United Slates
          Environmental Protection
          Agency
            Office of Air Quality
            Planning and Standards
            Research Triangle Park, NC 27711
EPA-453/R-98-003
June 1998
          Air
vv EPA
PETROLEUM REFINERIES -
BACKGROUND INFORMATION FOR
PROPOSED STANDARDS

Catalytic Cracking (Fluid and Other)
Units, Catalytic Reforming Units, and
Sulfur Recovery Units

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                    EPA-453/R-98-003
 Petroleum Refineries - Background
 Information for Proposed Standards
Catalytic Cracking (Fluid and Other)
Units, Catalytic Reforming Units, and
      Sulfur Recovery Units
       NESHAP

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                                    EPA- 453/R-98-003
 Petroleum Refinery - Background Information for
                Proposed Standards
Catalytic Cracking (Fluid and Other) Units, Catalytic
    Reforming Units, and Sulfur Recovery Units
            Emissions Standards Division
        U.S. Environmental Protection Agency
             Office of Air and Radiation
     Office of Air Quality Planning and  Standards
     Research Triangle Park, North Carolina 27711

                     June 1998

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                            Disclaimer

This report has been reviewed by the Emission Standards Division
of the Office of Air Quality Planning and Standards, EPA, and
approved for publication. Mention of trade names or commercial
products is not intended to constitute endorsement or
recommendation for use. Copies of this report are available
through the Library Services Office  (MD-35),  U.S. Environmental
Protection Agency, Research Triangle Park, NC 27711, or from the
National Technical Information Service, 5285 Port Royal road,
Springfield, VA 22161.

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                 Environmental Protection Agency

          Background Information for Proposed Standards
  National Emission Standards  for Hazardous Air Pollutants for
                Petroleum Refinery  Process Vents

                          Prepared  by:
 Bruce Jordan                                      (Date)
 Director,  Emission Standards Division
 U.S.  Environmental Protection Agency
 Research Triangle Park,  NC   27711

1.   The proposed standards would regulate emission of hazardous
     air pollutants (HAP) emitted from Petroleum Refinery
     process vents. Only those process vents that are part of
     major sources under Section 112(d) of the CAA would be
     regulated. The recommended standards would reduce emissions
     of xxx of the chemicals identified in the CAA list of
     hazardous air pollutants.

2.   Copies of this document have been sent to the following
     Federal Departments: Labor, Health and Human Services,
     Defense, Office of Management and Budget, Transportation,
     Agriculture, Commerce, Interior, and Energy; the National
     Science Foundation; and the Council on Environmental
     Quality. Copies have also been sent to members of the State
     and Territorial Air Pollution Program Administrators; the
     Association of Local Air Pollution Control Officials; EPA
     Regional Administrators; and other interest parties.

3.   For additional information contact:

     Mr. Robert Lucas
     Waste and Chemical Processes Group (WCPG)
     U.S. Environmental Protection Agency
     Research Triangle Park, NC 27711
     Telephone:  (919) 541-0884

4.   Copies of this document may be obtained from:

     U.S. EPA Library (MD-35)
     Research Triangle Park, NC 27711

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                             CONTENTS

Chapter                                                      Page

LIST OF TABLES	ix

LIST OF FIGURES	xi

1.0  INTRODUCTION   	1-1
     1.1  Background	1-1
     1.2  Petroleum Refinery Vents NESHAP   	  1-1
     1.3  Purpose of This Document	1-2

2.0  INDUSTRY DESCRIPTION    	2-1
     2.1  Petroleum Refinery Industry Profile   	  2-1
     2.2  Petroleum Refinery Industry Description   	  2-3
          2.2.1   Catalytic  Cracking Units   	  2-3
          2.2.2   Catalytic  Reforming  Units 	  2-4
          2.2.3   Sulfur Plant  Units	2-4
     2.3  References	2-5

3.0  PROCESS DESCRIPTION AND EMISSION POINTS  	  3-1
     3.1  Catalytic Cracking Unit  (CCU)    	3-1
          3.1.1   CCU  Process Description	3-3
          3.1.2   CCUCR  Process Description 	  3-4
          3.1.3   CCU  Emission  Points	3-4
     3.2  Catalytic Reforming Unit  (CRU)   	3-9
          3.2.1   CRU  Process Description	3-9
          3.2.2   CRU  Catalytic Regeneration Process
                  Description	3-10
          3.2.3   CRU  Emission  Points	3-16
     3.3  Sulfur Recovery Plant    	  3-17
          3.3.1   Sulfur Recovery Unit (SRU)  Process
                  Description	3-18
          3.3.2   Tail Gas Treatment Unit (TGTU)  Process
                  Description	3-18
          3.3.3   Claus  Sulfur  Recovery Plant  Emission
                  Points  	3-20
     3.4  References	3-22

4.0  CONTROL TECHNOLOGY AND PERFORMANCE OF CONTROLS    ....  4-1
     4.1  CCUCR Vent Emission Controls	4-1
          4.1.1   Metal  HAP  Emission Controls  for the
                  CCUCR  Vent   	4-1
          4.1.2   Organic HAP Emission Controls  for the CCUCR
                  Vent   	4-4
     4.2  HAP Emission Controls  for the CRU Purge Vent  .  . .  4-5
          4.2.1   HAP  Emission  Controls for the  CRU Purge
                  Vent   	4-6
                                vn

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                      CONTENTS  (Continued)
          4.2.2  HAP Emission Controls for the CRUCR Coke
                 Burn Vent	4-6
          4.2.3  HAP Emission Controls for the CRUCR Final
                 Purge Vent   	4-6
     4.3  Sulfur Plant Vent Emission Controls   	  4-7
          4.3.1  TGTU as a HAP Emission Control for the SRU
                 Vent   	4-7
     4.4  References	4-9

5.0  MODEL PLANTS AND EMISSION ESTIMATES   	  5-1
     5.1  Model Plants	5-1
     5.2  HAP Emissions From CCU Regeneration   	5-2
     5.3  HAP Emissions From Cru Regeneration   	5-8
     5.4  HAP Emissions From Sulfur Recovery Units (SRUs)     5-13
     5.5  References	5-15

6.0  OTHER ENVIRONMENTAL AND ENERGY IMPACTS ESTIMATES   .  .  .  6-1
     6.1  Other Environmental Impacts for CCUCR Vents   .  .  .  6-1
     6.2  Other Environmental Impacts for CRUCR Vents   .  .  .  6-4
     6.3  Other Environmental Impacts for SRU Vents   ....  6-6

7.0  MONITORING OPTIONS   	  7-1
     7.1  Monitoring Options for the CCUCR Vent   	7-1
     7.2  Monitoring Options for the CRUCR Vent   	7-3
     7.3  Monitoring Options for the SRU Vent   	7-3
     7.4  References	7-4

8.0  COST OF CONTROLS FOR MODEL PLANTS	8-1
     8.1  Costs of Control Devices for CCUCR Vent   	8-1
          8.1.1  Costs  for ESPs   	8-2
          8.1.2  Cost  for Venturi Wet Scrubbers   	8-4
          8.1.3  Costs  for CO Boilers/Incinerators	8-6
     8.2  Costs of Control Devices for CRUCR Vent   	8-7
     8.3  Costs of Control Devices for Sulfur Plant Vent  .  .  8-9
     8.4  Costs of Monitoring,  Reporting, and
          Recordkeeping   	   8-10
     8.5  References	8-13
                                Vlll

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                          LIST OF TABLES

Table                                                        Page

2-1     US Refineries-State  Capacities as  of
        January  1,  1997	2-2
5-1     Summary  of  Organic HAP Data  From CCU  Regeneration  .  .  5-5
5-2     Summary  of  Controlled Metal  HAP Emissions and HCl
        Data  From CCU Regeneration   	5-6
5-3     Summary  of  HAP Emission  Factors for CCU  Regeneration   5-6
5-4     Summary  of  Range of  Potential hap  Emission  for CCU
        Regeneration  From  the Model  Plants   	  5-7
5-5     Summary  of  Nationwide Emissions Estimates for CCU
        Regeneration   	  5-8
5-6     Summary  of  HAP Data  From CRU Regeneration	5-11
5-7     Summary  of  HAP Emission  Factors for CRU
        Regeneration   	   5-12
5-8     CRU HAP  Emission Estimates for Model  Plants  ....   5-12
5-9     Nationwide  HAP Emission  Estimates  for CRU
        Regeneration   	   5-13
5-10    Summary  of  HAP Emissions Data for  SRU Vents  ....   5-14
5-11    HAP Emission  Estimates for SRU Vents   	5-14
6-1     Comparison  of Other  Environmental  and Energy Impacts
        for Inorganic HAP  Emission Control Devices  for the
        CCUCR Vent    	6-3
6-2     Annual Other  Environmental and Energy Impact
        Estimates for Model  CCUCR Vent Incinerators  	  6-4
6-3     Nationwide  Annual  Other  Environmental and Energy
        Impacts  Estimates  for the CCUCR Vent   	6-5
6-4     Other Environmental  and  Energy Impacts Estimates for
        Model Plant CRUCR  Vents  	  6-6
6-5     Nationwide  Annual  Other  Environmental and Energy
        Impacts  Estimates  for the CRUCR Vent   	6-6
6-6     Annual Other  Environmental and Energy Impact Estimates
        for Model SRU Vent Incinerators	6-7
6-7     Nationwide  Other Environmental and Energy Impact
        Estimates for SRU  Vents	6-7
8-1     Model Plant CCUCR  Vent Flow  Rates	8-1
8-2     Design values for  ESP	8-2
8-3a    Model Plant CCUCR  ESP Control Costs-TCI  	  8-3
8-3b    Model Plant CCUCR  ESP Control Costs-AOC  	  8-3
8-3c    Model Plant CCUCR  ESP Control Costs-TAC  	  8-3
8-4     Design Values for  Venturi Scrubbers   	  8-4
8-5a    Model Plant CCUCR  Venturi Scrubber Control  Costs-TCI   8-5
8-5b    Model Plant CCUCR  Venturi Scrubber Control  Costs-AOC   8-5
8-5c    Model Plant CCUCR  Venturi Scrubber Control  Costs-TAC   8-5
8-6     Model Plant CCUCR  Incinerator Control Costs-TCI,
        AOC,  and TAG   	8-6
8-7     Model Plant CRUCR  Vent Flor  Rates	8-7
                                IX

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                   LIST OF TABLES  (Continued)
8-8    Model Plant CRUCR Wet  Scrubber/Absorber Control
       Costs-TCI, AOC, and TAG	8-8
8-9    Model Plant SRU Vent Flow Rates	8-9
8-10   Model Plant SRU Incinerator Control Costs-TCI, AOC,
       and TAG	8-10
8-11   First Cost and Initial Annual Cost for Continuous
       Emission Monitors on CCUs, CRUs, and  SRUs	8-12

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                         LIST OF FIGURES

Figure                                                       Page

3-1     Fluid  catalytic  cracking unit  	 3-2
3-2     Simplified  schematic  of  non-fluid  (thermal)  catalytic
        Cracking  unit  (TCCU)   	3-6
3-3     Typical regeneration  process flow  diagram for
        semi-regenerative  catalytic reformers  	  3-11
3-4     Typical regeneration  process flow  diagram for
        cyclic catalytic reformers   	  3-12
3-5     Typical process  flow  diagram for continuous
        reformers	3-13
3-6     Refinery  MACT  discussions: process vents  Clause
        sulfur recovery  units 	  3-19
                                XI

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                   xii

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                     1.0  INTRODUCTION

1.1  BACKGROUND
     Title III of the 1990 Amendments to the Clean Air Act
(CAA) substantially revised section 112 of the Act regarding
the development of National Emission Standards for Hazardous
Air Pollutants (NESHAP).  To implement the congressional
directives of Title III, the U.S. Environmental Protection
Agency  (EPA) has initiated a program to develop NESHAP for
certain categories of stationary air emission sources that
emit one or more of the hazardous air pollutants (HAP)
listed in section 112(b) of the CAA.
1.2  PETROLEUM REFINERY VENTS NESHAP
     On July 16,  1992,  EPA published a list of all source
categories emitting HAP  (57 FR 31576) and included Petroleum
Refineries among the listed source categories.  On August
18, 1995, EPA promulgated a NESHAP for the petroleum
refinery source category primarily for organic HAP emission
sources  (60 FR 43244).  In the 1995 petroleum refinery
NESHAP, EPA specifically excluded three process vents from
the NESHAP because of the unique characteristics of the
inorganic emissions from each of these vents and stated that
"these emission points are included in a separate source
category under a separate schedule."  These three process
vents are the subject of this rulemaking entitled "NESHAP:
Petroleum Refineries - FCC Units, Reformers, and Sulfur
Plants."  The emission sources considered under this
rulemaking include:  1) the catalyst regeneration process
vent(s) from the catalytic cracking unit  (CCU); 2) the
catalyst regeneration process vent(s) from the catalytic
                            1-1

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reforming unit (CRU); and the process vent(s) for the sulfur
recovery plant.
1.3  PURPOSE OF THIS DOCUMENT
     In developing NESHAP, the EPA evaluates different
strategies for reducing air emissions from the source
category.  For selected control strategies, the EPA develops
emission and control cost impacts to support in the
development of the NESHAP.  This technical support document
(TSD) presents the information and methods used by EPA to
perform the control strategy impact analysis.
     Chapter 2 presents, a brief overview of the petroleum
refinery industry as pertaining to the CCU, CRU, sulfur
recovery processes.  Chapter 3 provides a more detailed
description of each of the processes, the type of HAP
emitted, the process emissions points.  Chapter 4 describes
the control technologies available for reducing HAP
emissions from each of the process vents.  The procedures
used to estimate current  (baseline) and controlled emission
are provided in Chapter 5; the procedures used to estimate
the other environmental and energy impacts associated with
the control strategies are provided in Chapter 6.  The
options considered for monitoring the emission points are
discussed in Chapter 7.  Chapter 8 describes the methods and
procedures used to estimate the control cost impacts
associated with the selected control and monitoring
strategies.
                            1-2

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                 2.0  INDUSTRY DESCRIPTION

     This chapter presents a brief overview of the petroleum
refinery industry in general, with particular industry
descriptions of catalytic cracking units (CCUs),  catalytic
reforming unit (CRUs), and the sulfur recovery plants.
2.1  PETROLEUM REFINERY INDUSTRY PROFILE1
     There are approximately 162 petroleum refineries in 33
States nationwide (see Table 2-1) .  These 162 refineries
process 15.4 million barrels of crude oil daily.   As seen in
Figure 2-1, the following three States dominate U.S. crude
oil refining:  California (14.2 percent of the refineries
and 12.3 percent of the crude capacity); Louisiana  (11.7
percent of the refineries and 15.7 percent of the crude
capacity); and Texas  (17.3 percent of the refineries and
26.1 percent of the crude capacity).  Together, these three
States represent 43 percent of the U.S. refineries and
54 percent of the total nationwide crude oil processing
capacity.
     There are 36 petroleum refineries with crude oil
processing capacities of 20,000 barrels per calendar day
(b/cd) 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 b/cd of crude
oil and employs less  than 1,500 people corporately.  There
are 94 petroleum refineries that process less than
                            2-1

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   Table 1. U.S. Refineries-State Capacities as of January 1,1997a
State
Alabama
Alaska
Arkansas
California
Colorado
Delaware
Georgia
Hawaii
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Minnesota
Mississippi
Montana
Nevada
New Jersey
New Mexico
North Dakota
Ohio
Oklahoma
Pennsylvania
Tennessee
Texas
Utah
Virginia
Washington
West Virginia
Wisconsin
Wyoming
TOTAL
No. of
plants
3
6
3
23
2
1
2
2
6
3
3
2
19
3
2
4
4
1
6
3
1
4
5
6
1 
28
5
1
7
1
1
4
162
Crude
capacity,
b/cd
134,225
283,000
65,200
1,898,815
85,500
140,000
34,000
149,000
909,550
435,990
283,350
224,800
2,417,290
121,200
355,000
336,800
143,850
7,000
674,000
97,600
58,000
499,650
403,000
574,400
105,000
4,019,600
159,500
56,700
587,250
10,500
36,000
126,825
15,432,595
Catalytic
crackling,
b/cd
0
0
19,100
608,470
27,000
63,000
0
21,000
322,200
157,050
79,120
97,000
885,900
45,500
108,810
63,000
53,000
0
282,700
32,331
24,700
173,550
109,700
122,500
50,000
1,588,300
43,400
25,700
117,500
0
10,400
49,200
5,180,583
Catalytic
reforming,
b/cd
26,480
12,000
12,400
428,260
19,000
45,900
0
13,000
336,920
92,000
60,470
43,195
463,200
27,900
75,795
71,000
31,500
0
118,400
31,800
11,500
153,200
88,050
128,488
16,000
1,133,600
31,400
10,800
126,300
3,300
7,600
29,125
3,648,583
Sulfur
Production
,t/d
131
15
88
1,768
44
448
0
20
435
370
81
0
2,552
25
750
1,067
0
0
0
2
15
0
95
0
42
4,211
46
66
241
1
15
2
12,530
a Data obtained from Reference 2, but omits one facility in Oregon
  that has no reported crude capacity (apparently an asphalt plant).
  Data also omits Tosco Refining Co. in Marcus Hook, PA (180,500
  b/cd capacity) that was idled in 1996; it is expected to restart mid-
  1997.
                             2-2

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75,000 b/cd 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 b/cd or more, and these 24 refineries
represent almost 44 percent of the U.S. crude oil refining
capacity.
     Over the past 5 years the total nationwide petroleum
refining capacity has dropped slightly, but the actual crude
oil processing rates have risen slightly.  The total
petroleum refining capacity was 15.6 million b/cd in 1990
compared to 15.3 million b/cd in 1995.  During the same time
frame, the total number of operating refineries fell from
184 to 173.  However, the actual crude oil processing rate
increased from 13.6 million b/cd in 1990 to 14.1 million
b/cd in 1995.  Thus, the U.S. petroleum refining capacity
utilization has increased from 87 percent in 1990 to 92
percent in 1995.4
     Future trends in the petroleum refining industry are
expected to mirror the past five years.  According to U.S.
Department of Energy and Commerce projections, refinery
shutdowns are expected to continue, but the crude oil
processing rate is expected to remain relatively stable as a
result of increased capacity utilization at existing
facilities.  The demand for refined petroleum products is
expected to grow an average of 1.5 percent per year, which
is slower than the expected growth rate of the economy.5
2.2  PETROLEUM REFINERY INDUSTRY DESCRIPTION
2.2.1  Catalytic Cracking Units6
     The nationwide petroleum refinery catalytic cracking
(fluid and other) charge capacity was 5.18 million b/cd in
January 1997.1  There are 105 petroleum refineries that
operate a total of 117 CCU [either fluid and/or other
(non-fluidized) CCU].  However, fluid CCUs dominate the CCU
processes in the petroleum refinery industry.  There are
only 7 refineries that reported operating a non-fluidized
                           2-3

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CCU, only 4 of which reported operating only a non-fluidized
CCU, and non-fluidized CCUs accounted for only 2.9 percent
of the total catalytic cracking process charge rate.
     There are 9 refineries that reported catalytic cracking
charge capacities of less than 10,000 b/cd.  There are 8
refineries that reported charge capacities of greater than
100,000 b/cd; half of these refineries have more than one
catalytic cracking unit.
2.2.2  Catalytic Reforming Units7
     The total nationwide catalytic reforming charge
capacity was 3.65 million b/cd in January 1997.  There are
124 refineries that operate some form of CRU.  There are
three major types of CRU catalytic regeneration processes:
semi-regenerative; cyclic; and continuous  (see Section 3.2
for CRU process description).   There are 111 refineries,
representing 49 percent of reforming capacity, that use
semi-regenerative process technologies; 23 refineries with
24 percent of reforming capacity employed the cyclic process
technologies; and 32 refineries with 27 percent of reforming
capacity employed the continuous process technologies.
     There are 15 petroleum refineries that have reforming
capacities of 5,000 b/cd or less, and 14 petroleum
refineries that have reforming capacities of 50,000 b/cd or
more.
2.2.3  Sulfur Plant Units8
     Production of sulfur  (all forms measured as pure
elemental sulfur) from petroleum refineries was reported at
2,940 thousand Mg in 1985 and 4,200 thousand Mg in 1990.
There are 130 U.S. refineries that report operating some
form of sulfur production units  (in 1992), representing a
total sulfur production capacity of 20,500 Mg/day.
     There are 52 refineries that have sulfur production
capacities of less than 50 Mg/day; 24 refineries have sulfur
production capacities greater than 300 Mg/day; and 5
refineries have sulfur production capacities greater than
500 Mg/day.
                            2-4

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     Of the 130 refineries that have sulfur recovery plants,
88 provided the number of sulfur plant trains (units) at the

facility; the total number of units reported was 144 sulfur

trains; 38 reported multiple trains with 13 reporting 3 or

more units.

