United States

Environmental Protection

Agency

Air

Office of Air Quality

Planning and Standards

Research Triangle Park. NC 27711

EPA-453/R-98-003

June 1998

PETROLEUM REFINERIES -

BACKGROUND INFORMATION FOR

PROPOSED STANDARDS

Catalytic Cracking (Fluid and Other)

Units, Catalytic Reforming Units, and

Sulfur Recovery Units
(This page is intentionally left blank)
EPA-453/R-98-003

Petroleum Refineries - Background

Information for Proposed Standards

Catalytic Cracking (Fluid and Other)

Units, Catalytic Reforming Units, and

Sulfur Recovery Units

·NESHAP
EPA- 453/R-98-003

Petroleum Refinery - Background Information for

Proposed Standards

Catalytic Cracking (Fluid and Other) Units, Catalytic

Reforming Units, and Sulfur Recovery Units

Emissions Standards Division

u.s. Environmental Protection Agency

Office of Air and Radiation

Office of Air Quality Planning and Standards

Research Triangle Park, North Carolina 27711

June 1998
Disclaimer

This report has been reviewed by the Emission Standards Division

of the Office of Air Quality Planning and Standards, EPA, and

approved for publication. Mention of trade names or commercial

products is not intended to constitute endorsement or

recommendation for use. Copies of this report are available

through the Library Services Office (MD-35), u.s. Environmental

Protection Agency, Research Triangle Park, NC 27711, or from the

National Technical Information Service, 5285 Port Royal road,

Springfield, VA 22161.
Environmental Protection Agency

Background Information for Propos.ed Standards

National Emission Standards for Hazardous Air Pollutants for

Petroleum Refinery Process Vents

Prepared by:

Bruce Jordan

Director, Emission Standards Division

u.S. Environmental Protection Agency

Research Triangle Park, NC 27711

(Date)

1. The proposed standards would regulate emission of hazardous

air pollutants (HAP) emitted from Petroleum Refinery

process vents. Only those process vents that are part of

major sources under Section 112(d) of the CAA would be

regulated. The recommended standards would reduce emissions

of xxx of the chemicals identified in the CAA list of

hazardous air pollutants.

2. Copies of this document have been sent to the following

Federal Departments: Labor, Health and Human Services,

Defense, Office of Management and Budget, Transportation,

Agriculture, Commerce, Interior, and Energy; the National

Science Foundation; and the Council on Environmental

Quality. Copies have also been sent to members of the State

and Territorial Air Pollution Program Administrators; the

Association of Local Air Pollution Control Officials; EPA

Regional Administrators; and other interest parties.

3. For additional information contact:

Mr. Robert Lucas

Waste and Chemical Processes Group (WCPG)

u.S. Environmental Protection Agency

Research Triangle Park, NC 27711

Telephone: (919) 541-0884

4. Copies of this document may be obtained from:

u.S. EPA Library (MD-35)

Research Triangle Park, NC 27711
CONTENTS

Chapter

LIST OF TABLES

LIST OF FIGURES

ix

xi

1 . 0 INTRODUCTION . . . . . . . .. .... .. 1-1

1.1 Background . . . . . . . . . . . . . . . . 1-1

1.2 Petroleum Refinery Vents NESHAP .... . .. 1-1

1.3 Purpose of This Document . . . . ..... 1-2

2.0 INDUSTRY DESCRIPTION ..... . . 2-1

2.1 Petroleum Refinery Industry Profile 2-1

2.2 Petroleum Refinery Industry Description 2-3

2.2.1 Catalytic Cracking Units 2-3

2 .2 .2 Catalytic Reforming Uni ts . . . . . . . . . 2-4

2 .2 .3 Sulfur Plant Uni ts .... . . . . 2-4

2.3 References . . . . . . . . . . .. . ..... 2-5

3.0 PROCESS DESCRIPTION AND EMISSION POINTS 3-1

3.1 Catalytic Cracking Unit (CCU) 3-1

3 .1.1 CCU Process Description. 3-3

3 .1.2 CCUCR Process Description .. 3-4

3 .-1.3 CCU Emission Points . .. 3-4

3.2 Catalytic Reforming Unit (CRU) 3-9

3 .2.1 CRU Process Description . . . . .. .. 3-9

3.2.2 CRU Catalytic Regeneration Process

Description . . . . . . . . . . . . . . . 3-10

3.2.3 CRU Emission Points . . . . . . . . . . . 3-16

3.3 Sulfur Recovery Plant . . . . . . . . 3-17

3.3.1 Sulfur Recovery Unit (SRU) Process

Description . . . . . . . . . . . . 3-18

3.3.2 Tail Gas Treatment Unit (TGTU) Process

Description . . . . . . . . . . . . . 3-18

3.3.3 Claus Sulfur Recovery Plant Emission

Points ... ... . . . . . 3-20

3.4 References . . . . . . . . . . . . . . . . . . . 3-22

4.0 CONTROL TECHNOLOGY AND PERFORMANCE OF CONTROLS 4-1

4.1 CCUCR Vent Emission Controls . .. . 4-1

4.1.1 Metal HAP Emission Controls for the

CCUCR Vent 4-1

4.1.2 Organic HAP Emission Controls for the CCUCR

Vent 4-4

4.2 HAP Emission Controls for the eRU Purge Vent . 4-5

4.2.1 HAP Emission Controls for the CRU Purge

Vent 4- 6

vii
CONTENTS (Continued)

4.2.2 HAP Emission Controls for the CRUCR Coke

Burn Vent · · · · · · · · · · 4-6

4.2.3 HAP Emission Controls for the CRUCR Final

Purge Vent · · · · · · · · · · 4-6

4.3 Sulfur Plant Vent Emission Controls · · · · · · 4-7

4.3.1 TGTU as a HAP Emission Control for the SRU

Vent · · . . · · · · 4-7

4.4 References · · · · · . · · · · 4-9

5.0 MODEL PLANTS AND EMISSION ESTIMATES · · · · · · 5-1

5.1 Model Plants . · · · · · · · · · · 5-1

5.2 HAP Emissions From CCU Regeneration · · · 5-2

5.3 HAP Emissions From Cru Regeneration · · · · · 5-8

5.4 HAP Emissions From Sulfur Recovery Units (SRUs) 5-13

5.5 References . · · · · · · · · · · · 5-15

6.0 OTHER ENVIRONMENTAL AND ENERGY IMPACTS ESTIMATES

6.1 Other Environmental Impacts for CCUCR Vents

6.2 Other Environmental Impacts for CRUCR Vents

6.3 Other Environmental Impacts for SRU Vents

· . . 6-1

· 6-1

· 6-4

· . . . 6- 6

7.0 MONITORING OPTIONS · · · · · 7-1

7.1 Monitoring Options for the CCUCR Vent · · · · 7-1

7.2 Monitoring Options for the CRUCR Vent · · · · · 7-3

7.3 Monitoring Options for the SRU Vent · · · · · 7-3

7.4 References · · · · · · · · · · · · · · 7-4

8.0 COST OF CONTROLS FOR MODEL PLANTS · . · · · · · · · 8-1

8.1 Costs of Control Devices for CCUCR Vent · · · 8-1

8.1.1 Cost's for ESPs · · . · . · · · · 8-2

8.1.2 Cost for Ventu+i Wet Scrubbers · · · · · · 8-4

8.1.3 Costs for CO Boilers/Incinerators · · · · 8-6

8.2 Costs of Control Devices for CRUCR Vent · · · · 8-7

8.3 Costs of Control Devices for Sulfur Plant Vent · · 8-9

8.4 Costs of Monitoring, Reporting, and

Recordkeeping · · · · · · · · · · · 8-10

8.5 References . · · · · · · · 8-13

viii
. 8-6

8-7

Table

2-1

5-1

5-2

5-3

5-4

5-5

5-6

5-7

5-8

5-9

5-10

5-11

6-1

6-2

6-3

6-4

6-5

6-6

6-7

8-1

8-2

8-3a

8-3b

8-3c

8-4

8-5a

8-5b

8-5c

8-6

8-7

LIST OF TABLES

US Refineries-State Capacities as of

January 1, 199 7 . . . . . . . . . . . . . . . . . . . 2 - 2

Summary of Organic HAP Data From CCU Regeneration . . 5-5

Summary of Controlled Metal HAP Emissions and Hel

Data From CCU Regeneration 5-6

Summary'of HAP Emission Factors for CCU Regeneration 5-6

Summary of Range of Potential hap Emission for CCU

Regeneration From the Model Plants 5-7

Summary of Nationwide Emissions Estimates for CCU

Regeneration 5-8

Summary of HAP Data From CRU Regeneration . . . 5-11

Summary of HAP Emission Factors for CRU

Regeneration 5 -12

CRU HAP Emission Estimates for Model Plants . . . . 5-12

Nationwide HAP Emission Estimates for CRU

Regeneration 5-13

Summary of HAP Emissions Data for SRU Vents . . . . 5-14

HAP Emission Estimates for SRU Vents 5-14

Comparison of Other Environmental and Energy Impacts

for Inorganic HAP Emission Control Devices for the

CCUCR Vent 6-3

Annual Other Environmental and Energy Impact

Estimates for Model CCUCR Vent Incinerators . . . . . 6-4

Nationwide Annual Other Environmental and Energy

Impacts Estimates for the CCUCR Vent 6-5

Other Environmental and Energy Impacts Estimates for

Model Plant CRUCR Vents . . . . . .. 6-6

Nationwide Annual Other Environmental and Energy

Impacts Estimates for the CRUCR Vent . . . . . 6-6

Annual Other Environmental and Energy Impact Estimates

for Model SRU Vent Incinerators . .. 6-7

Nationwide Other Environmental and Energy Impact

Estimates for SRU Vents . . 6-7

Model Plant CCUCR Vent Flow Rates . . . . . . 8-1

Design values for ESP . . .. .. 8-2

Model Plant CCUCR ESP Control Costs-TCI . .. .. 8-3

Model Plant CCUCR ESP Control Costs-AOC . . . . 8-3

Model Plant CCUCR ESP Control Costs-TAC 8-3

Design Values for Venturi Scrubbers . . . . 8-4

Model Plant CCUCR Venturi Scrubber Control Costs-TCI 8-5

Model Plant CCUCR Venturi Scrubber Control Costs-AOC 8-5

Model Plant CCUCR Venturi Scrubber Control Costs-TAC 8-5

Model Plant CCUCR Incinerator Control Costs-TCI,

AOC, and TAC .

Model Plant CRUCR Vent Flor Rates . . . . . .

ix
8-8

8-9

8-10

8-11

LIST OF TABLES (Continued)

Model Plant CRUCR Wet Scrubber/Absorber Control

Costs-TCl, AOe, and TAC . . . . . . . . . . . . . . . 8-8

Model Plant SRU Vent Flow Rates . . . . . . . . . . . 8-9

Model PlantSRU Incine~ator Control Costs-TCl, AOC,

and TAC . . . . . . . . . . . . . . . . . . . . . . 8-10

First Cost and Initial Annual Cost for Continuous

Emission Monitors on CCUs, CRUs, and SRUs . . . . . 8-12

x
Figure

LIST OF FIGURES

3-11

3-19

3-12

3-1

3-2

3-3

3-4

3-5

3-6

Fluid catalytic cracking unit . . 3-2

Simplified schematic of non-fluid (thermal) catalytic

Cracking unit (TCCU) . . 3-6

Typical regeneration process flow diagram for

semi-regenerative catalytic reformers

Typical regeneration process flow diagram for

cyclic catalytic reformers . . . . .

Typical process flow diagram for continuous

reformers . . . . . . . . . . . . . . . . . . . . . 3-13

Refinery MACT discussions: process vents Clause

sulfur recovery units .. . . . . . . . . .

xi
.' I ._ : .....

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xii

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1.0 INTRODUCTION

1.1 BACKGROUND

Title III of the 1990 Amendments to the Clean Air Act

(CAA) substantially revised section 112 of the Act regarding

the development of National Emission Standards for Hazardous

Air Pollutants (NESHAP). To implement the congressional

directives of Title III, the U.s. Environmental Protection

Agency (EPA) has initiated a program to develop NESHAP for

certain categories of stationary air emission sources that

emit one or more of the hazardous air pollutants (HAP)

listed in section 112(b) of the CAA.

1.2 PETROLEUM REFINERY VENTS NESHAP

On July 16, 1992, EPA published a list of all source

categories emitting HAP (57 FR 31576) and included Petroleum

Refineries among the listed source categories. On August

18, 1995, EPA promulgated a NESHAP for the petroleum

refinery source category primarily for organic HAP emission

sources (60 FR 43244). In the 1995 petroleum refinery

NESHAP, EPA specifically excluded three process vents from

the NESHAP because of the unique characteristics of the

inorganic emissions from each of these vents and stated that

II these emission points are included in a separate source

category under a separate schedule. II These three process

vents are the subject of this rulemaking entitled IINESHAP:

Petroleum Refineries - FCC Units, Reformers, and Sulfur

Plants. II The emission sources considered under this

rulemaking include: 1) the catalyst regeneration process

vent(s) from the catalytic cracking unit (CCU); 2) the

catalyst regeneration process vent(s) from the catalytic

1 - 1
reforming unit (CRU); and the process vent(s) for the sulfur

recovery plant.

1.3 PURPOSE OF THIS DOCUMENT

In developing NESHAP, the EPA evaluates different

strategies for reducing air emissions from the source

category. For selected control strategies, the EPA develops

emission and control cost impacts to support in the

development of the NESHAP. This technical support document

(TSD) presents the information and methods used by EPA to

perform the control strategy impact analysis.

Chapter 2 presents. a brief overview of the petroleum

refinery industry as pertaining to the CCU, CRU, sulfur

recovery processes. Chapter 3 provides a" more detailed

description of each of the processes, the type of HAP

emitted, the process emissions points. Chapter 4 describes

the control technologies available for reducing HAP

emissions from each of the process vents. The procedures

used to estimate current (baseline) and controlled emission

are provided in Chapter 5; the procedures used to estimate

the other environmental and energy impacts associated with

the control strategies are provided in Chapter 6. The

options considered for monitoring the emission points are

discussed in Chapter 7. Chapter 8 describes the methods and

procedures used to estimate the control cost impacts

associated with the selected control and monitoring

strategies.

1 - 2
2.0 INDUSTRY DESCRIPTION

This chapter presents a brief overview of the petroleum

refinery industry in general" with particular industry

descriptions of catalytic cracking units (CCUs), catalytic

reforming unit (CRUs), and the sulfur recovery plants.

2.1 PETROLEUM REFINERY INDUSTRY PROFILE 1

There are approximately 162 petroleum refineries in 33

States nationwide (see Table 2-1). These 162 refineries

process 15.4 million barrels of crude oil daily. As seen in

Figure 2-1, the following three States dominate U.S. crude

oil refining: California (14.2 percent of the refineries

and 12.3 percent of the crude capacity); Louisiana (11.7

percent of the refineries and 15.7 percent of the crude

capacity); and Texas (17.3 percent of the refineries and

26.1 percent of the crude capacity). Together, these three

States represent 43 percent of the U.s. refineries and

54 percent of the total nationwide crude oil processing

capacity.

There are 36 petroleum refineries with crude oil

processing capa~ities of 20,000 barrels per calendar day

(bled) or less. Most of these small capacity refineries do

not have the processes of interest for this source category

(only 3 have a CCU and 8 have a CRU). In the petroleum

refinery industry, however, a small business is defined as

any business that processes less than 75,000 bled of crude

oil and employs 'less than 1,500 people corporately. There

are 94 petroleum refineries that process less than

2 - 1
Table 1. U.S. Refineries-State Capacities as of January 1, 1997a

Crude Catalytic Catalytic Sulfur

No. of capacity, crackling, reforming, Production

State plants bled bled blcd ,tid'

Alabama 3 134,225 0 26,480 131

Alaska 6 283,000 0 12,000 15

Arkansas 3 65,200 19,100 12,400 88

California 23 1,898,815 608,470 428,260 1,768

Colorado 2 85,500 27,000 19,000 44

Delaware 1 140,000 63,000 45,900 448

Georgia 2 34,000 0 0 0

Hawaii 2 149,000 21,000 13,000 20

Illinois 6 909,550 322,200 336,920 435

Indiana 3 435,990 157,050 92,000 370

Kansas 3 283,350 79,120 . 60,470 81

Kentucky 2 224,800 97,000 43,195 0

Louisiana 19 2,417,290 885,900 463,200 2,552

Michigan 3 121,200 45,500 27,900 25

Minnesota 2 355,000 108,810 75,795 750

Mississippi 4 336,800 63,000 71,000 1,067

Montana 4 143,850 53,000 31,500 0

Nevada 1 7,000 0 0 0

New Jersey 6 674,000 282,700 118,400 0

New Mexico 3 97,600 32,331 31,800 2

North Dakota 1 58,000 24,700 11.500 15

Ohio 4 499,650 173,550 153,200 0

Oklahoma 5 403,000 109,700 88,050 95

Pennsylvania 6 574,400 122,500 128,488 0

Tennessee 1 105,000 50,000 16,000 42

Texas 28 4,019,600 1.588,300 1,133,600 4,211

Utah 5 159,500 43,400 31,400 46

Virginia 1 56,700 25,700 10,800 66

Washington 7 587,250 117.500 126,300 241

West Virginia 1 10,500 0 3,300 1

Wisconsin 1 36,000 10,400 7,600 15

Wyoming 4 126,825 49,200 29,125 2

TOTAL 162 I 15,432,595 5,180,583 3,648,583 12,530

a Data obtained from Reference 2, but omits one facility in Oregon

that has no reported crude capacity (apparently an asphalt plant).

Data also omits Tasca Refining Co. in Marcus Hook, PA (180,500

bled capacity) that was idled in 1996; it is expected to restart mid1997.

2 - 2
75,000 bled of crude oil. Approximately half of these are

considered to be small businesses based on the number of

corporate employees as reported in an industry survey. 3

There are 24 petroleum refineries with crude oil processing

capacities of 200,000 bled or more, and these 24 refineries

represent almost 44 percent of the u.s. crude oil refining

capacity.

Over the past 5 years the total nationwide petroleum

refining capacity has dropped slightly, but the actual crude

oil processing rates have risen slightly. The total

petroleum refining capacity was 15.6 million bled in 1990

compared to 15.3 million bled in 1995. During the same time

frame, the total number of operating refineries fell from

184 to 173. However, the actual crude oil processing rate

increased from 13.6 million bled in 1990 to 14.1 million

bled in 1995. Thus, the U.S. petroleum refining capacity

utilization has increased from 87 percent in 1990 to 92

percent in 1995. 4

Future trends in the petroleum refining industry are

expected to mirror the past five years. According to u.S.

Department of Energy and Commerce projections, refinery

shutdowns are expected to continue, but the crude oil

processing rate is expected to remain relatively stable as a

result of increased capacity utilization at existing

facilities. The demand for refined petroleum products is

expected to grow an average of 1.5 percent per year, which

is slower than the expected growth rate of the economy.s

2.2 PETROLEUM REFINERY INDUSTRY DESCRIPTION

2.2.1 Catalytic Cracking Units 6

The nationwide petroleum refinery catalytic cracking

(fluid and other) charge capacity was 5.18 million bled in

January 1997. 1 There are 105 petroleum refineries that

operate a total of 117 CCU [either fluid andlor other

(non-fluidized) CCU]. However, fluid CCUs dominate the ccu

processes in the petroleum refinery industry. There are

only 7 refineries that reported operating a non-fluidized

2 - 3
CCU, only 4 of which reported operating only a non-fluidized

CCU, and non-fluidized CCUs accounted for only 2.9 percent

of the total catalytic cracking process charge rate.

There are 9 refineries that reported catalytic cracking

charge capacities of less than 10,000 bled. There are 8

refineries that reported charge capacities of greater than

100,000· bled; half of these refineries have more than one

catalytic cracking unit.

2.2.2 Catalytic Reforming Units?

The total nationwide catalytic reforming charge

capacity was 3.65 million blcd in January 1997. There are

124 refineries that operate some form of CRU. There are

three major types of CRU catalytic regeneration processes:

semi-regenerative; cyclic; and continuous (see Section 3.2

for CRU process description). There are 111 refineries,

representing 49 percent of reforming capacity, that use

semi-regenerative process technologies; 23 refineries with

24 percent of reforming capacity employed the cyclic process

technologies; and 32 refineries with 27 percent of reforming

capacity employed the continuous process technologies.

There are 15 petroleum refineries that have reforming

capacities of 5,000 bled or less, and 14 petroleum

refineries that have reforming capacities of 50,000 bled or

more.

2.2.3 Sulfur Plant Units 8

Production of sulfur (all forms measured as pure

elemental sulfur) from petroleum refineries was reported at

2,940 thousand Mg in 1985 and 4,200 thousand Mg in 1990.

There are 130 u.s. refineries that report operating some

form of sulfur production units (in 1992), representing a

total sulfur production capacity of 20,500 Mg/day.

There are 52 refineries that have sulfur production

capacities of less than 50 Mg/daYi 24 refineries have sulfur

production capacities greater than 300 Mg/day; and 5

refineries have sulfur production capacities greater than

500 Mg/day.

2 - 4
Of the 130 refineries that have sulfur recovery plants,

88 provided the number of sulfur plant trains (units) at the

facility; the total number of units reported was 144 sulfur

trains; 38 reported multiple trains with 13 reporting 3 or

more units.

