UnitedStates EnvironmentalProtection Agency Air OfficeofAir Quality PlanningandStandards ResearchTrianglePark. NC 27711 EPA-453/R-98-003 June 1998


# PETROLEUMREFINERIES
- BACKGROUNDINFORMATIONFOR 

# PROPOSEDSTANDARDS CatalyticCracking(Fluidand Other) Units,CatalyticReformingUnits,and SulfurRecoveryUnits(Thispageisintentionallyleft blank)

# EPA-453/R-98-003



# PetroleumRefineries

-Background InformationforProposedStandards

CatalyticCracking(Fluidand Other) Units,CatalyticReformingUnits,

# and SulfurRecoveryUnits



# ·NESHAP

## EPA-453/R-98-003

PetroleumRefinery
-BackgroundInformation for ProposedStandards

CatalyticCracking(Fluid and Other)Units,Catalytic ReformingUnits,andSulfurRecoveryUnits

Emissions Standards Division



### u.s. Environmental Protection Agency Office ofAir and Radiation Office ofAir Quality Planning and Standards Research Triangle Park, North Carolina 27711
June 1998Disclaimer This report has been reviewedby the Emission Standards Division of the Office ofAir 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, VA22161.Environmental Protection Agency Background Information for Propos.ed Standards National Emission Standards for Hazardous Air Pollutants for PetroleumRefinery Process Vents Prepared by:

Bruce Jordan Director, Emission Standards Division u.S. Environmental ProtectionAgency Research Triangle Park, NC 27711 (Date)

1. The proposed standards would regulate emission ofhazardous airpollutants (HAP) emitted from PetroleumRefinery process vents. Only those process vents that are part of major sources under Section 112(d) of the CAAwouldbe regulated. The recommended standards would reduce emissions ofxxx 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 ofManagement 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 ProgramAdministrators; 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. EPALibrary (MD-35) Research Triangle Park, NC 27711CONTENTS Chapter LIST OFTABLES LIST OF FIGURES ix 

### xi
1 . 0 INTRODUCTION

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

. . . . . . . . . . . . . . . . 1-1 1.2 PetroleumRefineryVents NESHAP

.... . .. 1-1 1.3 Purpose ofThis Document

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

..... . . 2-1 2.1 PetroleumRefinery Industry Profile 2-1 2.2 PetroleumRefinery Industry Description 2-3 2.2.1 Catalytic Cracking Units 2-3 2.2.2 Catalytic Reforming Units

. . . . . . . . . 2-4 2.2.3 Sulfur Plant Units

.... . . . . 2-4 2.3 References

. . . . . . . . . . .. . ..... 2-5 3.0 PROCESSDESCRIPTIONAND 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 SulfurRecovery 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 SulfurRecovery Plant Emission Points

... ... . . . . . 3-20 3.4 References

. . . . . . . . . . . . . . . . . . . 3-22 4.0 CONTROL TECHNOLOGY AND PERFORMANCE OFCONTROLS 4-1 4.1 CCUCRVent Emission Controls

. .. . 4-1 4.1.1 Metal HAP Emission Controls for the CCUCRVent 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

viiCONTENTS (Continued)

4.2.2 HAP Emission Controls for the CRUCR Coke BurnVent


## · 

## · · · 

## · 

## · · 

## · · 

## · 4-6 4.2.3 HAP Emission Controls for the CRUCRFinal Purge Vent



## · · · · · · · 

## · · · 4-6 4.3 Sulfur PlantVent 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 FromCCURegeneration


## · 

## · · 5-2 5.3 HAP Emissions FromCru 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 CCUCRVents 6.2 Other Environmental Impacts for CRUCRVents 6.3 Other Environmental Impacts for SRUVents · . . 6-1

· 6-1

· 6-4

· . . . 6-6 7.0 MONITORING OPTIONS


## · · · 

## · · 7-1 7.1 Monitoring Options for the CCUCRVent


## · · 

## · · 7-1 7.2 Monitoring Options for the CRUCRVent



## · · 

## · · · 7-3 7.3 Monitoring Options for the SRUVent


## · 

## · · · 

## · 7-3 7.4 References


## · · 

## · · 

## · 

## · · · 

## · · 

## · · · · 7-4 8.0 COST OFCONTROLS FORMODEL PLANTS



## · 

## . · 

## · · · · · · 8-1 8.1 Costs of Control Devices for CCUCRVent


## · 

## · · 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 CRUCRVent



## · · · · 8-7 8.3 Costs of Control Devices for Sulfur PlantVent


## · · 8-9 8.4 Costs ofMonitoring, 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, 1997 . . . . . . . . . . . . . . . . . . . 2 - 2 Summary of Organic HAPData FromCCURegeneration

. . 5-5 Summary of ControlledMetal HAPEmissions and Hel Data From CCURegeneration 5-6 Summary'of HAPEmission Factors for CCURegeneration 5-6 Summary of Range of Potential hap Emission for CCU Regeneration From the Model Plants 5-7 Summary ofNationwide Emissions Estimates for CCU Regeneration 5-8 Summary ofHAPData FromCRURegeneration

. . . 5-11 Summary of HAPEmission Factors for CRU Regeneration 5-12 CRU HAPEmission Estimates for Model Plants

. . . . 5-12 Nationwide HAPEmission Estimates for CRU Regeneration 5-13 Summary ofHAPEmissions Data for SRUVents

. . . . 5-14 HAPEmission Estimates for SRUVents 5-14 Comparison of Other Environmental and Energy Impacts for Inorganic HAPEmission Control Devices for the CCUCRVent 6-3 Annual Other Environmental and Energy Impact Estimates for Model CCUCRVent Incinerators

. . . . . 6-4 Nationwide Annual Other Environmental and Energy Impacts Estimates for the CCUCRVent 6-5 Other Environmental and Energy Impacts Estimates for Model Plant CRUCRVents

. . . . . .. 6-6 Nationwide Annual Other Environmental and Energy Impacts Estimates for the CRUCRVent

. . . . . 6-6 Annual Other Environmental and Energy Impact Estimates for Model SRUVent Incinerators

. .. 6-7 Nationwide Other Environmental and Energy Impact Estimates for SRUVents

. . 6-7 Model Plant CCUCRVent Flow Rates

. . . . . . 8-1 Designvalues for ESP

. . .. .. 8-2 Model Plant CCUCRESP Control Costs-TCI

. .. .. 8-3 Model Plant CCUCRESP Control Costs-AOC

. . . . 8-3 Model Plant CCUCRESP Control Costs-TAC 8-3 DesignValues for Venturi Scrubbers

. . . . 8-4 Model Plant CCUCRVenturi Scrubber Control Costs-TCI 8-5 Model Plant CCUCRVenturi Scrubber Control Costs-AOC 8-5 Model Plant CCUCRVenturi Scrubber Control Costs-TAC 8-5 Model Plant CCUCR Incinerator Control Costs-TCI, AOC, and TAC

. Model Plant CRUCRVent Flor Rates

. . . . . .

ix8-8 8-9 8-10 8-11 LIST OF TABLES (Continued)

Model Plant CRUCRWet Scrubber/Absorber Control Costs-TCl, AOe, and TAC . . . . . . . . . . . . . . . 8-8 Model Plant SRUVent Flow Rates

. . . . . . . . . . . 8-9 Model PlantSRU**Incine~ator** Control Costs-TCl, AOC, and TAC . . . . . . . . . . . . . . . . . . . . . . 8-10 First Cost and Initial Annual Cost for Continuous EmissionMonitors on CCUs, CRUs, and SRUs

. . . . . 8-12



### xFigure LIST OFFIGURES

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 RefineryMACT discussions: process vents Clause sulfur recovery units

.. . . . . . . . . .

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



### (Thispage is intentionally leftblank)

xii

:; ; " ':'1"1.0 INTRODUCTION

1.1 BACKGROUND Title III of the 1990 Amendments to the CleanAir Act (CAA) substantially revised section 112 of the Act regarding the development ofNational Emission Standards for Hazardous Air Pollutants (NESHAP). To implement the congressional directives of Title III, the U.s. Environmental Protection Agency (EPA) has initiateda program to develop NESHAP for certain categories of stationary air emission sources that emit one ormore of the hazardous air pollutants (HAP) listed in section 112(b) of the CAA. 1.2 PETROLEUM REFINERY VENTS NESHAP On July 16, 1992, EPApublished a list of all source categories emitting HAP (57 FR 31576) and included Petroleum Refineries among the listed source categories. OnAugust 18, 1995, EPApromulgated a NESHAPfor the petroleum refinery source category primarily for organic HAPemission
sources (60 FR 43244). In the 1995 petroleumrefinery NESHAP, EPA specifically excluded three process vents from the NESHAPbecause of the unique characteristics of the inorganic emissions from each of these vents and stated that

IIthese emissionpoints are included in a separate source category under a separate schedule.II These three process vents are the subject of this rulemaking entitled IINESHAP: PetroleumRefineries - FCCUnits, Reformers, and Sulfur Plants. II The emission sources consideredunder 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 - 1reforming unit (CRU); and the process vent(s) for the sulfur recovery plant. 

### 1.3 PURPOSE OFTHIS DOCUMENT In developing NESHAP, the EPA evaluates different strategies for reducing air emissions from the source category. For selected control strategies, the EPAdevelops emission and control cost impacts to support in the development of the NESHAP. This technical support document (TSD) presents the information andmethods 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 recoveryprocesses. 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 associatedwith the control strategies are provided in Chapter 6. The options considered for monitoring the emissionpoints are discussed in Chapter 7. Chapter 8 describes the methods and procedures used to estimate the control cost impacts associatedwith the selected control andmonitoring strategies.