2.3  REFERENCES
1.   Radler, Marilyn, Survey Editor.  "1996 Worldwide
     Refining Survey."  Oil and Gas Journal.  OGJ Special,
     December 23, 1996.  pp.  49 through 94.

2.   Reference 1.

3.   U.S Environmental Protection Agency.  Responses to
     Information Collection Request for Petroleum
     Refineries.  Publication No. XXXXX.  Office of Air
     Quality Planning and Standards, Research Triangle Park,
     NC.  1992. 

4.   Lidderdale, T., N. Masterson, and N. Dazzo.  "U.S.
     Refining Capacity Utilization."  Energy Information
     Administration, Petroleum Supply Monthly,  pp. 33
     through 3 9.

5.   U.S Environmental Protection Agency.  EPA Office of
     Compliance Sector Notebook Project - Profile of the
     Petroleum Refining Industry.  Publication No. EPA/310-
     R-95-013.  Office of Enforcement and Compliance
     Assurance, Washington, DC.  September 1995.  pp. 10
     and 11.

6.   Reference 1.

7.   Reference 1.

8.   1992 Report on Sulfur Production.  Chemical Economics
     Handbook.  1992.
                            2-5

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        3.0   PROCESS DESCRIPTION AND EMISSION POINTS

     This chapter presents a description of the processes
associated with the three refinery vents of interest:
catalytic cracking unit (CCU) catalyst regeneration process
vent (CCU vent),  the catalytic reforming unit (CRU) catalyst
regeneration process vent (CRU vent), and the sulfur
recovery plant vent  (SRU vent).   For each process vent,
process descriptions are provided with an emphasis on the
sources of hazardous air pollutants  (HAP) and a description
of the emission release points.   Much of the following
process descriptions result as a composite of infromation
collected during site visits to petroleum refineries (see
References 1 through 5).  The Petroleum Refinery Enforcement
Manual6 and the EPA Sector Notebook for petroleum refining7
are also general references for the process descriptions
provided in the chapter.
3.1  CATALYTIC CRACKING UNIT  (CCU)
     The CCU {fluid or other) is used to upgrade the heavy
distillates to lighter, more useful distillates such as
heating oils or gasoline.  The typical CCU system consists
of a CCU reactor, a CCU catalyst regenerator  (CCUCR), vent
gas process equipment for energy recovery and/or emission
control, and an exhaust stack (see Figure 3-1).  Nearly all
CCU systems operate as fluidized-bed reactors and use air or
oil gas flow to transport the catalyst between the CCU
reactor and the CCUCR.  These fluidized CCU systems are
                            3-1

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 OJ

  I

 10
 Feed
                                  +> Products
                     Reactor





/

k



r
                       ;i
ir
                                            Auxiliary Air
                                           and Auxiliary
                                               Fuel
          Steam
                                  Flue Gas
                                Regenerator
                                                       Energy Recovery
                                                  Particulate
                                                  Removal
                                                   Device
                              Air
                          Regenerated Catalyst Transfer Line
                                                                                         Flue Gas
                                                                                       Exhaust Stack
                                                                               D
                                                                               %
                                                                               CD
                                                                               H
                                                                               vo
                                                                               vo
                                                                               00
Figure 3-1. Fluid catalytic cracking unit.

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commonly referred to as FCCUs (fluid catalytic cracking
units),  and the process descriptions that follow will focus
primarily on FCCU operation due to their dominance in the
industry.  However, since catalyst regeneration vents for
non-fluid CCUs are included in this source category, the
term CCU is used throughout this document to refer to both
FCCU and other "thermal" CCU  (TCCU).  The terms FCCU and
TCCU will be used to refer to a specific type of CCU.
3.1.1  FCCU Process Description
     The FCCU 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 FCCU 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 with the
catalyst particles.  Some of the reaction products, however,
are deposited on the catalyst in the form of coke  (carbon),
which reduces catalyst activity.  The mixture of products
and catalyst flows up the riser into the CCU reactor vessel.
Current research indicates that most of the cracking
reactions take place in the riser.  As such the FCCU reactor
functions primarily to separate the vapor products from the
catalyst.
     Catalyst entrained with the vapor products are
typically disengaged from the vapor product by flow  (impact)
impingers followed by cyclone separators.  The vapor
products pass through the internal cyclones and are vented
from the top of the FCCU reactor to a fractionation column
for product separation.  The disengaged catalyst is
collected at the base of the reactor where the catalyst is
stripped with steam to remove any hydrocarbons that may have
deposited on the catalyst before returning the catalyst to
the regenerator.

-------
     Spent catalyst collected in the FCCU reactor is
continuously returned to the regenerator to burn off coke
deposits.  After the coke is burned off, the regenerated
catalyst flows down a transfer line for reuse and is then
introduced to the gas oil feed stream at the beginning of
the riser, and the process repeats itself.
     The spent catalyst that is returned from the CCU
reactor is continuously regenerated by burning off coke that
was deposited on the catalyst in the riser and CCU 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 CCU regenerators:
complete combustion regenerators and partial combustion
regenerators.  In a complete combustion regenerator, the
regenerator is typically operated at approximately 1,200 to
1,400F with excess oxygen and low levels (< 500 ppmv) of
carbon monoxide (CO) in the exhaust flue gas.  In a partial
(or incomplete) combustion regenerator, the regenerator is
typically operated at approximately 1,000 to 1,200F under
oxygen limited conditions and relatively high levels  (1 to
3 percent) of CO.  Small amounts of platinum may be added to
the CCUCR to promote combustion; "De-SOx" or other SOX
scavenging additives may be added to reduce SOX emissions;
and fresh catalyst may be added to the CCUCR to maintain
catalyst activity and replace catalyst lost from the system.
Prior to exiting the CCUCR, catalyst particles entrained
with the flue gases are initially removed by internal
cyclone separators.
3.1.2  TCCU Process Description
     The TCCU process employs catalyst pellets rather than
the fine catalyst powder used in FCCUs.  The TCCU pellets
are roughly 1/8 inch  (3,175 M) long compared to a typical
FCCU powder diameter of 85 M-  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 TCCU.  The TCCU catalyst enters the

                            3-4

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top of the vertical reactor and flows in a plug flow fashion
down the reactor bed by gravitational force (refer to
Figure 2).   Oil feed is introduced near the top of the
reactor portion of the TCCU where it mixes with the hot
catalyst pellets and flows cocurrent with the catalyst bed.
The feed oil vaporizes and the vapors and the cracking
reactions occur.  The catalyst and vapor products, upon
reaching the bottom of the reactor, pass through a vapor
disengaging grid.  Vapor is disengaged from the catalyst and
drawn off by a series of vapor tubes.  Purge steam is
introduced below the vapor draw off tubes to purge any
remaining oil vapor from the catalyst pellets.  The purge
steam is also removed from the system via the vapor draw off
tubes along with the oil vapor products.
       Purged catalyst pellets continue to move downward to
the regenerator  (or kiln) portion of the TCCU.  Air is
introduced near middle of the regenerator section in a
controlled manor to regulate the temperature and coke burn-
off rate.  The operating pressure in the TCCU regenerator is
approximately 3 psig compared to 30 psig for a FCCU
regenerator.  Flue gas is removed from the system both near
the top of the regenerator and near the bottom of the
regenerator.  Approximately 70 percent of the air feed
passes upward through the regenerator and 30 percent flows
downward with the catalyst.  Flue gas is separated from the
catalyst at the bottom of the regenerator is a similar
fashion as oil vapor was disengaged from the catalyst at the
bottom of the reactor.  The flue gas streams combine and
either fed to a CO boiler or released directly to the
atmosphere through a single stack vent.
                           3-5

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   Row deflector
         Catalyst lift
             Upper flue
              gas vent
Catalyst feed
                            vent to
                          atmosphere or
                            CO boiler
                                                      TCC Reactor
            Vaporized oil products to distillation
                                                           Steam in
                                                      TCC Regenerator

                                                           Combustion air in
                                                   Regenerated catalyst recirculation
                     Lin air line
Figure 3-2.   Simplified Schematic  of  non-fluid  (thermal)
                 catalytic  cracking unit  (TCCU).
                                     3-6

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     Below the regenerator,  the catalyst flows through a
cooler section to cool the catalyst and recover latent heat.
The catalyst is then transported to the catalyst surge
vessel at the top of the TCCU 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  CCU Emission Points
     There are two primary vents from the CCU system.  The
first vent is the product oil gases that exit the C.CU
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
CCU system result in a loss in product yield and the
refineries have an economic incentive to reduce or correct
any equipment leaks on the product side of the CCU system.
     The second vent from the CCU system is the flue gas
exhausted from the CCUCR as a result of burning off coke
deposited on the catalyst.  This exhaust vent is the primary
process emission vent from the CCU system.  This vent will
be referred to in this document as the CCUCR vent, although
other references cited in this document may refer to this
vent as the CCU vent, the FCCU vent, or the process vent for
FCC units.  Note, both FCCU and TCCU have a CCUCR vent.
     The CCUCR vent stack flue gas is characterized by low
HAP concentrations and large volumes of gas.  The final
CCUCR vent stack is typically 6 to 16 feet in diameter,
depending of the CCU throughput, and 100 feet high.  The
CCUCR vent from a TCCU are generally smaller, roughly 2 to 3
feet in diameter.  Typical volumetric flow rates of flue gas
in the CCUCR vent stack range from 50,000 standard cubic
feet per minute  {scfm) for smaller CCUs to 400,000 scfm or
more for larger CCUs.  The total HAP concentrations in the
CCUCR vent stack flue gas ranges from 0.1 to 1 parts per
million by volume  (ppmv).  HAP that are commonly present in
the flue gas from the CCUCR include metals  (primarily

                           3-7

-------
nickel) and organics  (primarily formaldehyde, acetaldehyde,
benzene, toluene, xylenes, hexane, and phenol).  Other
metals that have been detected in the CCUCR vent flue gas
include:  antimony, cadmium, chromium, cobalt, lead,
manganese, and mercury.  Other organics that have been
detected  (or suspected to be) in the CCUCR vent flue gas
include:  naphthalene, polycyclic organic matter (POM),
dioxins, and furans.8
     The TCCU has an additional emission point from the
surge vessel where  lift air used to transport catalyst from
the bottom to the top of the TCCU is vented to the
atmosphere.  Catalyst particles may remain entrained with
the lift air so there is a potential for the surge tank vent
to emit the same metal HAP that are emitted from the CCUCR
vent.  The relative volume of the lift air flow rate is
approximately one-third to one-half the flue gas flow rate
from the regenerator.  However, due to the relative
characteristics of  the surge vessel vent and the CCUCR vent,
the particulate emissions rate from the surge vessel vent
are expected to be  roughly equivalent and may be higher than
the particulate emissions from the CCUCR vent.  No data are
currently available regarding the HAP emissions from TCCU
surge vessel vent.  As such, it is unclear how the overall
HAP emissions from  the TCCU  (CCUCR vent plus the surge tank
vent emissions) compare to the CCUCR emissions from a CCU
with similar throughput.
     The metal HAP  are expected to originate as contaminants
in the CCU feed that  deposit on the catalyst particles.
Consequently the metal HAP emission rate may be dependent  on
the mix of oils and residual used as feed to the CCU.  Some
CCU feeds are hydrotreated.  The hydrotreater removes
sulfur, nitrogen, vanadium, nickel and other contaminants
from the  crude oil  feedstocks.  This  "pretreatment" step
prior  to  the CCU typically helps  to improve CCU yield,
prolongs  catalyst  life, and reduces CCU HAP emissions
according to industry representatives.9  Because most of the
                            3-8

-------
metal HAP emissions are in the form of particulate matter
(PM), PM control devices also reduce metal HAP emissions.
     Many of the organic HAP emissions originate as by-
products of coke combustion  (e.g., formaldehyde,
acetaldehyde, POM, dioxins and furans).   It is unclear,
however, why the volatile organic HAP (benzene, toluene,
xylenes, and hexane) are not destroyed in the CCUCR.  These
volatile organic HAP may originate as residual oil feed
material on the catalysts that somehow vaporize, but do not
combust prior to exiting the CCUCR.
      Organic HAP emissions from partial combustion
regenerators may be expected to be higher due to the lack of
sufficient oxygen to completely combust the coke material.
However, most partial combustion regenerators employ a CO
boiler or incinerator to recover the latent heat energy of
the CO in the CCUCR flue gas.  At this time, the EPA is
collecting data to determine whether a complete combustion
CCU system has significantly different HAP emissions from a
partial combustion CCU system followed by a CO boiler.
     Equipment leaks and fugitive emissions are not
anticipated to be significant from the CCUCR flue gas
treatment train because of the low concentrations of HAP in
this vent stream.
3.2  CATALYTIC REFORMING UNIT (CRU)
3.2.1  CRU Process Description
     The catalytic reforming process involves a complicated
series of reactions that occur over a catalyst that change
the chemical structure of the hydrocarbons.  The predominant
reaction is the dehydrogenation of naphthenes to form
aromatics.  The reactions occur over a noble metal catalyst,
such as platinum or rhenium.  The feedstocks for reforming
(referred to as naphtha) are first treated to remove sulfur
and other compounds that would poison the reforming
catalyst.  Because the reforming reaction is endothermic,
heat must be continually supplied to the system to maintain
optimal reaction temperatures.  This is typically
                            3  -.9

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accomplished by performing the reaction in a series of
reactors and applying heat to the naphtha/product stream
through heat exchangers between each reactor.
     The reforming products are separated into a gas and a
liquid stream.  The hydrogen gas is compressed with a
portion going back to the reformer; the hydrocarbon stream
is sent to a fractionation column for final product
separation.  As the reaction progresses, deposits accumulate
on the catalyst particles and reduce their reactivity.
Consequently, the catalyst must be occasionally regenerated.
3.2.2  CRU Catalytic Regeneration Process Description
     There are three different methods in which to effect
reforming catalyst regeneration.  Semiregenerative reforming
is characterized by shutdown of the reforming unit at
specified intervals, or at the operator's convenience, for
in situ catalyst regeneration  (see Figure 3-3} .   Cyclic
regeneration reforming is characterized by continuous or
continual regeneration of catalyst in situ by isolating one
of the reactors in the series, regenerating the catalyst,
then returning the reactor to the reforming operation (see
Figure 3-4).  Continuous regeneration reforming is
characterized by the continuous regeneration of part of the
catalyst in a special regenerator, followed by continuous
addition of this regenerated catalyst to the reactor  (see
Figure 3-5).
     As with the CCU catalyst, the CRU catalyst .is
regenerated by controlled oxidation  (burning) of the coke
deposited on the catalyst.  In semiregenerative and cyclic
regenerators, the CRU reactor(s) are first taken off-line,
                           3-10

-------
00

I
                                                                  Compressor
                                                                                 Step1.N2
                                                                                 Step 2. Air
                                                                                 Step 3. H2
               Chlorine
                                Chlorine
       Preheater
          1
Preheater
    2
Preheater
    3
        Step 1.  Depressuritation and hydrocarbon purge vent

        Step 2.  Coke burn pressure control vent

        Step 3.  Regjuvination and O2 purgenent
                                  Air
                                    Caustic>
                                                                Makeup Water-
                                                                                          Vent
                                                                                                Separator
                              Effluent to
                              Wastewater
                              Treatment
    Figure 3-3.   Typical regeneration process flow diagram for semi-regenerative catalytic
                   reformers.
vo
oo

-------
u>

I

M
to
        Preheater
                                 Organic
                                 Chloride'
 Offline
Reactor
                                                               Compressor
                                          Step 1. N2
                                          Step 2. Air
                                          Step 3. H2
                                 Gases to
                                   Stack
                        Heat
                     Exchanger
         Step 1.  Depressuritation and hydrocarbon purge vent
         Step 2.  Coke burn pressure control vent
         Step 3.  Regjuvination and O2 purge vent
                                                             Cooler
                                                                                           Makeup Water
Separator
                                                   Effluent to
                                                  Wastewater
                                                   Treatment
I
C|

0>
                                                                                                        VO
                                                                                                        00
      Figure  3-4.  Typical regeneration process  flow diagram for cyclic catalytic reformers

-------
 i

M
CO
                                                   1	Regenerated Catalyst
              4
                          Coke Burn
                          Pressure
                         Control Vent
            Air
         Organic_
         Chloride
                              Spent Catalyst
Heat
Exchangers
                                                             Low Pressure
                                                               Separator
                                                   Depressurization and
                                                    Hydrocarbon purge
                       Recycle Gas
          High Pressure
            Separator
             Reformate
                                                                                                         * Net Gas
D
5
n
^
i
9

o>
                                                                                                                      VJ3
                                                                                                                      00
   Figure 3-5.   Typical process flow diagram for continuous  reformers.

-------
the reactor(s) are isolated, and any residual hydrocarbons
are purged from the system using nitrogen.  This nitrogen
purge gas is typically vented to the refinery's flare
system.  Air is then slowly introduced to the CRU reactor(s)
to begin the combustion process, with the coke serving to
fuel the process.  The flue gas from the CRU coke combustion
is typically recirculated, with small amounts of fresh air
continuously added to the recirculated air to control the
coke burn rate.  Excess flue gas from the coke combustion is
vented to the atmosphere from a small pipe vent as necessary
to maintain the desired pressure within the system.
     The combustion process naturally produces some water.
The water tends to leach chloride atoms from the catalyst,
which reduces the catalyst's performance.  Consequently, a
chloride source  {usually a chlorinated organic such as
perchloroethene or trichloroethene) is used to replace the
chloride atoms stripped by the water.  The chlorination
cycle may be performed either as a separate cycle after the
coke burn cycle is completed or simultaneously while the
coke burn cycle is under way.  Once the catalyst is
regenerated (i.e., coke burn and chlorination cycles
completed), the system is first purged with nitrogen to
remove any oxygen and residual chlorination agent from the
system, and then purged with hydrogen to reduce the catalyst
from the metallic oxide formed during the burn cycle back to
its active (elemental) metal state prior to bringing the
unit back on-line.
     The overall regeneration cycle for semiregenerative
systems takes approximately 5 to 15 days depending on the
level of other maintenance the CRU requires.  The coke burn
cycle typically takes between 2 to 5 days.  Cycle times
between regeneration cycles may range from 6 to 18 months
depending on the severity of the CRU reactor operating
conditions (which are based on the product mix being
produced from the CRU).  Regeneration cycles for cyclic
systems are typically shorter in duration and more frequent
in occurrence than semiregenerative systems.  However, both

                           3-14

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systems are characterized by short, intermittent periods
when emissions may occur.
     In continuous CRU regeneration, catalyst from the CRU
is circulated in semi-continuous fashion  (small batches) to
the regenerator by a series of small hoppers.  These hoppers
serve the function of the depressurization and initial purge
cycle of the semiregenerative or cyclic systems.  A
continuous CRU regenerator typically has  three sections:  a
regeneration section, a chlorination section, and a drying
section.  The first section of the regenerator that the
catalyst enters is the regeneration section.  In the
regeneration section, hot air {at approximately 900 to
1,200F) is recirculated through the catalyst, with enough
fresh air added to maintain a low excess  oxygen content  (of
approximately 1 to 2 percent).  As air is added to the
recirculating regeneration air line, air  must also be vented
from the system to maintain the desired pressure in the
regeneration air line.  This vent is typically vented to the
atmosphere; however, a water or caustic scrubber may be used
in either the air recirculation line or in the vent line to
remove HC1.
     In the next section, called the chlorination section, a
chloride source  (e.g., perchloroethene or trichloroethene)
is recirculated through the catalyst to replace any chloride
leached from the catalyst in the regeneration section.  The
regeneration and chlorination sections are separated by a
series of baffles to allow catalyst to move  from the
regeneration section to the chlorination  section, but to
minimize gas flow between the two sections.
     The catalyst from the chlorination section then moves
past another series of baffles into the drying section.  In
this section, hot air is used to strip any chloride agent
remaining on the catalyst and dry the catalyst.  After  the
dying section, the catalyst is returned to the CRU reactor
by another series of small hoppers.  These hoppers serve the
function of the final purge cycle  (to remove oxygen and


