STUDY OF SELECTED

PETROLEUM REFINING RESIDUALS

INDUSTRY STUDY

Part 1

August 1996

U.S. ENVIRONMENTAL PROTECTION AGENCY

Office of Solid Waste
Hazardous Waste Identification Division
401 M Street, SW
Washington, DC 20460
 TABLE OF CONTENTS Page Number

1.0 INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.1 BACKGROUND . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.2 OTHER EPA REGULATORY PROGRAMS IMPACTING THE
PETROLEUM REFINING INDUSTRY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
1.3 INDUSTRY STUDY FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

2.0 INDUSTRY DESCRIPTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

2.1 PETROLEUM REFINING INDUSTRY PROFILE . . . . . . . . . . . . . . . . . . . . . 8
2.2 INDUSTRY STUDY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
2.2.1 Site Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
2.2.2 Engineering Site Visits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
2.2.3 RCRA §3007 Questionnaire . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
2.2.4 Familiarization Sampling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
2.2.5 Record Sampling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
2.2.6 Split Samples Analyzed by API . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
2.2.7 Synthesis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

3.0 PROCESS AND WASTE DESCRIPTIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

3.1 REFINERY PROCESS OVERVIEW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
3.2 CRUDE OIL DESALTING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
3.2.1 Process Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
3.2.2 Desalting Sludge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
3.3 HYDROCRACKING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
3.3.1 Process Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
3.3.2 Spent Hydrocracking Catalyst . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
3.4 ISOMERIZATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
3.4.1 Isomerization Process Description . . . . . . . . . . . . . . . . . . . . . . . . . . 43
3.4.2 Isomerization Catalyst . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
3.4.3 Isomerization Treating Clay . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
3.5 EXTRACTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58
3.5.1 Extraction Process Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58
3.5.2 Extraction Treating Clay . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
3.6 ALKYLATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66
3.6.1 Sulfuric Acid Alkylation Process Description . . . . . . . . . . . . . . . . . 66
3.6.2 Hydrofluoric Acid Alkylation Process Description . . . . . . . . . . . . . 67
3.6.3 Spent Treating Clay from Alkylation . . . . . . . . . . . . . . . . . . . . . . . 69
3.6.4 Catalyst from Hydrofluoric Acid Alkylation . . . . . . . . . . . . . . . . . . 75
3.6.5 Acid Soluble Oil from Hydrofluoric Acid Alkylation . . . . . . . . . . . 77
3.7 POLYMERIZATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
3.7.1 Process Descriptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
3.7.2 Spent Phosphoric Acid Polymerization Catalyst . . . . . . . . . . . . . . . 84
3.7.3 Spent Dimersol Polymerization Catalyst . . . . . . . . . . . . . . . . . . . . . 87
3.8 RESIDUAL UPGRADING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
3.8.1 Process Descriptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
3.8.2 Off-specification Product from Residual Upgrading . . . . . . . . . . . . 96

Petroleum Refining Industry Study 2 August 1996

 3.8.3 Process Sludge from Residual Upgrading . . . . . . . . . . . . . . . . . . . . 97
3.9 LUBE OIL PROCESSING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103
3.9.1 Process Descriptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103
3.9.2 Treating Clay from Lube Oil Processing . . . . . . . . . . . . . . . . . . . . . 107
3.10 H2S REMOVAL AND SULFUR COMPLEX . . . . . . . . . . . . . . . . . . . . . . . . 112
3.10.1 Process Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112
3.10.2 Off-Specification Product from Sulfur Complex and H2S
Removal Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117
3.10.3 Off-Specification Treating Solution from Sulfur Complex and
H2S Removal Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124
3.11 CLAY FILTERING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132
3.11.1 Process Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132
3.11.2 Treating Clay from Clay Filtering . . . . . . . . . . . . . . . . . . . . . . . . . . 134
3.12 RESIDUAL OIL TANK STORAGE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142
3.12.1 Residual Oil Storage Tank Sludge . . . . . . . . . . . . . . . . . . . . . . . . . . 142

Petroleum Refining Industry Study 3 August 1996

 LIST OF TABLES Page Number

Table 1.1. Petroleum Refining Residuals Identified in the EDF/EPA

Consent Decree . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Table 1.2. Overview of 15 Study Residuals of Concern as Managed in 1992 . . . . . . . . . . 5
Table 2.1. Engineering Site Visit Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Table 2.2. Study Residuals Volume Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Table 2.3. Residuals Collected for Record Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Table 2.4. Descriptions of Samples Collected for Record Analysis . . . . . . . . . . . . . . . . 17
Table 3.2.1. Generation Statistics for Desalting Sludge, 1992 . . . . . . . . . . . . . . . . . . . . . . 27
Table 3.2.2. Desalter Sludge: Physical Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Table 3.2.3. Desalting Sludge Record Sampling Locations . . . . . . . . . . . . . . . . . . . . . . . . 30
Table 3.2.4. Desalting Sludge Characterization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Table 3.3.1. Generation Statistics for Hydrocracking Catalyst, 1992 . . . . . . . . . . . . . . . . . 37
Table 3.3.2. Hydrocracking Catalyst Physical Properties . . . . . . . . . . . . . . . . . . . . . . . . . 38
Table 3.3.3. Spent Hydrocracking Catalyst Record Sampling Locations . . . . . . . . . . . . . . 39
Table 3.3.4. Spent Hydrocracking Catalyst Characterization . . . . . . . . . . . . . . . . . . . . . . . 40
Table 3.4.1. Generation Statistics for Catalyst from Isomerization, 1992 . . . . . . . . . . . . . 48
Table 3.4.2. Catalyst from Isomerization: Physical Properties . . . . . . . . . . . . . . . . . . . . . 49
Table 3.4.3. Spent Isomerization Catalyst Record Sampling Locations . . . . . . . . . . . . . . . 49
Table 3.4.4. Residual Characterization Data for Spent Isomerization Catalyst . . . . . . . . . 51
Table 3.4.5. Generation Statistics for Treating Clay from Isomerization, 1992 . . . . . . . . . 55
Table 3.4.6. Treating Clay from Isomerization: Physical Properties . . . . . . . . . . . . . . . . . 57
Table 3.4.7. Isomerization Spent Sorbent Record Sampling Locations . . . . . . . . . . . . . . . 57
Table 3.5.1. Generation Statistics for Treating Clay from Extraction, 1992 . . . . . . . . . . . 61
Table 3.5.2. Treating Clay from Extraction: Physical Properties . . . . . . . . . . . . . . . . . . . 63
Table 3.5.3. Extraction Spent Sorbent Record Sampling Locations . . . . . . . . . . . . . . . . . 63
Table 3.5.4. Residual Characterization Data for Spent Treating Clay from
Extraction/Isomerization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64
Table 3.6.1. Generation Statistics for Treating Clay from Alkylation, 1992 . . . . . . . . . . . 70
Table 3.6.2. Treating Clay from Alkylation: Physical Properties . . . . . . . . . . . . . . . . . . . 72
Table 3.6.3. Alkylation Treating Clay Record Sampling Locations . . . . . . . . . . . . . . . . . . 72
Table 3.6.4. Alkylation Treating Clay Characterization . . . . . . . . . . . . . . . . . . . . . . . . . . 73
Table 3.6.5. Generation Statistics for Catalyst from HF Alkylation, 1992 . . . . . . . . . . . . . 76
Table 3.6.6. Catalyst from HF Alkylation: Physical Properties . . . . . . . . . . . . . . . . . . . . 76
Table 3.6.7. Generation Statistics for Acid Soluble Oil, 1992 . . . . . . . . . . . . . . . . . . . . . . 78
Table 3.6.8. Acid Soluble Oil: Physical Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79
Table 3.6.9. Acid Soluble Oil Record Sampling Locations . . . . . . . . . . . . . . . . . . . . . . . . 79
Table 3.6.10. Acid Soluble Oil Characterization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80
Table 3.7.1. Generation Statistics for Phosphoric Acid Catalyst from
Polymerization, 1992 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85
Table 3.7.2. Phosphoric Acid Catalyst from Polymerization: Physical
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86
Table 3.7.3. Phosphoric Acid Polymerization Catalyst Record Sampling
Locations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86
Table 3.7.4. Generation Statistics for Spent Dimersol Polymerization
Catalyst, 1992 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88

Petroleum Refining Industry Study 4 August 1996

Table 3.7.5. Spent Dimersol Polymerization Catalyst Physical Properties . . . . . . . . . . . . . 89
Table 3.7.6. Dimersol Polymerization Catalyst Record Sampling Locations . . . . . . . . . . . 89
Table 3.7.7. Polymerization Catalyst Characterization . . . . . . . . . . . . . . . . . . . . . . . . . . . 90
Table 3.8.1. Generation Statistics for Off-Specification Product from Residual
Upgrading, 1992 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96
Table 3.8.2. Off-Specification Product from Residual Upgrading: Physical
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97
Table 3.8.3. Generation Statistics for Process Sludge from Residual
Upgrading, 1992 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98
Table 3.8.4. Process Sludge from Residual Upgrading: Physical Properties . . . . . . . . . . . 100
Table 3.8.5. Process Sludge from Residual Upgrading Record Sampling
Locations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100
Table 3.8.6. Process Sludge from Residual Upgrading Characterization . . . . . . . . . . . . . . 101
Table 3.9.1. Generation Statistics for Treating Clay from Lube Oil, 1992 . . . . . . . . . . . . 108
Table 3.9.2. Treating Clay from Lube Oil: Physical Properties . . . . . . . . . . . . . . . . . . . . 109
Table 3.9.3. Treating Clay from Lube Oil Processing Record Sampling
Locations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109
Table 3.9.4. Treating Clay from Lube Oil Processing Characterization . . . . . . . . . . . . . . . 110
Table 3.10.1. Sulfur Removal Technologies Reported in RCRA §3007
Questionnaire . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112
Table 3.10.2. Generation Statistics for Off-Spec Sulfur, 1992 . . . . . . . . . . . . . . . . . . . . . . 119
Table 3.10.3. Off-Specification Sulfur: Physical Properties . . . . . . . . . . . . . . . . . . . . . . . . 121
Table 3.10.4. Off-Specification Sulfur Record Sampling Locations . . . . . . . . . . . . . . . . . . 121
Table 3.10.5. Residual Characterization Data for Off-Specification Sulfur . . . . . . . . . . . . . 122
Table 3.10.6. Generation Statistics for Spent Amine for H2S Removal, 1992 . . . . . . . . . . . 125
Table 3.10.7. Generation Statistics for Stretford Solution for H2S Removal,
1992 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126
Table 3.10.8. Spent Amine: Physical Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127
Table 3.10.9. Spent Stretford Solution: Physical Properties . . . . . . . . . . . . . . . . . . . . . . . . 128
Table 3.10.10. Off-Specification Treating Solution Record Sampling Locations . . . . . . . . . 128
Table 3.10.11. Characterization Data for Off-Specification Treating Solution
from Sulfur Complex and H2S Removal . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130
Table 3.11.1. Generation Statistics for Treating Clay from Clay Filtering, 1992 . . . . . . . . . 136
Table 3.11.2. Treating Clay from Clay Filtering: Physical Properties . . . . . . . . . . . . . . . . 137
Table 3.11.3. Treating Clay Record Sampling Locations . . . . . . . . . . . . . . . . . . . . . . . . . . 137
Table 3.11.4. Residual Characterization Data for Treating Clay . . . . . . . . . . . . . . . . . . . . . 139
Table 3.12.1. Generation Statistics for Residual Oil Tank Sludge, 1992 . . . . . . . . . . . . . . . 144
Table 3.12.2. Residual Oil Tank Sludge: Physical Properties . . . . . . . . . . . . . . . . . . . . . . . 146
Table 3.12.3. Residual Oil Tank Sludge Record Sampling Locations . . . . . . . . . . . . . . . . . 146
Table 3.12.4. Residual Oil Tank Sludge Characterization . . . . . . . . . . . . . . . . . . . . . . . . . . 147

Petroleum Refining Industry Study 5 August 1996

 LIST OF FIGURES Page Number

Figure 2.1. Geographical Distribution of U.S. Refineries . . . . . . . . . . . . . . . . . . . . . . . . . 9

Figure 3.1. Simplified Refinery Process Flow Diagram . . . . . . . . . . . . . . . . . . . . . . . . . 22
Figure 3.2.1. Desalting Process Flow Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Figure 3.3.1. Hydrocracking Process Flow Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
Figure 3.4.1. Isomerization Process Flow Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
Figure 3.5.1. Extraction Process Flow Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58
Figure 3.6.1. H2SO4 Alkylation Process Flow Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . 66
Figure 3.6.2. HF Alkylation Process Flow Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68
Figure 3.7.1. Process Flow Diagram for Phosphoric Acid Polymerization
Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83
Figure 3.7.2. Dimersol Polymerization Process Flow Diagram . . . . . . . . . . . . . . . . . . . . . 84
Figure 3.8.1. Solvent Deasphalting Process Flow Diagram . . . . . . . . . . . . . . . . . . . . . . . . 93
Figure 3.8.2. Asphalt Oxidation Process Flow Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . 94
Figure 3.8.3. Supercritical Extraction Process Flow Diagram . . . . . . . . . . . . . . . . . . . . . . 95
Figure 3.9.1. Lube Oil Processing Flow Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104
Figure 3.10.1. Amine Sulfur Removal Process Flow Diagram . . . . . . . . . . . . . . . . . . . . . . . 113
Figure 3.10.2. Claus Sulfur Recovery Process Flow Diagram . . . . . . . . . . . . . . . . . . . . . . . 114
Figure 3.10.3. SCOT® Tail Gas Sulfur Removal Process Flow Diagram . . . . . . . . . . . . . . . 115

Petroleum Refining Industry Study 6 August 1996

1.0 INTRODUCTION

1.1 BACKGROUND

The U.S. Environmental Protection Agency (EPA) is directed in section 3001(e)(2) of

the Resource Conservation and Recovery Act (RCRA) (42 U.S.C. §6921 (e)(2)) to determine
whether to list as hazardous wastes a number of different wastes including those of the
petroleum refining industry. A lawsuit by the Environmental Defense Fund (EDF) in 1989
resulted in a consent decree approved by the court, that sets out an extensive series of deadlines
for making the listing determinations required by Section 3001 (e)(2). The deadlines include
those for making final listing determinations as well as for concluding various related studies or
reports on the industries of concern. With respect to the refining industry, the consent decree
identifies 14 specific residuals for which the Agency must make listing determinations and an
additional 15 residuals for which the Agency must conduct a study. These 29 residuals,
subsequently referred to as the Residuals of Concern (RCs), are listed in Table 1.1. As a result
of the consent decree, the Agency embarked on a project to determine whether these 29 RCs
pose a threat to human health and the environment and to develop a basis for making such a
determination. As a result of the preliminary evaluation of the waste subject to the listing
determination, EPA proposed a rule in which eleven wastes were not to be listed and three
wastes were to be listed as hazardous wastes: K169, K170, and K171 (clarified slurry oil storage
tank sediments and/or filter/separation solids from catalytic cracking, catalyst from
hydrotreating, and catalyst from hydrorefining, respectively) (60 FR 57747, November 20,
1995). The final determination will be issued under the applicable terms of the consent decree.
This report is the result of the Agency's study of the remaining 15 residuals.

The Petroleum Refining Industry was previously studied by OSW in the 1980s. This
original effort involved sampling and analysis of a number of residuals at 19 sites, distribution of
a RCRA §3007 questionnaire to 180 refineries (characterizing the industry as of 1983), and,
ultimately, a listing determination effort focused on wastewater treatment sludges, culminating
in the promulgation of hazardous waste listings F037 and F038 (respectively, primary and
secondary oil/water/solids separation sludges from petroleum refining).

As part of the Agency's current investigation of residuals from petroleum refining, the
Agency conducted engineering site visits at 20 refineries to gain an understanding of the present
state of the industry. These 20 refineries were randomly selected from the 185 refineries
operating in the continental United States in 1992. Familiarization samples of various residuals
were collected at 3 of the 20 refineries to obtain data on the nature of the RCs and to identify
potential problems with respect to future analysis. The Agency then conducted record sampling
and analysis of the RCs. During the record sampling timeframe, an additional 6 facilities were
randomly selected to increase sample availability. Approximately 100 record samples were
collected and analyzed. Concurrently, the Agency developed, distributed and evaluated a RCRA
§3007 survey to the 180 refineries in the U.S.

Petroleum Refining Industry Study 1 August 1996

 Table 1.1. Petroleum Refining Residuals Identified in the EDF/EPA Consent Decree

Listing Residuals

Clarified slurry oil sludge from catalytic cracking

Unleaded storage tank sludge
Crude storage tank sludge
Process sludge from sulfur complex and H2S removal facilities (sulfur complex sludge)
Sludge from HF alkylation
Sludge from H2SO4 alkylation
Catalyst from catalytic hydrotreating
Catalyst from catalytic reforming
Catalyst and fines from catalytic cracking (FCC catalyst and FCC fines)
Catalyst from catalytic hydrorefining
Catalyst from H2SO4 alkylation
Catalyst from sulfur complex and H2S removal facilities (Claus and tail gas treating catalysts)
Off-spec product and fines from thermal processes (Off-spec coke and fines)
Spent caustic from liquid treating

Study Residuals

Desalting sludge from crude desalting

Residual oil storage tank sludge
Process sludge from residual upgrading
Catalyst from extraction/isomerization processes*
Catalyst from catalytic hydrocracking
Catalyst from polymerization
Catalyst from HF alkylation
Off-spec product and fines from residual upgrading
Off-spec product from sulfur complex and H2S removal facilities (Off-spec sulfur)
Off-spec treating solution from sulfur complex and H2S removal facilities (Spent amine and spent
Stretford solution)
Acid-soluble oil from HF alkylation (ASO)
Treating clay from clay filtering
Treating clay from lube oil processing
Treating clay from the extraction/isomerization process
Treating clay from alkylation

*As described in Section 3.5 Extraction, catalyst used for extraction does not exist. The Agency believes it has been
classified as a residual of concern inappropriately based on erroneous old data. Therefore, only catalyst from
isomerization will be discussed in this study.

1.2 OTHER EPA REGULATORY PROGRAMS IMPACTING THE PETROLEUM

REFINING INDUSTRY

Each of EPA's major program offices has long-standing regulatory controls tailored to
the petroleum refining industry. Some of the more significant programs with some relevance to
OSW's listing determinations and industry study include:

• The Clean Air Act's Benzene National Emissions Standards for Hazardous Air
Pollutants (NESHAPS), designed to control benzene releases from process and waste
management units.

Petroleum Refining Industry Study 2 August 1996

 • The Clean Air Act's National Ambient Air Quality Standards (NAAQS), which
prescribe limits for sulfur oxides (SOx), carbon monoxide (CO), particulates, nitrogen
oxides (NOx), volatile organic compounds (VOCs), and ozone.

• The Clean Air Act's NESHAPs for Petroleum Refineries (40 CFR Part 63, Subpart
CC, see 60 FR 43244, August 18, 1995), designed to control hazardous air pollutants
(HAPs).

• The Clean Water Act sets specific technology-based limits and water quality-based
standards for discharges to surface waters and publically-owned treatment works
(POTWs) including standards designed specifically for discharges from the petroleum
refining industry.

• The Toxicity Characteristic, particularly for benzene, in combination with the F037/
F038 sludge listings, has had a significant impact on the industry's wastewater
treatment operations, forcing closure of many impoundments and redesign of tank-
based treatment systems.

• The Land Disposal Restrictions (LDR) Program, including the ongoing Phase III and
IV development work.

1.3 INDUSTRY STUDY FINDINGS

This document describes EPA's approach to conducting the industry study required by
the EDF/EPA consent decree. The consent decree requires that EPA “fully characterize” the
study residuals and how they are managed. “The report shall include a discussion of the
concentration of toxic constituents in each waste, the volume of each waste generated, and the
management practices for each waste (including plausible mismanagement practices).”

The statutory definition of “hazardous waste” is waste that may cause harm or pose a
hazard to human health or the environment “when improperly treated, stored, transported, or
disposed of, or otherwise managed.”

To implement this section of the statute, EPA considers available information on current
management practices, and also exercises judgment as to plausible ways the waste could be
managed in addition to those practices actually reported. EPA then judges which management
practices have the potential to pose the greatest risk to human health or the environment and
those practices would be assessed in a risk assessment.

As EPA explained in the preamble to the dyes and pigments proposed listing [59 FR
66072], EPA generally assumes that placement in an unlined landfill is a reasonably plausible
management scenario for solids that potentially poses significant risks and thus would be
“mismanagement” that should be examined by further risk assessment. For liquid wastes,
unlined surface impoundments are such a presumptive mismanagement scenario. In past risk
assessment work, EPA has found that these two scenarios are generally the scenarios most likely
to pose a risk to ground water and thus would be mismanagement scenarios for a hazardous
waste. In some cases, EPA has also found it appropriate to examine waste piles for solids prone

Petroleum Refining Industry Study 3 August 1996

to transport by wind or erosion and to look at an aerated tank for volatile hazardous constituents
in waste waters.

EPA also considers other scenarios, such as land application without Federal regulatory
controls, as possible mismanagement scenarios and, where there is evidence that such practices
occur for a particular waste stream, would consider whether further evaluation is appropriate. If
EPA determines that a presumptive mismanagement scenario, such as disposal in an unlined
surface impoundment, does not occur and would not reasonably be expected to occur, EPA may
consider it implausible and instead use a more likely scenario as the plausible mismanagement
scenario for subsequent analysis.

In the recent proposal to list petroleum residuals, EPA found the following waste
management practices to pose the greatest risk and be the basis for judging whether these wastes
posed a potential risk to human health or the environment when mismanaged:

• Unlined landfills
• Unlined surface impoundments
• Land application units not subject to Federal regulations

With respect to the residuals in this study, EPA found that the following management
practices and their associated residuals (see Table 1.2) were reported and thus would be
mismanagement scenarios EPA would further evaluate to ascertain if there were a potential risk:

• Unlined landfills

- Residual oil storage tank sludge

- Process sludge from residual upgrading
- Catalyst from catalytic hydrocracking
- Catalyst from polymerization
- Off-spec product from sulfur complex and H2S removal facilities (off-spec sulfur)
- Off-spec treating solution from sulfur complex and H2S removal facilities (spent
amine and spent Stretford solution)

Petroleum Refining Industry Study 4 August 1996

 Table 1.2. Overview of 15 Study Residuals of Concern as Managed in 1992
Petroleum Refining Industry Study

Residuals of Concern: Study Residuals

ASO Isom HF Polymer Desalting Hydro- Off-spec Off-spec Sludge Resid Oil Off-spec Treating Treating Treat Clay Treating TOTALS Percent
Catalystt Catalyst Catalyst Sludge Cracking Prod. Resid Sulfur Resid Tank Treating Clay Clay Isom/ Clay from of Total
Catalyst Upgrading Product Upgrad Sludge Solution Alkylation Clay Filter Extract Lube Oil
Management Practice mt mt mt mt mt mt mt mt mt mt mt mt mt mt mt MT
DISPOSAL
Disposal offsite Subtitle D landfill 1,429 29 1,593 5,043 138 6,458 200 634 3,641 937 37 20,138 16.8%
Disposal offsite Subtitle C landfill 44 65 221 992 3,576 0 622 39 24 1,735 516 79 7,913 6.6%
Disposal onsite Subtitle C landfill 349 289 62 4 67 52 58 5 886 0.7%
Disposal onsite Subtitle D landfill 256 102 226 7 30 711 626 1,032 496 3,485 2.9%
Disposal onsite or offsite underground injection 2 673 675 0.6%
Storage or disposal onsite surface impoundment 0 132 1 133 0.1%
Other disposal onsite/roadbed mixing 0 4 16 138 158 0.1%
Use as cover in onsite landfill 7 7 0.0%
Use as cap for onsite landfarm, fill material, or vent 20 20 0.0%
TOTAL DISPOSED 0 44 0 2,099 354 2,584 0 9,133 207 7,254 1,624 1,355 6,497 2,145 120 33,417 27.9%
DISCHARGED
Discharge to onsite wastewater treatment facility 1,258 128 3 47 205 0 7 1,648 1.4%
Discharge to POTW 647 1 0 648 0.5%
Discharge to surface water under NPDES 3,600 152 1,266 6,849 507 12,374 10.3%
Discharge to offsite POTW 1,566 1,566 1.3%
TOTAL DISCHARGED 3,600 0 152 0 1,913 0 0 0 1 0 8,415 0 507 0 0 14,588 12.2%
RECOVERED, RECYCLED, REUSED, REGENERATED
5

Metals Reclamation
Transfer metal catalyst for reclamation or regeneration 293 13,185 5,127 91 89 33 18,819 15.7%
Recycle to Processes
Recovery onsite via distillation, coker, or cat cracker 50 0 16 310 376 0.3%
Onsite reuse 20 20 0.0%
Other recycling, reclamation or reuse/sulfur recov. unit 2 13 15 0.0%
Recovery onsite in catalytic cracker 3,641 0 1,150 4,791 4.0%
Recovery onsite in coker 1,019 749 52 0 20 1,840 1.5%
Other recovery onsite/alky 1,300 1,300 1.1%
Other recovery onsite/hydroprocessing 510 510 0.4%
Other recovery onsite/reuse in extraction process 800 800 0.7%
Miscellaneous On-site Recycling
Reuse onsite as replacement catalyst for another unit 159 159 0.1%
Other recovery onsite 370 354 724 0.6%
Other recycling, reclamation or reuse/offsite reuse 30 38 68 0.1%
Other recycling, reclamation or reuse/cement plant 771 161 28 249 1,210 1.0%
TOTAL RECYCLED 6,890 293 0 749 52 13,345 800 2 16 310 6,290 892 329 62 603 30,633 25.6%
STORAGE
Storage in pile 0 30 128 20 178 0.1%
TOTAL STORED (interim) 0 0 0 0 0 0 0 0 0 0 0 30 128 20 0 178 0.1%
August 1996
 Table 1.2. Overview of 15 Study Residuals of Concern as Managed in 1992 (continued)
Petroleum Refining Industry Study

Residuals of Concern: Study Residuals

ASO Isom HF Polymer Desalting Hydro- Off-spec Off-spec Sludge Resid Oil Off-spec Treating Treating Treat Clay Treating TOTALS Percent
Catalystt Catalyst Catalyst Sludge Cracking Prod. Resid Sulfur Resid Tank Treating Clay Clay Isom/ Clay from of Total
Catalyst Upgrading Product Upgrad Sludge Solution Alkylation Clay Filter Extract Lube Oil
Management Practice mt mt mt mt mt mt mt mt mt mt mt mt mt mt mt MT
TRANSFER
Transfer of acid or caustic for recycle, reuse, reclamation 2,475
Transfer for use as ingredient in products placed on land 543 15 35 176 768 0.6%
Transfer to N.O.S. offsite entity and final management 0 0 14 14 0.0%
Transfer to another petroleum refinery 2,100 927 3,027 2.5%
Transfer for direct use as a fuel or to make a fuel 741 1,938 95 2,773 2.3%
Transfer with coke product or other refinery product 3,731 7 5 5 3,747 3.1%
Transfer to other offsite entity/carbon regeneration 54 54 0.0%
Transfer to other offsite entity/amine reclaimer 166 166 0.1%
Transfer to other offsite entity/alumina manufacturer 405 405 0.3%
Transfer to other offsite entity/smelter 155 155 0.1%
Transfer to other offsite entity/used as a raw material feed 488 488 0.4%
TOTAL TRANSFERRED 4,472 0 0 543 1,938 2,100 0 509 5 962 2,641 560 329 14 0 14,073 11.8%
TREATMENT
Evaporation* 8 8 0
Bioremediation* 21 21 0
Neutralization 11,388 0 0 0 11,388 9.5%
Offsite incineration, stabilization, or reuse 0 0 56 1 9 42 108 0.1%
6

Onsite boiler 2,610 9 2,619 2.2%

Onsite industrial furnace 3,274 3,274 2.7%
Onsite land treatment 728 346 530 59 923 231 10 2,827 2.4%
Offsite land treatment 53 1 4 198 256 0.2%
TOTAL TREATED (interim) 17,272 0 0 728 455 0 0 2 9 534 9 59 1,193 231 10 20,502 17.1%
GRAND TOTAL 33,493 337 152 4,119 4,841 18,029 800 9,647 242 9,107 23,881 2,895 8,990 2,471 733 119,738
28.0% 0.3% 0.1% 3.4% 4.0% 15.1% 0.7% 8.1% 0.2% 7.6% 19.9% 2.4% 7.5% 2.1% 0.6%

* To avoid double counting, these intermediate steps were not included in the total.
August 1996
 - Treating clay from clay filtering
- Treating clay from lube oil processing
- Treating clay from the extraction/isomerization process
- Treating clay from alkylation

• Unlined surface impoundments

- Residual oil storage tank sludge

- Off-spec treating solution from sulfur complex and H2S removal facilities (spent
amine and spent Stretford solution)

• Land application not subject to Federal regulations

- Residual oil storage tank sludge

- Catalyst from polymerization
- Off-spec product from sulfur complex and H2S removal facilities (off-spec sulfur)
- Treating clay from clay filtering
- Treating clay from lube oil processing
- Treating clay from the extraction/isomerization process
- Treating clay from alkylation

In addition, EPA found that the management practice of mixing of treating clays with
roadbed materials for onsite use was reported and would merit evaluation as a potential
mismanagement scenario.

Section 2.0 provides an overview of the petroleum refining industry and EPA's approach
to this study. The fifteen study residuals identified in the consent decree accounted for
approximately 120,000 metric tons in 1992, compared to over 3.1 million metric tons of listing
residuals generated in 1992. Table 1.2 provides a description of the 15 study residuals by
management practice and volume generated. The Agency believes that the management
practices reported consist of virtually all of the plausible management practices to which the
residuals may be subjected. Section 3.0 describes the refinery processes associated with
generating the consent decree residuals of concern and detailed characterization of each of the
study residuals as required by the consent decree.

Petroleum Refining Industry Study 7 August 1996

2.0 INDUSTRY DESCRIPTION

2.1 PETROLEUM REFINING INDUSTRY PROFILE

In 19921, the U.S. petroleum refining industry consisted of 185 refineries (of which 171
were fully active during the year) owned by 91 corporations. Atmospheric crude oil distillation
capacity totaled 15,120,630 barrels per calendar day (bpcd) (DOE, 1993). As of January 1,
1996, U.S. capacity totaled 15,341,000 bpcd, showing little change in the Nation's refining
capacity since the Agency's baseline year. Figure 2.1 illustrates the distribution of refineries
across the country. Refineries can be classified in terms of size and complexity of operations.
Forty-four percent of the refineries operating in 1992 processed less than 50,000 barrels per day
of crude, while the 20 largest companies account for 77 percent of the nation's total refining
capacity.

The simplest refineries use distillation to separate gasoline or lube oil fractions from
crude, leaving the further refining of their residuum to other refineries or for use in asphalt.
Approximately 18 percent of the U.S.'s refineries are these simple topping, asphalt, or lube oil
refineries. More sophisticated refineries will have thermal and/or catalytic cracking capabilities,
allowing them to extract a greater fraction of gasoline blending stocks from their crude. The
largest refineries are often integrated with chemical plants, and utilize the full range of catalytic
cracking, hydroprocessing, alkylation and thermal processes to optimize their crude utilization.
Section 3.1 describes the major unit operations typically found in refining operations.

The refining industry has undergone significant restructuring over the past 15 years.
Much of this restructuring has been in response to the price allocation programs of the 1970s and
industry deregulation in the 1980s. While the total national refining capacity dropped 17 percent
since 1980 to 15 million barrels per day, the number of refineries dropped 45 percent from 311
in 1980 to approximately 171 active in 1992 (and 169 as of 1/1/96). Refinery utilization rates
over the 1980 to 1992 period rose from 75 percent to 90 percent. (API, 1993). Very few new
refineries have been constructed in the past decade; the industry instead tends to focus on
expansions of existing plants.

The facilities closed tended to be smaller, inefficient refineries. Larger existing facilities
with capacities over 100,000 bbl/day have increased production to off-set the facility closings.

The data presented above indicates that the petroleum refining industry has been going
through a consolidation, which has resulted in a large decrease in the number of refineries in the
United States, but only a slight decrease in production. It is expected that this trend will

1
The Agency conducted its industry-wide survey in 1993-1994, characterizing residual generation in 1992.
Thus, 1992 was considered the Agency's baseline year. The Agency has no reason to conclude that 1992 was not
representative of industry management practices. EPA’s risk assessment modeling used as input the 1992 data for the
RCs as a “snap shot” of the industry’s management practices. However, information for years other than 1992 is
provided in the pertinent sections of the study.

Petroleum Refining Industry Study 8 August 1996

Figure 2.1. Geographical Distribution of U.S. Refineries
Figure 2.1. Geographical Distribution of U.S. Refineries

Petroleum Refining Industry Study 9 August 1996

continue, with refineries continuing to close, but expansions occurring at others, keeping the
total refinery capacity in line with demand for refinery products.

In addition to restructuring, the industry is adding and changing production operations.

Many of these process changes are being implemented as a result of two factors: (1) today's
crudes tend to be heavier and contain higher levels of sulfur and metals, requiring process
modifications, and (2) a series of important pollution control regulations have been
implemented, including new gasoline reformulation rules designed to reduce the amount of
volatile components in gasoline, and new regulations requiring low-sulfur diesel fuels. These
heavier crudes and new rules have caused refineries to make process modifications to their
gasoline production units such as catalytic cracker units, installing additional sulfur removal
hydrotreaters, and constructing unit processes to manufacture additives such as oxygenates.

Many of the process modifications in response to the reformulated gasoline and low
sulfur diesel fuels have been implemented since 1992. The Oil and Gas Journal (December,
1993, 1994, and 1995) reports the following major processing capacity changes from year end
1992 to year end 1995:

• 5.5 percent capacity increase in thermal operations (forecast to further increase by new
construction scheduled to be completed in 1996)

• 8.7 percent capacity increase in hydrocracking operations

• 9.8 percent capacity increase in combined hydrorefining and hydrotreating operations

(there was a 16 percent increase in hydrotreating capacity offset by a 12 percent
decrease in hydrorefining capacity).

• 13.8 percent increase in aromatic and isomerization unit capacity.

• 5.6 percent increase in alkylation capacity

• 11.3 percent increase in lube production capacity

• 7.7 percent decrease in asphalt production

• Small capacity increases for crude distillation, reforming, and catalytic cracking
(increases of 0.9, 0.7, and 1.6 percent, respectively).

2.2 INDUSTRY STUDY

OSW's current listing determination and industry study for the petroleum refining
industry has been underway since 1992 and can be characterized in terms of two major avenues
for information collection: field work and survey evaluation. As part of the Agency's field
work, site selection, engineering site visits, familiarization sampling, and record sampling were
conducted. The survey effort included the development, distribution, and assessment of an
extensive industry-wide RCRA §3007 survey. Each of these elements is described further
below, reflecting the relative order in which these activities were conducted.

Petroleum Refining Industry Study 10 August 1996

2.2.1 Site Selection

EPA's field work activities were focussed on a limited number of refineries, allowing the
Agency to establish strong lines of communication with the selected facilities, and maximizing
efficiency of information collection. After considering logistical and budgetary constraints, the
Agency determined that it would limit its field work to 20 refineries.

The Agency defined a site selection procedure that was used in selecting the 20 site visits
from the population of 185 domestic refineries in the continental U.S.. The objectives of the
selection procedure were:

• to ensure that the characterization data obtained from residuals at the 20 selected
facilities could be used to make valid, meaningful statements about those residuals
industry-wide.

• to give the Agency first-hand exposure to both large and small refineries.

• to be fair to all domestic refineries.

The Agency chose to select facilities randomly rather than purposefully. Although a
randomly selected group of refineries did not offer as many sampling opportunities as a hand-
picked group (e.g., focusing on those larger refineries that generate most of the RCs), the
Agency favored random selection because it did not require subjective input, and also because it
lends itself to statistical analysis, which is useful in making general statements about the
population of residuals.

The Agency broke the industry into two strata based on atmospheric distillation capacity
and made random selections from each stratum independently. The high-capacity stratum (those
with a crude capacity of 100,000 bpcd or greater) contains the top 30 percent of refineries, which
together account for 70 percent of the refining industry's capacity. The stratification enables the
Agency to weigh the selection toward the larger facilities on the basis that they produce larger
volumes of residuals, and that they offer a larger number of residual streams per site visit. The
Agency chose to select 12 of the 20 site visits, 60 percent, from the high-capacity stratum. The
smaller facilities had a lower chance of being selected, but not as low as they would have if the
likelihood of selection was based strictly on size. The selected facilities are presented in Table
2.12.

2
Upon initial contact with several of the randomly selected refineries, it was determined that they were
inappropriate candidates for site visits because they had stopped operation and were not generating any residuals of
interest to the Agency. Replacement facilities were then selected randomly from the same stratum.

The list of refineries slated for field investigations was expanded in June, 1994 to allow the Agency to fill out
certain categories of samples that proved to be difficult to find in the field. The final list presented in Table 2.1
represents those refineries at which site visits actually occurred.

Petroleum Refining Industry Study 11 August 1996

 Table 2.1. Engineering Site Visit Facilities

Refinery Location Initial Site Visit Date

Amoco Oil Texas City, Texas March 29, 1993

Arco Ferndale, Washington June 9, 1993

Ashland Canton, Ohio May 24, 1993

Ashland Catlettsburg, Kentucky March 22, 1993

BP Oil Belle Chasse, Louisiana May 3, 1993

BP Oil Toledo, Ohio May 26, 1993

Chevron (purchased by Clark)1 Port Arthur, Texas August 31, 1994

Chevron1 Salt Lake City, Utah February 21, 1995

Conoco 1 Commerce City, Colorado To be determined

Exxon Billings, Montana June 9, 1993

Koch St. Paul, Minnesota May 19, 1993

Little America Evansville, Wyoming June 8, 1993

Marathon Garyville, Louisiana April 22, 1993

Murphy Superior, Wisconsin May 17, 1993

Pennzoil Shreveport, Louisiana May 5, 1993

Phibro Energy1 Houston, Texas April 20, 1995

Rock Island (purchased by Marathon) Indianapolis, Indiana April 26, 1993

Shell Deer Park, Texas March 31, 1993

Shell Norco, Louisiana April 20, 1993

Shell Wood River, Illinois May 28, 1993

Star Enterprise1 Convent, Louisiana August 30, 1994

Star Enterprise1 Port Arthur, Texas September 21, 1994

Sun Philadelphia, Pennsylvania May 12, 1993

Texaco Anacortes, Washington June 10, 1993

Total Ardmore, Oklahoma June 23, 1993

Young Douglasville, Georgia June 21, 1993

1
Refinery selected to augment record sample availability.

Petroleum Refining Industry Study 12 August 1996

2.2.2 Engineering Site Visits

The field activities were initiated with a series of engineering site visits to the selected
facilities. The purpose of these trips was to:

• Develop a firm understanding of the processes associated with the RCs

• Understand how, when, why, and where each residual is generated and managed

• Establish a schedule of sampling opportunities

• Establish a dialogue with the refinery personnel to ensure optimal sampling and
collection of representative samples.

An engineering site visit report was developed for each of the trips; these are available in
the CBI and non-CBI dockets, as appropriate. For the later site visits conducted in 1994 and
1995, the engineering site visit reports were combined with the analytical data reports prepared
for each facility. The site visit reports included the following elements:

• Purpose of the site visit

• Refinery summary, including general information gathered during the site visit, as well
as data gleaned from telephone conversations and reviews of EPA files, the refinery's
process flow diagram, and expected residual availability

• A discussion of the processes used at the refinery generating the residuals of concern

• Source reduction and recycling techniques employed by the refinery

• A description of onsite residual management facilities

• A chronology of the site visit.

2.2.3 RCRA §3007 Questionnaire

EPA developed an extensive questionnaire under the authority of §3007 of RCRA for
distribution to the petroleum refining industry. A blank copy of the survey instrument is
provided in the RCRA docket. The questionnaire was organized into the following areas:

I. Corporate and facility information

II. Crude oil and product information
III. Facility process flow diagram
IV. Process units: general information
V. Process units: flow diagrams and process descriptions
VI. Residual generation and management
VII. Residual and contaminated soil and debris characterization
VIII. Residual management units: unit-specific characterization
IX. Unit-specific media characterization

Petroleum Refining Industry Study 13 August 1996

 X. General facility characterization (focusing on exposure pathway characterization)
XII. Source reduction efforts
XIII. Certification.

The survey was distributed in August 1993 to all refineries identified as active in 1992 in
the DOE Petroleum Supply Annual. Of the 185 surveys distributed, completed responses were
obtained for 172 refineries. Thirteen refineries notified EPA that they had stopped operations at
some point in or after 1992 and thus were unable to complete the survey due to no staffing or
inaccessible or unavailable data.

The survey responses were reviewed by SAIC chemical engineers for completeness and
then entered into a relational data base known as the 1992 Petroleum Refining Data Base
(PRDB). The entries were subjected to a series of automated quality assurance programs to
identify inappropriate entries and missing data links. An exhaustive engineering review of each
facility's response was then conducted, resulting in follow-up letters to most of the industry
seeking clarifications, corrections, and additional data where needed. The responses to the
followup letters were entered into the data base. A wide variety of additional quality assurance
checks were run on the data to ensure that the residuals of concern were characterized as
completely and accurately as possible. Follow-up telephone interviews were conducted as
necessary to address remaining data issues. After extensive review, the Agency believes that the
data are reliable and represent the industry's current residual generation and management
practices.

Table 2.2 describes the survey results for each of the study residuals of concern, sorted
by total volume generated in metric tons (MT).

2.2.4 Familiarization Sampling

The early phases of the analytical phase of this listing determination consisted of the
development of a Quality Assurance Project Plan (QAPjP) for sampling and analysis, followed
by the collection and analysis of six “familiarization” samples (five listing residuals and one
study residual). The purpose of collecting these samples was to assess the effectiveness of the
methods identified in the QAPjP for the analysis of the actual residuals of concern. Due to the
high hydrocarbon content of many of the RCs, there was concern at the outset of the project that
analytical interferences would prevent the contracted laboratory from achieving adequate
quantitation limits; familiarization analysis allowed the laboratories to experiment with the
analytical methods and waste matrices and optimize operating procedures.

