Unitad States
Environ menial Protection
Agency
Effluent Guide linos Division
WH-562
Washington DC 20460
Water and Wane MmMMMfll
Development
Document for
Effluent Limitations
Guidelines and
Standards for the
Petroleum Refining
EPA 440/1-82/014
October 1982
Point Source Category
-------
DEVELOPMENT DOCUMENT
for
EFFLUENT LIMITATIONS GUIDELINES
NEW SOURCE PERFORMANCE STANDARDS
and
PRETREATMENT STANDARDS
for the
PETROLEUM REFINING
POINT SOURCE CATEGORY
Anne M. Gorsuch
Administrator
Jeffery D. Denit
Director, Effluent Guidelines Division
Dennis Ruddy
Project Officer
October 1982
Effluent Guidelines Division
Office of Water Regulations and Standards
U.S. Environmental Protection Agency
Washington, D.C. 20460
-------
-------
TABLE OF CONTENTS
PAGE
CONTENTS iii
LIST OF TABLES vii
LIST OF FIGURES xvii
SECTION
I. EXECUTIVE SUMMARY 1
Summary and Conclusions 1
II. INTRODUCTION 15
Prior EPA Regulations 15
Overview of the Industry 15
Summary of Methodology 17
Approach 18
Industry Profile 18
Waste Characterization 18
Technology Evaluation 19
Cost Development 20
III. DESCRIPTION OF INDUSTRY 21
Introduction 21
Industry Profile 21
General Description of the 21
Industry
Refinery Distribution 22
Anticipated Industry Growth 23
Unit Manufacturing Processes 23
Overview of Refining Processes 23
Process Descriptions and Wastewater 23
Characteristics
1. Crude Oil and Product Storage 24
2. Ballast Water Storage 25
3. Crude Desalting 25
4. Crude Oil Fractionation 26
5. Thermal Cracking 27
6. Catalytic Cracking 28
7. Hydrocracking 29
8. Polymerization 29
9. Alkylation 29
10. Isomerization 30
11. Reforming 30
12. Solvent Refining 31
13. Hydrotreating 32
14. Grease Manufacturing 33
15. Asphalt Production 34
16. Drying and Sweetening 34
17. Lube Oil Finishing 35
18. Blending and Packaging 35
19. Hydrogen Manufacture 36
20. Utilities Function 36
111
-------
TABLE OF CONTENTS
(continued)
SECTION PAGE
IV. INDUSTRY SUBCATEGORIZATION 61
Introduction 61
Selected Subcategories 61
Purpose and Basis of Selection 62
Flow Model for 1974 Regulation 63
Flow Model Used for Proposed 65
1979 Regulations
Refined Flow Model 67
V. WASTE CHARACTERIZATION 69
Introduction 69
Concentration of Toxic, Conventional 70
and Non-Conventional Pollutants
1977 Survey
Short Term Sampling Program 71
Long Term Sampling Program 73
Survey of 1979 Effluent Monitoring 74
Data
Industry Flow 75
Summary of Net Wastewater Flow 75
Distribution of Flow by Subcategory 75
Trends in Industry Water Usage 76
VI. SELECTION OF POLLUTANTS TO BE REGULATED 121
Introduction 121
Selection of Regulated Pollutants for 121
Direct Dischargers
Pollutants Selected for Regulation 122
in the Petroleum Refining Point
Source Category (Direct Discharge
Segment)
Pollutants Excluded from Regulation 122
(Direct Discharge Segment)
Selection of Regulated Pollutants for 123
Indirect Dischargers
Pollutants Selected for Regulation 124
in the Petroleum Refining Point
Source Category (Indirect
Discharge Segment)
Pollutants Excluded from Regulation 124
(Indirect Discharge Segment)
Environmental Significance of Selected 124
Pollutants
Toxic Pollutants 124
Conventional Pollutants 126
Non-Conventional Pollutants 127
VII. CONTROL AND TREATMENT TECHNOLOGY 149
Introduction 149
IV
-------
TABLE OF CONTENTS
(continued)
SECTION PAGE
VII. CONTROL AND TREATMENT TECHNOLOGY (continued)
In-Plant Source Control 149
In-Plant Treatment Options 149
Chemical Substitution 151
Wastewater Reduction 152
Wastewater Reuse 153
End-of-Pipe Treatment 155
Biological Treatment 156
Filtration 157
Granular Activated Carbon 158
Powdered Activated Carbon 158
Cyanide Removal 160
Metals Removal 160
RSKERL Carbon Studies 161
Ultimate Disposal Methods 162
Existing Technology 164
Effluent Concentration 165
VIII. BEST AVAILABLE TECHNOLOGY ECONOMICALLY 223
ACHIEVABLE
Summary 223
BAT Options Considered 224
Identification of Best Available 234
Technology Economically Achievable
IX. NEW SOURCE PERFORMANCE STANDARDS 237
Summary 237
NSPS Options Considered 238
Identification of New Source Performance 240
Standards
X. PRETREATMENT STANDARDS FOR EXISTING AND NEW 243
SOURCES
Summary 243
Pretreatment Options Considered 244
Identification of Pretreatment Standards 249
for Existing and New Sources
XI. ACKNOWLEDGEMENTS 251
XII. REFERENCES 253
APPENDIX A COSTS OF TREATMENT AND CONTROL SYSTEMS A-l
Introduction A-l
Cost of Technologies Considered A-2
Biological Treatment A-2
Filtration A-2
Powdered Activated Carbon A-3
Granular Activated Carbon A-3
In-Plant Control A-4
v
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TABLE OF CONTENTS
(continued)
SECTION PAGE
APPENDIX A COSTS OF TREATMENT AND CONTROL SYSTEMS
(continued)
Cost of Technology Selected as Basis A-6
for Limitations and Standards
BAT Options A-6
New Source Costs A-10
Pretreatment Options A-ll
APPENDIX B RAW PLANT DATA B-l
APPENDIX C GLOSSARY AND ABBREVIATIONS C-l
VI
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LIST OF TABLES
TABLE TITLE PAGE
1-1 Effluent Guidelines - Petroleum Refining Point 3
Source Category Best Available Technology Econom-
ically Achievable (BAT) Process Configuration -
Process Breakdown
1-2 Effluent Guidelines - Petroleum Refining Point 4
Source Category Best Available Technology Econom-
ically Achievable (BAT) Size Factors by Sub-
category
1-3 Effluent Guidelines - Petroleum Refining Point 5
Source Category Best Available Technology Econom-
ically Achievable (BAT) Process Factors by Sub-
category
1-4 Effluent Guidelines - Petroleum Refining Point 6
Source Category New Source Performance Standards
(NSPS) Size Factors by Subcategory
1-5 Effluent Guidelines - Petroleum Refining Point 7
Source Category New Source Performance Standards
(NSPS) Process Factors by Subcategory
1-6 Effluent Guidelines - Petroleum Refining Point 8=
Source Category Best Available Technology
Achievable (BAT) Effluent Limitations by Sub-
category
1-7 Effluent Guidelines - Petroleum Refining Point 9
Source Category New Source Performance Standards
(NSPS) Effluent Limitations by Subcategory
1-8 Effluent Guidelines - Petroleum Refining Point 10
Source Category Ballast Water Standards for BAT
and NSPS
1-9 Effluent Guidelines - Petroleum Refining Point 11
Source Category Pretreatment Standards for
Existing Sources (PSES) and New Sources (PSNS)
III-1 Intermediate and Finished Products Produced by 41
Petroleum Refining Industry
III-2 Refining Capacity of Petroleum Refineries in the 42
U.S. by State as of January 1, 1981
III-3 1980 Consumption of Petroleum Products 43
vn
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LIST OF TABLES
(Continued)
TABLE TITLE PAGE
III-4 Sources of Supply for U.S. Petroleum Feedstocks 44
III-5 Characteristics of Crude Oils from Major Fields 45
Around the World
III-6 Trend in Domestic Petroleum Refining from 1975 ^8
to 1981
III-7 List of Processes Identified from the 1977 49
Industry Survey by EPA Process Number
III-8 Qualitative Evaluation of Wastewater Flow and 55
Characteristics by Fundamental Refinery Processes
V-1 Summary of Plant Characteristics for 17 Refin- 77
eries Sampled in Screening Program
V-2 Comparison of Plant Characteristics - 17 Refin- 78
eries Sampled vs. Overall Industry
V-3 Summary of Analytical Data Petroleum Refining 79
Industry Screening Sampling Program - Facility 1
V-4 Summary of Analytical Data Petroleum Refining 80
Industry Screening Sampling Program - Facility 20
V-5 Summary of Analytical Data Petroleum Refining 81
Industry Screening Sampling Program - Facility 50
V-6 Summary of Analytical Data Petroleum Refining 82
Industry Screening Sampling Program - Facility 59
V-7 Summary of Analytical Data Petroleum Refining 83
Industry Screening Sampling Program - Facility 64
V-8 Summary of Analytical Data Petroleum Refining 84
Industry Screening Sampling Program - Facility 80
V-9 Summary of Analytical Data Petroleum Refining 85
Industry Screening Sampling Program - Facility 84
V-10 Summary of Analytical Data Petroleum Refining 86
Industry Screening Sampling Program - Facility 126
V-11 Summary of Analytical Data Petroleum Refining 87
Industry Screening Sampling Program - Facility 153
V-12 Summary of Analytical Data Petroleum Refining 88
Industry Screening Sampling Program - Facility
157, Part 1
viii
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LIST OF TABLES
(Continued)
TITLE PAGE
Summary of Analytical Data Petroleum Refining 89
Industry Screening Sampling Program - Facility
157, Part 2
V-14 Summary of Analytical Data Petroleum Refining 90
Industry Screening Sampling Program - Facility 167
V-15 Summary of Analytical Data Petroleum Refining 91
Industry Screening Sampling Program - Facility 169
V-16 Summary of Analytical Data Petroleum Refining 92
Industry Screening Sampling Program - Facility 186
V-17 Summary of Analytical Data Petroleum Refining 93
Industry Screening Sampling Program - Facility 194
V-18 Summary of Analytical Data Petroleum Refining 94
Industry Screening Sampling Program - Facility 205
V-19 Summary of Analytical Data Petroleum Refining 95
Industry Screening Sampling Program - Facility 235
V-20 Summary of Analytical Data Petroleum Refining 96
Industry Screening Sampling Program - Facility 241
V-21 Summary of Analytical Data Petroleum Refining 97
Industry POTW Sampling Program - Facility 13
V-22 Summary of Analytical Data Petroleum Refining 98
Industry POTW Sampling Program - Facility 16
V-23 Summary of Analytical Data Petroleum Refining 99
Industry POTW Sampling Program - Facility 21
V-24 Summary of Analytical Data Petroleum Refining 100
Industry POTW Sampling Program - Facility 25
V-25 Summary of Analytical Data Petroleum Refining 101
Industry POTW Sampling Program - Facility 43
V-26 Summary of Analytical Data Petroleum Refining 102
Industry POTW Sampling Program - Facility 45
V-27 Direct Discharge - Final Effluent Priority 103
Pollutants - Summary of EPA Screening Program
Data
V-28 Indirect Discharge (To POTW} Priority Pollutants - 106
Summary of EPA Screening Program Data
IX
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LIST OF TABLES
(Continued)
TABLE TITLE PAGE
V-29 Final Effluent Priority Pollutants - Summary of 109
EPA Regional Surveillance and Analysis Data
V-30 Most Frequently Occurring Priority Pollutants - 112
Plant 1
V-31 Most Frequently Occurring Priority Pollutants - 113
Plant 2
V-32 Potential Surrogates for Priority Pollutants - 114
Correlation Coefficients
V-33 Summary of 1976 Net Wastewater Flow - By Refinery 115
Size
V-34 Summary of 1976 Net Wastewater Flow - By Refinery 116
Subcategory
VI-1 Flow - Weighted Concentrations and Loadings for 131
Direct Dischargers in the Petroleum Refining
Industry - Conventional Pollutants -
Nonconventional Pollutants
VI-2 Flow - Weighted Concentrations and Loadings for 133
Direct Dischargers in the Petroleum Refining
Industry - Toxic Pollutants - Total Phenols
(4AAP Method)
VI-3 Direct Discharge - Intake Water Priority Pollutant 134
Detection - Summary of EPA Screening Program Data
VI-4 Direct Discharge - Separator Effluent Priority 137
Pollutant Detection - Summary of EPA Screening
Program Data
VI-5 Priority Pollutants Not Detected in Treated 140
Effluents Discharged Directly/ and Excluded from
Regulation
VI-6 Priority Pollutants Detected in Treated Effluents 142
Discharged Directly, but Excluded from Regulation
VI-7 Statistical Analysis Table for the Petroleum 143
Refining Industry - Direct Discharge - Current/BPT
VI-8 Priority Pollutants Not Detected in Effluents 144
Discharged to POTW, and Excluded from Regulation
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LIST OP TABLES
(Continued)
VI-10
VII-1
VII-2
VII-3
VII-4
VII-5
VII-6
VII-7
VII-8
VII-9
VII-10
VII-11
VII-12
VII-13
VIII-1
TITLE PAGE
Priority Pollutants Detected in Effluents 145
Discharged to POTW, but Excluded from Regulation
Statistical Analysis Table for the Petroleum 147
Refining Industry - Indirect Discharge - Current
Sour Water Treatment in Petroleum Refineries 167
Effect of California Crudes on Reuse of Sour 171
Waters
Reuse of Sour Water - Industry Status 172
Cooling Tower Makeup Flow Rates in the Petroleum 174
Refining Industry
Summary of Flow Reduction Techniques Used 179
Identified by the 15 Refineries Studies During
Wastewater Recycle Study
Summary of Data on Removal of Cyanides with Steam 183
Stripping and Biological Treatment in the
Petroleum Refining Industry
Zero Discharge Refineries 184
Steam Electric Power Plants Using Vapor 188
Compression Evaporation as Part of Their Waste-
water Treatment System
Treatment Operations and Water Usage for 1973 189
and 1976
Summary of Treatment Technologies for 1973 and 215
1976
Refinery Flow vs. Final Effluent Concentrations 216
for 17 Screening Plants
Effluent Concentration from 50 Plant Study 217
Achievable Limitations Values 218
Diluted Effluent Concentrations from Direct Dis- 235
chargers in the Petroleum Refining Industry Com-
pared to the EPA Ambient Water Quality Criteria
for the Protection of Freshwater Aquatic Life
XI
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LIST OF TABLES
(Continued)
TABLE TITLE PAGE
A-1 Raw Wastewater Equalization Systems Capital A-14
and Operating Costs
A-2 Rotating Biological Contactors (RBC's) as A-15
Roughing Systems Equipment Cost Basis and Energy
Requirements
A-3 Rotating Biological Contactors (RBC's) as A-16
Roughing Filters Capital and Operating Costs
A-4 Filtration Equipment Cost Basis and Energy A-17
Requirements
A-5 Filtration Capital and Operating Costs A-18
A-6 Powdered Activated Carbon Equipment Cost Basis A-19
and Energy Requirements, 80 mg/L Dosage Rate
A-7 Powdered Activated Carbon Capital Costs, A-20
80 mg/L Dosage Rate
A-8 Powdered Activated Carbon Annual Operating A-21
Costs, 80 mg/L Dosage Rate
A-9 Powdered Activated Carbon Comparison of A-22
Operating Costs, Carbon Regeneration vs.
Throw-Away
A-10 Powdered Activated Carbon Equipment Cost Basis A-23
and Energy Requirements Including Costs for
Sludge Disposal, 80 mg/L Dosage Rate
A-11 Powdered Activated Carbon Capital Costs A-24
Including Costs for Sludge Disposal, 80 mg/L
Dosage Rate
A-12 Powdered Activated Carbon Annual Operating A-25
Costs Including Credit for Sludge Disposal,
80 mg/L Dosage Rate
A-13 Powdered Activated Carbon Equipment Cost Basis A-26
and Energy Requirements, 150 mg/L Dosage Rate
A-14 Powdered Activated Carbon Capital Costs, A-27
150 mg/L Dosage Rate
A-15 Powdered Activated Carbon Annual Operating A-28
Costs, 150 mg/L Dosage Rate
Xll
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LIST OF TABLES
(Continued)
TABLE TITLE PAGE
A-16 PACT Comparison of Operating Costs, Carbon A-29
Regeneration vs. Throw-Away, 150 mg/L Dosage
Rate
A-17 Powdered Activated Carbon Equipment Cost Basis A-30
and Energy Requirements Including Costs, for
Sludge Disposal, 150 mg/L Dosage Rate
A-18 Powdered Activated Carbon Capital Costs Including A-31
Costs for Sludge Disposal, 150 mg/L Dosage Rate
A-19 Powdered Activated Carbon Annual Operating Costs A-32
Including Credit for Sludge Disposal, 150 mg/L
Dosage Rate
A-20 Granular Activated Carbon Equipment Cost Basis A-33
and Energy Requirements
A-21 Granular Activated Carbon Capital Costs A-34
A-22 Granular Activated Carbon Annual Operating Costs A-35
A-23 Supplemental Economic Cost Information Capital A-36
and Operating Costs for 10,000 Gallon per Day
Treatment Systems
A-24 Cooling Tower Slowdown Rates Petroleum Refining A-37
Industry (Million Gallons per Day)
A-25 Chromium Removal Systems Equipment Cost Basis A-38
and Energy Requirements
A-26 Chromium Removal Systems Capital and Operating A-39
Costs
A-27 Wastewater Recycle Capital and Operating Costs A-4Q
A-28 Water Softening of Recycled Wastewater Capital A-4I
Costs
A-29 Capital and Operating Costs by Refinery Number A-42
A-30 Capital and Operating Costs, Indirect Discharge - A-47
Option 1
A-31 Capital and Operating Costs, Indirect Discharge - A-50
Option 2
Xlll
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LIST OF TABLES
(Continued)
TITLE PAGE
Analytical Results for Traditional Parameters B-2
for the RSKERL and B&R Sampling Program
B-2 Analytical Results for Priority Pollutants for B-9
the RSKERL and B&R Sampling Program - Volatile
Organics
B-3 Analytical Results for Priority Pollutants for B-12
the RSKERL and B&R Sampling Program - Semivola-
tile Organics
B-4 Analytical Results for Priority Pollutants for B-17
the RSKERL and B&R Sampling Program - Pesticides
B-5 Analytical Results for Priority Pollutants for B-20
the RSKERL and B&R Sampling Program - Cyanides,
Phenolics and Mercury
B-6 Analytical Results for Priority Pollutants for B-30
the RSKERL and B&R Sampling Program - Metals
B-7 Analytical Results for Traditional Parameters B-36
in the Pretreatment Sampling Program - Week 1
B-8 Analytical Results for Priority Pollutants for B-37
the Pretreatment Sampling Program - Week 1,
Volatile Organics
B-9 Analytical Results for Priority Pollutants for B-38
the Pretreatment Sampling Program - Week 1,
Semivolatile Organics
B-10 Analytical Results for Priority Pollutants for B-40
the Pretreatment Sampling Program - Week 1,
Pesticides
B-11 Analytical Results for Priority Pollutants for B-41
the Pretreatment Sampling Program - Week 1,
Metals
B-12 Analytical Results for Priority Pollutants for B-42
the Pretreatment Sampling Program - Week 2
B-13 Analytical Results for Priority Pollutants for B-43
the Pretreatment Sampling Program - Week 2,
Volatile Organics
xiv
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LIST OF TABLES
(Continued)
TABLE TITLE PAGE
B-14 Analytical Results for Priority Pollutants for B-45
the Pretreatment Sampling Program - Week 2,
Semivolatile Organics
B-15 Analytical Results for Priority Pollutants for B-48
the Pretreatment Sampling Program - Week 2,
Pesticides
B-16 Analytical Results for Priority Pollutants for B-49
the Pretreatment Sampling Program - Week 2,
Metals
xv
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LIST OF FIGURES
FIGURE TITLE PAGE
1-1 Effluent Guidelines - Petroleum Refining Point 13
Source Category Best Available Technology
Economically Achievable Sample Calculation -
Process Factor
III-1 Geographical Distribution of Petroleum Refineries 56
in the United States, as of January 1, 1981
III-2 Crude Desalting (Electrostatic Desalting) 57
III-3 Crude Fractionation (Crude Distillation, Three 53
Stages)
III-4 Catalytic Cracking (Fluid Catalytic Cracking) 59
V-1 Histogram of Net Wastewater Flow by Size Class 117
V-2 Histogram of Net Wastewater Flow by Subcategory us
V-3 Historical Trend of Total Industry Water Usage 119
VII-1 Rotating Biological Contactors 219
VII-2 Flow Diagram of a Granular Activated Carbon 220
System
VII-3 Carbon Regeneration System 221
Vll-4 Flow Diagram of One Powdered Activated Carbon 222
Treatment Scheme
xvi i
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SECTION I
EXECUTIVE SUMMARY
SUMMARY AND CONCLUSIONS
This development document presents the technical data base
developed by EPA to support effluent limitations and standards
for the.Petroleum Refining Point Source Category. Technologies
covered by this document to achieve these limitations and
standards are defined as best available technology economically
achievable (BAT), best available demonstrated technology (BADT,
equal to new source performance standards NSPS), pretreatment
standards for existing sources (PSES), and pretreatment standards
for new sources (PSNS). Best conventional pollutant control
technology (BCT) limitations are not addressed in this document
because the Agency has reserved coverage of BCT for future
rulemaking. Best practicable technology currently available
(BPT) is not being revised and therefore will not be addressed in
this document. The basis for BPT can be found in an earlier
document (EPA-440/l-74-014a). This document outlines the
technology options considered and the rationale for selecting the
technology levels on which pollutant limitations are based.
EPA is promulgating BAT effluent limitations guidelines
equivalent to BPT, which were promulgated on May 9, 1974 (39 FR
16560) and amended May 20, 1975 (40 FR 21939).
EPA decided to retain the New Source Performance Standards (NSPS)
that were promulgated May 9, 1974 (39 FR 16560).
Interim final pretreatment standards for existing sources (PSES)
were promulgated on March 23, 1977 (42 FR 15684). Pretreatment
standards for new sources (PSNS) were promulgated on May 9, 1974
(39 FR 16560). This document presents the final PSES and PSNS
promulgated, both of which are revision to the prior pretreatment
standards for this industry. Pretreatment standards for both
existing and new sources (PSES and PSNS) will limit ammonia and
oil and grease at 100 mg/1, each. An alternate mass - based
ammonia standard is also provided. In addition, PSNS contains a
chromium mass limitation based upon the application of a 1 mg/1
standard to the cooling tower discharge portion of the total
refinery flow to the POTW.
Stormwater runoff is not addressed in this document. The 1974
development document presented BPT, BAT, and NSPS for stormwater
run off. These limitations were remanded for reconsideration by
the U.S. Court of Appeals on August 11, 1976. These requirements
were reserved by the Agency for future rulemaking.
Effluent limitations guidelines for conventional pollutants
(BOD5, TSS, oil and grease, and pH) will be promulgated
-------
separately as BCT limitations for existing direct dischargers in
this category in future rulemaking.
The tables in this section summarize the final promulgated
regulations.
Table 1-1 lists the processes used in the determination of
process categories and their associated weighting factors as used
to determine process configurations. Tables 1-2 and 1-3 list the
BAT size factors and process factors/ respectively, while Tables
1-4 and 1-5 list the same factors as applied to NSPS. Tables 1-6
and 1-7 summarize effluent limitations by subcategory for BAT and
NSPS. These effluent limitations are to be used in conjunction
with the process factors and size factors determined in the
proceeding tables to calculate actual mass limitations applicable
to individual refineries. Table 1-8 summarizes the ballast water
allowance applicable to both BAT and NSPS. Table 1-9 contains
the general and specific pretreatment limitations applicable to
PSES and PSNS for indirect dischargers.
A sample calculation of BAT effluent limitations is provided in
Figure 1-1. The reader should note that the BPT model uses only
crude processes, cracking processes/ lube processes/ and asphalt
processes for the calculation of the process factor (Table 1-1).
Moreover/ the factors for process configuration and size shown in
Tables 1-2 through 1-5 are discrete factors (do not permit
interpolated/ intermediate values) which apply to all refineries
within a given range and subcategory.
Implementation of BAT/ NSPS and PSES would incur no additional
cost to the industry beyond existing requirements. A single new
indirect discharging refinery of the type and size likely to be
built in the 1980's and subject to PSNS would incur an additional
capital cost of $0.39 million and an annual cost of $0.26 million
(1979 dollars).
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TABLE 1-1
EFFLUENT GUIDELINES
PETROLEUM REFINING POINT SOURCE CATEGORY
BEST AVAILABLE TECHNOLOGY ECONOMICALLY ACHIEVABLE (BAT)
PROCESS CONFIGURATION - PROCESS BREAKDOWN
Process Category
Crude
Cracking and Coking
Processes Included
Weighting Factor
Lube
Asphalt
desalting 1
atmospheric distillation
vacuum distillation
fluid catalytic cracking 6
thermofor
houdrlflow
gas-oil cracking
vlsbreaklng
fluid coking
delayed coking
lube hydroflnlng 13
white oil manufacturing
propane - dewaxlng, deasphaltlng
duo soli solvent dewaxlng
lube vac. tower, wax fract.
centrifuglng and chilling
MEK dewaxlng
deoHIng (wax)
naphthenlc lubes
S02 extraction
wax pressing
wax plant (with neutral separ.)
furfural extraction
clay contacting - percolation
wax sweating
add treating
phenol extraction
asphalt production 12
asphalt oxidation
asphalt emulsifying
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TABLE 1-2
EFFLUENT GUIDELINES
PETROLEUM REFINING POINT SOURCE CATEGORY
BEST AVAILABLE TECHNOLOGY ECONOMICALLY ACHIEVABLE (BAT)
Size Factors By Subcategory;
1 ,000 Barrels
of Feedstock
Per Stream - Day
Less than 24.9
25.0 to 49.9
50.0 to 74.9
75.0 to 99.9
100.0 to 124.9
125.0 to 149.9
150.0 to 174.9
175.0 to 199.9
200.0 to 224.9
225.0 or greater
Topping;
Size
Factor
1.02
1.06
1.16
1.26
1.38
1.50
1.57
1.57
1.57
1.57
Cracking;
Size
Factor
0.91
0.95
1.04
1.13
1.23
1.35
1.41
1.41
1.41
1.41
Petrochemical ;
Size
Factor
0.73
0.76
0.83
0.91
0.99
1.08
1.13
1.13
1.13
1.13
Lube:
Size
Factor
0.71
0.71
0.74
0.81
0.88
0.97
1.05
1.14
1.19
1.19
Integrated;
Size
Factor
0.73
0.73
0.73
0.73
0.73
0.76
0.83
0.91
0.99
1.04
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TABLE 1-3
EFFLUENT GUIDELINES
PETROLEUM REFINING POINT SOURCE CATEGORY
BEST AVAILABLE TECHNOLOGY ECONOMICALLY ACHIEVABLE (BAT)
Process Factors By Subcategory:
Topping; Cracking;
Process
Configuration
Less
2.5
3.5
4.5
5.5
6.0
6.5
7.0
7.5
8.0
8.5
9.0
9.5
10.0
10.5
11.0
11.5
12.0
12.5
13.0
13.5
14.0
than 2.49
to 3.49
to 4:49
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
5.49
5.99
6.49
6.99
7.49
7.99
8.49
8.99
9.49
9.99
10.49
10.99
11.49
11.99
12.49
12.99
13.49
13.99
or greater
Process Process
Factor Factor
0
0
0
0
1
2
2
2
2
2
3
3
3
4
4
.62 0.58
.67 0.63
.80 0.74
.95 0.88
.07
.17
.27
.39
.51
.64
.79
.95
.12
.31
.51
.73
.98
.24
.53
.84
.18
.36
.00
.09
.19
.29
.41
.53
.67
.82
.89
.89
.89
.89
.89
.89
.89
.89
.89
.89
Petrochemical: Lube:
Process
Factor
0
0
0
0
0
0
i
1
1
1
1
.73
.73
.73
.80
.91
.99
.08
.17
.28
.39
.51
.65
.72
.72
.72
.72
.72
.72
.72
.72
.72
.72
Process
Factor
0
0
0
0
0
0
0
0
1
1
2
2
2
2
2
.81
.81
.81
.81
.81
.81
.88
.88
.00
.09
.19
.29
.41
.53
.67
.82
.98
.15
.34
.44
.44
.44
Integrated;
Process
Factor
0
0
0
0
0
0
0
0
0
1
1
1
1
2
2
2
2
.75
.75
.75
.75
.75
.75
.82
.82
.92
.00
.10
.20
.30
.42
.54
.68
.83
.99
.17
.26
.26
.26
-------
TABLE 1-4
EFFLUENT GUIDELINES
PETROLEUM REPINING POINT SOURCE CATEGORY
NEW SOURCE PERFORMANCE STANDARDS (NSPS)
Size Factors By Subcategoryt
Toppingt Crack ing i
1,000 Barrels
of Feedstock Size Size
Per Stream - Day Factor Factor
Less than 24.9
25.0 to 49.9
50.0 to 74.9
75.0 to 99.9
100.0 to 124.9
125.0 to 149.9
150.0 to 174.9
175.0 to 199.9
200.0 to 224.9
225.0 or greater
.02 0.91
.06 0.95
.16
.26
.38
.50
.57
.57
.57
.57
.04
.13
.23
.35
.41
.41
.41
.41
Petrochemical i
Size
Factor
0.73
0.76
0.83
0.91
0.99
1.08
1.13
1.13
1.13
1.13
Lube t
Size
Factor
0.71
0.71
0.74
0.81
0.88
0.97
1.05
1.14
1.19
1.19
Integrated!
Size
Factor
0.73
0.73
0.73
0.73
0.73
0.76
0.83
0.91
0.99
1.04
-------
TABLE 1-5
EFFLUENT GUIDELINES
PETROLEUM REPINING POINT SOURCE CATEGORY
MEM
SOURCE PERFORMANCE STANDARDS
(NSP8)
Process Factors By Subcategoryi
Proceaa
Configuration
Less than 2.49
2.5 to 3.49
3.5 to 4.49
4.5 to 5.49
5.5 to 5.99
6.0 to 6.49
6.5 to 6.99
7.0 to 7.49
7.5 to 7.99
8.0 to 8.49
8.5 to 8.99
9.0 to 9.49
9.5 to 9.99
10.0 to 10.49
10.5 to 10.99
11.0 to 11.49
11.5 to 11.99
12.0 to 12.49
12.5 to 12.99
13.0 to 13.49
13.5 to 13.99
14.0 or greater
Topping i
Process
Factor
0.62
0.67
0.80
0.95
.07
.17
.27
.39
.51
.64
1.79
1.95
2.12
2.31
2.51
2.73
2,98
3.24
3,53
3.84
4.18
4.36
Cracking s Petrochemical t
Process Process
Factor Factor
0.58 0.73
0.63 0.73
0.74 0.73
0.88 0.80
.00 0.91
.09 0.99
.19
.29
.41
.53
.67
.82
.89
.89
.89
.89
.89
.89
.89
.89
.89
.89
.08
.17
.28
.39
.51
.65
.72
.72
.72
.72
.72
.72
.72
.72
.72
.72
Lubes
Process
Factor
0.81
0.81
0.81
0.81
0.81
0.81
0.88
0.88
.00
.09
.19
.29
.41
.53
.67
.82
.98
2.15
2.34
2.44
2.44
2.44
Integrated i
Process
Factor
0.75
0.75
0.75
0.75
0.75
0.75
0.82
0.82
0.92
.00
.10
.20
.30
.42
.54
.68
.83
.99
2.17
2.26
2.26
2.26
-------
TABLE 1-6
EFFLUENT GUIDELINES
PETROLEUM REFINING POINT SOURCE CATEGORY
BEST AVAILABLE TECHNOLOGY ECONOMICALLY ACHIEVABLE (BAT)
Effluent Limitations By Subcategoryi<'l>
Effluent
Characteristics
Maximum
For Any
One Day
Metric Unitai kiloarema per
COD<»
Phenolic Compounds
Ammonia aa N
Sulfide
Total Chromium
117.0
0.168
2.81
0.149
0.34)
Hexavalent Chromium 0.028
Topping!
Average of Deily
Values For thirty
Consecutive Deys
Shsll Not Exceed
Maximum
For Any
One Dey
Cracking i
Average Of Daily
Values For Thirty
Consecutive Days
Shall Not Exceed
Petrochemical!
Average of Dally
Maximum
For Any
One Day
Valuea For Thirty
Consecutive Oaya
Shall Not Exceed
Maximum
For Any
One Day
Lubel
Average of Daily
Valuea For Thirty
Consecutive Deys
Shsll Not Exceed
Integrated!
Maximum
For Any
One Day
Average of Dally
Valuea For Thirty
Consecutive Days
Shsll Not Exceed
thousand cubic meters of feedstock (kg/1,000 a')
60.)
0.076
1.27
0.068
0.2
0.012
210.0
0.21
18.8
0.18
0.43
0.03)
109.0
0.1
8.)
0.082
0.2)
0.016
210.0
0.2)
23.4
0.22
0.52
0.046
109.
0.
10.
0.
0.
0.
0
12
6
099
3
02
360.0
0.38
23.4
0.33
0.77
0.06B
187.0
0.184
10.6
0.1)
0.4)
0.03
388.0
0.4
23.4
0.3)
0.82
0.068
198.0
0.192
10.6
0.1)8
0.48
0.0)2
English Unitsi pounds per thoueend bsrrsls of feedstock (lb/1.000(bbl)
COD<»
Phenolic Compounds
Ammonia aa N
Sulfida
Total Chromium
Hexavalent Chromium
41.2
0.06
0.99
0.0)3
0.122
0.10
21.)
0.027
0.4)
0.024
0.071
0.0044
74.0
0.074
6.6
0.06)
0.1)
0.012
38.4
0.036
3.0
0.029
0.088
0.00)6
74.0
O.OB8
8.2)
0.078
0.183
0.016
38.4
0.042)
3.8
0.033
0.107
0.0072
127
0
8
0
0
0
.0
.133
.3
.118
.273
.024
66.0
0.06)
3.8
0.0)3
0.16
0.011
136.0
0.14
8.3
0.124
0.29
0.02)
70.0
0.068
3.8
0.0)6
0.17
0.011
(1) To obtain actual Halt at Ions all values in this table Bust be multiplied by a aubcategory dependent variable, F| whets F ia the product of the process
factor and the size factor end the crude throughput (in thousand barrels par day).
(2) Ones-through cooling Meter eay be discharged Kith a total organic carbon (TOC) concentration not to exceed ) mg/l.
()) In any caaa in which the applicant can demonstrate that the chloride ion concentration in the effluent exceeds 1,000 my/I (1,000 ppm), the Regional
Adainlatrator may substitute TOC as a parsmater in lieu of COD. Effluent limitations for IOC shall be based on affluent date froa the plant correlating
TOC to BOD;.
If in the Judgoment of the Regional Administrator, adequate correlation data are not available, the effluent limitstions for TOC shall be eateblishod
at a ratio of 2.2 to 1 to the applicebla effluent limitations on BOD}.
-------
TABtE 1-7
ETTtMENT GUIDELINES
PEIROUW REFINING POINT SOURCE CATEGORY
MEM SOURCE PERTOBMMCE STANDARDS OBPS)
Effluent 11*1 tit lone By Subcsteooryill>
-------
TABLED 1-8
EFFLUENT GUIDELINES
PETROLEUM REFINING POINT SOURCE CATEGORY
BALLAST WATER TREATMENT STANDARDS FOR
BAT AND NSPS. FOR ALL SUBCATEGORIES
Pollutant or
Pollutant
Property
Maximum
For Any
One Day
Average of Daily
Values for 30
Consecutive Days
Metric Units
(Kilograms per
cubic meter of
flow) COD
English Units
(Pounds per
1,000 gal of flow) COD
-1
-1
0.47
3.9
0.24
2.0
1- In any case in which the applicant can demonstrate that the
chloride ion concentration in the effluent exceeds 1,000 mg/1
(1,000 ppm), the regional Administrator may substitute TOC as
a parmeter in lieu of COD. Effluent limitations for TOC shall
be based on effluent data from the plant correlating TOC to BODg.
If in the judgement of the Regional Administrator, adequate
correlation data are not available, the effluent limitations for
TOC shall be established at a ratio of 2.2 to 1 to the applicable
effluent limitations on BODg.
10
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1 of 2
TABLE 1-9
EFFLUENT GUIDELINES
PETROLEUM REFINING POINT SOURCE CATEGORY
PRETREATMENT STANDARDS FOR EXISTING SOURCES (PSES)
AND NEW SOURCES (PSNS)
A. General Prohibitions
Pollutants introduced into POTW by a non-domestic source shall not pass
through the POTW or interfere with the operation or performance of the
works. These general prohibitions and the specific prohibitions in
paragraph B of this section apply to all non-domestic sources introducing
pollutants into a POTW whether or not the source is subject to other
National Pretreatment Standards or any national, state, or local
pretreatment requirements.
B. Specific Prohibitions
In addition, the following pollutants shall not be introduced into a POTW:
1) Pollutants which create a fire or explosion hazard in the POTW;
2) Pollutants which will cause corrosive structural damage to the POTW,
but in no case Discharges with pH lower than 5.0, unless the works are
specifically designed to accommodate such Discharges;
3) Solid or viscous pollutants in amounts which will cause obstruction to
the flow in the POTW resulting in interference;
4) Any pollutant, including oxygen demanding pollutants (BOD, etc.)
released in a discharge at a flow rate and/or pollutant concentration
which will cause interference with the POTW;
5) Heat in amounts which will inhibit biological activity in the POTW
resulting in interference, but in no case heat in such quantities that
the temperature at the POTW treatment plant exceeds 40°C (104°F) unless
the approval authority, upon request of the POTW, approves alternate
temperature limits.
11
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2 of 2
TABLE 1-9
EFFLUENT GUIDELINES
PETROLEUM REFINING POINT SOURCE CATEGORY
PRETREATMENT STANDARDS FOR EXISTING SOURCES (PSES)
AND NEW SOURCES (PSNS)
(continued)
C. Categorical Pretreatment Standards
1) Maximum Pollutant Concentrations for Any One Day (All Indirect Dis-
chargers)
Pollutant or
Pollutant Property
Oil and Grease
Ammonia
Pretreatment Standard for
Existing and New Sources
Maximum for Any One Day
Milligrams per Liter (mg/L)
100
100 *
* Where the discharge to the POTW consists solely of sour waters, the
owner or operator has the option of complying with this limit or the
daily mass limitation set forth in the BAT or NSPS standards for
existing or new sources, respectively.
2) Maximum Pollutant Concentration For Any One Day (new source indirect
dischargers)
The following standard is applied to the cooling tower discharge part
of the total refinery flow to the POTW by mutliplying: (1) the stan-
dards; (2) the total refinery flow to the POTW; and (3) the ratio of
the cooling tower discharge flow to the total refinery flow.
Pollutant or
Pollutant Property
Total Chromium
Pretreatment Standard
for New Sources Only
Maximum for Any One Day
Milligrams per Liter (mg/L)
1
12
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1 of 2
FIGURE 1-1
EFFLUENT GUIDELINES
PETROLEUM REFINING POINT SOURCE CATEGORY
BEST AVAILABLE TECHNOLOGY ECONOMICALLY ACHIEVABLE
SAMPLE CALCULATION - PROCESS FACTOR
Step 1: Determine subcategory and size of the refinery (the example
refinery is a lube facility with 125,000 bbl/day throughout),
Step 2: Obtain information on capacity of processes listed in
Table 1-1 from the refinery.
Step 3: Calculate process configuration factor as follows: (the
processes and their associated capacities below are
for the example refinery).
Process
crude- ATM
vacuum
desalting
cracking-FCC
hyd roc racking
lubes hydro-
fining
furfural
extraction
phenol
extraction
asphalt
Process
capacity
(1,000
bbl/day)
125
60
125
41
20
5.3
4.0
4.0
4.0
Capacity of
process In
relation to
refinery
throughput*
1.0
0.48
1.0
2.48
0.328
0.160
0.488
0.042
0.032
0.032
0.106
0.032
Process
weighting
factor
(from
Table 1-1)
x 1
x 6
x 13
x 12
Process
config-
uration
factor
2.48
2.93
1.38
0.38
Process configuration factor:
7.17
*Divide process capacity by refinery throughput.
In most cases, refinery throughput is equal to the crude capacity.
13
-------
2 of 2
FIGURE 1-1 (Cont'd)
Step 4: Determine process factor by looking at Table 1-3 (for BAT),
For process configuration of 7.17 in the lube subcategory,
the process factor is 0.88.
Step 5: Determine size factor by looking at Table 1-2 (for BAT).
For a lube refinery with throughput of 125,000 bbl/day,
the size factor is 0.97.
Step 6: Obtain unadjusted effluent limitations from Table 1-6 for
BAT. This example calculation computes the 30-day daily
average COD (in units of Ib/mbbl of feedstock). The COD
value is 66 Ib/mbbl (30-day).
Step 7: Calculate limitation for COD by multiplying the process
factor (from Step 4), the size factor (from Step 5),
the effluent limit (from Step 6), and refinery throughput
(Step 1).
0.88 (process factor) x 0.97 (size factor) x 66 Ib/mbbl
(unadjusted effluent limitation) x 125 mbbl - 7042 Ib/day
of COD (30-day daily average limit).
14
-------
SECTION II
INTRODUCTION
This development document details the technical basis for the
Agency's BAT, NSPS, PSES, and PSNS for the petroleum refining
industry. These limitations and standards are promulgated under
authority of Sections 301, 304, 306, 307, and 501 of the Clean
Water Act (the Federal Water Pollution Control Act Amendments of
1972, 33 USC 1251 et seq., as amended by the Clean Water Act of
1977, P.L. 95-2177 also called the "Act". The regulation was
also promulgated in response to the Settlement Agreement in
Natural Resources Defense Council, Inc. v. Train, 8 ERC 2120
(D.D.C. 1976), modified, 12 ERC 1833TD.D.C. 1979) and in
response to the decision of the United States Court of Appeals in
American Petroleum Institute v.. EPA. 540 F.2d 1023 (10th Cir.
1976).
PRIOR EPA REGULATIONS
EPA promulgated BPT, BAT, NSPS and PSNS for the petroleum
refining industry on May 9, 1974 (39 FR 16560, Subparts A-E). A
development document was published in April 1974 (EPA-440/1-74-
014a). This document provided the bases for the 1974 regulation
and is henceforth referred to as the 1974 Development Document.
BPT and BAT limitations and NSPS were challenged in the U.S.
Court of Appeals for the Tenth Circuit by the American Petroleum
Institute and others. The court upheld both BPT limitations and
NSPS, but remanded BAT limitations, in toto, for further
consideration. Storm water regulations under BPT, BAT and NSPS
were set aside by the court in the same action. Interim final
PSES were promulgated on March 23, 1977 (42 FR 15684).
OVERVIEW OF THE INDUSTRY
The petroleum refining industry is defined by Bureau of the
Census Standard Industrial Classification (SIC) 2911. The raw
material of this industry is primarily petroleum material
(generally, but not always, crude oil). Petroleum refineries
process this raw material into a wide wariety of petroleum
products, including gasoline, residual fuel oil, jet fuel,
heating oils and gases, and petrochemicals. Refining includes a
wide variety of physical separation and chemical reaction
processes. Because of the diversity and complexity of the
processes used and the products produced, petroleum refineries
are generally characterized by the quantity of raw material
processed, rather than by the quantity and types of products
produced.
EPA has identified 285 petroleum refineries in the United States
and its possessions. The smallest refinery can refine fifty
15
-------
barrels of oil per day (one barrel equals 42 gallons), while the
largest can refine 665,000 barrels per day.
The U.S. refining industry has experienced a dramatic reversal of
historical growth trends as a result of the reduction in
consumption of petroleum products that has taken place since
1978. U.S. crude oil runs peaked at 14.7 million barrels per day
in the calendar year 1978. Runs have decreased each year since
then reaching 12.5 million barrels per day for the calendar year
1981. In early 1982 runs have dropped to below 11.5 million
barrels per day representing percentage capacity utilizations in
the low 60's. More than fifty plants have discontinued
operations in the U.S. over the past year. It is expected that
U.S. refinery activity will recover somewhat. The 1981 DOE
Annual Report to Congress projects U.S. crude runs at 14.4
million barrels per day in 1985 and 13.4 million barrels per day
in 1990 for their mid-oil price scenarios. The above forecasts
of U.S. refinery activity indicate that very little, if any, new
refinery facilities will be built at undeveloped sites over the
next decade. However, it will be necessary for U.S. refineries
to modernize and expand downstream facilities at existing
refinery sites to allow increasingly heavier and higher sulfur
crude oils to be processed into a product mix which emphasizes
production of the lighter and higher quality products that will
be demanded by the marketplace.
Since its inception, the U.S. refining industry has continued to
build bigger and more efficient plants as new technology has
developed over time. The average U.S. refinery capacity per
plant increased from 43.3 thousand barrels per day to 55.6
thousand barrels per day from January 1, 1967, to January 1,
1973. This trend was halted in the late 1970's in response to
the DOE "small refiner bias" provision of the crude oil
entitlements program. This provision encouraged the construction
of small, inefficient plants which offset the technological
improvements created by expanding existing, larger refineries.
53 additional U.S. refineries were in operation on January 1,
1981 versus January 1, 1975. The number of plants in operation
with capacity greater than 100 thousand barrels, per day increased
by only seven (from 46 to 53) over this time period. Most of the
new plants placed in operation were small. Average U.S. refinery
capacity increased only from 56.0 to 57.3 thousand barrels per
day from January 1, 1975, to January 1, 198.1. Many of the small
new plants built in this time period are among the fifty that
have discontinued operations during the last year.
The four major sources of process wastewater are cooling water,
water used to wash unwanted materials from a process stream,
water used as part of a reaction process, and boiler blowdowns.
Current treatment systems used by refineries for this process
wastewater include (a) in-plant controls of water use; (b) in-
plant treatment of segregated wastestreams for ammonia and
sulfide removal via steam stripping; and (c) end-of-pipe
16
-------
treatment, consisting of oil/water separators, biological
treatment and, in some cases, mixed media filtration. Although
significant concentrations of toxic and other pollutants are
found in untreated waste, data from an EPA sampling program of
seventeen refineries show that application of BPT substantially
reduces the concentrations of pollutants (See Sections V and VI
for details of sampling programs). Toxic pollutants were reduced
to near or below the concentrations that can be accurately
measured using available measurement techniques.
SUMMARY OF METHODOLOGY
On December 27, 1977, the President signed into law the Clean
Water Act of 1977. Although this law makes several important
changes in the Federal water pollution control program, its most
significant feature is the incorporation of several of the basic
elements of the Settlement Agreement program for toxic pollution
control. Sections 301(b)(2)(A) and 301(b)(2)(C) of the Act now
require the achievement by July 1, 1984, of effluent limitations
reflecting BAT for toxic pollutants, including the 65 pollutants
and classes of pollutants which Congress declared toxic under
Section 307(a). Likewise, the Agency's programs for new source
performance standards and pretreatment standards are now aimed
principally at toxic pollutant controls. Moreover, to strengthen
the toxics control program, Section 304(e) of the Act now
authorizes the Administrator to prescribe "best management
practices" ("BMPs") to prevent the release of toxic and hazardous
pollutants from plant site runoff, spillage or leaks, sludge or
waste disposal, and drainage from raw material storage associated
with, or ancillary to, the manufacturing or treatment process.
In keeping with its emphasis on toxic pollutants, the Clean Water
Act of 1977 also revised the control program for non-toxic
pollutants. Instead of BAT for "conventional" pollutants
identified under Section 304(a)(4) (including biochemical oxygen
demand, total suspended solids, fecal coliform, oil and grease
and pH), the new Section 301(b)(2)(E) requires achievement by
July 1, 1984, of "effluent limitations requiring the application
of the best conventional pollutant control technology" ("BCT").
BCT is not an additional limitation but replaces BAT for the
control of conventional pollutants. In addition to other factors
specified in section 304(b)(4)(B), the Act requires the BCT
limitations be assessed in light of a two part "cost-
reasonableness" test. American Paper Institute v. EPA, 660 F2d
954 (4th Cir. 1981). The first test compares the cost for
private industry to reduce its conventional pollutants with the
costs to publicly owned treatment works for similar levels of
reduction in their discharge of these pollutants. The second
test examines the cost-effectiveness of additional industrial
treatment beyond BPT. EPA must find that limitations are
"reasonable" under both tests before establishing them as BCT.
In no case may BCT be less stringent than BPT. For non-toxic,
nonconventional pollutants, Sections 301(b)(2)(A) and (b)(2)(F)
17
-------
require achievement of BAT effluent limitations within three
years after their establishment or by July 1, 1984, whichever is
later, but not later than July 1, 1987.
APPROACH
The emphasis of this regulatory development effort differs from
the one in 1974 because of legislative changes.
Despite the major revisions described above, the basic factors to
be considered in developing effluent limitation guidelines and
standards of performance remain unchanged. These include the
total cost of applying a technology; effluent reduction benefits
realized; the age of equipment and facilities; the process
employed; the engineering aspects of applying various types of
control techniques and process changes; nonwater-quality
environmental related impacts (including energy requirements);
and other factors as the Administrator deems appropriate.
Efforts to compile the necessary information to address the
statutory factors mentioned above were divided into four
segments: industry profile, waste characterization, technology
assessment, and cost development. These efforts are briefly
described below.
Industry Profile
To update the information needed to establish effluent guidelines
for the petroleum refining category, EPA sent questionnaires to
all refineries in the United States and its territorial
possessions. The surveys were made under Section 308 of the
Clean Water Act. The information obtained describes the
petroleum refining industry wastewater treatment practices for
the year 1976.
Information from these surveys was combined with existing
information to develop an industry profile, including number of
plants, their size, geographic location, manufacturing processes,
wastewater generation, treatment, and discharge methods.
Information on number, size, and geographical location of
refineries was later updated with 1980 data from the U.S.
Department of Energy (DOE). Questionnaire data aided in the
final selection of plants for other aspects of this program.
Flow data from the questionnaires was used to develop a flow
model for the analysis of refinery wastewater production.
Another objective of the survey was to obtain information
identifying the use or generation of 123 toxic pollutants and
determining the availability of plant data on the effectiveness
of their removal. Since the initial questionnaire survey, the
list of toxic pollutants has been revised from 123 to the present
list of 126 specific substances.
Waste Characterization
-------
Information on waste characterization of petroleum refining
effluent is available from four sources which are briefly
described below.
The first effort in determining the potential presence of the
toxics involved the identification of toxics manufactured and
purchased by the industry. The 1977 survey requested such
information from the industry.
The second effort was the sampling of 23 refineries and two POTW
to determine the presence, absence and relative concentrations of
toxic/ conventional and non-conventional pollutants. The
refineries were selected to be representative of the
manufacturing processes, the prevalent mix of production among
plants/ and the current treatment technologies in the industry.
The selected direct discharge refineries were meeting BPT
limitations. Seventeen plants were direct dischargers
(refineries that discharge effluents to U.S. waters) and six were
indirect dischargers (refineries that direct effluents to
publicly owned treatment works).
Subsequent to the 1979 proposal/ EPA conducted a 60-day sampling
program at two petroleum refineries. The program involved the
sampling of raw and treated effluent every other day for a period
of sixty days. Pollutants analyzed included toxics/ but excluded
asbestos and pesticides. The objectives of this program were to:
(1) determine if there is a surrogate relationship between the
priority pollutants and one or more of the traditional pollutant
parameters (i.e. COD/ TOG); and (2) confirm the presence or
absence of specific priority pollutants.
In a separate program/ eight refineries were sampled by EPA
regional surveillance and analysis field teams.
Technology Evaluation
Three major efforts were undertaken to identify and evaluate
available control and treatment technologies. These include:
o A literature search that compiled available information on
the status of and advances being made by the industry
relative to wastewater handling and disposal.
o A review of the responses to the 1977 EPA Petroleum Refining
Industry Survey which determined the status of the industry
with regard to in-plant source control and end-of-pipe
treatment.
o A program to assess the toxic removal effectiveness of carbon
absorption treatment on a pilot scale. Granular activated
carbon was tested at six plants and powdered activated carbon
was tested in four of the same six refineries.
19
-------
Subsequent to the 1979 proposal, the Agency conducted two
additional studies. The objective of the first study was to
determine the technical feasibility of recycle/reuse of
wastewater at fifteen refineries. The second study involved the
acquisition of effluent concentration data from fifty refineries
that have biological treatment systems. Most of these refineries
have below - industry average flows. The purposes were to
determine if low - flow refineries discharge at higher pollutant
concentrations and whether a long term average phenol
concentration of 19 ppb is achievable.
The results of the above studies established a range of control
and treatment technologies available to the petroleum refining
industry. Section V discusses these studies in greater detail.
Detailed discussion of BPT treatment technology is not presented
in this document. It is presented in the 1974 Development
Document.
Cost Development
Information on costs, energy requirements and non-water quality
environmental impacts associated with the control and treatment
technologies was compiled at the time of the 1979 proposal. The
preamble to the 1979 proposal presented estimates of the cost of
recycle/reuse for comparison. The Agency confirmed these
estimates of the cost of flow reduction via recycle/reuse during
the 15 refinery study conducted after the 1979 proposal.
Results of these programs are presented in Section III on
industry profile, Section V on waste characterization, Section
VII on technology assessment and Appendix A on cost of treatment
systems.
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SECTION III
DESCRIPTION OF THE INDUSTRY
INTRODUCTION
The purpose of this section is to provide a brief description of
the petroleum refining industry. This description is presented
in two parts:
1) the overall industry profile; and
2) the unit manufacturing processes.
The industry profile includes a general description of the
industry, a description of refinery distribution in the United
States, and data related to the growth anticipated for this
industry.
The information presented on unit manufacturing processes
includes an overview of refining process operations. Also
included is information on unit operations, and wastewater
characteristics, related to some 20 individual processes.
INDUSTRY PROFILE
General Description of. the Industry
This effluent guidelines study 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. SIC Code 2911 includes facilities primarily engaged in
producing hydrocarbon materials through the distillation of crude
petroleum and its fractionation products. There are numerous and
varied intermediate and finished products which can be refined
from crude petroleum. Table III-l presents a listing of some of
the major products of the petroleum refining industry.
It is important to note that the production of crude petroleum
and natural gas, the production of natural gasoline and other
natural liquid hydrocarbons, and operations associated with such
production are not included in SIC 2911. These are covered by
SIC Codes 1311 and 1312, respectively, and therefore, are not
within the scope of this subject. 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 affects a refinery's pollution control
activities, 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
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auxiliary processes which are an integral part of refinery
operations. Some of these include soap manufacture for the
production of greases, steam generation, and hydrogen production.
Refinery Distribution
As of January 1, 1981, there were a total of 303 petroleum
refineries operating in the United States, excluding Puerto Rico,
the Virgin Islands, and Guam. These refineries are operating
with a combined capacity of approximately 3.08 million cubic
meters per stream-day (19.37 million barrels per stream-day) of
crude oil processing. The individual capacities of the 303
refineries range from about 30 cubic meters per stream-day (190
barrels per stream-day) at the smallest plant to about 106,200
cubic meters per stream-day (668,000 barrels per stream-day) at
the largest plant.
Since it's inception, the U.S. refining industry has continued to
build bigger and more efficient plants as new technology has
developed over time. The average U.S. refinery capacity per
plant increased from 43.3 thousand barrels per day to 55.6
thousand barrels per day from January 1, 1967, to January 1,
1973. 53 additional U.S. refineries were in operation on January
1, 1981, versus January 1, 1975. The number of plants in
operation with capacity greater than 100 thousand barrels per day
increased by only seven (from 46 to 53) over this time period.
Most of the new plants placed in operation were small. Average
U.S. refinery capacity increased only from 56.0 to 57.3 thousand
barrels per day from January 1, 1975, to January 1, 1981. Many
of the small new plants built in this time period are among the
fifty that have discontinued operations during the last year.
Additional information on industry profile is provided in: Table
III-2 on refinery capacity; Table III-3 on 1980 consumption of
petroleum products; Table II1-4 on sources of supply for U.S.
petroleum feedstocks; Table III-5 on characteristics of crude oil
from major fields around the world; and Table II1-6 on trend in
domestic petroleum refining from 1975 to 1981.
Within the United States, most of the refining capacity is
concentrated in two areas: major crude production areas, such as
Texas, California, Louisiana, Oklahoma, and Kansas; and major
population areas, such as Pennsylvania, Illinois, Ohio, New
Jersey, and Indiana. Table II1-2 lists the number of refineries,
total crude refining capacity, and major process capacities in
the United States by state. The geographical distribution of
these refineries is displayed in Figure III-l.
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Anticipated Industry Growth
The U.S. refining industry has experienced a dramatic reversal of
historical growth trends as a result of the reduction in
consumption of petroleum products that has taken place since
1978. U.S. crude oil runs peaked at 14.7 million barrels per day
in the calendar year 1978. Runs have decreased each year since
then reaching 12.5 million barrels per day for the calendar year
1981. In early 1982 runs have dropped to below 11.5 million
barrels per day, representing percentage capacity utilizations in
the low 60's. More than fifty plants have discontinued
operations in the U.S. over the past year. It is expected that
U.S. refinery activity will recover somewhat. The 1981 DOE
Annual Report to Congress projects U.S. crude runs at 14.4
million barrels per day in 1985 and 13.4 million barrels per day
in 1990 for their mid-oil price scenarios. The above forcasts of
U.S. refinery activity indicate that very little, if any, new
refinery facilities will be built at undeveloped sites over the
next decade. However, it will be necessary for U.S. refiners to
modernize and expand downstream facilities at existing refinery
sites to allow increasingly heavier and higher sulfur crude oils
to be processed into a product mix which emphasizes production of
the lighter and higher quality products that will be demanded by
the marketplace.
UNIT MANUFACTURING PROCESSES
Overview of Refining Processes
A petroleum refinery is a complex combination of interdependent
operations engaged in separating crude molecular constituents,
molecular cracking, molecular rebuilding, and solvent finishing
to produce petroleum-derived products, such as those shown in
Table III-l. There are a number of distinct processes that may
be utilized by the industry for the refining of crude petroleum
and its fractionation products. The EPA questionnaire survey of
the petroleum refining industry, conducted during 1977,
identified over 150 separate processes being used. These
processes, along with the number of refineries employing each,
are presented in Table II1-7.
Although only about 150 separate processes were identified in the
petroleum refining industry, there are many more process
combinations that may be employed at an individual refinery,
depending upon the type of crude being processed, the type of
product being produced, and the characteristics of the particular
refinery.
Process Descriptions and Wastewater Characteristics
The characteristics of the wastewater differ considerably for
different processes. Considerable information is available that
can be used to make meaningful qualitative interpretations of
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pollutant loadings from refinery processes. The results of
analysis of available information is presented in Table II1-8
which shows the major sources of pollutants within a refinery.
In order to characterize the wastes for each of the industry
subcategories, it is essential to focus on 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 quite different water usages associated with it. The
types and quantities of contact wastewater are, therefore,
directly related to the nature of the various processes. This
implies that the types and quantities of wastewater generated by
each plant's total production mix are unique. Brief process
descriptions and delineation of wastewater sources for the more
important refining processes are presented below.
LL Crude Oil and Product Storage. 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.
Wastewater pollutants 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 levels and to a lesser
extent, BOD5.. 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 wastewaters and iron sulfide suspended solids. Finished
product storage can produce high BOD£, alkaline wastewaters, as
well as tetraethyl lead. Tank cleaning can contribute large
amounts of oil, COD, and suspended solids, and a minor amount of
BOD5.. Leaks, spills, and open or poorly ventilated tanks can
also be a source of air pollution, through evaporation of
hydrocarbons into the atmosphere.
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2. Ballast Water Storage. Tankers which are used to ship
intermediate and final products generally discharge ballast
(approximately 30 percent of the cargo capacity is generally
required to maintain vessel stability).
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, brackish
water and sediments are present, contributing high COD and
dissolved solids loadings to the refinery wastewater. These
wastewaters 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 wastewater treatment
system, and potentially constitutes a "shock" load to the
treatment system.
li. Crude Desalting. 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, wastewater 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 II1-2.
Much of the bottom sediment and water (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 wastewater stream from a desalter contains
emulsified oil occasionally free oil, ammonia, phenol, sulfides,
and suspended solids. These pollutants produce a relatively high
BOD5, and COD. This wastewater also contains enough chlorides and
other dissolved materials to contribute to the dissolved solids
problem in the areas where the wastewater is discharged to fresh
water bodies. There are also potential thermal pollution
problems because the temperature of the desalting wastewater
often exceeds 95°C (200°F).
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4_._ 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 include prefractionation and
atmospheric fractionation, vacuum fractionation, and three-stage
crude distillation.
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.
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 atmospheric distillation amounts to
roughly one-third (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 II1-3. 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; and
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.
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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 sidestream
products: naphtha, 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 sidestrearns. The two
sidestreams are combined to form catalytic cracking feedstocks,
with an asphalt base stock withdrawn from the tower bottom.
Wastewater 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
being processed. It also contains significant amounts of oil,
chlorides, mercaptans, and phenols.
A second waste source is discharge 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.
1L. Thermal Cracking. 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 a certain amount of heavy fuel oil
and coke formed by polymerization and condensation reactions.
The major source of wastewater 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 oils and fractions
and may be high in BOD5,, COD, ammonia, phenol, and sulfides, and
may have a high alkalinity.
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6. Catalytic Cracking. 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 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 III-4.
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 4) 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 and 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.
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.
The major pollutants resulting from catalytic cracking operations
are oil, sulfides, phenols, cyanides, and ammonia. These
pollutants produce an alkaline wastewater with high BOD5_ and COD
concentrations. Sulfide and phenol concentrations in the
wastewater vary with the type of crude oil being processed, but
at times are significant. Regeneration of spent catalyst may
produce enough carbon monoxide and catalyst fines to constitute
an air pollution problem.
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7_. Hydrocrackinq. 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.
At least one wastewater 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 H2S will dissolve in the wastewater being collected. This
water from the separator and fractionator will probably be high
in sulfides, and possibly contain significant quantities of
phenols and ammonia.
8_._ Polymerization. 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° - 224°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.
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 wastewater is high in sulfides, mercaptans, and
ammonia. These materials are removed from the feedstock in
caustic acid.
9. Alkvlation. Alkylation is the reaction of an isoparaffin
Tusually 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
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catalyst is recycled. The hydrocarbon stream is passed through a
caustic and water wash before going to the fractionation section.
The major discharges from sulfuric acid alkylation are the spent
caustics from the neutralization of hydrocarbon streams leaving
the sulfuric acid alkylation reactor. These wastewaters 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 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 fluorosilicates has caused line plugging
and similar problems. The major sources of waste material are
the overhead accumulators on the fractionator.
10. Isomerization. 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 use 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.
Isomerization wastewaters present no major pollutant discharge
problems. Sulfides and ammonia are not likely to be present in
the effluent. Isomerization wastewaters should also be low in
phenolics and oxygen demand.
11. Reforming. Reforming converts low octane naphtha, heavy
gasoline, and napthene-rich stocks to high octane gasoline
blending stock, aromatics for petrochemical 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
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isomerization and dehydrocyclization of paraffins. All three
reactions result in high 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- effluent 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.
Reforming is a relatively clean process. The volume of
wastewater flow is small, and none of the wastewater streams have
high concentrations of significant pollutants. The wastewater is
alkaline, and the major pollutant is sulfide from the overhead
accumulator on the stripping tower used to remove light
hydrocarbon fractions from the reactor effluent. The overhead
accumulator catches any water that may be contained in the
hydrocarbon vapors. In addition to sulfides, the wastewater
contains small amounts of ammonia, mercaptans, and oil.
12. 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
wastewaters which contain small amounts of the solvents employed.
However, these are usually minimized because of the economic
incentives for reuse of the solvents.
Solvent Deasphalting
The primary purpose of solvent deasphalting 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 recovered 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 drawing removes wax from lubricating oil stocks by
promoting crystallization of the wax. Solvents which are used
include: furfural, phenol, cresylic acid - propane (Duo-Sol),
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liquid sulfur dioxide (Eleleanu process), B-B - dichloroethyl
ether, methyl ethyl ketone, nitrobenzene, and sulfur-benzene.
The process yields deoiled 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) is
commonly used for the solvent extraction.
The major potential pollutants from the various solvent refining
subprocecses are the solvents themselves. Many of the solvents/
such as phenol/ glycol, and amines, can produce a high BOD5..
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 wastewater is from the bottom of fractionation
towers. Oil and solvent are the major wastewater constituents.
13. Hvdrotreatino. 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.
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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 M3_ (200 scf) per barrel of charge.
Principal hydrotreating subprocesses are used as follows:
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; and
6. Naphtha saturation.
The strength and quantity of wastewaters 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.
14. Grease Manufacturing. 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.
Only very small volumes of wastewater are discharged from a
grease manufacturing process. A small amount of oil is lost to
the wastewater system through leaks in pumps. The largest waste
loading occurs when the batch units are washed, resulting in soap
and oil discharges to the sewer system.
33
-------
15. Asphalt Production. 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.
Wastewaters from asphalt blowing contain high concentrations of
oils and have high oxygen demand. Small quantities of phenols
may also be present.
16. Drying and Sweetening. 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.
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 neutral oils. Sulfidic spent
caustics are rich in sulfides, but do hot contain any phenols.
These spent caustics have very high BOD5. 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 Na2 Pb02) in doctor sweetening. These
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.
34
-------
17. Lube Oil Finishing. 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.
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 wastewater stream containing acid, sulfur compounds,
and emulsified oil.
Clay treatment results in only small quantities of wastewater
being discharged to the sewer. Clay, free oil, and emulsified
oil are the major waste constituents. However, the operation of
clay recovery kilns involves potential air pollution problems of
hydrocarbon and particulate emissions. Spent clays usually are
disposed of by landfill.
18. Blending and Packaging. Blending is the final step in
producing finished petroleum products to meet quality
specifications and market demands. The largest volume operation
is the blending of various gasoline stocks (including alkylates
and other high-octane components) and anti-knock (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.
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 gasolines and
it must be carefully handled because of its liigh toxicity.
Sludges from finished gasoline storage tanks can contain large
amounts of lead and should not be washed into the wastewater
system.
35
-------
19. Hydrogen Manufacture. 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 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 passed 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 in 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.
Information concerning wastes from this process is 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.
20. 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
36
-------
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 noncontact 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;
and
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 wastewater 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 makeup 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 these can
occur in natural waters, and some can result from condensate
return line corrosion or even from makeup 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.
The quantity and quality of the blowdown from 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 depends 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.
37
-------
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 noncontact 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.
Noncontact cooling water also is normally supplied to several
processes from the utilities area. The system is either a loop
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 0.454 kg (1 Ib) of water.
Therefore, if 45.4 kg (100 Ibs) of water are introduced at the
tower inlet and 0.454 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 5.5°C (10°F). The common
rule of thumb is 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
temperture 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 the hot water
from the processes. With the closed system, makeup water is
required to replace evaporation loss at the tower.
38
-------
Two other types of water losses also occur. The first is drift,
which is droplet carryover in the air as contrasted to evaporate
loss. The cooling tower industry has a standardized 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 any 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 makeup 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 to maintain a solids concentration in the
recirculated water of three to four times that of the makeup
water.
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.
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. Acceptable amounts of
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
noncontact steam uses. Boiler operation generally requires the
use of antifoam agents and steam separation equipment.
39
-------
Boiler Water Concentration Limits
Parameter Boiler Pressure/ atm.
21.5-31.6 31.7-41.8 41.9-52.0
Total Solids
(rag/L) 6,000 5,000 4,000 2,500
Suspended Solids
(mg/L) 1,000 200 100 50
Total Alkalinity
(mg/L) 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 pre-
cedes the ion exchange operation.
40
-------
TABLE III-l
INTERMEDIATE AND FINISHED PRODUCTS
PRODUCED BY 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 (Distillate and Residual)
Gas (Refinery or Still Oil)
Gases (LPG)
Gasoline (except Natural Gasoline)
Greases (Petroleum, Lubricative, Mineral Jelly, 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
41
-------
TABLE II1-2
REFINING CAPACITY Of PE1ROLEUH REFINERIES IN THE U.S. BY StATE OS OF JANUARY 1. 1981 (167)
PO
Charge capscity, b/sd
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Deleware
Florida
Georgia
Hawaii
Illinois
Indiana
Kansas
Kentucky
Louisiana
Maryland
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
Nsw Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Tennessee
Tex aa
Utah
Virginia
Washington
Nest Virginia
Wisconsin
Wyo.lng
TOTAL
NOTES.
No. - Crude
plants • /ad
6
4
1
4
43
1
2
2
2
11
a
11
4
33
2
5
3
a
i
6
i
t
i
5
7
3
1
3
7
12
1
9
1
59
8
1
7
2
1
13
303
24,039
21,526
1,033
10,675
404,303
10,254
23,846
7,076
5,087
19,955
202,544
103,203
77,090
40,219
411,344
4,886
21,931
35,753
62,827
17,646
25,753
979
715
2,715
113,326
19,266
23,159
1,936
10,842
97,926
93,519
2,510
124,458
7,869
866,619
27,449
8,743
65,157
3,672
7,440
34,590
3,079,333
Capacity -
b/ad
151,218
135,410
6,500
67,150
2,769,725
64,500
130,000
44,513
32,000
125,526
1,274,104
649,200
484,933
253,000
2,587,555
30,736
137,594
224,905
395,214
111,000
162,000
6,160
4,500
13,684
712,878
121,190
145,684
12,495
68,200
616,000
588,281
15,789
782,900
49,500
5,451,461
172,668
55,000
409,867
23,100
46,800
217,589
19,370,529
Vacuue
dlstlllatln
31,500
3,000
26,100
1,188,100
27,500
90,700
a, ooo
28,000
429,499
285,500
143,710
118,000
874,542
14,300
26,000
121,000
158,300
40,000
51,100
2,400
3,000
347,952
21,900
43,000
208,500
194,763
16,000
332,850
12,000
1,804,904
45,500
29,000
164,015
10,875
20,500
74,650
6,996,660
Ihernal
i operations
459,683
3,300
44,000
133,600
23,000
50,000
4,000
215,633
23,000
7,000
13,500
10,000
35,944
1,500
1,100
27,400
77,866
394,588
8,500
15,000
38,000
13,444
1,600,058
- Cat cracking -
Fresh feed Recycle
15,000
549,000
7,000
62,000
22,000
449,110
212,000
177,550
70,000
876,677
43,000
85,500
72,200
42,000
50,100
2,400
231,444
18,200
42,000
26,000
205,500
206,700
216,300
30,000
1,555,565
54,000
28,000
94,833
9,700
77,477
5,531,256
5OO
60,200
500
15,000
88,640
12,700
46,150
21,000
56,983
6,100
7,900
6,860
12,000
14,700
500
46,333
5,620
12,900
5,200
43,300
32,400
23,300
12,000
273,899
11,660
5,000
28,999
1,000
19,233
870,577
Cat
reforming
23,500
10,000
10,000
578,738
19,000
42,000
12,000
319,677
123,700
121,400
49,000
461,713
34,400
34,600
95,400
16,000
44,200
750
79,944
25,750
23,000
12,500
170,700
127,222
232,900
9,300
1,175,109
23,200
9,500
112,722
6,400
10,000
37,094
4,051,419
Cat hydro-
cracking
7,500
331,722
20,000
66,500
3,200
82,200
68,000
4,900
81,000
5,000
55,000
139,666
1,100
46,000
911,788
Cat hydro-
refining
13,000
369,000
33,000
44,500
40,000
216,500
12,500
69,000
56,000
14,000
110,000
20,000
34,500
26,000
182,000
871,000
5,500
20,500
5,800
16,644
2,159,444
Cat hydro-
treating
38,000
10,000
15,300
834,866
20,200
110,000
15,500
582,753
223,660
175,400
100,500
602,910
39,700
78,800
53,450
61,500
97,550
325,043
31,050
39,500
13,500
172,500
158,277
331,600
29,500
2,150,597
33,600
26,500
172,165
7,800
10,000
63,394
6,625,115
Production capacity, b/ad
Alkyle- Aromatice-
tion isonsrlzstloi
4,500
95,644
8,000
4,500
107,098
30,000
50,400
11,000
162,188
7,500
14,400
14,400
5,000
10,200
17,133
2,940
2,000
2,800
36,800
47,733
43,900
3,600
251,698
11,150
25,333
1,700
7,950
979,567
10,500
3,595
1,500
7,300
21,200
3,400
18,500
36,500
6,000
4,600
28,000
7,000
500
10,900
16,305
9,900
254,220
3,750
2,900
1,500
448,070
n Lubes
3,950
21,570
5,600
8,900
5,400
5,000
30,600
6,500
7,500
2,100
9,800
27,700
97,522
6,600
1,830
240,572
Asphalt
26,500
6,000
8,250
62,100
3,300
17,500
1,300
53,000
55,400
23,000
33,500
56,100
11,300
6,650
49,000
10,400
14,450
96,000
3,100
10,500
31,800
24,600
11,500
30,000
3,500
62,800
4,700
6,500
13,500
14,016
774,266
Hydrogen
(MMcfd)
837.7
0.6
72.0
2.5
95.5
20.0
73.0
14.0
109.0
16.7
72.0
10.0
48.5
3)2.0
62.0
1.2
1,766.7
Coke
(t/d)
16,6)6
180
1,500
5,210
1,200
1,855
6,930
1,300
320
800
310
975
1,250
1,750
6,975
350
875
2,910
125
51 ,451
m /ad - cubic neter* per »trea»-dey
b/sd - barrels per stream-day
-------
TABLE II1-3
1980 Consumption of Petroleum Products
Products 1980 Consumption, Million Cubic Meters Per Day
(Million Barrels Per Day)
Motor Gasoline 1.05 (6.6)
Aviation Fuels 0.17 (1.1)
Distillate Fuel Oil 0.46 (2.9)
Residual Fuels 0.40 (2.5)
All Other Products 0.62 (3.9)
Total Consumption 2.70 (17.0)
Source - DOE Monthly Energy Review
43
-------
TABLE II1-4
Sources of Supply for U.S. Petroleum Feedstocks
Source
Crude Oil Imports
Residual Fuel
Other Imports
Exports
Supply, Million Barrels Per Day
: Oil Production
•al Gas Liquids
irts
Imports
Sources 1
>ply
1980
8.6
1.6
5.2
.9
.7
(.5)
.5
17.0
1985 (Projected)
7.9
1.4
5.1
•^1 1
^s i • 1
(.1)
.4
15.8
processing gain, stock change, etc.
Sources - 1980 - DOE Monthly Energy Review
1985 (Projected) - DOE Annual Report to Congress EIA/1980 - low
price scenario
44
-------
TABLE III-5 Page 1 of 3
Characteristics of Crude Oils from Major Fields Around the World
Country
Abu Dhabi
Murban
Algeria
Hassi Mesaaoud
Canada
Alberta
Bonnie Glen
Golden Spike
Judy Creek
Pembina
Swan Hills
Saskatchewan
Midale
Weyburn
Indonesia
Minas
Iraq
Basrah Light
Libya
Brega
Mexico
Reform*
Maya
Norway
Ekofisk
Saudi Arabia
United States
Alaska
Cook Inlet
Prudhoe Bay
Arkansas
Soackover
Gravity. API
39.4
44.7
_
34 - 44
36 - 39
42 - 43
32 - 37
41
28-32
24 - 33
35.2
33.9
40.4
33.0
22.0
36.3
27 - 39
36
26.8
22.2
Sulfur, Percent
0.74
0.13
_
0.25
0.23
0.42
0.80
1.89
2.12
0.09
2.08
0.21
1.56
3.4
0.21
1.0 - 2.8
0.1
1.04
2.10
Nitrogen. Percent
_
—
_
—
__
—
-—
—
—
—
— •
_
-—
—
—
—
0.080
45
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TABLE II1-5
Page 2 of 3
California
Elk Hills
Huntingcon Beach
Kern River
Midway-Sunset
San Ardo
Wilmington
Colorado
Rangely
Kansas
Bernis Shutts
Louisiana
Bayou Sale
Caillou Is).
Golden Meadow
Grand Bay
Lake Bar re
Lake Washington
West Bay
Bay Harchand 81k. 2
Main Pass Blk. 69
South Pass Blk. 24
South Pass Blk. 27
Timballer Bay
West Delta Blk. 30
Mississippi
Baxtervill*
New Mexico
Vacuum'
Oklahoma
Golden Trend
Texas
Anahuac
Conroe
Diamond M
East Texas
Hastings
Hawkins
Headlee
Kelly Snyder
Level land
Midland Farms
PanhandIe
Seeliason
Gravity. API
22,5
22.6
12.6
22.6
11.1
22.1
34.8
34.6
36.2
35.4
37.6
35
40.4
28.2
32.1
20.2
30.6
32.3
35.6
34.4
27
17.1
35
42.1
33.2
37.6
45.4
39.4
31.0
26.8
51.1
38.6
31.1
39.6
40.4
41.3
Sulfur. Percent Nitrogen. Percent
0.68
1.57
1.19
0.94
2.25
1.44
0.56
0.57
0.16
0.23
0.18
0.31
0.14
0.37
0.27
0.46
0.25
0.26
a. 18
0.33
0.33
2.71
0.95
0.11
0.23
0.15
0.20
0.32
0.15
2.19
<0.10
0.29
2.12
0.13
0.55
<0.10
0.472
0.048
0.604
0.913
0.073
0.162
0.040
0.02
0.146
0.071
0.098
0.068
0.069
0.081
0.09
0.111
0.075
0.041
0.02
0.076
0.083
0.066
0.136
0.080
.067
0.014
46
-------
TABLE II1-5 Page 3 of 3
Gravity, API Sulfur, Percent Nitrogen, Percent
torn O'Connor 31.1 0.16 0.03
Wasson 31.9 1.40 0.47
Webster 29.3 0.21 0.046
Yates 30.2 1.54 0.150
Utah
Aneth 40.4 0.20 0.059
Venezuela
Boscan 10.3 5.53 —
Tia Juana Medium 24.0 1.6 —
Lagomedio 32.6 1.23 —
47
-------
00
TABLE II1-6
Trend in Domestic Petroleum Refining from 1975 to 1981
Crude Capacity, bbl/CD
Total Companies
Total Refineries
CD
city MOO Mbbl/CD
iclty <35 Mbbl/CD
1 >100 Mbbl/CD
(Fifty States)
January 1, 1975
14,737,139
140
263
46
144
8,762.400
January 1, 1981
18,119,160
190
316
53
181
11,043,400
Percent
Change
+23
+36
+20
+15
+26
+26
Refineries
Average Refinery Capacity, bbl/CD 56,035 57,339 +2
Sources: DOE Annual Survey, EIA - 0111 (81)
DOI Bureau of Mines Annual Survey (1975)
-------
TABLE III- 7
Page 1 of 6
LIST OF PROCESSES IDENTIFIED FROM THE 1977 INDUSTRY SURVEY
BY EPA PROCESS NUMBER
Number of
Refineries
General Processes Units Using Process
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
Atmospheric Crude Distillation
Crude Desalting
Vacuum Crude Distillation
Visbreaking
Thermal Cracking
Fluid Catalytic Cracking
Moving Bed Catalytic Cracking
*'
HF Alkylation }•{
Hydrocracking '6| .
