STUDY OF SELECTED

PETROLEUM REFINING RESIDUALS

INDUSTRY STUDY

August 1996

U.S. ENVIRONMENTAL PROTECTION AGENCY

Office of Solid Waste, OSW (Note: Office of Solid Waste,

OSW, was renamed Office of Resource Conservation and Recovery, ORCR, on January

18, 2009)

Hazardous Waste Identification Division

401 M Street, SW

Washington, DC 20460

TABLE OF CONTENTS Page No.

1.0 INTRODUCTION. . . . . . . . . . . . . . . . . . . . 1

1.1 BACKGROUND . . . . . . . . . . . . . . . . . . 1

1.2 OTHER EPA REGULATORY PROGRAMS IMPACTING THE

PETROLEUM REFINING INDUSTRY. . . . . . . . . . 3

1.3 INDUSTRY STUDY FINDINGS. . . . . . . . . . . . 3

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

2.1 PETROLEUM REFINING INDUSTRY PROFILE. . . . . . 8

2.2 INDUSTRY STUDY . . . . . . . . . . . . . . . . 11

2.2.1 Site Selection . . . . . . . . . . . . . 11

2.2.2 Engineering Site Visits. . . . . . . . . 12

2.2.3 RCRA 3007 Questionnaire. . . . . . . . . 14

2.2.4 Familiarization Sampling . . . . . . . . 15

2.2.5 Record Sampling. . . . . . . . . . . . . 16

2.2.6 Split Samples Analyzed by API. . . . . . 17

2.2.7 Synthesis. . . . . . . . . . . . . . . . 17

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3.0 PROCESS AND WASTE DESCRIPTIONS. . . . . . . . . . . 23

3.1 REFINERY PROCESS OVERVIEW. . . . . . . . . . . 23

3.2 CRUDE OIL DESALTING. . . . . . . . . . . . . . 27

3.2.1 Process Description. . . . . . . . . . . 27

3.2.2 Desalting Sludge . . . . . . . . . . . . 28

3.3 HYDROCRACKING. . . . . . . . . . . . . . . . . 35

3.3.1 Process Description. . . . . . . . . . . 35

3.3.2 Spent Hydrocracking Catalyst . . . . . . 36

3.4 ISOMERIZATION. . . . . . . . . . . . . . . . . 45

3.4.1 Isomerization Process Description. . . . 45

3.4.2 Isomerization Catalyst . . . . . . . . . 49

3.4.3 Isomerization Treating Clay. . . . . . . 55

3.5 EXTRACTION . . . . . . . . . . . . . . . . . . 59

3.5.1 Extraction Process Description . . . . . 59

3.5.2 Extraction Treating Clay . . . . . . . . 61

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. . . 70

3.6.4 Catalyst from Hydrofluoric Acid

Alkylation . . . . . . . . . . . . . . . 76

3.6.5 Acid Soluble Oil from Hydrofluoric Acid

Alkylation . . . . . . . . . . . . . . . 79

3.7 POLYMERIZATION . . . . . . . . . . . . . . . . 85

3.7.1 Process Descriptions . . . . . . . . . . 85

3.7.2 Spent Phosphoric Acid Polymerization

Catalyst . . . . . . . . . . . . . . . . 87

3.7.3 Spent Dimersol Polymerization Catalyst . 90

3.8 RESIDUAL UPGRADING . . . . . . . . . . . . . . 94

3.8.1 Process Descriptions . . . . . . . . . . 94

3.8.2 Off-specification Product from Residual

Upgrading . . . . . . . . . . . . . . . 98

3.8.3 Process Sludge from Residual Upgrading. 100

3.9 LUBE OIL PROCESSING . . . . . . . . . . . . . 105

3.9.1 Process Descriptions. . . . . . . . . . 105

3.9.2 Treating Clay from Lube Oil Processing. 110

3.10 H2S REMOVAL AND SULFUR COMPLEX. . . . . . . . 114

3.10.1 Process Description. . . . . . . . . . 114

3.10.2 Off-Specification Product from

Sulfur Complex and H2S Removal

Facilities . . . . . . . . . . . . . . 120

3.10.3 Off-Specification Treating Solution

from Sulfur Complex and H2S Removal

Facilities . . . . . . . . . . . . . . 126

3.11 CLAY FILTERING. . . . . . . . . . . . . . . . 135

3.11.1 Process Description. . . . . . . . . . 135

3.11.2 Treating Clay from Clay Filtering. . . 138

3.12 RESIDUAL OIL TANK STORAGE . . . . . . . . . . 146

3.12.1 Residual Oil Storage Tank Sludge . . . 146

LIST OF TABLES Page No.

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 . . . . . . . . . . . . . . 6

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Table 2.1. Engineering Site Visit Facilities. . . . . . 13

Table 2.2. Study Residuals Volume Statistics. . . . . . 15

Table 2.3. Residuals Collected for Record Analysis. . . 18

Table 2.4. Descriptions of Samples Collected for Record

Analysis . . . . . . . . . . . . . . . . . . 19

Table 3.2.1. Generation Statistics for Desalting Sludge,

1992 . . . . . . . . . . . . . . . . . . . . 29

Table 3.2.2 Desalter Sludge: Physical Properties. . . . 30

Table 3.2.3. Desalting Sludge Record Sampling Locations . 31

Table 3.2.4. Desalting Sludge Characterization. . . . . . 33

Table 3.3.1. Generation Statistics for Hydrocracking

Catalyst, 1992 . . . . . . . . . . . . . . . 38

Table 3.3.2. Hydrocracking Catalyst Physical Properties . 39

Table 3.3.3. Spent Hydrocracking Catalyst Record Sampling

Locations. . . . . . . . . . . . . . . . . . 40

Table 3.3.4. Spent Hydrocracking Catalyst

Characterization . . . . . . . . . . . . . . 42

Table 3.4.1. Generation Statistics for Catalyst from

Isomerization, 1992. . . . . . . . . . . . . 50

Table 3.4.2. Catalyst from Isomerization: Physical

Properties . . . . . . . . . . . . . . . . . 51

Table 3.4.3. Spent Isomerization Catalyst Record Sampling

Locations. . . . . . . . . . . . . . . . . . 52

Table 3.4.4. Residual Characterization Data for Spent

Isomerization Catalyst . . . . . . . . . . . 53

Table 3.4.5. Generation Statistics for Treating Clay from

Isomerization, 1992. . . . . . . . . . . . . 56

Table 3.4.6. Treating Clay from Isomerization: Physical

Properties . . . . . . . . . . . . . . . . . 57

Table 3.4.7. Isomerization Spent Sorbent Record Sampling

Locations. . . . . . . . . . . . . . . . . . 58

Table 3.5.1. Generation Statistics for Treating Clay from

Extraction, 1992 . . . . . . . . . . . . . . 62

Table 3.5.2. Treating Clay from Extraction: Physical

Properties . . . . . . . . . . . . . . . . . 63

Table 3.5.3. Extraction Spent Sorbent Record Sampling

Locations. . . . . . . . . . . . . . . . . . 64

Table 3.5.4. Residual Characterization Data for Spent

Treating Clay from Extraction/Isomerization. 65

Table 3.6.1. Generation Statistics for Treating Clay from

Alkylation, 1992 . . . . . . . . . . . . . . 71

Table 3.6.2. Treating Clay from Alkylation: Physical

Properties . . . . . . . . . . . . . . . . . 72

Table 3.6.3. Alkylation Treating Clay Record Sampling

Locations. . . . . . . . . . . . . . . . . . 73

Table 3.6.4. Alkylation Treating Clay Characterization. . 74

Table 3.6.5. Generation Statistics for Catalyst from HF

Alkylation, 1992 . . . . . . . . . . . . . . 77

Table 3.6.6. Catalyst from HF Alkylation: Physical

Properties . . . . . . . . . . . . . . . . . 77

Table 3.6.7. Generation Statistics for Acid Soluble Oil,

1992 . . . . . . . . . . . . . . . . . . . . 80

Table 3.6.8. Acid Soluble Oil: Physical Properties . . . 81

Table 3.6.9. Acid Soluble Oil Record Sampling Locations . 81

Table 3.6.10.Acid Soluble Oil Characterization. . . . . . 83

Table 3.7.1. Generation Statistics for Phosphoric Acid

Catalyst from Polymerization, 1992 . . . . . 88

Table 3.7.2. Phosphoric Acid Catalyst from Polymerization:

Physical Properties. . . . . . . . . . . . . 89

Table 3.7.3. Phosphoric Acid Polymerization Catalyst

Record Sampling Locations. . . . . . . . . . 89

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Table 3.7.4. Generation Statistics for Spent Dimersol

Polymerization Catalyst, 1992. . . . . . . . 91

Table 3.7.5. Spent Dimersol Polymerization Catalyst

Physical Properties. . . . . . . . . . . . . 91

Table 3.7.6. Dimersol Polymerization Catalyst Record

Sampling Locations . . . . . . . . . . . . . 92

Table 3.7.7. Polymerization Catalyst Characterization . . 93

Table 3.8.1. Generation Statistics for Off-Specification

Product from Residual Upgrading, 1992. . . . 98

Table 3.8.2. Off-Specification Product from Residual

Upgrading: Physical Properties. . . . . . . 99

Table 3.8.3. Generation Statistics for Process Sludge from

Residual Upgrading, 1992. . . . . . . . . . 101

Table 3.8.4. Process Sludge from Residual Upgrading:

Physical Properties . . . . . . . . . . . . 102

Table 3.8.5. Process Sludge from Residual Upgrading Record

Sampling Locations. . . . . . . . . . . . . 102

Table 3.8.6. Process Sludge from Residual Upgrading

Characterization. . . . . . . . . . . . . . 103

Table 3.9.1. Generation Statistics for Treating Clay from

Lube Oil, 1992. . . . . . . . . . . . . . . 110

Table 3.9.2. Treating Clay from Lube Oil: Physical

Properties. . . . . . . . . . . . . . . . . 111

Table 3.9.3. Treating Clay from Lube Oil Processing Record

Sampling Locations. . . . . . . . . . . . . 112

Table 3.9.4. Treating Clay from Lube Oil Processing

Characterization. . . . . . . . . . . . . . 113

Table 3.10.1.Sulfur Removal Technologies Reported in RCRA

3007 Questionnaire. . . . . . . . . . . . . 114

Table 3.10.2.Generation Statistics for Off-Spec Sulfur,

1992. . . . . . . . . . . . . . . . . . . . 122

Table 3.10.3.Off-Specification Sulfur: Physical

Properties. . . . . . . . . . . . . . . . . 123

Table 3.10.4.Off-Specification Sulfur Record Sampling

Locations . . . . . . . . . . . . . . . . . 124

Table 3.10.5.Residual Characterization Data for

Off-Specification Sulfur. . . . . . . . . . 125

Table 3.10.6.Generation Statistics for Spent Amine for H2S

Removal, 1992 . . . . . . . . . . . . . . . 127

Table 3.10.7.Generation Statistics for Stretford Solution

for H2S Removal, 1992 . . . . . . . . . . . 128

Table 3.10.8.Spent Amine: Physical Properties . . . . . 130

Table 3.10.9.Spent Stretford Solution: Physical

Properties. . . . . . . . . . . . . . . . . 131

Table 3.10.10.Off-Specification Treating Solution Record

Sampling Locations . . . . . . . . . . . . 131

Table 3.10.11.Characterization Data for Off-Specification

Treating Solution from Sulfur Complex and

H2S Removal. . . . . . . . . . . . . . . . 133

Table 3.11.1.Generation Statistics for Treating Clay from

Clay Filtering, 1992. . . . . . . . . . . . 139

Table 3.11.2.Treating Clay from Clay Filtering: Physical

Properties. . . . . . . . . . . . . . . . . 141

Table 3.11.3.Treating Clay Record Sampling Locations . . 141

Table 3.11.4.Residual Characterization Data for Treating

Clay. . . . . . . . . . . . . . . . . . . . 142

Table 3.12.1.Generation Statistics for Residual Oil Tank

Sludge, 1992. . . . . . . . . . . . . . . . 148

Table 3.12.2.Residual Oil Tank Sludge: Physical

Properties. . . . . . . . . . . . . . . . . 149

Table 3.12.3.Residual Oil Tank Sludge Record Sampling

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Locations . . . . . . . . . . . . . . . . . 150

Table 3.12.4.Residual Oil Tank Sludge Characterization . 152

LIST OF FIGURES Page

Number

Figure 2.1. Geographical Distribution of U.S.

Refineries . . . . . . . . . . . . . . . . 10

Figure 3.1. Simplified Refinery Process Flow Diagram. . 26

Figure 3.2.1.Desalting Process Flow Diagram. . . . . . . 27

Figure 3.3.1.Hydrocracking Process Flow Diagram. . . . . 36

Figure 3.4.1.Isomerization Process Flow Diagram. . . . . 45

Figure 3.5.1.Extraction Process Flow Diagram . . . . . . 59

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. . . . . . . . . . . 86

Figure 3.7.2.Dimersol Polymerization Process Flow

Diagram . . . . . . . . . . . . . . . . . . 87

Figure 3.8.1.Solvent Deasphalting Process Flow Diagram . 95

Figure 3.8.2.Asphalt Oxidation Process Flow Diagram. . . 96

Figure 3.8.3.Supercritical Extraction Process Flow

Diagram . . . . . . . . . . . . . . . . . . 97

Figure 3.9.1.Lube Oil Processing Flow Diagram . . . . . 106

Figure 3.10.1.Amine Sulfur Removal Process Flow Diagram 115

Figure 3.10.2.Claus Sulfur Recovery Process Flow

Diagram . . . . . . . . . . . . . . . . . 116

Figure 3.10.3.SCOT Tail Gas Sulfur Removal Process Flow

Diagram . . . . . . . . . . . . . . . . . 117

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,

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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. Table 1.1.

Petroleum Refining Residuals Identified in the EDF/EPA

Consent Decree.

Listing Residuals

Clarified slurry oil sludge from catalytic cracking

Unleaded storage tank sludge

Crude storage tank sludge

Process sludge from sulfur complex and H2S removal

facilities (sulfur complex sludge)

Sludge from HF alkylation

Sludge from H2SO4 alkylation

Catalyst from catalytic hydrotreating

Catalyst from catalytic reforming

Catalyst and fines from catalytic cracking (FCC

catalyst and FCC fines)

Catalyst from catalytic hydrorefining

Catalyst from H2SO4 alkylation

Catalyst from sulfur complex and H2S removal facilities

(Claus and tail gas treating catalysts)

Off-spec product and fines from thermal processes

(Off-spec coke and fines)

Spent caustic from liquid treating

Study Residuals:

Desalting sludge from crude desalting

Residual oil storage tank sludge

Process sludge from residual upgrading

Catalyst from extraction/isomerization processes

Catalyst from catalytic hydrocracking

Catalyst from polymerization

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Catalyst from HF alkylation

Off-spec product and fines from residual upgrading

Off-spec product from sulfur complex and H2S removal

facilities (Off-spec sulfur)

Off-spec treating solution from sulfur complex and H2S

removal facilities (Spent amine and spent Stretford

solution)

Acid-soluble oil from HF alkylation (ASO)

Treating clay from clay filtering

Treating clay from lube oil processing

Treating clay from the extraction/isomerization process

Treating clay from alkylation

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.

The Clean Air Act's National Ambient Air Quality

Standards (NAAQS), which prescribe limits for

sulfur oxides (SOx), carbon monoxide (CO),

particulates, nitrogen oxides (NOx), volatile

organic compounds (VOCs), and ozone.

The Clean Air Act's NESHAPs for Petroleum

Refineries (40 CFR Part 63, Subpart CC, see 60

FR 43244, August 18, 1995), designed to control

hazardous air pollutants (HAPs).

The Clean Water Act sets specific technology-based

limits and water quality-based standards for

discharges to surface waters and

publically-owned treatment works (POTWs)

including standards designed specifically for

discharges from the petroleum refining industry.

The Toxicity Characteristic, particularly for

benzene, in combination with the F037/F038

sludge listings, has had a significant impact on

the industry's wastewater treatment operations,

forcing closure of many impoundments and

redesign of tank-based treatment systems.

The Land Disposal Restrictions (LDR) Program,

including the ongoing Phase III and IV

development work.

1.3 INDUSTRY STUDY FINDINGS

This document describes EPA's approach to conducting

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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 judgement 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 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

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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

mismanagment scenarios EPA would further evaluate to

ascertain if there were a potential risk:

unlined landfills

residual oil storage tank sludge

process sludge from residual upgrading

catalyst from catalytic hydrocracking

catalyst from polymerization

off-spec product from sulfur complex and H2S removal

facilities (off-spec sulfur)

off-spec treating solution from sulfur complex and H2S

removal facilities (spent amine and spent Stretford

solution)

treating clay from clay filtering

treating clay from lube oil processing

treating clay from the extraction/isomerization process

treating clay from alkylation

unlined surface impoundments

residual oil storage tank sludge

off-spec treating solution from sulfur complex and H2S

removal facilities (spent amine and spent Stretford

solution)

land application not subject to Federal regulations

residual oil storage tank sludge

catalyst from polymerization

off-spec product from sulfur complex and H2S removal

facilities (off-spec sulfur)

treating clay from clay filtering

treating clay from lube oil processing

treating clay from the extraction/isomerization process

treating clay from alkylation

In addition, EPA found that the management practice of

mixing of treating clays with roadbed materials for onsite

use was reported and would merit evaluation as a potential

mismanagement scenario.

Section 2.0 provides an overview of the petroleum

refining industry and EPA's approach to this study. The

fifteen study residuals identified in the consent decree

accounted for approximately 120,000 metric tons in 1992,

compared to over 3.1 million metric tons of listing

residuals generated in 1992. Table 1.2 provides a

description of the 15 study residuals by management practice

and volume generated. The Agency believes that the

management practices reported consist of virtually all of

the plausible management practices to which the residuals

may be subjected. Section 3.0 describes the refinery

processes associated with generating the consent decree

residuals of concern and detailed characterization of each

of the study residuals as required by the consent decree.

2.0 INDUSTRY DESCRIPTION

2.1 PETROLEUM REFINING INDUSTRY PROFILE

In 1992, the U.S. petroleum refining industry consisted

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of 185 refineries (of which 171 were fully active during the

year) owned by 91 corporations. Atmospheric crude oil

distillation capacity totaled 15,120,630 barrels per

calendar day (bpcd) (DOE, 1993). As of January 1, 1996,

U.S. capacity totaled 15,341,000 bpcd, showing little change

in the Nation's refining capacity since the Agency's

baseline year. Figure 2.1 illustrates the distribution of

refineries across the country. Refineries can be classified

in terms of size and complexity of operations. Forty-four

percent of the refineries operating in 1992 processed less

than 50,000 barrels per day of crude, while the 20 largest

companies account for 77 percent of the nation's total

refining capacity.

The simplest refineries use distillation to separate

gasoline or lube oil fractions from crude, leaving the

further refining of their residuum to other refineries or

for use in asphalt. Approximately 18 percent of the U.S.'s

refineries are these simple topping, asphalt, or lube oil

refineries. More sophisticated refineries will have thermal

and/or catalytic cracking capabilities, allowing them to

extract a greater fraction of gasoline blending stocks from

their crude. The largest refineries are often integrated

with chemical plants, and utilize the full range of

catalytic cracking, hydroprocessing, alkylation and thermal

processes to optimize their crude utilization. Section 3.1

describes the major unit operations typically found in

refining operations.