                           3-15

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create a reducing atmosphere) of the semiregenerative or
cyclic systems.
3.2.3  CRU Emission Points
     The CRU system is essentially a sealed system except
for the catalyst regeneration cycles.   Although the location
of the emission point might vary depending on whether
catalyst regeneration is semiregenerative, cyclic, or
continuous, there are three times during the regeneration
process that emissions can occur regardless of the
regenerator type.  These three emission points are:  (1) the
initial depressurization and purge vent;  (2) the coke burn
pressure control vent; and (3) the final catalyst purge
vent.
     The initial depressurization and purge cycle removes
the hydrocarbons from the catalyst prior to CRU catalyst
regeneration.  The vent gases from this initial purge may
have high levels of organic HAP such as benzene, toluene,
xylene, and hexane.10  This vent  is typically vented  to  the
refinery's fuel gas system or directly to a combustion
device  (e.g., flare or process heater).
     The coke burn cycle is typically the largest  (in terms
of gas volume) emission source of the overall catalyst
regeneration cycle.  The primary HAP contained in the CRU
coke burn vent are HCl and chlorine (C12),1:L which are
produced when the water formed during combustion leaches
chloride atoms from the CRU catalyst.  The CRU coke burn
vent is typically a 3" to 6" pipe with a varying flow rate
in the range of 50 to 1,000 scfm that is released to the
atmosphere.  The vent pipe may be only a few feet long, but
may be longer to provide a release height of at least 15 to
20 feet.  Caustic injection or caustic scrubbing may be used
in the flue gas recirculation line to remove HCl.  Although
these HCl removal techniques are implemented primarily  to
protect the process equipment, they are also expected to
reduce HCl emissions  from the coke burn vent.  Some  systems
operate a water or caustic scrubber for the vent  line
specifically to reduce HCl, although this is typically  more

                           3-16

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common for continuous regenerators or cyclic systems that
cycle frequently.
     The final purge and reduction cycle removes oxygen and
any remaining chorination agent from the system and reduces
the catalyst prior to returning CRU catalyst to the
reforming process or bringing the unit back on-line.  The
vent gases from this final purge may have low levels of the
chlorinating agent {usually an organic HAP such as
trichloroethene of perchloroethene) and residual HCl or C12
remaining in the system.10  This vent is typically vented to
the atmosphere or the refinery's fuel gas system depending
on the oxygen content of the vent gases (safety
considerations restrict the venting of oxygen containing
gases to the fuel gas system).  Alternatively, the purge gas
may be directly vented to a combustion device (e.g., flare
or process heater).
     Equipment leaks and fugitive process emissions may be
significant for the chlorinated organic circulation system
due to the high organic content of this stream.  No other
HAP emission points have been identified for the CRU or CRU
catalyst regeneration process.
3.3  SULFUR RECOVERY PLANT
     All crude oils contain some sulfur compound impurities.
Crude oils that contain relatively low levels of sulfur are
referred to as "sweet" crudes, while crudes that contain
high levels of sulfur are referred to a "sour" crudes.
Sulfur compounds are converted to hydrogen sulfide  (H2S) in
the cracking and hydrotreating processes of the refinery.
The H2S or "acid gas"  is removed from the process vapors
using amine scrubbers.  The amine scrubbing solution is
subsequently heated to release the H2S,  and the acid gas is
treated in the sulfur recovery plant to yield high purity
sulfur that is then sold as product.  The sulfur recovery
plant consists of one or more sulfur recovery units  (SRUs)
operated in parallel and may also contain one or more
                           3-17

-------
catalytic tail gas treatment units and/or a thermal oxidizer
(see Figure 3-6).
3.3.1  Glaus Sulfur Recovery Unit  (SRU) Process Description
     Sulfur recovery (the conversion of H2S to elemental
sulfur) is typically accomplished using the modified-Claus
process.  This is a multi-stage catalytic oxidation of H2S.
First, one third of the H2S is burned with air in a reaction
furnace to yield sulfur dioxide (S02) .   The S02 then reacts
reversibly with H2S in the presence of a catalyst to produce
elemental sulfur,  water, and heat.  Because the reaction is
reversible, the reaction occurs in a series of reactors, and
the vapors are cooled to condense the sulfur between each
reactor to drive the reaction towards completion.  Auxiliary
burners are used to reheat the gas stream prior to the next
reactor.  The gas from the final condenser of  the Glaus unit
(referred to as the "tail gas") consists primarily of inert
gases with less than 2 percent sulfur compounds.
3.3.2  Tail Gas Treatment Unit  (TGTU) Process  Description
     Tail gas treatment methods include any one or
combination of:   (1) catalytic reduction to convert as much
of the tail gas sulfur compounds to H2S (coupled with amine
adsorption or Stretford solution eduction);  (2) amine
adsorption to recover and recycle any H2S present in the
tail gas; and  (3) incineration to convert  the  remaining tail
gas sulfur compounds to S02.
     The most common tail gas catalytic reduction systems  in
use at refineries are:   (1) the Shell Glaus Offgas
Treatment  (SCOT) unit;  (2) the Beavon/amine system;  (3) the
Beavon/Stretford system; and  (4) the Wellman-Lord system.
                           3-18

-------
                                     Sulfur
                                   Condenser
                       Reaction
                       Furnace
            Sulfur
         Condenser
                 Steam
 U)

  i
                                          Catalytic
                                         Converter
LJ
                  Catalytic
                 Converter
 BFW = Boiler Feed Water

 * Additional converters/condensers to achieve additional
  recovery of elemental sulfur are optional at this point.
  Sulfur
Condenser
        . Steam
          *
                                                                                      BFW'
                       Sulfur Pit
                                                       Tail Gas
                                                                                                                  "-3
                                                                                                                  I
                                                             CO
Figure  3-6. Refinery MACT discussions:   process vents  Glaus sulfur recovery units.

-------
Except for the Wellman-Lord system, each of these systems
consist of a catalytic reactor and an H2S recovery system.
In either the Claus or Beavon reactor, the tail gas is
heated in the presence of hydrogen gas and a catalyst to
reduce most of the tail gas sulfur compounds to H2S.  The
off-gas from the catalytic reactor is typically quenched,
then routed to an amine scrubber or a Stretford solution to
strip the H2S from the tail gas.   The recovered H2S  is
recycled to the front of the Claus unit.  The overhead of
the amine scrubber or Stretford unit  (caustic scrubber) may
be vented to the atmosphere or incinerated to convert any
remaining H2S or other reduced sulfur compounds to S02.   The
total sulfur recovery efficiency of a Glaus/catalytic tail
gas treatment train can be 99.5 percent or higher.
     The Wellman-Lord uses thermal oxidation followed by
scrubbing with a sodium sulfite and sodium bisulfite
solution to remove S02.   The rich bisulfite solution is sent
to an evaporator-recrystallizer where the bisulfite
decomposes to SO2 and water and sodium sulfite is
precipitated.  Due to high capital, operating, and
maintenance costs, the Wellman-Lord system is not widely
used.12
3.3.3  Claus Sulfur Recovery Plant Emission Points
     The primary emission point from the sulfur recovery
plant is the final vent from the SRU, TGTU, or thermal
oxidizer, whichever is the last process unit in the
treatment train.  There may be a separate emission stack for
each SRU train; alternatively, the emissions from a couple
of SRU trains may be combined, e.g., prior to thermal
oxidation and release to the atmosphere.  A typical SRU vent
stack is approximately 4 feet in diameter and 100 feet tall.
A typical volumetric flow rate for an SRU vent stack ranges
from 8,000 to 40,000 scfm.  The primary HAP components of
the final sulfur plant vent are carbonyl sulfide  (COS) and
carbon disulfide  (CS2) .13  These HAP components are by-
products of the SRU and TGTU reactions; COS may also be a
product of incomplete combustion from a thermal oxidizer.

                           3-20

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     Sulfur recovery plants also have a potential for
fugitive HAP emissions from the sulfur recovery pits.  After
each reactor in the SRU, elemental sulfur is condensed and
removed from the SRU gas and the liquid sulfur is collected
and stored in bins.   There are limited data from a one
petroleum refinery that suggest that small amounts of HAP
are emitted from these sulfur recovery pits.14
     There is also a potential for fugitive emissions from
certain types of TGTUs, specifically the Stretford unit.
The Stretford unit employs a series of open vessels as part
of the solution circulation loop and a direct air contact
cooling tower to cool the Stretford solution.15   Limited
data were reported that suggest that small amounts of HAP
are emitted from these Stretford solution tanks.16
     There are a few refineries that operate non-Glaus type
SRUs.  All of the refineries that use non-Glaus SRU
technologies have very low sulfur production rates (2 long
tons per day or less).  There are several different trade
names for these "other" types of SRU, such as the LowCat,
Sulferox, and NaSH processes.  In general, these processes
operate at temperatures below 200F and yield a sulfur
product that has a much lower sulfur content (50 to 70
percent sulfur compared to 99.9 percent sulfur from the
Glaus process).  There are no HAP emissions data from these
other types of SRU.  Industry representatives claim that
these processes do not form COS and CS2 while treating the
sour gas, but these processes generally involve reactions
specific for H2S,  and they will not otherwise remove any COS
or CS2 that may be present in the sour gas.   That is,  the
non-Claus SRU are not expected to produce additional COS and
CS2,  but they may potentially emit any COS or 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 H2S treatment capacity in the United States),
the potential HAP emissions from non-Claus SRU are expected
to be minimal compared to Glaus SRU HAP emissions.
3.4  REFERENCES

                           3-21

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1.   Site Visit Report -- Girard Point Refinery: Sun
     Company.

2.   Site Visit Report -- Marcus Hook: Sun Company.

3.   Site Visit Report -- Coastal Eagle Point Company.

4.   Site Visit Report -- Star Enterprise.

5.   Site Visit Report -- Marathon Oil Company.

6.   U.S Environmental Protcetion Agency.  Petroleum
     Refinery Enforcement Manual.  Publication No. EPA-
     340/1-80-008.  Office of Enforcement and Compliance
     Assurance, Washington, DC.  March 1980.

7.   U.S Environmental Protcetion Agency.  EPA Office of
     Compliance Sector Notebook Project - Profile of the
     Petroleum Refining Industry.  Publication No. EPA/310-
     R-95-013.  Office of Enforcement and Compliance
     Assurance, Washington, DC.  September 1995.

8.   U.S Environmental Protcetion Agency.  Presumptive MACT
     for Petroleum Refinery Processs Vents:  FCC Units,
     Reformers, and Sulfur Plants.  Appendix B.  Summary of
     Emissions Data From the EPA Database on Petroleum
     Refinery Process Vents.  Publication No. XXXXX.  Office
     of Air Quality Planning and Standards, Research
     Triangle Park, NC.  November??? 1996.

9.   Reference 5.

10.  Reference 8.

11.  Reference 8.

12.  Personal communication  (e-mail) from Hathaway, Donna,
     Louisiana Department of Environmental Quality, to
     Lucas, Robert, U.S. Environmental Protcetion Agency,
     Office of Air Quality Planning and Standards.  Process
     Vent P-MACT - Some More Info.  February 8, 1996.

13.  Reference 8.

14.  Reference 12.

15.  Reference 8.
                           3-22

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    4.0  CONTROL TECHNOLOGY AND PERFORMANCE OF CONTROLS

     This chapter describes the control technologies
applicable to reduce HAP emissions from the three petroleum
refinery vents of interest (the CCUCR vent, the CRUCR vent
and the sulfur recovery plant vent).  It also presents a
summary of the available performance data of the control
technologies applicable for these three petroleum refinery
vents.
4.1  CCUCR VENT EMISSION CONTROLS
     There are two distinct types of emissions from CCUCR.
These are:   (!) metal HAP that are deposited on the catalyst
particles; and (2) organic HAP are products of incomplete
combustion.  As such, there are two different types of
emission control technologies considered for the CCUCR vent.
4.1.1  Metal HAP Emission Controls for the CCUCR Vent
     As the metal HAP are associated primarily with the
catalyst particles entrained in the CCUCR flue gas,
particulate emission control devices also provide metal HAP
emission control.  To be applicable to the CCUCR flue gas, a
particulate  (metal HAP) emission control device must be able
to treat large volumes of air continuously and reliably.  As
the CCU is often a critical process in a facility's refining
efforts, any shutdowns of the process due to control device
failure or maintenance must be minimized.  There are four
candidate particulate emission control devices that can
handle continuous, large volumes of flue gas.  These are:
cyclone separators, electrostatic precipitators (ESPs), wet
scrubbers, and fabric filters  (baghouses).
                            4-1

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     Cyclone separators use centrifugal force to separate
dust particles from gas streams. They have no moving parts,
and they can continuously and reliably process large volume
gas streams at the elevated temperatures typical of CCUCR
flue gases.  Cyclones are one of the least expensive dust
collection devices in terms of both operating and capital
investment costs, but they typically cannot meet the dust
removal efficiencies of ESPs, baghouses, and wet scrubbers.
Cyclones are generally applicable for dust particles with
diameters greater than 5 urn, but multiple-tube parallel
units may attain 80 to 85 percent collection efficiencies on
3 um diameter particles.1 Cyclone separators are used almost
universally within the CCUCR units to retain most of the
catalyst particles within the CCUCR unit.  Second and third
stage cyclones (i.e., cyclones in series) are commonly used
external to the CCUCR unit for dust removal.  By operating
cyclones in series, dust collection efficiencies are
reported to range from 90 to 98 percent.2
     ESPs use an electrostatic field to charge dust
particles within the gas stream. The charged particles
migrate to a grounded collection surface where they adhere.
The particles are then removed from the collection surface
periodically by vibrating or "rapping" the collection
surface.  The dislodged particles are then collected in
hoppers at the bottom on the ESP.  ESPs typically have a
high collection efficiency and can effectively remove
particles with diameters of less than 1 um.3 ESPs can
continuously and reliably process large volume gas streams
at the elevated temperatures typical of CCUCR flue gases,
and they are commonly used for particulate removal on the
CCUCR vent gases.
     Wet scrubbers use a liquid, usually water, to assist in
the particle collection process.  There are a number of
different types of wet scrubbing process equipment, 4 but
venturi type wet scrubbers are among the most efficient and
the most commonly used at refineries for the CCUCR vent.
Venturi wet scrubbers are typically designed for

                            4-2

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applications requiring very high removal efficiencies of
particles ranging in diameter between 0.5 and 5 um.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 um and
greater.6'7  However,  baghouses are typically designed to
operate at temperatures within 50 to 100 F of the gas
stream's dew point and generally cannot operate at
temperatures above 500 F.8  Therefore,  some pretreatment
(or heat recovery) of the CCUCR flue gas will be required
prior to a baghouse control device.  Additionally, baghouses
cannot provide continuous, long-term emission control due to
maintenance problems (e.g., clogged or torn bags) according
to air pollution control equipment representatives.9
     Selection of an air pollution control device for TCCU
is further complicated by the low operating pressure of the
TCCU regenerator.  Due to the pressure drops across the
control device, installation of an ESP, wet scrubber or
baghouse would require an induced draft fan to pull the
CCUCR flue gas through the control device.  The control of
this induced draft fan would be critically tied to the
process operations, making the application of these control
devices impracticable.  Single pass cyclone separators may
be applicable and may yield sufficient control due to the
larger size particles associated with the TCCU CCUCR vent.
The TCCU surge tank vent is not limited by the control
device pressure drop, but again, a cyclone separator may
provide adequate control based on the particle size
distribution of TCCU PM emissions.
     Many refiners operate a catalytic hydrotreating unit
and some of these refiners process a portion or all of the
CCU crude oil feedstocks in these hydrotreaters prior to the
CCU.  The hydrotreater removes sulfur, nitrogen, vanadium,

                           4-3

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nickel and other contaminants from the crude oil feedstocks.
This "pretreatment" step prior to the CCU typically helps to
improve CCU yield, prolongs catalyst life, and reduces CCU
HAP emissions, according to refinery representatives.10   Due
to the capital investment cost of hydrotreating units and
their functionality for individual refineries, hydrotreating
may not be a generally applicable emission reduction
technique for all petroleum refineries.  However, refiners
that operate a hydrotreating unit and process a portion or
all of the CCU feedstocks through the hydrotreater may
exhibit reduced metal HAP emissions compared to a similarly
operated CCU that does not hydrotreat the CCU feedstock.
4.1.2  Organic HAP Emission Controls for the CCUCR Vent
     Organic HAP emissions primarily originate as by-
products of coke combustion  (e.g., formaldehyde,
acetaldehyde, POM, dioxins and furans).  However, volatile
organic HAP such as benzene, toluene, xylenes, and hexane
are also reported for some CCUCR vent streams.11  These
volatile organic HAP may originate as residual oil feed
material on the catalysts that somehow vaporize, but do not
combust prior to exiting the CCUCR.  Presumably, these
organic HAP emission would be greater for units that operate
with insufficient oxygen  (i.e., incomplete combustion
CCUCRs).  From the data available for organic emissions
immediately following the CCUCR, it appears that incomplete
combustion CCUCRs have significantly higher organic HAP
emissions than complete combustion CCUCRs.12
     Due to the large volumes and the low concentrations of
organic HAP in the CCUCR flue gas, common organic HAP
emission control devices such as condensers and carbon
adsorption systems are not appropriate to control organic
HAP emissions from the CCUCR vent.  As the CCUCR flue gas is
already at high  (combustion) temperatures, catalytic
incineration would not be economically competitive with
traditional thermal incineration.  Thus, thermal
incineration or afterburning appear to be the only
                            4-4

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applicable air pollution control techniques to reduce
organic emissions from the CCUCR flue gas.
     Thermal incineration employs heat and oxygen to oxidize
(combust) organic chemicals, converting them to carbon
dioxide and water vapor at efficiencies of 99 percent or
higher.13'14  As the CCUCR flue gas stream  is already at
elevated temperatures, a minimum of auxiliary fuel would be
required to achieve effective afterburning.  Additionally,
for incomplete combustion CCUCRs, the CO  in the flue gas may
be sufficient to fuel the secondary combustion process.
Many incomplete CCUCRs already employ secondary combustion
devices, typically referred to as CO boilers, to combust CO
for the purpose of recovering the latent  heat in the CCUCR
flue gas.  From the organic emission data available at the
outlet of CO boilers and complete combustion CCUCRs, it
appears that complete combustion CCUCRs can achieve
comparable levels of organic HAP emission control as an
incomplete combustion CCUCR followed by a secondary
combustion unit.15
4.2  CRUCR VENT EMISSION CONTROLS
     As described in Section 3.2.3, there are three times
during the regeneration process that HAP  emissions can
occur.  These three emission points are:   (1) the initial
depressurization and purge vent;  (2) the  coke burn pressure
control vent; and  (3) the final catalyst  purge vent.
4.2.1 HAP Emission Controls for the CRU Purge Vent
     The initial depressurization and purge cycle removes
the hydrocarbons from the catalyst prior  to CRU catalyst
regeneration.  The vent gases from this initial contains
organic HAP such as benzene, toluene, xylene, and hexane.
During the initial depressurization process, these
hydrocarbons may be recovered by venting  the gas stream to
the refinery's fuel gas recovery system.  As this vent gas
stream hydrocarbon content becomes more dilute during the
purge cycle, venting to the fuel gas system may become
undesirable and an alternative air pollution control
                            4-5

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technique may de required.  Air pollution control devices
potentially applicable to this CRU purge vent stream include
combustion devices such as a flare or vapor incinerator and
carbon adsorption systems.
     Flares and vapor incinerators employ heat and oxygen to
oxidize  (combust) organic chemicals, converting them to
carbon dioxide and water vapor.   Although destruction
efficiencies of vapor incinerators may be slightly higher
than flare systems, flare systems typically achieve
destruction efficiencies of 98 percent or higher and they
are more suitable for the intermittent flows typical of the
CRU purge vent.1S
     Carbon adsorption may also be used to control organic
HAP emissions during the CRU hydrocarbon purge cycle.
Carbon adsorption systems remove organic chemicals from gas
streams by selective adsorption onto the surface of
activated carbon.  There are two general types of carbon
adsorption systems: regenerative and non-regenerative.
Regenerative carbon systems offer an advantage over
destructive emission control devices when the adsorbed
organics can be economically desorbed and recovered.
However, due to the low flow and intermittent nature of the
CRU purge vent stream, non-regenerative  (or canister) carbon
adsorption systems are probably most economical for the CRU
purge vent.  When the adsorbed organics cannot be recovered
or when non-regenerative carbon systems are used, carbon
adsorption has the disadvantage of creating a solid waste
material that requires proper disposal  (sometimes as a
hazardous waste) .17-18-19
4.2.2 HAP Emission Controls for the CRUCR Coke Burn Vent
     The primary HAP emitted during the coke burn cycle is
HC1.  Caustic injection, caustic scrubbing, and wet
scrubbing are all applicable air pollution control
techniques for removing HC1 from the CRUCR coke burn flue
gas.  Wet scrubbers use a liquid, usually water, to effect
removal of the desired pollutant.  For vapor phase
pollutants, scrubbing typically removes the pollutant by

