 4400 bbl/day).
4. Utilities -
Electricity: 0 to 20 kWh/m3 of feed (G to 3.4 kWh/bbl)
Steam: 86 to 400 kg/m3 of feed (30 to 140 Ib/bbl)
Heater Fuel: 127,000 to 220,000 kcal/m3 of feed (145,000 to
250,000 Btu/bbl)
Cooling Water: 7250 liters/m3 of feed (300 gal/bbl).
5. Haste Streams - The two sources of atmospheric emissions from de-
asphalting operations include the process heater flue gases and
fugitive hydrocarbon losses from high pressure equipment. Process
heaters will be discussed in a separate module. The miscellaneous
hydrocarbon leaks result from equipment with relief valves, pump
seals, valve stems, flanges, and compressor seals.
70
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A liquid effluent stream originates from the evaporator jet condensor
and trap. The condensed steam is contaminated with hydrocarbons and
is sent to the refinery waste water treatment facility.
6. EPA Source Classification Code - None exists
7. References -
(1) "Hydrocarbon Processing Refining Processes Handbook".
Hydrocarbon Proc. 53 (9), 1974.
71
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RESIDUAL HYDROCARBON PROCESSING
PROCESS NO. 24
Asphalt Blowing
Function - The purpose of asphalt blowing is to oxidize those
residual oils containing polycyclic aromatic rings. The resulting
increase in melting temperature and hardness improves their
resistance to weathering. These heavy residual oils, called asphalt,
are oxidized by blowing air through a batch heated mixture. The
reaction is exothermic and proceeds without additional heat after
the asphalt is heated to reaction temperature. The blowing is
stopped when the asphalt reaches the desired penetration specification
Input Materials - Feed to the asphalt blowing unit is vacuum resid
or raw asphalt from a deasphalting unit.
Operating Parameters - Asphalt blowing is an atmospheric pressure
operation. The asphalt feed is heated to 260°C to initiate the
oxidation reactions.
Utilities -
Heaters:
8,000-16,000 kcal/m3 feed (5,000-10,000 Btu/bbl) -
required to heat asphalt to reaction temperature.
Electricity:
6 kWh/m3 feed (1 kWh/bbl) - needed to compress
air for the air blowing.
5. Waste Streams - The only emissions are gases to the atmosphere.
The quantity is small, since the asphalt previously has been
distilled at high temperature. The vent pases are often highly
odorous and are usually incinerated. Before incineration of the
vent gases became common place, these gases constituted the most
objectionable form of air pollution from a refinery.
6. EPA Source Classification Code - None exists.
7. References -
(1) Nack, H, et al., Development of an Approach to Identification
of Emerging Technology and Demonstration Opportunities. EPA
650/2-74/048, Columbus, Ohio, Battelle-Columbus Labs., 1974.
(2) Sims, Anker V., Field Surveillance and Enforcement
Petroleum Refineries, Final
No. 68-02-0645, PB 236 669,
Report, EPA 450/3-74-04,
Pasadena, CA, Ben Holt Co.,
Guide for
Contract
1974.
72
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RESIDUAL HYDROCARBON PROCESSING PROCESS NO. 25
Residual Oil Hydrodesulfurlzation
1. Function - The catalytic hydrodesulfurization process is used to reduce
sulfur, nitrogen and metals concentrations in residuals. There is only
limited commercialization of the process since hydrogen consumption is
high and catalyst life is relatively short due to high concentrations of
contaminants in resids. Many refiners using this process charge an
atmospheric resid rather than a vacuum resid.
The process is the same as for lighter gas oils. The sour resid is mixed
with hydrogen, heated in a fired heater and passed through a catalyst bed
where the reactions occur in the liquid phase. Some processes utilize a
fixed catalyst bed while others have ebullient catalyst beds. Sulfur is
converted to H2S, nitrogen to NH3 and metals remain on the catalyst.
After products from the reactor are cooled, hydrogen and H2S are flashed
off in a series of high and low pressure separators. The hydrogen is
recycled and H2S is recovered for further processing. The oil product
is steam stripped to remove residual H2S. There may also be a fraction-
ation stage to separate out light hydrocarbon fractions. The desulfurized
resid is blended to fuel or processed further.
There is great interest in but limited application of the more severe
hydrocracking process, which substatially upgrades the value of residuum.
2. Input Materials - Feed to this unit is usually a high sulfur content atmo-
spheric residue having initial boiling points in the range of 300 to 390°C,
although some refiners change vacuum residuals. Also, hydrogen at the
rate of 70 to 120 m3/m3 of feed (400 to 700 ft3/bbl) is required.
3. Operating Parameters - The operating conditions for the reactor are:
Temperature: 340-450°C (650-850°F)
Pressure: 70 kg/sq cm (1000 psi)
Catalyst: Cobalt-molybdenum or cobalt-nickel.
4. Utilities -
Electricity: 6 to 24.0 kWh/m3 of feed (1 to 4 kWh/bbl)
Steam: 9 to 71 kg/m3 (3 to 25 Ib/bbl)
Heater Fuel: 15,700 to 157,000 kcal/m3 (10,000 to 100,000 Btu/bbl)
Water (cooling): 3570 to 4280 liters/m3 (150 to 180 gal/bbl)
Water (process): 100 liters/m3 (4.2 gal/bbl)
73
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5. Waste Streams - Atmospheric emissions which result from the operation
of this unit originate from the process heaters, periodic catalyst
regeneration, and fugitive hydrocarbon leaks. Emissions from the
process heaters will be discussed in a separate module. Catalyst
regeneration involves burning off deposited coke by passing a steam
and air mixture through the bed. The resulting gaseous emissions
include significant quantities of carbon monoxide. As with all high
pressure refinery equipment, a potential fugitive hydrocarbon emis-
sion problem exists. Emissions occur at relief valves, valve stems,
flanges, pump seals, and compressor seals.
A liquid waste stream which contains H2S is removed from the process
at the low pressure separator. It is equal in quantity to the amount
of process water added. This stream is passed to a sour water stripper
for processing. The steam which condenses within the reactor during
catalyst regeneration operations is contaminated with H?S and must be
treated in a sour water stripper.
Spent catalyst is either sold to a precious metals reclaimer or disposed
of as a solid waste. The catalyst may remain useful for a number of
years, so this disposal problem is not significant.
6. EPA Source Classification Code - None exists.
7. References -
(1) "Hydrocarbon Processing Refining Processes Handbook", Hydro-
carbon Proc. 53(9), 1974.
(2) Nack, H., et al., Development of an Approach to Identification
of Emerging Technology and Demonstration Opportunities, EPA
650/2-74-048, Columbus, Ohio, Battelle-Columbus Labs., 1974.
74
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RESIDUAL HYDROCARBON PROCESSING PROCESS NO. 26
Visbreaking
1. Function - The visbreaking process employs thermal cracking of resids
under mild conditions to reduce the viscosity or pour point of the charge,
The feed to the unit is heated and thermally cracked in the visbreaker
furnace. Cracked products are quenched with gas oil and flashed. The
vapor overhead is separated into light distillate products while the
liquid is processed in a fractionator, usually operating at a vacuum,
to recover a heavy distillate. Some refiners blend this distillate to
fuel oil while others use it as catalytic cracking feed. The residue
or tar from the fractionator is generally used for coker feed.
2. Input Materials - The charge to the visbreaking unit is either a topped
crude or vacuum resid. Lighter distillate stocks can be charged.
Operating Parameters - The operating conditions of the visbreaker
furnace are 450 to 480°C (850 to 890°F) and (4-18 kg/sq cm) 50-250
4. Utilities -
Electricity: 10.8 kWh/m3 of feed (1.8 kWh/bbi)
Furnace Fuel: 410,000 kcal/m3 of feed (260,000 Btu/bbl)
Water (Cooling): 6200 liter/m3 of feed (260" qals/bbl)
Steam: 286 kg/m3 (100 Ib/bbl) of feed is produced, with
57 kg/m3 (20 Ib/bbl) used in the fractionator
5. Waste Streams - Atmospheric emissions which result from the operation
of this unit originate from the visbreaker furnace and fugitive hydro-
carbon leaks. The emissions from the furnace will be discussed in
a separate module. The potential for fugitive hydrocarbon emissions
exists within this refinery unit. These emissions may occur at
such points as valve stems, flanges, pump seals, and compressor
seals.
A sour water waste stream is withdrawn from the fractionator. It
is equal in quantity to the amount of steam used in the column for
fractionation. This stream is sent to a sour water stripper for
processing.
No solid wastes are generated from this process.
6. EPA Source Classification Code - None exists
75
-------
7. References -
(1) "Hydrocarbon Processing Refining Processes Handbook".
Hydrocarbon Proc. 53 (9), 1974.
(2) Nack, H., et al., Development of an Approach to Identification
of Emerging Technology and Demonstration Opportunties,
EPA 650/2-74-048, Columbus, Ohio, Battelle-Columbus Labs., 1974,
75
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RESIDUAL HYDROCARBON PROCESSING PROCESS NO. 27
Coking
1. Function - Coking is a thermal cracking process in which crude oil
residue (vacuum residuals) and other decanted oils and tar-pitch pro-
ducts are cracked at high temperature and low pressure into lighter
products and petroleum coke. The objective is to produce gas oil and
lighter petroleum stocks from the residuum. There are two principal
coking processes: the fluid coking process and the delayed coking pro-
cess. The most widely used is the delayed coking process; very few
fluid coking units are now in service.
In the delayed coking process the charge stock is fed to the bottom
section of the fractionator where material lighter than the desired
end point of the heavy gas oil is flashed off. The remaining material
combines with recycle from the coke drum and is pumped from the bottom
of the fractionator to the coking heater where it is rapidly heated.
Steam is injected to control velocities in the tubes. The vapor-liquid
leaving the coking heater passes to a coke drum where the coke is formed
and recovered. Vapors from the top of the drum return to the fractionator
where the thermal cracking reaction products are recovered.
2. Input Materials - Feed to a delayed coking unit is usually crude
oil residue, decanted oils, or tar-pitch products.
3. Operating Parameters - Operating conditions within the coker tower
are:
Pressure: 1.8 to 2.1 kg/sq cm (25 to 30 psig)
Temperature: 382°C (750°F)
A heater heats the bottoms from the fractionator to 480 to 580°C
(900 to 1080°F).
4. Utilities -
Electricity: 9.5 kWh/m3 of feed (1.5 kWh/bbl)
Steam: 516 kg/m3 (180 Ibs/bbl) of feed is produced in the process,
while 230 kg/m3 (80 Ibs/bbl) is required for stripping.
Thermal: 475,000 to 630,000 kcal/m3 of feed (300,000 to 400,000
Btu/bbl)
5. Waste Streams - Atmospheric emissions which result from the operation
of this unit originate from the process heater, wind blown coke dust
that has been deposited on the equipment, storage containers for the
water used in cutting the coke, and fugitive hydrocarbon leaks.
Emissions from the process heater will be discussed in a separate
module. Particulate emissions can result from the coke dust which
often covers coking unit equipment. These fine particles will blow
with the wind unless the units are washed periodically. Most de-
layed coking units use water for cutting coke. The water is recycled
in this operation and stored in open containers. Since this water
77
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contains some sulphur compounds, it may be the source of objectionable
odors.
A waste water stream containing HaS is drawn from the overhead accumu-
lator on the coker tower. This stream is pumped to the sour water
stripper for purification before reuse or discharge.
A waste water stream is also produced as a result of steaming the coke
drum to remove volatile matter from the coke and using water to cool
the drum before opening. Most refiners attempt to remove the oil from
this stream and recycle as much as possible. However, much of this
water, which contains phenols, H2S and NHs in addition to oil, invari-
ably enters the wastewater treating system.
6. EPA Source Classification Code - None exists.
7. References -
(1) Nack, H., et al., Development of an Approach to Identification
of Emerging Technology and Demonstration Opportunities, EPA
650/2-74-048, Columbus, Ohio, Battelle-Columbus Labs., 1974.
(2) Sims, Anker V., Field Surveillance and Enforcement Guide for
Petroleum Refineries, Final Report, EPA 450/3-74-042, Contract
No. 68-02-0645 PB 236 669, Pasadena, Ca., Ben Holt Co., 1974.
78
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RESIDUAL HYDROCARBON PROCESSING PROCESS NO. 28
Residual Hydrocarbon Storage and Blending
1. Function - Residuals from crude distillation are stored in heated cone
roof tanks. Resid is cut with a lighter hydrocarbon, kerosene or light
gas oil, and kept hot to maintain pumpability. The resid can be pro-
cessed further (coking, visbreaking, hydrodesulfurization) or blended
with lighter oils to heavy fuel oil ( No. 6, Bunker C) specifications.
2. Input Materials - Residuals from crude distillation.
3. Operating Parameters - The resid is stored at 38-90°C (100-195°)
4. Utilities - Steam is used to heat the residua] oil.
5. Waste Streams - Negligible
6. EPA Source Classification - None exists
7. References -
(1) Radian Corporation, A Program to Investigate Various Factors in
Refinery Siting, Final Report, Contract No. EQC 319, Austin, Texas,
1974.
79
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Auxiliary Processes
There are several processing operations commonly used in the refining
industry which are not directly involved in the production of refinery
products. These processes are defined as auxiliary processes, and they
encompass such operations as wastewater treatment, steam generation,
and process heaters.
Products from these operations (clean water, steam, and heat) are common
to the majority of process units and are not limited to any one segment.
These auxiliary processes contribute to both the liquid and atmospheric
emissions from a refinery.
80
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AUXILIARY PROCESSES PROCESS NO. 29
Wastewater Treating
1. Function - The purpose of wastewater treating is to upgrade the quality
of effluent water so that it can be safely returned to the environment
or recirculated to the refinery. Refinery wastewater typically contains
oil, phenols, sulfides, ammonia, and dissolved and suspended solids.
Some refinery wastes contain other organic and inorganic chemicals, in-
cluding some toxic chemicals. The types of treatment processes utilized
vary with the types and concentrations of contaminants and with effluent
quality requirements.
Wastewater treatment processes can be separated into five general categories:
inplant pretreatment, primary treatment, intermediate treatment, secondary
treatment and tertiary treatment. Inplant pretreatment processes are
applied to individual aqueous streams before those streams are combined
with effluent flowing to primary treatment facilities. Some of the most
widely used pretreatment processes include sour water stripping, spent
caustic oxidation or neutralization, acidic/alkaline waste neutralization,
and cooling tower and boiler blowdown treatment.
Primary treatment facilities are usually designed for oil/water separation
and for removal of settlcable solids from the water. Two widely used de-
signs are the API separator and corrugated plate separators. Both pro-
cesses utilize gravity separation techniques to remove oil, oily sludge,
and grit from incoming wastewater before further treatment.
Intermediate treatment consists of a holding basin of several hours
residence time to allow leveling of hydraulic and contaminant concen-
tration surges, and dissolved air flotation units, sedimentation units
or filtration units to remove suspended matter from the water.
Secondary treatment processes are biological oxidation processes that
degrade the soluble organic contaminants in wastewater. The concentration
of contaminants is related to the biological oxygen demand (BOD) of the
wastewater. The biological processes utilize microorganisms and oxygen
to convert the soluble organic contaminants to COa, N2, and H20, thereby
reducing the BOD of the wastewater. Several biological processes are in
widespread use. Unaerated lagoons are the least complex but require
large land areas and low BOD loadings relative to the other processes.
Aerated lagoons utilize mechanical mixing and aeration to handle larger
BOD loadings. The trickling filter process and its variations, such as
the biodisc process, can handle relatively large BOD loadings. The acti-
vated sludge process and its variations can treat wastewater with high
BOD loadings. The trickling filter and activated sludge processes require
a clarification step to remove biological sludge from the effluent.
81
-------
Tertiary treatment processes are not widely used at the present time
but may be required as effluent quality regulations become more re-
strictive. Processes in limited use or in development include acti-
vated carbon adsorption, filtration, ion exchange and reverse osmosis.
The application of the process categories and individual processes as
described varies widely in the industry. All refines utilize some
combination of primary and intermediate treatment to remove separable
oils and solids from waste water. Most are using some form of biological
treatment although some may use chemical oxidation processes (oxidation
with chlorine, ozone or permanganate) or deep well disposal.
2. Input Materials - Effluent water streams from throughout the refinery
are feed streams to the wastewater treating system. Process water, once-
through cooling water, wash water, oily storm water, and cooling tower
and blowdown are examples.
3. Operating Parameters - Wastewater treatment processes are generally
operated at ambient temperatures and pressures.
4. Utilities - Utility requirements vary widely. The biological processes
such as aerated lagoons and activated sludge processes are the largest
energy consumers.
5. Waste Streams - The atmospheric emissions from wastewater systems consist
primarily of hydrocarbons released in the collection system and the
API separator. Extensive studies on API separators have shown that in
the process of treating aqueous effluents having a temperature of 60°C
and containing oil having a 10% TBP of 149°C, 16-17 vol % of the oil
vaporizes. Floating an insulating material such as foam glass slabs
on the oil has been found to reduce the hydrocarbon emissions to 2 vol
% of the oil. Sealing off API separators was found unsatisfactory due
to the creation of dangerous explosive spaces. Quantitative studies
have shown that the total hydrocarbon emissions from process pumps,
drains, and API separators range from 29-570 kg/1000 m3 capacity-day.
Solid wastes generated in the waste treatment plant consist of dirt,
grit, oily sludges, and clarifier sludges removed in the primary
treatment processes, and bacterial sludges removed in the secondary
treatment clarifiers. Dirt and grit are disposed of in landfills.
Oily sludges are usually landfilled but are sometimes incinerated.
Primary treatment clarifier sludges are disposed of in landfills and
evaporation ponds. Bacterial sludges are disposed of in incinerators
or landfills. The ash generated from burning sludges is normally dis-
posed of in landfills also.
6. EPA Source Classification Code - None exists.
82
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7. References -
(1) Nack, H., et al., Development of an Approach to Identification
of Emerging Technology and Demonstration Opportunities, EPA
650/2-74-048, Columbus, Ohio, Battelle-Columbus Labs., 1974.
(2) Radian Corporation, A Program to Investigate Various Factors
in Refinery Siting, Final Report, Contract No. EQC 319,
Austin, Texas, 1974.
83
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AUXILIARY PROCESSES PROCESS NO. 30
Steam Production
!• Function - A steam production unit is used to supply steam to various
processes for direct use in the operation, for heating, and to drive
steam turbines. From 85 to 285 kilograms of steam are used per
cubic meter of crude oil processed in a refinery. Process steam is
generated at about 35 kg/sq cm in typical large industrial boilers.
Steam of a lower pressure is obtained by reducing the pressure of
the 35 kg/sq cm steam.
Some refinery processes also generate steam in waste heat boilers.
The largest process-associated steam generator is the carbon monoxide
boiler on the exhaust from the catalytic cracker. The sulfur recovery
plant is another process that produces steam as a usable by-product.
Most of the process-associated steam production facilities produce a
low pressure steam.
2. Input Materials - The feed to the steam production unit is a water
stream which is treated to be non-corrosive.
3. Operating Parameters -
Furnace Temperature: 1200°C
Boiler Pressure: 35 kg/sq cm
4. Utilities -
Heaters: 792,500 kcal/m3 of crude
5. Waste Streams - Atmospheric emissions result from the fired haaters
associated with steam production and are directly dependent upon the
quality of the fuel burned. For residual oil fired boilers where S
equals percent by weight of sulfur in the oil, emissions are as follows
Particulates 2.75 kg/m3 fuel
Sulfur dioxide 19(S) kg/m3 fuel
Sulfur trioxide 0.25(S) kg/m3 fuel
Carbon monoxide 0.5 kg/m3 fuel
Hydrocarbons 0.35 kg/m3 fuel
Nitrogen oxides
tangentially fired - 4.8 kg/m3 fuel
horizontally fired - 9.6 kg/m3 fuel
Aldehydes - 0.12 kg/m3 fuel
84
-------
For gas fired boilers:
Participates - 290 kg/105 nr fuel
Sulfur oxides - 9.6 kg/106 m3 fuel
(based on 4600 g sulfur/105 m3 gas)
Carbon monoxide - 270 kg/10s m3 fuel
Hydrocarbons - 48 kg/106 m3 fuel
Nitrogen oxides - 230 kg/106 m3 fuel
S = weight percent sulfur in the fuel
Aqueous effluents are primarily boiler blowdown which does not contain
phenols or high BOD compounds. Boiler blowdown is often of high enough
quality to be reused in other processes with minimal treatment. Solid
wastes include ash from the fuel and sludges from treatment of boiler
feed water.
6. EPA Source Classification Code - None exists
7. References -
(1) Environmental Protection Agency, Compilation of Air Pollutant
Emission Factors, 2nd ed., AP-42, Research Triangle Park, N.C., 1973.
(2) Hack, H., et al., Development of an Approach to Identification of
Emerging Technology and Demonstration Opportunities, EPA 650/2-74-048,
Columbus, Ohio, Battelle-Columbus Labs., 1974.
(3) Radian Corporation, A Program to Investigate Various Factors in
Refinery Siting, Final Report, EQC 319, Austin, Texas, 1974.
85
-------
AUXILIARY PROCESSES PROCESS NO. 31
Process Heaters
!• Function - Process heaters are used throughout the refinery to supply
heat to raise input materials to reaction temperatures or cause
them to distill into various fractions. The heaters themselves are
not part of the processes and are considered here as a separate pro-
cess module.
2. Input Materials - Fuels to the heaters are usually either residual
fuel oils or refinery gases (mostly methane) produced as a by-product
throughout the refinery. Refinery gases produced from various pro-
cesses are piped to a common system known as plant fuel gas. The
plant fuel gas may contain high concentrations of sulfur if the plant
fuel gas has not been sent to an amine absorption unit, for removal of
acid gases. Burning a sour fuel gas would naturally result in
excessive sulfur dioxide emissions from the heaters.