The refining industry has undergone significant

restructuring over the past 15 years. Much of this

restructuring has been in response to the price allocation

programs of the 1970s and industry deregulation in the

1980s. While the total national refining capacity dropped

17 percent since 1980 to 15 million barrels per day, the

number of refineries dropped 45 percent from 311 in 1980 to

approximately 171 active in 1992 (and 169 as of 1/1/96).

Refinery utilization rates over the 1980 to 1992 period rose

from 75 percent to 90 percent. (API, 1993). Very few new

refineries have been constructed in the past decade; the

industry instead tends to focus on expansions of existing

plants.

The facilities closed tended to be smaller, inefficient

refineries. Larger existing facilities with capacities over

100,000 bbl/day have increased production to off-set the

facility closings.

The data presented above indicates that the petroleum

refining industry has been going through a consolidation,

which has resulted in a large decrease in the number of

refineries in the United States, but only a slight decrease

in production. It is expected that this trend will

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

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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.

2.2.1 Site Selection

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EPA's field work activities were focussed on a limited

number of refineries, allowing the Agency to establish

strong lines of communication with the selected facilities,

and maximizing efficiency of information collection. After

considering logistical and budgetary constraints, the Agency

determined that it would limit its field work to 20

refineries.

The Agency defined a site selection procedure that was

used in selecting the 20 site visits from the population of

185 domestic refineries in the continental U.S.. The

objectives of the selection procedure were:

to ensure that the characterization data obtained

from residuals at the 20 selected facilities could

be used to make valid, meaningful statements about

those residuals industry-wide.

to give the Agency first-hand exposure to both large

and small refineries.

to be fair to all domestic refineries.

The Agency chose to select facilities randomly rather

than purposefully. Although a randomly selected group of

refineries did not offer as many sampling opportunities as a

hand-picked group (e.g., focusing on those larger refineries

that generate most of the RCs), the Agency favored random

selection because it did not require subjective input, and

also because it lends itself to statistical analysis, which

is useful in making general statements about the population

of residuals.

The Agency broke the industry into two strata based on

atmospheric distillation capacity and made random selections

from each stratum independently. The high-capacity stratum

(those with a crude capacity of 100,000 bpcd or greater)

contains the top 30 percent of refineries, which together

account for 70 percent of the refining industry's capacity.

The stratification enables the Agency to weigh the selection

toward the larger facilities on the basis that they produce

larger volumes of residuals, and that they offer a larger

number of residual streams per site visit. The Agency chose

to select 12 of the 20 site visits, 60 percent, from the

high-capacity stratum. The smaller facilities had a lower

chance of being selected, but not as low as they would have

if the likelihood of selection was based strictly on size.

The selected facilities are presented in Table 2.1.

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

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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

X. General facility characterization (focusing on

exposure pathway characterization)

XII. Source reduction efforts

XIII.Certification.

The survey was distributed in August 1993 to all

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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 judgement

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.

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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 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.

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.

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

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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.

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,

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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 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.

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Thermal Processes: Thermal cracking uses the

application of heat to reduce high-boiling compounds to

lower-boiling products. Delayed (batch) or fluid

(continuous) coking is essentially high-severity thermal

cracking and is used on very heavy residuum (e.g., vacuum

bottoms) to obtain lower-boiling cracked products.

(Residuum feeds are not amenable to catalytic processes

because of fouling and deactivation.) Products are olefinic

and include gas, naphtha, gas oils, and coke. Visbreaking

is also thermal cracking; its purpose is to decrease the

viscosity of heavy fuel oil so that it can be atomized and

burned at lower temperatures than would otherwise be

necessary. Other processes conducting thermal cracking also

would be designated as thermal processes. Off-spec product

and fines is a listing residual from these processes.

Catalytic Reforming: Straight run naphtha is upgraded

via reforming to improve octane for use as motor gasoline.

Reforming reactions consist of (1) dehydrogenation of

cycloparaffins to form aromatics and (2) cyclization and

dehydrogenation of straight chain aliphatics to form

aromatics. Feeds are hydrotreated to prevent catalyst

poisoning. Operations may be semiregenerative (cyclic),

fully-regenerative, or continuous (moving bed) catalyst

systems. Precious metal catalysts are used in this process.

Spent reforming catalyst is a listing residual.

Polymerization: Polymerization units convert olefins

(e.g., propylene) into higher octane polymers. Two

principal types of polymerization units include fixed-bed

reactors, which typically use solid-supported phosphoric

acid as the catalyst, and Dimersol units, which typically

use liquid organometallic compounds as the catalyst. Spent

polymerization catalyst is a study residual.

Alkylation: Olefins of 3 to 5 carbon atoms (e.g., from

catalytic cracking and coking) react with isobutane (e.g.,

from catalytic cracking) to give high octane products.

Sulfuric (H2SO4) or hydrofluoric (HF) acid act as catalysts.

Spent sulfuric acid, sulfuric acid alkylation sludges, and

HF sludges are listing residuals, while spent HF acid, acid

soluble oil and treating clays are study residuals.

Isomerization: Isomerization converts straight chain

paraffins in gasoline stocks into higher octane isomers.

Isomer and normal paraffins are separated; normal paraffins

are then catalytically isomerized. Precious metal catalysts

are used in this process. Spent catalysts and treating

clays are study residuals from this process.

Extraction: Extraction is a separation process using

differences in solubility to separate, or extract, a

specific group of compounds. A common application of

extraction is the separation of benzene from reformate.

Treating clay is a study residual from this process.

Lube Oil Processing: Vacuum distillates are treated

and refined to produce a variety of lubricants. Wax,

aromatics, and asphalts are removed by unit operations such

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as solvent extraction and hydroprocessing; clay may also be

used. Various additives are used to meet product

specifications for thermal stability, oxidation resistances,

viscosity, pour point, etc. Treating clay is a study

residual from this process.

Residual Upgrading: Vacuum tower distillation bottoms

and other residuum feeds can be upgraded to higher value

products such as higher grade asphalt or feed to catalytic

cracking processes. Residual upgrading includes processes

where asphalt components are separated from gas oil

components by the use of a solvent. It also includes

processes where the asphalt value of the residuum is

upgraded (e.g., by oxidation) prior to sale. Off-spec

product and fines, as well as process sludges, are study

residuals from this category.

Blending and Treating: Various petroleum components

and additives are blended to different product (e.g.,

gasoline) specifications. Clay and caustic may be used to

remove sulfur, improve color, and improve other product

qualities. Spent caustic is a listing residual, while

treating clay is a study residual.

Sulfur Recovery: Some types of crude typically contain

high levels of sulfur, which must be removed at various

points of the refining process. Sulfur compounds are

converted to H2S and are removed by amine scrubbing. The

H2S often is converted to pure sulfur in a Claus plant.

Off-gases from the Claus plant typically are subject to tail

gas treating in a unit such as a SCOT treater for

additional sulfur recovery. Process sludges and spent

catalysts are listing residuals; off-spec product and

off-spec treating solutions are study residuals.

Light Ends (Vapor) Recovery: Valuable light ends from

various processes are recovered and separated.

Fractionation can produce light olefins and isobutane for

alkylation, n-butane for gasoline, and propane for liquid

petroleum gas (LPG). Caustic may be used to remove sulfur

compounds. Spent caustic is a listing residual of concern.

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.

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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 -

300øF to achieve reduced viscosity for better mixing. In

addition, the desalter operates at pressures of at least 40

lb/in2 gauge to reduce vaporization. Intimate mixing is

achieved through a throttling valve or emulsifier orifice

and the oil-water emulsion is then introduced into a gravity

settler. The settler utilizes a high-voltage electrostatic

field to agglomerate water droplets for easier separation.

Following separation, the water phase is discharged from the

unit, carrying salt, minerals, dirt, and other water-soluble

materials with it.

Desalting efficiency can be increased by the addition

of multiple stages, and in some cases acids, caustic, or

other chemicals may be added to promote additional

treatment. A simplified process flow diagram for crude oil

desalting is shown in Figure 3.2.1.

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.

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As with some tank sludges, some facilities remove their

desalting sludge using a vacuum truck or similar slurrying

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.

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 their frequent management in

wastewater treatment systems.

3.2.2.3 Plausible Management

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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

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attract oil and produce emulsions.

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.

3.3 HYDROCRACKING

Petroleum refining hydroprocessing techniques include

hydrocracking, hydrorefining, and hydrotreating.

Hydrorefining and hydrotreating processes and their

respective catalyst residuals are described in the Listing

Background Document for the November 20, 1995 proposed rule.

Hydrocracking processes are similar to hydrotreating and

hydrorefining processes in that they remove organic sulfur

and nitrogen from the process feeds, but differ in that they

also serve to break heavier fraction feeds into lighter

fractions. As refinery crudes have become heavier,

hydrocracking, a more recent process development compared to

long-established conversion processes such as thermal

cracking, has become more widely used. The current trend to

heavier feeds and lighter high-quality feeds causes

hydrocracking to offer advantages to future refining

operations.

In addition, hydrocracking is a versatile process, and

under mild conditions can be utilized for hydrotreating

(typically fractions that need to be saturated to give good

burning quality) and under more severe conditions can be

utilized as a cracker (typically feeds that are too heavy or

too contaminant-laden for catalytic cracking). As a result

of this flexibility, hydrocracking processes can appear in

refinery operations in a number of different places.

3.3.1 Process Description

The process flow for hydrocracking is similar to that

for hydrotreating: the feed is mixed with a hydrogen-rich

gas, pumped to operating pressure and heated, and fed to one

or more catalytic reactors in series. Hydrocracking units

are typically designed with two stages: the first uses a

hydrotreating catalyst to remove nitrogen and heavy

aromatics, while the second stage conducts cracking. The

catalysts for each stage are held in separate vessels.

Organic sulfur and nitrogen are converted to H2S and NH3,

and some unsaturated olefins or aromatics are saturated or

cracked to form lighter compounds. In addition, heavy metal

contaminants are adsorbed onto the catalyst. Following the

reactor, the effluent is separated via stabilization and

fractionation steps into its various fractions. There are

two major differences between hydrocracking and

hydrotreating: 1) operating pressures are much higher,

in the range from 2,000 - 3,000 lb/in2 gauge, and 2)

hydrogen consumption is much higher, in the range from

(1,200 - 1,600 SCF/barrel of feed), dependent on the feed.

The feed is generally a heavy gas oil or heavier stream.

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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 below.

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) Catnap

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.

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%)

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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 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.

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

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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 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.

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

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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.

3.4 ISOMERIZATION

The purpose of isomerization is to increase the

refinery's production of high octane, low aromatic gasoline.

Gasoline with low benzene and aromatics is newly specified

in the California market and is expected to be adopted by

other states in the future (Oil & Gas Journal, 1995).

3.4.1 Isomerization Process Description

Principal applications of isomerization at refineries

are naphtha isomerization, which produces a gasoline

blending component, and butane isomerization, which produces

isobutane feed for the alkylation unit. Figure 3.4.1

depicts a generic process flow diagram for isomerization.

Based on the results of the RCRA 3007 questionnaire, 65

facilities reported having isomerization units, distributed

as follows (some facilities have more than one type of

isomerization unit):

47 facilities have naphtha isomerization units

15 facilities have butane isomerization units

7 facilities have other types of isomerization

units.

3.4.1.1 Naphtha Isomerization

Gasoline, or naphtha, is generated throughout the

refinery and consists of a mix of C5 and higher hydrocarbons

in straight, branched, or ring configuration. Naphtha

isomerization converts the straight chains to branched,

significantly raising their octane number. A common

source of such "low grade" naphtha is light straight run,

which consists of the lighter fraction (C5/C6) of naphtha

from atmospheric crude distillation. The reduction of lead

in gasoline in the 1970s increased the demand for

isomerization technology; prior to that time naphtha

isomerization was not widely used (Meyers, 1986).

As found from the RCRA 3007 questionnaire results,

the most common naphtha isomerization processes presently

used in the industry are UOP's Penex process and Union

Carbide's Total Isomerization Process (TIP). Other licensed

processes used include the Union Carbide Hysomer process and

the BP Isomerization process. In these four processes,

naphtha is combined with hydrogen and flows through one or

two fixed bed reactors in series; the catalyst consists of a

precious metal catalyst on a support (non-precious metal

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catalysts are rarely, if ever, used for naphtha

isomerization). The reactor effluent is sent to a series of

columns where hydrogen and fuel gas are separated from the

isomerate product. The isomerate, having a significantly

higher octane number than the light straight run feed, is

charged to the gasoline blending pool. Although the

isomerization reaction is not a net consumer or producer of

hydrogen, the presence of hydrogen prevents coking and

subsequent deactivation of the catalyst (Meyers, 1986).

From a solid waste generation perspective, the

principal differences between the various processes relate

to the catalyst used; this will in turn affect the feed

pretreatment steps and spent catalyst characterization. The

two principal types of catalyst identified in the industry

are: (1) platinum on zeolite, which operates at temperatures

above 200øC, and (2) platinum chloride on alumina, which

operates at temperatures below 200øC. The higher

temperatures are characteristic of the TIP and Hysomer

processes, while the lower temperatures are characteristic

of the Penex process and the BP process. The effect of

these two different precious metal catalysts on the process

are as follows:

DIOXIN FORMATION. To maintain an environment of

hydrogen chloride in the reactor required for

catalyst activity, the platinum chloride

catalyst requires a small but continuous

addition of a chlorinated organic compound

(e.g., carbon tetrachloride) to the feed.

Although no oxygen is present during operating

conditions, the conditions encountered during

unit turnaround and catalyst removal (see

Section 3.4.3) could result in dioxin formation.

During sampling and analysis, the Agency tested

for dioxin and the results are presented in

Table 3.4.4.

Unlike reforming unit catalyst (a platinum

catalyst discussed in the Listing Background

Document), the isomerization unit catalyst

apparently does not undergo in situ

regeneration. One refinery stated that they do

not conduct regeneration because coke does not

form and contaminate the catalyst (making

regeneration unnecessary), and design

information for these units does not mention in

situ regeneration.

FEED PRETREATMENT. The platinum chloride

catalyst, operating at the lower temperatures,

provides better conversion of paraffins to

isomers. However, this catalyst is susceptible

to water, sulfur, and nitrogen as catalyst

poisons (Meyers, 1986). To combat these

contaminants, the feed is commonly desulfurized

over a cobalt/molybdenum or similar catalyst and

generated H2S is removed prior to the

isomerization reactor. To further protect

against sulfur poisoning, some processes include

a guard column between the hydrodesulfurization

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reactor and the isomerization reactor to remove

additional sulfur-containing compounds. Rather

than consisting of Co/Mo (like many

hydrotreating catalysts), this guard column

often consists of zinc oxide, nickel on

alumina, or copper oxide.

To remove water from the desulfurized naphtha, the

hydrocarbon feed is typically dried using

molecular sieve. When the molecular sieve is

saturated, it is taken off-line for water

desorption while the hydrocarbon is rerouted to

a parallel molecular sieve vessel. In a similar

way, water is removed from the hydrogen feed.

Certain molecular sieves can remove both sulfur

compounds and water from hydrogen or hydrocarbon

feeds.

The platinum on zeolite catalyst is less

susceptible to poisoning by these contaminants

and reportedly requires none, or significantly

less, pretreatment (Meyers, 1986).

Another difference in operating practices found among

individual refineries is product stream recycling to

increase yield and octane. These qualities can be increased

by (1) recycling the paraffins to the reactor following

their separation from the isomerized product, or (2)

separating (and effectively concentrating) low octane

paraffins from other high octane feed components such as

isomers and aromatics. These steps can be performed using

either conventional fractionation or an adsorbent. In the

latter case, the normal paraffins are adsorbed onto zeolite

or another adsorbent while the isomers pass through. The

paraffins are desorbed and introduced as isomerization

reactor feed, while the isomers bypass the isomerization

reactor and are introduced to a post reactor stabilizer.

Not all refineries conduct such separation, although

separation of the feed or product using molecular sieve is

integral to the Union Carbide Total Isomerization Process.

3.4.1.2 Butane Isomerization

The purpose of butane isomerization is to generate feed

material for a facility's alkylation or MTBE production

unit; alkylation unit feed includes isobutane and olefins,

while the raw materials used in making MTBE are isobutylene

and methanol. Butane isomerization is a much older process

than naphtha isomerization, having been used in refineries

since World War II. Presently, the most prevalent method of

producing isobutane from n-butane is the UOP Butamer

process, similar in many ways to the isomerization of

naphtha over platinum chloride catalyst. In the Butamer

process, normal butane, generated from throughout the

refinery and separated from other butanes by distillation,

is combined with hydrogen and a chlorinated organic

compound. The hydrogen is used to suppress the

polymerization of olefin intermediates, while the chlorine

source is used to maintain catalyst activity. The feed

flows through one or two fixed bed reactors in series,

containing platinum chloride on alumina catalyst. The

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isobutane product is recovered and used as alkylation unit

feed. Butane isomerization takes place at lower

temperatures than naphtha isomerization.

Like platinum chloride catalyst used in naphtha

isomerization, the Butamer catalyst is poisoned by water and

sulfur, as well as fluoride (Meyers, 1986). These compounds

are removed from the hydrogen and hydrocarbon feed by

molecular sieve.

Although the Butamer process and others using platinum

chloride on alumina as a catalyst dominate the industry,

other technologies are also used. Three facilities

conducting butane isomerization do not use platinum

catalysts. Instead, the catalyst is aluminum

chloride/hydrochloric acid and generates an almost

continuous spent catalyst waste stream in slurry or sludge

form.

3.4.1.3 Other Isomerization Processes

Seven facilities reported using isomerization for

purposes other than naphtha or butane isomerization. Such

applications demonstrate the integration of petroleum

refining and chemical production at many refineries. Some

of these processes more closely represent petrochemical

production than refining processes because they are not

widely reported by refineries as a refining step, are not

used for fuel production, and produce commodity chemicals.

The processes reported by these seven facilities can be

classified into three areas:

Xylene Isomerization Four facilities report

processes to convert xylene isomers (e.g., from

an extraction process) to p- and/or o-xylene.

Unlike the naphtha and butane isomerization

units described above, the catalyst is not

precious metal. The xylene products are sold.

Cyclohexane Isomerization Two facilities produce

cyclohexane from raw materials that include

benzene and hydrogen. Unlike the naphtha and

butane isomerization units described above, the

catalyst is not precious metal.

Butylene Isomerization Two facilities produce

butylene from various C4 olefins. Butylene is

used for feed to the alkylation unit. A

precious metal (palladium) catalyst is used.

3.4.2 Isomerization Catalyst

3.4.2.1 Description

As discussed in Section 3.4.2, the most prevalent

catalyst used for both butane and naphtha isomerization is

platinum or platinum chloride on alumina or zeolite. When

the catalyst loses activity, it is removed from the reactor

and replaced with fresh catalyst. Prior to removal, the

reactor may be swept to remove hydrocarbons from the

catalyst. These preparation steps can include one or more

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of the following:

Nitrogen sweep (to remove hydrocarbon)

Oxygen sweep (to burn hydrocarbon)

Steam stripping (to remove hydrocarbon).

