U.S. DEPARTMENT OF THE INTERIOR
Federal Water Pollution Control Administration
VOLUME III
INDUSTRIAL WASTE PROFILE NO. 5
PETROLEUM REFINING
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Other publications in the Industrial Waste Profile series
FWPCA Publication No. I.W.P.- 1
FWPCA Publication No. I.W.P.- 2:
FWPCA Publication No. I.W.P.- 3:
FWPCA Publication No. I.W.P.- 4:
FWPCA Publication No. I.W.P.- 6:
FWPCA Publication No. I.W.P.- 7:
FWPCA Publication No. I.W.P.- 8:
FWPCA Publication No. I.W.P.- 9:
FWPCA Publication No. I.W.P.-10:
Blast Furnace and
Steel Mills
Motor Vehicles and
Parts
Paper Mills
Textile Mill Products
Canned and Frozen
Fruits and Vegetables
Leather Tanning and
Finishing
Meat Products
Dairies
Plastics Materials and
Resins
FWPCA Publication No. I.W.P.-5
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"oa Control Admi
THE COST OF
CLEAN WATER
Volume III
Industrial Waste Profiles
No. 5 - Petroleum Refining
U. S. Department of the Interior
Federal Water Pollution Control Administration
For sale by the Superintendent of Documents, U.S. Government Printing Office
Washington, D.C., 20402 - Price $1.50
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11
PREFACE
The Industrial Waste Profiles are part of the National Requirements and
Cost Lstinate Study required by the Federal Water Pollution Control Act
as amended. The Act requires a comprehensive analysis of the reauire-
r.ent and costs of treating municipal and industrial wastes and other ef-
fluents to attain prescribed water quality standards.
The Industrial Kaste Profiles were established to describe the source
and quantity cf pollutants produced by each of the ten industries stud-
ied. The profiles were designed to provide industry and government
with information on the costs anci alternatives involved in dealing ef-
fectively with the industrial water pollution problem. They include
descriptions of the costs and effectiveness of alternative methods of
reducing linuid wastes by changing processing methods, by intensifying
use of various treatment methods, and by increasing utilization of
wastes in by-products or water reuse in processing. They also describe
past and projected changes in processing ana treatment methods.
The information provided by the profiles cannot possibly reflect the
cost or wasteload situation for a given plant. However, it is hoped
that the profiles, by providing a generalized framework for analyzing
individual plant situations, will stimulate industry's efforts to find
nore efficient ways to reduce wastes than are qenerally practiced today.
Commissioner
ii i
Federal wVt/r Pollution Control Administration
• 0
i*-*1!
(j |
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PETROLEUM REFINING
INDUSTRY WASTEWATER PROFILE
Prepared for F.W.P.C.A.
F.W.P.C.A. Contract 14-12-100
June 30, 1967
Federal Water Pollution Control Administration
November 1967
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Ill
SCOPE OF MATERIAL COVERED
This industrial wastewater profile covers the Petroleum
Refinery industry in the United States as defined by Standard
Industrial Classification 2911 of the U. S. Department of Com-
merce. It does not cover the production of crude oil or na-
tural gas from wells or the natural gasoline and other opera-
tions associated with such production. Transportation of pe-
troleum products is covered only to the extent that it is a
part of refinery pollution control, such as treatment of ballast
water. The principal areas of discussion are: the fundamental
manufacturing processes and their patterns of use, water use
and reuse, waste quantities and characteristics, waste reduction
practices (including both waste treatment and in-plant processing)
and their effectiveness, and waste treatment costs. In each area
of discussion trends have been projected to or estimates made for
the situation expected in 1977.
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V
TABLE OF CONTENTS
Page No.
PROJECT PARTICIPANTS
LIST OF TABLES
LIST OF DRAWINGS
SUMMARY
FUNDAMENTAL PROCESSES 1
Introduction 1
WATER USE AND REUSE 7
General 7
Water Requirements 9
MANUFACTURING PROCESS UTILIZATION 11
General Approach 11
Current and Future Subprocess Utilization 11
Projected Subprocess Mix 13
Technology Level and Refinery Size 1^
WASTE QUANTITIES AND CHARACTERISTICS 17
General Considerations 17
Discussion of Pertinent Wastewater Characteristics 18
Flow 19
Temperature 19
pH 19
Oxygen Demand 20
Phenol 20
Sulfide 21
Oil 21
Quantitative Evaluation of Waste Loads 22
Basis of Evaluation 22
Waste Loads by Refinery Technology Level 23
Waste Loads per Unit of Product 25
Projected Gross Waste Loads 27
Seasonal Waste Production Patterns 29
WASTE REDUCTION PRACTICES 30
In-Plant Processing Practices 30
Waste Treatment Practices 31
Discussion of Pertinent Waste Treatment Processes 31
Gravity Separation 31
Dissolved Air Flotation 31
Activated Sludge Process 32
Tr ickl ing Fi1ter 33
Aerated Lagoon 33
Oxidation Pond 34
Emulsion Breaking 35
Treatment of Ballast Waters 35
Spent Caustic Treatment 36
Sour Water Treatment 36
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vi
TABLE OF CONTENTS
(cont i nued)
Page No.
Slop Oil Treatment 37
Cool ing Towers 38
Disposal of Steam Generation Wastes 59
Sludge Disposal 39
Effectiveness of Waste Removal UO
Physical Treatment 40
Chemical Treatment Ul
Biological Treatment 4l
Tertiary Treatment k2
In-Plant Treatment ^2
Rate of Adoption of Waste Treatment Processes k-k-
Sequence and Inter-relationships of Waste Treatment UU
Discharge of Refinery Wastewater to Municipal Sewers k-6
By-Product Utilization 47
WASTE TREATMENT COSTS ^9
1966 Replacement Value and Operating Costs ^9
Capital and Annual Costs of Various Treatment Processes ^9
Effect of In-Plant Waste Reduction Practices 51
APPENDIX A - Table 1 through 19
APPENDIX B - Figures 1 through 2k
APPENDIX C - Glossary and Abbreviations
APPENDIX D - Interpretation of Water Quality Parameters
APPENDIX E - References
APPENDIX F - Fundamental Processes
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vii
Table No.
3
h
6
7
8
9
10
11
12
13
15
16
LIST OF TABLES
Title Page No.
Estimated Percentage of Petroleum Refineries Appendix A
Using Various Fundamental Manufacturing
Processes and Alternative Subprocesses
Classification of U.S. Petroleum Refineries Appendix A
by Size and Degree of Technology
Qualitative Evaluation of Wastewater Flows and Appendix A
Characteristics by Fundamental Refinery Processes
Waste Loadings and Wastewater Volumes Associated Appendix A
with Fundamental Processes in Older, Typical, and
Newer 100,000 bpsd Refineries
Waste Loadings and Wastewater Volumes Per Unit of Appendix A
Fundamental Process Throughput in Older, Typical,
and Newer Technologies
Summary of Principal Waste Loads and Wastewater Appendix A
Volumes
Estimated Wastewater Flows and Waste Loads Per Appendix A
Unit of Various Refinery Products
Projections of Total U.S. Petroleum Refinery Net Appendix A
Waste Loads and Wastewater Volumes to 1977
Monthly Variation of Total Crude Throughput and Appendix A
Gasoline and Distillate Fuel Oil Production
Efficiency of Oil Refinery Waste Treatment Appendix A
Practices Based on Effluent Quality
Degree of Adoption of Various Wastewater Treatment Appendix A
Processes
Sequence/Substitution Diagram of Waste Treatment Appendix A
Processes
Pollutional Loads from Refineries of Various Appendix A
Technologies and Sizes
Waste Treatment or Removal Cost Information - Appendix A
Older Technology
Waste Treatment or Removal Cost Information - Appendix A
Typical Technology
Waste Treatment or Removal' Cost Information - Appendix A
Newer Technology
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viii
LIST OF TABLES
(continued)
Table No. Ti tie Page No.
17 Percent of Wastewater Flow and BOD Loading Appendix A
from Fundamental Refinery Processes
18 Treatment Cost Allocations to Fundamental Appendix A
Refinery Processes
19 Estimated Percent of Sour Waters and Slop Oil Appendix A
from Fundamental Processes of Typical 100,000
bpsd Refinery
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LIST OF DRAWINGS
Figure No.
1
5
6
9
10
11
12
13
Uf
'5
16
17
18
19
20
Title Page No.
Subprocess Series Representative of an Appendix B
Older Technology
Subprocess Series Representative of a Appendix B
Typical Technology
Subprocess Series Representative of a Appendix B
Newer Technology
Effect of Waste Load Reduction on Capital Appendix B
Cost for "High" Degree of Treatment for
Typical 100,000 bpsd Petroleum Refinery
Crude Desalting (Electrostatic Desalting) Appendix B
Crude Fractionation (Crude Distillation, Appendix B
Three Stages)
Thermal Cracking (Delayed Coking) Appendix B
Thermal Cracking ( Visbreaki ng) Appendix B
Catalytic Cracking (Fluid Catalytic Cracking) Appendix B
Hydrocracki ng ( I somax) Appendix B
Polymerization (Bulk Acid Polymerization) Appendix B
Alkylation (Cascade Sulfuric Acid Alkylation) Appendix B
I somer ization (isomerate) Appendix B
Solvent Refining (Furfural Refining) Appendix B
Solvent Refining (Udex) Appendix B
Dewaxing (Solvent Dewaxing - MEK) Appendix B
Hydrotreati ng (Unifining) Appendix B
Deasphalting (Propane Deasphalting and Appendix B
Fractionation)
Drying and Sweetening (Copper Sweetening) Appendix B
Drying and Sweetening (Girbotol) Appendix B
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LIST OF DRAWINGS
(continued)
Figure No. Tit1e Page No.
2l Wax Finishing (Wax Fractionation) Appendix B
22 Grease Manufacture (Grease Manufacturing) Appendix B
23 Lube Oil Finishing (Percolation Filtration) Appendix B
2k Hydrogen Manufacture (Hydrogen, Steam Reforming) Appendix B
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SUMMARY
Introduction
Petroleum Refining is one of the most important manufacturing
industries in the country. In 1963 it employed approximately
120,000 people with an annual payroll of about 16 billion dollars.
In the same year it accounted for almost 3 percent of the Gross
National Product. It is one of the largest "wet" processing
industries in the United States. Extensive work has been done
in pollution abatement, as indicated by the 1966 estimated
replacement value of U. S. refineries' waste treatment equipment
of $255,000,000.
Fujidamental Processes
A petroleum refinery is a complex combination of interdepen-
dent processes and operations, many of which are complex in them-
selves. In the development of the pollution profile for this
industry twenty separate processes were determined to be funda-
mental operations essential to the production of the principal
products from crude oil. They are presented, with brief defini-
tions in a sequence as close to a refinery process flow sequence
as such a complex conbination permits.
Crude 0i 1__an_d Product Storage - in tanks of varying size to
provide adequate supplies of crude oils for primary frac-
tionation runs of economical duration, to equalize process
flows and provide feedstocks for intermediate processing
units, and to store final products prior to shipment in
adjustment to market demands. \.'atcr separates out during
storage and is drawn off to the sewer.
C rude Desa11 i ng - electrostatic and chemical processes for
removing inorganic salts and suspended solids from crude
oil prior to fractionation. The crude oil is mixed with
water to form an emulsion, v/hich is broken by the action
of an electrostatic field or specific demulsifying chem-
icals; the water sequesters the salts and other impurities
from the crude oil, settles out, and is discharged to
the sewer.
Crude Oil Fract?onatj_on_ - distillation to break heated
crude oil into light overhead products, such as: gases
and gasoline: kerosene, heating oil, gas oil, lube
oil and other sidestream distillate cuts; and reduced
crude bottoms. The trend is toward more complex combina-
tions of atmospheric and vacuum towers with more individual
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S-2
sidestream products. The crude oil fractional ion still
or stills provide feedstocks for the downstream processing
units and also some final products.
ThermaJ jCracking - includes visbreaking and coking as
well as regular thermal cracking. In each of these oper-
ations heavy oil fractions are broken down into lighter
fractions such as domestic heating oil, catalytic crack-
ing stock, etc., by the action of heat and pressure:
heavy fuels or coke are produced from the uncracked
residue. Regular thermal cracking, which was an impor-
tant process before the development of catalytic cracking
is being phased out, but visbreaking and coking units are
installed in a significant number of refineries, and their
application is expected to increase.
Catalytic Cracking - like thermal cracking breaks heavy
fractions', "principal ly gas oils, into lighter fractions.
This is probably the key process in production of large
volumes of high-octane gasoline stocks; furnace oils and
other useful middle distillates are also produced. The
use of a catalyst permits operations at lower temperatures
and pressures than with thermal cracking and inhibits the
formation of undesirable polymerized products. Fluidized
catalytic cracking processes, Jn which the finely-powdered
catalyst is handled as a fluid, have very largely replaced
the fixed-bed and moving bed processes, which use a beaded
or pelleted catalyst.
Hydj-oc rack ing - basically catalytic cracking in the pre-
sence of hydrogen with lower temperatures and higher pres-
sures than fluid catalytic cracking. The products are
similar to catalytic cracking, but hydrocracklng has greater
flexibility in adjusting operations to meet changing product
demands. It is one of the most rapidly growing refinery
processes.
Reforming - a molecular rearrangement process to convert
Fdw-octane feedstocks to high-octane gasoline blending
stock or to produce aromatics for petrochemical uses.
Mult5-reactor, fixed bed catalytic processes have almost
completely replaced the older thermal process. There are
many variations, but the essential and frequently the
only difference is the composition of the catalyst in-
volved.
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Polymerizat ion - a process to convert olefin feedstocks
Cprimarily propylene) into a higher molecular weight poly-
mer gasoline. This is a marginal process because the
product octane is not sufficiently higher than that of
the basic gasoline blending stocks to provide much help
in up-grading the overall motor fuel pool, and because
alkylation yields per unit of olefin feed are much better
than polymerization yields. Consequently the current poly-
merization downtrend is expected to continue.
Alkylation - the reaction of an isoparaffin (usually
isobutaneT and an olefin (propylene, butylene, etc.)
in the presence of a catalyst to produce a high octane
alkylate, which is one of the most important components
of automotive fuels. Sulfuric acid is the most widely
used catalyst, although hydrofluoric acid and aluminum
chloride are also used. Alkylation process capacity
is expected to continue to increase with the demand for
high-octane gasoline.
jsomer?zat?on - another molecular rearrangement process
very similar to reforming. The charge stocks generally
are lighter and more specific (normal butane, pentane
and hexane). The desired products are isobutane for
alkylation feedstocks and high octane isomers of the ori-
ginal feed materials for motor fuel.
Solvent Refining - includes a large number of alternative
subprocesses designed to obtain high-grade lubricating oil
stocks or aromatics, from feedstocks containing naphthenic,
acidic, organo-metal1ic or other undesirable materials.
Basically it is a solvent extraction process dependent
on the differential solubilities of the desirable and un-
desirable components of the feedstock. The principal
steps are countercurrent solvent extraction, separation
of solvent and product by heating and fractionation ,
removal of traces of solvent from the product, and solvent
recovery.
Dewaxijig - removal of wax from lube oil stocks, generally
after densphalting and solvent refining, to produce lubri-
cants with low pour points, and recover microcrystal1ine
wax. Except for Pressing and Sweating, a strictly physi-
cal process now used very little, the various dewaxing
processes use solvents, (principally methylethylketone,
MEK) to promote wax crystallization.
287-028 O - 68 - 2
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Solvent is introduced Into the waxy distillate stream
at selected points in chilling equipment, and the wax ts
removed in vacuum filters. Through selection of feed-
stocks and variation of operating conditions the empha-
sis can be shifted from dewaxing of a lube oil stock
to deoiling of a wax stock.
Hydrotreating - a process for the removal of sulfur com-
pounds, odor, color and gum-forming materials, and other
Impurities from a wide variety of petroleum fractions by
catalytic action in the presence of hydrogen. In most
subprocesses the feedstock is mixed with hydrogen, heated
and charged to the catalytic reactor. The reactor pro-
ducts are cooled, and the hydrogen, impurities, and high
grade product separated. Hydrotreating was first used
on lighter feedstocks, but with more operating experience
and improved catalysts, it has been applied to increas-
ingly heavy fractions such as lube oils and waxes. Along
with hydrocracking, it is one of the most rapidly growing
of refinery processes.
Peaspha 1 tjng - removal of asphalt or resins from viscous
hydrocarbon fractions, such as reduced crude, to produce
stocks suitable for subsequent lube oil or catalytic crack-
ing processes. This is a solvent extraction process,
generally with propane as the solvent for the asphaltic
materials. After contacting propane and the pipe still
bottoms or other heavy stock in an extraction tower, the
deasphalted oil overhead and asphaltic bottoms products
are processed to remove and recover propane.
Drying and Sweetening - a relatively broad process cate-
gory primarily to remove sulfur compounds, water and
other impurities from gasoline, kerosene, jet fuels,
domestic heating oils, and other middle distillate pro-
ducts. "Sweetening" pertains to the removal of hydro-
gen sulfide, mercaptans and elemental sulfur, which im-
part a foul odor and/or decrease the tetraethyl lead
susceptibility of gasoline; the major sweetening oper-
ations are oxidation of mercaptans to disulfides, re-
moval of nercaptans, and destruction and removal of all
sulfur compounds (and elemental sulfur). Drying is
accomplished by salt filters or adsorptive clay beds.
Electric fields are sometimes used to facilitate sep-
aration of the product and the treating solution.
------- OCR error (C:\Conversion\JobRoot\00000DAH\tiff\20017CAO.tif): Unspecified error
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S-6
available from reforming and other refinery processes.
Hydrogen is also in demand as a feedstock for ammonia
and methanol manufacture. The most widely used subpro-
cess Is Steam Reforming, In which desulfurized refinery
gases are converted to hydrogen, carbon monoxide, and
carbon dioxide in a catalytic reaction; generally there
is an additional shift converter to convert carbon mon-
oxide to carbon dioxide.
The foregoing brief definitions are amplified in the
discussion of Fundamental Processes in Appendix F.
Water JJse and Reuse
Total water used 5n U. S. petroleum refineries, including
recycle, increased 48.5 percent between 1954 and 1964 to an
average daily usage of 16.8 billion gallons. During the same
period the water Intake Increased by only 13.2 percent, which
indicates a substantial increase In water reuse. Crude oil
capacity increased 27 percent, and 1964 value added by manu-
facture was 70 percent higher than the corresponding 1954 figure.
The relationship between the Increases in total water used
and value added by manufacture is significant, because the change
in value added reflects the Increase in total products, and water
usage Is more closely related to total products than to crude
capacity. The greater increase in value added (70 percent vs.
48.5 percent for water usage) shows that more product is being
made with less water per product unit. Various surveys, as re-
ported in the literature, support this trend toward lower water
usage. A 1955 survey of 102 refineries showed an average waste-
water effluent of 374 gallons per barrel of crude throughput,
while a 1959 survey of 182 refineries showed an average of only
174 gallons. Interpretation of other data indicates wastewater
discharge of 200, 100 and 50 gallons per barrel of crude for
older, typical and newer refineries.
Cooling requirements are the major determinant of water
usage. It Is estimated that approximately 90 percent of the
refineries' water requirements are for cooling. In the 1955
survey, one third of the refineries reused their cooling water
10-50 times, and only 17 refineries used once-through cooling
systems. Refineries with recycle systems pumped about twice
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as much cooling water as the once-through refineries but withdrew
only 4 percent as much water from the streams; actual water con-
sumption (mostly evaporation losses) was, however, about 2k times
greater for the recycle systems.
Some indication of the water requirements of specific pro-
cesses is afforded by the much larger water usage of integrated
refineries as compared to "topping" plants that use no cracking
processes. The difference is attributed to the large volumes of
cooling water required for thermal and catalytic cracking pro-
cesses.
Another significant water usage is associated with the
overhead condensers on vacuum fractionating towers. Most re-
fineries use barometric condensers, which involve a direct
water spray and consequently formation of oil emulsions that
are hard to remove. With surface condensers, the cooling water
does not come in contact with the hydrocarbons and therefore
is available for reuse. Thus, replacement of barometric conden-
sers by surface condensers should have two beneficial effects:
increased water reuse, and reduction of wastewater volumes and
load ings.
Several advances in cooling water technology indicate po-
tential for water usage reductions. The use of air-cooled finned-
tube exchangers in place of conventional cooling towers should
sharply reduce water consumption because it would practically
eliminate evaporation losses; it would also achieve additional
benefits in connection with corrosion control and piping and
pumping costs. Another potential area for reduction of cooling
and heating requirements is in the reduction of intermediate
storage by sophisticated computer control to maintain uniform
product flow in a refinery. This would lessen the need to
cool hot product from a primary processing unit and reheat it
before changing to a downstream unit, and thus would reduce the
overall cooling water requirement.
In summary, it can be seen that while the total quantity of
petroleum products is increasing, the total water intake is level-
ing off. For the future, decreases in water usage and wastewater
effluent quantities through more effective cooling practices are
poss ible.
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Manufacturing Process Utilization
A knowledge of the degree of application or use of the various
fundamental and subprocesses 5s prerequisite to the development of
any meaningful industry profile. Since an exhaustive compilation of
every process in every refinery would be impractical, the analysis
of process utilization in this report is confined to the major sub-
process alternatives under each of the selected processes. In
view of the availability of wastewater data (or more precisely the
lack of such data) for many subprocesses, this restricted analysis
will be just as useful a process basis for a pollution profile
as would the elusive complete compilation. The use of the funda-
mental processes and major subprocesses in terms of percentage of
total U. S. Refineries using each is presented in the main body of
this report. The following tabulation summarizes the most signi-
ficant points of the process pattern and in particular highlights
the processing trends.
Percentage of Refineries
1950 1963 1967 1972 1977
Thermal Cracking
Thermal Cracking-Regular
Coking
V isbreaking
Catalytic Cracking
Fluid Catalytic Cracking
Thermofor Catalytic Cracking
Houdrif low
Hydrocracking
Isomax
Unicracking
H-G Hydrocracking
H-Oil
Reforming
Platforming
Catalytic Reforming-Engelhard
Powerforming
Ultraforming
59
48
28
14
13
45
18
16
16
40
8
20
18
35
2
25
22
25
51
39
13
3
56
45
12
4
60
50
10
2
65
60
6
0
0.3
8
4
2
0.8
0.4
25
11
8
3
1
34
15
12
3
1
62
37
5
1
6
67
40
9
2
6
74
44
11
3
7
79
47
12
3
8
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Pe rce n t a ge of Re fine r i_ej
Polymerization
Alkylation
Sulfuric Acid
HF
Mydrot resting
Uni fining
Hydrofi ni ng
Trickle Hydrodesulfurization
Ultrafining
Lube Oil Finishing
Percolation Filtration
Contin. Contact Filtration
Hydrotreating
550
25
10
1963
42
38
22
16
1967
33
A 7
26
21
1372
26
54
32
22
22
0.3
3
n
n
6
2
56
23
3
70
30
7
7
c
20
r
_/
7
o
1S77
62
33
25
80
10
20
2
7
11
In a number of cases the fundamental process figure and the sum
of the listed subprocesses do not agree. There are two reasons
for such apparent discrepancies. A single refinery may use two
or more subprocesses in a given fundamental process arsa, such as
Thermal Cracking; or all the applicable subprocesses may not be
listed, e.g., Hydrotreating, where there are so many alternatives.
The degree of utilization can be expressed also in terms of
capacities of the various processes and subprocesses as well as per-
centages of refineries using each. The difference between the two
approaches is not significant in comparing subprocesses within a
given fundamental process but is significant in establishing rela-
tionships between the fundamental processes. For example, in
1963 catalytic cracking was used in 51 percent of the nation's
refineries, and polymerization in k2 percent, not a great differ-
ence; however, the combined capacity of the catalytic cracking
units was more than 30 times that of the polymerization units.
One way of recognizing this factor in the subsequent develop-
ment of wastewater volumes and loadings is the establishment of a
series of categories to denote the general technology level of a
refinery. In this series three levels of technology are defined:
Older - using relatively inefficient and/or obsolescent
processes and subprocesses.
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Typical - The processes and subprocesses most widely
used today
Newer - using all or most of the advanced processes and
subprocesses.
Thus, each subprocess is designated as older, typical or newer.
This is not always clear cut, and in many cases a subprocess can
be justifiably classified in more than one technology category.
For example, the Platforming version of catalytic reforming is
designated in all these categories because it has been used for
many years, is the most widely used reforming process at present,
and is still being installed in the newest and most modern re-
fineries.
The 1950, 1963 and 196? figures in the process utilization
tabulation were based on the annual refinery surveys of The Oil
and Gas Jou_rna 1 supplemented by other published data and results
of specific refinery surveys. The projections for 1972 and 1577
involved several assumptions.
1. Decrease in number of refineries at rate of 2 percent
per year.
2. Most of this decrease attributed to shutdown of smaller
and less complex refineries.
3. Increase in crude capacity at a rate of 1.5 percent per
year.
'(. Increase in average capacity of newer subprocesses.
5. Mo change in average capacity of subprocesses being
phased out.
6. No introduction of revolutionary new processes by 1977.
The assumptions concerning the number of refineries and subprocess
unit capacities are based on analysis of industry practices and
trends from 1935 to the present. The crude capacity increase is
derived from industry forecasts of demand for petroleum products
with consideration of the impact of imported crude and of the
expectation of greater yields per barrel of crude. The prediction
of no introduction of revolutionary new processes is based on the
absence of any current new technological breakthrough and on the
proposition that even if such a breakthrough were achieved in con-
ceptual form this year, a resulting refinery process would require
several years of development work before even limited use.
Projections of the subprocess mix were also influenced by pro-
jections of product demands and economic factors. For example,
increasing demand for low sulfur fuels (based on air pollution
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considerations) will promote the use of hydrocracking and hydro-
treating. At the same time, the relatively greater cost of hydro-
treating will slow down the growth in situations where the newer
drying-and-sweetening subprocesses can attain acceptable sulfur
remova1s.
After delineation of the current and projected process
utilization picture, the next step in development of the industry
profile was to work up a combination of processes reflecting three
levels of technology and three ranges of refinery size. Subpro-
cesses most representative of older, typical, and newer technology
were selected, and overall flow diagrams were prepared for refin-
eries representatives of each stage of technology. There are some
differences in the fundamental processes comprising these three
hypothetical refineries because older methods are being phased out
and newer ones are becoming increasingly important. This involves
some divergence from the definition of fundamental processes as
being essential to the manufacturing process, but in the ever
changing petroleum industry what was essential in 1950 or 19&3
is not necessarily still required in 1967, nor expected to be so
in 1972 or 1977-
Refinery sizes ranges were established as: Small, under
35,000 bpsd; Medium, 35-100,000 bpsd; and Large, over 100,000
bpsd. The following table shows the percentage of U. S. Refin-
eries in each of the size and technology categories.
Refinery Size
Technology Sma11 Ned i urn Large
Older 31.2% 4.4% 0.4%
Typical 32.5% 17.4% 7.0%
Newer 3.4% 1.3% 2.4%
Total 67.1% 23.U 9.8%
The use of these figures in assessing the contribution of
each type of refinery to the total industry must be modified by
consideration of crude capacity. This factor shows that the
Large refineries (9.8 percent of the total) account for 45.7
percent of the total crude capacity, whereas the Small refineries
(67.1 percent in terms of number of refineries) account for only
19.5 percent of the crude capacity.
Classification of existing refineries into the technology
catagories presented some problems. There was sufficient infor-
mation on processes and subprocesses to provide a substantial
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S-12
basJs for classification In most instances, but numerous overlapping
and single-purpose situations required the exercise of considerable
judgment. The following examples illustrate the rationale of assign-
ment. A relatively complete refinery that included both hydrocracking
and isomertzation was classified as "newer". A refinery with Thermofor
catalytic cracking and polymerization but with neither alkylation nor
hydrotreatlng was classified as "older". In many Instances, parti-
cularly among the smaller refineries, the number of missing processes
was so high that meaningful technological classification was not
possible, and only 196 of the 261 refineries were classifed. The
remaining refineries were divided between the older and typical
technologies with a bias toward the older, because the hard-to-
classify, very small refineries are also the least likely to keep
pace with general technological advancement.
In view of the limitations imposed by the scarcity of waste-
water data for specific subprocesses, the quantitative evaluation
of waste loads Is based on apportionment of total refinery efflu-
ent data to supplement the incomplete specific subprocess effluent
data. Wastewater surveys from five refineries had pollutant con-
centration and wastewater flow data suitable for determination of
subprocess waste loadings. These data and information on subpro-
cess unit throughputs from other sources constituted the basis for
quantitative waste load determination. It soon was apparent that
the available data were not sufficiently comprehensive to support
the original plan for development of wastewater quantities and
pollutant loadings for small, medium, and large refineries in
each technology level. For one thing, the data sources which
were satisfactory on a subprocess basis did not include all re-
finery size ranges in each technology category. Thus, a hypo-
thetical 100,000 bpsd refinery was selected as the base for
quantitative waste evaluation for the three technology levels.
BOO, phenol and sulfide waste loadings were used in the quan-
titative evaluation, because experience has shown that these con-
taminants, along with wastewater flow, are the major determinants
of wastewater treatment costs. Total refinery values for these
three parameters and for wastewater flow were calculated by sum-
mation of the corresponding values for each fundamental refinery
process. These data are summarized in the following tables along
with similar data based on refinery effluents from API separators:
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S-13
Summation of Individual Processes
Technology
Older
Typical
Newer
Technology
Older
Typical
Newer
Flow
mg_d_
23.1
9.9
4.5
Flow
mgd
25.0
10.0
5.0
BOD
l_bs/day
Phenol
lj3S/day
Sulfide
l_bs/day
12,500
5.^00
4,200
3,500
1,650
850
After API Separator
BOD
Ibs/day
40,000
10,000
5,000
Phenol
l_bs_/day
3,000
1 ,000
500
2,200
625
680
Sulfide
l_bs_/d_a_y
1 ,000
300
300
The wastewater flow based on total effluent after API Separators
is somewhat higher, probably because flow data were not available for
some processes and because of significant variations in cooling water
practices. The BOD waste load in each technology category is higher
for total effluent than for the summation. There are two reasons
for this difference: lack of BOD data for a few processes- and,
more significantly, the contribution of leaks, spills and other non-
process sources. The much small discrepancy in the newer refineries
indicates the non-process sources as the principal explanation. On
the other hand, phenol and sulfide loadings are consistently lower
on the total refinery effluent basis. Phenol Is partially extracted
by oil and is removed along with oil in the API separators. Sulfide
concentrations in the refinery sewers are reduced by turbulence,
temperature and lower pH and by removal in sour water strippers at
various processing units.
Waste loads were also calculated on the basis of units of major
refinery products. This involved allocation of the overall refinery
and specific process waste loadings to specific products based on
average national yields of these products and the connection be-
tween specific processes and specific products.
Total industry waste loads and wastewater flow were projected
to 1977. Waste loads were projected on the basis of an annual
rate of increase of 3.6 percent, based on a compromise of industry
forecasts and projections of crude throughput and product value
added. The wastewater flow projection was more moderate, an
approximate increase of 1 percent per year, because of strong
trends in the Industry in improvement of cooling water practices.
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S-14
Refinery throughput and the output of major products were
reviewed for evidences of seasonal waste production patterns but
no appreciable variations were detected, despite seasonal changes
in demands for gasoline and domestic heating oil.
Waste Reduction PractIces
Evaluation of the effectiveness of in-plant processing changes
in reducing wastewater pollution was qualitative and general, rather
than quantitative and specific. In regard to the relative pollution
effects of specific processes, the most significant developments
have been hydrocracking and hydrotreating. Each of these processes
generates substantially lower pollution loadings than the processes
they are replacing; available data on pollutant concentrations in
the unit wastewater streams indicates that these processes have
significantly reduced sulfide and spent caustic waste loadings. A
more general indication of pollution reduction by ?n-plant pro-
cessing practices is the much lower pollutant loadings per unit of
throughput for "newer" refineries as compared to "older" or "typical1
refineries. This reduction is attributed In large measure to de-
creased losses to the sewers by sampling and water drawoff opera-
tions in the "newer" refineries, where facilities, controls, and
general operating practices are likely to be superior.
Waste treatment methods applicable to petroleum refineries can
be divided into five types: Physical, Chemical, Biological, Ter-
tiary, and Special In-Plant methods.