In some areas of the country, most notably Texas and Louisiana,
refiners purchase natural gas as a clean fuel source rather
than burn residual fuel oils. Although this practice is declining,
it still exists and will affect the level of emissions from a refinery.
3- Operating Parameters - Most fired heaters are designed to raise
reactants to a maximum temperature of about 500°C. Therefore, the
actual firebox temperature will vary but will probably be between
1000 and 1500°C.
4- Utilities - The fuel bill for firing heaters will range between 5 and 10%
of the heating value contained in the crude that enters the refinery.
This means that for a 10,000 cubic meter per day plant, 500 to 1,000
cubic meters of the crude (as fuel oil equivalent volume) are used
to fire the process heaters. In terms of heating values, the fuel
requirements are 460,000-920,000 kcal/m3 crude to the refinery.
5. Waste Streams
For residual oil fired heaters:
Particulates 2.75 kg/m3
Sulfur dioxide 19(S) kg/m3 fuel
Sulfur trioxide 0.25(S) kg/m3 fuel
Carbon monoxide 0.5 kg/m3 fuel
Hydrocarbons 0.35 kg/m3 fuel
tangentially fired - 4.8 kg/m3 fuel
horizontally fired - 9.6 kg/m3 fuel
Aldehydes - 0.12 kg/m3 fuel
86
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Where S is the weight percent sulfur in the fuel
For gas fired heaters:
Particulates - 290 kg/106 m3 fuel
Sulfur oxides - 9.6 kg/105 m3 fuel
(based on 4600 g sulfur/106 m3 gas)
Carbon monoxide - 270 kg/106 m3 fuel
Hydrocarbons - 48 kg/106 m3 fuel
Nitrogen oxides - 230 kg/106 m3 fuel
6. EPA Source Classification Code - None exists.
7. References -
(1) Environmental Protection Agency, Compilation of Air Pollutant
Emission Factors, 2nd ed., AP-42, Research Triagle Park, N.C.,
1973.
(2) "NPRA '74 Panel Views Processes", Hydrocarbon Processing, 54(3),
(March 1975).
87
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AUXILIARY PROCESSES PROCESS NO. 32
Pressure Relief and Flare Systems
1. Function - Pressure and flare systems are used to control discharges of
vapors and liquids from pressure relieving devices, furnace blowdowns and
blowdowns from process units during start-ups, shut-downs or emergencies.
Although some pressure relief and safety val es discharge to the atmos-
phere, environmental and safety considerations generally require the use
of a closed blowdown system.
The blowdown system typically consists of a gathering system for all
discharges, a knockout drum to separate vapor and liquid and a flare to
insure combustion of vapors vented to the atmosphere. Liquid collecting
in the blowdown drum is pumped away to an oil recovery system. Flares
are provided with pilots and ignitor systems to insure continuous com-
bustion of hydrocarbons. Steam is usually injected into the combustion
zone to promote complete combustion in order to reduce or eliminate
smoking.
Most flares are designed as vertical stacks with the flare tip 20 to 300
feet above the ground. Heat liberation and combustion product dispersion
are the primary considerations in determining flare height. Other flares
are horizontal designs with the flare tip extending over a burning pit,
using steam or water sprays to control smoking. Another type, called a
ground flare, utilizes a series of burners at ground level. The burners
are designed to induce large quantities of air into the combustion zone
to eliminate smoking.
2. Input Stream - All units and equipment subject to start-ups, shut-downs,
upsets, emergency venting and purging are connected to a blowdown system.
3. Operating Parameters - A continuous combustion source is required at flares
tips to insure combustion of hydrocarbon vapors vented to the atmosphere.
4. Utilities - The steam required for smokeless flaring varies from 0.2 - 0.5
Ib Steam/1b Hydrocarbon.
5. Haste Streams - Hydrocarbon emissions from blowdown systems have been
estimated to range from 0.34-0.57 kg/m3 crude (120-200 lbs/103 bbl crude).
Waste water can result if a water quench is used to cool hot streams
entering the blowdown drum. The volume of water should be small compared
to total effluent and easily handled in the waste water treating system.
6. EPA Source Classification Code - None exists
88
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7. References -
(1) Atmospheric Emissions from Petroleum Refineries, a Guide for
Measurement and Control, PHS No, 763, Washington, D.C., Public
Health Service (1960).
(2) MSA Research Corporation, Hydrocarbon Pollutant Systems Study,
Vol. 1, Stationary Sources, Effects and Control, APTD-1499, PB
219073, Evans City, Pa., MSA Research Corporation (1972).
-------
APPENDIX A
CRUDE OIL ANALYSES
-------
Table A-l. HYDROCARBONS ISOLATED FROM A REPRESENTATIVE
PETROLEUM (PONCA CITY, OKLAHOMA FIELD)
No. Formula
1. CH«
2. C.Hi
3. CiHt
4. C.Hu
5. C4H»
6. C.Hu
7. C»Hu
8. C.H..
9. C.Hu
10. CiHu
11. C.HU
12. C
-------
Table A-l (Continued). HYDROCARBONS ISOLATED FROM A
REPRESENTATIVE PETROLEUM (PONCA CITY, OKLAHOMA FIELD)
No.
33.
34.
35.
31.
37.
38.
31.
40.
41.
42.
43.
44.
45.
46.
47.
48.
41.
50.
51.
52.
53.
54.
55.
M.
57.
58.
59.
M.
tl.
82.
Formula
C.Hi.
C.H,.
C.H,,
C.H,.
CiH.
C.Hi.
C.H,i
C.H,.
CiHu
C.Hii
C.Hu
CiHi*
CiH,.
C.Hu
C.Hu
CtU.t
CiH»
C.Hu
C?Hi.
C.Hu
C.H..
CiH,.
CtHi.
CtHn
C.II,,
C.Hi.
CiHu
C.Hu
CiHu
C,H»
Compound
1 , tranj-2 ,cw-4-Trimethylcycto-
pentane
2,4-Dimethylhexar.e
2,2,3-Trimethylpentane
1 ,iron»-2,ci»-3-Trimethylcyclo-
pentane
Toluene
3,3-Dimethylhexane
2,3, 4-Trimethylpentane
1 , 1 ,2-Trimethylcyclopentane
2,3,3-Trimethyipentane
2,3-DimethyIhexane
2-Methyl-3-ethylpentane
l,cw-2.(rana-4-Trirnethylcyclo-
pentane
l,cw-2,iran»-3-Trimethylcyclo-
pentane
2-Methylheptane
4-Methylheptane
3 . 4-Dimethylherane
3-Methyl-3-ethylpentane
3-Ethylhexane
Cycloheptane
3-MethylKeptane
1 , rran*-4-Dimethylcyc!ohexane
1 , I-Dimethylcyelohexane
1 ,c«-3-DimethyIcyclohexnne
!-Methy!-
-------
Table A-l (Continued). HYDROCARBONS ISOLATED FROM A
REPRESENTATIVE PETROLEUM (PONCA CITY, OKLAHOMA FIELD)
No.
63.
64.
65.
66.
67.
68.
69.
70.
71.
72.
73.
74.
75.
76.
77.
78.
79.
80.
81.
82.
83.
84.
85.
86.
87.
88.
89.
90.
91.
92.
93.
94.
95.
96.
97.
98.
99.
100.
101.
102.
103.
104.
105.
106.
107.
108.
109.
110.
111.
112.
Formula
C,Hi,
C,Hi,
dlli,
C,H,,
C.H,,
C.H,,
C.Hi,
C.H,,
C.H,.
C,Hu
C.H»
Compound
1 ,«3-4-Dim<>thylcyclohexane
l,(ron«-3-Dimcthylcych)hexane
n-Octane
Isopropylcyclopentane
Tetrnnwthylcyclopentane'
l-Methyl-cis-2-ethylcyclopen-
tane
1 ,c«-2-Dimethylcycloliexane
n- Propy Icyclopentane
2,3, 5-Trimethylhexane
Ethylcyclohexanc
2 , 6- Dimethylheptane
j
CiHu 1 Ethylbeniene
C.Hii | 1.1, 3-Trimethylcyclohexane
C.Hn 1 p-Xylene
CiHio | m-Xylene
C.H»
C.Hi,
C.H«
C,H»
C.H»
C.H,,
C.Hi.
C.Hi,
2,3 Dimethylheptane
T ri meth ylcy clohexa nem
4-Methyloctane
2-Metbyloctane
3-Methyloctane
o-Xylcne
Monocycloparaffinm
Dicyc!oparaffinm
C.Hu n-Nonane
C.H,.
C.H.t
Isopropylbenzene
n-Propylbenzene
C.Hi! , l-Mothyl-3-ethylbenzene
C.Hu ! l-MctliyI-4-cthylbenzen*
C.Hii i 1,3,5 Trimethylbenzcne
C.Hii I l-Methyl-2-ethylbenzene
Ci.II« ! 4-Mcthylnonane
I
Cull,! ! 2-Methylnonane
!
CiaH:t • 3-Methylnonane
CioII,4 ! ftil-Jliitylbeiizene
CiHu 1,2,4-Trimrthyllx'nzi'ne
Ci«U-i n-Oecane
C.llu 1,2,3-Trimethyllwnzene
CiaHi4 l-Methyl-3-propyllienzene
C«Hw
Ci.Hi.
d.Hu
C.«Hu
Ci»H,4
Cl.11,4
CuHM
C,oHi<
CwIIii
CiiHt.
Cull,.
1.2 Diethylbenzene
l-Methyl-2-propylt)enzene
l,4-Dimethyl-2 ethytbenzene
trans- Decahydro naphthalene
1.3-Dimcthyl-4-ett,ylbcnzene
1 , 2- Di methyl-3-e thylTx-nzene
n-Undecane
1,2.4,5-Tetramcthylbenzene
l,2,3,5-Tetramcth>lbenzcne
Dicycloparaffin
AlkyHx-nzene0"
CtcH,4 1,2,3,4-Tetramethylbenzene
Type'
Cyclohexane
Cycluhexune
Normal paraffin
Cychipentnne
Cyclopentane
Cyclopentane
Cyclohexane
Cyclopentane
Branched par-
affin
Cyclobcxaoe
Branched par-
affin
Benzene
Cyciohexane
Benzene
Benzene
Branched par-
affin
Cyclohexane
Branched par-
affin
Branched par-
affin
Branched par-
affin
Benzene
Monocyclo par-
affin
Dicycloparaffin
Normal paraffin
Benzene
Benzene
Benzene
Benzene
Ber.tcne
Betizeno
Branched pfir-
affin
BrHnchcd pur-
affm
Branrhcd p»r-
afTm
Benzene
Benzf-nc
Normal pnratTm
Benzene
Benzene
Benzene
Benzene
Benzene
Die yclo para. Rln
Benzene
Benzene
Normal paraffin
Benzene
Benzene
Dicyclo paraffi n
Benzene
Benzene
"
Botlinn
j«nnt
at 1 atm.
V
u.
124.32
124.45
125.66
128.42
127.4
128.05
129.73
130.95
131.34
131.78
135.21
136.19
136.63
138.35
139.10
140.5
141.2
142.48
143.26
144.18
144.41
145.6
146.7
150 80
152.39
159.22
161.30
161.99
184 72
165.15
165.7
166.8
1B7.S
189 12
169 35
174 12
176 03
1M.80
183.42
184.80
186.91
187.25
188.41
193 91
195.39
196.80
198.00
202.5
204.1
205.04
Purity
of the
best
sample
iso-
lated0
Mole
per cent
76'
49'
992
IS'
90
52'
45 '
49'
16'
94
98.6
96
99.9
Esti- '
mated '
amount '
m t \e
crude
petrol-
eum'1
Volumt
ferctnl
0.09' ,
0.07'
1.9
0.01'
0.11
0.04'
0.06'
0.06'
0.031
0.37' !
0.05
0.19
0.2
99.8 < 0.10
99.9 i 0.51
60 0.05
95 0.2
80 0.1
99.9
0.4
95 0.1
1
99.7 ! 0.27
99
99
99.94
99.3
I
t
1.8 .
0.07'
.
88 ' 0.09'
99h ; 0.171
94h I 0.06'
99.9 ; 0.12'
89h * 0.09'
96 0.1
;
99.9 03
98 0. 1
1
' 0.01'
99 7 0.51'
99 9 l.S
M S ' 0.12
( I
i \ i '
' i ' •
'
I !
f 1 i
' i '
' '
(
'
99.97 1.6
( (
' ! '
' I '
98
0.06
99.9 ! 0.2
94
-------
Table A-l (Continued). HYDROCARBONS ISOLATED FROM A
REPRESENTATIVE PETROLEUM (PONCA CITY, OKLAHOMA FIELD)
So.
III.
114.
W.
m.
11T.
US.
119.
120.
131.
IX.
m.
124.
125.
125.
137.
128.
12«.
130.
Formula
CnHii
C,,H..
CiiHu
CiiHn
C,..Hll
C1(H.
CiiHu
CaHu
CiiHu
C«H«
CiiHi.
CiiHii
CwIIw
CiiHit
C.sIIn
CuHu
C,iH»
CirllH
Comf*iuntl
1 ,3-Dim«thyl-4-a'propylben-
tene"
1 ,2,3. 4-Tetrahy.iro naphthalene
l,2-Dimethyl-4-n-propj-lben-
lene"
Trimethylethylbenzenem
n-Dodecane
Naphthalene
Aromatie-cycloparatfinm
&- Methyl-[l, 2,3, 4-tetrahydro-
naphthalene)
5-JIethyl-[l,2,3,4-tetrahydro-
naphthalcnej
n-Tndecane
2-Methytnaphthalene
1- Methyl naphthalene
n-Tetradecsne
2,6-Dimethylnaphthalene
n-Pcntadecane
Trimethylnaphthalene*
n-Hexadecane
n-Heptadecane
TYJIL-*
B«niene
Tetrahydro-
naphthalene
Benzene
Benzene
Normal paraffin
Naphthalene
Aromatic cycin-
paraSin
Tetrahydro-
naphthalene
Tetrahydro-
aaphthalene
Normal paraffin
Naphthalene
Naphthalene
Normal paraffin
Naphthalene
Normal paraffin
Naphthalene
Normal paraffin
Normal paraffin
Boiling
pninlh at
1 .urn.
*C
206.5
207. S7
208.5
212.3
215.28
217.46
220.7
229.03
234. as
235.44
241.05
244.64
253.57
262
270 63
2S5
2M.79
301.82
Purity
of the
best
i-imple
iso-
lated1'
Male
ftr cent
W
99.:
99
97
99.9
99. Q
97
99.5
99.7
98
99.9
99.7
93. 5k
(
98. 5k
f
98k
97'
R.ti-
mated
amount
in the
crude
petrol-
eum"1
Volume
t" tent
0.03
0.03
0.03
0.04
1.4
0.06
0.04
0.09
0.08
1.2
0.2
0.1
t.O
1
0.3
f
0.7
0.8
* The compounds aie clasaifieil according to the following t>p«: normal paraffin; branched puraffin;
cyclop«ntane (cyciopontane and ita aikyl derivatives); cyclohexanc (cyclnhexane and its alkyl derivatives),
beniene (benzene and its alkyl derivatives^; naphthalene (naphthttlene and iu alkyl dcri\atives); tetrahy-
dronaphthatene (tutrahydronttphth.'tlene unil Jta alkyl depi\ attvra) ; aroniatif-cyclopuraffin (mixed
type); dicycluparaffin. "Monocyclnpaniflin" indicates either the "cyclopentane" or the "cyclohexane" type.
b This is the \*alue for the pure compound, as taken from the Tables and Hica of the API Research Pro-
" ject 44 (1). and is net necessarily the tennujruture at winch the compound appvurs m tho di<*ti[Iutton of the
appmprmtc fr.tctn n of pt'truloum.
* Whi're the amount "f the l>Obl Dimple laolttrcil witaxufTu'ient, and the sample was crjstaihzable, the purity
has beeij calculated from the \ulue of the freozum point pro\ tt>n-,lv ri'i>*>rTOil ;md the prr«-eut liot inlne^ <-f
tho frees ing jxunt for zero impurity and i-ryot-coptc i-i>n>tmits from the A 1*1 Research rrojcctw -J-J nn^l 6, \\hri-c
not evaluated rryos-eopicully, tlic pnrtty hiu* Inrrn c\Hhuitc»l fn»m tho ph>-i<"»l i>ro(*ertios nr >pectnigniphie
J The values fur the amount in the erudo petroleum are nximlt'tl e
cume available frum the work in progress.
subject to rt»\i>ion as new data
* The numbers m this column refer to the published papers c,f the American Petroleum Insntutc Researdi
Projects, a list of which is Kuun in \ppeiidi\ I.
1 Not deteiiaincd.
* Unpubii&hed.
** Determined t>pectrogr:iplucally fium mctu»urcmenU mude in the fiocony-Vucuum I^ibotuiorifb, I'aula-
boro, N. J.
* Determined spectrographically from measurements made in the laboratories of the Humble Oil and
Refining Company, Houston, Texas.
* Determined fptctroeraphically from measurements made in the follov, ing laboratories: Humble Oil aud
Refining Company, Bajtown, Texas; Socony- Vacuum Laboratc-iies, 1'aubboro, N. J., Standard Oil De-
velopment Company, Elizabeth, N. J.; Suu OU Company, Ncrv, fx>d, Pa.
* Purification of these Camples was not carried to Completion because, for purpcscsof itlent'ficution, mucli
purer samples were available from other sources.
m Identity not yet established.
B Tentative; identification not complete.
95
-------
Table A-2. PROPERTIES OF UNITED STATES CRUDE OILS
Item
No.
1
2
3
i
5
«
7
8
9
10
11
12
13
14
15
18
17
18
18
20
21
22
23
24
25
28
27
28
29
30
31
32
33
34
35
38
37
38
39
40
41
42
43
44
45
48
47
48
49
50
51
52
53
54
55
58
57
Stan
Field (Formation, age)1
Alabama
Citronelle (Rodessa L, Cre )
Alatka
Arlcaniai
Magnolia (Reynolds-Smackover, Jur.)
Sehuler (Jones 4 Cotton Valley, Jur.)
Smackover (U. Cre.)
California
Belridge, South (Tulars, Plio.-Pleist.)
Brea Olmda (Mio.)
Buena Viata (27-3 Basal Etchegoin, Plio.)
Castaic Junction (Zone 10. Mohnian, Mio.)
Cat Canyon, West (Los Flora. Mio.) ....
Coalmga, East (Main Gatchell, Eoc.)
Coalinga Nose (Gatchell, Eoc.)
Coalinga, West (Temblor, Mio.)
Coles Levee, North (Mio.)
Coyote, West (Emery, Repetto, Plio.) ....
Cymric (MeKittriek Group, Tulare, Plio.-
Pleiet.)
EdUoa (Chanac, Jur.)
Elk Hill* (Shallow U. Plio )
Gosford, East (Middle & Lower-SUvena,
Mio ) . .
Greeley (Rio Bravo- Vedder, Mio.)
Guijarral Hills (Leda Ohg.)
Huntington Beach (S. Main area, Mio.)...
Kern River (Kern River, Plio.-Plcist.) . . . .
Kettleman North Dome (Temblor, Mio.)..
Lonn Beach (Alamutoa, Repetto, Plio.) . . .
Midway-Sunset (Plio.-Pleist.)
Montalvo, Weal (Coloma. Scape, Olig.) . . .
Mount Poao (Vedders, L. Mio.)
New hulI-Potrero (Modelo, Mio.)
Rincon (Ptio.)
Russell Ranch (Dibblee, Vaqueroa, Mio.)..
San Ermdio Nose (Reef Ridf?e Mio.). ....
Sansinena (Mio.)
Santa Maria Valley (Monterey, Mio.)
Seal Beach (McGrath Mio )
Wheeler Ridge (Eoc )
Wilmington (Harbor area, Terminal, Mio.)
Colorado
Adena (Dakota "J" Cre.)
Rangely (Web«r, Penn.)
Grav-
ity.
"API
43.6
29.7
38.4
36.6
32.8
22 5
35 0
15.0
24 0
30 6
19.0
17.5
28.8
31.5
20.2
34.0
32.3
32.5
12.7
29.9
25.2
22.8
17.5
34.0
37 2
36 8
37 6
22.6
18.1
14 8
12.6
34 0
22.6
21.6
17.3
16 0
32.7
25 7
22.6
28.2
38.6
35.2
11.1
29.7
28 8
32.8
U 7
31.7
23 3
40 6
23.8
31 3
37.0
22 3
44.7
34.8
48.1
Sulfur,
wt.
per cent
0.38
0.16
0.90
1.36
1.55
2.10
0.56
0.23
0.75
0.59
3.40
5.07
0.31
0.25
0.55
0.39
0.82
0.42
1.18
0.40
0.20
0.68
0.93
0.57
0.31
0.63
0 40
1.57
2.50
0 85
1.19
0 40
1.29
0 86
4 10
0.68
0 56
1.72
1 86
1.40
0 35
0 35
2.25
0.83
0.87
0 33
4 99
0 53
2 79
0.16
1 84
0.94
0.29
1.33
<0.10
0.56
0.12
Viscos-
ity.