This procedure of catalyst preparation, removal, and

replacement is relatively lengthy (typically one week or

more) and requires the unit, or at least the reactor, to be

shut down such that no hydrocarbon is processed during the

time of catalyst replacement.

There are a handful of isomerization processes used at

domestic refineries that do not use platinum or platinum

chloride catalyst. At these facilities, spent catalyst is

generated in one of the following two methods:

A method similar to the generation of spent

platinum/platinum chloride catalyst described

above. Fixed-bed processes are used in both

palladium and non-precious metal catalyst

applications and spent solid catalyst is

infrequently removed.

A method where catalyst is removed from the

fixed-bed reactor frequently (up to once a day)

in liquid/semi-solid form, presumably with

little to no disruption of the process. This

method is used only for one process which uses

aluminum chloride/hydrochloric acid catalyst.

Another type of catalyst seen in conjunction with an

isomerization unit is desulfurization catalyst. In many

naphtha isomerization processes, the feed typically contains

high levels of mercaptans which are converted to H2S over a

non-precious metal catalyst, such as cobalt/molybdenum.

Such catalysts were discussed in the Listing Background

Document under the broad name of "hydrotreating catalysts"

and will not be discussed here.

3.4.2.2 Generation and Management

The spent catalyst is vacuumed or gravity dumped from

the reactors. Based on information from site visits, most

refineries place the material directly into closed

containers such as 55-gallon drums, flow-bins, or 1 cubic

yard "supersacks." The frequency of generation is typically

between 2 and 10 years, with a small number of facilities

generating a slurry/sludge continuously. In 1992, only one

facility reported classifying this residual as RCRA

hazardous (this facility classified 2 MT as D001). In

other years, some facilities reported that this residual

carried a RCRA hazardous waste code of D018 (TCLP benzene).

Eighteen facilities reported generating a total

quantity of 337 MT of this residual in 1992, according to

the 1992 RCRA 3007 Questionnaire. The questionnaire

reported that 65 facilities have isomerization units and

thus are likely to generate spent isomerization catalyst at

some time. Due to the infrequent generation of this

residual, not all of these 65 facilities generated spent

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catalyst in 1992. However, there was no reason to expect

that 1992 would not be a typical year with regard to this

residual's generation and management.

Residuals were assigned to be "spent isomerization

catalyst" if they were assigned a residual identification

code of "spent solid catalyst" and were generated from a

process identified as an isomerization unit. These

correspond to residual code 03-A in Section VII.A of the

questionnaire and process code 10 in Section IV.C of the

questionnaire. The small volume of continuously generated

residuals (discussed in Section 3.4.3.1) were typically

omitted from these statistics, because they were most often

characterized as sludges. However, as stated in Section

3.4.1, some nonprecious metal catalysts are also used in

fixed bed processes and are included in these statistics.

Table 3.4.1 provides a description of the 1992 management

practices, quantity generated, number of streams reported,

number of streams not reporting volumes (data requested was

unavailable and facilities were not required to generate

it), total and average volumes.

3.2.2.3 Plausible Management

EPA believes that most of the plausible management

practices for this residual were reported in the 1992 RCRA

3007 Survey, as summarized above in Table 3.4.1. The Agency

assessed information reported for other years but no

additional management practices were reported for this

residual. In addition, EPA compared the management practice

reported for isomerization catalysts to those reported for

reforming catalysts (a listing residual described in the

Listing Background Document) based on expected similarities.

The vast majority of both wastes are reclaimed due to their

precious metal content.

3.4.2.4 Characterization

Two sources of residual characterization were developed

during the industry study:

Table 3.4.2 summarizes the physical properties of

the spent catalyst as reported in Section VII.A

of the 3007 survey.

Four record samples of spent isomerization

catalyst were collected and analyzed by EPA.

These spent catalysts represent the majority of

processes used by the industry. Sampling

information is summarized in Table 3.4.3.

The collected samples are expected to be representative

of processes using platinum chloride catalyst. Other

processes use platinum catalyst or (rarely) non-precious

metal catalysts. Because similar feeds are processed by

most isomerization processes, these spent catalysts are

expected to display similar characteristics, with the

following exceptions: (1) spent platinum chloride catalysts

(and possibly aluminum chloride/hydrogen chloride catalysts)

are the only catalysts expected to contain dioxins, because

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of the presence of chlorine in the process, (2) platinum

chloride catalysts require cleaner feed (i.e., water and

sulfur are catalyst poisons), and thus concentrations of

some contaminants may be greater in spent catalysts from

processes not using platinum chloride catalysts.

All four record samples were analyzed for total and

TCLP levels of volatiles, semivolatiles, metals, and

reactivity (pyrophoricity). Three samples were analyzed for

total levels of dioxins/furans. Three of the four samples

were found to exhibit the toxicity characteristic for

benzene (i.e., the level of benzene in these samples' TCLP

extracts exceeded the corresponding regulatory level). A

summary of the analytical results is presented in Table

3.4.4. Only constituents detected in at least one sample

are shown in this table.

3.4.2.5 Source Reduction

As in the case of the hydrocracking catalyst, source

reduction methods are those that extend the life of the

catalyst. Currently, recycling of the spent catalyst by

sending to metals reclamation is a common practice since the

catalyst is platinum.

3.4.3 Isomerization Treating Clay

3.4.3.1 Description

Not all facilities with isomerization units use

"treating clay," or adsorbents. However, solid adsorbents

can be used in three places in the isomerization process:

Hydrocarbon feed purification. Processes using

platinum chloride catalysts require a purified

feed. Both spent molecular sieve (for drying)

and spent metal-alumina (for sulfur removal) are

generated.

Hydrogen feed purification. Processes using

platinum chloride catalysts require dry hydrogen

gas. Spent molecular sieve is generated.

Paraffin separation of the feed or product.

Various types of processes use adsorbents for

paraffin separation. Molecular sieve is the

most common adsorbent for this application.

All of these adsorbents go through adsorption/desorption

cycles. Over time, the adsorbent loses its capacity or

efficiency and is removed from the vessel and replaced with

fresh adsorbent. Prior to removal, the vessel can be swept

to remove light hydrocarbons and hydrogen sulfide from the

vessel. Typically, processes use adsorbent beds in parallel

so that one bed can be on-line (adsorption mode) while the

second is off-line for desorption or replacement.

3.4.3.2 Generation and Management

When spent, adsorbents from isomerization are vacuumed

or gravity dumped from the vessels. Interim storage can

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include 55-gallon drums, flow-bins, dumpsters, or piles.

The frequency of generation is highly dependent on the

generating process: isomerization adsorbents are typically

generated approximately every 5 years, while extraction clay

is typically generated once per year or less. According to

questionnaire results, 6 facilities reported classifying

39.5 MT of this residual as RCRA hazardous in 1992 (most

typically as D018, D001, and D006). This is consistent with

reporting for other years.

Twenty-two facilities reported generating a total

quantity of approximately 597 MT of this residual in 1992,

according to the 1992 RCRA 3007 Questionnaire. The

questionnaire reported that 65 facilities have isomerization

units. However, not all of these facilities use clay,

molecular sieve, or other adsorbents in their process; 25

percent of facilities with isomerization units did not

report generating any clay residual for their process in any

year, indicating either that clay is either not used, has

not yet been replaced, or is generated so infrequently that

respondents could not recall when, if ever, the clay was

last replaced. In addition, these adsorbents may be

replaced less often than once per year or not in 1992,

particularly those associated with the isomerization

process. However, there was no reason to expect that 1992

would not be a typical year with regard to this residual's

generation and management.

Residuals were assigned to be "spent clay from

isomerization" if they were assigned a residual

identification code of "spent sorbent" and were generated

from a process identified as an isomerization or extraction

unit. These correspond to residual code 07 in Section VII.A

of the questionnaire and process code 10 in Section IV.C of

the questionnaire. Table 3.4.5 provides a description of

the 1992 management practices, quantity generated, number of

streams reported, number of streams not reporting volumes

(data requested was unavailable and facilities were not

required to generate it), total and average volumes.

3.4.3.3 Plausible Management

EPA believes that most of the plausible management

practices for this residual were reported in the 1992 RCRA

3007 Survey, as summarized above in Table 3.4.5. The Agency

gathered information from other years but no additional

management practices were reported for this residual. In

addition, EPA compared the management practice reported for

isomerization treating clay to those reported for treating

clays from extraction, alkylation, and lube oil based on

expected similarities. Land treatment was reported for

these other types of treating clays, therefore it is likely

that land treatment is a plausible management practice for

clays from isomerization.

3.4.3.4 Characterization

Two sources of residual characterization were developed

during the industry study:

Table 3.4.6 summarizes the physical properties of

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the spent adsorbents as reported in Section

VII.A of the 3007 survey.

One record sample of spent adsorbents from

isomerization were collected and analyzed by

EPA. The isomerization treating clay was

categorized with the extraction clay in the

consent decree, therefore, the sampling

information is summarized with the extraction

clay in Table 3.5.4.

The one record sample was analyzed for total and TCLP

levels of volatiles, semivolatiles, and metals, and

ignitability. The sample was not found to exhibit a

hazardous waste characteristic. A summary of the results is

presented in Table 3.5.4. Only constituents detected in at

least one sample are shown in this table.

3.4.3.5 Source Reduction

Treating clay for isomerization is generally used as a

method of prolonging the life of the catalyst or for product

polishing. Because they are used as a source reduction

technique for other residuals, no source reduction methods

for the clays were found.

3.5 EXTRACTION

Extraction processes separate more valuable chemical

mixtures from a mixed aromatic and paraffinic stream. At

refineries, extraction processes most commonly fall into two

types: (1) "heavy end" extraction, commonly used in lube oil

manufacture and deasphalting operations to upgrade and

further process gas oils, and (2) gasoline component

extraction, commonly used to separate some of the more

valuable aromatics from naphtha. "Heavy end" extraction is

discussed with other residual upgrading technologies in

Section 3.8 of this document. The gasoline component

extraction processes are discussed here.

3.5.1 Extraction Process Description

Thirty facilities reported using gasoline component

extraction processes in their refineries. By far the most

common type of gasoline component extraction process

conducted at refineries, according to the RCRA 3007

questionnaire, is the recovery of benzene, toluene, and

mixed xylenes from reformate (i.e., the product from a

catalytic reforming unit) for sales or further processing.

Most extraction units actually consist of two sections in

series: an extraction section, which separates aromatics

from non-aromatics using continuous liquid-liquid

extraction, and a distillation section, which separates the

various aromatic compounds from each other in a series of

fractionation towers. Figure 3.5.1 depicts a generic

extraction process flow diagram.

In the extraction section, the charge is

countercurrently contacted with a solvent. The

solvent is most commonly sulfolane, C4H8SO2, or

tetraethylene glycol, O(CH2CH2OCH2CH2OH)2, although a small

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number of facilities use diglycol amine, O(CCO)CCN. The

raffinate is separated from the aromatic-rich solvent in a

tower. The aromatic-poor raffinate is water-washed to

remove solvent and used elsewhere in the refinery. The

aromatic-rich extract is also water-washed to remove solvent

and the aromatics sent to the distillation section for

separation into benzene, toluene, and xylenes.

In the distillation section, the aromatic extract is

distilled to remove benzene from the top of the column; the

bottoms are sent to the next column. In successive columns,

toluene and finally xylene are removed. The bottoms from

the xylene tower (C9 aromatics) are sent to gasoline

blending. Some facilities omit the distillation section

altogether, using their extraction unit simply to produce

low and high octane blending stocks.

To decrease the unit's loading, the feed can be

separated prior to extraction so that only the most

desirable fractions, such as C6 to C8, are upgraded. This

eliminates a final distillation step and eliminates a heavy

aromatic stream as a product from the benzene-toluene-xylene

separation.

Several other gasoline component extraction processes

are each reported by only 1 or 2 refineries in the industry.

Other refineries may use these processes, but did not report

them because of their resemblance to petrochemical

operations of solvent manufacture, etc., which some

refineries considered out of the survey scope. As a

result, the database may not accurately reflect the

incidence of these processes. These processes are as

follows:

The UOP Parex process separates p-xylene from

mixed C8 aromatics. C8 feed is injected

countercurrently to a bed of solid adsorbent,

which adsorbs p-xylene. The bed is then desorbed

and the p-xylene is recovered in the extract for

use in petrochemical production. This process

is typically associated with a xylene

isomerization process (Meyers, 1986). This

arrangement differs from the overwhelming

majority of extraction processes, which are

associated with reforming processes.

The Union Carbide IsoSiv process separates normal

C6-C8 paraffins from the other branched and ring

compounds present in light straight run. In

this process, the paraffins are adsorbed onto a

fixed bed of molecular sieve. The paraffins are

desorbed and used as petrochemical feedstock,

solvents, etc., while the branched and ring

compounds are used for gasoline blending

(Meyers, 1986).

One facility uses a process similar to the

gasoline component extraction process described

above, but with a slightly heavier feed.

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Heavy naphtha is fed to a fixed bed of silica gel.

Aromatics are adsorbed while paraffins pass

through. When saturated, the bed is desorbed

with benzene and the product distilled to form

various solvents. No other adsorbents are used

in the process.

3.5.2 Extraction Treating Clay

3.5.2.1. Description

Wastes generated from the reformate extraction

processes include the following:

"Fuel side:" Treating clay is used to remove

impurities from the hydrocarbon following

extraction; the most common application is the

filtering of the aromatic fraction prior to

benzene distillation (to keep impurities out of

the downstream fractions), although a small

number of facilities use the clay to filter the

benzene product stream only. The purpose of

the clay is to remove olefins, suspended

solids, and trace amount of solvent by a

combination of adsorption and catalytic

processes. A few facilities also treat the

raffinate (non-aromatic) stream with clay.

Many facilities did not report a clay treating

step anywhere in their reformate extraction

process. For these facilities, clay treating

is evidently not required to achieve the target

product limits.

"Solvent side:" Various treatment methods are

used to remove impurities such as polymers and

salts from the lean solvent. A slip stream of

lean solvent is processed using ion-exchange,

sock filters, carbon adsorption, or

regeneration. This is similar to the methods

used to treat amine in sulfur-removal systems.

An intermittent stream of spent solvent can

sometimes be generated.

Only the "fuel side" residuals are discussed and evaluated

in Section 3.4.4. The "solvent side" residuals are

generally classified as miscellaneous sludges in the

database and their volumes were not tabulated in Table 3.4.5

(below).

As stated above, reformate extraction is the most

common type of gasoline component extraction process, but

the small number of other processes also generate spent

adsorbents. These processes are unlike reformate extraction

because the adsorbent is used for aromatic separation (in

reformate extraction, clay treatment occurs following

aromatic extraction). In these processes, spent adsorbent

is also periodically generated, although generally less

frequently so than in the reformate extraction process.

These materials were included in the statistics presented in

Table 3.4.4.

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3.5.2.2 Generation and Management

When spent, adsorbents from extraction are vacuumed or

gravity dumped from the vessels. Interim storage can

include 55-gallon drums, flow-bins, dumpsters, or piles.

The frequency of generation is highly dependent on the

generating process: extraction clay is typically generated

once per year or less. According to questionnaire results,

2 facilities reported classifying 81.3 MT of this residual

as RCRA hazardous in 1992 (as D018). This is consistent

with reporting for other years.

Fifteen facilities reported generating a total quantity

of approximately 1900 MT of this residual in 1992, according

to the 1992 RCRA 3007 Questionnaire. The questionnaire

reported that 30 facilities have extraction units. However,

not all of these facilities use clay, molecular sieve, or

other adsorbents in their process; 33 percent of facilities

with extraction units did not report generating any clay

residual for their process in any year, indicating either

that clay is either not used, has not yet bee replaced, or

is generated so infrequently that respondents could not

recall when, if ever, the clay was last replaced. However,

there was no reason to expect that 1992 would not be a

typical year with regard to this residual's generation

and management. Extraction clays are generated more

frequently and in greater quantity than isomerization clays.

Residuals were assigned to be "spent clay from

extraction" if they were assigned a residual identification

code of "spent sorbent" and were generated from a process

identified as an isomerization or extraction unit. These

correspond to residual code 07 in Section VII.A and process

codes 12 in Section IV.C of the survey. Table 3.5.1

provides a description of the 1992 management practices,

quantity generated, number of streams reported, number of

streams not reporting volumes (data requested was

unavailable and facilities were not required to generate

it), total and average volumes.

3.5.2.3 Plausible Management

EPA believes that most of the plausible management

practices for this residual were reported in the 1992 RCRA

3007 Survey, as summarized above in Table 3.5.1. The Agency

gathered information suggesting that "offsite land

treatment" (95 MT) was used in other years. This practice

is comparable to the practice reported for 1992 (i.e.,

onsite land treatment). In addition, EPA compared the

management practice reported for extraction treating clay to

those reported for treating clays from isomerization,

alkylation, and lube oil based on expected similarities. No

additional management practices were reported.

3.5.2.4 Characterization

Two sources of residual characterization were developed

during the industry study:

Table 3.5.2 summarizes the physical properties of

the spent adsorbents as reported in Section

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VII.A of the 3007 survey.

One record sample of spent adsorbents from

extraction was collected and analyzed by EPA.

The sampling information is summarized in Table

3.5.3.

The record sample was analyzed for total and TCLP

levels of volatiles, semivolatiles, and metals, and

ignitability. It was not found to exhibit a hazardous waste

characteristic. A summary of the results is presented in

Table 3.5.4. Only constituents detected in at least one

sample are shown in this table. This residual was

categorized with isomerization clay in the consent decree,

and the characterization information for both residuals is

presented in Table 3.5.4.

3.5.2.5 Source Reduction

Treating clay for extraction is generally used as a

method of prolonging the life of the catalyst or for product

polishing. Because they are used as a source reduction

technique for other residuals, no source reduction methods

for the clays were found.

3.6 ALKYLATION

The petroleum refining industry uses both hydrofluoric

and sulfuric acid catalyzed alkylation processes to form

high octane products. DOE reported that 103 facilities

operated almost 1.1 million BPSD of alkylation capacity; 49

facilities used sulfuric acid and 59 used HF. While the

general chemistry of these processes is the same, the HF

process includes a closed loop and integral recycling step

for the HF acid, while the sulfuric acid process requires

a separate acid regeneration process, which generally occurs

off site. Study residuals are generated from both

alkylation processes.

3.6.1 Sulfuric Acid Alkylation Process Description

In the sulfuric acid alkylation process, olefin and

isobutane gases are contacted over concentrated sulfuric

acid (H2SO4) catalyst to synthesize alkylates for

octane-boosting. The reaction products are separated by

distillation and scrubbed with caustic. Alkylate product

has a Research Octane Number in the range of 92 to 99.

Figure 3.6.1 provides a generic process flow diagram for

H2SO4 alkylation.

The olefin stream is mixed with isobutane and H2SO4 in

the reactor. To prevent polymerization and to obtain a

higher quality yield, temperatures for the H2SO4 catalyzed

reaction are kept between 40 and 50øF (McKetta, 1992).

Since the reactions are carried out below atmospheric

temperatures during most of the year, refrigeration is

required. Pressures are maintained so all reaction streams

are in their liquid form. The streams are mixed well during

their long residence time in the reactor to allow optimum

reaction to occur.