                            4-6

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absorption into the liquid phase.  Since HC1 is readily
soluble in water, wet scrubbing or absorption (with or
without caustic addition) can achieve high HC1 removal
efficiencies (98 percent or higher).20'21
4.2.3 HAP Emission Controls for the CRUCR Final Purge Vent
     The final purge and reduction cycle vent gases from may
contain low levels of the chloriding agent (trichloroethene
or perchloroethene) and residual HCl or C12.   Safety
considerations  (i.e., the presence of oxygen) may restrict
the venting of the final purge cycle vent gases to the fuel
gas system.  However, the purge gases may be directly vented
to a combustion device  (e.g., flare, process heater, or
incinerator),  a carbon adsorption system, or a wet gas
scrubber (absorption).  Each of these types of air pollution
techniques have been previously described in this section.
If the primary HAP pollutants in the final CRUCR purge cycle
are organics,  then either combustion or carbon adsorption
are most appropriate.  If HCl or C12 are the primary HAP
from this vent at a given facility, then wet scrubbing is
probably the most appropriate control device.  The
suitability of carbon adsorption may depend on the
concentration of HCl in the vent stream because carbon has a
low adsorption capacity for HCl and there is a potential for
HCl condensation within the adsorption unit.22  Application
of thermal control devices may also be limited depending on
the concentration of chlorine or chloride containing
chemicals in the vent stream.  Combustion of chlorinated
organics produces HCl and provides the potential for the
formation of chlorinated dioxins and furans.23
4.3  SULFUR PLANT VENT EMISSION CONTROLS
     The primary HAP components of the final sulfur plant
vent are carbonyl sulfide  (COS) and carbon disulfide  (CS2).
These HAP components are by-products of the reactions in the
SRU reactors; COS may also be a product of incomplete
combustion from a thermal oxidizer.  There are two generally
applicable emission control techniques for the SRU vent.
                            4-7

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These are either the use a TGTU or a thermal oxidizer (or
both).
4.3.1 TGTU as a HAP Emission Control for the SRU Vent
     By recovering sulfur from the SRU tail gas, TGTUs are
expected to reduce the concentration of sulfur containing
compounds (HAP) in the sulfur plant vent as compared to a
similar SRUs with no TGTU.  Different types of TGTUs were
described in Section 3.3.3.  A typical TGTU recovers
approximately 95 percent of the sulfur remaining in the SRU
tail gas (i.e., a combined SRU/TGTU sulfur recovery
efficiency of over 99.5 percent}.24  At  this  time,  the EPA
has insufficient data to determine if the sulfur recovery
efficiency of a TGTU is directly correlated to its HAP
emission reduction or whether a given TGTU provides greater
HAP emission reduction than any other TGTU.  It appears that
certain TGTUs may have a higher potential for secondary
(fugitive)  emissions due to the type of TGTU process used
(e.g.,  Stretford units may have secondary emissions from the
handling and storage of the Stretford eduction solution).
     Thermal and catalytic oxidizers or combustion units are
also applicable air emission control devices to reduce the
HAP emissions from the sulfur plants.  Thermal and catalytic
oxidizers convert  (combust) reduced sulfur compounds to
sulfur oxides  (SOX) .   Thermal and catalytic oxidizers may be
applicable for nearly all SRU vents regardless of the
presence or absence of a TGTU  (although they may not be
appropriate following an oxidative TGTU process such as a
Wellman-Lord TGTU).  The destruction or oxidation efficiency
of reduced sulfur compounds, including COS and CS2, 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 Engineers'
     Handbook, 5th Edition.  McGraw-Hill Book Company, New
     York,  New York.  1973.  p. 20-82.
2.   ???
                            4-8

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3.    U.S Environmental Protection Agency.   Handbook -
     Control Technologies for Hazardous Air Pollutants.
     Publication No.  EPA/625/6-91/014.   Office of Research
     and Development,  Washington,  DC.   June 1991.  pp.  4-80
     through 4-90.

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

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

6.    Reference 3.  p.  4-64.

7.    Mclnnes, R. , K.  Jameson, and D. Austin.   "Scrubbing
     Toxic Inorganics."  Chemical Engineering. September
     1990.  pp. 116 through 121.

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

9.    ICAC Meeting Minutes Memorandum.

10.   Site Visit Report.

11.   PMACT Document - Emission Data.  Appendix B.

12.   Reference 11 (or API Database).

13.   Mclnnes, R., S.  Jelinek, and V. Putsche.   "Cutting
     Toxic Organics."  Chemical Engineering. September 1990.
     pp. 108 through 113.

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

15.   Reference 11.

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

17.   U.S Environmental Protection Agency.   Internal
     Instruction Manual for ESD Regulation Development -
     Carbon Adsorption Control for Organic Emissions.
     Office of Air Quality Planning and Standards, Research
     Traingle Park, NC.  March 1993.

18.   Reference 13.

19.   U.S Environmental Protection Agency.   OAQPS Control
     Cost Manual.  Publication No. EPA/450/3-90-006.  Office
     of Air Quality Planning and Standards, Research
     Traingle Park, NC.  January 1990.  pp 4-1 through 4-44.

20.   Reference 7.

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

22.   Reference 17.
                           4-9

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

24.  Gore,  B.  G.   "Tail Gas Cleanup Process Technology."
     Energy Progress, Vol. 6, No. 2.  June 1986.  pp. 84
     through 90.

25.  Reference 3.
                           4-10

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          5.0  MODEL PLANTS AND EMISSION ESTIMATES

     This chapter presents the derivation of controlled and
uncontrolled emission factors for hazardous air pollutants
(HAP) and applies them to three different sizes of model
plants to provide an estimate of the potential level of
emissions on a plant basis.  In addition, the emission
factors are applied on a nationwide basis to estimate
controlled and uncontrolled emissions from the entire
industry for the three processes of interest:  catalytic
cracking unit  (CCU) regeneration, catalytic reforming unit
(CRU) regeneration, and sulfur recovery units (SRUs).
5.1  MODEL PLANTS
     The three model plants used to represent small, medium,
and large facilities for the purpose of presenting typical
levels of emissions are given below.
Model plant capacities
No.
1
2
3
Size
Small
Medium
Large
Crude oil
(bbl/dav)
25,000
75,000
200,000
Catalytic
cracking
{ bbl/dav)
8,300
25,000
70,000
Catalytic
reforming
(bbl/dav)
6,300
19,000
50,000
Sulfur
recovery
(Itons/d)
30
120
480
bbl = barrels
5.2  HAP EMISSIONS FROM CCU REGENERATION
                            5-1

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     Data for HAP emissions were compiled by the EPA using
information provided through a variety of sources and are

documented in References 1 and 2.   A summary of the
emissions data is given in Appendix B.  The emissions data

were reported in responses to information collection
requests and follow-up surveys by the American Petroleum

Institute (API) the National Petroleum Refiners Association

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

EPA.  The approach used to estimate HAP emissions in this

section attempts to provide a range of "best estimates"

rather than an extreme range based on the absolute highest

and lowest values reported.  Estimates are provided only for

those compounds that were actually detected and quantified.

The original data base contained several entries for

pollutants that were not detected, and the detection limits

were reported and included with other information based on

actual measured values.

     The analysis of HAP emissions from CCU regeneration is

based on the following approach:


1.   Estimates are not provided for pollutants that were not
     detected, even when they are reported in the survey
     results at the detection limits.  In addition, if there
     was only one facility that reported the presence of a
     specific compound that was not verified by any other
     information, that value was flagged and was not used in
     the estimates of total HAP emissions.

2.   When the extremes of the range for a given pollutant
     differ by an order of magnitude or more from the bulk
     of the data, the extreme high and/or low values are not
     used to estimate a representative range of emissions
      (i.e., these values are treated as outliers).  However,
     the tables clearly note when an extremely high or low
     value is not used in the analysis.

3.   The data for CCU regeneration were mostly for units
     that controlled emissions with the destruction of
     organic compounds in a carbon monoxide  (CO) boiler and
     control of particulate matter by cyclones and an
     electrostatic precipitator (ESP).  Because of the
     combustion process, it is difficult to determine if the
     measurements made after the CO boiler represent
     products of incomplete combustion and/or by-products or
     if they represent the residual of compounds that were
                            5-2

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     not completely destroyed.   For example,  formaldehyde,
     acetaldehyde,  and polycyclic organic matter (POM)  may
     actually be formed in the CO boiler as by-products of
     combustion or they may be present before combustion in
     larger quantities.  For this analysis, the data for
     organic HAP (generally after the CO boiler) are used to
     derive emission factors for controlled organic HAP
     emissions.  Uncontrolled organic HAP emissions are
     estimated based on a assumption that the controlled
     emission factors represent 98 percent destruction
     (i.e., the uncontrolled emission factors are assumed to
     be 50 times the controlled emission factors).   This
     emission factor is applied only to units using partial
     combustion that do not vent to a CO boiler or other
     combustion device.  For complete combustion units,
     emissions of organic HAP are estimated from the
     "controlled" emission factors.

4.    Estimates of uncontrolled emissions of HAP metals for
     CCU regeneration are based on the measurements after
     the control device and the assumption of a nominal
     control efficiency of 95 percent for the ESP.

5.    Based on a review of the data, no distinction could be
     made in emission factors for CCUs using partial
     combustion and those using complete combustion.  A
     significant difference would be expected in the
     uncontrolled emissions from the two different types of
     combustion processes; however, the difference in
     organic compound emissions may be much less after
     combustion in a CO boiler.  In addition, 32 of the 34
     CCUs using partial combustion in the current data base
     were identified as having controls (e.g., CO boiler),
     and only 2 were identified as having no controls.
     Consequently,  uncontrolled emission factors for partial
     combustion processes may not be important in
     determining nationwide emissions.

6.    The data were inconclusive as to whether hydrotreating
     had any effect on the emission factors for HAP metals;
     consequently,  this analysis uses the same emission
     factors for units that hydrotreat as for those that do
     not.

     The range of controlled emission factors for organic

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

5-1 and the range for controlled metal HAP and HC1 is given

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

emissions per million barrels of CCU throughput  (Ib/mm bbl).

Nickel was the most commonly reported metal HAP and was also
                           5-3

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the one reported in the highest quantities.  The range and
midrange for the emission factors are given in Table 5-3.
     Using the approach and assumptions discussed above,
these factors were applied to the model plants to estimate
uncontrolled and controlled emissions.  The results are
given in Table 5-4 for the sum of organic, metal HAP, and
HC1.   The results for the model plants indicate that the
units with particulate matter controls probably have metal
HAP emissions that total less than a ton per year.
     Nationwide emission estimates for CCU regeneration were
derived based on CCU capacity and control devices in place.
Based on data from API3,  information on emission controls
was available for plants with 4.5 million bbl/day of CCU
capacity out of a total nationwide capacity of 5.2 million
bbl/day.  Approximately 27 percent of the nationwide
capacity did not have control devices in place for PM
{1,400,000 bbl/day).  In addition, only 47,000 bbl/day of
the total capacity was projected to have no controls for
emissions of organic compounds  (i.e., uncontrolled units
using partial combustion).  Nationwide emission estimates
are given in Table 5-5 for the baseline (current level of
control) and for the "controlled" case, which assumes that
all units control metal HAP and organic HAP.
                            5-4

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              TABLE  5-1.
SUMMARY OF ORGANIC HAP DATA FROM  CCU REGENERATION
        (from References 1 and 2)
Compound

1 , 3 -Butadi ene
Acetaldehyde
Benzene
Cyanide
Formaldehyde
HCN
Phenol
POM3
Toluene
Ul
i Xylene
<_n PCDF4
HCDF5
Total VOCs6
Totals
Emission factor
range (Ib/mm bbl)1
Lower
0.0008
1.7
0.73
28
2.7
14
0.74
0.15
0.26
3.2
5.56-07
l.le-06
78
51
Upper
0.05
48
12
36
950
194
41
3
2.5
3.2
5.5e-07
l.le-06
1,240
1,290
Number2

2
6
5
2
7
5
5
2-5
2
1
1
1
9

Comments

all after CO boiler
after CO boiler
after CO boiler
all after CO boiler
after CO boiler, excludes two very high values
with and without CO boiler, excludes one high and
one low value
with and without CO boiler
most after CO boiler and ESP
all after CO boiler; excludes one very high value
after CO boiler
after CO boiler and ESP
after CO boiler and ESP
after CO boiler or complete combustion CCUCR







DRAFT
I
0
H1
VO
CO
1   Ib/mm bbl = pounds per million barrels.
2   Number of facilities reporting detectable quantities of the compound.
3   POM = polycyclic organic matter determined from the sum of individual  compounds in Appendix B.
4   Total pentachlorodibenzofuran.
5   Total hexacholordibenzofuran.
6   Total volatile organic compounds  (as reported in Ref. 2; not included  in HAP  totals).

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 TABLE 5-2.  SUMMARY OF CONTROLLED METAL HAP EMISSIONS AND
 HC1  DATA FROM CCU REGENERATION (from References 1 and 2)
Compound
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Cobalt
Lead
Manganese
Mercury
Nickel
Selenium
Totals
HC1
Emission factor
{lb/mm bbl)
0.0032
0.0010
0.0020
0.0040
0.0430
0.0075
0.1100
0.1400
0.0010
0.0022
0.0062
0.32
528 2
range
a
10.0
1.7
0.1
2.8
15.2
1.5
8.2
19.7
0.6
43.0
29.4
132
,300
Number13
8
8
5
8
12
6
10
9
8
21
8

2
a lb/mm bbl = pounds per million barrels.
b Number of facilities reporting detectable quantities.
    TABLE 5-3.
                SUMMARY OF HAP EMISSION FACTORS FOR CCU
                       REGENERATION
HAP and type of control Emission

Total
Total
Metal
Metal
HC1

organics-controlled
organics -uncontrolled3
HAP-controlled
HAP-uncontrolledb

Lower
51
2,550
0.32
6
528
factor range (lb/mm
bbl)1
Upper
1,290
64,500
132
2,640
2.300
Midranae
670
33,500
66
1,320
1,400
8 Assumes controlled emissions represent 98 percent
destruction; applied only to uncontrolled partial  combustion
niri f-es
units.
units.
b Assumes controlled emissions represent 95 percent removal
                            5-6

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TABLE 5-4.  SUMMARY OF RANGE OF POTENTIAL HAP EMISSIONS FOR
           CCU REGENERATION FROM THE MODEL PLANTS
Model plant
Capacity
(bbl/day)
Total organic-
1
8,300
3.9 - 98
2
25,000
12 - 294
3
70,000
33 - 820
                 a
uncontrolled
partial
combustion {tpy)

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)

HC1                 0.8-3.5     2.4-10.5     6.7-29

    bbl/day = barrels per  day.
    tpy = tons per year.

  a       Applied only to partial combustion units that do
         not vent to a CO  boiler or other combustion
         device.

  b       The vast majority of the larger units use a PM
         control.  Consequently, these estimates are
         probably most relevant for CCUs in the size range
         of Model Plants 1 and 2.
                            5-7

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 TABLE 5-5.   SUMMARY OF NATIONWIDE EMISSIONS ESTIMATES FOR
                      CCU REGENERATION
Case
Baseline


Controlled0


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 EMISSIONS FROM CRU REGENERATION
     The data available for HAP emissions from CRU
regeneration were compiled by EPA (References 1 and 2) and
are presented in Appendix B.  Additionally, data from one
emission source test was available to estimate emission
factors for dibenzofurans both before and after a temporary
carbon adsorption control device  (Reference 4}.  The
emission factors developed for CRU regeneration are
summarized in Table 5-6.  There were very limited emission
data for nearly all HAP except chlorine  (C12)  and hydrogen
chloride (HCl) from uncontrolled CRU.  Additionally, nearly
all of the C12 and HCl emission data are from continuous or
cyclic CRU catalyst regeneration.  Therefore,  a single
emission factor was developed and applied to all CRU
regardless of the type of regeneration employed,  whether
cyclic, continuous, or semi-regenerative.
                           5-8

-------
     Most of the data for benzene, toluene,  and xylene were
from measurements after combustion in a process heater, and
information supplied by the industry indicated that organic
emissions are typically controlled by venting to a
combustion device.  A range of 23 to 28 Ib per million
barrels was developed to represent emissions of organic HAP
from CRU regeneration following combustion.   No
"uncontrolled" emission factor was developed for organics
from CRU catalyst regeneration.
     There are two sets of data regarding the emissions of
HAP metals during CRU regeneration.  Although these two sets
of data yielded metal HAP emission factors that varied by
four orders of magnitude, even the upper range emission
factor was very low.  Applying the upper range metal HAP
emission factor for the largest model plant CRU yields
emissions of only 1 Ib/yr.  Based on these limited and
disparate metal HAP emission data, it was appears that metal
HAP emissions from CRU is either negligible or non-existent.
     Data were available for chlorine and HCl both before
and after control, although most of the data represented
uncontrolled emissions.  Comparing the emissions range for
controlled versus uncontrolled emissions, it appears that a
control efficiency of approximately 99 percent may be
achieved.  However, based on an evaluation of the available
process data, the level of HCl scrubber control devices in-
place at semi-regenerative CRU are significantly different
than those in-place at continuous and cyclic CRU units.
Therefore, the midrange value of 4,450 Ib/million barrels
was used to estimate uncontrolled emissions and the emission
factors for controlled units were then calculated using this
uncontrolled emission factor and the nominal emission
control efficiency for the specified level of HCl scrubber
control(either 92 or 97 percent).
     The emission factors for CRU regeneration are
summarized in Table 5-7.  These factors were applied to the
model plants in Table 5-8 to estimate typical plant
emissions.  The results in Table 5-8 show that controlled

                           5-9

-------
emissions of all HAP from CRU regeneration total at or less
than a ton per year for the midrange CRU and total between 1
and 3 tons per year for large CRU.
     The major HAP from uncontrolled CRU regeneration is
HCl, which was reported by numerous facilities at rates
comparable to the upper end of the range shown for the model
plants.  Due to the different level of HCl scrubber control
devices in-place at semi-regenerative CRU compared to those
in-place at continuous and cyclic CRU units, separate
estimates are provided for semi-regenerative CRU and
continuous/cyclic CRU in developing the nationwide estimates
of emissions from CRU regeneration.  From the available
process data, semi-regenerative CRU processed 1.63-million
barrels per day of feedstock; 73 percent of that throughput
is controlled by single-stage (assumed 92 percent efficient)
scrubbers and 4 percent is controlled by multiple-stage
(assumed 97 percent efficient) scrubbers.  Cyclic and
continuous reformers combined processed 2.02-million barrels
per day of feedstock and 38 percent of that throughput is
controlled by multiple-stage scrubbers, with only 6 percent
controlled by single-stage scrubbers.  The nationwide
estimates of baseline and controlled emissions from CRU
regeneration are summarized in Table 5-9.  The estimates for
controlled emissions assume that all uncontrolled semi-
regenerative CRU regeneration vents are equipped with
single-stage scrubbers to remove HCl at an efficiency of 92
percent, and all continuous and cyclic CRU regeneration
vents are equipped with multiple-stage scrubbers to remove
HCl at an efficiency of 97 percent.
                           5-10

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TABLE 5-6.
SUMMARY OF HAP DATA FROM CRU REGENERATION
  (from References 1 and 2)
Compound
Benzene
Toluene
Xylene
PAHC
Dibenzofurans
Tetrachloro
Pentachloro
Hexachloro
Heptachloro
Octachloro
Total
Total orcianic
Chlorine
HC1
Total Cl HAP
Chlorine
HC1
Total Cl HAP
Emission factor Numberb Comments
range (Ib/mm bbl)a
1.5
9.6
7.0
4.5

2.8 E-09
4.5 E-09
7.4 E-09
BDL
BDL
1.5 E-08
23
0.26
0.06
0.32
0.44
34
34
6.5
9.6
7.0
4.5

8.4 E-09
1.6 E-08
2.4 E-08
1.4 E-08
3.1 E-09
9.3 E-08
28
0.26
4.0
4.3
440
8,430
8,870
3
1
1
1

1
1
1
1
1
1

1
2

10
20

After control
After control
After control
After control

(d)'
(d)
(d)
(d)

-------
    TABLE 5-7,
SUMMARY OF HAP EMISSION  FACTORS FOR CRU
       REGENERATION
 HAP and type  of
 control
       Emission  factor range (Ib/mm bbl)1
                          Lower

 Total organicsa           23

 Clb HAP-uncontrolled      34

 Cl HAP-controlled
                      Upper

                         28

                      8,870
              Midranqe

                 25

                4,450

              130-360
a Based on venting  to  a  combustion device.
b Includes HCl and  chlorine.
c Controlled emission  factor  range calculated based on
uncontrolled emission  factor  assuming a 92 to 97 percent
removal efficiency.
  TABLE 5-8.   CRU HAP EMISSION ESTIMATES FOR MODEL PLANTS
 Model plant	1	

 Capacity (bbl/day)       6,300

 Organics(tpy)        0.026 - 0.032
 Cl HAP-
 uncontrolled (tpy)

 Cl HAP-controlled
 (tpy)	
         5.1


      0.2 - 0.4
  19,000

0.08  -  0.10

    15


 0.5  -  1.2
  50,000

0.21  -  0.26

    40


 1.2  -  3.2
bbl/day = barrels  per day.
tpy = tons per year.
Ib/yr = pounds per year.
                            5-12

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

 Condition      HAP                   Emissions  (tpy)
Baseline3

Controlled"

Organics
HC1 and C12
Organics
HC1 and Cl,
15 - 19
1,350
15 - 19
150
   a Baseline estimates for HC1 and C12 are based on
     1,306,000 bbl/day of capacity with single stage
     scrubbers, 814,000 bbl/day of capacity with multiple
     stage scrubbers and 1,529,000 bbl/day of capacity
     without scrubbers.
   b Controlled estimates assume 1,577,000 bbl/day of
     capacity is equipped with single stage scrubbers and
     2,072,000 bbl/day of capacity is equipped with multiple
     stage scrubbers.
5.4  HAP EMISSIONS FROM SULFUR RECOVERY UNITS (SRUs)
     The major HAP from sulfur recovery units are carbon
disulfide  (CS2)  and carbonyl sulfide (COS).   The data for
these compounds are summarized in Table 5-10 and were
obtained primarily from responses to section 114 requests.5'6
(See Appendix B for more details.)  These data represent HAP
emissions following the incinerator and show a range of 29
to 285 Ib per 1,000 long tons per day  (Itpd) of sulfur
production capacity.  To estimate potential emissions from
units that do not have an incinerator, a destruction
efficiency of 98 percent was assumed, which yields an
uncontrolled emission factor of 1,450 to 14,250 lb/1,000
Itpd.
     These emission factors were applied to the model plants
in Table 5-11 to estimate typical plant emissions.
Nationwide emission estimates are based on survey data
provided by NPRA.6  The SRU database contains capacity
information on 161 units nationwide with a total sulfur

                           5-13

-------
pruduction capacity of 18,880 Itpd.  The database contains
process type and control information for 140 SRU and 120 of
these units were identified as having an incinerator (or
were subject to the NSPS for SRUs).  The capacity of these
controlled units was estimated as  15,470 Itpd, and the
capacity of units without incinerators was estimated as
3,410 Itpd.  These capacity estimates were used with the
emission factors to estimate nationwide emissions in
Table 5-11.