2 . 3 REFERENCES

1. Radler, Marilyn, Survey Editor. "1996 Worldwide

Refining Survey. II Oil and Gas Journal. OGJ Special,

December 23, 1996. pp. 49 through 94.

2. Reference 1.

3. u.S Environmental Protection Agency. Responses to

Information Collection Request for Petroleum

Refineries. Publication No. XXXXX. Office of Air

Quality Planning and Standards, Research Triangle Park,

NC. 1992.'

4. Lidderdale, T., N. Masterson, and N. Dazzo. "U.S.

Refining Capacity Utilization." Energy Information

Administration, Petroleum Supply Monthly. pp. 33

through 39.

5. u.S Environmental Protection Agency. EPA Office of

Compliance Sector Notebook Project - Profile of the

Petroleum Refining Industry. Publication No. EPA/310-

R-95-013. Office of Enforcement and Compliance

Assurance, Washington, DC. September 1995. pp. 10

and 11.

6. Reference 1.

7. Reference 1.

8. 1992 Report on Sulfur Production. Chemical Economics

Handbook. 1992.

2 - 5
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3.0 PROCESS DESCRIPTION AND EMISSION POINTS

This chapter presents a description of the processes

associated with the three refinery vents of interest:

catalytic cracking unit (CCU) catalyst regeneration process

vent (CCU vent), the catalytic reforming unit (CRU) catalyst

regeneration process vent (CRU vent), and the sulfur

recovery plant vent (SRU vent). For each process vent,

process descriptions are provided with an emphasis on the

sources of hazardous air pollutants (HAP) and a description

of the emission release points. Much of the following

process descriptions result as a composite of infromation

collected during site visits to petroleum refineries (see

References 1 through 5). The Petroleum Refinery Enforcement

Manual 6 and the EPA Sector Notebook for petroleum refining7

are also general references for the process descriptions

provided in the chapter.

3.1 CATALYTIC CRACKING UNIT (CCU)

The CCU (fluid or other) is used to upgrade the heavy

distillates to lighter, more useful distillates such as

heating oils or gasoline. The typical CCU system consists

of a CCU reactor, a CCU catalyst regenerator (CCUCR), vent

gas process equipment for energy recovery and/or emission

control, and an exhaust stack (see Figure 3-1). Nearly all

CCU systems operate as fluidized-bed reactors and use air or

oil gas flow to transport the catalyst between the CCU

reactor and the CCUCR. These fluidiied CCU systems are

3 - 1
, • Products

Reactor

Auxiliary Air

and Auxiliary

Fuel

VJ

tv

1411 Steam

Flue Gas

Regenerator

CO

Boiler

Energy Recovery

Particulate

Removal

Device

Flue Gas

Exhaust Stack

t:l

1-3

§

CD

""

""

co

, Air

Regenerated Catalyst Transfer Line

Figure 3-1. Fluid catalytic cracking unit.
commonly referred to as FCCUs (fluid catalytic cracking

units), and the process descriptions that follow will focus

primarily on FCCU operation due to their dominance in the

industry. However, since catalyst regeneration vents for

non-fluid CCus are included in this source category, the

term ceu is used throughout this document to refer to both

FCCU and other "thermal" CCU (TCCU). The terms FCCU and

Teeu will be used to refer to a specific type of ecu.

3.1.1 FCCU Process Description

The Feeu catalyst may be silica-based, alumina-based,

or zeolite based fine powder that is easily fluidized in

air. Hot catalyst from the regenerator is typically

returned to the Feeu reactor in a vertical ,tube referred to

as the riser (see Figure 1). Preheated liquid gas oil is

fed to the base of the riser, where it comes into contact

with hot catalyst from the regenerator. The gas oil

vaporizes at this point of initial contact, and the gas oil

vapors rise, carrying the catalyst with them. The gas oil

vapors undergo cracking reactions as they mix wit~ the

catalyst particles. Some of the reaction products, however,

are deposited on the catalyst in the form of coke (carbon),

which reduces catalyst activity. The mixture of products

and catalyst flows up the riser into the eeu reactor vessel.

Current research indicates that most of the cracking

reactions take place in the riser. As such the Fceu reactor

functions primarily to separate the vapor products from the

catalyst.

eatalyst entrained with the vapor products are

typically disengaged from the vapor product by flow (impact)

impingers followed by cyclone separators. The vapor

products pass through the internal cyclones and are vented

from the top of the Fceu reactor to a fractionation column

for product separation. The disengaged catalyst is

collected at the base of the reactor where the catalyst is

stripped with steam to remove any hydrocarbons that may have

deposited on the catalyst before returning the catalyst to

the regenerator.

3 - 3
spent catalyst collected in the FCCU reactor is

continuously returned to the regenerator to burn off coke

deposits. After the coke is burned off, the regenerated

catalyst flows down a transfer line for reuse and is then

introduced to the gas oil feed stream at the beginning of

the riser, and the proc~ss repeats itself.

The spent catalyst that is returned from the CCU

reactor is continuously regenerated by burning off coke that

was deposited on the catalyst in the riser and ecu reactor.

Air is blown into the regeneration vessel for use in the

combustion reaction and to mix (fluidize) the catalyst. The

coke deposited on the catalyst serves as the carbon fuel

source. There are two basic types of eeu regenerators:

complete combustion regenerators and partial combustion

regenerators. In a complete combustion regenerator, the

regenerator is typically operated at approximately 1,200 to

l,400 oF with excess oxygen and low levels « 500 ppmv) of

carbon monoxide (CO) in the exhaust flue gas. In a partial

(or incomplete) combustion regenerator, the regenerator is

typically operated at approximately 1,000 to 1,20QoF under

oxygen limited conditions and relatively high levels (1 to

3 percent) of CO. Small amounts of platinum may be added to

the eeUCR to promote combustion; "De-SOx" or other SOx

scavenging additives may be added to reduce SOx emissions;

and fresh catalyst may be added to the CCUCR to maintain

catalyst activity and replace catalyst lost from the system.

Prior to exiting the CeUCR, catalyst particles entrained

with the flue gases are initially removed by internal

cyclone separators.

3.1.2 TCCU Process Description

The TeCU process employs catalyst pellets rather than

the fine catalyst powder used in FCCUs. The TCCU pellets

are roughly 1/8 inch (3,175 ~) long compared to a typical

FCCU powder diameter of 85~. Due to the size of the

catlyst, moving bed catalyst recirculation is used rather

than fluidized bed. Figure 3-2 provides a simplified

schematic of a typical TCCD. The TCCD catalyst enters the

3 - 4
top of the vertical reactor and flows in. a plug flow fashion

down the reactor bed by gravitational force (refer to

Figure 2). Oil feed is introduced near the top of the

reactor portion of the TCCU where it mixes with the hot

catalyst pellets and flows cocurrent with the catalyst bed.

The feed oil vaporizes and the vapors and the cracking

reactions occur. The catalyst and vapor products, upon

reaching the bottom of the reactor, pass through a vapor

disengaging grid. Vapor is disengaged from the catalyst and

drawn off by a series of vapor tubes. Purge steam is

introduced below the vapor draw off tubes to purge any

remaining oil vapor from the catalyst pellets. The purge

steam is also removed from the system via the vapor draw off

tubes along with the oil vapor products.

Purged catalyst pellets continue to move downward to

the regenerator (or kiln) portion of the TCCU. Air is

introduced near middle of the regenerator section in a

controlled manor to regulate the temperature and coke burnoff rate. The operating pressure in the TCCU regenerator is

approximately 3 psig compared to 30 psig for a FCCU

regenerator. Flue gas is removed from the system both near

the top of the regenerator and near the bottom of the

regenerator. Approximately 70 percent of the air feed

passes upward through the regenerator and 30 percent flows

downward with the catalyst. Flue gas is separated from the

catalyst at the bottom of the regenerator is a similar

fashion as oil vapor was disengaged from the catalyst at the

bottom of the reactor. The flue gas streams combine and

either fed to a CO boiler or released directly to the

atmosphere through a single stack vent.

3 - 5
Flow deflector--t-I.

Vent to atmosphere

t

Surge Tank

Catalyst lift --~ Catalyst feed

TCC Reactor

011 feed --+----~

I:;:::=;::~::;:::;=:;:;::::::J)-' Vaporized oil products to distillation

Steam in

Upper flue --+-+----+-1--.1

gas vent

TCC Regenerator

~--t--- Combustion air In ""r!r-rrr-.n~~r""""II'''''''+--

.- Regenerated catalyst recirculation

t

Lift airline

Figure 3-2. Simplified Schematic of non-fluid (the~l)

catalytic cracking unit (TCCU).

3 - 6
Below the regenerator, the catalyst flows through a

cooler section to cool the catalyst and recover latent heat.

The catalyst is then transported to the catalyst surge

vessel at the top of the TceD via catalyst lift pipe. The

surge vessel acts both as reservoir for the catalyst and as

a catalyst / lift air separator. The lift air is vented

from the surge vessel to the atmosphere. Catalyst is fed to

the reactor from the surge vessel and the process repeats.

3.1.3 ceu Emission Points

There are two primary vents from the CCU system. The

first vent is the product oil gases that exit the ecu

reactor. This vent leads to a fractionation column for

product separation and is not a direct process vent emission

source. Process equipment leaks on this product side of the

ecu system result in a loss in product yield and the

refineries have an economic incentive to reduce or correct

any equipment leaks on the product side of the ecu system.

The second vent from the eeu system is the flue gas

exhausted from the ceDeR as a result of burning off coke

deposited on the catalyst. This exhaust vent is the primary

process emission vent from the eeu system. This vent will

be referred to in this document as the ceUCR vent, although

other references cited in this document may refer to this

vent as the ecu vent, the Feeu vent, or the process vent for

FCC units. Note, both FceD and Tecu have a ecueR vent.

The eCUeR vent stack flue gas is characterized by low

HAP concentrations and large volumes of gas. The final

ecueR vent stack is typically 6 to 16 feet in diameter,

depending of the ceu throughput, and 100 feet high. The

eCUeR vent from a TCCD are generally smaller, roughly 2 to 3

feet in diameter. Typical volumetric flow rates of flue gas

in the eCDCR vent stack range from 50,000 standard cubic

feet per minute (scfm) for smaller ceus to 400,000 scfm or

more for larger ceus. The total HAP concentrations in the

ceUCR vent stack flue gas ranges from 0.1 to 1 parts per

million by volume (ppmv). HAP that are commonly present in

the flue gas from the ceDCR include metals (primarily

3 - 7
nickel) and organics (primarily formaldehyde, acetaldehyde,

benzene, toluene, xylenes, hexane, and phenol). Other

metals that have been detected in the CCUCR vent flue gas

include: antimony, cadmium, chromium, cobalt, lead,

manganese, and mercury. Other organics that have been

detected (or suspected to be) in the ceUCR vent flue gas

include: naphthalene, polycyclic organic matter (POM),

dioxins, and furans. 8

The TCCU has an additional emission point from the

surge vessel where lift air used to transport catalyst from

the bottom to the top of the TCCU is vented to the

atmosphere. Catalyst particles may remain entrained with

the lift air so there is a potential for the surge tank vent

to emit the same metal HAP that are emitted from the CCUCR

vent. The relative volume of the lift air flow rate is

approximately one-third to one-half the flue gas flow rate

from the regenerator. However, due to the relative

characteristics of the surge vessel vent and the CCUCR vent,

the particulate emissions rate from the surge vessel vent

are expected to be roughly equivalent and may be higher than

the particulate emissions from the CCUCR vent. No data are

currently available regarding the HAP emissions from TCCU

surge vessel vent. As such, it is unclear how the overall

HAP emissions from the TCCU (CCUCR vent plus the surge tank

vent emissions) compare to the CCUCR emissions from a CCU

with similar throughput.

The metal HAP are expected to originate as contaminants

in the CCU feed that deposit on the catalyst particles.

Consequently the metal HAP emission rate may be dependent on

the mix of oils and residual used as feed to the CCU. Some

ceu feeds are hydrotreated. The hydrotreater removes

sulfur, nitrogen, vanadium, nickel and other contaminants

from the crude oil feedstocks. This II pretreatment " step

prior to the ceu t.ypdcel Ly helps to improve ecu yield,

prolongs catalyst life, and reduces CCU HAP emissions

according to industry representatives. 9 Because most of the

3 - 8
metal HAP emissions are in the form of particulate matter

(PM), PM control devices also reduce metal HAP emissions.

Many of the organic HAP emissions originate as byproducts of coke combustion (e.g., formaldehyde,

acetaldehyde, POM, dioxins and furans). It is unclear,

however, why the volatile organic HAP (benzene, toluene,

xylenes, and hexane) are not destroyed in the CCDCR. These

volatile organic HAP may originate as residual oil feed

material on the catalysts that somehow vaporize, but do not

combust prior to exiting the ceDCR.

Organic HAP emissions from partial combustion

regenerators may be expected to be higher due to the lack of

sufficient oxygen to completely combust the coke material.

However, most partial combustion regenerators employ a CO

boiler or incinerator to recover the latent heat energy of

the CO in the CCUCR flue gas. At this time, the EPA is

collecting data to determine whether a complete combustion

CCU system has significantly different HAP emissions from a

partial combustion ceu system followed by a CO boiler.

Equipment leaks and fugitive emissions are not

anticipated to be significant from the eCUCR flue gas

treatment train because of the low concentrations of HAP in

this vent stream.

3.2 CATALYTIC REFORMING UNIT (CRU)

3.2.1 CRU Process Description

The catalytic reforming process involves a complicated

series of reactions that occur over a catalyst that change

the chemical structure of the hydrocarbons. The predominant

reaction is the dehydrogenation of naphthenes to form

aromatics. The reactions occur over a noble metal catalyst,

such as platinum or rhenium. The feedstocks for reforming

(referred to as naphtha) are first treated to remove sulfur

and other compounds that would poison the reforming

catalyst. Because the reforming reaction is endothermic,

heat must be continually supplied to the system to maintain

optimal reaction temperatures. This is typically

3 -.9
accomplished by performing the reaction in a series of

reactors and applying heat to the naphtha/product stream

through heat exchangers between each reactor.

The reforming products are separated into a gas and a

liquid stream. The hydrogen gas is compressed with a

portion going back to the reformer; the hydrocarbon stream

is sent to' a fractionation column for final product

separation. As the reaction progresses, deposits accumulate

on the catalyst particles and reduce their reactivity.

Consequently, the catalyst must be occasionally regenerated.

3.2.2 CRU Catalytic Regeneration Process Description

There are three different methods in which to effect

reforming catalyst regeneration. Semiregenerative reforming

is characterized by shutdown of the reforming unit at

specified intervals, or at the operator's convenience, for

in situ catalyst regeneration (see Figure 3-3). Cyclic

regeneration reforming is characterized by continuous or

continual regeneration of catalyst in situ by isolating one

of the reactors in the series, regenerating the catalyst,

then returning the reactor to the reforming operation (see

Figure 3-4). Continuous regeneration reforming is

characterized by the continuous regeneration of part of the

catalyst in a special regenerator, followed by continuous

addition of this regenerated catalyst to the reactor (see

Figure 3-5) .

As with the CCU catalyst, the CRU catalyst .is

regenerated by controlled oxidation (burning) of the coke

deposited on the catalyst. In semiregenerative and cyclic

regenerators, the CRU reactor(s) are first taken off-line,

3 - 10
Compressor

Step 1. N2

Step 2. Air

Step 3. H2

..

Chlorine Chlorine

t:J

.-3

Separator I §

CD

f-l

\0

\0

00

Vent

Reactor

1.1 1 = ., 3

Preheater

3

I al Re~ctor I al

Preheater

2

Reactor

11-------lT'-I.....1 1 1-1----1.~1

Preheater

1

f-l

f-l

w

Step 1. Depressuritation and hydrocarbon purge vent

Step 2. Coke burn pressure control vent Air

Step 3. Regjuvination and 02 purgenent Causti~

MakeupWaterEffluentto

Wastewater

Treatment

Figure 3-3. ~ical regeneration process flow diagram for semi-regenerative catalytic

refo~ers.
Organic

Chloride --I.~I

Compressor

Step 1. N2

Step 2. Air .1

Step 3. H2

Makeup Water

w

tv

Preheater

Offline

Reactor Heat

Exchanger

Gases to

Stack

I' •• Separator

Cooler

t1

1-3

§

ro

\D

\D

0:>

Step 1. Depressuritation and hydrocarbon purge vent

Step 2~ Coke burn pressure control vent

Step 3. Regjuvination and O2 purge vent

Effluent to

Wastewater

Treatment

Figure 3-4. Typical regeneration process flow diagram for cyclic catalytic refo~ers.
t:I

"Ij

8

§

CD

\.0

\.0

(X)

Recycle Gas

I • Net Gas

Reformate

High Pressure

Separator

Heat

Exchangers

Low Pressure

Separator

Depressurization and

Hydrocarbon purge

H2

H2

Coke Burn

Pressure

Control Vent

Spent Catalyst

.....

LV

w

Figure 3-5. Typical process flow diagram for continuous refo~ers.
the reactor(s) are isolated, and any residual hydrocarbons

are purged from the system using nitrogen. This nitrogen

purge gas is typically vented to the refinery's flare

system. Air is then slowly introduced to the CRU reactor(s)

to begin the combustion process, with the coke serving to

fuel the process. The flue gas from the CRU coke combustion

is typically recirculated, with small amounts of fresh air

continuously added to the recirculated air to control the

coke burn rate. Excess flue gas from the coke combustion is

vented to the atmosphere from a small pipe vent as necessary

to maintain the desired pressure within the system.

The combustion process naturally produces some water.

The wa~er tends to leach chloride atoms fro~ the catalyst,

which reduces the catalyst's performance. Consequently, a

chloride source (usually a chlorinated organic such as

perchloroethene or trichloroethene) is used to replace the

chloride atoms stripped by the water. The chlorination

cycle may be performed either as a separate cycle after the

coke burn cycle is completed or simultaneously while the

coke burn cycle is under way. Once the catalyst is

regenerated (i.e., coke burn and chlorination cycles

completed), the system is first purged with nitrogen to

remove any oxygen and residual chlorination agent from the

system, and then purged with hydrogen to reduce the catalyst

from the metallic oxide formed during the burn cycle back to

its active (elemental) metal state prior to bringing the

unit back on-line.

The overall regeneration cycle for semiregenerative

systems takes approximately 5 to 15 days depending on the

level of other maintenance the CRU requires. The coke burn

cycle typically takes between 2 to 5 days. Cycle times

between regeneration cycles may range from 6 to 18 months

depending on the severity of the CRU reactor operating

conditions (which are based on the product mix being

produced from the CRU). Regeneration cycles for cyclic

systems are typically shorter in duration and more frequent

in occurrence than semiregenerative systems. However, both

3 - 14
systems are characterized by short, intermittent periods

when emissions may occur.

In continuous CRU regeneration, catalyst from the CRU

is circulated in semi-continuous fashion (small batches) to

the regenerator by a series of small hoppers. These hoppers

serve the function of the depressurization and initial purge

cycle of the semiregenerative or cyclic systems. A

continuous CRU regenerator typically has three sections: a

regeneration section, a chlorination section, and a drying

section. The first section of the regenerator that the

catalyst enters is the regeneration section. In the

regeneration section, hot air (at approximately 900 to

l,200 0 F ) is recirculated through the catalyst, with enough

fresh air added to maintain a low excess oxygen content (of

approximately 1 to 2 percent). As air is added to the

recirculating regeneration air line, air must also be vented

from the system to maintain the desired pressure in the

regeneration air line. This vent is typically vented to the

atmosphere; however, a water or caustic scrubber may be used

in either the air recirculation line or in the vent line to

remove HCl.

In the next section, called the chlorination section, a

chloride source (e.~., perchloroethene or trichloroethene)

is recirculated through the catalyst to replace any .chloride

leached from the catalyst in the regeneration section. The

regeneration and chlorination sections are separated by a

series of baffles to allow catalyst to move from the

regeneration section to the chlorination section, but to

minimize gas flow between the two sections.

The catalyst from the chlorination section then moves

past another series of baffles into the drying section. In

this section, hot air is used to strip any chloride agent

remaining on the catalyst and dry the catalyst. After the

dying section, th~ catalyst is returned to the CRU reactor

by another series of small hoppers. These hoppers serve the

function of the final purge cycle (to remove oxygen and

3 - 15
create a reducing atmosphere) of the semiregenerative or

cyclic systems.

3.2.3 CRU Emission Points

The CRU system is essentially a sealed system except

for the catalyst regeneration cycles. Although the location

of the emission point might vary depending on whether

catalyst regeneration is semiregenerative, cyclic, or

continuous, there are three times during the regeneration

process that emissions can occur regardless of the

regenerator type. These three emission points are: (1) the

initial depressurization and purge venti (2) the coke burn

pressure control venti and (3) the final catalyst purge

vent.

The initial depressurization and purge cycle removes

the hydrocarbons from the catalyst prior to CRU catalyst

regeneration. The vent gases from ~his initial purge may

have high levels of organic HAP such as benzene, toluene,

xylene, and hexane. 10 This vent is typically vented to the

refinery's fuel gas system or directly to a combustion

device (e.g., flare or process heater).