### 1 - 22.0 INDUSTRY DESCRIPTION

This chapterpresents a brief overview of the petroleum refinery industry in general" withparticular industry descriptions of catalytic crackingunits (CCUs), catalytic reforming unit (CRUs), and the sulfur recovery plants. 2.1 PETROLEUMREFINERY INDUSTRY PROFILE1 There are approximately 162 petroleumrefineries in 33 States nationwide (see Table 2-1). These 162 refineries process 15.4 millionbarrels 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); andTexas (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 petroleumrefineries 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 bledof crude oil and employs'less than 1,500 people corporately. There
are 94 petroleumrefineries that process less than



### 2 - 1Table 1. U.S.Refineries-StateCapacitiesasofJanuary1, 1997 a 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 NewJersey 6 674,000 282,700 118,400 0 NewMexico 3 97,600 32,331 31,800 2 NorthDakota 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 WestVirginia 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

aData obtained from Reference 2, but omits one facility in Oregon

that has no reported crude capacity(apparentlyanasphaltplant). Data also omitsTascaRefining Co. in Marcus Hook, PA (180,500bled capacity) that was idled in 1996; it is expected to restart mid

### 1997.

2 - 275,000 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 ormore, 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 capacitywas 15.6 millionbled in 1990 compared to 15.3 millionbled 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 millionbled in 1990 to 14.1 million bled in 1995. Thus, the U.S. petroleumrefining capacity utilization has increased from 87 percent in 1990 to 92 percent in 1995.4 Future trends in the petroleumrefining industry are expected to mirror the past five years. According to u.S. Department of Energy andCommerce 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 refinedpetroleumproducts is expected to grow an average of 1.5 percentperyear, which is slower than the expected growth rate of the economy.s 2.2 PETROLEUM REFINERY INDUSTRYDESCRIPTION 2.2.1 Catalytic Cracking Units6 The nationwide petroleumrefinery catalytic cracking (fluid and other) charge capacitywas 5.18 millionbled in January 1997.1 There are 105 petroleumrefineries 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 - 3CCU, 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 capacitywas 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 regenerationprocesses: semi-regenerative; cyclic; and continuous (see Section 3.2 for CRUprocess 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 petroleumrefineries 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 Units8 Production of sulfur (all forms measured as pure elemental sulfur) frompetroleumrefineries was reported at 2,940 thousandMgin 1985 and 4,200 thousandMgin 1990. There are 

### 130

## u.s. refineries that report operating some form of sulfur production units (in 1992), representing a total sulfurproduction capacity of 20,500 Mg/day. There are 52 refineries that have sulfurproduction capacities of less than 50 Mg/daYi 24 refineries have sulfur production capacities greater than 

### 300 Mg/day; and 5 refineries have sulfurproduction capacities greater than 500 Mg/day.

2 - 4Of 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 reportedwas 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 ProtectionAgency. Responses to Information Collection Request for Petroleum Refineries. PublicationNo. XXXXX. Office ofAir Quality Planning and Standards, Research Triangle Park, NC. 1992.' 4. Lidderdale, T., N. Masterson, andN. Dazzo. "U.S. Refining CapacityUtilization." Energy Information Administration, Petroleum SupplyMonthly. pp. 33 through 39. 5. u.S Environmental ProtectionAgency. EPA Office of Compliance Sector Notebook Project

- Profile of the PetroleumRefining Industry. PublicationNo. 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.:, . ':':,.:1

.;:

. " (Th,iLfS'':Ipage:is','**d.i.PJ.:t;en:tion~$JY ',!Le!£t;blCin~)**  I,,",' r I': -;3.0 PROCESS DESCRIPTIONAND EMISSION POINTS

This chapterpresents a description of theprocesses associatedwith the three refinery vents of interest: catalytic cracking unit (CCU) catalyst regenerationprocess vent (CCUvent), the catalytic reforming unit (CRU) catalyst regeneration process vent (CRU vent), and the sulfur recovery plant vent (SRUvent). For eachprocess vent, process descriptions are providedwith 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 PetroleumRefinery Enforcement Manual6 and the EPA SectorNotebook for petroleumrefining7

are also general references for the process descriptions provided in the chapter. 3.1 CATALYTICCRACKING 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 systemconsists 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 anduse 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
AuxiliaryAir andAuxiliary Fuel

VJ

tv 1411 Steam

Flue Gas

Regenerator 

## CO Boiler
EnergyRecovery Particulate Removal

Device Flue Gas ExhaustStack

t:l

1-3 

# §
CD



# "" "" co

, Air

RegeneratedCatalystTransferLine

Figure 3-1. Fluid catalytic crackingunit.commonly referred to as FCCUs (fluid catalytic cracking units), and the process descriptions that follow will focus primarily on FCCUoperation 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 FCCUand other "thermal" CCU (TCCU). The terms FCCU and Teeu will be used to refer to a specific type of ecu. 3.1.1 FCCUProcess 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 ofproducts and catalyst flows up the riser into the eeu reactorvessel. 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 entrainedwith 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 strippedwith steam to remove any hydrocarbons that mayhave deposited on the catalyst before returning the catalyst to the regenerator. 

### 3 - 3spent catalyst collected in the FCCUreactor 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 regeneratedby burning off coke that
was deposited on the catalyst in the riser andecu 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,400oF with excess oxygen and low levels « 500 ppmv) of carbonmonoxide 

### (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 ofplatinummay be added to the eeUCR to promote combustion; "De-SOx" or other SOx scavenging additives maybe added to reduce SOxemissions; 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 removedby 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 TCCUpellets
are roughly 1/8 inch (3,175**~)** long compared to a typical FCCUpowder 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 - 4top of the vertical reactor and flows in.a plug flow fashion down the reactor bedby gravitational force (refer to Figure 2). Oil feed is introducednear the top of the reactor portion of the TCCUwhere 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 andvapor products, upon reaching the bottom of the reactor, pass through a vapor disengaging grid. Vapor is disengaged from the catalyst and drawn offby a series ofvapor tubes. Purge steam is introducedbelow the vapor draw off tubes to purge any remaining oil vapor from the catalyst pellets. The purge steam is also removed from the systemvia the vapor draw off tubes along with the oil vapor products. Purged catalystpellets continue to move downward to the regenerator (or kiln) portion of the TCCU. Air is introducednear middle of the regenerator section in a controlledmanor to regulate the temperature and cokeburnoff 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 systembothnear the top of the regenerator andnear the bottomof the regenerator. Approximately 70 percent of the air feed passes upward through the regenerator and 30 percent flows downwardwith the catalyst. Flue gas is separated from the catalyst at the bottom of the regenerator is a similar fashion as oil vaporwas 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 stackvent.

3 - 5Flowdeflector--t-I. Vent toatmosphere 

# t

SurgeTank

Catalystlift**--~** Catalystfeed

TCCReactor

011feed**--+----~ I:;:::=;::~::;:::;=:;:;::::::J)-'**  Vaporizedoilproductstodistillation

Steam in

Upper flue--+-+----+-1--.1 gas vent TCCRegenerator**~--t---** Combustionair In**""r!r-rrr-.n~~r""""II'''''''+--**

.- Regenerated catalyst recirculation 

# t

Liftairline Figure 3-2. Simplified Schematic ofnon-fluid**(the~l)** catalytic crackingunit (TCCU).



### 3 - 6Below 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 systemresult 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 secondvent from the eeu system is the flue gas exhausted from the ceDeR as a result ofburning 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 ceUCRvent, 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 ecueRvent. The eCUeRvent stack flue gas is characterizedby low HAPconcentrations and large volumes of gas. The final ecueRvent stack is typically 6 to 16 feet in diameter, depending of the ceu throughput, and 100 feet high. The eCUeRvent from a TCCD are generally smaller, roughly 2 to 3 feet in diameter. Typical volumetric flow rates of flue gas in the eCDCRvent stackrange from 50,000 standard cubic feet per minute (scfm) for smaller ceus to 400,000 scfmor more for larger ceus. The total HAPconcentrations in the ceUCRvent 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 - 7nickel) and organics (primarily formaldehyde, acetaldehyde, benzene, toluene, xylenes, hexane, andphenol). Other metals that have been detected in the CCUCRvent flue gas include: antimony, cadmium, chromium, cobalt, lead, manganese, and mercury. Other organics that have been detected (or suspected to be) in the ceUCRvent flue gas include: naphthalene, polycyclic organic matter (POM), dioxins, and furans. 8 The TCCU has an additional emissionpoint 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 entrainedwith the lift air so there is a potential for the surge tankvent 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 CCUCRvent, the particulate emissions rate from the surge vessel vent
are expected to 

### be roughly equivalent andmaybe higher than the particulate emissions from the CCUCRvent. 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 (CCUCRvent plus the surge tank vent emissions) compare to the CCUCR emissions from a CCU with similar throughput. The metal HAPare 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. Thehydrotreater removes sulfur, nitrogen, vanadium, nickel and other contaminants from the crude oil feedstocks. This IIpretreatment" step prior to the

## ceu t.ypdcelLyhelps to improve

## ecu yield, prolongs catalyst life, and reduces CCU HAP emissions according to industry representatives. 9 Because most of the



### 3 - 8metal HAP emissions are in the form ofparticulate 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, andhexane) are not destroyed in the CCDCR. These volatile organic HAPmay originate as residual oil feed material on the catalysts that somehowvaporize, but do not combust prior to exiting the ceDCR. Organic HAPemissions frompartial combustion regenerators maybe 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 EPAis collecting data to determine whether a complete combustion CCU systemhas significantly different HAPemissions from a partial combustion ceu system followed by a CO boiler. Equipment leaks and fugitive emissions are not anticipated to be significant from the eCUCRflue gas treatment train because of the low concentrations of HAP in this vent stream. 3.2 CATALYTICREFORMING 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 ofnaphthenes 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 wouldpoison 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 -.9accomplishedby 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 compressedwith a portion going back to the reformer; the hydrocarbon stream is sent to' a fractionation column for final product separation. As the reactionprogresses, 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 characterizedby 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 characterizedby continuous or continual regeneration of catalyst in situby 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 characterizedby the continuous regeneration ofpart 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 regeneratedby 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. Depressuritationandhydrocarbonpurge vent Step 2. Coke burn pressure control vent Air Step 3. Regjuvinationand