TABLE 5-10.  SUMMARY OF HAP EMISSIONS DATA FOR SRU VENTS 7'8
Plant ID
20501
20701
20604
G
F
Range
HAP
CS2
COS
COS
COS
COS, CS2

Emissions (lb/1,000
29
285
171
50
180
29 - 285
Itpd)






     TABLE 5-11.  HAP EMISSION ESTIMATES FOR SRU VENTS
                        (COS and CS2>
Model plants
Size (Itpd)
Uncontrolled (tpy)
Controlled (tpy)
30
7.9 -
0.16 -
120
78 32 - 310
1.6 0.6 - 6.0
480
130 - 1,250
2.5 - 25
Nationwide1
 Baseline (tpy)
 Controlled (tpy)
980 - 9,700
100 - 1,000
   1 Nationwide estimates based 15,470 Itpd of sulfur
     produced in controlled units and 3,410 Itpd of
     sulfur produced in uncontrolled units.
5.5  REFERENCES
1.   Letter from David Hansell, EER, to Robert Lucas,
     U.S.EPA, transmitting the API CCU and CRU Data Base
     Summary  (Draft).  December 20, 1996.
                           5-14

-------
2.   Letter from David Hansell,  EER, to Robert Lucas,
     U.S.EPA,  transmitting the Detailed API CCU and CRU Data
     Base (2nd Draft).  January 23, 1997.

3.   Database spreadsheet provided by David Hansell, EER,  to
     Robert Lucas, U.S.EPA, updating the API database,  April
     1997.

4.   Radian Corporation.  Results of Dioxin Testing on the
     Catalytic Reformer Unit #1 Exhaust; Texaco Refinery;
     Bakersfield, California.  Final Report.  August 8,
     1991.

5.   U.S Environmental Protection Agency.  Responses to
     Information Collection Request for Petroleum
     Refineries.  Office of Air Quality Planning and
     Standards, Research Triangle Park, NC.  1992.

7.   U.S. Environmental Protection Agency.  Presumptive MACT
     for Petroleum Refinery Process Vents:  FCC Units,
     Reformers, and Sulfur Recovery Plants.  Appendix B-
     Summary of Emissions Data.   Office of Air Quality
     Planning and Standards, Research Triangle Park, NC.
     1997.

8.   Letter from Norbert Dee, NPRA, to Robert Lucas,
     U.S.EPA,  transmitting SRU Database.  June 12, 1997.
                           5-15

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            I :,



        .1.: '.
(This page intentionally left blank)

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   6.0  OTHER ENVIRONMENTAL AND ENERGY IMPACTS ESTIMATES

     This chapter presents estimates the environmental
impacts, other than HAP emission reduction, and the energy
impacts associated with the control technologies applicable
for the three petroleum refinery process vents.  Many of the
other environmental and energy impact estimates are based on
control device design algorithms from EPA's Control Cost
Manual.1  The control equipment design parameters  are,
therefore, summarized in Chapter 8 of this document and only
the applicable environmental and energy impacts are provided
in this chapter.  For more details on the control device
design parameters, the reader is referred to Chapter 8.
6.1  OTHER ENVIRONMENTAL IMPACTS FOR CCUCR VENTS
     The primary impacts from the operation of ESPs to
control metal HAP emissions from the CCUCR vent are the
added energy requirements of the ESP and the exhaust fan.
These energy requirements were estimated based on the
control device designs for model CCUCR units as described in
Chapter 8.  The ESP will also collect particle fines from
the CCU vent stream that will require disposal as a non-
hazardous solid waste.  The quantity of CCU fines requiring
disposal was calculated in the costing algorithm from the
particle loading to the ESP.
     There are two additional considerations in estimating
the other environmental impacts of operating a wet scrubber
emission control device for the CCUCR vent.  First, the wet
scrubber also creates a wastewater stream which contains the
CCU fines.  It is assumed that the CCU fines are first
settled (removed) from the wastewater stream and that the
wastewater stream then requires additional treatment and
                            6-1

-------
disposal.  The costing algorithm assumes that the total
weight of the settled solids is 2 times the particle loading
to the wet scrubber.  The amount of water requiring
treatment and disposal is also estimated from the control
cost algorithms.
     The second consideration in estimating the other
environmental impacts of operating a wet scrubber emission
control device is the scrubbers ability to also remove
sulfur oxides (SOX,  which includes both S02  and  S03) .  The
amount of SOX in the CCUCR 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 SO2 and 50 ppmv SO3) 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 CCUCR units.
     Due to the relatively high CO content of incomplete
combustion CCUCR exhaust gases, energy may actually be
recovered using a combustion device on this vent stream.
Additionally, refineries may be expected to have additional
fuel gas that could be used to stabilize the incinerator
flame.  However, it is assumed that energy is not being
recovered from the CCUCR vent incinerator except for heat
recovery as specified in the control cost's incinerator
design and that natural gas is used to stabilize the
incinerator flame for the purposes of estimating other
environmental and energy impacts.  The incinerator uses both
electricity  (for the exhaust fan) and natural gas.
Table 6-2 summarizes the other environmental and energy
                            6-2

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



               FOR INORGANIC HAP EMISSION CONTROL DEVICES  FOR THE  CCUCR VENT.
i


LO
Control Device/
Annual Impact
ESP
Electricity Use
(1,000 kW-hr)
Solid Waste (tons)
Venturi Scrubber
Electricity Use
(1,000 kW-hr)
Solid Waste (tons)
Water Consumption
(1E+06 gallons)
SOX Emissions1
( tons )
Small CCU
w/o CO
Boiler

470
180
w/ CO
Boiler
Medium CCU
w/o CO
Boiler

630
240
1,730
680
w/ CO
Boiler
Large CCU
w/o CO
Boiler
w/ CO
Boiler

2,200
860
4,400
1,710
6,290
2,450

390
370
130
(300)
520
490
170
(400)
1,420
1,350
470
(1,100)
1,810
1,720
600
(1,400)
3,620
3,430
1,200
(2,800)
5,170
4,910
1,720
(4,000)
I
(D
                                                                                       CD
     1Brackets  around other emission impact estimates indicate emission reductions

-------
 TABLE 6-2.  ANNUAL OTHER ENVIRONMENTAL AND ENERGY  IMPACT
       ESTIMATES  FOR MODEL  CCUCR VENT  INCINERATORS.
Annual Impact
Electricity Use
(1,000 kW-hr)
Natural Gas Consumption
(1E+06 cubic feet)
Small
ecu
600
31
Medium
ecu
2,190
114
Large
ecu
5,580
290
impacts for a thermal incinerator used to destroy organic
HAP in the CCUCR vent model units.
     Nationwide estimates of other environmental and energy
impacts were developed using the throughput of units
anticipated to add control devices for CCU units(i.e., the
same assumptions used to estimate the emission reductions
presented in Chapter 5).   The other environmental and energy
impacts were estimated two separate ways based on the type
of inorganic HAP emission control device installed.  The
first analysis assumes all units install an ESP; the second
analysis assumes all units install a venturi scrubber.  The
nationwide impacts estimates for both these analyses are
presented in Table 6-3.
6.2  OTHER ENVIRONMENTAL IMPACTS FOR CRUCR VENTS
     The types of other environmental and energy impacts
associated with wet scrubbing to remove HCl from the CRUCR
vent stream include electricity use for fans and pumps and
the production of a wastewater stream that requires
treatment and disposal.  These impacts are directly
estimated from the control cost algorithms for the model
CRUCR units as described in Chapter 8.  The other
environmental and energy impacts estimates for the CRU vent
model units are summarized in Table 6-4; the nationwide
                           6-4

-------
other environmental and energy impacts estimates for the

CRUCR units are provided in Table 6-5.
TABLE 6-3.  NATIONWIDE ANNUAL OTHER ENVIRONMENTAL AND ENERGY
            IMPACTS ESTIMATES  FOR THE CCUCR VENT1
Nationwide Annual
Impact
Electricity Use
(1E+06 kW-hr)
Solid Waste (tons)
Wastewater Production
(1E+06 gallons)
SOX Emissions (tons)
Natural Gas Consumption
(1E+06 cubic feet)
ESP/
Incinerator
100
41,200
0
0
31
Venturi
Scrubber/
Incinerator
87
82,500
28,900
(67,200)2
31
   1 Based on adding an inorganic HAP control device
     (either an ESP or a venturi scrubber) for
     1,400,000 bbl/day of CCU capacity and adding an
     organic HAP control device (incinerator) for
     47,000 bbl/day capacity.

   2 Brackets around emission impact indicate an
     emission reduction.
                            6-5

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TABLE 6-4.  OTHER ENVIRONMENTAL AND ENERGY  IMPACTS ESTIMATES
                FOR MODEL PLANT CRUCR VENTS
NO.
1
2
3
4
5
6
7
8
9
CRUCR Type
Semi-Regen.
Semi-Regen.
Semi-Regen.
Cyclic
Cyclic
Cyclic
Continuous
Continuous
Continuous
CRU
Throughput
Range
(1,000 bpd)
0 to <15
15 to 30
>30
0 to <15
15 to 30
>30
0 to <15
15 to 30
>30
Annual
Electricity
Use
(kW-hr)
349
621
1,160
1,360
2,270
4,090
1,230
2,050
4,090
Annual
Wastewater
Production
(1,000 gal)
39
70
130
57
95
170
51
86
170
TABLE 6-5.  NATIONWIDE ANNUAL OTHER ENVIRONMENTAL AND ENERGY
            IMPACTS ESTIMATES  FOR THE CRUCR VENT1
CRUCR Type
Annual
Electricity
Use
(fcW-hr)
Annual
Wastewater
Production
(1,000 gal)
Semi -Regenerative 13,000 1,460
Cyclic/Continuous 113,000 4,750
Total 126,000 6,210
   1 Based on facility specific analysis of size and
     type of CRUCR using impact factors presented in
     Table 6-4.  Total throughput of CRU units adding
     controls was 1,529,000 bbl/day.
6.3  OTHER ENVIRONMENTAL IMPACTS FOR SRU VENTS

     The environmental and energy impacts associated with

the SRU vent emission controls include both electricity and

natural gas consumption as well as additional SOX emissions

due to the conversion of reduced sulfur compounds to SOX.
                            6-6

-------
The energy impacts are directly estimated from the control
cost design algorithms for the model SRU incinerators as
described in Chapter 8.  The SOX emissions estimates are
based on the reduced sulfur compound inlet concentration of
4,000 ppmv (as used in the incinerator design) and one mole
SOX produced  per mole of  reduced sulfur compound in
incinerator inlet.  Table 6-6 summarizes the other
environmental and energy impacts estimates for model SRU
units.  Table 6-7 presents the nationwide other
environmental and energy impacts estimates for SRU vents.
  TABLE 6-6.   ANNUAL OTHER ENVIRONMENTAL AND ENERGY IMPACT
         ESTIMATES FOR MODEL SRU VENT INCINERATORS.
Annual Impact
Electricity Use
(1,000 kW-hr)
Natural Gas Consumption
(1E+06 cubic feet)
SOX Emissions (tons)
Small
ecu
135
11
336
Medium
ecu
539
44
1,340
Large
ecu
2,160
178
5,380
   TABLE 6-7.  NATIONWIDE OTHER ENVIRONMENTAL AND ENERGY
               IMPACT  ESTIMATES FOR SRU VENTS1
Annual impact
Electricity Use
(1,000 kW-hr)
Natural Gas Consumption
(1E+06 cubic feet)
SOX Emissions (tons)
Nationwide
2,160
178
38,200
   1 Based on incinerators added to control emissions
     from the production 3,410 Itpd of sulfur.
                            6-7

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(TJiis page  Is intentionally "left: blaiiK)

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                  7.0  MONITORING OPTIONS

     This chapter presents a brief review of options
available for monitoring HAP emission at petroleum
refineries for each process vent (CCUCR, CRUCR, SRU vents).
In general, the monitoring options were established using
the following priorities.  The top priority was given to the
use of continuous emission monitors  (CEMs) that directly
measure HAP emissions.  Second priority was given the
continuous emission monitors that measure a surrogate of HAP
emissions  (such as particulate matter for metal HAP).  Third
priority was given to continuous monitoring of process
parameters that are indicative of process emissions or the
effectiveness of the emission control device.
7.1  MONITORING OPTIONS FOR THE CCUCR VENT
     There are two separate monitoring options for the CCUCR
vent based on the two classes of HAP/control devices.  For
organic HAP, continuous emission monitoring for specific
organic HAP was not considered a proven  (commercially
available and reliable) monitoring option at this time, and
was considered inferior to other continuous monitoring
options due to the time delay between sample collection and
the availability of final results.   Continuous monitoring of
an indicator of organic HAP was therefore evaluated.  Two
potential indicators of organic HAP  were considered.  These
were:  1) continuous monitor of total hydrocarbon (THC) or
total organic carbon  (TOO using a flame ionization detector
(FID) or a photo ionization detector CEM; and 2) continuous
monitoring of carbon monoxide  (CO) using a carbon monoxide
CEM.  Both of these monitoring devices appear feasible for
                            7-1

-------
the CCUCR vent.  Several refineries currently employ
continuous TOC or CO monitors; however, only CO CEMs are
employed specifically on the CCUCR vent (to show compliance
with the petroleum refinery NSPS - 40 CFR 60, Subpart J).*
As the available emission data show an equally strong
correlation between measured organic HAP and CO emissions  as
they do organic HAP and THC/TOC emissions, a continuous CO
monitor was selected as the surrogate GEM for further
evaluation.  Finally, parametric monitoring options were
considered.  For complete combustion CCUCR units, continuous
parametric monitoring of temperature and exhaust oxygen
content were selected as a monitoring option to indicate
complete combustion of organic HAP.  For CO boilers/thermal
incinerators used for incomplete combustion CCUCR units,
continuous parametric monitoring of temperature was selected
as a monitoring option to indicate proper incinerator
performance and operation.  These parameters are commonly
monitored at nearly all CCUCR units.
     Continuous emission monitoring of either metal HAP or
an indicator of metal HAP such as particulate matter (PM)
was not considered proven (commercially available and
reliable) CEM.  Additionally, the lag time between sampling
and analysis for these monitoring approaches makes them
inferior to continuous parametric monitoring of the control
device.  The appropriate parameters to monitor are dependent
on the control device used to achieve.  For ESPs, continuous
parametric monitoring of voltage and secondary current were
selected as a monitoring option to indicate proper control
device performance and operation.  For venturi wet
scrubbers, continuous parametric monitoring of pressure
drop, air flow rate, and water flow rate were selected as a
monitoring option to indicate proper wet scrubber
performance and operation.
7.2  MONITORING OPTIONS FOR THE CRUCR VENT
     For the depressurization/purge and the rejuvenation/
final purge CRUCR vents, the vent gases are either vented to
                            7-2

-------
the refineries fuel gas (flare) system or a dedicated
thermal combustion device.  The monitoring provisions for a
flare as outlined in the General Provisions (40 CFR 63,
Subpart A)2 (i.e.,  monitor for presence of a flame)  was  the
only monitoring option considered.  The monitoring options
evaluated for a dedicated thermal combustion device for the
CRUCR vents included specific organic HAP CEM, surrogate of
organic HAP (THC/TOC) CEM, and continuous parametric
monitoring.  Due to the potentially acidic environment
within the combustion unit (from the formation or prior
existence of hydrogen chloride in the vent stream),  the
useful life of a CEM probe is uncertain and expected to be
short.  That is, both the organic HAP CEM and the THC/TOC
CEM were considered unproven technologies for the CRUCR vent
streams.  Consequently, continuous parametric monitoring of
temperature was selected as the only monitoring option for
the CRUCR vent streams that are exhausted to a dedicated
thermal combustion unit.
     For the CRUCR coke burn vent, the primary HAP emitted
from the depressurization/purge and the rejuvenation/final
purge vent cycles are hydrogen chloride (HCl) and chlorine.
Continuous HCl monitors are commercially available,  but no
refineries were identified that employed a continuous HCl
monitor for the CRUCR coke burn vent.  Continuous monitoring
of the gas and liquid flow/recirculation rates were selected
as indicators of proper control device operation.
7.3  MONITORING OPTIONS FOR THE SRU VENT
     Carbonyl sulfide and carbon disulfide are the primary
HAP emitted from the SRU vent.  A CEM specific to just these
two HAP is not commercially available at this time.
However, CEMs for monitoring reduced sulfur compound
emissions are commercially available and are in-use at
several refineries for the SRU vent to show compliance with
the petroleum refinery NSPS (40 CFR 60, Subpart J).3
Although reduced sulfur compounds are a surrogate of the HAP
emissions, it was considered a to be an excellent surrogate
                            7-3

-------
since reduced sulfur compounds consist only of the two
specified sulfur HAP compounds plus hydrogen sulfide.
     Only one parametric monitoring option was identified
for SRU vents and that monitoring option is applicable only

to SRU that employ an incinerator.  temperature and excess
oxygen were selected as the indicators of proper control
device performance.

7.4  REFERENCES
1.   Code of Federal Regulations.  Title 40, Part 60,
     Subpart J.  Standards of Performance for Petroleum
     Reifineries.  U.S. Government Printing Office.
     Washington ,D.C.  July 1, 1992.

2.   Code of Federal Regulations.  Title 40, Part 63,
     Subpart A.  General Provisions.  U.S. Government
     Printing Office.  Washington ,D.C.  July 1, 1992.

