EPA-R2-72-001
DECEMBER 1972 Environmental Protection Technology Series
Evaluation of Waste Waters
from Petroleum and
Coal Processing
^ PRO^°
Office of Research and Monitoring
U.S. Environmental Protection Agency
Washington, D.C. 20460
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and
Monitoring, Environmental Protection Agency, have
been grouped into five series. These five broad
categories were established to facilitate further
development and application of environmental
technology. Elimination of traditional grouping
was consciously planned to foster technology
transfer and a maximum interface in related
fields. The five series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5, Socioeconomic Environmental Studies
This report has been assigned to the ENVIRONMENTAL
PROTECTION TECHNOLOGY series. This series
describes research performed to develop and
demonstrate instrumentation, equipment and
methodology to repair or prevent environmental
degradation from point and non-point sources of
pollution. This work provides the new or improved
technology required for the control and treatment
of pollution sources to meet environmental quality
standards.
-------
EPA-R2-72-001
December 1972
EVALUATION OF WASTE WATERS
FROM PETROLEUM AND COAL PROCESSING
By
Professor George W. Reid
and
Dr. Leale E. Streebin
Project 12050 DKF
Project Officer
Mr. Leon Myers
Robert S. Kerr Water Research Center
Environmental Protection Agency
P. 0. Box 1198
Ada, Oklahoma 74820
Prepared for
OFFICE OF RESEARCH AND MONITORING
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
For sale by the Superintendent of Documents, U.S. Government Printing Office
Washington, D.C. 20402 - Price $2.7*
-------
EPA Review Notice
This report has been reviewed by the Environmental Protection Agency and has been
approved for publication. Approval does not signify that the contents necessarily
reflect the views and policies of the Environmental Protection Agency, nor does
mention of trade names or commercial products constitute endorsement or recommenda-
tion for use.
ii
-------
ABSTRACT
This report presents an evaluation on pollution problems, abatement procedures and
control techniques relevant to the petroleum and coal industries. Petroleum wastes
are discussed under three broad sections: Drilling-Production, Transportation and
Storage, and Refining. Each section is introduced with background information. With-
in each section, petroleum wastes are identified as to their source, volume, and com-
position, and waste treatment methods are discussed.
The results of a field study of three small refineries are reported, providing additional
information which delineates the characteristics of waste streams from individual pro-
cesses within the refinery.
Coal mining, coal processing, and coal utilization, the wastes associated with each,
and the corresponding control measures are discussed. Acid mine drainage, the most
significant pollution problem from coal mining, and possible control measures are
presented. The major pollution problems associated with coal processing originate
from coal cleaning, the coking process, and refuse disposal. The principal pollutants
in water discharged from the processing of coal are suspended solids usually in the
form of fine clay, black shale, and other minerals commonly associated with coal.
Coal and coke are used as sources of carbon for chemical reduction and energy sources
in the metallurgical and power industries. The production of coke by carbonization
of coal produces a waste water that is high in phenols, ammonia, and dissolved or-
ganics. Biological treatment processes appear to be very promising for the control of
these pollutants.
This report was submitted in fulfillment of project number 12050 DKF between the
Environmental Protection Agency and the University of Oklahoma, School of Civil
Engineering and Environmental Science.
n i
-------
CONTENTS
Section Page
I SUMMARY AND RESEARCH NEEDS 1
II INTRODUCTION 3
PETROLEUM SECTION
III DRILLING-PRODUCTION 5
A. Oil Field Brine Disposal and Land Pollution 5
1 . Surface Disposal of Brine 5
2. Waste Disposal by Injection Into Underground Formations 9
3. Typical Waters and Treatment Procedures 11
4. Detecting Subsurface Brine Pollution 15
B. Marine Oil Field Wastes and Pollution 19
1 . Introduction 19
2. Forecast of Offshore Development 20
3. Natural Seepages 21
4. Drilling Platforms for Offshore Operations 23
5. Marine Oil Pollution 23
IV TRANSPORTATION AND STORAGE OF PETROLEUM AND
PETROLEUM PRODUCTS 31
A. Waterborne Traffic 31
1 . Extent of Waterborne Traffic 31
2. Vessels as Pollution Sources 31
3. Reducing Vessel Pollution 33
B. Waste Oils 34
1. Gasoline Service Stations 34
2. Tank-cleaning Facilities 34
3. The Oily Waste Industries 35
C. Industrial Transfer and Storage 35
1. Pipelines 35
2. Seafloor Tanks for Oil Storage 36
3. Oil Storage in Sub-seafloor Cavity 37
4. Oil Transfer from Supertanker 38
V REFINING 39
A. Background 39
1. Oil Refining Technology 39
2. Effluent Sources and Characteristics: Oily Waste Water 39
3. Effluent Sources and Characteristics: Non-oily Waste
Water 46
4. Forecast 48
-------
Section Pq9e
B. Pollution Profile 55
1 . Waste Quantities 55
2. Waste Reduction, Treatment, and Costs 58
3. Water Use and Reuse 91
4. Instrumentation °"
VI FIELD STUDY OF SELECTED REFINERIES 103
A. Objective 1 °3
B. Description of Refineries 103
C. Sampling and Sample Analyses 104
D. Discussion 1 04
COAL SECTION
VII BACKGROUND 113
VIII MINING 119
IX PROCESSING 139
A. Coal Washing and Cleaning 139
1. Wet Tables 140
2. Jig Washing 140
3. Air Cleaning 141
4. Classifier-Type Cleaners 141
5. Launders 141
6. Flotation 141
7. Dewatering Screens 144
8. Thickeners 144
9. Cyclones 148
10. Centrifuges 148
11 . Thermal Dryers 148
12. Filtration 148
13. Flocculation 151
14. Desliming 151
B. Water Handling 151
C. Water Clarification 153
D. Coking 153
1 . Disposal by Dilution 158
2. Closed Systems and Evaporation in the Quenching
Station 158
3. Chemical Treatment 158
4. Biological Treatment 158
5. Adsorption by Activated Carbon 159
VI
-------
Section
6. Treating Phenolic Waste in a Municipal Sewage
Treatment Plant 159
7. Multi-Stage Process 159
8. Koppers-Loe Process 163
X UTILIZATION 171
XI ACKNOWLEDGEMENTS 187
XII REFERENCES 189
XIII GLOSSARY AND ABBREVIATIONS 203
VII
-------
FIGURES
PAGE
] PROCESSING PLAN FOR TYPICAL MINIMUM 41
REFINERY
2 PROCESSING PLAN FOR TYPICAL INTERMEDIATE 42
REFINERY
3 PROCESSING PLAN FOR TYPICAL COMPLETE 43
REFINERY
4 SCHEMATIC CROSS SECTION OF AN OXIDATION 66
POND
5 BIOLOGICAL WASTE TREATMENT SYSTEM 67
EMPLOYING COOLING TOWERS
6 TYPICAL DESIGNS OF OXIDATION DITCHES 69
7 ESSENTIAL PARTS OF A TRICKLING FILTER 72
PLANT
8 VARIOUS COMBINATIONS FOR TRICKLING FILTER 73
OPERATIONS
9 CROSS SECTION OF A TYPICAL TRICKLING 74
FILTER
10 CONVENTIONAL ACTIVATED SLUDGE PROCESS 76
1] STEP AERATION IN ACTIVATED SLUDGE PROCESS 77
12 FLOW DIAGRAM OF ENID SEWAGE TREATMENT 94
PLANT, ENID, OKLAHOMA
13 PLANNED PROGRAM OF RESEARCH FOR ACID 125
MINE DRAINAGE
14 FLOW DIAGRAM OF ACID MINE WATER MOBILE 129
TREATMENT PLANT
15 FLOW DIAGRAM OF U.S. STEEL MINE DRAINAGE 131
TREATMENT PLANT
viii
-------
FIGURES
PAGE
16 FLOW DIAGRAM OF U.S. STEEL MINE DRAINAGE 132
TREATMENT PLANT
17 FLOW DIAGRAM OF U.S. STEEL MINE DRAINAGE 132
TREATMENT PLANT
18 FLOW DIAGRAM OF COMPLETE BIOCHEMICAL 134
OXIDATION AND LIMESTONE NEUTRALIZATION
PROCESS
19 FLOWSHEET OF THE LIMESTONE NEUTRALIZATION 136
PROCESS
20 FLOW DIAGRAM OF AN ION EXCHANGE PILOT 137
PLANT
21 SCHEMATIC OF A TWO STAGE AIR CLEANING 142
PROCESS
22 FINE COAL LAUNDER 143
23 FLOW DIAGRAM OF ULTRA FINES RECOVERY BY 145
FLOTATION
24 FLOWSHEET BY DEWATERING OPERATION ON A 146
VIBRATING SCREEN
25 MATERIALS BALANCE FLOWSHEET OF A 147
THICKENING OPERATION
26 DESLIMING RAW AND CLEAN COAL USING 149
CYCLONES
27 FLOWSHEET OF A ROTATING DRUM CENTRIFUGE 150
28 MATERIALS BALANCE FLOWSHEET FOR TYPICAL 152
CENTRIFUGING OPERATION
29 FLOW DIAGRAMS OF TYPICAL WATER 154
CLARIFICATION METHODS
ix
-------
FIGURES
PAGE
30 FLOW DIAGRAMS OF TYPICAL WATER 155
CLARIFICATION METHODS
31 FLOW DIAGRAM OF TYPICAL WATER 156
CLARIFICATION METHODS
32 FLOWSHEETS SHOW VARIOUS POSSIBLE 160
METHODS FOR REMOVING PHENOL
33 FLOW DIAGRAM OF A DEPHENOLIZATION 162
PLANT
34 PLOT PLAN OF BIOLOGICAL PROCESSING 167
SYSTEM
35 FLOW DIAGRAM OF BIOLOGICAL 168
PROCESSING SYSTEM
36 GRAPHS OF CONCENTRATION OF AMMONIA, 169
PHENOL AND THIOCYANATE IN DILUTED FEED
AND DISCHARGED EFFLUENT (WEEKLY
AVERAGES)
37 SOLVENT REFINED COAL PROCESS 173
38 FLOW DIAGRAM OF REINLUFT PROCESS 1 75
39 FLOW DIAGRAM OF CATALYTIC OXIDATION 176
PROCESS
40 FLOW DIAGRAM OF ALKALIZED ALUMINA 178
PROCESS
41 PLANT FOR EXTRACTING PHENOLS FROM 182
EFFLUENTS BY MEANS OF COAL TAR OIL
42 ROTATING DISC CONTRACTOR EXTRACTION 184
COLUMN IN SIMPLIFIED SCHEMATIC DIAGRAM
-------
TABLES
No. Page
1 Compositions of Some Waters 6
\
2 Comparison of Dissolved Solids in Seawater and 7
Oil Field Brine
3 Mineral Analysis of Salt Water in East Texas Oil 11
Field
4 Comparison of Produced and Source Waters and 14
Injection Water Specification
5 A Comparison of the Chemical Characteristics of 24
Nineteen Crude Oils with the Chemical Characteristics
of Southern California Beach Tars
6 Survey of Operating Refineries in the U.S. 40
7 Composition of Oily Waste Water 47
8 Composition of So-called Non-oily Waste Water 49
9 American Petroleum Institute Summary of Effluent Data 50
10 Summary of Water Use and Effluent Treatment 60
11 Summary of Miscellaneous Treatment and Disposition 61
12 Typical Plant Wastes in the Houston Area 86
13 Typical Transport Costs to Plant 88
14 Typical Characteristics of the Enid Sewage Treatment 93
Plant Influent and Effluent
15 Typical Finished Water Quality at Champlin Refinery 96
16 Typical Treatment Costs for Cooling Tower Make-up 96
Water at Champlin Refinery (Based on 1100 gpm)
17 Average Monthly Operating Costs for Enid Sewage 97
Treatment- Plant (Based on First Half F. Y. 1970)
xi
-------
TABLES
18 Field Sampling Points in Refinery A JQ5
19 Field Sampling Points in Refinery B ]Q7
20 Field Sampling Points in Refinery C 1Q9
21 Removal Efficiencies of Treatment Processes ] ]•]
22 Output of Coal in Main Producing Countries 1 14
23 Potential Fish and Wildlife Waters Deleteriously 122
Affected by Acid Mine Pollution
24 States Which Reported That Acid Mine Pollution 123
Is No Problem
25 Fundamental Area Relations to the Acid Mine 124
Drainage Problem
26 Coal Categorization According to Moisture Content 140
27 Representative Influents of Phenol -carry ing Wastes 157
to Secondary Treatment Plants
28 Typical Operating Results, Koppers Light Oil 164
Extraction Dephenolizer Donner-Hanna Coke
Corporation
29 Comparative Analysis of Raw Coal and Solvent 172
Refined Product
30 Carcinogen Removal from Phenolic Effluents 181
31 Phenol Extraction by the Use of Coal Tar Oil 183
32 Typical Maximum Dephenolization Efficiency for 183
Rotating Disc Contractor Designs 6" to 8'0" diameter
X201 to 35' Tall
XII
-------
SECTION I
SUMMARY AND RESEARCH NEEDS
Increased emphasis on pollution abatement requires greater efficiency in waste
water treatment. The trend is toward using less water (air cooling rather than
water cooling) and reusing treated waste waters. The petroleum industry generates
a multitude of wastes from the oil wells to the finished petroleum products. Petro-
leum products (i.e. gasolines, greases, fuel oils, motor oils and natural gas) are
an integral part of the U.S. economy. Therefore, future research actions are
needed to cope with the pollution threat from the petroleum industry. Accordingly,
the following areas merit active and continued research:
1 . Develop sampler to obtain representative samples of floating oils, dis-
solved oils, emulsfied oils, and oily sludges.
2. Conduct internal refinery studies to reduce waste volumes and strengths
for old and new refineries.
3. Extend biosystem studies to optimize treatment efficiencies and handle
shock loading.
4. Devise a continuous monitor for hydrocarbon detection in waste waters
using common refinery laboratory equipment.
5. Design original waste water treatment systems for the petroleum industry.
6. Perform chronic (long term) toxicity studies on treated effluents.
7. Identification of toxic components in petroleum waste waters.
8. Develop efficient devices and techniques to remove oil spills on diverse
waters surfaces (i.e. swamps, rivers, and turbulent seas).
9. Assess environmental effects of spilled oils (i.e. volatile, soluble,
emulsified, floating, etc.) and oil products.
10. Investigate use of cooling towers for treating selected refinery waste-
waters for recycling.
11 . Study water reuse within refinery.
12. Explore feasibility of phenol removal from waste waters using phenol-
soluble oils.
13. Perform economic studies of brine treatment and disposal on land and
sea.
14. Develop remote sensing techniques for detection of oil and brine pol-
lution.
15. Perform feasibility studies on by-product recovery from refinery wastes.
16. Devise a monitoring program to prevent subsurface pollution from aban-
doned oil wells.
17. Examine pollution problems associated with extreme cold in the Alaskan
oil fields.
18. Determine proper measures to collect and reuse waste oils from U.S.
vehicular and boat service stations.
19. Design antipollution devices and management controls to insure proper
underwater storage of crude oil.
-1-
-------
20. Assess foxicological aspects to man and to warm-blooded animals in-
gesting oil and oily substances.
As coal production and consumption continue to increase, research efforts to ad-
vance control or abatement procedures are needed to cope with the pollution threat
from the coal industry. Accordingly, the following areas merit active and contin-
ued research;
1 . Develop a complete understanding of the reaction mechanisms of acid
drainage formation.
2. Determine the kinetics of the acid formation reactions to arrive at a rate-
controlling step.
3. Conduct applied studies on the effectiveness of the mine scaling operations,
4. Comprehensive biosystem studies to optimize treatment efficiencies to
handle shock loadings.
5. Design original waste water treatment systems for the coal industry.
6. Perform chronic (long term) toxicity studies on treated effluents.
7. Perform feasibility studies on by-product recovery from coal processing
and utilization wastes.
8. Devise a monitoring program to prevent subsurface pollution from sealed
or abandoned mines.
-2-
-------
SECTION II
INTRODUCTION
The purpose of the proposed study was to compile a concise report" outlining the
scientific and technological information presently available which applies to pe-
troleum and coal wastes and waste disposal. The origination and identification
will be addressed to petroleum wastes from production, transportation and refining
and to coal wastes from mining, processing, and utilization.
Evaluation of the oil and coal waste problem required gathering all available rele-
vant information. This necessitated an exhaustive search of pertinent literature in
addition to discussions with representatives from industries and government. The
available data were assimilated and presented through various tables and statistical
plots. A brief history of each industry and its relation to pollution problems was
included, and projections concerning the proposed growth and their attendant
waste products were made with the assistance of experts from industry. Their as-
sistance also was sought in determining the possibility of process changes, water
reuse potential, by-product recovery and socio-economic problems. Cross-sectional
studies, in the field, of several refineries were undertaken to further identify these
wastes. The final document includes cross-sectional data on the major waste streams
handled by industry, and the applicability and efficiency of the various treatment
processes. This report does not attempt to duplicate, but rather supplements, "The
Cost of Clean Water", Volume III.
-3-
-------
PETROLEUM SECTION
SECTION III
DRILLING—PRODUCTION
A. Oil Field Brine Disposal and Land Pollution
The major pollutant sources in oil drilling-production operations are: "lost" oils
(spills, leaks) and produced brines [ 1 ] . Other significant wastes include drilling
muds, free and emulsified oils, tank - bottom sludges, and natural gas. Minor
pollutant sources are spent acidizing waters, containing toxic corrosion inhibitors,
or concentrated salt solutions used as packer or completion fluids [ 1 ] • Of oil-
production wastes, salt water (brine) presents the big difficulty [2] .
Most oil-bearing strata have brine formations either directly over or under them.
These waters called connate wafers (produced brines) are ancient sea remains en-
trapped and buried along with igneous or sedimentary rock. High salinity connate
waters can be attributed to the formation of the sedimentary deposit from brackish
waters. These waters are usually found around the edges and the bottom of oil and
gas reservoirs, and as interstitial water within the hydrocarbon-bearing zone [1] •
To prevent these brine waters from seeping into the oil, crude withdrawal pumping
rates are controlled. However, because this can never be completely accomplished,
brine is frequently pumped out with the oil. Brine and oil must then be separated
by gravity and the brine properly treated or controlled to prohibit their discharge
to surface waters. Oil field brines also require proper treatment in order to prevent
corrosion of the disposal system or plugging of formation interstices if they are pumped
back into the oil bearing formation.
Sea water with its 20,000 parts per million in chlorides is mild compared to some
oil field brines which contain six times the above chloride concentration. In total
solids, sea water averages some 35,000 parts per million compared to oil field
brines with a concentration of 248,000 parts per million, a factor of seven [3] .
Sodium and chloride ions are present in the largest amounts. Other ions, in larger
than trace amounts are sulfate, bicarbonate, carbonate, calcium, magnesium,
barium, potassium, strontium, and bromide. Brine characteristics from Louisiana,
Oklahoma, and Texas are compared with seawater and fresh water in Table 1, and
typical oil field brines are compared with seawater in Table 2.
] . Surface Disposal of Brine
Brine pollution of surface and subsurface waters is an ever present problem. Tre-
mendous volumes of brine produced with crude oil must be treated and disposed of
to prevent pollution of fresh water supplies. Rivers, streams, and lakes, so polluted
in the past, had their beneficial uses curtailed. Brine subsurface pollution which
results from the downward percolation or direct injection of brines into fresh water
aquifers is also a serious problem.
-5-
-------
TABLE 1
Composition of Some Waters'
Marginulina Marginulina Garner
Saskatchewan Sand Sand Sand
Constituent River Ala. City Sea Water (Texas) (La.) (Okla.)
Carbonate
Bicarbonate
Sulfate
Chloride
Calcium
Magnesium
Sodium &
Potassium
Iron7 total
Barium
TDS
PH
0
219
40
20
59
10
30
0.1
—
378.1
7.7
0
120
2
11
1
1
51
0.4
—
186.4
7.6
—
142
2,560
18,980
400
1,272
10,840
0.02
—
34,292
— —
0
159
157
29,573
881
498
17,258
135
—
46,661
6.5
0
281
42
72,782
2,727
655
42,000
13
24
118,524
6.5
0
12
0
101,479
9,226
1,791
46,000
35
127
158,670
5.0
'* Expressed as mg/i.
-6-
-------
TABLE 2
Comparison of Dissolved Solids in Seawater and Oil Field Brine
Element Seawater, mg/l. Oil-field brine, mg/l.
Sodium 10,600 12,000 to 150,000
Potassium 380 30 to 4,000
Lithium 0.2 1 to 50
Rubidium 0.12 0.1 to 7
Cesium 0.0005 0.01 to 3
Calcium 400 1,000 to 120,000
Magnesium 1,300 500 to 25,000
Strontium 8 5 to 5,000
Barium 0.03 0 to 1,000
Chlorine 19,000 20,000 to 250,000
Bromine 65 50 to 5,000
Iodine 0.05 1 to 300
-7-
-------
Surface brine disposal includes evaporation, percolation and semi-controlled dis-
charge into fresh water streams and rivers Ml- Solar evaporation is not a complete
solution of the problem because only the water vapor is lifted from the pit. This
water loss leaves a more concentrated brine, and, finally, a solid residue problem.
Salt water evaporates at a slower rate than fresh wafer adding a weather dependency
factor [31 . Therefore, as the salt concentration increases, evaporation decreases,
requiring a large surface area for disposal.
a. Shal low Pits
Brine seepage from earthen pits (percolation pits) readily pollute fresh water aqui-
fers, rivers, streams and lakes, which cause many oil-producing states to bar un-
lined open pits [ 1 ] .
Seepage from earthen pits is reduced by lining with impervious films and/or Gunite.
However, the use of lined pits, depending on variable evaporation rates, poses a
solid waste disposal problem. Therefore, monies invested in lined surface pits are
only a stop-gap measure [ 1 ] .
b. Streams and Rivers
Controlled dumpage during high flow periods aims to take advantage of the dilution
factor. However, recent antipol lution regulations have discouraged this practice
m.
c. Evaporation by Heating
Evaporation of brines by heating has been fried in a small way, but even with cheap
fuel, a heavy salt residue presents a disposal problem. Every year U.S. oil wells
bring more than 250 billion gallons of salt water from subsurface formations; dissolved
in these saline waters is about 105 million tons of salt compounds: sodium chloride,
sodium sulfate, sodium bicarbonate, sodium bromide, sodium iodide, and similar
salts of lithium, potassium, calcium, manganese, etc. These estimated figures as-
sume that 2 gallons of brine containing 100,000 mg/l of dissolved solids are produced
with each gallon of crude oil.
Varying amounts of elements are found in oil field brines. Some of the minerals hav-
ing high market values may be recovered for a profit [41 . Some companies presently
recover minerals from subsurface brines: Dow Chemical extracts iodine, bromine,
calcium, potassium, etc.; Michigan Corporation recovers bromine. Other companies
which recover valuable minerals are: Morton Chemical, Ethyl-Dow Chemical, FMC
Corporation, Arkansas Chemicals, and American Potash and Chemical Corporation.
Iodine is recovered from subsurface brines in Japan, Indonesia, Java, France, Eng-
land, Germany and the U.S.S.R. [41
-8-
-------
A mineral recovery plan has several advantages and some disadvantages. The ad-
vantages are: 1) many oil field brines contain high concentrations of valuable
minerals which can be recovered at a profit; 2) expense of drilling disposal wells,
building water-treatment plants, and using expensive chemicals for injecting treat-
ed wafer would be lessened; 3) fresh wafer pollution and high-priced land damaged
from brine well and tank overflow would be curbed; and 4) pollution of fresh water
aquifers by faulty disposal wells would be eliminated [41 . The disadvantages are:
1) collecting of oil field brine is difficult due to its corrosive and electrolytic prop-
erties; and 2) changing the brine v/ater characteristics by extracting certain valuable
elements may result in a water that is incompatible with the receiving reservoir,
which may be undesirable if the water subsequently will be used for water flooding.
However, objections need not always deter since many reservoirs undergoing water-
flood can accept water treated to remove some or all of the dissolved salts [4] .
2. Waste Disposal by Injection info Underground Formations
When administered by a responsible disposal association, brine disposal into deep
seated formations can be the logical and economical answer to the brine disposal
problem. Underground formation capacity varies from thousands of gallons per min-
ute, with only hydrostatic head pressure, to a few hundred gallons per minute with
1000-2000 psi pump pressure [11 • Waterfloading, (Injecting water into the pro-
ducing formation to augment its existing water drive) by controlled brine injection
into acceptable formations presents advantages. Secondary crude recovery is pos-
sible, and costly brine treatment is precluded by careful selection of the under-
ground formation.
Kansas law, allowing the use of water as the repressuring media in secondary oil re-
covery, has not only given added incentive to the operator to increase the ultimate
oil yield, but affords a legitimate use of brine. Several areas in Kansas are using
the Arbuckle Formation, a silicious limestone, for disposal purposes. This forma-
tion is often 4500 feet below the surface, and takes immense volumes of water by
gravity with no injection pressures involved. Kansas has more brine disposal wells
than all other oil states combined [31 .
A conclusion drawn from this experience is that salt wafer can be a tremendous form
of energy, and when brought to the surface with oil, should not be figured solely
as waste, but with proper treatment, regarded as a means, by re-injection, to flush
out more oil.
The biggest problem associated with brine injection lies in plugging both the well
and the formation. Entrained solids, oil, muds, salt precipitates, sulfur, and bac-
teria commonly cause plugging. Even low concentrations, parts per million of the
mentioned materials, in a short time will plug a well. However, the Arbuckle gran-
ite wash in western Kansas contains fractures and large pores not as susceptible to
-9-
-------
plugging as other formations [11. Plugging from suspended material is not the only
problem. Corrosive products resulting from equipment corrosion may also plug the
injection wel i.
Another disadvantage of waterflooding is the possibility of contaminating ground or
surface waters. Old wells, long abandoned, frequently come to life as artesian salt
water wells when the pressure in the producing formation increases during flooding.
Old, inadequately plugged wells must then be replugged to hold any anticipated
pressure increase to the sand body.
Injection system considerations, must then include: an analysis to determine the
suitability of the formation, and the design of a waste water collection center,
water treatment facilities, and infection wells. To determine the suitability, in-
jection water analysis should include: pH, physical properties, scaling tendencies,
determination of the compatibility of the injection water with water in the forma-
tion, corrosivity, bacteriological properties, and studies to determine pretreafment
requirements.
Geological considerations, thickness, lithological character, and continuity of any
proposed disposal formation, impose a big influence on waste disposal by injection.
Porosity, which determines the storage capacity of the reservoir, is another consider-
ation. Porosities can be determined from cores taken during well drilling. The
ability of reservoir rock to let fluid flow through its interconnected pore volume or
its fluid conductivity is permeability. Permeability relates to effective porosity
factors, such as grain size and degree of lifhification. Henri Darcy, French hydrolo-
gist, developed an empirical permeability equation. With Darcy1 s equation, an in-
jection rate can be calculated for brine disposal [1] .
Moseley and Molina [5] investigated deep-well injection comprehensively. They
developed performance information and well costs. A computerized model was de-
veloped to predict relationships between physical conditions and injection costs
knowing input variables. The Moseley and Molina study states that deep-well dis-
posal is technically and economically feasible under certain conditions. Deep-well
disposal costs run from 0.25—0.50 dollars per thousand gallons. These costs include
some pre-infection treatment and amortization of the initial capital investment [5] .
It is a common practice to use abandoned oil wells for waferfboding [9] . The chief
advantage in using an abandoned oil well lies in utilizing the casing already cement-
ed in the hole. The disadvantages are: 1) the expense of drilling deeper if required
is frequently almost as great a cost as drilling a new well; 2) the casing is often too
small to accomodate tubing large enough to furnish adequate capacity; 3) many times
the well is not satisfactorily located.
-10-
-------
3. Typical Waters and Treatment Procedures [1]
Water treatment plants utilize aeration, chemical coagulation, sedimentation and
filtration. Two general disposal systems are in use: the open and the closed type.
Water in an open system, exposed to the atmosphere, contacts air and light. Since
surface temperature and pressure differ from those in the reservoir, the chemical e-
quilibrium may change. The treatment system must therefore make the water com-
patible with the reservoir.
In theory, produced and infected water, using a closed system, is in equilibrium
throughout the process and requires a minimum of treatment. However, pressure and
temperature may be different from the reservoir, resulting in the deposition of solids
and requiring sedimentation or filtration. To keep a closed system free of oxygen a
slight overpressure of natural gas is maintained in the vapor space of the brine-con-
ditioning equipment.
a. Open Treatment for Injection of Produced Brine
The classic example of subsurface injection of salt water is the disposal of brines in
the East Texas oil field. The East Texas Salt Water Disposal Company collects pro-
duced brine from field operators to reinject into the Woodbine sand. A cumulative
total of 2,349,958,237 barrels was treated then infected during the period 1938-
1957. A mineral analysis of salt water in the East Texas oil field is shown in Table
3.
TABLE 3
Mineral Analysis of Salt Water in East Texas Oil Field
Ion Concentration (ppm)
Carbonate 0
Bicarbonate 525
Sulfate 233
Chloride 37,128
Calcium 1,380
Magnesium 309
Sodium 22,223
-11-
-------
An open-type system for treating and handling this water was chosen because the
water is collected from hundreds of leases with different operators and therefore, it
is very difficult to control wafer™ hand I ing procedures. The large water volume is
more simply handled and treated in an open rather than a closed system.
The amount and kind of water treatment required was determined from the minimum
quality of water that could be injected without seriously damaging the reservoir.
Because economics are important where large volumes need treatment, cost to im-
prove the water quality was a prime consideration. Infrequent clean-out of an in-
jection well would cost less than treating the water to the degree requiring no well
clean-out.
Saltwater collected from the many leases in the East Texas field first passes through
an oil skimmer. After the oil skimmer, the brine is aerated to oxidize the iron.
Moreover, aeration serves to reduce dissolved carbon dioxide and hasten water sta-
bilization.
After aeration, the water flows into chemical treatment pits. First chlorine is added
to complete the oxidation of iron and to control algae and bacterial growths. Both
liquid chlorine purchased in cylinders and chlorine generated "in situ" by electroly-
sis are used. Approximately 4.4 pounds of chlorine per 1,000 barrels of water are
required to complete oxidation of the iron and provide a chlorine residual.
After chlorination, hydrated lime is added to promote sedimentation and to precipi-
tate calcium and magnesium. Only 8 to 1 2 pounds of lime per 1,000 barrels are
added. This is not sufficient to soften the water or to completely precipitate the
calcium carbonate. Therefore, even with this treatment, some carbonate precipi-
tate collects on the face of the injection formation. From 8 to 12 pounds of alum
or aluminum sulfate per 1,000 barrels of water is added as a coagulant prior to sedi-
mentation with a 24-hour retention period before filtration.
After sedimentation, the water is filtered with pressure-type sand or "anthrafilt"
filters. Finally, the treated water is injected into wells containing only cemenred-
in-place casing, but no tubing. This treatment, while not producing water of the
highest quality, balances treatment costs against infrequent well clean-out to obtain
satisfactory and economical disposal. In 1957, the average cost for chemical treat-
ment of this water with chlorine-alum-lime and sodium aluminate was 0.437 miIs/bbl.
b. Closed System for Infection of Produced and Source Waters [1]
A unit flood in Kansas required injection of 9,000 barrels of water per day, of which
6,500 barrels were produced water and 2,500 barrels were supply water from the
Douglas sandstone. Mineral analyses of the two waters indicated the waters were
very similar, so the waters were mixed without chemical treatment other than the
addition of a bactericide. Produced water and oil were separated and passed through
-12-
-------
a closed gravity sand filter and through the injection pumps into the distribution line.
Wafer from fhe supply wells was pumped directly into the distribution line, where it
mixed with fhe produced water.
c. River Water Treatment for Injection into Low-Permeable Formations [1]
A good illustration of a system designed to make surface wafer suitable for injection
into a formation was the treatment of North Saskatchewan river water for injection
into the Cardium sand. A pilot flood of six injection wells was used to determine
the subsurface reservoir characteristics. Flood water was obtained from wells in the
river1 s sand.
During the operation of the pilot flood, the two injection wells with the slowest over-
all permeability became plugged with bacterial slime and iron compounds. The un-
treated well water had a turbidity of 3 ppm and an iron content of 0 to 0.4 ppm.
Experience gained during operation of this pilot flood indicated that only high quality
infection water would work. Injection wafer specifications for fhis flood are in Table
4 as are the analyses of North Saskatchewan river wafer and produced water from the
Cardium sand formation. Specifications for treated water are: less than 1 ppm iron
or dissolved oxygen; less than 2 ppm turbidity,; and absence of harmful algae and
bacteria.
Because of the limited well water supply, water from the North Saskatchewan river
was used for the main flood. This water was taken from fhe river by three different
methods: directly from the river; by Ranney collector; and from wafer wells in the
river's sands. The amount of required water treatment varied with fhe method of col-
lection. Wafer directly from the river required fhe most treatment, while that from
fhe Ranney collector and wells required only sand filtration. Compatibility tests
of the river water mixed with the formation water indicated these waters were not
compatible over the range 40 to 60 volume percent produced water. The decision
was then made to handle fhe waters separately, thus avoiding excessive treatment.
Potential produced water problems are: scale formation, microbiological growth,
suspended silica, alumina and iron. Produced water was separated from oil in a
combination free water knockout freater and separator, and then discharged to an
oil skimmer and sedimentation tank. The water was chlorinated to obtain a 1 ppm.
residual chlorine content. Wafer from the skimmer was mixed with treated river
wafer, passed through a wellhead cartridge-type filter and injected into a single
well.
-13-
-------
TABLE 4
Comparison of Produced and Source Waters and Injection
Water Specification
Dissolved gases, ppm
02
CO2
H2S
Dissolved solids, ppm
col
HC03
soi
a-
Fe, total
Ca+ +
Mg+ +
Na and K
TDS (evap)
pH
Undissolved Solids, ppm
Organic
Suspended
Turbidity
Microbiological, organisms/m
Fungi
Algae
Bacteria: nonspore-forming si
Spore-forming slime
Sulfa re-reducing
Iron-depositing
Aerobic-viable
Produced
Water
--
—
0
185
2,075
53
4,900
—
34
14
4,060
10,760
8.6
present
—
8
1
0
0
ime 0
—
—
—
— —
N. Saskatchewan
River*
9.65
—
0
0
145
26
12
3
43
15
1
224
8.5
present
2,310
452
0
0
220
0
0
0
1,000
Injection Water
Specifications
<]
<10
0
—
—
—
—
1
—
—
—
6.5-8.5
—
0
<2
0
0
0
0
0
0
>1 0,000
*At flood stage.
-14-
-------
4. Defecting Subsurface Brine Pollution
a. Area Pollution History
The objective of this historical view is to find answers to several questions: 1 ) How
long has the problem existed? 2) Has there been a similar problem? 3) Do brine
pollution problems follow any characteristic pattern or trend? 4) Could the problem
be a naturally occurring phenomenon? and 5) Is there any apparent time relation-
ship between the problem and any operating system [111 ?
b. Brine Disposal Systems in the Area
Both past and present salt-water disposal methods in the area should be studied to
determine: 1) the type of systems in operation; 2) dates systems were operative; 3)
complete physical data; 4) complete operational data; and 5) operational problems
[111.
c. Wellhead Surveys
Tests to determine the condition of the annular space between the production string
and the surface pipe have been found useful in solving brine-pollution problems.
A deadweight gauge should be used for pressure measurements, and the annulus should
be vented to the atmosphere through a suitable valve to determine if fluid under pres-
sure is in the annulus. Purpose of these tests is to determine the extent of localized
over-charged sand, the presence of infection-well casing leaks, and injection-well
channeling [111.
d. Mapping [111
Maps of all types can be used in finding tht, solutions to the brine-pollution puzzle.
Experience shows that outcrop maps, topographic maps, isobaric maps, aerial photo-
graphs, isochloride, soil, and subsurface maps used alone or superimposed, yield
valuable data in many cases.
Mapping techniques have been found useful for: presenting data, relating data, fix-
ing the extent of the problem, finding the size of charged sands, finding the size of
disposal sands and sands under flood, determining the nature of surface beds, deter-
mining dip and strike, and predicting brine migration patterns.
e. Water Analysis, Pattern Studies [111
The chemical composition of a contaminated fluid may be a clue to the origin of the
contaminate. Pattern studies, based on geometric similiarity, have been found use-
ful for sample identification, for determining the relationship between samples, deter-
mining the degree of contamination, and finding evidence and degree of dilution or
chemical change.
-15-
-------
f. Injection-well Tests [111
Injection systems operating in a polluted area might be contributing to uncontrolled
migration of fluids. Surface and subsurface procedures can be used to determine if
any relationship exists among the well system, the sand system into which the fluids
are being infected and the migration system.
(1 ) Interference Test
The interference test helps determine if a loss exists within the well system, as
through a casing leak or by channeling. This test assumes some degree of hydraulic
charge and can only be considered as positive. Simultaneous measurements of in-
jection pressure and the annulus pressure inside the surface pipe allow comparison
to detect casing leaks or channeling.
(2) Tracer Additives
A dye or other marker is added to the injected water, and surface observations are
made in the problem area for effect. Assume a salt-seepage problem in an area
where three brine disposal systems are operating. The additive tracer test is made
by adding a tracer to each system, using a different tracer for each. Surface ob-
servations then are made at the seepage area to detect any evidence of the added
substance. A show of the tracer added to any particular system would establish a
relationship to that system.
(3) Pressure-faMoff Test
The pressure fall-off test is used on an injection well to detect the possibility of a
casing leak or channeling. Results must be compared with those from other wells in
the same reservoir. To interpret this test properly, local sand conditions must be
considered.
(4) Injection-well Performance
In a brine disposal system, overcharging of the water zone is possible. The injection-
well performance test is designed to defect an overcharged condition. Tests are run
at various times in the history of the well, usually about 6 months apart. The actual
test is run over a period of 48 to 72 hours and follows a shut-in-injection-shuf-in
cycle. A consistent gain in shut-in pressure between tests, as evidenced by a pro-
gressive flattening of the performance curve (pressure versus time), indicates that
the injection zone is becoming overcharged.
(5) Relative Injectivity Test
Ways of locating trouble spots through analysis of relative injectivity tests areavailable.
-16-
-------
One method compares fhe injection ratios of several wells injecting water into the
same zone, by using average or instantaneous data. Injection ratio, as used here,
is defined as injection pressure divided by injection rate. These injection ratios
are plotted on a map of the area.
The second method involves determination of rate-pressure profiles for several wells
in the same sand system. Results are plotted (pressure versus rate) and extreme dif-
ference in slope indicates possible trouble. Sand conditions and injection history
must be considered when interpreting relative infectivity tests.
(6) Subsurface Radioactive Tracer Survey
Subsurface tracer surveys are run by injecting water containing a radioactive material
into the well and then running a detection device down the well. A sudden change
in radioactivity at a point above the injection zone indicates the location of a cas-
ing leak or channel.
(7) Wire-line Plug Method
The wire-line plug technique is used to detect only a leaking casing. This procedure
assumes that a plug would pump (travel) to the bottom if the well did not have a cas-
ing leak, but would stop just below a hole in the casing.
(8) Temperature Survey
Waterflood operators want to know where and how much water is going into the pro-
ducing formation. A temperature survey of a water injection well may indicate a
possible casing leak. But the method will usually not work if the injection water is
cooler than 200 F. This test assumes that an anomaly will show up on the tempera-
ture profile in the vicinity of the casing leak [111.
Point of entry information can be obtained by other types of survey, but what hap-
pens to the water after it leaves the immediate vicinity of the well-bore is what is
important. Interpretations based on point of entry data can be misleading if large
volumes of water have been injected and no response is noted at the producing wells
[121.
Experience with the shut-in temperature profile in more than 500 water-injection
wells in West Texas has yielded meaningful results [ 12] . The case histories studied
cover wells with depths to 8,500 feet and cumulative injected volumes from 1,800
to over 3 million bbls of water. All shut-in temperature profiles were run with sur-
face-recording equipment on a single-conductor wireline. Depth control, pressure
control and accurate temperature measurements are vital for dependable interpreta-
tions. It is essential that no fluid movement be permitted up-hole while running a
shut-in temperature profile. Shut-in temperature profiles (depth versus temperature)
-17-
-------
are made from the top to the bottom of the well. Profiles are made upon initial shut-
in of the well and at time intervals within a 24-hour shut-in period. Monthly pro-
files should be made to monitor the injection well f 1 2} .
Radioactive trace profiles are often conducted with the temperature profile during
the shut-in period. The combined data give the operator the net interval being
flooded plus the percent of fluid going into each area [ 1 2] .
(9) Pipe Inspection Logs
Pipe inspection detects holes in the casing by measuring the pipe wall thickness.
Also, a collar-locator log may be used to locate a hole in the casing. However,
these two logs only find problems within the well system.
(10) Subsurface Pressure Profile
Subsurface pressure gauges can be used to run a pressure profile on a suspect water-
injection well. This test assumes a pressure profile shift will occur just below the
leak.
(1 1) Packer and Tubing Test
The packer and tubing test detects and isolates a casing leak in a water-injection
well. A packer is run on tubing to a point fust above the injection zone, and the
pressure is increased in the outer casing annulus. If the pressure falls off (the well
has a casing leak), failure is assumed. The leak may be located by moving the pack-
er up the hole and repressurizing. When the well will hold pressure, the leak is be-
low the packer location. If there is more than one leak, location might be difficult
using only this method.
g. Selective Shutdown Method
Where several different systems are operating in the area of the pollution problem, a
selective shutdown program has proven successful. One system at a time is taken out
of operation and observations for effect are made in the trouble area.
h. Test Hole Drilling
Drilling test holes in the area under investigation is often applied to brine seep or
brine spring-type problems; however, this method has been used also in contaminated
water-well problems. Test holes are drilled near the problem area to trace contami-
nating fluid back to its origin. The program has been very successful where an earthen
pit is suspected to cause the pollution.
-18-
-------
i. Soil Sample Study
Isoconramination maps can be prepared from analysis of soil samples taken in fhe pol-
luted area. Although this method has had limited application for locating contami-
nation sources, it has helped to determine that certain problems stem from natural
phenomena [111.
B, Marine Oilfield Wastes and Pollution
1 . Introduction
Oilfields on the American shore line are found primarily along the Gulf Coast of
Louisiana, and Texas, and on California's Pacific Coast. Promising fields are being
developed in and near Cook Inlet, Alaska and off the East Coast from Virginia to
Massachusetts.
The search for untapped oil and gas deposits off the United State's East Coast, con-
ducted during autumn 1969, covers the Eastern Seaboard from Virginia to 200 miles
east of Massachusetts. Some 16,000 nautical miles of track line laid out in a grid
network of 5 by 10 miles extends to water depths of 3,000 feet [141 .
Two surveyed geological basins were reported to have good potential for discoveries—
the Baltimore Canyon and the Georgia Bank basins. The Canyon, an elongated, 160-
mile basement depression, parallels the Delaware-New Jersey coast. Georgia Banks,
roughly parallel to the Rhode Island-Southern Massachusetts coast, extends about 200
miles northeast from a point 70 miles south of Nantucket Island [ 1 41 .
Northern seaboard interest has been spurred by a reported 1969 gas discovery on Mo-
bil Oil1 s Sable I land acreage off the coast of Nova Scotia. Oilmen say the well
appears geologically related to the propitious United States coast [ 1 41 . These po-
tential sights, although a boom to the oil industry, became potential pollution prob-
lems.
News media gives "front page" coverage to oil spills. To sportsmen, conservation-
ists, and fhe residents of coastal communities, oil in marine waters and on beaches
presents a frustrating problem. Frustrating, because responsibility for it cannot be
designated with certainty; a problem because it is unsightly, possibly harmful. Oil
problems do not have a simple, inexpensive solution [151 .
The nation1 s dichotomy of antipollution versus the national importance of the oil in-
dustry necessitates compromise. Freedom to explore for and to produce oil fuels is
vital so that hydrocarbons will continue in sufficient supply at reasonable prices.
For this freedom the oil industry must assume the responsibility to minimize the pol-
lution possibilities and to plan for compatible facilities with other purveyors in multi-
use areas.
-19-
-------
Readers are referred to a document entitled "Oil Pollution Problems and Policies"
for a comprehensive coverage of marine oil pollution. This publication is an ex-
cellent compendium on al! aspects of oil spills. Sections on oil pollution and the
law encompass the "National Multi-Agency Oil and Hazardous Materials Pollution
Contingency Plan" and the "Oil Pollution Acts of 1924 and 1961 , "
2. Forecast of Offshore Development [171
Probably within two years, oil operations will extend beyond the Continental Shelf
into waters 4,000 to 6,000 feet deep. Already, Global Marine1 s Glomar Challenger
has drilled core holes almost 3,000 feet into mid-ocean sediments in water over
18,000 feet deep. Using present deep sea drilling technology, penetrations of 5,000
feet into the ocean floor in waters up to 30,000 feet are possible. Technology is now
available to drill commercially in water to depths greater than 12,000 feet. An
ocean-floor satellite production system is under development for wells in waters up to
6,000 feet. The key to how rapidly industry works the ultradepths is economics. At
present, costs are prohibitive.
