EPA-650/2-73-017
August 1973 ENVIRONMENTAL PROTECTION TECHNOLOGY SERIES
ui
O
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EPA-650/2-7 3-017
ATMOSPHERIC EMISSIONS
FROM THE
PETROLEUM REFINING INDUSTRY
by
L. L. Luster
Control Svstems Laboratory
ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
National Environmental Research Center
Research Triangle Park. North Carolina 27711
August 1973
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This report has been reviewed by the Environmental Protection Agency and approved
for publication. Approval does nor signify that the contents necessarily reflect the
views and policies of the Agency, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
Publication No. EPA-650/2-73-017
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CONTENTS
Section Page
LIST OF FIGURES vi
LIST OF TABLES vi
ABSTRACT vii
INTRODUCTION 1
PETROLEUM REFINERIES 7
OPERATION OF REFINERIES 11
Separation 11
Conversion 14
Catalytic Cracking 14
Catalytic Naphtha Reforming 18
Light Hydrocarbon Processing 18
Isomedzation 19
Coking 20
Hydrocracking 22
Sulfur Recovery Unit ..; 23
Desulfurization of Fuel Oils 25
Treating 26
Blending 27
FACTORS CONTRIBUTING TO EMISSION OF POLLUTANTS 29
Emission Control Equipment and Methods in Use 29
111
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Sulfur Content of Raw Materials 29
Refining Operations 30
Housekeeping and Maintenance Practices 30
Major Sources of Pollutant Emissions 31
CONTROL METHODS 33
Available Methods 33
Hydrocarbons 33
Particulates 33
Carbon Monoxide 34
Smoke 34
Odors 34
Control Technology Needed 35
Sulfur Dioxide 35
Nitrogen Oxides 36
Particulates 36
Odors 36
Interim Control of Emissions 36
Sulfur Dioxide 36
Nitrogen Oxides 37
Particulates .37
Odors 38
Proposed Guidelines for Refinery Emissions 38
Comments on Emission Controls 38
REFERENCES 39
APPENDIX A: GLOSSARY 43
IV
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APPENDIX B: GUIDELINES PROPOSED BY THE ENVIRONMENTAL
PROTECTION AGENCY FOR REFINERY EMISSIONS 49
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LIST OF FIGURES
Figure Page
1 Processing Plan for Complete Modern Refinery 8
2 Typical Crude-oil Separation Unit
Employing Atmospheric and Vacuum Distillation 9
3 Typical Moving-bed (Thermofor)
Catalytic Cracking Unit (TCC) 15
4 Fluid Catalytic Cracking Unit (FCC) 16
5 Flow Diagram of Modern Fluid Coking Unit 21
6 Growth of Use of Hydrocracking 22
7 Recovery of Sulfur from Hydrogen Sulfide 25
LIST OF TABLES
Table Page
1 Crude-oil Charge for 1968,1969, and 1970 2
2 Crude-oil Charge for Various Sizes of Refineries (1970) 2
3 Crude-oil Charge to Refineries in Concentrated Areas (1970) 3
4 Estimated Emissions from 262 U.S. Refineries (1969) 4
5 Average Composition of Crude-oil and
Typical Composition of Overhead Stream 12
6 Pollutants from Crude-oil Separation Units 13
7 Emission Factors for Pollutants from Catalyst Regeneration 17
8 Major Sources of Pollutant Emissions 31
VI
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ABSTRACT
As petroleum refining has developed in recent years into one of the leading
industries of the nation, with a growth rate of 4 to 8 percent annually, air
pollution problems have increased, though the corporations involved have, as a
result of research, produced control methods for some of the pollutants. The
principal emissions from refining operations are sulfur oxides, nitrogen oxides,
hydrocarbons, particulates, carbon monoxide, and odors. The estimated
emissions of these pollutants (except for odor per se) at the 262 refineries
operating in the United States in 1969 totaled 7.04 million tons, with
substantial control exercised only in the case of hydrocarbons, particulates,
and carbon monoxide.
Although refineries vary considerably in capacity, type of crude oil
processed, and complexity of operations, petroleum refining generally
encompasses: (1) separation processes (atmospheric distillation and vacuum
distillation); (2) conversion processes, such as catalytic cracking, light
hydrocarbon processing, isomerization and coking; (3) treating; and (4)
blending. The bulk of air pollution emissions from a refinery is from process
equipment such as the catalytic cracking regenerators, storage tanks, baro-
metric condensers, waste oil separators, and cooling towers, and from such
miscellaneous sources as loading facilities, sampling activities, spillage, and
leaks. Factors contributing to the emission of pollutants include the sulfur
content of raw materials, emission control equipment and methods in use,
deficiencies in "housekeeping" and maintenance practices, and operational
considerations such as the variety of products manufactured and types of fuels
used.
Although control methods have been developed for some of the principal
pollutants from refining processes, the industry still has significant air pollution
problems because some of the pollutants emitted by refineries contribute to
photochemical smogs and have harmful effects on the public in congested
industrial areas. Substantial progress has been made in controlling hydro-
carbons, with the cost often offset by the saving of valuable products that
otherwise escape into the atmosphere. Particulates also can be controlled by
means such as electrostatic precipitators, but the necessary devices and
techniques are not being used in all refineries. In addition, the technology
exists for controlling carbon monoxide emissions and for significantly reducing
smoke and odors.
There is a definite need for methods by which to remove sulfur and nitrogen
oxides from refinery flue gases, as well as for better techniques for controlling
refinery odors. In 1968 through 1970, refineries released about 5.5 to 7.0
Vll
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percent of the national total of sulfur dioxide emitted annually into the
atmosphere from all sources. Though desulfurization of petroleum products
has increased in the industry in recent years, a reevaluation of direct crude
desulfurization may now be in order. It is anticipated that reduction of
nitrogen oxides from combustion processes will result from some combination
of combustion modification techniques. The technology for controlling all
pollutants from refineries has been instrumental in reducing odors, but
altogether effective means remain to be employed.
In accordance with guidelines proposed by the U.S. Environmental
Protection Agency for emissions from refinery operations, oil companies,
working in conjunction with trade organizations and equipment manufacturers,
have employed interim controls in many cases and have developed processes
and devices for at least reducing all pollutants from refineries. A major
problem, however, is the cost of the needed equipment, and the industry still
has installed only about 50 percent of the control equipment that is available.
Key Words: sulfur oxides, nitrogen oxides, particulates, hydrocarbons, odor
emissions, emission factors for petroleum refineries, emission control, pol-
lution, pollution control techniques, atmospheric pollution, fluid catalytic
cracking, refining, crude oil.
vm
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ATMOSPHERIC EMISSIONS
FROM THE
PETROLEUM REFINING INDUSTRY
INTRODUCTION
This report summarizes the air pollution problems of the petroleum refining
industry, with emphasis on gaseous emissions. A general outline of the refining
processes, sources and types of pollutant emissions, and present and needed
control methods is provided.
One of the leading industries of the nation, petroleum refining is growing at
an estimated 4 to 8 percent annually. Refineries have expanded from simple
"batch" stills to the large complex plants required today to supply products
needed for the general public and to produce feedstocks for the increasing
needs of the closely related petrochemical industry. The technical break-
throughs necessary for the development of present-day petroleum operations
came largely as a result of the need, in the early 1940's, for synthetic rubber,
high octane gasoline, and feedstocks for other related industries.
Petroleum products supply a large percentage of the world's energy, and the
industry estimates that the demand is increasing yearly. As a result, the refiner
must constantly seek new processes, develop these processes, improve the
efficiency of operations, and produce a wider variety of products, yet remain
competitive. With the development of new processes, existing ones could
shortly become obsolete. Table 1 shows the industry's growth in crude-oil
charge rate for 3 recent years. The capacities of the refineries (Table 2)1 range
from less than 1000 to 434,000 barrels per calendar day. The smaller refineries,
built for special markets such as fuel oils, do not contribute appreciably to air
pollution in congested areas because of the locations of these facilities and
their limited crude-oil charging rates. Geographically, approximately 80
percent of the crude-oil charge processed is concentrated in the five regions
shown in Table 3.'
Crude oil, the charge stock for a refinery, is a mixture of many different
hydrocarbons varying in chemical composition and physical properties.
Physically, crude oil ranges from a thick tar-like material to a light colorless
liquid. Chemically, the crude oil can be saturated hydrocarbons having a
formula of CnH2n+2> naphthene having a ring structure of CnH2rn or
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Table 1. CRUDE-OIL CHARGE FOR 1968,1969, AND 1970
Year
1968
1969
1970
Number of
refineries
263
262
253
Crude-oil charge,
10* bbl/calendardaya
11.5
12.0
12.7
aBarrels per day or barrels per calendar day is an expression for
the operating capacity of a refinery, generally with an allowance
for downtime. In the petroleum industry, a barrel is equivalent to
42 U.S. standard gallons.
Table 2. CRUDE-OIL CHARGE
FOR VARIOUS SIZES OF REFINERIES (1970)
Crude-oil charge,
bbl/calendar day
<1,000
1,000 to 2,000
2,000 to 10,000
10,000 to 20,000
20,000 to 50,000
50,000 to 100,000
100,000 to 200,000
200,000 to 300,000
300,000 to 400,000
MOO.OOO
Total 12,700,000
Number of
refineries'
5
14
67
32
59
40
22
7
6
1
253
PETROLEUM REFINING EMISSIONS
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Table 3. CRUDE-OIL CHARGE TO REFINERIES
IN CONCENTRATED AREAS (1970)
Region
Crude-oil charge,
106 bbl/calendarday'
California-West Coast
Texas, La., Miss., Ala. - Gulf Coast
Chicago, St. Louis, Kansas
Cleveland, Toledo, Detroit, Buffalo
Philadelphia, New Jersey, New York - East Coast
Total
2.0
4.3
1.9
0.7
1.3
10.2
aromatics having a benzene ring structure of CgHe-8 Most crude oils are a
mixture of these compounds. Distillation separates the crude oil into a number
of predetermined fractions, depending on the desired products resulting from
this operation and feedstocks desired for processing in downstream units that
are used to crack, reform, treat, redistill, air-blow and, if necessary, blend the
crude distillation products into finished products.
Though, as noted, the constituents of crude oil are carbon and hydrogen,
impurities such as sulfur, sodium chloride, oxygen, nitrogen, and various metals
also are present and cause operational and pollution problems in refining.
Before the crude oil is processed, some of the impurities, such as salts (chiefly
sodium chloride), are removed. Salt is separated out by washing the crude with
water and breaking down the resulting emulsion, either chemically or
electrically. The salty water is drawn from a settling drum to the refinery
sewage system. Then, the desalted crude oil is ready for further processing in a
crude-oil separation unit. Removing the salt reduces both the corrosion of
equipment and plugging or fouling of heat exchangers, thus decreasing
equipment expenses. Removal of the salt and other foreign materials, referred
to as "desalting," increases the on-stream hours of the crude-oil separation unit
and, thus, the throughput of a refinery.
