Assessment of Control Technology Options 

For Petroleum Refineries in the Mid-Atlantic Region 

Final Report

January, 2007 
i 

About MARAMA 

The Mid-Atlantic Regional Air Management Association is an association of ten state and local 

air pollution control agencies. MARAMA's mission is to strengthen the skills and capabilities of 

member agencies and to help them work together to prevent and reduce air pollution impacts in 

the Mid-Atlantic Region. 

MARAMA provides cost-effective approaches to regional collaboration by pooling resources to 

develop and analyze data, share ideas, and train staff to implement common requirements. 

The following State and Local governments are MARAMA members: Delaware, the District of 

Columbia, Maryland, New Jersey, North Carolina, Pennsylvania, Virginia, West Virginia, 

Philadelphia, and Allegheny County, Pennsylvania. 

About MACTEC Federal Programs, Inc. 

MACTEC, Inc. is a leader in the engineering, environmental and remedial construction 

industries. MACTEC provides premier management, technical, and professional services to help 

clients successfully manage complex businesses, projects, and facilities. Now operating with 

over 100 U.S. offices and 4,000 employees with specialists in over 50 scientific and engineering 

disciplines, MACTEC has the resources to perform virtually any scope of work, regardless of 

location, size or complexity. 

MACTEC Federal Programs, Inc. is a division of MACTEC that provides these same services 

tailored to meet the unique needs of government agencies, including state/local agencies and 

federal agencies. 

For copies of this report contact: 

MARAMA 

Mid-Atlantic Regional Air Management Association 

711 West 40th Street 

Suite 312 

Baltimore, MD 21211 

phone 410.467.0170 

fax 410.467.1737 

http://www.marama.org/
Assessment of Control Technology Options 

For Petroleum Refineries 

In the Mid-Atlantic Region 

Final Technical Support Document 

Prepared for: 

Mid-Atlantic Regional Air Management Association (MARAMA) 

Prepared by: 

MACTEC Federal Programs, Inc. 

560 Herndon Parkway, Suite 200, Herndon, VA 20170 

January 31, 2007 

______________________ ______________________ 

Edward Sabo Douglas A. Toothman 

Principal Scientist Principal Engineer 
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ACKNOWLEDGEMENTS 

MARAMA gratefully acknowledges the funding support provided by the United States 

Environmental Protection Agency. This project was funded by grants from the U.S. 

Environmental Protection Agency, Region II and Region III. 

The following members of the Technical Oversight Committee (TOC) provided directions 

guiding the project, reviewed the drafts of this report and gave insightful comments including: 

Ravi Rangan, Delaware DNREC 

Bruce Steltzer, Delaware DNREC 

Max Friedman, New Jersey DEP 

Ray Papalski, New Jersey DEP 

Gopal Sistla, New York DEC 

Thomas Barsley, Philadelphia AMS 

Thomas Huynh, Philadelphia AMS 

Henry Kim, Philadelphia AMS 

Keith Lemchak, Philadelphia AMS 

Tom Weir, Philadelphia AMS 

Edward Wiener, Philadelphia AMS 

David Brown, Pennsylvania DEP 

Wick Havens, Pennsylvania DEP 

George Monacky, Pennsylvania DEP 

Sachin Shankar, Pennsylvania DEP 

Brian Trowbridge, Pennsylvania DEP 

Virendra Triveti, Pennsylvania DEP 

Yogesh Doshi, Virginia DEQ 

Fred Durham, West Virginia DEP 

MARAMA’s project manager was Bill Gillespie, with oversight from Susan S.G. Wierman, 

Executive Director of MARAMA. 
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Table of Contents 

EXECUTIVE SUMMARY .......................................................................................................... 1

1.0 EMISSION INVENTORY AND EXISTING REQUIREMENTS.................................. 1-1

1.1 EMISSION INVENTORY .......................................................................................................1-1

1.1.1 EMISSIONS BY REFINERY..............................................................................................1-2

1.1.2 EMISSIONS BY REFINERY PROCESS ...........................................................................1-5

1.1.3 COMPARISON OF MARAMA EMISSIONS TO OTHER STATES................................1-7

1.1.4 EMISSION UNCERTAINTIES ..........................................................................................1-8

1.2 EXISTING REQUIREMENTS ................................................................................................1-8

1.2.1 FEDERAL REGULATIONS...............................................................................................1-8

1.2.2 STATE/LOCAL REGULATIONS ......................................................................................1-9

1.2.3 PERMIT REQUIREMENTS .............................................................................................1-10

