United States
Environmental Protection
Agency
Office of
Federal Activities
Washington, DC 20460
EPA 130/6-81-001-
October 1981
&EPA Environmentai
Impact Guidelines
For New Source
Petroleum Refineries
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EPA-130/6-81-001
October 1981
ENVIRONMENTAL IMPACT GUIDELINES
FOR NEW SOURCE
PETROLEUM REFINERIES
EPA Task Officer:
Frank Rusincovitch
US Environmental Protection Agency
Office of Federal Activities
Washington, D.C. 20460
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Preface
This document is one of a series of industry-specific Environmental Impact
Guidelines being developed by the Office of Federal Activities (OFA) for
use in EPA's Environmental Impact Statement preparation program for new
source NPDES permits. It is to be used in conjunction with Environmental
Impact Assessment Guidelines_for Selected New Source Industries, an OFA
publication that includes a description of impacts common to most industrial
sources.
The requirement for Federal agencies to assess the environmental impacts
of their proposed actions is included in Section 102 of the National
Environmental Policy Act of 1969 (NEPA), as amended. The stipulation that
EPA's issuance of a new source NPDES permit as an action subject to NEPA
is in Section 511(c)(1) of the Clean Water Act of 1977. EPA's regulations
for preparation of Environmental Impact Statements are in Part 6 of Title
40 of the Code of Federal Regulations; new source requirements are in
Subpart F of that Part.
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CONTENTS
Page
List of Tables v
List of Figures vii
INTRODUCTION 1
I. OVERVIEW OF THE PETROLEUM REFINING INDUSTRY 3
I.A. SUBCATEGORIZATION 4
I.B. PROCESSES 4
I.C. TRENDS 18
I.C.I. Locatlonal Changes 18
I.C.2. Raw Materials 22
I.C.3. Processes 24
I.C.4. Pollution Control 31
I.C.5. Environmental Impact 32
I. D. MARKETS AND DEMANDS 32
I.D.I. Refinery Capacity . \ 32
I.D.2. Incentives 35
I.D.3. Changes in Refinery Configuration 35
I.E. SIGNIFICANT ENVIRONMENTAL PROBLEMS 36
I.E.I. Location 36
I.E.2. Raw Materials 37
I.E.3. Process Wastes 37
I.E.4. Pollution Control 38
I.F. REGULATIONS 38
I.F.I. Water Pollution Standards of Performance 39
I.F.2. Air Pollution Performance Standards 50
I.F.3. Land Disposal of Wastes 56
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Page
II. IMPACT IDENTIFICATION 58
II.A. PROCESS WASTES (EFFLUENTS) 58
II.A.1. Various Liquid Waste Sources 58
II.A.2. Sources and Quantities of Process-Related
Wastes 62
II.A.3. Sources and Quantities of Wastewater from
Transportation Activities 63
II.B. PROCESS WASTES (AIR EMISSIONS) 63
II.C. PROCESS WASTES (SOLID WASTES) 68
II.D. TOXICITY AND POTENTIAL FOR ENVIRONMENTAL DAMAGE
FROM SELECTED POLLUTANTS 74
II.D.l. Human Health Impacts 74
II.D.2. Biological Impacts 78
I I.E. OTHER IMPACTS 78
II.E.l. Raw Materials Extraction and Transportation . . 78
II.E.2. Site Preparation and Refinery Construction . . 79
II.F. MODELING OF IMPACTS 79
III. POLLUTION CONTROL 85
III.A. STANDARDS OF PERFORMANCE TECHNOLOGY: IN-PROCESS
CONTROLS - WATER, AIR, SOLID WASTES 85
III.A.1. Cooling System 85
III.A.2. In-Process Physical/Chemical Pretreatment ... 86
III.B. STANDARDS OF PERFORMANCE TECHNOLOGY: END-OF-PROCESS
CONTROL (WATER STREAMS) 86
III.C. STANDARDS OF PERFORMANCE TECHNOLOGY: END-OF-PROCESS
CONTROL (AIR STREAMS) 87
III.D. STATE-OF-THE-ART TECHNOLOGY: END-OF-PROCESS CONTROLS
(SOLID WASTE DISPOSAL) 90
III.E. TECHNOLOGIES FOR CONTROL OF POLLUTION FROM CONSTRUCTION
SITES 98
ii
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PaSe
IV. OTHER CONTROLLABLE IMPACTS 100
IV. A. AESTHETICS 100
IV. B. NOISE 100
IV. C. SOCIOECONOMIC 101
IV.D. ENERGY SUPPLY 103
IV.E. IMPACT AREAS NOT SPECIFIC TO PETROLEUM REFINERIES ... 103
V. EVALUATION OF AVAILABLE ALTERNATIVES 104
V.A. SITE ALTERNATIVES 104
V.B. PROCESS ALTERNATIVES 105
V.C. NO-BUILD ALTERNATIVE 106
VI. REGULATIONS OTHER THAN POLLUTION CONTROL 107
VII. REFERENCES 108
GLOSSARY 115
ill
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LIST OF TABLES
Table Page
1 Subcategorization of the petroleum refining industry 5
2 Numerical distribution of petroleum refineries 6
3 Projected geographical distribution of new, expanded, or
reactivated U.S. refining capacity 19
4 Examples of typical compositions of representative crude oils. 23
5 Estimate percentage of petroleum refineries using various
manufacturing processes 25
6 Estimated percentage of petroleum refineries using various
wastewater treatment processes 33
7 Example of the application of the size and process configer-
ation factors 41
8 Standards of performance for new sources applicable to the
five subcategories of references 43
9 Applicable National Ambient Air Quality Standards 52
10 Nondeterioration increments for particulate matter and for SO2
by area air quality classifications 54
11 Qualitative evaluation of wastewater flow and characteristics
by fundamental refinery processes 64
12 Estimates waste loadings and volumes per unit of fundamental
process throughout for older, typical, and newer process
technologies 65
13 Types and magnitude of tanker casualties worldwide 66
14 Major air pollutants emitted from various refinery sources . . 59
15 Categorization of representative solid wastes from various
petroleum refining sources , . . , 70
16 Factors affecting the composition and quantity of specific
solid waste streams 71
17 Summary of pollutant sources and projected pollutant concen-
trations 75
18 Possible health problems associated with trace metals .... 76
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LIST OF TABLES (concluded)
Table Page
19 Outline of potential environmental impacts and relevant
pollutants resulting from site preparation and con-
struction practices
20 Efficiency of oil refinery waste treatment practices
based on effluent quality ^
21 Summary of emission control technologies currently in use
for various air pollutants generated from refinery
processes
vi
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LIST OF FIGURES
Figure Page
1 Processing plan for typical minimal refinery ........ 8
2 Processing plan for typical intermediate refinery 9
3 Processing plan for typical complete integrated refinery . . 10
4 Geographical locations of Petroleum Administration for
Defense Districts 20
5 Numbers of petroleum refineries within EPA regional juris-
dictions 21
6 Typical wastes produced in a complete petroleum refinery . . 59a
7 Sequence/substitute diagram of various wastewater treat-
ment system 88
8 Typical flare installation 91
9 Simplistic flow diagram for typical scrubbing system for
emission control from air-blown asphalt stills 92
vii
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INTRODUCTION
The Clean Water Act requires that EPA establish standards of performance for
categories of new source industrial wastewater dischargers. Before the dis-
charge of any pollutant to the navigable waters of the United States from a
new source in an industrial category for which performance standards have been
proposed, a new source National Pollutant Discharge Elimination System (NPDES)
permit must be obtained from either EPA or the State (whichever is the admin-
istering authority for the State in which the discharge is proposed). The
Clean Water Act also requires that the issuance of a permit by EPA for a new
source discharge be subject to the National Environmental Policy Act (NEPA),
which may require preparation of an Environmental Impact Statement (EIS) on
the new source. The procedure established by EPA regulations (40 CFR 6 Sub-
part F) for applying NEPA to the issuance of new source NPDES permits may
require preparation of an Environmental information Document (EID) by the permit
applicant. Each EID is submitted to EPA and reviewed to determine if there
are potentially significant effects on the quality of the human environment
resulting from construction and operation of the new source. If there are,
EPA publishes an EIS on the action of issuing the permit.
The purpose of these guidelines is to provide industry-specific guidance to
EPA personnel responsible for determining the scope and content of ElD's and
for reviewing them after submission to EPA. It is to serve as supplementary
information to EPA's previously published document, Environmental Impact
Assessment Guidelines for Selected New Source Industries, which includes the
general format for an EID and those impact assessment considerations common
to all or most industries. It also includes Appendix B-2 which covers the
petroleum refining industry. Both that document and these guidelines should
be used for development of an EID for a new source petroleum refinery.
These guidelines provide the reader with an indication of the nature of the
potential impacts on the environment and the surrounding region from construc-
tion and operation of petroleum refineries. In this capacity, the volume is
intended to assist EPA personnel in the identification of those impact areas
that should be addressed in an EID. In addition, the guidelines present (in
Chapter I) a description of the industry, its principal processes, environ-
mental problems, and recent trends in location, raw materials, processes,
pollution control and the demand for industry output. This "Overview of the
Industry" is included to familiarize EPA staff with existing conditions in
the industry.
Although this document may be transmitted to an applicant for informational
purposes, it should not be construed as representing the procedural require-
ments for obtaining an NPDES permit or as representing the applicant's total
responsibilities relating to the new source EIS program. In addition, the
content of an EId for a specific new source applicant is determined by EPA
in accordance with Section 6.604(b) Title 40 of the Code of Federal Regula-
tions and this document does not supersede any directive received by the
applicant from EPA's office responsible for implementing that regulation.
The guideline is divided into six sections. Chapter I is the "Overview of the
Industry," described above. Chapter II. "Impact Identification, discusses
process-related wastes and the impacts that may occur during construction and
1
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operation of the facility. Chapter III, "Pollution Control," decribes the
technology for controlling environmental impacts. Chapter IV discusses other
impacts that can be mitigated through design considerations and proper site
and facility planning. Chapter V, "Evaluation of Alternatives," discusses
the consideration and impact assessment of possible alternatives to the pro-
posed action. Chapter VI, describes regulations other than pollution control
that apply to the industry.
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I. OVERVIEW OF THE PETROLEUM REFINING INDUSTRY
Standard Industrial Classification (SIC) Code 2911 defines a petroleum
refinery as a complex combination of interdependent operations engaged in
the separation of crude oil by molecular cracking, molecular rebuilding and
solvent finishing to produce a varied list of intermediate and finished
products that include gasoline, jet fuel, fuel oil, "lube" oil*,
grease, asphalt, coke and wax among others. About 120 companies are
engaged in petroleum refining in the United States.
As of January 1978 there were 285 operating refineries in the US with a
daily production capacity of approximately 16.9 million barrels per calendar
day (B/CD). About 55% of these or 158 were constructed between 1944 and
1970. Production capacity ranges from 150 B/CD to 640,000 B/CD. More than
one-third of US refineries have a capacity of less than 10,000 barrels per
day, but together these refineries account for only 2.5% of the total
capacity of the industry. Refineries with a rated daily capacity greater
than 150,000 barrels, make up about 9% of the total number of US refineries
and account for about 43% of the total industry capacity. Total annual
employment for the industry is approximately 140,000, and total industry-
wide sales for domestically consumed petroleum products were estimated to
be $40 billion in 1978. The state of Texas has the highest concentration
of refineries; the 53 facilities there make up 18.8% of the national total.
California has 40 refineries, and Louisiana, Illinois, Kansas, Oklahoma,
Pennsylvania, and Wyoming have 10 or more each. Refining capacity of indi-
vidual states roughly parallels the number of facilities.
*See Glossary for discussion of technical terms
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I.A. SUBCATEGORIZATION
The processes by which crude oil is manufactured into a multitude of products
are numerous and complex. Crude oils from different sources themselves vary
importantly, and refineries are often designed especially to process crude
from a particular source. Refineries also differ widely not only in size but
in the number and sophistication of the processes they employ and the variety
of products they produce. While some can produce a wide range of items, from
fuel gas and LPG through gasoline and olefins to greases, asphalt and coke,
the simpler operations of others may limit their output to a few items such
as fuel gas, gasoline blending stocks and heavy fuel oil.
In order to classify refineries for the purpose of setting standards for
limitations on effluents that may be discharged and establishing new source
performance standards (i.e. effluent standards for new refineries), EPA has
subcategorized refineries by processes employed. This approach is practical
because raw waste load characteristics are related to process complexity rather
than of capacity.
A description of the separate subcategories and a numerical distribution of
petroleum refineries by subcategory (1976 data) are presented in Tables 1 and
2, respectively. Processes named in the tables are discussed in the following
section.
I.B. PROCESSES
The key components of various refinery processes and their capacities are
described in this section and process flow diagrams are provided to indicate
the different levels of sophistication in refinery processes. Definitions of
technical terms may be found in the glossary at the end of this report.
Crude oil consists of a large number of separate organic compounds whose
properties are primarily dependent on the number of carbon atoms that they
contain. Increasing numbers of carbon atoms result in higher boiling points,
and the first step in the refining process is to separate the crude by dis-
tillation into several fractions according to boiling point range. The high-
est boiling fraction, which exists as a gas at normal conditions, consists of
methane, having a single carbon atom, as well as molecules ranging from 2 to
4 carbon atoms. These components of the first, or gas fraction are used as
fuel gas, LPG (liquified petroleum gases, mainly propane and butane), and as
building blocks in petrochemical processes. The next higher-boiling fractions,
called naphtha and kerosene, are used in the production of gasolines and jet
fuels, and contain components in a range centering around 7 carbon atoms. The
next higher-boiling fraction? middle distallates, is the stock from which
diesel and light fuel oils are made. The still higher boiling fractions be-
come the heavier fuel oils and lubricating oils.
While some of these initial fractions, e.g. heavy fuel oil, may be satisfac-
tory as final products, most require additional processing. This may be
further separation, solvent finishing, or reforming in the presence of a
catalyst. Or it may involve the second and third major refinery processes —
cracking, and conversion or reconstruction. In these, the fractions are con-
verted to saleable products by cracking (i.e., splitting their molecules) then
4
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Table 1. Subcategorization of the petroleum refining industry.
Subcategory Basic Refinery Operations Included
Topping
Topping and catalytic reforming whether or not the facility
includes any other process in addition to topping and
catalytic reforming. This subcategory is not applicable to
facilities which include thermal processes (coking, vis-
breaking, etc.) or catalytic cracking.
Cracking
Petrochemical
Lube
Integrated
Topping and cracking whether or not the facility includes
any processes in addition to topping and cracking, unless
specified in one of the subcategories listed below.
Topping, cracking, and petrochemical operations^- whether
or not the facility includes any process in addition to
topping, cracking, and petrochemical operations except lube
oil manufacturing operations.
Topping, cracking, and lube oil manufacturing processes
whether or not the facility includes any process in addition
to topping, cracking, and lube oil manufacturing processes
except petrochemical and integrated operations.
Topping, cracking, lube oil manufacturing, and petrochemical
operations whether or not the facility includes any processes
in addition to topping, cracking, lube oil manufacturing,
and petrochemical operations.
1
The term "petrochemical operations" means the production of second generation
petrochemicals, i.e., alcohols, ketones, cumene, styrene, etc., or first
generation petrochemicals and isomerization products, i.e., BTX, olefins,
cyclohexane, etc., when 15% or more of refinery production is as first generation
petrochemicals and isomerization products. Owing to the diversity and complex-
ity of the petrochemical processes and associated impacts, this subcategory
will be the subject of a separate appendix. It is included here because it is
an official subcategory of the petroleum refining industry.
Source: U.S. EPA. 1977. Interim final supplement for pretreatment to the
development document for the petroleum refining industry. Existing
point source category EPA 440/1-76/083A.
5
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Table 2. Numerical distribution of petroleum refineries by subcategory
(data from 1976).
Subcategory Indirect Dischargers Total Industry
# % of total If T~of total
A -
Topping
10
38
96
38
B -
Cracking
13
50
111
43
C -
Petrochemical
2
8
19
7
D -
Lube
0
0
22
9
E -
Integrated
1
4
8
3
Sources: Contrell, Aileen. 1976. Annual refining survey. The Oil and Gas
Journal, 29 March, pp. 125-152.
National Commission on Water Quality. 1975. Petroleum refining
industry, technology and costs of wastewater control. Prepared by
Engineering Science, Inc.
6
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rearranging the molecular structure. Middle distillate and fuel oil fractions
are often processed to break them up into smaller components (cracking) to
increase the yield of gasolines and other light products. The heavy residues
can be used directly as residual fuel oils, or processed to give lighter frac-
tions .
Most products require treatment to remove, or inhibit activity by undesirable
components. Lastly, refined base stocks, blended with each other and with
various additives, are developed into useful products.
Figures 1,2 and 3 show the processing plans for typical minimal, intermediate
and complete petroleum refineries respectively. "Topping," that is, separation
of the crude by distillation, is the first step for all. Simple refineries
(Figure 1) separate the crude and perform limited treating. Immediate refin-
eries (Figure 2) use catalytic or thermal cracking, catalytic reforming, and
additional treating to produce the gasolines and LPG not produced in the
simple refineries and also to manufacture heavy products such as lube (lubri-
cating) oils and asphalt. Complete large refineries distill and crack the
crude oil, treat process gas, upgrade gasoline by catalytic reforming, alkyl-
ation, and isomerization, and manufacture lube oils, asphalts, and waxes
(Figure 3).
Auxiliary systems perform other functions in petroleum refineries. Examples
of these are: supplementary treatment units to purify both liquid and gas
streams; waste management and pollution control systems; cooling water systems;
units to recover hydrogen sulfide (H„S) from gas streams and to convert it
into elemental sulfur or sulfuric acid; electric power support stations;
steam-producing facilities; and storage and handling of crude oil and by-
products.
Description of the processes involved in the production of one type of fuel
product will illustrate the nature of complex refinery operations and the
nature of the problems that relate to refinery effluents. The following dis-
cussion therefore focuses on the basic unit processes for the manufacture of
fuel products in the US refinery industry^. Discussions of operations for the
manufacture of lubricating oils, waxes, solvents, road oils, asphalt, petro-
chemicals, and other nonfuel products may be found in Hobson et al (1973)
and other references.
The three basic functions performed by most refineries, and the basic unit
processes by which they may be accomplished in the manufacture of fuels are
as follows:
Separation of the various components or crude oil by boiling
point
— Distillation or fractionation
Splitting large molecules Into smaller ones
— Catalytic cracking
— Catalytic hydrocracking
— Thermal cracking
Outside the US the use of gasoline-creating processes e.g. catalytic
cracking, alkylation and catalytic hydrocracking (in refineries) is less
common.
7
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00
Figure 1. Processing plan for typical minimal refinery.
Source: U.S. EPA. 1972. Evaluation of waste waters from petroleum and coal
processing. Office of Research and Monitoring. R2-72-001. Washington DC.
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Wet gas
VO
Crude oil
Fuel gas
*— LPG
Motor gas
Aviation gasoline
Catalytic gasoline
Kerosine
*- Light fuel oil
and
diesel fuel
Lube stocks
*- Wax stocks
*- Asphalt
Heavy fuel oil
Figure 2. Processing plan for typical intermediate refinery.
Source: U.S. EPA. 1972. Evaluation of waste waters from petroleum and coal
processing. Office of Research and Monitoring. R2-72-001. Washington DC.
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Dry gos
Wet gas
Light naphlho
o
c
ci
a.
o
a»
"C
O
Heavy naphtha
Raw kerosine
Middle ditillates
Crude oil
Heavy gas oil
1
Reduced
crude
Voc gos
oil
Gos plants
Saturate
ond
unsaturate
Hydro-
crocking
unit
Jl
Cotoly t>C
cracking
unit
cracked
Lube distillates
Residuum
Hydrogen
h
Cotalytic
reforming
unit
H2S
1"
-»~{Poly plant
Alkylpti
on
| Poly gasoline
Alkylate
Straight run gasoline
¦Light hydrocrocked gasoline
Hlz_
Hydrogen
treating
unit
Hvy hydro-
—' crocked
gasoline
Hydrogen
Dry gos »
i Reformate
Hydrogen
plont
sulfide
Go soling
Sulfur plont
r-^Coker gosoime
Gasoline
trealer
Catalytic gasoline
C7
Light fuel oil
Asphalt
Still
JCoker
l"
Lube
processing
.
L.
r i;i>i gos
LPG
Moto' gaso'me
Aviation gor.C'.nf'
Olefins to
chemical
Kerosme
Lig''l fuel oil
Diesel fuel
Sulfur
Lubes
Woncs
Greases
Heavy fuel oil
Asphalt
Coke
Figure 3. Processing plan for typical complete refinery.
Source: U.S. EPA. 1972. Evaluation of waste waters from petroleum and coal
processing. Office of Research and Monitoring. R2-72-001. Washington DC.
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Reconstruction of molecules
— Hydrotreating
— Alkylation
— Polymerization
— Isomerization
— Reforming
Treating
— Gas concentration
— Solvent refining
The descriptions below focus on the basic function of the aforementioned
unit processes and the relationships between them.
I.B.I. Desalting of Crude Oil
Crude oil frequently contains brine from underground deposits. To minimize
corrosion of refining equipment, the crude is usually put through a desalter,
which reduces the inorganic salt content of the oil before it enters the
distillation unit. This brine is removed in settling towers, usually at
elevated temperatures 90 - 145 C (200 - 300 F) and at elevated pressures
3.4 - 17 atmospheres (50 - 250 pounds per square inch). The towers are
packed with sand, gravel, or excelsior. Caustic is sometimes added to ad-
just pH. In other cases, an electrical field (16,500 - 33,000 volts) is
applied across the vessel to cause droplets to coalesce more rapidly. Chemi-
cals (modified fatty acids, partly wholly saponified with ammonia, oil-
soluble petroleum sulfonate, water-soluble solvents, oil-soluble solvents
or inorganic sulfates) are used to improve the efficiency of desalting.
Salt concentrations in raw crude oil vary widely, from nearly zero to hun-
dreds of kilograms of sodium chloride (NaCl) per 1,000 bbl. The salt removed
from the crude are usually an important waste product.
I.B.2. Crude Oil Distillation
Distillation is the process of producing a gas or vapor from a liquid by
heating the liquid in a vessel and collecting and condensing the vapors into
liquids. In a petroleum refinery it is a method of separation. The crude oil
is distilled at the lowest boiling point and the distillate is collected as
one fraction. As the next high-boiling component begins to distill, it is
then collected as a separate fraction, and the process, sometimes called
"fractional distillation," continues. The fractions are then processed
appropriately in later stages to make specific products.
The term "fractionation" means separation of a mixture in successive stages,
each stage removing from the mixture some proportion of one of the substances,
as by distillation, or by differential solubility in water-solvent mixtures.
"Topping" refers to the distillation of crude petroleum to remove the light
fractions only. However, the crude distillation unit in a refinery is called
the "topping unit."
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In the atmospheric pressure distillation action of the-it, ^ ^e oil
is heated to a temperature at which it is pa bottom Df a distillation
introduced near, but at some distance above the bottom o through
column. This cylindrical Eac£ "ay ^on-
liquid can flow continuously by gravity in a downward
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By vacuum flashing
— Heavy fuel oil having a boiling range of 343 - 566 C
(650 - 1050°F)
— A nondistillable residual pitch
Of the components in modern gasoline pools the light straight-run fraction
has the lowest octane number (anti-knock rating). Its unleaded octane
number, in a typical case, will be just under 70, and the unleaded octane
number for the entire refinery pool (based on US average) will be about 89.
The light straight-run fraction has a good octane number response to addi-
tions of lead alkyls.
I.B.3. Reforming
Reforming is the rearranging in the presence of a catalyst of hydrocarbon
molecules in a gasoline boiling-range feedstock to form hydrocarbons having
a higher antiknock quality.
In order to raise the octane rating of the heavy naphtha fraction (Figure 1)
(which varies with the crude source but which normally ranges from 40 to 50)
so that it will be a suitable component for blending into finished gasoline
pools, the chemical composition of the fraction must be changed. This is
usually accomplished by catalytic reforming.
It should be noted that practically all naphtha stocks fed to catalytic re-
forming units are hydrotreated to remove or inactivate arsenic, sulfur and
nitrogen compounds that would deactivate the catalyst.
The resulting naphtha, called reformate, is then fed into the gasoline blend-
ing pool.
Byproducts of this process include hydrogen, which is used in hydrotreating
and whenever hydrocracking may be practiced in the refinery.
Reforming of natural gas or light naphtha fractions with steam also produce
hydrogen.
I.B.4. Catalytic Cracking
Catalytic cracking is the conversion of high-boiling hydrocarbons into
lower-boiling types by a catalyst.
A distilled gas-oil charge is fed at elevated temperatures from 460 - 515°C
(860 - 955 F) in a catalyst bed (usually silica-alumina) in which the feed
is converted to simpler hydrocarbons usually of a higher octane number.
Light olefin is usually produced as a byproduct. The catalyst arrangement
(fixed bed, fluid bed, multiple bed, single bed, etc.) varies but the
catalyst is always regenerated.
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The primary function of catalytic cracking is to convert into gasoline those
fractions having boiling ranges higher than that of gasoline which after
treatment for odor control, are blended with other gasoline stocks. An
important secondary function is to create light olefins such as propylene
and butylenes, to be used as feedstocks for motor-fuel alkylation and petro-
chemical production. Although the principal feedstock is the gas oil
separated from the crude by distillation, this feed often is supplemented
with light distillates and with distillate fractions which result from
thermal coking operations.
For practical reasons, the cracking of distillate feedstock to lighter
materials is not carried to completion. The remaining, uncracked distil-
lates (cycle oils) are usually used as components for domestic heating
fuels (generally after hydrotreating) and to blend with residual fractions
to reduce their viscosity to make acceptable heavy fuel oil. In some
refineries, however, cycle oils are hydrocracked to complete their con-
version to gasoline.
The principal products then, are gasolines, whose unleaded octane numbers
range from 89 to 93, and light olefins. Another product is isobutane, a
necessary reactant for the alkylation process.
I.B.5. Hydrocracking
In a sense, hydrocracking is complementary and supplementary to catalytic
cracking because hydrocracking occurs over a catalyst in a hydrogen environ-
ment with heavy distillates and, in some cases, with cycle oils which are
impractical to convert completely in catalytic cracking units. The purpose
of hydrocracking is to produce additional gasoline stock from heavy
materials. The process also takes place at lower temperatures and higher
pressures than fluid catalytic cracking. Generally, the C5-Cg fraction is
blended into the gasoline pool and occasionally the heavier portion of the
gasoline also is blended into the gasoline pool although the primary pro-
ducts are gasoline or jet fuels and other light distillates. An important
secondary product is isobutane. Sometimes this portion is reformed first,
to improve its octane number. Figure 3 shows only heavy gas oil as a
feedstock, and in the figure the entire liquid product as gasoline is routed
directly to the refinery gasoline pool even though the aforementioned options
are performed widely in various combinations.