Estimated emissions from the 262 operating refineries in the United States
in 1964 are given in Table,4.4 Sulfur, one of the impurities in the crude oil, is a
principal contributor to pollution problems, and its removal from the crude oil
is expensive, though research directed toward the development of effective,
inexpensive processes is progressing. McAfee et a/.5 reported in 1955 that
hydrodesulfurization of West Texas crude oil for a refinery with a capacity of
20,000 to 25,000 barrels per calendar day was practical. One of the initial
Introduction
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Table 4. ESTIMATED EMISSIONS FROM 262 U. S. REFINERIES (1969)4
Pollutant
Sulfur oxides
Nitrogen oxides
Hydrocarbons
Particulates
Carbon monoxide
Emission, 1000 tons
2200
61
2300
55
2420
Control, %
0
0
50
50
75
problems in this pilot plant study was solved by developing a rugged and stable
catalyst that can be regenerated periodically and has a unique stability toward
heavy-metal poisoning.5 Dcsulfurization of petroleum products has grown in
the industry in recent years. At first, gasolines were desulfurized, then
low-sulfur middle distillates or heating oils; now, in response to the demand for
low-sulfur residual fuel oils, what appears to be a crash desulfurization program
is under way. These developments suggest that a revaluation of direct
crude-oil desulfurization may be in order. Recently, Chevron Research
Company announced that it has developed a process6 for removing sulfur
directly from Mideast crude oil (having low metal content), and comparable
processes have been developed by other companies.
The average sulfur content of domestic crude oil is about 0.75 percent,
varying from 0.20 to 3.70 percent. When charged to the crude-oil separation
units with the higher sulfur imported crude oil, the average sulfur content of
the crude oil is slightly above 1 percent. These figures vary from region to
region and, in many instances, from refinery to refinery. Results7 obtained
from several laree oil corporations indicate that, during refinery operations,
approximately 50 tons of sulfur dioxide (862) are released per 100,000 barrels
of crude oil processed; thus, oil refining operations released about 2,100,000
tons of SO2 in 1968, 2,200,000 tons in 1969, and 2,300,000 tons in 1970.
These quantities represent about 5.5 to 7.0 percent of the national total of
SC>2 emitted annually into the atmosphere from all sources.4 The emission of
SC>2 can be decreased if natural gas rather than fuel oil is used to fire process
heaters and boilers.
Other air pollutants from refineries are nitrogen oxides (NOX), partic-
ipates, malodorous compounds, carbon monoxide (CO), smoke, and hydro-
carbons. Even though refineries are not the largest industrial emitters of air
pollution on a nationwide basis, they do add to local pollution problems
because they emit pollutants that can be hazardous if not controlled. These
pollutants contribute to the formation of photochemical smog and have
harmful effects on public health and property in congested industrial regions,
as well as on vegetation. This regional aspect of the problem is particularly
PETROLEUM REFINING EMISSIONS
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important in relation to the control of a refinery's emissions of S(>2, NOX and,
to some extent, odors and particulates. Technology has been developed for
effectively controlling emissions of carbon monoxide, hydrocarbons, partic-
ulates, and smoke, but improved devices and techniques are needed for
particulates and odors.
Introduction
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PETROLEUM REFINERIES
The modern petroleum refinery, in which crude oil is converted into usable
products, is a well-planned, integrated unit of many processes that encompass
the latest technology in the field. The larger refineries may be designed to
manufacture about 2500 different products. Feedstocks are also produced for
other industries such as the synthetic rubber, agriculture, drug, and steel
industries, and the closely related petrochemical industry.
Refineries differ in their processing schemes, depending on their capacity,
type of crude oil processed, complexity of the processes involved, product
distribution, and product requirements. The following processes are generally
used in petroleum refining:
1. Separation.
a. Atmospheric distillation.
b. Vacuum distillation.
2. Conversion.
a. Catalytic cracking.
b. Catalytic naphtha reforming.
c. Light hydrocarbon processing.
(1). Polymerization.
(2). Alkylation.
d. Isomerization.
e. Coking.
(1). Delayed.
(2). Fluid.
f. Hydrocracking.
g. Sulfur recovery.
h. Desulfurization of fuel oils.
3. Treating.
4. Blending.
Figure 1, a flow chart for a complete refinery, shows most of these processes;
Figure 2 illustrates a crude-oil separation unit in more detail. As noted in each
chart, the initial processing step consists of charging the heated crude to the
crude-oil separation unit. Predetermined products are withdrawn from this unit
and are either charged to other processing units (Figure 1) or transferred to
storage tanks for future processing. The process equipment consists mainly of
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00
DRY GAS
5
d
pa
en
LIGHT HYOROCRACKED GASOLINE
HYDROGEN SULFIOE
CRACKED GAS
REDUCED
CRUDE
OIL
CRUDE-OIL
SEPARATION
UNIT
OIL '-*
1
1
i
UKAUIUN
UNIT
L.
LUCE DISTILLATES
1
I RESIDUUM
-I'
COKtK CASOLINL
h M
> ^
ASPHALT
LUBE
PROCESSING
STILL
OLEFINS-TO
CHEWtCAL
KEROSENE
LIGHT FUEL
OIL
PIE.SEL
FUEL
SULFUR
LUBES
WAXES
GREASES
.HEAVY FUEL
OIL
-ASPHALT
-COKE
Figure 1. Processing plan for complete modern refinery.
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EXHAUST
STEAM AND
UNCONOENSED
HYDROCARBONS
GAS TO
REFINERY
FUEL GAS
SYSTEM OR
GAS TREATING
UNITS
BAROMETRIC WATER STEAM
CONDENSER
VACUUM
DISTIL-
LATION
TOWER
•GASOLINE
^-KEROSENE
LIGHT FUEL
OIL
GAS OIL TO
CATALYTIC
CRACKING
UNIT
STEAM
EJECTOR
LUBE STOCK
RESIDUUM
TO COKER
ASPHALT
PLANT
Figure 2. Typical crude-oil separation unit employing
atmospheric and vacuum distillation.
Petroleum Refineries
-------
fired heaters, heat exchangers, coolers, pumps, distillation towers (fraction-
ators), and absorption towers. Fuel oil, refinery fuel gas, or purchased natural
gas are used to generate steam and provide heat for the refinery. Electric power
is normally purchased, if available. Products are cooled by water (with a
once-through system or from cooling towers); by air fans; or, sometimes, by
both. The process equipment is protected against overpressure by safety valves
set for release at a predesignated pressure level to the atmosphere, to a flare, or
to a blowdown system, where the heavier hydrocarbons are recovered and
reprocessed. Oil-coataminated water and oil drained from processing equip-
ment and storage tanks are carried to a water sewer separator, where the oil is
recovered and reprocessed.
In addition to these processing units, other units and equipment may be
included:
1. Preparatory units for production of petrochemical feedstocks and
feedstocks for other industries.
2. Off-site facilities.
a. Storage tanks.
b. Utilities, such as boiler houses, power plants, water treating units, and
compressed air and cooling water systems.
c. Loading and shipping facilities for products shipped in tank cars,
transport trucks, railcars, and (if on a waterway) barges or tankers.
d. Incinerators for waste disposal.
e. Flares.
f. Waste oil treatment or recovery plants.
All of the facilities are potential sources of emissions. These units must be
effectively coordinated for the successful operation of the refinery as a whole.
10 PETROLEUM REFINING EMISSIONS
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OPERATION OF REFINERIES
The somewhat complex processes involved in petroleum refining can be
divided into four steps: separation, conversion, treating, and blending. The
function and operation of each phase will be briefly described below.
SEPARATION
The primary separation step in a refinery is simple fractionation or
distillation of the crude oil. Figure 2 is a simplified flow diagram of a complete,
typical crude-oil separation unit, employing atmospheric and vacuum distil-
lation. Such units vary in size of crude-oil charge capacity from 1000 to over
100,000 barrels per stream day. They consist of fired heaters, fractionating
towers, heat exchangers, coolers, drums, pumps, and instruments. For
economical operation, modern automatic control instruments are now being
installed in processing units.
Desalted crude oil is pumped through a pipe tube heater where, depending
on the type of crude, it is heated to a predetermined temperature (usually 690
to 710 °F); higher temperatures may cause some cracking. From the heater,
the hot crude oil enters the atmospheric tower. The tower is equipped with a
calculated number of fractionating trays of various types; desired products
determine the number, spacing, and types used. In the tower, the crude oil is
separated into specified boiling range products by controlled fractionation
under atmospheric pressure.
As shown in Figure 1, the typical crude-oil separation unit is principally a
preparatory unit for feedstocks to such other processes as catalytic reforming,
catalytic cracking, hydrogen treating, hydrocracking, vacuum distillation,
coking, alkylation, polymerization, sulfur production, asphalt production,
treating, chilling, filtering, and gasoline blending. This line of flow shows that
the present-day refinery must be a well-planned, integrated facility, employing
the latest petroleum refining technology in order to maintain efficient and
economical operations.
The first product from the crude-oil separation unit shown in Figure 2 is a
light gasoline stream plus gaseous hydrocarbons that together represent a total
of about 26.5 percent of the crude. This product is commonly called the
"overhead cut" or "stream." The yield and composition of this product
depend chiefly on the type of crude. Some petroleum companies inject light
hydrocarbons (propane and heavier) into the crude-oil stream at the pro-
duction source as a means of transporting them to the refinery for processing
11
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into suitable products. This procedure has a direct effect, of course, on yields
of light hydrocarbons. Typical yield and composition of this overhead stream,
without injection of the light hydrocarbons, are based on the average crude-oil
composition shown in Table 5.
Table 5. AVERAGE COMPOSITION OF CRUDE OIL AND
TYPICAL COMPOSITION OF OVERHEAD STREAM8
Product
Hydrogen sulfide
Methane
Ethane
Propane
Butane
Gasoline
Total-
Percent by volume
Product
0.20
7.00
2.30
3.00
2.80
84.70
100.00
Crude oil
0.05
1.86
0.61
0.80
0.74
22.45
26.51
aWithout injection of light hydrocarbons.
The hydrogen sulfide is recovered in an amine unit for charge to the sulfur
plants; propane is recovered and sold as liquid petroleum gas; butane is
recovered and blended into gasoline; and the gasoline is either blended into the
refinery gasoline pool or charged to the catalytic naphtha reformer for octane
upgrading.
Kerosene and light fuel oil (middle distillate), representing about 22 percent
of the crude oil, are the next two streams withdrawn from the crude-oil
separation unit. These streams are normally hydrogen-treated for sulfur
removal to make them saleable products. After withdrawing the two distillate
fuel streams, a maximum gas oil stream is taken for feedstocks to the catalytic
cracking unit and/or a hydrocracker.
As shown in Figure 2, the separation process is completed when the
bottoms from the atmospheric tower are transferred to the vacuum distillation
tower and heated under vacuum to reduce them further to residuum ("flux
bottoms"), representing about 8 percent of the typical domestic crude-oil
charge. From this tower, a gas oil is withdrawn and used as feedstock to the
catalytic cracking unit or to a hydrocracker. If a lube stock is required, it is
12
PETROLEUM REFINING EMISSIONS
-------
also withdrawn as a sidestream; if the lube stock is not required, the entire
vacuum tower distillate production is charged to the catalytic cracking
operations. The flux bottoms may be charged to the coker or asphalt plant, or
may be blended into residual fuel oils.
The barometric condenser on the vacuum unit is the principal source of
pollutants consisting of noncondensables, light hydrocarbons, and odors.
Equipment in new units injects these light hydrocarbons into the process
heater for burning and controls odors by using tubular condensers.
