Development Document for Effluent Limitations Guidelines
and New Source Performance Standards for the
PETROLEUM REFINING
Point Source Category
APRIL 1974
S t u-s- ENVIRONMENTAL PROTECTION AGENCY
° Washington, D.C. 20460
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DEVELOPMENT DOCUMENT
for
EFFLUENT LIMITATIONS GUIDELINES
and
NEW SOURCE PERFORMANCE STANDARDS
for the
PETROLEUM REFINING
POINT SOURCE CATEGORY
Russell E. Train
Administrator
James L. Agee
Assistant Administrator for Water and Hazardous Materials
Allen Cywin
Director, Effluent Guidelines Division
Martin Halper
Project Officer
April 1974
Effluent Guidelines Division
Office of Water and Hazardous Materials
U.S. Environmental Protection Agency
Washington, D.C. 20460
For sale by the Superintendent of Documents, U.S. Government Printing Office, Washington, 0.C. 20402 - Price $2.75
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ABSTRACT
This development document presents the findings of an extensive
study of the Petroleum Refining Industry for the purposes of
developing effluent limitation guidelines, standards of
performance, and pretreatment standards for the industry to
implement Sections 304, 306 and 307 of the Federal Water
Pollution Control Act of 1972, (PL 92-500) . Guidelines and
standards were developed for the overall petroleum refining
industry, which was divided into five subcategories.
Effluent limitation guidelines contained herein set forth the
degree of reduction of pollutants in effluents that is attainable
through the application of best practicable control technology
currently available (BPCTCA), and the degree of reduction
attainable through the application of best available technology
economically achievable (BATEA) by existing point sources for
July 1, 1977, and July 1, 1983, respectively. Standards of
performance for new sources are based on the application of best
available demonstrated technology (BADT).
Annual costs for the petroleum refining industry for achieving
BPCTCA Control by 1977 are estimated at $244,000,000, and the
additional annual costs for attaining BATEA Control by 198C are
estimated at $250,000,000. The estimated annual costs for BADT
for new sources is $26,000,000.
Supporting data and rationale for the development of proposed
effluent limitation guidelines and standards of performance are
contained in this development document.
iii
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CONTENTS
Section
ABSTRACT
CONTENTS v
FIGURES x
TABLES xi
I CONCLUSIONS 1
II RECOMMENDATIONS 3
III INTRODUCTION 11
Purpose and Authority 11
Methods Used for Development of the Effluent 12
Limitation Guidelines and Standard of
Performance
General Description of the Industry 14
Storage and Transportation 19
Crude Oil and Product Storage 19
Process Description
Wastes
Trends
Ballast Water 20
Process Description
Wastes
Treands
Crude Desalting 20
Process Description
Wastes
Trends
Crude Oil Fractionation 22
Process Description
Prefractionation and Atmospheric Distillation
(Topping or Skimming)
Vacuum Fractionation
Three Stage Crude Distillation
Wastes
Trends
Cracking 25
Thermal Cracking 25
Process Description
Wastes
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Section
Trends
Catalytic Cracking 26
Process Description
Wastes
Trends
Hydrocracking og
Process Description
Wastes
Trends
Hydrocarbon Rebuilding 29
Polymerization 29
Process Description
Wastes
Trends
Alkylation 29
Process Description
Wastes
Trends
Hydrocarbon Rearrangements 30
Isomerization 30
Process Description
Wastes
Trends
Reforming 3]
Process Description
Wastes
Trends
Solvent Refining 32
Process Description
Wastes
Trends
Hydrotreating 33
Process Description
Wastes
Trends
Grease Manufacture 34
Process Description
Wastes
Trends ._
Asphalt Production "*&
Process Description
Wastes
Product Finishing 35
Drying and Sweetening 35
Process Description
Wastes
Trends
vi
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Section
Lube Oil Finishing
Process Description
Wastes
Trends _
Blending and Packaging
Process Description
Wastes
Trends
Auxiliary Activities 37
Hydrogen Manufacture 37
Process Description
Wastes
Trends
Utilities Function 39
Refinery Distribution 42
Anticipated Industry Growth 48
IV INDUSTRY SUBCATEGORIZATION 55
Discussion of the Rationale of Subcategorization 55
Development of the Industry Subcategorization 55
Subcategorization Results 59
Analysis of the Subcategorization 5S
Topping Subcategory
Low and High Cracking Subcategory
Petrochemical Subcategory
Lube Subcategory
Integrated Subcategory
Conclusion 6
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Section
Hexane ExCractables - Oil and Grease
Ammonia as Nitrogen
Phenolic Compounds
Sulfides
Total Chromium
Hexavalent Chromium
Other Pollutants 81
Zinc
IDS
Cyanides
pll (Acidity and Alkalinity)
Temperature
Other Metallic Ions
Chlorides
Fluorides
Phosphates
VII CONTROL AND TREATMENT TECHNOLOGY 91
In-Plant Control/Treatment Techniques 91
Housekeeping
Process Technology
Cooling Towers
Evaporative Cooling Systems
Dry Cooling Systems
Wet Cooling Systems
At-Source Pretreatment 95
Sour Water Stripping
Spent Caustic Treatment
Sewer System Segregation
Storm Water Runoff
Gravity Separation of Oil
Further Removal of Oil and Solids Clarifiers
End-of-Pipe Control Technology 102
Equalization
Dissolved Air Flotation
Oxidation Ponds
Aerated Lagoon
Trickling Filter
Bio-Oxidation Tower
Activated Sludge
Physical Chemical Treatment
Flow Reduction Systems
Granular Media Filters
Activated Carbon
vill
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Section Page
Sludge Handling and Disposal 111
Digestion
Vacuum Filtration
Centrifugation
Sludge Disposal
Landfilling
Incineration
VIII COST, ENERGY, AND NON-WATER QUALITY ASPECTS 113
BPCTCA Treatment Systems Used For Economic Evaluation
BATEA Treatment Systems Used For Economic Evaluation
Estimated Costs of Facilities
Non-Water Quality Aspects
IX BEST PRACTICABLE CONTROL TECHNOLOGY CURRENTLY 143
AVAILABLE—EFFLUENT LIMITATIONS
Procedure for Development of BPCTCA Limitations
Application of Oxygen Demand Limitations
Variability Allowance for Treatment Plant Performance
X BEST AVAILABLE TECHNOLOGY ECONOMICALLY ACHIEVABLE— 169
EFFLUENT LIMITATIONS
Flow
Procedure for Development for BATEA Effluent Limitations
Statistical Variability of a Properly Designed and
Operated Waste Treatment Plant
XI NEW SOURCE PERFORMANCE STANDARDS 175
Procedure for Development of BADT Effluent Limitations
Variability Allowance for Treatment Plant Performance
XII ACKNOWLEDGEMENTS 179
XIII BIBLIOGRAPHY :i81
XIV GLOSSARY AND ABBREVIATIONS 187
ix
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LIST OF FIGURES
Figure No. Title Pnge No.
1 Crude Desalting (Electrostatic Desalting) 21
2 Crude Fractionation (Crude Distillation, 24
Three Stages)
3 Catalytic Cracking (Fluid Catalytic Cracking) 27
4 Geographical Distribution of Petroleum 44
Refineries in United States
5 Hypothetical 100,000 Barrel/Stream Day 45
Integrated Refinery
6 BPCTCA - Wastewater Treatment System 132
7 BATEA - Proposed Treatment 136
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TABLES
Table No. Title Page No.
1 Topping Subcategory Effluent Limitations 4
2 Cracking Subcategory Limitations 5
3 Petrochemical Subcategory Effluent
Limitations 6
4 Lube Subcategory Effluent Limitations 7
5 Integrated Subcategory Effluent Limitations 8
6 Runoff and Ballast Effluent Limitations 9
7 Intermediates and Finished Products
Frequently Found in the Petroleum Refining
Industry 15
8 Major Refinery Process Categories 17
9 Qualitative Evaluation of Wastewater Flow
and Character!'sites by Fundamental Refinery
Processes 18
10 Crude Capacity of Petroleum Refineries by
States as of January 1, 1974 (3) 43
11 Process Employment of Refining Processes as
of January 1, 1973 (3) 446
12 Trend in Domestic Petroleum Refining from
1967 to 1973 47
13 1972 Consumption of Petroleum Feedstocks 49
14 Sources of Supply for U. S. Petroleum Feed-
stocks 50
15 Characteristics of Crude Oils from Major
Fields Around the World 51-53
xi
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Table No. Title Page No.
16 Subcategorization of the Petroleum 60
Refining Industry Reflecting Significant
Differences in Waste Water Characteristics
17 Median Net Raw Waste Loads from Petroleum 61
Refining Industry Categories
18 Topping Subcategory Raw Waste Load 64
19 Cracking Subcategory Raw Waste Load 65
20 Petrochemical Subcategory Raw Waste Load 66
21 Lube Subcategory Raw Waste Load 67
22 Integrated Subcategory Raw Waste Load 68
23 Waste Water Flow from Petroleum Refineries 70
Using 3% or Less once-Through Cooling
Water for Heat Removal
24 Significant Pollutant Parameters for the 72
Petroleum Refining Industry
25 Mettalic Ions Commonly Found in Effluents 87
from Petroleum Refineries
26 Observed Refinery Treatment Systems and 104
Effluent Loadings
27 Expected Effluents from Petroleum Treatment 105
Processes
28 Typical Removal Efficiencies for Oil Refinery 106
Treatment Processes
29 Estimated Total Annual Costs for End-of-Pipe 114
Treatment Systems for the Petroleum Refining
Industry (Existing Refineries)
30 Summary of End-of-Pipe Waste Water Treatment 115
Costs for Representative Plants in the
Petroleum Refinery Industry
xii
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Table No. Title Page No.
31 Water Effluent Treatment Costs Petroleum 117
Refining Industry - Topping Subcategory
32 Water Effluent Treatment Costs Petroleum 118
Refining Industry - Topping Subcategory
33 Water Effluent Treatment Costs Petroleum 119
Refining Industry - Topping Subcategory
34 Water Effluent Treatment Costs Petroleum 120
Refining Industry - Cracking Subcategory
35 Water Effluent Treatment Costs Petroleum 121
Refining Industry - Cracking Subcategory
36 Water Effluent Treatment Costs Petroleum 122
Refining Industry - Cracking Subcategory
37 Water Effluent Treatment Costs Petroleum 123
Refining Industry - Petrochemical Sub-
category
38 Water Effluent Treatment Costs Petroleum 124
Refining Industry - Petrochemical Sub-
category
39 Water Effluent Treatment Costs Petroleum 125
Refining Industry - Petrochemical Sub-
category
40 Water Effluent Treatment Costs Petroleum 126
Refining Industry - Lube Subcategory
41 Water Effluent Treatment Costs Petroleum 127
Refining Industry - Lube Subcategory
42 Water Effluent Treatment Costs Petroleum 128
Refining Industry - Lube Subcategory
43 Water Effluent Treatment Costs Petroleum 129
Refining Industry - Integrated Subcategory
44 Water Effluent Treatment Costs Petroleum 130
Refining Industry - Integrated Subcategory
xm
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Table No. Title Page No.
45 Water Effluent Treatment Costs Petroleum 131
Refining Industry - Integrated Subcategory
46 BPCTCA - End-of-Pipe Treatment System 133-135
Design Summary
47 BATEA - End-of-Pipe Treatment System Design 137
Summary
48 Attainable Concentrations from the Applica- 145
tion of Best Practicable Control Technology
Currently Available
49 BPCTCA - Petroleum Refining Industry Effluent 147
Limitations (Annual Average Daily Limits)
50 Variability Factors 149
51 Petroleum Refining - Process Breakdown 151-168
52 Flow Basis for Developing BATEA Effluents 171
Limitations
53 BATEA Reductions in Pollutants Loads Achiev- 172
able by Application of Activated Carbon to
Media Filtration Effluent (BPCTCA)
54 BATEA - Petroleum Refining Industry Effluent 173
Limitations (Annual Daily Limits)
55 Variability Factors for BATEA 174
56 BADT - New Source Performance Standards for 176
the Petroleum Refining Industry (Annual
Average Daily Limits)
57 Metric Units Conversion Table 178
xiv
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SECTION I
CONCLUSIONS
This study covered the products included in the Petroleum
Refining Industry (SIC 2911). The 252 U.S. petroleum refineries
currently process 2.2 million cubic meters (14 million barrels)
of crude oil per stream day. U.S. refineries vary in complexity
from the very small, with simple atmospheric fractionation, or
topping, to the very large integrated refineries manufacturing a
multitude of petroleum and petrochemical products from a variety
of feedstocks. The raw waste water load is dependent upon the
types of processes employed by the refinery, justifying the
utilization of production process groupings, as delineated by
their effects on raw waste water as the basis for the
subcategorization. The subcategories developed for the petroleum
refining industry for the purpose of establishing effluent
limitations are as follows:
Subcategory
Topping
Cracking
Basic Refinery Operations Included
Topping, catalytic reforming, asphalt
production, or lube oil manufacturing
processes, but excluding any facility with
cracking or thermal operations.
Topping and cracking.
Petrochemical Topping, cracking
operations.*
and
petrochemicals
Lube
Integrated
Topping, cracking and lube
processes.
oil manufacturing
Topping, cracking, lube oil manufacturing
processes and petrochemicals operations.*
* The term "petrochemical operations" shall mean the production
of second generation petrochemicals (i.e. alcohols, ketones,
cumene, styrene, etc.) or first generation petrochemicals and
isomerization products (i.e. BTX, olefins, cyclohexane, etc.)
when 15% or more of refinery production is as first generation
petrochemicals and isomerization products.
All five subcategories generate waste waters which contain
similar constituents. However, the concentration and loading of
these constituents, termed "raw waste load," vary between the
subcategories. Existing control and treatment technology, as
practiced by the industry, includes both end-of-pipe treatment
and in-plant reductions. Many of the individual wastewater
streams, such as sour waters, have a deleterious effect on
biological treatment facilities and/or receiving waters.
Consequently, these individual streams are pretreateci in-plant,
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prior to discharge to waste water facilities. Current technology
for end-of-pipe treatment involves biological treatment and
granular media filtration. Biological treatment systems employed
include activitated sludge plants and aerated lagoons and
stabilization pond systems.
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SECTION II
RECOMMENDATIONS
The significant waste water constituents are BOD5, COD, TOC,
total suspended solids, oil and grease, phenolic compounds,
ammonia (N), sulfides, total and hexavalent chromium. These
waste water constituents were selected to be the subject of the
effluent limitations.
Effluent limitations commensurate with the best practical control
technology currently available are proposed for each refinery
subcategory. These limitations, listed in Tables 1-6 are
explicit numerical values for the allowable discharges within
each subcategory. Implicit in BPCTCA in-process technology is
segregation of non-contact waste waters from process waste water.
BPCTCA end-of-pipe technology is based on the application of the
existing waste water treatment processes currently used in the
Petroleum Refining Industry. These consist of equilization and
storm diversion; initial oil and solids removal (API separators
or baffle plate separators); further oil and solids removal
(clarifiers, dissolved air flotation, or filters); carbonaceous
waste removal (activated sludge, aerated lagoons, oxidation
ponds, trickling filter, activated carbon, or combinations of
these); and filters (sand, dual media; or multi-media) following
biological treatment methods. The variability of performance of
biological waste water treatment systems has been recognized in
the development of the BPCTCA effluent limitations.
Effluent limitations commensurate with the best available
technology economically achievable are proposed for each
subcategory. These effluent limitations are listed in Tables 1-
6. The limitations are explicit numerical values for the
allowable discharges within each subcategory. The primary end-
of-pipe treatment proposed for BATEA effluent limitations is
activated carbon adsorption, as further treatment in addition to
BPCTCA control technology. Also implicit in BATEA technology are
achievable reductions in waste water flow.
New source performance standards commensurate with the best
available demonstrated technology are based on the flows
achievable with BATEA technology, and the end-of-pipe control
technology achievable with BPCTCA technology. These BADT
effluent limitations are listed in Tables 1-6. Activated carbon
adsorption has not been included as BADT technology, since the
use of this technology has not been sufficiently demonstrated, at
this time, on petroleum refining waste water to insure its
applicability and reliability on secondary effluent waste waters
from refineries.
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BPCTCA
Effluent
limitations
Table 1
Petroleum Refining Industry Effluent Limitations
Topping Subcategory
(a )
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Table 2
Petroleum Refining Industry Effluent Limitations
Cracking Subcategory
BPCTCA
Effluent
limitations
BATEA
Effluent
limitations
BADT
Effluent
limitations
Maximum for
any one day
Average of daily
values for thirty
consecutive days
shall not exceed
Maximum for
any one day
Average of daily
values for thirty
consecutive days
shall not exceed
Maximum for
any one day
Average of daily
values for thirty
consecutive days
shall not exceed
(Metric units)
RODS
1SS
COO*
Oil and grease
Phenolic compounds
Ammonia as N
Sulfide
Total chromium
!!i;xsvalent chromium
oil
(English units)
MODS
T.SS ~
COD*
Oil and grease
Phenolic compounds
A.MUNonia as N
.S'llfi.le
T'ltal chromium
licxavalent chromium
pll
kg/k cu m of feedstock
28.2
17.1
210
8.4
0.21
18.8
0. 18
0.43
0. 0087
15.6
10.2
109
4.5
0.10
8.5
a 082
0.25
0.0040
Within the range 6.0 to 9.0
Ib/Mbbl of feedstock
9.9
6.1
74
3.0
0.074
6.6
0.065
0.15
0.0031
5.5
3.6
38.4
1.6
0.036
3.0
0.029
0.088
0.0014
kg/k cu m of feedstock
3.4
3.2
19.2
0.68
0.016
4.6
0.075
0.16
0.0035
2.7
2.7
15.4
0.54
0.011
3.5
0.048
0.14
0.0022
Within the range 6. 0 to 9. 0
Ib/Mbbl of feedstock
1.2
1.2
6.8
0.24
0. 0055
1.6
0.026
0.058
0.0013
0.99
0.99
5.4
0.19
0.0039
1.2
0.017
0.049
0. 0008
kg/k cu m of feedstock
16.3
9. 9
118
4.8
0.119
18.8
0.105
0.24
0.0050
8. 7
5.8
61
2. 6
0.058
8.6
0.048
0. 14
0.0022
Within the range 6. 0 to 9. 0
Ib/Mbbl of feedstock
5.8
3.5
41.5
1.7
0.042
6. 6
0.037
0.084
.0018
3.1
2.0
21
0. 93
0.020
3.0
0.017
0.049
0.00081
Within the range 6. 0 to 9. 0
Within the range 6. 0 to 9. 0
Within the range 6. 0 to 9. 0
(nl The limits H<:t forth above are to be
ir.utiiplicd by the following factors to
arrivt: at the maximum for any one day
atid the maximum average of daily values
for thirty consecutive days.
(1) Size factor
Mbbl of feedstock per stream day
0 - 34. 9
35 - 74.9
75 - 109.9
110 - 149.9
150 or greater
'•'•i> 'I hi.- a;l(ln 'onnl ;il lo<-a! ions to be applied whore appropiatc for
storm v.uu.r i-uiioi'f und ballast water are in Table 6.
Size factor
0.89
1.00
1.14
1.31
1.41
(2) Process factor
Process configuration
1. 5 - 3.49
3. 50 - 5.49
5.50 - 7.49
7.50 - 9.49
9. 50 - 1 0. 5 or greater
Process factor
0.58
0.81
1.13
1.60
1.87
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BPCTCA
Effluent
limitations
Table 3
Petroleum Refining Industry Effluent Limitations
Petrochemical Subcategory
BATEA
Effluent
limitations
BADT
Effluent
limitations
Maximum for
any one day
Average of daily
values for thirty
consecutive days
shall not exceed
Maximum for
any one day
Average of daily
values for thirty
consecutive days
shall not exceed
Maximum for
any one day
Average of daily
values for thirty
consecutive days
shall not exceed
(Metric units)
BODS
TSS~
COD*
Oil and grease
Phenolic compounds
Ammonia as N
bull'id e
Total chromium
llexavalent chromium
pH
(English units)
BOD5
TSS~
COD*
Oil and grease
Phenolic compounds
Ammonia as N
Sulfide
Total chromium
Hexavalent chromium
PH
kg/k cu m of feedstock
34.6
20.6
210
11.1
0.25
23.4
0. 22
0.52
0.0115
18.4
12.0
109
5.9
0.120
10.6
0.099
0. 30
0.0051
Within the range 6. 0 to 9. 0
Ib/Mbbl of feedstock
1 2.1
7.3
74
3.9
0.088
8.25
0.078
0.183
0.0040
6.5
4.25
38.4
2.1
0. 0425
3.8
0.035
0.107
0.0018
kg/k cu m of feedstock
4.6
4.4
22
0. 90
0.022
5.6
0. 099
0.22
0.0048
3. 7
3.7
17
0. 72
0.015
4.2
0.063
0.19
0.0031
Within the range 6. 0 to 9. 0
Ib/Mbbl of feedstock
1.7
1.6
7.6
0. 32
0. 0077
2.0
0.035
0. 080
0.0017
1.3
1. 3
6.1
0.26
0. 0054
1.5
0.022
0.068
0.0011
kg/k cu m of feedstock
21.8
13.1
133
6. 6
0.158
23.4
0. 140
0.32
0.0062
11.6
7.7
69
3.5
0.077
10.7
0.063
0. 19
0.0031
Within the range 6. 0 to 9. 0
Ib/Mbbl of feedstock
7.7
4. 6
47
2.4
0.056
8.3
0.050
0.116
0. 0024
4.1
2.7
24
1.3
0.027
3.8
0.022
0.068
0. 0011
W ithin the range 6. 0 to 9.0
Within the range 6. 0 to 9. 0
Within the range 6. 0 to 9. 0
(a) The limits set forth above are to be
"multiplied by the following factors to
arrive at the maximum for any one day
and the maximum average of daily values
for thirty consecutive days.
(1) Size factor
Mbbl of feedstock per stream day
0-49.9
50 - 99.9
100 - 149. 9
150 or greater
Size factor
0.73
0.87
1.04
1.13
(2) Process factor
Process configuration
3.25 - 4.74
4. 75 - 6.74
6. 75 - 8.74
8. 75 - 10.25 or greater
Process factor
0.67
0.91
1.27
1.64
(b) The additional allocations to be applied where appropiate for
»torm water runoff and ballast water are in Table 6.
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BPCTCA
Effluent
limitations
Table 4
Petroleum Refining Industry Effluent Limitations
Lube Subcategory
(a)(b)
BATEA
Effluent
limitations
BADT
Effluent
limitations
Maximum for
any one day
Average of daily
values for thirty
consecutive days
shall not exceed
Maximum for
any one day
Average of daily
values for thirty
consecutive days
shall not exceed
Maximum for
any one day
Average of daily
values for thirty
consecutive days
shall not exceed
(Metric units)
BODS
rss~
COD*
Oil and grease
Phenolic compounds
Ammonia as N
bul fide
•fetal chromium
litrxavalent chromium
pll
(English units)
HODS
TSS
COD*
Oil and grease
Phenolic compounds
Ammon'a as N
Sulfide
Total chromium
Hexavalent chromium
pH
kg/k cu m of feedstock
50.6
31.3
360
16.2
0.38
23.4
0.33
0.77
0.017
25.8
18.4
187
8.5
0. 184
10.6
0.150
0.45
0.0076
W ithin the range 6. 0 to 9. 0
Ib/Mbbl of feedstock
17.9
11.0
127
5.7
0.133
8.3
0.118
0.273
0.0059
9.1
6. 5
66
3.0
0.065
3.8
0.053
0.160
0.0027
kg/k cu m of feedstock
7.8
7.4
40
1.4
0.034
5.6
0.16
0.36
0.0081
6.3
6.3
32
1. 1
0.024
4.2
0. 10
0.31
0. 0052
Within the range 6. 0 to 9. 0
Ib/Mbbl of feedstock
2.7
2.6
13.8
0.50
0.012
2.0
0.055-
0. 13
0.0029
2.2
2.2
11.0
0.40
0.0087
1.5
0.035
0.11
0.0018
kg/k cvi in of feedstock
34.6
20.6
245
10.5
0.25
23.4
0.22
0.52
0.0115
18.4
12.1
126
5. 6
0. 12
10.7
0.10
0.31
0.0052
W ithin the range 6. 0 to 9. 0
Ib/Mbbl of feedstock
12.2
7.3
87
3.8
0.088
8.3
0. OT8
0.180
0.0056
6.5
4. 3
45
2.0
0.043
3.8
0.035
0.105
0.0018
Within the range 6.0 to 9.0
Within the range 6. 0 to 9. 0
W ithin the range 6. 0 to 9. 0
(a) The limits set forth above are to be
multiplied by the following factors to
arrive at the maximum for any one day
and the maximum average of daily values
for thirty consecutive days.
(1) Size factor
Mbbl of feedstock per stream day
30 - 69.9
70 - 109.9
110 - 149. 9
150 - 199.9
200 or greater
(Ij) The additional allocations to be applied where appropiate for
storm water runoff and ballast water are in Table 6.
Size factor
0.71
0.81
0.93
1.09
1.19
(2) Process factor
Process configuration
6. 0 or less - 7. 99
8.0-9. 99
10.0 - 11. 99
12.0 - 14. 0 or greater
Process factor
0.88
1.23
1.74
2.44
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Table 5
Petroleum Refining Industry Effluent Limitations
Integrated Subcategory
BPCTCA
Effluent
limitations
BATEA
Effluent
limitations
BADT
Effluent
limitations
Maximum for
any one day
Average of daily
values for thirty
consecutive days
shall not exceed
Maximum for
any one day
Average of daily
values for thirty
consecutive days
shall not exceed
Maximum for
any one day
Average of daily
values for thirty
consecutive days
shall not exceed
(Metric units)
kc/k cu m of feedstock
j;()D5 54.4
lASS" 32.8
COO- 388
O il and grease 17.1
I'iienolic compounds 0.40
/\;;imonia as N 23.4
.SuH'idt- 0.35
Toial chromium 0.82
I !i-xavalfiit chromium 0.017
I'll
(English units)
W ithin the range 6. 0 to 9. 0
28.9
19.2
198
9.1
0.192
10.6
0.158
0.48
0.0079
Ib/Mbbl of feedstock
f!OD5 19.2
TSS 11.6
roD* 136
Oil and grease 6. 0
Phenolic compounds 0.14
Ammonia as N 8. 3
bulfide 0.124
Total chromium 0.29
[I'-xavalent chromium 0.0062
10.2
6.8
70
3.2
0.068
3.8
0.056
0. 17
0.0'028
kg/k cu m of feedstock
8.8
8.4
47
1.7
0.041
5.6
0.19
0.44
0.0092
7.1
7.1
38
1.4
0.029
4.2
0.12
0. 37
0.0059
W ithin the range 6. 0 to 9. 0
Ib/Mbbl of feedstock
3.2
3.0
16. 8
0. 60
0.015
2.0
0.066
0.15
0.0033
2.6
2.6
13.4
0.48
0.010
1.5
0.042
0.13
0.0021
kg/k cu m of feedstock
41.6
24.7
295
12.6
0.30
23.4
0.26
0.64
0.013
22.1
14.5
152
6.7
0.14
10.7
0. 12
0.37
0.0059
Within the range 6. 0 to 9. 0
Ib/Mbbl of feedstock
W ithin the range 6. 0 to 9. 0
Within the range 6.0 to 9.0
14. 7
8.7
104
4.5
0.105
8.3
0.093
0.220
0.0047
7.8
5.1
54
2.4
0.051
3.8
0.042
0.13
0.0021
W ithin the range 6. 0 to 9. 0
(u) The limits set forth above are to be
multiplied by the following factors to
arrive at the maximum for any one day
and the maximum average of daily values
for thirty consecutive days.
(1) Size factor
Mbbl of feedstock per stream day
70 - 144.9
150 - 219.9
220 or greater
Size factor
0. 69
0.89
1.02
(2) Process factor
Process configuration
6.0 or less - 7.49
7.5-8. 99
9.0 - 10. 5 or greater
Process factor
0.78
1.00
1.30
The additional allocations to be applied where appropiate for
riii water runoff and ballast water are in Table 6.
-------
Table 6
Petroleum Refining Industry Effluent Limitations
Storm Water Runoff and Ballast Water
>a) Runoff: The allocation being allowed for storm runoff flow shall be based solely on that
storm flow ( process area runoff ) which is treated in the main treatment system. All
additional storm runoff { from'tankfields and non-process areas ) that has been segregated
from tlit' main waste stream for discharge, shall not exceed a concentration of 35 mg/1 of
TOC or 15 mg/1 of oil and grease when discharged.
BPCTCA
Affluent
limitations
BATEA
Effluent
limitations
BADT
Effluent
limitations
Maximum for
any one day
Average of daily
values for thirty
consecutive days
shall not exceed
Maximum for
any one day
Average of daily
values for thirty
consecutive days
shall not exceed
Maximum for
any one day
Average of daily
values for thirty
consecutive days
shall not exceed
(Metric units)
kg/cu m of flow
roir-
( 5
i x . i)
(,hi i und gr^ati e
nil
0.40
0.24
3. 1
0. 126
0.21
0.14
1.6
0.067
V. ithin the range 6.0 to 9.0
kg/cu m of flow
0.0105 0.0085
0.010 0.0085
0.028 0.022
0.0020 0.0016
Within the range 6. 0 to 9. 0
Ib/Mgal of flow
0.088 0.071
0.084 0.071
0.24 0.19
0.018 0.014
Within the range 6.0 to 9.0
(M P.alla.st: The allocation being allowed for ballast water flow
ballast waters treated at the refinery.
BPCTCA
Effluent
limitations
shall be based on those
BATEA
Effluent
limitations
kg/cu m of flow
0.048
0.029
0.37
0.015
0.026
0.017
0. 10
0.0080
Within the range 6. 0 to 9. 0
Ib/Mgal of flow
0.40
0.24
3. 1
0. 126
0.21
0. 14
1.6
0.067
Within the range 6.0 to 9.0
BADT
Effluent
limitations
Maximum for
any one day
BGU5_
T56
C-CD*
Cil and grease
pH
Average of daily
values for thirty
consecutive days
shall not exceed
(Metric units)
0.048
0.029
0.47
0.015
Maximum for
any one day
Average of daily
values for thirty
consecutive days
shall not exceed
kg/cu m of flow
0.026
0.017
0.24
0.008
W ithin the range 6. 0 to 9. 0
(English units) Ib/Mgal of flow
UGD5
TSi ~
COD*
(A! and grease
I'M
0.40
0.24
3.9
0.126
0.21
0.14
2.0
0.067
Within the range 6.0 to 9.0
kg/cu m of flow
0.0105 0.0085
0.010 0.0085
0.038 0.030
0.0020 0.0016
Within the range 6.0 to 9. 0
Ib/Mgal of flow
0.088 0.071
0.084 0.071
0.32 0.26
0.018 0.014
Within the range 6.0 to 9.0
Maximum for
any one day
Average of daily
values for thirty
consecutive days
shall not exceed
kg/cu m of flow
0.048
0.029
0.47
0.015
0.026
0.017
0.24
0.0080
Within the range 6.0 to 9.0
Ib/Mgal of flow
0.40
0.24
3.9
0. 126
0.21
0. 14
2.0
0.067
Within the range 6. 0 to 9. 0
-------
-------
SECTION III
INTRODUCTION
Purpose and Authority
Section 301 (b) of the Act requires the achievement by no later
than July 1, 1977, of effluent limitations for point sources,
other than publicly owned treatment works, which are based on the
application of the best practicable control technology currently
available as defined by the Administrator, pursuant to section
304 (b) of the Act. Section 301 (b) also requires the achievement
by not later than July 1, 1983, of effluent limitations for point
sources, other than publicly owned treatment works, which are
based on the application of the best available technology
economically achievable, which will result in reasonable further
progress toward the national goal of eliminating discharge of all
pollutants, as determined in accordance with requlations issued
by the Administrator, pursuant to section 304 (b) of the Act.
Section 306 of the Act requires the achievement by new sources of
a Federal standard of performance providing for the control of
the discharge of pollutants which reflects the greatest degree of
effluent reduction which the Administrator determines to be
achievable through the application of the best available
demonstrated technology, processes, operative methods or other
alternatives, including, where practicable, a standard permitting
no discharge of pollutants.
Section 304(b) of the Act requires the Administrator to publish
within one year of enactment of the Act, regulations providing
guidelines for effluent limitations setting forth the degree of
effluent reduction attainable through the application of the best
practicable control technology currently available and the degree
of effluent reduction attainable through the application of the
best control measures and practices achievable including
treatment techniques, process and procedure innovations,
operation methods and other alternatives. The regulations
proposed herein set forth effluent limitations guidelines
pursuant to section 304 (b) of the Act for the petroleum refining
industry source category.
Section 306 of the Act requires the Administrator, within one
year after a category of sources is included in a list published
pursuant to section 306 (b) (1) (A) of the Act, to propose
regulations establishing Federal standards of performance for new
sources within such categories. The Administrator published in
the Federal Register of January 16, 1973 (38 F.R. 1624), a list
of 27 source categories. Publication of the list constituted
announcement of the Administrator's intention of establishing,
under section 306, standards of performance applicable to new
sources within the petroleum refining industry source category
which was included in the list published January 16, 1973.
11
-------
Methods Used for Development of the Effluent Limitations
Guidelines and Standards of Performance
The Office of Air and Water Programs of the Environmental
Protection Agency has been given the responsibility for the
development of effluent limitation guidelines and new source
standards as required by the Act. In order to promulgate the
required guidelines and standards, the following procedure was
adopted.
The point source category was first categorized for the purpose
of determining whether separate limitations and standards are
appropriate for different segments within a point source
category. Such sub-categorization was based upon raw materials
used, products produced, manufacturing processes employed, raw
waste loads, and other factors. This included an analysis of (1)
the source and volume of water used in the plant and the sources
of waste and waste waters in the plant; and (2) the constituents
(including thermal) of all waste waters (including toxic
constituents and other constituents) which result in taste, odor,
and color in water or aquatic organisms. The constituents of
waste waters which should be subject to effluent limitations
guidelines and standards of performance were identified.
The full range of control and treatment technologies existing
within each subcategory was identified. This included an
identification of each distinct control and treatment technology,
including both inplant and end-of-pipe technologies, which are
existent or capable of being designed for each subcategory. It
also included an identification, in terms of the amount of
constituents (including thermal) and the chemical, physical, and
biological characteristics of pollutants, of the effluent level
resulting from the application of each of the treatment and
control technologies. The problems, limitations, and reliability
of each treatment and control technology, and the required
implementation time was also identified. In addition, the
nonwater quality environmental impact (such as the effects cf the
applisubcation of such technologies upon other pollution
problems, including air, solid waste, noise, and radiation) was
also identified. The energy requirement of each of the control
and treatment technologies was identified, as well as the cost of
the application of such technologies.
The information, as outlined above, was then evaluated in order
to determine methods or other alternatives. In identifying such
technologies, various factors were considered. These included
the total cost of application of technology in relation to the
effluent reduction benefits to be achieved from such application,
the age of equipment and facilities involved, the processes
employed, the engineering aspects of the application of various
types of control techniques, process changes, nonwater quality
environmental impact (including energy requirements) and other
factors.
-------
During the initial phases of the study, an assessment was made of
the availability, adequacy, and usefulness of all existing data
sources. Data on the identity and performance of waste water
treatment systems within the petroleum refining industry were
known to be included in:
1. National Petroleum Refining Waste Water
Characterization Studies and the
Petroleum Industry Raw Waste Load Survey of 1972.
(EPA/API Raw Waste Load Survey).
2. Environmental Protection Agency (Refuse Act) Permit
Application.
3. Self-reporting discharge data from various states.
U. Monitoring data on individual refineries, collected
by state agencies and/or regional EPA offices.
A preliminary analysis of these data indicated an obvious need
for additional information. Although approximately 135
refineries were surveyed during the 1972 Raw waste Load Survey,
five activated sludge treatment plants were subjected to
intensive sampling for identification of waste water treatment
plant effluent performance. Identification of the types of
treatment facilities used by the other individual refineries
included no performance data.
Refuse Act Permit Application data are limited to identification
of the treatment systems used and reporting of final
concentrations (which were diluted with cooling waters in many
cases); consequently, operating performance could not be
established.
Self-reporting data was available from Texas, Illinois, and
Washington. These reports show only the final effluent
concentrations and identify the systems in use; rarely is there
production information available which would permit the
establishment of unit waste loads.
Monitoring data from the individual states and/or regional EPA
offices again show only the final effluent concentrations and
identify the systems in use. Rarely is production information
available to permit the establishment of unit waste loads.
Additional data in the following areas were therefore required:
1) currently practiced or potential in-process waste control
techniques; 2) identity and effectiveness of end-of-pipe waste
control techniques; and 3) long-term data to establish the
variability of performance of the end-of-pipe waste control
techniques. The best source of information was the petroleum
refineries themselves. New information was obtained from direct
interviews and inspection visits to petroleum refinery
facilities. Verification of data relative to long-term
performance of waste control techniques was obtained by the use
13
-------
of standard EPA reference samples to determine the reliability of
data submitted by the petroleum refineries, and by comparison of
the refinery data with monitoring data from the state agencies
and/or regional EPA offices.
The selection of petroleum refineries as candidates to be visited
was guided by the trial categorization, which was based on the
1972 Raw Waste Load Survey. The final selection was developed
from identifying information available in the 1972 Raw Waste Load
Survey, EPA Permit Applications, state self-reporting discharge
data, and contacts within regional EPA offices and the industry.
Every effort was made to choose facilities where meaningful
information on both treatment facilities and manufacturing
processes could be obtained.
Survey teams composed of project engineers conducted plant
visits. Information on the identity and performance of waste
water treatment systems were obtained through:
1. Interviews with plant water pollution control personnel.
2. Examinations of treatment plant design and historical
data (flow rates and analyses of influent and effluent).
3. Inspection of operations and analytical procedures, in-
cluding verification of reported analyses by the use of
EPA standard reference samples and by comparison of the
refinery data with monitoring data from state agencies
and/or regional EPA offices.
Information on process plant operations and associated waste
water characteristics were obtained through:
1. Interviews with plant operating personnel.
2. Examination of plant design and operating data.
3. Inspection of in-plant waste water controls.
The data base obtained in this manner was then utilized to
develop recommended effluent limitations and standards of
performance for the petroleum refining industry. All of the
references utilized are included in Section XIII of this report.
The data obtained during the field data collection program are
included in Supplement B.
General Description of the Industry
The industrial waste water profile covers the petroleum refining
industry in the United States, as defined by Standard Industrial
Classification (SIC) Code 2911 of the U.S. Department of
Commerce. Intermediates and finished products in this industry
are numerous and varied. Table 7 is a partial listing of these
products. The production of crude oil or natural gas from wells,
or the production of natural gasoline and other operations
14
-------
TABLE 7
Intermediates and Finished Products
Frequently Found in the Petroleum Refining Industry
SIC 2911
Acid Oil
Alkylates
Aromatic Chemicals
Asphalt and Asphaltic Materials:
Semi-Solid and Solid
Benzene
Benzol
Butadiene
Coke (Petroleum)
Fuel Oils
Gas, Refinery or Still Oil
Gases, (LPG)
Gasoline, except natural gasoline
Greases: Petroleum, mineral jelly,
lubricative, etc.
Jet Fuels
Kerosene
Mineral Oils, natural
Mineral Waxes, natural
Naphtha
Naphthenic Acids
Oils, partly refined
Paraffin Wax
Petroleums, nonmedicinal
Road Oils
Solvents
Tar or Residuum
15
-------
associated with such production, as covered under SIC Code 1311,
are not within the scope of this study. This study also does not
include distribution activities, such as gasoline service
stations. Transportation of petroleum products is covered only
to the extent that it is part of refinery pollution control, such
as the treatment of ballast water. Other activities outside the
scope of the SIC Code 2911 were included in the development of
raw waste load data, and are listed as auxiliary processes which
are inherent to an integrated refinery operation. Some of these
include soap manufacture for the production of greases, steam
generation, and hydrogen production.
A petroleum refinery is a complex combination of interdependent
operations engaged in the separation of crude molecular
constituents, molecular cracking, molecular rebuilding and
solvent finishing to produce the products listed under SIC code
2911. The refining operations may be divided among 12 general
categories, where each category defines a group of refinery
operations. The categories are listed in Table 8.
The characteristics of the waste water differ considerably for
different processes. Considerable knowledge is available that
can be used to make meaningful qualitative interpretations of
pollutant loadings from refinery processes. Such information is
presented in Table 9, a semi-graphic outline of the major sources
of pollutants within a refinery. In order to set forth the
character of the waste derived from each of the industry
categories established in Section IV, it is essential to study
the sources and contaminants within the individual production
processes and auxiliary activities. Each process is itself a
series of unit operations which causes chemical and/or physical
changes in the feedstock or products. In the commercial
synthesis of a single product from a single feedstock, there
generally are sections of the process associated with: the
preparation of the feedstock, the chemical reaction, the
separation of reaction products, and the final purification of
the desired product. Each unit operation may have drastically
different water usages associated with it. The type and quantity
of contact waste water are therefore directly related to the
nature of the various processes. This in turn implies that the
types and quantities of waste water generated by each plant's
total production mix are unique. The processes and activities
along with brief process descriptions, trends in applications,
and a delineation of waste water sources, are as follows:
16
-------
TABLE 8
Major Refinery Process Categories
1. Storage and Transporation
2. Crude Processes
3. Coking Processes
4. Cracking and Thermal Processes
5. Hydrocarbon Processing
6. Petrochemical Operations
7. Lube Manufacturing Processes
8. Treating and Finishing
9. Asphalt Production
10. Auxiliary Activities (Not listed under SIC Code 2911)
17
-------
TABLE 9
Qualitative Evaluation of Wastewater Flow and Characteristics
CD
Production
Piocesses
Crude Oil and
Product Storage
Crude Desalting
Crude Distill-
ation
Thermal Cracking
Catalytic Cracking
Hydrocracktng
Polymerization
Alkylatlon
Isomerlzatton
Reforming
Solvent Refining
Asphalt Blowing
Dewaxlng
Hyd retreating
Drying and
Sweete Ing
Flow BOD COD
XX X XXX
XX XX XX
XXX X X
XXX
XXX XX XX
X
X XX
XX X X
X
X 0 0
X X
XXX XXX XXX
X XXX XXX
XXX
XXX XXX X
by Fundamental Refinery Processes
Emulsified Am-
Phenol Sulflde Oil Oil pH Temp. monta Chloride Acldltv Alkalinity SUSP. Solids
X XXX XX 0 0 0 0 XX
X XXX X XXX X XXX XX XXX 0 X 3CXX
XX XXX XX XXX X XX XXX X OX X
XXX XX XX X X 0 XX X
XXX XXX X X XXX XX XXX X 0 XXX X
XX XX XX XX
OX XOXXXX X 0 X
0 XX X 0 XX Z X XX XX 0 XX
XXX OOZXOO 0 0
X 0 X X 0 OX
X XXX
X 0 X 0
XX 0 XX XX 0 0 X 0
XX 00 X XX 0 X 0 X X XX
XXX - Major Contribution. XX - Moderate Contribution,
X - Minor Contribution,
0 - No Problem .