I.B.6. Thermal Cracking
The heavy fractions, as produced by most vacuum-flashing units, are too viscous
to be marketed as a heavy fuel oil without further treatment. In some refiner-
ies the pitch processing in a thermal cracking unit (visbreaking) at relatively
low temperatures and short contact times will reduce its viscosity sufficiently.
Additional viscosity reduction is obtained by blending in catalytically produced
oil to produce marketable residual fuel oil.
14
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In certain situations it is more economical to process the pitch in a thermal
coking unit from which the main products are gasoline, distillates, and coke.
The gasoline from a coking unit is handled as previously described. The coke
can be used, after calcination, for electrode manufacture where it meets
certain purity specifications, but the coke is used principally as a metal-
lurgical coke or fuel. Distillates from thermal coking operations may be
used as feedstock for catalytic cracking or the lighter distillates may be
routed to the refinery distillate produce pool hydrotreatment.
A few refiners obtain additional feedstock for catalytic cracking or hydro-
cracking operations by solvent extraction of the vacuum pitch, usually with
propane as the solvent. The extract is relatively free of organometallic
compounds and highly condensed aromatic structures hydrocarbons which are
difficult to crack. Thus, the extract is suitable for handling by catalytic
units. Extracted pitch is processed subsequently in thermal units or converted
to asphalts.
The small amount of thermal gasoline which is made as a byproduct is routed
after treatment to the gasoline pool or to catalytic reforming through a
hydrotreating unit because its octane number is relatively low.
I.B.7. Hydrotreating
As a processing tool hydrotreating has numerous applications in a refinery,
where its principal function is to saturate olefins and convert oxygen, sulfur
and nitrogen to compounds that can be removed. It also converts other impur-
ities such as arsenic to more easily removable compounds. The process employs
hydrogen and a catalyst. The use of hydrotreating for pretreating naphthas
prior to catalytic reforming has been already mentioned.
Figure 3 shows hydrotreatment of the crude light distillate (kerosine middle
distillate) and the catlytic cycle oil in a single block before being routed
to the refinery light distillate pool. Occasionally the light distillate in
the crude may be sufficiently low in sulfur content to bypass hydrotreating;
usually, however, part of the stream must be hydrotreated to remove native
sulfur compounds. Some refineries hydrotreat parts of their catalytic cracking
feeds, particularly if they originate from thermal operations or if they are
inordinately high in sulfur content.
Desulfurization is also an objective in the production of low sulfur residual
fuel oils. Sulfur content of reduced crudes (>4%) can be reduced to about
1% by vacuum flashing, hydrodesulfurizing the overhead vacuum-distilled gas
oil, and blending the gas oil of low sulfur content with the untreated pitch
to obtain a reconstituted low-sulfur fuel oil.
I.B.8. Gas Concentration
The gas concentration system (Figure 3) collects gaseous product streams from
various processing units and physically separates the components to provide,
usually, a C3/C4 stream as a feedstock for alkylation and a C2 and lighter
stream that largely is used to supply process heat (requirements) for the
refinery.
15
-------
Hydrogen sulfide is removed from gas streams in which it occurs by selective
absorption in liquid solutions (usually organic amines). The H2S released
from the rich solution is converted by further processing into elemental
sulfur or H2SO4 (sulfuric acid).
I.B.9. Alkylation
In motor fuel refineries the alkylation units produce a high quality par-
affinic gasoline by the chemical combination of isobutane with propylene
and/or butylenes. A small amount of pentenes is also alkylated. The alky-
lation is accomplished with the catalytic aid of hydrofluoric (HF) or sulfuric
acid (HoSO/) to produce a gasoline with octane numbers that range from 93 to
95.
Propane and n-butane associated with the olefins in the feedstocks are with-
drawn from alkylation units as byproducts. Part of the n-butane is routed
to the gasoline pool to adjust the vapor pressure of the gasoline to a level
which permits prompt and easy starting of engines. The remainder of the
n-butane and the propane is available for liquified petroleum gas (LPG), a
clean fuel that easily is distributed as bottled gas for heating purposes.
I.B.10. Polymerization
Polymerization, in an oil refinery, involves the combination of small mole-
cules (i.e., ethylene) into somewhat larger compounds (Cg and higher) including
cyclic compounds such as benzene and tolune.
Polymerization may be carried out thermally in the vapor phase at 510-595°C
(950-1100°F) for extended periods of time. Reaction pressures are about
170 atmospheres (2500 psig ) with a yield of 62 - 72% by weight.
Catalytic polymerization is carried by in the presence of phosphoric acid or
other catalysts (silica - alumina, aluminum chloride, boron triflouride and
activated bauxite). Phosphoric acid is used in three forms (quartz wetted
with liquid acid, acid-impregnated pellets and solid catalyst pellets) packed
in tubes surrounded with cooling water. This process operates at pressures
of 17-60 atmospheres (250-900 psig ) and temperatures of 155-230°C (310-450°F).
I.B.ll. Isomerization
In this process, normal parafinns are converted to branched chain paraffins
in order to produce higher octane gasoline. Aluminum chloride is the principal
catalyst used for this purpose. Temperatures range from 80-130°C (180-270°F)
with pressures of 13—20 atmospheres (200—300 psi).
I.B.12. Reforming
Reforming is a process in which a variety of complex and cyclic hydrocarbons
are converted to hydrocarbons which produce better gasoline and does so with
a much lower use of catalysts.
16
-------
Platinum and molybdenum are used to produce the following changes:
• Naphthalene dehydrogenation (removal of hydrogen)
• Naphthalene dehydroisomerization (removal of hydrogen and isomeriza-
tlon)
• Paraffin dehydrocyclization (removal of hydrogen and oxygenation
of paraffins)
• Paraffin isomerization
• Paraffin hydropacking
• Olefin hydrogenation (addition of hydrogen to unsaturates)
• Hydrodesulfurization (addition of hydrogen and elimination of sulfur)
Catalyst
Process
Changes
Platinum
Naphthalene dehydrogenation
Removal of
hydrogen
Platinum
Naphthalene
dehydroisomorization
Removal of
hydrogen and
isomerization
I.B.13. Coking
Coking is a process in which contact times are lengthened in a thermal cracker
so that polymerization or condensation products are produced. However, only
the most degraded carbonaceous high-boiling parts of the cracking reaction are
exposed. Coking takes place at temperatures over 435°C (820°F). The main
purpose of coking is the production of coker gas oil which is charged to cata-
lytic or thermal crackers. In addition, coke is heated in kilns at 590-650°C
(1100 - 1200°F) to produce artificial graphite.
I.B.14. Asphalt Production
Asphalt is produced by vacuum flashing of hot cracked tar as part of the
cracking operation or from the steam distillation of various stages. The
quality of asphalt can be improved by air blowing with the use of ferric
chloride or phosphorous cutoxide. Heavy topped crude oil or vacuum reduced
residue is heated to within 30°C (50°F.) of its flash point and blown with
1-1.6 cu. meters/minute/metric ton (30-50 cu. ft./minute of air/ton of
asphalt)over a period from 1.5 to 2.4 hours.
I.B.15. Catalyst Regeneration
Solid catalysts used in cracking are thermally regenerated by air blowing
followed by a nam purge with steam jet ejectors. This is carried out either
in the catalyst reactor bed or in a separate regeneration unit.
I.B.16. Lube Oil Production
Reduced oxide is taken to a vacuum fractionator where gas oil is removed.
The various fractions other than the residual is sent to solvent extraction
where various solvents (i.e., phenol, forfural) and used to recover the lube
oil fraction. This is then sent to a solvent dewaxing unit where propane or
17
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methyl ethyl ketone is used to remove wax. The produce is heated with clay
to remove acid values.
I.B.17. Propane Deasphaltlng
Propane is used to separate asphalt from oils. The propane is used to ex-
tract oil from asphalt producing a higher quality product than vacuum dis-
tillation. The process is basically an extraction process at temperatures of
70-90°C (160-190°F) and a pressure of 27-41 atmospheres (400 - 600 psi) .
I.C. TRENDS
I.C.I. Locational Changes
US refineries are concentrated largely in areas of major crude production
(California, Texas, Louisiana, Oklahoma, and Kansas) and in major population
areas (Illinois, Indiana, Ohio, Pennsylvania, Texas, and California) (us EPA
1973). Projected geographic growth patterns of new refineries by Petroleum
Administration for Defense (PAD) Districts through 1981, shown in Table 3,
indicate little change in this locational pattern.
The majority of 1977 growth was in PAD District III, as shown in Figure 4.
Host of this growth occurred in Texas and Louisiana. The next largest growth
was in PAD District V where California accounted for the largest increase in
new and expanded capacity. Alaska, however, had one new and one expanded
refinery. Texas and Louisiana continue to lead the growth trends through
1981. Outside those states a new 175,000 bbl/day facility in Portsmouth,
Virginia, in 1980 and a 250,000 bbl/day refinery in Eastport, Maine, in 1981
are the largest planned capacity additions. Large new projects not reflected
in Table 3 which are in early or uncertain stages of planning include
(FEA 1977) :
200,000 bbl/day at Baltimore, Maryland
250,000 bbl/day at Sanford, Maine
200,000 bbl/day at Oswego, New York
400,000 bbl/day at Sagbrook, Connecticut
PAD Districts are anachronisms relating to the old Petroleum Administration
for Defense which ceased to exist many years ago. The districts are shown
geographically in Figure 4. Figure 5 presents the concentrations of
petroleum refinery operations by EPA regional office jurisdictions.
In short, the consenses among industry representatives is that little or no
significant change is expected to occur in locational patterns unless sub-
stantial quantities of oil are discovered and produced offshore on the East
Coast (Interview, Mr. Eugene Peer, Office of Oil and Gas, DOE, 18 April 1978).
18
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Table 3 . Projected geographical distribution
of new, expanded, or reactivated U.S.
refining capacity by PAD District
(thousands of bbl/day, crude
distillation).
Total New, Expanded, or
Reactivated Capacity
1977
1978
1979
1980
1981
PAD Region I
-
12.0
24.0
199.0
274.0
PAD Region II
2.5
36.0
101.0
61.0
52.0
PAD Region III
478.2
117.0
181.0
284.0
84.0
PAD Region IV
24.5
9.4
8.0
8.0
8.0
PAD Region V
84.1
41.0
32.0
32.0
32.0
Source: Peer, E. L., et al. 1977. Trends in refinery capacity and utilization.
Federal Energy Administration, FEA/G-77/281. June.
19
-------
Figure 4. Geographical locations of Petroleum Administration
for Defense (PAD) Districts.
Source: Peer, E. L. , et al. 1977. Trends in refinery capacity and utilization.
Federal Energy Administration, FEA/G-77/281. June.
20
-------
Regional Offic es
to
H'CO
Source: U.S. EPA. 1976. Assessment of hazardous waste practices in the petroleum refining industry.
Prepared by Jacobs Engineering Company. NTIS PB-259-097. Springfield VA.
Figure 5. Numbers of petroleum refineries within EPA regional jurisdictions
(Arabic numbers indicate number of refineries in each region).
-------
I.C.2. Raw Materials
Crude oil is by far the most important raw material used by the refining
industry. Natural gasoline, a liquid product of the natural gas industry,
furnishes about 5% of refinery intakes. Butanes contribute about 1.5% of
refinery intake. No other significant raw materials exist. As of 1976,
about 73% of the industry's raw material was of domestic origin; 27% was
imported. Recent statistics indicate that 1978 will mark the first time
since 1970 that crude oil imports have dropped from the previous year,
permitting a temporary decrease in U.S. dependence on foreign sources. The
volume of crude imports anticipated in 1978 is the combined result of slower
growth in oil demand and increased domestic crude production (Oil and Gas
Journal 1978). The composition of crude oil is becoming increasingly
important because of its effect on air quality and industry economics. How-
ever, changes in the composition of crude oil supplies have shown a trend
toward higher sulfur crudes. Table 4 presents examples of typical com-
positions of several representative crude oils. (For a detailed analysis of
crude oils see McKinney et al. (1966) and McKinney and Shelton (1967).
In 1975 OPEC sour crude reserves (> .5% sulfur) were 5.5 times greater than
sweet crudes ( <.5% sulfur). In addition, the reserves to production ratio
of sour crudes was 49 versus 33 for sweet crudes, indicating that currently
sweet crude reserves are being used at a higher rate than sour crude re-
serves. This trend accelerated significantly through 1977 and is expected
to continue for the near future (US-DOE 1977).
More dramatic changes have occurred in the United States than in OPEC
countries concerning reserves of sweet and sour crudes. In 1964, 64% of all
U.S. crude oil reserves were in the sweet crude category. In the same year
66% of the production was sweet crude. The discovery of the Prudhoe Bay
field in Alaska has resulted in only 42% of 1975 crude oil reserves being
categorized as sweet.
In 1978, production in the U.S. is showing a significant increased percentage
of sour crude. Another factor giving impetus to this shift will be improved
sulfur recovery processes. In California this is reflected in more production
of heavy, high sulfur crude oils.
Short of any unforeseen large discoveries, it is expected that the world's
refineries will rely increasingly on sour crude supplies.
Despite the proportionately greater reserves and the production of sour crudes,
the U.S. continues to rely heavily on sweet crude imports. During the period
from 1969 through 1977, the percentage of crude oil imports that were sweet
ranged from a high of 66.95% (1972) to a low of 54.7% (1977). During the
same period crude oil Imports increased from 2.2 million barrels per day to
6.6 million barrels per day. Although the percentage of sweet crude has
dropped, the actual volume of sweet crude imports is increasing each year
(US-DOE 1977).
Recently the increased sweet crude imports have originated primarily in OPEC
sources. During 1969, the U.S. imported only 5% of OPEC's sweet crude pro-
duction; however, in 1976 the percentage increased to 37.57, and during the
22
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Table 4. Examples of typical compositions of representative
crude oils.
California
Viscosity Gasoline Kerosine
Saybolt, at Carbon Anonaphtha Distillation
Gravity Sulfur 100°F, Residuum Vol. Gravity Vol. Gravity
°API Wt.% seconds Wt.% % °API % °API
Brea Olinoa
Elk Hills
Torrance
24.0
22.8
23.8
0.75
0.68
1.84
135
135
160
14.2
4.6
13.2
17.4
11.1
17.9
51.3
49.9
52.5
-
-
Louisiana
Black Bay
Grand Isle
West Delta
30.0
36.4
27.0
0.27
0.18
0.33
57
40
92
6.3
3.7
5.7
15.2
25.8
9.5
54.2
54.7
50.9
5.5
15.0
4.7
42.1
11.7
40.0
Oklahoma
Bradley
Golden Trend
Sho-Ven-Tu
35.0
42.1
29.1
0.22
0.11
1.36
56
39
87
6.7
2.7
10.1
24.3
34.6
21.2
57.4
62.9
59.5
15.6
17.1
4.3
43.0
42.8
42.8
Texas
Conroe
East Texas
Walnut Bend
37.0
37.4
46.0
0.10
0.25
0.23
36
42
38
4.9
6.1
3.3
32.8
33.9
38.3
48.8
58.2
64.5
5.0
16.5
42.8
43.4
Libya
39.2
0.33
40
7.6
36.6
59.9
12.2
43.4
Indonesia
36.8
0.10
35
3.8
37.1
52.5
-
-
Iran
34.6
1.43
46
9.1
28.8
60.8
10.2
43.2
Iraq
36.6
1.93
42
14.6
35.5
63.7
9.8
44.5
Saudi Arabia
33.6
1.66
49
11.3
27.8
62.3
9.9
44.7
Venezuela
14.7
2.62
310
9.6
5.7
45.6
-
-
Source: McKinney, et al. 1966. Analyses of crude oils from 546 important oil fields
in the United States. Prepared for US-DOI. Bureau of Mines Report of
Investigations 6819. Available US-GPO, Washington, D.C.
23
-------
first quarter of 1977 it increased to 42%. By contrast, during the same 4-
month period in 1977, the U.S. imported only 12.4% of OPEC's sour crude pro-
duction (US-DOE 1977).
I.C.3. Processes
As in most industries, trends in process change are likely to be closely tied
to or motivated by pollution control requirements. This is true because few
industrial processes can be altered significantly without introducing some
effect on waste generation. If a process change improves efficiency, is
cosL-eflective, and does not adversely effect waste generation, it normally
has high use potential. In contrast there must be significant tradeoffs in
process change efficiency and economy to tolerate generation of additional
or more complex wastes, since the treatment or control of these wastes would
tend to offset the benefits. Commonly, process change is effected because
its improved efficiency and economy lie not solely in its own performance per
se, but in reduced waste generation. Therefore trends in internal pollution
control are addressed concomitantly with trends in process change. Trends in
external pollution treatment, control, and disposal methods are discussed in
Section I.C.4.
To assist in the projection of process trends a historical perspective of
degrees of application or use of the various processes and subprocesses is
meaningful. A comprehensive survey of every process in every refinery would
be beyond the scope of this study; therefore, based on a review of the litera-
ture this analysis was done only for the major processes and subprocess al-
ternatives. The percent use of these basic processes and major subprocesses
by U.S. refineries is presented in Table 5.
The discussions of current and future process trends which follow are largely
based on recent literature (US-EPA 1973a-d; US-EPA 1976a-d; FEA 1977; US-DOE
1977) and on conversations with key individuals knowledgeable of changes in the
petroleum refining industry.
I.C.3.a. Storage and Transportation
Crude oil and product storage.
Many refineries already had installed equipment to minimize the release of
hydrocarbons from crude and product storage areas to the atmosphere before
the storage regulations discussed in Section I.D.2 were promulgated. Doubt-
less some motivation was provided by Rule 66 of the Los Angeles Air Pollution
Control District, which regulates photochemical oxidants and other state and
local regulations patterned after Rule 66. Refineries also were motivated
by the economics of product loss versus vapor recovery.
Storage regulations now require the use of alternative technologies-floating-
roof covers, pressurized tanks, and/or connections to vapor recovery systems
—so the trend in this direction should accelerate. Floating roof tanks permit
the stored products to expand and contract without exhausting vapors to the
external environment. Although floating-roof covers can add to the wastewater
flow from storage tanks, strict refinery specifications on the characteristics
of crude oil supplies will minimize wastewater from modern crude storage facil~
ities. A factor which will tend to reduce quantities of wastewater from
24
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Table 5. Estimated percentage of petroleum refiniries
using various manufacturing processes.
Technological
Process Percentage Use by Year Status-*-
1950
1963
1967
1972
1977
Crude oil desalting
1007=
100%
100%
100%
-Chemical desalting
5
2
0
0
0
-electrostatic desalting
95
97
100
100
T,N
Crude distillation
100%
100
100
100
100
-Atmospheric fractionator
100
100
100
100
100
0,T,N
-Vacuum fractionator
60
64
70
75
0,T,N
-Vacuum flasher
Thermal cracking
59
48
45
40
35
-Thermal cracking
28
18
8
2
0
-Delayed coking
12
14
16
19
T,N
-Visbreaking
13
16
18
22
T,N
-Fluid coking
2
2
4
6
T,N
Catalytic cracking
25
51
56
60
65
-Fluid catalytic cracking
39
45
50
60
T,N
-Thermofor catalytic
cracking
13
12
10
6
0
-Houdriflow
3
3
2
0
0
Hydrocracking
0
2
8
25
34
-Isomax
4
11
15
N
-Unicracking
2
8
12
N
-H-G hydrocracking
0.3
0.8
3
3
N
-H-oil
0.4
1
1
N
Reforming
62
67
74
79
-Platforming
37
40
44
47
O.T.N
-Catalytic reforming-
Englehard
5
9
11
12
0,T
-Powerforming
1
2
3
3
T,N
-Ultraforming
6
6
7
8
T,N
Polymerization
25
42
33
26
7
T,N
-Bulk acid polymerization
-Solid phosphoric acid
T
condensation
0
-Sulfuric acid polymerization
0
-Thermal polymerization
1
0.4
Alkylation
10
38
47
54
62
T,N
-Sulfuric acid alkylation
22
26
32
38
-HF alkylation
16
21
22
25
0,T,N
-DIP alkylation
N
-Thermal alkylation
25
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Table 5. Estimated percentage of petroleum refineries
using various manufacturing processes (continued).
Percentage Use by Year
1963
1967
1972
1977
Isomerization
5%
7%
10%
15%
-Isomerate
1
1.5
3
6
-Liquid-Phase Isomerization
2
3
4
5
-Butamer
1
1
2
2
-Penex
0.7
1
1
2
Technological
Status 1
N
N
N
N
Solvent Refining
25
29
30
32
-Furfural Refining
14
15
16
16
O.T.N
-Duo-Sol
2
3
3
3
T,N
-Phenol Extraction
10
10
11
11
o,t,n
-Udex
3
5
8
8
T,N
Dewaxing
11
11
11
11
-Solvent Dewaxing (MEK)
8
8
9
9
0, T,N
-Propane Dewaxing
2
2
2
2
0, T
-Pressing and Sweating
1
1
0
0
0
Hydrotreating
47
56
70
80
-Unifining
22
23
30
35
T,N
-Hydrofining
3
3
5
8
T,N
-Trickle Hydrodesulfurization
0.3
2
4
5
T,N
-Ultraf ining
3
5
8
10
T,N
Deasphalting
20
23
25
27
-Propane Deasphalting and
15
18
20
21
0,T,N
Franc t iona t ion
-Solvent Decarbonizing
4
5
5
6
T,N
Drying and Sweetening
80
80
80
80
-Copper Sweetening
0, T
-Doctor Sweetening
0
-Merox
N
-Girbotal
0,t,n
Wax Finishing
11
11
11
11
-Wax Fractionation
10
9
6
5
0,T
-Wax Manufacturing, MIBX
1
1
1
1
0,T,
-Hydrotreating
1
4
5
N
Grease Manufacture
12
12
10
10
0,t,n
Lube Oil Finishing
19
19
20
20
-Perculation Filtration
11
7
5
2
0,T
-Continuous Contract Filtration
6
7
7
7
0,T
-Hydrotreating
2
5
8
11
N
26
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Table 5. Estimated percentage of petroleum refineries
using various manufacturing processes (concluded).
Hydrogen Manufacture
-Hydrogen Partial Oxidation
-Hydrogen, Steam Reforming
Percentage Use by Year
1963 1967 1972 1977
2
1
1
8
3
5
25
10
15
34
12
22
Technological
Status^
N
Total No. of Refineries 293 261 236 211
^ 0 = Older - Refineries which use relatively inefficient and/or obsolescent
processes and subprocesses
T = Typical - Refineries which use those processes and subprocesses that are
most common today
N ~ Newer - Refineries which use all or most of the advanced processes and sub-
processes available
Source: US-DOI. 1967. The cost of clean water. Volume 111 Industrial Waste
Profile No. 5: Petroleum Refining. Prepared for FWPCA. Available from
US-GPO, Washington, DC.
27
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finished product storage is the trend toward increased use of dehydration or
drying processes ahead of produce finishing (US-EPA 1973a).
• Crude oil and product transportation
The trend in tanker use for shipping intermediate and final products is to
larger and larger vessels which arrive at the refinery in ballast and must
discharge wastewaters from up to 30% of their capacity. If the discharge is
sent directly to the wastewater treatment system, a shock load could result
Thus, the use of larger ballast water storage tanks or holding ponds will be
necessary to control the flow into the treatment system. The discharge of
ballast wastewater directly into ocean or estuarine areas without treatment
is now illegal and is expected to be eliminated completely (US-EPA 1973a)
I.C.3.b. Crude Oil Desalting
The current trend is toward increased use of electrostatic desalting and less
use of chemical processes to remove inorganic salts and suspended solids from
crude oil prior to fractionation. In the future, chemical methods may be
used only as a supplement where the crude has a high salt content. A two-
stage electrical desalting process is expected to be used as "dirtier" crude
feedstocks are processed. The growth in capacity of desalting units will be
proportionate to the growth in crude oil capacity.
I.C.3.C. Crude Oil Fractionation
The trend is toward large and more complex combinations of atmospheric and
vacuum towers with more individual sidestream products.
I.C.3.d. Cracking Operations
• Thermal cracking
Regular thermal cracking, which was an important process before the develop-
ment of catalytic cracking, is being phased out. Visbreaking and coking units
are still installed, but at a slower rate than before, because of product
sulfur restrictions. Whereas the current trends are toward dirtier crudes
with higher sulfur content, hydrocracking, and propane deasphalting (which
break down high molecular weight compounds and remove sulfur from the compound
to form clean low molecular weight materials) are expected to receive more S
attention to recover saleable products with low sulfur content from the residUun|
• Catalytic cracking
Recycle rates have been declining since 1968 and the trend is expected to
continue because of the development of higher activity catalysts (molecular
sieve catalysts, instead of high surface area silica-alumina catalysts).
Large fluidized catalytic cracking processes, in which the finely-powered
catalyst is handled as a fluid, largely have replaced the fixed-bed and
moving-bed processes, that use a beaded or pelleted catalyst.
28
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• Hydrocracking
This process continues to be an efficient, low to moderate temperature,
catalytic method for conversion of refractory middle boiling or heavy feed-
stock into high-octane gasoline, reformer charger stock, jet fuel and/or
high grade fuel oil. Hydrocracking still possesses considerable flexibility
(relative to catalytic cracking) in adjusting operations to meet changing
product demands. At one time, hydrocracking was a rapidly growing refinery
process; however, its growth rate is now stable (about 1.5 percent/year)
because of high investment costs and the large quantities of expensive hydro-
gen that are required for operation. Primary catalysts which currently are
used in hydrocracking include tungsten sulfide-silica alumina, and nickel-
silica alumina.
I.C.3.e. Hydrocarbon Rebuilding
• Polymerization
This process currently is used by only a small number of refineries because
the product octane is not sufficiently higher than that of the basic gasoline
blending stocks to significantly upgrade the overall motor fuel pool. Also
alkylation yields per unit of olefin feed are much better than polymerization
yields. Consequently, the current polymerization downtrend is expected to
continue. The primary catalysts used include copper pyrophosphate and phos-
phoric acid.
• Alkylation
Alkylation (used to produce a high octane product) process capacity is ex-
pected to increase in response to the demand for high octane low lead gasoline.
I.C.3.f. Hydrocarbon Rearrangements
• Isomerization
Reforming capacity in the U.S. currently is expanding at about the same rate
as total crude capacity. This growth rate should continue to increase as the
demand for motor fuel grows.