Table 6 shows that the crude-oil separation unit (employed at the separation
stage of petroleum refining) can be a potential source of pollution,9
particularly if fuel oil is used for fuel in the processing. Control technology for
some of these pollutants is yet to be developed. Mechanical improvements have
been made to increase the efficiency of the furnaces and burners used in the
combustion process, thus reducing the emission factors for most of the
pollutants except sulfur oxides. Currently, the only practical method of
Table 6. POLLUTANTS FROM CRUDE-OIL SEPARATION UNITS
Source
Combustion
Process heaters
Boilers
Barometric
condensers
Miscellaneous:
Sampling,
spillage, leaks,
drains, and
hlowfiown
Pollutant
Sulfur oxides
Hydrocarbons
Particulates
Carbon monoxide
Nitrogen oxides
Hydrocarbons
Odors
Hydrocarbons
Emission factor
lb/1000 ft3
Neg.
0.03
0.02
0.02
lb/1000 bbl oil
6400 x %S
140
800
2
2900
130 lb/1000 bbl
charge to vacuum
distillation tower
Odors caused by
noncondensables and
light hydrocarbons
150 lb/1000 bbl crudes
Operation of Refineries
13
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controlling the emission of sulfur dioxide is the use of low-sulfur fuel. Table 6
shows that the emission factor of particulates from the combustion process is
about 800 pounds per 1000 barrels of fuel oil burned; for a large refinery, the
tonnage would be large. Using electrostatic precipitators on the many process
heaters would not be practical, but it would be on boilers if an appreciable
quantity of residual fuel oil were burned.
"Good housekeeping," employee training, improved maintenance, use of
efficient control equipment, and use of efficient process operations contribute
to controlling the emissions of smoke, odors, hydrocarbons, and carbon
monoxide; but, as stated, the technology for removing sulfur and nitrogen
oxides from flue gases has not been used commercially to date. Some processes
are, however, in the development stage.
CONVERSION
When the demand for gasoline began to exceed that for other petroleum
products, refiners were faced with the problem of producing an excessive
quantity of fuel oils or developing a process to convert heavier hydrocarbons
into low-boiling hydrocarbons within the gasoline range. First, they developed
thermal cracking, then, the catalytic process, which replaced the thermal
process. The catalytic unit is more economical and gives a higher yield, a higher
octane product, and a more desirable feedstock for other processes (especially
alkylation).
Catalytic Cracking
Catalytic cracking is the most important and essential process in the
refinery, so that the cracking unit is the heart of the refinery complex. To
supply more gasoline with a higher octane, refiners are increasing their catalytic
cracking capacity: the daily charge rate has increased from 5.80 million barrels
per day in 1968 to 5.97 million barrels per day in 1969, a 0.7-million-
barrel-per-day increase in 2 years. The gas oils from the crude-oil separation
unit and the vacuum unit, representing about 45 percent of the crude, are
charged to the catalytic unit. The method used for transferring the catalyst
determines the type or class of the catalytic unit:
1. Fixed-bed (Houdry Process) (Obsolete). A number"of reaction chambers
are used in a batch-type operation. When the catalyst must be
regenerated, the reactor is bypassed, the coke and other impurities are
burned off, and the catalyst is reused.
2. Once-through Process. The catalyst is passed through the cracking
furnace with the oil and is removed by a filter. This process has never
been used commercially to any extent.
14 PETROLEUM REFINING EMISSIONS
-------
3. Thermofor Catalytic Cracking Units (TCC) (Being phased out). These
units (figure 3) are classified as a moving-bed system. The catalyst
leaving the regenerator is lifted to the surge hopper and returned by
gravity to the reaction and regeneration areas.
GAS OIL
CHARGE
VENT]
S
REACTOR)K
STEAM WASH —*•
SPENT CATALYST!
REGENERATOR
AIR
SURGE
SEPARATOR
PRODUCTS
FLUE
GAS
REGENERATED
CATALYST
AIRLIFT OR
ELEVATOR
WET GAS TO POLY OR
•ALKYLATION UNITS
-CRACKED GASOLINE
•LIGHT FUEL OIL
•GAS OIL RECYCLE
-HEAVY FUEL OIL
Figure 3. Typical moving-bed (Thermofor) catalytic cracking
unit (TCC).
4. Fluid Catalytic Cracking Units (FCC). These units (Figure 4) are classified
as a fluidized system. The principal equipment in these units are reactor,
regenerator, catalyst stripper, slide valves, fractionator (recovery section),
air blowers, catalyst recovery system, waste heater boilers, and instru-
mentation.
The operation of these catalytic units is relatively simple. The finely
powdered hot catalyst from the regenerator is transferred to the reactor
(cracking zone) with the gas oil charge, as shown in Figure 4. Cracking begins
in the transfer line and is completed in the reactor, with the cracked
hydrocarbon products flowing into the fractionating tower where they are
separated into end products or feedstocks for other processes. During the
cracking process, coke is deposited on the catalyst and must be removed to
Operation of Refineries
15
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FLUE GAS
A
REGENERATOR
PRODUCTS
/<£!
REACTOR
REGENERATED
CATALYST'
CD
o
WET GAS
TO POLY OR
ALKYLATION UNITS
CRACKED
GASOLINE
.LIGHT FUEL OIL
.RECYCLE
GAS OIL
HEAVY FUEL OIL
GAS OIL
CHARGE
Figure 4. Fluid catalytic cracking unit (FCC).
maintain the activity of the catalyst. The powdered catalyst, saturated with oil
in the reactor, must be stripped with steam before it is returned to the
regenerator. This transfer is made by using air and steam. In the regenerator,
the coke is continuously burned from the catalyst with a controlled amount of
air. Steam and a water spray are used in an emergency to keep the temperature
from going too high during the coke burn. If the percentage of coke on the
catalyst is high, the temperature (if not controlled) could exceed the maximum
permissible limit for the metal of the regenerator. The amount of coke left on
the catalyst will vary from 0.2 to 0.35 percent, depending on the kind of
catalyst used. During its regeneration, some of the catalyst will be emitted
through the stack with the flue gases, regardless of the efficiency of the
methods used to control emissions. As a result of this loss, fresh catalyst is
added to the system to maintain the necessary bed levels in the reactor and
regenerator. At times, the activity of the catalyst decreases because impurities
accumulate to an undesirable level. When this decrease occurs, some of the
catalyst is withdrawn from the regenerator and replaced with fresh catalyst.
The vapors or synthetic crude oil (products) from the reactor enter the
fractionating tower as shown in Figure 4. Here the synthetic crude oil is
16
PETROLEUM REFINING EMISSIONS
-------
fractionated or separated into gas, gasoline, and fuel oils similar to the original
crude-oil charge shown in Figure 2. Figure 4 does not show the complete
recovery section of the fluid catalytic cracking unit, which contains, in
addition to the equipment shown, other fractionating towers, absorbers,
debutanizers, and other auxiliary equipment that could vary between
refineries. The wet gas from the fractionating tower is further processed into
various desirable products. For example, the hydrogen sulfide is recovered in
an amine absorber for feedstock to the sulfur unit; the methane and ethane are
used for refinery fuel gas; and the propane and butane are used for feedstock
for polymerization or alkylation units. Gasoline with a high octane number and
a good octane blenc'ing value can be blended into lead-free finished gasolines.
The lead susceptibility is good and, if leaded gasolines are permitted, will
decrease the lead content of the finished gasolines. The fuel oils are either used
as a cutter stock (for blending with the flux bottoms from the vacuum tower)
to make the residual fuel oils or are hydrotreated and sold as heating oils.
The catalytic cracking unit is one of the principal sources of pollutant
emissions in the refinery; however, control technology is available by which to
suppress these emissions to some extent. The regenerator is the largest polluter
of these units (Table 7).9 The installation of a carbon monoxide boiler
operating on the hot flue gases from the regenerator practically eliminates the
emission of carbon monoxide and hydrocarbons, without reducing particulates
or the oxides of sulfur and nitrogen. Particulates may be reduced by improving
the efficiency of the electrostatic precipitator used on the regenerator or by
installing modern cyclones. Except for leaks, sampling, spillage, and process
drains, the recovery section is not a potential source of air pollutants.
Table 7. EMISSION FACTORS FOR POLLUTANTS
FROM CATALYST REGENERATOR
Pollutant
Sulfur dioxide
Particulates
Hydrocarbons
Carbon monoxide
Nitrogen oxides
Source
Regenerator
Regenerator
(with precipitator)
Regenerator
Regenerator
Regenerator
Emission factor,
lb/1000 bbl charge
500
61
220
13,700
63
Operation of Refineries
17
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Catalytic Naphtha Reforming
The catalytic reforming process was developed largely in response to the
need for higher octane gasoline. Catalytic naphtha reforming is a simple
refining process that improves the antiknock quality (octane number) of
low-grade naphthas or virgin gasolines by contacting them with a platinum
catalyst under pressure and at high temperature. Rearranging the molecules
(usually by removing hydrogen) produces a gasoline of higher quality and
octane number. Naphthenes, such as cyclohexane, and paraffins are converted
into benzene, toluene, and xylenes.
H
^
H
BENZENE
H2
CYCLOHEXANE
H
TOLUENE
The operating conditions vary depending on the desired end products. An
excess of hydrogen is produced from this operation and is utilized in other
refining processes such as desulfurization and hydro treating. The charge is
normally hydro treated to prevent poisoning the catalyst. The reforming unit is
not a potential source of pollutants.
Light Hydrocarbon Processing
Polymerization
The polymerization process, used to produce a high octane gasoline, consists
of joining two or more olefins (unsaturated hydrocarbons) in the presence of a
catalyst, usually phosphoric acid. A typical reaction equation is:
18
PETROLEUM REFINING EMISSIONS
-------
CH3
CH3-CH-CH2 +CH3-CH2-CH=CH2+CATALYST--CH2-CH-CH2-CH2-CH-CH3
(PROPENE) (BUTENE-1) (PHOSPHORIC (4 METHYLHEXENE-1)
ACID)
Alkylation
In the alkylation process, an olefin is joined,with isobutane, using either
sulfuric or hydrofluoric acid as the catalyst. The olefin is usually butene-1,
butene-2, or isobutylene. This chemical reaction may be illustrated by the
following equation:
CH3 CH3
CH3-C-CH2-CH-CH3
CH3
(BUTENE-1)
(ISOBUTANE) (2-2-4 TRIMETHYLPENTANE
ISOOCTANE)
Isomerization
Isomerization reactions involve rearrangement of the molecular structure of
a hydrocarbon, with nothing added or removed from the material, as shown
below:
H2
H2
Ho
r c >
c c
c c
H2
Ho
H2
Ho
r c\
C C
c c
H2
CYCLOHEXANE
METHYLCYCLOPENTANE
Operation of Refineries
19
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Coking
Coking is not economically attractive unless the fuel-oil market is weak or
there is a demand for coke, because the coking operation will reduce the
production of residual fuel oils to practically zero. Coking will, however,
produce more feedstocks for the catalytic and hydrocracking units, thus giving
a higher yield of gasoline and other desirable products, such as jet fuels. A
disadvantage of this operation is that sulfur and nitrogen become concentrated
in the coke, constituting impurities that hinder its sale.
Delayed Process
The coking operation can be carried out by delayed or fluid processes.
Delayed coking, which is semicontinuous, is accomplished by cracking the
vacuum tower bottoms from the crude-oil separation unit as severely as
possible in a single-pass heater and transferring the cracked material into a coke
drum, where the liquids remain to form coke and the vapors proceed to a
fractionating tower for separation into lighter products to be used in other
processes. Two coke drums are used for this operation, one of which is kept in
operation while the other is being decoked hydraulically. Hydraulic decoking
involves drilling a hole down the center of the coking chamber for insertion of
a hydraulic cutting assembly having jets through which water under high
pressure is directed at the chamber walls, cutting away the coke. Normally the
drums are switched every 24 hours.