Physical methods include gravity separators, air flotation
(without chemicals), and evaporation. Gravity separators (API and
earthen basins), which are used in practically all refineries,
are designed primarily for removal of floatable oil and settleable
solids. They remove 50-99% of the separable oil and 10-85% of
the suspended solids: concurrently with these principal functions
they remove BOD, COD, and phenol, at times to a substantial degree
depending on the influent wastewater characteristics. Air flota-
tion without chemical addition obtains comparable results. Pollu-
tant removals by evaporation ponds are very high, but the appli-
cation of this method is severely limited by location, climate,
and land availability considerations.
Chemical methods (Coagulation-sedimentation and chemically
assisted air flotation) are more effective in oil and solids re-
moval, particularly in respect to emulsified oil.
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S-15
The biological methods Include activated sludge, trickling
filters, aerated lagoon, and oxidation ponds. In general these
treatment processes require wastewater pretreatment to remove
oil and remove or control other conditions (such as pH and toxic
substances). The Activated Sludge process is the most effective
for removal of organic materials (which is the main purpose of bio-
logical treatment); expected removal efficiencies are 70-95% for
BOD, 30-70% for COD, and 65-991 for phenols and cyanides.
Tertiary treatment to date has been limited to activated
carbon and ozonatlon, which are effective in removing taste and
odor elements and refractory organic substances from biologically
treated wastewaters.
The most important In-plant treatment methods are sour water
stripping, neutralization and oxidation of spent caustics, ballast
water treatment, slop oil recovery, and temperature control. These
measures substantially reduce the waste loadings in the influent
to general refinery treatment facilities, and to a significant de-
gree are necessary to insure reasonable performance of the general
treatment facilities.
The extent of use of various waste treatment practices was
reviewed. Practically all of today's refineries use gravity sep-
arators, but only 5-10% have chemical treatment facilities. Approx-
imately one-fourth have oxidation ponds, but substantially fewer
(5-7%) use the more effective biological treatment processes. Pro-
jection of the extent of use to 1977 indicates: continued full
application of gravity separators, with API separators replacing
most of the earthen basin types; chemical treatment processes in
15-20% of the refineries; greatly increased use of biological
treatment processes, with essentially all refineries using bio-
logical treatment, including 55% using the Activated Sludge pro-
cess; approximately 5% utilization of tertiary treatment. The
projections reflect the assumption of more comprehensive and
more stringent water and air pollution regulations.
In considering the effectiveness of individual waste treatment
processes, it is essential that they be arranged in proper sequence
and that segregation of "clean" wastewaters and other pretreatment
measures be properly evaluated.
Discharge of refinery wastewater to municipal sewers has not
been a significant factor in refinery pollution control, primarily
because of prohibition of discharges of oil and inflammable and
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S-16
and explosive materials. However, with proper pretreatment, In-
cluding oil, sulfide and phenol removal, disposal via municipal
systems is technically feasible and could be economically advan-
tageous .
Byproduct utilization, defined as disposal of materials to
accrue some economic benefit but not enough to cover the cost of
recovery, is limited. The only really significant byproduct
apparent at the present time is sulfur, which is recovered from
sour water and hydrotreating processes. The value of the sulfur
so recovered in 1966 has been estimated at $AO,000,000.
Wa_s_te ^Treatment Costs
A comprehensive report on waste treatment costs in the petrol-
eum refining industry in 1959 indicated that on the basis of 183
refineries reporting (out of a possible 313) replacement and opera-
ting costs for waste treatment processes totalled $156,000,000
and $30,000,000 respectively. These costs were calculated by extra-
polating to account for 100 percent of the crude capacity at that
time. In 1959, planned additions to waste treatment facilities for
13^ refineries totalled $29,000,000.
The data from this 1959 report were used as the basis for
calculation of replacement value and operating costs for 1966.
The factors used to update the data were assumption of a 30 per-
cent increase in construction and operating costs, and extrapo-
lation of the value of the 1959 planned additions for 134 refin-
eries to cover the 1966 total of 279 refineries. In this manner
the 1966 wastewater facilities replacement value was estimated
to be $275,000,000 and the related annual operating costs $55,000,000,
Capital and annual costs for 10-12 specific waste treatment
processes required for adequate overall refinery, or end-of-pipe,
treatment were calculated for small, medium, and large refineries
in the older, typical, and newer technology categories. For
purposes of this calculation, the following throughput were used:
small - 30,000 bpsd: medium - 75,000 bpsd; large - 150,000 bpsd.
The capital costs were based on estimates of 1967 construction costs
(including a 15% contingency allowance) but did not include design
or other engineering fees. The annual costs, also 1967 estimates.
included operating labor, maintenance, utilities, and chemicals
costs but no fixed charges for depreciation, interest, taxes, etc.
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S-17
These end-of-pipe treatment costs were then prorated among
the various fundamental refinery processes on the basis of waste-
water flow and BOD loading of each fundamental process. Ideally
the final step In this cost allocation procedure would have been
to spread the cost of each waste treatment process over each of
the fundamental processes for small, medium, and large refineries
In each of the three technology levels. However, this would have
required more than 100 separate tables, and to overcome this
formidable obstacle and at the same time obtain a reasonable
estimate of treatment cost allocation, three end-of-pipe waste-
water treatment trains were developed to represent low, inter-
mediate, and high degrees of treatment. These were defined as
follows :
Low - API Separator and Slop Oil Treatment
Intermediate - Low, plus Aerated Lagoon and Sour Water
Strlppi ng
High - Low, plus Activated Sludge, Sour Water Stripping,
Sludge Thickening and Vacuum Filtration, and
Sludge Incineration.
The cost allocations for a typical refinery are presented in
the following table.
Percent of Total Treatment Cost
Fundamental Process
Crude Oil Storage
Crude Oil Desalting
Crude Oil Fraction-
ation
Thermal Cracking
Catalytic Cracking
Hydrocracking
Reforming
Polymerization
Alkylation
Solvent Refining
Dewaxing
Hydretreating
Drylng-and-Sweet-
enlng
Other
Low
Degree
Capital Annual
1.9
7.0
50.1
5.3
17.6
2.6
0.6
0.7
1.7
0.4
o.4
0.2
9.6
1.9
2.7
4.6
50.0
3.5
16.6
1.7
0.8
0.9
2.4
o.4
0.6
0.3
13.3
2.2
Inter.
Capital
1.6
3^
41.2
6.2
19.7
4.5
0.5
0.6
1.5
0.2
0.4
5.4
11.4
3.2
Degree
Annual
2.5
2.8
45.0
3.8
17.8
2.8
0.8
0.9
2.3
0.3
0.6
3.3
14.9
2.2
High
Capital
2.4
2.5
34.2
2.6
14.4
1.9
0.6
0.7
1.8
0.3
5.5
2.5
17.9
12.7
Degree
Annual
2.7
2.3
35.4
1.6
13.5
1.0
0.6
0.9
2.2
0.3
5.7
1.6
19.6
12.6
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S-18
Examination of this table discloses that Crude Oil Fractionation,
Catalytic Cracking, and Drying-and-Sweetenlng account for the
major shore of the treatment costs, with Drying-and-Sweetening
becoming more prominent as the degree of waste treatment advances.
Although detailed cost information for justification of in-
ilant processing measures for pollution abatement is not available,
an indication of their economic value is afforded by analysis
3f the effects of reduction of organic and hydraulic loadings
on treatment costs. Data for a 100,000 bpsd refinery, with
a "high" degree of waste treatment as previously defined, indi-
cate that a 50% reduction in BOO loading (with wastewater flow
unchanged) would effect a 15% reduction In capital cost of the
treatment facilities. A 50% reduction In wastewater flow (with
BOD loading unchanged) would effect a 20% reduction. If both
BOD and flow are reduced 50%, the capital cost would be reduced
by 32%.
-------
FUNDAMENTAL PROCESSES
Introduction
A petroleum refinery Is a complex combination of Interdepen-
dent operations and processes, which can be divided Into six major
groups:
1) Storage - e.g., of crude oil, intermediates, and final
products
2) Fractionation - e.g., distillatlve separation and
vacuum fractionation
3) Decomposition - e.g., thermal cracking, catalytic
cracking, and hydrocracking
k) Hydrocarbon Rebuilding and Rearrangement - e.g., polymer-
ization, alkylation, reforming, isomertzatfon
5) Extraction - e.g., solvent refining, solvent dewaxlng
6) Product Finishing - e.g., drying-and-sweetening, lube
oil finishing, blending and packaging.
For this pollution profile, twenty separate processes have been
selected as the fundamental processes essential to production of
final products from crude oil. They are presented, with brief
definitions, in a sequence as close to a refinery process flow
sequence as such a complex combination permits.
The major sources for the process descriptions were the "1966
Refining Process Handbook" of Hydrpcarbon ProcessIng magaz1ne (1)
and W. L. Nelson's Petroleum Refinery Engineering (2). Information
regarding the wastes from each process was obtained from ROY F.
WESTON files (3), personal interviews (k), and Aqueous Wastes fj"om
Petroleum and Petrochemical Plants by W. R. Beychok (5).
Crude Oil and Product Storage - in tanks of varying size to
provide adequate supplies of crude oils for primary frac-
tionation runs of economical duration, to equalize process
flows and provide feedstocks for intermediate processing
units, and to store final products prior to shipment In
adjustment to market demands. Water separates out during
storage and is drawn off to the sewer.
Crude Desalting - electrostatic and chemical processes for
remov ing I no rganIc salts and suspended solids from crude
oil prior to fractionation. The crude oil Is mixed with
water to form an emulsion, which Is broken by the action
of an electrostatic field or specific demulslfylng chem-
icals; the water sequesters the salts and other Impurities
from the crude oil, settles out, and Is discharged to
the sewer.
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-2-
Crude Oil Fractionatlon - distillation to break heated
crude oil into light overhead products, such as: gases
and gasoline; kerosene, heating oil, gas oil, tube oil
and other sldestream distillate cuts; and reduced crude
bottoms. The trend is toward more complex combinations
of atmospheric and vacuum towers with more Individual
sidestream products. The crude oil fractionation still
or stills provide feedstocks for the downstream processing
units and also some final products.
Thermal Cracking - includes visbreaklng and coking as
well as regular thermal cracking. In each of these oper-
ations heavy oil fractions are broken down Into lighter
fractions such as domestic heating oil, catalytic crack-
ing stock, etc., by the action of heat and pressure;
heavy fuels or coke are produced from the uncracked
residue. Regular thermal cracking, which was an Impor-
tant process before the development of catalytic cracking
is being phased out, but visbreaklng and coking units are
Installed in a sfgnificant'number of refineries, and their
application is expected to increase.
Catalytic Cracking - like thermal cracking breaks heavy
f r actions, pr Inclpa11y gas oils, Into lighter fractions.
This is probably the key process in production of large
volumes of high-octane gasoline stocks; furnace oils and
other useful middle distillates are also produced. The
use of a catalyst permits operations at lower temperatures
and pressures than with thermal cracking and inhibits the
formation of undesirable polymerized products. Fluidized
catalytic cracking processes, in which the finely-powdered
catalyst is handled as a fluid, have very largely replaced
the fixed-bed and moving bed processes, which use a beaded
or pelleted catalyst.
Hydrocracking - basically catalytic cracking In the pre-
sence of hydrogen with lower temperatures and higher pres-
sures than fluid catalytic cracking. The products are
similar to catalytic cracking, but hydrocracking has greater
flexibility in adjusting operations to meet changing product
demands. It is one of the most rapidly growing refinery
processes.
Reforming - a molecular rearrangement process to convert
low-octane feedstocks to high-octane gasoline blending
stock or to produce aromatics for petrochemical uses.
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-3-
MultI-reactor, fixed bed catalytic processes have almost
completely replaced the older thermal process. There are
many variations, but the essential and frequently the
only difference Is the composition of the catalyst in-
volved.
Polymerization - a process to convert olefln feedstocks
(primarily propylene) into a higher molecular weight poly-
mer gasoline. This is a marginal process because the
product octane is not sufficiently higher than that of
the basic gasoline blending stocks to provide much help
in up-grading the overall motor fuel pool, and because
alkylation yields per unit of olefln feed are much better
than polymerization yields. Consequently the current poly-
merization downtrend is expected to continue.
Alkylation - the reaction of an isoparafffn (usually
isobutane) and an olefin (propylene, butylene, etc.)
in the presence of a catalyst to produce a high octane
aIky late, which is one of the most important components
of automotive fuels. Sulfurfc acid is the most widely
used catalyst, although hydrofluoric acid and aluminum
chloride are also used. Alkylation process capacity
is expected to continue to increase with the demand for
high-octane gasoline.
I somer|ration - another molecular rearrangement process
very si milar to reforming. The charge stocks generally
are lighter and more specific (normal butane, pentane
and hexane). The desired products are isobutane for
alkylation feedstocks and high-octane tsomers of the ori-
ginal feed materials for motor fuel.
Solvent Refining - includes a large number of alternative
subprocesses designed to obtain high-grade lubricating oil
stocks or aromatics, from feedstocks containing naphthenlc,
acidic, organo-metailIc or other undesirable materials.
Basically It is a solvent extraction process dependent
on the differential solubilities of the desirable and un-
desirable components of the feedstock. The principal
steps are countercurrent solvent extraction, separation
of solvent and product by heating and fractlonatlon,
removal of traces of solvent from the product, and solvent
recovery.
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-k-
Dewaxlng - removal of wax from lube oil stocks, generally
after deasphaltlng and solvent refining, to produce lubri-
cants with low pour points, and recover mlcrocrystal1Ine
wax. Except for Pressing and Sweating, a strictly physi-
cal process now used very little, the various dewaxlng
processes use solvents, (principally methylethylketone,
MEK) to promote wax crystallization.
Solvent is introduced into the waxy distillate stream
at selected points in chilling equipment, and the wax is
removed In vacuum filters. Through selection of feed-
stocks and variation of operating conditions the empha-
sis can be shifted from dewaxing of a lube oil stock
to deoillng of a wax stock.
H}^d retreating - a process for the removal of sulfur com-
pounds, odor" color and gum-forming materials, and other
impurities from a wide variety of petroleum fractions by
catalytic action in the presence of hydrogen. In most
subprocesses the feedstock Is mixed with hydrogen, heated
and charged to the catalytic reactor. The reactor pro-
ducts are cooled, and the hydrogen, impurities, and high
grade product separated. Hydretreating was first used
on lighter feedstocks, but with more operating experience
and improved catalysts, It has been applied to increas-
ingly heavy fractions such as lube oils and waxes. Along
with hydrocracking, it is one of the most rapidly growing
of refinery processes.
Peasphalting - removal of asphalt or resins from viscous
hyd rocarbon f ractIons, such as reduced crude, to produce
stocks suitable for subsequent lube oil or catalytic crack-
ing processes. This Is a solvent extraction process,
generally with propane as the solvent for the asphaltlc
materials. After contacting propane and the pipe still
bottoms or other heavy stock in an extraction tower, the
deasphalted oil overhead and asphaltic bottoms products
are processed to remove and recover propane.
D ryIng an d Swee ten J ng - a relatively broad process cate-
gory primarily to remove sulfur compounds, water and
other Impurities from gasoline, kerosene, jet fuels,
domestic heating oils, and other middle distillate pro-
ducts. "Sweetening" pertains to the removal of hydro-
gen sulfide, mercaptans and elemental sulfur, which Im-
part a foul odor and/or decrease the tetraethyl lead
-------
-5-
susceptibility of gasoline; the major sweetening oper-
ations are oxidation of mercaptans to dtsulfldes, re-
moval of mercaptans, and destruction and removal of ail
sulfur compounds (and elemental sulfur). Drying is
accomplished by salt filters or adsorptive clay beds.
Electric fields are sometimes used to facilitate sep-
aration of the product and the treating solution.
Wax Manufacture - the current widely used fractionatlon
process for production of paraffin (and at times microcry-
stalline) waxes of low oil content is similar in most re-
spects to MEK Dewaxing. The principal differences are the
selection of a solvent or solvent mixture more suitable to
the crystallization and separation of paraffin wax, and a
more complicated crystallization-filtration flow involving
redissolving and recrystallIzation.
Grease Manufacture - this process for the manufacture of
various lubricating greases involves preparation of a soap
base from an alkali earth hydroxide and a fatty acid,
followed by addition of oil and special additives. The
major equipment consists of an oil circulation heater,
a high-dispersion contactor, a scraper kettle, and a
grease polisher. Because of developments in sealed grease
fittings and longer lasting greases, grease production is
expected to continue to decline.
Lube Oil Finishing - Solvent refined and dewaxed lube
oil stocks are further refined by clay or acid treatment
to remove color-reforming and other undesirable materials.
Continuous Contact Filtration, In which an oil-clay
slurry is heated and the oil removed by vacuum filtra-
tion, and Percolation Filtration, wherein the oil Is
filtered through clay beds, are the most widely used
subprocesses. Percolation also involves naphtha washing
and kiln-burning of spent clay to remove carbonaceous de-
posits and other impurities.
Blending and Packaging - Blending Is the final step in
producing finished petroleum products to meet quality
specifications and market demands. The largest volume
operation is the blending of various gasoline stocks
(including alkylates and other high-octane components)
and anti-knock (tetraethyl lead) anti-rust, anti-Icing,
and other additives. Diesel Fuels, lube oils, waxes,
and asphalts are other refinery products which normally
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-6-
tnvolve blending of various components and/or additives.
Packaging at refineries Is generally highly-automated
and restricted to high-volume, consumer-oriented pro-
ducts such as motor oils.
Hydrogen Manuf act u re - the rapid growth of hydrotreatlng
and hydrocracking has Increased the newer refineries' de-
mand for hydrogen beyond the level of byproduct hydrogen
available from reforming and other refinery processes.
Hydrogen is also In demand as a feedstock for ammonia
and methanol manufacture. The most widely used subpro-
cess is Steam Reforming, in which desulfurlzed refinery
gases are converted to hydrogen, carbon monoxide, and
carbon dioxide in a catalytic reaction; generally there
is an additional shift converter to convert carbon mon-
oxide to carbon dioxide.
The foregoing brief definitions are amplified In the
discussion of Fundamental Processes In Appendix F.
Simplified process flow diagrams for representative sub-
processes in most of the fundamental process areas are presented
In Figures 5 through 2k.
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-7-
-'iD- AEJis_E
GeneraJ_
Total water used in the U. S. petroleum refineries, including
recycle, increased from 11.3 billion gallons per day (bgd) in
195** to 16.8 bgd in 1964, an increase of 48.52. Water intake
during this period increased only 13.2%, indicating a substantial
rise in water reuse. In 1954 70% of the total water used was
provided by recycle, while in 1964 77% was provided by recycle (8),
The reuse ratio (total water used divided by water intake) in-
creased from 3-3 to 4.4 during this period.
Future implications of water use can be best understood by
relating water use to refinery operation. The crude oil capacity
increased 27% during the 1954-64 period while the value added
by manufacture increased 70%. The following table summarizes
these increases.
Total Water Used 48.5%
Total Water Intake 13.2%
Crude Oil Capacity 27%
Value Added by Manufacture 70%
The most meaningful data in this table are the total water used
and the value added by manufacture, because value added reflects
the increase in total products generated and total water usage
is more closely related to total products than to crude capacity.
The main point in this discussion of water use and reuse is that
more products are being produced with less water. To further
support this conslusion, unit water discharged expressed as gal-
lons of water used per barrel of crude processed is a meaningful
yardstick. A 1955 survey (9) of 102 refineries indicated an
average effluent of 374 gallons per barrel of crude, and a 1959
survey (10) of 182 refineries indicated an average of 170 gallons
per barrel. Approximately 25 individual refinery effluents cover
ing various size refineries with varying degrees of technology
were also reviewed. An Interpretation of all the data available
indicates an older refinery discharges 200 gallons of wastewater
per barrel of crude; a typical refinery, 100 gallons per barrel;
and a new refinery. 50 gallons per barrel. As larger, more inte-
grated refineries are built, wastewater effluent unit volume will
decrease.
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-8-
The following tabulation summarizes the various uses of
the water withdrawn from surface and ground water sources by
petroleum refineries.
Use of Water Withdrawn by U.S. Petroleum Refineries-1964
Billion Gallons Percent
per year of Intake
Cooling and Condensing 1,125 81.0
Steam for Power Generation 81 5.8
Boiler Feedwater and Sanitary Service 98 7.1
Process 84 6.1
Total Intake 1,388 100.0
Total Water Used
(including reelrculation and reuse)
Very little, if any process water is reused. One eastern
refinery uses spent caustic from neutralization of alkylation
process wastes as make-up to the barometric condensers on the
vacuum distillation stills. However, severe emulsion problems
have arisen and the procedure is being abandoned. Some refin-
eries have used sulfidic wastes from separation operations in
the cracking processes to control temperature in a fluid cata-
lytic cracker by injecting the wastes into the reaction zone.
Again problems have been created by the recycle of metals and
tars, which tend to gum or poison the catalysts.
The API Manual on Disposal of Refinery Wastes (Vol. Ill,
p. 33) lists many situations where process waters can be reused,
such as reuse of phenolic wastewaters or sulfide stripped con-
densate as make-up water to a crude oil desalter. Only a small
number of refineries employ any of these methods, and even then
only on a limited basis.
Only 6.1% of water withdrawn is used for process water and
based on gross water used, process waters constitute only \.k%
of total water used. Information on process water reuse in the
industry is not available, but reuse is probably insignificant:.
The most fruitful area of water reuse is cooling water recircu-
lation.
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Wa t er Requ ! r erne n t s
In 1955 91% of the water requirements of the petroleum re-
fineries surveyed was for cooling. One third of the refineries
reused their cooling water from 10 to more than 50 times, and
only 17 refineries used once-through cooling systems. Refineries
with reci rculat ing cooling systems circulated about twice as much
water as refineries using once-through cooling systems, but needed
only k percent as much raw water supply. Evaporation loss
(actual water consumed) was about 2k times greater for the recir-
culating system.
Refineries which did not have cracking operations used con-
siderably less water than the more integrated plants having
cracking operations, primarily because of the large volumes
of water required for thermal and catalytic cracking processes.
Vacuum f ract ionat ion of crudes and reduced crudes is used
in essentially all refineries, and the steam jet ejector is the
most widely used method of producing a vacuum for these fraction-
ation processes. Ejectors use steam which is expanded through
a nozzle to create the vacuum. The steam vapors and the vapors
removed from the fractionator must be condensed. For certain
processes having rich overhead vapors a product cooler, such as
a shel 1 -and-tube heat exchanger, is used to condense and recover
the valuable organics. The remaining condensables must be re-
moved prior to discharge of the vapor stream to the atmosphere,
and the most commonly used method is a direct water spray in a
chamber called a barometric condenser. The organics, oils,
and steam condensate are intimately mixed in a large volume of
colling water. This mixing and dilution tends to form oil emul-
sions which are very difficult to remove.
In some refineries surface condensers are used instead of
barometric condensers. These usually consist of a series of
shel 1 -and-tube heat exchangers in which the condensable materials
are removed and the water used for cooling does not come in con-
tact with the condensate. In many cases the condensate is highly
concentrated and can be recovered, incinerated, or treated sep-
arately. The cooling water is not contaminated by the oils and
organics, and can be reused again after removal of the heat.
While surface condensers are far superior to the barometric con-
densers, they are most costly to install, have higher maintenance
and operation costs, and have a shorter equipment life. Surface-
condensing steam jets are being installed in the newer refineries
and will play an important role in reduction of wastewater ef-
fluents .
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-10-
There are several advances in technology that will reduce
cooling requirements and subsequently cooling water usage. In
arid regions where water is at a premium, the use of finned-tube
coolers is becoming important. This cooling method employs forced
air flow over a bank of finned tubes through which the spent cool-
ing water is passed. Heat is transferred from the water through
the tubes to the air stream by convection and radiation. The
greatest single advantage of this process is that the water is
contained in a completely closed system and requires minimal make-
up water. Another advantage is that very high quality water can be
used and corrosion can be virtually eliminated. Other indirect
benefits of reduction in total water usage are smaller pipelines
for water transport and lower water pumping costs.
Maintaining uniform product flow in a refinery is a desira-
ble goal, but involves rigid control and is quite difficult. The
normal procedure today where in-process inventory is required is to
take a hot product from a given process, cool it and store it
to provide an inventory of intermediate products for further
processing. Before the intermediate product can be further pro-
cessed, it must be reheated. If the use of computers and other
technological advances can reduce the amount of intermediate
storage and consequently the amount of heating and cooling re-
quired, the total cooling water requirements of the refinery could
be reduced.
Thus it can be seen that while the total quantity of petrol-
leum products is increasing the amount of water intake is level-
ing off. In the future, decreases in wastewater effluent quan-
tities through more effective cooling practices are possible.
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-11-
MANUFACTURING PROCESS UTILIZATION
Genera 1 App roach^
To develop an understanding of the overall pollution profile
for the petroleum industry, it is imperative that the parts con-
tributing to the whole be understood. The ideal solution would
involve detailed data on the subprocess mix of the industry, out-
put for each subprocess, and wastewater quantities and characteris-
tics for each subprocess per unit of output. Even if a completely
accurate profile of the present conditions could be developed,
there would still be a number of important questions to be answered,
What was the profile in the past? What will It be in the future?
What are the factors contributing to the changes? How is the
pollution picture affected by refinery size, degree of technology,
sources and characteristics of raw materials, refinery location,
combinations of refinery processes, and sequence or combination
of waste treatment processes? Can total impact of pollution be
measured solely by costs?
An understanding of all these factors for an industry with
such complex processing as petroleum refining would involve a
study so comprehensive that the time required would preclude Its
usefulness as a projection of future conditions and as a guide
for appropriate action. Lack of precise information, particularly
in regard to wastes from specific subprocesses, is one of the
major complications. Nevertheless, some basis must be chosen
that will reflect the best attainable understanding of the pollu-
tion picture for the present and for the specified future period.
The principal bases for the selected approach are: estimates of
waste quantities and characteristics from the most significant
subprocesses; size of refinery; and general level of technology.
Current and Future Subprocess Utilization
For this approach it Is necessary to know which subprocesses
are being used in the Industry and which subprocesses are expected
to be used in the future. Table 1 summarizes the fundamental pro-
cess and subprocess utilization percentages in the U. S. petro-
leum industry for 19&3 an^ 1967, as well as the expected per-
centages for 1972 and 1977. It also includes limited information
about fundamental processes and subprocesses for 1950. The in-
dustry process use is expressed in terms of percent of refineries
using each process or subprocess, with the principal subprocesses
In each fundamental process area listed. There are some discrep-
ancies between the fundamental process total and the sum of the
listed subprocesses, either because all applicable subprocesses
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-12-
are not listed or because a single refinery may use two or more
subprocesses Fn a given fundamental process area. This latte-.r
situation is frequently the result of modernization-expansion
where economic and technological considerations indicate the addi-
tion of a new type of processing unit but not the retirement of
an existing facility.
It must be pointed out again that the percentages given in
Table I are based on the number of refineries using the subpro-
cesses and not on the basis of feed capacity. This difference
Is not very significant when comparing subprocesses under a
fundamental process, but it can be significant when comparing
fundamental processes. For example, in 19&3 catalytic cracking
was utilized In 51 percent of the nation's refineries and poly-
merization was employed in 42 percent. These figures are fairly
close, but the total industry feed capacities of the two processes
were very different; the feed capacity of catalytic cracking was
more than 30 times that of polymerization.
The "0", "T", and "N" notations under the "Technology" heading
in Table 1 refer to whether the subprocess would usually be found
in an "older", "typical", or "newer" refinery. An "older" refin-
ery is one that uses a relatively Inefficient subprocess series.
"Typical" refers to a refinery that employs the subprocesses most
widely used today. A refinery classed as "newer" is one that
makes use of all or most of the more advanced subprocesses. Siome
subprocesses, such as Platforming, are rated as being older, typ-
ical, and newer; these have been used for many years, are promi-
nent today, and still are being included in the newest refineries.
Identification of a subprocess as being older, typical, or newer
was done on the basis of interviews with Industry representatives
(4) and a survey of the literature.
Most of the figures given in Table 1 for the years 1950,
1963, and 1967 are from the annual survey of United States refin-
eries by The OH and Gas Journal (11, 12, 13, 1A, 15). As is the
case throughout this report, data were available on the major re-
fining processes such as the cracking processes, reforming, poly-
merization, alkylation, isomerization, and hydrotreating. Infor-
mation on the number of plants using the other fundamental pro-
cesses and their subprocesses was not nearly as complete, and some
estimates had to be made; these estimates were based on incomplete
surveys of operating refineries and total production figures (I,
16, 17, 18, 19, 20, 21). The close inter-relationship of many
fundamental processes was used here as in many other sections of
this profile to aid In making the most accurate estimate possible.
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-13-
For example, the feed into wax finishing processes comes almost
entirely from dewaxing operations. The estimate of the percent
of plants using wax finishing was thus the same as indicated by
published data for percent of refineries using dewaxing.
Projected Subprocess Mix
The expected subprocess mix for 1972 and 1977 was obtained
by projecting the data from 1963 ar)d 1967 and using the following
assumptions:
1. The number of refineries will decrease at a rate
of 2 percent per year between 1967 and 1977-
2. Most of the decrease in the number of refineries
will be due to the shutdown of small refineries
using only a few fundamental processes.
3. Crude capacity will increase at the rate of 1.5
percent per year between 1967 ar)d 1977.
*». The average unit capacities of subprocesses coming
into greater use will increase.
5. The average unit capacities of subprocesses going
out of use will remain the same.
6. No revolutionary processes will be introduced and
widely adopted between 1967 and 1977.
The first assumption is based on published data showing a
continuing drop in the number of U. S. refineries since 1935
(11, 13, 1*0. The second, fourth, and fifth assumptions are
discussed or indicated by data given in the same sources. The
increase of crude capacity of 1.5 percent per year was based
on past increases of crude capacity (1.2 percent per year from
I960 to 1967) and forecasts of a 3 percent per year increase
in petroleum product demand between now and 1980 (22, 23). The
produce demand figure is reduced by the increasing percentage
of imports (23) and the larger volume of petroleum products ob-
tained from each barrel of crude oil processed. The last assump-
tion is based on the fact that no revolutionary process is pres-
ently foreseen and even if one were discovered tomorrow, it
would take several years of testing before it would come into
even limited use.
Projections of product demand were also used to project the
subprocess mix. For example, increasing demand for low-sulfur
fuels from air pollution considerations will result in increased
use of hydrocracking and hydretreating, because these processes
produce fuels with a low-sulfur content. The demand for grease
is expected to remain fairly constant or decrease slightly: thus
grease manufacturing remains unchanged as to the percent of plants
using it.
-------
Projections of the 1963 and 19&7 data were also modified by
other economic considerations. Dryf ng-and-sweetening of petroleum
products is used mainly to desulfurlze the product. It is being
replaced by hyd retreating because hydrotreating removes a higher
percentage of the sulfur. However, hydrotreating is more expen-
sive, and dry! ng-and-sweetening will remain in use for treat-
ing some products: the volume of products treated will be greatly
reduced, but the percentage of plants using dry! ng-and-sweetening
will remain about the same.
Trends in subprocess changes indicated In the literature
and summarized tn the fundamental process descriptions also in-
fluenced the projections, as did process inter-relationships.
An increase in alkylation creates a demand for isobutane feed,
which could mean more need for isomeri zation . But hydrocracking
Is also a source of isobutane, and since hydrocracking is In-
creasing In use because of its flexibility, it can also be
used to provide isobutane and thus limit the increase in isomer-
ization. The growth of hydrogen manufacture Is also linked t:o
hydrocracking in that reforming rcannot meet the hydrogen demeinds
of isomerization , hydrotreating, and hydrocracking.
anc'
After delineation of the subprocesses , the next step in
preparation of the industry profile was development of a combina-
tion of processes reflecting three levels of technology and three
ranges of refinery size. From each fundamental process listed
in Table 1 subprocesses most representative of older, typical,
and newer processing technology were selected. These subpro-
cesses formed the bases for three flow diagrams (See Figures
1,2, and 3) which present three hypothetical refineries -
one for each stage of technology. These flow diagrams were
developed from consulting and direct experience in the petroleum
industry, from literature review, and from special interviews
with refinery technical personnel.