3.   Reference 1.
                           7-4

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           8.0   COST OF CONTROLS  FOR MODEL PLANTS

     This chapter presents information on control costs for
the various control equipment that may be included in the
control option control requirements.  Control costs for each
control device for each model plant are reported in terms of
total capital investment  (TCI),  annual operating costs
(AOC),  and total annualized costs (TAG) in late 1996
dollars.  The basis for calculating these control costs are
also described.
8.1  COSTS OF CONTROL DEVICES FOR CCUCR VENT
     In this section, control costs are developed for
selected control devices applicable for reducing HAP
emissions from the CCUCR vent. The control devices selected
for cost analysis for the CCUCR vent include:  ESPs, venturi
wet scrubbers,  and CO boilers/incinerators.  A correlation
of the CCUCR flow rate versus CCU throughput was derived
based on the available data to estimate model plant CCUCR
vent flow rates.l  The predicted model plant CCUCR flow
rates are summarized in Table 8-1.  The control device
design and cost analyses were then performed based on these
model CCUCR vent flow rates.
       TABLE 8-1.  MODEL PLANT CCUCR VENT FLOW RATES
No.
1
2
3
Size
Small
Medium
Large
CCU capacity
(bbl/day)
8,300
25,000
70,000
Vent Flow Rate
w/no CO Boiler
O(scfm)1
15,000
55,000
140,000
Vent Flow Rate
w/CO Boiler
O(scfm)1
20,000
70,000
200,000
Standard conditions at 60F as defined in ICR.
8.1.1  Costs for ESPs
                            8-1

-------
     The costing procedures outlined in EPA's Control Cost
Manual were used to develop costs for ESPs.2  The ESP design
parameters were based on the model plant vent flow rates and
typical operating parameters as reported in responses to
EPA's information collection requests (ICR) and industry-
supported surveys.  The mean mass diameter was estimated to
be 4 ium based on the assumption that cyclone separators
(used to minimize catalyst loss from the CCUCR) will
generally pass particles with diameters of 10 (Jim and less.
It was assumed that the dust would not have severe back
corona effects (i.e., a resistivity of less than 2 x 10"
ohm-cm was assumed).  The design parameters used to develop
costs for ESPs are summarized in Table 8-2.
             TABLE 8-2.  DESIGN VALUES FOR ESP
Parameter
ESP Type
Inlet PM (grains/cu.ft)
Design outlet PM (grains/cu.ft)
Required design efficiency (E)
Penetration (p = 1 - E)
Temperature (K)
Resistivity (ohm-cm)
Inlet mass mean diameter, MMD (//m)
Sneakage (Sn)
Rapping Re-entrainment (RR)
MMD for most penetrating size (pm)
MMD for rapping puff size (jum)
Design flow rate, Q (acfm)
Value
Plate & wire
0.20
0.02
0.90
0.10
478
2.0E+09
4
0.07
0.124
2
3
Q(scfm)xT (K)/289
     Based on the ESP design parameters  in Table  8-2, the
projected specific  collection  area  is  717 ftVkacfm.  The
                            8-2

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total capital investment, annual operating costs and total
annual costs for model plant ESPs are summarized in
Table 8-3.   Equations for estimating the control costs based
on inlet flow rate and the design values summarized in
Table 8-2 are also provided Table 8-3.

  TABLE 8-3a.  MODEL PLANT CCUCR ESP CONTROL COSTS1 - TCI
No.
1
2
3
Size
Small
Medium
Large
ecu
capacity
(bbl/day)
8,300
25,000
70,000
TCI for CCU w/o
CO Boiler
($1,000)
1,500
3,200
6,900
TCI for CCU
w/CO Boiler
($1,000)
1,800
3,900
9,200
TCI ($1,000) = [0.0416 x Q(scfm)2] + 943
  TABLE 8-3b.  MODEL PLANT CCUCR ESP CONTROL COSTS1 - AOC
No.
1
2
3
Size
Small
Medium
Large
CCU
capacity
(bbl/day)
8,300
25,000
70,000
AOC for CCU w/o
CO Boiler
($1,000)
150
340
740
AOC for CCU
w/CO Boiler
($1,000)
180
410
1,000
AOC ($1,000) = [0.00468 x Q(scfm)2] + 85
  TABLE 8-3c.  MODEL PLANT CCUCR ESP CONTROL COSTS1 - TAG
NO.
1
2
3
Size
Small .
Medium
Large
CCU
capacity
(bbl/day)
8,300
25,000
70,000
TAG for CCU w/o
CO Boiler
($1,000)
300
640
1,400
TAG for CCU
w/CO Boiler
($1,000)
350
780
1,900
TAG ($1,000) = [0.0086 x Q(scfm)2] + 174
1Costs rounded to 2 significant digits or nearest $100,000,
2Based on standard conditions at 60F.
8.1.2  Cost for Venturi Wet Scrubbers
                           8-3

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     The costing procedures outlined in EPA's Handbook -
Control Technologies for Hazardous Air Pollutants were used
to develop costs for venturi scrubbers.3  The venturi
scrubber design parameters were based on the same model
plant vent flow rates as used to estimate costs for ESPs.
Again, the mean mass diameter was estimated to be 4 fj.m based
on the assumption that cyclone separators (used to minimize
catalyst loss from the CCUCR) will generally pass particles
with diameters of 10 nm and less.  The design parameters
used to develop costs for venturi scrubbers are summarized
in Table 8-4.
     The total capital investment, annual operating costs
and total annual costs for model plant venturi scrubbers are
summarized in Table 8-5.  Equations for estimating the
control costs based on inlet flow rate and the design values
summarized in Table 8-4 are also provided Table 8-5.
      TABLE 8-4.  DESIGN VALUES FOR VENTURI SCRUBBERS
Parameter
Inlet PM (grains/cu.ft)
Design outlet PM (grains/cu.ft)
Required design efficiency (E)
Pressure drop at design efficiency, in H20
Temperature (F)
Moisture content (vol %)
Inlet mass mean diameter, MMD (//m)
Inlet mass mean diameter, MMD (pm)
Design flow rate, Q (acfm)
Value
0.20
0.02
0.90
10
400
5
4
4
Q(scfm)xT (R)/520
      TABLE 8-5a.
MODEL PLANT CCUCR VENTURI SCRUBBER
 CONTROL COSTS1  - TCI
                            8-4

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No.
1
2
3
Size
Small
Medium
Large
ecu
capacity
(bbl/day)
8,300
25,000
70,000
TCI for CCU w/o
CO Boiler
($1,000)
210
530
1,100
TCI for CCU
w/CO Boiler
($1,000)
260
640
1,400
TCI ($1,000) = exp[0.7229 x ln(Q (scfm) 2) - 1.6086]
      TABLE 8-5b.
MODEL PLANT CCUCR VENTURI SCRUBBER
 CONTROL COSTS1  - AOC
No.
1
2
3
Size
Small
Medium
Large
CCU
capacity
(bbl/day)
8,300
25,000
70,000
AOC for CCU w/o
CO Boiler
($1,000)
300
880
2,100
AOC for CCU
w/CO Boiler
($1,000)
370
1,100
3,000
AOC ($1,000) = [0.0144 x Q(scfm)2] + 87
      TABLE 8-5C.
MODEL PLANT CCUCR VENTURI SCRUBBER
 CONTROL COSTS1 -  TAG
No.
1
2
3
Size
Small
Medium
Large
CCU
capacity
(bbl/day)
8,300
25,000
70,000
TAG for CCU w/o
CO Boiler
($1,000)
330
960
2,200
TAG for CCU
w/CO Boiler
($1,000)
410
1,200
3,200
TAG ($1,000) = [0.0153 x Q(scfm)2] + 109
       rounded to 2 significant digits or nearest $100,000,
2Based on standard conditions at 60F.
                           8-5

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8.1.3  Costs for CO Boilers/Incineration
     The control costs for incinerators were estimated using
the costing procedures outlined in EPA's Control Cost
Manual.4  The incinerator design parameters were based on
the model plant vent flow rates for CCU regenerators that do
not have CO boilers.  It was assumed that the CCUCR flue gas
was at 1,200F with 2 percent CO content (by volume).  To
minimize fuel requirements, the feed air to the incinerator
is preheated by the incinerator exhaust (a 35 percent
recuperative incinerator is more than sufficient); the total
air requirements were determined from the system energy
balance and a design outlet oxygen concentration of 2
percent (by volume).  The total capital investment, annual
operating costs and total annual costs for model plant
incinerators for the CCUCR vent are summarized in Table 8-6.
     Cost function equations were developed for model plant
incinerators for the CCUCR vent based on linear regression
analysis of the cost data summarized in Table 8-6 and
exhaust gas flow rates  (Q in scfm) .  The cost function
equations for CCUCR incinerators follow.

     TCI  ($1,000) = exp{0.36787xln(Q)+2.5925}
     AOC  ($1,000) = 0.01041xQ + 59
     TAG  ($1,000) = 0.01107xQ + 120
         TABLE 8-6.  MODEL PLANT CCUCR INCINERATOR
              CONTROL COSTS1 - TCI, AOC AND TAC
No.
1
2
3
Size
Small
Medium
Large
CCU
capacity
(bbl/day)
8,300
25,000
70,000
TCI
($1,000)
460
730
1,100
AOC
($1,000)
210
630
1,500
TAC
($1,000)
280
740
1,700
       rounded to 2 significant digits or nearest $100,000
8.2  COSTS OF CONTROL DEVICES FOR CRUCR VENT
                            8-6

-------
     In this section, control costs are developed for
selected control devices applicable for reducing HAP
emissions from the CRUCR vent.  The control devices selected
for cost analysis for the CRUCR vent include wet scrubbers
and caustic injection.  [Currently assumed that all purge
vents to flare or refinery fuel gas system are already in-
place.]  As the magnitude and duration of the CRUCR vent
flows are dependent on the type of CRUCR (semi-regenerative,
cyclic or continuous) as well as on the throughput of the
CRU, nine model CRUCR vents were developed based on the type
of CRUCR and CRU throughput ranges.  The flow rates and
durations of the model plant were selected based on an
analysis of information in the EPA data base.5  Table 8-7
summarizes the key parameters of the CRUCR model vents.
       TABLE 8-7.  MODEL PLANT CRUCR VENT FLOW RATES
No.
1
2
3
4
5
6
7
8
9
CRUCR Type
Semi-Regen.
Semi-Regen.
Semi-Regen.
Cyclic
Cyclic
Cyclic
Continuous
Continuous
Continuous
CRU
Throughput
Range
(1,000 bpd)
0 to <15
15 to 30
>30
0 to <15
15 to 30
>30
0 to <15
15 to 30
>30
Coke Burn
Vent Flow
Rate
(scfm)1
15,000
20,000
30,000
600
800
1,200
150
250
500
Annual
Coke Burn
Vent
Duration
(hrs/yr)
72
90
120
2,400
3,000
3,600
8,640
8,640
8,640
Standard conditions at 60F as defined in ICR.
                            8-7

-------
     The control device design and cost analyses were then
performed based on these model CRUCR vent flow rates and
durations.  For the cyclic and continuous CRUCR, the control
costs were developed using the control cost algorithms for
packed-bed absorbers presented in EPA's Control Cost
Manual.6  For semi-regenerative units,  control  costs  for  a
caustic spray chamber scrubber were derived using nearly the
same control cost algorithms for packed-bed absorbers
presented in EPA's Control Cost Manual, except no packing
material was used in the spray chamber.  The control cost
factors developed for the model CRUCR units are presented in
Table 8-8.  These control cost factors were applied directly
to a given CRUCR based on the CRU throughput.  That is,  no
regression of the cost factors were performed to correlate
CRUCR control costs with CRU throughput within a given CRU
throughput range.
    TABLE 8-8.  MODEL PLANT CRUCR WET SCRUBBER/ABSORBER
              CONTROL COSTS1 - TCI,  AOC AND TAG
No.
1
2
3
4
5
6
7
8
9
Regen .
Type
Semi
Semi
Semi
Cyclic
Cyclic
Cyclic
Cont.
Cont .
Cont.
CRU
capacity
(1000 bpd)
<15
15 to 30
>30
<15
15 to 30
>30
<15
15 to 30
>30
TCI
($1,000)
38
47
64
45
54
68
21
27
41
AOC
($1,000)
6
9
16
13
16
20
41
41
42
TAG
($1,000)
11
16
25
20
24
30
44
45
48
       rounded to 2 significant digits or nearest $1,000.
                           8-8

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8.3  COSTS OF CONTROL DEVICES FOR SULFUR PLANT VENT
     This section presents the control costs for
incinerators used to reduce HAP emissions from the SRU vent.
A correlation of the SRU tail gas flow rate versus sulfur
production rate was derived based on the data available in
the EPA database.  The EPA database was also used to
characterize the SRU tail gas.7  The predicted model plant
SRU flow rates are summarized in Table 8-9.  All model SRU
units  (that require an incinerator) are assumed to have tail
gas with the following properties:

     Temperature = 275F
     Reduced Sulfur Compound Concentration = 4,000 ppmv
     Oxygen Concentration = 0 ppmv.
        TABLE 8-9.  MODEL PLANT SRU VENT FLOW RATES
No.
1
2
3
Size
Small
Medium
Large
Sulfur
Production Rate
(long tons /day)
30
120
480
Vent Flow
Rate Q(scfm)1
1,950
7,800
31,200
Operating
Hours
(hrs/yr)
8,640
8,640
8,640
Standard conditions at 60F as defined in ICR.
     The control costs for SRU incinerators were estimated
using the costing procedures outlined in EPA's Control Cost
Manual.8  The incinerator design parameters were based on
the model plant vent flow rates for SRUs.  To minimize fuel
requirements, both the combustion air and the SRU tail gas
are preheated by the incinerator exhaust; a recuperative
incinerator with 70 percent energy recovery was employed.
The total air requirements were determined from the system
                            8-9

-------
energy balance and a design outlet oxygen concentration of
2 percent (by volume).   The total capital investment, annual
operating costs and total annual costs for model plant
incinerators for the SRU vent are summarized in Table 8-10.
         TABLE  8-10.   MODEL PLANT SRU INCINERATOR
             CONTROL COSTS1 - TCI, AOC AND TAG
No.
1
2
3
Size
Small
Medium
Large
Sulfur
Prod. Rate
(long tpd)
30
120
480
TCI
($1,000)
360
530
810
AOC
($1,000)
110
260
870
TAG
($1,000)
160
340
980
Cost's  rounded to 2  significant digits or nearest $100,000
     Cost function equations were developed for model plant
incinerators for the CCUCR vent based on linear regression
analysis of the cost data summarized in Table 8-6 and
exhaust gas flow rates  (Q in scfm).   The cost function
equations for SRU incinerators follow.

     TCI ($1,000) = exp{0.29295xln(Q)+3.6625)
     AOC ($1,000) = 0.02605XQ + 57
     TAG ($1,000) = 0.02811xQ + 109

8.4  COSTS OF MONITORING, REPORTING, AND RECORDKEEPING
     This section presents the costs associated with control
device monitoring, reporting and recordkeeping for each of
the different types of  control devices / refinery vent
combinations.  First costs and initial annual costs for
continuous emission monitors (CEMs)  are given in Table 8-11
for each type of subject unit and for alternative means of
compliance.  CEMs for the units may measure offgas
characteristics  (constituent concentration or temperature)
or equipment operating  parameters (voltage, current,
                           8-10

-------
pressure drop,  or flow rates).   Although purchase costs of
monitors may vary from a few hundred dollars to many
thousands of dollars, depending on the parameter being
monitored,  the major cost of a CEM system lies in time and
materials costs for planning, installing, maintaining,
certifying, and recertifying the system for its lifetime.
The costs in Table 1 include these items.  In particular,
relative accuracy test audits required for extractive
sampling contribute significantly to annual costs.  All
costing was done using EPA's EMTIC program, with costs
escalated to late 1996.9
     Elements of the EMTIC program for first costs include:
planning, selection of equipment, support facilities,
purchase of the CEM, installation and checking, performance
test, and preparation of a QA/QC plan.  Elements for the
first year's annual cost include:  operation and
maintenance, relative accuracy test audit and supplemental
audit (for extractive gas CEMs),  quarterly cylinder gas
audits  (for calibration),  record keeping and reporting, and
annual review and update.   Where process monitoring
instruments such as temperature,  pressure, voltage, and
current instruments are used, they are assumed to be part of
the control system and have their purchase costs allocated
to the process rather than to the CEM system.  However,
associated record keeping and reporting, annual review and
update,  and some operation and maintenance costs are
assigned to CEM system costs.
     The costs in Table 1 have large error bands, but should
be useful for comparing gas CEMs vs parameter monitoring.
While monitor costs are generally supplied by EMTIC or a
vendor quote, the multimetals CEM cost is an estimate.
                           8-11

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Table 8-11.
First cost and initial annual cost for
continuous emission monitors on CCUs,  CRUs,
and SRUs
Unit
ecu







CRU



SRU

Pollutant
Organic HAP


Particulate
matter


Metallic HAP

HC1

Organic Hap from
flare
Organic Hap from
incinerator
COS/CS2 from
incinerator

Monitored
parameter
CO
Temperature
HAP/TOC
ESP: volts/amps
WS: DP, liq. and
gas flow rates
Opacity
Mulitmetals (by
GEM)
Opacity
HC1 (by GEM)
HCl (by M26A)
per general
provisions
Temperature
Total reduced
sulfur
Temperature
First
cost, $
97,100
18,900
91,300
32,000
37,300
41,200
132,700
41,200
104,000
Not
applicable
0
18,900
117,600
18,900
Initial
annual
cost, $
63,400
19,500
63,900
20,300
20,400
18,400
66,600
18,400
65,000
13,800
0
19,500
65,900
19,500
CCU  Catalytic cracking unit
CEM  continuous emission monitor
CRU  Catalyst regeneration unit
DP   Differential pressure
ESP  Electrostatic precipitator
M26A EPA test method 26A for HCl
SRU  Sulfur recovery unit
HAP  Hazardous air pollutant
TOC  Total organic carbon
WS   Wet scrubber
                           8-12

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8.5  REFERENCES

1.    U.S.  Environmental Protection Agency.  Refinery process
     vent  data base...

2.    U.S.  Environmental Protection Agency.  OAQPS Control
     Cost  Manual.  Publication No. EPA/450/3-90-006.  Office
     of Air Quality Planning and Standards,  Research
     Triangle Park, NC.  January 1990.

3.    U.S.  Environmental Protection Agency.  Handbook -
     Control Technologies for Hazardous Air Pollutants.
     Publication No. EPA/625/6-91/014.  Office of Research
     and Development,  Washington, DC.  June 1991.  pp. 4-80
     through 4-90.

4.    Reference 2.

5.    Reference 1.

6.    Reference 2.

7.    Reference 1.

8.    U.S.  Environmental Protection Agency...
                           8-13

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                    DRAFT  - June 1998
                        APPENDIX A

             KEY DATES  IN DEVELOPMENT OF BID
   TABLE A-l.  KEY DATES IN THE DEVELOPMENT OF THE BID
      Date
                 Event
July 16, 1992
August 16-17,
1995
August 18, 1995
August 31, 1995
and September 1,
1995

December 1, 1995
December 7, 1995
June 24, 1996
February 28, 1997
The EPA published initial list of
hazardous air pollutant (HAP) emission
source categories (57 FR 31576)

EPA conducted information gathering
site visits to three petroleum
refineries in Pennsylvania and New
Jersey

The EPA published National Emission
Standards for Hazardous Air Pollutants
(NESHAP:  Petroleum Refineries; Final
Rule (60 FR 43244).  This rule, termed
Petroleum Refinery MACT I, deferred
setting NESHAP for three vents:
catalyst regeneration vents on
catalytic cracking units  (CCU) and
catalytic reforming units (CRU) and
vents from sulfur recovery units (SRU).

EPA conducted information gathering
site visits to two petroleum refineries
in Louisiana.

EPA held kick-off Presumptive MACT
meeting with regulatory agency
representatives.

EPA held kick-off Presumptive MACT
meeting with representatives of
industrial stakeholders.

EPA met with representatives of
emission control device manufacturers.

EPA finalized the Preliminary
Presumptive MACT for Petroleum Refinery
Process Vents:  FCC Units, Reformers,
and Sulfur Plants.
                            A-l

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                    DRAFT - June 1998


            TABLE A-l.  KEY DATES  (Continued)
      Date                          Event
July 29, 1997      EPA held meeting with small business
                   petroleum refineries to communicate
                   EPA's policies regarding Small Business
                   Regulatory Enforcement Fairness Act
                   (SBREFA).

September 12,      EPA conducted an information gathering
1997               site visit to a small business
                   petroleum refinery in Indiana.