• Reforming
No significant changes are expected except for a change to multireactive,
fixed bed, catalytic processes in place of thermal units.
I.C.3.g. Solvent Refining
Generally solvent extraction capacities are expected to increase slowly as
quality requirements for all refinery products become more stringent, as the
demand for the lube oils grows, and as the petrochemical industry continues
to require increased quantities of aromatics.
I.C.3.h. Hydrotreating
Hydrotreating was first used primarily on lighter feedstocks, however, with
29
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more operating experience and improved catalysts, hydrotreating has been applied
to heavier fractions such as lube oils and waxes. It has been one of the most
rapidly growing refinery processes. It should continue to increase at a greater
rate than crude capacity because the process can be applied to most sour feed-
stocks, it is flexible, and it also eliminates contaminants of concern to the
refining industry from an operating standpoint and to the general public from
an aesthetic standpoint. Among the catalysts most commonly used in hydro-
treating are alumina, cobalt molybdate, nickel sulfide platinum, silica alumina
and tungsten nickel sulfide.
I.C.3.i. Grease Manufacturing
Because of developments in sealed grease fittings and longer lasting greases,
grease production generally is expected to decline.
I.C.3.J. Product Finishing
• Drying and sweetening
Air quality regulatory agencies are expected to increase their efforts to
control emissions of sulfur. Therefore restrictions which govern sulfur
contents in fuels are expected to become stricter. This will generate a
trend toward replacement of the sweetening processes by hydrotreating (de-
sulfurization), because hydrotreating removes most sulfur compounds and not
just hydrogen sulfide,mercaptans, and elemental sulfur. Nevertheless, efficacy
and economics will ensure the use of sweetening processes for certain feedstocks
excepting those processes which produce high waste loads.
• Lube oil finishing
The two methods most widely used by industry are: (1) continuous contact
filtration in which an oil-clay slurry is heated and the oil removed by vacuum
filtration; and (2) percolation filtration, in which the oil is filtered through
clay beds. Percolation also involves naphtha washing and kiln-burning of spent
clay to remove carbon deposits and other impurities. It is expected that acid
and clay treatment of lube oils eventually will be replaced by hydrotreating
techniques with elimination of important wastewater streams. Acid treatment
has been significantly reduced.
• Blending and packaging
It is expected that there will be increased use of automated proportioning
facilities for the blending of products with a trend toward contracting out
of packaging of lower-volume products that are less suitable to highly-auto-
mated operation.
I.C.3.k. Auxiliary Activities
• Hydrogen manufacture
Past and present growth in hydrotreating and hydrocracking processes will result
in a continued demand by new refineries for hydrogen, to a level beyond that
obtained as a byproduct of reforming and other refinery processes. The demand
30
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for hydrogen as a feedstock for the manufacture of ammonia and methanol also is
expected to continue. Currently the most widely used subprocess is steam reform-
ing, in which desulfurized refinery gases are converted to hydrogen, carbon
monoxide, and carbon dioxide in a catalytic reaction; this generally requires the
use of an additional shift converter which converts carbon monoxide to carbon dioxide.
I.C.k. Pollution Control
Because of crude supply limitations, new refinery capacity will be designed to
process higher sulfur crudes which means a corresponding increase in desulfuri-
zation capacity. The increased use of sour (higher sulfur) crude feedstock
from outside the U.S. will require changes in processing equipment, in-plant
wastewater control, and treatment operations. There are refineries that consume
sweet crude stock, but do not employ strippers to remove minimal amounts of
ammonia and hydrogen sulfide from wastewaters. Increases in sour crude
processing within these refineries will require sour water strippers to be
used prior to discharge of the wastewaters to biological wastewater treatment
facilities. Generally, pollution control techniques with a higher level of
removal will continue to replace older techniques. These techniques include
use of incinerators to destroy trace organic discharges, use of reactor ex-
hausts as furnace air to reduce gaseous organic discharges, improved treatment
of sour heavy bottoms, more effective control of emissions of sour gases, and
increased emphasis on wastewater reuse/recirculation techniques such as:
• The use of catlytic cracker accumulator wastewaters rich in
H2S (sour waters) for makeup to crude desalters
• The use of blowdown condensate from high-pressure boilers for
makeup to low-pressure boilers
• The reuse of waters that have been treated for closed cooling
systems, fire mains, and everyday washing operations
• Stormwater use for routine water applications
• Blowdown waters from cooling towers for use as water seals on
high-temperature pumps
• The recirculation of steam condensate
• The recycling of cooling waters
Good maintenance practices can effectively reduce waste streams. More
emphasis is being place on:
• The recovery of oil spills and hydrocarbons with vacuum trucks
to reduce emissions and water effluents
• Reduction of leaks and accidents through preventive maintenance
• The separation of hazardous wastes, concentrated wastes, and
other process wastes from general effluents for more effective
treatment
• The diking of process unit areas to control and treat spills,
oily stormwater runoff, or periodic washes
• The reduction of shock pollutant loads on treatment facilities
through the periodic flushing of process sewers to prevent con-
taminant build-up
• Specialized programs for handling hazardous wastes, sludges,
washwaters, and other effluents
• Systems to minimize wastes from monitoring stations
• Personnel awareness that the waste treatment is initiated at the
process unit
31
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Process modifications often reduce waste streams significantly while returning
a recovery value. Technology changes that reduce pollution may not be as cost
effective during process cycles, but may prove to be highly beneficial when
waste treatment costs have been reduced. Depending on the feasibility and
suitability of a particular project, such process technology changes are ex-
pected to include:
• Catalyst switching to one of longer life and greater activity thereby
reducing regeneration rates
• Reduction in cooling water usage through the implementation of air-
fin coolers
• Reduction in spent caustic and sulfides loadings through use of
hydrocracking and hydrotreating processes
• Inclusion of process control instrumentation to employ emergency
shut-downs or control upset conditions
• Minimization of filter solids, water washes, and spent caustics
and acids through the optimization of drying, sweetening, and
finishing processes
• Higher removal of organics and residual solids
The removal of heavy metals from catalyst systems and specific toxic organics
also is being stressed. Treatment systems to remove heavy metals and organics
(i.e., precipitation, ion exchange, phenol removal by solvent extraction),
settling and filtration techniques to remove suspended solids and physical
systems to remove specific organics are now becoming common practice.
Table 6 presents historical trends (1950 to 1977) in the use of various waste
water treatment methods by oil refineries.
I.C.5. Environmental Impact
Federal and State regulations for water and air pollutants (Clean Water and
Air Act Amendments of 1977) and solid waste generation and disposal (Toxic
Substances Control Act; Resource Conservation and Recovery Act) have resulted
in improvements in the technological design and efficiency of pollution control
methods. More attention is being given to the siting of major new industrial
facilities in recognition of the increased emphasis on State, regional, and
local land use planning. Also, owing to the ratification of the National
Environmental Policy Act and other legislation, government decision making
is more exposed to public scrutiny and to a more objective, complete environ-
mental review process. Thus, refineries which have become operational since
the early 1970's generally can be expected to have less waste stream-related
impacts than those built a decade or two ago. Small refineries (<10,000 B/CD)
are expected to increase because of incentives provided in Federal entitlement
programs, as well as due to a general increase in industrial activity; there-
fore, more consideration will be given to the assessment of cumulative and
secondary impacts from siting new refinery facilities.
I.D. MARKETS AND DEMANDS
I.D.I. Refinery Capacity
During the period from 1 January 1960 to 1 January 1977, U.S. refinery
32
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Table 6. Estimated percentage of petroleum refineries
using various wastewater treatment processes.
Processes and Subprocess
1950
1963
1967
1972 b
1977
API Separators
40%
50%
60%
70%
80%
Earthen Basin Separators
60
50
40
30
20
Evaporation
0-1
0-1
1
1-2
2-5
Air Flotation
0-1
10
15
18
20
Neutralization (total wastewater)
0-1
0-1
0-1
0-1
0-1
Chemical Coagulation and Precipitation
1-5
1-5
5-10
10-15
10-15
Activated Sludge
0
5
10
40
55
Aerated Lagoons
0
5
10
25
30
Trickling Filters
1-2
7
10
10
10
Oxidation Ponds
10
25
25
25
20
Activated Carbon
0
0.5
0.5
3
5
Ozonation
0
1
1
3
5
Ballast Water Treatment (Physical)
9
9
8
5
5
Ballast Water Treatment (Chemical)
1
1
2
5
5
Slop Oil-Vacuum Filtration
0
5
7
12
15
Slop Oil-Centrifugation
0
2
3
10
15
Slop Oil-Separation
100
93
90
80
70
Sour Water-Stream Stripping
Flue Gas Strippers
60
70
85
90
90
Natural Gas
Sour Water-Air Oxidation
0
3
3-5
7
10
Sour Water-Vaporization
1
1-2
1
0
0
Sour Water-Incineration3
35-40
40
50
30
20
Neutralization of Spent Caustics
Flue gas
20
30
35
20
20
Spent acid (including springing
and stripping)
15
25
30
25
20
Oxidation
0
3
5
5
5
Incineration3
25
40
50
20
15
aIncineration includes flaring, boiler furnaces, and separate incinerators used
only in conjunction with stripping and vaporization.
^Estimated
Source: US-DOI. 1967. The cost of clean water, Volume III, Industrial Waste
Profiles no. 5 - petroleum refinering. FWPCA, Washington, DC.
33
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operation capacity increased about 7.0 million barrels per calendar day (9.5
million B/CD to 16.5 million B/CD). This increase represents an average
compounded growth rate of about 3.5 percent per year; however, this growth
has not been equal in all PAD districts. The highest growth during this
period occurred in PAD district III, whereas the lowest occurred in PAD
district 1 (see Figure 4 for the geographical distribution of PAD districts)
(FEA 1977a, 1977b). Future trends show total operable capacity to rise to:
• 17.0 million
• 17.3 million
• 17.6 million
• 18.2 million
• 18.6 million
B/CD in 1978
B/CD in 1979
B/CD in 1980
B/CD in 1981
B/CD in 1982
and actual crude runs through 1981 are estimated (by Bureau of Mines) to be
about 90 percent of the above total operable capacities, or 15.4 million B/CD
in 1978; 15.5 million B/CD in 1979; 15.8 million B/CD in 1980; and 16.4 milllo-,
B/CD in 1981.
Discrepencies do exist, however, among authroities for crude capacity pro-
jections. For example, Oil and Gas Journal figures (Lange 1978) for crude
runs during 1977 and 1978 are lower than those determined by the Bureau of
Mines and the Office of Oil and Gas (FEA 1977a) as indicated below:
1977 1978
(million B/CD) (million B/CD)
0 & G Journal 14.6 14.9
BM/OOG 14.9 15.3
Under the President's proposed National Energy Plan (NEP), the petroleum
product demand is expected to rise only slightly, but U.S. refinery output
is expected to increase at a greater rate owing to a decline in product
imports forced by a sharp decrease in residual fuel oil demand. Nevertheless
the required increase in refinery output is less than that capacity currently
planned. Capacity additions are expected to total 2.1 million barrels per
day between 1977 and 1982. Even if some of the projects scheduled to come on
stream between 1977 and 1982 fail to materialize, the addition of as little
as 1.0 million barrels per day is expected to meet future demand (1985) at
reasonable upper limits of refinery utilization. Because there probably will
be some growth in petroleum product demand between 1985 and 1990, some added
capacity beyond the 1.0 million barrels per day would be needed during that
period.
One very significant impact of the President's NEP is the substantial reduc-
tion in residual fuel oil demand which drops from 3.5 million barrels per
day in the base case to 2.0 million barrels per day under the program. Whereas
U.S. refineries in the 50 States already are capable of producing 2.0 million
barrels per day of residual fuel oil, it would appear that all export refin-
eries in the Bahamas/Caribbean refineries probably would continue operations
34
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while U.S. refineries would tend to minimize residual fuel oil production to
the extent possible, while still maintaining operations to produce other
necessary products.
The base case, for petroleum product demand which represents anticipated 1985
and 1990 demand without the President's program was also developed. The re-
quirement for new refinery capacity would be 3.6 million barrels per day by
1985 for the base case as compared with 1.9 million barrels per day of planned
"firm" projects (FEA 1977b).
I.D.2. Incentives
Currently the primary incentive to refine domestically (as opposed to abroad)
is the Federal entitlements program. A secondary incentive is the import fee
system which has been active since April 1973. Under the entitlements program,
because of price controls, the average refiner pays less for his crude oil than
other countries pay for foreign crude oil. This large advantage endangered
U.S.-owned refinery operations in the Bahamas and Caribbean with the result
that partial entitlements were given to residual fuel oil importers.
With the application of the crude equalization tax under the NEP, the advantage
offered by the entitlements system will disappear, and leave import fees as
the last significant element to encourage domestic refining.
Other factors for consideration include increased investment tax credits and
accelerated depreciation on new facilities or modification to existing
facilities. The NEP also will affect refinery operations through the user's
tax which is to be paid on liquid fuels burned in the refinery. Current tech-
nology does not permit the burning of coal in process furnaces. If the cost
of the tax can be passed through or exceptions granted, it will not affect
refineries. According to the NEP Macro Economic Effects, one-third of the
crude oil equalization tax will have to be absorbed by refineries which may
nullify the protection of the product import fee.
I.D.3. Changes in Refinery Configuration
Although the general trend has been toward fewer, but larger refineries this
trend appears to be reversing. The capacities of the 285 refineries operating
as of 1 January 1978, ranged from 32 m^/day (200 B/CD) to 69,000 m^/day
(434,000 B/CD). Refineries with unit capacities over 15,900 m^/day (100,000
(B/CD) represented only 11.5% of total refineries in 1967, but accounted for
48% of the refining capacity. By 1972, 16.6% of all refineries exceeded this
size and represented 58% of total capacity. However, more recent information
indicates that most new refinery construction utilizing fluid catalytic
cracking units will range from 25,000 to 50,000 B/CD (USEPA 1976b).
Although larger refineries are able to take advantage of continuous processing
units, the number of small refineries (under 10,000 B/CD), both new and re-
activated, is increasing. In part, this is because of the small refiner
bias in the Federal entitlements program which provides special allocations
of petroleum feedstocks to small refineries at a substantial price advantage
(FEA 1977b). In point of fact, the smaller the refinery, the greater dollar
35
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per barrel advantage. For example, a refinery with 80,000 B/CD capacity re-
ceives only one-tenth of the benefits of a 10,000 B/CD facility (Peer and
Marsik 1977).
Most of the small refineries being built or planned are of simple design that
often consists only of crude distillation towers and storage tanks; therefore
they are less able to respond to changing market demands or to produce more
sophisticated products (FEA 1977a).
In contrast, the larger refineries have instituted improvements in technology
which have resulted in more sophisticated processing techniques such as fluid-
bed catalytic cracking instead of static-bed catalytic cracking, catalytic
reforming, and advanced hydrotreating.
Trends in the construction of larger petroleum refineries will be dictated
primarily by market demand. This effect was evidenced by the considerable
buildup during the 1960's in processes which provided higher octane gasoline.
Recently, although there has been a significant reduction in the octane numbers
required, the necessity to achieve specific octanes without the addition of
lead again has modified petroleum processing. Moreover, the market for low
sulfur fuel oil has generated the construction of desulfurization facilities.
The rate of refinery expansion or construction will be influenced by the
relative contribution of oil-derived products to the total energy demand. The
share supplied by oil is projected to drop from 46% in 1975 to 42% in 1990
(Denman 1978).
Other factors that are expected to influence refinery configurations include:
• Uncertainty of government regulatory requirements
• Threat of legislation to force divestiture by refineries of
production and marketing
• Cost and composition of crude oils
• Inflation rates
• Construction costs, pollution control regulations, and equipment
costs
t Environmental restrictions and opposition
The above summary represents an overview. For the reviewer who seeks more
detailed analyses of this subject see: FEA 1977a; FEA 1977b; US-DOE 1977.
I.E. SIGNIFICANT ENVIRONMENTAL PROBLEMS
I.E.I. Location
Petroleum refinery operations generally are large installations which can occupy
considerable acreage. Naturally the areal extent varies with the capacity of
the refinery and the extent of ancillary support facilities planned. Most
refinery facilities are located either in rural areas or on the periphery
of an urban center in the oil producing regions. Because the siting of new
source petroleum refineries can involve a significant change in land use,
particularly in rural areas, direct and indirect social and ecological impacts
may occur. Direct impacts are primarily a function of the type and size of the
36
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facility proposed, the composition of the crude oil to be refined, and charac-
teristics of the site (e.g., wetlands versus upland). The extent and sig-
nificance of secondary or indirect impacts such as induced growth, infrastructure
changes, and demographic changes depends largely on the local economy, existing
infrastructure, numbers and characteristics of construction workers (e.g., local
or nonlocal, size of worker's family) and other related factors. Long term
secondary impacts are seldom significant unless the refinery, because of its
size, processing methods, and location, employs a sufficient number of workers
to result in spin-off developments (commercial, industrial, and residential).
A discussion of secondary impact assessment is contained in the existing EPA
document, Environmental Impact Assessment Guidelines for Selected New Source
Industries, pages III-11-12.
I.E.2. Raw Materials
Serious environmental problems associated with raw materials arise from the
production, transport, handling and storage of the crude oil. However a
discussion of impacts associated with exploration, development and production
activities are not discussed in this report.
Spills, leaks and tank cleaning operations can produce discharges of crude oil
into waterways and estuarine waters. Polynuclear aromatic compounds, heavy
metals, and nitrogen and sulfur containing organics can pose a serious threat
to human life and the ecology.
I.E.3. Process Wastes
Process operations produce a number of liquid wastes which can pose environ-
mental problems. Among the types of effluents which are characteristic of
process wastes are the following:
Free oil originates from numerous sources such as individual sampling taps,
pump gland leaks, valve and pipeline leaks, losses and spills at times of unit
shutdown and equipment repair, accidental spills and overflows, tank bottom
drawoff, and other miscellaneous sources. Some of the oil becomes emulsified
which poses another problem to the engineer.
Condensate waters originate from distillate separators, running tanks and
barometric condensers. These waters can contain a variety of chemicals such
as sulfur-containing inorganics, acids, alkalis, suspended solids and condensed
organics.
Acid wastes arise from the catalytic use of various acids and from the acid
treatment of gasoline, white oils, lubricating oils and waxes. They occur
as rinse waters, scrubber discharges, spent catalyst sludges, condensate, and
miscellaneous discharges resulting from sampling procedures, leaks, spills,
and shutdowns. Waste caustics arise from caustic washing and these waste
streams include various condensed sulfur compounds and condensed organics.
• Free oil
• Emulsified oil
• Condensate waters
• Acid wastes
• Waste caustics • Sludges and other solids
• Alkaline waters • Clean cooling water
• Special chemicals • Sanitary wastes
• Waste gases
37
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Alkaline waters arise from washings. Special solvents are used in refining
and leaks and spills may burden waste streams.
The bulk of the wastewaters from petroleum refineries is cooling water. This
water can become contaminated by oil leaks. They also may contain chromates
and other chemicals used in cooling towers. These can pose a serious environ-
mental problem.
Sanitary wastes can be easily treated, either separately or in conjunction
with other wastewaters.
Waste gases from petroleum refining are stack gases from furnances and reactors.
The particular pollutants of concern are particulates, various sulfur compounds
(hydrogen sulfide, condensed sulfur compounts, sulfur dioxide) and various
organic products and constituents of crude oil. Leaks and equipment shutdowns
constitute a major source of hydrocarbons.
A wide variety of solid wastes are generated in a refinery. These include
water and wastewater sludges, waste materials from catalyst reactors and
filtration. Slopes from reactors and storage tanks are also a significant
source. These sludges may contain organics, sulfur compounds and heavy metals.
I.E.4. Pollution Control
Pollution control measures on waste streams can effectively reduce adverse
impacts that result when control is absent; however, the same control mea-
sures can create other kinds of impacts. The equipment used to control
various waste streams in oil refining facilities also can generate solid and
liquid residual wastes which must be treated and disposed of properly. For
example, pollution control processes to remove acid components in the gas
stream (H2S) may leave sulfur-based compounds in the exhaust gases. Waste
treatment measures for aqueous streams likewise may not be adequate to treat
all of the complex organic compounds which are discharged from a petroleum
refinery. Therefore, all proposed pollution abatement devices should be well-
designed, well-operated, and properly maintained to minimize other pollutant
impacts which may result from unnecessary residual waste products.
I.F. REGULATIONS
Federal water pollution regulations are covered primarily by the Standards of
Performance for New Sources (SPNS) for the petroleum refining point source
category, in Section 40 CFR 419. Control is through the NPDES permit process.
Administration and enforcement rest either with USEPA or with those States
with approved NPDES permit programs.
38
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Air pollution control standards are enumerated by Federal New Source Perfor-
mance Standards (NSPS) as described in 40 CFR Parts 50 and 60 and by State
and local air pollution regulations. Usually control is through the State
regulatory function of licensing the construction of the oil refinery.
Other applicable pollution control regulations include the Federal Resource
Conservation and Recovery Act of 1976 and the various state regulations re-
garding disposal of solid wastes.
I.F.I. Water Pollution Standards of Performance
The effluents of new petroleum refineries or of major alternatives to exist-
ing refineries are subject to standards of performance for new sources
(SPNS) and pretreatment standards for new sources established under Public
Law 92-500, the Federal Water Pollution Control Act, as amended. These standards
have been subjected to court challenge, but currently are in effect. The
regulations govern conventional pollutants, as they are termed in Section
304(a)(4) of the Clean Water Act of 1977 (P.L. 95-217), and others as follows:
• BOD 5
• TSS
• COD
• Oil and grease
• Phenolic compounds
• Ammonia as N
• Sulfide
• Total chromium
• Hexavalent chromium
• pH
Additional SPNS and pretreatment standards for toxic pollutants applicable to
the subcategories of this industry also are being developed. These are re-
quired for a specific list of substances by the June 8, 1976 Consent Decree
resulting from the recent litigation, Natural Resources Defense Council, Inc.,
et al. v. Russell E. Train (Civil Action No. 2153-73 U.S. District Court for
the District of Columbia) and from the Clean Water Act of 1977. The list
appended to the Decree and referenced in the Act, includes a number of exotic
organics and heavy metals of concern to refiners. The toxic SPNS and pre-
treatment standards will be effective immediately upon promulgation.
EPA may revise the list from time to time, adding substances to it and re-
moving others. Thus, after determining the toxic effluents already subject
to standards, new source NPDES applicants should obtain the latest version
of the list in order to identify other types of effluents which will become
the subject of toxic SPNS and pretreatment standards.
The subcategories are further broken down by the use of two factors based on
size of plant and process configuration. The product of these two factors
is a number by which a specified base SPNS value for each waste parameter for
each of the five subcategories is multiplied to obtain a value for a specified
plant. Plant size is broken down into seven ranges, giving seven size factors
The process factor is broken down into 22 increments, each of which produces
a different process factor. An example of the application of the factors was
39
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promulgated (40 CFR, Part 419, Subpart D) and is shown In Table 7 for
a refinery in the lube subcategory. The SPNS for the five subcategories
topping, cracking, petrochemical, lube, and integrated are shown in Table 8.
From review of effluent limitations that reflect the best available treat-
ment economically achievable (BATEA), which were remanded by the courts, EPS
is expected to eliminate the size factor and simplify the regulations. Similar
action on the NSPS also can be expected.
The pretreatment standards for new source petroleum refineries are nearly
identical to the SPNS for each subcategory as presented in Table 8 provided
that:
• The SPNS value will be reduced correspondingly when the publicly-
owned treatment works receiving the discharge is committed in its
NPDES permit to remove a specified percentage of an incompatible
pollutant
• The following wastes are not introduced into the publicly-owned
treatment works:
—Pollutants which create a fire or explosion hazard in the POTW
—Pollutants which will cause corrosive structural damage to the POTti
but in no case discharges with pk lower than 5.0, unless the works *
is specifically designed to accomodate such discharges.
—Solid or viscous pollutants in amounts which cause obstruction to k
flow in sewers, or other interference with the operation of the Pn'm*
—Any pollutant, including oxygen demanding pollutants, released in
discharge or such volume or strength as to cause interference in t-w
POTW.
—Heat in amounts which will inhibit biological activity in the POTW
resulting in interference but in no case heat in such quantities tH
the temperature at the treatment works influent exceed 40 C (104
unless the works is designed to accomadate such heat.
These prohibitions are taken from the more general pretreatment standards set
forth in 40 CFR Part 403 which are applicable as amended by the specific pre-
treatment standards for each point source category.
NPDES permits also impose special conditions beyond the effluent limitations
stipulated, such as schedules of compliance and treatment standards. Once
refineries are constructed in conformance with all applicable standards of
performance, however, they are relieved by Section 306(d) of P.L. 92-500 from
meeting any more stringent standards of performance for 10 years or during
the period of depreciation or amortization, whichever ends first. This
guarantee does not extend to toxic standards adopted under Section 307(a)
of P.L. 92-500 which can be added to the refinery's NPDES permit when they
are promulgated.
Many States have qualified, as permitted by Public Law 92-500, to administer
their own NPDES permit programs. The major difference in obtaining an NPDES
permit through approved State programs vis-a-vis the Federal NPDES permit
system is that the FWPCA Amendments of 1972 do not extend the NEPA environ-
mental impact review requirements to State programs. As of April 1976,
40
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Table 7 . Example of the application of size and process configuration
factors for a new source.
Process
category
Crude
Cracking
and coking
Lube
Asphalt
Calculation of the Process Configuration
Processes included
Weighting
factor
Atm. crude distillation.
Vacuum crude distillation.
Desalting.
Fluid cat. cracking.
Vis-breaking.
Thermal cracking.
Moving bed cat. cracking.
Hydrocracking.
Fluid coking.
Delayed coking.
Less than 12% of the
feedstock throughput
Asphalt production.
Asphalt oxidation.
Asphalt emulsifying.
13
12
EXAMPLE.—Lube refinery 125,000 bbl per stream day throughput
Process
Capacity
(1,000 bbl per
stream day)
Capacity
relative to
throughput
Weighting
factor
Processing
configuration
Crude:
Atm
Vacuum
Desalting
Total
Cracking-FCC
Hydrocracking
Total
Lubes
Total
Asphalt
125
60
125
41
20
5.3
4.0
4.9
4.0
.48
1
2.48
.32 P
.160
.488
.042
.032
.039
.113
0.032
X
X
X
13
12
2.48
2.93
1.47
.38
Refinery process configuration
7.26
41
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Table 7. Example of the application of the size
and process configuration factors (Concluded).