In addition, the first version of the QAPjP identified a list of target analytes that was
derived from previous Agency efforts to characterize refinery residuals. These included the
Delisting Program's list of analytes of concern for refinery residuals, the “Skinner List”, an
evaluation of compounds detected in the sampling and analysis program for listing refinery
residuals in the 1980s, and the judgment of EPA and SAIC chemists who evaluated the process
chemistry of the residuals of concern. During familiarization sample analysis, particular
attention was paid to the tentatively identified compounds to determine whether they should be
added to the target analyte list.

Petroleum Refining Industry Study 14 August 1996

 Table 2.2. Study Residuals Volume Statistics

# of
Reported Total Volume
Study Residual Description Residuals (MT)
Acid Soluble Oil 80 33,493
Hydrocracking Catalyst 83 18,029
Off-specification Product from Sulfur Complex and H2S Removal 93 9,647
Residual Oil Tank Sludge 62 9,107
Treating Clay from Clay Filtering 244 8,990
Desalting Sludge 141 4,841
Off-specification Treating Solution from Sulfur Complex and H2S 76 23,881
Removal (spent amine and spent Stretford solution)
Catalyst from Polymerization (phosphoric acid and Dimersol) 42 4,119
Treating Clay from Alkylation 88 2,895
Treating Clay from Isomerization/Extraction 43 2,472
Off-specification Product from Residual Upgrading 3 800
Treating Clay from Lube Oil 19 733
Catalyst from Isomerization 21 337
Sludge from Residual Upgrading 34 242
Catalyst from HF Alkylation 3 152
Total 1,061 119,738

Samples of five listing residuals were collected for familiarization analysis: crude oil
tank sediments, hydrotreating catalyst, sulfur complex sludge, H2SO4 alkylation catalyst, and
spent caustic. One study residual, acid soluble oil, was analyzed under this program. The results
of the familiarization effort essentially confirmed the techniques identified in the QAPjP and
indicated that the laboratories generally would be able to achieve adequate quantitation of the
target analytes. The familiarization and final QAPjPs are provided in the docket to the
November 20, 1995 proposed rulemaking.

2.2.5 Record Sampling

Upon completion of the familiarization sampling and analysis effort, the Agency initiated
record sampling and analysis of the listing and study residuals. Given budgetary constraints, the
Agency set a goal of collecting 4-6 samples of each of the listing residuals, and 2-4 samples of
the study residuals for a total of 134 samples3. Table 2.3 shows the 103 samples that were
actually collected. The numbers in the darkened boxes refer to Table 2.4 which lists each of the
sample numbers, sample dates, facility names, and other information describing the residual
samples.

3
The Agency determined that one listing residual, catalyst from sulfuric acid alkylation, would not be sampled
due to the existing regulatory exemption for sulfuric acid destined for reclamation, and that one study residual,
catalyst from HF alkylation, could not be sampled due to its extremely rare generation.

Petroleum Refining Industry Study 15 August 1996

 Table 2.3. Residuals Collected for Record Analysis
Familiarization
Record Samples Samples
Listing Residuals 1 2 3 4 5 6 1
Crude oil tank sludge 33 67 73 53 89 91 F5
Unleaded gasoline tank sludge 34 42 65
CSO sludge 14 49 72 88
FCC catalyst and fines 1 12 13 26 27 28
Catalyst from hydrotreating 6 44 55 83 94 69 F2
Catalyst from hydrorefining 21 36 85
Catalyst from reforming 3 22 37 56 79 75
Sulfuric acid alkylation sludge 46
HF alkylation sludge 19 47 51 74 96
Sulfur complex sludge 10 25 29 80 70 F3
Catalyst from sulfur complex 9 15 23 24 52 54
Off-spec product & fines/thermal process 30 45 59 63 81 84
Spent caustic 16 17 32 62 64 95 F1

Study Residuals 1 2 3 4
Residual oil tank sludge 41 92
Desalting sludge 5 50 90 102
Hydrocracking catalyst 4 43 87
Catalyst from isomerization 39 48 71 97
Treating clay from isomerization/extraction 68 98
Catalyst from polymerization 35 66A 66B
Treating clay, alkylation (HF and H2S04) 20 76 86 99
ASO 18 38 77 93 F4
Off-spec sulfur product 2 8 40 100
Spent treating solution (amine) 61 58 82 78
Process sludge from residual upgrading 11
Off-spec product, residual upgrading
Treating clay from lube oil 60
Treating clay from clay filtering 7 31 57 101

Notes: Sulfuric Acid Alkylation catalyst is not presented in this figure. One familiarization sample of sulfuric
acid catalyst was captured and analyzed. HF catalyst is constant boiling mixture (CBM) and is not
shown in this figure.

The sampling team maintained monthly phone contact with the targeted refineries to
maintain an optimized sampling schedule. Despite careful coordination with the refineries and
best efforts to identify and collect all available samples, there were several categories of study
residuals for which the targeted minimum number of samples could not be collected:

• Two samples of residual oil tank sludge were collected. This residual is available only
for a brief period during tank turnarounds, which may occur only every 10 years. In
several cases, refineries mixed their residual oil and clarified slurry oil (CSO) in the
same tank.

Petroleum Refining Industry Study 16 August 1996

 Table 2.4. Descriptions of Samples Collected for Record Analysis
Petroleum Refining Industry Study

Sample Sample
Count Residual Name Number Date Notes Refinery
1 FCC catalyst and fines R2-FC-01 30-Sep-93 ESP Fines. Shell, Wood River, Illinois
2 Off-spec sulfur R2-SP-01 30-Sep-93 Taken from low spots on the unit. Shell, Wood River, Illinois
3 Catalyst from reforming R2-CR-01 01-Oct-93 Platinum catalyst. Shell, Wood River, Illinois
4 Catalyst from hydrocracking R2-CC-02 04-Oct-93 2nd stage, Ni/W. Shell, Wood River, Illinois
5 Desalting sludge R1-DS-01 26-Oct-93 Removed from vessel. Marathon, Indianapolis
6 Catalyst from hydrotreating R1-TC-01 26-Oct-93 Naphtha reformer pretreat, CoMo. Marathon, Indianapolis
7 Treating clay R1-CF-01 27-Oct-93 Kerosene. Marathon, Indianapolis
8 Off-spec sulfur R1-SP-01 27-Oct-93 From product tank. Marathon, Indianapolis
9 Catalyst from sulfur complex R1-SC-01 27-Oct-93 Al2O3. Marathon, Indianapolis
10 Sulfur complex sludge R1-ME-01 27-Oct-93 MEA reclaimer bottoms. Marathon, Indianapolis
11 Process sludge from residual upgrading R1-RU-01 27-Oct-93 ROSE butane surge tank sludge. Marathon, Indianapolis
12 FCC catalyst and fines R4-FC-01 16-Nov-93 Equilibrium cat. from hopper. Little America, Evansville, Wy
13 FCC catalyst and fines R4-FC-02 16-Nov-93 ESP fines. truck trailer comp. Little America, Evansville, Wy
14 CSO sludge R4-SO-01 16-Nov-93 Tank sludge from pad. Little America, Evansville, Wy
15 Catalyst from sulfur complex R4-SC-01 16-Nov-93 Claus unit alumina, super sack comp. Little America, Evansville, Wy
16 Spent caustic R3-LT-01 18-Nov-93 Tank samp. Cresylic, concentrated. Exxon, Billings, Montana
17 Spent caustic R3-LT-02 18-Nov-93 Tank samp. Sulfidic, concentrated. Exxon, Billings, Montana
17

18 ASO R3-AS-01 18-Nov-93 Non-neutralized, separator drum sample Exxon, Billings, Montana
19 HF alkylation sludge R3-HS-01 18-Nov-93 Not dewatered. Dredge from pit. Exxon, Billings, Montana
20 Treating clay from alkylation R3-CA-01 18-Nov-93 HF. Propane treater. Drum composite. Exxon, Billings, Montana
21 Catalyst from hydrorefining R5-TC-01 07-Feb-94 Heavy Gas Oil, CoMo Marathon, Garyville, LA
22 Catalyst from reforming R5-CR-01 07-Feb-94 CCR fines, Pt Marathon, Garyville, LA
23 Catalyst from sulfur complex R5-SC-01 07-Feb-94 Claus Marathon, Garyville, LA
24 Catalyst from sulfur complex R5-SC-02 07-Feb-94 Tail gas, CoMo Marathon, Garyville, LA
25 Sulfur complex sludge R5-ME-02,03 07-Feb-94 Refinery MDEA filter cartridge Marathon, Garyville, LA
26 FCC catalyst and fines R5-FC-02 07-Feb-94 Wet Scrubber Fines Marathon, Garyville, LA
27 FCC catalyst and fines R6-FC-01 09-Feb-94 Equil. from unit Shell, Norco, LA
28 FCC catalyst and fines R6-FC-02 09-Feb-94 Wet scrubber fines Shell, Norco, LA
29 Sulfur complex sludge R6-ME-01 09-Feb-94 Refinery DEA filter cartridge Shell, Norco, LA
30 Off-spec product & fines from thermal process R6-TP-01 09-Feb-94 Coke fines. Shell, Norco, LA
31 Treating clay R6-CF-01 09-Feb-94 Kerosene Shell, Norco, LA
32 Spent caustic R6-LT-01 09-Feb-94 Naph. Comb. Gas oil & Kero Shell, Norco, LA
33 Crude oil tank sludge R6B-CS-01 15-Mar-94 Mix of centrifuge and uncentrifuged Shell, Norco, LA
34 Unleaded gasoline tank sludge R6B-US-01 31-Mar-94 Water washed solids, collected by refinery Shell, Norco, LA
35 Catalyst from polymerization R6B-PC-01 15-Mar-94 Dimersol. filter Shell, Norco, LA
August 1996

36 Catalyst from hydrorefining R7B-RC-01 14-Mar-94 Diesel hydrorefiner BP, Belle Chase, LA
37 Catalyst from reforming R7B-CR-01 14-Mar-94 Platinum BP, Belle Chase, LA
38 ASO R5B-AS-01 16-Mar-94 Acid regen settler bottoms, not neutralized Marathon, Garyville, LA
 Table 2.4. Descriptions of Samples Collected for Record Analysis (continued)
Petroleum Refining Industry Study

Sample Sample
Count Residual Name Number Date Notes Refinery
39 Catalyst from isomerization R5B-1C-01 16-Mar-94 Butamer, platinum Marathon, Garyville, LA
40 Off-spec sulfur R7B-SP-01 14-Mar-94 From cleaned out tank BP, Belle Chase, LA
41 Residual oil tank sludge R8A-RS-01 30-Apr-94 CSO and Resid. Amoco, Texas City
42 Unleaded gasoline tank sludge R8A-US-01 14-Apr-94 Collected by refinery Amoco, Texas City
43 Catalyst from hydrocracking R8A-CC-01 30-Mar-94 Hydroproc., 1st stage cracker, CoMo Amoco, Texas City
44 Catalyst from hydrotreating R8A-TC-01 30-Mar-94 NiMo, landfilled Amoco, Texas City
45 Off-spec product & fines from thermal processes R8A-TP-01 30-Mar-94 Fines, F&K processed Amoco, Texas City
46 H2SO4 alkylation sludge R8B-SS-01 30-Apr-94 From Frog pond, not dewatered Amoco, Texas City
47 HF alkylation sludge R8B-HS-01 30-Apr-94 Not dewatered, dredged Amoco, Texas City
48 Catalyst from isomerization R8B-IC-01 30-Apr-94 Butamer, Pt Amoco, Texas City
49 CSO sludge R9-SO-01,02 17-May-94 Filters (and blank) Murphy, Superior, WI
50 Desalting sludge R9-DS-01 17-May-94 Murphy, Superior, WI
51 HF alkylation sludge R9-HS-01 17-May-94 Murphy, Superior, WI
52 Catalyst from sulfur complex R7B-SC-01 14-Mar-94 SCOT catalyst BP, Belle Chase, LA
53 Crude oil tank sludge R10-CS-01 26-Aug-94 Ashland, Catletsburg, KY
54 Catalyst from sulfur complex R11-SC-01 10-May-94 SCOT, CoMo ARCO, Ferndale, WA
55 Catalyst from hydrotreating R11-TC-01 10-May-94 NiMo, naphtha treater ARCO, Ferndale, WA
18

56 Catalyst from reforming R11-CR-01 10-May-94 Pt/Rh ARCO, Ferndale, WA

57 Treating clay R11-CF-01 10-May-94 Reformer sulfur trap ARCO, Ferndale, WA
58 Spent amine R11-SA-01 10-May-94 DEA ARCO, Ferndale, WA
59 Off-spec product & fines from thermal processes R11-TP-01 10-May-94 Coke fines ARCO, Ferndale, WA
60 Treating clay from lube oil R13-CL-01 30-Apr-94 Clay dust Shell, Deer Park, TX
61 Spent amine R13-SA-01 30-Apr-94 DEA Shell, Deer Park, TX
62 Spent caustic R13-LT-01 30-Apr-94 Sulfidic Shell, Deer Park, TX
63 Off-spec product & fines from thermal processes R12-TP-01 12-May-94 Coke fines, from trap Texaco, Anacortes, WA
64 Spent caustic R12-LT-01 12-May-94 Cresylic Texaco, Anacortes, WA
65 Unleaded gasoline tank sludge R16-US-01 03-Aug-94 Koch
66 Catalyst from polymerization R16-PC-01,02 03-Aug-94 2 catalysts from Dimersol and H2PO4 Koch
67 Crude oil tank sludge R8C-CS-01 01-Jul-94 collected by refinery from tank bottom Amoco, Texas City
68 Treating clay from extraction R8D-CI-01 15-Nov-96 collected by refinery Amoco, Texas City
69 Catalyst from hydrotreating R18-TC-01 20-Oct-94 naptha Ashland, Canton, OH
70 Sulfur complex sludge R18-ME-01 14-Oct-94 MEA sludge, collected by refinery Ashland, Canton, OH
71 Catalyst from isomerization R18-IC-01 20-Oct-94 Penex Ashland, Canton, OH
72 CSO sludge R1B-CS-01 26-Aug-94 mixed CSO/resid Marathon, Indianapolis
73 Crude oil tank sludge R4B-CS-01 26-Aug-94 Filter cake sludge Little America
August 1996

74 HF alkylation sludge R15-HS-01 02-Aug-94 Dredged from pit Total, Ardmore, OK

75 Catalyst from reforming R15-CR-01 02-Aug-94 CCR fines Total, Ardmore
76 Treating clay from alkylation R15-CA-01 02-Aug-94 Butane Total, Ardmore
 Table 2.4. Descriptions of Samples Collected for Record Analysis (continued)
Petroleum Refining Industry Study

Sample Sample
Count Residual Name Number Date Notes Refinery
77 ASO R15-AS-01 02-Aug-94 Neut., skimmed from pit Total, Ardmore, OK
78 Spent amine R15-SA-01 02-Aug-94 MDEA Total, Ardmore, OK
79 Catalyst from reforming R14-CR-01 07-Jun-94 Cyclic Pt reformer BP, Toledo, OH
80 Sulfur complex sludge R14-ME-01 07-Jun-94 DEA diatomaceous earth BP, Toledo, OH
81 Off-spec product & fines from thermal processes R14-TP-01 07-Jun-94 Delayed coking fines BP, Toledo, OH
82 Spent amine R14-SA-01 07-Jun-94 DEA from sump BP, Toledo, OH
83 Catalyst from hydrotreating R3B-TC-01 12-Jul-94 Naptha treater Exxon, Billings, MT
84 Off-spec product & fines from thermal processes R3B-TP-01 12-Jul-94 Fluid coker chunky coke Exxon, Billings, MT
85 Catalyst from hydrorefining R21-RC-01 31-Aug-94 Chevron, Port Arthur, TX
86 Treating clay from alkylation R21-CA-01 31-Aug-94 Chevron, Port Arthur, TX
87 Catalyst from hydrocracking R20-CC-01 30-Aug-94 H-Oil unit, moving bed Star, Convent, LA
88 CSO sludge R20-SO-01 30-Aug-94 Star, Convent, LA
89 Crude oil tank sludge R19-CS-01 12-Oct-96 Pennzoil, Shreveport, LA
90 Desalting sludge R11B-DS-01 01-Sep-94 collected by refinery ARCO, Ferndale, WA
91 Crude oil tank sludge R22-CS-01 21-Sep-94 Star, Port Arthur, TX
92 Residual oil tank sludge R22-RS-01 21-Sep-94 Star, Port Arthur, TX
93 ASO R7C-AS-01 12-Oct-96 BP, Belle Chase, LA
19

94 Catalyst from hydrotreating R22-TC-01 21-Sep-94 Star, Port Arthur, TX

95 Spent caustic R22B-LT-01 11-Oct-96 caustic from H2SO4 alky, sulfidic Star, Port Arthur, TX
96 HF alkylation sludge R7C-HS-01 12-Oct-96 Filter press BP, Belle Chase, LA
97 Catalyst from isomerization R23B-CI-01 19-Apr-95 Pt catalyst Chevron, Salt Lake City
98 Treating clay from isomerization R23B-IC-01 19-Apr-95 Mole sieve, butamer feed treater Chevron, Salt Lake City
99 Treating clay from alkylation R23-CA-01 19-Jan-95 propane treater Chevron, Salt Lake City
100 Off-spec sulfur R23-SP-01 19-Jan-95 Chevron, Salt Lake City
101 Treating clay from clay filtering R23-CF-01 19-Jan-95 diesel washed Chevron, Salt Lake City
102 Desalting sludge R24-DS-01 20-Apr-95 Sludge from Lakos separator Phibro, Houston, TX
Familiarization Samples
F1 Spent Caustic A-SC-01 08-May-93 Commingled. Marathon, Garyville
F2 Catalyst from hydrotreating A-HC-01 10-May-93 Cobalt molybdenum. Marathon, Garyville
F3 Sulfur complex sludge C-SS-01 23-Jun-93 MEA Reclaimer sludge. Amoco, Texas City
F4 ASO C-AS-01 23-Jun-93 Neutralized. Amoco, Texas City
F5 Crude oil tank sludge B-TS-01 15-May-93 Filter cake. Sun, Philadelphia
F6 Sulfuric Acid Catalyst B-SA-01 15-May-93 Spent from third unit. Sun, Philadelphia
August 1996
 • Two samples of treating clay from isomerization/extraction were collected. This
residual is available only for a brief period during unit turnarounds, which may occur
only every 3-5 years. This residual was not readily available from the set of facilities
selected for sampling.

• One sample of treating clay from lube oil processes was collected. Due to the
specialty of the processes, a limited number of refineries produce lube oils and not all
of these facilities use clay filtering. This residual is not readily available, and was
extremely difficult to find from the facilities randomly selected for sampling.

• One sample of residual upgrading sludge was collected. This residual is not readily
available from the set of facilities selected for sampling.

• No samples of off-specification product from residual upgrading were collected. As is

discussed further in Section 3.7.2, the Agency believes that this residual was
inappropriately classified as a residual due to the evaluation of inaccurate old data.
This residual was reported as being generated by only one facility in the 1992 §3007
Survey.

Each of the samples collected was analyzed for the total and Toxicity Characteristics
Leaching Procedure (TCLP) concentrations of the target analytes identified in the QAPjP. In
addition, certain residuals were tested for different characteristics based on the Agency's
understanding of the residuals developed during the engineering site visits. Each sample was
also analyzed for the ten most abundant nontarget volatile and the 20 most abundant nontarget
semi-volatile organics in each sample. These tentatively identified compounds (TICs) were not
subjected to QA/QC evaluation (e.g., MS/MSD analyses) and thus were considered tentative.

2.2.6 Split Samples Analyzed by API

The American Petroleum Institute (API) accompanied the EPA contractor (SAIC) on
virtually all sampling trips and collected split samples of many of the record samples. API's
analytical results for a number of the samples were made available to EPA for comparison
purposes. In general, the Agency found that the API and EPA split sample analyses had very
good agreement. Appendix B of the Listing Background Document, available in the RCRA
docket for the 11/20/95 proposal, presents the Agency's comparison of the split sample results.

2.2.7 Synthesis

The results of the Agency's four year investigation have been synthesized in this report
and in the Listing Background document for the November 20, 1995 proposed rulemaking.
Additional supporting documents are available in the docket for that rulemaking.

Petroleum Refining Industry Study 20 August 1996

3.0 PROCESS AND WASTE DESCRIPTIONS

3.1 REFINERY PROCESS OVERVIEW

Refineries in the United States vary in size and complexity and are generally geared to a
particular crude slate and, to a certain degree, reflect the demand for specific products in the
general vicinity of the refinery. Figure 3.1 depicts a process flow diagram for a hypothetical
refinery that employs the major, classic unit operations used in the refinery industry. These unit
operations are described briefly below, and in more detail in the remainder of this section. Each
subsection is devoted to a major unit operation that generates one or more of the study residuals
of concern and provides information related to the process, a description of the residual and how
and why it is generated, management practices used by the industry for each residual, the results
of the Agency's characterization of each residual, and summary information regarding source
reduction opportunities and achievements.

Storage Facilities: Large storage capacities are needed for refinery feed and products.
Sediments from corrosion and impurities accumulate in these storage tanks. The consent decree
identifies sludges from the storage of crude oil, clarified slurry oil, and unleaded gasoline for
consideration as listed wastes. Residual oil storage tank sludge was identified as a study
residual.

Crude Desalting: Clay, salt, and other suspended solids must be removed from the
crude prior to distillation to prevent corrosion and deposits. These materials are removed by
water washing and electrostatic separation. Desalting sludge is a study residual.

Distillation: After being desalted, the crude is subjected to atmospheric distillation,

separating the crude by boiling point into light ends, naphtha, middle distillate (light and heavy
gas oil), and a bottoms fraction. The bottoms fraction is frequently subjected to further distilla-
tion under vacuum to increase gas oil yield. No residuals from distillation are under
investigation.

Catalytic Cracking: Catalytic cracking converts heavy distillate to compounds with

lower boiling points (e.g., naphthas), which are fractionated. Cracking is typically conducted in
a fluidized bed reactor with a regenerator to continuously reactivate the catalyst. Cracking
catalysts are typically zeolites. The flue gas from the regenerator typically passes through dry or
wet fines removal equipment and carbon monoxide oxidation prior to being released to the
atmosphere. Catalyst and fines, as well as sediments from storage of and solids removal from
clarified slurry oil (the bottoms fraction from catalytic cracking), are listing residuals of concern.

Hydroprocessing: Hydroprocessing includes (1) hydrotreating and hydrorefining (or

hydrodesulfurization), which improve the quality of various products (e.g., by removing sulfur,
nitrogen, oxygen, metals, and waxes and by converting olefins to saturated compounds); and (2)
hydrocracking, which cracks heavy materials, creating lower-boiling, more valuable products.
Hydrotreating is typically less severe than hydrorefining and is applied to lighter cuts. Hydro-
cracking is a more severe operation than hydrorefining, using higher temperature and longer
contact time, resulting in significant reduction in feed molecular size. Hydroprocessing catalysts

Petroleum Refining Industry Study 21 August 1996

Figure 3.1. Simplified Refinery Process Flow Diagram
Figure 3.1. Simplified Refinery Process Flow Diagram

Petroleum Refining Industry Study 22 August 1996

are typically some combination of nickel, molybdenum, and cobalt. Typical applications of
hydroprocessing include treating distillate to produce low-sulfur diesel fuel, treating naphtha
reformer feed to remove catalyst poisons, and treating catalytic cracking unit feed to reduce
catalyst deactivation. Hydrotreating and hydrorefining catalysts are listing residuals, while
hydrocracking catalyst is a study residual.

Thermal Processes: Thermal cracking uses the application of heat to reduce high-
boiling compounds to lower-boiling products. Delayed (batch) or fluid (continuous) coking is
essentially high-severity thermal cracking and is used on very heavy residuum (e.g., vacuum
bottoms) to obtain lower-boiling cracked products. (Residuum feeds are not amenable to
catalytic processes because of fouling and deactivation.) Products are olefinic and include gas,
naphtha, gas oils, and coke. Visbreaking is also thermal cracking; its purpose is to decrease the
viscosity of heavy fuel oil so that it can be atomized and burned at lower temperatures than
would otherwise be necessary. Other processes conducting thermal cracking also would be
designated as thermal processes. Off-spec product and fines is a listing residual from these
processes.

Catalytic Reforming: Straight run naphtha is upgraded via reforming to improve octane
for use as motor gasoline. Reforming reactions consist of (1) dehydrogenation of cycloparaffins
to form aromatics and (2) cyclization and dehydrogenation of straight chain aliphatics to form
aromatics. Feeds are hydrotreated to prevent catalyst poisoning. Operations may be
semiregenerative (cyclic), fully-regenerative, or continuous (moving bed) catalyst systems.
Precious metal catalysts are used in this process. Spent reforming catalyst is a listing residual.

Polymerization: Polymerization units convert olefins (e.g., propylene) into higher

octane polymers. Two principal types of polymerization units include fixed-bed reactors, which
typically use solid-supported phosphoric acid as the catalyst, and Dimersol® units, which
typically use liquid organometallic compounds as the catalyst. Spent polymerization catalyst is a
study residual.

Alkylation: Olefins of 3 to 5 carbon atoms (e.g., from catalytic cracking and coking)
react with isobutane (e.g., from catalytic cracking) to give high octane products. Sulfuric
(H2SO4) or hydrofluoric (HF) acid act as catalysts. Spent sulfuric acid, sulfuric acid alkylation
sludges, and HF sludges are listing residuals, while spent HF acid, acid soluble oil and treating
clays are study residuals.

Isomerization: Isomerization converts straight chain paraffins in gasoline stocks into

higher octane isomers. Isomer and normal paraffins are separated; normal paraffins are then
catalytically isomerized. Precious metal catalysts are used in this process. Spent catalysts and
treating clays are study residuals from this process.

Extraction: Extraction is a separation process using differences in solubility to separate,

or extract, a specific group of compounds. A common application of extraction is the separation
of benzene from reformate. Treating clay is a study residual from this process.

Lube Oil Processing: Vacuum distillates are treated and refined to produce a variety of
lubricants. Wax, aromatics, and asphalts are removed by unit operations such as solvent extrac-

Petroleum Refining Industry Study 23 August 1996

tion and hydroprocessing; clay may also be used. Various additives are used to meet product
specifications for thermal stability, oxidation resistances, viscosity, pour point, etc. Treating
clay is a study residual from this process.

Residual Upgrading: Vacuum tower distillation bottoms and other residuum feeds can
be upgraded to higher value products such as higher grade asphalt or feed to catalytic cracking
processes. Residual upgrading includes processes where asphalt components are separated from
gas oil components by the use of a solvent. It also includes processes where the asphalt value of
the residuum is upgraded (e.g., by oxidation) prior to sale. Off-spec product and fines, as well
as process sludges, are study residuals from this category.

Blending and Treating: Various petroleum components and additives are blended to
different product (e.g., gasoline) specifications. Clay and caustic may be used to remove sulfur,
improve color, and improve other product qualities. Spent caustic is a listing residual, while
treating clay is a study residual.

Sulfur Recovery: Some types of crude typically contain high levels of sulfur, which
must be removed at various points of the refining process. Sulfur compounds are converted to
H2S and are removed by amine scrubbing. The H2S often is converted to pure sulfur in a Claus
plant. Off-gases from the Claus plant typically are subject to tail gas treating in a unit such as a
SCOT® treater for additional sulfur recovery. Process sludges and spent catalysts are listing
residuals; off-spec product and off-spec treating solutions are study residuals.

Light Ends (Vapor) Recovery: Valuable light ends from various processes are
recovered and separated. Fractionation can produce light olefins and isobutane for alkylation, n-
butane for gasoline, and propane for liquid petroleum gas (LPG). Caustic may be used to
remove sulfur compounds. Spent caustic is a listing residual of concern.

Petroleum Refining Industry Study 24 August 1996

3.2 CRUDE OIL DESALTING

Crude oil removed from the ground is contaminated with a variety of substances,
including gases, water, and various minerals (dirt). Cleanup of the crude oil is achieved in two
ways. First, field separation, located near the site of the oil wells, provides for gravity separation
of the three phases: gases, water (with entrained dirt), and crude oil. The second cleanup
operation is crude oil desalting conducted at the refinery. Crude oil desalting is a water-washing
operation prior to atmospheric distillation which achieves additional crude oil cleanup. Water
washing removes much of the water-soluble minerals and suspended solids from the crude. If
these contaminants were not removed, they would cause a variety of operating problems
throughout the refinery including the blockage of equipment, the corrosion of equipment, and
the deactivation of catalysts.

3.2.1 Process Description

To operate efficiently and effectively the crude oil desalter must achieve an intimate
mixing of the water wash and crude, and then separate the phases so that water will not enter
downstream unit operations. The crude oil entering a desalting unit is typically heated to 100 -
300 F to achieve reduced viscosity for better mixing. In addition, the desalter operates at
pressures of at least 40 lb/in2 gauge to reduce vaporization. Intimate mixing is achieved through
a throttling valve or emulsifier orifice and the oil-water emulsion is then introduced into a
gravity settler. The settler utilizes a high-voltage electrostatic field to agglomerate water
droplets for easier separation. Following separation, the water phase is discharged from the unit,
carrying salt, minerals, dirt, and other water-soluble materials with it.

Desalting efficiency can be increased by the addition of multiple stages, and in some
cases acids, caustic, or other chemicals may be added to promote additional treatment. A
simplified process flow diagram for crude oil desalting is shown in Figure 3.2.1.

Figure 3.2.1. Desalting Process Flow Diagram

Petroleum Refining Industry Study 25 August 1996

3.2.2 Desalting Sludge

3.2.2.1 Description

Desalting sludge is continuously separated from the crude oil and settles to the bottom of
the desalter with the water wash. The majority of the sludge is removed from the desalter with
the water wash and is discharged to the facility's wastewater treatment plant. The sludge then
becomes part of the wastewater treatment sludges. On a regular basis (e.g., weekly), water jets
at the bottom of the desalter are activated, stirring up sludge that has built up on the bottom of
the unit and flushing it to wastewater treatment. This process is known as “mud washing” and
allows the units to continue to operate without shutting down for manual sludge removal.

Desalting sludge is removed from the unit during unit turnarounds, often associated with
turnarounds of the distillation column. These turnarounds are infrequent (e.g., every several
years). Some refineries operate enough desalters in parallel to allow for turnarounds while the
distillation columns continue to operate.

At turnaround, the sludge can be removed in several different ways. Based on the results
of the questionnaire, approximately half of the total number of desalting sludge waste streams
are removed from the desalter using a vacuum truck, permanent or portable piping, or other
similar means where the sludge is removed in a slurry state. Another 25 percent of the sludges
are removed manually by maintenance workers while the removal method for the remaining 25
percent of the sludges was not clear. The questionnaire data further indicated that half of the
desalting sludge streams are further piped or stored in tanker trucks following removal, while the
remaining half are stored in drums or a dumpster.

As with some tank sludges, some facilities remove their desalting sludge using a vacuum
truck or similar slurring device, then centrifuge the material and store the solids in a drum or
dumpster. Such procedures would explain the apparent discrepancy between the number of
streams removed as solid and the number of streams stored in containers (presumably also as
solid). Questionnaire data indicate that approximately 10 percent of the streams generated in
1992 underwent dewatering or a similar volume reduction procedure.

3.2.2.2 Generation and Management

Eighty facilities reported generating a total quantity of 4,841 MT of desalting sludge in

1992, according to the 1992 RCRA §3007 Survey. Desalting sludge includes material generated
from turnaround operations; materials continuously flushed to wastewater treatment are
generally omitted. The survey contained a residual identification code for “desalter sludge”. All
residuals assigned this code, and any misidentified residual determined to be desalter sludge
generated from a process assigned process code for “desalting” were considered “desalter
sludge” residuals. This corresponds to residual code 02-A in Section VII.2 of the survey and
process code 01-A, 01-B, 01-C, and 01-D in Section IV-1.C. Quality assurance was conducted
to ensure that all desalting sludge residuals were correctly identified and coded.

Petroleum Refining Industry Study 26 August 1996

 Based on the results of the survey, 148 facilities use desalting units and are thus likely to
generate desalting sludge. Due to the infrequent generation of this residual, not all of these 148
facilities generated desalting sludge in 1992. In addition, some facilities do not generate
desalting sludge at all because they do not conduct unit turnarounds, or do not find any settled
sludge when conducting maintenance. However, there was no reason to expect that 1992 would
not be a typical year with regard to desalting sludge generation and management. Table 3.2.1
provides a description of the quantity generated, number of streams reported, number of streams
not reporting volumes (data requested was unavailable and facilities were not required to
generate it), total and average volumes.

Table 3.2.1. Generation Statistics for Desalting Sludge, 1992

# of Streams
# of w/ Unreported Total Volume Average
Final Management Streams Volume (MT) Volume (MT)
Discharge to onsite wastewater 25 9 2,041.62 81.66
treatment facility
Disposal in onsite or offsite 1 0 2.00 2.00
underground injection
Disposal in offsite Subtitle D landfill 14 1 28.80 2.06
Disposal in offsite Subtitle C landfill 15 5 221.40 14.76
Disposal in onsite Subtitle D landfill 2 0 102.00 51.00
Offsite incineration 8 1 56.00 7.00
Offsite land treatment 4 0 53.20 13.30
Onsite land treatment 8 0 345.76 43.22
Recovery onsite in a coker 3 3 52.40 17.47
Transfer for direct use as a fuel or to 17 1 1,937.60 113.98
make a fuel
TOTAL 97 20 4,840.78 49.90

Note that 42 percent of desalting sludge volumes are discharged to onsite wastewater
treatment. During engineering site and sampling visits, it was observed that refineries would
simply flush the sludge to wastewater treatment during desalter turnarounds in a manner similar
to mud washing.

Over half of the desalting sludge residuals (48) were reported to be managed as
characteristically hazardous (most commonly D018), accounting for 40 percent of the sludge
volume.4 Twenty seven of these streams were managed with F or K listed wastes, reflecting
their frequent management in wastewater treatment systems.

4
These percentages do not match up directly with any one of the management scenarios because the number of
streams and the volume are a combination of several management scenarios (i.e., managed in WWTP, Subtitle C
landfill, transfer as a fuel, etc.).

Petroleum Refining Industry Study 27 August 1996

3.2.2.3 Plausible Management

EPA believes that most of the plausible management practices for this residual were
reported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.2.1. The Agency
gathered information suggesting other management practices had been used in other years
including: “disposal in onsite Subtitle C landfill” (86 MT), “disposal in onsite surface
impoundment” (1 MT), and “recovery onsite via distillation” (0.5 MT). These non-1992
practices are generally comparable to practices reported in 1992 (i.e., off-site Subtitle C
landfilling and recovery in a coker). The very small volume reported to have been disposed in a
surface impoundment reflects the management of this residual with the refinery’s wastewater in
a zero discharge wastewater treatment facility with a final evaporation pond; this management
practice is comparable to the 1992 reported practice of “disposal in onsite wastewater treatment
facility”. EPA also compared management practices reported for desalting sludge to those
reported for crude oil tank sediment because of expected similarities in composition and
management. Similar land disposal practices were reported for both residuals.

3.2.2.4 Characterization

Two sources of residual characterization data were developed during the industry study:

• Table 3.2.2 summarizes the physical properties of desalting sludge as reported in

Section VII.A of the RCRA §3007 survey.

• Four record samples of desalting sludge were collected and analyzed by EPA. These
sludges represent the various types of desalting operations and sludge generation
methods typically used by the industry and are summarized in Table 3.2.3. The
samples represent sludges generated during turnaround operations (the most common
way desalting sludge is generated), and also represents sludges both with and without
undergoing interim deoiling or dewatering steps.

Table 3.2.4 provides a summary of the characterization data collected under this
sampling effort. The record samples are believed to be representative of desalting sludge as
typically generated by the industry. All four record samples were analyzed for total and TCLP
levels of volatiles, semivolatiles, and metals. Two of three samples analyzed for TCLP Benzene
exhibited the toxicity characteristic for benzene (i.e., the level of benzene in these samples'
TCLP extracts exceeded the corresponding regulatory level). Only constituents detected in at
least one sample are shown in Table 3.2.4.

3.2.2.5 Source Reduction

The electrostatic desalter removes most of the solids, salts and water present in the crude
oil. Minimizing the introduction or recycling of solids to the crude unit will assist the reduction
of desalting sludge, since solids attract oil and produce emulsions.

Petroleum Refining Industry Study 28 August 1996

 The amount of desalting sludge formed is a function of the efficiency of the desalter but
more fundamentally is a characteristic of the crude oil. Methods of managing desalting sludge
center on increasing the efficiency of the desalter and de-emulsifiers which increase the
capability of separating the oil, water and solid phases.

Reference Waste Minimization/Management Methods

”New Process Effectively Recovers Oil From Refinery Enhanced separation of oil, water and solids.
Waste Streams.” Oil & Gas Journal. August 15, 1994.
”Filtration Method Efficiently Desalts Crude in Alternative process: single-stage filtration.
Commercial Test.” Oil & Gas Journal. May 17, 1993.

D.T. Cindric, B. Klein, A.R. Gentry and H.M. Gomaa. Includes topic of more effective separation of
“Reduce Crude Unit Pollution With These Technologies.” phases in desalter.
Hydrocarbon Processing. August, 1993.
”Waste Minimization in the Petroleum Industry: A Practices described: 1. Shear mixing used
Compendium of Practices.” API. November, 1991. to mix desalter wash water and crude. 2.
Turbulence avoided by using lower pressure
water to prevent emulsion formation.

Petroleum Refining Industry Study 29 August 1996

 Table 3.2.2. Desalter Sludge: Physical Properties
# of
# of Unreported
Properties Values Values1 10th % 50th % 90th %
pH 118 144 6.10 7.00 8.40
Reactive CN, ppm 60 202 0.15 1.00 250.00
Reactive S, ppm 67 195 0.80 82.00 500.00
Flash Point, C 73 189 43.89 60.00 94.44
Oil and Grease, vol% 103 159 5.00 16.00 70.00
Total Organic Carbon, vol% 47 215 1.00 15.00 35.00
Vapor Pressure, mm Hg 14 248 0.00 10.50 150.00
Vapor Pressure Temperature, C 9 253 20.00 30.00 40.00
Viscosity, lb/ft-sec 3 259 0.00 0.00 1500.00
Viscosity Temperature, C 5 257 0.00 30.00 50.00
Specific Gravity 69 193 0.90 1.10 1.70
BTU Content, BTU/lb 56 206 270.00 3,590.00 10,000.00
Aqueous Liquid, % 157 105 0.00 30.00 78.00
Organic Liquid, % 151 111 0.00 15.00 50.00
Solid, % 170 92 9.00 45.00 100.00
Other, % 111 151 0.00 0.00 30.00
Particle >60 mm, % 10 252 0.00 0.00 50.00
Particle 1-60 mm, % 9 253 0.00 90.00 100.00
Particle 100 µm-1 mm, % 12 250 0.00 10.00 100.00
Particle 10-100 µm, % 9 253 0.00 0.00 100.00
Particle <10 µm, % 8 254 0.00 0.00 0.00
Median Particle Diameter, microns 7 255 0.00 200.00 2,000.00

1
Facilities were not required to do additional testing, therefore information provided was based on previously collected
data or engineering judgment.

Table 3.2.3. Desalting Sludge Record Sampling Locations

Sample No. Facility Description

R1-DS-01 Marathon, Indianapolis, IN From electrostatic precipitator turnaround.