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The hydrocarbon/acid mixture then moves to the acid

separator, where it is allowed to settle and separate. The

hydrocarbons are drawn off the top and sent to a caustic

wash to neutralize any remaining trace acid. The acid is

drawn from the bottom and recycled back to the reactor. A

portion of the acid catalyst is continuously bled and

replaced with fresh acid to maintain the reactor's acid

concentration at around 90 percent. This spent H2SO4 was a

listing residual of concern.

In the fractionator, the hydrocarbon streams are

separated into the alkylate and saturated gases. The

isobutane is recycled back into the reactor as feed. Light

end products may be filtered with sorbents to remove trace

H2SO4 acid, caustic or water. The sorbents (e.g., treating

clays) are study residuals of concern.

Some facilities have neutralization tanks (in and above

ground), referred to as pits, which neutralize spent caustic

and any acid generated from spills prior to discharge to the

WWTP, serving as surge tanks. Neutralizing agents (sodium,

calcium, potassium hydroxides) are selected by the

refineries. If necessary, the influent to the pit is

neutralized and, depending on the neutralizing agent, the

precipitated salts form a sludge. This sludge was also a

listing residual of concern. Sludge may also be generated

in process line junction boxes, in the spent H2SO4 holding

tank, and during turnaround. However, due to the aqueous

solubility of sodium, calcium, and potassium sulfates,

sludge generation rates are relatively low and the majority

of neutralization salts (e.g., sodium sulfate) are

solubilized and discharged to the WWTP.

3.6.2 Hydrofluoric Acid Alkylation Process Description

Hydrofluoric acid alkylation is very similar to the

H2SO4 alkylation process. In the hydrofluoric acid

alkylation process, olefin and isobutane gases are contacted

over hydrofluoric acid (HF) catalyst to synthesize alkylates

for octane-boosting. The reaction products are separated by

distillation and scrubbed with caustic. Alkylate product

has a research octane number (RON) in the range of 92 to 99.

Because it is clean burning and contributes to reduced

emissions, alkylate is a highly valued component in premium

and reformulated gasolines. The HF process differs from the

H2SO4 alkylation in that the HF catalyst is managed in a

closed-loop process, never leaving the unit for replacement

or regeneration. Figure 3.6.2 provides a generic process

flow diagram for HF alkylation.

The olefin stream is mixed with the isobutane and HF in

the reactor. To prevent polymerization and to receive a

higher quality yield, temperatures for the HF catalyzed

reaction are maintained at approximately 100øF. Pressures

are kept so all reaction streams are in their liquid form

(usually 85 to 120 psi). The streams are mixed well in the

reactor to allow optimum reaction to occur.

The hydrocarbon/acid mixture then moves to the settler,

where it is allowed to settle and phase separate. The

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hydrocarbons are drawn off the top and sent to a

fractionator. The acid is drawn from the bottom and

recycled back to the reactor. A slip stream of acid is sent

to an acid regenerator where distillation separates the HF

acid from by-product contaminants. The HF acid from the

regenerator is recycled back to the reactor. Fresh acid is

added to replace acid losses at a rate of about 500 pounds

per day per 5,000 BPSD alkylation unit capacity (a small to

medium size unit).

A residual of high molecular-weight reaction

by-products dissolves in the HF acid catalyst and lowers its

effectiveness. To maintain the catalyst activity, a slip

stream of catalyst is distilled, leaving the by-product,

acid soluble oil (ASO), as a residue. The ASO is charged

to a decanting vessel where an aqueous phase settles out.

The aqueous phase, an azeotropic mixture of HF acid and

water, is referred to as constant boiling mixture (CBM).

The ASO is scrubbed with potassium hydroxide (KOH) to remove

trace amounts of HF and either recycled, sold as product

(e.g., residual fuel), or burned in the unit's boiler. The

CBM is sent to the neutralization tank. In some cases, the

ASO from the regenerator is sent directly to the

neutralization tank. The ASO is a residual of concern for

the petroleum refining study.

A series of fractionators distills the product streams

from the reactor into the alkylate, saturated gases, and HF

acid. Isobutane and HF are recycled back into the reactor

as feed.

The main fractionator overhead is charged to the

depropanizer and debutanizer, where high-purity propane and

butane are produced. The propane and butane are then passed

through the alumina treater for HF removal. Once

catalytically defluorinated, they are KOH-treated and sent

to LPG storage.

As HF is neutralized by aqueous KOH, soluble potassium

fluoride (KF) is produced and the caustic is eventually

depleted. Some facilities employ KOH regeneration.

Periodically some of the KF-containing neutralizing solution

is withdrawn to the KOH regenerator. In this vessel KF

reacts with a lime slurry to produce insoluble calcium

fluoride (CaF2) and thereby regenerates KF to KOH. The

regenerated KOH is then returned to the system, and the

solid CaF2 is routed to the neutralizing tank. The KF, at

facilities that do not have a regenerator, is sent directly

to the neutralizing tank, where it is reacted with lime to

form a sludge.

Spent caustic, KOH scrubbers, acidic waters from acid

sewers and, in some cases, CBM are charged to in-ground

neutralization tanks (referred to by industry as pits),

which neutralize effluent to the WWTP. Neutralizing

controls fluoride levels to the WWTP. Neutralizing agents

(sodium, calcium, and potassium hydroxide) are selected

based on the refineries' WWTP permits. Effluent to the pit

is neutralized, generally with lime, which forms a sludge

(calcium fluoride) that collects on the bottom of the tank.

This sludge was a listing residual of concern.

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HF acid is an extremely corrosive and toxic chemical.

Refineries go to great lengths to protect their personnel

from HF contact. Prior to entrance to an HF alkylation

unit, personnel must have special training and wear various

levels of personal protective clothing (depending upon the

work to be performed). The unit is generally cordoned off

and marked as an HF hazard area. Valves, flanges, and any

place where leaks can occur are painted with a special paint

that will change colors when contacted with HF. The units

are continuously monitored and alarms are activated if an HF

leak is detected.

3.6.3 Spent Treating Clay from Alkylation

3.6.3.1 Description

Treating clay from alkylation predominantly includes

(1) molecular sieves used for drying feed and (2) alumina

used for removing fluorinated compounds from the product.

Both are applications in HF alkylation; clays are little

used in sulfuric acid alkylation. Specifically, the

industry reported 83 treating clay residuals from alkylation

in 1992, accounting for 2,890 metric tons of residuals.

Only 7 of these residuals (143 metric tons) were from

sulfuric acid alkylation processes.

After fractionation, products may be passed through a

filter filled with sorbents (referred to as treating clay)

to remove trace amounts of acid, caustic, or water.

Sorbents typically used in this service include alumina,

molecular sieve, sand, and salt.

Treating clay becomes spent when breakthrough of H2SO4

or HF acid, caustic, or water occurs. Depending on the type

of clay and the type of service, breakthrough can occur

anywhere between 2 months and 5 years (e.g., alumina in HF

service is typically 2 months and salt treaters can be as

long as 5 years). Prior to removal the clay may undergo one

of the following in situ treatments:

Nitrogen sweep

Propane sweep

Steam stripping

Methane sweep

Following removal, the spent clay is placed in closed

containers and is typically sent to an offsite landfill.

Certain types of treating clay, such as alumina, are more

amenable to recycling and may be sent offsite to a smelter

or a cement kiln to be used as process feeds.

In 1992, less than 2 percent of the volume of spent

treating clay from alkylation was managed as hazardous, with

one residual reported to be D004, and three others reported

generically to be managed as hazardous (i.e., no specific

codes were reported).

3.6.3.2 Generation and Management

The RCRA 3007 Survey responses indicated 2,895 MT of

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spent treating clay were generated in 1992. Residuals were

assigned to be "treating clay from alkylation" if they were

assigned a residual identification code of "spent sorbent"

and was generated from a process identified as a sulfuric

acid or HF alkylation unit. This corresponds to residual

code "07" in Section VII.1 and process codes "09-A" or

"09-B" in Section IV-1.C of the questionnaire. Due to the

frequent generation of this residual, not all 103 facilities

generated spent treating clay in 1992. However, there was

no reason to expect that 1992 would not be a typical year

with regard to this residual's generation and management.

Table 3.6.1 provides a description of the total quantity

generated, number of streams not reporting volumes (data

requested was unavailable and facilities were not required

to generate it), total and average volumes.

3.6.3.3 Plausible Management

EPA believes that most of the plausible management

practices for this residual were reported in the 1992 RCRA

3007 Survey, as summarized above in Table 3.6.1. The Agency

gathered information suggesting other management practices

have been used in other years including: "disposal onsite

in surface impoundment" (38.4 MT), "other recycling,

reclamation, or reuse: offsite fluoride recovery" (23.6 MT),

and "offsite incineration" (3.6 MT). The very small volume

reported to have been disposed in a surface impoundment was

placed in the surface impoundment the year it was closed,

suggesting the inert material was used as fill. The

refinery reported the future management of the spent clay

would be sent offsite to a cement kiln for reuse.

Similarly, the very small volume reported for offsite

fluoride recovery was a management practice seen as a trend

for fluoride containing residuals during the engineering

site visits. The very small volume reported for offsite

incineration are comparable to the 1992 practices for other

treating clay residuals (e.g., clay filtering).

3.6.3.4 Characterization

Two sources of residual characterization were developed

during the industry study:

Table 3.6.2 summarizes the physical properties of

the alkylation sorbents as reported in Section

VII.A of the 3007 survey.

Four record samples of actual treating clay were

collected and analyzed by EPA. These spent

clays are all from HF processes and represent

the various types of spent sorbents typically

used by the industry as summarized in Table

3.6.3.

The four record samples were analyzed for total and

TCLP levels of volatiles, semivolatiles, metals, fluorides,

reactivity and ignitability. None of the samples were found

to exhibit any of the hazardous waste characteristics. A

summary of the results is presented in Table 3.6.4. Only

constituents detected in at least one sample are shown in

this table.

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3.6.3.5 Source Reduction

Several solid-acid catalysts used for alkylation are

being tested in pilot plants. The solid-catalyst reactor

systems are different from the current liquid-acid systems,

but for one solid-catalyst operation, the other process

equipment is compatible. The three types of new solid

catalyst include aluminum chloride, alumina/zirconium

halide, and antimony pentafluoride (a slurry system). It is

unclear whether these processes will generate more or less

treating clays than current processes. Theoretically, these

processes would not require filtering for acid and water

removal.

The February 1, 1993 issue of the Oil & Gas Journal

reported that Conoco's Ponca City, Oklahoma refinery sold

reclaimed fluorinated alumina to Kaiser Aluminum & Chemical

Corporation's plant in Mead, Washington. The fluorinated

alumina is substituted for aluminum fluoride, a "bath"

chemical used in aluminum manufacturing.

At the Ponca City refinery, Conoco uses activated

alumina in one of the alkylation units to extract fluorides

from propane and butane products. In the process, activated

alumina is converted to aluminum fluoride. Activated

alumina reaches the end of its useful life when 60-80% of

the material is converted to aluminum fluoride. That is when

it become an additive for aluminum manufacturers.

During EPA's site visits, one facility used

distillation to dry its feed to the HF acid alkylation unit.

Most facilities use a molecular sieve treating clay for this

step, therefore this process configuration eliminates the

need for molecular sieve infrequently generating an RC.

Some refineries are experimenting with additives to the

HF acid catalyst. The purpose of these additives is to

reduce the risk from an accidental leak of HF acid to the

atmosphere. Although the technology is principally

developed in reaction to safety concerns, it is likely that

such additives would be present in some of the study

residuals such as acid soluble oil. The identity of those

additives were not reported (Oil and Gas Journal, August 22,

1994).

3.6.4 Catalyst from Hydrofluoric Acid Alkylation

3.6.4.1 Description

The consent decree which identifies the residuals to be

examined in this study specified "catalyst from HF

alkylation". However, the analysis used to identify the

residuals of concern in the consent decree contained some

flaws and erroneously identified this alkylation catalyst as

being generated in significant quantities. Upon further

review of the data used to characterize this residual

(derived from EPA's 1983 survey of the petroleum refining

industry), it was determined that several large volume

residuals were inappropriately identified as spent catalyst

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and instead should have been classified as acid soluble oil

(ASO). After adjusting the data to remove these

mischaracterized residuals, the remaining residuals

classified as spent HF catalyst accounted for small volumes

which are on the order of magnitude observed in the Agency's

1992 data.

A residual of high molecular-weight reaction

by-products dissolves in the HF acid catalyst and lowers its

effectiveness. To maintain catalyst activity, a slip stream

of HF acid is sent to an acid regenerator where

distillations separates the HF acid from by-product

contaminants, called acid soluble oil. The HF acid from the

regenerators is recycled back to the reactor. Fresh acid is

added to replace acid losses at a rate of about 500 pounds

per day depending on unit capacity.

ASO is charged to a decanting vessel where an aqueous

phase settles out. The aqueous phase, an azeotropic mixture

of HF acid and water, is referred to as constant boiling

mixture (CBM). CBM is charged to the neutralization tank

which neutralize effluent to the WWTP. The neutralization

sludge was examined in the listing proposal and Background

Document. The effluent from the neutralization tanks are

reported to go to the WWTP. The Agency has no data

suggesting that it can be handled in any other way.

As stated above, HF acid is an extremely corrosive and

toxic chemical. Refineries go to great lengths to protect

their personnel from coming into direct contact with HF

acid.

3.6.4.2 Generation and Management

The refineries reported generating approximately 152 MT

of HF alkylation catalyst in 1992. Residuals were assigned

to be "HF alkylation catalyst" if they were assigned a

residual identification code of "liquid catalyst" and was

generated from a process identified as an HF acid alkylation

unit. This corresponds to residual code 03-B in Section

VII.2 of the questionnaire and process code 09-B in Section

IV-1.C of the questionnaire. Table 3.6.5 provides a

description of the quantity generated, number of streams

reported, and number of unreported volumes. Catalyst from

HF alkylation includes spills and removed acid from the HF

alkylation process.

3.6.4.3 Plausible Management

EPA believes that most of the plausible management

practices for this residual were reported in the 1992 RCRA

3007 Survey, as summarized above in Table 3.6.5. No data

were available to the Agency suggesting any other management

practices.

3.6.4.4 Characterization

Only one source of residual characterization is

available from the industry study, reflecting the fact that

this residual is not generated for management:

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Table 3.6.6 summarizes the physical properties of

the HF catalyst as reported in Section VII.A of

the 3007 survey.

Due to the rareness of the generation of this residual,

no samples of this residual were available for collection

and analysis during record sampling.

3.6.4.5 Source Reduction

As described in the spent treating clay alkylation in

Section 3.6.3.4, several solid-acid catalysts used for

alkylation are being tested in pilot plants. The reactor

systems are different from the current liquid-acid systems,

but for one system the other equipment is compatible. Three

types of the new solid catalyst include aluminum chloride,

alumina/zirconium halide, and antimony pentafluoride (a

slurry system).

In general, additional source reduction is not possible

because of the closed loop recycle process and the strict

controls placed on this material due to the severe health

hazards associated with contact and inhalation.

3.6.5 Acid Soluble Oil from Hydrofluoric Acid Alkylation

3.6.5.1 Description

A residual of high molecular-weight reaction

by-products dissolves in the HF acid catalyst and lowers its

effectiveness. To maintain the catalyst activity, a slip

stream of catalyst is distilled, leaving the by-product,

acid soluble oil (ASO), as a residue. The ASO is charged

to a decanting vessel where an aqueous phase settles out.

The ASO is scrubbed with potassium hydroxide (KOH) to remove

trace amounts of HF and is either recycled, sold as product

(e.g., residual fuel), or burned in the unit's boiler. In

some cases, the ASO from the regenerator is sent directly to

the neutralization tanks. Effluent from the neutralization

tanks is sent to the WWTP. Neutralization tank sludges were

examined under the listing proposal and Background Document.

ASO is generated exclusively from the HF process. The

sulfuric acid alkylation process does not generate ASO.

Eight residuals of ASO, accounting for 25 percent of

this category's volume, was reported as being managed as

either D001, D002, or D008.

3.6.5.2 Generation and Management

The refineries reported generating approximately 33,493

MT of ASO in 1992. Residuals were assigned to be "ASO" if

they were assigned a residual identification code of

"alkylation acid regeneration tars" and were generated from

a process identified as an HF acid alkylation unit. This

corresponds to residual code 08 in Section VII.1 and process

code 09-B in Section IV-1.C of the questionnaire. Note that

sludges generated from neutralization of acid soluble oil

were examined under the proposal and the Background Document

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and are not included here. Table 3.6.7 provides a

description of the quantity generated, number of streams

reported, and number of unreported volumes.

3.6.5.3 Plausible Management

EPA believes that most of the plausible management

practices for this residual were reported in the 1992 RCRA

3007 Survey, as summarized in Table 3.6.7. The Agency

gathered information suggesting that "disposal in industrial

Subtitle D landfill" (1 MT) was used in other years. Upon

closer examination of this residual, EPA determined that the

facility neutralized its ASO and landfilled the sludge.

This management practice is consistent with the practices

reported above.

3.6.5.4 Characterization

Two sources of residual characterization were developed

during the industry study:

Table 3.6.8 summarizes the physical properties of

the ASO as reported in Section VII.A of the

3007 survey.

Four record samples of actual ASO were collected

and analyzed by EPA. The ASO represent the

various types of interim management practices

typically used by the industry (i.e., with and

without neutralization) and are summarized in

Table 3.6.9.

The four record samples were analyzed for total and

TCLP levels of volatiles, semivolatiles, and metals, as well

as ignitability. Three of the samples were found to exhibit

the hazardous waste characteristic of ignitability. A

summary of the results is presented in Table 3.6.10. Only

constituents detected in at least one sample are shown in

this table.

3.6.5.5 Source Reduction

As described in previous sections, several solid-acid

catalysts used for alkylation are being tested in pilot

plants. The reactor systems are different from the current

liquid-acid systems, but for one system the other equipment

is compatible. Three types of the new solid catalyst

include aluminum chloride, alumina/zirconium halide, and

antimony pentafluoride (a slurry system).

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

catalyst system.

3.7 POLYMERIZATION

Polymerization is a process utilized for the conversion

of propane/propylene and/or butane/butene feeds from other

operations into a low molecular weight, higher-octane,

polymer product, referred to as dimate. Dimate is used as a

high octane gasoline blending component of unleaded

gasolines.

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Almost 12 percent of the industry's polymerization

catalyst (Dimersol and phosphoric acid) volume was reported

to be managed as a hazardous waste ("as hazardous", D002 and

D007).

3.7.1 Process Descriptions

There are primarily two polymerization processes

utilized by the petroleum refining industry: phosphoric

acid polymerization and the Dimersol process, licensed by

IFP (Institute Francais du Petrole, or the French Petroleum

Institute). Process descriptions for each of these two

processes are provided in the following sections.

3.7.1.1 Phosphoric Acid Polymerization

Phosphoric acid polymerization units produce marginal

octane gasoline from propylene feeds from other operating

units (i.e., the FCC unit, coking, etc). Phosphoric acid

polymerization is more widely used by industry than the

Dimersol process, representing 80 percent of all

polymerization units in the United States. Phosphoric acid

polymerization unit capacities range from 400 to 8,000

barrels per stream day, with the majority of units ranging

between 2,200 and 3,000 barrels per stream day (as reported

in the 3007 survey).