There are some differences In the fundamental processes com-
prising each of these hypothetical refineries, because some older
fundamental processes are being phased out and some newer ones
are becoming increasingly important. This involves some diver-
gence from the original contract definition of fundamental pro-
cesses as being essential to the manufacturing process, but in
the ever-changing petroleum industry, what was essential in 1950
or 1963 is not necessarily essential in 19&7 nor expected to be
so in 1972 or 1977. Because of the complexity of the industry
and variations in growth patterns, there are few, if any, refin-
eries in the United States that have the exact combination of
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-15-
subprocesses presented In the three flow diagrams. A recent
survey In The Oil and Gas Journal (11) Illustrates the diffi-
culty In determination of a representative refinery. In this
survey of 261 operating refineries In the U. S. in 1967, in-
formation was obtained concerning capacity and extent of use
of the following processes: vacuum distillation, thermal op-
erations (thermal cracking, coking, vlsbreaklng), catalytic
cracking, reforming, hydretreating, alkylation, polymerization,
lube oil production, cake production, and asphalt production.
Only two of the refineries surveyed had all of the processes
listed; 14 lacked one of the processes, 23 lacked two, 30 lacked
three, and 19*t lacked four or more of the processes. Despite
the lack of any significant number of existing refineries with
exactly comparable facilities, the classification and diagramming
of these three hypothetical refineries is a useful step in de-
velopment of a reliable overall estimate of Industry conditions
and trends.
It should be pointed out that the process sequence shown
in Figures 1,2, and 3 have been simplified to the extent that
not all of the possible process streams are shown. The process
streams included in the flow diagrams were restricted to those
necessary to show how an integrated refinery produces its major
products; the actual situation Is much more complex. For example,
most refineries produce two or more grades of finished gasoline,
and these may be blended from six or more separate blending
stocks; yet, for purposes of clarity and simplicity the process
flow diagrams have only one gasoline stream.
The capacities shown for the various processes are the total
refinery capacities of those processes. In practice these may
be the sum of several process unit capacities at different lo-
cations in the refinery rather than the capacity of a single
unit. For example, although hydrotreatlng Is shown only at one
location in the "typical" refinery, there may be several hydro-
treating units at different locations. The process locations
shown, however, do represent the manner In which the most sig-
nificant part of the capacity of a given process is arranged.
The next factor to be considered was refinery size. Table 2
gives a breakdown of the number of refineries by size and tech-
nology. A "small" refinery has been defined as one with a crude
capacity of 35,000 bpsd or less, "medium" a capacity of 35,000 to
100,000 bpsd, and "large" a capacity greater than 100,000 bpsd.
The percentage of refineries in each size range and the crude
capacity ranges were taken from the literature (2*0. It is important
to note that the "large" refineries constitute only 9.8 percent by
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-16-
number but A5.7 percent of the total crude capacity. These large
refineries are also the most integrated ones in terms of the. number
of processes used. The group of small refineries represents 67.1
percent in terms of numbers, but only 19.5 percent of the total
crude capacity.
Classification of existing refineries as representative of
older, typical, and newer technologies was based on the previously-
mentioned OjJ_and_ Gas Journal survey of 1967. Since this survey
included subprocesses as well as fundamental processes it pro-
vides good basic data for such a classification. However, numerous
overlapping and single-purpose situations required considerable
exercise of judgment in assigning specific refineries to one of the
three classifications. The following examples illustrate the
rationale of assignment. A relatively complete refinery that in-
cluded both hydrocracking and isomerization was classified as
"newer". A refinery with Thermofor catalytic cracking and polymer-
ization but with neither alkylation nor hydrotreating was classified
as "older". In many instances, particularly among the smaller re-
fineries, the number of missing processes was so high that meaning-
ful technological classification was not possible, and only 196 of
the 261 refineries were classified. The remaining refineries were
divided between the older and typical technologies with a bias
toward the older, because the hard-to-classify, very small refin-
eries are also the least likely to keep pace with general tech-
nological advance.
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-17-
WASTE QUANTITIES AND CHARACTERISTICS
General Considerations
The next step after developing an understanding of the process-
ing patterns and inter-relationships is to determine the wastewater
quantities and characteristics and present them in a manner that
will enhance Interpretation of the pollution profile. If unit
waste loads could be developed for each sub-process, then the current
profile could be obtained by simply adding the components, and the
future could be ascertained by projecting the types and sizes of
refineries. However, the Information required for such a direct
approach is not available. Much of the available data on refin-
ery wastes (whether from published sources or in the files of
individual refineries) apply to total effluent, or major geo-
graphical sections of a refinery, rather than to specific pro-
cesses. While the industry has been definitely Interested in
pollution abatement for many years, the investigative and corrective
effort has been devoted mainly to effluent treatment and general
Improvement of in-plant operating practices without much quanti-
tative in-plant evaluation. There has been little systematic
effort to determine wastewater flows and characteristics for
specific processes or operating units, and some of the available
Information of this type Is quite old and of limited value for
use at this time.
The wastewater information that is available for specific
refinery subprocesses generally consists only of concentrations
of pollutant materials and seldom includes wastewater volumes
or operating capacity of the subprocess Involved. In part, this
circumstance results from the difficulty involved in obtaining
representative samples. In many refineries, especially older
ones, It Is difficult even to find a place to take a wastewater
sample, and it is even more difficult to find a location for
accurate measurement of the wastewater flow. A further compli-
cation is the frequent occurrence of oil floating on the surface
of the wastewater stream, which also interferes with the attain-
ment of a representative sample.
Another factor restricting the application of a direct sub-
process unit waste load approach Is the frequent practice of
combining specific waste streams discharging from several sub-
processes rather than from specific units. Thus, such streams as
sour waters, caustic washes, etc. In actual practice are generally
not traceable to a specific sub-process, but only to a stripping
tower or treatment unit handling wastes from several subprocesses.
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The size, sequence, and combinations of contributing processes are
so involved that a breakdown by subprocess would be extremely
difficult to achieve.
In light of the above limitations, a rational approach has
been developed. This starts with a qualitative evaluation of the
principal refinery wastewater characteristics and the problems
attributable to specific fundamental processes and waste streams;
then the relatively meager quantitative wastewater information
that is available is applied and apportioned in order to determine
quantitative waste loadings for refinery processes.
PjjscussJ on of J^crtlnent Wa s t ewate r Char act e r i s tjjc s
In view of the difficulty of determining definitive waste load-
ings for all parameters from each unit process, it is possible to
present only limited quantitative Information. However, considerable
knowledge is available that can be used to make meaningful quali-
tative interpretations. Such information is presented in Table 3.
This is a semi-graphic table with major waste-contributing funda-
mental processes shown with 3 X's, moderate contributors 2 X's,
and minor contributors only 1 X. The table is based on pounds
per day of contaminants from each fundamental process in a typi-
cal refinery, with throughput of each fundamental process taken
into consideration.
The quantities and characteristics of the wastewater differ
considerably for different processes. In general, the major
sources of waste contribution are storage tank dralnoffs, crude
desalting and distillation, and the thermal and catalytic cracking
processes, followed by the solvent refining, dewaxlng, and drying
and sweetening. A more detailed description of the sources and
contaminants within the individual processes are presented as
part of the description of fundamental processes in Appendix F.
Two significant general waste streams are the sour waters
(containing sulfides and mereaptans) and the spent caustics.
The sources of sour waters are primarily condensates from various
fractionation units. Caustics originate from caustic washing (of
feedstocks and intermediate and final products) to neutralize
acidity and remove sulfides and me reaptans.
The general type and degree of sophistication of refinery
wastewater treatment processes have been determined principally by
the quantities and characteristics of total effluent, not by the
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-19-
conf tguratlon of refinery equipment or processes. The increasing
stringency of pollution regulations requires consideration of
wastewater treatment in terms of specific pollution problems.
For this reason, a qualitative discussion of problems by individual
parameter will be presented below. Appendix D is an interpretation
of the significant water quality criteria, and these will be re-
lated to petroleum refining problems in the following discussion.
Flow
Based on total water usage, crude oil distillation is the
largest water user mainly because of the large volumes required
by the barometric condensers and desalters. Catalytic Cracking
and Drying-and-Sweetening are the next largest water users. The
extent of water use is significantly affected by the technology
level of the processes employed. In newer plants, drastic re-
ductions in water use are foreseen for Dewaxing, Alkylation, and
Catalytic Cracking, primarily through increased water reuse.
Temperature
Crude desalting, especially the electrostatic process, con-
tributes substantial thermal waste loads, as do distillation and
cracking. The increased use of cooling towers has played an Im-
portant role in the reduction of total thermal load primarily by
reduction In quantities of water discharged and not necessarily
by reduction in effluent temperature. Effluent heat loads can
have significant adverse effects on the receiving waters since
the increased temperature causes decreased oxygen solubility and
greater oxygen utilization, both of which reduce the ability of
the stream to handle waste loads.
pH indicates the hydrogen Ion concentration of a wastewater.
However, the extreme values often observed do not truly reflect
the buffering capacity of a waste or its ultimate effect upon a
receiving water course. Most refinery wastewaters are alkaline,
with the cracking (both thermal and catalytic) and crude desalting
processes as the principal problem sources; some solvent refining
processes also contribute substantial alkalinity. Power house
boiler treatment produces alkaline wastewaters and sludges; hy-
drotreating, which is becoming increasingly important, contri-
butes definite alkaline wastes. Alkylation and Polymerization
utilize acid processes and have severe acidity problems. In
general, petroleum refinery effluents have pH variations, but
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-20-
this Is not a major problem from the standpoint of effluent stan-
dards. Where pH range is outside the normal limits, equalization
of caustic wastes (and sometimes acid wastes) before bleeding into
the sewer system is usually sufficient to maintain pH control.
In general, large volumes of cooling and wash waters dilute out
strong acid or caustic discharges; thus, pH may become a more
significant problem as cooling water volumes decrease.
pH control is also important in regard to refinery waste-
water treatment operations. Very low or very high pH can cause
or worsen emulsif ication of oils already in the sewer. The pH
of the wastewater influent to biological treatment processes,
which are expected to be used to a much greater extent in
the future, is an important consideration for effective treat-
ment.
Oxygen Demand
The measurement of the biological and chemical demand an
effluent will exert on the oxygen resources of a stream is a very
meaningful water quality parameter. COD (chemical oxygen demand)
and BOD (biochemical oxygen demand) are standard analyses used
in this evaluation.
Almost without exception, wastewaters from petroleum refin-
eries exert a major, and sometimes severe, oxygen demand. The
primary sources are soluble hydrocarbons and sul fides. The combina-
tion of small leaks and inadvertent losses that occur almost con-
tinuously throughout a complex refinery can become principal
pollution sources. Crude and product storage and the product
finishing operations are the major contributors of COD and BOD,
mainly because of the many tanks and vessels used, and the number
of times a barrel of oil or product is handled in these operations.
The wastewater discharges from these operations are intermittent.
The cracking and solvent refining processes are the major BOD
contributors on a continuous basis.
Catalytic cracking, crude oil f ractlonatlon, and product:
treating are the major sources of phenolic compounds. Catalytic
cracking produces phenols by the decomposition of mult I -cyclic
aromatics, such as anthracene and phenanthrene. Some solvent: re-
fining processes use phenol as a solvent, and although it is sal-
vaged by recovery processes, losses are inevitable. Phenols, par-
ticularly when chlorinated, cause taste and odor problems in
drinking water.
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Sulfide
Sulfide waste streams generally originate from the crude de-
salting, crude distillation, and cracking processes. Sulfides
herein discussed are considered to include mercaptans also. Sul-
fides interfere with subsequent refinery operations and are removed
by caustic or dSethanolamine scrubbing or appear as sour conden-
sate waters in these Initial processing operations. Hydrotreating
processes which are used to remove sulfides In the feedstocks
naturally produce a rich sulfide waste stream; however, most of the
sulfide is removed as H^S and Is usually recovered or burned with
the resultant S0? going to the atmosphere.
Oil
This is a major pollutant characteristic of refinery waste-
waters. As free oil, it produces oil slicks and iridescence and
coats boats and shorelines if permitted to discharge to the re-
ceiving stream. Stream and effluent discharge standards severely
limit such discharges. Oil-coated solids are particularly trouble-
some since they are usually of neutral specific gravity, and are
not readily removed by conventional gravity-separation techniques.
Oil or oil-coated solids in the receiving stream also may have a
serious detrimental effect on the aquatic life. Oil removal (in
API separators or other facilities) is a necessary pretreatment
step for biological waste treatment.
Oil has limited solubility in water and therefore would be
expected to contribute little to effluent BOD or COD. However,
crude petroleum and its refined products contain a wide range of
soluble hydrocarbons which can ultimately find their way into
waste streams through product washes, etc. These product wash
streams contribute to effluent BOD and COD.
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Quantitattve Evaluation of Waste Loads
Basis o_f Eva 1 uajj on_
In view of the limitations imposed by the scarcity of waste-
water data for specific subprocesses, the quantitative evaluation
is based on apportionment of total refinery effluent data to sup-
plement the incomplete specific subprocess effluent data. As a
preliminary to discussion of this procedure, certain problems in-
volved in the analysis of phenol and sulfide data should be re-
viewed. Determination of the quantities of phenols and sulfides
being discharged from a process Is difficult because the concen-
trations of these substances in the waste stream vary with con-
ditions in the stream. If there is turbulence in the sewer
phenols are extracted by the oil, and when the oil is skimmed
off the phenols go with it. Thus, If the remaining waste is
analyzed for phenols, a low concentration Is measured. The sul-
fide concentration in the waste is affected by turbulence and
changes in temperature and pH; increases in turbulence and temp-
erature and a decrease in pH all act to liberate sulfides from
the waste stream.
Wastewater surveys from only five refineries (3, 25) had
pollutant concentration and wastewater flow data suitable for
determination of waste loadings from individual subprocesses.
Of these refinery surveys, one was very complete, three were
fairly complete, and one was applicable to only a few subpro-
cesses. None of these surveys gave the operating capacities
of the subprocesses discharging the waste; this information
was obtained from other sources (11, 13, 20). There was some
question about several of the waste streams sampled being repre-
sentative of all the waste coming from the particular subpro-
cess in question. In other instances, there was reason to be-
lieve that the samples were collected after the waste stream
had undergone some form of sour water stripping at the processing
uni t.
Because of the limited amount of data available, breakdown
of waste loading on a subprocess basis was considered impractical
and of doubtful validity. Therefore, the pollutant waste loadings
and wastewater quantities are presented on the basis of funda-
mental processes without any further allocation to specific sub-
processes. The original plan was to develop waste quantites and
pollutant loadings for small, medium, and large refineries for
each of the three levels of technology - older, typical, and newer.
However, since the overall data source did not include all size
ranges of refineries in each technology category, the original
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scope of presentation was reduced. The major difficulty was lack
of data for establishing a relationship between refinery size and
waste loadings. Thus, a hypothetical 100,000 bpsd refinery was
selected as the basis for quantitative waste evaluation. This
provides a reasonable evaluation of the effects of degree or level
of technology on wastewater quanties and characteristics.
Based on the data from the five refinery surveys and supple-
mental pollutant concentration data from various published sources
(5, 26, 27, 28, 29, 30), waste loadings and wastewater volumes
per unit of process capacity were estimated for each fundamental
process for which data was available. The division between older,
typical, and newer was a difficult decision. One of the waste
surveys available was definitely from an older refinery, and this
was the major source of data for the older technology. The remain-
ing surveys were from refineries in the typical class with only a
few "newer" processing units in use. The waste loadings from these
newer units in several refineries were used as the basis for esti-
mating waste loadings and wastewater flows in a newer refinery.
Throughout this estimating procedure there was a trend toward re-
ducing waste loads as technology advanced from older to newer. This
trend was substantiated by data available on total refinery effluents
from older, typical, and newer refineries.
Waste Loads by Refinery Technology Level
Table A presents estimates of wastewater volumes and waste
loadings for three of the major waste characteristics present in
refinery effluents - BOD, phenol, and sulfides. These three
characteristics, along with oil, are the major determinants of
treatment requirements. It is realized that, in a refinery,
the amount of oi1 in the wastewater is a major factor, but data
concerning the amount of oil lost to the sewer from specific pro-
cesses are not complete enough to justify inclusion of oil esti-
mates in Table 4. Volumes and quantities are given for most of
the fundamental processes for each of the three technologies. The
processes for which data are severely limited are the ones at the
tail end of integrated refineries; even when waste data was given,
it was not complete in terms of concentration, flow, and process
capacity. Since only a relatively few refineries manufacture
asphalt, wax, and grease, etc., data on these fundamental processes
are severely limited.
The values in Table k were determined by taking the volume or
quantity of waste per unit of process capacity for each technology
and multiplying by the capacity of that process in an older, typical,
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or newer refinery. An estimate of the total refinery effluent as
sampled after an API separator Is also given for each technology
fn Table 4. The estimate of total effluent was made for waste
quantities after the API separator because that is where all re-
fineries sample their plant effluent, and thus all the available
effluent data fs for such a sampling point. Prior to the API
separator the free oil concentration is high, and this oil layer
makes representative sampling difficult. These estimates of
total plant effluent characteristics after the API separator
are more reliable than the estimates of waste characteristics
from each fundamental process because more data were available.
This is so even though each of the refineries used differnet
process series and efficiencies of the API separators vary.
Table 5 presents the same basic information as Table *», ex-
cept that waste quantities and volumes are presented on the basis
of unit throughput Instead of on the basis of crude charge to the
refinery. This Table illustrates which fundamental processes
(like polymerization) are particularly dirty, even though they do
not contribute a large total waste loading in the typical refinery.
Table 6 is a summary of wastewater flow, and BOD, Phenol, and
Sulflde waste loads for the overall effluent from older, typical,
and newer refineries. These data (presented both as gallons or
pounds per barrel of crude throughput, and as gallons or pounds per
day for a 100,000 bpsd refinery) are based on measurement and analy-
sis of the total refinery effluent after the API Separator of var-
ious refineries. This Table shows significant reductions in waste-
water flow and in each of the listed pollutant characteristics from
the older to the typical refinery and further reductions from typical
to newer refinery. In the development of this summary, possible
effects of refinery size on wastewater volumes and waste loadings
were investigated; but no significant trends were detected. A
recent published study of water use in petroleum refineries (9)
supports this finding; this report states in part, "....that the
unit make-up water requirements of the refineries surveyed wesre not
directly affected by size."
Table 6 also includes a summary of wastewater volumes and waste
loadings based on the fundamental process waste load data of Table k.
Comparison of this summary with the corresponding data based
on total refinery effluent reveals some discrepancies. The waste-
water flow based on total effluent is somewhat higher than the sum
of the flows from the individual processes; the difference probably
is a measure of the wastewater flow from the processes for which
data was not available, and is an indication of variations in
cooling water practices.
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The BOD waste load in each case is also higher in the total
effluent summary, particularly for the older and typical techno-
logies. Actually the BOD loading not accounted for by fundamental
processes is even greater than Indicated in this table, because
some BOD is removed in the API Separator. The unaccounted-for
BOD probably comes from the fundamental processes noted on Table 5
as having insufficient data for waste load estimation, and from
leaks, spills, and other non-process sources. The much smaller
discrepancy (approximately 20 percent) for the newer refinery,
where equipment, controls and operating procedures are likely
to be superior, indicates the non-process sources as the major
explanation of the discrepancy.
The summation of sulfides, on the other hand, exceeds the
amount of sulfides present in the effluent for each technology.
There are two reasons for this apparent discrepancy. First, as
previously mentioned, the sulfides concentration will tend to
decrease in the sewer as turbulence and temperature inrease and
the pH decreases. Second, sour water strippers at various pro-
cessing units remove some sulfides before the waterwater gets
to the sewer.
Similarly, the phenol waste loads obtained by summation of
wastes from the fundamental processes exceed the phenol measured
in the plant effluent after the API Separator. This is because
oil extracts phenol, which is then removed with the oil in the API
Separator.
Waste Loads Per Unit of Product
Estimates of the total waste and wastewater quantities per
unit of physical product for each of the three technologies are
given In Table 7 for 14 petroleum products. The estimates were
made by dividing the wastes from each fundamental process on the
basts of the part that the process plays in the production of each
of the 14 products. For example, a unit such as crude oil desalt-
ing or crude oil fractionatlon affects all 14 products. The
wastes from each of these processes were then divided among each
of the products of the basis of average yield of that product from
a unit of crude oil throughput. On a national basis approximately
47 percent of refinery output is gasoline, 23 percent is furnace
oil, 6 percent jet fuel, etc. Thus 47 percent of the wastes from
crude distillation and crude desalting were assigned to gasoline,
23 percent of the wastes were assigned to furnace oil, 6 percent
to jet fuel, etc. For a process such as dewaxing, the waste was
divided only among the three products that result from dewaxing:
60 percent to lubricating oil, 30 percent to wax, and 5 percent
to greases.
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-26-
The division of each fundamental process into product segments
was made using the product mix of refineries on the national level
(I?) and the predicted yields from each fundamental process as
given in the literature (I, 2). The following factors were ex-
cluded in making the divisions, because they were considered to
have either negligible or compensating effects:
1. Product yields vary with the type of crude oil.
2. Different refineries are operated for different
product yields.
3. Product yields vary with the subprocess used.
After a certain percentage of the waste loads and wastewater
volumes from each fundamental process were assigned to a product,
the actual quantity or volume of waste was calculated by multi-
plying the percentage by the waste load in Table A for each
fundamental process and technology. For example, 10 of the funda-
mental processes In an older refinery affect gasoline production.
Gasoline production was ultimately a portion of each process's
output and these percentages had been assigned. The percentage
for each process was multiplied by the wastes from each process
as given in Table k. The resulting values were then totaled and
taken as the total volume of wastewater and waste load resulting
from gasoline production in a 100,000 bpsd older refinery. The
waste loading per unit of gasoline produced was obtained by
dividing the total quantity of each characteristic by the volume
of gasoline produced by the hypothetical refinery, 47,000 bpsd.
This procedure was repeated for each of the 14 products and each
technology to obtain the values presented in Table 7.
These estimates of total waste and wastewater quantities are
not complete, because the wastes from six fundamental processes
are not given in Table k. Nor do values in Table 7 include the
unaccounted-for portion of the wastes as indicated in Table 4.
These omissions must be kept In mind when comparing the wastes per
unit of product. For example, asphalt is shown with low waste pro-
duction per unit of product probably because the wastes from
Blending and Packaging and Deasphalting are not included. The five
other missing processes probably would not change the relative;
position of each product in terms of wastes generated per unit:
of product.
Another thing to consider when comparing the estimates in
Table 7 is the volume of each product. The very low-volume
items, such as greases, generate large amounts of wastewater
and BOD per unit of product mainly because they are low-volume!
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products rather than because the processes are high waste pro-
ducers. Because of their low output, these products account for
only a minor share of the total refinery waste load.
Some products, of course, produce more wastes than others per
unit of product, but is difficult to make fair comparisons on this
basis. In one sense all the products in a refinery other than
gasoline can be considered byproducts of gasoline production.
In that sense the wastes from gasoline production are being pro-
cessed and sold as a product rather than being put into the sewer
as may have been the practice 30 years ago. Each year petroleum
refineries get more and more product volume per unit of crude
processed.
These "byproducts" of gasoline production often contain wastes
from gasoline production that must be removed from the "byproduct",
and this often causes the "byproduct" to have a high waste genera-
tion per unit of product. For example, liquified petroleum gas
(LPG) processing results in a large amount of sulfides being dis-
charged to the sewer or burned. These sulfides come from the hy-
drogen sulfide that is released along with propane, butane, and
other gases during distillation and cracking operations which play
a large role in gasoline production. However, most of the hydro-
gen sulfide does not enter the environment until the gases given
off during distillation and cracking are treated for removal of
the hydrogen sulfide and production of LPG.
Projected Gross Waste Loads
An estimate of the 1963 industry-wide waste loads and waste-
water volumes following the API Separator is given in Table 8,
along with projections of the loads and volumes through 1977. The
1963 estimates for wastewater volume and BOD, phenol, and sulfide
loadings were made using the unit waste loadings for a typical
technology as given in Table 6. These waste loadings per unit
of crude capacity were multiplied by the industry's crude capa-
city In 1963, 10.J»5 x 10° bpsd (13), to obtain the total dally
waste loadings. It was felt that the accuracy of the estimates
for each technology in Table 6 was not good enough to justify deter-
mining the total waste loading by adding the waste loads from each
technology on the basis of the crude capacity of each technology.
Therefore, the unit waste loading of the typical technology was
used. Any error resulting from this simplified approach is re-
duced by the fact that the higher waste loadings from an older
technology and the lower waste loadings from a newer technology
tend to cancel each other.
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Th e projected waste loads and wastewater volumes given in
table 8 were obtained using an annual rate of increase of approx-
imately 3.6 percent for waste loads and an annual increment of
10,000,000 gallons of wastewater volume. This annual Increase
gives 50 percent increase in total industry waste loading be-
tween 1963 and 1977. The 3.6 percent per year figure was ob-
tained by projecting several parameters including crude capacity,
crude throughput, and product value added. Waste load projec-
tions based on crude capacity have the advantage of the avail-
ability of reliable information on crude capacity. This informa-
tion indicates an increase of 17 - 20 percent from 1963 to 1967.
On the other hand, the relationship between waste loads and crude
capacity may change from year to year, as the extent to which
the capacity is utilized changes. Thus, crude oil throughput
would be a more meaningful projection basis than crude capacity.
Extrapolation of 1959 " 1965 records of crude throughput In
U. S. refineries indicated a 38 percent increase between 1963
and 1967.
The third projection basis, product value added, is somewhat
more complicated in the calculation of the product value trend, but
overall is probably the most logical projection basis. The total
waste loads and wastewater volumes for 1963 can be determined with
a good degree of confidence from the unit loadings by fundamental
processes. The projections to 1977 can be made by forecasts or by
extrapolation of past and current product values. Two groups of
statistics are available for determining product value: "value
added by manufacture", which reflects labor, material, packaging
and related costs; and "value of shipments", which includes the
value added, plus costs for raw materials, transportation, etc.
Straight-line extrapolation of 1950 - 196*4 data indicates increase
of k2 and 83 percent from 1963 to 1977 for value of shipments and
value added by manufacture. An alternative product value projection
method is the multiple regression method of the Business and Defense
Administration of the U. S. Department of Commerce, based on Gross
National Product, Gross Private Business Investments, and other
economic components. This produces a projection of 88 percent in-
crease in product value added between 1963 and 1977, using a rather
liberal 6 percent annual increase in GNP.
By the various methods of projection the waste load increase
between 1963 and 1977 could be 17 to 88 percent. A 50 percent
increase was selected as a reasonable compromise between the
crude throughput increase of 38 percent and the BSDA value added
increase of 88 percent. Wastewater volume increase was estima-
ted to be much lower than the waste loading increase because of
significant developments in cooling water practices.
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Seasona1 Was te Product ion Patterns
Seasonal waste production patterns can be established by
variations in output of specific products through the calendar
year. The petroleum refining industry experiences only slight
changes in product mix through the year, and total production
does not change significantly. The most noticeable variation
In product demand Is that of distillate fuel oil. The total
demand for It during the winter months of December and January
is more than twice the demand during June and July. The peak
demand for gasoline occurs during the summer months, and this
demand Is approximately 20 percent higher than the demand during
January and February. However, these fairly large variations
in demand are not reflected in production patterns primarily
because of product inventory practices and the increasing dis-
tillate fuel-gasoline flexibility of the catalytic cracking
processes.
Table 9 gives a monthly breakdown of total crude throughput
and gasoline and distillate fuel oil production for 196*4 and 1965.
These figures show that there is only a 17 percent difference in
distillate fuel oil production between the highest and lowest month,
The maximum variation in gasoline production was about 15 percent.
The volume of total crude throughput is perhaps the best method of
predicting any changes In waste'product I on, and Its maximum varia-
tion Is only 13 percent. On any of these bases, Table 9 Indicates
that there is no appreciable seasonal waste production pattern.
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WASTE REDUCTION PRACTICES
In-PI an t P roce ssing P ra ctIces
A complete evaluation of the effectiveness of in-plant pro-
cessing practices in reducing wastewater pollution requires de-
tailed information on the wastewater flows and pollutant concen-
trations from all types of refinery processing units and storage
facilities. With such information one could determine the pollu-
tional effect of substitution of one alternative subprocess for
another, or of Improvement in general operating and housekeeping
practices. Unfortunately, this kind of information is not avail-
able, nor does there appear to be any systematic effort, even in
the latest installations reflecting the newest technology, to
determine waste loads from specific units.
Despite this lack of specific process wastewater data, there
is information of a more general nature which indicates substan-
tial wastewater pollution reduction through changes in processing
facilities and practices. Hydrocracking and hydretreating are two
processes that generate much lower waste loadings than the pro-
cesses they are replacing. The rapid pace at which such unit;; are
being installed is exerting and will continue to exert a strong
influence on the reduction of waste loadings, particularly su'l-
fides and spent caustics.
However, the greatest potential for waste reduction by Iri-
plant processing changes appears to be In improvement of general
operating and housekeeping practices rather than In changing
processes or subprocesses. For example, substantial reductions
in losses of oil to the sewers could be achieved through im-
provement of current practices in taking samples of charge stocks
and products and in drawing off water from storage tanks. An-
other general indication of significant pollution reduction by
in-plant measures is afforded by the lower pollutant loads per
unit of through put or product for refineries in the newer tech-
nology category as compared to typical or older refineries. Un-
doubtedly some of this reduction results from newer subprocesses,
but much of it also appears to come from better controls, improved
operating and sampling practices, and similar general considera-
tions.
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Waste Treatment Practices
Discussion of Pertinent Waste Treatment Processes
G rav 1ty Sepa rat I on
Gravity separation to remove oil is the first step in the
treatment of refinery wastes. The functioning of gravity-type
separators depends upon the difference in gravity of oil and
water. The gravity-type separator wi11 not separate substances
in solution, nor will it break emulsions. The effectiveness
of a separator depends upon the temperature of the water, the
density and size of the oil globules, and the amounts and char-
acteristics of the suspended matter present in the waterwater.
The "susceptibility to separation" (STS) test is normally
used as a guide to determine what portion of the influent to
a separator is amenable to gravity separation.
The Gravity Separator usually consists of a pre-separator
(grit chamber) and a main separator, usually rectangular in
shape, provided with influent and effluent flow distribution
and stilling devices and with oil skimming and sludge collec-
tion equipment. It is essential that the velocity distri-
bution of the approach flow be as uniform as possible before
reaching the inlet distribution baffle.
Gravity-type separators are used by all refineries to remove
free oil from oi1-containing wastes. The oil skimmed from the
separator is processed to recover the oil, and any sludge which
settles can be dewatered and either incinerated or disposed of
as landfill.
Dissolved AIr Flotation
Dissolved air flotation consists of saturating a portion of
the wastewater feed or a portion of reclrculated effluent from
the flotation unit with air at a pressure of ^0 to 60 psig. The
wastewater or effluent recycle is held at this pressure for 1 - 5
minutes in a retention tank and then released at atmospheric
pressure to the flotation chamber. The sudden reduction In
pressure results in the release of microscopic air bubbles which
attach themselves to oil and suspended particles in the waste-
water in the flotation chamber. This results in agglomerates
which, due to the entrained air, have greatly-Increased vertical
rise rates, of about 0.5 to 1.0 feet/minute. The floated materials
rise to the surface to form a froth layer. Specially designed
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fllght scrapers or other skimming devices continuously remove the
froth. The retention time in the flotation chambers is usually
about 10 - 30 minutes. The effectiveness of dissolved air flo-
tation depends upon the attachment of bubbles to the suspended oil
and other particles which are to be removed from the waste stream.
The attraction between the air bubble and particle Is a result of
the particle surface and bubble-size distrubtion.
Chemical flocculating agents, such as salts of iron and alumi-
num with or without organic polyelectrolytes, are often helpful
in improving the effectiveness of the air flotation process and in
obtaining a high degree of clarification of refinery effluent.
Dissolved air flotation is used by a number of refineries to
treat the effluent from a gravity separator. Dissolved air flo-
tation using flocculating agents is also used to treat oil emul-
sions. The froth skimmed from the flotation tank can be combined
with other sludges (such as those from a gravity separator) for
disposal. The clarified effluent from a flotation unit may re-
ceive further treatment in a biological unit or may be discharged
as final effluent, depending on the BOD content and effluent re-
quirements.