Sludge/slurry removed directly from unit

R9-DS-01 Murphy, Superior, WI Turnaround sludge/slurry taken from drums

R11-DS-01 ARCO, Ferndale, WA Dewatered sludge from turnaround taken from

bins

R24-DS-01 Phibro, Houston, TX Continuously generated “solids” from brine

separator; sample mostly aqueous

Petroleum Refining Industry Study 30 August 1996

 Table 3.2.4. Desalting Sludge Characterization
Petroleum Refining Industry Study

Volatile Organics - Method 8260A µg/kg ( µg/L )

Average
CAS No. R1-DS-01 R9-DS-01 R11B-DS-01 R24-DS-01 Conc Maximum Conc Comments
Acetone 67641 200,000 < 625 < 1,250 160 67,292 200,000
Benzene 71432 230,000 22,000 28,000 36 93,333 230,000
n-Butylbenzene 104518 < 62,500 42,000 31,000 < 5 36,500 42,000 1
sec-Butylbenzene 135988 < 62,500 24,000 19,000 < 5 21,500 24,000 1
Ethylbenzene 100414 180,000 150,000 48,000 J 7 126,000 180,000
Isopropylbenzene 98828 < 62,500 36,000 27,000 < 5 31,500 36,000 1
p-Isopropyltoluene 99876 < 62,500 25,000 18,000 < 5 21,500 25,000 1
Methylene chloride 75092 J 49,000 < 625 < 1,250 < 5 16,958 49,000
Methyl ethyl ketone 78933 < 62,500 < 625 < 1,250 41 NA NA
n-Propylbenzene 103651 < 62,500 74,000 44,000 < 5 60,167 74,000
Toluene 108883 660,000 220,000 61,000 77 313,667 660,000
1,2,4-Trimethylbenzene 95636 350,000 230,000 68,000 35 216,000 350,000
1,3,5-Trimethylbenzene 108678 140,000 85,000 34,000 12 86,333 140,000
o-Xylene 95476 290,000 190,000 54,000 38 178,000 290,000
m,p-Xylenes 108383 / 950,000 380,000 67,000 70 465,667 950,000
106423
Naphthalene 91203 < 62,500 55,000 54,000 32 54,500 55,000 1
TCLP Volatile Organics - Methods 1311 and 8260A µg/L
31

CAS No. R1-DS-01 R9-DS-01 R11B-DS-01 R24-DS-01 Average Maximum Conc Comments
Conc
Acetone 67641 770 < 50 B 260 NA 360 770
Benzene 71432 5,200 1,700 280 NA 2,393 5,200
Ethylbenzene 100414 550 340 120 NA 337 550
Toluene 108883 5,200 2,000 760 NA 2,653 5,200
1,2,4-Trimethylbenzene 95636 < 250 190 J 69 NA 130 190 1
1,3,5-Trimethylbenzene 108678 < 250 J 54 J 22 NA 38 54 1
Methylene chloride 75092 1,000 1,200 J 23 NA 741 1,200
o-Xylene 95476 1,100 540 200 NA 613 1,100
m,p-Xylene 108383 / 2,400 1,100 490 NA 1,330 2,400
106423
Naphthalene 91203 < 250 < 50 JB 52 NA 51 52 1
Semivolatile Organics - Method 8270B µg/kg ( µg/L )
Average
CAS No. R1-DS-01 R9-DS-01 R11B-DS-01 R24-DS-01 Conc Maximum Conc Comments
Benzo(a)pyrene 50328 J 4,300 J 5,600 < 10,000 < 5 4,950 5,600 1
Carbazole 86748 < 13,200 < 20,625 < 20,000 43 NA NA
August 1996

Chrysene 218019 < 6,600 < 10,313 J 13,000 < 5 9,971 13,000
Dibenzofuran 132649 < 6,600 12,000 J 16,000 < 5 11,533 16,000
2,4-Dimethylphenol 105679 < 6,600 < 10,313 < 10,000 190 NA NA
Fluorene 86737 J 6,000 24,000 26,000 < 5 18,667 26,000
 Table 3.2.4. Desalting Sludge Characterization (continued)
Petroleum Refining Industry Study

Semivolatile Organics - Method 8270B µg/kg (continued) ( µg/L )

Average
CAS No. R1-DS-01 R9-DS-01 R11B-DS-01 R24-DS-01 Conc Maximum Conc Comments
Phenanthrene 85018 J 12,000 61,000 68,000 26 47,000 68,000
Phenol 108952 < 6,600 < 10,313 < 10,000 900 NA NA
Pyrene 129000 < 6,600 J 10,000 < 10,000 < 5 8,867 10,000
1-Methylnaphthalene 90120 48,000 220,000 180,000 81 149,333 220,000
2-Methylnaphthalene 91576 66,000 330,000 240,000 130 212,000 330,000
2-Methylchrysene 3351324 < 13,200 J 13,000 < 20,000 < 10 13,000 13,000 1
2-Methylphenol 95487 < 6,600 < 10,313 < 10,000 340 NA NA
3/4-Methylphenol NA < 6,600 < 10,313 < 10,000 530 NA NA
Naphthalene 91203 33,000 110,000 130,000 110 91,000 130,000
TCLP Semivolatile Organics - Methods 1311 and 8270B µg/L
CAS No. R1-DS-01 R9-DS-01 R11B-DS-01 R24-DS-01 Average Maximum Conc Comments
Conc
Benzo(a)pyrene 50328 JB 16 < 50 < 50 NA 16 16 1
Bis(2-ethylhexyl)phthalate 117817 < 50 B 500 < 50 NA 200 500
Di-n-butyl phthalate 84742 < 50 < 50 J 20 NA 20 20 1
2,4-Dimethylphenol 105679 J 26 < 50 J 73 NA 50 73
1-Methylnaphthalene 90120 J 32 J 50 J 71 NA 51 71
2-Methylnaphthalene 91576 J 34 J 60 J 92 NA 62 92
32

2-Methylphenol 95487 J 48 J 25 J 43 NA 39 48
3/4-Methylphenol NA J 68 J 40 J 49 NA 52 68
Naphthalene 91203 J 86 J 61 120 NA 89 120
Phenol 108952 200 < 50 J 54 NA 101 200
Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg (mg/L)
CAS No. R1-DS-01 R9-DS-01 R11B-DS-01 R24-DS-01 Average Maximum Conc Comments
Conc
Aluminum 7429905 2,600 3,700 7,500 11.0 4,600 7,500
Antimony 7440360 16.0 14.0 < 6.00 0.28 12.0 16.0
Arsenic 7440382 16.0 34.0 16.0 0.05 22.0 34.0
Barium 7440393 2,200 1,700 1,400 1.80 1,767 2,200
Beryllium 7440417 < 0.50 < 0.50 1.40 < 0.0025 0.80 1.40
Cadmium 7440439 2.90 1.80 3.40 < 0.0025 2.70 3.40
Calcium 7440702 16,000 5,300 3,300 230 8,200 16,000
Chromium 7440473 110 76.0 150 0.17 112 150
Cobalt 7440484 27.0 16.0 13.0 < 0.025 18.7 27.0
Copper 7440508 680 340 430 1.20 483 680
Iron 7439896 71,000 55,000 77,000 200 67,667 77,000
August 1996
 Table 3.2.4. Desalting Sludge Characterization (continued)
Petroleum Refining Industry Study

Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg (continued) (mg/L)
CAS No. R1-DS-01 R9-DS-01 R11B-DS-01 R24-DS-01 Average Maximum Conc Comments
Conc
Lead 7439921 1,100 390 160 0.36 550 1,100
Magnesium 7439954 2,200 3,200 3,300 68.0 2,900 3,300
Manganese 7439965 310 250 450 1.60 337 450
Mercury 7439976 41.0 4.40 39.0 0.0085 28.1 41.0
Molybdenum 7439987 17.0 19.0 16.0 < 0.034 17.3 19.0
Nickel 7440020 76.0 100 110 0.48 95.3 110
Potassium 7440097 < 500 < 500 < 500 41.0 NA NA
Selenium 7782492 140 22.0 75.0 < 0.0025 79.0 140
Sodium 7440235 < 500 < 500 < 500 830 NA NA
Thallium 7440280 < 1.00 7.00 < 1.00 < 0.005 3.00 7.00
Vanadium 7440622 36.0 37.0 120 0.12 64.3 120
Zinc 7440666 1,300 1,900 5,400 2.20 2,867 5,400
TCLP Metals - Methods 1311, 6010, 7060, 7421, 7470, 7471, and 7841 mg/L
CAS No. R1-DS-01 R9-DS-01 R11B-DS-01 R24-DS-01 Average Maximum Conc Comments
Conc
Aluminum 7429905 7.60 < 1.00 < 1.00 NA 3.20 7.60
Barium 7440393 2.60 < 1.00 3.50 NA 2.37 3.50
Calcium 7440702 580 150.00 54.0 NA 261 580
33

Chromium 7440473 0.87 < 0.05 0.12 NA 0.35 0.87

Iron 7439896 210 24.00 190 NA 141 210
Magnesium 7439954 71.0 < 25.0 < 25.0 NA 40.3 71.0
Manganese 7439965 6.00 1.60 4.60 NA 4.07 6.00
Nickel 7440020 < 0.20 < 0.20 0.52 NA 0.31 0.52
Zinc 7440666 2.00 2.90 57.00 NA 20.6 57.0

Comments:

1 Detection limits greater than the highest detected concentration are excluded from the calculations.

Notes:

B Analyte also detected in the associated method blank.

J Compound's concentration is estimated. Mass spectral data indicate the presence of a compound that meets the identification criteria for which the result is less than the
laboratory detection limit, but greater than zero.
NA Not Applicable.
August 1996
3.3 HYDROCRACKING

Petroleum refining hydroprocessing techniques include hydrocracking, hydrorefining,

and hydrotreating. Hydrorefining and hydrotreating processes and their respective catalyst
residuals are described in the Listing Background Document for the November 20, 1995
proposed rule. Hydrocracking processes are similar to hydrotreating and hydrorefining
processes in that they remove organic sulfur and nitrogen from the process feeds, but differ in
that they also serve to break heavier fraction feeds into lighter fractions. As refinery crudes have
become heavier, hydrocracking, a more recent process development compared to long-
established conversion processes such as thermal cracking, has become more widely used. The
current trend to heavier feeds and lighter high-quality feeds causes hydrocracking to offer
advantages to future refining operations.

In addition, hydrocracking is a versatile process, and under mild conditions can be

utilized for hydrotreating (typically fractions that need to be saturated to give good burning
quality) and under more severe conditions can be utilized as a cracker (typically feeds that are
too heavy or too contaminant-laden for catalytic cracking). As a result of this flexibility,
hydrocracking processes can appear in refinery operations in a number of different places.

3.3.1 Process Description

The process flow for hydrocracking is similar to that for hydrotreating: the feed is mixed
with a hydrogen-rich gas, pumped to operating pressure and heated, and fed to one or more
catalytic reactors in series. Hydrocracking units are typically designed with two stages: the first
uses a hydrotreating catalyst to remove nitrogen and heavy aromatics, while the second stage
conducts cracking. The catalysts for each stage are held in separate vessels. Organic sulfur and
nitrogen are converted to H2S and NH3, and some unsaturated olefins or aromatics are saturated
or cracked to form lighter compounds. In addition, heavy metal contaminants are adsorbed onto
the catalyst. Following the reactor, the effluent is separated via stabilization and fractionation
steps into its various fractions. There are two major differences between hydrocracking and
hydrotreating: 1) operating pressures are much higher, in the range from 2,000 - 3,000 lb/in2
gauge, and 2) hydrogen consumption is much higher, in the range from (1,200 - 1,600
SCF/barrel of feed), dependent on the feed. The feed is generally a heavy gas oil or heavier
stream.

Catalysts employed in hydrocracking reactors have multiple functions. First, the catalyst
has a metallic component (cobalt, nickel, tungsten, vanadium, molybdenum, platinum,
palladium, or a combination of these metals) responsible for the catalysis of the hydrogenation
and desulfurization/denitrification reactions. In addition, these metals are supported on a highly
acidic support (silica-alumina, acid-treated clays, acid-metal phosphates, or alumina) responsible
for the cracking reactions. A simplified process flow diagram is shown in Figure 3.3.1.

Petroleum Refining Industry Study 34 August 1996

 Figure 3.3.1. Hydrocracking Process Flow Diagram

3.3.2 Spent Hydrocracking Catalyst

3.3.2.1 Description

Metal deposition acts to deactivate, or poison, the hydrocracking catalyst. In addition,

carbon from the cracking reactions deactivates the catalyst. The catalyst’s life is dependent on
the severity of cracking and metal deposition and is changed out every 6 months to 8 years. The
catalyst closest to the entrance (top) of the reactor becomes deactivated first, and for this reason
is sometimes replaced more frequently than the entire reactor contents (a “topping” operation).
When catalyst activity is unacceptable, the reactor is taken out of service and typically undergoes
a hydrogen sweep to burn residual hydrocarbon, then a nitrogen sweep to cool the reactor and
remove occupational hazards such as hydrogen sulfide and benzene. Such procedures were
reported by most facilities. The following additional procedures were reported to be employed
by fewer facilities, typically only one or two:

Oxidation (to burn residual hydrocarbon)

Cat nap technology or diesel wash (to lower vapor pressure of hazardous volatiles)

Wet dump, water wash, or soda ash wash (to neutralize sulfides and remove volatiles)

Steam stripping (to remove volatiles)

Evacuation (a technique possibly similar to nitrogen sweep)

Some facilities report using no pretreatment methods prior to catalyst removal.

Petroleum Refining Industry Study 35 August 1996

In some processes, a moving bed of catalyst is used instead of a fixed bed. In this process,
catalyst is continuously and slowly moved countercurrent to the hydrocarbon flow. Spent
catalyst is generated almost continuously and fresh catalyst added as needed for makeup. This
configuration differs significantly from the fixed bed design with respect to spent catalyst
generation frequency.

Unlike hydrotreating and hydrorefining catalysts (discussed in Listing Background

Document), both precious metal and nonprecious metal catalysts are used in hydrocracking
processes. Based on a total of 46 facilities reporting spent hydrocracking catalyst generation, 34
(74%) reported using nickel/molybdenum, 11 (24%) reported using nickel/tungsten, and 11
(24%) reported using palladium. An additional 16 facilities (35%) reported using other metals
in their catalyst such as cobalt, copper, magnesium, monometallic nickel, phosphorus, tin, and
zinc. As stated in Section 3.3.1, many hydrocracking units are constructed as a hydrorefining
stage followed by a cracking stage. In reporting catalysis use, refineries may not have
differentiated between hydrorefining and cracking functions in their response. In this section,
data for both pretreatment (hydrorefining function) and hydrocracking catalysts are presented.

Approximately 2,500 MT of the hydrocracking catalyst generated in 1992 was identified

as displaying hazardous characteristics.5 This is approximately 15 percent of the total volume
managed. The most commonly displayed hazardous waste codes were D001 (ignitable), D003
(reactive), D004 (TC arsenic) and D018 (TC benzene).

3.3.2.2 Generation and Management

During reactor change-outs, spent hydrocracking catalysts are removed from the reactors
using a variety of techniques including gravity dumping and water drilling. Upon removal from
the catalyst bed, the catalyst may be screened to remove fines or catalyst support media. The
catalyst is typically stored in covered bins pending shipment off site for disposal or recovery.

Twenty-eight facilities reported generating a total quantity of 18,000 MT of this residual

in 1992, according to the 1992 RCRA §3007 Questionnaire. Residuals were assigned to be
“spent hydrocracking catalyst” if they were assigned a residual identification code of “spent
solid catalyst” or “spent catalyst fines” and were generated from a process identified as a
hydrocracking unit. These correspond to residual code 03-A in Section VII.2 of the
questionnaire and process code 05 in Section IV-1.C of the questionnaire. Quality assurance
was conducted by ensuring that all hydrocracking catalysts previously identified in the
questionnaire (i.e., in Section V.B) were assigned in Section VII.2.

5
These percentages do not match up directly with any one of the management scenarios because the number of
streams and the volume are a combination of several management scenarios (i.e., Subtitle C landfill, transfer for
metals reclamation, etc.).

Petroleum Refining Industry Study 36 August 1996

 Based on the results of the questionnaire, 47 facilities use hydrocracking units and are
thus likely to generate spent hydrocracking catalyst. Due to the infrequent generation of this
residual, not all of these 47 facilities generated spent catalyst in 1992. However, there was no
reason to expect that 1992 would not be a typical year with regard to hydrocracking catalyst
generation and management. Table 3.3.1 provides a description of the quantity generated,
number of streams reported, number of streams not reporting volumes (data requested was
unavailable and facilities were not required to generate it), total and average volumes.

Table 3.3.1. Generation Statistics for Hydrocracking Catalyst, 1992

# of # of Streams w/ Total Volume Average

Final Management Streams Unreported Volume (MT) Volume (MT)
Disposal in offsite Subtitle D landfill 7 0 1,592.70 227.53
Disposal in offsite Subtitle C landfill 8 0 991.50 123.94
Reuse onsite as replacement catalyst for 1 0 159.40 159.40
another unit
Transfer metal catalyst for reclamation or 45 2 13,185.56 293.01
regeneration
Transfer to another petroleum refinery 14 0 2,100.00 150.00
TOTAL 75 2 18,029.16 295.56

3.3.2.3 Plausible Management

EPA believes that most of the plausible management practices for this residual were
reported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.3.1. The Agency
gathered information suggesting other management practices had been used in other years
including: “disposal in onsite Subtitle D landfill” (8 MT) and “other recycling, reclamation, or
reuse: cement plant” (320 MT). These non-1992 practices are comparable to 1992 practices
(i.e., off-site Subtitle D landfilling) or to typical practices for alumina-based catalysts (e.g.,
cement plants).

The Agency has no other data to suggest other management practices are used for
hydrocracking catalysts due to the physical characteristics and chemical composition of the
waste. EPA compared the management practice reported for hydrocracking catalysts to those
reported for hydrotreating and hydrorefining catalysts based on expected similarities. Similar
land disposal practices were reported for all three residuals.

3.3.2.4 Characterization

Two sources of residual characterization were developed during the industry study:

• Table 3.3.2 summarizes the physical properties of the spent catalyst as reported in
Section VII.A of the §3007 survey.

• Three record samples of spent hydrocracking catalyst were collected and analyzed by
EPA and are summarized in Table 3.3.3. The record samples represent the most
frequently used catalysts (i.e., nickel/tungsten and nickel/molybdenum, together used

Petroleum Refining Industry Study 37 August 1996

 by well over half of the refineries with hydrocracking processes. In addition, heavy
gas oil or similar distillate/residual feed is the most common application of
hydrocracking reactors, according to the questionnaire. Therefore, the record samples
are expected to represent most of the spent catalyst generated in the industry.
However, another frequently used catalyst (palladium) is not represented, and catalysts
employing feeds other than heavy gas oil (e.g., lube oil) may not have the same
characteristics when spent.

Table 3.3.4 provides a summary of the characterization data collected under this
sampling effort. All three record samples were analyzed for total and TCLP levels of volatiles,
semivolatiles, metals and ignitability. One of three samples exhibited the ignitability
characteristic. Only constituents detected in at least one sample are shown in Table 3.3.4.

Table 3.3.2. Hydrocracking Catalyst Physical Properties

# of # of Unreported
Properties Values Values1 10th % 50th % 90th %
pH 39 102 5.00 6.80 9.14
Reactive CN, ppm 21 120 0.30 3.20 10.00
Reactive S, ppm 38 103 1.00 12.50 9,500.00
Flash Point, C 36 105 60.00 157.50 200.00
Oil and Grease, vol% 17 124 0.00 0.36 9.00
Total Organic Carbon, vol% 14 127 0.00 0.63 8.00
Specific Gravity 54 87 0.80 1.74 3.15
Specific Gravity Temperature, C 10 131 17.80 20.00 25.00
BTU Content, BTU/lb 4 137 0.00 0.00 7,485.00
Aqueous Liquid, % 64 77 0.00 0.00 0.00
Organic Liquid, % 63 78 0.00 0.00 0.00
Solid, % 101 40 100.00 100.00 100.00
Other, % 62 79 0.00 0.00 0.00
Particle >60 mm, % 28 113 0.00 0.00 0.00
Particle 1-60 mm, % 42 99 95.00 99.00 100.00
Particle 100 µm-1 mm, % 31 110 0.00 1.00 5.00
Particle 10-100 µm, % 27 114 0.00 0.00 0.00
Particle <10 µm, % 27 114 0.00 0.00 0.00
Median Particle Diameter, microns 13 128 0.00 1,600.00 2,000.00

1
Facilities were not required to do additional testing, therefore information provided was based on previously collected
data or engineering judgement.

Petroleum Refining Industry Study 38 August 1996

 Table 3.3.3. Spent Hydrocracking Catalyst Record Sampling Locations
Sample No. Facility Description
R2-CC-01 Shell, Wood River, IL Nickel/tungsten catalyst, fixed bed, heavy gas oil feed
R8A-CC-01 Amoco, Texas City, TX Nickel/molybdenum catalyst, moving bed, heavy gas oil feed
R20-CC-01 Star, Convent, LA Mixed nickel/tungsten and nickel/molybdenum catalyst, moving
bed, heavy gas oil feed

3.3.2.5 Source Reduction

There is little that can be done to reduce the quantity of these generated catalyst since, by
design, they must be periodically replaced with fresh catalyst. As a result, the greatest
opportunity for waste minimization arises from sending these materials offsite for metals
regeneration, reclamation, or other reuse.

Refinery hydrocracking catalysts generally consist of cobalt and molybdenum or nickel

and molybdenum on an alumina support. Typically, the catalysts are regenerated after use.
However, industry is interested in finding more specific, long-lasting catalysts. Extensive
research is performed in producing new catalysts. Information on hydrotreating and
hydrorefining catalysts are also presented below because some of this information may be
relevant to hydrocracking catalysts.

Reference Waste Minimization/Management Methods

Monticello, D.J. “Biocatalytic Desulfurization.” An alternative to metal catalysts is the
Hydrocarbon Processing. February, 1994. development of microorganisms that can
catalyze the reaction.
”NPRA Q&A 1: Refiners Focus on FCC, Methods in improving catalyst life and
Hydroprocessing, and Alkylation Catalyst.” Oil & Gas performance.
Journal. March 28, 1994.
Gorra, F., Scribano, G., Christensen, P., Anderson, K.V., Material substitution to extend catalyst life.
and Corsaro, O.G. “New Catalyst, Improve Presulfiding
Result in 4+ Year Hydrotreater Run.” Oil & Gas Journal.
August 23, 1993.
”Petroleum-derived Additive Reduces Coke on Process modification extends life of catalyst.
Hydrotreating Catalyst.” Oil & Gas Journal. December
27, 1993.
”Waste Minimization in the Petroleum Industry: A Practices listed: 1. Metals reclamation, 2.
Compendium of Practices.” API. November, 1991. Recycling to cement, 3. Recycling to
fertilizer plants.

Petroleum Refining Industry Study 39 August 1996

 Table 3.3.4. Spent Hydrocracking Catalyst Characterization
Petroleum Refining Industry Study

Volatile Organics - Method 8260A µg/kg

CAS No. R2-CC-02 R8A-CC-01 R20-CC-01 Average Conc Maximum Conc Comments
Acetone 67641 5,300 < 6,250 < 1,250 3,275 5,300 1
Acrolein 107028 2,500 < 6,250 < 1,250 1,875 2,500 1
Benzene 71432 370,000 15,000 < 1,250 128,750 370,000
n-Butylbenzene 104518 10,000 40,000 12,000 20,667 40,000
sec-Butylbenzene 135988 < 1,250 18,000 13,000 10,750 18,000
Ethylbenzene 100414 35,000 95,000 < 1,250 43,750 95,000
Isopropylbenzene 98828 < 1,250 34,000 3,700 17,625 34,000
p-Isopropyltoluene 99876 < 1,250 28,000 8,500 12,583 28,000
Naphthalene 91203 < 1,250 64,000 7,600 24,283 64,000
n-Propylbenzene 103651 5,000 49,000 < 1,250 27,000 49,000
Toluene 108883 300,000 120,000 < 1,250 140,417 300,000
1,2,4-Trimethylbenzene 95636 25,000 170,000 21,000 72,000 170,000
1,3,5-Trimethylbenzene 108678 8,000 48,000 4,200 20,067 48,000
o-Xylene 95476 23,000 120,000 3,400 48,800 120,000
m,p-Xylenes 108383 / 106423 60,000 250,000 7,100 105,700 250,000
TCLP Volatile Organics - Methods 1311 and 8260A µg/L
CAS No. R2-CC-02 R8A-CC-01 R20-CC-01 Average Conc Maximum Conc Comments
40

Benzene 71432 10,000 230 < 50 3,427 10,000

Ethylbenzene 100414 470 180 < 50 233 470
Methylene chloride 75092 < 50 250 < 50 117 250
Toluene 108883 6,600 640 < 50 2,430 6,600
1,2,4-Trimethylbenzene 95636 J 94 120 J 44 86 120
1,3,5-Trimethylbenzene 108678 < 50 < 50 J 61 54 61
o-Xylene 95476 290 270 < 50 203 290
m,p-Xylene 108383 / 106423 750 410 < 50 403 750
Semivolatile Organics - Method 8270B µg/kg
CAS No. R2-CC-02 R8A-CC-01 R20-CC-01 Average Conc Maximum Conc Comments
Acenaphthene 83329 < 165 20,000 32,000 17,388 32,000
Benz(a)anthracene 56553 < 165 J 6,900 < 10,313 3,533 6,900 1
Benzofluoranthene (total) NA < 165 J 5,000 31,000 12,055 31,000
Benzo(g,h,i)perylene 191242 < 165 28,000 42,000 23,388 42,000
Benzo(a)pyrene 50328 < 165 J 3,100 29,000 10,755 29,000
Carbazole 86748 < 330 74,000 J 24,000 32,777 74,000
4-Chlorophenyl phenyl ether 7005723 < 165 < 4,125 83,000 29,097 83,000
August 1996

Chrysene 218019 < 165 17,000 68,000 28,388 68,000

Dibenzofuran 132649 1,200 9,700 J 13,000 7,967 13,000
7,12-Dimethylbenz(a)anthracene 57976 < 165 < 4,125 45,000 16,430 45,000
 Table 3.3.4. Spent Hydrocracking Catalyst Characterization (continued)
Petroleum Refining Industry Study

Semivolatile Organics - Method 8270B µg/kg (continued)

CAS No. R2-CC-02 R8A-CC-01 R20-CC-01 Average Conc Maximum Conc Comments
Fluoranthene 206440 < 165 20,000 25,000 15,055 25,000
Fluorene 86737 2,800 40,000 82,000 41,600 82,000
Indeno(1,2,3-cd)pyrene 193395 < 165 J 4,600 < 10,313 2,383 4,600 1
3-Methylcholanthrene 56495 < 165 < 4,125 23,000 9,097 23,000
2-Methylchrysene 3351324 < 330 J 13,000 64,000 25,777 64,000
1-Methylnaphthalene 90120 < 330 56,000 230,000 95,443 230,000
2-Methylnaphthalene 91576 < 165 110,000 390,000 166,722 390,000
2-Methylphenol 95487 < 165 < 4,125 J 7,000 3,763 7,000
Naphthalene 91203 < 165 43,000 45,000 29,388 45,000
Phenanthrene 85018 1,200 180,000 160,000 113,733 180,000
Pyrene 129000 1,600 430,000 680,000 370,533 680,000
TCLP Semivolatile Organics - Methods 1311 and 8270B µg/L
CAS No. R2-CC-02 R8A-CC-01 R20-CC-01 Average Conc Maximum Conc Comments
Carbazole 86748 < 100 J 78 < 100 78 78 1
2,4-Dimethylphenol 105679 < 50 J 23 J 44 34 44 1
1-Methylnaphthalene 90120 < 100 J 24 J 41 33 41 1
2-Methylnaphthalene 91576 < 50 J 46 J 59 52 59
41

2-Methylphenol 95487 J 66 J 70 J 25 54 70
3/4-Methylphenol (total) NA J 76 J 49 J 17 47 76
Naphthalene 91203 < 50 J 44 J 26 35 44 1
Phenol 108952 J 53 < 50 J 63 55 63
Phenanthrene 85018 < 50 J 23 < 50 23 23 1
Pyrene 129000 < 50 J 42 < 50 42 42 1
Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg
CAS No. R2-CC-02 R8A-CC-01 R20-CC-01 Average Conc Maximum Conc Comments
Aluminum 7429905 120,000 53,000 110,000 94,333 120,000
Antimony 7440360 < 6.0 220 < 6.0 77.3 220
Arsenic 7440382 12.0 29.0 < 5.0 15.3 29.0
Beryllium 7440417 < 0.5 160 18.0 59.5 160
Chromium 7440473 130 68.0 < 1.0 66.3 130
Cobalt 7440484 24.0 440 < 5.0 156 440
Copper 7440508 55.0 35.0 < 2.5 30.8 55.0
Iron 7439896 52,000 2,200 570 18,257 52,000
Lead 7439921 < 0.3 15.0 1.6 5.6 15.0
August 1996

Manganese 7439965 390 16.0 < 1.5 136 390

Molybdenum 7439987 < 6.5 5,400 17,000 7,469 17,000
Nickel 7440020 19,000 28,000 27,000 24,667 28,000
 Table 3.3.4. Spent Hydrocracking Catalyst Characterization (continued)
Petroleum Refining Industry Study

Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg (continued)
CAS No. R2-CC-02 R8A-CC-01 R20-CC-01 Average Conc Maximum Conc Comments
Selenium 7782492 < 0.5 4.0 < 0.5 1.7 4.0
Sodium 7440235 1,200 2,000 < 500 1,233 2,000
Vanadium 7440622 37.0 140,000 49,000 63,012 140,000
Zinc 7440666 82.0 110 < 2.0 64.7 110
TCLP Metals - Methods 1311, 6010, 7060, 7421, 7470, 7471, and 7841 mg/L
CAS No. R2-CC-02 R8A-CC-01 R20-CC-01 Average Conc Maximum Conc Comments
Aluminum 7429905 26.0 < 1.00 < 1.00 9.33 26.00
Chromium 7440473 0.35 < 0.05 < 0.05 0.15 0.35
Iron 7439896 130 < 0.50 < 0.50 43.7 130
Manganese 7439965 10.0 < 0.08 < 0.08 3.38 10.0
Nickel 7440020 110 3.60 0.43 38.0 110
Vanadium 7440622 < 0.25 4.70 < 0.25 1.73 4.70
Zinc 7440666 0.58 < 0.10 < 0.10 0.26 0.58
Miscellaneous Characterization
R2-CC-02 R8A-CC-01 R20-CC-01
Ignitability (oF) 138 145 NA

Comments:
42

1 Detection limits greater than the highest detected concentration are excluded from the calculations.

Notes:

B Analyte also detected in the associated method blank.

J Compound's concentration is estimated. Mass spectral data indicate the presence of a compound that meets the identification criteria for which the result is less than the laboratory detection limit, but greater than
zero.
ND Not Detected.
ND Not Applicable.
August 1996
Petroleum Refining Industry Study 43 August 1996
 STUDY OF SELECTED
PETROLEUM REFINING RESIDUALS

INDUSTRY STUDY

Part 2

August 1996

U.S. ENVIRONMENTAL PROTECTION AGENCY

Office of Solid Waste
Hazardous Waste Identification Division
401 M Street, SW
Washington, DC 20460
3.4 ISOMERIZATION

The purpose of isomerization is to increase the refinery's production of high octane, low
aromatic gasoline. Gasoline with low benzene and aromatics is newly specified in the California
market and is expected to be adopted by other states in the future (Oil & Gas Journal, 1995)1.

3.4.1 Isomerization Process Description

Principal applications of isomerization at refineries are naphtha isomerization, which

produces a gasoline blending component, and butane isomerization, which produces isobutane
feed for the alkylation unit. Figure 3.4.1 depicts a generic process flow diagram for
isomerization. Based on the results of the RCRA §3007 questionnaire, 65 facilities reported
having isomerization units, distributed as follows (some facilities have more than one type of
isomerization unit):

• 47 facilities have naphtha isomerization units

• 15 facilities have butane isomerization units
• 7 facilities have other types of isomerization units.

Figure 1.1.1. Isomerization Process Flow Diagram

1
Oil & Gas Journal, “Deadline Looming for California Refineries to Supply Phase II RFG,” December 11,
1995, pages 21-25.

Petroleum Refining Industry Study 49 August 1996

3.4.1.1 Naphtha Isomerization

Gasoline, or naphtha, is generated throughout the refinery and consists of a mix of C5 and
higher hydrocarbons in straight, branched, or ring configuration. Naphtha isomerization
converts the straight chains to branched, significantly raising their octane number. A common
source of such “low grade” naphtha is light straight run, which consists of the lighter fraction
(C5/C6) of naphtha from atmospheric crude distillation. The reduction of lead in gasoline in the
1970s increased the demand for isomerization technology; prior to that time naphtha
isomerization was not widely used (Meyers, 1986).

As found from the RCRA §3007 questionnaire results, the most common naphtha
isomerization processes presently used in the industry are UOP's Penex process and Union
Carbide's Total Isomerization Process (TIP). Other licensed processes used include the Union
Carbide Hysomer process and the BP Isomerization process. In these four processes, naphtha is
combined with hydrogen and flows through one or two fixed bed reactors in series; the catalyst
consists of a precious metal catalyst on a support (non-precious metal catalysts are rarely, if
ever, used for naphtha isomerization). The reactor effluent is sent to a series of columns where
hydrogen and fuel gas are separated from the isomerate product. The isomerate, having a
significantly higher octane number than the light straight run feed, is charged to the gasoline
blending pool. Although the isomerization reaction is not a net consumer or producer of
hydrogen, the presence of hydrogen prevents coking and subsequent deactivation of the catalyst
(Meyers, 1986).

From a solid waste generation perspective, the principal differences between the various
processes relate to the catalyst used; this will in turn affect the feed pretreatment steps and spent
catalyst characterization. The two principal types of catalyst identified in the industry are: (1)
platinum on zeolite, which operates at temperatures above 200 C, and (2) platinum chloride on
alumina, which operates at temperatures below 200 C. The higher temperatures are
characteristic of the TIP and Hysomer processes, while the lower temperatures are characteristic
of the Penex process and the BP process. The effect of these two different precious metal
catalysts on the process are as follows:

• Dioxin formation. To maintain an environment of hydrogen chloride in the

reactor required for catalyst activity, the platinum chloride catalyst requires a
small but continuous addition of a chlorinated organic compound (e.g., carbon
tetrachloride) to the feed. Although no oxygen is present during operating
conditions, the conditions encountered during unit turnaround and catalyst
removal (see Section 3.4.3) could result in dioxin formation. During sampling
and analysis, the Agency tested for dioxin and the results are presented in Table
3.4.4.

Unlike reforming unit catalyst (a platinum catalyst discussed in the Listing

Background Document), the isomerization unit catalyst apparently does
not undergo in situ regeneration. One refinery stated that they do not
conduct regeneration because coke does not form and contaminate the
catalyst (making regeneration unnecessary), and design information for
these units does not mention in situ regeneration.

Petroleum Refining Industry Study 50 August 1996

 • Feed pretreatment. The platinum chloride catalyst, operating at the lower
temperatures, provides better conversion of paraffins to isomers. However, this
catalyst is susceptible to water, sulfur, and nitrogen as catalyst poisons (Meyers,
1986). To combat these contaminants, the feed is commonly desulfurized over a
cobalt/molybdenum or similar catalyst and generated H2S is removed prior to the
isomerization reactor. To further protect against sulfur poisoning, some processes
include a guard column between the hydrodesulfurization reactor and the
isomerization reactor to remove additional sulfur-containing compounds. Rather
than consisting of Co/Mo (like many hydrotreating catalysts), this guard column
often consists of zinc oxide, nickel on alumina, or copper oxide.

To remove water from the desulfurized naphtha, the hydrocarbon feed is typically
dried using molecular sieve. When the molecular sieve is saturated, it is taken
off-line for water desorption while the hydrocarbon is rerouted to a parallel
molecular sieve vessel. In a similar way, water is removed from the hydrogen
feed. Certain molecular sieves can remove both sulfur compounds and water
from hydrogen or hydrocarbon feeds.

The platinum on zeolite catalyst is less susceptible to poisoning by these

contaminants and reportedly requires none, or significantly less, pretreatment
(Meyers, 1986).

Another difference in operating practices found among individual refineries is product

stream recycling to increase yield and octane. These qualities can be increased by (1) recycling
the paraffins to the reactor following their separation from the isomerized product, or (2)
separating (and effectively concentrating) low octane paraffins from other high octane feed
components such as isomers and aromatics. These steps can be performed using either
conventional fractionation or an adsorbent. In the latter case, the normal paraffins are adsorbed
onto zeolite or another adsorbent while the isomers pass through. The paraffins are desorbed
and introduced as isomerization reactor feed, while the isomers bypass the isomerization reactor
and are introduced to a post reactor stabilizer. Not all refineries conduct such separation,
although separation of the feed or product using molecular sieve is integral to the Union Carbide
Total Isomerization Process.

3.4.1.2 Butane Isomerization

The purpose of butane isomerization is to generate feed material for a facility's alkylation
or MTBE production unit; alkylation unit feed includes isobutane and olefins, while the raw
materials used in making MTBE are isobutylene and methanol. Butane isomerization is a much
older process than naphtha isomerization, having been used in refineries since World War II.
Presently, the most prevalent method of producing isobutane from n-butane is the UOP Butamer
process, similar in many ways to the isomerization of naphtha over platinum chloride catalyst.
In the Butamer process, normal butane, generated from throughout the refinery and separated
from other butanes by distillation, is combined with hydrogen and a chlorinated organic
compound. The hydrogen is used to suppress the polymerization of olefin intermediates, while
the chlorine source is used to maintain catalyst activity. The feed flows through one or two
fixed bed reactors in series, containing platinum chloride on alumina catalyst. The isobutane

Petroleum Refining Industry Study 51 August 1996

product is recovered and used as alkylation unit feed. Butane isomerization takes place at lower
temperatures than naphtha isomerization.

Like platinum chloride catalyst used in naphtha isomerization, the Butamer catalyst is
poisoned by water and sulfur, as well as fluoride (Meyers, 1986). These compounds are
removed from the hydrogen and hydrocarbon feed by molecular sieve.

Although the Butamer process and others using platinum chloride on alumina as a
catalyst dominate the industry, other technologies are also used. Three facilities conducting
butane isomerization do not use platinum catalysts. Instead, the catalyst is aluminum
chloride/hydrochloric acid and generates an almost continuous spent catalyst waste stream in
slurry or sludge form.

3.4.1.3 Other Isomerization Processes

Seven facilities reported using isomerization for purposes other than naphtha or butane
isomerization. Such applications demonstrate the integration of petroleum refining and chemical
production at many refineries. Some of these processes more closely represent petrochemical
production than refining processes because they are not widely reported by refineries as a
refining step, are not used for fuel production, and produce commodity chemicals. The
processes reported by these seven facilities can be classified into three areas:

• Xylene Isomerization. Four facilities report processes to convert xylene isomers

(e.g., from an extraction process) to p- and/or o-xylene. Unlike the naphtha and
butane isomerization units described above, the catalyst is not precious metal.
The xylene products are sold.

• Cyclohexane Isomerization. Two facilities produce cyclohexane from raw

materials that include benzene and hydrogen. Unlike the naphtha and butane
isomerization units described above, the catalyst is not precious metal.

• Butylene Isomerization. Two facilities produce butylene from various C4

olefins. Butylene is used for feed to the alkylation unit. A precious metal
(palladium) catalyst is used.

3.4.2 Isomerization Catalyst

3.4.2.1 Description

As discussed in Section 3.4.1, the most prevalent catalyst used for both butane and
naphtha isomerization is platinum or platinum chloride on alumina or zeolite. When the catalyst
loses activity, it is removed from the reactor and replaced with fresh catalyst. Prior to removal,
the reactor may be swept to remove hydrocarbons from the catalyst. These preparation steps can
include one or more of the following:

• Nitrogen sweep (to remove hydrocarbon)

• Oxygen sweep (to burn hydrocarbon)

Petroleum Refining Industry Study 52 August 1996

 • Steam stripping (to remove hydrocarbon).

This procedure of catalyst preparation, removal, and replacement is relatively lengthy (typically
one week or more) and requires the unit, or at least the reactor, to be shut down such that no
hydrocarbon is processed during the time of catalyst replacement.

There are a handful of isomerization processes used at domestic refineries that do not use
platinum or platinum chloride catalyst. At these facilities, spent catalyst is generated in one of
the following two methods:

• A method similar to the generation of spent platinum/platinum chloride catalyst

described above. Fixed-bed processes are used in both palladium and non-
precious metal catalyst applications and spent solid catalyst is infrequently
removed.

• A method where catalyst is removed from the fixed-bed reactor frequently (up to
once a day) in liquid/semi-solid form, presumably with little to no disruption of
the process. This method is used only for one process which uses aluminum
chloride/hydrochloric acid catalyst.

Another type of catalyst seen in conjunction with an isomerization unit is desulfurization

catalyst. In many naphtha isomerization processes, the feed typically contains high levels of
mercaptans which are converted to H2S over a non-precious metal catalyst, such as
cobalt/molybdenum. Such catalysts were discussed in the Listing Background Document under
the broad name of “hydrotreating catalysts” and will not be discussed here.

3.4.2.2 Generation and Management

The spent catalyst is vacuumed or gravity dumped from the reactors. Based on
information from site visits, most refineries place the material directly into closed containers
such as 55-gallon drums, flow-bins, or 1 cubic yard “supersacks.” The frequency of generation
is typically between 2 and 10 years, with a small number of facilities generating a slurry/sludge
continuously. In 1992, only one facility reported classifying this residual as RCRA hazardous
(this facility classified 2 MT as D001).2 In other years, some facilities reported that this residual
carried a RCRA hazardous waste code of D018 (TCLP benzene).

Eighteen facilities reported generating a total quantity of 337 MT of this residual in

1992, according to the 1992 RCRA §3007 Questionnaire. The questionnaire reported that 65
facilities have isomerization units and thus are likely to generate spent isomerization catalyst at
some time. Due to the infrequent generation of this residual, not all of these 65 facilities
generated spent catalyst in 1992. However, there was no reason to expect that 1992 would not
be a typical year with regard to this residual's generation and management.

2
These percentages do not match up directly with any one of the management scenarios because the number of
streams and the volume are a combination of several management scenarios (i.e., Subtitle C landfill, transfer for
metals reclamation, etc.).

Petroleum Refining Industry Study 53 August 1996

Petroleum Refining Industry Study 54 August 1996
 Residuals were assigned to be “spent isomerization catalyst” if they were assigned a
residual identification code of “spent solid catalyst” and were generated from a process
identified as an isomerization unit. These correspond to residual code 03-A in Section VII.A of
the questionnaire and process code 10 in Section IV.C of the questionnaire. The small volume
of continuously generated residuals (discussed in Section 3.4.3.1) were typically omitted from
these statistics, because they were most often characterized as sludges. However, as stated in
Section 3.4.1, some nonprecious metal catalysts are also used in fixed bed processes and are
included in these statistics. Table 3.4.1 provides a description of the 1992 management
practices, quantity generated, number of streams reported, number of streams not reporting
volumes (data requested was unavailable and facilities were not required to generate it), total and
average volumes.

Table 3.4.1. Generation Statistics for Catalyst from Isomerization, 1992

# of # of Streams w/ Total Average

Final Management Streams Unreported Volume Volume (MT) Volume (MT)
Disposal in offsite Subtitle C landfill 3 0 43.79 14.60
Transfer metal catalyst for 17 0 293.40 17.26
reclamation or regeneration
TOTAL 20 0 337.19 16.86

3.2.2.3 Plausible Management

EPA believes that most of the plausible management practices for this residual were
reported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.4.1. The Agency
assessed information reported for other years but no additional management practices were
reported for this residual. In addition, EPA compared the management practice reported for
isomerization catalysts to those reported for reforming catalysts (a listing residual described in
the Listing Background Document) based on expected similarities. The vast majority of both
wastes are reclaimed due to their precious metal content.

3.4.2.4 Characterization

Two sources of residual characterization were developed during the industry study:

• Table 3.4.2 summarizes the physical properties of the spent catalyst as reported in
Section VII.A of the §3007 survey.