The coke burn cycle is typically the largest (in terms

of gas volume) emission source of the overall catalyst

regeneration cycle. The primary HAP contained in the CRU

coke burn vent are HCI and chlorine (CI 2 ) , l l which are

produced when the water formed during combustion leaches

chloride atoms from the CRU catalyst. The CRU coke burn

vent is typically a 3" to 6 11 pipe with a varying flow rate

in the range of 50 to 1,000 scfm that is released to the

atmosphere. The vent pipe may be only a few feet long, but

may be longer to provide a release height of at least 15 to

20 feet. Caustic injection or caustic scrubbing may be used

in the flue gas recirculation line to remove HCl. Although

these HCI removal techniques are implemented primarily to

protect the process equipment, they are also expected to

reduce HCI emissions from the coke burn vent. Some systems

operate a water or caustic scrubber for the vent line

specifically to reduce HCl, although this is typically more

3 - 16
common for continuous regenerators or cyclic systems that

cycle frequently.

The final purge and reduction cycle removes oxygen and

any remaining chorination agent from the system and reduces

the catalyst prior to returning CRU catalyst to the

reforming process or bringing the unit back on-line. The

vent gases from this final purge may have low levels of the

chlorinating agent (usually an organic HAP such as

trichloroethene of perchloroethene) and residual ·HCl or C1 2

remaining in the system. 10 This vent is typically vented to

the atmosphere or the refinery's fuel gas system depending

on the oxygen content of the vent gases (safety

considerations restrict the venting of oxygen containing

gases to the fuel gas system). Alternatively, the purge gas

may be directly vented to a combustion device (e.g., flare

or process heater) .

Equipment leaks and fugitive process emissions may be

significant for the chlorinated organic circulation system

due to the high organic content of this stream. No other

HAP emission points have been identified for the CRU or CRU

catalyst regeneration process.

3.3 SULFUR RECOVERY PLANT

All crude oils contain some sulfur compound impurities.

Crude oils that contain relatively low levels of sulfur are

referred to as II sweet II crudes, while crudes that contain

high levels of sulfur are referred to a "sourll crudes.

Sulfur compounds are converted to hydrogen sulfide (H2S) in

the cracking and hydrotreating processes of the refinery.

The H2S or lIacid gas" is removed from the process vapors

using amine scrubbers. The amine scrubbing solution is

subsequent~y heated to release the H2S, and the acid gas is

treated in the sulfur recovery plant to yield high purity

sulfur that is then sold as product. The sulfur recovery

plant consists of one or more sulfur recovery units (SRUs)

operated in parallel and may also contain one or more

3 - 17
catalytic tail gas treatment units an~/or a thermal oxidizer

(see Figure 3-6) .

3.3.1 Claus Sulfur Recovery Unit (SRU) Process Description

Sulfur recovery (the conversion of H2S to elemental

sulfur) is typically accomplished using the modified-Claus

process. This is a multi-stage catalytic oxidation of H2S.

First, one third of the H2S is burned with air in a reaction

furnace to yield sulfur dioxide (S02). The S02 then reacts

reversibly with H2S in the presence of a catalyst to produce

elemental sulfur, water, and heat. Because the reaction is

reversible, the reaction occurs in a series of reactors, and

the vapors are cooled to condense the sulfur between each

reactor to drive the reaction towards completion. Auxiliary

burners are used to reheat the gas stream prior to the next

reactor. The gas from the final condenser of the Claus unit

(referred to as the II tail gas") consists primarily of inert

gases with less than 2 percent sulfur compounds.

3.3.2 Tail Gas Treatment Unit (TGTU) Process Description

Tail gas treatment methods include anyone or

combination of: (1) catalytic reduction to convert as much

of the tail gas sulfur compounds to H2S (coupled with amine

adsorption or Stretford solution eduction); (2) amine

adsorption to recover and recycle any H2S present in the

tail gas; and (3) incineration to convert the remaining tail

gas sulfur compounds to S02.

The most common tail gas catalytic reduction systems in

use at refineries are: (1) the Shell® Claus Offgas

Treatment (SCOT) unit; (2) the Beavan/amine system; (3) the

Beavon/Stretford system; and (4) the Wellman-Lord system.

3 - 18
Reaction I ~I---l~

Furnace

BFW

Air

Catalytic

Converter

w

Sulfur

Condenser

Steam

Catalytic

Converter

*

Sulfur

Condenser

Steam

i ~'~l *Tail Gas

t:I

8

J-1

'-0

BFW=BoilerFeedWater

*Additional converters/condensers to achieve additional

recovery of elemental sulfur are optional at this point. Sulfur Pit

§

CD

J-1

'-0

'-0

co

Figure 3-6. Refinery nCT discussions: process vents Claus sulfur recovery units.
Except for the Wellman-Lord system, each of these systems

consist of a catalytic reactor and an H2S recovery system.

In either the Claus or Beavon reactor, the tail gas is

heated in the presence of hydrogen gas and a catalyst to

reduce most of the tail gas sulfur compounds to H2S . The

off-gas from the catalytic reactor is typically quenched,

then routed to an 'amine scrubber or a Stretford solution to

strip the H2S from the tail gas. The recovered H2S is

recycled to the front of the Claus unit. The overhead of

the amine scrubber or Stretford unit (caustic scrubber) may

be vented to the atmosphere or incinerated to convert any

remaining H2S or other reduced sulfur compounds to 80 2 • The

total sulfur recovery efficiency of a Claus/catalytic tail

gas treatment train can be 99.5 percent or higher.

The Wellman-Lord uses thermal oxidation followed by

scrubbing with a sodium sulfite and sodium bisulfite

solution to remove S02. The rich bisulfite solution is sent

to an evaporator-recrystallizer where the bisulfite

decomposes to S02 and water and sodium sulfite is

precipitated. Due to high capital, operating, and

maintenance costs, the Wellman-Lord system is not widely

used. 12

3.3.3 Claus Sulfur Recovery Plant Emission Points

The primary emission point from the sulfur recovery

plant is the final vent from the SRU, TGTU, or thermal

oxidizer, whichever is the last process unit in the

treatment train. There may be a separate emission stack for

each SRU train; alternatively, the emissions from a couple

of SRU trains may be combined, e.g., prior to thermal

oxidation and release to the atmosphere. A typical SRU vent

stack is approximately 4 feet in diameter and 100 feet tall.

A typical volumetric flow rate for an SRU vent stack ranges

from 8,000 to 40,000 scfm. The primary HAP components of

the final sulfur plant vent are carbonyl sulfide (COS) and

carbon disulfide (CS 2 ) .13 These HAP components are byproducts of the SRU and TGTU reactions; COS may also be a

product of incomplete combustion from a thermal oxidizer.

3 - 20
Sulfur recovery plants also have a potential for

fugitive HAP emissions from the sulfur recovery pits. After

each reactor in the SRU, elemental sulfur is condensed and

removed from the SRU gas and the liquid sulfur is collected

and stored in bins. There are limited data from a one

petroleum refinery that suggest that small amounts of HAP

are emitted from these sulfur recovery pits. 14

There is also a potential for fugitive emissions from

certain types of TGTUs, specifically the Stretford unit.

The Stretford unit employs a series of open vessels as part

of the solution circulation loop and a direct air contact

cooling tower to cool the Stretford solution. is Limited

data were reported that suggest that small amounts of HAP

are emitted from these Stretford solution tanks. 16

There are a few refineries that operate non-Claus type

SRUs. All of the refineries that use non-Claus SRU

technologies have very low sulfur production rates (2 long

tons per day or less). There are several different trade

names for these "other" types of SRU, such as the LowCat,

Sulferox, and NaSH processes. In general, these processes

operate at temperatures below 200°F and yield a sulfur

product that has a much lower sulfur content (50 to 70

percent sulfur compared to 99.9 percent sulfur from the

Claus process). There are no HAP emissions data from these

other types 0"£ SRU. Industry representatives claim that

-these processes do not form COS and CS2 while treating the

sour gas, but these processes generally involve reactions

specific for H2S, and they will not otherwise remove any COS

or CS2 that may be present in the sour gas. That is, the

non-Claus SRU are not expected to produce additional COS and

CS2 , but they may potentially emit any COS or CS 2 that is

present in the treated sour gas. As, these units represent

much less than 1 percent of the total sulfur production

capacity (or H2S treatment capacity in the United States),

the potential HAP emissions from non-Claus SRU are expected

to be minimal compared to Claus SRU HAP emissions.

3.4 REFERENCES

3 - 21
1. Site Visit Report -- Girard Point Refinery: Sun

Company.

2.

3.

4.

5.

Site Visit Report

Site Visit Report

Site Visit Report

Site Visit Report

Marcus Hook: Sun Company.

Coastal Eagle Point Company.

Star Enterprise.

Marathon Oil Company.

6. u.s Environmental Protcetion Agency. Petroleum

Refinery Enforcement Manual. Publication No. EPA340/1-80-008. Office of Enforcement and Compliance

Assurance, Washington, DC. March 1980.

7. U.S Environmental Protcetion Agency. EPA Office of

Compliance Sector Notebook Project - Profile of the

Petroleum Refining Industry. Publication No. EPA/310-

R-95-013. Office of Enforcement and Compliance

Assurance, Washington, DC. September 1995.

8. U.S Environmental Protcetion Agency. Presumptive MACT

for Petroleum Refinery Processs Vents: FCC Units,

Reformers, and Sulfur Plants. Appendix B. Summary of

Emissions Data From the EPA Database on Petroleum

Refinery Process Vents. Publication No. XXXXX. Office

of Air Quality Planning and Standards, Research

Triangle Park, NC. November??? 1996.

9. Reference 5.

10. Reference 8.

11. Reference 8.

12. Personal communication (e-mail) from Hathaway, Donna,

Louisiana Department of Environmental Quality, to

Lucas, Robert, U.S. Environmental Protcetion Agency,

Office of Air Quality Planning and Standards. Process

Vent P-MACT - Some More Info. February 8, 1996.

13. Reference 8.

14. Reference 12.

15. Reference 8.

3 - 22
4.0 CONTROL TECHNOLOGY AND PERFORMANCE OF CONTROLS

This chapter describes the control technologies

applicable to reduce HAP emissions from the three petroleum

refinery vents of interest (the CCUCR vent, the CRUCRvent

and the sulfur recovery plant vent). It also presents a

summary of the available performance data of the control

technologies applicable for these three petroleum refinery

vents.

4.1 CCUCR VENT EMISSION CONTROLS

There are two distinct types of emissions from CCUCR.

These are: (1) metal HAP that are deposited on the catalyst

particles; and (2) organic HAP are products of incomplete

combustion. As such, there are two different types of

emission control technologies considered for the CCUCR vent.

4.1.1 Metal HAP Emission Controls for the CCUCR Vent

As the metal HAP are associated primarily with the

catalyst particles entrained in the CCUCR flue gas,

particulate emission control devices also provide metal HAP

emission control. To be applicable to the CCUCR flue gas, a

particulate (metal HAP) emission control device must be able

to treat large volumes of air continuously and reliably. As

the CCU is often a critical process in a facility's refining

efforts, any shutdowns of the process due to control device

failure or maintenance must be minimized. There are four

candidate particulate emission control devices that can

handle continuous, large volumes of flue gas. These are:

cyclone separators, electrostatic precipitators (ESPs), wet

scrubbers, and fabric filters (baghouses).

4 - 1
Cyclone separators use centrifugal force to separate

dust particles from gas streams. They have no moving parts,

and they can continuously and reliably process large volume

gas streams at the elevated temperatures typical of CCUCR

flue gases. Cyclones are one of the least expensive dust

collection devices in terms of both operating and capital

investment costs, but they typically cannot meet the dust

removal efficiencies of ESPs, baghouses, and wet scrubbers.

Cyclones are generally applicable for dust particles with

diameters greater than 5 ~, but multiple-tube parallel

units may attain 80 to 85 percent collection efficiencies on

3 diameter particles. 1 Cyclone separators are used almost

universally within the eCUCR units to retain most of the

catalyst particles within the eeUCR unit. Second and third

stage cyclones (i.e., cyclones in series) are commonly used

external to the ccueR unit for dust removal. By operating

cyclones in series, dust collection efficiencies are

reported to range from 90 to 98 percent. 2

ESPs use an electrostatic field to charge dust

particles within the gas stream. The charged particles

migrate to a grounded collection surface where they adhere.

The particles are then removed from the collection surface

periodically by vibrating or ~rapping" the collection

surface. The dislodged particles are then collected in

hoppers at the bottom on the ESP. ESPs typically have a

high collection efficiency and can effectively remove

particles with diameters of less than 1 ~.3 ESPs can

continuously and reliably process large volume gas streams

at the elevated temperatures typical of ceUCR flue gases,

and they are commonly used for particulate removal on the

CCUCR vent gases.

Wet scrubbers use a liquid, usually water, to assist in

the particle collection process. There are a number of

different types of wet scrubbing process equiprnent,4 but

venturi type wet scrubbers are among the most efficient and

the most commonly used at refineries for the CCUCR vent.

Venturi wet scrubbers are typically designed for

4 - 2
applications requiring very high removal efficiencies of

particles ranging in diameter between 0.5 and 5 ~.5

Venturi wet scrubbers may also provide some SOx removal, but

they have the disadvantage of generating a wastewater stream

that requires treatment and/or disposal.

Baghouses use fabric filtration to remove dust

particles from the gas stream. Baghouses are highly

efficient, achieving removal efficiencies of greater than

99 percent for particles with diameters of 0.3 and

greater. 6,7 However, baghouses are typically designed to

operate at temperatures within 50 to 100 of of the gas

stream's dew point and generally cannot operate at

temperatures above 500 °F. 8 Therefore, some pretreatment

(or heat recovery) of the CCUCR flue gas will be required

prior to a baghouse control device. Additionally, baghouses

cannot provide continuous, long-term emission control due to

maintenance problems (e.g., clogged or torn bags) according

to air pollution control equipment representatives. 9

Selection of an air pollution control device for. TCCU

is further complicated by the low operating pressure of the

TCCU regenerator. Due to the pressure drops across the

control device, installation of an ESP, wet scrubber or

baghouse would require an induced draft fan to pull the

CCUCR flue gas through the control device. The control of

this induced draft fan would be critically tied to the

process operations, making the application of these control

devices impracticable. Single pass cyclone separators may

be applicable and may yield sufficient control due to the

larger size particles associated with the TCCU CCUCR vent.

The TCCU surge tank vent is not limited by the control

device pressure drop, but again, a cyclone separator may

provide adequate control based on the particle size

distribution of TCCU PM emissions.

Many refiners operate a catalytic hydrotreating unit

and some of these refiners process a portion or all of the

CCU crude oil feedstocks in these hydrotreaters prior to the

CCU. The hydrotreater removes sulfur, nitrogen, vanad~um,

4 - 3
nickel and other contaminants from the crude oil feedstocks.

This "pretreatment" step prior to the CCU typically helps to

improve CCU yield, prolongs catalyst life, and reduces CCU

HAP emissions, according to refinery representatives. 10 Due

to the capital investment cost of hydrotreating units and

their functionality for individual refineries, hydrotreating

may not be a generally applicable emission reduction

technique for all petroleum refineries. However, refiners

that operate a hydrotreating unit and process a portion or

all of the CCU feedstocks through the hydrotreater may

exhibit reduced metal HAP emissions compared to a similarly

operated CCU that does not hydrotreat the CCU feedstock.

4.1.2 Organic HAP Emission Controls for the CCUCR Vent

Organic HAP emissions primarily originate as byproducts of coke combustion (e.g., formaldehyde,

acetaldehyde, POM, dioxins and furans). However, volatile

organic HAP such as benzene, toluene, xylenes, and hexane

are also reported for some CCUCR vent streams. 11 These

volatile organic HAP may originate as residual oil feed

material on the catalysts that somehow vaporize, but do not

combust prior to exiting the CCUCR. Presumably, these

organic HAP emission would be greater for units that 'operate

with insufficient oxygen (i.e., incomplete combustion

CCUCRs). From the data available for organic emissions

immediately following the CCUCR, it appears that incomplete

combustion CCUCRs have significantly higher organic HAP

emissions than complete combustion CCUCRS. 12

Due to the large volumes and the low concentrations of

organic HAP in the ccueR flue gas, common organic HAP

emission control devices such as condensers and carbon

adsorption systems are not appropriate to control organic

HAP emissions from the CCUCR vent. As the CCUCR flue gas is

already at high (combustion) temperatures, catalytic

incineration would not be economically competitive with

traditional thermal incineration. Thus, thermal

incineration or afterburning appear to be the only

4 - 4
applicable air pollution control techniques to reduce

organic emissions from the CCUCR flue gas.

Thermal incineration employs heat and oxygen to oxidize

(combust) organic chemicals, converting them to carbon

dioxide and water vapor at efficiencies of 99 percent or

higher. 13,14 As the CCUCR flue gas stream is already at

elevated temperatures, a minimum of auxiliary fuel would be

required to achieve effective afterburning. Additionally,

for incomplete combustion CCUCRs, the CO in the flue gas may

be sufficient to fuel the secondary combustion process.

Many incomplete CCUCRs already employ secondary combustion

devices, typically referred to as CO boilers, to combust CO

for the purpose of recovering the latent heat in the CCUCR

flue gas. From the organic emission data available at the

outlet of CO boilers and complete combustion CCUCRs, it

appears that complete combustion CCUCRs can achieve

comparable levels of organic HAP emission control as an

incomplete combustion CCUCR followed by a secondary

combustion unit. 15

4.2 CRUCR VENT EMISSION CONTROLS

As described in Section 3.2.3, there are three times

during the regeneration process that HAP emissions can

occur. These three emission points are: (1) the initial

depressurization and purge vent; (2) the coke burn pressure

control vent; and (3) the final catalyst purge vent.

4.2.1 HAP Emission Controls for the CRU Purge Vent

The initial depressurization and purge cycle removes

the hydrocarbons from the catalyst prior to CRU catalyst

regeneration. The vent gases from this initial contains

organic HAP such as benzene, toluene, xylene, and hexane.

During the initial depressurization process, these

hydrocarbons may be recovered by venting the gas stream to

the refinery's fuel gas recovery system. As this vent gas

stream hydrocarbon content becomes more dilute during the

purge cycle, venting to the fuel gas system may become

undesirable and an alternative air pollution control

4 - 5
technique may de required. Air pollution control devices

potentially applicable to this CRU purge vent stream include

combustion devices such as a flare or vapor incinerator and

carbon adsorption systems.

Flares and vapor incinerators employ heat and oxygen to

oxidize (combust) organic chemicals, converting them to

carbon dioxide and water vapor. Although destruction

efficiencies of vapor incinerators may be slightly higher

than flare systems, flare systems typically achieve

destruction efficiencies of 98 percent or higher and they

are more suitable for the intermittent flows typical of the

CRU purge vent. 16

Carbon adsorption may also be used to control organic

HAP emissions during the CRU hydrocarbon purge cycle.

Carbon adsorption systems remove organic chemicals from gas

streams by selective adsorption onto the surface of

activated carbon. There are two general types of carbon

adsorption systems: regenerative and non-regenerative.

Regenerative carbon systems offer an advantage over

destructive emission control devices when the adsorbed

organics can be economically desorbed and recovered.

However, due to the low flow and intermittent nature of the

CRU purge vent stream, non-regenerative (or canister) carbon

adsorption systems are probably most economical for the CRU

purge vent. When the adsorbed organics cannot be recovered

or when non-regenerative carbon systems are used, carbon

adsorption has the disadvantage of creating a solid waste

material that requires proper disposal (sometimes as a

hazardous waste) .17,18,19

4.2.2 HAP Emission Controls for the CRUCR Coke Burn Vent

The primary HAP emitted during the coke burn cycle is

HCl. Caustic injection, caustic scrubbing, and wet

scrubbing are all applicable air pollution control

techniques for removing HCI from the CRUCR coke burn flue

gas. Wet scrubbers use a liquid, usually water, to effect

removal of the desired pollutant. For vapor phase

pollutants, scrubbing typically removes the pollutant by

4 - 6
absorption into the liquid phase. Since HCl is readily

soluble in water, wet scrubbing or absorption (with or

without caustic addition) can achieve high HCl removal

efficiencies (98 percent or higher) .20,21

4.2.3 HAP Emission Controls for the CRUCR Final Purge Vent

The final purge and reduction cycle vent gases from may

contain low levels of the chloriding agent (trichloroethene

or perchloroethene) and residual HCI or Cl 2 " Safety

considerations (i.e., the presence of oxygen) may restrict

the venting of the final purge cycle vent gases to the fuel

gas system. However, the purge gases may be directly vented

to a combustion device (e.g., flare, process heater, or

incinerator), a carbon adsorption system, or a wet gas

scrubber (absorption). Each of these types of air pollution

techniques have been previously described in this section.

If the primary HAP pollutants in the final CRUCR purge cycle

are organics, then either combustion or carbon adsorption

are most appropriate. If HCI or Cl 2 are the primary HAP

from this vent at a given facility, then wet scrubbing is

probably the most appropriate control device. The

suitability of carbon adsorption may depend on the

concentration of HCI in the vent stream because carbon has a

low adsorption capacity for HCI and there is a potential for

HCI condensation within the adsorption unit. 22 Application

of thermal control devices may also be limited depending on

the concentration of chlorine or chloride containing

chemicals in the vent stream. Combustion of chlorinated

organics produces HCI and provides the potential for the

formation of chlorinated dioxins and furans. 2 3

4.3 SULFUR PLANT VENT EMISSION CONTROLS

The primary HAP components of the final sulfur plant

vent are carbonyl sulfide (COS) and carbon disulfide (CS 2 ) .