Fluid Process
In the fluid coking process, coke is built up on pellets until they are suitably
large for removal from the unit. Figure 5 is a flow diagram of a modern fluid
coking unit.10 As shown, two vessels are used: a reactor and a burner. The
solids are circulated between these vessels to transfer heat to the reactor. This
coke circulation is about 5 to 10 pounds per pound of feed. The hot residue is
coked by distributing it as a thin film on the hot coke particles in the reactor.
The coke bed is fluidized by introducing steam into the bottom of the reactor,
thus distributing the feed uniformly over the surface of the particles, where it
cracks and vaporizes. Vapor products leave the bed and pass through cyclones,
where most of the entrained coke is removed. The remaining coke is removed
by scrubbing, and the products are cooled to condense the heavy tar, which is
recycled to the reactor. The overhead products are recovered in the
fractionator and the coke is withdrawn from the system as necessary to
maintain a predetermined level in the vessel.1 °
Each of these coking processes has advantages or disadvantages with respect
to the other. The total operations of the individual refinery must be considered
in selecting the best coking process. Some of the factors involved are market
demands for specific products, control of emissions, flexibility of operations,
sulfur content of crude oil, savings in overall refinery cost, and presently
20 PETROLEUM REFINING EMISSIONS
-------
REACTOR PRODUCTS
TO FRACTIONATOR
REFLUX -
SLURRY
RECYCLE
SCRUBBER
T REACTOR
STOCK
'OTT3URNER
PRODUCT
COKE TO
STORAGE
Figure 5. Flow diagram of modern fluid coking unit.
installed coke handling equipment. Fluid coking would perhaps offer more
flexibility in refinery operations because its operation can be integrated with
other units such as carbon monoxide boilers, process heaters, power recovery
equipment, and the crude-oil separation unit. A combined coke- and carbon
monoxide-fired boiler would increase the steam generation.10 These factors
can contribute to decreasing the cost of refinery operations.
Delayed coking, which is an older process and has been well established
longer, is more widely used than fluid coking. The delayed coking process is
preferred where residual fuel oils with low sulfur are involved. The process is
not a serious source of pollutant emissions, although the usual pollutants are
emitted from the process heaters, and some particulates are emitted when the
coke is being removed from the drums. These emissions can be minimized,
however, by water quenching during the coke removal procedure.
The fluid coking process was commercially introduced in 1954 but today is
receiving serious consideration by refiners.10 With higher sulfur crude oil being
processed (resulting in higher sulfur residual fuel oils), fluid coking would be
preferred. The severity of fluid coking is greater than delayed coking; thus,
with fluid coking, less coke is produced, with more contaminants, but the
liquid yield is higher.
Operation of Refineries
21
-------
In addition to the usual pollutants from the combustion process of this
operation, an estimated 30 pounds of carbon monoxide per barrel of feed is
emitted. This emission can be controlled either by using a carbon monoxide
boiler on the coker or by using the boiler installed on the catalytic cracking
unit. Using the coke as fuel could present air pollution problems.
Hydrocracking
The growth of the hydrocracking process for the last 5 years is shown in
Figure 6.!1
Hydrocracking is a combination of catalytic cracking and hydrogenation in
which the olefinic materials created by cracking are saturated before being used
in coke formation. The conversion occurs in the presence of hydrogen, at
pressures ranging from 100 to 2000 pounds per square inch gauge, and at about
900 °F. The resulting product contains not only unsaturated hydrocarbons but
isomerized materials that are desirable as gasoline blending stocks. Depending
on sulfur content and characteristics of the chargestock, 1000 to 2500
standard cubic feet of hydrogen per barrel of charge may be required to obtain
the desired end products. Typical chargestocks are light and heavy gas oils,
vacuum gas oils, cracked and coker gas oils, deasphalted residuum, and topped
crude oil.1'
I
C3
Z
ce
900
800
700
600
500
400
1968
1969
1970
YEAR
1971
1972
(ESTIMATED)
Figure 6. Growth of use of hydrocracking.
22
PETROLEUM REFINING EMISSIONS
-------
The hydrocracking process was developed to convert middle distillates
obtained from the crude-oil separation unit to gasoline because the catalytic
cracking unit was incapable then of cracking these virgin distillates; but with
the development of zeolite catalysts that could crack these gas oils, operation
of hydrocrackers has been changed so that the unit is charged with different
feedstocks to produce a wider range of products, such as jet fuels and light
hydrocarbons for use in other processes. Gasolines produced from the
hydrocracker have a low octane number and must be catalytically reformed
before blending into the gasoline pool.
Sulfur Recovery Unit
A sulfur recovery unit is an example of the use of technology developed for
the control of pollutant emissions in petroleum refining. The hydrogen sulfide
(H2S) produced in miscellaneous processes is charged to a sulfur recovery unit
instead of being burned as fuel. In the 1950's, after naphtha catalytic
reforming was introduced, cheaper by-product hydrogen became available for
hydrodesulfurization, which removed sulfur from the distillates as H2S.
Recovering the H2S from the hydrodesulfurization gases with the amines
provided an increase in feedstock for the sulfur units. Contributing to the
increase in the number of sulfur recovery units used during the past 10 to 15
years has been the development of such new refining processes as:
1 . Catalytic cracking.
2. Catalytic reforming and desulfurization of naphtha.
3. Desulfurization of kerosene, and jet and diesel fuels.
4. Hydrocracking of virgin and cycle gas oils.
5. Desulfurization of residual fuel oil (to levels of 0.5 to 1 .0 percent of
sulfur).
6. Coking operations.
As shown in Figure 1, gases from various processes are treated in amine
units to recover the H2S for feedstock to the sulfur recovery unit (or sulfuric
acid plant). The amine units are simple to operate and do not present pollution
problems, except for odors perhaps. Usually the unit consists of an absorber,
regenerator exchanger, cooler for the amine solution, and a reboiler with which
to supply heat to the process. Either a 15 to 20 percent solution of
monoethanolamine (MEA) or a 20 to 30 percent solution of diethanolamine
(DEA) may be used.1 3 The H2S is absorbed at about 100 °F and is rejected at
about 240 °F. Chemically this reaction is:
RNH2 + H2S
Operation of Refineries 23
-------
where RNH2 represents MEA or DBA. The H2S thus recovered is charged to
the sulfur recovery unit. Amine units also will remove carbon dioxide (€62) as
shown:
RNH2 + CO2 + H2O * RNH3HC03
The C02 is absorbed at 120 °F and rejected at 300 °F. Efficient operation of
the amine units can increase the efficiency of the sulfur recovery units by
removing the CC>2 and hydrocarbons from the process stream containing the
H2S.
The basic process for converting H2$ to sulfur, developed by Claus, has
been improved through the years, and is now referred to as the Modified Claus
Process.14 The process involves burning one-third of the H2S to SC>2 and H20,
and then reacting the SC>2 with the remaining H2S to form elemental sulfur
and water vapor. The reaction occurs in a combustion chamber connected to a
fire-tube waste heat boiler that generates steam. The gas is cooled in the boiler
tubes and goes either directly to a condenser or to the first-stage catalytic
converter, where the reaction proceeds further over a catalyst of activated
bauxite (alumina). The operation may be shown by the chemical equations:
2H2S + 302 = 2S02 + 2H20
S02 + 2H2S = 3S + 2H20
The sulfur produced in the second step is recovered in the condenser. The
gases are reheated and flow to a second converter where more sulfur is
recovered. This two-converter process recovers about 90-92 percent of the sul-
fur from the charge. If a third converter is used, recovery is about 96-98
percent, reducing S02 emissions by about 50 percent.
Figure 7 is a simplified diagram of a sulfur recovery unit. With the
establishment of emission standards for S02, refiners (especially the larger
ones) were compelled to include sulfur recovery units in refinery operations
even if the process was not profitable.
Oddly enough, the operation of a sulfur unit to recover sulfur from refinery
waste gases has created a serious pollution problem within itself. During
operations, all unreacted H2S is incinerated and emitted "as S02 with the other
flue gases. This emission factor is about 400 pounds of SO2 per ton of sulfur
produced. The flue gas contains about 1.5 percent of S02, well over the legal
limit of proposed standards. Installation of more converters, although reducing
this emission somewhat, has been unsuccessful in meeting present standards;
however, several processes have been developed and are being installed for
commercial use on the tail gas from the sulfur recovery units used to control
S02.
24 PETROLEUM REFINING EMISSIONS
-------
CONDENSER
COALESCED
INCINERATOR
CONDENSER^ pREH*EATER CONDENSER
CATALYTIC
CONVERTER
PREHEATER
SULFUR
Figure 7. Recovery of sulfur from hydrogen sulfide.
Desulfurization of Fuel Oils
In many sections of the country, especially those that are highly
industrialized, fuel oils cannot legally exceed a maximum sulfur content.
Because of this restriction, it is mandatory that a desulfurization process be
included or at least considered in the development of the refining system.
Considering the sulfur level, volume of the market, the crude-oil source, and
the cost of producing the fuel oil, refiners may choose one of three such
processes:
1. Vacuum gas oil hydrodesulfurization (indirect).
2. Deasphalted oil hydrodesulfurization (indirect).
3. Residuum hydrodesulfurization (direct).
Operation of Refineries
25
-------
The process selected must be flexible enough to supply fuel oils to customers
within the marketing area of the refinery. V s>16
In the vacuum gas oil hydrodesulfurization process, the gas oil from the
vacuum distillation tower (Figure 2) is desulfurized to about 0.25 percent
sulfur and used directly as a grade of fuel oil or blended with the flux bottoms
for the amount of sulfur content permissible. The production of low-sulfur fuel
is limited in this process by the quantity of gas oil.
In the process referred to as deasphalted oil hydrodesulfurization, which is
important in meeting increasing demands for low-sulfur fuel oil, the vacuum
tower residuum is deasphaited. Then, the deasphalted oil (void of metals and
other catalyst poisons) can be desulfurized and thus supplement the fuel oil
inventory.
Direct residuum hydrodesulfurization produces more fuel oil than the
deasphalted oil process. One of the most promising advances in direct residuum
desulfurization has been the development of a catalyst that will be tolerant to
metal deposits and inexpensive, so that the spent catalyst can be discarded
rather than regenerated. Aalund1! indicates that these requirements have been
met for crude oil with low metal content such as the Mideast variety of crude
oils. This direct process does not necessitate all the equipment used in the
other processes, notably, the deasphalter and the vacuum tower, if the refinery
is operated to produce fuel oils as the prime product.
Basically, desulfurization processes are similar. The hydrocarbons are
treated with hydrogen at an elevated temperature under pressure, producing, as
a by-product, hydrogen sulfide, which is used as feedstock for the sulfur
recovery unit. Except for odors and other pollutants emitted through leaks,
spillage, process drains, and heaters, desulfurization units are not a serious
source of pollutants.
TREATING
In the refining process, some of the sulfur in the crude oil is converted to
H2S and lower molecular weight mercaptans. These sulfur compounds are
concentrated in the process gases and low-boiling-range hydrocarbons and are
normally removed in preparing the hydrocarbons for further processing. The
H2S is removed in the amine units, and the mercaptans are separated out by
chemical treatment as explained later.
Desulfurization of the heavier hydrocarbons will be necessary in order to
meet sulfur specifications for industrial uses. This process involves catalytic
treatment in the presence of hydrogen under pressure and at elevated
temperatures, so that the sulfur is removed as H2S. In this processing scheme,
it is imperative to include a sulfur recovery unit so as to prevent the emission
of sulfur oxides (from the incineration of the hydrogen sulfide) into the
atmosphere.