Kydroprocessing I"'
Catalytic Reforming
Catalytic Polymerization
Aromatic Petrochemicals Production
Delay Coking *c'
Fluid Coking
Isomerization
Asphalt Production ( .,
Eliminated
Eliminated
Lube Oil Processes
MBD
MBD
MBD
MBD
MBO
MBD
MBD
MBO
MBD
MBO
MBD
MBD
MBD
MBD
MBO
MBD
MBD
MBO
MBD
MBO
MBD
21. Hydrofining, Hydrofinishing, Lube
Hydrofining CO
22. White Oil Manufacture MBO
23. Propane Dewaxing, Propane Deasphalting MBD
Propane Fractioning, Propane Deresining
24. Duo Sol, Solvent Treating, Solvent MBD
Extraction, Duotreating, Solvent
Dewaxing, Solvent Oeasphalt
25. Lube Vac Twr, Oil Fractional on, Batch MBD
Still (Naphtha Strip), Bright Stock
Treating
26. Centrifuge S Chilling MBD
27. MEK Dewaxing, Ketone Dewaxing, MBO
MEK-Toluene Dewaxing
28. Oeoiling (Wax) MBD
29. Naphthenic Lube Production MBD
30. S02 Extraction MBD
31. See Other Processes MBO
32. See Other Processes MBO
33. See Other Processes MBD
34. Wax Pressing MBD
35. Wax Plant (with Neutral Separation) MBD
36. Furfural Extracting MBD
37. Clay Contacting - Percolation MBO
38. Wax Sweating MBO
39. Add Treat MBD
40. Phenol Extraction MBD
246
191
163
11
18
118
20
59
65
38
122
166
36
37
45
6
19
104
19
6
25
10
26
4
24
11
10
3
2
2
16
19
5
6
11
49
-------
TABLE III -7 Page 2 of 6
Treating and Finishing
41. Bender Treating MBD 33
42. Petreco Locap Gasoline Sweetening MBD 2
43. Asphalt Oxidizing (d) MBD 49
44. Caustic of KOH Treating, For example: MBD 162
Caustic of KOH Treating for: HgS,
Mercaptan, Cresyllc Add, Naphthenic
Add, PWS MEA for COS Removal, etc.
45. Water Wash MBD 99
46. Mercapflning, Pentane Mercapflning MBD 2
47. Merox Treating (i.e., Liquid-Liquid MBD 114
Extraction, Liquid-Liquid Sweetening,
and Fixed Bed)
48. C3 4 C4 Scrubbing, Glrbitol Treating MBD 46
49. Llnde Process (Charge) MBD 7
50. Doctor Treating MBD 17
51. Sulfuric Add Treating MBD 10
52. Unlsol Treating MBD 2
53. SO- Treating , , MBD 3
54. HyoYotreatlng (b) MBD 62
55. Perco (Copper Chloride), Copper Slurry MBD 25
56. Inhibitor Sweeting MBD 44
57. KCr MBD 1
58. Clay Treating, Bauxite Treating MBD 93
59. Hypochlorlte Sweetening MBD 4
60. Salt Brightening or Drying MBD 87
61. Sulfinol MBD 3
62. Unclassified Treating and Finishing MBD 9
(Charge)
Petrochemicals
63. Isobutane Production MBD 16
64. Carbon Black Feedstock Production MBD 4
65. Heptene Production MBD 2
66. Sulfblane Process (Charge) MBD 5
67. OxoAlcohol MBD. 1
68. Naphthalene Production MBO 1
69. Butadiene MBD 3
70. Aliphatics MBD 8
71. Cumene (Charge) MBD 10
72. Paraxylene (Charge) MBD 7
73. Xylene Fractionation (Charge) MBD 11
74. Polypropene, Polyisobutylene, Poly MBO 8
Feed Preparation, Trimer-Tetramer
Production
75. ' Phenol, Oxonation Additives Mfg., MBD 4
Polystyrene Resin, Lube Oil Depressant
Production
76. Eliminated MBD
77. Cresylic Acid MBD 2
78. Styrene Production MBD 2
79. Naphthenic Acid MBD 5
80. Alpha Olefins MLBD 1
81. Nitric Acid STD 1
82. Phtahalic Anhydride Production MBD 2
50
-------
TABLE III -7 Page 3 of 6
83. Butyl Rubber MLBD 1
84. Polypropylene MBO 2
85. Cyclohexane Production MBD 8
86. Solvent Hydrotreater (b) MBD 7
87. Hexane-Heptane Unit MBD 1
88. Unclassified Petrochemicals MBD 7
Other Processes
31. Feed Preparation MBO 1
32. 200°F Softening Point Unfluxed Asphalt MBD 5
(d)
33. Compounding MBD 29
89. Asphalt Emulsifying W MBD 30
90. Sulfur Recovery, Sulfur Production (') LTD 82
91. Hydrogen, Reformer Feed Prep, Steam MBD 37
Methane Reformer, Partial Oxidation
(Liquid Units) (9)
92. Gas Plant (Liquid Units) (9) MBO
93. DEA Treating and Other Amlne Treating MBD 37
Systems (Liquid Charge) (h) 59
94. C02 Recovery, C02 Production MLBD 7
95. Furfural MBD 0
96. Oubbs Pitch MBD 1
97. Solvent Decarbonizing MBO 7
98. HydrodemethylatlonW MBO 5
99. Catalyst Manufacture STD 3
100. Gasoline Additives Production MBO 2
101. Linear Paraffins MBD 1
102. Butadiene Concentration MBD 0
103. Nonene Production MBD 4
104. Ammonia Plants Production(«) MLBD 6
500. Light Ends Recovery MBD 7
501. M1sc. Fractionatlon and Distillation MBD 10
502. Incineration MLBH 4
503. Sulfuric Acid Plant STD 5
504. Sodium Hydrosulfide MBD 1
505. Coke Calciner STD 0
506. Lube and Fuel Additives MBO 5
508. Sulfonate Plant MBO 1
509. Marasol Splitter MBD 1
510. Aromatic Hydrogenatlon MBO 1
511. Aromatic Vacuum Unit MBD 1
512. Sour Concetrate Unifiner MBD 1
513. Naphtha Splitter MBD 4
514. Naphtha Unifining MBD 1
518. Isobutylene MLBD 2
519. NEK MBD 1
520. Secondary Butyl Alcohols MBD 1
521. Mesityl Oxide MBD 1
522. MIBK MBD 1
523. Isophorone MBD 1
524. SNG MBD 1
525. Petroleum Pitch MBD 1
526. Hydroalkylation of Aromatics MBO 1
528. Naphtha Rerun MBD 2
529. Wax Slabbing MBD 3
531. Rust Preventives MBD 1
51
-------
TABLE III - 7
Page 4 of 6
532. Petrolatum Oxidation MBO
533. Calcium Chloride Drying MBD
534. LPG M8D
535. Fuels Deasphalting MBO
536. Ethylene MLBO
537. Resin Former Stock MBO
539. Rerun Units MBO
540. Mineral Spirits MBO
541. Udex MLBO
542. Diallylamine MLBD
544. Ethyl flmyl Ketone MLBD
545. lonol Antioxidant MLBD
546. Tertiary Butyl Alcohol MLBD
547. Naphthenic Acids MLBD
548. Octyl Formol Alkylate MLBD
549. Octyl Formol Condensate MLBO
550. Perma 16 MLBD
551. Polyisobutylene Chloride MLBD
552. Automotive Spec Detergent MLBO
553. Pentoxone MLBD
554. Sodium Sulfonates MLBO
555. Tertiary Butyl Toluene MLBD
556. TBBA - Caustic Extraction MLBO
557. TBBA - Precipitation MLBD
558. Tergols MLBO
559. Dehydrating MBD
560. Desiccant Manufacture STD
562. Oxidate Manufacture MBO
563. Grease Mfg. v. Allied Products MBO
564. Tertiary Amylenes MBD
565. Scot Tail Gas MMSCFD
566. Propylene MBD
567. Acetone MBD
568. Misc. Blending and Packaging MBO
569. Hydrogen, Reformer Feed Prep, Steam MMSCFD
Methane Reformer, Partial Oxidation
(Gas Units) (g)
570. Gas Plant (Gas Units) (g) MMSCFD
571. DEA and Other Amine Treating Systems MMSCFD
(Gas Charge) (n)
Number of plants responding to survey
1
2
6
1
2
1
4
3
4
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
3
1
2
6
3
4
27
20
41
262
52
-------
TABLE III -7 Page 5 of 6
Notesi
(a) Process Nos. 20 and 76 have been eliminated to avoid multiple account-
Ing of process rates. Capacities and rates previously assigned to
these processes have been included wth Process Nos. 8 and 9, where
applicable.
(b) Multiple accounting of process rates may have occurred in the original
survey response for the following hydrogen processes:
10. Hydrocrackfng 54. Hydrotreating
11. Hydroprocessing 86. Solvent Hydrotreater
21. Hydrofinlng, Hydrofinishing 98. Hydrodemethylation
Lube Hydrofinlng
Revised values for Process Nos. 10 and 11 Include only capacities and
rates which cannot be Included in the other four processes. Process
No. 11 should Include hydrotreating of upstream feedstocks (I.e.,
hydrodesulfurl ration of catalytic reformer feed), while Process No. 54
should include hydrotreating of product.
(c) To obtain consistent units of 1000 barrels/day, reported charge rates
to Process No. 15 have been converted as follows:
tons/day x 0.00667 » 1000 barrels/day
(d) To avoid multiple accounting of process rates, asphalt processes have
been specifically revised to Include the following:
18. Asphalt Production 43. Asphalt Oxidizing
32. 200°F Softening Point 89. Asphalt Emulsifying
Unfluxed Asphalt
Reported capacities and rates have been reassigned to the appropriate
process.
(e) Multiple accounting of process rates occurred in the original response
for Process Nos. 19 and 104. To resolve this problem, Process No. 19
has been eliminated and the capacities and rates previously included
there have been reassigned to Process No. 104.
(f) To obtain consistent units of long tons/day, reported values for
Process No. 90 have been converted (using specific gravity of 1.803)
as follows:
1000 barrels/day X 282 * long tons/day
(g) Rates for Process Nos. 91 and 92 are in liquid units, while rates in
gaseous units for the same processes are included in Nos. 569 and 570.
(h) Liquid charge rates have been included in Process No. 93 for all amine
treating (DEA, MEA, etc), while gas charge rates have been assigned to
Process No. 571.
Unit Abbreviations:
MBD - thousand barrels per day
MLBO - thousand pounds per day
53
-------
TABLE III -7 Page 6 of 6
STO - short tons per day
LTD - long tons per day
MLBH - thousand pounds per hour
MMSCFD - million standard cubic feet per day
54
-------
TABLE III - 8
Qualitative Evaluation of Waatewater Flow and characteristics
Production
Processes
Crude oil and
Product Storage
Crude Desalting
Crude Distil-
lation
Theraal Cracking
Catalytic Cracking
Bydrocracklng
Polymer ixat ion
Alkylatlon
Isoa«risation
cn
Reforming
Solvent Refining
Asphalt Blowing
Dewaxlng
Rydrotreating
Drying and
Sweetening
XXX - ft
by Fundamental
Refinery Processes
Baulslfled
Plow
XX
XX
XXX
X
XXX
X
X
XX
X
X
X
XXX
X
X
XXX
lajor
BOD
X
XX
X
X
XX
X
X
0
XXX
XXX
X
XXX
COD
XXX
XX
X
X
XX
X
X
0
X
XXX
XXX
X
X
Contribution,
Phenol
X
X
XX
X
XXX
XX
0
0
X
X
X
X
XX
XX -
Sulfide
XXX
XXX
X
XXX
XX
X
XX
X
0
0
XX
0
Moderate
Oil Oil
XXX XX
X XXX
XX XXX
X
X X
X 0
X 0
X 0
X
XXX
X 0
0
0 X
Contribution,
pH Tess>. A*Bonia
000
X XXX XX
X XX XXX
XX XX X
XXX XX XXX
XX XX
XXX
XX X X
0 X X
X 0
XX XX
XX 0 X
X - Minor Contribution,
Chloride Acidity Alkalinity Susp. Solids
0 XX
XXX 0 X XXX
x o x x
x o xx x
X 0 XXX X
X X 0 X
XX XX 0 XX
000 0
0 X
0 0 X 0
o x x xx
0 - Insignificant Blank - No Data
-------
in
Alaska - 4
Hawaii - 2
FIGURE III-l
GEOGRAPHICAL DISTRIBUTION OF PETROLEUM REFINERIES
IN THE UNITED STATES, AS OF JANUARY 1, 1981
-------
PROCESS
WATER
Ul
—I
DESALTED
CRUDE
»-
EFFLUENT
WATER
»».
HEATER
EHULSIFIER
FIGURE III-2
CRUDE DESALTING
(ELECTROSTATIC DESALTING)
-------
en
00
phalter Ft«d
FIGURE IIJ-3
CRUDE FRACTIONATION
niSTJT.LATION - THREE STAGES)
-------
tn
UD
PRESSURE
REDUCING
ORIFICE
CHAMBER
O
FLUE GAS STEAM
GENERATOR
COMBUSTION AlK
GAS AND GASOLINE TO
GAS CONCENTRATION PLANT
MAIN COLUMN
LIGHT CYCLE GAS OjL
HEAVY CYCLE CAS OIL^
.HEAVY RECYCLE CHARGE
CtARJMED SLURRY r_
SLURRY
SETTLER
COMBINED REACTOR
CHARGE
RAW OIL
SLURRY CHARGE
RAW OIL
CHARGE
FIGURE III-4
CATALYTIC CRACKING
(FLUID CATALYTIC CRACKING)
-------
SECTION IV
INDUSTRY SUBCATEGORIZATION
INTRODUCTION
The purpose of this section of the development document is to
evaluate distinguishing refinery features which may require
subclassification of the industry. Included here is a
description of the selected subcategories, along with a
discussion of the purpose and basis of this selection. The
following items are addressed in the discussion of selection
"purpose and basis":
the Flow Model for 1974 Regulation;
the Flow Model Used for Proposed 1979 Regulation; and
the Refined Flow Model.
SELECTED SUBCATEGORIES
Subcategorization of the petroleum refining industry was
evaluated with respect to the traditional factors used to assess
industries. However, the complexity of refining facilities (over
150 distinct processes are used in this industry) makes
traditional Subcategorization infeasible. Instead, the Agency
used mathematical models that correlate achievable effluent flow
with process variables as the basis for Subcategorization. In
the development of the 1974 regulations, the Agency found that
the industry can be divided into five discrete subcategories:
o Topping Refineries
o Cracking Refineries
o Petrochemical Refineries
o Lube Refineries
o Integrated Refineries
The 1974 modeling effort developed five mathematical flow models
which represented the best fit for those refineries within each
subcategory. The models calculated discrete factors for refinery
size, process configuration, and allowable wasteload which
grouped the refineries within a subcategory in increments of
production capacity and process configuration.
Data collected for the 1976 industry characterization work
indicated that many refineries were making substantial
improvements to their wastewater management systems. The 1976
data base sampled twice the number of refineries that contributed
to the 1974 flow modeling effort.
61
-------
In 1976 the U.S. Court of Appeals upheld the 1974 BPT and NSPS
regulations, but remanded the more stringent BAT regulations (the
1974 BAT limitations were calculated using the 1974 flow model).
Analysis of the expanded 1976 data base suggested that an
alternative modeling approach which treated each refinery as an
individual was possible to support a more stringent regulation.
The flow model for the 1979 proposed regulation consisted of a
single flow model capable of treating each refinery, essentially,
as a separate subcategory. This model would calculate the
industry average wastewater generation for any combination of
processes. The petroleum refining industry found certain
mathematical and conceptual discrepancies in the 1979 flow model
which were reconciled with the "refined" flow model. This single
model, in. its final revised form, could serve as the basis for
developing more stringent limitations tailored to each refinery's
wastewater management potential as compared to industry average
performance. The refined flow model resulted in possible BAT
effluent limitations only slightly less stringent than those
calculated by the 1979 flow model.
Recent analyses by the Agency of the actual performance of
properly operated BPT technology treating refinery wastewaters
has concluded that these refineries are providing adequate
control of non-conventional and toxic priority pollutants. EPA
is establishing the effluent limitations based upon BPT
technology which was upheld in the U.S. Court of Appeals. The
pollutant load factors calculated by using the 1974 model,
achievable concentrations and variability factors insure adequate
treatment.
PURPOSE AND BASIS OF SELECTION
Section 304(b)(2)(B) of the Act requires EPA to take the
following factors into account in assessing best available
technology: (a) age of equipment and facilities involved, (b)
the process used, (c) the engineering aspects of applying various
types of control technology, (d) process changes, (e) the cost of
achieving such effluent reduction, (f) non-water-quality
environmental impacts (including energy requirements), and (g)
other factors that the Administrator deems appropriate. The
assessment for best conventional pollutant control technology
includes these factors plus an evaluation of "...the
reasonableness of the relationship between the costs of attaining
a reduction in effluents and the effluent reduction benefits
derived, and the comparison of the cost and level of reduction of
such pollutants from the discharge from publicly owned treatment
works to the cost and level of reduction of such pollutants from
a class or category of industrial sources....".
The Agency . considered each factor in establishing effluent
limitations for this industry. Factors that significantly
differentiate groups of facilities generally serve as the basis
62
-------
for industry subcategorization. Each subcategory then develops
its own technologies representative of BAT, BCT, or BADT.
In developing BAT, the Agency analyzed each of the statutory
factors to determine whether they significantly affect the
ability of any group of refineries to meet uniform limitations.
None of the factors were found to significantly affect the
ability of refineries to meet effluent concentrations. The
effluent flow, however, is significantly dependent on the
processes used. Information compiled since the 1974 regulation
supports this assessment. The long-term effluent study that is
described in Section V of this report confirms that the BPT
concentrations can be achieved by refineries regardless of age,
process, and engineering aspects of applying various types of
control technology. The revised flow model that is described in
this section indicates that flow is dependent on the processes
used.
In determining the flow to use in developing quantitative
effluent guidelines, the Agency used mathematical models that
correlate effluent flow with process variables. A brief
description of each model is provided below:
Flow Model For 1974 Regulation
Current BPT limitations for the refining industry are based on a
linear model of industry effluent flows. This BPT model was
developed using process and flow data from the 1972 EPA-API
industry survey and appears as:
Y - Ao+ A1X1. + A2X2
With components,
Y » LogJJD, (total flow/capacity)
Ao » Subcategory dependent constant
Al_,A;2 « Regression coefficient constants (1.51 and
"" 0.0738, respectively)
XI. » Refinery throughput
X2 - Sum of weighting factors for a particular
"" refinery.
For the development of BPT regulations, the equation was
mathematically transformed from the standard slope-intercept
representation shown above to a form denoting deviation from a
subcategory average value. The refinery process weighting
factors are the normalized coefficients of the regression model:
Z - Ao + AlX
63
-------
where
Z * effluent flow
Ao » regression constant
Ai, * regression constant (weighting factor)
~" corresponding to the ith petroleum refining
process.
Xi. « throughput for process i.
BPT subcategorization was designed to give overall minimum
variance to the system; i.e., variance within each subcategory
was minimized and the differences between the subcategories were
maximized. A more detailed discussion of this flow model is
found in the 1974 development document (3).
The model adopted for the 1974 regulation subcategorizes the
industry into five groups: topping, cracking, petrochemical,
lube, and integrated refineries. The model estimates the flow
from each refinery in units of gallons of wastewater per thousand
barrels of crude throughput. Refineries in the United States and
its territorial possessions fall into one of the following five
subcategories:
Subcateqory
Topping
Cracking
Petrochemical
Lube
Basic Refinery Operations Included
Topping and catlytic reforming whether or not
the facility includes any other process in
addition to topping and catalytic reforming.
This subcategory is not applicable to
facilities which include thermal processes
(coking, visbreaking, etc.) or catalytic
cracking.
Topping and cracking, whether or not the
facility includes any processes in addition to
topping and cracking, unless specified in one
of the subcategories listed below.
Topping, cracking and petrochemical
operations, whether or not the facility
includes any process in addition to topping,
cracking and petrochemical operations,* except
lube oil manufacturing operations.
Topping, cracking
manufacturing processes,
and lube oil
whether or not the
64
-------
facility includes any process in addition to
topping, cracking and lube oil manufacturing
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.
;. ,
In the recent toxics review program, the Agency reassessed the
1974 flow model in light of the more current data from the 1977
Survey for the purpose of determining achievable flow reduction.
Flow Model Used For Proposed 1979 Regulation
The Agency analyzed the refining industry's discharge flow for
the year 1976. Data Collected for the 1976 industry survey
indicated that many refineries were making substantial
improvements to their wastewater management systems. The
expanded data base (including approximately twice the number of
refineries covered in the 1972 data base) was suitable for the
development of an alternate modeling approach. In general, the
industry reduced discharge flow significantly between 1972 (BPT
data base) and 1976. A revised mathematical model was developed
that more closely described the industry flow of 1976.
This model differed from the BPT flow models in that it is
additive in form as opposed to the multiplicative form of the BPT
model. Also, a single flow model includes all refineries
compared to a separate model for each subcategory.
This model was used in the proposed regulation for the petroleum
refining guidelines of December 1979 and it takes the following
form:
FLOW - 0.004C + 0.046K + 0.048 (A + L).
Flow is in units of million gallons per day. A,C,K,L are in
units of thousands of barrels per day throughput. Constants are
in units of million gallons per thousand barrels per day.
Where,
A » sum of asphalt processes
65
-------
Asphalt Production
Asphalt Oxidizer
Asphalt Emulsifying
K = sum of cracking processes
Hydrocracking
Visbreaking
Thermal Cracking
Fluid Catalytic Cracking
Moving Bed Catalytic Cracking
C * sum of crude processes
Atmospheric Crude Distillation
Crude Desalting
Vacuum Crude Distillation
L * sum of lube processes
Hydrofining, Hydrofinishing, Lube Hydrofining
White Oil Manufacture
Propane Dewaxing, Propane Deasphalting, Propane Fractioning,
Propane Deresining
Duo Sol, Solvent Treating, Solvent Extraction, Duotreating,
Solvent Dewaxing, Solvent Deasphalt
Lube Vac Twr, Oil Fractionation, Batch Still (Naphtha Strip),
Bright Stock Treating
Centrifuge and Chilling
MEK Dewaxing, Ketone Dewaxing, MEK-Toluene Dewaxing
Deoiling (wax)
Naphthenic Lubes Production
S02, Extraction
Wax* Pressing
Wax Plant (with Neutral Separation)
Furfural Extracting
Clay Contacting - Percolation
Wax Sweating
Acid Treat
Phenol Extraction
Lube and Fuel Additives
Sulfonate Plant
MIBK
Wax Slabbing
Rust Preventives
Petrolatum Oxidation
Grease Mgf. v. Allied Products
Misc. Blending and Packaging
The model for the 1979 proposal does not classify refineries into
discrete subcategories. Instead, it estimates the flow from each
in-plant process. Regulation based on this model would provide
allocation which would equal the summation of the loading
calculated for each of the process throughputs.
66
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Refined Flow Model
Significant industry comments questioned the technical accuracy
and statistical validity of the model as applied to all petroleum
refineries in the industry. In response, the Agency refined the
flow model for the 1979 proposal to consider those factors.
The resulting model is the following:
FLOW = 0.0021C + 0.0127A + 0.0236K + 0.0549L + 0.0212R
Where:
Net Process Wastewater in million gallons/day
Sum of Crude Process Rates in 1000 bbl/day
Sum of Asphalt Process Rates in 1000 bbl/day
Sum of Cracking and Coking Process rates in 1000 bbl/day
Sum of Lube Process Rates in 1000 bbl/day
Sum of Reforming and Alkylation Process Rates in 1000 bbl/day
FLOW
C
A
K
L
R
and where;
Crude Processes are defined as:
PI, P2f and P3
Asphalt Processes are defined as:
P18, P32, P43,and P89
Cracking and Coking Processes are defined as:
P4, P5, P6, P7, P10, P15, P16, and P54
Lube Processes are defined as:
P21, to P30 and P34 to P40
Reforming and Alkylation Processes are defined as:
PS and PI 2
In accordance with the EPA process identification numbers for
the following refinery processes:
1. Atmospheric Crude Distillation
2. Crude Desalting
3. Vacuum Crude Distillation
4. Visbreaking
5. Thermal Cracking
6. Fluid Catalytic Cracking
7. Moving Bed Catalytic Cracking
8. H2SCM Alkylation
10. Hydrocracking
12. Catalytic Reforming
67
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15. Delayed Coking
16. Fluid Coking
18. Asphalt production
21. Hydrofining, Hydrofinishing, Lube Hydrofining
30. S02 Extraction
32. 200 °F Softening Point Unfluxed Asphalt
34. Wax Pressing
40. Phenol Extraction
43. Asphalt Oxidizing
54. Hydrotreating
89. Asphalt Emulsifying
Similar to the model for the 1979 proposal, the allocation for
each refinery would be equal to the sum of the loading for each
of the in-plant processes.
The methodology utilized to develop this model as well as a
complete evaluation of model performance is contained in the
Burns and Roe report "Draft, Petroleum Refining Industry,
Refinements to 1979 Proposed Flow Model and Supplemental
Documentation" (164).
This flow model is different and significantly better than the
one used for the proposed regulations of December 1979. This
model incorporates statistical improvements as well as updated
information. It should be noted that the refined model provides
allocation for Coking, Reforming and Alkylation processes.
Allocation was not provided for these processes in the 1979
proposed flow model. Although Reforming and Alkylation are found
to influence discharge flow in the refined model, these processes
should not be considered in calculating BPT limitations because
the model developed for BPT is different. This is because the
wastewaters from these processes were already considered in the
1974 BPT model, which generally predicts a higher flow rate than
the refined model.
The model evaluation study reaffirms the finding of the BPT
effort that the only refinery characteristics which should be
considered in the development of effluent limitations and
standards are the size and types of processes utilized at
individual refineries.
68
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SECTION V
WASTE CHARACTERIZATION
INTRODUCTION
The purpose of this section is to describe the waste
characterization efforts undertaken and the results obtained by
the Agency in the development of the limitations and standards
which are addressed in this document. Refinery wastewater
characterization efforts are described here in two parts:
a) the concentration of pollutants; and
b) the rate of flow.
The Agency conducted several studies to determine the flow and
concentration of toxic, non-conventional/ and conventional
pollutants from the petroleum refining industry. These studies
included extensive questionnaire surveys and sampling at
refineries of treated and untreated wastewater.
The Agency defined the industry's discharge flow practices by
distributing a questionnaire (1977) which requested information
on the quantity of wastewater generated and discharged. The
questionnaires were sent to all the refineries in the United
States and its territorial possessions. Information
representative of industry's production and treatment practices
during 1976 was requested.
Several major programs were implemented to define the presence of
toxics and other pollutants from the petroleum refining industry.
As required under the Consent Decree Agreement between EPA and
NRDC, the Agency was to determine whether control of the
discharge of 65 classes of toxic pollutants would be needed.
These 65 classes of toxic pollutants potentially included
thousands of specific compounds. The Agency in 1977 selected 123
toxic pollutants for analyses. This list of 123 is now expanded
to include 126 priority pollutants (PP). Most of the sampling
was conducted in 1977-78. Sampling and analytical methodologies,
including quality control and quality assurance procedures, were
not fine-tuned at that time to quantify low level toxics. The
results from these programs, however, were adequate to determine
the presence, absence and relative concentrations of toxic
pollutants.
Three major efforts were conducted. The first task was to
request data from the industry on: (a) toxic pollutants
purchased, manufactured, and analyzed in wastewater; and (b)
treatability data on toxic pollutants. The second program was to
sample 23 refineries and two POTW receiving refinery wastes for a
69
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three day period. The third effort was to sample two refineries
for a period of 60 days to determine long-term wastewater
characteristics. The first two programs were conducted in 1977-
1978 while the third program was conducted in 1980. In general,
toxic pollutants were found in the untreated refinery wastes, but
most were reduced to very low levels after BPT treatment systems.
Details on each of these programs follow.
The Agency also compiled and analyzed one full year of self-
monitoring effluent data which was provided by 49 refineries for
the calendar year 1979. This data gathering effort was referred
to as "The Survey of 1979 Effluent Monitoring Data for the
Petroleum Refining Point Source Category."
CONCENTRATIONS OF TOXIC, CONVENTIONAL AND NON-CONVENTIONAL
POLLUTANTS
The Agency directed three major efforts toward the
characterization of petroleum refinery wastewater quality: a
detailed questionnaire survey of the industry (1977 Survey); and
two wastewater sampling programs - one long-term and one short-
term. In addition, the Agency evaluated effluent monitoring data
for the calendar year 1979 reported by the 49 refineries.
1977 Survey
A comprehensive questionnaire was sent to all refineries in the
United States and its territorial possessions in 1977. The
questionnaire requested the following information: (1) chemicals
purchased or manufactured (final or intermediate) which contain
the 123 toxic pollutants; and (2) NPDES limitations on toxics
other than chromium. The list of 123 toxic pollutants was used
in the 1977 mailing and the following compounds were subsequently
added to form a list of 129 toxic pollutants:
o Di-n-octyl phthalate
o PCB 1221 (Arochlor 1221)
o PCB 1232 (Arochlor 1232)
o PCB 1248 (Arochlor 1248)
o PCB 1260 (Arochlor 1260)
o PCB 1016 (Arochlor 1016)
Since that time, three of the compounds in the original listing
have been removed from the list of priority pollutants leaving a
total of 126 pollutant compounds designated by the Agency (FR
10723, 2/4/81 and FR 2266, 1/8/81). The survey responses
indicated that 71 toxic pollutants were purchased as raw or
intermediate materials; 19 of these are purchased by single
refineries. At least 10 percent of all refineries purchase the
following toxic pollutants:
o Benzene
70
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o Carbon tetrachloride
o 1,1,1-trichloroethane
o Phenol
o Toluene
o Zinc and compounds
o Chromium and compounds
o Copper and compounds
o Lead and compounds
Zinc and chromium are purchased by 28 percent of all refineries,
while lead is purchased by nearly 48 percent of all plants.
Forty-five priority pollutants are manufactured as final or
intermediate materials; 15 of these are manufactured at single
refineries. Benzene, ethylbenzene, phenol, and toluene are
manufactured by at least 10 percent of all refineries. Eight
percent of all refineries manufacture cyanides; greater than 20
percent manufacture benzene/toluene.
Short Term Sampling program
Since the data obtained from the 1977 Survey was limited with
respect to toxic pollutant data, the Robert S. Kerr Environmental
Research Laboratory (RSKERL) (an EPA Laboratory) and Burns and
Roe (an EPA contractor) conducted a three-day sampling program at
each of 17 direct discharging refineries. Table V-l is a summary
of plant characteristics for these refineries. Table V-2 is a
comparison of plant characteristics of the 17 refineries sampled
versus the overall industry characteristics. The purpose of this
sampling program was to obtain more complete information on the
occurrence of toxic pollutants in refinery waste streams. The
results of this program are presented in Tables V-3 through V-20.
The effluents from 6 indirect discharging refineries, which
discharge their wastewater to a POTW, were sampled by Burns and
Roe in a supplemental sampling program. The results of this
study are presented in Tables V-21 through V-26.
Samples were collected before and after the biological treatment
systems. In some instances, samples were taken after polishing
(i.e., polishing pond, sand filter). The intake water was also
sampled to determine the presence of toxic pollutants before
contamination by refining processes.
Samples for conventional, nonconventional, and toxic pollutants
(except for volatile organics, total phenols, and cyanide) were
taken from 24-hour composite samples. The laboratory combined
aliquots from these samples in equal portions to obtain the
72-hour composites for toxic pollutant analysis (acid and
base-neutral extractible organics, pesticides, and metals). Grab
samples were taken in specially prepared vials for volatile
(purgeable) organics, total phenols and cyanide. Before plant
visits, sample containers were carefully washed and prepared by
71
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appropriate methods, depending on the type of sample. Samples
were kept on ice for express shipment in insulated containers.
The analyses for toxic pollutants were performed according to
groups of chemicals and associated analytical schemes. Organic
toxic pollutants included volatile (purgeable), base-neutral and
acid (extractable) pollutants, and pesticides. Inorganic toxic
pollutants included heavy metals, cyanide, and asbestos.
The primary method used to screen and verify the volatiles,
base-neutral, and acid organics was gas chromatography (GO with
confirmation and quantification of all priority pollutants by
mass spectrometry (MS). Total phenols was analyzed by the 4-AAP
method. GC was used to analyze pesticides with limited MS
confirmation. Toxic heavy metals were analyzed by atomic
absorption spectrophotometry (AAS)/ with flame or graphite
furnace atomization following appropriate digestion of the
sample. Duplicate samples were analyzed using plasma emission
spectrometry after appropriate digestion. Samples were analyzed
for cyanides by a colorimetric method, with sulfide previously
removed by distillation. Analysis for asbestos was accomplished
by microscopy and fiber presence reported as chrysotile fiber
count. Non-dispersive x-ray fluorescence was used for
confirmation. Conventional pollutants (BOOS., TSS, pH, and oil
and grease) and nonconventional pollutants (TOG and COD) were
analyzed using "Methods for Chemical Analysis of Water and
Wastes," (EPA 625/6-74-003) and amendments.
The most common pollutants found (detected in more than half the
samples analyzed) include:
Percent of Samples BPT
Fraction Pollutant Where Detected Limited
Conventionals BOD 100 Yes
Total Susp. Solids 100 Yes
Oil & Grease 100 Yes
Non-Conventionals Ammonia Nitrogen 100 Yes
COD 100 Yes
TOC 100 Yes
Sulfide 100 Yes
Phenol (4AAP) 76 Yes
Volatiles Methylene Chloride 69 No
Metals Chromium 78 Yes
Copper 54 No
Mercury 74 No
Selenium 68 No
Zinc 80 No
72
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Of the 126 toxic pollutants, 22 were detected and quantified more
than once in all final effluent samples analyzed from direct
discharges and 28 were detected and quantified more than once in
all final effluent samples from indirect discharges. Table V-27
is a summary of the final effluent priority pollutant data from
the 17 refineries' screening program. Table V-28 is a summary of
the indirect discharge priority pollutant effluent data from the
pretreatment program.
Samples were analyzed for asbestos at only four refineries.
Asbestos was not detected in the intake or effluent from these
refineries. One API separator effluent (prior to treatment)
sample contained 3.4 million asbestiform mineral fibers per
liter. However, the presence can be attributable to rain
occurring during the sample collection period.
Additional toxic pollutant data was obtained from another eight
direct discharging refineries by the EPA Regional Surveillance
and Analysis teams during routine monitoring operations. The
data extracted from single grab-samples taken at each of the
refineries is summarized in Table V-29. The concentrations and
pollutants detected are similar to those of the seventeen
refinery program.
Long-Term Sampling Program
A long-term sampling program was conducted at two refineries for
a period of sixty days.(162) The purposes were: (1) to
determine if there is a surrogate relationship between the
priority pollutants and one or more of the traditional pollutant
parameters; and (2) to confirm the presence or absence of
specific priority pollutants. Samples of the untreated and
treated wastewaters were collected every other day. Pollutant
parameters analyzed include the BPT regulated pollutants and the
toxics, excluding pesticides and asbestos. The sampling and
analytical methods used are similar to those described in the
short-term sampling program discussion. The results from this
program are summarized in Tables V-30 and 31.
In general, the types of pollutants and the concentration ranges
are similar to those found in the short term program. The data
also indicate that a strong correlation does not exist between
the toxics and the traditional pollutant parameters.
The 30-day samples from the two plants were statistically
analyzed to determine if surrogates for important pollutants
could be found. Surrogates were sought for five pollutants:
priority pollutant (PP) organics, total organics (PP organics
plus Appendix C alkanes), extractables, PP metals, and total
metals (PP metals plus a set of non-conventional metals). Seven
potential surrogates were: BOD, COD, total phenol (4AAP), TOC,
TSS, oil and grease, and chromium.
73
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To be acceptable, a surrogate must demonstrate a statistically
significant correlation with the pollutant and it must allow the
level of the pollutant to be estimated with satisfactory
accuracy.
Since the data samples were relatively small, the sensitivity of
statistical analysis to the presence of apparent, outliers was
assessed by plotting surrogates against pollutants and by
rerunning analyses with outliers removed. The findings of the
study, however, were not influenced by these precautionary
measures. Only two possible surrogates were identified, namely,
total phenol (4AAP) for PP organics and for total organics, and
chromium for PP metals and for total metals. However, as can be
seen from Table V-32, statistical significance was obtained only
in one plant. Because surrogate adequacy must be consistent
across plants, the relationship was found to be invalid. In
addition, the predictive adequacy, even for the single plant, is
not sufficient to allow practical application of these two
surrogates.
SURVEY OF 1979 EFFLUENT MONITORING DATA
The Agency also compiled and analyzed one full year of self
monitoring data supplied by 49 refineries covering the 1979
calendar year. EPA selected 50 refineries (163) on the basis
that each reported BPT technology in place in the 1976 survey.
Moreover, 25 of the 50 were examples of refineries reporting
process wastewater flows equal to or less than BAT Option 2 model
flow. Another 15 of the 50 reported flows equal to or less than
1979 BAT Option 1 model flow. (See Section VIII for details of
Options proposed for BAT in 1979).
This study was investigating the effects of BPT treatment where
the total refinery wastewater is less than 1979 proposed model
flows and therefore, 37 of the 50 refineries selected could be
described as low flow refineries. Objectives of the study were
to calculate variability factors, determine average effluent
concentration for phenolic compounds (4AAP), examine TOC and
cyanide as possible surrogate parameters, calculate refinery
model flow for 1978 and verify the reported flow level.
Review of the data to determine those refineries that actually
meet BPT performance levels appears in Preliminary Screening of_
the 1979 Effluent Monitoring (BPT) "DATATT60). Statistical
analysis of the same data set is reported in Petroleum Refining
Self Monitoring Data Analysis (161).
74
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INDUSTRY FLOW
Results of the Agency's efforts in the characterization of the
rate of wastewater flow from the petroleum refinery industry are
described below.
These results are in three parts: 1) summary data by refinery
size; 2) data on distribution by refinery subcategory; and 3)
water usage trends.
Summary of_ Net Wastewater Flow
Figure V-l presents a histogram of net flow for 243 refineries
which provided the necessary data. Each point on the histogram
represents a single refinery by its size class using the letters
A through 0 which represent selected size ranges in 1000 bbl of
crude processing capacity. The results of this histogram are
summarized in Table V-33.
Although it can be seen that nearly 75 percent of total water
usage in the industry is attributable to about 20 percent of the
refineries/ these refineries process a large majority of crude
petroleum.
Distribution of Flow by_ Subcateqory
Figure V-2 presents a histogram of net flow for the same 243
refineries according to the subcategorization procedure described
in Section IV. Similar to the previous figure, each point
depicts a single refinery. Letter designations correspond to the
five selected subcategories:
A - Topping
B - Cracking
C - Petrochemical
D - Lube
E - Integrated
This histogram is summarized in Table V-34.
This summary shows that, except for Topping Refineries, the
fractional share of industry water usage is approximately equally
distributed among the other four subcategories. However, the
subcategory averages show wide disparity, ranging from 0.128 MGD
for the topping subcategory to 9.327 MGD for the Integrated
subcategory.
The histograms in Figures V-1 and V-2 reveal a striking
consequence of the skewed (non-symmetrical) distribution in
75
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wastewater flow. This consequence is the large difference
between the industry average of 1.7 MGD and the industry median
(50-percentile) value of about 0.5 MGD.
Trends _iri Industry Water Usage
Figure V-3 presents the historical trends in industry water usage
from data contained in various surveys conducted by the Agency.
The first survey data is the 1972 EPA/API Raw Waste Load Survey.
This value is used as the baseline for further comparison. The
1977 Survey results provided the next value for calendar year
1976. Total flow in absolute units as well as a gallon/barrel
value (adjusting for increased process capacity) was calculated
for the same refineries surveyed in 1972. The results
demonstrate that a significant reduction in water usage had
occurred during the previous four year period. On an absolute
basis/ total water usage was reduced to about 67 percent of the
1972 value. On a gallon/barrel basis, the reduction was even
greater - up to 53 percent of the 1972 value.
The "Survey of 1979 Effluent Monitoring Data" (160) also provided
information which was used to evaluate industry water usage.
Since this survey was directed towards only 50 specific
refineries, 37 of which had the lowest flow rates, particular
care was taken to prevent the underestimation of industry flow.
For this purpose, the sum of the flows of the 49 respondents to
this questionnaire was compared to the sum of the 1976 flows from
the same refineries. Although the flows of some individual
refineries increased, the total flow in 1979 was found to be
significantly lower than the 1976 flow on both an absolute and a
gallon per barrel basis.
The two curves in Figure V-3 were extrapolated to the year 1984,
the earliest year in which BAT limitations could take effect. It
can be seen that the total water usage of the industry could
potentially reach 42 percent of the year 1972 value (or 62.5
percent of the 1976 average) by 1984 if the current trend
continues. On a gallon/barrel basis, water usage could
potentially reach 29 percent of the 1972 value (40 percent of the
1976 average value).
76
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TABLE V-I
Summary of Plant Characteristics
for 17 Refineries Sampled
in Screening Program
Refinery Location EPA 1000 barrels/ Sub-
Number State Region Stream-day category
1 Alabama IV 30.0 A
20 California IX 100.0 B
50 Colorado VII 21.5 B
59 Illinois V 57.0 B
64 Illinois V 78.0 B
80 Kansas VII 52.0 B
84 Kansas VII 80.0 C
126 Montana VIII 46.0 B
153 Ohio V 125.0 C
157 Oklahoma VI 130.3 D
167 Pennsylvania III 195.0 B
169 Pennsylvania III 188.0 B
186 Texas VI 185.0 C
194 Texas VI 405.0 E
205 Texas VI 103.4 C
235 Washington X 94.0 B
241 West Virginia III 12.0 A
77
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TABLE V-2
Comparison of Plant Characteristics
17 Refineries Sampled vs. Overall Industry
Percent Distribution of Plants
Overall 17 Refineries
EPA Region Industry Sampled
(Direct Discharge
Segment)
100
II 5 0
III
IV
V
VI
VII
VIII
IX
X
Subcateqory
A 27 12
B 45 53
C 12 24
D 11 6
E 5 __5
100 100
Crude Capacity
(1000 bbl/dav)
0-49
50 - 99
100 - 199
> - 200
78
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TABLE V-3
FRACTION
CONVENTIONALS
NON-CONVENTIONALS
VOLATILES
ID
ACID EXTRACT
BASE-NEUTRALS
METALS
NON-CONV. METALS
MISC.
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
SCREENING SAMPLING PROGRAM
FACILITY 1
PARAMETER
con
BOD
TOTAL SUSP. SOLIDS
PH
AMMONIA NITROGEN
TOC
SULFIDE
BENZENE
CHLOROFORM
lf2-TRANS-DICHLOROETHYLENE
ETHYLBENZENE
METHYLENE CHLORIDE
TETRACHLOROETHYLENE
TOLUENE
PHENOL
ACENAPHTHENE
NAPHTHALENE
DI-N-BUTYL PHTHALATE
DIETHYL PHTHALATE
ACENAPHTHYLENE
PHENANTHRENE
ARSENIC
CHROMIUM
COPFgR
CYANIDE
LEAD
MERCURY
NICKEL
ZINC
HEX-CHROMIUM
PHENOLICS <4AAPO>
UNITS
MO/L
MG/L
MO/L
UNIT
MG/L
MG/L
UG/L
UO/L
UG/L
UO/L
UO/L
UG/L
UG/L
UG/L
INTAKE
5
2
3
9
4
2
67
N-D
70
N-D
N-D
G 100
N-D
N-D
6
L
G
G
G
G
API
SEPARATOR
EFFLUENT
107
23
380
9
12
29
8133
100
S
20
100
100
SO
100
FINAL
EFFLUENT
35
1
o9
7
12
11
267
N-D
L 5
N-D
N-D
G 100
L 10
N-D
UG/L
N-D
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
L
L
L
L
L
L
L
L
N-D
N-D
I
N-D
N-D
N-D
10
2-4
5
10
60
1
SO
37
UG/L L 20
UG/L L 11
13
57
97
N-D
37
68
1
12
4
S
12
12
26
SO
132
1
S
263
L
L
L
L
L
N-D
N-D
1
N-D
N-D
N-D
10
1
2
30
60
1
50
57
13
POLLUTANTS NOT LISTED WERE NEVER DETECTED
L-LESS THAN! N-D NOT DETECTED! E-ESTIMATED OR VALUE NOT QUANTIFIED OR CONFIRMED!
G-GREATER THAN!
-------
TABLE V-4
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
SCREENING SAMPLING PROGRAM
FACILITY
FRACTION PARAMETER
CONVENTIONALS COD
BOD
TOTAL SUSP. SOLIDS
OIL S GREASE
PH
NON-CONVENTIONALS AMMONIA NITROGEN
TOC
SULFIDE
20
UNITS
HO/L
HG/L
MO/L
HG/L
UNIT
INTAKE
9
1
11
11
8
HG/L L 1
HG/L 19
UG/L 267
VOLATILES
ACID EXTRACT
METALS
00
O
NON-CONV. METALS
MISC.
CHLOROFORH
HETHYLENE CHLORIDE
2 f4-DIMETHYLPHENOL
CADHIUH
CHROMIUM
COPPER
CYANIDE
LEAD
NICKEL
SILVER
ZINC
HEX-CHROHIUH
PHENOLICS (4AAPO)
UG/L
UG/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UO/L
UG/L
10
22
N-D
1
34
22
20
48
9
1
36
10
P/C
TREATHENT
EFFLUENT
433
173
42
21
9
7
107
933
11
30
1000O
1
44
7
43
20
15
S
6
33
29333
FINAL
EFFLUENT
13O
14
22
31
7
17
43
533
10
N-D
10
2
46
6
20
20
15
S
S
20
52
POLLUTANTS NOT LISTED WERE NEVER DETECTED
L-LESS THAN* N-D NOT DETECTEDI E-ESTIMATED OR VALUE NOT QUANTIFIED OR CONFIRMED!
B-GREATER THAN.
-------
FRACTION
CONVENTIONALS
NON-CONWENT IONALS
VOLATILES
BASE-NEUTRALS
METALS
OO
TABLE V-5
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
SCREENING SAMPLING PROGRAM
NON-CONV. METALS
MISC.
PARAMETER
COD
BOD
TOTAL SUSP. SOLIDS
OIL f GREASE
PH
AMMONIA NITROGEN
TOC
SULFIDE
BENZENE
1.2-DICHLOROETHANE
ETHYLBENZENE
METHYLENE CHLORIDE
NAPHTHALENE
BIS(2-ETHYLHEXYL>
PHENANTHRENE
ANTIMONY
ARSENIC
CADMIUM
CHROMIUM
COPPER
CYANIDE
LEAD
MERCURY
NICKEL
SELENIUM
THALLIUM
ZINC
HEX-CHROMIUM
PHENOLICS (4AAPO)
PHTHALATE
FACILITY
50
UNITS
HO/L
MG/L
MG/L L
HB/L
UNIT
MG/L L
MG/L
UG/L
UG/L
UG/L
UG/L
UO/L
UG/L
UG/L
UG/L
UG/L L
UG/L L
UG/L L
UG/L L
UG/L
UG/L L
UG/L
UG/L
UG/L L
UG/L
UG/L L
UG/L
UG/L L
UG/L
INTAKE
(WELLS)
1
1
1
7
8
1
8
100
N-D
N-D
N-D
85
N-D
ISO
N-D
1
4
2O
1
11
20
IS
2
1
3
3
263
20
5
DAF UNIT
EFFLUENT
323
117
28
93
9
38
71
1347
417
16
38
3
950
290
190
L 1
8
L 20
718
179
323
75
10
L 50
11
L 1
931
17
4550
BIO-TREATMENT
EFFLUENT
123
34
22
11
8
6
41
67
N-D
N-D
N-D
7
N-D
900
N-D
1
6
7
547
118
105
83
3
10
8
L 1
1142
L 20
7
FINAL
EFFLUENT
120
41
19
10
8
10
38
467
N-D
N-D
N-»
20
N-D
155
N-D
3
5
L 20
99
26
50
48
2
5
15
N-D
632
L 20
3
POLLUTANTS NOT LISTED UERE NEVER DETECTED
L-LESS THANS N-D NOT DETECTED! E-ESTIMATED OR VALUE NOT QUANTIFIED OR CONFIRMED*
G-GREATER THAN!
-------
TABLE V-6
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
SCREENING SAMPLING PROGRAM
FACILITY
59
00
IN3
FRACTION
CONVENTIONALS
NON-CONUENTIONALS
VOLATILES
BASE-NEUTRALS
PESTICIDES
METALS
NON-CONV. METALS
MISC.
PARAMETER
COD
BOD
TOTAL SUSP. SOLIDS
PH
AMMONIA NITROGEN
TOC
SULFIDE
BENZENE
ETHYLBENZENE
TOLUENE
FLUORANTHENE
NAPHTHALENE
BENZO (A)PYRENE
CHRYSENE
PHENANTHRENE
PYRENE
PCB-1242
CHROMIUM
COPPER
CYANIDE
MERCURY
SILVER
ZINC
HEX-CHROMIUM
PHENOLICS (4AAPO)
UNITS
MG/L
MG/L
MG/L
UNIT
MO/L
MG/L
UG/L L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
INTAKE
(WELLS)
9
6
24
7
1
8
1
N-D
N-D
N-D
N-D
2
N-D
N-D
N-D
N-D
DAF UNIT
EFFLUENT
630
84
43
9
35
183
16000
G 100
G 100
G 100
3
190
N-D
L 1
140
11
FINAL
EFFLUENT
660
100
61
0
39
220
1200
N-D
N-D
N-D
N-D
N-D
3
1
N-D
7
UG/L
N-D
N-0
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
L
L
L
L
L
L
240
40
20
1
250
7
20
230
726
6
50
L 1
L 250
275
L 20
5600
1069
L 5
20
L 1
3
433
10
NOT 1
POLLUTANTS NOT LISTED WERE NEVER DETECTED
L-LESS THAN) N-D NOT DETECTED* E-ESTIMATED OR VALUE NOT QUANTIFIED OR CONFIRMED*
G GREATER THAN;
-------
00
co
FRACTION
CONVENTIONALS
NON-CONVENTIDNALS
VOLATILES
ACID EXTRACT
BASE-NEUTRALS
METALS
TABLE V-7
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
SCREENING SAMPLING PROGRAM
FACILITY
MISC.
PARAMETER
COD
BOD
TOTAL SUSP. SOLIDS
PH
AMMONIA NITROGEN
TOC
SULFIDE
BENZENE
ETHYLBENZENE
HETHYLENE CHLORIDE
TETRACHLOROETHYLENE
TOLUENE
TRICHLOROETHYLENE
2>4-DIMETHYLPHENOL
PHENOL
ACENAPHTHENE
NAPHTHALENE
DI-N-BUTYL PHTHALATE
CADMIUM
CHROMIUM
COPPER
CYANIDE
LEAD
MERCURY
NICKEL
SELENIUM
ZINC
PHENOLICS (4AAPO)
64
UNITS
MG/L
MG/L
H6/L
UNIT
MO/L
MG/L
UB/L
UG/L
UB/l.
UG/L
UQ/L
UO/L
UD/L
UG/L
UG/L
UG/L
UG/L
UG/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
INTAKE
47
3
20
8
6
15
L 1
N-D
N-D
50
30
N-D
20
N-D
N-D
2
N-D
L 1
L 1
39
9
10
5
N-D
10
L 10
122
SEPARATOR
EFFLUENT
157
49
15
7
13
43
1600
G 100
G 100
10
N-D
G 100
N-D
G 100
G 100
150
106
N-D
L 20
71
L 5
L 30
L 60
N-D
6
L 10
25
FINAL
EFFLUENT
59
S
14
8
20
10
467
N-D
N-D
10
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
L 20
43
L 5
L 30
L 60
L 1
4
12
52
UG/L
9067
POLLUTANTS NOT LISTED HERE NEVER DETECTED
L-LESS THAN; N-D NOT DETECTED! E-ESTIMATED OR VALUE NOT QUANTIFIED OR CONFIRMED.
G-GREATER THAN!
-------
00
FRACTION
CONVENTIONALS
NON-CONVENTIONALS
VOLATILES
BASE-NEUTRALS
PESTICIDES
METALS
TABLE V-8
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
SCREENING SAMPLING PROGRAM
FACILITY
PARAMETER
COD
BOD
TOTAL SUSP. SOLIDS
PH
AMMONIA NITROGEN
TOC
SULFIDE
CARBON TETRACHLORIDE
1i1i1-TRICHLOROETHANE
METHYLENE CHLORIDE
FLUORANTHENE
BENZO (A)PYRENE
CHRVSENE
PHENANTHRENE
PYRENE
CHLORDANE
BETA-BHC
PCB-1221
ARSENIC
CHROMIUM
COPPER
CYANIDE
MERCURY
NICKEL
SELENIUM
ZINC
NON-CONV. METALS HEX-CHROMIUM
80
UNITS
MG/L
MG/L
MG/L
UNIT
MG/L
MG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UO/L
UG/L
UO/L
UG/L
UG/L
UG/L
UG/L
UO/L
UG/L
UG/L
UG/L
UG/L
INTAKE
343
43
59
8
44
101
1067
G SO
G SO
L 10
29
33
49
140
140
3
N-D
N-D
27
38
157
L 30
1
35
12
76
COMBINED
BIO-TREATMENT
INFLUENT
287
G 73
73
7
11
78
500
N-D
N-D
70 L
N-D
10
7
2
10
N-D
1
L 1
41
58
409
727
L 1 L
93
L 10 L
339
FINAL
EFFLUENT
263
23
102
9
4
89
1000
N-D
N-D
10
N-D
1
1
N-D
M-D
N-D
N-ti
N-D
31
37
124
70
1
67
10
124
MISC.
PHENOLICS (4AAPO)
UG/L
UG/L
210
183
45
10
24
POLLUTANTS NOT LISTED MERE NEVER DETECTED
L-LESS THAN! N-D NOT DETECTED) E-ESTIMATED OR VALUE NOT QUANTIFIED OR CONFIRMED!
G GREATER THAN!
-------
TABLE V-9
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
SCREENING SAMPLING PROGRAM
FACILITY 84
00
cn
FRACTION
CONVENTIONALS
NON-CONVENTIONALS
VOLATILES
ACID EXTRACT
BASE-NEUTRALS
PESTICIDES
METALS
NON-CONV. METALS
MISC.
PARAMETER
COD
BOD
TOTAL SUSP. SOLIDS
OIL I GREASE
PH
AMMONIA NITROGEN
TOC
SULFIDE
BENZENE
METHYLENE CHLORIDE
TOLUENE
PHENOL
FLUORANTHENE
NAPHTHALENE
BIS<2-ETHYLHEXYL> PHTHALATE
DIETHYL PHTHALATE
CHRYSENE
PHENANTHRENE
ALPHA-EKDOSULFAN
PCB-1242
PCB-1232
PCB-1016
ANTIMONY
ARSENIC
CADMIUM
CHROMIUM
COPPER
CYANIDE
LEAD
MERCURY
NICKEL
SELENIUM
THALLIUM
ZINC
HEX-CHROMIUM
PNENOLICS (4AAPO)
UNITS
INTAKE
MG/L
MG/L
MG/L
MG/L
UNIT
MG/L
MG/L
UG/L
UG/L
UO/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
L
L
L
L
L
L
L
L
L
24
1
il
13
8
1
12
300
1
22
1
10
N-D
N-D
1100
N-D
N-D
N-D
N-D
N-D
N-D
N-D
1
5
20
1
1
20
36
1
10
3
2
27
20
6
SEPARATOR
EFFLUENT
640
360
139
99
10
14
230
27333
409
293
96
4900
40
1100
700
N-D
40
1100
N-D
1
N-D
2
L 1
5
L 20
7.23
19
11 25
245
1
36
8
L 2
106
IIAF UNIT
EFFLUENT
987
253
131
220
10
12
283
25333
2005
563
76405
2400
N-D
700
1100
N-D
N-D
600
L 1
1
4
8
1
L 4
5
570
2
1758
204
1
21
9
L 2
83
FINAL
EFFLUENT
210
7
59
14
8
14
60
1967
1
12
1
N-D
N-D
850
N P
N-D
1
N-D
N-D
N-D
N-D
1
5
20
50
1
144
40
1
24
13
3
45
13
23750
7
23333
L 20
33
POLLUTANTS NOT LISTED WERE NEVER DETECTED
L-LESS THAN. N-D NOT DETECTED* E-ESTIMATED OR VALUE NOT QUANTIFIED OR CONFIRMED;
0-GREATER THAN?
-------
TABLE V- 10
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
SCREENING SAMPLIN6 PROGRAM
FACILITY
OO
cn
FRACTION
CONVENTIONALS
NON-CONVENTIONALS
VOLATILES
ACID EXTRACT
PESTICIDES
METALS
NON-CONV. METALS
MISC.
PARAMETER
COD
BOD
TOTAL SUSP. SOLIDS
.OIL S GREASE
PH
AMMONIA NITROGEN
TOC
SULFIDE
BENZENE
CHLOROFORM
HETHYLENE CHLORIDE
2r4-DICHLOROPHENOL
2,4-DIMETHYLPHENOL
PHENOL
4.4'-DDE
CADMIUM
CHROMIUM
COPPER
CYANIDE
LEAD
SELENIUM
ZINC
HEX-CHROMIUM
PHENOLICS (4AAPO)
126
UNITS
MO/L
MG/L
MG/L
MG/L
UNIT
MG/L
MG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
INTAKE
(RIVER)
18
1
98
17
8
L 1
12
133
N-D
L 10
N-D
N-D
N-D
N-D
N-D
2
12
5
L 20
L 20
L 20
3
13
4
SEPARATOR
EFFLUENT
no
37
102
52
8
7
54
3100
N-D
55
N-D
N-D
175
440
7
L a
9
23
103
L 20
L 20
20
20 L
2133
FINAL
EFFLUENT
41
1
9
18
8
5
20
147
12
66
70
10
N-D
N-D
N-D
4
10
7
17
28
20
17
20
7
POLLUTANTS NOT LISTED WERE NEVER DETECTED
L-LESS THAN* N-D NOT DETECTED! E--ESTIMATED OR VALUE NOT QUANTIFIED OR CONFIRMED*
G--GREATER THAN*
-------
CO
FRACTION
CONVENTIONALS
NON-CONVENTIONALS
UOLATILES
ACID EXTRACT
BASE-NEUTRALS
METALS
MISC.
TABLE V- 11
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
SCREENING SAMPLING PROGRAM
FACILITY 153
PARAMETER
COD
BOD
TOTAL SUSP. SOLIDS
OIL I GREASE
PH
AMMONIA NITROGEN
TOC
SULFIDE
BENZENE
ETHYLBCNZENE
METHYLENE CHLORIDE
TOLUENE
PHENOL
NAPHTHALENE
BIS(2-ETHYLHEXYL> PHTHALATE
DI-N-BUTYL PHTHALATE
ARSENIC
CHROMIUM
COPPER
CYANIDE
LEAD
MERCURY
NICKEL
SELENIUM
ZINC
PHENOLICS <4AAPO> UG/L
UNITS
MG/L
MG/L
MG/L
HG/L
UNIT
MG/L
MG/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
INTAKE
(CITY)
5
L 3
1
4
8
L 1
5
450
NOT RUN
NOT RUN
NOT RUN
NOT RUN
N-D
N-D
950
30
L 4
L 1
10
L 5
32
1
L 50
2
202
SEPARATOR
EFFLUENT
257
66
39
32
8
4
81
550
2434
812
19
11747
390
2*0
300
N-D
5
78
127
8
52
1
2
3
376
FINAL
EFFLUENT
79
L 12
8
6
7
L 1
31
550
2
N-D
74
L 1
N-D
N-D
300
10
L 4
L 1
45
L 5
S3
1
L 50
21
550
5240
15
POLLUTANTS NOT LISTED WERE NEVER DETECTED
L-LESS THANI N-D NOT DETECTEDI E-ESTIMA.TED OR VALUE NOT QUANTIFIED OR CONFIRMED*
G-GREATER THAN!
-------
TABLE V- 12
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
SCREENING SAMPLING PROGRAM
FRACTION
CONVENTIONALS
PARAMETER
COD
BOD
TOTAL SUSP. SOLIDS
OIL t GREASE
PH
NON-CONVENT ZONALS AMMONIA NITROGEN
TOC
SULFIDE
00
00
ACID EXTRACT
BASE-NEUTRALS
PESTICIDES
METALS
PHENOL
FLUORANTHENE
NAPHTHALENE
BIS(2-ETHYLHEXYL> PHTHALATE
CHRYSENE
PHENANTHRENE
PCB-1242
PCB-1232
PCB-1016
ARSENIC
CHROMIUM
COPPER
CYANIDE
LEAD
MERCURY
NICKEL
SELENIUM
SILVER
THALLIUM
ZINC
NON-CONV. METALS HEX-CHROMIUM
MISC. PHENOLICS (4AAPO)
FACILITY
FART 1
UNITS
MG/L
MG/L
MG/L
MG/L
UNIT
MG/L
MG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
•UG/L
UO/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
157
INTAKE
25
1
5
13
8
1
14
100
N-D
N-D
N-D
110
N-D
N-D
N-D
N-D
N-D
3
L 1
4
7
L 1
2
L 1
3
L 23
L 2
41
7
11
SEPARATOR
EFFLUENT
(LUBE OIL)
177
59
S3
77
8
2
51
1433
420
30
N-D
180
30
30
N-D
N-D
N-D
3
136
284
10
192
1
154
7
L 25
L 2
304
17
733
SEPARATOR
EFFLUENT
(LIGHT OIL)
SS3
0 84
123
158
8
10
162
10500
160
N-D
3SO
300
30
90
1
1
L 1
5
651
59
10
862
2
26
13
L 25 L
2 L
872
2O
1833
SEPARATOR
EFFLUENT
(THERMAL)
187
29
45
34
7
5
53
2867
1
N-D
1
50
50
1
1
1
1
3
724
15
10
39
1
36
17
N-D
2
229
27
690
POLLUTANTS NOT LISTED MERE NEVER DETECTED
L-LESS THAN! N-D NOT DETECTEDI E-ESTIMATED OR VALUE NOT OUANTIFIED OR CONFIRMEDI
G-GREATER THAN*
-------
TABLE V-13
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
SCREENING SAMPLING PROGRAM
FRACTION
CONVENTIONALS
NON-CONVENTIONALS
ACID EXTRACT
BASE-NEUTRALS
00
PESTICIDES
METALS
NON-CONV. METALS
MISC.
PARAMETER
COD
BOD
TOTAL SUSP. SOLIDS
OIL t GREASE
PH
AMMONIA NITROGEN
TOC
SULFIDE
2.4-DIMETHYLPHENOL
PENTACHLOROPHENOL
PHENOL
ACENAPHTHENE
FLUORANTHENE
BIS<2-ETHYLHEXYL> PHTHALATE
DIETHYL PHTHALATE
DIMETHYL FHTHALATE
CHRYSENE
FLUORENE
PHENANTHRENE
PCB-1242
ANTIMONY
ARSENIC
BERYLLIUM
CADMIUM
CHROMIUM
COPPER
CYANIDE
LEAD
MERCURY
NICKEL
SELENIUM
SILVER
THALLIUM
ZINC
HEX-CHROMIUM
PHENOL ICS (4AAPO)
FACILITY
PART
UNITS
MO/L
MG/L
MG/L
MG/L
UNIT
MG/L
MG/L
UQ/L
UG/L
UG/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
157
2
SEPARATOR
EFFLUENT
(OTHER)
337
G 73
52
83
8
6
74
7000
650
850
14000
50
20
600
N-D
N-D
40
80
230
N-D
1
3
U 2
L 20
1451
38
57
32
2
L 50
16
L 1
L 2
•421
SEPARATOR
EFFLUENT
(OTHER-2)
83
12
30
14
B
1
25
4333
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
L 1
9
L 1
3
254B
75
20
53
1
54
20
6
3
575
BIO-TREATMENT
EFFLUENT
553
G SB
19
13
8
22
90
22167
750
N-D
G 12000
N-D
N-D
210
N-D
N-D
N-D
N-D
N-D
L ;
L 1
L 2
L 2
L 20
9
13
273
15
3
L 50
18
L 25
L 2
81
FINAL
EFFLUENT
89
6
12
14
7
6
31
700
N-D
N-D
N-D
N-D
N-D
190
30
3
N-D
N-D
N-D
N-D
L 11
L 4
L 2
L 20
79
9
78
18
2
19
19
L 25
L 2
70
UG/L
UG/L
17
4333
120
251
87
104333
L 20
11
POLLUTANTS NOT LISTED HERE NEVER DETECTED
L-LESS THANf N-D NOT DETECTED! E-ESTIMATED OR VALUE NOT QUANTIFIED OR*CONFIRMEDi
G-GREATER THAN!
-------
TABLE V-14
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
SCREENING SAMPLING PROGRAM
FACILITY
167
FRACTION
CONVENTIONALS
NON-CONVENTIONALS
VOLATILES
ACID EXTRACT
METALS
PARAMETER
COD
BOD
TOTAL SUSP. SOLIDS
OIL I GREASE
PH
AMMONIA NITROGEN
TOC
SULFIDE
BENZENE
CHLOROFORM
METHYLENE CHLORIDE
2-CHLOROFHENOL
2,4-DIMETHYLFHENOL
4-NITROPHENOL
2f4-DINITROPHENOL
PHENOL
CADMIUM
CHROMIUM
COPPER
LEAD
NICKEL
ZINC
NON-CONV. METALS HEX-CHROMIUM
MISC. PHENOLICS (4AAPO)
UNITS
MG/L
MG/L
MG/L
MG/L
UNIT
MG/L
MD/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
INTAKE
(RIVER)
25
3
12
10
8
L 1
11
347
N-D
L 10
N--D
N-D
N-D
N-D
N-D
N-D
1
13
9
46
L 15
89
L 20
L 10
HAF UNIT
EFFLUENT
690
118
283
293
8
7
237
1000
20
100 L
1100 L
315
1150
5800
11000
105
1 L
1320
276
96 L
15 L
1680
20 L
700
FINAL
EFFLUENT
122
7
23
19
8
3
41
367
N-D
10
10
N-D
N-D
N-D
N-D
N-D
1
87
28
20
15
278
20
29
POLLUTANTS NOT L1STEU WERE NEVER DETECTED
L-LESS THAN; N-D NOT DETECTED; E-ESTIMATED OR VALUE NOI HUANTIFIED OK CONFIRMED;
G-GREAIER THAN!
-------
FRACTION
CONVENTIONALS
NON-CONVENT IONALS
VOLATILES
ACID EXTRACT
BASE-NEUTRALS
PESTICIDES
METALS
TABLE V-15
SUMMARY OF ANALrTICAL DATA
PETROLEUM REFINING INDUSTRY
SCREENING SAMPLING PROGRAM
FACILITY
169
PARAMETER
COD
BOD
TOTAL SUSP.
FH
SOLIDS
NON-CONV. METALS
MISC.
AMMONIA NITROGEN
TOC
SULFIDE
BENZENE
CHLOROFORM
ETHYLBENZENE
METHYLENE CHLORIDE
TOLUENE
2,4-DIMETHYLPHENOL
PHENOL
ACENAPHTHENE
FLUORANTHENE
NAPHTHALENE
CHRYSENE
ACENAFHTHYLENE
FLUORENE
PHENANTHRENE
PYRENE
PCB-1242
CHROMIUM
COPPER
CYANIDE
LEAD
MERCURY
NICKEL
ZINC
HEX-CHROMIUM
PHENOLICS (4AAPO)
UNITS
MG/L
MG/L
MG/L
UNIT
MG/L
MG/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
INTAKE
33
1
210
7
L 1
10
700
N-D
N-D
N-D
40
N-D
N-D
N-D
29
L
-n
L
L
SEPARATOR
EFFLUENT
423
131
123
8
12
120
1200
G 100
10
G 100
G 100
G 100
G 100
G 100
N-D
N-D
SOO
20
N-D
270
230
N-D
SEPARATOR
EFFLUENT
(OTHER)
193
37
42
7
11
50
1133
G 100
10
G 100
50
G 100
G 100
G 100
3000
9
280
2
N-D
300
N-D
7
FINAL
EFFLUENT
A3
&
28
7
2
16
533
N-D
N-D
N-D
60
N-D
N-D
N-D
6
L 1
L 1
L 1
N-D
N-D
N-D
L 1
UG/L
UG/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
6
8
60
161
1
4
211
100
10
N-D
N-D
258
110
377
9
1
14
360
23
54667
841
44
150
3
L 1
3
323
17
11000
165
27
80
L 60
L 1
3
161
40
3
POLLUTANTS NOT LISTED WERE NEVER DETECTED
L-LESS THANI N-D NOT DETECTED) E-ESTIMATED OR VALUE NOT QUANTIFIED OR CONFIRMED!
G-GREATER THAN!
-------
TABLE V-16
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
SCREENING SAMPLING PROGRAM
FACILITY
186
<£>
ro
FRACTION
CONVENTIONALS
NON-CONVENT IONALS
VOLATILES
ACID EXTRACT
METALS
NON-CONV. METALS
MISC.
PARAMETER
COD
BOD
TOTAL SUSP. SOLIDS
OIL 1 GREASE
PH
AMMONIA NITROGEN
TOC
SULFIDE
BENZENE
CHLOROFORM
METHYLENE CHLORIDE
PARACHLOROMETA CRESOL
2r4-DIMET.HYLPHENOL
4-NITROPHENOL
2r4-DINITROPH£NOL
PHENOL
BERYLLIUM
CADMIUM
CHROMIUM
COPPER
CYANIDE
LEAD
NICKEL
SILVER
ZINC
HEX-CHROMIUM
PHENOLICS (4AAPO)
UNITS
MO/L
MG/L
MO/L
MO/L
UNIT
MG/L
MO/L
UO/L
UQ/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UO/L
UO/L
UO/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
INTAKE
(CITY)
9
L 6
L 1
8
8
L 1
7
233
14
44
91
N-D
N-D
N-D
N-D
L 10
L 3
L 2
16
176
L 20
65
2
L 5
113
OAF UNIT
EFFLUENT
233
40
11
17
8
12
67
500
12
55
180
N-D
18300
1400
2660
33500
2
L 2
113
9
20
L 20
L 15
L 5
126
FINAL
EFFLUENT
84
L 12
11
13
8
L 1
16
367
11
L 10
L 10
10
N-D
N-D
N-D
L 10
1
1
81
14
L 20
16
6
2
116
UG/L
UG/L
10
250
4400
20
10
POLLUTANTS NOT LISTED MERE NEVER DETECTED
L-LESS THAN! N-D NOT DETECTEIK E-ESTIMATEIl OR VALUE NOT QUANTIFIED OR CONFIRMED!
G-GREATER THAN!
-------
to
FRACTION
CONVENTIONALS
NON-CONVENTIONALS
VOLATILES
ACID EXTRACT
EASE-NEUTRAL'S
PESTICIDES
METALS
TABLE V-17
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
SCREENING SAMPLING PROGRAM
FACILITY
PARAMETER
COD
BOD
TOTAL SUSP,
PH
SOLIDS
NON-CONV. METALS
MISC.
AMMONIA NITROGEN
TOC
SULFIDE
BENZENE
CHLOROFORM
ETMVLBENZENE
METHYLENE CHLORIDE
TOLUENE
PARACHLOROMETA CRESOL
2f4-DIMETHYLPHENOL
PHENOL
ACENAPHTHENE
FLUORANTHENE
NAPHTHALENE
CHRYSENE
ACENAPHTHYLENE
PHENANTHRENE
PYRENE
HEPTACHLOR EPOXIDE
PCB-1221
PCB-1232
PCB-1016
CHROMIUM
COPPER
CYANIDE
LEAH
MERCURY
NICKEL
ZINC
HEX-CHROMIUM
PHENOLICS (4AAPO)
194
UNITS
MG/L
MG/L
MG/L
UNIT
MG/L
MG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
INTAKE
(RIVER)
28
L 5
22
8
L 1
11
733
N-D
N-D
N-D
G 100
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-P
N-D
N-D
N-D
N-D
601
L 40
L 60
L 600
L 1
158
28
S3
L 11
SEPARATOR
EFFLUENT
•410
101
85
8
13
103
6733
0 100
IS
G 100
G 100
G <00
N-D
71
G 100
522
8
302
6
87
140
16
N-D
L 1
1
2
1332
16
13
4
L 1
3
597
L 20
5800
G
G
G
L
L
L
L
L
L
L
UNTREATED
UASTEUATER
(OTHER)
463
83
35
7
1
134
833
90
10
20
100
100
10
100
40
N-D
N-D
27
1
N-D
1
1
5
N-D
1
1
667
6
60
60
1
50
4980
20
49
FINAL
EFFLUENT
133
9
45
8
5
34
800
6
N-D
N-D
G 100
35
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-B
N-D
N-D
N-D
N-D
109
2
L 60
L 60
L 1
L 50
64
L 20
L 15
POLLUTANTS NOT LISTEU WERE NEVER DETECTED
I -LESS THAN! NO NOT DETECTED* E-ESTIMATED OR VAl UE NOT QUANTIFIED OR CONFIRMED.
G-GREATER THAN!
-------
TABLE V- 18
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
SCREENING SAMPLING PROGRAM
FRACTION
CONVENTIONALS
NON-CONVENTIONALS
VOLATILES
ACID EXTRACT
CASE-NEUTRALS
IO
-pi
METALS
NON-CONV. METALS
MISC.
FACILITY
PARAMETER
COD
BOD
TOTAL SUSP.
PH
SOLIDS
AMMONIA NITROGEN
TOC
SULFIDE
CHLOROFORM
METHYLENE CHLORIDE
TOLUENE
2.4-PIMETHYLPHENOL
PHENOL
ACENAPHTHENE
ISOPHORONE
NAPHTHALENE
ACENAPHTHYLENE
ANTHRACENE
FLUORENE
PHENANTHRENE
CHROMIUM
COPPER
CYANIDE
LEAD
ZINC
HEX-CHROMIUM
PHENOLICS (4AAPO)
205
UNITS
MG/L
MG/L L
MG/L
UNIT
MG/L L
MG/L
UG/L
UG/L
UG/L
UG/L L
UG/L
UG/L
UG/L
UG/L
UB/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L L
UG/L L
UG/L L
UG/L L
UG/L
UG/L L
INTAKE
(WELLS)
16
5
11
7
1
19
200
55
130
10
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
2
6
20
20
60
13
10
DAF UNIT
EFFLUENT
423
94
32
9
10
137
3633
13
N-D
16
2000
1900
390
2500
3750
530
1750
495
1750
248
20 L
147 L
5 L
47 L
L 20
10667
FINAL
EFFLUENT
137
20
25
B
3
47
500
32
44
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
62
&
30
20
60
7
46
POLLUTANTS NOT LISTED WERE NEVER DETECTED
L-LESS THANi N-D NOT DETECTED) E-ESTIMATED OR VALUE NOT QUANTIFIED OR CONFIRMED)
G-GREATER THAN)
-------
TABLE V-19
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
SCREENING SAMPLING PROGRAM
FACILITY
«£>
cn
FRACTION
CONVENTIONALS
NON-CONVENTIONALS
VOLATILES
ACID EXTRACT
BASE-NEUTRALS
PESTICIDES
METALS
NON-CONV. METALS
MISC.
PARAMETER
COD
BOD
TOTAL SUSP.
PH
SOLIDS
AMMONIA NITROGEN
TOC
SULFIDE
BENZENE
CHLOROFORM
1 F2-TRANS-DICHLOROETHYLENE
ETHYLBENZENE
METHYLENE CHLORIDE
TOLUENE
2-NITROPHENOL
4-NITROPHENOL
2.4-DINITROPHENOL
4tA-DINITRO-0-CRESOL
ACENAPHTHENE
ISOPHORONE
NAPHTHALENE
ACENAPHTHYLENE
ANTHRACENE
PHENANTHRENE
ALDRIN
BETA-ENDOSULFAN
DELTA-BHC
ANTIMONY
CHROMIUM
CYANIDE
ZINC
HEX-CHROMIUM
PHENOLICS (4AAPO)
235
UNITS
MG/L
MG/L
HO/L
UNIT
MG/L
MG/L
UG/L
UG/L
OG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
L
L
L
L
L
L
L
L
L
L
L
L
L
INTAKE
(CITY)
3
5
1
7
1
6
1
10
10
11
N-D
N-D
10
10
10
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
25
8
30
12
20
10
SEPARATOR
EFFLUENT
537
212
63
10
IS
150
24333
1100
100
N-D
28
1600
65S
1350
20
110
60
315
3550
3200
665
660
660
12
13
12
360
464
63
11
67
67500
FINAL
EFFLUENT
51
5
7
8
2
24
300
10
10
N-D
N-tl
41
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
370
8
L 30
9
L 20
11
POLLUTANTS NOT LISTEH HERE NEVER DETECTED
L -LESS THAN) N-D N01 DETECTED! E-ESTIMA1EU OR VALUE NOT QUANTIFIED OR CONFIRMED*
B fiRFATER THAN!
-------
TABLE V- 20
en
FRACTION
CONVENTIONALS
NON-CONVENTIONALS
VOLATILES
ACID EXTRACT
BASE-NEUTRALS
METALS
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
SCREENING SAMPLING PROGRAM
FACILITY
PARAMETER
COD
BOD
TOTAL SUSP. SOLIDS
OIL t GREASE
PH
AMMONIA NITROGEN
TOC
SULFIDE
BENZENE
CHLOROFORM
METHYLENE CHLORIDE
DICHLOROBROMOMETHANE
TOLUENE
PHENOL
BIS(2-ETHYLHEXYL) PHTHALATE
DIETHYL PHTHALATE
ANTIMONY
ARSENIC
CADMIUM
CHROMIUM
COPPER
CYANIDE
LEAD
MERCURY
SELENIUM
ZINC
PHENQLICS (4AAPO)
241
UNITS
MG/L
MG/L
MG/L
MG/L
UNIT
MG/L
MG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
INTAKE
(WELLS)
11
L 3
2
9
7
L 1
9
333
L 1
N-D
&
N-D
N-D
SEPARATOR
EFFLUENT
320
62
17
50
9
44
80
5767
894
6
4
24
167
FINAL
EFFLUENT
247
26
29
42
9
48
66
600
N-D
N-D
3
N-D
N-D
UG/L
10
60
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
1100
20
L 1
21
L 20
L 1
85
4
34
2
6
553
320
N-D
L 1
438
L 20
L 1
98
3
22
1
8
550
N-D
2000
1
1
734
1
1
90
65
23
2
16
416
UG/L
112
POLLUTANTS NOT LISTED WERE NEVER DETECTED
L-LESS THAN! N-D NOT DETECTED. E ESTIMATED OR VALUE NOT QUANTIFIED OR CONFIRMFDf
G- RREIATER THAMi
-------
FRACTION
CONVENTIONALS
NON-CONVENTIONAL8
VOLATILES
ACID EXTRACT
BASE-NEUTRALS
PESTICIDES
HETALS
NISC.