Activated Sludge Process
Activated Sludge Is an aerobic biological treatment process in
which high concentrations of newly-grown and recycled microorgan-
isms are suspended uniformly throughout a holding tank to which raw
wastewaters are added. Oxygen is introduced by mechanical aerator,
diffused air systems, or other means. The organic materials In
the waste are removed from the aqueous phase by the microbiological
growths and stabilized by biochemical synthesis and oxidation
reactions. The basic activated sludge process consists of an aera-
tion tank followed by a sedimentation tank. The flocculent mlcro-
bial growths removed in the sedimentation tank are reycled to the
aeration tank to maintain a high concentration of active micro-
organisms. Although the microorganisms remove almost all of the
organic matter from the waste being treated, much of the converted
organic matter remains in the system in the form of mlcrobial
cells, which have a relatively high rate of oxygen demand and
must be removed from the treated wastewater before discharge.
Thus, final sedimentation and reelrculatlon of biological solids
are important elements in an activated sludge system.
Sludge is wasted on a continuous basis at a relatively low
rate to prevent build-up of excess activated sludge in the aeration
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tank. Shock organic loads usually result In an overloaded system
and poor sludge settling characteristics. Effective performance
of activated sludge facilities requires pretreatment to remove or
substantially reduce oil, sulfide (which causes toxicity to micro-
organisms), and phenol concentrations. The pretreatment units
most frequently used are: gravity separators and air flotation
units to remove oil; and sour water strippers to remove sulfides,
mercaptans, and phenol. The high rate and degree of organic
stabilization possible with activated sludge has already resulted
In some application of this process to the treatment of refinery
wastewaters, and the extent of use is expected to increase.
Trickling Filter
A trickling filter is an aerobic biological treatment pro-
cess with a fixed growth of microorganisms contained in a porous
bed, through which the wastewater is passed. A microbial film
develops on the surface of the bed media and removes organic ma-
terials from the wastewater by adsorption, bioflocculation, and
sedimentation. Oxygen is very important in the trickling filter
system (as in any aerobic biological system) for rapid metabolism
of the removed organic matter. The large surface area of the
filter media permits rapid transfer of oxygen by simple diffusion
from the void spaces into the liquid layer. Treatment rates on
trickling filters are controlled by hydraulic as well as organic
loading rates. Trickling filters with stone media are limited by
economics to depths between 3 feet and 10 feet. Plastic, rather
than rock, media are generally used in filters which have very high
hydraulic and organic loadings, with bed depths approaching kO feet.
Trickling filter units have been used in the petroleum industry
both as complete secondary treatment and as roughing devices to re-
duce the organic load on subsequent activated sludge units. The
trickling filter Is extensively used to remove phenolic compounds,
and has been used to treat sour waters.
The wastewater applied to the filter normally requires pretreat-
ment to remove oil, and to limit concentrations of sulfides, mercaptans
and phenol; oil removal is accomplished by gravity separation and
air flotation, and sulfide and mereaptan removal is accomplished by
stripping.
Aerated Lagoon
An aerated lagoon provides aerated biological treatment by
mixing dilute concentrations of microorganisms with wastewater in
a large, relatively deep basin. Oxygen necessary for aerobic
287-028 O - 68 - 5
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stabilization of organic matter Is supplied by mechanical or dif-
fused aeration units, and by induced surface aeration. The tur-
bulence normally maintained In the basin insures distribution of
oxygen and biological solids throughout the basin.
An aerated lagoon differs from an eciivated sludge unit in
that the effluent from the aerated lagoon is not settled prior
to discharge, and the biological solids are not recirculated.
Because of the low rate of organic removal resulting from the low
concentration of biological solids maintained in the system, aer-
ated lagoon detention time (and basin volume) is greater than fn
an activated sludge system for removal of an equivalent amount of
BOD. An aerated lagoon is capable of removing 55~90 percent of
applied BOD, depending on wastewater temperatures and treatabi1ity.
Oxidation Pond
The oxidation pond Is useful as a biological treatment system
where land is plentiful and cheap. Fundamentally, the oxidation
pond utilizes bacteria to aerobically stabilize the organic wastes
added to the pond. Oxygen for the bacteria is supplied by atmos-
pheric reaeration at the pond surface and from oxygen production
by algae in the pond. The production of oxygen by algae occurs as
a result of synthesis of cellular protoplasm from carbon dioxide
in the presence of sunlight. The organic loading on the oxidation
pond is limited by the lack of mixing, which also limits the
oxygen transfer capacity. In heavily loaded ponds a certain a-
mount of the stabilization will occur anaerobically rather than
aerobically. Temperature plays an important part in the efficiency
of oxidation ponds, especially if the ponds are loaded to near
capacity. Turbidity, colored wastes, and emulsions block part
of the light transmittance and reduce the production of oxygen
by algae. Because organic loadings are low, very little bio-
logical sludge Is produced; what little is produced settles in
the pond.
Oxidation ponds have been used as the only treatment of re-
finery waste and also as a polishing step for the effluent from
physical-chemical or other biological waste treatment processes.
Multi-cellular ponds are used in some instances, especially if
the oxidation pond is used as a basic treatment unit rather than
a polishing unit. The first pond generally functions as an emer-
gency oil skimming pond and also serves to settle out heavy solids.
Pretreatment of wastewater is normally required before it.
can be treated in an oxidation pond. Pretreatment Is carried
out to remove oil, and to limit concentrations of sulfides, mer-
captans and phenol.
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Emulston Breaking
This is used to remove oil from oil-ln-water and water-1 n-
oil emulsions. Oil emulsions may comprise several percent of re-
finery throughput and therefore represent an important economic
consideration. Emulsions result from the intimate contact be-
tween oil, water, and emulsifying agents, or may originate
directly as process byproducts.
Emulsions may be broken by electrical, chemical, or physical
methods (heating, filtration, or centrifugation). In the elec-
trical process, water-in-oil emulsions are passed through an
electrical field to coalesce the water droplets sufficiently to
produce gravity settling of the water phase.
In the chemical process both oil-ln-water and water-in-otl
emulsions can be treated. The process consists of rapidly mixing
coagulating chemicals with the waste, followed by flocculation
and flotation or settling. Acidification alone is also used.
Settling usually results in separation of the aqueous layer.
The recovered oil is skimmed for subsequent reprocessing.
Physical emulsion-breaking methods include heating, centrifu-
gation, and precoat filtration. Emulsion breaking by heating mark-
edly reduces the viscosity of the oil phase, permitting coalescence
and separation of the oil and water phases to take place. Centri-
fugation breaks oil emulsions by separating the oil and water
phases under the influence of centrifugal forces. Stable water-
in-oil emulsions, particularly those stabilized by finely divided
solids, can be broken by continuous precoat filtration. Emul-
sion breaking occurs as a result of rupture of the globules of
the dispersed phase on passing though the interstices of the
filter cake and precoat materials, and as a result of the removal
of the stabilizing solids.
Treatment of Ballast Waters
Ballast water generally requires treatment for the separation
of oil from wastewater. Ballast water oil can be present as free
oil or as emulsified oil. Minimum treatment for ballast water
involves settling the waste in storage facilities and skimming
the oil. The settling tank can also be provided with a steam coil
for heating the tank contents to help break emulsions, and an
air coil to provide agitation.
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Further treatment may consist of providing a coagulation or a
chemically-aided air flotation unit to remove emulsified oil, or
filtration to remove suspended particles and oil. The oil skimmed
from various treatment units is discharged to a slop oil storage
tank for further processing to recover the oil.
Spent Caustic Treatment
Alkaline solutions are used to wash refinery gases and light
products; the spent solutions, generally classified as sulfidic
or phenolic, contain varying quantities of sulfides, sulfates,
phenolates, naphthenates, sulfonates, mercaptides and other or-
ganic and inorganic compounds. These compounds are often removed
before the spent caustic solutions are added to refinery effluent.
Spent caustics usually originate as batch dumps, and the batches
may be combined and equalized before being treated and/or dis-
charged to the general refinery wastewaters.
Spent caustic solutions can be treated by neturalization
with spent acid or flue gas, although some phenolic caustics
are sold untreated for their recoverable phenol value. Neu-
tralization with spent acid is carried to a pH of 5 to insure
maximum liberation of hydrogen sulfide and acid oils.
In the treatment of spent caustic solutions by flue gas,
hydroxides are converted to carbonates. Sulfides, mercaptides,
phenolates, and other basic salts are converted to hydrogen
sulfide, phenols and mercaptans at the low pH conditions caused
by the flue gas stripping. Phenols can be removed and used as
a fuel or can be sold. Hydrogen sulfide and mercaptans are
usually stripped and burned in a heater. Some sulfur is recovered
from stripper gases. The treated solution will contain mixtures
of carbonates, sulfates, sulfites, thiosulfates and some phenolic
compounds. Reaction time of 16 - 2*t hours is required for the
neutralization of caustic solution with flue gas.
Sour Water Treatment
The purpose of the treatment of sour water is to remove sul-
fides (as hydrogen sulfide, ammonium sulfide and polysulfides)
before the waste enters the sewer. The sour water can be treated
by stripping with steam or flue gas, air oxidation to convert
hydrogen sulfide to thiosulfates, or vaporization and incinera-
tion.
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The heated sour water is stripped with steam or flue gas in
a packed or plate-type column. Hydrogen sulfide released from
the wastewater can be recovered as sulfuric acid or sulfur, or may
be burned in a furnace. The bottoms have a low enough sulfide
concentration to permit discharge into the general wastewater
system for biological treatment. If the waste contains ammonia,
it is neutralized with acid before steam stripping. The waste
liquid passes down the stripping column while the stripping gas
passes upward.
Another way of treating sour water is to oxidize by aeration.
Compressed air is injected into the waste followed by sufficient
steam to raise the reaction temperature to at least 190°F. Re-
action pressure of 50-100 psig is required. Oxidation proceeds
rapidly and converts practically all the sulfides to thiosulfates
and about 10% of the thiosulfates to sulfates. Air oxidation,
however, is much less effective than stripping in regard to re-
duction of the oxygen demand of sour waters, since the remaining
thiosulfates can later be oxidized to sulfates by aquatic micro-
organisms.
In treating sour water by stripping and incineration, suffi-
cient care must be taken to prevent an air pollution problem due
to insufficient burning of sulfides removed from sour water. Hy-
drogen sulfide itself is a foul-smelling gas, and any releases
to the atmosphere cause odor problems.
The removal of hydrogen sulfide and ammonia occur at different
pH conditions. The removal of hydrogen sulfide requires a pH in the
acidic range, while ammonia removal occurs in the alkaline range.
The stripping of sour water is normally carried out to remove sul-
fides, and hence the effluent may contain 100 - 2000 ppm of ammonia
depending on the influent ammonia concentration.
Slop Oi1 Treatment
Separator skimmings, which are generally referred to as slop
oil, require treatment before they can be reused, because they contain
an excess of solids and water. Solids and water contents in
excess of about 1 percent generally interfere with processing.
In most cases slop oils are easily treated by heating to 190°F.,
retaining at this temperature for k to 6 hours, and then settling
for 12 to 2k hours. At the end of settling, three definite layers
exist: a top layer of clean oil; a middle layer of secondary
emulsion; and a bottom layer of water containing soluble components,
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suspended solids and oil. In some cases it is advantageous or even
necessary to use acid or specific chemical demulsifiers to break
slop oil emulsions. The water layer resulting from acid and heat
treatment has high BOD and COD and also high pH, and must be treated
before it can be discharged.
Slop oil can also be successfully treated by precoat filtra-
tion. The normal precoat is diatomaceous earth.
Cool ing Towers
Cooling towers are used in many refineries to dissipate heat
from recirculated spent cooling water and thereby reduce water
supply requirements. Cooling towers are not normally considered
to be an effluent treatment device except that total effluent
quantity is reduced by their use. However, cooling towers have
been used to treat refinery effluents biologically where cooling
water supply is short and it is economically advantageous to
reclaim sufficient water to meet the cooling water makeup needs
of the refinery.
In some cases, selected process waste streams are discharged
to the cooling water system. In these cases the cooling towers
act as a biological treatment system, in which oxygen is trans-
ferred by the air which cools the wastewater circulating through
the cooling tower, and the excess biological growth is continu-
ously discharged into the cooling tower blowdown. Some biological
growths become attached to the cooling tower itself, but the
quantity of adhered growth appears small. Normally the waste
receives sufficient dilution in the recirculating water to
prevent excessive growths, which can plug heat exchangers and
pipelines.
Cooling towers handling restricted loadings of specific wastes
are capable of 99 percent phenol removal,75-90 percent COD
removal, and 90 percent BOD removal. These percent removals in-
clude the effects of windage losses and volatilization, as well
as biological effects. With proper control, heat transfer capa-
city is not appreciably affected by increased biological growths
formed through the use of wastewater in cooling towers, although
operating effort may be increased. One of the benefits of using
wastes as partial makeup is that the oxygen demand of the waste-
water reduces the concentration of dissolved oxygen in the cooling
water and thus tends to reduce corrosion of steel and cast iron.
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.'•Yetreatment of waste may be required before it can be used
as makeup water for cooling purposes. Oil-bearing waste must pass
through a gravity separator to remove oil, and other process wastes
may require treatment in a stripper to remove sulfides and mercaptans.
Disposal of Steam Generation Wastes
Steam is required for many refinery processes and usually is
generated on site; the current trend is to waste heat boilers at
processing units rather than major dependence on centralized boiler
houses. Water for steam generation must be exceptionally pure to
avoid excessive scaling and corrosion of boiler tubes. Consequently,
boiler feed water is treated mainly for removal of solids and alka-
linity; this produces an alkaline sludge. Other sources of waste
are the continuous boiler blowdown required to control the dissolved
solids concentration in the boiler water, and intermittent blowdown
of sludge which accumulates in the boiler.
The boiler blowdown water, relatively high in solids and alka-
linity, is almost always discharged directly to the refinery sewer
system. The feedwater treatment sludge is also discharged to the
sewer, although in some cases other disposal methods are used. Some
refineries lagoon the sludge, and others use it to neutralize acid
wastes or for coagulant purposes. In general the boiler blowdown
constitutes only a small part of the overall refinery wastewater,
but the solids and alkalinity may reduce the effectiveness of oil
removal in the separators.
Sludge Disposal
Sludges from refinery operations and waste treatment processes
can be handled in a number of ways. Historically, the method first
used was lagoon storage of sludges in vacant areas of the refinery,
with ultimate disposal of the combustible materials by open burning.
As land becomes scarcer, it becomes more important to concentrate
the sludges prior to disposal.
Methods of sludge concentration vary with the type of sludge.
Oily sludges such as storage tank and gravity separator bottoms can
be concentrated by precoat vacuum filtration or centrifugation. It
is possible to recover a certain amount of oil from the sludge by
these methods.
Sludges from boiler treatment blowdown and chemical or biologi-
cal treatment of refinery effluents can be thickened and subsequently
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dewatered by vacuum filtration or centrifugation. Ultimate disposal
of dewatered sludge can be by incineration, landfill or ocean disposal.
Acid and caustic sludges from refinery processes generally require
neutralization before dewatering and ultimate disposal.
Effectiveness of Waste Removal
A summary of the effectiveness of waste treatment processes in
removing the principal oil refinery pollutants is presented in Table 10.
For convenience of discussion, the treatment methods have been divided
into 5 generic types: Physical, Chemical. Biological, Tertiary, and
In-plant. Included as a parameter In the table is the Most Probable
Process Influent (MPPl), which indicates the kind and/or extent of
prior treatment required for efficient utilization of the specific
process under consideration.
In addition to removal efficiencies for specific pollutants,
the summary includes qualitative information on the effect of the
various treatment processes on three important general pollutional
characteristics: pH, toxicity, and temperature. The removal effi-
ciency ranges and the qualitative effects are based on available
data from actual refinery Installations; however, considerable ex-
ercise of engineering judgment based on general wastewater treatment
experience was required to supplement the relatively meager data in
several areas.
Physical Treatment
Included in this type of treatment are gravity separators (API
and earthen basins), evaporation, and air flotation without chemicals.
Gravity separators are designed primarily for removal of floatable
oil and settleable solids, and they achieve removals of 50-99 per-
cent of separable oil and 10-85 percent of suspended solids. Con-
current with these major functions, gravity separators also remove
BOD, COD, and at times phenol; these removals can be substantial
(up to 40-50 percent) depending on the characteristics of the waste.
Phenols are oil-soluble and thus could be extracted from combined
wastewaters and removed along with the oil by the separators.
The oil removal efficiency of gravity separators is greatly
influenced by the quality of in-plant wastewater management, as
well as by the design and operation of the separators themselves.
Large amounts of separable oil in the wastewater system can be
removed at high efficiency by the separators, but the effluent
quality (which varies from 20 to 150 mg/L of oil) would be much
better if effective in-plant controls had been used to minimize
the amount of oil getting to the sewers in the first place. In
addition, oil in the form of emulsions, and especially when coated
on fine solids, is difficult to remove with gravity separators.
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It should be noted that the BOD and COD removals shown in
Table 10 for gravity separators do not include the BOD and COD
attributable to the readily-separable oil which is removed. In-
clusion of these would indicate unrealistically high organic re-
movals that would be inconsistent with the quantities of contam-
inants actually dispersed in the wastewater.
The treatment of refinery effluents by evaporation is severely
limited by geographical location, climate, and land availability.
It is obviously a very attractive method where stringent effluent
regulations are in force and the geographical, climatic and land
conditions are favorable. At least one refinery in the continental
U. S. utilizes this method. Pollutant removals are essentially com-
plete. However, in order for this method to function, even where
geographically feasible, extensive water reuse must be practiced.
Air flotation without chemicals, like evaporation, is not
widely used in refinery waste treatment at the present tine. In
general the performance is comparable to gravity separators, but
with somewhat better oil removal. In addition to those waste para-
meters where definite efficiency ranges are presented, an undetermined
amount of sulfides will be oxidized by the oxygen dissolved from the
applied air. Some stripping of ammonia may also occur if the pH is
alkaline.
Chemical Treatment
Chemical methods of treating refinery effluents include chemical
coagulation-sedimentation, and air flotation with chemical addition.
Removal efficiencies of coagulation-sedimentation and chemically
assisted air flotation are judged to be essentially the same. The
chemical methods are more effective than gravity separators, par-
ticularly in regard to removal of emulsified oil; in addition, slight-
ly more BOD (beside that associated with separable oil) will probably
be removed by chemical coagulation then by air flotation.
As was the case with simple air flotation, it is likely that
In chemical air flotation a portion of the dissolved sulfide will
be oxidized and some ammonia stripped off by action of the entrained
and released air.
^ ' o 1 °g ical Treatment
Types of biological treatment used for refinery wastewaters in-
clude activated sludge, trickling filter, aerated lagoons and oxida-
tion ponds. All of these treatment methods require prior removal of
oil. A general comparison of the relative merits of the various bio-
logical methods and their applicability to different wastewater situ-
ations is available from the previous section of this report, Discus-
sion of Pertinent Waste Treatment Processes.
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Table 10 indicates that Activated Sludge is the most effective
process for removal of organic materials, with removal efficiencies
of 70-95 percent for BOD, 30-70 percent for COD, and 65-99 percent
for phenols and cyanides. Suspended solids removal efficiencies
are good, except with aerated lagoons. Since these lagoons are
seldom followed by sedimentation facilities, it is entirely possible
that the concentration of solids leaving the lagoons would be higher
than that of the influent wastewaters.
In any biological treatment system there is a unique and im-
portant relationship between the ammonia and BOD concentrations
in the wastewaters. The organisms which develop to oxidize the
organic material will utilize approximately 5 pounds of ammonia ni-
trogen and 1 pound of phosphorus for every 100 pounds of BOD removed.
These nutrients probably will not have to be added in a petroleum
refinery treatment system, because there is almost always enough
ammonia (from corrosion inhibitors) and phosphorus (from cooling
tower blowdown) present in the refinery wastewater.
Acidity/alkalinity will be altered by the buffering action which
accompanies the development of biological growths. This buffering is
due primarily to the carbon dioxide formed during biological oxidation,
which produces bicarbonates in the wastewater.
Tertiary Treatment
The treatment of secondary effluents in petroleum refineries has
been limited to activated carbon and ozonation. The primary purpose
of tertiary treatment is to remove refractory organics and small quan-
tities of phenols which pass through biological treatment processes.
Activated carbon and ozonation are very effective in removing these
materials. Chlorination cannot be used for these purposes because
of the formation of chlorophenols, which have highly objectionable
taste and odor characteristics.
In-Plant Treatment
Major treatment processes which are applicable to individual
process effluents or groups of effluents within a refinery are
stripping of sour waters, neutralization and oxidation of spent cau-
stics, ballast water separation, slop oil recovery, and temperature
control. The particular areas of application of these processes
have been covered in the previous Discussion of Pertinent Waste
Treatment Processes.
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Sour water strippers are designed primarily for the removal
of sulfides and can be expected to achieve 85~99 percent removal.
If acid is not required to enhance sulfide stripping, ammonia will
also be stripped with the percentage varying widely with stripping
temperature and pH. If acid is added to the wastewater, essentially
none of the ammonia will be removed. Thus, ammonia removals in sour
water strippers vary from 0 to 95 percent. Depending upon such
conditions as wastewater pH, temperature, and contaminant partial
pressure, phenols and cyanides can also be stripped with removal
as high as 30 percent. COD and BOD are reduced because of the
stripping out of phenol and oxidizable sulfur compounds.
The oxidation phase of spent caustic treatment is aimed at the
sulfide content of these wastes and achieves 85~99 percent sulfide
removal. In this process, sulfides are oxidized primarily to thio-
sulfates although in some variations there is partial oxidation of
the sulfur compounds to sulfate. Oxidation processes are not applied
to phenolic caustics because phenols inhibit oxidation. It should be
noted that those processes which oxidize the sulfide only to thiosul-
fate satisfy only part of the oxygen demand of the sulfur, as thiosul-
fate can be oxidized biologically to sulfate. Neutralization of spent
caustics is applied to both phenolic and sulfidic caustic streams;
the sulfidic caustics are also steam stripped, after neutralization,
to remove the sulfides. When phenolic spent caustics are neutralized,
crude acid oils or "crude carbolates" are sprung and thus removed
from the wastewater. The major part of the phenols will appear in
the oil fraction, but a significant part may remain in the wastewater
as phenolates.
Ballast Water Treatment, Slop Oil Recovery, and Temperature con-
trol are included in the list of In-Plant Processes, primarily for
discussion purposes rather than evaluation as part of the overall
refinery wastewater treatment system. Ballast water normally is
not discharged to the refinery sewer system because the intermittent
high-volume discharges, with potentially extremely high oil concen-
trations, would upset the refinery wastewater treatment facilities.
Thus ballast waters are treated separately, with heating, settling,
and at times filtration as the major steps. The recovered oil, which
is considerable, is generally sent to the slop oil system.
Temperature control is becoming increasingly important as stream
standards become more stringent. Reducing the heat load to the river
without changing manufacturing processes is possible only by increased
water reuse through cooling towers, spray ponds, or dry finned-tube
air coolers. The heat load to the water course is reduced by the
amount transferred to the atmosphere. It is conceivable that the
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temperature of the effluent in certain situations might be raised
even though the total heat load is reduced. A number of refineries
have made use of cooling towers as biological treatment processes,
especially for phenol-bearing wastes.
Reuse or recovery of refinery process sludges has been dis-
cussed in a previous section. Process sludges and sludges produced
in biological treatment of wastewaters are generally dewatered and
burned or disposed of as landfill. The burning of sludges must be
carefully controlled to prevent air pollution.
Rate of Adoption of Waste Treatment Processes
The estimated percentage of oil refineries using specific waste
treatment processes is presented in Table 11. This table is primarily
the result of judgment based on a relatively small sample of present
refineries and expected trends. There is a dearth of usable infor-
mation on the present waste treatment "mix" used by refineries.
The most reliable data are for gravity separators; all refineries
use some sort of gravity separation for removal of separable oil.
Values were estimated for 1950, 19&3 and 1967, and projected for
1972 and 1977.
The values shown for 1977 reflect the assumption of more com-
prehensive and more stringent water and air pollution regulations.
In particular, it is assumed that 90 to 100 percent of the plants
will be required to provide some type of biological secondary treat-
ment. Processes such as incineration of spent caustics and flaring of
stripped sulfides should be drastically reduced by 1977 as the result
of air pollution requirements. The percentage of plants utilizing
ballast water treatment was assumed to be equal to those receiving
their supplies by tanker.
Sequence and Intel—relationships of Waste Treatment
The sequence of waste treatment required for refinery wastes due
to various technological considerations is shown in Table 12. The
treatment requirements are divided into 1) primary; 2) secondary;
3) tertiary; 4) pre-treatment; 5) disposal of sludges and slop oil
emulsion; and 6) miscellaneous treatment. Whenever feasible, wastes
should be separated at the source to avoid contamination of large
volumes of uncontaminated waste streams such as cooling water.
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In order to provide efficient treatment to the wastes originating
within a refinery, it is very important that segregation of concentrated
waste streams be considered. Segregation of waste streams frequently
simplifies waste treating problems. Thus, treatment of highly polluted
waste streams at the source can prevent gross pollution of large vol-
umes of relatively clean wastewater. Such treatment is often a
more economical solution of a problem than would be possible if wastes
are discharged directly to the refinery sewers. Treatment at the source
is also helpful in recovering by-products from the wastes which other-
wise could not be economically recovered when the wastes are combined.
Treatment at the source is useful not only for recovery of by-products
but also for preparation of the wastes for subsequent treatment. For
example, sour water and spent caustics which are treated biologically
must be pretreated to remove sulfides and mercaptans, which are toxic
to microorganisms present in the biological treament units. Segrega-
tion of relatively clean wastewater, such as cooling water, is helpful
in reducing the total quantity of wastes to be treated, since cooling
waters constitute such a large percentage of wastewater flow.
The wastes that normally receive secondary treatment are the
oily wastes, sour water, and spent caustic. These wastes can be
treated in one of several types of secondary treatment units. Occa-
sionally, a combination of biological treatment units, rather than
a single type of unit, is used in the petroleum industry. Trickling
filters have been used to level out the organic load before the wastes
are treated by activated sludge. Aerated lagoons and oxidation ponds
in series are also used to treat the wastes, and cooling towers are
sometimes used as biological treatment units for specific process wastes.
The effluent from secondary treatment units can be further treated to
remove organic matter, taste-and-odor producing substances, and dissolved
inorganic substances. Treatment by oxidation with ozone is particularly
useful in removing phenols from petroleum wastewaters. This is important
when the effluent from petroleum refineries is discharged to natural
bodies of water used as a source of water supply. Ion exchange can be
used to remove inorganic substances from treated wastewater, but it is
unlikely that such a high quality treatment will be required for refinery
wastes. In the treatment of wastes, sludge and slop oil emulsions are
produced and require treatment. The treatment required for sludge and
slop oil emulsion is shown in Table 12. The solids resulting from these
treatment processes are disposed of by either landfill or incineration.
There are several waste streams which do not require very extensive
treatment. Cooling waters, which in general are relatively clean, can
either be discharged directly to the receiving waters or (if they con-
tain oil) treated in a gravity separator before discharge. Spent cata-
lysts are not normally discharged to the sewer. They can either be re-
generated for reuse, or disposed of as landfill. Spent catalysts like
aluminum chloride and phosphoric acid must be neutralized before being
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used as landfill. Acid sludges can be treated to recover sulfuric
acid or can be disposed of by incineration. Waste streams such as
spent caustic or acid sludges can be concentrated and incinerated.
Ballast waters are not normally discharged to oil sewers because of
the large quantity of such wastewater. Ballast water can be treated
in gravity separators to remove free oil, or by chemical flocculation
if it contains oil emulsions. If further treatment with general
wastewaters is indicated flow equalization is required.
There are several factors which may affect the treatment effi-
ciency of different processes. Oil wastes should not be mixed
with process wastes containing chemicals which tend to emulsify
the oil and reduce the efficiency of gravity separators. Large
amounts of oil tend to coat the microbial surface in a trickling
filter, thus reducing the transfer of organic matter. In activated
sludge, the oil causes the sludge to float in the sedimentation
tank and to be lost to the effluent. As mentioned earlier, high
concentrations of sulfides must be reduced in sour waters as they
are toxic to the microorganisms present in the biological treat-
ment units. In the stripping of sour water, pH is important in
the removal of sulfides and ammonia. Stripping with flue gas causes
the pH of wastewater to be In the acidic range, and ammonia may not
be removed. In steam stripping considerable ammonia will be re-
moved because the pH is not lowered by this treatment. The cost of
secondary treatment will vary considerably depending upon the units
used in secondary treatment. Activated sludge facilities are less
expensive to construct but the operating costs will be high; on the
other hand, a trickling filter for most refinery wastewater appli-
cations will probably be higher in capita! cost but lower in oper-
ating costs. Pond treatment Is economical only when sufficient
land is available at low cost, but the operating cost will be very
low compared to activated sludge or trickling filter. Treatment of
wastes in cooling towers can reduce the cost of makeup water.
Discharge of Refinery Wastewater to Municipal Sewers
Available data indicates that only about 1-2 percent of the pro-
cess wastewater from U. S. oil refineries is discharged to municipal
sewers. The major reason is that almost all sewer regulations in-
clude a prohibition of discharge of oil and inflammable and explosive
materials. Even the more permissive proposed regulations for dis-
charge of essentially untreated industrial waste to municipal sewers
require that no straight oils, tars, greases, petroleum products or
concentrated emulsions enter the system. These materials are gener-
ally rejected because of problems both in the sewer and In the treat-
ment plant. Oil materials tend to cling to the walls of the sewer,
thus adversely effecting hydraulic properties and becoming a fire or
explosive hazard. In the treatment plant, large amounts of oi1 in
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the primary settling tanks will overload the skimming facilities and
tend to keep solids in suspension due to the formation of emulsions.
Large amounts of oi) entering activated sludge or trickling filter
units can interfere with biological action and oxygen transfer. High
concentration of sulfldes and mereaptans can be toxic to biological
treatment. Phenols also cause trouble by formation of undesirable
chlorophenols In the subsequent disinfection by chlorine. Although
these problems are serious, they are not insurmountable, and oil re-
finery waste and municipal sewage can be treated together If it is
first realized that pretreatment of the refinery wastewater is
necessary.
Cooling and condensing waters generally are not segregated
from process waters and hence the wastewaters from both sources
would be handled together. In those few instances where cooling and
condensing waters are segregated, they are usually either discharged
directly to a waterway or reused by recycling through cooling towers.
There Is no information available which indicates that refineries
discharge segregated cooling or condensing waters directly to muni-
cipal sewers.
A philosophy of waste treatment which has been receiving in-
creased attention Is the conveyance of municipal wastes to industrial
wastewater treatment plants, which may be serving either an individual
plant or a group of industries. The municipal sewage often provides
needed nutrient materials as well as economic and tax benefits. As
far as refinery wastes are concerned, certain pretreatment would be
required prior to entry into any treatment plant. These include
floatable oil separation (API Separation) and at times spent caustic
neutralization and sour water stripping.
By-Product Utilization
The concept of byproduct utilization as applied to petroleum
refining is limited to those materials which, if recovered, would
accrue some economic benefit but not necessarily enough to cover
the cost of recovery.
Based on this definition, the major byproduct is sulfur, which
is recovered from sour waters and from the hydro-treat ing process.
In 1966, the value of sulfur recovered was estimated at $40,000,000.
This value Is likely to increase greatly In the near future, primarily
because of the increased demand for low-sulfur fuels brought on by
more stringent urban air pollution controls.
A number of other refining process wastes have been recovered
or reused, although no meaningful cost data can be provided be-
cause of the highly volatile nature of the market for such products,
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variatlons in refinery accounting practices relative to credit for
reused materials, and similar reasons. The recovered materials
include:
I. Recovery of sulfuric acid from sludges produced
in the acid treatment of oils. Hydrolysis of
the sludge produces a dilute (30-60%) black acid
of rather limited utility.
2. Reuse of spent alkylation acid in the treatment
of oils and waxes, with subsequent regeneration
in captive or outside acid plants.
3. Sale of high-phenol waste caustics from treat-
ment of catalytically-cracked naphthas.
*». Use of sprung phenols as refinery fuels. These
materials come from acid springing of spent
caustics from cracked naphtha treatment.
5. Use of various waste acids In slop oil treat-
ment.
6. Recovery of aluminum chloride from hydrocarbon
sludges, for use as a coagulant.
7. Recovery of acid oils by reaction of waste caus-
tics with acids.