Notes:
Using the Table for the Lube Subcategory on page 48 a feedstock through of
125 (1000 bbs/day); and a process configuration number of 7.26, it is seen
that: process factor=0.88
size factor =0.97
To calculate the new source limits for each parameter multiply the applicabl
limits (from page 48) by both the process factor and the size factor. For
example, the B0D5 limit (maximum for any one day) is calculated as follows:
BOD5 limit = 34.6 kg/1000 mg3 (12.2 lb/1000 bbl) x .88 x .97 =
2915 kg/1000 mg3 (10.4 lb/1000 bbl)
42
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Table 8. Standards of performance for new sources
applicable to the five subcategories of
references.
TOPPING SUBCATEGORY
Effluent Limitations
kg/1000 m3 (lb/1000 bbl) of feedstock
Average of daily
values for 30
consecutive days
shall not exceed
Maximum for
any one day
B0D5
11.8
(4
.2)
6.3
(2.2)
TSS
8.3
(3
.0)
4.9
(1.9)
COD1
61
(21.7)
32
(11.2)
Oil and grease
3.6
(1
• 3)
1.9
(.70)
Phenolic compounds
.088
(•
031)
.043
(.016)
Ammonia as N
2.8
(1
• 0)
1.3
(.45)
Sulfide
.078
(.
027)
.035
(.012)
Total chromium
.18
(.
064)
.105
(.037)
Hexavalent chromium
.015
(.
0052)
.0068
(.0025)
pH Within the range 6.0 to 9.0
In any case in which the applicant can demonstrate that the chloride ion
concentration in the effluent exceeds 1,000 mg/1 (1,000 ppm), the Regional
Administrator may substitute TOC as a parameter in lieu of COD. Effluent
limitations for TOC shall be based on effluent data from the plant corre-
lating TOC to BOD5.
If in the judgment of the Regional Administrator, adequate correlation
data are not available, the effluent limitations for TOC shall be estab-
lished at a ratio of 2.2 to 1 to the applicable effluent limitations on BOD5.
43
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Table 8. Standards of performance for new sources applicable to the five
subcategories of references (Continued).
Size factor.
Size
1,000 bbl of feedstock per stream day: factor
Less than 24.9 1.02
25.0 to 49.9 1.06
50.0 to 74.9 1.16
75.0 to 99.9 1.26
100.0 to 124.9 1.38
125.0 to 149.9 1.50
150.0 or greater 1.57
Process factor.
Process
Process Configuration factor
Less than 24.9 • 0.62
2.5 to 3.49 0.67
3.5 to 4.49 0.80
4.5 to 5.49 0.95
5.5 to 5.99 1.07
6.0 to 6.49 1.17
6.5 to 6.99 1.27
7.0 to 7.49 1.39
7.5 to 7.99 1.51
8.0 to 8.49 1.64
8.5 to 8.99 1.79
9.0 to 9.49 1.95
9.5 to 9.99 2.12
10.0 to 10.49 2.31
10.5 to 10.99 2.51
11.0 to 11.49 2.73
11.5 to 11.99 2.98
12.0 to 12.49 3.24
12.5 to 12.99 3.53
13.0 to 13.49 3.84
13.5 to 13.99 4.18
14.0 or greater 4.36
(a) Runoff
The allocation allowed for storm runoff flow, as kg/cu m
(lb/Mgal), shall be based solely on that storm flow (process area runoff)
which is treated in the main treatment system. All additional storm runoff
(from tankfields and non-process areas), that has been segregated from
the main waste stream for discharge, shall not exceed a concentration of
35mg/l of TOC or 15 mg/1 of oil and grease when discharged. The following
allocations for runoff are in addition to the process discharge allowed by
the above limitations:
44
-------
Table 8. Standards of performance for new sources applicable to the five
subcategories of references (Continued).
(a) Runoff continued „C1-, , . .
Effluent Limitations
kg/1000 m3 (lb/1000 gal) of flow
Average of daily
values for 30
Maximum for consecutive days
any one dav shall not exceed
BOD5 0.048 (0.40) 0.026 (.21)
TSS .033 (.27) .021 (.17)
COD1 .37 (3.1) .19 (1.6)
Oil and grease .015 (.126) .0080 (.067)
pH Within the range 6.0 to 9.0
(b) Ballast
The allocation allowed for ballast water flow, as kg/cu m (lb/M
gal), shall be based on those ballast waters treated at the refinery. The
following allocations are in addition to the process and runoff limitations:
Effluent Limitations
kg/1000 m3 (lb/1000 gal) of flow
Average of daily
values for 30
Maximum for consecutive days
any one day shall not exceed
B0D5
TSS
COD1
Oil and grease
0.048
.033
.47
.15
pH Within the range 6.0 to 9.0
(c) Cooling water
(.40)
(.27)
(3.9)
(.126)
0.026
.021
.24
.008
(.21)
(.17)
(2.0)
(.067)
Once through cooling water may be discharged with a total organic
carbon concentration not to exceed 5 mg/1.
The above provisions relating to runoff, ballast, and once through
cooling water also are applicable to the cracking, petrochemical, lube,
integrated subcategories.
45
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Table 8. Standards of performance for new sources applicable to the five
subcategories of references (Continued)
CRACKING SUBCATEGORY
Effluent Limitations
kg/1000 m3 (lb/1000 bbl) of feedstock
Average of daily
values for 30
consecutive days
shall not exceed
Maximum for
any one day
BOD5 16.3
TSS 11.3
COD1 118
Oil and grease 4.8
Phenolic compounds .119
Ammonia as N 18.8
Sulfide .105
Total chromium .24
Hexavalent chromium .020
pH Within the range 6.0 to 9.0
Size Factor,
1,000 bbl of feedstock per
(5.8)
8.7
(3.1)
(4.0)
7.2
(2.5)
(41.5)
61
(21.0)
(1.7)
2.6
(.93)
(.042)
.058
(.020)
(6.6)
8.6
(3.0)
(.037)
.048
(0.17)
(.084)
.14
(.049)
(.0072)
.0088
(.0032)
Size
day: factor
Less than 2.49 0.91
25.0 to 49.9 0.95
50.0 to 74.9 1.04
75.0 to 99.9 ¦ 1.13
100.0 to 124.9 1.23
125.0 to 149.9 1.35
150.0 or greater 1.41
Process Factor. Process
Process configuration: factor
Less than 2.49 0.58
2.5 to 3.49 0.63
3.5 to 4.49 0.74
4.5 to 5.49 0.88
5.5 to 5.99 1.00
6.0 to 6.49 1.09
6.5 to 6.99 1.19
7.0 to 7.49 1.29
7.5 to 7.99 1.41
8.0 to 8.49 1.53
8.5 to 8.99 1.67
9.0 to 9.49 1.82
9*5 or greater 1.89
46
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Table 8. Standards of performance for new sources applicable to the five
subcategories of references (Continued).
PETROCHEMICAL SUBCATEGORY
Effluent Limitations
kg/1000 m3 (lb/1000 bbl) of feedstock
Maximum for
any one day
Average of daily
values for 30
consecutive days
shall not exceed
B0D5
TSS
COD1
Oil and grease
Phenolic compounds
Ammonia as N
Sulfide
Total chromium
Hexavalent chromium
PH
21.8
14.9
133
6.6
.158
23.4
.140
.32
.025
Within the range 6.0 to 9.0
Size factor.
(7.7)
(5.2)
(47.0)
(2.4)
(.056)
(8.3)
(.050)
(.116)
(.0096)
11.6
9.5
69
3.5
.077
10.7
.063
.19
.012
(4.1)
(3.3)
(24.0)
(1.3)
(.027)
(3.8)
(.022)
(.068)
(.0044)
1,000 bbl of feedstock per stream day:
Size
factor
Less than 24.9 0.73
25.0 to 49.9 0.76
50.0 to 74.9 0.83
75.0 to 99.9 0.91
100.0 to 149.9 1.08
150.0 or greater 1.13
Process factor.
Process configuration:
Less than 4.49 —
4.5 to 5.49
5.5 to 5.99
6.0 to 6.49
to 6.99
6.5
7.0 to 7.49 —
7.5 to 7.99 —
8.0 to 8.49 —
8.5 to 8.99 —
9.0 to 9.49 —
9.5 or greater
Process
factor
- 0.73
- 0.80
- 0.91
- 0.99
- 1.08
- 1.17
- 1.28
- 1.39
- 1.51
- 1.65
- 1.72
47
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Table 8. Standards of performance for new sources applicable to the five
subcategories of references (Continued.)
LUBE SUBCATEGORY
Effluent Limitations
kg/1000 m3 (lb/1000 bbl) of feedstock
Average of daily
values for 30
consecutive days
shall not exceed
Maximum for
any one day
bod5
34.6
(12.2)
18.4
TSS
23.4
(8.3)
14.9
CODl
245.0
(87.0)
126.0
Oil and grease
10.5
(3.8)
5.6
Phenolic compounds
.25
(.088)
.12
Ammonia as N
23.4
(8.3)
10.7
Sulfide
.220
(.078)
.10
Total chromium
.52
(.180)
.31
Hexavalent chromium
.046
(.022)
.021
pH Within the range 6.0
to 9.0
Size factor.
1,000 bbl of feedstock per stream day:
(6.5)
(5.3)
(45.0)
(2.0)
(.043)
(3.8)
(.035)
(.105)
(.0072)
Size
factor
Less than 49.9 0.71
50.0 to 74.9 0.74
75.0 to 99.9 0.81
100.0 to 124.9 0.88
125.0 to 149.9 0.97
150.0 to 174.9 1.05
175.0 to 199.9 1.14
200.0 or greater 1.19
Process factor
Process
Process configuration: factor
Less than 6.49 0.81
6.5 to 7.49 0.88
7.5 to 7.99 1-00
8.0 to 8.49 1-09
8.5 to 8.99 1.19
9.0 to 9.49 1-29
9.5 to 9.99 1.41
10.0 to 10.49 1.53
10.5 to 10.99 1.67
11.0 to 11.49 1-82
11.5 to 11.99 1-98
12.0 to 12.49 2-15
12.5 to 12.99 2*34
13.0 or greater 2.44
48
-------
Table 8. Standards of performance for new sources applicable to the five
subcategories of references (Concluded).
INTEGRATED SUBCATEGORY Effluent Limitations
kg/1000 (lb/1000 bbl) of feedstock^
Average of daily
values for 30
Maximum for consecutive days
any one day shall not exceed
bod5
41.6
(14.7)
22.1
(7.8)
TSS
28.1
(9.9)
17.9
(6.3)
C0D1
295
(104.0)
152
(54.0)
Oil and grease
12.6
(4.5)
6.7
(2.4)
Phenolic compounds
.30
(.105)
.14
(.051)
Ammonia as N
23.4
(8.3)
10.7
(3.8)
Sulfide
.26
(093)
.12
(0.042)
Total chromium
.64
(.220)
.37
(.13)
Hexavalent
.052
(.019)
.024
(.0084)
pH Within the range 6.0 to 9.0
Size factor.
Size
1,000 bbl of feedstock per stream day: factor
Less than 124.9 0.73
125.0 to 149.9 0.76
150.0 to 174.9 0.83
175.0 to 199.9 0.91
200.0 to 224.9 0.99
225 or greater 1.04
Process factor.
Process
Process configurations factor
Less than 6.49 0.75
6.5 to 7.49 0.82
7.5 to 7.99 0.92
8.0 to 8.49 1.00
8.5 to 8.99 1.10
9.0 to 9.49 1.20
9.5 to 9.99 1.30
10.0 to 10.49 1.42
10.5 to 10.99 1.54
11.0 to 11.49 1.68
11.5 to 11.99 1.83
12.0 to 12.49 1.99
12.5 to 12.99 2.17
13.0 or greater 2.26
49
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however, 26 States had enacted NEPA-type legislation and others plan to do
so. Thus it is likely that new refineries or major expansions of existing
refineries will come under increased environmental review in the future.
Because the scope of the implementing regulations varies considerably,
current information on prevailing requirements should be obtained early in
the planning process from permitting authorities in the appropriate juris-
diction.
I.F.2. Air Pollution Performance Standards
Air pollution regulations specify both the amount of various pollutants that
can be emitted from a source and standards for pollution of ambient air.
The paragraphs which follow discuss these regulations.
New source performance standards (NSPS) applicable to several sources of air
pollution from petroleum refineries are promulgated in 40 CFR 60, subpart J
and K. Subpart J imposes emission limitations on fluid catalytic cracking
unit catalyst regenerators, fuel gas combustion devices, and all Claus sulfur
recovery plants (except recovery plants of 20 long tons per day or less
associated with a small refinery). Subpart K regulates the storage of
petroleum, condensate, and finished or intermediate products (with the excep-
tion of most fuel oils) in order to control hydrocarbon emissions.
The storage NSPS only apply to storage vessels of greater than 151,412 liters
(40,000 gal.) except:
• Pressure vessels designed to operate in excess of 6.8kg per cm
(15 psi) gauge without emissions except under emergency conditions
• Subsurface caverns or reservoirs
• Underground tanks if the total volume added to and taken from a
tank annually does not exceed twice the volume of the tank
In contrast to other NSPS's, the standards for storage vessels do not place
specific limitations on hydrocarbon emissions, and instead require the
installation and use of specified equipment. A floating roof, vapor recovery
system, or equivalent is required for storage vessels when the true vapor
pressure of the liquid stored is equal to or greater than 78 mm Hg (1.5 psia)
but not greater than 570 mm Hg (11.1 psia). A vapor recovery system or
equivalent is required when the vapor pressure exceeds the latter value.
Some gasolines and gasoline feedstocks, for example, would fall in this
category. The applicant should note that any device capable of providing
comparable hydrocarbon emission control may be substituted for the specified
device. These regulations currently are undergoing review to determine
whether or not revisions are needed.
The sulfur dioxide NSPS for fuel gas combustion systems in refineries limits
SO2 emissions to the atmosphere by specifying that the fuel gas combusted
shall contain no more than 230 milligrams per dry standard cubic meter (mg/dscm)
(0.10 grain per dry standard cubic foot) (gr/dscf) of hydrogen sulfide. Compli-
ance with the standard also will be permitted by effectively removing S0_ from
the stack gases instead of removing H2S from the fuel gas. Fuel gas is defined
as any gas produced by a process unit and combusted except process upset gas.
50
-------
SC>2 standards applicable to Claus sulfur recovery plants, which process gases
produced within a petroleum refinery regardless of whether the plant is phys-
ically located within the refinery, are as follows:
• 0.025% by volume of sulfur dioxide at 0% oxygen on a dry basis if
emissions are controlled by an oxidation control system, or a
reduction control system followed by incineration; or
• 0.030% by volume of reduced sulfur compounds and 0.0010% by
volume of hydrogen sulfide calculated as sulfur dioxide at 0%
oxygen on a dry basis if emissions are controlled by a reduction
control system not followed by incineration.
Particulate matter emitted from fluid catalytic cracking unit catalyst re-
generators is limited to 1.0 kilogram (kg)/1000 kg (1.0 lb^lOOO lb) of coke
burnoff. When the gases from the regenerator pass through an incinerator
or waste heat boiler in which oil or coal is burned as an auxiliary fuel,
this limitation may be exceeded except that the incremental rate of emissions
may not exceed 43.0 gram (g)/MS (0.10 lb/million Btu) of heat input attributable
to the auxiliary fuel.
The opacity of catalyst regenerator gases is limited to less than 30% except
for six minutes in any one hour or when greater opacity is due to the presence
of uncombined \/ater. The opacity standard is a backup means to ensure that
control equipment always is maintained and operated properly. The NSPS limit
on the CO content of the regenerator emission is 0.050% by volume.
Screening studies preliminary to establishing NSPS are being completed on
vacuum distillation and other miscellaneous sources (e.g., leaks) in refineries.
Projections on future NSPS action on these sources currently are not available.
The above NSPS for air applicable to new source refineries have undergone
several revisions, which indicates that these regulations are far from static.
Applicants, therefore, should determine the most recent status of the various
air regulations, early in the planning process.
Applicants also should be current on the status of national emission standards
for hazardous air pollutants (NESHAP) promulgated under Section 112 of the
Clean Air Act. To date only five materials have been declared as hazardous
pollutants: asbestos, beryllium, mercury, polyvinyl chloride, and benzene.
EPA is examining other substances for possible inclusion in this classifica-
tion. Also, although present standards only apply to specific processes
which generate concentrated emissions of these pollutants, EPA is emphasizing
control of trace toxic emissions.
The effects of the national ambient air quality standards (NAAQS) on con-
struction of expansion of refinery capacity also should be ascertained. Since
the Clean Air Act requires States to enact State Implementation Plans (SIP's)
for attaining the NAAQS, these standards may exert a strong influence on the
siting of new facilities. The primary and secondary standards designed to
protect public health and welfare respectively are shown in Table 9. NAAQS
for sulfur dioxide and particulates assume special importance in both pristine
areas where the air quality is cleaner than the levels of these standards and
in areas where the standards are being exceeded.
51
-------
Table 9.
Emission
Sulfur dioxide
Particulate matter
Hydrocarbons
Nitrogen dioxide
Ozone
Carbon monoxide
Lead
Summary of National Ambient Air Quality Standards (from 40 CFK 50)
Standard
Primary
80 micrograms/m^ annual
arithmetic mean
365 micrograms/tip maximum
24-hour concentration*
75 micrograms/m3 annual
geometric mean
260 micrograms/m maximum
24-hour concentration*
160 micrograms/m-* (0.24 ppm)
maximum 3-hour concentration *
100 micrograms/m^ annual
arithmetic mean
235 micrograms/m^ (0.12 ppm)
maximum 1-hour concentration*
10 mg/nr* (9 ppm)
maximum 8-hour concentration*
40 mg/m^ (35 ppm)
maximum 1-hour concentration*
1.5 micrograms/m^
maximum calendar quarterly
average
Secondary
1,300 micrograms/in^ maximum
3-hour concentration*
150 micrograms/m^ maximum
24-hour concentration*
60 micrograms/m^ annual geometric
mean
(as guide in assessing
implementation plans)
160 mic.rograms/m^ (0.24 ppm)
maximum 3-hour concentration*
100 micrograms/m^ annual
arithmetic mean
235 micrograms/m^ (0.12 ppm)
maximum 1-hour concentration*
10 mg/m^ (9 ppm)
maximum 8-hour concentration*
40 mg/m^ (35 ppm)
maximum 1-hour concentration*
1.5 micrograms/m^
maximum calendar quarterly
average
*The maximum allowable concentration may be exceeded for the
prescribed period once each year without violating the standard.
-------
In 1974, the Environmental Protection Agency (EPA) issued regulations for
the prevention of significant deterioration of air quality (PSD) under the
1970 version of the Clean Air Act (Public Law 90-604). These regulations
established a plan for protecting areas that possess air quality which is
cleaner than the National Ambient Air Quality Standards (NAAQS). Under
EPA's regulatory plan, clean air areas of the Nation could be designated
as one of three "Classes." The plan permitted specified numerical "increments"
of air pollution increases from major stationary sources for each class, up
to a level considered to be "significant" for that area. Class I provided
extraordinary protection from air quality deterioration and permitted only
minor increases in air pollution levels. Under this concept, virtually any
increase in air pollution in the above pristine areas would be considered
significant. Class II increments permitted increases in air pollution levels
such as would usually accompany well-controlled growth. Class III increments
permitted increases in air pollution levels up to the NAAQS.
Sections 160-169 were added to the Act by the Clean Air Act Amendments of
1977. These amendments adopt the basic concept of the above administratively
developed procedure of allowing incremental increases in air pollutants by
class. Through these amendments, Congress also provided a mechanism to apply
a practical adverse impact test which did not exist in the EPA regulations.
The PSD requirements of 1974 applied only to two pollutants: total suspended
particulates (TSP) and sulfur dioxide (SO2) (See Table 10). However, Section
166 requires EPA to promulgate PSD regulations by 7 August 1980 addressing
nitrogen oxides, hydrocarbons, carbon monoxide, and photochemical oxidants
utilizing increments or other effective control strategies. For these addi-
tional pollutants, States may adopt non-increment control strategies which,
if taken as a whole, accomplish the purposes of PSD policy set forth in
Section 160.
Whereas the earlier EPA regulatory process had not resulted in the Class I
designation of any Federal lands, the 1977 Amendments designated certain
Federal lands Class I. All international parks and national memorial parks
and national parks exceeding 5,000 acres, are designated Class I. These 158
areas may not be redesignated to another class through State or adminstrative
action. The remaining areas of the county are initially designated Class II.
Within this Class II category, certain national primitive areas, national
wild and scenic rivers, national wildlife refuges, national seashores and
lakeshores, and new national park and wilderness areas which are established
after 7 August 1977, if over 10,000 acres in size are Class II "floor areas"
and are ineligible for redesignation to Class III.
Although the earlier EPA regulatory process allowed redesignation by the
Federal land manager, the 1977 amendments place the general redesignation
responsibility with the States. The Federal land manager only has an
advisory role in the redesignation process, and may recommend redesignation
to the appropriate State or to Congress.
In order for Congress to redesignate areas, proposed legislation would be
introduced. Once proposed, this would probably follow the normal legisla-
tive process of committee hearings, floor debate, and action. In order for
a State to redesignate areas, the detailed process outlined in Section 164(b)
53
-------
Table 10. Nondeterioration increments for particulate matter
and for SC>2 by area air quality classifications.
r> 11 _ ^ Class I Class II CJass III Clas^ t'
Pollutant* / / 3\ / , 3n , , dbS J increment
(MR/m ) (ug/mj) (Mg/m3). (up/m3->
Particulate matter:
Annual geometric mean 5 19 37
24-hour maximum 10 37 75 37
Sulfur dioxide:
Annual arithmetic mean 2 20 40 20
24-hour maximum 5** 91 182 9j
3-hour maximum 25** 512 700 325
*0ther pollutants for which PSD regulations will be promulgated
are to include hydrocarbons, carbon monoxide, photochemical
oxidants, and nitrogen oxides.
**A variance may be allowed to exceed each of these increments
on 18 days per year, subject to limiting 24-hour increments of
36 yg/m3 for low terrain and 62 yg/m3 for high terrain and 3-hour
increments of 130 yg/m3 for low terrain and 221 yg/ro3 for high
terrain. To obtain such a variance both State and Federal
approval is required.
Source: Public Law 95-95. 1977. Clean Air Act Amendments of
1977, Part C, Subpart 1, Section 163 (Passed August 1977).
54
-------
would be followed. This would Include an analysis of the health, environ-
mental, economic, social, and energy effects of the proposed redesignation
to be followed by a public hearing.
Class I status provides protection to areas by requiring any new major
emitting facility (generally a large point source of air pollution—see
Section 169(1) for definition) in the vicinity to be built in such a way and
place as to insure no adverse impact on the Class I air quality related values.
The permit may be issued if the Class I increment will not be exceeded, unless
the Federal land manager demonstrates to the satisfaction of the State that
the facility will have an adverse impact on the Class I air quality related
values.
The permit must be denied if the Class I increment will be exceeded, unless
the applicant receives certification from the Federal land manager that the
facility will not adversely affect Class I air quality related values.
Non-attainment provisions of the Clean Air Act, as interpreted in a ruling
of 21 December 1976 (41 Federal Register 40; 55524), stipulate that a major
new source may locate in an area with air quality worse than a national
standard (non-attainment area) only if stringent conditions be met. These
conditions are designed to ensure that emissions from the new source will
be controlled to the greatest degree possible (lowest achievable emission rate);
that more than equivalent offsetting emission reductions (emission offsets)
will be obtained from existing sources; and that there will be progress toward
achievement of the standard. For the purposes of this ruling, a major source
is defined as one having an allowable emission rate of 100 or more tons per
year of a pollutant (1,000 tons for carbon monoxide). The lowest achievable
emission rate, at a minimum, must correspond to the lowest rate achieved in
practice and must not exceed any applicable new source performance standard.
According to the Prevention of Significant Deterioration (PSD) provisions of
the Clean Air Act, a proposal for the construction of a major new source or
a major modification to an existing source (allowable emission increase of
50 tons or more per year) must undergo a preconstruction review. This review
requires the application of the best available control technology, ambient
air quality monitoring, emission modeling, and various other assessments.
Emission modeling must show that the new source or modification will not cause
increases in ambient pollutant concentrations greater than allowable increments
specified in the PSD provisions and will not cause violations of any National
Ambient Air Quality Standard.
The Clean Air Act also contains provisions regarding the use of tall stacks or
other dispersion techniques for complying with ambient air standards. Thq
height of a stack should be based on good engineering practice; it should not
exceed the height necessary to ensure that emissions do not result in excessive
concentrations in the immediate vicinity of the source as a result of atmospheric
downwash, eddies, and wakes, created by the source (2*s times the height of the
source), nearby structures, or terrain. Other dispersion techniques, including
any intermittent or supplemental control of air pollutants varying with atmo-
spheric conditions, may not be employed.
55
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I.F.3 Land Disposal of Wastes
The disposal of hazardous and non-hazardous wastes on land are regulated
under the Federal Resource Conservation and Recovery Act of 1976 (RCRA)
(P.L. 94-580), either by EPA or by a State with an approved state program.
Disposal of non-hazardous wastes on land will require the use of sanitary
landfills because disposal sites classified as open dumps are prohibited.
A site can be classified as a sanitary landfill only if disposal of wastes
at the site would pose no reasonable probability of adverse effects on
health or the environment.
Hazardous wastes are identified in 40 CFR 261 Subpart D. The hazardous
substances identified at this time in Subpart D include the major solid
wastes of the petroleum industry.
All new facilities that will generate, transport, treat, store, or dispose
of hazardous wastes must notify USEPA of this occurence and obtain a USEPA
identification number. Storage, treating, and disposal also require a
permit.
The determination of whether wastes generated or handled are hazardous is
the responsibility of the owner or operator of the generating or handling
facility. The first step is to consult the promulgated list (40 CFR 261,
Subpart D). Dissolved air flotation float, for example, is listed as a
hazardous waste. If the waste is not listed, the second step is to determine
whether the waste exhibits any of the hazardous characteristics of listed
through analytical tests using procedures promulgated in the regulations of
by applying known information about characteristics of the waste based on
process or materials used.
If it is determined that a hazardous waste is generated, it should be
quantified to determine applicability of the small generator exemption. This
cutoff point is 2,200 pounds per month, but it drops to 2.2 pounds for any
commercial product or manufacturing chemical intermediate having a generic
name listed in Section 261.33. Containers that have been used to contain less
than 21 quarts of Section 261.33 materials and less than 22 pounds of liners
from such containers are also exempt. It is anticipated that this exemption
may be available to many very small plants with, for example, only one machine
tool and one small painting operation. However, as more information is ob-
tained on the behavior of substances in a disposal enviroranent, the terms of
this exemption may be altered from time to time.