Capital expenditures to develop and produce a 50-million bbl model offshore field
under existing conditions in depths often of 100 to 600 feet of water in the Gulf of
Mexico are more than double that of onshore production. Moving to 1,000 feet, the cost
goes up two and one-half to three times. Production facilities cost three to eight
times more; and in addition, the cost per mile of pipelines moves up two or three
times. Nevertheless, if the oil energy need arrives; as projected, and if the price
paid for crude justifies its cost, then the ultra depths are ready to be explored. The
Arctic areas—both on and offshore—exert influence on how soon the ultradepths are
tackled. The enormous reserves, in the northlands, will probably delay the deep
hunt.
Experts estimate total world offshore oil reserves at 1,600 billion bbl of equivalent
oil: petroleum liquids, gas, secondary-oil recovery, and heavy oil sands. Of more
than 10 million square miles of offshore area with water depths up to 1,000 feet, a-
bout 6 million square miles or 57% consist of sedimentary deposits conductive to hy-
drocarbon accumulation. This equals one-third of the world's land basins. However,
only a small portion of this offshore acreage has been tested.
About $25 billion—$2.5 billion/year—is forecast for exploration and development
during the 1970's. One estimator sees a $200 billion investment accumulated for off-
shore by the end of the decade. Now operational in the free world, the 200 mobile
drilling units represent an investment of some $1 billion. The rate of offshore activity
is expected to increase to about 18 percent/year. Most offshore operators see a con-
tinuing, steady rate of rig construction, but because of high costs and tax uncertainties,
no explosive surge in forthcoming.
-20-
-------
U. S. offshore claims extend out to a depth of 600 feet totaling 875,000 square miles.
These comprise 1,370,000 square miles if extended to 6,000 feet of water. Slightly
over 1 percent, only 19,000 square miles, has been leased. A concept proposed for
300 to 6,000 feet depths involves completion through ocean floor satellites. An in-
terim system, combining ocean-floor completions and a fixed-surface platform in
300 to 600 feet water, is available. Prototypes of spherical drilling and cylindrical
oscillating platforms are slated for testing within 5 years.
Many in the industry think that 600 feet is an economic limit for conventional surface
platforms. However, research is progressing on platforms designed for 1,000 to 1 ,200
feet depths. An existing platform model, for 800 feet, can accomodate 40 or more
wells drilled through vertical conductors outside (rather than inside) the legs.
Offshore operators think that when exploration turns up substantial deepwater reserves,
production techniques and equipment will develop to handle the job. Present en-
gineering knowledge probably can solve the deepwater problems.
3. Natural Seepages
Oil seepage has occurred over many years. For more than 400 years natural seeps in
the Santa Barbara Channel have poured oil onto California beaches [181 . Studies
have spotted 11 individual seep areas in the channel itself and three along the shore-
line. Four generalized areas, containing many seeps, have been mapped; moreover,
three areas of ocean-bottom tar mounds extend the problem. A generalized seep
area, about eight miles off Santa Barbara1 s shore, covers about 1,400 acres in the
northeastern corner of Federal Tract 402. A large general seep area—containing
hundreds of individual seeps—is offshore just southwest of Santa Barbara at Coal Oil
Point near Goleta, California. It is estimated that about 20 bbl/day of tar-like oil
is emitted from this area [ 18] . On June 12, 1958, University of South California
researchers found almost 100 pounds of tarry materials spread over 500 square feet of
beach site. The average quantity found was 21.5 pounds/500 square ft. Researchers
say the intensity of the pollution varies seasonally, particularly with tide, tempera-
ture, and wind. Sometimes great quantities of oil can be seen bubbling to the sur-
face at seep sites. At other times, only small quantities of gas are emitted [ 1 8] .
First written notice of the oil seeps was by an early Franciscan, Father Pedro Font.
While near Goleta in Santa Barbara County in 1776 he wrote ... "much tar which
the sea throws up is found on the shores. Little balls of fresh tar are also found.
Perhaps there are springs of it which flow out of the sea [18] . " Later geologists
W. P. Blake in 1855 and J. D. Whitney in 1865 described the occurrences of tarry
materials in the Carpinteria vicinity. Whitney wrote: "The slates are black and
highly bituminous where the outcrop strikes the sea 3 miles to the southeast of Car-
pinteria, and large quantities of tarry asphaltum flow from them. For a mile or more
along the shore, the banks abound in it, and it saturates the beach sand and flows
-21-
-------
down into the sea. "The asphaltum, or hardened bituminous matter, occurs in great-
est abundance on the shore at Hill1 s ranch, about 6 miles west of Santa Barbara, and
lies along the beach for a distance of a mile in large masses ( 18] . "
By 1957, the Sanitary Engineering Center of the University of Southern California
had developed sampling and laboratory procedures scientifically acceptable for
general use in determining the amount of oil and tarry substances on any given beach
at any given time. This development was financed by a number of oil companies
through the Western Oil and Gas Association. Then, in late 1958 the Robert A. Toff
Sanitary Engineering Center of the Public Health Service announced that it would
conduct a study to develop a method to characterize oily substances as to origin and
type. With the help of interested members of the petroleum industry, a wide range
of samples was obtained. They included emissions from four coastal seeps, (one
sample was procured by scuba divers in Santa Monica Bay), fhree beach fars, eight
crude oils, two refinery residues samples and a sample of a nearshore oily foam which
had been bothering communities fronting Santa Monica Bay. The scientists used a
process of dissolution, extraction, and spectrographic examination. Among their
findings: seep oil clearly differs from nearby crude oils. In other words, the nature
of the source of a given sample of pol lution could be identified [19].
To continue research, in 1959, the oil industry engaged Engineering-Science, Inc.
These scientists found that the amount of tar on beaches sampled downcurrent from
offshore drilling was less than the amount cited in the DSC study and did not represent
a nuisance for beach recreational purposes (less than 2 ounces per 500 square feet).
A method has been developed to identify oils and greases found on beaches and in open
waters. The method separates chemical groups using differential solubilities and frac-
tionates the neutral groups by adsorption chromatography [20] .
The analyses demonstrate that crude oil composition differs from beach tars. Three
distinguishing characteristics are: 1) the ether insoluble fraction was from 7.5 to
20.2 percent in offshore seeps and beach tar material, but was 2.9 to 9.4 percent
in crude oils; 2) the neutral fraction ranged from 76.6 to 86.3 percent in the seep
and beach tar, but 81 .4 to 92.2 percent in crude oils; and 3) the ratio of aliphatics
to aromatics was higher in crude oils than in tars [20] .
The chemical characteristics of the seep material was not significantly altered by con-
fact with sea water and air. The seep material, floating on the ocean surface, was
analyzed and compared with an analysis of known seep material (collected by divers
as if came from an ocean floor seep). The two analyses showed that the weak acid
content of diver collected seep material was higher than seep material on the ocean
surface, presumably due to the loss of weak acid on exposure to salt water [ 19] .
Studies by Ludwig and Carter f 15] showed that a single fraction of the material ex-
tracted by the ether insoluble fraction method is sufficient to differentiate between
a seep tar deposit and a crude oil deposit. The neutral fraction is similarly useful to
-22-
-------
distinguish between crude oils and seep tars. The average chemical characteristics
of 19 crude oils and 79 typical beach tar samples are shown in Table 5. Ether in-
solubles averaged 30.2 percent by weight in seep tar deposits compared with 7.9
percent in crude oils. The minimum value of this fraction for all beach tars was
21 .7 percent and the maximum for the crude oil sample was 15.5 percent. Consider-
ing the expected variations, (3.7 percent for the 99.9 percent confidence level) the
maximum value for the fraction in crude oils and the minimum value for the fraction
in tar deposits would be 16.5 and 20.7 percent, respectively. Or, on the basis of
the 12 crude oils assayed, in less than one assay in 10,000 would the ether insoluble
fraction fail to distinguish correctly between a crude oil or a beach deposit of seep
origin. Tars contain more ether insoluble material than crude oils, while the crude
oils have a greater amount of neutral fraction. In 79 beach tar samples the neutral
fraction averaged 65.6 percent, while in 18 samples of crude the neutral fraction
averaged 89.1 percent [20] . However, the ranges of values for the neutral fraction
in beach tars and in crudes may slightly overlap, and therefore this index is less
valuable than ether Insolubles for differentiating purposes [19] .
Determination of the specific gravity of the chloroform extract is also a valuable
supplement to the aforementioned methods. Ludwig and Carter also showed that the
specific gravities of chloroform extracts from seep tars are greater than one (averag-
ing 1 .0373). In comparison, the corresponding specific gravities for crude oil ex-
tracts are less than one—averaging only 0.941 . The specific gravity is the first
measurement made following chloroform extraction. Further identification is required
only when there is doubt as to the nature of the material. Chromatography and fluo-
rescence go beyond the limitationsof the usual method. These complex techniques are
costly for routine characterization work [ 20] .
4. Drilling Platforms for Offshore Operations
To reduce well blowouts, leaks, or spills, drilling platforms are equipped with pol-
lution control devices. The platforms are designed so oil and other fluids on the deck
drain toward peripheral scuppers, then into tanks to be cleaned of contaminants, or
barged ashore. Control equipment includes high-test blowout preventers, wellheads
encased behind protective bulkheads, velocity or storm chokes and other downhole
devices to control well flowing pressure. Also gas sniffers are placed at various
points on the platform to detect potentially dangerous gas concentrations. In addition
to the protective equipment the rig crews practice unannounced emergency drills to
counteract accidents [19] .
5. Marine Oil Pollution
a. Effect on the Marine Environment
Dr. Wheeler J. North, Assistant Professor of Environmental Health at California
-23-
-------
NJ
TABLE 5
A Comparison of Chemical Characteristics of Nineteen Crude Oils With
the Chemical Characteristics of Southern California Beach Tars
Range of Values for the
Chemical Characteristics
of 12 Crude Oils
from Ludwig & Carter
Range of Values for the
Chemical Characteristics
of 7 Crude Oils
from Musgrave
Range of Values for the
Chemical Characteristics
79 Samples of Typical
Beach Tar Deposits from
Southern California
Max.
Ether Insolubles
Water Solubles
Neutrals
Aliphatics
Aromatics
Oxys 1
Oxys II
Aromatics + Oxys 1
Weak Acids
Strong Acids
Bases
* Table values
Data from 41
15
0
99
45
52
21
6
1 & II
1
1
.5*
.8
.4
.4
.0
.9
.7
.8
.0
1.9
Min .
nil
nil
79.3
12.4
27.4
9.8
1.4
nil
nil
0.1
are weight percentage
samples.
Avg.
7.9
0.1
89.2
28.9
40.3
14.3
3.3
57.9
0.5
0.4
0.5
of samples
Max.
9.4
< 1.0
92.8
38.0
44.0
23.9
2.7
2.9
4.9
< 1.0
Min .
2.9
nil
81 .4
18.1
25.6
4.1
0
1.0
trace
trace
after evaporation
Avg.
6.0
< 1.0
88.8
26.9
35.2
14.5
1 .0
50.7
< 1.0
< 1.0
< 1.0
to constant
irom L
Max.
43.6
0.6
76.9
29.1
38.2
27.2
13.4
1.6
1.3
1.1
weight.
.uawig c
Min.
21.7
nil
53.3
3.7
19.5
11.6
0.9
nil
nil
nil
x Barter
Avg.
30
0
65
14
29
16
3
49
0
0
.2
.2
.6
.1
.3
.5
.5
.3
.3**
.2**
0.2**
-------
Institute of Technology, states that recent floods may have damaged more marine life
in southern California than has oil. Dr. North gave a preliminary report on the Santa
Barbara oil spill effects to the Fourth Offshore Exploration Conference in San Diego
[22].
Dr. North, endorsed by the Western Oil and Gas Association, conducted a one-
week study of pollution damage only three weeks after the oil spill. The survey em-
ployed three marine biologists and nine California Institute of Technology under-
graduates to collect marine samples. The inquiry covered ten miles of beach hit
hardest by the spill. One dead Pismo clam attributable to the oil slick was found.
The North study found no other evidence of damage to plant or marine life. Although
blackened by surface oil, the kelp beds were found substantially unharmed. Dr.
North pointed out that kelp secretes a mucous substance which prevents oil from stick-
ing to living plant tissue. Also, he said, the small sea life living on the kelp was not
harmed. Dives were made offshore, in 15 to 50 feet of water, to inspect possibly
damaged sea life. Divers collected organisms, starfish, snails, and mussels from pil-
ings and rocks. All were found to be normal. The first evidence of sea life damage
was found at Platform A, where the oil leak broke loose January 28, 1969. Here,
divers encountered a few dead scallops [22] .
Near the platform, about 30 percent of the marine life evidenced adverse effects from
the oil. But the remaining 70 percent was feeding normally in the ocean current. To
check possible dead marine life washed out to sea, researchers spent three days on
Anacapa, the hardest hit of the channel islands; they found only light damage to sea
life. Based on this evidence, the study concluded, that with the exception of bird
deaths, the effect of the oil spill on animal life was negligible. After the oil leaked
for three weeks about 500 birds had died. Through March 31, 1969, the Fish and
Game Department reported on actual count of 1,582 dead birds. The fearful pre-
diction had been 3,500. Generally, the mortality rate of marine life has been low.
No evidence has been found of significant damage to fish [ 1 81 .
Dr. North attributed the light toll to the fact that the leak was some six rr.iles off-
shore. By the time oil reached the beaches most of its toxic qualities had dissipated.
Dr. North pointed out that on the Southeast English coast the tanker Torrey Canyon
lost some 20 million gallons of oil when it ran aground on March 18, 1967. Despite
the huge spill and use of highly toxic detergents to break up the oil, the beaches
were used by the public the following summer. The channel spill produced about
200,000 to 300,000 gallons. In contrast, the Torrey Canyon's loss reached about
100 times the volume of the Santa Barbara Spill I 22] .
Another survey [18] by scientist William L. Brisby covered the Rincon Island area
off Point Corda in Ventural County, California. Studies during February and March,
1969 showed the oil spill killed some intertidal organisms on the island. However,
the destruction was not nearly as bad as anticipated, Brisby reported to the meeting
-25-
-------
of the Pacific Coast District Division of Production, American Petroleum Institute
in Los Angeles. Further, he thought the greatest damage to life on the island would
be from silting and pollution by spring storms/ rather than from oil.
Preliminary results, from a 12-month study by the University of Southern California
launched in late February, 1969, have found no high mortality rate among channel
marine life and no species wiped out. Instead, damage was far less than expected,
scientists said. Death of intertidal species--such as mussels, barnacles, and limpets—
from oil pollution only was patchy, and, in general, occurred only where there was
a thick layer of oil. Recolonization has begun on beaches where the oil has departed,
Scientists consider long-term effects will be minimal, and seal life could possibly
be back to normal by next summer. The scientists admit it is exceedingly hard to
differentiate between storm damage and oil-seep r'-image. Fresh water, silt and storm
debris, may have damaged the saltwater marine life more than oil [ 1 71 .
State fish and game officials agree that the oil slick left no evident harm to fishing
prospects in the channel. Catches were fewer in February when the oil slick was
extensive. But this partly was due to the reluctance of fishermen to operate their
nets in the oily water, rather than to drastic fish population reductions [17] .
During March, five California gray whales and one pilot whale were washed ashore
on California beaches. Conservationists pointed to the oil lead as the cause of their
deaths. Autopsy tests by the Bureau of Commercial Fisheries were performed on three
of the six whales. No evidence was found to indicate that either crude or dispersants
caused their deaths. A U.S. Bureau of Commercial Fisheries spokesman said that,
of the other three whales, one died before the spill, one died of pneumonia, and
a third had been harpooned. The Department of Interior said the mortality rate for
gray-whales was not unusual. Dr. Robert Orr, Associate Director of the California
Academy of Sciences in San Francisco, followed the migratory route of the gray
whales on March 20. He reported seeing no dead whales, either floating or on-
shore. He commented that the sea lion and sea elephant populations of the Channel
Islands appeared normal [17].
In June 1969, a special White House panel recommended a six-point program to deal
with the oil seepage near Union Oil Co. of California' s Platform A in Santa Barbara
Channel. Secretary of the Interior Walter J. Nickel said he would implement the
first three recommendations immediately while "studying and evaluating" the others
[23].
As a prelude to listing "order of priorities" dealing with leaks near the Union Plat-
form, the report said "it is less hazardous to proceed with the development of the
lease than to attempt to seal the structure with its oil content intact; in fact, the
panel is of the opinion that withdrawal of the oil from the Repetto zone is a neces-
sary part of any plan to stop the oil seep and to ensure against recurrence of oil
seeps on the crest of the structure [ 23] .
-26-
-------
Six priorities listed by the panel follow:
] . Contain and control present oil seepage through the use of under water re-
ceptacles or other suitable methods.
2. Seal off or reduce as much as possible, the flow from existing seeps through
a program of shallow drilling, pumping and grouting.
3. Review the possible earthquake hazard and take necessary actions.
4. Attempt through an oil withdrawal program to determine the degree of inter-
connection between levels of the Repetto formation.
5. Reduce pressure throughout the reservoir to hydrostatic or less and maintain
pressures if needed with water injection to minimize subsidence.
6. Deplete all Repetto reservoirs consistent with safe practices as efficiently
and rapidly as possible.
b. Antipollution [18]
As soon as Santa Barbara erupted, Union announced it assumed full responsibility for
beach damage resulting from the oil slick. To June 1, 1969, about $4,600,000 had
been spent on cleanup operations and pollution control. Prophylaxis stretched to
beach areas, sea walls, boats, rocks and private home backyards.
Significantly, the work involved more than just cleaning oil leaking from Tract 402.
It included oil washing ashore from the channel's estimated 11 individual oil seeps
and four general seep areas. It involved removing 30,000 tons of storm debris washed
to sea then ashore in the wake of California' s worst floods in years. Geologists say
the higher water table resulting from floods might have increased the natural pollution
seeps for a year, and activated dormant seeps.
Within hours after the oil slicks began, efforts were launched to contain it. Three
planes and two boats were pressed into service spraying dispersants. Shore patrols
were armed with the same chemicals. Plastic barriers were erected at harbors and
marinas to ward off encroaching oil. A plastic boom was rigged around the spill near
Union's platform. A barge, outfitted with tanks and vacuum equipment, attempted
to suck up oil by sweeping it into a pocket using telephone pole booms. Mulch
spreaders dumped 30,000 pounds of straw a day around the slick edges. And kelp
harvesters retrieved the oil-soaked straw. At the height of the effort, the work force
employed 1,500 people, 54 water craft, 6 bulldozers, 96 motor vehicles, 16 skip
loaders, 4 backhoes and tractors, and 6 mulch spreaders.
(1) Dispersant Performance
Dispersants met with success the first day or two. But as oil character changed and
light fractions dissipated through weathering, chemicals did not work.
-27-
-------
Dispersants sprayed on a weathered crude slick and not mixed by a moving boat, showed
little breakup. Dispersanrs sprayed and mixed up by the wake of a boat moving at 10
knots results in good dispersion along the boat1 s path and to a distance as far as 150
feet. However, boats run through the slick at the same speed with no dispersants left
a breakup about as thorough. Union concluded the dispersants tested were not signif-
icantly better than boat's propellers to break up a slick in open sea. Types of sinking
agents (tried with no success/ Union says) included diatomaceous earth, cement and
bentonite.
Union also conducted a test for possible harm to fish from using surfactants of different
manufacture. Control fish, exposed to varying surfactant dilutions, survived without
indications of injury.
(2) Skimmers, Booms
Floating skimmers, developed during the emergency, worked well in waves to 6 feet,
but in higher waves they were not effective. Double booming was used often with
straw spread between to absorb carry-through oil. A modified sea curtain filled with
plastic foam and carrying chain-weighted skirts performed well. Inflated booms used
offshore failed sometimes when sand migrated to the center of the skirts. Also, as-
sembling and towing the booms at sea overstressed some fittings. Wooden booms fail-
ed at connections due to sea action, because they were not anchored adequately. Ex-
perts need and expect some sort of mobile thruster system to position booms which will
contain the oil, and adjust to sea and wind pressures.
(3) Beach Cleanup
Naphtha-impregnated Mistron Vapor was used in some cases on rock seawalls before
hydroblasting to absorb the freed oil and prevent recontamination. Ekoperl and Mistron
Vapor, Union said did not materially aid in oil removal from beaches. Straw was ef-
fective but was hard to remove from rock crevices. Warm water, stream hydroblasting,
and sandblasting were successful in cleaning rocks and sea walls.
(4) Ideal System
Union pollution-control engineers stated that a good control system should consist of
an effective booming system which would contain rhe oil spill for recovery with a
mechanical skimmer and an effective mobile skimmer with some sort of booming system
to collect spills migrating from the immediate leakage area. The biggest challenge
to any system, is storm conditions; therefore equipment should be able to function ef-
fectively in Sea State 5 (12 feet waves).
-28-
-------
(5) Present Efforts [30]
Louisiana is preparing to add a strict new section to its antipollution laws governing
offshore operations. New laws (drafted in the wake of the Santa Barbara, California,
pollution case) contain six new guidelines:
1 . Forbid dumping of trash, debris, and nonedible refuse into offshore waters.
2. Forbid discharging of petroleum, waste oil, fuel or oil refuse into offshore
waters. Therefore, facilities must handle the maximum anticipated quantities,
and contain drippage and spills for proper disposal. Oil, from produced
sand and drill cuttings must be removed prior to discharge. Hydrocarbon
concentrations in discharged saltwater must be on the level harmful to
aquatic life.
3. Require an operator, discharging substantial oil quantities into offshore
waters, to notify the State Department of Conservation immediately and
to keep a record of such notifications.
4. Authorize the conservation commissioner to order the operator to control
or remove the oil.
5. Require any operator, observing a substantial amount of oil on offshore
waters, to report the sighting to the department.
6. Empower the commissioner to suspend drilling or producing operators in
case of significant waste of oil shown by leaks and oil slicks. The com-
missioner could suspend the allowable production, or cancel it, pending
corrective action by the operator involved.
-29-
-------
SECTION IV
TRANSPORTATION AND STORAGE OF PETROLEUM
AND PETROLEUM PRODUCTS
A. Waterborne Traffic
1. Extent of Waterborne Traffic [ 24]
Commerce makes extensive uses of waterborne fleets powered mostly by oil, and per-
haps one vessel in five is engaged in transporting the oil itself. Water transport con-
st! tures a significant pollution threat over extensive water areas; therefore, it is im-
portant that both government and industry give careful attention to control measures.
In 1965, of the world1 s merchant fleet, (18,000 vessels of 1,000 gross tons or heavier)
almost 3,500 were tankers. The United States flag was represented by about 2,500
vessels, of which approximately 400 were tankers. About 1,000 American vessels
carried foreign commerce, and the remainder served coastal and domestic trades in
the United States. The United States fleet, supplemented by approximately 36,000
smaller vessels, included several thousand tank ships and tank barges on the American
inland waterways. Many merchant fleet vessels (dry cargo and tanker both), not en-
gaged in the United States trade, are not relevant to this report.
Domestic inland and coastwise trade transports substantial quantities of oil and related
materials. In 1965, some 80 million tons of such products were moved between Amer-
ican ports by coastwise tankers. In 1966, 50,000 visits with a total capacity of al-
most 300,000 tons were made to U.S. Ports by ocean-going vessels, carrying poten-
tially polluting materials. Potential pollutants are also transported in the entire
25,000 mile United States inland waterway network. In 1964, waterways were used
to move an estimated 188 million tons of petroleum products and hazardous substances.
Although the inland fleet involves smaller vessels, they are of special concern be-
cause of their substantial number and because they use confined water areas, where
bulk spills can spread quickly through populated regions to endanger shore facilities
and potable water supplies. One recent movement of petroleum on the Mississippi-
Ohio River routes involved 277,000 barrels, in a single tow of a 1,180 feet length
(about one-third the amount carried by the 974 feet Torrey Canyon).
2. Vessels as Pollution Sources [24]
From this heavy waterborne traffic, pollution can develop in a variety of ways. Ac-
cidents produce spills of cargo or fuel oils. Operational mistakes may occur while
pumping petroleum products. Oil can be discharged into seas and rivers in connec-
tion with deballasting vessels, the cleaning of oil tanks, and the pumping of bilge
water which collects in the below-decks areas of vessels and which usually becomes
mixed there with waste oils. No thorough nationwide survey exists which estimates
-31-
-------
the amounts of oil spilled into United States inland and offshore waters by vessels,
barges, and shore facilities.
Although the discharge of oil into American waters is prohibited by law, the United
States Army Corps of Engineers estimates that over 2,000 oil spills happened within
United States waters in 1966 with 40 percent coming from landbased facilities.
Because of their numbers, the dry cargo vessels, with low oil capacities individually
present a big pollution hazard. The potential is higher when merchant vessels use
fuel tanks for ballasting purposes. It is hard to determine the quantity of waste oil
discharged in deballasting ships. However, it is estimated that the average vessel
uses about 40 percent of its fuel capacity for ballast and discharges a mixture con-
taining one per cent oil every time it debal lasts. Wirh over 10,500 foreign vessels
with a fuel capacity of 1,500 tons and over 5,000 U.S. vessels of 2,500 tons fuel
capacity entering U.S. waters, the potential for oil pollution in deballasfing would
probably exceed 100,000 tons per year.
The biggest hazard, however, is the transportation of petroleum products themselves.
These products, with over one million tons moved daily through our coastal and in-
land waters, account for over 40 percent of the total waterborne tonnage in the
United States. Vessels in this trade share with dry cargo carriers pollution problems
in deballasting, and in addition have the problem of tanker cleaning. For example,
a 50,000-ton tanker may have as much as 1,200 barrels of oil to be cleaned from
its tanks after unloading. In 1963, prior to the development of "load on top" pro-
cedures, an estimated 441,000 tons of petroleum were spilled overboard worldwide
as a result of these cleaning operations.
More important than any of the above pollution sources is the risk of a serious pol-
luting accident involving tanker traffic. Too many accidents carry important im-
plications for our ports and waterways. In June of 1966, the British tanker, Alva
Cape, discharged 23,000 tons of naphtha into Arthur Kill (New York area) after col-
liding with the tanker, TEXACO Massachusetts. In December of 1966, about 120,000
gallons of oil were spilled when an oil barge hit a sunken obstacle in the Illinois
River. In April of 1967, about 5,000 gallons of gasoline were spilled from a barge
which struck a bridge pier in the Mississippi River at Chester, Illinois.
General aspects of the ocean tanker traffic deserve mention. The steady growth of
the world's tanker fleet is being made primarily in the size and capacity of individual
vessels rather than in their numbers. The T-2 tanker of the World War II period carried
16,000 tons. In 1965, the average tanker reached a capacity of 27,000 tons. The
new tankers delivered in 1966 averaged about 76,000 tons. The Torrey Canyon car-
ried 119,000 tons of oil when she grounded off the Cornish coast. Tankers recently
placed in service or now on order will exceed 150,000 tons, and some of them will
reach 312,000 tons. Enormous rankers increase the hazard from any single accident,
and emphasize the importance of preventive steps and contingency plans against
enormous spillage.
-32-
-------
Fewer and fewer rankers carry U.S. registry. This trend has been continuous since
World War II and foreign flag tankers have carried a steadily increasing percentage
of oil imports into the United States. Foreign ships transported about 20 percent
of U.S. imports in 1945, about 50 percent in 1951, and about 95 percent by 1964.
Because foreign vessels are preeminent in this trade, some aspects of tanker operation,
relevant to pollution, are hard to manage under U.S. domestic law, and protection
must therefore be sought through international channels.
3. Reducing Vessel Pollution
The discussion indicates two avenues for research studies to lessen pollution threats:
1) reduce maritime accidents; and 2) improve operating practices.
The marine and inland water casualty rate, fluctuates at a high level and justifies
concern. The casualty record of U.S. registered vessels and foreign vessels in U.S.
waters is serious, as can be seen below:
Vessel Casualty Record
FY 1966 FY 1967
Number of casualties, all types 2,408 2,353
VesseIs over 1,000 tons 1,310 1,347
Tank ships and tank barges 470 499
Locations:
U.S. water 1,685 1,569
Elsewhere 723 784
Types of casualties:
Collisions 922 1,090
Explosions 175 168
Grounding with damages 302 282
Foundering, capsizing, and floodings 315 230
Since casualties can and do cause polluting spills in U.S. coastal and inland water-
ways, preventive steps must be taken in the field of navigation and traffic guidance.
Accident prevention measures, however, are no guarantee against human error or poor
judgement.
-33-
-------
Improving operating practices is essential to decrease pollution resulting from trans-
portation. Officials formulating operating practices need to habituate proper pro-
cedures on loading and unloading of oil, fuel transfers within ships, bilge pumping,
ballasting, and tank cleaning. Major U.S. operators of tankers and barges have
adopted procedures to minimize pollution, but performance still falters.
B. Waste Oils [24]
Unlike cargo spills, waste oil (oil that has served its purpose) presents a different
kind of pollution problem. The troublesome residue must be disposed of in very large
quantities each day. The sources of waste oil can be categorized as follows:
1 . Gasoline Service Stations [24]
Annually in the U.S., some 350,000, 000 gallons of used motor oil must be disposed
of by the more than 210,000 gasoline filling stations. These stations have long been
key suppliers of used oils to oil re-refiners. Re-refined oils are used in railroad
journals, to freeze-proof coal, as dust control for rural roads, and as motor oils and
industrial lubricants. Re-refining, however, has now become a marginal business.
In the last 5 years, more than half of the re-refiners have gone out of business due
to changes in labeling requirements and tax laws. As the demand for used oil for
re-refining diminishes, more of this material must be disposed of in some way. Waste
oil, uncollected and unused, too often winds up flushed into city sewers because this
is the handy way for filling station operators and others to dispose of their small a-
mounts of oil. Ordinances already exist against this throw-out practice. The ques-
tion is how to monitor and police more than 210,000 service stations. Further study
is needed to determine the proper measures for preventing the discharge of waste oils.
Properly-operated municipal waste treatment facilities can normally cope with limited
quantities of oil. However, the limit is easily exceeded. Even a moderate amount may
upset theoperarion of the plantand be discharged into fhe receiving stream. Further waste
oil also finds its way directly into streams and lakes through storm sewers and combined
storm sanitary sewer systems.
2. Tank-cleaning Facilities [24]
Most large ship yards have facilities to clean cargo holds, ballast tanks, and engine
rooms. Normally, these facilities are used only in connection with vessel repair
and maintenance. Many major oil refineries in the country and seaports have debal-
lasting and other waste receiving systems. These facilities are an essential part of
controlling oil pollution from vessels. However, unless the receiving facilities are
backed up by adequate treatment, water pollution is bound to occur. Facilities now
available to receive and treat oily wastes from vessels may be inadequate. This
situation should be analyzed to determine the actual need and the ways to assure their
instal lotion.
-34-
-------
3. The Oily Waste Industries [24]
According to the Bureau of the Census, over 10,000 industrial plants are major water
users. Many of these plants have significant quantities of oil in their wastes. Un-
treated or inadequately treated wastes cause continuing oil pollution problems in
receiving waters.
Although technology is available to cope with wastes having floating and emulsified
oils, this available technology is not always tapped. Water quality standards having
implementation plans with strong enforcement provisions for interstate waters would
mean real progress in meeting this problem.
C. Industrial Transfer and Storage
1. Pipelines [24]
The U.S. is laced by about 200,000 miles of pipelines operating at pressures up to
1,000 pounds per square inch. In 1965, these lines conveyed more than one billion
tons of oil and other hazardous substances. Many sections of the network cross nav-
igable waterways and reservoir systems. In populous areas there is heavy concentra-
tion of lines to meet the demand for petroleum products. Therefore, the pipeline
transport system involves the risk of oil pollution in watercourses, portareas, and drink-
ing water supply areas. The potential danger of spills from accidental punctures,
cracked welds, and leaks from corrosion require attention and technical improve-
ments.
The interest of the pipeline industry is not to lose oil in transit or to cause water pol-
lution. To control pollution anddecrease losses, subsections of the industry have made
important strides by continuing surveillance of the lines, by adopting better material
specifications, by implementing corrosion control methods, and by enforcing higher
welding standards. Also, in some locations, pumps are automatically shutdown if
the line pressure drops and block valves are placed at more critical river crossings
to minimize drain-back should a break occur within the river pipe segments. The
American Petroleum Institute and the American Waterworks Association have coop-
erated in establishing plans to protect against the threat of pipeline leaks.
Currently, basic pipeline safety regulations are being formulated in the Department
of Transportation. These regulations aim for uniform national pipeline standards bear-
ing directly and indirectly on the polluHon problem. Broad coverage will include
materials, construction, fabrication, maintenance, inspection, and testing of the
lines. Specific features involve pipe coating, a requirement that block valves be
used generally on both sides of river crossing, and line markers used to indicate
crossing points. These regulations could reduce pollution incidents from this source.
Expanded administrative effort and engineering expertise in this area include rigorous
inspection, enforcement action, and continuing evaluation of every possible improve-
ment in the pipeline network.
-35-
-------
Several requirement are being enforced on the construction of new pipe line systems
such as the Trans Alaska Pipeline System (TAPS).
The Bureau of Land Management requirements for TAPS are:
1 . TAPS must post a security bond of $5 million, with charges for environ-
mental damages to be paid from this fund.
2. Disturbed areas must be restored as much as practicable.
3. TAPS must file a detailed contingency plan for controlling oil spills and
pipeline leaks.
4. BLM may require pipeline realignment or modification to meet unforeseen
environmental conditions.
5. The pipeline may have to be rerouted around areas with unstable soil con-
ditions including permafrost, or special construction methods may be re-
quired through these areas. A contract requirement is to try to avoid melt-
ing and subsequent erosion of the permafrost.
6. Passageways for fish must be provided where the pipeline crosses a stream,
e.g., ColumbiaRiver'ssalmon ladders.
7. In all cases the pipeline will go under the streambed unless Interior approves
an exception.
8. Construction may be halted to protect key wildlife areas during seasonal
nesting activities and fish and game migrations.
9. Handclearing must be done where heavy equipment would damage steep
slopes or streams.
2. Seafloor Tanks for Oil Storage [27]
Concrete tanks on the ocean floor can serve offshore oil fields taking the place of
pipelines and onshore terminals. The idea developed by an offshore construction firm,
is proposed for:
1 . Eliminating the cost of long underwater pipelines.
2. Use in areas where sabotage of surface facilities is a threat.
3. Use in areas with pipelaying or shore oil-handling problems.
4. Use in fields with fluctuating storage requirements.
Multiple tanks of 200,000-bbl capacity located near the offshore production platform
may serve as intermediate storage with a single-mooring, tanker-loading buoy. These
subsurface tanks may solve problems of onshore sites and would eliminate right-of-way
payments to the state. Made of prestressed and reinforced concrete, the storage ves-
sels would be built near the field, floated and towed to the offshore field, flooded
with seawater, and sunk. A 200,000-bbl vessel would be 326 feet long, 105 feet
wide, and 54 feet deep, and would contain two internal storage cylinders with 48
feet diameters. Cylindrical design produces a minimum surface area per volume of
capacity, and reduces reinforcing steel requirements and fabrication and painting
costs. Submerged units require little maintenance.
-36-
-------
Crude oil is pumped into a distribution chamber at the top of the tank. Lateral ducts
move the oil into the tank at a low velocity to prevent turbulence or mixing of the
oil and seawater. The oil displaces sea water out the bottom of the tank as the storage
vessel is filled. As oil is pumped out into a tanker, seawater enters the tank through
a lower distribution chamber equipped with lateral ducts. Filters prevent silt and
sludge from entering the ves.se! with the seawater.
Notably absent from these underwater vessels are antipollution provisions. Pumping
oil into the subsurface tanks will displace emulsified and free oils along with the sea-
water. Also oily sludges will be flushed out onto the ocean floor, resulting in oil
pollution. Combating oil losses from subsurface tanks will be a problem. Since un-
derwater storage tanks are only now being designed, antipollution devices and con-
trols should be incorporated.
3. Oil Storage in Sub-seafloor Cavity [28]
A proposal by Lockheed to detonate a nuclear device beneath the sea floor to pro-
duce a cavity of some 500 feet by 300 feet which could hold up to 5 million bbls.
of oil is now being considered. The cavity would be created in impermeable rock
situated above or near the oil field. The object is to so locate, size, and condition
the cavity that the natural and explosive-produced fractures do not communicate
with unpredicted void areas or the surface. Any conventional drilling vessel or rig
capable of making 15 Inch to 24 inch diameter holes is suitable for the project.
Once holes have been drilled to a depth of several thousand feet, a nuclear device
of 20 to 200 kflotons would be lowered downhole and detonated, leaving a substantial
cavity. Created by the explosion, the molten and vaporized rock resolidifies, and
the resulting glass puddle traps the radioactive products. Remaining radioactive pro-
ducts will be removed or allowed to decay. Offshore cavities could be flushed with
sea water. With adequate sea water flushing, it is estimated that there would be no
serious problem concerning radioactive contamination of the stored product. Using
a minimum depth of 1200 feet below the sea floor, radioactivity should be self-con-
trolled by the intense heat of the blast.
Crude production would be force-pumped into the cavity, displacing the sea water
and the differential hydrostatic pressure of water and oil would provide for rapid re-
trieval of the oil. Maximum fluid static pressure in the cavity will be considerably
less than the lithosratic pressure. Methods available to prevent leakage from the
cavity are: selecting the best geological formation available (with a low matrix
permeability and avoiding planes of natural weakness running to seafloor); during
flushing operations, hydrostatic testing to discover leaks; and sealing techniques to
prevent oil seepage.
The Atomic Energy Commission (AEC) and other government agencies will be involved.
Under the present AEC Act of 1954, the proposed concept would be viewed as experi-
mental and the nuclear device provided by government funds. The AEC, the Joint
-37-
-------
Committee on Atomic Energy and various industries involved support underground oil
storage.
4, Oil Transfer from Supertanker [29]
Shell Marine International Ltd. has successfully completed sea trials for tanker-to-
tanker transfer of oil at sea. This procedure may solve the problem of super-tankers'
inability to enter shallow ports, as well as relieve the concern over spillage and pol-
lution of waters and beaches along the English Channel. Smaller lightening tankers,
with access to shallow ports, are used to transfer the oil ashore from supertankers
standing off shore.
In sea trials, the 207,000 dwt tanker Macoma, carrying a full cargo of crude oil from
the Arabian Gulf, linked up with the 70,000 dwt lightening tanker Drupa off Berry
Head, South Devon, England and transfered 65,650 tons of crude oil at about 6000
tons/hour.
Supertankers of the 200,000 dwt cannot use any existing European port when fully
laden, but these ships are still more economical to run with a 170,000-ton load than
tankers of the 165,000 dwt capacity. Once lightened by a smaller vessel at sea,
these supertankers can use existing facilities to finish discharging the load. Shell in-
tends to use this new tanker-ro-tanker procedure to transfer its Middle East production
until major Western European ports are dredged. Europoort, Le Havre, Gothenburg
and Fos near Marseilles are already undergoing full-scale renovation of facilities
and more ports are scheduled to be widened and deepened during the next few years.
-38-
-------
SECTION V
REFINING
A. Background
1. Oil Refining Technology [31,32]
To understand water pollution control requires technical knowledge of oil industry
operations. As an aid to develop this understanding, refining processes, capabilities,
and flow diagrams are presented in Table 6 and Figures 1-3.
Each refinery is practically unique. The process involves towers, vessels, piping,
valves, tubes, exchangers, and storage tanks; and each system can be divided into
four basic procedures: separation, conversion, treating, and blending.
The purpose of crude oil refining is to separate the crude oil into gases, gasoline,
kerosene, middle distillates (diesel fuel), fuel oil
-------
TABLE 6
Survey of Operating Refineries in the U.S.
(State Capacities as of January 1, 1967)
A S obama
AlaU.0
Arkansas
California
Colorodo
Dclawaic
Florida
Georgia
Hawa'i"
Ulirxm
Indiana
K amai
Kentucky
Louisiana
Moiy fond
Michigan
Minnesota
Mississippi
Missoun
MontU'ia
Nebiosto
Nevada
New jersey
New Mexico
New York
North Dokoto
Ohio
O t lahomo
Oregon
Pennsylvania
Rhode Hand
Teonciicc
Texas
Utah
Virginia
•//a^fiingtof1
Wcsf Virginia
WriCOMiin
Wyoming
Total
No.
Plants
5
1
6
31
4
\
1
2
1
12
II
1?
3
U
2
9
3
5
1
9
|
I
6
6
2
2
11
13
1
13
1
1
46
5
1
5
2
2
261
Crude capacity
b cd b ud
20, 770
20,000
85,730
1,429,050
39,500
140,000
3,000
6,600
35,000
683,800
500,525
360,250
126,425
903,950
19,400
150,700
106,100
152,400
72,400
116,325
3,000
2,000
491,000
it, 070
72,500
57,000
474,700
429,910
8,700
MB, 695
11,000
22,000
2,-J6,300
108. SSO
43,600
191,000
6,850
25,500
114,300
10,451,600
22,320
NR
39,400
1,497,410
42,765
150,000
3,000
10,000
NR
714,095
5rc,500
376,860
130,000
940,325
20,500
158,315
110,300
164,500
73,850
123,435
3,100
2,000
520,375
38,635
75,000
55,000
498,545
444,620
9.500
683,500
13,000
73,000
•2, 865, 935
112,755
45,000
2111,320
7,300
27,000
123,445
10,952,495
Vacuum
distillation
11,500
—
44,875
644,070
9,400
90,700
2,400
--
--
231,440
196,900
96,600
46,000
303,100
8,000
52,500
16,000
69,775
35,000
32.350
—
._
246,245
9,800
31,600
—
145,700
139,210
9,500
308,070
5,000
11,500
934,945
3O,000
._
60,'Oi
2,000
13,000
4E.800
3,856,535
Thermal
operations
—
—
16,650
513,925
13.200
42,000
--
--
—
124,820
88,150
39,800
21,000
110,600
—
23,700
22,OOC
6,700
14,300
15,150
1,300
--
45,945
1,600
4,500
1,500
60,900
75,000
--
85,750
--
—
284,555
—
14,000
8,100
700
—
6,445
1,642,290
— CKorge cape
Catalytic
Freih feed
--
--
31,000
388,500
li,500
62,000
--
--
13,000
279,030
208,000
136,900
42,400
368,500
--
54,000
40,100
46,000
36,300
35,300
--
--
230,445
•0,400
27,500
20,500
174,400
174,150
--
242,200
--
10,000
1,112,365
' 43,000
25,000
78,775
—
5,000
40,62?
3,953,235
'
cracking
Recycle
—
—
8,700
174,375
£,500
44,000
--
--
13,000
110,915
66,100
81,600
9,500
116,500
—
31,150
14,500
31,000
ie,OOD
30,200
—
--
91,760
7,400
13,000
10,300
97,400
84,825
--
110,960
—
5,000
375,865
19,250
15,000
32,610
--
5,000
IB, 060
1,649,935
Catalytic
ifforming
--
--
17,240
328,220
10,300
45,000
--
--
—
173,125
94,700
74,400
24,000
153,150
—
34,850
17,700
35,700
14,000
20,540
875
—
71,945
7,150
17,500
8,200
100,400
80,470
--
150,700
—
--
628,010
IB, 300
e.ioo
28,690
2,350
3,000
18,445
2,187,060
Hydrogen
treating
—
—
27,000
515,230
8,000
86,000
—
--
—
321,125
154,900
68,500
30,500
73,400
—
58,250
40,000
20,500
20,000
66,010
--
—
184,155
3,300
21,500
10,800
142,850
73,990
--
231,100
--
--
1,0)9,465
0,000
23,100
83,445
2,500
6,900
50,290
3,352,810
Altylo-
rion
--
—
5,900
60,690
--
5,000
--
--
3,800
44,695
28, ^00
29,520
--
61,400
--
7,850
6,200
12, 100
4,600
3,600
—
--
21,835
3,000
2,450
2,400
28,485
26,855
--
26,600
--
1,600
178,815
7,525
--
15,135
--
1,100
4,770
595,045
Pioductior
Polymcti-
zation
—
—
500
3,450
1,500
5,100
—
—
--
e,785
3,100
2,550
4,400
9,500
--
1,900
2,000
--
2,200
1,725
25
--
7,775
--
1,000
1.440
6,520
6,675
—
6,680
—
350
22,285
700
2,500
4,220
--
—
2,005
110,885
> capacity-lj
Lubes
—
—
4,675
26,330
--
--
--
--
--
5,700
10,950
4,000
--
25,815
--
--
--
--
--
--
8,000
--
—
--
4,200
11,650
—
26,330
--
--
78,660
--
--
--
1,750
—
1,070
209,330
-^
Coko
'Tons)
--
--
420
6,455
--
1,200
--
--
--
1,235
2,040
1,175
--
2,825
--
430
1,200
320
400
250
--
--
850
--
--
—
1,100
1,420
--
-'
"
--
2,635
--
90O
--
--
140
24,995
Abpholt
11,350
--
9,800
88,410
1,470
--
1,500
6,700
555
34,355
29,900
21,700
9,400
17,500
11,900
9,500
9,000
18.B60
20,000
15,125
--
--
47,400
2,430
10,500
--
39,520
16,850
5.900
14,500
6,000
3,500
50,400
2,850
--
5,100
—
4,000
14,115
542,850
Souice: Indusfriol Waste Profile No. 5, Pet'oleum Refining, Vcl. 3, November, \Wi.