— No Data
-------
1. STORAGE AND TRANSPORTATION
A. CRUDE OIL AND PRODUCT STORAGE
Process Description
Crude oil, intermediate, and finished products are stored in
tanks of varying size to provide adequate supplies of crude oils
for primary fractionation runs of economical duration, to
equalize process flows and provide feedstocks for intermediate
processing units, and to store final products prior to shipment
in adjustment to market demands. Generally, operating schedules
permit sufficient detention time for settling of water and
suspended solids.
Wastes
Waste waters associated with storage of crude oil and products
are mainly in the form of free and emulsified oil and suspended
solids. During storage, water and suspended solids in the crude
oil separate. The water layer accumulates below the oil, forming
a bottom sludge. When the water layer is drawn off, emulsified
oil present at the oil-water interface is often lost to the
sewers. This waste is high in COD and contains a lesser amount
of BODS. Bottom sludge is removed at infrequent intervals.
Additional quantities of waste result from leaks, spills, salt
"filters" (for product drying), and tank cleaning.
Intermediate storage is frequently the source of polysulfide
bearing waste waters and iron sulfide suspended solids. Finished
product storage can produce high BODS, alkaline waste waters, as
well as tetraethyl lead. Tank cleaning can contribute large
amounts of oil, COD, and suspended solids, and a minor amount of
BODS. Leaks, spills and open or poorly ventilated tanks can also
be a source of air pollution, through evaporation of hydrocarbons
into the atmosphere.
Trends
Many refineries now have storage tanks equipped to minimize the
release of hydrocarbons to the atmosphere. This trend is
expected to continue and probably accelerate. Equipment to
minimize the release of hydrocarbon vapors includes tanks with
floating-roof covers, pressurized tanks, and/or connections to
vapor recovery systems. Floating-roof covers add to the waste
water flow from storage tanks. Modern refineries impose strict
Bottom Sediment and Water (BSSW) specifications on crude oil
supplies, and frequently have mixed-crude storage tanks;
consequently, little or no waste water should originate from
modern crude storage. Another significant trend is toward
increased use of dehydration or drying processes preceding
product finishing. These processes significantly reduce the
water content of finished product, thereby minimizing the
quantity of waste water from finished product storage.
19
-------
B. BALLAST WATER
Process Description
Tankers which are used to ship intermediate and final products
generally arrive at the refinery in ballast (approximately 30
percent of the cargo capacity is generally required to maintain
vessel stability).
Wastes
The ballast waters discharged by product tankers are contaminated
with product materials which are the crude feedstock in use at
the refinery, ranging from water soluble alcohol to residual
fuels. In addition to the oil products contamination, drackish
water and sediments are present, contributing high COD, and
dissolved solids to the refinery waste water. These waste waters
are generally discharged to either a ballast water tank or
holding ponds at the refinery. In many cases, the ballast water
is discharged directly to the waste water treatment system, and
constitutes a shock load on the system.
Trends
As the size of tankers and refineries increases, the amount of
ballast waters discharged to the refinery waste water system will
also increase. The discharge of ballast water to the sea or
estuary without treatment, as had been the previous practice by
many tankers, is no longer a practical alternative for disposal
of ballast water. consequently, the ballast water will require
treatment for the removal of pollutants prior to discharge. The
use of larger ballast water storage tanks or ponds, for control
of flow into the waste water treatment system, should increase as
ballast water flow increases.
2. CRUDE DESALTING
Process Description
Common to all types of desalting are an emulsifier and settling
tank. Salts can be separated from oil by either of two methods.
In the first method, water wash desalting in the presence of
chemicals (specific to the type of salts present and the nature
of the crude oil) is followed by heating and gravity separation.
In the second method, water wash desalting is followed by
water/oil separation under the influence of a high voltage
electrostatic field acting to agglomerate dispersed droplets. In
either case, waste water containing various removed impurities is
discharged to the waste stream, while clean desalted crude oil
flows from the upper portion of the holding tank. A process flow
schematic of electrostatic desalting is shown in Figure 1.
wastes
20
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PROCESS
WATER
ELECTRICAL
POWER
DESALTED
CRUDE
EFFLUENT
WATER
HEATER
EMULSIFIER
Figure \
Crude Desalting
(Electrostatic Desalting)
21
-------
Much of the BS&W content in crude oil is caused by the "Load-on-
Top" procedure used on many tankers. This procedure can result
in one or more cargo tanks containing mixtures of sea waters and
crude oil, which cannot be separated by decantation while at sea,
and are consequently retained in the crude oil storage at the
refinery. While much of the water and sediment are removed from
the crude oil by settling during storage, a significant quantity
remains to be removed by desalting prior to processing of the
crude in the refinery.
The continuous waste water stream from a desalter contains
emulsified, and occasionally free oil, ammonia, phenol, sulfides,
and suspended solids. These pollutants produce a relatively high
BOD5 and COD. This waste water also contains enough chlorides
and other dissolved materials to contribute to the dissolved
solids problem in the areas where the waste water is discharged
to fresh water bodies. There are also potential thermal
pollution problems because the temperature of the desalting waste
water often exceeds 95°C (200°F).
Trends
Electrical desalting is currently used much more than chemical
desalting. In the future, chemical methods are expected to be
used only as a supplement where the crude has a very high salt
content. Two stage electrical desalting will become a more
prevelant process, as dirtier crude feedstocks are processed in
refineries. The growth in capacity of desalting units will
parallel the growth of crude oil capacity.
3. CRUDE OIL FRACTIONATION
Fractionation serves as the basic refining process for the
separation of crude petroleum into intermediate fractions of
specified boiling point ranges. The several alternative
subprocesses included are prefractionation and atmospheric
fractionation, vacuum fractionation, vacuum flashing, and three-
stage crude distillation.
Process Description
Prefractionation and Atmospheric Distillation (Topping or
Skimming)
Prefractionation is an optional distillation process to separate
economical quantities of very light distillates from the crude
oil. Lower temperature and higher pressure conditions are used
than would be required in atmospheric distillation. Some process
water can be carried over to the prefractionation tower from the
desalting process.
Atmospheric Distillation breaks the heated crude oil as follows:
1. Light overhead products (C5 and lighter) as in the case
of prefractionation.
22
-------
2. Sidestream distillate cuts of kerosene, heating and gas
oil can be separated in a single tower or in a series of
topping towers, each tower yielding a successively
heavier product stream.
3. Residual or reduced crude oil.
Vacuum Fractionation
The asphaltic residuum from the atmospheric distillation amounts
to 37 percent (U.S. average) of the crude charged. This
material is sent to vacuum stills, which recover additional heavy
gas oil and deasphalting feedstock from the bottoms residue.
Three Stage Crude Distillation
Three stage crude distillation, representing only one of many
possible combinations of equipment, is shown schematically in
Figure 2. The process consists of:
1. An atmospheric fractioning stage which produces lighter
oils;
2. An initial vacuum stage which produces well-fractioned,
lube oil base stocks plus residue for subsequent propane
deasphalting;
3. A second vacuum stage which fractionates surplus
atmospheric bottoms not applicable for lube production,
plus surplus initial vacuum stage residuum not required
for deasphalting. This stage adds the capability of
removing catalytic cracking stock from surplus bottoms
to the distillation unit.
Crude oil is first heated in a simple heat exchanger, then in a
direct-fired crude charge heater. Combined liquid and vapor
effluent flow from the heater to the atmospheric fractionating
tower, where the vaporized distillate is fractionated into
gasoline overhead product and as many as four liquid sidestreams
products:naphthaf kerosene, light and heavy diesel oil. Part of
the reduced crude from the bottom of the atmospheric tower is
pumped through a direct-fired heater to the vacuum lube
fractionator. Bottoms are combined and charged to a third
direct-fired heater. In the tower, the distillate is
subsequently condensed and withdrawn as two sidestreams. The two
sidestreams are combined to form catalytic cracking feedstocks,
with an asphalt base stock withdrawn from the tower bottom.
Wastes
The waste water from crude oil fractionation generally comes from
three sources. The first source is the water drawn off from
overhead accumulators prior to recirculation or transfer of
hydrocarbons to other fractionators. This waste is a major
source of sulfides and ammonia, especially when sour crudes are
23
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Atmospheric
Fr.iet ionator
Stabllizer
(
Vacuum Lube
Fract ionator
Propane Deasphalter Feed
Oesalter
Figure 2
CRUDE FRACTIONATI ON
(CRUDE DISTILLATION, THREE STAGES)
-------
being processed. It also contains significant amounts of oil,
chlorides, mercaptans and phenols.
A second waste source is discharged from oil sampling lines.
This should be separable but may form emulsions in the sewer.
A third possible waste source is the very stable oil emulsions
formed in the barometric condensers used to create the reduced
pressures in the vacuum distillation units. However, when
barometric condensers are replaced with surface condensers, oil
vapors do not come in contact with water; consequently, emulsions
do not develop.
Trends
The general industry trend to larger and more complete refineries
has been reflected also in larger and more complete crude
fractionation units. Thus, simple atmospheric "topping" units
are being replaced by the atmospheric- vacuum combinations with
an increasing number of sidestream products. Installed vacuum
fractionation capacity now totals, 0.8 million cu m/day (5
million bbl/day). (3) Modern refineries are installing surface
condensers to significantly reduce waste water loads from vacuum
operations.
4. CRACKING
A. THERMAL CRACKING
Process Description
This fundamental process is defined in this study to include
visbreaking and coking, as well as regular thermal cracking. In
each of these operations, heavy gas oil fractions (from vacuum
stills) are broken down into lower molecular weight fractions
such as domestic heating oils, catalytic cracking stock, and
other fractions by heating, but without the use of a catalyst.
Typical thermal cracking conditions are 480° - 603°C, (900°
1100°F) and 41.6 - 69.1 atm (600-1000 psig). The high pressures
result from the formation of light hydrocarbons in the cracking
reaction (olefins, or unsaturated compounds, are always formed in
this chemical conversion). There is also always a certain amount
of heavy fuel oil and coke formed by polymerization and
condensation reactions.
Wastes
The major source of waste water in thermal cracking is the
overhead accumulator on the fractionator, where water is
separated from the hydrocarbon vapor and sent to the sewer
system. This water usually contains various oil and fractions
and may be high in BOD5, COD, ammonia, phenol, and sulfides, and
may have a high alkalinity.
Trends
25
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Regular thermal cracking, which was an important process before
the development of catalytic cracking, is being phased out.
Visbreaking and coking units are still installed but, because of
product sulfur restrictions, to a lesser extent than before.
With the trends toward dirtier crudes containing more sulfur,
hydrocracking and propane deasphalting are receiving more
attention to recover salable products with low sulfur content
from the residuum.
B. CATALYTIC CRACKING
Process Description
Catalytic cracking, like thermal cracking, breaks heavy
fractions, principally gas oils, into lower molecular weight
fractions. This is probably the key process in the production of
large volumes of high-octane gasoline stocks; furnace oils and
other useful middle molecular weight distillates are also
produced. The use of a catalyst permits operations at lower
temperatures and pressures than with thermal cracking, and
inhibits the formation of undesirable polymerized products.
Fluidized catalytic processes, in which the finely powdered
catalyst is handled as a fluid, have largely replaced the fixed
bed and moving bed processes, which use a beaded or pelleted
catalyst. A schematic flow diagram of fluid catalytic cracking
is shown in Figure 3.
The process involves at least four types of reactions: 1)
thermal decomposition; 2) primary catalytic reactions at the
catalyst surface; 3) secondary catalytic reactions between the
primary products, and U) removal of polymerizable products from
further reactions by absorption onto the surface of the catalyst
as coke. This last reaction is the key to catalytic cracking
because it permits decomposition reactions to move closer to
completion than is possible in simple thermal cracking. Cracking
catalysts include synthetic and/or natural silica-alumina,
treated bentonite clay, Fuller's earth, aluminum hydrosilicates
and bauxite. These catalysts are in the form of beads, pellets,
and powder, and are used in either a fixed, moving or fluidized
bed. The catalyst is usually heated, lifted into the reactor
area by the incoming oil feed which, in turn, is immediately
vaporized upon contact. Vapors from the reactors pass upward
through a cyclone separator, which removes most of the entrained
catalyst. These vapors then enter the fractionator, where the
desired products are removed and heavier fractions recycled to
the reactor.
Wastes
Catalytic cracking units are one of the largest sources of sour
and phenolic wastewaters in a refinery. Pollutants from
catalytic cracking generally come from the steam strippers and
overhead accumulators on fractionators, used to recover and
separate the various hydrocarbon fractions produced in the
catalytic reactors.
26
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PRESSURE
REDUCING
ORIFICE
CHAMBER
u
is
FLUE GAS STEAM
GENERATOR U
COMBUSTION AIR11
O
RAW OIL
CHARGE
REACTOR
CATALYST
STRIPPER
F. EG EN ERATO R
COMBINED REACTOR
CHARGE
J L
J L
GAS AND GASOLINE TO
GAS CONCENTRATION PLANT
MAIN COLUMN
LIGHT CYCLE GAb OIL
»
HEAVY CYCLE GAS OIL.
A
HEAVY RECYCLE CHARGE
CLARIFIED SLURRY^
SLURRY
SETTLER
RAW OIL
SLURRY CHARGE
Figure 3
CATALYTIC CRACKING
(FLUID CATALYTIC CRACKING)
27
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The major pollutants resulting from catalytic cracking operations
are oil, sulfides, phenols, cyanides, and ammonia. These
pollutants produce an alkaline waste water with high BOD5 and COD
concentrations. Sulfide and phenol concentrations in the waste
water vary with the type of crude oil being processed, but at
times are significant. Regeneration of spent catalyst may
produce enough carbon monoxide and catalyst fines to constitute
an air pollution problem.
Trends
Recycle rates have been declining since 1968, and the trend is
expected to continue due to the development of higher activity
catalysts (molecular sieve catalysts, as opposed to high surface
area silica-alumina catalysts). The trend in subprocesses is
toward greater use of large fluid catalytic cracking in prefer-
ence to moving or fixed-bed cracking. Catalytic cracking units
are also being supplanted by hydrocracking and hydrotreating
processes. During 1972, a decline of 1.4 percent in fresh feed
catalytic cracking capacity was experienced in the United States.
(3)
C. HYDROCRACKING
Process Description
This process is basically catalytic cracking in the presence of
hydrogen, with lower temperatures and higher pressures than fluid
catalytic cracking. Hydrocracking temperatures range from 203° -
425°C (400° - 800°F), while pressures range from 7.8 - 137.0 atm
(100 to 2000 psig). Actual conditions and hydrogen consumption
depend upon the feedstock, and the degree of hydrogenation
required. The molecular weight distribution of the products is
similar to catalytic cracking, but with the reduced formation of
olefins.
Wastes
At least one waste water stream from the process should be high
in sulfides, since hydrocracking reduces the sulfur content of
the material being cracked. Most of the sulfides are in the gas
products which are sent to a treating unit for removal and/or
recovery of sulfur and ammonia. However, in product separation
and fractionation units following the hydrocracking reactor, some
of the HS will dissolve in the waste water being collected. This
water from the separator and fractionator will probably be high
in sulfides, and possibly contain significant quantities of
phenols and ammonia.
Trends
Hydrocracking has greater flexibility than catalytic cracking in
adjusting operations to meet changing product demands. For the
last few years, it has been one of the most rapidly growing
refining processes. This trend is expected to continue.
28
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5. HYDROCARBON REBUILDING
A. POLYMERIZATION
Process Description
Polymerization units are used to convert olefin feedstocks
(primarily propylene) into higher octane polymer units. These
units generally consist of a feed treatment unit (remove H2S,
mercaptans, nitrogen compounds), a catalytic reactor, an acid
removal section, and a gas stabilizer. The catalyst is usually
phosphoric acid, although sulfuric acid is used in some older
methods. The catalytic reaction occurs at 147° - 22U°C (300° -
435°F) , and a pressure of 11.2 - 137.0 atm (150 - 2000 psig).
The temperature and pressure vary with the individual subprocess
used.
Wastes
Polymerization is a rather dirty process in terms of pounds of
pollutants per barrel of charge, but because of the small
polymerization capacity in most refineries, the total waste
production from the process is small. Even though the process
makes use of acid catalysts, the waste stream is alkaline,
because the acid catalyst in most subprocesses is recycled, and
any remaining acid is removed by caustic washing. Most of the
waste material comes from the pretreatment of feedstock to the
reactor. The waste water is high in sulfides, mercaptans, and
ammonia. These materials are removed from the feedstock in
caustic acid.
Trends
Polymerization is a marginal process, since the product octane is
not significantly higher than that of the basic gasoline blending
stocks, and does not provide much help in upgrading the overall
motor fuel pool. In addition, alkylation yields per unit of
olefin feed are much better than polymerization yields.
Consequently, the current polymerization downtrend is expected to
continue.
B. ALKYLATION
Process Description
Alkylation is the reaction of an isoparaffin (usually isobutane)
and an olefin (propylene, butylene, amylenes) in the presence of
a catalyst at carefully controlled temperatures and pressures to
produce a high octane alkylate for use as a gasoline blending
component. Propane and butane are also produced. Sulfuric acid
is the most widely used catalyst, although hydrofluoric acid is
also used. The reactor products are separated in a catalyst
recovery unit, from which the catalyst is recycled. The
hydrocarbon stream is passed through a caustic and water wash
before going to the fractionation section.
29
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Wastes
The major discharge from sulfuric acid alkylation are the spent
caustics from the neutralization of hydrocarbon streams leaving
the sulfuric acid alkylation reactor. These waste waters contain
dissolved and suspended solids, sulfides, oils, and other
contaminants. Water drawn off from the overhead accumulators
contains varying amounts of oil, sulfides, and other
contaminants, but is not a major source of waste in this
subprocess. Most refineries process the waste sulfuric acid
stream from the reactor to recover clean acids, use it as if for
neutralization of other waste streams, or sell it.
Hydrofluoric acid alkylation units have small acid rerun units to
purify the acid for reuse. HF units do not have a spent acid or
spent caustic waste stream. Any leaks or spills that involve
loss of fluorides constitute a serious and difficult pollution
problem. Formation of fluosilicates has caused line plugging and
similar problems. The major sources of waste material are the
overhead accumulators on the fractionator.
Trends
Alkylation process capacity is currently declining slowly, but
this trend may be reversed, as the demand for low lead, high
octane gasoline increases.
6. HYDROCARBON REARRANGEMENTS
A. ISOMERIZATION
Process Description
Isomerization is a process technique for obtaining higher octane
motor fuel by converting light gasoline stocks into their higher
octane isomers. The greatest application has been, indirectly,
in the conversion of isobutane from normal butane, for uses as
feedstock for the alkylation process. In a typical subprocess,
the desulfurized feedstock is first fractionated to separate
isoparaffins from normal paraffins. The normal paraffins are
then heated, compressed, and passed through the catalytic
hydrogenation reactor which isomerizes the n-paraffin to its
respective high octane isomer. After separation of hydrogen, the
liquids are sent to a stabilizer, where motor fuel blending stock
or synthetic isomers are removed as products.
Wastes
Isomerization waste waters present no major pollutant discharge
problems. Sulfides and ammonia are not likely to be present in
the effluent. Isomerization waste waters should also be low in
phenolics and oxygen demand.
Trends
30
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The requirements for units to isomerize n-butane to isobutane
will not be as great in refineries where hydrocracking is being
installed, as the hydrocracking process yields an off-gas rich in
isobutane. However, the isomerization capacity of U.S. refiners
is not expected to decrease, but to continue to grow as the
demand for motor fuel grows.
B. REFORMING
Process Description
Reforming converts low octane naphtha, heavy gasoline, and
napthene-rich stocks, to high octane gasoline blending stock,
aromatics for petro-chemical use, and isobutane. Hydrogen is a
significant by-product of the process. Reforming is a mild
decomposing process, since some reduction occurs in molecular
size and boiling range of the feedstock. Feedstocks are usually
hydrotreated for the removal of sulfur and nitrogen compounds
prior to charging to the reformer, since the platinum catalysts
widely used are readily poisoned.
The predominant reaction during reforming is the dehydrogenation
of naphthenes. Important secondary reactions are the
isomerization and dehydrocyclization of paraffins. All three
reactions result in higher octane products.
One subprocess may be divided into three parts: the reactor
heater section, in which the charge plus recycle gas is heated
and passed over the catalyst in a series of reactions; the
separator drum, in which the reactor effluenr is separated into
gas and liquid streams, the gas being compressed for recycle; and
the stabilizer section, in which the separated liquid is
stabilized to the desired vapor pressure. There are many
variations in subprocesses, but the essential, and frequently the
only, difference is the composition of the catalyst involved.
Wastes
Reforming is a relatively clean process. The volume of waste
water flow is small, and none of the waste water streams has high
concentration of significant pollutants. The waste water is
alkaline, and the major pollutant is sulfide from the overhead
accumulator on the stripping tower used to remove light hydro-
carbon fractions from the reactor effluent. The overhead
accumulator catches any water that may be contained in the
hydrocarbon vapors. In addition to sulfides, the waste water
contains small amounts of ammonia, mercaptans and oil.
Trends
Reforming capacity in the U.S. is currently growing at about the
same rate as total crude capacity. This growth rate may
increase, however, as the demand for motor fuel grows.
31
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7. SOLVENT REFINING
Refineries employ a wide spectrum of contact solvent processes,
which are dependent upon the differential solubilities of the
desirable and undesirable feedstock components. The principal
steps are: counter-current extraction, separation of solvent and
product by heating and fractionation, and solvent recovery.
Napthenics, aromatics unsaturated hydrocarbons, sulfur and other
inorganics are separated, with the solvent extract yielding high
purity products. Many of the solvent processes may produce
process waste waters which contain small amounts of the solvents
employed. However, these are ususally minimized, because of the
economic incentives for reuse of the solvents.
Process Description
The major processes include:
Solvent Deasphalting - The primary purpose of solvent de-
asphalting is to recover lube or catalytic cracking feedstocks
from asphaltic residuals, with asphalt as a by-product. Propane
deasphalting is the predominant technique. The vacuum
fractionation residual is mixed in a fixed proportion with a
solvent in which asphalt is not soluble. The solvent is re-
covered from the oil via steam stripping and fractionation, and
is reused. The asphalt produced by this method is normally
blended into fuel oil or other asphaltic residuals.
Solvent Dewaxing - Solvent dewaxing removes wax from lubricating
oil stocks by promoting crystallization of the wax. Solvents
which are used include: furfural, phenol, cresylic acid -
propane (Duo-Sol), liquid sulfur dioxide (Eleleanu process), B-B
- dichloroethyl ether, methyl ethyl ketone, nitrobenzene, and
sulfur-benzene. The process yields de-oiled waxes, wax-free
lubricating oils, aromatics, and recovered solvents.
Lube Oil Solvent Refining - This process includes a collection of
subprocesses for improving the quality of lubricating oil stock.
The raffinate or refined lube oils obtain improved temperature,
viscosity, color and oxidation resistance characteristics. A
particular solvent is selected to obtain the desired quality
raffinate. The solvents include: furfural, phenol, sulfur
dioxide, and propane.
Aromatic Extraction - Benzene, toluene, and xylene (BTX) are
formed as by-products in the reforming process. The reformed
products are fractionated to give a BTX concentrate cut, which in
turn is extracted from the napthalene and the paraffinics with a
glycol base solvent.
Butadiene Extraction - Approximately 15 percent of the U.S.
supply of butadiene is extracted from the C4 cuts from the high
temperature petroleum cracking processes. Furfural or cuprous
ammonia acetate (CAA) are commonly used for the solvent
extraction.
32
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Wastes
The major potential pollutants from the various solvent refining
subprocesses are the solvents themselves. Many of the solvents,
such as phenol, glycol, and amines, can produce a high BODS.
Under ideal conditions the solvents are continually recirculated
with no losses to the sewer. Unfortunately, some solvent is
always lost through pump seals, flange leaks, and other sources.
The main source of waste water is from the bottom of
fractionation towers. Oil and solvent are the major waste water
constituents.
Trends
Solvent extraction capacities can be expected to slowly increase
as quality requirements for all refinery products become more
stringent, as the demand for lube oils grows, and as the
petrochemicals industry continues to require increasing
quantities of aromatics.
8. HYDROTREATING
Process Descrip-tion
Hydrotreating processes are used to saturate olefins, and to
remove sulfur and nitrogen compounds, odor, color and gum-forming
materials, and others by catalytic action in the presence of
hydrogen, from either straight-run or cracked petroleum
fractions. In most subprocesses, the feedstock is mixed with
hydrogen, heated, and charged to the catalytic reactor. The
reactor products are cooled, and the hydrogen, impurities and
high grade product separated. The principal difference between
the many subprocesses is the catalyst; the process flow is
similar for essentially all subprocesses.
Hydrotreating processes are used to reduce the sulfur content of
product streams from sour crudes by approximately 90 percent or
more. Nitrogen removal requires more severe operating
conditions, but generally 80 - 90 percent, or better, reductions
are accomplished.
The primary variables influencing hydrotreating are hydrogen
partial pressure, process temperature, and contact time. An
increase in hydrogen pressure gives a better removal of
undesirable materials and a better rate of hydrogenation. Make-
up hydrogen requirements are generally high enough to require a
hydrogen production unit. Excessive temperatures increase the
formation of coke, and the contact time is set to give adequate
treatment without excessive hydrogen usage and/or undue coke
formation. For the various hydrotreating processes the pressures
range from 7.8 - 205.1 atm (100 to 3000 psig). Temperatures
range from less than 177°C (350<>F) to as high as 450°C (850°F) ,
with most processing done in the range of 314°C (600°F) to 427°C
(800°F). Hydrogen consumption is usually less than 5.67 NM3 (200
scf) per barrel of charge.
Principal hydrotreating subprocesses are used as follows:
33
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1. Pretreatment of catalytic reformer feedstock.
2. Naphtha desulfurization.
3. Lube oil polishing.
4. Pretreatment of catalytic cracking feedstock.
5. Heavy gas-oil and residual desulfurization.
6. Naphtha saturation.
Wastes
The strength and quantity of waste waters generated by
hydrotreating depends upon the subprocess used and feedstock.
Ammonia and sulfides are the primary contaminants, but phenols
may also be present, if the feedstock boiling range is
sufficiently high.
Trends
The use of hydrotreating is increasing and should continue to
increase at a greater rate than crude capacity since the process
can be applied to almost any sour feedstock, is flexible, and
eliminates contaminants of concern to the refining industry from
an operating standpoint, and to the general public from an
aesthetic standpoint.
9. GREASE MANUFACTURING
Process Description
Grease manufacturing processes require accurate weight or
volumetric measurements of feed components, intimate mixing,
rapid heating and cooling, together with milling, dehydration and
polishing in batch reactions. The feed components include soap
and petroleum oils, with inorganic clays and other additives.
Grease is primarily a soap and lube oil mixture. The properties
of grease are determined in large part by the properties of the
soap component. For example, sodium metal base soaps are water
soluble and would then not be suitable for water contact service.
A calcium soap grease can be used in water service. The soap may
be purchased as a raw material or may be manufactured on site as
an auxiliary process.
Wastes
Only very small volumes of waste water are discharged from a
grease manufacturing process. A small amount of oil is lost to
the waste water system through leaks in pumps. The largest waste
loading occurs when the batch units are washed, resulting in soap
and oil discharges to the sewer system.
Trends
Because of an increase in sealed grease fittings in automobiles
and longer lasting greases, a slight decline in grease production
is expected through 1975.
34
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10. ASPHALT PRODUCTION
Process Description
Asphaltic feedstock (flux) is contacted with hot air at 203°C
(400°F) to 280°C (550°F) to obtain desirable asphalt product.
Both batch and continuous processes are in operation at present,
but the batch process is more prevalent because of its
versatility. Nonrecoverable catalytic compounds include: Copper
sulfate, zinc chloride, ferric chloride, aluminum chloride,
phosphorous pentoxide, and others. The catalyst will not
normally contaminate the process water effluent.
Wastes
Waste waters from asphalt blowing contain high concentrations of
oils, and have high oxygen demand. Small quantities of phenols
may also be present.
11. PRODUCT FINISHING
A. DRYING AND SWEETENING
Process Description
Drying and sweetening is a relatively broad process category
primarily used to remove sulfur compounds, water and other
impurities from gasoline, kerosene, jet fuels, domestic heating
oils, and other middle distillate products. "Sweetening"
pertains to the removal of hydrogen sulfide, mercaptans and
thiophenes, which impart a foul odor and decrease the tetra-ethyl
lead susceptibility of gasoline. The major sweetening operations
are oxidation of mercaptans or disulfides, removal of mercaptans,
and destruction and removal of all sulfur compounds. Drying is
accomplished by salt filters or absorptive clay beds. Electric
fields are sometimes used to facilitate separation of the
product.
Wastes
The most common waste stream from drying and sweetening
operations is spent caustic. The spent caustic is characterized
as phenolic or sulfidic, depending on which is present in the
largest concentration. Whether the spent caustic is actually
phenolic or sulfidic is mainly determined by the product stream
being treated. Phenolic spent caustics contain phenol, cresols,
xylenols, sulfur compounds, and some neutral oils. Sulfidic
spent caustics are rich in sulfides, but do not contain any
phenols. These spent caustics have very high BOD£ and COD. The
phenolic caustic streams are usually sold for the recovery of
phenolic materials.
Other waste streams from the process result from water washing of
the treated product and regeneration of the treating solution
such as sodium plumbite (No2 PbO2) in doctor sweetening. These
35
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waste streams will contain small amounts of oil and the treating
material, such as sodium plumbite (or copper from copper chloride
sweetening) .
The treating of sour gases produces a purified gas stream, and an
acid gas stream rich in hydrogen sulfide. The H2S rich stream
can be flared, burned as fuel, or processed for recovery of
elemental sulfur.
Trends
As air pollution agencies increase their efforts to control
sulfur emissions to the atmosphere, the restrictions on sulfur
content in fuels can be expected to tighten. This will generate
a strong trend to replacement of the sweetening processes by more
hydrotreating (desulfurization), because hydrotreating removes
almost all sulfur compounds and not just hydrogen sulfide,
mercaptans, and elemental sulfur. Nevertheless, on certain
feedstocks sweetening will continue to be used because it will be
as effective as, and more economical than, hydrotreating. Those
processes producing high waste loads (Doctor Sweetening, etc.)
are being replaced by lower waste-producing processes.
B. LUBE OIL FINISHING
Process Description
Solvent refined and dewaxed lube oil stocks can be further
refined by clay or acid treatment to remove color-forming and
other undesirable materials. Continuous contact filtration, in
which an oil-clay slurry is heated and the oil removed by vacuum
filtration, is the most widely used subprocess.
Wastes
Acid treatment of lubricating oils produces acid bearing wastes
occuring as rinse waters, sludges, and discharges from sampling,
leaks and shutdowns. The waste streams are also high in
dissolved and suspended solids, sulfates, sulfonates, and stable
oil emulsions.
Handling of acid sludge can create additional problems. Some
refineries burn the acid sludge as fuel. Burning the sludge
produces large volumes of sulfur dioxide that can cause air
pollution problems. Other refineries neutralize the sludge with
alkaline wastes and discharge it to the sewer, resulting in both
organic and inorganic pollution. The best method of disposal is
probably processing to recover the sulfuric acid, but this also
produces a waste water stream containing acid, sulfur compounds
and emulsified oil.
Clay treatment results in only small quantities of waste water
being discharged to the sewer. Clay, free oil, and emulsified
oil are the major waste constituents. However, the operation of
clay recovery kilns involves potential air pollution problems of
36
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hydrocarbon and particulate emissions. Spent clays usually are
disposed of by landfill.
Trends
Acid and clay treatment of lube oils is gradually being replaced
by hydrotreating methods. Acid treatment in particular is being
phased out rather rapidly.
C. BLENDING AND PACKAGING
Process Description
Blending is the final step in producing finished petroleum
products to meet quality specifications and market demands. The
largest volume operation is the blending of various gasoline
stocks (including alkylates and other high-octane components) and
anti-knock (tetra-ethyl lead) , anti-rust, anti-icing, and other
additives. Diesel fuels, lube oils, and waxes involve blending
of various components and/or additives. Packaging at refineries
is generally highly-automated and restricted to high volume,
consumer-oriented products such as motor oils.
Wastes
These are relatively clean processes because care is taken to
avoid loss of product through spillage. The primary source of
waste material is from the washing of railroad tank cars or
tankers prior to loading finished products. These wash waters
are high in emulsified oil.
Tetra-ethyl lead is the major additive blended into gasoline and
it must be carefully handled because of its high toxicity.
Sludges from finished gasoline storage tanks can contain large
amounts of lead and should not be washed into the wastewater
system.
Trends
There will be an increased use of automatic proportioning
facilities for product blending with a trend toward contracting
out of packaging of lower-volume products that are less suitable
to highly-automated operation.
12. AUXILIARY ACTIVITIES
A. HYDROGEN MANUFACTURE
Process Description
The rapid growth of hydrotreating and hydrocracking has increased
the demand for hydrogen beyond the level of by-product hydrogen
available from reforming and other refinery processes. The most
widely used process for the manufacture of hydrogen in the
refinery is steam reforming, which utilizes refinery gases as a
37
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charge stock. The charge is purified to remove sulfur compounds
that would temporarily deactivate the catalysts.
The desulfurized feedstock is mixed with superheated steam and
charged to the hydrogen furnace. On the catalyst the
hydrocarbons are converted to hydrogen, carbon monoxide, and
carbon dioxide. The furnace supplies the heat needed to maintain
the reaction temperature.
The gases from the furnace are cooled by the addition of
condensate and steam, and then passed through a converter
containing a high- or low-temperature shift catalyst depending on
the degree of carbon monoxide conversion desired. Carbon dioxide
and hydrogen are produced by the reaction of the monoxide with
steam.
The gas mixture from the converter is cooled and passes to a
hydrogen purifying system where carbon dioxide is absorbed into
amine solutions and later driven off to the atmosphere by heating
the rich amine solution into the reactivator.
Since some refining processes require a minimum of carbon oxides
in the product gas, the oxides are reacted with hydrogen in a
methanation step. This reaction takes place in the methanator
over a nickel catalyst at elevated temperatures.
Hydrocarbon impurities in the product hydrogen usually are not
detrimental to the processes where this hydrogen will be used.
Thus, a small amount of hydrocarbon is tolerable in the effluent
gas.
Wastes
Information concerning wastes from this process are not
available. However, the process appears to be a relatively clean
one. In the steam reforming subprocess a potential waste source
is the desulfurization unit, which is required for feedstock that
has not already been desulfurized. This waste stream would
contain oil, sulfur compounds, and phenol. In the partial
oxidation subprocess free carbon is removed by a water wash.
Carbon dioxide is discharged to the atmosphere at several points
in the subprocess.
Trends
Hydrogen requirements of the rapidly growing hydrocracking and
hydrotreating processes in many instances exceed the by-product
hydrogen available from catalytic reforming units. Since
hydrocracking and hydrotreating are expected to grow more rapidly
than other refinery processes, the demand for hydrogen
manufacturing units should continue to be strong.
38
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B. UTILITIES FUNCTION
Utility functions such as the supply of steam and cooling water
generally are set up to service several processes. Boiler feed
water is prepared and steam is generated in a single boiler
house. Non-contact steam used for surface heating is circulated
through a closed loop whereby varying quantities are made
available for the specific requirements of the different
processes. The condensate is nearly always recycled to the
boiler house, where a certain portion is discharged as blowdown.
The three major uses of steam generated within a refinery plant
are:
1. For non-contact process heating. In this
application, the steam is normally generated at
pressures of 9.5 to 45.2 atm (125 to 650 psig).
2. For power generation such as in steam-driven
turbines, compressors, and pumps associated with
the process. In this application, the steam is
normally generated at pressures of 45.2 to 103 atm
(650 to 1500 psig) and requires superheating.
3. For use as a diluent, stripping medium, or source
of vacuum through the use of steam jet ejectors.
This steam actually contacts the hydrocarbons in
the manufacturing processes and is a source of
contact process waste water when condensed. It is
used at a substantially lower pressure than the
foregoing and frequently is exhaust steam from one
of the other uses.
Steam is supplied to the different users throughout the plant
either by natural- circulation, vapor-phase systems, or by
forced-circulation liquid heat-transfer systems. Both types of
systems discharge some condensate as blowdown and require the
addition of boiler make-up water. The main areas of
consideration in boiler operation are normally boiler efficiency,
internal deposits, corrosion, and the required steam quality.
Boiler efficiency is dependent on many factors. One is the
elimination of boiler-tube deposition that impedes heat transfer.
The main contributors to boiler deposits are calcium, magnesium,
silicon, iron, copper, and aluminum. Any of thase can occur in
natural waters, and some can result from condensate return-line
corrosion or even from make-up water pretreatment. Modern
industrial boilers are designed with efficiencies on the order of
80 percent. A deposit of 0.32 cm (1/8 inch) in depth will cause
a 2-3 percent drop in this efficiency, depending on the type of
deposit.
Internal boiler water treatment methods have advanced to such a
stage that corrosion in the steam generation equipment can be
virtually eliminated. The control of caustic embrittlement in
boiler tubes and drums is accomplished through the addition of
sodium nitrate in the correct ratio to boiler water alkalinity.
39
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Caustic corrosion in high heat transfer boilers can also be
controlled by the addition of chelating agents. This type of
solubilizing internal boiler water treatment has been shown to be
more effective than previous precipitation treatment using
phosphate.
Other factors influencing boiler efficiency include reduction of
the amount of boiler blowdown by increasing cycles of
concentration of the boiler feedwater, efficiency of the blowdown
heat-recovery equipment, and the type of feed used.
Steam purity is of prime importance if:
1. The boilers are equipped with superheaters.
2. The boilers supply power-generation equipment.
3. The steam is used directly in a process where
contamination could affect product quality or destroy
some material (such as a catalyst) essential to the
manufacture of the product.
The minimum purity required for contact steam (or contact process
water) varies from process to process. Limits for suspended
solids, total solids, and alkalinity vary inversely with the
steam pressure. The following tabulation summarizes boiler water
concentration limits for a system providing a steam purity of 0.5
- 1.0 ppm total solids, which is required for most non-contact
steam uses. It should be noted that the boiler operation must
incorporate the use of antifoam agents and steam separation
equipment for the concentrations shown to be valid.
Boiler Water Concentration Required to
Maintain Steam Purity at 0.5 - 1.0 ppm Total Solids
Boiler Pressure, atm.
Parameters 21.4 21.5 - 31.6 31.7 -41.8 41.9 - 52.0
Total Solids (mg/1) 6,000 5,000 4,000 2,500
Suspended Solids(mg/1) 1,000 200 100 50
Total Alkalinity (mg/1) 1,000 900 800 750
Water conditioning or pretreatment systems are normally part of
the utilities section of most plants. From the previous
discussions, it is obvious that the required treatment may be
quite extensive. Ion-exchange demineralization systems are very
widely employed, not only for conditioning water for high-
pressure boilers, but also for conditioning various process
waters. Clarification is also widely practiced and usually
precedes the ion-exchange operation.
Non-contact cooling water also is normally supplied to several
processes from the utilities area. The system is either a loop
40
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which utilizes one or more evaporative cooling towers, or a once-
through system with direct discharge.
Cooling towers accomplish the cooling of water circulated over
the tower by moving a predetermined flow of ambient air through
the tower with large fans. The air water contact causes a small
amount of the water to be evaporated by the air. Thus, through
latent heat transfer, the remainder of the circulated water is
cooled.
Approximately 252 kg cal (1,000 BTU) are removed from the total
water circulation by the evaporation of O.H5U kg (1 Ib) of water.
Therefore, if 45.4 kg (100 Ibs) of water are introduced at the
tower inlet and O.U54 kg (1 Ib) is evaporated to the moving air,
the remaining 44.9 kg (99 Ibs) of water are reduced in total heat
content by 252 kg cal (1,000 BTU), of water leaving the tower
have been cooled 3.24°c/kg/kg cal (l°F/lb/BTU removed, and the
exit temperature is reduced by about 5,500 (1C°F). This leads to
the common rule of thumb: 1 percent evaporation loss for each
5.5°C (10°F) cooling.
Since cooling is primarily by transfer of latent heat, cooling
tower selection is based on the total heat content or enthalpy of
the entering air. At any one enthalpy condition, the wet bulb
temperature is constant. Therefore, cooling towers are selected
and guaranteed to cool a specific volume of water from a hot-
water temperature to a cold-water temperature while operating at
a design wet-bulb temperature. Design wet-bulb temperatures vary
from 15.6°C (60°F) to 35°C (85°F) depending on the geographic
area, and are usually equaled or exceeded only 2.5 percent to 5
percent of the total summer operating time.
Hot water temperature minus cold water temperature is termed
cooling range, and the difference between cold water and wet-bulb
temperature is called approach.
A closed system is normally used when converting from once-
through river cooling of plant processes. In the closed system,
a cooling tower is used for cooling all of the hot water from the
processes. With the closed system, make-up water from the river
is required to replace evaporation loss at the tower.
Two other water losses also occur. The first is drift, which is
droplet carryover in the air as contrasted to evaporative loss.
The cooling tower industry has a standarized guarantee that drift
loss will not exceed 0.2 percent of the water circulated. The
second loss in the closed system is blowdown to sewer or river.