Phosphoric acid polymerization utilizes a catalyst

consisting of an alumina substrate impregnated with

phosphoric acid. A typical phosphoric acid polymerization

unit contains one or more reactors consisting of a series of

tubes coming off of a single header. The reactor feed is

charged to the header and flows through the tubes. The tubes

are packed with the phosphoric acid catalyst. The reaction

conditions are controlled to stop the polymerization at

the desired C6 or C9 product. The polymerization reaction

is highly exothermic and boiler feed water is fed through

the reactor (on the shell side of the tubes) to recover the

heat for use as steam. Over time, the catalyst's acid sites

become blocked and the catalyst is slated for change-out.

After leaving the reactor, the reactor effluent is

fractionated to give the desired products. A simplified

process flow diagram for a typical phosphoric acid

polymerization unit is shown in Figure 3.7.1.

3.7.1.2 Dimersol Polymerization

As stated above, Dimersol polymerization units

represent only 20 percent of the existing polymerization

units in the United States. The capacity of Dimersol units

range from 1,000 to 5,500 barrels per stream day, with an

average capacity of approximately 3,200 barrels per stream

day (as reported in the 3007 survey).

The Dimersol process is used to dimerize light olefins

such as ethylene, propylene and butylene. The process

typically begins with the pretreatment of the

propane/propylene or butane/butene feed prior to entering

the reactor section of the process. Pretreatment can

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include the use of molecular sieve dryers, sand filters,

etc. to remove water and/or H2S. Water in the feed stream

can deactivate the catalysts used in the Dimersol process.

After drying the feed is combined with a liquid nickel

carboxylate/ethyl aluminum dichloride (EADC) catalyst prior

to entering the first of a series of three reactors. The

first two are continuous stirred batch reactors and the

third is a plug-flow tubular reactor. The reactor feed

is converted to the process product, dimate, primarily in

the first reactor, and additional conversion is achieved in

the last two reactors. The final reactor effluent consists

of dimate product, unreacted C3/C4s, and liquid catalyst.

Immediately following the last reactor, the liquid catalyst

is removed from the reactor effluent by treating the reactor

effluent with caustic, subsequent water washing, and

filtering to remove solids. Spent caustic residuals are

typically reused or reclaimed on- or off-site, and as a

result, do not constitute solid wastes. After filtering,

the product stream enters a "Dimersol stabilizer," a

distillation unit that removes unreacted LPG from the dimate

product. In some cases, the product stream is also further

treated by drying. LPG from the stabilizer overhead is

typically sent to another unit of the refinery for further

processing. The dimate product from the bottom of the

stabilizer is sent to storage or product blending.

A simplified process flow diagram for a typical

Dimersol polymerization unit is shown in Figure 3.7.2.

3.7.2 Spent Phosphoric Acid Polymerization Catalyst

3.7.2.1 Description

Spent phosphoric acid polymerization catalyst is

generated after the solid catalyst active sites have become

blocked and lost their reactivity.

3.7.2.2 Generation and Management

During reactor change-outs, spent phosphoric acid

catalysts are flushed or water drilled from the

shell-and-tube reactors.

Twenty-two facilities reported generating a total

quantity of 3,358 MT of this residual in 1992, according to

the 1992 RCRA 3007 Questionnaire. Residuals were assigned

to be "spent phosphoric acid polymerization catalyst" if

they were assigned a residual identification code of "spent

solid catalyst" or "spent catalyst fines" and were generated

from a process identified as a phosphoric acid

polymerization unit. These correspond to residual codes

03-A and 03-B in Section VII.2 of the questionnaire and

process code 11-A in Section IV-1.C of the questionnaire.

Quality assurance was conducted by ensuring that all

phosphoric acid polymerization catalysts previously

identified in the questionnaire (i.e., in Section V.B) were

assigned in Section VII.2.

Based on the results of the questionnaire, 25

facilities use phosphoric acid polymerization units and are

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thus likely to generate spent phosphoric acid polymerization

catalyst. Due to the infrequent generation of this

residual, not all of these 25 facilities generated spent

catalyst in 1992. However, there was no reason to expect

that 1992 would not be a typical year with regard to this

residual's generation and management. Table 3.7.1 provides

a description of the quantity generated, number of streams

reported, number of streams not reporting volumes (data

requested was unavailable and facilities were not required

to generate it), total and average volumes.

3.7.2.3 Plausible Management

EPA believes that most of the plausible management

practices for this residual were reported in the 1992 RCRA

3007 Survey, as summarized above in Table 3.7.1. No data

were available to the Agency suggesting any other management

practices.

3.7.2.4 Characterization

Two sources of residual characterization were developed

during the industry study:

Table 3.7.2 summarizes the physical properties of

the spent catalyst as reported in Section VII.A

of the 3007 survey.

One record sample of phosphoric acid

polymerization catalyst was collected and

analyzed by EPA. The sample is representative

of typical phosphoric acid polymerization

catalyst used by the industry and is summarized

in Table 3.7.3.

The record sample was analyzed for total and TCLP

levels of volatiles, semivolatiles, and metals, reactivity

(pyrophoricity) and corrosivity. The sample was found to

exhibit the hazardous waste characteristic of corrosivity.

Dimersol and phosphoric acid catalysts were categorized

together in the consent decree, therefore, a summary of the

results for both residuals is presented in Table 3.7.7. Only

constituents detected in at least one sample are shown in

this table.

3.7.2.5 Source Reduction

No source reduction techniques were reported by

industry or found in the literature search for this

residual.

3.7.3 Spent Dimersol Polymerization Catalyst

3.7.3.1 Description

Dimersol catalyst is added to the reactor feed stream

and exits the final reactor as part of the reactor effluent.

The liquid catalyst is then removed from the reactor

effluent by neutralization (contact with caustic). Spent

caustic streams, containing the spent dimersol catalyst, are

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commonly reused on-site or sent off-site for metals

reclamation or caustic recovery, and as a result are

typically not solid wastes. Spent catalyst also may be

generated in two other points in the process. First, during

routine shutdowns spent catalyst may be generated as a

component of any reactor sludge removed from the reactors.

Second, certain Dimersol processes contain filters following

caustic neutralization and water washing to remove entrained

residual nickel from the dimate product. The filters are

removed and disposed periodically.

3.7.3.2 Generation and Management

Dimersol catalysts are generated as solid wastes in the

form of reactor sludges generated during reactor clean-outs

and as spent nickel filters.

Four facilities reported generating a total quantity of

761.5 MT of this residual as a reactor sludge in 1992,

according to the 1992 RCRA 3007 Survey. Residuals were

assigned to be "spent dimersol catalyst" if they were

assigned a residual identification code of "spent solid

catalyst" or "spent catalyst fines" or "other process

sludge" and were generated from a process identified as a

Dimersol polymerization unit. These correspond to residual

codes "03-A," "03-B" and "02-D" in Section VII.2 and process

code "11-B" in Section IV-1.C of the questionnaire. Quality

assurance was conducted by ensuring that all dimersol

catalysts previously identified in the questionnaire (i.e.,

in Section V.B) were assigned in Section VII.2.

Based on the results of the survey, 7 facilities use

Dimersol polymerization units and may generate spent

dimersol catalyst. Due to the continuous generation of this

residual, 1992 is expected to be a typical year in regard to

catalyst generation volume and management. There was no

reason to expect that 1992 would not be a typical year with

regard to this residual's generation and management. Table

3.7.4 provides a description of the quantity generated,

number of streams reported, number of streams not reporting

volumes (data requested was unavailable and facilities were

not required to generate it), total and average volumes.

3.7.3.3 Plausible Management

EPA believes that most of the plausible management

practices for this residual were reported in the 1992 RCRA

3007 Survey, as summarized above in Table 3.7.4. No data

were available to the Agency suggesting any other management

practices. Unlike with phosporic acid polymerization

catalyst, EPA does not expect spent Dimersol catalyst to be

land treated due to the physical nature of the filters.

3.7.3.4 Characterization

Two sources of residual characterization were developed

during the industry study:

Table 3.7.5 summarizes the physical properties of

the spent catalyst as reported in Section VII.A

of the 3007 survey.

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Two record samples of Dimersol polymerization

catalyst were collected and analyzed by EPA.

The samples represent typical Dimersol

polymerization catalyst used by the industry and

are summarized in Table 3.7.6.

The two record samples were analyzed for total and TCLP

levels of volatiles, semivolatiles, and metals, and

pyrophoricity and corrosivity. None of the samples were

found to exhibit a hazardous waste characteristic. Dimersol

and phosphoric acid catalysts were categorized together in

the consent decree, therefore, a summary of the results for

both residuals is presented in Table 3.7.7. Only

constituents detected in at least one sample are shown in

this table.

3.7.3.5 Source Reduction

No source reduction techniques were reported by

industry or found in the literature search for this

residual.

3.8 RESIDUAL UPGRADING

After vacuum distillation, there are still some

valuable oils left in the vacuum-reduced crude. Vacuum

tower distillation bottoms and other residuum feeds can be

upgraded to higher value products such as higher grade

asphalt or feed to catalytic cracking processes. Residual

upgrading includes processes where asphalt components are

separated from gas oil components by the use of a solvent.

It also includes processes where the asphalt value of the

residuum is upgraded (e.g., by oxidation) prior to sale.

Off-spec product and fines, as well as process sludges, are

study residuals from this category.

3.8.1 Process Descriptions

A total of 47 refineries reported using residual

upgrading units. Four types of residual upgrading processes

were reported in the 1992 RCRA 3007 Petroleum Refining

Survey:

Solvent Deasphalting

Asphalt Oxidation

Supercritical Extraction

Asphalt Emulsion

Asphalt uses are typically divided into use as road

oils, cutback asphalts, asphalt emulsions, and solid

asphalts. These asphalt products are used in paving roads,

roofing, paints, varnishes, insulating, rust-protective

compositions, battery boxes, and compounding materials that

go into rubber products, brake linings, and fuel briquettes

(REF).

Solvent Deasphalting

Residuum from vacuum distillation is separated into

asphalt components and gas oil components by solvent

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deasphalting. Figure 3.8.1 provides a simplified process

flow diagram. The hydrocarbon solvent is compressed and

contacted with the residuum feed. The extract contains the

paraffinic fractions (deasphalted oil or DAO), and the

raffinate contains the asphaltic components. The extract

and raffinate streams are sent to separate solvent recovery

systems to reclaim the solvent. The DAO may be further

refined or processed, used as catalytic cracking feed, sent

to lube oil processing/blending, or sold as finished

product. The following types of solvents are typically used

for the following residual upgrading processes:

Propane is the best choice for lube oil production due

to its ability to extract only paraffinic

hydrocarbons and to reject most of the carbon

residue. (McKetta)

A mixture of propane and butane is valuable for

preparing feedstocks for catalytic cracking processes

due to its ability to remove metal-bearing

components. (McKetta)

Pentane deasphalting, plus hydrodesulfurization, can

produce more feed for catalytic cracking or low

sulfur fuel oil. (McKetta)

One facility reported using propane and phenol solvents

for deasphalting residuum. The DAO is sent to lube

oil processing and the asphalt fraction is sent to

delayed coking or fuel oil blending.

During process upsets, heavy hydrocarbons may become

entrained in the solvent recovery systems, and

off-specification product may be generated. The entrained

hydrocarbons are periodically removed from the unit as a

process sludge and typically disposed in an industrial

landfill. The off-specification product are returned to the

process for re-processing.

Asphalt Oxidation (Asphalt Blowing)

Residuum from the vacuum tower or from solvent

deasphalting is upgraded by oxidation with air. Figure

3.8.2 provides a simplified process flow diagram. Air is

blown through the asphalt that is heated to about 500øF,

starting an exothermic reaction. The temperature is

controlled by regulating the amount of air and by

circulating oil or water through cooling coils within the

oxidizer. The oxygen in the air reacts with hydrogen in the

residuum to form water, and the reaction also couples

smaller molecules of asphalt into larger molecules to create

a heavier product. These reactions changes the

characteristics of the asphalt to a product with the desired

properties.

During this process, coke will form on the oxidizer

walls and the air sparger. The coke is removed periodically

(1 to 2 years) and sent to the coke pad for sale, mixed with

asphalt for use as road material, stored, or disposed. The

off-gases from the process are scrubbed to remove

hydrocarbons prior to burning in an thermal unit such as an

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incinerator or furnace.

Supercritical Extraction

The Residuum Oil Supercritical Extraction (ROSE)

process is not, in a strict sense, a supercritical fluid

extraction process. The primary extraction step is not

carried out at supercritical conditions, but at liquid

conditions that take advantage of the variable solvent power

of a near-critical liquid. A simplified process flow

diagram is provided in Figure 3.8.3. The first stage of the

ROSE process consists of mixing residuum with compressed

liquid butane or pentane and precipitating the undesired

asphaltene fraction. Butane is used for its higher solvent

power for heavy hydrocarbons. If an intermediate resin

fraction is desired, another separator and stripper system

would be used directly after the asphaltene separator. To

recover a resin fraction, the overhead from the asphaltene

separator is heated to near the critical temperature of the

butane. At the elevated, near-critical temperature, the

solvent power of the compressed liquid butane decreases and

the resins precipitate from solution. The remaining

fraction would consist of deasphalted light oils dissolved

in butane. The butane is typically recovered using steam.

The DAO may be sent to FCC, blended into lubricating

oil, or sold as finished product. The asphaltene and resins

are reported to be blended into No. 6 fuel oil. The solvent

and steam are condensed and collected in a surge drum where

the solvent is recycled back to the process. This surge

drum accumulates sludges during process upsets that are

removed during routine process turnarounds and disposed as

nonhazardous wastes.

Asphalt Emulsion

Residuals from the vacuum tower may be upgraded to an

asphalt emulsion by milling soap (or shear mixing) with the

asphalt. These emulsions are used for road oils, where good

adhesion is required.

This process generated residuals from the cleanout of

the soap tanks and from the generation of off-spec

emulsions. The soap tank cleanout residuals are typically

sent to the wastewater treatment plant, and the off-spec

emulsions are sent to a pit where heat is applied to break

the emulsion. The soap fraction is sent the wastewater

treatment system and the oil fraction is recycled back to

the coker feed.

3.8.2 Off-specification Product from Residual Upgrading

3.8.2.1 Description

This residual was identified in the consent decree

based on an incorrect characterization of data in a

supporting document generated from 1983 PRDB data. After

conducting a review of the underlying data, it was

determined that volumes associated with the category of

"off-specification product from residual upgrading" were

actually process sludges generated during process upset

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conditions. The Agency's finding regarding this category

was corroborated during its field investigation where this

residual category was not identified and in the 3007 survey

results. Generally, refineries re-work any residuum that

does not initially meet product specifications within the

upgrading process and rarely (one reported in 1992 in the

3007 survey) generate off-specification product for

disposal.

3.8.2.2 Generation and Management

Off-spec product from residual upgrading includes

material generated from asphalt oxidation, solvent

deasphalting, and other upgrading processes. Residuals were

assigned to be "off-specification product from residual

upgrading" if they were assigned a residual identification

code of "off-specification product" or "fines" and were

generated from a process identified as a residual upgrading

unit. These correspond to residual codes "05" and "06" in

Section VII.2 of the questionnaire and process code "13" in

Section IV-1.C of the questionnaire.

Based on the results of the questionnaire, 47

facilities use residual upgrading processes and thus could

potentially generate off-specification product from residual

upgrading. Only one facility reported this residual,

generating 800 MT that was recovered within the process.

The base year, 1992, was expected to be a typical year for

residual upgrading processes and the survey results are in

keeping with the Agency's understanding of this process.

Table 3.8.1 provides a description of the quantity generated

and number of reporting facilities.

3.8.2.3 Plausible Management

The Agency does not find it necessary to consider other

management practices because off-spec product from residual

upgrading had been classified as a residual of concern based

on erroneous old data and in fact is not generated for

disposal.

3.8.2.4 Characterization

Only one source of residual characterization data were

developed during the industry study:

Table 3.8.2 summarizes the physical properties of

the off-specification product as reported in

Section VII.A of the 3007 survey.

Because it is rarely generated, no record samples of

this residual were available during record sampling for

analysis.

3.8.2.5 Source Reduction

No source reduction techniques were reported by

industry or found in the literature search for this

residual.

3.8.3 Process Sludge from Residual Upgrading

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3.8.3.1 Description

Process sludge is generated from miscellaneous parts of

the various residual upgrading processes. This category is

neither uniform nor routinely generated. Solvent

deasphalting may generate a sludge due to hydrocarbon

carryover in the solvent recovery system. Similarly, the

ROSE process may generate sludges due to process upsets in

the solvent condensate collection system. Additional

sludges may be generated during unit turnarounds and in

surge drums and condensate knockout drums.

Three residuals were reported to be managed "as

hazardous", accounting for 25 percent of the volume of this

category generated in 1992.

3.8.3.2 Generation and Management

Twenty-one facilities reported generating a total

quantity of 241 MT of this residual in 1992, according to

the 1992 survey. Residuals were assigned to be "process

sludge from residual upgrading" if they were assigned a

residual identification code of "process sludge" and were

generated from a process identified as a "residual

upgrading" unit. These correspond to residual code "02-D"

in Section VII.2 of the questionnaire and process code "13"

in Section IV-1.C of the questionnaire.

Based on the results of the questionnaire, 47

facilities use residual upgrading units and thus may

generate process sludge from residual upgrading. Due to the

infrequent generation of this residual, not all of these 47

facilities generated sludge in 1992. However, there was no

reason to expect that 1992 would not be a typical year with

regard to this residual's generation and management. Table

3.8.3 provides a description of the quantity generated,

number of streams reported, number of streams not reporting

volumes (data requested was unavailable and facilities were

not required to generate it), total and average volumes.

3.8.3.3 Plausible Management

EPA believes that most of the plausible management

practices for this residual were reported in the 1992 RCRA

3007 Survey, as summarized above in Table 3.8.3. The Agency

gathered information suggesting that "recovery onsite in an

asphalt production unit" (3.6 MT) and "transfer to offsite

entity: unspecified" (unreported quantity) were used in

other years. This non-1992 management practice is

comparable with other recovery practices reported in 1992.

3.8.3.4 Characterization

Two sources of residual characterization data were

developed during the industry study:

Table 3.8.4 summarizes the physical properties of

the sludge as reported in Section VII.A of the

3007 survey.

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One record sample of process sludge from residual

upgrading was collected and analyzed by EPA.

This sample is summarized in Table 3.8.5.

The sample was analyzed for total and TCLP levels of

volatiles, semivolatiles, metals, and ignitability. The

sample was found to exhibit the toxicity characteristic for

benzene. A summary of the results is presented in Table

3.8.6. Only constituents detected in the sample are shown

in this table.

3.8.3.5 Source Reduction

Source reduction techniques were reported to be process

modifications and better housekeeping. This residual is

generated infrequently and in very small quantities,

therefore limited information was expected.

3.9 LUBE OIL PROCESSING

Vacuum distillates are treated and refined to produce a

variety of lubricants. Wax, aromatics, and asphalts are

removed by unit operations such as solvent extraction and

hydroprocessing; clay may also be used. Various additives

are used to meet product specifications for thermal

stability, oxidation resistances, viscosity, pour point,

etc.