-------
Crude oil
Gas
c
a.
Q.
o
a.
(A
o
Straight run naphtha
Heavy naphtha
Raw kerosine
Distillates
Gasoline stabilization
and
treatment
Stabilized straight
run gasoline
Catalytic reformer
Reformate
Hydrotreating plant
Reduced crude oil
-*- Fuel gas
Gasoline blending
stock
Kerosine
-»- Light fuel oil
and
diesel fuel
Heavy fuel oil
FIGURE 1. PROCESSING PLAN FOR TYPICAL MINIMUM REFINERY.
-------
(0
Crude oil
Wet gas
l\ JL
opping un
Amosphe
Straight run
naphtha
Heavy naphtha
LPG
plant
Alkylate
gasoline
Raw kerosine
Catalytic reformer
Reformate
Middle distillate
Hydrotreating plant
Heavy gas oil
5
Catalytic cracker
Vac gas oil
Crocked gaso.
a>^
Ji CL
Si
o
o
gos
Aviation gasoline
Catalytic gasoline
Li9n* fuel oil
-»~ Kerosine
-*- Light fuel oil
and
diesel fuel
/
Reduced
i 1*_
crude
••W^MM
C
Q.
O —
*~ C
O
5
Lube stock?;
Heavy fuel
»- Lube processing
J Acnhnlt <-+il Ic 1
L— . .^^
Lube stocks
Residuum
i
Asphalt
Heavy fuel oil
FIGURE 2. PROCESSING PLAN FOR TYP/CAL INTERMEDIATE REFINERY.
-------
Dry gos
CO
I
Crude oil
Wet gas
i
Light naphtha |
K
rj
3*
a.
n.
o
o
ZJ
J
LJ
£
a.
s
a
^
1 t
Heavy naphtha
Raw kerosine
Mddle ditillates
Heavy gas oil
Tvac gas
f\o\\
Reduced " - — —
crude ^
GT
1 ^ Hyc
crac
^~ u
t ,
i
i
( i
'
Co-
king
lit
i
i_
r
Catalytic
— cracking
unit
_J-
cracked
DC distillates
rrr
i
J
Hy
'c
ias plants
Saturate
and
jnsoturate
^ f.ntnlytir
^. reforminc
unit
L
Hydrogen |n2
IH2
^ Hydroqe
treating
*" unit
•Hvy hydro*
crocked
gasoline
droaen '
n
1
sulfide
Gc
soline_ Gosolr
treote
>e
L-
H2
Dry
s
— ^—
i
"
j
;
1 _
jlv plant! ^-4
[Poly gasoline o
-»-|Aikylotion | Alkylate _ ^
IStraight
run gasoline ^ -&
!Light hydrocracked gasoline^ 3
• i
i
i i Refomnate
gas -
i
r
L-^-
r
-»-Coker gasoline
— ^-lAsphalt
| Still
T
i
H
\
i
i
f
ydrogen
plant
Suitur piani |
Catalytic gasoline
Light fuel oil
Lube
processing
"' *r
^_ c "
^ °
3
^/
» ^-
_^
»-
1 +*-
\ '
^
Residuum
I Coker
T
*~ Fuel gos
LPG
Motor gasoline
Aviation gasoline
Olefins to
chemical
Kerosine
Light fuel oil
Diesel fuel
Sulfur
Lubes
Greases
Heavy fuel oil
Asphalt
FIGURE 3. PROCESSING PLAN FOR TYPICAL COMPLETE REFINERY.
-------
specified boiling point range is accomplished by distillation.
(1) Crude Disfi I lotion
Preheated crude oil goes into an atmospheric fractionating tower where it is vaporized
and fractionated into a gaseous overhead product which is condensed and depropanized
or debutanized to give straight run gasoline and other liquid products such as naptha,
kerosene, fuel oil, and lube distillates.
(2) Vacuum Distillation
The heavy crude fraction from the fractionating towers is vaporized and sent too vacuum dis-
tillation unitwhere the distillates are separated into vacuum gasoil, lubeoil, and asphalt
base. These initial productsmay be treated and used as feed stock for subsequent processing,
b. Conversion
In the conversion processes, the aim is to increase the yield of desirable gasoline pro-
ducts and, conversely/ to reduce the quantity of middle distillate fractions which have
lesser consumer demand. In addition to product distribution, the following conver-
sion processes upgrade component quality:
1. Thermal cracking is a familiar technique used in conversion. Here, heavy
hydrocarbon molecules are split under heat and pressure to produce smaller,
lower boiling hydrocarbons.
2. Coking is a severe form of thermal cracking in which the feed is held at
a high cracking temperature until coke is formed and settles out. The
cracked products are then sent to a fractionator for separation.
3. Catalytic cracking is the most common conversion process. In U.S. re-
fineries, catalytic cracking is used for approximately 50 percent of the
total crude capacity. Moreover, catalytic cracking yields additional
synthetic gaseous hydrocarbons, gasoline and reduced quantities of heavy
fuel oil. This process requires regeneration of the catalyst (usually an
alumina-silicate). Coke deposits, which form on the catalyst are burned
off in a separate regenerator vessel. Earlier catalytic processes em-
ployed fixed bed or once-through catalysts, but now moving bed and
fluid bed systems are more commonly used.
4. Hydrocracking, cracking in the presence of a high hydrogen partial
pressure is becoming more predominant. Hydrocracking compliments
catalytic cracking and adds flexibility in meeting seasonal product
demand fluctuations. The process is characterized by high liquid yields
of saturated isomerized hydrocarbons.
5. Catalytic reforming is a rearrangement of molecular structure to pro-
duce higher quality gasoline and large quantities of hydrogen. Plat-
forming, the use of platinum as a catalyst, is the most widely used
-44-
-------
reforming process. The catalyst promotes isomerization of paraffins and
dehydration of napthalenes.
6. Polymerization is the process where two or more gaseous olefins (unsatu-
rated hydrocarbons) are combined in a reactor with or without the presence
of a catalyst. When a catalyst is used, it is usually phosphoric acid.
7. Alkylation is the reaction of an olefin with aromatic or paraffinic hydro-
carbons to form liquid hydrocarbons in the gasoline range. The process
is carried out in the presence of a catalyst, AICI3, HF, or H2SO4.
8. Isomerization is the alteration of the structure of a straight chain hydro-
carbon to a more highly branched isomer having a higher octane value.
This is accomplished by the action of heat, pressure, and catalyst.
c. Treatment
Crude oil contains quantities of impurities, such as sulfur and certain trace amounts
of metals. Generally sulfur in oil occurs as sulfides, mercaptans, polysulfides, and
thiophenes. A substantial portion of the domestic crude in the United States contains
over 0.5 percent sulfur, and up to 10 percent of the crude contains as much as 2 per-
cent sulfur. Imported crudes also vary over a wide range of sulfur content. Over
recent years, the sulfur content of available crudes has generally increased, although
new sources of low-sulfur crude have been discovered. While sulfur removal from
basic crude is neither technically nor economically feasible at this time, desulfuri-
zation of products and intermediate stocks has come into wide use; the exception is
residual fuel where costs thus far have been uneconomic. Some desulfurization is
mandatory because of sulfur1 s bad effect on product quality of all materials, and on
catalyst sensitivity. It also produces odor and corrosivity.
Both physical and chemical procedures are available for treating products and feed
stocks. Physical methods include electrical coalescence, filtration, absorption, and
aeration. Chemical methods include:
1. Acid Treatment of hydrocarbon streams to remove sulfur and nitrogen com-
pounds/ using additives in the sweetening processes to oxidize mercaptans
to disulfides.
2. Solvent extraction, such as removing aromatics or sulfur compounds with
strong caustic, is widely practiced. The lighter aromatics are ex-
tracted from gasoline boiling-range material for sale as a petrochemical,
and heavier aromatics are extracted from fuel oil and lube oil fractions
for quality improvement.
3. Hydrotreating is used widely for desulfurization of petroleum products.
Hydrogenation converts organic sulfur compounds into hydrogen sulfide
for subsequent disposal or recovery. Generally, the extracted hydro-
gen sulfide is converted and recovered as elemental sulfur or is burned
to sulfur dioxide in plant boilers when the quantities do not justify re-
covery. This process also converts gum-forming hydrocarbons and diolefins
-45-
-------
info stable compounds. Commonly, hydrogen reforming for the process is
furnished by catalytic reforming units and frequently is supplemented by
generated hydrogen from steam-methane reforming processes.
4. Desalting is another necessary crude oil treatment process. At present,
probably over 90 percent of all desalting is done by the electrical method.
Only about 10 percent is desalted chemically. [33]
The characteristics of oily waste from a typical refinery are shown in Table 7.
d. Crude Oil Handling
Wastes encountered in handling and storage of crude oil are mainly in the form of
free and emulsified oil and suspended solids. For further discussion of the charac-
teristics of these wastes, the reader is referred to Appendix F of "The Cost of Clean
Water," Volume III, [32] and to Section IV of this report.
3. Effluent Sources and Characteristics: Non-oily Waste Water
The greatest volume of water used and waste water generated in petroleum refineries
is non-oily. These non-oily wastes come from several sources: spent cooling water
from surface condensers and heat exchangers, water from steam equipment, storm
water, sanitary wastes, and general cleaning waters.
a. Spent Cooling Water
Spent cooling water is generally classified as non-oily waste water. However some
of these waters are subject to minor oil contamination from leaks in heat exchange
equipment and from spills. They may also be contaminated with chemicals used for
scale inhibition, and slime and corrosion control. The cooling system can be either
a once-through or a recycle system.
(1) "Once Through to Waste"
Where a large amount of water is available, the cooling water is sometimes used only
once, and is then wasted or used for some other purpose. In either case, problems
with handling and treatment are minimal and usually require only a small oil separa-
ter or surge pond to protect against loss of oil to the receiving waters.
(2) Recycle Systems
The volume of waste water can be reduced significantly using cooling towers for re-
cycling water. Generally, water circulates through the cooling system and then i$
cooled through a cooling tower or spray pond. For each 10°F of cooling effected in
the cooling tower or spray pond, approximately one percent of the water is evapora-
ted. This results in an increased concentration of dissolved solids, and scale formation
-46-
-------
TABLE 7
Composition of Oily Waste Water
OPERATION
Sources
Typical Pollutants
Crude oi! handling
Process units
Specific Syntheses
Specific treating operations
Transfer lines. Ballast tanks. Butterworthing
Tank leakage. Desalting.
Overhead water from distillation, cracking,
coking, etc.
Alkylation and polymerization processes
Hydrodesulfurization and reforming processes
Specific process for specific compound
Sweetening, stripping, filtering
Oil, oily solids and sludge, rag interfaces, acids, sulfides,
chlorides, ammonia organic nitrogen and sulfur compounds
corrosion inhibitors, emulsion breakers, inorganic salts,
suspended solids.
Low molecular weight hydrocarbons, coke, gums, organic
acid, soaps, organic salts, phenols and phenolates,
cyanides ammonia.
Acid sludges, spent acids, caustics, oil, bauxite and
catalyst fines, corrosive products, HoS.
Hydrogen sulfide and miscellaneous gases (H^), coke, gums,
catalyst fines.
Acrylonitrile, polyacrylonitrile, acrylic acid, acrolein,
acetalcfehyde, HCN, etc.
r^S, mercaptans, amine, sulfonates, acids, bases, miscel-
laneous nitrogen and sulfur compounds, ammonia, cyanides,
furfural inorganic salts and suspended solids.
Source: Hydrocarbon Processing, Vol. 46, July, 1967.
-------
and corrosion become more serious. To control these problems chemicals are
added to the system, and circulating water (cool ing-tower blowdown) is contin-
uously or intermittently removed from the system.
This practice adds cooling-tower blowdowns, containing higher concentrations of dis-
solved solids, to the waste-disposal problem. However, the blowdown volume may
be as little as 0.75 percent of the cooling-tower circulation [38] .
b. Steam Equipment — Boiler Slowdown^
Except where demineralization or distillation is used for boiler water treatment, con-
centration of dissolved solids, in the form of sodium salts, build up in the boiler as
a result of chemical treatment. The concentration of salines in the boiler is controlled
by blowing to waste a given amount of the boiler water and replacing it with lower
salinity boiler feed water.
c. Storm Water
Surface runoff varies greatly from one refinery to another both in quality and quantity.
The quantity is a function of topographical and meterological factors and the quality
is a function of inplant practices. Although normally grouped under the classifica-
tion of non-oily waste water, storm water from refinery processing and tankage areas
are subject to oil and chemical pollution. The degree of pollution is a function of
"good housekeeping" in the vicinity of these areas.
Table 8 lists the sources and types of the mafor pollutants in the waste streams describ-
ed above and for sanitary and general cleaning wastes.
Table 9 is a summary of effluent data for both oily and non-oily wastes. It presents
a list of the pounds per day per thousand barrels of crude through-put of BOD, COD,
oil, phenols, suspended solids, dissolved solids, alkalinity, sulfide, phosphorus and
ammonia nitrogen in the effluent from refineries of different complexity grouping and
for different types of terminal treatment as discussed in Section V.B.I .a. of this report.
4. Forecast [74l
United States refiners will need to step up their construction activities if they are to
keep pace with the big boost in demand foreseen in the next decade. The 2] million
b/d demand for petroleum products in 1980 requires a domestic refining capacity of
about 18.5 million bc/d. This is some 6.4 million bc/d above the expected crude
capacity at the close of 1969. Keeping pace thus will require building at the rate
of 610,000 bbI/year.
This is just for the additional crude capacity that will be needed. To match output
vvifh changes in product demand, older plants will have to undergo modernization.
-48-
-------
TABLE 8
Composition of So-called Non-oily Waste Water
>o
Wafer Sources
Cooling Wale.
(exluding sea water!
Steam
Equipment
Miscellaneous
General cleaning
Sanitary wastes
Storm Water
% of Total
Waste Woter
40-80
00
10-20
10-20
<5
Flow Range (GPM)
100-6000
(5-60 gallon 'barrel
crudel
50-300 (peak 5001
Peak 300
30-300
Peak 400/acre
POTENTIAL POLLUTANTS
Source
Process leaks:
Bearings, exchangers, etc.
Water treatment
Scrubbed from air through
rower
Mate-up Water
Boiler Slowdown
Watte Condemate
Ion Exchanger regeneration
and rinsing
Rimes following acid cleaning
Lay up water
Equipment
Ground areas Misc.
Type
Extroctobte*
Uercaptons
Sulfldei
Phenoli
Cyanide
Misc. N compounds
Misc. f>on -ex tractable ortjflnici
Acids
Ch remote
Phosphate
Heavy metals
Fluoride
Sulfate
B ioc ides, algae ides
Misc. organic*
Acids
Hydrogen sulfide
Svtfur dioxide \
Oxides of nitrogen I
AmmonJd /
Porticulatei
Total dissolved solids
Particulars
Phosphates
Fli>oride
Total dissolved solids
^articulates
Extroctables
PKoiphote
Sulfite
Sulfide
Misc. organic compounds
Mite. N compound*
Heavy metals
Alkalinity
Extroc tables
Ammonia
Acid
Caustic
Total dissolved solidt .
Acid 1
Caustic )
(Twiphate J
Sulfitc
SwIFofe
HyaVazine
Portico lot es
Extroctables
Acids
Caustic
PKosprxrt*
Mies, wastes depending
on housekeeping, etc.
Range (ppm)
1-MOQQ
0-1000, but usually
less than 1 ppm
0-60
0-60
0-30
0-30
100-10,000
0-50
0-100
0-100
0-MOOQ
0-300
100-5000
0-TOO
0-5
0-2
500-10,000
5-300
0-10
1-50
0-50
0-5
0-200
1-100
0-10
50-400
0-100
0-10
Highly variable, greater
than solids removed
from make-up
Highly variable
Highly variable
Seure.: Hydrocarbon Procming, Vol. 46, July, 1967.
-------
TABLE 9
American Petroleum Institute Summary of Effluent Data
Pounds Per Day Per Thousand Barrels Crude Oil Throughput
TYPE OF EFFLUENT TREATMENT
01
o
BOD
Maximum
Minimum
Average (Arith)
Average (Weighted)
COD
Max! mum
Minimum
Average (Arith)
Average (Weighted)
Oil
Maximum
Minimum
Average (Arith)
Average (Weighted)
Phenols
Maximum
Minimum
Average (Arith|
Average (Weighted)
Suspended Solidi
Maximum
Minimum
Average (Arith)
Average (Weighted)
Primary
Refinery Classifi
A
I
C
cation
D
Intermediate
Refinery Classifical
E
A
B
C \
D E
Biological
Refinery Classification
A B
C
£
£
A
Total Refineries Reporting
Refinery Classification
B
C
D
E
Ibs/D/MBCD ~
87.6
5.8
36.5
54.2
84.2
0.6
16.4
29.0
3.5
0.9
0.8
101.1
0.8
26.0
56.6
208.9
0.2
70.7
73.2
544.8
12.3
168.6
207.1
154.3
0.6
33.4
25.4
59.2
0.1
11.4
13.4
345.7
71.2
85.3
350.0
5.4
116.5
111.1
234.0
10.8
123.7
114.9
292.0
3.0
56.6
44.6
5.6
0.6
2.6
2.4
350.0
10.0
70.2
42.1
257.8
32.0
122.5
146.9
1481.5
77.4
382.7
216.3
222.2
4.5
53.2
67.5
44.4
1.2
7.4
10.2
113.0
0.1
38.3
4O.7
143.8
92.6
118.2
125.1
366.0
152.2
259.1
287.9
88.2
6.8
47.5
58.5
9.5
1.6
5.6
6.6
94.1
33.7
63.9
72.0
5.5
0.8
2.7
1.2
1.1
0.01
0.6
0.9
155.0
2.1
78.6
12.3
28.7
25.6
27.2
27.2
79.0
41.9
57.4
58.5
6.3
0.5
4.4
5.1
2.1
0.2
1.1
1.3
15.7
10.5
13.1
13.1
82.9
13.9
42.5
43.4
144.1
56.0
99.5
109.1
52.7
1.8
12.6
17.2
21.6
0.3
7.5
6.4
56.3
0.1
18.4
20.6
96.6
75.6
86.1
88.8
395.3
155.9
275.6
245.0
21.6
7.6
14.6
16.4
338.3
0.2
29.2
26.2
600.0
4.8
95.4
77.8
64.0
0.1
5.6
5.6
0.5 8.6
0.04
0.3 1.0
0.5 0.9
154.5
1.3
26.2
20.7
60.8
2.6
33.0
33.9
209.0
26.9
97.0
96.5
37.8
3.7
14.4
14.1
7.0
•
1.8
1.9
16.3
3.0
11.7
12.8
235.4
5.5
67.4
67.6
649.4
26.3
167.7
159.1
163.4
0.4
27.9
26.5
13.3
0.01
2.5
3.9
72.2
4.0
25.3
26.5
168.4
65.2
115.5
107.7
1054.8
204.3
675.5
706.4
131.6
28.3
65.9
71.9
10.9
1.4
6.2
6.3
150.0
87.0
117.1
118.7
87.6
5.8
30.5
30.7
1528.9
9.0
769.0
535.1
84.2
0.6
13.0
18.0
3.5
0.7
0.8
155.0
0.8
43.5
33.1
338.3
0.2
600.0
4.8
114.3
120.7
154.3
0.1
16.0
11.7
59.2
3.8
4.1
345.7
38.3
37.3
350.0
2.6
69.6
68.6
234.0
10.8
108.3
107.2
292.0
1.8
31.6
27,6
21.6
3.9
3.7
350.0
0.1
38.7
27.0
257.8
5.5
86.2
118.6
1481.5
26.3
270.4
195.0
222.2
0.4
38.7
50.9
44.4
0.01
5.0
8.2
113.0
0.1
31.8
35.5
168.4
65.2
108.8
107.6
1054.8
152.2
471.4
566.1
131.6
6.8
50.4
62.3
10.9
1.4
6.0
6.3
150.0
7.8
90.1
103.8
-------
Ptimon
Rc'irory C lossl*i cot ipr
Disiolved Solids
Average 'Arith:
Average 'Weighted1
Alkalinity
Maximum
Aveiage (Arith1
Average (Weighted!
Sulfide
Maximum
Average lAi iihi
Average 'Weighted1
P
Max imum
Minimurn
Average lArithi
Average IWeightedi
NMjlN.
Maximum
Average (Arithi
Average (Weightedl
Total Refineries Reporting
A
13600.0
56.8
2511.4
4966.7
101.1
6.6
53.9
73.0
0.9
O.I
0.4
0.6
9
B
26E-.5
14.-
604.-
465.5
463.5
2.5
109.1
107.8
41 .9
0.03
11.3
5.6
0.1
0.5
0.5
199.0
3.E
59.8
64.6
23
C
7600.0
83.0
1667.1
1063.6
41.7
40.9
41.3
41.2
2.0
5.0
4.4
33.6
5.6
19.6
24.9
8
0 I
1157.4 350.0
241.9 78.4
596.2 214.2
576.5 177.6
56.1 220.3
45.7 65.8
51.9 143.1
48.3 163.9
0.7
26.4
43.9
0.9
27.8
4.8
U.3
17.6
9 2
TABLE 9
(Cont)
Pounds Per Day Pel Thousand Barrels Crude Oil Throughput
TYPE OF EFFLUENT TREATMENT
Intermediate Bi
Refinery Classification Refinery
A B C D 1 A, B
Ibs, 0,'MBCD
50.4 968.0 4800.0
36 7 529.4 4.5
43 6 703.2 522.5
47.8 720.2 386.1
9.8 71.1 109.2 736-7
3 3 1.4 93.0 0.3
6'6 42.4 101.1 125.1
9.1 48.2 103.2 90.1
1.1 o-oi
6.5 2.0
5.5 1.7
8.2
0.01
1 9
2 3
2 6 "8.0
1.2 °-03
1.9 »-7
1.7 10-0
44612 43
ological
ClassiFi
C
516.7
307.7
412.2
855.9
E7.2
14.1
44.3
40.8
0.6
3.2
1.9
1.9
0 2
1 0
7.0
2.1
3.9
3.6
6
Total Refineries Reporting
cation
D
543.9
257.7
371.8
357.3
0.1
2.2
1.0
1.0
0.2
o 5
0 4
69.7
2.7
22.0
31.1
8
Refinery Classif
I *
13600.0
36.7
1691.0
2695.1
154.7 101.1
70.6 3.3
112.7 30.2
110.2 34.7
6 7 0.9
1.0 0.01
2.9 0.3
3.1 0-5
5 15
B
4800.0
4.5
541.2
408.7
736.7
0.3
117.0
80.8
41 9
0.01
5.2
2.7
8.2
0.01
1.5
1.8
199.0
0.03
19.1
27.0
70
C
7600.0
83.0
1127.0
855.9
87.2
1.4
42.6
43.8
10.7
0.6
4.7
3.7
1.9
0.2
1.1
1.0
33.6
2.1
9.1
11.9
20
icotion
D
1157.4
241.9
485.0
489.6
58.1
24.6
44.3
41.8
117.7
0.1
18.1
36.6
1.5
0.2
0.7
0.8
69.7
2.7
18.2
23.2
18
E
6806.5
78.4
2026. B
3497.3
220.3
65.8
118.9
120.9
6.7
0.3
2.3
2.8
9.7
0.3
3.5
6.3
21.7
5.9
13.7
16.5
9
Source "1967 Domestic Refinery Effluent Profile," American
Petroleum Institute, September, 1968.
-------
Still other building will be carried out for the purpose of replacing two or more smal-
ler plants with one big plant in order to obtain the benefits of size. All of this should
add up to almost 3 million b/d of new refining capacity under construction at all times
based on the normal 3-year period between start of design and completion of the pro-
ject.
Insofar as refining technology is concerned, no major innovations are anticipated.
Catalytic cracking will continue to be the major tool for producing motorfuel com-
ponents, even though hydrocracking will take over some of the load. If limits are
placed on the olefin content of motor fuels, catalytic reforming, hydrocracking, and
the newer hydrorefining processes will come into greater prominence than will be re-
flected here.
Other features of 1980 refineries, other than their larger average size, will stem from
the better catalyst available then, instrumentation that permits closer control, and
still longer onstream periods. Use of improved metals which better withstand high
temperatures and pressures will make the latter possible. In processes involving crack-
ing reactions, new catalysts not only will make for higher yields but will give the re-
finer greater flexibility.
The improvements will not be limited to catalysts with cracking functions. Extensive
research with zeolitic types will pay off in better desulfurizing, alkylation, and hy-
drogenation catalysts. The recent development of reforming catalysts involving use
of rhenium or a similar metal, which has promoting and stabilizing effects on the
platinum, likewise could extend to other applications.
In the overall downstream processing scheme, hydroprocessing will probably be used
so extensively that processing gains will almost equal losses and fuel needs. In other
words, distillate yields will approach 100 percent of the volume of crude charged to
the refinery. This big boost in hydroprocessing, particularly for olefin and aromatic
saturations, is anticipated despite little hope for hydrogen costs much lower than
those of today. As more and more hydrogen finds its way into refinery waste-gas
streams/ however, cryogenic units will find wider use for recovering the hydrogen.
Thus while methane reforming costs may show little decline, recovery of the hydro-
gen from off-gases can help reduce overall costs.
In 1964, when refiners still felt the effects of their overbuilding spree some 4 years
earlier, the average plant was operated at the rate of 87 percent. By 1966 it was
operating at 91 percent of capacity. Ninety-two percent probably is close to the
maximum desirable for a yearly average. While 92 percent may seem low, it re-
sults in a utilization of about 96 percent during cold months. A fire, strike, hur-
ricane, or other disaster at only a few larger refineries could readily result in
shortages. The 18.5 million bc/d capacity projected for 1980 is based on 92 per-
cent utilization.
-52-
-------
New plants under way, and those to be built in the next 10 years will be designed
for different product patterns than most of today1 s refineries. Residual and midbarrel
heating fuels are losing out to motor fuel and turbine fuel. Thus, older plants that
have not already adjusted yields In pace with this trend will have to do so if they are
to remain competitive.
Light fuels — motor fuel and turbine fuel — will be the big gainers in the next de-
cade. On top of the gain registered in the past 5 years, they are expected to move
up to about 65 percent in 1980. The 9 percent gain may not seem like much of a
switch in yield patterns. But translated into barrels of gasoline and jet fuels it means
an additional 1 .5 million bbls. of these fuels in 1980. Most new plants will be de-
signed to convert some 70-80 percent of the crude charge into motor and jet fuels.
In terms of output, U.S. refineries will be turning out about 11 million b/d of these
light fuels at that time. Demand estimates for jet fuels vary but a commercial de-
mand of 1.6 million b/d — almost 1 million b/d above current levels — seems likely.
Armed Services needs cannot be fixed, but they have been running more than 600,000
b/d. Of this amount about 380,000 was from U.S. plants. Thus jet fuel needs could
easily exceed 2.1 million b/d in 1980. Motor fuels are projected to grow at about
4 percent/year. Output of these fuels, excluding that coming from natural-gas
liquids, will be about 8.8 million b/d in 1980. As a percent of crude, this will rep-
resent a yield of 52 percent.
The growth in light-fuels yields will be at the expense of the middle and bottom of
the barrel. The former will decline to about 15 percent from the present level of
21 percent. This will be principally due to increased pressure from natural gas in
home heating. In terms of daily refinery output, this will represent a slight gain to
about 2.5 million b/d.
The drive for cleaner air, plus the relative low-selling prices received for residual
fueJs, will result in yields declining to 3 percent from the present level of 6 percent.
This will represent a slight decline in daily production.
Daily demand for residual fuel oil is expected to climb by several hundred thousand
barrels—as oil takes over some of coal' s demand. But this will be supplied by im-
ported materials. U.S. refiners will continue to grind almost all their residual ma-
terials into lighter products.
Processing routes chosen for individual refineries are influenced by type of crude,
likes and dislikes of the refiner as to processes, and what the refiner individually re-
gards as the most promising markets. Generalization can be made, however, as to
the process to be used.
Catalytic cracking, at least for the bulk of the ' 70' s, will continue to be the favored
-53-
-------
tool for producing motor fuels. On a fresh-feed basis, if is now applied to about one-
third of the total refinery feed. In 1970 refineries cat-cracking will probably be e-
quivalent to 40 to 50 percent of a plant1 s crude capacity. Thus, some 2,5-3.1 mil-
lion b/d of new cat-cracking capacity is likely.
Catalytic reforming now is applied to almost 21 percent of refinery capacity. Apply-
ing this percentage to the anticipated 6.4 million b/d of new refining capacity trans-*
lates into 1 .3 million b/d of new refining capacity.
Hydrocracking, because of its newness/ cannot be projected in the same manner.
Opinions vary from company to company but it ultimately may be applied to some
15-20 percent of the crude charge. The amount of this new capacity probably will
be in the range of 1 to 1 .25 million b/d.
le,
Other hydroprocessing steps now are applied to about one-third of the crude charg_
The outlook is for at least 2.2 million b/d of new hydroprocessing to accompany the
new crude capacity.
Alkylation and isomerization, both relatively high cost alternatives to antiknock com-
ponents, will likely become much more popular before the decade is over. Should
the lead content of motor fuels be reduced, alkylation capacity built will be well
above the approximately 400,000 b/d that would normally be expected.
Coking will continue to be the most favored of the thermal processing routes. It still
must be looked upon as a low-cost means of disposing of residual oils, but there are
some developments which may make it a more economic tool, too. Among these are
new routes for converting coke into carbon black, for converting it into activated
carbon, and needle coke in the form of carbon shapes to be used in spacecraft and
other applications.
There is little question as to the steps refiners will have to take insofar as residual
fuels are concerned. Tightening air pollution ordinances require that they either
produce a low-sulfur product or no residual fuel at all. The ready availability of
large quantities of low-sulfur resid from Caribbean and other foreign refineries will
probably result in the U.S. becoming almost totally dependent upon imports. Low-
sulfur North African resids are being blended with Venezuelan and other high-sulfur
resids at delivered Eastern seaboard prices well below those domestic refiners can
post. Unless some development in catalysts occurs which makes if economically fea-
sible to directly hydrocrack high-metal resids, U.S. refiners will fill an increasingly
small portion of what is expected to be a growing market. The laws have yet to be
written and passed, but the odds favor stricter limits on motor fuel composition. Lead
content readily could be lowered by the late ' 70' s. If is also entirely possible for
volatility to be lower and for the olefin content to be reduced. None of these pose
a problem of know-how, but they do lead to much higher capital costs and more op-
erating expenses.
-54-
-------
B. Pollution Profile
1 . Waste QuantiMes
a. Refinery Complex!ty, Parameters [35]
Refinery effluent characteristics, both quality and quantity depend on processing
complexity, therefore the immediate problem is to assess and classify the myriad re-
fineries operating today. This was done by the American Petroleum Institute (API)
for the following purposes:
1. To provide the petroleum industry with valid data on refinery effluent
loads and current waste control practices for preparation of accurate
responses to legitimate inquiries.
2. To develop reliable data on waste control performance to prevent un-
realistic comparisons of waste load characteristics between refineries
of varying processes complexity and waste load potential.
3. To allow the comparison of effluent control for typical types of refineries
under varying conditions of waste treatment and control.
4. To establish a realistic basis for development of good practices in refinery
water pollution control.
To satisfy all these purposes a questionnaire was mailed to all 261 API and National
Petroleum Refiners Association (NPRA) member companies. In response, 171 replies
were received representing 93 percent of the domestic capacity. From this informa-
tion, a categorization system was adopted and reflected oil processing complexity
on the waste load characteristics. The categories are:
A Crude topping (Atmospheric, Vacuum Distillation)
B Topping and Catalytic Cracking
C Topping and Cracking plus Petrochemicals
D Integrated (Topping and Catalytic Cracking plus Lube Oil Processes)
E Integrated plus Petrochemicals
In this report product quality upgrading technology (reforming, alkylation, hydro-
treating, drying and sweetening), was not delineated because of their widespread
use. Specific processing (solvent refining, dewaxing and lube oil manufacturing) ^
are implied in Categories D and E. Some refineries manufacture oil-derived chemi-
cals and their waste streams are composited for treatment and disposal; therefore,
Categories C and E reflect the additional petrochemical waste loads. Category A
refineries represent some 3 percent of U.S. refining capacity, and Categories B, C,
D and E account for approximately 28 percent, 19 percent, 21 percent and 16 per-
cent respectively.
In addition to classifying each refinery on the basis of system complexity they were
-55-
-------
further evaluated and classified by type of waste treatment. Terminal treatment
categories were:
1 . Primary Treatment Gravity Separation
2. Intermediate Treatment Chemical Flocculation
Air Flotation-Without Chemicals
Air Flotation-With Chemicals
Filtration
3. Biological Treatment Activated Sludge
Trickling Filter
Stabilization Ponds
With Aerators
Without Aerators
Oxidation in Cooling Towers
Approximately 33 percent of U.S. refining capacity reported primary treatment. An
additional 11 percent reported intermediate treatment and 42 percent reported some
form of biological treatment.
The principal objective of the API report as stated before was to assess the current
overall state of refinery waste control performance. No in-depth attempt was made
to evaluate the following factors which affect any industrial effluent quality survey-
1 . Inadequate water utilization and discharge volume data did not permit
reliable correlation with waste loadings.
2. No rigorous attempt was directed toward accumulating data on all ?n-
plant waste load reduction procedures. This area has been reported in
varying depth of inquiry by others/ [32,37] and its importance is recog-
nized. Presently there is no assurance that a material balance can ac-
count for overall waste loads in complex refinery operations.
3. Biological treatment covers a broad range of design and operating effect-
iveness accounting for some of the effluent data scatter. A more rigorous
evaluation of refinery effluent biotreatment procedures is required. A
special API-sponsored study group, within the Committee on Disposal of
Refinery Wastes, is pursuing current practices in more depth.
4. No distinction has been drawn between "old" and "new" refineries. New
"grass roots" plants/ incorporating modern process, off-site and drainage
technology should produce a relatively clean effluent. However, it is
not clear whether "modernization" of older refineries, which often is pur-
sued on a progressive unit-by-unit basis, has a significant effect on overall
waste loads.
5. Although no rigorous attempt was made to insure consistency of analytical
methods in reporting contaminant data, it is believed that common standar-
ized procedures were utilized in reporting BOD, COD, phenols and sus-
pended solids. There is less confidence in the effluent oil data because of
-56-
-------
..: sampling procedures and alternative laboratory techniques still in use.
The information gathered by this report is the most comprehensive to date on refinery
waste treatment. The API Refinery Effluent Survey concludes:
1 . Refinery effluent pollution depends on the degree of processing complexity.
2. Within specific categories, effluent quality comes from the extent of waste
treatment.
3. Intermediate and biological procedures yield substantial improvement over
primary treatment for all major contaminant categories. (It is not clear
that biological treatment produces significant benefits over intermediate
treatment.)
4. Using data from waste treatment facilities, it is not possible to categorize
refinery effluents solely as operating with "primary", "intermediate" and
"biological" treatments. Numerical parameters, as to complexity and
capacity reflect waste control performance.
5. Following waste treatment, the overall net U.S. refinery effluent has the
following cumulative parameters.
Parameter Pounds Per Day
BOD 800,000
COD 2,500,000
Oil 360,000
Phenol 55,000
Suspended Solids 500,000
Table 9, a summary of effluent data arranged by type of terminal treatment and by
refinery complexity grouping, presents a summary of refinery waste load data (as
pounds per day per thousand barrels of crude through-put) including BOD, COD,
oil, phenols, suspended solids, dissolved solids, alkalinity, sulfide, phosphorus and
ammonia nitrogen.
b. Waste Effects
The effect of oil pollution upon wildlife is adverse. Waterfowl that alight on oil
areas or on water covered with oil are usually rendered flightless. It is important to
realize that the oils causing the worst pollution are ordinarily the most stable com-
pounds or mixtures, [36] but this is true only for physical effects because lighter hydro-
carbons are more toxic.
Remarkably/ scanty information is available on the toxicological aspects to man or
to warmblooded animals ingesting oil and oily substances. Apparently, taste and
odors render the oily water unacceptable long.before they become toxic. Studies
of cattle, sheep, and hogs drinking water polluted with crude oil showed that they
-57--
-------
became sick due to the laxative properties of oil. The Ohio Department of Health
has specified a limit of 30 mg per liter of emulsified oils in creeks used for grazing
cattle [36] .
The adverse effects of oil substances on aquatic life are summarized below:
1 . Oil and emulsions of oil adhere to the epithelial cells of fish gills and
interfere with normal respiration. With mild pollution, the mucous washes
away trie oil. In heavy pollution, however, oil cannot be washed away
and accumulates on the gills.
2. Oil and oil emulsions coat algae and other plankton and destroy them.
These plants are food sources for fish. Dead organisms clump together,
settle to the bottom, and decompose.
3. Oil and oily substances settle and coat the bottom. Benthal organisms
may be destroyed and also spawning may be prevented.
4. Fish flesh may become tainted and thus unmarketable.
5. Organic pollutants deoxygenate waters and kill fish.
Wilber [36] stated that crude oil can produce drastic and long-term effects not only
on the plants and organisms themselves but also on the habitat. Each refiner must
monitor the natural water characteristics into which wastes are discharged. Such
mandatory knowledge determines the effects of his wastes.
Solutes in wastes may exist in varying degrees of dissociation or ionization. The dis-
sociation ranges from none, as in some organic compounds, to practically complete
ionization, as in some acids and inorganic salts. Because of chemical reactions pro-
moted by dissociation, solutes have marked chemical effects on receiving waters.
Undissociated solutes may react chemically, but in general, at slow rates. There-
fore, they have lesser chemical effects than do dissociated or ionized solutes. Any
solute however, may have a pronounced physiological effect whether dissociated or
not. An understanding of molecular structure, dissociation, and mass reaction is
helpful when considering solute effects in waste water.
These effects are discussed in the literature [37,38,39] under the headings: pH and
salinity; acidity; alkalinity; dissolved oxygen; oxygen demand; hardness; osmotic ef-
fects; toxicity; tasteandodor; color, turbidity, and suspended matter; oil and tem-
perature.
These parameters are not arranged in order of importance. An important character-
istic in one locality may be secondary elsewhere. Because of synergistic and anta-
gonistic characteristics and relationships, the importance varies.
2. Wastes Reduction, Treatment, and Costs
The current overall state of refinery waste control performance is difficult to assess.
-58-
-------
A study of the art is assisted by examining Tables 10 and 11.
Table 10, "Summary of Wafer Use and Effluent Treatment, " [35] gives a breakdown
of all refineries reporting by complexity grouping and type of terminal treatment.
It also shows the crude oil through-put capacity classified by type of terminal treat-
ment: primary, intermediate, and biological.
Table 11, "Summary of Miscellaneous Treatment and Disposition, " [35] lists the num-
ber of refineries by complexity grouping which dispose of their wastes by one or more
methods. These methods separated into physical, biological, and chemical are de-
scribed below.
a. Physical Treatment
Included in this type of treatment are gravity type oil separators, oil-water emulsion
breakers, air flotation, and centrifugation.
0) Oil Separators [38]
Oil in refinery waste water is recovered by oil separators. The separator most widely ac-
cepted in the industry was designed by the American Petroleum Institute (API), and
is a gravity type, oil-water separator. Separation depends upon the difference in
specific gravity of oil and water. Important factors for effective performance are
design, velocity of flow through the separator, and settling time.
If the waste water contains emulsified oil, not all of this oil will be separated in a
gravity separator. If the oil is to be retained in the separator the emulsion must be
broken before the waste reaches the separator.
(2) Pit-water Emulsion Breakers [38]
Many refinery operations produce emulsions. The emulsions may be either oil-in-
water (minute oil globules dispersed in water as the continuous phase) or water-in-
oiI emulsions, where oil is the continuous phase. Generally, oil-in-water emulsions
are milky in appearance and pass through gravity separators without breaking. Emul-
sions lighter than water rise to the surface and are separated with other oils. Con-r
versely, emulsions heavier than water are deposited with separator or tank bottoms.
In addition to the oil and water, a third substance, an emulsifier,. is present when
stable emulsions are formed. Common emulsifiers, -for oil-irv-warer systems, are
sodium and potassium soaps, and precipitated sulfides plus surface active solids.
Common emulsifiers, for water-in-oil systems, are multivalent metal soaps, oxides
and sulfides plus sulfide ion.
Emulsions form by agitating two immiscible liquids, and can be minimized by proper
-59-
-------
TABLE 10
Summary of Water Use and Effluent Treatment
Type Effluent
Fresh
Brackish
Flow
Recycle
Once Through
No Answer
Water Source
Freth
Salt
Treated
Type of Effluent Treatment
Primary
Intermediate
Biological
Treatment of Selected Wastes
Sour Water
Spent Caustic
Other
No Answer
Effluent Discharge To
Fresh
Brackish
Salt
Other
A
11
15
12
2
1
13
.
8
13
5
2
5
5
2
7
4
7
3
5
Refinery Classification
B
62
69
68
18
1
62
1
49
70
13
43
45
41
16
5
40
26
8
4
C
17
20
17
11
18
2
13
20
6
6
16
20
6
-
8
10
4
1
&
16
18
17
9
16
1
10
18
5
8
14
17
7
1
6
7
1
4
E
8
9
9
8
9
6
9
3
5
7
9
3
4
5
-
Number of
Refineries
114
131
123
48
2
118
4
86
130
32
64
87
] 12
34
13
62
55
16
14
Total Refineries Reporting
15
70
20
18
132
Source: "1967 Domettfc Refinery Effluent Profile, " September,
1968.
-------
TABLE 11
Summary of Miscellaneous Treatment and Disposition
Refinery Classification
Other Disposal Method? Reported
Deep Well
Stripping
None
Sanitary Sewoge
Complete Treatment
Partial or Untreated
No Answer
Sludge Disposition
Oil - Water Separator:
Settling, Filtering, Centrifuging
Incineration, Digestion
Land Disposal, Impoundment, Dewatering
No Answer
Bio-Treatment:
Settling, Filtering, Centrifuging
Incineration, Digestion
Land Disposal, Impoundment, Dewatering
No Answer
Water Conditioning:
Settling, Filtering, Cenlrifuging
Incineration, Digestion
Land Disposal, Impoundment, Dewatering
Discharged In Effluent
No Answer
Septic Tanks Discharge To
Plant Sewer
Percolation, Evaporation
Aerobic Bio-Treatment
Municipal Sewer
Other
Not Applicable
Stripper Discharge To
Plant Sewer
Percolation, Evaporation
Aerobic Bio-Treatment
Muncipal Sewer
Desalting Unit
Other
(Not Applicable
2
13
13
2
10
3
34
33
5
67
1
40
30
3
46
1
13
6
1
13
6
15
1
16
3
11
7
4
15
2
11
1
12
5
Number of
Refineries
4
65
63
10
115
13
79
53
B
86
39
1
3
_
11
9
_
8
_
_
1
6
2
_
1
1
_
_
.
13
_
34
5
31
36
10
20
4
2
_
34
34
5
_
6
_
5
18
36
_
11
-
9
7
5
1
1
-
.
13
13
3
_
2
_
2
6
7
-
10
2
6
12
7
3
2
-
.
6
11
1
-
3
1
2
4
7
1
5
1
3
5
1
2
2
-
-
4
5
-
-
-
.
-
5
4
1
63
8
60
69
23
34
9
2
1
63
65
9
1
12
1
9
33
67
Total Refineries Reporting
15 70 20 Ijl
Source: "1967 Domestic Refinery Effluent Profile", September, 1968.
132
-------
selection of mechanical methods. Oversized pipes in drainage systems reduce turbu-
lent flow and lessen emulsion formation. Steam syphons tend to cause stable emul-
sions in water and oil systems. Also, barometric condensers form emulsions.
Emulsions can be broken by different methods: heating, pH adjustment, distillation;
centrifuging, vibrations, quiesence, electrical current, and chemicals. Heat helps
in nearly all emulsion-breaking operations. Heating (water-in-oil emulsions) lowers
the viscosity of the oil and promotes settling of free water. Also, heating increases
the vapor pressure of the water and breaks the film around the emulsified globule.
Oil and water phases may be separated by using caustic to adjust the pH between
9 and 9.5. Distillation breaks emulsions, and separates the water and light oil from:
the emulsifying agent which remains in the residue.