Although blowdown is usually taken off the hot water line, it may
be removed from the cold water stream in order to comply with
regulations that limit the temperature of water returned to the
stream. Blowdown from a tower system will vary depending on the
solids concentration in the make-up water, and on the occurrence
of solids that may be harmful to equipment. Generally, blowdown
will be about 0.3 percent per 5.5°C (10°F) of cooling, in order
41
-------
to maintain a solids concentration in the recirculated water of
three to four times that of the make-up water.
The quantity and quality of the blowdown form boilers and cooling
towers depend on the design of the particular plant utility
system. The heat content of these streams is purely a function
of the heat recovery equipment associated with the utility
system. The amounts of waste brine and sludge produced by ion
exchange and water treatment systems depend on both the plant
water use function and the intake source. None of these utility
waste streams can be related directly to specific process units.
Quantitative limitations on parameters such as dissolved solids,
hardness, alkalinity, and temperature, therefore, cannot be
allocated on a production basis. The limitations on such
parameters associated with non-contact utility effluents should
be established on the basis of the water quality criteria of the
specific receiving water body or an EPA study of all industries,
to define specific utility effluent limitations.
Refinery Distribution
There are a total of 252 operating petroleum refineries in the
United States, Puerto Rico and the Virgin Islands, as of January
1, 1973, with a combined capacity of 2.24 million cu m/day (14
million barrels/day) of crude oil processing (see Figure 4 and
Table 10). The capacity of these plants range from 32 cu m/day
(200 bbl/day) to 69,000 cu m/day (434,000 bbl/day) of crude oil.
Within the United States, refineries are concentrated in areas of
major crude production (California, Texas, Louisiana, Oklahoma,
Kansas), and in major population areas (Illinois, Indiana, Ohio,
Pennsylvania, Texas, and California).
There are an almost unlimited number of process combinations
possible within the process area, or "Battery Limits", of the
typical refinery. Selection of the processing route for the
manufacture of a particular product mix at a particular location
or time is a decision based on the particular refiner's unique
situation. In order to illustrate the diversity of operations
which may be included within a refinery, Figure 5 shows the
schematic flow diagram for a hypothetical 15,900 cu m/day
(100,000 bbl/day) integrated refinery. This hypothetical
refinery includes essentially all production processes previously
outlined; hence the hypothetical refinery shown in Figure 5 is
completely integrated for current U.S. refinery capacity.
Inspection of Table 11 demonstrates the general distribution of
refining processes.
The trend in the petroleum refining industry is toward fewer and
larger refineries, which are integrated with satellite or
companion industries. This consolidation trend for a six-year
period (1967-1973) is shown in Table 12. Refineries with
capacities over 15,900 cu m/day (100,000 bbl/day) (11.5 percent
of the total) represented 48 percent of the domestic refinery
42
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TABLE 10
CRUDE CAPACITY OF PETROLEUM REFINERIES BY
STATES AS OF JANUARY 1, 1974T3T
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Delaware
Florida
Georgia
Hawaii
Illinois
Indiana
Kansas
Kentucky
Louisiana
Maryland
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
New Jersey
New Mexico
New York
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Tennessee
Texas
Utah
Virginia
Washington
West Virginia
Wisconsin
Wyoming
Puerto Rico
Virgin Islands
TOTAL
Number of Plants Cubic Meters/Day
4
4
1
4
34
3
1
1
2
2
11
7
11
3
18
2
6
3
5
1
8
T
5
6
2
2
7
12
1
11
1
40
6
1
7
3
1
10
3
1
251
5,885
10,970
1,590
9,220
301,270
9,210
23,850
875
2,410
11,720
191,820
93,500
66,470
26,550
275,580
3,930
23,410
31,480
47,440
17,570
26,430
875
102,735
9.080
17,650
8,790
96,430
79,130
2,340
115,945
4,770
619,550
22,360
8,870
57,400
3,260
6,040
28,810
46,269
71.550
2,483,110
Rated Crude Capacity
Barrels/Day
37,010
69,020
10,000
58,000
1,894,800
57,920
150,000
5,500
15,130
73,689
1,206,390
588,050
418,050
167,000
1,733,180
24,740
147,230
198,000
298,390
110,530
166,200
5,500
646,131
57,130
111,000
55,300
606,500
497,695
14,740
729,215
30,000
3,896,560
140,620
55,790
361,100
20,500
38,000
181,210
291,000
450.000
15,617,050
43
-------
o
Figure 4
Geographical Distribution of Petroleum
Refineries in the
United States
-------
FIGURE 5
HYPOTHETICAL 100,000 BARREL/STREAM DAY INTEGRATED REFINERY
wt mint 11 mimms mmim mms tmtnui
II IMREL5 HI ITIEIK ttl (I/SD).
-------
TABLE 11
Process Employment Profile of Refining Processes as of January 1, 1973 ( 3 )
Production Processes
Number of Refineries
Employing a Production Process
by Crude Capacity Classification
Storage: Crude 6 Product
Crude Desalting
Atmospheric Distillation
Vacuum Distillation
jai Thermal Cracking
01 Catalytic Cracking
Hydrocracking
Hydrotreating: Cat Reformer
and Cat Crack Feed
Middle Distillates & Naptha
Lubes
Heavy Oils and Residuals
Other Feedstocks
Alkylation
Isomerization
Reforming
Aromatics
Lubes
Asphalt
All
Refineries
247
24?
247
175
87
141
45
129
54
13
5
57
125
30
166
35
44
111
<35
MB/SD
141
141
141
79
27
41
11
42
11
2
2
14
30
4
65
3
16
58
35 to 100
MB/SD
65
65
65
55
32
59
11
52
21
2
3
17
57
19
60
16
10
30
>100
.MB/SD
41
41
41
41
28
41
23
35
22
9
-
26
38
7
41
16
18
23
Percent of Refineries
Employing a Production Process
by Crude Capacity Classification
All
Refineries
100
100
100
70
35
57
18
52
22
5
2
23
51
12
67
14
18
45
<35
MB/SD
100
100
100
56
19
29
8
30
8
1
1
10
21
3
46
2
11
41
35 to 100
MB/SD
100
100
100
85
49
91
17
80
32
3
5
26
88
29
92
25
15
46
>100
MB/SD
100
100
100
100
68
100
56
85
54
22
-
63
93
17
100
39
44
56
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TABLE 12
Trend in Domestic Petroleum Refining from 1967 to 1973 (3,3a)
Percent
January 1, 1967 January 1, 1973 Change
Crude Capacity, M3/SD(bbl/SD) 1
Total Compnaies
Total Refineries
Refineries with Capacity 100
Refineries with Capacity 35
Total Capacity of All 100
,853,618
Mbbl/SD
Mbbl/SD
Mbbl/SD
(11,657,975)
146
269
31
159
5,597,300
2,224,661(13,991,580)
132
247
41
141
8,167,200
+ 20
(- 10)
(- 8)
+ 32
(- ID
+ 46
Refineries
Average Refinery Capacity, M3/SD (bbl/SD) 6890 (43,338) 9006(55,646) + 31
47
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crude capacity in 1967; in 1972, 16.6 percent of the refineries
had capacities of 15,900 cu m/day (100,000 bbl/day) or more, and
represented 58 percent of the domestic refinery crude capacity.
Growth of the large refinery was a result of the annual need for
increased fuel capacity, and the imposed load due to the phasing
out of smaller refineries. Refineries are increasing capacities
for reforming, hydrotreating, cracking, and isomerization
processes to obtain higher octane gasoline in lieu of adding
lead. Desulfurization of heavy fuels, longer process catalyst
life requirements, and high quality, low sulfur, light fuels and
lubes are factors in the rapid growth of the hydrogen treating
process. The complexity and size of the typical refinery can be
expected to increase at a rate comparable to the period 1967
through 1972 for the near future, and no major technological
breakthroughs are expected that would drastically alter petroleum
processes.
Anticipated Industry Growth
The petroleum refining industry is presently facing a shortage of
crude oil. There have been shortages of gasoline and fuel oil.
Since demand continues to grow and little refinery expansion
work is under way, shortages will become more severe over the
next few years. Consumption of petroleum products will keep
growing, and supplies must be generated to satisfy these growing
demands. (1972 consumption of petroleum products, shown in Table
13, was approximately 2.56 million cu m/day (16.1 million
bbl/day). The growth rate in consumption has been 5.2 percent
per year; the projected growth in consumption over the next eight
years is 43 percent, or a compounded growth rate of 4.6 percent
per year.
Supplies of refinery feedstocks and products will show a rapid
increase in imports. Table 14 indicates current and projected
1980 sources of feedstocks and products. In 1972, imports
accounted for 29 percent of the total supply; in 1980, imports
are projected at 55 percent of the total supply.
Refinery runs of crude oil are projected to increase from 1.86
million cu m/day (11.7 million bbl/day) in 1972 to 2.73 million
cu m/day (17.2 million bbl/day) in 1980. Refinery capacity in
1972 was about 2.23 million cu m/day (14.0 million bbl/day). By
1980 the national refinery capacity must increase to 3.18 million
cu m/day (20.0 million bbl/day) to satisfy the projected
requirements. The need for 0.95 million cu m/day (6.0 million
bbl/day) of new refinery construction for real growth, plus 0.64
million cu m/day (4.0 million bbl/day) of new construction for
replacement, indicates a total of 1.59 million cu m/day (10.0
million bbl/day) of new refinery construction is required by
1980.
Because of crude supply limitations, most new refinery capacity
will be designed to process higher sulfur crudes. (A partial
list of analyses of crude oils from major oil fields around the
world is given in Table 15.) The use of sour crude feedstock
48
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TABLE 13
1972 Consumption of Petroleum Products (63)
Products 1972 Consumption, Million Cubic Meters/Day
(Million Barrels/Day"
Motor Gasoline 1.02 (6.4)
Aviation Fuel 0.17 (1.1)
Middle Distillates 0.49 (3.1)
Residual Fuels 0.40 (2.5)
All Other Products 0.49 (3.1)
49
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TABLE 14
Sources of Supply for U.S. Petroleum Feedstocks^
Supply, Million Barrels/Day
Source 19721980 (Projected)
Domestic Crude Oil Production 9-5 8.5
Domestic Natural Gas Liquids 1.7 1.5
Crude Oil Imports 2.2 8.7
Residual Fuel Imports 1.7 2.5
Other Imports 0.8 1.5
Miscellaneous Sources 0.^ 0.5
50
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TABLE 15
Characteristics of Crude Oils from Major Fields Around the World ( ^0,
Country
Abu Dhabi
Algeria
Brunei
Canada
Alberta
Bonnie Glen
Golden Spike
Judy Creek
Pembina
Swan Hi 11s
Saskatchewan
Midale
Weyburn
Indonesia
1 ran
1 rag
Libya
Mexico
Ebano Panuco
Naranjos-Cerro-Azul
Poza Rica
Peru
Saudi Arabia
United States
Alaska
Cook Inlet
Prudhoe Bay
Swanson River
Arkansas
Smackover
Gravity
39.3
46 -
21 -
41 -
36 -
42 -
35 -
41
28 -
24 -
35
31 -
35 -
37 -
12
20
35
33.5
27 -
36
30.5
29.7
22.2
, API
48
37
42
39
43
42
32
33
38
36
41
- 35.5
38
Sulfur, Percent Nitrogen, Percent
0.15
0.1
0.25
0.23
0.42
0.80
1.89
2.12
0.10
1.12 - 1.66
1.97
0.23 - 0.52
5.38
3.80
1.77
0.12
1.30 - 3-03
0.0
0.16 0.203
2.10 0.080
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TABLE 15
(Continued)
Country Gravity, API Sulfur, Percent Nitrogen, Percent
Cali forn ia
Elk Hills 22.5 0.68 0.1*72
Huntington Beach 22.6 1.57 0.048
Kern River 12.6 1.19 0.604
Midway-Sunset 22.6 0.94
San Ardo 11.1 2.25 0.913
Wilmington 22.1 1.44
Colorado
Rangely 34.8 0.56 0.073
Kansas
Bemis Shutts 34.6 0.57 0.162
Loui s iana
Bayou Sale 36.2 0.16
Caillou Isl. 35.4 0.23 0.040
Golden Meadow 37.6 0.18
Grand Bay 35 0.31
Lake Barre 40.4 0.14 0.02
Lake Washington 28.2 0.37 0.146
West Bay 32.1 0.27 0.071
Bay Marchand Blk. 2 20.2 0.46
Main Pass Blk. 69 30.6 0.25 0.098
South Pass Blk, 24 32.3 0.26 0.068
South Pass Blk. 27 35.6 0.18 0.069
Timbalier Bay 34.4 0.33 0.081
West Delta Blk. 30 27 0.33 0.09
Mi ss i ss i ppi
Baxterville 17.1 2.71 0.111
New Mexico
Vacuum 35 0.95 0.075
Oklahoma
Golden Trend 42.1 0.11
Texas
Anahuac 33-2 0.23 0.041
Con roe 37.6 0.15
Diamond M 45.4 0.20
East Texas 39-4 0.32
Hastings 31.0 0.15 0.02
Hawkins 26.8 2.19 0.076
Headlee 51.1 <0.10 0.083
Kelly Snyder 38.6 0.29 0.066
Levelland 31.1 2.12 0.136
Midland Farms 39-6 0.13 0.080
Panhandle 40.4 0.55 0.067
Seeliason 41.3 <0.10 0.014
52
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TABLE 15
(Continued)
Country
Tom O'Connor
Wasson
Webster
Yates
Utah
Aneth
Venezuela
Bachaquero
Boscan
Laguni1 las
Mene Grande
Tia Juana
Oficina
Los Claros
Gravity, API
31.1
31.9
29.3
30.2
Sulfur, Percent
21.
10.
18.
20.
21.
2*4.8
,16
,40
0.21
1.54
0.20
,62
,53
,18
,65
,49
0.59
Nitrogen, Percent
0.03
0.07
0.046
0.150
0.059
10.5
53
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from outside the United States will require not only a change in
processing equipment, but changes in in-plant waste water control
and treatment operations. Some refineries currently consuming
sweet crude stocks are not employing strippers to remove minimal
amounts of ammonia and hydrogen sulfide from their waste waters.
When processing sour crude within these refineries, sour water
strippers will be required prior to discharge of the waste waters
to biological waste water treatment facilities. Two stage
desalting will become more prevalent. Other changes will be
required within the refinery to minimize corrosion, treat more
sour heavy bottoms, and reduce emissions of sour gases.
-------
SECTION IV
INDUSTRY SUBCATEGORIZATION
Discussion of the Rationale of Subcategorization
The goal of this study is the development of effluent limitations
commensurate with different levels of pollution control
technology. These effluent limitations will specify the quantity
of pollutants which will ultimately be discharged from a specific
manufacturing facility and will be related to the quantity of raw
materials consumed and the production methodology.
The diverse range of products and manufacturing processes to be
covered suggests that separate effluent limitations be designated
for different segments within the industry. To this end, a
subcategorization of the Petroleum Refining Industry has been
developed. The subcategorization is process oriented, with a
delineation between subcategories based upon raw waste load
characteristics in relation to the complexity of refinery
operations.
Today's petroleum refinery is a very complex combination of
interdependent operations and systems. In the development of a
pollution profile for this industry, ten major process categories
were listed as fundamental to the production of principal oil
products (see listing in Table 8).
The American Petroleum Institute (API) has developed a
classification system which utilizes this technology breakdown.
They have tentatively divided U.S. refineries into 5
classifications, which primarily recognize varying degrees of
processing complexity and resultant distribution of products.
The present API classification system is as follows:
Class Process Complexity
A Crude Topping
B Topping and Cracking
C Topping, cracking, and petrochemicals
D "B" Category, and lube oils processing
E "D" Category, and petrochemicals
Development of Industry Subcategorization
Age, size, and waste water treatability of refineries were
considered during the subcategorization of the refining industry.
However, subcategorization by age is not necessarily useful, as
additions to and modifications of refineries are the industry's
principal form of expansion. Since most of the technology
55
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employed within the industry is of an evoluationary nature,
refinery age was not a major factor in refinery
subcategorization.
While the size of a refinery is important in terms of economical
waste water treatment, the control technology employed in smaller
refineries need not be as sophisticated a technology to achieve
parity with larger refineries within the same subcategory.
Treatability characteristics of refinery waste waters indicate
that these waste waters are generally amenable to excellent
degrees of removal of pollutants. Since this is an industry-wide
characteristic, the proper place to evaluate the
subcategorization of the industry is with the raw waste load
delivered to the refinery waste water treatment plant. The 1972
National Petroleum Refining Waste Water Characterization Studies
of 135 refinery API separator effluents, provides a major tool
for this evaluation. Attempts to explain and justify the
differences based solely on type and method of cooling, inplant
pretreatment, and housekeeping practices were also fruitless.
However, generally speaking those refineries with good practices
in all these areas did have the lower waste loadings.
In an attempt to determine the effects of process technology, a
further analysis was made of the API individual or combined
categories to evaluate the raw waste load as a function of the
degree of cracking employed within the refinery. The operations
included in degree of cracking were: thermal operations,
catalytic cracking and hydroprocessing. The degree of cracking
was expressed as percentage capacity of the total feedstock
processing capacity within the refinery. The data for evaluating
the net raw waste loads by this criteria were obtained by
analyzing the raw waste load surveys supplied by refineries,
literature sources, and analysis of the 1972 National Petroleum
Refining Waste Water Characterization Studies.
Even though this new breakdown was a step in the right direction
it did not explain raw waste load differences caused by the
amount of cracking in the other subcategories and did not explain
the effect of other process on the raw waste load. Therefore,
the effort to further determine the effect of each refining
process on the raw waste load continued.
Since the guideline is based on attainable flow rates and
achievable concentrations based on each treatment technology, the
effort was directed toward determining the relative flows
expected from the many refining processes.
The approach taken, was the use of a multiple regression analysis
using process and flow data from the 1972 National Petroleum
Refining Waste Water Characterization Studies. The data
consisted of waste water flows and individual process capacities
for 94 refineries with less than 3 percent heat removal by once-
through cooling. Those refineries with greater than 3 percent
56
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once-through cooling water were not used in order to eliminate as
much of the non-process flow variation as possible.
The initial regressions carried out were in the form:
(1) Total Flow = A + B £ Ci Pi
Capacity
where A,B,and C are the constants to be determined from the
regressions; Pi is the capacity of individual process categories
relative to the refinery throughput and for each Pi there is a Ci
which is the relative "weight" or importance of each process
category in explaining the flow. The initial process breakdown
used was supplied through the American Petroleum Institute and
broke 126 individual process types into nine process categories.
Since the results of this initial form were not considered
satisfactory, attempts were made to find out what other factors,
if any, had explanatory power in predicting refinery flow. After
many attempts, it was found that in addition to the process
configuration of the refinery, the refinery size was an important
factor in explaining the flow.
The final form of the equation which gave the best fit to the
data was as follows:
(2) log Total Flow = A + BT + C £Di Pi
Capacity (T)
where T or capacity is equal to the refinery throughput; A, C, Di
and Pi are the same as A, B, Ci and Pi, respectively, in the
initial regression form; and B is a constant.
Adjustments were then made to the API breakdown of the process
categories to improve the fit to the data. The 126 individual
processes were finally put into one of the following nine process
categories:
1. crude processes
2. cracking processes
3. hydrocarbon processing
4. lubes and greases
5. coking processes
6. treating and finishing processes
7. first generation petrochemicals
8. second generation petrochemicals
9. asphalt production
It was found that only crude processes, cracking processes, lubes
and greases, coking processes, second generation petrochemicals
and asphalt production showed significance in the regression. In
addition, even though second generation petrochemicals showed
significance, the Di or "weighting factor" for it was -6. The
57
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nonsignificant processes and second generation petrochemicals
were therefore given 0 (zero) weighting factors.
The Di's or weighting factors for the significant process
categories are as follows: crude process f-1; cracking and coking
processes -f-6; lubes and greases *13; and asphalt production -H2.
A breakdown of the individual process in each process category is
contained in Table 51.
The values for constants B and C were then obtained by regressing
against flow with equation (2) with the Di value defined as
above. The resulting values are B=1.51 and C=0.0738. The
magnitude of A has no significance since the analysis is to be
used only within each subcategory and not across all
subcategories. (Fitting the actual flows with those predicted
was tried both using the analysis across the entire industry and
within each subcategory, with the results being much better using
it only to explain differences within subcategories).
The above results were then put into a usable form by taking the
anti log of equation (2), which is
BT C £. DiPi
(3) flow(galXbbl) = AlO 10
The constant A is now the 50 percent probability flow (gal/bbl)
which was used previously to calculate the limits for each
subcategory. To apply this to each subcategory (to determine the
variance needed for each case from the average refinery in each
subcategory) the average size (Ta) and process configuration
(C £~ DiPi ]a) for each subcategory was calculated. The range of
sizes and process configurations were then divided up into ranges
and the midpoint of each range was then compared to the average
for that subcategory to calculate the size and process factor for
that range (see below).
BT l.Sl(Ti-Ta)
10 = 10
C £ DiPi 0.0738[ ( £ DiPi) j-( £DiPi)a]
10 = 10
where Ti is the midpoint of that particular size range; Ta is the
average size in the subcategory, with both Ta and Ti in millions
of barrells per day; [<£. DiPi ]i is the midpoint of that particular
process configuration range; and [ ^DiPija is the average process
configuration of the subcategory.
Further analysis of the data showed a break in the significance
of size in explaining flow for those refineries over 150,000
bbl/day. This means that over 150,000 bbl/day only the process
configuration has significance in explaining the flows. As a
58
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result the size ranges where broken off at either 150,000 bbl/day
or the average refinery size in a subcategory, whichever was
greater.
An example of the application of the size and process factors is
in section IX. The basic data used, regressions run, etc. are in
Supplement B "Refinery Configuration Analysis".
The size and process factors are in Table 1-5, Section II.
Subcategorization Results
Using the procedures outlined above, many trials were performed
in order to obtain a Subcategorization of the petroleum refining
industry which is reflective of the net raw waste load with
respect to type of refinery (function) , process technology
employed, and severity of operations. The final
Subcategorization obtained from this analysis is indicated below
in Table 16. Detailed probability plots for the development of
the Subcategorization are contained in supplement B.
For each of these new subcategories the parameters for the
selected median values are indicated in Table 17. A further
enumeration of overall net raw waste load characteristics is
given in Section V.
Analysis of the Subcategorization
Topping subcategory
The topping subcategory is similar to the previous API category A
in that it does not include any refineries with cracking or
coking processes. That is to say it includes all refineries
which combine all other porcesses except cracking and coking.
Cracking subcategory
API Category B includes refineries which contain topping,
reforming, and cracking operations. Also included are all first
generation conventional refinery-associated products or
intermediates, such as benzene-toluene-xylene (BTX), alkanes,
alkenes, alkynes, and other miscellaneous items such as sulfur,
hydrogen and coke.
Subcategory B as defined here is the same as API category B
execpt that the inclusion of first generation petrochemicals
shall only be for those whose production amounts to less than 15
percent of the refinery throughput.
Petrochemical subcategory
The petrochemical subcategory is similar to the API category C.
Operations included within this subcategory are topping,
59
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TABLE 16
Subcategorization of the Petroleum Refining Industry
Reflecting Significant Differences in Waste Water Characteristics
Subcategory Basic Refinery Operations Included
Topping Topping and catalytic reforming whether
or not the facility includes any other process
in addition to topping and catalytic process.
This subcategory is not applicable to facilities
which include thermal processes (coking, visbreaking,
etc.) or catalytic cracking.
Cracking Topping and cracking, whether or not the facility
includes any processes in addition to topping and
cracking, unless spefified in one of the subcategories
listed below.
Petrochemical Topping, cracking and petrochemical operations, whether
or not the facility includes any process in addition
to topping, cracking and petrochemical operations,*
except lube oil manufacturing operations.
Lube Topping, cracking and lube oil manufacturing processes,
whether or not the facility includes any process in
addition to topping, cracking and lube oil manu-
facturing processes, except petrochemical operations.*
Integrated Topping, cracking, lube oil manufacturing processes,
and petrochemical operations, whether or not the
facility includes any processes in addition to
topping, cracking, lube oil manufacturing processes
and petrochemical operations.*
* The term "petrochemical operations" shall mean the production of second
generation petrochemicals (i.e., alcohols, ketones, cumene, styrene, etc.)
or first generation petrochemicals and isomerization products (i.e., BTX,
olefins, cyclohexane, etc.) when 15% or more of refinery production is
as first generation petrochemicals and isomerization products.
60
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TABLE 17
NET RAW WASTE LOADS FROM PETROLEUM REFINING
INDUSTRY CATEGORIES (50 Percent Probability of Occurrence)
KILOGRAMS/10000 M3 (LB/1000 BBLS)
SUBCATEGORY
TOPPING
CRACKING
PETROCHEMICAL
LUBE
INTEGRATED
BODS
3.43(1.2)
72.93(25.5)
171.6(60)
217(76)
197(69)
OIL/GREASE
PHENOL
AMMONIA
8.29(2.9)
31.17(10.9)
52.91(18.5)
120.1(42)
75(26)
0.034(0.012) 1.20(0.42)
4.00(1.4) 28.31(9.9)
7.72(2.7) 34.32(12)
8.3(2.9) 24.1(8.5)
3.8(1.3) 20.5(7.2)
61
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cracking, and petrochemical operations. Petrochemical operations
include first generation conventional refinery-associated
production, as described in the cracking subcategory, but only
when it amounts to greater than 15 percent of the refinery
throughput. This takes into consideration the additional cooling
tower blowdown from this operation. Intermediate chemical
production, including such typical products as cumene, phthalic
anhydride, alcohols, ketones, trimer, and styrene, shall be
considered second generation petrochemical operations and
classify a refinery in this subcategory.
Lube subcategory
The lube subcategory is the same as the API category D.
In the lube subcategory, the operations included under the
cracking subcategory are expanded to include lube oil
manufacturing processes. Lube oil processing excludes
formulating blended oils and additives.
Integrated subcategory
The integrated subcategory is the same as API category E, except
for the definition of petrochemical operatons specified in the
petrochemical subcategory.
Conclusion
The subcategorization of the petroleum refinery industry
presented above allows for the definition of logical segments of
the industry in terms of factors which effect generated API
separator effluent waste water quality. It allows for rapid
identification of the expected median net raw waste loads as a
basis for developing effluent guidelines for the discharge from
the individual refinery. The subcategorization determined above
is used throughout this report as the basis for development of
effluent limitations and guidelines.
62
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SECTION V
WASTE CHARACTERIZATION
General
After developing an understanding of the fundamental production
processes and their inter-relationships in refinery operations,
determination of the best method of characterizing of refinery
discharges will enhance the interpretation of the industry water
pollution profile. If unit raw waste loads could be developed
for each production process, then the current effluent waste
water profile could be obtained by simply adding the components,
and future profiles by projecting the types and sizes of
refineries. However, the information required for such an
approach is not available. Essentially all of the available data
on refinery waste waters apply to total API separator effluent,
rather than to effluents from specific processes.
Another factor detracting from the application of a summation of
direct subprocess unit raw waste loads, is the frequent practice
of combining specific waste water streams discharging from
several units for treatment and/or reuse. Thus, such streams as
sour waters, caustic washes, etc., in actual practice are
generally not traceable to a specific unit, but only to a
stripping tower or treatment unit handling wastes from several
units. The size, sequence, and combination of contributing
processes are so involved that a breakdown by units would be
extremely difficult to achieve.
In view of the limitations imposed by the summation of waste
water data from specific production process, the evaluation of
refinery waste loads was based on total refinery effluents
discharged through the API (Oil) separator, which is considered
an integral part of refinery process operations for product/raw
material recovery prior to final waste water treatment.
Raw Waste Loads
The information on raw waste loading was compiled from the 1972
National Petroleum Refining Waste Water Characterization Studies
and plant visits. The data are considered primary source data,
i.e., they are derived from field sampling and operating records.
The raw waste data for each subcategory of the petroleum refining
industry, as subcategorized in Section IV, have been analyzed to
determine the probability of occurrence of mass loadings for each
considered parameter in the subcategory. These frequency
distributions are summarized in Tables 18 through 22 for each
subcategory.
Waste water Flows
As shown in Table 18 through 22, the waste water flows associated
with raw waste loads can vary significantly. However, the
63
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TABLE 18
TOPPING SUBCATEGORY RAW WASTE LOAD**
EFFLUENT FROM REFINERY API SEPARATOR
NET KILOGRAMS/1000 M3 (LB/1000 BBLS) OF FEEDSTOCK
THROUGHPUT
PARAMETER
PROBABILITY OF OCCURRENCE
PERCENT LESS THAN OR EQUAL TO
BOD.5
COD
TOC
TSS
O&G
PHENOLS
AMMONIA
SULFIDES
CHROMIUM
FLOW*
10%
1.29(0.45)
3.43(1.2)
1.09(0.38)
0.74(0.26)
1.03(0.36)
0.001(0.0004)
0.077(0.027)
0.002(0.00065)
0.0002(0.00007)
8.00(2.8)
50% (MEDIAN)
3.43(1.2)
37.18(13)
8.01(2.8)
11.73(4.1)
8.29(2.9)
0.034(0.012)
1.20(0.42)
0.054(0.019)
0.007(0.0025)
66.64(23.3)
90%
217.36(76)
486.2(170)
65.78(23)
286(100)
88.66(31)
1.06(0.37)
19.45(6.8)
1.52(0.53)
0.29(0.1)
557.7(195)
* 1000 cubic meters/1000 m Feedstock Throughput (gallons/bbl)
** Probability plots are contained in Supplement B
64
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TABLE 19
CRACKING SUBCATEGORY RAW WASTE LOAD**
EFFLUENT FROM REFINERY API SEPARATOR
NET KILOGRAMS/1000 M3 (LB/1000 BBLS) OF FEEDSTOCK
THROUGHPUT
PARAMETER
BOD5_
COD
TOC
O&G
PHENOLS
TSS
SULPHUR
CHROMIUM
AMMONIA
FLOW*
10%
14.3(5.0)
27.74(9.7)
5.43(1.9)
2.86(1.0)
0.19(0.068)
0.94(0.33)
0.01(0.0035)
PROBABILITY OF OCCURRENCE
PERCENT LESS THAN OR EQUAL TO
50%(MEDIAN)
90%
72.93(25.5)
217.36(76.0)
41.47(14.5)
31.17(10.9)
4.00(1.4)
18.16(6.35)
0.94(0.33)
0.0008(0.00028) 0.25(0.088)
2.35(0.82) 28.31(9.9)
3.29(1.15) 92.95(32.5)
466.18(163)
2516.8(880)
320.32(112)
364.65(127.5)
80.08(28.0)
360.36(126.0)
39.47(13.8)
4.15(1.45)
174.46(61.0)
2745.6(960.0)
* 1000 cubic meters/1000 m3 Feedstock Throughput (gallons/bbl)
** Probability plots are contained in Supplement B
65
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TABLE 20
PETROCHEMICAL SUBCATEGORY RAW WASTE LOAD**
EFFLUENT FROM REFINERY API SEPARATOR
NET KILOGRAMS/1000 M3 (LB/1000 BBLS) OF FEEDSTOCK
THROUGHPUT
PROBABILITY OF OCCURRENCE
PERCENT LESS THAN OR EQUAL TO
PARAMETER
BOD_5
COD
TOC
TSS
O&G
PHENOLS
AMMONIA
SULFIDES
CHROMIUM
FLOW*
** Probability plots are contained in Supplement B
10%
40.90(14.3)
200.2(70)
48.62(17)
6.29(2.2)
12.01(4.2)
2.55(0.89)
5.43(1.9)
0.009(0.003)
0.014(0.005)
26.60(9.3)
50% (MEDIAN)
171.6(60)
463.32(162)
148.72(52)
48.62(17)
52.91(18.5)
7.72(2.7)
34.32(12)
0.86(0.3)
0.234(0.085)
108.68(38)
90%
715(250)
1086.8(380)
457.6(160)
371.8(130)
234.52(82)
23.74(8.3)
205.92(72)
91.52(32)
3.86(1.35)
443.3(155)
_—. — /!_!_ 1 \
66
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TABLE 21
LUBE SUBCATEGORY RAW WASTE LOAD**
EFFLUENT FROM REFINERY API SEPARATOR
NET KILOGRAMS/1000 M3 (LB/1000 BBLS) OF FEEDSTOCK
THROUGHPUT
PROBABILITY OF OCCURRENCE
PARAMETERS PRECENT LESS THAN OR EQUAL TO
BOD5_
COD
TOG
TSS
O&G
PHENOLS
AMMONIA
SULFIDES
CHROMIUM
FLOW*
10%
62.92(22)
165.88(58)
31.46(11)
17.16(6)
23.74(8.3)
4.58(1.6)
6.5(2.3)
0.00001(0
50% (MEDIAN)
217.36(76)
543.4(190)
108.68(38)
71.5(25)
120.12(42)
8.29(2.9)
24.1(8.5)
.000005) 0.014(0.005)
0.002(0.0006) 0.046(0.016)
68.64(24)
117.26(41)
90%
757.9(265)
2288(800)
386.1(135)
311.74(109)
600.6(210)
52.91(18.5)
96.2(34)
20.02(7.0)
1.23(0.43)
772.2(270)
* 1000 cubic meters/1000 m3 Feedstock Throughput (gallons/bbl)
** Probability plots are contained in Supplement B
67
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TABLE 22
INTEGRATED SUBCATEGORY RAW WASTE LOAD**
EFFLUENT FROM REFINERY API SEPARATOR
NET KILOGRAMS/1000 M3 (LB/1000 BBLS) OF FEEDSTOCK
THROUGHPUT
PROBABILITY OF OCCURRENCE
PARAMETERS- PERCENT LESS THAN OR EQUAL TO
10% 50%(MEDIAN) 90%
BOD_5 63.49(22.2) 197.34(69.0) 614.9(215)
COD 72.93(25.5) 328.9(115) 1487.2(520)
TOC 28.6(10.0) 139.0(48.6) 677.82(237)
O&G 20.88(7.3) 74.93(26.2) 268.84(94.0)
PHENOL 0.61(0.215) 3.78(132) 22.60(7.9)
TSS 15.16(5.3) 58.06(20.3) 225.94(79.0)
SULPHUR 0.52(.182) 2.00(.70) 7.87(2.75)
CHROMIUM 0.12(0.043 0.49(0.17) 1.92(0.67
AMMONIA 3.43(1.20) 20.50(7.15) 121.55(42.5)
FLOW* 40.04(14.0) 234.52(82.0) 1372.8(480)
o
* 1000 cubic meters/1000 m Feedstock Throughput (gallons/bbl)
** Probability plots are contained in Supplement B
68
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loadings of pollutants tend to vary within fairly narrow limits,
independent of flow.
Since the inter-refinery data suggest that the pollutant loading
to be expected from a refinery is relatively constant in
concentration, an examination of water use practices was made.
The waste water flow frequencies reported in Tables 18 through 22
are dry-weather flows, and in many cases include large amounts of
once-through cooling water. Refineries with more exemplary waste
water treatment systems are probably making a greater effort to
control waste loads and flows. Conversely, refineries with very
high water usages and/or raw waste loads either do not have
identifiable waste water treatment plants, or have them under
construction.
The -primary methods for reduction of the waste water flows to the
API separator are either segregation of once-through cooling
waters, or by installation of recycle cooling towers and/or air
coolers. In order to estimate the flows that should be
attainable in refineries with good water practices, a statistical
analysis was made of flows from refineries in which 3 percent or
less of the total heat removal load is accomplished by once-
through cooling water. Data for this analysis were obtained from
the tabulation of refinery cooling practices contained in the
1972 National Petroleum Pefining Waste Water Characterization
Studies. These frequency distributions are summarized in Table
23.
Basis for Effluent Limitations
The 50 percent probability-of-occurrence raw waste loads outlined
in Tables 18 through 22 are reflective of the performance of
median refineries within each subcategory. At the same time,
attainable process waste water flows, as reflected by the median
water usage for refineries in which 3 percent or less of the
total heat removal load is accomplished by once-through cooling
water, are indicative of equitable process waste water loadings
which require waste water treatment.
Consequently, these 50 percent probability-of-occurrence waste
water loadings and estimated process waste water flows were
selected as one basis for developing effluent limitations, and
are used in subsequent sections to define these effluent
limitations.
69
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TABLE 23
WASTE WATER FLOW FROM PETROLEUM REFINERIES USING
3% OR LESS ONCE-THROUGH COOLING WATER FOR HEAT REMOVAL*
KILOGRAMS/1000 M3 (LB/1000 BBLS) OF FEEDSTOCK
THROUGHPUT
SUBCATEGORY
TOPPING
CRACKING
PETROCHEMICAL
LUBE
INTEGRATED
PROBABILITY OF OCCURRENCE
PERCENT LESS THAN OR EQUAL TO
10%
8.01(2.8)
16.59(5.8)
40.04(14)
65.78(23)
91.52(32)
50% (MEDIAN)
57.2(20)
71.5(25)
85.8(30)
128.7(45)
137.28(48)
90%
314.6(110)
148.72(52)
183.04(64)
243.1(85)
1287(450)
* Probability plots are contained in Supplement B
70
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SECTION VI
SELECTION OF POLLUTANT PARAMETERS
Selected Parameters
The selection of the complete list of pollutant parameters which
are discharged in significant quantities was based on a review
of: the Environmental Protection Agency permits for discharge of
waste waters from a number of refineries; reviews with personnel
in regional EPA offices; the 1972 National Petroleum Refining
Waste Water characterization Studies; discussions with industry
representatives and consultants; and literature survey data. The
results of the above indicated the parameters shown in Table 24
are significant in describing the physical, chemical and
biological characteristics of waste waters discharged by the
petroleum refining industry, as defined in the Act.
The rationale and justification for inclusion of these parameters
are discussed below. This discussion will provide the basis for
selection of parameters upon which the actual effluent
limitations were postulated and prepared. In addition,
particular parameters were selected for discussion in the light
of current knowledge as to their limitations from an analytical
as well as from an environmental standpoint.
Oxygen Demand Parameters
Three oxygen demand parameters are discussed below: BODS, COD,
and TOC. It should be noted that limitations are specified for
BOD5, COD, and TOC in sections IX, X, and XI for each
subcategory.
Almost without exception, waste waters from petroleum refineries
exert a significant and sometimes major oxygen demand. The
primary sources are soluble biodegradable hydrocarbons and
inorganic sulfur compounds. Crude distillation, cat cracking,
and the product finishing operations, are the major contributors
of BOD5. In addition, the combination of small leaks and
inadvertent losses that occur almost continuously throughout a
complex refinery can become principal BOD5 pollution sources.
Biochemical oxygen demand (BOD) is a measure of the oxygen
consuming capabilities of organic matter. The BOD does not in
itself cause direct harm to a water system, but it does exert an
indirect effect by depressing the oxygen content of the water.
Sewage and other organic effluents during their processes of
decomposition exert a BOD, which can have a catastrophic effect
on the ecosystem by depleting the oxygen supply. Conditions are
reached frequently where all of the oxygen is used and the
continuing decay process causes the production of noxious gases
such as hydrogen sulfide and methane. Water with a high BOD
indicates the presence of decomposing organic matter and
71
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TABLE 24
Significant Pollutant Parameters for
the Petroleum Refining Industry
Biochemical Oxygen Demand (BOD5)
Chemical Oxygen Demand (COD)
Total Organic Carbon (TOC)
Oil and Grease (0§G)
Ammonia as Nitrogen (NH3-N)
Phenolic Compounds
Sulfides
Chromium
72
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subsequent high bacterial counts that degrade its quality and
potential uses.
Dissolved oxygen (DO) is a water quality constituent that, in
appropriate concentrations, is essential not only to keep
organisms living but also to sustain species reproduction, vigor,
and the development of populations, organisms undergo stress at
reduced DO concentrations that make them less competitive and
able to sustain their species within the aquatic environment.
For example, reduced DO concentrations have been shown to
interfere with fish population through delayed hatching of eggs,
reduced size and vigor of embryos, production of deformities in
young, interference with food digestion, acceleration of blood
clotting, decreased tolerance to certain toxicants, reduced food
efficiency and growth rate, and reduced maximum sustained
swimming speed. Fish food organisms are likewise affected
adversely in conditions with suppressed DO. Since all aerobic
aquatic organisms need a certain amount of oxygen, the
consequences of total lack of dissolved oxygen due to a high BOD
can kill all inhabitants of the affected area.
If a high BOD is present, the quality of the water is usually
visually degraded by the presence of decomposing materials and
algae blooms due to the uptake of degraded materials that form
the foodstuffs of the algal populations.
Historically, the BOD^ test has also been used to evaluate the
performance of biological waste water treatment plants and to
establish effluent limitation values. However, objections to the
use of the BODS test have been raised.
The major objections are as follows:
1. The standard BOD5 test takes five days before the
results are available, thereby negating its use as a
day-to-day treatment plant operational indicator.
2. At the start of the BODjj test, seed culture
(microorganisms) is added to the BOD5 bottle. If the
seed culture was not acclimated, i.e., exposed to a
similar waste water in the past, it may not readily be
able to biologically degrade the waste. This results in
the reporting of a low BOD5 value. This situation is
very likely to occur when dealing with complex
industrial wastes, for which acclimation is required in
most cases. The necessity of using "acclimated
bacteria" makes it very important to take a seed from
the biological plant treating the waste or downstream of
the discharge in the receiving waterbody.
3. The BOD.5 test is sensitive to toxic materials, as are
all biological processes. Therefore, if toxic materials
are present in a particular waste water, the reported
BODJ5 value may very well be erroneous. This situation
73
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can be remedied by running a toxicity test, i.e.,
subsequently diluting the sample until the BOD5 value
reaches a plateau indicating that the material is at a
concentration which no longer inhibits biological
oxidation.
There has been much controversy concerning the use of BOD5 as a
measure of pollution, and there have been recommendations to
substitute some other parameter, e.g., COD or TOC. EPA has
recently pointed out that some or all of the previously cited
reasons make the BOD5 test a non-standard test, and ASTM's
Subcommittee D-19 has also recommended withdrawal of the BOD5_
test as a standard test.
However, some of the previously cited weaknesses of the BOD5 test
also make it uniquely applicable. It is the only parameter now
available which measures the amount of oxygen used by selected
microorganisms in metabolizing a waste water. The use of COD or
TOC to monitor the efficiency Of BOD5 removal in biological
treatment is possible only if there is a good correlation between
COD or TOC and BOD. After consideration of the advantages,
disadvantages and constraints, BODjj will continue to be used as a
pollutional indicator for the petroleum refining industry.