These HAP components are by-products of the reactions in the

SRU reactors; COS may also be a product of incomplete

combustion from a thermal oxidizer. There are two generally

applicable emission control techniques for the SRU vent.

4 - 7
These are either the use a TGTU or a thermal oxidizer (or

both) .

4.3.1 TGTU as a HAP Emission Control for the SRU Vent

By recovering sulfur from the SRU tail gas, TGTUs are

expected to reduce the concentration of sulfur containing

compounds (HAP) in the sulfur plant vent as compared to a

similar SRUs with no TGTU. Different types of TGTUs were

described in Section 3.3.3. A typical TGTU recovers

approximately 95 percent of the sulfur remaining in the SRU

tail gas (i.e., a combined SRU/TGTU sulfur recovery

efficiency of over 99.5 percent}.24 At this time, the EPA

has insufficient data to determine if the sulfur recovery

efficiency of' a TGTU is directly correlated to its HAP

emission reduction or whether a given TGTU provides greater

HAP emission reduction than any other TGTU. It appears that

certain TGTUs may have a higher potential for secondary

(fugitive) emissions due to the type of TGTU process used

(e.g., Stretford units may have secondary emissions from the

handling and storage of the Stretford eduction solution) .

Thermal and catalytic oxidizers or combustion units are

also applicable air emission control devices to reduce the

HAP emissions from the sulfur plants. Thermal and catalytic

oxidizers convert (combust) reduced sulfur compounds to

sulfur oxides (SOx). Thermal and catalytic oxidizers may be

applicable for nearly all SRU vents regardless of the

presence or absence of a TGTU (although they may not be

appropriate following an oxidative TGTU process such as a

Wellman-Lord TGTU). The destruction or oxidation efficiency

of reduced sulfur compounds, including COS and CS 2, in a

properly designed and operated thermal or catalytic oxidizer

is anticipated to be 99 percent or higher. 25

4.4 REFERENCES

1. Perry, R. H., and C. H. Chilton. Chemical Enaineers'

Handbook, 5th Edition. McGraw-Hill Book Company, New

York, New York. 1973. p. 20-82.

2. ???

4 - 8
3. u.s Environmental Protection Agency. HandbookControl Technologies for Hazardous Air Pollutants.

Publication No. EPA/625/6-91/014. Office of Research

and Development, Washington, DC. June 1991. pp. 4-80

through 4-90.

4. Reference 1. pp. 20-94 through 20-103.

5. Reference 3. pp. 4-90 through 4-98.

6. Reference 3. p. 4-64.

7. McInnes, R., K. Jameson, and D. Austin. "Scrubbing

Toxic Inorganics." Chemical Engineering. September

1990. pp. 116 through 121.

8. Reference 3. pp. 4-64 through 4-65.

9. ICAC Meeting Minut'es Memorandum.

10. Site Visit Report.

11. PMACT Document - Emission Data. Appendix B.

12. Reference 11 (or API Database).

13. McInnes, R., S. Jelinek, and V. Putsche. "Cutting

Toxic Organics." Chemical Engineering. September 1990.

pp. 108 through 113.

14. Reference 3. pp. 4-1 through 4-10.

15. Reference 11.

16. Reference 3. pp. 4-20 through 4-27.

17. u.s Environmental Protection Agency. Internal

Instruction Manual for ESD Regulation Development - Carbon Adsorption Control for Organic Emissions.

Office of Air Quality Planning and Standards, Research

Traingle Park, NC. March 1993.

18. Reference 13.

19. u.S Environmental Protection Agency. OAQPS Control

Cost Manual. Publication No. EPA/450/3-90-006. Office

of Air Quality Planning and Standards, Research

Traingle Park, NC. January 1990. pp 4-1 through 4-44.

20. Reference 7.

21. Reference 3. pp. 4-44 through 4-54.

22. Reference 17.

4 - 9
23. Reference 3. pp. 4-2 through 4-3.

24. Gore, B. G. "Tail Gas Cleanup Process "Technology."

Energy Progress, Vol. 6, No.2. June 1986. pp. 84

through 90.

25. Reference 3.

4 - 10
5.0 MODEL PLANTS AND EMISSION ESTIMATES

This chapter presents the derivation of controlled and

uncontrolled emission factors for hazardous air pollutants

(HAP) and applies them to three different sizes of model

plants to provide an estimate of the potential level of

emissions on a plant basis. In addition, the emission

factors are applied on a nationwide basis to estimate

controlled and uncontrolled emissions from the entire

industry for the three processes of interest: catalytic

cracking unit (CCU) regeneration, catalytic reforming unit

(CRU) regenerati~n, and sulfur recovery units (SRUs).

5.1 MODEL PLANTS

The three model plants used to represent small, medium,

and large facilities for the purpose of presenting typical

levels of emissions are given below.

Model plant capacities

Catalytic Catalytic Sulfur

No. Size

Crude oil cracking reforming recovery

(bbl/day) (bbl/day) (bbl/day) (ltons/d)

1 Small 25,000 8,300 6,300 30

2 Medium 75,000 25,000 19,000 120

3 Large 200,000 70,000 50,000 480

bbl = barrels

5.2 HAP EMISSIONS FROM CCU REGENERATION

5 - 1
Data for HAP emissions were compiled by the EPA using

information provided through a variety of sources and are

documented in References 1 and 2. A summary of the

emissions data is given in Appendix B. The emissions data

were reported in responses to information collection

requests and follow-up surveys by the American Petroleum

Institute (API) the National Petroleum Refiners Association

(NPRA) , as well as collected during site visits conducted by

EPA. The approach used to estimate HAP emissions in this

section attempts to provide a range of "best estimates"

rather than an extreme range based on the absolute highest

and lowest values reported. Estimates are provided only for

those compounds that were actually detected and quantified.

The original data base contained several entries for

pollutants that were not detected, and the detection limits

were reported and included with other information based on

actual measured values.

The analysis of HAP emissions from CCU regeneration is

based on the following approach:

1. Estimates are not provided for pollutants that were not

detected, even when they are reported in the survey

results at the detection limits. In addition, if there

was only one facility that reported the presence of a

specific compound that was not verified by any other

information, that value was flagged and was not used in

the estimates of total HAP emissions.

2. When the extremes of the range for a given pollutant

differ by an order of magnitude or more from the bulk

of the data, the extreme high and/or low values are not

used to estimate a representative range of emissions

(i.e., these values are treated as outliers). However,

the tables clearly note when an extremely high or low

value is not used in the analysis.

3. The data for CCU regeneration were mostly for units

that controlled emissions with the destruction of

organic compounds in a carbon monoxide (CO) boiler and

control of particulate matter by cyclones and an

electrostatic precipitator (ESP). Because of the

combustion process, it is difficult to determine if the

measurements made after the CO boiler represent

products of incomplete combustion and/or by-products or

if they represent the residual of compounds that were

5 - 2
not completely destroyed. For example, formaldehyde,

acetaldehyde, and polycyclic organic matter (POM) may

actually be formed in the CO boiler as by-products of

combustion or they may be present before combustion in

larger quantities. For this analysis, the data for

organic HAP (generally after the CO boiler) are used to

derive emission factors for controlled organic HAP

emissions. Uncontrolled organic HAP emissions are

estimated based on a assumption that the controlled

emission factors represent 98 percent destruction

(i.e., the uncontrolled emission factors are assumed to

be 50 times the controlled emission factors). This

emission factor is applied only to units using partial

combustion that do not vent to a CO boiler or other

combustion device. For complete combustion units,

emissions of organic HAP are estimated from the

"controlled" emission factors.

4. Estimates of uncontrolled emissions of HAP metals for

CCU regeneration are based on the measurements after

the control device and the assumption of a nominal

control efficiency of 95 percent for the ESP.

5. Based on a review of the data, no distinction could be

made in emission factors for CCUs using partial

combustion and those using complete combustion. A

significant difference would be expected in the

uncontrolled emissions from the two different types of

combustion processes; however, the difference in

organic compound emissions may be much less after

combustion in a CO boiler. In addition, 32 of the 34

CCUs uS1ng partial combustion in the current data base

were identified as having controls (e.g., CO boiler),

and only 2 were identified as having no controls.

Consequently, uncontrolled emission factors for partial

combustion processes may not be important in

determining nationwide emissions.

6. The data were inconclusive as to whether hydrotreating

had any effect on the emission factors for HAP metals;

consequently, this analysis uses the same emission

factors for units that hydrotreat as for those that do

not.

The range of controlled emission factors for organic

HAP derived from the data in Appendix B is given in Table

5-1 and the range for controlled metal HAP and HCI is given

in Table 5-2. Both are expressed in terms of pounds of

emissions per million barrels of CCU throughput (lb/rnm bbl) .

Nickel was the most commonly reported metal HAP and was also

5 - 3
the one reported in the highest quantities. The range and

midrange for the emission factors are given in Table 5-3.

Using the approach and assumptions discussed above,

these factors were applied to the model plants to estimate

uncontrolled and controlled emissions. The results are

given in Table 5-4 for the sum of organic, metal HAP, and

HCl. The results for the model plants indicate that the

units with particulate matter controls probably have metal

HAP emissions that total less than a ton per year.

Nationwide emission estimates for CCU regeneration were

derived based on CCU capacity and control devices in place.

Based on data from API 3 , information on emission controls

was available for plants with 4.5 million bbl/day of CCU

capacity out of a total nationwide capacity of 5.2 million

bbl/day. Approximately 27 percent of the nationwide

capacity did not have control devices in place for PM

(1,400,000 bbl/day). In addition, only 47,000 bbl/day of

the total capacity was projected to have no controls for

emissions of organic compounds (i.e., uncontrolled units

using partial combustion). Nationwide emission estimates

are given in Table 5-5 for the baseline (current level of

control) and for the lIcontrol1edll case, which assumes that

all units control metal HAP and organic HAP.

5 - 4
TABLE 5-1. SUMMARY OF ORGAN:IC HAP DATA FROM ceo REGENERATION

(from References 1 and 2)

Compound

--

1,3-Butadiene

Acetaldehyde

Benzene

Cyanide

Formaldehyde

HCN

Phenol

POM)

Toluene

U1

Xylene

U1 PCDF4

HCDFs

Total VOCs 6

Totals

Emission factor

range (lb/mm bbl) 1 Number2 Comments

Lower Upper

0.0008 0.05 2 all after CO boiler

1.7 48 6 after CO boiler

0.73 12 5 after CO boiler

28 36 2 all after CO boiler

2.7 950 7 after CO boiler, excludes two very high values

14 194 5 with and without CO boiler, excludes one high and t:l one low value

0.74 41 5 with and without CO boiler t'Ij

J-3

0.15 3 2-5 most after CO boiler and ESP

0.26 2.5 2 all after CO boiler; excludes one very high value C

P

3.2 3.2 1 after CO boiler CD

5.5e-07 5.5e-07 1 after CO boiler and ESP \.0

\.0

1.le-06 1.le-06 1 after CO boiler and ESP co

78 1,240 9 after CO boiler or complete combustion CCUCR

Sl 1,290

1

2

)

4

5

6

lb/mm bbl = pounds per million barrels.

Number of facilities reporting detectable quantities of the compound.

POM = polycyclic organic matter determined from the sum of individual compounds in Appendix B.

Total pentachlorodibenzofuran.

Total hexacholordibenzofuran.

Total volatile organic compounds (as reported in Ref. 2; not included in HAP totals).
TABLE 5-2. SUMMARY OF CONTROLLED METAL HAP EM:ISS:IONS AND

HCl DATA FROM CCU REGENERATXON (from References 1 and 2)

Compound Emission factor range NumberS

(lb/mm bbl) a

Antimony 0.0032 10.0 8

Arsenic 0.0010 1.7 8

Beryllium 0.0020 0.1 5

Cadmium 0.0040 2.8 8

Chromium 0.0430 15.2 12

Cobalt 0.0075 1.5 6

Lead 0.1100 8.2 10

Manganese 0.1400 19.7 9

Mercury 0.0010 0.6 8

Nickel 0.0022 43.0 21

Selenium 0.0062 29.4 8

Totals 0.32 132

Hel 528 2,300 2

a lb/mm bbl = pounds per million barrels.

b Number of facilities reporting detectable quantities.

TABLE 5-3. SUMMARY OF HAP EM:ISSXON FACTORS FOR CCU

REGENERAT:ION

HAP and type of control Emission factor range (lb/mm

bbl) 1

Lower Upper Midrange

Total organics-controlled 51 1,290 670

Total organics-uncontrolleda 2,550 64,500 33,500

Metal HAP-controlled 0.32 132 66

Metal HAP-uncontrolledb 6 2,640 1,320

Hel 528 2,300 1,400

a Assumes controlled emissions represent 98 percent

destruction; applied only to uncontrolled partial combustion

units.

b Assumes controlled emissions represent 95 percent removal.

5 - 6
TABLE 5-4. SUMMARY OF RANGE OF POTENT~AL HAP EM~SSXONS FOR

CCU REGENERAT~ON FROM THE MODEL PLANTS

Model plant 1 2 3

.Capacity 8,300 25,000 70,000

(bbl/day)

Total organic- 3.9 - 98 12 - 294 33 - 820

uncontrolled

partial

combustion (tpy) a

Total organic- 0.08 - 2.0 0.23 - 5.9 0.65 - 16

controlled (tpy)

Total metal- 0.01 - 4.0 0.03 - 12 0.08 - 34

uncontrolled

(tpy) b

Total metal- 0.0005 - 0.2 0.001 - 0.6 0.004 - 1.7

controlled (tpy)

HCl 0.8 - 3.5 2.4 - 10.5 6.7 - 29

bbl/day = barrels per day.

tpy = tons per year.

a

b

Applied only to partial combustion units that do

not vent to a CO boiler or other combustion

device.

The vast majority of the larger units use a PM

control. Consequently, these estimates are

probably most relevant for CCUs in the size range

of Model Plants 1 and 2.

5 - 7
TABLE 5-5. SUMMARY OF NATXONWXDE EMXSSXONS ESTXMATES FOR

CCU REGENERATXON

Case

Baseline

contro.lLed"

Range

Lower

Upper

Midrange

Lower

Upper

Midrange

Metal HAP

(tpy) a

1.8

770

380

0.3

120

62

Organic HAP

(tpy) b

70

1,800

920

48

1,200

630

a Based on the emission factors in Table 5-3, an

uncontrolled capacity of 1,400,000 bbl/day, and a

controlled capacity of 3,780,000 bbl/day.

b Based on the emission factors in Table 5-3, an

uncontrolled capacity of 47,000 bbl/day, and a

controlled capacity of 5,133,000 bbl/day.

C Based on the emission factors in Table 5-3 and a

controlled capacity of 5,180,000 bbl/day.

5.3 HAP EM:ISS:IONS FROM CRU REGENERAT:ION

The data available for HAP emissions from CRU

regeneration were compiled by EPA (References 1 and 2) and

are presented in Appendix B. Additionally, data from one

emission source test was available to estimate emission

factors for dibenzofurans both before and after a temporary

carbon adsorption control device (Reference 4). The

emission factors developed for CRU regeneration are

summarized in Table 5-6. There were very limited emission

data for nearly all HAP except chlorine (CI 2 ) and hydrogen

chloride (HCI) from uncontrolled CRU. Additionally, nearly

all of the Cl 2 and HCI emission data are from continuous or

cyclic CRU catalyst regeneration. Therefore, a single

emission factor was developed and applied to all CRU

regardless of the type of regeneration employed, whether

cyclic, continuous, or semi-regenerative.

5 - 8
Most of the data for benzene, toluene, and xylene were

from measurements after combustion in a process. heater, and

information supplied by the industry indicated that organic

emissions are typically controlled by venting to a

combustion device. A range of 23 to 28 lb per million

barrels was developed to represent emissions of organic HAP

from CRU regeneration following combustion. No

"uncontrolled" emission factor was developed for organics

from CRU catalyst regeneration.

There are two sets of data regarding the emissions of

HAP metals during CRU regeneration. Although these two sets

of data yielded metal HAP emission factors that varied by

four orders of magnitude, even the upper range emission

factor was very low. Applying the upper range metal HAP

emission factor for the largest model plant CRU yields

emissions of only 1 lb/yr. Based on these limited and

disparate metal HAP emission data, it was appears that metal

HAP emissions from CRU is either negligible or non-existent.

Data were available for chlorine and HCI both before

and after control, although most of the data represented

uncontrolled emissions. Comparing the emissions range for

controlled versus uncontrolled'emissions, it appears that a

control efficiency of approximately 99 percent may be

achieved. However, based on an evaluation of the available

process data, the level of HCl scrubber control devices inplace at semi-regenerative CRU are significantly different

than those in-place at continuous and cyclic CRU units.

Therefore, the midrange value of .4,450 lb/million barrels

was used to estimate uncontrolled emissions and the emission

factors for controlled units were then calculated using this

uncontrolled emission factor and the nominal emission

control efficiency for the specified level of HCl scrubber

control(either 92 or 97 percent).

The emission factors for CRU regeneration are

summarized in Table 5-7. These factors were applied to the

model plants in Table 5-8 to estimate typical plant

emissions. The results in Table 5-8 show that controlled

5 - 9
emissions of all HAP from CRU regeneration total at or less

than a ton per year for the midrange CRU and total between 1

and 3 tons per year for large CRU.

The major HAP from uncontrolled CRU regeneration is

Hel, which was reported by numerous facilities at rates

comparable to the upper end of the range shown for the model

plants. Due to the different level of HCI scrubber control

devices in-place at semi-regenerative CRU compared to those

in-place at continuous and cyclic CRU units, separate

estimates are provided for semi-regenerative CRU and

continuous/cyclic CRU in developing the nationwide estimates

of emissions from CRU regeneration. From the available

process data, semi-regenerative CRU processed 1.63-million

barrels per day of feedstock; 73 percent of that throughput

is controlled by single-stage (assumed 92 percent efficient)

scrubbers and 4 percent is controlled by multiple-stage

(assumed 97 ~ercent efficient) scrubbers. Cyclic and

continuous reformers combined processed 2.02-million barrels

per day of feedstock and 38 percent of that throughput is

controlled by multiple-stage scrubbers, with only 6 percent

controlled by single-stage scrubbers. The nationwide

estimates of baseline and controlled emissions from CRU

regeneration are summarized in Table 5-9. The estimates for

controlled emissions assume that all uncontrolled semiregenerative CRU regeneration vents are equipped with

single-stage scrubbers to remove HCl at an efficiency of 92

percent, and all continuous and cyclic CRU regeneration

vents are equipped with multiple-stage scrubbers to remove

HCI at an efficiency of 97 percent.

5 - 10
TABLE 5-6. SUMMARY OF HAP DATA FROM CRO REGENERAT:ION

(from References 1 and 2)

Compound Emission factor Numberb Comments

range (lb/mm bbl)a

Benzene 1.5 6.5 3 After control

Toluene 9.6 9.6 1 After control

Xylene 7.0 7.0 1 After control

PARc 4.5 4.5 1 After control

Dibenzofurans

Tetrachloro 2.8 E-09 8.4 E-09 1 (d) ,

Pentachloro 4.5 E-09 1.6 E-08 1 (d)

Hexachloro 7.4 E-09 2.4 E-08 1 (d)

Heptachloro BDL 1.4 E-08 1 (d)

Octachloro BDL 3.1 E-09 1 (d)

Total 1.5 E-08 9.3 E-08 1 (d)

Total organic 23 28 After control

Chlorine 0.26 0.26 1 After control

HCI 0.06 4.0 2 After control

Total Cl HAP 0.32 4.3 After control

Chlorine 0.44 440 10 Uncontrolled

HCI 34 8,430 20 Uncontrolled

Total Cl HAP 34 8,870 Uncontrolled

a lb/mm bbl = pounds per million barrels.

b Number of facilities reporting detectable quantities.

C PAR = polycyclic aromatic hydrocarbons, which include

POM.

d Left hand column represents emissions after temporary

carbon adsorber, right hand column represents emissions

before control device. Assumes 90 hours of coke burnoff per year.

5 - 11
TABLE 5-7. SUMMARY OF HAP EMXSSXON FACTORS FOR CRU

REGENERATION

HAP and type of Emission factor range (lb/mm bbl) 1

control

Total organics 8

Clb HAP-uncontrolled

Cl HAP-controlled

Lower

23

34

Upper

28

8,870

Midrange

25

4,450

130-360c

a Based on venting to a combustion device.

b Includes Hel and chlorine.

c Controlled emission factor range calculated based on

uncontrolled emission factor assuming a 92 to 97 percent

removal efficiency.

TABLE 5-8. CRU HAP EMISSXON ESTXMATES FOR MODEL PLANTS

Model plant

Capacity (bbl/day)

Organics (tpy)

Cl HAPuncontrolled (tpy)

Cl HAP-controlled

(tpy)

1

6,300

0.026 - 0.032

5.1

0.2 - 0.4

2

19,000

0.08 - 0.10

15

0.5 - 1.2

3

50,000

0.21 - 0.26

40

1.2 - 3.2

bbl/day = barrels per day.

tpy = tons per year.

Ib/yr = pounds per year.