With large differences between the specific gravity of the oil and water, centrifug-
ing will break stable mixtures. Water-in-oil emulsions, stabilized by finely divided
solids, can be treated by diatomaceous earth filtration. The emulsion is forced
through a layer of diatomaceous earth deposited on a continuously rotating drum.
Any suspended solid matter in the emulsion is retained on the filter media, and
globules of the dispersed phase are broken on passing through the media, thus break-*
ing the emulsion. The oil and water phases will separate on standing (quiescent con-
ditions), but if an emulsifier is present, care must be exercised to prevent excessive
agitation and the consequent reformation of the emulsion. Some emulsions can be
broken by passing them between two electrodes which permit a high-potential, pul-.
sating, unidirectional current through the emulsion. The electrically attracted water
globules coalesce, until the mass is sufficiently large to settle by gravity. Crude
oil may be desalted and dehydrated using this method.
Emulsions can be severed by chemical methods which vary according to the proper-
ties of the emulsions. Perhaps the most widely used chemical method is coagulation
or flocculation. A coagulating agent, alum, ferric chloride or lime, is added in
doses from 1/8 to 1/2 pound per 1,000 gallons, and mixed with slow stirring. The
colloidal oil adheres to the flocculated precipitate and settles to the bottom. A
detailed discussion of this process can be found in succeeding pages.
(3) Air Flotation [38]
Oil and suspended matter can be removed from water by air or gas flotation. The
oily water is saturated with air under pressure and passed into a flotation chamber
at atmospheric pressure. Under reduced pressure, the air is released from solution
as small bubbles which lift the free oil globules to the surface, where they are re-
moved by mechanical flight scrapers. Air is generally used in treating refinery
wastes for disposal. Either air or natural gas is used to treat produced water for
injection in secondary crude oil recovery projects. Use of air has the disadvan-
tage of saturating the water with oxygen and thus increasing corrosivity of the water.
-62-
-------
Natural gas will not oxidize dissolved ferrous iron (or saturate the water with air)
and will sweep dissolved oxygen out of the water rendering the water less corrosive.
Both air and natural gas will remove dissolved carbon dioxide from the water. This
will cause the precipitation of calcium carbonate from waters saturated with calcium
bicarbonate. This should be considered in designing the system. Also, the use of
natural gas will require safer/ controls to reduce the potential fire hazard.
(4) Centrifugation
Sunray DX Oil Company, at its refinery at Tulsa, Oklahoma, has developed an
emulsion-breaking method by two-stage centrifuging [40] . The first stage is a solid-
bowl scroll-conveyor type which removes most of the solid matter, and the second
state is a nozzle-discharge disk-type centrifuge to separate oil, water, and fine sol ids.
This method is said to be very economical. The engineers who developed it feel that
any plant requiring more than a simple treatment to resolve emulsions will find the
centrifuge process economically fustifiable. The centrifuges used in this development
were conventional types.
(5) Future Oil, Water Separators
A new oil-and-water separator may prove useful in eliminating free and emulsified oil
from Industrie I-waste discharges [41] . It is claimed that the system is able to remove
oil, in the free-floating state or emulsified to a residual content of 1 milligram per
liter or less, in a single pass through the unit. The unit has no moving parts to re-
quire maintenance. The system coalesces minute droplets in the influent into larger
drops. These drops rise to the surface, or drop to the bottom in the case of heavier-
than-water oils, and are then drawn off. The coalescing action is accomplished by
passing the influent through a semipermeable barrier formed of a specially activated
medium. A unit with a capacity of 100 gallons per minute, treating a waste with an
oil content of 4,000 milligrams per liter, was claimed to yield an effluent of 1 milli-
gram per liter oil. Standard sizes with capacities up to 600 gal Ions per minute are said
to be available.
Another new development is a process for direct steam generation from unsoftened oil-
field waste water [42] . Called Thermo-sludge, the process is claimed to make thermal
recovery possible in many oil-producing areas, heretofore considered impractical. The
process claims to eliminate the need for freshwater pipe lines, water softening, oil
separation, or other pretreatment systems. The steam generator converts dirty, hard,
salty, and oily low-gravity waste water from oil-producing formations, directly into
100 percent quality steam. The capacity of the unit is said to be 20 million BTU/hour
at 1,500 pounds per square inch maximum working pressure. If the claims of the devel-
opers are borne out in 'full-scale working installations of the system, it may prove to
be a very useful unit in the elimination and disposal of oilfield wastes. It could be
used by oil refineries or other plants to upgrade present effluents at moderate cost and
-63-
-------
provide a useful by-product. It has been demonstrated in actual practice at a petro-
leum refinery. Although developed originally for the oil Industry, it has possibilities
for use in other industries which have wastes with the following characteristics:
Materials Milligrams per liter
"oil o -1,000
Total dissolved solids 1,000 - 50,000
Hardness 100 - 2,000 as CaCO3
Silica 0-150
Sulfate 0-1,000
The generator may be fired by crude oil, diesel fuel, fuel oil, LPG, or natural gas.
The Royal Dutch/Shell research group has used small quantities of oil to remove soot from
water. Already widely used to remove soot from the water employed in making gas
from oil, the process is be ing considered for removing solid particles from municipal
sewage. Heart of the process is the Shell pelletizing separator, a mixing device that
brings the suspended solids in water into intimate contact with a stream of oil. The
oil makes the solids mass together and the resulting agglomerate forms pellets which
can be removed readily from the water. With sooty water, 99.95 percent of the soot
is removed, and the resulting pellets can be used as fuel. An obvious extension of
the process is the purification of water contaminated with oil. The oily water con-
tacted with soot, or some other oil-wettable powder, forms pellets incorporating
and removing the oil [43] .
b. Biological Treatment
Objectives in purification of industrial waste waters are to reduce amounts of solids and
salts, acid or caustic concentrations, eliminate toxic substances above maximum Iimirs,
and reduce oxygen consuming organics [44] .
Generally speaking, any oil present in waste water must be removed before the waste
water can be discharged into surface waters. From a practical standpoint, it is de-
batable if minute amounts of oil in surface waters are detrimental to aquatic life or
the future use of the water [38] . Biological purification depends on the nature and
concentration of the organic substances in the waste water.
Most organic compounds are eliminated by the ever-present bacteria in the receiving
water, and are used either for synthesis of bacterial substances, or oxidized for
energy production. Dissolved oxygen in surface waters is utilized by microorganisms,
fish, plants, and oxidation processes in the self-purification of waters. As the supply
of oxygen is consumed, it is replenished by oxygen diffusion from the air. Oil films
interfere with reaeration of water, and can result in death of fish and termination of
the self-purification process [38] . If the oxygen concentration in the water, necessary
-64-
-------
for the existence of normal water flora and fuana, is adequate, biological self-puri-
fication will occur without the production of nuisances. However, if soluble organic
substances, brought into the receiving water with industrial or municipal waste waters,
impose an oxygen demand greater than the reaeration potential, the oxygen content
declines until anaerobic conditions prevail. Foul smelling products of anaerobic de-
composition result [44] .
Temperature is one of the most critical environmental factors affecting biological waste
treatment systems. Increasing the temperature of a biological system increases the rate
of metabolic reactions . For common microorganisms in waste water treatment systems,
the upper limit of optimum microbial metabolism isaround 98° F (37°C). The solu-
bility of oxygen in water decreases as the temperature increases. It appears that
temperature is no problem when total refinery waste waters are treated separately
[45] . Basically, biological treatment systems include: oxidation ponds, towers and
ditches, aerated lagoons, trickling filters, and activated sludge.
(1) Oxidation Ponds [45] .
Oxidation ponds (see Figure 4 for a schematic cross section of an oxidation pond [46])
have definite promise for the treatment of dilute wastewaters, especially those with
radically fluctuating hydraulic flows. The major advantage of oxidation ponds is their
lack of a need for operational control. Operational data on oxidation ponds is limited,
Results obtained in Kansas indicated that oxidation ponds must have waste concentra-
tions of less than 20 mg/l oil, 15 mg/l sulfide, and 7 mg/l phenol, as well as a mini-
mum ot 60 days retention [47] . A study of two refinery oxidation ponds showed that
BOD reductions of 43-96 percent, phenol reductions of 61-99 percent, and COD re-
ductions of 20-60 percent were possible [48] . Retention for 60 days can produce ac-
ceptable phenol reductions in oxidation ponds.
Disadvantages of oxidation ponds are that they require large areas of land and the
effluent quality fluctuates radically from summer to winter. Maximum treatment
is obtained in the summer when temperature is a maximum. The nature of refinery
wastes requires oxidation ponds larger than those normal for other wastes. The
emulsified oils reduce light penetration and algae growth; however bacterial action
combined with atmospheric oxidation appears to be satisfactory for breaking the oil
emulsion, provided adequate time is available for the reactions. Oxidation ponds
are commonly used following other treatment units to produce a more polished effluent.
(2) Oxidation Towers
Oxidation towers (see Figure 5 [38]) for biological treatment of dilute wastewaters
at the Sun Oil Company refinery in Toledo, Ohio, have produced a unique treatment
system somewhere between trickling filters and activated sludge. Sun Oil Company
developed a cooling tower system to oxidize the organics in the waste and recover
water for reuse. Over eight years of operational data indicate stripping the spent
-65-
-------
5'
U
4
en
Q
I
CD
o
cr
:;
y
m
o
uj
<
z
' :
:: I
(CH20)X+02— ^C02+H20
SEWAGE ORGANICS ' ^QNE"
(olgoe)
a •
• »
i *
, •
1 'ANAE
• • Z(
. •
S~^\
/ 2CH 0 — CH COOH S~\' ' '
£- X j f \ B ,
3 2 H4
:ROBIC /
)NE
SLUDGE
TEMPERTURE —
l-IUUKt A. bCHEMATIC CROSS SECTION OF AN OXIDATION POND.
-------
CITY
WATER
REFINERY
FIRE WATER
SYSTEM
ll
ONCE-THROUGH
COOLERS
PUMP GLANDS,
HOSES, MISC.
I
STORM WATER
a
INFILTRATION
API
OIL
SEPARATOR
IMPOUNDING BASIN
PROCESS
CONDENSATE
COOLING
TOWERS
REUSE
WATER
COOLING TOWER
SLOWDOWN
RECEIVING STREAM
FIGURE 5. BIOLOGICAL WASTE TREATMENT SYSTEM EMPLOYING COOLING
TOWERS. [38]
-------
alkali with steam and flue gas removes 99 percent of the reduced sulfur compounds.
the cooling tower system produced 99.9 percent phenol reduction, 90 percent BOD
reduction, 80 percent COD reduction, and a net savings in water costs of $100/000/
year.
Thermal power plants, steel plants, and petroleum refineries use river and lake water
in vast amounts for heat rejection. A typical refinery, operating at 50,000 b/d,
rejects about 0.5 billion BTU/hr to cooling waters. Heated discharges can affecr
the quality of water in many ways. But two principal ways are: (1) the influence
on the ability of the water to carry and assimilate waste, and (2) the effect on the
biodynamic balance of aquatic life forms [50] .
Under normal conditions, the cooling tower reduces the total amount of waste water
being returned to the stream. It airstrips volatile compounds and serves as an equal-
ization basin. This prevents shock loads of unwanted materials from entering the re-
ceiving stream. By its very nature, the coolingjower eliminates one of the> major
sources of heat pollution. Cooling towers can pollute streams through careless handl-
ing of boiler blowdowns. Streams then receive both toxicants and nutrients from the
cooling system's waste, while pure water evaporates and escapes to the atmosphere
[51].
(3) Oxidation Ditches
The oxidation ditch [41] (see Figure 6 [52] ) (or Dutch ditch), developed in the
Netherlands about 1953, has been adopted rapidly in the United States. As of Sep-
tember, 1966, it was reported that there were more than 75 installations in this
country and Canada treating sewage and numerous industrial wastes.
Although it has many of the features of the common oxidation pond, the oxidation
ditch (OD) does not depend on natural absorption of atmospheric oxygen. In reality
the OD is a form of activated sludge (depending entirely upon mechanical aeration
and agitation to maintain circulation in the ditch itself), and it induces atmospheric
oxygen into the waste water by means of rotors which spray the liquid over the sur-
face of the ditch.
The oxidation ditch has been used in the Netherlands for many years. Dr. A. Pasveer
developed it in that country as early as 1953. The Dutch ditch accomplishes long
term oxidation, usually in excess of 24 hours. Sufficient oxygen is provided to stab-
ilize the primary organic solids, and remove the dissolved and colloidal matters.
Design considerations are: 1) waste characteristics, 2) the waste volume, 3) the
area required for the installation, and 4) control of mosquitos and odors. In practice,
the OD is an economical method of treatment requiring little accessory equipment.
The system consists of the circular ditch, a final clarifier or sedimentation unit, and
a means for dewatering small amounts of sludge withdrawn periodically. The ditch
-68-
-------
&
I
f
b
ICLO(
••
V
•ROCEC
^f^
U
^ 1
I
J
RE
VLET to} Dl
OTOff ibl Dl
UTLET (c) Dl
V
CO }
CO > OR
01 \
CO
Dl
CO
CO
CO
CO
DI » DISCONTINUOUS
CO " CONTINUOUS
FIGURE 6. TYPICAL DESIGNS OF OXIDATION DITCHES. [52]
-------
combines the aeration and sfudge digestion Into one unit. Aeration rotors provide
atmospheric oxygen and circulate the mixed liquor through the ditch. Advantageous
characteristics of the ditch are: 1) simplicity of operation, 2) ease of maintenance,
3) low-cost construction and operation, and 4) flexibility fn the degree of treatment.
The ditch should be lined with an impervious material to prevent leakage. The ditch
may be a single loop, a double loop, or any other shape as long as a continuous cir-
cuit is maintained. The median strip should be of such width that the radius of curvature at
the ends of the ditch is not too sharp, thereby restricting the horizontal flow induced by the
aerators.
Oxidation ditches have satisfactorily treated wastes from slaughterhouses, dairy and
milk processing plants and oil refineries. The following loading of an oxidation
ditch has been reported successful: 13.5 pounds of BOD per 1,000 cubic feet of ditch
volume, and a hydraulic loading of 16,000 gallons of liquid capacity per day per
linear foot of rotor. In one specific case, the concentration of solids in the ditch
was from 3,000 to 8,000 milligrams per liter, and the reported removal of BOD was
80 to 97 percent. Regardless of the loading rate the ditch should provide a detention
period of at least 12 hours and a depth of 3 to 5 feet.
(4) Aerated Lagoons
The aerated lagoon was developed to permit additional organic loading on oxidation
ponds. The aeration units allow a dispersed microbial sludge to develop while stab-
ilizing the waste organic components. Three primary advantages are simplicity of
operation, a high degree of waste stabilization, and positive oxygen transfer. One
disadvantage is that the effluent will contain considerable dispersed microbial solids
unless several series of ponds are used [45] .
Using aerated, heated lagoons, Continental Oil Company has reduced effluent
phenols by 98 percent in the Billings, Montana refinery [53] . Biologically treated
waste water averages 210 gpm, and operating cost amount to $115 per day. The
collection system consists of two drums. One drum collects water from low pressure
receivers, and the second drum receives water from high pressure sources. Non-oily
waters are segregated from oily waters for clarification and disposal into the Yellow-
stone River. The oily waters pass through an API separator for removal of floating
oils and oil sludges. The bulk of the waste water is pumped into an aerated holding
lagoon. Surge flow leveling and mixing In the holding lagoon yield a more uniform
waste for additional treatment. The two lagoons were designed to operate in series;
however, either one may be bypassed. Both lagoons are aerated with compressors
through pipe spargers. The temperatures of both lagoons are kept at 105-110° F
with 40-pound steam spargers. Biological oxidation in the three aerated lagoons
reportedly removes 98 percent of the phenols and 100 percent of the sulfides in the
total effluent. The American Oil Company refinery at Sugar Creek, Missouri, also
utilizes aerated lagoons to treat its totaf refinery wastes [54] „ Reported data for
-70-
-------
three months of winter operations showed 94 percent phenol reduction/ 7.4 to 0.4
mg/l; 96 percent sulfide reduction, 8 to 0.2 mg/l; 69 percent COD reduction 4o7
to"146'ing/I; arid 76 percent BOD reduction 175 to 42 mg/l. The aerated lagoon
utilizes two aerated cells with three 60-hp mechanical aerators in the first cell and
three 15-hp mechanical aerators in second cell. These aerators are designed to
transfer 13,000 pounds of oxygen per day.
'(5)- Trickling Filters
Oil disappears naturally from surface waters as a result of evaporation, auto-oxida-
tion, biological oxidation, sorption, and sedimentation. The more persistent oils
disappear chiefly as a result of'bacterial oxidation or sorption and settlement.
Most'oil-oxidlzing bacteria requiredissolvedoxygen, but some are able to utilize
nitrate or sulfate as their oxygen source [55] . Oil is apparently not attacked in
sediments unless an oxygen source is present. The rate of oxidation of oil by bac-
teria is attecred by the degree of dispersion of the oil and by temperature. The
optimum temperature range is 25° C to 37° C; below 10° C oxidation is slow, but
some has been reported at temperatures as low as 0° C. It is clear that some oxida-
tion of oil will occur in trickling filters but where too much oil is present it is likely
to coat the zoogleal film and interfere with aeration 156] .
Popularity of trickling filters (see'Figures 7, 8, and 9 [38]) stems from their ability tore-
sist shock loads of toxic organics. Actually, trickling filters may not absorb shock
loads, but rather allow the toxic materials to pass through the filters. The toxic
nature of refinery wastes has made trickling filters popular. Not only have trickling
filters been used as principal treatment devices but also serve as preliminary treat-
ment devices to reduce the BOD, to a suitable level, for further treatment by act-
ivated sludge or oxidation ponds [45] .
Shell Oil Company's refinery at Anacortes, Washington uses a 140 feet diameter,
10 feetdeep trickling filter [57] . The 5-day BOD reduction is from' 175 to 25 mg/l,
while the phenol reduction is from 30 to 0.6 mg/l. The 13 mg/l sulfides in the waste-
waters are completely oxidized. Standard rock-medium is used in the trickling filter.
Great Northern Oil Company has utilized plastic trickling filter media [58] . ' In
V964, the average phenol reduction was 62 percent, from 211 to 81 mg/l. Marathon
Oil Company at Robinson, Illinois, also has used plastic trickling filter media tor
treating process wastewaters [59] . With an average waste-water flow rate of 800
gpm, the phenol reduction averaged 95 percent, 11.0 to 0.5 mg/l; however, the
hydrogen sulfide reduction averaged only 58 percent, 115 to 48 mg/l. The differ-
ence in BOD reduction and phenol reduction lay primarily in the excess microbidl
solids that exerted a BOD.
-71-
-------
fO
I
ROTARY WASTE n DISTRIBUTOR
INFLUENT
UNDERDRAIN
SYSTEM'
SEDIMEN'
TAT I ON
TANK
EFFLUENT
^SLUDGE
FIGURE 7. ESSENTIAL PARTS OF A TRICKLING FILTER PLANT. [38]
-------
•il
CO
FIGURE 8. VARIOUS COMBINATIONS FOR TRICKLING FILTER OPERATIONS. [38]
-------
ENT CHANNEL
FIGURE 9. CROSS SECTION OF A TYPICAL TRICKLING FILTER.
-------
Trickling filters are useful in producing 80 to 90 percent BOD reduction at low or-
ganic loadings of less than 20 pounds of 5-day BOD per day per 1,000 cubic feet of
filter volume. At higher loadings it is possible to use plastic media and reduce the
land area required. Plastic filters can be built 18 feet high and can produce phenol
reduction of 60 to 90 percent, depending on the loading rate. Where high degrees
of treatment are required, trickling filters are used as pretreatment devices ahead
of oxidation ponds or activated sludge units [45] .
(6) Activated Sludge [45]
Activated sludge (see Figures 10 and 11 [38]) has proved only marginally successful
in treating industrial wastes because of its inability to accept shock loads. However,
with the advent of the completely mixed process this is no longer true. Successful
treatment of refinery wastes requires complete mixing of the wastes, the microbes^
and oxygen in the reaction unit. With toxic refinery waste waters, complete-mixing
systems can handle higher organic concentrations than conventional activated sludge
and actually absorb shock loads (unlike trickling filters which allow the shock to
pass through the filter).
One problem with activated sludge is the disposal of excess microbial sludge. The
putrescible quality of microbial sludge can necessitate treatment by aerobic diges-
tion and/or vacuum filtration. The dewatered sludge can be burned or buried and
the digested sludge used for soil conditioners. The most critical factor in the acti-
vated sludge process is the transfer of oxygen. There must be enough dissolved oxy-
gen to meet the oxygen demand of the microbes. Another vital control factor is the
separation of the microbes from the waste waters after treatment. Solids separation,
in a gravity clarifier, limits the mixed liquor suspended solids (MLSS) level to about
5000 mg/l dry weight, provided the sludge recirculation rate is adequate.
Numerous refineries are utilizing the activated sludge process for waste water treat-
ment. Shell Chemical Company has constructed a secondary waste water treatment
facility at Houston, Texas, which represents an investment of over $4.0 million and
annual operating cost of $0.8 million. The secondary treatment system supplements
the primary waste water facilities which consist of acid base neutralization, oil se-
paration and flocculant-aided settling, and air flotation of suspended materials.
The combined primary and secondary treatment facilities will occupy approximately
30 acres of land. The secondary facility utilizes the activated sludge process. Two
large aeration basins mix primary treated water with activated sludge. Seven aera-
tors agitate the water in each basin and provide atmospheric oxygen necessary in
carrying out the biological treatment process. After a twenty hour retention period
in the aeration basins, the waste water flows to clarifiers for further flocculotion
and settling of suspended solids. The treated water will then be discharged into the
Houston Ship Channel. Sludge will be concentrated, dried and disposed in a land
fill at an average rate of 15,000 Ibs/day in addition to 40,000 Ibs/day from the
-75-
-------
INFLUENT
AERATION
SEOIMENTA-LJFPLUENT
TION
RETURN SLUDGE
WASTE SLUDGE
FIGURE 10. CONVENTIONAL ACTIVATED SLUDGE PROCESS. [38]
-------
INFLUENT
i ,
AERATION
SEDIMENTA- ] EFFLUENT
TION ' '
>.
RETURN SLUDGE
WASTE SLUDGE
FIGURE 11. STEP AERATION IN ACTIVATED SLUDGE PROCESS. [38]
-------
primary treatment basin. The system will treat 6.0 mgd [92],
Sun Oil Company's activated sludge system at Sarnia, Ontario, is not a complete-
mixing system but it has such a long aeration period (37 hours based on raw waste
flow) that it tends to act as a complete-mixing system. This unit handles 200 gpm
of wastes with a sulfide concentration of 18 mg/l and a phenol concentration of 54
mg/l. The activated sludge effluent contains zero mg/l sulfides and 1.9 mg/l phenol
160].
Imperial Oil Company's complete-mixing activated sludge plant at Sarnia, Ontario
produced a 99.5 percent phenol reduction at a loading rate of 600 Ibs of phenol per
day. A similar system at the Great Northern Oil Company refinery in St. Paul
yielded a phenol reduction of 97.5 percent, from 14 to 0.3 mg/l, with only 3 hours
aeration [59].
Phillips Petroleum Company at Okmulgee, Oklahoma, and at Borger, Texas, and
Continental Oil Company at Ponca City, Oklahoma have activated sludge treat-
ment plants. The Phillips complex, northeast of Borger, Texas, includes an oil re-
finery, a natural-gas fractionating and processing center, a chemical-specialties
plant and a 700-home residential area. This complex produces 4.5-5 million gpd
of highly variable and complex effluent. Prior to the design of the treatment system
numerous pollution-abatement measures including better inplant housekeeping, se-
gregation and disposal of strong chemicals, and recovering elemental sulfur from
highly concentrated hydrogen sulfide streams were undertaken [61],
Automated instruments measure and record effluent pH, conductivity, turbidity,
dissolved oxygen and temperature. If a biological upset occurs, it is sensed as a
turbidity increase. Analysis of recorded data may determine the factor causing
the upset. Since October, 1964, the bio-system has produced a consistently high-
quality effluent. The data-collecting devices have operated within required limits
of accuracy [61].
In this system about 3500 gpm is pumped to a primary clarifier where solids are de-
posited and floating oils skimmed off. Free of oil and heavy sediment, the waste
water flows by gravity to 5-million gal-capacity surge and equalization pond.
Water is drawn from the pond to a chemical-coagulation unit, where remaining
sulfides and colloidal solids are removed by coagulation with ferric sulfate supple-
mented with a polyelectrolyte. The pre-treated water enters two activated sludge
bio-treaters. Waste retention time is about 6 hours. A turbine aerator disperses
700 scfm of air to maintain the biological action. The settled sludge is recirculated
with incoming water. The clear supernatant exits over the overflow weir to a final
holding pond with a 3.78 million gallon capacity and about an 18 hour retention
time. The shallow pond encourages algal growth and functions as an oxidation pond.
The following table depicts average values and removal efficiencies of certain pol-
lution parameters [61].
-78-
-------
To Skimmer From holding pond % removal
Flow, gpm 329-4800 3500
PH 8.4 7.0
CODf ppm 429 60 86
BOD, ppm 125 13 90
Phenols, ppm 14 0.1 99
Oil, ppm 108 0 99
Sulfides, ppm 30 0 99
Suspended Solids, ppm 259 15 94
Activated sludge is used where a highly purified effluent is required. Conventional
activated sludge can be used only for dilute organic waste waters or for wastes first
treated by trickling filters. Complete-mixing activated sludge can be used for con-
centrated as well as for dilute waste waters. Actually, complete-mixing, activated
sludge can be used to produce any degree of phenol reduction required up to 99.9+
percent.
c. Chemical Separation of Oil-in-Water Emulsions [56]
Emulsion breaking allows the free oil to be skimmed off in a gravity-type separator.
Heating, distillation, centrifuging and pre-coat filtration may be effective for
water-in-oil emulsions, but chemical treatment is usually necessary for oil-in-water
emulsions.
Deemulsifying chemicals increase the surface-tension at the oil-water interface,
neutralize electrical charges, and precipitate the emulsifying agent or cause it to
become highly soluble in or incompletely wetted by one of the phases. Oil-in-water
emulsions, stabilized by soaps, sulphonated oils, or long-chain alkyl sulphates, can
be broken down by adjusting the pH and addition of polyvalent cations, such as those
of calcium, magnesium, aluminium, or ferric iron. Sometimes addition of acid alone
is sufficient. Generally the amount of reagent required to break an emulsion is smaller for
trivalent than for divalent cations, and smal ler for divalent cations than for monova lent ones,
The behavior of different emulsion systems is highly specific. It is not possible to
state what concentration or type of reagent would be effective in a particular case
without examination. The only way to decide is to carry out small-scale tests with
a variety of reagents under different conditions. Such tests should determine the
optimum pH value, and the most suitable coagulant, the optimum dose, coagula-
tion time, period of settlement, and the nature and volume of any sludge and scum.
Treatment of the emulsions, by the method described will normally reduce their oil
content to a few hundred milligrams per liter. Provided the treated liquid does not
contain organic matter in excess of the permitted limit, it will usually be suitable
-79-
-------
for discharge to a sewer. If a higher standard is required, a further stage of treat-
ment involving entrainment of residual oil in a sludge blanket may be needed. The
process involves addition of salts of iron or aluminium which hydrolyze to form a
heavy flocculent precipitate of the metal hydroxide. This absorbs or entrains sus-
pended matter and droplets of oil and carries them to the bottom as sludge. Gentle
stirring after the reagents are added and the use of flocculent aids, such as activated
silica and organic polyelectrolytes, encourage the formation of large, rapidly-settling
floes and the production of a clear oil-free supernatant liquid.
d. In-plant Practices
(1) Supervision, Operation, and Maintenance [62]
Overall responsibility for supervision should rest with one well-qual ified person —
a waste control supervisor — who should be able to give top priority to waste con-
trol problems. Such an assignment facilitates the establishment and maintenance
of good waste disposal practices.
The supervisor should study all sources of waste waters that discharge into the dis-
posal system to recommend changes which might reduce the quantity of oil, sedi-
ment, and other pollutants being discharged.
The supervisor should maintain a complete record of the sources, characteristics,
and quantities of waste water streams and, with the cooperation of the refinery lab-
oratory, prepare periodic reports on the quality and quantity of the waters being
discharged from the refinery property.
A procedure should be established and well understood by all employees whereby
any complaints from control authorities or other responsible individuals are immed-
iately brought to the attention of the waste control supervisor and the appropriate
company official. Complaints should be investigated promptly and then discussed
with the party making the complaint.
A training program should be undertaken to acquaint everybody in the refinery with
the pollution control program. The control of a pollution program starts at the
source of the pollutants.
Literature is available that will assist in the start-up and guidance for continuance
of pollution abatement programs [63] .
(2) Environmental Considerations in New Refinery Construction [64]
The following examples of environmental concern will illustrate measures now being
taken by the petroleum industry.
-80-
-------
Jn 1966, HUMBLE OIL & Refining Company spent $10 million to insure that its new
$135 million Benicia refinery in California will have no adverse impacton the San Fran-
cisco Bay area environment. A west coast firm did an extensive environmental study
of the Benicia area before construction. Basic purpose of the study was to establish
a base line, reflecting the state of water and air quality, vegetation, soil, and
climatic conditions.
Within a 4-mile radius of the refinery site, experts collected and chemically ana-
lized several hundred samples of air, water, vegetation, and soil. The survey
serves as a gauge of any future changes in the environmental conditions of the area
and the nature of the changes. Meteorological conditions ~ including wind, cli-
mate, and inversions — were measured.
Benicia1 s initial capacity is 73,000 b/d. Hydrogen processing is used extensively.
Coking, cat cracking, hydrocracking, and alkylation units produce high yields of
gasoline and fuels. The coker eliminates residual fuels. Hydrotreating is used on
the naphtha, jet fuels, diesel fuels, and cracked-distillate streams. The hydrogen
comes from a hydrogen-synthesis unit.
The Benicia site has several environmental factors working in its favor. It Is east of
the big Bay Area population centers of San Francisco and Oakland with prevailing
winds blowing west to east during most of the year. But there are also some draw-
backs — the main one being topography. Under certain weather conditions, the
hills to the west cause a downsweepof the winds. Releases from stacks will tend
to be swept toward the ground.
Priority was given to defining meteorological and topographical conditions. As a
result of the studies, the main stack is 465 feet high - 115 feet taller than normally
would have been necessary for an environment with flat, open terrain.
Two complete sulfur-recovery units, each with sufficient capacity for handling the
entire refinery's H2$ streams were installed. Each sulfur plant can recover 150 tons/
day of elemental sulfur. Desulfurizers were installed to remove the sulfur from
naphtha, distallates, and cracking feed. Humble will burn no fuel oil —only
natural gas and gas generated by the refinery itself. The latter is treated for the
removal of ^S which is subsequently converted in the sulfur-recovery unit. Benicia
was designed to handle predominantly high-nitrogen, high-sulfur California valley
and coastal crudes.
The refinery effluent will be only about one-tenth as great as that from refineries
of older design and similar capacity. This is made possible by maximum use of air
cooling. About 70 percent of the cooling is accomplished by air, only 30 percent
by water.
-81-
-------
Oily water from tanks and process streams goes to a preseparator, which takes out
trash, settles sludge, and removes some oil. Then the water goes to two typical
API separators, operated in parellel, each with capacity to handle more than a
normal load. These remove oil and reduce turbidity. From the separators the water
moves to an aeration section of a final pond. There it is held for 3 days before
being pumped through submerged dispersers into the bay. In heavy rains, excess
water is automatically diverted to a holding pond for later treating.
About 50 percent of the normal water flowing to the treatment plant is oily. The
remainder is stripped sour waters, etc. The sour waters come from the desalter, hy-
drocracker, hydrofiners, coker, and cat-cracker streams. Sour water containing
both H2$ and ammonia (NH3) is fractionated to remove both of these materials. This
fractionator overhead becomes part of the feed to sulfur plants. Sour water with no
NH3 is air stripped for H2$ removal. The stripped sour waters are treated with
chemicals and flocculated to reduce turbidity and remove some oil. The clarified
water then goes to an activated sludge unit where biological oxidation removes or-
gan ics that could compete with fish and plant life for oxygen in the bay area.
The waste water is held 3 days in a retention lagoon as a further safety measure,
then released through underwater jets to facilitate blending with the water in the
bay. Water is pumped out under a pressure of about 60 psi.
Humble plans studies to eliminate dispersal of effluent into the bay entirely. This
might be accomplished by using most of the effluent to irrigate the installation's
extensive landscaped areas and grass for grazing. Experimental work will be required
to determine if this is practical. The main problem in cleaning up the water, Humble
says, is dissolved salts. Some of these are from spent caustic; others are concentrated
in the cooling tower.
Another refinery, with good pollution controls, was built adjacent to Mediterranean
beach resorts in Algeciras Bay, Gibraltar. Steps taken to clean up waste water re-
sulted in an effluent which would pass the most severe U.S. regulation [52] . Hy-
drocarbon content is reduced to 55 ppm or less, the biochemical oxygen demand
(BOD) to25ppmor less, and the phenol contenttoO. 1 ppm or less. Almost all of the
cooling load is performed by air coolers. This minimizes air pollution from hy-
drocarbon leaks into the cooling water, as well as reduces potential water pol-
lution.
Five separate sewers collect sanitary wastes, storm water, process oily water, pro-
cess clean water, and ballast water. Ballast water is discharged from ships to bal-
last water tankage. These tanks are heated for emulsion breaking and are equipped
with internal skimmers for decanting oil. After decanting, ballast water is given
further treatment through a gravity-type oil separator and air-flotation unit. The
air-flotation unit is equipped with chemical feeders to aid in the removal of oil
from water. Air-flotation effluent discharges to a retention pond. This pond is a
-82-
-------
guard against oil that might carry through the flotation unit during periods where
upsets or operating problems may occur.
Waste water from refinery operations is treated through a gravity-type separator,
qir- flotation unit, and primary retention pond. A common oil -recovery system
and sludge-treatment system serves the ballast water and refinery water-treatment
system. Water from the primary retention ponds along with sanitary waste discharges
to an oxidation pond for BOD and oil reduction. The oxidation pond is equipped with
mechanical aeration units.
A waste water stripper is used to pretreat waters containing h^SandNH^, andawaste
water neutral izer handles those containing caustic. Carbon dioxide produced in the
hydrogen systhesis step is used in these operations. Sludge removed in the separation
and flotation systems is combined and run to a precoat vacuum filter. There all excess
is removed to result in a solid product which can be disposed of more easily.
Storm water from the process area and tank farm that may contain oil discharges to
a storm-water retention pond. Provision is made to recycle this water to the refin-
ery treatment system.
(3) Money Return from Treating Waste Water
Chevron Research Company has found a way to turn a pollution problem into a profit.
|t has developed a waste water treating system which recovers almost pure ammonia
and hydrogen sulfide from foul water streams, converting these pollutants into sale-
able products. The first commercial unit recovers 38.4 ton/day of ammonia 58 ton/
day of hydrogen sulfide, from 230 gpm of foul water. The company has calculated
25 percent/year return on its investment in two years. If the alternative disposal costs
of stripping and incinerating are considered, the return becomes 75 percent/year [65] .
Chevron's patented waste water treating process converts the foul water into three
streams: ammonia of over 99 percent purity, hydrogen sulfide of 99.9 percent purity
which can be fed directly to sulfur or sulfuric acid plants, and clean water which can
be recycled in essentially a closed-loop system. The ammonia can be recovered as a
high-purity anhydrous liquid, or it can be produced asan aqueous solution. The process
;$ attractive in refineries which are hydrocracking relatively dirty feedstocks, such as
those derived from the Middle East, Venezuela or California crudes. Italso is valuable
in refineries operating inarid areas where water costsare high, and itshould have appeal
for plants which will be hydrotreating feedstocks from oil shale, tar sands, or coal.
It also holds promise for fertilizer plants and other processing facilities [65] .
A new sour-water stripping unit is one of the weapons that Sinclair Refining Com-
pany has developed to fight pollution in the Houston Ship Channel [66] . The strip-
ping unit works basically on the principle that sulfuric acid reacts with ammonia in
-83-
-------
the sour-water stream to form ammonium sulfate, a fertilizer. Addition of acid to
the proper pH also releases hydrogen sulfide, which is converted to elemental sulfur.
In contrast to other units of this kind, Sinclair's approach is different in two ways:
1) The acid is added after the sour-water stream has gone through the stripper. This
cuts corrosion problems that arise when the acid is mixed before the stripper. 2)
Sinclair uses spent alkylation acid (about 85 percent H^SCty), which is high in sul-
fur dioxide. Sulfur dioxide forms elemental sulfur when it reacts with hydrogen sul-
fide and deposits of sulfur in the H^S outlet line were experienced in early operations
However, adding the acid downstream and putting a heated sulfur dropout pot in the
H2S release line eliminated the problem.
The Sinclair unit is designed to take 250 gpm of sour water. This fluid when it
enters the stripper typically contains 5,000 ppm NH3/ 2,000 ppm sulfide, 340 ppm
phenol, and 440 ppm total carbon. When it leaves the stripper the water contains
only 200 ppm ammonia, 5 ppm sulfide, 240 ppm phenol, and 250 ppm total ogrbon
[66].
Quite possibly, petroleum coke is a sleeper due to technical neglect. If the Indus- '
try had spent as much time and money on its use as governmental and private inter- ~
ests have devoted to Pennsylvania anthracite culm banks, this story might be differ-'
ent [67] .
The two principal uses for petroleum coke have been as a raw material for electrode
manufacture and as a last-resort fuel. Electrode-coke buyers discriminate against
high metals and high sulfur content.
It seems a waste, however, to see this potential source of relatively pure carbon
competing with coal in the solid fuels market — particularly in view of current re-
search aimed at deashing coal — so that it may compete with petroleum coke. Many
products can be made with petroleum coke [68] .
Desulfurization is an essential prerequisite for the foregoing applications. Petroleum
coke can be desulfurized by extended residence at very high temperature, as in the
case of carbon packing in graphitization furnaces. It can also be desulfurized by
treatment with hydrogen. Both of these methods are prohibitively expensive [68] .
More recently, the Carbon Company developed a process that appears capable of
removing two-thirds of the sulfur from petroleum coke at a cost of $2 to $3/ton in
a plant designed to process at least 500 tons/day [69,70] . This process involves the
treatment of causticized coke in a bed fluidized with steam at elevated temperature
[71] . Sulfur which comes off as hydrogen sulfide in the off-gas may be recovered.
Many modest end uses for a product lead to a more stable product demand than a few
major markets. Perhaps the future of petroleum coke lies in diversity. Brainstorm-
ing aimed at stimulating some pertinent thinking includes [68]:
-84-
-------
1. Service stations sell most of the 50,000,000 oil-filter cartridges annually
sold in this country. Excellent cartridges for this purpose can be made of
fluid-coker coke.
2. Esso Research and Engineering has designed a clever system for recovering
automotive fuel vapor to reduce air pollution [77] . How about making the
active carbon for this system out of petcoke and selling it for other processes
as well?
\
3. South America needs foundry, blast furnace, and electric-reduction furnace
coke. It might be possible to take heavy eastern Venezuela crude, strip it
and coke the bottoms near its source, combine the distillates for export as
high grade reconstituted crude, desulfurize the coke and convert it to met-
allurgical coke.
4. Oil refineries are substantial users of supported catalysts. Can catalyst be
efficiently support on petcoke compacts?
5. How many oil refineries could solve a pollution problem with captively man-
ufactured active carbon made out of petcoke?
6. Would internal combustion engine off-gas contribute less to air pollution
if it were exhausted through a coarse-grained filter cartridge made of pet-
coke (preferably high-vanadium) and fitted into a muffler-like case?
7. Many refiners use tower packing, such as raschig rings and ceramic saddles.
Similar shapes can be made of petcoke.
8. Carbon brick or other shapes made of petcoke can be wired and buried to
serve as cathodic protection electrodes.
9. Low BID fuel gas for nearby consumption as a clean fuel can be made of
petcoke in a simple fluid-bed generator.
10. Porous carbon tile made of petcoke can be laid between plant rows in truck
gardens to absorb early spring heat, to smother weeds and serve as permanent
cultivation, and to reduce evaporation of soil moisture.
e. Centralized Waste Disposal [73]
A central waste-disposal plant, planned for the Houston ship channel area, is designed
to consume industrial wastes which would otherwise create serious pollution problems
This type of facility may be the answer to proposed legislation which would impose
-85-
-------
harsher pollution criteria and penalties on plant owners. Many of those affected by
tightened laws and moresevere fines may well not be able to afford to handle their
own wastes. The plant which was scheduled for completion in 1970, appears to
be an effective and economic answer to the problems of many plants which have a
variety of waste products (Table 12).
TABLE 12
Typical Plant Wastes in the Houston Area
Semisolids
Tank Bottoms Soot Cake
Tank Cleanings Filter Cake
Oil and Chemical Sludges Filter Aid
Tars and Asphalts Spent Clay
Aluminum Alkyls Sediments
Polymer Residues
Carbon Tetrachloride Residue Solids
Isocyanate Residue Trash
Organic Alcohols Polymer Scrap
Methanol Tails Rubber Scrap
PVC Wastes paper y/aste
Soot Slurry
(1) Incineration
Land fill is not suitable for liquids and in many instances less than satisfactory for
solids. Burning, on the other hand, would reduce nearly all compounds to the
simplest of oxides, most of them gaseous. The greater part of the latter, such as
oxides of hydrogen and carbon, are compatible with the normal environment.
Noncumbustible, noxious, or odorous materials can often be converted to inoffen-
sive products by passing them through a furnace. And the solid, inorganic ashes
much reduced in bulk, can be disposed of more simply than the feed material .
-86-
-------
Hydrocarbon residues, chemical and oil sludges, asphalts, and tars require rather
simple equipment to fire. Solid wastes, trash, polymers, and rubber chunks re-
quire more complex furnaces. In all cases, the gaseous products need to be treated
to remove those solids and other products whose emission would offend within the
affected area.
(2) Plant layout
The plant is designed to front on about 200 feet of the Houston ship channel and
to extend about 600 feet in depth. A second unit of equal size, perhaps modi-
fied to meet changing conditions, could be placed alongside the first.
One major problem with such a plant is the slug receipts of various wastes as op-
posed to the steady-state nature in the incineration process. A barge may arrive
with 1,000 tons of waste. This must be unloaded and stored in a few hours with-
out an upset to normal plant operation. A string of railroad cars carrying liquids
and solids may require attention at the same time. Therefore, handling equip-
ment and storage units requires a lot of thought in planning the work balance of
such a unit.
(3) Handling
One factor affecting any plant producing wastes Is the cost of moving the waste to
the central burning plant. See Table 13 for haulage costs by truck and barge of
liquid and solid wastes. When wastes arrive at the unit, they must be weighed and
classified since disposal charges will depend on the amount and quality of the waste
received. Liquid receipts must be analyzed so they can be transferred to the proper
bulk-storage tanks. Analysis will show what solids can be premixed with other mat-
erials to maintain relatively constant input rates of moisture, ash, heating value,
and combustion characteristics. Analysis would also permit incompatible materials
to be separated and to be burned at different times. Pits in the storage area will
contain ash from the incinerators until it is moved to land-fill areas. At a waste
rate of 15,000 tons/month, ash would be produced at a rate of about 50 tons/day.
Initially, this will be used as fill on the plant site. Eventually, it will have to be
trucked or barged to other sites.
-87-
-------
TABLE 13
Typical Transport Costs to Plant
(Cost - dollars per ton)
Miles to Liquid Waste Solid Waste Liquid & Solid Wash
Plant (8,000 gal truck) (12-ton truck) (1,000 ton barge)
5 0.90 1.50
10 1.00 1.70
20 1.45 2.20 0.55
40 1.90 2.80
50 2.00 3.00 0.66
100 — — 0.83
(4) Small Particles
One group of wastes would include those materials which, by either application of
heat or pressure, can be atomized or otherwise converted into small particles. These
particles would be consumed in seconds. Also, a liquid furnace would be charged
with relatively noncombustible liquids and soot slurries as well as liquids from pet-
roleum and petrochemical sources. If the heat balance were not being maintained
in the liquid furnace, the outlet temperature could drop to a point where combustion
would not be complete. In this case, natural gas would be fired until the proper
heat balance could be regained with waste materials. The liquid furnace is basically
an adiabatic combustion chamber designed to heat materials to an ignition tempera- '
ture and to vaporize the aqueous streams. Turbulence must be created to complete
the oxidation process in a few seconds. The furnace can be arranged with its axis
either horizontal or vertical.
(5) Semisolid Wastes
Another group of waste materials includes those which contain large amounts of ash.
Some of these might be burned in the liquid furnace, but it is preferable not to load
the combustion gases with fly ash and particulate solids.