26 PETROLEUM REFINING EMISSIONS
-------
In the chemical process, a mixing chamber, a separator vessel, a water-wash
system, and a regeneration system by which to recover spent chemicals are
needed for removing sulfur compounds. The sweetening process oxidizes the
mercaptans to disulfides but does not remove the sulfur from the products.
The oxidation process also removes the disagreeable odor of the mercaptans.
Treatment of petroleum products has been improved during the past few
years. The previous sodium plumbite method of oxidizing the odoriferous
mercaptans to disulfides is shown in the following chemical equation:
! 2RSH +Na2Pb02 +S-»
MERCAPTANS + SODIUM PLUMBITE + SULFUR
2R2S2 + PbS + 2NaOB
DISULFIDES + LEAD SULFIDE + SODIUM HYDROXIDE
This process has been replaced by either the copper chloride or the "inhibitor"
sweetening process. Unlike the sodium plumbite process, these techniques will
oxidize the mercaptans without the loss of octane number. The copper
chloride reaction is:
4RSH + 4CuCl2
MERCAPTANS + COPPER CHLORIDE + OXYGEN
2R2S2 + 4CuCl2 + 2H20
DISULFIDES + COPPER CHLORIDE + WATER
Because of the regeneration of the chemicals, treating plants are the
potential sources of odors, sulfur compounds, and hydrocarbons.
In the inhibitor sweetening process, a p-phenylenediamine type of inhibitor
is added to the gasoline and, in the presence of air, reduces odors by converting
the mercaptans to disulfides.
With the development of new techniques, the treating operation is not a
serious potential source of pollutants. Odors are the predominating pollutant;
sulfur compounds and hydrocarbons are contained within the system.
BLENDING
To make the 2500 different finished products, the refinery blends base
stocks in different proportions to meet the applicable specifications. This
routine step is the final one in the refining system. Except for leaks and
spillage, blending should not be a source of emissions.
Operation of Refineries 27
-------
FACTORS CONTRIBUTING
TO EMISSION OF POLLUTANTS
The control of refinery emissions is complicated by the diversity of refinery
operations required For this reason, in any survey of pollutant emissions, a
refinery should be considered one unit. Since no two refineries have exactly
the same operations, emissions will vary in both quantity and type; therefore,
any total estimate of a specific pollutant should be the sum of the emissions of
that pollutant from all sources throughout the refinery.8 Major factors
affecting the quantities and types of pollutants are the emission control
equipment in use, the sulfur content of raw materials, refining operations, and
housekeeping and maintenance practices.
EMISSION CONTROL EQUIPMENT AND METHODS IN USE
The modern refinery utilizes equipment for emission control in order to
meet air quality standards, to prevent loss of products, or both. Older refineries
hesitate to spend large sums of money strictly for pollution control; but if use
of the equipment is economically feasible or if the refinery is required by law
to control specified pollutants, the devices will be installed. Floating-roof
storage tanks, for example, are a justified expenditure that will reduce the loss
of valuable products, thus giving a short-term return on the investment. As
another example, the types of stacks at a refinery may affect the quantities and
types of pollutants. Although taller stacks are not considered a long-term,
effective control method, shorter stacks will not disperse combustion gases
above ground level and will contribute to photochemical smog. If the latest
control methods are not being used, excessive emissions of all the pollutants
produced during refinery operations will occur.
SULFUR CONTENT OF RAW MATERIALS
Sulfur is present in the crude oil charged and in the acid (sulfuric acid)
utilized in treating or alkylating operations. Serious pollution problems are
created when the original sulfur compounds in the crude oil are exposed to
refinery processing or when they are burned as fuel. By the use of modern
refining methods, up to 85 percent of this sulfur will be converted first to H2S
and then, by the Claus process, to sulfur. A refinery charging 100,000 barrels
per calendar day of crude oil containing 1 percent sulfur could produce about
100 tons of sulfur per day.
29
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REFINING OPERATIONS
A number of refining operations and practices can contribute to the air
pollution problem even if they are not the major sources of emission from
refineries. For example, the variety of products manufactured has an effect on
emissions, inasmuch as potential pollution sources will increase as more
equipment is needed for more and different products. Also, the use of flares
and incinerators, even though they are smokeless, will result in the emission of
particulates, sulfur dioxide, nitrogen oxides, and hydrocarbons. Such
emissions, especially from flares, are difficult to estimate because of the
manner in which flares and incinerators are operated. Flaring is controlled but
not measured, and is the result of depressurizing processing Units or of some
disruption in a unit. The fuels used in process operations and the types and
sizes of equipment can also affect emissions. Specifically, the quantities and
types of air pollutants emitted from refinery operations can be affected by the
size and number of catalytic cracking units (cat crackers) used and by the type
of particulate control equipment used on cat crackers. In addition, the
following considerations are significant:
1. Whether a carbon monoxide boiler is operated.
2. Whether the chemical or catalytic method of product treating is used.
3. Whether the fuel used is refinery gas, oil, or natural gas.
4. Whether a sulfur recovery unit is operated, and whether flue gases from
incineration of hydrogen sulfide are controlled.
5. Whether fixed- or floating-roof storage tanks are used.
6. Whether a sulfuric acid plant is operated.
7. How acid sludge is disposed of (if a sulfuric acid plant is operated).
HOUSEKEEPING AND MAINTENANCE PRACTICES
Poor housekeeping practices can increase emissions. For example, if
excessive purging of lines is the normal practice, sampling alone will contribute
about 50 to 100 pounds of hydrocarbons per 1000 barrels of crude-oil charge.
Other important items connected with housekeeping are use of process drains
and blowdown systems, and occurrence of spills. General maintenance
practices also affect emissions. Leaking of flanges, valves, and pump seals, and
spillage from the installation and removal of blinds will contribute about 200
pounds of hydrocarbons per 1000 barrels of daily crude charge.
30 PETROLEUM REFINING EMISSIONS
-------
MAJOR SOURCES OF POLLUTANT EMISSIONS
Table 8 shows major sources of air pollution from a petroleum refinery,
with the principal pollutants from these sources, as discussed in the general
description of refining processes.y
Table 8. MAJOR SOURCES OF POLLUTANT EMISSIONS 4- 9- 29
Source
Pollutant
Emission factor,
lb/1000 bbl
Catalytic cracking
regenerator
Combustion operations
Storage tanks
Miscellaneous factors
Loading facilities
Sampling
Spillage
Leaks
Barometric condensers
Waste oil separator
Cool ing tower
Sulfur oxides
Hydrocarbons
Particulates (with ESP)a
Carbon monoxide
Nitrogen oxides
Sulfur oxides
Hydrocarbons
Particulates
Carbon monoxide
Nitrogen oxides
Hydrocarbons (cone roof)
Hydrocarbons
500 (charge)
220 (charge)
61 (charge)
13,700 (charge)
63 (charge)
6,400 x %S (oil burned)
140 (oil burned)
800 (oil burned)
2 (oil burned)
2,900 (oil burned)
400 (throughput)6
700 (crude charge)
a Electrostatic precipitator
bWith a floating-roof tank the emission factor would be about 4 pounds per
day per 1000 barrels.
Factors Contributing to Emissions
31
-------
CONTROL METHODS
AVAILABLE METHODS
Control methods have been developed for some of the principal pollutants
from refining processes, but only about 50 percent of the necessary control
equipment has been installed by the refineries.
Hydrocarbons
Perhaps more progress has been made in controlling hydrocarbon emissions
than any other pollutant, and the control methods are economically feasible.
Expenditures for new equipment are more than offset by the saving of valuable
products lost through vaporization to the atmosphere, especially for such
high-vapor-pressure hydrocarbons as gasoline and crude oil. Some of these
control methods are:
1. Installation of floating-roof tanks.
2. Manifolding of purge lines to a recovery system or to a flare.
3. Use of vapor recovery system on loading facilities.
4. Use of improved housekeeping method.
5. Use of covered waste treatment plant.
6. Operation of a carbon monoxide boiler.
7. Installation of mechanical seals on pumps and compressors.
8. Training of personnel.
Particulates
Although emissions may not meet standards, particulates can be controlled
by:
1. Use of high-efficiency mechanical separators.
2. Installation of electrostatic precipitators on catalyst regenerators or on
power plant stacks or on both.
33
-------
3. Careful control of combustion to avoid smoke.
4. Maintenance of correct stack temperature.
5. Use of smokeless flames for burning waste gases.
6. Use of improved incinerators.
Carbon Monoxide
The emission of carbon monoxide can be controlled by using a modern
furnace and burner design and proper fuel atomization. Furthermore, a waste
heat boiler, such as a carbon monoxide boiler, should be installed on the
catalytic cracking and fluid coking units. The flue gases from the regenerator
will contain 4 to 9 percent carbon monoxide (13.7 pounds per barrel of fresh
feed) and about 200 pounds of hydrocarbons per 1000 barrels of charge. The
boiler will not only remove these pollutants but will reduce the cost of fuel
used to produce steam.28
Smoke
Although visible emissions could occur if high-sulfur fuel is used, develop-
ments in the design of efficient furnaces, burners, control instrumentation,
smokeless flares, and incinerators, and improvements in their operation have
enabled refineries to reduce smoke emissions greatly.
Odors
Odor can be reduced in a number of ways, including improved housekeeping
and maintenance practices. Primary methods of odor reduction, however,
involve the control of emissions of hydrocarbon and sulfur compounds and the
treatment of sour water.
The method selected for treatment of sour water will vary from refinery to
refinery, must be evaluated on its own merits, and must be solved for local
requirements. Most of the sour water is produced in fluid catalytic cracking, in
gas processing, and. in the vacuum tower. Sulfides, ammonia, and phenols are
the principal pollutants contributing to odors. The waste water, after heating
to 200°F, is pumped to a stripper, with air and steam being injected. The H2S
from this stripping process is either incinerated or used as chargestock for the
sulfur unit. In numerous refineries, stripped water is used for the crude
desalting process, where phenols and other compounds are absorbed in the
crude oil, with a resulting reduction in process odors. The excess water from
the stripper will go with other process waste to the waste treatment plant for
oxidation, skimming, settling, or any treatment necessary before the water is
discharged into a receiving stream.
34 PETROLEUM REFINING EMISSIONS
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CONTROL TECHNOLOGY NEEDED
It is important that methods for removing sulfur and nitrogen oxides from
refinery flue gases be developed and that techniques for controlling odor from
refineries be improved. Millions of dollars have been spent by the petroleum
industry and by the Federal Government on research to develop control
methods for nitrogen oxides and sulfur dioxide. Although progress is being
made, continued development could result in further substantial reductions in
emissions, along with a decrease in investment and operating costs.
Sulfur Dioxide
The most successful approach to controlling sulfur dioxide (S02) from
refineries is the desulfurization processes that have been developed for distillate
fuels, residual fuels (both indirect or direct methods), and for fuel gas cleaning.
Metals in the residual fuel oil adversely affect direct desulfurization. There is a
definite need for a catalyst that can withstand high metal deposits or for some
auxiliary process that can remove the metals before contacting the catalyst;
such developments could simplify the refinery desulfurization program.
The principal sources of SOj in the refinery are:
1. Refinery process heaters and boilers.
2. Oaus sulfur recovery plants.
3. Sulfuric acid plants.
4. Fluid catalytic cracking units.
5. Fluid coking units.
The technology for preventing the emission of SC>2 has been developed and
can be employed, though processes may be expensive to operate. They are as
follows:
1. Desulfurize the fuels used in process heaters and boilers.
2. Use recently developed processes to control emissions from the Claus
sulfur recovery and sulfurjc acid units.