1.2.4 REQUIREMENTS FOR ENFORCEMENT SETTLEMENTS.........................................1-10

1.3 SELECTION OF SOURCE CATEGORIES FOR FURTHER EVALUATION ....................1-11

1.4 REFERENCES .......................................................................................................................1-12

2.0 CATALYTIC AND THERMAL CRACKING UNITS.................................................... 2-1

2.1 PROCESS DESCRIPTION ......................................................................................................2-1

2.2 EMISSION INVENTORY .......................................................................................................2-3

2.3 EXISTING REQUIREMENTS ................................................................................................2-5

2.3.1 FEDERAL REGULATIONS...............................................................................................2-5

2.3.2 STATE REGULATIONS ....................................................................................................2-6

2.3.3 PERMIT REQUIREMENTS ...............................................................................................2-6

2.3.4 REQUIREMENTS FROM RECENT ENFORCEMENT SETTLEMENTS.......................2-6

2.4 AVAILABLE CONTROL TECHNOLOGIES ......................................................................2-13

2.4.1 SO2 CONTROLS ...............................................................................................................2-13

2.4.1.1 Wet Scrubbing...........................................................................................................2-13

2.4.1.2 DeSOx Additives.......................................................................................................2-16

2.4.1.3 Feed Hydrotreatment .................................................................................................2-16

2.4.2 NOX CONTROLS .............................................................................................................2-17

2.4.3 PM CONTROLS................................................................................................................2-19

2.4.3.1 Wet Scrubbing...........................................................................................................2-19

2.4.3.2 Electrostatic Precipitators..........................................................................................2-19

2.4.3.3 SBS Injection Technology.........................................................................................2-19

2.4.3.4 Third Stage Separators ..............................................................................................2-21

2.4.4 CO CONTROLS ................................................................................................................2-22

2.4.4.1 CO Boilers.................................................................................................................2-22

2.4.4.2 CO Combustion Promoters........................................................................................2-22

2.4.5 VOC CONTROLS .............................................................................................................2-23
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2.5 COSTS AND AVAILABILITY .............................................................................................2-23

2.6 REFERENCES .......................................................................................................................2-25

3.0 BOILERS AND PROCESS HEATERS ............................................................................ 3-1

3.1 PROCESS DESCRIPTION ......................................................................................................3-1

3.2 EMISSION INVENTORY .......................................................................................................3-1

3.3 EXISTING REQUIREMENTS ................................................................................................3-3

3.3.1 FEDERAL REQUIREMENTS............................................................................................3-3

3.3.2 STATE REGULATIONS ....................................................................................................3-6

3.3.3 PERMIT REQUIREMENTS ...............................................................................................3-7

3.3.4 REQUIREMENTS FROM RECENT ENFORCEMENT SETTLEMENTS.......................3-7

3.4 AVAILABLE CONTROL TECHNOLOGIES ......................................................................3-11

3.4.1 SO2 CONTROLS...............................................................................................................3-11

3.4.1.1 Wet Scrubbers ...........................................................................................................3-11

3.4.1.2 Spray Dry Scrubbers..................................................................................................3-11

3.4.1.3 Dry Scrubbers............................................................................................................3-12

3.4.2 NOX CONTROLS .............................................................................................................3-12

3.4.2.1 Low NOx Burners .....................................................................................................3-12

3.4.2.2 Combustion Air Modifications..................................................................................3-15

3.4.2.3 SNCR.........................................................................................................................3-16

3.4.3 SELECTIVE CATALYTIC REDUCTION (SCR)............................................................3-17

3.4.4 PM CONTROLS................................................................................................................3-17

3.5 COSTS AND AVAILABILITY .............................................................................................3-17

3.6 REFERENCES .......................................................................................................................3-20

4.0 FLARES................................................................................................................................4-1

4.1 PROCESS DESCRIPTION ......................................................................................................4-1

4.2 EMISSION INVENTORY .......................................................................................................4-2

4.3 EXISTING REQUIREMENTS ................................................................................................4-6

4.3.1 FEDERAL REQUIREMENTS............................................................................................4-6

4.3.2 STATE REGULATIONS ....................................................................................................4-7

4.3.3 REQUIREMENTS FROM RECENT ENFORCEMENT SETTLEMENTS.......................4-7

4.4 AVAILABLE CONTROL OPTIONS......................................................................................4-8

4.4.1 FLARE GAS RECOVERY UNITS.....................................................................................4-9

4.4.2 CALIFORNIA REGULATIONS.......................................................................................4-10

4.4.2.1 BAAQMD .................................................................................................................4-10