A rotary hearth furnace has been selected to burn these wastes. This furnace will
have a dish-shaped hearth turning around a vertical axis. Material to be burned
is added at the rim and revolves with the hearth. Air flows radially across the
hearth from the central axis toward the rim at low linear velocity. Combustion
takes place on the surface of the burning material. Rabbles turn the waste to expose
-------
fresh surfaces and waste products move toward the central shaft where the ash is re-
moved. Thus, a type of countercurrent contact between waste and air is achieved
without producing a combustion gas heavily laden with fly ash. However, this type
of incineration produces a combustion gas containing unburned combustible material
distilled or sublimed from the waste at the cooler outer regions of the hearth. Com-
bustion gases from this burning unit are far from suitable for emission to the atmos-
phere. Ash removed from this furnace may total 20 to 30 tons/day and ash handling
is a big problem.
(6) Slow-burning
Another group of wastes include relatively large items which burn slowly and those
solids which melt at high temperature. Included are packaged or boxed solids and
liquids which must be charged to the incinerator in drums.
The incinerator chosen for this service is a rotary kiln designed to retain materials
for hours. It spreads melting solids over its internal surface and tumbles packages
and drums to spill their contents. This device is the most versatile, but it costs more
than the other incineration units to be installed.
Its feeder mechanism includes the conventional charging chute. It must also include
a feed chamber into which closed drums willbeplaced, drum heads perforated or re-
moved, and the drums dumped into the kiln. Since these drums may contain hazar-
dous materials, this feed chamber must provide complete protection to operators.
Since the kiln is charged intermittently, means must be provided to add natural gas
if for any reason the outlet temperature shows a deficiency of combustibles in the
kiln. By alternately feeding materials of different heating values, a rather constant
level of heat release can be maintained.
(7) Combined Gases
Combustion gases from the three furnaces will be combined and taken into a secondary
furnace where oxidative decomposition of gas pollutants, particularly the unburned
materials in the effluent from the rotary hearth furnace, is completed.
This chamber is designed to combine three elements of combustion — time, tempera-
ture, and turbulence. They are combined in such a manner as to completely burn
soot, hydrocarbon vapors, sulfur-containing materials, and odor or smog-producing
compounds. Hot combined gases, at a temperature as high as 1,800° F., possess a
potential to raise steam. In fact, about 200,000 Ib/hr of high-pressure steam can
be developed in the cooling of these gases. There is one liability, however, in
passing the gases through waste-heat boilers. They possess appreciable amounts of
fly-ash which could, and likely will, be sticky at the temperature of the secondary
furnace. Accordingly, a special waste-heat boiler has been designed to lessen the
-89-
-------
problem of ash adhesion.
(8) Gas Cleaning
Gas is purified by removing anything which would produce an illegal or offensive
emission. Presently, the only pertinent regulations of the Texas Air Control Board
encompass smoke and particulate matter and sulfur oxides. Since regulations are
expected to tighten, gas-purification equipment will be designed to remove pollu-
tants to levels a fraction of those now required.
Wet scrubbing is the method preferred to simultaneously remove solid-particulate
matter, sulfur oxides, and hydrogen chloride. Gas temperatures are dropped from
700° C. down to about 150° F. with a spray of wa^?r.
Gas is washed with venturi scrubbers, impingement baffles, or other energy-consuming
devices which bring liquid and gas together and then separate them. Solid particles
are removed by a mechanical cleansing effect. Gaseous acidic compounds are ab-
sorbed in the scrubbing liquid, which must be maintained in an alkaline condition
to ensure rapid and efficient removal. The blowdown from the wet scrubber will be
a slurry of fly-ash in a water solution of sulfites and chlorides.
(9) Stack Gases
Directing wet gas up a stack to the atmosphere presents a number of problems. A
heavy steam plume would be visible and might, in adverse weather, fog the ship
channel. Also, water pushed up the inside wall of the stack by the gas could over-
flow and spill down the outside of the wall.
To avoid these problems, a small burner in the base of the stack will heat the ID fan
discharge flow from about 150° to about 300° F. This arrangement permits the stack
to be built of carbon steel with a minimum amount of outside insulation. The stack
will be 200 to 250 feet high, which is adequate to disperse stack gas. It is estimated
that on the average, at full plant capacity, the stack-gas flow would be near 150,000
scfm. Handling this flow in a single train would require equipment which, in some
cases, would be larger than previously built. It also makes the plant vulnerable to
complete shutdown if failure occurs at any point. Accordingly, the combustion-gas
flow, after leaving the secondary combustion furnace, is divided into three equal
streams. Each is directed to a separate train consisting of waste-heat boiler, wet
scrubber, and ID fan. These streams rejoin at the stack. High-pressure saturated
steam generated in the three waste-heat boilers is directed to a single gas-fired
super-heater before being exported.
Current Texas Air Control Board regulations would permit 150,000 scfm of stack gas
to carry 650 Ib/hr of solid particulates and 5,200 Ib/hr of sulfur dioxide. This
-90-
-------
would be at an elevation of 250 feet and at 300° F. Plant design is predicated on
reducing these pollutants to a small fraction of these values.
3. Water Use and Reuse
in the past, water has not received due concern as a major economic item in manu-
facturing or processing operations [75] . Water has been plentiful and inexpensive,
and its real costs have been difficult to assess. Water as a raw material has not
been accorded the cost accounting attention given to other raw materials. How-
ever, there can be no doubt that future water use will be closely managed, receiv-
ing attention as an element of the processing or manufacturing operation. A wise
course is for industry to work toward its own solutions to the problems of water [76] .
Water management is not new. But not until recently has the shortage of usable water
affected the future of industry. Two factors have created an important awareness of
water management. First, the national concern about water pollution bears on every
industry. Increasing production and unremitting governmental pressure to prevent
pollution at its source are problems. Second, water from natural precipitation re-
mains virtually fixed, but the demand for usable water is rapidly increasing [76] .
In 1959, the U.S. water usage was 265 bgd (billion gallons a day). Presently, our
total water use is about 315 bgd. Because of our fast growing population and our
rising standards of living, it has been estimated our nation wi 11 require 500 bgd by 1980.
From the 1964 Bureau of the Census, "water use in manufacturing" averages 30.7 bgd.
Notably, industry is predicted to be the segment of our society with the fastest growing
water demand. However, larger water reuse will make industry a more efficient userof
the water it must have. According to the 1 964 water use in manufacturing survey, the pet-
roleum refining industry practices water reuse. In 1954, refining operations had a daily
requirement of 3.4 bgd compared to a gross wateruseof 11.3bgd. (Gross wateruseis
defined as the total volumeof water needed, and countsagain all reuse.) By 1964, in-
take volume increased only 12percent to 3.8bgd while gross water use increased 50
percent to 16.8 bgd. During this 10-year period the reuse ratio climbed from 3.4to
4.4. Almost one-half of the total intake water volume was from brackish water sources [76]
Generally, the biggest need is not for water treatment chemicals or for waste treat-
ment chemicals or for waste treatment plants and equipment, but for more precise
knowledge of water use and how this use is related to pollution. Eventually, the
"let's-wait-and-see approach" can result in expensive crash programs and unwise
decisions. In some regions, water needs have grown until they are almost greater
than the usable supply. In the coming years, it will be a race between keeping
water re-usable and the fast rising needs for water. Inevitably, regulatory agencies
must enforce the clean water practices [76] .
Water is a reusable resource. It is used many times over. Sewage plant effluent
dumped into a river by one cityeventually may be used asa water supply downstream
-91-
-------
by another. The water could be reclaimed in a treatment facility, and ultimately
serve as a water supply, for a lower use. conserving potable water for higher uses
(e.g. domestic consumption) [77]. In the former case, nature purifies the water
and in the latter case, man implements purification.
Intended use dictates water quality requirements. Treated properly, municipal sew-
age may be reused. Industry is reusing water on an increasing scale, and finding
reclaimed water valuable for augmenting existing supplies.
Major industrial water users are the primary-metal manufacture, chemicals and allied
products, paper, petroleum and coal products, and food industries [78] . Reclaimed
water could be utilized by all these but the food industry for obvious health and
psychological reasons. Economic conditions in the United States favor reuse. Pre-
sently, direct reuse is minimal, but good potential exists. Reuse provides industry
with a dependable, low-cost water supply, since sewage effluents are available in
large quantities near metropolitan areas. Metropolitan areas attract industry because
of the readily available labor pool. Hence, industrial reuse seems logical.
Treated properly, sewage treatment plant effluents can be used as processing water,
boiler makeup water, and cooling water. Cooling waters comprise 60-80 percent
of all industrial water uses [78] . The cooling requirements are tremendous. Using
reclaimed water may be more economical than municipal water because:
1. Treatment costs are usually higher for municipal water.
2. If the municipal water treatment plant is already working at capacity,
as many are, additional water production requires costly expansions.
3. Potable water is conserved for higher uses.
4. Reuse reduces the amount of sewage effluentpol luting the receiving stream.
Slime control might be the only treatment needed to use the sewage treatment plant
effluent for cooling water [78] . Obviously, reclaimed water offers significant value
to industry. As a result, industry should consider reuse when faced with a water shortage,
Condltionsnecessary for industrial reuse of sewage treatment plant effluents [79,80,
81] are:
1. A local industry must need water for a process not concerned with public
health.
2. Enough effluent must be available to supply the requirements of the in-
dustry.
3. Processing and transportation costs must not exceed the cost of alternate
water supplies.
4. The effluent quality must be consistent enough for the intended reuse.
-92-
-------
The Champlin Oil and Refining Company, Enid, Oklahoma, demonstrates the benefits
of water reuse. The only supply of water available to the refinery for an expansion
of their facilities in Enid, in 1942, was the "treated" effluent from the inadequate,
overloaded sewage treatment plant[79,82] . Until 1954, when a new treatment plant
was completed, the refinery used a mixrure of raw sewage and treated effluent for
cooling water. Now, only treated effluent is used barring a complete upset of the
system. The effluent is their principal source of water.
First priority for the effluent belongs to the municipal treatment plant for housekeep-
ing requirements. By agreement, the city allows the refinery up to 2000 gpm, or
nearly 3 mgd, provided the treatment plant's requirements have been fulfilled. How-
ever, in practice, the city allows the refinery to withdraw any amount they need.
The sewage treatment plant is located about 2 miles south of the refinery, on the
outskirts of Enid, a city of some 47,000 persons. Daily sewage flow rates vary from
2 to 6 mgd. The treatment plant provides primary and secondary sewage treatment.
Figure 12 shows a simplified flow diagram of the plant. The primary treatment in-
volves screening, grit removal, and sedimentation. Secondary treatment, a biologi-
cal process, uses a modified activated-sludge process.
Typical quality characteristics of the plant influent and effluent (1969 data) are tab-
ulated in Table 14.
TABLE 14
Typical Characteristics of the Enid Sewage Treatment
Influent and Effluent
, . _ .. . , , Influent Effluent
Dissolved Solids (ppm) 683 632
Suspended Solids (ppm) 277 56
Total Solids (ppm) 953 691
B.O.D.(ppm) 284 64
PH 7.7 7.4
Flow (mgd) 4.1
The final effluent, emerging from the secondary clarifiers, is divided into two streams:
one discharges into an adjacent receiving stream (Boggy Creek); the other is for treat-
ment plant and refinery use. Champlin's water is transported to the refinery via a pipe
line. Storage is available at the treatment plant for the refinery; however, storage
is not used because the minimum sewage flow rate exceeds the combined demand of
the treatment plant and the refinery. Present withdrawal for the refinery is 1100 gpm,
-93-
-------
RAW
SEWAGE
SCREENS
GRIT
CHAMBER
TO ANAEROBIC
TO REFINERY
CHLORINATORS
AND
LIFT STATION
PRIMARY
CLARIFIER
SECONDARY
CLARIFIER
AERATION
FIGURE 12. FLOW DIAGRAM OF ENID SEWAGE TREATMENT PLANT,
ENID, OKLAHOMA.
-------
or approximately 1.6 mgd. The refinery chlorinates the effluent (about 17 ppm) at
their pumping station located at the sewage treatment plant.
At the refinery, all the treated sewage is used for cooling. Additional treatment
is required to meet minimum quality standards for cooling, to restrain microorganism
growth, and to reduce corrosion and scaling. Briefly, in-plant treatment at the re-
finery involves: 1) cold lime softening; 2) alum coagulation; 3) polymerization; 4)
pH adjustment; and 5) slime control.
Lime treatment lowers the phosphate concentration in the makeup water. Alum
coagulation reduces the suspended solids concentration and aids phosphate removal.
Fifty percent phosphate removal is attained. Polymerization increases the weight
of the flocculant in the clarifier, and hypothetically increases the capacity from
500 gpm to about 1100 gpm. Fair results are obtained at 1100 gpm, but better re-
sults are obtained up to 800 gpm. The primary purpose of the pH adjustment is to
reduce the bicarbonate alkalinity of the makeup water; however, it also serves to
keep the scale forming calcium phosphate in solution. Slime control is accomplished
with bromine and various commercial non-oxidizing microbiocides on a slug dosage
basis. The treatment schedule is involved and will not be presented here. The micro-
biocides are tailored by experience to the microorganisms found in the cooling
towers and the dosages are empirical.
Finished water quality and an analysis of refinery water treatment and costs appears
in Tables 15and 16. Fiscal year 1970 (first half) cost data from the Enid Sewage
Treatment Plant indicates an average treatment cost of $51 per million gallons (5
-------
TABLE 15
Typical Finished Water Quality at Champlin Refinery
Total Dissolved Solids (ppm)
Suspended Solids (ppm)
Alkalinity as CaCO,, (ppm)
•j
Total Hardness as CaCO (ppm)
o
Calcium Hardness as CaCO_ (ppm)
NaCI
Phosphate (ppm)
Ammonia Nitrogen (ppm)
600
30
150
210
170
320
15-24
28-50
6.2-6.5
TABLE 16
Typical Treatment Costs for Cooling Tower
Make-up Water at Champlin Refinery
(Based on 1100 gpm)
Sewage Effluent
Pumping (electricity)
Chlorinatlon (17 ppm)
Softening & Clarification
140-150 ppm lime
8 ppm alum
0.2 ppm polymer
200 ppm H2SO4
Biocides (including Bromine)
Total
*all costs rounded to nearest dollar
cost *
per month
$ 75
817
474
709
131
143
921
3660
$6930
cost *
per million gallons
$ 2
17
10
15
3
3
19
77_
$146
-96-
-------
TABLE 17
Average Monthly Operating Costs for Enid
Sewage Treatment Plant
(Based on First Half F. Y. 1970)
cosr
Electric $ 304
Natural Gas 341
Telephone 23
Mobile Equipment Expense 121
Maintenance 1141
Salaries 4447
Total $6377
Average Montly Sewage Flow = 125 million gallons
Average Sewage Treatment Cost = $6377 _ $51
125 million gallons -
*all costs rounded to nearest dollar
3. Reuse causes more corrosion in the cooling system.
4. Increased fouling lowers the heat exchanger efficiency.
5. More frequent backwashing is required.
Measurement of these costs is subjective. Present accounting procedures lack water
reuse cost data. Hence, only qualitative measurements can be made. Considering
an adequate alternate water supply is not available from any other source, the sew-
age plant effluent is a vital asset to the refinery. If a refinery is to resort to sewage
treatment plant effluent these measures should be considered [82,83].
1. Adequate chlorination of the sewage treatment plant effluent.
2. Reduce suspended solids and phosphates prior to water use.
3. Establish a slime control program, preferably using non-oxidizing microbiocides.
4. Use suitable corrosion inhibitors and fouling dispersants.
The Champlin Oil and Refining Company, Enid, Oklahoma, demonstrates the benefits
-97-
-------
of water reuse. While in-piant treatment costs at the refinery are higher than for
domestic water, they are offset by the lower purchase price for the treated sewage
effluent. Reuse in Enid supplements limited fresh water resources and allows addi-
tional beneficial use of the water. Experiences at Champlin1 s refinery show that'
municipal sewage treatment plant effluents provide a dependable, low-cost water
supply worthy of consideration.
4. Instrumentation
a. Introduction
Despite the constant increase in production and processing of petroleum products,
there has not been a correspondingly intensive development of improved methods
for the analysis of hydrocarbon pollution. Gravimetric and volumetric analyses,
mass spectrometry and infrared spectroscopy have been the four most popular tech-
niques used for the analysis of pollution caused by petroleum and its products. The
first two techniques serve as methods of analysis of gross pollution, while the latter
two techniques are suitable where the.pollution is not heavy. Because of its simpli-
city, speed and sensitivity, gas chromatrography is emphasized in many current
analytical developments. These characteristics make it a valuable technique in the
analysis of hydrocarbon pollution [84].
Instrumentation involves a myriad of analytical "tools". Their utilization, in spite
of diversity, collectively and separately/ is part of a new discipline. It led to the
collection and correlation of measurement theories—research and automation accel-
erated the process [85] . Technical books [36,85-91] explain techniques and instruments.
b. Refractometry [92]
Refraction is the bending of a light beam as it passes from one medium into another.
In refractometry one measures the difference between the velocity of light in one
medium and its velocity in another. The measurement is obtained by applying Snell1 s
Law. The refractive index is expressed as the ratio of the sine of the incidence
angle, of the incident light beam, to the sine of the angle of the refracted beam.
Refractive index is a characteristic property of a substance.
Chemical compositions determined by refractive index can be done only in binary,
or two compound, mixtures. The measurement becomes ambiguous with more com-
ponents. With the myriad of compounds in petroleum refining, refractometry has'
limited use.
c. Absorption Spectroscopy [92]
Absorption spectroscopy utilizes the infrared analyzer. The infrared region of prac-
tical interest lies between the electromagnetic wavelengths of two and fifteen microns.
-98-
-------
In this range, most organic and inorganic substances exhibit strong absorption spectras.
Particular substances have unique spectras since adsorption band frequencies are
determined by vibrating atom positions and configurational relations within the sub-
stance's molecules. The amount of energy absorbed by a substance at any one of its
characteristic frequencies is a measure of the substance" s concentration in a mixture.
Infrared spectroscopy measures the absorbed energy in the infrared range (2-15 microns).
This i5 a sensitive and powerful technique for the analysis of mixtures.
An infrared absorption photometer that will continuously measure oil in water has been
developed. A special split-beam photometer and capillary emulsifier is incorpora-
ted into a single package. This field instrument is to be further evaluated in the
laboratory at a Chicago refinery. Finally, the Maritime Administration will designate
a ship for seaboard testing [93] .
The infrared analyzer, I ike the refractometer, measures only the concentration of a
single component in a sample stream. Unlike refractometry however, it can isolate
that component from a mixture. Again, complex mixtures present in refinery process
streams have precluded the use of an infrared analyzer.
d. Gas Chromatography [92]
Gas chroma tography separates volatile mixtures into its components by a moving inert
gas, usually helium, passing over a sorbent. The sorbent can be a solid having a
large surface area, but it usually consists of an inert solid support coated with a nonvol'
atile liquid. A typical seqaration column is a small diameter tube, perhaps 1/8 inch,
packed with small solid particles coated with up to 20 percent by weight of a sorbent
liquid. However, the support for the liquid can be the tube walls; in this case the
inner diameter tube is 0.02 inch or less. In either configuration, the gas passes
through the tube carrying the sample mixture. The components separate into char-
acteristic ratios between the gas and liquid phases. Separation occurs because com-
ponents, more soluble in the liquid, move slower down the column than the less
soluble components. At the exit, a detector "sees" the components emerge in a
series of peaks; the emergence time of peak identifies the component, and the area
under the peak indicates the component concentration. Notably, as a method of
separating the individual components of a complex mixture, gas chromatography
has no equal. Complex organics occurring in petrochemical wastes have been iden-
tified and measured using gas chromatographic techniques [94] .
Chromatography has the greatest potential of the three methods. Process chromato-
graphy, coupled to computer systems, is installed in plant-control laboratories re-
quiring many repetitive analyses. In this system, a man injects a sample into a
laboratory chromatograph, and directs the computer to carry out a complete analy-
sis. A single computer can handle as many as 30 instruments. It is a small step from
the laboratory systems to process chroma tog raphs. At the Mobil Oil Corporation's
-99-
-------
refinery in Torrance, California, eight chromatographs analyze 27 process streams
and one computer controls the entire operation. The computer mechanizes tta functions
of the laboratory workers and coordinates the instruments.
A better approach incorporated all the latest chromatography knowledge and utilized
the computer1 s capacity for high speed data processing and for making programmed
decisions. A computer-chromatograph system is being tested in the laboratories of
Applied Automation Inc. in Bartlesville, Oklahoma. Eight different chromatographic
columns in the system, with five independent temperature zones, allow the chroma-
tograph to give different separations at different temperatures. A given sample goes
concurrently through all the columns, receiving a different separation in each one.
The peaks, coming through each detector, are sensed, identified, and stored by
computer until ready for a complete analysis. The system can identify components
that might otherwise be unidentified because of limitations in a less sophisticated
system. The computer can mathematically separate and identify components from
the abundant information.
The limitation of gas chroma tography lies in the fact that it lacks positive identifica-^
tion of component peaks. Eluting components are identified by comparing their
elution times with those of pure components under the same conditions. Disturbances
change the test conditions and therefore, the elution times. Moreover a new com-
pound, appearing in the chromatographic stream, may have the sameefution time
as a compound already there. Identification of components becomes more difficult
as the number of compounds in a mixture increases.
An unambiguous sensor is needed to identify compounds emerging from a chromato-
graphic column. Sensing is achieved by directing a small portion of chromatographic
effluent to a mass spectrometer, where the mass spectra patterns, uniquely caused
by each component, provide an excellent means of identification. Presently, the
mass spectrometer is an expensive research tool requiring skilled operators.
e.
Vopor-Phase-Pyrolysis Gas Chromatography [94]
A new technique, vapor-phase-pyrolysis gas chromatography (PGC), holds good
potential for the qualitative analysis of hydrocarbons. Particularly, analyses of
trace hydrocarbon amounts (10~9 to 10~& grams) having a vapor pressure greater
than 1 torr at 250° C. These test conditions are not severe restrictions. Even the
saturated alkanetriacontane ^Q-H^) has a vapor pressure of approximately 1 torr
at 250°.
Generally, hydrocarbons are degraded under controlled thermal conditions and the
decomposition products analysed by gas-chromatography. The result is a pyrogram.
The pyrogram is a unique reproducible signature of the parent material. Materials
such as high-modecular-weight polymers, drugs, and even bacteria pyrolyze in a
-100-
-------
characteristic manner. Chroma tog ram of the pyrolytic fragments, the pyrogram,
is unique and characteristic of the particular material pyrolyzed.
f. Mass Spectrometry [94]
In the mass spectrometer (MS) a volatile compound is injected into the ion source
and is ionized. The ionizing source is an electron beam of about 70 volts, (the
beams'energy exceeds the compound's chemical bonding energy). Ions, produced
by the electron beam, are highly excited and decompose to neutral and ionic frag-
ments. Many molecules are involved and many possible decomposition paths exist.
Thus, a complex pattern of ions is produced. The subsequent detection and record-
ing of each particular type ion constitutes the mass spectrum. (Two recent innova-
tions in mass spectrometry, field ionization and chemical ionization, leave the ion
with less energy, and therefore, a simpler spectrum; but they are not widely used
for a variety of reasons).
The MS spectrum is analogous to a fingerprint, and identifies the material in the
ion source by comparison to a known sample spectrum. However, if different (num-
erous olefins) compounds are ionized, and then the ion rearranges and passes through
the same excited state, their fragmentation patterns will not differ and falsely indi-
cate identical mass spectra.
The combination gas chroma tog raph-mass spectrometer (GC-MS) is a sensitive and
fast analytical instrument, and shortens the analysis time. Also, some analyses
could not be done any other way. The GC-MS is not a new instrument to analyti-
cal chemists, but only a few water pollution investigations have been done [96,97
98] . Researchers [99,100] recognized its potential for analyzing complex trace organ-
ics in surface waters, but there are few published results.
The GC-MS was used to Investigate and identify some organic compounds in Okla-
homa oil refinery effluents [101,102] . Final, treated effluents samples are shipped to
Oklahoma State University by members of the Oklahoma Refiner1 s Waste Control
Council. Ten liters of the effluent are steam distilled and the steam volatile organic
compounds continuously extracted and concentrated in diethylether. Steam volatile
compounds are separated on impregnated paper thin-layer (ITLC), thin-layer (TLC),
and gas liquid chroma tog raph y (GLC). After this preliminary resolution, the separ-
ated samples are analyzed with GC-MS.
Retention times (in GLC) of 8 to 10 compounds from different refineries are identi-
cal, indicating similar compounds. Subsequent GC-MS analysis indicates a series
of aliphatic hydrocargons from C^ ^24 through C^gHgg.
The MS, in conjunctionwitha GC, is a powerful tool, butpresently, expensive to purchase,
and maintain and of course skilled technicians are needed to perform routine analyses.
-101-
-------
SECTION VI
FIELD STUDY OF SELECTED REFINERIES
A. Objective
A field investigation was conducted (summer, 1969) in three refineries to investigate
internal waste water process streams and examine existing treatment systems.
B. Description of Refineries
Refinerysize has been defined: [32] a "small" refinery has a daily crude oil capacity
of 35 000 b/sd (operating day) or less; a "medium" size a capacity of 35,000 to
100,000 b/sd; and a "large" size capacity greater than 100,000 b/sd.
At the onset of this project, eleven Oklahoma refineries were solicited to obtain in-
formation, and permission to sample individual waste water process streams. There
are no "large" refineries in Oklahoma. "Medium" size refineries refused any "in
plant" investigations. However, permission was granted to sample the treated com-
posite effluent. Three "small" size refineries agreed to let us sample existing waste
streams. Each refinery has unique waste water piping. Commonly, a myriad of pipes
form a closed collection sewer. These sewers were not sampled. However, numerous
individual waste streams were sampled. Their willingness to help provided congenial
working conditions and useful information.
Refinery A' s major operations include: electrolytic and chemical crude desalting;
vacuum distillation; fluid catalytic cracking; catalytic reforming, alkylation; polym-
erization; and production of lubes, gasolines, coke, and asphalt. The treatment
facilities are: an API separator, surge holding pond, and aerated lagoons. Using
the API refinery processing classification system, [35] Refinery A is in Category D.
The complexity grouping Category D includes integrated refineries with lube oil pro-
cessing. Also, further API classification by type of waste treatment (primary,
intermediate and biological) places refinery A in the biological treatment category.
Refinery B's major process operations are: electrolytic crude desalting; vacuum dis-
TlI lotion, fluid catalytic cracking, catalytic reforming; and polymerization. Gaso-
lines, naphthas, and asphalt constitute the major products. Waste water treatment
Is accomplished with API separators, a bio-treating system, and oxidation lagoons.
Refinery B classifies into the complexity grouping Category B and utilizes biological
treatment.
Refinery C1 s major processes are: electrolytic crude desalting; vacuum distillation;
Tluid catalytic cracking; hydro-cracking, and polymerization. Major products are
gasolines, naphthas, and asphalt. Waste water treating facilities are an API separa-
tor and a series of oxidation ponds with a 30 day retention period. The complexity
-103-
-------
grouping of Refinery C falls into Category B, and has biological waste treatment.
These refineries are active members of the Oklahoma Refiners Waste Control Council.
This organization provides a common meeting time to discuss waste treatment and re-
duction.
C. Sampling and Sample Analyses
The field data collected is presented in Tables 18-20. All analyses were conducted
in accordance with "Standard Methods for the Examination of Water and Waste Water."
Three sets of one liter grab samples were obtained at each refinery. Refinery person-
nel identified sampling points for various processes. For most sampling points, the
waste water flow rates and temperatures were obtained from refinery records,
D. Discussion
The field data gathered from the three refineries can serve only as an indicator of
waste water characteristics and volumes from the individual processes. This is be-
cause the strength of each waste stream varies considerably; each stream is unique
and only three grab samples were taken from each stream. This does not negate the
value of the data because by referring to Tables 18, 19, and 20 certain trends and
relative strengths are immediately discernible. For example, the catalytic crackers
discharge high strength, low volume streams. These streams are high in COD, Sul-
fides, and ammonia, Jn contrast, the cooling towers have much higher volumes
and the lower strengths. Since all three refineries had numerous wooden cooling
towers and only one practiced any air cooling, high volumes of contaminated cooling
water were discharged.
Chloride concentrations were only determined for refinery A on two samples. In this
refinery both chemical and electrical desalters are used, resulting in chloride con-
centration in the samples of 2700 and 3200 ppm.
The refineries analyzed combined all waste water streams and treated the composite
waste in both primary and biological processes. The results are recorded in Table 21 .
The data are insufficient, and valid conclusions concerning treatment efficiencies
are not possible. At the time the data were collected two of the refineries were
making substantial changes in their treatment systems, and therefore it is not indica-
tive of the present operation.
The three refineries' treated effluents empty into nearby receiving streams. No com-
plaints of fish kills, odors, oils, etc. were reported. Toxicity studies (conducted by
the Department of Zoology, Oklahoma State University) are performed monthly on
these and other Oklahoma refinery treated effluents. Fathead minnows were used
for bioassays on samples of the treated effluents. Statistical analyses were attempted
in order to correlate TLm with these test parameters: pH, NHg, phenol, sulfide,
COD and P and M alkalinity.
-104-
-------
18
Field Sampling Points in Refinery A
No. Sampling Points
1 Crude Overhead Accumulator
(Separated Water from Off Gas)
2 Coker Overhead Accumulator
(Separated Water from Off Gas)
3 Coker Quench Water Tank
4 Coker Collection Pit
5 Catalytic Cracker Sour Water Stripper
6 Catalytic Cracker Slowdown Cooling
Tower
7 Overhead Receiver After Catalytic Cracker
8 Chill Section Waste Water from Dewaxing
and Cooling
9 Boiler Slowdown
10 Chemical Desalter Effluent
11 Make Up Water to Coolfng Towers
12 Chlorinated Influent Feedwarer
13 Inlet Water to Bio-oxidation Ponds
(Waste Water passed through
API separator and settling ponds)
1
180
8820
180
180
3360
96
12960
575
72
304
144
176
COD
II
153
770
306
153
5568
153
7488
306
76
268
76
76
(MG/L)
III
188
8206
151
214
6957
205
8385
312
98
366
169
178
AVG
173
5932
212
182
5295
151
9611
397
82
312
129
143
1
<0.1
5000
<0.1
<0.1
5000
<0.1
4000
<0. 1
<0.1
<0. 1
<0. 1
<0. 1
SULFIDE (MG/L)
II III AVG
7500
7500
3000
7500 6670
<0.1 T
<0.1 <0.1
5000 6200
7500 5200
360 231
294
295
0.2
T T
-------
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
t4
ALKALINITY
(MG/L CaCO)
1 1
20
*
140
168
*
32
*
576
572
124
136
272
192
206
II MI
50
*
171
154
*
45
*
540
590
142
173
341
143
235
1 AVG
35
*
155
161
*
38
*
558
581
133
154
306
167
221
TABLE 18
(Cont)
FREE AMMONIA (MG/L) PHENOL
(MG/L)
1
64
3120
71
103
3500
79
3750
253
0.7
168
64
61
146
155
II
70
*
70
60
*
80
*
1500
0.5
115
60
55
no
90
III
90
*
60
60
*
80
*
700
0.7
215
60
65
140
JOS
AVG
74
3120
67
74
3500
80
3750
817
0.7
166
61
60
132
}\6
III
0.018
*
0.08
0.01
*
T
*
*
<0.01
<0.05
0.07
0.06
0.11
0.015
AVG
0.018
*
0.08
0.01
*
T
*
*
-------
TABLE 19
Field Sampling Points in Refinery B
No. Sampling Points COD (MG/L) SULFIDE (MG/L) ALKALINITY (MG/L, CaCO3)
I || in AVG I II II" AVG I II HI AVG
1 Boiler Slowdown 148 156 108 137 < 0.1 <0.1 <0.1 <0.1 885 975 825 895
2 fromStLPGlScrubbLf!Uenf 6780 3675 4475 4976 7500 2000 3000 4200 *
3 Catalytic Cracker Cooling
Tower Return from Petro- of.a «,- or 009
, ,- . 74 ISA 54 94 <0.1 <0.1 <0.1 <0.1 808 oo & *o~r
leum Condensers '4 loo w >"*
4 Crude Unit Cooling Tower _,. sn on AI
from Petroleum Condensers 148 129 72 116 <0.1 <0.1 <0.1 <0.1 105 50 30
5 Electric Desalter Effluent 148 " 296 222 <0.1 <0.1 <0.1 <0.1 105 " 100 103
6 Composite Waste Before
SeM*atortAfterAPI ** 524 695 609 ** 200 250 225 ** 635 * 635
7 FinTrreated Effluent 460 314 162 312 <0.1 <0.1 <0.1 <0.1 335 455 245 345
-------
o
00
No.
1
2
3
4
5
6
7
FREE AMMONIA (MG/L)
1 II III AVG
1.2 1.05 1.20 1.15
* * * *
0.6 1.25 3.0 1.43
6 8.0 8.5 7.5
6 ** 5.5 5.7
240 * 240
260 280 170 236
TABLE 19
(Cont)
Refinery B
PHENOL (MG/L)
1 II III AVG
T 1.2 T 1.2
2.2 * 2.2
0.05 0.08 T 0.07
0.20 T T 0.2
0.38 ** 0.35 0.37
** * 1.64 1.64
0.15 1.05 0.60 0.60
pH
1 II III
11.3 11.0 10.5
8.7 8.5 8.5
6.2 7.7 6.7
6.5 8.0 6.9
8.4 ** 8.1
8.4 10.1
7.7 7.9 7.1
AVG
10.9
8.6
6.8
7.1
8.3
9.2
7.6
FLOW
RATE
(GPM)
50
10
75
10
15
420
400
TEMP
(CENT)
76
58
40
35
100
42
35
SAMPLING DATES
Trial I 8/14/69
Trial II 8/19/69
Trial III 8/29/69
* - Sulfide Interference
** - Sample Losr
U - Unknown
T - Trace
AVG - Average
-------
TABLE 20
Field Sampling Points in Refinery C
_^
o
I
2
3
5
6
7
8
9
10
11
12
13
14
15
Sampling Points
Water from Raw Crude Oil
Condensate from Crude Flash Distillation
Condensate from Crude Still
(Naphtha Separated)
Condensate from Crude Still
(Rerun for Naphtha Separator)
Catalytic Cracker Process Water
High Pressure Receiver Water
from Cracked Gasoline
Electrical Desalter Effluent
Boiler Blowdown
Make Up Water
Cooling Tower for Crude Distillation
Cooling Tower for Catalytic
Cracker and Crude Flash Tower
Cooling Tower for Alkylation Unit
Composite Before Treatment in Bio-oxi-
dation Ponds (Effluent Passed through
API Separator)
Final Effluent from No. 9 Pond
Final Effluent from No. 6 Pond
1
295
314
196
98
7282
9446
315
453
^0.1
10
"OJ
*
275
639
COD
II
350
273
156
46
5900
10150
230
615
28
9
18
765
405
560
(MG/L) SULFIDE (MG/L)
III
280
170
50
70
3400
9800
170
970
20
10
20
440
590
500
AVG 1 II
308 7.5 50
252 3 .'i
<0.1 <0.1
<0.1 <0.1
<0.1 25
<0.1 <0.1
<0.1 <0.1
-------
TABLE 20
(Cont)
ALKALINITY
(MG/L CoC03)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
1
165
95
65
15
*
*
25
415
240
55
25
25
**
130
375
II
*
80
80
40
*
*
40
430
220
30
45
<0.1
615
185
215
III
140
60
25
90
*
*
80
315
220
105
60
50
130
200
185
I
AVG
152
78
55
48
*
*
48
386
226
63
43
25
372
171
258
FREE AMMONIA (MG/L)
1
520
360
220
70
*
*
170
45
0.5
20
22
35
**
150
140
II
*
60
55
30
*
*
50
40
45
30
35
40
130
50
45
III
85
55
45
70
*
•A
50
43
0.6
40
38
4.5
200
60
70
AVG
302
158
106
56
*
*
90
43
15.3
30
31
26.5
165
86
83
PHENOL (MG/L)
1 11
0.08 0.10
0.18 0.22
0.19 0.20
0.17 0.21
* *
* *
0.28 0.20
0.34 0.20
<0.1 <0.1
<0.1 <0.1
<0.1 <0.1
<0.1 <0.1
0.44
0 < 0.1
<0.1 < 0. 1
I.H AVG
0.06 0.08
0.22 0.20
0.20 0.20
0.21 0.19
* *
* *
0.20 0.22
0.15 0.23
<0.1 <0.1
<0.1 <0.1
<0.1 <0.1
<0.1 <0.1
0.45 0.45
<0.1 <0.1
<0.1 T
1
8.6
6.9
7.2
6.3
8.6
7.5
7.2
10.4
7.2
6.8
6.4
6.1
**
6.9
7.4
PH
II
8.2
7.8
8.2
6.8
8.5
7.2
7.7
10.8
7.8
6.8
7.7
4.3
8.5
7.5
7.8
III
8.9
6.9
7.5
8.3
8.5
7.1
7.4
10.7
7.6
7.3
7.2
6.4
6.5
7.3
7.2
AVG
8.6
7.2
7.6
7.1
8.6
7.3
7.4
10.6
7.5
6.9
7.1
5.6
7.5
7.2
7.5
FLOW
RATE TEMP
(GPM) (CENT)
1
6
1
2
6
12
10
15
450
130
105
35
U
110
no
35
34
63
68
49
41
85
100
15
36
36
29
25
25
25
-------
TABLE 21
Removal Efficiencies of Treatment Processes
Test Parameter
COD (mg/l)
Sulfide (mg/l)
All 1 • • / ^Q/ ' \
Alkalinity ( _ ' _ )
Free Ammonia (mg/l)
Phenol (mg/l)
PH
Average
Influent
295
<0.1
167
116
o.n
7.7
Average
Effluent
182
<0.1
221
132
0.02
7.0
Remova 1
38
99
—
—
84
—
Average
Influent
609
225
635
240
1.64
10.1
Average
Effluent
312
<0.1
345
236
0.60
7.1
Removal
49
99
46
2
63
—
Average
Influent
602
25
372
165
0.45
7.5
Average
Effluent
423
<0.1
171
86
<0.1
7.2
Removal
30
99
54
48
99
—
-------
The eight listed parameters have large individual standard deviations with some ex-
ceeding their arithmetic means. Multiple regression analyses, on the eight test pa-
rameters were inconclusive. The researchers, at Oklahoma State University have
analyzed their data (10 or more years) with similar inconclusive results.
None of the three refineries have established accounting procedures that reflect costs
incurred from waste collection and treatment.
The field study was undertaken to develop data that could be used to indicate relative
strengths and volumes of the various waste streams. It should be used only as a guide
to indicate sources and magnitudes. To develop comprehensive information the fol-
lowing should receive consideration:
1 . Installation of sample ports on each waste stream.
2. Composite sampling of process waste streams is necessary due to upsets and
inherent fluctuations in refinery operations.
3. Sampling should be undertaken on several refineries in each size and com-
plexity category. This may be difficult because of the reluctance on the
part of some to allow State or Federal Agencies to sample and investigate
process streams. This is suspected to stem from: 1) A desire to protect
"trade secrets"; and 2) to preclude punitive actions and "bad publicity"
from wastes generated.
4. Accounting procedures should be developed to assess waste water collection
treatment efficiencies and costs.
Difficulties were encountered at the participating refineries. Some process waste
streams were piped directly to inacessible sewers. Commonly, several pipes emptied
into a collective sewer. Thus, these sewers contain unknown composites from several
processes. Installation of sampling ports or taps would have necessitated equipment
shutdown and considerable expense. Flow measurement of waste streams was impos-
sible where direct sewer connections existed. Upsets and fluctuations occurred in
process streams, but the magnitude of the change could not be gauged with single
grab samples.
-112-
-------
COAL SECTION
SECTION VII
BACKGROUND
Coal is a general name for firm, brittle, conbustible rocks derived from vegetable
debris which have undergone a complex series of chemical and physical changes dur-
ing the course of many millions of years. Coal is derived largely from carbon con-
tained in organic compounds such as starch, sugar and cellulose which, along with
water, account for most of the bulk of vegetation.
The variations in the properties and characteristics of coal depend upon the influence
of three main factors: the nature of the original plant debris, the extent and char-
acter of its decay before burial, and the geological changes subsequently undergone
particularly with respect to heat and pressure.
Geologically, peat is the youngest member of the coal series; next in the ascending
scale is brown coal. Brown coals or lignites represent an early stage in the coali-
fication of peat.
Bituminous coals are the best known of the solid fuels. Most bituminous coals have
a banded or laminated structure and shiny black appearance.
Anthracite is the highest ranking coal to be produced by the physico-chemical al-
teration of peat. It is hard, dense and lustrous, does not break down easily and is
clean to handle. Difficult to ignite, it burns with a short intense flame and with
tfie virtual absence of smoke.
As shown in Table 22, the United States is the largest coal exporter in the world. In
1968, total exports of bituminous and lignite coals rose to 50.6 million tons and were
valued at $496 million. World production of coal totaled 3 billion tons, with the
United States supplying nearly 18 percent of the world output [49] .
Interest in the quantity and quality of coal in the United States has increased greatly
because we now realize that we are using up our reserves of petroleum and natural
gas at a rate far surpassing that anticipated a few years ago. At some time in the
future, therefore, the contribution of coal to our total production of energy must
be enlarged to include some of the needs now served by petroleum and gas.
Although coal-bearing rocks cover 14 percent of the total area of the United States
and contain enormous reserves, it is nevertheless apparent that reserves of coal also
have limits. The U.S. Bureau of Mines projects that for me period 1965-2000 coal
consumption will increase more than 250% in the U.S. and more than 575% world
widc [103] . In extensively mined sections in the East it is already difficult to
-113-
-------
TABLE 22
Output of Coal in Main
Producing Countries
(m i 11 ions of m. tons, including anthracite and lignite)
U.S.S.R.
U.S.
European Coal and
Steel Community
U.K.
India*
Australia*
Canada
Rep. of South Africa
Poland
Japan
China (e)
p Preliminary
* Financial Year
e Estimate
Source: Mining Journal,
1965
578
478
325
191
72
53
10
48
141
50
300
1 968 and 1 969,
1966
585
496
307
177
73
56
10
48
146
52
330
Annual Review.
1967
595
519
290
172
74
58
10
49
152
48
250
1968(p)
600
510
288
164
75
61
10
52
155
47
275
-114-
-------
locate new areas that contain thick beds of high-rank and high-quantity coal to re-
place areas that have been mined out. Remaining anthracite reserves are estimated
at about 15 billion tons, enough to support the rate of production at 61 .5 percent
recovery for 450 years. A considerable part of the total coal reserves of the United
States consists of lignite and sub-bituminous coals or thincoal beds that can be mined
only with difficulty and expense.
Goal is removed from the earth by either of two mining procedures. If the coal seam
Is a substantial distance under the ground, shaft mines are employed, from which coal
is mined after tunneling through rock and other strata above the coal seam [104]
Underground mining in 1968 produced 344 million tons of bituminous and lignite coal
from 3400 mines at an average value of $4.67 per ton. The high degree of underground
mechanization has had a profound effect on output resulting in an average 15 tons per
man per day in 1967 [105] .
When the coal is near the surface of the earth (approximately 100 ft or less), it may
be removed by surface or strip mining procedures. In surface mining, the rock and
other strata overlying the coal are excavated to expose the top of the coal seam- the
coal is then removed from the surface mine [104] . '
During 1917, surface mining accounted for only 1 percent of the total United States
production of bituminous coal and lignite as compared to 33.7 percent in 1966 Since
World War II, coal has been in intense competition with petroleum and natural'gas and
has maintained a competitive advantage in areas where it can be mined on a large scale
at very low cost by surface mining methods. Illinois, in 1 966, lead the nation in strip
coal production with a total of 36.1 million tons; Pennsylvania produced 30 million
tons from operations in both the bituminous coal and anthracite regions That same
year the entire coal production of eight states: Alaska, Kansas, Missouri, Oklahoma
Texas, Wyoming, North and South Dakota, was obtained by surface mining. In 1968
strip mining produced 186 million tons of bituminous and lignite coal [105] ' Ultimate-
ly strip mining greatly increases the amount of recoverable coal, for the method yields
on average recovery of about 80 percent as compared to 50 percent for underground
mining U06J .
The electric utilities have fostered the development of strip mining because the demand
for electricity has increased greatly over the years and because the huge generating
plants are equipped to use the most economical fuel available. Sales to electric util-
ities are expected to approach 450 million tons annually by 1980 [107] .
Reclamation of stripped acreage is one of the major problems confronting the coal in-
dustry. If all the recoverable bituminous coal in the State of Pennsylvania were to
be stripped- by the surface mining method, only 3 percent of the state's total land
area would be d.sturbed [108] . However, the thousands of stripped areas in the
United States total about 1500 square miles. Recognizing this threat to the beauty
of the land, many states have enacted legislation to require reclamation of future
mined land.