### 02purgenent**Causti~** 

### MakeupWaterEffluentto Wastewater

Treatment

Figure 3-3.**~ical** 

### regenerationprocess flow diagramfor 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. Depressuritationandhydrocarbonpurge vent Step**2~** 

### Coke burnpressurecontrol vent Step 3. Regjuvination and O2

### purge vent Effluent to Wastewater

Treatment

Figure 3-4. Typical regenerationprocess flow diagramfor cyclic catalytic**refo~ers.**t:I
"Ij 8 

# §
CD

\.0 \.0 (X) RecycleGas

I • Net Gas

Reformate HighPressure Separator Heat Exchangers

LowPressure

Separator Depressurizationand

Hydrocarbonpurge



### H

2 

### H

2 CokeBurn

Pressure ControlVent

SpentCatalyst ..... LV

w



### Figure 3-5. Typical process flow diagramfor continuous**refo~ers.**the reactor(s) are isolated, and any residual hydrocarbons
are purged from the systemusing 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 combustionprocess, 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 desiredpressure within the system. The combustion process naturally produces somewater. 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 strippedby the water. The chlorination cycle may be performed either as a separate cycle after the coke burn cycle is completed or simultaneouslywhile the coke burn cycle is underway. Once the catalyst is regenerated (i.e., coke burn and chlorination cycles completed), the system is first purgedwithnitrogen to
remove any oxygen and residual chlorination agent from the system, and then purgedwithhydrogen 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 andmore frequent in occurrence than semiregenerative systems. However, both


### 3 - 14systems are characterizedby 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,2000

### 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 desiredpressure in the regeneration air line. This vent is typically vented to the atmosphere; however, a water or caustic scrubbermay 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 separatedby a series ofbaffles 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 thenmoves 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 - 15create a reducing atmosphere) of the semiregenerative or cyclic systems. 3.2.3 CRU Emission Points The CRU system is essentially a sealed systemexcept for the catalyst regeneration cycles. Although the location of the emission point might vary depending onwhether 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 emissionpoints are: (1) the initial depressurization andpurge venti (2) the cokeburn pressure control venti and (3) the final catalystpurge vent.The initial depressurization andpurge cycle removes the hydrocarbons from the catalyst prior to CRU catalyst regeneration. The vent gases from**~his** initial purgemay have high levels of organic HAP such as benzene, toluene, xylene, andhexane. 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 primaryHAP contained in the CRU coke burn vent are HCI and chlorine (CI2) , l l which are producedwhen 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 maybe used in the flue gas recirculation line to remove HCl. Although these HCI removal techniques are implementedprimarily 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 typicallymore 

### 3 - 16common 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 catalystprior 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) andresidual·HCl or C12 remaining in the system. 10 This vent is typicallyvented to the atmosphere or the refinery's fuel gas systemdepending
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 maybe significant for the chlorinatedorganic circulation system due to the high organic content of this stream. No other HAPemissionpoints have been identified for the CRU or CRU catalyst regenerationprocess. 3.3 SULFURRECOVERY PLANT All crude oils contain some sulfur compound impurities. Crude oils that contain relatively low levels of sulfur are referred to as IIsweetII 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 andhydrotreating processes of the refinery. The 

### H 2S 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 yieldhighpurity sulfur that is then sold as product. The sulfur recovery plant consists of one ormore sulfur recovery units (SRUs) operated inparallel andmay also contain one or more

3 - 17catalytic tail gas treatment units**an~/or** a thermal oxidizer (see Figure 3-6)

. 3.3.1 Claus Sulfur RecoveryUnit (SRU) Process Description Sulfur recovery (the conversion of H2S to elemental sulfur) is typically accomplishedusing the modified-Claus process. This is a multi-stage catalytic oxidation of H2S. First, one third of the H2S is burnedwith 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, andheat. Because the reaction is reversible, the reaction occurs in a series of reactors, and the vapors are cooled to condense the sulfurbetween each reactor to drive the reaction towards completion. Auxiliary burners are used to reheat the gas streamprior to the next reactor. The gas from the final condenser of the Claus unit (referred to as the IItail 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 (coupledwith amine adsorption or Stretford solution eduction); 

### (2) amine adsorption to recover and recycle any H2Spresent 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 

# *Additionalconverters/condenserstoachieveadditional

recoveryofelementalsulfur areoptionalat thispoint. 

### SulfurPit 

# §
CD J-1 '-0 '-0 co

Figure 3-6. RefinerynCT discussions: process vents Claus sulfurrecoveryunits.Except for the Wellman-Lord system, each of these systems consist of a catalytic reactor and an 

### H2 S recovery system. In either the Claus or Beavon reactor, the tail gas is heated in the presence ofhydrogen 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 recoveredH2S is recycled to the front of the Claus unit. The overhead of the amine scrubber or Stretfordunit (caustic scrubber) may be vented to the atmosphere or incinerated to convert any remaining H 2S or other reduced sulfur compounds to 802• The total sulfur recovery efficiency of a Claus/catalytic tail gas treatment train can be 99.5 percent orhigher. The Wellman-Lorduses thermal oxidation followed by scrubbing with a sodium sulfite and sodiumbisulfite solution to remove S02. The rich bisulfite solution is sent to an evaporator-recrystallizerwhere the bisulfite decomposes to S02 andwater 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 maybe a separate emission stack for each SRUtrain; alternatively, the emissions from a couple of SRUtrains may be combined, e.g., prior to thermal oxidation and release to the atmosphere. A typical SRUvent stack is approximately 4 feet in diameter and 100 feet tall. Atypical volumetric flow rate for an SRUvent stackranges from 8,000 to 40,000 scfm. The primary HAPcomponents of the final sulfur plant vent are carbonyl sulfide (COS) and carbon disulfide (CS2).13 These HAPcomponents are byproducts of the SRU and TGTU reactions; COSmay also be a product of incomplete combustion from a thermal oxidizer.
3 - 20Sulfur recovery plants also have a potential for fugitive HAPemissions from the sulfur recovery pits. After each reactor in the SRU, elemental sulfur is condensed and removed from the SRUgas and the liquid sulfur is collected and stored in bins. There are limiteddata from a one petroleumrefinery that suggest that small amounts ofHAP
are emitted from these sulfur recovery pits. 14 There is also a potential for fugitive emissions from certain types of TGTUs, specifically the Stretfordunit. The Stretfordunit 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 ofHAP
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 sulfurproduction 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, andNaSH processes. In general, these processes operate at temperatures below 200°F andyield 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 SRUare not expected to produce additional COSand CS2, but they may potentially emit any COS or CS2 that is present in the treated sour gas. As, these units represent much less than 1 percent of the total sulfur production capacity (or 

### H 2S treatment capacity in the United States), the potential HAPemissions from non-Claus SRUare expected to be minimal compared to Claus SRUHAP emissions. 3.4 REFERENCES
3 - 211. 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 ProtcetionAgency. Petroleum Refinery Enforcement Manual. PublicationNo. 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 PetroleumRefining Industry. PublicationNo. 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: FCCUnits, Reformers, and Sulfur Plants. Appendix B. Summary of Emissions Data From the EPA Database on Petroleum Refinery Process Vents. Publication No. XXXXX. Office ofAir 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 ProtcetionAgency, 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 - 224.0 CONTROL TECHNOLOGY AND PERFORMANCE OFCONTROLS

This chapter describes the control technologies applicable to reduce HAPemissions from the three petroleum refinery vents of interest (the CCUCRvent, the CRUCRvent and the sulfur recoveryplant vent). It also presents a summary of the available performance data of the control technologies applicable for these three petroleumrefinery vents. 4.1 CCUCRVENT EMISSION CONTROLS There are two distinct types of emissions fromCCUCR. 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 CCUCRvent. 4.1.1 Metal HAP Emission Controls for the CCUCRVent As the metal HAPare associatedprimarilywith the catalyst particles entrained in the CCUCR flue gas, particulate emission control devices also providemetal 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 - 1Cyclone 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 ofESPs, baghouses, andwet 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 eCUCRunits to retain most of the catalyst particles within the eeUCRunit. Secondand 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 chargedparticles migrate to a grounded collection surface where they adhere. The particles are then removed from the collection surface periodicallyby vibrating or**~rapping"** the collection surface. The dislodgedparticles are then collected in hoppers at the bottom on the ESP. ESPs typicallyhave 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 CCUCRvent gases. Wet scrubbers use a liquid, usually water, to assist in the particle collection process. There are a number of different types ofwet scrubbingprocess equiprnent,4 but venturi type wet scrubbers are among the most efficient and the most commonly used at refineries for the CCUCRvent. Venturi wet scrubbers are typically designed for
4 - 2applications requiring veryhigh 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 designedto operate at temperatures within 50 to 100 of of the gas stream's dewpoint and generally cannot operate at temperatures above 500 

### °F. 8 Therefore, somepretreatment (or heat recovery) of the CCUCR flue gas will be required prior to a baghouse control device. Additionally, baghouses cannot provide continuous, long-termemission control due to maintenance problems (e.g., cloggedor torn bags) according to air pollution control equipment representatives. 9 Selection of an air pollution control device for. TCCU is further complicatedby 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 wouldbe critically tied to the process operations, making the application of these control devices impracticable. Single pass cyclone separators may be applicable andmay yield sufficient control due to the larger size particles associatedwith the TCCU CCUCRvent. The TCCU surge tank vent is not limitedby the control device pressure drop, but again, a cyclone separatormay 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 - 3nickel and other contaminants from the crude oil feedstocks. This "pretreatment" step prior to the CCU typically helps to improve CCUyield, prolongs catalyst life, and reduces CCU HAPemissions, 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 petroleumrefineries. However, refiners that operate a hydrotreating unit andprocess a portion or all of the CCU feedstocks through the hydrotreatermay exhibit reducedmetal HAPemissions compared to a similarly operatedCCU that does not hydrotreat the CCU feedstock. 4.1.2 Organic HAPEmission Controls for the CCUCRVent Organic HAPemissions primarily originate as byproducts of coke combustion (e.g., formaldehyde, acetaldehyde, POM, dioxins and furans). However, volatile organic HAP such as benzene, toluene, xylenes, andhexane
are also reported for some CCUCRvent streams. 11 These volatile organic HAPmay 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 emissionwouldbe 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 CCUCRshave 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 CCUCRvent. As the CCUCR flue gas is already at high (combustion) temperatures, catalytic incinerationwould not be economically competitivewith traditional thermal incineration. Thus, thermal incineration or afterburning appear to be the only



