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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                                S-l


                               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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                            S-3

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.

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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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                                 S-7

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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                                S-8
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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                                 S-9
                                        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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                                 S-10

     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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                                S-11

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%.

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                        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.

-------
                            -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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                                 -9-

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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                                -18-

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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                                -21-

     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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                                -22-

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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                                -23-

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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                                -25-

     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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                                -27-

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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                                  -28-

     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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                                -29-

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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                                -30-

                      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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                                -31-

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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                                 -32-

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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                                -33-

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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                                -34-

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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                                -35-

          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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                                -36-

     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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                                -37-

     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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                                -38-

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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                                -39-

     .'•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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                                -40-

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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                                -1*3-

     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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                                -kk-

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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                                -1.5-

     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

-------
                                -46-

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

-------
                                -1.7-

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,

-------
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.

-------
                        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

-------
                                -50-

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.

-------
                                -51-

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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-------
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                                                                                                               O

-------
                  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

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           DRYING AND  SWEETENING
             (COPPER  SWEETENING)
                    FIGURE 19
Prepared for F.W.P.C.A.
HYDROCARBON PROCESSING 1966

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              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

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                        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

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             GREASE MANUFACTURE
           (GREASE  MANUFACTURING)
                     FIGURE 22
  Prepared for F.W.P.C.A.
HYDROCARBON PROCESSING 1966
287-028 o - 68 - 9

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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

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             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

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APPENDIX.     C

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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.

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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.

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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.

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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.

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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

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APPENDIX    D

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                             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.

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                          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.

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                           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

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     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.

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                            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.

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                                 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.

-------
                               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).

-------
                               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;

-------
                                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).

-------
                                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),

-------
                               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

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                           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

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       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

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                           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

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                                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.

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     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

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                           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.

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                                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

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                                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.

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                                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

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                               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.

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                           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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