Typical raw waste load concentrations for each subcategory are
listed below:
Subcategory BOD5 RWL Range, mg/1
Topping 10 - 50
Cracking 30 - 600
Petrochemical 50-800
Lube 100 - 700
Integrated 100 - 800
As a matter of reference, typical BOD5. values for raw municipal
waste waters range between 100 and 300 mg/L.
COD
Chemical oxygen demand (COD) provides a measure of the equivalent
oxygen required to oxidize the materials present in a waste water
sample, under acid conditions with the aid of a strong chemical
oxidant, such as potassium dischromate, and a catalyst (silver
sulfate). One major advantage of the COD test is that the
results are available normally in less than three hours. Thus,
the COD test is a faster test by which to estimate the maximum
oxygen exertion demand a waste can make on a stream. However,
one major disadvantage is that the COD test does not
differentiate between biodegradable and non-biodegradable organic
material. In addition, the presence of inorganic reducing
chemicals (sulfides, reducible metallic ions, etc.) and chlorides
may interfere with the COD test.
The slow accumulation of refractory (resistant to biological
decomposition) compounds in watercourses has caused concern among
74
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various environmentalists and regulatory agencies. However,
until these compounds are identified, analytical procedures
developed to quantify them, and their effects on aquatic plants
and animals are documented, it may be premature (as well as
economically questionable) to require their removal from waste
water sources. • , ,'
Typical raw waste load concentrations for each subcategory are
listed below:
Subcategory COD RWL Range, mg/1
Topping 50 - 150
Cracking 150 - 400
Petrochemical 300 - 600
Lube 400 - 700
Integrated 300 - 600
Typical COD values for raw municipal waste waters are
between 200 mg/1 and 400 mg/1.
TOC
Total organic carbon (TOC) is a measure of the amount of carbon
in the organic material in a waste water sample. The TOC
analyzer withdraws a small volume of sample and thermally
oxidizes it at 150°C. The water vapor and carbon dioxide from
the combustion chamber (where the water vapor is removed) is
condensed and sent to an infrared analyzer, where the carbon
dioxide is monitored. This carbon dioxide value corresponds to
the total inorganic value. Another portion of the same sample is
thermally oxidized at 950°C, which converts all the carbonaceous
material to carbon dioxide; this carbon dioxide value corresponds
to the total carbon value. TOC is determined by subtracting the
inorganic carbon (carbonates and water vapor) from the total
carbon value.
The recently developed automated carbon analyzer has provided a
rapid and simple means of determining organic carbon levels in
waste water samples, enhancing the popularity of TOC as a
fundamental measure of pollution. The organic carbon
determination is free of many of the variables which plague the
COD and BOD analyses, yielding more reliable and reproducible
data. However, meaningful correlations between the three are
sometimes hard to develop.
Typical raw waste concentrations for each subcategory are
presented below:
Subcategory TOC RWL Range, mg/1
Topping 10-50
Cracking 50 - 500
Petrochemical 100 - 250
Lube 100 - 400
Integrated 50 - 500
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Typical values for raw municipal waste waters range between 50
and 250 mg/L.
TSS
In refineries, major sources of suspended matter are contributed
by crude storage, alkylation, crude desalting and finishing
operations. Quenching and removal operations in the production
of coke can contribute significant amounts of suspended fines to
the refinery effluent.
Suspended solids include both organic and inorganic materials.
The inorganic components include sand, silt, and clay. The
organic fraction includes such materials as grease, oil, tar,
animal and vegetable fats, various fibers, sawdust, hair, and
various materials from sewers. These solids may settle out
rapidly and bottom deposits are often a mixture of both organic
and inorganic solids. They adversely affect fisheries by
covering the bottom of the stream or lake with a blanket of
material that destroys the fish-food bottom fauna or the spawning
ground of fish. Deposits containing organic materials may
deplete bottom oxygen supplies and produce hydrogen sulfide,
carbon dioxide, methane, and other noxious gases.
In raw water sources for domestic use, state and regional
agencies generally specify that suspended solids in streams shall
not be present in sufficient concentration to be objectionable or
to interfere with normal treatment processes. Suspended solids
in water may interfere with many industrial processes, and cause
foaming in boilers, or encrustations on equipment exposed to
water, especially as the temperature rises. Suspended solids are
undesirable in water for textile industries; paper and pulp;
beverages; dairy products; laundries; dyeing; photography;
cooling systems, and power plants. Suspended particles also
serve as a transport mechanism for pesticides and other
substances which are readily adsorbed into or onto clay
particles.
Solids may be suspended in water for a time, and then settle to
the bed of the stream or lake. These settleable solids
discharged with man's wastes may be inert, slowly biodegradable
materials, or rapidly decomposable substances. While in
suspension, they increase the turbidity of the water, reduce
light penetration and impair the photosynthetic activity of
aquatic plants.
Solids in suspension are aesthetically displeasing, when they
settle to form sludge deposits on the stream or lake bed, they
are often much more damaging to the life in water, and they
retain the capacity to displease the senses. Solids, when
transformed to sludge deposits, may do a variety of damaging
things, including blanketing the stream or lake bed and thereby
destroying the living spaces for those benthic organisms that
would otherwise occupy the habitat. When of an organic and
therefore decomposable nature, solids use a portion or all of the
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dissolved oxygen available in the area. Organic materials also
serve as a seemingly inexhaustible food source for sludgeworms
and associated organisms.
Typical total suspended solids raw waste concentrations for each
subcategory are listed below:
Subcategory TSS RWL Range, mg/1
Topping 10 - 40
Cracking 10 - 100
Petrochemical 50 - 200
Lube 80 - 300
Integrated 20 - 200
Total suspended solids concentrations for typical raw municipal
waste waters range from 100 to 300 mg/1.
Freon Extractables - Oil and Grease
No solvent is known which will directly dissolve only oil or
grease, thus the manual "Methods for the Chemical Analysis of
Water and Wastes 1971" distributed by the Environmental
Protection Agency states that their method for oil and grease
determinations includes the freon extractable matter from waters.
In the petroleum refining industry, oils, greases, various other
hydrocarbons and some inorganic compounds will be included in the
freon extraction procedure. The majority of material removed by
the procedure in a refinery waste water will, in most instances,
be of a hydrocarbon nature. These hydrocarbons, predominately
oil and grease type compounds, will make their presence felt in
the COD, TOC, TOD, and usually the BOD tests where high test
values will result. The oxygen demand potential of these freon
extractables is only one of the detrimental effects exerted on
water bodies by this class of compounds. Oil emulsions may
adhere to the gills of fish or coat and destroy algae or other
plankton. Deposition of oil in the bottom sediments can serve to
exhibit normal benthic growths, thus interrupting the aquatic
food chain. Soluble and emulsified materials ingested by fish
may taint the flavor of the fish flesh. Water soluble components
may exert toxic action on fish. The water insoluble hydrocarbons
and free floating emulsified oils in a waste water will affect
stream ecology by interfering with oxygen transfer, by damaging
the plumage and coats of water animals and fowls, and by con-
tributing taste and toxicity problems. The effect of oil spills
upon boats and shorelines and their production of oil slicks and
iridescence upon the surface of waters is well known. The
average freon extractable material recorded by a refinery survey
for effluent waters from the refineries ranged from a maximum of
37 mg/1 to a minimum of 4. mg/1.
Grease is defined in "Webster's Third New International
Dictionary" as a thick lubricant. The class of refinery products
known as greases are usually included in the freon extractable
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portions of a water analysis. Some thick heavy petroleum
products coat the silt and sediment of a stream bottom samples
which have been contaminated by oily products over a long period.
An infrared scan of such an extract done on bottom sediments from
the New York Harbor area compares closely to a typical 90 w
automative grease. Such bottom contamination can, of course,
exert influence upon the aquatic life of a stream, estuary, bay
or other water body. Typical oil and grease concentrations for
each sutcategory are listed below:
Freon Extractables as Oil and Grease
Subcategory RWL Range, mg/1
Topping 10-50
Cracking 15 - 300
Petrochemical 20 - 25C
Lube UO - 400
Integrated 20 - 500
Ammonia as Nitrogen
Ammonia is commonly found in overhead condensates from
distillation and cracking and from desalting. It is usually
found combined with sulfide as an ammonium sulfide salt. Ammonia
is a common product of the decomposition of organic matter. Dead
and decaying animals and plants along with human and animal body
wastes account for much of the ammonia entering the aquatic
ecosystem. Ammonia exists in its non-ionized form only at higher
pH levels and is the most toxic in this state. The lower the pH,
the more ionized ammonia is formed and its toxicity decreases.
Ammonia, in the presence of dissolved oxygen, is converted to
nitrate (NO3) by nitrifying bacteria. Nitrite (t)O2) , which is an
intermediate product between ammonia and nitrate, sometimes
occurs in quantity when depressed oxygen conditions permit.
Ammonia can exist in several other chemical combinations
including ammonium chloride and other salts.
Nitrates are considered to be among the poisonous ingredients of
mineralized waters, with potassium nitrate being more poisonous
than sodium nitrate. Excess nitrates cause irritation of the
mucous linings of the gastrointestinal tract and the bladder; the
symptoms are diarrhea and diuresis, and drinking one liter of
water containing 500 mg/1 of nitrate can cause such symptoms.
Infant methemoglobinemia, a disease characterized by certain
specific blood changes and cyanosis, may be caused by high
nitrate concentrations in the water used for preparing feeding
formulae. While it is still impossible to state precise
concentration limits, it has been widely recommended that water
containing more than 10 mg/1 of nitrate nitrogen (N03-N) should
not be used for infants. Nitrates are also harmful in
fermentation processes and can cause disagreeable tastes in beer.
In most natural water the pH range is such that ammonium ions
(NHJ4+) predominate. In alkaline waters, however, high
concentrations of un-ionized ammonia in undissociated ammonium
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hydroxide increase the toxicity of ammonia solutions. In streams
polluted with sewage, up to one half of the nitrogen in the
sewage may be in the form of free ammonia, and sewage may carry
up to 35 mg/1 of total nitrogen. It has been shown that at a
level of 1.0 mg/1 un-ionized ammonia, the ability of hemoglobin
to combine with oxygen is impaired and fish may suffocate.
Evidence indicates that ammonia exerts a considerable toxic
effect on all aquatic life within a range of less than 1.0 mg/1
to 25 mg/1, depending on the pH and dissolved oxygen level
present.
Ammonia can add to the problem of eutrophication by supplying
nitrogen through its breakdown products. Some lakes in warmer
climates, and others that are aging quickly are sometimes limited
by the nitrogen available. Any increase will speed up the plant
growth and decay process.
Typical ammonia as nitrogen raw waste concentrations for each
subcategory are listed below:
Subcategory NH3 - N RWL Range, mg/1
Topping 0.05 - 20
Cracking 0.5 - 200
Petrochemical 4-300
Lube 1-120
Integrated 1-250
Phenolic Compounds
Catalytic cracking, crude distillation, and product finishing and
treating, are the major sources of phenolic compounds. Catalytic
cracking produces phenols by the decomposition of multi-
cyclicaromatics, such as anthracene and phenanthrene. Some
solvent refining processes use phenol as a solvent and although
it is salvaged by recovery processes, losses are inevitable.
Many phenolic compounds are more toxic than pure phenol; their
toxicity varies with the combinations and general nature of total
wastes. The effect of combinations of different phenolic
compounds is cumulative.
Phenols and phenolic compounds are both acutely and chronically
toxic to fish and other aquatic animals. Also, chlorophenols
produce an unpleasant taste in fish flesh that destroys their
recreational and commercial value.
It is necessary to limit phenolic compounds in raw water used for
drinking water supplies, as conventional treatment methods used
by water supply facilities do not remove phenols. The ingestion
of concentrated solutions of phenols will result in severe pain,
renal irritation, shock and possibly death.
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Phenols also reduce the utility of water for certain industrial
uses, notably food and beverage processing, where it causes
unpleasant tastes and odors in the product.
Typical phenolic
are listed below:
raw waste concentrations for each subcategory
Subcategory
Topping
Cracking
Petroleum
Lube
Integrated
Phenolics, RWL Range, rag/1
0-200
0-100
0.5-50
0.1-25
0.5-50
Sulfides
In the petroleum refining industry, major sources of sulfide
wastes are crude desalting, crude distillation and cracking
processes. Sulfides cause corrosion, impair product quality, and
shorten the useful catlyst life. They are removed by caustic,
diethanciamine, water or steam, or appear as sour condensate
waters in these initial processing operations. Hydrotreating
processes can be used to remove sulfides in the feedstock. Most
removed and recovered sulfide is burned to produce sulfuric acid
or elemental sulfur.
When present in water, soluble sulfide salts can reduce pH; react
with iron and other metals to cause black precipitates; cause
odor problems; and can be toxic to aquatic life. The toxicity of
solutions of sulfides to fish increases as the pH value is
lowered. Sulfides also chemically react with dissolved oxygen
present in water, thereby lowering dissolved oxygen levels.
Typical sulfide raw waste concentrations for each subcategory are
listed below:
Subcategory
Topping
Cracking
Petroleum
Lube
Integrated
Total Chromium
Sulfide, RWL Range, mg/1
0-5
0-400
0-200
0-40
0-60
Chromium may exist in water supplies in both the hexavalent and
trivalent state. Chromium salts are used extensively in
industrial processes and chromate compounds are frequently added
to cooling water for corrosion control. The toxicity of chromium
salts toward aquatic life varies widely with the species,
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temperature, pH, concentration, and synergistic or antagonisitc
effects of other water constituents, especially hardness.
Chromium, in its various valence states, is hazardous to man. It
can produce lung tumors when inhaled and induces skin
sensitizations. Large doses of chromates have corrosive effects
on the intestinal tract and can cause inflammation of the
kidneys. Levels of chromate ions that have no effect on man
appear to be so low as to prohibit determination to date.
The toxicity of chromium salts toward aquatic life varies widely
with the species, temperature, pH, valence of the chromium, and
synergistic or antagonistic effects, especially that of hardness.
Fish are relatively tolerant of chromium salts, but fish food
organisms and other lower forms of aquatic life are extremely
sensitive. Chromium also inhibits the growth of algae.
In some agricultural crops, chromium can cause reduced growth or
death of the crop. Adverse effects of low concentrations of
chromium on corn, tobacco and sugar beets have been documented.
Typical total chromium raw waste load concentrations for each
subcategory are listed below:
Subcategory Total Chromium, RWL Range, mg/1
Topping 0-3
Cracking 0-6
Petrochemical 0-5
Lube 0-2
Integrated 0-2
Hexavalent Chromium
The hexavalent chromium content of potable water supplies within
the U.S. has been reported to vary between 3 to UO micrograms per
liter. In the +6 oxidation state; chromium is usually combined
with oxygen in the form of the oxide, chromium trioxide cr03 or
the Oxyanions chromate Cr04= and dichrornate Cr207. Chromates
will generally be present in a refinery waste stream when they
are used as corrosion inhibitors in cooling water.
Other Pollutants
Other pollutants which were examined in this study of refining
waste water practices included: total dissolved solids, cyanide,
zinc, temperature, various metallic ions, chloride, fluoride and
phosphates.
It was determined that these parameters are generally found in
refineries in small enough amounts as not to warrant accross the
board treatment. Restrictions on these parameters may be
required as a result of water quality requirements.
Zinc
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Zinc is an essential and beneficial element in human metabolism
when its intake to an organism is limited. At higher amounts
zinc can lead to gastrointestinal irritation and large amounts of
the metal have been reported to upset trickling filter and
activated sludge waste treatment processes.
Concentrations of zinc in excess of 5 mg/1 in raw water used for
drinking water supplies cause an undesirable taste which persists
through conventional treatment. Zinc can have an adverse effect
on man and animals at high concentrations.
In soft water, concentrations of zinc ranging from 0.1 to 1.0
mg/1 have been reported to be lethal to fish. Zinc is thought to
exert its toxic action by forming insoluble compounds with the
mucous that covers the gills, by damage to the gill epithelium,
or possibly by acting as an internal poison. The sensitivity of
fish to zinc varies with species, age and condition, as well as
with the physical and chemical characteristics of the water.
Some acclimatization to the presence of zinc is possible. It has
also been observed that the effects of zinc poisoning may not
become apparent immediately, so that fish removed from zinc-
contaminated to zinc-free water (after 4-6 hours of exposure to
zinc) may die 48 hours later. The presence of copper in water
may increase the toxicity of zinc to aquatic organisms, but the
presence of calcium or hardness may decrease the relative
toxicity.
Observed values for the distribution of zinc in ocean waters vary
widely. The major concern with zinc compounds in marine waters
is not one of acute toxicity, but rather of the long-term sub-
lethal effects of the metallic compounds and complexes. From an
acute toxicity point of view, invertebrate marine animals seem to
be the most sensitive organisms tested. The growth of the sea
urchin, for example, has been retarded by as little as 30 ug/1 of
zinc.
Zinc sulfate has also been found to be lethal to many plants, and
it could impair agricultural uses.
Zinc compounds can be used as corrosion inhibitors for cooling
water. In addition, zinc is produced in the combustion of fossil
fuels and may find its way into refining waters by leaching
processes.
A survey of effluents from petroleum refineries across the U.S.
reports zinc concentrations of .04 to 1.84 mg/1 in the effluent
waters. The median concentration of zinc found in the effluents
was .16 mg/1.
TDS
Dissolved solids in refinery waste waters consist mainly of
carbonates, chlorides, and sulfates. U.S. Public Health Service
Drinking Water Standards for total dissolved solids are set at
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500 mg/L on the basis of taste thresholds. Many communities in
the United States use water containing from 2,000 to 4,000 mg/1
of dissolved solids. Such waters are not palatable and may have
a laxative effect on certain people. However, the geographic
location and availability of potable water will dictate
acceptable standards. The following is a summary of a literature
survey indicating the levels of dissolved solids which should not
interfere with the indicated beneficial use:
Domestic Water Supply 1,000 mg/1
Irrigation 700 mg/1
Livestock Watering 2,500 mg/1
Freshwater Fish and Aquatic Life 2,000 mg/1
Median total dissolved solids concentrations for refinery
effluents are 400-700 mg/L. The extensive amount of process
water recycle and reuse is primarily responsible for these high
concentrations.
Because dissolved solids concentrations are intimately tied to
process recycle and the quality of the process raw water source;
it is recommended that this parameter be dictated by local water
quality requirements.
Cyanides
Cyanides in water derive their toxicity primarily from
undissolved hydrogen cyanide (HCN) rather than from the cyanide
ion (CN~). HCN dissociates in water into H+ and CN~ in a pH-
dependent reaction. At a pH of 7 or below, less than 1 percent
of the cyanide is present as CN-; at a pH of 8, 6.7 percent; at a
pH of 9, U2 percent; and at a pH of 10, 87 percent of the cyanide
is dissociated. The toxicity of cyanides is also increased by
increases in temperature and reductions in oxygen tensions. A
temperature rise of 10°C produced a two- to threefold increase in
the rate of the lethal action of cyanide.
Cyanide has been shown to be poisonous to humans, and amounts
over 18 ppm can have adverse effects. A single dose of 6, about
50-60 mg, is reported to be fatal.
Trout and other aquatic organisms are extremely sensitive to
cyanide. Amounts as small as .1 part per million can kill them.
Certain metals, such as nickel, may complex with cyanide to
reduce lethality especially at higher pH values, but zinc and
cadmium cyanide complexes are exceedingly toxic.
When fish are poisoned by cyanide, the gills become considerably
brighter in color than those of normal fish, owing to the
inhibition by cyanide of the oxidase responsible for oxygen
transfer from the blood to the tissues.
Cyanide raw waste load data for the refining industry show median
values of 0.0 - 0.18 mg/L for the five subcategories. Only
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occasionally are any values found above 1.0 mg/1. At these
concentration ranges, no inhibition is expected in biological
waste facilities. Consequently, the values are such that
specific limitations are not required. Cyanides are on the EPA
toxic materials list and limitations based on health effects will
be made available at a later date.
pH (Acidity and Alkalinity)
The acidity of a waste is a measure of the quantity of compounds
contained therein which will dissociate in an aqueous solution to
produce hydrogen ions. Acidity in petroleum refining waste
waters can be contributed by both organic and inorganic compound
dissociation. Most mineral acids found in waste waters (sulfuric
acid, hydrochloric acid, nitric acid, phosphoric acid) are
typically strong acids. The most common weaker acids found
include the organic acids such as carboxyl and carbonic.
Compounds which contribute to alkalinity in waste waters are
those which dissociate in aqueous solutions to produce hydroxyl
ions. Alkalinity is often defined as the acid-consuming ability
of the waste water and is measured by titrating a given volume of
waste with standard acid until all of the alkaline material has
reacted to form salts. In effect, alkalinity is the exact
opposite of acidity; high alkalinities lower the hydrogen ion
concentration of a solution and raise its pH.
Most refinery waste waters are alkaline due to the presence of
ammonia and the use of caustic for sulfur removal. Cracking
(both thermal and catalytic) and crude distillation are the
principal sources of alkaline discharges. Alkylation and
polymerization utilize acids as catalysts and produce severe
acidity problems.
Extreme pH values are to be avoided because of effects on
emulsification of oil, corrosion, precipitation, volatilization
of sulfides and other gases, etc. In streams and water courses,
extreme pH levels accentuates the adverse effects of other
pollutants as well as causing toxicity itself.
The hydrogen ion concentration in an aqueous solution is
represented by the pH of that solution. The pH is defined as the
negative logarithm of the hydrogen ion concentration in a
solution. The pH scale ranges from zero to fourteen, with a pH
of seven, representing neutral conditions, i.e., equal
concentrations of hydrogen and hydroxyl ions. Values of pH less
than seven indicate increasing hydrogen ion concentration or
acidity; pH values greater than seven indicate increasing
alkaline conditions. The pH value is an effective parameter for
predicting chemical and biological properties of aqueous
solutions. It should be emphasized that pH cannot be used to
predict the quantities of alkaline or acidic materials in a water
sample. However, most effluent and stream standards are based on
maximum and minimum allowable pH values rather than on alkalinity
and acidity.
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Since pH RWL values are not additive, it is not always possible
to predict the final pH of a process waste water made up of
multiple discharges. In addition, the individual refinery's
discharge characteristics will dictate final pH ranges, which may
be kept within the acceptable range merely by equalization, or
which may require more sophisticated neutralization facilities.
However, it is recommended that a pH range of 6.0 to 9.0 be
established as the .effluent limitation.
Temperature
Crude desalting, distillation, and cracking contribute
substantial thermal wasteloads.
Temperature is one of the most important and influential water
quality characteristics. Temperature determines those species
that may be present; it activates the hatching of young,
regulates their activity, and stimulates or suppresses their
growth and development; it attracts, and may kill when the water
becomes too hot or becomes chilled too suddenly. Colder water
generally suppresses development. Warmer water generally
accelerates activity and may be a primary cause of aquatic plant
nuisances when other environmental factors are suitable.
Temperature is a prime regulator of natural processes within the
water environment. It governs physiological functions in
organisms and, acting directly or indirectly in combination with
other water quality constituents, it affects aquatic life with
each change. These effects include chemical reaction rates,
enzymatic functions, molecular movements, and molecular exchanges
between membranes within and between the physiological systems
and the organs of an animal.
Chemical reaction rates vary with temperature and generally
increase as the temperature is increased. The solubility of
gases in water varies with temperature. Dissolved oxygen is
decreased by the decay or decomposition of dissolved organic
substances and the decay rate increases as the temperature of the
water increases reaching a maximum at about 30°C (86°F). The
temperature of stream water, even during summer, is below the
optimum for pollution-associated bacteria. Increasing the water
temperature increases the bacterial multiplication rate when the
environment is favorable and the food supply is abundant.
Reproduction cycles may be changed significantly by increased
temperature because this function takes place under restricted
temperature ranges. Spawning may not occur at all because
temperatures are too high. Thus, a fish population may exist in
a heated area only by continued immigration. Disregarding the
decreased reproductive potential, water temperatures need not
reach lethal levels to decimate a species. Temperatures that
favor competitors, predators, parasites, and disease can destroy
a species at levels far below those that are lethal.
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Fish food organisms are altered severely when temperatures
approach or exceed 90°F. Predominant algal species change,
primary production is decreased, and bottom associated organisms
may be depleted or altered drastically in numbers and
distribution. Increased water temperatures may cause aquatic
plant nuisances when other environmental factors are favorable.
Synergistic actions of pollutants are more severe at higher water
temperatures. Given amounts of domestic sewage, refinery wastes,
oils, tars, insecticides, detergents, and fertilizers more
rapidly deplete oxygen in water at higher temperatures, and the
respective toxicities are likewise increased.
When water temperatures increase, the predominant algal species
may change from diatoms to green algae, and finally at high
temperatures to blue-green algae, because of species temperature
preferentials. Blue-green algae can cause serious odor problems.
The number and distribution of benthic organisms decreases as
water temperatures increase above 90°F, which is close to the
tolerance limit for the population. This could seriously affect
certain fish that depend on benthic organisms as a food source.
The cost of fish being attracted to heated water in winter months
may be considerable, due to fish mortalities that may result when
the fish return to the cooler water.
Rising temperatures stimulate the decomposition of sludge,
formation of sludge gas, multiplication of saprophytic bacteria
and fungi (particularly in the presence of organic wastes), and
the consumption of oxygen by putrefactive processes, thus
affecting the esthetic value of a water course.
In general, marine water temperatures do not change as rapidly or
range as widely as those of freshwaters. Marine and estuarine
fishes, therefore, are less tolerant of temperature variation.
Although this limited tolerance is greater in estuarine than in
open water marine species, temperature changes are more important
to those fishes in estuaries and bays than to those in open
marine areas, because of the nursery and replenishment functions
of the estuary that can be adversely affected by extreme
temperature changes.
Other Metallic Ions
Several metallic ions in addition to chormium and zinc may be
found in refinery effluents. The major sources for their
presence in waste water are from the crude itself and corrosion
products. The concentration of metallic ions varies considerably
dependent upon the effectiveness of catalyst recovery in
production process. Table 25 lists those metals which may be
commonly found in petroleum refinery effluents. Dissolved
metallic ions create turbidity and discoloration, can precipitate
to form bottom sludges, and can impart taste to water.
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TABLE 25
Metallic Ions Commonly Found in Effluents from Petroleum Refineries
Aluminum
Arsenic
Cadmium
Chromium
Cobalt
Copper
Iron
Lead
Mercury
Niche1
Vanadium
Zinc
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Metallic ions such as copper, and cadmium are toxic to
microorganisms because of their ability to tie up the proteins in
the key enzyme systems of the microogranisms.
Chlorides:
Chloride ion is one of the major anions found in water and
produces a salty taste at a concentration of about 250 mg/1.
Concentrations of 1000 mg/1 may be undetectable in waters which
contain appreciable amounts of calcium and magnesium ions.
Water is invariably associated with naturally occurring hydro-
carbons underground and much of this water contains high amounts
of sodium chloride. The saltiest oil field waters are located in
the mid-continent region of the country where the average
dissolved solids content is 174,000 ppm; therefore, waters
containing high levels of salt may be expected.
Copper chloride may be used in a sweetening process and aluminum
chloride in catalytic isomerization. These products may also
find their ways to waste streams.
The toxicity of chloride salts will depend upon the metal with
which they are combined. Because of the rather high
concentration of the anion necessary to initiate detrimental
biological effects, the limit set upon the concentration of the
metallic ion with which it may be tied, will automatically govern
its concentration in effluents, in practically all forms except
potassium, calcium, mganesium, and sodium.
Since sodium is by far the most common (sodium 75 percent,
magnesium 15 percent, and calcium 10 percent) the concentration
of this salt will probably govern the amount of chlorides in
waste streams from petroleum refineries.
It is extremely difficult to pinpoint the exact amount of sodium
chloride salt necessary to result in toxicity in waters. Large
concentrations have been proven toxic to sheep, swine, cattle or
poultry.
In swine fed diets of swill containing 1.5 to 2.0% salt by
weight, poisoning symptoms can be induced if water intake is
limited and other factors are met. The time interval necessary
to accomplish this is still about one full day of feeding ar this
level.
Since problems of corrosion, taste and quality of water necessary
for industrial or agricultural purposes occur at sodium chloride
concentration levels below those at which toxic effects are
experienced, these factors will undoubtedly determine the amount
of chlorides allowed to escape in waste streams from refining
operations. The study of refinery effluents previously
mentioned, placed net chloride levels at values ranging from 57
to 712 mg/1. The median value was 176 mg/1.
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Fluoride: HF
Alkalation units (when hydrofluoric acid is used) can contribute
fluoride ion to the plant's waste effluent. Since calcium and
barium fluoride are insoluble in water the fluorides will by
necessity be associated with other cations.
In concentrations of approximately 1 mg/1 in potable water
supplies fluorides have been found to be an effective preventor
of dental cavities. In concentrations greater than this amount,
fluorides can cause molting of tooth enamel and may be
incorporated into the bones.
Natural waters can contain levels of fluorides up to 10 ppm. If
these waters are to be used for potable supplies or for certain
industrial or agricultural purposes the fluoride levels must be
reduced. Since many municipal waters are artificially
fluoridated as a dental health aid, the U.S. Public Health
Service has placed limits on the total amounts of fluorides a
water supply may contain. Their recommended control levels
depend upon temperature and are expressed as lower, optimum, and
upper limits. Optimum limits range from .7 to 1.2 mg/1. If
values exceed two times the optimum value, the supply must be
rejected or the fluoride content lowered. Because refinery
effluents may empty into water ways which may eventually become
public supplies, the maximum permissible limits of fluorides
present in an effluent will probably be derived from the USPHS
control limits for drinking water.
Phosphate - Total
Various forms of phosphates find their way into refinery
effluents. They range through several organic and inorganic
species and are usually contributed by corrosion control
chemicals. Plant cooling systems may contain 20 to 50 mg/1 of
phosphate ion.
Phosphorus is an element which is essential to growth of an
organism. It may at times become a growth limiting nutrient in
the biological system of a water body. In these instances an
over abundance of the element contributed from an outside source
may stimulate the growth of photosynthetic aquatic macro and
micro-organisms resulting in nuisance problems. Since the forms
of phosphorus in waters or industrial wastes are so varied, the
term total phosphate has been used to indicate all the phosphate
present in an analyzed sample regardless of the chemical form.
Also, many phosphorus compounds tend to degrade rather readily,
and in these less complex forms phosphate may be readily utilized
in the aquatic life cycle. It is therefore reasonable to direct
concern toward the total amount of phosphorus present rather than
chemical structure it may assume, for in only very unusual cases
may the form or concentration of the element present in a waste
stream be toxic. Total phosphate values noted on a nationwide
refinery survey were 9.49 mg/1 maximum and .096 mg/1 minimum for
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effluents. The median value was .68 mg/1 expressed as
phosphorus.
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SECTION VII
CONTROL AND TREATMENT TECHNOLOGY
Petroleum refinery waste waters vary in quantity and quality from
refinery to refinery. However, the wastes are readily treatable.
The results of the industry survey indicate, as would be
expected, that techniques for in-process control are general
across the industry and the specific application of these
techniques at individual plants determines their success. Local
factors such as climate, discharge criteria, availability of
land, or other considerations may dictate the use of different
waste water treatment processes to reach an acceptable effluent.
The survey has shown that although the end-of-pipe waste water
treatment technologies used throughout the petroleum refining
industry have a marked similarity in operational steps, a
considerable variation in treatment results exist. The processes
used for treating refinery waste water, however, are similar in
purpose; namely—maximizing oil recovery and minimizing the
discharge of other pollutants. The wastewater treatment
technology described below is generally applicable across all
industry sutcategories.
In-Plant Control/Treatment Techniques
In-plant practices are the sole determinant of the amount of
waste water to be treated. There are two types of in-plant
practices that reduce flow to the treatment plant. First, reuse
practices involving the use of water from one process in another
process. Examples of this are: using stripper bottoms for
makeup to crude desalters; using blowdown from high pressure
boilers as feed to low pressure boilers; and using treated
effluent as makeup water whereever possible. Second, recycle
systems that use water more than once for the same purpose.
Examples of recycle systems are: the use of steam condensate as
boiler feedwater; and cooling towers. The reduction or
elimination of a waste stream allows the end-of-pipe processes to
be smaller, provide better treatment, and be less expensive.
Since no treatment process can achieve 100 percent pollutant
removal from the individual stream, reduction in flow allows for
a smaller pollutant discharge.
Housekeeping
In addition to reuse/recycle of water streams and reduction in
flows by other in-plant techniques, another effective in-plant
control is good housekeeping. Examples of good housekeeping
practices are: minimizing waste when sampling product lines;
using vacuum trucks or dry cleaning methods to clean up any oil
spills; using a good maintenance program to keep the refinery as
leakproof as possible; and individually treating waste streams
with special characteristics, such as spent cleaning solutions.
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The use of dry cleaning, without chemicals, aids in reducing
water discharges to the sewer. Using vacuum trucks to clean up
spills and charging of this recovered material to slop oil tanks,
reduces the discharge of both oil and water to the waste water
system. The oil can also be recovered for reprocessing. Process
units should be curbed to prevent the contamination of clean
areas with oily storm runoff and to prevent spills from spreading
widely. Prompt cleanup of spills will also aid in reducing
discharges to the sewer systems. Additionally, sewers should be
flushed regularly to prevent the buildup of material in the
sewer, eliminating sudden surges of pollutants during heavy
rains. Collection vessels should also be provided whenever
maintenance is performed on liquid processing units, to prevent
accidental discharges to the sewers.
Operations during turnaround present special problems. Wastes
generated by cleaning tanks and equipment should be collected,
rather than draining directly to the sewer. The wastes from
these holding tanks should be gradually bled to the sewer, after
first pretreating as necessary to eliminate deleterious effects
on the waste water treatment system. An alternative method of
disposal is through the use of contract carriers.
While these are not all the examples of good housekeeping
practices which can be cited for refinery operations, it is
evident that housekeeping practices within a refinery can have
substantial impact on the loads discharge to the waste treatment
facilities. The application of good housekeeping practices to
reduce waste loads requires judicious planning, organization and
operational philosophy.
Process Technology
Many of the newer petroleum refining processes are being designed
or modified with reduction of water use and subsequent
minimization of contamination as design criteria; although no
major innovations in basic refining technology are anticipated.
Improvements which can be expected to be implemented in existing
refineries are: primarily dedicated to better control of refinery
processes and other operations; elimination of marginal
processing operations, and specific substitution of processes
and/or cooling techniques to reduce discharge loads to waste
treatment facilities. Examples of the possible changes which may
be implemented include:
1. Substitution of improved catalysts which have higher
activity and longer life, consequently requiring less
regeneration and resulting in lower waste water loads.
2. Replacement of barometric condensers with surface
condensers or air fan coolers, reducing a major oil-
water emulsion source. As an alternative, several
refineries are using oily water cooling tower systems,
with the barometric condensers, equipped with oil
separation/emulsion breaking auxiliary equipment.
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3. Substitution of air fan coolers to relieve water cooling
duties simultaneously reduces blowdown discharges.
U. Installation of hydrocracking and hydrotreating
processes will allow generation of lower waste loadings
than the units they replace. The rapid pace at which
such units are being installed is exerting and will
continue to exert a strong influence on the reduction of
waste loadings, particularly sulfides and spent
caustics.
5. Installation of automatic monitoring instrumentation,
such as TOC monitors, will allow early detection of
process upsets which result in excessive discharges to
sewers.
6. Increased use of improved drying, sweetening, and
finishing procedures will minimize spent caustics and
acids, water washes, and filter solids requiring
disposal.
Cooling Towers
Cooling towers eliminate large volumes of once through cooling
water by passing heated water through heat exchange equipment.
By recycling the cooling water many times, the amount of water
used is greatly reduced. The number of times cooling water can
be reused is determined by the total dissolved solids (TDS)
content of the water, and the effects high dissolved solids have
on process equipment. When the TDS becomes too high, scaling
occurs and heat transfer efficiency decreases. The TDS level in
the circulating water is controlled by discharging a portion of
the steam (blowdown) from the system. The higher the allowable
TDS level, the greater number of cycles of concentration and the
less make-up water is required (87). Installation of cooling
towers will reduce the amount of water used within the refinery
by at least 90 percent (87).
There are three types of cooling towers (106); wet or
evaporative, dry, and combined "wet-dry."
Evaporative Cooling Systems
Evaporative cooling systems transport heat by transfer of the
latent heat of vaporization. This results in a temperature
decrease of circulating water and a temperature and humidity
increase of cooling air.
Spray ponds are an evaporative cooling system using natural air
currents and forced water movement. Because of their
inefficiency, spray ponds are used less in industry than cooling
towers. Cooling towers have a higher efficiency because they
provide more intimate contact between the air and water. As the
water falls over the packing, it exposes a large contact surface
area. As the water heats up the air, the air can absorb more
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water. The more water evaporated, the more heat is transferred
(106). Because an evaporative cooling tower is dependent on
ambient temperatures and humidity, its performance is variable
throughout the year. There are three types of evaporative
cooling towers: mechanical draft towers; atmospheric towers,
which use wind or natural air currents; and natural draft towers,
which use tall stacks to move air by stack effect. Most
refineries use mechanical draft towers, which have baffles,
called drift eliminators, to separate entrained water from the
air stream, thus reducing the amount of water carried into the
air. The evaporative system is the least costly of all cooling
towers.
Dry Cooling Systems
There are two types of dry air cooling systems. Either system
can be used with either mechanical or natural draft cooling
towers. Most refineries use mechanical draft towers on indirect
condensing systems. The tubes used in dry cooling equipment have
circumferential fins to increase the heat transfer area. Most
tube designs have an outside to inside surface area ratio of
20:1. (106) The advantage of the dry air system is that it
requires no makeup water and there is no water entrainment. Dry
air cooling systems are being increasingly used to reduce the
amount of water discharged to the waste water treatment plant. A
disadvantage of the dry cooling process is that it has low rates
of heat transfer requiring large amounts of land and uses more
power than other cooling systems. The dry cooling tower is also
more expensive to install than evaporative systems.
Wet-Dry Systems
The wet-dry systems use an evaporative and non-evaporative
cooling tower in either series or parallel, each of which can be
operated with a mechanical or natural draft tower. The series
design has the evaporative cooling process preceeding the dry
process with respect to the air flow. This lowers the
temperature of the air entering the dry process which would mean
a smaller unit could be used. The problem with this method is
that solids are deposited in the dry tower due to drift from the
wet section. The parallel process uses a dry cooling tower
upstream of the wet section, each of which has its own air
supply. The two air streams are mixed and discharged, reducing
the vapor plume.
Recycle/Reuse Practices
Recycle/reuse can be accomplished either by return of the waste
water to its original use, or by using it to satisfy a lower
quality demand. The recycle/reuse practices within the refining
industry are extremely varied and only a few examples are
described briefly below:
1. Reduction of once-through cooling water results in
tremendously decreased total effluents.
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2. Sour water stripper bottoms are being used in several
refineries as make-up water for crude desalter
operations. These sour water bottoms are initially
recovered from overhead accumulators on the catalytic
cracking units.
3. Regeneration of contact process steam from contaminated
condensate will reduce the contact process waste water
to a small amount of blowdown. This scheme can be used
to regenerate steam in distillation towers or dilution
steam stripping in pyrolysis furnaces.
H. Reuse of waste water treatment plant effluent as cooling
water, as scrubber water, or as plant make-up water,
reduces total make-up requirements.
5. Cooling tower blowdowns are frequently reused as seal
water on high temperature pump service, where mechanical
seals are not practicable.
6. Storm water retention ponds are frequently used as a
source of fire water or other low quality service
waters.
Many other conservation methods can be implemented, such as the
use of stripped sour water as low pressure (LP) boiler make-up,
and LP boiler blowdown as make-up water for crude desalting.
However, these, and the other possible recycle/reuse cases
outlined above must be examined by the individual refinery in
light of its possible advantages/disadvantages, insofar as
product quality or refining process capabilities are affected.
For example, one refinery has reported that reuse of sour water
stripper bottoms for desalting resulted in a desalted crude which
was difficult to process downstream.
At-Source Pretreatment
Major at-source pretreatment processes which are applicable to
individual process effluents or groups of effluents within a
refinery are stripping of sour waters, neutralization and
oxidation of spent caustics, ballast water separation, and slop
oil recovery. The particular areas of application of these
processes are discussed below.
Sour Water Stripping
Sour or acid waters are produced in a refinery when steam is used
as a stripping medium in the various cracking processes. The
hydrogen sulfide, ammonia and phenols distribute themselves
between the water and hydrocarbon phases in the condensate. The
concentrations of these pollutants in the water vary widely
depending on crude sources and processing involved.
The 1 purpose of the treatment of sour water is to remove sulfides
(as hydrogen sulfide, ammonium sulfide, and polysulfides) before
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the waste enters the sewer. The sour water can be treated by:
stripping with steam or flue gas; air oxidation to convert
hydrogen sulfide to thiosulfates; or vaporization and
incineration.
Sour water strippers are designed primarily for the removal of
sulfides and can be expected to achieve 85-99 percent removal.
If acid is not required to enhance sulfide stripping, ammonia
will also be stripped with the percentage varying widely with
stripping temperature and pH. If acid is added to the waste
water, essentially none of the ammonia will be removed. Thus,
ammonia removals in sour water strippers vary from 0 to 99
percent. Depending upon such conditions as waste water pH,
temperature, and contaminant partial pressure; phenols and
cyanides can also be stripped with removal as high as 30 percent.
The bottoms from the stripper usually go to the desalter where
most of the phenols are extracted and the waste water can be sent
to the regular process water treating plant. COD and BODJ5 are
reduced because of the stripping out of phenol and oxidizable
sulfur compounds.
The heated sour water is stripped with steam or flue gas in a
single stage packed or plate-type column. Two-stage units are
also being installed to enhance the separate recovery of sulfide
streams and ammonia streams. Hydrogen sulfide released from the
waste water can be recovered as sulfuric acid or sulfur, or may
be burned in a furnace. The bottoms have a low enough sulfide
concentration to permit discharge into the general waste water
system for biological treatment. If the waste contains ammonia,
it is neutralized with acid before steam stripping. The waste
liquid passes down the stripping column while the stripping gas
passes upward. Most refiners now incinerate th sour water
stripper acid gases without refluxing the stripper. This
converts the ammonia to nitrogen with possibly traces of nitrogen
oxides. Due to the high concentrations of sulfur dioxide
produced more complex processing will probably be required in the
future.