TABLE V-21
SUHHARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
POTU SAHPLINO PROGRAN
FACILITY 13
PARAHETER
COD
BOO
TOTAL SUSP. SOLIDS
OIL S OREASE
PH
AMMONIA NITROGEN
SU1FIDE
BENZENE
1r1»1-TRICHLOROETHANE
CHLOROFORH
ETHYLBENZENE
TOLUENE
2»4-DIHETHYLPHENOL
PHENOL
ACENAPHTHENE
ISOPHORONE
NAPHTHALENE
DIETHYL PHTHALATE
1f2-BENZANTHRACENE
CHRYSENE
ANTHRACENE
FLUORENE
PHENANTHRENE
4.4'-DDT
4,4'-DDE
ALPHA-BHC
ARSENIC
CHROHIUH
COPPER
CYANIDE
LEAD
MERCURY
SELENIUH
ZINC
PHENOLICS (4AAPO)
UNITS
MG/L
HG/L
HG/L
HG/L
UNIT
HO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UG/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UG/L L
UO/L L
UO/L I
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L L
UO/L
UO/L
FINAL EFFLUENT-
TO POTU
842
404
73
290
11
23
30
173
7
9
203
2300
2430
1650
9
£
92
19
A
&
33
7
33
1
1
1
14
1108
11
203
26
1
107
120
UO/L
92150
POLLUTANTS NOT LISTED HERE NEVER DETECTED
L-LESS THAN! N-D NOT DETECTED! E-ESTIHATED OR VALUE NOT QUANTIFIED OR CONFIRMED!
-------
CD
FRACTION
CONUENTIONALS
NON-CONVENTIONALS
VOLATILEB
ACID EXTRACT
DASE-NEUTRALS
PESTICIDES
NETALS
HISC.
TABLE V-22
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
POTII SAMPLING PROGRAM
FACILITY 16
PARAMETER UNITS
COD HO/L
BOD HO/L
TOTAL SUSP. SOLIDS HO/L
OIL t OREASE HO/L
PH UNIT
AHHONIA NITROGEN HO/L
BENZENE UG/L
ETHYLBENZENE UO/L
TOLUENE UO/L
2>4-DIHETHYLPHENOL UO/L
PHEHOL UO/L
NAPHTHALENE UO/L
4i4'-DDT UO/L
ALPHA-BHC UO/L
ARSENIC UG/L
CHROHIUH UO/L
COPPER UO/L
CYANIDE UO/L
LEAD UG/L
SELENIUH UO/L
ZINC UG/L
PHENOLICS (4AAPO) UO/L
FINAL EFFLUENT-
TO POTU
484
120
22
37
8
29
240
277
420
318
345
53
3
1
23
1880
14
47
20
144
333
3700
POLLUTANTS NOT LISTED HERE NEVER DETECTED
L-LESS THANI N-D NOT DETECTED* E-ESTIMATED OR VALUE NOT QUANTIFIED OR CONFIRMED!
-------
10
FRACTION
CONVENTIONALS
NON-CONVENT IONAtS
VOLATILES
ACID EXTRACT
BASE-NEUTRALS
PESTICIDES
METALS
MISC.
TABLE V- 23
SUHMARY OF ANALYTICAL DATA
PETROLEUH REFINING INDUSTRY
POTU SAHPLINO PROGRAM
FACILITY 21
PARAMETER UNITS
COD HG/L
BOD HO/L
TOTAL SUSP. SOLIDS HG/L
OIL t OREASE hO/L
PH UNIT
AMMONIA NITROOEN HO/L
BENZENE UO/L
1'2-DICHLOftOETHAME UO/L
CHLOROFORN UO/L
ETHYLBENZENE UO/L
TOLUENE UO/L
2t4-DIHETHYLPHENOL UO/L
PHENOL UO/L
NAPHTHALENE UO/L
BUTYL BENZYL PHTHALATE UO/L
DIETHYL PHTHALATE UO/L
ALDRIN UO/L
ALPHA-BHC UO/L
CHROHIUH UO/L
COPPER UO/L
CYANIDE UO/L
LEAD UO/L
SELENIUH UO/L
ZINC UO/L
PHENOLICS MAAPO) UO/L
FINAL EFFLUENT-
TO POTU
351
125
23
34
9
466
29
19
6073
18500
3?4
133
162
5
&
1
1
742
15
20
3?
17
172
1467
POLLUTANTS NOT LISTED UERE NEVER DETECTED
L-LESS THANI N-D NOT DETECTEDI E-ESTINATED OR VALUE NOT QUANTIFIED OR CONFIRHEDI
-------
TABLE V-24
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
POTW SAMPLING PROGRAM
FACILITY 25
O
O
FRACTION
CONVENTIONALS
NON-CONVENTIONALS
VDLAT1LES
ACID* EXTRACT
BASE-NEUTRALS
PESTICIDES
METALS
PARAMETER
COD
BOD
TOTAL SUSP. SOLIDS
OIL I GREASE
PH
AMMONIA NITROGEN
BENZENE
CHLOROBENZENE
CHLOROFORM
ETHYLBENZENE
TETRACHLOROETHYLENE
TOLUENE
2i4-DIHETHYLPHENOL
PENTACHLOROPHENOL
PHENOL
NAPHTHALENE
BUTYL BENZYL PHTHALATE
DI-N-BUTYL PHTHALATE
DIETHYL PHTHALATE
ANTHRACENE
FLUORENE
PHENANTHRENE
PYRENE
BETA-BHC
ARSENIC
CHROMIUM
COPPER
CYANIDE
LEAD
SELENIUM
ZINC
UNITS
HG/L
MO/L
HG/L
MO/L
UNIT
MG/L
UG/L
UG/L
UG/L
UO/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UO/L
UO/L
UG/L
UG/L
UG/L
UG/L
FINAL EFFLUENT-
TO POTU
700
328
30
48
9
37
3847
Id
13
6200
?
10200
644
41S
1430
330
8 '
20
7
47
32
47
11
19
170S
23
2800
28
261
148
MON-CONV. METALS
MISC.
HEX-CHROHIUH
PHENOLICS (4AAPO)
UG/L
UG/L
320
103333
POLLUTANTS NOT LISTED WERE NEVER DETECTED
L-LESS THANI N-D NOT DETECTEDI E-ESTIMATED OR VALUE NOT QUANTIFIED OR CONFIRHEDI
-------
TABLE V-2S
FRACTION
CONVENTIONALS
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
POTH SAMPLING PROGRAM
FACILITY 43
PARAMETER
COD
BOD
TOTAL SUSP. SOLIDS
OIL t CREASE
PH
UNITS
MG/L
MG/L
NO/L
HO/L
UNIT
FINAL EFFLUENT
TO POTU
2910
931
32
134
B
DIRECT
DISCHARGE
130
38
23
4
B
NON-CONVENTIONALS
V01.ATILES
ACID EXTRACT
BASE-NEUTRALS
PESTICIDES
METALS
NON-CONV. METALS
MISC.
AMMONIA NITROGEN
BENZENE
lf2-DICHLOROETHANE
1r1>1-TRICHLOROETHANE
METHYLENE CHLORIDE
2r4-PIMETHYLPHENOL
PHENOL
2>4-DINITROTOLUENE
lr2-DIPHENYLHYORAZINE
N-NITROSODIPHENYLANINE
DI-N-BUTYL PHTHALATE
DIETHYL PHTHALATE
ALDRIN
4»4'-DDT
HEPTACHLOR EPOXIDE
ALPHA-BHC
BETA-BHC
ARSENIC
CHROMIUM
COPPER
CYANIDE
LEAD
NICKEL
SELENIUM
ZINC
HEX-CHROMIUM
PHENOLICS (4AAPO)
HO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
43
24
N-D
8
6
4950
7000
N-D
12
N-D
N-D
6
N-D
N-D
N-D
1
N-D
63
49
47
6667
N-D
14
481
47
200
140SOO
N-D
14
N-D
N-D
8
N-B
10
N-D
21
7
N-D
1
1
1
1
1
N-D
204
S
30
18
N-D
N-D
137
30
103
POLLUTANTS NOT LISTED HERE NEVER DETECTED
L-LESS THANI N-D NOT DETECTED! E-ESTIMATED OR VALUE NOT QUANTIFIED OR CONFIRHEDI
-------
TABLE V-Z6
SUMMARY OF ANALYTICAL DATA
PETROLEUM REFINING INDUSTRY
POTW SAMPLING PROGRAM
FACILITY 45
O
ro
FRACTION
CONVENTIONALB
NON-CONVENTIONALS
VOLATILEB
ACID EXTRACT
BASE-NEUTRALS
PESTICIDES
METALS
MISC.
PARAMETER UNITS
COD HG/L
BOD HO/L
TOTAL SUSP. SOLIDS HO/L
OIL I GREASE MO/L
PH UNIT
AMMONIA NITROGEN HO/L
BENZENE UO/L
ETHYLBENZENE UO/L
TOLUENE UO/L
2.4-DIHETHVLPHENOL UG/L
PHENOL UG/L
ACENAPHTHENE UO/L
MAPHTHALEME UO/L
ANTHRACENE UO/L
PHENANTHRENE UG/L
PYRENE UG/L
ALDRIN UG/L L
4,4'-DDT UQ/L L
ALPHA-BHC UO/L L
CHROMIUM UO/L
COPPER UO/L
CYANIDE UG/L
LEAD UO/L
MERCURY UG/L L
SELENIUM UG/L
ZINC UO/L
PHENOLICS (4AAPO) UG/L
FINAL EFFLUENT-
TO POTU
429
153
17
15
7
104
242
105
434
1360
2447
1?
229
SB
SB
B
1
1
1
440
22
4000
17
1
143
180
14347
POLLUTANTS NOT LISTED UERE NEVER DETECTED
L-LESS THANI N-D NOT DETECTEDI E-ESTIHATED OR VALUE NOT QUANTIFIED OR CONFIRHEDI
-------
TABLE V-27
DIRECT iHSCHAIlGE
FINAL EFFLUENT PRIORITY POLLUTANTS
SUMMARY OF EPA SCREENING PROGRAM DATA
Pa.e 1 of 3
TRACTION
VOI.ATJLES
ACHi EXTRACT
BASE-NEUTRALS
PAR.
NO.
2
3.
4
&
7
10
11
13
14
15
16
17
19
23
2?
30
32
33
38
44
45
44
47
48
49
SO
51
85
86
87
88
21
22
24
31
34
57
58
59
60
64
65
PARAMETER
ACROLEIN
ACRYt ONITRILE
PFNZENE
CARBON TETRACHLORIHE
rHLOROBENZENE
1 2-DICHLOROETHANE
1 1 . 1-TRICHI.OROETHANE
1 1-DICHLOROFTHANE
1 1 .2-TRICHLOROF.THANE
1 I .2.2-TFTRACHIOROETHANE
CHI OROETHANE
BIS(CHl.OROMETHYL> ETHER
2-CHLOROETHYL VINYL ETHER
CHLOROFORM
1 , 1 -DICHLOROETHYLENE
1,2-TRANS-DICHLOROETHYLENE
1 .2-DICHL OROPROPANE
1.3-DICHLOROPROPYLENE
ETHYLBFNZENE
METHYLENF CHLORIDE
MFTHYl CHLORIDE
METHYL BROMIDE
PROMOFORM
DICHLOROBROMOMETHANF
TRICHLOROFL UOROHETHANE
DICHLORODIFLUOROMETHANE
CHLOROniBROMOMETHANE
TETRACHl.OROETHYl ENE
TOLUENE
TRICHl OROETHYl FNE
VINYL CHLORIDE
2.4 . 6-TRICHI.OROF'HFNOL
PARACHLOROHETA CRESOL
2-CHLOROPHENOL
2 » 4 -D I CHLOROPHENOL
2.4-DIMETHYl PHENOL
2-NITROPHFNOL
4-NITROPHENOL
2.4-DINITROPHFNOL
4.6-DINITRO-O-CRFSOL
PENTACHLOROPHENOL
PHENOL
TOTAL TOTAL
PI ANTS PI ANTS SAMPLES TIMES PER
UNITS SAMPLED DETECTING ANALYZED DETECTED CENT AVFRAOF MINIMUM MAXIMUM
1 ACENAPHTHENE
5 BFNZIBINF.
8 1.2.4-TRICHLOROBENZENF
UG/I
UO/L
UO/L
UG/L
UG/l
UG/L
UG/l
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/l
UG/L
UG/L
UG/L
UG/L
UG/L
UG/l
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UO/L
UG/L
UG/L
UG/l.
UG/L
UG/L
UG/L
UG/l
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UO/L
UG/l
UG/L
1«
16
1«
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
17
17
17
17
17
17
17
17
17
17
17
17
17
17
0
0
4
0
0
0
0
0
0
0
0
0
0
2
0
0
0
0
0
11
0
0
0
0
0
0
0
0
1
0
0
0
1
0
1
0
0
0
0
0
0
0
1
0
0
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
22
22
22
22
22
22
22
22
22
22
22
22
22
12
0
0
4
0
0
0
0
0
0
0
0
0
0
2
0
0
0
0
0
11
0
0
0
0
0
0
0
0
1
0
0
0
i
0
1
0
0
0
0
0
0
0
1
0
0
25 2 L 1 12
13 6 L 5 &6
69 33 L 10 100
6 2 L 1 35
5 L 1 L 10 10
5 L 1 N-D 10
5 L 1 N-D 6
L-IESS THAN! T-TRACFI N-D NOT DETFCTEDI
G-GREATER THAN*
Note: Laboratory analysis reported as less than a deduction
limit Is considered not detected (value = 0) for this table.
-------
TABLE V-27
DIRECT DISCHARGE
FINAL EFFLUENT PRIORITY POLLUTANTS
SUMMARY OF EPA SCREENING PROGRAM DATA
Page 2 of 3
FRACTION
BASE-NEUTRALS
PESTICIDES
PAR.
NO. PARAMETER
9 HEXACHLOROBENZENE
12 HEXACHIOROETHANE
IB BIS<2-CHLOROETHri > ETHER
20 2-CHLORONAPHTHALENE
25 lf2-DICHLOROBENZENE
26 1.3-DICHIOROBENZENE
27 1.4-DICHLOROBENZENE
28 3.V-OICHLOROBFNZIDINE
35 2r4-DINITROTOLUENE
36 2.4-DINITROTOLUENE
37 lr2-DIPHENYLHYDRAZINE
39 FLUORANTHENE
40 4-CHLOROPHENYL PHENYL ETHER
41 4-BROMOPHENYL PHENYL ETHER
42 BIS<2-CHIOROISQPROPYL> ETHER
43 BIS(2-CHLOROF.THYOXY) HETHANE
52 HEXACHLOROBUTADIENE
53 HFXACHLQROCYCLOPFNTADIENE
54 ISOF'HORONE
55 NAPHTHALENE
56 NITROBENZENE
61 N-NITROSODIHETHYl AMINE
62 N-NITROSODIPHF.NYLAMINF
63 N-NITROSODI-N-PROPYLAHINE
66 BIS<2-ETHYLHEXYL> PHTHALATE
67 BUTYL BENZYL PHTHAIATE
68 DI-N-BUTYL PHTHALATE
69 OI-N-OCTYL PHTHALATE
70 DIETHYL PHTHALATE
71 DIMETHYL FHTHAl ATE
72 It2-BENZANTHRACENE
73 BFNZO (A)PYRENE
74 3r4-BFNZOFLUORANTHENE
75 11.12-BEN70FLUORANTHENE
76 CHRYSENE
77 ACENAPHTHYLENE
78 ANTHRACENE
79 1r!2-PENZOPERYLENE
80 FLIIORENE
81 PHENANTHRENE
82 lf2!5r6-DIBENZANTHRACENE
83 INDENCK 1,2r3-C.n> PYRENE
84 PYRENE
89 ALDRIN
70 DIELDRIN
91 CHLORTiANF
TOTAL TOTAL
PLANTS PLANTS SAHPI.E8 TIMES PER-
UNITS SAMPLED DETECTING ANALYZED DETECTED CENT AVERAGE MINIMUM
MAXIMUM
L-LESS THANI T-TRACEt N-D NOT DETECTEDI G-GREATER THAN)
UG/L
UO/I.
UG/L
IIG/L
UO/L
UG/L
UB/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UB/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UO/I.
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
IIG/L
UG/L
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
5
0
2
0
3
1
0
2
0
0
3
0
0
0
0
1
0
0
1
0
0
0
Note:
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
17
17
17
Laboratory analysis
limit Is considered
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1 5 L 1 N-ti L
0
0
0
0
5 23 180 I 10
0
2 9 1 N-D
0
3 14 1 N-D
1 5 L 1 N-D
0
2 9 L 1 N-D
0
0
3 14 L 1 L 1
0
0
0
0
1 5 L 1 L 1
0
0
1 5 L 1 L 1
0
0
0
reported as less than a deduction
not detected (value = 0) for this tahlo
1
2000
10
30
3
3
1
1
7
-------
TABLE V-27
DIRECT DISCHARGE
FINAL EFFLUENT PRIORITY POLLUTANTS
SUMMARY OF EPA SCREENING PROGRAM DATA
Page 3 of 3
FRACTION
PESTICIDES
O
tn
METALS
NON-CONV. METAIS
MISC.
PAR.
NO.
92
93
94
95
96
97
98
99
too
101
103
103
104
105
106
107
10B
109
110
111
112
113
129
111
115
117
11B
119
120
121
12?
123
124
125
126
127
128
148
147
PARAMETER
4i4'-DDT
4f4/-DDE
4>4'-DDD
AlPHA-ENDOSULFAN
BETA-ENDOSUIFAN
ENDOSUt.FAN SULFATE
FNDRIN
ENDRIN ALDEHYDE
HEPTACHLOR
HEPTACHLOR EPOXIDE
AlPHA-BHC
BETA-BHC
CAMMA-BHC
DELTA-BHC
PCB-1242
PCB-1254
PCB-1221
PCB-1232
PCB-124B
PCB-1260
PCB-1016
TOXAPHENE
TCDD
ANTIMONY
ARSENIC
BERYLLIUM
CADMIUM
CHROMIUM
COPPER
CYANIDE
LEAD
MERCURY
NICKEL
SELENIUM
SILVER
THALLIUM
ZINC
HEX-CHROMIUM
PHENOLICS (4AAPO)
TOTAl TOTAL
PLANTS PLANTS SAMPLES TIMES PER-
UNITS SAMPLED DETECTING ANALYZED DETECTED CENT AVERAGE
MINIMUM MAXIMUM
UG/L
(JO /I.
UO/L
UG/L
UO/L
UO/l.
UG/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UO/L
UO/L
UO/l.
UG/L
UG/L
UG/L
UO/L
UG/L
UG/L
UO/L
UG/L
UG/L
UO/l.
UG/L
UG/L
UG/L
UG/I.
UG/L
UO/L
UG/L
UO/L
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
16
17
17
17
17
17
16
16
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
3
4
1
5
17
12
8
7
11
7
7
2
2
16
5
14
Note:
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
22
17
21
84
86
87
85
54
87
72
89
31
84
32
92
48
45
Laboratory
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
3
8
2
5
68
46
26
20
53
20
21
3
5
74
6
34
analysis
limit 1s consldred
IB
38
2 I
6 L
78
54
48
23
74
22
68
4 L
16
80
13
76
reported as
not detected
22 L
177 L
1 L
1 L
115 1.
23 L
39 L
14 L
1 1
8 L
11 L
1 L
1 L
203 L
5 L
16 L
less than a
(value - 0)
1
4
1
1
5
4
5
15
1
1
10
1
1
10
20
10
deduction
for this
370
900
2
20
1230
TOO
320
211
12
74
32
15
12
3000
110
64
table.
L-LESS THANI T-TRACEI N-D NOT DETECTED!
G-GREATER THANI
-------
TABLE V-20
INDIRECT DISCHARGE (TO POTW)
PRIORITY POLLUTANTS
SUMMARY OF EPA
PRETREATMENT PROGRAM DATA
Page 1 of 3
FRACTION
VOLATILES
ACID EXTRACT
PAR.
NO.
2
3
4
6
7
10
11
13
14
IS
16
17
19
23
29
3O
32
33
38
44
45
46
47
48
49
SO
51
85
86
87
88
21
22
24
31
34
57
58
59
60
64
65
1
5
8
PARAMETER
ACROLEIN
ACRYI.ONITRILE
BENZENE
CARBON TETRACHLORIDE
CHLOROBF.NZENE
2-DICHLOROETHANE
1 f 1-TRICHLOROETHANE
1-DICHLOROE THANE
1.2-TRICHLOROETHANE
1 f 2 > 2-TETRACHLOROETHANE
CHLOROETHANE
DISC CHI OROMETHYL) ETHER
2-CHLOROETHYI. VINYL ETHER
CHLOROFORM
Irl-DICHLOROETHYLENE
1 r 2-TRANS-DICHL OROETHYLENE
lf2-DICHLOROPROPANE
I i3-DICHLOROPROPYLENC
ETHYL BENZENE
METHYLENE CHLORIDE
METHYL CHLORIDE
METHYL BROMIDE
BROHOFORM
DICHLOROBROMOMETHANE
TR I CHLOROFLUOROME THANE
DICHLORODIFLUOROMETHANE
CHLORODIBROMOHETHANE
TETRACHLOROETHYLENE
TOLUENE
TRICHI.OROETHYl.ENE
VINYL CHLORIDE
2r4r6-TRICHt.OROPHFNOl
PARACHLOROHETA CRESOL
2-CHLOROPHENOL
2r4-DICHLOROPHENOL
2t4-DIMETHYLPHENOL
2-NITROPHENOL
4-NITROPHENOL
2»4-DINITROPHENOL
4t6-DINITRO-0-CRFSOL
PF.NTACHl OROPHFNOL
PHFNOL
ACFNAPHTHENE
BENZIDINE
1 »2,4-TRICHLORQBFN7EN£
TOTAt TOTAL
PLANTS PLANTS SAMPLES TIMES F'ER-
UNITS SAHPLFD DETECTING ANALYZED DETECTED CENT AVERAGE
MINIMUM MAXIMUri
BASE-NEUTRALS
L-LESS THAN) T-TRACEI N-D NOT DETECTED)
UO/L
UO/L
UO/L
UO/L
UG/L
UO/l
UG/L
UO/L
UG/L
UO/L
UG/L
UO/l.
UG/L
UG/L
UO/L
UG/L
UO/L
UO/L
UO/L
UO/l
UG/L
UG/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UO/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
«
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
0
0
6
0
1
1
2
0
0
0
0
b
0
3
0
0
0
0
5
1
0
0
0
0
0
0
0
1
5
0
0
0
0
0
0
6
0
0
0
0
1
6
2
0
0
18
18
18
IS
15
IS
IS
IS
18
IS
18
18
18
IS
IS
IS
18
IS
IS
IS
18
18
18
IS
18
18
15
15
IS
IS
18
18
15
15
IB
IS
18
18
18
18
16
15
IS
18
15
0
0
12
0
1
2
2
0
O
0
0
0
0
6
0
0
0
0
11
1
0
0
0
0
0
0
0
1
11
0
0
0
0
0
0
14
0
0
0
0
1
12
3
0
0
67 817 N-Ii 5800
7 2 N-D 31
13 6 N-D 54
13 2 N-D 15
40 7 N-D 21
73 2540 N-D 18000
7 1 N-D 12
7 1 N-D 18
73 6216 N-tl 48000
93 1509 N-D 9300
4 52 N-D 830
80 194? N-D 14000
20 5 N-D 41
Note: Laboratory analysis reported as less th
-------
TABLE V-28
INDIRECT DISCHARGE (TO POTW)
PRIORITY POLLUTANTS
SUMMARY OF EPA
PRETREATMENT PROGRAM DATA
Page 2 of 3
FRACTION
BASE-NEUTRALS
PAR.
NO.
PARAMETER
TOTAl TOTAL
PLANTS PLANTS 8AHPIES TIMES FFR-
UNITS SAMPLED DETECTING ANALYZED DETECTED CENT AVFRAfiE
MINIMUM MAXIMUM
PESTICIDES
9 HEXACHLOROBFN7ENE
12 HEXACHLOROETHANE
18 BIS(2-CHLOROFTHYL> ETHER
20 2-CHLORONAPHTHALENE
25 1>2-DICHLOROBENZENE
26 lr3-DICHLOROBENZENF
27 t ,4-tlICHl OROBEN7EME
28 3.3--DICHI OROBENZIDJNE
35 2,4-DINITROTOI.UENE
36 ?»6-DINITROTOLUF.NE
37 1,2-DIPMF.NYtHYDRAZINE
39 FLUORANTHF.NE
40 4-CHLOROPHF.NYL PHENYL ETHER
41 4-BROMOPHENYL PHFNYL ETHER
•42 BIS(2-CHLOROISOPROPYL) ETHER
43 BIS(2-CHLOROETHYOXY> METHANE
52 HFXACHI.OROBUTABIENE
53 HFXACHLOROCYCl.OPFNTADIF.NE
54 ISOPHORONE
55 NAPHTHALENE
56 NITROBENZENE
61 N-NITROSODIMETHYLAMINE
62 N-NITROSOOIPHFNYHMINE
63 N-NITROSODI-N-PROFCLAMINF
66 BIS(2-ETHYl HFXYL) PHTHAlATE
67 BUTYL BENZYL PHTHALATE
68 DI-N-BUTYL PHTHAlATE
69 DI-N-dCTYL PHTHALATE
70 PIETHYL PHTHAl ATE
71 DIMETHYL PHTHALATE
72 lr2-BFN7ANTHRACFNE
73 BENZO (A)FYRFNE
74 3.4-RFNZOFLUORANTHFNE
75 11 (12-BENZOFLUORANTHENE
76 CHRYSENE
77 ACENAPHTHYIFNF
78 ANTHRACENE
79 1.12-BENZOPF.RYl ENE
80 FLUORENF
81 PHFNANTHRENE
82 irF.NZANTHRACFNF
83 INriFNO(l,2f3-C.D) PYRENE
84 PYRENE
89 ALDRIN
90 DITI.DRIN
91 CHIORDANE
UG/L
UG/L
UG/L
UG/L
UO/t.
UG/L
UG/L
UG/L
UO/I.
UG/L
UG/L
UG/L
UG/L
UG/L
tIG/L
UG/L
Ufl/L
UG/L
UO/L
UG/L
UG/L
UG/L
UO/L
UG/L
UG/L
UG/l
UG/L
UG/l
WO/I.
UG/l
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UQ/l
UG/L
UO/L
UG/L
UG/l.
UG/L
UO/L
UO/L
UG/L
Note:
6
6
6
6
6
6
6
6
&
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
A
6
6
6
A
6
A
A
A
A
Laboratory
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
1
5
0
0
0
0
0
2
1
0
4
0
1
0
0
•o
1
0
3
0
2
3
0
0
2
2
0
0
analysis
18
18
18
IB
15
17
15
18
15
18
15
15
18
18
15
15
IB
18
15
14
18
18
IS
18
15
15
15
15
15
IS
15
18
18
18
15
IS
15
18
15
15
18
18
15
15
15
18
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
1
11
0
0
0
0
0
2
1
0
4
0
1
0
0
0
1
0
8
0
3
8
0
0
2
2
0
0
reported as less than
is considered not detected (value
- 0) for
7
7
79
13
7
27
7
7
S3
20
53
13
13 I
a (iettttton
this table.
2
1
169
2
3
5
1
1
25
7
25
2
1
Unit
N-D
N-D
N-D
N-D
N-D
N- D
N-D
M-D
N-D
N-D
N-D
N-D
N-D
23
12
620
16
40
30
12
II.'
ei
A3
HI
21
1
L-LFSS THANI T-TRACF! N-D NOT DETECTED)
-------
TABLE V-28
INDIRECT DISCHARGE (TO POTW*
PRIORITY POLLUTANTS
SUMMARY OF EPA
PRETREATMENT PROGRAM DATA
Page 3 of 3
FRACTION
PESTICIDES
O
CO
METAI. S
PAR.
NO.
92
93
94
95
96
97
98
99
100
101
102
103
104
105
104
107
108
109
110
111
112
113
129
114
11H
117
118
119
120
121
122
123
124
125
124
127
128
PARAMETER
4r4'-DDT
4r4'-DDF
4f4'-DDD
Al.PHA-ENDOSULFAN
BFTA-FNBOSUIFAN
ENDOSULFAN
FNDRIN
SULFATF
ENFIRIN ALDEHYDE
HFPTACHLOR
HEPTACHl OR
AlPHA-BHC
BETA-BHC
OAMMA-BHC
LF.LTA-BHC
FCB-1242
PCB-1254
PCB-1221
PCB-1232
PCB-1248
FCB-12AO
PCB-101A
TOXAPHENE
TCDD
ANTIHONY
ARSENIC
BERYLLIUM
CADMIUM
CHROMIUM
COPPER
CVANIDF
LEAD
MERCURY
NICKEL
SELENIUM
SILVER
THALLIUM
ZINC
EPOXIDE
NON-CONV. MF.TAIS 148 HEX-CHROMIUM
TOTAl IOTAL
PI ANTS PLANTS SAMPl ES TIMES PER
UNITS SAMPLED DETECTING ANALYZED DETECTED CENT AVERARE
MINIMUM MAXIMUM
MISC.
11A ASBESTOS
1A7 PHENOLJCS (4AAPO)
UO/L
UG/L
00/1.
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UO/L
IIG/I
UG/L
UG/L
UG/L
UG/L
UO/L
UG/L
UG/L
UO/L
UO/L
UO/L
UG/L
UG/L
UG/L
UO/L
UG/L
UO/L
UO/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/l
UG/L
UG/L
UG/L
UG/l
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
4
A
A
A
A
A
A
A
A
A
A
A
A
A
A
3
1
0
0
0
0
0
0
0
0
5
1
0
0
0
0
0
0
0
0
0
0
0
0
4
0
0
A
4
A
5
2
1
A
0
0
A
1
0
A
15
15
15
15
18
18
18
18
15
15
15
15
15
15
18
IB
18
18
18
IB
18
18
18
18
18
18
18
IB
18
18
19
18
18
18
18
18
IB
IB
18
IB
4
1
0
0
0
0
0
0
0
0
A
2
0
0
0
0
0
0
0
0
0
0
0
0
7
0
0
18
1A
18
10
5
1
16
0
0
18
3
0
IB
27 L
7 L
40 L
13 1
39
100
89
100
53
28 L
A
89
100
17
100
1
1
1
1
18
1057
21
7S2A
18
1
2
192
167
53 I
56900
N-D f,
N-D L 1
N-n 2
N-D I 1
N-D 69
A4 219A
N-D 57
10 9000
N-D 43
N-D 1
N-tt 27
N-D 682
36 405
20 480
1100 151000
Hote[ Laboratory analysis reported as less than a defection limi;
is considered not detected (value = 0) for this table.
L-IESS THAN! T-TRACE) N-D NOT DETECTED*
-------
TABLE V-29
FINAL EFFLUENT PRIORITY POLLUTANTS
SUMMARY OF EPA
REGIONAL SURVEILLANCE AND ANALYSIS DATA
Page 1 of 3
FRACTION
VOt.ATILES
PAR.
NO.
PARAMETER
O
VO
ACID EXTRACT
BASE-NEUTRALS
2 ACROI.EIM
3 ACRYLQNITRILE
4 BENZENE
6 CARBON TETRACHI.ORIDE
7 CHl.OROBENZENE
10 1.2-DICHLOROETHANE
11 ttl't-TRICHLOROrTHANE
13 It1-OICHlOROETHANE
14 lili2-TRICHLOROETHANE
15 lrli2>2-TETRACHLOROETHANE
14 CHL.OROETHANE
17 BIS ETHER
19 2-CHLOROETHYL VINYL ETHER
23 CHLOROFORH
2? l>l-OICHLORn£THrt.ENE
30 1>2-TRANS-DICHLOROETHYI.ENE
32 l>2-DICHlflROPROPANE
33 J'3-DICHLOROPROF-YLENE
38 ETHYl BENZENE
44 HETHYLENE CHLORIDE
45 METHYL CHLORIDE
46 METHYL BROMIDE
47 BROHOFORM
48 niCHLOROBROMOHETHANE
49 TRICHLOROFLUOROHETHAME
50 DICHLOROniFLUOROHETHANE
51 CHLORODIBRONOHETHANE
85 TETRACHLOROETHYI.ENE
86 TOLUENE
87 TRICHI.OROETHYLENE
88 VINYL CHLORIDE
200 TRANS-1,3-DICHLOROPROPENE
21 2>4r6-TRICHLOROPHENOL
22 PARACHLOROMETA CRESOL
24 2-CHLOROPHENOL
31 2.4-DICHLOROPHENOL
34 2t4-DinETHY(.F-HEN01.
57 2-NITROPHENOL
58 4-NITRQFHENOL
59 2.4-DINITROPHENOL
60 4>«-DINITRO-0-CRESOL
64 PENTACHLOROPHENOL
65 PHENOL
1 ACFNAPHTHENE
TOTAL TOTAL
PLANTS PLANTS {SAMPLES TIMES PER-
UNIT8 SAMPLED DETECTING ANALYZED DETECTED CENT AVERAGE MINIMUM
MAXIMUM
UO/L
UG/L
UO/L
UO/I.
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UG/L
UO/L
UO/L
110 /I.
UO/L
UO/L
UO/L
UO/L
UG/L
UO/L
UO/L
UG/L
UO/I.
UO/L
UG/L
UG/L
IIO/L
UG/L
UO/L
UO/L
IIO/L
UO/L
UG/L
U6/L
UO/L
UG/L
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
0
0
0
0
0
2
2
0
0
0
0
0
0
2
0
0
1
0
1
3
0
0
1
0
0
0
2
0
0
«
0
0
0
0
0
0
0
0
0
0
0
0
1
8
8
8
8
8
10
8
8
8
8
8
8
8
10
8
8
8
8
8
9
8
8
8
8
8
8
9
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
9
0
0
0
0
O
2
2
0
0
0
0
0
0
2
0
0
1
0
1
3
0
0
1
0
0
0
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
20 L 1 N-D 3
25 1 N-D 3
20 1 1 L 10 1
13 L 1 N-D 1
13 L 1 N-D L 1
33 21. 10 9
13 L 1 L 10 1
22 2 L 10 13
11 8 N~fi 76
UO/L
L-LESS THANI T-TRACEI N-D NOT DETECTED*
-------
TABLE V-2S
FINAL EFFLUENT PRIORITY POLLUTANTS
SUMMARY OF EPA
REGIONAL SURVEILLANCE AND ANALYSIS DATA
Page 2 of 3
FRACTION
BASF-NEUTRALS
PAR.
NO.
PARAMETER
TOTAL TDTAL
PLANTS PLANTS SAMPLES TINES PER-
UNITS SAMPLED DETECTING ANALYZED DETECTED CENT
AVERAGE MINIMUM MAXIMUM
S BENZIDINE
8 lr2r4-TRICHLOROBFNZENE
9 HEXACHIOROBENZENE
12 HFXACHLOROETHANE
18 BIS(2-CHLOROETHYL) ETHER
20 2-CHl ORONAPHTHAIENE
25 lf2-DICHLOROBENZENE
26 li3-DICHlOROBFNZENE
27 1>4-DICHLOROBENZFNE
28 3r3'-DICHL.OROBENZIDINE
35 2.4-DINITROTOLUENE
36 2rA-DINITROTOLUENE
37 lr2-niPHENYLHYDRAZINE
39 FLUORANTHENE
40 4-CHLOROPHENYt PHENYL ETHER
41 4-BROMOFHFNYL PHENYL FTHER
42 BIS(2-CHI.OROISOPROPYL) FTHER
43 BIS(2-CHLOROETHYOXr> METHANE
52 HEXACHLOROBUTADIENE
S3 HFXACHLOROCYCLOPENTADICNE
54 ISOPHORONE
55 NAPHTHALENE
56 NITROBENZENE
61 N-NITROSODIMETHYLAHINE
62 N-NITROSODIPHENYLAMINF
63 N-NITROSODl-N-PROPYl.AHINE
66 BIS(2-ETHYLHEXYL> PHTHALATE
67 BUTYL BENZYL PHTHALATE
68 DI-N-BUTYL PHTHALATE
69 OI-N-OCTYL PHTHAIATE
70 niETHYL FHTHALATF
71 DIMETHYL PHTHALATE
72 1.2-BENZANTHRACENE
73 BENZO PYRENE
84 PYRENE
207 ANTHRACFNE/PHFNANTHRENE
UO/L
UG/L
UO/l
UG/L
UO/l.
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
IIQ/l
UG/L
UG/L
UO/L
UO/L
UG/L
UG/L
UO/L
UO/L
UG/L
UO/L
UG/L
UO/L
UO/t
UG/L
UO/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/t
UG/L
UG/L
UO/L
UG/L
UG/L
UO/L
UO/l
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
3
0
1
0
•0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
1
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
e
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
3
0
1
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
1
13 34 N-D 270
38 16 L 10 75
13 1 L 10 9
13 L 1 N-D 1
13 9 N-D 80
L-LEPS THANI T-TRACEI N-D NOT DETECTEDI
-------
TABLE V-29
FINAL EFFLUENT PRIORITY POLLUTANTS
SUMMARY OF EPA
REGIONAL SURVEILLANCE AND ANALYSIS DATA
Page 3 of 3
PAR.
FRACTION NO.
PESTICIDES 89
90
91
?2
93
94
95
9A
97
98
99
100
101
102
103
104
105
10A
107
108
109
110
111
112
113
129
METALS 114
US
117
118
119
120
121
172
123
124
125
126
127
12B
PARAMETER
ALDRIN
DIELDRIN
CHLORDANE
4.4--DDT
4.4'-DDE
4>4'-DDD
ALPHA-ENnoSULEAN
BETA-FNDOSIJLFAN
ENDOSULFAN SULFATF
FNDRIN
ENDRIN At DEHYDE
HEPTACHLOR
HEPTACHLOR EPOXIDE
AlPHA-BHC
BETA-BHC
OAMMA-BHC
PELTA-BHC
PCB-1242
PCB-1254
PCB-1221
PCB-1232
PCB-1248
PCB-1260
PCB-1016
TOXAPHENE
TCPD
ANTIMONY
ARSENIC
BERYLLIUM
CAPHIUM
CHROMIUM
COPPER
CYANIDE
I EAD
MERCURY
NICKEL
SELENIUM
SILVER
THALLIUM
ZINC
TOTAL TOTAL
PLANTS PLANTS SAMPLES TIMES PER-
UNITS SAMPLED DETECTING ANALYZED DETECTED CENT AVERAGE MINIMUM
MAXIMUM
NON-CONV. METALS
MISC.
1 16
167
HEX-CHROMIUM
ASBESTOS
PHENOLICS (4AAPO)
UG/l
UG/L
UO/L
UG/1
UG/L
UG/L
UP/L
UG/L
UG/L
UG/L
UO/L
UO/L
UO/L
UG/L
UO/l
UG/L
UO/L
UO/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UO/L
UG/L
UG/L
UG/L
IIG/l
UG/L
UG/L
UG/L
UO/L
UO/L
UO/L
UO/L
UG/L
UG/L
UG/L
UG/L
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
6
7
7
7
7
7
7
7
7
7
7
7
7
2
8
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2
1
2
3
6
6
3
5
5
3
1
1
1
7
0
0
7
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
7
8
9
9
8
9
8
8
8
8
8
10
8
T
9
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2
1
2
3
8
7
4
s
5
3
1
1
1
9
0
0
8
25
13
29
38
89
78
50
56
A3 L
38
13
13 L
13
90
89
20
4
7
6
149
11
3
33
1
13
2
1
13
258
46
1
L
L
L
L
L
L
L
L
L
L
L
5
3
2S
10
5
10
N-D
N-D
1
5
5
5
10
10
N-D
98
28
40
35
480
20
8
160
1
39
18
2
100
620
125
L-LFSS THAN) T-TRACEf N-P NOT DETECTED*
-------
TABLE V-30
MOST-FREQUENTLY OCCURRING PRIORITY POLLUTANTS*
PLANT 1
Parameter
Influent
Volatiles - 30 samples analyzed
Benzene
Toluene
Times
Detected
Average(ug/1) Range(ug/1)
30
28
Extractables - 30 samples analyzed
2, 4 Dimethyphenol 29
Phenol 30
Napthalene 30
Bis (2-ethylhexyl) Phthalate 28
Di-N-Butyl Phthalate 26
Anthracene/Phenanthracene 30
Fluorene 30
Pyrene 25
Metals - 30 samples analyzed
Arsenic 26
Chromium 30
Selenium 29
Zinc 30
27,083
6,877
256
769
253
26
8
38
20
23
10
320
28
350
5800
ND
ND
180
72
NO
ND
5
L5
ND
LI
120
LI
22
75000
17000
800
1800
610
170
30
120
79
400
24
920
81
1900
Effluent
Extractables - 29 samples analyzed
Phenol28
Di-N-Butyl Phthalate 28
Metals - 30 samples analyzed
Arsenic 26
Chromium 30
Selenium 29
Zinc 26
12
9
8
103
31
69
ND
ND
LI
50
LI
9
55
27
21
167
72
411
Notes;
*Pollutants occurring in 80 percent of samples taken from each point
L - Less than
ND - Not detected
112
-------
TABLE V-31
MOST-FREQUENTLY OCCURRING PRIORITY POLLUTANTS*
PLANT 2
Parameter
Influent
Volatiles - 30 samples analyzed
Benzene
Ethylbenzene
Toluene
Times
Detected
Average(ug/1) Range(ug/1)
30
29
30
Extractables - 29 samples analyzed
2, 4-Dimethylpheno1
Phenol
Naphthalene
Bis (2-ethylhexyl) Phthalate
Di-N-Butyl Phthalate
Chrysene/1, 2 Benzoanthracene
Anthracene/Phenanthracene
Fluorene
Pyrene
Metals - 30
Chromium
Selenium
Zinc
samples analyzed
29
29
29
26
23
26
29
28
23
30
27
30
18,747
1,890
8,573
272
3,007
289
21
5
32
195
77
23
1,324
18
516
3600
ND
2300
60
1200
89
ND
ND
ND
11
ND
ND
70
LI
9
90000
3800
20000
720
6300
810
205
19
150
730
383
72
3420
76
1840
Effluent
Extractables - 28 samples analyzed
Phenol26
Bis (2-ethylhexyl Phthalate) 23
Di-N-Butyl Phthalate 26
Metals - 30 samples analyzed
Arsenic 26
Chromium 30
Selenium 28
Zinc 27
8
17
6
7
160
21
60
ND
ND
ND
LI
20
LI
L9
51
260
12
20
1250
71
339
Notes;
'Pollutants occurring in 80 percent of samples taken from each point
L - Less than
ND - Not detected
113
-------
TABLE V-32
POTENTIAL SURROGATES FOR PRIORITY POLLUTANTS
CORRELATION COEFFICIENTS
(Statistics obtained by removing
outliers shown in parentheses)
Pollutant
PP Organics
PP Organics
Appendix C
Alkanes
PP Metals
Total Metals
Plant 1
Plant 2
Plant 1
Plant 2
Plant 1
Plant 2
Plant 1
Plant 2
Total Phenol
0.681 (-0.013)
-0.011 ( 0.027)
0.545
-0.104
Chromium
0.39
0.844 (0.589)
0.571
-0.057 (0.108)
114
-------
TABLE V-33
SUMMARY OF 1976 NET WASTEWATER FLOW
BY REFINERY SIZE
(Million Gallons Per Day)
Size Class
(1000 bbl crude
Capacity)
(A)
(B)
(C)
(D)
LT
50
100
GT
50-1
- 100
- 200
200-2
Number of
Refineries
143
50
32
18
Fraction of
Total for Average for Total
Size Class Size Class Industry Flow
37.
72.
131.
180.
75
25
90
00
0.
1.
4.
10.
264
450
122
000
0.
0.
0.
0.
0895
1713
3126
4266
243
421.90
1.736
1.0000
Footnotes;
(1) LT - less than
(2) GT - greater than
115
-------
TABLE V-34
SUMMARY OF 1976 NET WASTEWATER FLOW
BY REFINERY SUBCATEGORY
(Million Gallons Per Day)
Subcategory
(A) Topping
(B) Cracking
(C) Petrochemical
(D) Lube
(E) Integrated
All Subcategories
Number of Total for
Refineries Subcategory
85
103
24
20
11
243
10.880
135.857
84.816
88.080
102.597
422.230
Average for
Subcategory
0.128
1.319
3.534
4.404
9.327
1.738
Fraction of
Total
Industry Flow
0.0258
0.3218
0.2008
0.2086
0.240
1.0000
116
-------
SrHBOL COUNT
LT50 A 143
50-100 B SO
100-200 C 32
MEAN ST.DEV.
0.264 0.384
1.450 1.282
4.122 2.849
FLOW
(MGD)
.50000
1.0000
1.5000
2.0000
2<5000
3.0000
3.SOOO
4.0000
4.5000
5.0000
5.5000
6.0000
6.5000
7.0000
7.5000
8.0000
8.5000
9.0000
9.5000
10.000
10.500
11.000
11.500
12.000
12.300
13.000
13.500
14.000
14.500
is.'ooo
15.500
16.000
16.500
17.000
17.500
18.000
18.300
19.000
19.500
20.000
20.30O
21.000
21.500
22.000
22.500
23.000
23.500
* 24.000
* 24.500
* 23.000
UllUU O 10
5 10 13 20 25 30 35
4AAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAA*
4AAAAAAAAAAAAAAAABBBBBBBBBBBBBBC
4AAAAAAABBBBBBBBBBBBC
4BBBBBBCC
4AABBBBCCCCCCD
4BBBCCCCD
4BCCCCC
4CCC
4CD
4BCCCOO
4
4
4CD
4
40
4BD
4C
4C
40
4C
4CDD
4
40
4
4CD
4
40
4
4
f
4
4
40
40
4
4
40
4
4
4
4
4
40
4
4
4
4
4
4
4
5 10 13 20 25 30 US
1U.UUI 3.343
FREQUENCY
40 45 50 55 60 65 70 73 80 INT. CUM.
AAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAt 126
31
20
8
13
B
6
3
2
6
0
0
2
0
1
2
1
1
1
1
3
0
1
0
2
0
1
0
0
0
0
0
1
1
0
0
1
0
0
0
0
0
1
0
0
0
0
0
0
0
40 43 50 SS 60 A3 70 73 80
126
157
177
185
198
206
212
215
217
223
223
223
225
225
226
228
229
230
231
232
233
235
236
236
238
238
239
239
239
239
239
239
240
241
241
241
242
242
242
242
242
242
243
243
243
243
243
243
243
243
PERCENTAGE
INT. CUM.
51
12
0
3
5
3
2
1
0
2
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
.9
.8
.2
.3
.3
.3
.5
.2
.8
.3
.0
.0
.8
.0
.4
.8
.4
.4
.4
.4
.2
.0
.4
.0
.8
.0
.4
.0
.0
.0
.0
.0
.4
.4
.0
.0
.4
.0
.0
.0'
.0
.0
.4
.0
.0
.0
.0
.0
.0
.0
51
44
72
76
81
84
87
88
89
91
91
91
92
92
93
93
94
94
95
95
96
96
97
97
97
97
98
98
98
98
98
98
98
99
99
99
99
99
99
99
99
99
100
100
100
100
100
100
100
100
.9
.6
.8
.1
.5
.8
.2
.5
.3
.8
.8
.8
.6
.6
.0
.8
.2
.7
.1
.5
.7
.7
.1
.1
.9
.9
.4
.
.
.
.
.
.8
.2
.2
.2
.6
.6
.6
.6
.6
.6
.0
.0
.0
.0
.0
.0
.0
.0
NUMBER OF REFINERIES
-------
CO
FLOW
(MGD)
* .50000
1 .0000
1.5000
2.0000
2.5000
3.000O
3.5000
4.0000
4.5000
5.0000
5.5000
6.0000
6.5000
7.0000
7.500O
8.0000
8.5000
9.0000
9.5000
10.000
10.500
11.000
11.500
12.000
12.500
13.000
13.500
14.000
14.500
15.000
13.500
16.000
16.300
17.000
17.500
18.000
18.500
19.000
19.300
20.000
20.300
21.000
21.500
22.000
22,500
23.000
2^.500
24.000
24.500
23.000
SYMBOL COUNT MEAN ST. DEW.
A A 85 0.128 0.210
B B 103 1.319 1.682
C C 24 3.334 3.857
D D 20 4.404 5,508
E E 11 9.327 5.477
FREQUENCY
5 10 15 20 25 30 35 40 45 50 35 60 65 70 75 80
4AAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAB*
4AAAAABBBBBBBBBBBBBBBBBBCCCCDDDD
4ABB8BBBBBBBBBBCCCDDO
4BBBBBBCC
48BBBBCCCDDBDE
4BBBBBBBC
4BBBCCE
4BBD
4CC
4BBCDEE
4
4
4BE
4
4B
4CD
4B
46
4E
4C
4CDE
4
40
4
4DE
4
4E
4
4
4
4
4
4C
4E
4
4
4E
4
4
4
4
4
4D
4
4
4
4
4
4
4
+ 1 1 + + + + + + ^ 4 1 + 1 f 1 +
5 10 15 20 23 30 35 40 45 50 55 60 65 70 75 80
INT.
126
31
20
8
13
B
6
3
2
6
0
0
2
0
1
2
1
1
1
1
3
0
1
0
2
0
1
0
0
0
0
0
1
1
0
0
1
0
0
0
0
0
1
0
0
0
0
0
0
0
CUM.
126
157
177
185
198
206
212
213
217
223
223
223
223
225
226
228
229
230
231
232
235
235
236
236
238
238
239
239
239
239
239
239
240
241
241
241
242
242
242
242
242
242
243
243
243
243
243
243
243
243
PERCENTAGE
INT.
51.9
12.8
8.2
3.3
5.3
3.3
2.5
1.2
0.8
2.3
0.0
0.0
0.8
0.0
0.4
0.8
0.4
0.4
0.4
0.4
1.2
0.0
0.4
0.0
0.8
0.0
0.4
0.0
0.0
0.0
0.0
0.0
0.4
0.4
0.0
0.0
0.4
0.0
0.0
0.0
0.0
0.0
0.4
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CUM.
31.9
64.6
72.8
76.1
81.5
84.8
87.2
88.5
89.3
91.8
91.8
91.8
92.6
92.6
93.0
93.8
94.2
94.7
95.1
95.5
96.7
96.7
97.1
97.1
97.9
97.9
98.4
98.4
98.4
98.4
98.4
98.4
98.8
99.2
99.2
99.2
99.6
99.6
99.6
99.6
99.6
99.6
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
NUMBER OF REFINERIES
-------
FIGURE V-3
HISTORICAL TREND OF TOTAL INDUSTRY
WATER USAGE
100
g
1972
—O.LO
— 0
I
h
O
2
O
M
Gu
119
-------
SECTION VI
SELECTION OF POLLUTANTS TO BE REGULATED
INTRODUCTION
The purpose of this section is to describe the selection of
pollutants to be regulated. Included here is a description of
the selection process (and results) for both the direct and
indirect discharge segments of the petroleum refining point
source category. Also presented here is a discussion of the
environmental effects of certain pollutants.
EPA conducted an extensive sampling and analytical program to
determine the presence of toxic, conventional and nonconventional
pollutants in petroleum refinery wastewaters (see Section V for
details). The program included the sampling of 17 direct
dischargers, 6 indirect dischargers, and 2 POTW. Additional
long-term wastewater sampling was conducted at two refineries to
investigate the possible existence of surrogate relationships
between toxic pollutants and other pollutant parameters. The
results of these sampling efforts are presented in Section V.
Since results of the various sampling programs are quite similar,
the data from the 17 direct and 6 indirect discharge refineries
were used as the basis for estimating pollutant loadings and for
selecting pollutants to be regulated.
The conventional and nonconventional pollutants analyzed were
found frequently in effluent streams. Toxics were detected less
frequently and at much lower concentrations. Pollutants from
direct discharge refineries that have average concentrations
greater than 10 ppb include total chromium, cyanide, zinc,
toluene, methylene chloride, and bis (2-ethylhexyl) phthalate.
The latter two compounds are contaminants from the analyses and
their presence can not be solely attributable to the plants'
operation. Cyanide, whose flow weighted concentration averages
45 ug/1, occurs at levels too low to be effectively reduced by
feasible technology available to this industry. Zinc found at
average concentrations of 105 ug/1 is neither causing nor likely
to cause toxic effects. Toluene was removed to below measureable
limits by all but one direct discharge refinery.
The estimated concentration and discharge loading of the
conventional and non-conventional pollutants are summarized in
Table VI-1. Similar information on toxics is included in Table
VI-2.
Characteristics of wastewaters from indirect discharge refineries
prior to their entry into POTW sewers are provided in Table V-28.
SELECTION OF REGULATED POLLUTANTS FOR DIRECT DISCHARGERS
121
-------
The Act requires that effluent limitations be established for
toxic pollutants referred to in Section 307{a)(l). The
Settlement Agreement in Natural Resources Defense Council,
Incorporated vs. Train, 8 ERC 2120 (D.D.C. 1976), modified, 12
ERC 1833 (D.D.C. 1979), provides for the exclusion of particular
pollutants, categories and subcategories (Paragraph 8), according
to the criteria summarized belowj
1. Equal or more stringent protection is already provided
by EPA's guidelines and standards under the Act.
2. The pollutant is present in the effluent discharge
solely as a result of its presence in the intake water taken from
the same body of water into which it is discharged.
3. The pollutant is not detectable in the effluent within
the category by approved analytical methods or methods
representing the state-of-the-art capabilities. (Note: this
includes cases in which the pollutant is present solely as a
result of contamination during sampling and analysis by sources
other than the wastewater.)
4. The pollutant is detected in only a small number of
sources within the category and is uniquely related to only those
sources.
5. The pollutant is present only in trace amounts and is
neither causing nor likely to cause toxic effects.
6. The pollutant is present in amounts too small to be
effectively reduced by known technologies.
7. The pollutant is effectively controlled by the
technologies upon which other effluent limitations and guidelines
are based.
Pollutants Selected for Regulation in the Petroleum Refining
Point Source Category (Direct Discharge Segment)
Specific effluent limitations are established for BOD5., TSS, COD,
oil and grease, phenolic compounds (4AAP), ammonia, sulfide,
total chromium, hexavalent chromium, and pH. These pollutants
are limited under BPT, as well as BAT, and NSPS.
Tables VI-3 and VI-4 are summaries of priority pollutant
detection results from the screening program for the intake
water, and separator effluent, respectively, at direct discharge
refineries.
Pollutants Excluded From Regulation (Direct Discharge Segment)
All of the organic and inorganic priority pollutants (except
chromium) are excluded from regulation.
122
-------
Those priority pollutants which were not detected in the final
effluent of direct discharge refineries are listed in Table VI-5.
Priority pollutants which were detected in the final effluent of
direct dischargers are listed in Table VI-6. Table VI-7 contains
a statistical evaluation of the analytical data for these
parameters. Average flow-weighted concentrations from Table VI-7
show low or trace concentrations for all priority pollutants
except chromium (108 ppb). These pollutants are neither causing,
nor likely to cause, toxic effects.
Two of the priority pollutants, methylene chloride and bis(2-
ethylhexyl) phthalate, were detected in one or more of the
treated effluent samples, however, their presence is believed to
be the result of contamination in the field and laboratory.
During sampling, polyvinyl chloride (Tygon) tubing was used.
Phthalates are widely used as plasticizers to ensure that tubing
(including tygon) remains soft and flexible. Methylene chloride
was used as a solvent in the organic analytical procedure. The
presence of these two pollutants, therefore, cannot be solely
attributable to the refinery effluents.
SELECTION OF REGULATED POLLUTANTS FOR INDIRECT DISCHARGERS
Section 307(b) of the Act requires EPA to promulgate pretreatment
standards for both existing and new sources which discharge their
wastes into publicly owned treatment works (POTW). These
pretreatment standards are designed to prevent the discharge of
pollutants which pass through, interfere with, or are otherwise
incompatible with the operation of POTW. In addition, the Clean
Water Act of 1977 adds a new dimension to these standards by
requiring pretreatment of pollutants, such as metals, that limit
POTW sludge management alternatives.
The Settlement Agreement in Natural Resources Defense Council,
Incorporated vs. Train, 8 ERC 2120 (D.D.C. 1976), modified. 12
ERC 1833, D.D.C. 1979, provides for the exclusion of particular
pollutants from pretreatment standards, categories and
subcategories (Paragraph 8), according to the criteria summarized
below:
(1) if 95 percent or more of all point sources in the point
source category or subcategory introduce only pollutants to POTW
that do not interfere with, do not pass through, or are not
otherwise incompatible with the POTW; or
(2) the toxicity and amount of the incompatible pollutants
(taken together) introduced by such point sources into POTW is so
insignificant as not to justify development of pretreatment
standards; or
(3) criteria (1, 3, 4, 5, and 6) set forth in the above
direct discharge segment discussion.
123
-------
Pollutants Selected for Regulation in the Petroleum Refining
Point Source Category (Indirect Discharge Segment)
Specific pretreatment standards are established for total
chromium, ammonia, and oil and grease.
Pollutants Excluded From Regulation
With the exception of chromium, all organic and inorganic
priority pollutants are excluded from regulation.
Those priority pollutants excluded because they were not detected
are listed in Table VI-8.
Table VI-9 lists the priority pollutants which were detected in
the effluents of indirect dischargers. Pollutants listed in Part
I and Part II of Table VI-9 are excluded from national regulation
in accordance with Paragraph 8 of the Settlement Agreement
because either they were found to be susceptible to treatment by
the POTW and do not interfere with, pass through, or are not
otherwise incompatible with the POTW, or the toxicity and amount
of incompatible pollutants are insignificant. Pollutants listed
in Part III of Table VI-9 are excluded for several reasons.
First, there is significant removal of several of these
pollutants by the existing oil/water separation technology used
to comply with the pretreatment standard for oil and grease.
Second, there is significant removal of these pollutants by the
POTW treatment processes by air stripping and biodegradation.
Third, the amount and toxicity of these pollutants does not
justify developing national pretreatment standards.
Table VI-10 contains a statistical evaluation of the occurrance
and average flow weighted concentrations for those priority
pollutants listed in Table VI-9.
ENVIRONMENTAL SIGNIFICANCE OF SELECTED POLLUTANTS
The environmental significance of the pollutants selected above
is discussed here in the following groupings: a) toxic
pollutants, b) conventional pollutants, and c) non-conventional
pollutants.
Toxic Pollutants
The following "selected" pollutants are addressed here (under the
grouping of toxics): lead, chromium, zinc, cyanide, and toluene.
Lead. Human exposure to lead has been shown to cause
disturbances of blood chemistry, neurological damage, kidney
damage, adverse reproductive effects, and adverse cardiovascular
effects. Lead has also been shown to be carcinogenic and
teratogenic in experimental animals.
124
-------
The effects of lead on aquatic life have been extensively
studied, particularly for freshwater species. As with other
toxic metals, the toxicity of lead is strongly dependent on water
hardness. LC50 values reported for freshwater fish in soft water
are in the low mg/L range. Lead is chronically toxic in soft
water at concentrations ranging from 19 to 174 »g/L for six
species of freshwater fish. Lead is bioconcentrated by fish,
invertebrates, algae, and bacteria.
Chromium. Although chromium is an essential nutrient in trace
amounts, it can be quite toxic to man at high concentrations.
Damage to the skin, respiratory tract, liver, and kidneys has
resulted from occupational exposure to high levels of chromium.
Epidemiological studies suggest that long term inhalation of
chromium produces lung cancer.
Concentrations of chromium lethal to aquatic organisms vary
considerably depending upon the chemical form of chromium, the
water hardness, and the species or organism exposed. LC$0 values
reported for 21 species of fish range from 3,300 *g/L to 249,000
i«g/L. LC50 values reported for 33 invertebrates range from 67
<«g/L to 105,000 »»g/L.
Cyanides. Cyanides are a diverse group of compounds defined as
organic or inorganic compounds which contain the -CN group.
Cyanides are rapidly lethal to humans in low doses but apparently
do not exert sublethal or chronic toxic effects. Cyanides are
acutely toxic to fish at concentrations as low as 57
-------
single chronic value of 2.2 mg/L has been reported for saltwater
fish.
Conventional Pollutants.
The environmental Significance of the conventional pollutants,
biochemical oxygen demand, suspended solids, and oil and grease
is discussed below.
Biochemical Oxygen Demand. 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 subsequent high bacterial counts that degrade
its quality and potential uses.
Suspended Solids. Suspended solids include both organic and
inorganic materials. 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.
Solids may be suspended in water for a time, and then settle to
the bed of the stream or lake. These settleable solids 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
dissolved oxygen available in the area. Organic materials also
126
-------
serve as a seemingly inexhaustible food source for sludgeworms
and associated organisms.
Oil and Grease. 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 wastewater
will, in most instances, be of a hydrocarbon nature. These
hydrocarbons, predominately oil and grease type compounds,
contribute to COD, TOC, TOD, and usually BOD resulting in high
test values. 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
inhibit 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 wastewater will affect
stream ecology by interfering with oxygen transfer, by damaging
the plumage and coats of water animals and fowls, and by
contributing 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.
Non-convent i ona1 Pollutants.
The environmental significance of the following non-conventional
pollutants: chemical oxygen demand, sulfides, total organic
carbon, phenolics (4AAP), and ammonia is discussed below.
Chemical Oxygen Demand. Chemical oxygen demand (COD) provides a
measure of the equivalent oxygen required to oxidize the
materials present in a wastewater sample, under acid conditions
with the aid of a strong chemical oxidant, such as potassium
dichromate, 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 demand a waste can exert 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.
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 catalyst life. They are removed
by caustic, diethanolamine (DEA), water or steam, or appear as
sour condensate waters in these initial processing operations.
Hydrotreating processes can be used to remove sulfides in the
127
-------
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.
Total Organic Carbon. Total organic carbon (TOO is a measure of
the amount of carbon in the organic material in a wastewater
sample. The TOC analyzer withdraws a small volume of sample and
thermally oxidizes it at 150 degrees C. The water vapor and
carbon dioxide from the combusion 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 degrees 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.
Phenolic Compounds (4AAP). Phenols and phenolic compounds are
found in wastewaters of the petroleum refinery, chemical and wood
distillation industries. Phenolic compounds include phenol
(commonly referred to as carbolic acid) plus a number of other
compounds that contain the hydroxy derivatives of benzene and its
condensed nuclei. EPA has identified a number of toxic materials
from this family of compounds, nine of which have been designated
priority pollutants.
Phenol in concentrated solutions is quite toxic to bacteria, and
it has been widely used as a germicide and disinfectant. Many
phenolic compounds are more toxic than pure phenol; their
toxicity varies with the chemical combination and general nature
of the total wastes in which they occur. The toxic effects of
combinations of different phenolic compounds is cumulative.
Biological treatment systems have been found able to effectively
treat relatively high concentrations of phenolic compounds using
them as food without serious toxic effects. Experience has
indicated that biological treatment systems may be acclimated to
phenolic concentrations of 300 mg/L or more. However, protection
of the biological treatment system against slug loads of phenol
should be given careful consideration in the design. Slug
loadings as low as 50 mg/L could be inhibitory to the biological
population, especially if the biological system is not completely
mixed.
Phenols in wastewater present the following two major problems:
128
-------
1) At high concentrations, phenol acts as a bactericide.
2) At very low concentrations, when disinfected with chlorine,
chlorophenols are formed, producing taste and odor problems.
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, destroying their
recreational and commercial value.
It is necessary to control phenolic compounds in the raw water
used to supply drinking water, 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.
The amino antipyrine method (4AAP) measures the presence of
phenolic compounds in terms of the color effects caused when
^these materials react in the presence of potassium ferricyanide
at a pH of 10 to form a stable reddish-brown colored antipyrine
dye. Color response of phenolic materials with 4-amino-
antipyrine is not the same for all compounds. Because phenolic
type wastes usually contain a variety of phenols, it is not
possible to duplicate a mixture of phenols to be used as a
standard. For this reason phenol itself has been selected as a
standard and any color produced by the reaction of other phenolic
compounds is reported as phenol. This value will represent the
minimum concentration of phenolic compounds present in the
sample. It is not possible to distinguish between different
phenolic compounds using this analytical method.
Results of the sampling data for direct discharge refineries
(Table V-27) illustrates the concentrations of total phenols (as
measured by the 4AAP method) versus concentrations of the
individual phenolic compounds identified as priority pollutants
and present in refinery wastewaters. While phenolic compounds
were found in the effluents of 14 of 16 refineries at an average
concentration of 16 ug/L, only one of the priority pollutant
phenols was detected at a concentration at or below measureable
limits of the analytical equipment.
Ammonia. 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 aminals 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 (N03) by nitrifying bacteria. Nitrite (N02), which is an
intermediate product between ammonia and nitrate, sometimes
129
-------
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/L of nitrate can cause such symptoms.
In most natural water the pH range is such that ammonium ions
(NH4+) predominate. In alkaline waters, however, high
concentrations of un-ionized ammonia in undissociated ammonium
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/L of total nitrogen. It has been shown that at a
level of 1.0 mg/L 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/L
to 25 mg/L, 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.
130
-------
1 of 2
TABLE VI-1
(Ref. 168, page 22)
FLOW-WEIGHTED CONCENTRATIONS1 AND LOADINGS FOR
DIRECT DISCHARGERS IN THE PETROLEUM
REFINING INDUSTRY
-Conventional Pollutants-
Pollutant
BOD
TSS
Oil and Grease
.Total Loading
Pre treated Raw
Cone.
mg/L
133.2
92.1
150.6
Load
kkg/yr
57405.4
39691.8
64909.6
162006.8
Current/BPT
Cone.
mg/L
13.5
26.1
17.1
Load
kkg/yr
5833.0
11252.1
7389.2
24474.3
-Nonconventional Pollutants- 2
Pollutant
COD
Ammonia
TOG
Sulfides
Total Phenols
Total Loading
Pretreated Raw
Cone.
mg/L
442.7
14.1
112.2
5.2
22.5
Load
kkg/yr
190836.3
6070.1
48348.8
2257.1
9719.1
257231.4
Current/BPT
Cone.
mg/L
114.6
6.8
33.3
0.6
0.018
Load
kkg/yr
49422.2
2941.3
14342.5
274.1
7.6
66987.7
131
-------
2 of 2
TABLE VI-1
(Ref. 168, page 22)
FLOW-WEIGHTED CONCENTRATIONS1 AND LOADINGS FOR
DIRECT DISCHARGERS IN THE PETROLEUM
REFINING INDUSTRY
(continued)
Footnotes:
1 Pretreated Raw and Current/BPT concentrations were supplied by EGD on
a plant-by-plant basis. The industry-wide Pretreated Raw direct and the
Current indirect discharge concentrations were obtained by flow-weight-
ing the data for the seventeen direct and the four indirect dischargers
studied in this analysis. The plant-by-plant Current/BPT direct dis-
charge concentrations were flow-weighted to determine the industry-wide
concentrations. The BAT industry-wide concentrations were calculated
using the Current/BPT concentrations and flow-weighting on a plant-by-
plant basis, based on the adjusted BAT flows. The flow-weighted con-
centrations were derived by multiplying the average concentrations by
the flow for each of the 17 refineries sampled. The sum of the products
divided by the total flow of the refineries sampled results in a flow-
weighted average concentration.
2 Nonconventional pollutant loadings are not presented for BAT because the
BAT removal effectiveness for these pollutant parameters is unknown.
132
-------
TABLE VI-2
FLOW-WEIGHTED CONCENTRATIONS1 AND LOADINGS
FOR DIRECT DISCHARGERS IN THE
PETROLEUM REFINING INDUSTRY
-Toxic Pollutants- 2
Pollutant
Total
Toxic
Loadings
Pretreated
Raw
Load
kkg/yr
3502.1
Current/
BPT
Load
kkg/yr
136.6
BAT3
Option 1
Load
kkg/yr
103.3
Option 2
Load
kkg/yr
83.0
Rev. Option 1
Load
kkg/yr
100.8
Rev. Option '*
Load
kkg/yr
87.1
Footnotes:
1 Pretreated Raw and Current/BPT concentrations were supplied by EGD on
a plant-by-plant basis. The industry-wide Pretreated Raw direct and the
Current indirect discharge concentrations were obtained by flow-weight-
ing the data for the seventeen direct and the four indirect dischargers
studied in this analysis. The plant-by-plant Current/BPT direct dis-
charge concentrations were flow-weighted to determine the industry-wide
concentrations. The BAT industry-wide concentrations were calculated
using the Current/BPT concentrations and flow-weighting on a plant-by-
plant basis, based on the adjusted BAT flows. The flow-weighted con-
centrations were derived by multiplying the average concentrations by
the flow for each of the 17 refineries sampled. The sum of the products
divided by the total flow of the refineries sampled results in a flow-
weighted average concentration.
2 The individual toxic pollutant concentrations are listed in Section 2.3.
3 Some of the pollutants have an increased BAT concentration above Current/BPT
because of the plant-by-plant flow-weighting procedure.
133
-------
TABLE VI-3
DIRECT DISCHARGE
INTAKE WATER PRIORITY POLLUTANTS' DETECTION
SUMMARY OF EPA SCREENING PROGRAM DATA
PAGE 1 of 3
FRACTION
VOLATILES
CO
ACIfi EXTRACT
BASE-NEUTRALS
PAR.
NO. PARAMETER
2 ACROLEIN
3 ACRYIONITRII.E
4 BENZENE
6 CARBON TETRACHLORIPE
7 CHLllROBENZENE
10 1.2-DJCHLOROETHANE
11 Irl.l-TRICHLOROFTHANE
13 1.1-nICHLOROETHANE
14 l»lr2-TRICHLOROFTHANE
15 lil,2i2-TETRACHI.OROETHANE
16 CHLOROETHANE
17 BIS
-------
TABLE VI-3
DIRECT JISCHARJE
INTAKE HATER 'PRIORITY POLLUTANTS* DETECTION
SUMMARY OF EPA SCREENING PROGRAM DATA
2 of 3
FRACTION
BASF-NEUTRALS
PAR.
NO.
PARAMETER
TOTAL TOTAL
PLANTS PLANTS SAMPLES TIMES
UNITS SAHPLED DETECTING ANALYZED DETECTED
CO
en
PESTICIDES
9 HEXACHLOROBENZENE
12 HFXACHLOROETHANE
18 BIS<2-CHLOROETHYl> ETHER
20 2-CHLORONAPHfHAl.ENE
25 1F2-DICHLOROBENZENE
26 1.3-DICHLOROBENZENE
27 1>4-DICHLOROBFNZENE
28 3f3'-DICHLflROBENZIDINE
35 2>4-DINITROTOLUENE
36 2f6~DINITROTOLUENE
37 1.2-DIPHENYLHYDRAZINE
39 FLUORANTHENE
40 4-CHLOROPHENYL PHENYL ETHER
41 4-BROMOPHFNYL PHENYL ETHER
42 BIS(2-CHLOROISOPROPYL) ETHER
43 BIS(2-CHl.OROETHYOXY> METHANE
52 HFXACHLOROBUTADIENE
53 HEXACHLOROCYCLOPENTADIENE
54 KiOPHORONE
55 NAPHTHALENE
54 NITROBENZENE
61 N-NITROSODIMETHYLAMINE
42 N-NITROSODIPHFNYl.AHINE
63 N-NITROSODI-N-PROPYLAMINE
66 BIS(2-ETHYl HEXYl) PHTHALATE
67 BUTYL BENZYL PHTHALATE
68 DI-N-BUTYL PHTHALATE
69 DI-N-OCTYL PHTHAl ATE
70 D7ETHYL PHTHALATE
71 DIMETHYL PHTHAl ATE
72 lf2-BENZANTHRACENE
73 BFN70 (A)PYRENE
74 3t4-BENZOFLUORANTHENE
75 11.12-BENZOFLUORANTHENE
76 CHRYSFNE
77 ACFHAPHTHYLENE
78 ANTHRACENE
79 It12-BFNZOPFRYLENE
80 FLUORENE
81 PHFNANTHRENE
82 1,2l5r6-DlBENZANTHRACENE
83 INriFNO(l,2.1-CrF» PYRENE
84 PYRENE
89 At UK 1H
90 DIFLDRIN
91 CHLORDANE
UO/L
IIO/L
UO/I.
UG/L
UG/L
UG/L
UG/L
UO/L
UO/L
UG/L
UG/L
UO/L
UG/L
UG/l.
UG/L
UO/L
UG/L
UG/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UG/L
IIO/L
UO/L
UO/L
UO/L
IIO/L
UG/L
UG/L
UG/L
UO/L
UO/L
UO/L
UG/L
UG/L
UG/L
U6/L
UG/L
UG/L
Note:
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
Laboratory
0
0
0
0
0
0
0
0
0
0
0
2
0
0
0
0
0
0
0
2
0
0
0
0
5
0
4
0
0
1
0
1
0
0
1
1
0
0
1
2
0
0
2
0
0
1
analysis
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
reported as
0
0
0
0
0
0
0
0
0
0
0
2
0
0
0
0
0
0
0
2
0
c
0
0
5
0
4
0
0
1
0
1
0
0
1
1
0
0
1
2
0
0
2
0
0
1
less than
r : — r-" : .
L-LESS THAN) T-TRACFI N-D NOT DETECTED)
detection limit Is considered not detected
(value = 0) for this table.
-------
TABLE VI-3
DIP.ECT DISCHARGE
INTAKE WATER PRIORITY POLLUTANTS' DETECTION
SUMMARY OF EPA SCREENING PROGRAM DATA
PAGE 3 of 3
FRACTION
PESTICIDES
CO
CT)
METALS
PAR.
NO.
92
93
94
95
96
97
9B
99
100
101
10?
103
104
105
106
107
108
109
110
111
112
113
129
114
115
117
MR
119
120
121
1?2
123
124
125
126
127
12fl
PARAMETER
4r4'-DDT
4,4'-DDE
4f4'-ODn
ALPHA-ENDOSULFAN
BEfA-F.NDOSUl FAN
FNDOSULFAN
FNDRIN
Sill FATE
ENDRIN ALDEHYDE
HFPTACHLOR
HFPTACHLOR
ALPHA-BHC
BETA-BHC
GAMMA-BHC
DFl TA-BHC
PCB-1242
PCB-1254
PCB-1221
PCB-1232
PCB-1248
PCB-1260
PCB-1016
TOXAPHENE
TCDD
ANTIMONY
ARSFNIC
BERYLLIUM
CADMIUM
CHROMIUM
COPPER
CYANIDE
LEAD
MERCURY
NICKEL
SELENIUM
SILVER
THALLIUM
ZINC
EPOXIDF
NON-CONV, METALS 148 HEX-CHROMIUM
MISC.
167 PHENOl ICS (4AAPO)
TOTAL TOTAL
PLANTS PI ANTS SAMPLES TIMES
UNITS SAMPLED DETECTING ANALYZED DETECTED
UG/L
UG/L
UG/L
UG/L
UO/L
UO/L
UG/l
UO/L
UG/l
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UO/L
UG/L
UG/L
IIG/L
UG/L
UG/L
UG/L
UG/l.
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/l
UG/L
UG/L
Note:
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
16
17
17
17
17
17
16
17
Laboratory
deduction
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
0
0
4
0
4
IS
12
3
10
10
9
6
1
0
16
7
9
analysis
limit Is
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
17
18
85
85
85
86
52
88
69
88
23
85
34
90
48
48
reported <
considered
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
0
0
s
0
4
34
48
4
26
51
13
10
2
0
3u
10
17
is less than a
not detected
(value - 0) for this table.
L-LESS THAN) T-TRACE) N-D NOT DETECTED)
-------
TABLE VI-4
DIRECT DISCHARGE
SEPARATOR EFFLUENT PRIORITY POLLUTANTS' i DETECTION
SUMMARY OF EPA SCREENING PROGRAM DATA
Page 1 of 3
FRACTION
VOLATILES
CO
--4
ACID EXTRACT
PAR.
NO.
2
3
A
&
7
10
11
13
14
15
16
17
19
23
29
3O
32
33
38
44
45
46
47
48
49
50
51
85
86
87
88
21
22
24
31
34
57
58
59
to
64
65
1
5
8
PARAMETER
ACROIEIN
ACRYLONITRILE
BENZENE
CARBON TETRACHLORIDE
CHI.OROBENZENE
2-DICHLOROETHANE
1.1-TRICHLOROFTHANE
1-DICHLOROETHANE
1,2-TRICHLOROFTHANE
li2f2-TETRACHLOROFTHANE
CHLOROETHANE
BIS(CHIOROHETHYL) ETHER
7-CHLOROFTHYL VINYL ETHER
CHLOROFORM
1 , 1-DICHLOROETHYLENE
1 » 2-TRANS-DICHLOROETHYl ENE
1 , 2-DICHLOROPROPANE
1 1 3-PICHLOROPROPYI ENE
FTHYLBEN7ENE
MFTHYLFNE CHLORIDE
METHYL CHIORIDE
METHYL BROMIDE
BROMOFORM
DICHl.OROBROMOMETHANE
TRICHLOROFLUOROMETHANE
niCHLORODIFLUOROMETHANE
CHLORODIBROMOMFTHANE
TETRACH1 OROETHYLENE
TOLUENE
TRICHL OROETHYLENE
VINYL CHIORIDE
2>4f6-TRICHLOROPHENOL
PARACHLOROHETA CRESOL
2-CHl.OROPHENOL
2>4-DICHLOROPHENOL
2i4-DIMFTHrLPHFNOL
2-NITROPHFNOL
4-NITROPHENOL
2.4-PINITROPHFNOL
4.6-DINITRO-O-CRESOL
PFNTACHl OROPHFNOL
PHENOL
ACFNAPHTHENE
BENZIDINE
1 »2,4-TRICHLOROBEN7ENE
TOTAL TOTAL
PI ANTS PLANTS SAMPIES TIMES
UNITS SAMPIED DETECTING ANALYZED DETECTED
BASE-NFIITRALS
L-LESS THANI T-TRACFI N-P NOT PETFCTFIII
UO/L
UO/L
UO/l
UO/L
UO/l
UO/L
UO/L
UO/l.
UO/L
UO/L
UG/l
UG/L
UO/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/l
UG/L
UG/L
UG/L
UG/L
UG/L
UG/l
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UG/L
UO/L
UG/L
UG/L
UG/L
UG/L
UO/l
UG/L
HG/L
UG/L
UG/L
Note:
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
10
10
10
10
10
10
10
10
10
10
10
10
10
10
Laboratory
detection
0
0
8
0
0
0
0
0
0
0
0
0
0
5
0
1
0
0
6
8
0
0
0
1
0
0
0
1
8
0
0
0
0
0
0
5
9
6
0
0
analysis
limit Is
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
IS
15
IS
IS
15
IS
15
15
reported
considered
0
0
9
0
0
0
0
0
0
0
0
0
0
6
0
1
0
0
7
9
0
0
0
1
0
0
0
1
9
0
0
0
0
0
0
4
1
1
1
1
1
12
6
0
0
as less than
not detected
(value = 0) for this table.