September 15,      EPA conducted information gathering
1997 through       site visits to four small petroleum
September 17,      refineries in Wyoming and Utah that
1997               have non-conventional units (non-fluid
          	    CCU and non-Glaus SRU) .	
                            A-2

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                 APPENDIX B.   HAP EMISSIONS DATA


     This appendix contains the HAP emissions data used to
develop estimates of emissions in Chapter 5 for model plants and
for all units nationwide.  The data for catalytic cracking and
catalytic reforming given in Tables B-l and B-2 were provided in
a database from API and included the results of their survey of
the industry.1  The data for sulfur recovery units in Table B-3
were from responses to section 114 questionnaires compiled by the
EPA.2  These data are also summarized in the document developed
for the presumptive MACT process.3


REFERENCES
1.   Letter from David Hansel1, EER, to Robert Lucas, U.S.EPA,
     transmitting the Detailed API CCU and CRU Data Base; 2nd
     Draft.  January 23, 1997

2.   U.S Environmental Protection Agency.  Responses to
     Information Collection Request for Petroleum Refineries.
     Office of Air Quality Planning and Standards, Research
     Triangle Park, NC.  1992.

3.   U.S Environmental Protection Agency.  Presumptive MACT for
     Petroleum Refinery Process Vents:  FCC Units, Reformers, and
     Sulfur Recovery Plants.  Appendix B-Summary of Emissions
     Data.  Office of Air Quality Planning and Standards,
     Research Triangle Park, NC.  1997.
                               B-l

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TABLE  B-l.
EMISSIONS DATA FOR CCU REGENERATION (abbreviations
are explained at the end of the table)
Combustion
type
NA
NA
Complete
NA
NA
Partial
Complete
Complete
NA
NA
Partial
Partial
Partial
Partial
Partial
Partial
NA
NA
Complete
Complete
NA
NA
Partial
Complete
Partial
NA
Partial
NA
Complete
Complete
Complete
Partial
Partial
NA
NA
Complete
Complete
Partial
NA
Complete
Partial
Partial
Partial
Hydro
treat
NA
NA
Yes
NA
NA
NA
Yes
Yes
NA
NA
NA
Yes
Yes
Yes
Yes
Yes
NA
NA
Yes
Yes
NA
NA
NA
Yes
NA
NA
NA
NA
Yes
Yes
Yes
NA
NA
NA
NA
Yes
Yes
Yes
NA
Yes
Yes
Yes
Yes
APC System
COB
COB
C\COB\ESP
ESP
ESP
C\COB\ESP
C\WHB\ESP\
COB
C\COB\ESP
COB\ESP
COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
ESP
ESP
C\WHB\ESP\
COB
WHB\ESP\CO
B
ESP
ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
COB\ESP
C\COB\ESP
COB\ESP
NA
C\WHB\ESP\
COB
C\WHB\ESP\
COB
C\COB\ESP
C\COB\ESP
C\ESP
COBVESP
C\COB\ESP
C\WHB\ESP\
COB
C\COB\ESP
ESP
WHBWS
C\COB\ESP
C\COB\ESP
C\COB\ESP
Sample
location
COB Outlet
COB Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
NA
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
COB Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
NA
ESP Outlet
ESP Outlet
NA
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
NA
ESP Outlet
ESP Outlet
NA
ESP Outlet
VS Outlet
ESP Outlet
ESP Outlet
ESP Outlet
Substance
1 ,3-Butadiene
1 ,3-Butadlene
1 ,3-Butadlene
Acetaldehyde
Acetaldehyde
Acetaldehyde
Acetaldehyde
Acetaldehyde
Acetaldehyde
Acetaldehyde
Acetaldehyde
Benzene
Benzene
Benzene
Benzene
Benzene
Benzene
Benzene
Cyanide
Cyanide
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Hydrogen Cyanide
Hydrogen Cyanide
Hydrogen Cyanide
Hydrogen Cyanide
Hydrogen Cyanide
Hydrogen Cyanide
n-Hexane
Toluene
Toluene
Toluene
Data
source
114
114
Test
ICR
Test
Test
Test
Test
Test
114
Test
Test
Test
Test
Test
Test
Test
ICR
ICR
Test
ICR
Test
Test
Test
ICR
Test
Test
114
SV
ICR
Test
Test
Test
Test
Test
Test
Test
114
Test
114
Test
Test
Test
Factor
(Ib/mm bbl)
7.00e-04
9.00e-04
4.82e-02
2.998+00
3.006+00
1.34e+01
1.35e+01
2.07e+01
2.476+01
3.029+01
3.418+01
7.256-01
1.988+00
2.790+00
1.068+01
1.17e+01
3.97e+01
4.30e+01
2.B38+01
3.556+01
1.036+01
1.046+01
1.31e+01
1.636+01
1.926+01
2.666+01
2.838+01
3.156+01
7.89e+01
9.29e+02
9.56e+02
6.186+04
1.408+05
7.84e-01
1.408+01
2.466+01
2.906+01
1.946+02
2.586+03
5.416+01
B.OSe-02
9.016-02
1.276-01
                               B-2

-------
TABLE  B-l.  EMISSIONS  DATA FOR CCU REGENERATION  (continued)
Combustion
type
Partial
NA
NA
Partial
Complete
Complete
NA
NA
NA
NA
Complete
Partial
Complete
Complete
Complete
NA
Complete
Partial
Complete
Partial
Complete
Partial
Complete
Partial
Complete
Partial
Partial
Partial
NA
Complete
Partial
NA
Partial
Complete
Partial
NA
NA
NA
Hydro
treat
Yes
NA
NA
Yes
Yes
Yes
NA
NA
NA
NA
Yes
Yes
Yes
Yes
Yes
NA
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
NA
Yes
Yes
NA
Yes
Yes
Yes
NA
NA
NA
APC System
C\COB\ESP
COB\ESP
COB\ESP
C\COB\ESP
WHB\ESP\CO
B
C\COB\ESP
ESP
ESP
COBVESP
C\ESP
WHB\ESP\CO
B
C\COB\ESP
WHB\ESP\CO
B
C\COB\ESP
WHB\ESP\CO
B
C\ESP
WHB\ESP\CO
B
C\COB\ESP
WHB\ESP\CO
B
C\COB\ESP
WHB\ESP\CO
B
C\COB\ESP
WHB\ESP\CO
B
C\COB\ESP
WHB\ESP\CO
B
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\ESP
WHB\ESP\CO
B
C\COB\ESP
C\ESP
C\COB\ESP
WHB\ESP\CO
B
C\COB\ESP
ESP
ESP
C\ESP
Sample
location
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
COB Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
COB Outlet
ESP Outlet
COB Outlet
ESP Outlet
COB Outlet
ESP Outlet
COB Outlet
ESP Outlet
COB Outlet
ESP Outlet
COB Outlet
ESP Outlet
COB Outlet
ESP Outlet
COB Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
COB Outlet
ESP Outlet
ESP Outlet
ESP Outlet
COB Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
Substance
Toluene
Toluene
Total Xylene
2-Methylnaphthalene
Phenol
Phenol
Phenol
Phenol
Phenol
Phenol
Acenaphthene
Acenaphthene
Acenaphthylene
Acenaphthvlene
Anthracene
Anthracene
Benzo(a)anthracene
Benzo(a)pyrene
Benzo(b)fluoranthene
Benzo(b)fluoranthene
Benzo(e)pyrene
Benzo(g,h,i)perylene
Benzo(k)fluoranthene
Benzo(k)fluoranthene
Chrysene
Chrysene
dibenz(a,h)anthracen
e
Fluoranthene
Fluoranthene
Fluorene
Fluorene
Fluorene
lndeno(1 ,2,3-cd)pyren
e
Naphthalene
Naphthalene
Naphthalene
Naphthalene
Naphthalene
Data
source
Test
ICR
ICR
Test
Test
Test
ICR
Test
114
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
ICR
Test
Test
Factor
(Ib/mm bbl)
3.74e+00
1.388+03
9.008+01
2.61e-02
2.27e-04
8.41e-01
1.116+00
1.15e-fOO
2.158+01
4.096401
4.900-04
6.08e-03
3.54e-04
2.57e-01
1.13e-03
2.03e-01
5.246-04
1.06B-02
1.066-03
5.946-03
4.546-04
4.606-03
3.666-04
4.86e-03
2.566-03
3.986-03
4.580-03
4.926-03
2.71 e-01
1.926-03
6.52e-03
1.016-01
4.386-03
1.026-01
8.64e-01
1.526+00
1.556+00
1. 686+00
                               B-3

-------
TABLE  B-l.  EMISSIONS DATA FOR CCU  REGENERATION (continued)
Combustion
type
NA
Partial
Complete
Partial
NA
NA
NA
Complete
Partial
NA
Partial
NA
Complete
Complete
Partial
Complete
Partial
NA
NA
Partial
Partial
Complete
Partial
NA
Partial
Partial
Partial
Partial
Partial
Partial
NA
NA
Partial
Partial
NA
NA
Partial
Partial
Partial
Partial
NA
NA
Partial
Partial
Partial
Partial
NA
Hydro
treat
NA
Yes
Yes
Yes
NA
NA
NA
Yes
Yes
NA
Yes
NA
Yes
Yes
No
Yes
No
NA
NA
Yes
Yes
Yes
NA
NA
NA
Yes
NA
NA
Yes
No
NA
NA
No
Yes
NA
NA
NA
NA
Yes
NA
NA
NA
No
Yes
Yes
Yes
NA
APC System
COBVESP
C\COB\ESP
WHB\ESP\CO
B
C\COB\ESP
ESP
C\ESP
COB\ESP
WHB\ESP\CO
B
C\COB\ESP
COB
C\COB\ESP
COB
ESP
ESP
1
ESP
C\ESP\COB
COB
COB
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
1
COB
COB
1
C\COB\ESP
COB
COB
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
ESP
ESP
1
C\COB\ESP
C\COB\ESP
C\COB\ESP
COB
Sample
location
NA
COB Outlet
COB Outlet
ESP Outlet
ESP Outlet
ESP Outlet
NA
COB Outlet
ESP Outlet
COB Outlet
ESP Outlet
COB Outlet
ESP Outlet
ESP Outlet
Regen Outlet
ESP Outlet
COB Outlet
COB Outlet
COB Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
Regen Outlet
COB Outlet
COB Outlet
Regen Outlet
ESP Outlet
COB Outlet
COB Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
Regen Outlet
ESP Outlet
ESP Outlet
ESP Outlet
COB Outlet
Substance
PAH (Total)
PAH (Total)
Phenanthrene
Phenanthrene
Phenanthrene
Phenanthrene
Phenolics (Total)
Pyrene
Pvrene
Antimony
Antimony
Antimony
Antimony
Antimony
Antimony
Antimony
Antimony
Arsenic
Arsenic
Arsenic
Arsenic
Arsenic
Arsenic
Arsenic
Arsenic
Arsenic
Arsenic
Arsenic
Arsenic
Arsenic
Beryllium
Beryllium
Beryllium
Beryllium
Cadmium
Cadmium
Cadmium
Cadmium
Cadmium
Cadmium
Cadmium
Cadmium
Cadmium
Cadmium
Cadmium
Cadmium
Chromium
Data
source
Test
114
Test
Test
Test
Test
Test
Test
Test
114
Test
114
114
114
Test
114
ICR
114
114
Test
Test
Test
Test
Test
Test
Test
ICR
Test
Test
Test
114
114
Test
Test
114
114
ICR
Test
Test
Test
ICR
Test
Test
Test
Test
Test
114
Factor
(Ib/mm bbl)
S.OSe+OO
1.94e+02
1.156-02
2.408-02
1.489-01
7.946-01
2.02e+01
2.49e-03
4.426-03
3.206-02
4.366-02
4.408-02
5.008-02
1.006-01
2.33e+00
5.53e+00
9.956+00
1.008-03
1.00e-03
6.876-02
7.408-02
1.218-01
1.676-01
2.296-01
2.896-01
3.976-01
4.70e-01
1.12e+00
1.43e+00
1.70e+00
2.006-03
3.00e-03
5.366-02
6.586-02
4.006-03
5.006-03
2.006-02
2.066-02
4.498-02
9.246-02
2.808-01
2.968-01
3.41 e-01
8.706-01
1.656+00
2.826+00
4.306-02
                               B-4

-------
TABLE  B-l.  EMISSIONS DATA. FOR CCU REGENERATION  (continued)
Combustion
type
NA
Partial
Partial
Partial
Complete

Partial
NA
Partial
Complete

Complete
Complete

Partial
Partial
Partial
NA
NA
Partial
Partial
Partial
NA
NA
Complete
Complete
Partial
Complete
NA
NA
Complete
Partial
Partial
Complete

Partial
Partial
Partial
Complete
Partial
Partial
NA
Partial
Partial
Partial
NA
Partial
Partial
Hydro
treat
NA
NA
Yes
NA
Yes

NA
NA
Yes
Yes

Yes
Yes

No
Yes
Yes
NA
NA
NA
Yes
NA
NA
NA
Yes
Yes
No
Yes
NA
NA
Yes
NA
Yes
Yes

NA
Yes
Yes
Yes
NA
Yes
NA
NA
Yes
No
NA
NA
NA
APC System

COB
C\COB\ESP
C\COB\ESP
C\COB\ESP
WHB\ESP\CO
B
C\COB\ESP
C\ESP
C\COB\ESP
C\WHB\ESP\
COB
C\COB\ESP
C\WHB\ESP\
COB
1
C\COB\ESP
C\COB\ESP
ESP
ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
COB
COB
ESP
ESP
1
ESP
COB
COB
WHBWS
C\COB\ESP
C\COB\ESP
WHB\ESP\CO
B
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\ESP
C\COB\ESP
C\COB\ESP
1
I\ESP
C\COB\ESP
C\COB\ESP
Sample
location
COB Outlet
ESP Outlet
ESP Outlet
ESP Outlet
COB Outlet

ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet

ESP Outlet
ESP Outlet

Regen Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
COB Outlet
COB Outlet
ESP Outlet
ESP Outlet
Regen Outlet
ESP Outlet
COB Outlet
COB Outlet
VS Outlet
ESP Outlet
ESP Outlet
COB Outlet

ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
Regen Outlet
NA
ESP Outlet
ESP Outlet
Substance

Chromium
Chromium
Chromium
Chromium
Chromium

Chromium
Chromium
Chromium
Chromium

Chromium
Chromium

Chromium
Chromium
Chromium
Chromium
Chromium
Chromium
Chromium
Chromium
Cobalt
Cobalt
Cobalt
Cobalt
Cobalt
Cobalt
Lead
Lead
Lead
Lead
Lead
Lead

Lead
Lead
Lead
Lead
Lead
Lead
Lead
Lead
Lead
Lead
Lead
Lead
Manganese
Data
source
114
Test
Test
ICR
Test

Test
Test
Test
ICR

Test
Test

Test
Test
Test
ICR
Test
Test
Test
Test
114
114
114
114
Test
114
114
114
114
ICR
Test
Test

Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
114
Test
Test
Factor
(Ib/mm bbl)
5.90e-02
1.26e-01
2.43e-01
2.909-01
4.99B-01

5.016-01
5.666-01
8.306-01
9.006-01

9.476-01
9.796-01

1.116+00
1.166+00
2.106+00
2.596+00
2.936+00
7.586+00
1.18e+01
2.71 e+01
6.006-03
9.006-03
2.10e-01
4.10e-01
,13e+00
.498+00
.056-01
.45e-01
.80e-01
2.706-01
2.81e-01
2.826-01

4.54e-01
6.066-01
1.53e+00
1.656+00
2.846+00
3.506+00
4.526+00
5.456+00
6.206+00
6.296+00
6.726+00
9.176+00
3.69e-01
                                B-5

-------
TABLE  B-l.  EMISSIONS DATA FOR CCU REGENERATION  (continued)
Combustion
type
Complete
NA
Partial
Partial
Complete
NA
NA
Partial
Complete
Complete
Partial
Partial
NA
NA
Partial
Partial
Complete
NA
Partial
Partial
NA
NA
Complete
Complete
Partial
Complete
Partial
Partial
Partial
NA
Partial
Complete
Partial
Complete
Complete
Partial
Complete
Complete
Complete
Complete
Complete
NA
Hydro
treat
Yes
NA
Yes
NA
Yes
NA
NA
No
Yes
Yes
NA
NA
NA
NA
NA
NA
Yes
NA
Yes
NA
NA
NA
Yes
Yes
No
No
NA
NA
No
NA
NA
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
NA
APC System
WHB\ESP\CO
B
C\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
ESP
ESP
1
C\WHB\ESP\
COB
C\WHB\ESP\
COB
C\COB\ESP
C\COB\ESP
COB
COB
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\ESP
C\COB\ESP
C\COB\ESP
ESP
ESP
C\WHB\ESP\
COB
C\WHB\ESP\
COB
1
WHB\ESP
C\COB\ESP
C\COB\ESP
COB
C\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
ESP
WHB\ESP
C\COB\ESP
C\WHB\ESP\
COB
WHBWS
ESP
C\WHB\ESP\
COB
WHB\ESP\CO
B
ESP
Sample
location
COB Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
Regen Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
COB Outlet
COB Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
Regen Outlet
ESP Outlet
ESP Outlet
ESP Outlet
Regen Outlet
ESP Outlet
ESP Outlet .
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
VS Outlet
ESP Outlet
ESP Outlet
COB Outlet
ESP Outlet
Substance
Manganese
Manganese
Manganese
Manganese
Manganese
Manganese
Manganese
Manganese
Manganese
Manganese
Manganese
Manganese
Mercury
Mercury
Mercury
Mercury
Mercury
Mercury
Mercury
Mercury
Mercury
Mercury
Mercury
Mercury
Mercury
Nickel
Nickel
Nickel
Nickel
Nickel
Nickel
Nickel
Nickel
Nickel
Nickel
Nickel
Nickel
Nicksl
Nickel
Nickel
Nickel
Nickel
Data
source
Test
Test
Test
Test
Test
ICR
Test
Test
ICR
Test
Test
Test
114
114
Test
Test
Test
Test
Test
Test
ICR
Test
Test
ICR
Test
ICR
ICR
Test
114
Test
Test
Test
Test
114
ICR
Test
ICR
114
114
Test
Test
ICR
Factor
(Ib/mm bbl)
3.71e-01
6.266-01
1.05e+00
1.78e+00
2.09e+00
2.326+00
2.45e+00
6.696+00
1.086+01
1.10e+01
1.426+01
2.306+01
1.006-03
1.006-03
3.076-02
3.496-02
6.986-02
7.046-02
1.486-01
1.626-01
3.006-01
3.196-01
4.586-01
6.006-01
2.886+00
2.206-03
2.006-02
4.31e-01
5.506-01
5.536-01
8.62e-01
1.396+00
1.396+00
1.486+00
1.49e+00
2.396+00
3.206+00
3.236+00
3.556+00
3.746+00
5.216+00
5.476+00
                               B-6

-------
TABLE    B-l.    EMISSIONS  DATA FOR CCU REGENERATION   (continued)
Combustion
type
Partial
Partial
NA
NA
Complete
Partial
Complete
Partial
NA
Complete
Partial
Partial
Partial
Partial
Complete
Partial
Partial
Partial
NA
Complete
Partial
Partial
Partial
Partial
Partial
Partial
Complete
Partial
Partial
Partial
Partial
Partial
Partial
Partial
Partial
Partial
Hydro
treat
Yes
NA
NA
NA
Yes
No
Yes
Yes
NA
Yes
No
NA
No
NA
Yes
NA
NA
NA
NA
Yes
Yes
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Vac
APC System
C\COB\ESP
C\COB\ESP
C
ESP
WHB\C\ESP
COB
ESP
C\COB\ESP
ESP
NA
C\ESP\COB
C\COB\ESP
I
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\ESP
WHB\ESP\CO
B
C\COB\ESP
1
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
WHB\ESP\CO
B
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
C\COB\ESP
mr^nRVPRp
Sample
location
ESP Outlet
ESP Outlet
Cyclone Outlet
ESP Outlet
ESP Outlet
COB Outlet
ESP Outlet
ESP Outlet
ESP Outlet
NA
COB Outlet
ESP Outlet
Regen Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
COB Outlet
ESP Outlet
Regen Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
COB Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
ESP Outlet
PSP Hi if lot
Substance
Nickel
Nickel
Nickel
Nickel
Nickel
Nickel
Nickel
Nickel
Nickel
Nickel
Nickel
Nickel
Nickel
Selenium
Selenium
Selenium
Selenium
Selenium
Selenium
Selenium
Selenium
Selenium
Selenium
Selenium
Selenium
Chlorine
HO
HCI
HCI
5F Total
6F 123478
6F 123678
6F 234678
6F Total
7D 1234678
7R Tntsil
Data
source
Test
Test
ICR
ICR
ICR
114
114
Test
Test
SV
ICR
Test
Test
ICR
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Toot
Factor
(Ib/mm bbl)
6.40e+00
6.54e+00
7.196+00
8.03e+00
1.056+O1
1.34e+01
1.356+01
1.41e+01
2.219+01
2.79e+01
4.31e+01
4.536+01
3.366+02
2.006-02
3.236-02
3.38e-02
2.54e-01
4.236-01
9.346-01
9.446-01
2.02e+00
3.346+00
4.969+00
7.616+00
1.406+01
5.046+00
5.28e+02
6.67e+02
8.40e+02
5.51e-07
6.24e-07
3.756-07
6.516-07
1.076-06
9.45e-07
O AXaJYT
APC = air pollution control
C = cyclone
COB = carbon monoxide boiler
ESP = electrostatic precipitator
I = incinerator
ICR = information collection request
Ib/mm bbl = pounds per million barrels
NA = not available
VS = venturi scrubber
WHB = waste heat boiler
5F = pentachlorodibenzofuran
6F - hexaohlorodibenzofuran
7D = heptachlorcdibenzo-p-dioxin
                                              B-7