-115-
-------
During mining operations water from a number of sources finds its way into the voids
and depressions created by the mining process. When the water is removed so that
mining can continue, or when it leaves the mine by natural drainage, it sometimes
becomes acid in character as a result of a complex process involving interactions
between the physical, chemical and biological characteristics of the environment.
The seriousness of the mine water problem was recognized in the 1930' s and 1940' s
particularly from abandoned mining operations. Present practices have shown that
drainage from strip mines can usually be controlled, but the prevention or treatment
of acid drainages from worked out or active underground mines presents a sizable
problem. The magnitude of this problem may be realized when one considers that
in 1962, when approximately 32 percent of the total anthracite production was deep
mined, about 46 billion gallons of water were pumped to the surface. In the same
year the uncontrolled flow was estimated at more than twice the controlled or pump-
ed flow [109] .
After coal has been taken from the earth, it frequently must be processed to make it
suitable for use. Processing generally consists of removing rock and other mineral
impurities and of sizing or screening the coal. In 1968 the quantity of raw bituminous
and lignite coal mechanically cleaned in the U.S. was 438 million tons producing
97 million tons of refuse ll 10] . Many processes are available for removing the ex-
traneous mineral matter; most of these operations use water as the cleaning medium.
The principal pollutants in water discharged from the processing of coal are suspended
solids usually in the form of fine clay, black shale and other minerals commonly as-
sociated with coal. Elaborate water circulation and clarification systems have become
more common since environmental control laws have become more stringent.
Coal and coke are used as sources of carbon for chemical reduction and energy sources
in the metallurgical and power industries. Considerable quantities of activated car-
bon are used to decolorize and remove tastes and odors from water; and to recover sol-
vent vapors from air. The production of coke by carbonization of coal produces a
wastewater that is high in phenols, ammonia, and dissolved organics. Biological
treatment processes appear to be very promising.
The increased emphasis on air pollution has brought into sharper focus another problem
associated with the coal industry. Coal preparation plants emit fine particles from
cleaning and drying operations. The combustion of high-sulfur coals adds substantial
amounts of contaminants to the atmosphere in the form of particulates and sulfur oxides.
Power plants, the basic coal burners, are responsible for 14 percent of the total air
pollutants [110] . Fortunately, the outlook with regard to stringent sulfur content
limitations on utility grade coal is much brighter because of a process to convert high-
sulfur coal to low sulfur boiler fuel with concomitant by-product recovery of elemental
sulfur and hydrogen. However,most of the procedures employed tor extracting wastes
from gaseous emissions incorporate water into the removal scheme at some point. The
water used in scrubbers, in the transport of solid wastes, etc. must subsequently be
-116-
-------
treated. Waste products from the combustion of coal, continue tobea liability. Fly
ash production in 1967 was approximately 18 mi 11 ion tons, 89 percent of which was con-
sidered refuse and of no commercial use. In 1968, however, utilization of fly ash,
which constitutes about two thirds of the 30 million tons of ash generated per year,
amounted to 2.5 million tons, a 17% increase from 1967 [111] .
This report presents a literature review of practices that are employed to alleviate
water pollution problems associated with coal technology as related to its procure-
ment, processing and utilization. Included is an overview of the problems confront-
ing each phase which are to some extent uniform, and the current status of pollution
control legislation and research. A review of the supplies needed to satisfy the grow-
ing energy market, present and future, are summarized.
-117-
-------
SECTION VIII
MINING
Practically all water pollution problems that result from the mining of coal are asso-
ciated with drainage. All types of mineral mining present some version of a drainage
problem, but probably the most serious, because of its severity and magnitude, is from
coal mining. According to Braley, [112] drainage from coal mines was probably the
most serious water pollution problem in 1957; and in 1969, an editorial from Environ-
mental Science and Technology [113] reported that perhaps no major industrial water
pollution problem is as complex or will be more costly to remedy than acid mine
drainage. These comments suggest that even though the acid mine drainage problem
has been recognized for a number of years, little has been accomplished in terms of
abatement. Perhaps the reason for the lack of accomplishment lies in the confusion
surrounding acid mine drainage. Only the gross mechanism of acid drainage formation
is known and even the basic reactions involved are not completely understood. Ques-
tions arise about the precise course of the various reactions and their products, the
importance of various components and the methods for their determination. According
to Krickovic [l 14] the acid mine drainage problem has been made more complex and
confusing by a lack of realistic definitions. He further states that there is no single,
permanent cure for drainage from all acid producing mines because of the variety of
mines. He categorizes mines as active and worked out deep mines above drainage, or
drift mines; deep mines below drainage, or shaft and slope mines; and contour strip
mines with high walls of 30 to 70 feet and those with high walls ranging from 70 to
130 feet and possibly higher. All types include mines which are abandoned and may
be reopened, thus contributing to the variety and making it more apparent that there
can be no one solution for the overall problem.
Attempts to alleviate the confusion concerning acid mine drainage are made difficult
because the concepts and mechanisms, in order to be understood and applied by the
coal industry, must often be described in general, lay terms. A case in point is the
description of acid formation by Maneval and Charmbury [115] . They state, "Water
draining from coal mines in Pennsylvania nearly always contains sulfuric acid. This
acid is formed by the oxidation of the sulfur occurring in the coal and in the rock and
clay found above and below the coal seams. This sulfur is in part combined with the
coal, but by far the greater part is a sulfide of iron, known variously a ' fool1 s gold1 ,
pyrite, iron pyrites, or 'sulfur balls' . In the presence of water, and under the in-
fluence of oxygen in the air of the mine, the sulfur is oxidized and still combined
with iron, dissolves in the water as copperas, more properly called ferrous sulfate.
Flowing from the mine, and still in the presence of air, and sometimes under the in-
fluence of other agents, the copperas is oxidized to ferric sulfate. The iron after this
oxidation has a weakened affinity for sulfuric acid, and in various forms is partially
separated as a sediment, brownish yellow in color, frequently called 'yellowboy1.
Sulfuric acid, accompanied by some iron, remains in the water." This description of
-119-
-------
acid formation may be basically correct, but it also may be misleading in that admin-
istrators or other key, non-technical personnel, because of the casual nomenclature
and incidental descriptions, are apt to overlook the complexity and mystery that make
acid mine drainage such a pressing problem.
With the growing importance of water pollution control programs and their relation-
ship to coal mine operations, and in view of the problem of communications and in
formulating an exact description of acid mine drainage, many literary contributions
have been made. Corriveau [l 16] believes that there is a need to review the defini-
tion of terms and limitation of tests which are becoming increasingly more important
to plant operators and regulatory bodies with which they have to deal. Among the
tests and terms which he describes and defines are pH, total and mineral acidity,
alkalinity, iron and sulfates. In his paper, Braley [l 12] points out the intricacies
of pH, and free acid interpretations. It is his belief that the one factor most valuable
in determining the quality of a mine water is total acidity or alkalinity as determined
by titration in hot solution too phenolphthalein end point; and that its use as a common
method of evaluating the quality of mine water discharge will eliminate much misun-
derstanding concerning the effect and control of mine acid.
In an authors reply, Braley, in rebuttal to a paper written by Ashmead [117] asserting
that bacteria play a major role in the formation of acid mine waters, reemphasizes
that the bacteria in question, Ferrobacillus ferrooxidans, do not directly oxidize
pyritic material, but do, however, augment the chemical formation of sulfuric acid
by atmospheric oxidation. Contrary to this, laboratory studies by Schearer, [118]
et. al., indicate that bacteria are apparently responsible for the production of much
of the acid which drains into Pennsylvania streams. Their studies indicate that acid
production in coal mines might be reduced by 50 to 70% by inoculating influent
streams with unidentified, naturally occurring antibacterial agents. A $120,000
project to test this technique in two operating coal mines was scheduled for July 1968.
Nemerow [l 19] agrees that bacterial activity plays an important role in acid formatiorv
but cites the sulfur-oxidizing bacterium Thiobacillus thiooxidans as the contributing
organism. In addition, Nemerow presents a scheme of chemical reactions depicting
acid formation.
Even though the complexities involved with acid mine drainage are controversial,
there is general agreement among most as to the overall cause effect relationship.
This is that the primary pollutants found in coal mine drainage are chemical contam-
inants, acids, sulfates and iron, and sediment. Acid formation and some sedimen-
tation occur when natural drainage brings water into contact with sulfur bearing
minerals in mines or refuse piles. Exposure of pyritic materials, (iron sulfides which
often occur in conjunction with coal deposits), to air or oxygen dissolved in water
results in oxidation of these materials. Leaching by the drainage water then results
in acidic discharges. These discharges destroy aquatic life in streams, make water
-120-
-------
corrosive and unfit for industrial use, may react with alkaline substances in the earth
thus adding to the hardness of the water, and are responsible for the deposition of
50me undesirable substances along a watercourse.
An authoritative estimate made in 1962 of the magnitude of the problem in the U.S.
was that 3,500,000 tons of sulfuric acid equivalent per year were being discharged
to inland watercourses [120] . There is little doubt that an even greater amount is
being discharged into streams and rivers today. According to Environmental Science
and Technology, ll 13] "about 75% of the mine drainage problem occurs in the
Appalachia area alone, where it degrades over 10,000 miles of surface streams."
They further point out that fully 60% of the acid drainage in the U.S. is from aban-
doned surface and deep shaft mines.
The Bureau of Sport Fisheries and Wildlife [121] receives reports from all 50 states
concerning the extent of acid mine pollution in that state. As can be seen from
Table 23, 5,890 miles of streams and 14,967 acres of impoundments in the U.S. could
classify as suitable habitats for fish and wildlife if acid pollution were sufficiently
reduced. Approximately 97% of the acid mine pollution reported for streams and 93%
Of the acid mine pollution reported for impoundments resulted from coal mining
operations. Pennsylvania and West Virginia contain over 66% of the stream mileage
and 90% of the impounded acreage of waters deleteriously affected. If these polluted
habitats could be restored, an estimated 2 million days of recreational fishing annually
with a value in fisherman expenditures of more than $11,500,000 would result. This
aid would be extremely beneficial to the economics of these areas. Table 24 is a
list of states which reported that acid mine pollution was no problem.
|n conjunction with these findings, Environmental Science and Technology [113] re-
ports that in 1967 over a million fish were killed; making this type of pollution among
the primary causes of fish kills in the U.S.
|n view of the magnitude of the acid mine drainage problem, and in spite of only a
tentative knowledge of the precise mechanisms involved, enough is known to initiate
programs to combat the problems.
Hanna, et. al., [122] have provided impetus toward initiation of such programs by
conducting a study intended to place in perspective the factors relating to the for-
rriation, measurement and control of acid mine drainage. The study indicates gaps
in knowledge that should be filled in order to master the associated problems and to
provide an efficient research approach to existing, additional, or ensuing problems.
Table 25, taken from their study, indicates the status of knowledge in 1963 and the
proposed endeavors and the goals to be achieved in four fundamental areas. Figure
13, is their suggested, planned program of research for acid mine drainage.
-121-
-------
TABLE 23
Potential Fish and Wildlife Waters Deleteriously
Affected by Acid Mine Pollution
State
Pennsylvania
West Virginia
Kentucky
Ohio
Illinois
Missouri
Tennessee
Maryland
California
Kansas
Indiana
Montana
Arkansas
South Dakota
Iowa
Colorado
Maine
Virginia
New Hampshire
Wyom ing
Totals
Miles of
streams
2,906
1,150
580
278
222
208
125
83
54
62
58
48
35
34
20
10
10
4
3
5,890
Acres of Minerals
impoundments mined
10,100 Coal
3,533 Coal
Coal
92 Coal
80 Coal
Coal
Coal, Cu, P
Coal
1,000 Cu, Zn
Coal
Coal
Coal, Cu, Vm
Al, Ba
Bog iron
Coal
Pb, Zn
62 Cu, Pb, Zn
Cu, Zn
Cu, Pb, Zn, Ag
Cu
14,967
Symbols used: Ag - Silver; Al - Aluminum; Ba - Barium; Cu - Copper;
P - Phosphorous; Vm - Vermiculite; Zn - Zinc.
Source: U.S. Dept. of the Interior, Fish and Wildlife Service, Bureau of
Sport Fisheries and Wildlife, Circular 191.
-122-
-------
TABLE 24
States Which Reported That Acid Mine Pollution is No Problem
Alabama
Alaska
Arizona
Connecticut
Delaware
Florida
Georgia
Hawaii
Idaho
Louisiana
Source: U.S. Dept.
Massachusetts
Michigan
Minnesota
Mississippi
Nebraska
Nevada
New Jersey
New Mexico
New York
North Carolina
of the Interior, Fish and Wildlife Service,
North Dakota
Oregon
Rhode Island
South Carolina
Texas
Utah
Vermont
Washington
Wisconsin
Wyoming
Bureau of Sport
Fisheries and Wildlife, Circular 191.
-123-
-------
TABLE 25
Fundamental Area Relations to the Acid Mine Drainage Problem
Funda-
mental
Areas
Status
ro
•t*.
i
Proposed
endeavors
Goals
Chemistry
End products and
general overall
reactions are well
defined. Elemen-
tary reaction mech-
anism is unknown
and intermediate re-
actants are not estab-
lished. Several rate-
mechanism concepts
are postulated.
Basic research on
reaction mechanisms.
Determine kinetics of
sulfide-sulfate system.
Arrive at rate-control-
ling mechanisms on
which methods of inhib-
iting or catalyzing reac-
tions and evaluating acid
potential may be based.
Microbiology
Microorganisms are
"somehow" involved
in sulfide oxidations.
Microorganisms can
reduce SO. .
Basic studies of
oxidation of S
and reduction of
SO^ by micro-
organisms.
Determine quali-
tative and quantita-
tive roles of various
microorganisms in both
oxidation of sulfides
and reduction of suf-
fates.
Mineralogy-
Petrology
General description of
pure sulfide materials
is well established.
Little is known of the
mineral associations
of sulfides in coal and
associated strata.
Petrographic studies of
sulfuritic material in
coal and associated
strata.
Determine mineralogic
relationship of sulfides
in coal and associated
strata.
Geology-Hydrology
General principles
and overall effect
are known.
Quantizing and specific
application of general
principles pertinent to
the in situ setting.
Evaluate rock composi-
tion and mineral varia-
tion as a measure of acid
potential. Determine the
neutralization character
of certain measures and
their effect on the acid
production. Develop a
rational hydrological ap-
praisal of the acid water
production.
Source: Journal WPCF, 35, No. 3, March 1963, p. 291
-------
DEFINITION OF PROBLEM
POSTULATE METHOD OF ATTACK
based on known principles of:
chemistry, microbiology, mineralogy-
petrography, and geology hydrology
I
ESTABLISH TESTING PROCEDURES (Utilize pre-planned statistical design)
1. Select parameters to measure results
2. Select or develop testing techniques and equipment
3. Establish testing pattern and frequency
FUNDAMENTAL EXPERIMENTS
AND STUDIES
1. Kinetics of sulfide sulfate system
2. Role of microorganisms
3. Mineralogic and petrographic
relations
4. Relation of rock composition to
acid production
5. Rational Hydrological approach
APPLIED EXPERIMENTS
AND STUDIES
1. Exclusion of reactants by
seals - air and water flooding,
earth fill
2. Water control by diversion,
containment, controlled
discharge
3. Chemical applications
4. Biological applications
5. Area reclamation
MONITORING OF EXPERIMENTS I
I
CORRELATION AND EVALUATION
CONCLUSIONS
Effects of the overall abatement program of funda-
mental principles applied to the reduction of acidity
in mine waters as measured by specific parameters.
Effects at the sources of production
Effects in the receiving streams
FIGURE 13. PLANNED PROGRAM OF RESEARCH FOR ACID MINE DRAINAGE, [122]
-125-
-------
An important facet of a combatant program is prevention of the problem at its source.
Hert [1231 recommended the following five practical control measures to reduce acid
mine drainage:
1 . Drainage control and diversion of water, to prevent water from entering the
mining area, and rapid removal of any water present.
2. Proper disposal of sulfur-bearing materials, to ensure that none of the "gob"
(sulfurtc refuse) comes in contact with water.
3. Elimination of slug effects of pumping, i.e., equalize loading on treatment
plant by distributed pumping.
4. Sealing terminal activities, actually a process of sealing up abandoned mines
to prevent water from entering the sulfur-bearing soil.
5. Treatment of mine drainage, under certain circumstances chemical treatment
of controlled quantities of drainage from workings, to protect water quality.
Nemerow [119] concludes that by observing fourgeneral rules, keep waterout, keep drain-
age moving, segregate sulfuritic materials and neutralize acid pools, the formation of
acid mine water can be prevented.
Steinman [124] outlines preventive measures advanced by the Pennsylvania Sanitary
Water Board and the Mellon Institute that apply to coal mines currently in operation
which have met with success. These measures include:
1. Surface water and ground water are diverted where practical to prevent the
entry or reduce the flow of water into and through workings.
2. Water is not allowed to accumulate in working areas. Sumps are dug in low
spots and kept pumped out, thereby keeping the water from the acid-formina
pyrites on the face. Numerous pick-ups are employed for each pump.
3. Wherever possible, pipes, instead of ditches, are provided to conduct water
by grav.ty. This keeps exposure to acid-forming material on the bottom to
a minimum.
4. Gathering or main sumps are provided in the mine by driving separate sump
entries or by digging up the bottom. This practice does not permit water to
accumulate m the local |OW gob areas with large acid-producing surface
areas exposed to the water. These large sumps also provide reservoir capacity
and prevent surges of mine water from entering a stream
5. Discharges into streams are regulated, insofar as practical, to equalize daily
accumulation throughout a 24-hour period.
6. Samples are token periodically to determine the quality of the mine water
discharged These samples are gathered and processed at the company's
analytical laboratory in accordance with standards set forth by the Mellon
Institute. Records are kept to determine any significant change in quality.
A 1960 article [125] in Engineering News-Record in reference to deary's
work announced positive steps which could be taken to minimize acid mine
drainage. Bas.cally, they were aimed at reducing waterflow into mines. The
-126-
-------
steps mentioned were a reduction in contact time between the water and acid forming
materials, proportioning discharge according to stream flow over a 24-hour period
instead of discharging "slugs" of acid water, and when feasible, sealing mines to
minimize exposure of sulfurous materials to oxygen.
The Coal Industry Advisory Committee to the Ohio River Valley Water Sanitation
Commission recommended practical approaches for the control of acid mine drainage
in 1964 [126] . Included were the diversion of surface and ground waters where
practical to prevent or reduce flow through and into workings, the control of mine
drainage within the mine to minimize water flow over acid-producing materials, the
regulation of mine-drainage to streams over a 24-hour period and mine-closing measures
to minimize acid formation and discharge from inactive mines. Despite such preventive
measures, some drainage from active mines is inevitable and some means of treating
the drainage waters is necessary.
The lime neutralization process has been successful and provides a basis of reference
with which to compare other methods. The principle of this process in that lime,
CaO or Ca(OH)2, is mixed with acid mine drainage to neutralize the acid and pre-
cipitate the contaminating metal salts. This process is represented by chemical equa-
tions as follows:
Ca(OH)
2AI(OH>
3
The sludge formed by the sedimentation of the metal salts has a high water content
and presents a difficult disposal problem. Braley [127] concluded that because of
slow sludge settling and excessive cost, the application of lime neutralization to mine
drainage would not be practical.
Crichton [128] discussed the application of the lime neutralization process to acid
mine drainage and reported that treatment cost estimates ranged from 15 to 25 cents
per 1000 gallons.
|n a review of the acid mine drainage problem, Hanna, et. al.f [122] concluded
tf,at neutralization processes were not economically feasible except in cases involving
v/e 1 1 -defined areas.
|n 1965 Maneval and Charmbury [115] described an acid mine water mobile treatment
pilot plant project known as "Yellowboy, " which involved the lime neutralization
process. This truck-mounted pilot plant was to attain data from five different mine
sites; the results to be used in the design of commercial-sized acid mine drainage treat-
plants. Operation of the pilpt plant was to entail flash mixing of the acidic
water with slaked lime thus neutralizing the water, followed by aeration and settling
-127-
-------
to precipitate the iron in solution. The precipitate or slurry was then to be dewatered
by filtration or centrifugation depending upon the characteristics of the slurry. If the
acidity of the effluent from the dewatering unit was not within the range acceptable by
the Pennsylvania Sanitary Water Board, it was to be reprocessed. A flow diagram of
the unit is shown in Figure 14.
Girard and Kaplan [129] reported preliminary results of "operation yellowboy," in
1967. The results indicated that mine water can be treated by lime neutralization
aeration, sedimentation and dewatering to produce an effluent containing less than
6 ppm iron at a neutral pH. Results further revealed that depending upon the degree
of contamination and the extent of treatment used, costs range from 0.7 cents to $1.09
per thousand gallons treated or 5.2 cents to $3.25 per ton of coal produced.
Charmbury, in a later article [1301 , reported that as a result of the technical and
economic data provided by operation of the mobile field plant the nation's first lime
neutralization plant was built and put in operation on Little Scrubgrass Creek in
Pennsylvania, in December 1966, at a cost of $35,000. He further reported that by
way of basic research, the economic feasibility of building water demineralization
plants at key, central points has been determined. Operating by desalinization prin-
ciples used on salt water, the demineralization plants would produce pure water which
could be used for generating electricity, thereby creating a by-product that could defer
operational expenses. Other mine-drainage research projects started in Pennsylvania
include ion exchange treatment, coal products interaction with mine drainage, deep
well disposal of drainage, inhibition of acid formation by antibacterial action'and the
removal of iron from mine water using ozone. Charmbury concludes that although the
methods and^technology have been developed, money is the key to alleviating mine
water pollution.
Another lime treatment process is described in a presentation of the facilities used by
U.S. Steel in removing drainage contaminants from three of its mines [131] . The
relatively simple schemes utilize neutralization, mechanical aeration and sedimentation
Water discharged from mine one had a flow of 150 gpm, an initial pH of 4.5 to 7.1
acidity of 25 to 125 mg/l and a total iron content of 25 to 125 mg/l. Limited land '
area necessitated a compact treatment plant involving a constant-speed lime feeder
for acid neutralization, a surface aerator for faster iron precipitate formation, a
flocculate feed system for greater solids settling, and two 40,000 gallon settling tanks
A portion of the precipitate was recirculated to help maintain maximum sludge density*
The plant effluent had a PH of 7.5 to 8.0, no acidity and 2 to 5 mg/l total iron content
Mine two discharged 900 gpm into an 8,000,000 gallon raw water pond which provided
storage capacity whenever the treatment plant was down for repairs. An analysis of
the raw water influent showed a pH of 7.3 to 8.2, alkalinity of 350 to 610 mg/l and an
iron content of 0 to 12 mg/l, all ferric. Water then flowed to a surface aerator which
-128-
-------
>0
AMD
OVERFLOW
TO WASTE
"in
HEAD
BOX
PRECOAT
TANK
DRUM
FILTER
SLAKED
LIME
OVERFLOW TO
WASTE
HEADBOX
AERATOR
FLOWRATOR
CAKE TO WASTE
*• TREATED AMD
(PRODUCT)
TREATED AMD
RECEIVER
FIGURE 14. FLOW DIAGRAM OF ACID MINE WATER MOBILE
TREATMENT PLANT. [115]
-------
prepared the iron for easier settling in a 250 million gallon pond. The final effluent
had a PH of 7.5 to 8.3, alkalinity of 330 to 420 mg/l and total iron of 0 to 4 mg/l.
Water from mine three ranged in quality from mildly alkaline in the new areas to h!nM
ac.d.c in older sections. To ease the load on the treating facilities and reduce \\JT
consumption, alkalinewater was routed and mixed with acid water This resulted i
d.scharge with a PH of 2.9 to 3.3, an acidity of 500 to 1600 mg/l and an iron rnn* «•
of 300 to 800 mg/l. Treatment facilities included an 8,000,000 gaMon raw water-
storage pond, lime feeder with slurry-mixing chamber, surface aerator, and 140 mil
lion gallon settling pond. As discharged, the effluent had a pH of 7 3 to 8 5
' * '° 4 m' • FI°W dla '
Hydrated lime neutralization of acid mine drainage is known to be effective and U
currently the only extensively used method of treating acid mine drainage. However
he e f.c.ent storage handling and disposal of the resulting sludge represents a verv
troublesome aspect of treatment by lime neutralization. It is apparent from its accL
ance that th.s process can be applied economically in certain situations. Other situ
a ,ons, however may require different treatment methods to be economically and
eff.c.ently sound. Therefore, research continues in an attempt to find alternative
TrAntm*»n* m^f-U^^J/. ' vmvc
treatment methods.
A process for treatmg ac.d mme drainage using an active biochemical sludge followed
by limestone neutral.zat.on is discussed by Glover [132] . He announced that whT
trea ting mme dramages that contain more than 10 to 20 mg/l of dissolved iron «n7
total acidity of more than 25 mg/l (CaCOJ the process h .fflcF.n^7LTn cost"
and that consequently over half of the aciJ coal mine drainages in the U.S. couTd L
treated using this novel process. be
According to Glover, limestone has been used for neutralizing acid mine aran
but because of a hard scale of iron and other precipitable salts that form on the surF
the reagent soon becomes inactive. Preliminary studies using limestone grit vertical
columns with mechanical scouring showed that free acidity and ferric and aluminum
salts could be removed, but ferrous salts passed through unchanged. When draina
were pretreated with iron oxidizing bacterial cultures, ferrous salts were readily
verted to ferric and could then be removed together with the original ferric salt. k^T
limestone grit. DX the
In response to Glover's study and previous studies, a pilot plant consisting of a 300 I-
aerated biochemical oxidation reactor, a sedimentation tank for active solids coll '
an upflow expanded bed limestone grit column, and a sludge filter was constructed Ct'°n'
Drainage at the point of discharge from a mine was collected in an equilization ba *
fed at a f|ow rate of 0-5 liters/minutes to the plant. The influent had a pH of 3 Q "
-130-
-------
ATI
1
SETT
PREClPITATt
TO
TO
STEAM
••'•f. 1131]
-------
RAW STORAGE LAGOON
LIME STORAGE
TANK
LIM
SLURRY
MIXER
SURFACE
AERATOR
MINE
BOREHOLE SKIMMER
WELL, SETTLING
LAGOON
TO RECEIVING STREAM
fcfc-
FIGURE 16. FLOW DIAGRAM OF U.S. STEEL MINE DRAINAGE TREATMENT PLANT. [131]
RAW STORAGE
^
SURFACE
AERATOR
STORAGE TANK
FUTURE
LIME SLURRY
MIXER
BOREHOLE
SETTLING
LAGOON
TO RECEIVING STREAM
FIGURE 17. FLOW DIAGRAM OF U.S. STEEL MINE DRAINAGE TREATMENT PLANT. [131
-132-
-------
ferrous and ferric iron content of 100-300 mg/l and suspended solids concentration up
to 10,000 mg/l. After oxidation, neutralization and sedimentation the pH ranged
from 6.0 to 6.5 and contained almost no detectable iron. Suspended solids were re-
duced to less than 20 mg/l.
The active sludge formed a strong floe, settled well, and could be returned to the bio-
chemical reactors successfully. Although taking many months to develop, the sludge
retained its full activity for a few days in the absence of mine drainage provided the
air supply and feedback circuit was maintained. Microscopic examination revealed
masses of iron oxide, mineral particles, and a few motile bacilli.
Dense high calcium limestone graded from .0099 in. to .0255 in. made up the neutral-
izing media. The oxidized drainage was forced upward through two 10 feet by 0.5
feet columns in series at a pressure sufficient to maintain the bed in a fluidized state.
Internal phospherbronze impellers located near the top of the columns continually
scoured the grit. Discharge from the limestone reactors settled poorly and required
four hours retention time. Sludge from the neutralization process compacted well
having one-tenth the volume of sludge from the same mine water neutralized with lime.
Solids content of 9 to 12 percent (w/w) were common compared to 1 .2 percent for the
lime process. Sludge dewatered well on a model rotary vacuum filter.
Cost estimates for treating a typical acid mine drainage indicated that the new process
had a distinct cost advantage over the lime process but the lime process became more
efficient as the degree of contamination rose.
The process is represented chemically by the following reaction and schematically by
Figure 18.
3 + 3CACO3 + 3H20->- 3CaSO4 + 2AI(OH)3 + 3CO2
A pilot plant for treating mine drainage by neutralization that was designed, fabricated,
and operated by the U.S. Bureau of Mines [133] showed the limestone-neutralization
process to be effective and costs are estimated to be one-third to one-half that of the
conventional hydrated lime process.
A horizontal rotating tube mil charged with coarse limestone and fed a small volume
of mine drainage generates a fine (minus 400-mesh) slurry; the slurry is then mixed
with the drainage to be treated and aerated. The constant grinding action on the lime-
stone that takes place in the tube removes the sulfate scale thus presenting a clean
reactive surface at all times. Surface aerators oxidize the ferrous iron and air sparging
strips CO2 from the solution. A sedimentation pond collects the iron precipitates and
other solids from the liquid.
The process was successful in treating flows of 300-400 gpm, at a pH of 2.8, total
acidity of 1700 ppm and total iron of 360 ppm (36 ppm ferrous iron). Final effluent
-133-
-------
AIR
LIMESTONE
GRIT
ACID MINE
DRAINAGE
FLOW
BALANCING
BIOCHEMICAL
OXIDATION
SEDIMENTATION
LIMESTONE
NEUTRALIZATION
SEDIMENTATION
ACTIVE
SLUDGE
TREATED
EFFLUENT
SLUDGE
FILTRATION
CAKE TO WASTE
FIGURE 18. FLOW DIAGRAM OF COMPLETE BIOCHEMICAL OXIDATION
AND LIMESTONE NEUTRALIZATION PROCESS. [1321
-------
contained no detectable iron and had a pH of 7.4. A three-fold reduction in sludge
volume resulted as compared to mine water neutralized with lime. A flow sheet of
the process is shown in Figure 19.
As part of a research program directed toward developing more effective and econo-
mical methods for treating acid mine drainage, Sterner and Conahan [134] undertook
experimental and pilot plant studies of ion exchange as a means of producing a con-
centrated waste stream which would contain the iron and aluminum and could be
handled more conveniently and economically than the sludge from lime neutralization.
The pilot plant results demonstrated that by using 15 percent aqueous sodium chloride
solution as a regenerant for the ion exchange treatment process an effluent containing
7 mg/l iron and 70 mg/1 acidity could be expected. By this treatment the cations
were concentrated into a waste stream with 1.7 percent of the volume of the original
acid mine drainage stream. The acidity in the processed water and in the concentrated
waste stream could be neutralized via lime treatment. The authors provide a materials
cost analysis, but point out that these costs apply only to the particular mine drainage
processed in this pilot study. A flow diagram of the pilot plant is shown in Figure 20.
An iron removal technique utilizing high energy radiation is described by Steinberg et.
a|. [135] . Cobalt-60 gamma radiation is used to oxidize ferrous iron to the insoluble '
and precipitable ferric form. In part II of the study, experimental results from samples
containing 488 ppm Fe4"1" and pH = 3.35 are given. At ambient temperature (25°C)
with limestone neutralized and aerated solutions., chain-oxidation-yields with G values
(G value = molecules of Fe oxidized to Fe or removed from solution per 1000 CV of
radiation deposited) ranging up to 285 are obtained. G values and rates of Fe re-
moval decrease with decreasing temperature, and at field temperature (10°C) the G
va|ue is decreased to the point indicative of a nonchain mechanism. At high intensity
(3.5 x 10° rads/rir) a G value of 12 is obtained together with a rate of Fe4^ removal
v/hich is 20 times higher than the unirradiated control and is relatively insensitive to
temperature decreases. Increasing either the pH of the mine water or the aeration in-
creases the radiation yield (G) and the rate of Fe44" removal. These results indicate
that radiation treatment offers a means of improving the rate of Fe4"4" removal. In part
III of the study however, it was concluded that a limestone neutralization process might
prove more promising in terms of economics and removal rates for the particular drain-
age under study. In addition, the authors discuss the economics of competitive Fe4"*"
oxidation and removal processes. These include limestone neutralization and aeration,
limestone and lime neutralization and aeration, lime treatment, hydrogen peroxide
oxidation, ozone oxidation and the ultraviolet light process. As was previously in-
dicated, limestone treatment for most instances seems to have an economic advantage.
Since a large percentage of acid drainage in the U.S. is from abandoned mines, it is
essential that they be properly recognized as pollution sources. The abatemen/pro-
cedures mentioned would normally be applied to active rather than inactive mines, and
-135-
-------
POND
TO
"i, 7O Ft, < I
-------
I
XI
REGENERANT
—8—4
—3—
WASTE
REGENERANT
ION
EXCHANGE
CONTACTOR
REGENERANT
PUMP
PULSE WATER (fresh)
BACKWASH
RESIN
OUT
i.
PRODUCT
FEED
AMD
PUMP
RESIN
IN
RESIN
PUSH
PULSE
OUT
BACKWASH
OUT
SERVICE WATER
PUMP
DRAIN
SERVICE
WATER
SUPPLY
FIGURE 20. FLOW DIAGRAM OF AN ION EXCHANGE
PILOT PLANT. [134]
-------
would be financed at least partially by the mining company. Although many of these
treatment procedures could be applied to abandoned mines the matter of financing
might be prohibitive. Many authors [113,114,124,186,130,136] therefore advocate
the incorporation of reclamation programs as a means of healing the scarred lands.
Many reclamation techniques would also classify as preventive measures; but irregard-
less of categorization, tasks including construction of diversion ditches that reroute
mine drainage, sealing of abandoned mines, mine flushing to protect against subsidence
control of underground mine fires, extinguishment of burning refuse banks, and filling
grading and replanting strip mined lands are now considered to be integral parts of
state pollution abatement and control programs.
Based on 80% reduction of acid pollution from active and inactive mines, FWQA, two
years ago, placed a $3 billion price tag on nation wide control programs. Now, how-1
ever, FWQA feels that to meet most of the water quality objectives being proposed,
95% reduction is necessary and the cost of control programs may reach $7 billion
[112], This figure does not appear unreasonable in light ot the tremendous emphasis
placed upon finding solutions to the acid mine drainage problem. At this point it should
be clear that while only a few control measures are in use, many possible methods exist
and are presently being studied. Many mine drainage treatment facilities not mentioned
in this paper are in operation, but most, if not all, are modifications of the general
types described.
The characteristics peculiar to a particular drainage problem determine the type of treat-
ment most feasible for that problem. An infinite number of different problems may exist
and the solution to each problem may lie in the myriad of existing treatment modifica-
tions or in a completely different process. At any rate, the acid mine drainage problem
is complex, and because the different encounters are so numerous and the situation is
so acute, the astronomical price tag is justifiable.
-138-
-------
SECTION IX
PROCESSING
A. Coal Washing and Cleaning
Major pollution problems associated with coal processing originate from coal clean-
ing, the coking process and refuse disposal.
Many millions of tons of coal are mechanically cleaned each year before being sent
to the industrial market. Of this amount 80 to 90 percent are washed with water.
After the washing process, the water has to be rid of coal and waste products for re-
use. It is important to industry that all water be removed from the clean coal because
each percent of moisture left in the coal lowers the heating or Btu value the same as
each percent of ash. Water left on the coal also can cause shipping and handling
troubles. Wet coal has a tendency to stick to bins, chutes, railroad cars and trucks.
Additionally, in cold weather the wet coal will freeze and cause handling problems.
fh,ws, moisture in coal not only reduces the heating value but also increases the cost
pf transportation and handling of the coal. Therefore, the coal-water separation prob-
lem (which involves not only drainage of the water from the coal but also the removal
of moisture) is an important one for the producer as well as the buyer.
For purposes of definition, water in coal may be considered as that water held in the
cpq| by capillary action. Surface moisture may be defined as that attached to the sur-
face of coal particles. Inherent moisture may best be defined as that moisture present
ir,, the coal in the bed. The percent moisture in a particular coal sample describes the
percent loss in weight of the coal sample when the sample is heated in a 110°C oven
for one hour [137] .
When coarse coal, that is coal with particle size greater than 1/4 inch, is in suspension
Jt is easy to perform the coal water separation. The coal may be removed from the water
by perforated bucket elevators or the water may be removed from the coal by passing it
over dewatering screens. In either case water or moisture will remain on the surface of
the coal particles but the amount of surface area on this larger size coal is relatively
small. Therefore, the percent moisture in coarse coal after cleaning and separating is
relatively low. But with fine coal the problem for producers is considerably more dif-
ficult. First, some of the fine coal sizes will pass through the screen or bucket open-
Ings/ thus necessitating more complicated dewatering techniques. Secondly, the amount
of surface area is relatively large and consequently the amount of moisture remaining
on the surface is large per unit weight of coal. Additionally, finer sizes of coal tend
to pack rather tightly, and capillary action tends to hold water in the void spaces be-
tween coal particles. All this contributes to a relatively high percent moisture in fine
coal after cleaning and separating. Table 26 descriptively categorizes coal according
to its moisture content.
-139-
-------
TABLE 26
Coal Categorization According to Moisture Content
% Moisture Description of coal
0~3 Bone dry or dusty
3-6 Wet
6*40 Balled to soupy or sloppy
above 40 A suspension containing
x percent solids
Source: Mechanization,, Vol. 21, No. 9, September, 1957.
Today the utility and steel markets rank as the two most important coal markets account-
ing for more than 250,000,000 tons annually. Unlike the major coal consumers of the
past, these two industries do not demand a coarse product. As a result, fines, which
were considered a nuisance or little more than waste about 20 years ago, are now mar-
ketable. Coal buyers however, are demanding that the quality of the fines be as good
as that of the coarse coal. Also, with the advent of continuous mining and the practice
of full-seam mining, greater demands on cleaning facilities have taken place. These
two developments have contributed to the accelerated growth of fine coal cleaning.
The processes and equipment currently employed in fine coal cleaning and coal-water
separation are described in numerous reports [137,138,139] .
Descriptions of the following processes and equipment are given: wet tables, jig
cleaning, air cleaning, classifier-type cleaners, launders, flotation, dewatering
screens,^thickeners, cyclones, centrifugation, thermal drying, filtration, flocculation
and desliming.
1. Wet Tables [1391
Wet tables have been used for cleaning coal for more than 40 years and are handling
a major portion of the fine coal cleaning today. The main features of a wet table are
its differential motion and the riffled deck with water flowing across it. The differ-
ential motion provides a side ways conveying action along the fitted deck and the
water imparts a downward motion on the sloped surface. Wet tables yield excellent
cleaning results.
2. Jig_Washing H39)
Jigging is one of the oldest washing processes and the fig frequently is called the uni-
versal washer. In the conventional Baun jig for coarser coal, the entire bed moves
-MO-
-------
horizontally over a perforated plate to the end of the washing compartment. At this
point stratification has been accomplished and a separation is made by cutting the
bed at the proper level to obtain the desired clean product at the top and refuse at
the bottom. The fine-coal jig removes refuse in a different manner. Refuse is passed
downward through the screen plate on which the permanent bedding material is retained.
3. Air Cleaning [139]
The same principles apply for air cleaning as in wet units. An advantage cited for air
cleaning is the elimination of the need for drying, thickening, and water clarification.
But dust may become a problem, and some method of keeping fine dust from the atmos-
phere must be considered in designing an air plant. Most air methods rely on an up-
ward current of air traveling through the bed to get the necessary mobility for proper
classification. They differ, however, in methods of applying air and in the method of
removing refuse. Air devices usually are grouped into jigs, tables or launders. Some
units incorporate features from one or more of these groups. Jigs use a pulsated air
current. Tables employ riffles attached to the deck to divert refuse from the direction
of flow of the clean coal. In launders, clean coal and refuse flow in the same direc-
tion with the clean coal being skimmed off the top and refuse removed from the bottom
Jn several cuts. A two staged air cleaning plant process is shown in Figure 21.
4. Classifier-Type Cleaners [139]
Classifier-type coal washes, both for coarse and fine coal, were first used in the an-
thracite region of Pennsylvania. From there use spread to the bituminous fields. Types
include the hydroseparator (upward current) and hindered units such as the hydrotator.
The principle features of the hydrotator are a revolving agitator with four or more arms,
each having downward inclined nozzles. Water flows out the nozzles and strikes the
bottom of the tank and deflects upward. Water is pumped from the upper level of the
tank back through the agitator. Fine coal feeds continuously into the top of the ves-
sel. Some particles go into suspension immediately and are circulated to form a medi-
um which makes possible the separation of the larger sizes.
5. Launders [139]
Launders employ a flowing current of water in a channel to accomplish separation of
coal and refuse. Bed density increases from top to bottom and refuse it is drawn off the
bottom of the flowing stream. A fine coal launder differs from a coarse-coal one in
the number and type of boxes used. For example, a fine-coal system may employ as
,nany as six units arranged one below the other. Discharge from the boxes of one
launder falls directly into the launder below (Figure 22).
6. Flotation [139]
plotation is the opposite of sedimentation, but the same laws apply. As the term is
used in coal treatment it implies the raising of suspended solids to the surface of a tank
-141-
-------
16'BELT (BREAKER
SECONDARY REJECT)
I2'XI2' HOPPER (REJECT)
ItfX 20 DOUBLE
HOPPER
12)30" FEEDERS
f- 52" SCREEN 8
PICKING TABLE
20"X 40* SINGLE-ROLL
CRUSHER
RAW COAL
CLEAN COAL
REJECT
MIDDLINGS
2«" BELT
(TRANSFER POINT
TO CLEANER
SURGE BINS)
24-BELT (3/4 MINUS
TO TRANSFER POINT)
28" Cf CONVEYOR
(BREAKER 8 SCREEI*
UlXDERSIZE)
52 XI2' SCREEN
13/4'OPENING!
18" X 40" DOUBLE-
ROLL CRUSHER
\
42"X6'SCREEN
(2" OPENING)
36" RAW COAL BELT
IB BELT (RE-CIRCULATING CONV.)
9X12' ROTARY BREAKER
12 C F CONVEYOR
(SECONDARY REJECT)
\ 24" BELT CONV
DUST-COLLECTING SYSTEM xCLEAN COAL
FOR PRIMARY AIR CLEANERS
18'BELT (SECONDARY
MIDDLINGSI-
30" BELT
(CLEAN COAL
TO CAR]
DUST COLLECTING
SYSTEM FOR
SECONDARY CLEANER
10' X 20' DOUBLE HOPPER
(CLEANER SURGE)
10 X 10 HOPPER
(SECONDARY SURGE)
16" BELT
[REJECT!
PRIMARY AIR CLEANERS
BUCKET ELEVATOR
(REJECT)
I2'XI2' HOPPER (SECONDARY
MIDDLINGS)
SECONDARY
AIR CLEANER
1-
J-
FIGURE 21. SCHEMATIC OF A TWO STAGE AIR CLEANING PROCESS. [139]
-------
I
CO
Thickener
To impounding
bo»in ^f—]
5" pump
VizXO
No. 4 launder
1
Glorified
water to
creek
FIGURE 22. FINE COAL LAUNDER. [139]
Conveyor
To bin
-------
by use of chemicals. Flotation is used for the recovery of ultra fines, which in the
past were discarded as waste, (Figure 23). The Following are a number of reasons
flotation has come Into use.
1. The drive for clean streams requires the removal of extreme fines formerly
bled into streams.
2. More grinding at the preparation plant is necessary to liberate pyrite which
', then can be removed by flotation.
3. The possibility of new coal pipelines being laid to power plants requires fine
sizes which are readily handled by flotation.
4. The desire by producers to increase profits by recovering a maximum of the
coal brought to the plant.
7. Dewatering Screens [1371
Removing water from fine coal is a major problem and must be considered an individual
problem for each plant. Several different types of dewatering screens are used in coal
processing. One type is a high speed, small amplitude, vibrating screen. The screen-
ing surfaces are either parallel rods or punched plates. A material balance flowsheet
for a typical dewatering operation on a vibrating screen is shown in Figure 24.
A second type of screen used for dewatering is a V-screen. The wet coal is fed into
a vaned-disc feed-distributing plate located at the top of the drum and rotated in uni-
son with the drum. The material is dispersed outward to the top of the inside of the
screening cloth attached to the drum. The high speed gyration and rotation (having
an acceleration of approximately "5 g's") throws the water through the screen.
A third type of dewatering screen is the stationary DSM screen. Feed slurry enters
the top of the unit and is distributed by a feed box over the width of the screen. The
pulp flows down by gravity over a curved portion of the screen equipped with a parallel
rod surface with rods running perpendicular to the flow of the pulp. Overflow material
slides off the bottom of the screen and the underflow suspension passes through the
screen and is discharged from the back of the unit.
8. Thickeners
Thickeners are generally used for the removal of a portion of the water from a suspen-
sion having a relatively low percent solids. This separation makes it technically pos-
sible, and economically feasible, to make a more efficient separation in other equip-
ment, such as filters. A material balance flowsheet for a typical thickener operation
is shown in Figure 25.