-------
TABLE ¥1-4
UIRECT BI50HAR6E
SEPARATOR EFFLUENT PRIORITY POLLUTANTS' UETECT10N
SUMMARY OF EPA SCREENING PROG I AM DATA
Page 2 of 3
FRACTION
BASE-NEUTRALS
PAR.
NO.
PARAMETER
TOTAL TOTAL
PLANTS PLANTS SAMPLES TINES
UNITS SANPLED DETECTING ANALYZED DETECTED
CO
00
PESTICIDES
9 HEXACHLOROBENZENE
12 HEXACHLOROETHANE
18 BIS(2-CHLOROETHYL) ETHER
20 2-CHLORONAPHTHALENE
25 lf2-I>ICHLOROFENZENE
26 lr3-DICHLOROBENZENE
27 1r4-DICHLOROBENZENE
28 3r3'-DICHLORDBEN7lDlNE
35 2>4-DINITROTOLUFNE
36 2>6-DINITROTOLUENE
37 li2-DIPHENYI.HYDRAZINE
39 FLUORANTHENE
40 4-CHLOROPHENY1. PHENYL ETHER
41 4-BROHOPHENYL PHENYL ETHER
42 BIS(2-CHLOROISOPROPYL> ETHER
43 BIS<2-CHLQROETHYOXYJ HETHANE
52 HEXACHLOROBUTADIENE
53 HEXACHLOROCYCl.OPENTADIENE
54 ISOPHORONE
55 NAPHTHALENE
56 NITROBENZENE
61 N-NITROSODIMETHYLAHINE
62 N-NITROSODIPHFNY1AMINE
63 N-NITROSODI-N-PROPYLAHIHE
66 BIS<2-ETHYLHEXYL) PHTHALATE
67 BUTYL BENZYL PHTHALATE
68 DI-N-BUTY1. PHTHAl ATE
69 DI-N-OCTYL PHTHALATE
70 DIETHYL PHTHALATE
71 DIMETHYL PHTHALATE
72 1t2-BEN7ANTHRACENE
73 BENZO (A)PYRENE
74 3>4-BENZOFLUORANTHENE
75 11.12-BENZOFLUORANTHENE
76 CHRYSENE
77 ACENAPHTHYLENE
78 ANTHRACENE
79 It12-BENZOPERYLENE
SO Fl UORENE
81 PHENANTHRF.NE
82 1.2IS»6-DIBENZANTHRACENE
83 INDENO3-CrD> PYRENE
84 PYRENE
89 AI.DRIN
90 nmtlRIN
91 CHI.ORDANE
L-LESS THANI T-TRACEi N-D NOT PFTFCTEIH
UO/L
UO/L
UG/L
UG/l.
UO/L
UG/L
UG/L
UG/L
UO/L
UG/L
UG/l.
UO/L
UO/L
UO/L
UG/L
UO/L
UO/L
UO/L
UG/l.
UG/L
UG/L
UG/L
UG/L
UO/L
UG/L
UO/I
UG/L
UO/L
UO/L
UO/I.
UG/L
UO/L
UG/L
UG/L
UO/L
UG/L
UO/L
UO/L
UO/L
UG/L
UG/L
UG/L
UG/L
UO/L
UG/L
UO/L
Note:
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
Laboratory
detection
0
0
0
0
0
0
0
0
0
0
0
4
0
0
0
0
0
0
1
8
0
0
0
0
4
0
1
0
1
0
0
0
0
0
4
3
1
0
2
6
0
0
2
1
0
0
analysis
limit is
15
15
15
IS
IS
IS
IS
15
15
15
IS
IS
IS
15
15
15
15
15
15
15
IS
15
IS
15
IS
IS
15
15
15
15
IS
15
15
15
IS
15
15
15
15
15
15
15
15
15
15
IS
reported
considered
0
0
0
0
0
0
0
o
0
0
0
s
0
0
0
0
0
0
1
9
0
0
0
0
7
0
1
0
1
0
0
0
0
0
8
3
1
0
3
8
0
0
2
1
0
0
as less tnan ,
not detected
-------
TABLE VI-4
DIRECT DISCHARGE
SEPARATOR EFFLUENT PRIORITY POLLUTANTS' DETECTION
SUMMARY OF EPA SCREENING PROGRAM DATA
Page 3 Of 3
FRACTION
PESTICIDES
to
METALS.
PAR.
NO.
92
93
94
95
96
97
9B
99
100
101
102
103
104
105
106
107
108
109
110
111
112
in
129
114
115
117
118
119
120
121
122
123
124
125
12A
127
128
PARAMETER
4i4'-DDT
4f4'-DDE
4t4'-DDD
ALPHA-ENDOSULFAN
BETA-ENDOSUl.FAN
FNDOSULFAN
FNDRIN
SULFATE
ENDRIN ALDEHYDE
HFPTACHLOR
HEPTACHLOR
At PHA-BHC
BETA-BHC
OAMHA-BHC
DELTA-BHC
PCB-1242
PCB-1254
PCB-1221
PCB-1232
PCB-1248
FCB-1260
PCB-1016
TOXAPHENE
TCDD
ANTIMONY
ARSENIC
BERYLLIUM
CADMIUM
CHROMIUM
COPPER
CYANIDE
LEAD
MERCURY
NICKEL
SELENIUM
SILVER
THAI LIUM
ZINC
EPOXIDE
NON-CONV. METALS 148 HEX-CHROMIUM
MISC.
167 PHFNOIICS (4AAPO)
TOTAL TOTAL
PLANTS PLANTS SAMPLES TIMES
UNITS SAMPLED DETECTING ANALY7FD DETECTED
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/L
UO/l
UG/L
UO/L
(IG/L
UO/L
UO/L
UG/L
IIG/L
UO/L
UO/L
UO/L
(10 /I.
UO/L
UO/L
UG/L
UO/L
UG/L
UO/L
UG/L
U8/L
UO/L
UO/L
UG/L
UO/L
UG/L
IIG/L
UG/L
UG/L
UG/L
UO/l.
UG/L
UO/L
Note:
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
9
10
Laboratory
detection
0
1
0
0
1
0
0
0
0
0
0
0
0
1
3
0
1
2
0
0
3
0
0
2
5
1
1
10
8
9
7
7
7
4
1
1
10
6
10
analysis
limit Is
IS
15
15
15
IS
IS
15
15
IS
IS
IS
15
IS
IS
15
15
IS
IS
15
15
15
IS
15
15
19
75
78
92
79
47
81
80
78
39
75
40
100
42
48
reported
considered
0
l
0
0
1
0
0
0
0
0
0
0
0
1
3
0
1
2
0
0
3
0
0
2
13
1
4
80
61
38
39
61
17
29
3
4
89
22
46
as less than i
not detected
(value = 0) for this table.
L-LESS THAN) T-TRACEi N-D NOT DFTECTEDI
-------
1 of 2
TABLE VI-5
PRIORITY POLLUTANTS NOT DETECTED IN TREATED EFFLUENTS
DISCHARGED DIRECTLY, AND EXCLUDED FROM REGULATION
Pursuant to Paragraph 8(a)(iii) of the Settlement Agreement, the following 98
priority pollutants are excluded from national regulation because they were not
detected in effluents from BPT treatment systems by Section 304(h) analytical
methods or other state-of-the-art methods:
EPA EPA
No. Priority Pollutant No.
2 acrolein 52
3 acrylonitrile 53
5 benzidine 54
6 carbon tetrachloride 55
7 chlorobenzene 56
8 1,2,4-trichlorobenzene 57
9 hexachlorobenzene 58
10 1,2-dichloroethane 59
11 1,1,1-trichloroethane 60
12 hexachloroethane 61
13 1,1-dichloroethane 62
14 1,1,2-trichloroethane 63
15 1,1,2,2-tetrachloroethane 64
16 chloroethane 65
18 bis(2-chloroethyl)ether 67
19 2-chloroethylvinyl ether 69
20 2-chloronaphthalene 72
21 2,4,6-trichlorophenol 74
24 2-chlorophenol 75
25 1,2-dichlorobenzene 77
26 1,3-dichlorobenzene 78
27 1,4-dichlorobenzene 79
28 3,3'-dichlorobenzidine 80
29 1,1-dichloroethylene 82
30 1,2-trans-dichloroethylene 83
32 1,2-dichloropropane 85
33 1,3-dichloropropylene 87
34 2,4-dimethylphenol 88
35 2,4-dinitrotoluene 89
36 2-6-dinitrotoluene 90
37 1,2-diphenylhydrazine 91
38 ethylbenzene 92
39 fluoranthene 93
40 4-chlorophenyl phenyl ether 94
41 4-bromophenyl phenyl ether 95
42 bis(2-chloroisopropyl) ether 96
43 bis(2-chloroethoxy) methane 97
45 methyl chloride 98
46 methyl bromide 99
47 bromoform 100
48 dichlorobromomethane 101
51 chlorodibromomethane 102
Priority Pollutant
hexachlorobutadiene
hexachlorocyclopentadiene
isophorone
naphthalene
nitrobenzene
2-nitrophenol
4-nitrophenol
2,4-dinitrophenol
4,6-dinitro-o-cresol
N-nitrosodimethylamine
N-nitrosodiphenylamine
N-nitrosodi-n-propylamlne
pentachlorophenol
phenol
butyl benzyl phthalate
di-n-octyl phthalate
benzo(a)anthrace ne
3,4-benzofluoranthene
benzo(k)fluoranthane
acenaphthylene
anthracene
benzo(ghl)perylene
fluorene
dibenzo(a,h)anthracene
ideno(1,2,3-cd)pyrene
tetrachloroethylene
trichloroethylene
vinyl chloride
aldrin
dieldrin
chlordane
4,4'-DDT
4,4'-DDE
4,4'-DDD
alpha-endosulfan
be ta-endosulfan
endosulfan sulfate
endrin
endrin aldehyde
heptachlor
heptachlor epoxide
alpha-BHC
140
-------
TABLE VI-5 (Cont'd)
2 of 2
EPA
No. Priority Pollutant
103 beta-BHC
104 gamma-BHC
105 delta-BHC
106 PCB-1242
107 PCB-1254
108 PCB-1221
109 PCB-1232
EPA
No. Priority Pollutant
110 PCB-1248
111 PCB-1260
112 PCB-1016
113 toxaphene
114 antimony (total)
116 asbestos
129 2,3,7,8-tetrachlorodibenzo-p-
dioxin (TCDD)
141
-------
TABLE VI-6
PRIORITY POLLUTANTS DETECTED IN TREATED EFFLUENTS
DISCHARGED DIRECTLY, BUT EXCLUDED FROM REGULATION
I. Pursuant to Paragraph 8(a)(lli) of the Settlement Agreement, the following
25 priority pollutants are excluded from national regulation because they
are already effectively controlled by technologies upon which other
effluent limitations and guidelines are based:
EPA
No. Priority Pollutant
1 acenaphthene
4 benzene
22 parachlorometacresol
23 chloroform
31 2,4-dichlorophenol
68 di-n-butyl phthalate
70 diethyl phthalate
71 dimethyl phthalate
73 benzo(a)pyrene
76 chrysene
81 phenanthrene
84 pyrene
86 toluene
EPA
No. Priority Pollutant
115
117
118
120
121
122
123
124
125
126
127
128
arsenic
beryllium
cadmium
copper
cyanide
lead
mercury
nickel
selenium
silver
thallium
zinc
II. Pursuant to Paragraph 8(a)(iii) of the Settlement Agreement, the following
two priority pollutants are excluded from national regulation because
their detection is believed to be attributed to laboratory analysis and
sample contamination:
EPA
No. Priority Pollutant
44 methylene chloride
66 bis(2-ethylhexyl) phthalate
142
-------
TABLE VI-7
Statistical Analysis Table for the Petroleum Refining Industry'
Direct Discharge - Current/BPT
Pollutant
Chloroform
Benzene
Toluene
2 , 4-0 1 eh 1 or opheno 1
p-ch 1 oro-ffl-creso 1
Dimethyl ph thai ate3
Dl ethyl ph thai ate
0!-n-butyl phthalate
Acenaphthene
Benzo(a)pyrene
Chyrsene
Phenanthrene
Pyrene ^
Arsenic
Bery 1 1 1 urn
Cadmium '
Chromium (Trlvalent)
Chromium (Hexavalent)
Copper
Cyanide
Lead
Mercury
Nickel
Selenium
Silver3
Thai Hum
Zinc
Average
Flow-Weighted
Pol 1. Cone.
(uq/l )
3.1
2.3
10.1
0.2
0.3
0.1
1.5
0.04
1.1
0.1
0.02
0.2
0.1
0.01
0.04
0.25
107.8
7.7
9.8
45.3
5.2
0.9
3.4
17.2
0.04
3.2
104.6
Maximum
Pol lutant
Concentration
(ug/l)
66
11
35
10
10
3
30
10
6
3
1
1
7
31
2
20
1230
110
199
320
113
6
74
32
4
12
620
Frequency
of Detection
2/17
3/17
1/17
1/17
1/17
1/17
1/17
2/17
1/17
2/17
2/17
1/17
1/17
3/17
2/51
3/53
41/53
8/48
26/50
26/39
10/54
20/45
13/55
17/20
1/47
5/14
43/59
Footnote :
^11 129 priority pollutants were analyzed during the sampling of the Current/BPT
wastestream. Thirteen organic pollutants and fourteen Inorganic pollutants were detected.
The Current/BPT concentrations were calculated by flow-weighting the data available for
the seventeen direct dischargers sampled.
2Low values were not Included, and were assumed to be not quantifiable. High values
were not Included because laboratory contamination was suspected; therefore, data were
assumed to be Invalid.
Current/BPT pollutant concentration Js greater than In the Pretreated Raw
wastestream because of the variability of the data during sampling.
143
-------
TABLE VI-8
PRIORITY POLLUTANTS NOT DETECTED IN TREATED EFFLUENTS
DISCHARGED TO POTW, AND EXCLUDED FROM REGULATION
Pursuant to Paragraph 8(a)(ill) of the Settlement Agreement, the following 75
priority pollutants are excluded from national regulation because they were
not detected by Section 304(h) analytical methods or other state-of-the-art
methods in effluents discharged to POTW:
EPA
No. Priority Pollutant
EPA
No.
3 acrylonitrile 62
5 benzidine 63
6 carbon tetrachloride 66
8 1,2,4-trichlorobenzene 69
9 hexachlorobenzene 71
12 hexachloroethane 74
13 1,1-dich^oroethane 75
14 1,1,2-trichloroethane 79
15 1,1,2,2-tetrachloroethane 82
16 chloroethane 83
18 bis(2-chloroethyl)ether 87
19 2-chloroethylvlnyl ether 88
20 2-chloronaphthalene 90
21 2,4,6-trichlorophenol 91
22 parachlorometa eresol 94
25 1,2-dichlorobenzene 95
26 1,3-dichlorobenzene 97
27 1,4-dichlorobenzene 98
28 3,3'-dichlorobenzidine 99
29 1,1-dichloroethylene 100
31 2,4-dichlorophenol 101
32 1,2-dichloropropane 102
33 1,3-dichloropropylene 103
35 2,4-dinitrotoluene 104
36 2-6-dinitrotoluene 106
37 1,3-diphenylhydrazine 107
41 4-bromophenyl phenyl ether 108
42 bis(2-chloroisopropyl) ether 109
43 bis(2-chloroethoxy) methane 110
44 methylene chloride 111
45 methyl chloride 112
46 methyl bromide 113
47 bromoform 114
51 chlorodibromomethane 116
52 hexachlorobutadiene 126
53 hexachlorocyclopentadiene 127
56 nitrobenzene 129
61 N-nitrosodimethylamine
Priority Pollutant
N-nitrosodiphenylamine
N-nit rosodi-n-propylamine
bis(2-ethylhexyl) phthalate
d-n-octyl phthalate
dimethyl phthalate
3,4-benzofluoranthene
benzo(k)fluoranthane
benzo(ghi)perylene
dibenzo(a,h)anthracene
ideno(l,2,3-C,D)pyrene
trichloroethylene
vinyl chloride
dieldrin
chlordane
4,4'-DDD
alpha-endosulfan
endosulfan sulfate
endrin
endrin aldehyde
heptachlor
heptachlor epoxide
alpha-BHC
beta-BHC
gamma-BHC (lindane)
PCB-1242
PCP-1254
PCB-1221
PCB-1232
PCB-1248
PCB-1260
PCB-1016
toxaphene
antimony (total)
asbestos
silver (total)
thallium (total)
2,3,7,8-tetrachloro-dibenzo-p-
dioxin (TCDD)
144
-------
1 of 2
TABLE VI-9
PRIORITY POLLUTANTS DETECTED IN EFFLUENTS
DISCHARGED TO POTW, BUT EXCLUDED FROM REGULATION
I. Pursuant to Paragraph 8(b)(i) of the Settlement Agreement, the following 5
priority pollutants are excluded from regulation because 95 percent or
more of all point sources in the subcategory introduce into POTW only
pollutants which are susceptible to treatment by the POTW and which do not
interfere with, do not pass through, or are not otherwise incompatible
with such treatment works:
EPA
No. Priority Pollutant
24 2-chlorophenol
57 2-nitrophenol
77 acenaphthylene
80 fluorene
125 selenium
II. Pursuant to Paragraph 8(b)(ii) of the Settlement Agreement, the following
33 priority pollutants are excluded from regulation because the amount and
toxicity of each pollutant do not justify developing national
regulations:
EPA EPA
No. Priority Pollutant No.
2 acrolein 85
7 chlorobenzene 89
10 1,2-dichloroethane 92
11 1,1,1-trichloroethane 93
23 chloroform 96
30 1,2-trans-dichloroethylene 105
39 fluoranthene 115
40 4-chlorophenyl phenyl ether 117
48 dichlorobromomethane 118
60 4,6 dinitro-o-cresol 120
64 pentachlorophenol 121
67 butyl benzyl phthalate 122
68 di-n-butyl phthalate 123
70 diethyl phethalate 124
72 benzo(a)anthracene 128
73 benzo(a)pyrene
76 chrysene
84 pyrene
Priority Pollutant
t e t rachloroe thylene
aldrin
4,4'-DDT
4,4'-DDE
beta endosulfan
delta BHC
arsenic
beryllium
cadmium
copper
cyanide
lead
mercury
nickel
zinc
145
-------
2 of 2
TABLE VI-9 (Cont'd)
III. Pursuant to Paragraphs 8(a)(iii), 8(a)(iv), and 8(b) of the Settlement
Agreement, the following 12 priority pollutants are excluded from regula-
tion for the following reasons. (1) There is significant removal of
several of the pollutants by the technology upon which existing pretreat-
ment standards for oil and grease are based. (2) There is significant
removal of all these pollutants by the POTW treatment system. (3) The
amount and toxicity of the pollutants do not justify developing national
pretreatment standards.
EPA EPA
No. Priority Pollutant No. Priority Pollutant
1 acenaphthene 58 4-nitrophenol
4 benzene 59 2,4-dinitrophenol
34 2,4-dimethylphenol 65 phenol
38 ethylbenzene 78 anthracene
54 isophorone 81 phenanthrene
55 naphthalene 86 toluene
146
-------
1 of 2
TABLE VI-10
Statistical Analysis Table for the Petroleum Refining Industry
Indirect Discharge - Current
Pollutant
Aeroieln
Aldrln
i-BHC
ODE
DOT
0-Endosulfan
1 sophorone
0 Ich 1 orobromomethane
Chloroform
1,2-Otchloroethane
Average
Flow-weighted
Poll. Cone.
Cua/M
0.7
0.6
0.6
0.4
0.01
0.6
293.3
0.1
24.6
0.9
1,1, 1-Tr Ich 1 oroethane 0.3
Trans-1,2-01chloroethene 0.1
Tetracn 1 oroethene
4-Ch 1 oropnenypheny I
ether
Benzene
Chlorobenzene
Ethyl benzene
Toluene
Pnenol
2-Chlorophenol
Pentach 1 or opheno 1
2-Nttrophenol
4-mtrophenol
2,4-OlnItrophenol
2,4-Olmethy (phenol
4 , 6-0 1 n I tro-o-ereso 1
Oiethyl phthalate
Ol-n-butyl phthalate
0.4
1.4
148.8
0.1
123.8
398.1
1368.7
28.3
2.2
63.3
361.4
1068.4
1207.7
2,9
1.3
0.1
Butyl benzyl ph thai ate 0.04
Acenap n thene
Aeenaphthylene
Anthracene
Benzo ( a )anthracene
188.9
81.3
119.2
0.4
Maximum
Pollutant
Concentration
(ua/I)
100
12
12
7
3
13
3350
24
too
34
14
20
30
30
3800
31
18000
48000
33500
313
830
1350
3800
11000
18300
60
38
40
16
522
665
1750
12
Frequency
of Detection
1/29
3/22
2/27
1/27
1/28
1/29
3/27
1/28
17/28
3/29
1/28
1/29
1/29
21/27
1/28
17/27
20/27
20/27
1/27
1/27
1/27
1/29
4/29
3/29
17/27
1/29
4/27
1/27
2/27
6/27
4/27
7/27
1/27
147
-------
2 of 2
TABLE VI-10 (Continued)
Statist tea I Analysis Table for the Petroleum Refining Industry1
Indirect Discharge - Currant
(Continued)
Pollutant
Benzo(a)pyrene
Chrysene
F 1 uoranthene
Fluorene
Naphthalene
Phenanthrene
Pyrene
Arsenic2
Beryllium
Cadmium
Average
Flow-Weighted
Poll. Cone.
(UQ/1 )
0.03
3.3
6.3
50.5
581.6
234.7
4.6
0.3
0.1
0.03
Chromium (Trlvaient) 731.1
Chromium (Hexavalent) 16.8
Copper
Cyanide
Lead
Mercury
Nickel
Selenium
Zinc
80.6
195.2
24.6
1.8
14.6
51.2
429.4
Maximum
Pol lutant
CmiCeMi rf1 Q^ ion
(UQ/I )
10
30
812
495
3750
1750
16
41
2
3
2196
410
310
3000
958
78
771
322
3000
Frequency
of Detection
1/29
4/27
4/27
4/27
18/26
13/27
5/27
9/29
3/63
1/63
58/71
23/60
52/66
53/36
21/66
28/65
6/66
10/78
65/78
Footnota:
All 129 priority pollutants «ara analyzad during ttia sampling of tha Currant
wastastraam. Forty organic pollutants and twalva Inorganic pollutants wara datactad.
Tha
pollutant concentrations wara obtained fro» How-weighting tha data for seventeen
Pretreated Raw direct and the four Currant Indirect dischargers studied In this analysis.
PSE5 limits for toxic pollutants are assumed to renain at Current levels. There Is no
flow reduction at PSE5.
values were not Included, and were assumed to be not quantifiable. High values
were not Included because laboratory contamination was suspected; therefore, data were
assumed to be Invalid.
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SECTION VII
CONTROL AND TREATMENT TECHNOLOGY
INTRODUCTION
This section describes the control and treatment technologies
that are determined to be feasible methods for the reduction of
pollutants in petroleum refining wastewater. In identifying
these technologies/ the Agency assumed that each refinery had or
would install the best practicable control technology currently
available (BPCTCA) to comply with BPT limitations (3). The
treatment technologies described below can further reduce the
amount of pollutants discharged to navigable waters. They are
divided into two broad classes: in-plant source control and
end-of-pipe treatment. (A discussion of BPT technologies is also
presented here for completeness). These two "classes" are
discussed in the following paragraphs/ along with a description
of existing wastewater treatment and its effectiveness in the
industry.
IN-PLANT SOURCE CONTROL
In-plant source control reduces the overall pollutant load that
must be treated by an end-of-pipe system and reduces or
eliminates a particular pollutant before it is diluted in the
main wastewater stream.
In developing an in-plant control scheme/ the source of each
particular pollutant must be identified and evaluated as to
whether it can be eliminated or reduced. Sampling the wastewater
at various points within the refinery sewer, beginning at the
end-of-pipe treatment system and ending at the process units/
produces a profile of the refinery sewer, which shows the origin
and flow path of the pollutant in question.
Once the source of the particular pollutant is identified/ the
next step is to determine if the pollutant can be (a) removed
with an in-plant treatment system; (b) eliminated by chemical
substitution; or (c) reduced by recycling or reusing the
particular wastewater stream. In-plant source control is further
discussed below in terms of treatment options, chemical
substitution, wastewater reduction, and wastewater reuse.
In-Plant Treatment Options
In all in-plant treatment options, the process waste streams
under consideration must be segregated. If a particular
pollutant (or pollutants) has more than one source, they all
require segregation from the main wastewater sewer. However/
similar sources can be combined for treatment in one system. Sour
water, for example is produced at various locations within a
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refinery complex but can be treated as a combined wastewater
stream.
Sour water and cooling tower blowdown are the two waste streams
for which in-plant treatment is now practiced or is available.
Sour Water. Sour water generally results from water brought into
direct contact with a hydrocarbon stream. Direct contact results
when steam is used as a stripping or mixing medium or when water
is used as a washing medium, as in the crude desalting unit.
Sour water contains sulfides, ammonia, and phenols.
The most common in-plant treatment schemes for sour waters
involve sour water stripping, sour water oxidizing, or combin-
ations of the two. These systems can greatly reduce sulfides and
ammonia levels, and can also remove some phenols (24). Table
VII-1 summarizes the extent of this technology in the refining
industry. The operation of sour water strippers and sour water
oxidizers is discussed at great length in numerous technical
publications (3, 6, 18, 20, 24, 28, 48). A sour water stripping
study was undertaken in 1972 by the American Petroleum Institute
(24). The results of this survey showed that 17 of 31 refluxed
sour water strippers and 12 of 24 non-refluxed sour water
strippers removed more than 99 percent of the sulfides. An
additional nine refluxed and three non-refluxed units removed
more than 99 percent of the sulfides and more than 95 percent of
the ammonia. The data thus suggest that, overall, refluxed
columns remove greater percentages of both pollutants. Note that
of the five two-stage units studied, only one unit removed large
percentages of both pollutants. Six of the seven strippers
operating with flue or fuel gases removed over 99 percent of the
sulfides. However, none of these units removed a high percentage
of ammonia.
The average effluent concentration of all refluxed, non-refluxed,
and flue gas units that removed more than 99 percent of the
sulfide was 6.7 mg/L of sulfide. The average effluent from all
units that removed more than 95 percent of the ammonia was 62.5
mg/L of ammonia. These averages are based upon a wide range of
influent and effluent values.
Existing sour water stripper performance can be improved by (a)
increasing the number of trays, (b) increasing the steam rate,
(c) increasing tower height, and/or (d) adding a second column' in
series (107). All these methods are now available to the
refining industry.
Biological treatment to remove total phenols is also a
demonstrated technology in this industry (48). Biological
treatment of stripped sour waters may prove cost-effective in
removing any biodegradable organic priority pollutants that may
originate in this waste stream.
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Phenols can also be removed from the sour water waste stream by
the addition of oxidizing agents, such as ozone (51), hydrogen
peroxide (11), chlorine, chlorine dioxide, and potassium
permanganate (113).
A recent research project demonstrated that activated carbon also
removes phenolic compounds. The experiment showed that activated
carbon has a high affinity for phenolic compounds, requiring
relatively short detention times. Activated carbon treatment in
sour water streams may also remove any other organic priority
pollutants present. Refinery 237 uses activated carbon to treat
the sour water waste stream, and the Agency has investigated this
particular system further.
Cooling Tower Slowdown. Metals (such as chromium and zinc) and
phosphate can be removed by precipitation and clarification at a
relatively high pH (8 to 10). Hexavalent chromium, however, must
be first reduced to the trivalent state before it can be
precipitated and removed by clarification. Reduction is usually
accomplished by adding sulfur dioxide, ferrous sulfate, or sodium
bisulfite. The pH of the wastewater then rises with the addition
of lime or caustic (lime is preferred if phosphates are to be
precipitated), and the wastewater stream is clarified.
Flocculants and flocculant aids, such as ferric chloride, alum,
and polymers, can be added to increase removal efficiencies.
Japan's Mitsubishi Petrochemical Company has reported a new
treatment technique for the removal of heavy metal ions (126).
The system involves electrolytic coagulation in which electrical
currents cause an iron electrode to dissolve. The iron combines
with heavy metals and added hydroxide ion to form a sludge that
can be precipitated rapidly from solution. Magnets aid the
settling process. Mitsubishi reports that the new treatment
system can reduce Cr+* concentration to less than 0.05 ppm in
2900 gallons of metal plating wastewater. This system could be
used to treat cooling tower blowdown streams at petroleum
refineries.
Chemical Substitution
Chemicals are added to cooling tower recirculating water and
boiler water to reduce corrosion, scaling, and biological growth.
These chemicals usually include chromium, zinc, phosphates, and
free chlorine.
Using organic chemicals to replace zinc and chromium solutions is
also a viable alternative (53,54). Molybdates are also a
practical alternative (55). (Molybdates are compounds containing
the anion MQ4-2 )
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Wastewater Reduction
Reduction in water usage may sometimes be more cost-effective if
the wastewater discharge is reduced, rather than reusing or
recycling the existing amount of wastewater discharged. Good
housekeeping is one inexpensive method of reducing wastewater and
may include (a) shutting down pump gland cooling water lines on
pumps that are out of service; (b) shutting down washdown hoses
that are not in use, (c) eliminating leaks, (d) using dry
cleaning methods/ and (e) using vacuum trucks to clean up oil
spills. Numerous other housekeeping procedures are commonly
practiced throughout the industry.
Many new and modified refineries incorporate reduced water use
and pollutant loading into their design. Some of these
modifications include:
o Substitution of improved catalysts that require less
regeneration.
o Replacement of barometric condensers with surface
condensers or air fan coolers.
o Replacement of surface condensers with air fan coolers.
o Use of hydrocracking and hydrotreating processes that
produce lower wastewater loadings than existing
processes.
o Increased use of improved drying, sweetening, and
finishing procedures to minimize spent caustics and
acids, water washes, and filter solids requiring
disposal.
o Recycle of wastewater at the process units to reduce the
amount of wastewater leaving the process area.
A major process change that can reduce wastewater is the
substitution of air cooling devices for water cooling systems.
Many refineries have installed air cooling systems with their new
process installations, thereby reducing the additional wastewater
production associated with increased refinery complexity.
Of the 78 refineries for wh;Lch comparative data are available
between 1972 and 1976, the use of air cooling systems has
increased at 39 refineries, has decreased at 26 refineries, and
has remained the same at 13 refineries. Increased use of air
cooling systems can reduce the quantity of cooling tower blowdown
discharges that require treatment.
Another method of reducing wastewater is to eliminate cooling
water from general purpose pumps (117). In certain instances the
elimination of water can increase machinery reliability, reduce
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capital expenditures for piping and water treatment facilities,
and save operating costs. Guidelines are available for
implementing a well-planned, step-by-step program of deleting
cooling water from pumps and drivers. These procedures have been
successfully implemented on a full-scale basis (117).
Wastewater Reuse
Many streams, such as treated sour waters, cooling tower
blowdowns, and utility blowdowns, are suitable for use as wash
water and fire system water. However, before reusing wastewater
for these purposes, each plant must be investigated to determine
the technical and economic feasibility.
Wastewe. jrs emanating from end-of-pipe BPT facilities are
generally of such quality that reuse can be quite attractive.
Uses for treated refinery wastewaters include makeup water for
cooling towers, pump gland cooling systems, washdown water, and
fire water systems.
A number of articles in recent years describe actual reuse
practices at one refinery (41, 57, 58). This plant reuses most
of its treated wastewater as makeup to the cooling tower and fire
water systems. In practice, the cooling towers act as biological
treatment units, removing over 99 percent of the phenols present
(41). The refinery reuses approximately 4.5 million gallons of
process wastewater per day in the cooling towers; about 2.2
million gallons of cooling tower blowdown per day are sand
filtered and discharged to the receiving stream. The difference,
over 2 million gallons per day, is evaporated in the cooling
towers or in an impounding basin (58). Wastewater reuse began at
this refinery in 1954. Years of operating experience have
confirmed that reuse water is a satisfactory makeup supply to
cooling towers and does not require special water conditioning or
treatment. Continued monitoring has confirmed that the system
has no problems of corrosion, heat transfer, or cooling tower
wood deterioration. Refinery management has concluded that
cooling water reuse is an economically sound practice, paying
significant dividends in terms of both pollution abatement and
water conservation (57).
Finelt and Crump (128) report that refiners faced with increasing
freshwater costs may direct their water management policies
toward the recirculation of treated water. Properly treated
wastewater can be recycled as makeup to the cooling tower system.
At new refineries, the recycle system could be justified
economically over a non-recycle system for a number of reasons.
There are a number of factors to be considered, most notably the
cost. The cost of fresh water primarily determines the least
costly system. At existing well-operated facilities, only at
very high freshwater costs can the recycle system prove to be
less costly than a non-recycle system. However, application of
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recycle technology can reduce effluent discharge by up to 90
percent.
The use of sour waters as makeup to the desalter is a proven
technology in this industry. This practice does remove some
phenol because the phenolics are extracted from the sour water
while the crude is washed. However, the removal efficiency
varies greatly, depending on a number of factors, and this
treatment scheme may not be a practical alternative for some
refineries (48). Certain crudes, particularly California crudes,
may present problems in reusing sour waters in the desalter
because they produce emulsions in the desalter effluent.
Table VI1-2 identifies refineries with California crudes that
recycle wastewater; the table also lists the percentage of
California crudes that makeup crude capacity and the percentage
of reused sour waters. These data show that refineries
processing California crudes do not use large percentages of sour
water in the desalter. In fact, refineries that use a large
percentage of California crudes appear to reuse less sour water
than refineries that process a small percentage of California
crude. However, Table VII-3 shows that five of the six plants in
this analysis do reuse sour water elsewhere in the refinery.
Sour water from stripper bottoms has other demonstrated uses in
the petroleum refining industry (36). It can be reused as
cooling tower makeup and as process wash water. In the
biological environment in most cooling systems, 90 percent or
more of the phenols present can be removed (36).
The 1977 Survey shows that 36 refineries reuse 100 percent of
their treated sour waters in the desalter, while an additional 43
plants reuse at least some portion of their treated sour waters
in the desalter. In addition, 32 refineries reuse treated sour
waters in some other process. Of these plants, four reuse 100
percent of their treated sour waters as makeup to cooling towers.
Table VII-3 summarizes the extent of industry reuse of treated
sour waters.
The American Petroleum Institute published Water Reuse Studies in
August 1977 (150). This document presents methods for achieving
zero discharge, including:
o Recycle and reuse of treated effluent as well as other
wastewaters
o Recovery and reuse of condensate streams
o Evaporation of wastewater with waste heat
0 Use of brine concentrators to eliminate high TDS streams.
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The API report concludes that for most existing refineries, "(1)
engineering concepts are available which indicate complete reuse
of refinery water is technically possible and (2) the capital and
operating costs appear favorable for complete recycle
."(150).
The recycle of treated effluent as cooling tower makeup or for
other uses is certainly a viable treatment alternative.
Significant reductions in wastewater generation can decrease the
quantities of pollutants discharged to navigable waters. When
refineries improve the present wastewater management system by
minimizing cooling tower blowdown, the treated effluent to be
recycled may require softening before recirculation.
To determine an upper limit of how much treated wastewater can be
reused as cooling tower makeup, the amount of cooling tower
makeup required by each plant in the industry is summarized in
Table VI1-4. The percentage of cooling tower makeup water in the
total wastewater discharged is also shown. This table has been
derived from the 1977 survey data base. Approximately half the
facilities have a cooling tower makeup water requirement that
equals or exceeds the total refinery discharge flow.
In order to determine the degree of flow reduction that can be
achieved on a national basis, EPA developed a flow model. The
objective of the model was to estimate the average wastewater
discharge flow from refineries which use similar processes. The
model established which refineries are discharging less flow than
other facilities. The higher flow refineries may be subject to
flow reduction requirements.
In the proposed revisions of December 1979, an industry average
flow reduction of 52% was required. This reduction level was
determined by selecting the medium performance of refineries
which are discharging less then the model predicts. The flow
model upon which the proposal was based was found to be
statistically deficient. A refined flow model was developed (see
Section IV).The overall flow reduction as calculated from the
refined flow model is 37.5%. For the purpose of confirming the
achievability of this flow level, a detailed engineering study
was conducted at 15 refineries located throughout the United
States. The results of this study showed that the 37.5%
reduction on an industry wide basis is technically achievable
(159). A summary of the techniques identified for reusing
wastewaters and reducing discharge flow rates at the refineries
studied is presented in Table VI1-5.
END-OF-PIPE TREATMENT
End-of-pipe treatment is defined here as all wastewater treatment
systems that follow an API separator or a similar oil/water
separation unit. The following end-of-pipe treatment techniques
are available for the reduction of pollutants in petroleum
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refining wastewater: a) biological treatment, b) filtration, c)
granular activated carbon, d) powdered activated carbon, e)
cyanide removal, and f) metals removal. These techniques are
discussed below, along with the carbon studies conducted by the
EPA Kerr Lab, and ultimate disposal methods.
Biological Treatment
Biological treatment is the basic process by which most
refineries meet existing BPT guidelines. Very large amounts of
oxygen-demanding compounds (as measured by the BOD5> COD, and TOC
test methods) are removed at many refineries through the
application of well-designed and well-operated biological
treatment systems (146).
Many options are available to plants which would upgrade their
present biological systems. These include compartmentalized
oxidation ponds to provide preliminary mechanical aeration,
revamping of aerated lagoon systems into activated sludge
systems, and converting of standard activated sludge systems to
pure oxygen systems. Other modifications can improve the
operating efficiency of particular biological treatment units,
but each plant must be investigated to determine the feasibility
of such modification.
Rotating Biological Contactors (RBC's) have attracted widespread
attention in the United States since 1969. RBC's generally
consist of rows of plastic disks mounted on horizontal shafts
that turn slowly keeping the disk about 40 percent immersed in a
shallow tank containing wastewater (see Figure VII-1). The RBC
is a combination fixed film reactor and mechanical aerator. The
fixed film reactor is the disk upon which microorganisms attach
themselves and grow. Mechanical aeration occurs during the
portion of each rotation that a section of disk is above water
level. Microorganisms produce a film on the surface of the disk
which removes organic matter from the wastewater. Biodegradation
of organic matter causes biomass to accumulate on the surface of
each disk. Excess biomass is stripped and returned to the
wastewater stream by the shearing action of water against
rotating disks. Waste biomass is held in suspension by the
mixing action of the disks, and carried out of the reactor for
removal by a clarifier. Treatment efficiency can be improved by
increasing the number of RBC's in series, and by temperature
control, sludge recycle, and chemical addition.
RBC's have characteristics such as ability to sustain shock
loads, modular expansion, and low power consumption which may be
especially attractive for industrial application.
Full scale RBC installations treating refinery wastewaters have
resulted in removal of oxygen demanding pollutants comparable to
activated sludge and trickling filter systems (23, 172, 173).
These refineries did not report removal effectiveness for
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priority pollutants, however, they do report 4AAP phenol removals
ranging from 42 percent to 97 percent. Data from the Regional
Surveillance and Analysis program show one refinery using RBC's,
Refinery 131, which achieved priority pollutant removals similar
to the BPT systems studied in the 17 refinery B&R/RSKERL sampling
program (158, Appendix B).
The sampling data presented in Section V indicate that biological
treatment can remove organic priority pollutants to low levels
(10-100 ug/L). These samples are from both industry and POTW and
were collected and analyzed by EPA for this study.
Filtration
Filtration, utilized as a polishing step after biological
treatment, is part of model BPT treatment (3). The survey
results indicate that 27 of the 259 respondents use filtration as
part of the existing treatment scheme, including plants that use
filtration before biological treatment. Sixteen other
refineries plan to install filtration systems in the near future.
Table VI1-6 lists those refineries that have, or are planning to
install, rapid sand or dual media filtration systems. Filtration
can improve effluent quality by removing suspended solids and
associated BOD5_ and COD and by removing carryover metals that
have already been precipitated and flocculated. Filtration can
also improve overall treatment plant performance (130, 132, 133).
Use of filtration techniques to remove solids reduces the
effluent variability of biological treatment systems. One study
(30) showed that the percentage of suspended solids removed does
not deteriorate with high feed content; in fact, the amount of
solids removed often increases with feed concentration.
Concentration of suspended solids in the effluent rose during
these situations, but not in proportion to the feed increase.
Thus, one conclusion of the report is that granular media filters
may be used to clarify refinery wastewaters, including occasional
surges.
Another study (99) showed that filtration of refinery effluent
can reduce suspended solids to less than 5 mg/L for "all feed
concentrations" (8 to 91 mg/L of TSS), further supporting the
fact that filters can reduce the effluent variability of
biological treatment systems.
One petroleum refining company uses rapid sand filtration to
treat its biological treatment plant influent (150). Biological
treatment systems now remove both suspended and dissolved
materials. However if filtration is used before biological
treatment to remove the suspended material not removed in primary
treatment, the biological system can remove more dissolved
organics and generate fewer solids (50). Another advantage of
prefiltration is that it allows the biological system to operate
at increased sludge ages (20 to over 40 days). With high sludge
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ages, treatment efficiencies are greater and less sludge is
generated with fewer system upsets.
Granular Activated Carbon
Granular activated carbon has been used in the potable water
industry for many years; recently industrial and municipal
wastewater treatment plants have used it to remove dissolved
organics (49). Activated carbon systems have functioned both as
polishing units following a biological treatment system and as
the major treatment process in a physical/chemical treatment
system.
The granular activated carbon system considered here consists of
one or more trains of carbon columns, each train having three
columns operated in series. The columns operate by rotating their
positions in the train. The newly regenerated carbon would be in
the third vessel, whereas the vessel with the most spent carbon
would be the first vessel. One possible piping and equipment
arrangement showing this scheme is presented in Figure VI1-2.
Smaller refineries may require only one or two vessels operated
manually without the sophisticated piping arrangement shown in
Figure VII-2.
EPA expects that all but the smallest systems will require on-
site regeneration of carbon. Figure VII-3 is a flow diagram of
one possible carbon regeneration system. In some instances,
filtration may be needed before carbon adsorption to remove
suspended solids and prevent plugging of the carbon pores.
Refinery 168 treats all wastewater with activated carbon. This
refinery uses granular activated carbon as the main treatment
process; that is, it uses no biological treatment system for
organic and BOD removal before adsorption. The refinery has
experienced operating problems with the system (many of which
have been mechanical in nature) and now plans to install a
biological treatment facility to replace the carbon system.
Powdered Activated Carbon
A new technology developed over the past several years consists
of adding powdered activated carbon to biological treatment
systems. The adsorbant quality of carbon, which has been known
for many years, aids in the removal of organic materials in the
biological treatment unit (144). This treatment technique also
enhances color removal, clarification, and system stability, as
well as BOD and COD removal (115, 116). Results of pilot testing
(59, 60) indicate that this type of treatment, when used as a
part of the activated sludge process, is a viable alternative to
granular carbon systems.
One chemical manufacturing complex has installed a full-scale, 40
MGD powdered activated carbon system that started up during the
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spring of 1977 (61). A simplified flow diagram is presented in
Figure VII-4. The waste sludge, which contains powdered carbon,
is removed from the activated sludge system and thickened in a
gravity thickener. The sludge is then dewatered in a filter
press before being fed to the regeneration furnace. The
regenerated carbon is washed in an acid solution to remove metals
as well as other inorganic materials. Fresh carbon is added as
makeup to replace the carbon lost in the overflow from the
activated sludge process or in the regeneration system.
The powdered activated carbon system just described is a very
comprehensive treatment system and includes operations that not
all installations may require. The decision to use a filter
press system or acid cleaning system in addition to a carbon
regeneration furnace should be made individually, since some
refineries may not require every treatment step. If the metals
content is low and most of the solids are settleable, the filter
press or acid cleaning systems may not be required even by
refineries that regenerate carbon onsite.
Several tests in which powdered activated carbon was added to
petroleum refinery activated sludge systems were conducted.
Rizzo reported on a plant test in which carbon was added to an
extended aeration treatment at the Sun Oil Refinery in Corpus
Christi, Texas (150). In this test, three carbon dosages, 24
ppm, 19 ppm, and 9 ppm, were tried. Test results showed that
even the very small carbon dosages significantly improved BOO,
COD, and TSS removals, as well as producing uniform effluent
quality, a clearer effluent and eliminating foam.
Grieves et al. (153) reported on a pilot plant study at the Amoco
refinery in Texas City where activated carbon was added to the
activated sludge process in 37.9- liter (10- gallon) pilot plant
aerators. Significant amounts of soluble organic carbon (53
percent), soluble COD (60 percent), NH3-N (98 percent), and
phenolics were removed after 50 mg/L of high surface area carbon
was added. The amounts removed increased with increasing carbon
dosage.
Exxon researchers tried adding activated carbon to bench scale
activated sludge units with somewhat less success (154). They
evaluated three carbon dosages, which produced aerator
equilibrium carbon levels of 25 to 2,000 mg/L. At aerator carbon
levels of 25 to 400 mg/L, the performance of the activated sludge
process did not improve. This low dosage is usually an
inadequate amount of carbon, which gets lost or overwhelmed in
the system.
At higher carbon dosages, aerator carbon levels of 1,000 mg/L or
more, Exxon got positive results. In a field test (scale
undisclosed), Thibault et al. significantly improved effluent
quality and noted improvement in shock loading resistance leading
159
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to process stability. An additional 10 percent of TOG and COD
was removed.
Another powdered activated carbon scheme that uses very high
sludge ages (60 days or more) has been studied (60, 145). The
high sludge ages allow carbon to accumulate to high
concentrations in the mixed-liquor, even though only small makeup
amounts are added to the system. This approach may eliminate the
costly regeneration scheme previously described because of the
low carbon addition rates and spent carbon may be disposed of
with the sludge. Considerable pilot work has been done with this
concept, but no full-scale system is currently operating.
Pilot tests (62) have also shown that powdered activated carbon
can be used successfully with rotating biological contactors
(RBCs). Refinery 32 has constructed a full-scale system on the
basis of pilot test results.
Cyanide Removal
Various treatment technologies are available for the removal of
cyanides. Cyanide can be removed by treatment with ferrous
sulfate. This precipitates the cyanide as a ferrocyanide, which
can be removed in a subsequent sedimentation step. For the coil
coating industry, a long-term effluent concentration of 0.07 mg/L
was achieved via this technology (169).
Chlorine oxidation is a common technique of cyanide treatment.
Chlorine is used primarily as an oxidizing agent in industrial
waste treatment to destroy cyanide. Chlorine can be used in the
elemental or hypochlorite form. The two step chemical reaction
is:
C12 + NaCN + 2NaOH - NaCNO + 2 NaCl + H20 (2)
3C12 + 6NaOH + 2NaCNO - 2NaHC03 + N2 + 6 NaCl + 2H20 (2)
The long-term concentrations achieved by the metal plating and
inorganic chemical industry (hydrogen cyanide subcategory) are
0.18 mg/L (171) and 0.21 mg/L, (170) respectively.
Cyanide can also be removed by steam stripping and biological
treatment. Both of these technologies are currently being used
by the petroleum refining industry. Steam stripping removes
approximately 50% (See Table VI1-6) of the cyanide, and
biological treatment removes approximately 75%. The long-term
concentration of cyanide being discharged by the petroleum
refining industry after steam stripping and biological treatment
is 0.16 mg/L.
Metals Removal
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Metals such as copper, zinc, lead, arsenic, and cadmium may
originate from many sources within a refinery, and may, in
specific cases, require end-of-pipe treatment. The development
document published in March 1974 for the copper, nickel,
chromium, and zinc segment of the electroplating industry (114)
considered chemical precipitation and clarification to be the
best practicable treatment in that category. The best plants in
that industry obtained the following long-term average effluent
concentrations for selected metals:
o Copper (Cu) 0.2 mg/L
o Nickel (Ni) 0.5 mg/L
o Hexavalent Chromium (Cr+«) 0.055 mg/L
o Trivalent Chromium (Cr(T)) 0.3 mg/L
o Zinc (Zn) 0.3 mg/L
o Cyanide (CN) 0.04 mg/L
The results of the RSKERL and Burns and Roe supplemental sampling
programs (see Section V) show that BPT in the refining industry
achieves metal discharges similar to or lower than the values
shown; therefore, end-of^pipe chemical precipitation and
clarification generally will not significantly improve the metals
concentrations in petroleum refinery effluent over those
achievable with existing BPT. Further reductions in the
concentration of metals would require advanced wastewater
treatment schemes, such as ion exchange, reverse osmosis, or
activated carbon (147).
Since the chemical treatment scheme described earlier is applied
as an in-plant measure, the actual discharge concentration of
chromium may be lowered by dilution of the cooling tower blowdown
in the final effluent stream.
A study was conducted to determine whether separate treatment of
cooling tower blowdown prior to mixing with other refinery
process wastewaters would be practical. Site visits were made to
fifteen refineries and engineering analyses were performed to
determine: (1) the feasibility of separating cooling tower
blowdown and (2) the advantage of separate treatment. The
findings of the study are: (1) not all cooling tower blowdown
streams are collectable (especially for older refineries where
sources of leaks-cannot be found); and (2) some cooling tower
blowdown is highly contaminated with oil. Therefore, cooling
tower blowdown may still require biological treatment. The
conclusion from the study is that a national regulation requiring
separate treatment of cooling tower blowdown for existing
refineries is not technically feasible.
RSKERL Carbon Studies
The Robert S. Kerr Environmental Research Laboratory (RSKERL)
studied the implementation and effects of carbon treatment at six
refineries as part of this study.
161
-------
In the granular carbon tests, four columns were operated in
parallel. Each column contained a different type of carbon so
that differences in performance could be determined. One column
contained previously exhausted and then regenerated carbon. The
other three columns contained different types of virgin carbon.
Using the isotherm testing method, the laboratory conducted field
tests to determine which of the virgin carbons demonstrated the
best .performance. The effluents from the "best" virgin carbon
and the "regenerated" carbon were then tested to evaluate removal
capabilities. The inlet wastewater to the carbon columns was
treated using multi-media filtration.
RSKERL also tested a powdered activated carbon system at four of
the six refineries. The test unit consisted of a small activated
sludge pilot unit to which powdered carbon was added on a batch
basis.
Because of the limited testing period, the low concentration of
toxic pollutants in the influent to the PAC system, and lack of
repeated carbon exhaustion and regeneration, the data from these
pilot tests are insufficient to determine removal effectiveness.
Ultimate Disposal Methods
The use of flow reduction and the recycle methods previously
described will reduce the quantity of water discharged or that
needing end-of-pipe treatment. None of the techniques discussed
will eliminate the discharge of water. Zero discharge of water
is technically achievable. 55 existing refineries have reported
zero discharge. Table VI1-7 presents information on the
capacities and disposal methods used by these 55 refineries. Of
the 55 plants, 32 use evaporation or percolation ponds, 10 use
disposal wells, 5 use contract disposal, 2 use leaching beds, 1
uses surface spray, and 6 reported no wastewater generation at
all.
To highlight the geographical and process distribution of the
zero dischargers, the following breakdown is provided:
162
-------
Distribution by
EPA Region
Distribution by
BPT Subcateqorv
Number of
Refineries
Number of
Subcateqorv Refineries
Not
A
B
C
D
E
Classified
Total
34
15
1
2
0
3
55
Region
1
2
3
4
5
6
7
8
9
10
Total
Percolation and evaporation ponds are attractive disposal methods
when evaporation losses exceed rainfall. These ponds are sized
according to the annual flow so that the inflow, plus the
incidentally added water such as rainfall, equals percolation and
evaporation losses. Many U.S. petroleum refineries now use this
sizing technique.
The petroleum refining industry also practices deep-well
injection. This method can be used only if extensive studies are
conducted to ensure environmental protection.
Irrigation or other similar land disposal techniques is a viable
end-of-pipe treatment alternative. This can eliminate discharge
of all or a portion of process wastewaters to navigable streams.
Refinery 26 already uses this or a similar technology.
Deep-well injection and irrigation or similar disposal methods
are viable treatment alternatives. However, their application
depends largely on the amount of rainfall, availability of a
suitable deep-well, availability of land, and/or availability of
land suitable for irrigation. Plants that are not located in an
area with these conditions can also achieve zero discharge. The
zero discharge technology for these plants is based on forced
(vapor compression) evaporation. (Table VI1-8 is a listing of
steam electric power plants which use vapor compression
evaporation as part of their wastewater treatment system). Heat
is used to evaporate the water. The steam is condensed and
reused as makeup water to the refinery while the brine (slurry)
stream is transformed into a solid state in a flash dryer. This
zero discharge treatment scheme is described in detail in the
1977 American Petroleum Institute Report (150).
163
-------
EXISTING TECHNOLOGY
Existing BPT guidelines are based on: (a) end-of-pipe treatment
systems consisting of biological treatment followed by rapid sand
or multi-media filtration or an equivalent polishing step, and
(b) in-plant control practices widely used within the petroleum
refining industry that include the following:
o Installation of sour water strippers to reduce the
sulfide and ammonia concentrations entering the treatment plant.
o Elimination of once-through barometric condenser water
by using surface condensers or recycle systems with oily-water
cooling towers.
o Segregation of sewers so that unpolluted storm runoff
and once-through cooling waters are not normally treated with the
process and other polluted waters.
o Elimination of polluted once-through cooling water by
monitoring and repairing surface condensers or by using wet and
dry recycle systems.
The National Commission on Water Quality received a contractor's
report prepared in 1975 on the petroleum refining industry. The
report included a status of the treatment technology and water
usage of most of the refineries in the United States (65). The
data were obtained for 1973 and present a picture of the industry
as it appeared at the time the BPT limitations were promulgated.
Data in the 1977 EPA Petroleum Refining Industry Survey (1977
Survey) reflect conditions during 1976. Table VII-9 presents a
comparison of the industry's wastewater treatment practices for
1973 (National Commission Data) and 1976 (1977 survey). The
following list explains the abbreviated treatment processes in
Table VII-9:
(Corr. Plat Sep.) Corrugated Plate Separator
(DAF) Dissolved Air Flotation
(OAF) Other Air Flotation Systems
(Chemical Floe.) Chemical Flocculation
Prefiltration
(Stab. Pond) Stabilization Pond
(Aerated Lag.) Aerated Lagoon
(Act. Sludge) Activated Sludge
(Trick. Filter) Trickling Filter
(RBC) Rotating Biological Contactor
(Other Org. Rem.) Other Organics Removal
Filtration
(Pol. Pond) Polishing Pond
(Act. Carbon) Activated Carbon Adsorption
(Evap. or Perc. Pond) Evaporation or Percolation Pond
164
-------
Table VII-10 summarizes the treatment systems listed in Table
VI1-9, showing the progress made by the industry in installing
end-of-pipe treatment technology. The treatment units shown in
these tables do not necessarily treat all of a particular re-
finery's wastewaters, and many treatment schemes may be pretreat-
ment systems for discharge to a POTW.
The word "none" where indicated in Table VI1-9 refers to
refineries that do not have any of the treatment operations
considered in this analysis. However, these plants may treat
their wastewaters using gravity oil separation techniques.
A definitive list of refineries that have filtration or activated
carbon operations is significant. Refineries that included
filtration or activated carbon in their responses to the 1977
survey were screened to eliminate those systems that are treating
only a minor portion of their wastewater, such as stormwater
runoff or boiler blowdown. This approach reduced the total
number of refineries listed as having these types of treatment to
just those plants that treat a significant portion of their
wastewater using this technology.
Table VII-10 shows that in 1976 the number of refineries having
BPT in place markedly increased from the number in 1973. The
number of pretreatment operations, such as DAF, OAF and chemical
flocculation also significantly increased, indicating the
importance of these unit operations in meeting BPT limitations.
Table VI1-9 also presents data on water usage, including
once-through cooling water, during the two 1-year periods
surveyed. The comparison is based on water usage, rather than
wastewater production, because data on wastewater production were
not available for 1973. Those refineries for which data were
available for both survey years, had reduced the overall flow by
approximately 16 percent. This percentage would undoubtedly have
been greater if market conditions had remained constant.
However, many refineries expanded their operations or increased
their complexity by adding additional process units between 1973
and 1976; these additions would minimize the effect of water
reduction on a unit basis.
Effluent Concentration
The effluent concentration achievable by BPT treatment is
discussed in the 1974 development document. The sampling results
from the 17 screening plants agree with the original findings.
The concentrations and variability factors used in the BPT
limitations are given below:
165
-------
Concentration
mq/L
Variability Factors
daily monthly
Phenol
Chromium
Chromium
BODS
TSS~
O&G
(total)
(hexavalent)
0.1
0.25
0.02
15.0
10.0
5.0
3.5
2.9
3.1
3.2
3.3
3.0
1 .7
1 .7
1 .4
1.7
2.1
1 .6
The 1974 development document concluded that the influent
concentrations do not affect the effluent quality of the BPT
wastewater treatment system. Screening sampling results support
this conclusion.
Table VII-1-1 presents a detailed summary of the discharge data
from 17 sampled plants/ including the percentage of actual
discharge flow to BPT model flow and effluent concentrations for
BOD, TSS, TOC, and oil and grease. The table also presents an
analysis of the correlations among these factors. These data
show that there is no significant correlation between percentages
of actual flow to BPT flow and final effluent concentrations
after BPT treatment.
A study was conducted to further examine the relationship between
flow and concentration. Effluent flow and concentration data
from fifty refineries were compiled. The data were analyzed to
determine whether a statistically significant correlation exists
between concentration and discharge flow (in relationship to the
flow model prediction). The results of this study support the
assessment that refineries with low discharge flow (in relation
to the model prediction) do not have higher effluent
concentrations than refineries with higher discharge flow. The
data from the fifty refineries were also analyzed to determine
the level of phenols (4AAP) achievable. The result indicated
that the 19 ppb long-term average concentration (a value used in
the proposed regulation of December 1979) is too low and that the
BPT long-term concentration of 100 ppb is appropriate.
Effluent information was also evaluated to determine the
appropriateness of the BPT concentrations for BODS, TSS, oil and
grease, and chromium (total). The result indicates that the 30-
day concentrations from the new data closely approximate that of
BPT (See Table VII-12). The daily maximum concentrations,
however, are higher than the BPT values for TSS, BOD5, and
phenols. It should be noted that most of the refineries in this
study have flows that are significantly lower than the BPT model
prediction. If significant flow reduction is required, the
concentrations in Table VII-13 would probably be more appropriate
than the BPT values. Long-term pollutant reduction would be
achieved by flow reductions, but higher daily maximum
concentrations should be permitted because of higher variability.
166
-------
TABLE VII-1 Page 1 of 4
SOUR UATER TREATMENT
IN PETROLEUM REFINERIES
REFINERY SINGLE STAGE TUO STAGE
NUMBER STRIPPING STRIPPING OXIDIZING OTHER
3 X
3 X
10 X
13 X X
IS X
16 X
IS X
20 X
24 X
23 X X
29 X XX
30 X
31 X
32 X
33 X X
36 X
37 X
38 X XX
39 X
4O X X X
41 X X X
42 X
43 X X
43 X
4<4 X X
49 X
SO X
51 X X
33 X
53 X
54 X x
57 X
39 X
60 X
61 X
62 X
63 X X
64 X
63 X
67 X
68 X
70 X
71 X
72 X
73 X
74 X
76 X
77 X
73 X
SO X
31 X
33 X X
167
-------
TABLE VII - 1 Page 2 of 4
REFINERY
NUMBER
34
35
36
87
38
94
96
98
102
103
104
105
106
107
108
109
111
113
114
115
116
117
121
122
124
125
126
127
129
130
131
132
133
134
139
142
143
144
147
149
150
151
132
153
156
157
158
159
160
161
162
163
165
SINGLE STAGE TWO STAGE
STRIPPING STRIPPING
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
OXIDIZING
X
X
X
X
X
X
OTHER
168
-------
TABLE VII - 1 Page 3 of 4
REFINERY
NUMBER
166
167
163
169
174
175
176
179
180
182
133
134
135
136
137
133
190
194
195
196
197
200
203
204
205
208
209
210
211
212
213
216
221
n22
224
225
226
227
228
230
232
233
234
235
237
238
241
243
245
246
252
255
256
257
SINGLE STAGE TWO STAGE
STRIPPING STRIPPING
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X X
X
X
X
X
X X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X X
X
X
X
X
X
X
X
X
OXIDIZING
X
X
X
X
X
X
OTHER
169
-------
TABLE VII - 1 Page 4 of 4
REFINERY SINGLE STAGE TUO STflGE
NUMBER STRIPPING STRIPPING OXIDIZING OTHER
258 X
259 X
241 X
265 X
309 X
170
-------
TABLE VII-2
EFFECT OF CALIFORNIA CRUDES ON REUSE OF SOUR WATERS
Ref. No.
13
32
37
38
40
41
State
CA
CA
CA
CA
CA
CA
Crude Source
L.A. Basin
California
San Joaquin Val, CA
Coalinga, CA
California
California
California
California
California
California
CA Midway Waxy
CA Mid Spec.
Percentage
of Crude
Capacity
17
49
39.6
23.0
28.1
20.2
15.7
1.2
20
10
35
10
Percentage
of Sour Water
to Desalter
26
12.5
17
30
60
25
171
-------
Page 1 of 2
TABLE VII-3
Percentage of Percentage of
Refinery Reuse in Desalter Other Reuse
2
13
20
24
29
30
32
37
38
40
41
49
51
52
53
55
57
59
60
61
42
65
67
68
71
72
73
76
80
81
33
83
36
94
98
104
111
114
115
116
121
122
126
130
131
132
142
143
144
145
147
149
150
131
100.00
26.00
0.0
100.00
0.0
0.0
12.30
17.00
UNKNOWN
60.00
23.00
100.00
10.00
UNKNOWN
0.0
100.00
0.0
90.00
48.00
51.00
70.00
55.40
100.00
74.00
100.00
0.0
0.0
100.00
0.0
37.00
100.00
39.00
100.00
100.00
38.00
10.00
UNKNOWN
60.00
33.30
60.00
0.0
38.00
0.0
30.00
62.00
0.0
100.00
100.00
100.00
0.0
100.00
100.00
100.00
73.00
0.0
13.00
29.10
0.0
30.00
UNKNOWN
18.90
17.00
0.0
22.00
37.00
0.0
20.00
0.0
100.00
0.0
28.50
10.00
15.00
10.00
0.0
23.40
0.0
26.00
0.0
59.00
100.00
0.0
100.00
0.0
0.0
0.0
0.0
0.0
12.00
0.0
0.0
0.0
0.0
0.0
9.00
0.0
30.00
0.0
28.00
i.OO
0.0
0.0
0.0
100.00
0.0
0.0
0.0
0.0
172
-------
TABLE VII-3 Page 2 of 2
Percentage of Percentage of
ReftneaL Reuse, in Desalter Other RP.US&
133
153
136
137
159
160
161
163
165
169
179
132
133
134
136
187
133
194
196
200
203
204
205
209
211
216
224
223
227
223
230
232
233
234
241
243
232
256
257
238
259
265
303
20.00
33.00
30.00
0.0
50.00
100.00
90.00
100.00
100.00
37.00
100.00
0.0
100.00
66.00
30.00
100.00
73.00
30.00
40.00
100.00
40.00
100.00
100.00
100.00
100.00
13.00
100.00
100.00
73.00
100.00
100.00
60.00
30.00
UNKNOWN
35.00
99.99
30.00
100. OO
100.00
100.00
100.00
100.00
20.00
30.00
0.0
50.00
3.20
0.0
0.0
10.00
0.0
0.0
0.0
0.0
15.00
0.0
0.0
0.0
0.0
27.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
23.00
0.0
0.0
40.00
0.0
0.0
•o.o
0.0
0.0
0.0
0.0
0.0
0.0
0.0
30.00
173
-------
TABLE SECTION VII-4
COOLING TOWER MAKEUP FLOW RATES
IN THE PETROLEUM REFINING INDUSTRY
Page 1 of 5
Refinery
Makeup Percentage
Flow Divided Of Cooling
Makeup Flow By Total By BUI By
(MGD) Effluent FlowCooling Towers
i
2
3
4
A
7
a
9
10
11
12
13
13
IS
16
17
IS
19
20
21
22
23
24
23
26
29
30
31
32
33
35
36
37
38
39
40
41
42
43
44
45
46
48
49
50
31
32
53
54
55
56
37
58
59
0.059600
0.114800
0.0
NOT APP.
NOT APP.
0.107000
0.010000
0.025000
0.020000
2.909999
0.300000
7.303997
7.303997
0.084300
0.382100
0.018500
0.108000
0.013000
1.450000
0.298000
0.094500
NOT APP.
0.350000
0.367000
0.297000
3.419997
0.193000
0.0
4.969995
0.650000
NOT APP.
0.036000
6.808996
3.290996
0.163000
6.614997
6.621992
0.030000
3.769996
0.0
4.348996
1.462999
0.140500
0.650000
0.23SOOO
NOT APP.
NOT APP.
0.050000
0.030000
NOT APP.
1.600000
9.699997
1.314149
1.82S500
0.313684
2.125923
0.0
NOT APP.
NOT APP.
0.648485
2.000000
0.694444
0.400000
1.939999
0.723589
1.446336
1.446336
0.354099
1.179320
0.337229
0.473684
3.037382
0.739162
4.382351
1.049999
NOT APP.
1.166666
1.791321
1.993238
0.914438
0.814277
0.0
0.342372
1.633164
NOT APP.
1.090908
2.883168
1.073734
1.092714
0.348076
0.703969
0.874126
1.314045
0.0
1.363321
1.116793
0.231848
UNKNOWN
1.523973
NOT APP.
NOT APP.
0.200000
1.764706
NOT APP.
1.223115
0.941747
1.058845
1.639544
94.0000
100.0000
100.0000
0.0
0.0
70.1000
30.0000
UNKNOWN
UNKNOWN
94.0000
UNKNOWN
95.0000
31.5000
100.0000
72.0000
40.000O
UNKNOWN
100.0000
30.000O
UNKNOWN
73.0000
0.0
15.0000
58.000O
79.000O
75.0000
100.0000
UNKNOWN
76.8000
100.0000
0.0
98.5000
43.0000
80.0000
UNKNOWN
9O.0000
4.5000
UNKNOWN
62.9000
95.0000
53.6000
50.0000
95.0000
65.0000
30.0000
0.0
0.0
98.0000
100.0000
.0
.0000
89.0000
99.0000
47.3000
0.
81.
174
-------
TABLE SECTION VII-4
COOLING TOWER MAKEUP FLOW rtATES
IN THE PETROLEUM REFINING INDUSTRY
Refinery
60
61
62
63
64
65
66
67
68
70
71
72
73
74
76
77
78
79
30
31
32
33
34
85
36
37
38
89
90
91
92
93
94
95
96
97
98
99
100
102
103
104
103
106
107
108
109
110
111
112
113
114
115
116
Makeup Flow
(MGD)
Makeup
Flow Divided
By Total
Effluent Flow
3.052498
4.599999
5.659997
1.355000
4.308998
2.484499
0.000050
3.829994
8.348999
0.0
0 . 359000
0.021000
0.468000
0.471500
1.933998
0.630000
0 . 075SOO
0.0
2.129998
0.776500
0.216000
2.929999
2.204995
5.394799
0.440950
NOT APP.
0.735000
0.0
0.017000
0.005000
6.552999
0.0
1 . 728000
0.0
19.014984
0.014040
4.289999
NOT APP.
NOT APP.
0.0
0.025000
8.384995
NOT APP.
2 . 250000
0.045000
0.126000
0.200000
NOT APP.
2.342497
0.302500
0.529300
0.320000
1.983199
1.568117
1.742423
1.179166
0.496337
0.897708
0.690139
UNKNOWN
0.416706
1.717900
0.0
1.486542
0.138158
0.605433
2.357499
0.848245
2.232607
0.111029
UNKNOWN
9 . 260860
0.641735
0.375000
1.197973
1.304730
1.639756
1.274422
NOT APP.
3.223682
0.0
0.377773
0.416667
'< 0.387186
0.0
0.941176
0.0
1.605995
UNKNOWN
1.656370
NOT APP.
NOT APP.
0.0
> 0.396825
1.123531
NOT APP.
1.069391
1.499999
2.S63636
0.833333
NOT APP.
1.799048
1.490147
0.957305
1.C30000
0.708235
Page 2 of 5
Percentage
Of Cooling
By BTU B>
CaolincL Towers
0.364000
0.720000
60.0000
47.0000
74.0000
91.4100
66.0000
40.0000
100.0000
65.6000
74.4000
UNKNOWN
100.0000
10.0000
75.0000
95.OOOO
36.5000
59.0000
90.0000
UNKNOWN
35.4000
100.0000
100.0000
60.0000
75.0000
80.0000
97.0000
0.0
39.2000
28.0000
60.0000
UNKNOWN
56.0000
UNKNOWN
36.5000
100.0000
100.0000
UNKNOWN
39.4OOO
0.0
0.0
0.9000
UNKNOWN
71.0000
0.0
30.0000
100.0000
99.0000
7.6000
0.0
46.0000
35.0000
49.4000
78.0000
58.8000
40.0000
175
-------
TABLE SECTION VII-4
COOLING TOWER MAKEUP FLOW RATES
IN THE PETROLEUM REFINING INDUSTRY
Ref i nerv
117
113
119
120
121
122
124
125
126
127
128
129
130
131
132
133
134
135
136
137
138
139
140
141
142
143
144
145
146
147
148
149
150
151
152
133
154
155
156
157
158
159
160
161
162
163
164
165
166
167
168
169
172
173
Makeup Flow
.. JMGD) _^
1.450000
0.036500
0.100500
0.175000
4.250000
3.323500
0.975999
0.766000
0.400000
0.090000
NOT APP.
0.066600
NOT APP.
0.330000
1.599999
5.160996
0.0
0.0
0.378000
0.0
0.466000
• 0.071000
0.222000
0.0
0.502500
0.030000
0 . 739500
0.004500
0.300000
1.695000
0.126500
0.740000
NOT APP.
4.150000
3.070000
5.792999
0.063000
0.391700
1.697997
4.119996
0.570800
0.199500
0.323000
2.1149V7
2.115499
2.732998
0.030000
0.595400
0.050000
3.364999
1.240000
6.794998
0.772000
0.0
Makeup
Flow Divided
By Total
Effluent Flow
1.435642
1.013387
0.670000
1.590908
0.944444
0.519297
2.054733
1.723224
0.061728
0.320231
NOT APP.
0.665999
NOT APP.
0.114383
0.156648
0.630819
0.0
UNKNOWN
1.321678
0.0
0.647222
• 3.071427
2.018131
0.0
0.317233
0.023000
1.161314
UNKNOWN
3.223806
2.942707
0 . 790623
0.627650
NOT APP.
1.044288
0.366348
1.489202
0.063000
2.266782
1.697997
2.049748
1 .041605
0.720216
1.374235
3.253841
0.363469
2.633486
1 .363636
2.053102
0.434545
0.737343
0.430355
0.783737
0.339130
0.0
Percentage
Of Cooling
By BTU By
Cool ina_ Towers
99.0000
30.0000
28.0000
30.0000
65.0000
97.0000
100.0000
60.0000
22 . 0000
99 . 0000
0.0
UNKNOWN
0.0
20 . 0000
10.0000
35.0000
62.0000
UNKNOWN
100.0000
100.0000
1.0000
99.9000
70.0000
100.0000
66.5000
2 . 0000
100.0000
100.0000
UNKNOWN
39.0000
100.0000
77 . 0000
0.0
61.7000
35.0000
63.0000
UNKNOWN
100.0000
60.0000
38.9000
71.5000
60.0000
100.0000
70.0000
UNKNOWN
38.0000
100.0000
49.3000
67.0000
70.0000
200.0000
90.0000
91.3000
UNKNOWN
Page 3 of 5
176
-------
TABLE SECTION VII-4
COOLING TOWER MAKEUP FLOW RATES
IN THE PETROLEUM REFINING INDUSTRY
Page 4 Of 5
Refinery
Makeup Flow
Makeup
Flow Divided
By Total
Percentage
Of Coding
By BTU By
(MGD) Effluent Flow Cooling Towers
174
175
176
177
179
180
181
182
183
184
18S
184
187
188
18?
190
191
192
193
194
193
196
197
199
200
201
202
203
204
203
206
207
208
209
210
211
212
213
214
213
216
219
219
220
221
-*••»*>
224
223
226
227
228
229
230
231
NOT APP.
10.787498
0.086000
0.028000
0.632700
1.870998
20.876480
6.399497
2.169648
4.673997
1.771300
2.374697
3v 244994
4.633500
0.0
0.085000
2.345300
0.028000
0.0
11.303490
0.0
16.445445
0.002000
0.017200
1.694998
2.156999
0.009500
10.209991
5.268191
2.818796
12.300000
0.180000
2.344998
0.413500
0.137000
0.679049
1.743000
0.038880
0.0
0.0
16.502472
7.300000
1 . 939999
0 . 022000
0.0
0 . 360000
0.0
1.679999
0.0
1.483199
0.364500
0.113300
1.150000
NOT APP.
NOT APP.
0.364521
0.184986
0.036601
2.243616
0.676183
1.301526
1.031171
3.390073
3.438233
2.116487
1.418566
4.203360
? 1.911087
0.0
2.360240
5.606828
> 0.198582
0.0
0.664911
0.0
0.388944
0.250000
UNKNOWN
2.769604
2.270524
95.000000
0.789026
1.560205
1.156192
134.408600
2.533211
0.370140
1.759574
3.312819
0.834726
2.507822
0.762333
0.0
0.0
0.808945
UNKNOWN
1.616665
0.716667
0.0
2.457141
0.0
1.411764
0.0
1.167872
1.732403
3.456731
1.642857
NOT APP.
0.0
UNKNOWN
33.0000
73.0000
32.0000
98.7500
49.0000
70.0000
59.7000
75.0000
93.0000
71.0000
60.0000
30.0000
UNKNOWN
70.0000
100.0000
100.0000
UNKNOWN
79.0000
UNKNOWN
91.3000
100.0000
UNKNOWN
70.0000
69.0000
100.0000
65.0000
75.0000
90.6000
100.0000
90.0000
47.3000
40.0000
79.9000
UNKNOWN
63.0000
35.0000
UNKNOWN
UNKNOWN
78.0000
100.0000
63.0000
10O.OOOO
99.3000
100.0000
UNKNOWN
97.7000
29.8000
30.0000
100.0000
100.0000
38.0000
0.0
177
-------
TABLE SECTION VII-4
COOLING TOWER MAKEUP FLOW RATES
IN THE PETROLEUM REFINING INDUSTRY
Page 5 of 5
Refinery
Makeup Percentage
Flow Divided of Coaling
Makeup Flow By Total By BTU by
(MGD) Effluent Flow Cooling Towers
232
233
234
235
236
237
238
239
i40
241
14^
243
244
243
246
247
248
249
230
231
252
233
234
235
256
237
258
239
260
261
244
265
266
279
291
"l(p">
275
296
299
302
303
305
307
303
309
0.0
2,450000
0.0
2.149999
0.016000
0.016000
1.999999
0.055000
0.130000
0.324000
0.450000
0.524000
0.612000
0.707000
0.182500
0.558800
0.0
0.380000
0.0
NOT APP.
0.009000
0.0
0.0
0.0
0.040000
NOT APP.
0.792000
NOT APP.
NOT APP.
0.640000
0.0
1.296000
NOT APP.
0.0
0.506000
NOT APP.
0.610600
NOT APP.
0.0
NOT APP.
0.0
0.040000
0.0
0.0
0.720000
0.0
2.430000
0.0
1.433332
0.133333
0.571428
1.044931
0.436508
0.300000
0.490909
0.703125
3.119045
0.334426
1.178332
0.323009
2.696910
0.0
0.456731
UNKNOWN
NOT APP.
0.064748
0.0
UNKNOWN
0.0
0.109389
NOT APP.
0.792000
NOT APP.
NOT APP.
1.361701
0.0
1.169674
NOT APP.
UNKNOWN
3.563379
NOT APP.
2.361176
NOT APP.
0.0
NOT APP.
UNKNOWN
0.363931
UNKNOWN
UNKNOWN
0.743801
2.5000
45.0000
UNKNOWN
33.0000
UNKNOUH
90.0000
34.3000
47.0000
UNKNOWN
100.0000
93.0000
69.0000
99.0000
99.6000
UNKNOWN
100.000O
100.0000
50.0000
UNKNOWN
0.0
90.0000
UNKNOWN
UNKNOWN
UNKNOWN
100.0000
0.0
40.0000
0.0
0.0
90.0000
UNKNOWN
UNKNOWN
0,0
UNKNOWN
90'. 0000
0.0
90.0000
0.0
100.0000
0.0
UNKNOWN
100.0000
UNKNOWN
UNKNOWN
100.0000
. - DUE TO UNKNOWN MAKE-UP FLOWS FOR SOME COOLING TOWERS.
THE NUMBER IS GREATER THAN SHOWN
NOT APP. - NOT APPLICABLE BECAUSE OF 0.0 7. COOLING BY COOLING TOWERS
178
-------
TABU! VII-5
Page 1 of 4
SUMMARY OF FLOW REDUCTION TECHNIQUES USED IDENTIFIED DURING HASTEHATER RECYCLE STUDY
Refinery
Ho.
Base
Year
Process
Mastewater
Discharge
Rate (MGO)
Proposed
BAT
Discharge
Rate (MGO)
Potential Plow Reduction
Techniques Identified to
Achieve BAT Discharge Bate
Additional Flow Reductions
Techniques Identified
32 1979 2.43
3.53
Refinery has achieved BAT
discharge rate.
50 1979 0.06
57 1978 4.10
0.32
1.S9
60 1979 1.12
2.46
Refinery has achieved BAT
discharge rate
Recovery and reuse of
condensate for desalter
•akeup and boiler feed-
water.
Reduction of steap vent
losses.
Control of cooling tower
blowdown.
Reduction of once-thru
pump cooling water.
Refinery has achieved BAT
discharge rate
67 1979 10.0
8.26
Reuse of treated effluent
for cooling tower makeup
In-Place t
Reuse of treated effluent for cooling water,
service water, coke sluicing operation, and
coke pile dust control.
Reuse of stripped sour water for desalter
•akeup and washwater.
Recovery and reuse of condensate for boiler
feedwater.
Potential!
Reuse of stripped sour water and Isocracker
water for cooling tower Makeup.
Recovery and reuse of condensate for cooling
tower Makeup.
Optimization of cooling tower operation
In Placet
Reuse of treated effluent for cooling tower
•akeup.
Potential!
Reuse of sour water for desalter makeup.