56
-------
The hazardous waste management system is based on the use of a manifest
prepared by the generator describing and quantifying the raste and d"s i ¦ \at '. ng
a disposal, treatment, or storage facility permitted to receive the type waste
described to which the waste is to be delivered. One alternate site may be
designated. Copies of the manifest are turned over to the transporter and a
copy must be signed and returned to the generator each time the waste changes
hands. If the generator does not receive a copy from the designated receiving
facility or alternate within 35 days, he must track the fate of the waste
through the transporter and designated facility or facilities. If the mani-
fest copy is not received in 45 days, the generator must file an Exception
Report with USEPA or the cognizant state agency.
A copy of each manifest must be kept for three yea rs or until a signed
copy is received from the designated receiving facility. In turn, the signed
copy must be kept for three years. The same retention period applies to each
Annual Report required whether disposal, storage, or treatment occurs on-site
or off-site.
The generator must also:
• package the waste in accordance with the applicable DOT regulations
under 49 CFR Parts 173, 178, and 179;
• label each package in accordance with DOT regulations under 49 CFR 172;
• mark each package in accordance with the applicable DOT regulations
under 49 CFR 172;
• nark each container of 110 gallons or less with the following DOT
(49 CFR 172) notice;
"Hazardous Waste - Federal Law Prohibits Improper Disposal.
If found, contact the nearest police or public safety authority
or the U.S. Environmental Protection Agency."
• supply appropriate placards for the transporting vehicle in accordance
with DOT regulations under 49 CFR Part 172, Subpart F.
57
-------
Waste in properly labelled and dated containers in compliance with the
regulations may be stored on the generator's premises for up to 90 days with-
out a storage permit. This is to permit time for accumulation for more economic
pickup or to find an available permitted disposal facility.
Due to the cost and stringent design and operating requirements for
permitted landfills, it is anticipated that most new generator plants will
utilize off-site disposal facilities. However, any companies desiring to
construct their own will be subject to 40 CFR Part 264.
Incineration is considered to be "treatment," and, as such, is also
subject to Part 264 as are chemical, physical, and biological treatment of
hazardous wastes, and a permit will be required. Totally enclosed treatment
systems--such as in-pipe treatment of acid and alkaline solutions—are not
subject to this part.
Although underground injection of wastes constitutes "disposal" as de-
fined by RCRA, this activity will be regulated by the underground injection
control (UIC) program adopted pursuant to the Safe Drinking Water Act (P.L..
9 3-523). The consolidated permit regulations (40 CFR Parts 122, 123, 124)
govern the procedural aspects of this program; the technical considerations
are contained in 40 CFR Part 146.
57a
-------
II. IMPACT IDENTIFICATION
A variety of impacts may result from waste streams generated by typical
petroleum refinery operations. These process operations were described in
some detail in Section l.B. The sections that follow outline the major
waste streams (water, air, solid waste), pollutant sources, pollutant loads
and the potential environmental impacts that should be addressed in the EID
for a new source oil refinery.
II.A. PROCESS WASTES (EFFLUENTS)
Refineries are substantial dischargers of wastewaters. Further, these waste-
waters generally have high concentrations of tars, oils and dissolved organics.
Frequently a large fraction of the dissolved organics are not readily bio-
degradable. Spent catalysts, containing large amounts of heavy metals may
create serious problems for waste treatment systems and the environment. Many
chemicals which may be found in refinery effluents such as styrene, benzene,
anthracene and phenol are believed to be toxic if they reach life forms in
harmful concentrations. Therefore, it is necessary for the permit applicant
to include best estimates for at least the following.
• All effluent streams (sources, quantities, flow composition)
• Frequency and duration of wasteflows and variations in composition
• Potential toxic chemicals
• Biological/chemical characteristics of all receiving waters and
their use patterns
II.A.1. Various Liquid Waste Sources
II.A.l.a- Raw Materials
The most significant environmental problems associated with raw materials re-
sult from the transport, handling, and storage of the crude oil.
During handling, transportation and storage of crude oil and products, residues
can impact waste streams through spills and leaks, tank-cleaning operations,
and ballast waters from tankers, which in turn, can affect environmental
quality Oil, finished product, water and other residues on storage tank
bottoms (i.e., product, intermediate, and crude storage tanks) are potential
sources of wastewaters. Filters and filter media also can contribute to waste
streams. These waste streams could adversely affect streams, estuarine and
coastal waters.
Relative to crude oil constituents, sulfur and sulfur compounds constitute the
most significant contaminants in crude oil fractions. Oxygen compounds,
nitrogen compounds and metal compounds of vanadium, nickel, iron, calcium,
mangesium, aluminum, copper, sodium, potassium, arsenic, and zinc are other
compounds which can present treating problems and potential environmental
degradation. Of the metals, vanadium, nickel and iron are the most sig-
nificant because they shorten the life of hydrodesulfurization catalysts.
Polynuclear aromatic hydrocarbons are important constituents and are known
to be toxic and/or carcinogenic.
58
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Further, the sulfur content of crude oil Is not distributed uniformly through-
out the boiling range of the oil, but is concentrated progressively in the
higher boiling fractions. The types of sulfur compounds present in crude oils
also vary. Over one hundred sulfur compounds have been identified through
analyses of only three crude oils (Rail, et al. 1962). During the past three
years, however, increasingly severe environmental restrictions have been placed
on sulfur recovery units themselves (Claus process) in terms of emission controls.
II.A.l.b. Process Wastes^1
Figure 6 shows basic oil refinery operations and the general character of their
respective wastes; the diagram includes operations typical of a complete refin-
ery (i.e., a refinery that manufactures motor fuels, burning oils, lubricating
oils and greases, waxes, asphalts and speciality products).
Because a multiplicity of potential pollutants may be generated from an inte-
grated refinery operation, for these guidelines, they have been categorized
generally as follows:
• Free oil
• Emulsified oil
• Condensate waters
• Acid wastes
• Waste caustics
• Alkaline waters
• Special chemicals
• Waste gases
• Sludges and other solids
• Clean cooling water
• Sanitary wastes
The various wastes that may pollute the environment usually originate in small
quantities from a large number of sources which are distributed widely through-
out the refinery. The sources and characteristics of the various types of
wastes that have potential to significantly effect the environment are described
below.
II.A.1.c. Free Oil
Depending on the efficiency of pollution control measures used, large integrated
refineries may be expected to have varying amounts of their crude oil charge
escape to the sewers in the form of free oil.
The presence of light ends creates a potential explosion hazard in the sewers.
For this reason precaution should be taken in the design of the sewerage
system to adequately trap all sewer inlets.
Oil exists in the wastewater in three fractions:
• Suspended fraction (small droplets, small solids-oil agglomerates,
oil in water emulsion)
• Floating fraction (water in oil emulsion or free oil)
• Settleables
In practically all cases gravity differential oil-water separators are pro-
vided to recover floating oil and to treat the waste. In the process of
separating oil from water, oil rises to the surface, sediment (containing
oils) settles to the bottom and relatively small concentrations of oil and
suspended solids pass through the separator. Some solid matter rises to the
This summary discussion is based largely on the following more detailed source
documents: USEPA 1976 a-d; 1967 Ind. Waste Treatment, USEPA 1973.
59
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Coke From Equipment
Tub#* ond Towers
Fro and Emulsified Oil
From Leaks, Spills, Ois-
tillate Separators, Con-
densots Water and/or
Tank Drowoff
Solutions of Anti-Cor-
rosion Additives ond/or
Wotsr-Sciutte Constit-
uents of the Charge
from Distillate S»porotor»„l
Condensate Woter ond^rf
Tor* Orowofl
Waste Chemical
Solution* from 60s
Purification
Free and Emulsified
Oil From Leaks, Spills,
ond/or Tank Drawofr
Tank Bottom
SludQe
Tank Bottom
Sludge
Caustic Sludges, Woste
Caustic ond Alkaline Water
From Coustte Treatment of
Oils
Acid Sludges, Acid ond/or Ai -
kaline Waters ond Emulsions
from Acid Treatlng,Neutro-
liring and Washing of Oils
Solutions of Anti-cor-
rosion Additives ond/or
Woter-Soluble Constit-
uents of the Crude
from Distillate Separa-
tor*, Condensate Woter
ond/or Took Drowoff
Free and Emulsified Oil
from Leaks, Spills, Dis-
tillate Separators, Con-
densate Woter and/or
Tonfc Orqwoff
Coke from Equipment
Tubes ond Towers
Tonk Bottom Sludge
I Wok Toiling*
I Condenser Woter
Selective Solvents from
Leaks, Spills,Axeotropic
QHtiltations, etc
Condenser
Water
T—
Free ond Emulsified Oil
from Lsoks, Spills, Sw-
eating Ovens, Centrifu-
ges, etc
Special Chemicals from Leaks, Spils
and Wdste by Products
Oil from Laboratories,Floor Washing,Cutting
Tod ond Bone! Washing Emulsions, etc
Oil and Aephoit from Leaks,
Spills and Tank Cleaning
| Condenser Water |
I Product
\ Slorogi 1
| Tank Cloooina Wottt*
Special Chemicals from
Lookt and Sp»l«
1 from Watar Tmating,
' Blowdoan and Slop
I fronting Bottoms
Sanitary Woof«
Oil from Looks ond
Spill*
Tank CI toning Wast»7|
Aspiioll from Look* ft
Spills
Tank atoning Wastos
Figure 6. Typical wastes produced in a complete
petrolcum
re 1 morv,
59a
-------
surface with the oil and some oil settles to the bottom with the solids. It
also should be noted that gravity differential oil-water separators cannot
remove oil in the form of oil in water emulsions or in the form of oil-sus-
pended solids agglomerates with specific gravities approximately that of the
water or water soluble fractions, air flotation, in which finely divided air
bubbles carry upward where they are collected.
II.A.l.d. Emulsions of Oil
The presence of oil that cannot be separated from waste waters by conventional
gravity differential means can significantly impact the environment- however
it also is of considerable economic importance to the refiner because of the*
loss of valuable product and the need for costly facilities to treat the
effluent from oil recovery separators.
An oil in water emulsion has turbididty as its chief characteristic and
usually has a milky or pearly-gray appearance. This type of emulsion is not
removed in the gravity type oil separator, and when it is discharged into a
large stream or body of water, it usually breaks as a result of dilution and
the oil rises to the surface of the water.
Emulsions also may be formed in the sewerage system as a result of intimate
contact between oil, water, and emulsifying agents or may originate directly
as process byproducts.
The occurrence of coke, clay, sanitary sewage, water treating plant sludges
and other flocculent and fibrous solids appears to increase the concentration
of nonseparable oil. The presence of tars, asphalts, petroleum sludges, soaps
and numerous solvent and treating chemicals also increases the nonseparable
oil content of waste waters. The pumping of wastewater is especially conduciv
to the formation of emulsions. e
The direct formation of emulsions may result from the chemical treatment of
lubricating oils, waxes and burning oils, from distillate separators, from
barometric condensors, tank drawoffs, desalting operations, pump gland leak-
age, special chemical manufacturing, acid sludge recovery processing, wax
deoiling, barrel and truck washing, machine shops and other sources.
Emulsions can be broken by changing the pH, adding various chemicals or the
use of electrical emission breakers.
II.A.I.e. Condensate Waters
Condensate waters originate from distillate separators, running tanks, and
barometric condensers. It has been reported (Teague 1950) that condensate
waters from distillate separators may contain one or more of such compounds
as organic and inorganic sulfides, normal or acid sulfites and sulfates,
sulfonic acids and their salts, mercaptans, amines, amides, quinalines and
pyridines, napthenic acids, phenols, etc. They also may contain chemicals
used for corrosion prevention such as ammonia, caustic soda, calcium
hydroxide, etc. Not all these substances will be found in a specific waste-
water at the same time. Waste of this type also may contain suspended matter
60
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such as coke, iron sulfide, silica, metallic oxides, soaps, emulsions, sulfonic
and naphthenic acids, insoluble mercaptides and other suspended solids (Teague
1950).
II.A.l.f. Acid Wastes
Sulfuric acid is used extensively in the petroleum industry both as a treating
agent and a catalyst. Other acids and acid salts also used as catalysts include
hydrofuoric acid, phosphoric acid, aluminum chloride and zinc chloride. Acid
bearing wastes originate form the acid treatment of gasoline, white oils,
lubricating oils and waxes; from the handling of acid sludges and the recovery
or manufacture of acid; from the alkylation of motor fuel stocks; from the use
of acidic catalysts; and from special chemical manufacturing.
II.A.l.g. Waste Caustics
Waste caustics originate from the caustic washing of light oils to remove
mercaptans, hydrogen sulfide, and other acidic materials that occur
naturally in crude oil or any of its fractions or may be produced by a
variety of processing methods.
The constituents of waste caustics responsible for their potent pollution
characteristics include mercaptans, thiophenol, thiocresols, phenols, cresols,
disulfides, alkylsulfides, the sodium salts of any one of a number of saturated
mono acids, naphthenic acids or sulfonic acids and other materials.
II.A.l.h. Alkaline Waters
Alkaline waters, as differentiated from alkaline condensate waters and waste
caustics, may originate from the washings of neutralized acid treated oils,
the washings of caustic treated oils, the dehydration of treated light oils,
the aqueous tank bottoms of stored caustic treated and washed gasolines,
vessel and tower washings at times of shutdowns and miscellaneous sources.
II.A.l.i. Special Chemicals
This category of wastes includes the special solvents and extraction solutions
utilized in selective solvent refining, gas purification, light oil treating,
etc. Such special chemicals utilized in petroleum processing may include
phenol, creosols, furfural, salts of isobutyric acid, nitrobenzene, acetone,
methyl ethyl ketone, B.B. dichlorethyl ether, ethylene dichloride, benzol,
tannin, fatty acids, diethanol amine, methanol, toluol sodium hypochlorite,
tri-sodium phosphate, lead sulfide, copper chloride and others. These special
chemicals may create serious waste control problems. The water soluble organics,
for example, can add tremendously to the oxygen demand characteristics of the
plant wastes if allowed to discharge into the sewers. Others listed are emul-
sifying agents and would adversely affect separator operation if allowed to mix
with other refinery wastes. Frequently, the value of these materials is suf-
ficient to justify the use of collection and recovery systems. Drainage from
leaks, spills, pumps, valves, sampling, routine maintenance activities, etc.,
often is recovered to keep losses to a minimum.
61
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II.A.2. Sources and Quantities of Process-Related Wastes
The permit applicant should identify all sources of process wastes, preferably
by means of a schematic or flow diagram. The checklist that follows indicates
the major process operations and the associated wastewater streams that should
receive a careful, systematic analysis in the E]D .
• Crude Desalting
- Desalter wastewater
• Crude Oil Fractionation
- Wastewater from overhead accumulators
- Oil sampling lines
- Barometric condensers
• Cracking
- Overhead accumulator wastewater (thermal cracking)
- Wastewaters from steam strippers and overhead accumulators on
fractionators (catalytic)
• Hydrocarbon Rearranging
- Wastewater from polymerization process
- Alkylation wastewater streams resulting from the neutralization
of hydrocarbon streams leaving the sulfuric acid alkylation
reactor
- Wastewater from overhead accumulator
- Wastewaters from hydrofluoric acid alkylation rerun-unit
• Hydrocarbon Rearrangements
- Wastewater from overhead accumulator
• Solvent Refining
- Fractionation tower bottoms
• Hydrotreating
- Wastewater from hydrotreatment unit
• Grease Manufacturing
- Wastewater from grease manufacturing unit
• Asphalt Production
- Wastewater from asphalt-blowing operations
• Product Finishing
- Wastewater from drying and sweetening (H2S removal) process
- Lubricating oil finishing wastes (acid-bearing wastes, rinse
waters, sludges and discharges resulting from acid treatment
of lubricating oils)
- Wastewaters from blending and finishing operations
- Washing of railroad tank cars or tankers prior to loading
- Tetraethyl and tetramethyl lead additives. These anti-knock
compounds are extremely toxic and can gain entrance to waste-
waters via two avenues: (1) TEL and TML are separated from
other compounds by a steam distillation and purification
process. Water is then contaminated by the condensing steam;
(2) TEL and TML are present in tank bottom sludges and con-
taminate waters through washings and other maintenance.
• Auxiliary Activities
- Process wastes from hydrogen manufacture
- Utilities functions (steam and cooling water systems)
- Blowdowns from closed-loop recirculating systems
- Sour water stripper
- General housekeeping
62
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Table 11 presents a qualitative matrix showing the relative contributions of
pollutants from various refinery operations.
The estimated wastewater pollutant loadings and volumes per unit for the major
refinery processes are present in Table 12. Also the table makes a distinction
between process technologies (old, typical, new) and the waste loads that can
be expected from each.
II.A.3. Sources and Quantities of Wastewater from Transportation Activities
One of the most unpredictable sources of wastewaters from oil refineries are
those associated with the transportation of feedstock and product to and from
refineries. Although some of the discharges are associated with the accident-
al spillage from transport lines, tanker and truck washings, the major concern
is associated with tanker and truck accidents and the spillage from a major
tanker breakup.
The applicant must consider several key factors to predict the occurrence of
and impact from tanker accidents. These include:
• Characteristics of the waterways to and from the unloading location
(e.g., narrow passageways with frequent fog and inclement weather
conditions, high tides and severe wave action will necessarily have
a higher incidence of accidents)
• Nature of the navigational controls and guides available in harbors
and passages
• The sophistication and availability of cleanup equipment
• Environmental sensitivity and value of ecosystems within the
transport corridor
• Historical record of occurrences of tanker accidents under similar
conditions
To assess adequately the potential impacts from an accidental oil spill, one
approach could be to develop and evaluate a range of scenarios involving
potential tanker accidents of various magnitudes in high probability areas.
From this, a projection of ecological consequences could be made for purposes
of Inclusion in the EID. Table 13 presents a generalized summary of the types
and magnitude of tanker accidents throughout the world. It gives an indication
of the types and sizes of accidents that historically have been most frequent
and significant.
II.B. PROCESS WASTES (AIR EMISSIONS)
Sources of air emissions and air pollutants differ considerably among refineries
which largely is a function of:
• Size of refinery
• Type of crude oil feedstock
0 Product mix (which dictates the type and complexity of processes
employed)
• Pollution control measures
Because of the wide variations possible in the above factors, new refineries
63
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Table 11. Qualitative evaluation of wastewater flow
and characteristics by fundamental refinery processes.
Fundamental
Processes
Flow
BOD
COD
Phenol
Sulfide
Oil
Emulsified
Oil
pH Temp.
Ammonia Chlorides Acidity Alkalinity
Crude Oil and
Product Storage
XX
X
XXX
—
—
XXX
XX
0
0
0
0
Crude Oil Desalting
XX
XX
XX
X
XXX
X
XXX
X
XXX
XX
XXX
0
X
Crude Oil
Distillation
XXX
X
X
XX
XXX
XX
XXX
X
XX
XXX
X
0
X
Thermal Cracking
X
X
X
X
X
X
—
XX
XX
X
X
0
XX
Catalytic Cracking
XXX
XX
XX
XXX
XXX
X
X
XXX
XX
XXX
X
0
XXX
Hydrocracking
X
—
—
—
XX
—
—
—
XX
—
--
—
—
Reforming
X
0
0
X
X
X
0
0
X
X
0
0
0
Polymerization
X
X
X
0
X
X
0
X
X
X
X
X
0
Alkylation
XX
X
X
0
XX
X
0
XX
X
X
XX
XX
0
Isomerization
X
—
—
—
-~
—
—
—
—
—
—
—
—
Solvent Refining
X
—
X
X
0
—
X
X
0
—
0
X
Dewaxing
X
XXX
XXX
X
0
X
0
—
—
—
—
—
—
Hydrotreating
X
X
X
—
XX
0
XX
—
0
0
0
X
Susp.
XX
XXX
X
X
X
0
X
XX
Drying and
Sweetening XXX XXX XXX00XXX0X 0 X XXX
Legend
XXX - Major contribution
XX - Moderate contribution
X - Minor contribution
0 - No Problem
— - No data
Source: US-DOI. 1967. The cost of clean water. Volume III, Industrial Waste Profile No. 5: Petroleum Refining.
FWPCA Publication No. I.W.P.-5. Available from US-GPO. Washington, DC.
-------
Table 12. Estimated waste loadings and volumes per unit of fundamental process throughput for older, typical, and newer process technologies
Older Technology Typical Technology Newer Technology
Mercaptans Mercaptans Mercaptan:
Flow BOD Phenol ^Sulfides Flow BOD Phenol SSulfides Flow B0D Phenol ^Sulfides
Fundamental Process (gal/bbl) (lb/bbl) (lb/bbl) (lb/bbl) (gal/bbl) (lb/bbl) (Ib/bbl) (lb/bbl) (gal/bbl) (lb/bbl) (lb/bbl) (lb/bbl)
Crude Oil and Product Storage
4
0.001
-
-
4
0.001
-
-
4
0.001
-
-
Crude Desalting
2
0.002
0.20
0.002
2
0.002
0.10
0.002
2
0.002
0.05
0.002
Crude Fractionation
100
0.020
3.0
0.001
50
0.0002
1.0
0.001
10
0.0002
1.0
0.001
Thermal Cracking
66
0.001
7.0
0.002
2
0.001
0.2
0.001
1.
5 0.001
0.2
0.001
Catalytic Cracking
85
0.062
50.0
0.03
30
0.010
20
0.003
5
0.010
5
0.003
Hydrocracking
not in this
technology
not in this
technology
5
tr
0.7
-
Reforming
9
tr
0.7
tr
6
tr
0.7
0.001
6
0.001
Polymerization
300
0.003
1.4
0.22
140
0.003
0.4
0.010
not in this
technology
Alkylation
173
0.001
0.1
0.005
60
0.001
0.1
0.010
20
0.001
0.1
0.020
Isomerization
not in this
technology
not in this
technology
-
Solvent Refining
8
-
3
tr
8
3
tr
8
-
3
tr
Dewaxlng
247
0.52
2
tr
23
0. SO
1.5
tr
20
0.25
1.5
tr
Hydrotreating
1
0.002
0.6
0.007
1
0.002
0.01
0.002
8
0.002
0.01
0.002
Deasphalting
-
-
-
-
-
-
-
-
-
-
10
-
Drying and Sweetening
100
0.10
10
-
40
0.05
10
-
40
0.05
Wax Finishing
-
-
-
-
-
-
-
-
-
-
-
-
Grease Manufacture
-
-
-
-
-
-
-
-
-
-
~
Lube Oil Finishing
-
-
-
-
-
-
-
-
-
-
~
-
Hydrogen Manufacture
not in this technology
not in this technology
-
-
"
—
Blending and Packaging
- Data not available for reasonable estimate.
tr - trace
Source: US-DOI. 1967. The cost of clean water. Volume III, Industrial Waste Profile No. 5: Petroleum Refining. FWPCA Publication No. I.W.P.-5.
Available from US-GPO, Washington, DC.
-------
Table 33. Types and magnitude of tanker casualties worldwide.
Percent of Percent of
Type of Casualty Polluting Incidents Pollution Resulting
Structural Failures
19
49
Groundings
26
29
Collisions
31
8
Explosions
6
8
Rammings
8
1
Fires
7
1
Breakdowns and Other
2
4
Percent of Total
Range-Barrels Percent of Incidents Oil Released
1 to 1,000 63-47 5-75
1,001 to 3,500 22.37 11.29
3,501 to 20,000 10.05 16.07
20,001 to 100,000 3.65 37.74
> 100,000 °-46 39.15
Source: US-EPA. 1975. Environmental impact assessment guidelines for
selected new source industries. Office of Federal Activities
Washington, DC.
66
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normally must be assessed on an Individual basis. There are, however, certain
types of emissions which must be addressed in an emission assessment of any
refinery, and there are certain major sources of emissions which must be
evaluated if they are part of the refinery's process scheme-
Specifically the EID should identify, describe (quantitatively), and evaluate
all such refinery air emissions. Interim heat releases, start-up, shut-down,
safety valve releases, leaks and any other potential sources of emissions
should be documented in the EID. Major sources of air waste streams from a
petroleum refinery include:
¦ Storage tanks
• Catalyst regeneration units
• Pipeline valves and flanges
• Pressure relief valves
• Pumps and compressors
• Compressor engines
• Acid treating
• Wastewater separators and
process drains
The waste gases from petroleum refining are stack gases from furnaces and
reactors, hydrogen sulfide and sulfur dioxide. Except that stack gases may
be used in waste treatment processes or may be scrubbed with water for solids
removal they do not enter into water pollution control problems.
The acid gases (hydrogen sulfide and sulfur dioxide), however, may cause
water pollution control problems. Hydrogen sulfide as produced from the
distillation of crude and other processing is a contaminant to other refinery
gases (i.e., methane, ethane, etc.). The removal of hydrogen sulfide from
liquid and gaseous hydrocarbon stream creates wastewaters of highly obnoxious
characteristics. These wastes were discussed briefy in section I.E.3.
Sulfur dioxide is produced from stack gases, sulfuric acid concentrators,
liquid sulfur dioxide refining units and sulfuric acid treating units. Nor-
mally sulfur dioxide wastes are discharged to the atmosphere. However, not
infrequently atmospheric pollution problems must be corrected and the cor-
rective measures may create water pollution problems. The utlization of
sulfur dioxide for the recovery of sulfur offers the best long term solution
to the problem of pollution abatement. In addition to the formation of SO2
during the combustion of sulfur-containing liquid refinery fuels, NOx forma-
tion can be enhanced if those fuels also contain nitrogen compounds. This
NOx, as well as the small amount of SO3 formed from sulfur compounds in the
fuel, tend to be the principal cause of stack plumes from refinery furnaces.
Carbon monoxide and particulate emissions also occur, however, they largely
are confined to flue gases from catalytic crack regenerators and fluid cokers
(unless coal or coke are used as fuel).
• Cooling towers
• Loading facilities
• Blowdown systems
• Pipeline blind-flange changing
• Boilers and process heaters
• Vacuum jets
• Sampling
•Air blowing
67
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The principal types of air pollutants from various emission sources are shown
in Table 14.
II.C. PROCESS WASTES (SOLID WASTES)
Typical solid wastes generated at a refinery include process sludges, spent
catalysts, and various sediments. The applicant should identify all solid
waste streams and provide a flow diagram which quantitatively and qualitativelv
describes their characteristics.
Refinery solid wastes are grouped into three general categories:
• Process solids
• Effluent treatment solids
• General wastes (scrap materials, etc.)
Tank bottom sludges vary greatly in their characteristics, e.g., from an
easily pumpable fluid to a set solid. In general these wastes may be treated
for oil recovery or burned as fuel. Sometimes for the purpose of tank clean-
ing it is advantageous to flush these materials from the tanks using water.