SUSat
100°F
40
61
33
42
52
220
40
2,440
135
48
1,230
3,000
67
48
195
43
50
49
6,000
60
115
135
1,750
51
41
40
37
210
680
5,100
6,000
44
208
210
7.648
1,900
46
95
230
80
38
43
6,000
59
63
47
6,000
52
220
35
160
56
38
210
36
48
33
Carbon
residue
of
residuum,
wt.
per cent
6.7
22.3
6.7
11.3
12.0
8.5
8.3
11.3
14.2
12.1
9.4
13.3
9.9
8.0
10.9
10.3
11.6
6.5
11.0
12.2
11.2
4.6
9.8
8.0
11.3
10.9
8.0
6 2
12.3
10.0
10.0
12.3
6.3
5 7
7 9
10.9
11.4
7 8
11.5
11.0
7.1
13.1
4.6
8.8
9.8
10.1
14,8
10 8
13.5
9 8
13 2
13.5
7.8
8 3
2.9
7.8
4.8
Gasoline and
naphtha
Per
cent
34.2
27.4
32.2
30.8
26.4
11.2
35.5
2.1
19 4
33.9
17.1
13.3
23.2
25.1
6.9
35.0
29.9
30.1
26.4
20.8
H.I
0.7
34.6
37.3
37.7
37 5
20 0
11.7
33.5
13.7
14. S
14 6
33.9
20.3
18.9
26.3
40 3
32.9
27 3
28 1
28 5
11.3
29 0
20 4
47.8
17 9
30 0
34.9
16 7
37.1
26 1
49.9
Grav-
ity.
"API
65.6
58.7
59 2
82.6
60 2
49.0
56.4
44.3
51.3
54 2
57 4
58 9
52 3
53.0
45.2
56.2
53 7
56.4
52.7
51.3
49.9
43.4
57.7
57.4
58.4
54.9
52.3
48 5
54.2
51 3
51.1
55 7
57.2
56 2
52 0
56.7
56.9
58 4
56 2
52.5
52 0
53.0
55 9
58.2
54 2
52 5
57.4.
55.4
52.5
60.5
59 5
64.8
Kerosina
distillate
Per
cent
20.7
9.1
10.5
10.0
9.5
5.5
2.6
4.6
4 8
1.8
5.5
5.1
4.4
6.1
4.8
2.7
4.5
3.8
3.3
4.6
4.4
8.3
4 9
3.4
5.7
4.1
18.5
10.3
11.0
Grav-
ity.
•API
47.2
42.1
43.8
43.4
43.2
41.1
42.1
40.9
40.0
44.7
40.7
40.2
40 6
40.6
40 0
40 6
40.4
41.1
41.1
40.2
41.3
40.6
41.5
41.1
39 6
40 4
42.8
41.5
43.6
Gas oil
diacillate
Per
cent
9.6
15.4
22.2
18 0
15.5
20.6
21.2
17.2
20.7
21.2
16.0
14 0
26 0
32.2
26.5
21.0
18.8
17.9
11.2
19.5
21.5
28.7
19.0
19.6
18.5
20 3
27 0
18 6
19.3
13 7
9 6
20 6
17.9
23.5
12.6
13 8
16 8
17 3
20 7
18.4
19 2
24 7
11.7
18.2
22.5
22.7
15.3
19 5
15 5
19.4
21.0
16 3
28.1
19.4
12.8
15.3
15 0
Grav-
ity,
'API
38.2
34.6
35.2
35.2
35.8
33.0
35.4
30.4
33 8
32.5
33.2
33 2
34.4
33 S
29.7
35 0
34.4
34.4
31.0
34.6
32.7
31.7
30.8
35 8
34 6
35.0
35.0
33.4
31.9
31 0
29 9
34.8
34 2
32.1
34 8
30 6
34 4
35 0
33.4
34.8
35.2
34.8
30.2
35.0
34 0
34.6
32.5
34 8
33 6
33 4
34 0
34.6
34 4
33.0
37.6
34.6
37 4
Lubricating
distillate
Per
cent
17.1
16.7
11.4
16.2
16.3
20 2
15.5
29.6
20.4
15 0
13 1
13 5
21.6
16.2
28.9
16.3
16.9
16.6
26.6
17.9
19.5
22.0
25.4
16.6
16.5
16.1
14 7
17 9
17 2
29.1
23 3
20.5
24.1
20 7
19 2
33 8
14.9
19.6
17.3
18.4
14.9
17 4
14.7
19 1
18.3
17 5
11.3
18.1
14.1
15 5
18 4
16 3
17.2
20.7
12.5
20.3
12.3
Gravity,
'API
38.6-28.4
31.1-22.5
31.5-25.9
31.0-24 2
31.3-24.5
27.9-21.3
31 3-22.5
24.3-12.0
28.9-16 8
27.1-18.4
27.9-19 2
27.5-20 0
28.2-22 5
28.4-22.5
24.5-14.4
29.7-19.7
30.2-21.5
29.7-21.8
25.4-15.0
29.9-21.5
28.6-19.5
25.7-17.8
26.6-18.1
30 0-20 2
30.6-22.0
30 8-22 6
30 6-23.1
28.4-17 0
26.4-17.9
25 4-15.0
24 5-15 1
30 8-19.7
29 1-17.8
25.9-16.0
28 2-19.4
26.4-15 3
30.4-22.1
29.3-19 0
28.8-18.9
30.6-20.3
31.3-24 2
28.0-22 8
25.6-17 3
29 9-20.5
29.5-20.0
30.4-23.1
25.4-18 2
30 6-20.7
28 8-20 2
28 9-21.8
28 4-20.0
31.1-20.7
29 9-23.5
27.1-17.1
36.8-31 1
32 1-24.5
34.8-28.4
Reftduum
Per
cent
16 7
31.4
20.5
24.9
31.7
47.0
22 2
49.4
37.7
28 0
53.3
55.7
28.4
24.8
36 5
25.3
29.2
27.6
59.4
29.9
38.0
37.4
54.4
25 0
19 9
20.7
17.8
43.1
51 6
55 8
65 7
19 1
38.7
40 8
50 0
52 0
28 4
36 0
42.9
34.1
18.6
23 0
72.0
30 3
30 9
23 2
61.3
28.1
46 0
8 9
41.9
31.5
17 3
42.1
15 9
26.5
10.8
Grav-
ity.
•API
18.5
7.8
17.3
13.6
13 2
12.2
11.9
7.1
7 8
11.0
5.6
4.3
11.6
13.5
10.3
11 7
11.4
10.4
6.8
11.0
10.1
11.1
11.3
10 0
12.0
12.0
13 9
7.9
7.6
8.9
8.2
11.7
8.7
9 2
2.8
10.3
10 1
7 1
7.8
8 5
15.0
11.4
8.8
10.6
10 0
12.0
4 8
11 3
7 5
12.0
9.4
10.9
15 0
8.7
21.8
15.6
20.8
From Petroleum Processing Handbook edited by W. F. Bland and R. L. Davidson, Copyright © 1967
by McGraw-Hill, Inc. Used by permission of McGrav»-Hi11 Book Company.
96
-------
Table A-2(Continued). PROPERTIES OF UNITED STATES CRUDE OILS
I torn
No.
58
59
60
61
82
63
84
65
66
67
68
69
70
71
72
73
74
75
76
77
78
7P
SO
81
82
83
84
85
86
87
88
89
90
91
92
03
94
95
96
97
98
99
100
101
102
103
104
105
106
107
108
109
110
111
112
113
114
115
116
117
Stall
Field (Formation, age) '
Jttinait
Clay City (Mix )
Dale (Aux Vases Miss.)
Loudon (Bethel, Miss.)
Salem (Aux Vases Miu.)
Indiana
Kanta*
Bemis-Shutta (U. Arbuckle Ord.)
Chase-Silica (Kansas City, Peon.)
£1 Dorado (Admire, Perm.)
Hall-Gurney (Kansas City, Pena.)
Seely-Wick (Bartlesville, Penn.)
Louisiana
Avery Island (U. Mio.)
Bateman Lake (9900' U. Mio )
Bay de Chene (Mio.)
Bay Marchand (3900' Mio )
Bay Si. Elaine (U Mio.)
1 Bayou Sal* (Morin, Mio.)
Black Bay, West (7300', Mio.)
Black Bay West (8050' Mio.)
Black Bay West (8300', Mio.)
Black Bay, West (8650', Mio.)
Black Bay, West (9100', Mio.)
Black Bay, West (9200', Mio.)
Caddo (Annona Chalk, U. Cre.)
Caillou Island (No. 70, Mio.)
Cameron, West (Block 45, U. Mio.)
Cote Blanche Bay West (U. Mio.) ......
Cotton Valley (Bodcaw, Jur.)
Cox Bay (Mio.)
Delhi (Tuacaloosa U. Cre.)
Delta Farms (Mio.)
Duck Lake (U. Mio.)
Erath (Mio )
Eugene Island (Block 32, 7500', Mio.)
Eugene Island (Block 126. Mio.)
Eugene Island (Block 188, 9080', Mio.) . . .
Garden Island Bay (Mio.)
Golden Meadow (Mio.) . ...
Grand Bay (Mio.)
Grand Isle (Block 16, B-l, Seg. E, Plio.) . .
Grand Isle (Block 18, B-2, Plio.)
Grand Isle (Block 47. Plio.-Mio.)
• Hackberry, West (U. Mio.)
Krotz Springs (Fno Olig.)
Lafitte (Mio.)
Lake Barre (R-l Mio )
Lake Pelto (U. Mio ) .
Lake Washington (Mio.)
Leeville (U. Mio.)
Little Lake (Eggerella 2 Mio.) .....
Little Lake (Eggerells 4, Mio.)
Little Lake (Textularia Panamensii 1, Mio.)
Little Lake (Textularia Panamenaig 2, Mio.)
Little Lake (Textularia Paoamenaii 6, Mio.)
Grav-
ity,
•API
38.6
36.4
35.6
36.2
36.0
37.4
37.2
35.2
34 6
38 8
36.8
39.4
43 0
41.1
23.5
39.2
34 4
38 2
33.6
20.2
33.6
36.2
30 0
23 0
30.6
34.4
35 2
34.4
36.8
35.4
39.2
33 6
40.6
31.9
41.7
35.6
36 4
31.0
39.2
36.2
27.1
34.8
37 6
35 0
36.4
34.6
33.6
31 3
54 9
36 2
40.4
34.6
35.4
28.2
35.4
32.1
32.5
31.7
36.2
46.3
Sulfur,
wt.
per cent
0.19
0.15
0.21
0.22
0.23
0.20
0.17
0.20
0.57
0.44
0.18
0.34
0 27
0.23
0.93
0.41
0.12
0.15
0.27
0.48
0.39
0.16
0 27
0 38
0.28
0.18
0.17
0.19
0.37
0.23
<0 10
0.16
•CO 10
0.38
<0.10
0.26
0.14
0.20
<0.10
0.19
0.35
0 22
0 18
0.31
0 18
0 22
0 23
0 29
<0.10
0.30
O.H
0 21
0.14
0.37
0.20
0.27
0.28
0.27
0.15
<0.10
Viscos-
ity,
SUSat
100°F
43
49
46
45
45
44
43
47
52
42
43
43
38
38
84
41
46
41
52
270
49
44
57
140
58
45
43
46
44
45
41
49
46
56
39
44
44
54
39
52
91
49
44
48
40
46
56
45
34
45
39
45
47
82
45
58
61
59
46
34
Carbon
reeidue
o(
residuum,
wt,
per cent
8.2
4.3
8.4
7.6
7.7
9.0
11.4
11.2
11.9
6.7
8.3
8.6
12.7
9.6
14.3
11.2
3.1
3.3
' 5.0
7.5
4.3
2.2
6.3
9.0
7.1
5.6
5.1
4.6
6 0
8.3
2.3
3.9
0.6
5.7
5 1
4 9
2.0
2.5
1 3
2.9
4.7
7.4
1.9
3.0
3 7
5.1
5.7
5.2
Nil
3.3
2.2
3.9
5.6
9.2
4.7
5.3
7.1
5.3
3.9
4 8
Gasoline and
naphtha
Per
cent
32.8
29.1
29.8
30.2
31.2
32.6
32.5
30.9
28.3
38.7
32.1
36.2
40.9
35.3
22.8
34 3
18.2
22.5
19.3
2.5
21.2
18.5
15 2
6.3
16.2
19 8
21.7
19.4
27 0
28 1
18 2
16 6
19 1
20 4
33.1
28.0
11.7
15 0
13.0
17 6
4.1
23.6
19 1
20.5
25.8
21.0
18.0
22 0
87 0
20 8
36.2
17.9
14 6
20.0
26.8
18.3
18.2
17.8
17 3
45.9
Grav-
ity.
"API
59.2
58.2
60.0
59.5
58.4
60.5
59.7
59.7
60 5
60.0
59.5
60.0
64.5
61.8
56.4
62.9
55.4
53.2
55.7
45.8
52.0
53 5
54.2
48.5
55.9
54 2
55.2
53.5
54 7
56 7
51.6
51 1
60.0
58 2
61.0
55 4
52 0
54 4
52 0
57 9
45.8
55.4
54 4
55.2
54.7
53 2
56 2
49 5
62.6
55.2
57 2
53 7
52.5
57.7
52 4
55 9
56.2
54.0
55.4
59 7
Keroauie
diitillaU
Per
cent
10.1
10.5
9.5
10.2
10.3
10.3
9.7
10.5
9.6
11.7
13 3
11.0
11.8
10.5
9.1
9 9
4.6
31.6
11.5
6.7
15 5
5 5
4.9
13 8
13.0
12 5
12.4
12 1
21.9
5 5
15.8
4.9
10.4
14 1
13.1
40.4
20.5
5 3
23 0
12.5
15.0
6 9
12.7
7.0
10 7
13 8
14 4
7 5
13.8
3 7
15.7
12 2
13.1
13.2
13 7
24.8
Grav-
ity,
"API
42.3
42.8
41.9
42.6
41 9
41.9
42.1
42.6
42 3
43.4
43 4
43.2
44.1
"42.8
41.7
42.8
42 3
42.1
41.3
41.3
41.9
42.1
43.0
42.1
42.1
42 1
41.7
41 9
42.8
41.5
44.7
43.2
44 3
41 7
41.5
42.1
42 8
42 3
42 6
41 1
41 7
43.0
41 9
40 0
43 0
43 4
42.8
42 1
42.8
42.1
42.3
41 9
42.1
41 5
43.6
43.6
Ga» oil
diitillate
Per
cent
14.0
13.7
13.7
14.2
13.4
13.3
14.5
14.1
14.2
13 5
16.6
15 3
14.9
14.3
11.8
15.8
29.0
14 0
20.9
22.2
25.4
25 4
24.8
25.0
23.9
21.7
20.3
21 9
20 4
16.5
39 6
30 8
15 7
24 1
IS 3
18.5
39 4
38 6
19.5
12 6
32.7
24 0
17 7
22 1
19.9
31 1
20.9
27 5
10.6
22.4
16 3
33 1
25.3
19.3
16.8
18 8
17.7
18.9
26 6
10.8
Grav-
ity,
•API
34.2
36.2
35.6
36.4
35.8
35.8
35.4
42.3
36.6
36.8
36.0
37 0
37 4
38.4
34.6
37.2
34 8
35.8
35.2
30.8
35.6
36.2
35.0
32.8
35 4
35 8
36 2
36 4
36.8
35 4
37 4
35 4
33 6
35.6
37 6
35 2
36 8
33 6
36 6
35 4
33 8
36.4
36 8
35 8
35.8
36 2
35 8
32 1
36 4
37 2
36 0
36 2
36 8
33 8
36 2
34 8
35.2
34.8
37 4
37.0
Lubricating
distillate
Per
cent
17.8
15 9
16.3
15.7
36.7
16.3
15.9
16.7
16.5
13.7
17.8
14.9
13.7
16 3
18 5
15.2
25.9
16.2
22.1
38 8
21.5
20.4
21.7
35.1
21.7
20.2
20 5
20 2
18 5
19.4
12.9
23 7
22 3
22 6
19 0
19 5
21 3
27.7
IS 3
23 5
35 0
23 8
22 0
22 1
19.0
22 1
22 7
23 0
2 1
21 4
18 3
21 1
30 7
22 5
18.8
23 8
22 8
22 1
24.8
12 8
Gravity,
•API
30.2-2T5
33 2-25.9
32.8-24.2
33.6-25.9
32.3-24.5
32.8-21.6
33 . 2-24 . 9
33.6-24.9
32 . 8-25 . 6
33.4-25.4
32.5-24.9
33 6-26 3
33.8-26.1
33.4-28 8
31.3-23.1
33.6-26.3
31.1-28.3
34.6-28.4
31.5-24.5
25.2-16.2
31.7-25.6
33.6-27.7
30 6-23.7
26 8-17.5
30.6-22.6
32.8-25 0
33 2-25 4
33.4-26 1
34 6-28 9
32 7-24.0
34 8-30.0
31 9-26.1
37 2-34 4
30 8-23.5
35 0-27 9
32.1-25 9
35 0-27.1
29 5-24 0
35.4-29 7
34 6-27 5
28 8-22.3
32 7-24 3
36 0-28 6
33.6-27.1
32.3-25 4
31.3-24.0
32.1-25 0
23. 4-22. 8
33 8-32 5
34 4-27 5
33 4-25.9
32 7-25 6
34.2-25.7
28 2-20.2
32 3-24 0
31 9-24.7
31 9-24.3
30.4-24.5
34 8-27.7
35.6-27.0
Residuum
Per
cent
21.6
30.0
28 3
29.0
25.4
25.4
25.3
27.5
29.5
21.3
19.5
21.1
17 6
20 8
36.7
23.4
20.3
15.2
25.2
34 8
24.5
18.1
29 8
31 9
30.7
22 S
2*2 4
24 5
21.5
23 1
6.7
21 9
25 9
27 2
16 8
20 6
14 3
20.5
8 4
25 0
26 9
20 9
17.4
22 6
18 6
17 6
24 6
20 2
5.7
21 3
14.0
19 3
14.3
32 5
21.7
28.1
26 7
26 7
17.6
5.1
Grav-
ity,
•API
18.9
20.3
15.9
16.4
14.8
16.8
16.0
14.8
14 1
14.1
12.9
15.7
15.9
17.9
1.6
18 5
20 5
20.7
18.1
11.7
19.2
21.0
15.6
14.1
15.7
18.4
18 6
19.0
20.7
17 1
20.7
20.2
31 9
15 9
19 0
17 8
22.1
19 0
24.2
21.1
17 9
16 2
22.3
19.8
13 9
17.9
18.2
18 2
22 8
20 3
20.3
18 9
18.4
12.2
18 4
18 7
14.8
16.4
20.2
19.5
97
-------
Table A-2 (Continued). PROPERTIES OF UNITED STATES CRUDE OILS
Item
No.
118
110
120
121
121
123
124
125
126
127
128
129
130
131
132
133
134
135
136
137
138
139
140
141
142
143
144
145
146
147
148
149
150
151
152
153
154
155
156
157
158
159
160
161
162
163
164
165
166
167
168
169
170
171
Stall
Field (Formation. age)'
Little Lake, South (Textulari* Panamenais
1 "D" Mio.)
Main Pax (Block 69, Mio.)
Paradia (Paradie, Mio.)
Romeie Paaa (Mio.)
Ship Shoal (Block 154, Mio.)
South Pa» (Block 24, Mio.)
Timbalier Bay (Mio.)
Venice (Mio.)
Week» Island (Mio.)
West Bay (Mio.)
West Delta (Block 30, Mio.)
West Delta (Block 53, KE, U. Mio.)
West Deita (Block 83, KE, U. Mio.)
Michigan
Albion (Trenton-Black River Ord.)
J/tHt««ippt
Baxterville (L. Tuscaloosa, U. Cre.)
Bryan (Rodesaa, L. Cre.)
Heidelberg (U. Tuscaloosa, U. Cre.)
Little Creek (L. Tuscalooaa, U. Cr».)
Raleigh (Hoaston, L. Cre.)
Sooo 111,701 Baiter, Rodaaaa, L. Cre.)
Tinaley (Selma, U. Cre.)
Montana
Cabin Creek (Misaion Canyon, Mi».)
Cut Bank (Cut Bank L. Cre.)
Pine ( De v.)
Pftw Mvx\co
Bisti (Gallup, Cre.)
Caprock, East ( Wotfcamp, Perm.)
Eunice-Monument (Graylnirg, Perm.) ....
Gladiola (Wolfcamp Perm.)
Hobba (San Andrea, Perm.)
North Dakota
Beaver Lodge-Tioga (Mission-Canyon,
Ord )
Blue Butte (Madison, Miss.)
Oklahoma
Bradley (Springer, Penn. & Cunningham,
Miss.)
Cement (U. Melton, Penn.)
Cuahinft (Bartlesville Penn.)
Eola-Robberson (Oil Creek, L. Ord.)
Golden Trend
Antioch, Southwest (Gibson, Miss.) ....