In-Placet
Reuse of treated effluent for firewater system
Recovery and reuse of condensate for desalter
•akeup and boiler feedwater
In-Place i
Reuse of treated effluent for utll'ity water,
firewater, wssVyater, pump cooling, and coking
operation.
Reuse of stripped sour water for desalter makeup
and washwater.
Recovery and reuse of condensate.
Recycle of desalter effluent
In-Placei
Reuse of treated effluent for cooling tower makeup
and firewater system-.
Potential!
Recovery and reuse of condensate for boiler feed-
water.
Reduction of steam vent losses.
Recycle of process water.
-------
Page 2 of 4
TABLE VII-5
SUMMARY Of FLOW REDUCTION TECHNIQUES USED IDENTIFIED DURING NASTEWATER RECYCLE STUDY (Continued)
Process
Westewatar
Discharge
Rat* (MSDl
Proposed
BAT
Discharge
lUte (HBP)
1978
1.33
1.12
Potential flow Reduction
Technique! Identified to
achieve Mt Discharge Kate
Reuse of •tripped sour
water for desalter makeup
and fee weihwater.
Redaction of boiler blow-
Additional Plow Reductions
Techniques Identified
In-Placei
Reuee of treated effluent for decoklng operation.
Potential!
Recovery of atearn vent loeeea.
Control of cooling tower blowdown.
96 1979 8.0
10.1
Refinery hae achieved BAT In-Plecei
discharge rate
Reuee of •tripped eour water for deealter Makeup.
Recovery and reuse of condensate for deaalter
makeup.
Reduction of once-thru pomp cooling water.
112 1978 0.17
CO
o
125 1978 2.36
0.11 Recovery and reuse of con-
densate for boiler feed-
water.
Reduction of steal) vent
losses.
Recovery and reuse of once-
thru pump end compressor
cooling water for deselter
awkeup.
1.13 Reuee of treated effluent
for cooling water at
catalytic cracking unit.
Replacement of barometric
condensers with surface
condensers and reuse of
treated effluent for
cooling.
Recovery and reuse of
condensate for boiler
feedwater.
Control of cooling tower
blowdown.
Reduction of once-thru
pump cooling water.
In-Placet
Reuee of treated effluent for barometric con-
densers and pump cooling water at crude unit.
Recovery and reuse of condensate for boiler feedwater.
Potentiali
Reuse of treated effluent for utility water, fame
and heat exchanger cooling water.
-------
Page 3 of 4
TABLE VII-5
SUMMARY OF FLOW REDUCTION TECHNIQUES USED IDENTIFIED DURING NASTEHATER RECYCLE STUDY (Continued)
Refinery
Ho.
157
Base
Year
1979
Process
Mastewater
Discharge
Rate (HOP)
Proposed
BAT
Discharge
Rate (MOD)
Potential Flow Reduction
Techniques Identified to
Achieve BAT Discharge Rate
Additional Flow Reductions
Techniques Identified
2.17
2.31
CO
168
1979
3.25
2.75
ISO
196
1978
1978
1.81
26.7
1.66
7.6
Refinery has achieved BAT
discharge rate.
In-Placei
Recovery and reuse of condensate for boiler
feedwater and deaalter makeup.
Reduction of steam requirements.
Reuse of stripped sour water for wash water.
Reuse of treated effluent for desalter makeup.
Optimization of cooling tower operation.
Recycle of desalter effluent and process
water.
Potentiali
Recovery and reuse of condensate for boiler
feedwater.
Reduction of steam vent losses.
Reuse of treated effluent for cooling tower
makeup.
Reuse of once-thru cooling water for cooling
tower makeup.
Reduction of once-thru
cooling water and service
water.
Improved oil/water
separation for once-thru
cooling water with
In-Placei
Recovery and reuse of condensate for desalter
makeup.
Potential!
Reuse of stripped sour water for desalter makeup.
WWA^II^ w«t-o& W.LI.II Recovery and reuse of condensate for boiler
Increased segregation from feedwater.
process wastewater for Reduction of steam vent losses.
separate discharge.
Control of cooling tower
blowdown.
Dissolved air flotation
and reuse of treated
effluent for cooling tower
makeup, firewater, and
service water.
Segregation, dissolved air
flotation and filtration
of ballast water, and
filtration of regenerant
wastes for separate
discharge.
Elimination of brackish
water In firewater system.
Potentialt
Reuse of stripped sour water for desalter makeup.
Recovery and reuse of condensate for boiler
feedwater and desalter makeup.
Reduction of steam vent losses.
Reuse of treated effluent for firewater system.
Potentiali
Reuse of stripped sour water for desalter makeup.
Recovery and reuse of condensate for boiler firewater.
-------
Page 4 of 4
TABLE VII-5
SUMMARY OF FLOW REDUCTION TECHNIQUES USED IDENTIFIED DURING WASTEWRTER RECYCLE STUDY (Continued)
Refinery
Ho.
205
238
Base
Tear
Process
Hastewater
Discharge
Rate, (MOD)
Proposed
BAT
Discharge
Rate (MOD)
Potential Flow Reduction
Technique* Identified to
achieve, BAT Discharge Rate
Additional Plow Reductions
Techniques Identified
1978
1979
1.65 1.34 Filtration and reuse of
treated effluent for
firewater system.
CO
N)
2.14 1.03 Dissolved air flotation,
filtration, and reuse of
treated effluent for
cooling tower makeup and
washwater.
Segregation, dissolved air
flotation and filtration
of ballast water, and
filtration of regenerant
wastes for separate
discharge.
In-Placei
Reuse of stripped sour water for desalter makeup.
Recovery and reuse of condensate for cooling tower
makeup and boiler feedwater.
Optimization of cooling tower operation.
In-Placet
Recovery and reuse of condensate for desalter
makeup and boiler feedwater.
Potentialt
Control of cooling tower blowdown.
-------
TABLE VII-6
Summary of Data on Removal of Cyanides with
Steam Stripping and Biological Treatment in
the Petroleum Refining Industry
Percent Removal of Cyanides
by Steam Stripping (ref. 48)
Biological Treatment
(from Tables V-l thru V-18)
Refluxed
0
73
0
57
Non-Refluxed
91
59
22
50
75
Average for Both 53
Plant
Number
50
59
80
84
126
169
205
235
Average
Percent Removal
of Cyanides
85
60
90
90
83
70
82
52
77
183
-------
TABLE VII -7
Page 1 of 4
Refinery
C5H Refinery, Inc.
Lusk, WY
Zero Discharge Refineries
Capacity
(1000 bbl/stream day)
.05
Southwestern Refining Co., Inc. .5
LaBarge, WY
United Independent Oil Co. .75
Tacoma, HA
Yetter Oil Co. 1.
Colmer, IL
Dorchester Gas Producing Co. 1.
Amarillo, TX
Mountaineer Refining Co., Inc. 1.
LaBarge, WY
Glenrock Refinery, Inc. 1.
GlenrocJc, WY
Thriftway, Inc. 1.
Graham, TX
Sage %Creek Refining Co. 1.
Cowley, WY
Pioneer Refining, Ltd. 2.2
Nixon, TX
Oxnard Refinery 2.S
Oxnard, CA
Caribou Four Corners, Inc. 2.5
Kirtland, MM
Kanco Refinery, Inc. 3.
Woif Point, MT
Kentucky Oil and Refining Co. 3.0
Betsy Layne, Ky
Wastewater
Disposition
Evap/perc pond
No wastewater
generated
No wastewater
generated
Evap/perc pond
Evap/perc pond
Evap/perc pond
Evap/perc pond
No wastawater
generated
No wastewater
generated
Evap/perc pond
Disposal well
No wastewater
generated
Evap/perc pond
No wastewater
generated
This table includes all refineries whose production wastewater
(excluding stonswatar, ballast water, once-thru non-contact cooling
water, and sanitary wastewater) is not discharged directly via an
MPDES permit nor is discharged to a POTW. This table also includes
those refineries which do not generate production wastewater.
184
-------
TABLE VII-7
Page 2 of 4
Refinery
Sabre Refining, Inc.
Bakersfield, CA
Mid-Tax Refinery
Hearne, TX
Bayou State Oil Corp.
S hreveport, LA
Thriftway Co.
Fannington, MM
Capacity
(1000 obi/stream day)
3.5
3.5
4.
4.
Southern Union Refining Co.,
Monument Refinery, Sobbs, KM
Arizona Fuels Corp.
Fredonia, A2
Tonkawa Refining Co.
Arnett, OK
Plateau. Inc.
Roosevelt, OT
Texas Asphalt and Refining Co.
Euleaa, IX
Sunland Refining Corp.
Bakersfield, CA
Plateau, Inc.
Farming-ton,
MM
Douglas- Oil Co. of CA
Santa Maria, CA
Gary Western Co.
Fruita, CO
E-Z Serve, Inc.
Scott City, KS
Husky Oil Co.
Cody, WY
4.5
5.
5.
5.6
6.0
7.
7.5
9.5
10.
10.
10.3
Wastewater
Disposition
Contract
disposal
Recycle (7/1/77)
Disposal well,
Evap/perc pond
Evap/perc pond
Disposal well
Leaching bed
Disposal well
Evap/perc pond
Svap/perc pond
Evap/perc pond
Contract disposal
Evap/perc pond
Evap/perc pond
Disposal well
Evap/perc pond
Recycle
Evap/perc pond
Evap/perc pond
(7/1/77)
185
-------
TABLE VII-7
Page 3 of 4
Refinery
Witco Chemical Corp.
Oildale, CA
Newhall Refining Co., Inc.
Newhall, CA
Atlantic Richfield Co.
Prudhoe Bay, AK
Atlantic Terminal Corp.
Newington, MH
Kern County Refinery, Inc.
Bakersfield, CA
San Joaquin Refining Co.
BaJcersfield, CA
Texaco Inc.
El Paso, TX
Shell Oil Co.
Gallup, MM
Texaco, Inc.
Amarillo, TX
Texaco,,Inc.
Casper, WY
Mohawk Petroleum Corp., Inc.
Bakarafield, CA
CHA, Inc.
Phillipsburg, KS
Husky Oil Co.
Cheyenne, WY
Southern Union Refining Co.
Lovington Refinery, Hobbs, MM
Little America Refining Co.
Evansville, WY
Chevron U.S.A. Inc.
Bakersfield, CA
Capacity
(1000 bbl/stream day)
11.
12.
13.
15.
17.
17.
17.
19.
20.
21.
22.3
23.2
24.2
2S.1
, MM
25.5
Waatewater
Disposition
Contract
disposal
Contract
disposal
Evaporation
Leaching bed
Surface spray
Evap/perc pond,
recycle
Evap/perc pond,
recycle
Evap/perc pond
Disposal well,
Evap/perc pond
Evap/perc pond,
recycle
Evap/perc pond
Evap/perc pond
Evap/perc pond
Disposal well
Evap/perc pond
26.
Contract disposal,
recycle
186
-------
TABLE VII-7
Page 4 of 4
Refinery
Navajo Refining Co.
Artesia, NM
Champlin Petroleum Co.
Wilmington, CA
Shell Oil Co.
Odessa, TX
Lion Oil Co.
Bakersfiald, CA
Amoco Oil Co.
Casper, WY
Sinclair Oil Corp.
Sinclair, WV
Diamond Shamrock Corp.
Sunray, TX
Capacity
(1000 bbl/stream day)
29.9
Cosden Oil and Che
Big Spring, TX
32.
35.
40.
44. S
SO.9
53.5
aical Co. 56.
Hawaiian Independent Refininery 60.3
Ewa Beach, HI
Chevron U.S.A. Inc. 75.
El Paso, TX
Waatewater
Disposition
Evap/pero pond
Disposal well
Evap/perc pond
Disposal well,
Evap/perc pond
Evap/perc pond,
recycle
Evap/perc pond
Disposal well
Evap/perc pond,
recycle
Disposal well,
Evap/perc pond
Evap/perc pond
187
-------
TABLE VI1-8
STEAM ELECTRIC POWER PLANTS USING VAPOR COMPRESSION
EVAPORATION AS PART OF THEIR WASTEWATER TREATMENT SYSTEM
Station & Location
San Juan Station
Farmington, NM
Huntington Station
Huntington, UT
Navajo Station
Page, AZ
Hayden Station
Hayden, CO
Colstrip Station
Colstrip, MT
Craig Station
Craig, CO
R. D. Nixon Station
Four Corners
Fruitland, NM
Pawnee Station
Brush, CO
Big Stone Plant
South Dakota
Owner/Operator
Public Service Co.
of New Mexico
Utah Power & Light
Salt River Project
Montana Power Co.
City of Colorado
Springs
Capacity
(Ibs/hr)
94,500
189,000
94,500
94,500
Colorado-Ute Electric 123,000
Assoc. Inc.
Public Service Co.
of Colorado
Otter Tail Power
157,000
Colorado-Ute Electric 350,000
Assoc. Inc.
175,000
Arizona Public Service 202,000
227,000
300,000
188
-------
TABU VII-9
Page 1 of 26
TREATMENT OPERATIONS AND WATER USAGE 1973 AMD 1976
Hater Usage
Re*.
Mo.
001
002
003
__ 004
CO
UD 006
007
008
009
010
Oil
012
013
014
Treatment
1973
DAF
Act. Sludge
Stab. Fond
DAE
Stab. Pond
Aerated Lag.
Aerated Lag.
Stab. Pond
Stab. Pond
Stab. Pond
DAF
DAF
Operations
1976
Corr. Plate Sep.
DAF
Act. Sludge
Chemical Floe.
RBC
None
DAF
Aerated Lag.
DAF
Aerated Lag.
Aerated Lag.
Pol. Pond
Stab. Pond
Pre-Flltratlon
Stab. Pond
Chemical Floe.
DAF
Million
1973
0.61
0.291
0.144
0.200
0.26
0.44
2.92
0.23
12.35
0.062
Gal/Day
1976
1.87
0.186
0.125
0.144
0.243
ip.o
0.09
0.14
3.S2
0.72
10.96
0.155
X Red.
-207
36
0.0
-22
65
68
-21
-213
11
-150
-------
Page 2 of 26
TABLB VI1-9
TREATMENT OPEEATIONS AND WATER USAGE 1973 AND 1976
Ref.
No.
015
016
017
018
019
020
021
022
023
024
025
026
Treatment
1973
DAF
Filtration
None
None
None
DAF
Act. Sludge
None
DAF
Aerated Lag.
DAF
None
(continued)
Operationa
1976
Chemical Floe.
OAF
None
Chemical Floe.
Evap. or Pete. Pond
None
None
Chemical Floe.
DAF
Act. Sludge
Pol. Pond
None
DAF
Filtration
Evap. or Perc. Pond
DAF
Aerated Lag.
Other Org. Rem.
DAF
Other Org. Rem.
Other Org. Rem.
Water Usage
Million Gal/Day
1973 1976
0.270
0.56
0.06
0.60
4.79 4.51 .
0.22
0.18
.475
0.35 0.54.
1.4
0.35
Z Red.
5.8
-54
027
-------
Page 3 of 26
TABLE VI1-9
TREATMENT OPERATIONS AND WATER USAGE 1973 AND 1976
Ref.
No.
028
029
030
031
032
033
034
035
036
037
038
039
040
Treatment
1973
None
None
None
OAF
Aerated Lag.
Stab. Pond
Evap. or Perc. Pond
DAF
Act. Sludge
Corr. Plate Sep.
DAF
Evap. or Perc. Pond
None
(continued)
Operations
1976
OAF
Evap. or Perc. Pond
DAF
DAF
Aerated Lag.
Stab. Pond
None
Evap. or Perc. Pond
DAF
Aerated Lag.
Pol. Pond
Corr Plate Sep.
DAF
Chealcal Floe.
DAF
Act. Sludge
Othera Org. KM.
Water Usage
Million Gal/Day
1973 1976
•
6.5
0.33
0.10
18.80 16.2
0.71
4.0
0.12
7.6 7.6
7.73 6.34
0.35
57.0 11.2
X Red.
14
0.0
18
20
-------
Page 4 of 26
TABLE VII-9
TREATMENT OPEKATIOtIS AMD WATER USAGE 1973 AND 1976
VO
Ref.
No.
041
042
043
044
045
046
047
048
049
050
(continued)
Treatment Operation*
1973 1976
Aerated Lag. Corr. Plate Sep.
Aerated Lag.
Stab. Pond
Pol. Pond
Aerated Lag. Chemical Floe.
Evap. or Perc. Pond Aerated Lag.
Evap. or Perc. Pond
None DAF
Stab. Pond
Filtration
Evap. or Perc. Pond
DAF Chemical Floe.
DAF
OAF
DAF Chemical Floe.
DAF
Stab. Pond Evap. or Perc. Pond
Evap. or Perc. Pond
Aerated Lag. Aerated Lag.
Pol. Pond
Aerated Lag. DAF
Aerated Lag.
Stab. Pond
Filtration
Hater Usage
Million Gal/Day
• 1973 1976
126.2
0.10
4.96
2.72
29.71 28.9
55.60 44.
1.27 0.85
1.53 0.77
0.40 0.47
Z Red.
2.7
21
33
50
-18
-------
Page 5 of 26
TABLE VII-9
TREATMENT OPERATIONS AND WATER USAGE 1973 AND 1976
<£>
CO
Ref.
No.
051
052
053
054
055
056
(continued)
Water Usage
Treatment Operation* Million Gal/Day Z Red.
1973
1976 1973 1976
Act. Sludge Chemical Floe. 321.
Act.
Pol.
Evap. or Pare. Pond Stab
Pol.
DAF
Sludge
Pond
. Pond 0.34
Pond
None Filtration 1.25 0.11 Question-
DAF
None Corr
Stab
Pol.
Evap
Aerated Lag.
able
Data
0.08 0.09 -13
. Plate Sep. 0.18
. Pond
Pond
. or Perc. Pond
DAF 5.82 -37
Aerated Lag. 4.24
057
058
059
Pol.
Evap
Pond
. or Perc. Pond
Aerated Lag. Aeraged Lag. 17.63
Pol.
None DAF
DAF DAF
Aerated Lag. Act.
Pond
2.73
51.27 2.4 Question
Sludge able
Data
-------
TABLE VII-9
Page 6 of 26
TREATMENT OPERATIONS AND WATER USAGE 1973 AND 1976
VD
Ref.
No.
060
061
062
063
064
065
066
067
068
070
Treatment
1973
DAT
Aerated Lag.
Act. Sludge
Filtration
DAF
Act. Sludge
Trick Filter
Evap. or Fare. Pond
Aerated Lag.
Stab. Pond
DAF
Act. Sludge
Act. Sludge
DAF
Aerated Lag.
Act. Sludge
(continued;
Operatlona
1976
Chemical Floe.
DAF
Act. Sludge
Filtration
Chemical Floe.
DAF
Act. Sludge
Pol. Pond
Trick Filter
Aerated Lag.
Pol. Pond
Aerated Lag.
Pol. Pond
DAF
Act. Sludge
Act. Sludge
Pol. Pond
Evap. or Pare. Pond
Chemical Floe.
DAF
Aerated Lag.
Act. Sludge
None
Water Ueaga
Million Gal/Day Z Red,
1973 1976
4.84 5.2 -7.4
12.09
13.4 9.57 29
7.97 8.79 -10
27.89 24.8 11
4.06 5.0 -23
0.001
13.49 144.3 -7
8.52 6.72 21
0.17
-------
TABLE VIl-9
Page 7. of 26
IKEATMBNT OPERATIONS AND HATE* USAGE 1973 AND 1976
en
Ref.
No.
071
072
073
074
075
076
077
078
079
oao
Treatment
1973
OAF
Stab. Pond
Aerated ,Lag.
Stab. Pond
Aerated Lag.
Stab. Pond
Aerated Lag.
None
Stab. Pond
Evap. or Pare. Pond
None
None
Stab. Pond
(continued)
Operationa
1976
Chemical Floe.
OAF
Aerated Lag.
Pol. Pond
Chemical Floe.
Aerated Lag.
Pol. Pond
Chemical Floe.
Aerated Lag.
Pol. Pond
Aerated Lag.
Pol. Pond
Chemical Floe.
Aerated Lag.
Pol. Pond
Act. Sludge
Pol. Pond
Evap. or Perc. Pond
Chemical Floe.
Stab. Pond
Hater Oaage
Million Gal/Day
1973 1976
0.68 0.59
1.44
1.01 1.79
0.63 0.67
1.27
3.60 3.0
0.63 0.63
O.S1
0.16
1.33 3.46
X Red.
13
-77
-0.3
17
0.0
-160
-------
TABLE VI1-9
Page 8 of 26
TREATMENT OPERATIONS AND WATER USAGE 1973 AND 1976
Ref.
No.
081
082
083
084
085
086
087
088
089
090
091
092
Treatment
1973
Chemical Floe.
Aerated Lag.
Stab. Pond
None
OAF
Aerated Lag.
Stab. Pond
None
DAP
None
OAF
Evap. or Perc. Pond
None
DAF
Other Org. Rea.
(continued}
Operations
1976
Aerated Lag.
Pol. Pond
Evap. or Perc. Pond
DAF
DAF
Act. Sludge
Pol. Pond
Chenlcal Floe.
OAF
Act. Sludge
Chenical Floe.
DAF
Evap. or Perc. Pond
Stab. Pond
Evap. or Perc. Pond
Aerated Lag.
None
DAF
Act. Sludge
Aerated Lag.
Pol. Pond
Water Usage
Million Gal/Day
1973 1976
2.50 1.58
4.62 4.86
3.54 3.84
11.0 10.43
0.35 0.47
0.42 1.0
1.16
0.31 0.19
0.031
0.032 0.012
321.5 278.8
I Red
37
-5.0
-8.5
5.2
-34
-138
39
63
13
-------
Page 9 of 26
TABLE VII-9
TREATMENT OPERATIONS AND WATER USAGE 1973 AND 1976
Ref.
No.
093
094
095
096
097
098
099
100
101
102
103
(continued)
Treatment Operations
1973 1976
None
Act. Sludge Corr. Plate Sep.
Aerated Lag. DAF
Act. Sludge
Pol. Pond
None Stab. Pond
Pol. Pond
Corr. Plate Sep. Corr. Plate Sep.
Aerated Lag. Chealcal Floe,
DAF
Act. Sludge
None
Aerated Lag. OAF
DAF
Aerated Lag.
Stab. Pond
DAF
Aerated Lag.
Pol. Pond
Filtration Filtration
Aerated Lag.
Aerated Lag. Aerated Lag.
Aerated Lag.
Water Usage
Million Gal/Day
1973 1976
4.59 3.6
0.60
90.52 34.64
0.034
31.27 26.56
121.
0.19
17.9 21.1
0.27
X Red.
22
62
IS
-18
-------
TABLE VIl-9
Page 10 of 26
TREATMENT OPERATIONS AND WATER USAGE 1973 AND 1976
UD
00
Ref.
No.
104
105
106
107
108
109
110
111
112
113
114
Treatment
191 f
Aerated Lag.
Aerated Lag.
Stab. Pond
None
OAF
OAF
Act; Sludge ,
Trick. Filter
Stab. Pond
Filtration
Aerated Lag.
Act. Sludge
(continued)
Operations
1976
Corr. Plate Sep.
Aerated Lag.
Stab. Pond
Chemical Floe.
OAF'
Aerated Lag.
Aerated Lag.
Pol. Pond
Filtration
OAF
Chealcal Floe.
DAF
Act. Sludge
Trick. Filter
Pol. Pond
Chemical Floe.
DAF
Aerated Lag.
Aerated Lag.
Pol. Pond
Aerated Lag.
Pol. Pond
Water
Million
1973
24.88
71.0
S.76
0.39
0.31
83.25
1.22
0.75
1.14
0.72
Usage
Gal/Day
1976
21.34
84.
4.59
0.39
0.34
66.22
1.0
1.8
0.51
0.90
0.59
X Red.
14
-18
20
0.0
-9.7
20
18
32
21
18
-------
TABLE VII-9
Page 11 of 26
TREATMENT OPERATIONS AND WATER USAGE 1973 AND 1976
(continued)
Ref. Treatment Operation*
No. 1973
115 Act. Sludge
116 Aerated Lag.
117 DAF
Aerated Lag.
Stab. Pond
_, 118 None
10
10
119 Filtration
120 None
121 Corr. Plate Sep.
1976
Pre-Filtratlon
Act. Sludge
Pol. Pond
Stab. Pond
OAF
Aerated Lag.
Pol. Pond
Aerated Lag.
Filtration
Aerated Lag.
Filtration
Aerated Lag.
Filtration
Corr. Plate Sep.
Water Usage
Million Gal/Day Z Red.
1973 1976
5.05 3.92 22
2.06 2.77 -34
2.01 2.10 -4.5
0.13 0.94 -623
0.17 0.23 -35
0.35 0.29 17
34.5 14.0 59
122
124
DAF
Aerated Lag.
Stab. Pond
Aerated Lag.
None
DAF
Aerated Lag.
Other Org. Ren.
Pol. Pond
Aerated Lag.
Chealcal Floe.
DAF
Stab. Pond
12.08
35.
1.87
Question-
able
Data
-------
Page 12 of 26
TABLE VI1-9
TREATMENT OPERATIONS AND WATER USAGE 1973 AND 1976
Ref.
No.
125
126
127
ro
0
o
128
129
130
131
132
133
134
Treatment
1973
Aerated Lag.
Stab. Pond
Aerated Lag.
Stab. Pond
DAF
Aerated Lag.
Stab. Pond
Bvap. or Perc. Pond
None
Stab. Pond
Act. Sludge
Aerated Lag.
Stab. Pond
Stab. Pond
(continued)
Operationa
1976
Aerated Lag.
Other Org. Re*.
Pol. Pond
Aerated Lag.
Pol. Pond
Cheaical Floe.
DAF
Aerated Lag.
Pol. Pond
Evap. or Perc. Pond
Aerated Lag.
Evap. or Perc. Pond
Pol. Pond
None
OAF
BBC -
OAF
Act. Sludge
DAF
Adt. Sludge
Trick. Filter
Filtration
Act. Sludge
Filtration
Water Usage
Million Gal/Day X Red.
1973 1976
1.23 1.28 -4.1
33.0 40.8 -24
0.31 0.25 19
0.01
0.15
3.13 2.67 15
74.01 56.6 24
174.5 181.5 -4.0
35.28 19.3 45
8.64 8.81 -2.0
-------
Page 13 of 26
TABU VII-9
TREATMENT OPERATIONS AMD HATU USAGE 1973 AMD 1976
INi
O
Ref.
Mo.
US
136
137
138
139
140
141
142
143
144
14S
146
147
(continued)
Treatment Operations
1973 1976
Core. Plata Sap.
Nova Nona
Hone Kvap. or Pare. Pond
Stab. Pond Kvap. or Pare. Pond
Kvap. or Pare. Pond
None Kvap. or Pare. Pond
DA? Chemical Floe.
DAP
OAF Chenlcal Floe.
DAF
Aerated Lag. Aerated Lag.
Pol. Pond
None
Stab. Pond Stab. Pond
DAF Chemical Ploc.
DAF
Act. Sludga
Water Oaaga
Million Gal/Dav X Red.
1973 1976
0.6
0.06
1.03
0.168
0.5
0.03
10.35 21.67 -18
28.85 33.7 -17
45.02 1.77 Question-
able
Data
0.014
0.32 0.3 6.3
1.40 1.94 -39
148
DAF
DAF-
0.47
-------
TABU VII-9
Page 14 of 26
TREATMENT OPERATIONS AND WATER USAGE 1973 AND 1976
ReC.
No.
149
150
151
ro
o
^ 152
153
154
155
156
1973
Aerated Lag.
Aerated Lag.
OAF
Aerated Lag.
DAF
Aerated Lag.
Act. Sludge
Trick. Filter
Aerated Lag.
Stab. Pond
Aerated Lag.
Stab. Pond
Aerated Lag.
(continued)
Treatment Opera tlona
1976
Corr. Plate Sep.
Aerated Lag.
Corr. Plate Sep.
Act. Sludge
Chealcal Floe.
DAF
Aerated Lag.
Pol. Pond
DAF
Act. Sludge
Other Organica Reau
Filtration
Stab. Pond
Pol. Pond
Stab. Pond
Pol. Pond
Cheaical Floe.
DAF
Aerated Lag.
Pol. Pond
Water lleage
Million Gal/Day
1973 1976
1.78 4.92
84.44 60.14
6.50 7.59
122.1 44.05
5.43 4.7
0.31 0.85
0.59 0.65
2.47 2.37
X Red,
-176
29
-17
64
13
-174
-10
4.0
157 Other Organica Hem.
Act. Sludge
Aerated Lag.
Other Organica Re*.
7.65
7.33
4.2
-------
Page 15 of 26
TABLE VI1-9
TREATMENT OPERATIONS AND WATER USAGE 1973 AND 1976
Kef.
No.
158
159
160
ro
o
OJ
161
162
163
164
165
197?
Act. Sludge
Stab. Pond
None
DAF
Act. Sludge
Filtration
Aerated Lag.
DAF
Aerated Lag.
Aerated Lag.
Stab. Pond
(continued)
Water Usage
Treatment Operation* Million Gal/Day X Red.
1976 1973 1976
Act. Sludge 1.40 1.49 -6.4
Pol. Pond
Stab. Pond 0.75 0.69 8.0
Pol. Pond
Chemical Floe. 0.53 0.65 -23
OAF
Act. Sludge
Stab. Pond
Pol. Pond
Evap. or Perc. Pond
Aerated Lag. 1.72 0.12 -81
Other Organic* Rea.
Pol. Pond
DAF 5.84 6.3 -7.9
Act. Sludge
Aerated Lag. 4.48 3.5 22
Pol. Pond
Bvap. or Perc. Pond
Chemical Floe. 0.73 0.80 -9.6
DAF
Stab. Pond
Pol. Pond
166 None
None
0.2
-------
Page 16 of 26
TABLE VI1-9
TREATMENT OPERATIONS AMD HATER USAGE 1973 AMD 1976
ro
o
tef.
Mo.
167
168
169
170
172
173
174
175
176
177
178
179
180
Treatment
1973
DAF
Other Organic* Re*.
nitration
Act. Carbon
Act. Sludge
Trick. Filter
None
None
None
None
None
None
None
OAF
Aerated Lag.
Aerated Lag.
Bvap. or Fere. Fond
(continued)
Operattona
1976
Chemical Floe.
DAF
Act. Sludge
Fre-Filtratlon
Act. Carbon
Act. Sludge
Trick. Filter
None
None
Aerated Lag.
Corr. Flate Sep.
Aerated Lag.
None
Chemical Floe.
Aerated Lag.
Stab. Fond
Pol. Fond
DAF
Act. Sludge
Water
Million
1973
9.84
81.4
51.2
7.84
5.43
28.8
124.5
3.28
4.10
0.82
0.98
4.38
Usage
Gal/Day
1976
11.8
123.
49.23
1.58
3.07
8.08
106.6
5.86
2.15
0.98
3.91
X Red,
-20
-51
3.8
43
72
14
-79
48
0.0
11
-------
Page 17 of 2$
TABLE VII-9
TREATMENT OPERATIONS AND WATER USAGE 1973 AND 1976
Ret.
Mo.
181
182
183
ro
o
en
184
185
186
187
188
189
190
191
Treatment
1973
Aerated Lag.
Aerated Lag.
DAP
Aerated Lag.
Act. Sludge
Evap. or Perc. Pond
DAP
Act. Sludge
Evap. or Perc. Pond
Hone
None
DAP
Aerated Lag.
DAP
(continued)
Operations
1976
Pre-Plltration
Act. Sludge
Filtration
Act. Sludge
Chealcal Ploc.
DAP
Aerated Lag.
Pol. Pond
Chemical Ploc.
Act. Sludge
Evap. or Perc. Pond
DAP
Act. Sludge
Stab. Pond
Piltration
Bvap. or Perc. Pond
Corr. Plate Sep.
Aerated Lag.
Pol. Pond
Aerated Lag.
Pol. Pond
Water
Million
1973
26.70
16.56
1.40
6.32
4.35
6.22
0.05
0.40
Usage
Gal/Day
1976
27.5
14.53
6.86
2.4
6.13
2.35
5.23
0.03
0.12
2.89
X Red
-3.0
12
-8.5
-18
16
40
70
-------
Page 18 of 26
TABLE VZI-9
TKKATHBNT OPERATIONS AND WATER USAGE 1973 AND 1976
Ref.
No.
192
193
194
195
196
ro
O
Treatment
1973
None
Aerated Lag.
Stab. Pond
None
DAF
Act. Sludge
Stab. Pond
(continued)
Operations
1976
Evap. or Perc. Pond
None
Aerated Lag.
Pol. Pond
None
Corr. Plate Sep.
Chemical Floe.
DAF
Water
Million
1973
0.039
44.25
130.0
Usage
Gal/Day
1976
0.035
0.053
32.7
0.0011
46.38
Z Red.
-36
26
64
197
198
199
200
201
None
None
DAT
Aerated Lag.
Act. Sludge
Stab. Pond
Aerated Lag.
Pol. Pond
Pre-Flltratlon
Aerated Lag.
Filtration
None
Chemical Floe.
OAF
Act. Sludge
Filtration
2.00
2.02
0.012
0.05
1.43
2.9
29
-44
202
0.004
-------
TABLE VII-9
Page 19 of 26
TREATMENT OPERATIONS AND WATER USAGE 1973 AND 1976
ro
o
--4
Ref.
No.
203
204
205
206
207
208
Treatment
1973
DAF
Act. Sludge
Act. Sludge
DAF
Aerated Lag.
Stab. Pond
Bvap. or Perc. Pond
None
Trick. Filter
Act. Sludge
Stab. Pond
(continued)
Water Usage
Operation* Million Gal/Day X Red.
1976 1973 1976
Chemical Floe. 52.4 29.14 44
DAF
Chemical Floe. 8.07
DAF
Act. Sludge
Pol. Pond
DAF 12.66 9<05 29
Aerated Lag.
Pol. Pond
0.05 0.14 -180
None
Corr. Plate Sep. IS. 25 23.2 -52
Act. Sludge
Trick. Filter
209
210
211
Evap. or Perc. Pond
DAF
Aerated Lag.
Stab. Pond
DAF
Stab. Pond
Pol. Pond
Bvap. or Perc. Pond
None
Chemical Floe.
DAF
Act. Sludge
Aerated Lag.
Filtration
1.25
0.76
1.98
-58
-------
TABU VI1-9
Page 20 of 26
TREATMENT OPERATIONS AND WATER USAGE 1973 AND 1976
CO
Ref.
No.
212
213
214
215
216
218
219
220
221
222
223
224
Treatment
1973
DAF
Act. Sludge
DAF
Evap. or Perc. Pond
Evap. or Perc. Pond
Act . Sludge
Aerated Lag.
Evap. or Perc. Pond
Aerated Lag.
Evap. or Perc. Pond
Act . Sludge
Stab. Pond
DAF
(continued)
Water Usage
Operations Million Gal/Day Z Red.
1976 1973 1976
DAF 3.57
Act. Sludge
OAF 0.14
Aerated Lag.
Stab. Pond
Pol. Pond
Evap. or Perc. Pond
Evap. or Perc. Pond
Cheaical Floe. 672. 53.24 Question-
Act. Sludge able
Aerated Lag. Data
0.68
Aerated Lag. 3.45
Pol. Pond
Filtration
0.087
Other Organic* Rev. 14.33 8.15 43
Aerated Lag. 0.89
Pol. Pond
None
Cheaical Floe. 0.40 0.413 -3.3
DAF
-------
TABLE VII-9
Page 21 of 26
TREATMENT OPERATIONS AMD HATER USAGE 1973 AND 1976
Ret.
No.
22S
226
227
ro
o
10
228
229
230
231
232
233
234
Treatment
1973
DAT
Stab. Pond
Stab. Pond
Rvap. or Perc. Pond
Kvap. or Perc. Pond
None
Stab. Pond
Aerated Lag.
Filtration
DAP
Act. Sludge
Stab. Pond
DAF
Act. Sludge
(continued)
Operation*
1976
DAF
Filtration
Stab. Pond
Pol. Pond
OAF
Aerated Lag.
RBC
Pol. Pond
Filtration
Stab. Pond
Pol. Pond
Evap. or Perc. Pond
Stab. Pond
Chemical Floe.
Filtration
Act. Sludge
Trick. Filter
Pol. Pond
DAF
Act. Sludge
Trick. Filter
Pol. Pond
Hater Uaage
Million Gal/Day
1973 1976
2.52
0.04 0.084
2.56 2.59
0.48 0.55
0.1S
1.80 1.5
72.22 63.65
5.59 3.75
2.30
X Re<
-110
-1.2
-15
17
12
33
-------
TABLE VI1-9
Page 22 of 26
TREATMENT OPERATIONS AND HATER USAGE 1973 AND 1976
Ref.
No.
235
236
237
238
239
240
241
242
243
Treatment
1973
Trick. Filter
Act. Sludge
Filtration
Corr. Plate Sep.
Trick. Filter
Act. Sludge
Filtration
Stab. Pond
None
Other Organic* Re>.
None
Aerated Lag.
Evap. or Perc. Pond
(continued)
Operation*
1976
Act. Sludge
Trick. Filter
Pol. Pond
Corr. Plate Sep.
OAF
Act . Carbon
Act. Sludge
Trick. Filter
Aerated Lag.
Stab. Pond
Pol. Pond
Corr. Plate Sep.
BBC
Pol. Pond
Act. Sludge
Pol. Pond
None
Aerated Lag.
Pol. Pond
Water
Million
1973
4.40
0.13
3.72
0.23
1.58
2.47
0.95
0.86
Usage
Gal/Day Z Red.
1976
3.66 17
0.15 -15
0.038
4.2 -13
0.216 6.1
1.34 15
0.96 61
0.86 9.5
0.77 10
244
Bvap. or Perc. Pond
3.19
-------
Page 23 of 26
TABLE VII-9
TREATMENT OPERATIONS AND HATER USAGE 1973 AND 1976
(continued)
Water Usage
Ref. Treatment Operations Million Gal/Day I Red.
Ho. 197? TSTf I97J 197?
245 Stab. Pond Corr. Plate Sep.
Aerated Lag.
Pol. Pond
Evap. or Perc. Pond
246 DAF Aerated Lag. 2.16 2.84 -31
Stab. Pond Evap. or Perc. Pond
Evap. or Perc. Pond Pol. Pond
ro 247 Evap. or Perc. Pond Evap. or Perc. Pond 0.84
248 Evap. or Perc. Pond
249 DAF DAF
Evap. or Perc. Pond Evap. or Perc. Pond
250 Evap. or Perc. Pond
251
252 Stab. Pond Stab. Pond 0.24 0.32 -33
253 Evap. or Perc. Pond Evap. or Perc. Pond
254 None 1.0
255 Pre-Flltration 0.13
Aerated Lag.
Pol. Pond
256 Corr. Plate Sep. 0.04
Stab. Pond
-------
TABLE VI1-9
Page 24 of 26
TREATMENT OPK1ATIOHS AND WATER USAGE 1973 AND 1976
ro
Ref.
No.
257
258
259
260
261
264
265
266
275
278
282
(continued)
Treatment Operation*
1973 1976
DAF Stab. Pond
Aerated Lag.
Aerated Lag. DAF
Act. Sludge
Pol. Pond
OAF
Act. Sludge
None Aerated Lag.
DAF
Trick. Filter
EBC
Evap. or Pare. Pond
Corr. Plate Sap.
DAF
Act. Sludge
Stab. Pond
Pol. Pond
None None
None
Hater Uaage
Million Gal/Day
197T 1976
99.5
1.96
21.55
0.25 1.0
3.0
2.07
0.94 0.83
0.024
Z Red.
-300
12
-------
ro
GO 290
291
292
293
294
295
296
297
298
Page 25 of 26
TABLE VII-9
TR&ATMEIfr OPERATIOHS AMP HATER U8AGK 1973 AMD 1976
(continued)
Water Usage
Kef. Treatment Operation* Million Gal/Day X Red.
Mo. T97fT9TS WfS WfG
283
284
287
288
289
-------
Page 26 of 26
TABLE VII-9
TRKATMKMT OPERATIONS AMD MATER USAGE 1973 AMD 1976
(continued)
Hater Uaage
Ref. Treatment Operattona Million Cal/Day X Red.
MO. T977 787S
299
300
301
302 Bvap. or Perc. Pond
303
304
305
306
307
308 Bvap. or Perc. Pond
309 Chemical Floe.
Act. Sludge
Aerated Lag.
-------
TABLE VI1-10
For 1973 and
1976
Tr^fl,^ svst— Htabar of Raf inaria.
Corragatad Plata Separators
Chanical Flocenlation
Oiaaolvad Air Flotation
Othar Flotation Systana
Prafiltration
Activatad Sludga
Trickling Filtar
Aaratad Lagoon
Stabilization *)nd
Rotating Biological Contactor
Othar Organica Ranoval
Filtration
Polishing Ponda
Activatad Carbon
Evaporation or Percolation Ponda
1973
4
1
56
1
Unknown
30
7
63
4-4
0
4
10
Unknown
1
26-
1976
20
46
68
15
6<1'
50
10
73
35
5
10
23 (1)
75
2
37
(1) Two rafineriaa hav« both prafiltration and poat filtration.
3o that a total of only 27 rafinariaa had filtration systama
in 1976.
215
-------
TABLE VII-11
BZFIMEKJf FUN VS. FBDU, hJPFUJBIT
COHQ9ITRKTIQH FOR 17 SCREENING PLANTS
Refiaerr
Coda
A
a
c
0
c
F
<3
H
I
J
K
L
M
H
0
P
Q
Slope
Intercept
Percent of
Actual Diacbarg*
Flow to 3PT Flow
40.3
37.3
36.7
49.7
143.3
.96
121.7
72.5
69.4
58.0
39.4
173.9
35.0
69.1
121.3
*
28.0
t
(Correlation)*
Average
SOD.
">/l
< 2.5
13.5
41.0
125.0
< 9.5
27.0
<12.5
<. 4.5
<'U.O
6.0
* 3.5
•* 7.5
•C12.0
9.0
«S1.0
-------
ro
TABLE VII-12
Effluent Concentration From 50 Plant Study
Pollutant Parameter
BOD5
TSS"
O & G
CRT
POL
NOTE: Concentrations are given in milligrams per liter (mg/L)
Daily
tudy
62
58
17
0.5
1.2
Maximum
BPT
48
31
15
0.725
0.35
30-day
Study
20
24
5.6
0.13
0.19
BPT
25.5
21
8.0
0.425
0.17
-------
TABLE VII-13
ACHIEVABLE LIMITATIONS VALUES
Pollutant
BPT Refineries
BOD
TSS
O&G
CRT
POL
ro
00
Mean
Pollutant
Level
15.74
19.23
4.446
0.0928
0.1229
Daily
Variability
Factor
3.93
3.00
3.90
5.48
10.04
Daily
Limitation
Value
61.86
57.69
17.34
0.5085
1.234
30-Day
Variability
Factor
1.27
1.22
1.27
1.36
1.56
30-Day
Limitation
Value
19.95
23.53
5.63
0.13
0.19
Note; Concentrations are given in milligrams per liter (mg/L)
-------
O
at
u
in
(3
»—
I
IU
t-
-------
FIGURE VII-2
flow. Diagram of a Granular Activated Carbon Syste
ro
o
Backwash out
Influent
Effluent
V
To other carbon trains
PIping Explaoatjon
Main influent heoder (to 1st tank in series)
Main effluent deader (from 3rd tank in series)
Influent header to 2nd tank tit series
Influent header to 3rd tank in series
Effluent header from 1st tank in series
Effluent fn* 2nd tank in series
Connection between 13 and IS headers
Connection between M and 16 headers
.. Backwash inlet header
16) Backwash outlet (leader
-------
FIGURE VI1-3
Carbon Regeneration System
r>o
Make-up carbon
Regenerated
Carbon
Holding
Tank
I
Carbon, Adsorption
Tanks
Spent Carbon
Holding
Tank
Furnace
-------
FIGURE VII-4
Flow Diagram of One Powdered Activated
Carbon Treatment Treatment Scheme
ro
ro
ro
Uastewater Influent
i-M
r
Powdered
Activated
Carbon
Inlet
Carbon Make-up
Treated Effluent
V-
Sludge
Thickener
Filter Presses
Carbon
Regeneration
Furnace
Acid Hash
System
-------
SECTION VIII
BEST AVAILABLE TECHNOLOGY ECONOMICALLY ACHIEVABLE
SUMMARY
Best Available Control Technology Economically Achievable (BAT)
is equivalent to the existing Best Practicable Technology
Currently Available (BPT) level of control. BAT technology/
which is the same as BPT, includes in-plant control and end-of-
pipe treatment. BPT in-plant technology consists of widely used
control practices such as ammonia and sulfide control,
elimination of once through barometric condenser water,
segregation of sewers, and elimination of polluted once-through
cooling water. BPT end-of-pipe treatment includes flow
equalization, initial oil and solids removal (API separator or
baffle plate separator), further oil and solids removal
(clarifier or dissolved air flotation), biological treatment, and
filtration or other final "polishing" steps. The effluent
limitations for BAT are the same as those for BPT because the BAT
flow model and subcategorization scheme are the same as those for
BPT. BAT control technology, which is equivalent to BPT
technology, is Option 9 of the nine options considered by the
Agency.
BAT limitations, in general, represent the best economically
achievable performance of direct dischargers included in an
industrial category or subcategory. BAT limitations control the
discharge of toxics (priority pollutants) and non-conventional
pollutants (COO, phenolic compounds [4AAP], ammonia and sulfides)
in the effluent of existing direct dischargers in the petroleum
refining industry. BAT does not regulate conventional pollutants
(TSS, oil and grease, B005. and pH) which are considered under
Best Conventional Treatment Economically Available (BCT).
In assessing BAT, the Agency considers the age of the equipment
and facilities involved, the processes employed, the engineering
aspects of control technologies, process changes, the cost of
achieving such effluent reduction, and non-water quality
environmental impacts. The Administrator retains considerable
discretion in assigning the weight to be accorded these factors.
Where existing performance is uniformly inadequate, BAT may be
transferred from a different subcategory or category.
EPA is required to consider costs, but does not have to balance
costs against effluent reduction benefits. However, EPA has
given substantial weight to the reasonableness of costs. The
Agency has considered the volume and nature of discharges, the
volume and nature of discharges expected after application of
BAT, the general environmental effects of the pollutants, and the
223
-------
costs and economic impacts of the required pollution control
levels.
Effluent limitations for the petroleum refining industry are
expressed as mass limitations, i.e., restrictions on the total
quantity of pollutants that may be discharged. Since the total
mass of pollutants in an effluent stream depends on both the
total effluent flow and the concentration of pollutants in that
flow, the nine options considered for BAT reflect both flow and
concentration considerations.
BAT OPTIONS CONSIDERED
EPA investigated nine control and treatment technology options
for selection of BAT criteria. Options 1 through 6 were
considered in formulating the proposed rule published in 1979.
Model flow for options 1 through 5 refers to the flow model
presented in the 1979 proposed regulation. Detailed explanation
of these options is available in the 1979 draft development
document. Option 7, a modification of Option 2, and Option 8, a
modification of Option 1, were developed using the data base
available at the time of the 1979 proposal, supplemented and
modified by information collected by EPA after the proposed rule
was published, as well as from public comments received on the
proposed rule. Model flow for Options 7 and 8 refers to the
refined flow model which reconciled discrepancies noted in the
1979 model, and more accurately depicted refinery wastewater
flows (see Section IV).
Option 9, the BPT level of control, was reconsidered after
publication of the proposed rule, as a result of public comments
received. Model flow for Option 9 refers to the flow model
presented in the 1974 development document.
Option 1 - Discharge flow reduction of 27 percent from model
flow, achieved through greater reuse and recycle of
wastewaters, in addition to BPT treatment.
Option 2 - Discharge flow reduction of 52 percent from model
flow, achieved through greater reuse and recycle of
wastewaters, in addition to BPT treatment. This was the
control treatment option selected in the 1979 proposal.
Option 3 - Discharge flow reduction of 27 percent from model
flow per Option 1, plus BPT treatment enhanced with powdered
activated carbon to reduce residual toxic organic pollutants.
Option 4 - Discharge flow reduction of 52 percent from model
flow per Option 2, in addition to BPT treatment plus
segregation and separate treatment of cooling tower blowdown.
Cooling tower blowdown treatment for metals removal includes
reduction of hexavalent chromium to trivalent chromium, pH
adjustment, precipitation, and settling or clarification.
224
-------
Option 5 - Discharge flow reduction of 27 percent from model
flow per Option 1, in addition to BPT treatment plus granular
activated carbon treatment to reduce residual toxic organic
pollutants.
Option 6 - A "no discharge of wastewater pollutants" (i.e.,
zero discharge) standard based upon reuse, recycle,
evaporation, or reinjection of wastewaters.
Option 7 - Discharge flow reduction of 37.5 percent from
refined model flow achieved through greater reuse and recycle
of wastewaters, in addition to BPT treatment.
Option 8 - Discharge flow reduction of approximately 20
percent from refined model flow achieved through greater
reuse and recycle of wastewaters, in addition to BPT
treatment.
Option 9 - Flow equalization, initial oil and solids removal
(API separator or baffle plant separator), additional
oil/solids removal (clarifiers or dissolved air flotation),
biological treatment, and filtration or other final
"polishing" steps. This option is the basis of the existing
regulations.
Option K Reduce discharge flow to 27 percent below model
flow (flow model for 1979 proposal) in addition to BPT treatment.
Establish a long term achievable concentration for phenolic
compounds (4AAP) at 19 ug/1 as the base for computing pollutant
load. Fifty percent of the petroleum refineries were already
operating at this flow level (27 percent less than model flow) at
the time of the 1979 proposal.
Flow reduction is a viable technology in the petroleum refining
industry. Since 1972 the refining industry has reported
decreasing wastewater discharge flows as refineries install water
conservation, recycle and reuse technology in response to
existing regulations, water supply costs, and water treatment
costs. The following summary of industry discharge flows
demonstrates this significant change in water management
practices:
Specified Flow Type Total Flow, MGD
1. Total 1976 Indirect Discharge Flow
(Supplemental Flow Questionnaire) 50
2. Total Calculated BPT Flow 1972 569
3. Total 1976 Direct Discharge Flow
(Supplemental Flow Questionnaire) 346
4. Total 1976 Direct Discharge Flow
225
-------
Minus Planned Flow Reductions (1977
Industry Survey and Supplemental Flow
Questionnaire) 311
5. Total allowable BAT Flow Based on
1979 Proposed Flow Model 227
6. Total allowable BAT Flow Based on
Refined Flow Model 251
7. Same as (5), except actual individual
flows from (4) are used if less than
allowable individual BAT Flows 205
8. Same as (6), except actual individual
flows from (4) are used if less than
allowable individual BAT Flows 215
The methods of recycle/reuse are described in detail in Section
VII. In order to verify that the 37.5 percent flow reduction was
achievable, the Agency conducted a 15 plant study (159). The
study concluded that this level of flow reduction can be achieved
by traditional recycle/reuse schemes.
Figure V-3 shows the results of projecting this trend toward
reduced wastewater flow. The analysis predicts that the
petroleum refining industry will achieve the Option 7 flow level
(63 percent of revised model flow) within a few years. Reduction
in pollutant loading occurs when BPT treatment systems achieve
the same discharge pollutant concentrations at a reduced
discharge flow level.
The Agency has concluded that removal of non-conventional
pollutants would not change measureably from BPT treatment to BPT
treatment plus 27 percent flow reduction. Ammonia and sulfide
loadings depend primarily upon the process of stripping sour
waters, an in-plant control technique, and will not be directly
related to flow. No technologically feasible process changes or
in-plant controls have been identified to further reduce ammonia
and sulfides. Also, chemical oxygen demand (COD) does not vary
directly with effluent flow. The Agency's attempts to quantify
or predict changes in COD levels with the implementation of flow
reduction/water reuse technologies were inconclusive.
Option 1 would limit total phenols at a mass limitation based
upon an effluent concentration equivalent to 19 ug/L. The Agency
received a number of comments on this issue stating that the
proposal to limit total phenols at 19 ug/L was too stringent
because technology is not available to consistently achieve such
a level. Additional information on phenols was collected by EPA
in the Petroleum Refining Long Term Data Analysis (161) and the
"Surrogate Sampling Program" (1621subsequent to the December
1979 proposal. Information collected included effluent data from
226
-------
49 refineries for calendar year 1979 plus 60 day sampling results
at two refineries in 1980. Analysis of the data collected during
these two studies concluded that TOO ug/L is appropriate to
establish a mass limitation applicable on an industrywide basis
in light of the variability due to fluctuations in treatment
system performance.
Discharge of toxic priority pollutants would be less than BPT
levels because the refineries would achieve former BPT
concentrations at reduced discharge flows. Estimates of the
pollutant reductions to be achieved by BPT treatment plus flow
reduction assumed that the pollutant load for trivalent and
hexavalent chromium after BPT treatment would be at or near the
allowable level. Subsequent evaluation of BPT treatment since
the original estimates indicates that BPT treatment achieves
better removal of priority pollutants than originally thought,
and that reduction in flow would achieve minimal further
reductions. The Agency has estimated this further reduction in
toxic pollutants over BPT treatment at 1 percent of the priority
pollutants in raw refinery wastewater. This translates into an
additional removal beyond BPT of approximately 1.3 pounds of
toxic pollutants per day, per direct discharge refinery (168).
The preamble to the proposed 1979 regulation (44 FR 75933) stated
that $23.5 million additional investment would be required with
an annual cost of $9.3 million (1979 dollars) to implement Option
1 for this industry. The capital costs, to a considerable
extent, represent retrofit costs. These cost figures are the
incremental costs beyond BPT to achieve Option 1 technology.
Option 1 effluent limitations are based upon the flow model for
the 1979 proposal. Since the Agency has decided not to use this
flow model for the regulation, Option 1 was rejected.
Option 2_. Reduce discharge flow, 52 percent below model flow
(flow model for 1979 proposal) in addition to BPT treatment.
Establish a long term achievable concentration for phenolic
compounds (4AAP) at 19 ug/1 as the base for computing pollutant
load. Thirty-eight percent of the refineries were already
operating at or below 52 percent of model flow at the time of the
1979 proposal.
Removal of non-conventional pollutants (ammonia, sulfides and
COD) is not directly dependent upon flow reduction. Like Option
1, the Agency has concluded that installation of flow reduction
will not achieve measureable decrease in non-conventional
pollutant loads over BPT treatment.
This option would also apply the 19 ug/L long term concentration
to the 52 percent of model flow to calculate the allowable load
by phenolic compounds (4AAP).
227
-------
Again, many commenters questioned the ability of petroleum
refineries to achieve this long term effluent concentration on an
industrywide basis. Additional studies by the Agency concluded
that 19 ug/L cannot be achieved consistently and that 100 ug/L is
the appropriate concentration for regulating loadings of phenolic
compounds (4AAP) for all direct dischargers in the petroleum
refining industry.
Removal of priority pollutants would again be accomplished by the
refineries achieving BPT level treatment at even greater reduced
flows. The Agency's analysis of available data shows that
implementation of Option 2 would remove an additional 1.5 percent
of toxic pollutants from raw wastewaters beyond BPT treatment
levels (168). BPT removes 96 percent of the toxic pollutants
from raw wastewaters discharged by the petroleum refining
industry. This additional 1.5 percent translates into an
additional removal beyond BPT of approximately two pounds of
toxic pollutants per day, per direct discharge refinery.
The preamble to the 1979 proposal (44 FR 75938) stated that
implementation of Option 2 would result in the removal of
approximately 123,000 pounds of chromium per year. This 123,000
pounds of chromium per year represents the incremental removal
from the BPT level to the BAT Option 2 level. However, based
upon reevaluation of the effluent data base, the Agency has found
this figure was overstated, because the observed chromium
discharge of refineries with BPT level treatment was considerably
less than that allowable by the BPT chromium limitations. The
actual amount of chromium which would have been removed under
this option is approximately 32,000 pounds per year (168).
Implementation of Option 2 would result in annual cost to the
industry of $62 million with an initial capital investment of
$138 million (1979 dollars). Initial investment includes, to a
considerable extent, retrofit costs. These cost estimates
represent the incremental cost beyond BPT treatment to achieve
Option 2 technology.
BAT Option 2 was developed using the proposed 1979 flow
model. However, based upon data submitted by commenters and the
"Flow Model" study performed by EPA after the proposal (See
Section IV), the proposed 1979 flow model was modified. The
technical points raised by some of the commenters were of
considerable assistance in the flow model refinement prpcess.
The main emphasis of the comments concerned the statistical
deficiencies of the proposed model, the choice of model
variables, and aspects of the resulting model fit. The structure
of the model and the process variables to be included were
reexamined and modified accordingly. This refinement process
resulted in the refined flow model which was more representative
of the current wastewater generation in the industry. Thus,
Option 2 has been rejected because it was based on the proposed
flow model that has been modified.
228
-------
Option 3_. Reduce discharge flow by 27 percent of model flow
(flow model for 1979 proposal) per Option 1 plus enhanced BPT
treatment with powdered activated carbon (PAC) to reduce residual
toxic organic pollutants.
The two end-of-pipe treatment technologies that were used to
establish Option 3 are rotating biological contactors (RBC) and
powdered activated carbon (PAC) treatment. At the time of the
Agency's data collection efforts in 1976-1979, there were seven
facilities using these technologies. The Agency determined that,
upon analysis of available data, there are significant
operational (mechanical) problems with RBC technology. The
Agency also found that full-scale experience with PAC technology
was mixed, i.e., some facilities experienced consistently
measurable pollutant reductions as intended, while others
experienced inconsistent or no measurable effluent reductions.
Because of these operational problems observed in full-scale
facilities, there was limited performance information available.
The Agency's analysis of available data shows that implementation
of Option 3 would remove an additional 1.5 percent of toxic
pollutants from raw wastewaters beyond BPT treatment levels.
This translates into an additional removal beyond BPT of
approximately two pounds of toxic pollutants per day, per direct
discharge refinery (168).
Option 3, flow reduction plus PAC enhancement of a biological
system may offer promise as a treatment technology to remove
individual toxic pollutants under special circumstances, but this
option is not a proven technology in the petroleum refining
industry which can be applied in an industrywide regulation.
Full scale experience with this technology did not produce
consistent measurable results.
Given the limited additional effluent reduction benefits and the
limited performance data available at this time, Option 3 is not
warranted for this industry.
Option 4. Reduce discharge flow by 52 percent of model flow
(flow model for 1979 proposal) per Option 2 plus BPT treatment
and separate treatment of cooling tower blowdown. This option
could result in better removals than Option 2, since cooling
tower biocides would not enter the biological treatment system
and wastewater would not be diluted with cooling water before
biological treatment.
Option 4 was predicated on industrywide ability to segregate,
collect, and separately treat cooling tower blowdown, the major
source of chromium for this industry. The wastewater
recycle/reuse study (see Section VII), completed after the
publication of the proposed regulation, concluded that, for
existing sources, it is extremely difficult in many instances to
segregate cooling tower blowdown for chromium treatment. Cooling
229
-------
tower blowdown is typically effected at numerous locations
throughout a refinery. Extensive collection systems would be
necessary at many refineries to collect all blowdown streams for
separate treatment. In addition, not all cooling tower blowdown
streams are collectible. For instance, cooling water when used
as makeup for refinery processing commingles with process water
and cannot be traced or segregated, especially in older
refineries. Therefore, the Agency has determined that it would
not be proper to base BAT effluent limitations guidelines on this
technology option.
Because this technology is not available to all direct discharge
refineries on an industrywide basis, the Agency has rejected
Option 4 as the basis for BAT regulation of existing refineries.
However, refineries which will be built in the future can
incorporate separate treatment of cooling tower blowdown into the
plant design.
Option 5.. Reduce discharge flow to 27 percent below model
flow (flow model for 1979 proposal) plus BPT treatment and
granular activated carbon treatment to reduce residual toxic
organic pollutants. Option 5 would provide treatment equivalent
to Options 2 and 3.
BAT Option 5 is predicated on industrywide ability to install and
operate granular activated carbon (GAC) treatment as an end-of-
pipe technology. Although GAC technology is used in other
industries, long term performance data of full scale systems
treating refinery wastewaters would be required before this
technology could be used as the basis for industrywide effluent
limitations.
The Agency conducted six pilot plant treatability studies that
used GAC to treat refinery wastes after BPT treatment (108).
While toxic pollutant removal generally increases with the use of
GAC, the levels of toxic pollutants after BPT treatment were so
low that additional pollutant reduction across GAC treatment was
minimal. Difficulties in quantifying pollutant reductions were
experienced when the Agency tried to evaluate toxic pollutant
removals in BPT treated water where concentrations approached the
analytical limits of quantification.
Because of the difficulties experienced in Agency attempts to
measure removal of toxic pollutants, removal efficiencies have
not been estimated for this option. Moreover, considering the
marginal benefits and uncertain effectiveness of this technology
in treating dilute concentrations of priority pollutants, the
Agency decided to reject BAT Option 5.
Option 6,. Zero discharge of wastewater is a demonstrated
technology. "There are currently fifty-five refineries in the
United States that do not discharge wastewater. However, the
technology employed at these zero discharge refineries is very
230
-------
site specific, e.g., 32 of the 55 use evaporation/percolation
basins which rely upon special conditions of climate and geology.
The zero discharge technologies considered by the Agency include
those currently in use by the industry and those that are
applicable from other industrial sources. The Agency realizes
that some of the technologies in use by the refinery industry can
not be applied in other geographical locations because of
meteorological conditions, load availability, and other
environmental constraints. Vapor compression distillation is
identified to be universally available and applicable. Although
none of the refineries are using VCD, full scale use of such a
system is being used successfully in the steam electric industry.
However, the secondary impacts of VCD can be quite severe, and
are prohibitive in the Agency's opinion. These secondary impacts
include high energy consumption and solid waste generation.
Removal of toxic pollutants under this option would be 100%
assuming that percolating or injected wastewater will not be
transported to acquifers and streams. The 1979 development
document (158) did not contain an estimate of the cost of
retrofitting all existing direct discharge refineries to zero
discharge. The technology would be different for each refinery
and could be expected to incur higher capital and operating costs
than a new refinery designed to achieve zero discharge.
The Agency rejected BAT Option 6, (1) because of its high capital
and operating costs, including significant retrofit expenditures;
and (2) because analysis of the zero discharge technologies
revealed that significant non-water quality impacts would result
from their use. These non-water quality impacts include
generation of large amounts of solid waste and very high energy
consumption.
Option 7_. Reduce discharge flow to 37.5 percent below model
flow (refined flow model) plus BPT treatment. Option 7 is
similar to Option 2, except that the revised mathematical model
calculates a slightly different flow quantity. Also the flow
reduction below model flow is less than the 1979 proposal. Based
upon the refinements to the 1979 flow model described above, flow
reduction was revised from an average 52 percent from the 1979
model flow to 37.5 percent from the refined model flow. This
average 37.5 percent flow reduction was designated Option 7.
Option. 7 resulted from modeling efforts conducted after the 1979
proposed regulation. The methods of recycle/reuse are described
in detail in Section VII. In order to verify that the 37.5
percent flow reduction was achievable, the Agency conducted a 15
plant study. The study concluded that this level of flow
reduction can be achieved by traditional recycle/reuse schemes.
Removal of non-conventional pollutants beyond BPT treatment would
be limited for the reasons discussed under Options 1 and 2.
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The Agency's analysis of available data shows that implementation
of Option 7 would have removed an additional 110,000 pounds of
toxic pollutants annually beyond BPT treatment levels, equivalent
to an additional 1.5 percent of toxic pollutants from raw
wastewaters beyond BPT treatment levels. This translates into an
additional removal beyond BPT of two pounds of toxic pollutants
per day per direct discharge refinery.
The Agency estimated the costs to implement Option 7 recycle and
reuse technologies. A capital cost of $112 million and $37
million (1979 dollars) in annual costs are associated with Option
7.
The Agency believes, that given the limited additional effluent
reduction benefits and the costs involved, Option 7 is not
warranted for this industry.
Option §.. Reduce discharge flow to 20 percent below model
flow (revised flow model) plus BPT treatment. BAT Option 8 is
similar to Option 1. Based upon additional data submitted by
commenters and the technical studies performed by EPA after the
proposal (See Section IV), the flow model upon which Option 1 is
based was reevaluated. The result of this reevaluation was a
refinement in the 1979 flow model with use of more and better
quality data. The amount of flow reduction via recycle and reuse
technologies was determined to be an average 20 percent below
refined model flow.
Removal of non-conventional pollutants beyond BPT would be
limited for the reasons discussed under Option 1. The Agency's
analysis of available data shows that implementation of Option 8
would remove an additional one percent of toxic pollutants from
raw wastewaters beyond BPT treatment levels. This translates
into an additional removal beyond BPT of 1.3 pounds of toxic
pollutants per day, per refinery (168).
The cost of implementing Option 8 is estimated at a capital cost
of $77 million and an annual cost of $25 million (1979 dollars).
The Agency believes that, given all these factors and the costs
involved, Option 8 is not warranted for this industry.
Option 9_. A level of control equivalent to the BPT level of
control consists of flow equalization, initial oil and solids
removal (API separator, baffle plate separator), further oil and
solids removal (clarifiers, dissolved air flotation), biological
treatment, and filtration or other final "polishing" steps. This
option is based upon the flow model developed for the BPT
regulations promulgated by the Agency in 1974. Therefore, the
effluent limitations are equivalent to the BPT effluent
limitations.
232
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Removal of non-conventional pollutants would remain at current
BPT levels. Table VI-1 shows a total annual raw wastewater
loading of non-conventional pollutants equal to 257,231 kkg/yr.
BPT treatment would reduce this pollutant waste load to 66,988
kkg/yr for a net 74 percent removal of non-conventional
pollutants by the petroleum refining industry. Table VI-1
contains removal efficiencies for total phenols as measured by
the 4AAP method. BPT treatment reduces the total annual
wasteload from 9719 kkg/yr to 7.6 kkg/yr.
Table V-27 contains a summary of the analytical results for
concentrations of phenolic compounds (4AAP) and individual toxic
phenolic compounds found in the effluent of direct dischargers.
Parameter No. 167 (4AAP phenolic) shows an average 15 ug/L in 76
percent of the samples while individual toxic phenolic compounds
identified as priority pollutants (parameters 21, 24, 31, 34, 57,
58, 59, 64 and 65) show a total of one detection occurrence at a
concentration at or below measurable limits. This data was the
basis for the 19 ug/L achievable concentration proposed in 1979.
EPA compiled additional data on the performance of refineries
providing BPT treatment in the "Survey of 1979 Effluent
Monitoring Data." This study examined the results of BPT
treatment at refinery flows predominantly less than 1979 model
flows. The analytical results are, therefore, representative of
low-flow treatment systems (163). This study computed an average
long term achievable concentration of 123 itg/L for refineries
with BPT treatment systems. This conclusion supports the long
term achievable concentration of 0.100 mg/L initially set forth
to calculate BPT pollutant loads at the BPT model flow rate. In
addition, the Agency collected data on discharge of phenolic
compounds from the Long Term Sampling Program (162) and the EPA
Regional Surveillance and Analysis Teams (Table V-29) which
confirm that the 19 ug/L value is not representative of average
long term performance and that the 100 ug/L is appropriate.
Removal of toxic pollutants would remain at the levels achieved
by BPT treatment. Table VI-2 shows a total annual raw wastewater
loading equal to 3502 kkg/yr. BPT treatment can reduce the
discharge of toxic pollutants to a total annual loading of 137
kkg/yr for a net removal efficiency of 96 percent. Ninety-six
percent removal of toxic pollutants is calculated from the
actual, measured performance of BPT treatment.
The concentration of pollutants in the final refinery effluents
and their associated water quality criteria are presented in
Section VI. Limited environmental benefit would be gained by
requiring further control beyond BPT.
In summary, only the following pollutants were found at
concentrations (average) in excess of 10 ppb: chromium
(trivalent), cyanide, zinc, toluene, methylene chloride, and
bis(2-ethyhexyl) phthalate. Of these, methylene chloride and
233
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bis(2-ethylhexyl) phathalate are contaminants of the sampling and
analytical methodology. Chromium is already limited by BPT.
Cyanide occurs in concentrations (flow-weighted average 45 »»g/L)
at the limits of effective removal by known technologies.
Toluene is removed to below measurable limits by all but one
refinery and is not characteristic of the industry. Zinc at an
average concentration of 105 «g/L is not likely to cause toxic
effects.
The cost of implementing Option 9 is effectively zero, since the
Act requires that all refineries achieve BPT treatment by 1977.
Considering the limited pollutant reduction benefits associated
with Options 1 through 8, the inability to quantify
nonconventional pollutant reduction via Options 1 through 8, the
costs involved of going beyond the BPT level of control/ and the
96 percent reduction in toxic pollutant loadings achieved by BPT/
the Agency has determined that the BAT level of control should be
equivalent to the BPT level of control for the petroleum refining
industry.
IDENTIFICATION OF BEST AVAILABLE TECHNOLOGY ECONOMICALLY
ACHIEVABLE
BAT Selection and Design Criteria - EPA selected Option 9.
Effluent data from the EPA sampling survey show that present BPT
treatment removes 96 percent of the toxic pollutants/ 85 percent
of the conventional pollutants (BOD/ TSS, oil and grease), and 74
percent of the nonconventional pollutants (COD/ ammonia/ TOC,
sulfides, and phenolics (4AAP)). The levels of toxics from the
final refinery effluents are extremely low (see Section VI for
details).
A separate analysis of the Effluent Guidelines Division sampling
and analytical data showed that there are no environmentally
significant priority pollutants in direct discharges from
petroleum refineries at BPT technology levels after application
of the 50th percentile average and low flow dilutions. (See
Table VIII-1). The basis for this determination of environmental
significance is the comparison of diluted average plant effluent
concentrations with ambient water quality criteria as determined
by EPA Criteria and Standards Division (165). Selection of this
option would result in no additional cost or secondary impacts
beyond that associated with BPT compliance.
The bases for the BPT limitations can be found in the 1974
development document. The information upon which the numerical
limitations are derived is presented in Table 50-52(3). These
tables provide the concentrations/ variability factors, and flows
used. An example of how BPT should be applied is presented in
Section I.
234
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TABLE VIII-1
1 of 2
1.6 Diluted Effluent Concentrations from Direct Dischargers In the Petroleua Refining Industry
Pollutant
Arsenic
Bary Ilium
CddnliM
Cnrcnlwa ITrl.l
Chromium (Hex.)
Copper
Cyan Ida
Lead
Mercury
Nickel
SelanliM
Silver
IhallluM
Zinc
Chlurolonn
Ranzene
Toluene
Currant/bPT '
Flow-Mlghted
Avg. Cone.
ug/l
0.01
0.04
0.29
107.79
7.73-
9.89
49.46
9.19
0.88
3.39
17.19
0.04
3.21
104.6
3.1
2.3
10.1
Diluted Concentration 2
using the 50th percent lie
average flow
ug/l
0
0
0
0.01
0
0
0
0
0
0
0
0
0
0.01
0
0
0
Diluted Concentration
using the 9Oth percent lie
low flow
ug/l
0
0
0
0.22
0.02
6.02
0.09
0.01
0
0.0|
0.03
0
0.01
0.21
0.01
0
0.02
EPA Mblent Mater
For the Protect lo
Aquatl
Acute *
ug/l
440
130"
3.0
4700
21
22
92
170
4.1
1800
260
4.1
1400*
320
28900*
9300*
17900*
Quality Criteria
« of Freshwater
cLIfe
Chronic f
ug/l
MCA
9.3*
0.029
44*
0.29
9.6
3.9
3.8
0.2
96
39
0.12*
40*
47
1240*
MCA
NCA
N)
CO
Ul
-------
TABLE VIII-1 (Continued)
2 of 2
Co
(Ti
1.6 Diluted Effluent Concentration* Fro Direct Dischargers In the Petroleum Refining Industry
Compared to the EPA Ambient Water Quality Criteria for the Protection of Freshwater Aquatic Life
(Continued)
Pollutant
2. 4-Dlch lorophenol
p-Ch loro-m-Cresol
Dimethyl phthalate
Dlethyl phthalate
Ol-n-butyl phthalate
Acanaphthena
Benzo(a)pyrena
Chyrsana
Phananthrana
'yrane
1
Current/Mr
Flow-weighted
Avg. Cone.
ug/l
0.22
0.28
0.19
1.46
0.04
1.06
0.09
0.02
O.|8
0.12
2
Diluted Concentration
using the 90th percentlle
averaga flow
U9/I
0
0
0
0
0
0
0
0
0
0
3
Diluted Concentration
using the 90th percent II*
low flow
ug/l
0
0
0
0
0
0
0
0
0
0
EPA Ambient Water Quality Criteria
For the Protection of Freshwater
Aquatic Life
Acute4
ug/l
2020*
290*
33000*
92100*
940*
1700*
NCA
NCA
NCA
NCA
Chronic »
ug/l
369*
NCA
NCA
NCA
NCA
NCA
NCA
NCA
NCA
NCA
Footnotas:
'Derived by multiplying the average concentration by the flow for each of the 17 refineries sampled. The turn of the products divided by the
total How of the refineries sampled results In a flow-weighted average concentration.
Wived by dividing the flow-weighted averaga concentration by the 90th percent lie average flow dilution factor. The 90th percentlle (19127)
corresponds to the median average flow dilution factor. Flow data were available for 43 of the 164 refineries. Diluted concentration values
lass than 0.01 ug/l are reported as lero.
'Derived by dividing the flow-weighted average concentration by the 90th percentlle low flow dilution factor. The 90th percentlle (496)
corresponds to the median low flow dilution factor. Flow data were available for 32 of the 164 refineries. Diluted concentration values less
than 0.0) ug/| are reported as zero.
*Acute - The maximum concentration of a pollutant allowed at any time to protect freshwater organisms.
'chronic - The 24-hour averaga concentration of • pollutant to protect freshwater organisms.
•Lowest reported toxic concentration to protect freshwater organisms. Reported when no other criteria are available.
NCA - No criteria available.
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SECTION IX
NEW SOURCE PERFORMANCE STANDARDS
SUMMARY
New source performance standards (NSPS) are equivalent to the
existing NSPS promulgated on May 9, 1974 (39 FR 16560) which were
upheld by the United States Court of Appeals in American
Petroleum Institute v. EPA, 540 F.2d 1023 (10th cir. 1976T
NSPS require a reduction in pollutant load based upon BPT in-
plant and end-of-pipe treatment plus a 25 to 50 percent
wastewater flow reduction (depending upon subcategory). BPT in-
plant technology consists of widely used control practices such
as ammonia and sulfide control, elimination of once-through
barometric condenser water, segregation of sewers, and
elimination of polluted once-through cooling water. BPT end-of-
pipe technology consists of flow equalization, initial oil and
solids separation (API separator or baffle plate separator),
further oil and solids separation (clarifier or dissolved air
flotation), biological treatment, and filtration or other
"polishing" steps. NSPS use the flow model developed for the
1974 regulation to calculate pollutant loadings.
NSPS regulate the discharge of the following conventional,
nonconventional and toxic pollutants from new refineries, which
include BOD5_, TSS COD, oil and grease, total phenols (4AAP),
ammonia(N),""sulfide, total chromium, hexavalent chromium, and pH.
A "new source" is a new refinery ("greenfield site") or a
modification to an existing plant which is extensive enough to be
"substantially independent" of an existing source. For example,
as stated in the preamble to the proposed criteria for new source
determinations, 45 FR 59343 (September 9, 1980) the addition of a
structurally separate cracking unit at the site of an existing
refinery that processes crude oil by the use of topping and
catalytic reforming would be considered a modification of the
existing source and not a new source, because the cracking unit
would not be a substantially independent process.
New Source performance standards are equal to existing NSPS; this
is Option 4 of the four options considered by EPA in this study.
Instructions for calculating effluent limitations and mass
limitation factors for each subcategory are in Section I.
The basis for new source performance standards (NSPS) under
Section 306 of the Act is the best available demonstrated
technology (BADT). New plants have the opportunity to design the
best and most efficient petroleum refining processes and
wastewater treatment technologies; Congress therefore directed
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EPA to consider the best demonstrated process changes, in-plant
controls, and end-of-pipe treatment technologies capable of
reducing pollution to the maximum extent feasible.
NSPS OPTIONS CONSIDERED
EPA considered four control and treatment options for the final
new source performance standards. Options 1 and 2 were
considered in formulating the proposed rule and were based upon
the flow model for the proposed 1979 regulations. Option 4, the
existing NSPS level of control, was reconsidered after
publication of the proposed rule as a result of the public
comments and is based upon the 1974 flow model.
Option 1 - Discharge flow reduction to 52 percent below model
flow (flow model for 1979 proposal), achieved through greater
reuse and recycle of wastewaters, in addition to BPT
treatment. This Option is equivalent to BAT Option 2.
Option 2 - Discharge flow reduction to 27 percent below model
flow (flow model for 1979 proposal), achieved through greater
reuse and recycle of wastewaters in addition to BPT
treatment, plus use of granular activated carbon to reduce
residual organic toxic pollutants. This option is equivalent
to BAT Option 5.
Option 3 - Zero discharge of wastewater pollutants.
Option 4 - Discharge flow reduction from 25 percent to 50
percent below BPT model flow, depending upon subcategory,
achieved through greater reuse and recycle of wastewaters in
addition to BPT treatment. This option is the basis for the
existing NSPS regulation, including the 1974 flow model upon
which the existing NSPS is based.
NSPS Option 1 - Effluent flow reduction to 52 percent below model
flow (flow model for 1979 proposal) plus BPT treatment is
equivalent to BAT Option 2. The technology for this option is
the same as that for the existing NSPS regulations - wastewater
recycle and reuse technologies, in addition to BPT end-of-pipe
treatment.
The Agency compared effluent reductions achievable by existing
NSPS and this option. This comparison concluded that effluent
reductions are comparable to the 1974 NSPS. The analysis was
performed on a model greenfield new source refinery (190,000
bbl/day, cracking) which is classified as a "Subcategory B"
refinery as defined by the existing regulation. This model
refinery was configured to correspond with demand growth as
published by the Department of Energy (see the Economic Analysis
document). The costs to implement this option are comparable to
the existing NSPS (see Appendix A). Nonwater quality
environmental impacts and energy requirements are also similar to
existing NSPS.
238
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Since the costs, pollutant removals/ energy and environmental
effects are comparable there would be no significant benefit in
adopting a regulation equivalent to BAT Option 2 (or BAT Option 7
which incorporates the refined flow model).
NSPS Option 2 - Effluent flow reduction to 27 percent below model
flow (flow model for 1979 proposal) plus BPT technology and
granular activated carbon (GAC) to remove residual organic toxic
pollutants. NSPS Option 2 is equivalent to BAT Option 5, which
is also based on GAC end-of-pipe technology.
A major proportion of the cost of GAC treatment is annual
operating expense which will be similar for a new plant and for
an existing plant. A new refinery will not incur the retrofit
cost of flow reduction associated with BAT Option 5, however/ the
new refinery will sustain the capital costs of GAC technology
plus annual operating costs. Estimates of these costs are shown
in Appendix A.