• Four record samples of spent isomerization catalyst were collected and analyzed
by EPA. These spent catalysts represent the majority of processes used by the
industry. Sampling information is summarized in Table 3.4.3.

Petroleum Refining Industry Study 55 August 1996

 Table 3.4.2. Catalyst from Isomerization: Physical Properties

# of # of Unreported
Properties Values Values1 10th % 50th % 90th %
pH 20 51 3.35 4.50 7.75
Reactive CN, ppm 14 57 0.04 1.00 11.60
Reactive S, ppm 16 55 0.90 3.00 100.00
Flash Point, C 15 56 60.00 100.00 200.00
Oil and Grease, vol% 14 56 0.00 0.50 1.00
Total Organic Carbon, vol% 13 58 0.00 0.20 3.00
Specific Gravity 23 48 0.65 1.08 3.00
Aqueous Liquid, % 32 39 0.00 0.00 0.00
Organic Liquid, % 32 39 0.00 0.00 1.00
Solid, % 52 19 95.00 100.00 100.00
Other, % 29 42 0.00 0.00 0.00
Particle >60 mm, % 11 60 0.00 0.00 100.00
Particle 1-60 mm, % 22 49 0.00 100.00 100.00
Particle 100 µm-1 mm, % 13 58 0.00 0.00 1.00
Particle 10-100 µm, % 13 58 0.00 0.00 5.00
Particle <10 µm, % 11 60 0.00 0.00 0.00
Median Particle Diameter, microns 9 62 0.00 1,590.00 2,000.00

1
Facilities were not required to do additional testing, therefore information provided was based on previously collected
data or engineering judgement.

Table 3.4.3. Spent Isomerization Catalyst Record Sampling Locations

Sample number Facility Description: Process Name/Catalyst Type

R5B-IC-01 Marathon, Garyville LA Butane isomerization (UOP Butamer process),

platinum chloride catalyst

R8B-IC-01 Amoco, Texas City TX Naphtha isomerization (UOP Penex process),

platinum chloride catalyst

R18-IC-01 Ashland, Canton OH Naphtha isomerization (UOP Penex process),

platinum chloride catalyst

R23B-IC-01 Chevron, Salt Lake Butane isomerization (UOP Butamer process),

City, UT platinum chloride catalyst

Petroleum Refining Industry Study 56 August 1996

 The collected samples are expected to be representative of processes using platinum
chloride catalyst. Other processes use platinum catalyst or (rarely) non-precious metal catalysts.
Because similar feeds are processed by most isomerization processes, these spent catalysts are
expected to display similar characteristics, with the following exceptions: (1) spent platinum
chloride catalysts (and possibly aluminum chloride/hydrogen chloride catalysts) are the only
catalysts expected to contain dioxins, because of the presence of chlorine in the process, (2)
platinum chloride catalysts require cleaner feed (i.e., water and sulfur are catalyst poisons), and
thus concentrations of some contaminants may be greater in spent catalysts from processes not
using platinum chloride catalysts.

All four record samples were analyzed for total and TCLP levels of volatiles,
semivolatiles, metals, and reactivity (pyrophoricity). Three samples were analyzed for total
levels of dioxins/furans. Three of the four samples were found to exhibit the toxicity
characteristic for benzene (i.e., the level of benzene in these samples' TCLP extracts exceeded
the corresponding regulatory level). A summary of the analytical results is presented in Table
3.4.4. Only constituents detected in at least one sample are shown in this table.

3.4.2.5 Source Reduction

As in the case of the hydrocracking catalyst, source reduction methods are those that
extend the life of the catalyst. Currently, recycling of the spent catalyst by sending to metals
reclamation is a common practice since the catalyst is platinum.

Reference Waste Minimization Methods

J. Liers, J. Mensinger, A. Mosch, W. Reschefilowski. The platinum catalyst together with erionite
“Reforming Using Erionite Catalysts.” Hydrocarbon increases isomerization.
Processing. Aug. 1993.

Petroleum Refining Industry Study 57 August 1996

 Table 3.4.4. Residual Characterization Data for Spent Isomerization Catalyst
Petroleum Refining Industry Study

Volatile Organics - Method 8260A µg/kg

CAS No. R5B-IC-01 R8B-IC-01 R18-IC-01 R23B-IC-01 Average Conc Maximum Conc Comments
Acetone 67641 < 625 < 625 B 1,200 < 15,625 817 1,200 1
Benzene 71432 24,000 19,000 280,000 < 15,625 84,656 280,000
tert-Butylbenzene 98066 < 625 < 625 1,900 < 15,625 1,050 1,900 1
Chlorobenzene 108907 < 625 15,000 J 580 < 15,625 5,402 15,000 1
Chloromethane 74873 3,700 1,900 2,800 150,000 39,600 150,000
2-Chlorotoluene 95498 < 625 < 625 1,900 < 15,625 1,050 1,900 1
4-Chlorotoluene 106434 < 625 < 625 1,300 < 15,625 850 1,300 1
1,4-Dichlorobenzene 106467 < 625 J 730 < 600 < 15,625 652 730 1
Ethylbenzene 100414 < 625 < 625 63,000 < 15,625 19,969 63,000
Isopropylbenzene 98828 < 625 < 625 J 520 < 15,625 520 520 1
n-Propylbenzene 103651 < 625 < 625 1,800 < 15,625 1,017 1,800 1
Methyl ethyl ketone 78933 < 625 < 625 B 1,200 < 15,625 817 1,200 1
Toluene 108883 < 625 J 500 270,000 < 15,625 71,688 270,000
1,2,4-Trimethylbenzene 95636 < 625 1,500 3,800 < 15,625 1,975 3,800 1
1,3,5-Trimethylbenzene 108678 < 625 J 540 < 600 < 15,625 540 540 1
o-Xylene 95476 < 625 < 625 29,000 < 15,625 11,469 29,000
m,p-Xylenes 108383 / 106423 < 625 J 720 190,000 < 15,625 51,743 190,000
58

Naphthalene 91203 < 625 1,900 < 600 J 9,800 3,231 9,800
TCLP Volatile Organics - Methods 1311 and 8260A µg/L
CAS No. R5B-IC-01 R8B-IC-01 R18-IC-01 R23B-IC-01 Average Conc Maximum Conc Comments
Acetone 67641 < 50 < 50 B 180 < 50 83 180
Benzene 71432 1,700 1,400 8,800 < 50 2,988 8,800
Chlorobenzene 108907 < 50 220 < 50 < 50 93 220
2-Chlorotoluene 95498 < 50 < 50 J 33 < 50 33 33 1
4-Chlorotoluene 106434 < 50 < 50 J 21 < 50 21 21 1
Ethylbenzene 100414 < 50 < 50 1,500 < 50 413 1,500
Methylene chloride 75092 < 50 B 3,500 J 23 < 50 906 3,500
Methyl ethyl ketone 78933 < 50 < 50 J 42 < 50 42 42 1
Toluene 108883 < 50 J 48 8,300 < 50 2,112 8,300
1,2,4-Trimethylbenzene 95636 < 50 < 50 J 55 < 50 51 55
o-Xylene 95476 < 50 < 50 930 < 50 270 930
m,p-Xylene 108383 / 106423 < 50 < 50 3,800 < 50 988 3,800
Naphthalene 91203 < 50 < 50 < 50 J 26 26 26 1
August 1996
 Table 3.3.4. Residual Characterization Data for Spent Isomerization Catalyst (continued)
Petroleum Refining Industry Study

Semivolatile Organics - Method 8270B µg/kg

CAS No. R5B-IC-01 R8B-IC-01 R18-IC-01 R23B-IC-01 Average Conc Maximum Conc Comments
Bis(2-ethylhexyl) phthalate 117817 < 165 J 410 710 < 165 363 710
7,12-Dimethylbenz(a)anthracene 57976 J 73 J 600 < 165 < 165 251 600
Isophorone 78591 1,200 15,000 J 220 2,700 4,780 15,000
2,4-Dimethylphenol 105679 < 165 < 413 1,000 < 165 436 1,000
2-Methylphenol 95487 < 165 < 413 640 < 165 346 640
3/4-Methylphenol NA < 165 < 413 1,500 < 165 561 1,500
Phenol 108952 < 165 < 413 1,700 < 165 611 1,700
TCLP Semivolatile Organics - Methods 1311 and 8270B µg/L
CAS No. R5B-IC-01 R8B-IC-01 R18-IC-01 R23B-IC-01 Average Conc Maximum Conc Comments
Bis(2-ethylhexyl) phthalate 117817 < 50 < 25,000 J 18 < 50 18 18 1, 2
Di-n-butyl phthalate 84742 J 31 < 25,000 J 50 < 50 44 50 2
2,4-Dimethylphenol 105679 < 50 320,000 J 53 < 50 51 53 2
2-Methylphenol 95487 < 50 140,000 140 < 50 80 140 2
3/4-Methylphenol (total) NA < 50 870,000 240 < 50 113 240 2
Phenol 108952 < 50 < 25,000 840 < 50 313 840 2
Isophorone 78591 < 50 J 6,700 < 50 < 50 NA NA 2
Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg
59

CAS No. R5B-IC-01 R8B-IC-01 R18-IC-01 R23B-IC-01 Average Conc Maximum Conc Comments
Aluminum 7429905 460,000 130,000 260,000 230,000 270,000 460,000
Arsenic 7440382 < 1.00 < 1.00 26.0 < 1.00 7.25 26.0
Chromium 7440473 20.0 17.0 17.0 17.0 17.8 20.0
Copper 7440508 < 2.50 < 2.50 < 2.50 5.50 3.25 5.50
Iron 7439896 < 10.0 54.0 190 73.0 81.8 190
Nickel 7440020 14.0 10.0 < 4.00 < 4.00 8.00 14.0
Zinc 7440666 < 2.00 < 2.00 < 2.00 9.2 3.80 9.20
TCLP Metals - Methods 1311, 6010, 7060, 7421, 7470, 7471, and 7841 mg/L
CAS No. R5B-IC-01 R8B-IC-01 R18-IC-01 R23B-IC-01 Average Conc Maximum Conc Comments
Aluminum 7429905 620 560 380 450 503 620
Chromium 7440473 < 0.05 < 0.05 0.13 < 0.05 0.07 0.13
Iron 7439896 2.40 < 0.50 7.60 < 0.50 2.75 7.60
Lead 7439921 < 0.015 < 0.015 0.045 < 0.015 0.023 0.045
Manganese 7439965 < 0.08 < 0.08 0.42 < 0.08 0.16 0.42
Zinc 7440666 B 0.45 B 0.41 B 0.70 B 0.53 0.52 0.70
August 1996
 Table 3.3.4. Residual Characterization Data for Spent Isomerization Catalyst (continued)
Petroleum Refining Industry Study

Dioxins/Furans - Method 8290 ng/kg

CAS No. R5B-IC-01 R8B-IC-01 R18-IC-01 R23B-IC-01 Average Conc Maximum Conc Comments
2,3,7,8-TCDF 51207319 < 0.13 < 0.20 B 0.69 NA 0.34 0.69
Total TCDF 55722275 < 0.13 < 0.20 B 0.69 NA 0.34 0.69
2,3,4,6,7,8-HxCDF 60851345 0.32 < 0.34 < 0.50 NA 0.32 0.32 1
Total HxCDF 55684941 B 0.32 < 0.34 < 0.50 NA 0.32 0.32 1
1,2,3,4,6,7,8-HpCDF 67562394 0.42 < 0.26 < 0.37 NA 0.35 0.42
Total HpCDF 38998753 2.10 < 0.26 < 0.37 NA 0.91 2.10
1,2,3,4,6,7,8-HpCDD 35822469 3.00 < 0.60 < 0.50 NA 1.37 3.00
Total HpCDD 37871004 B 3.00 < 0.60 < 0.50 NA 1.37 3.00
OCDF 39001020 3.70 < 0.80 < 0.55 NA 1.68 3.70
OCDD 3268879 B 43.0 B 1.70 B 1.70 NA 15.47 43.00
2,3,7,8-TCDD Equivalence 1746016 0.11 0.0017 0.071 NA 0.06 0.11

Comments:

1 Detection limits greater than the highest detected concentration are excluded from the calculations.
2 TCLP Semivolatile Organic results for sample R8B-IC-01 are excluded from the calculations.

Notes:
60

B Analyte also detected in the associated method blank.

J Compound's concentration is estimated. Mass spectral data indicate the presence of a compound that meets the identification criteria for which the result is less than the laboratory detection limit, but greater than
zero.
NA Not Applicable.
August 1996
3.4.3 Isomerization Treating Clay

3.4.3.1 Description

Not all facilities with isomerization units use “treating clay,” or adsorbents. However,
solid adsorbents can be used in three places in the isomerization process:

• Hydrocarbon feed purification. Processes using platinum chloride catalysts require

a purified feed. Both spent molecular sieve (for drying) and spent metal-alumina (for
sulfur removal) are generated.

• Hydrogen feed purification. Processes using platinum chloride catalysts require dry
hydrogen gas. Spent molecular sieve is generated.

• Paraffin separation of the feed or product. Various types of processes use

adsorbents for paraffin separation. Molecular sieve is the most common adsorbent for
this application.

All of these adsorbents go through adsorption/desorption cycles. Over time, the adsorbent loses
its capacity or efficiency and is removed from the vessel and replaced with fresh adsorbent.
Prior to removal, the vessel can be swept to remove light hydrocarbons and hydrogen sulfide
from the vessel. Typically, processes use adsorbent beds in parallel so that one bed can be on-
line (adsorption mode) while the second is off-line for desorption or replacement.

3.4.3.2 Generation and Management

When spent, adsorbents from isomerization are vacuumed or gravity dumped from the
vessels. Interim storage can include 55-gallon drums, flow-bins, dumpsters, or piles. The
frequency of generation is highly dependent on the generating process: isomerization adsorbents
are typically generated approximately every 5 years, while extraction clay is typically generated
once per year or less. According to questionnaire results, 6 facilities reported classifying 39.5
MT of this residual as RCRA hazardous in 1992 (most typically as D018, D001, and D006).3
This is consistent with reporting for other years.

Twenty-two facilities reported generating a total quantity of approximately 597 MT of

this residual in 1992, according to the 1992 RCRA §3007 Questionnaire. The questionnaire
reported that 65 facilities have isomerization units. However, not all of these facilities use clay,
molecular sieve, or other adsorbents in their process; 25 percent of facilities with isomerization
units did not report generating any clay residual for their process in any year, indicating either
that clay is either not used, has not yet been replaced, or is generated so infrequently that
respondents could not recall when, if ever, the clay was last replaced. In addition, these
adsorbents may be replaced less often than once per year or not in 1992, particularly those

3
These percentages do not match up directly with any one of the management scenarios because the number of
streams and the volume are a combination of several management scenarios (i.e., Subtitle C landfill, transfer for
metals reclamation, etc.).

Petroleum Refining Industry Study 61 August 1996

associated with the isomerization process. However, there was no reason to expect that 1992
would not be a typical year with regard to this residual's generation and management.

Residuals were assigned to be “spent clay from isomerization” if they were assigned a
residual identification code of “spent sorbent” and were generated from a process identified as
an isomerization or extraction unit. These correspond to residual code 07 in Section VII.A of
the questionnaire and process code 10 in Section IV.C of the questionnaire. Table 3.4.5 provides
a description of the 1992 management practices, quantity generated, number of streams reported,
number of streams not reporting volumes (data requested was unavailable and facilities were not
required to generate it), total and average volumes.

Table 3.4.5. Generation Statistics for Treating Clay from Isomerization, 1992
# of # of Streams w/ Total Volume Average
Final Management Streams Unreported Volume (MT) Volume (MT)
Disposal in offsite Subtitle D landfill 14 0 202 14.4
Disposal in offsite Subtitle C landfill 6 0 140 23.3
Disposal in onsite Subtitle C landfill 1 0 18 18
Disposal in onsite Subtitle D landfill 2 0 46.8 23.4
Other discharge or disposal offsite: 2 0 14 7
broker
Other recycling, or reuse: cement 2 0 2.5 1.25
plant
Other recycling, or reuse: onsite road 4 0 138 34.5
material
Storage in pile 7 0 19.7 2.8
Transfer metal catalyst for reclamation 5 0 15 3
or regeneration
TOTAL 43 0 596 13.8

3.4.3.3 Plausible Management

EPA believes that most of the plausible management practices for this residual were
reported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.4.5. The Agency
gathered information from other years but no additional management practices were reported for
this residual. In addition, EPA compared the management practice reported for isomerization
treating clay to those reported for treating clays from extraction, alkylation, and lube oil4 based
on expected similarities. Land treatment was reported for these other types of treating clays,
therefore it is likely that land treatment is a plausible management practice for clays from
isomerization.

4
EPA did not compare these management practices to those reported for the broader category of “treating clay
from clay filtering” due to the diverse types of materials included in this miscellaneous category.

Petroleum Refining Industry Study 62 August 1996

3.4.3.4 Characterization

Two sources of residual characterization were developed during the industry study:

• Table 3.4.6 summarizes the physical properties of the spent adsorbents as reported in
Section VII.A of the §3007 survey.

• One record sample of spent adsorbents from isomerization were collected and
analyzed by EPA. The isomerization treating clay was categorized with the extraction
clay in the consent decree, therefore, the sampling information is summarized with the
extraction clay in Table 3.4.7.

The one record sample was analyzed for total and TCLP levels of volatiles,
semivolatiles, and metals, and ignitability. The sample was not found to exhibit a hazardous
waste characteristic. A summary of the results is presented in Table 3.4.7. Only constituents
detected in at least one sample are shown in this table.

3.4.3.5 Source Reduction

Treating clay for isomerization is generally used as a method of prolonging the life of the
catalyst or for product polishing. Because they are used as a source reduction technique for
other residuals, no source reduction methods for the clays were found.

Petroleum Refining Industry Study 63 August 1996

 Table 3.4.6. Treating Clay from Isomerization: Physical Properties

# of # of Unreported
Properties Values Values1 10th % 50th % 90th %
pH 37 71 5.9 7 9.4
Reactive CN, ppm 22 86 0 1 10
Reactive S, ppm 27 81 0 1 100
Flash Point, C 20 88 19.17 60 131.7
Oil and Grease, vol% 20 85 0 0.75 1.5
Total Organic Carbon, vol% 18 87 0 0.18 2
Specific Gravity 31 77 0.8 1.2 2.2
Aqueous Liquid, % 50 58 0 0 3.5
Organic Liquid, % 51 57 0 0 0.1
Solid, % 75 33 97.5 100 100
Particle >60 mm, % 22 86 0 0 100
Particle 1-60 mm, % 32 76 0 100 100
Particle 100 µm-1 mm, % 23 85 0 0 7.5
Particle 10-100 µm, % 20 88 0 0 0
Particle <10 µm, % 20 88 0 0 0
Median Particle Diameter, microns 9 98 0 2 3000

1
Facilities were not required to do additional testing, therefore information provided was based on previously collected
data or engineering judgement.

Table 3.4.7. Isomerization Spent Sorbent Record Sampling Locations

Sample number Facility Description

R23B-CI-01 Chevron, Salt Lake City UT Molecular sieve, drying butane feed prior to
isomerization

Petroleum Refining Industry Study 64 August 1996

3.5 EXTRACTION

Extraction processes separate more valuable chemical mixtures from a mixed aromatic
and paraffinic stream. At refineries, extraction processes most commonly fall into two types: (1)
“heavy end” extraction, commonly used in lube oil manufacture and deasphalting operations to
upgrade and further process gas oils, and (2) gasoline component extraction, commonly used to
separate some of the more valuable aromatics from naphtha. “Heavy end” extraction is
discussed with other residual upgrading technologies in Section 3.8 of this document. The
gasoline component extraction processes are discussed here.

3.5.1 Extraction Process Description

Thirty facilities reported using gasoline component extraction processes in their

refineries. By far the most common type of gasoline component extraction process conducted at
refineries, according to the RCRA §3007 questionnaire, is the recovery of benzene, toluene, and
mixed xylenes from reformate (i.e., the product from a catalytic reforming unit) for sales or
further processing. Most extraction units actually consist of two sections in series: an extraction
section, which separates aromatics from non-aromatics using continuous liquid-liquid extraction,
and a distillation section, which separates the various aromatic compounds from each other in a
series of fractionation towers. Figure 3.5.1 depicts a generic extraction process flow diagram.

Figure 1.2.1. Extraction Process Flow Diagram

In the extraction section, the charge is countercurrently contacted with a solvent. The
solvent is most commonly sulfolane, C4H8SO2, or tetraethylene glycol,
O(CH2CH2OCH2CH2OH)2, although a small number of facilities use diglycol amine,
O(CCO)CCN. The raffinate is separated from the aromatic-rich solvent in a tower. The
aromatic-poor raffinate is water-washed to remove solvent and used elsewhere in the refinery.
The aromatic-rich extract is also water-washed to remove solvent and the aromatics sent to the
distillation section for separation into benzene, toluene, and xylenes.

Petroleum Refining Industry Study 65 August 1996

 In the distillation section, the aromatic extract is distilled to remove benzene from the top
of the column; the bottoms are sent to the next column. In successive columns, toluene and
finally xylene are removed. The bottoms from the xylene tower (C9 aromatics) are sent to
gasoline blending. Some facilities omit the distillation section altogether, using their extraction
unit simply to produce low and high octane blending stocks.

To decrease the unit's loading, the feed can be separated prior to extraction so that only
the most desirable fractions, such as C6 to C8, are upgraded. This eliminates a final distillation
step and eliminates a heavy aromatic stream as a product from the benzene-toluene-xylene
separation.

Several other gasoline component extraction processes are each reported by only 1 or 2
refineries in the industry. Other refineries may use these processes, but did not report them
because of their resemblance to petrochemical operations of solvent manufacture, etc., which
some refineries considered out of the survey scope. As a result, the database may not accurately
reflect the incidence of these processes. These processes are as follows:

• The UOP Parex process separates p-xylene from mixed C8 aromatics. C8 feed is
injected countercurrently to a bed of solid adsorbent, which adsorbs p-xylene. The bed
is then desorbed and the p-xylene is recovered in the extract for use in petrochemical
production. This process is typically associated with a xylene isomerization process
(Meyers, 1986). This arrangement differs from the overwhelming majority of
extraction processes, which are associated with reforming processes.

• The Union Carbide IsoSiv process separates normal C6-C8 paraffins from the other
branched and ring compounds present in light straight run. In this process, the
paraffins are adsorbed onto a fixed bed of molecular sieve. The paraffins are desorbed
and used as petrochemical feedstock, solvents, etc., while the branched and ring
compounds are used for gasoline blending (Meyers, 1986).

• One facility uses a process similar to the gasoline component extraction process
described above, but with a slightly heavier feed.

• Heavy naphtha is fed to a fixed bed of silica gel. Aromatics are adsorbed while
paraffins pass through. When saturated, the bed is desorbed with benzene and the
product distilled to form various solvents. No other adsorbents are used in the process.

3.5.2 Extraction Treating Clay

3.5.2.1. Description

Wastes generated from the reformate extraction processes include the following:

• ”Fuel side.” Treating clay is used to remove impurities from the hydrocarbon
following extraction; the most common application is the filtering of the aromatic
fraction prior to benzene distillation (to keep impurities out of the downstream
fractions), although a small number of facilities use the clay to filter the benzene

Petroleum Refining Industry Study 66 August 1996

 product stream only. The purpose of the clay is to remove olefins, suspended solids,
and trace amount of solvent by a combination of adsorption and catalytic processes. A
few facilities also treat the raffinate (non-aromatic) stream with clay. Many facilities
did not report a clay treating step anywhere in their reformate extraction process. For
these facilities, clay treating is evidently not required to achieve the target product
limits.

• ”Solvent side.” Various treatment methods are used to remove impurities such as
polymers and salts from the lean solvent. A slip stream of lean solvent is processed
using ion-exchange, sock filters, carbon adsorption, or regeneration. This is similar to
the methods used to treat amine in sulfur-removal systems. An intermittent stream of
spent solvent can sometimes be generated.

Only the “fuel side” residuals are discussed and evaluated in Section 3.4.4. The “solvent side”
residuals are generally classified as miscellaneous sludges in the database and their volumes
were not tabulated in Table 3.5.1 (below).

As stated above, reformate extraction is the most common type of gasoline component
extraction process, but the small number of other processes also generate spent adsorbents.
These processes are unlike reformate extraction because the adsorbent is used for aromatic
separation (in reformate extraction, clay treatment occurs following aromatic extraction). In
these processes, spent adsorbent is also periodically generated, although generally less frequently
so than in the reformate extraction process. These materials were included in the statistics
presented in Table 3.5.1.

3.5.2.2 Generation and Management

When spent, adsorbents from extraction are vacuumed or gravity dumped from the
vessels. Interim storage can include 55-gallon drums, flow-bins, dumpsters, or piles. The
frequency of generation is highly dependent on the generating process: extraction clay is
typically generated once per year or less. According to questionnaire results, 2 facilities reported
classifying 81.3 MT of this residual as RCRA hazardous in 1992 (as D018).5 This is consistent
with reporting for other years.

Fifteen facilities reported generating a total quantity of approximately 1900 MT of this

residual in 1992, according to the 1992 RCRA §3007 Questionnaire. The questionnaire reported
that 30 facilities have extraction units. However, not all of these facilities use clay, molecular
sieve, or other adsorbents in their process; 33 percent of facilities with extraction units did not
report generating any clay residual for their process in any year, indicating either that clay is
either not used, has not yet bee replaced, or is generated so infrequently that respondents could
not recall when, if ever, the clay was last replaced. However, there was no reason to expect that
1992 would not be a typical year with regard to this residual's generation and management.
Extraction clays are generated more frequently and in greater quantity than isomerization clays.

5
These percentages do not match up directly with any one of the management scenarios because the number of
streams and the volume are a combination of several management scenarios (i.e., Subtitle C landfill, transfer for
metals reclamation, etc.).

Petroleum Refining Industry Study 67 August 1996

 Residuals were assigned to be “spent clay from extraction” if they were assigned a
residual identification code of “spent sorbent” and were generated from a process identified as
an isomerization or extraction unit. These correspond to residual code 07 in Section VII.A and
process codes 12 in Section IV.C of the survey. Table 3.5.1 provides a description of the 1992
management practices, quantity generated, number of streams reported, number of streams not
reporting volumes (data requested was unavailable and facilities were not required to generate
it), total and average volumes.

Table 3.5.1. Generation Statistics for Treating Clay from Extraction, 1992

# of # of Streams w/ Total Volume Average

Final Management Streams Unreported Volume (MT) Volume (MT)
Disposal in offsite Subtitle D landfill 10 0 734.8 88.4
Disposal in offsite Subtitle C landfill 4 0 376.3 94
Disposal in onsite Subtitle C landfill 1 0 40 40
Disposal in onsite Subtitle D landfill 2 0 448.8 224.4
Onsite land treatment 3 0 231 78
Other recycling, or reuse: cement 1 0 26 26
plant
Transfer metal catalyst for 1 0 18 18
reclamation or regeneration
TOTAL 22 0 1875 85.2

3.5.2.3 Plausible Management

EPA believes that most of the plausible management practices for this residual were
reported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.5.1. The Agency
gathered information suggesting that “offsite land treatment” (95 MT) was used in other years.
This practice is comparable to the practice reported for 1992 (i.e., onsite land treatment). In
addition, EPA compared the management practice reported for extraction treating clay to those
reported for treating clays from isomerization, alkylation, and lube oil6 based on expected
similarities. No additional management practices were reported.

6
EPA did not compare these management practices to those reported for the broader category of “treating clay
from clay filtering” due to the diverse types of materials included in this miscellaneous category.

Petroleum Refining Industry Study 68 August 1996

3.5.2.4 Characterization

Two sources of residual characterization were developed during the industry study:

• Table 3.5.2 summarizes the physical properties of the spent adsorbents as reported in
Section VII.A of the §3007 survey.

• One record sample of spent adsorbents from extraction was collected and analyzed by
EPA. The sampling information is summarized in Table 3.5.3.

The record sample was analyzed for total and TCLP levels of volatiles, semivolatiles,
and metals, and ignitability. It was not found to exhibit a hazardous waste characteristic. A
summary of the results is presented in Table 3.5.4. Only constituents detected in at least one
sample are shown in this table. This residual was categorized with isomerization clay in the
consent decree, and the characterization information for both residuals is presented in Table
3.5.4.

3.5.2.5 Source Reduction

Treating clay for extraction is generally used as a method of prolonging the life of the
catalyst or for product polishing. Because they are used as a source reduction technique for
other residuals, no source reduction methods for the clays were found.

Petroleum Refining Industry Study 69 August 1996

 Table 3.5.2. Treating Clay from Extraction: Physical Properties

# of # of Unreported
Properties Values Values1 10th % 50th % 90th %
pH 12 17 4.28 6.65 7.5
Reactive CN, ppm 14 15 0 0.5 250
Reactive S, ppm 13 16 0 1 100
Flash Point, C 10 19 37.78 71.1 96.1
Oil and Grease, vol% 6 23 0 0.85 1
Total Organic Carbon, vol% 5 24 0 0.34 100
Specific Gravity 9 20 0.9 1 2
Aqueous Liquid, % 20 9 0 0 11
Organic Liquid, % 19 10 0 0 1
Solid, % 25 4 98 100 100
Particle >60 mm, % 10 19 0 0 100
Particle 1-60 mm, % 11 18 0 85 100
Particle 100 µm-1 mm, % 9 20 0 0 20
Particle 10-100 µm, % 8 21 0 0 20
Particle <10 µm, % 9 20 0 0 100
Median Particle Diameter, microns 1 28 10 10 10

1
Facilities were not required to do additional testing, therefore information provided was based on previously collected
data or engineering judgement.

Table 3.5.3. Extraction Spent Sorbent Record Sampling Locations

Sample number Facility Description

R8D-CI-01 Amoco, Texas City, TX Clay from aromatic extraction unit (reformate
feed)

Petroleum Refining Industry Study 70 August 1996

 Table 3.5.4. Residual Characterization Data for
Spent Treating Clay from Extraction/Isomerization

Volatile Organics - Method 8260A µg/kg

CAS No. R8D-CI-01 R23B-CI-01 Average Conc Maximum Conc Comments
Acetone 67641 < 600 940,000 470,300 940,000
Benzene 71432 2,500 < 62,500 2,500 2,500 1
Isopropylbenzene 98828 J 650 < 62,500 650 650 1
Toluene 108883 36,000 < 62,500 36,000 36,000 1
Naphthalene 91203 < 600 J 29,000 14,800 29,000
TCLP Volatile Organics - Methods 1311 and 8260A µg/L
CAS No. R8D-CI-01 R23B-CI-01 Average Conc Maximum Conc Comments
Acetone 67641 120 32,000 16,060 32,000
Benzene 71432 < 50 J 45 45 45 1
4-Methyl-2-pentanone 108101 < 50 6,100 3,075 6,100
Methyl ethyl ketone 78933 < 50 3,800 1,925 3,800
Toluene 108883 < 50 110 80 110
1,2,4-Trimethylbenzene 95636 < 50 250 150 250
1,3,5-Trimethylbenzene 95476 < 50 630 340 630
m,p-Xylene 108383 / 106423 < 50 J 62 56 62
Naphthalene 91203 < 50 J 30 30 30 1
Semivolatile Organics - Method 8270B µg/kg
CAS No. R8D-CI-01 R23B-CI-01 Average Conc Maximum Conc Comments
Fluoranthene 206440 J 130 < 165 130 130 1
Fluorene 86737 < 165 J 220 193 220
Isophorone 78591 < 165 130,000 65,083 130,000
2,4-Dimethylphenol 105679 < 165 J 2,800 1,483 2,800
3/4-Methylphenol NA < 165 J 150 150 150 1
Naphthalene 91203 J 280 < 165 223 280
1-Methylnaphthalene 90120 J 220 J 650 435 650
2-Methylnaphthalene 91576 520 J 310 415 520
TCLP Semivolatile Organics - Methods 1311 and 8270B µg/L
CAS No. R8D-CI-01 R23B-CI-01 Average Conc Maximum Conc Comments
Isophorone 78591 < 50 7,300 3,675 7,300
2-Methylphenol 95487 < 50 J 34 34 34 1
3/4-Methylphenol (total) NA < 50 J 99 75 99
Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg
CAS No. R8D-CI-01 R23B-CI-01 Average Conc Maximum Conc Comments
Aluminum 7429905 8,300 110,000 59,150 110,000
Barium 7440393 250 < 20.0 135 250
Calcium 7440702 4,700 4,500 4,600 4,700
Chromium 7440473 < 1.00 14.0 7.50 14.0
Iron 7439896 1,800 3,000 2,400 3,000
Lead 7439921 13.0 1.60 7.30 13.0

Petroleum Refining Industry Study 71 August 1996

 Table 3.5.4. Residual Characterization Data for
Spent Treating Clay from Extraction/Isomerization (continued)

Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg (continued)
CAS No. R8D-CI-01 R23B-CI-01 Average Conc Maximum Conc Comments
Magnesium 7439954 4,300 9,600 6,950 9,600
Manganese 7439965 350 43.0 197 350
Potassium 7440097 < 500 1,300 900 1,300
Sodium 7440235 < 500 81,000 40,750 81,000
Vanadium 7440622 20.0 10.0 15.0 20.0
Zinc 7440666 8.80 28.0 18.4 28.0
TCLP Metals - Methods 1311, 6010, 7060, 7421, 7470, 7471, and 7841 mg/L
CAS No. R8D-CI-01 R23B-CI-01 Average Conc Maximum Conc Comments
Aluminum 7429905 < 1.00 17.0 9.00 17.0
Calcium 7440702 160 < 25.0 92.5 160.0
Iron 7439896 18.0 1.30 9.65 18.0
Lead 7439921 0.04 < 0.015 0.03 0.04
Magnesium 7439954 82.0 50.0 66.0 82.0
Manganese 7439965 12.0 < 0.08 6.04 12.0

Comments:

1 Detection limits greater than the highest detected concentration are excluded from the calculations.

Notes:

B Analyte also detected in the associated method blank.

C Compound's concentration is estimated. Mass spectral data indicate the presence of a compound that meets the identification criteria for
which the result is less than the laboratory detection limit, but greater than zero.
ND Not Detected.
NA Not Applicable.

Petroleum Refining Industry Study 72 August 1996

3.6 ALKYLATION

The petroleum refining industry uses both hydrofluoric and sulfuric acid catalyzed
alkylation processes to form high octane products. DOE reported that 103 facilities operated
almost 1.1 million BPSD of alkylation capacity; 49 facilities used sulfuric acid and 59 used HF.
While the general chemistry of these processes is the same, the HF process includes a closed
loop and integral recycling step for the HF acid, while the sulfuric acid process requires a
separate acid regeneration process, which generally occurs off site. Study residuals are
generated from both alkylation processes.

3.6.1 Sulfuric Acid Alkylation Process Description

In the sulfuric acid alkylation process, olefin and isobutane gases are contacted over
concentrated sulfuric acid (H2SO4) catalyst to synthesize alkylates for octane-boosting. The
reaction products are separated by distillation and scrubbed with caustic. Alkylate product has a
Research Octane Number in the range of 92 to 99. Figure 3.6.1 provides a generic process flow
diagram for H2SO4 alkylation.

Figure 1.3.1. H2SO4 Alkylation Process Flow Diagram

The olefin stream is mixed with isobutane and H2SO4 in the reactor. To prevent
polymerization and to obtain a higher quality yield, temperatures for the H2SO4 catalyzed
reaction are kept between 40 and 50 F (McKetta, 1992). Since the reactions are carried out
below atmospheric temperatures during most of the year, refrigeration is required. Pressures are
maintained so all reaction streams are in their liquid form. The streams are mixed well during
their long residence time in the reactor to allow optimum reaction to occur.

The hydrocarbon/acid mixture then moves to the acid separator, where it is allowed to
settle and separate. The hydrocarbons are drawn off the top and sent to a caustic wash to

Petroleum Refining Industry Study 73 August 1996

neutralize any remaining trace acid. The acid is drawn from the bottom and recycled back to the
reactor. A portion of the acid catalyst is continuously bled and replaced with fresh acid to
maintain the reactor's acid concentration at around 90 percent. This spent H2SO4 was a listing
residual of concern.

In the fractionator, the hydrocarbon streams are separated into the alkylate and saturated
gases. The isobutane is recycled back into the reactor as feed. Light end products may be
filtered with sorbents to remove trace H2SO4 acid, caustic or water. The sorbents (e.g., treating
clays) are study residuals of concern.

Some facilities have neutralization tanks (in and above ground), referred to as pits, which
neutralize spent caustic and any acid generated from spills prior to discharge to the WWTP,
serving as surge tanks. Neutralizing agents (sodium, calcium, potassium hydroxides) are
selected by the refineries. If necessary, the influent to the pit is neutralized and, depending on
the neutralizing agent, the precipitated salts form a sludge. This sludge was also a listing
residual of concern. Sludge may also be generated in process line junction boxes, in the spent
H2SO4 holding tank, and during turnaround. However, due to the aqueous solubility of sodium,
calcium, and potassium sulfates, sludge generation rates are relatively low and the majority of
neutralization salts (e.g., sodium sulfate) are solubilized and discharged to the WWTP.

3.6.2 Hydrofluoric Acid Alkylation Process Description

Hydrofluoric acid alkylation is very similar to the H2SO4 alkylation process. In the
hydrofluoric acid alkylation process, olefin and isobutane gases are contacted over hydrofluoric
acid (HF) catalyst to synthesize alkylates for octane-boosting. The reaction products are
separated by distillation and scrubbed with caustic. Alkylate product has a research octane
number (RON) in the range of 92 to 99. Because it is clean burning and contributes to reduced
emissions, alkylate is a highly valued component in premium and reformulated gasolines. The
HF process differs from the H2SO4 alkylation in that the HF catalyst is managed in a closed-loop
process, never leaving the unit for replacement or regeneration. Figure 3.6.2 provides a generic
process flow diagram for HF alkylation.

The olefin stream is mixed with the isobutane and HF in the reactor. To prevent
polymerization and to receive a higher quality yield, temperatures for the HF catalyzed reaction
are maintained at approximately 100 F. Pressures are kept so all reaction streams are in their
liquid form (usually 85 to 120 psi). The streams are mixed well in the reactor to allow optimum
reaction to occur.

The hydrocarbon/acid mixture then moves to the settler, where it is allowed to settle and
phase separate. The hydrocarbons are drawn off the top and sent to a fractionator. The acid is
drawn from the bottom and recycled back to the reactor. A slip stream of acid is sent to an acid
regenerator where distillation separates the HF acid from by-product contaminants. The HF acid
from the regenerator is recycled back to the reactor. Fresh acid is added to replace acid losses at
a rate of about 500 pounds per day per 5,000 BPSD alkylation unit capacity (a small to medium
size unit).

Petroleum Refining Industry Study 74 August 1996

 Figure 3.6.2. HF Alkylation Process Flow Diagram

A residual of high molecular-weight reaction by-products dissolves in the HF acid

catalyst and lowers its effectiveness. To maintain the catalyst activity, a slip stream of catalyst is
distilled, leaving the by-product, acid soluble oil (ASO), as a residue. The ASO is charged to a
decanting vessel where an aqueous phase settles out. The aqueous phase, an azeotropic mixture
of HF acid and water, is referred to as constant boiling mixture (CBM). The ASO is scrubbed
with potassium hydroxide (KOH) to remove trace amounts of HF and either recycled, sold as
product (e.g., residual fuel), or burned in the unit's boiler. The CBM is sent to the neutralization
tank. In some cases, the ASO from the regenerator is sent directly to the neutralization tank.
The ASO is a residual of concern for the petroleum refining study.

A series of fractionators distills the product streams from the reactor into the alkylate,
saturated gases, and HF acid. Isobutane and HF are recycled back into the reactor as feed.

The main fractionator overhead is charged to the depropanizer and debutanizer, where
high-purity propane and butane are produced. The propane and butane are then passed through
the alumina treater for HF removal. Once catalytically defluorinated, they are KOH-treated and
sent to LPG storage.

As HF is neutralized by aqueous KOH, soluble potassium fluoride (KF) is produced and

the caustic is eventually depleted. Some facilities employ KOH regeneration. Periodically some
of the KF-containing neutralizing solution is withdrawn to the KOH regenerator. In this vessel

Petroleum Refining Industry Study 75 August 1996

KF reacts with a lime slurry to produce insoluble calcium fluoride (CaF2) and thereby
regenerates KF to KOH. The regenerated KOH is then returned to the system, and the solid
CaF2 is routed to the neutralizing tank. The KF, at facilities that do not have a regenerator, is
sent directly to the neutralizing tank, where it is reacted with lime to form a sludge.

Spent caustic, KOH scrubbers, acidic waters from acid sewers and, in some cases, CBM
are charged to in-ground neutralization tanks (referred to by industry as pits), which neutralize
effluent to the WWTP. Neutralizing controls fluoride levels to the WWTP. Neutralizing agents
(sodium, calcium, and potassium hydroxide) are selected based on the refineries' WWTP
permits. Effluent to the pit is neutralized, generally with lime, which forms a sludge (calcium
fluoride) that collects on the bottom of the tank. This sludge was a listing residual of concern.

HF acid is an extremely corrosive and toxic chemical. Refineries go to great lengths to

protect their personnel from HF contact. Prior to entrance to an HF alkylation unit, personnel
must have special training and wear various levels of personal protective clothing (depending
upon the work to be performed). The unit is generally cordoned off and marked as an HF hazard
area. Valves, flanges, and any place where leaks can occur are painted with a special paint that
will change colors when contacted with HF. The units are continuously monitored and alarms
are activated if an HF leak is detected.

3.6.3 Spent Treating Clay from Alkylation

3.6.3.1 Description

Treating clay from alkylation predominantly includes (1) molecular sieves used for
drying feed and (2) alumina used for removing fluorinated compounds from the product. Both
are applications in HF alkylation; clays are little used in sulfuric acid alkylation. Specifically,
the industry reported 83 treating clay residuals from alkylation in 1992, accounting for 2,890
metric tons of residuals. Only 7 of these residuals (143 metric tons) were from sulfuric acid
alkylation processes.