8. Use of boiler feedwater treatment sludge in the
neutralization of wastewater.
9. Reuse of treated wastewater to supplement normal
refinery water supply.
10. Recovery of ammonia and hydrogen sulflde from
sour water stripping for use as raw materials
In the manufacture of fertilizer grade ammonium
sulfate.
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WASTE TREATMENT COSTS
1966 Replacement Value and Operating Costs
A comprehensive report on waste treatment costs in the petrol-
eum refining industry in 1959 indicated that, on the basis of 183
refineries reporting (out of a possible 313), replacement and operat-
ing costs for waste treatment processes totalled $156,000,000 and
$30,000,000 respectively. These costs were calculated by extrapa-
lating to account for 100 percent of the crude capacity at that time.
In 1959» planned additions to waste treatment facilities for 13^
refineries totalled $29,000,000.
The data from this 1959 report were used as the basis for cal-
culation of replacement value and operating costs for 1966. The
factors used to update the data were assumption of a 30 percent in-
crease in construction and operating costs, and extrapolation of the
value of the 1959 planned additions for 13^ refineries to cover the
1966 total of 279 refineries. In this manner the 1966 wastewater
facilities replacement value was estimated to be $275,000,000 and the
related annual operating costs $55,000,000.
Capital and Annual Costs of Various Treatment Processes
Wastewater flows and principal pollutant loadings for small,
medium, and large refineries of older typical and newer technologies
are summarized in Table 13. Capital and annual costs for the specific
waste treatment processes required to handle these wastes adequately
on an end-of-pipe basis are presented in Tables !*», 15, and 16. The
capital costs are based on estimates of 1967 construction costs,
including an allowance of 15 percent for contingencies; they do
not include design or other engineering fees. The annual costs
include operating labor, maintenance, utilities, and chemicals
costs but no fixed charges for depreciation, interest, taxes, etc.
The end-of-pipe treatment costs of Tables 1^, 15, and 16 were
prorated among the individual fundamental processes. This alloca-
tion of treatment costs is considered the most reliable and most
detailed breakdown that could be justified by available waste and
processing data and by current and reasonably expected future
industry practice. Costs based on separate waste treatment plants
for specific processes or subprocesses would not be realistic, be-
cause there are compelling technical and economic reasons for com-
bined treatment in most cases. Spent caustic, sour water, and at
times separable oil are the only wastewater streams for which
treatment on an individual process unit basis can be justified.
The first step in the cost allocation is prorating the waste-
water flow and BOD loadings. Table 17 gives the percentages of
287-028 O - 63 - 6
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overaH refinery flow and BOD contributed by each of the major
fundamental processes. These figures were calculated from the
wastewater flows and loadings of Table 4, discussed earlier.
Particular note should be made of the "unaccounted" entry at the
bottom of the table, from which Ft is obvious that the BOD in the
total wastewater of older and typical refineries cannot be adequately
accounted for by a summation of the Individual process effluents.
This circumstance makes the allocation procedure less than completely
satisfactory, but it also indicates that direct evaluation of waste
treatment costs on a specific process basis (instead of end-of-pipe
treatment) would be virtually impossible.
The desirable final step in cost allocation would be to spread
the costs of each separate waste treatment process over each of the
fundamental manufacturing process for small, medium, and large re-
fineries in the older, typical, and newer technology categories;
this would require more than 100 separate tables. To overcome this
formidable obstacle and still obtain a reasonable estimate of waste
treatment costs, three end-of-the-pipe wastewater treatment trains
were developed to represent low, intermediate, and high degrees of
treatment.
The composition of these treatment trains is as follows:
Low - API Separator and Slop Oil Treatment.
Intermediate- API Separator, Slop Oil Treatment, Aerated
Lagoon, and Sour Water Stripping.
High - API Separator, Slop Oil Treatment, Sour
Water Stripping, Activated Sludge Treatment,
Sludge Thickening and Vacuum Filtration, and
Sludge Incineration.
The flow and BOO allocations of Table 17 and the treatment pro-
cess cost figures of Table 15 (for a typical refinery) were the
principal bases for calculation of the treatment cost allocations
presented in Table 18. The cost allocations for the treatment
trains involving Slop Oil and Sour Water Treatment included con-
sideration (see Table 19) of portions of these treatment processes
attributed to the various fundamental processes.
The most significant feature of the final treatment cost alloca-
tions of Table 16 is that about 50 to 70 percent of the capital and
annual costs is allocated to the crude oil fractionation and catalytic
cracking processes.
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Effect of In-Plant Waste Reduction Practices
Although detailed cost Information is not available on cost
justification of in-pi ant process modifications, an indication of
the approximate cost savings is afforded by the estimated effect
of a reduction in organic and hydraulic loading upon capital costs
of wastewater treatment facilities for a 100,000 bpsd refinery, as
presented tn Figure 4. The high-degree waste treatment train upon
which this analysis is based includes an API separator, activated
sludge system (aeration basin and secondary clarification), and
sludge thickening, vacuum filtration, and incineration.
Upon inspection of Figure k It can be seen that a 50 percent
reduction In BOD (flow remaining constant) would result in a 15
percent reduction in costs. Similarly, a 50 percent reduction in
flow (with BOD constant) would result in a 20 percent cost reduc-
tion. If both BOD and Flow are reduced by 50 percent, treatment
costs would be reduced by 32 percent. An important factor in the
relatively shallow rate of decrease is the insensitivlty of in-
cineration costs to waste load reduction in this size range.
Incineration costs are relatively constant below five (5) tons/day;
thus the reduction tn BOD load in a 100,000 bpsd refinery has
little effect on reducing incinerator costs.
-------
-------
-------
-------
Table 1
Estimated Percentage of Petroleum Refineries
Using Various Fundamental Manufacturing Processes
and Alternative Subprocesses
Crude Oi1 Desalting
1. Chemical Desalting
2. Electrostatic Desalting
Crude D i sti1lat ion
1. Atmospheric Fractionator
2. Vacuum Fractionator
3. Vacuum Flasher
Thermal Cracking
1. Thermal Cracking
2. Delayed Coking
3. Visbreaking
4. Fluid Coking
Catalytic Cracking
1. Fluid Catalytic Cracking
2. Thermofor Catalytic
Cracki ng
3. Houdriflow
Hydrocracking
1. Isomax
2. Unicracking
3- H-G Hydrocracking
4. H-Oil
Reforming
1. Platforming
2. Catalytic Reforming -
Engelhard
3. Powerforming
4. Ultraforming
-950
100
100
59
25
0
1963
100
5
95
100
100
60
48
28
12
13
2
51
39
13
3
2
0-3
62
37
5
i
6
196?
100
2
97
100
100
6k
45
18
14
16
2
56
45
12
3
8
ii
2
0.8
0.4
67
40
9
2
6
1972
100
0
100
100
100
70
40
8
16
18
4
60
50
10
2
25
11
8
3
l
74
44
11
3
7
1977 Technology
100
0
100
100
100
75
35
2
19
22
6
65
60
6
0
34
15
12
3
1
79
47
12
3
8
0
T,N
0,T,N
0,T,N
0,T,N
0
T,N
T,N
T,N
T,N
0
0
N
N
N
N
0,T,N
0,T
T,N
T,N
-------
Table 1 (Cont. )
Estimated Percentage of Petroleum Refineries
Using Various Fundamental Manufacturing Processes
and Alternative Subprocesses
1950 1963 1967 1972 1977 Technology
G. Polymerization 25 42 33 26 7
1. Bulk Acid Polymerization T,N
2. Sol id Phosphoric Acid
Condensation T
3. Sulfuric Acid Polymerization 0
4. Thermal Polymerization 1 0.4 0
H. Alkylation 10 38 kl $k 62
1. Sulfuric Acid Alkylation 22 26 32 38 T,N
2. HF Alkylation l6 21 22 25 0,T,N
3. DIP Alkylation N
k. Thermal Alkylation 0
I. Isomerization 5 7 10 15
1. Isomerate 1 1.5 3 6 N
2. Liquid-Phase Isomerization 2 3 h 5 N
3. Butamer 1 1 2 2 N
4. Penex 0.7 1 1 2 N
J. Solvent Refining 25 29 JO 32
1. Furfural Refining 11+ 15 l6 16 0,T,N
2. Duo-Sol 23 3 3 T,N
3. Phenol Extraction 10 10 11 11 0,T,N
k. Udex 3 5 8 8 T,N
K. Dewaxing 11 11 11 11
1. Solvent Dewaxing(MEK) 8899 0,T,N
2. Propane Dewaxing 2222 0,T
3. Pressing and Sweating 11000
-------
Table 1 (Cont.)
L. Hydrotreating
1. Un if in ing
2. Hydrofining
3- Trickle Hydrodesulfur-
izat ion
4. Ultrafining
M. Deasphalting
1. Propane Deasphalting and
Fract ionat ion
2. Solvent Decarbonizing
N. Drying and Sweetening
1. Copper Sweetening
2. Doctor Sweetening
3. Merox
4. Girbotol
0. Wax Finishing
1. Wax Fractionation
2. Wax Manufacturing, MIBX
3- Hydrotreating
P. Grease Manufacture
Q.. Lube Oil Finishing
1. Perculation Filtration
2. Continuous Contact
Fi1trat ion
3. Hydrotreating
R. Hydrogen Manufacture
1. Hydrogen Partial Oxidation
2. Hydrogen, Steam Reforming
Total No. of Refineries
346
Petroleum Refineries
Manufacturing Processes
Subprocesses
1963
47
22
3
0.3
3
20
15
4
80
11
10
1
12
19
11
6
2
2
1
1
293
196?
56
23
3
2
5
23
18
5
80
11
9
l
l
12
19
7
7
5
8
3
5
261
1972
70
30
5
4
8
25
20
5
80
11
6
1
4
10
20
5
7
8
25
10
15
236
1977
80
35
8
5
10
27
21
6
80
11
5
l
5
10
20
2
7
11
34
12
22
211
Technology
T,N
T,N
T,N
T,N
O.T.N
T,N
0,T
0
N
O.T.N
0,T
0,T
N
0,T,N
0,T
0,T
N
N
N
-------
Table 2
Classification of U.S. Petroleum Refineries
by Size and Degree of Technology
Technology
Older
Typical
Newer
Smal 1
Up to 35,000
bpsd
31.2
32.5
3.4
Percent of Total
Med i urn Large
35-100,000 Moo, ooo
bpsd
bpsd
4.4
17.4
1.3
0.4
7.0
2.4
Total
36.0
56.9
7.1
Total
(based on
No. of Refineries)
67.1
23.1
9.8
100.0
Total
(based on
Crude Capacity
19.6
34.7
45.7
100.0
-------
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-------
Table 6
Summary of Principal Waste Loads and Wastewater Volumes
Total Refinery Effluent after API Separator
per Barrel of Crude Oil Throughput
Type of
Technology
Older
Typical
Newer
Flow
gal/bbl
avg. range
250 170-374
100 80-155
50 20-60
Waste
BOO
Ibs/bbl
avg. ran
.4o .31-
.10 .08-
.05 .02-
Loads from
Phenol
Ibs/bbl
2s. avg. range
. 45 . 030 . 028- . 033
.16 .0] .009-. 013
.06 .005 .001 -.006
100,000 bpsd Refinery
Sulfide
Ibs/bbl
avg. range
.01 .008-.
. 003 . 0028-
.003 .0015-
013
.008
.003
Based on Total Refinery Effluent after API Separator
Type of
Techno! ogy
Older
Typical
Newer
Type of
Technol ogy
Older
Typical
Newer
Flow
mgd
25.0
10.0
5.0
Waste
Based on
Flow
mgd
23. 10
9-93
4.45
BOD
Ibs/day
40,000
10,000
5,000
Loads from
Spec if ic
BOD
Ibs/day
12,526
5,414
4,166
Phenol
Ibs/day
3,000
1 ,000
500
100.000 bpsd Refinery
Su 1 f i de
Ibs/day
1,000
300
300
Process Unit Waste Loads1
Phenol
Ibi/day
3,504
1,652
848
Sulfide
Ibs/day
2,206
625
683
Summarized from Table 4
-------
-------
Table 8
Projections of Total U. S. Petroleum Refinery
Gross Waste Loads and Wastewater Volumes
to 1977
Year
1963
1968
1969
1970
1971
1972
1977
Flow
cjal /day
l .04
1.09
1.10"
1.11
1.12
1.13
1.18
X
X
X
X
X
X
X
1C9
109
109
109
109
109
109
BOD
Ibs/day
1 . 04 x 1 0s
1.23
1.26
1.30
1.3*
1.38
1.56
X
X
X
X
X
X
10s
10s
106
10s
10s
10s
Phenol
1 bs/day
1.04 x 105
1.23
1.26
1.30
1.34
1.38
1.56
x
X
X
X
X
X
105
105
105
105
105
105
Sulf ide
Ibs/day
3-14
3.70
3.82
3-93
4.04
4.15
4.71
x 104
x 104
x 104
x 104
x 104
x 104
x I04
-------
Table 9
Monthly Variation of Total Crude Throughput and Gasoline and Distillate
Fuel Oil Production1
January
February
March
Apri 1
May
June
July
August
September
October
November
December
1965
January
February
March
Apri 1
May
June
July
August
September
October
November
December
Total Crude Throughput
Cm
275,585
257,221
268, U73
255,555
268 , 273
270 , 258
285,771+
282,273
268,107
271+, 601
263,295
281 ,236
282,328
256,222
271+, 888
161,080
27M93
273,932
292,0514.
291 ,914.6
271^,390
280,51+0
278,608
292,1+72
Gasol ine
thousands of barrels)
114-0,586
IJ], 1+01+
138,527
132,911
138,996
138,975
11+7,552
114.7,610
114-0,521
1 14.14- , 92l+
139,65>+
1^5,785
11+ 8 1+
132^772
114.2,029
135,685
lii-0,097
1^,2114-
150,981
152,775
11+2,908
H4.1+, 897
1 10+, 977
15U,029
Disti 1 late
Fuel Oil
67,1+1+3
62,812
61,681
57,525
60,775
61 ,092
61+ , 181+
61,936
59,31+7
59,552
58,88!
66,768
66,765
60,930
62,188
58,5^
61,1+53
58,692
65A97
66,370
62 , 7ii-l+
65,652
66,112
70 , 1 2i+
1 Annual Statistical Bulletin, Department of Statistics American Petroleum
Institute, Apri1, 1966.
287-028 O - 68 - 7
-------
£o
-------
Table 11
Degree of Adoption of Various
Wastewater Treatment Processes
Estimated Percentage of Refineries Employing Process
Processes and Subprocesses
API Separators
Earthen Basin Separators
Evaporation
Air Flotation
Neutral i zat ion
(Total Wastewater)
Chemical Coagulation and
Precipitation
Activated Sludge
Aerated Lagoons
Tr ickl ing Fi 1 ters
Oxidation Ponds
Activated Carbon
Ozonat ion
Ballast Water Treatment-Phys.
Ballast Water Treatment-Chem.
Slop Oil-Vacuum Filtration
Slop 0 i 1 -Centr i fugat ion
Slop Oi 1 -Separat ion
1950
1+0
60
0-1
0-1
0-1
1-5
0
0
1-2
10
0
0
9
i
0
0
100
1965
50
50
0-1
10
0-1
1-5
5
5
7
25
0.5
l
9
1
5
2
93
1967
60
i+o
1
15
0-1
5-10
10
10
10
25
0.5
1
8
2
7
3
90
1972
70
30
1-2
18
0-1
10-15
1+0
25
10
25
3
3
5
5
12
10
80
1977
80
20
2-5
20
0-1
10-15
55
30
10
20
5
5
5
5
15
15
70
-------
Table 11 (cont'd.)
Degree of Adoption of Various
Wastewater Treatment Processes
Estimated Percentage of Refineries Employing Process
Processes and Subprocesses
Sour Water-Steam Stripping )
-Flue Gas Strippers)
-Natural Gas )
Sour Water-Air Oxidation
Sour Water-Vaporization
Sour Water-Incineration1
Neutralization of Spent Caustics
Flue Gas
Spent Acid (including
springing and stripping)
Oxidati on
Inc inerat ion
1950
60
0
1
35-to
20
15
0
25
1963
70
3
1-2
IK)
30
25
3
to
1967
85
3-5
1
50
35
30
5
50
1972
90
7
0
30
20
25
5
20
197'
90
10
0
20
20
20
5
15
Incineration includes flaring, boiler furnaces, and separate
incinerators used only in conjunction with stripping and vapor-
izat ion.
-------
3 c
4J QJ
— E
-------
Table 1J
Pollutions! Loads from Refineries
of Various Technologies and Sizes
Technology
Older
Typi cal
Newer
S i ze
Smal 1
Med i urn
Large
Small
Medium
Large
Small
Med i urn
Large
Throughput
(bpsd)
30,000
75,000
150,000
30,000
75,000
150,000
30,000
75,000
150,000
Flow
(mgd)
7-5
18.7
37.5
3.0
7-5
15.0
1.5
3.8
7.5
BOD
(Ibs/day)
12,000
30,000
60,000
3,000
7,500
15,000
1,500
3,250
7,500
Phenol
(Ibs/day)
900
2,250
^,500
300
750
1,500
300
750
1,500
Sulf ide
( 1 bs/day)
300
750
1 , 500
90
225
ii50
90
225
450
-------
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-------
Table 17
Percent of Wastewater Flow and BOD Loading
from Fundamental Refinery Processes
Fundamental Process
Crude Oi 1 Storage
Crude Oi 1 Desal t ing
Crude Oil Fract ionat ion
Thermal Cracking
Catalytic Cracking
Hydrocracking
Reforming
Pol ymer izat ion
Al kylat ion
Solvent Refining
Dewaxing
Hydrotreat ing
Drying and Sweetening
Sub Total
Unaccounted
01<
Flow
1.6
0.8
4o.o
5.3
17.0
-
0.6
1.6
1.4
0.2
3-6
0.004
20.0
92.1
7.9
Jer
BOD
0.25
0.50
5-0
0.05
7-75
-
nil
0.01
0.005
-
5.20
0.05
12.50
31.31
68.7
Jyp
Flow
4.o
2.0
50.0
0.3
15.0
-
1.2
1.4
3-6
0.5
0.9
0.4
20.0
99-3
0.7
ical
BOD
1.0
2.0
0.2
0.15
5-0
-
nil
O.OJ
0.06
-
20.0
0.7
25.0
54.14
44.9
Newer
Fl ow
8.0
4.0
20.0
o.4
5.0
1.4
2.8
-
2.4
1.0
1.6
6.4
36.0
89.0
1 1.0
BOD
2.0
4.0
0.4
0.2
10.0
-
nil
-
0.12
-
20.0
1.6
45.0
83-5
16.5
-------
Table 18
Treatment Cost Allocations to
Fundamental Refinery Processes1
Fundamental Process
Crude Oi1 Storage
Crude Oi1 Desalting
Crude Oil Fractionation
Thermal Cracking
Catalytic Cracking
Hydrocracking
Reforming
Polymer izat ion
Alkylat ion
Solvent Refining
Dewaxing
Hydrotreat ing
Drying and Sweetening
Unaccounted
Degree of Treatment
% of Total Cost
Low2
Capital
1.9
7.0
50.1
5-3
IT. 6
2.6
0.6
0.7
1.7
OA
oA
0.2
9-6
1.9
Annual
2.7
tv.6
50.0
3-5
16.6
1.7
0.8
0.9
2A
OA
0.6
0.3
13-3
2.2
1 ntermediate3
Capital
1.6
3A
1+1.2
6.2
19-7
^.7
0.5
0.6
1-5
0.2
OA
5A
11 A
3.2
Annual
2.5
2.8
^5.0
3-8
IT. 8
2.8
0.8
0.9
2.3
0.3
0.6
3-3
A. 9
2.2
High4
Cap! tal
2A
2.5
3^.2
2.6
1UA
1.9
0.6
0.7
1.8
0.3
5-5
2.5
17.9
12. T
Annual
2.7
2-0
35A
1.6
13-5
1.0
0.6
0.9
2.2
0.3
5.7
1.6
19.6
12.6
Total (% ) 100.0 100.0 100.0 100.0 100.0 100.0
Total (Dollars) 219,000 53,000 W-5,000 72,500 1,126,000 18T.OOO
1 Typical 100,000 bpsd refinery.
2 API Sep., Slop Oil Treatment.
3 API Sep., Aer. Lagoon, Slop Oil Treatment, Sour Water Strip.
4 API Sep., Act. Sludge,Thick., Vac. Filt., Incin., Slop Oil Treatment, Sour Water
Strip.
-------
Table 19
Estimated Percent of Sour Waters and
Slop Oil from Fundamental
Processes of Typical 100,000 bpsd Refinery
Fundamental Process
Crude 0 i1 Storage
Crude Oi1 Desalting
Crude Oil Fractionation
Thermal Cracking
Catalytic Cracking
Hydrocracking
Reforming
Pol ymer izat ion
Al kylat ion
Solvent Refining
Dewaxing
Hydrotreat ing
Drying and Sweetening
four Waters
Negligible
Negli gible
25
10
25
10
1
15
10
Slop Oil
Negl igible
10
50
10
20
5
T
-------
APPENDIX B
-------
-------
EFFECT OF IN PLANT WASTE LOAD REDUCTION
ON CAPITAL COST FOR HIGH DEGREE
OF TREATMENT FOR TYPICAL
100,000 BPSD PETROLEUM REFINERY
100
Ul
UJ
(T
UJ
-------
PROCESS
WATER
UNREFINED
CRUDE
IOZHJ!
CRUDE DESALTING
CELECTROSTATIC DESALTING)
ELECTRICAL
POWER
r
ALTERNATE
•XH/
HEATER EMULSIFIER
FIGURE 5
DESALTED
CRUDE
EFFLUENT
WATER
HYDROCARBON PROCESSING 1 9<:
-------
CRUDE FRACTIONATION
(CRUDE DISTILLATION,THREE STAGES")
STAllLltER
OAS
STAIILIZCD !
G1SOLINE
CRUDE
PETROLEUM
ATMOSPHERIC
FRACTION »TOR
OtSALTtR
GAS OIL
KERCSINE
mi
DIESEL
DIESEL
VACUUM LU«E
FRACTIONATOR
TO VACUUM
SYSTEM
1
\
FIGURE 6
VACUUM
FLASHER
TO VACUUM
SYSTEM
LIGHT LUiE
NEC LUH
••i
HVY LU8E
PROPANE DFASPHALTER FEED
Prepared for F.W.P.C A
HYDROCARBON PROCESSING 1960
287-028 O - 68 - 8
-------
THERMAL CRACKING
(DELAYED COKING)
Combination
Froctionator
Gas
Gasoline
Gas Oi
Furnace
Coke
Drums
AA/VV
FIGURE 7
HYDROCARBON PROCESSING 1966
-------
THERMAL CRACKING
(VISBREAKING)
FRACTIONATOR
TOPPED CRUDE S.P. VIStR.
CHANGE FURNACE
GAS TO
RECOVERY UNIT
^GASOLINE
^FURNACE OIL
FUEL OIL
FIGURE 8
Prepared for F.W.P.C.A.
HYDROCARBON PROCESSING 1966
-------
CATALYTIC CRACKING
(FLUID CATALYTIC CRACKING)
Pressure
Reducing
Orifice
Chombtf
Gas and Gasoline to
Gas Concentration Plant
Main Column
Light Cycle Got CM _
Heovy Cycle Gos Oil
T *"
I Heovy Recycle Charge
^n
doftfud Slurry
Slurry
ROM Oil
Slurry Charge
Raw Oil
Chora*
FIGURE 9
Prepared for F.W.P.C.A
HYDROCARBON PROCESSING 1Q66
-------
HYDROCRACKING
(ISOMAX)
Recycle Feed
J»l or Di«iel Fuel
FIGURE 10
Prepared for F.W.P.C A.
HYDROCARBON PROCESSING 1966
-------
POLYMERIZATION
(BULK ACID POLYMERIZATION)
C3 or
C3-C4
Feed
Settler
I
Reactor
Steom
Heater
Acid /
Cooler \
Pump
N Reaction Mix
/ Cooler
LPG
Recovery
Polymer
Gasoline
FIGURE I
Prepared for F.W.P.C.A.
HYDROCARBON PROCESSING 1966
-------
ALKYLATION
(CASCADE SULFURIC ACID ALKYLATION)
CKUDC t RCFOMMCK
IUTANES
—.—•— ALTERNATE FOR C4 ALKYLATION
- — — _ —— TURBINE EXH4UST STEAM
FIGURE 12
Prepared for F.W.P.C.A.
HYDROCARBON PROCESSING 1966
-------
1SOMERIZATION
(1 SOME RATE)
Naturaljsomers
Ptntont Or
Hexane Fraction
>^&s
•'•Ui \ dV^MB^^B^^H
^^r-
i^
A
No
Pa
It o -Paraffin Fraction
Isomer
Splitter
_ Recycle Hydrogen
rmal
raff in
Mat
Hyc
ft
Compressor
ilFeactor
rV
5 — '
Heater ^r?
Liquid Recycle
rf
*•
Recycle Ope
le-Up
rogen
> ^ Fuel Gas
^StabHiztr
Gas
Liquid
~i~a»w, l|
, Synthetic
Single Pass
FIGURE 13
Prepared for F.W.P.C.A.
HYDROCARBON PROCESSING 1966
-------
SOLVENT REFINING
(FURFURAL REFINING)
— *i fettling Drum
" o* Pressure
tj *| I Refined Qij
Flosh Tower
*~~ Frfurol From
_St
-------
SOLVENT REFINING
(UDEX)
EXTRACTOR
CLAY TOWER
W*TtR > MtVCIIT ITM.I
MATER WASH TOW
FIGURE 15
Prepared for F.W.P.C.A.
HYDROCARBON PROCESSING 1966
-------
DEWAKING
(SOLVENT DEWAXING-MEK)
Legend
— Oil
— Solvent
i. Vopor
Stcom
strjp.«r
r^__ — ___ -__ ___ *- From Sot»ent Sforoge
Wax-Free
Oil
FIGURE 16
Prepared for F.W.P.C.A.
HYDROCARBON PROCESSING 1966
-------
HYDROTREATING
(UNIFINING)
To Gas
r
| Cot Croclie'
FIGURE 17
Prepared for F.W.P.C.A.
HYDROCARBON PROCESSING 1966
-------
DE ASPHALTING
(PROPANE DEASPHALTING AND FRACTION ATI ON)
CONDENSERS ]^
COMPRESSOR
DEASPHALTINS
TOWER
FUNMACC
JET CONDENSER
AND TRAP
._.
T
• 'WATER
SEWCR
^1
STRIPPERS
k. .^
STEAM
OE ASPHALTED
OIL
REOUCtO CHUM
STEAM
ASPHALT
FIGURE I 8
Prepared for F.W.P.C.A.
HYDROCARBON PROCESSING 1966
-------
DRYING AND SWEETENING
(COPPER SWEETENING)
FIGURE 19
Prepared for F.W.P.C.A.
HYDROCARBON PROCESSING 1966
-------
DRYING AND SWEETENING
(GIRBOTOL)
Purified Cos
Impure
Cos
Lean Solution
Absorber
Acid Gas
Cooler
Steam
Rich Solution
FIGURE 20
Reoctivator Reboiler
Prepared for F.W.P.C.A.
HYDROCARBON PROCESSING 1966
-------
WAX FINISHING
(_WAX FRACTIONATION)
Woij
Conctntrot* and
Solvtnt Mixture
Soft Wai to
Slorofl*
Wnx to
Storage
FIGURE 2
Prepared for F.W.P.C.A.
HYDROCARBON PROCESSING 1966
-------
GREASE MANUFACTURE
(GREASE MANUFACTURING)
FIGURE 22
Prepared for F.W.P.C.A.
HYDROCARBON PROCESSING 1966
287-028 o - 68 - 9
-------
Oil Charge
Condenser
Decanter
To Rerun
LUBE OIL FINISHING
(PERCOLATION FILTRATION)
Mckt-Up
Clean
Mophtha
rVcolation
Filter
Spent Naphtha
Regenerated
Moke-Up Clay clqV Elevator
Surge
Tanks
Regenerated Clay
! Belt
Clay
Bed
Finished
Oil
,1 Additional Filters)
U§e~d~cTay~B~e7f ~
Used Clay
Elevator
FIGURE 23
Prepared for F.W.P.C.A.
HYDROCARBON PROCESSING 1966
-------
HYDROGEN MANUFACTURE
(HYDROGEN, STEAM REFORMING)
Steom
Reformer
COg Absorber
"I^ To St'om
— Boiler
FIGURE 24
Prepared for F.W.P.C.A.
HYDROCARBON PROCESSING
-------
-------
APPENDIX. C
-------
-------
GLOSSARY
Ae rob i c
Aquatic Life
Aromatics
Ballast Water
Biochemical Oxygen
Demand
By-Product
Catalyst
Cetane
Chemical Oxygen
Demand
APPENDIX C
GLOSSARY AND ABBREVIATIONS
In the presence of oxygen.
- All living forms in natural waters, including
plants, fish, shellfish, and lower forms of
animal 1ife.
Hydrocarbon compounds involving a 6-carbon,
benzene ring structure.
- Water used as ballast by oil tankers.
Oxygen used by bacteria in consuming a waste
substance.
- Material which, if recovered, would accrue some
economic benefit but not necessarily enough to
cover the cost of recovery.
- A substance which can change the rate of a chemical
reaction but which is not itself involved in the
reaction.
- A straight chain, 16-carbon hydrocarbon, used as
a standard for performance of diesel fuels.
Oxygen consumed through chemical oxidation of a
waste.
Direct-Fired Heater - A heater in which heat is supplied by combustion,
as distinguished from a heat exchanger where heat
is supplied by a hot liquid or gas.
-------
Emu Is ion
End-of-Pipe Treat-
ment
Fractionator
Gasoline
Grease
Hydrocarbon
Hydrogenation
I somer
A liquid system in which one liquid is finely
dispersed in another liquid in such a manner
that the two will not separate through the
action of gravity alone.
Treatment of overall refinery wastes, as disting-
uished from treatment at individual processing
units.
A generally cylindrical tower in which a mixture
of liquid components is vaporized and the compon-
ents separated by carefully varying the tempera-
ture and sometimes pressure along the length of
the tower.
A mixture of hydrocarbon compounds with a boil-
ing range between 100 and lj-00°F.
A solid or semi-solid composition made up of
animal fats, alkali, water, oil and various
add it ives.
A compound consisting of carbon and hydrogen.
The contacting of hydrocarbons with hydrogen
gas at controlled temperatures and pressures for
the purpose of obtaining saturated hydrocarbons
and/or removing various impurities such as sul-
fur and nitrogen.
A chemical compound that has the same number,
and kinds of atoms as another compound, but a
different structural arrangement of the atoms.
-------
Mercaptan - An organic compound containing hydrogen,
carbon, and sulfur (RSH).
Microcrystal1ine
Wax - A non-crystalline solid hydrocarbon with a
melting point of about 106 to 195°F. Also
known as petrolatum.
Motor Octane Number - An octane rating determined by testing the gaso-
line at an engine speed of 90 rpro ^nd thus a
better indicator of high-speed performance.
Naphtha - A petroleum fraction including parts of the
boiling range of gasoline and kerosine, from
which solvents are obtained.
Octane - The numerical rating of a gasoline's resistance
to engine knock.
Olefins - Unsaturated straight-chain hydrocarbon compounds
seldom present in crude oil, but frequently in
cracking processes.
Overhead Accumulator- A tank in which the condensed vapors from the
tops of the fractionators, steam strippers or
stabilizers are collected.
Paraffin Wax - A crystalline solid hydrocarbon with a melting
point of 105 to 155°F.
Petroleum - A complex liquid mixture of hydrocarbons and
small quantities of nitrogen, sulfur, and oxygen.
Raffinate - The oil-rich solution formed during the solvent
refining extraction step.
-------
Raw
Reduced Crude
Research Octane
Number
Sour
Spent Caustic
Stabilizer
Stripper
Sweet
Topping Plant
Waste Loading
Untreated or unprocessed.
The thick, dark, high-boiling residue remain-
ing after crude oil has undergone atmospheric
and/or vacuum fractionation.
An octane rating determined by testing the
gasoline at an engine speed of 60 rpm.
Denotes the presence of sulfur compounds such
as sulfides and mercaptans that cause bad odors.
Aqueous solution of sodium hydroxide that has
been used to remove sulfides, mercaptans, and
organic acids from petroleum fractions.