3.9.1 Process Descriptions

The manufacture of lubricating oil base stocks consists

of five basic steps:

1) distillation

2) deasphalting to prepare the feedstocks

3) solvent or hydrogen refining to improve viscosity

index and quality

4) solvent or catalytic dewaxing to remove wax and

improve low temperature properties of paraffinic

lubes

5) clay or hydrogen finishing to improve color,

stability, and quality of the lube base stock.

Based on results of the 1992 survey, 22 facilities

reported conducting lube oil processing. The finished lube

stocks are blended with each other and additives using batch

and continuous methods to produce formulated lubricants.

The most common route to finishing lube feedstocks consists

of solvent refining, solvent dewaxing, and hydrogen

finishing. The solvent and clay processing route or the

hydrogen refining and solvent dewaxing route are also used.

The all-hydrogen processing (lube hydrocracking-catalytic

dewaxing-hydrorefining) route is used by two refiners for

the manufacture of a limited number of paraffinic base oils.

Figure 3.9.1 provides a general process flow diagram for

lube oil processing.

Lube Distillation

Lube processing may be the primary production process

at some facilities, while at others it is only one of many

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operations. The initial step is to separate the crude into

the fractions which are the raw stocks for the various

products to be produced. The basic process consists of an

atmospheric distillation unit and a vacuum distillation

unit. The majority of the lube stocks boil in the range

between 580øF and 1000øF and are distilled in the vacuum

unit to the proper viscosity and flash specifications.

Caustic solutions are sometimes introduced to the feed to

neutralize organic acids present in some crude oils. This

practice reduces or eliminates corrosion in downstream

processing units, and improves color, stability, and

refining response of lube distillates.

Lube Deasphalting

Other facilities incorporate lube deasphalting to

process vacuum residuum into lube oil base stocks. Propane

deasphalting is most commonly used to remove asphaltenes and

resins which contribute an undesirable dark color to the

lube base stocks. This process typically uses baffle towers

or rotating disk contactors to mix the propane with the

feed. Solvent recovery is accomplished with evaporators,

and supercritical solvent recovery processes are also used

in some deasphalting units. Another deasphalting process is

the Duo-Sol Process that is used to both deasphalt and

extract lubricating oil feedstocks. Propane is used as the

deasphalting solvent and a mixture of phenol and cresylic

acids are used as the extraction solvent. The extraction is

conducted in a series of batch extractors followed by

solvent recovery in multistage flash distillation and

stripping towers. See the section on Residual Upgrading for

additional discussion on these processes.

Lube Refining Processes

Chemical, solvent, and hydrogen refining processes have

been developed and are used to remove aromatics and other

undesirable constituents, and to improve the viscosity index

and quality of lube base stocks. Traditional chemical

processes that use sulfuric acid and clay refining have been

replaced by solvent extraction/refining and hydrotreating

which are more effective, cost efficient, and

environmentally more acceptable. Chemical refining is used

most often for the reclamation of used lubricating oils or

in combination with solvent or hydrogen refining processes

for the manufacture of specialty lubricating oils and

by-products.

Chemical Refining Processes: Acid-alkali refining,

also called "wet refining", is a process where lubricating

oils are contacted with sulfuric acid followed by

neutralization with alkali. Oil and acid are mixed and an

acid sludge is allowed to coagulate. The sludge is removed

or the oil is decanted after settling, and more acid is

added and the process repeated.

Acid-clay refining, also called "dry refining" is

similar to acid-alkali refining with the exception that clay

and a neutralizing agent are used for neutralization. This

process is usedfor oils that form emulsions during

neutralization.

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Neutralization with aqueous and alcoholic caustic, soda

ash lime, and other neutralizing agents is used to remove

organic acids from some feedstocks. This process is

conducted to reduce organic acid corrosion in downstream

units or to improve the refining response and color

stability of lube feedstocks.

Hydrogen Refining Processes: Hydrogen refining, also

called hydrotreating, has since been replaced with solvent

refining processes which are more cost effective.

Hydrotreating consists of lube hydrocracking as an

alternative to solvent extraction, and hydrorefining to

prepare specialty products or to stabilize hydrocracked base

stocks. Hydrocracking catalysts are proprietary to the

licensors and consist of mixtures of cobalt, nickel,

molybdenum, and tungsten on an alumina or

silica-alumina-based carrier. Hydrorefining catalysts are

proprietary but usually consist of nickel-molybdenum on

alumina.

Lube hydrocracking are used to remove nitrogen, oxygen,

and sulfur, and convert the undesirable polynuclear

aromatics and polynuclear naphthenes to mononuclear

naphthenes, aromatics, and isoparaffins which are typically

desired in lube base stocks. Feedstocks consist of

unrefined distillates and deasphalted oils, solvent

extracted distillates and deasphalted oils, cycle oils,

hydrogen refined oils, and mixtures of these hydrocarbon

fractions.

Lube hydrorefining processes are used to stabilize or

improve the quality of lube base stocks from lube

hydrocracking processes and for manufacture of specialty

oils. Feedstocks are dependent on the nature of the crude

source but generally consist of waxy or

dewaxed-solvent-extracted or hydrogen-refined paraffinic

oils and refined or unrefined naphthenic and paraffinic oils

from some selected crudes.

Solvent Refining Processes: Feedstocks from solvent

refining processes consist of paraffinic and naphthenic

distillates, deasphalted oils, hydrogen refined distillates

and deasphalted oils, cycle oils, and dewaxed oils. The

products are refined oils destined for further processing or

finished lube base stocks. The by-products are aromatic

extracts which are used in the manufacture of rubber, carbon

black, petrochemicals, FCCU feed, fuel oil, or asphalt. The

major solvents used today are N-methyl-2-pyrolidone (NMP)

and furfural, with phenol and liquid sulfur dioxide used to

a lesser extent.

The solvents are typically recovered in a series of

flash towers. Steam or inert gas strippers are used to

remove traces of solvent, and a solvent purification system

is used to remove water and other impurities from the

recovered solvent.

Lube Dewaxing Processes

Lube feedstocks typically contain increased wax content

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resulting from deasphalting and refining processes. These

waxes are normally solid at ambient temperatures and must be

removed to manufacture lube oil products with the necessary

low temperature properties. Catalytic dewaxing and solvent

dewaxing (the most prevalent) are processes currently in

use; older technologies include cold settling, pressure

filtration, and centrifuge dewaxing.

Catalytic Dewaxing: Because solvent dewaxing is

relatively expensive for the production of low pour point

oils, various catalytic dewaxing (selective hydrocracking)

processes have been developed for the manufacture of lube

oil base stocks. The basic process consists of a reactor

containing a proprietary dewaxing catalyst followed by a

second reactor containing a hydrogen finishing catalyst to

saturate olefins created by the dewaxing reaction and to

improve stability, color and demulsibility of the finished

lube oil.

Solvent Dewaxing: Solvent dewaxing consists of the

following steps: crystallization, filtration, and solvent

recovery. In the crystallization step, the feedstock is

diluted with the solvent and chilled, solidifying the wax

components. The filtration step removes the wax from

the solution of dewaxed oil and solvent. Solvent recovery

removes the solvent from the wax cake and filtrate for

recycle by flash distillation and stripping. The major

processes in use today are the ketone dewaxing processes.

Other processes that are used to a lesser degree include the

Di/Me Process and the propane dewaxing process.

The most widely used ketone processes are the Texaco

Solvent Dewaxing Process and the Exxon Dilchill Process.

Both processes consist of diluting the waxy feedstock with

solvent while chilling at a controlled rate to produce a

slurry. The slurry is filtered using rotary vacuum filters

and the wax cake is washed with cold solvent. The filtrate

is used to prechill the feedstock and solvent mixture. The

primary wax cake is diluted with additional solvent and

filtered again to reduce the oil content in the wax. The

solvent recovered from the dewaxed oil and wax cake by flash

vaporization and recycled back into the process. The Texaco

Solvent Dewaxing Process (also called the MEK process) uses

a mixture of MEK and toluene as the dewaxing solvent, and

sometimes uses mixtures of other ketones and aromatic

solvents. The Exxon Dilchill Dewaxing Process uses a direct

cold solvent dilution-chilling process in a special

crystallizer in place of the scraped surface exchangers

used in the Texaco process.

The Di/Me Dewaxing Process uses a mixture of

dichloroethane and methylene dichloride as the dewaxing

solvent. This process is used by a few refineries in

Europe. The Propane Dewaxing Process is essentially the

same as the ketone process except for the following:

propane is used as the dewaxing solvent and higher pressure

equipment is required, and chilling is done in evaporative

chillers by vaporizing a portion of the dewaxing solvent.

Although this process generates a better product and does

not require crystallizers, the temperature differential

between the dewaxed oil and the filtration temperature is

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higher than for the ketone processes (higher energy costs),

and dewaxing aids are required to get good filtration rates.

Lube Oil Finishing Processes

Today, hydrogen finishing processes (also referred to

as hydrorefining) have largely replaced the more costly acid

and clay finishing processes. Hydrogen finishing processes

are mild hydrogenation processes used to improve the color,

odor, thermal, and oxidative stability, and demulsibility of

lube base stocks. The process consists of fixed bed

catalytic reactors that typically use a nickel-molybdenum

catalyst to neutralize, desulfurize, and denitrify lube base

stocks. These processes do not saturate aromatics or break

carbon-carbon bonds as in other hydrogen finishing

processes. Sulfuric acid treating is still used by some

refiners for the manufacture of specialty oils and the

reclamation of used oils. This process is typically

conducted in batch or continuous processes similar to the

chemical refining processes discussed earlier, with the

exception that the amount of acid used is much lower that

used in acid refining. Clay contacting involves mixing the

oil with fine bleaching clay at elevated temperature

followed by separation of the oil and clay. This process

improves color and chemical, thermal, and color stability of

the lube base stock, and is often combined with acid

finishing. Clay percolation is a static bed absorption

process used to purify, decolorize, and finish lube stocks

and waxes. It is still used in the manufacture of

refrigeration oils, transformer oils, turbine oils, white

oils, and waxes.

3.9.2 Treating Clay from Lube Oil Processing

3.9.2.1 Description

The majority of treating clays (including other

sorbents) generated from lube oil processing are from

acid-clay treating in refining or lube oil finishing. The

average volume is approximately 40 metric tons.

3.9.2.2 Generation and Management

The spent clay is vacuumed or gravity dumped from the

vessels into piles or into containers such as drums and

roll-off bins. Only one residual was reported to be managed

"as hazardous" from this category in 1992.

Seven facilities reported generating a total quantify

of approximately 733 metric tons of this residual in 1992,

according to the 1992 RCRA 3007 Questionnaire. Residual

were assigned to be "treating clay from lube oil processes"

if they were assigned a residual identification code of

"spent sorbent" and were generated from a lube oil process.

These correspond to residual code "05" in Section VII.A of

the questionnaire and process code "17" in Section IV.C of

the questionnaire. Table 3.9.1 provides a description of

the 1992 management practices, quantity generated, number of

streams reported, number of streams not reporting volumes

(data requested was unavailable and facilities were not

required to generate it), total and average volumes.

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3.9.2.3 Plausible Management

EPA believes that most of the plausible management

practices for this residual were reported in the 1992 RCRA

3007 Survey, as summarized above in Table 3.9.1. No data

were available to the Agency suggesting any other management

practices. In addition, EPA compared the management

practice reported for lube oil treating clay to those

reported for treating clays from extraction, alkylation, and

isomerization based on expected similarities. No

additional management practices were reported.

3.9.2.4 Characterization

Two sources of residual characterization were developed

during the industry study:

Table 3.9.2 summarizes the physical and chemical

properties of treating clay from lube oil

processes as reported in Section VII.A of the

3007 survey.

One record sample of treating clay from lube oil

processes was collected and analyzed by EPA.

Sampling information is summarized in Table

3.9.3.

The collected sample is expected to be generally

representative of treating clay from lube oil processes.

The sample was analyzed for total and TCLP levels of

volatiles, semi-volatiles, and metals. The sample did not

exhibit any of the hazardous waste characteristics. A

summary of the analytical results is presented in Table

3.9.4. Only constituents detected in the sample are

reported.

3.9.3.5 Source Reduction

This residual is generated infrequently and in very

small quantities. Treating clays use for product polishing

in lube oil manufacturing are being phased out by industry.

No source reduction methods were reported by industry or

found in the literature search.

3.10 H2S REMOVAL AND SULFUR COMPLEX

3.10.1 Process Description

All crude oil contains sulfur, which must be removed at

various points of the refining process. The predominant

technique for treating light petroleum gases is (1) amine

scrubbing followed by (2) recovery of elemental sulfur in a

Claus unit followed by (3) final sulfur removal in a tail

gas unit. This dominance is shown in Table 3.10.1, which

presents the sulfur complex/removal processes reported in

the RCRA 3007 Survey.

Caustic or water is often used in conjunction with, or

instead of, amine solution to remove sulfur, particularly

for liquid petroleum fractions. These processes, however,

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are generally not considered sulfur removal processes

because either (1) the sulfur is not further complexed from

these solutions (i.e., is not removed from the solution), or

(2) if removed, it occurs in a sour water stripper which is

in the domain of the facility's wastewater treatment system.

Such processes are considered to be liquid treating with

caustic, which was discussed in the Listing Background

Document.

The dominant sulfur removal/complex train, amine

scrubbing followed by Claus unit followed by SCOT -type tail

gas treating, is discussed below. In addition, the

second-most popular tail gas system, the Beavon-Stretford

system, is discussed. Finally, other processes reported in

the questionnaires are discussed.

3.10.1.1 Amine Scrubbing

As shown in Table 3.10.1, amine scrubbing is used by

most facilities, with 106 refineries reporting this process

in the questionnaire. A typical process flow diagram for an

amine scrubbing system is shown in Figure 3.10.1. The

purpose of the unit is to remove H2S from refinery fuel gas

for economical downstream recovery. Fuel gas from the

refinery is fed to a countercurrent absorber with a 25 to 30

percent aqueous solution of amine such as monoethanolamine

(MEA), diethanolamine (DEA), or methyldiethanolamine (MDEA).

The H2S reacts with the amine solution to form a complex,

"rich" amine. Typically, a refinery will have several

absorbers located throughout the refinery depending on the

location of service. These "rich" streams are combined and

sent to a common location at the sulfur plant where the H2S

is stripped from the amine in the reverse reaction. The

"lean" amine is recycled back to the absorbers.

3.10.1.2 Claus Unit

The H2S from the sulfur removal unit is most often

recovered in a Claus system as elemental sulfur. Table

3.10.1 shows that 101 refineries reported this process in

the questionnaire. A typical process flow diagram for a

Claus unit is shown in Figure 3.10.2. In a Claus unit, the

H2S is partially combusted with air to form a mixture of SO2

and H2S. It then passes through a reactor containing

activated alumina catalyst to form sulfur by the following

endothermic reaction:

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

The reaction is typically conducted at atmospheric pressure.

The resulting sulfur is condensed to its molten state,

drained to a storage pit, and reheated. The typical Claus

unit consists of three such reactor/condenser/reheaters to

achieve an overall sulfur removal yield of 90 to 95 percent.

At this point the tail gas can be (1) combusted and released

to the atmosphere, or (2) sent to a tail gas unit to achieve

greater sulfur reduction.

3.10.1.3 SCOT Tailgas Unit

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The most common type of tail gas unit uses a

hydrotreating reactor followed by amine scrubbing to recover

and recycle sulfur, in the form of H2S, to the Claus unit.

Shell licenses this technology as the Shell Claus Offgas

Treating (SCOT) unit; many other refineries reported using

similar designs licensed by other vendors. All can be

represented by the generalized process flow diagram shown in

Figure 3.10.3.

Tail gas (containing H2S and SO2) is contacted with H2

and reduced in a hydrotreating reactor to form H2S and H2O.

The catalyst is typically cobalt/molybdenum on alumina. The

gas is then cooled in a water contactor. The water

circulates in the column and requires periodic purging due

to impurity buildup; filters may be used to control levels

of particulates or impurities in the circulating water.

The H2S-containing gas enters an amine absorber which

is typically in a system segregated from the other refinery

amine systems discussed above. The purpose of segregation

is two-fold: (1) the tail gas treater frequently uses a

different amine than the rest of the plant, such as MDEA or

diisopropyl amine (DIPA), and (2) the tail gas is frequently

cleaner than the refinery fuel gas (in regard to

contaminants) and segregation of the systems reduces

maintenance requirements for the SCOT unit. Amines chosen

for use in the tail gas system tend to be more selective for

H2S and are not affected by the high levels of CO2 in the

offgas.

The "rich" amine generated from this step is desorbed

in a stripper; the lean amine is recirculated while the

liberated H2S is sent to the Claus unit. Particulate

filters are sometimes used to remove contaminants from lean

amine.

3.10.1.4 Beavon-Stretford Tail Gas Unit

This system was reported to be used by 14 facilities.

A hydrotreating reactor converts SO2 in the offgas to H2S.

The generated H2S is contacted with Stretford solution (a

mixture of vanadium salt, anthraquinone disulfonic acid

(ADA), sodium carbonate, and sodium hydroxide) in a

liquid-gas absorber. The H2S reacts stepwise with sodium

carbonate and ADA to produce elemental sulfur, with vanadium

serving as a catalyst. The solution proceeds to a tank

where oxygen is added to regenerate the reactants. One or

more froth or slurry tanks are used to skim the product

sulfur from the solution, which is recirculated to the

absorber.

3.10.1.5 Other Processes

Although the amine/Claus train followed by a SCOT or

Beavon-Stretford tail gas unit is the dominant system used

in the industry, it is not exclusive. Some refineries,

mostly small asphalt plants, do not require sulfur removal

processes at all, while others use alternative technologies.

Each of these processes are used by less than five

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refineries, and most often are used by only one or two

facilities. In decreasing order of usage, these other

processes are as follows:

Sulfur Removal/Recovery Processes

Sodium hydrosulfide. Fuel gas containing H2S is

contacted with sodium hydroxide in an absorption

column. The resulting liquid is product sodium

hydrosulfide (NaHS).

Iron chelate. Fuel gas containing H2S is

contacted with iron chelate catalyst dissolved

in solution. H2S is converted to elemental

sulfur, which is recovered.

Stretford. Similar to iron chelate, except

Stretford solution is used instead of

iron chelate solution.

Ammonium thiosulfate. In this process, H2S is

contacted with air to form SO2. The SO2 is

contacted with ammonia in a series of absorption

column to produce ammonium thiosulfate for

offsite sale. (Kirk-Othmer, 1983)

Hyperion. Fuel gas is contacted over a solid

catalyst to form elemental sulfur. The sulfur

is collected and sold. The catalyst is

comprised of iron and naphthoquinonsulfonic

acid.

Sulfatreat. The Sulfatreat material is a black

granular solid powder; the H2S forms a chemical

bond with the solid. When the bed reaches

capacity, the Sulfatreat solids are removed and

replaced with fresh material. The sulfur is

not recovered.

A few facilities report sour water stripping,

which was not part of the scope of the survey.

The actual number of sour water strippers is

likely to be much greater than reported in the

questionnaire.