Grav-
ity,
•API
34.8
30.6
36.0
31.9
37.4
29.1
32.3
34.4
37.6
33.2
32.1
27.0
32.3
35.0
41.9
17.1
35.0
37.2
23.3
38.0
45.8
41.1
30.4
33.4
39.0
33.8
39.6
29.5
37.6
43.2
46.0
28.8
42.1
37.4
36.2
36.4
28.9
39.4
38.6
41.7
35.0
39.6
42.8
46.0
41.1
41.3
35.0
39.6
33.2
42.1
39.8
38.0
37.4
42. V
Sulfur,
wt.
per cent
0.26
0.25
0.23
0.27
0.30
0.36
0.26
0.33
0.24
0.19
0.27
0.33
0.43
0.37
0.10
2.71
0.43
1.47
3.75
0.15
0.43
0.39
1.02
0.60
0.85
0.36
0.32
0.65
0.18
0 17
0.17
0.97
0.10
1.41
1.22
0.12
1.65
0.36
0.70
0.11
0 95
0.12
<0.10
0.23
0.52
0.31
0.22
0.24
0.47
0 22
0.35
0 27
0.31
0 11
Vi*co«-
ity,
BUS at
100'F
49
61
41
52
44
78
51
43
41
51
54
92
66
48
44
1,480
50
47
370
43
58
41
79
47
38
55
38
72
40
35
35
54
35
41
47
35
64
36
37
34
42
39
32
34
34
35
56
43
56
38
41
42
'42
39
Carbon
residue
of
reaiduum,
wt.
percent
9.9
6.2
4.4
- 6.1
7.1
3.5
5.2
7.7
6.0
4.8
6.8
5.7
6.7
6.7
3.5
16.6
8.5
6.3
10.0
5.4
5.7
9.9
8.5
15.7
9.9
18.9
4.4
11 2
5.6
3.3
4.0
10,9
4.6
9.6
6.0
S.S
9.2
4.6
8.8
4.0
9.2
3.4
2.7
2.7
2.6
2.8
8.7
4.4
5.3
5.6
3.9
3.5
6.5
2.7
Gaaoline and
naphtha
Per
cent
23.6
16.0
29.4
19.6
26.4
8.7
18.7
31.6
30.4
20.1
17.3
9.5
17.6
'22.1
28.9
5.2
25.7
32 3
19.2
33.4
40.9
36.5
20.9
25.1
34.2
24.7
33.8
18.2
31 4
46.0
44.3
27.9
48.6
35.5
32.8
44.8
20.4
41.0
37.5
46.9
33.5
31.6
41.9
46.6
41.0
40.7
24.3
30.2
28.9
41.2
33.1
32.6
32.3
34.6
Grav-
ity,
•API
58.2
53.2
53.0
54.0
60.0
51.1
54.9
57.4
55.8
54.9
53.7
50.9
56.7
58.7
63.1
55.4
60.0
67.0
64.5
58.9
64.2
63.7
63.1
61.5
60.5
64 2
60.2
53.5
57.9
58.7
61.0
56.2
57.7
60.8
58.2
49.9
50.9
55.7
57.7
56 4
54.0
59.2
60.0
60.8
57.4
59.5
57.4
60 0
53 2
61.3
60.8
58.4
56.9
62.9
Keroeine
dimlillate
Per
cent
13.0
4.6
7.2
5.6
11.0
5.5
5.1
5.5
13.3
4.7
6.3
4.7
11.4
12.6
17.3
2.1
10.8
15.3
6.3
10.9
18.1
18.1
11.1
18.1
10.6
19.8
12.3
10 9
4.0
12.2
11 3
5.0
5.7
4 5
10.5
4.9
6.2
5.0
4.7
5.2
4.7
10.7
10.8
9 8
10.0
11.3
15.6
10. 1
9.7
11.8
10. 1
10.4
12.0
17 1
Grav-
ity,
•API
44.1
41.1
43.6
41.5
43.8
41.9
40.8
42.6
42.6
42.8
42.6
40.0
42.8
43.4
45.8
40.4
41.9
47.2
43.2
42.8
45.2
45.2
44.7
43 6
42.3
46.0
43.8
41.9
41.7
42.3
42 8
40.2
41.1
41.3
42.8
41.1
41.3
41.5
42.8
41.9
42 8
42.6
42.3
42.1
42.8
43.0
43.0
42.8
42.1
42.8
42.3
42.8
42.3
42 3
Ga« oil
cUatillhte
Per
cent
19.0
25.4
26.1
26.0
19.3
26.6
25.4
19.9
20.2
28.6
27.5
24.4
18.6
18.0
9.4
14.4
16.7
10.0
11.1
16.3
10.6
10.0
11.4
12.9
15.8
11.9
17.5
18.8
19.4
17.3
16.3
18,3
21.3
17.0
13.4
19.9
22.6
19.0
19.7
19 8
21.3
16.0
15.8
13.1
17.0
15.3
9.6
14 8
13 0
14.5
14.0
15.7
16.4
8.1
Grav-
ity.
"API
36.8
35.2
36.0
35.6
37.2
34.8
34.6
34.2
36.2
35.4
36.4
33.8
35 8
36.6
36.6
33.2
.32.7
36.4
.35.0
.36.4
57.0
36.8
35.0
34.6
34.6
36.2
36.0
35.2
36.4
35.8
36.0
32.7
34 6
34 0
36.0
32.3
35.0
34 0
35.6
34.6
35 0
37.4
35.2
35 0
34.6
35.0
36.6
36 4
36.0
36 6
35.8
36.0
36.0
.36 0
Lubricating
distillate
Per
cent
23.9
23.6
18.2
21.4
19.4
30.1
23.2
19.6
16.7
24.1
21.9
28.5
22.7
18.9
13.3
24.3
17.8
13.7
16.1
17.1
13.9
15.4
18.6
12.3
19.3
10.6
17.5
22.5
16.5
12,4
13 3
17.9
12.8
19.6
19 0
16 3
20 4
13.6
17.3
12.8
17.1
19.1
17.0
13.9
14.0
15.9
19.5
15.8
18.3
14.4
15.3
14.7
15.7
15.3
Gravity,
•API
32.5-23.5
31 7-24.7
31.7-24.5
31 3-23.3
34.0-27.5
30.6-23.0
31.0-23.5
30 2-21.1
33.0-28.6
31.5-24.7
32.7-24.7
29.1-22.1
32.8-23.7
32.7-26.3
35.0-28.9
29,3-19.7
32.8-26.3
34.0-27.1
30 6-20.2
33.4-27.9
34.4-28.9
34.0-26.6
31.7-22.0
31.7-23.8
30.8-24.2
31.5-23.5
31.9-28.3
32.5-24.7
32 5-24.9
32.7-27.3
33.0-28.2
27.7-21.5
31.0-25.7
28.6-20.7
31.5-23.8
27.0-21.1
28 8-20.8
29.3-24 0
30.8-24 2
30 6-25 4
30.0-22.5
34.2-25.9
32.7-23.5
31 0-26 3
31.1-26.4
31.1-25.9
34.8-27.1
33.2-27.5
33.0-26.3
33 4-27.0
32.7-25.6
32.7-27 3
32.5-26 1
34 . 4-27 . 5
Residuum
P«r
cent
20 1
29 6
18.9
26.8
22.9
27.7
26.3
21.8
19.2
22.4
27.3
32.7
28.2
26 8
25.7
52.8
28.0
27.5
45.4
21.6
14.7
19.4
37.8
31.0
17.0
31.2
18.7
32.5
24 2
11.7
11.5
27.6
12.4
17.9
21.6
13.1
29.5
18.0
19 0
13.6
22.2
20.7
12.8
12.2
16.8
15.2
30.4
26.0
29.8
17.0
22.7
24.6
23.0
22 3
Grav-
ity.
•API
16 7
17.0
19.0
17.1
17.9
17.8
17.3
14.5
18.1
18.7
17.9
16.2
16.4
17.3
20.8
7.0
15.1
10.7
5.0
17.6
19.8
15.3
13.8
12.0
14.8
9.7
19.2
14.4
17.3
21.3
21.6
13.3
18.1
U.I
12.6
16.0
13.6
17.9
15.7
18.6
14.4
20.3
20.0
20.3
19.4
20.0
18.6
21.5
15.9
18.6
18.9
19.4
18.1
23.3
98
-------
Table A-2 (Continued). PROPERTIES OF UNITED STATES CRUDE OILS
Item
No.
172
173
174
175
176
177
178
179
180
181
182
183
184
185
188
187
188
189
190
181
192
193
194
195
196
197
198
199
200
201
202
203
204
205
206
207
208
209
210
211
212
213
214
215
216
217
218
219
220
221
222
223
224
225
226
227
228
229
230
231
232
Stalt
Field (Formation, age)1
Elmore, Northeast (Gibson, Miss.). .
New Hope, Southeaat (Gibson, Miw.) . . .
Panther Creek (Penn )
Healdton (IleaMton Penn.)
Hewitt (Lone Grove, Pre-Cara.)
Joiner City (Bois D'Arc Sil.-Dev.)
Oklahoma City (Wilcox, Ord.)
Sho-Vel-Tum District
Sholem Alechem (Springer, Penn.)
Tatums (Deese, Penn.)
Velma (L. Dornick Hills, Springer, Penn.)
Prnniyhama
Bradford (U. Dev.)
TYrot
Anahuac (Marg. No. 1, Olig.)
Andector (Ellen Cam.-Ord.)
Andrews, North (Dev.)
Andrews, North (Ellen, Cam.-Ord.),.
Andrew*, South (Dev.)
Bakke (Dev.)
Bakke (Ellen Cam -Ord )
Bakke (Penn )
Bakke (Wolfcamp Perm.)
Bethany (4300' Glen Rose, L. Cre.)
Block 31 (Dev )
Borregos (F-5 Fno Olig.)
Borregos (L-5 Fno, Otig.)
Borregos (N-21 Fno, Olig.)
Borregos (R-13. Vicksburg, Olis.)
CoKdell area (Canyon Reel, Penn.)
Conroe (Cockfield Eoc )
Cow den, North (Grayburg, Perm.)
Cowden, South (Grayburg, Perm.)
Darst Creek (Buda L Cre )
Darst Creek (Edwards L. Cre.)
Diamond "M" (Canyon Reef, Perm.)....
Dollarlude (Clear Fork Perm.)
Dollarhide (Dev )
Dollarhide (Ellen.. Cam.-Ord.)
Dollarhide (Sil.) ...
Dollarhide, East (Ellen., Cambro-Ord.) . .
East Tevas (Woodbine U. Cre.)
Emma (Ellen., Cam.-Ord.)
Emma (Grayburg-San Andres, Perm.). . . .
Emperor, Deep (Seven Rivers, Queen,
Perm.)
Fairway (James, L. Cre.)
Fort Cliadbourne (Odem, Penn.)
Fuhrman-Mascho (Grayburg, Perm.)
Fullerton (Clear Fork Perm.)
Fullerton (Dev )
Fullerton, South (Wolfcamp, Perm.).. .
Grav-
ity,
•API
42.1
41.1
46.5
28 9
37.0
40 4
43 0
39 8
37 6
28 0
36.0
30 0
26 8
21.0
29.1
41.1
33 2
43.2
39.0
36.8
44 3
45.2
44 7
36 8
44.7
45.6
39.4
37.4
41 5
44.5
42.1
40 6
42 3
38.2
39 0
41 7
37.0
30 4
36 6
34 8
36 6
36 8
45 4
37.4
38.2
41 5
41 3
42 3
29.7
37.4
45 6
49 2
49 0
35.6
45.6
44 1
34.2
31 3
39.6
41.5
43 4
Sulfur,
wt.
per cent
0 14
0.19
0.14
0 92
0.65
0.47
<0 10
0.25
0.16
1.41
0.57
1.73
1.44
1.68
1.36
0.11
0 23
0.22
0.11
0.78
0.30
0.11
<0.10
0.10
0.16
0.21
<0.10
0 41
0 23
0 18
<0.10
<0 10
<0 10
<0 10
<0 10
0 38
<0 10
1 89
0 96
1 77
0 76
0.78
0.20
0 42
0.57
0 23
0 36
0.10
3 11
0.25
<0.10
<0 10
<0.10
1.11
0.24
0.24
1 53
2 06
0 47
0 32
0 17
Viacos-
i'y.
SUS at
100°F
38
41
37
110
49
40
37
42
45
115
49
100
150
550
87
44
48
38
41
40
37
37
36
49
37
<32
40
40
41
35
35
36
35
37
35
37
36
51
42
44
49
46
35
43
41
40
39
40
57
42
36
35
35
45
33
37
44
47
40
38
36
Carbon
residue
of
residuum,
wt.
per cent
3.0
4.3
3.8
10.7
8.3
4 0
3.6
4.0
4.2
11.4
6.6
11.8
7.9
8.2
10.1
1.6
4.0
4.9
5.6
7.6
3 7
7.8
9.1
5 6
1.1
6.3
2.2
4.7
6.8
3 9
3.3
3 9
4 0
3.5
3.9
7 6
4 9
10 9
6.7
3.5
7 8
6.8
4 9
5 8
6.4
6.0
8.3
4 3
7 4
6.1
2.9
5 6
3.4
7.1
2.0
3 4
7 4
8.4
5 8
4 4
3.0
Gasoline and
naphtha
Per
cent
37.0
32.7
51.5
17.2
28.6
34.9
37.3
31.2
27 5
22.2
27.0
22 6
21 5
14 5
21.2
30.7
17 7
34 9
33 8
37 0
39.3
37.0
42.2
32.0
42 4
36 7
33.9
35.8
30 9
43 3
42.3
38.2
31.6
23.3
29 9
38 2
32 8
27 7
35.0
32 6
23 5
25 7
43 0
33 4
35.8
31.6
32 4
35 7
24 4
33 9
39 9
42 0
39 6
34.0
36.1
39 9
31.6
33 1
35.1
37 4
39 5
Grav-
ity,
'API
62.1
62.1
61.5
54.2
61.0
63.7
60 0
60.5
58.2
58 2
57 4
59.7
58.7
55.9
59.5
56.2
51 8
64.2
59.2
56.4
62 9
68.1
60.8
55.9
61 3
65.7
58 9
55.2
61 5
61 8
55.9
53 5
54 0
54 4
52 7
62 6
48 8
54 4
58 7
57 9
58 9
57 9
61 5
60 5
61 3
65 0
65 9
62 9
55 9
58 2
62 9
65 6
67-5
57.7
62 7
61 0
57.4
55.2
58.7
61 3
61 3
Kerosine
distillate
Per
cent
17 4
11 1
11.6
3 9
9.7
9.9
11.9
10 3
10.6
4.1
11.5
8 8
3 3
3.1
4 3
18.1
7.0
18 7
10.1
4 5
10.7
19.6
17.1
10.5
10.7
19.5
10.7
4 3
21 6
10.4
8 8
17 3
25.6
5 5
17.8
9 9
5 0
10 4
3 6
22.5
19 4
5.0
11.1
9 8
20 9
20 0
17 2
4 8
5.0
11 9
20 8
21.3
10 8
18 8
11.2
4.7
5 5
10 9
11 4
10 6
Grav-
ity.
"API
43.0
43 8
43 8
42. S
43 6
43 6
43 4
42 8
42.8
42.3
43.6
42 3
42.6
41 7
42.8
44.1
42 1
44 9
42.3
41.9
44.3
47.6
43.0
42.3
43 8
45 8
43 4
43 0
47 4
43 0
42 6
42 3
42 1
43.6
42 3
42.1
-13 0
41 7
42.1
44.1
43 4
42 3
42.6
11 9
46.7
45 6
44 5
42 1
42 8
44 5
46 0
47 4
42 3
45 4
43 6
42 1
41 7
43 2
43.6
43 8
Gas oil
distillate
Per
cent
8.8
15.1
12 1
20.8
13 5
12.2
14 0
14.8
15 3
16.0
15 5
13.0
14 8
13.6
15.9
8.7
32.4
9.8
14 1
19.3
14.1
13 0
8.7
15.9
15.0
13 1
14 2
20 3
10 0
13.1
32 6
21.4
32 2
48 6
30 3
14 4
43.4
19 5
15 0
18 5
12.2
13 1
17.5
13 8
13 2
14.5
13 1
9.8
20 7
17 7
14 8
12 6
13 4
14.0
10 4
15 3
19 9
17.7
14 2
15 6
13 7
Grav-
ity,
"API
36.4
37 3
37 2
37 0
37.0
37 0
37 6
36 8
36 8
36.2
37.2
35 4
35.4
34.2
34.8
38 4
35 2
38 6
36 2
34.6
37 8
37.0
37 2
37 2
38.0
38 0
37 6
38 0
37 3
37 2
35.6
34 2
36 0
33 6
35 6
35 8
34 4
35 0
34 8
35 0
36 0
38 4
36 6
35.8
34 8
37 8
37 2
36 4
35 2
37 2
38 2
39 4
38 6
34 6
36 3
37 8
35 2
33 4
38 0
37 4
37 2
Lubricating
distillate
Per
cent
15.9
20 0
11 3
21 3
16.4
15.7
18 8
16.4
18.8
15 8
15 8
14.8
15 5
10 1
16 6
15.9
21 1
15.1
16 4
14.1
15.1
12.8
16.1
16 3
15.0
11.1
17.7
15 0
18 5
15 5
12.3
13 0
7 5
17 1
15 9
14 4
15 9
18 1
15 0
15 5
18.8
17 9
13 5
17 5
15 0
11 5
12 0
13 6
14 6
20 3
13 5
13 4
9 3
16 1
16 4
15.1
16 8
15.8
16.3
15 8
14.8
Gravity,
•API
34.4-28 4
34.0-28 8
34.0-27.7
32.5-25.2
33 2-24.9
33 4-25 2
35,4-28 4
33.6-28 0
34.4-27 5
34.2-26 8
34,0-28 3
31 7-23 8
30 4-21.8
29,3-22 5
30.0-22 8
36 8-31 . 1
31 9-25.9
36 6-28 0
34.6-26 8
30.2-24 0
34 4-27.7
34 4-26.4
36.0-29.1
34 6-28.0
35.4-29.9
35 0-27,7
35 2-28.8
32.1-28.3
36 2-29.1
34 4-27 1
31 7-22 0
31 5-19 0
33 2-23.0
32 8-23 3
32 5-23 1
32 7-28 8
31 3-26 3
30 4-22 5
31 7-24 7
30 2-2.1 0
34 6-28 0
34.6-28 6
32 8-27 7
32 7-24 9
31 3-25 9
34 8-27 7
34 4-26 1
34 6-27 3
30 4-24 3
34 2-25 9
35 2-28 4
36 4-27 5
35.8-31 5
30 0-23 5
35 2-28 1
35 2-29.3
30.6-24.3
28.6-20.8
33 0-26 4
34 6-28.8
33 6-27 9
Residuum
Per
cent
20.2
19 0
13.3
36.7
29 0
24.3
16 3
25 6
26.0
40 9
29 0
39 8
43.2
55.9
40.4
25.0
21.8
20 0
24.2
23 6
17.6
1S.O
14.8
25.0
15 0
18.2
22.7
22 4
19 4
15.2
4 3
5 7
2 0
5 0
5 I
19 9
7 2
29 7
24 8
28 3
22 5
23 2
16.1
24 0
24 7
21 4
22 2
20 9
35 0
22 2
18.7
8 8
13 2
24.4
13.4
16.7
26.5
27 7
21 0
19 6
18 3
Grav-
ity.
•API
22.8
21 1
20 8
15.0
16 8
18 9
22 8
22.3
21.0
12 9
17.9
13 2
10.8
8.3
13.9
25.7
19 4
20 7
19.8
16.0
22.1
18.6
24.3
19.5
24.3
25.7
21.8
18.2
19.0
21 6
12.5
11.3
13.2
13.6
13 6
17 5
17 5
12 3
17 1
13 5
17 5
17 S
20.2
17 9
17 3
19.7
17.8
21 0
13 2
16 4
23 3
21 8
23 8
15.7
24 0
23.0
15 3
10 0
19 4
22 0
22 1
99
-------
Table A-2 (Continued). PROPERTIES OF UNITED STATES CRUDE OILS
Item
No.
233
234
235
239
237
238
239
240
241
242
243
244
245
246
247
248
249
250
251
252
253
254
255
256
257
258
259
260
261
282
263
264
265
266
267
268
269
270
271
272
273
274
275
276
277
278
279
280
2St
282
283
284
285
286
287
288
289
290
291
292
293
294
295
296
297
298
Stall
Field (Formation, age)1
Gillock (Hudgings Frio Olig.) ....
Gillock. South (Frio, Olig.)
Goldsmith (5600-, U. Clear Fork, Perm.)..
Goldsmith (Clear Fork-Tubb Perm.) . .
Goldsmith (Dev.)
Goldsmith, East (Holt, Perm.)
Goldsmith, North (Kllen. Cam.-Ord.)
Goldsmith, West (U. Clear Fork, Perm.) . .
Goldsmith West (Ellen Cam -Ord.)
Goldsmith, West (San Andres, Perm.). . . .
Goose Creek (Fno Olig )
Hastings, Fast (Frio, Olig.)
Hastings, West (Frio, Olig.)
Hawkins (Eagle Ford, U. Cre.)
Ileadlee (Dev.)
Headlee (Kllen., Cam.-Ord.)
High Island (Mio )
Hull (Caprock, Mio.)
Jo- Mill (Spraberry, Perm.)
Jordan (San Andres, Perm.)
K«lly-Snydftr (Canyon Rw! Penn.)
Kelaey (Fno, Olig.)
Kefoey South (IS- A Frio Olig )
Kermit (Yates and Seven Rivera, Perm.).-
Kermit South (Dev.)
Keystone-Ellenburger (Ellen., Cam.-Ord.) .
Lake Pasture (FT-569, Frio-Sinton, OHg.).
Liberty South (FY, Olig.)
Magutex (Ellen Cam -Ord )
Midland Farms (Ellen Cam.-0rd.)
Midland Farms, North (Grayburg. Perm.).
Midland Farms, Northeast (Ellen., Cam.-
Ord.)
Pegasus (Ellen Cam -Ord )
Penwell (Ellen Cam -Ord ) . ...
Penwell (San Andres Perm.)