In some cases water flushing will create emulsions and suspensions that will
produce unsatisfactory waste water effluents. The use of water flushing
should be avoided as much as possible.
One of the major sources of sludge of high pollutional characteristics is
the acid treatment of refinery stocks (See Section I.E.3. Acid Wastes).
Sludge accumulating at the bottom of cooling towers generally is adaptable
to disposal as fill. However, the removal of the sludge from the tower
basin and the transfer of the material to the point of final disposal can
pose numerous problems in cleaning, transportation and storage.
Sludge from the clarification of water for process use create the same type
of problem as that of cooling tower sludge.
Sludge from the softening of water may be utilized, in some cases, for the
neutralization of acid waters or as a coagulant aide in wastewater treatment
Table 15 presents sources, descriptions, and characteristics of various cate-
gories of solid wastes generated from refinery operations. Table 16 lists
the range of factors that can affect the composition and quantity of solid
waste streams. Such factors should be considered by a new source applicant
in designing control measures for solid waste generation and disposal.
Many solids may contain significant amounts of leachable heavy metals and
organics which could contaminate the environment if not treated and disposed
of properly. Therefore, to evaluate the potential impacts from solid wastes
68
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Table 14. Major air pollutants emitted from
various refinery sources.
Pollutant
Oxides of Sulfur
Hydrocarbons
Oxides of Nitrogen
Particulate Matter
Aldehydes
Ammonia
Odors
Carbon Monoxide
Boilers, process heaters, catalytic cracking unit
regenerators, treating units, H2S flares, decoking
operations
Loading facilities, turnarounds, sampling, storage
tanks, wastewater separators, blow-down systems,
catalyst regenerators, pumps, valves, blind changing,
cooling towers, vacuum jets, barometric condensers,
air-blowing, high pressure equipment handling
volatile hydrocarbons, process heaters, boilers,
compressor engines
Process heaters, boilers, compressor engines, catalyst
regenerators, flares
Catalyst regenerators, boilers, process heaters,
decoking operations, incinerators
Catalyst regenerators
Catalyst regenerators
Treating units (air-blowing, steam-blowing), drains,
tanks vents, barometric condenser sumps, wastewater
separators
Catalyst regeneration, decoking, compressor engines,
incinerators
Source: US-DHEW. 1960. Atmospheric emissions from petroleum refineries.
Public Health Service Publication No. 763, Washington, DC.
69
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Table 15« Categorization of representative solid wastes from various petroleum refining sources.
Waste Category
Process Solids
Wa9te Sources
Crude oil storage, desalter
Catalytic cracking
Coker
Alkylation
Lube oil treatment
Drying and sweetening
Storage tanks
Slop oil treatment
Waste Description
Waste Characteristic
Basic sediment and water
Catalyst fines
Coker fines
Spent sludges
Spent clay sludges, press dumps
Copper sweetening residues
Tank bottoms (crude, leaded,
non-leaded)
Precoat vacuum filter sludges
Iron rust, iron sulfides, clay, sand, water
oil
Inert solids, catalyst particles, carbon
Carbon particles, hydrocarbons
Calcium flouride, bauxite, aluminum chloride
Clay, acid sludges, oil
Copper compounds, sulfides, hydrocarbons
Oil, water, solids
Oil, diatomaceous earth, solids
Effluent Treatment
Solids
API separator
Chemical treatment
Air flotation
Biological treatment
Separator sludge
Flocculant aided precipitates
Scums or froth
Waste sludges
Oil, sand and various process solids
Aluminum or ferric hydroxides, calcium carbonate
Oil, solids, flocculants(if used)
Water, biological solids, inerts
General Waste
Water treatment plant
Office
Cafeteria
Shipping and receiving
Boiler plant
Laboratory
Plant expansion
Maintenance
Water treatment sludges
Waste paper
Food wastes (garbage)
Packaging materials, strapping
pallets, cartons, returned
products, cans, drums
Ashes, dust
Used samples, bottles, cans
Construction and demolition
General refuse
Calcium carbonate, alumina, ferric oxide, silica
Paper, cardboard
Putrescible matter, paper
Paper, wood, some metal, wire
Inert solids
Glass, metals, waste products
Dirt, building materials, insulation, scrap metal
Insulation, dirt, scrapped materials-valves,
hoses, pipe
Source: US-EPA. 1975. Environmental impact assessment guidelines for selected new source industries. Office of Federal Activities, Washington, DC
-------
Table 16. Factors affecting the composition and
quantity of specific solid waste streams.
Solid Waste
Potential Factors
Crude tank bottoms
Leaded tank bottoms
Type of crude
Treatment given to crude prior to storage
Slop oil processing method
Refinery size
Mixing, if any
Storage time
Degree, if any, of sludge emulsion breaking
Type and quantity of chemical additives
Plant and tank metallurgy
Type of product treatment used
Type of processes used in producing gasoline and/or
other products
Refinery size
Non-leaded tank bottoms
API separator sludge
Type and quantity of chemical additives
Plant and tank metallurgy
Type of product treatment used
Type of processes used in producing gasoline and/or
other products
Refinery size
Composition and quantity of process wastewater
Composition and quantity of spills and leaks
Composition and quantities blowdowns
Refinery housekeeping
Refinery size and age
Segregation of refinery sewers
Neutralized HF
alkylation sludge
Spent filter clays
Once-through cooling
water sludge
Composition of fresh hydrofluoric (HF) acid
Composition of lime
Feedstock composition
Process operating conditions
Hydrofluoric acid alkylation process metallury
Size of hydrofluoric acid
Type and number of clay treatment processes used
Type and number of products treated
Composition and quantity of products treated
Type and amount of clay used
Refinery size
Composition and quantity of raw water
Cooling system metallurgy
Size and nature of process leaks
Refinery size and complexity
71
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Table 16. Factors affecting the composition and quantity of specific solid
waste streams (Continued)•
Solid Waste
Potential Factors
DAF float
Same factors as API separator sludge plus:
Residence time
Amount and time of flocculating chemical used
Efficiency of API separator
Slop oil emulsions
solids
Spent lime from boiler
feedwater treatment
Cooling tower sludge
Exchanger bundle
cleaning sludge
Waste bio-sludge
Stormwater silt
Composition and quantity of individual oil spills
and oil leakage
Composition of wastewater emulsions
Nature of emulsion breaking treatment and degree of
success
Refinery size and complexity
Quantity of oil in wastewater and degree of removal
Composition of raw water
Degree of hardness removed
Type of treatment (hot or cold)
Refinery size
Boiler blowdown rates
Percent condensate recovered and returned to boilers
Make-up water composition
Type of chemical treatments employed
Metallurgy of cooling water system
Nature of contaminants introduced by process leaks
Blowdown rate
Make-up water rate
Quantity of treatment chemicals used
Composition of shell and tubeside fluids
Equipment metallurgy
Effectiveness of desalter
Refinery size and complexity
Effectiveness of corrosion inhibitor systems
Composition and quantity of wastewater treated
Type of biological treatment
Efficiency of prior treatment units
Operating conditions and practice
Dewatering and/or treatment
Plant housekeeping
Amount of rain
Amount of refinery area paved
Segregation of surface drainage
72
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Table 16. Factors affecting the composition and quantity of specific solid
waste streams (Concluded).
Solid Waste Potential Factors
FCC catalyst fines Catalyst compositon
Oil composition
Type of process
Process operating conditions (temperature, percent
conversion, recycle feed rate)
Catalyst make-up rate
Process metallurgy
Oil feed rate
Number of cyclones
Use of precipitators
Use of elutriators
Coke fines Oil composition
Type of process
Operating condition (temperature, pressure, time)
Process metallurgy
Method of coke removal
Method of handling and shipping
Number of cyclone stages
Oil feed rate
Source: US-EPA. 1976. Assessment of hazardous waste practices in the
petroleum refining industry. Prepared by Jacobs Engineering
Company. NTIS Publication PB-259 097, Washington, DC.
73
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the applicant should provide at least the following information in the EID:
• Source and quantity of solid wastes generated
• Chemical composition of solid wastes generated
• Composition of possible hazardous leachates from solid wastes
(quantitative)
• Proposed measures to handle and dispose of solid wastes and the
ecological sensitivity of all proposed deposition areas
Table 17 lists typical refinery pollutants by source. Pollutants are listed
in terms of 1,000 barrels of crude oil processed. Total emissions and efflu-
ents quantities can be approximated (although often the existing data base
was unsuitable for projecting certain pollutant levels).
II.D. TOXICITY AND POTENTIAL FOR ENVIRONMENTAL DAMAGE FROM SELECTED
POLLUTANTS
II.D.l. Human Health Impacts
Airborne and waterborne emissions from petroleum refineries may contain sub-
stances which could seriously affect human health. Both heavy metals and a
variety of complex hydrocarbons are emitted from refinery operations. Petrole-
um-related contamination of ground water drinking supplies is another serious
problem. The following paragraphs describe briefly the major health-related
effects of selected pollutants.
II.D.l.a. Carcinogens
During various refinery operations a worker may be exposed to such suspected
carcinogens as arsenic, benzene, cadmium, chromium, cobalt, lead, vanadium
and certain organics. Likewise these carcinogens may pose a threat to those
in the plant vicinity. These and other trace metals along with their potential
health problems are presented in Table 18; references to detailed research
studies are provided.
II.D.l.b. Sulfur Dioxide, Hydrogen Sulfide, and Mercaptans
The impact of high concentrations of sulfur dioxide and sulfates (especially
in the presence of particulates), has been well documented (USEPA 1970). Nor-
mally emissions of sulfur dioxide from petroleum refineries would not produce
concentrations that would exceed national ambient air quality standards. How-
ever, even SO2 levels below national ambient air quality standards may produce
some adverse impacts upon sensitive receptors. The formation of sulfates at
very low concentrations of sulfur dioxide may produce significant eye and
respiratory problems (Science Applications, Inc. 1975) as well as damage to
vegetation and to certain materials (metal surfaces).
Likewise hydrogen sulfide and other reduced sulfur compounds (i.e., mercaptans)
is strongly Irritating to the respiratory organs. At high concentrations
(1,000 mg/m3), hydrogen sulfide is extremely toxic and may paralyze the brain
center that controls respiratory movements (Cavanaugh 1975).
74
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Table 17. Summary of pollutant sources and projected pollutant concentrations.
Pollutant Levels kg/1000 bbl.(lbs./1000 bbl,).
Source of Pollutant
BOD
COD Particulates
NOx
SQx Hydrocarbons
Solids
Transport
Crude or product
-
-
-
—
—
-
-
Pipeline
-
-
.86(1.9)
24.94(55)
1.81(40)
2.50(5.5)
-
Tankers
-
-
.18(04)
17.27(38)
2.63(5.8)
.09(0.2)
-
Supertankers
-
-
.19(. 042)
17.27(38)
2.63(5.8)
.09(0.2)
-
Barges
-
-
15.42(34)
10.90(24)
11.79(26)
7.26(16)
-
Tank Trucks
-
-
3.17(7)
95.26(210)
6.80(15)
9.53(21)
-
Tank Cars
-
—
6.35(14)
19.50(43)
16.78(37)
13.15(29)
-
Processing
Crude desalting
.45
—
0(0)
0(0)
0(0)
0(0)
0(0)
Crude fractionation
.09(0.2)
2.27(5)
1.04(2.3)
12.25(27)
.045(0.1)
15.42(34)
-
Cracking
6.8(15)
8.16(18)
7.71(17)
46.27(102)
136.08(300)
19.96(44)
21.77(48)
Hydrocarbon rebuilding
5.4(12)
64.41(142)
3.17(7)
50.80(112)
.045(0.1)
34.92(Ti)
-
Hydrocarbon rearrangement
-
18.14(40)
2.27(5)
65.32(144)
.023(0.05)
15.72(34)
-
Solvent refining
-
-
-
-
-
40.82(90)
-
Hydrotreating
43.1(95)
45.36(100)
2.27(5)
22.68(50)
-
54.43(120)
-
Grease manufacturing
-
-
-
-
-
10.43(23)
-
Asphalt production
—
14.51(32)
2.72(6)
31.75(70)
.090(0.2)
15.88(35)
-
Storage
Crude
.45(1)
—
0
0
0
28.12(62)
—
Product
-
-
-
-
-
9.53(21)
-
Source: US-EPA. 1974. Environmental Impacts, efficiency and cost of energy supply and end use. Volume 1
Final Report. Prepared by Hittman Associates, Washington, DC.
-------
Table 18. Possible health problems associated with trace metals
Metal or metal compounds
Aluminum, arsenic,
cadmium, cobalt,
copper, iron, lead,
and zinc oxides
Nickel
Cadmium
Chromium and compounds
Arsenic
Cobalt
Lead and compounds
Mercury and compounds
Vanadium
Zinc
Health problems
Enzymatic inference
Fume fever
Reference
(Waldbott 1973)
Nasal cancers
Prostate cancer
Enzymatic interference
Carcinogenesis
Cancer of the skin
Poisoning
Carcinogenesis
Nasal cancers
Kidney damage
Mutagenic and
teratogenic effects
Inhibition of lipid
formation; eye and
respiratory irritant;
carcinogenic
Gastrointestinal
irritation
(Potts 1965)
(Gilman and
Ruckerbauer 1963)
(Potts 1965)
(Kipling and
Waterhouse 1967)
(Hueper 1961)
(Wickstrom 1972)
(Lee and Fraumeni
1969)
(Gilman and
Ruckerbauer 1963)
(Zawirsica and
Medras 1968)
(Zollinger 1953)
(D'ltri 1972)
(Stokinger 1963)
(Waldbott 1973)
76
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II.D.I.e. Nitrogen Compounds
Nitrogen oxides are pulmonary irritants and may impair the ability of the
lungs to clear inhaled infectious organisms. Exposure to nitrogen dioxide
also can be corrosive to the mucous lining of the lungs. At high concentra-
tions, it may cause pulmonary edema and even death, while chronic exposure
may produce emphysema, polyeythamia, and leukocytosis. Further, nitrogen
oxides have been shown to contribute to the formation of photochemical smog
(USEPA 1971c).
II.D.l.d. Hydrocarbons
Apart from their potential carcinogenic activity, hydrocarbons play a vital
role in the formation of photochemical smog (USEPA 1971b) .
II.B.I.e. Carbon Monoxide
The toxicity of carbon monoxide is associated with its reactions with hemo-
proteins. Generally one can anticipate that there will be no increase of
ambient concentrations of CO beyond national ambient air standards as a re-
sult of refinery emissions.
II.D.l.f. Ammonia
Ammonia is a highly irritating gas with a strong, pungent odor. It forms
ammonium hydroxide when it comes in contact with the moisture of the throat
and bronchi. Ammonium hydroxide is caustic, but it is not usually considered
a threat to human health. Extremely high concentrations, however, (1,700-
4,500 mg/m^) can produce pulmonary edema (Waldbott 1973).
II.D.l.g. Trace Metals
Among the possible health problems associated with trace metals are those shown
in Table 18. The appropriate references should be reviewed by the permit
applicant to ascertain the significance of the impact as associated with trace
metal emissions from the proposed petroleum refining facility.
To adequately evaluate potential impacts to human health, the applicant should
include at least the following information in the EID;
• Analysis of metal-containing catalysts used in the refining process
• Analysis of crude oil to be used in the refining process
• Projection of emissions of potentially toxic substances (volumes,
frequencies, and duration)
• Analysis of sensitive receptors (by use of isopleths or other suit-
able technique)
• Groundwater parameters including depth to water, direction of flow,
interflow between ground and surface waters, stratigraphy to aquifer
local groundwater withdrawals
• Projection of ground level maximum concentrations of potentially
hazardous substances
• Description of proposed measures to avoid or reduce potential
adverse effects from toxic materials
77
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II.D.2. Biological Impacts
The biological environment also may be affected by certain pollutants especially
heavy metals and certain chlorinated and cydic hydrocarbons which are toxic to
many terrestrial and aquatic organisms.
The potential impacts on terrestrial and aquatic biota may be categorized by
the following waste streams and pollutants:
• Air pollutants - emissions of heavy metals, sulfur compounds,
particulates, and hydrocarbons
• Wastewater discharges - water pollutants such as heavy metals
and toxic organics from process wastes, leachate from solid
waste residues.
• Solid wastes - stockpiling and disposal of process sludges and
other solid wastes (spent catalysts, sediments)
At a minimum the following factors should be described in the EID to assess
adequately the extent and significance of impacts to biological resources:
• Discharges and sinks for specific toxic materials such asxheavy
metals and organics, including information on conventional and
priority (consent decree) chemicals, volume, duration, and time
of discharges)
• Characteristics of the aquatic and terrestrial biota of the impact
area (species composition, diversity, abundance, densities, impor-
tance values)
• Description of economic, aesthetic, recreational and other uses
or potential uses of the aquatic and terrestrial receiving en-
vironments
• Complete characterization of the aquatic land and air environ-
ments that are to receive waste discharges
• Determination of tolerance or sensitivity thresholds for selected
species of plants and animals in the impact area
• Proposed measures to avoid or reduce adverse impacts to biological
communities
II.E. OTHER IMPACTS
II.E.1. Raw Materials Extraction and Transportation
EPA requires that the environmental impacts of all activities directly caused
or induced by a new source industry be assessed. A new petroleum refinery
may cause changes in the level and nature of activities for extraction, trans-
portation and handling of crude oil raw materials and various metals such as
platinum which are used as catalysts. If such changes occur, their environ-
mental impacts must be assessed in the EID. EPA's Regional responsible of-
ficial is the arbiter of whether or not a particular activity is directly
caused or induced by the new source facility. The proposed refinery complex
also may include integral support or ancillary facilities as deepwater ports
submerged pipelines, marine terminals, overland pipelines, bulk storage areas
and loading areas.
78
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As appropriate, such facilities should be fully described and analyzed in the
EID.
By way of guidance, the degree of detail given to impact evaluations for these
facilities could be directly proportional to the degree to which such facilities
are directly owned, operated, or supported by the proposed refinery. In cases
where the proposed refinery will construct its own marine facility, or deep-
water port, for example, the impact investigation would be tantamount to that
for the refinery itself. This would apply to cases where a substantial part
of the deepwater port or marine facility would be leased to other industry.
If, however, the port facilities are being expanded to meet the new refinery
demands by some independent or non-affiliated party, the degree of detail might
be different. In short, the permit applicant should consult with EPA officials
as to the required information and detail.
II.E.2. Site Preparation and Refinery Construction
The environmental effects of site preparation and construction of new oil
refinery facilities are common to most major land disturbing activities. Al-
though erosion, dust, noise, vehicular traffic and emissions, and some loss
of wildlife habitats are expected, the applicant has a number of mitigative
measures available by which adverse impacts can be reduced. At present, how-
ever, neither the quantities of the various pollutants resulting from site
preparation and construction nor their effects on the integrity of aquatic
and terrestrial ecosystems has been studied sufficiently to permit broad
generalizations. Therefore in addition to the impact assessment framework
provided in the EPA document, Environmental Impact Assessment Guidelines for
Selected New Source Industries, a suggested checklist of important study items
is presented in Table 19 for further guidance to the applicant. The basic
components of site preparation and plant construction outlined in the table
Include preconstruction, site work, permanent facilities, and ancillary
facilities. At this time only potentially significant areas of impact are
presented in the checklist, but a system of importance values should be
assigned to the checklist items after sufficient quantitative data have been
acquired at an individual site or for a region. The permit applicant also
should tailor all proposed conservation practices to the specific site(s)
being considered in order to account for and to protect certain site-specific
features that warrant special attention (e.g., critical habitats of imperiled
species, archaeological/historical sites, high quality streams, wetlands, or
other sensitive areas on the site). All mitigating conservation measures
which are proposed to avoid or reduce adverse Impacts from preparation of the
site and construction activities should be described in the EIB.
II.F. MODELING OF IMPACTS
The ability to forecast environmental impacts accurately often is improved
by the use of mathematical modeling of the dispersion and dissipation of
air and water pollutants as well as the effects of storm runoff.
Two of the most widely used and accepted models are:
• DOSAG (and its modifications)
• The QUAL series of models developed by the Texas Water Development
Board and modified by Water Resources Engineers, Inc.
79
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Table 19. Outline of potential environmental impacts and relevant
pollutants resulting from site preparation and construction
practices.
Construct ion
practice
Potential environmental
impacts
1. Preconstruction
Primary
pollutants
a. Site inventory
(1) Vehicular traffic
(2) Test pits
Short term and nominal
Dust, sediment, tree injury
Tree root injury, sediment
Dust, noise, sediment
b. Environmental
monitoring
Negligible if properly done
Visual
c. Temporary controls
(1) Sedimentation
ponds
(2) Dikes and berms
(3) Vegetation
(4) Dust control
Short term and nominal
Vegetation destroyed, water
quality improved
Vegetation destroyed, water
quality improved
Fertilizers in excess
Negligible if properly done
Sediment spoil, nutri-
ents, solid waste
Site Work
a. Clearing and
demolition
(1) Clearing
(2) Demolition
Short term
Decreased area of protective
tree, shrub, ground covers;
stripping of topsoil; in-
creased soil erosion, sedi-
mentation, stormwater runoff;
increased stream water tem-
peratures; modification of
stream banks and channels,
water quality
Increased dust, noise, solid
wastes
Dust, sediment, noise
solid wastes, wood
wastes
b. Temporary
facilities
(1) Shops and storage
sheds
(2) Access roads and
parking lots
Long term
Increased surface areas impervious
to water infiltration, increased
water runoff, petroleum products
Increased surface areas impervious
to water infiltration, increased
water runoff, generation of dust
on unpaved areas
Gases, odors, fumes
particulates, dust,
deicing chemicals,
noise, petroleum
products, waste-
water, solid wastes,
aerosols, pesticides
(continued on next page)
80
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Table 19. Outline of potential environmental impacts and relevant
pollutants resulting from site preparation and construction
practices (Continued).
Construction
practice
Potential environmental
impacts
Primary
pollutants
(3) Utility trenches
and backfills
(4) Sanitary facili-
ties
(5) Fences
(6) Laydown areas
(7) Concrete batch
plant
(8) Temporary and
permanent pest
control (ter-
mites, weeds,
insects)
Earthwork
(1) Excavation
(2) Grading
(3) Trenching
(4) Soil treatment
d. Site drainage
(1) Foundation
drainage
(2) Dewatering
(3) Well points
(4) Stream channel
relocation
Increased visual impacts, soil
erosion, sedimentation for
short periods
Increased visual impacts, solid
wastes
Barriers to animal migration
Visual impacts, increased runoff
Increased visual impacts; dispo-
sal of wastewater, increased
dust and noise
Nondegradable or slowly degradable
pesticides are accumulated by
plants and animals, then passed
up the food chain to man. De-
gradable pesticides having short
biological half-lives are pre-
ferred for use
Long term
Stripping, soil stockpiling,
and site grading; increased
erosion, sedimentation, and
runoff; soil compaction; in-
creased in-soil levels of
potentially hazardous materials;
side effects on living plants
and animals, and the incorpora-
tion of decomposition products
into food chains, water quality
Long term
Decreased volume of underground
water for short and long time
periods, increased stream flow
volumes and velocities, down-
stream damages, water quality
Dust, noise, sediment,
debris, wood wastes,
solid wastes, pesti-
cides, particulates,
bituminous products,
soil conditioner
chemicals
Sediment
e. Landscaping
(1) Temporary seeding
(2) Permanent seeding
and sodding
Decreased soil erosion and over-
land flow of stormwater,
stabilization of exposed cut
and fill slopes, increased
water infiltration and under-
ground storage of water,
minimized visual impacts
Nutrients, pesticides
(continued on next page)
81
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Table 19.
Construction
practice
Outline of potential environmental impacts
pollutants resulting from site preparation
practices (Continued).
Potential environmental
impacts
and relevant
and construction
Primary
pollutants
3. Permanent facilities
a. Petroleum refinery
and heavy traffic
areas
(1) Parking lots
(2) Marine terminal
b. Other buildings
(1) Warehouses
(2) Sanitary waste
treatment
c. Possible ancillary
facilities
(1) Intake and dis-
charge channel
(2) Water supply and
treatment
(3) Stormwater drain-
age
(4) Wastewater treat-
ment
(5) Dams and
impoundments
(6) Breakwaters, jet-
ties, etc.
(7) Fuel handling
equipment
(8) Waste storage
areas
(9) Overland or
underground pipe-
lines , bulk
storage areas,
loading areas
(10) Conveying systems
(cranes, hoists,
chutes)
(11) Cooling lakes and
ponds
Long term
Stormwater runoff, petroluem
products
Visual impacts, sediment, runoff
Long term
Impervious surfaces, stormwater
runoff, solid wastes, spillages
Odors, discharges, bacteria,
viruses
Long term
Shoreline changes, bottom topog-
raphy changes, fish migration,
benthic fauna changes
Waste discharges, water quality
Sediment, water quality
Sediment, water quality
Dredging, shoreline erosion
Circulation patterns in the
waterway
Spillages, fire, and visual
impacts
Visual impacts, waste
discharges
Sediment runoff and erosion,
landscape alteration,
waste discharges, visual
impacts
Visual impacts
Conversion of terrestrial and free
flowing stream environment to a
lake environmenta(land use trade-
offs); hydrological changes,
habitat changes, sedimentation,
water quality
Sediment, dust, noise,
particulates
Solid wastes
Sediment, trace ele-
ments, noise,
caustic chemical
wastes, spoil, floc-
culants, particulates,
fumes, solid wastes,
nutrients.
(continued on next page)
82
-------
Table 19. Outline of potential environmental impacts and relevant
pollutants resulting from site preparation and construction
practices (Concluded).
Construction Potential environmental Primary
practice impacts pollutants
(12) Solid waste Noise, visual impacts Particulates, dust,
handling equipment solid wastes
(incinerators,
trash compactors)
d. Security fencing Long term Sediments, wood
(1) Access road Increased runoff wastes
(2) Fencing Barriers to animal movements
Source: Modified from Hittman Associates, Inc. 1974. General environmental guide-
lines for evaluating and reporting the effects of nuclear power plant site
preparation, plant and transmission facility construction. Modified from:
Atomic Industrial Forum, Inc. Washington, DC.
83
-------
Some of the parameters that these models simulate are:
• Dissolved oxygen
• BOD
• Temperature
• pH
• Solids
There also are available mathematical models that may be used for air
pollution studies and solid waste management optimization:
• For short term dispersion modeling of point sources, EPA's PTMAX
PTDIS, and PTMTP models may be employed.
• For modeling of long term concentrations over larger areas, the
EPA's Climatological Dispersion Model, AQDM and CRSTER, may be
used for point and area sources.