For the reasons stated in the proceeding discussion on BAT Option
5/ the Agency believes that GAC treatment is not demonstrated
technology for this industry.
NSPS Option 3 - Zero discharge of pollutants is a demonstrated
technology. However, the technology employed and the associated
costs are very site-specific. This technology is now practiced
by about 55 refineries in the United States where conditions of
climate and geology make zero discharge attractive.
The Agency estimated the pollutant removal benefits which would
accrue over and above existing NSPS for a typical 150/000 bbl/day
refinery of the cracking subcategory. Daily pollutant removals
would be 2.46 Ib/day phenol, 3.9 Ib/day hexavalent chromium, 6
Ib/day total chromium, 308 Ib/day TSS and 381 Ib/day BOD.
Section VII and the discussion on BAT Option 6 describe
technologies such as vapor compression distillation and deep well
injection which are available, but which have other cost, energy
and environmental affects that must be considered for an industry
wide regulation. Unlike BAT Option 6, a newly constructed
refinery can be designed to incorporate zero discharge during
construction. However, annual operating costs remain high at
sites which do not have favorable conditions.
The Agency reported a costing method for incorporating zero
discharge into the construction of a typical new refinery as
described by the American Petroleum Institute. The capital and
annual costs for a typical petroleum refinery producing 150,000
barrels/day are estimated to be $11.6 million and $4.6 million
(1979 dollars), respectively. The industry indicated in their
comments that the energy consumed would cost $2,000,000 per year;
they also stated that 7,300 tons per year of solid waste would be
239
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generated. EPA believes that the energy and solid waste
estimates from the industry are reasonable approximations.
While the Agency proposed zero discharge for NSPS in 1979, after
careful re-examination of the combined effects associated with
NSPS Option 3, EPA has rejected this proposal because:
1. it generates significant adverse non-water quality
related impacts, including the production of large
amounts of solid waste and high energy consumption;
2. the cost of achieving zero discharge is estimated to be
extremely high, especially in geographical areas of low
evapotranspiration which requires energy intensive
forced evaporation techniques;
3. only marginal additional water pollution reduction
benefits would be achieved beyond the existing NSPS.
4. the high costs of implementation could raise serious
barriers to any decision invovling construction of a new
source refinery.
NSPS Option 4 - Effluent flow reduction to 25 to 50 percent below
model flow (ilow model for 1974 regulation) plus BPT technology
is equivalent to the existing NSPS. Flow reduction of from 25 to
50 percent of average BPT flow, depending upon subcategory, would
be achieved by recycle and reuse technology.
Implementation of Option 4 would not cause the petroleum refining
industry to incur any additional expense beyond the cost of
meeting the current regulations for new direct discharge.
After careful consideration of the options proposed in 1979,
together with the public comments received, the Agency finds no
reason for revising current NSPS.
IDENTIFICATION OF NEW SOURCE PERFORMANCE STANDARDS
EPA is retaining the existing NSPS which are based on recycle and
reuse technology resulting in pollutant reductions that range
from 25 to 50 percent beyond BPT removals, depending upon the
subcategory. Regulated pollutants for NSPS are BODS, total
suspended solids, chemical oxygen demand, oil and grease, .total
phenols (4AAP), ammonia (N), sulfide, total chromium, hexavalent
chromium, and pH.
New greenfield refineries are not expected to be built between
now and 1990. Existing refineries, however, may be modified to
accommodate the heavier and higher sulfur crudes which are
becoming increasingly prevalent in the current oil market. The
change could cause certain refineries, or parts of refineries, to
be considered new sources. However, it is unlikely that the
240
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modification would be extensive enough so that the existing
refinery would be reclassified as a new source.
241
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SECTION X
PRETREATMENT STANDARDS FOR EXISTING AND NEW SOURCES
Summary
PSES - Pretreatment Standards for Existing Sources
Interm final PSES were promulgated by the Agency on March 23,
1977 (42 FR 15684) and are currently in effect. Regulated
pollutants are oil and grease (100 mg/L) and ammonia (N) (100
mg/L) each on a daily maximum basis. EPA is retaining the
existing PSES regulation, with one modification. An alternative
mass limitation for ammonia (N) is provided for those indirect
dischargers whose discharge to the POTW consists solely of sour
waters. PSES is equivalent to Option 3 of the three technology
options considered by the Agency for pretreatment standards.
PSNS - Pretreatment Standards for New Sources
PSNS were promulgated by the Agency on May 9, 1974 (39 FR 16560)
and are currently in effect. Pretreatment standards for
incompatible pollutants are equivalent to NSPS. Final PSNS are
equivalent to pretreatment standards for existing sources (PSES),
except that they also regulate total chromium at the equivalent
of 1 mg/L for the cooling tower discharge part of the refinery
flow to the POTW. An alternative mass limitation for ammonia (N)
is also provided, as described above for PSES. PSNS is
equivalent to Option 1 of the two technology options considered
by the Agency for pretreatment standards for new sources.
A new indirect discharging refinery of the size and configuration
likely to be built in the 1980's would incur additional capital
costs of $0.37 million and an annual cost of $0.26 million (1979
dollars) beyond the cost of complying with existing PSNS.
Section 307(b) of the Act requires EPA to promulgate pretreatment
standards for both existing sources (PSES) and new sources (PSNS)
that discharge pollutants into publicly owned treatment works
(POTW). PSES are designed to prevent the discharge of pollutants
that pass through, interfere with, or are otherwise incompatible
with the operation of the publicly owned treatment works (POTW).
They must be achieved within three years of promulgation. The
legislative history of the 1977 Act indicates that pretreatment
standards are to be technology-based, analogous to the best
available technology for removal of toxic pollutants. The
general pretreatment regulations, which served as the framework
for the categorical pretreatment regulations are found in 40 CFR
Part 403 (43 FR 27736, June 26, 1978; 44 FR 9462, January 28,
1981) (also see Section I).
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The Clean Water Act of 1977 requires pretreatment for toxic
pollutants that pass through the POTW in amounts that would
violate direct discharger effluent limitations or interfere with
the POTW's treatment process or chosen sludge disposal method.
EPA has generally determined that there is pass through of
pollutants if the percent of pollutants removed by a well-
operated POTW achieving secondary treatment is less than the
percent removed by the BAT model treatment system.
Like PSES, PSNS are to prevent the discharge of pollutants which
pass through, interfere with, or are otherwise incompatible with
the operation of the POTW. PSNS are to be issued at the same
time as NSPS. New indirect dischargers, like new direct
dischargers, have the opportunity to incorporate the best
available demonstrated technologies. The Agency considers the
same factors in promulgating PSNS as it considers in promulgating
PSES.
Pollutants Not Regulated
The toxic pollutants listed in Table VI-9 were detected in
petroleum refinery waste streams that are discharged to POTW.
The Agency has decided not to establish PSES for these toxic
pollutants in this industry for the following reasons:
The pollutants listed in Part I and Part II of Table VI-9 are
excluded from national regulation in accordance with Paragraph 8
of the Settlement Agreement because they were either found to be
susceptible to treatment by the POTW and do not interfere with,
pass through, or are not otherwise incompatible with the POTW, or
the toxicity and amount of incompatible pollutants were
insignificant.
The pollutants listed in Part III of Table VI-9 are excluded from
regulation for a combination of reasons. First, there is
significant removal of some of these pollutants by the existing
pretreatment standards for oil and grease. Second, there is
significant removal of all these pollutants by the POTW treatment
system. Third, the amount and toxicity of these pollutants does
not justify developing national pretreatment standards.
The Agency did not propose requiring installation of BPT-type
treatment on an industrywide basis for indirect dischargers.
PRETREATMENT OPTIONS CONSIDERED
EPA considered three control and treatment options for
pretreatment standards for existing sources and two options for
pretreatment standards for new sources. Options 1 and 2 were
considered in formulating the proposed rule. As a result of
public comments received, an alternative mass limitation for
ammonia was added to Option 1 after proposal of the regulation.
Option 3, the existing PSES level of control, was reconsidered
244
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after publication of the proposed rule. Option 3 also contains
an alternative mass limitation for ammonia (N).
Option 1 - Chromium reduction by pH adjustment, precipitation
and clarification technologies applied to segregated cooling
tower blowdown, plus control of oil and grease and ammonia at
the existing PSES level of control.
Option 2 - Establishment of two sets of pretreatment
standards. The first would be Option 1 control for
refineries discharging to POTW with existing or planned
secondary treatment. The second would be Option 1 control
plus treatment for total phenols by biological treatment for
those refineries discharging to a POTW that has been granted
a waiver from secondary treatment requirements under Section
301(h) of the Act. EPA's proposed pretreatment standards for
existing sources were based on this option. Further
discussion is provided in the 1979 proposed petroleum
refining regulation at 44 FR 75935.
Option 3 - Reduction of oil and greases and ammonia by
oil/water separation and steam stripping technologies.
Evaluation of. Pretreatment Options Considered
Option 1 - Reduce chromium in cooling tower blowdown to 1 mg/L by
pH adjustment/ precipitation, and clarification, and maintain
control of oil and grease and ammonia (N) at existing (PSES)
level of control (100 mg/L). Include alternative mass
limitations for ammonia (N) for those refineries that discharge
only sour waters to the POTW.
For the 1979 proposal, the Agency estimated the cost of
retrofitting the affected indirect discharge refineries at an
initial investment of $11.7 million and an annual cost of ?6.8
million (1979 dollars). These estimates assume that cooling
tower waste streams are readily identifiable and separable for
all refineries (see Appendix A).
This option presumes the industrywide ability to segregate,
collect, and separately treat cooling tower blowdown, the major
source of chromium for this industry. The wastewater
recycle/reuse study (see Section VII), completed after
publication of the proposed regulation, concluded that, for
existing sources, it is not technologically feasible, in many
instances, to segregate cooling tower blowdown for chromium
treatment. Cooling tower blowdown is typically effected at
numerous locations throughout a refinery. Extensive collection
systems would be necessary at many refineries to collect all
blowdown streams for separate treatment. In addition, not all
cooling tower blowdown streams are collectable. For instance,
cooling water when used as makeup for refinery processing
245
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commingles with process water and cannot be traced or segregated,
especially in older refineries.
An alternative, treatment of the combined refinery waste stream
for chromium removal, would require installation of most, if not
all, of the BPT treatment train. Installation of BPT treatment
for all existing indirect dischargers would cost an estimated
$110 million in capital costs, and an annual cost of $42 million
(1979 dollars). This estimate represents the maximum cost
estimated by assuming installation of BPT treatment for all
indirect dischargers (See Option 2).
New refineries have the opportunity to design separation of
cooling tower waste streams into the system and do not incur
retrofit costs or the cost of treating combined waste streams.
Separate treatment of cooling tower blowdown may be readily
applied by new source indirect dischargers. The Agency estimated
the incremental cost of incorporating Option 1 technology in a
new source at an annual investment of $0.37 million and an annual
cost of $0.26 million (1979 dollars) (see Appendix A).
Option 2 - Establish two sets of criteria; one for refineries
that discharge to POTW with existing or planned secondary
treatment, and one for refineries that discharge to POTW which
have received a Section 301(h) waiver.
Under Section 301
-------
total phenols. Treatment for total phenols (4AAP) would require
the addition of BPT end-of-pipe treatment.
Total cost of implementing Option 2 for existing indirect
dischargers could not be calculated for the 1979 proposal, since
no POTW had yet been granted a Section 301(h) waiver. The Agency
did estimate the cost of installing biological treatment for each
indirect discharge refinery. The Agency also estimated the cost
of installing Option 1 treatment technology for each indirect
discharging refinery. There was no determination of which of the
refineries would ultimately discharge to POTW with secondary
treatment versus those that would discharge to POTW with Section
301(h) waivers. However, if all indirect discharging refineries
were required to install biological (BPT end-of-pipe) treatment
systems, the maximum cost to the industry would be an initial
capital investment of $110 million and an annual cost of $42
million (1979 dollars) (Appendix A).
Option 2 was proposed in the December 1979 regulation. The
rationale was that a POTW with a primary treatment system will
not adequately remove the toxics from the refinery. A POTW with
primary treatment that receives waste from refineries was
sampled. The results indicated that removal effectiveness is
significantly less than that of a secondary system (see Appendix
B - Raw Plant Data).
There are currently three POTW which recieve refinery wastes that
can apply for Section 301(h) variances. In order to obtain a
301(h) variance, the POTW must be able to demonstrate that:
o The discharge will not interfere with the attainment or
maintenance of water quality which assures the
protection of public water supplies and the protection
and propagation of a balanced, indigeneous population of
shellfish, fish and wildlife and allows recreational
activities, in and on the water, (Section 301(h)(2);
o The POTW has a monitoring system to measure, to the extent
practicable, the impact of the discharge on a
representative sample of aquatic biota, (Section
301(h)(3);
o The discharge will not impose additional requirements on
any other point or nonpoint source, ^Section 301(h)(4);
o All applicable pretreatment standards are enforced,
(Section 301(h)(5);
o The POTW, to the extent possible, has established a
schedule of activities designed to eliminate the
entrance of toxic pollutants from non-industrial sources
into the treatment works, (Section 301(h)(6));
247
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o There will be no substantial increase in the volume of
discharged pollutants to which the modification applies
from the treatment works.
The degree of treatment required for a POTW obtaining a Section
301(h) waiver is determined after evaluating, among other things,
the physical characteristics of the discharge and the nature of
the receiving waters. Treatment levels vary for every POTW
because of the importance of these site-specific factors; thus,
the levels of toxic pollutants which pass through will also vary
significantly in each case.
EPA now believes that it is not feasible and that it would be
inappropriate to establish national pretreatment standards that
take into account whether a discharger uses a POTW which has
received a 301(h) waiver. Rather, the need for more rigorous
pretreatment controls should be resolved on a case-by-case basis
during the Section 301 (h) waiver process, depending on the degree
of the toxic pollutant problems in each instance.
Option 3 - Reduce oil and grease and ammonia by oil/water
separation and steam stripping technologies. This option is
equivalent to existing PSES except that an alternate mass
limitation for ammonia is provided for ammonia (N) for those
refineries that discharge only sour waters to the POTW.
Regulated pollutants are oil and grease and ammonia (N) (100
mg/L), each on a daily maximum basis.
Option 3 does not limit the concentration of chromium in the
effluent of indirect dischargers. At the time of proposal, the
Agency believed such concentrations of chromium would limit a
POTW's use or management alternatives of the sludge. Based upon
review of existing information and analysis of public comments on
the proposal, EPA has determined that this rationale is not valid
on a nation wide basis. For this industry, chromium levels in
sludge from POTW receiving petroleum refinery wastes generally do
not impact sludge disposition or alternatives for use. There are
no Section 405 sludge standards directed at concentrations of
chromium in the sludge. Therefore, EPA has determined that the
better approach is to permit the POTW to establish chromium
pretreatment standards for existing sources if refinery waste
would limit their sludge disposal alternatives. The general
pretreatment regulations specifically provide the POTW with this
authority. (See 40 CFR 403.5).
This option is the basis for the existing interim final PSES
regulation. An alternative mass limitation for ammonia (N) is
provided to those indirect dischargers whose discharge to the
POTW consists solely of "sour waters. Sour waters generally
result from water brought into direct contact with a hydrocarbon
stream, and contains sulfides, ammonia and phenols. The Agency
developed an alternative mass limitation for ammonia in response
to public comments received on the proposed regulation. Several
248
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commenters indicated that, when the refinery discharge to the
POTW consists solely of sour waters, achievement of the 100 mg/L
ammonia concentration limitation is often not possible. This is
because steam stripping technology, the basis for the
limitations, cannot consistently reduce ammonia in sour water
streams to the 100 mg/L level. Thus, an equivalent mass
limitation for ammonia was developed by the Agency.
IDENTIFICATION OF PRETREATMENT STANDARDS
PSES - EPA has selected Option 3, retention of the existing level
of control, for final regulation of existing indirect discharge
refineries. Option 1 was rejected because the Agency found it
infeasible in many instances to segregate cooling tower blowdown
for chromium treatment on an industrywide basis for existing
refineries. Option 2 was rejected on the basis that it would be
inappropriate to establish separate national pretreatment
standards for those refineries that discharge to POTW which have
a Section 301(h) waiver because the conditions surrounding those
installations are very site specific and can be better evaluated
by the individual POTW. The general pretreatment regulations
specifically provide POTW with authority to institute standards
for pretreatment of industrial discharges which limit sludge
disposal options.
PSNS - The Agency has selected Option 1 for the regulation of new
sources. Segregation and separate treatment of cooling tower
blowdown can fae implemented with little additional expense in the
design and construction of new refineries. Option 2 was rejected
for the same reasons discussed under PSES.
249
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SECTION XI
ACKNOWLEDGMENTS
Many individuals representing numerous organizations,
corporations, and agencies have contributed material, time and
energy to the technical studies conducted in developing these
effluent limitations guidelines and standards, and to the
production of this document.
This document was prepared under the direction of Mr. Dennis
Ruddy and Mr. John Lum, Project Officers in the Energy and Mining
Branch of EPA's Effluent Guidelines Division. Mr. William A.
Telliard, Chief of the Energy and Mining Branch, also provided
direction and assistance during the course of the program.
The Agency wishes to acknowledge the contributions to this
project of Burns and Roe Industrial Services Corporation of
Paramus, New Jersey under the direction of Mr. Arnold S. Vernick,
Manager of Environmental Engineering, and Mr. Elwood C. Walker,
Program Director.
The cooperation and assistance of the American Petroleum
Institute and of the numerous company and refinery personnel who
were involved in data gathering efforts/ site studies, and
wastewater sampling programs are greatly appreciated. The
Agency's Robert S. Kerr Environmental Research Laboratory, all
EPA regional offices, and the County Sanitation Districts of Los
Angeles are specifically acknowledged for their efforts.
Appreciation is expressed to those at EPA Headquarters who
contributed to the completion of this project, including Mr.
Jeffery Denit of the Effluent Guidelines Division; Ms. Eleanor
Zimmerman of the Monitoring and Data Support Division; Mr. Louis
DuPuis, Mr. John Kukulka, and Mr. Henry Kahn of the Office of
Analysis and Evaluation; and Ms. Susan Lepow and Mr. Mark Gordon
of the Office of General Counsel.
251
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SECTION XII
REFERENCES
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Waste Load Survey," December 1972.
2. American Petroleum Institute, Disposal of. Refinery
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3. Development Document for Effluent Limitations Guidelines
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4. Bush, K. E., "Refinery Wastewater Treatment and Reuse,"
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7. Easthagen, J.H. et al., "Development of Refinery Waste
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27. Diehl, D. S. et al., "Effluent Quality Control at a
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33. Mitchell, G. E., "Environmental Protection - Benecia
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255
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for the Environmental Protection Agency, June 1976,
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44. Wiley, M. A., "Chromium Analysis", API Proceedings,
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46. "Environmental Effect of Disposal of Municipal
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47. Donaldson, W. T., "Trace Organics in Water,"
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49. Davis, J. C., "Activated Carbon: Prime Choice to Boost
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50. Grutsch, J. F. and Mallatt, R. C., "A New Perspective on
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256
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51. Gould, J. P. and Weber, W. J., "Oxidation of Phenols by
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52. Zogorski, J. S. and Faust, S.D., "Removing Phenols via
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53. Gesick, J. A., "A Comparative Study of Non-Chromate
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54. Zecher, D. C., "Corrosion Inhibition by Surface - Active
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55. Robitaille, D. R. and Bilek, J. G., "Molybdate Cooling-
Water Treatments," Chemical Engineering, December 20,
1976.
56. Bush, K. E., "Refinery Wastewater Treatment and Reuse,"
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57. Mohler, E. F., Jr., and Clere, L. T., "Development of
Extensive Water Reuse and Bio-Oxidation in a Large Oil
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58. Mohler, E. F., Jr., and Clere, L. T., "Sun Oil Develops
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10, 1973.
59. Crame, L. W., "Activated Sludge Enhancement: A Viable
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60. Grieves, C. G. et al., "Powdered Activated Carbon
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61. Heath, H. W., Jr., "Combined Powdered Activated Carbon -
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257
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62. Dehnert, J. F., "Case History - The Use of Powdered
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63. Zanitsch, R. H., and Lynch, R. T., "Granular Carbon
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64. Process Design Manual for Carbon Adsorption,
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65. Ford, D.L. and Tischler, L. F., "Meeting BPT Standards
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66. Proceedings of_ the 1972 National Conference on Control
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70. DeWall, F.B. et al., "Organic Matter Removal by Powdered
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258
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and Engineering News, January 23, 1978.
127. Reed, D.T., Klen, E.F., and Johnson, D.A., "Use Stream
Softening to Reduce Pollution," Hydrocarbon Processing,
November 1977.
128. Finelt, S. and Crump, J.R., "Pick the Right Water Reuse
System," Hydrocarbon Processing, October 1977.
129. Telliard, W. A., Rationale for the Development o_f BAT
Priority Pollutant Parameters, May 24, 1977.
130. Grutsch, J.F. and Mallatt, R.C., "Optimizing Granular
Media Filtration," Chemical Engineering Progress, April,
1977.
131. Lash, L., "Scale-up of Granular Media Filters," Chemical
Engineering Progress, April 1977.
132. Brody, M.A. et al., "Performance of Dual-Media Filters,"
Chemical Engineering Progress. April 1977.
Upflow Filtration," Chemical Engineering Progress, April
1977.
134. Bardone, L. et al., Costs of Reducing SOs Emissions and
Improving Effluent Water Quality from Refineries,
Concawe, Report NR., March 1977.
135. Heath, H.W., Jr., "Chambers Works Wastewater Treatment
Plant Removal of Organic and Organo-Nitrogen Compounds
From Wastewater," unpublished report .to Robert S. Kerr
Environmental Research Laboratory, November 1976 to
April 1977.
136. Hakansson, H. et al., Petroleum and Petrochemicals,
Swedish Water and Air Pollution Research Laboratory,
B346, Stockholm, January 1977.
137. Matthews, J.E. et al., Acute Toxic Effects of. Petroleum
Refinery Wastewaters on Redear Sunfish. Office of
Research and Development, U.S. Environmental Protection
Agency, EPA-600/2-76-241, October 1976.
138. Pendleton, H.E., Ph.D., "Petroleum and the Environment,"
Pollution Engineering. September 1977.
139. Dickerman, J.C. et al., Industrial Process Profiles for
Environmental Use "Chapter 3-Petroleum Refining
Industry," U.S. Environmental Protection Agency, EPA-
600/2-77-023C, January 1977.
263
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140. "Industry's Challenge-on Benzene," Business Weeks August
22, 1977.
141. Gubrud, A.E., remarks at the Federal Water Quality
Association Conference on Toxic Substances in the Water
Environment, April 28, 1977.
142. Weiss, A.E., remarks at the Federal Water Quality
Pollutants in the Aquatic Environment," prepared for the
Open Forum on Management of Petroleum Refinery
Wastewater, June 7, 1977.
143. Kuserk, F., "Texaco Has the Right Answer for Cleaner
Refinery Effluents," New Jersey Effluents, October 1977.
144. DeWalle, F.B. et al., "Organic Matter Removal by
Powdered Activated Carbon Added to Activated Sludge,"
Journal Water Pollution Control Federation, April 1977.
145. Grieves, C.G., "Powdered Carbon Improves Activated
Sludge Treatment," Hydrocarbon Processing, October 1977.
146. Ford, O.L. et al., "Meeting BPT Standards for
Intermediate and Secondary Refinery Wastewater
Treatment," Industrial Wastes, September/October 1977.
147. Hannah, S.A. et al., "Removal of Uncommon Trace Metals
by Physical and Chemical Treatment Processes," Journal
Water Pollution Control Federation, November 1977.
148. Electron Microscopic Analysis of. Water Samples for
Asbestos, Final Report, GCA Corporation, GCA/Technology
Division, December 1977.
149. Analysis of Petroleum Refinery Effluents for Organic
Priority Pollutants, Draft Final Report, Midwest
Research Institute, March 1978.
150. Water Reuse Studies, API Publication 949, American
Petroleum Institute, August 1977.
151. Cost Manual for the Direct Discharge Segment of_ the
Petroleum Refining Industry, prepared by Burns and Roe
Industrial Services Corporation, for the U.S.
Enviornmental Protection Agency March 1979.
152. Rizzo, J.A., "Case History: Use of Powdered Activated
Carbon in an Activated Sludge System," prepared for the
First Open Forum on Petroleum Refinery Wastewaters,
Tulsa, OK, January 1976.
153. Grieves, C.G. et al., "Effluent Quality Improvement by
Powdered Activated Carbon in Refinery Activated Sludge
264
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Processes," prepared for the API Refining Department,
42nd Midyear Meeting, Chicago, Illinois, May 11, 1977.
154. Thibault, G.T., Tracy, K.D., and Wilkinson, J.B.,
"Evaluation of Powdered Activated Carbon Treatment for
Improving Activated Sludge Performance," prepared for
the API Refining Department, 42nd Midyear Meeting,
Chicago, IL, May 11, 1977.
155. Flynn, B.P., "Startup of 38 MGD Powdered Activated
Carbon - Activated Sludge (PACT) Treatment System at
DuPont's Chambers Works," prepared for the 50th Annual
Water Pollution Control Federation conference,
Philadelphia, PA, October 3, 1977.
156. Robertaccio, F.L., "Combined Powdered Activated Carbon -
Biological Treatment: Theory and Results," prepared for
the Second Open Forum on Management of Petroleum
Refinery Wastewaters, Tulsa, OK, June 8, 1977.
157. Spady, B. and Adams, A.D., "Improved Activated Sludge
Treatment With Carbon," Deeds £ Data, Water Pollution
Control Federation, January 1976."
158. Development Document for Effluent Limitations Guidelines
and Standards for the PetroleumRefining Point Source
Category. U.S. Environmental Protection Agency
440/1-79/014-b, December 1979.
159. Wastewater Recycle Study - Petroleum Refining Industry,
preparedby Burns and Roe Industrial Services
Corporation for the U.S.E.P.A. E.G.D., November 1980.
160. Preliminary Screening of the 1979 Effluent Monitoring
(BPT)Data, prepared by Burns and Roe Industrial
Services Corporation for the U.S. Environmental
Protection Agency, Effluent Guidelines Division,
September 1982.
161. Petroleum Refining Self Monitoring Data Analysis,
prepared bySanford Research Institute for the U.S.
Environmental Protection Agency, Office of Analysis and
Evaluation, September 1982.
162. Surrogate Sampling Program Petroleum Refining Industry,
prepared by Burns and Roe Industrial Services
Corporation Submittal to U.S. Environmental Protection
Agency, Effluent Guidelines Division, September, 1982.
163. Summary of the Record for the Development of, the Survey
of 1979 Effluent Monitoring Data for the Petroleum
Refining Point Source Category, prepared by Burns and
Roe Industrial Services Corporation for the U.S.
265
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Environmental Protection Agency, Effluent Guidelines
Division, June 19SQ.
164. Petroleum Refining Industry, Refinements to 1979
Proposed Flow Model and Supplemental Documents, prepared
by Burns and Roe Industrial Services Corporation for the
U.S. Environmental Protection Agency, Effluent
Guidelines Division, September 1982.
165. Ambient Water Quality Criteria, U.S. Environmental
Protection Agency, Criteria and Standards Division, EPA
440/5-80-069, November 1980.
166. Petroleum Refining Industry, Flow Model Documentation
Report, prepared by Burns and Roe Industrial Services
Corporation for the U.S. Environmental Protection
Agency, Effluent Guidelines Division, March 1980.
167. Cantrell, Ailleen, "Annual Refining Survey," Oil and Gas
Journal, March 30, 1981.
168. Environmental Data Summary and Analysis for the
PetroleumRefining Industry, prepared by Versar, Inc.
for the U.S. Environmental Protection Agency, Monitoring
and Data Support Division, September 10, 1982.
169. Development Document for Effluent Limitations Guidelines
andStandardsfor the Coil Coating Point Source
Category, EPA 440/1-81/071b, January 1981.
170. Development Document for Effluent Limitations Guidelines
and Standards""!:or the Inorganic Chemicals Manufacturing
Point Source Category, Final, EPA 440/1-82/007, June
T9827
171. BAT Compliance Costs for the Direct Discharge Segment of_
the Petroleum Refining Industry, prepared by Burns and
Roe Industrial Services Corporation for the U.S.Environ-
Protection Agency, Effluent Guidelines Division,December
1980.
172. Hynek, R.J. and Chou, C.C., "Field Performance of Three
RBC Aeration Modes Treating Industrial Wastes,"presented
at the 35th Annual Purdue Industrial Waste Conference,
May 13-15, 1980.
173. Davies, B.T. and Vose, R.W. "Custom Designs Cut Effluent
Treating Costs Case Histories at Chevron U.S.A., inc."
Proceedings of the 32nd Purdue Industrial Waste Confer-
ence, May 10-12, 1977.
174. Grieves, C.G., Crame, L.W., Vernardos, D.G., Ying, W. ,
"Powdered versus Granular Carbon For Oil Refinery Waste-
water Treatment," Journal Water Pollution Control Feder-
ation , March 1980.
266
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APPENDIX A
COSTS OF TREATMENT AND CONTROL SYSTEMS
INTRODUCTION
This section addresses the costs associated with the control and
treatment technologies presented in Section VII. As such, the
cost estimates represent the incremental expenditures required
over and above the capital and operating costs associated with
attainment of existing effluent limitations. These differential
costs, therefore, relate to specific control and treatment
alternatives that could be necessary to comply with BAT limit-
ations .
The cost estimates presented do not include land costs; the cost
of land is variable and site dependent and cannot be estimated on
a national basis. However, the amount of land required is
indicated for each of the major end-of-pipe treatment schemes.
These land requirements are minimal compared with the land
requirements for refinery process equipment and existing waste-
water treatment facilities.
The cost data presented in this section are based on flow rates.
The major capital cost items considered were equipment, instal-
lation, engineering, and contingencies, while operating costs
included maintenance, labor, chemical, and power costs. The
following unit costs in 1977 dollars were used for calculating
the major capital and operating costs presented in this section:
Item Unit Cost
1. Tank Steel $1.40 - 2.00/pound
2. Tank Lining $3.00 - 4300/ft
3. Carbon, granular (capital cost) $31.00/ft
4. Carbon, granular (operating cost) $0.61/lb
5. Carbon, powdered (operating cost) $0.31/lb
6. Electricity $0.04/kilowatt hr
7. Manpower $10.00/hr
Capital costs for major equipment items such as clarifiers,
filters, carbon regeneration furnaces, solids dewatering filters,
activated carbon, and large pumps were obtained from equipment
manufacturers. Other costs such as the unit cost of tank steel,
piping, small pumps, etc. were derived from the contractor's
(Burns and Roe) in-house experience and expertise in the design
and construction of major facilities.
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COST OF TECHNOLOGIES CONSIDERED
Biological Treatment
Cost analyses developed for BPT regulations are based on activated
sludge or equivalent BPT systems (3). A very limited number of
refineries may need to upgrade their existing biological treatment
systems to comply with BAT limitations.
One method of upgrading a biological unit is to install a raw
wastewater equalization system (143). Table A-l presents capital
and operating costs for this type of modification. These costs
are based on 12 hours detention and include the necessary pumps
and controls for equalization of flow and pollutant loading.
EPA assumes the tanks are manufactured by placing a steel shell
on a concrete pad. Costs are included for pumping the wastewater
either to or from the equalization tank. The Agency also assumes
that either pumping is not required on both sides of the tank, or
one set of pumps exists to supply the second pumping requirement.
Another method of improving the performance of a biological
treatment system is to install a biological roughing unit.
Rotating biological contactors (RBCs) are an applicable treatment
alternative for use as a roughing system.
Tables A-2 and A-3 present equipment sizes and energy requirements
and capital and operating costs for RBC units. It is assumed
that this treatment alternative will be used if aerated lagoons
or oxidation ponds comprise the basic biological treatment process.
The use of aerated lagoons and oxidation ponds implies that the
refinery has sufficient land to install this type of wastewater
treatment system.
It is also assumed that the RBC units will precede the present
biological system. Clarifiers or additional sludge handling
capabilities will not be required, based on the assumption that
the amount of solids carryover from the RBC units to the lagoons
is approximately the same as that now entering the lagoons from
the raw wastewater.
Filtration
BPT limitations are based, in part, on granular media filtration
or polishing ponds (3). Many refineries do not include filtration
or other polishing techniques in their present systems, even
though that technology was included in model BPT. Certain
refineries may have to install granular media filtration to
comply with BAT limitations. Tables A-4 and A-5 include the
associated cost data for filtration systems.
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Powdered Activated Carbon
Refineries with activated sludge or trickling filter systems may
inprove their effluent quality with powdered activated carbon
treatment. Tables A-6 through A-8 present cost data for powdered
activated carbon systems that do not include the cost of sludge
handling in the analysis. However, when carbon regeneration is
used in conjunction with powdered activated carbon treatment,
the sludge produced in the biosystem is incinerated as the
carbon is regenerated, thus eliminating the sludge disposal
costs associated with this requirement. An analysis was undertaken
to compare annual cost when sludge handling is included as a
cost factor. This analysis is included in Table A-9. Tables A-
10 through A-12 present cost data for powdered activated carbon
systems based upon the inclusion of sludge handling costs.
Table A-ll includes the costs for purchase of solids dewatering
systems, whereas Table A-12 includes operating costs with sludge
disposal shown as a credit for the systems that include carbon
regeneration.
The powdered activated carbon costs described above are based
upon an 80 mg/L dosage rate. Thfis number is based upon one year
of operating data at the DuPont Chambers works facility.
Powdered activated carbon treatment may also be used for the
removal of organic toxic pollutants, but may require higher
carbon dosages. Tables A-13 through A-15 present costs for
powdered activated carbon systems based upon a carbon dosage of
150 mg/L. Tables A-16 through A-19 present the analyses and
associated results when the costs for sludge hauling are recognized.
Granular Activated Carbon
Table A-20 presents the equipment sizes and energy requirements
used to estimate the capital and operating costs for granular
activated carbon systems. The sizes are based on the design
concept described in Section VII, with the system consisting of
tanks that can be shipped in one piece, thereby minimizing field
construction. This sizing constraint results in an unusually
large number of tanks for the larger systems. In reality, a more
cost-effective approach (with cost savings approximately 5 to 15
percent) is for a given refinery to use field constructed steel
tanks, concrete tanks, or other construction techniques, which
have been determined for that refinery individually. The use of
shop fabricated tanks with similar sizes allows for uniformity in
cost estimating, especially in developing construction and design
engineering estimates. This approach also results in a conserva-
tive (larger) estimate, and is considered preferable when considering
general industry-wide costs.
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Table A-21 presents the capital costs for the systems outlined in
Table A-20. Table A-22 provides the operating costs, excluding
depreciation, for these granular activated carbon systems. The
capital costs for carbon regeneration systems are based on an
equipment manufacturer's quotations. Manpower requirements for
the operation of the granular carbon adsorbers were obtained from
the EPA Technology Transfer Series, Carbon Adsorption Manual
(64).
One equipment supplier leases carbon adsorption systems. Plants
would pay a yearly operating cost with no initial investment
other than a foundation for and piping to the equipment. This
supplier has suggested the following rental cost estimates for
the two smallest systems:
o 380 M3/day (O.lxlO6 gal/day)
Foundation and hookup
o 3,800 M3/day (l.OxlO6 gal/day)
Foundation and hookup
- $75,000 to $100,000/yr
- $5,000
- $450,000/yr
- $15,000
These estimates are based on a lease agreement for a minimum of
three years and include the carbon adsorbers with installation,
all granular carbon required, and carbon regeneration services.
Manpower for the operation of the carbon columns is not included.
Low Flow Rate Systems
Table A-23 presents capital and operating costs for the systems
discussed above at a design flow rate of 10,000 gal/day.
In-Plant Control
Chromium Removal - The treatment technology described in Section
VII is the basis for estimating the costs of chromium removal.
Refineries can also take advantage of the reduction capabilities
of refinery sewers and the removal capabilities of secondary
treatment systems.
Table A-24 presents cooling tower blowdown rates for the refineries
that responded to the 1977 EPA Petroleum Refining Industry Survey.
The flow rates have been used as the design basis for chromium
treatment systems. Table A-25 presents equipment cost bases and
energy requirements for selected flow rates from Table A-24;
Table A-26 presents the capital and operating costs for these
systems.
Flow Reduction - Section VII describes a number of in-plant
control measures designed to reduce or eliminate wastewater flow.
Many of these measures, however, require a plant-by-plant evaluation
to determine their usefulness. In addition, the costs associated
with their implementation are, for the most part, site dependent
making an accurate estimation of representative costs on an
industry-wide basis very difficult.
A-4
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For the 1979 proposal, the Agency did select one in-plant flow
reduction measure, however, that can be applied at most refineries
and whose cost can be readily estimated on an industry-wide
scale. This flow reduction scheme consists of recycling treated
refinery wastewaters for process-related applications such as
cooling tower makeup, pump gland cooling water, washdown water,
and fire system water. This wastewater could be reused once and
then returned to the refinery wastewater collection system for
end-of-pipe treatment. The amount of wastewater that can be
recycled in this manner depends on many factors, including the
number of cooling towers in the plant and the salinity of the
wastewater to be recycled. EPA chose this wastewater reduction
technique to form an estimate, because it is both definable and
representative of the costs that would be incurred by other,
similarly effective in-plant control measures.
Table A-27 presents the capital and operating costs per mile used
for the 1979 proposal for recycling various amounts of treated
wastewater. In some cases, particularly for cooling tower makeup,
the recycled wastewater may require treatment to remove calcium
and magnesium hardness. The costing procedure for the 1979
proposal assumed the use of lime or lime-soda ash softening
followed by filtration. Table A-28 presents the capital costs
for softening systems that correspond to the flow rates in Table
A-27. Operating costs cannot be readily determined on an industry-
wide basis because they depend largely on the site specific
concentrations of calcium and magnesium in the recycled waste-
water. Lime costs can be approximated at $0.025/1,0000 gal of
treated water for an influent hardness of 100 mg/1 (as CaCCU), to
$0.12/1,000 gal for an influent hardness of 500 mg/1 (as CaCOO.
These costs can vary, depending on the desired effluent qualify
and on the influent water quality, especially costs involving
alkalinity.
In an effort to confirm its assessment of wastewater flow reduction
costs, the Agency conducted a series of site investigations after
proposal to identify feasible flow reduction techniques and to
determine actual costs for specific refineries to install these
technologies. This Wastewater Recycle Study involved fifteen
refineries throughout the United States and focussed on methods
of recycling and reusing wastewaters within a refinery in an
effort to reduce the rate of final discharge. These methods
included the recycling of treated wastewaters, the reuse of sour
water, the recycling of pump and compressor cooling water, and
the collection and reuse of steam condensate. Site investigations
involved wastewater management practices that were found to be
successful in reducing final effluent and that could be generally
applicable to other refineries. The findings of the overall
study, including discussions of the flow reduction schemes developed
A-5
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for each refinery and estimates of the capital and annual
operating cost requirements involved, were presented in a report
(159). Results indicate that wastewater discharge reduction to
the proposed BAT flow level is achievable at the refineries
investigated. The study also revealed that the costing procedure
used in developing the proposed regulations did produce conserva-
tive cost estimates.
COST OF TECHNOLOGY SELECTED AS BASIS FOR LIMITATIONS AND STANDARDS
EPA considered nine options in finalizing BAT regulations, four
options for NSPS guidelines, and three options for PSES and PSNS
controls. The following discussions describe the costing method-
ologies and results obtained for each.
BAT Options
As discussed in Section VIII, nine regulating options that included
various combinations of flow reduction and wastewater treatment
technology were considered for BAT. Options 1 through 6 were
investigated in formulating the proposed rule. Option 7 (a
modification of Option 2) and Option 8 (a modification of Option
1) were developed on the basis of information that was available
at the time of the 1979 proposal, but was then modified and
supplemented as a result of information collected by EPA after
the proposal. Option 9 requires no additional controls beyond
existing BPT, and therefore, would incur no additional cost.
Cost estimates for Options 1, 2, and 3 were developed for the
direct discharging segment of the industry on a plant-by-plant
basis for the 1979 proposal. These estimates of total capital
and annual operating costs in 1977 dollars are presented in
Table A-29.
It was realized that the most accurate method of determining
compliance costs would be to conduct an engineering evaluation at
each refinery that might be affected by proposed discharge regu-
lations. However, in order to produce conservative compliance
costs within a reasonable manhour expenditure, a cost estimating
procedure was established. The procedure relied on flow reduction
and end-of-pipe treatment alternatives that could be directly
defined. The approach included flow reduction only (Option 1) ,
and flow reduction plus enhanced biological treatment (Option 3).
The costs of the Option 3 wastewater management combination were
used to represent the costs associated with meeting Option 2
requirements.
The procedure developed to estimate plant-by-plant compliance
costs began with a review of each refinery's generated waste-
waters, end-of-pipe treatment system, and modes of disposition.
The volume of wastewater generated daily by each refinery was
traced and categorized according to treatment and disposal. Data
were obtained from industry responses to EPA's 1977 Petroleum
Refining Industry Survey and its subsequent submittals.
A-6
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The next step in the costing procedure was to determine the type
of biological enhancement to be added at each refinery and then
assign costs. Although an individual refinery may choose to
upgrade its biological treatment system in other ways, powdered
activated carbon treatment and rotating biological contactors
were considered in this procedure, and readily priced as add-on
systems. Refineries that had, or were planning to have, aerated
lagoons or oxidation ponds were given costs for RBC systems.
Refineries that had, or were planning to have, activated sludge,
trickling filters, or RBC systems were given costs for powdered
activated carbon treatment. Capital and operating treatment
costs were based on the influent rate to the end-of-pipe system,
with a minimum of 10,000 gallons per day. Costs for these systems
were expected to be conservatively high estimates.
Determining the amount of flow reduction required by each refinery
was the third step in the procedure. The proposed flow model
presented in Section IV was used to calculate model wastewater
generation rates, based on process capacities, for each direct
discharger. BAT discharge rates were then set at 73 percent of
the calculated model flow (27 percent reduction). Each refinery's
actual rate of direct discharge of production wastewaters was
compared to its calculated BAT discharge rate to determine
required reductions. Prior to this comparison, actual discharges
were adjusted by planned reductions in the amount of wastewater
generated, and reductions in flow to end-of-pipe treatment.
The following step in the procedure was to allocate flow reduction
costs. The assumed reduction technique selected for the develop-
ment of cost estimates was the recycling of treated wastewater
for use in process related applications, such as cooling tower
make-up, pump gland cooling water, wash down water, and fire
system water. Based on recycle flow rate and a derived relation-
ship between refinery size and required pumping distance, pumping
and piping costs were calculated for each refinery that required
flow reduction. The assumption was also made that softening
would be necessary before treated wastewater could be reused.
Costs were determined for softening 25 percent of the recycled
wastewater with the lime-soda process and filtration.
The final step in the compliance costing procedure was to combine
the treatment and flow reduction costs assigned to each refinery
and to compute overall industry costs. Capital and operating
costs for each refinery were generated by adding those model
technologies that did not exist in 1976 and that were not planned
for the future. Since biological treatment is essential in
meeting the BPT guidelines, this level of treatment was assumed
to exist at all direct discharging refineries. Therefore, the
cost estimates represent the incremental expenditures required
over and above the costs associated with attainment of BPT
effluent limitations.
A-7
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More details on the costing procedure and refinery data used to
estimate compliance costs can be found in the report on this
effort entitled, "Cost Manual for the Direct Discharge Segment of
the Petroleum Refining Industry" (151). The cost evaluation
concluded that, for Option 1, a total industry capital cost of
$23.5 million in 1979 dollars would be required, with an annual
operating cost of $3.4 million, to comply with proposed effluent
limitations guidelines. Option 2 and Option 3 would require a
total capital cost of $138 million and an annual operating cost
of $27.1 million. These cost figures have been updated to 1979
dollars based upon the Nelson Refinery Construction and Operating
Cost Indices.
An "annualized cost" combines capital cost and operating cost
into a single value that represents average annual disbursements
required to finance, operate, and amortize a facility. The basis
for computing annualized compliance costs, as outlined in the
Agency's economic analysis of proposed effluent standards and
limitations (87), is the sum of annual operating costs (including
labor, materials, chemicals, energy, insurance, and taxes),
capital recovery, and return-on-investment. Computed on this
basis, the estimated annualized cost that would be required for
Option 1 is $9.3 million, while $62 million would be required for
Options 2 and 3.
Option 4 required effluent limitations beyond BPT based upon
wastewater flow reduction and the segregation and separate
treatment of cooling tower blowdown. While the cost of chromium
removal could be estimated, the cost of segregating cooling tower
blowdown from other process streams was not available at the time
of proposal. Therefore, EPA did not make a detailed cost analysis
for this option.
One objective of the Agency's wastewater recycle/reuse study
(159), conducted after the publication of the proposed regulation,
was to determine the waste management changes that would be
required and the costs involved to segregate and collect these
blowdown streams. Results of the study indicate that, for
existing sources, it is extremely difficult, in many instances, to
segregate cooling tower blowdown for chromium treatment. Cooling
tower blowdown is typically effected at numerous locations
throughout a refinery. Extensive collection systems would be
necessary at many refineries to collect all blowdown streams for
separate treatment. In addition, not all cooling tower blowdown
streams are collectible. For instance, cooling water when used
as makeup for refinery processes commingles with process water
and cannot be traced or segregated, especially in older refineries.
Therefore, the Agency has determined that it would not be proper
to base BAT effluent limitations guidelines on this technology
option. Complete cost estimates for this option have not been
developed.
A-8
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Option 5 was based upon wastewater flow reduction in addition to
BPT treatment plus the addition of granular activated carbon
treatment to control residual toxic organic pollutants. Cost
estimates for this option were based upon compliance costs
developed for Option 1 and the capital and operating costs for
GAG treatment as shown in Tables A-21 and A-22. A total annual
industry cost of an estimated $470 million in 1979 dollars would
be required for this option.
Prohibiting the discharge of wastewater pollutants was proposed
as Option 6, and was based upon reuse, recycle, evaporation, or
reinjection of wastewaters. Total industry costs were not calcu-
lated for this option. While additional costs for building a new
refinery to eliminate discharge have been determined, the costs
of retrofitting an existing refinery are highly site specific.
Costs for a zero discharge option, however, would be significantly
higher than costs for applying any of the other options.
Options 7 and 8 are revisions to Options 1 and 2, and are based
upon discharge flow reductions from the revised model flow.
Results of the Agency's wastewater recycle study were used to
revise the compliance costing procedures previously developed for
Options 1 and 2.
Several methods were found at the refineries studied that could
reduce the rates at which wastewaters were being discharged from
boiler circuits, cooling tower circuits, and general process
uses. The use of treated effluent as a replacement for raw water
in these areas was also examined. However, not all methods are
applicable at every refinery. Each refinery's flow scheme,
intake water quality, and wastewater treatment system limit the
flow reduction options available to it. But, a list of techniques
has been identified from which a refinery can select one or more
alternatives to reduce its discharge rate to the target BAT
level.
Capital and operating cost data developed during the study represeni
combinations of flow reduction techniques that could be used to
meet the BAT level. A unit flow reduction cost resulted for each
refinery based on the mix of reduction schemes proposed for that
particular refinery. Annual flow reduction costs established for
all of the refineries investigated fall within a specified range
when expressed in terms of dollars per gallon reduced per day.
These cost data were used to estimate flow reduction costs for
the industry.
The previous compliance costing procedure began with a review of
each refinery's generated wastewaters, end-of-pipe treatment
system, and modes of disposition. The volume of wastewater
generated daily by each refinery was traced and categorized
according to treatment and disposal. The revised procedure
continued with a determination of the amount of flow reduction
A-9
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required by each refinery. Model flows were calculated based
upon process crude capacities. BAT discharge rates were then set
at 62.5 percent of the calculated model flows. Each refinery's
existing process wastewater discharge rate is compared to its
target BAT discharge rate to determine required reductions.
Prior to this comparison, existing discharges were adjusted by
flow reductions that were reportedly being planned for the near
future. Flow reduction costs were then allocated for each
refinery.
Plant-by-plant estimates of the costs that would be required for
Option 7 were developed for the direct discharge segment of the
industry. These estimates, along with refinery data used in the
costing procedure, are presented in a report prepared for this
effort entitled, "BAT Compliance Costs for the Direct Discharge
Segment of the Petroleum Refining Industry" (171). Results of
the revised procedure indicate that a total capital cost of $112
million and an annualized cost of $37 million in 1979 dollars
would be required for this segment of the industry to comply with
Option 7.
The Agency has not performed a detailed cost analysis of Option 8,
but has estimated such costs based upon the costing procedure
developed for Option 7. BAT discharge rates were set at 80
percent of the revised model flows. Flow reduction costs were
allocated for each direct discharge refinery, generating plant-
by-plant estimates of compliance costs for Option 8. This effort
concluded that a total capital cost of $77 million and an annualized
cost of $25 million in 1979 dollars would be required for the
industry to comply with Option 8.
New Source Costs
EPA considered four options for the final rulemaking. NSPS
Options 1, 2, and 3 were included in the 1979 proposal. Option 4
was added subsequently and would set new source standards equal
to the existing standards promulgated in 1974. NSPS Options 1,
2, and 3 utilize technology similar to BAT Options 2, 5, and 6,
respectively. Unlike the similar BAT technology options, new
sources have the opportunity to incorporate technological changes
without incurring the retrofit costs included in modifications to
existing refineries.
NSPS Option 1 - Discharge flow reduction to 52 percent below
model flow, achieved through greater reuse and recycle of waste-
water, in addition to BPT treatment, is equivalent to BAT Option 2.
A-10
-------
The 1979 development document contains an estimate of cost to
construct a new 150,000 barrel/day subcategory B refinery. Cost
for NSPS Option 1 include:
Cost Component 1979 Dollars
Capital Costs $ 0.75 million
Operating Costs 0.37 million
NSPS Option 2 - Discharge flow reduction to 27 percent below BPT
model flow, achieved through greater reuse and recycle of waste-
waters in addition to BPT treatment, plus use of granular activated
carbon (GAC) treatment to reduce residual organic toxic pollutants
is equivalent to BAT Option 5. A new refinery will not incur the
retrofit costs of flow reduction associated with BAT Option 5,
however, it will incur the capital cost for GAC plus annual
operating costs as shown in Tables A-21 and A-22.
NSPS Option 3 - Zero discharge of wastewater pollutants is similar
to BAT Option 6 except that the new refinery will not incur
retrofit costs.
EPA has not calculated the costs for eliminating wastewater
discharge. However, the API publication Water Reuse Studies
(150) has presented such costs for a 150,000 barrel per day
refinery. Based upon estimates contained in this document,
investment, over BPT, of 11.6 million would be required with an
annual cost of 4.6 million, including interest and depreciation
(1979 dollars).
NSPS Option 4 - Discharge flow reduction to from 25 percent to 50
percent below BPT model flow, depending upon subcategory, achieved
through greater reuse and recycle of wastewater is equivalent to
the existing new source performance standard promulgated in 1974.
NSPS Option 4 is equal to the existing criteria for new sources,
and therefore, a new refinery will incur no additional cost in
complying with this technology option.
Pretreatment Options
The Agency evaluated three technology options for the selection
of final standards for indirect dischargers. Options 1 and 2 are
similar to Options 1 and 2 presented in the 1979 proposal. The
third option was considered after the 1979 proposal and is similar
to the existing standard for existing sources. EPA developed
these costs by estimating the values for each plant requiring
chromium removal and/or biological treatment. The costs presented
in the tables were updated to January 1977.
Costs for end-of-pipe treatment includes the following processes:
Biological treatment, consisting of activated sludge units,
thickeners, digesters, and dewatering facilities.
A-ll
-------
Granular media filtration, consisting of filter systems and
associated equipment.
These costs were also indexed to January 1977 values.
PS Option 1 - Chromium reduction by pH adjustment, precipitation
and clarification technologies applied to cooling tower blowdown,
plus control of oil and grease and ammonia at the existing level
of control is similar to Option 1 in the 1979 proposal. Separ-
ation and treatment of cooling tower blowdown is the additional
technology required beyond existing pretreatment standards.
Table A-30 presents the costs of modifying each indirect discharge
refinery to meet Option 1 requirements. The analysis includes
the cost of combining the effluents from multiple cooling tower
installations. Estimates of necessary pumps and piping were
obtained from the cost presented for recycle of treated effluents
in Table A-27.
The Agency estimated the combined cost of retrofitting affected
indirected dischargers at $11.7 million initial investment and
an annual cost of $6.8 million (1979 dollars).
The Agency estimated the incremental cost of incorporating PS
Option 1 technology into a subcategory B model new refinery
(150,000 barrel per day topping and cracking) at an initial
investment of 0.37 million and an annual cost of $0.26 million
(1979 dollars) including interest and depreciation.
PS Option 2 - Establish two sets of pretreatment standards.
Provide Option 1 control for refineries that discharge to POTW
with existing or planned secondary treatment. Provide Option 1
controls plus biological treatment for refineries that discharge
to POTW that have a Section 301(h) waiver from secondary treatment.
Tables A-30 and A-31 combined contain the costs to implement
Option 2 (1977 dollars). Included in Table A-31 are costs for
the installation of in-plant control measures for those plants
whose wastewater flow exceeded the calculated BPT model flow.
These costs were obtained from the National Commission on Water
Quality (20).
Total cost of implementing Option 2 for existing refineries
could not be calculated for the 1979 proposal since no POTW had
been granted a Section 301(h) waiver at the time the cost estimates
were prepared. The Agency did estimate the cost of installing
biological treatment for each indirect discharge refinery.
These values are shown in Table A-31 for information purposes
only. If all indirect discharge refineries were required to
install biological treatment systems, the maximum cost to the
industry (obtained by summing cost to each refinery in Table A-
31 and indexing to a base year) would be an initial investment
of $110 million and an annual cost of $42 million (1979 dollars).
All refineries discharging to POTW having secondary treatment
were subject to the cost of providing Option 1 treatment shown
in Table A-30.
A-12
-------
PS Option 3 - Reduction of oil and grease and ammonia by oil/water
separation and steam stripping technologies is equivalent to the
existing pretreatment standard. Since indirect discharging
refineries are already required to provide treatment equivalent
to Option 3, implementation of Option 3 would incur no additional
cost to existing refineries.
A-13
-------
TABLE A-l
RAW WASTEWATER EQUALIZATION SYSTEMS
CAPITAL AND OPERATING COSTS
Capital Cost, Dollars
Description
Detention tank, 12 hours detention,
steel shell on concrete pad
Pumps, and associated controls,
installed
Subtotal
Piping, installed (15%)
Total Installed Cost
Engineering
Contingency
Total Capital Cost
Land Requirements, Ft
Pumping
Maintenance (3% of Capital Cost)
380 M3/day
(0.1 x 10°)
gal/day
$ 30,000
8,000
$ 38,000
5,700
$ 43,700
6,650
6.650
$ 57,000
585
$ 140
1.700
3800 M3/dpy 19
(1.0 x 10 )
gal/day
$
$
$
$
$
116,000
30,000
146,000
22,000
168,000
26,000
26,000
220,000
5,780
Annual
1,400
6,600
,000 M /day 38
(5 x ICT)
gal/day
$ 346,000
87,000
$ 433,000
65,000
$ 498,000
75,000
75,000
$ 648,000
28,200
Operating Costs
$ 7,000
19,500
,000 M /day
(10 x 10 )
gal/day
$ 595,000
149,000
$ 744,000
117,000
$ 861,000
129,500
129,500
$1,120,000
57,600
, Dollars
$ 14,000
33,600
76,000 M /day
(20 x 10 )
gal/day
$1,020,000
255,000
$1,275,000
192,000
$1,467,000
221,500
221,500
$1,910,000
113,000
$ 28,000
57,300
Total Annual Cost
$ 1,840
8,000
$ 26,500
47,600
85,300
Notet The Depreciation factor has been omitted from this analysis due to the fact that it will be included
separately in the Economic Impact Analysis Supplement.
-------
TABLE A-2
ROTATING BIOLOGICAL CONTACTORS (RBC's)
AS ROUGHING SYSTEMS
EQUIPMENT COST BASIS
AND ENERGY REQUIREMENTS
Equipment Size
Description
Design Percent Removal
of BOD
Number of Units
> Shaft Lengths, each
1
in Total Square Feet of Surface Area
Manpower Requirements, hours
Power Requirements, kwh/year
380 M /day
(0.1 x 10 )
gal/day
50
1
15
75,000
500
33,000
3800 M /day
(1.0 x 10°)
gal/day
50
6
20
630,000
Annual
750
294,000
19,000 M3/day 38,000 M3/day
(5 x 10°)
gal/day
50
24
25
3,200,000 6,
Operating and Energy
1,000
1,180,000 2,
(10 x 10")
gal/day
50
48
25
400,000
Requirements
1,500
360,000
76,000 M /day
(20 x 10 )
gal/day
50
96
25
12,800,000
2,000
4,720,000
-------
TABLE A-3
ROTATING BIOLOGICAL CONTACTORS (RBC's)
AS ROUGHING FILTERS
CAPITAL AND OPERATING COSTS
Capital Cost, Dollars
Description
RBC Units, Steel Shell,
Fiberglass Cover
Piping
Total Equipment Cost
Installation (50%)
Total Constructed Cost
Engi neering
Contingency
Total Capital Cost
Land Required, Ft
Power
Labor
Maintenance (3% of Total Capital Cost)
Total Annual Cost
380 M /day
(0.1 x 10 )
gal/day
$ 46,000
5,000
51,000
25,500
76,500
11,750
11,750
$100,000
420
$ 1,500
5,000
3,000
$ 9,500
3800 M /day
(1.0 x 10°)
gal/day
$340,000
35,000
375,000
187,500
562,500
84,750
84,750
$732,000
2,600
$ 12,000
7,500
22,000
$ 41,500
19,000 H /day 38,000 M /day
(5 x 10U)
gal/day
$1,590,000
160,000
1,750,000
875,000
2,625,000
397,500
397,500
$3,420,000
13,500
Annual Operating
$ 48,000
10,000
103,000
$ 161,000
(10 x 10")
gal/day
$3,170,000
317,000
3,487,000
1,744,000
5,231,000
784,500
784,500
$6,800,000
27,000
Costs*
$ 95,000
15,000
204,000
$ 314,000
76,000 M3/day
(20 x 10 )
gal/day
$6,340,000
634,000
6,974,000
3,487,000
10,461,000
1,569,500
1,569,500
$13,600,000
54,000
$ 190,000
20,000
408,000
$ 798,000
Notei The depreciation factor has been omitted from this analysis due to the fact that it will be included separately
in the Economic Impact Analysis Supplement.
-------
TABLE A-4
I
I-1
^3
FILTRATION
EQUIPMENT COST BASIS AND ENERGY REQUIREMENTS
Equipment Coat Basia
Description
Filter Description
(all units are
automatic and
air scoured)
Bed depth, ft.
Operation type
Media type
Pumping.
KHH/year
Labor,
Manhours/year
380 M3/ day
(0.1 X 106gal/day)
2 units
5* dia»., steel
4
Gravity
Dual Media
3,440
400
3800 M3/day
(1 X 10%al/day)
2 units
11* diam., steel
4
Gravity
Dual Media
Annual Operating
34,400
500
19,000 M3/day
(5 X 106gal/day)
1 unit. 4-35 'square
cells, concrete
4
Gravity
Dual Media
and Energy RequireMei
172,000
6OO
38,000 M3/day
(10 X 106gal/day
1 unit, 4-47 'square
cells, concrete
4
Gravity
Dual Media
its
344,OOO
700
76,000 N3/day
(20 X 106gal/day)
2 units, 47' square
cells, concrete
4
Gravity
Dual Media
688,000
BOO
-------
TABLE A-5
FILTRATION
CAPITAL AND OPERATING COSTS
Capital Cost, Dollars
Description
Filtration Units Installed
Interconnecting Piping, Installed
Pumps, Installed
Total Installed Cost
Engineering
I—1 Contingency
00 Total Capital Cost
Land Requirement, Ft
Pumping
Labor
Maintenance (3% of Capital Cost)
380 M3/day
(0.1 x 10 )
gal/day
$ 25,000
3,000
5,000
33,000
6,OOO
6,000
$ 48,000
200
$ 140
4,000
1,400
3800 H /day
(1.0 x 10 )
gal/day
$100,000
10,000
15,000
125,000
20,000
20,000
$165,000
700
Annual
$ 1,400
5,000
5,000
19,000 M3/day
(5 x 10°)
gal/day
$250,000
25,000
42,000
317,000
49,000
49,000
$415,000
5,000
Operating Cost,
$ 7,000
6,000
12,500
38,000 M /day
(10 x 10 )
gal/day
$350,000
35,000
60,000
451,000
69,500
69,500
$590,000
9,000
Dollars
$ 14,000
7,000
18,000
76,000 M3/day
(20 x 10 )
gal/day
$600,000
60,000
100,000
770,000
115,000
115,000
$1,000,000
18,000
$ 28,000
8,000
30,000
Total Annual Cost
$ 5,540
$ 11,400
$ 25,500
$ 39,000
66,000
Note: The Depreciation factor has been omitted from this analysis due to the fact that it will be included
separately in the Economic Impact Analysis Supplement.
-------
TABLE A-6
POWDERED ACTIVATED CARBON
EQUIPMENT COST BASIS
AND ENERGY REQUIREMENTS
80 ng/1 DOSAGE RATE
Squlpstent Size
Description
380 • 3/day
(0.1 x 10S
3800 • /day
(1.0 x UT)
gal/d
19.000 •3/dav
(5 x 10")
9al/d
38.000 B/day
(10 x KT)
gal/d
76. 000 • /day
(20 v 10 )
gal/d
Powdered Carbon Feed Tanks (2 each) 700 7.000 35.000 70.000 140.OOO
Capacity, gallons (Based on feed
concentration of one pound
carbon/gallon water)
Feed Rate pounds/day 67 670 3.350 6.700 13.400
Annual Operating and Energy Requirements
Manpower RequireeMnts, hours
Miscellaneous Power Require**
kWh/yr
nt*,
400
540
25.OOO 50,000
940
125.000
1,240
200,000
1.940
375.000
-------
TABLE A-7
POWDERED ACTIVATED CARBON
CAPITAL COSTS
80 mg/l DOSAGE RATE
I
KJ
O
Total Capital Cost
Capital Costa, Dollars
Description
Powdered Carbon Peed System
Piping
Total Equipment Cost
Installation (SOt)
Total Constructed Cost
Engineering
Contingency
380 * /day
(0.1 x l
-------
TABLE A-8
POWDERED ACTIVATED CARBON
ANNUAL OPERATING COSTS
BO mg/1 DOSAGE RATE
Annual Cost, Dollar*
Description
Carbon Nake-Up
Miscellaneous Power Requirements
Labor (flO/nanhour)
Maintenance (3% of total Capital Cost)
380* '/day
(0.1 x 10")
9«l/d
$ 7,400
1.000
4,000
1.000
3800»3/day
(1.0 * 10°)
«al/d
$74,000
2.000
5,400
2.000
19. 000 • /day
(5 x 10°)
9»l/d
$370,000
5,000
9,400
3.000
38.000m /day
(10 x 10*")
9al/d
$740.000
8,000
12.400
4.000
76,000 m /day
(20 x 10")
9«l/d
$1,480.000
15.000
19.400
6.600
Total Annual Colt $11,400 $83,400 $387,400 $764,400 $1.521,000
Motei
The depreciation (actor has been omitted from this analysis due to the fact that it will be included separately
in the Economic Impact Analysis Supplement.
-------
TABLE A-9
i
M
NJ
POMDBMCD ACTIVATED CARBON
COMPARISON OF OPERATING COSTS
CARBON REGENERATION VS. THROW-AWAY
80 B9/1 DOSAGE RATE
Regenerated
Item
Capital Cost
Carbon Make-Up
Furnace Power
Miscellaneous Power
Labor
Maintenance (3%)
(15%)
Depreciation (27%)
Total Annual Cost
Capital Cost
Carbon Make-up
Labor
Maintenance (3%)
Miscellaneous Power
Depreciation (27%)
Total Annual Cost
Cost for Sludge Dewatering
Annual Cost with Sludge Dewatering
Cost for Land Disposal
Annual Cost with Land Disposal
380 m /day
(0.1 * 10")
gal/d
$735.000
> 2.200
5,000
1,000
91.600
1,000
105,000
200.000
$405.800
$ 35.000
$ 7.400
4,000
1.000
1.000
9.500
$ 22.900
$ 20.000
$ 42.900
4.000
$ 46.900
3800 • /day
(1.0 x 10 J
gal/d
$1.000.OOO
$ 22.000
19,000
2.000
93,000
2,000
140,000
270.000
$ 548,000
$ 39.SOO
$ 74,000
5,400
2.000
2,000
17,600
$ 101,000
$ 76.000
$ 177,000
40.000
$ 217.000
19.000 • /day
(5 x 10°)
gal/d
$1.650.000
$ 110,000
44,000
5,000
97,000
3,000
233,000
446,000
$ 938,000
Non-Regenerated
$ 97.000
9 370,000
9.400
3.000
5,000
26.200
$ 413,600
$ 137,000
$ 550,000
200,000
$ 750,000
38.000 • /day
(10 x 10 )
gal/d
$2.300,000
$ 220.000
76.0OO
8,000
100,000
4.000
328.000
621.000
$1.357.000
$ 130,000
$ 740,000
12,400
4,000
8,000
35,100
$ 799,500
$ 226,000
$1,025,000
400,000
$1,425,000
76,000 • /day
(20 x 10 )
gal/d
$3,250,000
$ 440.000
132.000
• 15,000
108,000
6,600
455.000
878.000
$2,034,600
$ 215,000
$1,480.000
19,400
6.600
15.000
58,000
$1,579,000
$ 335,000
$1,914,000
800,000
$2,714,000
-------
TABLE A-10
POWDERED ACTIVATED CARBON
EQUIPMENT COST BASIS
AND ENERGY REQUIREMENTS
INCLUDING COSTS FOR SLUDGE DISPOSAL
80 mg/1 DOSAGE RATE
Equipment Size
Description
Powdered Carbon Feed Tanks (2 each)
Capacity, gallons (Based on feed
concentration of one pound
carbon/gallon water)
;> Feed Rate pounds/day
N)
oo Sludge handling and/or regeneration
system, Ibs/day dry solids
380 M3/day
(0.1 x 10 )
gal/day
700
67
290
3800 M3/day
(1.0 x 10 )
gal/day
7,000
670
2,900
19,000 M /day 38
(5 x 10L)
gal/day
35,000
3,350
14,600
Annual Operating and Energy
Carbon make-up Ibs/day
Furnace power requirements
Fuel, BTU/hr
Connected hp
67
N.A.
N.A.
670
N.A.
N.A.
3,350
N.A. 2
N.A.
,000 M3/day
(10 x 10 )
gal/day
70,000
6,700
29,000
Requirements
2,000
,500,000
100
76,000 M3/day
(20 x 10 )
gal/day
140,000
13,400
58,000
4,000
4,500,000
140
Manpower requirement, hours
400
540
940
10,OOO
10,700
-------
TABLE A-11
i
to
POWDERED ACTIVATED CARBON
CAPITAL COSTS
INCLUDING COSTS FOR SLUDGE DISPOSAL
80 ng/1 DOSAGE RATE
Capital Costs, Dollars
Description (P
Powdered Carbon Feed systesi
Solids Dewatering Systesi
Regenerated Carbon Acid Mash
Systea
Subtotal
Piping (10%)
Total Equipment Cost
Installation (50%)
Total Constructed Cost
Engineering
Contingency
Subtotal
Activated Carbon Regeneration
Syste* (Installed)
Contingency (For Utility
Hook-up, etc.)
Engineering for Carbon
Regeneration Systen
Total Capital Cost
Land Requirements, ft2
380 «3/«I
.IxlOgal/d) .
(10.000
—
10,000
1.000
11,000
5.500
16,500
9,000
8,000
35,000
—
135,000
100
3800 p3/d
(1.0x10 gal/d)
$30,000
—
30,000
3.000
33.000
16.500
49.500
10,000
10.000
69.500
—
(69,500
200
19,000 «3/d
(SxlO qal/d)
$45.000
~
45.000
49.500
24.800
74.300
11.350
11.350
97.000
~
$97,000
900
38,000 «3/d
(10x10 qal/d)
$60,000
397,000
40,000
497,000
546,700
273.400
820,100
119.950
119,950
1.O60.0OO
900.OOO
190.000
150.000
82.300.000
3.000
76.000 B3/d
(20x10 gal/d)
$100,000
585,000
60,000
745.000
74,500
819.500
410,000
1,229.500
185,250
185.250
1,600,000
1,200,000
250,000
200,000
$3,250,000
4,500
-------
TABLE A-12
PONDERED ACTIVATED CARBON
ANNUAL OPERATING COSTS
INCLUDING CREDIT FOR SLUDGE DISPOSAL
BO ng/1 DOSAGE RATE
Annual Cost, Dollars
Description
Carbon Make-Up
Furnace Power
Miscellaneous Power Requirements
Labor ($10/manhour)
I
Is-1 Sludge Disposal Credit
Maintenance
Total Annual Cost
380 M /day
(0.1 x 10 )
gal/day
$7,400
1,000
4,000
1,000
$13,400
3800 M3/day
(1.0 x 10°)
gal/day
$74,000
2,000
5,400
2,000
$ 83,400
19,000 M /day
(5 x 10 )
gal/day
$370,000
S.OOO
9,4OO
3,000
$387,000
38,000 M /day
(10 x 101*)
gal/day
$220,000
76,000
8,OOO
100,000
(-)400,000
332,000
$336,000
76,000 M /day
(20 x 10°)
gal/day
$440,000
132,000
15,000
108,000
(-) 800,000
461,600
$ 356,000
Note:
The depreciation factor has been omitted from this analysis due to the fact that it will be included separately
in the Economic Impact Analysis Supplement.
-------
TABLE A-13
POWDERED ACTIVATED CARBON
EQUIPMENT COST BASES AND ENERGY REQUIREMENTS
ISO mg/l DOSAGE RATE
Equipment Site
I
NJ
Description (0.
Powdarad Carbon Feed Tanks
(2 each) Capacity, gallons
(Based on feed concentration
of 1 Ib carbon/gal water)
Feed Rate Ib/d
Sludge Handling and/or
Regeneration System,
Ib/d dry solids
Carbon Make-Up Ib/d
(25% Make-up)
Furnace Power Requirements
Fuel. Btu/h
Connected hp
380 «j3/d
1x10 gal/d)
1,000
125
335
Annual
125
N.A.
N.A.
3800 «3/d
(1.0x10 gal/d)
10,000
1.250
3,350
Operating and Energy
1,250
N.A.
N.A.
19.000 B)3/d
(5x10 gal/d)
43.0OO
6,250
16,700
Requirements
6.250
N.A.
N.A.
38,000 »3/d
(10x10 gal/d)
87,000
12.500
33.500
12.500
N.A.
N.A.
76.000 B)3/d
(20x10 gal/d)
175.000
25,000
66,700
8,150
4,500.000
140
Manpower Requirements, hours
400
540
940.
1.240
10.700
-------
TABLE A-14
i
NJ
FOUDERED ACTIVATED CARBON
CAPITAL COSTS
ISO mg/1 DOSAGE HATE
Capital Costs. Dollar*
Description |0.
Powd«r*<1 Carbon Fe«d System
Solids Dewatering System
Regenerated Carbon Acid Hash
System
Subtotal
Piping (10*)
Total Equipment Cost
Installation (SOt)
Total Constructed Cost
Engineering
Contingency
Subtotal
Activated Carbon Regeneration
System (Installed)
Contingency (For Utility
Hook-up, etc.)
Engineering for Carbon
Regeneration System
Total Capital Cost
Land Requirements, ft
180 li'/d
1x10 aal/d)
$15.000
--
~
15,000
1.500
16.500
8.500
25.000
9.000
9.000
43,000
--
$ 43,000
100
3800 m3/d
(1.0x10 gal/d)
$45.000
—
«
45.000
4,500
49.500
24.500
74,000
13.000
13.000
100.000
f 100.000
800
19.000 mJ/d
(5x10 «al/d)
$65,000
—
~
65.000
6.500
71.500
35.500
107.000
16,500
16.500
140.000
—
$140.000
2,000
38, OOP mJ/d
(10x10 9al/d)
$90,000
—
^
90,000
9.000
99,000
49.500
148.500
22.250
22.250
193.000
—
$193.000
3.OOO
76, OOO 8>J/d
(20x10 aal/d)
$150,000
615,000
60.000
825,000
83.000
908,000
454.000
1,362.000
207.500
207.500
1.777,000
1,300,000
280.000
200.000
$3.557.000
4,500
-------
TABLE A-15
POWDERED ACTIVATED CARBON
ANNUAL OPERATING COSTS
150 ng/1 DOSAGE RATE
Annual Coat. Dollars
I
M
00
Description
Carbon Hake-Up
Furnace Power
Mlacallanaoua Power
Requirements
Labor ($10/man-hour)
Nalntananca
Total Annual Cost
380 |3/d
(0.1x10 gal/d)
$13.900
—
1,000.
4,000
1,000
» 19, 900
3800 «i3/d
(1.0x10 gal/d)
$139,000
. „
2,000
5,400
2.000
$148.400
19,000 «3/d
(5*10 gal/d)
$694.000
~
5.000
9,400
3.000
$711.400
38.000 »3/d
(10x10 gal/d)
$1,388.000
~
8,000
12.400
4.000
$1,412.400
76,000 »3/d
(20x10 gal/d)
$ 825.000
132.000
15.000
108,000
491,000
$1,571,000
NQt« i
Tha Depreciation factor has bean omitted from this analysis due to the fact that it will ba included separately
in the Economic Jspact Analysis Supplement.
-------
TABLE A-16
i
NJ
PACT
COWARISON OF OPERATING COST*
CARBON REGENERATION VS. THROW-AWAY
150 «g/l DOSAGE RATE
Regenerated
Description (0,
Capital Cost
Carbon Make-up
Furnace Power
Miscellaneous Power
Labor
Maintenance (3%)
(15%)
Depreciation (25%)
Total Annual Cost
380 «3/d
$743.000
4,130
5,000
1,000
91,600
1.000
105,000
200. OOP
$407,730
3800 B3/d
(1.0x10 gal/d)
$1.035.000
41.300
19.000
2,000
93.000
2,000
140,000
280.000
$577.300
19.000 »3/d
(SxlO qal/d)
$1.743,000
207,000
44,000
5,000
97,000
3,000
240,000
471.000
$1,067,000
38,000 n3/d
(10x10 gal/d)
$,2,463,000
413,000
76,000
8.000
100,000
4,000
343,000
$1,609,000
76,000 «3/d
(20x10 gal/d)
$3.557.000
825,000
132,000
15,000
108,000
6,000
485,000
961,000
$2,532,000
Non-Regenerated
Capital Cost
Carbon Make-up
Labor
Maintenance (3t)
Miscellaneous Power
Depreciation (27t)
Total Annual Cost
Cost for Sludge Dewatering
Annual Cost with Sludge
Dewatering
Cost for Land Disposal
$ 43,000
13.900
4,000
1,000
1,000
11.600
$ 11,500
25.000
$ 56,500
5,000
$100,000
139.000
5,400
2,000
2,000
27.000
$175,400
95.000
$270,400
50,000
$140,000
694,000
9,400
3,000
5,000
37.600
$749.200
171,000
$920,200
250.000
$193,000
1,388,000
12,400
4,000
8.000
52 , 100
$1,464,500
282.000
$1,746.500
500,000
$322,000
2,775,000
19,400
6.600
15,000
87.000
$2,903,000
419,000
$3,322,000
1.000,000
Annual Cost with Land
Disposal
* 61.500
$320.400
$1,170.200
$2.246.500
$4.322,000
-------
TABLE A-17
POWDERED ACTIVATED CAR13GN
EQUIPMENT COST BASES AND ENERGY REQUIREMENTS
INCLUDING COSTS FOR SLUDGE DISPOSAL
ISO B9/1 DOSAGE RATE
Equipment Sizo
I
U>
O
Description (0.
Powdered Carbon Feed Tanks
(2 each) Capacity, gallons
(Based on feed concentration
of 1 Ib carbon/gal water)
Feed Rate Ib/d
Sludge handling and/or
Regeneration System,
Ib/d dry solids
Carbon Make -Up Ib/d
(25% make-up)
Furnace Power Requirements
Fuel, Btu/h
Connected hp
380 m'/d
1x10 gal/d)
1,000
125
335
Annual
125
N.A.
N.A.
3800 m /d
(1.0x10 gal/d)
10,000
1,250
3,350
Operating and Energy
1,250
N.A.
N.A.
19,000 m /d
(5x10 gal/d)
43,000
6,250
16,700
Requirements
2.100
1,300.000
80
38.000 m'/d
(10x10 gal/d)
87.000
12,500
33,500
418
2,500,000
100
76,000 B /d
(20x10 gal/d)
175,000
25,000
66 , 7OO
8,350
4,500,OOO
140
Manpower Requirements, hours
400
540
9.700
10,000
10.700
-------
TABLE A-18
PONDERED ACTIVATED CARBON
CAPITAL COSTS
INCLUDING COSTS FOR SLUDGE DISPOSAL
150 ag/1 DOSAGE RATE
Capital Costs. Dollar*
Description (0.
Powdered Carbon Peed Systra
Solid* Dem te ring Syste>
Regenerated Carbon Acid Hash
System
Subtotal
Piping (104)
Total Equipment Cost
Installation (SO)
Total Constructed Cost
Engineering
Contingency
Subtotal
Activated Carbon Regeneration
System (Installed)
Contingency (For Utility
Hook-up, etc.)
