EPA-650/2-73-017

August 1973        ENVIRONMENTAL PROTECTION TECHNOLOGY SERIES



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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

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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

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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

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     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

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   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

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                                  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

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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

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                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

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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

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                   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

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   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

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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
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          21. No. of Pages

                62
          22. Price
FORM NTIS-35 (REV. 3-7Z)
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