The percent solids In the feed pulp seldom exceed 15 to 20 percent. The feed pulp is
discharged into the center of a circular tank. During the period of containment the
solids settle to the bottom of the tank and are removed in the form of a slurry or sludge
by rakes and/or scrapers. The solid-free water overflows the periphery of the tank and
-144-
-------
ISO-TON
RAW COAL
FEEDER
4-SCALPINC.
I SCREENS \ CLEfN c
I2-ROU6HER
FROTH
FLOTATION
CELLS
CENTR. DRIED COAL CONVEYOR
1
••
1
r~7 t^
I/FURNACE
FdESJTli
HOPPER WATER
_
— ^^
•^TT" THICKENER
noIL-
n
-^THICKENER OVERFLOI SUMP
^ *1
> noiFn rnn rn riR<^ IIH tn BFFIKF
FLOOR
SUMP
TO REFUSE
BIN
COARSE COAL
'DEGRADATION
FIGURE 23. FLOW DIAGRAM CF ULTRA FINES RECOVERY BY FLOTATION. f!39|
-145-
-------
FINE CLEAN COAL
Suspension from
Concentrating Table
160 tph solids
3600 gpm water
18% solids
Size—3/16" xO
&
UNDERFLOW
SUSPENSION
60 tph solids
351 2 gpm water
6.4% solids
Size—10M xO
OVERFLOW
PRODUCT
Sire 3/16" x 1OM
100 tph solids
22% moisture
or
88 gpm water
FIGURE 24. FLOWSHEET OF A DEWATERING OPERATION
ON A VIBRATING SCREEN. [137]
-------
FEED PULP
50.0 tph solids
2800 gpm water
7.0% solids
SIZE ANALYSIS
+ 28
28x48
48x100
100x200
200x325
—325
— 4.5%
—13.5%
—20.4 %
—22.6%
— 12.0%
—27.0%
120FT THICKENER
FIGURE 25.
UNDERFLOW
45.0 tph solids
300 gpm water
38.0% solids
- 5.0%
-15.0%
-22.7%
-24.5%
-10.0%
OVERFLOW
5.0 tph solids
2500 gpm water
0.8% solids
+28
28x48
48x100
100x200
200x325
—325
+ 28
28x48
48 x 100
100x200
200x 325
—325 —22.8%
MATERIALS BALANCE FLOWSHEET OF A
THICKENING OPERATION. [137]
— 0.0%
— 0.0%
— 0.0%
— 5.2%
—30.1%
—64.7%
-------
is recirculated through the plant. In many cases, however, the overflow water con-
tains some extreme fines too small to settle. This pulp must be sent to settling pond to
allow more time for settling.
9. Cyclones [137]
Cyclones serve the same purpose as thickeners in coal-water separation. Both cyclones
and thickeners reduce a pulp with a low percentage of solids to a relatively thick sus-
pension by removing some of the water. In addition, cyclones also remove high ash
slimes from the fine coal (Figure 26). The cyclone is a cylindro-conical vessel with
the cylindrical portion above the cone. Feed enters the cylindrical section tangen-
tially and spins around in the unit. Because of the spinning, centrifugal forces throw
the solids to the outer edge from which they slide down into the conical section and are
discharged as a thick slurry through a nozzle at the apex of the cone. The water and
slimes in the center of the cylinder and cone are discharged through an overflow noz-
zle at the top.
10. Centrifuges [137]
Centrifuges are mechanical devices which use strong centrifugal force to dewater fine
coal products from primary dewatering units. The feed to centrifuges is a product con-
taining some percent moisture content as a result of some limited type of coal water
separator. The objective in centrifuging is to squeeze out additional moisture to ob-
tain a dryer product. There are many types of centrifuges. A flowsheet of the rotat-
ing drum centrifuge is shown in Figure 27.
11. Thermal Dryers
Thermal dryers are used to obtain the maximum amount of surface-moisture reduction in
coal. The dryers operate by bringing heated air in contact with the wet coal and there-
by evaporate the moisture from the surface of the coal. This must be done carefully so
that the coal does not catch fire or lose volatile matter.
12. Filtration [137,138]
Filters take a suspension with a high percentage of solids and separate the water to pro-
duce a compact wet cake of coal solids. This process is performed by placing a filter
with a cloth or screen surface in the suspension and having a suction or less than atmos-
pheric pressure behind the surface so that the water and solids are drawn into the fil-
ter. The solids are trapped on the surface; the water is drawn through the filter and
separated from the solids. The solids trapped on the filtering surface are removed from
the suspension as a cake and air is drawn through them into the filter to remove as much
of the surface moisture as possible. To complete the continuous cycle the air pressure
in the filter is increased to greater than atmospheric. The solids are blown from the
surface of the filter before they re-enter the suspension.
-148-
-------
FIGURE 26. DESLIMING RAW AND CLEAN COAL USING CYCLONES. [137]
-149-
-------
Cn
o
I
CYCLONE UNDER-
FLOW FEED
63 tph dry solids
507.gpm water
33% solids
SIZE OF SOLIDS
4x 16M
16x30M
30 x 50M
50 x100M
100x200M
200x325M
—325M
Ash in solids
FILTER CAKE
60.0 tph -dry solids
14% surface moisture
SIZE OF SOLIDS
4 x 16M
16x30M
30x50M
50 x100M
100x200M
200 > 325M
—325M
Ash in solids
— 16.9%
— 26.3%
— 19.6%
— 17.5%
— 8.9%
— 3.7%
— 7.1%
— 7.0%
FILTRATE
468 gpm water
3 tph dry solids
2.5% solids
SIZE OF SOLIDS
30 x 50M
50xlOOM
lOOx 200M
200x325M
—325M
Ash in solids
— 0.2%
— 18.8%
—10.5%
— 11.4%
—59.3%
— 18.2%
FIGURE 27. FLOWSHEET OF A ROTATING DRUM CENTRIFUGE. fl37l
-------
There are many different arrangements for filtering operations. A material balance
flowsheet for typical filtering operations is shown in Figure 28. The filtration tech-
nique described represents vacuum filtration. Pressure filtration is another type of
filtration. It is used because tailings, clays and some slurries of very fine size give
difficulty in vacuum filtration.
13. Flocculation [139]
All slurries are not readily filterable or can be filtered only at a slow rate. In some
instances these difficult slurries can be made filterable by flocculation. Flocculation
is the process of agglomerating extremely small particles or colloids into larger sizes,
thus making a larger effective size for settling and filtering. For many years starch,
lime, and alum have been used to speed settling in thickeners and acids in filtering.
In recent years a number of new synthetic flocculants have become available. These
new products are reported to be more versatile in that they continue to give good
flocculation as the solids content increases.
14. Desliming [139]
Slime is a suspension containing 50% or more minus 200 M material the removal of
which is desirable in order to aid in pollution prevention, as well as to prevent loss
of equipment capacity. A common method of removing slime is by the use of classifier
water cleaners. The sludge pond, however, is probably the most widely used method
for slime disposal. The skjdge pond is very economical if it does not have to be clean-
ed out or if suitable land is available. Before going to the pond, usually the slurry
will pass through a classifier device which makes possible recovery of larger coal
particles. A disadvantage of using sludge ponds for desliming is their large make-up-
water requirements. Furthermore, pollution problems may be encountered if solids
settle slowly or if rainfall is heavy.
B. Water Handling [139]
Water handling is important in wet washing plants from the standpoint of providing
satisfactory fresh supply and clarifying the water for recirculation. Two problems in
water handling are:
1. Obtaining a reliable source of suitable water.
2. Reclaiming dirty water from the system, and reprocessing it for recirculation.
Sources of fresh water are: man-made lakes, deep wells, streams, and mine water
which may be available in sufficient quantity and be of satisfactory quality to meet
plant needs. One company pumps plant bleed into an abandoned mine section where
solids settle out leaving clarified water available for make up water. A fire clay bottom
neutralizes acidity the water may have gained in the plant circuit. This system also
eliminates the cost of building and maintaining settling ponds.
-151-
-------
Oi
K)
EFFLUENT
31.7 tph total
17.3 tph dry solids
14.4 tph water
57.6 gpm water
54% solids
SIZE
— 0.0%
— 0.0%
— 0.0%
—61.7%
—21.2%
— 7.0%
—10.0%
X a
V8"xl4M
14x48M
48x 100M
100 x 200M
—200M
FEED COAL
75.0 tph wet solids
57.8 tph dry solids
17.2 tph water
22.9% moisture
SIZE
y8"x!4M
14 x 48M
48xlOOM
100x200M
—200M
FIGURE 28.
DRIED COAL
43.3 tph product
40.5 tph dry solids
2.8 tph water
6.6% moisture
MATERIALS BALANCE FLOWSHEET FOR A
TYPICAL CENTRIFUGING OPERATION. [!37l
- 0.4%
-21.1%
-34.1%
-34.4%
- 6.5%
- 1.6%
- 1.9%
SIZE
Vi" x '/4M
14 x 48M
48 x 100M
100x200M
— 200M
— 0.2%
— 16.9%
—39.6%
—33.7%
— 5.7%
— 1.8%
— 2.1%
-------
C. Water Clarification [139]
Activity and interest have increased in the processing of waste water. This is the
result of stream pollution regulation and the coal industry1 s desire to recover coal
formerly lost to refuse and the need to prevent solid build up in the washing circuit.
Closed water circuits have grown in popularity and are usually the goal in water-
clarification circuits. Since closing the circuit results in the build up of slimes, it
is necessary to remove a certain portion of these fine solids. Flow diagrams of various
methods of water clarification are shown in Figures 29, 30", and 31.
D. Coking [140]
Coke is made by the distinctive distillation of coal in the absence of air. The coal
Is carbonized in silica brick ovens by being heated to approximately 2000°F. The
bituminous coal charged contains surface water and water of combination. In the cok-
ing process this water is evaporated and then condensed along with tar vapor as the
gas is cooled. The water is then separated from the tar in continuous decanters. A
typical coking plant may produce about 75,000 gpd of this type of water which is
called ammonia liquor. This liquor, by volume, is the second largest product from
the coking operation. The chemical analysis of the ammonia liquor can vary consider-
ably; however, a typical analysis is as follows:
PH 8.8
COD 3400 mg/l
Total ammonia 2010 mg/l
Thiocyanate & cyanide (CMS) 185 mg/l
Total phenols 1100 mg/l
Monohydric phenols 750 mg/|
The phenols present in this liquor constitute a real threat to water purity, due to the
objectionable odor and taste they impart to water even when present in very minute
quantities. Therefore, phenols are the most objectionable constituent of coke plant
wastewater. The largest concentrations of phenolic wastes from the coking operation
originates in the condensate from gas coolers. But, smaller amounts come from light
oil decanters and from miscellaneous minor sources. Steel plants have constructed
dephenolizing units for the removal and recovery of most of the phenols. Usually
however, only the ammonia still influent or discharge is treated.
In 1957, R. Nebolsine [141] reviewed the various methods of phenol-water separation
He also gave some typical figures for the amounts and concentrations of various phenolfc
compounds that must be given treatment. Nebolsine states:
••The total amount of phenols in the discharges from a coke plant (ahead of dephenol-
izing) is usually between 1/4 and 1/2 Ib per ton of coal carbonized. The total amount
of phenol-carrymg water discharged may be in the order of 35 to 50 gallons per ton of
coal. Approximately half of this is the condensate from the gas coolers. Representative
-153-
-------
5" or 8"
cyclone
V
24"or 28
cyclone
Possible I
f t filter I
MoKeup Coal
water or ref.
I
i
t
Makeup
water
Coal
or ref.
Recirc.
I
I
I
t
Recirc.
I I
Possible
filter
I
I
I
t
Ref.
FLOCWUTIW
"tm"~ LJ
-FINE-COAL
SLURRT
no FIHE-
COAL FILTfR
1
VACUUM
FILTER
CLEAR MATER
TO PLAHT
Ciatiificotion at 30 micr«nt
Apprldobli + 30-mieron
moitnol in overflow
+ 30-micron moltrial rtmovttf
by eycloni*
FIGURE 29.
FLOW DIAGRAMS OF TYPICAL WATER CLARIFICATION METHODS. [1391
-154-
-------
,0»Elf 10! CEHEUU1 jniUW CEIEIAUT
/ -» TO-411 SOUK ,'' -IMKmiOS
,.,,,,.. OYEIFLO! TO
J CTCLMES IECIIMLATIOI 01
SLUDGE LACOON,
CEIEIALU -ZOO
N SOLIDS
THlOLEHfO
WDEKFLOf
I
TMICIEIfO
IMKIFIOI
i
IILTIATE TO
lECUCULATKM
CAIE TO
FWDDCT.
•ILEIOED
mm
COAISEI-
COAL
flLTEt
_'.'liit.*5t10? ^ loisiuit
~* \ ^""" ,X-"'r "f vT~
( r— ^UCIClllll£S f|E
i. LlMtM i '
« V—^-Jl f|°»
lq?a"y ""'
!- t ?'JJJ B! umfitt
IS ;i(™' el «« I/
.<.j.-k"j' »"«"r"E'
'"';" j WATER
i i PURIFICATION
• II,K ""
rilir-, »»«isoi
' 'I .' I rm
t r1-) «HB.,
L_W Lhe-V
niW SI««« ib,—...—
,... i... i«;'»
fLOCCUL JTION
T£
!I[W
1IJEI
ru«f
H—
ufsurni
TO
Oiimicn
*r|Ki"
lu^u^ ^^X
._; [2Ha»_^ lUJprr:......^.^^j
THICKENER
o»ni«i
fun
OVEIFLOHS CflEIALLT
-tt TO -41 N SOLIDS
i. N oi a*
CTtlDHi
-100*
OYflfLCI TO
«ECIICUL»TiO«
01 SUKE UUO*
FIITHFE TO
IECIICUUII
OVEIfLOf CEIEIALLT
,' -It TO-4I«
' SOLIDS
I FIIE-OML 1 ' i
1 DIM TAH | 0««fLO» tO lECIICULATlOII
. MiniTiHr |— •• »' SLU06E l»WO»S- GEKEIALLT
Mfii\^*?r?M W -ZOOM SCUDS
1 wLAd^l' ItK vR 1^^^^^_
1 "leinii 1
{ THIMEJEt P^P
Ul'oVifLOl ~S
fILIUTE 10 .
lECIMULMlOlt
fer-.
^>C ^XCAIE TO F«OUCT
^T MW *lll(
mni »«i«»«.
mm
5-6% moijlur*
filter
FIGURE 30. FLOW DIAGRAMS OF TYPICAL WATER CLARIFICATION METHODS. [139]
-155-
-------
FROM RHEO !
*
A S > LAUNDER C IAL
IOMESH VII SCREEN (K1H
1 TORI
UMDER7RODUC 1 OVERFOOOl
BOOT— - OVERFLOW
UNBEHIOW TO ICC « SUMP
48 MESH Vl> SCREEN
UNDER OVE«P8OOUCT
REFSUUP — -. J"^
V \ \ CENTH
UNDO OVEI \ |
1 * \ con
KfUSE IKtt \ \
OISP ySUMf \ l|
/ t \CA«5
1 RXEO \
1 HEAD v-
I IANK
* » t '
INDER 0 LAUNDER FflOM TABLE PLANT FROM HYDROli
f 1 i -P..'-.
CUUftP • 1 VIB- SCREEN (1 =™)
^WCOAL ff 1 1
001 DUG FRO TANK oviRp,iDUC, ^JpjODUC ,
«r I | I I
OVEKFLOW in^DEit | |
.TOJOANT
r 0v«fflow
TOKCIft J B«CA«S L
*"W C LWJNDIH «,. mjcJENQ,
UNDEVLOW OVEBFLOW.
M
Fusl -an? '
«f" 7 isisra
SUJAP PUMP HfAO CANK
1 X 10 SILT MAKE UP
OVEI UNDEI /OMIJ WAnR
visuroi
UNDfl OVit
(• FINE COAL IN WAni 1USPCNSION
=
u
FROM COAL WASHING TABLE PLANT
SCUENED AT 14 MESH
3VERPBOOUCT UNCEP.PtODUCT
20" CYC LOME J
OVEOT.OW UNDERFLOW
10- CYCLONES 1 PLAfJTBffUSE
^ j SCREENED AT ffl MESH
OVERFLOW UNDERFLOW 1 f
I UNDfiFtOOUCI
DBUMflirER
| ^ OVERPeOOUCT
COAL LfFLUINT
T
A6S 2 - CAU5TK STARCH THFCKF^ERS "*~~^
OVEKFLOW UNDEIFLOW
J FINE COAL IN WATER SUSPENSION
FROM CONCENTRATING TABLES
SETTLING IANK
UNDERFLOW OVERFLOW
( |f- OVfJFLOW-
CENRIFUG! THICrCNU
J L» EFFLUENI —/f-
DBYER
UNDERFLOW
I
FILTEB -~ FILTRATE —|
RECIRCIAAT1ON WAFER
FINE COAL IN WATER SUSPENSION
1/4-« a MESH
FIOM TABLES
l/4nmVl:
OVE«PROPUCT
CENTRIFUGE
I3IAIOI SCREEN
LNOEHPOROUCT
- I 1/4 WNO
CRUSHED PLANT
REFUSE AND SPILL
WAIC1
Sflf , 0 COAL
FROMRHCOFLANI
CLEAN COAL ROOT
I I
UNCEIFLOW OVERFLOW
1/4 rrm VIBRA FOR DIRTY WATER
I | HEAD TANK
OVERFRODUCT UNOERFRODUCT I
4
PtANT E£FLR£
PUMP . $UMP
IETTUNO POND
V-SCREEN CENTRIFUGES
EFFLUENf COAL
« H
COAL
FOR RECIRCUIAHON
OR DISPOSAL
RRCARS
HEAD TANK AND
JIG MAKE UP WATER
F-INI COAL IN VJATEA SUSPENSION
• OlAO SETT
OVERFLOW UNOEtflOW
CVCLONli
OVERFLOW UNDERFLOW
FROM TABLE KANT
COAL REFUSE
LING TANK VIBRATOR SCREE N
VltRATI
I OVERPRODUCT .
UNDERPIOOUCT
CENTRIFUGES
I t
-EFRU6NI COAL
SUtGt 9IN
FUUHMYEI
COAL EXHAUST
RRCAU
\/4-.
JCG PRCtOUCTS
I \-
COAL.
SUSPENSION
SIWWE TAMK M1DDUMO SUMP
II I
OVERFLOW UNDERFLOW HECIBCUUTED
J TO JIG
MJXING TANK
CENTSIFUCE
1 I
EfFLIJENT
EFFLUENI TANK
tor Krawi ^rar
TYPICAL COAL-WATER
SEPARATION FLOWSHEETS
FIGURE 31. FLOW DIAGRAM OF TYPICAL WATER CLARIFICATION
METHODS. [139]
-156-
-------
concentrations of phenol in this effluent may be from 1000 to 2000 ppm. In the dis-
charge from the light oil decanters, the concentrations may be 50 to 150 ppm and 10
to 50 ppm in the effluents from miscellaneous sources."
If we assume that most fair-sized coke plants will use new efficient dephenolizers, and
that these will remove 95 to 99 percent of the phenol in the gas cooling condensate,
and then add the discharge from the light oil decanters (without passing it through a
dephenolizer), according to Nebolsine the combined effluent from the coke plant that
may have to receive secondary treatment would have the characteristics given in Table
27.
TABLE 27
Representative Influents of Phenol-Carrying Wastes to Secondary
Treatment Plants
(assuming average concentration of phenol of 100 ppm)
Size of coking Phenol to
plant, tons of Discharge be treated,
coal per day in gpm Ibs per day
1000 25 30
2000 50 60
4000 100 120
8000 200 240
Source: Iron and Steel Engineering, Vol. 34, Dec. 1957. (141]
Industry has contributed two types of extractive dephenolizers. One is based on liquid
to liquid contact and the other is based on vapor recirculation.
Up to 98 or 99 percent of the phenols can be removed by the latest liquid extraction
processes. In order to extract the phenol, these liquid to liquid dephenolizers use a
solvent which is passed counter-currently through a tower, or a centrifugal extractor,
with the waste. The phenol is stripped from the solvent by caustic, yielding a con-
densate consisting of crude sodium phenolate. Furthermore, the phenolafe may be
treated by an outside refinery for production of phenol.
-157-
-------
The vapor recircu lotion process, which is becoming less common works as follows:
while no solvents are used m the process, the waste steam, and caustic are brought
into intimate contact. The caustic strips the phenols from the waste and, in turn, the
phenol may be recovered. However, with this method the removal of phenols may
average less than 90 percent. These processes are not self-supporting because sodium
phenolate brings only ten to fifteen cents per gallon, and this does not begin to meet
fixed and operating costs.
A dephenolizer cannot by itself reduce the phenolic concentrations enough to satisfy
some of the antipollution requirements now in effect. However, dephenolizers are a
valuable and, in some cases, an essential means of greatly reducing the phenolic
waste load for secondary treatment facilities. Therefore, it is appropriate that at many
coke plants dephenolizers should precede other treatment forms. Other forms of phenolic
waste treatment are as follows:
1. Disposal by Dilution
The phenolic wastes are mixed with other effluents and the combined waste is then dis-
charged into a body of water large enough to reduce the phenolic concentration to an
acceptable level. Usually this can be contemplated only after installing a dephenolizer
or some other process, to intercept the bulk of the phenol produced.
2. Closed Systems and Evaporation in the Quenching Station
In some coke plants the effluent from a dephenolizer and other phenol carrying discharges
enter a closed system and are consumed by, or vaporized and mixed with, the gases pro-
duced m the quenching of coke. However, this process results in a certain amount of
atmosphere pollution. This atmospheric pollution, due to the calcium chlorides that
are also vaporized in the process, accelerates corrosion on all exposed metals in the
vicinity.
3. Chemical Treatment
Phenols can be neutralized by using chlorine, chlorine dioxide and ozone as oxidizinq
agents. ^ All three chemicals will produce good results in the initial reduction of phenols
but getting rid of the last bit of phenols is like squeezing the last drop of toothpaste '
out of the tube-there always seems to be some left. Chemical treatment is expensive
For small quantities of waste it may be economical, but for larger quantities requiring '
yy% removal it has not so far been found practical.
4. Biological Treatment
Biological treatment consists of feeding the phenolic wastes to active bacteria. The
L^tr-'Q| U$e thC phenols for food and thereby oxidize them into inoffensive byproducts
This biological oxidation must take place in the proper environment—temperature, PH'
-158-
-------
nutrient supply, etc. This process can be carried out by several methods, including
trickling filters and activated sludge. The trickling filter has bacteria living on the
surface of stones or other media in a bed. The waste is distributed over the media and
as the waste passes by, the bacteria absorbs the phenols and other pollutant matter. In
the activated sludge process, bacteria are suspended in the liquid contents of a tank.
The bacteria's growth and feeding on the phenols is stimulated by blowing large vol-
umes of air through the liquid. In both processes, auxiliary operations such as chem-
ically conditioning the inflow supplying nutrients and back feeding the sludge are in-
volved. Bio-oxidation, although not cheap or simple, generally costs less than chem-
ical oxidation. Also, bio-oxidation gives a high degree of phenol reduction.
5. Adsorption by Activated Carbon
This process requires mixing a quantity of graded activated carbon with the phenol
carrying wastes and maintaining contact for some time. The carbon particles are then
separated from the liquid with the use of flotation equipment. Filtering the waste
through a bed of activated carbon is another method. In both methods, however the
spent carbon must be replaced or reactivated. By selecting the proper activated car-
bon phenol ratio and contact time, almost any degree of phenol removal can be obtained.
6. Treating Phenolic Wastes in Municipal Sewage Treatment Plant
Several years ago a test was run to determine the feasibility of treating ammonia still
wastes together with domestic sewage. In this test the Gary Coke Works of the United
States Steel Corporation used the City of Gary, Indiana's municipal sewage treatment
facilities. The presence of the stitl wastes in the sewage did not, over the six month
period of the test, interfere with the normal operating efficiency of the plant. During
the test, some days the phenol loading was as much as 2000 Ibs. with a 9 to 1 dilution
factor. After treatment by dilution and activated sludge 99.7 percent of the phenol
was removed, yielding an average phenol concentration in the effluent of 5 ppb.
7. Mult!-Stage Process
Combinations of the aforementioned processes can be used. Flow diagrams of several
possible multi-stage methods for removal of phenol may be seen in Figure 32.
The new and improved dephenolizers offer an effective method to knock out the bulk of
the phenols produced in coke plants. However, secondary treatment (multi-stage pro-
cessing) may be necessary to produce phenol concentration of ten to twenty ppm. Since
1957 more efficient dephenolizers have been developed and produced [142] . Addi-
tionally, the treatment of the ammonia liquor solely by biological means has been tested
and even put into use.
F. C. Lauer, E. J. Littlewood, and J. J. Butler [142] described the development of a
more efficient phenol removal plant as follows:
-159-
-------
LEGEND:
G.C.C. - Gas cooler condensate
L.O.D. - Light oil decanter
M. - Miscellaneous DEPHT"""—I
DEPH. - Dephenolyzer ^ i '
CHEM. - Chemical oxidation AMM. f
BIOL. - Biological oxidation STILL _[_
i
I j
u
]
1
1
I
).D. II
i
• — ' — • ~ — - — • -
/I. (
DEPH
AMM.
STILL
3.C.C.
y,
i — i
L.O.D. N
I
•^™^-— -^— •-
^^-^^— "
GC.C.
AMM
STILL
V
L.0.0
M.
CHEM
OR
BIOL.
G.C.C.
AMM. 1 _
STILL [ 1
L.0.0.
STOP.
lflST. CHEM.-BIOL
Z'-STCHEM-BIO.
FIGURE 32. FLOWSHEETS SHOW VARIOUS POSSIBLE METHODS
FOR REMOVING PHENOL. [141]
-------
In 1955, the Pittsburgh Works was faced with the prospect of replacing the existing
vapor recirculation, phenols removal, plant. The decision was made to evaluate any
and all tar acid removal processes then in existence, and go even beyond existing
processes in search of new solvents. The primary product requisites of the phenols
removal process desired for Pittsburg works were:
1. A phenol removal efficiency greater than 99 percent.
2. Recovery of the phenols directly in the form of a crude tar acid for sale.
A research program was initiated to develop a technique for dephenolization. The first
step was the selection of a solvent. Criteria used as guidelines in the selection of a
solvent were:
1. Low solubility
2. Limited volatility
3. Low cost
4. Significant density differential between waste and solvent
5. High distribution coefficient
6. Low freezing point
7. Minor degradation during distillation
8. Ease of solvent regeneration.
After the selection of a solvent, the next step was design, construction and operation
of a pilot plant with the following objectives:
1. To determine the quantity of phenols removable from ammonia liquor and/or
final cooler water by extraction using the selected organic solvent.
2. To determine and reduce the losses of solvent incurred during the extraction
and subsequent recovery of process streams.
3. To provide a sufficient quantity of crude tar acids to ascertain their value
and disposition.
4. To simulate commerical operation over an extended period, establish suitable
materials of construction, and determine and eliminate process difficulties
encountered.
5. To provide data for a firm process economic evaluation and commercial scale-
up.
Upon successful completion of the pilot plant, construction of the actual plant began in
mid-1961 and operations began at the end of October the same year. Figure 33 is a
flow diagram of the plant. Ammonia liquor is pumped from the ammonia still to the
surge tank, which serves to trap some suspended solids and can be by-passed for periodic
cleaning. The liquor is then pumped to the top of the extraction column where, as it
descends the column, it comes into counter-current contact with the solvent as it rises
up through the column. The raffinate is fed to the solvent stripping column where the
dissolved solvent is removed from the dephenolized liquor by steam distillation. The
-161-
-------
LEGEND
RAFFINATE
CRUDE TAR ACID
SOLVENT
WATER
IS)
I
FEED FROM
NH3 STILL—i
SURGE TANK
F-l
EXTRACTION
-| CONDENSER
SOLVEN
PUMPING
TANK
CRUDE TAR
ACID
RECYCLE SOLVENT
SOLVENT
STRIPPING
COLUMN
RAFFINATE
DEPHENOLIZED
LIQUOR
FIGURE 33. FLOW DIAGRAM OF A DEPHENOLIZATION
PLANT. [142]
-------
product from the solvent stripping column, after condensing, goes to one section of
the solvent pumping tank where the water is separated from it and pumped back to the
solvent stripping column. The solvent recovered here is ready for recirculation to the
extractor. The extract flows from the top of the extractor to the solvent recovery
column through a control valve, which maintains a constant interface level between
extract and liquor at the top of the extractor. In the solvent recovery column, a
separation is made between the solvent and crude tar acids in the extract. The over-
head product after condensing goes to the solvent pumping tank, and from there is
pumped back to the extractor as recycle solvent with a side stream to the solvent re-
covery column as reflux. The solvent recovery column bottoms are pumped to the
crude tar acids column in which, under vacuum, the solvent content of the crude tar
acids is reduced to less than 1 percent. The overhead product is, after condensing,
returned to the solvent recovery column with a side stream to the crude tar acids still
as reflux [142] .
After debugging the new plant has performed as illustrated in the following chart.
Item Flow, gpm
NHo liquor 180
Final cooler H^O 20
Total to extractor 200
Item Analyses
Phenols in NHo liquor 2000 ppm
Phenols in feed to extractor 1500 ppm
Phenols in dephenolized waste 1 to 4 ppm
Salable tar acids in product 82 percent
Solvent content of product 1 percent
Philip S. Savage [143] described another solution tosome of the waste problems of a chem-
ical-type coke plant when he described the Koppers-Loe Process. This process removes
and recovers phenol from crude ammonia liquor and also simultaneously reduces the
phenol in the waste from ammonia stills. From Table 28 it can be seen that this pro-
cess is extremely effective.
8. Koppers-Loe Process [143]
Operation of the Koppers-Loe process consists of the following steps:
1. The phenol-bearing, crude ammonia liquor, after filtering and cooling, passes
through two specially designed highly efficient contact towers in series. Light
oil is pumped counter-currently to the liquor in the contractors, where, due to
the intimate mixing, the phenol is extracted from the liquor by the light oil.
2. The dephenolized liquor flows by gravity to storage tanks and thereafter to the
ammonia stills as feed. After distillation of the ammonia from the feed, the
bottoms are sufficiently low in phenol concentration to be discharged to the
inland waters.
-163-
-------
TABLE 28
Typical Operating Results, Koppers Light Oil Extraction
Dephenolizer Donner-Hanna Coke Corporation
Phenol Content (p.p.m.)
Date
(1957)
Apr. 22
23
24
25
26
Feb. avg.
Mar. avg.
Apr. avg.
Liquid
Treated
(gal/day)
66,000
73,000
82,000
96,000
99,000
87,000
89,000
89,000
Crude
Liquid
1,531
1,589
1,813
1,988
1,804
1,923
1,760
1,693
Treated
Liquid
23
21 -
22
19
23
22
18
24
Phenol
Removed
(Ib/day)
829
943
1,223
1,575
1,469
1,369
1,288
1,235
Removal
(%)
98.5
97.6
98.8
99.0
98.7
98.9
98.9
98.6
s°urce: Sewage and Industry, Vol. 29, PP. 1363-1369, December 1957. [143J
-164-
-------
3. The phenolized light oil from the contact tower is pumped to the top com-
partment of a three-section tower. Here any traces of ammonia liquor en-
trained with the oil are removed by decantation.
4. The decanted light oil flows by gravity through the lower two sections of
this same tower. These sections comprise a multiple contactor for phenol ized
light oil and caustic soda solution in which the phenol content of the light
oil is reacted upon by the caustic soda to form sodium phenolate. The light
oil flow is upwards through each of the two sections, beginning with the bottom
one. At the outlet of the top section, it is sufficiently dephenolized to re-
turn to the light oil circulating tank from which it is pumped to the liquor
contact towers to begin the next phenol absorption cycle.
5. Caustic soda solution is pumped in batches to the two lower sections of the
three-section tower. Step No. 4 indicates that the phenolized light oil
passes upwards through these two batches of caustic in series and that the
reaction produces sodium phenolate. When the; conversion of the lowermost
batch of caustic has reached about 70 percent, the resultant phenolate solu-
tion is transferred to a springing plant to make icrude concentrated tar-acids
or to a concentrator where the excess water and light oil are boiled off be-
fore storing as phenolate. At Donner-Hanna the conversion of caustic to tar
acids is not less than 85 percent at the efficiencies being accomplished. In
the meantime, the caustic soda from the middle compartment is dropped to
the bottom one, and that from the top compartment is dropped to the middle
compartment. A fresh batch of caustic soda solution is pumped into the upper-
most of the three contact compartments from the caustic soda dilution tank
and the cycle is resumed. The towers for contacting the ammonia liquor and
light oil are specially designed units containing multiple trays.
A quick but temporary method was also developed to dispose the phenol wastes. This
quick procedure involves drilling wells down to a strata of salt water and then casing
them off from any fresh water sources. Then the phenol wastes are discharged into the
strata of brackish water. One drawback in this method is that the rock pores eventually
clog.
In May of 1968, J. M. Muller and F. L. Coventry [144] described a test in which
Gary Steel Works Coke Plant, in 1967, had diverted its contaminated ammonia liquor
water to the Gary Sanitary District Sewage Treatment Plant. The purpose of the test
was to determine the degree of degradation of phenols, cyanides, and ammonia that
might be accomplished by biological oxidation at a sewage treatment plant. The test
was also to provide information on the sewage plant operating conditions necessary to.
accomplish the degradation. Normally, the waste ammonia liquor is disposed of in the
quenching system. However, this method contributes to in-plant air pollution and to
corrosion of steel in the vicinity of the quenching operation. The results of the test
were as follows:
-165-
-------
1. Significant quantities of ammonium carbonate in the liquor will combine with
calcium and magnesium ion if present in the sewage to form a precipitate which
will plug up pumps and pipelines. Therefore, it is mandatory that carbonate
ions not be present in waste waters discharged into any system that cannot be
readily cleaned, such as vitreous clay tile sewer systems.
2. The addition of a scale control material did prevent carbonate deposition at
the lift stations during the two and one-quarter months that it was used.
3. The biological-oxidation process can for all practical purposes, eliminate
phenols and cyanides from Coke plant streams.
4. The biological oxidation process has little or no effect on free or fixed am-
monium compounds.
5. With the quantities of ammonia in Gary's Coke Plant ammonia liquor, chlor-
ination of effluent would cost $1900 per million gallons of liquor processed.
In November of 1969, James E. Ludberg and G. Donald Nicks [140] described a new
biological processing plant built at Dominion Foundries and Steel of Hamilton, Ontario.
Figures 34 and 35 show this processing plant which is used without pretreating the am-
monia liquor. Figure 36 shows the concentration of ammonia thiocyanate and phenol in
the diluted feed and discharge effluent.
-166-
-------
L-,
FUTURE
AERATION
TANK I
STORAGE TANK
40' OIA.
AERATION
TANK
INOCULUM
TANK
SWITCH
GEAR
a
PUMP
HOUSE
-20'—
<0
(M
SETTLING TANK
33'-IO"DIA.
-3-8"
161-0*
FIGURE 34. PLOT PLAN OF A BIOLOGICAL
PROCESSING SYSTEM. [140J
-------
V
PHOSPHORIC
AGIO
STORAGE
b
ANTI-FOAM
JNIT
rt±±J~
i
i
i
DILUTED FEED
EFFLUENT SPLITER
BOX
.-ANTI-FOAM
/ UNIT
SLUDGE
RECIRCULATION
PUMP^
r EXCESS SLUDGE (IF FORMED)
DILUTION WATER
UNTREATED
EFFLUENT
SETTLING TANK
TREATED EFLUENT
TAR RETURN
INOCULUM TANK
ELECTRIC
IMMERSON
HEATER
FIGURE 35. FLOW DIAGRAM OF A BIOLOGICAL
PROCESSING SYSTEM. [140]
-------
900
500
5400
_J CL
0^300
OJ
aSzOO
LU
Li-
100
0
I I
J "0
z
UJ
3
u.
u.
25 I 8 15 22 I
JAN I FEBRUARY I
8 15 22 29 5 12 19 26 2
MARCH I APRIL I MAY
FIGURE 36. GRAPHS OF CONCENTRATION OF AMMONIA,
PHENOL AND THIOCYANATE IN DILUTED FEED
AND DISCHARGED EFFLUENT (WEEKLY AVERAGES)
[140]
-169-
-------
SECTION X
UTILIZATION
Because of the combustible nature of coal, it is used primarily to generate heat and
power. Approximately 50% of the coal production in the United States is used for
this purpose. About 20% is carbonized and used in the metallurgical industry, pri-
marily in blast furnaces. Other industries account for 20%. These include all in-
dustrial consumers other than electric power utilities, railroads and coke plants. The
remainder of the annual production falls in the general categories of gasification,
hydrogenation and special products [145] .
Most pollution incident to coal use is air pollution resulting from combustion. This
problem is particularly evident in the power industry where large volumes of coal are
burned. Here sulfur and fly ash are the main pollutants.
In the metallurgical industry, however, air pollution is not considered as great a prob-
lem as water pollution. The two most common water pollutants resulting from coal usage
are ammonical liquor and phenols. Most of the air pollution controls in the power in-
dustry will also apply to the metallurgical industry, but because of different waste
characteristics the polluted water effluents from the industries must be treated by dif-
ferent methods.
In power generation, management has a two fold objective:
1. To generate at the lowest possible costs the required power to meet energy
demands and
2. To minimize the total costs associated with environmental quality control.
The greatest problem in controlling environmental pollutants arises from the contaminants
in flue gas. Waste prevention and disposal costs have been compared with overall power
production costs and indicate the importance of a comprehensive waste management
approach [146] .
A great deal of work has been done by the power industry itself in an attempt to reduce
the environmental contaminants produced by the industry. An effective control program
must begin with strict controls on the quality of fuel used. A fuel coal low in sulfur
and ash content will cause fewer control problems during and after combustion. The use
of solvent refined coal (SRC) has been suggested by Jimeson [147] as a means of pollu-
tion control.
Solvent Refined Coal is reconstituted coal which has been dissolved, filtered, and sepa-
rated from its solvent. It is free of water, low in sulfur, very low in ash, and sufficiently
low in melting point so that it can be handled as a fluid. In its solid state it is brittle
and readily grindable into a fine powder. Its heating value is 16,000 btu/lb regardless
of the original coal from which it is processed.
-171-
-------
In the process shown in Figure 37, the coal is ground and slurried in an initial solvent
oil. The slurry is pumped to a pressure of 1,000 Ib/sq in and heated to 450°C and as
a result more than 90% of the carbon in the coal goes into solution. A small amount
of H2 is introduced into the slurry to prevent polymerization of the dissolved coal. Any
moisture in the slurry separates and can be easily removed. Ash is filtered from the dis-
solved coal and the coal solution is flash evaporated to recover the solvent. The re-
maining hot liquid residue is discharged and cooled to form a hard, brittle solid of
solvent refined coal.
This refined product is relatively clean and uniform, has negligible ash and relatively
low sulfur content as indicated in Table 29.
TABLE 29
Comparative Analysis of Raw Coal and Solvent Refined Product.
Kentucky Refined
No. 11 Coal Coal
Constituent (Percent)
Ash 6.91 0.14
Carbon 71.31 89.18
Hydrogen 5.29 5.03
Nitrogen 0.94 1.30
Sulfur 3.27 0.95
a
Oxygen (By difference) 12.28 4.40
Volatile Matter 44 51
Heat Content (Btu per Ib.) 13,978 15,956
Melting Point (°C) 128
Source: Chemical Engineering Progress, V. 62, No. 10, p. 54, Oct. 1966.
In a few instances SRC could be substituted for coal in power plants to reduce air
pollution at a profit to the user. On a national average the additional cost of pollu-
tion control through the use of SRC would be about 14 $/MM btu.
Water used in the power plant for cooling and cleaning flue gases, although not con-
sidered to be a major problem, does deserve some comment. Plant cooling water is
normally recirculated with makeup water added as required. In a few instances cool-
ing water is drawn from a natural source such as a stream, lake, or from underground.
-172-
-------
COAL
SOLVENT
SLURRY TANK
FEED PUMP
PREHEATER
DISSOLVER
FILTER
HYDROGEN
GAS
TREATMENT
LIGHT OIL
DISTILLATION
FLASH EVAPORATOR
SOLVENT
REFINED COAL
SOLIDIFICATION BELT
ASH PRODUCTS
ASH RESIDUE
ASH PROCESSING
FIGURE 37. SOLVENT REFINED COAL PROCESS. [147]
-173-
-------
This water is used in a cooling process and pumped, at an elevated temperature, back
into the stream, lake or aquifer. In these cases there is a danger of thermal pollution
causing a depression of dissolved oxygen and an increase in temperature sufficient to
place severe limitations on the usefulness of the stream. Water used in cleaning flue
gases will contain the same contaminants that were in the gas prior to cleaning in
addition it will have an elevated temperature. This water must be treated to remove
the contaminants and cooled before being released into a stream.
Some major research efforts have been directed toward the removal of sulfur from coal
prior to its use. According to Bush, et. al., [148] coal operated power plants are
responsible for 46% of the total sulfur oxide emissions to the atmosphere. For this rea-
son recent emphasis has been on sulfur removal at power stations. The bench scale
study described by Bush used a high intensity magnetic separator developing 11,800-
gauss. Over 80% of the pyrite and sulfate sulfur and over 25% of the organic sulfur
was successfully removed by this process.
Although the removal of sulfur from coal prior to its utilization is under study, most
research to date has been directed toward the removal of SC>2 from flue gases. One
such sulfur removal process involves the injection of pulverized limestone and/or dolo-
mite above the boiler combustion zone to absorb the sulfur gases and trap them in the
solid fly ash which is then removed by electrostatic precipitators or wet scrubbers. This
system increases the amount of fly ash to be disposed of by 130% in a system removing
95% of the sulfur gases [148] .
Processes are being tested which cannot only remove sulfur gases but also produce mar-
ketable by-products such as dilute sulfuric acid and elemental sulfur. S. Kate 11 [149]
has described three such SO« removal processes which have been developed to the ex-
perimental stage. The three processes, Reinluft, Catalytic oxidation, and alkalized
alumina, were examined and the estimated capital investment and operating costs were
projected for removal of 90% of the SOo from 87.3 million cu. ft/hr of flue gas in an
800-Mw. power plant burning a 3% sulfur coal.
In the Reinluft process (Figure 38) the absorbent is a fixed, slowly moving bed of an
activated charcoal. The flue gas at an elevated temperature enters the bottom of the
absorber where SOg is removed. The gas is then drawn off, cooled at 220°F and re-
turned to the absorber at a higher level. The SO2 in the gas is oxidized to SOg and
absorbed with water on the char to form sulfuric acid. The sulfuric acid can then be
removed from the char.
In the catalytic oxidation process (Figure 39) the flue gas passes through a high temper-
ature electrostatic precipitator where virtually all the fly ash is removed. The gas then
flows through a fixed catalyst bed of vanadium pentoxide where the $©2 is oxidized to
SOo. The exit gas is cooled to about 200°F. This cooling causes the formation of sul-
furic acid mist. The acid mist and droplets of condensed acid are removed by an electro-
static precipitator.
-174-
-------
Adsorbent
so
1
"<£
Fl
| *
ue gos@
KXD* F *
/
,2
X
J
"o
"in
CJ
\
0'-3" ID
9 -3" ID
\
-/
k
<
215° F Scrubbed gas
» .
iu siacn
(
Adsorber
290'
r 300
70O'
Regener
^ 700
Vibrating
scr$ en
""«-^^^x^
Cooler
'F ,^
<.«
•F @
•F ©
otor
Heat
*F ,•-
^
h
*3O€
Fines 3,350 Ib/hr
Total gas flow tlOO units), vol.
Stre<
N2
02
CO2
SOa
Million 3
am /
76.2
3.4
14.2
6.0
.2
Trace
cfh87.3
76.2
3.4
14.
2
6.0
.2
—
49I.7
J
76.5
3.3
14.2
6.0 \
Trace
-
88.2
4
28.6
1.3
17.8
27.3
25.0
—
5.5
t
5
28.6
1.3
17.8
27. 3
25.0
—
0.719
22
>
St
(1C
er
,0. Blow
ff^
ilfuric acid plant
38 ton /day
)0 percent acid)
Blower
I™ -N.
Q'
J
^••M
1
(. — j
•—Char make-up 6,700 Ib/hr
J.OOO Ib/hr char Br^Br
6"
76.5
3.3
14.2
6.0
Trace
—
.1
•-i
<
* Includes 5 %
^
•«^
i
<
leakage
(Flue gas from 800-Mw power plant)
FIGURE 38. FLOW DIAGRAM OF THE REINLUFT
°ROCESS. [149]
-175-
-------
From 900* F
boiler /T\
Cyclone
Electrostatic
precipitotor
exchonqer
I
Combustion air
to boiler
Heat
exchanger
IOO°F
Catalytic
converter
Combustion
air
Acid mist
precipitotor
200" E To
880 »F
Acid
FIGURE 39. FLOW DIAGRAM OF A CATALYTIC
OXIDATION PROCESS. (149]
-------
In the alkalized alumina process (Figure 40) the flue gas is fed to an absorber where
the SO2 and SO3 are absorbed by alkalized alumina spheres, 1/16 In. diameter, in
free fall. The spent absorbent is transported to the regenerator, heated to 1,200°F,
and then treated with producer gas. The absorbed sulfur dioxide reacts with the H2
and CO of the producer gas to give H2S, CO2 and H2O. The gas is then fed to a claus
unit where 1/3 of the H2S is oxidized to SO2; the gas streams-are then mixed and passed
over a bauxite catalyst and elemental sulfur recovered.