A type of fractionator used ro remove dissolved
gaseous hydrocarbons from liquid hydrocarbon
products.
A unit in which certain components are removed
from a liquid hydrocarbon mixture by passing a
gas, usually steam, through the mixture.
Denotes the absence of odor-causing sulfur com-
pounds such as sulfides and mercaptans.
A refinery whose processing is largely confined
to oil into raw products by simple atmospheric
disti1lat ion.
Total amount of a pollutant substance, generally
expressed as pounds per day.
-------
ABBREVIATIONS
API - American Petroleum Institute
bbl - barrel
BOD - Biochemical Oxygen Demand
bpcd - barrels per calendar day
bpsd - barrels per stream day (operating day)
BS and W - Bottom Sediment and Water
COD - Chemical Oxygen Demand
Ib/day - pounds per day
LPG - liquefied petroleum gas
mgd - million gallons per day
mg/L - milligrams per liter (parts per million)
psia - pounds per square inch, absolute
psig - pounds per square inch, gauge (above 1U.7 psia)
RSH - mercaptan
scf - standard cubic feet of gas at 60°F. and II).. 7 psia
SS - suspended solids
VSS - volatile suspended solids
-------
-------
APPENDIX D
-------
-------
APPENDIX D
INTERPRETATION OF WATER QUALITY PARAMETERS
GENERAL
The quality of a stream is generally defined in terms of its
physical, chemical, biological, and bacteriological characteristics.
The degree of degradation of quality is interpreted as the extent
to which the existing conditions depart from specified desirable
levels. The specified levels have been established to provide safe-
guards against nuisances or harm to plant and animal life. Water
quality is usually expressed in terms of parameters that are mea-
surable by standard analyses. An interpretation and discussion
of the important water quality parameters follows.
ACIDITY
Acidity is not a specific polluting substance but rather a
combined effect of several substances and conditions. It may be
defined as the power of a water to neutralize hydroxyl ions, and
it is expressed in terms of the calcium carbonate equivalent of the
hydroxyl ions neutralized. Acidity is usually caused by the pres-
ence of free carbon dioxide, sulfuric and other mineral acids,
weakly-dissociated acids, such as phosphoric, that affect the buf-
fering action, and salts of strong acids and weak bases.
No limit has been recommended for acidity in drinking water
standards.
ALKALINITY
Like acidity, alkalinity is not a direct or specific pollu-
tant, but it is rather a measure of the effect of a combination
of substances and conditions in water. By definition it is a
measure of the power of a solution to neutralize hydrogen ions
and it is expressed in terms of an equivalent of amount of calcium
carbonate. Alkalinity is caused by the presence of carbonates,
bicarbonates, hydroxides, and to a lesser extent by borates, sili-
cates, phosphates, and organic substances.
No limits for alkalinity have been recommended in the drink-
ing water standards, but a concentration of 20 mg/L has been rec-
ommended for unaerated water to inhibit corrosion.
-------
D-2
BACTERIA
For many years the best available indicator of the sanitary
quality of water has been an estimate of the density of coliform
bacteria. The results of this test are not specific in that many
bacteria common to the soil are included. Therefore many health
agencies have not been satisfied with criteria based on this test.
More recently tests have been developed for the determination of
fecal coliforms and fecal streptococci which are attributable to
human or animal sources. However, sufficient information has not
been developed to apply the results of these tests. Until criteria
are developed which are more specific, many states have retained
the widely used coliform test.
At best, this method measures indirectly the quantitative
presence of bacteriological contaminants. While only certain
types of coliform bacteria are associated with pathogens, an
excessive amount of coliform organisms would indicate a poten-
tially undesirable level of pathogenic bacteria.
The Tennessee Valley Authority has suggested the adoption
of criteria based on fecal coliform organisms to provide a more
direct method of limiting disease-producing organisms.
COLOR
Color in water may be of natural, mineral, or vegetable
origin, caused by metallic salts, humus material, peat, tannins,
algae, weeds, and protoza. Waters may also be colored by solu-
ble inorganic or organic wastes from many industries including
mining, refining, pulp and paper, chemicals, and others. The term
"apparent color" is used for colors that include an effect from
suspended matter. The unit of color considered as a standard
is the color produced by the platinum-cobalt method, and results
are conventionally expressed as units of color.
The USPHS drinking water standards limit the color of accep-
table water to 15 units.
FOAM
Foam or froth in watercourses is unsightly. Foams are gen-
erally created by agitation or aeration of surface-active agents,
such as detergents. Detergents are refractory compounds in that
they are decomposed very slowly by biological processes. Deter-
gents inhibit oxygen transfer in biological wastewater treatment
processes, increase turbidity, interfere with coagulation, and
sometimes produce taste or odor. Detergents are not toxic to fish
in the concentrations normally found in watercourses; however, a
maximum permissible concentration of alkylbenzene sulfonate of
0.5 mg/L has been established. This limit appears to have been
based on aesthetic rather than toxicological considerations.
-------
D-3
NUTRIENTS
The presence of even trace amounts of nutrients such as
phosphates, ammonia and nitrates in surface waters encourage
the growth of plants such as algae in water. Where these sub-
stances are present in greater amounts, they often trigger abun-
dant growths of such plants. Large growths of algae are unsightly,
often interfere with swimming, boating and water skiing, impart
tastes and odors to water, and when they die in the early fall
they add a substantial organic load to the stream often causing
depletion of dissolved oxygen. Significant sources of nutrients
are sewage effluents, certain industrial wastes, and land runoff
particularly from farm lands.
For drinking water the U. S. Public Health Service has estab-
lished the maximum limit for nitrate at 10 mg/L as N. No limits
have been established for ammonia or phosphates. In fact ammonia
is frequently used along with chlorine for the disinfection of
public water supplies.
Of the three nutrients only ammonia may exert a toxic effect
on aquatic life. This effect is usually more pronounced at
higher pH values. Precise limitations must be determined from
a toxicological study for a particular stream and given species
of fish. For the control of algae the suggested limitation for
elemental phosphorus has been set by a number of researches at
O.OJ mg/L.
OIL
Oily substances can be deleterious in domestic water supplies.
The potential effects are:
1) Production of taste and odors,
2) Presence of turbidity, film, or iridescence,
3) Increased difficulty of water treatment, with pos-
sible hazard to the health of consumers.
Free oil and emulsions may act on the gills of fish to interfere
with respiration, and they may coat and destroy algae and other
plankton thereby removing a source of fish food. Settleable oily
substances may coat the bottom, destroy benthal organisms, and
interfere with spawning areas. Soluble and emulsified materials
ingested by fish can taint the flavor of the flesh. Organic ma-
terials may deoxygenate the waters sufficiently to kill fish.
Water-soluble components may exert a direct toxic action on fish
or fish food. Oil film can interfere with the natural processes
of stream reaeration and photosynthesis if thick films of free oil
are present.
287-028 O - 68 - 10
-------
If the depth of contamination of the water surface \s assumed
to be 1 inch, the following table indicates the significance of
oil contamination.
Gal Ions of Oi1
Appearance Concentration per sq. mile of surface
mg/L
No visible sign of oil 6 Less than 25
Barely visible under good light 15 25
SiIvery Sheen 30 50
Traces of color 60 100
Bright bands of color 120 200
Dull Color lj-00 666
Dark Color 800 1,532
These data indicate that oil pollution should not be visible
if the amount of contamination does not exceed 10 mg/L, but when
it increases to about 20 mg/L, visible identification may be expec-
ted. The effluent criteria for oil should probably be less than
20 mg/L in the effluent, with the river water quality being about
1 to 2 mg/L.
Oil Analyses - Analyses for oily materials are performed
according to the American Petroleum Institute (API) method,
which involves the extraction of oily substances from a
sample of wastewater with carbon tetrachloride followed by
an infra-red spectro-photometric analysis. A standard cali-
bration curve is developed for SAE 20 motor oil, and all
values are expressed as mg/L of oil. Substances which are
extracted by the carbon tetrachloride and have a molecular
weight higher than motor oil will yield low concentration
as oil. Conversely, those compounds of lower molecular
weight will yield higher concentrations as oil.
Oil STS Analyses - The API method for oil STS (Susceptibility
to Separation)Ts a procedure for determining the feasibility
of removing suspended oil from effluent wastewater by means
of gravity-differential separation. This analysis involves
the determination of oily substances in a sample which has been
allowed to settle for JO minutes. The units are expressed as
mg/L of oil and indicates the amount of oil which cannot be
removed by gravity separation.
-------
D-5
OXYGEN DEMAND
For most water uses, an ample amount of dissolved oxygen is
desirable. However, water with zero dissolved oxygen would be
desirable as a means of inhibiting corrosion, especially in indus-
trial cooling waters. Low concentration of dissolved oxyen may
contribute to an unfavorable environment for fish and other aquatic
life, and the absence of dissolved oxygen may give rise to obnox-
ious odors resulting from anaerobic decomposition. Low dissolved
oxygen values in surface waters may result from the presence of
oxygen-demanding organic substances, an inorganic chemical oxygen
demand, and increased water temperature. Significant sources of
organic substances are sanitary sewage, organic industrial wastes,
and in some instances, decaying plants and leaves.
Biochemical Oxygen Demand (BOD)- Indicates the amount of
oxygen required for biological oxidation of organic matter.
The standard BOD analysis is based upon a five-day oxida-
tion of the sample. A biological oxidation of sewage normally
takes twenty days for completion, and this 20 day BOD by defi-
nition is an ultimate BOD. The BOD5 value is approximately
68 percent of the ultimate BOD value. The COD and ultimate
BOD of a pure organic substance are theoroetically the same.
However, some organic compounds, such as acetic acid, are
difficult to oxidize chemically, while others, such as cell-
ulose and elemental carbon are biologically inert but do
exert a COD. The BODs of untreated municipal sewage is
approximately 200 mg/L.
Chemical Oxygen Demand (COD) - indicates the amount of oxygen
required for chemical oxidation of organic and other oxidi-
zable materials. The COD of untreated municipal sewage nor-
mally is about 300 mg/L.
EH
pH is defined as the logarithm of the reciprocal of the hydro-
gen ion concentration and is expressed in units ranging from zero
(0) to fourteen (14). Low values indicate the presence of acids
or acid-forming salts. High values indicate the presence of alka-
line material. A pH of 7-0 is considered neutral. High pH values
in streams are often the results of excessive utilization by algae
of the free (C03) and half-bound carbonates (HC03) in natural
waters.
Although the L). S. Public Health Service drinking water stan-
dards specify no limits of pH, extreme values are to be avoided
because of effects on treatment processes, piping and many indus-
trial processes. In streams and water courses, the most signifi-
cant effect of extreme values of pH is the possible lethal effect
on fish and other aquatic life. pH values in the ^.0-^.0 range
are generally acceptable.
-------
D-6
REFRACTORY COMPOUNDS
Refractory compounds are defined herein as those that resist
ordinary water or wastewater treatment. Refractory compounds are
primarily organic. The main effects are development of taste and
odor, and increase of oxygen demand. If a compound cannot be re-
moved in a normal biological treatment system, it will be discharged
to a receiving watercourse and exert an oxygen demand downstream.
Refractory compounds can also cause taste and odor in drinking water
supply because the standard water treatment methods will not remove
them. While phenol is considered the classic contributor to tastes
and odors, it can be biologically degraded in a wastewater treat-
ment system. The U. S. Public Health Service has identified over
12 compounds which because of their refractory nature are major
taste and odor producers. These compounds are: Tetralin, Ace-
tophenone, Bis-(2-chloroethyl) ether, 2-Ethylhexanol, Dissobutyl
carbinol, Bis-(21chloroisopropyl) ether, -Methylbenzyl alcohol,
Naphthalene, 2-Methyl-5-ethy1 pyridine, Ethylbenzene, Styrene,
and Isophorone.
SOLIDS
Solids can be detrimental to fish and aquatic life. They
can settle to the stream bed destroying food organisms or dam-
aging fish-spawning beds. Solids can trap bacteria and organic
wastes on the bottom and promote anaerobic decomposition. Solids
can cause turbidity, .which will interfere with the penetration
of light, thus restricting photosynthesis and making it more dif-
ficult for fish to locate food. Excessive turbidity interferes
with the feeding habits and retards the growth of certain types
of shel 1 fish.
Solids in water are classified as either "dissolved" (capable
of passing a fine mat of asbestos fiber in a Gooch crucible), or
"suspended" (retained on the asbestos mat). Both dissolved and
suspended solids may be differentiated further as "fixed" (inorganic)
and "volatile" (organic materials, or volatile matter driven off
by ignition at about 600°C). Total suspended solids include solids
which are floatable, settleable, or truly suspended (non-separable).
Dissolved solids indicate the total amount of inorganic chem-
icals in solution. The major portion of the dissolved solids are
the carbonates, bicarbonates, sulfates and chlorides of sodium and
calcium. All of these salts can be leached from the soils or geo-
logical deposits and are therefore present in the natural waters.
Significant amounts of these chemicals are also found in sewage and
industrial effluents. Land runoff, water treatment sludges and in-
dustrial wastes discharged after treatment with lime are major sour-
ces of carbonates. Likewise chlorides are leached from the soil,
and found in the discharge of human waste, brines, and industrial
wastes, as well as street washings. Sulfates are of natural, as
well as industrial, origin.
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D-T
Excessive dissolved solids are objectionable to waters used
for public or industrial water supply. In public water supply, they
may be objectionable from a public health standpoint. In an
industrial water supply they may lead to scaling, foaming or accelerated
corrosion.
The U.S. P.H.S. drinking water standards recommend a limit of
500 mg/L of total dissolved solids.
TASTES AND ODORS
Discharges of untreated as well as treated sewage, digester
liquors, industrial wastes, algae and decaying vegetation, as well
as land runoff contribute significant tastes and odors to surface
waters. Accidental spills of organic chemicals have been also
found to be a source of objectionable tastes and odors. Odor is
usually measured in terms of the number of volumes of odor-free
water that is necessary to add to a sample until the odor is just
detectable. This number is referred to as the threshold-odor
number.
A recent analytical technique has been developed for mea-
suring taste and odor producing compounds. The technique is
Carbon Chloroform Extract (CCE), and it involves absorption of
materials on activated carbon followed by extraction of the
carbon with chloroform. The extract is dried and the residue is
expressed as mg L of CCE. The 1962 Drinking Water Standards set
a recommended 1 imit of 0.2 mg/L CCE based on studies by the
U.S. P.M. S.
Phenol
Phenolic compounds may affect fish by exerting a direct toxic
action and by imparting a taste to the fish flesh. There is a
wide spectrum of toxic levels and considerable overlap between the
lethal or damaging concentrations and those that do not harm fish
in specified time periods.
The toxicity of phenol toward fish increases as the dissolved
oxygen concentration is diminished, as the temperature is raised,
and as the hardness is lessened. Phenol appears to be less toxic
toward fish food organisms and other lower aquatic life than toward
fish. Phenolic compounds in minute quantities in domestic water
supplies impart distinctive taste and odors. Chlorination greatly
magnifies the taste and odor characteristics.
The U. S. Public Health Service drinking water standards limit
the concentration of phenolic compounds to 0.001 mg/L. The levels
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D-8
accepted for fish and aquatic life are approximately 0.2 mg/L. The
allowable effluent quality criteria can be expected to be less than
0.1 mg/L.
Sulfide
Sulfides are constituents of many industrial wastes, and
are also generated in sewage and some natural waters by the ana-
erobic decomposition of organic matter. When added to water,
soluble sulfide salts such as sodium s'ulfide (Na s) dissociate
into sulfide ions, which in turn react with a hyarogen ion in
the water to form HS- or H2S, the proportion of each depending
upon the resulting pH value. When reference is made to sulfides
in water, the sulfide is probably in the form of HS- or HLS.
The toxicity of solutions of sulfides to fish increases as
the pH value is lowered. However, inorganic sulfides have proved
fatal to sensitive fishes such as trout at concentrations between
0.5 and 1.0 mg/L as sulfide, even in neutral and somewhat alkaline
alkaline solut i on.
Sulfides impart unpleasant taste and odor to drinking water.
The threshold odor has been reported as low as 0.2 mg/L of sulfides.
Most water quality criteria do not list specfic concentrations
for sulfides.
TEMPERATURE
Water temperature is important in terms of its effect on a-
quatic life, the use of water for cooling purposes, and its influ-
ence on the self-purification processes in a stream. Increased
temperatures reduce the solubility of oxygen in water. With re-
spect to fish, higher temperatures increase metabolism and respri-
ation and thus require more oxygen. High temperatures have also
been reported to intensify the effect of toxic substances. In-
creased water temperature speeds biological degradation processes
and thus accelerates the demand on the oxygen resources of the
stream. This in turn upgrades the treatment needed to maintain
the required dissolved oxygen levels. A temperature of 95°F is
about the maximum acceptable for aquatic life. The optimum range
of temperatures for biological waste treatment systems is 86-95°F-
TOXICITY
General
Most quality criteria refer to toxic substances and
attempt to establish specific guidelines. Although much research
has been done with respect to the toxicity of specific ions to
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D-9
plants and animals, the number of variables involved in setting
limits for aquatic or human life is too great to provide a
definite limiting value for each ion or possible combinations of
ions. Thus, toxicological evaluations of materials involve in-
ductive techniques and predict only a range of levels which may
have an effect upon the species tested. To be meaningful,
toxicity studies require considerable time, serious conscientious
investigation, and highly competent interpretation of the results.
The research being conducted on toxicity is constantly providing
up-to-date information concerning the toxicity of the substances
to various forms of plant and animal life. A normal procedure
involved in specifying levels of toxicants is usually based upon
incorporating a safety factor into the median tolerance limit of
the test animals.
Cyanide
The toxicity of cyanides toward fish is affected by the
pH, temperature, dissolved oxygen, and concentration of minerals.
The toxicity of cyanide is also increased at elevated tempera-
tures, a rise of 10°C producing a two to three-fold increase in
the rate of lethal action. Toward lower organisms, cyanide does
not appear to be as toxic as toward fish.
The WHO International and WHO European Drinking Water Stan-
dards both set a maximum allowable limit of 0.01 mg/L for cya-
nides, as CH-. In 1962, the U.S.P.H.S. Drinking Water Standards
set a recommended limit of 0.01 mg/L and a mandatory limit of
0.2 mg/L.
The toxicities of cyanides toward fish have been reported
to range from 0.05 to 0.15 mg/L. The allowable effluent criteria
can be expected to be less than 0.1 mg/L,
Metals
Dissolved metallic ions create turbidity and discoloration,
can precipitate to form bottom sludges, and can impart taste to
waters. However, limits on metals are usually based on toxicity
levels. The more common metals will be discussed.
The toxicity of copper to aquatic organisms varies signigi-
cantly with the species, and also with the physical and chemical
characteristics of the water, such as, temperature, hardness, tur-
bidity and carbon dioxide content. Copper concentrations ranging
from 0.015 to 3.0 mg/L have been reported as toxic to many kinds
of fish and other aquatic life. Copper can also be detrimental to
biological waste treatment systems. The U.S.P.H.S. drinking water
standards recommend a limit of 1.0 mg/L. Limits of 0.02 mg/L have
been recommended for fish in fresh water and 0.05 mg/L for fish
in sea water. The allowable effluent quality criteria will pro-
bably be less than 0.05 mg/L.
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D-10
Cadmium acts synergistically with other substances to in-
crease toxicity. Cadmium can form a complex with cyanide in metal
plating wastes; but in dilute solutions the complex is almost
completely dissociated and highly toxic. Synergism of the toxic
cadmium and cyanide ions liberated in the dissociation is indi-
cated. The 1962 Drinking Water Standards of the U.S.P.H.S. set
a mandatory limit of 0.01 mg/L for cadmium and the WHO European
Standards prescribe a tolerance limit of 0.05 mg/L. The lethal
concentration for fish varies from about 0.01 to about 10 mg/L
depending on the test animal, the type of water, temperature,
and time of exposure. The allowable effluent quality criterion
would probably be less than 1.0 mg/L
Chromium is picked up by plants from the soil, and is toxic
at all concentrations. The chromate ion is slightly more toxic
than the chromic ion at equivalent concentrations. The toxicity
of chromium salts toward aquatic life varies widely with the
species, temperature, pH, valence of the chromium, and syner-
glistic or antagonistic effects, especially that of hardness.
There appears to be no evidence that hexavalent chromium is
more toxic toward fish than the trivalent form. The U.S.P.H.S.
Drinking Water Standards of 1962 set a mandatory limit of 0.05
mg/L for hexavalent chromium. Allowable effluent criteria can
be expected to be less than 1.0 mg/L.
Dissolved iron in excessive amounts adds an objectionable
color to water and stains plumbing fixtures. In the presence
of alkalinity, it reacts to form an insoluble salt which settles
to the stream bed. In sufficient amounts, these solids may
smother the eggs of fish. In slightly buffered streams the
above reaction may lower the pH to a level which is detrimental
to fish and other aquatic life. The maximum concentration of
iron is listed as 0.3 mg/L in the U.S.P.H.S. Drinking Water
Standards.
Nickel appears to be less toxic to fish than copper, zinc,
brass, and iron. Nickel combines readily with cyanide to form
a nickel-cyanide complex that is relatively stable. It can be
present in water at concentrations greater than 100 mg/L as
cyanide without harm to fish life if the water is moderately
alkaline. In acid waters, however, the complex breaks down and
releases hydrogen cyanide. The U.S.P.H.S. Drinking Water
Standards do not place any limit 01. nickel. No data on the
toxicity of nickel to man are revealed, but the toxicity is be-
lieved to be very low. Nickel is extremely toxic to citrus plants
The allowable effluent quality criterion would probably be less
than 20 mg/L.
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D-ll
Zinc exhibits considerable toxicity towards fish and aquatic
life. In soft water, concentrations of zinc ranging from 0.1
to 1.0 mg/L have been reported to be lethal. The sensitivity of
fish to zinc varies with species, age and conditions of the fish,
as well as with the physical and chemical characteristics of the
water. The presence of copper appears to have a synergistic
effect on the toxicity of zinc. The U.S.P.H.S. Drinking Water
Standards of 1962 set a limit of 5 mg/L of zinc in acceptable
water supplies when no alternate sources are available. The
WHO International and European standards also prescribe a per-
missible or recommended limit of 5-0 mg/L. Zinc has no known
adverse physiological effects upon man except at very high con-
centrations. The allowable effluent quality criterion would
probably be less than 10 mg/L.
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APPENDIX E
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APPENDIX E
REFERENCES
SPECIFIC REFERENCES
1. "1966 Refining Process Handbook," Hydrocarbon Processing, k-5' 173-
276 (September 1966).
2. Nelson, W. L., Petroleum Refinery Engineering, Uth Ed., McGraw-
Hill Book Co., Inc. , N. Y., 1958.
3. Confi'dential Files, ROY F. WESTON, INC.
h. Interviews with industry representatives.
5. Beychok, M. R., Aqueous Wastes from Petroleum and Petrochemical
Plants, John Wiley and Sons, N. Y., 1967.
6. Elkins, H. F., "Petroleum Refinery Emissions," Air Pollution, Vol. 2,
A. C. Stern, Ed., Academic Press, N. Y., 1962, pp. 138-152.
7. "Cat Cracking Process Still Ranks as Workhorse of the Oil Industry",
The Baton Rouge Record, May, 19&7- (Publication of Employees
of Humble Oil and Refining and Enjay Chemical Co. at Baton
Rouge, La. )
8. "Water Use in Manufacturing," 1 9&3 Census of Manufactures, U. S.
Bureau of the Census, Dept. of Commerce, U.S.G.P.O., Washing-
ton, D. C. , 1966.
9. Otts, Louis E., "Water Requirements of the Petroleum Refining Indus-
try", U.S.G.S. Water Supply Paper 1330-G, Dept. of Interior,
U.S.G.P.O., Washington, D.C., 1963.
10. Cutting, F. C., "A Survey of Water Use by Petroleum Refineries
in the United States, 1959> "American Petroleum Institute in
Cooperation with the National Technical Task Committee on
Industrial Wastes, July 1963.
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E-2
11. "Annual Refining Section," The Oil and Gas Journal, 65: 141 -
204 (April 3, 1967).
12. Starmont, D. H., "Refiners Hold Line on Capacity", The Oi1 and
Gas Journal , 6]_: 104-107 (April 15, 1963).
13. "Survey of Operating Refineries in the U.S.," The Oi1 and Gas
Journal, 6±: 149 - 173 (April 15, 1963).
14. Tuttle, R. B., "U.S. Refineries Have Crude-Oil Input Capacity
of 6.75 Mil 1 ion Barrels," The Oil and Gas Journal, 48: 302 -
303 (March 23, 1950).
15. "346 Operating Plants, 48 Idle, Survey Shows," The Oil and Gas
Journal. 45: 304 (March 23, 1950).
16. "Petroleum Refining and Related Industries," 1963 Census of Manu-
factures, U.S. Bureau of the Census, Dept. of Commerce,
U.S.G.P.O., Washington, D.C., 1966.
17- Petroleum Facts, and Figures, 1965 Ed., American Petroleum Institute,
N. Y., 1965.
18. "1964 Refining Process Handbook, " Hydrocarbon Processing, 43: 139-
234 (September 1964).
19. "1962 Refining Process Handbook," Hydrocarbon Processing, 41 : 149-
244 (September 1962).
20. "Survey of Refineries Making Lubes," Hydrocarbon Processing, 46:
185 - 186 (June 1967).
21. Johnson, I. H. and Hagstrom, P.E., "Grease Market: Forecast to
1975," Hydrocarbon Processing, _46: 161 - 164 (April 1967).
22. "Review and Forecast," The Oil and Gas Journal, 64: 135 - 160
(January 31, 1966).
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E-3
23. Gonzalez, P. J., "How Big a Task Ahead for the Petroleum Industry?,"
The Oil and Gas Journal, 65: 101 -101+ (May 15, 1967).
2k. Lawson, S. D., Moore, J. F., and Rather, J. B., "Added Cost of Un-
leaded Gasoline," Hydrocarbon Processing, 1+6: 173 - '8'
(June 1967).
25. Davis, R. W. and Smith, R. M., "Pollution Control and Waste Treat-
ment at an Inland Refinery," Proc. of 19th Industrial Waste
Conference, Purdue University, Part I: 126 - 138 (1964).
26. "Manual on Disposal of Refinery Wastes," 7th Ed., Division of
Refining, American Petroleum Institute, N. Y., 19&3-
27- Weston, R. F., Merman, R. G., and De Mann, J. G., "Waste Disposal
Problems of the Petroleum Industry," Industrial Wastes,
William Rudolfs, Ed., Reinhold Publishing Corp., N. Y., 1953
pp. 1+19 _ 14.1+9.
26. Burroughs, L. C. and Carnahan, R. W., "Disposal of Spent Chemicals
from Petroleum Refining," Paper Presented at ll+th Mid-Year
Meeting of the API's Division of Refining, Houston, Texas,
(April 7, W).
29. Eldridge, E. F., Industrial Waste Treatment Practice, McGraw-Hill
Book Co. , Inc., N. Y., 19^2.
30. "How Much and What's In HPI Waste Water Streams," Hydrocarbon Pro-
cessing, 1+6: 109 - 110 (July 1967).
31. "Annual Statistical Bulletin," Department of Statistics, American
Petroleum Institute, Washington, D. C., 1;
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E-k
GENERAL REFERENCES
Austin, R. J., Meehan, W. F., and Stockham, J. D., "Biological Oxida-
tion of Oil-Containing Waste Water," Ind. and Eng. Chem.,
h6: 316 (19510.
Austin, R. J., et.al., "Operation of Experimental Trickling Filters on
Oil Containing Waste Waters," Proc. of 8th Industrial Waste
Conference, Purdue University, p. 2k (1953).
Baker, R. A. and Weston, R. F. , "Biological Treatment of Petroleum
Wastes," Sew, and Ind. Wastes. 28: 58 (1956).
Berger, M., "The Disposal of Liquid and Solid Effluents from Oil Refineries,1
Proc. of 21st Industrial Waste Conference, Purdue University,
p. 759 (1966).
"Biological Treatment of Petroleum Refinery Wastes," Division of Refin-
ing, American Petroleum Institute, N. Y., 1963.
Bloodgood, D. E. and Kelleher, W. F., "Fundamental Studies on the Remov-
al of Emulsified Oil by Chemical Flocculation," Proc. of 7th
Industrial Waste Conference, Purdue University, p. 3^1 (1952).
Brunsmann, J. J., Cornelissen, J., and Eilers, H., "Improved Oil Separa-
tion in Gravity Separators," JWPCF, 3^: kk (1962).
Buck, W. B., "Progress Made by Oil Industry of Oklahoma in the Disposal
of Brine," Proc. of 13th Industrial Waste Conference, Purdue
University, p. 35^ (1958).
Burroughs, L. C. and Sample, G. E., "Pollution Control at Shell Oil
Refineries," Sew, and Ind. Wastes, 30: 57 (1958).
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E-5
Coe, R. H., "Bench Scale Biological Oxidation of Refinery Wastes
with Activated Sludge," Sew, and Ind. Wastes, 2^: 731 (1952).
Coogan, F. J. and Paille, E. B., "Physical and Chemical Characteris-
tics of Waste Waters," Ind. and Eng. Chem., k6: 290 (195*0.
Crosby, E. S., Rudolfs, W., and Heukelekian, H., "Biological Growths
in Petroleum Refinery Waste Waters," Ind. and Eng. Chem.,
1+6: 283 (195*0.
Degnan, J. M-. , Merman, R. G., and De Mann, J. G., "Pilot Plant Investi-
gations of the Biological Filtration of Petroleum Refinery
Wastes," Proc. of 7th Industrial Waste Conference, Purdue
University, p. 78 (1952).
Dorris, F. C., Patterson, D., and Copeland, B. J., "Oil Refinery Efflu-
ent Treatment in Ponds," JWPCF, j>5_: 932 (1963).
Easthagen, J. H., Skrylov, V., and Purvis, A. L., "Development of
Refinery Wastewater Control at Pascagonla, Mississippi,"
JWPCF, 27: 1671 (1965).
Eaton, C. D., Evans, R. R., and Kominek, E. G., "Reclamation of Refinery
Effluents," Ind. and Eng. Chem., k6: 319 095*0-
Eldridge, E. F. and Orlob, G. J., "Investigation of Pollution of Port
Gardner Bay and Snohmish River Estuary," Sew, and Ind. Wastes,
23: 782 (1951).
Elkin, H. F., "Activated Sludge Process Applications to Refinery Efflu-
ent Waters," Sew, and Ind. Wastes, 28: 1122 (1956).
Elkin, H. F. and Austin, R. J., "Petroleum," Industrial Wastewater Con-
trol , C. F. Grunham, Ed., Academic Press, N. Y., 1965.
287-028 O - 68 - 11
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E-6
Fiske, C. F., "Economical Refinery Waste Disposal," Sew, and Ind.
Wastes, 27: 1317 (1955).
Frame, J. D., "Field Trip to the Treatment Works of a New Refinery,"
Sew, and Ind. Wastes, 3jh 967 (1959).
GMliam, A. S., and Anderegg, F. C., "Biological Disposal of Refinery
Wastes," Proc. lUth Industrial Waste Conference, Purdue
University, p. 145 (1959).
Gils, R. N., Scheinemah, F. W., Nicholson, C. F., and Austin, R. J.,
"Performance of a Gravity Type Oil-Water Separator on Pet-
roleum Industry Wastes." Sew, and Ind. Wastes, 23: 281 (1951).
Gils, R. N. "A Rational Approach to Industrial Waste Disposal Problems,"
Sew, and Ind. Wastes, 24: 1495 (1952).
Gould, W. R.and Dorris, F. C., "Toxicity Changes of Stored Oil Refinery
Effluents," JWPCF, 33: 1107(1961).
Graves, B. S., "Biological Oxidation of Phenols in a Trickling Filter,"
Proc. 14th Industrial Waste Conference, Purdue University,
P. 1 (1959).
Hodgkinson, G. F., "Oil Refinery Waste Treatment in Kansas," Sew, and
Ind. Wastes, 3_h 1304 (1959).
Landsberg, Hans H., Natural Resources for U.S. Growth, The Johns Hopkins
Press, Baltimore, Md., 1964.
Lewis, W. L., "Use of Centrifuges in Deoiling Silt," Proc. 18th Indus-
trial Waste Conference, Purdue University, p. 273 (1963).