Engineering for Carbon
Regeneration System
Total Capital Cost
Land Requircnents, ft
380 p3/d
1x10 gal/d)
(15,000
—
15,000
1,500
16,500
6,500
25,000
9,000
9,000
43,000
—
$43.000
100
3800 B3/d
(1.0x10 gal/d)
I 45,000
—
45,000
4,500
49,500
34,500
74,000
13,000
13,000
100,000
—
$100,000
000
19,000 B3/d
(5x10 gal/d)
$ 65.000
250.000
20.000
335.000
34.000
369,000
IBS. OOP
554,000
62.000
62.000
718.000
750.000
16O.OOO
115.000
$1,743.000
2,000
38.000 »3/d
(10x10 gal/d)
$ 90,000
415.000
40.000
545,000
55.000
602,000
300.000
900,000
131,500
131.500
1,163,000
950,000
200,000
150.000
$2,463,000
3,000
76,000 BJ/d
(20x10 gal/d)
$150.000
615,000
60.000
825,000
83. OOP
908,000
454.000
1.362.000
207.500
207,500
1.777.000
1.300.000
2 80,000
200.000
$3.557.000
4.500
-------
TABLE A-19
i
U>
NJ
POWDERED ACTIVATED CARBON
ANNUAL OPERATING COSTS
INCLUDING CREDIT FOR SLUDGE DISPOSAL
ISO mg/l DOSAGE RATE
Annual Cost. Dollars
Description
Carbon Make-up
Furnace Power
Miscellaneous Power
Requirement*
Labor ($10/Mn-hour|
Sludge Disposal Credit
Maintenance
Total Annual Cost
380 g3/d
(0. 1x10 qal/d)
$13,900
~
1,000
4,000
~
1.000
$19.900
3800 p3/d
(1.0x10 gal/d)
$139,000
—
2.000
5,400
—
2.000
$148,400
19,000 m3/d
(5x10 gal/d)
$207.000
55,000
5,000
97,000
(-) 250.000
243,000
$357,000
38,000 »3/d
(10x10 gal/d)
$413,000
95.000
8.000
100,000
(-1500.000
347.000
$463.000
76.000 m3/d
(20x10 gal/d)
$825.000
165,000
15.000
108.000
(-) 1,000, 000
491.000
$604.000
Mote i
The Depreciation factor ha* been oaltted Iron thla analysis due to the fact that it will be included separately
in the Economic Ispact Analysis Supplement
-------
TABLE A-20
Description
380 m3/day
(0.1x106 gal/d)
Granular Activated Carbon
Equipment Cost Basis
Energy Requirements
Equipment Size
19,000 m*7~~
£gu
and"
3800 ni3/day "l97op6 m37day 38,000 m3/day 76.000 m3/day
(l.OxlO6 gal/d) (SxlO6 gal/d) (JOxlO6 gal/d) (20x10° gal/d)
Activated Carbon Units
.3
Three-4'diam.
x 13' high
281
Carbon, ftj Total
Automatic Controls Included No
Furnace size, Ib/d N.A.
of carbon
Three-11' dlam.
x 18' high
2800
Yes
1250
Nine-12' diara. Fifteen-12' dlam. Thirty-12' dlam.
x 25' high x 30' high x 30' high
14.000 28.000 56,000
Yes
6,250
Yes
12.500
Yes
25,000
Carbon Make-up, Ib/d
(10% make-up)
Furnace Power Require-
ments
Fuel.Btu/hr
Connected hp
Pumping Power Require-
ments kWh/yr
Manpower Requirements,
hours
125
Annual Operating and Energy Requirements
12,5 625 1,250
2,500
N.A.
N.A.
11,400
2,100
500.000
40
114,000
9,800
800,000
50
570.000
10.500
1,500.000
60
1.140,000
11,500
2,800,000
80
2,280,000
12.500
-------
TABLE A-21
I
OJ
GRANULAR ACTIVATED CARBON
CAPITAL COSTS
Capital Coats, Dollars
Description
Activated Carbon Units
Pumping t Misc. Equip. (10\)
Piping (1O%)
Total Equipment Cost
Installation (50t)
Total Constructed Cost
Engineering
Contingency
Subtotal
Activated Carbon Regeneration
System (Installed)
Contingency (For utility hooK-
up, etc.)
Engineering for Carbon Regeneration
System
38O »3/day
(0.1 X10 )
gal/d
$50, OOO
5.OOO'
5,000
6O.OOO
30, OOO
90,000
40.0OO
20.0OO
150,000
3800 «3/day
(1.0 X10 )
yal/d
$325,000
32,500
32,500
390,000
195,000
585,000
85,000
80,000
75O,OOO
3OO,OOO
6O.OOO
50,000
19,000 JI3/d«
(5 X10 )
gal/d
$1,500,000
150,000
150,000
1,800,000
900,000
2.700.OOO
400,000
400,000
3,500,000
450,OOO
100,000
5O.OOO
y 38,000 " /day
(10 X10 )
gal/d
$2,600,000
260, OOO
260, OOO
3,120,000
1,560,000
4,680,OOO
710,000
710,000
6,1OO,OOO
600,000
12O.OOO
80,000
76, OOO »3/day
(20 XlO )
gal/d
$5,000,000
500,000
500,000
6,000,000
3,000,000
9,000,OOQ
1,350,000
1,350,000
11,700,000
750,000
15O.OOO
100,000
Total Capital Cost
$150,000
$1,160,000
$4,100,000
$6,920,000
$12,700,000
Land Requirements, ft
300
1,500
3,500
5,500
12.0OO
-------
TABLE A-2 2
URANULAR ACTIVATED CARBON
ANNUAL OPERATING COSTS
Annual Coats, Dollars
OJ
Description
Carbon Make-Op
Furnace Power
Pumping
*
Labor ($lO/manhour)
Maintenance (3% of total
Capital Cost)
Total Annual Cost
NOTE: The depreciation factor
380 u /day
(0.1 X106)
gal/day
528,000
50O
21.0OO
4,500
$54,000
3800 n3/da
(1.0 X106)
gal/day
$28,000
19,000
5.OOO
98,000
35,000
$185,000
has been omitted from this
y 19,000 m /day
(5 X106)
gal/day
$137,000
27,000
25,000
105,000
123,000
$417,000
analysis due to the
38,000 »3/day
(10 X106)
gal/day
$275,000
46,000
50,000
115,000
208, OOO
$694,000 $1
fact that it will
76, OOO » /day
(20 X106)
gal/day
$550,000
82,000
100,000
125,000
381,000
,238,000
be included
separately in the Economic Impact Analysis Supplement.
* The Manpower requirements were obtained from the "Process Pesign Manual for carbon Adsorption,"
Environmental Protection Agency Technology Transfer Series, October 1973. Labor includes operation,
maintenance, and laboratory personnel requirements.
-------
TABLE A-23
SUPPLEMENTAL ECONOMIC COST INFORMATION
CAPITAL AND OPERATING COSTS
FOR 10,000 GALLON PER DAY TREATMENT SYSTEMS
Capital Cost, Annual Operating Cost
Treatment System Dollars Dollars*
Equalization $ 12,000 $ 400
Rotating Biological 50,000 6,100
Contactors
Filtration 35,000 3,000
Powdered Activated 35,000 4,300
Carbon
Granular Carbon 60,000 10,000
A-36
-------
TABLE A-24
COOfclNG TOWER SLOWDOWN RATES
PETROLEUM REFINING INDUSTRY
(MILLION GALLONS PER DAY)
REFINERY
NUMBER
1
2
3
4
6
7
8
9
10
11
12
13
15
16
17
18
19
20
21
22
23
24
25
26
29
30
31
32
33
35
36
37
38
39
40
41
42
43
44
45
46
48
49
SO
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
70
71
72
73
74
76
77
79
80
81
82
83
84
85
87
88
89
90
91
92
93
94
95
SLOWDOWN
0.008
0.014
Unknown
Not App.
Not App.
0.03
Unknown
0.001
0.015
1.8
0.002
1.015
0.023
0'.069
0.005
0.021
0.0015
0.32
0.0113
0.011
Not App.
0.065
0.167
0.0745
0.33
0.033
0.01
0.84
0.11
Hot App.
0.0055
1.83
0.702
0.06
Unknown
1.01
0.012
0.55
Unknown.
0.817
0.145
0.141
0.17
0.0255
Not App.
Not App.
0.0355
Unknown
Not App.
0.65
6.3
0.269
0.237
0.85
1.4
1.025
0.299
1.0
0.944
Unknown
3.23
2.448
Unknown
0.095
0.022
0.138
0.157
0.826
0.198
Unknown
0.87
0.24
0.006
1.015
Unknown
2.539
Not App.
0.073
Unknown
0.007
0.0036
2.024
0.021
0.432
Unknown
SLOWDOWN
96
97
98
99
100
102
103
104
105
106
107
108
109
110
111
112
113
114
115
116
117
118
119
120
in
122
124
125
126
127
128
129
130
131
132
133
134
135
136
137
138
139
140
141
142
143
144
145
146
147
148
149
150
151
152
153
154
155
156
157
158
159
160
161
162
163
165
166
167
168
169
172
173
174
175
176
177
179
180
181
182
183
184
185
186
187
6.01
0.01
0.78
Not App.
Not App.
Unknown
0.01
2.59
Not App.
0.52
0.01
Unknown
0.185
Not App.
1.11
Unknown
0.109
0.12B
0.521
0.288
0.50
0.012
0.031
0.023
0.74
1.562
0.135
0.114
0.120
0.025
Not App.
0.066
Not App.
0.120
0.75
1.831
Unknown
Unknown
Unknown
Unknown
0.153
0.006
0.055
Unknown
0.11
Unknown
0.144
Unknown
Unknown
0.49
0.055
0.15
Not App.
1.50
1.78
3.806
0.050
0.098
0.564
0.925
0.067
0.066
0.042
1.129
0.356
0.-642
0.16S
0.025
1.189
0.62
1.659
0.149
Unknown
Not App.
4.36
0.0026
0.014
0.149
0.386
5.219
1.858
0.341
0.521
0.322
0.516
0.983
A- 37
NUMBER
188
189
190
191
192
193
194
195
196
197
199
200
201
202
203
204
205
206
207
208
209
210
211
212
213
214
2X5
216
218
219
220
221
222
224
225
.226
227
228
229
230
231
232
233
234
235
236
237
238
239
240
241
242
243
244
245
246
247
246
249
250
251
252
253
254
255
256
257
258
259
260
261
264
265
266
278
291
292
295
296
298
302
303
305
307
308
309
SLOWDOWN
1.01
Unknown
0.01
0.485
0.01
Unknown
2.99
Unknown
3.51
0.001
0.01
0.4
0.48
Unknown
2.035
1.536
0.6911
2.5
0.037
0.86
0.095
0.015
0.279
0.374
0.013
Unknown
Unknown
2.42
Unknown
0.565
0.012
Unknown
0.20
0.711
Unknown
0.389
0.122
0.009
0.37
Hot App.
Unknown
0.307
Unknown
0.23
0.00
0.0015
0.325
Daknown
0.072
0.11
0.305
0.125
0.0315
0.153
0.0425
0.1166
Unknown
0.015
Unknown
Not App.
0.0015
Unknown
Unknown
Unknown
0.0008
Hot App.
0.634
Not App.
Hot App.
0.20
Unknown
0.259
Not App.
Unknown
0.00126
Not App.
0.158
Not App.
Unknown
Not App.
Unknown
0.010
Unknown
Unknown
0.302
-------
I
(jO
CO
TABLE A-25
Chromium Removal Systems
Equipment Cost Basis and Energy Requirements
Description
Detention Tank, gallons
Mixer, hp
Mixing Requirements , Mh/yr
3.8,m3/day
(1x10 gal/d)
32
0.25
1.650
Solids Contact Clarifier, diaro. 8
S02 Feed Rate. lb/d
Acid Feed Rate, lb/d
Caustic Feed Rate, lb/d
Pumping Requirements, kWh/yr
Manpower Requirements, h/yr
0.4
0.2
2
23
520
38 j3/day
(1x10 gal/d)
320
0.25
1.650
8
4
2
20
230
520
380,M3/day
(IxlCT gal/d)
3.200
1.5
9.900
15
40
20
200
2,300
520
3800 m3/day
(IxlO6 gal/d)..
32.000
15
99.000
45
400
200
2.000
23.000
1.040
19,000 m3/day
(5x10° gal/d)
160.000
80
528,000
100
2.000
1,000
10,000
115.000
2.080
-------
TABLE A-26
u>
VD
Description
(IxJO3 gal/day)
Chromium Removal Systems
Capital and Operating Costs
Capital Costs. Dollars
38.m3/day 380,m3/day 3800 m3/day 19.000 m3/day
(1x10* gal/day) (IxlO3 gal/day) (1x10° gal/day) (5x10° gal/day)
Detention Tank
Chemical Feed Systems
Automatic Controls
Solids Contact Clarifler
Pumps
Total Equipment Cost
Installation (SOX)
Total Constructed Cost
Engineering
Contingency
Total Capital Cost
SO
Acfd
Caustic
Mixing
Pumping
Labor
Maintenance (31 of
Total Capital Cost)
$ 100
5,000
--
25.000
30,100
15,000
45.100
6.950
6,950
$59,000
* 16
4
130
70
Negligable
5.200
1.780
V 1,000
15.000
10,000
25.000
51,000
25.500
76.500
11.750
11,750
$100.000
Annual
$ 160
40
1.300
70
10
5,200
3,000
$ 5,000
30.000
10,000
35.000
80.000
40,000
120.000
17.500
17.500
$155.000
Operating Costs.
$ 1,600
400
13,000
400
100
5,200
4,800
$20,000
40.000
10,000
80,000
150,000
75,000
225,000
37.500
37,500
$300,000
Dollars*
$ 16.000
4,000
130.000
4,000
1,000
10,000
9,000
$50.000
45,000
10.000
155,000
260.000
130,000
390,000
60,000
60,000
$510.000
$ 80.000
20,000
620,000
21.000
5,000
20,000
16,000
Total Annual Cost
$ 7.200
$ 9.780
$ 25,500
$174,000
$782.000
*Hote: The depreciation factor has been omitted from this analysis due to the fact that It will be included
separately in the Economic Impact Analysis Supplement,
-------
TABLE A-27
Description
Uastewater Recycle - Capital and Operating Costs
Capital Costs. Dollars - Per Mile
2.3 m3/hr 16 m3/hr 80 m3/hr 160 m3/hr 320 m3/hr 800 m3/hr
(10 qpm) (70 qpm) (350 qpm) (700 gpm) (1400 qpm) (3500 gpm)
Piping:
Piping,installed,per mile
M1sc. Costs (15%)
Total Constructed cost,
per mile
Engineering (15%)
Contingency
Piping-total capital costs
per mile
$32,000 $53,000 $100,000 $135,000 $175,000 $243,000
5.000 8.000 15.000 20.000 26.000 36,000
37,000 61,000 115,000 155,000 201,000 279,000
6,000 9,000 18,000 23,000 30,000 42,000
7.000 10.000 17.000 22.000 29.000 42.000
$50,000 $80,000 $150,000 $200,000 $260,000 $363,000
Pumps:
Pumps and associated
equipment instated (10*
of piping cost)
5,000 8,000 15,000 20,000 26,000 37,000
Total capital costs per mile $55,000 $88,000 $165,000 $220,000 $286,000 $400,000
(Minimum pumping costs
regardless of distance)
5,000 6,000 12,000 18,000 24,000 40,000
Pumping costs per mile,
per year
Maintenance (V.5% of capital
costs) per mile,per year
Annual Operating Costs, Dollars - Per flile
$100 $ 700 $2600 $4500 $ 9200 $24,300
800 1300 2500 3300 4300 6,000
Total Annual operating cost
$900 $2000
$5100 $7800 $13,500 $30,300
Note: The Depreciation factor has been omitted from this analysis due to the fact that
it will be included separately in the Economic Input Analysis Supplement.
A-40
-------
TABLE A-28
Water Softening of Recycled Uastewater
Canital flnst.s
Capital Costs, Dollars
Description
Solids Contact Clarifier
(Diameter, ft)
2.3 m3/hr
(10 gprn)
$ 25,000
(8)
16 m3/hr
(70 apm)
$ 30,000
(ID
80 m3/hr
(350 gpm)
$ 45,000
(23)
160 m3/hr
(700 qpm)
$ 65,000
(32)
320 m3/hr
(1400 qpm)
$ 80,000
(45)
800 m3/hr
(3500 qpm)
$125,000
(72)
Chemical Feed System(s)
Total Capital Costs
5,000
7,000 10,000 15,000 25,000
50,000
Filter Unit
(Diameter, ft)
Subtotal
Auxiliary Equipment
Total Capital Cost
Installation(50%)
Total Constructed Cost
Engineering
Contingency
15,000
(3)
45,000
5,000
50,000
25,000
75,000
15,000
15,000
25,000
(8)
62,000
8,000
70,000
35,000
105,000
20,000
20,000
30,000
(11)
85,000
10,000
95,000
50,000
145,000
25,000
25,000
40,000
(15)
120,000
15,000
135,000
70,000
205,000
30,000
30,000
80,000
(two-151
units)
185,000
20,000
205,000
100,000
305,000
45,000
45,000
150,000
(three-201
units)
325,000
35,000
360,000
180,000
540,000
80,000
80,000
$105,000 $145,000 $195,000 $265,000 $395,000 $700,000
A-41
-------
1 of 5
TABLE A-2 9
CAPITAL AND OPERATING COSTS 3Y REFINERY NUMBER
REFINERY
5TUMBER
1
2
3
6
7
9
10
11
12
13
19
20
24
30
32
37
38
40
41
43
46
49
50
51
52
53
54
56
57
59
60
61
62
63
64
65
67
63
70
OPTION
CAPITAL
COSTS
131.000
76.000
50.000
36,000
70.000
15.000
70,000
179,000
145,000
No coat -
No coat -
200.000
73,000
325.000
750,000
610,000
No co*t -
935,000
550.000
300,000
338,000
110,000
130.000
1.420,000
166,000
65,000
53,000
645,000
1,280,000
385,000
0
650,000
400,000
250,000
485,000
720,000
4,510,000
1,335,000
190,000
ECONOMIC COSTS. DOLLARS
I
ANNUAL OPERATING
COSTS
3,600
5,900
4,700
6.700
5.600
3.200
5,600
6,500
5,200
considered presently indirect
insignificant flow.
15.000
6.900
19,300
29.300
32.300
considered presently indirect
47.300
37.500
17.300
17.500
7,800
6.600
606.000
10.100
2.200
4.000
35.300
121.000
19,100
0-
33,300
24,500
13.000
32,500
47,600
360,000
38.000
10,700
OPTION 2.
CAPITAL
COSTS
131.000
126,000
35,000
171.000
140,000
67.000
140 , 000
233.000
536,000
discharger only.
275,000
313, OCO
375,000
4.750.000
2,210,000
discharger only
1,060,000
6.950,000
2,400,000
398,000
230,000
745,000
3.690,000
406.000
100.000
38.000
1.550,000
1.380.000
460 , 000
75,000
730,000
500,000
2.150,000
560,000
320,000
7.760,000
1,490,000
225,000
3
ANNUAL OPERATING
COSTS
30.100
14.900
9,700
14,700
12,600
9.400
12,600
73,500
32,200
165,000
22.900
43 , 300
122,000
117,000
558,000
323.000
120.000
90.500
17.300
40,600
942.000
26.100
20.200
15.000
33.300
683 , 000
104,000
145,000
238.000
397,000
103.000
225,000
330.000
720,000
464,000
28 , 700
A-42
-------
TABLE A-29
CAPITAL AND OPERATING COSTS BY
2 of 5
REFINERY
HUMBES
71
72
73
74
76
77
30
31
33
34
35
37
38
39
90
91
92
93
94
96
97
98
99
100
102
103
104
105
106
107
108
109
110
112
113
114
115
116
117
ECONOMIC COSTS. DOLLARS
OPTICS i
CAPITAL
COSTS
145.000
50,000
So cost -
72.000
380 , 000
70.000
91.000
270.000
210,000
520.000
300.000
220.000
60.000
79.000
58,000
45,000
1.630.000
51,000
428.000
600,000
35,000
650,000
45,000
30,000
230,000
48,000
500,000
305,000
200,000
HO coet -
70,000
145.000
So cost -
295,000
90,000
So cost -
0
400,000
677,000
ANNUAL OPERATING
COSTS
9,300
5,700
OPTION
CAPITAL
COSTS
345,000
35,000
2.3
ANNUAL OPERATING
COSTS
24.300
22,700
considered presently indirect discharger only.
2,500
26,400 1.
6,700
6,300
21,100 1.
17,000
25,400
22.000
15,400
6,200
6,100
4.700
3,400
78.100 4.
4.000
27.400
44,300 3,
6.500
30.300 2.
5.000
1.100
13,600
6,100
28,000 4,
22,200
13,000 1.
will discharge to POTW in future.
5,400
9.300
will discharge to POTW in future.
184,000
7.300
will discharge to POTW in future.
0
21.000 1.
25.300 1,
242.000
630,000
110.000
181,000
150,000
295,000
595.000
295,000
315.000
235.000
156.000
118.000
30,000
0 1C. 000
86,000
503,000
080,000
120.000
250.000
128.000
65.000
305.000
157.000
600.000
380.000
300,000
105,000
185,000
465.000
420 , 000
90,000
300.000
270.000
15,500
92,400
34,700
15,300
69,100
209,000
164,000
286.000
24,400
19.200
15.100
11.700
7,400
415.000
10.000
172.000
387,000
17.500
111.000
13,000
10,600
32.600
14,100
208.000
203,000
73,000
13,400
119.000
31,400
28.300
216,000
69,000
59,300
A-43
-------
TABLE A-29 3 of 5
CAPITAL AND OPERATING COSTS 3Y aSTINERY NUMBER
REFINERY
NUMBER
1X3
119
120
121
122
124
12S
126
127
129
131
132
133
134
142
143
144
146
147
149
150
151
152
133
154
155
156
157
158
159
160
161
162
163
165
167
163
169
172
173
OPTION
CAPITAL
COSTS
20,000
60.000
55,000
1,000.000
1.320.000
220.000
210,000
760,000
126,000
221.000
300.000
740,000
1.560.000
940.000
Bo cost - vill
No eo«t - will
110.000
220,000
109.000
570,000
372,000
1.230,000
1,530.000
0
310.000
95,000
115.000
580,000
243,000
158.000
56.000
30.000
220.000
165.000
162.000
1.680.000
0
2.220.000
320.000
255.000
r
ANNUAL OPERATING
COSTS
900
2.000
1,300
47,500
115.000
12,400
12.000
54,500
3.400
15,600
17,500
108,000
172.000
56,500
di.«ch»rg« to POTW
disch»rg« to POTW
7,700
15.300
3,700
31,700
18.900
62.000
155.000
0
19.400
7.000
9.000
23,500
13.400
10.200
6.500
7.200
17.000
11.400
10.000
111,000
0
172.000
24,000
17,700
A-44
OPTION
CAPITAL
COSTS
75,000
175.000
155,000
4.100.000
5,720,000
535.000
550.000
5.160,000
276,000
521.000
390.000
3,070,000
1.690.000
1.040,000
la fatux*.
in futuz*.
223,000
315,000
149,000
1.370.000
424.000
3.930.000
1,650.000
100,000
1.010,000
190,000
S90.000
655,000
283,000
333.000
91.000
355,000
295.000
365,000
396,000
1,780,000
30,000
2, 3
-------
TABLE A-29
4 of 5
CAPITAL AHD OPERATING COSTS 3Y REFINERY HUMBER
REFINERY
NUMBER
174
175
176
177
179
ISO
131
183
184
186
189
190
194
196
197
199
201
204
203
208
210
211
21?
213
216
219
221
222
226
227
230
231
232
233
234
235
236
237
238
ECONOMIC COSTS.
OPT! OH 1
CAPITAL
COSTS
244,000
Ho cost -
185.000
485,000
158,000
565.000
980,000
106,000
150,000
580.000
50.000
38.000
2.870,000
2,230,000
35.000
155.000
209,000
268,000
890.000
420.000
35,000
0
0
71,000
1.000.000
0
600,000
235.000
63.000
0
125.000
Mo coat -
0
385.000
385,000
400,000
100,000
55.000
793,000
ANNUAL OPERATING
COSTS
16,900
will diacharg* to POTW in
11.000
28.500
9,800
46.100
106,000
8.500
12.000
26,500
3,700
3,800
154,000
255,000
3,000
9,500
7,700
18.700
43.400
25.000
3,200
0
0
5,700
€6.800
0
423,000
17.000
5.000
0
9,400
will discharge to POTW in
0
19,400
19.400
24,000
7,100
4,500
45,100
A-45
D Of, TARS
OPTION 2 ,
CAPITAL
COSTS
674,000
fucura.
470,000
535,000
383,000
640.000
3,540,000
526.000
225,000
655.000
103.000
60,000
12.200.000
5.330,000
85.000
227.000
269,000
358.000
2.590.000
520.000
70,000
60.000
50,000
144,000
4.250,000
350,000
690,000
510,000
128,000
60 , 000
645,000
future.
60,000
445,000
445.000
475.000
135,000
90.000
368,000
3
ANNUAL OPERATING
COSTS
42,900
30.000
93 , 500
25.600
263.000
448.000
33,400
112.000
171.500
9.900
6.400
650,000
611,000
9.000
16,500
87,700
283 , 000
133,000
415,000
3,200
69,000
61,000
12,700
424,000
48,000
301.000
35,000
12,000
96,000
40 , 400
90,000
103,400
103,400
144,000
20,100
10,500
196.000
-------
TABLE A-29
5 of 5
REFINERY
SUMBER
239
240
241
242
243
252
235
256
2S7
238
239
260
261
265
266
292
293
309
ECONOMIC COSTS. DOLLARS
OPTICS i OPTICS
CAPITAL
COSTS
110,000
145.000
205,000
70,000
55,000
110.000
60,000
30,000
590,000
165,000
590.000
58,000
335,000
248,000
410,000
So coat -
315,000
425,000
ANNUAL OPERATING
COSTS
7.700
9.100
11,300
6.700
6,000
7,700
2.000
7",300
29,000
11,400
29.300
4.400
22,100
13.700
23.200
inaigniiicant Slow.
20.100
59, 100
CAPITAL
COSTS
145.000
135.000
250,000
110,000
200,000
225,000
175,000
365.000
1.990.000
225,000
665.000
.116.000
433,000
296.000
470. '000
355.000
470.000
2 ,3
ANNUAL OPERATING
COSTS
24.200
33 . 600
51.800
34.700
17.500
17,700
12.000
26,300
101.000
95,400
198.000
10.700
261.000
64,700
81.200
45.100
99. 100
A-46
-------
TABLE A-30
Page 1 of 3
CAPITAL AND OPERATING COSTS
INDIRECT DISCHARGE - OPTION I
Cooling
Refinery Tower
Code Slowdown
No. gal/day
8
13
14
16
18
21
23
25
29
31
33
38
45
58
73
1,250*«
1,O20,OOO
7,700
69, 300
21,500
11,300
Does Not
167,000
325,000
10,000
J 10, OOO
702,000
817,000
269,000
139,000
ChroBiiw Removal, $ Piping Coat, $
Capital Annual Capital Annual
Cost operating Cose Cost Operating Coat
63,000
300,000
94,000
143,000
115,000
102,000
Have Cooling
172,000
207,000
100.OOO
156,000
265,000
280,000
194,000
165,000
7,300 « «
17L,, OOO 320,000 11,000
8,000 20,000 400
20,OOO 45,000 900
12,500 30, OOO 4OO
10,OOO * •
Tower +
40,000 60,000 1,600
70,000 ISO, OOO 4,200
9,800 * *
28, OOO 5u,OuO 1.10U
130,000 160,000 5,000
150,000 200,000 6,500
60.0OO 90,OOO 2,500
35.OOO 60, OOO 1,300
Total Cost, $
Capital Annual
cost Operating Cost
63,000
620,000
114, OOO
188,000
145.0OO
102,000
232,000
357.OOO
lOu.OOO
2O6 , OOO
425,000
480,000
284,000
225.0OO
7,300
186,000
8,400
20,900
12,900
10,000
41,600
74,200
9,800
29,1OO
135,000
157,000
62,500
36,300
-------
Page 2 of 3
TABLE A-30
Cooling
Refinery Tower Chromium Removal, § Piping Cost, $ Total Cost, $
Code Blowdown Capital Annual Capital Annual Capital Annual
No. gal/day Cost Operating Cost Cost Operating Cost Cost Operating Cost
78
79
86
107
110
111
' 114
iP>
°°
130
142
143
145
148
166
175
182
188
15,000 108,000 10,000 35,000 500 143,000
No Cost - Unknown Flow
148,000 166,000 35,000 45.0OO 1,100 211,000
10,000 100,000 10,000 « * 100,000
No Cooling Tower +
1,110,000 310,000 188,000 160,000 5,600 470,000
Non Chromium Treatment -*•+
No Cooling Tower +
No Cooling Tower +
110,000 156,000 28,000 60.0OO 1,400 216,000
Non Chromium Treatment t+
1,000«* 59,000 7,200 * * 59,000
Non Chromium Treatment + +
25,000 118,000 12,000 « * 118,000
4,360,000 487,000 628,000 405,000 34,200 972,000
1,860,000 370,000 285,000 630,000 28,700 1,OOO,000
l,010,uOO 300,000 175,000 200,000 7,000 500,000
10,500
36,100
10,000
194,000
29,400
7,200
12,000
662,000
314,000
182,000
-------
TABLE A-30
Page 3 of 3
Cooliny
Refinery Tower
Code Blowdown
No. gal/day
V£>
Chromium Removal, $
Capital Annual
Cost Operating Cost
Piping Cost, $
Capital Annual
Cost Operating Cost
Total Cost. S
Capital Annual
Cost Operating Coat
193
195
20O
203
206
207
220
224
225
228
229
231
264
291
305
TOTAL
130"
59,OOO 7,200 « *
59.OOO 7,200
No Cooling Tower +
395,000
2,040,000
2,OOO
36,500
Non Chromi
Non Chrowi
Non Chromi
122.OOO
8,500
No Cooling
No Cooling
126,000
11,600"
5
220,000 80,000 65,000 2,000
382,000 308, OOO 680,000 31,800
70,000 8,000 * *
126. OOO 15,000 40,000 700
uw Treatment ++
urn Treatment ++
uw Treatment ++
166,000 30.0OO 50,000 1,000
98/000 9,400 • *
Towers +
Tower a +
162,000 30,000 40,000 BOO
103, OOO 11,300 * *
,916. OOO 2, 633, OOO J, 675, OOO ISO, OOO
285,000 82,000
1,062,000 340,000
70,000 8,000
166,000 15,700
216,000 31,000
98,000 9,400
2O2.OOO 30.8OO
103,000 11,300
9,591,000 2, 783, OOO
NOTE: * These Refineries have only one cooling tower and so piping coat is excluded.
** Actual Cooling Tower blowdown data were not availablej the blowdown rate is assumed to be
25% of total wastewater generated.
+ These Refineries do not have any cooling towers.
+t These Refineries do not use Chromium in the cooling towers.
-------
Page 1 of 2
TABLE A-31
CAPITAL AMD OPERATING COSTS
INDIRECT DISCHARGE - OPTION 2
Mfinary
Cod* NO.
8
13
14
16
13
21
23
25
29
31
33
38
45
58
73
78
79
36
107
110
111
114
128
130
Capital
Co«M, S
No Cost
5,800,000
315,000
826,000
495,000
373,000
315,000
375,000
4,650,000
247,000
1,090,000
4,350,000
3,900,000
1,900,000
915,000
1,390,000
NO Cost
300, JOO
255,000
250,000
2,450,000
683,000
277,000
1,310,000
Annual Operating
Costs, $
- Insignificant Flow
626,000
51,400
136,000
58,000
62,500
60,200
54,500
521,000
54,700
152,000
455,000
419 , 000
159,000
34 , 100
119,000
- Unknown Flow
104,000
57 , 900
56 , 700
211,000
103,000
29,700
421,000
A-50
-------
TABLE A-31
Page 2 of 2
Refinery
Cod* NO.
142
143
145
148
166
175
1S2
188
193
195
200
203
206
207
220
224
225
228
229
231
264
291
305
Capital
Costs , $
2,450,000
2,190,000
247,000
493,000
273,000
13,300,000
7,000,000
3,660,000
247,000
247,000
1,150,000
13,300,000
437,000
375,000
258,000
655,000
2,220,000
710,000
242,000
1,110,000
250,000
250,000
277 , 000
Annual Operating
Costs, S
211,000
174,000
54,700
111,000
96,900
2,360,000
781,000
340 , 000
54 , 700
54,700
106,000
1,510,000
95,800
92,500
56,700
112,000
177 , 000
112 , 000
25 , 400
378,000
55,500
51,200
29,700
A-51
-------
APPENDIX B
RAW PLANT DATA
The purpose of this appendix is to present the raw analytical
results for both the 17 refineries' screening program, and
the pretreatment program. (It should be noted that the
"screening program1 is referred to in this appendix as the
RSKERL and B&R sampling program). These results are presented
in Tables B-l through B-16, which follow.
Tables B-l through B-6 contain the analytical results for
the 17 direct discharge refineries.
Tables B-7 through B-ll include results from the first week
of sampling for the pretreatment program. These tables
report pollutant characteristics for wastewater leaving
Refinery No. 25 and at various points in the treatment train
of the first POTW.
Tables B-12 through B-16 contain the analytical results from
the second week of the pretreatment program. Included in
these tables are effluent characteristics for Refinery Nos.
13, 16, 21, 43, and 45, as well as the wastewater pollutant
characteristics at various stages in the treatment train of
the second POTW.
-------
TABLE B-l
Page 1 of 7
Analytical Usenlts tot Traditional Parameters tot the K3KEM. and BtR Saaplina Prcxirasi
Sasole - DOT
tannery A
Intake - 1
Intake - 2
Intake - 3
Separator effluent - 1
Separator effluent - 2
Separator effluent - 3
Final effluent - 1
Final effluent - 2
Final effluent - 3
Refinery B
Intake - 1
Intake - 2
£0 Intake - 3
| DAT effluent - 1
NJ DAP effluent - 2
OAF effluent - 3
Final effluent - 1
Final effluent - 2
Final effluent - 3
Refinery c
Intake - 1
Intake - 2
Intake - 3
Separator effluent - 1
Separator effluent - 2
Separator effluent - 3
Treated effluent - 1
Treated effluent - 2
Treated effluent - 3
Final effluent - 1
Final effluent - 2
Final effluent - 3
BStl
L2
U
2
20
20
2S
L2
L2
3
L3
L3
2
130
170
270
IS
9
30
2
L3
2
ISO
160
78
28
34
4O
37
40
45
BOD-2 BOD-3 COD
L2 4
U 4
4 •
24 130
18 91
10 99
L2 36
L2 40
2 28
U 9
U 9
L3 9
140 420
110 440
220 500
14 ISO
7 120
7 120
1
1
2
110 380
120 370
as 220
130
120
120
130
130
100
TOC
1
2
2
36
25
26
ii
11
11
11
25
18
100
110
110
47
39
43
12
a
s
88
75
49
44
39
41
42
37
36
TBS
S
4
Ll
49O
39O
260
44
30
42
9
13
11
38
SO
38
22
24
20
Ll
Ll
Ll
22
36
26
2O
18
28
2O
22
16
Sl3
Ll.O
11
1.0
13
11
11
16
11
9.0
Ll.O
Ll.O
Ll.O
8.4
7.3
6.7
18
16
IB
Ll.O
Ll.O
Ll.O
52
SO
13
8.4
S.6
4.5
7.8
17
3.9
+6
CE
L.02
L.O2
L.02
.09
.03
.OS
.04
L.O2
L.02
L.O2
.02
L.O2
L.02
.10
L.02
L.02
L.O2
L.02
L.02
L.02
L.02
.OS
L.O2
L.O2
L.O2
L.02
L.02
L.O2
L.02
L.O2
s-2
L.I
L.I
.2
9.0
6.9
8.5
.2
.2
.4
.2
.2
.4
.6
1.0
1.2
.5
.5
.6
L.S
L.S
.3
L.S
3.8
.3
L.S
L.S
.2
.5
.5
.4
ota
19
7
6
33
18
11
53
24
IS
8
10
4
150
1OO
28
a
15
11
7
11
11
Flow (MOD)
7.6
9.0
8.8
8.6
8.5
9.0
6.9
7.4
7.O
B.2
8.]
*.3
S.2
a.e
».S
7.2
».6
7.4
7.6
7.8
7.4
8.6
9.1
8.7
7.8
7.7
7.6
8.0
8.1
7.6
.433
.427
.432
3.91
3.86
.12
.78
.81
.81
.69
.07
.48
.0715
.0848
.1526
.1787
.1411
.2357
Notei L - Less than
G - Greater than
BOD-1 Indicate* analytical Method used aeed fra* a domestic sewage treatment plant.
BOO-2 Indicates analytical method used seed fron refinery final effluent.
BOD-3 Indicates analytical method where no seed was used.
-------
TABLE B-1
Analytical Result* for Traditional Parameters for the BSKERL and BtR Sampling Program
Page 2 of 7
Concentration (•£/!)
Sanpla - n.»
w
1
1
U)
Refinery D
Intake - 1
Intake - 2
Intake - 3
DAF effluent -
DAF effluent -
DAF effluent -
Final effluent
Final effluent
Final effluent
Refinery B
Intake - 1
Intake - 2
Intake - 3
DAF effluent -
DAF effluent -
DAF effluent -
Final effluent
Final effluent
Final effluent
Refinery F
Intake - 1
Intake - 2
Intake - 3
1
2
3
- 1
- 2
- 3
1
2
3
- 1
- 2
- 3
Cooling tower blowdown-1
Cooling tower blowdown-2
Cooling tower blowdown-3
Final effluent
Final effluent
Final effluent
- 1
- t
- 3
BCO-1
LS
1
3
160
140
12O
SO
210
150
3
2
2
54
52
45
18
2
LI
4O
40
42
25
130
47
18
36
20
SfiP-J
20
4
6
L220
L360
4
3
3
56
41
44
SO
52
42
G160
36
BOD-j COD
20
4
4
1OOO
500
390
40 820
62 670
9O 49O
43
59
39
160
160
ISO
18 47
U 75
U 55
340
350
35 340
210
300
350
10 260
36 270
18 260
TOC
1O
5
a
3OO
150
100
290
220
150
IS
IS
IS
48
42
39
1O
7
13
96
110
97
62
78
95
110
75
82
at
24
32
16
60
36
32
64
6O
6O
14
19
28
17
13
16
9
20
13
68
68
40
64
76
80
110
96
100
Slj
Ll.O
2.2
2.O
36
29
4O
36
42
39
1.0
7.8
7.8
13
1}
IS
35
11
13
1.7
68
63
3.9
10
19
3.9
2.8
3.9
«*"
L.02
L.02
L.02
L.O2
L.O2
L.O2
L.02
L.O2
.03
L.O2
L.02
L.O2
L.O2
L.OJ
L.02
L.O2
L.02
L.02
L.02
.02
L.02
.05
.09
.41
L.02
L.02
.03
£-* 1
L.I
L.I
L.I
15
18
15
1.7
1.1
.8
L.I
L.I
L.I
1.8
l.S
1.5
.3
.5
.6
1.6
.9
.7
1.0
L.I
2.0
L.I
OSG ug Flow (USD)
7.3
7.4
7.3
8.9 .932*
8.5
8.6
7.7 .932*
7.7
7.6
7.7 18.00
7.6 16.56
7.5 18.00
7.3
7.1
7.2
7.6 5.02
7.5 4.59
7.5 4.61
8.2 1.5*
8.1
8.0
7.3 0.17*
8.1
6.8
8.6 0.017*
8.5
8.6
* Average flow during 72-hour campling period.
-------
TABLE B-l
Page 3 of 7
Sample-Day
Refinery 6
Intake - 1
Intake - 2
Intake - 3
Separator effluent - 1
Separator effluent - 2
Separator effluent - 3
DAF effluent - 1
DAT effluent - 2
mr effluent - 3
final effluent - 1
rinal effluent - 2
Final effluent - 3
•efinery R
Intake - 1
Intake - 2
(JO Intake - 3
I Separator effluent - 1
*"• Separator effluent - 2
Separator effluent - 3
Final effluent - 1
Final effluent - 2
Final effluent - ]
Deflnery I
Intake - 1
Intake - 2
Intake - 1
Separator effluent - 1
Separator effluent - 1
Separator effluent - 3
Mnal efflnent-1
Final affluent-}
Final efflnent-3
Concentration (Bg/l)
BCD-1
L3
L3
L3
24O
250
260
240
280
220
IS
10
6
L2
L2
2
60
20
30
L6
L6
3
U
u
u
88
76
SS
L12
U2
U2
pOO-2 BOP-3
L3 L3
L3
L3
280 260
240
J90
270 250
280
260
12
UO
U4
L2
U
2
80
US
31
U
U
3
'-
77
32
66
U2
U2
SOD
20
28
24
820
860
860
900
1200
200
22O
210
12
23
200
ISO
40
16
48
4
S
260
260
ISO
88
76
72
«
12
16
8
240
220
200
360
290
60
64
56
9
14
57
SO
20
18
21
S
4
89
eo
75
34
29
29
TSa
U
18
16
54
252
112
64
152
176
36
76
64
14
113
167
120
66
121
8
10
8
U
LI
2
38
46
32
6
8
10
NHl
Ll.O
Ll.O
Ll.O
2O
8.O
14
12
10
IS
15
12
Ll.O
Ll.O
7.3
6.2
6.2
S.O
5.0
U.O
U.O
t.
4.
S.
U.
u.
1.
CC*6
L.02
L.02
L.02
.02
.02
L.02
.02
L.02
L.02
L.02
L.02
L.02
L.02
L.02
.04
L.02
.02
.04
L.O2
L.02
L.02
-2
L.I
.6
.3
22
32
28
18
28
30
2.0
1.8
2.1
.3
L.I
.1
3.7
4.4
1.2
.2
.2
.1
.$
.4
.5
.6
.7
.4
O&G
23
7
8
13O
56
no
190
250
220
24
9
10
31
13
8
8O
51
24
37
13
3
2
4
5
30
25
42
5
3
9
pH
7.6
7.6
7.7
10.2
10.3
10.6
9.9
10.2
1O.4
8.3
8.0
8.O
8.2
8.5
7.9
7.3
8.6
1.4
8.4
7.8
7.8
8.6
7.
5.
9.
8.
7.
7.
7.5
3.22
3.11
3.20
2.50
2.27
2.O4
35.•
5.04*
3.53
3.53
3.53
2.99
3.26
3.29
2.75
2.27
2.44
•Average, flow durina thn r.aupUng period.
-------
TABLE B-l
Page 4 of 7
Analytical Haaulta tor Traditional Paraa»ter» tor tha mOOf. mi BtK Saaolino, Program
Conc«ntr«tloo
BOO-1
BOO-3 OOP TOO
OM
Rnflnary J
Intake-1
Intake-2
Intake-}
Separator
Separator
Separator
Separator
Separator
Separator
Separator
Separator
Separator
W Separator
Ul
Separator
effloant-1
eMloant-2
attlwnt-3
•ffloant-1
affluent-*
etfluant-3
afflnant-1
•fflmnt-
afflnant-
aftlaant-
•fflwnt-
affluant-
•fflaant-
•fflmnt-
•ffluent-
Separator
Separator
Separator
Separator
Bio-pond lnfloant-1
Bio-pond tnflnant-2
Bio-pond lnfluent-3
rinal effluent:-!
final eMltnnt-2
Final e(flwnt-)
13
2
SI
76
OS
IS
20
70
10
12
004
3
»
7*
SO
004
OM
OM
H
21
it
100
35
•0
1O
10
10
004
6
1C
40
30
JIO
ISO
ico
310
«M
««0
ICO
100
MO
110
no
430
03
7»
•2
•10
370
4OO
07
07
92
14
1»
10
CO
39
SS
57
200
23O
SI
45
«3
66
50
97
23
22
31
SO
100
120
34
M
32
10
3
1
54
02
22
C4
19C
100
C2
30
34
3C
2C
94
26
1C
4O
24
16
10
20
7
8
2.
U.
U.
2.
1.
1.
0.
1
0.
3.
C.
4.
7.
0.
2.
1.
U.
2;
14
2C
«.l
S.(
5.<
L.02 1
.02 1
L.O2
.02
L.O2
.01
L.O2
.04
.02
.02
.02
.04
L.02
L.02
.OS
.14
.13
.09
1 .08
1 .10
• .08 3
1 L.02
» L.OJ
> L.OZ
..1 1C 1
k.l 11 1
.3 11 1
.7 74
.0 120
.0 3C
.5 04
11 140
IS 250
.0 25
.3 23
.5 S4
.0 CS
.1 34
.1 ISO
.1 7
.0 9
12 25
14 11
•*» 9
I.S 2O
.2 20
L.O C
.9 16
r.s
r.o
r.3
.9
.2
.9
.2
.2
.2
.4 .464
.3 .122
r.3 .572
r.7
r.3
.C
.1
.1
.1
.4
.7
r.s
r.o 2.70
r.s 2.55
r.9 2.71
-------
TABLE B-1
Page 5 of 7
Analytical Beaulta for traditional f«ra»Mtet» tor the KsrERL and BtR Sailing Program
Concentration (»g/l)
Sample-Day
Refinery K
Intake-1
Intake-1
Intake-3
DAT effluent-1
DAT effluent-2
DMT effluent-3
Final effluent-1
Final effluent-2
Final effluent-3
Refinery L
lntake-1
Intake-2
Intake-)
|jj Separator 1 effluent-
| Separator J. effluent-
CTl Separator 1 effluent-
Separator 2 effluent-
Separator ? affluent-
Separator 2 effluent-
Final effluent-1
Final effluent-2
Final effluent-3
Refinery H
Intake-1
Intake-2
Intake-3
OAF effluent-1
DAP effluent-2
OAF effluent-3
Final effluent-1
Final effluent-2
Final effluent-3
BOfcl
4
4
I*
LI 20
22O
LI 20
a
L6
11
2
L2
100
180
32
40
3
11
L6
LS
L6
51
SO
36
L12
L6
L6
«*
U20
210
LI 2O
3
l&
L3
130
100
170
38
31
42
2$
S2
40
BPP.-3
4
4
V*
80
200
LI 20
7
6
10
2
L3
LS
120
98
150
34
42
40
3
L4
8
LS
L6
34
40
34
112
LS
L6
COB
27
23
24
53O
10OO
540
96
130
140
56
20
24
390
350
S30
200
210
170
75
44
71
1O
9
a
260
220
220
92
86
73
TOC
11
10
180
350
180
39
42
13
10
6
110
110
140
49
56
46
19
IS
14
6
10
4
72
62
66
18
16
14
IBS
12
14
10
260
38O
210
21
16
32
290
220
120
140
110
120
36
48
34
21
LI
LI
LI
18
9
7
8
IS
11
m
Ll.O
Ll.O
.0
.7
.7
.2
.2
.4
.9
Ll.O
Ll.O
Ll.O
6.2
10
20
7.8
IS
9.0
Ll.O
3.4
3.0
Ll.O
Ll.O
Ll.O
13
9.5
12
u.o
Ll.O
1.0
**«
L.O2
L.O2
L.02
L.02
.04
.02
L.02
L.O2
L.02
.25
L.02
.05
L.02
L.O2
.07
.05
L.02
L.O2
L.02
.11
.01
L.O2
L.02
L.O2
.75
L.O2
L.02
L.O2
L.O2
L.02
a'
.4
.4
,3
.8
1.6
.6
.5
.3
.3
.1
1.0
1.0
.9
1.5
1.2
.8
1.7
.9
.4
.3
.9
.2
.2
.3
.6
.5
.4
.4
.4
.3
OtG
9
6
14
59O
190
98
31
15
12
4
8
11
16
18
18
13
12
14
8.1
7.4
7.8
7.3
7.7
7.3
7.2
7.5
7.1
7.9
8.3
8.6
8.0
6.3
8.4
7.2
6.9
7.2
8.0
8.0
8.1
6.9
8.4
8.2
7.7
7.9
7.8
flow
-------
TABLE B-l
Analytical Raanlte tor Traditional Paranaters for the BSKBRI. and B»R Sampling Program
Concentration (mg/1)
BOD-1
BOO-2
BOO-3 COO
IDC TSS
Cr
Page 6 of 7
oea pH
w
i
Refinery M
lntake-1
Intake-2
Intake-3
Separator effluent-1
Separator effluent-2
Separator effluent-3
Cheat, plant effluent-!
Chen, plant effluent-2
Che». plant effluent-3
final effluent-1
Final effluent-2
Final effluent-3
Refinery O
Intake-1
Intake-2
Intake-3
OUT efflnent-1
Wt effluent-2
DAF effluent-3
Final efflu.nt-1
Final effluent-2
Final effluent-3
ts
U
34
L2
tS
U
120
100
as
6
uo
94
tS
L2
U
83
100
120
74
140
10
8
10
tio
tB
40
16
28
360
430
440
340
810
240
140
120
140
11
26
12
380
410
480
ISO
140
120
12
8
12
88
120
100
93
240
69
33
33
36
10
21
X
1*0
110
180
48
40
S2
18
22
26
68
112
76
28
36
40
SO
4O
44
10
10
14
21
32
42
24
26
24
tl.O
U.O
tl.O
12
IS
13
1.1
U.O
2.0
6.2
6.7
3.0.
U.O
U.O
U.O
.1
.4
18
.S
.1
.S
t.02
.07
.09
L.02
t.02
t.O2
t.02
t.02
t.02
t.02
t.O2
t.02
t.02
.02
.02
t.02
t.02
t.02
t.02
.02
t.02
.3
.9
1.1
2.9
8.1
9.2
.1
.9
.9
.6
.9
.9
.5
t.l
.1
3.9
4.1
2.9
.6
.5
.4
8.4
7.7
7,3
0.1
8.1
7.9
6.8
6.6
6.7
8.6
7.4
7.4
7.1
6.8
7.O
8.4
8.6
8.8
7.9
24.69
26.84
25.91
15.25
1S.2S
18.25
0.8
0.95
0.9
14.75
15.9
17.6
2.88*
2.88*
7.8
•Average flow during 72-hour period.
-------
TABLE B-l
Page 7 of 7
Analytical Ra«ult» for Traditional ParMeteca for the RSKERI. and »t» Sampling Program
to
I
00
Saeple-Dav
Refinery P
Intake-1
Intake-2
Intake-3
Separator «ffluant-l
Separator effluont-2
Separator effluent-3
Final effluent-1
Final effluent-2
Final effluent-3
Refinery g
Intake-1
Intake-2
Intake-3
Separator effluant-1
Separator effluent-2
Separator effluent-3
Final effluant-1
Final effluent-2
Final effluent-3
Concentration (•£/!)
**>-!
L2
LS
L2
320
210
ISO
LS
LS
13
L2
L2
13
80
40
66
26
2O
3O
BOp-2 BOD-3 CU>
4
LS 6
L2 14
600
220 540
160 470
64
LS 49
L3 41
4
4
24
SO 370
70 33O
64 260
260
2SO
230
TOG
3
7
7
170
140
140
16
24
31
8
11
9
91
84
CS
59
78
60
TOS
U
u
U
68
78
42
11
2
7
3
2
LI
28
10
12
38
22
26
Bb
Ll.O
Ll.O
Ll.O
11
16
18
1.4
2.0
2.0
Ll.O
Ll.O
Ll.O
41
48
39
S3
49
42
a*6
L.O2
L.02
L.02
L.02
.IS
.05
L.02
L.O2
L.02
L.02
L.02
L.02
L.02
L.02
L.02
L.02
L.02
L.02
r2
L.I
L.I
L.I
25
25
23
.3
.6
L.I
.4
.3
.3
9.3
5.6
2.4
.7
.6
.5
QCG
5
9
13
62
38
45
45
37
EH
7.0
6.8
6.3
10.1
9.9
7.7
7.S
7.1
7.4
7.5
9.2
9.3
9.8
8.8
8.3
8.7
Flow (MSP)
.2783
.3086
.3186
-------
TABLE B-2
ANALYTICAL RESULTS FOR PRIORITY POLLUTANTS
FOR THE RSKERL AND BSR SAMPLING PROGRAM
VOLATILE ORGANICS (CONCENTRATIONS, uq/1)
Page 1 of 3
Compound Intake Water
4 Benzene NDj,
23 Chloroform 70
29 1,2-trana-Dichloroethylene ND
38 Ethylbenzene NO
44 Methylene chloride G (100)°
85 Tetrachloroethylene NO
36 Toluene NO
Refinery A
Separator Effluent
GdOOK
D(L 5)°
20
GUOO)h
G(100)
G(50)
G(100)
Final Effluent
NO
b
D (L 5)
ND
ND b
G(100)
D(L 10)
NO
4
23
Benzene
Chloroform
44 Hethylene chloride
Intake Water
DU 10)d
Refinery B"
OAF Effluent
11?
30^
Final Effluent
0(L 10)J?
D(L 10)a
NO5
Refinery Ca
Intake Water Separator Effluent Treated Effluent Final Effluent
4 Benzene
10 1,2-Oichloroethane
23 Chloroform
38 Ethylbenzene
44 Hethylene chloride
4 Benzene
38 ethylbenzene
86 Toluene.
4 Benzene
38 Ethylbenzene
44 Methylene chloride
85 Tetrachloroethylene
86 Toluene '
87 Trichloroeehylene
6 Carbon tetrachloride
11 1,1,1-Trichloroethaae
44 Hethylene chloride
4 Benzene
44 Methylene chloride
36 Toluene
4 Benzene
23 Chloroform
44 Hethylene chloride
36 Toluene
ND
ND
oft,:
417b
16
ND
Intake Water
ND
ND
ND
Intake Water
ND
ND.
50d
SO
ND
20
Intafce Water
G(50)
0(50) A
D(L 10)
ND
ND
ND
2
Refinery Da
Separator Effluent
G(IOO)
G(IOO)
G(IOO)
Refinery E
DAT Effluent
G(100)
G(IOO)
ND
a(loo)
NO
Refinery F
Cooling Tower Slowdown
ND
ND
ND
ND
NO.
20a
final Effluent
ND
ND
NO
Final Effluent
NO
10d
ND
ND
ND
Final Effluent
ND
D(L 10)d
Refinery G
Intake Water Separator Effluent OAF Effluent Final Effluent
D(L 1)
22fi
D(L 1)
409,,
293b
2,005,.
563b
Intake Water
D(L 10)d
ND
ND
96 76,405
Refinery Hc
Separator Effluent
55
NO
ND
0(L 1)
12a
D(L 1)
Final Effluent
66
70°
D(L 10)
B-9
-------
TABLE B-2
Page 2 of 3
Refinery I
Intake Water Separator Effluent Final Effluent
4 Benzene
23 Chloroform
38 Ethylbenxene
44 Mathylene chloride
86 Toluene
D(L 1)/OJ[L 1)
8/d(L 1)B
NO/NO
12/73
ND/ND
243*
NO
,
11767°
Refinery K
2
HD
HDb
7«b J
D(L 1)
Intafce Water Separator Effluent Final effluent
4 Benzene
10 1,2-Cichloroethane
15 1.1,2,2-Tetrachloroethane
23 Chloroform
30 1,2-trana-Oicaloroethylene
38 Ethylbenzene
44 Methylene chloride
85 Tetraehloroethylene
86 Toluene
HD
ND
HO d
D(t 10)
m '
SO
ND
$" b
0(L 10)
Mfinery L*
D(L 10)
OIL 10),
0(L 10)
0(L 10)
0(L 10)
MO
DU. 101
HO
Intake Water Separator 1 effluent Separator 2 effluent effluent
4 BWUUM
23 Cftlorofora
38 Ethylb«n*«n«
44 M«thyl«n« eblerid*
86 Tolu«n«
HO
MD
40
SO
0(100)
10
QdOOlv
0(100)°
0(100)
0(100)
10
5(100)
SO6
0(100)
HO
HO
NO
60°
HD
•> 3OHXUM
6 Carbon tctraehlorida
23 CJilorofora
44 lUthylaM ehlorid*
86 Tolu
Intalc* Mat«r
14b
91
0(L 10)
R«fin«rv MC
OAT Bfflj«nc
0(L 10)
SS A
180d
0(1. 10)
»«fin«rv s*
Final effluent
D(t 10) .
0(1 101?
0(1. 10)
0(1. 10)
Intake M«t«r Ch«m.Plant Effluent Separator effluent final Effluent
23 Chloroform
38 Bthylbentene
44 iiethylene ehlorid*
86 Toluene
•D
HO
HO K
S(100)D
MO
90
10
20 b
0(100)
S(IOO)
G(100)
15
S(100)b
o(ioo);;
6(1001°
6°
HO
HO
0(100)
35
4
6 Carbon tetraenloride
23 Chloroform
44 nethylene chloride
86 Toluene
Intake Water
HO
D(L 10)
55
130
0(L 10)
Itefinery o"
T Effluent
OIL 10)°
HD
13
HD
16
final effluent
0(1. 10) f
Dtlj 10)
A
4 Bensene
6 Carbon tetraclxloride
15 l,l,2,2-Tetrac&loroetnaae
23 Chloroform
30 1,2-trans-oieliloroetbylene
38 Ethylbensene
44 Metnylene chloride
85 Tetraehloroetaylene
86 Toluene
37 Trichloroethylene
Intake Hater
0(1. 10)b
MO
D(L 10),.
0(1. 10)
11
MD
HD
OIL 10)
0(L 10)
0(1. 10)
Refinery p"
Separator Effluent Final Effluent
1,100
RD
HO b
100
HD
28 b
l.SOO
HD
655
NO
oa loir
0(1. 10)
D(L 10)„
OIL 10)
HD
MD
41
HD
ND
D(L 10)
B-10
-------
TABLE B-2
Page 3 of 3
4 Bens
23 Chloroform
44 Methylene chloride
48 DichlorobromoinethaQe
86 Toluene
Refinery Q
Intake Water Separator Effluent final Effluent
D(L 1) 894 HD
NO
ND
89
6°
5*
24
167
SO
HD
Ngtesi
Volatile organic compounds not lifted for a refinery were not detected in samplee
taken at that refinery.
MO - Compound was not detected.
0(Lx) - Compound was detected at some concentration less than x, but the concentration
could not be quantified.
G(x) - compound wae detected at a level greater than x.
a) Midwest Research Institute conducted the analyses for volatile organic compounds
ia samples from Refineries A, 0, E, P, L, H. See Reference Ho. 149.
b) Compound was detected in sample blank.
c) NUS Corporation conducted the analyses for volatile organic compounds in samples
from Refineries 3, H, K, M, 0, P.
d) Compound was detected at a greater level in sample blank than in sample.
e) Gulf South Research Institute conducted the analyses for volatile organic
compounds in samples from Refineries C, G, I, Q. These data represent results
from one-time grab samples collected during revisits to these refineries.
Additional sampling was necessary because the initial volatile organic results
had been considered invalid due to improper analytical techniques. Since the
revisit to Refinery J was conducted by an EPA regional surveillance and analysis
sampling team, the results are not presented in this table.
%
f) Concentrations presented are for unpreserved/preserved samples.
B-ll
-------
TABLE B-3
ANALYTICAL RESULTS FOR PRIORITY POLLUTANTS
FOR THE RSKERL AND BtR SAMPLING PROGRAM
QBGANICS fCONggMTSATTOHS. iia/11
Page 1 of 5
Compound Intake Water
Ba«e - Heutral Extractable*
X Acenaphthene HD
55 Naphthalene NO
77 Acenaphthylene NO
31 Phenantnrene/78 Anthracene O(LO.l)
63 Di-n-butyl phthalat* 0.2
70 oiathyl phthalate NO
Acid Extraetablea
"73 Phenol HD
Refinery A
Separator Effluent13
37
68
4
5
1.3
12
13
Final Effluent
NO
NO
MO
NO
0.7
HO
HD
Baae-Neutral Extractablea
Acid Extractablea
22 Parachlorometa er««ol
34 2,4 - Dimathylphenol
58 4- Nitrophenol
65 Phenol
Baae-Neutral Extractabla«
55 daphthalan*
81 Ph«nanthr«n«/78 Anthracene
56 Bis(2-«thylh«xyl) phthalate
Acid Extractablea
65 Phenol
Intake Water
ttD
HD
HD
NO
HD
Intake Separator
Water Effluent
HD 950
HO 190
ISO 290
Refinery Ba
DAT Effluent
NO
HD
10,000
NO
HD .
Refinery C-l
Treated
Effluent
ND
HD
900
Final Effluent
HD
0 (L 10)
0 (L 10)
D (L 10)
0 (L 10)
Final
Effluent
ND
NO
310
NO
2200
Base-Neutral Extraetables
Acid Extractablea
Final Effluent
NO
NO
Refinery C-21
Base-Meutral Sxtractablea
39 Fluoranthene
55 Naphthalene
73 Benzo (a) pyrene
76 Chrysene
31 Phananthrana/78 Anthracene
84 Pyrene
Acid Sxtra'ctablaa
Intake Water
NO
2
HD
NO
DC.Q.1)
ND
NO
Refinery Da
Separator Effluent^
3
190
ND
0.1
140
11
HD
Final Effluent
HD
ND
3
1.4
ND
7
HD
B-12
-------
TABLE B-3
Page 2 of 5
Refinery Ea
IntaJce Water DAT Effluent"
Final Effluent Final Effluent
Base-Neutral Sxtractablaa
1
25
27
39
55
76
30
31
34
68
Acid
34
65
Acenaphthene
1 , 2-Oichlorobenzene
1 , 4-Oichlorobenzene
Fluor an th«n«
Naphthalene
Chrysene
Fluor ene
Phenanthrene/78 Anthracene
Pyrene
Di-n-butyl phthalate
Extractables
2 , 4-Oiinethylphanol
Phenol
1.3
0(1.0.5}
D(LO.S)
D(L0.2)
ND
ND
NO
ND
O(LO.l)
0.4
ND
ND
150
ND
ND
NO
106
0.3
110
50
5
ND
G<100)
G<100)
ND
ND
ND
ND
ND
D(LO.l)
ND
ND
D(LO.S)
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
0(1,0.1)
O(LO.S)
MD
ND
ND
Refinery F
Base-Neutral Extraetablea
39 Pluoranthene
73 Benzo (a) pyrene
76 Chryaene
31 Phenanthrene/78 Anthracene
84 Pyrsne
Acid Sxtractablea
IntaJce Water1 Cooling Tower Blov/downb Final Effluent
29
33
49
160
140
ND
ND
10
7
2
10
ND
ND
1.3
0.3
ND
ND
ND
Baae-Neutral Extraetablea
39 Fluoranthene/94 Pyrene
35 Naphthalene
76 Chrysene/72 Benzo (a)
Anthracene
91 Phenanthrane/78 Anthracene
66 Bis (2-ttthylhexyl)phthalate
Acid Sxtraetables
65 Phenol
Refinery G-l*
IntaJce Water
ND
ND
ND
ND
1100
Separator Effluent
40
1100
40
1100
700
DAT Effluent
ND
700
ND
600
1100
Final Effluent
ND
ND
ND
ND
350
10
4900
2400
ND
Base-Neutral Sxtractablea
70 Diethyl phthalate
Acid Extraetablea
Final Effluent
1
ND
Refinery G-2*
Baae-Neutral Extractablas
66 Bis(2-ethylhexyl)phthalate
Acid Extractablas
31 2,4-Oichlorophenol
34 2,4-Diroethylphenol
65 Phenol
Intake Water
ND
ND
ND
ND
Refinery H
Separator Effluent
ND
ND
175
440
Final Effluent
D (L 10)
10
ND
ND
B-13
-------
TABLE B-3
Page 3 of 5
Baae-Neutral Extractable»
55 Naphthalene
(6 Bia(2-ethylhexyl)phthalate
68 Di-n-butyl phthalate
Acid Extractable*
65 Phenol
Intake Water
ND
950
30
ND
Refinery I-Ia
Separator Effluent Final Effluent
290
300
ND
390
ND
600
10
Refinery I-2f
Acid Extractable
final Effluent
ND
HO
Baae—Neutral Extractanlee'
1 Acenaphthena
39 rluoranth«ne/84 Pyrene
55 naphthalene
76 Chryiene/72 Benzo (a)
anthracene
81 Phenanthrene/7 8 Anthracene
30 Fluoreae
66 8i»(2-ethyllJ«xyl)phthalate
70 Oiethyl phthalate
71 Dimethyl phthalate
Acid Extractable*
34 2,4-Diaethylphenol
64 Pentachlorophenol
65 Phenol
Intake Water
ND
NO
ND
ND
ND
NO
110
ND
ND
ND
ND
HD
Separator
Effluent
ND
30
ND
30
30
ND
180
NO
ND
ND
ND
420
Refinery J
Separator 2
Effluent
ND
ND
350
30
90
HD
300
ND
ND
ND
ND
160
Separator 3
Effluent
ND
ND
ND
50
ND
ND
SO
ND
ND
ND
ND
ND
Refinery J (continued)
Separator 4
. Effluent
Base^Neutral Extraetablea
1 Aeenaphthene so
39 riuoranthene/84 Pyrene 20
55 Naphthalene ND
76 Chry*ene/72 Benso(a)anthracene 40
81 Phenaathrene/78 Anthracene 230
80 Fluorene 80
66 Bia(2-ethylhexyl)phthalate 600
70 Diethyl phthalate NO
71 Dimethyl phthalate ND
Acid Extractabla«
34 2.4-Oiaathylphenol
64 Pentachlorophenol
65 Phenol
650
850
16,000
Separator
Effluent
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
Bio-Pond
Influent
ND
ND
ND
NO
ND
ND
210
ND
ND
750
ND
G(12,000)
Final
Effluent
MD
ND
HD
ND
ND
ND
190
30
3
ND
ND
Ba«e-Neutral Extraetabla*
Acid Bxtractables
24 2-Chlorophenol
34 2,4-oinethyIphenol
58 4-Nitrophenol
59 2,4-Dinitrophenol
65 Phenol
Intake Water
ND
ND
ND
ND
ND
ND
Refinery
Separator Effluent
ND
315
1,150
5,300
11,000
105
Final Effluent
ND
ND
ND
ND
HD
B-14
-------
TABLE- 8-3
Page 4 of 5
Ba«e-Neutral Extraetaftlea
1 Acenaphthene
39 Fluoraathene
55 Naphthalene
76 Chrysene
77 Acenaphthylene
80 Fluorena
81 Pheaanthrene/78 Anthracene
94 Pyrene
Acid Extractablei
34 2,4-Dioethy Iphenol
65 Phonal
Intake
Water
29
0.2
1
ND
0.2
1
1
0.3
ND
ND
Separator
Effluent
HO
ND
500
20
ND
270
230
HO
5(100)
0(100)
Refinery I.
Separator 2
Effluent
,000
9
280
2
ND
300
HO
7
G(IOO)
GUQO)
Final
Effluent
D(LO.l)
0.1
0.3
ND
ND
1
0(1.0.1)
ND
NO
Refinery
Ba»e-Heutral Bxtractalale*
Acid Extractablee
22 Parachloroneta cre*ol
34 2,4-DioethyIphenol
58 4-Nitrophenol
59 2,4-Olnitrophenol
S3 Phenol
Intake Water
HO
ND
ND
NO
ND
DU. 10)
DAT Effluent
ND
ND
18,300
1,400
2,660
33,500
Final Effluent
ND
10
ND
ND
ND
DU, 10)
Refinery Na
Ba«e-Neutral Extractable«
1 Acenaphthene
39 Fluoranthene
55 Saphtha,lene
76 Chryiene
77 Acenaphtnyl«ne
81 Phenanthrene/78 Anthracene
84 Pyrene
Acid Extractable*
22 Paraohloroo«ta creeol
34 2,4-Dimethylphenol
65 Phenol
Ba«e-M«utral Extractable*
1 Acenaphthene
39 Fluoranthene
54 Isophorone
55 Naphthalene
68 Di-n-bueyl phthalate
71 Dimethyl phthalate
76 Chrysene
77 Acenaphthylene
78 Anthracene
80 Fluorane
31 Phenanthrene
34 Pyrene
Acid Extractabla«
34 2,4-Dioethylphenol
65 Phenol
Intake
Water
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
Che*. Plant
Effluent
NO
27
0(1,0.1)
ND
1
1
10
G(100)
40
Separator'
Effluent
522
8
302
6
87
140
16
ND
71
G(IOO)
ND
ND
ND
NO
ND
ND
ND
ND
ND
HO
Refinery 0
intafce water
NO
ND
NO
ND
ND
ND
ND
ND
ND
ND
ND
MD
ND
OAT Effluent
390
ND
2,500
3,750
ND
ND
ND
530
1,750
495
1,750
ND
2,000
1,900
Pinal Effluent
HO
ND
ND
ND
ND
ND
NO
HO
HO
ND
NO
ND
ND
ND
B-15
-------
TABLE B-3
Page 5 of 5
Watar
Base-Neutral Extractablaa
1 Acanaphthene
54 Isophorone
'55 Naphthalene
77 Acenaphthylena
79 Anthracene
91 Phenanthrene
Acid Extractables
57 2-Nitrophenol
S3 4-«itrophenol
59 2,4-Dini erophenol
60 4,6-Oinitro-o-cresol
Bage-Nautral Extractablaa
66 Bis(2-ethylhexyl)phthalate
68 Di-n-butyl phthalate
71 Dimethyl phthalata
Acid Extractablaa
65 Phenol
Base-Neutral Extractables
70 Diethyl phthalata
Acid Extractables
MOTES:
ND
NO
ND
ND
ND
ND
D (L 10)
D (L 10)
ND
ND
Intaxe Watar
1,100
20
20
10
Final Effluent
1
ND
Refinery P
Separator Effluent
315
3,550
3,200
665
660
660
1,350
20
110
60
Refinery Q-la
Separtor Effluent
320
NO
ND
60
Eefinery Q-2f
Final Effluent
ND
ND
ND
ND
NO
ND
ND
KD
ND
ND
Final Effluent
2,000
ND
ND
NO
Semivolatile organic compound* not listed for a refinery were not detected in samples taken
at that refinery.
ND - Compound was not detected.
D(LX) - compound was detected at some concentration lea* than X, but the concentration could
not be quantified.
G(X) - Compound was detected at a level greater than X.
(a) Midwest Research Institute conducted the analyses for semivolatile organic compounds in
samples from Refineries A,0,E,P,I,,N. See Reference No. 149.
(b) Base-neutral extract was diluted 1:10 before analysis.
(c) Concentrations represent sums for these two compounds which elute simultaneously and
have the same major ions for GC/MS.
(d) NUS Corporation conducted the analyse* for semivolatile organic compounds in samples
from Refineries 3, H, K, H, 0, P.
(a) Ryckman, Edgarlay, Tomlinson s Associates and Gulf South Research Institute conducted
the analyses for semivolatile organic compounds in sample* from Refineries C,G,I,J,Q.
!f) Gulf South Research Institute conducted the analyses for semivolatile organic compound*
in additional samples from Refineries C,S,I,Q. These data represent results from one-
time grab samples collected during revisits to these refineries. Since the revisit to
Refinery J was conducted by an EPA regional surveillance and analysis sampling team, the
results ara not presented in this table.
(g) Both acidic and base-neutral extracts wera diluted 1:10 before analysis.
(h) This sample was stored for 6 weeks prior to extraction for base-neutral and acidic
organic compounds.
(i) Base-neutral extract was diluted 1:5 before analysis.
B-16
-------
TABU B-4
ANALYTICAL RESULTS FOR PRIORITY POLLUTANTS
FOR THE R3KERL AMD BSR SAMPLING PROGRAM
PESTICIDES (COMCgHTRATIOMS, ug/1)
Page 1 of 3
Compound
109 PCB-1239
94 4,4 -ODD
97 Endosulfan «ulfata
100 Heptachlor
103 b-BBC-Mta
104 r-BHC-
106 PCB-1242
107 PCB-12S4
108 PCB-1221
109 PCB-1232
110 PCS-12 48
111 PCB-1260
112 PCa-1016
Pesticide*
10« PCS-1242
108 PCB-1221
106 PCB-1242
91 Chlordane
103 b-BBC-Beta
108 PCB-1221
95 a-Endo>ulfan-Alpha
106 PCB-1242
109 PCB-1232
112 PCS-1016
39 Aldrin
93 4,4 -ODE
105 g-SHC-Oelta
106 PCB-1242
107 PCB-12S4
108 PCB-1221
109 PCB-1232
llO PCS-1248
111 PCB-1260
112 PCB-101S
Refinery A
Intake Water Separator Effluent
NO 0.9
Refinery Bb
IntaJce Water
em
ND
NO
HD
ND
ND
ND
HD
ND
HD
HD
HD
DAF Effluent
D(L
0
-------
TABLE B-4
Page 2 of 3
Refinery Ia
Intake Water Separator Effluent
Pesticides
106 PCB-1242
109 PCB-1232
112 PCB-1016
106 PCB-1242
109 PCB-1232
112 PCB-1016
101 Heptachlor epoxide
106 PCB-1242
107 PCS-1254
108 PCB-1221
109 PCS-123"
110 PCS-1248
111 PCB-1260
112 PCS-1016
106 PC8-1242
106 PCB-1242
107 ' PCS-1254
108 PCB-1221
109 PCB-1232
110 PCS-12 4 8
111 PCS-1260
112 PCB-1016
101 Heptachlor apoxida
108 PCB-1221
109 PCB-1232
112 PCB-101S
102 a-BHC-Alpha
89 Aldrin
96 b-Endosulfan-Beta
100 Haptachlor
103 b-BHC-Bata
105 g-BHC-Oelta
ND
ND
Refinery Ja
Intake
Water
ND
NO
ND
Separator 4
Effluent
ND
ND
Separator 1
Effluent
ND
NO
Separator 2
Effluent
0.5
0.5
0.2
Final Effluent
ND
Separator 3
Effluent
ND
NO
ND
Refinery Ja(continued)
Separator 5
Effluent
ND
ND
Bio-Pond
fluent
0.1
ND
ND
Refinery ic"
Intake Water Separator Effluent
ND
ND
ND
ND
ND
ND
ND
ND
0(1 5)
0(1 10)
D(L 10)
D(L 10)
D(L 10)
D(L 10)
Q(L 10)
D(L 10)
Refinery la
Intake
water
0.2
Separator 1
Effluent
5.2
Separator 2
Effluent
ND
Refinery
Intake Water
ND
ND
ND
ND
ND
ND
ND
OAF Effluent
0(1 10)
0(1 10)
D(L 10)
0(L 10)
0(L 10)
D(L 10)
0(L 10)
Refinery Na
ND
ND
ND
ND
Chemical Plant
Effluent
4.6
ND
0.1
1.3
Separator
Effluent
ND
0.1
0.5
1.9
Intake Water
ND
Intake Water
ND
OT5
ND
ND
ND
Refinery O°
DAF Effluent
Da 10)
Refinery Pb
Separator Effluent
12
13
D(L 5)
0(1 5)
12
Final
Effluent
ND
ND
NO
Final Effluent
ND
0(1 10)
0(1 10)
0(1 10)
0(1 10)
0(1 10)
0(1 10)
0(1 10)
Final
Effluent
ND
Final Effluent
0(1 10)
0(1 10)
0(1 10)
0(1 10)
0(1 10)
0(1 10)
0(1 10)
ND
ND
ND
HO
Final Effluent
ND
Final Effluent
ND
ND
ND
ND
ND
B-18
-------
TABLE B-4 Page 3 of 3
Refinery Qa
Intake Water Separator Effluent Final Effluent
Pesticides ND NO ND
Notes; Pesticide compounds not listed for a refinery were not detected in samples
taken at that refinery.
No-Compound was not detected.
D(Lx)-Compound was detected at some concentration less than x, but the
concentration could not be quantified.
a) Ryckman, Edgerley, Tomlinson and Associates conducted the analyses for
pesticide compounds in samples from Refineries A,C,D,E,F,G,I,J,L,N,Q. Since
these results have not been verified by GC/MS, the reported identifications
must be considered tentative.
b >NUS Corporation conducted the analyses for pesticide compounds in samples
from Refineries B,H,!C,M,0,P.
B-19
-------
TABLE B-5
Page 1 of 10
ANALYTICAL RESULTS FOR PRIORITY POLLUTANTS
FOR THE RSKEHL
CYANIDE, PHEHOLICS,
S ample- Oaya
Refinery A
Intake-1
Intake-1
Intake-2
Intake-2
Intake-3
Intake-3
tntake-ooapoaite
Intake-conpoaita
Separator effluent-1
Separator effluent-1
Separator effluent-2
Separator effluent-2
Separator ef£luent-3
Separator effluent-3
separator affluent-coapoeite
Separator effluent-conpoaite
final effluent-1
final effluent-1
final effluent-2
final effluent-2
final affluent- 3
final effluent-3
final eff luent-conposite
final affluene-coapoeite
Jtef inery a
Intake-1
Intake-2
Intake-3
Intake-coupoeita
OAF effluent-1
OAF effluent-2
OAF effluent-3
OAF eff luent-compoeite
final effluent-1
final effluent-2
final effluent-3
Final affluent-composite
AMD B&R
MERCURY
Lab
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
2
2
2
2
2
2
2
2
2
2
2
SAMPLING 990GSAW
CONCENTRATIONS
Cyanide
K
L.01
L.01
L.01
.OS
.06
.04
L.03
L.03
L.03
L.02
L.02
L.02
.04
.05
.04
L.02
L.02
L.02
, B9/1 )
Phenolics
L.010
L.010
L.011
L.S2
.14
.15
L.021
.010
L.011
L.010
L.OQS
L.OOS
32.
34.
22.
.064
.048
.045
Mercury
.0001
.0001
.0001
L.OOOS
.0001
.0002
.0002
L.OOOS
.0008
.0002
.0002
.0002
L.OOOS
.0003
L.OOOS
L.0005
L.0005
B-20
-------
TABLE B-5
Page 2 of 10
Sample-Day
2
Refinery C
IntaJce-1
IntaJce-1
IntaJce-2
Intake-2
Intake-3
Intake-3
Intake-conpoaite
Separator effluent-l
Separator effluent-l
Separator effluent-2
Separator effluent-2
Separator effluent-3
Separator «ffluent-3
Separator affluent-3
Separator effluent-3
Separator effluent-coBpoeit*
Treated effluent-l
Treated effluant-1
treated affluent-1
Treated «ffluent-2
Treated affluent-2
Treated affluent-2
Treated effluent-3
Treated effluent-3
Treated effluent-3
'Treated «ffluent-compo«ite
Final affluent-!
Final effluent-i
Final effluent-2
Final effluent-2
Final effluent-2
Final effluent-3
Final effluent-3
Final effluent-co«po«ita
Intake-4
Separator effluent-4
Treated «ffluent-4
Final effluent-4
Refinery 0
Intake-1
Intake-L
Intake—2
Intake-2
Lab Cyanide
Phenolica
Mercury
1
3
1
3
1
3
1
1
3
1
3
1
3
3
3
1
1
3
3
1
3
3
1
3
3
1
1
3
1
3
3
1
3
1
3
3
3
3
2
1
2
1
L.01
t.Ol
L. 01
1.1
.12
.07
.07
• 12
.17
• 08
• 03
• OS
.04
.06
L.02
L.02
• OS
.07
L.02
I.. 02
.004
.006
.004
12.