Plymouth (6100' Frio, Otic-)
Grav-
ity,
"API
45 2
38.0
38.0
38 0
40.9
38.4
36.4
37 0
37.4
42.6
37.4
34.4
35.0
31.5
31 0
30.2
26 8
47.4
51.1
27.3
30 6
31 1
40.9
44.3
37.4
43.1
33.2
39.8
40.6
43.4
41.9
36.6
32 3
34.2
32.7
42 1
37.8
35.4
40 0
37.2
23.7
31,1
36.4
28 6
40.2
46.9
31.5
30.0
35 6
43.0
50.6
31.7
39.6
30.0
49.2
36.8
25 4
40.4
53.0
45 4
35 6
41.7
33.2
37.2
42.3
40.6
SuUur,
wt.
per cent
<0 10
0.11
0.52
0.57
0.16
1.16
0.15
0 58
0.53
0.32
0 96
1 38
0.13
0.15
0 15
0 17
2 19
<0.10
<0.10
0.26
1.18
0.35
<0 10
<0.1Q
0.11
0.28
1.48
0.21
0.13
<0.10
0.19
0 94
0.79
0.95
0.69
0.13
0.63
0.49
0 31
0.13
0 20
2.12
0 14
0 86
0.30
0.12
2.37
2.40
1 11
0.10
<0.10
2.04
0.13
2.37
<0 10
0.14
0 21
0.55
<0.10
<0.10
0.17
0.24
1.69
0.12
0 12
0.13
Viscos-
ity,
SUSat
100«F
34
38
46
44
40
40
59
44
44
39
43
43
42
48
55
58
135
37
35
79
61
41
34
36
43
38
46
37
35
34
39
42
81
48
68
40
43
51
39
35
60
48
40
90
38
39
53
54
48
35
34
46
40
53
38
43
71
47
33
36
48
40
45
39
.34
37
Carbon
residue
of
residuum.
wt.
per cent
3.5
6.0
5.7
5 1
5.2
6.7
4 8
5.6
5.2
3.7
6.1
9.1
4 3
4.7
4.3
5.8
6.0
0.4
1.5
6.2
7.6
3.7
1.6
1.3
3.7
5.2
9.4
4.8
8.9
2.9
2.3
7 2
4.8
5.7
5.2
2 3
5.1
5.2
6.3
4.7
5.3
8 6
2 5
6.6
4 3
4.0
10.5
8.5
11.8
3.0
2.2
11.3
3.1
6 9
3.0
4.6
4.0
5 6
1.6
1.3
8.5
8 2
8.3
5.6
6.1
5,4
Gasoline and
naphtha
Per
cent
38 2
28' 3
30.4
30.2
35.4
35.4
29 5
29.6
31.7
33 1
31 9
33.2
22.1
20.1
15 8
18.4
20.7
45.7
43.0
10.1
21.8
33.4
36 3
41.7
32.6
34.5
29.7
42.2
38 5
45.3
30.0
34.8
17 0
26.1
18 6
30 0
31 7
21.9
36 9
32.0
2.8
31 0
30 6
12 7
38 5
38 4
24.7
29.7
31 3
45 2
42 g
29.5
38.6
28.3
41.3
24.8
3.6
31.1
46.3
42 9
31.9
32.3
31.0
40 0
44.2
47.0
Grav-
ity.
•API
60.2
56.9
58.7
58.9
SI. 8
58.7
54 9
58.9
60.2
64.5
60 0
56 7
54 2
52.0
49.2
50.6
63 1
62 1
67.0
47.2
53.2
51.8
56.9
60.0
57.7
65.3
55.9
57.4
57 4
55.4
61.8
59.5
58.7
54 2
57 7
62.9
57 7
57 4
579
52.5
43.2
54.2
53 7
51 6
58 4
65 3
57 4
56 7
59 7
58.4
66.1
57 9
56 9
57.4
64.8
54.7
44.3
61 5
67 5
61 0
59.2
65 9
55,9
53.7
57.4
56 9
Kerosiue
distillate
Per
cent
16 5
7.3
10.7
11.7
10.5
4 5
5.3
10.4
10.2
18.7
9.8
11.0
6.1
7 3
17 6
22.3
13 5
18.0
4 5
19.9
5.1
4.9
6.3
18.8
19.2
5.0
8 6
12 6
8.2
20.1
11 8
19.5
11.4
9 0
4.2
5 6
4 8
11 Q
22.1
4.4
4.3
10.2
5.3
22 5
4.7
10.3
40
23 5
13.8
8.7
21 2
9.8
9.4
19.5
4 9
6 7
8 0
7 6
Grav-
ity,
"API
43.2
43.0
43 8
43 8
43.4
42 8
42.8
43.8
43 4
45 6
42 6
41 7
42 6
44.5
43 3
48 5
43.0
42.6
41.7
54.7
43.0
41.9
43.6
42.6
44.9
41.9
43.8
42 1
43 0
45.4
43.6
43.4
42 1
42 1
42.3
42 6
41.3
42.3
47.2
41 9
42 3
43.2
42.1
48.3
42 1
41 3
42.3
47 8
41.7
43 6
48.5 •
43 2
41 9
45 8
43.0
40 2
44 3
42.1
Ga* oil
distillate
Per
cent
21 6
32 8
15.0
15.5
13.2
18 1
19 7
15 6
14.6
13.2
15 8
16.2
32 6
36 9
35.6
35.6
12 7
9 8
14 7
33 6
24.5
29.5
15.0
8.6
17 6
14.3
20 1
19.2
33.4
19.8
13.1
18.5
13.1
16 7
15 6
15.0
17 1
12 8
15.7
37.6
50 3
17 8
26 8
24.4
15.6
13 4
20.2
IS 6
12.6
17 5
14.0
19.2
13 5
17.7
14 4
23.0
43 9
13 6
12.9
12 7
12.4
12 7
19.8
21 5
30.8
26.3
Grav-
ity,
"API
;i7.o
36.2
36.6
:I6.8
36 4
35 8
'.16 8
36 2
36.4
38.4
35 o
31.3
35.0
33 4
34.0
33.6
IS5.4
37 6
•10.2
32.1
35.0
29 3
38.6
•,)6.6
35.8
'AS 0
36.0
35 8
35.4
34 8
37.2
35 0
36 8
35 4
36 4
37 8
36 8
36 2
35.4
34.2
3,0 0
34 0
3,4 6
34 8
38.6
394
35.0
33 6
S5.6
38 4
39 6
34 0
35 6
33 6
39 8
35 0
30 0
3'8 4
40.9
36 4
36.4
38 0
35.6
33 0
34.6
32.8
Lubricating
distillate
Per
cent
14.2
19.1
16.7
16.3
16.0
15 6
17.9
17 8
16.1
12.6
15.3
14.1
21 3
22.7
23.1
23.0
15.4
13 2
8 8
30.1
19.5
19.1
17.1
14.3
15.2
10.4
18 6
14.9
14.1
5.5
16.8
17 5
22.9
16 9
22 6
14 4
15.4
17 3
15 5
15.1
34 3
17.1
19 9
22 7
15.8
13.5
19 5
15.6
15 1
14.6
9.6
16.6
15 5
16.2
11 6
18.2
27.5
16.1
8 4
13 8
16.3
12.1
16.4
17.5
10.9
12.1
Gravity,
"API
34 6-26.1
32 8-27.1
33 4-23.5
34.6-26.3
33 6-27 3
31.0-20 8
33 0-26.8
33.0-25 0
32 8-25 9
35.4-27.7
31 3-25 2
30 0-25.0
30 6-25.0
29.5-21.6
29.3-23 5
28 6-22 6
30.6-22 0
37.0-31 0
38.0-32.8
28.0-20 5
31.5-25.4
22.1-16.8
34.4-29 9
35.4-30 0
31.9-27.5
35.4-29-1
30 4-23.5
32.1-29 3
32.1-17.6
31 . 3-22 . 8
35.2-29 9
29.9-23.1
32 7-28 8
32.1-25.9
33 2-29.8
35.6-29 1
33.2-29 6
34 0-27 3
32 7-25 7
28 9-17 5
25.0-13.9
28 9-21.8
31.1-25.2
30.8-23 7
34 0-28.0
37 0-28 4
29.7-22 8
28 0-21.5
31 9-25.4
32 3-26 8
37 0-32.7
28 6-22 1
33.2-27.3
28.2-21 1
37.8-30.2
32 8-26 3
26.3-20 8
36 0-31.1
38 0-33.4
33 2-27 5
32 3-24.7
35 0-27.0
30 6-22.3
29 9-20 5
28.2-15.1
27.0-14 8
Residuum
Per
cent
6 6
12.2
24.1
24 6
21.9
21.7
256
24 7
26 4
21 0
25.4
24 8
17.7
20.3
23.0
22 4
43 1.
12 2
9 3
21 0
33.3
17.5
17.1
15.6
27 8
20.0
26 4
18 4
6 8
9.0
20.3
22 8
37.5
26 7
34 5
19.1
23 3
28.5
18.7
5 4
12.1
28 3
16 5
35.4
18 9
13.1
29.6
30 9
28.5
13.4
9 4
28 8
22.1
31 7
8.7
19 6
24.7
27.2
8 3
17 1
23 4
22 0
27.7
14.3
5.0
6.0
Grav-
ity.
•API
19 8
17.9
18.2
19.4
19.7
15.3
19 2
17 5
IS 2
21.3
16.8
13.6
19.7
18.2
18 7
17.0
9.3
25.4
26.3
15.7
17.3
16 5
23.7
25 0
19.8
20.8
14 5
19. S
9.9
\6.7
24.3
16.2
19.7
17.6
20.3
22 8
18 4
19 5
18.2
11.0
9.9
10 4
19.8
17.9
20.8
23.0
13.3
9 9
13.9
21.5
27.1
11.6
21.3
10.1
23.5
19.5
17.3
20 0
27 9
23.5
16.5
17.8
15 1
17 5
9.2
8.9
TOO
-------
Table A-2 (Continued). PROPERTIES OF UNITED STATES CRUDE OILS
Item
No.
299
300
301
302
303
304
305
308
307
303
309
310
311
312
313
314
315
316
317
318
319
320
321
322
323
324
325
328
327
328
329
330
331
332
333
334
33*
338
337
338
339
340
341
342
343
344
345
348
347
348
349
350
3M
352
3.13
354
355
356
357
358
359
300
361
362
363
364
State
Field (Formation, age)'
Plymouth (Gret* Frio Olig )
Portilla (7100', Frio Olig.)
Portilla (7300', Frio, Olig.)
PortiHa (7400' Frio Olig.) . ...
Portilla (8100', Frio Olig.)
Prentice (6700', Clear Fork Perm.)
Quitman (Eagle Ford XT. Cre.)
Quitraan (Sub-Clarkiville, U. Cre.)
Quitman (Trinity L. Cre.)
Robertson (San Angelo-Clear Fork, Perm.)
Robertson. North (7100', Clear Fork,
Russell (6100' Glorieta, Perm.)
Ryasell (7000' Clear Fork Perm.) ...
Russell, North (Dev.)
Salt Creek (Canyon Penn.)
Sand Hills (Ellea Cam -Ord )
Sand Hills (Me Knight, San Andrei, Perm.)
Sand Hills (Tubb Perm.)
Seeligson (Zone 14-B, Frio, Olig.)
Seeligson (Zone 19-B, Frio, Olig.)
Seeligson (Zone 19-C, Frio, Olig.)
Seeligaon (Zone 20 Frio OUg.)
Seeligaon (Zone 21-D, Frio, Olig.)
Shatter Lake (Dev )
Sharon Ridge (1700' San Andres, Perm.). .
Sharon Ridge (2400' San Angelo, Perm.) . .
Sharon Ridge (Clear Fork, Perm.)
Slaughter (San Andres. Perm.)
Sproberry Trend area (Spraberry, Perm.) . .
Ta(t (Frio Olig.)
Talco (Trinity L, Cre )
Thompson (36OO-, Mio.)
Thompson, North (Vicksburg. Olig.)
Ttjerina-Canaies-Blueher (Frio, Olig.)
Tom O'Connor (Frio, Olig.)
TXL (Dev.)
TXL (Ellen Cam -Ord )
TXL (San \ndres Perm.)
TXL (Tufab Perm.)
University-Block 9 (Woifcamp, Perm.)
Van (Woodbine-Defter U. Cre.)
Waddcll (Grayburg Perm.)
Walnut Bend (Hudspeth, Strawn, Peon.)..
Walnut Bend (U. Strawn, Penn.l
Walnut Bend (Winger. L. Strawn. Penn.) . .
War'l-Estes North (Yates, Perm.)
Ward, South, (Yates, Perm.)
Wasson 66 (Clear Fork Pefm.)
Wasson 72 (Clear Fork Perm.)
Webster (Marginuhna, Frio, Olig.)
Welch (San Andres Perm.)
West Columbia ("Z " Frio. Olig.)
West Columbia New (Frio, Olig.)
West Ranch (41-A Frio, Olig.)
Grav-
ity,
'API
23.5
28.8
40.4
39 8
39 8
39.0
25.9
28.6
26.3
16.2
43. 8
34 0
29.9
34 8
32.7
34.8
40.2
36.8
37 0
31 7
36.8
34.0
41 5
41.3
41.9
40.2
41. 5
33.8
31.7
38.6
37.4
27.1
28 2
29 1
38.0
31 1
35.0
21.6
20 5
23 8
36 4
25 7
40.5
34 8
38.6
42 3
30 8
38.4
44 7
36 4
37.0
35 4
33 6
46 0
44 1
31.0
34.0
35 8
32.8
31 9
33 2
29.3
32 3
28 0
28. 8
31.5
Sulfur,
wt.
p«r cent
0.19
0.15
<0.10
<0.10
0.14
0.12
2.60
2 68
2.06
3.64
0 92
1.31
1.95
0.79
1.20
1.23
0:31
0.63
0.73
3.33
0 92
1.00
<0.10
<0.10
<0.10
<0.10
0.12
1.88
2.27
0.77
0.25
2.04
1.71
1.67
1.34
2.04
0.18
0.21
3.00
0 25
0.11
0 20
<0 10
0 17
0.50
0 21
1 93
0.54
<0 10
0.12
0.57
0 82
1 69
0 23
0 17
0.86
1 17
1.12
1 76
1 40
1 01
0 21
2.14
0.23
0 19
0 17
Visco*-
ity,
SUS at
100"F
55
44
34
38
35
35
54
47
145
3,700
39
44
49
44
40
39
37
41
45
45
42
47
34
35
34
34
38
43
45
40
46
58
49
49
41
48
43
85
520
140
46
64
35
39
41
39
49
47
36
45
39
51
46
38
33
77
45
42
43
44
42
64
45
65
63
41
Carbon
reaidu*
of
residuum,
wt.
per cent
4.7
5.8
4.3
4 3
4.6
4.8
9.4
5.8
5.8
12.0
8.5
9 2
8.1
8 4
11.7
10 8
7.8
10.3
5.4
9.9
7.6
8.2
3.9
6.9
4.4
3.4
4.4
9.7
12 2
7 6
8.0
6.8
13 4
13.5
8.9
12 1
7.1
3.9
17 6
4.2
3.3
4.4
7.7
4.4
6.0
3 9
9 8
5.2
2.7
5.3
8 2
8.3
9 8
3 3
3.5
8.3
7 7
8.0
5.2
13.6
11 9
4.6
11.7
4.2
6 2
3.5
Gasoline and
naphtha
Per
cent
6.1
19 8
39.6
38.6
37. S
30.5
29.4
31.9
15.4
8.6
43.8
32.4
29.1
31.5
35.7
38.2
35.9
33.4
27.7
34.3
33.6
30.2
40.2
39.0
38.8
40.2
28.8
32.7
32.9
33.7
28.5
26 9
23.3
29.1
34 7
31.1
31.3
10 7
23.4
7 2
37.7
30 6
32 8
33 7
28 9
30.3
39 1
29 5
33 4
26.5
30 9
38 3
37 5
24 5
31 6
33.8
33.3
33 9
35.9
14 5
31.7
13 7
14 1
25 7
Grav-
ity,
"API
54.7
51.1
55.9
55.2
54.9
53.7
52.3
54.2
59.7
58.9
66.4
56 7
53.7
56.2
53.7
55.4
61.3
59.5
60 2
57.2
59.5
57.2
54.7
54.4
55.2
53.2
56.2
57.7
55.9
61.0
58.2
54 7
51 1
55 4
59 5
56.4
55.9
58 9
54 7
45.2
54.9
5.5 2
59.7
64.5
52.0
59.2
62 3
56 7
56 4
64 8
58 4
64 5
64 2
59 2
59.7
58 2
57 2
54 9
54.4
49 7
56.2
51.3
50 1
51 1
Kerosioe
distillate
Per
cent
9.1
7.4
7.1
7.9
4.7
4.5
7.4
2 2
16.9
4.7
4.0
10.3
5.1
4.6
10.3
10.5
19.2
4 4
10 6
6.0
8.0
18.8
9.6
8.9
21.0
5.0
5.0
4.5
20.5
4.3
4.2
4 4
9.7
4 4
4.5
7.0
13.2
17.5
9.7
19.7
5.0
9 8
17.1
11 0
5.2
15.1
4 7
16 5
16.5
8 7
5 4
5.3
4 5
4.6
4.9
4.9
5.3
5.7
Grav-
ity,
•API
43.2
41.7
42.3
42 8
41.1
41.1
42.3
42.8
44.1
42.1
41.7
41.9
41.9
41.5
42.1
41.7
43.4
42.1
43.4
42.6
42.1
41.5
44.3
43.2
43.2
42.8
42.8
42 6
43.4
41 7
41.9
42.3
41 7
45.2
41 3
42 3
42 3
43 0
42.1
45.8
42 6
42.3
43.2
42.3
42 1
43 9
41 9
43 4
44.1
42.1
41.5
42 6
42 6
42.3
42 6
42 6
41.7
41 3
Ga»oil
distillate
Per
cent
47 4
42.3
34.4
32.8
35.9
42.8
19.1
19.4
14.9
13.7
8.6
19 2
18.6
14.8
20 2
19.5
14.9
15.0
12.7
18.4
14.9
20.2
33.3
22.7
34.5
31.7
28.1
19.4
19 9
18.8
10.9
18.1
17 8
19 2
14 4
IS 6
17.5
43.9
13 7
32.4
20 9
42 4
23 8
38 5
13.7
12 5
20.3
14 1
9 1
14 7
19.5
9 5
19 7
7.3
9 3
12 6
18 8
19 5
19 6
18 3
19 6
31 4
19 0
22.7
27 7
41 4
G rar-
ity.
'API
28.9
30.6
33.8
34.8
34.4
34 6
31.7
31.0
34.6
34.4
35 4
35.4
33 8
35.2
32 3
32.3
35.0
35.2
35.0
34.2
36.4
35.4
35.8
34.6
36.2
34.8
36.2
34.4
34.4
36.4
37.0
32 5
33 0
33 8
34 4
34 4
36 2
28 4
34 2
29 9
35 6
28 4
35.6
33.2
36 0
39 4
34 4
36 0
35 6
36 4
35 0
32 5
33 2
37 0
37 0
35 2
33 8
35 2
34 2
33 6
33 4
32 8
34 2
33 8
32 7
31 0
Lubricating
distillate
Per
cent
31.0
28.4
11.6
12.4
13 2
14.6
16.4
15.8
15 9
19.6
12 0
17.0
16.3
17 8
15 0
14.3
13.8
15.4
12.3
17.5
15.5
19.5
12.1
12.7
12.2
13.2
14.9
16 0
15.1
16.4
16.6
16 5
16 5
16 4
16 2
16 1
15.0
38 0
17 9
33 4
19 6
27 7
14 5
19 8
17 7
12 1
17 4
15.8
14 0
17 1
15 9
17.5
16.9
14 0
14 5
18 2
16 4
17 2
14 3
16 1
16 6
25 2
16 4
29 4
25 3
21 0
Gravity,
•API
23.8-12.0
24.7-11 7
28 2-15 3
29.3-19.0
30.0-19.5
31.5-20 3
24 7-17.8
24.9-18.1
31 3-25.7
27.5-17.0
32 8-26 6
30.6-24 0
28.0-22.1
31 9-25 0
26.6-21.5
26 6-21 6
31.7-25.2
32.5-26.3
32.5-25.9
28 2-22 5
32.7-26.1
30 2-22 8
31.7-22.0
31.9-20.0
31.5-20.5
30.6-19.4
34.0-21.5
29 . 1-22 . 5
28 9-22.0
32 7-26 3
35 6-28.2
2B. 8-21.0
27 3-21.0
27 3-21 5
30.6-24 0
28 4-21.6
32 3-23 7
24 2-14 5
33 8-24 7
27 3-22 1
33 2-25 2
24 7-20 5
33 4-19 7
27 5-14.5
32 8-25.9
39.6-27 7
29.3-22 0
32 8-28 1
34.0-29 3
33 6-23 9
30.2-25 7
32 3-24 5
30 4-24.3
35 6-23 1
35 8-29 1
31.1-22.0
29 1-22 0
30 4-23 0
29 3-22 8
28 4-20 2
27 3-21 0
28 9-22 5
28 9-22 6
29 1-21 3
28 4-21 5
26.1-14.4
Reaiduum
Per
cent
15.1
9 8
4.3
6.6
5.3
4 0
30 3
27 2
45 8
55.0
18.4
25 5
31.4
25.0
22.8
21.7
22.1
24.3
26 2
23.9
25 0
23.7
5.2
5.4
4.0
5.8
£.2
26 0
27 8
24.4
25.2
33 0
32 1
30.8
23.9
29 3
28 4
20 0
50 7
33.5
22.1
22.8
6 4
9.5
23 5
21 5
26 8
28.5
17.4
26 7
21 0
30 1
28 8
20 8
20.6
35 7
26 8
23 8
27 8
24 1
21 7
27 6
27 0
28 6
26 9
9.7
Grav-
ity,
•API
9.3
9.2
9.7
10.7
10.7
10.9
5.8
5 9
12.5
4.2
15.4
13.5
12 a
15.9
10.7
11.4
16.4
15.8
17.0
4.7
16 8
15.1
13.6
11.4
12.8
12.3
13. S
12 5
10.8
17.0
19 7
7.5
9.2
9.8
14.2
10.7
17.0
11. 1
97
18 2
21 0
18.1
12.2
9 9
18 2
21 1
11.9
17 9
22 8
19 5
18.0
16.0
12 9
26 8
23 3
14.2
15.1
15.7
11 9
9 3
11 0
18 4
12 5
18 4
16 2
11.9
-------
Table A-2 (Continued). PROPERTIES OF UNITED STATES CRUDE OILS
Item
No.
365
366
367
368
36B
370
371
372
373
374
375
376
377
378
379
380
381
382
383
384
385
386
387
388
389
390
391
392
393
394
395
396
397
398
399
400
401
Stall
Field (Formation, age)1
West Ranch (98-A Frio Olig.)