In general, the use of mathematical models is indicated when arithmetic
calculations are too repetitious or too complex. Their use also simplifies
analysis of systems with intricate interaction of variables. Models thus
offer a convenient way of describing the behavior of environmental systems,
but their use and applicability should be determined on a case by case basis.
(For a more detailed discussion of modeling techniques see Section II.E.,
Modeling of Impacts, in Environmental Impact Assessment guidelines for New
Source Ebssil-Fueled Steam Electric Generating Stations, (EPA 13016-79-001).
84
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III.
POLLUTION CONTROL
III.A. STANDARDS OF PERFORMANCE TECHNOLOGY: IN-PROCESS CONTROLS - WATER,
AIR, SOLID WASTES
There are a number of pollution control measures which can be taken to effec-
tively reduce refinery waste streams and their associated impacts. Many of
these steps also will reduce operation and capital costs and/or increase
production. The EID should contain a discussion of the applicability of these
steps to the particular installation. Discussions of pollution control should
consider reduction of effluents and emissions at the source (design planning,
etc.). Further, reuse and recycling options should be investigated and may
include:
• Use of catalytic cracker accumulator wastewaters rich in H2S
for makeup to crude desalters
• Use of blowdown condensate from high pressure boilers for makeup
to low pressure boilers
• Reuse of waters that have been treated for closed cooling systems,
fire mains and everyday washing operations
• Stormwater use for routine water applicators
• Blowdown waters from cooling towers for use as water seals on
high temperature pumps
• Recirculation of steam condensate
• Recycling of cooling waters
Effective maintenance measures also can reduce waste streams. The applicant
should describe all proposed maintenance activities in the EID. They may
include:
• Recovery of oil spills and hydrocarbons with vacuum trucks to
reduce emission and water effluents
• Reduction of leaks and accidents through preventive maintenance
(pump seals, valve stems, etc.)
• Separation of hazardous wastes, concentrated wastes, and other
process wastes from general effluents for more effective treat-
ment
• Diking of process unit areas to control and treat spills, oily
stormwater runoff, or periodic washes
• Reduction of shock pollution loads on treatment facilities
through the periodic flushing of process sewers to prevent
contaminant buildup
• Development of a specialized program for handling hazardous
wastes, sludges, washwaters and other effluents
• Development of a system to minimize wastes from monitoring
stations
• Improvement of personnel awareness that waste treatment is
initiated at the process unit.
Actual process changes often can reduce pollution significantly while return-
ing a value through recovery. Technology changes that reduce pollution may
not be as cost-effective during process cycles, but may prove to be highly
beneficial when waste treatment costs have been reduced. Depending on the
feasibility and suitability of a particular project, such process technology
85
-------
changes may include:
• Catalyst switching to a longlife catalyst with greater activity
to reduce regeneration frequency
• Replacement of barometric condensers (direct-contact condensers)
with surface condensers (indirect-contact condensers) or air-fin
coolers
III.A.l. Cooling System
A description of the cooling system is necessary including possible alterna-
tives, i.e., nonevaporative devices. The evaporating cooling systems include
spray ponds, mechanical-draft cooling towers, atmospheric cooling towers, and
natural-draft cooling towers. Treated wastewater should be considered for
makeup purposes. The cooling water blowdown composition is dependent on the
composition of the original water used, the operation methods, and cooling
water treatment. Chromates, zinc, polyphosphates, dust, other corrosion
inhibitors and micro-organisms are constituents of the cooling treatment waste-
waters. A discussion of alternate treatment methods, process operations and
piping materials also should be discussed. Dry cooling systems of air-fins
to dissipate the undesired heat directly to the atmosphere should be discussed.
III.A.2. In-Process Physical/Chemical Pretreatment
The applicant should discuss the following important pretreatment steps in the
EID:
• Flow equalization neutralization of spent acid and spent caustic
wastewaters
• Oil separators and slop oil recovery systems
• Clarifiers to separate sediments using chemical coagulants as
needed
• Sour water stripping
III.B. STANDARDS OF PERFORMANCE TECHNOLOGY: END-OF-PROCESS CONTROL (WATER
STREAMS)
Table 6 (page 33) identifies and estimates the various wastewater treatment
processes used by petroleum refineries. It illustrates the impact of the
recent environmental considerations on the increased usage of wastewater
pollution control devices.
Depending on refinery location, refinery plant size, the refining process
(degree of crude finishing), and wastewater characteristics, the wastewater
treatment facilities are designed based on the processes in Table 6. Table
12 (page 65) shows wastewater characteristics and quantities for the various
petroleum unit operation.
The EID should demonstrate that the applicant has given adequate attention
to implementation of new technology for abatement of water pollution. The
EID should include an understandable, but complete description of the proposed
wastewater treatment system. A process flow diagram also should be provided
to illustrate each step of treatment scheme. Some refineries use the
86
-------
following basic treatment approach:
• Pretreatment to remove phenols, sulfides, mercaptans, ammonia and
adjust pH (processes utilized are steam stripping, flue gas strip-
ping, oxidation and neutralization)
• Removal of free oil and suspended solids by gravity
• Removal of emulsified oil, suspended solids, colloids and solids
by coagulation and settling, aand filtration and gas flotation
• Trickling filters, activated sludge processes, oxidation ponds
and aerated lagoons are biological organisms are biological
organisms to convert dissolved organic matter to a settleable
floe
• Tertiary treatment to remove dissolved organics and inorganics,
color, odor and taste with foam fractionation, activated carbon,
ion exchange, electrodialysis or ultrafiltration
• Disposal of high organic containing liquids or solids by combus-
tion (incineration)
• Sludge arising from biological systems and solids separation
processes are dewatered with the use of sand beds, vacuum
filtration or centrifugation; sludge is then disposed of by
landfill or incineration
Figure 7 shows the diverse combinations of waste treatment processes that can
be used to treat refinery wastewater streams. In addition, Table 20 estimates
efficiencies of the various treatment practices on refinery effluent streams.
By viewing Figure 7 and Table 20 collectively, one can obtain a first order
estimation of treatment efficiency for a particular oil refining facility.
To determine the optimum wastewater treatment system, there are a number of
key factors which should be considered. Specifically, the applicant should
demonstrate in the EID, the analysis and selection method(s) used to arrive
at the proposed wastewater treatment design. At least the following infor-
mation should be presented:
• Systematic consideration and analysis of all alternative waste-
water treatment approaches
• Waste loadings from various process systems
• Efficiency of alternative waste treatment sequences (system's
reliability and susceptibility to upset)
• Energy and material demands of various treatment systems
• Margin for system expansion
• BAT for priority and conventional pollutants
• Ability to meet receiving water quality standards
III.C. STANDARDS OF PERFORMANCE TECHNOLOGY: END-OF-PROCESS CONTROL (AIR
STREAMS)
Refinery operations result in emission of sulfur oxides, nitrogen oxides,
particulate matter, CO and various hydrocarbons. Other emissions which
lately have earned considerable interest are trace elements such as asbestos,
mercury, benzene, etc. The USEPA haft enacted New Source Performance Standards
for various pollutants such as sulfur dioxide and particulates arising from
petroleum refineries. State and local air quality and emission standards
87
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Process
Pretreatment
Primary
Treatment
Secondary Treatment
Tertiary Treatment
Sludge Dewotering
Sludge Disposal
Miscellaneous
Application
Waste
Stream
I
General
Oil Wastes
Sour
Water.
r~
Spent
Caustic
Battast
Water
S , Phenol, PH,
NH3,RSH
Free 01I.SS
Emulsified Oil
SS, Colloid,SoMs
Dissolved
Organics
DissolveixOrganics
Color, Taste, Odor
(I)
(2)
(3)
(4)
(5)
Steam
Stripping
Flue Gas
Stripping
» Oxidation
Neutralization _
Gravity
Seporatar
Gas
Flotation
Coagulation
ft Settling
Trickling
Filter
Sand
Filtration
Activated
Sludge
+
Foam
Fractionation
Oxidation or
Polishing Ponds
Activated
Carbon
Dissolved
Inorganics
Sludge From
(2) a (4)
Dewatered
Sludge
(6)
(7)
( 8 )
Aerated
Lagoon
Ozone
Oxidation
ion Exchange
Elect rodlalysis
i»-Sand Beds-r
Vacuum
Filtration
I
Thickening
Gas Hydration
Centrifuge
Incineration
Ultrdfiltratlon
*> Landfill
Lagoon
Gaseous Effluent
HgS, Phenols
Slop Oil
Gravity
Separotor
Discharge
Coagulation
& Settling
Discharge
Solid, Liquid, or
Gaseous Wastes
O)
Combustion
Recovery
Heating
Coagulation
Precoat
Filtration
Centrif uqotioi
Flow
Equalization
To Primary or
Secondary Refine
Treatment Proces
Source: US-DOI. 1967. The cost of clean water. Volume III, Industrial Waste Profile No. 5: Petroleum Refining. FWPCA
Publication No. I.W.P.-5. Available from US-GPO, Washington, DC.
Figure 7. Sequence/substitute diagram of various wastewater treatment systems.
-------
Table 20. Efficiency of oil refinery waste treatment practices based on effluent quality
Emul- Sus-
Process
Separable sified
Sulfide
pended
Temp.
Influent®
BOD
COD
Oil
Oil
Phenol
S
Solids
Chloride
Ammonia
Cyanide
Toxicity
(°F)
Physical Treatment
L
5-30b
API separators
Raw waste
5-35
60-99
n.a.
Reduced
n.a.
10-50
n.a.
n.a.
n.a.
n.a.
n.a.
n.a.
Earthern separators
Raw waste
5-50
5-40
50-99
n.a.
Reduced
n.a.
10-85
n.a.
n.a.
n.a.
n .a.
n.a.
n.a.
Evaporation
API
100
100
n.a.
100
100
100
100
100
100
100
n.a.
n.a.
n.a.
effluent
Air flotation
API
5-25
5-20
70-95
10-40
n.a.
10-40
n.a.
n.a.
n.a.
n.a.
n.a.
n.a.
n.a.
without chemicals
effluent
Reduced
10-40
n.a.
Chemical Treatment
Air flotation with
API
10-60
10-50
75-95
50-90
n.a.
Reduced
50-90
n.a.
Reduced
n.a.
n.a.
n.a.
n.a.
chemicals
effluent
Chemical coagulation
API
10-70
10-50
60-95
50-90
n.a.
n.a.
50-90
n.a.
n.a.
n.a.
Altered
n.a.
n.a.
and precipitation
effluent
Biological Treatment
Activated sludge
API
70-95
30-70
n.a.
50-80
65-99
90-99
60-85
n.a.
50-95
65-99
Altered
Reduced
10-60
effluent
Aerated lagoons
API
50-90
25-60
n.a.
50-80
65-99
90-99
0-40
n.a.
0-45
65-99
Altered
Reduced
10-90
effluent
Trickling filters
API
50-90
25-60
n.a.
50-80
65-99
80-99
60-85
n.a.
50-99
65-99
Altered
Reduced
10-60
effluent
Oxidation ponds
API
A 0-80
20-50
n.a.
40-70
65-99
70-90
20-70
n.a.
20-90
65-99
Altered
Reduced
10-90
effluent
Activated carbon
Secondary0
50-90
50-90
n.a.
50-90
80-99
80-99
n.a.
n.a.
10-30
80-99
n.a.
Reduced
n.a.
effluent
Ozonation
Secondary
50-90
50-90
n.a.
80-99
80-99
n.a.
n.a.
10-30
80-99
n.a.
Reduced
n.a.
effuent _
aMo8t probable process influent-indicates the kind or extent of prior treatment required for efficient utilization of the specific process under
consideration.
^BOD and COD from separable oil not included.
cChemical or biological treatment.
LEGEND: API " American Petroleum Institute, n.a. * Not Applicable
Source: US-DOI. 1967. The cost of clean water. Volume III, Industrial Haste Profile No. 5: Petroluem Refining. FWPCA Publication No. I.W.P.-5.
Available from US-GPO, Washington, DC.
-------
also may be imposed. To comply with these regulations, the operator of a new
source refinery has available various air pollution control devices and tech-
niques to reduce emissions to within allowable levels. At a minimum, the
following air pollution control measures for each pollutant should be con-
sidered and described in the EID:
• Hydrocarbon emissions can be limited through the use of floating-
roof tops; manifolding purge lines to a recovery system (condenser
or carbon absorber) or to a flare (see Figure 8); vapor recovery
systems on loading facilities; preventive maintenance; enclosed
waste treatment plant; mechanical seals on compressors and pumps,
and trained and cognizant personnel. A typical scrubbing system
for emissions from air-blown asphalt stills is shown in Figure 9.
• Particulates can be controlled with the use of wet scrubbers and
high-efficiency mechanical collectors (cyclones, bag houses);
electrostatic precipitators on catalyst regenerators and power
plant stacks; controlled combustion to reduce smoke; controlled
stack and flame temperatures, and improved burner and incinerator
design.
• Carbon monoxide emissions can be controlled at the catalytic
cracker and fluid coker units with a CO boiler and at other sites
through proper furnace and burner design.
• Odor controls include a good preventive maintenance program; the
treatment of H2S-rich wastewater streams from the catalytic crackers*
gas-processing units and vacuum distillation towers; and the flaring
of H2S, mercaptans, other sulfides and other odor-producing compounds
• Sulfur dioxide emissions can be controlled primarily through the
burning of low-sulfur fuels in furnaces and boilers, the wet scrubbing
of high-sulfur dioxide flue gases, and the desulfurization of fuels
before use.
• Nitrogen oxide emissions can be controlled through an improved
combustion process (i.e., lower flame temperature, less excess air)
low nitrogen fuel burning, and good stack dispersion.
Table 21 presents a summary of the principal emission control devices currently
employed at oil refinery facilities.
Other emission control technologies that currently are not used widely com-
mercially, but are emerging include:
• Amine scrubbing
• Hot potassium carbonate process
• Sulfnol process (Shell Oil Co.)
• Seaboard and vacuum carbonate process (Koppers Co.)
• Phosphate process (Shell Development Co.)
• Wet iron box process
• Thylox process
• Dolomite acceptor process
III.D. STATE OF THE ART TECHNOLOGY: END-OF-PROCESS CONTROLS (SOLID WASTE
DISPOSAL)
Petroleum refineries generate an estimated 625,000 metric tons per year of
90
-------
Source: API. 1973. Hydrocarbon emissions from refineries. Publication 0.928,
Washington, D.C.
Figure 8. Typical flare installation.
Note: This represents an operable system arrangement and its components.
Arrangement of the system will vary with the performance required. Corres-
pondingly, the selection of types and quantities of components, as well as
their applications, must match the needs of the particular plant and its
specifications.
91
-------
I
FUME
SCRUBBERl
WATER
EXHAUST
GASES 1
TO
ATMOSPHERE
a
STEAM
KNOCK-I
OUT
DRUM
AIR BLOWN
ASPHALT STILLS
(BATCH OPERATIONS)
BLANKET
MIST
ELIMINATOR
& COVERED SEPARATOR
KIMMER
CON DEI
TO STORAGE
SKIMMED OIL
TO STORAGE
EFFLUENT WATER
TO COVERED
SEPARATOR
Source: API. 1973. Hydrocarbon emissions from refineries. Publication 0.928
Washington, D.C.
Figure 9. Simplistic low diagram for typical scrubbing system for emission
control from air-blown asphalt stills.
92
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Table 21.
PROCESS
Catalyst
Regeneration
EMISSION
Particulates
Fluidized
Coking
Boilers/
Process Heaters
Sulfur
Recovery
SOx
CO
Particulates
SOx
Particulates
so2/h2s
Storage
Tanks
Loading
Facilities
Incineration
Hydrocarbon
Hydrocarbon
Particulates
Summary of emission control technologies currently in use
for various air pollutants generated from refinery processes.
UNCONTROLLED LEVEL
90-350 Lb/103 BBL Fresh Feed
310-525 Lb/103 BBL Fresh Feed
13,700
520
Essentially all fuel sulfur is
emitted as S0X
0.1-10 Lb/103 Lb Fuel Burned
5-10% of Sulfur Input
CONTROL TECHNOLOGY
APPROX. CONTROL
EFFICIENCY
Cyclones
Multiple Cyclones
Electrostatic Precipitation
Wet Scrubber (high
energy venturi)
Wet Scrubber (high
energy venturi)
Waste Heat Boiler
65-85%
70-90%
> 95%
> 90%
> 80%
> 99%
Cyclones 65-85%
Multiple Cyclones 70-90%
Electrostatic Precipitation > 95%
Fuel Blending/Switching
Electro. Precip.
> 95%
Additional Claus Stages Total Process
Achieves S Removal
of 97%
Tail Gas Scrubbing
Tail Gas Recovery (IFP,
Beagon, Cleanair)
1-10 Lb/day/103 gallons throughput
1-12 Lb/103 Gallons Transferred Submerged Loading
Floating Roof
Pressurized Tanks
Vapor Recovery
Variable
Cyclones
Multiple Cyclones
Wet Scrubber - Packed Tower
Venturi
> 90%
> 90%
99%
90-95%
50-70%
65-85%
70-90%
>90%
>90%
Light Ends
Hydrogen
Methane
Variable
Flare
-------
waste (dry weight) in the course of distilling crude petroleum and processing
of petroleum products (USEPA 1976d). The volume of waste generated as well
as the economics of material recovery are determined to a large degree by
the type, age, and condition of process units and the market for product "mix".
Further, refineries in different geographic areas encounter widely varying
requirements and problems associated with their individual solid waste streams.
Treatment and disposal methods used in oil refineries are contingent upon the
nature, concentration, and quantities of waste generated, as well as upon the
potential toxicity or hazardousness of these materials. Pollution control
methods are further affected by geographic conditions, transportation distances
disposal site hydrogeological characteristics, and regulatory agency require-
ments.
Much of the material wasted by refineries only 20 to 25 years ago has either
been eliminated by process changes, is now processed into marketable products,
is recycled for reprocessing, or is sold to secondary material processors for
extraction of valuable constituents. Noble metal catalysts, caustic solutions
containing recoverable quantities of phenolic compounds, and some alkylation
sludges reprocessed for sulfuric acid are examples of such waste streams.
The types of wastes requiring disposal have been listed and described in
Section II.C. of this report.
The paragraphs that follow discuss the primary treatment and disposal tech-
niques for handling solid wastes from refineries. These and any other developing
technologies should be considered by the permit applicant prior to selection
of the proposed disposal method.
III.D.l. Landfilling
Landfilling is presently the most widely used method for disposing of all
types of petroleum refinery waste products. The environmental adequacy of
this method is contingent not only upon the types and characteristics of
generated wastes, but also upon methods of operation and on specific site
geologic and climatologic conditions. Of all the land disposal methods used
by the refining industry, perhaps the greatest variations in operations and
in site suitability are experienced with landfills. Landfilling operations
range from open dumping of construction and refinery debris to controlled
disposal in secure landfills. However the precise impact of solid waste
disposal depends on the nature of the waste (inert construction waste may
not pose a problem even in an open dump) and the landfill (secure landfills
involve control of wastewater, groundcover, plot padding, etc.)
The environmental adequacy of a refinery waste landfill is affected by the
following operational and management practices:
• The extent of segregation of wastes to prevent mixing of incompat-
ible compounds, such as solids containing heavy metals with acids,
or solutions with other wastes which together produce explosions,
heat, or noxious gases
• The extent to which liquid or semi-liquid wastes are blended with
soil or refuse materials to suitably absorb their moisture content
and reduce their fluid mobility within the landfill
• The extent to which acids or caustic sludges are neutralized to
minimize their reactivity
94
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• Selection of sites in which the active fill area is large enough
to allow efficient truck discharging operations, as well as to
assure that blended wastes may be spread, compacted, and covered
daily with approximately six inches of cover soil; A site operated
in this manner is called a sanitary landfill
e The routing of surface waters around the landfill site and sloping
of cover soil to avoid on-site runoff and erosion
III.D.2. Landspreading
Landspreading is a relatively inexpensive method of disposal of petroleum
refinery wastes which is being used by an increasing number of refineries.
The success of landspreading in the warm southwestern states (due to higher
ambient temperatures and therefore faster biological degradation) has prompted
many U.S. refineries in colder climates to experiment with this method of
disposal. Many refineries, however, which employ landspreading have done so
for only about one to three years; only a few have a working experience with
this process for a longer period of time.
Historically, refineries have been concerned largely with possible oil con-
tamination of ground and surface waters which may result from landspreading.
Few refineries have considered other environmental effects which may result
from this operation. The real concern is not only the recognized short-term
oil problem and incomplete treatment of organic acids and other intermediate
byproducts, but the long-term implications of trace metal accumulation in the
soil over long periods of operation. The problem posed by disposal of heavy
metals on or in land largely is the same for all treatment and disposal tech-
nologies. The major difference is a quantitative one, with repeated applica-
tions of oily wastes to the same land areas potentially producing greater
concentrations of heavy metals than result from other disposal methods. In
a confined secure disposal area, these heavy metals and other hazardous organic
acids or degradation products do not pose the same level of hazard to the
environment. Landspreading appears to be emerging as an important method
for disposal of certain refinery wastes and should be carefully assessed during
the EID process.
III.D.3. Lagoons, Ponds, Sumps, and Open Pits
Lagoons, ponds, sumps and open pits have been used for many decades by the
petroleum refining industry for the disposal of liquid and semi-solid waste.
The expediency of past disposal by simply dumping wastes into lagoons or sumps
has turned into a major disposal problem in many parts of the country (Oil
and Gas Journal 1972). The demand for elimination of these unsightly sumps
has been prompted by many factors, among which, are the following:
• The need for additional land for refinery expansion
• Increasing land values which demand that land be put to a
higher and more profitable use
• The envelopment of these lands by urban areas, and the
resulting increased potential dangers to people
• Increasingly stringent regulatory agency requirements
• The desire to eliminate potentially catastrophic situations
which may arise as a result of flooding rivers carrying large
amounts of petroleum sludge with them
95
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Action Is now being taken by a number of states (California, Oklahoma, Texas
and Pennsylvania), to phase out the use of sumps and lagoons as permanent *
disposal methods, allowing them to be used only as temporary retention or
treatment ponds. They are thus being relegated to use as wastewater treat-
ment units, such as primary and secondary clarifiers, biostabilization or
oxidation ponds, or thickening basins. Other uses included evaporation
ponds or emergency diversion basins. As wastewater treatment requirements
have become more stringent, many simple facultative and anaerobic lagoons
have been converted into aeration basins by the addition of mechanical aera-
tors. Because of their simplicity and ease of construction, many of the newer
refineries make considerable use of earthen or lined lagoons as primary or
secondary sedimentation chambers, aeration basins, oxidation ponds, storm
runoff ponds, and emergency oil spill retention basins.
The environmental acceptability of lagoons for any of the prescribed purposes
is very much dependent upon the method and materials of construction, specific
local hydrogeologic conditions, and the types of waste which are handled. The
potential for significant contamination of underlying water aquifers from many
inadequately lined lagoons, both old and new, is appreciable because of improper
location and inadequate safeguards. Although many of the units are acceptable
the applicant should ascertain that adequate design and construction practices'
are followed in areas with high water tables, porous soils, or other environ-
mental constraints.
III.D.4. Leaded Gasoline Sludge Treatment and Disposal
Because organic lead vapors are known to be toxic at various concentrations
(approximately 0.075 to 0.15 mg/m3, depending on lead compound), special
procedures have been developed exclusively for the treatment and disposal
of leaded gasoline sludges which accumulate in aviation and motor gasoline
storage tanks. Gasoline product storage tank sludges are disposed by land-
fill or landfarming. This involves the construction of a dike surrounding
the tank to be cleaned. After the tank contents (except sludge) is pumped to
another tank, the remaining sludge is either pumped into the dike for
weathering and degradation or is transported to a weathering pad elsewhere
within the refinery. It subsequently is rotodisked into the soil or buried
on refinery property. Careful monitoring of such sites is required since
such practices have not been totally shown to be safe. The volume of leaded-
gasoline sludge generated is quite small and the frequency of cleaning is
subsequently low - on the order of every one to ten years. Even then, the
frequency of tank cleaning is dictated more by required tank maintenance
than by need for sludge removal.
III.D.5. Incineration
Incineration of semi-solid and solid organic containing refinery-generated
wastes requires a special type of system which provides adequate detention
times, stable combustion temperatures, sufficient mixing, and high heat
transfer efficiency. A fluidized bed is one of the few systems which can
satisfy all these criteria. In addition, the fluidized bed of heated solids
serves as a heat sink to ignite volatilized hydrocarbons, thereby reducing
or eliminating the possibility of creating an extremely dangerous explosive
mixture of unburned gaseous hydrocarbons and air. The material to be incinerated
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can be injected either into the fluidized bed or immediately above it. Re-
finery wastes known to be incinerated by such systems include spent caustic
solutions, API separator bottoms, DAF float, waste bio sludge, and slop oil
emulsion solids. Experience has shown that the reaction is self-sustaining
if the thermal content of the total wastes incinerated exceeds about 29,000
BTU per gallon. Normal range of operating temperature is from 1300 to 1500
F. Loss of fluidization and plugging of the bed is still a major problem in
the operation of these units. Reduced temperatures permit discharge of un-
combusted organics. There are a variety of other incineration processes in
any standard sanitary engineering text.
III.D.6. Deep Well Disposal
Subsurface or deep well injection is a disposal method which originated with
the oil and gas extraction industry. Brines, separated from the extracted
gas and oil, are pumped back into the formations from which the fluid is
originally taken, thus restoring the formation pressure and facilitating the
extraction of additional gas and oil. Gradually the injection practice has
been extended to include a multitude of wastes which would be difficult to
dispose of by any other means.
Several refineries in the Southern California area are known to inject waste
brines into deep wells. Deep well injection capital and operating costs can
be considerable. The future of deep well injection has been clouded by recent
legal and regulatory agency decisions (Ricci 1974; Ruckelshaus 1973). Deep
well disposal must follow the guidelines established by the state Underground
Injection Control Program.
III.D.7. Ocean Disposal
The 1971 Dillingham report (Smith and Brown 1971) for the EPA on ocean disposal
of barge-delivered liquid and solid wastes reported that approximately 500,000
tons of refinery wastes have been dumped into the ocean. The Marine Protection
Act of 1972 (PL 92-532) has transferred regulation and control of all ocean
dumping from the district office of the U.S. Corps of Engineers to the Environ-
mental Protection Agency. Ocean disposal of certain prescribed hazardous wastes
is prohibited. Permits for other less hazardous wastes are becoming increasingly
difficult to obtain, as well, as alternative methods of ultimate disposal become
available. Regulations will force the end of ocean disposal.