After fractionation, products may be passed through a filter filled with sorbents (referred
to as treating clay) to remove trace amounts of acid, caustic, or water. Sorbents typically used in
this service include alumina, molecular sieve, sand, and salt.

Treating clay becomes spent when breakthrough of H2SO4 or HF acid, caustic, or water
occurs. Depending on the type of clay and the type of service, breakthrough can occur anywhere
between 2 months and 5 years (e.g., alumina in HF service is typically 2 months and salt treaters
can be as long as 5 years). Prior to removal the clay may undergo one of the following in situ
treatments:

• Nitrogen sweep
• Propane sweep
• Steam stripping
• Methane sweep

Petroleum Refining Industry Study 76 August 1996

 Following removal, the spent clay is placed in closed containers and is typically sent to
an offsite landfill. Certain types of treating clay, such as alumina, are more amenable to
recycling and may be sent offsite to a smelter or a cement kiln to be used as process feeds.

In 1992, less than 2 percent of the volume of spent treating clay from alkylation was
managed as hazardous, with one residual reported to be D004, and three others reported
generically to be managed as hazardous (i.e., no specific codes were reported).7

3.6.3.2 Generation and Management

The RCRA §3007 Survey responses indicated 2,895 MT of spent treating clay were
generated in 1992. Residuals were assigned to be “treating clay from alkylation” if they were
assigned a residual identification code of “spent sorbent” and was generated from a process
identified as a sulfuric acid or HF alkylation unit. This corresponds to residual code “07” in
Section VII.1 and process codes “09-A” or “09-B” in Section IV-1.C of the questionnaire. Due
to the frequent generation of this residual, not all 103 facilities generated spent treating clay in
1992. However, there was no reason to expect that 1992 would not be a typical year with regard
to this residual's generation and management. Table 3.6.1 provides a description of the total
quantity generated, number of streams not reporting volumes (data requested was unavailable
and facilities were not required to generate it), total and average volumes.

Table 3.6.1. Generation Statistics for Treating Clay from Alkylation, 1992

# of # of Streams w/ Total Volume Average

Final Management Streams Unreported Volume (MT) Volume (MT)
Disposal in offsite Subtitle D landfill 28 2 633.7 22.6
Disposal in offsite Subtitle C landfill 4 1 23.9 6
Disposal in onsite Subtitle C landfill 3 0 67.0 22.3
Disposal in onsite Subtitle D landfill 18 0 626.3 34.8
Disposal in onsite wastewater 0 2 -- --
treatment facility
Onsite land treatment 4 0 59.2 14.8
Other recycling, or reuse: cement plant 4 0 770.5 154.1
Other recycling, or reuse: onsite road 1 0 3.6 3.6
material
Storage in pile 6 0 30.0 5.0
Transfer to offsite entity: alumina 15 0 680.4 45.4
manufacturer, smelter, or other
unspecified recycle
TOTAL 83 5 2,894.6 34.9

7
These percentages do not match up directly with any one of the management scenarios because the number of
streams and the volume are a combination of several management scenarios (i.e., managed in WWTP, Subtitle C
landfill, transfer to offsite entity, etc.).

Petroleum Refining Industry Study 77 August 1996

3.6.3.3 Plausible Management

EPA believes that most of the plausible management practices for this residual were
reported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.6.1. The Agency
gathered information suggesting other management practices have been used in other years
including: “disposal onsite in surface impoundment” (38.4 MT), “other recycling, reclamation,
or reuse: offsite fluoride recovery” (23.6 MT), and “offsite incineration” (3.6 MT). The very
small volume reported to have been disposed in a surface impoundment was placed in the
surface impoundment the year it was closed, suggesting the inert material was used as fill. The
refinery reported the future management of the spent clay would be sent offsite to a cement kiln
for reuse. Similarly, the very small volume reported for offsite fluoride recovery was a
management practice seen as a trend for fluoride containing residuals during the engineering site
visits. The very small volume reported for offsite incineration are comparable to the 1992
practices for other treating clay residuals (e.g., clay filtering)

3.6.3.4 Characterization

Two sources of residual characterization were developed during the industry study:

• Table 3.6.2 summarizes the physical properties of the alkylation sorbents as reported
in Section VII.A of the §3007 survey.

• Four record samples of actual treating clay were collected and analyzed by EPA.
These spent clays are all from HF processes and represent the various types of spent
sorbents typically used by the industry as summarized in Table 3.6.3.

The four record samples were analyzed for total and TCLP levels of volatiles,
semivolatiles, metals, fluorides, reactivity and ignitability. None of the samples were found to
exhibit any of the hazardous waste characteristics. A summary of the results is presented in
Table 3.6.4. Only constituents detected in at least one sample are shown in this table.

3.6.3.5 Source Reduction

Several solid-acid catalysts used for alkylation are being tested in pilot plants. The solid-
catalyst reactor systems are different from the current liquid-acid systems, but for one solid-
catalyst operation, the other process equipment is compatible. The three types of new solid
catalyst include aluminum chloride, alumina/zirconium halide, and antimony pentafluoride (a
slurry system). It is unclear whether these processes will generate more or less treating clays
than current processes. Theoretically, these processes would not require filtering for acid and
water removal.

The February 1, 1993 issue of the Oil & Gas Journal reported that Conoco's Ponca City,
Oklahoma refinery sold reclaimed fluorinated alumina to Kaiser Aluminum & Chemical
Corporation's plant in Mead, Washington. The fluorinated alumina is substituted for aluminum
fluoride, a “bath” chemical used in aluminum manufacturing.

Petroleum Refining Industry Study 78 August 1996

 Table 3.6.2. Treating Clay from Alkylation: Physical Properties
# of
# of Unreported
Properties Values Values1 10th % 50th % 90th %
pH 60 91 2.91 7.00 9.00
Reactive CN, ppm 39 112 0.00 0.25 250.00
Reactive S, ppm 45 106 0.00 4.00 170.00
Flash Point, C 43 108 60.00 93.33 100.00
Oil and Grease, vol% 43 108 0.00 0.05 1.00
Total Organic Carbon, vol% 25 126 0.00 0.00 1.00
Specific Gravity 54 97 0.70 1.24 2.24
Specific Gravity Temperature, C 27 124 15.00 15.60 25.00
BTU Content, BTU/lb 12 139 0.00 0.00 500.00
Aqueous Liquid, % 89 62 0.00 0.00 8.00
Organic Liquid, % 85 66 0.00 0.00 1.00
Solid, % 123 28 96.00 100.00 100.00
Other, % 77 74 0.00 0.00 0.00
Particle >60 mm, % 41 110 0.00 0.00 100.00
Particle 1-60 mm, % 53 98 0.00 100.00 100.00
Particle 100 µm-1 mm, % 37 114 0.00 0.00 50.00
Particle 10-100 µm, % 38 113 0.00 0.00 3.00
Particle <10 µm, % 36 115 0.00 0.00 0.00
Median Particle Diameter, microns 21 130 0.00 1,200.00 9,525.00

1
Facilities were not required to do additional testing, therefore information provided was based on previously collected
data or engineering judgement.

Table 3.6.3. Alkylation Treating Clay Record Sampling Locations

Sample Number Location Description

R3-CA-01 Exxon, Billings, MT Alumina propane product treater1
R15-CA-01 Total, Ardmore, OK Alumina butane product treater1
R21-CA-01 Chevron, Pt. Arthur, TX Alumina propane or butane product treater1
R23-CA-01 Chevron, Salt Lake City, UT Alumina propane product treater1

1
HF process

Petroleum Refining Industry Study 79 August 1996

 Table 3.6.4. Alkylation Treating Clay Characterization
Petroleum Refining Industry Study

Volatile Organics - Method 8260A µg/kg

CAS No. R3-CA-01 R15-CA-01 R21-CA-01 R23-CA-01 Average Conc Maximum Conc Comments
Acetone 67641 42,000 680 J 880 13,000 14,140 42,000
Benzene 71432 J 67 < 25 < 625 < 650 46 67 1
sec-Butylbenzene 135988 < 625 < 25 J 1,200 < 650 625 1,200
p-Isopropyltoluene 99876 < 625 < 25 J 800 < 650 525 800
Methyl ethyl ketone 78933 < 625 290 < 625 1,300 710 1,300
Toluene 108883 J 67 < 25 < 625 < 650 46 67 1
1,2,4-Trimethylbenzene 95636 J 112 < 25 2,100 < 650 722 2,100
o-Xylene 95476 < 625 < 25 J 530 < 650 278 530 1
m,p-Xylenes 108383/106423 J 136 < 25 1,300 < 650 528 1,300
Naphthalene 91203 < 625 < 25 J 1,100 < 650 600 1,100
TCLP Volatile Organics - Methods 1311 and 8260A µg/L
CAS No. R3-CA-01 R15-CA-01 R21-CA-01 R23-CA-01 Average Conc Maximum Conc Comments
Acetone 67641 1,500 < 50 280 B 1,100 733 1,500
Toluene 108883 JB 11 < 50 < 50 < 50 11 11 1
Methyl ethyl ketone 78933 J 95 < 50 210 250 151 250
m,p-Xylene 108383 / 106423 JB 10 < 50 < 50 < 50 10 10 1
Semivolatile Organics - Method 8270B µg/kg
80

CAS No. R3-CA-01 R15-CA-01 R21-CA-01 R23-CA-01 Average Conc Maximum Conc Comments
Di-n-butyl phthalate 84742 < 165 < 165 J 200 < 165 174 200
Phenanthrene 85018 < 165 J 160 < 165 < 165 160 160 1
TCLP Semivolatile Organics - Methods 1311 and 8270B µg/L
CAS No. R3-CA-01 R15-CA-01 R21-CA-01 R23-CA-01 Average Conc Maximum Conc Comments
Bis(2-ethylhexyl)phthalate 117817 J 10 < 50 < 50 < 50 10 10 1
Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg
CAS No. R3-CA-01 R15-CA-01 R21-CA-01 R23-CA-01 Average Conc Maximum Conc Comments
Aluminum 7429905 240,000 170,000 210,000 240,000 215,000 240,000
Arsenic 7440382 26.0 13.0 < 5.0 < 5.0 12.3 26.0
Beryllium 7440417 2.20 1.70 2.00 2.20 2.03 2.20
Iron 7439896 23.0 < 5.0 < 5.0 52.0 21.3 52.0
Manganese 7439965 < 1.5 4.70 6.50 6.90 4.90 6.90
Sodium 7440235 2,200 2,000 8,000 7,700 4,975 8,000
Zinc 7440666 23.0 33.0 40.0 39.0 33.8 40.0
August 1996
 Table 3.6.4. Alkylation Treating Clay Characterization (continued)
Petroleum Refining Industry Study

TCLP Metals - Methods 1311, 6010, 7060, 7421, 7470, 7471, and 7841 mg/L
CAS No. R3-CA-01 R15-CA-01 R21-CA-01 R23-CA-01 Average Conc Maximum Conc Comments
Aluminum 7429905 5,300 1,300 4,100 4,100 3,700 5,300
Beryllium 7440417 0.05 < 0.025 < 0.025 < 0.025 0.031 0.050
Iron 7439896 1.60 < 0.50 1.10 1.00 1.05 1.60
Manganese 7439965 < 0.08 < 0.08 0.18 0.17 0.13 0.18
Zinc 7440666 B 1.10 B 0.60 B 0.82 B 0.85 0.84 1.10
Miscellaneous Characterization
R3-CA-01 R15-CA-01 R21-CA-01 R23-CA-01 Average Conc Maximum Conc Comments
Total Fluorine (mg/kg) 39,000 4,500 NA NA 21,750 39,000

Comments:

1 Detection limits greater than the highest detected concentration are excluded from the calculations.

Notes:

B Analyte also detected in the associated method blank.

J Compound's concentration is estimated. Mass spectral data indicate the presence of a compound that meets the identification criteria for which the result is less than the laboratory detection limit, but greater than
zero.
ND Not Detected.
NA Not Applicable.
81
August 1996
 At the Ponca City refinery, Conoco uses activated alumina in one of the alkylation units
to extract fluorides from propane and butane products. In the process, activated alumina is
converted to aluminum fluoride. Activated alumina reaches the end of its useful life when 60-
80% of the material is converted to aluminum fluoride. That is when it become an additive for
aluminum manufacturers.

During EPA's site visits, one facility used distillation to dry its feed to the HF acid
alkylation unit. Most facilities use a molecular sieve treating clay for this step, therefore this
process configuration eliminates the need for molecular sieve infrequently generating an RC.

Some refineries are experimenting with additives to the HF acid catalyst. The purpose of
these additives is to reduce the risk from an accidental leak of HF acid to the atmosphere.
Although the technology is principally developed in reaction to safety concerns, it is likely that
such additives would be present in some of the study residuals such as acid soluble oil. The
identity of those additives were not reported (Oil and Gas Journal, August 22, 1994).

3.6.4 Catalyst from Hydrofluoric Acid Alkylation

3.6.4.1 Description

The consent decree which identifies the residuals to be examined in this study specified
“catalyst from HF alkylation”. However, the analysis used to identify the residuals of concern in
the consent decree contained some flaws and erroneously identified this alkylation catalyst as
being generated in significant quantities. Upon further review of the data used to characterize
this residual (derived from EPA's 1983 survey of the petroleum refining industry), it was
determined that several large volume residuals were inappropriately identified as spent catalyst
and instead should have been classified as acid soluble oil (ASO). After adjusting the data to
remove these mischaracterized residuals, the remaining residuals classified as spent HF catalyst
accounted for small volumes which are on the order of magnitude observed in the Agency's 1992
data.

A residual of high molecular-weight reaction by-products dissolves in the HF acid

catalyst and lowers its effectiveness. To maintain catalyst activity, a slip stream of HF acid is
sent to an acid regenerator where distillations separates the HF acid from by-product
contaminants, called acid soluble oil. The HF acid from the regenerators is recycled back to the
reactor. Fresh acid is added to replace acid losses at a rate of about 500 pounds per day
depending on unit capacity.

ASO is charged to a decanting vessel where an aqueous phase settles out. The aqueous
phase, an azeotropic mixture of HF acid and water, is referred to as constant boiling mixture
(CBM). CBM is charged to the neutralization tank which neutralize effluent to the WWTP. The
neutralization sludge was examined in the listing proposal and Background Document. The
effluent from the neutralization tanks are reported to go to the WWTP. The Agency has no data
suggesting that it can be handled in any other way.

As stated above, HF acid is an extremely corrosive and toxic chemical. Refineries go to

great lengths to protect their personnel from coming into direct contact with HF acid.

Petroleum Refining Industry Study 82 August 1996

3.6.4.2 Generation and Management

The refineries reported generating approximately 152 MT of HF alkylation catalyst in

1992. Residuals were assigned to be “HF alkylation catalyst” if they were assigned a residual
identification code of “liquid catalyst” and was generated from a process identified as an HF acid
alkylation unit. This corresponds to residual code 03-B in Section VII.2 of the questionnaire and
process code 09-B in Section IV-1.C of the questionnaire. Table 3.6.5 provides a description of
the quantity generated, number of streams reported, and number of unreported volumes.
Catalyst from HF alkylation includes spills and removed acid from the HF alkylation process.

Table 3.6.5. Generation Statistics for Catalyst from HF Alkylation, 1992

# of # of Streams w/ Total Volume Average

Final Management Streams Unreported Volume (MT) Volume (MT)
Discharge to WWTP 3 0 151.94 50.65

3.6.4.3 Plausible Management

EPA believes that most of the plausible management practices for this residual were
reported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.6.5. No data were
available to the Agency suggesting any other management practices.

3.6.4.4 Characterization

Only one source of residual characterization is available from the industry study,
reflecting the fact that this residual is not generated for management:

• Table 3.6.6 summarizes the physical properties of the HF catalyst as reported in

Section VII.A of the §3007 survey.

Due to the rareness of the generation of this residual, no samples of this residual were
available for collection and analysis during record sampling.

Table 3.6.6. Catalyst from HF Alkylation: Physical Properties

# of # of Unreported
Properties Values Values 10th % 50th % 90th %
pH 2 1 2.00 2.00 2.00
Vapor Pressure, mm Hg 1 2 775.00 775.00 775.00
Specific Gravity 1 2 1.00 1.00 1.00
Aqueous Liquid, % 2 1 0.00 0.00 0.00
Organic Liquid, % 2 1 0.00 0.00 0.00
Solid, % 2 1 0.00 0.00 0.00
Other, % 2 1 100.00 100.00 100.00

Petroleum Refining Industry Study 83 August 1996

3.6.4.5 Source Reduction

As described in the spent treating clay alkylation in Section 3.6.3.5, several solid-acid
catalysts used for alkylation are being tested in pilot plants. The reactor systems are different
from the current liquid-acid systems, but for one system the other equipment is compatible.
Three types of the new solid catalyst include aluminum chloride, alumina/zirconium halide, and
antimony pentafluoride (a slurry system).

In general, additional source reduction is not possible because of the closed loop recycle
process and the strict controls placed on this material due to the severe health hazards associated
with contact and inhalation.

3.6.5 Acid Soluble Oil from Hydrofluoric Acid Alkylation

3.6.5.1 Description

A residual of high molecular-weight reaction by-products dissolves in the HF acid

catalyst and lowers its effectiveness. To maintain the catalyst activity, a slip stream of catalyst is
distilled, leaving the by-product, acid soluble oil (ASO), as a residue. The ASO is charged to a
decanting vessel where an aqueous phase settles out. The ASO is scrubbed with potassium
hydroxide (KOH) to remove trace amounts of HF and is either recycled, sold as product (e.g.,
residual fuel), or burned in the unit's boiler. In some cases, the ASO from the regenerator is sent
directly to the neutralization tanks. Effluent from the neutralization tanks is sent to the WWTP.
Neutralization tank sludges were examined under the listing proposal and Background
Document.

ASO is generated exclusively from the HF process. The sulfuric acid alkylation process
does not generate ASO.

Eight residuals of ASO, accounting for 25 percent of this category's volume, was
reported as being managed as either D001, D002, or D008.8

3.6.5.2 Generation and Management

The refineries reported generating approximately 33,493 MT of ASO in 1992. Residuals

were assigned to be “ASO” if they were assigned a residual identification code of “alkylation
acid regeneration tars” and were generated from a process identified as an HF acid alkylation
unit. This corresponds to residual code 08 in Section VII.1 and process code 09-B in Section
IV-1.C of the questionnaire. Note that sludges generated from neutralization of acid soluble oil
were examined under the proposal and the Background Document and are not included here.
Table 3.6.7 provides a description of the quantity generated, number of streams reported, and
number of unreported volumes.

8
These percentages do not match up directly with any one of the management scenarios because the number of
streams and the volume are a combination of several management scenarios (i.e., managed in WWTP, transfer as a
fuel, offsite incineration, etc.).

Petroleum Refining Industry Study 84 August 1996

 Table 3.6.7. Generation Statistics for Acid Soluble Oil, 1992

# of
Streams w/ Total Average
# of Unreported Volume Volume
Final Management Streams Volume (MT) (MT)
Discharge to onsite wastewater treatment facility 6 0 4,858.8 809.8
Neutralization 15 14 11,387.9 759.2
Offsite incineration 2 0 0.2 0.1
Onsite boiler 3 0 2,610.3 870.1
Onsite industrial furnace 10 1 3,274 327.4
Other recovery onsite: alkylation or hydrotreating/
3 1 2,180 726.7
hydrorefining process or unknown
Recovery onsite in a catalytic coker 5 0 3,641.3 728.3
Recovery onsite in a coker 1 0 1,019 1,019
Recovery onsite via distillation 2 3 50 25
Transfer for direct use as a fuel or to make a fuel 2 0 740.6 370.3
Transfer with coke product or other refinery product 4 1 3,731 932.8
TOTAL 53 20 33,493 631.9

3.6.5.3 Plausible Management

EPA believes that most of the plausible management practices for this residual were
reported in the 1992 RCRA §3007 Survey, as summarized in Table 3.6.7. The Agency gathered
information suggesting that “disposal in industrial Subtitle D landfill” (1 MT) was used in other
years. Upon closer examination of this residual, EPA determined that the facility neutralized its
ASO and landfilled the sludge. This management practice is consistent with the practices
reported above.

3.6.5.4 Characterization

Two sources of residual characterization were developed during the industry study:

• Table 3.6.8 summarizes the physical properties of the ASO as reported in Section
VII.A of the §3007 survey.

• Four record samples of actual ASO were collected and analyzed by EPA. The ASO
represent the various types of interim management practices typically used by the
industry (i.e., with and without neutralization) and are summarized in Table 3.6.9.

The four record samples were analyzed for total and TCLP levels of volatiles,
semivolatiles, and metals, as well as ignitability. Three of the samples were found to exhibit the
hazardous waste characteristic of ignitability. A summary of the results is presented in Table
3.6.10. Only constituents detected in at least one sample are shown in this table.

Petroleum Refining Industry Study 85 August 1996

 Table 3.6.8. Acid Soluble Oil: Physical Properties

# of
# of Unreported
Properties Values Values1 10th % 50th % 90th %
pH 30 59 2.00 6.50 10.75
Reactive CN, ppm 12 77 0.00 0.13 50.00
Reactive S, ppm 14 75 0.00 5.00 200.00
Flash Point, C 27 62 25.00 60.00 93.33
Oil and Grease, vol% 26 63 15.00 90.00 100.00
Total Organic Carbon, vol% 16 73 30.00 77.00 100.00
Vapor Pressure, mm Hg 10 79 3.00 135.00 575.00
Vapor Pressure Temperature, C 9 80 20.00 25.00 38.00
Viscosity, lb/ft-sec 11 78 0.00 0.01 0.40
Viscosity Temperature, C 6 83 15.00 17.50 37.80
Specific Gravity 34 55 0.80 0.90 1.00
Specific Gravity Temperature, C 12 77 15.00 15.00 15.60
BTU Content, BTU/lb 15 74 750.00 15,000.00 19,000.00
Aqueous Liquid, % 47 42 0.00 10.00 75.00
Organic Liquid, % 56 33 50.00 98.00 100.00
Solid, % 32 57 0.00 0.00 30.00
Other, % 27 62 0.00 0.00 0.05
1
Facilities were not required to do additional testing, therefore information provided was based on previously collected
data or engineering judgment.

Table 3.6.9. Acid Soluble Oil Record Sampling Locations

Sample Number Location Description

R3-AS-01 Exxon, Billings, MT Un-neutralized separator drum sample
R5B-AS-01 Marathon, Garyville, LA Acid regenerator settler bottoms, not neutralized
R15-AS-01 Total, Ardmore, OK Neutralized, skimmed from pit
R7C-AS-01 BP, Belle Chasse, LA Neutralized from storage tank

3.6.5.5 Source Reduction

As described in previous sections, several solid-acid catalysts used for alkylation are
being tested in pilot plants. The reactor systems are different from the current liquid-acid
systems, but for one system the other equipment is compatible. Three types of the new solid
catalyst include aluminum chloride, alumina/zirconium halide, and antimony pentafluoride (a
slurry system).

It is likely that ASO will not be generated in a solid catalyst system.

Petroleum Refining Industry Study 86 August 1996

 Table 3.6.10. Acid Soluble Oil Characterization
Petroleum Refining Industry Study

Volatile Organics - Method 8260A µg/L (µg/kg)

CAS No. R3-AS-01 R5B-AS-01 R7C-AS-01 R15-AS-01 Average Conc Maximum Conc Comments
Acetone 67641 49,000 < 625 B 40,000 3,000 23,156 49,000
Acrolein 107028 < 6250 < 625 25,000 < 1,250 8,281 25,000
Benzene 71432 < 6250 < 625 30,000 < 1,250 9,531 30,000
n-Butylbenzene 104518 < 6250 < 625 J 9,500 < 1,250 4,406 9,500
sec-Butylbenzene 135988 < 6250 < 625 J 2,600 J 488 1,238 2,600 1
tert-Butylbenzene 98066 < 6250 < 625 J 7,200 J 1,350 3,856 7,200
Carbon disulfide 75150 < 6250 < 625 J 1,800 < 1,250 1,225 1,800 1
trans-1,3-Dichloropropene 10061026 < 6250 < 625 J 1,600 < 1,250 1,158 1,600 1
Ethylbenzene 100414 < 6250 < 625 37,000 < 1,250 11,281 37,000
Isopropylbenzene 98828 < 6250 < 625 J 3,100 < 1,250 1,658 3,100 1
p-Isopropyltoluene 99876 < 6250 < 625 J 6,600 < 1,250 3,681 6,600
Methyl ethyl ketone 78933 < 6250 < 625 27,000 < 1,250 8,781 27,000
4-Methyl-2-pentanone 108101 < 6250 < 625 26,000 < 1,250 8,531 26,000
n-Propylbenzene 103651 < 6250 < 625 J 8,200 < 1,250 4,081 8,200
Toluene 108883 < 6250 < 625 41,000 < 1,250 12,281 41,000
1,2,4-Trimethylbenzene 95636 18,000 7,400 110,000 3,300 34,675 110,000
1,3,5-Trimethylbenzene 108678 < 6250 < 625 27,000 J 1,260 8,784 27,000
87

o-Xylene 95476 < 6250 < 625 20,000 < 1,250 7,031 20,000
m,p-Xylenes 108383 / 106423 16,000 2,100 55,000 < 1,250 18,588 55,000
Naphthalene 91203 < 6250 < 625 30,000 < 1,250 9,531 30,000
TCLP Volatile Organics - Methods 1311 and 8260A µg/L
CAS No. R3-AS-01 R5B-AS-01 R7C-AS-01 R15-AS-01 Average Conc Maximum Conc Comments
Acetone 67641 NA NA NA B 350 350 350
Isopropylbenzene 98828 NA NA NA J 32 32 32
Methyl ethyl ketone 78933 NA NA NA J 80 80 80
Semivolatile Organics - Method 8270B µg/L (µg/kg)
CAS No R3-AS-01 R5B-AS-01 R7C-AS-01 R15-AS-01 Average Conc Maximum Conc Comments
Methyl ethyl ketone 78933 NA NA NA J 80 80 80
1-Methylnaphthalene 90120 < 250,000 < 46,000 100,000 < 12,375 73,000 100,000 1
2-Methylnaphthalene 91576 < 250,000 < 46,000 180,000 < 12,375 113,000 180,000 1
Naphthalene 91203 < 250,000 < 46,000 79,000 < 12,375 62,500 79,000 1
2-Methylnaphthalene 91576 < 250,000 < 46,000 180,000 < 12,375 113,000 180,000 1
Naphthalene 91203 < 250,000 < 46,000 79,000 < 12,375 62,500 79,000 1
August 1996
 Table 3.6.10. Acid Soluble Oil Characterization (continued)
Petroleum Refining Industry Study

TCLP Semivolatile Organics - Methods 1311 and 8270B µg/L

CAS No. R3-AS-01 R5B-AS-01 R7C-AS-01 R15-AS-01 Average Conc Maximum Conc Comments
Aniline 62553 NA NA NA J 20 20 20
Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg (mg/kg)
CAS No. R3-AS-01 R5B-AS-01 R7C-AS-01 R15-AS-01 Average Conc Maximum Conc Comments
Aluminum 7429905 < 0.10 < 0.10 < 0.10 290 NA NA
Calcium 7440702 < 2.50 < 2.50 < 2.50 29,000 NA NA
Copper 7440508 1.00 < 0.13 < 0.13 37.0 0.42 1.00
Iron 7439896 < 0.50 < 0.50 < 0.50 120 NA NA
Lead 7439921 0.64 < 0.015 < 0.015 < 0.30 0.22 0.64
Manganese 7439965 < 0.015 < 0.015 < 0.015 5.00 NA NA
Mercury 7439976 < 0.01 0.022 < 0.01 < 0.05 0.014 0.022
Nickel 7440020 < 0.04 < 0.04 < 0.04 15.0 NA NA
Potassium 7440097 < 2.50 < 2.50 < 2.50 5,900 NA NA
Sodium 7440235 < 2.50 < 2.50 < 2.50 1,300 NA NA
Zinc 7440666 0.27 < 0.10 < 0.10 < 2.00 0.16 0.27
TCLP Metals - Methods 1311, 6010, 7060, 7421, 7470, 7471, and 7841 mg/L
CAS No. R3-AS-01 R5B-AS-01 R7C-AS-01 R15-AS-01 Average Conc Maximum Conc Comments
Potassium 7440097 NA NA NA 140 140 140
88

Zinc 7440666 NA NA NA B 0.24 0.24 0.24

Miscellaneous Characterization
R3-AS-01 R5B-AS-01 R7C-AS-01 R15-AS-01 Average Conc Maximum Conc Comments
Total Fluorine (mg/L) 450 110 19.0 9,300 mg/kg 193 450
Ignitability ( oF ) 132 57 97 > 158 NA NA
Corrosivity ( pH ) 3 5 7 10.8 NA NA
Heat of Combustion ( BTU/lb ) 18,700 19,245 19,000 14,000 17,736 19,245

Comments:

1 Detection limits greater than the highest detected concentration are excluded from the calculations.

Notes:

B Analyte also detected in the associated method blank.

J Compound's concentration is estimated. Mass spectral data indicate the presence of a compound that meets the identification criteria for which the result is less than the laboratory detection limit, but greater than
zero.
ND Not Detected.
NA Not Applicable.
August 1996
3.7 POLYMERIZATION

Polymerization is a process utilized for the conversion of propane/propylene and/or

butane/butene feeds from other operations into a low molecular weight, higher-octane, polymer
product, referred to as dimate. Dimate is used as a high octane gasoline blending component of
unleaded gasolines.

Almost 12 percent of the industry's polymerization catalyst (Dimersol and phosphoric

acid) volume was reported to be managed as a hazardous waste (”as hazardous”, D002 and
D007).9

3.7.1 Process Descriptions

There are primarily two polymerization processes utilized by the petroleum refining
industry: phosphoric acid polymerization and the Dimersol process, licensed by IFP (Institute
Francais du Petrole, or the French Petroleum Institute). Process descriptions for each of these
two processes are provided in the following sections.

3.7.1.1 Phosphoric Acid Polymerization

Phosphoric acid polymerization units produce marginal octane gasoline from propylene
feeds from other operating units (i.e., the FCC unit, coking, etc). Phosphoric acid
polymerization is more widely used by industry than the Dimersol process, representing 80
percent of all polymerization units in the United States. Phosphoric acid polymerization unit
capacities range from 400 to 8,000 barrels per stream day, with the majority of units ranging
between 2,200 and 3,000 barrels per stream day (as reported in the §3007 survey).

Phosphoric acid polymerization utilizes a catalyst consisting of an alumina substrate

impregnated with phosphoric acid. A typical phosphoric acid polymerization unit contains one
or more reactors consisting of a series of tubes coming off of a single header. The reactor feed is
charged to the header and flows through the tubes. The tubes are packed with the phosphoric
acid catalyst. The reaction conditions are controlled to stop the polymerization at the desired C6
or C9 product. The polymerization reaction is highly exothermic and boiler feed water is fed
through the reactor (on the shell side of the tubes) to recover the heat for use as steam. Over
time, the catalyst’s acid sites become blocked and the catalyst is slated for change-out.

After leaving the reactor, the reactor effluent is fractionated to give the desired products.
A simplified process flow diagram for a typical phosphoric acid polymerization unit is shown in
Figure 3.7.1.

9
These percentages do not match up directly with any one of the management scenarios because the number of
streams and the volume are a combination of several management scenarios (i.e., Subtitle C landfill, recovery in
coker, etc.).

Petroleum Refining Industry Study 89 August 1996

 Figure 3.7.1. Process Flow Diagram for Phosphoric Acid Polymerization Process

3.7.1.2 Dimersol Polymerization

As stated above, Dimersol polymerization units represent only 20 percent of the existing
polymerization units in the United States. The capacity of Dimersol units range from 1,000 to
5,500 barrels per stream day, with an average capacity of approximately 3,200 barrels per stream
day (as reported in the §3007 survey).

The Dimersol process is used to dimerize light olefins such as ethylene, propylene and
butylene. The process typically begins with the pretreatment of the propane/propylene or
butane/butene feed prior to entering the reactor section of the process. Pretreatment can include
the use of molecular sieve dryers, sand filters, etc. to remove water and/or H2S. Water in the
feed stream can deactivate the catalysts used in the Dimersol process. After drying the feed is
combined with a liquid nickel carboxylate/ethyl aluminum dichloride (EADC) catalyst prior to
entering the first of a series of three reactors. The first two are continuous stirred batch reactors
and the third is a plug-flow tubular reactor. The reactor feed is converted to the process product,
dimate, primarily in the first reactor, and additional conversion is achieved in the last two
reactors. The final reactor effluent consists of dimate product, unreacted C3/C4s, and liquid
catalyst. Immediately following the last reactor, the liquid catalyst is removed from the reactor
effluent by treating the reactor effluent with caustic, subsequent water washing, and filtering to
remove solids. Spent caustic residuals are typically reused or reclaimed on- or off-site, and as a
result, do not constitute solid wastes. After filtering, the product stream enters a “Dimersol
stabilizer,” a distillation unit that removes unreacted LPG from the dimate product. In some
cases, the product stream is also further treated by drying. LPG from the stabilizer overhead is
typically sent to another unit of the refinery for further processing. The dimate product from the
bottom of the stabilizer is sent to storage or product blending.

Petroleum Refining Industry Study 90 August 1996

 A simplified process flow diagram for a typical Dimersol polymerization unit is shown in
Figure 3.7.2.

Figure 3.7.2. Dimersol Polymerization Process Flow Diagram

3.7.2 Spent Phosphoric Acid Polymerization Catalyst

3.7.2.1 Description

Spent phosphoric acid polymerization catalyst is generated after the solid catalyst active
sites have become blocked and lost their reactivity.

3.7.2.2 Generation and Management

During reactor change-outs, spent phosphoric acid catalysts are flushed or water drilled
from the shell-and-tube reactors.

Twenty-two facilities reported generating a total quantity of 3,358 MT of this residual in

1992, according to the 1992 RCRA §3007 Questionnaire. Residuals were assigned to be “spent
phosphoric acid polymerization catalyst” if they were assigned a residual identification code of
“spent solid catalyst” or “spent catalyst fines” and were generated from a process identified as a
phosphoric acid polymerization unit. These correspond to residual codes 03-A and 03-B in
Section VII.2 of the questionnaire and process code 11-A in Section IV-1.C of the questionnaire.
Quality assurance was conducted by ensuring that all phosphoric acid polymerization catalysts
previously identified in the questionnaire (i.e., in Section V.B) were assigned in Section VII.2.

Based on the results of the questionnaire, 25 facilities use phosphoric acid polymerization
units and are thus likely to generate spent phosphoric acid polymerization catalyst. Due to the
infrequent generation of this residual, not all of these 25 facilities generated spent catalyst in
1992. However, there was no reason to expect that 1992 would not be a typical year with regard
to this residual's generation and management. Table 3.7.1 provides a description of the quantity
generated, number of streams reported, number of streams not reporting volumes (data requested
was unavailable and facilities were not required to generate it), total and average volumes.

Petroleum Refining Industry Study 91 August 1996

 Table 3.7.1. Generation Statistics for Phosphoric Acid Catalyst
from Polymerization, 1992

# of Streams
# of w/ Unreported Total Volume Average
Final Management Streams Volume (MT) Volume (MT)
Disposal in offsite Subtitle D landfill 12 0 1,429.5 119
Disposal in offsite Subtitle C landfill 3 0 62 20.7
Disposal in onsite Subtitle C landfill 2 0 349 174.5
Disposal in onsite Subtitle D landfill 6 0 246.8 41
Onsite land treatment 3 0 728 242.7
Transfer for use as an ingredient in
7 0 542.5 77.5
products placed on the land
TOTAL 33 0 3357.8 101.7

3.7.2.3 Plausible Management

EPA believes that most of the plausible management practices for this residual were
reported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.7.1. No data were
available to the Agency suggesting any other management practices.

3.7.2.4 Characterization

Two sources of residual characterization were developed during the industry study:

Table 3.7.2 summarizes the physical properties of the spent catalyst as reported in
Section VII.A of the §3007 survey.

• One record sample of phosphoric acid polymerization catalyst was collected and
analyzed by EPA. The sample is representative of typical phosphoric acid
polymerization catalyst used by the industry and is summarized in Table 3.7.3.

The record sample was analyzed for total and TCLP levels of volatiles, semivolatiles,
and metals, reactivity (pyrophoricity) and corrosivity. The sample was found to exhibit the
hazardous waste characteristic of corrosivity. Dimersol and phosphoric acid catalysts were
categorized together in the consent decree, therefore, a summary of the results for both residuals
is presented in Table 3.7.7. Only constituents detected in at least one sample are shown in this
table.

Petroleum Refining Industry Study 92 August 1996

 Table 3.7.2. Phosphoric Acid Catalyst from Polymerization: Physical Properties

# of # of Unreported
Properties Values Values1 10th % 50th % 90th %
pH 21 21 1.4 4.7 7
Reactive CN, ppm 12 30 0.01 7 40
Reactive S, ppm 12 30 1 10 40
Flash Point, C 14 28 60 93.3 200
Oil and Grease, vol% 16 26 0 0 25.5
Total Organic Carbon, vol% 15 27 0 0 16.6
Specific Gravity 20 22 0.85 0.96 1.4
Aqueous Liquid, % 29 13 0 0 50
Organic Liquid, % 28 14 0 0 1
Solid, % 35 7 50 100 100
Particle >60 mm, % 16 26 0 0 0
Particle 1-60 mm, % 17 25 0 95 95
Particle 100 µm-1 mm, % 16 26 0 5 5
Particle 10-100 µm, % 16 26 0 0 100
Particle <10 µm, % 16 26 0 0 0
Median Particle Diameter, 10 31 5030 12,000 12,000
microns

1
Facilities were not required to do additional testing, therefore information provided was based on previously collected
data or engineering judgment.

Table 3.7.3. Phosphoric Acid Polymerization Catalyst Record Sampling Locations

Sample Number Location Description

R16-PC-01 Koch, St. Paul, MN Phosphoric acid catalyst

3.7.2.5 Source Reduction

No source reduction techniques were reported by industry or found in the literature

search for this residual.

Petroleum Refining Industry Study 93 August 1996

3.7.3 Spent Dimersol Polymerization Catalyst

3.7.3.1 Description

Dimersol catalyst is added to the reactor feed stream and exits the final reactor as part of
the reactor effluent. The liquid catalyst is then removed from the reactor effluent by
neutralization (contact with caustic). Spent caustic streams, containing the spent dimersol
catalyst, are commonly reused on-site or sent off-site for metals reclamation or caustic recovery,
and as a result are typically not solid wastes. Spent catalyst also may be generated in two other
points in the process. First, during routine shutdowns spent catalyst may be generated as a
component of any reactor sludge removed from the reactors. Second, certain Dimersol
processes contain filters following caustic neutralization and water washing to remove entrained
residual nickel from the dimate product. The filters are removed and disposed periodically.

3.7.3.2 Generation and Management

Dimersol catalysts are generated as solid wastes in the form of reactor sludges generated
during reactor clean-outs and as spent nickel filters.

Four facilities reported generating a total quantity of 761.5 MT of this residual as a

reactor sludge in 1992, according to the 1992 RCRA §3007 Survey. Residuals were assigned to
be “spent dimersol catalyst” if they were assigned a residual identification code of “spent solid
catalyst” or “spent catalyst fines” or “other process sludge” and were generated from a process
identified as a Dimersol polymerization unit. These correspond to residual codes “03-A,” “03-
B” and “02-D” in Section VII.2 and process code “11-B” in Section IV-1.C of the questionnaire.
Quality assurance was conducted by ensuring that all dimersol catalysts previously identified in
the questionnaire (i.e., in Section V.B) were assigned in Section VII.2.

Based on the results of the survey, 7 facilities use Dimersol polymerization units and may
generate spent dimersol catalyst. Due to the continuous generation of this residual, 1992 is
expected to be a typical year in regard to catalyst generation volume and management. There
was no reason to expect that 1992 would not be a typical year with regard to this residual's
generation and management. Table 3.7.4 provides a description of the quantity generated,
number of streams reported, number of streams not reporting volumes (data requested was
unavailable and facilities were not required to generate it), total and average volumes.

3.7.3.3 Plausible Management

EPA believes that most of the plausible management practices for this residual were
reported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.7.4. No data were
available to the Agency suggesting any other management practices. Unlike with phosphoric
acid polymerization catalyst, EPA does not expect spent Dimersol catalyst to be land treated due
to the physical nature of the filters.

Petroleum Refining Industry Study 94 August 1996

 Table 3.7.4. Generation Statistics for Spent Dimersol Polymerization Catalyst, 1992

# of Streams w/
# of Unreported Total Average
Final Management Streams Volume Volume (MT) Volume (MT)
Disposal Offsite Subtitle C Landfill 1 0 3.4 3.4
Disposal Onsite Subtitle D Landfill 1 0 8.8 8.8
Offsite incineration 1 1 0.3 0.3
Recover onsite in a coker 1 0 749 749
TOTAL 4 1 761.5 190.4

3.7.3.4 Characterization

Two sources of residual characterization were developed during the industry study:

• Table 3.7.5 summarizes the physical properties of the spent catalyst as reported in
Section VII.A of the §3007 survey.

• Two record samples of Dimersol polymerization catalyst were collected and analyzed
by EPA. The samples represent typical Dimersol polymerization catalyst used by the
industry and are summarized in Table 3.7.6.

The two record samples were analyzed for total and TCLP levels of volatiles,
semivolatiles, and metals, and pyrophoricity and corrosivity. None of the samples were found to
exhibit a hazardous waste characteristic. Dimersol and phosphoric acid catalysts were
categorized together in the consent decree, therefore, a summary of the results for both residuals
is presented in Table 3.7.7. Only constituents detected in at least one sample are shown in this
table.

3.7.3.5 Source Reduction

No source reduction techniques were reported by industry or found in the literature

search for this residual.

