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
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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
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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
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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
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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 H S Removal, 2

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
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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 1 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.
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Listing Residuals

Clarified slurry oil sludge from catalytic cracking

Unleaded storage tank sludge

Crude storage tank sludge 

Process sludge from sulfur complex and H S removal facilities (sulfur complex sludge) 2

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 H S removal facilities (Claus and tail gas treating catalysts) 2

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 H S removal facilities (Off-spec sulfur) 2

Off-spec treating solution from sulfur complex and H S removal facilities (Spent amine and spent 2

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.

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

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 3 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 tankbased 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 4 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 H S removal facilities (off-spec sulfur) 2

- Off-spec treating solution from sulfur complex and H S removal facilities (spent 2

amine and spent Stretford solution)
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Table 1.2. Overview of 15 Study Residuals of Concern as Managed in 1992

Management Practice mt mt mt mt mt mt mt mt mt mt mt mt mt mt mt MT

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

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

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%
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Table 1.2. Overview of 15 Study Residuals of Concern as Managed in 1992 (continued)

Management Practice mt mt mt mt mt mt mt mt mt mt mt mt mt mt mt MT

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

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%

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.
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- 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 H S removal facilities (spent 2

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 H S removal facilities (off-spec sulfur) 2

- 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.
 The Agency conducted its industry-wide survey in 1993-1994, characterizing residual generation in 1992. 1

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.

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2.0 INDUSTRY DESCRIPTION

2.1 PETROLEUM REFINING INDUSTRY PROFILE

In 1992 , the U.S. petroleum refining industry consisted of 185 refineries (of which 171 1

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
Petroleum Refining Industry Study 9 August 1996

Fig

u

r

e

2.1. G

e

o

g

r

a

p

hic

al Distrib

utio

n

of U.S. R

efin

e

ries

Figure 2.1. Geographical Distribution of U.S. Refineries
Petroleum Refining Industry Study 10 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.
 Upon initial contact with several of the randomly selected refineries, it was determined that they were 2

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

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 handpicked 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

2.1 .

2
Petroleum Refining Industry Study 12 August 1996

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

Refinery selected to augment record sample availability. 1

Table 2.1. Engineering Site Visit Facilities
Petroleum Refining Industry Study 13 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 14 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.
 The Agency determined that one listing residual, catalyst from sulfuric acid alkylation, would not be sampled 3

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

Study Residual Description

# of

Reported

Residuals

Total Volume

(MT)

Acid Soluble Oil 80 33,493

Hydrocracking Catalyst 83 18,029

Off-specification Product from Sulfur Complex and H S Removal 2 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

Removal (spent amine and spent Stretford solution)

76 23,881

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

Table 2.2. Study Residuals Volume Statistics

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 samples . Table 2.3 shows the 103 samples that were 3

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.
Petroleum Refining Industry Study 16 August 1996

Listing Residuals

Record Samples

Familiarization

Samples

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.

Table 2.3. Residuals Collected for Record Analysis

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.
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Table 2.4. Descriptions of Samples Collected for Record Analysis

Count Residual Name Number Date Notes Refinery

Sample Sample

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

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

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
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Table 2.4. Descriptions of Samples Collected for Record Analysis (continued)

Count Residual Name Number Date Notes Refinery

Sample Sample

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

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

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
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Table 2.4. Descriptions of Samples Collected for Record Analysis (continued)

Count Residual Name Number Date Notes Refinery

Sample Sample

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

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
Petroleum Refining Industry Study 20 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 21 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 distillation 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. Hydrocracking 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 22 August 1996

Fig

u

r

e

3.1. Sim

plifie

d

R

efin

e

r

y

P

r

o

c

ess Flo

w

Dia

g

r

a

m

Figure 3.1. Simplified Refinery Process Flow Diagram
Petroleum Refining Industry Study 23 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 highboiling 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 24 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

H S and are removed by amine scrubbing. The H S often is converted to pure sulfur in a Claus 2 2

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, nbutane 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 25 August 1996

Figure 3.2.1. Desalting Process Flow Diagram

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/in gauge to reduce vaporization. Intimate mixing is achieved through 2

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.
Petroleum Refining Industry Study 26 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.
 These percentages do not match up directly with any one of the management scenarios because the number of 4

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

Final Management

# of

Streams

# of Streams

w/ Unreported

Volume

Total Volume

(MT)

Average

Volume (MT)

Discharge to onsite wastewater

treatment facility

25 9 2,041.62 81.66

Disposal in onsite or offsite

underground injection

1 0 2.00 2.00

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

make a fuel

17 1 1,937.60 113.98

TOTAL 97 20 4,840.78 49.90

Table 3.2.1. Generation Statistics for Desalting Sludge, 1992

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.

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. Twenty seven of these streams were managed with F or K listed wastes, reflecting 4

their frequent management in wastewater treatment systems.
Petroleum Refining Industry Study 28 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 29 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 30 August 1996

Properties

# of

Values

# of

Unreported

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

Facilities were not required to do additional testing, therefore information provided was based on previously collected 1

data or engineering judgment.

Table 3.2.2. Desalter Sludge: Physical Properties

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

Table 3.2.3. Desalting Sludge Record Sampling Locations
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Table 3.2.4. Desalting Sludge Characterization

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

CAS No. R1-DS-01 R9-DS-01 R11B-DS-01 R24-DS-01 Conc Maximum Conc Comments

Average

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

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 )

CAS No. R1-DS-01 R9-DS-01 R11B-DS-01 R24-DS-01 Conc Maximum Conc Comments

Average

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

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 
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Table 3.2.4. Desalting Sludge Characterization (continued)

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

CAS No. R1-DS-01 R9-DS-01 R11B-DS-01 R24-DS-01 Conc Maximum Conc Comments

Average

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 

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 
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Table 3.2.4. Desalting Sludge Characterization (continued)

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 

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.
Petroleum Refining Industry Study 34 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 longestablished 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 35 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.
 These percentages do not match up directly with any one of the management scenarios because the number of 5

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

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. This is approximately 15 percent of the total volume 5

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.
Petroleum Refining Industry Study 37 August 1996

Final Management

# of

Streams

# of Streams w/

Unreported Volume

Total Volume

(MT)

Average

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

another unit

1 0 159.40 159.40

Transfer metal catalyst for reclamation or

regeneration

45 2 13,185.56 293.01

Transfer to another petroleum refinery 14 0 2,100.00 150.00

TOTAL 75 2 18,029.16 295.56

Table 3.3.1. Generation Statistics for Hydrocracking Catalyst, 1992

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.

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 38 August 1996

Properties

# of

Values

# of Unreported

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

Facilities were not required to do additional testing, therefore information provided was based on previously collected 1

data or engineering judgement.

Table 3.3.2. Hydrocracking Catalyst Physical Properties

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.
Petroleum Refining Industry Study 39 August 1996

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

Table 3.3.3. Spent Hydrocracking Catalyst Record Sampling Locations

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.
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Table 3.3.4. Spent Hydrocracking Catalyst Characterization

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

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 

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 
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Table 3.3.4. Spent Hydrocracking Catalyst Characterization (continued)

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 

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 

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 
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Table 3.3.4. Spent Hydrocracking Catalyst Characterization (continued)

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:

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.
Petroleum Refining Industry Study 43 August 1996