-------
TABLE   B-l.  EMISSIONS DATA. FOR CCU REGENERATION  (continued)




114 = section 114 request
                                 B-8

-------
TABLE B-2 .
EMISSIONS DATA FOR CRU REGENERATION (abbreviations
given at end of table)
Design
Continuous
Cyclic
Continuous
Cyclic
Cyclic
Cyclic
Continuous
Cyclic
Cyclic
Continuous
Continuous
Continuous
Continuous
Continuous
Cyclic
Cyclic
Cyclic
Cyclic
Semi-Regenerativ
e
Cyclic
Semi-Regenerativ
e
Semi-Regenerativ
e
Cyclic
Cyclic
Continuous
Continuous
Continuous
Semi-Regenerativ
e
Semi-Regenerativ
e
Continuous
Continuous
Cyclic
Continuous
Continuous
Continuous
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
APC
System
PC
SCS/Flare
PH
SCS
SCS/Flare
PS
PH
SCS/Flare
None
PH
PH
PH
PH
None
SCS
SCS/Flare
PS
PS
S

None
CI\C
CS

SCS/Flare
SCS/Flare
None
PC
na
S

CI\C
PH
PH
SCS
PC
None
None
CS
CS

VSA

VSA

VSA
Sample
location
Regen Outlet
Regen Outlet
Heater Outlet
SCS Outlet
Regen Outlet
Regen Outlet
Heater Outlet
Flare Outlet
Regen Outlet
Heater Outlet
Heater Outlet
Heater Outlet
Heater Outlet
Regen Outlet
SCS Outlet
Flare Outlet
Regen Outlet
Regen Outlet
S Outlet

Regen Outlet
Cyclone Outlet
CS Outlet

Regen Outlet
Regen Outlet
Regen Outlet
Regen Outlet
Heater Outlet
S Outlet

Cyclone Outlet
Heater Outlet
Heater Outlet
SCS Outlet
Regen Outlet
Regen Outlet
Regen Outlet
CS Outlet
CS Outlet

VSA Outlet

VSA Outlet

VSA Outlet
Type
Uncontrolled
Uncontrolled
Controlled
Controlled
Uncontrolled
Uncontrolled
Controlled
Controlled
Uncontrolled
Controlled
Controlled
Controlled
Controlled
Uncontrolled
Controlled
Controlled
Uncontrolled
Uncontrolled
Controlled

Uncontrolled
Controlled
Controlled

Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Controlled
Controlled

Controlled
Controlled
Controlled
Controlled
Uncontrolled
Uncontrolled
Uncontrolled
Controlled
Controlled

Controlled

Controlled

Controlled
Substance
1,2-Dichloroethane
Benzene
Benzene
Benzene
Benzene
Benzene
Benzene
Hydrogen Sulfide
n-Hexane
Toluene
Toluene
Total Xylene
Total Xylene
VOC (Total)
VOC (Total)
VOC (Total)
VOC (Total)
VOC (Total)
VOC (Total)

VOC (Total)
VOC (Total)
Paniculate

Particulate
Paniculate
Particulate
Particulate
Particulate
Particulate

Particulate
Naphthalene
Naphthalene
PAH (Total)
PAH (Total)
PAH (Total)
PAH (Total)
Cadmium
Chromium

Chromium

Chromium

Chromium
Data
Source
114
114
ICR
114
114
114
ICR
114
114
ICR
ICR
ICR
ICR
114
114
114
114
114
114

114
114
Test

114
114
114
114
Test
114

114
ICR
ICR
114
114
114
114
Test
Test

ICR

ICR

ICR
Factor
(Ib/mm bbl)

5.00e-03
1.00B-01
2.14e-01
4.276+00
6.54e+00
7.098+00
7.10e-05
8.566+02
2.70e-01
1.89e+01
1.90e-01
1.37e+01
5.859+00
1.71e+01
7.966+01
1.996+02
6.426+02
7.41 e+02

1.74e+03
7.990+03
5.796-04

5.946-03
3.49e+00
5.856+00
2.70e+01
1.786+03
2.596+03

2.486+04
1.006-02
9.506-01
4.476+00
4.35e+02
9.57e+02
3.798+03
9.736-08
6.556-07

1.508-02

1.508-02

2.108-02
B-9

-------
TABLE  B-2.  EMISSIONS DATA FOR CRU REGENERATION (continued)
Design
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Cyclic
Continuous
Continuous
Continuous
Continuous
Continuous
Semi-Regenerativ
e
Continuous
Continuous
Continuous
Continuous
Continuous
Cyclic
Semi-Regenerativ
e
Cyclic
Cyclic
Cyclic
Cyclic
Cyclic
Cyclic
Continuous
Continuous
Cyclic
Cyclic
Semi-Regenerativ
e
Continuous
Cyclic
Continuous
Continuous
Continuous
Continuous
Cyclic
Cyclic
ARC
System
CS
CS
CS
CS

VSA

VSA

VSA
SCS
None
None
None
na
None
None

None
None
None
None
PC
SCS/Flare
CS

PS
SCS/Flare
None
None
SCS
SCS/Flare
PC
None
None
None
None

None
None
None
None
None
None
None
None
Sample
location
CS Outlet
CS Outlet
CS Outlet
CS Outlet

VSA Outlet

VSA Outlet

VSA Outlet
SCS Outlet
Regen Outlet
Regen Outlet
Regen Outlet
Heater Outlet
Regen Outlet
Regen Outlet

Regen Outlet
Regen Outlet
Regen Outlet
Regen Outlet
Regen Outlet
Regen Outlet
CS Outlet

Regen Outlet
Flare Outlet
Regen Outlet
Regen Outlet
SCS Outlet
Regen Outlet
Regen Outlet
Regen Outlet
Regen Outlet
Regen Outlet
Regen Outlet

Regen Outlet
Regen Outlet
Regen Outlet
Regen Outlet
Regen Outlet
Regen Outlet
Regen Outlet
Regen Outlet
Type
Controlled
Controlled
Controlled
Controlled

Controlled

Controlled

Controlled
Controlled
Uncontrolled
Uncontrolled
Uncontrolled
Controlled
Uncontrolled
Uncontrolled

Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Controlled

Uncontrolled
Controlled
Uncontrolled
Uncontrolled
Controlled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled

Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Substance
Lead
Manganese
Mercury
Nickel

Nickel

Nickel

Nickel
Chlorine
Chlorine
Chlorine
Chlorine
Chlorine
Chlorine
Chlorine

Chlorine
Chlorine
Chlorine
Chlorine
Chlorine
HCI
HCI

HCI
HCI
HCI
HCI
HCI
HCI
HCI
HCI
HCI
HCI
HCI

HCI
HCI
HCI
HCI
HCI
HCI
HCI
HCI
Data
Source
Test
Test
Test
Test

ICR

ICR

ICR
114
114
SV
114
Test
114
ICR

114
114
ICR
114
114
114
Test

114
114
114
114
114
114
114
114
114
114
ICR

SV
114
114
114
114
114
114
114
Factor
(Ib/mm bbl)
3.036-07
7.826-03
1.909-08
3.27e-06

3.50e-02

3.50e-02

4.906-02
2.580-01
4.400-01
4.506-01
6.006-01
1.41e+01
1.46e+01
8.20e-f01

9.309+01
1.16e+02
1.75e-f02
1,838+02
4.086+02
3.106-02
5.776-02

1.006-01
1.506-01
1.416+00
3.246+00
4.006+00
2.516+01
2.716+01
3.406+01
4.496+02
4.496+02
4.526+02

5.406+02
5.750+02
6.716+02
7.526+02
7.896+02
9.426+02
1.126+03
1.146+03
                               B-10

-------
TABLE  B-2.  EMISSIONS  DATA FOR CRU REGENERATION (continued)
Design
Continuous
Continuous
Cyclic
Continuous
Continuous
Continuous
Cyclic
Sem i-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
APC
System
None
na
None
None
None
None
None
CS

Cf\Flare

CS

CIXFIare

CIVFIare

CIXFIare

CI\Flare

CS

CIXFIare

CI\Flare

CS

CI\Flare

CIXFIare

CS

CIXFIare

CI\Flare

CINRare

CS

CS

CI\Flare

CI\Flare

CS

CKFIare
Sample
location
Regen Outlet
Heater Outlet
Regen Outlet
Regen Outlet
Regen Outlet
Regen Outlet
Regen Outlet
CS Outlet

Regen Outlet

CS Outlet

Cl Outlet

Regen Outlet

Regen Outlet

Regen Outlet

CS Outlet

Cl Outlet

Regen Outlet

CS Outlet

Cl Outlet

Regen Outlet

CS Outlet

Cl Outlet

Regen Outlet

Regen Outlet

CS Outlet

CS Outlet

Cl Outlet

Regen Outlet

CS Outlet

Cl Outlet
Type
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Uncontrolled
Controlled

Uncontrolled

Controlled

Controlled

Uncontrolled

Uncontrolled

Uncontrolled

Controlled

Controlled

Uncontrolled

Controlled

Controlled

Uncontrolled

Controlled

Controlled

Uncontrolled

Uncontrolled

Controlled

Controlled

Controlled

Uncontrolled

Controlled

Controlled
Substance
HCI
HCI
HCI
HCI
HCI
HCI
HCI
4F 2378

4F 2378

4F Total

4F Total

4F Total

5D 12378

5D Total

5F 12378

5F 12378

5F 12378

5F 23478

5F 23478

5F 23478

5F Total

5F Total

5F Total

6D 123478

60 123789

6D Total

6D Total

6D Total

6F 123478

6F 123478
Data
Source
ICR
Test
114
114
114
114
114
Test

Test

Test

Test

Test

Test

Test

Test

Test

Test

Test

Test

Test

Test

Test

Test

Test

Test

Test

Test

Test

Test

Test
Factor
(Ib/mm bbl)
1.246+03
2.17e403
2.39e+03
3.16e+03
3.609+03
3.97B+03
8.439+03
8.649-12

3.849-10

8.649-12

1.506-09

4.48e-09

2.236-10

5.896-10

1.496-11

1.79e-10

7.756-10

1.106-11

3.536-10

1.816-09

6.106-11

2.380-09

8.486-09

1.986-10

5.786-12

1.25B-11

4.606-10

2.13e-09

2.910-11

3.966-10
                                B-ll

-------
TABLE  B-2.  EMISSIONS DATA FOR CRU REGENERATION (continued)
Design
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
9
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
ARC
System
CIXFIare
CS
CI\Flare
CI\Flare
CS
CI\Flare
CI\Flare
CS
CIVFIare
CIVFIare
CS
CI\Flare
CI\Flare
CS
CI\Rare
CI\Flare
CS
CI\Flare
CI\Flare
CS
CI\Flare
CI\Flare
CS
CI\Flare
CI\Flare
CS
CI\Flare
Sample
location
Regen Outlet
CS Outlet
Cl Outlet
Regen Outlet
CS Outlet
Cl Outlet
Regen Outlet
CS Outlet
Cl Outlet
Regen Outlet
CS Outlet
Cl Outlet
Regen Outlet
CS Outlet
Cl Outlet
Regen Outlet
CS Outlet
Cl Outlet
Regen Outlet
CS Outlet
Cl Outlet
Regen Outlet
CS Outlet
Cl Outlet
Regen Outlet
CS Outlet
Regen Outlet
Type
Uncontrolled
Controlled
Controlled
Uncontrolled
Controlled
Controlled
Uncontrolled
Controlled
Controlled
Uncontrolled
Controlled
Controlled
Uncontrolled
Controlled
Controlled
Uncontrolled
Controlled
Controlled
Uncontrolled
Controlled
Controlled
Uncontrolled
Controlled
Controlled
Uncontrolled
Controlled
Uncontrolled
Substance
6F 123478
6F 123678
6F 123678
6F 123678
6F 234678
6F 234678
6F 234678
6F Total
6F Total
6F Total
7D 1234678
7D 1234678
7D 1234678
7D Total
7D Total
7D Total
7F 1234678
7F 1234678
7F 1234678
7F 1234789
7F 1234789
7F 1234789
7F Total
7F Total
7F Total
80
8D
Data
Source
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test
Test 
Test
Test
Test
Test
Test
Test
Test
Factor
(Ib/mm bbl)
1.756-09
2.916-11
5.30e-1 0
1.78e-09
1.136-11
1.04e-09
2.056-09
5.156-1 1
3.936-09
1.30e-08
9.456-12
6.356-10
1.166-09
1.906-11
1.026-09
2.30e-09
1.37e-11
1.546-09
4.876-09
9.736-12
9.196-10
1.336-09
2.226-11
2.876-09
8.10e-09
1.996-11
4.23e-09
                               B-12

-------
Design
Semi-Regenerativ
e
Sem i-Regenerati v
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Reganerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
e
Semi-Regenerativ
a
ARC
System
CIVFIare

CS

CI\Flare

CI\Flare

VSA

VSA

VSA

VSA

VSA

VSA
Sample
location
Cl Outlet

CS Outlet

Cl Outlet

Regen Outlet

VSA Outlet

VSA Outlet

VSA Outlet

VSA Outlet

VSA Outlet

VSA Outlet
Type
Controlled

Controlled

Controlled

Uncontrolled

Controlled

Controlled

Controlled

Controlled

Controlled

Controlled
Substance
8D

8F

8F

8F

Total PCDD

Total PCDD

Total PCDD

Total PCDF

Total PCDF

Total PCDF
Data
Source
Test

Test

Test

Test

ICR

ICR

ICR

ICR

ICR

ICR
Factor
(Ib/mm bbl)
4.456-09

1.86e-11

7.86e-10

1.676-09

3.008-09

3.106-09

4.206-09

2.106-08

3.006-08

2.20e-02
APC = air pollution control
C = cyclone
Cl = caustic injection
CS = caustic scrubber
I = incinerator
ICR = Information collection request
Ib/mm bbl = pounds per million barrels
NA = not available
PC = packed column
PCDD = polychlorinated dibenzo-p-dioxins
PCDF = polychlorinated dibenzofurans
PH = process heater
PS = plate and spray
SCS = spray circulating solution
ST = spray tower
VRS = vortex scrubber
VS = venturi scrubber
WHB = waste heat boiler
114 = section 114 request
4D - 8D = chlorodibenzo-p-dioxins (tetra- through octa-)
4F - 8F = chlorodibenzofurans (tetra- through octa-)
                                                        B-13

-------
Table B-3.  HAP Emission Data for SRU Plant Vent
A
JKBBWD&&DE
f&R&tfiL&EftyrfE
TOTAL !HXP (affsyjls)
fOW&IL'D'EfffJVE
cyxi*(PDT,CQ(M!FD
RCEIUL'&Eyfy&L
"fOSfM&LWiyty&L
cyyo^yDf, COMS*D
ACEZwp&tyvL
fonfy&LUftyfyr/E
cy$i9{iT/B COMS
RCEfffiLGfEyfyiyE,
TOTAL Jff3
27701 VVm3
27701 1^Ey&3
27701 VEmA
27701 1^E3\ff4
27701 VE$T4
27701
20501 iSEJfTl
20501 VENTl
20501 VENT 1
20501 VENT 1
20501 VENT 1
20501 VENT 1
J VENTS
J VENTS
J
20701 Vent 1
20701 Vent 2
20701 Vent 3
20701 Vent 4
20701 Vent 5
20701
20604 VENT 3
20604 VENT 4
20604
G VENTS
F VENT 10
F VENT 10
27903 VENT 1
28103 VENT1
28103 VENT1
28103 VENT 2
28103 VENT 2
28103 VENTS
28103 VENT 3
28103
Vent 'Description
CLUUS
CLXUS

CLAUS
CLUUS
CLA11S
CLUUS
CLUUS
CLSIUS
CLUUS
CLUUS
CLA11S

suapux.
SIILTUX
SULFUR
SULFUR
SULFUR
SULFUR
CLAUS/TGCU
CLAUS/TGCU







Isaigos
Type





















UnspecTGT
UnspecTGT
UnspecTGT
UnspecTGT
UnspecTGT

SULFUR PLANT
SULFUR PLANT

SCU2H-GCU
SRU 1/2
SRU 1/2
GLAUS
GLAUS -
GLAUS -
GLAUS -
GLAUS -
GLAUS -
CLAUS-



Tail gas
Tail gas

BEAVON
BEAVON
BEAVON
BEAVON
BEAVON
BEAVON

XSODl
Incinerator
Incinerator

Incinerator
Incinerator
Incinerator
Incinerator
Incinerator
Incinerator
Incinerator
Incinerator
Incinerator









Incinerator
Incinerator
Incinerator
Incinerator
Incinerator

Incinerator
Incinerator


Incinerator
Incinerator
Incinerator







$JIU













247.5
247.5
247.5
247.5
247.5
247.5
357.5
357.5

132
132
132
132
132

225
225

1485
55
55








"Emissions
0.0012
0.0080
0.0092
4.7^08
42E-10
7.&E-10
4.7&08
4JHE-10
7.&E-10
0.0221
0.0150
0.0027
0.0399
0.003
0.50
0.80
0.011
0.002
1.32
0.018
1.43
1.5
0.15
2.67
2.37
0.33
1.35
6.86
3.5
3.5
7.0
13.6
0.39
1.42
21.7
16.32
0.20
6.97
0.28
24.34
0.20
48.30
"Emissions
((6/1000 ton)













0.07
11J07
17.71
0.24
0.04
29.14
0.28
22.0
22.2
6.14
110.7
98.4
13.8
55.9
285
85.2
85.2
170.5
50.18
38.9
141.5








'Data
Source
ICR,assmeconcinppM
Id(_assume cone in ppm

ICR,asstane cone in ppm
ICS^assume cone in ppm
ICS(_ossuase cone in ppm
ICR_assuKi cone in ppm
lCR.assumc cone in ppm
Id^assutiu cone in ppm
!CH.assumt cone in ppm
ICS^assume cone in ppm
IGK^assiune cone in ppm

114 "Response
114 Response
114 Response
114 Response
114 Response
114 Response
114 Response
114 Response

D. Hathaway (1993
SourceTest - Sulfur
Production Rate
from Site
Visit Data)

114 Response
114 Response

114 Response
114 Response
114 Response
ICR
ICR
ICR
ICR
ICR
ICR
ICR

                       B-14

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                            Table  B-3.   HAP Emission Data for  SRU  Plant Vent
faafitu
9&KP I'D
Vent
timber
Vent (Description
Taifgas
Type
XSOD1
(tp<0
"Emissions
'Emissions
(16/1400 ton)
'Data
Source
CARBONYLSULFIDE    28282                        Unpec.TGT

CARBON DISULFIDE       29403   VENT 1    CLAUS      BEAVON
CARBONYLSULFIDE      29403   VENT 1    CLAUS      BEAVON
CARBON DISULFIDE       29403   VENT 2    CLAUS      BEAVON
CARBONYLSULFIDE      29403   VENT 2    CLAUS      BEAVON
CARBON DISULFIDE       29403   VENTS    STRETFORD
CARBONYLSULFIDE      29403   VENT 3    STRETFORD
TOTAL HAP (all SRUs)      29403
Incinerator
Incinerator
50.0

244
15.1
312
16.3
0.21
1.06
589
D Hathaway-all SRU vents

\CRassumtctmcinppm
\CR assume cone in ppm
\CRassumeconcinppm
\CRassumtamtinppm
\CRassumeccmcinppm
ICR assume cone in ppm
                                                             B-15

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