Petroleum Refining Industry Study 95 August 1996

 Table 3.7.5. Spent Dimersol Polymerization Catalyst Physical Properties

# of
# of Unreported
Properties Values Values1 10th % Mean 90th %
pH 7 4 3.8 5.5 9
Flash Point, C 4 7 93.3 93.3 100
Oil and Grease, vol% 3 8 2.6 5.3 6.4
Total Organic Carbon, vol% 3 8 0.08 4.1 9.5
Specific Gravity 6 5 0.7 1.2 1.4
Aqueous Liquid, % 11 0 0 0 70
Organic Liquid, % 11 0 0 0 60
Solid, % 11 0 20 100 100

1
Facilities were not required to do additional testing, therefore information provided was based on previously collected
data or engineering judgment.

Table 3.7.6. Dimersol Polymerization Catalyst Record Sampling Locations

Sample Number Location Description

R6B-PC-01 Shell, Norco, LA Dimersol filter
R16-PC-02 Koch, St. Paul, MN Dimersol filter

Petroleum Refining Industry Study 96 August 1996

 Table 3.7.7. Polymerization Catalyst Characterization
Petroleum Refining Industry Study

Volatile Organics - Method 8260A µg/kg

CAS No. R6B-PC-01 R16-PC-01 R16-PC-02 Average Conc Maximum Conc Comments
Ethylbenzene 100414 < 25 J 92 < 625 59 92 1
Isopropylbenzene 98828 < 25 J 350 < 625 188 350 1
Naphthalene 91203 58 < 250 < 625 58 58 1
Toluene 108883 < 25 J 130 < 625 78 130 1
1,2,4-Trimethylbenzene 95636 < 25 J 91 < 625 58 91 1
1,3,5-Trimethylbenzene 108678 < 25 J 91 < 625 58 91 1
m,p-Xylenes 108383 / 106423 < 25 J 120 < 625 73 120 1
TCLP Volatile Organics - Methods 1311 and 8260A µg/L
CAS No. R6B-PC-01 R16-PC-01 R16-PC-02 Average Conc Maximum Conc Comments
None Detected NA NA NA NA NA NA
Semivolatile Organics - Method 8270B µg/kg
CAS No. R6B-PC-01 R16-PC-01 R16-PC-02 Average Conc Maximum Conc Comments
Acenaphthene 83329 < 2,063 J 360 < 165 263 360 1
Anthracene 120127 < 2,063 J 300 < 165 233 300 1
Benz(a)anthracene 56553 < 2,063 990 < 165 578 990 1
Bis(2-ethylhexyl) phthalate 117817 < 2,063 < 413 630 521 630 1
Di-n-butyl phthalate 84742 < 2,063 < 413 J 77 77 77 1
97

Chrysene 218019 < 2,063 890 < 165 528 890 1

Dibenzofuran 132649 < 2,063 J 420 < 165 293 420 1
Fluoranthene 206440 < 2,063 J 210 < 165 188 210 1
Fluorene 86737 < 2,063 1,300 < 165 733 1,300 1
2-Methylchrysene 3351324 < 4,125 J 570 < 330 450 570 1
1-Methylnaphthalene 90120 < 4,125 1,800 < 330 1,065 1,800 1
2-Methylnaphthalene 91576 < 2,063 1,700 < 165 933 1,700 1
Phenanthrene 85018 < 2,063 3,100 < 165 1,776 3,100
Pyrene 129000 < 2,063 3,400 < 165 1,876 3,400
TCLP Semivolatile Organics - Methods 1311 and 8270B µg/L
CAS No. R6B-PC-01 R16-PC-01 R16-PC-02 Average Conc Maximum Conc Comments
None Detected NA NA NA NA NA NA
August 1996
 Table 3.7.7. Polymerization Catalyst Characterization (continued)
Petroleum Refining Industry Study

Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg
CAS No. R6B-PC-01 R16-PC-01 R16-PC-02 Average Conc Maximum Conc Comments
Aluminum 7429905 6,500 3,400 19,000 9,633 19,000
Arsenic 7440382 210 < 1.00 5.30 72.1 210
Barium 7440393 2,600 < 20.0 4,200 2,273 4,200
Calcium 7440702 1,200 3,500 < 500 1,733 3,500
Chromium 7440473 2.70 33.0 < 1.00 12.2 33.0
Cobalt 7440484 15.0 < 5.00 < 5.00 8.33 15.0
Copper 7440508 7.40 21.0 28.0 18.8 28.0
Iron 7439896 1,300 4,200 500 2,000 4,200
Lead 7439921 3.50 9.70 2.20 5.13 9.70
Magnesium 7439954 < 500 1,200 < 500 733 1,200
Manganese 7439965 13.0 57.0 15.0 28.3 57.0
Mercury 7439976 0.10 < 0.05 < 0.05 0.07 0.10
Nickel 7440020 9,600 52.0 75,000 28,217 75,000
Potassium 7440097 1,100 < 500 < 500 700 1,100
Sodium 7440235 13,000 < 500 8,000 7,167 13,000
Vanadium 7440622 < 5.00 21.0 < 5.00 10.3 21.0
Zinc 7440666 1,700 1,400 3,000 2,033 3,000
98

TCLP Metals - Methods 1311, 6010, 7060, 7421, 7470, 7471, and 7841 mg/L
CAS No. R6B-PC-01 R16-PC-01 R16-PC-02 Average Conc Maximum Conc Comments
Arsenic 7440382 0.19 NA < 0.05 0.12 0.19
Barium 7440393 < 1.00 NA 36.0 18.5 36.0
Nickel 7440020 160 NA 67.0 114 160
Zinc 7440666 B 1.40 NA B 4.90 3.15 4.90
Miscellaneous Characterization
R6B-PC-01 R16-PC-01 R16-PC-02
Corrosivity (pH) NA < 1.0 NA

Comments:

1 Detection limits greater than the highest detected concentration are excluded from the calculations.

Notes:

B Analyte also detected in the associated method blank.

J Compound's concentration is estimated. Mass spectral data indicate the presence of a compound that meets the identification criteria for which the result is less than the laboratory detection limit, but greater than
zero.
ND Not Detected.
August 1996

NA Not Applicable.
 STUDY OF SELECTED
PETROLEUM REFINING RESIDUALS

INDUSTRY STUDY

August 1996

U.S. ENVIRONMENTAL PROTECTION AGENCY

Office of Solid Waste
Hazardous Waste Identification Division
401 M Street, SW
Washington, DC 20460
3.8 RESIDUAL UPGRADING

After vacuum distillation, there are still some valuable oils left in the vacuum-reduced
crude. Vacuum tower distillation bottoms and other residuum feeds can be upgraded to higher
value products such as higher grade asphalt or feed to catalytic cracking processes. Residual
upgrading includes processes where asphalt components are separated from gas oil components
by the use of a solvent. It also includes processes where the asphalt value of the residuum is
upgraded (e.g., by oxidation) prior to sale. Off-spec product and fines, as well as process
sludges, are study residuals from this category.

3.8.1 Process Descriptions

A total of 47 refineries reported using residual upgrading units. Four types of residual
upgrading processes were reported in the 1992 RCRA §3007 Petroleum Refining Survey:

• Solvent Deasphalting
• Asphalt Oxidation
• Supercritical Extraction
• Asphalt Emulsion

Asphalt uses are typically divided into use as road oils, cutback asphalts, asphalt
emulsions, and solid asphalts. These asphalt products are used in paving roads, roofing, paints,
varnishes, insulating, rust-protective compositions, battery boxes, and compounding materials
that go into rubber products, brake linings, and fuel briquettes (REF).

3.8.1.1 Solvent Deasphalting

Residuum from vacuum distillation is separated into asphalt components and gas oil
components by solvent deasphalting. Figure 3.8.1 provides a simplified process flow diagram.
The hydrocarbon solvent is compressed and contacted with the residuum feed. The extract
contains the paraffinic fractions (deasphalted oil or DAO), and the raffinate contains the
asphaltic components. The extract and raffinate streams are sent to separate solvent recovery
systems to reclaim the solvent. The DAO may be further refined or processed, used as catalytic
cracking feed, sent to lube oil processing/blending, or sold as finished product. The following
types of solvents are typically used for the following residual upgrading processes:

• Propane is the best choice for lube oil production due to its ability to extract only
paraffinic hydrocarbons and to reject most of the carbon residue. (McKetta)

• A mixture of propane and butane is valuable for preparing feedstocks for catalytic
cracking processes due to its ability to remove metal-bearing components.
(McKetta)

• Pentane deasphalting, plus hydrodesulfurization, can produce more feed for

catalytic cracking or low sulfur fuel oil. (McKetta)

Petroleum Refining Industry Study 107 August 1996

 Figure 3.8.1. Solvent Deasphalting Process Flow Diagram

• One facility reported using propane and phenol solvents for deasphalting
residuum. The DAO is sent to lube oil processing and the asphalt fraction is sent
to delayed coking or fuel oil blending.

During process upsets, heavy hydrocarbons may become entrained in the solvent
recovery systems, and off-specification product may be generated. The entrained hydrocarbons
are periodically removed from the unit as a process sludge and typically disposed in an industrial
landfill. The off-specification product are returned to the process for re-processing.

3.8.1.2 Asphalt Oxidation (Asphalt Blowing)

Residuum from the vacuum tower or from solvent deasphalting is upgraded by oxidation
with air. Figure 3.8.2 provides a simplified process flow diagram. Air is blown through the
asphalt that is heated to about 500 F, starting an exothermic reaction. The temperature is
controlled by regulating the amount of air and by circulating oil or water through cooling coils
within the oxidizer. The oxygen in the air reacts with hydrogen in the residuum to form water,
and the reaction also couples smaller molecules of asphalt into larger molecules to create a
heavier product. These reactions changes the characteristics of the asphalt to a product with the
desired properties.

During this process, coke will form on the oxidizer walls and the air sparger. The coke is
removed periodically (1 to 2 years) and sent to the coke pad for sale, mixed with asphalt for use
as road material, stored, or disposed. The off-gases from the process are scrubbed to remove
hydrocarbons prior to burning in an thermal unit such as an incinerator or furnace.

Petroleum Refining Industry Study 108 August 1996

 Figure 3.8.2. Asphalt Oxidation Process Flow Diagram

Supercritical Extraction

The Residuum Oil Supercritical Extraction (ROSE) process is not, in a strict sense, a
supercritical fluid extraction process. The primary extraction step is not carried out at
supercritical conditions, but at liquid conditions that take advantage of the variable solvent
power of a near-critical liquid. A simplified process flow diagram is provided in Figure 3.8.3.
The first stage of the ROSE process consists of mixing residuum with compressed liquid butane
or pentane and precipitating the undesired asphaltene fraction. Butane is used for its higher
solvent power for heavy hydrocarbons. If an intermediate resin fraction is desired, another
separator and stripper system would be used directly after the asphaltene separator. To recover a
resin fraction, the overhead from the asphaltene separator is heated to near the critical
temperature of the butane. At the elevated, near-critical temperature, the solvent power of the
compressed liquid butane decreases and the resins precipitate from solution. The remaining
fraction would consist of deasphalted light oils dissolved in butane. The butane is typically
recovered using steam.

Petroleum Refining Industry Study 109 August 1996

 Figure 3.8.3. Supercritical Extraction Process Flow Diagram

The DAO may be sent to FCC, blended into lubricating oil, or sold as finished product.
The asphaltene and resins are reported to be blended into No. 6 fuel oil. The solvent and steam
are condensed and collected in a surge drum where the solvent is recycled back to the process.
This surge drum accumulates sludges during process upsets that are removed during routine
process turnarounds and disposed as nonhazardous wastes.

Asphalt Emulsion

Residuals from the vacuum tower may be upgraded to an asphalt emulsion by milling
soap (or shear mixing) with the asphalt. These emulsions are used for road oils, where good
adhesion is required.

This process generated residuals from the cleanout of the soap tanks and from the
generation of off-spec emulsions. The soap tank cleanout residuals are typically sent to the
wastewater treatment plant, and the off-spec emulsions are sent to a pit where heat is applied to
break the emulsion. The soap fraction is sent the wastewater treatment system and the oil
fraction is recycled back to the coker feed.

Petroleum Refining Industry Study 110 August 1996

3.8.2 Off-specification Product from Residual Upgrading

3.8.2.1 Description

This residual was identified in the consent decree based on an incorrect characterization
of data in a supporting document generated from 1983 PRDB data. After conducting a review
of the underlying data, it was determined that volumes associated with the category of “off-
specification product from residual upgrading” were actually process sludges generated during
process upset conditions. The Agency's finding regarding this category was corroborated during
its field investigation where this residual category was not identified and in the §3007 survey
results. Generally, refineries re-work any residuum that does not initially meet product
specifications within the upgrading process and rarely (one reported in 1992 in the §3007
survey) generate off-specification product for disposal.

3.8.2.2 Generation and Management

Off-spec product from residual upgrading includes material generated from asphalt
oxidation, solvent deasphalting, and other upgrading processes. Residuals were assigned to be
“off-specification product from residual upgrading” if they were assigned a residual
identification code of “off-specification product” or “fines” and were generated from a process
identified as a residual upgrading unit. These correspond to residual codes “05” and “06” in
Section VII.2 of the questionnaire and process code “13” in Section IV-1.C of the questionnaire.

Based on the results of the questionnaire, 47 facilities use residual upgrading processes
and thus could potentially generate off-specification product from residual upgrading. Only one
facility reported this residual, generating 800 MT that was recovered within the process. The
base year, 1992, was expected to be a typical year for residual upgrading processes and the
survey results are in keeping with the Agency's understanding of this process. Table 3.8.1
provides a description of the quantity generated and number of reporting facilities.

Table 3.8.1. Generation Statistics for Off-Specification Product

from Residual Upgrading, 1992

# of Streams
# of w/ Unreported Total Volume Average
Final Management Streams Volume (MT) Volume (MT)
Other recovery onsite: reuse in
1 0 800 800
extraction process

3.8.2.3 Plausible Management

The Agency does not find it necessary to consider other management practices because
off-spec product from residual upgrading had been classified as a residual of concern based on
erroneous old data and in fact is not generated for disposal.

Petroleum Refining Industry Study 111 August 1996

3.8.2.4 Characterization

Only one source of residual characterization data were developed during the industry
study:

• Table 3.8.2 summarizes the physical properties of the off-specification product as

reported in Section VII.A of the §3007 survey.

Because it is rarely generated, no record samples of this residual were available during
record sampling for analysis.

Table 3.8.2. Off-Specification Product from Residual Upgrading: Physical Properties

# of
# of Unreported
Properties Values Values1 10th % 50th % 90th %
Flash Point, C 1 2 99.00 99.00 99.00
Specific Gravity 1 2 1.02 1.02 1.02
Aqueous Liquid, % 1 2 40.00 40.00 40.00
Organic Liquid, % 1 2 60.00 60.00 60.00
Solid, % 1 2 100.00 100.00 100.00
Other, % 1 2 100.00 100.00 100.00

1
Facilities were not required to do additional testing, therefore information provided was based on previously collected
data or engineering judgment.

3.8.2.5 Source Reduction

No source reduction techniques were reported by industry or found in the literature

search for this residual.

3.8.3 Process Sludge from Residual Upgrading

3.8.3.1 Description

Process sludge is generated from miscellaneous parts of the various residual upgrading
processes. This category is neither uniform nor routinely generated. Solvent deasphalting may
generate a sludge due to hydrocarbon carryover in the solvent recovery system. Similarly, the
ROSE process may generate sludges due to process upsets in the solvent condensate collection
system. Additional sludges may be generated during unit turnarounds and in surge drums and
condensate knockout drums.

Petroleum Refining Industry Study 112 August 1996

 Three residuals were reported to be managed “as hazardous”, accounting for 25 percent
of the volume of this category generated in 1992.1

3.8.3.2 Generation and Management

Twenty-one facilities reported generating a total quantity of 241 MT of this residual in

1992, according to the 1992 survey. Residuals were assigned to be “process sludge from
residual upgrading” if they were assigned a residual identification code of “process sludge” and
were generated from a process identified as a “residual upgrading” unit. These correspond to
residual code “02-D” in Section VII.2 of the questionnaire and process code “13” in Section IV-
1.C of the questionnaire.

Based on the results of the questionnaire, 47 facilities use residual upgrading units and
thus may generate process sludge from residual upgrading. Due to the infrequent generation of
this residual, not all of these 47 facilities generated sludge in 1992. However, there was no
reason to expect that 1992 would not be a typical year with regard to this residual's generation
and management. Table 3.8.3 provides a description of the quantity generated, number of
streams reported, number of streams not reporting volumes (data requested was unavailable and
facilities were not required to generate it), total and average volumes.

Table 3.8.3. Generation Statistics for Process Sludge from Residual Upgrading, 1992

# of Streams
# of w/ Unreported Total Volume Average
Final Management Streams Volume (MT) Volume (MT)
Discharge to onsite wastewater
3 0 3.94 1.31
treatment facility
Disposal in offsite Subtitle D landfill 12 0 137.56 11.46
Disposal in offsite Subtitle C landfill 1 0 0.10 0.10
Disposal in onsite Subtitle C landfill 4 0 62.00 15.50
Disposal in onsite Subtitle D landfill 2 0 7.30 3.65
Offsite incineration 1 0 9.00 9.00
Other recycling, reclamation, or reuse:
4 0 0.22 0.06
onsite road material
Recovery onsite via distillation 1 0 16.00 16.00
Transfer with coke product or other
4 0 5.44 1.36
refinery product
TOTAL 32 0 241.56 7.55

1
These percentages do not match up directly with any one of the management scenarios because the number of
streams and the volume are a combination of several management scenarios (i.e., managed in WWTP, Subtitle C
landfill, etc.).

Petroleum Refining Industry Study 113 August 1996

3.8.3.3 Plausible Management

EPA believes that most of the plausible management practices for this residual were
reported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.8.3. The Agency
gathered information suggesting that “recovery onsite in an asphalt production unit” (3.6 MT)
and “transfer to offsite entity: unspecified” (unreported quantity) were used in other years. This
non-1992 management practice is comparable with other recovery practices reported in 1992.

3.8.3.4 Characterization

Two sources of residual characterization data were developed during the industry study:

• Table 3.8.4 summarizes the physical properties of the sludge as reported in

Section VII.A of the §3007 survey.

• One record sample of process sludge from residual upgrading was collected and
analyzed by EPA. This sample is summarized in Table 3.8.5.

The sample was analyzed for total and TCLP levels of volatiles, semivolatiles, metals,
and ignitability. The sample was found to exhibit the toxicity characteristic for benzene. A
summary of the results is presented in Table 3.8.6. Only constituents detected in the sample are
shown in this table.

3.8.3.5 Source Reduction

Source reduction techniques were reported to be process modifications and better

housekeeping. This residual is generated infrequently and in very small quantities, therefore
limited information was expected.

Petroleum Refining Industry Study 114 August 1996

 Table 3.8.4. Process Sludge from Residual Upgrading: Physical Properties

# of
# of Unreported
Properties Values Values1 10th % 50th % 90th %
pH 11 38 5.50 6.30 7.60
Reactive CN, ppm 8 41 0.01 0.74 50.00
Reactive S, ppm 7 42 0.01 15.00 4400.00
Flash Point, C 14 35 82.22 94.17 315.56
Oil and Grease, vol% 7 42 0.10 9.00 100.00
Total Organic Carbon, vol% 16 33 50.00 98.50 100.00
Specific Gravity 12 37 0.90 1.08 1.85
BTU Content, BTU/lb 3 46 11.00 5,000.00 10,000.00
Aqueous Liquid, % 23 26 0.00 0.00 25.00
Organic Liquid, % 23 26 0.00 5.00 90.00
Solid, % 34 15 10.00 99.00 100.00
Other, % 18 31 0.00 0.00 2.00
Particle >60 mm, % 12 37 20.00 50.00 100.00
Particle 1-60 mm, % 9 40 1.00 49.00 80.00
Particle 100 µm-1 mm, % 5 44 0.00 1.00 1.00
Particle 10-100 µm, % 1 48 0.00 0.00 0.00
Particle <10 µm, % 1 48 0.00 0.00 0.00
Median Particle Diameter, microns 1 48 60.00 60.00 60.00

1
Facilities were not required to do additional testing, therefore information provided was based on previously collected
data or engineering judgment.

Table 3.8.5. Process Sludge from Residual Upgrading Record Sampling Locations

Sample Number Location Description

R1-RU-01 Marathon, Indianapolis, IN ROSE unit scale/sludge

Petroleum Refining Industry Study 115 August 1996

 Table 3.8.6. Process Sludge from Residual Upgrading Characterization

Volatile Organics - Method 8260A µg/kg

CAS No. R1-RU-01 Comments
Acetone 67641 B 120,000
Benzene 71432 73,000
Ethylbenzene 100414 130,000
Methylene chloride 75092 64,000
4-Methyl-2-pentanone 108101 63,000
n-Propylbenzene 103651 65,000
Toluene 108883 310,000
1,2,4-Trimethylbenzene 95636 570,000
1,3,5-Trimethylbenzene 108678 150,000
o-Xylene 95476 230,000
m,p-Xylenes 108383 / 106423 690,000
Naphthalene 91203 160,000
TCLP Volatile Organics - Methods 1311 and 8260A µg/L
CAS No. R1-RU-01 Comments
Benzene 71432 2,600
Ethylbenzene 100414 570
Toluene 108883 4,100
1,2,4-Trimethylbenzene 95636 990
o-Xylene 95476 1,300
m,p-Xylene 108383 / 106423 2,800
Semivolatile Organics - Method 8270B µg/kg
CAS No R1-RU-01 Comments
Acenaphthene 83329 J 38,000
Anthracene 120127 J 13,000
Dibenzofuran 132649 J 13,000
Fluorene 86737 J 39,000
Phenanthrene 85018 120,000
Pyrene 129000 J 19,000
1-Methylnaphthalene 90120 390,000
2-Methylnaphthalene 91576 570,000
Naphthalene 91203 190,000
TCLP Semivolatile Organics - Methods 1311 and 8270B µg/L
CAS No. R1-RU-01 Comments
Bis(2-ethylhexyl)phthalate 117817 J 30
2,4-Dimethylphenol 105679 J 52
Indene 95136 J 16
1-Methylnaphthalene 90120 J 96
2-Methylnaphthalene 91576 130

Petroleum Refining Industry Study 116 August 1996

 Table 3.8.6. Process Sludge from Residual Upgrading Characterization (continued)

TCLP Semivolatile Organics - Methods 1311 and 8270B µg/L (continued)

CAS No. R1-RU-01 Comments
2-Methylphenol 95487 J 65
3/4-Methylphenol NA J 85
Naphthalene 91203 190
Phenol 108952 J 57
Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg
CAS No. R1-RU-01 Comments
Aluminum 7429905 150
Antimony 7440360 14.0
Arsenic 7440382 43.0
Barium 7440393 41.0
Cadmium 7440439 1.10
Calcium 7440702 15,000
Chromium 7440473 86.0
Cobalt 7440484 13.0
Copper 7440508 92.0
Iron 7439896 200,000
Lead 7439921 20.0
Magnesium 7439954 6,500
Manganese 7439965 770
Mercury 7439976 0.11
Molybdenum 7439987 24.0
Nickel 7440020 90.0
Vanadium 7440622 100
Zinc 7440666 40.0
TCLP Metals - Methods 1311, 6010, 7060, 7421, 7470, 7471, and 7841 mg/L
CAS No. R1-RU-01 Comments
Calcium 7440702 130
Iron 7439896 120
Manganese 7439965 3.90
Zinc 7440666 0.24
Miscellaneous Characterization
R1-RU-01 Comments
Ignitability ( oF ) 199

Notes:

B Analyte also detected in the associated method blank.

J Compound's concentration is estimated. Mass spectral data indicate the presence of a compound
that meets the identification criteria for which the result is less than the laboratory detection limit, but
greater than zero.

Petroleum Refining Industry Study 117 August 1996

3.9 LUBE OIL PROCESSING

Vacuum distillates are treated and refined to produce a variety of lubricants. Wax,
aromatics, and asphalts are removed by unit operations such as solvent extraction and
hydroprocessing; clay may also be used. Various additives are used to meet product
specifications for thermal stability, oxidation resistances, viscosity, pour point, etc.

3.9.1 Process Descriptions

The manufacture of lubricating oil base stocks consists of five basic steps:

1) Distillation

2) Deasphalting to prepare the feedstocks

3) Solvent or hydrogen refining to improve viscosity index and quality

4) Solvent or catalytic dewaxing to remove wax and improve low temperature properties
of paraffinic lubes

5) Clay or hydrogen finishing to improve color, stability, and quality of the lube base
stock.

Based on results of the 1992 survey, 22 facilities reported conducting lube oil processing.
The finished lube stocks are blended with each other and additives using batch and continuous
methods to produce formulated lubricants. The most common route to finishing lube feedstocks
consists of solvent refining, solvent dewaxing, and hydrogen finishing. The solvent and clay
processing route or the hydrogen refining and solvent dewaxing route are also used. The all-
hydrogen processing (lube hydrocracking-catalytic dewaxing-hydrorefining) route is used by
two refiners for the manufacture of a limited number of paraffinic base oils. Figure 3.9.1
provides a general process flow diagram for lube oil processing.

Lube Distillation

Lube processing may be the primary production process at some facilities, while at others
it is only one of many operations. The initial step is to separate the crude into the fractions
which are the raw stocks for the various products to be produced. The basic process consists of
an atmospheric distillation unit and a vacuum distillation unit. The majority of the lube stocks
boil in the range between 580 F and 1000 F and are distilled in the vacuum unit to the proper
viscosity and flash specifications. Caustic solutions are sometimes introduced to the feed to
neutralize organic acids present in some crude oils. This practice reduces or eliminates corrosion
in downstream processing units, and improves color, stability, and refining response of lube
distillates.

Petroleum Refining Industry Study 118 August 1996

 Figure 3.9.1. Lube Oil Processing Flow Diagram

Lube Deasphalting

Other facilities incorporate lube deasphalting to process vacuum residuum into lube oil
base stocks. Propane deasphalting is most commonly used to remove asphaltenes and resins
which contribute an undesirable dark color to the lube base stocks. This process typically uses
baffle towers or rotating disk contactors to mix the propane with the feed. Solvent recovery is
accomplished with evaporators, and supercritical solvent recovery processes are also used in
some deasphalting units. Another deasphalting process is the Duo-Sol Process that is used to
both deasphalt and extract lubricating oil feedstocks. Propane is used as the deasphalting solvent
and a mixture of phenol and cresylic acids are used as the extraction solvent. The extraction is
conducted in a series of batch extractors followed by solvent recovery in multistage flash
distillation and stripping towers. See the section on Residual Upgrading for additional
discussion on these processes.

Lube Refining Processes

Chemical, solvent, and hydrogen refining processes have been developed and are used to
remove aromatics and other undesirable constituents, and to improve the viscosity index and
quality of lube base stocks. Traditional chemical processes that use sulfuric acid and clay
refining have been replaced by solvent extraction/refining and hydrotreating which are more
effective, cost efficient, and environmentally more acceptable. Chemical refining is used most
often for the reclamation of used lubricating oils or in combination with solvent or hydrogen
refining processes for the manufacture of specialty lubricating oils and by-products.

Chemical Refining Processes: Acid-alkali refining, also called “wet refining”, is a

process where lubricating oils are contacted with sulfuric acid followed by neutralization with

Petroleum Refining Industry Study 119 August 1996

alkali. Oil and acid are mixed and an acid sludge is allowed to coagulate. The sludge is
removed or the oil is decanted after settling, and more acid is added and the process repeated.

Acid-clay refining, also called “dry refining” is similar to acid-alkali refining with the
exception that clay and a neutralizing agent are used for neutralization. This process is used for
oils that form emulsions during neutralization.

Neutralization with aqueous and alcoholic caustic, soda ash lime, and other neutralizing
agents is used to remove organic acids from some feedstocks. This process is conducted to
reduce organic acid corrosion in downstream units or to improve the refining response and color
stability of lube feedstocks.

Hydrogen Refining Processes: Hydrogen refining, also called hydrotreating, has since
been replaced with solvent refining processes which are more cost effective. Hydrotreating
consists of lube hydrocracking as an alternative to solvent extraction, and hydrorefining to
prepare specialty products or to stabilize hydrocracked base stocks. Hydrocracking catalysts are
proprietary to the licensors and consist of mixtures of cobalt, nickel, molybdenum, and tungsten
on an alumina or silica-alumina-based carrier. Hydrorefining catalysts are proprietary but
usually consist of nickel-molybdenum on alumina.

Lube hydrocracking are used to remove nitrogen, oxygen, and sulfur, and convert the
undesirable polynuclear aromatics and polynuclear naphthenes to mononuclear naphthenes,
aromatics, and isoparaffins which are typically desired in lube base stocks. Feedstocks consist of
unrefined distillates and deasphalted oils, solvent extracted distillates and deasphalted oils, cycle
oils, hydrogen refined oils, and mixtures of these hydrocarbon fractions.

Lube hydrorefining processes are used to stabilize or improve the quality of lube base
stocks from lube hydrocracking processes and for manufacture of specialty oils. Feedstocks are
dependent on the nature of the crude source but generally consist of waxy or dewaxed-solvent-
extracted or hydrogen-refined paraffinic oils and refined or unrefined naphthenic and paraffinic
oils from some selected crudes.

Solvent Refining Processes: Feedstocks from solvent refining processes consist of

paraffinic and naphthenic distillates, deasphalted oils, hydrogen refined distillates and
deasphalted oils, cycle oils, and dewaxed oils. The products are refined oils destined for further
processing or finished lube base stocks. The by-products are aromatic extracts which are used in
the manufacture of rubber, carbon black, petrochemicals, FCCU feed, fuel oil, or asphalt. The
major solvents used today are N-methyl-2-pyrolidone (NMP) and furfural, with phenol and
liquid sulfur dioxide used to a lesser extent.

The solvents are typically recovered in a series of flash towers. Steam or inert gas
strippers are used to remove traces of solvent, and a solvent purification system is used to
remove water and other impurities from the recovered solvent.

Petroleum Refining Industry Study 120 August 1996

Lube Dewaxing Processes

Lube feedstocks typically contain increased wax content resulting from deasphalting and
refining processes. These waxes are normally solid at ambient temperatures and must be
removed to manufacture lube oil products with the necessary low temperature properties.
Catalytic dewaxing and solvent dewaxing (the most prevalent) are processes currently in use;
older technologies include cold settling, pressure filtration, and centrifuge dewaxing.

Catalytic Dewaxing: Because solvent dewaxing is relatively expensive for the

production of low pour point oils, various catalytic dewaxing (selective hydrocracking)
processes have been developed for the manufacture of lube oil base stocks. The basic process
consists of a reactor containing a proprietary dewaxing catalyst followed by a second reactor
containing a hydrogen finishing catalyst to saturate olefins created by the dewaxing reaction and
to improve stability, color and demulsibility of the finished lube oil.

Solvent Dewaxing: Solvent dewaxing consists of the following steps: crystallization,

filtration, and solvent recovery. In the crystallization step, the feedstock is diluted with the
solvent and chilled, solidifying the wax components. The filtration step removes the wax from
the solution of dewaxed oil and solvent. Solvent recovery removes the solvent from the wax
cake and filtrate for recycle by flash distillation and stripping. The major processes in use today
are the ketone dewaxing processes. Other processes that are used to a lesser degree include the
Di/Me Process and the propane dewaxing process.

The most widely used ketone processes are the Texaco Solvent Dewaxing Process and
the Exxon Dilchill Process. Both processes consist of diluting the waxy feedstock with solvent
while chilling at a controlled rate to produce a slurry. The slurry is filtered using rotary vacuum
filters and the wax cake is washed with cold solvent. The filtrate is used to prechill the
feedstock and solvent mixture. The primary wax cake is diluted with additional solvent and
filtered again to reduce the oil content in the wax. The solvent recovered from the dewaxed oil
and wax cake by flash vaporization and recycled back into the process. The Texaco Solvent
Dewaxing Process (also called the MEK process) uses a mixture of MEK and toluene as the
dewaxing solvent, and sometimes uses mixtures of other ketones and aromatic solvents. The
Exxon Dilchill Dewaxing Process uses a direct cold solvent dilution-chilling process in a special
crystallizer in place of the scraped surface exchangers used in the Texaco process.

The Di/Me Dewaxing Process uses a mixture of dichloroethane and methylene dichloride
as the dewaxing solvent. This process is used by a few refineries in Europe. The Propane
Dewaxing Process is essentially the same as the ketone process except for the following:
propane is used as the dewaxing solvent and higher pressure equipment is required, and chilling
is done in evaporative chillers by vaporizing a portion of the dewaxing solvent. Although this
process generates a better product and does not require crystallizers, the temperature differential
between the dewaxed oil and the filtration temperature is higher than for the ketone processes
(higher energy costs), and dewaxing aids are required to get good filtration rates.

Petroleum Refining Industry Study 121 August 1996

Lube Oil Finishing Processes

Today, hydrogen finishing processes (also referred to as hydrorefining) have largely

replaced the more costly acid and clay finishing processes. Hydrogen finishing processes are
mild hydrogenation processes used to improve the color, odor, thermal, and oxidative stability,
and demulsibility of lube base stocks. The process consists of fixed bed catalytic reactors that
typically use a nickel-molybdenum catalyst to neutralize, desulfurize, and denitrify lube base
stocks. These processes do not saturate aromatics or break carbon-carbon bonds as in other
hydrogen finishing processes. Sulfuric acid treating is still used by some refiners for the
manufacture of specialty oils and the reclamation of used oils. This process is typically
conducted in batch or continuous processes similar to the chemical refining processes discussed
earlier, with the exception that the amount of acid used is much lower that used in acid refining.
Clay contacting involves mixing the oil with fine bleaching clay at elevated temperature
followed by separation of the oil and clay. This process improves color and chemical, thermal,
and color stability of the lube base stock, and is often combined with acid finishing. Clay
percolation is a static bed absorption process used to purify, decolorize, and finish lube stocks
and waxes. It is still used in the manufacture of refrigeration oils, transformer oils, turbine oils,
white oils, and waxes.

3.9.2 Treating Clay from Lube Oil Processing

3.9.2.1 Description

The majority of treating clays (including other sorbents) generated from lube oil
processing are from acid-clay treating in refining or lube oil finishing. The average volume is
approximately 40 metric tons.

3.9.2.2 Generation and Management

The spent clay is vacuumed or gravity dumped from the vessels into piles or into
containers such as drums and roll-off bins. Only one residual was reported to be managed “as
hazardous” from this category in 1992.

Seven facilities reported generating a total quantify of approximately 733 metric tons of
this residual in 1992, according to the 1992 RCRA §3007 Questionnaire. Residual were
assigned to be “treating clay from lube oil processes” if they were assigned a residual
identification code of “spent sorbent” and were generated from a lube oil process. These
correspond to residual code “05” in Section VII.A of the questionnaire and process code “17” in
Section IV.C of the questionnaire. Table 3.9.1 provides a description of the 1992 management
practices, quantity generated, number of streams reported, number of streams not reporting
volumes (data requested was unavailable and facilities were not required to generate it), total and
average volumes.

Petroleum Refining Industry Study 122 August 1996

 Table 3.9.1. Generation Statistics for Treating Clay from Lube Oil, 1992

# of Streams
# of w/ Unreported Total Volume Average
Final Management Streams Volume (MT) Volume (MT)
Disposal in offsite Subtitle D landfill 1 1 36.7 36.7
Disposal in offsite Subtitle C landfill 2 0 78.7 39.4
Disposal in onsite Subtitle C landfill 1 0 5 5
Onsite land treatment 1 0 9.8 9.8
Other recycling, reclamation, or reuse: 1 0 249.2 249.2
cement plant
Other recycling, reclamation, or reuse: 12 0 354 29.5
onsite regeneration
TOTAL 18 1 733.4 40.7

3.9.2.3 Plausible Management

EPA believes that most of the plausible management practices for this residual were
reported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.9.1. No data were
available to the Agency suggesting any other management practices. In addition, EPA compared
the management practice reported for lube oil treating clay to those reported for treating clays
from extraction, alkylation, and isomerization2 based on expected similarities. No additional
management practices were reported.

3.9.2.4 Characterization

Two sources of residual characterization were developed during the industry study:

• Table 3.9.2 summarizes the physical and chemical properties of treating clay from lube
oil processes as reported in Section VII.A of the §3007 survey.

• One record sample of treating clay from lube oil processes was collected and analyzed
by EPA. Sampling information is summarized in Table 3.9.3.

The collected sample is expected to be generally representative of treating clay from lube
oil processes. The sample was analyzed for total and TCLP levels of volatiles, semi-volatiles,
and metals. The sample did not exhibit any of the hazardous waste characteristics. A summary
of the analytical results is presented in Table 3.9.4. Only constituents detected in the sample are
reported.

2
EPA did not compare these management practices to those reported for the broader category of “treating clay from
clay filtering” due to the diverse types of materials included in this miscellaneous category.

Petroleum Refining Industry Study 123 August 1996

 Table 3.9.2. Treating Clay from Lube Oil: Physical Properties

# of
# of Unreported
Properties Values Values 10th % 50th % 90th %
pH 3 17 3.80 7.40 7.40
Flash Point, C 2 18 95.00 95.00 95.00
Oil and Grease, vol% 12 8 1.00 1.00 1.00
Total Organic Carbon, vol% 12 8 1.00 1.00 1.00
Specific Gravity 15 5 0.90 3.20 3.20
Aqueous Liquid, % 4 16 0.00 0.00 0.00
Organic Liquid, % 4 16 0.00 0.00 0.00
Solid, % 7 13 100.00 100.00 100.00
Particle >60 mm, % 2 18 0.00 0.00 0.00
Particle 1-60 mm, % 2 18 0.00 45.80 91.60
Particle 100 µm-1 mm, % 2 18 8.40 54.20 100.00
Particle 10-100 µm, % 4 16 0.00 50.00 100.00
Particle <10 µm, % 2 18 0.00 0.00 0.00
Median Particle Diameter, microns 2 18 0.00 400.00 800.00

1
Facilities were not required to do additional testing, therefore information provided was based on previously collected
data or engineering judgment.

Table 3.9.3. Treating Clay from Lube Oil Processing Record Sampling Locations

Sample Number Location Description

R13-CL-01 Shell, Deer Park, TX Pellets from wax treating

3.9.3.5 Source Reduction

This residual is generated infrequently and in very small quantities. Treating clays use
for product polishing in lube oil manufacturing are being phased out by industry. No source
reduction methods were reported by industry or found in the literature search.

Petroleum Refining Industry Study 124 August 1996

 Table 3.9.4. Treating Clay from Lube Oil Processing Characterization

Volatile Organics - Method 8260A µg/kg

CAS No. R13-CL-01 Comments
Benzene 71432 11
Ethylbenzene 100414 J 8
Methylene chloride 75092 24
n-Propylbenzene 103651 J 8
Toluene 108883 31
1,2,4-Trimethylbenzene 95636 78
1,3,5-Trimethylbenzene 108678 34
o-Xylene 95476 18
m,p-Xylenes 108383 / 106423 52
TCLP Volatile Organics - Methods 1311 and 8260A µg/L
CAS No. R13-CL-01 Comments
Methylene chloride 75092 B 2,600

Semivolatile Organics - Method 8270B µg/kg

CAS No R13-CL-01 Comments
Bis(2-ethylhexyl)phthalate 117817 38,000
Di-n-butyl phthalate 84742 J 390
N-Nitrosodiphenylamine 86306 J 470

TCLP Semivolatile Organics - Methods 1311 and 8270B µg/L

CAS No. R13-CL-01 Comments
2-Methylphenol 95487 J 18
3/4-Methylphenol NA J 18

Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg
CAS No. R13-CL-01 Comments
Aluminum 7429905 140,000
Barium 7440393 53.0
Calcium 7440702 1,300
Chromium 7440473 100
Copper 7440508 260
Iron 7439896 19,000
Lead 7439921 36.0
Manganese 7439965 180
Vanadium 7440622 130
Zinc 7440666 120

Petroleum Refining Industry Study 125 August 1996

 Table 3.9.4. Treating Clay from Lube Oil Processing Characterization (continued)

TCLP Metals - Methods 1311, 6010, 7060, 7421, 7470, 7471, and 7841 mg/L
CAS No. R13-CL-01 Comments
Aluminum 7429905 12.0
Copper 7440508 0.90
Manganese 7439965 1.50
Zinc 7440666 B 0.94
Miscellaneous Characterization
R13-CL-01 Comments
Ignitability ( oF ) NA

Comments:

1 Detection limits greater than the highest detected concentration are excluded from the calculations.

Notes:

B Analyte also detected in the associated method blank.

J Compound's concentration is estimated. Mass spectral data indicate the presence of a compound
that meets the identification criteria for which the result is less than the laboratory detection limit, but
greater than zero.
ND Not Detected.
NA Not Applicable.

Petroleum Refining Industry Study 126 August 1996

3.10 H2S REMOVAL AND SULFUR COMPLEX

3.10.1 Process Description

All crude oil contains sulfur, which must be removed at various points of the refining
process. The predominant technique for treating light petroleum gases is (1) amine scrubbing
followed by (2) recovery of elemental sulfur in a Claus unit followed by (3) final sulfur removal
in a tail gas unit. This dominance is shown in Table 3.10.1, which presents the sulfur
complex/removal processes reported in the RCRA §3007 Survey.

Table 3.10.1. Sulfur Removal Technologies Reported in RCRA §3007 Questionnaire

Number of Percentage of
Technique Facilities Facilities1
Amine-based sulfur removal 106 86
2
Claus sulfur recovery 101 82
Other sulfur removal or recovery 16 13
3
SCOT®-type tail gas unit 50 41
Other tail gas treating unit4 19 15

1
Percentage of the 123 facilities reporting any sulfur removal/complex technique.
2
Note that more facilities perform sulfur removal than perform sulfur recovery. Some refineries transfer their H2S-
containing amine offsite to another nearby refinery.
3
Shell and other companies license similar technologies. All are included here as “SCOT®-type.”
4
14 facilities use the Beavon-Stretford process for tail gas treating.