### 4 - 4applicable 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 andwater 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 wouldbe required to achieve effective afterburning. Additionally, for incomplete combustionCCUCRs, the CO in the flue gas may be sufficient to fuel the secondary combustionprocess. 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 HAPemission control as an incomplete combustion CCUCR followed by a secondary combustion unit. 15 4.2 CRUCRVENTEMISSION CONTROLS As described in Section 3.2.3, there are three times during the regenerationprocess that HAPemissions can occur. These three emissionpoints are: (1) the initial depressurization andpurge vent; (2) the coke burn pressure control vent; and (3) the final catalystpurge vent. 4.2.1 HAP Emission Controls for the CRU PurgeVent The initial depressurization andpurge cycle removes the hydrocarbons from the catalyst prior to CRU catalyst regeneration. The vent gases from this initial contains organic HAPsuch as benzene, toluene, xylene, andhexane. During the initial depressurization process, these hydrocarbons maybe recoveredbyventing the gas stream to the refinery's fuel gas recovery system. As this vent gas streamhydrocarbon content becomes more dilute during the purge cycle, venting to the fuel gas systemmay become undesirable and an alternative air pollution control

4 - 5technique 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 andvapor incinerators employ heat and oxygen to oxidize (combust) organic chemicals, converting them to carbon dioxide andwater 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 CRUpurge vent. 16 Carbon adsorption may also be used to control organic HAP emissions during the CRUhydrocarbon 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 canbe 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 probablymost economical for the CRU purge vent. When the adsorbed organics cannot be recovered
orwhen non-regenerative carbon systems are used, carbon adsorption has the disadvantage of creating a solidwaste material that requires proper disposal (sometimes as a hazardous waste) .17,18,19 4.2.2 HAP Emission Controls for the CRUCRCoke BurnVent The primary HAP emittedduring the coke burn cycle is HCl. Caustic injection, caustic scrubbing, andwet 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 desiredpollutant. For vapor phase pollutants, scrubbing typically removes the pollutant by
4 - 6absorption into the liquidphase. 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 HAPEmission Controls for the CRUCRFinal Purge Vent The final purge and reduction cycle vent gases frommay contain low levels of the chloriding agent (trichloroethene
or perchloroethene) and residual HCI or Cl2" 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 airpollution techniques have beenpreviously described in this section. If the primary HAPpollutants in the final CRUCRpurge cycle
are organics, then either combustion or carbon adsorption
are most appropriate. IfHCI or Cl2 are the primary HAP from this vent at a given facility, thenwet scrubbing is probably the most appropriate control device. The suitability of carbon adsorption may depend on the concentration ofHCI in the vent streambecause carbonhas a low adsorption capacity for HCI and there is a potential for HCI condensationwithin the adsorption unit. 22 Application of thermal control devices may also be limiteddepending on the concentration of chlorine or chloride containing chemicals in the vent stream. Combustion of chlorinated organics produces HCI andprovides the potential for the formation of chlorinateddioxins and furans. 2 3 4.3 SULFURPLANT VENT EMISSION CONTROLS The primary HAPcomponents of the final sulfur plant vent are carbonyl sulfide (COS) and carbon disulfide (CS2) . These HAPcomponents are by-products of the reactions in the SRUreactors; COSmay also be a product of incomplete combustion from a thermal oxidizer. There are two generally applicable emission control techniques for the SRUvent.



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

. 4.3.1 TGTUas a HAPEmission Control for the SRUVent 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 TGTUrecovers 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 TGTUis directly correlated to its HAP emission reduction or whether a given TGTU provides greater HAPemission 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., Stretfordunits 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 HAPemissions 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 SRUvents regardless of the presence or absence of a TGTU (although they may not be appropriate following an oxidative TGTUprocess such as a Wellman-LordTGTU). The destruction or oxidation efficiency of reduced sulfur compounds, including COS andCS2, 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, 5thEdition. McGraw-Hill BookCompany, New York, New York. 1973. p. 20-82. 2. ???

4 - 8

### 3. 

## u.s Environmental ProtectionAgency. HandbookControl Technologies for Hazardous Air Pollutants. Publication No. EPA/625/6-91/014. Office ofResearch andDevelopment, 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, andD. Austin. "Scrubbing Toxic Inorganics." Chemical Engineering. September 1990. pp. 116 through 121. 8. Reference 3. pp. 4-64 through 4-65. 9. ICACMeetingMinut'es Memorandum. 10. Site Visit Report. 11. PMACT Document

- Emission Data. Appendix B. 12. Reference 11 (orAPI Database). 13. McInnes, R., S. Jelinek, andV. 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 ProtectionAgency. Internal InstructionManual for ESDRegulation Development

- CarbonAdsorption Control for Organic Emissions. Office ofAir Quality Planning and Standards, Research Traingle Park, NC. March 1993. 18. Reference 13. 19. u.S Environmental ProtectionAgency. OAQPS Control Cost Manual. PublicationNo. EPA/450/3-90-006. Office ofAir 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 - 923. 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

- 105.0 MODEL PLANTS AND EMISSION ESTIMATES

This chapterpresents the derivation of controlledand uncontrolled emission factors for hazardous airpollutants (HAP) and applies them to three different sizes ofmodel 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 anduncontrolled emissions from the entire industry for the three processes of interest: catalytic cracking unit (CCU) regeneration, catalytic reformingunit (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 ofpresenting 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 - 1Data for HAP emissions were compiledby the EPAusing information provided through a variety of sources and are documented in References 1 and 2. A summary of the emissions data is given inAppendix B. The emissions data
were reported in responses to information collection requests and follow-up surveys by the American Petroleum Institute (API) the National PetroleumRefiners Association (NPRA) , as well as collectedduring site visits conductedby EPA. The approach used to estimate HAPemissions 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 includedwith other informationbased on actual measuredvalues. 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, evenwhen 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 verifiedby any other information, that value was flagged andwas not used in the estimates of total HAP emissions. 2. When the extremes of the range for a givenpollutant differ by an order ofmagnitude ormore 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 carbonmonoxide (CO) boiler and control ofparticulate 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 - 2not completely destroyed. For example, formaldehyde, acetaldehyde, andpolycyclic organic matter (POM) may actually be formed in the COboiler 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 COboiler) are used to derive emission factors for controlled organic HAP emissions. Uncontrolled organic HAPemissions are estimatedbased 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 COboiler or other combustion device. For complete combustionunits, emissions of organic HAPare estimated from the "controlled" emission factors. 4. Estimates of

### uncontrolledemissions ofHAP 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 couldbe made in emission factors for CCUs using partial combustion and those using complete combustion. A significant difference wouldbe expected in the 

### uncontrolled emissions from the two different types of combustionprocesses; however, the difference in organic compound emissions may be much less after combustion in a COboiler. 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 combustionprocesses maynot be important in determining nationwide emissions. 6. The data were inconclusive as to whether 

### hydrotreating had any effect on the emission factors for HAPmetals; 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 inAppendix B is given in Table 5-1 and the range for controlledmetal HAP and HCI is given in Table 5-2. Both are expressed in terms ofpounds of emissions per million barrels of CCU throughput (lb/rnmbbl)

. Nickel was the most commonly reportedmetal HAP andwas also



### 5 - 3the 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 withparticulate matter controls probably have metal 

### HAP emissions that total less than a ton per year. Nationwide emission estimates for CCU regenerationwere derivedbased on CCU capacity and control devices inplace. Basedon data fromAPI3

, 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 didnot have control devices inplace 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., uncontrolledunits 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 - 4TABLE 5-1. SUMMARY OF ORGAN:IC HAP DATA FROM

## ceo REGENERATION (fromReferences 1 and 2) Compound



## -- 1,3-Butadiene Acetaldehyde Benzene Cyanide Formaldehyde HCN
Phenol POM) Toluene U1 Xylene
U1 PCDF4 HCDFs TotalVOCs6 Totals Emission factor range (lb/mmbbl)1 Number2 Comments Lower Upper 0.0008 0.05 2 all afterCOboiler

1.7 48 6 afterCOboiler 0.73 12 5 afterCOboiler

28 36 2 all afterCOboiler 2.7 950 7 afterCOboiler, excludes twoveryhighvalues 14 194 5 withandwithoutCOboiler, excludes onehighand t:l one lowvalue 0.74 41 5 withandwithoutCOboiler t'Ij J-3 0.15 3 2-5 most afterCOboilerandESP 0.26 2.5 2 all afterCOboiler; excludes oneveryhighvalue C P 3.2 3.2 1 afterCOboiler CD 5.5e-07 5.5e-07 1 afterCOboilerandESP \.0 \.0 1.le-06 1.le-06 1 afterCOboilerandESP co 78 1,240 9 afterCOboilerorcomplete combustionCCUCR Sl 1,290

1 2 ) 4 5 6 lb/mmbbl =pounds permillionbarrels. Number of facilities reporting detectable quantities ofthe compound. POM =polycyclic organicmatterdeterminedfromthe sumofindividual compounds inAppendixB. Totalpentachlorodibenzofuran. Totalhexacholordibenzofuran. Totalvolatile organic compounds (as reported inRef. 2; not includedinHAP totals).TABLE 5-2. SUMMARY OFCONTROLLEDMETAL HAP EM:ISS:IONS AND HCl DATA FROM CCU REGENERATXON (from References 1 and 2) Compound Emission factor range NumberS (lb/mmbbl)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/mmbbl

# =pounds per million barrels. b Number of facilities reporting detectable quantities.

TABLE 5-3. SUMMARY OFHAP 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 uncontrolledpartial combustion units. b Assumes controlled emissions represent 95 percent removal.