5 - 12
TABLE 5-9. NATIONWIDE HAP EMISSION ESTIMATES FOR CRU

REGENERATION

Condition

Baselinea

Controlledb

HAP

Organics

HCl and C12

Organics

HCl .and ci,

Emissions (tpy)

15 - 19

1,350

15 - 19

150

a Baseline estimates for HCl and Cl 2 are based on

1,306,000 bbl/day of capacity with single stage

scrubbers, 814,000 bbl/day of capacity with multiple

stage scrubbers and 1,529,000 bbl/day of capacity

without scrubbers.

b Controlled estimates assume 1,577,000 bbl/day of

capacity is equipped with single stage scrubbers and

2,072,000 bbl/day of capacity is equipped with multiple

stage scrubbers.

5.4 HAP EMISSIONS FROM SULFUR RECOVERY UNITS (SRUs)

The major HAP from sulfur recovery units are carbon

disulfide (CS 2 ) and carbonyl sulfide (COS). The data for

these compounds are summarized in Table 5-10 and were

obtained primarily from responses to section 114 requests. 5,6

(See Appendix B for more details.) These data represent HAP

emissions following the incinerator and show a range of 29

to 285 lb per 1,000 long tons per day (ltpd) of sulfur

production capacity. To estimate potential emissions from

units that do not have art incinerator, a destruction

efficiency of 98 percent was assumed, which yields an

uncontrolled emission factor of 1,450 to 14,250 lb/l,OOO

ltpd.

These emission factors were applied to the model plants

in Table 5-11 to estimate typical plant emissions.

Nationwide emission estimates are based on survey data

provided by NPRA. 6 The SRU database contains capacity

information on 161 units nationwide with a total sulfur

5 - 13
pruduction capacity of 18,880 ltpd. The database contains

process type and control information for 140 SRU and 120 of

these units were identified as having an incinerator (or

were subject to the NSPS for SRUs). The capacity of these

controlled units was estimated as 15,470 ltpd, and the

capacity of units without incinerators was estimated as

3,410 ltpd. These capacity estimates were used with the

emission factors to estimate nationwide emissions in

Table 5-11.

TABLE 5-10. SUMMARY OF HAP EMI:SSIONS DATA FOR SRU VENTS 7,8

Plant ID HAP Emissions (lb/1,000 ltpd)

20501 CS2 29

20701 COS 285

20604 COS 171

G COS 50

F COS, CS2 180

Range 29 - 285

TABLE 5-11. HAP EMI:SSI:ON ESTI:MATES FOR SRU VENTS

(COS and CS 2 )

Model plants

Size (ltpd)

Uncontrolled (tpy)

Controlled (tpy)

30

7.9 - 78

0.16 - 1.6

120

32 - 310

0.6 - 6.0

480

130 - 1,250

2.5 - 25

Baseline (tpy)

Controlled (tpy)

Nationwide1

980 - 9,700

100 - 1,000

1 Nationwide estimates based 15,470 ltpd of sulfur

produced in controlled units and 3,410 ltpd of

sulfur produced in uncontrolled units.

5 .5 REFERENCES

1. Letter from David Hansell, EER, to Robert Lucas,

U.S.EPA, transmitting the API CCU and CRU Data Base

Summary (Draft). December 20, 1996.

5 - 14
2. Letter from David Hansell, EER, to Robert Lucas,

U.S.EPA, transmitting the Detailed API CCU and CRU Data

Base (2nd Draft). January 23, 1997.

3. Database spreadsheet provided by David Hansell, EER, to

Robert Lucas, U.S.EPA, updating the API database, April

1997.

4. Radian Corporation. Results of Dioxin Testing on the

Catalytic Reformer Unit #1 Exhaust; Texaco Refinery;

Bakersfield, California. Final Report. August 8,

1991.

5. u.s Environmental Protection Agency. Responses to

Information Collection Request for Petroleum

Refineries. Office of Air Quality Planning and

Standards, Research Triangle Park, NC. 1992.

7. u.s. Environmental Protection Agency. Presumptive MACT

for Petroleum Refinery Process Vents: FCC Units,

Reformers, and Sulfur Recovery Plants. Appendix BSummary of Emissions Data. Office of Air Quality

Planning and Standards, Research Triangle Park, NC.

1997.

8. Letter from Norbert Dee, NPRA, to Robert Lucas,

U.S.EPA, transmitting SRU Database. June 12, 1997.

5 - 15
,1

". I

-. r

" I'

r.

(Thi's pageintention~llyleft blank)
6.0 OTHER ENVIRONMENTAL AND ENERGY IMPACTS ESTIMATES

This chapter presents estimates the environmental

impacts, other than HAP emission reduction, and the energy

impacts associated with the control technologies applicable

for the three petroleum refinery process vents. Many of the

other environmental and energy impact estimates are based on

control device design algorithms from EPA's Control Cost

Manual.! The control equipment design parameters are,

therefore, summarized in Chapter 8 of this document and only

the applicable environmental and energy impacts are provided

in this chapter. For more details on the control device

design parameters, the reader is referred to Chapter 8.

6.1 OTHER ENVIRONMENTAL IMPACTS FOR CCUCR VENTS

The primary impacts from the operation of ESPs to

control metal HAP emissions from the CCUCR vent are the

added energy requirements of the ESP and the exhaust fan.

These energy requirements were estimated based on the

control device designs for model CCUCR units as described in

Chapter 8. The ESP will also collect particle fines from

the CCU vent stream that will require disposal as a nonhazardous solid waste. The quantity of CCU fines requiring

disposal was calculated in the costing algorithm from the

particle loading to the ESP.

There are two additional considerations in estimating

the other environmental impacts of operating a wet scrubber

emission control device for the CCUCR vent. First, the wet

scrubber also creates a wastewater stream which contains the

CCU fines. It is assumed that the CCU fines are first

settled (removed) from the wastewater stream and that the

wastewater stream then requires additional treatment and

6 - 1
disposal. The costing algorithm assumes·that the total

weight of the settled solids is 2 times the particle loading

to the wet scrubber. The amount of water requiring

treatment and disposal is also estimated from the control

cost algorithms.

The second consideration in estimating the other

environmental impacts of operating a wet scrubber emission

control device is the scrubbers ability to also remove

sulfur oxides (SOx' which includes both S02 and 5°3 ) . The

amount of SOx in the CCDCR flue gas is dependent primarily

on the sulfur content of the CCU feedstock. For the

purposes of estimating other environmental impacts, it is

assumed that the average SOx concentration in the CCUCR flue

gas is 500 ppmv (450 ppmv S02 and 50 ppmv 803) and it is

assumed that the scrubber's SOx removal efficiency is

90 percent. 2

Table 6-1 provides a comparison of the other

environmental and energy impact estimates for an ESP and a

wet scrubber control device used to remove metal HAP for the

model CCDCR units.

Due to the relatively high CO content of incomplete

combustion CCUCR exhaust gases, energy may actually be

recovered using a combustion device on this vent stream.

Additionally, refineries may be expected to have additional

fuel gas that could be used to stabilize the incinerator

flame. However, it is assumed that energy is not be~ng

recovered from the CCUCR vent incinerator except for heat

recovery as specified in the control cost's incinerator

design and that natural gas is used to stabilize the

incinerator flame for the purposes of estimating other

environmental and energy impacts. The incinerator uses both

electricity (for the exhaust fan) and natural gas.

Table 6-2 summarizes the other environmental and energy

6 - 2
0'\

w

TABLE 6-1. COMPARISON OF OTHER ENVIRONMENTAL AND ENERGY IMPACTS

FOR INORGANIC HAP EMISSION CONTROL DEVICES FOR THE CCUCR VENT.

small CCU Medium CCU Large CCU

Control Devicel

Annual Impact wlo CO wi CO w/o CO wi CO w/o CO wi CO

Boiler Boiler Boiler Boiler Boiler Boiler

ESP

Electricity Use

470 630 1/730 2/200 4/400 6/290

(1/000 kW-hr)

Solid Waste (tons) 180 240 680 860 1/710 2/450

Venturi Scrubber ,

Electricity Use

390 520 1/420 1/810 3/620 5/170

(1/000 kW-hr)

Solid Waste (tons) 370 490 1/350 1/720 3/430 4/910

Water Consumption 130 170 470 600 1/200 1/720

(1E+06 gallons)

SOx Emissions 1

(300 ) (400) (1/100) (1/400) (2/800) (4/000) (tons)

lBrackets around other emission impact estimates indicate emission reductions.

t:l

t'1j

t-3

§

CD

\D

\D

co
TABLE 6-2. ANNUAL OTHER ENVIRONMENTAL AND ENERGY IMPACT

ESTIMATES FOR MODEL CCUCR VENT INCINERATORS.

Small Mediwn Large Annual :Impact CCtJ CCU CCU

Electricity Use

600 2,190 5,580 (1,000 kW-hr)

Natural Gas Consumption 31 114 290

(lE+06 cubic feet)

impacts for a thermal incinerator used to destroy organic

HAP in the CCUCR vent model units.

Nationwide estimates of other environmental and energy

impacts were developed using the throughput of units

anticipated to add control devices for CCU units(i.e., the

same assumptions used to estimate the emission reductions

presented in Chapter 5). The other environmental and energy

impacts were estimated two separate ways based on the type

of inorganic HAP emission control device installed. The

first analysis assumes all units install an ESP; the second

analysis assumes all units install a venturi scrubber. The

nationwide impacts estimates for both these analyses are

presented in Table 6-3.

6.2 OTHER ENVIRONMENTAL IMPACTS FOR CRUCR VENTS

The types of other environmental and energy impacts

associated with wet scrubbing to remove HCI from the CRUCR

vent stream include electricity use for fans and pumps and

the production of a wastewater stream that requires

treatment and disposal. These impacts are directly

estimated from the control cost algorithms for the model

CRUCR units as described in Chapter 8. The other

environmental and energy impacts estimates for the CRU vent

model units are summarized in Table 6-4; the nationwide

6 - 4
other environmental and energy impacts estimates for the

CRUCR units are provided in Table 6-5.

TABLE 6-3. NATIONWIDE ANNUAL OTHER ENVIRONMENTAL AND ENERGY

IMPACTS ESTIMATES FOR THE CCUCR VENT1

Nationwide Annual ESPI venturi

Scrubberl Impact Incinerator Incin~rator

Electricity Use 100 87 (lE+06 kW-hr)

Solid Waste (tons) 41,200 82,500

Wastewater Production 0 28,900 (lE+06 gallons)

SOx Emissions(tons) 0 (67,200)2

Natural Gas Consumption 31 31 (lE+06 cubic feet)

1 Based on adding an inorganic HAP control device

(either an ESP or a venturi scrubber) for

1,400,000 bbl/day of CCU capacity and adding an

organic HAP control device (incinerator) for

47,000 bbl/day capacity.

2 Brackets around emission impact indicate an

emission reduction.

6 - 5
TABLE 6-4. OTHER ENVIRONMENTAL AND ENERGY IMPACTS ESTIMATES

FOR MODEL PLANT CRUCR VENTS

CRU Annual Annual

No. CRUCR Type Throughput Electricity Wastewater

Range Use Production

(1,000 bpd) (kW-hr) (1,000 gal)

1 Semi-Regen. o to <15 349 39

2 Semi-Regen. 15 to 30 621 70

3 Semi-Regen. >30 1,160 130

4 Cyclic o to <15 1,360 57

5 Cyclic 15 to 30 2,270 95

6 Cyclic >30 4,090 170

7 Continuous 0 to <15 1,230 51

8 Continuous 15 to 30 2,050 86

9 Continuous >30 4,090 170

TABLE 6-5. NATIONWIDE ANNUAL OTHER ENVIRONMENTAL AND ENERGY

IMPACTS ESTIMATES FOR THE CRUCR VENTi

Annual Annual

CRUCR Type Electricity Wastewater

Use Producti.on

(kW-hr) (1,000 gal)

Semi-Regenerative 13,000 1,460

Cyclic/Continuous 113,000 4,750

Total 126,000 6,210

1 Based on facility specific analysis of size and

type of CRUCR using impact factors presented in

Table 6-4. Total throughput of CRU units adding

controls was 1,529,000 bbl/day.

6.3 OTHER ENVIRONMENTAL IMPACTS FOR SRU VENTS

The environmental and energy impacts associated with

the SRU vent emission controls include both electricity and

natural gas consumption as well as additional SOx emissions

due to the conversion of reduced sulfur compounds to SOx.

6 - 6
The energy impacts are directly estimated from the control

cost design algorithms for the model SRU incinerators as

described in Chapter 8. The SOx emis~ions estimates are

based on the reduced sulfur compound inlet concentration of

4,000 ppmv (as used in the incinerator design) and one mole

SOx produced per mole of reduced sulfur compound in

incinerator inlet. Table 6-6 summarizes the other

environmental and energy impacts estimates for model SRU

units. Table 6-7 presents the nationwide other

environmental and energy impacts estimates for SRU vents.

TABLE 6-6. ANNUAL OTHER ENVIRONMENTAL AND ENERGY IMPACT

ESTIMATES FOR MODEL SRU VENT INCINERATORS.

Annual :Impact Small Medium Large

CCU CCU CCU

Electricity Use 135 539 2,160 (1,000 kW-hr)

Natural Gas Consumption 11 44 178 .(1E+06 cubic feet)

SOx Emissions(tons) 336 1,340 5,380

TABLE 6-7. NATIONWIDE OTHER ENVIRONMENTAL AND ENERGY

IMPACT ESTIMATES FOR SRU VENTS 1

ADDual :Impact Nationwide

Electricity Use 2,160 (1,000 kW-hr)

Natural Gas Consumption 178 (1E+06 cubic feet)

SOx Emissions (tons) 38,200

1 Based on incinerators added to control emissions

from the production 3,410 ltpd of sulfur.

6 - 7
.. :

{q:'11i. spage 1'8'· i'ri'~ eritional1$' ·'ler·t". .JjlaiilfF

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("~'.~~" ~:~'" ,. ", .'. .'-.1,~
7.0 MONITORING OPTIONS

This chapter presents a brief review of options

available for monitoring HAP emission at petroleum

refineries for each process vent (CCUCR, CRUCR, SRU vents).

In general, the monitoring options were established using

the following priorities. The top priority was given to the

use of continuous emission monitors (CEMs) that directly

measure HAP emissions. Second priority was given the

continuous emission monitors that measure a surrogate of HAP

emissions (such as particulate matter for metal HAP). Third

priority was given to continuous monitoring of process

parameters that are indicative of process emissions or the

effectiveness of the emission control device.

7.1 MONITORING OPTIONS FOR THE CCUCR VENT

There are two separate monitoring options for the CCUCR

vent based on the two classes of HAP/control devices. For

organic HAP, continuous emission monitoring for specific

organic HAP was not considered a proven (commercially

available and reliable) monitoring option at this time, and

was considered inferior to other continuous monitoring

options due to the time delay between sample collection and

the availability of final results. Continuous monitoring of

an indicator of organic HAP was therefore evaluated. Two

potential indicators of organic HAP were considered. These

were: 1) continuous monitor of total hydrocarbon (THC) or

total organic carbon (TOC) using a flame ionization detector

(FID) or a photo ionization detector CEMj and 2) continuous

monitoring of carbon monoxide (CO) using a carbon monoxide

CEM. Both of these monitoring devices appear feasible for

7 - 1
the CCUCR vent. Several refineries currently employ

continuous Toe or CO monitors; however, only CO CEMs are

employed specifically on the CCUCR vent (to show compliance

with the petroleum refinery NSPS - 40 CFR 60, Subpart J).l

As the available emission data show an equally strong

correlation between measured organic HAP and CO emissions as

they do organic HAP and THC/TOC emissions, a continuous CO

monitor was selected as the surrogate CEM for further

evaluation. Finally, parametric monitoring options were

considered. For complete combustion CCUCR units, continuous

parametric monitoring of temperature and exhaust oxygen

content were selected as a monitoring option to indicate

complete combustion of organic HAP. For CO boilers/thermal

incinerators used for incomplete combustion CCUCR units,

continuous parametric monitoring of temperature was selected

as a monitoring option to indicate proper incinerator

performance and operation. These parameters are commonly

monitored at nearly all CCUCR units.

Continuous emission monitoring of either metal HAP or

an indicator of metal HAP such as particulate matter (PM)

was not considered proven (commercially available and

reliable) CEM. Additionally, the lag time between sampling

and analysis for these monitoring approaches makes them

inferior to continuous parametric monitoring of the control

device. The appropriate parameters to monitor are dependent

on the control device used to achieve. For ESPs, continuous

parametric monitoring of voltage and secondary current were

selected as a monitoring option to indicate proper control

device performance and operation. For venturi wet

scrubbers, continuous parametric.monitoring of pressure

drop, air flow rate, and water flow rate were selected as a

monitoring option to indicate proper wet scrubber

performance and operation.

7.2 MONITORING OPTIONS FOR THE CRUCR VENT

For the depressurization/purge and the rejuvenation/

final purge CRUCR vents, the vent gases are either vented to

7 - 2
the refineries fuel gas (flare) system or a dedicated

thermal combustion device. The monitoring provisions for a

flare as outlined in the General Provisions (40 CFR 63,

Subpart A)2 (i.e., monitor for presence of a flame) was the

only monitoring option considered. The monitoring options

evaluated for a dedicated thermal combustion device for the

CRUCR vents included specific organic HAP CEM, surrogate of

organic HAP (THC/TOC) CEM, and continuous parametric

monitoring. Due to the potentially acidic environment

within the combustion unit (from the formation or prior

existence of hydrogen chloride in the vent stream), the

useful life of a CEM probe is uncertain and expected to be

short. That is, both the organic HAP CEM and the THC/TOC

CEM were considered unproven technologies for the CRUCR vent

streams. Consequently, continuous parametric monitoring of

temperature was selected as the only monitoring option for

the CRUCR vent streams that are exhausted to a dedicated

thermal combustion unit.

For the CRUCR coke burn vent, the primary HAP emitted

from the depressurization/purge and the rejuvenation/final

purge vent cycles are hydrogen chloride (HCl) and chlorine.

Continuous HCl monitors are commercially available, but no

refineries were identified that employed a continuous HCl

monitor for the CRUCR coke burn vent. Continuous monitoring

of the gas and liquid flow/recirculation rates were selected

as indicators of proper control device operation.

7.3 MONITORING OPTIONS FOR THE SRU VENT

Carbonyl sulfide and carbon disulfide are the primary

HAP emitted from the SRU vent. A CEM specific to just these

two HAP is not commercially available at this time.

However, CEMs for monitoring reduced sulfur compound

emissions are commercially available and are in-use at

several refineries for the SRU vent to show compliance with

the petroleum refinery NSPS (40 CFR 60, Subpart J).3

Although reduced sulfur compounds are a surrogate of the HAP

emissions, it was considered a to be an excellent surrogate

7 - 3
since reduced sulfur compounds consist only of the two

specified sulfur HAP compounds plus hydrogen sulfide.

Only one parametric monitoring option was identified

for SRU vents and that monitoring option is applicable only

to SRU that empl.oy an incinerator. temperature and excess

oxygen we~e selected as the indicators of proper control

device performance.

7.4 REFERENCES

1. Code of Federal Regulations. Title 40, Part 60,

Subpart J. Standards of Performance for Petroleum

Reifineries. u.S. Government Printing Office.

Washington ,D.C. July 1, 1992.

2. Code of Federal Regulations. Title 40, Part 63,

Subpart A. General Provisions. u.S. Government

Printing Office. Washington ,D.C. July 1, 1992.

3. Reference 1.

7 - 4
8.0 COST OF CONTROLS FOR MODEL PLANTS

This chapter presents information on control costs for

the various control equipment that may be included in the

control option control requirements. Control costs for each

control device for each model plant are reported in terms of

total capital investment (TCI), annual operating costs

(AOC), and total annualized costs (TAC) in late 1996

dollars. The basis for calculating these control costs are

also described.

8.1 COSTS OF CONTROL DEVICES FOR CCUCR VENT

In this section, control costs are developed for

selected control devices applicable for reducing HAP

emissions from the CCUCR vent. The control devices selected

for cost analysis for the CCUCR vent include: ESPs, venturi

wet scrubbers, and CO boilers/incinerators. A correlation

of the CCUCR flow rate versus CCU throughput was derived

based on the available data to estimate model plant CCUCR

vent flow rates. 1 The predicted model plant CCUCR flow

rates are summarized in Table 8-1. The control device

design and cost analyses were then performed based on these

model CCUCR vent flow rates.

TABLE 8-1. MODEL PLANT CCUCR VENT FLOW RATES

CCU capacity Vent Flow Rate Vent Flow Rate

No. Size wino CO Boiler w/CO Boiler (bbl/day) O(scfml 1 o (scfml 1

1 Small 8,300 15,000 20,000

2 Medium 25,000 55,000 70,000

3 Large 70,000 140,000 200,000

lStandard conditions at 60°F as defined in ICR.

8.1.1 Costs for ESPs

8 - 1
The costing procedures outlined in EPA's Control Cost

Manual were used to develop costs for ESPs. 2 The ESP design

parameters were based on the model plant vent flow rates and

typical operating parameters as reported in responses to

EPA's information collection requests (ICR) and industry

supported surveys. The mean mass diameter was estimated to

be 4 ~m based on the assumption that cyclone separators

(used to minimize catalyst loss from the CCUeR) will

generally pass particles with diameters of 10 ~m and less.

It was assumed that the dust would not have severe back

corona effects (i.e., a resistivity of less than 2 x lOll

ohm-cm was assumed). The design parameters used to develop

costs for ESPs are summarized in Table 8-2.