Several stripping processes are available. These include:
Chevron WWT; ammonium sulfate production; a dual burner Claus
sulfur plant; and the Howe-Baker ammonex process. Deep well
injection and oxidation to the thiosulfate are also being used,
but in the future probably won't do a good enough job.
The Chevron WWT process (37) is basically two stage stripping
with ammonia pruification, so that the hydrogen sulfide and
ammonia are separated. The hydrogen sulfide would go to a
conventional Claus sulfur plant and the ammonia can be used as
fertilizer.
Ammonium sulfate can be produced by treating with sulfuric acid
but a very dilute solution is produced and concentrating it for
sale as fertilizer is expensive. Again the hydrogen sulfide goes
to a conventional Claus sulfur plant.
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A dual burner Glaus sulfur process is generally the answer in new
plants, but adding the second burner to an existing sulfur plant
is difficult. The second burner is required to handle the
ammonia. A refluxed stripper is required to reduce the water
vapor in the hydrogen sulfide-ammonia mixture and the line
between the stripper and the Glaus Unit must be kept at about
150°F to prevent precipitation of ammonium sulfide complexes.
Howe-Baker Engineers Inc. of Tyler, Texas have developed to the
pilot plant stage a process they call "Ammonex". It is a solvent
extraction process that basically is intended to complete with
the Chevron WWT process. No commercial units have been built.
Another way of treating sour water is to oxidize by aeration.
Compressed air is injected into the waste followed by sufficient
steam to raise the reaction temperature to at least 190°F.
Reaction pressure of 50-1 CO psig is required. Oxidation proceeds
rapidly and converts practically all the sulfides to thiosulfates
and about 10 percent of the thiosulfates to sulfates. Air
oxidation, however, is much less effective than stripping in
regard to reduction of the oxygen demand of sour waters, since
the remaining thiosulfates can later be oxidized to sulfates by
aquatic microorganisms.
The stripping of sour water is normally carried out to remove
sulfides and hence, the effluent may contain 50-100 ppm of
ammonia, or even considerably higher, depending on the influent
ammonia concentration. Values of ammonia have been reported as
low as 1 ppm, but generally the effluent ammonia concentration is
held to approximately 50 ppm to provide nutrient nitrogen for the
refinery biological waste treatment system (2,14,33,58).
Spent Caustic Treatment
Caustic solutions are widely used in refining. Typical uses are
to neutralize and extract:
a. Acidic materials that may occur naturally in crude oil.
b. Acidic reaction products that may be produced by various
chemical treating processes.
c. Acidic materials formed during thermal and catalytic
cracking such as hydrogen sulfide, phenolics, and
organic acids.
Spent caustic solutions may therefore contain sulfides,
mercaptides sulfates, sulfonates, phenolates, naphthenates, and
other similar organic and inorganic compounds.
At least four companies process these spent caustics to market
the phenolics and the sodium hyposulfide. However, the market is
limited and most of the spent caustics are very dilute so the
cost of shipping the water makes this operation uneconomical.
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Seme refiners neutralize the caustic with spent sulfuric from
other refining processes, and charge it to the sour water
stripper. This removes the hydrogen sulfide. The bottoms from
the sour water stripper go to the desalter where the phenolics
are extracted by the crude oil.
Spent caustics usually originate as batch dumps, and the batches
may be combined and equalized before being treated and/or
discharged to the general refinery waste waters. Spent caustic
solutions can also be treated by neutralization with flue gas.
In the treatment of spent caustic solutions by flue gas,
hydroxides are converted to carbonates. Sulfides, mercaptides,
pbenolates, and other basic salts are converted by the flue gas
stripping. Phenols can be removed and used as a fuel or can be
sold. Hydrogen sulfide and mercaptans are usually stripped and
burned in a heater. Some sulfur is recovered from stripper
gases. The treated solution will contain mixtures of carbonates,
sulfates, sulfites, thiosulfates and some phenolic compounds.
Reaction time of 16-24 hours is required for the neutralization
of caustic solution with flue gas.
The oxidation phase of spent caustic treatment is aimed at the
sulfide content of these wastes and achieves 85-99 percent
sulfide removal. In this process, sulfides are oxidized
primarily to thiosulfates although in some variations there is
partial oxidation of the sulfur compounds to sulfate. Oxidation
processes are not applied to phenolic caustics, as phenols
inhibit oxidation. It should be noted that those processes which
oxidize the sulfide only to thiosulfate, satisfy half of the
oxygen demand of the sulfur, as thiosulfate can be oxidized
biologically to sulfate. Neutralization of spent caustics is
applied to both phenolic and sulfidic caustic streams; the
sulfidic caustics are also steam stripped, after neutralization,
to remove the sulfides. When phenolic spent caustics are
neutralized, crude acid oils or "crude carbolates" are sprung and
thus removed from the waste water. The major part of the phenols
will appear in the oil fraction, but a significant part may
remain in the waste water as phenolates.
Fluid bed incineration is also now being used. This process was
developed under an EPA demonstration grant (26) and at least two
large units are under construction. Once the incinerator is
started up, the sludge should provide the necessary heating value
to keep the system operating. Oxidizing fuels may be required
when the sludge is burnt, as ash remains in the bed of the
incinerator. A constant bed level is maintained, so the sand bed
originally in the incinerator is gradually replaced by the inert
sludge ash (5). The gasses pass through a scrubber, so the fines
and particulate matter can be recovered. The ash and fines can
be landfilled. This landfill is cleaner than a sludge landfill,
because there are no organic materials present to contaminate
ground water or run-off.
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In the past ocean dumping, deep well injection, evaporative
lagoons, and simple dilution have all been used. These methods
will no longer be acceptable.
Sewer System Segregation
Waste water quantity is one of the major factors that affect the
cost of waste treatment facilities most directly. Water usage in
the petroleum refining industry varies from less than 5 gallons
of water per barrel of crude charge in the newer refineries to
higher than 1000 gallons of water per barrel of crude charge in
the older refineries. In order to provide efficient treatment to
the wastes originating within a refinery, it is very important
that segregation of concentrated waste streams be considered.
Segregation of waste streams frequently simplifies waste treating
problems as well as reduces treatment facility costs. Thus,
treatment of highly polluted waste streams at the source can
prevent gross pollution of large volumes of relatively clean
waste water. Such treatment is often a more economical solution
of a problem than would be possible if wastes are discharged
directly to the refinery sewers. Treatment at the source is also
helpful in recovering by-products from the wastes which otherwise
could not be economically recovered when the wastes are combined.
In areas where water supply is limited, reduced water
requirements have been incorporated into the design and
operation, thereby reducing total water usage.
To minimize the size of the waste water treatment processes it is
imperative polluted water only be treated. This can be
guaranteed by segregating the various sewer systems. There
should be a sewer carrying process and blowdown waters that are
treated continuously. A polluted storm water sewer should go to
a storage area from which it can be gradually discharged to the
treatment facilities. A sewer system containing clean storm
water can be discharged directly to the receiving water. The
sanitary system should be treated separately from the process
water because of the bacteria present in this stream. Once
through cooling water should be kept separate because of the
large volumes of water involved and the low waste loadings
encountered. A connection to the treatment plant should be
provided in case of oil leaks into the system.
Storm Water Runoff
An additional source of pollution from a petroleum refinery area
is caused by rainfall runoff. Size and age of refinery site,
housekeeping, drainage areas, and frequency and intensity of
rainfall are seyeral of the factors which compound the assignment
of allowable pollutional values.
There are several measures that refiners can provide to minimize
storm water loads to their treatment system after diverting all
extraneous drainage around the refinery area. The major
consideration is a separate storm water sewer and holding system.
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By providing separate collection facilities for storm water
runoff, protection is afforded the operation of the separator and
ancillary treatment systems by controlling the hydraulic load to
be treated. Comingling of inorganic particles with oily waste
water often times produces an emulsion which is difficult to
break in the oil-water separator.
Design of this facility should be based on the maximum ten-year,
twenty-four-hour rainfall runoff of the refinery drainage area.
Diversion of the collected storm water runoff to the oil-water
separator facilities can be provided when hydraulic flows return
to normal operations. In the event of excessive collection due
to a high intensity storm, diversion facilities should be
provided to allow for emergency bypass capability to divert the
trailing edge of the runoff hydrograph (the leading edge normally
contained the mass of pollutants in urban runoff investigations).
An oil retention baffle and an API type overflow weir should be
provided to prevent the discharge of free and floating oil.
An alternate to the separate sewer system would be the provision
of a storm surge pond that would receive the polluted waters when
the flow to the oil-water separator exceeded 15 percent of the
normal hydraulic flow. During normal periods, the collected
storm water-refinery water could then be diverted to the oil-
water separator (provided process flow did not equal or exceed
the units hydraulic capacity).
The major cause of pollution by storm water runoff is the lack of
housekeeping within the refinery confine. Proper procedures
should be encouraged to prevent the accumulation of materials
which contribute to pollution due to rainfall runoff. Some of
the more common preventive measures are: (1) Provide curbing
around process unit pads; (2) Prevent product sample drainage to
sewers; (3) Repair pumps and pipes to prevent oily losses to the
surface areas; (4) Contain spilled oil from turnarounds; (5) Dike
crude and product tank areas and valve precipitation to the storm
water sewer.
In the event the collected water needs to be released from the
storm water detention pond due to overflow, samples of the water
should be monitored for; (1) Oil and Grease, (2) Organic analysis
such as TOC.
Ballast Water Separation
Ballast water normally is not discharged directly to the refinery
sewer system because the intermittent high-volume discharges.
The potentially high oil concentrations, would upset the refinery
waste water treatment facilities. Ballast waters may also be
treated separately, with heating, settling, and at times
filtration as the major steps. The settling tank can also be
provided with a steam coil for heating the tank contents to help
break emulsions, and an air coil to provide agitation. The
recovered oil, which may be considerable, is generally sent to
the slop oil system.
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Slop Oil Treatment
separator skimmings, which are generally referred to as slop oil,
require treatment before they can be reused, because they contain
an excess amount of solids and water. Solids and water contents
in excess of about 1 percent generally interfere with processing.
In most cases slop oils are easily treated by heating to 190°F
for 12 to m hours. At the end of settling, three definite
layers exist: a top layer of clean oil; a middle layer of
secondary emulsion; and a bottom layer of water containing
soluble components, suspended solids, and oil. In some cases, it
is advantageous or even necessary to use acid or specific
chemical demulsifiers to break slop oil emulsions. The water
layer resulting from acid and heat treatment has high BOD and
COD, but also low pH, and must be treated before it can be
discharged.
Slop oil can also be successfully treated by centrifugation or by
precoat filtration using diatcmaceous earth as the precoat.
Gravity Separation of Oil
Gravity separators remove a majority of the free oil found in
refinery waste waters. Because of the large amounts of
reprocessable oils which can be recovered in the gravity
separators, these units must be considered an integral part of
the refinery processing operation and not a waste water treatment
process. The functioning of gravity-type separators depends upon
the difference in specific gravity of oil and water. The
gravity-type separator will not separate substances in solution,
nor will it break emulsions. The effectiveness of a separator
depends upon the temperature of the water, the density and size
of the oil globules, and the amounts of characteristics of the
suspended matter present in the waste water. The "susceptibility
to separation" (STS) test is normally used as a guide to
determine what portion of the influent to a separator is amenable
to gravity separation.
The API separator is the most widely used gravity separator. The
basic design is a long rectangular basin, with enough detention
time for most of the oil to float to the surface and be removed.
Most API separators are divided into more than one bay to
maintain laminar flow within the separator, making the separator
more effective. API separators are usually equipped with
scrapers to move the oil to the downstream end of the separator
where the oil is collected in a slotted pipe or on a drum. On
their return to the upstream end, the scrapers travel along the
bottom moving the solids to a collection trough. Any sludge
which settles can be dewatered and either incinerated or disposed
of as landfill.
The gravity separator usually consists of a pre-separator (grit
chamber) and a main separator, usually rectangular in shape,
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provided with influent and effluent flow distribution and
stilling devices and with oil skimming and sludge collection
equipment. It is essential that the velocity distribution of the
approach flow be as uniform as possible before reaching the inlet
distribution baffle.
Another type of separator finding increasing employment in
refineries is the parallel plate separator. The separator
chamber is subdivided by parallel plates set at a 45° angle, less
than 6 inches apart. This increases the collection area while
decreasing the overall size of the unit. As the water flows
through the separator the oil droplets coalesce on the underside
of the plates and travel upwards where the oil is collected. The
parallel plate separator can be used as the primary gravity
separator, or following an API separator.
Further Removal of Oil and Solids
If the effluent from the gravity separators is not of sufficient
quality to insure effective treatment before entering the
biological or physical-chemical treatment system, it must undergo
another process to remove oils and solids. Most refineries use
either clarifiers, dissolved air flotation units or filters to
reduce the oil and solids concentration. Each of these processes
has also been used to treat the effluent from a biological
system.
Clarifiers
Clarifiers use gravitational sedimentation to remove oil and
solids from a waste water stream. Often it is necessary to use
chemical coagulants such as alum or lime to aid the sedimentation
process. These clarifiers are usually equipped with a skimmer to
remove any floating oil. clarifiers used after a biological
system normally do not have skimmers as there should be no
floating oils at that point. The sludge from the clarifiers is
usually treated before final disposal.
End-of-Pipe Control Technology
End-of-pipe control technology in the petroleum refining industry
relies heavily upon the use of biological treatment methods.
These are supplemented by appropriate pretreatment to insure that
proper conditions, especially sufficient oil removal and pH
adjustment, are present in the feed to the biological system.
When used, initial treatment most often consists of
neutralization for control of pH or equalization basins to
minimize shock loads on the biological systems. The
incorporation of solids removal ahead of biological treatment is
not as important as it is in treating municipal waste waters.
One of the initial criteria used to screen refineries for the
field survey, was degree of treatment provided by their waste
water treatment facilities. Therefore, the selection of plants
was not based on a cross-section of the entire industry, but
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rather was biased in favor of those segments of the industry that
had the more efficient waste water treatment facilities. Table
26 indicates the types of treatment technology and performance
characteristics which were observed during the survey. In most
of the plants analyzed, some type of biological treatment was
utilized to remove dissolved organic material. Table 27
summarizes the expected effluents from waste water treatment
processes throughout the petroleum refining industry. Typical
efficiencies for these processes are shown in Table 28.
During the survey program, waste water treatment plant
performance history was obtained when possible. This historical
data were analyzed statistically and the individual plant's
performance evaluated in comparison to the original design basis.
After this evaluation, a group of plants was selected as being
exemplary and these plants were presented in Table 26. The
treatment data in Table 28 represent the annual daily average
performance (50 percent probability-of-occurrence).
There were enough plants involving only one subcategory to make
the interpretation meaningful. In preparing the economic data
base, however, all the waste water treatment plant data were
analyzed to develop a basis for subsequent capital and operating
costs.
The treatment data from the exemplary plants referred to
previoulsy were analyzed to formulate the basis for developing
BPCTCA effluent criteria. The effluent limitations were based on
both these treatment data, other data included in Supplement B,
and other sources as discussed in Section IX. These effluent
limitations were developed for each subcategory individually and
thus no common treatment efficiency was selected as being typical
of the petroleum refining industry for use in the BPCTCA effluent
limitations. A brief description of the various elements of
end-of-pipe treatment follows.
Equalization
The purpose of equalization is to dampen out surges in flows and
loadings. This is especially necessary for a biological
treatment plant, as high concentrations of certain materials will
upset or completely kill the bacteria in the treatment plant. By
evening out the loading on a treatment plant, the equalization
step enables the treatment plant to operate more effectively and
with fewer maintenance problems. Where equalization is not
present, an accident or spill within the refinery can greatly
affect the effluent quality or kill the biomass (R7, R20).
The equalization step usually consists of a large pond that may
contain mixers to provide better mixing of the wastes. in some
refineries the equalization is done in a tank (55, R29). The
equalization step can be before or after the gravity separator
but is more effective before as it increases the overall
efficiency of the separator. However, care must be taken to
prevent anaerobic decomposition in the equalization facilities.
103
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SL'BCATEGORT
Observed Refinery Treatment System and Effluent Loadings
TABLE 26
Type of OP AL-PP
Treatment
Refinery R32 R18
Observed Average
Effluent Loadings
Met-kg/1000 m3 of
feedstock
(lb/1000 bbl of
feedstock)
BODS 8(2.8)
COD 39(13.8)
TCC _» —_. _,__,.,„
JL3O _»•-•-_-__ —_._.— «.
Ac/* 4 A/ A 7\ 41 /rt B\
O&G Z . 0\0. 7) Z.j(O.o)
Phenolic
Compounds 0.14(0.05) 0.003(0.001)
Sulflde 0.03(0.009)
AL-F E-DAF-A
R27
8.0(4.4) 5.9(2.1)
68(24) 96(34)
25(8.7) 34(12)
A/I t\ t. n/i A
9(3*2) 4*0(1*4
0.4(0.145) 0.37(0.
0.2(0.07) 0(0)
S OP I
R26
10(3.6)
71(25.0)
8.5(3.0)
4Q/1 7\
• O^X* / /
13) 0.05(0.018)
0.03(0.010)
)AF,AL,PP
R7
3.7(1.3)
39(13.8)
4.2(1.5)
2 ft/1 f\\
*0\1 t\JJ
0 14(0 05^
0.0006
(0.002)
0.014
(0.005)
DAK. AS
R20
13(4.6)
67(23.5)
13.6(4.8)
6*5(2 • 3)
Ac /i f\
* J VX >O/
0.06
(0.023)
0.05
(0.018)
DAF.AS DAF.AL.FP E,TF,AS E.AS DAF.AS.PP
R8 R23 R24 R28 R25
2.7(0.95) 2.6(0.91) 7.4(2.6) 14(5.0) 17.5(6.2)
54(19, 57(20) 136(48) 320(113)
8.5(3.0) 7(2.5) 12(4.3) 38(13.5) 36(12.7)
A /I A\ 79/9R^^ 91 n *1\
•»•»••••-- *t \X • *t y ***V**^'^ ** \ / • / /
—— — _ 9^n 7\ i 9 fn AA^ -.. _ o ^/A n\
-"••"•— ^ \,u* if x* _; vu**my _._-— » *• j ^u, o/
0.17(0.06) 0.017(0.005)
0.20 (.07)
Footnotes! AL-aerated lagoon
AS-actlvated sludge
DAF-dlssolved air flotation
E-equallzatlon
F-flltratlon
OP-oxldatlon pond
PP-pollshing pond
TF-trlckling filter
A-Topplng D-Lube
B-Cracking B-lntegr«t«d
C-Petrochemicals
-------
TABLE 27
Expected Effluents from Petroleum Treatment Processes
EFFLUENT CONCENTRATION
PROCESS
1
2
3
It
5
6
T.
8,
9.
10.
IX.
12.
. API Separator
. Clarlfler
. Dissolved Air
Flotation
. Granular Media
Filter
. Oxidation Fond
. Aerated Lagoon
Activated Sludge
Trickling Filter
Cooling Tower
Activated Carbon
Granular Media Filter
Activated Carbon
PROCESS
INFLUENT
Raw Waste
1
1
1
1
2,3,1*
2,3,1*
1
2,3.1.
2.3.U
5-9
5-9 and 11
BOD5
250-350
1*5-200
1*5-200
1*0-170
10-60
10-50
5-50
25-50
25-50
5-100 .
NA
3-10
COD
260-700
130-1*50
• 130-1*50
100-1*00
50-300
50-200
30-200
80-350
1*7-350
j. 30-200
NA
30-100
TOC
NA
NA
NA
NA
NA
NA
20-80
NA
70-150
NA
25-61
1-17
ss
50-200
25-60
25-60
-5-25
20-100
10-80
5-50
20-70
U. 5-100
10-20
3-20
1-15
, WS/L
OIL
20-100
5-35
5-20
6-20
1.6-50
5-20
1-15
10-80
20-75
2-20
3-17
0.8-2.5
PHENOL
6-100
10-1*0
10-1*0
3-35
0.01-12
0.1-25
0.01-2.0
0.5-10
.1-2.0
41
0.35-10
0-0.1
AMMOHIA
15-150
NA
SA
NA
3-50
lt-25
1-100
25-100
1-30
10-lUo
NA
1-100
SULF1DE
HA
NA
HA
HA
0-20
0-0.2
0-0.2
0.5-2
HA
NA
NA
0-0.2
Ktmuaiuiss
7, 13, 30, ill, It9 ,59
3U.UBa.l0
13,29,32,l*8a,l<9
17»ltl,l*8a,l*8
18 ,22 ,23,31, 1*2 ,U8»,
!*9,55,75,R18
31,39,l*2a,l*8a,li9,
55,59,R7,R23,R26
13,2l*,27,30,3l*,35,
1*2, l*8a, 1*9 ,60 ,69 ,72
R8,R20,R2l*,R25,R27
R28.R29
18,30,1*2,1* 8a,l*9>
33,1*1
17,2l,27,l*8,l*8a,l*9,
53,62a
17,1*8,51*
17,21,27,l*8,1.8a,l*9,
C-3 ^O_
53,6
- Data lot Available
-------
TABLE 28
Typical Removal Efficiencies for Oil Refinery Treatment Processes
PROCESS
1.
2.
3.
It.
5.
6.
T.
8.
9.
10.
11.
12.
API Separator
Clarifler
Dissolved Air
Flotation
Filter
Oxidation Pond
Aerated Lagoon
Activated Sludge
Trickling
Filter
Cooling Tower
Activated
Carbon
Filter
Granular Media
Activated
Carbon
PROCESS
INFLUENT
Raw Waste
1
1
1
1
2.3.U
2.3.U
1
2,3,1*
2,3,U
5-9
5-9- plus 11
REMOVAL EFFICIENCY, %
BODs
5-1*0
30-60
20-70
1*0-70
1*0-95
• 75-95
80-99
60-85
50-90
70-95
NA
91-98
COD
5-30
20-50
10-60
20-55
30^65
60-85
50-95
30-70
1*0-90
70-90
NA
86-9U
TOC
HA
HA
HA
HA
60
HA
1*0-90
HA
10-70
50-80
50-65
50-80
SS
10-50
50-80
50-85
75-95
2"0-70
1.0-65
60-85
60-85
50-85
60-90
75-95
60-90
OIL
60-99
60-95
JO-85
65-90
50-90
70-90
80-99
50-80
60-75
75-95
65-95
70-95
PHENOL
0-50
0-50
10-75
5-20
60-99
90-99
95-99+
70-98
75-99+
90-100
5-20
90-99
AMMONIA
NA
NA
HA ,
HA
0-15
10-1*5
33-99
15-90
60-95
7-33
NA
33-87
SULFIDE
NA
NA
NA
NA
70-100
95-ioo
97-100
70-100
NA
NA
NA
NA
REFERENCES
7, 13, 30, Ul ,1*9 ',59
3lt,l*8a,l*9
13,29,32,l*8a,U9
17,l*l,l*8a,l*9
18,22,23,31,1*2,1*8
!*9,55,75,Rl8
31, 39 ,!t2, 1*811,1*9,
55,59,R7,R23,R26
13,2l»,R7,30,3l*,35
1*2,1* 8a, 1)9 ,60,69,72
R8,B20,?2l*,R25,R2
R28.R29
18,30, 1*2, l*8a,l*9
33,1*1
17 ,21 ,27 ,1*8', l*8a, 1*9
l*9,53,62a
17,1*8,51*
rr^i^.w.usa,
>*9,53,62a
HA - Data lot Available
-------
Dissolved Air Flotation
Dissolved air flotation consists of saturating a portion of the
waste water feed, or a portion of the feed or recycled effluent
from the flotation unit with air at a pressure of 40 to 60 psig.
The waste water or effluent recycle is held at this pressure for
1-5 minutes in a retention tank and then released at atmospheric
pressure to the flotation chamber. The sudden reduction in
pressure results in the release of microscopic air bubbles which
attach themselves to oil and suspended particles in the waste
water in the flotation chamber. This results in agglomerates
which, due to the entrained air, have greatly-increased vertical
rise rates of about 0.5 to 1.0 feet/minute. The floated
materials rise to the surface to form a froth layer. Specially
designed flight scrapers or other skimming devices continuously
remove the froth. The retention time in the flotation chambers
is usually about 10-30 minutes. The effectiveness of dissolved
air flotation depends upon the attachment of bubbles to the
suspended oil and other particles which are to be removed from
the waste stream. The attraction between the air bubble and
particle is a result of the particle surface and bubble-size
distribution.
Chemical flocculating agents, such as salts of iron and aluminum,
with or without organic polyelectrolytes, are often helpful in
improving the effectiveness of the air flotation process and in
obtaining a high degree of clarification.
Dissolved air flotation is used by a number of refineries to
treat the effluent from the oil separator. Dissolved air
flotation using flocculating agents is also used to treat oil
emulsions. The froth skimmed from the flotation tank can be
combined with other sludges (such as those from a gravity
separator) for disposal. The clarified effluent from a flotation
unit generally receives further treatment in a biological unit,
prior to discharge. In two refineries, dissolved air flotation
is used for clarification of biologically treated effluents (29).
Oxidation Ponds
The oxidation pond is practical where land is plentiful and
cheap. An oxidation pond has a large surface area and a shallow
depth, usually not exceeding 6 feet. These ponds have long
detention periods from 11 to 110 days.
The shallow depth allows the oxidation pond to be operated
aerobically without mechanical aerators. The algae in the pond
produce oxygen through photosynthesis. This oxygen is then used
by the bacteria to oxidize the wastes. Because of the low
loadings, little biological sludge is produced and the pond is
fairly resistant to uspsets due to shock loadings.
Oxidation ponds are usually used as the major treatment process.
Some refineries use ponds as a polishing process after other
treatment processes.
107
-------
Aerated Lagoon
The aerated lagoon is a smaller, deeper oxidation pond equipped
with mechanical aerators or diffused air units. The addition of
oxygen enables the aerated lagoon to have a higher concentration
of microbes than the oxidation pond. The retention time in
aerated lagoons is usually shorter, between 3 and 10 days. Most
aerated lagoons are operated without final clarification. As a
result, biota is discharged in the effluent., causing the effluent
to have high BODJ> and solids concentrations. As the effluent
standards become more strict, final clarification will be
increasing in use.
Trickling Filter
A trickling filter is an aerobic biological process. It differs
from other processes in that the biomass is attached to the bed
media, which may be rock, slag, or plastic. The filter works by:
1) adsorption of organics by the biological slime 2) diffusion of
air into the biomass; and 3) oxidation of the dissolved organics.
When the biomass reaches a certain thickness, part of it sloughs
off. When the filter is used as the major treatment process, a
clarifier is used to remove the sloughed biomass.
The trickling filter can be used either as the complete treatment
system or as a roughing filter. Most applications in the
petroleum industry use it as a roughing device to reduce the
loading on an activated sludge system.
Bio-Oxidation Tower
The bio-oxidation tower uses a cooling tower to transfer oxygen
-to a waste water. API (112) has called the bio-oxidation towers
a modified activated sludge process, as most of the biomass is
suspended in the wastewater. Results from refineries indicate it
is a successful process to treat portions or all of a refinery
waste water (80, 81, 92).
Activated Sludge
Activated sludge is an aerobic biological treatment process in
which high concentrations (1500-3000 mg/L) of newly-grown and
recycled microorganisms are suspended uniformly throughout a
holding tank to which raw waste waters are added. Oxygen is
introduced by mechanical aerators, diffused air systems, or other
means. The organic materials in the waste are removed from the
aqueous phase by the microbiological growths and stabilized by
biochemical synthesis and oxidation reactions. The basic
activated sludge process consists of an aeration tank followed by
a sedimentation tank. The flocculant microbial growths removed
in the sedimentation tank are recycled to the aeration tank to
maintain a high concentration of active microorganisms. Although
the microorganisms remove almost all of the organic matter from
the waste being treated, much of the converted organic matter
remains in the system in the form of microbial cells. These
108
-------
cells have a relatively high rate of oxygen demand and must be
removed from the treated waste water before discharge. Thus,
final sedimentation and recirculation of biological solids are
important elements in an activated sludge system.
Sludge is wasted on a continuous basis at a relatively low rate
to prevent build-up of excess activated sludge in the aeration
tank. Shock organic loads usually result in an overloaded system
and poor sludge settling characteristics. Effective performance
of activated sludge facilities requires pretreatment to remove or
substantially reduce oil, sulfides (which causes toxicity to
microorganisms), and phenol concentrations. The pretreatment
units most frequently used are: gravity separators and air
flotation units to remove oil; and sour water strippers to remove
sulfides, mercaptans, and phenol. Equalization also appears
necessary to prevent shock loadings from upsetting the aeration
basin. Because of the high rate and degree of organic
stabilization possible with activated sludge, application of this
process to the treatment of refinery waste waters has been
increasing rapidly in recent years.
Many variations of the activated sludge process are currently in
use. Examples include: the tapered aeration process, which has
greater air addition at the influent where the oxygen demand is
the highest; step aeration, which introduces the influent waste
water along the length of the aeration tank; and contact
stabilization, in which the return sludge to the aeration tank is
aerated for 1-5 hours. The contact stabilization process is
useful where the oxygen demand is in the suspended or colloidal
form. The completely mixed activated sludge plant uses large
mechanical mixers to mix the influent with the contents of the
aeration basin, decreasing the possibility of upsets due to shock
loadings. The Pasveer ditch is a variation of the completely
mixed activated sludge process that is widely used in Europe.
Here brushes are used to provide aeration and mixing in a narrow
oval ditch. The advantage of this process is that the
concentration of the biota is higher than in the conventional
activated sludge process, and the wasted sludge is easy to
dewater. There is at least one refinery using the Pasveer ditch
type system.
The activated sludge process has several disadvantages. Because
of the amount of mechanical equipment involved, its operating and
maintenance costs are higher than other biological systems. The
small volume of the aeration basin makes the process more subject
to upsets than either oxidation ponds or aerated lagoons.
As indicated in Table 25, the activated sludge process is capable
of achieving very low concentrations of BODS, COD, TSS, and oil,
dependent upon the influent waste loading and the particular
design basis. Reported efficiencies for BODS removal are in the
range of 80 to 99 percent.
Physical-chemical Treatment
109
-------
Physical-chemical treatment refers to treatment processes that
are non-biological in nature. There are two types of physical-
chemical processes; those that reduce the volume of water to be
treated (vapor compression evaporators, reverse osmosis, etc.),
and those that reduce the concentration of the pollutants
(activated carbon).
Physical-chemical (P-C) processes require less land than
biological processes. P-C processes are not as susceptible to
upset due to shock loading as are biological processes. Another
advantage of P-C is that much smaller amounts of sludge are
produced.
Flow Reduction Systems
Flow reduction systems produce two effluents, one of relatively
pure water and one a concentrated brine. The pure water stream
can be reused within the refinery resulting in a smaller effluent
flow. The brine is easier to treat as it is highly concentrated.
Both of the processes described herein have been demonstrated on
small flows only and at present the costs involved are extremely
high (45, 52, 93).
In the vapor compression evaporator the waste water flows over
heat transfer surfaces. The steam generated enters a compressor
where the temperature is raised to a few degrees above the
boiling point of the waste water. The compressed steam is used
to evaporate more waste water while being condensed. The
condensed steam is low in dissolved solids. The major process
costs are the costs of electrical power, which is approximately
$1.0/1000 gallons of clean water (93).
The reverse osmosis process uses high pressures (400-800 psig) to
force water through a semi-permeable membrane. The membrane
allows the water to pass through, but contains the other con-
stituents in the waste water. Currently available membranes tend
to foul and blind, requiring frequent cleaning and replacement.
Until this problem is corrected, reverse osmosis is not a
practicable process. The operating cost for a reverse osmosis
unit is approximately 20-300/1000 gallons (U5, 95).
Granular Media Filters
There are several types of granular media filters: sand, dual
media, and multimedia. These filters operate in basically the
same way, the only difference being the filter media. The sand
filter uses relatively uniform grade of sand resting on a coarser
material. The dual media filter has a course layer of coal above
a fine layer of sand. Both types of filters have the problem of
keeping the fine particles on the bottom. This problem is solved
by using a third very heavy, very fine material, (usually garnet)
beneath the coal and sand.
As the water passes down through a filter, the suspended matter
is caught in the pores. When the pressure drop through the
110
-------
filter becomes excessive, the flow through the filter is reversed
for removal of the collected solids loading. The backwash cycle
occurs approximately once a day, depending on the loading, and
usually lasts for 5-8 minutes. Most uses of sand filters have
been for removing oil and solids prior to an activated carbon
unit. There is one refinery that uses a mixed media filter on
the effluent from a biological system. Granular media filters
are shown to be capable of consistently operated with extremely
low TSS and oil effluent discharges, on the order of 5-10 mg/L.
Activated Carbon
The activated carbon (AC) process utilizes granular activated
carbon to adsorb pollutants from waste water. The adsorption is
a function of the molecular size and polarity of the adsorbed
substance. Activated carbon preferentially adsorbs large organic
molecules that are non-polar.
An AC unit follows a solids removal process, usually a sand
filter which prevents plugging of the carbon pores. From the
filter the water flows to a bank of carbon columns arranged in
series or parallel. As the water flows through the columns the
pollutants are adsorbed by the carbon, gradually filling the
pores. At intervals, portions of the carbon are removed to a
furnace where the adsorbed substances are burnt off. The
regenerated carbon is reused in the columns, with some makeup
added, because of handling and efficiency losses.
Activated carbon processes currently have only limited usage in
the refining industry. However, there are new installations in
the planning construction stages. The increasing use of
activated carbon has occured because activated carbon can remove
organic materials on an economically competitive basis with
biological treatment. Activated carbon regeneration furnaces
have high energy requirements.
Sludge Handling and Disposal
Digestion
Digestion is usually used preceding the other sludge
concentration and disposal methods. The purpose of digestion is
to improve the dewatering of the sludge. Digestion can occur
aerobically or anaerobically. During digestion, bacteria
decompose the organic material in the sludge producing methane,
carbon dioxide and water. At the end of the digestion process,
the sludge is stable and non-decomposable.
Vacuum Filtration
The various vacuum filters, usually a revolving drum, use a
vacuum to dewater the sludge. The revolving drum type has a
vacuum applied against a cloth. The water passes through the
cloth and returns to the influent of the treatment plant. The
sludge remains on the drum until it is scraped off with a knife.
Ill
-------
Centrifugation
Centrifugal!on uses high speed rotation to separate sludge and
water. The heavier sludge moves to the outside and is conveyed
to one end, where it is collected for final disposal. The water
flows out the opposite end and is returned to the treatment
plant.
Sludge Disposal
From any waste water treatment plant, the sludge must be disposed
of. The methods used are landfilling, landfarming, barging to
sea, and incineration.
Landfilling
A landfill operation requires a large amount of land. Before
landfilling, the sludge should be digested to avoid odor
problems. The sludge is disposed of in an excavation site.
After each batch is disposed of, it is covered with a layer of
earth. When the site is filled to capacity it is covered with a
thick layer of earth.
The largest problem of industrial landfills is the pollution to
ground and surface waters by leaching. Leaching occurs when
water percolates through the landfill. As it drains through the
landfill site, the water carries with it dissolved and suspended
solids and organic matter. This water can then contaminate
underground or surface streams it comes in contact with.
Incineration
Incineration is gradually complementing landfills as a method of
sludge disposal. The principal process is fluid bed
incineration. In this process, a bed of sand is preheated with
hot air to U82-538°C (900 - 1000°F). Torch oil is then used to
raise the bed temperature to 649 - 705°C (1200 - 1300°F). At
this point waste water sludge and/or sludge is introduced and the
torch oil is stopped. The solid products of combustion remain in
the bed which is a gradually withdrawn to maintain a constant bed
height. Eventually, the bed will be composed of only ash.
The sludge fed to the incinerator usually contains inorganic as
well as organic material. However, the sludge must contain a
minimum amount of organics to maintain the combustion process.
One refinery (26) suggests a minimum of 1,930,000 cal/cu m
(29,000 Btu/gal) of sludge heating value is necessary to maintain
the combustion process.
112
-------
SECTION VIII
COST, ENERGY, AND NON-WATER QUALITY ASPECTS
The first part of this section summarizes the costs (necessarily
generalized) and effectiveness of end-of-pipe control technology
for BPCTCA and BATEA and BADT-NSPS effluent limitations. Treat-
ment costs for small, medium, and large refineries in each
subcategory have been estimated for the technologies considered.
The expected annual costs for existing plants in the petroleum
refining industry in 1977 consistent with BPCTCA effluent
limitations are estimated at $225 million (end-of-pipe treatment
only). For 1983, consistent with EATEA effluent limitations, the
estimated additional annual costs are estimated at $250 million
(end-of-pipe treatment only). For BADT-NSPS the annual cost is
estimated at $26 million. These costs are summarized by
subcategory in Table 29.
The effect of plant size relative to annual costs can be seen in
Table 30 where the annual costs are summarized for application of
BPCTCA and BATEA to small, medium, and large refineries in each
subcategory. The cost, energy, and nonwater quality aspects of
in-plant controls are intimately related to the specific
processes for which they are developed. Although there are
general cost and energy requirements for equipment items (e.g.
surface air coolers), these correlations are usually expressed in
terms of specific design parameters, such as the required heat
transfer area. Such parameters are related to the production
rate and specific situations that exist at a particular
production site.
There is a wide variation in refinery sizes. When these size
ranges are superimposed on the large number of processes within
each subcategory, it is apparent that many detailed designs would
be required to develop a meaningful understanding of the economic
impact of process modifications. The decision to attain the
limitations through in-plant controls or by end-of-pipe treatment
should be left up to individual manufacturers. Therefore, a
series of possible designs for the end-of-pipe treatment models
is provided.
Alternative Treatment Technologies
The range of components used or needed for either best
practicable or best available technology have been combined into
five alternative end-of-pipe treatment steps, which are as
follows:
A. Initial treatment, consisting of dissolved air flotation,
equalization, neutralization, and nutrient (phosphoric acid)
feed facilities.
113
-------
TABLE 29
Estimated Total Annual Costs for End-of-Pipe Treatment
Systems for the Petroleum Refining Industry (Existing Refineries)
Subcategory Total Annual Cost, $ Million
1977 1983
Topping $14.2 $16.5
Cracking 81.3 92.5
Petrochemical 53.9 50.0
Lube 70.1 66.2
Integrated 55.5 24.8
Industry Total $255.0 $250.0
114
-------
TABLE 30
Summary of End-of-Pipe Waste Water Treatment Costs
for Representative Plants 1n the Petroleum Refining Industry
Subcategory
Topping
Cracking
Petrochemical
Lube
Integrated
Representative
Refinery Size
1000 m3/day 1000 BBL/day
Annual
Level 1 Costs
$/1000 m3 $/1000 gal
Annual Additional
Level 11 Costs
$/10QO m3 $/1000 gal
0.318
1.11
2.4
2.4
11.9
23.8
4.0
15.9
31.8
4.0
17.5
39.8
9.8
23.0
49.0
2
7
15
15
75
150
25
100
200
25
110
250
65
152
326
0.066
0.030
0.018
0.014
0.007
0.006
0.009
0.007
0.005
0.009
0.006
0.005
0.006
0.005
0.005
17.31
7.86
4.87
3.78
1.84
1.62
2.32
1.78
1.35
2.33
1.50
1.25
1.67
1.28
1.13
0.070
0.034
0.023
0.019
0.008
0.006
0.010
0.006
0.005
0.010
0.006
0.004
0.006
0.005
0.003
18.41
9.06
5.97
4.90
2.20
1.47
2.65
1.63
1.20
2.57
1.51
0.93
1.53
1.05
0.65
115
-------
B. Biological treatment, consisting of acitvated sludqe
units, thickness, digesters, and dewatering facilities.
C. Granular media filtration, consisting of filter systems
and associated equipment.
D. Physical-chemical treatment facilities consisting of
activated carbon adsorption.
E. Alternative Biological treatment, consisting of aerated
lagoon facilities.
Tables 31 through 45 are summaries of the costs of major
treatment steps required to achieve different levels of
technology for small, medium, and large refineries in each
subcategory; using median raw waste loads and median "good water
use" flow rates, for the end-of-pipe treatment models.
BPCTCA Treatment Systems Used for the Economic Evaluation
A general flow schematic for the BPCTCA waste water treatment
facilities is shown in Figure 6. A summary of the general design
basis is presented in Table 46 and a summary of the treatment
system effluent limitations for each subcategory is presented in
Tables 1-6.
BATEA treatment Systems Used for the Economic Evaluation
BATEA treatment facilities are basically added on to the
discharge pipe from BPCTCA facilities. It is expected that flows
will be reduced slightly by the application of BATEA in-plant
technology, so that the activated carbon treatment unit may treat
a smaller hydraulic load. However, the activated carbon system
was sized for the same flow basis as in BPCTCA technology in
order to establish a conservative basis for economic evaluation
of proposed effluent limitations.
A general flow schematic diagram for the BATEA waste water
treatment facilities is shown in Figure 7. A summary of the
general design basis is presented in Table 47. and a summary of
the treatment system effluent limitations for each subcategory is
presented in Tables 1-6.