4.4.2.2 SCAQMD..................................................................................................................4-10

4.4.3 TEXAS REGULATIONS..................................................................................................4-11

4.5 COSTS AND AVAILABILITY .............................................................................................4-12

4.5.1 FLARE GAS RECOVERY UNIT .....................................................................................4-12

4.5.2 COMPLIANCE WITH SCAQMD RULE 1118................................................................4-12
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4.5.3 COMPLIANCE WITH BAAQMD RULE 12 ...................................................................4-12

4.6 REFERENCES .......................................................................................................................4-17

5.0 FUGITIVE EQUIPMENT LEAKS.................................................................................... 5-1

5.1 PROCESS DESCRIPTION ......................................................................................................5-1

5.2 EMISSION INVENTORY .......................................................................................................5-1

5.3 EXISTING REQUIREMENTS ................................................................................................5-3

5.3.1 FEDERAL REGULATIONS...............................................................................................5-3

5.3.2 STATE REGULATIONS ....................................................................................................5-4

5.3.3 PERMIT REQUIREMENTS ...............................................................................................5-4

5.3.4 REQUIREMENTS FROM RECENT ENFORCEMENT SETTLEMENTS.......................5-5

5.4 AVAILABLE CONTROL TECHNOLOGIES ........................................................................5-5

5.4.1 ENHANCED LDAR............................................................................................................5-5

5.4.2 SMART LDAR ....................................................................................................................5-7

5.5 COSTS AND AVAILABILITY ...............................................................................................5-8

5.6 REFERENCES .......................................................................................................................5-11

6.0 WASTEWATER TREATMENT ....................................................................................... 6-1

6.1 PROCESS DESCRIPTION ......................................................................................................6-1

6.2 EMISSION INVENTORY .......................................................................................................6-3

6.3 EXISTING REQUIREMENTS ................................................................................................6-5

6.3.1 FEDERAL REQUIREMENTS............................................................................................6-5

6.3.2 STATE REGULATIONS ....................................................................................................6-6

6.3.3 REQUIREMENTS FROM RECENT ENFORCEMENT SETTLEMENTS.......................6-6

6.4 AVAILABLE CONTROL TECHNOLOGIES ......................................................................6-10

6.4.1 EQUIPMENT COVERS....................................................................................................6-11

6.4.1.1 Water Seals on Drains and Junction Box Vents ........................................................6-11

6.4.1.2 Sealing Manholes ......................................................................................................6-12

6.4.1.3 Enclosing Weirs and Hard Piping .............................................................................6-13

6.4.1.4 Installing Domed Roofs on Sludge Tanks.................................................................6-13

6.4.2 POLLUTION CONTROL EQUIPMENT .........................................................................6-13

6.4.2.1 Air & Steam Stripping...............................................................................................6-13

6.4.2.2 Carbon Adsorption ....................................................................................................6-14

6.4.2.3 Combustion Devices..................................................................................................6-15

6.4.3 REDUCE VOCS FROM WASTEWATER.......................................................................6-15

6.4.4 SECONDARY TREATMENT CONTROL OPTIONS.....................................................6-16

6.5 COSTS AND AVAILABILITY .............................................................................................6-17

6.6 REFERENCES .......................................................................................................................6-19

7.0 STORAGE TANKS ............................................................................................................. 7-1

7.1 PROCESS DESCRIPTION ......................................................................................................7-1
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7.1.1 FIXED ROOF TANKS ........................................................................................................7-1

7.1.2 EXTERNAL FLOATING ROOF TANKS..........................................................................7-2

7.1.3 INTERNAL FLOATING ROOF TANKS...........................................................................7-4

7.1.4 DOMED EXTERNAL FLOATING ROOF TANKS ..........................................................7-5

7.1.5 VARIABLE VAPOR SPACE TANKS ...............................................................................7-6

7.1.6 PRESSURE TANKS............................................................................................................7-6

7.2 EMISSION INVENTORY .......................................................................................................7-6

7.3 EXISTING REQUIREMENTS ................................................................................................7-8

7.3.1 FEDERAL REQUIREMENTS............................................................................................7-8

7.3.2 STATE REGULATIONS ..................................................................................................7-10