West Ranch (Glaascock, Frio, Olig.)
West Ranch (Greta, Olig.)
West Ranch (Ward, Frio, Olig.)
White Point, East (58OO' Greta, Olig.) . .
White Point, East (5600' Brigham, Frio,
Olig )
Yates (San Andres, Perm.)
Vtah
Ratherford (Paradox, Penn.)
White Mesa (Paradox Penn.)
(f yarning
Beaver Creek (Steele U Cre.)
Big Muddy (Frontier U. Cre.) . . .
Big Sand Draw (Tenslftep Penn.) . . .
Coyote Creek (Minnelusa, Penn.)
Donkey Creek ( Dakota L. Cre.)
Elk Basin (Frontier U Cre.)
Glenrock (Dakota I*. Cre.)
Grieve (L. Cre.)
Little Buffalo Buin (Phosphoria. Perm.)
Meadow Creek (Sussex U. Cre.)
Oregon Basin (Embar-Tensleep-Madison,
Salt Creek (Wall Creek U. Cre.)
Werta (Tensleep Penn.)
Winkleman Dome (Phosphoria, Perm.). . . .
Grav-
ity,
"API
39.8
31.0
24.9
30.8
27.3
38 4
30.2
40 4
40.0
41.3
41.1
33.8
35.8
34.2
35.8
24 3
28 6
40.9
39.4
43.2
13.8
27.5
22.0
34.4
44.5
38.2
22.8
20.7
35.2
38 8
34 0
20.5
36 6
28.2
39.0
33.6
25.7
Sulfur,
wt.
per cent
0.11
0.13
0.16
0.15
0.13
0.13
1.54
0.20
<0.10
<0.10
0.10
0 20
0.12
1 35
1 87
2.50
2 52
<0 10
0.12
<0 10
3.58
2.43
2.88
0 16
<0.10
<0.10
2.98
3.31
1 23
0.12
1.70
3.25
0.12
2.18
0.37
1.32
2.59
Viscos-
ity.
SUSat
100°F
35
41
57
40
44
35
50
38
37
37
36
48
47
43
37
140
63
36
37
35
6.000
66
180
55
35
42
230
340
41
39
43
360
43
66
38
43
93
Carbon
residue
of
residuum,
wt.
per cent
3.9
3.8
2.7
4.3
4.3
3.5
9.9
3.5
3.0
2.9
2.9
5.6
4.7
12 4
9.7
12.2
13.9
4.6
4.0
3.3
22.7
11.6
18.3
6.5
2.3
4.0
15 2
15.3
11.4
4.4
10.8
20.5
4 4
16.1
6.4
10.1
16 3
Gasoline and
naphtha
Per
cent
35.2
23.5
4.3
23.7
15.4
40.5
24.1
35.0
34.0
34.5
35.2
24.4
26 3
26.6
36.1
12.3
20.2
36.5
34.4
46.1
2.1
19.0
13.3
24.9
45 8
28 8
11.2
12 1
29.1
32.5
29.3
14 3
27.6
19 3
317
28 5
16.0
Grav-
ity,
"API
55.7
50.1
44.7
49.9
47.2
54.7
58.4
59.5
57.9
59.7
59.5
54.2
58 2
60.0
60.5
59.7
58.7
59.7
59.5
57.7
52.7
58.9
50.4
55.7
60 2
58 9
58 9
60 2
61 3
60.2
61 5
59.5
56.9
61 0
60 0
59.7
57.7
Keroaine
dieullate
Per
cent
8.8
7 0
4.4
10.2
11.5
10 0
11.3
11.7
3.5
12.8
5.8
7.2
8.5
9.2
10.8
6.2
5.4
4.3
8.4
6.7
10.3
4.9
8.7
6.3
10.7
10 6
11.3
3 3
10 1
9 1
10.4
10.8
8.4
Grav-
ity,
•API
44.1
42.0
40.2
42,1
42.6
42 8
42.6
42.8
42.3
43.6
41 5
42 1
41.7
43.0
41.5
41 3
43 2
43 4
43.8
43 2
42 3
42.6
44.1
41 7
42.8
42.8
42.5
42.6
42.8
44.1
42.8
42 5
42 3
GaJ oil
distillate
Per
cent
34.2
40.6
48.8
42.0
45.7
30.8
17.9
16.9
9.5
16.8
14.9
18.1
20.5
17.8
21.5
13.4
16.3
18.6
14.9
20.8
12.8
18.6
14.1
17 0
15.8
19 8
12.2
12.0
15.5
15.9
18.8
14.8
16.4
17 0
13.6
16 1
15 2
Grav-
ity,
•API
36.0
31.3
29 7
31.0
30.6
32.3
33 0
36.8
37.8
36.8
36.6
36.6
36.1
34.8
32.8
32.8
33 2
36.6
38.0
36.4
35.6
34.4
35.3
37.0
36.4
37 0
34 2
32.7
34 2
36.0
33 6
33 8
36 8
33 4
36 8
33 6
32 8
Lubricating
distillate
Per
cent
14.9
23.5
28.2
24.2
26.0
14.3
20 3
15.7
19 9
15.1
14 8
18.1
16.5
19.7
17 8
20.3
23.9
13.5
13.8
14.4
26 9
21 7
21.1
15 1
13.1
17 7
22.4
19 4
19 8
17 4
17 8
19.6
18.9
20 6
19.6
19 9
21.5
Gravity.
"API
31 5-18.7
26.8-ld 7
24.7-16.5
26.3-13.9
23.1-14 7
26.6-18 5
28 8-21.6
34.2-31.0
35.8-28.9
34.4-28.2
34 4-27.3
33 8-25.9
33 0-26.4
30.4-21.5
26.4-18.4
29 3-20.0
29.1-19.4
34 0-27.7
33.8-27.7
32.8-27.7
28.6-14.8
27.5-19.4
28. 8-17. B
34.6-28 Ql
33.6-27.5
33.6-26.8
29 5-19.7
27.5-18.1
30.2-22.1
33.2-25 4
29 1-21 0
27.7-17 9
34 0-27 1
29 5-20 8
34.2-26 6
29 8-19 2
28 7-19.5
Residuum
Per
cent
5.6
11.5
18.1
8.8
12.2
'6.6
31.6
21.2
24.0
21.3
21.5
28.8
31 2
21.8
17 9
45.9
28.9
21.2
24.3
11.7
52.9
35.2
43.3
34.7
13.2
25 8
45.1
49.3
23 5
21.9
22 6
47 5
26.1
33 1
21 9
24 3
37 3
Grav-
ity,
•API
11.1
14.1
15.1
11.6
12.3
12.9
14.5
23.1
22. 8
22.3
22.3
16.7
19.8
11.6
10.7
11 7
10 1
20.7
19 5
19.5
4.0
10 9
7.1
18.7
20.7
19.2
9.0
8.2
13.2
18.4
11 3
6.8
19.2
9 4
18.2
13.5
9.2
1 Geologic age names are abbreviated a> follows; Cambrian, Cam.; Cambro-Ordovician, Cam.-Ord.; Cretaceous, Cre.; Lower Cretaceous, L. Cre.; Upper Cretaceous,
U. Cre.; Devonian, Dev,; Upper Devonian, U. Dev.; Eocene, Eoc.; Jurassic, Jur.; Miocene, Mio.; Lower Miocene, L. Mio.; Upper Miocene, U. Mio.; Misstssippian,
Miss.; Oligocene, Olig.; Ordovician, Ord.; Lower Ordovician, L. Ord.; Middle Ordovician, M. Ord.; Penney Iranian, Penn.; Permian, Perm.; Pliocene, Plio.; Pliocene-
Miocene, Plio.-Mio.; Pliocene-Pleistocene, PHo.-Pleist.; Upper Pliocene, U. Plio.; Silurian, Sil., Pre-Cambrian, Pre-Cam.
102
-------
Table A-3. TRACE ELEMENT CONTENT OF UNITED STATES CRUDE OILS
Tr.icr_&la>icat. ff*
Stft« and Field
ALABAMA
Toxey
Toxey
V
9
10
Nl Fc Ba Li
L4
16
Kn Ha Sn Hg
Analytical Method Y^ar
Emission spoctroscopy 1971
Ealssiou spi-ctroscopy 1971
ALASKA
Kuparuk. Prudhoe Bay
Kuparuk., Prudhoe Bay
McArthur River, Cook Inlet
Prudhae Bay
Put River, Prudhoe Bay
Redoubt Shoal, Cook Inlet
Trading Bay, Cook Inlet
32
n
Emission
Emission
Emission
Emission
Emission
Emission
Emission
spectroscopy
spectroscopv
spectroscopy
spertroscopy
spectroscopy
spectroscopy
spectroscopy
1971
1971
1971
1971
1971
1971
1971
ARKANSAS
Brlater, Columbia
El Dorado, East
Schuler
Smackover
Stephens-Smart
Tubal, Union
West Atlanta
1.2 <1 <1 <1 nd nd
6.3 <1 <1 <1 nd ^1
:1 <1 <1 <1 nd nd
Emission speccroscopy
Emission spectroscopy
Emission spectroscopy
Emission spectroscopy
Emission spectroscopy
Emission spectroscopy
Emission spectroscopy
1971
1971
1961
1971
1961
1971
1961
CALIFORNIA
Ant Hill
Arvin
Bradley Sands
Cat Canyon
Cat Canyon
Co*linger
Coal Oil Canyon
Coles Levee
Coles Levee
Guyana
Cymric
Cymric
Cymric
Cymric
Cymric
Cymric
Edison
Elk
Clwood South
Glbaon
Cota Ridge
Helm
Helm
Huntlngton Beach
Inglewood
Kettlenan
Kettleman Hills
Las Flores
Lompoc
Lonpoc
Lost Hills
Midway
Nicolai
North Belridge
North Bel ridge
North Belrldge
Nortn Belridge
Orcutt
Oxnard
Purlsna
Raisin City
14.3 66.5 28.5 <1 <1 nd
9.0 28.0
134.5
128 75
209 102
5.1 21.9 5.1 <1 <1 <1
6.0 20.0
11.0 31.0
2.2 21.6 2.2 <1 <1 nd
10.0 12. 0
30.0 43.0
0.8 2.3 2.0
0.6 1.1 2.0
1.0 2.0 2.0
6.0 ll.O
8.3 38.5 38.5 <1 <1 <1
nd 11
37 125
188 80
14.0 27.0
2.5 10.5 2.5 <1 <1 nd
29 104
125.7 125.7 125.7 <1 1.3 nd
34.0 35.0 24.0
11.0 24.0
106.5
37. h
199 90
39.0 8.0
82.6 82.6 82.6 1.8 1.8 <1
246.5
— 107
— 80
-- 83
23 83
162.5
403.5 — '
^18.5
8.0 21-. 0
Emission spectroscopv
(1)
Emission spectroscopy
Emission spectroscopy
-.1 nd Emission spectroscopv
Emission spectroscopy
Emission spectroscopy
<1 nd Emission spectroscopy
Emission spectroscopy
Emission spectroscopy
Emission speccroscopy
2.6^
2.4 ) Emission spectroscopy
l.sJ
Emission spectroscopy
21. (T\
14.0 } Emission spectroscopy
2.9J
Emission spectroscopy
Emission spectroscopy
<1 nJ Emission spectroscopy
Emission spectroscopy
X-rav fluorescence
Emission spectroscopy
Emission spectroscopy
ad <1 Emission spectroscopy
emission spectroscopy
<1 od Emission spectroscopy
Colorlmetrlc
U)
(1)
(1)
Emission .spectroscopy
Emission spectrosLOpy
*1 nd Kmission spectruscopy
(1)
X-ray fluon-scence (inter, st
Cojorlmet r ii_
Emission svt-ctroscopy
X-r.iy flunresc. (ext. std.)
(1!
(1)
(1)
Emission spectroscopy
1961
1956
1958
1971
1971
1961
1956
1956
1961
1956
1956
1961
1961
1961
1961
1961
1956
1961
1971
1969
1971
1956
1961
1971
1961
1952
1958
1958
1958
1971
1956
1961
1958
d)19'->9
I95y
1959
1960
195S
1938
!<*•)«
1«6
(1) Not specified.
nd Sought but not detected.
103
-------
Table A-3 (Continued). TRACE ELEMENT CONTENT OF UNITED STATES CRUDE OILS
Trie* El «
State and Field
Rio ftravo
Rio Bravo
Rio Bravo
Russell Ranch
San Joaquln
Santa Maria
Santa Maria
Santa Maria
Santa Maria
Santa Maria Valley
Santa Maria Valley
Santa Maria Vallev
Santa Maria Valley
Signal Hill
Signal Hill
Tejon Hills
Ventura
Ventura
Ventura Avenue
Wheeler Ridge
Wilmington
Wilmington
Wilmington
Wilmington
Wilmington
Wilmington
Wilmington
COLORADO
Badger Creek
Badger Creek
Cramps
Cramp
Hiawatha
Moffat Dome
Range ly
Rangely
Ratvgely
Seep
White River Area
FLORIDA
Jay
ILLINOIS
Loudon
KANSAS
Brevster
Brews ter
Brock
CofCeyvllle
Cunn Ingnam
Cunningham
lola
lola
"Xansas-1"
"K»nsas-2"
Me touch
Otis Albert
Ot In Albert
Pawnee Rock
Rhod-s
Rhodes
Rhodes
Rhodes
Rhodes
Rhodes
Solomun
V
^^
—
12.0
44.8
223
202
180
280
207
240
280
174
28
25
64
42
49
25.2
7
43
41
53
—
—
46
36.0
<1
<1
<1
<5
>21
6.3
6.0
9.1
3.4
—
—
—
36
38
32
7
Te Ba Cr Hn Mo Sn *•
2.6
2.5
17
1.7 <1 1.7 <1 4.0 md
31
28
36 3.6 <1 nd 1 nd
<1 <1 <1 <1 <1 <1
<1 pect rost-opy
Emission speccroscopy
Emission ^peccroscopy
X-ray t iuorescenc« (Int.
Emission spectroscopy
X-ray f luorttscencc (int.
X-ray f luoresccnc*; (Int.
Emission spectrusropy
X-ray fluorescence ( tnt ,
Emission apectrosropy
Year
• f A ) t QA?
SCO • / iTOi
std.) 1960
1960
1956
1958
1952
1958
1956
1960
1971
std.) 1960
std.) 1960
1961
1958
1956
1956
1956
1952
1958
1956
1956
1952
1971
std.) 1959
atd.) 1959
1966
1961
1961
1961
1961
1961
1961
1961
1961
1961
1961
1956
1961
1971
1952
1958
1961
1961
1961
1961
1961
1961
1961
1961
1966
1966
1961
1961
1961
1961
std.) 1960
1960
std.) I960
std.) 1960
1960
std.) 1959
1961
(1) Not specified
nd Sought but not detected
104
-------
Table A-3 (Continued). TRACE ELEMENT CONTENT OF UNITED STATES CRUDE OIL
State and Field
LOUISIANA
Bay Harchard
Colquitc, Clairbomc
Colqultt, Clalrborne
Colqultt, Callrborne
(Saackover 8)
Delta (West) Offshore,
Block 117
Delta (West) Block 27
Delta (West) Block 41
Eugene Island, Offshore,
Block 276
Eugene Island, offshore.
Block 238
lake Washington
Hain Paaa, Slock 6
Main Pasa, Block 41
01 la
Ship Shoal, Offshore,
Block 176
Ship Shoal, Offshore,
Block 176
Ship Shoal, Block 208
Shongaloo, N. Red Rock
South Pass, Offshore,
Block 62
Tigfcaller, S.. Offshore,
Block 54
MICHICAfl
Trent
V
nd
nd
ad
nd
nd
nd
nd
4
nd
ml
od
ad
<1
•4
nd
nd
nd
nd
ad
—
Tcaca giueat. alf
Nl ft B« tr Hn
2
nd
nd
nd
2
2
2
ad
na
4
3
1
5.56 0.07
ad
nd
2
nd
4
nd
0.23
i
X" Sn Aa Analytical Method
Emission spt-c truscopy
Emission spn t rosropy
Emission sp«-i t fo:.< <>py
Emission spivt rosnipv
Emission t,pcctro«copv
Emission spectroMcopy
Cmf s {
Emission spetlroscopy
Caission spectroacopy
sVnisslon spectrotcopy
blssion ipectroscopy
Emission spectroacopy
Emission spectroscopy
Emission spectroscopv
p py
Emission spectroscopy
Emission spectroacopy
Emission spectroscopy
Year
1971
1971
1171
1971
1971
1971
1971
1971
2971
1971
1971
1971
1952
1971
1971
1971
1971
1971
1971
19S6
MISSISSIPPI
Bantervllle, Laaar and
Marlon
Heidelberg
Mississippi
Tallhalla Creek, Smith
Tallhalla Creek, Smith
Tallhalla Creek, Smith
(Smackover)
Tlngley, Yazoo
MONTANA
Bell Creek
Big Wall
Soap Cr*«k
NEW MEXICO
Rattlesnake
Rattlesnake
Table Mesa
Allurve (Novaca)
Allurve (Nowata)
Allurve (Nowata)
Bethel
Burbank
Canr
Chelaea (Novata)
Chelsea (Novaca)
Cheleea (Novata)
Cheyarha
Ch*yarha
Choyarha
Ch«yarha
Cronuell
Cromwel1
Croavell
" Cromwell
Cronwell
Cromwell
Oil!
Dover, Southeast
Dustin
E. Lindsay
E. Semlnole
E. Teaser
Fish
Glen Pool
40
15.35
—
nd
nd
nd
7
nd
24
132
-------
Table A-3 (Continued). TRACE ELEMENT CONTENT OF UNITED STATES CRUDE OILS
State and Field
Crief Creek
Hawkins
Hawkins
Horns Corner
K»r 1 m
ac le
Kacle
Ptatie
Xatle
Kendrlck
Xonava
Laf f oon
Little River
Middle Cllllland
Naval Reserve
New England
N. Dill
M. E. Castle Ext.
M. E. Elmore
N. E. Elmore
S. Okemah
H. U. Horn* Comer
Olympia
Osage City
S. U. Maysville
S. U. Maysville
Tatuas
Tatuas
Tatuas
Veleetka
U. Holdenvllle
U. Uevoka
Uevoka
Uewoka Lake
Wewoka Uke
WUdhorse
Wynona
Wynona
TEXAS
Anahuac
Brantley-Jackson, Hopkins
Srantley-Jackson, Soackover
Conroe
East Texas
East Texas
East Texas
East Texas
Edgevood, Van Zandt
Flnley
Jackson
Lake Trammel, Nolan
Mtrando
Panhandle, Carson
Panhandle, Hutchinson
Panhandle, West Texas
Refugio
Refuglo, Light
Salt Flat
Scurry County
Sweden
Talco
Talco
Wasson
West Texas
West Texas
West Texas
West Texas
West Texas
West Texas
West Texas
West Texas (Imogene)
Tfates-Pecus
T
V U
0.10 0.42
2.10 8.50
0.72 3.50
0.70
0.17 0.52
0.48 1.60
0.29 1.00
0.24 1.00
<1 <1
0.10 0.65
0.17 1. 10
<1 <1
<1 <1
<1 mls*.ion spectroscopy
(1)
Emission spectroscopy
•- EmlHsion bpcct roscopy
Eaission spectroscopy
(1)
5.1 ' Colbrlmetric
0.88 Chemical
0.11 Chemical
Tear
1956
1956
1956
1956
1956
1956
1956
1956
1961
1956
1961
195*
1961
1961
1961
1956
1956
1956
1956
1956
1956
1956
1961
1956
1956
1959
1959
1960
1956
1956
1956
1956
1956
1956
1956
1961
1961
1961
1958
1971
1971
1952
1971
1952
1952
1952
1971
1961
1952
1971
1952
1971
1 971
A.? / 1
1952
1952
1958
1952
1952
19S8
1952
1958
1971
1960
1952
1956
ma
1958
1958
1952
1952
1952
(1) Not specified
nd Sought but not detected
106
-------
Table A-3 (Continued). TRACE ELEMENT CONTENT OF UNITED STATES CRUDE OILS
State and Field
UTAH
Duchesne
Ducheane
Ducheane County
Red Waah
Red Wash
Roosevelt
Roosevelt
Virgin
Virgin
West Pleasant Valley
Wildcat
WYOMING
Beaver Creek
Big Horn Mix
Bison Basin
Circle Ridge
Corral Creek
Crooks Cap
Dallas
Dallas
Derby
Elk Basin
Elk Basin
Garland
Crass Creek
Half Moon
Half Moon
Hani 1 ton Done
Hamilton Done
Hamilton Dome
Little Mo
Lost Soldier
Lost Soldier
Lost Soldier
Mitchell Creek
North Oregon Basin
North Oregon Basin
North Oregon Basin
• Oil Mountain
Pilot Butte
Pilot Butte
Pine Ridge
Prescott No. 3
Recluse
Roelis
Salt Creek
Salt Creek
Salt Creek
Salt Creek
Skull Creek
South Casper Creek
South Fork
South Spring Creek
South Spring Creek
Steamboat Butte
Washakie
Winkleman Done
V Ni tr »«
'•1 <1 19 ^ 0
* * J.T J.T
<1 <1 1.4 <1
<1 12.3 12.3 -2.9
nd nd
nd nd ~—
<1 3.2 <1 -l •! ^1
<1 <1 <1 nd
<1 •! *1 nd
el • I <1 nd
< 1 '• 1 < 1 nd
<1 ^1 -:1 nd
^i ^l <1 nd
«*! • 1 <1 nd
<1
-------
Table A-4. SULFUR AND NITROGEN CONTENT OF THE GIANT U.S. OIL FIELDS
State/Region and Field
ALABAMA
Citronelle
ALASKA
Granite Point
McArthur River
Middle Ground Shoal
Prudhoe Bay (North Slope)
Swanson River
APPALACHIAN
Allegany
Bradford
ARKANSAS
Magnolia
Schuler and East
Smackover
CALIFORNIA
SAN JOAQUIN VALLEY
Belridge South
Buena Vista
Coalinga
Coalinga Nose
Coles Levee North
Cuyama South
Cymric
Edison
Elk Hills
Fruitvale
Greeley
Kern Front
Kern River
Kettleman North Dome
Lost Hills
McKittrick - Main Area
Midway Sunset
Mount Poso
Rio Bravo
COASTAL AREA
Carpenteria Offshore
Cat Canyon West
Dos Cuadras
Elwood
Sulfur,
Weight
Percent
0.38
0.02
0.16
0.05
1.07
0.16
0.12
0.11
0.90
1.55
2.10
Nitrogen,
Weight
Percent
0.02
0.039
0.160
0.119
0.23
0.203
0.028
0.010
0.02
0.112
0.08
1971
Production
(Thousands
of Barrels)*
6,390
5,552
40,683
11,277
1,076
11,709
388
2,470
850
800
2,800
0.23
0.59
0.43
0.25
0.39
0.42
1.16
0.20
0.68
0.93
0.31
0.85
1.19
0.40
0.33
0.96
0.94
0.68
0.35
—
5.07
—
—
0.773
—
0.303
0.194
0.309
0.337
0.63
0.446
0.472
0.527
0.266
0.676
0.604
0.212
0.094
0.67
0.42
0.475
0-158
— '
0.54
—
—
9,211
5,429
7,866
4,752
1,006
2,034
3,345
1,417
951
1,109
761
3,440
25,54-2
840
2,328
5,348
33,583
1,378
425
5,295
2,705
27,739
108
* Oil and Gas Journal, January 51, 1972, pp. 95-ICQ.