TABLE 8-2. DESIGN VALUES FOR ESP

Parameter Value

ESP Type Plate & wire

Inlet PM (grains/cu.ft) 0.20

Design outlet PM (grains/cu.ft) 0.02

Required design efficiency (E) 0.90

Penetration (p=1- E) 0.10

Temperature (OK) 478

Resistivity (ohm-em) 2.0E+09

Inlet mass mean diameter, MMD (pm) 4

Sneakage (8n) 0.07

Rapping Re-entrainment (RR) 0.124

MMD for most penetrating size (pm} 2

MMD for rapping puff size (pm) 3

Design flow rate, Q(acfm) Q(scfm)xT (OK)/289

Based on the ESP design parameters in Table 8-2, the

projected specific collection area is 717 ft 2/kacfm. The

8 - 2
total capital investment, annual operating costs and total

annual costs for model plant ESPs are summarized in

Table 8-3. Equations for estimating the control costs based

on inlet flow rate and the design values summarized in

Table 8-2 are also provided Table 8-3.

TABLE 8-3a. MODEL PLANT CCUCR ESP CONTROL COSTS1 - TCl

CCU TCl for CCU wlo TCl for CCU

No. Size capacity CO Boiler w/CO Boiler

(bbl/day) ($1,000) ($1,000)

1 Small 8,300 1,500 1,800

2 Medium 25,000 3,200 3,900

3 Large 70,000 6,900 9,200

TCl ($1,000) = [0.0416 x Q(scfm}2] + 943

TABLE 8-3b. MODEL PLANT CCUCR ESP CONTROL COSTS1 - AOC

CCU AOC for CCU wlo AOC for CCU

No. Size capacity CO Boiler w/CO Boiler

(bbl/day) ($l,OOO) ($l,OOD)

1 Small 8,300 150 180

2 Medium 25,000 340 410

3 Large 70,000 740 1,000

AOC ($1,000) = [0.00468 x Q(scfm) 2] + 85

TABLE 8-3c. MODEL PLANT CCUCR ESP CONTROL COSTS1 - TAC

CCU TAC for CCU wlo TAC for CCU

No. Size capacity CO Boiler w/CO Boiler

(bbl/day) ($1,000) ($1,000)

1 Small. 8,300 300 350

2 Medium 25,000 640 780

3 Large 70,000 1,400 1,900

TAC ($1,000) = [0.0086 x Q(scfm)2] + 174

lCosts rounded to 2 significant digits or nearest $100,000.

2Ba s e d on standard conditions at 60°F.

8.1.2 Cost for Venturi Wet Scrubbers

8 - 3
The costing procedures outlined in EPA's Handbook -

Control Technologies for Hazardous Air Pollutants were used

to develop costs for venturi scrubbers. 3 The venturi

scrubber design parameters were based on the same model

plant vent flow rates as used to estimate costs for ESPs.

Again, the mean mass diameter was estimated to be 4 ~m based

on the assumption that cyclone separators (used to minimize

catalyst loss from the CCUCR) will generally pass particles

with diameters of 10 ~m and less. The design parameters

used to develop costs for venturi scrubbers are summarized

in Table 8-4.

The total capital investment, annual operating costs

and total annual costs for model plant venturi scrubbers are

summarized in Table 8-5. Equations for estimating the

control costs based on inlet flow rate and the design values

summarized in Table 8-4 are also provided Table 8-5.

TABLE 8-4. DESIGN VALUES FOR VENTURI SCRUBBERS

Parameter Value

Inlet PM (grainslcu.ft) 0.20

Design outlet PM (grainslcu.ft) 0.02

Required design efficiency (E) 0.90

Pressure drop atdesign efficiency, in H2O 10

Temperature (oF) 400

Moisture content (vol %) 5

Inlet mass mean diameter, MMD (pm) 4

Inlet mass mean diameter, MMD (pm) 4

Design flow rate, Q(acfm) Q(scfm)xT (OR)/520

TABLE 8-5a. MODEL PLANT CCUCR VENTURI SCRUBBER

CONTROL COSTS1 - TCI

8 - 4
CCU TCI for CCU w/o TCI for CCU

No. Size capacity CO Boiler w/CO Boiler

(bbl/day) ($1,000) ($1,000)

1 Small 8,300 210 260

2 Medium 25,000 530 640

3 Large 70,000 1,100 1,400

TCI ($1,000) = exp[O.7229 x In(Q(scfm)2)- 1.6086]

TABLE 8-5b. MODEL PLANT CCUCR VENTURI SCRUBBER

CONTROL COSTSl - AOC

CCU AOC for CCU w/o AOC for CCU

No. Size capacity CO Boiler w/CO Boiler

(bbl/day) ($1,000) ($1,000)

1 Small 8,300 300 370

2 Medium 25,000 880 1,100

3 Large 70,000 2,100 3,000

AOC ($1,000) = [0.0144 x Q(scfm)2] + 87

TABLE 8-5c. MODEL PLANT CCUCR VENTURI SCRUBBER

CONTROL COSTSl - TAC

CCU TAC for CCU w/o TAC for CCU

No. Size capacity CO Boiler w/CO Boiler

(bbl/day) ($1,000) ($1,000)

1 Small 8,300 330 410

2 Medium 25,000 960 1,200

3 Large 70,000 2,200 3,200

TAC ($1,000) = [0.0153 x Q(scfm)2] + 109

lCosts rounded to 2 significant digits or nearest $100,000.

2Ba s e d on standard conditions at GooF.

8 - 5
8.1.3 Costs for CO Boilers/Incineration

The control costs for incinerators were estimated using

the costing procedures outlined in EPA's Control Cost

Manual. 4 The incinerator design parameters were based on

the model plant vent flow rates for CCU regenerators that do

not have CO boilers. It was assumed that the CCUCR flue gas

was at l,200 oF with 2 percent CO content (by volume). To

minimize fuel requirements, the feed air to the incinerator

is preheated by the incinerator exhaust (a 35 percent

recuperative incinerator is more than sufficient); the total

air re~irements were determined from the system energy . I

balance and a design outlet oxygen concentration of 2

percent (by volume). The total capital investment, annual

operating costs and total annual costs for model plant

incinerators for the CCUCR vent are summarized in Table 8-6.

Cost function equations were developed for model plant

incinerators for the CCUCR vent based on linear regression

analysis of the cost data summarized in Table 8-6 and

exhaust gas flow rates (Q in scfm). The cost function

equations for CCDCR incinerators follow.

TCI ($1,000) = exp{0.36787xln(Q)+2.5925}

AOC ($1,000) = 0.01041xQ + 59

TAC ($1,000) = 0.01107xQ + 120

TABLE 8-6. MODEL PLANT CCDCR INCINERATOR

CONTROL COSTS1 - TCI, AOC AND TAC

CCU TCI AOC TAC No. Size capacity ($1,000) ($1,000) ($1,000) (bbl/day)

1 Small 8,300 460 210 280

2 Medium 25,000 730 630 740

3 Large 70,000 1,100 1,500 1,700

lCosts rounded to 2 significant digits or nearest $100,000.

8.2 COSTS OF CONTROL DEVICES FOR CRUCR VENT

8 - 6
In this section, control costs are developed for

selected control devices applicable for reducing HAP

emissions from the CRUCR vent. The control devices selected

for cost analysis for the CRUCR vent include wet scrubbers

and caustic injection. [Currently assumed that all purge

vents to flare or refinery fuel gas system are already inplace.] As the magnitude and duration of the CRUCR vent

flows are dependent on the type of CRUCR (semi-regenerative,

cyclic or continuous) as well as on the throughput of the

CRU, nine model CRUCR vents were developed based on the type

of CRUCR and CRU throughput ranges. The flow rates and

durations of the model plant were selected based on an

analysis of information in the EPA data base. 5 Table 8-7

summarizes the key parameters of the CRUCR model vents.

TABLE 8-7. MODEL PLANT CRUCR VENT FLOW RATES

CRU Coke Burn Annual

Coke Burn

No. CRUCR Type Throughput Vent Flow Vent Range Rate Duration (1,000 bpd) (scfm) 1 (hrs/yr)

1 Semi-Regen.

°to <15 15,000 72

2 Semi-Regen. 15 to 30 20,000 90

3 Semi-Regen. >30 30,000 120

4 Cyclic °

to <15 600 2,400

5 Cyclic 15 to 30 800 3,000

6 Cyclic >30 1,200 3,600

7 Continuous °

to <15 150 8,640

8 Continuous 15 to 30 250 8,640

9 Continuous >30 500 8,640

lStandard conditions at 60°F as defined in ICR.

8 - 7
The control device design and cost analyses were then

performed based on these model CRUCR vent flow rates and

durations. For the cyclic and continuous CRUCR, the control

costs were developed using the control cost algorithms for

packed-bed absorbers presented in EPA's Control Cost

Manual. 6 For semi-regenerative units, control costs for a

caustic spray chamber scrubber were derived using nearly the

same control cost algorithms for packed-bed absorbers

presented in EPA's Control Cost Manual, except no packing

material was used in the spray chamber. The control cost

factors developed for the model CRUCR units are presented in

Table 8-8. These control cost factors were applied directly

to a given CRUCR based on the CRU throughput. That is, no

regression of the cost factors were performed to correlate

CRUCR control costs with CRU throughput within a given CRU

throughput range.

TABLE 8-8. MODEL PLANT CRUCR WET SCRUBBER/ABSORBER

CONTROL COSTS1 - TCl, AOC AND TAC

Regen. CRU TCl AOC TAC No. capacity Type (1000 bpd) ($1,000) ($1,000) ($1,000)

1 Semi <15 38 6 11

2 Semi 15 to 30 47 9 16

3 Semi >30 64 16 25

4 Cyclic <15 45 13 20

5 Cyclic 15 to 30 54 16 24

6 Cyclic >30 68 20 30

7 Cont. <15 21 41 44

8 Cont. 15 to 30 27 41 45

9 Cont. >30 41 42 48

lCosts rounded to 2 significant digits or nearest $1,000.

8 - 8
8.3 COSTS OF CONTROL DEVICES FOR SULFUR PLANT VENT

This section presents the control costs for

incinerators u~ed to reduce HAP emissions from the SRU vent.

A correlation of the SRU tail gas flow rate versus sulfur

production rate was derived based on the data available in

the EPA database. The EPA database was also used to

characterize the SRU tail gas. 7 The predicted model plant

SRU flow rates are summarized in Table 8-9. All model SRU

units (that require an incinerator) are assumed to have tail

gas with the' following properties:

Temperature = 275°F

Reduced Sulfur Compound Concentration = 4,000 ppmv

Oxygen Concentration = 0 ppmv.

TABLE 8-9. MODEL PLANT SRU VENT FLOW RATES

Sulfur Vent Flow Operating

No. Size Production Rate Rate Q (scfm) 1

Hours

(long tons/day) (hrs/yr)

1 Small 30 1,950 8,640

2 Medium 120 7,800 8,640

3 Large 480 31,200 8,640

lStandard conditions at 60°F as de-fined in ICR.

The control costs for SRU incinerators were estimated

using the costing procedures outlined in EPA's Control Cost

Manual. 8 The incinerator design parameters were based on

the model plant vent flow rates for SRUs. To minimize fuel

requirements, both the combustion air and the SRU tail gas

are preheated by the incinerator exhaust; a recuperative

incinerator with 70 percent energy recovery was employed.

The total air requirements were determined from the system

8 - 9
energy balance and a design outlet oxygen concentration of

2 percent (by volume). The total capital investment, annual

operating costs and total annual costs for model plant

incinerators for the SRU vent are summarized in Table 8-10.

TABLE 8-10. MODEL PLANT SRU INCINERATOR

CONTROL COSTS1 - TCI, AOC AND TAC

Sulfur TCI AOC TAC No. Size Prod. Rate ($1,000) ($1,000) ($1,000) (long t.pd)

1 Small 30 360 110 160

2 Medium 120 530 260 340

3 Large 480 810 870 980

lCosts rounded to 2 significant digits or nearest $100,000.

Cost function equations were developed for model plant

incinerators for the CCUCR vent based on linear regression

analysis of the cost data summarized in Table 8-6 and

exhaust gas flow rates (Q in sefm). The cost function

equations for SRU incinerators follow'.

TCI ($1,000) = exp{0.29295xln(Q)+3.6625}

AOC, ($1,000) = 0.02605xQ + 57

TAC ($1,000) = 0.02811xQ + 109

8.4 COSTS OF MONITORING, REPORTING, AND RECORDKEEPING

This section presents the costs associated with control

device monitoring, reporting and recordkeeping for each of

the different types of control devices / refinery vent

combinations. First costs and initial annual costs for

continuous emission monitors (CEMs) are given in Table 8-11

for each type of subject unit and for alternative means of

compliance. CEMs for the units may measure offgas

characteristics (constituent concentration or temperature)

or equipment operating parameters (voltage, current,

8 - 10
pressure drop, or flow rates}. Although purchase costs of

monitors may vary from a few hundred dollars to many

thousands of dollars, depending on the parameter being

monitored, the major cost of a CEM system lies in time and

materials costs for planning, installing, maintaining,

certifying, and recertifying the system for its lifetime.

The costs in Table 1 include these items. In particular,

relative accuracy test audits required for extractive

sampling contribute significantly to annual costs. All

costing was done using EPA's EMTIC program, with costs

escalated to late 1996. 9

Elements of the EMTIC program for first costs include:

planning, selection of equipment, support facilities,

purchase of the CEM, installation and checking, performance

test, and preparation of a QA/QC plan. Elements for the

first year's annual cost include: operation and

maintenance, relative accuracy test audit and supplemental

audit (for extractive gas CEMs) , quarterly cylinder gas

audits (for calibration), record keeping and reporting, and

annual review and update. Where process monitoring

instruments such as temperature, pressure, voltage, and

current instruments are used, they are assumed to be part of

the control system and have their purchase costs allocated

to the process rather than to the CEM system. However,

associated record keeping and reporting, annual review and

update, and some operation and maintenance costs are

assigned to CEM system costs.

The costs in Table 1 have large error bands, but should

be useful for comparing gas CEMs vs parameter monitoring.

While monitor costs are generally supplied by EMTIC or a

vendor quote, the multimetals CEM cost is an estimate.

8 - 11
Table 8-11. First cost and initial annual cost for

continuous emission monitors on CCUs, CRUs,

and SRUs

Unit Pollutant Monitored First Initial

parameter cost, $ annual

cost, $

CCU Organic HAP CO 97,100 63,400

Temperature 18,900 19,500

HAP/TOC 91,300 63,900

Particulate ESP: volts/amps 32,000 20,300

matter

WS: DP, liq. and 37,300 20,400

gas flow rates

Opacity 41,200 18,400

Metallic HAP Mulitmetals (by 132,700 66,600

CEM)

Opacity 41,200 18,400

CRU HCl HCl (by CEM) 104,000 65,000

HCl (by M26A) Not 13,800

applicable

Organic Hap from per general 0 0

flare provisions

Organic Hap from Temperature 18,900 19,500

incinerator

SRU COS/CS2 from Total reduced 117,600 65,900

incinerator sulfur

Temperature 18,900 19,500

CCU

CEM

CRU

DP

ESP

M26A

SRU

HAP

TOC

WS

Catalytic cracking unit

continuous emission monitor

Catalyst regeneration unit

Differential pressure

Electrostatic precipitator

EPA test method 26A for HC1

Sulfur recovery unit

Hazardous air pollutant

Total organic carbon

Wet scrubber

8 - 12
8.5 REFERENCES

1. u.s. Environmental Protection Agency. Refinery process

vent data base ...

2. u.s. Environmental Protection Agency. OAQPS Control

Cost Manual. Publication No. EPA/450/3-90-006. Office

of Air Quality Planning and Standards, Research

Triangle Park, NC. January 1990.

3. u.s. Environmental Protection Agency. HandbookControl Technologies for Hazardous Air Pollutants.

Publication No. EPA/625/6-91/014. Office of Research

and Development, Washington, DC. June 1991. pp. 4-80

through 4-90.

4. Reference 2.

5. Reference 1.

6. Reference 2.

7. Reference 1.

8. u.s. Environmental Protection Agency ...

8 - 13
DRAFT - June 1998

APPENDIX A

KEY DATES IN DEVELOPMENT OF BID

TABLE A-l.

Date

KEY DATES IN THE DEVELOPMENT OF THE BID

Event

July 16, 1992

August 16-17,

1995

August 18, 1995

August 31, 1995

and September 1,

1995

December 1, 1995

December 7, 1995

June 24, 1996

February 28, 1997

The EPA published initial list of

hazardous air pollutant (HAP) emission

source categories (57 FR 31576)

EPA conducted information gathering

site visits to three petroleum

refineries in Pennsylvania and New

Jersey

The EPA published National Emission

Standards 'for Hazardous Air Pollutants

(NESHAP: Petroleum Refineries; Final

Rule (60 FR 43244). This rule, termed

Petroleum Refinery MACT I, deferred

setting NESHAP for three vents:

catalyst regeneration vents on

catalytic cracking units (CCU) and

catalytic reforming units (CRU) and

vents from sulfur recovery units (SRU).

EPA conducted information gathering

site visits to two petroleum refineries

in Louisiana.

EPA held kick-off Presumptive MACT

meeting with regulatory agency

representatives.

EPA held kick-off Presumptive MACT

meeting with representatives of

industrial stakeholders.

EPA met with representatives of

emission control device manufacturers.

EPA finalized the Preliminary

Presumptive MACT for Petroleum Refinery

Process Vents: FCC Units, Reformers,

and Sulfur Plants.

A-1
DRAFT - June 1998

TABLE A-1. KEY DATES (Continued)

Date Event

July 29, 1997

September 12,

1997

September 15,

1997 through

September 17,

1997

EPA held meeting "with small business

petroleum refineries to communicate

EPA's policies regarding Small Business

Regulatory Enforcement Fairness Act

(SBREFA) .

EPA conducted an information gathering

site visit to a small business

petroleum refinery in Indiana.

EPA conducted information gathering

site visits to four small petroleum

refineries in Wyoming and Utah that

have non-conventional units (non-fluid

CCU and non-Claus SRU).

" A-2
APPENDJ:X B. HAP EMJ:SSJ:ONS DATA

This appendix contains the HAP emissions data used to

develop estimates of emissions in Chapter 5 for model plants and

for all units nationwide. The data for catalytic cracking and

catalytic reforming given in Tables B-1 and B-2 were provided in

a database from API and included the results of their survey of

the industry.l The data for sulfur recovery units in Table B-3

were from responses to section 114 questionnaires compiled by the

EPA. 2 These data are also summarized in the document developed

for the presumptive MACT process. 3

REFERENCES

1. Letter from David Hansell, EER, to Robert Lucas, U.S.EPA,

transmitting the Detailed API CCU and CRU Data Base; 2nd

Draft. January 23, 1997

2. u.s Environmental Protection Agency. Responses to

Information Collection Request for Petroleum Refineries.

Office of Air Quality Planning and Standards, Research

Triangle Park, NC. 1992.

3. u.S Environmental Protection Agency. Presumptive MACT for

Petroleum Refinery Process Vents: FCC units, Reformers, and

Sulfur Recovery Plants. Appendix B-Surnmary of Emissions

Data. Office of Air Quality Planning and Standards,

Research Triangle Park, NC. 1997.