Hysulf. This process is under development by

Marathon Oil Company and was not reported by any

facilities in the questionnaire. Hydrogen

sulfide is contacted with a liquid quinone in an

organic solvent such as n-methyl-2-pyrolidone

(NMP), forming sulfur. The sulfur is removed

and the quinone reacted to its original state,

producing hydrogen gas (The National

Environmental Journal, March/April 1995).

Tail Gas Processes

Caustic scrubbing. An incinerator converts trace

sulfur compounds in the offgas to SO2. The gas

is contacted with caustic which is sent to the

wastewater treatment system.

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Polyethylene glycol. Offgas from the Claus unit

is contacted with this solution to generate an

elemental sulfur product. Unlike the Beavon

Stretford process, no hydrogenation reactor is

used to convert SO2 to H2S. (Kirk-Othmer, 1983)

Selectox. A hydrogenation reactor converts SO2 in

the offgas to H2S. A solid catalyst in a fixed

bed reactor converts the H2S to elemental

sulfur. The elemental sulfur is recovered and

sold. (Hydrocarbon Processing, April 1994).

Sulfite/Bisulfite Tail Gas Treating Unit.

Following Claus reactors, an incinerator

converts trace sulfur compounds to SO2. The gas

is contacted with sulfite solution in an

absorber, where SO2 reacts with the sulfite to

produce a bisulfite solution. The gas is then

emitted to the stack. The bisulfite is

regenerated and liberated SO2 is sent to the

Claus units for recovery. (Kirk-Othmer, 1983)

3.10.2 Off-Specification Product from Sulfur Complex and

H2S Removal Facilities

3.10.2.1 Description

Elemental sulfur is the most common product from sulfur

complex and H2S removal facilities, although a small number

of facilities generate product sodium hydrosulfide or

ammonium thiosulfate, as discussed in Section 3.10.1.5.

Like other refinery products, sulfur must meet certain

customer specifications such as color and impurity levels.

The failure of the refinery to meet these requirements

causes the sulfur to be "off-spec."

Stretford System

Although the Beavon-Stretford system is used by only 14

refineries, off-spec sulfur generated from this process

accounts for 2/3 of the refinery-wide 1992 generation of

off-spec sulfur. Sources of this volume are as follows:

Product sulfur: Some refineries routinely dispose

of their continuously generated product sulfur

rather than sell it. Presumably, these

refineries have operational difficulties making

"on-spec" sulfur from the vanadium-catalyzed

process. The small number of refineries

managing sulfur this way account for most of the

quantity of off-spec sulfur generated

industry-wide. Other refineries sell all or

most of their product sulfur and only dispose of

sulfur generated from spills, etc.

Filtered solids from spent Stretford solution: As

discussed further in Section 3.10.3, many

refineries report that a portion of the

circulating Stretford solution must be purged to

remove impurities in the system. After purging,

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some refineries filter out the solids prior to

further managing the spent solution.

Turnaround sludge (sediment): Every few years,

the process units are thoroughly cleaned as

preparation for maintenance. The principal

source of this turnaround sludge is the froth

(slurry) tank.

Miscellaneous sludges (sediments): Other solids

build up in the system, including tank sludges

and process drain pit sludge. They are removed

intermittently.

Every residual generated by the Stretford process

contains elemental (product) sulfur because sulfur is a

reaction product. Most refineries designated the above

materials as off-spec product in their questionnaire

response, and these residuals are included in statistics

discussed later in this Section.

Claus System

Based on database responses, many Claus units generate

off-spec sulfur at frequencies ranging from 2 months to 2

years. Sources of such sulfur are spills, process upsets,

turnarounds, or maintenance operations. Some refineries

generate off-spec sulfur more frequently; one refinery

reports that certain spots are drained daily to ensure

proper operation.

Other Systems

The amine scrubbing and SCOT units do not generate

off-spec sulfur because they do not generate product sulfur

(their product is H2S, an intermediate for the Claus sulfur

recovery unit). Other systems generating elemental sulfur

or product sulfur compounds can generate off-spec sulfur for

the same reasons described above for Claus and Stretford

processes.

3.10.2.2 Generation and Management

Most off-spec sulfur from Claus units is solid with

little water content. The off-spec sulfur residuals

described above from the Stretford process contain varying

levels of solution which would give the residual a solid,

sludge, or slurry form. Some refineries report filtering

this material to generate off-spec sulfur with higher solids

levels.

Based on the questionnaire responses, most refineries

(regardless of process) reported storing off-spec sulfur

onsite in a drum, in a dumpster, or in a pile prior to its

final destination. In 1992, five facilities reported

classifying this residual as RCRA hazardous (a total

quantity of 2,551 MT were reported), however, the hazard

waste code was generally not reported.

Sixty facilities reported generating a total quantity

of almost 9,650 MT of this residual in 1992, according to

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the 1992 RCRA 3007 Survey. As stated in Section 3.10.1, 123

facilities reported sulfur complex/removal processes. The

remaining 63 facilities either report never generating this

residual, or reported generation in years other than 1992

(due to intermittent generation). There was no reason to

expect that 1992 would not be a typical year with regard to

this residual's generation and management. Because most of

the generation quantity is concentrated at a small number of

facilities using the Stretford process, however, future

operational changes at those sites could greatly impact the

industry-wide residual generation rate.

Residuals were assigned to be "off-spec sulfur" if they

were assigned a residual identification code of "off-spec

product" and were generated from a process identified as a

sulfur removal or complex unit. These correspond to

residual code 05 in Section VII.A of the questionnaire and

process code 15 in Section IV.C of the questionnaire. Table

3.10.2 provides a description of the 1992 management

practices, quantity generated, number of streams reported, number of streams not reporting volumes (data requested

was unavailable and facilities were not required to generate

it), total and average volumes.

3.10.2.3 Plausible Management

EPA believes that most of the plausible management

practices for this residual were reported in the 1992 RCRA

3007 Survey, as summarized above in Table 3.10.2. No data

were available to the Agency suggesting any other management

practices.

3.10.2.4 Characterization

Two sources of residual characterization were developed

during the industry study:

Table 3.10.3 summarizes the physical and chemical

properties of off-spec sulfur as reported in

Section VII.A of the 3007 survey.

Four record samples of off-spec sulfur were

collected and analyzed by EPA. All of these were

collected from the Claus process. Sampling

information is summarized in Table 3.10.4.

The collected samples are expected to be representative

of off-spec sulfur generated from Claus units, the sulfur

recovery process used by most refineries. They are not

expected to represent off-spec sulfur from the Stretford

process because vanadium would be present in off-spec sulfur

from this process at levels higher than those found in

off-spec sulfur from Claus units. Concentrations of other

contaminants may also differ.

All four record samples were analyzed for total and

TCLP levels of volatiles, semivolatiles and metals. None of

the samples were found to exhibit a hazardous waste

characteristic. A summary of the analytical results is

presented in Table 3.10.5. Only constituents detected in at

least one sample are shown in this table.

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3.10.2.5 Source Reduction

During EPA's site visit, one facility was observed to

generate "off-spec" sulfur product daily. Portions of the

sulfur plant are being replaced with a newer design. As a

result, waste sulfur residual from equipment "low points"

will no longer be generated.

3.10.3 Off-Specification Treating Solution from Sulfur

Complex and H2S Removal Facilities

3.10.3.1 Description

All treating solutions used in refinery sulfur removal

systems are regenerative, meaning the solution is used over

and over in a closed system (for example, amines use

multiple absorption/desorption cycles, while Stretford

solution undergoes multiple reversible reactions). In the

following instances the treating solution becomes "off-spec"

and cannot be reused:

AMINE SYSTEMS: At most refineries, amine

continuously leaves the closed system through

entrainment in overhead gas, leaks, and other

routes. The amine is collected in various

locations such as sumps and either returned to

the process or discharged to the refinery's

wastewater treatment (possibly due to purity

constraints).

At some refineries, the circulating amine must be

replaced in whole or in part due to

contamination or process upset. Rarely, a

refinery may change from one amine to another

and completely remove the existing amine from

the system prior to introducing the new

solution.

STRETFORD SYSTEM: Many refineries report that a

portion of the circulating Stretford solution

must be purged to remove impurities in the

system. After purging, some refineries filter

out the solids prior to further managing the

spent solution. Stretford systems are used at a

smaller number (15) of facilities. Unlike amine

systems, Stretford solution is generally used

only in tail gas treating.

During operation, the treating solution alternatively

becomes "rich" (i.e., containing H2S) and "lean" (i.e.,

containing low levels or no H2S). In all observed cases, a

refinery will generate off-spec treating solution when it is

"lean."

Approximately 800 MT of off-spec treating solution

generated in 1992 was identified by 6 facilities as

displaying hazardous characteristics. The facilities

designated the wastes with hazardous waste codes D002

(corrosive), D003 (reactive), D010 (TC selenium), and

D018 (TC benzene). No single hazardous waste code was

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reported by more than one facility.

3.10.3.2 Generation and Management

Spent Amine Solution

As discussed in Section 3.10.1, the amine sulfur

removal process is the dominant sulfur removal process for

gas streams used in the industry. Amine solutions are

aqueous and are typically stored in covered sumps, tanks,

etc. In the 1992 questionnaire, most facilities did not

report how their off-spec treating solution is stored prior

to final management; those that did indicated storage in a

tank (most common), storage in a container, or storage in a

sump.

Forty-four facilities reported generating a total

quantity of 4,627 MT of spent amine in 1992, according to

the 1992 RCRA 3007 Questionnaire. Residuals were assigned

to be "off-spec treating solution (spent amine)" if they

were assigned a residual identification code of "treating

solution" and were generated from a sulfur complex or H2S

removal process. These correspond to residual codes of

"04-B" or "04-C" in Section VII.A and process code "15-A"

and "15-D" in Section IV-1.C of the questionnaire. Based on

the results of the questionnaire, approximately 123

facilities employ some type of sulfur removal system (most

of these systems employ treating solution). Many facilities

generate this residual on an intermittent basis, or only

during unusual circumstances such as upsets. Therefore, not

all of these 123 facilities are expected to generate

off-spec treating solution.

Table 3.10.6 provides a description of the 1992

management practices, quantity generated, number of streams

reported, number of streams not reporting volumes (data

requested was unavailable and facilities were not required

to generate it), total and average volumes.

Spent Stretford Solution

The second most frequently used process is the

Stretford sulfur removal/complex process. Stretford

solutions are aqueous and are typically stored in covered

sumps, tanks, etc.

Twelve facilities reported generating a total quantity

of 19,254.5 MT of spent Stretford solution in 1992,

according to the 1992 RCRA 3007 Questionnaire. Residuals

were assigned to be "spent Stretford solution" if they were

assigned a residual identification code of "treating

solution" and were generated from a sulfur complex or H2S

removal process. These correspond to residual codes of

"04-B" or "04-C" in Section VII.A and process code "15-B"

and "15-E" in Section IV-1.C of the questionnaire.

Table 3.10.7 provides a description of the 1992

management practices, quantity generated, number of streams

reported, number of streams not reporting volumes (data

requested was unavailable and facilities were not required

to generate it), total and average volumes.

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3.10.3.3 Plausible Management

Spent Amine

EPA believes that most of the plausible management

practices for this residual were reported in the 1992 RCRA

3007 Survey, as summarized above in Table 3.10.6. The

Agency gathered information suggesting other management

practices have been used in other years including: "onsite

Subtitle D landfill" (200 MT) and "offsite incineration"

(120 MT). These non-1992 practices are generally comparable

to practices reported in 1992 (i.e., off-site Subtitle D

landfilling and on-site boiler, respectively).

Spent Stretford Solution

EPA believes that most of the plausible management

practices for this residual were reported in the 1992 RCRA

3007 Survey, as summarized above in Table 3.10.7. Even

though spent Stretford solution has different properties, it

is possible that the solution could be managed as the spent

amine in Table 3.10.6.

3.10.3.4 Characterization

Two sources of residual characterization were developed

during the industry study:

Tables 3.10.8 and 3.10.9 summarize the physical

properties of spent amine and spent Stretford

solution as reported in Section VII.A of the

3007 survey.

Four record samples of spent amine solution were

collected and analyzed by EPA. The sample

locations are summarized in Table 3.10.10.

No samples of spent Stretford solution were

available from the randomly selected facilities

during record sampling.

All of the samples were taken from refinery amine

systems and are believed to represent the various types of

spent amine generated by refineries. No samples from the

tail gas system units were collected. Tail gas residuals

are expected to be cleaner because the feeds are cleaner.

Therefore, the tail gas treating residuals are expected to

exhibit levels of contaminants no higher than those found in

the sampled residuals. No samples of Stretford solution

were taken. Stretford systems were not used by the

facilities randomly selected by the Agency for record

sampling. Samples of Stretford solution are expected to

exhibit higher levels of vanadium than amine solution

because vanadium is present in new Stretford solution;

levels of some organic contaminants may be lower because

most refineries use their Stretford system to treat

low-organic Claus unit tail gas.

Several of the samples were taken from the process line

(i.e., at the time of sampling, the refinery had no

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immediate plans to remove the sampled treating solution from

the system). However, these refineries indicated they do

remove all or part of their circulating amine on an

infrequent basis due to process upset or excessive

contaminant levels. The sampled amine is expected to have

contaminant concentrations at least as high as when the

circulating amine is removed from the system. Physical

properties such as pH and flash point are expected to be

similar as well.

All four samples were analyzed for total and TCLP

levels of volatiles, semivolatiles, and metals, pH, total

amines, and ignitability. Two samples were also analyzed

for reactive sulfides. One sample exhibited the

characteristic of ignitability. A summary of the results is

presented in Table 3.10.11. Only constituents detected in

at least one sample are shown in this table.

3.10.3.5 Source Reduction

Source reduction of amine involves modifying the

process. During the site visits, information was gathered

that several facilities capture the amine for recycling.

Two facilities replaced the cloth filter at the sulfur

recovery unit with an etched metal mechanical filter. The

new filter requires less maintenance, and also eliminates

amine discharges to the wastewater treatment plant due to

filter change-outs. Another two facilities have installed

sumps at the sulfur complex. The sumps capture amine that

is drained from the filters during bag change-outs and

recycle it to the amine system. Without the sumps, the

amine drained from the filters is discharged to the

wastewater treatment plant.

3.11 CLAY FILTERING

Clay belongs to a broad class of materials designed to

remove impurities via adsorption. Examples of clay include

Fullers earth, natural clay, and acid treated clay.

However, similar materials such as bauxite are also

available and used to impart similar qualities to the

product. In addition, materials such as sand, salt,

molecular sieve, and activated carbon are used for removing

impurities by adsorption or other physical mechanisms. All

solid materials discussed in Section 3.11.1 are termed as

"solid sorbents" for the purposes of defining this residual

category.

3.11.1 Process Description

Clay or other adsorbents are used to remove impurities

from many hydrocarbon streams. Some of these applications

are associated with isomerization, extraction, alkylation,

and lube oil processing; such processes are discussed in the

respective sections of this document. Other solid media

remove impurities from amine solutions used in hydrogen

sulfide removal systems; such media were discussed in the

Listing Background Document. Solid media used in all other

refinery processes are summarized and discussed in this

section. The principal applications are described below.

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Kerosene Clay Filtering. Clay treatment removes

diolefins, asphaltic materials, resins, and acids; this

improves the color of the product and removes gum-forming

impurities (Speight, 1991). The RCRA 3007 Survey indicates

that approximately 90 facilities use this process; some

facilities have multiple treaters or treat different

streams, so that an estimated 150 processes exist. Most

clay treatment is conducted as a fixed bed. A typical clay

volume is 2,000 ft3, distributed in 1 or more vessels.

Alternatively to the fixed bed process, the clay can be

mixed with the hydrocarbon and filtered in a belt press. In

addition to kerosene, some facilities identify filtering

furnace oils through clay and generating spent clay in a

similar manner.

Catalyst Support in Merox and Minalk Systems. The

Merox and Minalk caustic treatment systems convert

mercaptans to disulfides using oxygen and an organometallic

catalyst in an alkaline environment. Depending on the

process configuration, the disulfides can remain in the

hydrocarbon product (a "sweetening" process) or the

disulfides can be removed by settling (an "extractive"

process). These treatment processes are commonly applied to

gasoline, but refinery streams ranging from propane to

diesel undergo this treatment.

The catalyst can either be dissolved in the caustic or

can be supported on a fixed bed. Either activated carbon,

coal, or charcoal are typically used as support material for

solid supported catalyst (the hydrocarbon passes over the

catalyst, where reaction occurs). These materials provide

contact area for reaction when the catalyst is dissolved in

the caustic. The RCRA 3007 survey indicates that

approximately 25 facilities (using 40 processes) reported

generating spent carbon, coal, or charcoal from these

processes; additional facilities likely generate this

residual but did not report generation in the questionnaire

because the residual is typically generated infrequently.

Drying. Water is removed from many hydrocarbon streams

ranging from diesel fuel to propane. Water must be removed

for reasons including: (1) product specifications (e.g.,

jet fuel has low tolerances for water content), and (2)

reactor feed preparation (e.g., precious metal catalysts are

often poisoned by water). Salt and sand are commonly used

for the first application, while molecular sieve is commonly

used for the second application.

When hydrocarbon is passed through a fixed bed of sand,

the moisture collects on the sand particles and eventually

settles to the bottom of the vessel, where the water is

removed. In a salt drier, water in the stream dissolves

salt (e.g., sodium chloride) which then collects in the

vessel bottom and is periodically removed. As a result,

the vessel requires periodic topping with solid salt.

Salt and sand treaters can be found throughout the

refinery to treat hydrocarbons ranging from diesel to

propane. They are commonly found following aqueous

treatments such as caustic washing, water washing, or Merox

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caustic treatment. In these treatments, the hydrocarbon is

contacted with the aqueous stream; the hydrocarbon then

passes through salt or sand to remove residual moisture.

The RCRA 3007 questionnaire indicates that approximately 60

facilities (using 150 processes) reported generating spent

salt or sand from these processes; additional facilities

likely generate this residual but did not report generation

in the questionnaire because it was not generated in 1992.

Molecular sieves are most commonly used to selectively

adsorb water and sulfur compounds from light hydrocarbon

fractions such as propane and propylene. The hydrocarbon

passes through a fixed bed of molecular sieve. After the

bed is saturated, water is desorbed by passing heated fuel

gas over the bed to release the adsorbed water and sulfur

compounds into the regeneration gas stream, which is

commonly sent to a flare stack. Molecular sieves are often

used for drying feed to the isomerization unit and HF acid

alkylation unit, applications that are discussed in Sections

3.4 and 3.5, respectively, of this document. Other

applications include drying propane or propylene prior to

entering the Dimersol unit, drying naphtha entering the

reformer, and feed preparation for other reaction units.

Molecular sieves are also used to dry light-end product

streams from the hydrocracker, catalytic reformer, and

light-ends recovery unit. Less common uses also exist for

molecular sieves including the separation of light-end

fractions such as methanol, butane, and butylene. In total,

the RCRA 3007 questionnaire indicates that approximately 70

facilities (using 150 processes) reported generating spent

molecular sieve; this includes the applications of HF acid

alkylation and isomerization that are discussed elsewhere in

this document, but excludes additional facilities that are

likely generate this residual but did not report 1992

generation in the questionnaire.