108
-------
Table A-4 (Continued), SULFUR AND NITROGEN CONTENT OF THE
GIANT U.S. OIL FIELDS
State/Region and Field
Orcutt
Rincon
San Ardo
Santa Ynez***
Santa Maria Valley
South Mountain
Ventura
LOS ANGELES BASIN
Beverly Hills
Brea Olinda
Coyote East
Coyote West
Dominguez
Huntington Beach
Inglewood
Long Beach
Montebello
Richfield
Santa Fe Springs
Seal Beach
Torrance
Wilmington
COLORADO
Rangely
FLORIDA
Jay
ILLINOIS
Clay City
Dale
Loudon
New Harmony
Salem
KANSAS
Bemis-Shutts
Chase-Silica
Eldorado
Hall-Gurney
Kraft-Prusa
Trapp
LOUISIANA
NORTH
Black Lake
Caddo-Pine Island
Delhi
Haynesville (Ark.-La.)
Homer
Lake St. John
Rodessa (La.-Tex.)
Sulfur,
Weight
Percent
2.48
0.40
2.25
4.99
2.79
0.94
2.45
0.75
0.95
0.82
0.40
1.57
2.50
1.29
0.68
1.86
0.33
0.55
1.84
1.44
Nitrogen,
Weight
Percent
- 0.525 ~
0-48
0.913
0.56
—
0.413
0-612
0.525
0.336
0.347
0.360
0.648
0.640
0.55
0.316
0.575
0.271
0.394
0.555
0.65
1971
Production
(Thousands
of Barrels)*
2,173
4,580
9,939
1,966
1,962
10,188
8,400
4,228
864
2,436
1,717
16,249
3,992
3,183
740
1,910
953
1,468
1,338
72,859 .
0.56
0.32
0.37
0.82
0.66
0.83
0.17
0.46
0.073
0.002
0.19
0.15
0.27
0.23
0.17
0.57
0.44
0.18
0.34
0.27
0.41
0.082
0.080
0.097
0-158
0.102
0.162
O.L3
0.085
0.108
0.171
0.076
0.026
0.053
0.022
0.081
0.032
10,040
.370
4,650
690
4,420
2,740
3,360
2,590
1,600
1,500
2,480
3,200
1,930
3,500
5,870
2,730
330
1,170
900
'* Oil and Gas Journal, January 31, 1972, pp. 95-100.
109
-------
Table A-4 (Continued). SULFUR AND NITROGEN CONTENT OF THE
GIANT U.S. OIL FIELDS
State/Region and Field
OFFSHORE
Bay Marchand Block 2
{Incl. onshore)
Eugene Island Block 126
Grand Isle Block 16
Grand Isle Block A3
Grand Isle Block 47
Main Pass Block 35
Main Pass Block 41
Main Pass Block 69
Ship Shoal Block 208
South Pass Block 24
(Incl. onshore)
South Pass Block 27
Timbalier S. Block 135
Timbalier Bay
(Incl. onshore)
West Delta Block 30
West Delta Block 73
SOUTH, ONSHORE
Avery Island
Bay De Chene
Bay St. Elaine
Bayou Sale
Black Bay West
Caillou Island
(Incl. offshore)
Cote Blanche Bay West
Cote Blanche Island
Delta Farms
Garden Island Bay
Golden Meadow
Grand Bay
Hackberry East
Hackberry West
Iowa
Jennings
Lafitte
Lake Barre
Lake Pelto
Lake Salvador
Lake Washington
(Incl. offshore)
Leeville
Paradis
Quarantine Bay
Romere Pass
Venice
Vinton
Weeks Island
West Bay
Sulfur,
Weight
Percent
0.46
0.15
0.18
0.23
0.19
0.16
0.25
0.38
0.26
0.18
0.66
0.33
0.33
0.12
0.27
0.39
0.16
0.19
0.23
0.16
0.10
0.26
0.22
0.18
0.31
0.30
0.29
0.20
0.26
0.30
0 .14
0.21
0.14
0.37
0.20
0.23
0.27
0.30
0.24
0.34
0.19
0.27
Nitrogen,
Weight
Percent
0.11
0.030
0.04
0.04
0.071
0.025
0.098
0.02
0.068
0.049
0.088
0.081
0.09
0.060
0.04
0.04
0.04
0.033
0.01
0.055
0.06
0.054
0.039
0.02
0.035
0.02
0.146
0 .019
0 .061
0 .044
0 .071
Production
(Thousands
of Barrels)*
30,806
5,621
21,681
22,776
4,271
3,504
18,469
12,775
10,038
20,330
21,425
13,578
30,988
26,390
15,987
3,400
6,643
7,775
5,293
9,892
31,828
15,658
8,797
1,278
16,096
2,738
6,680
2,226
3,760
876
292
10,877
7,592
4,891
4,380
10,913
4,343
1,898
7 ,,117
3 ,,759
5,,475
2,299
iO,,183
9,563
* Oil and Gas Journal, January 31, 1972, pp. 95-100.
no
-------
Table A-4 (Continued). SULFUR AND NITROGEN CONTENT OF THE
GIANT U.S. OIL FIELDS
State/Region and Field
MISSISSIPPI
Baxterville
Heidelberg
Tinsley
MONTANA
Bell Creek
Cut Bank
NEW MEXICO
Caprock and East
Denton
Empire Abo
Eunice
Hobbs
Maij amar
Monument
Vacuum
NORTH DAKOTA
Beaver Lodge
Tioga
OKLAHOMA
Allen
Avant
Bowlegs-
Burbank
Cement
Gushing
Earlsboro
Edmond West
Eola-Robberson
Fitts
Glenn Pool
Golden Trend
Healdton
Hewitt
Little River
Oklahoma City
Seminole, Greater
Sho-Vel-Tum
Sooner Trend
St". Louis
Tonkawa
Sulfur,
Weight
Percent
2.71
3.75
1.02
0.24
0.80
0.17
0.17
0.27
14
41
0.55
1.14
0.95
0.24
0.31
Nitrogen,
Weight
Percent
0.111
0.112
0.08
0.13
0.055
0.034
0.014
0.014
0.071
0.08
0.062
0.071
0.075
0.019
0.016
0.70
0.18
0.24
0.24
0.47
0.22
0.47
0.21
0.35
0.27
0.31
0-15
0.92
0.65
0.28
0.16
0.30
1.18
0.11
0.16
0.21
—
0.140
0.051
0.152
0.08
—
0.045
0.115
—
0.096
0.15
0.15
0.148
0.065
0.079
0.016
0.27
0.04
0.033
1971
Product
(Thousands
of Barrels)*
9,300
3,450
2,450
5,950
5,180
905
2,350
9,520
1,330
5,700
6,040
3,720
17,030
3,140
1,790
2,920
365
2,260
5,240
2,370
4,300
765
730
4,850
1,420
2,480
12,330
4,600
5,660
440
1,750
1,640
36,500
15,240
1,350
290
* Oil and Gas Journal, January 31, 1972, pp. 95-100.
m
-------
Table A-4 (Continued). SULFUR AND NITROGEN CONTENT OF THE
GIANT U.S. OIL FIELDS
State/Region and Field
TEXAS
DISTRICT 1
Big Wells
Darst Creek
Luling-Branyon
DISTRICT 2
Greta
Refugio
Tom O'Connor
West Ranch
DISTRICT 3
Anahuac
Barbers Hill
Conroe
Dickison-Gillock
Goose Creek and East
Hastings E&W
High Island
Hull-Merchant
Humble
Liberty South
Magnet Withers
Old Ocean
Raccoon Bend
Sour Lake
Spindletop
Thompson
Webster
West Columbia
DISTRICT 4
Agua Duke-Stratton
Alazan North
Borregas
Government Wells N.
Kelsey
La Gloria and South
Plymouth
Seeligson
Tijerina-Canales-Blucher
White Point East
DISTRICT 5
Mexia
Powell
Van and Van Shallow
Sulfur,
Weight
Percent
Nitrogen,
Weight
Percent
0.78
0.86
0.17
0.11
0.17
0.14
0.23
0.27
0.15
0.82
0.13
0.20
0.26
0.35
0.46
0.14
0.19
0.14
0.19
0.14
0.15
0.25
0.21
0.21
<.l
0.04
<.l
0.22
0,13
<.l
0.15
<.l
<.l
0.13
0.20
0.31
0.8
0.075
0.110
0.038
0.027
0.038
0.029
0.041
0.06
0.022
0.014
0.028
0.03
0.048
0.081
.0.097
0.044
0.033
0.029
0.048
0.016
0.03
0.029
0.046
0.055
0.015
0.014
0.029
0.043
0.008
0.008
0.049
0.015
0.010
0.02
0.048
0.054
0.039
1971
Production
(Thousands
of Barrels_l*
5,840
1,971
1,679
3,577
657
23,360
17,009
9,052
766
12,994
2,920
1,095
17,191
2,081
1,643
1,241
949
3,869
1,132
2,409
1,058
328
12,885
16,206
1,351
2,518
3,723
4,818
511
6,059
936
986
6,424
5,986
1,606
109
109
12,337
Oil and Gas Journal, January 31, 1972, pp. 95-100.
•112
-------
Table A-4 (Continued). SULFUR AND NITROGEN CONTENT OF THE
GIANT U.S. OIL FIELDS
State/Region and Field
DISTRICT 6
East Texas
Fairway
Hawkins
Neches
New Hope
Quitman
Talco
DISTRICT 7-C
Big Lake
Jameson
McCamey
Pegasus
DISTRICT 8
Andector
Block 31
Cowden North
Cowden South, Foster,
Johnson
Dollarhide
Dora Roberts
Dune
Emma and Triple N •
Fuh rman-Mas cho
Fullerton
Goldsmith
Headlee and North
Hendrick
Howard Glasscock
latan East
Jordan
Kermit
Keystone
McElroy
Means
Midland Farms
Penwell
Sand Hills
Shafter Lake
TXL
Waddell
Ward South
Ward Estes North
Yates
Sulfur,
Weight
Percent
0.32
0.24
2.19
0.13
0.46
0.92
2.98
Nitrogen,
Weight
Percent
0.066
0-076
0.083
0.007
0.036
0.26
<.l
2.26
0.73
0.22
0.11
1.89
1.77
0.39
<.l
3.11
<.l
2.06
0.37
1.12
<.l
1.73
1.92
1.47
1.48
0.94
0.57
2.37
1.75
0.13
1.75
2.06
0.25
0.36
1.69
1.12
1.17
1.54
0-071
0.034
0.139
0.200
0.033
0.032
0.095
0.127
0.074
0.023
0.111
0.025
0.085
0.041
0.079
0.083
0.094
0.096
0.120
0.10
0.092
0.042
0.080
0.205
0 .080
0.205
0.085
0 .041
0 .067
0 .098
0 .08
0 .107
0 .150
1971
Production
(Thousands
of Barrels)*
71,139
14,271
29,054
3,942
292
3,103
4,380
474
1,387
985
4,052
5,694
6,242
9,782
14,198
7,592
3,066
11,425
3,030
1,935
6,607
20,951
1,460
766
6,606
3,687
3,212
2,007
8,322
9,015
7,921
6,059
2,044
6,606
2,956
4,854
4,453
803
10,184
13,359
Oil and Gas Journal, January 31, 1972, pp. 95-100.
113
-------
Table A-4 (Continued). SULFUR AND NITROGEN CONTENT OF THE
GIANT U.S. OIL FIELDS
State/Region and Field
DISTRICT 8-A
Cogdell Area
Diamond M
Kelly-Snyder
Levelland
Prentice
Robertson
Russell
Salt Creek
Seminole
Slaughter
Spraberry Trend
Wasson
DISTRICT 9
KMA
Walnut Bend
DISTRICT 10
Panhandle
UTAH
Greater Aneth
Greater Redwash
WYOMING
Elk Basin (Mont.-Wyo.)
Garland
Grass. Creek
Hamilton Dome
Hilight
Lance Creek
Lost Soldier
Oregon Basin
Salt Creek
Sulfur,
Weight
Percent
0.38
0.20
0.29
2.12
2.64
1.37
0.77
0.57
.98
.09
0.18
1.14
1.
2.
0.31
0.17
0-55
0.20
0.11
1.78
2.99
2.63
3.04
0.10
1.21
3.44
0.23
Nitrogen,
Weight
Percent
0 .063
0 .131
0 .066
0 .136
0 .117
0 .100
0 .078
0 .094
0 .106
0 .173
0 .065
0.068
0.05
0.067
0.059
0.255
0.185
0.290
0.311
0.343
0.055
0.076
0.356
0.109
1971
Production
(Thousands
of Barrels)*
14,235
7,373
52,487
9,746
5,913
2,774
4,234
9,271
9,125
35,515
18,688
51,210
2,920
3,942
14,235
7,660
5,800
14,380
3,500
3,760
4,
11,
,500
,300
325
4,820
12,260
11,750
* Oil and Gas Journal. January 31, 1972, pp. 95-100.
Source: Magee, E. M., H. J. Hall, and G. M. Varga, Jr., Potential
Pollutants in Fossil Fuels, PB 225 039, EPA-R2-73-249,
Contract No. 68-02-0629, Linden, N.J., Esso Research and
Engineering Co., 1973.
114
-------
Table A-5. SULFUR AND NITROGEN CONTENT OF CRUDE OILS
FROM NATIONS WHICH EXPORT TO THE U.S.
NORTH AMERICA
Province and Field
Sulfur, Nitrogen,
Weight Weight Production,
Percent Percent bbl/dav
Canada
Acheson, Alta.
Bantry, >lta.
Bonnie Glen, Alta.
Boundary Lake, B.C.
Coleville, Sask.
Daly, Manitoba
Dollard, Sask.
Excelsior, Alta.
Fenn - Big Valley, Alta.
Fosterton-Dollard, Sask.
Gilby, Alta.
Golden Spike, Alta.
Harraattan, East, Alta.
Harmattan-Eklton, Alta.
Innisfail, Alta.
Joarcam, Alta.
Joffre, Alta.
Kaybob, Alta.
Leduc, Alta.
Lloydrainster, Alta.'
Midale, Sask.
North Premier, Sask.
Pembina, Alta.
Redwater, Alta.
Steelman, Sask.
Stettler, Alta.
Sturgeon Lake, S., Alta.
Swan Hills, Alta.
Taber, East, Alta.
Taber, West, Alta.
Turner Valley, Alta.
Virden-Roselea, Man.
Virden-North Scallion, Man.
Wainwright, Alta.
Westerose, Alta.
West Drumheller, Alta.
Weybum, Sask.
Wizard Lake, Alta.
0.46
2.41
0.32
0.72
2.62
0.18
2.18
0.71
1.89
2.91
0.12
0.37
0.37
0.44
0.58
0.13
0.56
0.04
0.53
3.67
2.24
2.92
0.22
0.22
0.73
1.59
0.85
0.46
3.08
2.55
0.34
1.43
1.47
2.60
0.25
0.51
1.89
0.24
—
—
—
—
0.126
—
—
0.027
—
0.120
—
—
—
—
—
—
—
—
0.016
—
—
—
—
0.041
— —
0.055
—
0.034
\
— J
—
— —
—
r —
-—
—
—
0.023
9,400
6,900
36,800
27,700
4,700
1,400
8,800
1,600
19,600
7,600
5,300
37,400
6,000
4,500
5,500
5,900
6,600
10,900
• 16,700
2,200
11,700
6,300
140,000
58,000
28,200
3,200
11,700
76,900
4,500
2,900
3,700
7,500
10 , 800
9,400
1,900
33,300
27,600
115
-------
Table A-5 (Continued). SULFUR AND NITROGEN CONTENT OF
CRUDE OILS FROM NATIONS WHICH EXPORT TO THE U.S.
SOUTH AMERICA Sulfur, Nitrogen,
Weight Weight Production,
Field and State Percent Percent bbl/day
Venezuela
Aguasay, Monagas
Bachaquero, Zulia
Boca, Anzoategui
Boscan, Zulia
Cabimas, Zulia
Caico Seco, Anzoategui
Centre del Lago, Zulia
Ceuta, Zulia
Chiinire, Anzoategui
Dacion, Anzoategui
El Roble, Anzoategui
Guara, Anzoategui
Guario, Anzoategui
Inca, Anzoategui
La Ceibita, .Anzoategui
Lago Medio, Zulia
Lagunillas, Zulia
Lama, Zulia
La Paz, Zulia
Leona, Anzoategui
Mapiri, Anzoategui
Mara, Zulia
Mata, Anzoategui
Mene Grande, Zulia
Mercy, Anzoategui
Nipa, Anzoategui
Oficina, Anzoategui
Oritupano, Monagas
Oscurote, Anzoategui
Pilon, Monagas
Pradera, Anzoategui
Quiriquire, Monagas
Ruiz, Guarico
San Joaquin, Anzoategui
Santa Ana, Anzoategui
Santa Rosa, Anzoategui
Sibucara, Zulia
Silvestre, Barinas
Sinco, Barinas
Soto, Anzoategui
Santa Barbara, Monagas
Tacat, Monagas
Taman, Guarico
Temblador, Monagas
Tia Juana, Zulia •
Tucupita, Amacuro
Yopalcs, AnzoateRui
Zaputos, Anzoategui
0.82
2.65
0.89
5.54
1.71
0.13
1.42
1.36
1.07
1.29
0.10
2.95
0.13
—
0.41
1.16
2.15
1.47
1.29
1.38
0.54
1.16
1.09
2.00
2.52
0.38
0.59
1.89
1.19
2.11
0.75
1.33
1.05
0.14
0.42
0.09
0.82
1.17
1.38
0.52
0.88
1.55
0.14
0.83
1.70
1.05
1.15
0.48
—
0.377
0.178
0.593
0.249
—
—
—
0.119
0.274
0.001
0.314
0.003
0.223
0.055
—
0.319
0.203
—
—
0.058
0.116
0.238
—
0.429
—
0.202
—
0.360
0.033
0.252
0.161
0.036
—
0.006
0.074-
0.261
0.284
0.159
0.125
—
0.025
0.338
0.269
0.312
0.275
0.075
14,800
738,900
6,100
68, ,400
82,000
4,200
132,200
63,800
17,100
10,900
1,000
26,900
1 , 100
9,500
14 „ 300
58!P100
940 ,,100
320,000
23,500
11 ,,900
2 ,,800
10,100
55 ,,800
12 ,,200
27,500
29,200
48,100
14 , 500
11,400
23,900
700
22,000
600
2 , 300
7,000
34 , 700
2,000
12,200
28,400
10,000
6,100
3,500
400
5,300
373,000
3,700
15,700
19,300
116
-------
Table A-5 (Continued). SULFUR AND NITROGEN CONTENT OF
CRUDE OILS FROM NATIONS WHICH EXPORT TO THE U.S.
SOUTH AMERICA (Cont'd)
Country and Field
Colombia
Casabe
Colorado
Galan
Infantas
La Cira
Payoa
Rio Zulia
Tibu
Sulfur, Nitrogen,
Weight Weight Production,
Percent Percent bbl/day
1.07
0.25
1.11
0.88
0.96
0.83
0.32
0.71
1,
4,
0.147
7,500
900
,300
,500
17,200
8,200
23,700
12,900
Bolivia
Camiri
0.02
2,800
Chile
Cerro Manatiales
0.05
117
-------
Table A-5 (Continued). SULFUR AND NITROGEN CONTENT OF
CRUDE OILS FROM NATIONS WHICH EXPORT TO THE U.S.