III.D.8. Special Treatment and/or Disposal Practices
A procedure for reducing the volume of crude tank bottoms is the use of poly
electrolytes to promote phase separation. The process is performed prior to
cleaning the tanks, at which time any crude oil remaining in the tank is pumped
out to the sludge layer and replaced with approximately 5,000 to 6,000 barrels
of "Canadian Condensate" or "off-gas" from field wells. The material in the
tank is heated with steam and mixed with the crude tank bottoms to a temperature
of approximately 130°F to recover crude fractions. The residue is used as fuel.
Another special practice that may be used for treatment of both liquid and solid
wastes is that of chemical fixation. Among the chemical fixation methods which
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are in use in the petroleum refining industry are the following:
• Use of chemical coagulants to create an insoluble precipitate.
Often the one waste stream that is deliberately treated to pro-
duce a chemically inert precipitate is the routing of cooling
tower blowdown containing hexavalent chromium through the API
separator where available sulfides bring about the reduction
of hexavalent chromium to trivalent chromium. From the API
separator, reduced chromium ion is routed through the spent lime
slurry tank where it is converted to chromium hydroxide, an
insoluble precipitate. The lime sludge containing the precipitated
hydroxide usually is removed by vacuum truck.
• Sorption of solvent-like hydrocarbons
• The use of a variety of chemical systems have been devised to
overcome the fluidity of certain petroleum wastes. These chemical
systems react with various components of the waste to form a
semi-solid material which effectively encapsulates or otherwise
ties up the harmful constituents. The majority of these methods
tend to isolate the material from the environment by either iso-
lating the waste component as a solid mass, drying out the liquid
or achieving some form of chemical bonding or sorption. Chemical'
fixation or solidification is used by a few refineries to solve
specific disposal problems, such as the permanent disposal of
environmentally unacceptable (because of leaching) lagoons filled
with API separator bottoms or crude tank bottoms. The Chemfix
Process is an example of such a chemical system. It consists of
adding metered quantities of reactants to 300 to 500 gallons of
waste slurry at intervals of one minute, and mixing to obtain
homogeneity. The volurae of reactant added to the waste is usually
less than 10% and often below 5% by volume. If cement were used
to solidify the same waste, a volume increase of about 100% would
typically be required to obtain a solid waste containing the
entire liquid portion. The process is continuous and occurs at
ambient temperature and pressure.
III.E. TECHNOLOGIES FOR CONTROL OF POLLUTION FROM CONSTRUCTION SITES
The major pollutant at a construction site is loosened soil that finds its
way into the adjacent water bodies and becomes "sediment." This potential
problem of erosion and sedimentation is not unique to refinery construction
but applies widely to all major land disturbing activities. Common remedial
measures include, but are not limited to, proper planning at all stages of
development and application of modern control technology to minimize the pro-
duction of huge loads of sediment. Specific control measures include:
• The use of paved channels or pipelines to prevent surface erosion
• Staging or phasing of clearing, grubbing, and excavation activities
to avoid high rainfall periods
• The use of storage ponds to serve as sediment traps, where the
overflow may be carefully controlled
• The use of mulch or seeding immediately following disturbance
If the applicant chooses to establish temporary or permanent ground cover,
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grasses normally are more valuable than shrubs or trees because of their
extensive root systems that entrap soil. Grasses may be seeded by sodding,
plugging, or sprigging. During early growth, grasses should be supplemented
with mulches of wood chips, straw, and jute mats. Wood fiber mulch also has
been used as an antierosion technique. The mulch, prepared commercially from
waste wood products, is applied with water in a hydroseeder.
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IV. OTHER CONTROLLABLE IMPACTS
IV.A. AESTHETICS
New source petroleum refineries may be large and complex facilities occupying
an area of up to several hundred acres. Cooling towers, air emission stacks,
material storage and handling areas, and other plant components may detract
considerably from the surrounding landscape. Particularly in rural and sub
urban areas, this configuration may represent a significant intrusion on the
landscape- existing industrial areas would be less affected. Measures to
minimize ihe impact on the environment should be developed primarily during
site selection and design. The applicant should consider as applicable,
the following factors to reduce potential aesthetic impacts.
• Existing Nature of the Area—The topography and major land uses
in the area of the candidate sites can be important aesthetic
considerations. Natural topographic conditions perhaps could
serve to screen the refinery from public view. A lack of topo-
graphic relief will require other means of minimizing impact,
such as regrading or establishing (or leaving) vegetation buffers.
Analysis of major land uses may be useful to assist in the design
and appearance of the facility. Design of the refinery should
reflect the nature of the area in which it is to be placed (i.e.,
the structures should blend into the existing environment as much
as possible). The use of artists' conceptions, preferably in
color will be most useful in determining the visual impact and
annroiriate mitigation measures and should be included in the EID.
. Proximity of Sites to Parks and Other Areas Where People Congre-
gate for Recreation and Other Activities — The location of these
areas should be mapped and presented in the EID. Representative
views of the plant (site) from observation points and the visual
effects on these areas should be described in the EID in order
to develop the appropriate mitigation measures.
• Pipeline and Transportation System ~ The visual impact of new
pipelines access roads, railroad lines, barge loading/unloading
facilities etc. on the landscape should be considered. Specific
locations,'construction methods and materials, maintenance activi-
ties and mitigation plans should be discussed.
• Creation of Aesthetically Pleasing Areas — In some cases, the
development of a refinery will create aesthetically pleasing areas.
Screening the facility by vegetation or using the natural topo-
graphy may improve the appearance of an area. Creation of open
soace and development of recreational facilities also can improve
the area. Such positive impacts should be described in the EID.
IV.B. NOISE
impact on ambient noise levels at the
?eLeeitae!leL^s the'major sources of noise in a refinery are the following:
• Compressors
• Pumps and motors
• Flares
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In addition, construction activities also generate substantial noise levels.
The applicant should undertake a site ambient noise survey prior to construc-
tion. This survey should be undertaken according to standard procedures
(Miller 1976). Then fence line noise levels should be projected during con-
struction and operation using estimates based on active noise levels of various
equipment as determined from other refineries and from equipment suppliers.
Noise levels can be reduced by:
• Use of equipment designed to reduce emission levels
• Shielding equipment
• Good maintenance
• Shielding the plant with a noise barrier
To evaluate noise generated from a proposed site, the applicant should follow
the sequence listed below:
• Identify all noise-sensitive land uses and activities adjoining
the site
• Identify existing noise sources, such as traffic, aircraft flyover,
and other industry, in the study area as defined
• Identify all applicable State and/or local noise regulations
• Estimate the noise level of the refinery during construction and
operation and compare with the existing community noise levels
and the applicable noise regulations
• Calculate the change in community noise levels resulting from
construction of the refinery
• Assess the noise impact of the refinery operational noise and
construction noise, and, if warranted, propose noise abatement
measures to reduce the impact
IV.C. SOCIOECONOMIC '
Introduction of a large oil refining facility into a community may cause
economic and social changes. Therefore, it is necessary for an applicant
to understand the types of impacts or changes that may occur so that they
can be evaluated adequately in the EID. The importance of these changes
usually depends on the nature of the area where the refinery is located (e.g.,
size of existing community, existing infrastructure). Normally, however,
the significance of the changes caused by a refinery of a given size will be
greater in a small, rural community than in a large, urban area. This is
primarily because a small, rural community is likely to have a nonmanufacturing
economic base and a lower per capita income, fewer social groups, a more
limited socioeconomic infrastructure, and fewer leisure pursuits than a large,
urban area. There are situations, however, in which the changes may not be
significant in a small community and, conversely, in which they may be
considerable in an urban area. For example, a small community may have had
a manufacturing (or natural resource) economic base that has declined. As a
result, such a community may have a high incidence of unemployment in a skilled
labor force and a surplus of housing. Conversely, a rapidly growing urban
area may be severly strained if a new oil refinery is located there.
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The rate at which the changes occur (regardless of the circumstances) also is
an important determinant of the significance of the changes. The applicant
should distinguish clearly between those changes occasioned by the construction
of the plant and those resulting from its operation. The former changes could
be substantial but usually are temporary; the latter may or may not be sub-
stantial but normally are more permanent in nature.
During the construction phase, the impact usually will be greater if the pro-
ject requires large numbers of construction workers to be brought in from
outside the community than if local, unemployed workers are available. The
impacts are well known and include:
• Creation of social tension
• Demand for increased housing, police and fire protection, public
utilities, medical facilities, recreational facilities, and other
public services
• Strained economic budget in the community where existing infra-
structure becomes inadequate
Various methods of reducing the strain on the budget of the local community
during the construction phase should be explored. For example, the company
itself may build the housing and recreation facilities and provide the services
and medical facilities for its imported construction force. Or the company
may prepay taxes and the community may agree to a corresponding reduction in
the property taxes paid later. Alternatively, the community may float a bond
issue, taking advantage of its tax-exempt status, and the company may agree
to reimburse the community as payments of principal and interest becomes due.
During refinery operation, the more extreme adverse changes of the construction
phase are likely to disappear. Longer run changes may be profound, but less
extreme, because they evolve over a longer period of time and may be both
beneficial and harmful.
The permit applicant should document fully in the ElD the range of potential
impacts that are expected and demonstrate how possible adverse changes will
be handled. For example, an increased tax base generally is regarded as a
positive impact. The revenue from it usually is adequate to support the
additional Infrastructure required as the operating employees and their
families move into the community. The spending and respending of the earnings
of these employees has a multiplier effect on the local economy, as do the
interindustry links created by the new refinery. Socially, the community may
benefit as the increased tax base permits the provision of more diverse and
higher quality services and the variety of its interests increases with growth
in population. Contrastingly, the transformation of a small, quiet community
into a larger, busier community may be regarded as an adverse change by some
of the residents who chose to live in the community, as well as by those who
grew up there and stayed, because of its amenities. The applicant also should
consider the economic repercussions if, for example, the quality of the air
and water declines as a result of various waste streams from the new source
oil refinery and its ancillary facilities.
In brief, the applicant's framework for analyzing the primary and secondary
socioeconomic impacts of constructing and operating a refinery must be com-
prehensive. Most of the changes described should be measured to assess fully
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the potential costs and benefits. The applicant should distinguish clearly
between the short term (construction) and long term (operation) changes, al-
though some changes may be common to both (e.g., the provision of infrastructure)
because the significance of the changes depends not only on their absolute mag-
nitude, but also on the rate at which they occur.
The applicant should develop and maintain close coordination with State,
regional, and local planning and zoning authorities to ensure full under-
standing of all existing and/or proposed land use plans and other related
regulations.
IV.D. ENERGY SUPPLY
The impact of a petroleum refinery on local energy supplies will depend largely
on the type of processes proposed and the ancillary facilities. The applicant
should evaluate the energy efficiencies of all processes considered during
project planning and then consider the alternatives. Feasible design modifi-
cations also should be considered in order to reduce energy consumption.
At a minimum, the applicant should provide the following information:
• Total external energy demand for operation of the refinery
• Total energy available on site
• Energy demands by type
• Proposed measures to reduce energy demand and increase plant
efficiency
IV.E. IMPACT AREAS NOT SPECIFIC TO PETROLEUM REFINERIES
The intent of the preceding sections was to provide guidance to new source
NPDES permit applicants on those impact areas that are specific to or repre-
sentative of new source refinery operations. It is recognized that many im-
pacts resulting from the construction and operation of an oil refinery are
similar to impacts associated with many other new sources industries; there-
fore, no effort has been made to discuss these types of impacts, but instead,
to reference other more general guideline documents. For example, general
guidelines for developing a comprehensive inventory of baseline data (pre-
project conditions) and a general methodology for impact evaluation are
contained in Chapters 1 and 2 of the EPA document, Environmental Impact
Assessment Guidelines for Selected New Source Industries. Although broad in
scope, this document and other appropriate guidance materials should be used
by the applicant for assistance in evaluating impacts which are not unique
to petroleum refineries.
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V.
EVALUATION OF AVAILABLE ALTERNATIVES
V.A. SITE ALTERNATIVES
As with most industries, the petroleum refinery industry locates plants on
the basis of market demand for specific products, convenience to raw mate-
rials, an adequate labor force and water supply, proximity to energy supplies
and transportation, minimization of environmental problems, and other factors
Preliminary site selection activities should occur before the EID document
is prepared. A variety of candidate sites initially should be considered and
following a detailed analysis of each one, a preferred site should be selected
that best satisfies project objectives and that Is expected to result in the
least adverse environmental impact.
The factors considered in selecting each site, and especially those that
influenced a positive or negative decision on its suitability, should be
documented carefully in the permit applicant's EID. Adequate information
on the feasible alternatives to the proposed site is a necessary consideration
in issuing, conditioning, or denial of an NPDES permit.
Specifically the advantages and disadvantages of each aIterative site must
be catalogued with due regard to preserving natural features such as wetlands
and other sensitive ecosystems and to minimizing significant adverse environ-
mental Impacts. The applicant should ascertain that all Impacts are evaluated
as to their significance, magnitude, frequency of occurrence, cumula ive
effects reversibility, secondary or induced effects, and duration of Impacts.
If site'selection could Influence accidents or spills of hazardous or toxic
substances, it should be discussed fully in the EID.
Tn ^ FTD ,-he aDDlicant also should display the alternative site locations
In the EID the pp refinery layout, environmental conditions,
L^her'ISe^nf siUlnLr^ion! A constant identification syst™ for
thf alternative sites should be established and retained on all graphic and
text material. Pertinent and useful information might include, but is not
limited to:
• All candidate areas and sites considered by the applicant
• Major centers of population density (urban, high, medium, low
density* or scslfi)
. Water bodies suitable for use in cooling system and/or in other
. Kilw^s, highways (existing and planned), and waterways suitable
for the transportation of fuels, wastes, raw materials, products,
. Important^topographic/geological features (mountains, marshes,
. SedicawrSd'use areas (parks, historic sites, wilderness areas,
. 0 the ^"sensitive' entiroOTM ta^aleas (wetlands, prime agricultural
lands, critical wildlife habitat, etc*>
• Mai or interconnections with power suppliers
. Sr industrial complexes, significant mineral deposits, and
mineral industries
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Quantification, although desirable, may not be possible for all factors because
of lack of adequate data. Under such circumstances, qualitative and general
comparative statements, supported by documentation, may be used. Where possible,
experience derived from operation of other refineries at the same site, or at
an environmentally similar site, may be helpful in appraising the nature of
expected environmental impacts.
Economic estimates should be based at least on a preliminary conceptual design
that considers how construction costs are affected by such site-related factors
as topography, geology, and tectonics; distance from water supply source, and
cooling tower configuration as determined by meteorological factors.
Once a specific site for location of the refinery is proposed it may receive
considerable opposition locally, statewide or even nationally. Such opposition
may derive from the fact that the proposed refinery would significantly impact
a unique recreational, archaeological, or other important natural or manmade
resource. It may destroy the rural or pristine character of an area or con-
flict with planned development for the area. It may have significant geological
and hydrological constraints. It may be subject to periodic flooding, hurri-
canes, earthquakes, or other natural disasters.
Therefore, if the proposed site location proves undesirable, then alternative
sites from among those originally considered should be reevaluated or new sites
should be identified and evaluated. Expansion or technological changes at an
existing plant site may be a possible alternative. Therefore, it is critical
that a permit applicant systematically identify and assess all feasible alter-
native site locations as early in the planning process as possible.
Several different agencies may be able to assist the applicant in evaluating
potential areas for location of the new source industry. Those include:
• State, regional, county, or local zoning or planning commissions
can describe their land use programs and where variances would be
required. Federal lands are under the authority of the appropriate
Federal land management agency (Bureau of Reclamation, U.S. Forest
Service, National Park Service, etc.)
• State or regional water resource agencies can provide information
relative to water appropriations and water rights
• Air pollution control agencies can provide assistance relative
to air quality allotments and other air-related standards and
regulations
• The Soil Conservation Service and State Geological Surveys can
provide data and consultation on soil conditions and geologic
characteristics
If the State has an industry siting law, the requirements should be cited
and any applicable constraints described.
V.B. PROCESS ALTERNATIVES
Typically, when the decision is made to expand refining capacity—either through
a new refinery or an addition to an existing one—the type of facility to be
constructed is already fixed; that is, the demand for any given product which
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initiated the decision would have dictated the type of process to be used.
The limitation on process alternatives is not as severe as it once was be-
cause of improved process versatility and the development of new process
technologies.
In addition to demand, process alternatives should be selected on the basis
of economics, engineering, and environmental considerations. The applicant
should present clearly and systematically in the EID, the methodology used
to identify, evaluate, and select the preferred process alternative. All
process alternatives that appear practical should be evaluated on the basis
of criteria such as:
• Land requirements, fuel storage facility requirements, and waste
storage facility requirements
• Release to air of CO, sulfur dioxide, nitrogen oxides, hydrogen
sulfide or other potential pollutants, subject to Federal, State
or local limitations
• Releases to water of heat, chemicals, and trace metals, etc. subject
to Federal, State, and local regulations
• Water consumption rate
• Fuel consumption and the generation of wastes with associated waste
treatment and disposal problems
• Economics
• Aesthetic considerations for each alternative process
• Reliability and energy efficiency of process
A tabular or matrix form of display often is helpful to compare costs and bene-
fits of feasible process alternatives. Processes which are not feasible should
be dismissed with an objective explanation for rejection,
V.C. NO-BUILD ALTERNATIVE
In all proposals for industrial development, the applicant must consider and
evaluate the alternative of not constructing the proposed new source facility.
Because this analysis is not unique to the development of petroleum refineries
no specific guidance is provided as part of this document. The permit appli- '
cant, therefore, is referred to Chapter IV (Alternatives to the Proposed New
Source) in the EPA document, Environmental Impact Assessment Guidelines for
Selected New Sources Industries, which was published in October 1975.
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VI. REGULATIONS OTHER THAN POLLUTION CONTROL
The applicant should be aware that various regulations other than pollution
control may apply to the siting and operation of new petroleum refineries.
The applicant should consult with the appropriate EPA Regional Administrator
regarding applicability of such regulations to the proposed new source.
Some Federal Regulations that may be pertinent to a proposed facility are:
• Coastal Zone Management Act of 1972 (16 USC 1451 et seq.)
• Fish and Wildlife Coordination Act of 1974 (16 USC 661-666)
• USDA Agriculture Conservation Service Watershed Memorandum
108 (1971)
• Wild and Scenic Rivers Act of 1969 (16 USC 1274 et seq.)
• Flood Control Act of 1944
• Federal-Aid Highway Act, as amended (1970)
• Wilderness Act of 1964
• Endangered Species Preservation Act, as amended (1973)
(16 USC 1531 et seq.)
• National Historical Preservation Act of 1974 (16 USC 470 et seq.)
• Executive Order 11593 (Protection and Enhancement of Cultural
Resources)
• Executive Order 11980 (Floodplain management)
• Executive Order 11990 (Protection of wetlands)
• Archaeological and Historic Preservation Act of 1974 (16 USC 469
01 s @q )
• Procedures of the Council on Historic Preservation (1973)(39FR3367)
• Occupational Safety and Health Act of 1970
In connection with these regulations, the applicant should place particular
emphasis on obtaining the services of a recognized archaeologist to determine
the potential for disturbance of an archaeological site, such as an early
Indian settlement or a prehistoric site. The National Register of Historic
Places also should be consulted for historic sites such as battlefields. The
applicant should consult the appropriate wildlife agency (State and Federal)
to ascertain that the natural habitat of a threatened or endangered species
will not be affected adversely.
From a health and safety standpoint, most industrial operations involve a
variety of potential hazards and to the extent that these hazards could
affect the health of plant employees, they may be characterized as potential
environmental impacts. All refinery operators should emphasize that no phase
of operation or administration is of greater importance than safety and
accident prevention. Company policy should provide and maintain safe and
healthful conditions for its employees and establish operating practices that
will result in safe working conditions and efficient operation.
The refinery must be designed and operated in compliance with the standards of
the U.S. Department of Labor, the Occupational Safety and Health Administration,
and the appropriate State statutes relative to industrial safety. The applicant
also should cooridinate closely with local and/or regional planning and zoning
commissions to determine possible building codes and restrictions.
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114
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GLOSSARY
1. Alkane - saturated hydrocarbon of the formula CnH2n+2
2. Alkylation - a process in which a branched chained hydrocarbon is created
by combining a olefin with an alkane
3. Amines - hydrocarbons containing the amine radical - NH2
4. B/CD - barrels per calender day; annual production divided by 365
5. Benzene - cyclic hydrocarbon - CgHg
6. Boiling Range - the temperature range between which the middle 80% of a
fraction boils
7. BTX - benzene, tolvene, oxylene
8. Butane - C4 alkane; C4H1Q
9. Butvlene - C4 olefins also butene
10. Catalyst - substance which encourages a reaction but does not participate
in the reaction, thereby remains unchanged
11. Catalytic Gasoline - gasoline arising from any of several catalytic pro-
cesses
12. Cracking - the process of reducing long chained hydrocarbons to simplier
compounds; also molecular cracking; when catalysts are used to accom-
plish this, the process is known as catalytic cracking; when heat alone
is used, it is called thermal cracking
13. Crude Oil - petroleum directly from wells
14. Cumene - benzene derivative; C9H12
15. Cyclic Compounds - ring hydrocarbons
16. Cyclohexane - cyclic hydrocarbon;
17. Deasphalting - a process which removes the asphalt fraction from feed-
stock
18. Distillation - a process for dividing liquid mixtures by their boiling
points; also fractionation products are known as fractions
19. Ethylene - an olefin; C2H4
20. Feedstocks - the petroleum material entering the process
21. Flash Separation - a process in which the feed is sent into a chamber
where the lower boiling components are flashed off
22. Gas Oil - a petroleum fraction which is recovered in fractionation
between kerosene and residual fuel oil (boiling range 260°C-400°C (500-
750°F.)
23. Gasoline Stabilization - a process to remove low boiling fractions which
tend to evaporate from gasoline
24. Heavy Bottoms - highest boiling fraction in a distillation column
25. Heavy Tapped (Crude Oil) - crude oil with highest boiling fraction removed
26. Hydrocracking - cracking in the presence of hydrogen to saturate the
olefins formed in the process; catalytic hydrocracking utilizes a
catalyst
27. Hydrodesulfurizing - removal of sulfur from petroleum in presence of
hydrogen; similar to hydrotreating
28. Hydroeenatlon - the process of adding hydrogen to an unsaturated hydro-
carbon
29. Hydrogen Sulfide - H2S
30. Hydrotreating - a process which removes sulfur from oil by treating it
with hydrogen to form hydrogen sulfide
31. Isobutane - branched butane isomer
115
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32. Isoroerization - the process of converting straight chained alkanes into
the branch chained isomers
33. Kerosine - a petroleum fraction with a boiling range 2202275°C (430-530°F.)
34. LPG - liquified petroleum gas - contains C3, C4 hydrocarbons
35. Lube Oil - petroleum fraction with high viscosity and flash point of
205-315°C (400-600°F); used for lubricating purposes
36. Mercaptans - organics containing SH radical groups
37. Methane - CH4
38. Middle Distillates - distilled products in the middle range of the
fractionation column
39. Naphtha - a petroleum fraction boiling in the kerosene and light gas
oil range
40. Octane Rating - percentage by volume of isooctane that must be mixed
with normal heptane to match knock intensity of the fuel undergoing
testing
41. Olefins - hydrocarbons containing a carbon - carbon double bond formula
CnH2n
42. Overhead Vacuum - distilled gas oil. Gas oil produced by use of vacuum
in distillation tower
43. Paraffins - straight chain alkanes
44. Petrochemicals, first generation - petrochemicals produced in process
step from petroleum feed stocks
45. Petrochemicals, second generation -petrochemicals produced directly from
first generation petrochemicals
46. Phenol - Benzene - containing alcohol
47. Phosphorous Pentoxide - P2O5
48. Polymerization - formation of polymers
49. Propane - C^Hg
50. Propylene - 03!!^
51. Reformate - product of reformation
52. Reforming - a catalytic process to produce gasoline using a series of
reactions including decyclization, desulfurization, ionizationed de-
hhydrogenization
53. Residual Fuel Oil - petroleum fraction boiling above 750°F.
54. Steam Electors - use of steam to produce a vacuum in a process
55. Stvrene - CH=CH2
56. Thermal Coking - conversion of heavy feed stock to coke using high
temperatures
57. Thermal gasoline - gasoline by non-catalytic means
58. Tolvene - benzene derivatives
59. Topping - distillation process which removes low boiling fraction
60. Visbreaking - a process which thermally reduces visusity
116
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TECHNICAL REPORT DATA
¦(Please read Instructions on the reverse before completing)
1. REPORT NO. 2.
EPA-130/6-81-001
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Environmental Impact Guidelines for New Source
Petroleilm Refineries
5. REPORT DATE
1^81
6. PERFORMING ORGANIZATION CODE
7. AUTHOFUS)
Technical staff of Wapora Inc.
8. PERFORMING ORGANIZATION REPORT NO.
613/A
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Wapora, Inc.
6900 Wisconsin Ave., N.W.
Washington, D.C. 20015
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-01-4157
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Federal Activities
401 M Street, S.W.
Washington, D.C. 20460
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
EPA/100/102
15. SUPPLEMENTARY NOTES
EPA Task Officer is Frank Rusincovitch, (202) 755-9368
16. ABSTRACT
This guideline document has been prepared to augment the information previously
released by the Office of Federal Activities entitled Environmental Impact
Assessment Guidelines for Selected New Source Industries. Its purpose is to
provide guidance for the preparation and/or review of environmental documents
(Environmental Information Document or Environmental Impact Statement) which
EPA may require under the authority of the National Environmental Policy Act
(NEPA) as part of the new source (NPDES) permit application review process.
This document has been prepared in seven sections, organized in a manner
to facilitate analysis of the various facets of the environmental review process.
The initial section includes a broad overview of the industry intended to
familiarize the audience with the processes, trends, impacts and applicable
pollution regulations commonly encountered in the petroleum refining industry.
Succeeding sections provide a comprehensive identification and analysis of
potential environmental impacts, pollution control technologies available to
meet Federal standards, and other controlable impacts. The document concludes
with three sections: available alternatives a listing of Federal regulations
(other than pollution control) which may apply to the new source applicant,
and a comprehensive listing of references for further reading.
,7. KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
b.IDENTIFIERS/OPEN ENDEO TERMS
c. COSATI Field/Group
Petroleum Refineries
Water Pollution
Air Pollution
Hazardous Waste
Environmental Impact
Assessment
10A
13B
18. DISTRIBUTION STATEMENT
Release Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
116
20. SECURITY CLASS (This pagef
Unclassified
22. PRICE
CPA Form 2220-1 (t-7J)
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