B-1
TABLE B-1. EM~SS~ONS DATA FOR CCU REGENERAT~ON (abbreviations

are explained at the end of the table)

Combustion Hydro APC System Sample Substance Data Factor

tvoe treat location source (Jb/mmbbll

NA NA COB COB Outlet 1,3-Butadiene 114 7.00e-04

NA NA COB COB Outlet 1,3-Butadiene 114 9.00e-04

Comolete Yes C\COB\ESP ESP Outlet 1 3-Butadlene Test 4.82e-02

NA NA ESP ESP Outlet Acetaldehyde ICR 2.9ge+OO

NA NA ESP ESP Outlet Acetaldehyde Test 3.ooe+OO

Partial NA C\COB\ESP ESP Outlet Acetaldehyde Test 1.34e+01

Complete Yes C\WHB\ESP\ ESP Outlet Acetaldehyde Test 1.35e+01

COB

Complete Yes C\COB\ESP ESP Outlet Acetaldehyde Test 2.07e+01

NA NA COB\ESP NA Acetaldehyde Test 2.47e+01

NA NA COB\ESP ESP Outlet Acetaldehyde 114 3.02e+01

Partial NA C\COB\ESP ESP Outlet Acetaldehyde Test 3.41e+01

Partial Yes C\COB\ESP ESP Outlet Benzene Test 7.25e-01

Partial Yes C\COB\ESP ESP Outlet Benzene Test 1.98e+OO

Partial Yes C\COB\ESP ESP Outlet Benzene Test 2.7ge+00

Partial Yes C\COB\ESP ESP Outlet Benzene Test 1.06e+01

Partial Yes C\COB\ESP ESP Outlet Benzene Test 1.17e+01

NA NA ESP ESP Outlet Benzene Test 3.97e+01

NA NA ESP ESP Outlet Benzene ICR 4.30e+01

Complete Yes C\WHB\ESP\ ESP Outlet Cyanide ICR 2.83e+01

COB

Complete Yes WHB\ESP\CO COB Outlet Cyanide Test 3.55e+01

B

NA NA ESP ESP Outlet Formaldehyde ICR 1.03e+01

NA NA ESP ESP Outlet Formaldehyde Test 1.04e+01

Partial NA C\COB\ESP ESP Outlet Formaldehyde Test 1.31e+01

Complete Yes C\COB\ESP ESP Outlet Formaldehyde Test 1.63e+01

Partial NA C\COB\ESP ESP Outlet Formaldehyde ICR 1.92e+01

NA NA COB\ESP NA Formaldehyde Test 2.66e+01

Partial NA C\COB\ESP ESP Outlet Formaldehyde Test 2.83e+01

NA NA COB\ESP ESP Outlet Formaldehyde 114 3.15e+01

Complete Yes NA NA Formaldehyde SV 7.89e+01

Complete Yes C\WHB\ESP\ ESP Outlet Formaldehyde ICR 9.299+02

COB

Complete Yes C\WHB\ESP\ ESP Outlet Formaldehyde Test 9.56e+02

COB

Partial NA C\COB\ESP ESP Outlet Formaldehyde Test 6.18e+04

Partial NA C\COB\ESP ESP Outlet Formaldehvde Test 1.40e+05

NA NA C\ESP ESP Outlet Hydrogen Cyanide Test 7.84e-01

NA NA COB\ESP NA Hydrogen Cyanide Test 1.40e+01

Complete Yes C\COB\ESP ESP Outlet Hydrogen Cyanide Test 2.46e+01

Complete Yes C\WHB\ESP\ ESP Outlet Hydrogen Cyanide Test 2.90e+01

COB

Partial Yes C\COB\ESP NA Hydrogen Cyanide 114 1.94e+02

NA NA ESP ESP Outlet Hvdroaen Cyanide Test 2.58e+03

Complete Yes WHBWS VS Outlet n-Hexane 114 5.41e+01

Partial Yes C\COB\ESP ESP Outlet Toluene Test 8.05e-02

Partial Yes C\COB\ESP ESP Outlet Toluene Test 9.01e-02

Partial Yes C\COB\ESP ESP Outlet Toluene Test 1.27e-01

B-2
TABLE B-1. EMJ:SSJ:ONS DATA FOR CCU REGENERATJ:ON (continued)

Combustion Hydro APC System Sample Substance Data Factor

Itvce treat location source llb/mm bbll

Partial Yes C\COB\ESP ESP Outlet Toluene Test 3.749+00

NA NA COB\ESP ESP Outlet Toluene ICR 1.38e+03

NA NA COB\ESP ESP Outlet Total XYlene ICR 9.00e+01

Partial Yes C\COB\ESP ESP Outlet 2-MethYlnachthalene Test 2.61e-02

Complete Yes WHB\ESP\CO COB Outlet Phenol Test 2.27e-04

B

Complete Yes C\COB\ESP ESPOutlet Phenol Test 8.41e-01

NA NA ESP ESPOutlet Phenol ICR 1.11e+OO

NA NA ESP ESPOutlet Phenol Test 1.15e+OO

NA NA COB\ESP ESPOutlet Phenol 114 2.15e+01

NA NA C\ESP ESPOutlet Phenol Test 4.0ge+01

Complete Yes WHB\ESP\CO COB Outlet Acenaphthene Test 4.90e-04

B

Partial Yes C\COB\ESP ESPOutlet Acenaohthene Test 6.08e-03

Complete Yes WHB\ESP\CO COB Outlet Acenaphthylene Test 3.54e-04

B

ComDlete Yes C\COB\ESP ESPOutlet Acenachthylene Test 2.57e-01

Complete Yes WHB\ESP\CO COB Outlet Anthracene Test 1.13e-03

B

NA NA C\ESP ESPOutlet Anthracene Test 2.03e-01

Complete Yes WHB\ESP\CO COB Outlet Benzo(a)anthracene Test 5.24e-04

B

Partial Yes C\COB\ESP ESP Outlet BenzolalDvrene Test 1.06e-02

Complete Yes WHB\ESP\CO COB Outlet Benzo(b)fluoranthene Test 1.06e-03

B

Partial Yes C\COB\ESP ESPOutlet BenzoCblfluoranthene Test 5.94e-03

Complete Yes WHB\ESP\CO COB Outlet Benzo(e)pyrene Test 4.54e-04

B

Partial Yes C\COB\ESP ESPOutlet BenzoCa.h.j)De~lene Test 4.60e-03

Complete Yes WHB\ESP\CO COB Outlet Benzo(k)fluoranthene Test 3.66e-04

B

Partial Yes C\COB\ESP ESPOutlet BenzoCklfluoranthene Test 4.86e-03

Complete Yes WHB\ESP\CO COB Outlet Chrysene Test 2.569-03

B

Partial Yes C\COB\ESP ESPOutlet chrvsene Test 3.98e-03

Partial Yes C\COB\ESP ESPOutlet dibenz(a,h)anthracen Test 4.58e-03

e

Partial Yes C\COB\ESP ESPOutlet Fluoranthene Test 4.92e-03

NA NA C\ESP ESPOutlet FIuoranthene Test 2.71e-01

Complete Yes WHB\ESP\CO COB Outlet Fluorene Test 1.92e-03

B

Partial Yes C\COB\ESP ESP Outlet Fluorene Test 6.52e-03

NA NA C\ESP ESP Outlet Fluorene Test 1.01e-01

Partial Yes C\COB\ESP ESP Outlet Indeno(1,2,3-cd)pyren Test 4.38e-03

e

Complete Yes WHB\ESP\CO COBOuUet Naphthalene Test 1.02e-01

B

Partial Yes C\COB\ESP ESP Outlet Naphthalene Test 8.64e-01

NA NA ESP ESP Outlet Naphthalene ICR 1.52e+OO

NA NA ESP ESP Outlet Naphthalene Test 1.55e+oO

NA NA C\ESP ESP Outlet Naohthalene Test 1.68e+OO

B-3
TABLE B-1. EM:ISS:IONS DATA FOR CCU REGENERAT:ION (continued)

Combustion Hydro APC System Sample Substance Data Factor

type treat location source flb/mm bbl)

NA NA COB\ESP NA PAH (Total) Test 8.05e+OO

Partial Yes C\COB\ESP COB Outlet PAH (Total) 114 1.94e+02

Complete Yes WHB\ESP\CO COB Outlet Phenanthrene Test 1.15e-02

B

Partial Yes C\COB\ESP ESP Outlet Phenanthrene Test 2.40e-02

NA NA ESP ESP Outlet Phenanthrene Test 1.48e-01

NA NA C\ESP ESP Outlet Phenanthrene Test 7.94e-01

NA NA COB\ESP NA Phenolics (Total) Test 2.02e+01

Complete Yes WHB\ESP\CO COB Outlet Pyrene Test 2.4ge-03

B

Partial Yes C\COB\ESP ESP Outlet Pvrene Test 4.42e-03

NA NA COB COB Outlet Antimony 114 3.20e-02

Partial Yes C\COB\ESP ESP Outlet Antimony Test 4.36e-02

NA NA COB COB Outlet Antimony 114 4.40e-02

Complete Yes ESP ESP Outlet Antimony 114 5.00e-02

Complete Yes ESP ESP Outlet Antimony 114 1.00e-01

Partial No I Regen Outlet Antimony Test 2.33e+OO

Complete Yes ESP ESP Outlet Antimony 114 5.53e+oO

Partial No C\ESP\COB COB Outlet Antimonv ICR 9.95e+OO

NA NA COB COB Outlet Arsenic 114 1.00e-03

NA NA COB COB Outlet Arsenic 114 1.00e-03

Partial Yes C\COB\ESP ESP Outlet Arsenic Test 6.87e-02

Partial Yes C\COB\ESP ESP Outlet Arsenic Test 7.40e-02

Complete Yes C\COB\ESP ESP Outlet Arsenic Test 1.21e-01

Partial NA C\COB\ESP ESP Outlet Arsenic Test 1.67e-01

NA NA C\ESP ESP Outlet Arsenic Test 2.2ge-01

Partial NA C\COB\ESP ESP Outlet Arsenic Test 2.8ge-01

Partial Yes C\COB\ESP ESP Outlet Arsenic Test 3.97e-01

Partial NA C\COB\ESP ESP Outlet Arsenic ICR 4.70e-01

Partial NA C\COB\ESP ESP Outlet Arsenic Test 1.12e+OO

Partial Yes C\COB\ESP ESP Outlet Arsenic Test 1.43e+OO

Partial No I Reoen Outlet Arsenic Test 1.70e+OO

NA NA COB COB Outlet Beryllium 114 2.00e-03

NA NA COB COB Outlet Beryllium 114 3.00e-03

Partial No I Regen Outlet Beryllium Test 5.36e-02

Partial Yes C\COB\ESP ESP Outlet Beryllium Test 6.58e-02

NA NA COB COB Outlet Cadmium 114 4.00e-03

NA NA COB COB Outlet Cadmium 114 5.00e-03

Partial NA C\COB\ESP ESP Outlet Cadmium ICR 2.00e-02

Partial NA C\COB\ESP ESP Outlet Cadmium Test 2.06e-02

Partial Yes C\COB\ESP ESP Outlet Cadmium Test 4.4ge-02

Partial NA C\COB\ESP ESP Outlet Cadmium Test 9.24e-02

NA NA -ESP ESP Outlet Cadmium ICR 2.80e-01

NA NA ESP ESP Outlet Cadmium Test 2.96e-01

Partial No I Regen Outlet Cadmium Test 3.41e-01

Partial Yes C\COB\ESP ESP Outlet Cadmium Test 8.70e-01

Partial Yes C\COB\ESP ESP Outlet Cadmium Test 1.65e+OO

Partial Yes C\COB\ESP ESP Outlet Cadmium Test 2.82e+OO

NA NA COB COB Outlet Chromium 114 4.30e-02

B-4
TABLE B-1. EMZSSZONS DATA FOR CCU REGENERATZON (continued)

Combustion Hydro APCSystem Sample Substance Data Factor

tvDe treat location source C1b1mm bbl)

NA NA COB COB Outlet Chromium 114 5.90e-02

Partial NA C\COB\ESP ESP Outlet Chromium Test 1.26e-01

Partial Yes C\COB\ESP ESP Outlet Chromium Test 2.43&-01

Partial NA C\COB\ESP ESP Outlet Chromium ICR 2.90e-01

Complete Yes WHB\ESP\CO COB Outlet Chromium Test 4.99e-01

8

Partial NA C\COB\ESP ESP Outlet Chromium Test 5.01e-01

NA NA C\ESP ESP Outlet Chromium Test 5.66e-01

Partial Yes C\COB\ESP ESP Outlet Chromium Test 8.3Oe-01

Complete Yes C\WHB\ESP\ ESP Outlet Chromium ICR 9.ooe-01

COB

Complete Yes C\COB\ESP ESP Outlet Chromium Test 9.47e-01

Complete Yes C\WHB\ESP\ ESP Outlet Chromium Test 9.79e-01

COB

Partial No I Regen Outlet Chromium Test 1.116+00

Partial Yes C\COB\ESP ESP Outlet Chromium Test 1.166+00

Partial Yes C\COB\ESP ESP Outlet Chromium Test 2.106+00

NA NA ESP ESP Outlet Chromium ICR 2.596+00

NA NA ESP ESP Outlet Chromium Test 2.936+00

Partial NA C\COB\ESP ESP Outlet Chromium Test 7.58e+OO

Partial Yes C\COB\ESP ESP Outlet Chromium Test 1.186+01

Partial NA C\COB\ESP ESP Outlet Chromium Test 2.716+01

NA NA COB COB Outlet Cobalt 114 6.00e-03

NA NA COB COB Outlet Cobalt 114 9.00e-03

Complete Yes ESP ESP Outlet Cobalt 114 2.1Oe-01

Complete Yes ESP ESP Outlet Cobalt 114 4.10e-01

Partial No I Regen Outlet Cobalt Test 1.13e+OO

Comolete Yes ESP ESP Outlet Cobalt 114 1.4ge+OO

NA NA COB COB Outlet Lead 114 1.05e-01

NA NA COB COB Outlet Lead 114 1.45e-01

Complete Yes WHBWS VS Outlet Lead 114 1.80e-01

Partial NA C\COB\ESP ESP Outlet Lead ICR 2.70e-Q1

Partial Yes C\COB\ESP ESP Outlet Lead Test 2.81e-Q1

Complete Yes WHB\ESP\CO COB Outlet Lead Test 2.82e-01

B

Partial NA C\COB\ESP ESP Outlet Lead Test 4.54e-01

Partial Yes C\COB\ESP ESP Outlet Lead Test 6.06e-01

Partial Yes C\COB\ESP ESP Outlet Lead Test 1.53e+OO

Complete Yes C\COB\ESP ESP Outlet Lead Test 1.65e+OO

PartIal NA C\COB\ESP ESP Outlet Lead Test 2.84e+OO

Partial Yes C\COB\ESP ESP Outlet Lead Test 3.50e+OO

NA NA C\ESP ESP Outlet Lead Test 4.52e+OO

Partial NA C\COB\ESP ESP Outlet Lead Test 5.45e+OO

Partial Yes C\COB\ESP ESP Outlet Lead Test 6.20e+OO

Partial No I Regen Outlet Lead Test 6.2ge+OO

NA NA I\ESP NA Lead 114 6.72e+OO

Partial NA C\COB\ESP ESP Outlet Lead Test 9.17e+OO

Partial NA C\COB\ESP ESP Outlet Manganese Test 3.69e-Q1

B-5
TABLE B-1. EM:ISS:IONS DATA FOR CCU REGENERAT:ION (continued)

Combustion Hydro APCSystem Sample Substance Data Factor

Itvoe treat location source (Ib/mm bbn

Complete Yes WHB\ESP\CO COB Outlet Manganese Test 3.71e-01

B

NA NA C\ESP ESP Outlet Manganese Test 6.26e-01

Partial Yes C\COB\ESP ESP Outlet Manganese Test 1.05e+oO

Partial NA C\COB\ESP ESP Outlet Manganese Test 1.78e+OO

Complete Yes C\COB\ESP ESP Outlet Manganese Test 2.0ge+OO

NA NA ESP ESP Outlet Manganese ICR 2.32e+OO

NA NA ESP ESP Outlet Manganese Test 2.45e+OO

Partial No I Regen Outlet Manganese Test asse-oo

Complete Yes C\WHB\ESP\ ESP Outlet Manganese ICR 1.08e+01

COB

Complete Yes C\WHB\ESP\ ESP Outlet Manganese Test 1.10e+01

COB

Partial NA C\COB\ESP ESP Outlet Manganese Test 1.42e+01

Partial NA C\COB\ESP ESP Outlet Manaanese Test 2.3Oe+01

NA NA COB COB Outlet Mercury 114 1.00e-03

NA NA COB COB Outlet Mercury 114 1.00e-03

Partial NA C\COB\ESP ESP Outlet Mercury Test 3.07e-02

Partial NA C\COB\ESP ESP Outlet Mercury Test 3.4ge-02

Complete Yes C\COB\ESP ESP Outlet Mercury Test 6.98e-02

NA NA C\ESP ESP Outlet Mercury Test 7.04e-02

Partial Yes C\COB\ESP ESP Outlet Mercury Test 1.48e-01

Partial NA C\COB\ESP ESP Outlet Mercury Test 1.62e-01

NA NA ESP ESP Outlet Mercury ICR 3.00e-01

NA NA ESP ESP Outlet Mercury Test 3.1ge-01

Complete Yes C\WHB\ESP\ ESP Outlet Mercury Test 4.58e-01

COB

Complete Yes C\WHB\ESP\ ESP Outlet Mercury ICR 6.00e-01

COB

Partial No I Recen Outlet Mercurv Test 2.88e+00

Complete No WHB\ESP ESP Outlet Nickel ICR 2.20e-03

Partial NA C\COB\ESP ESP Outlet Nickel ICR 2.00e-02

Partial NA C\COB\ESP ESP Outlet Nickel Test 4.31e-01

Partial No COB Regen Outlet Nickel 114 5.50e-01

NA NA C\ESP ESP Outlet Nickel Test 5.53e-01

Partial NA C\COB\ESP ESP Outlet Nickel Test 8.62e-01

Complete Yes C\COB\ESP ESP Outlet Nickel Test 1.3ge+00

Partial Yes C\COB\ESP ESP Outlet Nickel Test 1.39e+OO

Complete Yes ESP ESP Outlet Nickel 114 1.48e+00

Complete Yes WHB\ESP ESP Outlet Nickel ICR 1.4ge+OO

Partial Yes C\COB\ESP ESP Outlet Nickel Test 2.3ge+OO

Complete Yes C\WHB\ESP\ ESP Outlet Nickel ICR 3.20e+OO

COB

Complete Yes WHBWS VS Outlet Nickel 114 3.23e+OO

Complete Yes ESP ESP Outlet Nickel 114 3.55e+OO

Complete Yes C\WHB\ESP\ ESP Outlet Nickel Test 3.74e+OO

COB

Complete Yes WHB\ESP\CO COB Outlet Nickel Test 5.21e+OO

B

NA NA ESP ESP Outlet Nickel ICR 5.47e+OO

B-6
TABLE B-1. EMXSSXONS DATA FOR ceu REGENERATXON (continued)

Combustion Hydro APC System Sample Substance Data Factor

tvoe treat location source (Ib/mm bbl)

Partial Yes C\COB\ESP ESP Outlet Nickel Test 6.4Oe+00

Partial NA C\COB\ESP ESP Outlet Nickel Test 6.54e+oO

NA NA C Cyclone Outlet Nickel ICR 7.1ge+OO

NA NA ESP ESP Outlet Nickel ICR 8.03e+OO

Complete Yes WHB\C\ESP ESP Outlet Nickel ICR 1.05e+01

Partial No COB COB Outlet Nickel 114 1.34e+01

Complete Yes ESP ESP Outlet Nickel 114 1.35e+01

Partial Yes C\COB\ESP ESP Outlet Nickel Test 1.41e+01

NA NA ESP ESP Outlet Nickel Test 2.21e+01

Complete Yes NA NA Nickel SV 2.7ge+01

Partial No C\ESP\COB COB Outlet Nickel ICR 4.31e+01

Partial NA C\COB\ESP ESP Outlet Nickel Test 4.53e+01

Partial No I Recen Outlet Nickel Test 3.36e+02

Partial NA C\COB\ESP ESP Outlet Selenium ICR 2.00e-02

Complete Yes C\COB\ESP ESP Outlet Selenium Test 3.23e-02

Partial NA C\COB\ESP ESP Outlet Selenium Test 3.38e-02

Partial NA C\COB\ESP ESP Outlet Selenium Test 2.54e-01

Partial NA C\COB\ESP ESP Outlet Selenium Test 4.23e-01

NA NA C\ESP ESP Outlet Selenium Test 9.34e-01

Complete Yes WHB\ESP\CO COB Outlet Selenium Test 9.44e-01

B

Partial Yes C\COB\ESP ESP Outlet Selenium Test 2.02e+OO

Partial No I Regen Outlet Selenium Test 3.34e+OO

Partial Yes C\COB\ESP ESP Outlet Selenium Test 4.96e+OO

Partial Yes C\COB\ESP ESP Outlet Selenium Test 7.61e+OO

Partial Yes C\COB\ESP ESP Outlet Selenium Test 1.40e+01

Partial Yes C\COB\ESP ESP Outlet Chlorine Test 5.04e+OO

Complete Yes WHB\ESP\CO COB Outlet HCI Test 5.28e+02

B

Partial Yes C\COB\ESP ESP Outlet HCI Test 6.67e+02

Partial Yes C\COB\ESP ESP Outlet HCI Test 8.40e+02

Partial Yes C\COB\ESP ESP Outlet 5F Total Test 5.51e-07

Partial Yes C\COB\ESP ESP Outlet 6F 123478 Test 6.24e-07

Partial Yes C\COB\ESP ESP Outlet 6F 123678 Test 3.75e-07

Partial Yes C\COB\ESP ESP Outlet 6F234678 Test 6.51e-07

Partial Yes C\COB\ESP ESP Outlet 6F Total Test 1.07e-06

Partial Yes C\COB\ESP ESP Outlet 701234678 Test 9.45e-07

10",.+1",1 Va... :\1 C'C! 0 ""tI",t 7n Tntal To.... o Aka.l'l7

APC = air pollution control

C = cyclone

COB =carbon monoxide boiler

ESP = electrostatic precipitator

I = Incinerator

ICR = Information collection request

Ib/mm bbl =pounds per million barrels

NA =not available

VS = venturi scrubber

WHB = waste heat boiler

5F = pentachlorodibenzofuran

6F =hexachlorodibenzofuran

70 = heptachlorodibenzo-p-dioxin

B-7
TABLE B-1. EMJ:SSJ:ONS DATA FOR CCU REGENERATJ:ON (continued)

114 =section 114 request

B-8
TABLE B-2. EMJ:SSJ:ONS DATA FOR CRU REGENERATJ:ON (abbreviations

given at end of table)

Design APC Sample Type Substance Data Factor

System location Source (Ib1mm bbl)