### 5 - 6TABLE 5-4. SUMMARY OFRANGE OF**POTENT~AL** HAP**EM~SSXONS** FOR CCU**REGENERAT~ON** FROMTHE 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 combustionunits that do not vent to a CO boiler or other combustion device. The vast majority of the largerunits use a PM control. Consequently, these estimates are probably most relevant for CCUs in the size range ofModel Plants 1 and 2.

5 - 7TABLE 5-5. SUMMARY OFNATXONWXDE 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 HAPemissions from CRU regenerationwere compiledby 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 bothbefore 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 (CI2) andhydrogen chloride (HCI) from uncontrolledCRU. Additionally, nearly all of the Cl2 andHCI 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 - 8Most of the data for benzene, toluene, andxylene were frommeasurements after combustion in a process.heater, and information suppliedby the industry indicated that organic emissions are typically controlledby venting to a combustion device. A range of 23 to 28 lb permillion barrels was developed to represent emissions of organic HAP from CRU regeneration following combustion. No "uncontrolled" emission factor was developed for organics from CRUcatalyst regeneration. There are two sets of data regarding the emissions of HAP metals during CRU regeneration. Although these two sets of datayieldedmetal HAPemission factors that variedby 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 CRUyields 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. Datawere available for chlorine and HCI bothbefore and after control, althoughmost of the data represented uncontrolled emissions. Comparing the emissions range for controlledversus uncontrolled'emissions, it appears that a control efficiency of approximately 99 percent maybe 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/millionbarrels
was used to estimate uncontrolled emissions and the emission factors for controlledunits were then calculatedusing 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 - 9emissions 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 HAPfrom uncontrolledCRU regeneration is Hel, whichwas reportedbynumerous 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 controlledby single-stage (assumed 92 percent efficient) scrubbers and 4 percent is controlledbymultiple-stage (assumed 97**~ercent** efficient) scrubbers. Cyclic and continuous reformers combinedprocessed 2.02-million barrels per day of feedstock and 38 percent of that throughput is controlledbymultiple-stage scrubbers, with only 6 percent controlledby single-stage scrubbers. The nationwide estimates ofbaseline 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 equippedwith single-stage scrubbers to remove HCl at an efficiency of 92 percent, and all continuous and cyclic CRU regeneration vents are equippedwithmultiple-stage scrubbers to remove HCI at an efficiency of 97 percent.



### 5 - 10TABLE 5-6. SUMMARY OF HAPDATA FROM CROREGENERAT:ION (fromReferences 1 and 2) Compound Emission factor Numberb Comments range (lb/mmbbl)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 PAR c 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/mmbbl

## =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 burnoffperyear.

5 - 11TABLE 5-7. SUMMARY OFHAP EMXSSXONFACTORS FOR CRU REGENERATION


### HAP and type of Emission factor range (lb/mmbbl) 1 

### control

Total organics8 

### Clb 

### HAP-uncontrolled Cl HAP-controlled Lower 23 

### 34 Upper 28 8,870 Midrange 25 4,450 130-360c

a 

### Basedonventing to a combustion device. b 

### Includes Hel and chlorine.

c 

### Controlled emission factor range calculatedbasedon uncontrolled emission factor assuming a 92 to 97 percent removal efficiency.

TABLE 5-8. CRU HAP EMISSXONESTXMATES FORMODEL 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 - 12TABLE 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 Cl2 are based on 1,306,000 bbl/day of capacity with single stage scrubbers, 814,000 bbl/day of capacitywithmultiple stage scrubbers and 1,529,000 bbl/day of capacity without scrubbers.

b Controlled estimates assume 1,577,000 bbl/day of capacity is equippedwith single stage scrubbers and 2,072,000 bbl/day of capacity is equippedwithmultiple stage scrubbers.

5.4 HAP EMISSIONS FROM SULFUR RECOVERY UNITS (SRUs) The major HAP from sulfur recoveryunits are carbon disulfide (CS2) and carbonyl sulfide (COS). The data for these compounds are summarized in Table 5-10 andwere obtainedprimarily 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, whichyields 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 providedbyNPRA. 6 The SRUdatabase contains capacity information on 161 units nationwide with a total sulfur
5 - 13pruduction capacity of 18,880 ltpd. The database contains process type and control information for 140 SRUand 120 of these units were identified as having an incinerator (or
were subject to the NSPS for SRUs). The capacity of these controlledunits was estimated as 15,470 ltpd, and the capacity of units without incinerators was estimated as 3,410 ltpd. These capacity estimates were usedwith 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 CS2)
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 controlledunits and 3,410 ltpd of sulfurproduced in uncontrolledunits.
5.5 REFERENCES 1. Letter from DavidHansell, EER, to Robert Lucas, U.S.EPA, transmitting the API CCU and CRU Data Base Summary (Draft). December 20, 1996.
5 - 142. Letter from DavidHansell, EER, to Robert Lucas, U.S.EPA, transmitting the DetailedAPI CCU andCRU Data Base (2nd Draft). January 23, 1997. 3. Database spreadsheet providedby DavidHansell, EER, to Robert Lucas, U.S.EPA, updating the API database, April 1997. 4. Radian Corporation. Results ofDioxin Testing on the Catalytic Reformer Unit #1 Exhaust; Texaco Refinery; Bakersfield, California. Final Report. August 8, 1991. 

### 5. 

## u.s Environmental ProtectionAgency. 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. PresumptiveMACT for PetroleumRefinery Process Vents: FCCUnits, Reformers, and Sulfur Recovery Plants. Appendix BSummary of Emissions Data. Office ofAir Quality Planning and Standards, Research Triangle Park, NC. 1997. 8. Letter from Norbert Dee, NPRA, to Robert Lucas, U.S.EPA, transmitting SRUDatabase. June 12, 1997.

5 - 15,1

". I

-. r " I' r.

(Thi's**pageintention~lly** leftblank)6.0 OTHER ENVIRONMENTALAND ENERGY IMPACTS ESTIMATES

This chapterpresents estimates the environmental impacts, other than HAP emission reduction, and the energy impacts associatedwith the control technologies applicable for the three petroleumrefineryprocess vents. Many of the other environmental and energy impact estimates are basedon control device design algorithms from EPA's Control Cost Manual.! The control equipment designparameters are, therefore, summarized in Chapter 8 of this document and only the applicable environmental and energy impacts are provided in this chapter. Formore details on the control device design parameters, the reader is referred to Chapter 8. 6.1 OTHER ENVIRONMENTAL IMPACTS FORCCUCRVENTS The primary impacts from the operation ofESPs to control metal HAPemissions from the CCUCRvent are the added energy requirements of the ESP and the exhaust fan. These energy requirements were estimatedbased on the control device designs for model CCUCRunits as described in Chapter 8. The ESP will also collect particle fines from the CCU vent stream that will require disposal as a nonhazardous solidwaste. 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 CCUCRvent. First, the wet scrubber also creates a wastewater streamwhich contains the CCU fines. It is assumed that the CCU fines are first settled (removed) from the wastewater streamand that the wastewater stream then requires additional treatment and



### 6 - 1disposal. The costing algorithm assumes·that the total weight of the settled solids is 2 times the particle loading to the wet scrubber. The amount ofwater 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 CCDCRunits. Due to the relatively high CO content of incomplete combustion CCUCR exhaust gases, energymay actually be recoveredusing a combustion device on this vent stream. Additionally, refineries may be expected to have additional fuel gas that couldbe used to stabilize the incinerator flame. However, it is assumed that energy is not**be~ng** recovered from the CCUCRvent 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 incineratoruses both electricity (for the exhaust fan) andnatural gas. Table 6-2 summarizes the other environmental and energy



### 6 - 20'\

w 

### TABLE 6-1. COMPARISONOFOTHERENVIRONMENTALAND ENERGY IMPACTS FORINORGANIC HAPEMISSIONCONTROLDEVICES FORTHE CCUCRVENT.

small CCU MediumCCU 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 

### ElectricityUse 470 630 1/730 2/200 4/400 6/290 (1/000 kW-hr) SolidWaste (tons) 180 240 680 860 1/710 2/450 Venturi Scrubber

, 

### ElectricityUse 390 520 1/420 1/810 3/620 5/170 (1/000 kW-hr) SolidWaste (tons) 370 490 1/350 1/720 3/430 4/910 Water Consumption 130 170 470 600 1/200 1/720 (1E+06 gallons) SOxEmissions1 

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

lBrackets aroundother emission impact estimates indicate emissionreductions. t:l
t'1j t-3 

# §
CD

\D \D coTABLE6-2. ANNUAL OTHER ENVIRONMENTAL AND ENERGY IMPACT ESTIMATES FORMODEL CCUCRVENT INCINERATORS.



### Small Mediwn Large Annual :Impact 

### CCtJ CCU CCU ElectricityUse 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 CCUCRvent model units. Nationwide estimates of other environmental and energy impacts were developedusing the throughput ofunits 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 HAPemission 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 OTHERENVIRONMENTAL IMPACTS FORCRUCRVENTS The types of other environmental and energy impacts associatedwithwet scrubbing to remove HCI from the CRUCR vent stream include electricityuse for fans andpumps and theproduction of a wastewater stream that requires treatment and disposal. These impacts are directly estimated from the control cost algorithms for the model CRUCRunits as described in Chapter 8. The other environmental and energy impacts estimates for the CRUvent model units are summarized in Table 6-4; the nationwide
6 - 4other environmental and energy impacts estimates for the CRUCRunits are provided in Table 6-5.

TABLE6-3. NATIONWIDEANNUAL OTHERENVIRONMENTALANDENERGY IMPACTS ESTIMATES FOR THECCUCRVENT1

NationwideAnnual ESPI venturi Scrubberl Impact Incinerator**Incin~rator** Electricity Use 100 87 (lE+06 kW-hr) SolidWaste (tons) 41,200 82,500 Wastewater Production 0 28,900 (lE+06 gallons) SOxEmissions(tons) 0 (67,200)2 Natural Gas Consumption 31 31

(lE+06 cubic feet)

1 Basedon adding an inorganic HAPcontrol device (either an ESP or a venturi scrubber) for 1,400,000 bbl/day of CCU capacity and adding an organic HAPcontrol device (incinerator) for 47,000 bbl/day capacity. 2 Brackets around emission impact indicate an emission reduction.