Sulfur and Chloride Guards in Catalytic Reforming. As

discussed in the Listing Background Document, catalytic

reforming units require a platinum catalyst; this catalyst

is readily poisoned by sulfur compounds. To prolong

catalyst life, many refineries install sulfur traps to

remove sulfur compounds prior to the reforming catalyst bed.

This material can consist of granular or pelletized metal

oxides, such as copper or magnesium. These materials (1)

remove H2S, (2) convert mercaptans to H2S and organic

sulfides, and (3) remove generated H2S. The material can be

desorbed, reactivated, and reused (Perry's, 1950). Alumina

also is used to treat light naphtha prior to isomerization

(which also uses precious metal catalyst). The RCRA 3007

questionnaire indicates that approximately 20 facilities

reported generating spent sulfur guards from 35

applications, most often as guards for reforming and

isomerization reactors. Additional facilities may employ

sulfur guards but did not report generation in the

questionnaire because the residual is typically generated

infrequently.

Alumina beds may be used to remove chlorides from the

hydrogen produced from the reforming process. The hydrogen

is then used throughout the refinery. The alumina bed is

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expected to last for 24-30 months prior to chloride

breakthrough, when replacement of the alumina is required.

Reformate from the reformer may also be passed through

alumina to remove chloride. The RCRA 3007 questionnaire

indicates that approximately 15 facilities reported

generating spent chloride guards from 25 applications, most

often in the reforming process.

Propane Treating by Alumina. An activated alumina bed

is used to de-fluorinate propane generated from a propane

stripper. The propane then is dried in a sand tower and a

drier which also contains alumina. Both the defluorinator

and drier periodically generate spent alumina.

Particulate filters. Entrained solids can be removed

by in-line cartridge filters. These cartridges are commonly

used for finishing kerosene, diesel fuel, etc., prior to

sale. Approximately 10 facilities reported generating spent

cartridges from 20 applications, according to the

questionnaire results.

In most of the applications discussed above, the use of

solid media such as clay, sand, etc. are not the only

options refineries have in imparting the desired properties

on a product. For example, drying can be conducted by

simple distillation. Hydrotreating and caustic treating are

common alternatives to the clay treatment of jet fuel by

removing undesirable contaminants from the kerosene/jet fuel

fraction. And, as discussed above, the Merox process can be

conducted with or without solid supported catalyst.

3.11.2 Treating Clay from Clay Filtering

3.11.2.1 Description

Generated at many places in the refinery, spent solid

sorbents have liquid contents ranging from very low (e.g.,

for molecular sieves treating light hydrocarbons) to

oil-saturated material (e.g., for clay used for treating

kerosene). The substrate is either inorganic (such as

alumina, zeolite, or clay) or organic (such as activated

carbon). Most applications are fixed bed, where the

material is charged to vessels and the hydrocarbon passed

through the fixed bed of solid sorption media. The fixed

bed can remain in service for a period of time ranging

from several months to 10 years, depending on the

application. At the end of service, the vessel is opened,

the "spent" material removed, and the vessel recharged.

3.11.2.2 Generation and Management

The spent clay is vacuumed or gravity dumped from the

vessels into piles or into containers such as drums and

roll-off bins. The RCRA 3007 questionnaire and site visits

indicate that very few other interim storage methods are

used.

In 1992, approximately 30 facilities reported that

1,700 MT of this residual was managed as hazardous. The

most commonly designated waste codes were D001 (ignitable),

D008 (TC lead), and D018 (TC benzene). This is consistent

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with how the residual was reported to be managed in other

years.

One hundred facilities reported generating a total

quantity of approximately 9,000 MT of this residual in 1992,

according to the 1992 RCRA 3007 Questionnaire. There was no

reason to expect that 1992 would not be a typical year with

regard to this residual's generation and management.

Residuals were assigned to be "treating clay from clay

filtering" if they were assigned a residual identification

code of "spent sorbent" (residual coded "07") and were not

generated from a process identified as an alkylation,

isomerization, extraction, sulfur removal, or lube oil unit

(process codes "09," "10," "12," "15," and "17,"

respectively) (sorbents from these units are discussed

elsewhere in this document or in the Listing Background

Document). The frequency of generation is highly variable

as discussed in Section 3.11.1. Table 3.11.1 provides a

description of the 1992 management practices, quantity

generated, number of streams reported, number of streams not

reporting volumes (data requested was unavailable and

facilities were not required to generate it), total and

average volumes.

The wide array of management methods reflect the

numerous applications of sorbents. For example, disposed

salt from salt driers can be managed in onsite wastewater

treatment plants, cement plants can accept spent alumina,

and catalyst reclaimers can accept sulfur sorbers having

recoverable metals. The large quantity disposed, however,

demonstrates that for most applications and refineries the

spent clay is seen as a low value solid waste.

3.11.2.3 Plausible Management

EPA believes that most of the plausible management

practices for this residual were reported in the 1992 RCRA

3007 Survey, as summarized above in Table 3.11.1. The

Agency gathered information suggesting other management

practices have been used in other years including: "other

recycling, reclamation, or reuse: unknown" (1 MT), "other

recycling, reclamation, or reuse: onsite road material"

(13.5 MT) and "reuse as a replacement catalyst for another

unit" (5 MT). These non-1992 very small management

practices are comparable to the recycling practices reported

in 1992.

3.11.2.4 Characterization

Two sources of residual characterization were developed

during the industry study:

Table 3.11.2 summarizes the physical properties of

the spent clay as reported in Section VII.A of

the 3007 survey.

Four record samples of spent clay were collected

and analyzed by EPA. These spent clays

represent some of the various types of

applications used by the industry. Sampling

information is summarized in Table 3.11.3.

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The collected samples are expected to be representative

of treating clay from kerosene treatment. Section 3.11.1

shows that kerosene clay treatment represents the highest

single use of sorbents in refineries (outside of the sulfur

recovery, isomerization, and alkylation processes that are

not included in the scope of this study residual). In

addition, a cursory review of the 1992 generation data

presented in Section 3.11.2.2 shows that the 1992 generation

rate of spent kerosene treating clay represents at least

half of the total 1992 quantity from all sources identified

in Section 3.11.1.

One of the samples is representative of a sulfur guard

bed. Other applications of spent sorbents (discussed in

Section 3.11.1) are not well represented by the record

sampling. Specifically:

Spent activated carbon from Merox treatment, salt

and sand from product drying, particulate

filters, and chloride removal beds are not

expected to resemble these materials.

Spent molecular sieves and alumina are not

represented by the collected record samples.

However, they may be represented by the record

samples of isomerization treating clay and

alkylation treating clay, discussed in Sections

3.4 and 3.5, respectively.

All four record samples were analyzed for total and

TCLP levels of volatiles, semivolatiles, and metals. Two

samples were analyzed for ignitability and all were analyzed

for reactivity (pyrophoricity). One of the samples was

found to exhibit the ignitability characteristic. High

manganese concentrations in one sample result from the

adsorbent make-up. A summary of the results is presented in

Table 3.11.4. Only constituents detected in at least one

sample are shown in this table.

3.11.2.5 Source Reduction

One facility reported that its jet fuel treating clay

is regenerated once by back-washing the clay bed with jet

fuel to "fluff" the clay and alleviate the pressure drop.

3.12 RESIDUAL OIL TANK STORAGE

Almost every refinery stores its feed and products in

tanks onsite. Occasionally (every 10 to 20 years), tanks

require sediment removal due to maintenance, inspection, or

sediment buildup. These tank bottoms are removed by

techniques ranging from manual shoveling to robotics and

filtration. Residual oil tank sludge is a study residual of

concern.

Residual oil is generally considered to be equivalent

to No. 6 fuel oil which is a heavy residue oil sometimes

called Bunker C when used to fuel ocean-going vessels.

Preheating is required for both handling and burning. It is

typically produced from units such as atmospheric and vacuum

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distillation, hydrocracking, delayed coking, and

visbreaking. The fluid catalytic cracking unit also

contributes to the refinery's heavy oil pool, but EPA terms

this material "clarified slurry oil," or CSO, and discussed

this product separately in the Listing Background Document

(October 31, 1995).

According to DOE's Petroleum Supply Annual,

approximately 400 million barrels of "residual oil" was

domestically used in 1992 (including imports and exports).

The use profile in 1994 was as follows (DOE's Fuel Oil and

Kerosene Sales 1994):

Sector 1990 Consumption of Residual

Fuel Oil

Electric Utility 40%

Shipping 35%

Industrial 15%

Commercial and Other 10%

The larger utilities often have their own specifications

when purchasing residual fuel oil. These can include sulfur,

nitrogen, ash, and vanadium. The current ASTM standard for

No. 6 oil (D-396) specifies only three parameters: minimum

flash point (of 150øF), maximum water and sediment (of 2

percent), and a viscosity range (Bonnet, 1994). Thus, the

characteristics of residual oil, and the generated tank

sludge, can vary greatly depending on the buyer and the

refinery.

3.12.1 Residual Oil Storage Tank Sludge

In 1992, 125 U.S. refineries reported approximately 717

residual oil storage tanks. From the survey, tank volume

was reported for about 10 percent (73) of these tanks

(excluding outliers); the average tank volume was

approximately 77,000 barrels. DOE's Petroleum Supply Annual

1992 reported that refineries produced about 327 million

barrels of No. 6 fuel oil or residual oil or approximately

900,000 barrels per day (this likely includes CSO).

3.12.1.1 Description

Residual oil tank sludge consists of heavy

hydrocarbons, rust and scale from process pipes and

reactors, and entrapped oil that settles to the bottom of

the tank. It can be manually removed directly from the tank

after drainage of the residual oil or, commonly, removed

using a variety of oil recovery techniques. The recovered

oil is returned generally to slop oil storage while the

remaining solids are collected and discarded as waste.

Once a tank is taken out of service, many refineries

use in situ and ex situ oil recovery techniques. Common in

situ oil recovery techniques include hot distillate washing,

and steam stripping. This allows entrapped oil to float to

the top of the sediment layer and be recovered prior to

removal of the sediment from the tank. Ex situ recovery

methods are usually performed by a contractor at the tank

site and include filtration, centrifuging, and settling.

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Separated oil is recycled back to the process or sent to the

slop oil tanks, and the water phase is sent to the

wastewater treatment plant (WWTP). The solids are managed

in a variety of ways, but primarily are disposed of in

Subtitle C and D landfills (78 percent in 1992).

Many refineries reduce tank bottom buildup with in-tank

mixers. Mixers keep the sediments or solids continuously in

suspension so that they travel with the residual oil.

In 1992, less than one percent of the volume of

residual oil tank bottom sludge was reported to be managed

as hazardous. Of the few refineries that reported a

hazardous waste designation for this residual in 1992, only

one reported a hazardous waste code (the others specified

handling the sludge as hazardous without designating a

code).

3.12.1.2 Generation and Management

The refineries reported generating 9,107 MT of residual

oil tank bottom sludge in 1992. Residual oil tank sludge

includes sludges from No. 6 oil and similar product tanks.

Sludges from tanks identified as containing a mixture of

residual oil and clarified slurry oil were included in the

scope of K170 and are omitted here. Residuals were assigned

to be "residual oil tank sludge" if they were assigned a

residual identification code of "residual oil tank

sediment," corresponding to residual code "01-B" in Section

VII.1 of the questionnaire. Process wastewaters,

decantates, and recovered oils (e.g., from deoiling or

dewatering operations) were eliminated from the analysis.

These correspond to residual codes "09," "10," and "13"

(newly added "recovered oil") in the questionnaire. Quality

assurance was conducted by ensuring that all residual oil

tank sludges previously identified in the questionnaire

(i.e., in Section V.D) were assigned in Section VII.1.

Table 3.12.1 provides a description of the 1992 management

practices, quantity generated, number of streams reported,

number of streams not reporting volumes, and average

volumes.

When cleaning a tank, it is common for refineries to

use some type of in situ treatment, such as washing with

lighter fuel, to recover oil from the top layers of sludge

where there is a high percentage of free oil. However,

treatment or recovery practices after this depend on the

refinery's planned final management method. If land

disposed (as most residual oil tank sludge was in 1992), low

free liquid must be achieved; such levels can be achieved by

sludge deoiling/dewatering or stabilization. A refinery may

conduct this treatment for only some of the waste (e.g., the

top layers); in the deeper sections of sludge where free

liquid levels are lower no treatment may be performed. In

addition to lower liquid levels, treatment or deoiling may

be used to achieve lower levels of benzene or other

hazardous properties.

3.12.1.3 Plausible Management

EPA believes that most of the plausible management

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practices for this residual were reported in the 1992 RCRA

3007 Survey, as summarized above in Table 3.12.1. The

Agency gathered information suggesting other management

practices have been used in other years including: "recovery

onsite in an asphalt production unit" (9.2 MT), "transfer

for direct use as a fuel or to make a fuel" (380.8 MT),

"transfer with coke product or other refinery product" (5

MT), "onsite industrial furnace" (39 MT), "recycle to

process" (unknown quantity), "recovery in coker" (unknown

quantity), and "recovery in a catalytic cracker" (unknown

quantity). These non-1992 management practices are generally

comparable to the recycling practices reported in 1992.

3.12.1.4 Characterization

Two sources of residual characterization were developed

during the industry study:

Table 3.12.2 summarizes the physical properties of

residual oil tank sludges as reported in Section

VII.A of the 3007 survey.

Two record samples of actual residual oil sludge

were collected and analyzed by EPA. These

sludges represent the various types of treatment

typically used by the industry and are

summarized in Table 3.12.3.

Table 3.12.2. Residual Oil Tank Sludge: Physical

Properties

Properties # of # of 10th % Mean 90th %

Values Unreported

Values

pH 39 87 5.5 7 8.5

Reactive

CN, ppm 27 99 0 0.3 5

Reactive

S, ppm 27 99 0 2.5 15

Flash

Point, øC 42 84 60 93.3 140

Oil and

Grease,

vol% 36 90 9 34.1 99

Total

Organic

Carbon,

vol% 20 106 3.5 51 85.3

Vapor

Pressure,

mm Hg 11 115 0 0.1 10

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Vapor

Pressure

Temperature,

øC 9 117 25 37.8 38

Viscosity,

lb/ft-sec 6 120 0.01 50.2 500

Specific

Gravity 30 96 0.9 1.2 2.4

BTU Content,

BTU/lb 16 110 600 5,000 20,000

Aqueous

Liquid, % 78 48 0 0 50

Organic

Liquid, % 82 44 0 18 86

Solid, % 91 35 1 60 100

Other, % 65 61 0 0 0

Particle

>60 mm, % 4 122 0 0 0

Particle

1-60 mm, % 6 120 0 50 100

Particle

100 æm-1

mm, % 5 121 0 50 100

Particle

10-100 æm, % 4 122 0 0 1

Particle

<10 æm, % 4 122 0 0 0

Median

Particle

Diameter,

microns 3 123 0 0 15,000

1 Facilities were not required to do additional testing,

therefore information provided was based on previously

collected data or engineering judgement.

Table 3.12.4 provides a summary of the characterization

data collected under this sampling effort. The record

samples collected are believed to be representative of

residual oil tank sludges generated by the industry.

The samples collected of the composite of oily and

de-oiled sediment are representative of industry treatment

practices. As reported in the RCRA 3007 questionnaires, 10

of the 34 residual oil tank sludges (30 percent) that were

ultimately managed in a land treatment or landfill in 1992

were deoiled in some manner, most often by filtration or

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centrifuge. This management resulted in volume reduction

averaging 55 percent. Another 7 (20 percent) were

stabilized, resulting in the volume increasing by an average

of 55 percent. The remaining 17 residuals (50 percent) were

not reported to be treated ex situ in any manner. The

sampled refineries represent two alternative interim

management procedures: free liquid reduction using

stabilization (Amoco), and ex situ deoiling (Star).

Therefore, the record samples represent the various types of

ex situ treatment typically performed for residual oil tank

sludge, but may not represent cases in which no treatment is

performed. However, the same contaminants will be present

in all three types of sludge (i.e., deoiled. stabilized, and

untreated), but their levels may differ.

As illustrated in Table 3.12.4, none of the record

samples exhibited a hazardous waste characteristic. Only

constituents detected in at least one sample are shown in

this table.

3.12.1.5 Source Reduction

Only a small quantity of sludge was reported to be

deoiled in 1992, as reported in the 3007 survey. Of the 34

residuals disposed in landfills or land treatment units in

1992, 10 residuals, totaling approximately 1,000 MT. The

remaining 24 residuals, totaling approximately 7,600 MT,

were reported to be untreated or underwent volume addition

treatment (such as stabilization. As stated in Section

3.12.1.3, the average volume reduction achieved by deoiling

was 55 percent (as calculated from those facilities

providing sludge quantities prior to and following deoiling

in 1992).

In situ oil recovery techniques can greatly reduce the

total amount of residual oil tank sludge to be disposed as

well as reduce volatile constituents such as benzene. As

discussed above, recovery methods include distillate

washing, nonpetroleum solvent washing, water wash with

surfactant, and steam stripping. These operations

allow entrapped oil to float to the top of the sediment

layer and be recovered prior to removal from the tank.

Separated oil is recycled back to the process or sent to the

slop oil tanks, and the water phase is sent to the WWTP.

Oily sludges are emulsions formed due to a surface

attraction among oily droplets, water droplets, and solid

particles. If the solids are large and dense, the resultant

material will settle and become a sludge. The surface

charge interactions between the solid particles and oil

droplets cause the sludge to become stable and difficult to

separate. However, the sludge can be separated into its

individual components by mechanically removing the solids or

by neutralizing the surface charge on the solids and oil

droplets.

The predominant method of minimizing the formation of

tank sludge is the use of mixers to keep the sludges

continuously in suspension. A common mixer configuration is

a sweeping mixer that automatically oscillates to produce a

sweeping motion over the floor of the tank, keeping the

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heavy oil and particles suspended.

Of the twenty facilities that EPA visited, eight listed

methods in recovering oil from tank sludges. Several

facilities wash the tanks with light oils and water, whereas

another facility washes with a surfactant followed by

pressure filtration.

BIBLIOGRAPHY

1992 RCRA 3007 Survey of the Petroleum Refining Industry

Database.

Department of Energy, Energy Information Administration.

Petroleum Supply Annual 1992, Volume 1. May 1993.

Donald Bonett, "ASTM D-396 Specification for No. 6 Fuel

Oil," in Proceedings, 1993 Fuel Oil Utilization Workshop,

Electric Power Research Institute, August 1994 (page 3-101).

Fuel Oil and Kerosene Sales 1994, U.S. Department of Energy,

September 1995 (DOE/EIA-0340(92)/1).

Hydrocarbon Processing. "Refining Processes '94." November

1994.

Hydrocarbon Processing. "Gas Processing '94." April 1994.

Kirk-Othmer. Encyclopedia of Chemical Technology. Third

Edition, Volume 22. 1983.

McKetta, John J. Petroleum Processing Handbook. Marcel

Dekker, Inc. 1992.

Meyers, Robert A. Handbook of Petroleum Refining Processes.

McGraw-Hill Book Company. 1986.

Perry's, 1950. John H. Perry, ed. Chemical Engineer's

Handbook. McGraw-Hill, New York. Third edition, 1950.

Speight, 1991. James Speight. The Chemistry and Technology

of Petroleum. Marcel Dekker, New York. Second edition,

1991.

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