Ludzack, F. J., Middleton, F. M., and Ettinger, M. B., "Observation and
Measurement on Refinery Wastes," Sew, and Ind. Wastes, 30:
662 (1958).
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E-7
Maehler, C. Z. and Greenberg, A. E., "Identification of Petroleum
Wastes in Groundwaters," JWPCF, 3k: 1262 (1962).
Man, G. E., "Pilot Plant Studies of Refinery Waste Treatment on
Trickling Filters," Sew, and Ind. Wastes, 26: 1236(1954).
Merman, R. G., Ferrall, P. J. and Foradori, G. F., "Sludge Disposal
at a Philadelphia Refinery," JWPCF. 3>3_: 1153 (1961 ).
Mohler, E. F., Elkin, H. F., and Kumnick, C. R., "Experience with Re-
use and Bioxidation of Refinery Wastewater in Cooling Tower
Systems," JWPCF. 36: 1380 (1964).
Morris, J. M., "Disposal of Oil Field Brines in the San Joaquin Valley
of California," Proc. 18th Industrial Waste Conference,
Purdue University, p. 348 (1963).
Morris, W. S., "Subsurface Disposal of Salt Water from Oil Wells,"
JWPCF, 3>2: 41 (I960).
McRae, A. D., "Disposal of Alkaline Wastes in the Petrochemical Indus-
try," Sew, and Ind. Wastes, jH: 712 (1959).
McRae, A. D., "Modern Waste Disposal and Recovery in a Petroleum Indus-
try," Proc. 9th Industrial Waste Conference, Purdue Univer-
sity, p. 440 (1954).
Niegonski, S. J., "Ozone Method for Destruction of Phenols in Petro-
leum Waste Waters," Sew, and Ind. Wastes, _28; 1266 (1956).
Phillips, C., "Treatment of Refinery Emulsions and Chemical Wastes,"
Ind. and Eng. Chem., _46: 300 (1954).
Pomeroy, R., "Disposal of Wastewater from Oil Fields in the Coastal
Counties of California," Sew, and Ind. Wastes, 26: 59 (1954),
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E-8
Pomeroy, R., "Floatabi1ity of Oil and Grease in Waste Waters," jew.
and Ind. Wastes, _2j?: 1304 (1953).
Porgi, R., "Industrial Waste Stabilization Ponds in the United States,"
JWPCF. 22.: 456 (1963).
Prather, B. V., "Development of a Modern Petroleum Refinery Wastewater
Program," JWPCF, 36: 96 (1964).
Pursell, W. L. and Miller, R. B., "Waste Treatment of Skelly Oil Com-
pany's El Dorado, Kansas Refinery," Proc. 16th Industrial
Waste Conference, Purdue University, p. 292 (1961).
Quigley, R. E. and Hoffman, E. L., "Flotation of Oily Wastes," Proc. 21st
Industrial Waste Conference, Purdue University, p. 527 )1966).
Ray, F. E., "Operating Problems of Industrial Waste Treatment Plants IV.
Oil Refining Wastes," Sew, and Ind. Wastes, ^0: 1390 (1958).
Rohlick, G. A., "Application of Air Flotation to Refinery Waste Waters,"
Ind. and Eng. Chem., 46: 304 (1954).
Rohlick, G. A., "Pilot Plant Studies of Air Flotation of Oil Refinery
Wastewater," Proc. 8th Industrial Waste Conference, Purdue
University, p. 368 (1953).
Ross, W. K. and Sheppard, A. A., "Biological Oxidation of Petroleum
Phenolic Wastewaters," Proc. 10th Industrial Waste Confer-
ence, Purdue Universtiy, p. 106 (1955)-
Ruchhoft, C. C., Middleton, F. M. Rans, H., and Rosen, A. A., "Taste-and
Odor-Producing Components in Effluents," Ind. and Eng. Chem.,
46: 284 (1954).
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E-9
Schindler, H., "Chemical Treating Plant for Refining Wastewater from
White Oils and Petroleum Sulfonates," Proc. 6th Industrial
Waste Conference, Purdue University, p. 30*4- 0950-
Shadow, R. D., "Waste Treatment at a Large Petrochemical Plant," JWPCF,
38: *4-28 (1966).
Sheets, W. D., Hamdy, M. K. and Weiser, H. H., "Microbiological Studies
on the Treatment of Petroleum Refinery Phenolic Wastes,"
Sew, and Ind. Wastes, 26: 862 (195*4-).
Shreve, R. N., Chemical Process Industries, 3rd Ed., McGraw-Hill Book
Co., Inc. N. Y., 1967.
Simonsen, R. N., "How Four Oil Refineries Use Water," Sew, and Ind.
Wastes, 2k: 1372 (1952).
Soloms, E. D., "Development, Construction, and Operation of an Oily
Waste Treatment Plant," Proc. 7th Industrial Waste Confer-
ence, Purdue University, p. Ml (1952).
Strong, E. R. and Hatfield, R. , "Superact ivated Sludge Process," Ind.
and Eng. Chem. , lj-6: 308 (195*4-).
Turnbul 1 , H., De Mann, J. G., and Weston, R. F., "Toxicity of Various
Refinery Materials to Fresh Water Fish," Ind. and Enq. Chem. ,
Umback, R. D., "How One Refinery Is Handling Its Waste Treatment Pro-
blem," Proc. lUth Industrial Waste Conference, Purdue Uni-
versity, p. 385 (1959).
Voege, F. A. and Stanley, D. R. , "Industrial Waste Stabilization Ponds
in Canada," JWPCF, 35: 1019 (1963).
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E-10
Weston, R. F., "Separation of Oil Refinery Waste Waters," Ind. and
Eng. Chem., k2: 607 (1950).
Weston, R. F. , "Waste Control at Oil Refineries," Chem. Eng. Prog.,
M: ^59 (1952).
Williamson, A. E., "Land Disposal of Refinery Wastes," Proc. 13th
Industrial Waste Conference, Purdue University, p. 337
(1958).
Zeien, J. F.,' "Reduction and Control of Wastes in a New Refinery,"
Proc. 9th Industrial Waste Conference, Purdue University,
P. 3U (195*0.
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APPENDIX F
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APPENDIX F
FUNDAMENTAL PROCESSES
Introduction
For this pollution profile, twenty separate processes have
been selected as the fundamental processes essential to produc-
tion of final products from crude oil. The brief discussion of
each fundamental process will cover: The application of the
process in the overall refinery scheme; raw materials and products
involved; process description; waste generated, including water,
solids, air and thermal considerations; the principal subprocesses
(alternative methods of carrying out the fundamental process);
and related economic and technological information and trends.
The major sources for the process descriptions were the "1966
Refining Process Handbook" of Hydrocarbon ProcessIng roagazIne (1)
and W. L. Nelson's Petroleum Refinery Engineering U). Information
regarding the wastes from each process was obtained from ROY F.
WESTON files (3), personal interviews (k), and Aqueous Wastes from
Petroleum and Petrochemical Plants by W. R. Beychok (5).
Crude and Product Storage
ApplI cat Jon: Crude oil storage Is used to provide adequate
supplIes of feedstocks for primary fractlonatlon runs of
economical duration. Intermediate product storage equalizes
flows within the refinery. Final product storage is used to
store the finished products prior to shipment, to mix and
blend products, and to lessen the effects on refinery opera-
tions of changes In product demands.
Charge; Crude oil or refinery products
Products; Crude oil or refinery products
Proces s DescrIjatIon; Crude oil and intermediate and finished
products are stored in steel tanks ranging In size from a few
thousand barrels to more than a hundred thousand barrels.
Generally, operating schedules permit detention periods suffi-
cient for settling of water and suspended solids. The settled
water layer Is drawn off at Intervals depending on the rate of
accumulation.
Wastes: Wastes associated with storage of crude oil and
products are mainly In the form of free and emulsified oil
and suspended solids. During storage, water and suspended
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F-2
solids In crude oil separate, with the water accumulating
under the oil and solids forming • bottom sludge. When the
water layer Is drawn off, emulsified oil present at the oil-
water interface and some solids are often lost to the sewers.
This waste Is high in COO and contains a lesser amount of BOD.
Bottom sludge is removed at less frequent intervals; It is
generally disposed of to landfill. Additional quantities of
waste result from leaks, spills, salt "filters" (for product
drying), and tank cleaning.
Intermediate storage Is frequently the source of polysulfide-
bee ring wastewaters and Iron sulflde suspended solids. Fin-
ished product storage can produce htgh-BOD, alkaline waste-
waters, as well as tetraethyl lead. Tank cleaning can con-
tribute large amounts of oil, COD and suspended solids, and
a minor amount of BOD. Leaks, spills, open or poorly ventil-
ated tanks, and improper landfill disposal can also be a
source of air pollution, through evaporation of hydrocarbons
Into the atmosphere.
Trends; Many refineries now have storage tanks equipped
to minimize the release of hydrocarbons to the atmosphere.
This trend is expected to continue end probably accelerate.
Equipment to minimize the release of hydrocarbon vapors in-
cludes tanks with float ing-roof covers, pressurized tanks,
and/or connections to vapor-recovery systems (6). Floating-
roof covers add to the wastewater flow from storage tanks.
Modem refineries impose strict Bottom Sediment and Water
(BScW) specifications on crude oil supplies, and they fre-
quently have mixed-crude storage tanks; consequently, little
or no wastewater should originate from modem crude storage.
Another significant trend is toward Increased use of dehydra-
tion or drying processes preceding product finishing. These
processes significantly reduce the water content of finished
product, thereby minimizing the quantity of wastewater from
finished product storage.
Crude Desalting
AlternatIve Subprocesses;
1. Chemical Desalting
2. Electric Desalting - Petrolfte
3. Electrical Desalting - Howe-Baker
*». Electrostatic Desalting
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F-3
>lication; Removal of Inorganic salts and certain suspended
from crude oil to reduce mechanical plugging in process
equipment, coke formation in furnaces, and corrosion. Desalt-
ing also provides removal of arsenic and other impurities which
act as poisons to catalytic cracking catalysts.
Appjici
soli ds
Charge; Crude oi1
Products: Crude oil from which most water-soluble and solid
contaminants such as chlorides, sulfates, bicarbonates, sand
silt, etc., have been removed. Arsenic is also substantially
reduced.
Process Descri ption: Common to all types of desalting are an
emuTsifier and a settling tank. Salts can be separated from
the oil by water washing in the presence of chemicals specific
to the type of salts present and the nature of the crude oil.
In chemical desalting, chemicals are added to the crude oil,
and water is added and mixed with the crude to form an emul-
sion. The emulsion is heated to 150-350*F and held in a
settling tank for 20-60 minutes. The salts and other impuri-
ties attach to or dissolve in the water droplets, which In
turn coagulate and settle out. The desalted crude Is drawn
off the top of the settling tank.
The electrical methods of crude desalting differ from chem-
ical desalting in that demulstfylng chemicals are used only
when the crude oil Is abnormally high in suspended solids.
Normally the oil Is mixed with fresh water to form an emul-
sion. The water, which now contains most of the impurities,
is separated from the oil in a settling tank under the in-
fluence of a high voltage electrostatic field, which acts
to agglomerate the dispersed water droplets and accumulate
them in the lower portion of the tank. The water containing
the various removed impurities is continuously discharged
to the wastewater system. Clean desalted crude flows from
the top of the tank and Is ready for subsequent refining.
Wastes; The continuous waste stream from a desalter contains
emulsified and at times free oil, ammonia, phenol, and sus-
pended solids. Ammonia is added in many refineries to reduce
corrosion. These pollutants produce a relatively high BOD
and COD. This waste also contains enough chlorides and other
dissolved materials to contribute to the dissolved solids
problem in areas where the waste is discharged to fresh water
bodies. There is also a potential thermal pollution problem,
because the temperature of the desalter waste often exceeds
200°F.
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f-k
Trends: Electrical desalting is used much more than chemical
desalting and is rapidly replacing it. In the future, chem-
ical methods are expected to be used only as a supplement to
electrical desalting where the crude oil has a very high salt
content. The growth in capacity of desalting units will
parallel the growth of crude oil capacity.
Crude Oil Fractionat ion
Alternative Subprocesses; Atmospheric Fractional ion; Vacuum
FractionalIon; Vacuum Flashing; Crude Distillation, Three
Stages.
Appl1 cat Ion; Serves as the basic refining process for the
separation of crude petroleum into intermediate fractions of
specified boiling point ranges.
Charge; Crude ol1 (desalted)
Products; A complete range of fractions including: gas,
straight-run gasoline, naphtha, kerosene, dtesel fuel,
heating oils, cracking stock, base stocks for wax and
lubricating oil, fuel oil, and asphalt.
Process Description: There are several possible combinations
of fractions and quantities from crude distillations. The
combination used in any particular case depends upon the type
of crude being processed and the desired products. This
description of crude distillation Is Intended to represent
only one possible combination of equipment, Crude Distilla-
tion-Three Stages, which consists of:
1) an atmospheric fractionating stage which produces
the lighter oils;
2) an initial vacuum stage which produces weTl-
fractlonated lubricating oil base stocks and a "long"
residue for subsequent propane deasphalting;
3) a second vacuum stage designed for high vacuum, which
fractionates surplus atmospheric bottoms not required
or not suitable for lube production plus surplus
initial vacuum-stage residuum not required for deas-
phalttng. This third stage adds to the unit the
the capability of removing catalytic cracking
stock from surplus bottoms. A light ends frac-
tionating section is included to stabilize the
light straight-run gasoline.
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F-5
Crude oil Is heated In a heat exchanger then in a direct -
ft red crude charge heater. The combined vapor and liquid
effluent from the heater flows to the atmospheric fraction-
ating tower where the vaporized distillate is fractionated
into a gasoline overhead product and four iiquid sidestream
products - naphtha, kerosene, tight diesel oil, and heavy
diese) oil. The overhead gasoline Is condensed and pumped
to a stabilizer where the gasoline is debutanized or depro-
panlzed to produce straight-run gasoline. The gas products
Include butane, propane and methane.
Part of the reduced crude from the bottom of the atmospheric
tower Is pumped through a direct-fired heater to the vacuum
lube fractionator, where the distillate Is separated into
a gas oil and three lube oil sldestreams. Propane deasphal-
ttng feedstock is withdrawn from the bottom of the tower.
The remainder of the atmospheric tower bottoms plus all
of the vacuum lube fractionator bottoms not required as
deasphaltlng feedstock are combined and charged to a third
direct-fired heater. In the tower the distillate is con-
densed In two sections and withdrawn as two sidestreams.
The two sldestreams are combined to form catalytic cracking
feedstocks. An asphalt base stock Is withdrawn from the
bottom of the tower.
Wastes; The wastes from crude oil fractlonatlon generally
come from three sources. The first Is the water drawn off
from overhead accumulators prior to reclrculatlon or transfer
of the hydrocarbons to another fractionator. The water that
separates from the hydrocarbons In these accumulators Is
drawn off and discharged to the sewer system. This water is
a major source of sulfides, especially when sour crudes are
being processed; it also contains significant amounts of oil,
chlorides, mereaptans, and phenols.
A second significant waste source is discharge from oil
sampling lines; this oil should be separable but may form
emulsions In the sewer. A third possible waste source Is
the very stable oil emulsions formed In the barometric con-
densers used to create the reduced pressure in vacuum dis-
tillation units; however, when barometric condensers are re-
placed with surface condensers, oil vapors do not come in
contact with water, and emulsions do not develop.
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F-6
Trends; The general industry trend to larger and more com-
plete refineries has been reflected also In larger and more
complex crude fracttonation units. Thus, the simple atmos-
pheric "topping" units are being replaced by the atmospheric-
vacuum combinations with an increasing number of sidestream
products. Installed capacity now totals 3 million barrels
per day. Modern refineries use surface condensers In place
of barometric condensers. This reduces pollution signifi-
cantly.
Thermal Cracking
Alternative Subprocesses;
I. Delayed Coking
2. Fluid Coking
3. Thermal Cracking
4. Visbreaking
Application; In this profile study the term Thermal Cracking
is used to define a fundamental process that includes vis-
breaking, delayed coking, and fluid coking as well as regular
thermal cracking. Heavy Oil fractions are broken down into
lighter fractions by application of heat and pressure but
without the use of a catalyst. With regular thermal cracking
there Is a minimum of gasoline production but more middle
distillate and stable fuel oils. Visbreaking or coking max-
imizes the production of catalytic cracking feedstocks and
thus indirectly Increases gasoline production.
Charge; Reduced crudes, asphalts, and unfractionated crudes.
Products: Coke, fuel oils, gas oil, naphtha, gasoline, and
gases.
Proces s DCS c r I pt ion; Basic to all thermal cracking processes
are a furnace where the feed is heated to cracking tempera-
tures and a fractionator where the cracked products are sepa-
rated. The heat breaks the bonds holding the large molecules
together, and under certain conditions some of the resulting
smaller molecules may recombine to give molecules even larger
than those In the feedstock. The products of this second re-
action may be again decomposed into smaller molecules depen-
ding on the time they are held at cracking temperatures.
Visbreaking is a mild form of thermal cracking; it causes
very little reduction in boiling point, but significantly
lowers the viscosity of the feed. The feed is heated and
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F-7
cracked slightly In a furnace. The furnace effluent ts
then quenched with light gas oil and flashed tn the bottom
of a fracttonator. Gas, gasoline, and furnace oil fractions
are drawn off, and the heavier fractions are recycled.
Coking ts a severe form of thermal cracking In which the feed
ts held at a high cracking temperature long enough for coke
to form and settle out. The cracked products are sent to
a fractlonator where gas, gasoline, and gas oil are separated
and drawn off. The heavier materials are recycled to the
coking operation.
Wastes; The major source of wastes tn thermal cracking Is
the overhead accumulator on the fractionator, where water Is
separated from the hydrocarbon vapor and sent to the sewer
system. This water usually contains various oil fractions
and may be high in BOD, COD, ammonia, phenol, and sulfldes.
The waste has an alkaline pH and may have a high alkalinity.
Trends; Vlsbreaktng and coking are the two major forms of
therma1 cracking in the U. S. today. The older forms of
thermal cracking, which were significant before the intro-
duction of catalytic cracking, have been practically elimi-
nated. Increasing use of visbreaktng and coking will largely
compensate for the downtrend of these older methods.
Catalytic Cracking
AI te mat I ve Subprocesses;
Fluid Catalytic Cracking - UOP
Fluid Catalytic Cracking, Model IV
Fluid Catalytic Cracking, Orthoflow
Fluid Catalytic Cracking, Two Stage
Houdriflow
Houdry - Fixed Bed
Application; To Increase the yield and quality of gasoline
and other desirable products while minimizing the yield of
residual fuels.
Charge; Naphthas, gas oils, coker distillates, deasphalted
oils, and sometimes unfractionated crude oil.
Products; High-octane gasoline, dtesel oil, furnace oil,
oleflns, isobutane, butane and dry gas.
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F-8
Process Description; The major parts of a catalytic cracking
unit are the reactor, regenerator, and fractionator. Catalytic
cracking does essentially the same thing as thermal cracking,
but the presence of a catalyst permits operation at lower temp-
eratures and pressures, thus giving greater yields of high-
octane gasoline. The process Involves at least four types
of reactions: 1) thermal decomposition; 2) primary catalytic
reactions at the catalyst surface; 3) secondary catalytic
reactions between the primary products; and k) removal of
polymerIzable products from further reaction by adsorption
on the surface of the catalyst as coke. This last reaction
is the key to catalytic cracking, because It allows decompo-
sition reactions to move closer to completion than is possi-
ble In thermal cracking.
Cracking catalysts Include synthetic silica-alumina, natural
silica-alumina, treated bentonite clay, fuller's earth, alu-
minum hydros!llcates, and bauxite. These catalysts are In
the form of beads, pellets, and powder, and are used In a
fixed bed, in a moving bed, or In fluldtzed form. Fluidtzed
catalyst is finely-powdered material which has the essential
physical characteristics of a fluid and is transferred as
such. The various modifications of fluid catalytic cracking
account for most of the catalytic cracking capacity In the
U.S.
In a fluid catalytic cracking unit, finely powdered catalyst
Is lifted Into the reactor area by the incoming oil feed
which immediately vaporizes upon contact with the hot cata-
lyst. Vapors from the reactor pass upward through a cyclone
separator which removes most of the entrained catalyst. The
vapors then enter the fractionator, where the desired products
are removed and heavier fractions recycled to the reactor.
Spent catalyst passes downward through a steam stripper and
Into the regenerator where the carbon deposit is burned off.
The regenerated catalyst again mixes with the incoming charge
stream to repeat the cycle.
Wastes; Catalytic cracking units are one of the largest
sources of sour waters in a refinery. Pollution from cata-
lytic cracking generally comes from the steam strippers and
overhead accumulators on fractionators used to recover and
separate the various hydrocarbon fractions produced In the
catalytic reactors. The major pollutants resulting from
catalytic cracking operations are oil, sulfides, phenols,
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F-9
and ammonia. These pollutants produce an alkaline wastewater
with high BOD and COD concentrations. Sulftde and Phenol
concentrations In the wastewater vary with the type of crude
oil being processed, but at times are significant.
Regeneration of spent catalyst may produce enough carbon
monoxide to constitute an air pollution problem. Frequently
the off gases are burned In a CO boiler to prevent the air
pollution problem and at the same time recover heat.
Trends; Because of the great demand for high-octane gasoline,
catalytic cracking capacity is expected to continue growing
at a rate faster than crude feed capacity. In 1965 fresh
feed capacity increased 0.3 percent, whereas gasoline capacity
increased 1.6 percent. The trend in subprocesses is greater
use of fluid catalytic cracking in preference to moving or
fixed-bed cracking. From 1955 to 1965 fluid catalytic crack-
ing's share of U.S. catalytic cracking capacity increased
from 72 to 82 percent (7). There Is also a trend to larger
fluid catalytic cracking units.
Hydrocracking
Al ternatI ye Subprocesses:
BASF - IFP Hydrocracklng
H - Oil
Isomax
UnicrackIng - JMC
H-G Hydrocracklng
Shell
Gulf Hydrocracklng
Ultracracklng
Application: Conversion of hydrocarbon feedstocks Including
distillates, gas oils, and residues into gasoline, high quality
middle distillates, LPG, or low-sulfur residual fuel. The
process is used to improve overall refinery efficiency and
flexibility.
Charge; A wide range of feedstocks including distillates,
gas oils, heavy sour crudes, and atmospheric and vacuum
residues.
Products: Gasoline, high-octane IsoparaffIns, jet fuels,
dJesel fuels, and low-sulfur fuel oil. Except for gases,
final products from hydrocracking do not have to be "sweet-
ened", as they are already free of sulfur compounds.
287-028 O - 68 - 12
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F-10
Process Description: HydrocrackIng Is basically catalytic
cracking In the presence of hydrogen. Because hydrogen Is
present, the oleftns formed during cracking are saturated
before they can contribute to coke formation.
Hydrocracktng temperatures range from 400" to 800°F., which
Is lower than the temperature required In catalytic cracking.
Pressures, however, are much higher In a hydrocrackIng unit,
ranging from about 100 to 2,000 pslg. Actual operating con-
ditions and the amount of hydrogen consumption depend greatly
upon the feedstock and the degree of hydrogenatlon desired.
The reactor effluent passes through a separator, stabilizer,
and a product fractionator. Hydrogen gas is recycled from
the separator to the reactor. Products from the fractionator
heavier than those desired are also recycled to the reactor.
Wastes: This Is a new process, and no definite Information
concerning its waste production has been published. At least
one waste stream from the process should be high in sulfides
because hydrocracking reduces the sulfur content of the ma-
terial being cracked. Most of the sulfides are probably In
the gas products, which are sent to a treating unit for re-
moval and/or recovery of h^S. However, In the product sepa-
ration and fractional Ion units following the hydrocracking
reactor, some of the ^S will dissolve In the water being
collected. This water from the separator and fractionator
will probably be high in sulfides, and possibly phenols and
ammonia.
Trends; Hydrocracking Is perhaps the most Important refinery
Innovation of the decade, primarily because of the flexibility
It provides. It allows refineries to adjust their operations
economically to meet changing market demands. Because of
this, hydrocracking capacity is growing at a rapid rate. At
the beginning of 1966 U. S. capacity was 117,000 bpsd. By
1968, It Is estimated that total installed capacity will be
approximately 400,000 bpsd.
Reforming
AI te matIve Subprocesses:
Catalytic Reforming - Kellogg
Catalytic Reforming - Engelhard
Houdrlforming
I so-Plus Houdriforming
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F-ll
PI atforming
PowerformIng
Thermal Reforming
Ultraformi ng
Appli cat i on: Reforming converts naphthas to finished high-
octane gasoline and produces aromatics for petrochemicals or
aviation gasoline; it improves gasoline quality, but does
not contribute to increased yield.
Charge: Straight-run naphthas, cracked naphthas, heavy gaso-
line, and naphthene-rich stocks.
Products: High-octane gasoline; benzene, toluene, xylene,
and other aromatics; and isobutane. Hydrogen Is a signifi-
cant by-product of the process.
Proces s Description: Platform!ng Is the most widely used
reforming subprocess. A typical Platform!ng unit may be
divided into three parts: the reactor heater section, in
which the charge plus recycle gas is heated and passed over
the catalyst in a series of reactors; the separator drum, in
which the reactor effluent is separated into gas and liquid
streams, the gas being compressed for recycling; and the
stabilizer section, in which the separated liquid is stabil-
ized to the desired vapor pressure. The predominant reaction
during reforming is the dehydrogenation of naphthenes. Im-
portant secondary reactions are the isomerization and dehy-
drocyclization of paraffins. Ail three of these reactions
result In products with higher octane ratings than the
reactants. Since the reactions occur over a single catalyst,
the catalyst has a dual function. It must posses an acid
characteristic to promote IsomerizatIon and an electron-
deficient structure to promote dehydrogenation. Platinum and
molybdenum are the most widely used catalysts, with platinum
predominating because it gives better octane yields. Because
platinum catalysts are poisoned by arsenic, sulfur and
nitrogen compounds, feedstocks usually are hydrotreated be-
fore being charged to the reforming unit.
After pretreatment the feedstock In most reforming units Is
combined with hydrogen-rich recycle gas. The mixture then
flows through 3 or k reactors in series each preceded by a
fired heater. The effluent from the last reactor is cooled
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F-12
and passes to the separator drum. The liquid from the sepa-
rator drum ts stabilized, and the stripped hydrogen gas ts
compressed and recycled to the first reactor. The catalyst
In each reactor Is regenerated periodically either by taking
the whole reforming unit off streamer by regenerating one
reactor at a time with flow continuing through the remaining
reactors. In some cases a "swing" reactor is provided to
replace the reactor being regenerated.
Wastes: Reforming Is a relatively clean process. The volume
of waste flow Is small, and none of the waste streams has
high concentrations of significant pollutants. The waste
is alkaline, and the major pollutant Is sulfide from the over-
head accumulator on the stripping tower used to remove light
hydrocarbon fractions from the reactor effluent. The over-
head accumulator catches any water that may be contained in
the hydrocarbon vapors. In addition to sulfides, the waste
contains small amounts of ammonia, mercaptans and oil.
Trends: Reforming capacity In the U. S. Is growing at about
the same rate as total crude capacity. Reforming capacity is
about 20 percent of crude capacity or approximately 1,999,000
barrels per calendar day (bpcd). In 1965 reforming capacity
was k] percent of gasoline demand, and it is estimated that
this relationship w!11 remain relatively constant.
Polymerization
AlternatIve Subprocesses;
1. Bulk Acid Polymerization
2. Solid Phosphoric Acid Condensation
3. Sulfuric Acid Polymerization
k. Thermal Polymerization
ApplI cat Ion: To convert olefin feedstocks Into higher-octane
polymer gaso)Ine.
Charge: All types of olefin feeds.
Products: Polymer gasoline, propane, and butane.
P roce s s De s c r I j> t i on; Polymerization units generally consist
of a feed treatment section, a reactor, an acid removal sec-
tion, and a stabilizer. The feed must be treated to protect
the catalyst present in the reactor. A caustic scrubber is
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F-13
used to remove H2S and raereaptans, and a water wash Is used
to remove nitrogen compounds and residual caustic. Thermal
polymerization, which Is not widely used, is the only type
of polymerization that doesn't use a catalyst.
After pretreatment the hydrocarbon feed is brought into con-
tact with an acid catalyst in the reactor. The catalyst is
usually phosphoric acid, although sulfuric acid is used in
some older methods. The acid catalyst can be a liquid with-
out supporting materials, a thin film on quartz, or impreg-
nated in a solid. The effluent from the reactor is treated
to remove all traces of acid from the polymerized products,
in order to protect the stabilizer from corrosion and to con-
serve the catalyst. In the polymerization reaction two olefln
molecules are joined to form a larger molecule. This reaction
In the presence of a catalyst occurs at a temperature of 300-
^35°F and a pressure of 150-1200 psig. The temperature and
pressure vary with the subprocess used. The reaction is exo-
thermic, and the reactor temperature Is controlled by using
cooling water or Injecting cold feed into the reactor.
Wastes: This is a rather dirty process in terms of pollution
foadTng per barrel of charged material, but because of the
small polymerization capacity In most refineries, the total
waste production from the process is small. Even though the
process makes use of acid catalysts, the waste stream is
alkaline, because the acid catalyst in most of the subpro-
cesses is recycled, and any remaining acid is removed by
caustic washing. Host of the waste material comes from the
pretreatment of the feedstock to the reactor. The waste Is
high In sulfldes, mercaptans, and ammonia. These materials
are removed from the feedstock in caustic scrubbers and
wash water towers. Spent catalyst is removed periodically
and causes acid and solids disposal problems.
Trends: Polymer gasoline does not have an octane rating
TuTfTclently higher than the gasoline base stocks to be
of much help In the continuing competitive market for high
octane gasoline. Furthermore, the yield per unit of olefin
feed is much less than alkylation yield for the same feed.
Polymerization capacity in U. S. refineries has been dropping
for several years and the downtrend is expected to continue.
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F-14
Alkylation
Alternative Subprocesses:
1. Cascade Sulfurlc Acid Alkylatlon
2. DIP Alkylatlon (Aluminum Chloride Alkylation)
3. Effluent Refrigeration Alkylatlon
4. HF Alkylatlon
5. HF Alkylatlon, Perco
Application: For conversion of normally gaseous hydrocarbons
to high-octane motor fuel.
Charge; Isoparafflns (usually Iso-butane) and oleflns such
as propylene, butylene, and amylene.
Products: High-octane alkylate for use as a gasoline blending
component; propane and butane.
Process Description; Alkylation Is the reaction of an olefin
with an aromatic or parafflnlc hydrocarbon, and could be con-
sidered a petrochemical process rather than a refinery process.
The alkylatlon reaction occurs In the presence of a catalyst
at carefully controlled temperatures and pressures. The
catalyst, temperature, and pressure all vary with the subprocess
used. The reactor products go to a catalyst recovery section,
where the catalyst is separated from the hydrocarbons and
recirculated to the reactor. The hydrocarbon stream is
passed through a caustic and water wash before going to the
fractlonation section. Isobutane Is recirculated to the
reactor feed, and the alkylate is drawn off from the bottom
of the debutanizer.
Three different catalysts, aluminum chloride, sulfuric acid,
and hydrofluoric acid, are presently In use. The aluminum
chloride catalyst is used in the form of a hydrocarbon com-
plex. When aluminum chloride Is used, reactor temperatures
are maintained at about 120°F. If sulfuric acid is used as
the catalyst, the reactor temperature is maintained at 3^-40°F
by refrigeration equipment. With hydrofluoric acid higher
temperatures are technically feasible, but octane rating
specifications generally require operation at temperatures
below 70°F.
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F-15
Wastes; There are three general sources of waste In a sulfuric
acid alkylatlon unit: the overhead accumulators in the frac-
tional ion section; the alkylation reactor; and the caustic
wash. Water drawn off from the overhead accumulators con-
tains varying amounts of oil, sulfides, and other contami-
nants, but is not a major source of waste in this subprocess.
The waste from the reactor consists of spent acids, and gen-
erally has a pH of less than 3; this acid stream seldom enters
the sewer system because most refineries process it to recover
clean acids, use it as is for neutralization, or sell it.
Occasionally some leakage to the sewer does occur. The major
contaminants entering the sewer from a sulfuric acid alkylation
unit are generally spent caustics from the neutralization of
the hydrocarbon stream leaving the alkylation reactor.