### 6 - 5TABLE6-4. OTHERENVIRONMENTALAND ENERGY IMPACTS ESTIMATES FORMODEL PLANT CRUCRVENTS
CRU Annual Annual No. CRUCRType Throughput Electricity Wastewater Range Use Production (1,000 bpd) (kW-hr) (1,000 gal) 1 Semi-Regen. 

## oto <15 349 39 2 Semi-Regen. 15 to 30 621 70 3 Semi-Regen. >30 1,160 130 4 Cyclic 

## oto <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

TABLE6-5. NATIONWIDEANNUALOTHERENVIRONMENTALANDENERGY IMPACTS ESTIMATES FOR THECRUCRVENTi
Annual Annual CRUCRType 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 CRUCRusing 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 associatedwith the SRUvent emission controls include both electricity and natural gas consumption as well as additional SOxemissions due to the conversion ofreduced sulfur compounds to SOx.


### 6 - 6The energy impacts are directly estimated from the control cost design algorithms for the model SRUincinerators 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 producedpermole 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 SRUvents.

TABLE6-6. ANNUAL OTHERENVIRONMENTALAND ENERGY IMPACT ESTIMATES FORMODEL SRU VENTINCINERATORS.


### 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

TABLE6-7. NATIONWIDE OTHER ENVIRONMENTALAND ENERGY IMPACT ESTIMATES FOR SRUVENTS1



### 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".

.Jjl

### aiilfF

""j**("~'.~~" ~:~'"**  ,.",.'.**.'-.1,~**

### 7.0 MONITORING OPTIONS
This chapterpresents a briefreview ofoptions available formonitoringHAP emissionatpetroleum refineries for eachprocess vent (CCUCR, CRUCR, SRUvents). Ingeneral, themonitoring options were establishedusing the following priorities. The topprioritywas givento the
use ofcontinuous emissionmonitors (CEMs) that directly
measure HAP emissions. Secondprioritywas given the continuous emissionmonitors thatmeasure a surrogate ofHAP emissions (such as particulatematter formetal HAP). Third prioritywas given to continuous monitoring ofprocess parameters that are indicative ofprocess emissions or the effectiveness of the emission control device. 7.1 MONITORING OPTIONS FORTHE CCUCRVENT There are two separatemonitoring options for theCCUCR ventbasedon the two classes ofHAP/control devices. For organic HAP, continuous emissionmonitoring for specific organic HAPwas not considereda proven (commercially available andreliable) monitoring optionat this time, and
was considered inferior to othercontinuous monitoring options due to the time delaybetween sample collectionand the availability of final results. Continuous monitoring of
an indicator of organic HAPwas therefore evaluated. Two potential indicators oforganic HAPwere considered. These
were: 1) continuous monitor oftotal hydrocarbon (THC) or total organic carbon (TOC) using a flame ionizationdetector (FID) or a photo ionizationdetector CEMj 

### and2) continuous monitoring ofcarbonmonoxide (CO) using a carbonmonoxide CEM. Bothof thesemonitoring devices appear feasible for

7 - 1the CCUCRvent. Several refineries currently employ continuous

## Toe or CO monitors; however, only CO CEMs are employed specifically on the CCUCRvent (to show compliance with the petroleum refinery NSPS - 40 CFR 60, Subpart J).l As the available emission data show an equally strong correlationbetween 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 CCUCRunits, 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 CCUCRunits, 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 eithermetal HAP or an indicator ofmetal HAP such as particulate matter (PM)
was not consideredproven (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 ofvoltage and secondary current were selected as a monitoring option to indicate proper control device performance and operation. For venturi wet scrubbers, continuous parametric.monitoring ofpressure drop, air flow rate, andwater flow rate were selected as a monitoring option to indicate proper wet scrubber performance and operation. 7.2 MONITORING OPTIONS FOR THECRUCRVENT For the depressurization/purge and the rejuvenation/ final purge CRUCRvents, the vent gases are either vented to



### 7 - 2the 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 onlymonitoring option considered. The monitoring options evaluated for a dedicated thermal combustion device for the CRUCRvents 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 orprior existence ofhydrogen chloride in the vent stream), the useful life of a CEMprobe is uncertain and expected to be short. That is, both the organic HAPCEM and the THC/TOC CEMwere consideredunproven technologies for the CRUCRvent streams. Consequently, continuous parametric monitoring of temperature was selected as the onlymonitoring option for the CRUCRvent streams that are exhausted to a dedicated thermal combustion unit. For the CRUCR coke burnvent, 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 ofproper control device operation. 7.3 MONITORINGOPTIONS FOR THE SRU VENT Carbonyl sulfide and carbon disulfide are the primary HAPemitted from the SRUvent. ACEM specific to just these two HAPis 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 SRUvent 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 - 3since reduced sulfur compounds consist only of the two specified sulfur HAP compounds plus hydrogen sulfide. Only one parametric monitoring option was identified for SRUvents and that monitoring option is applicable only to SRUthat empl.oy an incinerator. temperature and excess oxygen**we~e** selected as the indicators ofproper 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, SubpartA. General Provisions. u.S. Government Printing Office. Washington ,D.C. July 1, 1992. 3. Reference 1.



### 7 - 48.0 COST OFCONTROLS FORMODEL PLANTS

This chapterpresents 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 eachmodel 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 OFCONTROL DEVICES FORCCUCRVENT In this section, control costs are developed for selected control devices applicable for reducing HAP emissions from the CCUCRvent. The control devices selected for cost analysis for the CCUCRvent include: ESPs, venturi wet scrubbers, and CO boilers/incinerators. Acorrelation of the CCUCR flow rate versus CCU throughput was derived based on the available data to estimatemodel plant CCUCR vent flow rates. 1 The predictedmodel plant CCUCR flow rates are summarized in Table 8-1. The control device design and cost analyses were thenperformedbased on these model CCUCRvent flow rates. TABLE 8-1. MODEL PLANT CCUCRVENT FLOW RATES CCU capacity Vent Flow Rate Vent Flow Rate No. Size wino CO Boiler w/CO Boiler (bbl/day) O(scfml1 

### o(scfml1 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 - 1The 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 meanmass 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. Itwas assumed that the dust wouldnot have severe back
corona effects (i.e., a resistivity of less than 2 x 

### lOll ohm-cmwas assumed). The design parameters used to develop costs for ESPs are summarized in Table 8-2.

TABLE 8-2. DESIGN VALUES FORESP Parameter Value ESPType Plate&wire InletPM(grains/cu.ft) 0.20 DesignoutletPM(grains/cu.ft) 0.02 Requireddesignefficiency(E) 0.90 Penetration(p

## = 1-E) 0.10 Temperature(OK) 478 Resistivity(ohm-em) 2.0E+09 Inletmassmeandiameter,MMD(pm) 4 Sneakage(8n) 0.07 RappingRe-entrainment(RR) 0.124 MMDformostpenetratingsize(pm} 2 MMDforrappingpuffsize(pm) 3 Designflowrate,Q(acfm) Q(scfm)xT(OK)/289

Based on the ESP design parameters in Table 8-2, the projected specific collection area is 717 ft2/kacfm. The


### 8 - 2total 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 providedTable 8-3.

TABLE 8-3a. MODEL PLANT CCUCRESP 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
TABLE8-3b. MODEL PLANT CCUCRESP 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
TABLE8-3c. MODEL PLANT CCUCRESP 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 ed on standard conditions at 60°F.

8.1.2 Cost for Venturi Wet Scrubbers

8 - 3The 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 designparameters 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 providedTable 8-5.

TABLE 8-4. DESIGNVALUES FOR VENTURI SCRUBBERS
Parameter Value InletPM(grainslcu.ft) 0.20 DesignoutletPM(grainslcu.ft) 0.02 Requireddesignefficiency(E) 0.90 Pressuredropatdesignefficiency,inH 2O 10 Temperature(oF) 400 Moisturecontent(vol%) 5 Inletmassmeandiameter,MMD(pm) 4 Inletmassmeandiameter,MMD(pm) 4 Designflowrate,Q(acfm) Q(scfm)xT(OR)/520

TABLE 8-5a. MODEL PLANT CCUCRVENTURI SCRUBBER CONTROL COSTS1

- TCI

8 - 4CCU 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]

TABLE8-5b. MODEL PLANT CCUCRVENTURISCRUBBER 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 CCUCRVENTURI SCRUBBER CONTROL COSTSl

- TAC CCU TAC for CCUw/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 ed on standard conditions at 

### GooF.

8 - 58.1.3 Costs for CO Boilers/Incineration The control costs for incinerators were estimatedusing 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,200oF with 2 percent CO content 

### (by volume). To minimize fuel requirements, the feed air to the incinerator is preheatedby the incinerator exhaust (a 35 percent recuperative incinerator is more than sufficient); the total air**re~irements** were determined from the systemenergy

. 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 CCUCRvent are summarized in Table 8-6. Cost function equations were developed for model plant incinerators for the CCUCRvent based on linear regression analysis of the cost data summarized in Table 8-6 and exhaust gas flow rates (Qin 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 OFCONTROL DEVICES FORCRUCRVENT



### 8 - 6In this section, control costs are developed for selected control devices applicable for reducing HAP emissions from the CRUCRvent. The control devices selected for cost analysis for the CRUCRvent include wet scrubbers and caustic injection. [Currently assumed that all purge vents to flare or refinery fuel gas systemare already inplace.] As the magnitude and duration of the CRUCRvent flows are dependent on the type of CRUCR (semi-regenerative, cyclic or continuous) as well as on the throughput of the CRU, nine model CRUCRvents were developedbased on the type of CRUCR andCRU throughput ranges. The flow rates and durations of the model plant were selectedbased on an analysis of information in the EPA data base. 5 Table 8-7 summarizes the key parameters of the CRUCRmodel vents.