Figures presented by the author reveal that the capital investment and operating costs
were lowest for the alkalized alumina process. The Reinluft process exhibited lower
capital investment costs and higher operating costs than the catalytic oxidation pro-
cess. According to Katell, although many of the projections are based on actual oper-
ating data, some of the assumptions made could have been optimistic.
The amount of fly ash in the flue gases of a coal-fired power plant varies directly with
the ash content of the fuel coal. The eleven coal-fired plants in the TVA system des-
cribed by Gartrell, et. al., [150] annually consume 21 million tons of coal with an
ash content of 12.5%. Ash removal from the furnace gases by the collectors total ap-
proximately 1.5 million tons annually. Fly ash is removed by mechanical collectors,
electrostatic precipitators, or both. A small fraction of the collected ash is converte
to commercial use. The remainder presents a major disposal problem. The ash is nor-
mally pumped to settling ponds where the ash settles out of the cleaning water. The
alkaline overflow is discharged to the nearest watercourse. To prevent the discharge
of any floating ash skimmer devices are placed at the settling pond outlet.
Coke production is so intimately associated with the metallurgical industry that pollution
problems in this industry cannot be discussed without including those of the ancillary
coke oven installations. Blast furnaces account for over 90% of the total annual coke
consumption [151] . To produce one ton of iron, 2.0 tons of ore, 0.9 ton of coke,
0.4 ton of limestone and 3.5 tons of air are required. Byproducts produced are 0.6 ton
of slag, 0.1 ton of flue dust and 5.1 tons of blast furnace gas. Modern furnaces produce
3,000 or more tons of iron, per day [152] . While steel production is the largest metal-
lurgical consumer of coal, other new uses for coal in this industry include the production
of titanium tetrachloride, zinc, metal carbides and aluminum [153] .
The major water pollution problem associated with coal products in the metallurgical
industry occurs at coke oven installations [154] . The problem involves the disposal
of spent ammonical liquor. During the production of metallurgical coke, large volumes
of weak ammonical liquor containing phenols are produced when the coke oven gas
from the collecting main is cooled directly with water sprays. At small installations
thfe spent ammonical liquor is mixed with town sewage. However, difficulties arise when
this effluent exceed about 0.5% of the dry-weather flow of sewage. Most coke ovens
are so large as to preclude local town treatment works as a method of disposal.
-177-
-------
I
5
625*F
i
Flue gos^
625" F*
^x
F V
i |~
Absorber
27'-O" ID
\
^••^
p,8
^ Flue gas
| _to stock
HADSOI
Icycfc
\^
4354.4OO
Ib/hr
lOO Ib/hr
^®
one
/
303.600 Ib/hr
^
| Flue gas from
> 625-F
-1 neoier j-
1 1 200*
I^OC
Dis
6
I3-6" ID
M*-
>
I-F
engaging Total 9as f low t6 units), vol. %
hopper
fc-r nm
* VIU«
•^Vo sulfur
0 recovery
Regenerator
rorbent makeup
' 455 Ib/hr
F J s . F'«« 90*
"y^ from stack
Stream.
N2
CO
SOj
SO}
H2S
CH4
Millio
scfh
n
/
76.2
3,^
14.2
6.0
-
-
0.2
Trace
-
-
-
87.3
i .
1 i 2
2
76.5
3-3
14.2
6.0
-
-
Trace
-
-
—
—
87.0
Electi
prec
no»F
J
47.4
-
5.0
1.4
16.6
262
-
—
04
2.6
0.4
1.8
4
47.4
-
29.6
4.O
4.3
1.6
-
-
10. 1
2.6
0.4
1.8
•astatic
pitator
From
/-"\produc
stock
(Flue gas from 800-Mw power plant)
Amounts of solids flow are total for 6 units.
FIGURE 40. FLOW DIAGRAM OF ALKALIZED ALUMINA
PROCESS. [1491
-------
In a method of treatment discussed by R. D. Hoak, et. al., [152] the free and fixed
ammonia in the liquor are stripped out and returned to the coke oven gas stream. The
gas stream is bubbled through a dilute solution of sulfuric acid where the ammonia is
recovered as ammonium sulfate.
Other, more expensive, methods are biological oxidation at the coke works or absorption
by ion-exchange resins and activated carbon [154] .
To eliminate this pollutant the first aim should be to operate the coke ovens so as to in-
sure that the volumes of ammonical liquor are kept as small as possible; tar and liquor
should be separated as soon as possible. If the amount of monohydric phenol in the
liquor is 0.3% or more, it may be profitable to recover the phenol [154] .
phenols are toxic compounds produced by the distillation of organic substances and are
common to the wastes of many industries. In many cases dilution and natural oxidation
in a river will take care of a phenol residual of the order of less than 1. mg/l. This
concentration can be obtained with a fair degree of consistency and at reasonable cost
in a properly treated effluent. G. Gutzeit, et. al., [155] have presented a classi-
fication scheme of phenol removal methods based on unit operations and phenol con-
centration. A portion of that classification scheme is presented below and will
be used in discussing the various methods of dephenolization.
Process Original Phenol
Concentration mg/l
I
2000+
Effluent Phenol
Concentration mg/l
200+
2000+
500-
50-
20-
Method of
Dephenolization
(A) Steam distillation
(B) Simple Solvent
extract ion-single
stage concurrent
(C) Adsorption by acti-
vated carbon in static
column with desorption
by benzol or super-
heated steam
Countercurrent Solvent
extraction
Adsorption by bituminous
coal or lignite followed by
flotation of some (Note:
this range also can be treated
by Method II)
-179-
-------
Process Original Phenol Effluent Phenol Method of
Concentration mg/l Concentration mg/l Dephenol ization
IV TOO- 1- (A) Biological oxidation
(B) Chemical oxidation
(1) Ozone
(2) Chlorine dioxide
(3) Hyperchlorination
Processes I and II are stripping methods, and can be used for the recovery of phenols
if the required capital investment is justified by the value of the product. The pro-
cesses listed under I never result in final liquors which can be discharged directly into
a watercourse. Their efficiency is at best 95%. Process II is considered to be the
most economical and most efficient treatment for wastes with relatively high phenol
concentrations. When combined with one of the methods under Process IV this system
would give complete treatment of relatively large volumes of high phenolic wastes.
A study conducted by Yanysheva, et. al., [156] suggested steaming as a means of
phenol removal. The!study was made on the very powerful carcinogen, 3,4-benzo-
pyrene, in coke and chemical works effluent. The improvement after dephenolization
was so small that the type of phenol removing equipment used could not be considered
as an efficient means of removing carcinogens from effluent. Table 30 reproduces the
average results of these investigations.
Pritsker, et. al., [157] have- reported the results of an industrial scale pilot plant for
extracting phenols from an effluent by the use of coal tar oil. The main unit of the
plant is a seven-stage mixer extractor (Figure 41). The liquor for dephenol ization
enters a mixer-extractor where the liquor and oil are mixed. Afterwards, the mixture
enters a separator for separation of the oil from the liquor. The saturated oil is then
washed continuously with an alkaline solution or with weak phenolates. After this
washing the mixture of oil and phenolates enters a separator-settler where the oil is
separated from the phenolates. The phenolates go to a finished product storage tank
and the oil goes to a collector from where it is recycled for further phenol extraction.
Table 31 lists the results of this method. The maximum efficiency indicated is 91.6%*
with a minimum effluent content of 282 mg/l. The effluent, therefore, is not considered
safe for release into a watercourse.
Gutzeit, et. al., [155] discussed the Barrett process phenol recovery plant. This
method was listed previously (Process II) as a countercurrent solvent extraction pro-
cedure. The basic unit of the process is a rotating disc contactor (Figure 42). This
unit makes use of a difference in densities to mix the wastes with the dephenolizing
liquid. Because energy input is controlled by rotor speed rather than by flow rates
the efficiency can actually be increased over a range of thru-put rates varying from
100% to 10% of design flow. Table 32 gives the typical maximum efficiency of this
type extractor.
-180-
-------
Sampling point
Collecting-main ammonia-tar
liquor from clarifier
Collecting-main ammonia-tar
liquor entering dephenol izing
scrubber
Collecting-main ammonia-tar
liquor leaving dephenol izing
scrubber
Ammonia-tar liquor entering
dephenol izing scrubber
Ammonia-tar liquor leaving
dephenolizing scrubber
Process water from final gas
coolers
Liquor from primary phenol
clarifier
Liquor from tar settler
Liquor from final phenol
clarifier, used to quench
coke
TABLE 30
Carcinogen Removal from Phenolic Effluents
Content of
tarry matter,
g/l
0.4502
0.3380
0.3126
0.0592
3,4-benz- 3,4-benz-
pyrene in pyrene content
, % of effluent mg/l
1.380
0.200
0.1476
0.2041
0.1226
0.2640
0.8500
1.0569
0.1279
istry USSR,
0. 1200
0.0508
0.0750
0.3480
0.0820
0.2500
0.0818
No. 10, p. 40,
0.175
0.103
0.092
0.920
0.690
2.650
0.102
1963.
-181-
-------
PLANT FOR EXTRACTING PHENOLS FROM EFFLUENTS BY MEANS OF COAL TAR OIL
7- WEAK PHENOLATES COLLECTOR
FIGURE 41. PLANT FOR EXTRACTING PHENOLS FROM EFFLUENTS
BY MEANS OF COAL TAR OIL. [157]
-------
TABLE 31
Phenol Extraction by the Use of Coal Tar Oil
Month
1959
December
1960
January
February
March
*° £
C^
•^.
^^
86.2
88.7
85.5
89.0
TJ
Q)
i-i- N
o •—
*- O
^
-------
*"^ <•'••
FIGURE 42. A ROTATING DISC CONTRACTOR EXTRACTION
COLUMN IN SIMPLIFIED SCHEMATIC DIAGRAM.
11551
-------
Coal adsorption (Process III) is limited by the adsorption capacity of coal. In other
words, the weights of adsorbent ground to an acceptable size for flotation recovery
required are roughly proportional to the phenol content of the waste in a ratio of
1:200. Consequently, unless powdered coal can be utilized locally in large quan-
tities or unless the volume of waste is small, this method cannot be generally
recommended [155] .
G. Clough [158) describes a plant for the biological oxidation of a phenolic effluent
installed in large steelworks. The full scale treatment plant was designed to remove
substantially all the monohydric phenol from the mixed coke oven effluent. The plant
consists basically of four aeration tanks each 26 feet square, each provided with a
simplex surface aeration unit. These aeration units are supported from spanning walk-
ways^and driven by two line shafts, each line shaft driving two aeration cones. The
hot liquor is first passed through a pipe system under the aeration tanks to heat the tank,
then through a pair of rack coolers. Operation of the plant gave a decrease in phenol
concentration in ppm of from 400-700 to 10-20.
W. R. Davis [159] has described a process of dephenolization of coke plant wastes by
bacterial action used at the Bethlehem steel plant. The equipment used includes a 1
million gallon storage tank, a 265,000 gallon aeration pond with eight surface aerators
and a 40 feet diameter X 9 feet deep clarifier. This unit was designed for 150,000
gpd of liquor with a phenol content of 5000 ppm. The plant has been operating at a
phenol loading of 1500 ppm and an efficiency of 99.9%. The Bethlehem plant incor-
porates recycling and reuse of industrial water thus eliminating a major source of
stream pollution.
H. R. Eisenhaur [160] has reported on experiments conducted on the ozone treatment
of phenolic wastes. In these experiments ozone was generated and bubbled through an
oxidation reactor which was initially charged with 1,000 ml. of phenol solution. Ex-
cess gas passed into an absorber for analysis. A bleed off was made in the oxidation
reactor to remove samples of the oxidized phenol solution for analysis. It was found
that the phenol degradation reaction may be increased by any one of the following:
Increasing the ozone concentration in the gas stream
Increasing the gas flow rate
Increasing gas bubble frequency
Reducing gas bubble size
Increasing gas/liquid contact time
Among the processes under process category IV, it can be generally said that chemical
oxidation is expensive unless the phenol concentrations are very low. Biological oxi-
dation is preferred although controlled conditions are required for its satisfactory
operation. 7
-185-
-------
SECTION XI
ACKNOWLEDGEMENTS
The directors are especially indebted to Mr. Leon H. Myers, Research Chemist, Robert
S. Kerr Walter Research Center, Federal Water Pollution Control Administration, Ada,
Oklahoma, for his advice and supervision of this study.
Appreciation is extended to Silas Law, Duane Motsenbocker, Keith Giles, John Palafox,
Robert Sweazy, David Rumfeldt, James Bradshaw, and Hok Jang Thung, students at the
University of Oklahoma, who participated in the literature search and draft preparation.
Appreciation is extended to the members of the Oklahoma Refiners Waste Control
Council for their guidance and consideration and the American Petroleum Institute
for their review of this treatise.
Sincere gratitude is expressed for the financial support provided by the U.S. Depart-
ment of Interior, Federal Water Pollution Control Administration, Grant No. 12050
DKF.
-187-
-------
SECTION XII
REFERENCES
1. Ostroff, A. G., "Introduction to Oilfield Water Technology," Prentice-Hall
Inc., Englewood Cliffs, N.J., 1965.
2. Nemerow, N. L., "Theories and Practices of Industrial Waste Treatment,"
Addision-Wesley Publishing Co., Inc., Reading, Mass., p. 432, 1963.
3. Jones, Ogden S., "Fresh Water Protection from Pollution Arising in the Oil
Fields," University of Kansas Publications, Lawrence, Kansas, 1950.
4. Collins, A. Gene, "Here's how producers can turn brine disposal into profit "
The Oil and Gas Journal, Vol. 64, No. 27, p. 112, July 4, 1966.
5. Moseley, J. C. and Molina, J. F., "Relationships Between Selected Physical
Parameters and Cost Responses for the Deep-Well Disposal of Aqueous Industrial
Wastes," Center for Research in Water Research in Water Resources, the Uni-
versity of Texas at Austin, Civil Engineering Department, CRWR 28, August,
1968.
6. Warner, Don R., "Deep Wells for Industrial Waste Injection in the United States "
Summary of Data FWPCA, November, 1967. '
7. Staff, "Fresh-Water Use in Floods Defended," The Oil and Gas Journal, Vol 67
No. 45, p..140, November 10, 1969. " ~~ ' '
8. Donaldson, Erie C., "Subsurface Disposal of Industrial Wastes in the United
States," U.S. Dept. of the Interior, Bureau of Mines, 1964.
9. Rice Ivan M., "Guidelines for Disposal Systems," Petroleum Engineer, Vol. 39
No. 7-13, July, 1967.
10. Hicks, T. G., "Pump Selection and Application," McGraw-Hill Book Co. Inc.,
New York, 1957.
11. Raschke Alvin, Smith, James E., and Wills, M. E., "Let engineering know-how
solve salt-polluhon problems," The Oil and Gas Journal. V^l 63 No 30 _ 7c
August 9, 1965. ~~ ' N°' 32' p* 75'
12. Kading, Horace, "Shut-in temperature profiles tell where the water went," The
Oil and Gas Journal, Vol. 66, No. 20, p. 77, May 18, 1968.
13. Sayers, G.W., Potable Water Drawn from Abandoned Oil Well," Public Works,
November, 1964.
-189-
-------
References (Cont.)
14. Staff, "Eastern Seaboard Survey to Shoot 16,000 mile Grid," Offshore Vol
28, No. 8-13, p. 34, July, 1968. ''
15. Ludwig, H. F. and Carter, R., "Analytical Characteristics of Oil-tar Materials
on Southern California Beaches." Journal Water Pollution Federation Vol 33
p. 1123, 1961. -' ' '
16. Degler, S. E., "Oil Pollution: Problems and Policies," The Bureau of National
Affairs, Inc., Washington, D. Cf/ 1969.
17. Basye, D. E., "Forecast For the Seventies," The Oil and Gas Journal, Vol 67
No. 45, p. 199, November 10, 1969. ~~ ' '
18. Basye, D. E., "Scr.ta Barbara Sparkling in Wake of Clean-up Job," The Oil
and Gas Journal, YO!. 67, No. 34, p. 33, August 25, 1969.
19. Easthagen, John H., "Pollution Control in the Oil Industry," Shore and Beach
October, 1963. ~ '
20. Ludwig, H. F., Carter, R. C., and Scherfig, J., "Characteristics of Oil and
Grease Found in the Marine Environment," Water and Sewage Works, Vol. Ill
November, 1964. ' * '
21. Wilson, H., "Advanced Diving Problems Solving Depth Problems Offshore "
Offshore, Vol. 28, p. 56, August, 1968.
22. Staff, "Oil-spill Damage to Marine Life Scant," The Oil and Gas Journal Vol
67, No. 11, p. 65, March 17, 1969. ~~'
23' 1969' "H'ckel Evaluates Santa Barbara Study, " Offshore, Vol. 29, p. 86, March 24,
24. "Oil Pollution - A Report to the President," Report No. 0-298-767 U.S. Govern-
ment Printing Office,
25. O1 Donnell, J. P., "Forecast for the Seventies Pipelining," The Oil and Gas
Journal, Vol. 67, No. 40, p. 96, November, 10, 1969.
26. Staff, "Environmental Rules Cleared for TAPS Permit, The Oil and Gas Journal
Vol. 67, No. 40, p. 96, October 6, 1969. ' £
27. Staff, "Sea-Floor Tanks for Oil Storage Pushed," The Oil and Gas Journal Vol
66, No. 16, p. 47, April 15, 1968. '
-190-
-------
References (Cont.)
28. Staff, "Lockheed Eyes Subsea Cavity for Oil Storage, " Offshore, Vol. 28,
p. 152, December, 1968.
29. Staff, "Shell Tankers Transfer Oil at Sea Successfully," Offshore, Vol. 28.
p. 47, September, 1968.
30. Staff, "Louisiana Pollution Rule Out," The Oil and Gas Journal Vol 67
No. 12, p. 70, March 24, 1969. '— ' '
31. Stern, A.C., Air Pollution, Academic Press, New York, Vol. Ill, 1968.
32. "The Cost of Clean Water, " Volume III, Industrial Waste Profile No. 5,
Petroleum Refining, U.S. Department of Interior, Federal Water Pollution
Control Administration, November, 1967.
33. Staff, "Electrical Desalting, " The Oil and Gas Journal, Vol. 67, No. 39,
p. 84, September 29, 1969. '
34. Staff, "How Much and What1 s in HPI Waste Water Streams, " Hydrocarbon
Processing, Vol. 46, No. 7, p. 110, July, 1967.
35. "1967 Domestic Refinery Effluent Profile," conducted by Committee for Air and
Water Conservation American Petroleum Institute, September 1968.
36. Wilber, C.G., The Biological Aspects of Water Pollution, Charles C. Thomas
Publisher, 1969.
37. Beychok, M.R., Aqueous Wastes from Petroleum and Petrochemical Plants,
John Wiley & Sons, N.Y., 1967.
38. "Manual on Disposal of Refinery Wastes," Volume on Liquid Wastes, American
Petroleum Institute, 1969.
39. "Manual on Disposal of Refinery Wastes/" Vol. IV, Sampling and Analysis of
Waste Water, American Petroleum Institute, New York, N.Y. 1957.
40. Johnson, J.O., and Fleming, R.L., "Oil Recovery and Solids Removal by
Centrifugal Means," paper, Oklahoma Industrial Waste Conference, 1964.
41. Besselievre, E.B., The Treatment of Industrial Wastes. McGraw-Hill Book
Co., New York 19697 ~
42. Bevins, J.M.: "Use of Low Quality Waste Water for Steam Generation,"
paper, Petroleum Industry Conference on Thermal Oil Recovery, Los Anqeles,
Calif., June 6, 1966.
-191-
-------
References (Cont.)
43. Staff, "Shell Scientists Use Oil to Clean Water, " The Oil and Gas Journal
Vol. 67, No. 5, p. 97, February 3, 1969. " ' '
44. Jaeschke, L. and Trobisch, K., "Treat HP I Wastes Biologically, " Hydro-
carbon Processing, Vol. 46, No. 7, p. Ill, July, 1967.
45. McKinney, R.E., "Biological Treatment Systems for Refinery Wastes " JWPrF
Vol. 39, p. 346, March, 1967. ' —'
46. Gloyna, E.F. and Eckenfelder, W.W., "Advances in Water Quality Improve-
ment," University of Texas Press, Austin, Texas, 1968.
47. Hodgkinson. CF. "Oil Refinery Waste Treatment in Kansas." Sewage and
Industrial Wastes, Vol. 31, No. 11, p. 1304, November, 1959. ~
48. Copeland B J and Dorris, T.C., "Effectiveness of Oil Refinery Effluent
Moldings ronds, Trans, of 13thAnnual Trmf ^«-«i. c • ,, •
k-nncoc P u R ii re ' ,nuai ^-onr. Sanitary Engineering, Univ. of
Kansas. Publ., Bull, of Eng. and Arch. No. 51, 8, (1963).
49. Gnerson A., "The Fuel Mineral-Coal," I968and 1969 Annual Review,
Mining Journal. '
, Vol. 67, Nc
-
^^
. Ser. H5, 460 (1964).
55. MiddJeton, P.M. and Lichrenbera, J.J., "Organic Contaminants ;„ the
Nation's Rivers as Measured by the Carbon Filter, " Abstracts of Papers, I36rh
Meeting, Am. Chem. Soc., TV, September ]3, 18 New York 1959.
-192-
-------
References (Cont.)
56. Staff, "Pollution of Inland Waters by Oil," Journal of the Institute of Water
Pollution Control (England), Vol. 67, No. 4, December, 1968;
57. Newman, E.D-, Reno, C.J. and Burroughs, L.C., "Waste Disposal at
Anacortes." The Oil and Gas Journal, Vol. 56, No. 20, p. 124, 1958.
58. Gillian, AS. and Anderegg, F.C., "Biological Disposal of Refinery Wastes."
Proc. Nth Ind. Waste Conf. Purdue Univ., Ext. Ser. 104, 145(1959).
59. Davis, R.W., Biehl, J.A. and Smith, R.M., "Pollution Control and Waste
Treatment at an Inland Refinery." Proc. 19th Ind. Waste Conf., Purdue Univ
Ext. Ser. 117, 126 (1965).
60. Elkins, H.F., "Activated Sludge Process Applications to Refinery Effluent
Waters." Sewage and Industrial Wastes, 289, 1122, September,1956.
61. Word, J.C. and Klippel, R.W., "Multi-Plant Wastes Taken in Stride by
Automated System," Chemical Processing, October, 1965.
62. Young, R.A., "Pollution Control," Plant Engineering, pp. 53-84, September
4. 1969.
4, 1969.
63. Industrial Oily Waste Control, American Petroleum Institute, American Society
of Lubrication Engineers, No. 9660, 1970.
64. Basye, D., "How Humble Controls Its Environment at Benicia " The Oil and
Gas Journal, Vol . 67, No. 12, p. 102, March 24, 1969. -
65. Staff "Chevron Turns Waste Water into Profit," The Oil and Gas Journal,
Vol. 66, No. 14, p. 79, April 1, 1968. ~~ - " -
67 •
68-
69. U.S. Pat. No. 3393978, July 23, 1968, The Carbon Co.
-193-
-------
References (Cont.)
70. Chemical Engineering, January 15, 1968 p. 68.
71. Messman, H.C., "Desulfurization of Solid Carbonaceous Materials," Institute
of Briquetting and Agglomeration, Sun Valley, Idaho, August 29, 1969.
72. "Charcoal Device May Cut Auto Pollution," Vol. 65, No. 3, p. 60, The
Oil and Gas Journal, January 167 1967.
73. Faatz, A.C., "Centralized Waste-Disposal Facility is Economical," The
Oil and Gas Journal, Vol. 67, No. 32, p. 142, August 11, 1969.
74. Staff, "Forecast for the Seventies," The Oil and Gas Journal, Vol. 67
No. 45, p. 160, November 10, 196^ '
75. Forbes, M.S., and Witt, P.A., "Indices for the Evaluation and Reporting
of Industrial Water Pollution Control," presentedat the National Petroleum
Refiners Association Rocky Mountain Regional Meeting, Casper, Wyomina
September 27-29, 1966. 8'
76. Welder, B.Q., "Water Must Be Managed," Hydrocarbon Processing Vol
46, No. 7, p. 103, July, 1967. ~
77. Merz, R.C., et. al., "A Survey of Direct Utilization of Waste Waters,"
State Water Pollution Control Board, Sacramento, California, Publication
No. 12. *
78. McGauhey, P.M., Engineering Management of Water Quality, McGraw-
Hill Book Company, New York, 1968.
79. Keating, R.J. and Calise, V.J., "Treatment of Sewage Plant Effluent
for Industrial Re-use." Sewage and Industrial Wastes, Vol. 27, No 7
p. 773, July, 1955. "" ' '
80. Clark, W. and Viessman, W. Jr., Water Supply and Pollution Control,
International Textbook Co., Scranton, Pa., 1961. ~~~~'
81. Veatch, N.T., "Industrial Uses of Reclaimed Sewage Effluent," Sewage
Works Journal, Vol. 20, No. 1, p. 3, January, 1948.
82. Perkins, D.G., "Municipal Sewage Effluent as a Refinery Water Supply."
Proceedings of the Oklahoma Industrial Wastes Conference, Publication
No. 79, December, 1955. "~~
-194-
-------
References (Cont.)
83. Private communication witii B. Hodgden, Wafer Supervisor, Champlin Oil
and Refining Co., Enid, Oklahoma, March, 1970.
84. Lively, L. and Mashni, C.I., "Indenh'ficaMon of Petroleum Products in
Wafer," Proc. 12th Industrial Waste Conference, Purdue University, Lafayette,
Indiana, May 4, 5, and 6, 1965.
85. Strobel, H.A., Chemical Instrumentation, Addison-Wesley Publishing Com-
pany, Inc. Reading, Mass., 1960.
86. Pecsok, R.L. and Shields, L.D., Modern Methods of Chemical Analysis,
John Wiley and Sons, Inc., New York, 1968. "
87. "Annual Reviews, " a special biannual issue of Analytical Chemistry.
88. Kolthoff, I.M. and Elving, P.J., "Treatise on Analytical Chemistry, "
Interscience, New York, 1959.
89. Weissberger, A., "Physical Methods of Organic Chemistry/1 Interscience
New York , 1 959 . - '
90. Sixma, F.L.J. and Wynberg, H., A Manual of Physical Methods in
Organic Chemistry. John Wiley and Sons, Inc., New York, 1964.
91 ' ^'u1"^ H/AH",Merrm' Jr" L'1--' ™<* Dean, J.A., Instrumental
Methods of Analysis, 4th Ed., Van Nostrand, Princeton, N.J., 1965.
92. Karasek, F. w "Analytic Instruments in Process Control, » Scientific Ameri-
can, June, 1969. -
93. Salkowski, M.J., "Detection of Oil Contamination in Sea Water," NT
Research Institute, Technology Center, Chicago, Illinois, May 9, 1966.
94. Wolf, C.J. and Walker, J.Q., "New Chromatography Technique is
Promising," The Oil and Gas Journal, Vol.67, No. 13, p. 69, March 31 , 1969.
95. Levy, R.L., "Chromatographic Reviews, " 8, 48, 1966.
96. Brady, S.O., "Tastes and Odor Components in Refinery Effluents,"
Paper presented at 33rd Midyear Meeting of A. P. I. , Div. of Refining,
Philadelphia, Pa., 1968.
-195-
-------
References (Cont.)
97. Medsker, L.L., Jenkins, D., and Thomas, J.F., "An Earthy-Smelling
Compound Associated with Blue-Green Algae and Actinomycetes, "
Environ. Sci. & Technol.y Vol. 2, pp. 461-464, 1968.
98. Melpolder, F.W., Warfield, C.W., and Headington, C.E., "Mass
Spectrometer Determination of Volatile Contaminants in Water," Anal.
Chem., Vol. 25, pp. 1453-1456, 1953.
99. Baker, R.A. and Malo, B.A., "Water Quality Characterization—Trace
Organics," Jour, of San. Engr. Div., ASCE, Vol. 92, No. SAG pp. 41-
54, 1967.
100. Kroner, R.C., "Solutions to Classical Pollution Problems Using Advanced
Analytical Techniques," Symposium on Organic Matter in Natural Waters,
University of Alaska, September 2-4, 1968.
101. Waller, G.R., "Description of the Oklahoma State University Combination
Mass Spectrometer Gas Chromatograph," Proc. Okla. Acad. Sci Vol 47
pp. 271-292, 1968. '
102. Burks, S.L., "Organic Chemical Compounds in Keystone Reservoir,"
Doctoral Dissertation, Oklahoma State University. Stillwater, Oklahoma
May 1969.
103. Anon., The Plain Truth, p. 14, February 1970.
104. "Industrial Wastewater Control," Ed. by C. Fred Gurnham, Academic
Press, New York, 1965, pp. 169-81.
105. "Coal Bituminous and Lignite, " Reprint from the 1968 Bureau of Mines
Minerals Yearbook.
106. Averitt, Paul, "Stripping Coal Resources of the United States," U.S.
Geological Survey Bulletin 1252 C, U.S. Government Printing Office,
1968.
107. National Ash Association Brochure Washington, D.C.
108. Jackson, D., Jr., "Strip Mining, Reclamation, and the Public," Cool
Age, Vol. 68, No. 5, May 1963.
-196-
-------
References (Cont.)
109. Bellano, W., "An Operator Looks at Acid Mine Drainage," Mining
Congress Journal, Vol. 50, No. 8, pp. 66-75, August, 1964.
110. S Helton, T.C., Jr., "Coal Looks to the Future," Mining Engineering,
Vol. 20, February 1968.
111. Anon., "Fly Ash Utilization Climbing Steadily," Environmental Science
and Technology, Vol. 4, No. 3, pp. 187-189, March, 1970.
112. Braley, S.A., "Evaluation of Mine Drainage Water," Mining Engineering,
Vol. 9, No. 1, pp. 76-78, January, 1957.
113. Anon., "States Make Headway on Mine Drainage," Environmental Science
and Technology, Vol. 3, No. 12, pp. 1237-1239, December, 1969.
114. Krickovic, S., "Acid Mine Drainage Pollution Control-Approach to
Solution," Mining Congress Journal, Vol. 52, pp. 64-68, December
1966. —
115. Maneval, D.R. and H.B. Charmbury, "Acid Mine Water Mobile
Treatment Plant," Mining Congress Journal, Vol. 51, pp. 69-71,
March 1965. "
116. Corriveau,M.P., "Some Aspects of Acid Mine Water Analysis, " Mining
Congress Journal, Vol. 52, pp. 52-53, July 1966.
117. Ashmead, Douglas, "Acid Coal Mine Drainage: Truth and Fallacy
About a Serious Problem," Mining Engineering, Vol. 8, No. 9,
pp. 928-929, September, l~956i ~~
118. Anon., "Antibacterial Agents Reduce Acidity of Caol Mine Drainage,"
Chem. and Eng. News, Vol. 46, pp. 19-20, May 19, 1968.
119. Nemerow, N.L., "Theories and Practices of Industrial Waste Treatment"
Addision-Wesley Publishing Co., Inc., Reading, Mass., 1968.
120. U.S. Department of Health, Education and Welfare, "Acid Mine
Drainage," A report prepared for the Committee on Public Works, House
of Representatives, 87th Congress, 2nd session, House Committee, Print
No. 18, p. 24, 1962.
-197-
-------
References (Cont.)
121. U.S. Department of the Interior, Bureau of Sport Fisheries and Wildlife
JUIM* -i? « W M?ne Pollutlon Fn the United States Affecting Fish '
and Wildlife, "Circular 191, June, 1964.
122. Hanna G p j j.R> >
K.A. Brant, Acid Mine Drainage Research Potentialities," J. Water
Pollution Control Federation. Vol. 35, No. 3, pp. 275-296, March"
123. Hert o.H., "Pract.cal Control Measure to Reduce Acid Mine Drain-
age, Proceedings of the 13th Industrial Waste Conference, Purdue
University, p. 189, Max 1958.
124. Steinman, H.E., "An Operator's Approach to Mine Water Drainage
Problems and Stream Pollution, " Mining Congress Journal Vol 4A
No. 7, pp. 70-73, July, 1960. ' ' '
125. Anon., "New Look at Acid Mine Drainage," Engineering News-
Record, pp. 61-62, May 27, 1960. —* ~ -
126. Anon., "Acid Mine-Drainage Control: Principles and Practices
Guide, "Coal Age, Vol. 69, No. 5, pp. 81-84, May, 1964. '
127. Braley, S.A. "A Pilot Plant Study of the Neutralization of Acid
Dramage from Bituminous Coal Mines, "Sanitary Water Board Publi
cation, Department of Health, Harrisburg, Pa., 195K "
128. Crichton, A.B., "Disposal of Drainage from Coal Mines," Trans Amer
Soc. Civ. Engr. Vol. 92, pp. 1332-1342, 1928. L -'
129. Girard, L. and R. Kaplan," 'Operation Yellow Boy1
Acid Mine Drainage," Coa. Age, Vol. 72, No. l/pp
130.. Charmbury, H B., "Developments in Mine Drainage Pollution Con-
trol, Mining Congress Journal, Vol. 54, No. 1, pp. 50-53 Janu-
ary, 1968. '
131. Anon., "U.S. Steel Solves Acid-Water Problems," Coal Age Vol 74
No. 5, May 1969. s— * '
-198-
-------
References (Cont.)
132. Glover, H.G., "The Control of Acid Mine Drainage Pollution by Bio-
chemical Oxidation and Limestone Neutralization Treatment," Purdue
University Extension Service, pp. 823-846, October, 1968.
133. Mihok, E.A., M. Deul, C.E. Chamberlain, and J.G. Selmeczi, "Mine
Water Research - The Limestone Neutralization Process," U.S. Bureau
of Mines Report, Investigation 7191, pp. 20, September, 1968.
134. Sterner, J.S. and H.A. Conahan, "Ion Exchange Treatment of Acid
Mine Drainage," Proceedings of the 23rd Industrial Waste Conference,
Purdue Univ. Part, one, pp. 101-110, May 7-9, 1968.
135. Steinberg, M.J. Pruzansky, L.R. Jefferson, and B. Manowitz, "Removal
of Iron From Acid Mine Drainage Waste With the Aid of High Energy
Radiation, Part II," Second Symposium on Coal Mine Drainage Research,
Mellon Institute, pp. 291-307, May 14-15, 1968.
136. Deane, J.A., "Reclamation and Water Control of Stripped Coal Mines, "
Proceedings of the 7th Annual Air and Water Pollution Conference,
November 14, 1961, Missouri University Engineering Experiment Station,
Bull. 54, pp. 8-10, April 15, 1962.
137. Charmbury, H.B., "Coal-Water Separations, " Mechanization, Vol. 21,
No. 9, pp. 60-68, September, 1957.
138. Adamson, G.F.S., "Some Modern Aspects of Coal Cleaning and Their
Influence on the Avoidance of River Pollution," Effluent and Water
Treatment Journal, Vol. 5, No. 3, pp. 143-144, 146, 148.
139. "Fine-Coal Treatment and Water Handling," Coal Aae. Vol. 66,
No. 12, pp. 68-82, December, 1961.
140. Ludberg, James E. and C. Donald Nicks, "Phenols and Thiocyanate
Removed from Coke Plant Effluents," Industrial Wastes, A Water and
Sewage Works Supplement, Vol. 116, No. 11, pp. 10-13, November,
1969.
141. Nebolsine, R., "Treatment of Water-Borne Wastes from Steel Plants,"
Iron and Steel Engineering, Vol. 34, pp. 141-145, December, 1957.
-199-
-------
References (Cont.)
142. Lauer, F.C., E.J. Littlewood and J.J. Butler, "Solvent Extraction Process
for Phenols Recovery from Coke Plant Aqueous Waste, " Iron and Steel Engi-
neering, Vol. 46, No. 5, pp. 99-102, May, 1969. ~
143. Savage, Philip S., "Industrial Wastes," Sewage and Industry, Vol. 29 DD
1363-1369, December, 1957. —Z ' PP*
144. Muller, J.M. and F.L. Coventry, "Disposal of Coke Plant Waste in the
Sanitary Water System, " Blast Furnace and Steel Plant, Vol. 56 No 5
pp. 400-406, May, 1968T~~ * '
145. "Outlook and Research Possibilities for Bituminous Cool," U.S. Department
of the Interior, Bureau of Mines, Circular No. 7754, May, 1956. ~
146. Frankel, R.J., "Technologic and Economic Interrelationships Among Gaseous,
Liquid, and Solid Wastes in the Coal, Energy Industry," WPCF J Vol 40
pp. 779-788, May, 1968. ' ' '
147. Jimeson, R.M., "Utilizing Solvent Refined Coal in Power Plants," Chemical
Engineering Progress, Vol. 62, No. 10, pp. 53-60, October, 1966~
148. Bush, R.I.., et. al., "Coal Utilization," Mining Engineering, Vol. 21 No
2, pp. 104-117, February, 1969. ~
149. Katell, S., "Removing Sulfur Dioxide from Flue Gases," Chemical Engineerina
Progress, Vol. 62, No. 10, pp. 67-73, October, 1966. -^
150. Gartrell, F.E., et. al., "Pollution Control Interrelationships," Chemical
Engineering Progress. Vol. 62, No. 10, pp. 44-47, October, 1966^
151. Labee, C.J. et. al., "Coke and By-products in 1963," Iron and Steel
Engineer, Vol. 41, pp. 145-152, December, 1964. '
152. Hoak, R.D., et. al., "Pollution Control in the Steel Industry," Chemical
Engineering Progress. Vol. 62, No. 10, pp. 48-52, October, 1966^
153. Walsh, J.H., et. al., "Present and Potential Uses for Coal in the Canadian
Metallurgical Industry," The Mining and Metallurgical Bulletin, Vol. 56
pp. 81-88, February, 1958: "
154. Parker, A., "Air and Water Pollution in the Iron and Steel Industry," Journal
of the Iron and Steel Institute, Vol. 189, No. 4, pp. 297-302, August, 1958.
-200-
-------
References (Cont.)
155. Gutzeit, G., et. al., "Treatment of Phenolic Wastes." Industrial Wastes,
Vol. 4, No. 4, p. 57, July, 1959. '
156. Yanysheva, N. Ya., et. al., "The 3,4-Benzopyrene Content of Coke and
Chemical Works Affluent," Coke and Chemistry USSR, Vol. 10, pp. 39-40,
1963. —'
157. Pritsker, A. S., et. al., "Dephenolizing Effluents by Use of Coal Tar Oil,"
Coke and Chemistry USSR, Vol. 11, pp. 48-49, 1960.
158. Clough, G. F. G., "Biological Oxidation of Phenolic Waste Liquor/1
Chemical and Process Engineering and Atomic World, Vol. 42, No. 1,
pp. 11-14, January, 1961.
159. Davis, W. R., "Control of Stream Pollution at Bethlehem Plant," Iron and
Steel Engineer; Vol. 45, No. 11, pp. 135-140, November, 1968i
160. Eisenhauer, H. R., "Ozanization of Phenolic Wastes," WPCF J, Vol. 40
pp. 1887-1899, November, 1968. '
-201-
-------
SECTION XIII
GLOSSARY AND ABBREVIATIONS
GLOSSARY
]. Ammoniacal Liquor-An impure solution of ammonia obtained as a by product
of destructive distillation.
2. Annular space - Void in the area around the oil well casing.
3. Benzopyrene -Yellow crystal line cancer-producing hydrocarbon ^20^12 found
in coal tar.
4. Carbonization - Conversion of coal to carbon by destructive distillation through
the action of heat.
5. Carcinogen-A substance producing or inciting cancerous growth.
6. Free-water knock out treater - Gravity separator to remove water from crude
oil.
7. Gasification - Conversion of coal into gas by burning or by reaction with oxygen
and superheated steam.
8. Hydrogenation - Decomposition of coal at high temperature and pressure with
addition of hydrogen to form gasoline and oils.
9. Ranney collector - A concrete caisson set in the river sand, with perforated
laterals running out from the caisson, to obtain filtered water.
10. Shut-in - Condition existing when an oil well is sealed at the surface to prevent
fluid movement.
11. Solvent Refined Coal (SRC) - Reconstituted coal which has been dissolved, fil-
tered, and separated from its solvent.
12. Torr - Pressure exhibited by a column of mercury one (1) millimeter high.
13. Yellowboy - Produced as a result of acid mine drainage and the process of
hydrophis. It is formed when ferrous sulfate is oxidized into ferric hydroxide
and sulfuric acid. Ferric hydroxide forms a yellowish-brown sediment on the
bottom of stream beds.
-203-
-------
ABBREVIATIONS
1 . b/d - Barrels per day.
2. bc/d - Barrels of crude per day.
3. b/sd - Barrels per stream day (operating day).
4. BOD - Biochemical Oxygen Demand can be defined as the amount of oxygen
required by bacteria while stabilizing decomposable organic matter under
aerobic conditions.
5. COD - Chemical Oxygen Demand test measures the total quantity of oxygen
required for oxidation to carbon dioxide and water.
6. dwt - Dead weight tons
7. eV - Electron volt.
8. FWQA - Federal Water Quality Administration
9. G/BCD - Gallons of water per barrel of crude oil throughput per day.
10. gpm - Gallons per minute.
11. Lbs/D/MBCD - Pounds per day per thousand barrels of crude oil throughput
per day.
12. M-Mesh
13. MBCD - Thousands of barrels of crude oil throughput per day.
14. mg/l - Milligram per liter.
15. ml - Milliliter.
16. MMbtu - Million British Thermal Units.
17. MMGD - Millions of gallons of water per day.
18. NHg(N) - Ammonia nitrogen.
19, P- Phosphate.
20. ppm - parts per million.
-204-
-------
21. ppb -parts per billion
22. pH - Negative logarithm of the hydrogen ion concentration; it is a measure
of acidity.
23. rad - Radiation dose (an absorbed dose of 100 ergs/g).
24. SRC - Solvent refined coal.
25. W/W - Weight-weight bases.
26. * - Values less than 0.01 (included in weighted average computations).
-205-
«U.S. GOVERNMENT PRINTING OFFICE:1973 136-514/151 1-3
-------
Number
Subject Fivld &. Group
05D
SELECTED WATER RESOURCES ABSTRACTS
INPUT TRANSACTION FORM
Oklahoma University, Norman
Research Institute
Title
Evaluation of Waste Waters From Petroleum and Coal Processing
10
Aulliot(s)
Reid, George W.
Streebin, Leale E.
Rumfeldt, David W.
Sweazy, Robert
16
21
Project Designation •
FWQA 12050 DKF
Note
22
Citation
Environmental Protection Agency report
number EPA-R2-72-001, December 1972
23
Descriptors (Starred First)
*Oil Wastes, *Coal Wastes, *Waste Water Reclamation, *Water Pollution, Oil Well, Brine Dis-
posal, Secondary Recovery (Oil)/ Injection, Strip Mines, Mine Acids, Mining
25
Identifiers (Starred First)
27
Refining, Drilling-Production, Refinery Classification, Transportation and Storage (Oil), Coal
Processing, Coal Utilization
Abstract
The purpose of this study was to evaluate pollution problems, abatement procedures, and control tech-
niques relevant to the petroleum and coal industries. Petroleum wastes are discussed under three broad
categories: 1) Drilling-Production, 2) Transportation and 3) Storage, and Refining. Within each
section, petroleum wastes are identified as to their source, volume, and composition, and waste treat-
ment methods are discussed.' The results of a field study, delineating the characteristics of waste streams
from individual processes within a refinery are reported. Coal mining, processing and utilization, the
wastes associated with each, and the corresponding control measures are discussed. Acid mine drain-
age, the most significant pollution problem from coal mining, is discussed. The principal pollutants
generated from the processing of coal are suspended solids usually in the form of fine clay, black shale,
and other minerals associated with coal. Coal is commonly used for the production of coke. This process
producesa waste high in phenols, ammonia, and dissolved organics. Waste characteristics and treatment
efficiencies are tabulated in the report and process and treatment schematic diagrams are presented.
This report contains 160 references.
Abstractor
_ Leale E. jtreebin
WHSIC
IPI;V. JULY tg<>9>
.
University. .9.L.Qi5johprna_
SE.MD.WITM C OPV OF DOCUMENT, TO: W AT >.R H U SOURCES SC ILIM1 IF 1C INKOKMATION C tN :
U.S. Clt I'AHT ME1N1 OF TMC INTERIOR
W ASHINOT ON. C. C. 20240
------- |