116
-------
TABLE 31
WATER EFFLUENT TREATMENT COSTS
PETROLEUM REFINING INDUSTRY
TOPPING SUBCATEGORY
Refinery Capacity
1000 cubic meters/day (1000 bbl/day)
Wastewater Flow
cubic meters/cubic meter of feedstock (gal/bbl)
Treatment Plant Size
1000 cubic meters/day (MGD)
0.318 (2)
0.477 (20)
0.146 (0.040)
Costs in $1000
Initial Investment
ANNUAL COSTS:
Capital Costs (10%)
Depreciation (20%)
Operating Costs
Energy
Total Annual Costs
A
210
21.0
42.0
14.6
1.0
78.6
Alternative Treatment Steps
B_ C D
174 60 390
17.4
34.8
12.4
7.8
72.4
6.0
12.0
4.2
1.0
23.2
39
78
72.5
6.5
196.0
Effluent Quality
Raw Waste
Load
kg/1000 cu m (lb/1000 bbl)
BOD5
COD
Oil & Grease
Phenolics
Sulfide
Ammonia
Suspended Solids
Total Chromium
13
36
8
0
0
3
11
3 (4.7)
8 (13)
2 (2.9)
034 (0.012)
054 (0.019)
7 (1.3)
6 (4.1)
Resulting Effluent Levels
(Design Average kg/1000 cu m)
0.20 (0.07)
7. 1
37.6
3.3
0.048
0.048
0.85
9.6
0.24
2.3
4.8
0. 119
£
1.2
5.0
0.25
0.0051
0.025
0.34
1.2
0.062
117
-------
TABLE 32
WATER EFFLUENT TREATMENT COSTS
PETROLEUM REFINING INDUSTRY
TOPPING SUBCATEGORY
Refinery Capacity
1000 cubic meters/day (1000 bbl/day)
Wastewater Flow
cubic meters /cubic meter of feedstock (gal/bbl)
Treatment Plant Size
1000 cubic meters/day (MGD)
Costs in $1000
Initial Investment
ANNUAL COSTS:
Capital Costs (10%)
Depreciation (20%)
Operating Costs
Energy
A
320
1.11 (7)
0.47 (20)
0.51 (0.140)
Alternative Treatment Steps
B C_ D
290 102 815
32.0
64.0
23.0
2.0
29.0
58.0
19.0
12.0
10.2
20.4
6.0
2.0
81.5
163.0
89.0
9.0
Total Annual Costs 121.0
118.0
38.6
342.5
Effluent Quality
Raw Waste
Load
kg/1000 cu m (lb/1000 bbl)
BOD5
COD"
Oil & Grease
Phenolic s
Sulfide
Ammonia
Suspended Solids
Total Chromium
13. 3 (4. 7)
36.8 (13)
8.2 (2.9)
0.034 (0.012)
0.054 (0.019)
3. 7 (1.3)
11.6 (4. 1)
0.20 (0.07)
Resulting Effluent Levels
(Design Average kg/1000 cu m)
B
7. 1
37.6
3.3
0.048
0.048
0.85
9.6
0.24
£
_
-
2. 3
-
-
-
4.8
0. 119
D
1.2
5.0
0.25
0.0051
0.025
0.34
1.2
0.062
118
-------
TABLE 33
WATER EFFLUENT TREATMENT COSTS
PETROLEUM REFINING INDUSTRY
TOPPING SUBCATEGORY
Refinery Capacity
1000 cubic meters/day (1000 bbl/day) 2.4 (15)
Wastewater Flow
cubic meters /cubic meter of feedstock (gal/bbl) 0.47 (20)
Treatment Plant Size
1000 cubic meters/day (MGD) 1.1 (0.30)
Costs in $1000
Initial Investment
ANNUAL COSTS:
Capital Costs (10%)
Depreciation (20%)
Operating Costs
Energy
Total Annual Costs
A
378
37.8
75.6
28.0
3.0
144.4
Alternative Treatment Steps
B_ £ D
400 150 1257
40.0
80.0
26.0
19.0
165.0
15.0
30.0
17.0
2.0
64.0
126.0
252.0
101.0
10.0
489.0
Effluent Quality
Raw Waste
Load
kg/1000 cu m (lb/1000 bbl)
BODS
COD"
Oil & Grease
Phenolics
Sulfide
Ammonia
Suspended Solids
Total Chromium
13
36
8
0
0
3
11
3 (4.7)
8 (13)
2 (2.9)
034 (0.012)
054 (0.019)
7 (1.3)
6 (4.1)
Resulting Effluent Levels
(Design Average kg/1000 cu m)
0.20 (0.07)
7. 1
37.6
3.3
0.048
0.048
0.85
9.6
0.24
2.3
4.8
0. 119
D
1.2
5.0
0.25
0.0051
0.025
0.34
1.2
0.062
119
-------
TABLE 34
WATER EFFLUENT TREATMENT COSTS
PETROLEUM REFINING INDUSTRY
CRACKING SUBCATEGORY
Refinery Capacity
1000 cubic meters/day (1000 bbl/day)
Wastewater Flow
cubic meters/cubic meter of feedstock (gal/bbl)
Treatment Plant Size
1000 cubic meters/day (MGD)
2.4 (15)
0.596 (25)
1. 37 (0.375)
Costs in $1000
Initial Investment
ANNUAL COSTS:
Capital Costs (10%)
Depreciation (20%)
Operating Costs
Energy
Total Annual Costs
A
405
40.5
81.0
29.0
2.0
152. 5
Alternative Treatment Steps
13 £ D
455 158 1458
45.5
91.0
30.0
21.0
187.5
15.
31.
11.
3.
61.4
146.0
292.0
106.0
10.0
554.0
Effluent Quality
Raw Waste
Load
kg/1000 cu m (lb/1000 bbl)
BODS
COD
Oil & Grease
Phenolic s
Sulfide
Ammonia
Suspended Solids
Total Chromium
72.5 (25)
216.0 (76)
31.0 (10.9)
3.95 (1.4)
1.0 (0.35)
28.0 (9.9)
17.8 (6.3)
0.25 (0.09)
Resulting Effluent Levels
(Design Average kg/1000 cu m)
B
8.8
67.9
3.9
0.059
0.059
5. 7
11.8
0.3
2.8
5.9
0. 147
D
1.6
9.6
0.34
0.0065
0.045
2.8
1.6
0.05
120
-------
TABLE 35
WATER EFFLUENT TREATMENT COSTS
PETROLEUM REFINING INDUSTRY
CRACKING SUBCATEGORY
Refinery Capacity
1000 cubic meters/day (1000 bbl/day)
11.9 (75)
Wastewater Flow
cubic meters/cubic meter of feedstock (gal/bbl) 0.596 (25)
Treatment Plant Size
1000 cubic meters/day (MGD)
6.8 (1.875)
Costs in $1000
Initial Investment
ANNUAL COSTS:
Capital Costs (10%)
Depreciation (20%)
Operating Costs
Energy
Total Annual Costs
A
950
95.0
190.0
64.0
8.0
357.0
Alternative Treatment Steps
B £ D
1760 290 3600
176.0
352.0
86.0
59.0
63.0
29.0
58.0
20.0
7.0
114.0
360.0
720.0
152.0
25.0
125.0
Effluent Quality
Raw Waste
Load
kg/1000 cu m (Ib/lOOO bbl)
BODS
COD
Oil & Grease
Phenolic s
Sulfide
Ammonia
Suspended Solids
Total Chromium
72,
216
31
3
1
28
17
5 (25)
0 (76)
0 (10.9)
95 (1.4)
0 (0.35)
0 (9.9)
8 (6.3)
Resulting Effluent Levels
(Design Average kg/1000 cu m)
0.25 (0.09)
&
8.8
67.9
3.9
0.059
0.059
5.7
11.8
0.3
2.8
5.9
0. 147
D
1.6
9.6
0.34
0.0065
0.045
2.8
1.6
0.05
121
-------
TABLE 36
WATER EFFLUENT TREATMENT COSTS
PETROLEUM REFINING INDUSTRY
CRACKING SUBCATEGORY
Refinery Capacity
1000 cubic meters/day (1000 bbl/day)
23.8 (150)
Wastewater Flow
cubic meters/cubic meter of feedstock (gal/bbl) 0.596 (25)
Treatment Plant Size
1000 cubic meters/day (MGD)
13.7 (3.75)
Costs in $1000
Initial Investment
ANNUAL COSTS:
Capital Costs (10%)
Depreciation (20%)
Operating Costs
Energy
Total Annual Costs
A
1460
146.0
292.0
119.0
17.0
574.0
Alternative Treatment Steps
B C_ D
3080 415 5370
308.0
616.0
236.0
113.0
123.0
41.5
83.0
31.0
15.0
180.5
537.0
1074.0
211.0
44.0
1866.0
Effluent Quality
Raw Waste
Load
kg/1000 cu m (lb/1000 bbl)
BODS
COD
Oil & Grease
Phenolics
Sulfide
Ammonia
Suspended Solids
Total Chromium
72,
216,
31
3
1
28
17
5 (25)
0 (76)
0 (10.9)
95 (1.4)
0 (0.35)
0 (9.9)
8 (6.3)
Resulting Effluent Levels
(Design Average kg/1000 cu m)
0.25 (0.09)
13
8.8
67.9
3.9
0.059
0.059
5.7
11.8
0.3
2.8
5.9
0.147
D
1.6
9.6
0.34
0.0065
0.045
2.8
1.6
0.05
122
-------
TABLE 37
WATER EFFLUENT TREATMENT COSTS
PETROLEUM REFINING INDUSTRY
PETROCHEMICAL SUBCATEGORY
Refinery Capacity
1000 cubic meters/day (1000 bbl/day)
Wastewater Flow
cubic meters/cubic meter of feedstock (gal/bbl)
Treatment Plant Size
1000 cubic meters/day (MGD)
Costs in $1000
Initial Investment
ANNUAL COSTS:
Capital Costs (10%)
Depreciation (20%)
Operating Costs
Energy
Total Annual Costs
A
530
4.0 (25)
0.715 (30)
2.7 (0.75)
Alternative Treatment Steps
B £ D
720 195 2050
53.0
106.0
39.0
5.0
72.0
144.0
48.0
34.0
19.5
39.0
15.0
4.0
205.0
410.0
125.0
16.0
203.0
298.0
7.5
56.0
Effluent Quality
Raw Waste
Load
kg/1000 cu m (lb/1000 bbl)
BOD5
COD
Oil & Grease
Phenolics
Sulfide
Ammonia
Suspended Solids
Total Chromium
173.0 (60)
460.0 (162)
52.6 (18.5)
7.6 (2.7)
0.9 (0.3)
35.0 (12.4)
47.7 (17)
0.30 (0. 107)
Resulting Effluent Levels
(Design Average kg/1000 cu m)
B
10.8
67.9
5.1
0.071
0.071
7. 1
14.2
0.35
£ D
2.2
10.8
3.7 0.45
0.0091
0.045
2.8
7.1 2.2
0.178 0.11
123
-------
TABLE 38
WATER EFFLUENT TREATMENT COSTS
PETROLEUM REFINING INDUSTRY
PETROCHEMICAL SUBCATEGORY
Refinery Capacity
1000 cubic meters/day (1000 bbl/day)
Wastewater Flow
cubic meters /cubic meter of feedstock (gal/bbl)
Treatment Plant Size
1000 cubic meters/day (MGD)
15.9 (100)
0.715 (30)
10.9 (3.0)
Costs in $1000
Initial Investment
ANNUAL COSTS:
Capital Costs (10%)
Depreciation (20%)
Operating Costs
Energy
Total Annual Costs
A
1260
126.0
252.0
98.0
15.0
491.0
Alternative Treatment Steps
1. £ P.
2700 360 4700
270.0
540.0
203.0
93.0
1106.0
36.0
72.0
29.0
12.0
149.0
470.0
940.0
192.0
38.0
1640.0
Effluent Quality
Raw Waste
Load
kg/1000 cu m (lb/1000 bbl)
BODS
COD
Oil & Grease
Phenolics
Sulfide
Ammonia
Suspended Solids
Total Chromium
173.0 (60)
460.0 (162)
52.6 (18.5)
7.6 (2.7)
0.9 (0.3)
35.0 (12.4)
47. 7 (17)
0.30 (0. 107)
Resulting Effluent Levels
(Design Average kg/1000 cu m)
B
10.8
67.9
5. 1
0.071
0.071
7. 1
14.2
0.35
C
3.7
7. 1
0. 178
D_
2.2
10.8
0.45
0.0091
0.045
8
.2
2.
2.
0.11
124
-------
TABLE 39
WATER EFFLUENT TREATMENT COSTS
PETROLEUM REFINING INDUSTRY
PETROCHEMICAL SUBCATEGORY
Refinery Capacity
1000 cubic meters/day (1000 bbl/day)
Wastewater Flow
cubic meters/cubic meter of feedstock (gal/bbl)
Treatment Plant Size
1000 cubic meters/day (MGD)
Costs in $1000
Initial Investment
ANNUAL COSTS:
Capital Costs (10%)
Depreciation (20%)
Operating Costs
Energy
Total Annual Costs
31.8 (200)
0.715 (30)
21.9 (6.0)
Alternative Treatment Steps
A 13 £ D
1830 4070 430 6650
183.0
366.0
145.0
25.0
407.0
814.0
329.0
155.0
43.0
86.0
37.0
20.0
665.0
1330.0
270.0
60.0
719.0
1648.0
186.0
2325.0
Effluent Quality
Raw Waste
Load
kg/1000 cu m (lb/1000 bbl)
BODS
COD
Oil &. Grease
Phenolics
Sulfide
Ammonia
Suspended Solids
Total Chromium
173.0 (60)
460.0 (162)
52.6 (18.5)
7.6 (2.7)
0.9 (0. 3)
35.0 (12.4)
47.7 (17)
0. 30 (0. 107)
Resulting Effluent Levels
(Design Average kg/1000 cu m)
B_
10.8
67.9
5. 1
0.071
0.071
7. 1
14.2
0.35
C D
2.2
10.8
3.7 0.45
0.0091
0.045
2.8
7.1 2.2
0.178 0.11
125
-------
TABLE 40
WATER EFFLUENT TREATMENT COSTS
PETROLEUM REFINING INDUSTRY
LUBE SUBCATEGORY
Refinery Capacity
1000 cubic meters/day (1000 bbl/day)
Wastewater Flow
cubic meters/cubic meter of feedstock (gal/bbl)
Treatment Plant Size
1000 cubic meters/day (MGD)
4.0 (25)
1.07 (45)
4. 1 (1.125)
Costs in $1000
Initial Investment
ANNUAL COSTS:
Capital Costs (10%)
Depreciation (20%)
Operating Costs
Energy
Total Annual Costs
A
690
69.0
138.0
62.0
6.0
275.0
Alternative Treatment Steps
B C_ D
1120 220 2700
112.0
224.0
72.0
47.0
455.0
22.0
44.0
20.0
5.0
91.0
270.0
540.0
139.0
20.0
969.0
Effluent Quality
Raw Waste
Load
kg/1000 cu m (lb/1000 bbl)
BOD5>
COD
Oil & Grease
Phenolics
Sulfide
Ammonia
Suspended Solids
Total Chromium
215
538,
119
8
0
35
71
0 (76)
0 (190)
0 (42)
2 (2.9)
014 (0.005)
0 (12.4)
0 (25)
Resulting Effluent Levels
(Design Average kg/1000 cu m)
0.45 (0. 16)
15.8
116.0
7 5
o!ios
0. 108
7.1
22.0
0.50
5.4
10.8
0.266
D
3.7
20.0
0.71
0.014
0.071
2.8
3.7
0. 18
126
-------
TABLE 41
WATER EFFLUENT TREATMENT COSTS
PETROLEUM REFINING INDUSTRY
LUBE SUBCATEGORY
Refinery Capacity
1000 cubic meters/day (1000 bbl/day)
17.5 (45)
Wastewater Flow
cubic meters/cubic meter of feedstock (gal/bbl) 1.07 (45)
Treatment Plant Size
1000 cubic meters/day (MGD)
18.0 (4.95)
Costs in $1000
Initial Investment
ANNUAL COSTS:
Capital Costs (10%)
Depreciation (20%)
Operating Costs
Energy
Total Annual Costs
A
1650
165.0
330.0
129.0
20.0
644.0
Alternative Treatment Steps
B £ D
3720 420 6100
372.0
744.0
285.0
135.0
1536.0
42.0
84.0
35.0
17.0
178.0
610.0
1220.0
236.0
52.0
2118.0
Effluent Quality
Raw Waste
Load
kg/1000 cu m (Ib/1000 bbl)
BODS
COD"
Oil & Grease
Phenolics
Sulfide
Ammonia
Suspended Solids
Total Chromium
215.
538.
119.
8.
0.
35,
71,
0 (76)
0 (190)
0 (42)
2 (2.9)
014 (0.005)
0 (12.4)
0 (25)
Resulting Effluent Levels
(Design Average kg/1000 cu m)
0.45 (0. 16)
15.8
116.0
7.5
0.108
0.108
7.1
22.0
0.50
5.4
10.8
0.266
D_
3.7
20.0
0.71
0.014
0.071
2.8
3.7
0.18
127
-------
TABLE 42
WATER EFFLUENT TREATMENT COSTS
PETROLEUM REFINING INDUSTRY
LUBE SUBCATEGORY
Refinery Capacity
1000 cubic meters/day (1000 bbl/day)
Wastewater Flow
cubic meters/cubic meter of feedstock (gal/bbl)
Treatment Plant Size
1000 cubic meters/day (MGD)
39.8 (250)
1.07 (45)
41.0 (11.25)
Costs in $1000
Initial Investment
ANNUAL COSTS:
Capital Costs (10%)
Depreciation (20%)
Operating Costs
Energy
Alternative Treatment Steps
A B_ £ D
3220 7720 600 9500
322.0
644.0
256.0
45.0
772.0
1544.0
595.0
245.0
60.0
120.0
48.0
35.0
950.0
1900.0
370.0
95.0
Total Annual Costs 1267. 0
3156.0
263.0
3315.0
Effluent Quality
Raw Waste
Load
kg/1000 cu m (lb/1000 bbl)
BODS
COD
Oil & Grease
Phenolics
Sulfide
Ammonia
Suspended Solids
Total Chromium
215.0 (76)
538.0 (190)
119.0 (42)
8.2 (2.9)
0.014 (0.005)
35.0 (12.4)
71.0 (25)
0.45 (0.16)
Resulting Effluent Levels
(Design Average kg/1000 cu m)
B
15.8
116.0
7.5
0. 108
0. 108
7. 1
22.0
0.50
£
_
-
5.4
-
-
-
10.8
0.266
D
3.7
20.0
0. 71
0.014
0.071
2.8
3.7
0.18
128
-------
TABLE 43
WATER EFFLUENT TREATMENT COSTS
PETROLEUM REFINING INDUSTRY
INTEGRATED SUBCATEGORY
Refinery Capacity
1000 cubic meters/day (1000 bbl/day) 9.8 (65)
Wastewater Flow
cubic meters/cubic meter of feedstock (gal/bbl) 1.14 (48)
Treatment Plant Size
1000 cubic meters/day (MGD) 11.4 (3. 12)
Costs in $1000
Initial Investment
ANNUAL COSTS:
Capital Costs (10%)
Depreciation (20%)
Operating Costs
Energy
Total Annual Costs
A
1270
127.0
254.0
103.0
20.0
504.0
Alternative Treatment Steps
B C_ D
3040 242 4900
304.0
608.0
243.0
106.0
1261.0
24.0
48.0
21.0
15.0
108.0
490.0
980.0
206.0
43.0
1719.0
Effluent Quality
Raw Waste
Load
kg/1000 cu m (lb/1000 bbl)
BODS
COD"
Oil & Grease
Phenolics
Sulfide
Ammonia
Suspended Solids
Total Chromium
195.
325.
74.
3.
2.
35
57
0 (69)
0 (115)
0 (26)
7 (1.32)
0 (0.7)
,0 (12.4)
, 0 (20.3)
Resulting Effluent Levels
(Design Average kg/I OOP cu m)
0.48 (0. 17)
B_
17.0
125.0
8.4
0. 113
0. 113
7.1
22.0
0.57
5.7
11.3
0.283
D
4.2
23.7
0.85
0.017
0.085
2.8
4.2
0.22
129
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TABLE 44
WATER EFFLUENT TREATMENT COSTS
PETROLEUM REFINING INDUSTRY
INTEGRATED SUBCATEGORY
Refinery Capacity
1000 cubic meters/day (1000 bbl/day) 23.0 (152)
Wastewater Flow
cubic meters /cubic meter of feedstock (gal/bbl) 1.14 (48)
Treatment Plant Size
1000 cubic meters/day (MGD) 26.6(7.3)
Costs in $1000
Initial Investment
ANNUAL COSTS:
Capital Costs (10%)
Depreciation (20%)
Operating Costs
Energy
Total Annual Costs
A
2340
234.0
468.0
203.0
36.0
941.0
Alternative Treatment Steps
B_ £ D_
5440 434 7860
544.0
1088.0
470.0
188.0
2290.0
43.0
86.0
38.0
21.0
188.0
786.0
1572.0
329.0
68.0
2755.0
Effluent Quality
Raw Waste
Load
kg/1000 cu m (lb/1000 bbl)
BODS
COD
Oil & Grease
Phenolics
Sulfide
Ammonia
Suspended Solids
Total Chromium
195.
325.
74.
3.
2.
35
57
0 (69)
0 (115)
0 (26)
7 (1.32)
0 (0.7)
.0 (12.4)
. 0 (20.3)
Resulting Effluent Levels
(Design Average kg/1000 cu m)
0.48 (0. 17)
Ei
17.0
125.0
8.4
0. 113
0.113
7.1
22.0
0.57
5.7
11.3
0.283
D
4.2
23.7
0.85
0.017
0.085
2.8
4.2
0.22
130
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TABLE 45
WATER EFFLUENT TREATMENT COSTS
PETROLEUM REFINING INDUSTRY
INTEGRATED SUBCATEGORY
Refinery Capacity
1000 cubic meters/day (1000 bbl/day) 49.0 (326)
Wastewater Flow
cubic meters/cubic meter of feedstock (gal/bbl) 1.14 (48)
Treatment Plant Size
1000 cubic meters/day (MGD) 56.8 (15.6)
Costs in $1000
Initial Investment
ANNUAL COSTS:
Capital Costs (10%)
Depreciation (20%)
Operating Costs
Energy
A
4410
441.0
882.0
381.0
69.0
Alternative Treatment Steps
B C_ D
10100 820 10500
1010.0
2020.0
885.0
354.0
Total Annual Costs 1773.0 4269.0
82.0
164.0
71.0
52.0
369.0
1050.0
2100.0
439.0
107.0
3696.0
Effluent Quality
Raw Waste
Load
kg/1000 cu m (lb/1000 bbl)
BODS
COD"
Oil & Grease
Phenolics
Sulfide
Ammonia
Suspended Solids
Total Chromium
195.
325.
74.
3.
2.
35
57
0 (69)
0 (115)
0 (26)
7 (1.32)
0 (0.7)
, 0 (12.4)
,0 (20.3)
Resulting Effluent Levels
(Design Average kg/1000 cu m)
0.48 (0.17)
B_
17.0
125.0
8.4
0.113
0.113
7.1
22.0
0.57
5.7
11.3
0.283
D
4.2
23.7
0.85
0.017
0.085
2.8
4.2
0.22
131
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FIGURE 6
BPCTCA - Wastewater Treatment System
MODEL SYSTEM USED FOR THE ECONOMIC EVALUATION
-------
TABLE 46
BPCTCA - END OF PIPE TREATMENT SYSTEM
MODEL USE FOR THE ECONOMIC EVALUATION
DESIGN SUMMARY
Treatment System Hydraulic Loading
Treatment system hydraulic loadings are sized to represent
the projected waste water flows from small, average, and
large refineries in each subcategory. The flow range used in
these estimates ranges from 95 to 38,000 m^/day (25,000 gpd
to 10,000,000 gpd) .
Dissolved Air Flotation
The flotation units are sized for an overflow rate of 570
m3/day/m2 (1400 gpd/sq.ft)
Pump Station
Capacity to handle 200 percent of the average hydraulic flow.
Equalization
One day detention time is provided. Floating mixers are I
provided to keep the contents completely mixed. I
Neutralization
The two-stage neutralization basin is sized on the basis of
an average detention time of twenty minutes. The lime-
handling facilities are sized to add 1,000 Ibs. of hydrated
lime per mgd of waste water, to adjust the pH. Bulk-storage
facilities (based on 15 days usage) or bag storage is
provided, depending on plant size. Lime addition is
controlled by two pH probes, one in each basin. The lime
slurry is added to the neutralization basin from a lime
slurry recirculation loop. The lime-handling facilities are
enclosed in a building.
Nutrient Addition
Facilities are provided for the addition of phosphoric acid
to the biological system in order to maintain the ratio of
BOD:P at 100:1.
Aeration Basin
Platform-mounted mechanical aerators are provided in the
aeration basin. In addition, walkways are provided to all
aerators for fan access and maintenance. The following data
were used in sizing the aerators.
Oxygen utilization 1.5 kg O2/kg BOD
133
-------
L
B
Waste water temperature
Oxygen transfer
Motor Efficiency
Minimum Basin D.O.
(1.5 Ibs 02/lb. BOD) removed
0.8
0.9
20°C
1.6 kg (3.5 Ibs.) O|/hr./shaft HP at
20°c and zero D.O. in tap water
85 percent
1 mg/1
Oxygen is monitored in the basins using D.O. probes.
Secondary Clarifiers
All secondary clarifiers are circular units. The side water
depth is 3.0 meters (10 ft.) and the overflow rate is 500
gpd/sq. ft.). Sludge recycle pumps are sized to deliver 50
percent of the average flow.
Sludge Holding Tank-Thickener
For the smaller plants, a sludge-holding tank is provided,
with sufficient capacity to hold 5 days flow from the aerobic
digester. The thickener provided for the larger plants was
designed on the basis of 29 kg/m2/day (6 Ibs./sq. ft./day)
and a side water depth of 3.0 meters (10 ft.)
Aerobic Digester
The aerobic digester is sized on the basis of a hydraulic
detention time of 20 days. The sizing of the aerator-mixers
was based on O.OUUHP/m3 (1.25 HP/1,000 cu.ft.) of digester
volume.
Vacuum Filtration
The vacuum filters were sized on cake yield of 9.75 kg/m2/hr.
(2 lbs,/sq.ft./hr) and a maximum running time of 18 hrs./day.
The polymer system was sized to deliver up to 0.005kg of
polymer/kg of day solids (10 Ibs. of polymer/ton dry solids).
Granular Media Filters
The filters are sized on the basis of an average hydraulic
loading of 9.12m3/mz/min, (3 gpm/sq.ft.) Backwash facilities
are sized to provide rate up to 0.82m3/m2/min. (20
gpm/sq.ft.) and a backwash cycle of up to 20 minutes
duration.
Final Sludge Disposal
Sludge is disposed of at a sanitary landfill assumed to be 5
miles from the waste water treatment facility.
Design Philosophy
134
-------
The plant's forward flow units are designed for parallel
flow, i.e. either half of the plant can be operated
independently. The sludge facilities are designed on the
basis of series flow. All outside tankage is reinforced
concrete. The tops of all outside tankage are assumed to be
12 ft above grade.
135
-------
REGENERATED CARBON
STORAGE TANK
FILTER WATER
HOLDING TANK
CARBON COLUMN
FEED PUMPS
PLANT
EFFLUENT
CARBON
COLUMNS)
A
TRANSFER
TANK
DRYING TANK
AIR
BLOWER
DRY STORAGE TANK
M>»>fr»-,H) SCREW
FEEDER
REGENERATION
FURNACE
QUENCH TANK
VIRGIN
CARBON
STORAGE
FIGURE 7
BATEA - PROPOSED TREATMENT
-------
TABLE 47
BATEA - END OF PIPE TREATMENT SYSTEM
DESIGN SUMMARY
Granular Carbon Columns
The carbon columns are sized on a hydraulic loading of 0.4-0.8
m3/m2/min. (10-20 gpm/sq. ft.) and a column detention time of 40
minutes. A backwash rate of (50 gpm/sq. ft.) was assumed for 40
percent bed expansion at 70°F.
Filter-Column Decant Sump
Tankage is provided to hold the backwash water and decant it back
to the treatment plant over a 24-hour period. This will
eliminate hydraulic surging of the treatment units.
Regeneration Furnace
An exhaustion rate of 1 kg of COD/kg carbon (1 Ib COD/lb carbon)
was used for sizing the regeneration facilities.
Regenerated Exhausted Carbon Storage
Tankage is provided to handle the regenerated and exhausted
carbon both before and after regeneration.
137
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Estimated costs of Facilities
As discussed previously, designs for the model treatment systems
were costed out in order to evaluate the economic impact of the
proposed effluent limitations. The design considerations
resulted in the generation of cost data which would be
conservative. However, relatively conservative cost numbers are
preferred for this type of general, economic analysis.
Activated sludge followed by granular media filtration was used
as the BPCTCA treatment system. The plant designs were varied to
generate cost effectiveness data within each category. Activated
carbon adsorption was used as the BATEA treatment.
Capital and annual cost data were prepared for each of the
proposed treatment systems.
The capital costs were generated on a unit process basis, e.g.
equalization, neutralization, etc. for all the proposed treatment
systems. The following "percent add on" figures were applied to
the total unit process costs in order to develop the total
capital cost requirements:
Percent of Unit
Item Process Capital cost
Electrical 12
Piping 15
Instrumentation 8
Site work 3
Engineering Design and Construction
Supervision Fees 15
Construction Contingency 15
Land costs were computed independently and added directly to the
total capital costs.
Annual costs were computed using the following cost basis:
Item Cost Allocation
Amortization 10 percent of investment.
Depreciation 5 year-straight line with zero salvage
Operations and value. Includes labor and supervision.
Maintenance chemicals sludge, hauling and disposal,
insurance and taxes (computed at 2 per-
cent of the capital cost), and maintenance
(computed at U percent of the capital cost)
Power Based on $1.50/100 KWH for electrical
power.
The short term capitalization and depreciation write-off period
is that which is presently acceptable under current Internal
Revenue Service Regulations pertaining to industrial pollution
control equipment.
138
-------
All cost data were computed in terms of August, 1971 dollars,
which corresponds to an Engineering News Records (ENR) value of
1580.
The following is a qualitative as well as a quantitative
discussion of the possible effects that variations in treatment
technology or design criteria could have on the total capital
costs and annual costs.
Technology or Design Criteria
1. Use aerated lagoons and sludge de-
watering lagoons in place of the
proposed treatment system.
2. Use earthern basins with a plastic
liner in place of reinforced concrete
construction, and floating aerators
versus platform-mounted aerators
with permanent-access walkways.
3. Place all treatment tankage above
grade to minimize excavation,
espcaially if a pumping station is
required in any case. Use all-steel
tankage to minize capital cost.
4. Minimize flow and maximize concen-
trations through extensive in-plant
recovery and water conservation, so
that other treatment technologies
(e.g. incineration) may be economi-
cally competitive.
Capital
Cost Differential
1. The cost reduction
could be to 70 percent
of the proposed figures.
2. Cost reduction could
be 10 to 15 percent of
the total cost.
3. Cost savings would
depend on the individual
situation.
4. Cost differential
would depend on a number
of items, e.g. age of
plant, accessibility to
process piping, local air
pollution standards, etc.
The following table summarizes the general ranges of sludge
quantities generated by small, medium, and large refineries in
each subcategory.
139
-------
Subcategory cu m/vr * cu yd/yr *
Topping 2.3-15 3-20
Low Cracking 76-380 100 - 500
High Cracking 380-2300 500 - 3000
Petrochemical 460-3800 600 - 5000
Lube 610-6900 800 - 9000
Integrated 760-9200 1000 - 12000
iWet-weight basis
Particular plants within the petrochemical, lube, and integrated
subcategories may be amenable to sludge incineration because of
the large quantities of sludge involved. For example, sludge
incineration would reduce the previous quantities by about 90
percent. Sludge cake is 80 percent water, which is evaporated
during incineration, and more than half of the remaining (20
percent) solids are thermally oxidized during incineration.
Sludge incineration costs were not evaluated for those specific
cases, because the particular economics depend to a large degree
on the accessibility of a sanitary landfill and the relative
associated hauling costs.
The following discussion is presented to help visualize the
complexities involved in evaluating cost effectiveness data.
Every treatment system is composed of units whose design basis is
primarily hydraulically dependent, organically dependent, or a
combination of the two. The following is a list of the unit
processes employed, and a breakdown of the design basis.
Hydraulically Organically Hydraulically and
Dependent Dependent Organically Dependent
Pump station Thickener Aeration basin
API separator Aerobic Digestor Oxygen transfer equipment
Equalization Vacuum filter Air flotation Unit
Neutralization
Nutrient addition
Sludge recycle pump
Clarifier
The annual cost associated with the hydraulically dependent unit
processes is not a function of effluent level. On the other
hand, the sizing of the organically dependent units should
theoretically vary in direct proportion to the effluent level:
e.g. reducing the BOD5 removal from 95 to 85 percent should
reduce the sizes of the sludge handling equipment by
approximately 10 percent. However, there are two complicating
factors: 1) only a relatively few sizes of commercially available
equipment; and 2) broad capacity ranges. These two factors,
especially in regard to vacuum filters, tend to negate
differentials in capital cost with decreasing treatment levels.
140
-------
The relationship between design varying contaminant levels and
the design of aeration basins and oxygen transfer equipment is
somewhat more complex. The levels are dependent on the hydraulic
flow, organic concentration, sludge settleability, and the
relationship between mixing and oxygen requirements. For
example, to reach a particular effluent level, the waste water's
organic removal kinetics will require a particular detention time
at a given mixed-liquor concentration. The oxygen transfer
capacity of the aerators may or may not be sufficient to keep the
mixed liquor suspended solids in suspension within the aeration
basin. Therefore, the required horsepower would be increased
merely to fulfill a solids mixing requirement. Alternatively,
the oxygen requirements may be such that the manufacturer's
recommended minimum spacing and water depth requirements would
require that the basin volume be increased to accommodate oxygen
transfer requirements.
Non-water Quality Aspects
The major nonwater quality consideration which may be associated
with in-process control measures is the use of and alternative
means of ultimate disposal of either liquid or solid wastes. As
the process Raw Waste Load is reduced in volume, alternate
disposal techniques such as incineration, ocean discharge, and
deep-well injection are feasible. Recent regulations are tending
to limit the applicability of ocean discharge and deep-well
injection because of the potential long-term detrimental effects
associated with these disposal procedures. Incineration may be a
viable alternative for highly concentrated waste streams.
However, associated air pollution and the need for auxiliary
fuel, depending on the heating value of the waste, are
considerations which must be evaluated on an individual basis for
each use. Other nonwater quality aspects, such as noise levels,
will not be perceptibly affected. Most refineries generate
fairly high noise levels (85-95 dB(A)) within the battery limits
because of equipment such as pumps, compressors, steam jets,
flare stacks, etc. Equipment associated with in-process or end-
of-pipe control systems would not add significantly to these
levels. In some cases, substituting vacuum pumps for steam jets
would in fact reduce plant noise levels. There are no
radioactive nuclides used in the industry, other than in
instrumentation. Thus no radiation problems will be expected.
Compared to the odor emissions possible from other refinery
sources, odors from the waste water treatment plants are not
expected to create a significant problem. However, odors are
possible from the waste water facilities, especially from the
possible stripping of ammonia and sulfides in the air flotation
units, and from accidental anaerobic conditions in biological
facilities during upsets.
The extra power required for waste water treatment and control
systems is negligible compared to the total power requirements of
the petroleum refining equipment.
141
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-------
SECTION IX
BEST PRACTICABLE CONTROL TECHNOLOGY CURRENTLY
AVAILABLE—EFFLUENT LIMITATIONS
Based on the information contained in Sections III through VIII
of this report, effluent limitations commensurate with the best
practicable control technology currently available have been
established for each petroleum refining subcategory. The
limitations, which explicitly set numerical values for the
allowable pollutant discharges within each subcategory, are
presented in Tables 1-6. The effluent limitations specify
allowable discharges of BODS, COD, TOC, total suspended solids,
oil and grease, phenolic compounds, ammonia (N), sulfides, total
and hexavalent chromium; based upon removals which are capable of
being attained through the application of BPCTCA pollution
control technology.
The best practicable control technology currently available is
based on both in-plant and end-of-pipe technology. BPCTCA in-
plant technology is based on control practices widely used within
the petroleum refining industry, and include the following:
1. Installation of sour water strippers to reduce the sulfide
and ammonia concentrations entering the treatment plant.
2. Elimination of once-through barometric condenser water by
using surface condensers or recycle systems with oily water
cooling towers.
3. Segregation of sewers, so that unpolluted storm runoff and
once-through cooling waters are not treated normally with the
process and other polluted waters.
4. Elimination of polluted once-through cooling water, by
monitoring and repair of surface condensers or by use of wet
and dry recycle systems.
BPCTCA end-of-pipe treatment technology is based on the existing
waste water treatment processes currently used in the Petroleum
Refining Industry. These consist of equalization and storm
diversion; initial oil and solids removal (API separators or
baffle plate separators); further oil and solids removal
(clarifiers, dissolved air flotation, or filters); carbonaceous
waste removal (activated sludge, aerated lagoons, oxidation
ponds, trickling filter, activated carbon, or combinations of
these); and filters (sand, dual media; or multi-media) following
biological treatment methods. It must be recognized that
specific treatability studies are required prior to the
application of a specific treatment system to the individual
refinery.
Granular media filtration or polishing ponds prior to final
discharge are included so that the total suspended solids and oil
143
-------
concentrations in the final effluent can be generally maintained
at approximately 10 mg/1 and 5 mg/1, respectively. The final
polishing step is considered BPCTCA for the petroleum refining
industry since several refineries are now using polishing ponds,
and granular media filters are becoming accepted technology with
a few installations operating currently and several more now
under construction.
In a petroleum refinery the waste water treatment plant should be
used to treat only polluted waters. All once-through cooling
water or storm runoff which is unpolluted should be segregated as
it dilutes the polluted waters and requires treatment of a
greater flow. Flows for BPCTCA were based on the 50 percent
probability of occurance flows for plants practicing recycle with
less than 3 percent heat removal by once-through cooling water
(on a dry weather basis). Recognizing the additional flows and
waste loads associated with rain runoff and ballast waters,
allocations for these added flows must be given based on strict
segregation of runoff and ballast waters treated.
PROCEDURE FOR DEVELOPMENT OF BPCTCA EFFLUENT LIMITATIONS
The effluent guideline limitations were determined using effluent
data from refineries visited during this project or attainable
effluent concentrations and the 50 percent probability of
occurance flow from the refineries with 3 percent or less of the
heat removed by once-through cooling water. In some cases the
available data from the refineries visited was considered to be
too stringent to be met by the industry in general. In these
cases the flow and concentration procedure was used. The median
flows are presented in Table 23, Section V. The attainable
concentrations for BPCTCA are presented in Table 48. Refinery
data are presented in Tables 26-28, Section VII.
Several exceptions to this procedure were required to establish
meaningful effluent limitations in specific cases. These are as
follows:
Topping, Cracking, Petrochemical, Lube, and Integrated
Subcategories - Ammonia as Nitrogen
The ammonia as nitrogen effluent limitations were calculated
using an 80 percent reduction from the 50 percent probability of
occurance raw waste loads in each subcategory.
Topping, Cracking, Petrochemial, Lube and Integrated
Subcategories - TOC
Little data is available on the reduction of TOC. Available
effluent data indicate an effluent TOC/BOD ratio of less than
2.2. Using this factor, effluent limitations for TOC, were based
on BODJ3 limitations. It is recognized that this ratio (TOC/BOD)
is variable between the refineries, and prior to use, an agreed
upon correlation should be developed for the individual refinery.
144
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TABLE 48
Attainable Concentrations from the Application of
Best Practicable Control Technology Currently Available
Parameter
BODS
COD
TOC
SS
0 & G
Phenol
NH3-N
Sulfide
CrT
Cr6
Concentration mg/1
15
*
*(2.2 x BODS)
10
5
0.1
*(80% removal)
0.1
.25
.005
*See Text
145
-------
Topping, Cracking, Petrochemical, Lube and Integrated
Subcategories - COD
The COD effluent concentrations were determined from refinery
effluent data and are as follows: topping - 80 mg/1; cracking -
115 mg/1; petrochemical - 96 mg/1; lube - 110 mg/1; and
integrated - 110 mg/1.
The long term (annual or design) average effluent limitations
determined are contained in Table U9.
Statistical Variability of a Properly Designed and Operated Waste
Treatment Plant
The effluent from a properly designed and operated treatment
plant changes continually due to a variety of factors. Changes
in production mix, production rate and reaction chemistry
influence the composition of raw wasteload and, therefore, its
treatability. Changes in biological factors influence the
efficiency of the treatment process. A common indicator of the
pollution characteristics of the discharge from a plant is the
long-term average of the effluent load, however, the long-term
(e.g., design or yearly) average is not a suitable parameter on
which to base an enforcement standard. However, using data which
show the variability in the effluent load, statistical analyses
can be used to compute short-term limits (30 day average or
daily) which should never be exceeded, provided that the plant is
designed and run in the proper way to achieve the desired long-
term average load. It is these short-term limits on which make
up the effluent guidelines.
In order to reflect the variabilities associated with properly
designed and operated treatment plants for each of the parameters
as discussed above, a statistical analysis was made of plants
where sufficient data was available to determine these variances
for day-to-day and month-to-month operations.
This data was acquired during the initial field investigation or
submitted by API or other industry sources.
The variability data have been treated in the following manner:
a. The form of the statistical distribution
which most generally describes the data for all plants
was determined;
b. For each plant the statistical parameter which best fit
the plants' data to the above distribution were
calculated;
c. Values of "daily maximum" and "30 day maximum"
variabilities were then determined using the values
calculated above. The daily maximum variability was set
embracing 99% of the expected variation and the 30 day
average was set embracing 98% of the expected variation.
146
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TABLE 49
BPCTCA
PETROLEUM REFINING INDUSTRY EFFLUENT LIMITATIONS
Annual Daily Kilograms of Pollutants/lOOOCubic Meters Feedstock (1) Per Stream Day
(Annual Average Daily Pounds of Pollutant/1000 BBL of Feedstock Per Stream Day)
Ref i nery
Subcategory
Topping
Cracking
Petrochemical
Lube
Integrated
Runoff(2) 0
8allast(3) 0,
8005
7.1(2.5)
8.8(3.1)
10.8(3.8)
15.8(5.6)
17.0(6.0)
.015(0.125
.015(0.125
Total
Suspended
Solids
4.8(1.7)
5.9(2.1)
7.1(2.5)
0.8(3.8)
1.3(4.0)
Oil &
Grease
2.3(0.
2.8(1.
3.7(1.
5.4(1.
5.7(2.
83)
0)
3)
9)
0)
Phenolic
Compounds
0.048(0.017)
0.059(0.
0.071(0.
0.108(0.
0.113(0.
021)
025)
038)
040
Ammonia(N)
0.85(0.30)
5.7 (2.0)
7.1 (2.5)
7.1 (2.5)
7.1 (2.5)
Sulfide
0.
0.
0.
0.
0.
048(0.
059(0.
071(0.
108(0.
113(0.
017)
021)
025)
038)
040)
Total
Chromium
0.119(0,
0.147(0.