Continuous PC Regen Outlet Uncontrolled 1 2-Dlchloroethane 114

Cyclic SCSlFlare Regen Outlet Uncontrolled Benzene 114 5.00e-03

Continuous PH HeaterOutlet Controlled Benzene ICR 1.00e-01

Cyclic SCS SCS Outlet Controlled Benzene 114 2.14e-01

Cyclic SCS/Rare Regen Outlet Uncontrolled Benzene 114 4.278+00

Cyclic PS Regen Outlet Uncontrolled Benzene 114 6.549+00

Continuous PH HeaterOutlet Controlled Benzene ICR 7.0ge+OO

Cvclic SCS/Flare FlareOutlet Controlled Hvdroaen Sulfide 114 7.10e-05

Cvclic None Reaen Outlet Uncontrolled n-Hexane 114 8.56e+02

Continuous PH HeaterOutlet Controlled Toluene ICR 2.70e-01

Continuous PH HeaterOutlet Controlled Toluene ICR 1.899+01

Continuous PH HeaterOutlet Controlled Total Xylene ICR 1.90e-01

Continuous PH HeaterOutlet Controlled Total Xvlene ICR 1.379+01

Continuous None RegenOutlet Uncontrolled VOC (Total) 114 5.859+00

Cyclic SCS SCS Outlet Controlled VOC (Total) 114 1.719+01

Cyclic SCS/Flare FlareOutlet Controlled VOC (Total) 114 7.969+01

Cyclic PS RegenOutlet Uncontrolled VOC (Total) 114 1.9ge+02

Cyclic PS RegenOutlet Uncontrolled VOC (Total) 114 6.42e+02

Semi-Regenerativ S S Outlet Controlled VOC (Total) 114 7.41e+02

e

Cyclic None . RegenOutlet Uncontrolled VOC (Total) 114 1.74e+03

Semi-Regeneratlv CI\C CycloneOutlet Controlled VOC (Total) 114 7.9ge+03

e

Semi-Regeneratlv CS CSOutlet Controlled Particulate Test 5.7ge-04

e

Cycltc SCS/Flare Regen Outlet Uncontrolled Particulate 114 5.94e-03

Cyclic SCS/Flare RegenOutlet Uncontrolled Particulate 114 3.499+00

Continuous None Regen Outlet Uncontrolled Particulate 114 5.858+00

Continuous PC Regen Outlet Uncontrolled Particulate 114 2.709+01

Continuous na HeaterOutlet Controlled Particulate Test 1.78e+03

Semi-Regenerativ S S Outlet Controlled Particulate 114 2.599+03

e

Semi-Regenerativ CI\C CycloneOutlet Controlled Particulate 114 2.489+04

e

Continuous PH HeaterOutlet Controlled Naphthalene ICR 1.00e-Q2

Continuous PH HeaterOutlet Controlled Naphthalene ICR 9.50e-Q1

Cyclic SCS SCS Outlet Controlled PAH (Total) 114 4.47e+OO

Continuous PC Regen Outlet Uncontrolled PAH (Total) 114 4.35e+02

Continuous None Regen Outlet Uncontrolled PAH (Total) 114 9.579+02

Continuous None Regen Outlet Uncontrolled PAH (Total) 114 3.7ge+03

Semi-Regenerativ CS CS Outlet Controlled Cadmium Test 9.73e-08

e

Semi-Regeneratlv CS CS Outlet Controlled Chromium Test 6.55e-07

e

Semi-Regeneratlv VSA VSAOutlet Controlled Chromium ICR 1.50e-02

e

Semi-Regenerativ VSA VSA Outlet Controlled Chromium ICR 1.50e-02

e

Semi-Regenerativ VSA VSA Outlet Controlled Chromium ICR 2.10e-02

e

B-9
TABLE B-2. EM:ISS:IONS DATA FOR CRU REGENERATZON (continued)

Design APC Sample Type Substance Data Factor

System location Source (Ib/mm bbl>

Semi-Regenerativ CS CS Outlet Controlled Lead Test 3.03e-07

e

Semi-Regeneratlv CS CS Outlet Controlled Manganese Test 7.82e-03

e

Semi-Regenerativ CS CSOutlet Controlled Mercury Test 1.90e-08

e

Semi-Regenerativ CS CSOutlet Controlled Nickel Test 3.27e-06

e

Semi-Regeneratlv VSA VSAOutiet Controlled Nickel ICR 3.50e-02

e

Seml-Regenerativ VSA VSAOutlet Controlled Nickel ICR 3.50e-02

e

Semi-Regenerativ VSA VSA Outlet Controlled Nickel ICR 4.90e-02

e

Cyclic SCS SCS Outlet Controlled Chlorine 114 2.58e-01

Continuous None Regen Outlet Uncontrolled Chlorine 114 4.409-01

Continuous None Regen Outlet Uncontrolled Chlorine SV 4.50e-01

Continuous None Regen Outlet Uncontrolled Chlorine 114 6.00e-Q1

Continuous na Heater Outlet Controlled Chlorine Test 1.41e+01

Continuous None Regen Outlet Uncontrolled Chlorine 114 1.46e+01

Semi-Regenerativ None Regen Outlet Uncontrolled Chlorine ICR 8.20e+01

e

Continuous None Regen Outlet Uncontrolled Chlorine 114 9.3Oe+01

Continuous None Regen Outlet Uncontrolled Chlorine 114 1.169+02

Continuous None Regen Outlet Uncontrolled Chlorine ICR 1.75e+02

Continuous None Regen Outlet Uncontrolled Chlorine 114 1.83e+02

Continuous PC Reaen Outlet Uncontrolled Chlorine 114 4.089+02

Cyclic SCS/Flare Regen Outlet Uncontrolled HCI 114 3.10e-02

Semi-Regenerativ CS CSOutiet Controlled HCI Test 5.ne-02

e

Cyclic PS Regen Outlet Uncontrolled HCI 114 1.00e-01

Cyclic SCS/Flare Flare Outlet Controlled HCI 114 1.50e-01

Cyclic None Regen Outlet Uncontrolled HCI 114 1.41e+OO

Cyclic None Regen Outlet Uncontrolled HCI 114 3.24e+OO

Cyclic SCS SCS Outlet Controlled HCI 114 4.00e+OO

Cyclic SCS/Flare Regen Outlet Uncontrolled HCI 114 2.51e+01

Continuous PC Regen Outlet Uncontrolled HCI 114 2.719+01

Continuous None Regen Outlet Uncontrolled HCI 114 3.40e+01

Cyclic None Regen Outlet Uncontrolled HCI 114 4.499+02

Cyclic None Regen Outlet Uncontrolled HCI 114 4.499+02

Semi-Regeneratlv None Regen Outlet Uncontrolled HCI ICR 4.529+02

e

Continuous None Regen Outlet Uncontrolled HCI SV 5.40e+02

Cyclic None Regen Outlet Uncontrolled HCI 114 5.75e+02

Continuous None Regen Outlet Uncontrolled HCI 114 6.71e+02

Continuous None Regen Outlet Uncontrolled HCI 114 7.52e+02

Continuous None Regen Outlet Uncontrolled HCI 114 7.8ge+02

Continuous None Regen Outlet Uncontrolled HCI 114 9.42e+02

Cyclic None Regen Outlet Uncontrolled HCI 114 1.129+03

Cvclic None R9QenOutlet Uncontrolled HCI 114 1.14e+03

B-IO
TABLE B-2. EM:ISS:IONS DATA FOR CRU REGENERAT:ION {continued}

Design APC Sample Type Substance Data Factor

System location Source (Ib1mm bbll

Continuous None Regen Outlet Uncontrolled HCI ICR 1.24e+03

Continuous na Heater Outlet Uncontrolled HCI Test 2.178+03

Cyclic None Regen Outlet Uncontrolled HCI 114 2.3ge+03

Continuous None Regen Outlet Uncontrolled HCI 114 3.16e+03

Continuous None Regen Outlet Uncontrolled HCI 114 3.60e+03

Continuous None Regen Outlet Uncontrolled Hel 114 3.97e+03

Cvclic None Regen Outlet Uncontrolled HCI 114 8.43e+03

Semi-Regeneratlv CS CSOutlet Controlled 4F 2378 Test 8.64e-12

e

Semi-Regenerativ CI\Flare Regen Outlet Uncontrolled 4F 2378 Test 3.84e-10

e

Semi-Regeneratlv CS CS Outlet Controlled 4FTotai Test 8.648-12

e

Semi-Regenerativ Cl\Flare CIOutlet Controlled 4FTotai Test 1.50e-09

e

Semi-Regenerativ CI\Flare Regen Outlet Uncontrolled 4FTotai Test 4.48e-09

e

Semi-Regenerativ CI\F1are Regen Outlet Uncontrolled 5012378 Test 2.239-10

e

Semi-Regenerativ CI\Flare Regen Outlet Uncontrolled 50 Total Test 5.899-10

e

Semi-Regeneratlv CS CS Outlet Controlled 5F 12378 Test 1.49e-11

e

Semi-Regeneratlv CI\Flare CIOutlet Controlled 5F 12378 Test 1.79e-10

e

Semi-Regeneratlv CI\Flare Regen Outlet Uncontrolled 5F 12378 Test 7.75e-10

e

Semi-Regenerativ CS CS Outlet Controlled 5F23478 Test 1.10e-11

e

Semi-Regenerativ CI\Flare CIOutlet Controlled 5F23478 Test 3.53e-10

e

Semi-Regenerativ CI\Flare Regen Outlet Uncontrolled 5F23478 Test 1.81e-09

e

Semi-Regenerativ CS CS Outlet Controlled 5FTotai Test 6.10e-11

e

Semi-Regenerativ CI\Flare CIOutlet Controlled 5FTotai Test 2.38e-09

e

Semi-Regeneratlv CI\F1are Regen Outlet Uncontrolled 5F Total Test 8.48e-09

e

Semi-Regenerativ CI\Flare Regen Outlet Uncontrolled 60123478 Test 1.98e-10

e

Seml-Regenerativ CS CS Outlet Controlled 60123789 Test 5.78e-12

e

Semi-Regeneratlv CS CS Outlet Controlled 60 Total Test 1.25e-11

e

Semi-Regenerativ CI\Flare CIOutlet Controlled 60 Total Test 4.60e-10

e

Seml-Regenerativ CI\Flare Regen Outlet Uncontrolled 60 Total Test 2.139-09

e

Semi-Regenerativ CS CSOutlet Controlled 6F 123478 Test 2.91e-11

e

Seml-Regenerativ CI\Flare CIOutlet Controlled 6F 123478 Test 3.96e-10

e

B-ll
TABLE B-2. EMJ:SSJ:ONS DATA FOR CRU REGENERATJ:ON (continued)

Design APC Sample Type Substance Data Factor

System location Source t1b/mm bbl)

Semi-Regenerativ CI\Flare Regen Outlet Uncontrolled 6F 123478 Test 1.75e-09

e

Semi-Regenerativ CS CS Outlet Controlled 6F 123678 Test 2.91e-11

e

Semi-Regenerativ CI\Flare CIOutlet Controlled 6F 123678 Test 5.30e-10

e

Semi-Regenerativ CI\Flare Regen Outlet Uncontrolled 6F 123678 Test 1.78e-09

e

Semi-Regenerativ CS CS Outlet Controlled 6F 234678 Test 1.13e-11

e

Semi-Regenerativ CI\Flare CIOutlet Controlled 6F 234678 Test 1.04e-09

e

Semi-Regenerativ CI\Flare Regen Outlet Uncontrolled 6F 234678 Test 2.05e-09

e

Semi-Regenerativ CS CS Outlet Controlled 6F Total Test 5.15e-11

e

Semi-Regenerativ CI\Flare CIOutlet Controlled 6F Total Test 3.93e-09

e

Semi-Regenerativ CI\Flare Regen Outlet Uncontrolled 6F Total Test 1.30e-08

e

Semi-Regenerativ CS CS Outlet Controlled 701234678 Test 9.45e-12

e

Semi-Regenerativ CI\Flare CIOutlet Controlled 701234678 Test 6.35e-10

e

Semi-Regenerativ CI\Flare Regen Outlet Uncontrolled 701234678 Test 1.16e-09

e

Semi-Regenerativ CS CS Outlet Controlled 70 Total Test 1.90e-11

e

Semi-Regenerativ CI\Aare CIOutlet Controlled 70 Total Test 1.02e-09

e

Semi-Regenerativ CI\Flare Regen Outlet Uncontrolled 70 Total Test 2.30e-09

e

Semi-Regenerativ CS CS Outlet Controlled 7F 1234678 Test 1.37e-11

e

Semi-Regenerativ CI\Flare CIOutlet Controlled 7F 1234678 Test 1.54e-09

e

Semi-Regenerativ CI\Flare Regen Outlet Uncontrolled 7F 1234678 Test 4.87e-09

e

Semi-Regenerativ CS CS Outlet Controlled 7F 1234789 Test 9.73e-12

e

Semi-Regenerativ CI\Flare CIOutlet Controlled 7F 1234789 Test 9.19e-10

e

Semi-Regenerativ CI\Flare Regen Outlet Uncontrolled 7F 1234789 Test 1.38e-09

e

Semi-Regenerativ CS CS Outlet Controlled 7FTotai Test 2.22e-11

e

Semi-Regenerativ CI\Flare CIOutiet Controlled 7F Total Test 2.87e-09

e

Seml-Regenerativ CI\Flare Regen Outlet Uncontrolled 7FTotai Test 8.10e-09

e

Semi-Regenerativ CS CS Outlet Controlled 80 Test 1.9ge-11

e

Semi-Regenerativ CI\Flare Regen Outlet Uncontrolled BD Test 4.23e-09

e

B-12
Design APC Sample Type Substance

System location

Seml-Regenerativ CI\Flare CIOuUet Controlled 80

e

Semi-Regenerativ CS CSOutlet Controlled 8F

e

Semi-Regenerativ CI\Rare CIOuUet Controlled 8F

e

Semi-Regenerativ CI\Rare Regen OuOet Uncontrolled 8F

e

Seml-Regeneratlv VSA VSAOutiet Controlled Total PCDD

e

Semi-Regeneratlv VSA VSAOutiet Controlled Total PCDD

e

Semi-Regeneratlv VSA VSA Outlet Controlled Total PCDD

e

Semi-Regenerativ VSA VSA Outlet Controlled Total PCDF

e

Semi-Regenerativ VSA VSAOutlet Controlled Total PCDF

e

Semi-Regenerativ VSA VSAOutlet Controlled Total PCOF I"",

APC = air pollution control

C = cyclone

CI =caustic injection

CS =caustic scrubber

I =incinerator

ICR =information collection request

Ib/mm bbl =pounds per million barrels

NA =not available

PC =packed column

PCDD = polychlorinated dlbenzo-p-dloxlns

PCDF = polychlorinated dlbenzofurans

PH =process heater

PS = plate and spray

SCS = spray circulating solution

ST = spray tower

VRS = vortex scrubber

VS = venturi scrubber

WHB =waste heat boiler

114 =section 114 request

40 - 80 =chlorodlbenzo-p-dloxins (tetra- through octa-)

4F - 8F = chlorodibenzofurans (tetra- through octa-)

B-13

Data Factor

Source llblmm bbn

Test 4.458-09

Test 1.86e-11

Test 7.86e-10

Test 1.67e-09

ICR aooe-os

ICR 3.10e-09

ICR 4.20e-09

ICR 2.10e-08

ICR 3.00e-08

ICR 2.20e-02
Table B-3. HAP Emission Data for SRU Plant Vent

S!Jt'U Prot!. !JIM' :J{fJJ.p

!Facility 'lIetzt 'lImt 'DtscriptUm 'Tai£gQS fR..ate 'Emissions 'Emissions 11ata

:J{fJJ.p 111 'Jf:Iun6er 'Type ~1 (tpa) (tpy) (£6/1,000 ton) SOUIU

JJtCYE/DUJ1J'E:Jf)tJJ'£ 27702

=~ cisous Incinerator 0.0012 IC'J{assume cone inppm

!FaltMJU/lY£:}tyr1YE 27702 ccsus Incinerator 0.0080 IC!1tossutlll conein ppm tfaT.U :J{fJJ.p (a£{S!l{tUs) 27702 0.0092

!f~1/1J'F:JiYJY£ 27701 1 cisus Incinerator 4.7'£-08 IC'J(ossutlll cone inppm

CO'1tf!Pt1J 27701 1 CUIUS Incinerator 4.2'£-10 IC!!(assume cone in ppm

JJt '1J'E:J/)1JYE 27701 1 ccsus Incinerator 7.(/£.10 IC!1tossutlll conein ppm

fJalt9tfM/D'E:Ji]'1J'E 27701 3 ccsus Incinerator 4.7'£-08 IC'J(ossutlll cone inppm

cryJJt?(J'1J'£ CO'1tf!Pt1J 27701 3 CL.9lUS Incinerator 4.2'£-10 IC'J(assume coneinppm

JJtC'EfDU/lYE:Ji]'1J'E 27701 3 CilIUS Incinerator 7.6'£.10 IC!!(assume cone inppm

!faltMfltL'1J'E:J/)1JYE 27701 4 CUIUS Incinerator 0.0221 IC!!(ossutlll conein ppm

CY!Jt?(J'1J'£ CO'1tf!Pt1J 27701 4 Cl,jIUS Incinerator 0.0150 IC'J(assume cone inppm

JJtC'£rr;UJ1J'£:JfY1J'£ 27701 4 CL.9lUS Incinerator 0.0027 IC'J{assume cone inppm tfaT.U :J{fJJ.p (a£{S!l{tUs) 27701 0.0399

~~c; 20501

=~1 SUL!FWl 247.5 0.003 0.07 114!JYsponse

'D/S'llL 1'1J'£ 20501 ~'Btf~ 247.5 0.50 11.07 114 ~onse

~BO YL SdL.FIDE 20501 247.5 0.80 17.71 114 sponse

FORMALDEHYDE 20501 VENT 1 SULFUR 247.5 0.011 0.24 114 Response

TOLUENE 20501 VENT 1 SULFUR 247.5 0.002 0.04 114 Response

TOTAL HAP 20501 VENT 1 SULFUR 247.5 1.32 29.14 114 Response

CARBON DISULFIDE J VENT 3 CLAUSITGCU 357.5 0.018 0.28 114 Response

CARBONYL SULFIDE J VENT 3 CLAUSfTGCU 357.5 1.43 22.0 114 Response

TOTAL HAP (all SRUs) J 1.5 22.2

CARBONYL SULFIDE 20701 Vent 1 Unspec.TGT Incinerator 132 0.15 6.14 D. Hathaway ~993

CARBONYL SULFIDE 20701 Vent 2 Unspec.TGT Incinerator 132 2.67 110.7 SourceTest· ulfur

CARBONYL SULFIDE 20701 Vent 3 Unspec.TGT Incinerator 132 2.37 98.4 Production Rate

CARBONYL SULFIDE 20701 Vent 4 Unspec.TGT Incinerator 132 0.33 13.8 from Site

CARBONYL SULFIDE 20701 Vent 5 Unspec.TGT Incinerator 132 1.35 55.9 Visit Data) TOTAL HAP (all SRUs) 20701 6.86 285

CARBONYL SULFIDE 20604 VENT 3 SULFUR PLANT Incinerator 225 3.5 85.2 114 Response

CARBONYL SULFIDE 20604 VENT 4 SULFUR PLANT Incinerator 225 3.5 85.2 114 Response

TOTAL HAP (all SRUs) 20604 7.0 170.5

CARBONYL SULFIDE G VENT 5 SCU2fTGCU 1485 13.6 50.18 114 Response

CARBON DISULFIDE F VENT 10 SRU 1/2 Tail gas Incinerator 55 0.39 38.9 114 Response

CARBONYL SULFIDE F VENT 10 SRU 1/2 Tail gas Incinerator 55 1.42 141.5 114 Response

CARBONYL SULFIDE 27903 VENT 1 CLAUS Incinerator 21.7 ICR

CARBONYL SULFIDE 28103 VENT 1 CLAUS· BEAVON 16.32 ICR

CARBON DISULFIDE 28103 VENT 1 CLAUS· BEAVON 0.20 ICR

CARBONYL SULFIDE 28103 VENT 2 CLAUS· BEAVON 6.97 ICR

CARBON DISULFIDE 28103 VENT 2 CLAUS· BEAVON 0.28 ICR

CARBONYL SULFIDE 28103 VENT 3 CLAUS· BEAVON 24.34 ICR

CARBON DISULFIDE 28103 VENT 3 CLAUS· BEAVON 0.20 ICR

TOTAL HAP (all SRUs) 28103 48.30

B-14
Table B-3. HAP Emission Data for SRU Plant Vent

S'lt'l1Protf. :HM 9£!4P

!Jadflty '}lent '}lent1}tscription 'TaifBas 1(au '£missions 'Emissions iIJata

:HM 1'1) ?{um6tr t'J'ypt M'C'1Jl (tptf) (tpy) (f611jJOO ton) Soruu

CARBONYL SULFIDE 28282 Unpec.TGT 50.0 oHathaway-all SRUvents

CARBON DISULFIDE 29403 VENT 1 CLAUS BEAVON 244 ICRas.stU1Ucone inppm CARBONYL SULFIDE 29403 VENT 1 CLAUS BEAVON 15.1 ICRas.stU1Ucone inppm CARBON DISULFIDE 29403 VENT 2 CLAUS BEAVON 312 ICRas.stU1Ucone inppm CARBONYL SULFIDE 29403 VENT 2 CLAUS BEAVON 16.3 ICRas.stU1Ucone inppm CARBON DISULFIDE 29403 VENT 3 STRETFORD Incinerator 0.21 ICRas.stU1Ucone inppm CARBONYL SULFIDE 29403 VENT 3 STRETFORD Incinerator 1.06 leR as.stU1Ucone in ppm TOTALHAP (all SRUs) 29403 589

B-15