3. Desulfurize the gas oil used to charge the catalytic cracking units, a
technique currently employed in some refineries.
The most critical unknown is flue gas desulfurization. A workable cheap
process would save millions of dollars spent in residual fuel desulfurization.
Accordingly, research should be continued to develop the technology for
removing SO^ from flue .gases.
Control Methods 35
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Nitrogen Oxides
Nitrogen oxides (NOX) are formed in the combustion processes, largely by
fixation of oxygen and nitrogen at high temperature.3 ° The most promising
prospects for significant early reduction of NOX from the combustion
processes will probably result from applying some combination of combustion
modification techniques to reduce the NOX formed.
Improved burner designs, reduced load, low-excess-air firing, and flue gas
recirculation have reduced NOX emissions; however, since NOX will react with
moisture in the atmosphere to frrm acids and with hydrocarbons to form new
compounds (which under certain atmospheric conditions will contribute to the
formation of photochemical smogs), research to improve current techniques
and to identify additional methods for removing or reducing emissions of
nitrogen oxides is urgently needed.
Particulates
Even though technology has been developed for controlling particulate
emissions, it has not yet been applied in all refineries; some refiners, depending
on electrostatic precipitators to control the fine clay-like catalyst, have not
installed modern control equipment on the catalytic cracking units and process
heaters. Extensive investments have been made for research on the control of
sulfur compounds and hydrocarbons, and on combustion techniques, but the
efforts to control particulate emissions have not reached the same level.3' '3 2
Odors
Technology developed for controlling emissions of all pollutants from
refinery processes has been instrumental in reducing odors. Since disagreeable
odors from petroleum refineries cause the majority of complaints from the
public, it is clearly desirable from a public relations standpoint to eliminate or
at least reduce these pollutants.17:'33
INTERIM CONTROL OF EMISSIONS
Until technologies can be developed by which to control the emission of
some pollutants, interim control techniques can be employed to reduce these
emissions.
Sulfur Dioxide
Taller Stacks
Currently, tall stacks are permitted as a dispersion method for SC>2
emission, but this approach is not likely to be a long-term solution. Tall stacks
36 PETROLEUM REFINING EMISSIONS
-------
are effective, however, in reducing local ground level concentration of
pollutants (except in a major industrial area) and could prevent the ground
level concentration from becoming harmful. This method depends on process,
source, and meteorological factors but is not really a control method.
Low-sulfur Fuel
The use of low-sulfur fuel is the quickest way to reduce 862 emissions;
however, the natural low-sulfur fuel supply is limited. It is produced mostly
from foreign crudes, and low-sulfur crude is in short supply because of import
limitations.
Natural Gas
Here again, limited supply and lack of facilities for delivering the fuel to
customers are factors governing the use of natural gas as fuel in order to reduce
SO 2 emissions.
Sulfur Recovery Unit
The development and installation of sulfur recovery units have contributed
to the reduction of SC>2 in the refinery flue gases by removing the H2S from
the process gases before they are burned as refinery fuel. Tail gases from these
sulfur recovery units contain an appreciable amount of SC>2 and are the subject
of current efforts to remove this pollutant for commercial use. Some progress
has been made in developing processes by which to control these emissions.
Nitrogen Oxides
Efficient control technology for NOX has not been developed. The use of
modern equipment and the control of combustion processes will reduce NOX.
Taller stacks will improve local NOX concentrations by permitting better
dispersion, but will not control the pollutants.
Participates
Although emissions may be in excess of prescribed standards, particulates
can be abated by the use of: (1) highly efficient mechanical separators,
(2) electrostatic precipitators on catalytic regenerator and power plant stacks,
and (3) smokeless flares and incinerators. In addition, the careful control of
combustion (no smoke) and the maintenance of specified stack temperature
will help reduce particulate emissions.
Control Methods 37
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Odors
Odors can be controlled by improvements in: housekeeping, maintenance,
and control of emissions of hydrocarbons and sulfur compounds.
PROPOSED GUIDELINES FOR REFINERY EMISSIONS
The U.S. Environmental Protection Agency has proposed guidelines for
emissions from refinery operations. These guidelines were published in the
Federal Register, Volume 36, Number 158, Part 2, August 14, 1971, and are
reprinted in this document as Appendix B.
COMMENTS ON EMISSION CONTROLS
Working separately, or with such trade organizations as the American
Petroleum Institute and the National Petroleum Refiners Association, and in
cooperation with equipment manufacturers, oil companies have, through
research, developed processes and equipment for controlling or at least
reducing all pollutants from refineries. One of the most recent developments is
that of a new catalyst, suitable for direct desulfurization of residual fuel oils or
of the whole crude. The problem confronting refineries is the present cost of
this equipment. Hopefully, processes will be improved and the cost of control
can be cut accordingly.
In 1955, Lauren B. Hitchcock, President of the Air Pollution Foundation,
said: "The approach to the solution of the smog problem taken by the Air
Pollution Foundation is to devise means of economically controlling pollutants
at their sources - under this approach, we seek out the sources of pollution,
identify them and their emissions, assess their magnitudes and go after the
more important ones first. Organic compounds, oxides of nitrogen and sulfur,
and particulate head the list."2
Following this philosophy, refiners have developed controls for all pol-
lutants except nitrogen oxides; but the fact that all refiners are not employing
these controls is a major drawback of the pollution control effort being
expended by the petroleum refining industry.
38 PETROLEUM REFINING EMISSIONS
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REFERENCES
1. Gardner, FJ. Worldwide Issue. Oil and Gas J. 69(52): 67-156, December
27,1971.
2. Hitchcock, L.B. Air Pollution and the Oil Industry. In: Proceedings,
American Petroleum Institute, Division of Production. Los Angeles,
American Petroleum Institute, April 28, 1955. p. 150-154.
3. Siegmund, C.W. and E.H. Manny. Effect of Fuel-oil Sulfur on Product
Patterns. (Presented at ASME-IEEE Power Conference. San Francisco.
1968|)
4. Nationwide Emission Estimates for 1969. Environmental Protection
Agency, Washington, D.C. April 1971.
5. McAfee, J. et al. Gulf HDS Process Upgrades Crude. Petro. Refiner. Vol.
34, May 1955.
6. Paradis, S.G. et al. Isomax Desulfurization of Residuum and Whole Crude
Oil. Chevron Research Company. (Presented at 68th National Meeting of
American Institute of Chemical Engineers. February 28-March 4, 1971.)
7. Rohrman, F.A. and J.H. Ludwig. Sources of Sulfur Dioxide Pollution.
Public Health Service, U.S. Department of Health, Education, and Welfare,
Cincinnati, Ohio. (Presented at 55th National Meeting of American
Institute of Chemical Engineers. Houston. February 7-11,1965. 17 p.)
8. Steigerwald, B.J. Atmospheric Emissions from Petroleum Refineries — A
Guide for Measurement and Control. Public Health Service, U.S. Depart-
ment of Health, Education, and Welfare. Washington, D.C. Publication No.
763. 1960. 56 p.
9. Duprey, R.L. Compilation of Air Pollutant Emission Factors. Public
Health Service, U.S. Department of Health, Education, and Welfare.
Durham, N.C. Publication No. 999-AP-42.1968. p. 41-42.
10. Busch, R.G. Fluid Coking: Seasoned Process Takes on New Job. Oil and
Gas J. 68(14): 102-111, April 1970.
11. 1970 Refining Progress Handbook. Hydrocarbon Processing. 49(9):
167-173, September 1970.
39
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12. Cantrell, A. Annual Refining Issue. Oil and Gas J. 69(1): 93-124, March
1971.
13. Nelson, W.L. Petroleum Refinery Engineering. New York, McGraw-Hill,
1958.960 p.
14. Chute, A.E. Sulfur from Petroleum Gases and Liquids. The Ralph M.
Parsons Company. (Presented at meeting of Society of Mining Engineers.
September 7,1967.)
15. Meredith, H.H., Jr. and W.L. Lewis. Desulfurization and the Petroleum
Industry. Chem. Eng. Proc. September 1968.
16. Rogers, L.C. and D.H. Stormont. Oil Scrambling to Unravel Sulfur - Curb
Supply Knot. Oil and Gas J. 66(26): 41-44, June 24, 1968.
17. Burhouse, W.A. The Oil Industry and Air Pollution. Air Eng. 70(3): 18-22,
March 1968.
18. Chass, R.L. The Status of Engineering Knowledge for Control of Air
Pollution. Los Angeles County Air Pollution Control District. (Presented at
National Conference on Air Pollution. Washington, D.C. December 1962.)
19. Devorkin, H. and BJ. Steigerwald. Emissions of Air Contaminants from
Boilers and Process Heaters, Joint District, Federal, and State Project for
the Evaluation of Refinery Enu'ssions, Report No. 7. June 1958. '
20. Flynn, N.E. and W.R. Grouse. Report on Nitrogen Oxides in the Bay Area
Pollution Control District. Bay Area Pollution Control District. San
Francisco, Calif. September 3, 1964. 20 p.
21. Gammelgard, P.N. Current Status and Future Prospects - Refinery Air
Pollution Control. In: Proceedings from the Third National Conferences on
Air Pollution. Washington, D.C., The American Petroleum Institute, 1966.
p. 260, 263.
22. Giever, P.M. Significance of Carbon Monoxide as a Pollutant. J.
Occupational Med. June 1967.
23. Hardison, L.C. Where It Originates, How to Stop It - Air Pollution
Control Equipment. Petro/Chem. Ehg. 40(3): 30-38, March 1968.
24. Kirby, A.W.W. Pollution Abatement in the Petroleum Refining Industry.
Inst. Petro. Rev. 77(131): 289-293, November 1957.
25. Mencher, SX. Change Your Process to Alleviate Your Pollution Problem.
Petro/Chem. Ehg. May 1967.
40 PETROLEUM REFINING EMISSIONS
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26. Mencher, S.K. Minimizing Waste in the Petrochemical Industry. Chem.
Eng. Progress. 65(10): 80-88, October 1967.
27. Phillips, C.W. and S.W. Dickey. Air Pollution Control Features of a
Modern Refinery. (Presented at the American Chemical Society Meeting.
Chicago. September 1967.) '
28: Wangerin, D.D. Waste-Heat Boilers - Principles and Applications.
(Presented at American Power Conference. April 14-16, 1964. 7 p.)
29. Estimated Cost of Controlling SOX in the United States. Ernst and Ernst.
Washington, D.C. December 22, 1967.
30. Systems Study of NOX Control Methods for Stationary Sources. Esso
Research and Engineering Company. Linden, N.J. Contract No. PH
22-85-55. November 1969. 520 p.
31. Wilson, J.G. and D.W. Miller. The Removal of Particulate Matter from
Fluid Bed Catalytic Cracking Unit Stack Gases. J. Air Pollut. Contr. Assoc.
77(10): 682-685, October 1967.
32. Profile of Industry Costs for Control of Particulate Air Pollution;
Background Paper for the Interagency Pollution Control Incentive Study
Committee. Ernst and Ernst. Washington, D.C. October 6, 1967.
33. Kendall, D.A. and A.J. Neilson. Odor Profile Studies of Effluent Waste
Waters from Seven Refineries. (Presented at Midyear Meeting of American
Petroleum Institute, Division of Refining. May 1964.)