0.178(0,
). 266(0,
0.283(0,
.042)
.052)
.063)
.094)
.10)
Hexavalent
Chromium
0.0023(0.0008)
0.0028(0'. 0010)
0.0037(0.0013)
0.0054(0.0019)
0.0056(0.0020)
COD TOC
37.6(13.3) 15.6(5.5)
67.9(24.0) 19.2(6.8)
67.9(24.0) 23.5(8.3)
116 (41.0) 35.1(12.4) 10.8(3.8)
125 (44.0) 37.4(13.2) 11.3(4.0)
0.015(0.125) 0.12(1.0) 0.033(0.275)0.010(0.083)0.0050(0.042)
0.015(0.125) 0.15(1.250)0.033(0.275)0.010(0.083)0.0050(0.042)
(1) Feedstock - Crude oil and/or natural gas liquids.
(2) The additional allocation being allowed for contaminated storm runoff flow, kg/cubic meter (lb/1000 gallons), shall be based solely on that storm
flow which passes through the treatment system. All additional storm runoff, that has been segregated from the main waste stream, shall not
exceed a TOC concentration of 35 mg/1 or Oil and Grease concentration of 15 mg/1 when discharged.
(3) This is an additional allocation, based on ballast water intake - kilograms per 1000 liters (pounds per 1000 gallons).
-------
Results of -the Data analysis:
The data from each refinery were determined to be eiter normally
or log normally distributed.
The daily maximums, when the data is normally distributed, the
variability is equal to x + 2.321 Q; where x is the mean or
x
design average and Q is the standard deviation for the data.
When the data was log normally distributed, the variability is
(4.65-2.30R)R/2
equal to 10 : where R is the standard deviation
of the logarithm of the data points.
The variability factors used are contained in Table 50. These
factors for each parameter except total and hexavalent chromium
were calculated from long-term refinery data. The factor for
total chromium is the same as that used for suspended solids
since metallic ion is removed as an insoluble salt. The
variability factor for hexavalent chromium was based on the
sulfide variability. The guidelines for BPCTCA presented in
Tables 1-6 have taken into consideration the above variability
factors.
Process and Size Factor
A complete process breakdown of many of the U.S. refineries is
contained in Table 51. This table was prepared from the best
published data available (Oil and Gas Journal, International
Petroluem Encyclopedia, and the EPA/API Raw Waste Load Survey of
1972) , but should only be used as a guide. The values used to
determined the process and size factors for permit issuance
should be documented by the individual refineries.
An example calculation of the process and size factors follows
below. It should be noted that only crude processes, cracking
processes, lube processes, and asphalt processes enter into the
calculation of process configuration.
Process Processes included Weighting
category factor
Crude Atm. crude distillation 1
Vacuum crude distillation.
Desalting
Cracking and Fluid cat. cracking 6
coking Vis-breaking.
Thermal cracking
Moving bed cat. cracking
Hydrocracking
Fluid coking
Delayed coking
148
-------
TABLE 50
VARIABILITY FACTORS BASED ON PROPERLY DESIGNED
AND OPERATED WASTE TREATMENT FACILITIES
BODS COD. TOC_ TSS, 0 & G Phenol Ammonia Sulfide CrT Cr6
Daily 3.2 3.1 3.1 2.9 3.0 3.5 3.3 3.1 2.9 3.1
Variability
30 Day Average 1.7 1.6 1.6 1.7 1.6 1.7 1.5 1.4 1.7 1.4
Variability
VO
-------
Lube
Asphalt
Further defined in
Table 51.
Asphalt production
Asphalt oxidation
Asphalt emulsifying
13
12
Example: Lube Refinery - 125,000 bbl/day stream day
Process
Crude - ATM
Vacuum
Desalting
Total
Cracking - FCC
Hydrocracking
Total
Lubes
Lube Hydro-
fining
Furfural
Extraction
Phenol
Extraction
Total
Asphalt
Capacity
(1,000 bbl per
stream day)
125
60
125
41
20
5.3
4.0
4.0
Capacity Weighting Process
relative to factor configu-
throughput
1
.48
1
2.48 X
.328
..,160
.488 X
.042
.032
.030
.113 X
1 =
6 =
ration
2.48
2.48
4.0 0.032 X
Refinery process configuration
NOTES
13
12
1.47
.38
7.26
See Table 4 for process factor. Process factor = 0.88. See Table
4 for.,.,size factor for 125,000 bbl per stream day lube refinery.
Size factor = 0.93. To calculate the limits for each parameter,
multiply the limit Table 4 by both the process factor and size
factor. BODS limit (maximum for any 1 day) = 17.9 x 0.88 x
0.93=14.6 Ib. per 1,000 bbl of feedstock.
IbO
-------
TABLE 51
PETROLEUM REFINING - PROCESS BREAKDOWN
Legend:
A. Crude Processes
D - desalting
A - atmospheric distillation
V - vacuum distillation
B. Cracking Processes
FCC - fluid catalytic cracking
Thermo. - thermofor
Houdri. - houdriflow
Gas-Oil Cr.- gas-oil cracking
Visbreak. - visbreaking
Fl. Coke - fluid coking
Delay.Coke - delayed coking
C. Lube Processes
A - lube hydrofining 0 - S02 extraction
B - white oil manufacturing k - wax pressing
C - propane - dewaxing, deasphalting L - wax plant (with neutral separ.)
D - duo sol, solvent dewaxing M - furfural extraction
E - lube vac. tower, wax fract. N - clay contacting - percolation
F - centrifuging and chilling 0 - wax sweating
G - MEK dewaxing P - acid treating
H - deoiling (wax) Q - phenol extraction
I - naphthenic lubes
151
-------
TABLE 51 cont'd
PETROLEUM REFINERY - PROCESS BREAKDOWN
COMPANY
Amerada Mess
Corporation
Chevron Oil
Company
Exxon Co., USA
Mobil 011
Corporation
Texaco Inc.
Ashland Petro.
^i Company
Ui
N>
Amerada-Hess
Corporation
Caribbean
Gulf Ref.
Company
Commonweal th
Oil Refining Co.
Inc.
Yabocoa Sun
Oil Company
REGION
2
2
2
2
2
2
2
2
2
2
LOCATION
Port
Reading
Perth
Amboy
Linden
Paulsboro
Westvllle
Tonawanda
St. Croix
Bayamon
Penuelas
Yabocoa
TATE
N.J.
N.J.
N.J.
N.J.
N.J.
N.Y.
V.I.
P.R.
P.R.
P.R.
SUBCAT.
B
B
C
D
C
C
A
B'
C
A
REFINERY
CAPACITY
1000 bbl
day
75.0
92.0
286.0
100.5
88.0
67.0
418.0
40.0
100.0
66.0 *
CRUDE F
Process
D
A .
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
'ROCESSES
Capacity
1000 bbl
day
75.0
75.0
30.0
92.0
92.0
50.0
286.0
286.0
143.0
100.5
100.5
62.6
88.0
88.0
29.5
67.0
67.0
25.0
418.0
418.0
20.0
40.0
40.0
9.0
100.0
100.0
50.0
66.0
66.0
30.0
CRACKING
•Process
FCC
Houdrl .
FCC
Visbreak.
Thermo.
Delay. Cok.
FCC
Visbreak.
FCC
FCC
FCC
Visbreak,
PROCESSES
Capacity
1000 bbl
day
45.0
38.0
140.0
2.2»
25.0
23.7
40.0
13.0
20.0
8.5
40.0
22.0
•'•"
LUBE P
Process
Unk.
E
G
M
ROCESSES
Capacity
1000 bbl
day
13.0
5.0
8.5
6.0
ASPHALT
PRODUCTION
Capacity
1000 bbl /day
25.0
46.0
10.0
PROCESS
CONFIG-
URATION
6.00
8.28
7.41
7.21
5.95
5.96
2.0
3.50
6.22
6.30
-------
TABLE 51 cont'd
PETROLEUM REFINERY - PROCESS BREAKDOWN
COMPANY
Getty Oil Co.
Inc.
Amoco Oil Company
Chevron
Asphalt Company
Atlantic
Richfield Company
BP Oil
Corporation
Bradford Pet.
K(Witco)
00
Gulf Oil
Company
Pennzoil Company
Quaker State Oil
Ref. Corporation
Quaker State Oil
Ref. Corporation
Sun Oil Company
United Refining
Company
REGION
3
3
3
3
3
3
3
3
3
3
3
3
LOCATION
Delaware
City
Baltimore
Bal timore
Phila.
Marcus
Hook
Bradford
Phila.
Rouseville
Emlenton
Farmers
Valley
Marcus
Hook
Warren
STATE
Del.
MD.
MD.
PA.
PA.
PA.
PA.
PA.
PA.
PA.
PA.
PA.
SUBCAT.
C
A
A
B
B
A
B
A
A
A
E
B
REFINERY
CAPACITY
1000 bbl
day
150.0
10.0
13.8
195.0
105.0
7.8
174.0
10.4
3.5
6.8
180.0
*3
38.0
CRUDE
Process
D
A
V
A
D
A
V
D
- A
. V
D
A
V
D
A
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
PROCESSE
Capacit
1000 bb
day
150.0
150.0
90.7
10.0
13.8
13.8
13.8
195.0
195.0
57.0
105.0
105.0
60.0
7.8
7.8
174.0
174.0
. 65.0
10.4
10.4
3.3
3.5
3.5
1.7
6.8
6.8
2.75
180.0
180.0
48.0
38.0
38.0
8.0
CRACKING
Process
FCC
Hydro.
FT. Coke
Hydro.
FCC
Visbreak.
FCC
FCC
FCC
PROCESSES
Capacity
1000 bbl
day
77.0
17.0
44.0
30.0
41.9
12.0
80.5
85.0
10.2
LUBE P
Process
Unk.
C
D
Unk.
C
G
M
D
E
G
I
M
ROCESSES
Capacity
1000 bbl
day
3.1
0.7
3.0
3.0
1.0
2.5
2.0
5.8
11.7
13.4
10.7
4.0
ASPHALT
PRODUCTION
Capacity
1000 bbl /day
8.0
11.0
19.5
12.0
4.0
PROCESS
CONFIG-
URATION
8.12 .
10.6
12.6
4.42
5.65
7.17
5.15
6.94
13.63
12.92
9.19
5.08
-------
TABLE 51 cont'd
PETROLEUM REFINERY - PROCESS BREAKDOWN
COMPANY
Valvoline Oil
Company
Wolf's Head
Oil (Pennzoil)
Amoco Oil
Company
Pennzoil Company
Quaker State Oil
Ref. Corporation
•> Quaker State Oil
I Ref. Corporation
Hunt Oil Co.
Marion Corp.
Vulcan Asphalt
Refining Co.
Warrior Asphalt
Corp.
Seminole Asphalt
Refining, Inc.
Amoco Oil Co.
Young Refining
Corp.
REGION
3
3
3
3
3
3
4
4
4
4
4
4
4
LOCATION
Freedom
Reno
Yorktown
Falling
Rock
Newel 1
St. Mary's
Tuscaloosa
Mobile
Cordova
Holt
St. Mark's
Savannah
Douglasville
STATE
PA.
PA.
VA.
W.V.
W.V.
W.V.
ALA.
ALA.
ALA.
ALA.
FLA.
GA.
6A.
SUBCAT.
A
A
C
A
A
A
A
A
A
A
A
A
A
REFINERY
CAPACITY
1000 bbl.
day
6.5
2.22
53.0
5.5
10.0
5.0
15.75
15.5
3.0
2.6
5.5 •»
12.0
2.5
CRUDE
Proces
D
A
V
A .
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
A
A
D
A
V
A
A
PROCESSE
Capacity
1000 bb
day
6.5
6.5
2.0
2.22
53.0
53.0
28.0
5.5
5.5
2.5
10.0
10.0
4.0
5.0
5.0
2.2
15.75
15.75
8.66
15.5
15.5
3.0
2.6
5.5
5.5
2.4
12.0
CRACKING
Process
FCC
Delay. Coke
PROCESSES
Capacity
1000 bbl
day .
30.5
14.0
LUBE P
Process
Unk.
F
K
F
K
Unk.
C
F
K
M
ROCESSES
Capacity
1000 bbl
1.3
0.95
0.6
2.4
1.0
7-0
0.7
1.85
1.25
0.8
ASPHALT
PRODUCTION
Capacity
1000 bbl/da
5.2
1.8
1.73
2.5
i <; *
PROCESS
CONFIG-
URATION
4.91
10.08
7.57
10.49
11.50
14.40
6.51
2.0
'8.20
8.98
7.89
6.5
2.5 |
-------
TABLE 51 cont'd
PETROLEUM REFINERY - PROCESS BREAKDOWN
COMPANY
Ashland Oil, Inc.
Ashland Oil, Inc.
Somerset Refining
Inc.
Amerada Hess
Corporation
Southland Oil
Company
^Southland Oil
£j Company
Southland Oil
Company
STD. Oil of
Kentucky
Delta Refining
Company
Amoco Oil
Company
Clark Oil and
Refining Corp.
REGION
4
4
4
4
4
4
4
4
4
5
5
i
Clark Oil and j _ 5
Refining Corp. j
i
Marathon Oil \ 5
Company !
!
LOCATION
Catlettsburg
Louisville
Somerset
Purvis
Crupp
Lumberton
Sandersville
Pascagoula
Memphis
WoodRiver
Blue Island
Hartford
i
Robinson
STATE
KY.
KY.
KY.
MISS.
MISS.
MISS.
MISS.
KY.
TENN.
ILL.
ILL.
ILL.
ILL.
SUBCAT.
C
B
A
B
A
A
A
C
B
C
C
3
B
REFINERY
CAPACITY
1000 bbl
day
138.0
26.0
3.0
30.0
3.2
4.26
8.3
240.0
30.0
107.0
70. 0'3
38.0
205.0
CRUDE
Proces
D
A
V
D
A
V
A
D
A
D
A
D
A
D
A
V
D
A
V
D
A
D
A
V
D
A
V
D
A
V
D
A
PROCESSES
Capacity
1000 bbl
day
138.0
138.0
55.0
26.0
26.0
10.0
3.0
30.0
30.0
3.2
3.2
4.26
4.26
8.3
8.3
4.6
240.0
240.0
148.0
30.0
30.0
107.0
107.0
40.0
70.0
70.0
27.0
38.0
38.0
15.0
205.0
205.0
J CRACKING
Process
FCC
Visbreak.
FCC
Thermo.
Delay coke
- Hydro.
"
FCC
Hydro.
Thermo .
FCC
FCC
Hydro .
FCC
Delay.
coke
Gas-Oil
Cr.
Delay.
PROCESSES
Capacity
1000 bbl
day
55.0
4.0
9.0
30.5
6.7
3.0
58.0
59.0
12.0
42.0
25.0
11.0
27.0
13.0
2.8
19.0
LUBE P
Proces
ROCESSES
Capacity
1000 bbl
day
ASPHALT
PRODUCTION
Capacity
1000 bbl /day
10.0
3.5
2.5
1.44
2.35
3.5
3.0
10.8
4.5
PROCESS
CONFIG-
URATION
5.83
6.08
11.00
10.04
7.40
8.62
7.61
5.54
5.60
5.94
6.24
8.71
4.89
-------
TABLE 51 cont'd
PETROLEUM REFINERY - PROCESS BREAKDOWN
COMPANY
Mobil 011
Corporation
Shell 01V
Company
Texaco Inc.
Texaco Inc.
Union 011 Co.
of California
Swireback 011
"^Company
Yetter 011
Company
Amoco 011
Atlantic Rich-
field Company
Gladleux
Refinery Inc.
Ind. Farm
Bureau Coop.
Assoc. Inc.
Laketon Asphalt
Refinery Inc.
REGION
5
5
5
5
5
< 5
5
5
5
5
5
5
LOCATION
Jo! let
Wood River
Lawrencevllle
Lockport
Lemont
Plymouth
Col mar
Whiting
East Chicago
Fort Wayne
Mt. Vernon
Laketon
STATE
ILL.
ILL.
ILL.
ILL.
ILL.
ILL.
ILL.
IND.
IND.
IND.
IND.
.
. IND.
SUBCAT.
B^
D
B
B
B
A
A
D
B
A
B
A
REFINERY
CAPACITY
LQOO bbl
.. .""day
186.0
268.0
84.0
72.0
152.0
1.5
1.0
315.0
140.0
4
10.0
15.2
8.5
CRUDE
Process
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
A
D
A
V
D
A
V
D
A
V
D
A
D
A
V
D
A
V
PROCESSES
Capacity
1000 bbl
186.0
186.0
82.0
268.0
268.0
91.5
84.0
84.0
24.0
72.0
72.0
14.0
152.0
152.0
55.0
1.5
1.0
1.0
1.0
315.0
315.0
,140.0
140.0
140.0
7.0
'
' 10.0
10.0
15.2
: 15.2
6.0
8.5
8.5
5.0
CRACKING
Process
Delay.
coke
FCC
Vlsbreak.
FCC
Hydro.
Gas-Oil Cr.
Fi,C
Del ay. Coke
FCC
Del ay. Coke
FCC
Del ay. Coke
FCC
FCC
FCC
PROCESSES
Capacity
1000 bbl
day
28.0
66.0
21.0
98.0
33.5
9.0
31.0
27.0
30.0
19.5
60.0
14.5
146.0
50.0
5.8
\
V
LUBE P
Process
A
C
Q
A
B
C
E
G
N
Q
'
'
ACCESSES
Capacity
1000 bbl
day
5.6
11.2
5.6
-
2.5
1.0
3.6
19.1
2.0
0.7
12.2
ASPHALT
PRODUCTION
Capacity
1000 bbl/day
22.5
2.7
2.0
31.0
*
10.4
2.6
PROCESS
CONFIG-
URATION
5.47
7.85
5.53
6.94
5.66
1.0
3.0
8.38
. 5.68
2.0
4.68
! 6.26
-------
TABLE 51 cont'd
PETROLEUM REFINERY - PROCESS BREAKDOWN
COMPANY
Gulf Oil
Company
Gulf Oil
Company
STD. Oil
Company of Ohio
STD. Oio
Company of Ohio
Sun Oil
M
Murphy Oil
Corporation
Berry
Petroleum Co.
Cross Oil and
Refining Company
Lion Oil
Company
MacMillian Ring-
Free Oil Co.,
Inc.
Atlas Processing
Company
REGION
5
5
5
5
5
5
6
6
6
6
6
LOCATION
Cleves
Toledo
Lima
Toledo
Toledo
Superior
Stephens
A
Smackover
El Dorado
Norphlet
Shreveport
STATE
OH.
OH.
OH.
OH.
OH.
WIS.
ARK.
ARK.
ARK.
ARK.
LA.
SUBCAT.
B
B
D
B
C
B
A
A
D
A
A
REFINERY
CAPACITY
1000 bbl
day
43.5
51.0
175.0
125.0
130.0
38.0
3.5
5.0
45.0
•3
4.5
29.0
CRUDE
Process
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
ACCESSES
Capacity
1000 bbl
day
43.5
43.5
13.0
51.0
51.0
12.5
175.0
175.0
51.0 '
125.0
125.0
43.0
130.0
130.0
22.0
38.0
38.0
15.5
3.5
3.5
1.0
5.0
5.0
2.0
45.0
45.0
18.0
4.5
4.5
2.8
29.0
29.0
0.6
CRACKINC
Process
FCC
FCC
Del ay. Coke
FCC
Hydro.
Delay. Coke
FCC
Hydro.
FCC
Hydro .
FCC
,
Solvent
FCC
Therno.
PROCESSES
Capacity
1000 bbl
day
27.0
22.0
15.0
45.5
20.0
12.8
71.5
36.0
57.5
26.0
10.7
5.0
12.5
7.7
LUBE P
Process
G
M
A
unknown
ROCESSES
Capacity
1000 bbl
day
1.7
5.2
1.3
0.8
ASPHALT
PRODUCTION
Capacity
1000 bbl /day
2.9
2.0
- •
7.0
12.0
1.0
1.4
6.0
1.25 •
PROCESS
CONFIG-
URATION
6.82
*
5.30
5.56
8.79
6.02
7.89
5.71
9.14
7.58
5.96
2.02
-------
TABLE 51 COnt'd
PETROLEUM REFINERY - PROCESS BREAKDOWN
COMPANY
Gulf Oil
Company
Gulf Oil
Company
Kerr McGee
Corporation
La Jet Inc.
Murphy Oil
Corporation
Shell Oil
Company
Tenneco Oil
* Company
i
Texaco Inc.
Caribou Four
Corners Inc.
Famariss Oil
Corporation
Navajo Ref.
Company
Plateau Inc.
Shell Oil
Company
Thriftway
Company
Allied Materials
•Corporation
REGION
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
LOCATION
Belle
Chase
Venice
Cotton Valley
St. James
Meraux
Norco
Chalmette
Convent
Kirtland
Monument
Artesia
Bl cornfield
Ciniza
Bl cornfield
Stroud
STATE
LA.
LA.
LA.
LA.
LA.
LA.
LA.
LA.
N.M.
N.M.
N.M.
N.M.
N.M.
N.M.
Okla.
SUBCAT.
B
B
A
A
B
B
B
B
A
'A
B
A
B
A
A
REFINERY
CAPACITY
1000 bbl
186.0
29.1
8.0
11.0
95.4
250.0
97.0
140.0
1.4
5.0
20.93
5.2
21.0
2.13
5.8
C • " 11!
CRUDE
Process
D
A
V
D
A
D
A
D
A
D
V
D
A
V
D
A
V
D
A
V
A
A
D
A
V
A
D
A
V
A
D
A,
V
PROCESSES
Capacity
1000 bbl
day
186.0-
186.0
55.0
29.1
29.1
8.0
8.0
11.0
11.0
95.4
14!5
250.0
250.0
90.0
97.0
97.0
23.0
140.0
140.0
35.0
1.4
5.0
20.93
20.93
4.5
5.2
21.0
21.0
8.0
2.13
5.8
5.8
2.8
CRACKINC
Process
Delay. Cok.
FCC
Hydro.
FCC
Delay. Cok.
FCC
Hydro.
Delay. Cok.
FCC
Hydro .
Visbreak.
FCC
Gas-Oil Cr.
Thermo.
FCC
. PROCESSES
Capacity
1000 bbl
day
16.0
78.0
11.5
11.0
18.0
97.0
28.0
9.0
22.0
18.0
12.0
70.0
1.25
5.2
. ./I0.5
LUBE P
Process^
t
Unk.
ROCESSES
Capacity
1000 bbl
day
0.9
ASPHALT
PRODUCTION
Capacity
1000 bbl/day
. .
6.0
1.4
0.84 ••
1.21
PROCESS
CONFIG-
URATION
5.33
4.37
2.0
2.0
2.84
6.08
5.27
5.76
1.0
1.0
4.87
1.6
5.86
1.0
7.00
-------
Ul
VO
TABLE 51 cont'd
PETROLEUM REFINERY - PROCESS BREAKDOWN
COMPANY
Apco Oil
Corporation
Champlin
Petroleum Company
Continental Oil
Comapny
Kerr-McGee
Corporation
Midland Coop.
Inc.
Okc Refining
Inc.
Sun Oil
Company
Sun Oil
Company
Texaco Inc.
Tonkawa Ref.
Company
Vickers Petro.
Corporation
-
Adobe Ref.
Company
American
Petrofina Inc.
REGION
6
6
6
6
6
6
6
6
6
6
6
6
6
LOCATION
Cyril
Enid
Ponca
Wynnewood
Gushing
Okmul gee
Duncan
Tulsa
West Tulsa
Tonkawa
Ardmore
LaBlanca
Nt. Pleasant
STATE
Okla.
Okla.
Okla.
Okla.
Okla
Okla
Okla.
Okla.
Okla.
Okla.
Okla.
Tex.
Tex.
SUBCAT.
B
D '
D
B
B
B
B
D
B
4
A
B
A
B
REFINERY
CAPACITY
1000 bbl
day
12.5
52.0
120.0
34.0
19.8
21.5
50.0
90.0
50.0
6.0
4
32.0
5.0
26.0
CRUDE 1
Process
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
D
A
V
D
A
D
A
V
'ROCESSES
Capacity
1000 bbl
day
12.5
12.5
5.0
52.0
52.0
18.0
120.0
120.0
34.5 -
34.0
34.0
10.0
19.8
19.8
7.0
21.5
21.5
3.2
50.0
50.0
17.0
90.0
90.0
31.5
50.0
50.0
14.5
6.0
6.0
32.0
32.0
11.0
5.0
5.0
26.0
26.0
15.0
CRACKING
Process
FCC
Delay. Cok.
FCC
Gas-Oil Cr.
Delay. Cok.
FCC
FCC
Hydro.
Delay. Cok.
FCC
Thermo .
Delay. Cok.
FCC
Delay. Cok.
FCC
Gas -Oil Cr.
FCC
Pitch
FCC
Thermo.
PROCESSES
Capacity
1000 bbl
day
7.5
3.7
21.45
13.5
18.5
44.6
13.5
4.5
4.0
10.0
10.0
12.0
35.5
8.2
31.4
6.0
18.0
2.5
13.0
11.8
LUBE P
Process
D
E '
F
D
G
M
C
G
M
ROCESSES
Capacity
1000 bbl
day
'""
- 3.1
1.0
1.6
2.1
2.2
1.9
8.2
8.0
13.6
ASPHALT
PRODUCTION
Capacity
1000 bbl /day
1.3
1.4
3.0
3.5
1.4
4.2
5.0
8.0
PROCESS
CONFIG-
URATION
7.25
7.02
7.09
6.71
6.60
5.72
8.04
9.85
5.17
•
2.0
7.13
2.0
8.99
-------
TABLE 51 cont'd
PETROLEUM REFINERY - PROCESS BREAKDOWN
o
COMPANY
American
Petroflna Inc.
Amoco Oil
Company
Atlantic
Richfield Company
Champlin Petro.
Company
Charter Inter.
Oil Company
Coastal States
Petrochemical
Company
Cosden Oil &
Chemical Company
Crown Central
Petro. Corp.
Diamond Shamrock
Oil & Gas -Company
Eddy Ref . Company
Exxon Company,
USA
Flint Chemical
Company
Gulf Oil Company
REGION
6
6
6
6
6
6
6
6
6
6
6
6
6
LOCATION
Port
Arthur
Texas City
Houston
Corpus Christl
Houston
Corpus Christi
Big Spring
Houston
Sunray
Houston
Bay town
San Antonio
Port Arthur
STATE
Tex.
Tex.
Tex.
Tex
Tex.
.Tex.
Tex.
Tex.
Tex.
Tex.
Tex.
Tex.
Tex.
SUBCAT.
B
C
E
B
B
C
C
B
B
A
E
A
E
REFINERY
CAPACITY
1000 bbl
day
84.0
333.0
233.5
63.0
66.0
135.0
65.0
103.0
49.0
3.25
420.0
0.75
319.0
CRUDE 1
Process
D
A
V
D
A
V
D
A
V
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V ,
A
D
A
V
A
D
A
V
'ROCESSES
Capacity
1000 bbl
day
84.0
84.0
28.0
333.6
333.0
131.0
233.5
233.5
70.0
63.0
9.2
66.0
66.0
22.0
135.0
135.0
33.0
65.0
65.0
25.0
103.0
103.0
38.0
49.0
49.0
14.5
3.25
420.0
420.0
180.0
0.75
319.0
319.0
147.4
CRACKING
Process
Visbreak
FCC
Delay. Cok.
FCC
Hydro.
Delay. Cok.
FCC
Hydro.
FCC
Visbreak.
FCC
Delay. Cok.
FCC
Gas-Oil Cr.
FCC
Delay, Cok.
FCC
Gas-Oil Cr.
Thermo .
Houdri .
FCC
Hydro.
Delay. Cok.
FCC
Hydro.
PROCESSES
Capacity
1000 bbl
day
10.0
28.0
22.5
185.0
38.0
27.0
74.0
4.5
10.1
10.0
29.0
12.0
19.3
10.0
25.0
9.5
52.0
2.5
13.5
13.5
145.0
20.0
30.0
126.0
15.0
LUBE P
Process
A
C
D
G
Q
C
G
Q
A
C
D
u
ROCESSES
Capacity
1000 bbl
day
5.2
3.4
0.6
4.0
6.2 .
"
13.0
9.0
24.0
14.2
4.9
25.9
i i
ASPHALT
PRODUCTION
Capacity
1000 bbl /day
5.3
!•
4.0
0.5
8.0
• •
2.5
12.0
PROCESS
CONFIG-
URATION
5.05
*
7.01
6.09
2.11
6.61
3.63
7.09
5.95
6.52
1.0
6.55
1.0
7.56
-------
TABLE 51 cont'd
PETROLEUM REFINERY - PROCESS BREAKDOWN
COMPANY
Howel 1
Hydrocarbon
La Gloria
Oil and Gas Co.
Longview
Refining Company
Marathon Oil
Company
Mobil Oil
Corporation
Phillips
Petroleum
Company
Phillips
Petroleum Company
Pride Ref. Inc.
Quintana -
Howel 1
Shell Oil Companj
,
Shell Oil Companj
Southwestern Oil
& Ref. Company
REGION
6
6
6
6
6
6
6
6
6
6
6
6
LOCATION
San Antonio
Tyler
Longview
Texas City
Beaumont
Borger
Sweeny
Abilene
Corpus Chrlstl
Deer Park
Odessa
Corpus Christi
STATE
.'TEX.
TEX.
TEX.
TEX.
TEX.
TEX.
Tex.
Tex.
Tex.
Tex.
Tex.
Tex.
SUBCAT.
A
B
A
C
D
C
C
A
A
D
B
B
REFINERY
CAPACITY
1000 bbl
day
3.1
29.0
7.5
63.0
335.0
95.0
85.0
14.69
10.0
293.0
4
34.0
150.0
CRUDE
Process
D
*.«
D
A
A
D
A
V
D
A
V
D
A
D
A
V
D
A
D
A
0
A
V
D
•A
V
D
A
V
'ROCESSES
Capacity
1000 bbl
day
3.1
3.1
29.0
29.0
7.5
63.0
63.0
20.0
335.0
335.0
103.0
95.0
95.0
85.0
85.0
17.0
14.69
14.69
10.0
10.0
293.0
293.0
106.4
34.0
34.0
10.0
150.0
; 150.0
24.0
CRACKING
Process
Gas-Oil Cr.
Del ay. Coke
FCC
FCC
Del ay. Coke
FCC
Thermo.
Hydro.
FCC
FCC
Thermal
Gas-Oil Cr.
FCC
Hydro.
FCC
FCC
PROCESSES
Capacity
1000 bbl
day
3.0
12.0
15.0
33.0
33.0
55.0
•52.0
29.0
70.0
35.0
20.0
65.0
70.0
25.0
15.5
12.0
LUBE P
Process
D
G
M
,
A
C
G
Q
ROCESSES
Capacity
1000 bbl
day
2.5
15.7
13.2
"8.0
3.3
7.9
6.8
ASPHALT
PRODUCTION
Capacity
1000 bbl /day
0.1
-•
3.8
PROCESS
CONFIG-
URATION
2.0
8.21
1.0
5.46
6.55
6.42
4.67
2.0
2.0
7.36 '
5.03
2.64
-------
TABLE 51 cont'd
PETROLEUM REFINERY - PROCESS BREAKDOWN
COMPANY
Suntlde Refining
Company
Tesoro Petro.
Company
Texaco, Inc.
Texaco, Inc.
Texaco, Inc.
H"
cr>
ro
.Texaco, Inc.
Texas Asphalt
and Refining Co.
Texas City
Refining, Inc.
Three Rivers
Refinery
Union 011
Company of
California
Union Texas
Petro. (Allied)
Winston Refining
REGION
6
6
6
6
6
6
6
6
6
6
6
6
LOCATION
Corpus Chr1st1
CarrUo Springs
Amarlllo
El Paso
Port Arthur
Port Neches
Fort Worth
Texas City
Three Rivers
Nederland
Winnie
Fort Worth
STATE
TEX.
TEX.
TEX.
TEX.
TEX.
TEX.
TEX.'
TEX.
TEX.
TEX.
TEX.
TEX.
SUBCAT.
C
A
B
B
D
A
A
B
A
•
E
B
B
REFINERY
CAPACITY
1000 bbl
day
60.0
13.5
20.0
17.0
406.0
47.0
3.5
63.0
1.5
4
116.0
10.0
15.5
CRUDE I
Process
D
A
V
D
A
D
A
D
A
D
A
V
D
A
V
A
D
A
V
A
V
D
A
V
A
D
A
V
'ROCESSES
Capacity
1000 bbl
day
60.0
60.0
10.0
13.5
13.5
ZO.O
20.0
17.0
17.0
106.0
106.0
142.0
28.0
47.0
26.0
3.5
63.0
63.0
14.5
1.5
0.8
116.0
116.0
44.0
10.0
15.5
15.5
3.5
CRACKING
Process
Delay. Coke
FCC
Del ay. Coke
FCC
Delay. Coke
FCC
Gas-Oil Cr.
FCC
Hydro.
'
Vlsbreak.
Houdrl .
FCC
Hydro.
FCC
PROCESSES
Capacity
1000 bbl
day
7.7
26.5
4.0
8.0
4.0
7.0
51.0
135.0
15.0
5.0
23.0
40.7
3.0
6.0
LUBE P
Process
C
G
J
M
P
inknown
unknown
ROCESSES
Capacity
1000 bbl
.
4.2
17.2
0.6
21.5
3.8
0.8
3.5
ASPHALT
PRODUCTION
Capacity
1000 bbl /day
9.0
0.12
5.4
PROCESS
CONFIG-
URATION
5.59
•
2.0
5.60
. -
5.88
6.84
4.45
1.0
4.90
9.43
5.44
2.8
4.55
-------
TABLE 51 cont'd
PETROLEUM REFINERY - PROCESS BREAKDOWN
COMPANY
American
Petroflna, Inc.
Apco Oil
Corporation
CRA Inc.
CRA Inc.
Derby Ref.
Company
£
Mid America
Ref. Company Inc.
Mobil 011
Corporation
National Coop.
Ref. Assoc.
North American
Petro. Corp. •:
Phillips
Petroleum Co.
Skelly 011
Company
Amoco Oil
Gary Western
Co. (Gllsontte)
REGION
7
7
7
7
7
7
7
7
7
7
7
7
8
LOCATION
El Dorado
Arkansas City
Cof fey vllle
PhilHpsburg
Wichita
Chanute
Augusta
McPherson
Shallow
Water
Kansas City
El Dorado
Sugar Creek
Grand Junction
STATE
KAN.
KAN.
Kan.
Kan.
Kan.
Kan.
Kan.
Kan.
Kan.
KAN.
KAN.
KAN.
COLO.
SUBCAT.
B
B
D
B
B
A
B
B
•* B
E
C
B
B
REFINERY
CAPACITY
1000 bbl
25.0
26.0
36.0
21.0
27.0
3.3
52.0
57.0
5.0
85.0
75.0
4
105.0
; 8.5
CRUDE 1
Process
D
A
V
D
A
-V
D
A
V
D
A
V
D
A
V
A
V
A
V
D
A
0
A
V
D
A
V
D
A
V-
0
A
V
D
A
'ROCESSES
Capacity
1000 bbl
day
25.0
25.0
9.0
26.0
26.0
5.0
36.0
36.0
12.5
21.0
21.0
7.5
27.0 '
27.0
8.8
3.3
1.8
52.0
17.7
57.0
57.0
5.0
5.0
2.5
85.0
85.0
15.0
75.0
75.0
23.0
105.0
105..0
40.0
8.5
8.5
CRACKING
Process
FCC
FCC
Hydro.
Delay. Cok.
FCC
•
FCC
Delay. Cok.
Thermo.
Gas-Oil Cr.
Thermo.
Delay. Cok.
FCC
Thermo.
FCC
Delay. Coke
FCC
Del ay. Coke
FCC
Fluid. Coke
PROCESSES
Capacity
1000 bbl
day
11.5
12.0
2.95
8.5
14.2
7.35
3.8
12.55
4.1
23.5
i;:o
21t'o.
4.5
48.0
9.8
48.0
11.0
50.0
8.5
LUBE P
Process
G
K
M
N
C
E
Q
ROCESSES
Capacity
1000 bbl
day
1.66
0.15
2.76
0.85
5.2
6.8
2.4
ASPHALT
PRODUCTION
Capacity
1000 bbl /day
2.0
1.4
.2.0
8.0
3.0
6.5
PROCESS
CONFIG-
URATION
6.08
6.29
8.09
5.60
5.96
1.55
6.37
6.0
7.9
8.19
6.93
6.61
8.00
-------
TABLE 51 cont'd
PETROLEUM REFINERY - PROCESS BREAKDOWN
COMPANY
Continental
011 Company
The Refinery
Corporation
B1g West 011
Company
Cenex
Continental Oil
Company
Exxon' Company
USA
Jet Fuel
Refinery
Phillips Petro.
Company
Tesoro Petro.
Corporation
Westco Ref.
Company
Amoco Oil
Company
Hestland Oil
Company
Amoco Oil
Company
Arizona Fuels
Corporation
Caribou Four
Corners Inc.
REGION
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
LOCATION
Commerce City
Commerce City
'
Kevin*
Laurel
Billings
Billings
Mosby
Great Falls
Wolf Point
Cut Bank
Handan
W11 listen
Salt Lake City
Roosevelt
Woods Cross
STATE
COLO.
COLO.
*
MONT.
Mont.
Mont.
Mont.
Mont.
Mont.
Mont.
Mont.
N.D.
N.D.
Utah
Utah
Utah
SUBCAT.
B
B
B
B
B
B
A
B
A
B
B
B
B
B
B
REFINERY
CAPACITY
1000 bbl
~3ay
31.0
17.5 •
5.5
44.0
56.0
46.0
1.0
5.7
2.65
5.0
48.0
5.0 *
39.0
11.0
5.0
CRUDE
Process
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
A
• D
A
V
A
D
A
D
A
D
A
D
A
D
A
D
A
V
PROCESSES
Capacity
1000 bbl
day
26.0
31.0
7.0
17.5
17.5
3.5
5.5
5.5
0.75
44.0
44.0
15.4
38.0
C£ A
56.0
12.2
46.0
46.0
18.0
1.0
5.7
5.7
2.0
2.65
5.0
5.0
48.0
48.0
5.0
5.0
39.0
39.0
11.0
11 .0
5.0
5.0
1.0
CRACKINC
Process
FCC
Vlsbreak.
FCC •
Gas-Oil Cr.
FCC
FCC
Fluid. Cok.
• FCC
Hydro.
FCC
Gas-011 Cr.
FCC
Gas-Oil Cr.
FCC
FCC
\
Hydro.
• PROCESSES
Capacity
1000 bbl
•lay
14.5
6.0
6.5
1.2
18.0
21.0
5.2
34.0
4.9
3.0
2.2
34.0
1-1
22.0
6.0
1.0
LUBE F
Process
-
ROCESSES
Capacity
1000 bbl
day
ASPHALT
PRODUCTION
Capacity
1000 bbl /day
3.3
0.325
3.5
13.0
0.8
2.5
PROCESS
CONFIG-
URATION
6.15
6.49
4.15
4.81
4.90
11.54
1.0
7.19
1.0
4.64
6.25
3.32
6.15
i
5.27
3.4
-------
TABLE 51 cont'd
PETROLEUM REFINERY - PROCESS BREAKDOWN
COMPANY
Chevron 011
Company
Husky Oil
•Company
Phillips Petro.
Company
Amoco Oil
Company
Husky 'Oil
Company
l«i
SI Husky Oil
Company
Little America
Ref. .Company
Mountaineer. Ref.
Company Inc.*
Pasco Inc.
Sage Creek Ref.
Company
Southwestern Ref.
Company
Tesoro Petro.
Corporation
Texaco Inc.
REGION
8
8
8
8
8
8
8
8
8
8
8
8
8
LOCATION
Salt Lake
city
North Salt
Lake
Moods Cross
Casper
Cheyenne
Cody
Casper
LaBarge
Sinclair
Cowley
LaBarge
Newcastle
Casper
STATE
Utah
\
Utah
Utah
Wyn.
Wym.
Wym.
Wym.
Wym.
Wym.
Wym.
Vtfro.
Wym.
Hym.
SUBCAT.
B
B
B
0
8
B
B
A
B
A
A
B
B
REFINERY
CAPACITY
1000 bbl
45.0
12.0
23.0
43.0
24.6
11.2
23.0
O.SO
42.0
«
1.2
0.33
11.0
21.0
CRUDE 1
Process
D
A
V
D
A
V
D
A
V
A
V
0
A
V
D
A
V
D
A
V
A
D
A
V
A
A
D
A
0
A
V
'ROCESSES
Capacity
1000 bbl
day
45.0
45.0
27.0
12.0
12.0
3.8
23.0
23.0
3.0
43.0
13.5
24.6
24.6
14-0
11.2
11.2
6.5
23.0
23.0
5.8
0.5
42.0
42.0
14.2
1.2
0.33
11.0
11.0
21.0
21.0
10.0
CRACKING
Process
FCC
Houdrl .
Thermo.
Thermo
FCC
FCC
t
FCC
Thermo.
FCC
Thermo.
Press. Coke
FCC
PROCESSES
Capacity
1000 bbl
day
12.0
13.0
6.9
10.5
11.0
12.5
4.3
10.5
12.8
8.0
4.0
7.0
LUBE P
Process
F
M
N
0
ROCESSES
Capacity
1000 bbl
day
1.8
2.6
1.0
0.3
-
ASPHALT
PRODUCTION
Capacity
1000 bbl /day
2.2
1.55
3.0
4.0
2.0
2.3
1.5
PROCESS
CONFIG-
URATION
5.93
5.77
6.02
5.00
7.08
'
9.17
6.03
1.0
4.82
1.0
1.0
6.36
6.48
-------
TABLE 51 cont'd
PETROLEUM REFINERY - PROCESS BREAKDOWN
COMPANY
Atlanta, Rlchfielc
Company'
1
Beacon 011
'.Company
Exxon Company
USA
Fletcher Oil £
Ref. Company
Golden Bear
Div. (Witco)
Gulf 011 .
Company
Mobil 011 .
Corporation
Mohawk Petro.
Corporation Inc.
Newhall Ref.
Company Inc.
Phillips Petro.
Company
Power line
Oil Company
Sequoia Ref.