MIDDLE EAST
Country and Field
Saudi Arabia
and Neutral Zone
Abqaiq
Abu Hadriya
Abu Sa'Fah
Berri
Dammam
Fadhili
Ghawar
Khafji
Khursaniya
Khurais
Manifa
Qatif
Safaniya
Wafra
Abu Dhabi
Bu Hasa I
Bu Hasa II
Habshan
Murban-Bab-Bu Hasa
Iran
Agha Jari
Cyrus
Darius
Gach Saran
Haft Kel
Naft-i-Shah
Sassan
Sulfur, Nitrogen,
Weight Weight Production,
Percent Percent bbl/day
03
69
2.61
24
47
25
89
99
2.53
,73
,75
2.55
2.88
3.91
0.74
0.77
0.71
0.62
1.41
3.68
2.44
1.57
1.20
0.76
2.06
0.105'
—
0.232
0.206
—
0.029
0.107
0.159
0.093
0.307
0.338
0.109
0.126
0.145
0.032
0.031
0.026
0.028
0.015
0.300
0.089
0.226
—
—
0.082
892,500
103,700
82,900
155,900
21,600
47,900
2,057,900
— .
74,300
22,300
5,100
95,100
791,400
141,000
_ir rj|
—
—
564,100
848,000
24,000
100,000
882,000
45,000
10,000
137,000
Kuwait
Burgan
Magwa-Ahmadi
Minagish
Raudhatain
Sabriyah
2.58
2.21
2.12
2.13
1.62
2,950,000
Bai Hassan
Kirkuk
Rumaila
1.36
1.93
2.1
0.28
57,000
1,097,000
480,000
118
-------
Table A-5 (Continued). SULFUR AND NITROGEN CONTENT OF
CRUDE OILS FROM NATIONS WHICH EXPORT TO THE U.S.
AFRICA
Country and Field
Sulfur,Nitrogen,
Weight Weight Production,
Percent
Jercent
Export crude mixture delivered to
pipeline terminals.
bbl/dav
Nigeria
Afam
Apara
Bomu
Delta
Ebubu
Imo River
Meji
Meren
Obagi
Oloibiri
Umuechem
Libya
Amal
Beda
Bel Hedan
Brega*
Dahra
Defa
El Dib
Es Sider*
Farrud
Gialo
Hofra
Kctla
Nafoora
Ora
Rakb
Samah
Sarir
Umm Farud
Waha
Zaggut
Zelten
0.09
0.11
0.20
0.18
0.20
0.20
0.15
0.09
0.21
0.26
0.14
0.14
0.45
0.24
0.22
0.41
0.28
1.04
0.42
0.39
0.56
0.32
0.84
0.55
0.23
0.23
0.25
0.16
0.13
0.24
0.30
0.23
0.027
0.050
0.084
0.096
0.113
0.121
0.041
0.048
0.060
0.179
0.076
0.093
0.203
0.120
—
0.106
0.140
0.127
0.160
0.070
0.121
0.082
0.274
0.091
0.119
0.118
0.127
0.079
0.033
0.134
0.188
0.090
8,400
1,000
46,000
69,800
2,600
104,100
19,400
82,700
43,100
4,200
32,800
162,400
7,900
6,600
33,300
165,800
2,200
4,500
359,400
5,200
11,900
238,800
11,300
11,500
57,000
440,000
4,200
129/300
2,700
357,900
119
-------
Table A-5 (Continued). SULFUR AND NITROGEN CONTENT OF
CRUDE OILS FROM NATIONS WHICH EXPORT TO THE U.S.
AFRICA (Cont'd)
Country and Field
Egypt
Asl
El Alamein
El Morgan
Sudr
Sulfur, Nitrogen,
Weight Weight Production,
Percent Percent bbl/day
2.05
0.84
1.67
2.06
0.075
0.183
24,600
260,900
*
Angola (Cabinda)
Tobias
1.51
Algeria
Edjeleh
Gassi Touil
Hassi Messaoud
Ohanet
Rhourde el Baguel
Tin Fouye
Zarzaitine
0.095
0.020
0.15
0.06
0.31
0.13
0.06
0.058
0.008
0.018
0.087
0.061
0.018
18,900
59,000
387,200
8,600
65,900
46,200
44,200
120
-------
Table A-5 (Continued). SULFUR AND NITROGEN CONTENT OF
CRUDE OILS FROM NATIONS WHICH EXPORT TO THE U.S.
ASIA
Country and Field
Indonesia
Bekasap
Duri
Kalimantan
Lirik
Minas
Pematang
Seria
Tarakan
Sulfur, Nitrogen,
Weight Weight Production,
Percent Percent bbl/dav
0.17
0.18
0.07
0.08
0.115
0.10
0.13
0.124
0.337
0.132
0.159
111,100
37,900
4,500
408,700
67,300
1,600*
Source: Magee, E. M., H. J. Hall, and G. M. Varga, Jr.,
Potential Pollutants in Fossil Fuels, PB 225 039,
EPA-R2-73-249, Contract No. 68-02-0629, Linden,
N.J., Esso Research and Engineering Co., 1973.
121
-------
APPENDIX B
PROPERTIES AND CHARACTERISTICS OF PETROLEUM PRODUCTS
-------
Table B-l. GASOLINE REQUIREMENTS
Gasoline
Type A
Type B
TypeC
Minimum percentage*
to be evaporated at
temperature*. °F
ahowa below
10 per cent
W'
140
14(1
167
F'
149
149
137
S«
158
158
187
SO
284
257
284
90
392
356
392
Distil-
lation
resi-
due,
max.
%
2
2
2
Vapor preaaure,
max, Ib*
15.0'
15 0'
15.0'
11.5
11 5
11.5
10'
10'
10-
Research
method
octane
number,*
87 or 96<
87 or 96*
4
Copper
strip
sion,
No. 1
No. 1
No. 1
Gum,
max,
rag per
100 mi
5-
s«
5'
Sul-
fur
,
f
'
• W, F, and 5 denote the seasonal variations indicated in Table *~V
* la all cases the octane number shall be agreed upou between the purchase/1 and the seller.
* The numerical values shown are minimum values currently encountered in service stations. The
lower value pertain* to regular-price gasolines, and the higher value to premium-price gasolines. For
more detailed information on current levels for both Research and Motor octane numbers, as well as for
other characteristics of motor gasoline, reference is made to the series of semiannual reports, issued as
Information Circulars (I.C.) by the U.S. Bureau of Mines and entitled \ational Motor Gasoline Survey.
* The information available does not permit designation of a minimum Research octane number value
for Type C gasoline.
* In the case of gasoline containing added nonvolatile material, the gum requirement shall apply to
the base stock.
f The technical data available do not afford an adequate basis for specifying maximum sulfur content.
At the time of this report, gasolines containing up to 0.25 per cent sulfur (ASTM Methods D 90 and
D 1266) were distributed within the United States.
• The maximum vapor pressure shall be 13.5 Ib in Section 3 and in March, and November in Suction 2,
(see Table B-2).
* Lower maximum vapor pressures may be required for operations at high altitudes or when; abnor-
mally high fuel system temperatures are encountered as in some heavy-duty equipment [(see Section
1 (&))] and in some heavy-duty operations.
1 These values shall be 9.5 ib, max, in Arizona, California, Colorado, Nevada, New Mexico, and Utah.
"Reprinted by permission of the American Society for Testing
and Materials from Petroleum Processing Handbook, copyright
1967."
124
-------
Table B-2. SCHEDULE FOR GEOGRAPHICAL SEASONAL
VARIATIONS IN GASOLINE REQUIREMENTS
Territory
Section 1
Section 2
Month
C
d
3
C
«
"»
W
W
Section 3 W
Section 4
F
'C
a
3
fc*
r«
W
WorF
W or F
ForS
j=
u
S
Wor F
Wor F
F or S
F orS
_
<
F
For?
F or S
S
a
"?-.
F or S
ForS
g
S
®
C
"^
s
S
s
s
"5
-i
S
s
s
s
93
3
<
S
s
s
s
^
J*
3
O3
S or F
S or F
S
S
1
i
F
F
Sor F
Sor F
^
J5
oj
o
Z
F or W
F or W
F
SorF
S
a
a
a
w
F or W
For W
F
Section I
Section 2
Section 3
Section 4
Idaho
Iowa
Maine
Michigan
Minnesota
Montana
New Hampshire
North Dakota
South Dakota
Vermont
Wisconsin
Wyoming
Colorado
Connecticut
Delaware
District of
Columbia
Illinois
Indiana
Kansas
Kentucky
Maryland
Massachusetts
Missouri
Nebraska
Nevada
New Jersey
New York
Ohio
Oregon
Pennsylvania
Rhode Island
Utah
Virginia
Washington
West Virginia
Alabama
Arizona*
Arkansas
California
Georgia
Mississippi
New Mexico"
North Carolina
Oklahoma
South Carolina
Tennessee
Teias*
Arizona*
Florida
Louisiana
New Mexico
Texas6
• North of 33 deg latitude.
• South of 33 deg latitude.
"Reprinted by permission of the American Society for Testing
and Materials from Petroleum Processing Handbook, copyright
1967."
125
-------
Table B-3. AVERAGE PROPERTIES OF JET FUELS SOLD IN U.S.
Property
Gravity, "API .
Distillation temperatures, °f:
Initial boiling point
10 % point ,"
20 % point
50^ point,
90 % pr.int
Final boiling point
Evaporation, % at 400°F
Freezing point °F
Viscosity, kinematic, at — 30°F
Water tolerance, ml
Aniline point °F
Sulfur, wt%:
Total
Aromatic content vol %
Gum, mg/100 ml. steam jet at 450°F:
Net heat of combustion Btu/lb
Type A
43.9
338
369
382
410
464
500
37 9
—54
8.85
0.2
145.8
8.401
0.055
0.0002
14.1
1 2
24.3
0.8
1.8
18,600
Average values
Type B
52 0
137
222
254
315
423
480
82.6
-76
2.94
0.1
132.9
6.911
0.044
0.0006
12.3
0,9
26.4
0.7
1.3
13,703
Type A-l
43.3
333
360
372
401
464
501
48.4
-64
8.04
0.2
139.1
6.058
0.071
0.0004
15.3
1.0
23.2
0.7
1.6
18,571
Source: Blade, 0. C., Survey of Aviation Fuels. Petroleum
Research Center, Bureau of Mines, Bartlesville,
Okla., 1963.
126
-------
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x
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co 55
1. Perfume extraction
2. Carter oil or fat extraction
3. Toluene substitute, lacquer formulas,
x
X X
• x
X X
X X
• X
M • •
• X X
• X X
X
X
• x
irt O O
f~ o r-
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*" 2 *
fast-setting varnishes
4. Seed extraction
5. Rubber cements, tire manufacture. . .
6. Lacquers, -art leather, rotogravure ink,
x
x
X
X
X
x
X
X
X
X
o
1
CS
adhesive tape
x
x
x
S
1
7. R<>siu extraction, shade cioth, rubber dip
goods
x
x
X
X
X
x
x
x
X
X
0
g
8. Brake linings, leather degrcasing, bone
decreasing ; .
x
x
x
f^
1
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rt
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CSO O O tf} O t— C"'
r- -r o o t— 5 >o —
12. Paints and coatings (aircraft), paint re-
movers and solvents
13. Puint shop rinsing and cleaning (aircraft)
14. Floor coverings, wax, polish, wash for
printing plates or rolls
15 Dry denning, ineta! and machinery
cleaning
10. Zylol substitute (in many instances). .
17. Flat finishes, rustproof compounds .
18 Synthetic resin thinner
19. Wood preservatives
"3
A
S
o
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x
a
«!
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IS
• Solvents high in aromatic hydrocarbons
00
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128
-------
Table B-6. AVERAGE OF SELECTED PROPERTIES
OF CENTRAL REGION DIESEL FUELS
Property
Gravity, "API
Viscosity at 100°F:
Saybolt Universal, sec. . .
Sulfur content, wt %
Ramsbottom carbon residue
on 10% residuum, %. . . .
Ash, % . ....
Cetane number
Distillation test:
IBP "F ...
10%, °F
50% °F
90%
EP °F . ...
Class 1,
Type C-B
41.9
1.84
32.1
0 142
148 6
0.057
0 0005
51.1
356
393
440
501
542
Class 2.
Type T-T
37.3
2.54
34.6
0.223
146 2
0.088
0 0009
50.0
380
430
490
557
600
Class 3,
Type R-R
34.8
2.74
35.2
0.287
140 2
0.117
0 0010
47.0
388
440
502
574
618
Class 4,
Type S-.M
34.0
2.79
35 4
0.543
139 3
0.163
0 . 0023
46.7
397
448
509
582
622
•Central region: Minnesota, Iowa, Wisconsin, Illinois, Indiana, Missouri, Kansas;
parts of Oklahoma, Michigan, Kentucky. Arkansas, Texas, Nebraska, and the Dakotas.
Source: Blade, 0. C., Diesel Fuel Oils. Bureau of Mines Petroleum
Experiment Station, Bartlesville, Okla., 1966.
129
-------
Table B-7. CHARACTERISTICS OF THREE GRADES
OF UNITED STATES FUEL OIL
Property
Gravity, °API
Viscosity at 100°F, cs. . .
Sulfur, wt %
Ramsbottoro carbon residue, wt %. . . .
Distillation, °F:
Initial boiling point. .
10% point
50 % point
Grade 1
42 6
1 79
0 071
0.052
349
390
437
533
Grade 2
34 9
2 61
0 249
O.U6
370
432
499
629
Grade 4
21 2
15 41
0 77
3.30
422
496
674
754
Source: Blade, 0. C., Burner Fuel Oils, Bureau
of Mines, Bartlesville, Okla., 1960.
Table B-8. CHARACTERISTICS OF RESIDUAL HEATING OILS
Gravity, "API ... .
Viscosity:
Kinematic at 100°
Furol at 122°F se
Sulfur content %
Ash %
Property
F cs
residue on 100% sample, % ...
vol % . .
Grade 5
17.1
60.2
25.8
1.07
6.7
0.035
0.16
Grade 6
12.3
170.2
1.33
10.7
0.41
0.15
Source: Blade, 0. C., Burner Fuel Oils, Bureau
of Mines, Bartlesville, Okla., 1962.
130
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Table B-12. COMPARISON OF WAX TYPES PRODUCED
IN THE UNITED STATES
Wax
Paraffin
Motor oil
Tank bottom
Charac-
teristic
Brittle
Brittle
Flexible
Hard
No. of
carbon
atoms
18-56
26-42
36-70
40-70
Melting
point,
•F
122-140
145-170
145-175
180-200
Viscosity
at 210°F,
S3U
40
50
65-100
Crystals
Plates
Needles
Small needles
From Petroleum Processinc
Davidson, Copyright ©19
of McGraw-Hill Book Company.
Handbook edited by W. F. Bland and R. L.
7 by McGraw-Hill, Inc. Used by permission
134
-------
Table B-13. SPECIFICATIONS FOR ASPHALT CEMENT
OF THE ASPHALT INSTITUTE
Characteristics
Penetration, 77°F, 100 g.,
5 sec
Viscosity at 275°F:
Say bolt Furol SSF
Flash point (Cleveland
open cup), °F
Thin-film oven test.
Penetration after test,
77°F, 100 g., 5 sec,
% of original.. . .
Ductility:
At 77°F cms
At 60°F, cms
Solubility in carbon tetra-
chloride, %
General requirements
AASHO*
Test
Method
T49
T48
T 179
T49
T51
T44f
ASTM
Test
Method
D5
E 102
D 445
D 92
D 5
D113
D4t
Grades
Indus-
trial and
special
40-50
120 +
240 +
450 +
52 +
100 +
99 5 +
Paving
60-70
100 +
200 +
450 +
50 +
100 +
99 5 +
85-100
85 +
170 +
450 +
45 +
100 +
99.5 +
120-150
70 +
140 +
425 +
42 +
60 +
99.5 +
200-300
50 +
100 +
350 +
37 +
60 +
99.5 +
The asphalt shall be prepared by the refin-
ing of petroleum. It shall be uniform in
character and shall not foam when heated
to 350°F
* American Association of State Highway Officials.
t Except that carbon tetrachloride is used instead of carbon disulHde as solvent, Method
No. 1 in AASHO Method T 44 or Procedure No. 1 in ASTM Method D 4.
From Petroleum Processing Handbook edited by W. F. Bland and R L
Davidson, Copyright © 1967 by McGraw-Hill, Inc. Used by permission
of McGraw-Hill Book Company.
135
-------
Table B-14. PROPERTIES OF PETROLEUM COKES
Moisture, wt %
Volatile combustible matter,
wt % . .
Ash, wt
Sulfur, wt %
Bulk density, Ib per cu ft
True or real density, g per ml . .
Btu per Ib as rec'd
Hydrogen, wt %
Carbon, wt %
Early pet. cokes,
1930-1935
Cracking
still
0.15-3.3
8-18
0-1,6
0.2 -4,2
56-
15,300-
16,400
Coking
still
0.3-1.8
2-13
0.5--!. 2
0 5-1.2
-69
14,500-
15,500
Oven
cokes
0.3-2
0.6-7.4
0.2-1.8
0 8-1.5
14,400-
14,700
Delayed
process
cokes
Nil-0.5
8-18
0.5-1.6
0.5-4.2
1.28-1.42
Con-
tinuous
or fluid
cokes
3.7-5.3
0.1-2.8
1.4-7.0
55-65
1.5-1 6
14,000
1.6-2.1
88.3-92.5
From Petroleum Refinery Engineering, 4th ed., by W. L. Nelson,
Copyright © 1958 by the McGraw-Hill Book Company, Inc. Used
by permission of McGraw-Hill Book Company.
136
-------
APPENDIX C
COMPANIES COMPRISING THE INDUSTRY
137
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APPENDIX D
HAZARDOUS CHEMICALS POTENTIALLY EMITTED
FROM PROCESS MODULES
145
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Table D-l. HAZARDOUS CHEMICALS POTENTIALLY
EMITTED FROM PROCESS MODULES
Chemical
Maleic Acid
Benzole Acid
Cresy'iic Acid
Acetic Acid
Formic Acid
Sulfuric Acid
Diethylamine
Methyl ethyl amine
Aromatic Amines
Ammonia
Chlorides
Sulfates
Chromates
Ketones
Aldehydes
Formaldehyde
Acetaldehyde
Carbon Monoxide
Sulfur Oxides
Nitrogen Oxides
Pyridines
Pyrroles
Quinolines
Indoles
Furans
Benzene
Toluene
Xylene
Phenol
Dimethyl phenol
Cresols
Xylenols
Thiophenols
Carbazoles
Anthracenes
Benzo(a)pyrene
Pyrene
8enzo(e)pyrene
Perylene
Benzo(ghi)pe"ylene
Coronene
Phenanthrene
Fluoranthrene
Metallooorphrins
Nickel Carbonyl
Cobalt Carbonyl
Tetraethyl Lead
Sulfides
Sulfates
Sulfonates
Sulfonas
Hercaptans
Thiophenes
Hydrogen Sulfide
Methylmercaptan
Carbon Oilsulfide
Carbonyl Sulfide
Thiosulfide
Dibenzothiophene
Alkyl Sulfide
Vanadium
Nickel
Lead
Zinc
Cobalt
Molybdenum
Copper
Strontium
Barium
Sulfur Particulates
Catalyst Fines
Coke Fines
Cyani des
Potential Emission Source
Process Module Numbers
1,2,3,4,7,16,17,13.19,20,22,23,24.25,26,27,23,30
1,2,30
3,7,16,17,18,19,20,22.23,24,25,26,27,28,30
4,30
4,30
27,30
4,5,30
4,5,30
18,19,26,30
3,5,7,16,17,18,19,20,22,23,24,25,26,27,30
1,2.30
27,30
30
1,2,3,7,16,17,18,19,20,22,23,24,25,26,27,30
1,2,3,7,16,17.18,19,20,22,23,24,25,26,27,30,32
18,19,26
18.19,26
5,9,10,12,13,16,17,18,19,20,22,24,25,26,27,32
5,10,13,16,17,18,19,20,22,24,25,25,27,32
31,32
1,2,3,7,16,17,18,19,20,22,23,24,25,26,27,28,30
1,2,3,7,16,17,18,19,20,22,23,24,25,26,27,23,30
28,30
18,19,26,30
23,27,30
1,2,3,7,10,13.14,16,17,18,19,20,21,22,23,24,25,26,27,28,29,30
1,2,3,7,10,13,14,16,17,18,19,20,21,22,23,24,25,26,27,28,29,30
1,2,3,7,10,13,14,16,17,18,19,20,21,22,23,24,25,26,27,23,29,30
1,2,7,18,19,25,25,28,30
1,2,27
1,2,7,18,19,25,27,28,30
7,18,19,25,26.27,28,30
26,30
1,2,28,30
1,2,18,19,26,28,30
13,19,26,28,32
18,19,26,30
18,19,26
18,19,26,30
18,19
18,19,25
18,19,26
18,19,26
1,2,30
10,16,17,20,22,24,27
10,16,17,20,22,24,27
14,21
3,7,15,16,17,18.19,20,22,23,24,25,26,27.28,29,30
30
3,7,16,17,18,19,20,22,23,24,25,26,27,28,29,30
30
1,10,15,26,30
1,2,3,7,16,17,18,19,20,22,23,25,25,26.27,28.30
1,3,5,7,10,13,15,16,17,13,19,20,22,23,24,25,26,27
3,4,7,16,17,13,19,20,22,23,24,25,26,27
4,5,10,16,17,18,19,20,22,24,27
4,5,10,13,16,17,18,19,20,22,24,27
4
28
28
1,2,10,16,17,18,19,20,22,24,25,26,27,28,30,32
1,2,10,16,17,18,19,20,22,24,25,26,27,28,30,32
1,2,32
1,2,18,19,25,26,23,30
10,16,17,20,22,24,27
10,16,17,20,22,24,27
18,19,25,26,23,30,23
23
28
5
9,10,12,16,17,18,19,20,22,24,27
10,16,17,20,22,24,25,26,27,32
4,5,13,19,26,30
Source: Cavanaugh, G., et al, Potfntidlly Haz^rdau": Emissions From the Extraction
and Processing of Coal and Oil, PA-65d72-"75-038, Austin, Texas, Radian
Corporation, and Columbus, Onio, Battelle - Columbus Labs. (April 1975).
146
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