3.2
1.6
1.4
I,. 001
.011
.016
L.001
.002
.006
.002
.0014
.0010
.0016
.0060
.0013
.0010
.0013
.0011
I.. 0010
.0012
.0060
.0015
.0020
.0050
.0780
.0012
.0008
.0020
.0006
.0010
.0050
.0010
.0090
.0060
.0012
.0011
.0010
.0014
.0010
.0013
.0060
.0013
I,. 0001
L.0004
L.0002
.0005
.0001
.0002
B-21
-------
TABLE 3-5
Page 3 of 10
Sample- Pay
aafinery D (Cant.)
lntafce-3
Intake- 3
Intake-compoeite
OAF effluent-1
OAF ef fluent- 1
DAF effluent-2
OAF effluent-2
OAF affluent-3
OAF affluent- 3
OAF affluent-co«po«ite
OAF eff luent-conpocite
Final e££luant-l
Final effluent-1
Final effluent-2
Final effluent-2
Final effluent- 3
Final effluent-3
Final effluent-coBpoeite
Final eff luent-coapoeita
R*f in«ry E
Inealca-1
lneak«-l
Intaka-2
Intalca-2
Ineaka-3
Intake- 3
Intalo- eoapo»i,t«
OAF <££lu«nt-l
DAF •£fluant-l
OAF •ffluant-2
OAF •ffluant-2
OAF affluant-3
OAF cffluant-3
DAF
OAF «fflu«nt-coBiposit»
Final «ffln«nt-l
Final e£flu*n«-l
Final affluont-2
Final affluent- 2
Final affluent- 3
Final affluent-3
Final affluent-coopoaita
Final a£fluant-conpo»ita
Ub
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
2
1
Cyanide
I,. 02
.OS
.06
.04
.03
.03
1. 02
.03
L.03
L.03
L.03
L.03
L.03
L.03
L.03
L.03
Phenolio
0.23
3.7
5.1
8.0
L.011
.015
L.010
6.3
9.9
11.0
.013
.011
L.010
Mercury
.0001
L.OOOS
.0002
.0002
.0001
.0002
L.OOOS
L.0001
.0002
.0002
.0002
L.OOOS
.0002
L.0001
L.0001
L.0001
L.OOOS
L.OOO1
L.0001
L.0001
L.0001
L.OOOS
L.0001
.0001
L.0001
.0001
L.OOOS
.0001
B-22
-------
TABLE B-5
3arola-Day Lab Cyanide Phenolica
Refinery F
Intake-1 2 L.03 .21
Intake-1 1
Intake-2 2 L.03 .21
Intake-2 1
Intake- 3 2 L.03 .21
Intake-3 1
Intake- eoapoaita 2
Intake-cogpoeite 1
Cooling tower blowdown-L 2 .32 .037
Cooling tower blowdown-1 I
Cooling tower blowdown-2 2 .83 .041
Cooling tower blowdown-2 1
Cooling tower blowdONn-3 2 .33 .037
Cooling toiwr blo«da«n-3 1
Cooling towr olowdown-co«po»it« 2
Cooling tovu; blowoown-coopoait* 1
Final ««lu«nt-l 2 .06 .022
Final •ffltMnt-1 1
Final «fflu«nt-2 2 .07 .024
Final •fiCluant-2 1
Final •fflun«-3 2 .08 .026
Final «fflu«nt-3 1
Final «f flu«it-coapo«it« 2
Final «fflu«nt-coc5)o«it« 1
.010
L.001
.008
23.
24.
23.
23.
22.
26.
Page 4 of 10
Mercury
IntAka-l
Intalu-i
lneafca-2
Intak*-2
Intaka-3
Xntak*-3
S«paracor •ffluant-1.
S«paraeoc «£flu«nt-l
Separator «££luant-l
Separator «fflu«nt-2
Sapaxacor «fCluant-2
Saparaeoc «fflu«nt-3
Separator •£flu«ne-3
Separator effluent-conpoait*
OAF «ffliwnt-l
OAF afflu«nt-l
OAF attluant-2
OAF ezfluent-2
1
3
1
3
1
3
1
3
3
1
3
1
3
1
1
3
1
3
L.01
L.01
L.01
1.2
1.2
1.2
1.5
1.9
2.0
.0002
.0007
.0009
I.. 0005
.0006
.0004
.0005
.0007
I.0003
.0003
.0003
.0003
.0003
L. 0005
.0004
.0013
.0005
.0021
.0004
.0023
I.. 0005
.0008
.0017
L.0002
.0009
L.0002
.0018
.0002
.0003
.0011
L.0002
.0011
.0005
B-23
-------
TABLE. B-5
Page 5 of 10
Sample-Pay"
Refinery G (Cont. )
OAF ef£luent-3
OAF effluent- 3
OAF ef f lu«nt-ccnpo»ita
Final effluent-1
Final affluent-1.
Final affluent-!.
Final effluent-2
Final effluant-2
Final effluane-2
Final effluent- 3
Final effluent-3
Final effluent-coopo«ite
Intake-4
Separator aff luent-4
OAF affluent-4
Final eff luent-4
Refinery H
Intake-l
Ineak«-2
Incak«-3
Lab Cyanide
S«para«or «fflu«nt-l
Separator •f£la«nt-2
Separator «££luant-3
Separator e££luent-coivo«ite
Final efflueot-1
Final effluent- 2
Final «££luent-3
Final affluent-composite
Refinery I
Intake-1
Intake-1
Intake- 2
Intake-2
Intake- 3
Intake- 3
Separator effluent-l
Separator ef£luent-l
Separator effluent-1
Separator affluent-2
Separator effluent-2
Separator affluent- 3
Separator affluent- 3
3.0
.09
.07
.09
.30
L.02
.60
.13
.17
L.02
L.02
L.02
.16
.07
.08
.02
.01
.02
Phenolic*
22.
.047
.020
.032
.011
L.005
L.005
2.3
2.2
1.9
L.010
.010
.012
Mercury
.0010
.0010
.0003
.0008
.0010
.0007
.0018
L.0002
.0008
.0005
.0004
L.0005
L.OOOS
L.0005
1
3
1
3
1
3
1
3
3
1
3
1
3
L.005
L.005
L.005
.010
.015
L.005
L.001
L.001
.004
6.0
5.6
4.4
S.O
.0013
.0007
.0011
.0005
.0014
.0007
.0012
L.0002
L.0002
.0028
.0008
.0011
.0003
B-24
-------
TABLE. B-S
Page 6 of 10
Sampl«-0ay
Refinery I (Cont.)
Separator effluent-3
Final effluent-1
Final efflu*nt-l
Final efflu«nt-l
Final effluent-2
Final effluent-2
Final effluent-2
Final affluent-3
Refinery J
Intalc*-!
Intake-1
Intake-!
Intaka-2
Intakat-2
Intate-3
Intake-3
Intak«-3
Intakav-3
Intaka—coapoait*
Separator-1 «£flu«nt-l
3«parator-l cffluant-1
Separator-1 cffluant-2
Saparator-1 «ffluent-2
Separator-1 «ffluent-2
Separator-1 effluent-3
Separator-! «ffluent-3
Separator-1 effluent-conposite
Separator-2 affluent-1
Separator-2 effluent-1
Separator-2 effluent-1
Separator-2 effluant-2
Separator-2 effluent-2
Separatoc-2 effluent-3
Separator-2 effluent-3
Separator—2 effluent-coBposite
Separator-3 effluent-!
Separator-3 effluent-1
Separator-3 effluent-1
Separator-3 effluent-2
Separator-3 effluent-2
Separator-3 affluent-3
Separator-3 effluent-3
Separator-3 effluent-composite
Lab Cyanide
Phenolies
3
1
3
3
1
3
3
3
L.OOS
L.005
L.OOS
L.OOS
L.OOS
5.2
.018
.014
.012
.01
.01
L.01
.01
.01
.01
.01
.01
.01
.01
.01
.01
.01
.017
.024
.002
1.0
1.0
.2
1.0
1.0
2.0
2.5
.690
.5
1.3
.270
Mercury
.0042
L.0002
.0012
L.0002
.0010
.0007
.0001
.0004
.0009
.0002
.0019
.0020
.0070
.0070
.0005
.0001
.0030
.0012
L.0001
.0012
.0010
.0005
.0028
.0001
.0016
.0050
.0003
L.0010
.0006
.0002
L.0001
.0006
.0010
.0009
.0006
.0010
B-25
-------
TABU B-5
Page 7 of 10
Lab Cyanide
Phenolica
Marcurv
Refinery J (Cant.)
Separator-* effluent-1
Separator-4 efflueat-1
Separator-4 effluent-2
Separator-4 «f fluent-2
Separator-4 «ffluent-2
Separator-4 effluent-3
3epvfator-4 effluent-3
S«parator-4
S«p«rator-4
S«p«zmtor-5 •ffluant-1
S«p«rmtar-S •ffluaot-1
Separator-! •£fliMot-2
3«paxator-5 «fflu«nt-2
S«paxacar-5 «fflu«nt-3
Separator-! affluent-3
S«parator-S «fflu«nt-coapo«it«
Bio-pond influaat-1
Bio-pond lnflvMnd-2
Bio-pond influ«nt-3
Final •ffluwvt-l
Final «ffluent-1
Final •fflunt-2
Final «fflu«mt-2
Final *ffluant-3
Final effluent-3
Final effluent-3
Final effluent-coapoaite
Refinery,K
mtake-1
IntaJce-2
Intake-3
Intake-coapoaite
OAF effluent-1
OAF effltnnt-2
OAF effluent-3
OAF effluent-coBposite
Final affluent-!
Final effluent-2
Final effluent-3
Final effluant-conpoaite
.06
.05
.06
.02
.02
.02
.22
.34
.26
.07
.08
.08
.08
L.02
L.02
L.02
9.5
2.0
2.0
1.5
1.5
.294
.214
.246
120.
110.
83.
.008
.024
.002
.0002
.0002
.0013
.0050
.0070
.0016
.0020
.0004
.0003
L.OO01
.0011
.0002
.0016
.0020
.0005
.0020
.0060
.0030
.0008
L. 0001
.0013
.0060
.0009
.0040
L.010
.7
.029
.0005
L.0005
L.OOOS
L.0005
B-26
-------
TABLE B-5
3apple-Pay Lab
Refinery L
Intake-1 2
Intake-1 1
Intak«-2 2
Intak«-2 1
Intake-3 2
Intake-3 1
Intafca-compoaite, 2
Intalce-conponte 1
Separator-1 efflueat-1 2
Separator-1 effliurnt-1 1
Separator-1 affluent-2 2
Separator-1 effluent-2 i
Separator-! affluent-3 2
Separator-! «fflue«t-3 1
Separator-JL effluent-composite 2
Separator-1 effluent-composite 1
Sep«rator-2 affluent-1 2
Separator-2 efflueot-1 1
S«parator-2 «£flueMt-2 2
Separator-2 effluent-2 1
Separator-2 effluent-3 2
Separator-2 affluent-3 1
3eparator-2 affluent-composite 2
Separator-2 effluent-composite 1
final affluent-1 2
Final affluent-1 1
final effluent-2 2
Final affluent-2 1
Final affluent-3 2
Final* effluent-3 1
Final «ffluent-co«ipo«ita 2
Final effluent-composite 1
Refinery M
Intake-1 2
Ineake-2 2
Intake-3 2
Intake-composite 2
OAF effluant-1 2
OAF efflvwnt-2 2
OAF effluent-3 2
OAF affluent-composite 2
Final effluent-1 2
Final affluent-2 2
Final affluent-3 2
Final effluent-coraposito 2
L.02
L.02
L.02
.01
.02
.03
L.02
L.02
L.02
Phenolic*
Page 8 of 10
Mercury
L.06
L.06
L.06
.19
.36
.58
.16
.21
.08
.08
.08
.08
L.010
L.010
L.010
51.
52.
61.
22.
U.6
L.010
.010
L.010
L. 0001
.0002
.0002
.0002
.0014
.0014
.0008
.001S
.0006
.0004
.0004
.0005
.0003
.0003
.0003
.0003
L.010
L.010
L.010
4.7
4.2
4.3
L.010
L.010
L.010
B-27
-------
Bafinery N
Intake-1
Intake-1
Intake-2
IntaJca-2
Intake-3
Intake-3
Intake-composite
Intake-composite
Separator efflu«nt-l
Separator effluent-!
Separator afflu«nt-2
Separator «fflu«nt-2
Saparaeor affluent-3
Separator afflu«nt-3
Separator «fflu«nt-compo»ita
Separator effluejit-conpoait*
Qien plant affluent-1
Ch«m plant affluent-!
OMB plant affluent-2
Qua plant «fflu*nt-2
Oaoi plant «fflu«nt-3
diem plant «ffluent-3
OMB plant «ifluant-co«ipo«it»
Chea plant •£flu*nt-coBpo>ita
Final affluent-I
Final »ffluent-l
Final affluent-2
Finai affluent-2
Final «ffluent-3
Final affluent-3
Final effluent-composite
Final affluent-composite
Refinery O
Intake-1
Intake-2
Intake-3
Intake-composite
DAF effluent-1
OAF affluent-2
OAF affluent-3
DAF effluent-composite
Final effluent-1
Final effluent-2
Final effluent-3
Final effluent-composite
TABLE B-5
Lab
2
1
2
1
2
1
2
1
2
1
2
1
2
1
> 2
1 1
2
1
2
1
2
1
:• 2
:e 1
2
1
2
1
2
1
2
1
2
2
2
2
2
2
2
2
2
2
2
2
Cyanide
L.06
L.03
L.06
L.06
.04
L.06
L.06
L.03
L.06
L.06
L.03
L.06
L.02
L.02
L.02
.21
.16
.13
L.03
L.03
L.03
Page 9 of 10
Phsnolics
L.010
L.011
L.010
6.2
6.5
4.7
L.260
.073
.074
L.01S
L.011
L.010
X.. 005
L.005
" 11.
10.
11.
.052
.049
.036
Mercury
.0002
.0001
.0002
L.OOOS
.0002
.0004
.0006
.0004
L.OOOS
.0005
L.0001
.0004
.0002
L.Q005
.0002
.0004
.0002
.0001
L.OOOS
.0001
L.OOOS
L.0005
L.OOOS
B-28
-------
TABLE B-5
Page 10 of 10
Seaple-Day*
Lab Cyanide
Hettnery F
Intake-1
Intake-2
Intake-3
Xntake-coevosita
Separator effluent-1
Separator effluent-2
Separator effluent-3
Separator e<£luent-ccaposite.
Final effluent-1
Final effluent-2
Final, affluent-3
Final effluent-coaposita
aginary gc
Intake-1
Intake-1
Intake-2
Iatake-2
Intake-3
Intake-3
Separator effluent-1
Separator effluent-1
Separator affluent-1
Separator effluent-2
Separator effluent-2
Separator «ffluent-3
'Separator effluent-3
Final effluent-1
Finkl effluent-1
Final effluent-1
Final effluent-I
Final effluent-2
Final effluent-2
Final effluent-2
Final effluent-3
Final effluent-3
Iatake-4
Separator efflueat-4
Final effluent-4
L.03
L.02
L.02
.09
.06
.04
L.03
C..03
L.03
L.01
.02
L.01
L.01
L.01
.03
L.01
L.01
.32
.32
.01
L.02
L.02
L.02
PhenoUcs
L.010
L.005
L.OOS
106.
29.
.012
.011
.010
L.001
.004
.010
.102
.113
.116
.113
.016
.018
.018
.014
Mercury
L.OOOS
L.OOOS
L.OOOS
.0021
.0012
.0010
.0034
.0060
.0002
.0060
.0003
L.0002
.0003
L.0002
.0003
.0060
.0120
.0002
.0003
.0020
L.0002
.0008
L.0002
L.0001
L.0002
L.0001
Notes:
(a) If a value i» not listed for * particular sample location and time,
then the indicated laboratory did not test that sample for the
specified pollutant.
(b) L - less than.
(c) Grab samples collected during revisits to Refineries, c, G, Q are
indicated as Day 4.
Labs:
!• - EPA Region v Laboratory.
2 - Robert S. Kerr Environmental Research Laboratory,
3 - Ryckman* Edgerley, Tomlinson and Associates.
EPA
B-29
-------
TABLE B-6
Page 1 of 6
FOR THE RSKEBL AMD BtR SAMPLING P
MEIALS (COH
s«^n-°«r*
RafliwxT A
1-1
1-2
1-3
l-camfomt.t»
l-Caapotit*
SE-l
SE-2
SE-3
SE-C
SE-C
rt-i
FE-2
FE-3
FE-C
FE-C
taflnuy B
I- 1
1-2
1-3
I-C
I-C
DAT E-l
OAT E-2
OAF S-3
OAT E-C
OAT S-C
FE-l
FE-2
FE-3
FE-C
FE-C
MCiaacy C-l
1-1
1-1
i-:
1-2
i-j
1-3
I-C
I-C
SE-l
SE-l
SE-2
SE-2
SE-3
SE-3
SE-C
SS-C
TS-1
TE-l
TE-2
TE-2
TE-3
TE-3
TE-C
TB-C
rs-i
re-i
FB-2
FE-2
FE-3
FE-3
FE-C
FE-C
R««ln«ry 0-2"
I
SE
TE
FE
L«b
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
3
1
3
1
3
1
3.
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
3
3
3
3
a
us
us
us
us
LS
us
us
us
us
LS
us
us
us
us
LS
u
u
2
2
LS
U
u
u
u
LS
u
u
u
u
LS
us
us
us
us
u
us
us
us
us
u
us
us
us
us
u
us
us
us
us
LI
Si
u
u
u
u
u
u
u
u
u
u
u
u
u
u
u
u
u
u
u
u
u
u
u
u
L3
u
u
u
u
u
u
LZ
u
u
u
u
u
u
u
u
u
u
u
u
u
u
u
u
u
u
£&.
uo
uo
uo
uo
u
L20
uo
uo
uo
u
uo
uo
uo
uo
u
u
u
7
u
u
u
u
3
u
u
a
u
u
u
u
L20
uo
uo
uo
u
uo
uo
uo
uo
u
uo
13
uo
9
uo
IS
uo
16
uo
uo
uo
uo
LI
S.
U4
U4
L24
U4
LS
U4
L24
1220
30
32
U4
U4
U4
U4
S
30
30
SO
60
LS
SO
so
60
60
LS
70
70
40
SO
LS
U4
L24
U4
L24
2
375
770
513
820
669
940
574
880
133
940
128
470
770
1100
342
490
112
119
142
120
3
'OHS . ua/
BOGBAK
Ti
CU
L4
L4
L4
L4
LS
26
23
39
23
17
L4
L4
6
S
LS
30
20
40
30
LS
LS
9
10
10
7
LS
LS
LS
LS
LS
12
9
11
21
2
231
1S1
140
182
190
27
100
26
190
SI
260
59
230
19
50
24
27
10
Ml
LSO
LSO
LSO
LSO
L1S
LSO
LSO
LSO
LSO
23
LSO
LSO
LSO
LSO
US
6
6
20
20
US
LS
LS
LS
LS
US
LS
LS
LS
LS
L15
LSO
U
LSO
U
LSO
U
LSO
I
LSO
LSO
LSO
LSO
U.
LSO
9
LSO
6
LSO
44
LSO
IB
LSO
7
LSO
7
LSO
7
LSO
IS
Pb
LSO
LSO
LSO
LSO
L1S
147
109
224
114
64
LSO
LSO
LSO
LSO
US
60
60
SO
70
L1S
UO
UO
UO
UO
us
uo
uo
uo
uo
us
LSO
u
LSO
U
LSO
U
119
1
71
LSO
64
227
12
LSO
66
LSO
331
17
LSO
26
113
58
LSO
26
112
50
sa Ji Si
31
45
68
43
UO UO US
253
239
329
272
220 12 US
64
65
77
SI
30 UO US
LSO
LSO
100
100
IS UO US
L60
LSO
LSO
LSO
30 UO US
LSO
LSO
LSO
LSO
25 UO US
79
44
109
1450
20 4 1
607
630
517
670
614
sso
3420
690 8 LI
527
930
489
440
381
930
4780
780 6 1
478
590
565
620
326
590
1080
700 5 3
U.
579
519
543
3. Tl
UO US
uo us
uo us
uo us
uo us
L20 US
4 U
13 3
4 U
5 U
11 U
8 U
9 U
IS
10 LI
LS U
3 U
IS
13 3
10 7
19 LI
19 U
U
LI
U
U
B-30
-------
TABLE B-6
Page 2 of 6
Concentration (aa/ll
SMTI.-D.V*
tefiawr 0
I-l
1-2
1-3
I-C
I-C
OAT E-l
OAF E-2
OAT E-3
OAF E-C
OAF E-C
FS-1
Ft-2
FE-3
FE-C
FE-C
f*l iauy E
1-1
1-2
1-3
I-C
I-C
OAF E-l
OAF E-2
OAF E-3
OAF E-C
OAF E-C
FE-1
FE-2
FE-3
FE-C
FE-C
I-l
1-2
>3
I-C
I-C
cr a-i
CT B-2
CT B-3
CT B-C
CT B-C
FS-1
FE-2
FE-3
FE-C
FE-C
a»fln.ry 0-1
I-l
I-l
1-2
1-2
1-3
1-3
I-C
I-C
51-1
51- 1
SB- 2
SI- 2
SI-3
SE-3
SE-C
SE-C
OAF E-l
DAF E-l
OAF E-2
DAF E-2
OAF E-3
OAF E-3
OAF E-C
OAF E-C
FE-1
FE-1
FE-2
FE-2
FE-3
FE-3
FE-C
FE-C
J*»
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
3
1
3
1
3
1
3
1
3
I
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
tO.
USO
uso
uso
uso
LS
uso
us
us
us
LS
us
us
us
us
IS
us
us
us
us
LS
us
us
us
us
LS
us
us
us
us
LS
uso
uso
uso
uso
LS
uso
uso
us
us
LS
us
* us
us
us
LS
us
us
us
us
u
us
us
us
us
u
us
us
us
us
u.
us
us
us
us
LI
a*
uo
uo
uo
uo
u
uo
u
u
u
u
u
u
u
u
L3
u
u
u
u
L3
u
u
u
u
L3
u
u
u
u
u
uo
uo
u
u
L3
u
u
u
u
L3
u
u
u
L2
13
u
u
u
u
u
u
u
a
u
u
u
u
u
u
u
u
L2
L2
u
L2
Si
uoo
uoo
uoo
uoo
u
uoo
uo
uo
uo
u
uo
uo
uo
uo
u
uo
uo
uo
uo
2
uo
uo
uo
uo
u
uo
uo
uo
uo
u
uoo
uoo
uo
uo
u
uo
uo
uo
uo
u
uo
uo
uo
uo
u
uo
uo
uo
uo
u
uo
uo
uo
uo
u
uo
uo
uo
24
u
uo
uo
L20
uo
u
SS.
U40
U40
U40
U40
114
1020
681
479
719
730
1230
1160
875
1080
1000
25
58
35
42
35
104
86
89
89
76
42
52
44
42
36
1240
U40
7Z
58
60
SO
60
79
57
44
73
31
29
45
7
124
U4
L24
124
1
615
320
676
790
73
1200
SOS
1000 .
526
710
414
680
73
930
425
300
39
36
73
124
1
Cu
L40
L40
140
L40
LS
L40
IS
6
7
LS
14
14
U
L4
LS
S
8
IS
10
8
L4
14
L4
U
LS
L4
L4
L4
L4
LS
50
190
184
1S1
210
278
350
510
40S
500
199
36
84
125
125
14
L4
14
L4
7
S
53
L4
3
7
14
L4
L4
a
3
14
U
14
U
7
Si.
LSOO
LSOO
LSOO
LSOO
115
LSOO
LSO
LSO
LSO
115
LSO
LSO
LSO
LSO
us
LSO
LSO
LSO
LSO
SI
LSO
LSO
LSO
LSO
28
'LSO
LSO
LSO
LSO
19
LSOO
LSOO
57
62
58
64
101
134
38
77
68
74
71
64
sa
LSO
52
LSO
ISO
U
LSO
35
LSO
93
U
ISO
LSO
LSO
104
1
57
63
LSO
LSO
U
&
LSOO
LSOO
LSOO
LSOO
US
LSOO
LSO
LSO
LSO
US
LSO
LSO
L60
LSO
US
LSO
160
LSO
LSO
23
LSO
160
LSO
L60
US
LSO
LSO
LSO
L60
US
LSOO
LSOO
LSO
LSO
115
160
LSO
L60
LSO
US
LSO
L60
160
LSO
US
78
102
LSO
LSO
2
181
420
308
160
160
430
181
278
159
270
115
320
160
360
144
260
107
90
160
160
2
Zn A>
USO
USO
USO
uso
33 UO
410
242
181
262
280 UO
SIS
480
338
430
400 UO
141
102
130
127
110 UO
61
47
54
74
50 UO
49
77
59
44
30 UO
uso
uso
127
133
120 27
229
342
4S2
342
330 41
125
151
112
132
100 31
52
LI
72
U
28
U
30
36 5
125
60
117
24
170
110
179
66 5
93
44
94
87
64
92
139
53 L4
51
46
64
30
36 5
Sb. S. Tl
US UO US
us uo us
us uo us
us uo us
us uo us
US 12 US
US 12 US
us uo us
r.?; UO US
u
u
u
U 3 U
9 U
10 U
6 U
U « U
5 U
13 U
7 U
1 9 U
32 6
9 12
7 5
U 3 12
B-31
-------
TABLE B-6
Conc«ntr«tion (ug/11
Page 3 of 6
Miin«r? G-f
I
sx
DAT I
R
Mf iMzy a
l-l
1-2
1-3
I-C
I-C
SB-l
n-2
SC-3
st-c
ss-c
R-l
R-2
R-3
R-C
R-C
ttmtiMff I
-1
-I
-2
-2
-3
-3
I-C
I-C
SX-1
SK-1
SI-2
SC-2
St-3
SE-3
Sl-C
3I-C
R-l
Fl-1
R-2
R-2
R-3
R-3
R-C
R-C
«•< inwcy >J
1-1
l-l
t-2
1-2
1-3
1-3
I-C
I-C
SI E-l
U 1-1
SI t-2
SI 1-2
SI 1-3
SI 1-3
SI E-C
SI E-C
12 E-l
32 E-l
S2 E-l
S2 E-2
32 1-3
12 C-3
S2 I-C
32 I-C
S3 S-l
33 S-l
S3 «-2
S3 E-2
S3 1-3
S3 E-3
3
3
3
3
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
\
3
1
3
1
3
1
3
Ll
Ll
Ll
Ll
LS
U
Ll
U.
Ll
LS
LL
Ll
U
Ll
LS
US
US
US
us
Ll
US
US
us
us
Ll
US
us
us
Ll
*
us
us
us
us
u.
us
us
us
us
u
us
us
us
us
Ll
us
us
us
Ll
u
Ll
Ll
u
Ll
Ll
Ll
U.
L3
Ll
U
U
U
u
u
u
u
u
Ll
u
u
u
u
Ll
U
u
u
u
u
u
u
u
u
u
u
u
u
u
u
u
u
u
Ll
U
U
U
U
u
8
U
u.
u
u
u
u
Ll
U
U
20
U
U
UO
UO
UO
UO
Ll
UO
UO
UO
uo
u
UO
UO
UO
u
UO
UO
UO
UO
Ll
UO
UO
UO
UO
Ll
UO
UO
UO
UO
u
UO
UO
UO
Or
20
10
20
10
LS
10
7
20
10
LS
20
10
10
10
LS
U4
L24
U4
U4
1
98
91
102
98
3
U4
U4
L24
1
L24
U4
L24
U4
1
36
620
100
50
16
52
76
440
4SO
1050
1100
411
390
384
780
547
830
1010
1200
3SO
660
Cu
L6
9
10
7
LS
30
20
30
30
7
10
10
9
7
LS
L4
6
20
16
10
1S7
167
146
1S7
6
85
22
71
3
S
10
L4
4
1
L4
1370
33
25
2
L4
231
L4
55
7
14
16
16
Ni
L5
LS
LS
LS
L1S
LS
LS
LS
LS
US
LS
LS
U
LS
US
LSO
LSO
LSO
LSO
U
LSO
7
LSO
U
LSO
U
LSO
5
LSO
LSO
LSO
Ll
LSO
LSO
LSO
LSO
1
LSO
771
LSO
LSO
U
LSO
69
LSO
61
Ll
118
LSO
LSO
gb
UO
UO
UO
UO
US
UO
UO
UO
UO
us
30
30
UO
30
L1S
LSO
LSO
79
78
2
LSO
LSO
90
1M
2
LSO
LSO
211
2
LSO
LSO
LSO
LSO
2
LSO
9S8
LSO
LSO
4
190
190
2080
200O
976
380
810
970
123
LSO
LSO
Zn
LSO
LSO
LSO
LSO
IS
LSO
LSO
70
LSO
30
LSO
SO
LSO
LSO
25
69
52
336
S36
25
172
110
237
100
1070
100
1120
100
69
69
2000
60
72
54
62
62
54
ISO
120
499
2SO
432
420
2S7
320
316
290
14OO
2100
790
680
6S8
740
194
ISO
24S
210
280
280
Aj Sb S«
UO US UO
UO US UO
UO US 20
L4 U 2
L4
L4
7
5 Ll 4
25
23
L4 Ll 16
3 Ll 3
7
16
L4
3 Ll 5
16
12
14
S Ll 9
17
13
31
Tl
Ll
Ll
Ll
Ll
L1S
L1S
L1S
U
Ll
Ll
Ll
Ll
Ll
U
U
Ll
Ll
U
U.
Ll
Ll
U
U.
U
U
U
3
Ll
Ll
3
Ll
Ll
Ll
B-32
-------
TABLE B-6
Page 4 of 6
Concentration (uq/1)
3«apl«-0ay *
!4*
a
SS.
Si
Cr
21
Mi.
Pb
Zn
A* Sb
§2.
li
R>f intry J (Cone* )
S3 E-C
S3 E-C
34 E-l
54 E-l
S4 E-2
34 E-2
34 E-3
34 E-3
34 E-C
34 E-C
SS E-l
SS E-l
SS S-2
SS E-2
SS E-3
SS E-3
SS E-C
SS E-C
S-P 1-1
B-P I-l
B-P 1-2
B-P 1-2
B-P 1-3
B-P 1-3
B-P I-C
B-P I-C
PE-1
PK-1
fS-2
P*-2
PS-3
PS- 3
PE-C
FS-C
fmtintrr x.
I-l
1-2
1-3
I-C
I-C
OAT E-l
DAT E-2
DAT E-3
OAT E-C
OAT E-C
rs-i
PI-2
FE-3
Pl-C
PE-C
R*f iMTT L
I-l
1-2
1-3
I-C
I-C
31 E-l
31 S-2
SI E-3
SI S-C
Si E-C
32 E-l
32 S-2
32 8-3
32 S-C
32 S-C
PE-l
FE-2
PE-J
FE-C
PB-C
1
3
1
3
1
3
I
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
3
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
us
I
us
us
us
us
2
31
US
US
US
U
us
us
us
us
LI
us
us
us
us
u
u
u
LI
u.
u
LI
u
LI
u
u
LI
LI
U.
LI
•u
uso
uso
us
uso
u
uso
uso
uso
uso
u
us
us
us
us
u
us
L25
US
US
u
u
u.
u
u
u
u
LI
2
U
U
u
u
u
u
u
u
u
u
u
u
u
u.
u.
LI
u
LI
U
U
U
u
LI
U
U
u
u.
u
u
uo
uo
u
uo
u
uo
uo
uo
uo
u
u
u
u
u
u
u
u
u
u
u
uo
LI
uo
uo
uo
uo
u
uo
4
uo
5
uo
9
uo
7
uo
uo
uo
uo
u
UO
uo
uo
uo
u.
u
u
3
u
u
u
u
u
u
3
u
u
u
u
1
uoo
uoo
uo
uoo
u
uoo
uoo
uoo
uoo
LI
uo
uo
uo
uo
u
uo
UO
uo
uo
LI
626
570
335
1500
1210
1300
1860
1700
1300
1900
1580
2200
2790
4900
1500
1800
2010
3600
L24
9
US
5
L24
6
29
22
96
ISO
94
27
102
27
82
54
20
10
10
20
S
1000
2000
1000
1000
1600
100
60
100
100
73
U40
U40
U4
U40
30
10OO
U40
L240
U40
290
773
831
928
802
370
205
119
165
144
190
25
2
38
21
77
42
10
51
47
51
45
182
41
7
L4
17
2
9
L4
6
L4
32
10
10
10
10
6
200
400
200
300
280
60
10
20
30
18
L40
L40
22
MO
20
170
L40
100
100
ISO
43
54
31
42
50
24
19
31
24
39
63
LI
UO
UO
UO
LSO
LI
139
LSO
UO
79
1
LSO
UO
uo
LSO
U
53
LSO
7
65
6
UO
3
U
U
u
u
L1S
9
20
U
20
28
U
U
u
u
us
uoo
uoo
LSO
uoo
21
uoo
uoo
uoo
uoo
70
LSO
UO
UO
UO
16
UO
UO
uo
LSO
IS
71
2
80
UO
UO
69
12
164
UO
UO
101
2
72
UO
uo
uo
3
82
L60
UO
UO
9
70
40
80
40
US
50
200
60
100
70
UO
UO
UO
UO
L1S
UOO
700
64
UOO
40
UOO
UOO
UOO
uoo
45
UO
UO
UO
LSO
17
UO
UO
UO
uo
us
215
260
411
340
261
290
579
620
304
560
464
600
609
740
417
520
491
760
148
54
65
55
130
51
46
62
62
200
70
60
70
45
1000
3000
1000
2000
1400
100
70
100
1000
120
810
USO
125
USO
120
49O
290
290
360
370
382
304
314
32S
290
174
157
161
174
140
3 LI
3 1
9 LI
U LI
M LU
UO US
uo us
uo us
uo us
uo us
uo us
uo us
6
25
24
4
11
7
29
19
23
20
10
18
22
20
27
16
12
UO
UO
uo
uo
uo
uo
uo
U
LI
U
LI
U
LI
4
6
U
LI
LI
LI
U
U
U.
U
U
us
L1S
US
US
L15
U5
US
B-33
-------
TABLE 6-6
Page 5 of 6
Concentration (uq/11
3«nol«-O«Y *
R»fin«ry N
1-1
1-2
1-3
I-C
I-C
DAT 2-1
OAF S-2
DAF E-3
OAF E-C
OAF S-C
FE-I
FE-2
re- 3
FE-C
FE-C
S»t in«ry H
1-1
1-2
1-3
I-C
I-C
SE-l
SB- 2
SI- 3
SI-C
SE-C
CJE-I
CTE-2
CPE-3
CTE-C
CPS-C
FE-I
FE-2
rz-3
FE-C
FE-C
!Uf in*ry 0
1-1
1-2
1-3
I-C
I-C
OAF E-l
oar s-2
SAF E-3
OAF E-C
DAT E-C
FE-1
FE-2
FE-3
FE-C
FE-C
R«f in«ry f
I-l
1-2
1-3
I-C
I-C
SE-l
SE-2
SZ-3
SE-C
SE-C
FE-1
FE-2
FE-3
FE-C
FE-C
Lib
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
I
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
1
1
1
2
1
1
1
I
2
1
1
1
1
2
1
1
1
1
2
1
1
I
1
2
1
1
1
1
2
£9.
u
u
LI
LI
LS
U.
U.
u
u.
LS
U
LI
4
4
LS
US
L2S
L2SO
L25
LS
L2SO
L2SO
L2S
L2S
•LS
US
L2S
US
L2S
LS
US
us
us
us
LS
u
u.
LI
U
LS
LI
U
LI
U
LS
U.
LI
LI
U.
LS
LI
U.
U.
LI
LS
LI
U
LI
LI
LS
LI
LI
LI
U.
LS
is.
u
LI
LI
LI
L3
2
2
2
2
U
2
2
U
U
U
u
u
uo
u
u
uo
uo
u
u
L3
U
U
U
u
u
u
u
u
u
u
LI
u
LI
U
L3
U
U
U.
u.
L3
LI
LI
U
U
L3
U.
U
U.
U
U
U.
u
LI
U.
U
LI
LI
U
U
U
Si
U
U
u
u
LI
L2
U
U
U
LI
3
U
U
U
u
uo
uo
uoo
uo
u.
uoo
uoo
uo
uo
LI
uo
L20
UO
uo
u
uo
uo
uo
uo
u
u
u
u
u
LI
u
u
u
u
LI
u
u
u
u
LI
u
u
u
u
LI
U
u
u
u
LI
U
u
u
u
Li
21
30
10
20
20
LS
200
100
90
100
73
90
100
90
100
24
U4
U4
3000
U4
7
1000
2000
960
1380
1400
SOS
679
499
701
650
U4
159
131
137
120
LS
LS
LS
LS
8
200
300
300
200
240
SO
SO
90
SO
110
LS
LS
LS
LS
40
900
SO
700
600
72
LS
LS
LS
LS
40
Cu
300
100
100
200
180
10
10
9
10
6
10
10
20
20
3
L4
L4
L40
L4
LS
UO
L40
7
14
61
L4
8
7
L4
13
L4
L4
L4
L4
11
LS
L6
L6
L6
LS
30
10
a
20
3O
L6
L6
L6
L6
LS
LS
L6
LS
L«
LS
LS
LS
L6
L6
LS
L6
LS
LS
L6
LS
Si.
10
L5
LS
LS
L1S
LS
LS
LS
LS
L1S
LS
LS
10
20
L1S
LSO
uo
790
LSO
L1S
LSOO
LSOO
LSO
LSO
16
LSO
LSO
LSO
LSO
L1S
LSO
LSO
LSO
LSO
L1S
LS
LS
LS
LS
us
LS
LS
LS
U
us
LS
LS
LS
LS
US
LS
LS
LS
LS
US
LS
LS
LS
LS
L1S
LS
LS
LS
LS
US
Pb
200
UO
40
60
25
UO
uo
uo
uo
us
uo
so
uo
30
us
LSO
LSO
LSOO
UO
US
LSOO
LSOO
LSO
LSO
18
LSO
LSO
LSO
LSO
US
LSO
LSO
LSO
LSO
US
UO
uo
uo
uo
us
uo
uo
uo
uo
27
uo
uo
uo
uo
us
uo
uo
uo
uo
us
uo
uo
uo
uo
us
uo
uo
uo
uo
us
Zn
200
90
100
100
75
200
100
90
100
140
90
100
100
200
90
56
29
uso
36
19
48O
760
S73
603
570
6S20
4110
4260
S210
4800
US
118
61
104
35
LSO
LSO
LSO
LSO
UO
LSO
LSO
100
60
74
LSO
LSO
LSO
160
L10
LSO
LSO
LSO
LSO
61
LSO
LSO
LSO
LSO
55
LSO
LSO
LSO
LSO
43
i! 5S. 5i li.
uo us uo us
uo us uo us
uo us uo us
uo us uo us
uo us uo us
uo us uo us
uo us uo us
uo us uo us
uo us uo us
uo us uo us
uo us uo us
UO 360 UO US
UO 370 UO US
B-34
-------
TABLE B-6
Page 6 of 6
Sa»Pl«-OaY* Lab
Concentration (ug/1)
a. Cd
cu Mi Pb
Sa U
MflMry S-l
1-1
1-1
1-2
1-2
1-3
t-J
I-C
I-C
St-1
SI- 1
SI-2
St-1
SC-3
SI- 3
SC-C
SI-C
ra-i
ra-i
f»-2
n-2
ra-3
n-3
ra-c
ra-c
Mfiamy 9*2b
IS
ss
n
i
3
1
3
1
3
1
3
1
3
1
3
1
]
1
3
3
3
3
US
us
L25
US
U
US
US
US
us
LI
us
us
us
us
U
U
L2
U
L2
U
U
LI
n
L2
LI
U
U
U
L2
U
L20
UO
LZO
UO
U
UO
UO
UO
UO
U
UO
UO
U
UO
U
UO
3
U4
L24
L24
U4
1
L24
U4
L24
U4
1
U4
L24
L24
U4
2
37
37
20
S3
120
7
«0
L4
140
6
60
IS
210
U
20
«
U
180
LSO
L50
UO
LSO
U.
LSO
LSO
LSO
LSO
LI
uo
uo
uo
uo
U.
L60
L60
L60
167
2
LSO
UO
L60
101
10
LSO
L60
LM
102
IS
70
62
329
2820
33
274
330
444
470
511
640
1460
470
24S
380
329
3«0
300
310
U70
340
7
480
460
460
440
790
900
680
800
U
6
10
&
9
7
6
10
11
10
22
20
U
LI
U
U
U.
U
LI
L2
U
U
U.
L2
240
380
300
U.
2*2
35
350
SOO
nataai
a) If « nOua U not Uatad for • particular Minla loot ton and tiaw. than tha iadicatad laboratory
old not taa-t tfaac saavla Car tha aaaeifiad pollutant.
b> OMM daea rapm*nt raavlts froa <
c. a, g.
L • Lua than
I - Intata
If - Mparator «Mlu«t
OAF s - DAT affluaat
TI - Tr*at*d »ttloant
n - final «Kluant
CT 1 - Cooling Tovar blovdoim
B-f I - alo-oond influaat
CPK ~ Qua^cal plant affluant
-tia* grab
plaa collaetad dociag r*riaa.ti to Raflaariaa
Uba; 1 - SP» Kaqtoa V Laboratory
2 - aobart S. Karr Envirnn»»ntal Banana Laboratory,
3 - RyeJoun, Sdoarlay, ToaOinaon and Aaaoelataa
B-35
-------
TABLE B-7
Analytical Results for Traditional Para»eters in the PretreaUaent Sampling Program - Week 1.
Sampling
Location
1. Refinery No. 25
Effluent
2. POTH No. 1
a. Raw Influent
b. Final Effluent
c. Primary Sludge
d. Secondary Sludge
Day
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
PH
8.9
8.7
8.68
7.50
7.50
7.30
7.40
7.55
7.80
5.9
8.5
6.78
7.3
7.45
7.60
SS
19
45
25
316
290
524
1
2
2
21.200
39.160
12.450
1.948
3.536
3.000
Sulfide
mg/1 S
<0.1
< 0.1
<0.1
0.25
0.20
0.40
< 0. |
<0. 1
< 0. 1
35.0
110.0
33.0
0.25
0.80
0.50
BODg
mg/1
310
320
355
212
240
235
3
4
5
>4.930
8.920
1.230
745
1.460
5.680
COO
ing/1
690
710
700
505
580
580
34
30
35
28.600
39.700
30.100
2.070
42.300
15.800
CN
mg/1
3.0
2.6
3.0
0.1
*
0.02
0.06
0.07
0.05
0.24
*
0.05
0.15
*
0.17
Phenol
*g/l
123
88
99
1.7
*
0.113
0.003
0.011
0.012
2.30
*
0.622
0.074
*
0.169
O&G
mg/1
41.4
42.3
61.8
54.1
59.0
22.4
1.3
1.0
0.9
2.660
5.260
1.044
29.5
59.5
42.0
Cr*6
mg/1
0.26
0.48
0.22
< 0.02
<0.02
<0.02
<0.02
-------
TABLE B-8
AHALYTICAl RESULTS FOR PRIORITY POLLUTANTS FOR THE PRETREATMENT SAMPLING
PROGRAM-WEEK I. VOLATILE ORGANIC CDNCENTRAT
uq/T
Po1
Pollutant No.
Benzene
Chlorobenzene
4
7
1,l,1-tr1chloro-n
ethane
1,1-d1chloro-
e thane
Chloroform
1 ,2-trans-
dlchloroethylene
Ethyl benzene
Methylene
chloride
Tetrachloro-
ethylene
Toluene
Trichloro-
ethylene
13
23
30
38
44
35
36
87
Oay
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
Ref.No. x
25
Eff .to
POTW
4,200
5.800
1,600
„
31
-
.
.
-
.
.
-
_
21
17
.
.
-
9,000
5,600
4,000
-
-
*
.
18
15,000
9,900
5,700
.
.
-
POTW*
Inf.
23
81
*
.
•
-
5
22
*
.
•
-
.
10
*
.
-
*
25
20
*
*
*
*
88
117
19
34
103
24
38
57
27
Primary* Secondary* Final* Primary
Eff. Eff. Eff. Sludge
17
64
14
.
.
-
. •
16
10
.
-
-
.
* .
• *
.
•
*
38 *
25
*
* *
* *
» *
43 *
160 16
24
67
no
31
21
78 *
36 *
.
.
-
.
-
-
.
-
15
.
-
-
.
*
*
.
-
-
.
*
-
*
23
*
10
23
.
.
-
*
*
*
9
13
-
.
-
-
.
-
-
16
-
-
-
-
-
60
-
50
50
20
•
30
(11) *
(11) •
-
-
-
30
30
10
150
-
20
^ xx
Secondary
Sludge
_
»
-
-
-
-
.
.
-
.
-
-
.
-
-
-
-
-
.
-
-
10
120
18(15)
-
-
-
.
-
-
-
7
-
NOTE: - Not detected.
* In traces,but below detection limit.
( } Sanpla blanfc. Ho volatile orgaaics detected in other sample blanJts.
x Analysis performed by West Coast Technical Service.
xx Analysis performed by Pomeroy, Johnston and 8a-iley.
Of the 30 volatile organics, only 11 were detected.
B-37
-------
TABLE -B-9
ANALYTICAL RESULTS FOR PRIORITY POLLUTANTS FOR THE PRETREATMENT SAMPLING
Page 1 of 2
PR06RAH-HEEK 1 ,
Poll **
Pollutants No.
2,4-Oliwthyl- 34 AE
phenol
Pentachloro- 64 AE
phenol
Phenol 65 AE
1,2 dlchloro- 25 BNE
benzene
1,3 dlchloro- 26 BNE
benzene
1,4 dlchloro- 27 BNE
benzene
Isophorene 54 BNE
t
Naphthalene 55 BNE
Nitrobenzene 56 BNE
B1s(2-«thyl- 66 BNE
hexy1)phthalate
Butyl benzyl 67 BNE
phthalate
Day
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
Z
3
SEWVOLATILE ORGAN ICS (CONCENTRATIONS, uq/1)
Ref.No. x
25 - ,, * * xx
Eff. to POTW* Primary* Secondary* Final* Primary
POTW inf. Eff. Eff. Eff. Sludge
1,700 69
-
233 25
_ —
-
330
2,900 575
700
980
- *
4
15
*
19
10
28
29
24
.
-
-
620 113
121
370 20
^ .
-
-
124
112
130
16 55
53
39
72 »
. *
34
_ .
*
-
520
700 *
1.100 *
*
17 *
n *
* »
17 *
n *
23 *
30 *
30 10
. ,
23
-
93 *
156 *
35
_ m
.
-
94 *
56 *
150
59
43
68 *
* ..
.
-
* .
* .
•
*
* 355
* 180
* 13
7
* 10
* 30
15
*
• 30
15
* 9
» ^
-
*
* 440
30
* .
5
.
-
_ _
* 130
240
170
25
* 14
XX
Secondary
Sludge
.
-
-
„
.
-
_
405
1,200
20
9
-
»
5
-
^
5
-
.
-
-
_
.
-
—
.
-
75
180
140
_
.
.
B-38
-------
TABLE B-9 Page 2 of 2
ANALYTICAL RESULTS FOR PRIORITY POLLUTANTS FOR THE PRETREATHENT SAMPLING
PROGRAM-WEEK 1. SEHIVOLATILE OP.SAHICS (COMCEXTRATIOHS. ug/11
Ref.NO.*
25 xx x x xx xx
Pol 1 utants
Dl-n-butyl
PhthaJate
01-n-ortyl
Phthalate
Diethyl
Phthalate
Dimethyl
Phthalate
Acenaphthylene
Anthracene
F1 uorene
Phenanthrene*
Pyrene
Poll
Ho.
68
69
70
71
77
78
30
81
84
Day
BNE 1
2
3
BNE 1
2
3
3NE 1
2
3
BNE 1
2
3
8NE 1
2
3
BNE 1
2
3
BNE 1
2
3
3NE 1
2
3
BNE 1
2
3
Eff. to
POTW
40
#
-
-
-
.
14
-
m
.
-
*
.
-
60
51
30
.
63
32
60
SI
30
_
21
-
POTH
Inf.
24
28
34
12
-
,
13
*
^
.
-
.
.
-
*
*
*
w
*
*
*
*
*
^
.
-
Primary
Eff.
19
21
17
*
*
-
27
17
*
*
*
-
.
,
*
*
*
*
—
*
-
' *
*
*
—
.
.
Secondary Final
Eff. Eff.
* *
* .
* *
-
.
. *
* .
15 *
*
_ »
* *
m ^
.
-
.
. »
*
*
— ^
-
.
.
*
.
. ^
.
Primary Secondary
SI udge SI udge
-
-
-
-
190 5
11
9
-
— —
. _
-
.
-
^ —
-
.
^ ^
-
.
_ —
.
Of 59 semi-volatile organlcs, only 20 were detected.
* in traces, but below Detection Limit.
** AE - Acid extractable; 8NE - Base/neutral extractables.
+• Anthracene and Phenanthrene are unresolved.
- Not detected.
x Samples were analyzed by West Coast Technical Services.
xx Samples were analyzed by Pomeroy, Johnston and Bailey.
B-39
-------
Pollutant
TABLE.B-10
ANALYTICAL ^gSULTS FOR PRIORITY PguUTANTS FOR THE PRETREATHENT
PROGRAM-WEEK 1. PESTICIDES(CONCENTRATIONS, ug/1\
Poll.
No.
Day
f'Z5r POTW* Primary* Secondary* Final* Primary* Secondary"
Eff.to
POTW
Inf. Eff.
Eff.
Eff. Sludge Sludge
4,4'-OOE
93 1
2
3
Heptachlor 100 1
2
3
b-8HC-Beta 103 1
2
3
r-BHC-Gamma 104 1
2
3
0.68 0.39
0.12 0.13
0.18
0.10 0.55 0.49
6.3
0.14 0.13
1.1
1.2
NOTE: Of 25 pesticides only 4 were found; none of the four were confirmed by GCMS.
- Not detected.
x Samples were analyzed by West Coast Technical Service.
xx Samples were analyzed by Pomeroy, Johnston and Bailey.
B-40
-------
TABLE B-ll
Metal» (Ceneeotratioiu, un/1)
a. 1
feUutut fell. He.
Unftxgny 114
anenie 115
Beryllium 117
^•^^^ ne
OiroBitai 119
Sapper 120
Lead 122
Mercury 123
Viekel 124
Swleaiiai 125
Silver 126
Th«Uiu» 1.27
Zinc 128
Oar Influent
X
1
2
3
1 27
2
3 26
1
2
3
1 61
2 29
3 42
1 335
2 357
3 241
1 263
2 248
3 202
1 251
2 218
3 324
1
2 1.50
3 0.41
1 204
2 123
3 92
1 U
2 38
3 32
1
2 11
3 11
1
2
3
1 336
2 911
3 357
MriMcr
tffluent
X
28
37
20
20
197
188
140
161
132
106
148
105
141
.
.
0.44
190
89
73
3O
41
-
_
_
-
_
.
-
492
462
449
Secondary
Effluent
X
-
-
39
33
31
56
16
16
37
.
39
1.48
0.41
0.38
90
89
68
.
.
30
_
_
-
.
_
-
122
93
143
Cffluant
X
;
*
IB
16
IS
34
*
32
29
-
38
0.52
1.06
0.51
81
86
69
_
.
35
_
_
-
.
.
-
SB
64
69
Priaexr
Sludge
XX
1250
830
60
86
174
66
12
4
1590
610
180
17900
17900
2870
7800
11200
3300
15700
9000
3800
14
253
46
3220
3400
700
_
6
-
30
80
60
20
30
70
40000
15400
S340
Secondary .
XX
830
210
23
73
76
60
6
10
240
320
310
4080
5560
5140
2500
3300
3000
1200
1500
1600
17
23
20
710
350
750
.
6
9
SO
SO
60
20
-
10
6100
9400
3040
UXMleBE CO
PQTV flUH
Uflnerjr HO.
25
X
30
-
1994
1473
1649
29
26
15
28
26
30
.
•
-
_
_
-
193
322
267
_
~
-
.
-
-
155
119
171
nee o»ot«ot«d
Analyzed by OA-Region IV Laboratory
Analyzed by Pi^wroy, Johnnon and Bailey
B-41
-------
TABLE B-12
Sampling
Location
1. Effluent to POTU fro" gefli
a. No. 13
I). No. 21
c.1 No. 45
d. No. 43 Direct Din
No. 43
e. No. 16
to
| 2. PO1V No. 2
^ a. Influent
M
b. Primary Effluent
c. final Effluent
d. UNOX Influent
e. l«OX Effluent
f . Primary Sludge
g. Digested Sludge
h. Centrate
Day
usry Mo.
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
a
*•'
10.80
10.00
11.42
8.75
8.56
8.65
7.32
6.90
7.13
8.24
7.60
7.29
7.68
7.84
7.52
7.51
7.10
8.13
7.50
7.57
7.51
7.50
7.58
7.51
7.68
7.77
7.55
7.51
7.71
7.20
6.91
6.98
7.OO
6.38
6.OO
»
7.20
7.01
7.59
7.58
S3
84
86
56
20
26
24
22
24
6
14
36
36
58
30
8
29
23
14
390
324
552
82
112
92
188
184
232
78
82
791
7
16
9
43.510
39.220
t
28,210
27.254
t
13,970
Sulfldu.
aa S
o!i
^O.X
Ko.x
^0. X
XO. X
^O.X
Ko, i
^0. J7
^0. X
fo.x**
-------
1 of 2
TABLE B-13
ANALYTICAL RESULTS OF PRIORITY POLLUTANTS FOR THE PRETREATMENT SAMPLING PROGRAM - WEEK 2
VOLATILE ORGANICS (Concentrations, ug/L)
POTW NO. 2
Pollutant
Benzene
Carbon Tetra-
chloride
Chlorobenzene
1 , 2-dichloroethane
ra
1 1,1, l-trichloro-
Oi> ethane
IjO
1 , 1-dichloroe thane
1,1,2, 2-tetrachloro-
e thane
Chloroform
1 , 1-dichloro-
ethylene
1 , 2-trans-dichloro-
ethylene
Poll.
No.
4
6
7
10
11
13
15
23
29
30
Day
**
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
x
Inf.
62
57
24
-
Ill
100
_
_
-
30
-
500
200
535
230
-
-
_
_
-
_
13
11
21
*
30
-
-
-
-
Primary
Eff.
71
67
27
-
-
-
_
-
-
30
19
714
98
95
252
-
_
_
_
-
-
13
14
111
-
-
-
-
_
-
UnoxX
Inf.
79
77
45
-
-
. -
-
-
-
-
_
-
306
159
482
*
-
*
-
-
_
10
12
14
*
-
32
-
_
_
Unoxx
Eff.
*
_
-
-
-
_
-
*
231
370
*
11
-
_
15
14
-
16
-
_
Finalx xx
Eff. Centrate
.
62
31 35
-
_
184
-
-
_
_
14
621 11
-
97
364
_
* 10
51
-
_
12
19
-
-
-
-
-
25
XX
Primary
Sludge
40
130
5
6
-
_
7
-
-
50
30
25
_
_
13
-
-
_
-
_
XX
Digested
Sludge
17
19
-
_
-
_
12
-
-
-
6
12
_
-
_
-
-
-
30
-
Effluent to POTW from Refinery No.
XX X X
Filter 13 21 45X
Cake
(rag/kg)
6 1200 226
* * 240
349 198 319
_ _
_ _
_
_
_ _ _
_ _ _ _
5 -
54 -
* 33 -
- - - -
14
_ * _ _
_
_
_
_
_
_
18 *
9 21 *
* 19 *
-
_
_
_
_
_
43x
Direct 43x 16X
* 380
* 47 140
_
_ _
_
_
* _ -
_
_ _
* _ _
18
24
- - -
15
-
_
_ _
_
_ _
_
_
* _ *
* _ _
*
- - -
_
-
- -
_ _
_
-------
2 of 2
TABLE B-13 (Continued)
ANALYTICAL RESULTS OF PRIORITY POLLUTANTS FOR THE PRETREATMENT SAMPLING PROGRAM - WEEK 2
W
I
VOLATIU5 ORGAMICS (Concentrations, ug/L)
POTW No. 2
Pollutant
1,2-dichloro-
propylene
Ethylbenzene
Methylene Chloride
Dichlorobromo-
me thane
Chlo>-odibromo-
me thane
Tetrachloro-
ethylene
Toluene
Trichloroethylene
Poll.
No.
33
38
44
48
51
85
86
87
Day
**
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
X
Inf.
_
-
-
33
59
53
24
221
37
-
-
-
-
-
-
73
64
63
161
127
61
12
14
12
Primary
Eff.
_
-
-
41
51
46
44
15
14
-
-
-
-
-
-
70
65
61
197
156
72
15
21
12
Unox*
Inf.
_
3
-
31
47
47
67
11
-
-
-
-
*
_
85
67
98
202
174
86
29
26
24
UnoxX Final*
Eff. Eff.
-
-
* 53
48
44
40
-
* -
*
-
-
129
133 76
* _
80
22
* 15
XX
xx Primary
Centrate Sludge
— _
-
70
35 150
(6)* (7)*450
540
-
-
- .
-
9
-
140
65 260
250
380
XX
Digested
Sludge
_
->
55
75
-
6
-
-
-
-
-
-
60(6)
75
-
10
Effluent to POTW from Refinery
XX X X
Filter 13 21
Cake
(mg/kg)
_ _
-
_
25 18000
* *
15 410 220
- *
-
13 - -
_
-
_
-
-
_
-
-
_
35 48000
* *
8 4600 7500
-
-
_
43x
45X Direct 43x
_ _ —
_
-
108
130
76
- - 12
_
-
_
_
-
_
_
-
_
_
-
426 - *
420 - *
457
_
_
-
No.
16X
_
-
383
170
-
-
-
-
-
-
-
-
870
370
-
-
Note: - not detected; * in traces but below detection limit; () sample blank. No volatile organics detected for other sample
blanks; x - analysis performed by West Coast Technical Services; xx - analysis performed by Pomeroy, Johnston s
Bailey; priority pollutants not listed were not detected; **Day 1, 2, S 3 are respectively August 23, 24, and 25
of 1978.
-------
TABLE B-14
ANALYTICAL RESULTS OF PRIORITY POLLUTANTS FOR THE PRETREATMENT SAMPLING PROGRAM - WEEK 2
Cd
I
£»
CD
SEMIVOLATILE ORGANICS (CONCENTRATIONS, ug/1)
Pollutant **
Parachloronetacresol AE
2-Chlorophenol AE
2.4-dlBethylphenol AE
Pentachlorophenol AE
Phenol AE
Acenaphthene BNE
1,2,4-trichloro BNE
benzene
1 , 2-dlchlorobenxene BNE
1,3-dlchlorobenzene BNE
1,4-dlchlorobenzene BNE
2,4-dlnltrotoluene BNE
J ,2-diphenyJhydraline BNE
Poll
No.
22
24
34
64
65
1
8
25
26
27
35
37
Day
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
Inf.*
.
-
-
_
-
-
300
220
720
-
-
-
700
ISO
840
*
-
*
*
-
20
48
27
13
*
20
12
17
20
12
_
-
-
-
-
-
Prt.«
Eff.
_
-
-
-
-
-
_
230
750
-
-
-
840
210
600
*
-
*
29
-
-
57
32
14
*
*
*
17
16
*
_
-
-
-
-
-
POTW No. 2
Filter
Unoxx Unoxx Final* xx Prl.** Dig.** Cake *x
Inf. Eff. Eff. Generate Sludge Sludge (mg/kg)
- _ - -. _
_
96
_
_ _ -
- - -
317 -
210 - 180
470 - 740 - -
_
_ _ -
- _ _
620 7300 470 1900
190 * 160
420 * 660 4600 - 1300
_
_
_ _ _
_
*
_ _ -
24 85 35 30
32 * 12
14 - 22 170 135 245 45
* 55 40 25
* - *
* 21 - - -
12 55 40 25
17 * *
* * 12 140 105 180 40
_
_
_ - -
-
_ _ _
_ - _
Effluent to POTW from Refinery No.
43x
13X 21X 45X Direct 43x 16x
j _ -
_ _ _
_
* - -
_ _ _ _ -
- - -
202 459 - 599 385
1300 430 720 * 9300 250
3600 550 2000 16
_ _ -
- - - - - *
-----
218 4200 - - 944
1100 63 1000 - 14,000 185
2200 119 2200
17 *
18-41 * - -
* *
_ _ -
_ _ -
- - -
_ - _ _
_ _ _
- - -
_ _ _ _
_ _ -
- - - - - -
_ _ _ _ _
_ _ -
- - -
20 -
_ _ _
-
23
- _ _
_
-------
TABLE B-14
Page 2 of 3
ANALYTICAL RESULTS OF PRIOR ITT POLLUTANTS FOR THE FRETREATMENT SAMPLING PROGRAM - WEEK 2
w
I
8EMIVOLATILE ORGANIC8 (CONCENTRATIONS, ug/1)
Pollutant **
Fluorathene BNE
bl8(2-chlorolaopropyl) BNK
ether
bls(2-chloxoethoxy) BNE
•ethane
laophorone BNE
Naphthalene BNE
N-nltroao dlphenyl BNE
aaine
bls(2-ethylhexyl) BNE
phthalate
Butyl benzyl BNE
phthalate
dl-n-butyl phthalate BNE
di-n-octyl phthalate BNE
Poll
No. Day
39 1
2
3
42 1
2
3
43 1
2
3
54 1
2
3
55 1
2
3
62 1
2
3
66 1
2
3
67 1
2
3
68 1
2
3
69 I
2
3
Inf."
—
-
-
_
-
-
_
-
-
-
-
-
28
*
27
-
-
-
13
30
43
_
21
*
*
*
17
_
-
-
Pri.«
Eff.
_
-
-
_
-
-
_
-
-
-
-
-
23
35
25
-
-
-
33
29
23
28
13
14
27
*
11
_
*
-
P01W No. 2
Filter
Unoxx Unoxx Final* xx Prl." Dig." Cake xx
Inf. Eff. Eff. Centrate Sludge Sludge (ag/kg)
_ _ — _ •
_
_ _ _
-
_
_ _ _ _ _
_ _
_
_ - -
_
- - _
- - - -
23 340 70 125
33
16 * 55 480 305 565 90
_
-
- - _
22 440 250 300
17 *
23 14 61 810 - - 250
16 -
10 *
16 13 27 - - -
15 -
* *
* * 22 - - -
* _
*
- _ _
Effluent to P01W
13X 21X 45X
„ _
*
_
_
. _
*
_
_
_ * _
_
12
- - -
285 425
140 91
92 62 170
_
_
-
-
* it *
* * -
_
*
* 10
* *
*
-
-
_
_
from Refinery No.
43x
Direct 43x 16x
_ — _
- - *
-
_
_
-
_
_
-
- _
_
-
- 88
18
-
_
_
41
it *
* *
*
* - *
* it _
*
*
14 *
*
-
_
-
-------
TABLE B-14
ANALYTICAL RESULTS OF PUOUTT POLLUTANTS POt THE PUTREATtBNT SAMPLING PROGRAM - WKEK 2
Page 3 of 3
Pollutant **
dlethyl phthalate BNE
dlattthylphthalate BNB
benco(a)aothracenett BNB
Chryaenett BNE
Acenaphythylene BNE
Anthracenet BNE
Fluorene BNE
Phenanthrenet BNB
Pyrene BNE
Poll
No.
70
71
72
76
11
78
.
80
81
84
Day
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
Inf."
_
*
*
„
-
-
_
-
-
_
-
-
_
-
-
*
*
*
«
-
*
*
*
*
_
-
-
SEN
Prl."
Eff.
10
*
*
*
-
-
_
-
-
_
-
-
_
—
-
•
*
*
_
*
-
*
*
*
*
-
-
IVOLATILE ORGAJIICS (CONCENTRATIONS, ttg/1)
POTW Ho. Z
Filter
Unoxx Unoxx Final" xx Prl." Dig.*" Cake ""
Inf. Eff. Eff. Centrate Sludge Sludge (««/kg)
* 6 14 6 -
* - -
* - * 10 15 6
-. _ _ _ _
*
_ - _
_ _ _ _ _
_ _ _
_ _ _
. — _ _ —
-
_ _ _
_ _ _ _ _
_ — —
* - - - • - - -
* -
* - -
* - » - _ _ _
— — — — —
» - -
- - - -
* - - - -
* - -
* - * - - -
— — _ — —
_ _
_ _ _
Effluent to POTH
13Z
38
-
-
-
*
12
*
12
-
-
36
29
14
*
36
29
*
*
21X 4SX
__ _
12
7
_ _
- -
-
_ _
*
-
_ _
*
-
_ _
~ —
-
* 81
* 39
* 54
_ _
- -
-
* 81
* 39
• 54
_ _
16
*
from Refinery
43x
Direct 43x
* 11
- -
-
_ _
-
-
__ _
* *
*
_ _
* •
*
_
- -
-
* *
- -
*
_ _
-
-
* *
-
*
«
*
-
Ho.
16x
_
-
*
-
_.
-
_
-
_
-
*
-
_
*
*
-
_
*
NOTE: Of 59 »e«tvolatlle», only 31 were detected
* In trace*, but below detection Halt
** AE - Acid Extractable; BNE - Base/neutral Extractable
t Anthracene and Phenanthrene are unresolved
tt Chrysene and Benro (a) anthracene art unresolved
- Not detected
x Sanplea analyzed by Weit Coast Technical Service*
xx Sample* analyzed by Pomeroy, Johnston t Bailey
-------
TABLE B-15
Analytical Results of Priority Pollutants for the Era treatment Sampling Program - Meek 2
Pollutant
Aldrin
Diuldrin
4,4' -DDT
4,4'-DDE
4, 4 '-ODD
A-endosulfan-Alpha
Heptachlor
Cd
I
*? Heptachlor
epoxide
A-BHC-Alpha
B-BHC-beta
R -Bile-Gamma
G-BIIC-Delta
Poll
No.
89
90
92
93
94
95
100
101
102
103
104
105
XX
Day Inf*
1
2
3 3.60
1
2
3
1
2
3 0.11
1
2 0.19
3
1 0.38
2
3
1
2
3 0.12
1 0.47
2
3 0.70
1
2
3
1
2
3 0.88
1
2
3
1
2
3
1 1.25
2
3
Pesticides (Concentrations ,ug/l)
POTH No. 2
„ „„ vl( „„ Effluent to POTW from Refinery No.
Primary Unox* Unox* Final" xx Primary Digested Filter 43^
Eff. Inf Eff Eff Centrate Sludge Sludge Cake 13X 21X 45X Direct Ajx 16X
(»8/kg)
-
-_-_ ______
0.10 - - - - - - 1.0 0.29 0.82
__ ____ _____
- - 0.08 _-_"-__
-__ - - _ __- _ _
0.30 - 4.90
0.17 - . 0.08 - O.O9 -
0.39 - - 0.83
0.09 0.35 --__ __-_
0.11 - - 0.17 - _ - _
0.66 . - 0.17 - - - .--- --
-_ _-__ _____
____ ______
___ _ _ _ ___ __
_- ____ _____
____ ______
0.52 - 0.22 - - - _-_ _-
0.1O 0.45 -_.- -_-_
1.75 _____
-__ _ _ _ __- __
-- -__- _____
--__ ______
2.10 --- - - _ ___ _ o.32
1.30 - - _ _ _ _ o.52
0.24 - 1.5 1.62 - 0.17 0.27 0.36 2.21 0.41
1.20 1.40 0.76 - 0.43 0.08
0.16 0.76 - - - - - --
0.32
--_ _ _ _ ___ -_
0.27 --._ -_._
____ ______
-__ _ _ _ ___ __
0.45 1.50 - - - - - --
____ ______
0.27 -- - - - -_- -_
NOTE: Of the 25 Pesticides, only 12 were found) however, none of them were confirmed by GCMS
not detected
x samples analyzed by West Coast Technical Services
xx samples analyzed by Pomeroy, Johnston and Bailey
-------
TABLE B-16
ANALYTICAL RESULTS FOR PRIORITY POLLUTANTS FOR THE PRETREATMENT SAMPLING PROGRAM - WEEK 2
Page 1 of 2
I
4^
VD
METALS (CONCENTRATIONS,
Ufl/1)
POTW No. 2
Pollutant
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Copper
Lead
Mercury
Nickel
Poll.
No. Day
114 1
2
3
115 1
2
3
117 1
2
3
118 1
2
3
119 1
2
3
120 1
2
3
122 1
2
3
123 1
2
3
124 1
2
3
Influent
X
—
33
-
40
37
66
-
-
-
28
27
28
520
427
573
376
349
529
235
220
254
0.25
0.37
-
399
265
304
Primary
Effluent
X
_
33
-
_
_
-
-
-
-
12
20
13
151
154
164
141
153
176
62
62
70
1.69
0.25
0.49
208
190
228
Unox
Influent
X
_
-
-
26
-
49
-
-
-
13
14
77
162
177
1249
251
162
1019
58
50
277
1.82
0.43
-
220
246
743
Unox
Effluent
X
_
-
-
_
-
-
-
-
-
_
-
-
45
45
50
24
23
25
_
-
-
2.46
-
-
206
236
310
Final
Effluent
X
_
35
-
29
-
-
-
-
-
20
25
26
369
334
456
390
311
341
135
126
168
0.49
-
-
290
272
343
Generate
XX
58
1000
162
196
10
2
580
1040
17100
27600
6900
12300
4200
7600
94
90
3200
6500
Primary
Sludge
XX
1000
1000
324
427
4
10
2020
1200
57000
39600
29000
31000
18600
18200
124
171
6650
6950
Digested
Sludge
XX
625
625
285
297
4
10
1050
1580
29600
42500
13300
19200
10800
15300
232
147
6300
9810
Filter
Cake
xx(mg/kg)
7
13
3
2
0.04
0.07
16
9
461
249
243
173
214
247
1.6
1.5
119
67
Effluent to POTW from Refinery
13
X
—
-
-
27
-
-
-
-
-
_
-
-
1345
845
1133
22
-
-
43
-
-
0.79
0.37
1.08
_
-
-
21
X
—
-
-
_
-
-
_
-
-
^
-
-
747
824
1254
14
17
15
42
36
38
-
-
-
_
-
-
43x
45 Direct
X X
_ _
- -
-
_ _
- -
-
-
- -
-
_ _
-
-
670 233
646 192
603 186
25 10
19
19
33 35
- -
-
0.67
0.46
- -
_
- -
-
43
X
_
-
-
60
67
69
-
-
-
..
-
-
72
70
64
57
47
38
_
-
-
_
-
-
_
27
-
No.
16
X
_
-
-
_
35
34
-
-
-
_
-
-
1644
2196
1800
17
12
14
39
-
36
-
-
-
_
-
-
-------
TABLE B-16
ANALYTICAL RESULTS FOR PRIORITY POLLUTANTS FOR THE PRETRBATMEMT SAMPLING PROGRAM - WEEK 2
METALS (CONCENTRATIONS, ug/1)
Page 2 of 2
P01H Mo. 2
Pollutant
Selenium
Silver
Thallium
Cd Zinc
1
(Ji
0
Poll.
Mo.
125
126
127
128
Day
1
2
3
1
2
3
1
2
3
1
2
3
Influent
X
_
33
37
15
11
13
_
-
-
945
952
1593
Primary
Effluent
X
^
-
-
_
-
-
_
-
-
274
375
385
Unox
Influent
X
35
36
66
_
-
40
_
-
-
232
452
2086
Unox
Effluent
X
_
-
-
_
-
-
_
-
-
144
178
178
Final
Effluent
X
29
37
-
_
a
10
_
-
-
820
810
1027
Centrate
XX
5
5
70
60
20
50
25600
43400
Primary
Slu'ge
XX
5
5
80
100
80
50
69000
52600
Digested
Sludge
XX
6
7
50
90
10
50
47000
70000
Filter
Cake
xx(mg/kg)
0.06
0.06
0.93
1
0.3
0.3
771
457
Effluent to POTW
13
X
101
109
110
_
-
-
_
-
-
190
116
55
21
X
_
33
-
_
-
-
_
-
-
153
173
189
45
X
132
158
140
_
-
-
_
-
-
183
182
174
from Refinery
43x
Direct
X
_
-
-
_
-
-
_
-
-
115
137
158
43
X
248
514
682
_
-
- •
_
-
-
57
49
36
No.
16
X
90
199
149
_
-
-
_
-
-
196
405
398
Notes: - Mot Detected.
x Analyzed by EPA Region IV Laboratory
xx Analyzed by Pomeroy, Johnston and Bailey
Centrate, primary sludge, digested sludge and filter cake were not sampled for on day 3.
-------
APPENDIX C
GLOSSARY AND ABBREVIATIONS
Act; The Federal Water Pollution Control Act, P.L. 92-500,
October 18, 1972. As amended by the Clean Water Act of 1977.
Administrator: Administrator of the U.S. Environmental Protection
Agency whose duties are to administer the Act.
American Petroleum Institute et al. v. EPA, U.S. Court of Appeals
- Tenth Circuit, August 11, 1976. API challenged the regulations
promulgated in 1974. The Court upheld, BPT and NSPS, while
remanding BAT and storm water effluent guidelines.
Appendix A Pollutants; Pollutants listed in Appendix A of the
Settlement Agreement of June 7, 1976.
Best Available Technology Economically Achievable (BATEA or BAT);
Treatment required by July 1, 1983, for industrial discharge to
surface waters as defined by Section 301 (b) (2) (A) of the Act.
Best Conventional Technology Economically Achievable (BCT);
Treatment required by July 1, 1984 for industrial discharge as
defined by Section 301(b)(2)(E) of the Act.
Best Practicable Control Technology Currently Achievable 03PCTCA
or BPT); 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.
Catalyst; A substance that can change the rate of a chemical
reaction but is not involved in the reaction.
Conventional Pollutants; Conventional pollutants are those
defined in Section 304(a)(4) including: biological oxygen
demanding pollutants (BODM, total suspended solids (TSS), fecal
coliforming, and pH, and any additional pollutants defined by the
Administrator as "conventional" (oil and grease).
Data Validation; An operation performed to ensure the accuracy
and reliability of raw input information.
Dependent Variable; A variable whose value is a function of one
or more independent variables.
Direct Discharger; A facility which discharges or may discharge
pollutants into waters of the United States.
C-l
-------
Economics Survey; Survey mailed by the Office of Analysis and
Evaluation of EPA to the petroleum refining industry, pursuant to
Section 308 of the Act requesting data on the economic status of
petroleum refineries.
End-of-Pipe Treatment (Control); Wastewater treatment
technologies that are used after gravity oil separation.
F1ow Model; A mathematical model of the effluent wastewater flow.
Independent Variable; A variable whose value is not dependent on
the value of any other variable.
Indirect Discharger; A facility which discharges or may
discharge pollutants into a publicly owned treatment works.
In-plant Treatment Control; Treatment techniques that are used to
reduce, reuse, recycle, or treat wastewater before end-of-pipe
treatment.
Linear Regression; A method to fit a line through a set of points
so that the sum of squared vertical deviations of the point
values from the fitted line is a minimum; i.e., no other line, no
matter how it is computed, will have a smaller sum of squared
distances between the actual and predicted values of the
dependent variable.
Mathematical Mode1; A quantitative equation or system of
equations formulated so that the structure of a situation and the
relationships among the relevant variables are reasonably
depicted.
Mean Va1ue; The statistical expected or average figure.
Multiple Linear Regression; A method to fit a plane through a set
of points so that the sum of squared distances between the
individual observations and the estimated plane is a minimum.
This statistical technique is an extension of linear regression
in that more than one independent variable is used in the least
squares equation.
Portfolios Aj_ B; The two sections that make up the 1977 U.S. EPA
Petroleum Refining Industry Survey (see "1977 Survey").
Priority Pollutants; Pollutants included in Tables VI-5 and VI-6
of this document.
Process Configuration; A numerical measurement of a refinery's
process complexity that was developed for use in calculating BPT
limitations for this industry.
C-2
-------
Process Factor; A factor that is based on process configuration
and used in calculating BPT Limitations for a particular
petroleum refinery.
Random Process; A procedure that varies according to some
probability function.
Random Variable ; A variable whose values occur according to the
distribution of some probability function.
Regression Statistics; Values generated during a regression
analysis that identify the significance, or reliability, of the
regression-generated figures.
Regression Modelj_ A mathematical model, usually a single
equation, developed using a least squares linear regression
analysis.
Residuals; The differences between the expected and actual values
in a regression analysis.
Settlement Agreement of_ June 7^ 1976; Agreement between the U.S.
Environmental Protection Agency (EPA) and various environmental
groups, as instituted by the United States District Court for the
District of Columbia, directing the EPA to study and promulgate
regulations for a list of chemical substances, referred to as
Appendix A Pollutants.
Significance; A statistical measure of the validity, confidence,
and reliability of a figure.
Size Factor; A factor that is based on a petroleum refinery's
size and used in calculating a petroleum refinery's BPT
limitations.
Sour Waters; Wastewaters containing sulfur compounds, such as
sulfides and mercaptans.
Statistical Stability; A condition in which when a process is
repeated over time, differences occur that are due solely to
random processes.
Statistical Variance; The sum of the squared deviations about the
mean value in proportion to the likelihood of occurrence. A
measure used to identify the dispersion of a set of data.
The 1977 EPA Petroleum Refining Industry Survey (1977 Survey); A
survey mailed pursuant to Section 308 of the Act to 274
refineries on February 11, 1977, and an additional 23 refineries
on August 12, 1977. The survey was issued in two sections,
Portfolio A and Portfolio B, requesting data on various aspects
of process operations, wastewater production, and wastewater
treatment.
C-3
-------
Tolerance Limits; Numerical values identifying the acceptable
range of some variable.
Traditional Pollutant Parameters; Pollutant parameters considered
and used in the development of BPT limitations guidelines. These
parameters include, but are not limited to BOD, COD, TOC, TSS,
and ammonia.
C-4
-------
ABBREVIATIONS
API:
BATEA (BAT):
bbl:
BCTEA (BCT):
BODJ5:
BPCTCA (BPT);
B & R:
COD:
DMR:
EPA:
GC:
Kg/m3:
Ib/bbl:
MS:
MGD:
mg/L:
NPDES:
NSPS:
POTW:
ppb:
PSES:
PSNS:
American Petroleum Institute
Best Available Technology Economically Achievable
Barrel
Best Conventional Technology Economically
Achievable Under Section 304(b)(4) of the Act.
Five Day Biochemical Oxygen Demand
Best Practicable Control Technology Currently
Available Under Section 304(b)(1) of the Act.
Burns and Roe
Chemical Oxygen Demand
Discharge Monitoring Report
U.S. Environmental Protection Agency
Gas Chromatography
Kilograms Per Cubic Meter
Pounds Per Barrel (One Barrel Equals 42 Gallons)
Mass Spectrometry
Million Gallons Per Day
Milligrams Per Liter
National Pollutant Discharge Elimination System
Permit Issued Under Section 402 of the Act.
New Source Performance Standards Under Section 306
of the Act.
Publicly Owned Treatment Works
Parts Per Billion
Pretreatment Standards for New Sources of Indirect
Discharges Under Section 307(b) of the Act.
Pretreatment Standards for New Sources of Indirect
Discharges Under Section 307(b) of the Act.
C-5
-------
ABBREVIATIONS
(Continued)
RCRA:
RSKERL:
S & A:
SPSS:
TOG:
TSS:
ug/L:
Resources Conservation and Recovery Act (P.L.
94-580) of 1978f Amendments to Solid Waste
Disposal Act.
Robert S. Kerr Environmental Research Laboratory
Surveillance and Analysis
Statistical Package"for the Social Sciences
Total Organic Carbon
Total Suspended Solids
Micrograms Per Liter
*U.S. GOVERNMENT PRINTING OFFICE : 1982 0-381-085/4-492
C-6
------- |