TABLE 8-7. MODEL PLANT CRUCRVENTFLOWRATES CRU CokeBurn Annual Coke Burn No. CRUCRType 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 - 7The control device design and cost analyses were then performedbased on these model CRUCRvent flow rates and durations. For the cyclic and continuous CRUCR, the control costs were developedusing 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 derivedusing 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 CRUCRunits are presented in Table 8-8. These control cost factors were applied directly to a given CRUCRbased on the CRU throughput. That is, no regression of the cost factors were performed to correlate CRUCR control costs withCRU throughput within a given CRU throughput range.

TABLE 8-8. MODEL PLANT CRUCRWET 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 ornearest $1,000.

8 - 88.3 COSTS OFCONTROL DEVICES FOR SULFURPLANTVENT This sectionpresents the control costs for incinerators**u~ed** to reduce HAP emissions from the SRUvent. A correlation of the SRUtail gas flow rate versus sulfur production rate was derivedbasedon the data available in the EPA database. The EPAdatabase was also used to characterize the SRUtail gas. 7 The predictedmodel 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 CompoundConcentration

## =4,000 ppmv Oxygen Concentration

# =0 ppmv.

TABLE8-9. MODEL PLANT SRUVENT FLOWRATES 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 SRUincinerators were estimated using the costingprocedures 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 SRUtail gas are preheatedby the incinerator exhaust; a recuperative incineratorwith 70 percent energy recovery was employed. The total air requirements were determined from the system



### 8 - 9energy 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 SRUvent 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 CCUCRvent 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 sectionpresents the costs associatedwith control device monitoring, reporting andrecordkeeping 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 alternativemeans of compliance. CEMs for the units may measure offgas characteristics (constituent concentration or temperature)
or equipment operating parameters (voltage, current,

8 - 10pressure drop, or flow rates}. Althoughpurchase 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. Inparticular, relative accuracy test audits required for extractive sampling contribute significantly to annual costs. All costing was done using EPA's EMTICprogram, with costs escalated to late 1996.9 Elements of the EMTICprogram for first costs include: planning, selection of equipment, support facilities, purchase of the CEM, installation and checking, performance test, andpreparation of a QA/QCplan. 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), recordkeeping and reporting, and annual review andupdate. Where process monitoring instruments such as temperature, pressure, voltage, and current instruments are used, they are assumed to be part of the control system andhave their purchase costs allocated to the process rather than to the CEM system. However, associated recordkeeping and reporting, annual review and update, and some operation andmaintenance costs are assigned to CEM system costs. The costs in Table 1 have large error bands, but should be useful for comparing gas CEMsvs parametermonitoring. While monitor costs are generally suppliedby EMTIC or a vendor quote, the multimetals CEM cost is an estimate.



### 8 - 11Table 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 (byM26A) 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 emissionmonitor 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 ProtectionAgency. Refinery process vent data base

... 2. 

## u.s. Environmental ProtectionAgency. OAQPS Control Cost Manual. PublicationNo. EPA/450/3-90-006. Office of Air Quality Planning and Standards, Research Triangle Park, NC. January 1990. 3. 

## u.s. Environmental Protection Agency. Handbook

### Control Technologies for Hazardous Air Pollutants. Publication No. EPA/625/6-91/014. Office of Research andDevelopment, 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 - 13DRAFT

- June 1998

APPENDIX A KEY DATES IN DEVELOPMENT OFBID

TABLEA-l. Date KEY DATES IN THEDEVELOPMENT OF THEBID 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 EPApublished 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 andNew Jersey The EPApublishedNational Emission Standards 'for Hazardous Air Pollutants (NESHAP: PetroleumRefineries; Final Rule (60 FR 43244). This rule, termed PetroleumRefineryMACT 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 petroleumrefineries in Louisiana. EPAheldkick-off PresumptiveMACT meeting with regulatory agency representatives. EPAheld kick-off PresumptiveMACT meeting with representatives of industrial stakeholders. EPAmet with representatives of emission control device manufacturers. EPA finalized the Preliminary Presumptive MACT for PetroleumRefinery Process Vents: FCCUnits, Reformers, and Sulfur Plants.

A-1DRAFT

- June 1998
TABLE A-1. KEY DATES (Continued) Date Event July 29, 1997

September 12, 1997 September 15, 1997 through September 17, 1997 EPAheldmeeting"with small business petroleumrefineries to communicate EPA's policies regarding Small Business Regulatory Enforcement Fairness Act (SBREFA) . EPA conducted an information gathering site visit to a small business petroleumrefinery in Indiana. EPA conducted information gathering site visits to four small petroleum refineries inWyoming andUtah that have non-conventional units (non-fluid CCU and non-Claus SRU).

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

This appendix contains the HAP emissions dataused 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 fromAPI and included the results of their survey of the industry.l The data for sulfur recovery units inTable B-3
were from responses to section 114 questionnaires compiledby the EPA.2 These data are also summarized in the document developed for the presumptive MACT process. 3

REFERENCES 1. Letter from DavidHansell, EER, to Robert Lucas, U.S.EPA, transmitting the DetailedAPI CCU andCRUData Base; 2nd Draft. January 23, 1997 2. u.s Environmental ProtectionAgency. Responses to Information Collection Request for PetroleumRefineries. Office of Air Quality Planning and Standards, Research Triangle Park, NC. 1992. 3. u.S Environmental ProtectionAgency. PresumptiveMACT for PetroleumRefinery Process Vents: FCCunits, Reformers, and Sulfur Recovery Plants. Appendix B-Surnmary ofEmissions Data. Office ofAir Quality Planning and Standards, ResearchTriangle Park, NC. 1997.

B-1TABLE B-1.**EM~SS~ONS** DATAFORCCU**REGENERAT~ON** (abbreviations are explained at the end ofthe 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 13-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-2TABLE B-1. EMJ:SSJ:ONS DATAFOR CCUREGENERATJ: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 TotalXYlene 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-3TABLE 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 ReoenOutlet Arsenic Test 1.70e+OO NA NA COB COB Outlet Beryllium 114 2.00e-03 NA NA COB COBOutlet 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-4TABLE B-1. EMZSSZONS DATA FOR CCU REGENERATZON (continued)

Combustion Hydro APCSystem Sample Substance Data Factor tvDe treat location source C1b1mmbbl) 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 RegenOutlet Chromium Test 1.116+00 Partial Yes C\COB\ESP ESP Outlet Chromium Test 1.166+00 Partial Yes C\COB\ESP ESPOutlet Chromium Test 2.106+00 NA NA ESP ESPOutlet 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 COBOutlet 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-5TABLE 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 COBOutlet 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 ESPOutlet Manganese Test 1.78e+OO Complete Yes C\COB\ESP ESPOutlet Manganese Test 2.0ge+OO NA NA ESP ESPOutlet Manganese ICR 2.32e+OO NA NA ESP ESPOutlet Manganese Test 2.45e+OO Partial No I RegenOutlet Manganese Test 

### asse-oo Complete Yes C\WHB\ESP\ ESPOutlet Manganese ICR 1.08e+01 COB Complete Yes C\WHB\ESP\ ESPOutlet Manganese Test 1.10e+01 COB Partial NA C\COB\ESP ESPOutlet Manganese Test 1.42e+01 Partial NA C\COB\ESP ESPOutlet Manaanese Test 2.3Oe+01 NA NA COB COBOutlet Mercury 114 1.00e-03 NA NA COB COBOutlet Mercury 114 1.00e-03 Partial NA C\COB\ESP ESPOutlet Mercury Test 3.07e-02 Partial NA C\COB\ESP ESPOutlet Mercury Test 3.4ge-02 Complete Yes C\COB\ESP ESPOutlet Mercury Test 6.98e-02 NA NA C\ESP ESPOutlet Mercury Test 7.04e-02 Partial Yes C\COB\ESP ESPOutlet Mercury Test 1.48e-01 Partial NA C\COB\ESP ESPOutlet Mercury Test 1.62e-01 NA NA ESP ESPOutlet Mercury ICR 3.00e-01 NA NA ESP ESPOutlet Mercury Test 3.1ge-01 Complete Yes C\WHB\ESP\ ESPOutlet Mercury Test 4.58e-01 COB Complete Yes C\WHB\ESP\ ESPOutlet Mercury ICR 6.00e-01 COB Partial No I RecenOutlet Mercurv Test 2.88e+00 Complete No WHB\ESP ESPOutlet 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 RegenOutlet Nickel 114 5.50e-01 NA NA C\ESP ESPOutlet Nickel Test 5.53e-01 Partial NA C\COB\ESP ESPOutlet Nickel Test 8.62e-01 Complete Yes C\COB\ESP ESPOutlet Nickel Test 1.3ge+00 Partial Yes C\COB\ESP ESPOutlet Nickel Test 1.39e+OO Complete Yes ESP ESPOutlet Nickel 114 1.48e+00 Complete Yes WHB\ESP ESPOutlet Nickel ICR 1.4ge+OO Partial Yes C\COB\ESP ESPOutlet Nickel Test 2.3ge+OO Complete Yes C\WHB\ESP\ ESPOutlet Nickel ICR 3.20e+OO COB Complete Yes WHBWS VSOutlet Nickel 114 3.23e+OO Complete Yes ESP ESPOutlet Nickel 114 3.55e+OO Complete Yes C\WHB\ESP\ ESPOutlet Nickel Test 3.74e+OO COB Complete Yes WHB\ESP\CO COBOutlet Nickel Test 5.21e+OO B NA NA ESP ESPOutlet Nickel ICR 5.47e+OO
B-6

### TABLE B-1. EMXSSXONS DATAFOR

## 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 7nTntal To

.... oAka.l'l7
APC=air pollution control C=cyclone COB

### = carbonmonoxideboiler ESP=electrostaticprecipitator I=Incinerator ICR=Informationcollectionrequest Ib/mm bbl=pounds per million barrels NA