Hydrofluoric acid alkylation units do not have a spent acid
or spent caustic waste stream. Any leaks or spills that in-
volve loss of fluorides constitute a serious and difficult
pollution problem. Formation of fluosi1icates has also caused
line plugging and similar problems. The major sources of
waste material are the overhead accumulators on the frac-
tionators.
T rends: Alkylation Is replacing polymerization as the means
of converting oleflns to gasoline, because alkylation pro-
duces higher yields of gasoline per unit of olefin feed, and
because the gasoline obtained has a higher octane rating.
Alkylation capacity can be expected to continue growing as
long as the demand for high octane gasoline is increasing.
Isomerization
Alternati ve Subprocesses;
I. I some rate
2. Liquid phase Isomerization
3. Butamer, Penex
*>. Pentafining, Butomerate
5. Catalytic Isomerization
6. Isomerization (BP), Light Naphtha Isomerization
Applicat ion: Isomerization is another processing technique
available for obtaining higher octane motor fuel by converting
the light gasoline materials into their higher octane Isomers.
An indirect route to higher octane is the use of the process
to convert normal butane into isobutane needed for alkylation.
To date the greatest application of isomerization is for the
production of isobutane.
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F-16
Raw Materials: The raw materials consist primarily of normal
butane, and normal pentane and normal hexane from light
straight-run gasoline. Other sources of pentane and hexane
are light straight-run naphthas, natural gasoline, light
catalytic reformate, and hydro-treated light naphtha from
thermal cracking, coking or visbreaking units.
Products: The primary products are isobutane, isopentane,
methylpentane and dime thy I butane. Isopentane has a research
octane number (RON) of 92.3 as compared to 61.7 for normal
pentane. The isomerate produced from most straight-run
naphthas has a clear research octane number of approximately
75 compared to 25 for normal hexane. The octane numbers vary
depending upon the feed composition, extent of re-cycling,
and degree of fractional ion.
P roces s Descript ?uii: I somerate is a typical isomerization
process. The first" section in this process is an I some r
splitter, which separates isoparafflns from normal paraffins.
Normal paraffins are then heated, compressed and passed
through an active hydrogenation catalyst, which selectively
isomerizes normal pentane and normal hexane to their respec-
tive high-octane isomers. The reactants are passed through
a gas-liquid separator, where the hydrogen Is removed for
recycling. The liquids are sent to a stabilizer, where
motor fuel blending stock or synthetic Isomers are removed
as product. The feed preparation fractlonators can be
arranged for once-through or recycle operations.
The isomerization catalyst retains Its high activity for a
long operating period and can be regenerated in place if
it is fouled due to an operational upset. When yields
are computed on a volumetric basis, the ultimate yields for
butane and pentane are greater than 100 percent. Although
the reactions are carried out in a hydrogen atmosphere,
the process neither consumes nor produces any net hydrogen.
The hydrogen suppresses cracking and hydrogenates any
slight amount of cracked materials which may be formed
by side reactions in the process.
Wastes; No specific data are available concerning waste
discharges from isomerization subprocesses, but interviews
with industry personnel and a literature review indicate
there are no major problems. Sulfides and ammonia are not
likely to be present in the effluent. Isomerization wastes
should also be low in phenolics and oxygen demand.
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F-17
Trends: The need for units to fsomerfze normal butane Into
tsobutane will not be as great tn areas where hydrocracklng
Is being installed. When a hydrocracker converts heavy oils
Into gasoline and distillate, the resulting off gas is rich in
Isobutane. All refiners do not believe a separate isomeri-
zation process for the light fractions of gasoline is needed,
and they suggest the stock be charged along with a normal
catalytic feed. Some isomerlzation will occur, and the loss
In octane of the reformer product Is compensated for by the
Increased quantity of material produced.
Solvent Refining
A1ternat i ve Subprocesses;
1. Furfural Refining
2. Duo-Sol
3. Phenol Extraction
k. Udex
5. Furfural Extraction of'Gas Oils
6. S(>2 Extraction
7. Sulfolane Extraction
8. DHSO Extraction
9. Propane Extraction
Appl}cat Ion: As used In this report, solvent refining refers
to methods used primarily to obtain lube oil fractions or aro-
matlcs from feedstocks containing mixtures of hydrocarbons
and undesirable materials such as unstable, acidic, sulfur,
organo-metallic, napthentc, and/or nitrogen compounds.
Charge: A wide variety of feedstocks can be used including
reduced crude, deasphalted oil, naphtha, and catalytic re-
formates. The feedstock varies with the subprocess and de-
si red products.
Products: Refined oils, high-octane blending components, and
high-purity aromatIcs.
Process Description: Solvent refining Is a complicated pro-
cess, even among the generally complex refining processes.
It is physical in nature, with the chemical character of the
various hydrocarbons remaining unchanged. The hydrocarbon
-------
F-18
mixtures are separated on the basis of their relative solu-
bilities without specific regard to volatility. The phy-
sical properties of the solvent and the desired products
govern the specific nature of each subprocess, but there are
several general operations common to most of them:
1. Drying and/or deaeratlon of the feedstock.
2. Extraction using countercurrent solvent contacting.
3. Separation of the bulk of the solvent from the
product by heating and fractionation or evaporation.
k. Removal of traces of solvent from the product by
steam stripping or vacuum flashing.
5. Purification of the solvent.
Equipment required for these operations includes contact or
extraction towers, fractlonators, settling drums, steam strip-
pers, gas condensers, and atmospheric and pressurized flash
towers.
The Udex process for high-purity aromatics uses a mixture of
glycols and water as solvent. The solvent is fed at the top
of a countercurrent extraction column, and the hydrocarbon is
fed at an intermediate point, with hydrocarbon reflux at the
bottom. The rich solvent is taken to a stripper, where the
dissolved aromatics are removed and the solvent recirculated
to the extraction column. Vapors from the stripper are con-
densed, with the formation of two liquid phases. Part of the
water phase is used to wash traces of dissolved glycols from
the raffinate, and the remainder is returned to the stripper.
The hydrocarbon phase from the stripper Is a mixture of aro-
matfcs from which the benzene, toluene, and a mixed ethylben-
zene-xylene fraction are separated by distillation.
Process flow In a lube oil solvent refining process Is similar,
except that the desirable lube oil fraction is in the raffinate
rather than the extract stream, and solvent recovery is more
complex.
Wastes: The major potential pollutants from the various
solvent refining subprocesses are the solvents themselves.
Many of the solvents, such as phenol, glycols, and amines,
can produce a high BOD. Under ideal conditions the solvents
are continually recirculated with no losses to the sewer.
Unfortunately, some solvent is always lost through pump
seals, flange leaks, etc. The main source of wastewater
is from the bottom of fractionation towers. Oil and sol-
vent are the major waste constituents.
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F-19
Trends: Solvent extraction capacities can be expected to
increase as quality requirements for all refinery products
become more stringent, as the demand for lube oils grows,
and as the petrochemical industry continues to require
increasing quantities of aromatlcs.
Dewaxlng
AlternatIve Subprocesses:
1. Solvent Dewaxlng (MEK)
2. Propane Dewaxing
3. Pressing and Sweating
k. Urea Dewaxing
5. Di-Me Solvent Dewaxing (all foreign installations)
ApplI cat I on: Removal of wax from lube oil stocks to produce
lubricants with low pour points and to recover wax for
further processing.
Charoe: Either virgin distillates or decarbonized residual
stocks of practically any viscosity In the raw or refined
state from any crude source.
Products; Dewaxed oils with low pour points, and microcrystal-
Tine wax.
Process Description; Except for "Pressing and Sweating", de-
waxing subprocesses use solvents to promote wax crystallization.
The first step in "Pressing and Sweating" Is to chill the waxy
distillate to crystallize the wax. Most of the oil is re-
moved by squeezing out from the wax cake when the crystallized
wax is pressed. After pressing, the wax cakes are slowly
heated and sweated, during which the remaining oil drains
from the wax crystals.
Solvent dewaxlng, using methyl ethyl ketone (MEK), is the most
widely used subprocess. Essential equipment in MEK dewaxing
is as follows :
1. Direct-expansion ammonia chillers.
2. Double-pipe scraped-surface exchangers for solvent
dewaxing and wax recrystallizlng.
3. Continuous dewaxing filters.
k. Tubular exchangers to chill the wash solvent.
5. Product recovery systems.
6. Solvent-water separating and recovery systems.
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F-20
In operation, the solvent is introduced into the waxy dis-
tillate stream at selected points in the chilling cycle to
insure the wax crystal structure and liquid viscosity most
suitable for filtration. The chilled mixture flows from
the double-pipe chillers through a filter feed tank to en-
closed drum-type vacuum filters. A wax-free oil filtrate
is drawn through the filter cloth to tanks in which the
vacuum is maintained. The wax cake deposited on the filter
Is washed continuously with cold solvent to produce a low
ol1-content wax.
The filtrate is pumped through double pipe exchangers to
evaporators for recovery of the solvent. Heat for evaporating
the solvent from the dewaxed oil solution may be supplied by
either steam or fired heaters.
Propane dewaxing and DI-Me Solvent dewaxing are similar to
the above subprocess, with propane or 01-Me Solvent being
used instead of methyl ethylketone. Urea dewaxing differs
in that no refrigeration is used.
Wastes; Leaks and spills are the major source of wastes in
solvent dewaxing subprocesses; spillage of MEK can result
In a high BOD. Propane dewaxing is a cleaner process than
MEK dewaxing with respect to water pollution, but may pro-
duce some air pollution from the "smokeless" flares asso-
ciated with the process.
Trends: Solvent dewaxing wilt completely replace pressing
and sweating. Dewaxing capacity should increase as the
demand for waxes and low pour point oils increases.
Hyd retreating
Alternative
Subprocesses;
1. Unifining
2. Hydroflntng
3. Hydrodesul-
furization
k. Ultrafinlng
5. Autofining
6. Distillate
Hydrogenation
Charge
Cracked or Straight-Run
Fractions
Any petroleum fraction
from virgin Naphthas to
waxes
Virgin or cracked
naphthas, oi1
Naphtha, gas oiIs
SR Distillates
Naphtha, furnace oil
Product
Feedstocks and finished
products
Feedstocks and finished
products
Reformer feed, finished
products
Feedstocks and finished
products
Gasoline, kerosene
Naphtha, furnace oil
-------
Alternative
Subprocesses:
7. Ferrofining
8. Gulf HOS
9. Gulf Hydro-
treating
10. Gulfinishing
11. Selective
Hydrogenation
12. Trickle
Hydrodesul-
furization
F-21
Charge
Refined lube oil stocks
High-sulfur stocks
Raw Disti Hates or
deasphalted oiIs
Solvent extracted or
raw paraffinic neutral
or bright stocks
Cracked gasoline
Gasoline-deasphalted
oils
Product
Finished lube oils
Low sulfur fuels or
cracker charge
Finished gasoline-
oiIs-waxes
Finished lube oils and
waxes
Finished gasoline
Cracking feeds and fin-
ished products
Applteat ton: Hydrotreattng is used to saturate olefins, and
to remove sulfur, nitrogen and oxygen compounds and other con-
taminants from either straight-run or cracked petroleum frac-
tions.
Charge: Practically all crude otl fractions from light naph-
thas through waxes and lube oils. Naphthas (including gaso-
line) account for the largest share of hydrotreating charge
stocks.
Products; Materials having low sulfur, nitrogen and olefin
contents and improved stability.
P rocess Descrtpt1 on; The principal difference between the
many subprocesses is the catalyst; the process flow is similar
for practically all the subprocesses. The most widely used
hydrotreating subprocess is Untfining, which is designed to:
1) pretreat catalytic reforming feedstock;
2) improve odor, color, gum and storage stability of
all distillates;
3) improve burning properties of furnace oils, cetane
number of diesel fuels, and lead susceptibility of
gasoline;
*0 pretreat catalytic cracking feedstock.
The major equipment units in the unifining process are the
reactor and the fractionator. The feed is combined with
recycle hydrogen, heated to a reaction temperature, and
-------
F-22
charged to the reactor. The reactor products are cooled
and enter a hydrogen separator, from which recycle hydrogen
is taken overhead for return to the system. The separator
bottoms flow through a low-pressure separator, where addi-
tional gases are removed, and then to a fractionator, for
separation of light naphtha and hydrogen sulfide from the
des i rabIe feeds tock.
The primary variables influencing hydretreating are hydrogen
partial pressure, process temperature, and contact time. An
increase in hydrogen pressure gives a better removal of un-
desirable materials and a better rate of hydrogenation.
Makeup hydrogen requirements are generally high enough to
require a hydrogen production unit. Excessive temperatures
increase the formation of coke, and the contact time is set
to give adequate treatment without excessive hydrogen usage
and/or undue coke formation. For the various hydrotreating
processes the pressures range from 100 to 3000 psig. Temp-
eratures range from less than 350°F to as high as 850°F,
with most processing done In the range of 600°F to 800°F.
Hydrogen consumption is usually less than 200 scf per barrel
of charge.
Hydrotreating Processes can reduce the sulfur content by
80-95 percent, with the average being about 90 percent.
Nitrogen usually requires more severe conditions, but reduc-
tions of 80-90 percent are feasible.
Wastes; The strength and quantity of waste depends on the
subprocess used and the material being hydrotreated. Waste
streams come from overhead accumulators on fractionators
and steam strippers and sour water stripper bottoms. The
major pollutants are sulfides and ammonia. Phenols may also
be present if the boiling range of the feed is high enough.
Trends: Hydrotreating was first used on lighter materials
(naphthas), but with the accumulation of operating experi-
ence and the development of better catalysts, it has been
applied to increasingly heavier petroleum fractions. Hy-
drotreating use is increasing because the process can be
applied to almost any sour feedstock, is flexible, and eli-
minates contaminants of concern to refineries from an opera-
ting standpoint and to the general public from an aesthetic
standpoint. Increased public pressures to reduce air and
water pollution will continue to enhance the overall value
-------
F-23
of hydrotreating. Consequently, hydrotreating processes are
being Installed in more refineries than any other process ex-
cept hydrocracking.
Peasphalting
A11 e mat I ve S ufa p roces s es; Propane Ocas phalt ing, Deasphalting
and Fractionation, Solvent Decarbonizing
Applicatton: Propane deasphalting separates asphalts or
resins from viscous hydrocarbon fractions; it can be modi-
fied to segregate heavy or medium neutral fractions by
extraction with propane. Solvent Decarbonizing recovers
parafflnlc catalytic cracking stock from distillation resi-
dues, thus Increasing yields of light products at the ex-
pense of heavy fuel oil.
Raw Materials: Atmospheric or vacuum reduced crude.
Products; Deasphalted or Decarbonized Oil, and Asphalt or
Heavy Fuel Blending stocks.
P roces s Des c r tD11on: The major equipment Includes an atmos-
phe r Ic deaspha1tIng tower and separate vacuum strippers for
the tower overhead and tower bottoms products. The vacuum
residue and liquid propane are pumped to the deasphalting
(extraction) tower at controlled rate and temperature, pro-
ducing a deasphalted oil solution overhead and an asphalt
bottoms product, by separation based on different solubili-
ties in propane. The overhead and bottoms streams both of
which contain propane, are processed separately. The over-
head is passed through a propane evaporator and the bottoms
through a flash drum, for propane removal. The propane from
both steps is recycled. The two streams are then vacuum
stripped for further removal of propane and other impuri-
ties.
Propane Fractionation is a two-stage extraction process iden-
tical with the above process except that an additional ex-
traction tower and recovery system are added for each addi-
tional product stage. Propane Fractionation is usually ap-
plied to a "long" vacuum residue and produces a medium to
heavy neutral fraction in addition to cyclinder bright stock
and asphalt.
-------
Wastes: No specific data is available concerning waste dis-
charges from deasphaltlng processes. Indications are that
no water wastes result from the actual deasphaltlng step, but
wastewater is discharged from the overhead condensers on the
steam strippers that are used to separate the asphalt, deas-
phalted of 1, and propane. The "sour water" from the conden-
sers probably contains small amounts of sulfides, oil and
ammonia. At times spills of asphalt may occur and set up
in the sewer system. If the sewer becomes blocked, the only
solution is to build a new sewer.
Trends: The factors influencing the future application of
deasphalting are essentially the same as for solvent refining
because in many cases solvent refining feedstocks require
deasphalting as a pretreatment. Thus deasphalting capacity
can be expected to increase as refinery product quality re-
quirements become more stringent, as demand for lube oils,
grows, and as petrochemical aromatic feedstock requirements
increase.
Drying and Sweetening
Alternative Subprocesses;
1. Copper Sweetening
2. Electrical Distillate Treating
3. Merox
k. Soluttzer
5. Adsorptive Drying and Sweetening
6. Bender (Petreco Bender)
7. Distillate Treating
8. Doctor Sweetening
9. Dualayer Distillate Process
10. Electrolytic Mercaptan
11. Girbotol
12. Glycol - Amine Gas Treating
13. Inhibitor Sweetening
14. Mercapsol
15. Phosphate Desulfurization
16. Petreco Locap Gasoline Sweetner
Application: To remove sulfur compounds, including hydrogen
sulfide and mereaptans; to improve color, odor, oxidation
stability, and inhibitor response. Water, carbon dioxide,
and other impurities are also removed in some of the sub-
processes.
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F-25
Charge; A few subprocesses treat sour gases, but most treat
liquid distillates including gasoline, naphtha, kerosene, jet
fuel, and domestic heating oils.
Products; Hydrocarbon products of reduced sulfur content
and low in water and other impurities. They are suitable
for blending, shipping, or further processing.
Process Description; The method used in drying and sweetening
varies greatly with each particular subprocess. "Sweetening"
pertains to the removal of hydrogen sulflde, mereaptans, and
elemental sulfur from hydrocarbon products. These substances
impart a foul odor, and mereaptans seriously decrease the
octane number of gasoline by reducing the susceptibility to
tetraethyl lead. Elemental sulfur in the presence of mer-
captans causes corrosion.
There are three major sweetening methods:
1) oxidation of mercaptans to disulfides
2) removal of mercaptans, and
3) destruction and removal of other sulfur compounds
along with mercaptans, hydrogen sulfide and sulfur
The last of these methods is desulfurization and is generally
accomplished through hydretreating.
Processes that convert mercaptans into less odoriferous dt-
sulfides include copper sweetening, Doctor Sweetening, Bender,
and Herox. Mercaptans are removed completely by being dis-
solved and carried away in an extracting agent or by adsorp-
tion on clay. The Mercapsol and Solutlzer processes dissolve
mercaptans; most of the sweetening processes use solubility
promoters and caustic soda. The washing solutions are regen-
erated by heating and stream stripping. In Adsorptlve Drying
and Sweetening the mercaptans, other sulfur compounds, and
water are adsorbed onto clay beds. Water removal (drying)
is accomplished in most of the other methods through the
use of salt fiIters.
Except for Adsorptlve Drying and Sweetening the above sub-
processes rely on gravitational settling to separate the
caustic or other treating solution from the product. In
cases where the treating solution and product are slow to
287-028 O - 63 - 13
-------
F-26
separate, Distil late Treating or Electrical Distillate
Treating can be used. These subprocesses use an electric
field to enhance separation of the treating solution and
product.
The Girbotol and Glycol-Amlne Gas Treating subprocesses are
used primarily for treating sour gases. Both processes use
aqueous solutions of ethanolamines to scrub the sour gases
in an absorber.
Wastes: The most common waste stream from drying and sweet-
ening operations is spent caustic. The spentcaustic is
characterized as phenolic or sulfidic depending on which
Is present in the largest concentration. Whether the spent
caustic is actually phenolic or sulfidic is mainly determined
by the product stream being treated. Phenolic spent caustics
contain phenol, cresols, xylenols, sulfur compounds, and
some neutral oils. Sulfidic spent caustics are rich in sul-
fides, but do not contain any phenols. These spent caustics
have very high BOD and COD.
Other waste streams from the process result from water washing
of the treated product and regeneration of the treating
solution such as sodium plumbite (Na£ Pb02) in Doctor Sweet-
ening. These waste streams wilt contain small amounts of oil
and the treating material such as sodium plumbite (or copper
chloride from copper chloride sweetening).
The treating of sour gases produces a purified gas stream,
and an acid gas stream rich in hydrogen sulfide. The h^S-
rich stream can be flared, burned as fuel, or processed for
recovery of elemental sulfur. The ethanolamines used in
treating the sour gases are continuously resued, and very
little of the treating solution reaches the sewer.
Trends; As air pollution agencies increase their efforts to
control sulfur emissions to the atmosphere, the restrictions
on sulfur content in fuels can be expected to tighten. This
will generate a strong trend to replacement of the sweet-
ening processes by more hydrotreating (desulfurization), be-
cause hydrotreattng removes almost all sulfur compounds and
not just hydrogen sulfide, mercaptans, and elemental sulfur.
Nevertheless, on certain feedstocks sweetening will continue
to be used because it will be as effective as and more eco-
nomical than hydrotreating. Those processes producing high
waste loads (Doctor Sweetening, etc.) are being replaced by
the lower waste-producing processes such as Bender and Herox.
-------
F-27
Wax Manufacture
Al ternatIve Subprocesses;
1. Wax Fractlonatton
2. Wax Manufacturing, MIBK
Application; For the production of waxes of low oil content.
Charge; High oil-content wax fractions directly from crude
fract1onation and/or waxes from dewaxlng of lube oils.
Products: Paraffin and microcrystalline waxes of low oil-
content, high melting point, and other properties charac-
teristic of high-quality waxes.
P roces s Des c rIj>tIon; The processing steps of Wax Fractfona-
tion and Wax Manufacturing, MIBK are very much the same, and
in most respects are similar to MEK Dewaxlng. Each of these
wax manufacture subprocesses makes use of double-pipe scraped-
surface chillers, and primary and secondary rotary vacuum
filters. In the most common method of wax finishing, Wax
FractIonation, a mixture of th& wax-bearing charge stock
with a substantial amount of solvent is chilled in double-
pipe scraped-surface chilling equipment to a temperature
suitable for the production of dewaxed oil of the desired
pour point. The mixture is then filtered, and the oil-bearing
solution in the wax cake is washed continuously from the wax
by displacement with cold solvent. The wax cake is contin-
uously discharged from the primary filters and heated until
the wax is totally dissolved In the solvent. Additional warm
solvent Is mixed Into the solution, and the mixture Is cooled
In double-pipe scraped-surface equipment to a temperature
suitable for crystallization of the desired wax fractions.
The recrystallized wax is then separated by means of a second
filter, on which the wax receives a final wash. The wax cake
from this filter is pumped to the solvent recovery system
from which the solvent-free product wax is recovered. This
wax may be sent to a hydretreating unit as a finishing step.
The filtrate from the second filter, containing oil and un-
desirable soluble wax fractions, is pumped to the solvent re-
covery system from which the "soft" wax is delivered to stor-
age tanks.
Wastes: No specific data are available, but there is no
reason to believe that wastes from wax finishing are a sig-
nificant source of waste material. Solvents and oil enter
-------
F-28
the wastewater system mainly through leaks. If wax particles
enter the sewer system, they may interfere with settling op-
erations in the effluent treatment plant and also may clog
the sewers.
Grease Manufacture
Application! For the manufacture of a wide range of lubrl-
catTrig greases.
Charge; Various alkali earth metal hydroxides and fatty acids
for soap manufacture, together with petroleum oils, waxes, or
other materials.
P roducts; Lubricating greases with a sodium, calcium, alu-
minum, lithium, or barium soap base; mixed-base or non-soap-
base greases.
Process Description; The process involves accurate weight
cont rol of a11 feed" materia 1s , intimate mixing, rapid heating
and cooling, together with milling, dehydration and deaera-
tion, if required. The major equipment consists of an oil
circulation heater, high dispersion contactor, scraper kettle,
and a grease polisher.
The soap Is prepared by charging the ingredients to the con-
tactor and heating the mixture. Saponification time varies
with the type of soap, but is generally between 1/2 and 2
hours. The petroleum oil and additives are mixed with the
soap base either in the contactor or in a scraper kettle.
Heavier greases are normally finished In a scraper kettle
because of the high viscosity which prevails at finishing
temperatures.
The finished grease may be packaged directly, or processed
further In a grease mill and polisher, as required by the
specifications of the final product.
Wastes: Only very small volumes of wastewater are discharged
from a grease manufacturing process. A small amount of oil
Is lost to the wastewater system through leaks in pumps. The
largest waste loading occurs when the batch units are washed.
This results in soap and oil discharges to the sewer system.
-------
F-29
Trends; Because of an increase In sealed grease fittings in
automobiles and longer lasting greases, a slight decline in
grease production is expected through 1975.
Lube Oil Finishing
Alternative Subprocesses;
1. Continuous Contact Filtration
2. Percolation Filtration
3. Hydretreating
App Heat ion; Principally for the production of motor oils
and other lubricants, but the subprocesses can also be used
to finish waxes and other fractions.
Charge; Petroleum fractions in the lubricating oil range
that have been solvent extracted (and possibly acid treated).
Solvent-extracted stocks usually undergo dewaxing before
lube oil finishing.
Products; Finished lube oils characterized by excellent
color and odor. The oils are ready for blenlng and com-
pounding.
Process Description: Although solvent treating eliminates
most of the dark materials in lube oil stocks, It Is usually
necessary to further refine the lube oils by clay treatment
and at times acid treatment. The subprocesses listed are
methods of clay treatment. In addition to or in place of
solvent, acid, and clay treating, many lube oils are treated
in dry!ng-and-sweetenlng or hydrotreating units.
Acid and clay treatment are used mainly to improve the color
of lubricating oils. After acid treating the lube oil must
be neutralized. Neutralization is usually accomplished by
contact filtration, which further decolorizes the oil while
neutralizing it.
In Continuous Contact Filtration the clay adsorbent is added
to the oil charge and the slurry enters a pipe still heater
where maximum contact temperature is obtained In a once-
through operation. From the pipe still the slurry enters a
stripping tower, and steam is added to facilitate the strip-
ping action. The slurry Is drawn continuously from the
bottom of the tower to a vacuum filter. The filtered oil
-------
F-30
ts charged to a high vacuum stripper to furnish additional
product control. Percolation Filtration consists of fil-
tering the oil through either Fuller's earth, activated
bauxite, or other clay. When the filtrate no longer meets
product specifications, oil flow is stopped, the bed is
washed with naphtha, and the clay is conveyed to a kiln,
where the carbonaceous deposits of oil and impurities are
burned off prior to its return to the filter for another
cycle.
Wastes; Acid treatment of lubricating oils produces acid-
bearing wastes occurring as rinsewaters, sludges, and dis-
charges from sampling, leaks, and shutdowns. The waste
streams are also high in dissolved and suspended solids,
sulfates, suifonates, and stable oil emulsions. This is a
very difficult waste problem.
Handling of the acid sludge can create additional problems.
Some refineries burn the acid sludge as fuel. Burning the
sludge produces large volumes of sulfur dioxide that can
cause air pollution problems. Other refineries neutralize
the sludge with alkaline wastes and discharge it to the
sewer system, resulting in both organic and inorganic pollu-
tion. The best method of disposal Is probably processing
to recover the sulfurlc acid, but this also produces a
wastewater stream containing acid, sulfur compounds and
emulsified oil.
Clay treatment results in only small quantities of wastewater
being discharged to the sewer. Clay, free oil, and emulsified
oil are the major waste constituents. However, the operation
of the clay recovery kilns Involves potential air pollution
problems of hydrocarbon and paniculate emissions. Spent clays
usually are disposed of by landfill.
Trends; Acid and clay treatment of lube oils is gradually
being replaced by hydrotreating methods. Acid treatment in
particular is being phased out rather rapidly.
Blending and Packaging
Application: Blending Is used to produce finished petroleum
products meeting required specifications at the lowest pos-
sible cost. Packaging places the finished produced into
containers which industries, retailers, and consumers require.
-------
F-31
Charge; Various refinery products, and additives to improve
product quality.
Products; All the products produced in a petroleum refinery.
Process Descr1ption: Finished motor and aviation gasolines
are blends of straight-run and cracked gasoline, reformate,
alkylate, and other components. The percentage of each of
these components varies with the quality requirements of the
finished gasoline. Additives are also blended in to improve
the fuel. The most common additive used in gasoline is
tetraethyl lead, which is added to increase resistance to
engine knock. Other additives are ant?-rust, antl-oxidant,
and anti-icing compounds.
Diesel fuels, lubricating oils, greases, waxes, and asphalt
are other major products that are blends of various refinery
streams and additives. Blending is accomplished while the
products are in bulk form.
Packaging puts the large volumes of products into containers
that can be used by industry, wholesalers, retailers, and
individual consumers, industrial and wholesale accounts
require very little packaging because most products are sold
in large volumes.
Packaging for individual consumers is done both by refineries
and by customers or contract packagers. Refineries tend to
restrict their packaging to high-volume, strong brand-name
products, such as lubricating oils.
Wastes: These are relatively clean processes because care
is taken to avoid loss of product through spillage. The
primary source of waste material is from the washing of rail-
road tank cars or tankers prior to loading finished products.
These wash waters are high in emulsified oil.
Tetraethyl lead is the major additive blended into gasoline
and it must be carefully handled because of its high toxl-
city. Sludges from finished gasoline storage tanks can con-
tain large amounts of lead and should not be washed into
the wastewater system.
Trends; Increased use of automatic proportioning facilities
for product blending. Trend toward contracting out of pack-
aging of lower-volume products that are less suitable to
highly-automated operation.
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F-32
Hydrogen Manufacture
Alternative Subprocesses; Partial Oxidation, Steam Reforming,
Hypro.
Application: For the manufacture of the hydrogen needed for
refining operations, such as hydrotreating and hydrocrack ing,
and for petrochemical feed stocks. Hydrogen manufacture is
also the source of feed stock for production of ammonia or
methanol.
Charge; The primary raw materials are natural gas, refinery
gas, propane, butane, etc. Heavy fuel oil can be used in
the partial oxidation process.
P roducts: Moderate to high-purity hydrogen. A typical
analysis from a steam reforming process shows 98 percent
hydrogen with less than 10 parts per million of carbon di-
oxide.
P rocess DescrIpt I on: The most widely used subprocess is
steam re fo rmIng, wh i ch utilizes refinery gases as a charge
stock. The charge is purified to remove sulfur compounds
that would temporarily deactivate the catalysts.
The desulfurized feedstock is mixed with superheated steam
and charged to the hydrogen furnace, which consists of a
vertical combustion chamber with suspended alloy tubes con-
taining a nickel-base catalyst. On the catalyst the hydro-
carbons are converted to hydrogen, carbon monoxide, and
carbon dioxide. The furnace supplies the heat needed to
maintain the reaction temperature.
The gases from the furnace are cooled by the addition of
condensate and steam, and then passed through a converter
containing a high- or low-temperature shift catalyst de-
pending on the degree of carbon monoxide conversion desired.
Carbon Dioxide and hydrogen are produced by the reaction
of the monoxide with steam.
The gas mixture from the converter is cooled and passes
to a hydrogen purifying system where carbon dioxide Is re-
moved by the Girbotol Process. The carbon dioxide is absorbed
into the amine solution and later driven off to the atmosphere
by heating the rich amine solution in the reactivator.
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F-33
Since some refining processes require a minimum of carbon
oxides in the product gas, the oxides are reacted with hy-
drogen in a methanation step. This reaction takes place in
the methanator over a nickel catalyst at elevated tempera-
tures.
Hydrocarbon impurities in the product hydrogen usually are
not detrimental to the processes where this hydrogen will
be used. Thus, a small amount of hydrocarbon is tolerable
in the effluent gas.
Wastes; Information concerning wastes from this process are
not available. However, the process appears to be a rela-
tively clean one. In the steam reforming subprocess a po-
tential waste source is the desulfurization unit, which is
required for feedstock that has not already been desulfur-
ized. This waste stream would contain oil, sulfur compounds,
and phenol. In the partial oxidation subprocess free carbon
is removed by a water wash. Carbon dioxide is discharged
to the atmosphere at several points in the subprocess.
Trends: Hydrogen requirements of the rapidly growing hydro-
cracking and hydretreating processes in many instances exceed
the by-product hydrogen available from catalytic reforming
units. This has increased the demand for separate hydrogen
manufacturing units. Since hydrocracking and hydrotreating
are expected to grow more rapidly than other refinery pro-
cesses, the demand for hydrogen manufacturing units should
continue to be strong.
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