34. Giant Stack Will Vent Sulfur Oxides above Smog Ceiling. Chcm. Eng.
74(17): 104, August 17, 1967.
35. Petroleum Products Handbook. Guthrie, V.B. (ed.). New York, McGraw-
Hill. 1960.
References 41
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APPENDIX A: GLOSSARY35 *
Alkylation. A refinery process for chemically combining isoparaffin with olefin
hydrocarbons. The product, alkylate, has high octane value and is blended with
motor and aviation gasoline to improve the antiknock value of the fuel.
Barrel. For statistical purposes, the petroleum industry uses a barrel containing
42 U.S. standard gallons. Where the price of fuel oils or other products is
quoted by the barrel, it is the 42-gal. barrel, regardless of the method of
shipment.
Blending. The process of mixing two or more oils having different properties to
obtain a product of intermediate properties. Lubricating oil stocks are blended
to a desired viscosity; naphthas and gasolines are blended to meet distillation
and octane requirements.
Bottoms. See Residue.
Catalyst. A substance used to accelerate or retard a chemical reaction without
itself undergoing significant chemical change or change in volume during the
process.
Coke. The solid residue remaining after the destructive distillation of crude
petroleum or residual fractions. Used commercially as domestic and industrial
fuel and, when purified, in various metallurgical and industrial processes.
Cracked. When applied to gasolines, naphthas, distillate gas oils, fuel oik, and
similar products, reference is to oils produced by the cracking process in place
of straight distillation.
Cracking. Process carried out in a refinery reactor in which the large molecules
in the charge stock are broken up into smaller, lower-boiling, stable
hydrocarbon molecules, which leave the vessel overhead as unfinished cracked
gasoline, kerosenes, and gas oils. At the same time, certain of the unstable or
reactive molecules in the charge stock combine to form tar or coke bottoms.
The cracking reaction may be carried out with heat and pressure (thermal
cracking) or in the presence of a catalyst (catalytic cracking).
*From Petroleum Products Handbook, V.B. Guthrie, editor. Copyright 1960
by McGraw-Hill Book Company. Used with permission of McGraw-Hill Book
Company.
43
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Crude Oil, Crude Petroleum. A naturally occurring mixture, consisting
predominantly of hydrocarbons and/or of sulfur, nitrogen, and/or oxygen
derivatives of hydrocarbons, which is capable of being removed from the earth
in a liquid state. Basic types of crudes are asphahic, naphthenic, or paraffinic,
depending on the relative proportion of these types of hydrocarbons present.
Deasphalting. Process for removing asphalt from petroleum fractions, such as
reduced crude. A common deasphalting process introduces liquid propane in
which the nonasphaltic compounds are soluble while the asphalt settles out.
Distillate. The product of distillation obtained by condensing the vapors from a
refinery still; also known as overhead fractions, as distinguished from the
non-vaporizing residual components left in the still.
Distillate Fuel Oils. A general classification for one of the overhead fractions
produced from crude oil in conventional distillation operations. The so-called
light heating oils, diesel fuels, and gas oils come from this fraction.
Distillation. The general process of vaporizing liquids, crude oil, or one of its
fractions in a closed vessel; then collecting and condensing the vapors into
liquids. Commercial forms of distillation in petroleum refining include crude,
atmospheric, vacuum, rerun, steam, and extractive.
Floating Roof. Special type of steel tank roof which floats on the surface of
the oil in the/tank; it eliminates tank breathing and reduces evaporation losses.
Fuel Oils. Any liquid or liquefiable petroleum product burned for the
generation of heat and power.
Gallon (U.S.). Unit of liquid volume equal to 231 cu. in., equal to 0.83268
times the imperial gallon.
Gas Oil. A fraction derived in refining petroleum with a boiling range between
kerosene and lubricating oil. Derives its name from having originally been used
in the manufacture of illuminating gas. Now supplies distillate-type fuel oils
and diesel fuel, also cracked to produce gasoline.
Gasoline. A refined petroleum naphtha which by its composition is suitable for
fuel in a reciprocating-type internal-combustion engine. ASTM D 439 specifies
three grades for various types of motor vehicle operations. Straight-run gasoline
is the product of distillation; cracked gasoline, of a cracking process.
Hydrocarbons. Compounds containing only carbon and hydrogen. They form
the principal constituents of petroleum. The simplest hydrocarbons are gases at
ordinary temperatures, but with increasing molecular weight, they change to
liquid and, finally, to solid form.
44 PETROLEUM REFINING EMISSIONS
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Hydrodesulfurizing. A process for combining hydrogen with the sulfur in
refinery petroleum streams to make hydrogen sulfide, which is removed from
the oil as a gas.
Hydrogen (Hz). Colorless gas recovered from naphtha reforming processes in
refinery operations; also made from methane. Used in refinery processing and
treating and in manufacturing ammonia and methyl alcohol.
Hydrogen Sulfide (H^S). An objectionable impurity present in some natural
gas and crude oils and formed during the refining of sulfur-containing oils. It is
removed from products by various treating methods at the refinery.
Isomerization. A refining process which alters the fundamental arrangement of
atoms in the molecule. Used to convert normal butane into isobutane, an
alkylation process feedstock, and normal pentane and hexane into isopentane
and isohexane, high-octane gasoline components.
Jet Fuel. Kerosene-type fuels or blends of gasoline, distillate, and residual oils
which are used as fuels for gas-turbine-powered aircraft.
Kerosene. A refined petroleum distillate suitable for use as an illuminant when
burned in a wick lamp. In the United States, state, local, and insurance
regulations generally require flash points higher than 73 °F (23 °C) by the
standard test for flash point, ASTM D 56. Synonymous terms are lamp oil,
burning oil, illuminating oil, and range oil when the product is used in space
heaters.
Kerosene Distillate. The second or water-white cut from the distillation of
crude petroleum, which is the unrefined base for all grades of domestic and
export kerosene.
Mercaptans. Compounds of sulfur having a strong, repulsive garlic-like odor. A
contaminant of "sour" crude oil and products.
Naphtha. Liquid hydrocarbon fractions, generally boiling within the gasoline
range, recovered by the distillation of crude petroleum. Used as solvents,
dry-cleaning agents, and charge stocks to reforming units to make high-octane
gasoline.
Octane Number. The anti-knock quality of motor gasoline is expressed by a
numerical scale which is based on the knocking tendencies of two pure
hydrocarbons: normal heptane is rated zero and isooctane is rated 100. In a
standard laboratory test engine, the octane number of the fuel under test is the
percentage by volume of isooctane in blend with heptane that knocks with the
same intensity as the fuel under test. This intensity is recorded on a scale.
Appendix A 45
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Polymerization. The process of combining two or more simple molecules of the
same type, called monomers, to form a single molecule having the same
elements in the same proportion as in the original molecule but having
different molecular weights. The product of this combination is a copolymer.
GR-S synthetic rubber is a copolymer of butadiene and styrene.
Refinery Gas. Gas produced in refineries by cracking, reforming, and other
processes. Components are principally methane, ethane, ethylene, propane,
propene, butanes, and butylene.
Refining. The separation of crude petroleum into its component parts and the
manufacture therefrom of finished commercial products by distillation,
thermal or catalytic cracking processes using chemicals, and treating.
Reforming. The mild thermal cracking of naphthas to obtain more volatile
products, such as olefins, of higher octane values; or catalytic conversion of
naphtha components to produce higher octane aromatic compounds.
Residual Fuel Oils. Topped crude petroleum or viscous residuums obtained in
refinery operations. Commercial grades of burner fuel oils No. 5 and 6 are
residual oils and include Bunker fuels.
Residue. In the standard laboratory distillation test, the amount of the original
liquid remaining in the flask after the distillation is complete. Also the
substance left after distilling off from crude oil in refinery operations all but
the heaviest components. Also known as residuum or bottoms.
Smog. An atmospheric disturbance caused by dust, smoke, and fumes
remaining over a given area, sometimes to the point that discomfort results to
humans and vegetation is affected.
Sour Gas. A gas containing sulfur-bearing compounds such as hydrogen sulfide
and mercaptans; usually corrosive.
Straight-Run Distillation. Continuous distillation of petroleum oils which
separates the products in the order of their boiling points without cracking.
Straight-Run Products. Gasoline, naphthas, or other products obtained directly
from the distillation of crude or other straight-run charge stocks without
cracking.
Sulfur (S). Amorphous or solid substance made from hydrogen sulfide
recovered from sour natural gas and from refinery gases. Used in manufacturing
sulfuric acid, plastics, and fertilizers.
46 PETROLEUM REFINING EMISSIONS
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Thermal Cracking. See Cracking
Treating. Usually the contact of petroleum products with chemicals, during
refining, to improve their properties; e.g., treating unfinished products such as
gasoline, kerosene, diesel fuels, and lubricating stocks with sulfuric acid to
improve color, odor, and other properties.
Unsaturates. Hydrocarbon compounds of such molecular structure that they
readily pick up additional hydrogen atoms. Olefins and dioelfins, which occur
in cracking, are of this type.
Vacuum Distillation. Distillation under reduced pressure, which reduces the
boiling temperature of the material being distilled sufficiently to prevent
decomposition or cracking. See Distillation.
Vapor Pressure. The pressure exerted by the vapors released from an oil at a
given temperature when enclosed in an airtight container. For motor gasoline, a
criterion of vapor-lock tendencies; for light products generally, an index of
storage and handling requirements.
Yield. In petroleum refining, the percentage obtained of product or inter-
mediate fractions of the amount of crude charged to the processing operation.
Appendix A
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APPENDIX B: GUIDELINES PROPOSED BY
THE ENVIRONMENTAL PROTECTION
AGENCY FOR REFINERY EMISSIONS
Proposed guidelines for emissions from refining operations, as published in
the Federal Register, Volume 36, Number 158, Part 2, are presented below.
2.0 CONTROL OF PARTICIPATE EMISSIONS
2.1 Visible emissions.. The emission of visible air pollutants can be limited
to a shade or density equal to but not darker than that designated as No. 1 on
the Ringelmann chart or 20 percent opacity except for brief periods during
such operations as soot blowing and startup. This limitation would generally
eliminate visible pollutant emissions from stationary sources.
2.3 Incineration. The emission of particulate matter from any incinerator
can be limited to 0.20 pound per 100 pounds (2 gm/kg) of refuse charged. This
emission limitation is based on the source test method for stationary sources of
particulate emissions which will be published by the Administrator. This
method includes both a dry filter and wet impingers and represents particulate
matter of 70 °F and 1.0 atmosphere pressure.
2.4 Fuel burning equipment. The emission of particulate matter from
fuel-burning equipment burning solid fuel can be limited to 0.30 pound per
million B.t.u. (0.54 gm/106 gm-cal) of heat input. This emission limitation is
based on the source test method for stationary sources of particulate emissions
which will be published by the Administrator. This method includes both a dry
filter and wet impingers and represents particulate matter of 70 °F and 1.0
atmosphere pressure.
3.0 CONTROL OF SULFUR COMPOUND EMISSIONS
i
3.1 Fuel combustion. It is not possible to make nationally applicable
generalizations about attainable degrees of control of sulfur oxides emissions
from combustion sources. Availability of low-sulfur fuels varies from one area
to another. In some areas, severe restrictions on the sulfur content of fuels
could have a significant impact on fuel-supply patterns; accordingly, where
such restrictions are necessary for attainment of national ambient air quality
standards, adoption of phased schedules of sulfur-in-fuel limitations is
recommended. Stack gas cleaning of sulfur-in-fuel limitations is recom-
mended
49
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Alternative means of meeting requirements for the control of sulfur oxides
emissions from fuel combustion sources include: use of natural gas, distillate
oil, low-sulfur coal, and low-sulfur residual oil; desulfurization of oil or coal;
stack gas desulfurization; and restricted use, shutdown, or relocation of large
existing sources.