Company
Shell Oil
Company
Shell Oil
Company
REGION
9
9
9
9
9
9
9
9
9
9
9
9
9
9
LOCATION
Carson
Hanford
Benlcia
Carson
Oildale
Santa Fe
Springs
Torrence
Bakers-
field •
Newhall
Avon
Santa Fe
Springs
Hercules
Martinez
Wilmington
STATE
Cal.
Cal.
Cal.
Cal.
Cal.
Cal.
Cal.
Cal.
Cal.
Cal.
Cal.
Cal.
Cal.
Cal.
SUBCAT.
C
B
B
A
A
B
B
A
A
D
B
B
E
D
REFINERY
CAPACITY
1000 bbl
day
173.0
12.1
95.0
16.2
vi.o
53.8
130.0
22.8
8.0
110.0
30.0
4
28.3
103.0
101.0
CRUDE
Process
A
V
A
D
A
V
D
A
D
A
V
D
A
V
D
A
V
A
A
V
D
A
V
D
A
V
D
A
V
D
A
V
D
A
V
PROCESSES
Capacity
1000 bbl
day
173.0
93.0
12.1
95.0
95.0.
53.0
16.2
16.2
11.0
11.0
9.5
53.8
53.8
25.0
100.0
130.0
95.0
22.8
8.0
5.0
90.0
110.0
74.5
30.0
30.0
15.0
28.3
28.3
5.9
85.0
103.0
55.3
101.0
101.0
60.0
CRACKING
Process
Gas-Oil Cr.
Visbreak.
Delay. Cok.
FCC
Hydro.
Gas-Oil Cr.
Visbreak.
Fluid. Cok.
FCC
Hydro.
.
Visbreak.
FCC
Hydro.
Visbreak
Delay. Cok.
FCC
Hydro.
Fluid. Cok.
FCC
Hydro.
FCC
Hydro.
FCC
Hydro.
Delay. Cok.
FCC
PROCESSES
Capacity
1000 bbl
day
12.5
42.0
30.0
65.0
19.7
0.5
2.75
21.6
57.0
22.0
13.8
13.8
11.0
16.0
46.64
56.0
18.0
42.0
47.0
22.0
12.0
2.9
86.0
19.0
30.0
40.0
LUBE P
Proces;
Unk.
Unk.
A
M
P
C
D
E
G
N
ROCESSES
Capacity
1000 bbl
day
4.0
1.67
3.5
4.8
1.8
7.8
24.3
1.8
18.6
7.8
ASPHALT
PRODUCTION
Capacity
1000 bbl /day
3.2
4.0
3.0
5.0
10.4
PROCESS
CONFIG-
URATION
7.41
2.60
8.91
2.0
11.09
7.66
8.81
1.0
6.13
8.75
6.90
• -
2.82
10.96
14.51
-------
TABLE 51 cont'd
PETROLEUM REFINERY - PROCESS BREAKDOWN
COMPANY
STD. Oil Company
of Calif.
STD. Oil Company
of Calif.
STD. Oil Company
of Calif.
Texaco Inc.
Union Oil
Company of Calif
Union Oil Company
of Calif.
STD. Oil Company
of Calif.
STD. Oil Company
of Calif.
Atlantic Rich-
field Company
Mobil Oil
Corporation
Shell Oil
Company
REGION
9
9
9
9
9
9
9
10
10
10
10
LOCATION
Bakers-
Field
El Segundo
'
Richmond
Wilmington
Los Angeles
San Francisco
Barber's Point
Portland
Fernadale
Ferndale
Anacortes •
STATE
Cal.
Cal.
Cal.
Cal.
Cal.
Cal.
Haw.
Ore.
Wash.
Wash.
Wash.
SUBCAT.
A
C
E
B
B
D
B
A
B
B
B
REFINERY
CAPACITY
1000 bbl
day
26.0
230.0
190.0
75.0
111.0
115.0
40.0
15.0
100.0
74.5 *
94.0
CRUDE 1
Process
A
D
A
V
D
A
V
D
A
D
A
V
D
A
V
0
A
V
A
V
D
A
V
0
A
V
D
A
V
'ROCESSES
Capacity
1000 bbj
26.0
120.0
230.0
103.0
190.0
190.0
150.0
22.0
75.0
86.0
111.0
83.0
115.0
115.0
38.5
40.0
40.0
15.0
15.0
15.0
100.0
100.0
55.0
74.5
74.5
7.0
94.0
94.0
33.0
CRACKING
Process
Delay. Cok.
FCC
Hydro.
FCC
Hydro.
Delay. Cok.
• FCC
Hydro.
Visbreak.
FCC
Hydro.
Delay. Cok.
Hydro.
FCC
Delay. Cok.
Hydro.
Visbreak.
Thermo.
FCC
PROCESSES
Capacity
1000 bbl
day
54.0
54.5
49.0
54.5
67.5
48.0
28.0
20.0
20.0
52.0
21.0
42.5
30.0
23.0
29.0
35.0
7.0
27/5
53.0
LUBE P
Process
A
C
G
H
J
Q
D
E
G
H
ROCESSES
Capacity
1000 bbl
day
3.1
62.4
7.3
6.2
2.9
4.0
11.2
5.1
6.1
0.8
ASPHALT
PRODUCTION
Capacity
1000 bbl /day
1.1
8.3
n.o
10.0
6.15
•1.3
8.6
PROCESS
CONFIG-
URATION
1.51
•
6.51
13.21
8.97
8.63
9.34
6.19
8.88
6.39
4.87
5.73
-------
TABLE 51 cont'd
PETROLEUM REFINERY - PROCESS BREAKDOWN
COMPANY
Sound Ref. Inc.
STD. Oil Company
of Calif.
Texaco Inc.
U.S. Oil & Ref.
Company
STD. Oil Company
of Calif.
Tesoro-Alaskan
Petro. Corp.
M
CO
REGION
10
10
10
10
10
10
LOCATION
Tacoma
Richmond
Beach
Anacortes
Tacoma
Kenal
Kenal
STATE
Wash.
Wash.
Wash.
Wash.
Alka.
Alka.
SUBCAT.
A
A
B '
A
A
A
REFINERY
CAPACITY
1000 bbl
day
4.7
. 5.0
63.0
16.0
22.0
39.5
«
4
CRUDE I
Process
D
A
V
A
V
D
A
V
D
A
V
D
A
0
A
'ROCESSES
Capacity
1000 bbl
day
4.7
4.7
4.5
5.0
5.0
63.0
63.0
22.5
16.0
16.0
3.2
22.0
22.0
39.5 '
39.5
CRACKING
Process
FCC
-
PROCESSES
Capacity
1000 bbl
25.0
LUBE P
Process
Unk.
ROCESSES
Capacity
1000 bbl
d.ay
1.9
-
*"
,.
ASPHALT
PRODUCTION
Capacity
1000 bbl /day
2.6
4.0
3.0
0.3
PROCESS
CONFIG-
URATION
14.85
11.6
4.74
4.45
2.16
2.0
-------
SECTION X
BEST AVAILABLE TECHNOLOGY ECONOMICALLY
ACHIEVABLE — EFFLUENT LIMITATIONS
The application of best available technology economically
achievable is being defined as further reductions of water flows
in-plant and the addition of a physical - chemical treatment step
(activated carbon), end-of-pipe. The limitations, which set
numerical values for the allowable pollutant discharges within
each subcategory for BATEA are presented in Tables 1-6. Although
there are specific systems which can effectively reduce the water
usage from a particular process to nearly zero, these "zero
discharge" systems cannot be uniformly applied throughout the
refinery to develop "zero discharge" criteria for the entire
refinery.
BATEA in-plant technology is based on control practices now
practiced by some plants in the petroleum refining industry, and
include the following:
(1) Use of air cooling equipment.
(2) Reuse of sour water stripper bottoms in crude desalters.
(3) Reuse of once-through cooling water as make-up to the
water treatment plant.
(4) Using waste water treatment plant effluent as cooling water,
scrubber water, and influent to the water treatment plant.
(5) Reuse of boiler condensate as boiler feedwater.
(6) Recycle of water from coking operations.
(7) Recycle of waste acids from alkylation units.
(8) Recycle of overhead water in water washes.
(9) Reuse overhead accumulator water in desalters.
(10)Use of closed compressor and pump cooling
water system.
(11)Reuse of heated water from the vacuum overhead condensers
to heat the crude. This reduces the amount of cooling water
needed.
(12)Use of rain runoff as cooling tower make-up or
water treatment plant feed.
(13)Other methods.
Flow
Flow reductions proposed for BATEA effluent limitations were
derived from further analysis of the 1972 National Petroleum
Waste Water Characterization Studies. The flows from refineries
in each subcategory meeting the BPCTCA flow basis were averaged
to determine the flow basis for establishment of BATEA effluent
limitations. That these average flows are achievable within the
petroleum refining industry is readily demonstrable, by
determining the number and geographical distribution of
refineries in the United States currently at, or lower than, the
proposed BATEA flows. There are 3 to 5 refineries in each of the
five subcategories which have flows less than or equal to the
169
-------
proposed BATEA effluent limitations. These refineries range in
size from 827,000 to 69,000,000 cubic meters per stream day
(5,200 to 434,000 barrels per stream day) , and range in cracking
capacity from 0 to 106 percent. The geographical distribution of
these refineries indicates that good water practices, and
consequently low waste water flows, are not confined to water -
short areas or cool climates, but are located throughout the
United States. Within this group of refineries with low-water
usage, there are refineries located in both high rainfall and dry
areas (Washington and New Mexico) and areas of extreme
temperatures (New Mexico and Texas to Alaska and Minnesota).
Consequently, these flows, shown in Table 52, were used as the
basis for establishment of BATEA effluent limitations. The
objective of this basis for flow is to provide inducement for in-
plant reduction of both flow and contaminant loadings prior to
end-of-pipe treatment. However, it is not the intent of these
effluent limitations to specify either the unit waste water flow
which must be achieved or the waste water treatment practices
which must be employed at the individual petroleum refinery.
The end-of-pipe system proposed for BATEA technology is based on
the addition of activated carbon adsorption in fixed bed columns,
to the treatment system proposed as BPCTCA technology.
Procedure for Development of BATEA Effluent Limitations
The effluent limitations proposed for BATEA technology are based
on refinery pilot plant data, which indicate the percentage
reductions achievable or concentrations achievable for effluents
from activated carbon adsorption systems. These data are
presented in Table 53.
These concentrations were then used in conjunction with the BATEA
flows from Table 53 or the percentage reductions were applied to
the BPCTCA effluent limit. The daily annual average effluent
limitations determined are contained in Table 54.
Since these effluent limitations are based upon pilot plant data,
which have not been fully demonstrated in full-scale
installations as actual performance data becomes available, the
effluent limitations presented in Tables 1-6 may require
revision.
Variability Allowance for Treatment Plant Performance
The effluent limitations presented in Tables 1-6 have taken into
consideration the variability factors, as in BPCTCA. Since there
is not enough performance data from physical - chemical treatment
systems available at this time to determine variability, the
ratios established for BPCTCA at the 98% confidence level have
been used. (See Table 55).
170
-------
Subcategory
Topping
Cracking
Petrochemical
Lube
Integrated
TABLE 52
FLOW BASIS FOR DEVELOPING
BATEA EFFLUENT LIMITATIONS
Flow, per unit throughout
M3/M3 Gallons/BBL
0.255
0.33
0.46
0.73
0.88
10.5
14
19
30.5
36.5
171
-------
TABLE 53
BATEA REDUCTIONS IN POLLUTANT LOADS ACHIEVABLE BY
APPLICATION OF ACTIVATED CARBON TO
MEDIA FILTRATION EFFLUENT BPCTCA
Parameter
Type of Data
Achievable
Refinery Effluent
BOD
COD
TOC
TSS
Of!
Phenols
Ammonia
Sulftdes
Pilot Plant
Pilot Plant
Pilot Plant
Pilot Plant
Pilot Plant
Pilot Plant
Pilot Plant
No data
mg/L
5
-
15
5
1-1.7
0.02
-
_
% Reduction
-
75
-
-
80
99
60
-
References
21,27,31A,U8,62A
21,27,31AfU7,53,62A
17,31A,U8,62A
31A>8,53,62A
31A,1*8,62A
31A,lt8,62A
27,31A,62A
-------
TABLE 54
BATEA
Annual Average Daily Kilograms of Pollutants/1000 Cubic Meters of Feedstock (1) Per Stream Day
(Annual Average Daily Pounds of Pollutants/1000 BBL of Feedstock Per Stream Day)
Refinery
Subcategory
BODS
COD
1.2(0.44) 5.0(1.75)
1.6(0.58) 9.6(3.4)
2.2(0.79) 10.8(3.8)
3.7(1.3) 20.0(6.9)
4.2(1.5) 23.7(8.4)
TOC
3.7(1.3)
5.0(1.75)
6.8(2.4)
10.8(3.8)
13.0(4.6)
Total
Suspended
Solids
1.2(0.44)
1.6(0.58)
2.2(0.79)
•3.7(1.3)
4.2(1.5)
Oil &
Grease
0.25(0.088)
0.34(0.12)
0.45(0.16)
0.71(0.25)
0.85(0.30)
Phenolic
Compounds
0.0051(0.0018)
0.0065(0.0023)
0.0091(0.0032)
0.014 (0.0051)
0.017 (0.0061)
Ammonia(N]
0.34(0,12;
2.3 (0.8)
2.8 (1.0)
2.8 (1.0)
2.8 (1.0)
Total
Chromium
Hexavalent
Chromi urn
0.34(0,12) 0.025(0.0087) 0.062(0.022) 0.0012(0.00044)
2.3 (0.8) 0.034(0.012) 0.082(0.029) 0.0016(0.00058)
0.045(0.016) 0.11 (0.040) 0.0022(0.00079)
0.071(0.025) 0.18 (0.063) 0.0037(0.0013)
0.085(0.030) 0.22(0.076) 0.0042(0.0015)
Topping
^jCracking
Petrochemical
Lube
Integrated
Runoff(Z) 0.0050(0.042) 0.014(0.12) 0.016(0.13) 0.0050(0.042) 0.0010(0.009)
Ballast (3) 0.0050(0.042) 0.019(0.16) 0.016(0.13) 0.0050(0.042) 0.0010(0.009)
(1) " Feedstock - Crude oil and/or natural gas liquids.
(2) The additional allocation being allowed for contaminated storm runoff flow, kg/1000 (lb/1000 gallons), shall be based solely on that storm
flow which passes through the treatment system. All additional storm runoff, that has been segregated from the main waste stream, shall not
exceed a TOC concentration.of 35 mg/1 or Oil & Grease concentration of 15 mg/1 when discharged.
(3) This is an additional allocation, based on ballast water intake - kilograms per 1000 liters (pounds per 1000 gallons). »
-------
TABLE 55
VARIABILITY FACTORS BASED ON PROPERLY DESIGNED
AND OPERATED WASTE TREATMENT FACILITIES-BATEA
BOD,. COD TOG TSS 0 & G Phenol Ammonia Sulfide CrT Cr6
Daily
Variability 2.1 2.0 1.6 2.0 2.0 2.4 2.0 2.2 2.0 2.2
30-day
Variability 1.7 1.6 1.3 1.7 1.6 1.7 1.5 1.4 1.7 1.4
-------
SECTION XI
NEW SOURCE PERFORMANCE STANDARDS
Recommended effluent limitations for new source performance
standards are based upon the application of BPCTCA control
technology to the waste water flows used as the basis for BATEA
effluent limitations. The proposed BADT effluent limitations are
shown in Tables 1-6.
The refining technology available today does not call for major
innovations in refining processes. Basically, BADT refining
technology consists of tiae same fundamental processes which are
already in practice, with few modifications and additions.
However, a major design criterion for new refinery capacity is
reuse/ recycle of water streams to the greatest extent possible,
in order to minimize discharges to waste water treatment
facilities. Consequently, the water flow on which new source
performance standards were based is identical to the best
available technology economically achievable flow, which reflects
the best water usage as demonstrated in the petroleum refining
industry. These flows are shown in Table 52.
It should be clearly understood that no recommendations have been
made, nor are any implied, regarding the substitution of
processes which produce a lower raw waste load for others with
higher raw waste load.
This is based on the consideration that the choice of a
particular commercial route is governed largely by the
availability of feedstocks and on the conditions in the product
markets. Companies produce a given mix of products based on
their particular marketing and feedstock position within the
industry. The substitution of a cleaner process may be possible
for new producers from a technical point of view, but completely
impossible based on limited availability of the required alterna-
tive feedstocks or on the lack of viable markets for new .co-
products.
The waste water treatment technology recommended for BADT
effluent limitations is the same as called for by BPCTCA and does
not include physical - chemical treatment, because that
technology has not been sufficiently demonstrated by the
petroleum refining industry.
Procedure for Development of BADT Effluent Limitations
The effluent limitations proposed for BADT technology are based
on the concentrations considered achievable by BPCTCA and the
flows from BATEA. The daily annual average effluent limitations
thus determined are contained in Table 56.
175
-------
TABLE. 56
BADT
Refinery,
Subcategory
Topping
Cracking
^Petrochemical
-------
Variability Allowance for Treatment Plant Performance
The guideline numbers presented in Tables 1-6 have taken into
consideration the variability factors, as in BPCTCA. Since the
treatment technology and process technology for BADT are the same
as BPCTCA, the ratios established for BPCTCA have been used in
BADT.
177
-------
TABLE 57
METRIC UNITS
CONVERSION TABLE
MULTIPLY (ENGLISH UNITS)
ENGLISH UNIT ABBREVIATION
acre
acre - feet
British Thermal
Unit
British Thermal
Unit/pound
cubic feet/minute
cubic feet/second „
cubic feet
cubic feet
cubic inches
degree Fahrenheit
feet
gallon'
gallon/minute
horsepower
inches
inches of mercury
pounds
million gallons/day
mile
pound/square
inch (gauge)
square feet
square inches
tons (short)
yard
* Actual conversion, not a multiplier
by TO OBTAIN (METRIC UNITS)
CONVERSION ABBREVIATION METRIC UNIT
hectares
cubic meters
kilogram - calories
kilogram calories/kilogram
cubic meters/minute
cubic meters/minute
cubic meters
liters
cubic centimeters
degree Centigrade
meters
liters
liters/second
killowatts
centimeters
atmospheres
kilograms
cubic meters/day
kilometer
atmospheres (absolute)
square meters
square centimeters
metric tons (1000 kilograms)
meters
ac
ac ft
BTU
BTU/lb
cfm
cfs
cu ft
cu ft
cu in
F°
ft
gal
gpm
hp
in
in Hg
Ib
mgd
mi
psig
sq ft
sq in
t
y
0.405
1233.5
0.252
0.555
0.028
1.7
0.028
28.32
16.39
0.555(°F-32)*
0.3048
3.785
0.0631
0.7457
2.54
0.03342
0.454
3,785
1.609
(0.06805 psig +1)*
0.0929
6.452
0.907
0.9144
ha
cu m
kg cal
kg cal/kg
cu m/min
cu m/min
cu m
1
cu cm
°C
m
1
I/sec
kw
cm
atm
kg
cu m/day
km
atm
sq m
sq cm
kkg
m
178
-------
SECTION XII
ACKNOWLEDGEMENT
The preparation of the initial draft report was accomplished
through a contract with Roy F. Weston, Inc., under the direction
of Clem Vath, Project Director. The following individuals of the
staff of Roy F. Weston, Inc. made significant contributions to
this effort:
David Baker, Project Manager
Michael Smith, Project Engineer
M. Jotwani, Project Engineer
Martin Halper, Project Officer and David L. Becker, Chemical
Engineer, Effluent Guidelines Division, contributed to the
overall supervision of this study, preparation of the draft
report and preparation of this Development Document. Allen
Cywin, Director, Effluent Guidelines Division, Ernst P. Hall,
Deputy Director, Effluent Guidelines Division and Walter J.
Hunt, Chief, Effluent Guidelines Development Branch, offered
guidance and suggestions during this program.
Special appreciation is given to Charles Cook and Gary Liberson.
Water Program Operations, for their contributions to this effort.
The members of the working group/steering committee who
coordinated the internal EPA review are:
Allen Cywin, Effluent Guidelines Division
Walter J. Hunt, Effluent Guidelines Division
David Becker, Effluent Guidelines Division
Martin Halper, Effluent Guidelines Division
Leon Myers, Office of Research and Monitoring, (Ada)
William Bye, Region VIII
Robert Twitchell, Region III
Wayne Smith, National Field Investigation Center, (Denver)
Thomas Belk, Office of Permit Programs
John Savage, Office of Planning and Evaluation
Alan Eckert, Office of General Counsel
Phillip Bobel, Region IX
Benigna Carroll, Office of Hazardous Materials Control
Ned Burleson, Region VI
Srini Vasan, Region V
Acknowledgement and appreciation is also given to the secretarial
staff of both the Effluent Guidelines Division and Roy F. Weston,
Inc., for their effort in the typing of the drafts and necessary
revisions, and the final preparation of the effluent guidelines
document. The following individuals are acknowledged for their
contributions:
Kit Krickenberger, Effluent Guidelines Division
Kay Starr, Effluent Guidelines Division
Brenda Holmone, Effluent Guidelines Division
179
-------
Chris Miller, Effluent Guidelines Division
Sharon Ashe, Effluent Guidelines Division
Susan Gillmann, Roy F. Weston, Inc.
Judith Cohen, Roy F. Weston, Inc.
Appreciation is extended to staff members of EPA's Regions II,
III, V, VI, IX, and X offices and the Robert S. Kerr Laboratory
for their assistance and cooperation.
Appreciation is extended to the following State organizations for
assistance and cooperation given to this program.
California, State Water Resources Control Board
Illinois, Environmental Protection Agency
Michigan, Water Resources Commission
Texas, Water Control Board
Virginia, State Water Control Board
Washington, Department of Ecology
Appreciation is extended to the following trade associations and
corporations for their assistance and cooperation given to this
program.
American Petroleum Institute
Amerada Hess Corporation
American Oil Company
Ashland Oil Inc.
Atlantic Richfield Company
Beacon Oil Company
BP Oil Corporation
Champlin Petroleum Company
Coastal States Petrochemical Company
Commonwealth Oil & Refining company. Inc.
Exxon, USA
Gulf Oil Company
Kerr - McGee Corporation
Laketon Asphalt Refining, Inc.
Leonard Inc.
Lion Oil Company
Marathon Oil Company
OKC Refining Inc.
Phillips Petroleum Company
Shell Oil Company
Sun Oil Company of Pennsylvania
Texaco Inc.
Union Oil Company of California
United Refining Company
U.S. Oil and Refining Company
180
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SECTION XIII
BIBLIOGRAPHY
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Load Survey," December, 1972.
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181
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14. "Chevron Waste Water Treating Process," Chevron Eesearch
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15. Cohen, J. M., "Demineralization of Waste waters," Advanced
Waste Treatment and Water Reuse Symposium, Volume 2, February
23-24, 1971.
16. Conser, R. E., "The Environmental Fuels Processing Facility,"
SNG Symposium, Institute of Gas Technology, Chicago,
Illinois, March 12-16, 1973.
17. Gulp, R. L., and Gulp, G. L., Advanced Waste water Treatment,
Van Nostrand Reinhold Company, New York, 1971.
18. Davis, R. W., Biehl, V. A., and Smith, R. M., "Pollution
Control and Waste Treatment at an Inland Refinery," 19th
Purdue Industrial Waste Conference, pp. 128-138, 1964.
19. Daniels, E. K., Latz, J. R., Castler, L. A., "Pollution
Control at Ferndale, Washington," 23rd Midyear Meeting of the
American Petroleum Institute's Division of Refining, May,
1958.
20. Denbo, R. T., and Gowdy, F. W., "Baton Rouge Waste Water
Control Program Nears End," The Oil and Gas Journal, pp. 62-
65, May 29, 1972.
21. Diehl, D. S., Denbo, R. T., Bhatta, M. N., and Sitman, W. D.,
"Effluent Quality Control at a Large Refinery," Journal of
the Water Pollution Control Federation, 43 (11), November,
1971.
22. Dorris, T. C., Patterson, D., Copeland, B. J., "Oil Refinery
Effluent Treatment in Ponds," 35th Meeting of the Water
Pollution Control Federation, pp. 932-939, # October 7-11,
1962.
23. Easthagen, J. H., Skrylov, V., and Purvis, A. L. ,
•Development of Refinery Waste water control at Pascagowle,
Mississippi," Journal of Water Pollution Control Federation,
37 (12): 1621-1628, December, 1965.
24. Elkin, H. F., "Activated Sludge Process Application to
Refinery Effluent Waters," Journal of Water Pollution Control
Federation, 28 (9): 1122-1129, September, 1956.
25. Fair, G. M., Geyer, J. C., and Okum, D. A., Water and Waste
water Engineering, Volume 2, John Wiley & Sons, Inc., New
York, 1968.
26. Fluid Bed Incineration of Petroleum Refinery Wastes for the
Environmental Protection Agency, Washington, D.C., March,
1971. 12050KET
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27. Ford, D. L., and Buercklin, M. A., "The Interrelationship of
Biological-Carbon Adsorption Systems for the Treatment of
Refinery and Petrochemical Waste waters," 6th International
Water Pollution Research Conference, Session 11, Hall C, June
18-23, 1972.
28. Fosberg, T. M., "Industrial Waste Water Reclamation," 7Uth
National Meeting American Institute of Chemical Engineers,
March 11-15, 1973.
29. Franzen, A. E. , Skogan, V. G., and Grutsch, J. F.,
"Successful Tertiary Treatment at American," The Oil and Gas
Journal, April 3, 1972.
30. Gillian, A. S., and Anderegg, F. C., "Biological Disposal of
Refinery Wastes," 14th Purdue Industrial Waste Conference,
pp. 145-154, 1959.
31. Gloyna, E. G., Brady, S. O., and Lyles, H., "Use of Aerated
Lagoons and Ponds in Refinery and Chemical Waste Treatment,"
41st Conference of the Water Pollution Control Federation,
September 22-27, 1968.
31a. Hale, J.H., and Myers, L.H., "The Agencies Removed by Carbon
Treatment of Refinery Waste waters".
32. Hart, J. A., "Air Flotation Treatment and Reuse of Refinery
Waste water," 25th Annual Purdue Industrial Waste Conference,
May, 1970.
33. Hart, J. A., "On Improving Waste water Quality," Water and
Sewage Works, IW 20-26, September-October, 1970.
34. Hentschel, M. L., and Cox, T. L., "Effluent Water Treating at
Charter International Oil Company's Houston Refinery," 74th
National Meeting American Institute of Chemical Engineers,
March, 1973.
35. Horne, W. R., and Hurse, J. E., "Biological Reduction of
Phenolic Type Industrial Wastes," Southern Engineering,
January, 1965.
35a. Ingols, R.S., "The Toxicity of Chromium," $ percentSth
Purdue Industrial Waste Conference,$ percent pp. 86-95, 1953.
36. Kaup, E. C., "Design Factors in Reverse Osmosis," Chemical
Engineering, April 2, 1973.
37. Klett, Robert J., "Treat Sour Water for Profit," Hydrocarbon
Processing, October, 1972.
38. Klipple, R. W., "Pollution Control Built into Guayama
Petrochemical Complex," Water and Sewage works, 116 (3): IW
2-6, March, 1969.
183
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39. Lankin, J. C., and Sord, L. V. , "American Oil Cleans up
Wastes in Aerated Lagoons," Hydrocarbon Processing &
Petroleum Refiner, 43 (5): 133-136, May, 1964.
40. "Major Oil Fields Around the World," International Petroleum
Encyclopedia, 1967, Petroleum Publishing Co., Tulsa,
Oklahoma.
41. Mohler, E. F. Jr., Clere, L. T., "Development of Extensive
Water Reuse and Bio-oxidation in a Large Oil Refinery,"
National Conference on Complete Water Reuse, April, 1973.
42. McKinney, R. E., "Biological Treatment Systems for Refinery
Wastes," 39th Annual Conference of the Water Pollution
Control Federation, pp. 346-359, September 24-30, 1966.
43. McKinney, G. M., Ferrero, E. P., and Wenger, W. J., "Analysis
of Crude Oils from 546 Important Oil Fields in the United
States," Report of Investigations 6819, United States
Department of the Interior.
44. McPhee, W. T., and Smith, A. R., "From Refinery Waste to Pure
Water," 16th Purdue Industrial Wastes Conference, pp. 440-
448, May, 1961.
45. McWilliams, F. G., and Schuller, R. P., "SNG, Naptha and Low-
Sulfur Fuel Oils from Crude Oils Using Commercially Proven
Technology," American Institute of Chemical Engineers, New
York, November 26-December 2, 1972.
46. Patterson, J. W., and Minear, R. A., Waste water Treatment
Technology, for state of Illinois Institute for Environmental
Quality, 2nd, January, 1973.
47. "P. C. Treatment Gets Industrial Trial," Environmental
Science and Technology, Vol. 7, No. 3, March, 1973, pp. 200-
202.
48. Peoples, R. F., Krishnan, P., and Simonsery, R. N.,
"Nonbiological Treatment of Refinery Waste water," Journal of
the Water Pollution Control Federation, 44 (11): 2120-2128,
November, 1972.
48a. "Petroleum Refining Effluent Guidelines", for the
Environmental Protection Agency, Office of Water Programs.
49. "Petroleum Refining Industry Waste water Profile" for the
Federal Water Pollution Control Association.
50. Porges, R., "Industrial Waste Stabilization Ponds in the
United States," Journal of the Water Pollution Control
Federation, 35 (4): 456-468, April, 1963.
51. Prather, B. V., "Effects of Aeration on Refinery Waste Water
Effluents," Western Petroleum Refiners Association
184
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Proceedings of the Waste Disposal and Stream Pollution
Conference, October 7-8, 1959.
52. "Pretreatment of Discharges to Publicly Owned Treatment
Works," Federal Guidelines, E.P.A., 1973.
53. Process Design Manual for Carbon Adsorption, Environmental
Protection Agency, Washington, D.C., October, 1971.
54. Process Design Manual for Suspended Solids Removal,
Environmental Protection Agency, Washington, D.C., 1971.
55. Purcell, W. L., and Miller, R. B., "Waste Treatment of Skelly
Oil Company's El Dorado, Kansas Refinery," 16th Purdue
Industrial Waste Conference, pp. 292-303, 1961.
56. Rambow, C. A., "Industrial Waste water Reclamation," 23rd
Purdue Industrial Waste Conference, pp. 1-9, May, 1968.
57. Reid, G. W., and Streebin, L. E., "Evaluation of Waste Waters
from Petroleum and Coal Processing," Prepared for Office of
Reserach and Monitoring U.S. Environmental Protection Agency,
Washington, D.C., (Contract no. EPA-R2-72-001. December,
1972).
58. Rodriguez, D. G., "Sour Water Strippers," 74th National
Meeting American Institute of Chemical Engineers, March 11-
15, 1973.
59. Rose, B. A., "Water Conservation Reduces Load on Sohio's
Waste Treatment Plant," Water and Sewage Works, 116 (9): IW
4-8, September, 1969.
60. Rose, W. L., and Gorringe, G. E., "Activated Sludge Plant
Handles Loading Variations," The Oil and Gas Journal, pp. 62-
65, October, 1972.
61. Sebald, J. F., "A Survey of Evaporative and Non-Evaporative
Cooling Systems," 74th National Meeting American Institute of
Chemical Engineers, March 11-15, 1973.
62. Selvidge, C. W., Conway, J. E., and Jensen, R. H., "Deep
Desulfurization of Atmospheric Reduced Crudes by RCD Isomax,"
Japan Petroleum Institute Meeting, Tokyo, Japan, November 29,
1972.
62a. Short, E., and Myers, L.H., "Pilot-Plant Activated Carbon
Treatment of Petroleum Refinery Waste water".
63. Skamser, Robert 0., "The U.S. Refining Outlook to 1980," 74th
National Meeting American Institute of Chemical Engineers,
March 11-15, 1973.
185
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64. Solid Waste Disposal Study, Technical Report Genesee County,
Michigan, U.S. Department of Health, Education and Welfare,
Bureau of Solid Waste Management, Cincinnati, 1969.
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Office of the President, Bureau of the Budget.
66. Standard Methods for Examination of Water and Waste water,
American Public Health Association, American Waterworks
Association, Water Pollution Control Federation, 13th
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67. Stern, Arthur C., Air Pollution, Vol. Ill, Academic Press
Inc., 1968.
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Municipal Waste water Treatment Facilities, February 29 and
March 1-2, 1972.
69. Strong, E. R., and Hatfield, R., "Treatment of Petrochemical
Wastes by Superactivated Sludge Process," Industrial and
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Division of Refining, 37th Midyear Meeting, New York, May 8-
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186
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SECTION XIV
GLOSSARY AND ABBREVIATIONS
Glossary
Acid Oil
Straight chain and cyclic hydrocarbon with carboxyl group(s)
attached.
Act
The Federal Water Pollution Act Amendments of 1972.
Aerobic
In the presence of oxygen.
Alkylates
Branched paraffin hydrocarbons.
Anaerobic
Living or active in absence of free oxygen.
Aquatic Life
All living forms in natural waters, including plants, fish,
shellfish, and lower forms of animal life.
Aromatics
Hydrogen compounds involving a 6-carbon, benzene ring structure.
Best Available Technology Economically Achievable (BATEA)
Treatment required by July 1, 1983 for industrial discharge to
surface waters as defined by section 310 (b) (2) (A) of the Act.
Best Practicable Control Technology Currently Achievable (BPCTCA)
Treatment required by July 1, 1977 for industrial discharge to
surface waters as defined by section 301 (b) (1) (A) of the Act.
Best Available Demonstrated Technology (BADT)
Treatment required for new sources as defined by section 306 of
the Act.
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Biochemical Oxygen Demand
Oxygen used by bacteria in consuming a waste substance.
Slowdown
A discharge from a system, designed to prevent a buildup of some
material, as in boiler and cooling tower to control dissolved
solids.
Butadiene
Synthetic hydrocarbon having two unsaturated carbon bonds.
By-Product
Material which, if recovered, would accrue some economic benefit,
but not necessarily enough to cover the cost of recovery.
Capital Costs
Financial charges which are computed as the cost of capital times
the capital expenditures for pollution control. The cost of
capital is based upon a weighted average of the separate costs of
debt and equity.
Catalyst
A substance which can change the rate of a chemical reaction, but
which is not itself involved in the reaction.
Category and Subcategory
Divisions of a particular industry which processed different
traits which affect water quality and treatability.
Chemical Oxygen Demand
Oxygen consumed through chemical oxidation of a waste.
Clarification
The process of removing undissolved materials from a liquid.
Specifically, removal of solids either by settling or filtration.
Coke Petroleum
Solid residue of 90 to 95 percent fixed carbon.
Cycles of Concentration
The ratio of the dissolved solids concentration of the
recirculating water to make-up water.
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Depletion or Loss
The volume of water which is evaporated, embodied in product, or
otherwise disposed of in such a way that it is no longer
available for reuse in the plant or available for reuse by others
outside the plant.
Depreciation
The cost reflecting the deterioration of a capital asset over its
useful life.
Direct-Fired Heater
A heater in which heat is supplied by combustion, as
distinguished from a heat exchanger where heat is supplied by a
hot liquid or gas.
Emulsion
A liquid system in which one liquid is finely dispersed in
another liquid in such a manner that the two will not separate
through the action of gravity alone.
End-of-Pipe Treatment
Treatment of overall refinery wastes, as distinguished from
treatment at individual processing units.
Filtration
Removal of solid particles or liquids from other liquids or gas
streams by passing the liquid or gas stream through a filter
media.
Fractionator
A generally cylindrical tower in which a mixture of liquid
components is vaporized and the components separated by carefully
varying the temperature and sometimes pressure along the length
of the tower.
Gasoline
A mixture of hydrocarbon compounds with a boiling range between
100o and UOOo F.
Grease
A solid or semi-solid composition made up of animal fats, alkali,
water, oil and various additives.
Hydrocarbon
A compound consisting of carbon and hydrogen.
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Hydrogenation
The contacting of unsaturated or impure hydrocarbons with
hydrogen gas at controlled temperatures and pressures for the
purpose of obtaining saturated hydrocarbons and/or removing
various impurities such as sulfur and nitrogen.
Industrial Waste
All wastes streams within a plant. Included are contact and non-
contact waters. Not included are wastes typically considered to
be sanitary wastes.
Investment Costs
The capital expenditures required to bring the treatment or
control technology into operation. These include the traditional
expenditures such as design; purchase of land and materials; site
preparation; construction and installation; etc., plus any
additional expenses required to bring the technology into
operation including expenditures to establish related necessary
solid waste disposal.
Isomer
A chemical compound that has the same number, and kinds of atoms
as another compound, but a different structural arrangement of
the atoms.
Mercaptan
An organic compound containing hydrogen, carbon, and sulfur
(RSH) .
Microcrystalline Wax
A non-crystalline solid hydrogen with a melting point of about
106o to 195o F. Also known as petrolatum.
Motor Octane Number
An expression of the antiknock value of gasoline.
Naphtha
A petroleum fraction, including parts of the boiling range of
gasoline and kerosene, from which solvents are obtained.
Naphthenic Acids
Partially oxidized naphthalenes.
New source
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Any building, structure, facility, or installation from which
there is or may be a discharge of pollutants and whose
construction is commenced after the publication of the proposed
regulations.
No Discharge of Pollutants
No net increase (or detectable gross concentration if the
situation dictates) of any parameter designated as a pollutant to
the accuracy that can be determined from the designated
analytical method.
Octane
The numerical rating of a gasoline's resistance to engine knock.
Olefins
Unsaturated straight-chain hydrocarbon compounds seldom present
in crude oil, but frequently in cracking processes.
Operation and Maintenance
Costs required to operate and maintain pollution abatement
equipment. They include labor, material, insurance, taxes, solid
waste disposal, etc.
Overhead Accumulator
A tank in which the condensed vapors from the tops of the
fractionators, steam strippers, or stabilizers are collected.
Paraffin Wax
A crystalline solid hydrocarbon with a melting point of 105o to
155o F.
Petroleum
A complex liquid mixture of hydrocarbons and small quantities of
nitrogen, sulfur, and oxygen.
PH
A measure of the relative acidity or alkalinity of water. A pH
of 7.0 indicates a neutral condition. A greater pH indicates
alkalinity and a lower pH indicates acidity. A one unit change
in pH indicates 10 fold change in acidity and alkalinity.
Phenol
Class of cyclic organic derivatives with basic formula C6HOH.
Pretreatment
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Treatment proved prior to discharge to a publicly owned treatment
works.
Process Effluent or Discharge
The volume of water emerging from a particular use in the plant.
Plant Effluent or Discharge After Treatment
The volume of waste water discharge from the industrial plant.
In this definition, any waste treatment device is considered part
of the industrial plant.
Raffinate
The portion of the oil which remains undissolved and is not
removed by solvent extraction.
Raw
Untreated or unprocessed.
Reduced Crude
The thick, dark, high-boiling residue remaining after crude oil
has undergone atmospheric and/or vacuum fractionation.
Secondary Treatment
Biological treatment provided beyond primary clarification.
Sludge
The settled solids from a thickener or clarifier. Generally,
almost any flocculated settled mass.
Sour
Denotes the presence of sulfur compounds, such as sulfides and
mercaptans, that cause bad odors.
Spent Caustic
Aqueous solution of sodium hydroxide that has been used to remove
sulfides, mercaptans, and organic acids from petroleum fractions.
Stabilizer
A type of fractionator used to remove dissolved gaseous
hydrocarbons from liquid hydrocarbon products.
Standard Raw Waste Loads (SRWL)
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Net pollution loading produced per unit of production (or raw
material) by a refining process after separation of the
separables (STS).
Stripper
A unit in which certain components are removed from a liquid
hydrocarbon mixture by passing a gas, usually steam, through the
mixture.
Supernatant
The layer floating above the surface of a layer of solids.
Surface Waters
Navigable waters. The waters of the United States, including the
territorial seas.
Sweet
Denotes the absence of odor-causing sulfur compounds, such as
sulfides and mercaptans.
Topping Plant
A refinery whose processing is largely confined to oil into raw
products by simple atmospheric distillation.
Total Suspended Solids (TSS)
Any solids found in waste water or in the stream which in most
cases can be removed by filtration. The origin of suspended
matter may be man-made wastes or natural sources such as silt
from erosion.
Waste Discharged
The amount (usually expressed as weight) of some residual
substance which is suspected or dissolved in the plant effluent
after treatment if any.
Waste Generated
The amount (usually expressed as weight) of some residual
substance generated by a plant process or the plant as whole and
which is suspended or dissolved in water. This quantity is
measured before treatment.
Waste Loading
Total amount of pollutant substance, generally expressed as
pounds per day.
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Abbreviations
AL - Aerated Lagoon
AS - Activated Sludge
API - American Petroleum Institute
BADT - Best Available Demonstrated Technology
BATEA - Best Available Technology Economically Achievable
BPCTCA - Best Practicable Control Technology Currently Available
bbl - Barrel
BOD - Biochemical Oxygen Demand
bpcd - Barrels per calendar day
bpsd - Barrels per stream day (operating day)
BS and w - Bottom Sediment and Water
ETX - Eenzene-Toluene-Xylene mixture
COD - Chemical Oxygen Demand
cu m - cubic meter(s)
DAF - Dissolved Air Flotation
DO - Dissolved Oxygen
gpm - Gallons per minute
k - thousand(e.g., thousand cubic meters)
kg - kilogram(s)
1 - liter
Ib - pound(s)
LPG - Liquified Petroleum Gas
M - Thousand (e.g., thousand barrels)
MBCD - Thousand Barrels per calendar day
MBSD - Thousand Barrels per stream day
mgd - Million gallons per day
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mg/L - Milligrams per liter (parts per million)
MM - Million (e.g., million pounds)
PP - Polishing pond
psig - pounds per square inch, gauge (above 14.7 psig)
RSH - Mercaptan
sec - second-unit of time
scf - standard cubic feet of gas at 60o F and 14.7 psig
SIC - standard Industrial Classification
SRWL - standard Raw Waste Load
SS - Suspended Solids
STS - Susceptible to Separation
TOG - Total Organic Carbon
TSS - Total Suspended Solids
VSS - volatile Suspended Solids
ftU.S. GOVERNMENT PRINTING OFFICEU974 58Z-414/81 1-3 195
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