Caustic or water is often used in conjunction with, or instead of, amine solution to
remove sulfur, particularly for liquid petroleum fractions. These processes, however, are
generally not considered sulfur removal processes because either (1) the sulfur is not further
complexed from these solutions (i.e., is not removed from the solution), or (2) if removed, it
occurs in a sour water stripper which is in the domain of the facility's wastewater treatment
system. Such processes are considered to be liquid treating with caustic, which was discussed in
the Listing Background Document.

The dominant sulfur removal/complex train, amine scrubbing followed by Claus unit
followed by SCOT®-type tail gas treating, is discussed below. In addition, the second-most
popular tail gas system, the Beavon-Stretford system, is discussed. Finally, other processes
reported in the questionnaires are discussed.

Petroleum Refining Industry Study 127 August 1996

3.10.1.1 Amine Scrubbing

As shown in Table 3.10.1, amine scrubbing is used by most facilities, with 106 refineries
reporting this process in the questionnaire. A typical process flow diagram for an amine
scrubbing system is shown in Figure 3.10.1. The purpose of the unit is to remove H2S from
refinery fuel gas for economical downstream recovery. Fuel gas from the refinery is fed to a
countercurrent absorber with a 25 to 30 percent aqueous solution of amine such as
monoethanolamine (MEA), diethanolamine (DEA), or methyldiethanolamine (MDEA). The
H2S reacts with the amine solution to form a complex, “rich” amine. Typically, a refinery will
have several absorbers located throughout the refinery depending on the location of service.
These “rich” streams are combined and sent to a common location at the sulfur plant where the
H2S is stripped from the amine in the reverse reaction. The “lean” amine is recycled back to the
absorbers.

Figure 3.10.1. Amine Sulfur Removal Process Flow Diagram

3.10.1.2 Claus Unit

The H2S from the sulfur removal unit is most often recovered in a Claus system as
elemental sulfur. Table 3.10.1 shows that 101 refineries reported this process in the
questionnaire. A typical process flow diagram for a Claus unit is shown in Figure 3.10.2. In a
Claus unit, the H2S is partially combusted with air to form a mixture of SO2 and H2S. It then
passes through a reactor containing activated alumina catalyst to form sulfur by the following
endothermic reaction:

2 H2S + SO2 --> 3 S + 2 H2O

The reaction is typically conducted at atmospheric pressure. The resulting sulfur is condensed to
its molten state, drained to a storage pit, and reheated. The typical Claus unit consists of three
such reactor/condenser/reheaters to achieve an overall sulfur removal yield of 90 to 95 percent.

Petroleum Refining Industry Study 128 August 1996

At this point the tail gas can be (1) combusted and released to the atmosphere, or (2) sent to a
tail gas unit to achieve greater sulfur reduction.

Figure 3.10.2. Claus Sulfur Recovery Process Flow Diagram

3.10.1.3 SCOT® Tailgas Unit

The most common type of tail gas unit uses a hydrotreating reactor followed by amine
scrubbing to recover and recycle sulfur, in the form of H2S, to the Claus unit. Shell licenses this
technology as the Shell Claus Offgas Treating (SCOT®) unit; many other refineries reported
using similar designs licensed by other vendors. All can be represented by the generalized
process flow diagram shown in Figure 3.10.3.

Tail gas (containing H2S and SO2) is contacted with H2 and reduced in a hydrotreating
reactor to form H2S and H2O. The catalyst is typically cobalt/molybdenum on alumina. The gas
is then cooled in a water contractor. The water circulates in the column and requires periodic
purging due to impurity buildup; filters may be used to control levels of particulates or
impurities in the circulating water.

The H2S-containing gas enters an amine absorber which is typically in a system

segregated from the other refinery amine systems discussed above. The purpose of segregation
is two-fold: (1) the tail gas treater frequently uses a different amine than the rest of the plant,
such as MDEA or diisopropyl amine (DIPA), and (2) the tail gas is frequently cleaner than the
refinery fuel gas (in regard to contaminants) and segregation of the systems reduces maintenance
requirements for the SCOT® unit. Amines chosen for use in the tail gas system tend to be more
selective for H2S and are not affected by the high levels of CO2 in the offgas.

Petroleum Refining Industry Study 129 August 1996

 The “rich” amine generated from this step is desorbed in a stripper; the lean amine is
recirculated while the liberated H2S is sent to the Claus unit. Particulate filters are sometimes
used to remove contaminants from lean amine.

Figure 3.10.3. SCOT® Tail Gas Sulfur Removal Process Flow Diagram

3.10.1.4 Beavon-Stretford Tail Gas Unit

This system was reported to be used by 14 facilities. A hydrotreating reactor converts

SO2 in the offgas to H2S. The generated H2S is contacted with Stretford solution (a mixture of
vanadium salt, anthraquinone disulfonic acid (ADA), sodium carbonate, and sodium hydroxide)
in a liquid-gas absorber. The H2S reacts stepwise with sodium carbonate and ADA to produce
elemental sulfur, with vanadium serving as a catalyst. The solution proceeds to a tank where
oxygen is added to regenerate the reactants. One or more froth or slurry tanks are used to skim
the product sulfur from the solution, which is recirculated to the absorber.

3.10.1.5 Other Processes

Although the amine/Claus train followed by a SCOT® or Beavon-Stretford tail gas unit is
the dominant system used in the industry, it is not exclusive. Some refineries, mostly small
asphalt plants, do not require sulfur removal processes at all, while others use alternative
technologies. Each of these processes are used by less than five refineries, and most often are
used by only one or two facilities. In decreasing order of usage, these other processes are as
follows:

Petroleum Refining Industry Study 130 August 1996

Sulfur Removal/Recovery Processes

Sodium Hydrosulfide: Fuel gas containing H2S is contacted with sodium hydroxide in
an absorption column. The resulting liquid is product sodium hydrosulfide (NaHS).

Iron Chelate: Fuel gas containing H2S is contacted with iron chelate catalyst dissolved
in solution. H2S is converted to elemental sulfur, which is recovered.

Stretford: Similar to iron chelate, except Stretford solution is used instead of iron
chelate solution.

Ammonium Thiosulfate: In this process, H2S is contacted with air to form SO2. The
SO2 is contacted with ammonia in a series of absorption column to produce ammonium
thiosulfate for offsite sale. (Kirk-Othmer, 1983)

Hyperion: Fuel gas is contacted over a solid catalyst to form elemental sulfur. The
sulfur is collected and sold. The catalyst is comprised of iron and naphthoquinonsulfonic acid.

Sulfatreat: The Sulfatreat material is a black granular solid powder; the H2S forms a
chemical bond with the solid. When the bed reaches capacity, the Sulfatreat solids are removed
and replaced with fresh material. The sulfur is not recovered.

A few facilities report sour water stripping, which was not part of the scope of the
survey. The actual number of sour water strippers is likely to be much greater than reported in
the questionnaire.

Hysulf: This process is under development by Marathon Oil Company and was not
reported by any facilities in the questionnaire. Hydrogen sulfide is contacted with a liquid
quinone in an organic solvent such as n-methyl-2-pyrolidone (NMP), forming sulfur. The sulfur
is removed and the quinone reacted to its original state, producing hydrogen gas (The National
Environmental Journal, March/April 1995).

Tail Gas Processes

Caustic Scrubbing: An incinerator converts trace sulfur compounds in the offgas to

SO2. The gas is contacted with caustic which is sent to the wastewater treatment system.

Polyethylene Glycol: Offgas from the Claus unit is contacted with this solution to
generate an elemental sulfur product. Unlike the Beavon Stretford process, no hydrogenation
reactor is used to convert SO2 to H2S. (Kirk-Othmer, 1983)

Selectox: A hydrogenation reactor converts SO2 in the offgas to H2S. A solid catalyst in
a fixed bed reactor converts the H2S to elemental sulfur. The elemental sulfur is recovered and
sold. (Hydrocarbon Processing, April 1994).

Sulfite/Bisulfite Tail Gas Treating Unit: Following Claus reactors, an incinerator

converts trace sulfur compounds to SO2. The gas is contacted with sulfite solution in an

Petroleum Refining Industry Study 131 August 1996

absorber, where SO2 reacts with the sulfite to produce a bisulfite solution. The gas is then
emitted to the stack. The bisulfite is regenerated and liberated SO2 is sent to the Claus units for
recovery. (Kirk-Othmer, 1983)

3.10.2 Off-Specification Product from Sulfur Complex and H2S Removal Facilities

3.10.2.1 Description

Elemental sulfur is the most common product from sulfur complex and H2S removal
facilities, although a small number of facilities generate product sodium hydrosulfide or
ammonium thiosulfate, as discussed in Section 3.10.1.5. Like other refinery products, sulfur
must meet certain customer specifications such as color and impurity levels. The failure of the
refinery to meet these requirements causes the sulfur to be “off-spec.”

Stretford System

Although the Beavon-Stretford system is used by only 14 refineries, off-spec sulfur

generated from this process accounts for 2/3 of the refinery-wide 1992 generation of off-spec
sulfur. Sources of this volume are as follows:

• Product sulfur: Some refineries routinely dispose of their continuously generated

product sulfur rather than sell it. Presumably, these refineries have operational
difficulties making “on-spec” sulfur from the vanadium-catalyzed process. The small
number of refineries managing sulfur this way account for most of the quantity of off-
spec sulfur generated industry-wide. Other refineries sell all or most of their product
sulfur and only dispose of sulfur generated from spills, etc.

• Filtered solids from spent Stretford solution: As discussed further in Section

3.10.3, many refineries report that a portion of the circulating Stretford solution must
be purged to remove impurities in the system. After purging, some refineries filter out
the solids prior to further managing the spent solution.

• Turnaround sludge (sediment): Every few years, the process units are thoroughly
cleaned as preparation for maintenance. The principal source of this turnaround
sludge is the froth (slurry) tank.

• Miscellaneous sludges (sediments): Other solids build up in the system, including

tank sludges and process drain pit sludge. They are removed intermittently.

Every residual generated by the Stretford process contains elemental (product) sulfur
because sulfur is a reaction product. Most refineries designated the above materials as off-spec
product in their questionnaire response, and these residuals are included in statistics discussed
later in this Section.

Petroleum Refining Industry Study 132 August 1996

Claus System

Based on database responses, many Claus units generate off-spec sulfur at frequencies
ranging from 2 months to 2 years. Sources of such sulfur are spills, process upsets, turnarounds,
or maintenance operations. Some refineries generate off-spec sulfur more frequently; one
refinery reports that certain spots are drained daily to ensure proper operation.

Other Systems

The amine scrubbing and SCOT® units do not generate off-spec sulfur because they do
not generate product sulfur (their product is H2S, an intermediate for the Claus sulfur recovery
unit). Other systems generating elemental sulfur or product sulfur compounds can generate off-
spec sulfur for the same reasons described above for Claus and Stretford processes.

3.10.2.2 Generation and Management

Most off-spec sulfur from Claus units is solid with little water content. The off-spec
sulfur residuals described above from the Stretford process contain varying levels of solution
which would give the residual a solid, sludge, or slurry form. Some refineries report filtering
this material to generate off-spec sulfur with higher solids levels.

Based on the questionnaire responses, most refineries (regardless of process) reported

storing off-spec sulfur onsite in a drum, in a dumpster, or in a pile prior to its final destination.
In 1992, five facilities reported classifying this residual as RCRA hazardous (a total quantity of
2,551 MT were reported), however, the hazard waste code was generally not reported.3

Sixty facilities reported generating a total quantity of almost 9,650 MT of this residual in
1992, according to the 1992 RCRA §3007 Survey. As stated in Section 3.10.1, 123 facilities
reported sulfur complex/removal processes. The remaining 63 facilities either report never
generating this residual, or reported generation in years other than 1992 (due to intermittent
generation). There was no reason to expect that 1992 would not be a typical year with regard to
this residual's generation and management. Because most of the generation quantity is
concentrated at a small number of facilities using the Stretford process, however, future
operational changes at those sites could greatly impact the industry-wide residual generation
rate.

Residuals were assigned to be “off-spec sulfur” if they were assigned a residual

identification code of “off-spec product” and were generated from a process identified as a sulfur
removal or complex unit. These correspond to residual code 05 in Section VII.A of the
questionnaire and process code 15 in Section IV.C of the questionnaire. Table 3.10.2 provides a
description of the 1992 management practices, quantity generated, number of streams reported,
number of streams not reporting volumes (data requested was unavailable and facilities were not
required to generate it), total and average volumes.

3
These percentages do not match up directly with any one of the management scenarios because the number of
streams and the volume are a combination of several management scenarios (i.e., Subtitle C landfill, transfer to offsite
entity, etc.).

Petroleum Refining Industry Study 133 August 1996

 Table 3.10.2. Generation Statistics for Off-Spec Sulfur, 1992

# of Streams
# of w/ Unreported Total Volume Average
Final Management Streams Volume (MT) Volume (MT)
Disposal in offsite Subtitle D landfill 41 10 5,043.53 123.01
Disposal in offsite Subtitle C landfill 6 2 3,575.50 510.79
Disposal in onsite Subtitle C landfill 3 0 289.07 96.36
Disposal in onsite Subtitle D landfill 10 3 225.50 22.55
Other disposal offsite (anticipated to be
1 0 0.10 0.10
Subtitle C landfill)
Offsite incineration 1 0 0.70 0.70
Offsite land treatment 1 0 0.95 0.95
Other recovery onsite: sulfur plant 1 1 2.00 2.00
Transfer for use as an ingredient in
1 0 15.00 15.00
products placed on the land
Transfer to other offsite entity 1 2 487.80 487.80
Transfer with coke product or other
4 0 6.52 1.63
refinery product
TOTAL 70 21 9,646.57 137.8

3.10.2.3 Plausible Management

EPA believes that most of the plausible management practices for this residual were
reported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.10.2. No data were
available to the Agency suggesting any other management practices.

3.10.2.4 Characterization

Two sources of residual characterization were developed during the industry study:

• Table 3.10.3 summarizes the physical and chemical properties of off-spec sulfur as
reported in Section VII.A of the §3007 survey.

• Four record samples of off-spec sulfur were collected and analyzed by EPA. All of
these were collected from the Claus process. Sampling information is summarized in
Table 3.10.4.

The collected samples are expected to be representative of off-spec sulfur generated from
Claus units, the sulfur recovery process used by most refineries. They are not expected to
represent off-spec sulfur from the Stretford process because vanadium would be present in off-
spec sulfur from this process at levels higher than those found in off-spec sulfur from Claus
units. Concentrations of other contaminants may also differ.

Petroleum Refining Industry Study 134 August 1996

 All four record samples were analyzed for total and TCLP levels of volatiles,
semivolatiles and metals. None of the samples were found to exhibit a hazardous waste
characteristic. A summary of the analytical results is presented in Table 3.10.5. Only
constituents detected in at least one sample are shown in this table.

3.10.2.5 Source Reduction

During EPA's site visit, one facility was observed to generate “off-spec” sulfur product
daily. Portions of the sulfur plant are being replaced with a newer design. As a result, waste
sulfur residual from equipment “low points” will no longer be generated.

Petroleum Refining Industry Study 135 August 1996

 Table 3.10.3. Off-Specification Sulfur: Physical Properties

# of
# of Unreported
Properties Values Values1 10th % 50th % 90th %
pH 45 62 2.80 5.50 9.00
Reactive CN, ppm 20 87 0.00 0.25 20.85
Reactive S, ppm 35 72 0.00 1.23 92.00
Flash Point, C 30 77 60.00 93.33 187.78
Oil and Grease, vol% 28 78 0.00 0.54 13.10
Total Organic Carbon, vol% 12 95 0.00 0.00 1.00
Vapor Pressure, mm Hg 9 98 0.00 0.10 11.00
Vapor Pressure Temperature, C 9 98 20.00 140.00 284.00
Specific Gravity 35 72 0.80 1.36 2.07
Specific Gravity Temperature, C 11 96 4.00 15.60 21.10
BTU Content, BTU/lb 15 92 0.00 4,606.00 4,606.00
Aqueous Liquid, % 46 61 0.00 0.00 5.00
Organic Liquid, % 44 63 0.00 0.00 100.00
Solid, % 82 25 60.00 100.00 100.00
Particle >60 mm, % 28 79 0.00 80.00 100.00
Particle 1-60 mm, % 24 83 0.00 22.50 100.00
Particle 100 µm-1 mm, % 23 84 0.00 0.00 100.00
Particle 10-100 µm, % 14 93 0.00 0.00 0.00
Particle <10 µm, % 14 93 0.00 0.00 0.00
Median Particle Diameter, microns 7 100 0.00 0.00 200.00
1
Facilities were not required to do additional testing, therefore information provided was based on previously collected
data or engineering judgment.

Table 3.10.4. Off-Specification Sulfur Record Sampling Locations

Sample number Facility Description

R1-SP-01 Marathon, Indianapolis, IN Claus unit: contents of product tank destined for
disposal
R2-SP-01 Shell, Wood River, IL Claus unit: generated daily from unit “low spots”
R7B-SP-01 BP, Belle Chase, LA Claus unit: from cleaning and turnaround of
product tank
R23-SP-01 Chevron, Salt Lake City, Claus unit: from loading spills, connection
UT leaks, and sumps

Petroleum Refining Industry Study 136 August 1996

 Table 3.10.5. Residual Characterization Data for Off-Specification Sulfur
Petroleum Refining Industry Study

Volatile Organics - Method 8260A µg/kg

CAS No. R1-SP-01 R2-SP-01 R7B-SP-01 R23-SP-01 Average Conc Maximum Conc Comments
Acetone 67641 < 25 < 25 < 5 2,000 514 2,000
TCLP Volatile Organics - Methods 1311 and 8260A µg/L
CAS No. R1-SP-01 R2-SP-01 R7B-SP-01 R23-SP-01 Average Conc Maximum Conc Comments
Acetone 67641 B 2,300 < 50 < 50 B 160 640 2,300
Semivolatile Organics - Method 8270B µg/kg
CAS No. R1-SP-01 R2-SP-01 R7B-SP-01 R23-SP-01 Average Conc Maximum Conc Comments
Bis(2-ethylhexyl) phthalate 117817 J 75 < 165 880 460 395 880
Benzo(a)pyrene 50328 < 165 < 165 < 165 J 110 110 110 1
Benzo(g,h,i) perylene 191242 < 165 < 165 < 165 J 130 130 130 1
Chrysene 218019 < 165 < 165 < 165 J 270 191 270
Di-n-butyl phthalate 84742 < 165 < 165 J 140 < 165 140 140 1
Di-n-octyl phthalate 117840 < 165 < 165 J 180 < 165 169 180
Pyridine 110861 < 165 J 160 < 165 < 165 160 160 1
Fluorene 86737 < 165 < 165 J 280 < 165 194 280
2-Methylchrysene 3351324 < 330 < 330 < 330 J 230 230 230 1
137

1-Methylnaphthalene 90120 < 330 < 330 680 < 330 418 680
2-Methylnaphthalene 91576 < 165 < 165 760 < 165 314 760
Phenanthrene 85018 < 165 < 165 J 140 < 165 140 140 1
TCLP Semivolatile Organics - Methods 1311 and 8270B µg/L
CAS No. R1-SP-01 R2-SP-01 R7B-SP-01 R23-SP-01 Average Conc Maximum Conc Comments
Bis(2-ethylhexyl) phthalate 117817 < 50 J 11 < 50 < 50 11 11 1
August 1996
 Table 3.10.5. Residual Characterization Data for Off-Specification Sulfur (continued)
Petroleum Refining Industry Study

Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg
CAS No. R1-SP-01 R2-SP-01 R7B-SP-01 R23-SP-01 Average Conc Maximum Conc Comments
Aluminum 7429905 < 20 < 20 780 350 293 780
Barium 7440393 < 20 < 20 90.0 < 20 37.5 90.0
Calcium 7440702 < 500 < 500 3,400 < 500 1,225 3,400
Chromium 7440473 2.70 < 1.00 62.0 4.70 17.6 62.0
Copper 7440508 < 2.50 < 2.50 68.0 8.40 20.4 68.0
Iron 7439896 62.0 610 22,000 710 5,846 22,000
Lead 7439921 < 0.30 0.83 4.30 3.40 2.21 4.30
Manganese 7439965 < 1.50 < 1.50 91.0 3.20 24.3 91.0
Molybdenum 7439987 < 6.50 < 6.50 15.0 < 6.50 8.63 15.0
Nickel 7440020 < 4.00 < 4.00 21.0 < 4.00 8.25 21.0
Zinc 7440666 < 2.00 < 2.00 140 34.0 44.5 140
TCLP Metals - Methods 1311, 6010, 7060, 7421, 7470, 7471, and 7841 mg/L
CAS No. R1-SP-01 R2-SP-01 R7B-SP-01 R23-SP-01 Average Conc Maximum Conc Comments
Aluminum 7429905 < 1.00 < 1.00 5.90 < 1.00 2.23 5.90
Calcium 7440702 < 25.0 < 25.0 62.0 < 25.0 34.3 62.0
138

Chromium 7440473 < 0.05 < 0.05 0.43 < 0.05 0.15 0.43
Iron 7439896 < 0.50 16.0 44.0 1.50 15.5 44.0
Manganese 7439965 < 0.08 0.26 0.77 < 0.08 0.30 0.77
Zinc 7440666 0.31 < 0.10 B 2.90 B 0.87 1.05 2.90

Comments:

1 Detection limits greater than the highest detected concentration are excluded from the calculations.

Notes:

B Analyte also detected in the associated method blank.

J Compound's concentration is estimated. Mass spectral data indicate the presence of a compound that meets the identification criteria for which the result is less than the laboratory detection limit, but greater than
zero.
August 1996
3.10.3 Off-Specification Treating Solution from Sulfur Complex and H2S Removal
Facilities

3.10.3.1 Description

All treating solutions used in refinery sulfur removal systems are regenerative, meaning
the solution is used over and over in a closed system (for example, amines use multiple
absorption/desorption cycles, while Stretford solution undergoes multiple reversible reactions).
In the following instances the treating solution becomes “off-spec” and cannot be reused:

• Amine systems. At most refineries, amine continuously leaves the closed system
through entrainment in overhead gas, leaks, and other routes. The amine is collected
in various locations such as sumps and either returned to the process or discharged to
the refinery's wastewater treatment (possibly due to purity constraints).

At some refineries, the circulating amine must be replaced in whole or in part due to
contamination or process upset. Rarely, a refinery may change from one amine to
another and completely remove the existing amine from the system prior to
introducing the new solution.

• Stretford systems. Many refineries report that a portion of the circulating Stretford
solution must be purged to remove impurities in the system. After purging, some
refineries filter out the solids prior to further managing the spent solution. Stretford
systems are used at a smaller number (15) of facilities. Unlike amine systems,
Stretford solution is generally used only in tail gas treating.

During operation, the treating solution alternatively becomes “rich” (i.e., containing H2S) and
“lean” (i.e., containing low levels or no H2S). In all observed cases, a refinery will generate off-
spec treating solution when it is “lean.”

Approximately 800 MT of off-spec treating solution generated in 1992 was identified by

6 facilities as displaying hazardous characteristics.4 The facilities designated the wastes with
hazardous waste codes D002 (corrosive), D003 (reactive), D010 (TC selenium), and D018 (TC
benzene). No single hazardous waste code was reported by more than one facility.

3.10.3.2 Generation and Management

Spent Amine Solution

As discussed in Section 3.10.1, the amine sulfur removal process is the dominant sulfur
removal process for gas streams used in the industry. Amine solutions are aqueous and are
typically stored in covered sumps, tanks, etc. In the 1992 questionnaire, most facilities did not

4
These percentages do not match up directly with any one of the management scenarios because the number of
streams and the volume are a combination of several management scenarios (i.e., managed in WWTP, Subtitle C
landfill, transfer for reclamation, etc.).

Petroleum Refining Industry Study 139 August 1996

report how their off-spec treating solution is stored prior to final management; those that did
indicated storage in a tank (most common), storage in a container, or storage in a sump.

Forty-four facilities reported generating a total quantity of 4,627 MT of spent amine in

1992, according to the 1992 RCRA §3007 Questionnaire. Residuals were assigned to be “off-
spec treating solution (spent amine)” if they were assigned a residual identification code of
“treating solution” and were generated from a sulfur complex or H2S removal process. These
correspond to residual codes of “04-B” or “04-C” in Section VII.A and process code “15-A” and
“15-D” in Section IV-1.C of the questionnaire. Based on the results of the questionnaire,
approximately 123 facilities employ some type of sulfur removal system (most of these systems
employ treating solution). Many facilities generate this residual on an intermittent basis, or only
during unusual circumstances such as upsets. Therefore, not all of these 123 facilities are
expected to generate off-spec treating solution.

Table 3.10.6 provides a description of the 1992 management practices, quantity

generated, number of streams reported, number of streams not reporting volumes (data requested
was unavailable and facilities were not required to generate it), total and average volumes.

Table 3.10.6. Generation Statistics for Spent Amine for H2S Removal, 1992

# of Streams
# of w/ Unreported Total Volume Average
Final Management Streams Volume (MT) Volume (MT)
Discharge to onsite wastewater treatment
40 16 1,224.2 30.6
facility
Discharge to offsite privately-owned WWT
1 0 152 152
facility
Disposal in onsite or offsite underground
4 0 673.3 168.3
injection
Disposal in offsite Subtitle D landfill 1 0 200 200
Disposal in offsite Subtitle C landfill 1 0 39 39
Disposal in onsite surface impoundment 3 0 0.8 0.3
Neutralization 1 0 0.2 0.2
Onsite boiler 1 0 9.1 9.1
Other recovery onsite: recycle to the
3 4 12.8 4.27
process
Recovery onsite in catalytic cracker 1 0 1,150 1,150
Transfer to other offsite entity/amine
3 0 166 55.3
reclaimer
TOTAL 59 20 4,627.4 78.4

Petroleum Refining Industry Study 140 August 1996

Spent Stretford Solution

The second most frequently used process is the Stretford sulfur removal/complex
process. Stretford solutions are aqueous and are typically stored in covered sumps, tanks, etc.

Twelve facilities reported generating a total quantity of 19,254.5 MT of spent Stretford

solution in 1992, according to the 1992 RCRA §3007 Questionnaire. Residuals were assigned to
be “spent Stretford solution” if they were assigned a residual identification code of “treating
solution” and were generated from a sulfur complex or H2S removal process. These correspond
to residual codes of “04-B” or “04-C” in Section VII.A and process code “15-B” and “15-E” in
Section IV-1.C of the questionnaire.

Table 3.10.7 provides a description of the 1992 management practices, quantity

generated, number of streams reported, number of streams not reporting volumes (data requested
was unavailable and facilities were not required to generate it), total and average volumes.

Table 3.10.7. Generation Statistics for Stretford Solution for H2S Removal, 1992

# of Streams
# of w/ Unreported Total Average
Final Management Streams Volume Volume (MT) Volume (MT)
Discharge to onsite wastewater treatment
4 2 4,830 1,207.5
facility
Discharge to offsite privately-owned
3 0 6,111.5 2,037.2
WWT facility
Disposal in onsite Subtitle D landfill 1 0 711 711
Transfer metal catalyst for reclamation or
2 0 5,127 2563.5
regeneration
Transfer of acid or caustic for
3 0 2,475 825
reclamation, regeneration, or recovery
TOTAL 13 2 19,254.5 1,481

3.10.3.3 Plausible Management

Spent Amine

EPA believes that most of the plausible management practices for this residual were
reported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.10.6. The Agency
gathered information suggesting other management practices have been used in other years
including: “onsite Subtitle D landfill” (200 MT) and “offsite incineration” (120 MT). These
non-1992 practices are generally comparable to practices reported in 1992 (i.e., off-site Subtitle
D landfilling and on-site boiler, respectively).

Petroleum Refining Industry Study 141 August 1996

Spent Stretford Solution

EPA believes that most of the plausible management practices for this residual were
reported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.10.7. Even though
spent Stretford solution has different properties, it is possible that the solution could be managed
as the spent amine in Table 3.10.6.

3.10.3.4 Characterization

Two sources of residual characterization were developed during the industry study:

• Tables 3.10.8 and 3.10.9 summarize the physical properties of spent amine and spent
Stretford solution as reported in Section VII.A of the §3007 survey.

• Four record samples of spent amine solution were collected and analyzed by EPA.
The sample locations are summarized in Table 3.10.10.

• No samples of spent Stretford solution were available from the randomly selected
facilities during record sampling.

Table 3.10.8. Spent Amine: Physical Properties

# of
# of Unreported
Properties Values Values1 10th % 50th % 90th %
pH 36 67 4.5 9.1 11.8
Reactive CN, ppm 5 98 0 5 12
Reactive S, ppm 10 93 1.41 280 7,500
Flash Point, C 16 87 -10 90.6 168.9
Oil and Grease, vol% 11 92 0 0.1 1
Total Organic Carbon, vol% 16 87 0 10 15
Vapor Pressure, mm Hg 12 91 1 30 300
Vapor Pressure Temperature, C 13 90 15 25 50
Viscosity, lb/ft-sec 10 93 0 0 10
Specific Gravity 34 69 1 1.1 1.1
Specific Gravity Temperature, C 16 87 15 17.5 38
Aqueous Liquid, % 61 42 0 100 100
Organic Liquid, % 43 60 0 0 100
Solid, % 36 67 0 0 20

1
Facilities were not required to do additional testing, therefore information provided was based on previously collected
data or engineering judgment.

Petroleum Refining Industry Study 142 August 1996

 Table 3.10.9. Spent Stretford Solution: Physical Properties

# of
# of Unreported
Properties Values Values1 10th % 50th % 90th %
pH 10 12 8.3 8.8 9.7
Reactive CN, ppm 2 19 1 1.35 1.7
Reactive S, ppm 2 19 0.1 3,190 6,380
Oil and Grease, vol% 1 20 1 1 1
Total Organic Carbon, vol% 4 17 0 0 1
Vapor Pressure, mm Hg 3 18 1.5 10 20
Specific Gravity 8 14 1 1.1 1.5
COD, mg/L 4 17 100 6,930 6,930
Aqueous Liquid, % 9 13 0 90 100
Organic Liquid, % 3 19 0 0 0
Solid, % 10 12 0.5 10 100

1
Facilities were not required to do additional testing, therefore information provided was based on previously collected
data or engineering judgment.

Table 3.10.10. Off-Specification Treating Solution Record Sampling Locations

Sample Number Facility Description

R11-SA-01 ARCO, Ferndale, WA Refinery DEA system: circulating amine
R13-SA-01 Shell, Deer Park, TX Refinery DEA system: circulating amine
R14-SA-01 BP, Toledo, OH Refinery DEA system: from sump
collecting knock-out pot liquid, etc, prior to
its exiting the system
R15-SA-01 Total, Ardmore, OK Refinery MDEA system: circulating amine

All of the samples were taken from refinery amine systems and are believed to represent
the various types of spent amine generated by refineries. No samples from the tail gas system
units were collected. Tail gas residuals are expected to be cleaner because the feeds are cleaner.
Therefore, the tail gas treating residuals are expected to exhibit levels of contaminants no higher
than those found in the sampled residuals. No samples of Stretford solution were taken.
Stretford systems were not used by the facilities randomly selected by the Agency for record
sampling. Samples of Stretford solution are expected to exhibit higher levels of vanadium than
amine solution because vanadium is present in new Stretford solution; levels of some organic
contaminants may be lower because most refineries use their Stretford system to treat low-
organic Claus unit tail gas.

Several of the samples were taken from the process line (i.e., at the time of sampling, the
refinery had no immediate plans to remove the sampled treating solution from the system).

Petroleum Refining Industry Study 143 August 1996

However, these refineries indicated they do remove all or part of their circulating amine on an
infrequent basis due to process upset or excessive contaminant levels. The sampled amine is
expected to have contaminant concentrations at least as high as when the circulating amine is
removed from the system. Physical properties such as pH and flash point are expected to be
similar as well.

All four samples were analyzed for total and TCLP levels of volatiles, semivolatiles, and
metals, pH, total amines, and ignitability. Two samples were also analyzed for reactive sulfides.
One sample exhibited the characteristic of ignitability. A summary of the results is presented in
Table 3.10.11. Only constituents detected in at least one sample are shown in this table.

3.10.3.5 Source Reduction

Source reduction of amine involves modifying the process. During the site visits,
information was gathered that several facilities capture the amine for recycling. Two facilities
replaced the cloth filter at the sulfur recovery unit with an etched metal mechanical filter. The
new filter requires less maintenance, and also eliminates amine discharges to the wastewater
treatment plant due to filter change-outs. Another two facilities have installed sumps at the
sulfur complex. The sumps capture amine that is drained from the filters during bag change-outs
and recycle it to the amine system. Without the sumps, the amine drained from the filters is
discharged to the wastewater treatment plant.

Reference Waste Minimization/Management Methods

Stewart, E.J. and Lanning, R.A. “Reduce Amine Plant Process modification.
Solvent Losses, Part 2.” Hydrocarbon Processing. June,
1994.
”Liquid Catalyst Efficiently Removes H2S From Liquid Lower catalyst quantities needed to remove H2S in the
Sulfur.” Oil & Gas Journal. July 17, 1989. sulfur degassing process.
Stewart, E.J. and Lanning, R.A. “Reduce Amine Plant Process modification.
Solvent Losses, Part 1.” Hydrocarbon Processing. May,
1994.

Petroleum Refining Industry Study 144 August 1996

 Table 3.10.11. Characterization Data for Off-Specification Treating Solution from Sulfur Complex and H2S Removal
Petroleum Refining Industry Study

Volatile Organics - Method 8260A µg/L

CAS No. R11-SA-01 R13-SA-01 R14-SA-01 R15-SA-01 Average Conc Maximum Conc Comments
Acetone 67641 < 25 < 50 < 25 10 10 10 1
Benzene 71432 < 25 < 50 88 < 5 42 88
Toluene 108883 < 25 < 50 220 < 5 75 220
o-Xylene 95476 < 25 < 50 J 24 < 5 15 24 1
m,p-Xylenes 108383 / 106423 < 25 < 50 69 < 5 37 69
Naphthalene 91203 < 25 < 50 J 32 < 5 19 32 1
Semivolatile Organics - Method 8270B µg/L
CAS No. R11-SA-01 R13-SA-01 R14-SA-01 R15-SA-01 Average Conc Maximum Conc Comments
Acenaphthene 83329 < 50 < 545 180 < 575 115 180 1
Anthracene 120127 J 18 < 545 250 < 575 134 250 1
Aniline 62553 < 50 J 540 < 50 < 575 213 540 1
Benz(a)anthracene 56553 < 50 < 545 J 34 < 575 34 34 1
Bis(2-ethylhexyl)phthalate 117817 JB 26 < 545 J 17 < 575 22 26 1
Carbazole 86748 J 80 < 1,090 < 100 < 1,150 80 80 1
Chrysene 218019 < 50 < 545 J 71 < 575 61 71 1
Dibenzofuran 132649 < 50 < 545 160 < 575 105 160 1
2,4-Dimethylphenol 105679 110 < 545 J 86 < 575 98 110 1
145

Fluoranthene 206440 J 17 < 545 < 50 < 575 17 17 1

Fluorene 86737 < 50 < 545 1,100 < 575 568 1,100
2-Methylchrysene 3351324 < 100 < 1,090 J 84 < 1,150 84 84 1
1-Methylnaphthalene 90120 < 100 < 1,090 2,500 < 1,150 1,210 2,500
2-Methylnaphthalene 91576 < 50 < 545 3,400 < 575 1,143 3,400
2-Methylphenol 95487 360 < 545 210 < 575 285 360 1
3/4-Methylphenol NA 1,200 < 545 1,000 < 575 830 1,200
Phenanthrene J 50 < 545 3,000 < 575 1,043 3,000
Phenol 108952 4,400 < 545 3,100 < 575 2,155 4,400
Pyrene J 25 < 545 430 < 575 228 430 1
1-Naphthylamine 134327 < 50 < 545 < 50 J 230 110 230 1
Naphthalene 91203 < 50 < 545 150 < 575 100 150 1
August 1996
 Table 3.10.11. Characterization Data for Off-Specification Treating Solution from Sulfur Complex and H2S Removal
Petroleum Refining Industry Study

(continued)

Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/L
CAS No. R11-SA-01 R13-SA-01 R14-SA-01 R15-SA-01 Average Conc Maximum Conc Comments
Aluminum 7429905 0.39 < 0.10 < 0.10 < 0.10 0.17 0.39
Antimony 7440360 0.81 < 0.03 < 0.03 0.62 0.37 0.81
Cadmium 7440439 0.035 < 0.003 < 0.003 0.025 0.016 0.035
Chromium 7440473 0.26 0.99 0.021 0.031 0.326 0.990
Cobalt 7440484 0.11 < 0.025 < 0.025 0.099 0.065 0.110
Copper 7440508 < 0.013 < 0.013 0.034 < 0.013 0.018 0.034
Iron 7439896 39.0 14.0 1.10 0.11 13.6 39.0
Manganese 7439965 0.31 2.30 0.043 < 0.008 0.67 2.30
Potassium 7440097 21.0 < 2.50 < 2.50 22.0 12.0 22.0
Selenium 7782492 0.031 0.61 0.038 0.99 0.42 0.99
Sodium 7440235 8.40 < 2.50 < 2.50 2,300 578 2,300
Zinc 7440666 < 0.01 < 0.01 0.039 < 0.01 0.017 0.039
Miscellaneous Characterization
R11-SA-01 R13-SA-01 R14-SA-01 R15-SA-01 Average Conc Maximum Conc Comments
Ignitability (oF) > 211 NA > 210 90 NA NA
Corrosivity (pH units) 10 10 8.9 11.5 NA NA
146

Reactivity - Total ReleasableH2S (mg/L) < 20 NA 48 NA NA NA

Amines - Methyldiethanolamine (mg/L) ND ND ND 36,000 36,000 36,000
Amines - Ethanolamine (mg/L) 4,400 4,500 ND ND 4,450 4,500
Amines - Diethanolamine (mg/L) 330,000 280,000 41,300 ND 217,100 330,000

Comments:

1 Detection limits greater than the highest detected concentration are excluded from the calculations.
TCLP was not performed because these were liquid samples

Notes:

B Analyte also detected in the associated method blank.

J Compound's concentration is estimated. Mass spectral data indicate the presence of a compound that meets the identification criteria for which the result is less than the laboratory detection limit, but greater than
zero.
ND Not Detected.
NA Not Applicable.
August 1996
3.11 CLAY FILTERING

Clay belongs to a broad class of materials designed to remove impurities via adsorption.
Examples of clay include Fullers earth, natural clay, and acid treated clay. However, similar
materials such as bauxite are also available and used to impart similar qualities to the product.
In addition, materials such as sand, salt, molecular sieve, and activated carbon are used for
removing impurities by adsorption or other physical mechanisms. All solid materials discussed
in Section 3.11.1 are termed as “solid sorbents” for the purposes of defining this residual
category.

3.11.1 Process Description

Clay or other adsorbents are used to remove impurities from many hydrocarbon streams.
Some of these applications are associated with isomerization, extraction, alkylation, and lube oil
processing; such processes are discussed in the respective sections of this document. Other solid
media remove impurities from amine solutions used in hydrogen sulfide removal systems; such
media were discussed in the Listing Background Document. Solid media used in all other
refinery processes are summarized and discussed in this section. The principal applications are
described below.

Kerosene Clay Filtering: Clay treatment removes diolefins, asphaltic materials, resins,
and acids; this improves the color of the product and removes gum-forming impurities (Speight,
1991). The RCRA §3007 Survey indicates that approximately 90 facilities use this process;
some facilities have multiple treaters or treat different streams, so that an estimated 150
processes exist. Most clay treatment is conducted as a fixed bed. A typical clay volume is 2,000
ft3, distributed in 1 or more vessels. Alternatively to the fixed bed process, the clay can be
mixed with the hydrocarbon and filtered in a belt press. In addition to kerosene, some facilities
identify filtering furnace oils through clay and generating spent clay in a similar manner.

Catalyst Support in Merox and Minalk Systems: The Merox and Minalk caustic
treatment systems convert mercaptans to disulfides using oxygen and an organometallic catalyst
in an alkaline environment. Depending on the process configuration, the disulfides can remain
in the hydrocarbon product (a “sweetening” process) or the disulfides can be removed by settling
(an “extractive” process). These treatment processes are commonly applied to gasoline, but
refinery streams ranging from propane to diesel undergo this treatment.

The catalyst can either be dissolved in the caustic or can be supported on a fixed bed.
Either activated carbon, coal, or charcoal are typically used as support material for solid
supported catalyst (the hydrocarbon passes over the catalyst, where reaction occurs). These
materials provide contact area for reaction when the catalyst is dissolved in the caustic. The
RCRA §3007 survey indicates that approximately 25 facilities (using 40 processes) reported
generating spent carbon, coal, or charcoal from these processes; additional facilities likely
generate this residual but did not report generation in the questionnaire because the residual is
typically generated infrequently.

Drying: Water is removed from many hydrocarbon streams ranging from diesel fuel to
propane. Water must be removed for reasons including: (1) product specifications (e.g., jet fuel

Petroleum Refining Industry Study 147 August 1996

has low tolerances for water content), and (2) reactor feed preparation (e.g., precious metal
catalysts are often poisoned by water). Salt and sand are commonly used for the first
application, while molecular sieve is commonly used for the second application.

When hydrocarbon is passed through a fixed bed of sand, the moisture collects on the
sand particles and eventually settles to the bottom of the vessel, where the water is removed. In
a salt drier, water in the stream dissolves salt (e.g., sodium chloride) which then collects in the
vessel bottom and is periodically removed. As a result, the vessel requires periodic topping with
solid salt.

Salt and sand treaters can be found throughout the refinery to treat hydrocarbons ranging
from diesel to propane. They are commonly found following aqueous treatments such as caustic
washing, water washing, or Merox caustic treatment. In these treatments, the hydrocarbon is
contacted with the aqueous stream; the hydrocarbon then passes through salt or sand to remove
residual moisture. The RCRA §3007 questionnaire indicates that approximately 60 facilities
(using 150 processes) reported generating spent salt or sand from these processes; additional
facilities likely generate this residual but did not report generation in the questionnaire because it
was not generated in 1992.