### =notavailable VS=venturiscrubber WHB=waste heatboiler 5F=pentachlorodibenzofuran 6F=hexachlorodibenzofuran 70=heptachlorodibenzo-p-dioxin 

### B-7TABLE B-1. EMJ:SSJ:ONS DATA FOR CCU REGENERATJ:ON (continued)

114=section114request



### B-8TABLE B-2. EMJ:SSJ:ONS DATA FOR CRUREGENERATJ:ON (abbreviations given at end of table) Design APC Sample Type Substance Data Factor System location Source (Ib1mmbbl) Continuous PC RegenOutlet Uncontrolled 12-Dlchloroethane 114 Cyclic SCSlFlare RegenOutlet 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 RegenOutlet Uncontrolled Benzene 114 4.278+00 Cyclic PS RegenOutlet Uncontrolled Benzene 114 6.549+00 Continuous PH HeaterOutlet Controlled Benzene ICR 7.0ge+OO Cvclic SCS/Flare FlareOutlet Controlled HvdroaenSulfide 114 7.10e-05 Cvclic None ReaenOutlet 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 RegenOutlet Uncontrolled Particulate 114 5.94e-03 Cyclic SCS/Flare RegenOutlet Uncontrolled Particulate 114 3.499+00 Continuous None RegenOutlet Uncontrolled Particulate 114 5.858+00 Continuous PC RegenOutlet 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 RegenOutlet Uncontrolled PAH(Total) 114 4.35e+02 Continuous None RegenOutlet Uncontrolled PAH(Total) 114 9.579+02 Continuous None RegenOutlet 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-9TABLE 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 VSAOutlet 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 RegenOutlet Uncontrolled Chlorine SV 4.50e-01 Continuous None RegenOutlet 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 ReaenOutlet 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 RegenOutlet 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 SCSOutlet 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-IOTABLE B-2. EM:ISS:IONS DATA FOR CRU REGENERAT:ION {continued}
Design APC Sample Type Substance Data Factor System location Source (Ib1mmbbll 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 CSOutlet 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 RegenOutlet Uncontrolled 5012378 Test 2.239-10 e Semi-Regenerativ CI\Flare Regen Outlet Uncontrolled 50Total 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 RegenOutlet 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 CSOutlet Controlled 60Total Test 1.25e-11 e Semi-Regenerativ CI\Flare CIOutlet Controlled 60Total Test 4.60e-10 e Seml-Regenerativ CI\Flare Regen Outlet Uncontrolled 60Total 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-llTABLE B-2. 

### EMJ:SSJ:ONS DATAFORCRU REGENERATJ:ON (continued)
Design APC Sample Type Substance Data Factor System location Source t1b/mmbbl) Semi-Regenerativ CI\Flare Regen Outlet Uncontrolled 6F 123478 Test 1.75e-09 e Semi-Regenerativ CS CSOutlet 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 RegenOutlet Uncontrolled 6F 123678 Test 1.78e-09 e Semi-Regenerativ CS CSOutlet 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 RegenOutlet Uncontrolled 6F 234678 Test 2.05e-09 e Semi-Regenerativ CS CSOutlet 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 CSOutlet 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 CSOutlet Controlled 70Total Test 1.90e-11 e Semi-Regenerativ CI\Aare CIOutlet Controlled 70Total Test 1.02e-09 e Semi-Regenerativ CI\Flare Regen Outlet Uncontrolled 70Total Test 2.30e-09 e Semi-Regenerativ CS CSOutlet 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 RegenOutlet Uncontrolled 7F 1234678 Test 4.87e-09 e Semi-Regenerativ CS CSOutlet 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 RegenOutlet Uncontrolled 7F 1234789 Test 1.38e-09 e Semi-Regenerativ CS CSOutlet Controlled 7FTotai Test 2.22e-11 e Semi-Regenerativ CI\Flare CIOutiet Controlled 7F Total Test 2.87e-09 e Seml-Regenerativ CI\Flare RegenOutlet Uncontrolled 7FTotai Test 8.10e-09 e Semi-Regenerativ CS CSOutlet Controlled 80 Test 1.9ge-11 e Semi-Regenerativ CI\Flare Regen Outlet Uncontrolled BD Test 4.23e-09 e 

### B-12Design 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 VSAOutlet 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

### = causticinjection CS

### = causticscrubber I

### =incinerator ICR

### =informationcollectionrequest Ib/mm bbl=pounds per million barrels NA

### =notavailable PC

### =packed column PCDD=polychlorinateddlbenzo-p-dloxlns PCDF=polychlorinateddlbenzofurans PH

### =processheater PS=plate and spray SCS=spraycirculatingsolution ST=spraytower VRS=vortexscrubber VS=venturiscrubber WHB

### = waste heat boiler 114

### = section114 request 40

-80

### = chlorodlbenzo-p-dloxins(tetra- through octa-) 4F - 8F=chlorodibenzofurans(tetra- through octa-)



### B-13 Data Factor Source llblmmbbn

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-02Table B-3. HAP Emission Data for SRUPlant Vent

S!Jt'UProt!. !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) (£6/1,000ton) SOUIU JJtCYE/DUJ1J'E:Jf)tJJ'£ 27702

# =~ cisous Incinerator 0.0012 IC'J{assumeconeinppm !FaltMJU/lY£:}tyr1YE 27702 ccsus Incinerator 0.0080 IC!1tossutlllconeinppm 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(ossutlllconeinppm CO'1tf!Pt1J 27701 1 CUIUS Incinerator 4.2'£-10 IC!!(assumeconeinppm JJt '1J'E:J/)1JYE 27701 1 ccsus Incinerator 7.(/£.10 IC!1tossutlllconeinppm fJalt9tfM/D'E:Ji]'1J'E 27701 3 ccsus Incinerator 4.7'£-08 IC'J(ossutlllconeinppm cryJJt?(J'1J'£CO'1tf!Pt1J 27701 3 CL.9lUS Incinerator 4.2'£-10 IC'J(assumeconeinppm JJtC'EfDU/lYE:Ji]'1J'E 27701 3 CilIUS Incinerator 7.6'£.10 IC!!( assumeconeinppm !faltMfltL'1J'E:J/)1JYE 27701 4 CUIUS Incinerator 0.0221 IC!!(ossutlllconeinppm CY!Jt?(J'1J'£CO'1tf!Pt1J 27701 4 Cl,jIUS Incinerator 0.0150 IC'J( assumeconeinppm JJtC'£rr;UJ1J'£:JfY1J'£ 27701 4 CL.9lUS Incinerator 0.0027 IC'J{assumeconeinppm 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 YLSdL.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 TOTALHAP 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 CARBONYLSULFIDE J VENT 3 CLAUSfTGCU 357.5 1.43 22.0 114 Response TOTALHAP (all SRUs) J 1.5 22.2 CARBONYLSULFIDE 20701 Vent 1 Unspec.TGT Incinerator 132 0.15 6.14 D. Hathaway**~993** CARBONYLSULFIDE 20701 Vent 2 Unspec.TGT Incinerator 132 2.67 110.7 SourceTest· ulfur CARBONYLSULFIDE 20701 Vent 3 Unspec.TGT Incinerator 132 2.37 98.4 Production Rate CARBONYLSULFIDE 20701 Vent 4 Unspec.TGT Incinerator 132 0.33 13.8 from Site CARBONYLSULFIDE 20701 Vent 5 Unspec.TGT Incinerator 132 1.35 55.9 VisitData) TOTALHAP (all SRUs) 20701 6.86 285 CARBONYLSULFIDE 20604 VENT 3 SULFUR PLANT Incinerator 225 3.5 85.2 114 Response CARBONYLSULFIDE 20604 VENT 4 SULFUR PLANT Incinerator 225 3.5 85.2 114 Response TOTALHAP (all SRUs) 20604 7.0 170.5 CARBONYLSULFIDE 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 CARBONYLSULFIDE F VENT 10 SRU 1/2 Tail gas Incinerator 55 1.42 141.5 114 Response CARBONYLSULFIDE 27903 VENT 1 CLAUS Incinerator 21.7 ICR CARBONYLSULFIDE 28103 VENT 1 CLAUS· BEAVON 16.32 ICR CARBON DISULFIDE 28103 VENT 1 CLAUS· BEAVON 0.20 ICR CARBONYLSULFIDE 28103 VENT 2 CLAUS· BEAVON 6.97 ICR CARBON DISULFIDE 28103 VENT 2 CLAUS· BEAVON 0.28 ICR CARBONYLSULFIDE 28103 VENT 3 CLAUS· BEAVON 24.34 ICR CARBON DISULFIDE 28103 VENT 3 CLAUS· BEAVON 0.20 ICR TOTALHAP (all SRUs) 28103 48.30


### B-14Table B-3. HAP EmissionData for SRUPlant Vent

S'lt'l1Protf. :HM 9£!4P !Jadflty '}lent '}lent 1}tscription 'TaifBas 1(au '£missions 'Emissions iIJata :HM 1'1) ?{um6tr t'J'ypt M'C'1Jl (tptf) (tpy) (f611jJOOton) Soruu CARBONYLSULFIDE 28282 Unpec.TGT 50.0 

### oHathaway-allSRUvents CARBONDISULFIDE 29403 VENT 1 CLAUS BEAVON 244 ICRas.stU1Uconeinppm CARBONYLSULFIDE 29403 VENT 1 CLAUS BEAVON 15.1 ICRas.stU1Uconeinppm CARBONDISULFIDE 29403 VENT 2 CLAUS BEAVON 312 ICRas.stU1Uconeinppm CARBONYLSULFIDE 29403 VENT 2 CLAUS BEAVON 16.3 ICRas.stU1Uconeinppm CARBONDISULFIDE 29403 VENT 3 STRETFORD Incinerator 0.21 ICRas.stU1Uconeinppm CARBONYLSULFIDE 29403 VENT 3 STRETFORD Incinerator 1.06 leRas.stU1Uconeinppm TOTALHAP (all SRUs) 29403 589

B-15