It is technically feasible to produce or desulfurize fuels to meet the
following specifications: distillate oil - 0.1 percent sulfur (though it should be
noted that distillate oil containing less than 0.2 percent sulfur is not generally
available at this time); residual oil — 0.3 percent sulfur; and bituminous coal -
0.7 percent sulfur. Availability of significant quantities of such low-sulfur fuels
in any region where they do not naturally occur or have not been imported
from other domestic or foreign sources will require planning for the timely
development of new sources of such fuels. Because residual oil generally is
obtained from overseas sources, its use ordinarily is restricted to areas
accessible to waterborne transportation. There are limited tonnages of 0.7
percent sulfur coal produced at the present time, primarily in the western
United States; large reserves of such coal exist but are not now being mined.
The flaring or combustion of any refinery process gas stream or any other
process gas stream that contains sulfur compounds measured as hydrogen
sulfide can be limited to a concentration of 10 grains per 100 standard cubic
feet (23 gm/100 scm) of gas. This limitation on combustion of process gas
relates to the control of sulfur oxide emissions that would result from burning
untreated process gas from refinery operations or coke ovens containing
hydrogen sulfide and other sulfur compounds. Hydrogen sulfide emissions can
be controlled by requiring incineration or other equally effective means for all
process units. Approximately 95 to 99 percent of the sulfur compounds must
be removed from the process gas stream to meet this emission limitation. It
may be appropriate to consider exemption of very small units which
economically may not be able to achieve this level of control.
3.2 Sulfuric acid plants. The emission of sulfur oxides, calculated as sulfur
dioxide, from a sulfur recovery plant can be limited to 0.01 pound (kg) per
pound (kg) of sulfur processed. Approximately 99.5 percent of the sulfur
processed must be recovered to meet this limitation. Existing plants typically
recover 90 to 97 percent of the sulfur. This emission limitation corresponds to
a sulfur dioxide concentration of about 1300 ppm by volume.
4.0 CONTROL OF ORGANIC COMPOUNDS EMISSIONS
The following emission limitations are applicable to the principal stationary
source of organic compound emissions. Reducing total organic compound
emissions will reduce photochemical oxidant formation. Such control of
organic compound emissions may appropriately be considered in areas where
application of the Federal motor vehicle emission standards will not produce
the emission reductions necessary for attainment and maintenance of the
national ambient air quality standards for photochemical oxidants. These
50 PETROLEUM REFINING EMISSIONS
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emission limitations emphasize reduction of total organic compound emissions,
rather than substitution of "non-reactive" or "less reactive" organic com-
pounds for those already in use, because there is evidence that very few organic
compounds are photochemically non-reactive. Substitution may be useful,
however, where it would result in a clearly evident decrease in reactivity and
thus tend to reduce photochemical oxidant formation. The extent to which
application of these emission limitations would reduce photochemical oxidant
formation in a given air quality control region will depend on the "mix" of
emission sources in the region. These limitations are separable; i.e., one or more
portions can be considered, as necessary.
4.1 Storage of volatile organic compounds. The storage of volatile organic
compounds in any stationary tank, reservoir, or other container of more than
40,000 gallons (150,000 liters) can be in a pressure tank capable of maintaining
working pressures sufficient at all times to prevent vapor or gas loss to the
atmosphere. If this cannot be done, the tank can be equipped with a vapor loss
control device such as:
(a) A floating roof, consisting of a pontoon type, double-deck type roof or
internal floating cover, which will rest on the surface of the liquid contents and
be equipped with a closure seal or seals to close the space between the roof
edge and tank wall. This control equipment may not be appropriate if the
volatile organic compounds have a vapor pressure of 11 pounds per square inch
absolute (568 mm Hg) or greater under actual storage conditions. All tank
gauging or sampling devices can be gas-tight except when tank gauging or
sampling is taking place.
(b) A vapor recovery system, consisting of a vapor gathering system capable
of collecting the volatile organic compound vapors and gases discharged, and a
vapor disposal system capable of processing such volatile organic vapors and
gases so as to prevent their emission to the atmosphere and all tank gauging and
sampling devices can be gas-tight except when gauging or sampling is taking
place.
The storage of any volatile organic compound in any stationary storage
vessel more than 250-gallon (950 liter) capacity can be in a vessel equipped
with a permanent submerged fill pipe or fitted with a vapor recovery system.
This emission limitation will reduce volatile organic emissions 90 to 100
percent from uncontrolled sources of storage in vessels 40,000 gallon capacity
or greater and approximately 40 percent from uncontrolled sources of storage
in vessels 250 gallon capacity or greater.
4.2 Volatile organic compounds loading facilities. The loading of volatile
organic compounds into any tank, truck, or trailer having a capacity in excess
of 200 gallons (760 liters) can be from a loading facility equipped with a vapor
collection and disposal system. Also, the loading facility can be equipped with
a loading arm with a vapor collection adaptor, pneumatic, hydraulic or other
mechanical means to force a vapor-tight seal between the adaptor and the
hatch. A means can be provided to prevent drainage of liquid organic
Appendix B 51
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compounds from the loading device when it is removed from the hatch of any
tank, truck, or trailer, or to accomplish complete drainage before the removal.
When loading is effected through means other than hatches, all loading and
vapor lines can be equipped with fittings which make vapor-tight connections
and which close automatically when disconnected. This emission limitation wifl
result in 55 to 60 percent reduction in volatile organic emissions from
uncontrolled sources in gasoline marketing and other organic transfer
operations.
4.3 Volatile organic compounds water separation. Single or multiple
compartment volatile organic compounds water separators which receive
effluent water containing ?90 gallons (760 liters) a day or more of any volatile
organic compound from any equipment processing, refining, treating, storing
or handling volatile organic compounds having a Reid vapor pressure of 0.5
pound or greater can be equipped with one of the following vapor loss control
devices, properly installed in good working order and in operation:
(a) A container having all openings sealed and totally enclosing the liquid
contents. All gauging and sampling devices can be gas-tight except when
gauging or sampling is taking place.
(b) A container equipped with a floating roof, consisting of a pontoon
type, double-deck type roof, or internal floating cover, which will rest on the
surface of the contents and be equipped with a closure seal or seals to close the
space between the roof edge and container wall. All gauging and sampling
devices can be gas-tight except when gauging or sampling is taking place.
(c) A container equipped with a vapor recovery system consisting of a
vapor gathering system capable of collecting the organic vapors and gases
discharged and a vapor disposal system capable of processing such organic
vapors and gases so as to prevent their emission to the atmosphere and with all
container gauging and sampling devices gas-tight except when gauging or
sampling is taking place. This emission limitation will reduce organic
compound emissions from uncontrolled waste water separator units
approximately 95 to 100 percent.
4.4 Pumps and compressors. All pumps and compressors handling volatile
organic compounds can be equipped with mechanical seals or other equipment
of equal efficiency.
4.5 Waste gas disposal. Any waste gas stream containing organic compounds
from any ethylene producing plant or other ethylene emission source can be
burned at 1300 °F (704 °C) for 0.3 second or greater in a direct-flame
afterburner or an equally effective device. This does not apply to emergency
reliefs and vapor blowdown systems. The emission of organic compounds from
a vapor blowdown system or emergency relief can be burned by smokeless
flares, or an equally effective control device. This emission limitation will
reduce organic compound emissions approximately 98 percent.
52 PETROLEUM REFINING EMISSIONS
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5.0 CONTROL OF CARBON MONOXIDE EMISSIONS
The emissions of carbon monoxide can be limited by requring complete
secondary combustion of waste gas generated in such operations as a grey iron
cupola, blast furnace, basic oxygen steel furnace, catalyst regeneration of a
petroleum cracking system, petroleum fluid coker or other petroleum process.
6.0 CONTROL OF NITROGEN OXIDES EMISSIONS
6.1 Fuel burning equipment. The emission of nitrogen oxides, calculated as
nitrogen dioxide, from gas-fired fuel burning equipment can be limited to 0.2
pound per million B t.u. (0.36 gm/106 gm-cal) of heat input. This emission
limitation is about equivalent to a nitrogen dioxide concentration of 175
p.p.m., by volume, on a dry basis at 3 percent oxygen and represents about a
50 percent reduction in nitrogen oxide emissions from uncontrolled gas-fired
equipment.
The emission of nitrogen oxides, calculated as nitrogen dioxide, from
oil-fired fuel burning equipment can be limited to 0.30 pound per million
B.t.u. (0.54 gm/106 gm-cal) of heat input. This emission limitation is about
equivalent to a nitrogen dioxide concentration of 230 p.p.m. by volume, on a
dry basis, at 3 percent oxygen and represents about a 50 percent reduction in
nitrogen oxide emissions from uncontrolled oil-fired fuel burning equipment.
6.2 Nitric acid manufacture. The emission of nitrogen oxides, calculated as
nitrogen dioxide, from nitric acid manufacturing plants can be limited to 5.5
pounds per ton (2.8 kg/metric ton) of 100 percent acid produced. This
emission limitation is about equivalent to a nitrogen dioxide concentration of
400 p.p.m., by volume.
Appendix B 53
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BIBLIOGRAPHIC DATA
SHEET
4. Title and Subtitle
1. Report No.
EPA-650/2-73-017
3. Recipient's Accession No.
Atmospheric Emissions from the Petroleum Refining Industry
Report Dace
August 1973
6.
'. Author(s)
L. L. Laster
8. Performing Organization Kept.
. No.
Performing Organization Name and Address
Control Systems Laboratory
Environmental Protection Agency
National Environmental Research Center
Research Triangle Park, North Carolina 27711
10. Project/Task/Work Unit No.
Program Element 1A 2fJ13
Jll. Contract/Grant No.
In-house report
12. Sponsoring Organization Name and Address
13. Type of Report & Period
Covered
Final
14.
15. Supplementary Notes
16. Abstracts
As petroleum refining has developed in recent years into one of the leading industries
of the nation, with a growth rate of 4 to 8 percent annually, air pollution problems
have increased, though the corporations involved have, as a result of research,
produced control methods for some of the pollutants. The principal emissions from
refining operations are sulfur oxides, nitrogen oxides, hydrocarbons, particulates,
carbon monoxide, and odors. The estimated emissions of these pollutants (except for
odor per se) at the 262 refineries operating in the United States in 1969 totaled 7.04
million tons with substantial control excercised only in the case of hydrocarbons,
particulates, and carbon monoxide. In accordance with guidelines proposed by the U. S
Environmental Protection Agency for emissions from refinery operations, oil companies,
working in conjunction with trade organizations and equipment manufacturers, have
employed interim controls in many cases and have developed processes and devices for
at least reducing all pollutants from refineries.
17. Key Words and Document Analysis. 17a. IVscriptors
Sulfur oxides
Nitrogen oxides
Hydrocarbons
Emission
Air pollution
Refining
Crude oil
Pollution
17b. Identifiers/Open-Ended Terms
17c. COSATI F.e Id /Group
13b
18. Availability Statement
Release unlimited
•54-
19. Security Class (This
Report)
UNCLASSIFIED
T a *r.f_*_^-m~i ,„,,.»--.—
207 Security Class (This
Page
UNCLASSIFIED
21. No. of Pages
62
22. Price
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