Molecular sieves are most commonly used to selectively adsorb water and sulfur
compounds from light hydrocarbon fractions such as propane and propylene. The hydrocarbon
passes through a fixed bed of molecular sieve. After the bed is saturated, water is desorbed by
passing heated fuel gas over the bed to release the adsorbed water and sulfur compounds into the
regeneration gas stream, which is commonly sent to a flare stack. Molecular sieves are often
used for drying feed to the isomerization unit and HF acid alkylation unit, applications that are
discussed in Sections 3.4 and 3.5, respectively, of this document. Other applications include
drying propane or propylene prior to entering the Dimersol unit, drying naphtha entering the
reformer, and feed preparation for other reaction units. Molecular sieves are also used to dry
light-end product streams from the hydrocracker, catalytic reformer, and light-ends recovery
unit. Less common uses also exist for molecular sieves including the separation of light-end
fractions such as methanol, butane, and butylene. In total, the RCRA §3007 questionnaire
indicates that approximately 70 facilities (using 150 processes) reported generating spent
molecular sieve; this includes the applications of HF acid alkylation and isomerization that are
discussed elsewhere in this document, but excludes additional facilities that are likely generate
this residual but did not report 1992 generation in the questionnaire.

Sulfur and Chloride Guards in Catalytic Reforming: As discussed in the Listing

Background Document, catalytic reforming units require a platinum catalyst; this catalyst is
readily poisoned by sulfur compounds. To prolong catalyst life, many refineries install sulfur
traps to remove sulfur compounds prior to the reforming catalyst bed. This material can consist
of granular or pelletized metal oxides, such as copper or magnesium. These materials (1)
remove H2S, (2) convert mercaptans to H2S and organic sulfides, and (3) remove generated H2S.
The material can be desorbed, reactivated, and reused (Perry's, 1950). Alumina also is used to
treat light naphtha prior to isomerization (which also uses precious metal catalyst). The RCRA
§3007 questionnaire indicates that approximately 20 facilities reported generating spent sulfur
guards from 35 applications, most often as guards for reforming and isomerization reactors.

Petroleum Refining Industry Study 148 August 1996

Additional facilities may employ sulfur guards but did not report generation in the questionnaire
because the residual is typically generated infrequently.

Alumina beds may be used to remove chlorides from the hydrogen produced from the
reforming process. The hydrogen is then used throughout the refinery. The alumina bed is
expected to last for 24-30 months prior to chloride breakthrough, when replacement of the
alumina is required. Reformate from the reformer may also be passed through alumina to
remove chloride. The RCRA §3007 questionnaire indicates that approximately 15 facilities
reported generating spent chloride guards from 25 applications, most often in the reforming
process.

Propane Treating by Alumina: An activated alumina bed is used to de-fluorinate

propane generated from a propane stripper. The propane then is dried in a sand tower and a
drier which also contains alumina. Both the defluorinator and drier periodically generate spent
alumina.

Particulate Filters: Entrained solids can be removed by in-line cartridge filters. These
cartridges are commonly used for finishing kerosene, diesel fuel, etc., prior to sale.
Approximately 10 facilities reported generating spent cartridges from 20 applications, according
to the questionnaire results.

In most of the applications discussed above, the use of solid media such as clay, sand,
etc. are not the only options refineries have in imparting the desired properties on a product. For
example, drying can be conducted by simple distillation. Hydrotreating and caustic treating are
common alternatives to the clay treatment of jet fuel by removing undesirable contaminants
from the kerosene/jet fuel fraction. And, as discussed above, the Merox process can be
conducted with or without solid supported catalyst.

3.11.2 Treating Clay from Clay Filtering

3.11.2.1 Description

Generated at many places in the refinery, spent solid sorbents have liquid contents
ranging from very low (e.g., for molecular sieves treating light hydrocarbons) to oil-saturated
material (e.g., for clay used for treating kerosene). The substrate is either inorganic (such as
alumina, zeolite, or clay) or organic (such as activated carbon). Most applications are fixed bed,
where the material is charged to vessels and the hydrocarbon passed through the fixed bed of
solid sorption media. The fixed bed can remain in service for a period of time ranging from
several months to 10 years, depending on the application. At the end of service, the vessel is
opened, the “spent” material removed, and the vessel recharged.

Petroleum Refining Industry Study 149 August 1996

3.11.2.2 Generation and Management

The spent clay is vacuumed or gravity dumped from the vessels into piles or into
containers such as drums and roll-off bins. The RCRA §3007 questionnaire and site visits
indicate that very few other interim storage methods are used.

In 1992, approximately 30 facilities reported that 1,700 MT of this residual was managed
as hazardous. The most commonly designated waste codes were D001 (ignitable), D008 (TC
lead), and D018 (TC benzene).5 This is consistent with how the residual was reported to be
managed in other years.

One hundred facilities reported generating a total quantity of approximately 9,000 MT of

this residual in 1992, according to the 1992 RCRA §3007 Questionnaire. There was no reason
to expect that 1992 would not be a typical year with regard to this residual's generation and
management. Residuals were assigned to be “treating clay from clay filtering” if they were
assigned a residual identification code of “spent sorbent” (residual coded “07”) and were not
generated from a process identified as an alkylation, isomerization, extraction, sulfur removal, or
lube oil unit (process codes “09,” “10,” “12,” “15,” and “17,” respectively) (sorbents from these
units are discussed elsewhere in this document or in the Listing Background Document). The
frequency of generation is highly variable as discussed in Section 3.11.1. Table 3.11.1 provides
a description of the 1992 management practices, quantity generated, number of streams reported,
number of streams not reporting volumes (data requested was unavailable and facilities were not
required to generate it), total and average volumes.

The wide array of management methods reflect the numerous applications of sorbents.
For example, disposed salt from salt driers can be managed in onsite wastewater treatment
plants, cement plants can accept spent alumina, and catalyst reclaimers can accept sulfur sorbers
having recoverable metals. The large quantity disposed, however, demonstrates that for most
applications and refineries the spent clay is seen as a low value solid waste.

3.11.2.3 Plausible Management

EPA believes that most of the plausible management practices for this residual were
reported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.11.1. The Agency
gathered information suggesting other management practices have been used in other years
including: “other recycling, reclamation, or reuse: unknown” (1 MT), “other recycling,
reclamation, or reuse: onsite road material” (13.5 MT) and “reuse as a replacement catalyst for
another unit” (5 MT). These non-1992 very small management practices are comparable to the
recycling practices reported in 1992.

5
These percentages do not match up directly with any one of the management scenarios because the number of
streams and the volume are a combination of several management scenarios (i.e., managed in WWTP, Subtitle C
landfill, transfer as a fuel, etc.).

Petroleum Refining Industry Study 150 August 1996

 Table 3.11.1. Generation Statistics for Treating Clay from Clay Filtering, 1992

# of # of Streams w/ Total Average

Final Management Streams Unreported Volume Volume (MT) Volume (MT)
Discharge to onsite wastewater 14 3 514 36.7
treatment facility
Disposal in offsite Subtitle D landfill 91 0 3,642.1 40
Disposal in offsite Subtitle C landfill 42 0 1,735 41.3
Disposal in onsite Subtitle C landfill 1 1 52.4 52.4
Disposal in onsite Subtitle D landfill 15 0 1,031.9 68.8
Evaporation 1 0 7.9 7.9
Offsite incineration 7 0 42.1 6
Offsite land treatment 9 0 198.3 22
Onsite land treatment 16 0 923.1 57.7
Other disposal onsite: 5 0 57.4 11.5
bioremediation, fill material, or onsite
berms
Other recovery onsite: recycle to 1 0 20.1 20.1
process
Other recycling, reclamation, or 5 0 161.4 32.3
reuse: cement plant
Offsite filter recycling 2 0 38 19
Storage in pile 2 0 128 64
Recovery in coker 1 0 20 20
Transfer for direct use as a fuel or to 1 0 95 95
make a fuel
Transfer for use as an ingredient in 6 0 175.8 29.3
products placed on the land
Transfer metal catalyst for 10 0 89.4 8.9
reclamation or regeneration
Transfer to other offsite entity/carbon 2 0 53.6 26.8
regeneration
Transfer with coke product or other 1 0 4.5 4.5
refinery product
TOTAL 232 4 8,990 38.8

3.11.2.4 Characterization

Two sources of residual characterization were developed during the industry study:

• Table 3.11.2 summarizes the physical properties of the spent clay as reported in
Section VII.A of the §3007 survey.

• Four record samples of spent clay were collected and analyzed by EPA. These spent
clays represent some of the various types of applications used by the industry.
Sampling information is summarized in Table 3.11.3.

Petroleum Refining Industry Study 151 August 1996

 Table 3.11.2. Treating Clay from Clay Filtering: Physical Properties

# of
# of Unreported
Properties Values Values1 10th % 50th % 90th %
pH 171 334 4.6 7.6 10.4
Reactive CN, ppm 100 405 0 0.5 50
Reactive S, ppm 106 399 0 10 125
Flash Point, C 132 373 57.2 93.3 200
Oil and Grease, vol% 94 411 0 1 17.5
Total Organic Carbon, vol% 50 455 0 1 55
Specific Gravity 167 338 0.7 1.3 2.6
Specific Gravity Temperature, C 50 455 15 20 25
BTU Content, BTU/lb 31 474 0 2,000 13,500
Aqueous Liquid, % 230 275 0 0 10.3
Organic Liquid, % 240 265 0 0 5
Solid, % 346 159 89.0 100 100
Particle >60 mm, % 59 446 0 0 100
Particle 1-60 mm, % 91 414 0 100 100
Particle 100 µm-1 mm, % 70 435 0 10 100
Particle 10-100 µm, % 54 451 0 0 20
Particle <10 µm, % 49 456 0 0 0
Median Particle Diameter, microns 48 457 0 1,000 3,000

1
Facilities were not required to do additional testing, therefore information provided was based on previously collected
data or engineering judgment.

Table 3.11.3. Treating Clay Record Sampling Locations

Sample # Facility Description

R1-CF-01 Marathon Indianapolis, IN kerosene/jet treating clay (fixed bed process)
R6-CF-01 Shell Norco, LA kerosene/jet treating clay (bag filter process,
generated daily)
R11-CF-01 ARCO Ferndale, WA reformer unit sulfur trap
R23-CF-01 Chevron, Salt Lake City, UT kerosene/jet treating clay

Petroleum Refining Industry Study 152 August 1996

 The collected samples are expected to be representative of treating clay from kerosene
treatment. Section 3.11.1 shows that kerosene clay treatment represents the highest single use of
sorbents in refineries (outside of the sulfur recovery, isomerization, and alkylation processes that
are not included in the scope of this study residual). In addition, a cursory review of the 1992
generation data presented in Section 3.11.2.2 shows that the 1992 generation rate of spent
kerosene treating clay represents at least half of the total 1992 quantity from all sources
identified in Section 3.11.1.

One of the samples is representative of a sulfur guard bed. Other applications of spent
sorbents (discussed in Section 3.11.1) are not well represented by the record sampling.
Specifically:

• Spent activated carbon from Merox treatment, salt and sand from product drying,
particulate filters, and chloride removal beds are not expected to resemble these
materials.

• Spent molecular sieves and alumina are not represented by the collected record
samples. However, they may be represented by the record samples of isomerization
treating clay and alkylation treating clay, discussed in Sections 3.4 and 3.5,
respectively.

All four record samples were analyzed for total and TCLP levels of volatiles,
semivolatiles, and metals. Two samples were analyzed for ignitability and all were analyzed for
reactivity (pyrophoricity). One of the samples was found to exhibit the ignitability
characteristic. High manganese concentrations in one sample result from the adsorbent make-
up. A summary of the results is presented in Table 3.11.4. Only constituents detected in at least
one sample are shown in this table.

3.11.2.5 Source Reduction

One facility reported that its jet fuel treating clay is regenerated once by back-washing
the clay bed with jet fuel to “fluff” the clay and alleviate the pressure drop.

Petroleum Refining Industry Study 153 August 1996

 Table 3.11.4. Residual Characterization Data for Treating Clay
Petroleum Refining Industry Study

Volatile Organics - Method 8260A µg/kg

CAS No. R1-CF-01 R6-CF-01 R11-CF-01 R23-CF-01 Average Conc Maximum Conc Comments
Acetone 67641 260,000 < 565 < 25 < 1,250 65,460 260,000
Benzene 71432 < 125,000 8,500 540 < 1,250 3,430 8,500 1
n-Butylbenzene 104518 < 125,000 94,000 < 25 < 1,250 31,758 94,000 1
sec-Butylbenzene 135988 < 125,000 54,000 < 25 < 1,250 18,425 54,000 1
Ethylbenzene 100414 < 125,000 76,000 J 28 2,800 26,276 76,000 1
Isopropylbenzene 98828 < 125,000 44,000 < 25 < 1,250 15,092 44,000 1
p-Isopropyltoluene 99876 < 125,000 59,000 < 25 < 1,250 20,092 59,000 1
n-Propylbenzene 103651 < 125,000 70,000 < 25 < 1,250 23,758 70,000 1
Methylene chloride 75092 < 125,000 < 565 100 < 1,250 100 100 1
Toluene 108883 < 125,000 140,000 340 3,600 67,235 140,000
1,2,4-Trimethylbenzene 95636 580,000 620,000 < 25 32,000 308,006 620,000
1,3,5-Trimethylbenzene 108678 < 125,000 210,000 < 25 13,000 87,006 210,000
o-Xylene 95476 < 125,000 180,000 89 7,200 78,072 180,000
m,p-Xylenes 108383 / 106423 300,000 380,000 130 23,000 175,783 380,000
Naphthalene 91203 310,000 350,000 < 25 9,800 167,456 350,000
TCLP Volatile Organics - Methods 1311 and 8260A µg/L
CAS No. R1-CF-01 R6-CF-01 R11-CF-01 R23-CF-01 Average Conc Maximum Conc Comments
154

Acetone 67641 43,000 < 50 < 50 B 100 10,800 43,000

Benzene 71432 < 1,250 100 J 44 < 50 65 100 1
Ethylbenzene 100414 < 1,250 190 < 50 < 50 97 190 1
Methylene chloride 75092 2,600 < 50 1,700 < 50 1,100 2,600
Toluene 108883 < 1,250 850 210 < 50 370 850 1
1,2,4-Trimethylbenzene 95636 4,900 840 < 50 J 62 1,463 4,900
1,3,5-Trimethylbenzene 108678 < 1,250 270 < 50 < 50 123 270 1
o-Xylene 95476 < 1,250 610 < 50 J 44 235 610 1
m,p-Xylene 108383 / 106423 < 1,250 1,200 < 50 110 453 1,200 1
Naphthalene 91203 < 1,250 650 < 50 J 71 257 650 1
Semivolatile Organics - Method 8270B µg/kg
CAS No. R1-CF-01 R6-CF-01 R11-CF-01 R23-CF-01 Average Conc Maximum Conc Comments
Bis(2-ethylhexyl) phthalate 117817 < 6,600 < 4,125 J 100 < 4,150 100 100 1
Carbazole 86748 < 13,200 < 8,250 < 330 J 6,000 3,165 6,000 1
Di-n-butyl phthalate 57976 < 6,600 < 4,125 420 < 4,150 420 420 1
Dibenzofuran 132649 < 6,600 J 24,000 < 165 < 4,150 8,729 24,000
Fluorene 86737 < 6,600 < 4,125 < 165 20,000 7,723 20,000
August 1996

2,4-Dimethylphenol 105679 < 6,600 < 4,125 2,500 < 4,150 2,500 2,500 1
 Table 3.11.4. Residual Characterization Data for Treating Clay (continued)
Petroleum Refining Industry Study

Semivolatile Organics - Method 8270B µg/kg (continued)

CAS No. R1-CF-01 R6-CF-01 R11-CF-01 R23-CF-01 Average Conc Maximum Conc Comments
2-Methylphenol 95487 < 6,600 < 4,125 9,000 < 4,150 5,969 9,000
3/4-Methylphenol NA < 6,600 < 4,125 30,000 < 4,150 11,219 30,000
1-Methylnaphthalene 90120 980,000 890,000 < 165 78,000 487,041 980,000
2-Methylnaphthalene 91576 150,000 1,200,000 < 165 92,000 360,541 1,200,000
Naphthalene 91203 120,000 740,000 < 165 43,000 225,791 740,000
Phenanthrene 85018 < 6,600 J 4,800 < 165 25,000 9,141 25,000
Phenol 108952 < 6,600 < 4,125 20,000 < 4,150 8,719 20,000
TCLP Semivolatile Organics - Methods 1311 and 8270B µg/L
CAS No. R1-CF-01 R6-CF-01 R11-CF-01 R23-CF-01 Average Conc Maximum Conc Comments
Bis(2-ethylhexyl) phthalate 117817 290 J 16 < 250 < 50 152 290
Dibenzofuran 132649 < 50 J 17 < 250 < 50 17 17 1
Di-n-butyl phthalate 84742 < 50 JB 19 < 250 < 50 19 19 1
2,4-Dimethylphenol 105679 350 J 73 1,400 < 50 468 1,400
Fluorene 86737 < 50 J 41 < 250 < 50 41 41 1
1-Methylnaphthalene 90120 J 190 550 < 250 J 130 280 550
2-Methylnaphthalene 91576 220 780 < 500 120 405 780
Naphthalene 91203 600 700 < 250 140 423 700
155

2-Methylphenol 95487 310 < 50 7,800 < 50 2,053 7,800

3/4-Methylphenol (total) NA 580 < 50 6,300 < 50 1,745 6,300
Phenol 108952 < 50 < 50 2,300 < 50 613 2,300
Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg
CAS No. R1-CF-01 R6-CF-01 R11-CF-01 R23-CF-01 Average Conc Maximum Conc Comments
Aluminum 7429905 12,000 6,800 110,000 13,000 35,450 110,000
Arsenic 7440382 3.20 < 1.00 14.0 16.0 8.55 16.0
Barium 7440393 78.0 < 20.0 < 20.0 59.0 44.3 78.0
Beryllium 7440417 3.80 < 0.50 < 0.50 2.50 1.83 3.80
Calcium 7440702 4,500 16,000 < 500 4,400 6,350 16,000
Chromium 7440473 37.0 24.0 34.0 39.0 33.5 39.0
Cobalt 7440484 12.0 < 5.00 34.0 11.0 15.5 34.0
Copper 7440508 < 2.50 < 2.50 5.30 620 158 620
Iron 7439896 9,400 3,800 97.0 9,800 5,774 9,800
Lead 7439921 4.80 1.90 2.70 6.00 3.85 6.00
Magnesium 7439954 9,400 10,000 < 500 9,300 7,300 10,000
Manganese 7439965 130 140 150,000 120 37,598 150,000
August 1996

Mercury 7439976 < 0.05 < 0.05 < 0.05 0.26 0.10 0.26
 Table 3.11.4. Residual Characterization Data for Treating Clay (continued)
Petroleum Refining Industry Study

Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg (continued)
CAS No. R1-CF-01 R6-CF-01 R11-CF-01 R23-CF-01 Average Conc Maximum Conc Comments
Molybdenum 7439987 < 6.50 < 6.50 14.0 < 6.50 8.38 14.0
Nickel 7440020 16.0 < 4.00 < 4.00 31.0 13.8 31.0
Potassium 7440097 1,400 < 500 < 500 1,300 925 1,400
Selenium 7782492 < 0.50 < 0.50 22.0 < 0.50 5.88 22.0
Silver 7440224 < 1.00 < 1.00 70.0 < 1.00 18.3 70.0
Sodium 7440235 34,000 < 500 < 500 < 500 8,875 34,000
Vanadium 7440622 37.0 21.0 34.0 35.0 31.8 37.0
Zinc 7440666 47.0 19.0 < 2.00 55.0 30.8 55.0
TCLP Metals - Methods 1311, 6010, 7060, 7421, 7470, 7471, and 7841 mg/L
CAS No. R1-CF-01 R6-CF-01 R11-CF-01 R23-CF-01 Average Conc Maximum Conc Comments
Aluminum 7429905 < 1.00 < 1.00 < 1.00 3.90 1.73 3.90
Arsenic 7440382 < 0.05 < 0.05 < 0.05 0.13 0.07 0.13
Calcium 7440702 54 590 < 25.0 60.0 182 590
Copper 7440508 < 0.13 < 0.13 < 0.13 0.89 0.32 0.89
Iron 7439896 < 0.50 < 0.50 < 0.50 1.00 0.63 1.00
156

Magnesium 7439954 < 25.0 91 < 25.0 < 25.0 41.5 91.0
Manganese 7439965 < 0.08 2.60 1,400 0.85 351 1,400
Silver 7440224 < 0.05 < 0.05 0.10 < 0.05 0.06 0.10
Zinc 7440666 < 0.10 B 0.76 < 0.10 B 0.27 0.31 0.76
Miscellaneous Characterization
R1-CF-01 R6-CF-01 R11-CF-01 R23-CF-01 Average Conc Maximum Conc Comments
Ignitability ( oF ) 185 131 NA NA NA NA

Comments:

1 Detection limits greater than the highest detected concentration are excluded from the calculations.

Notes:

B Analyte also detected in the associated method blank.

J Compound's concentration is estimated. Mass spectral data indicate the presence of a compound that meets the identification criteria for which the result is less than the laboratory detection limit, but greater than
zero.
ND Not Detected.
NA Not Applicable.
August 1996
3.12 RESIDUAL OIL TANK STORAGE

Almost every refinery stores its feed and products in tanks onsite. Occasionally (every
10 to 20 years), tanks require sediment removal due to maintenance, inspection, or sediment
buildup. These tank bottoms are removed by techniques ranging from manual shoveling to
robotics and filtration. Residual oil tank sludge is a study residual of concern.

Residual oil is generally considered to be equivalent to No. 6 fuel oil which is a heavy
residue oil sometimes called Bunker C when used to fuel ocean-going vessels. Preheating is
required for both handling and burning. It is typically produced from units such as atmospheric
and vacuum distillation, hydrocracking, delayed coking, and visbreaking. The fluid catalytic
cracking unit also contributes to the refinery's heavy oil pool, but EPA terms this material
“clarified slurry oil,” or CSO, and discussed this product separately in the Listing Background
Document (October 31, 1995).

According to DOE's Petroleum Supply Annual, approximately 400 million barrels of

“residual oil” was domestically used in 1992 (including imports and exports). The use profile in
1994 was as follows (DOE's Fuel Oil and Kerosene Sales 1994):

Sector 1990 Consumption of Residual Fuel Oil

Electric Utility 40%
Shipping 35%
Industrial 15%
Commercial and Other 10%

The larger utilities often have their own specifications when purchasing residual fuel oil. These
can include sulfur, nitrogen, ash, and vanadium. The current ASTM standard for No. 6 oil (D-
396) specifies only three parameters: minimum flash point (of 150 F), maximum water and
sediment (of 2 percent), and a viscosity range (Bonnet, 1994). Thus, the characteristics of
residual oil, and the generated tank sludge, can vary greatly depending on the buyer and the
refinery.

3.12.1 Residual Oil Storage Tank Sludge

In 1992, 125 U.S. refineries reported approximately 717 residual oil storage tanks. From
the survey, tank volume was reported for about 10 percent (73) of these tanks (excluding
outliers); the average tank volume was approximately 77,000 barrels. DOE's Petroleum Supply
Annual 1992 reported that refineries produced about 327 million barrels of No. 6 fuel oil or
residual oil or approximately 900,000 barrels per day (this likely includes CSO).

3.12.1.1 Description

Residual oil tank sludge consists of heavy hydrocarbons, rust and scale from process
pipes and reactors, and entrapped oil that settles to the bottom of the tank. It can be manually re-
moved directly from the tank after drainage of the residual oil or, commonly, removed using a
variety of oil recovery techniques. The recovered oil is returned generally to slop oil storage
while the remaining solids are collected and discarded as waste.

Petroleum Refining Industry Study 157 August 1996

 Once a tank is taken out of service, many refineries use in situ and ex situ oil recovery
techniques. Common in situ oil recovery techniques include hot distillate washing, and steam
stripping. This allows entrapped oil to float to the top of the sediment layer and be recovered
prior to removal of the sediment from the tank. Ex situ recovery methods are usually performed
by a contractor at the tank site and include filtration, centrifuging, and settling. Separated oil is
recycled back to the process or sent to the slop oil tanks, and the water phase is sent to the
wastewater treatment plant (WWTP). The solids are managed in a variety of ways, but
primarily are disposed of in Subtitle C and D landfills (78 percent in 1992).

Many refineries reduce tank bottom buildup with in-tank mixers. Mixers keep the
sediments or solids continuously in suspension so that they travel with the residual oil.

In 1992, less than one percent of the volume of residual oil tank bottom sludge was
reported to be managed as hazardous.6 Of the few refineries that reported a hazardous waste
designation for this residual in 1992, only one reported a hazardous waste code (the others
specified handling the sludge as hazardous without designating a code).

3.12.1.2 Generation and Management

The refineries reported generating 9,107 MT of residual oil tank bottom sludge in 1992.
Residual oil tank sludge includes sludges from No. 6 oil and similar product tanks. Sludges
from tanks identified as containing a mixture of residual oil and clarified slurry oil were
included in the scope of K170 and are omitted here. Residuals were assigned to be “residual oil
tank sludge” if they were assigned a residual identification code of “residual oil tank sediment,”
corresponding to residual code “01-B” in Section VII.1 of the questionnaire. Process
wastewaters, decantates, and recovered oils (e.g., from deoiling or dewatering operations) were
eliminated from the analysis. These correspond to residual codes “09,” “10,” and “13” (newly
added “recovered oil”) in the questionnaire. Quality assurance was conducted by ensuring that
all residual oil tank sludges previously identified in the questionnaire (i.e., in Section V.D) were
assigned in Section VII.1. Table 3.12.1 provides a description of the 1992 management
practices, quantity generated, number of streams reported, number of streams not reporting
volumes, and average volumes.

When cleaning a tank, it is common for refineries to use some type of in situ treatment,
such as washing with lighter fuel, to recover oil from the top layers of sludge where there is a
high percentage of free oil. However, treatment or recovery practices after this depend on the
refinery's planned final management method. If land disposed (as most residual oil tank sludge
was in 1992), low free liquid must be achieved; such levels can be achieved by sludge
deoiling/dewatering or stabilization. A refinery may conduct this

6
These percentages do not match up directly with any one of the management scenarios because the number of
streams and the volume are a combination of several management scenarios (i.e., managed in WWTP, Subtitle C
landfill, recovery onsite in coker, etc.).

Petroleum Refining Industry Study 158 August 1996

 Table 3.12.1. Generation Statistics for Residual Oil Tank Sludge, 1992

# of Streams
# of w/ Unreported Total Volume Average
Final Management Streams Volume (MT) Volume (MT)
Discharge to onsite wastewater 1 0 47 47
treatment facility
Disposal in offsite Subtitle D landfill 13 4 6,458 496.8
Disposal in offsite Subtitle C landfill 8 0 622 77.8
Disposal in onsite Subtitle C landfill 2 0 4 2
Disposal in onsite Subtitle D landfill 3 0 30.4 10.1
Disposal in onsite surface impoundment 1 0 132 132
Offsite land treatment 1 1 4 4
Onsite land treatment 2 0 530.4 265.2
Other recycling, reclamation, or reuse: 1 0 7.2 7.2
cover for onsite landfill
Recovery onsite via distillation 1 3 310 310
Transfer for use as an ingredient in 1 0 35 35
products placed on the land
Transfer to another petroleum refinery 1 0 927 927
TOTAL 35 8 9,107 260.2

treatment for only some of the waste (e.g., the top layers); in the deeper sections of sludge where
free liquid levels are lower no treatment may be performed. In addition to lower liquid levels,
treatment or deoiling may be used to achieve lower levels of benzene or other hazardous
properties.

3.12.1.3 Plausible Management

EPA believes that most of the plausible management practices for this residual were
reported in the 1992 RCRA §3007 Survey, as summarized above in Table 3.12.1. The Agency
gathered information suggesting other management practices have been used in other years
including: “recovery onsite in an asphalt production unit” (9.2 MT), “transfer for direct use as a
fuel or to make a fuel” (380.8 MT), “transfer with coke product or other refinery product” (5
MT), “onsite industrial furnace” (39 MT), “recycle to process” (unknown quantity), “recovery in
coker” (unknown quantity), and “recovery in a catalytic cracker” (unknown quantity). These
non-1992 management practices are generally comparable to the recycling practices reported in
1992.

Petroleum Refining Industry Study 159 August 1996

3.12.1.4 Characterization

Two sources of residual characterization were developed during the industry study:

• Table 3.12.2 summarizes the physical properties of residual oil tank sludges as
reported in Section VII.A of the §3007 survey.

• Two record samples of actual residual oil sludge were collected and analyzed by EPA.
These sludges represent the various types of treatment typically used by the industry
and are summarized in Table 3.12.3.

Table 3.12.4 provides a summary of the characterization data collected under this
sampling effort. The record samples collected are believed to be representative of residual oil
tank sludges generated by the industry.

The samples collected of the composite of oily and de-oiled sediment are representative
of industry treatment practices. As reported in the RCRA 3007 questionnaires, 10 of the 34
residual oil tank sludges (30 percent) that were ultimately managed in a land treatment or landfill
in 1992 were deoiled in some manner, most often by filtration or centrifuge. This management
resulted in volume reduction averaging 55 percent. Another 7 (20 percent) were stabilized,
resulting in the volume increasing by an average of 55 percent. The remaining 17 residuals (50
percent) were not reported to be treated ex situ in any manner. The sampled refineries represent
two alternative interim management procedures: free liquid reduction using stabilization
(Amoco), and ex situ deoiling (Star). Therefore, the record samples represent the various types
of ex situ treatment typically performed for residual oil tank sludge, but may not represent cases
in which no treatment is performed. However, the same contaminants will be present in all three
types of sludge (i.e., deoiled. stabilized, and untreated), but their levels may differ.

As illustrated in Table 3.12.4, none of the record samples exhibited a hazardous waste
characteristic. Only constituents detected in at least one sample are shown in this table.

3.12.1.5 Source Reduction

Only a small quantity of sludge was reported to be deoiled in 1992, as reported in the
§3007 survey. Of the 34 residuals disposed in landfills or land treatment units in 1992, 10
residuals, totaling approximately 1,000 MT. The remaining 24 residuals, totaling approximately
7,600 MT, were reported to be untreated or underwent volume addition treatment (such as
stabilization. As stated in Section 3.12.1.3, the average volume reduction achieved by deoiling
was 55 percent (as calculated from those facilities providing sludge quantities prior to and
following deoiling in 1992).

Petroleum Refining Industry Study 160 August 1996

 Table 3.12.2. Residual Oil Tank Sludge: Physical Properties

# of # of Unreported
Properties Values Values1 10th % Mean 90th %
pH 39 87 5.5 7 8.5
Reactive CN, ppm 27 99 0 0.3 5
Reactive S, ppm 27 99 0 2.5 15
Flash Point, C 42 84 60 93.3 140
Oil and Grease, vol% 36 90 9 34.1 99
Total Organic Carbon, vol% 20 106 3.5 51 85.3
Vapor Pressure, mm Hg 11 115 0 0.1 10
Vapor Pressure Temperature, C 9 117 25 37.8 38
Viscosity, lb/ft-sec 6 120 0.01 50.2 500
Specific Gravity 30 96 0.9 1.2 2.4
BTU Content, BTU/lb 16 110 600 5,000 20,000
Aqueous Liquid, % 78 48 0 0 50
Organic Liquid, % 82 44 0 18 86
Solid, % 91 35 1 60 100
Other, % 65 61 0 0 0
Particle >60 mm, % 4 122 0 0 0
Particle 1-60 mm, % 6 120 0 50 100
Particle 100 µm-1 mm, % 5 121 0 50 100
Particle 10-100 µm, % 4 122 0 0 1
Particle <10 µm, % 4 122 0 0 0
Median Particle Diameter, microns 3 123 0 0 15,000
1
Facilities were not required to do additional testing, therefore information provided was based on previously collected
data or engineering judgment.

Table 3.12.3. Residual Oil Tank Sludge Record Sampling Locations

Sample No. Facility Description:

R8B-RS-01 Amoco, Texas City, TX Residual oil and CSO mixed.1 Cleaning
procedure: pumped down, mixed with
diatomaceous earth, removed with backhoe.
R22-RS-01 Star, Port Arthur, TX Residual oil.2 Cleaning procedure: washed
with lighter oil, centrifuged to generate cake.
1
The refinery has a fluid catalytic cracking unit and generates CSO. An unknown quantity of CSO was stored in the
sampled tank.
2
The refinery has a fluid catalytic cracking unit and generates CSO. It is unknown if, or to what extent, CSO was
stored in the sampled tank.

Petroleum Refining Industry Study 161 August 1996

 Table 3.12.4. Residual Oil Tank Sludge Characterization

Volatile Organics - Method 8260A µg/kg

CAS No. R8B-RS-01 R22-RS-01 Average Conc Maximum Conc Comments
n-Butylbenzene 104518 < 6,250 3,600 3,600 3,600 1
Ethylbenzene 100414 13,000 J 1,600 7,300 13,000
p-Isopropyltoluene 99876 < 6,250 J 470 470 470 1
n-Propylbenzene 103651 J 6,850 J 1,600 4,225 6,850
Toluene 108883 26,000 < 1,250 13,625 26,000
1,2,4-Trimethylbenzene 95636 43,000 18,000 30,500 43,000
1,3,5-Trimethylbenzene 108678 J 11,000 4,200 7,600 11,000
o-Xylene 95476 19,000 J 1,800 10,400 19,000
m,p-Xylenes 108383 / 106423 51,000 7,400 29,200 51,000
Naphthalene 91203 64,000 19,000 41,500 64,000
TCLP Volatile Organics - Methods 1311 and 8260A µg/L
CAS No. R8B-RS-01 R22-RS-01 Average Conc Maximum Conc Comments
Benzene 71432 110 < 50 80 110
Ethylbenzene 100414 J 55 < 50 53 55
Toluene 108883 690 < 50 370 690
1,2,4-Trimethylbenzene 95636 J 79 < 50 65 79
Methylene chloride 75092 B 1,200 < 50 625 1,200
o-Xylene 95476 J 96 < 50 73 96
m,p-Xylene 108383 / 106423 220 JB 28 124 220
Naphthalene 91203 J 91 J 46 69 91
Semivolatile Organics - Method 8270B µg/kg
CAS No R8B-RS-01 R22-RS-01 Average Conc Maximum Conc Comments
Acenaphthene 83329 60,000 27,000 43,500 60,000
Anthracene 120127 150,000 < 4,125 77,063 150,000
Benz(a)anthracene 56553 480,000 9,200 244,600 480,000
Benzofluoranthene (total) NA 130,000 34,000 82,000 130,000
Benzo(g,h,i)perylene 191242 450,000 36,000 243,000 450,000
Benzo(a)pyrene 50328 250,000 87,000 168,500 250,000
Bis(2-ethylhexyl)phthalate 117817 < 10,313 10,000 10,000 10,000 1
Carbazole 86748 < 20,625 J 16,000 16,000 16,000 1
Chrysene 218019 800,000 170,000 485,000 800,000
Dibenzofuran 132649 25,000 8,700 16,850 25,000
Dibenz(a,h)anthracene 53703 65,000 J 8,000 36,500 65,000
3,3'-Dichlorobenzidine 91941 < 10,313 87,000 48,656 87,000
Fluoranthene 206440 120,000 < 4,125 62,063 120,000
Fluorene 86737 160,000 38,000 99,000 160,000
Indeno(1,2,3-cd)pyrene 193395 58,000 < 4,125 31,063 58,000
Phenanthrene 85018 1,000,000 220,000 610,000 1,000,000
Pyrene 129000 3,500,000 46,000 1,773,000 3,500,000
1-Methylnaphthalene 90120 500,000 250,000 375,000 500,000
2-Methylnaphthalene 91576 650,000 410,000 530,000 650,000
2-Methylchrysene 3351324 380,000 < 8,250 194,125 380,000
Naphthalene 91203 230,000 110,000 170,000 230,000

Petroleum Refining Industry Study 162 August 1996

 Table 3.12.4. Residual Oil Tank Sludge Characterization (continued)

TCLP Semivolatile Organics - Methods 1311 and 8270B µg/L

CAS No. R8B-RS-01 R22-RS-01 Average Conc Maximum Conc Comments
Di-n-butylphthalate 84742 < 50 JB 24 24 24 1
1-Methylnaphthalene 90120 J 28 J 54 41 54
2-Methylnaphthalene 91576 J 37 J 74 56 74
Naphthalene 91203 J 37 J 73 55 73
Total Metals - Methods 6010, 7060, 7421, 7470, 7471, and 7841 mg/kg
CAS No. R8B-RS-01 R22-RS-01 Average Conc Maximum Conc Comments
Aluminum 7429905 9,100 38,000 23,550 38,000
Arsenic 7440382 3.00 < 1.00 2.00 3.00
Barium 7440393 < 20.0 230 125 230
Beryllium 7440417 1.80 < 0.50 1.15 1.80
Calcium 7440702 < 500 1,400 950 1,400
Chromium 7440473 11.0 31.0 21.0 31.0
Cobalt 7440484 130 < 5.00 67.5 130
Copper 7440508 7.40 110 58.7 110
Iron 7439896 1,600 11,000 6,300 11,000
Lead 7439921 6.50 84.0 45.3 84.0
Magnesium 7439954 < 500 4,300 2,400 4,300
Manganese 7439965 12.0 67.0 39.5 67.0
Mercury 7439976 1.50 < 0.05 0.78 1.50
Molybdenum 7439987 330 18.0 174 330
Nickel 7440020 410 83.0 247 410
Sodium 7440235 < 500 3,200 1,850 3,200
Vanadium 7440622 1,400 480 940 1,400
Zinc 7440666 75.0 200 138 200
TCLP Metals - Methods 1311, 6010, 7060, 7421, 7470, 7471, and 7841 mg/L
CAS No. R8B-RS-01 R22-RS-01 Average Conc Maximum Conc Comments
Aluminum 7429905 < 1.00 3.70 2.35 3.70
Iron 7439896 < 0.50 10.0 5.25 10.0
Manganese 7439965 < 0.08 1.10 0.59 1.10
Zinc 7440666 B 0.26 1.20 0.73 1.20

Comments:

1 Detection limits greater than the highest detected concentration are excluded from the calculations.

Notes:

B Analyte also detected in the associated method blank.

J Compound's concentration is estimated. Mass spectral data indicate the presence of a compound that meets the identification criteria for which the
result is less than the laboratory detection limit, but greater than zero.
ND Not Detected.
NA Not Applicable.

Petroleum Refining Industry Study 163 August 1996

 In situ oil recovery techniques can greatly reduce the total amount of residual oil tank
sludge to be disposed as well as reduce volatile constituents such as benzene. As discussed
above, recovery methods include distillate washing, nonpetroleum solvent washing, water wash
with surfactant, and steam stripping. These operations allow entrapped oil to float to the top of
the sediment layer and be recovered prior to removal from the tank. Separated oil is recycled
back to the process or sent to the slop oil tanks, and the water phase is sent to the WWTP.

Oily sludges are emulsions formed due to a surface attraction among oily droplets, water
droplets, and solid particles. If the solids are large and dense, the resultant material will settle
and become a sludge. The surface charge interactions between the solid particles and oil
droplets cause the sludge to become stable and difficult to separate. However, the sludge can be
separated into its individual components by mechanically removing the solids or by neutralizing
the surface charge on the solids and oil droplets.

The predominant method of minimizing the formation of tank sludge is the use of mixers
to keep the sludges continuously in suspension. A common mixer configuration is a sweeping
mixer that automatically oscillates to produce a sweeping motion over the floor of the tank,
keeping the heavy oil and particles suspended.

Of the twenty facilities that EPA visited, eight listed methods in recovering oil from tank
sludges. Several facilities wash the tanks with light oils and water, whereas another facility
washes with a surfactant followed by pressure filtration.

Reference Waste Minimization/Management Methods

”Re-refiner Fluidizes Tank Residue Using Portable Mixer.” A portable mixer was used to cut lighter oil into the
Oil & Gas Journal. September 5, 1994. partially gelled residue.
Kuriakose, A.P., Manjooran, S. Jochu Baby. Utilizing waste sludge.
”Utilization of Refinery Sludge for Lighter Oils and Industrial
Bitumen.” Energy & Fuels. vol.8, no.3. May-June, 1994.
”Environmental Processes '93: Challenge in the '90s.” A variety of technologies described, such as
Hydrocarbon Processing. August, 1993. bioslurry treatment of oily wastes, oily-waste
recovery, and evaporation/solvent extraction.
”Waste Minimization in the Petroleum Industry: A Sludge formation can be minimized by mixing
Compendium of Practices.” API. November, 1991. contents of tank.

Petroleum Refining Industry Study 164 August 1996

 BIBLIOGRAPHY

1992 RCRA §3007 Survey of the Petroleum Refining Industry Database.

Department of Energy, Energy Information Administration. Petroleum Supply Annual 1992,

Volume 1. May 1993.

Donald Bonett, “ASTM D-396 Specification for No. 6 Fuel Oil,” in Proceedings, 1993 Fuel Oil
Utilization Workshop, Electric Power Research Institute, August 1994 (page 3-101).

Fuel Oil and Kerosene Sales 1994, U.S. Department of Energy, September 1995 (DOE/EIA-
0340(92)/1).

Hydrocarbon Processing. “Refining Processes '94.” November 1994.

Hydrocarbon Processing. “Gas Processing '94.” April 1994.

Kirk-Othmer. Encyclopedia of Chemical Technology. Third Edition, Volume 22. 1983.

McKetta, John J. Petroleum Processing Handbook. Marcel Dekker, Inc. 1992.

Meyers, Robert A. Handbook of Petroleum Refining Processes. McGraw-Hill Book Company.

1986.

Perry's, 1950. John H. Perry, ed. Chemical Engineer's Handbook. McGraw-Hill, New York.
Third edition, 1950.

Speight, 1991. James Speight. The Chemistry and Technology of Petroleum. Marcel Dekker,
New York. Second edition, 1991.

Petroleum Refining Industry Study 165 August 1996