7.3.3 REQUIREMENTS FROM RECENT ENFORCEMENT SETTLEMENTS.....................7-10

7.4 AVAILABLE CONTROL TECHNOLOGIES ......................................................................7-33

7.4.1 CONTROLS FOR FIXED ROOF TANKS .......................................................................7-33

7.4.1.1 Install an Internal Floating Roof and Seals ...............................................................7-33

7.4.1.2 Vapor Balancing........................................................................................................7-33

7.4.1 FLOATING ROOF TANKS..............................................................................................7-33

7.4.1.3 Weather Shields.........................................................................................................7-34

7.4.1.4 Secondary Seals.........................................................................................................7-34

7.4.2 VAPOR RECOVERY SYSTEMS.....................................................................................7-34

7.4.2.1 Condensation .............................................................................................................7-34

7.4.2.2 Carbon Adsorption ....................................................................................................7-34

7.4.2.3 Absorption .................................................................................................................7-35

7.4.2.4 Incinerators................................................................................................................7-35

7.4.3 MORE STRINGENT STANDARDS ................................................................................7-35

7.4.3.1 Vapor Pressure Criteria .............................................................................................7-36

7.4.3.2 Tank Cleaning ...........................................................................................................7-36

7.4.3.3 Maintenance Programs ..............................................................................................7-37

7.5 COSTS AND AVAILABILITY .............................................................................................7-37

7.6 REFERENCES .......................................................................................................................7-37

8.0 SULFUR RECOVERY UNITS .......................................................................................... 8-1

8.1 PROCESS DESCRIPTION ......................................................................................................8-1

8.2 EMISSION INVENTORY .......................................................................................................8-1

8.3 EXISTING REQUIREMENTS ................................................................................................8-1

8.3.1 FEDERAL REQUIREMENTS............................................................................................8-1

8.3.2 STATE REGULATIONS ....................................................................................................8-1

8.3.3 REQUIREMENTS FROM RECENT ENFORCEMENT SETTLEMENTS.......................8-5

8.4 AVAILABLE CONTROL TECHNOLOGIES ........................................................................8-6

8.4.1 INCREASE CLAUS UNIT CAPACITY.............................................................................8-6

8.4.1.1 Oxygen Enrichment.....................................................................................................8-6

8.4.1.2 Selectox Catalyst .........................................................................................................8-7
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8.4.1.3 SUPERCLAUS® ........................................................................................................8-7

8.4.2 TAIL GAS TREATMENT...................................................................................................8-7

8.4.2.1 SCOT Tailgas Unit......................................................................................................8-7

8.4.2.2 Sulfreen .......................................................................................................................8-8

8.4.2.3 Beaven Process............................................................................................................8-8

8.4.2.4 Stretford Process..........................................................................................................8-9

8.4.2.5 Clauspol.......................................................................................................................8-9

8.4.2.6 PROClaus ....................................................................................................................8-9

8.4.2.7 LO-CAT® ..................................................................................................................8-10

8.4.2.8 FLEXSORB®.............................................................................................................8-12

8.4.2.9 Emission Free Claus Unit..........................................................................................8-12

8.4.2.10 Tail Gas Scrubbers & Incinerators ............................................................................8-12

8.5 COSTS AND AVAILABILITY .............................................................................................8-13

8.6 REFERENCES .......................................................................................................................8-16

APPENDIX A - METHODOLOGY FOR ESTIMATING EMISSION REDUCTIONS 

FROM MODEL RULES 
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List of Tables 

Table ES-1 Key Findings 

Table 1-1 Capacity and Emissions by Refinery for 2002 

Table 1-2 Capacity and Emissions by Refinery for 2009 (Accounting for Growth and 

Effects of On-the-Books and On-the-Way Requirements) 

Table 1-3 Recent Enforcement Settlements Under EPA’s Petroleum Refinery Initiative 

Table 2-1 Emission Inventory for FCCUs and FCUs 

Table 2-2 Summary of MARAMA State Regulations for FCCUs/FCUs 

Table 2-3 Summary of Other State Regulations for FCCUs/FCUs 

Table 2-4 Summary of Permit Requirements for FCCUs/FCUs 

Table 2-5 Summary of Recent Enforcement Settlements for FCCUs/FCUs 

Table 2-6 Control Technology Options for FCCUs and FCUs 

Table 3-1 Emission Inventory for Boilers/Heaters 

Table 3-2 Summary of NSPS Regulations for Boilers & Process Heaters 

Table 3-3 Summary of MARAMA State Regulations 

Table 3-4 Summary of Other State Regulations 

Table 3-5 Summary of Recent Enforcement Settlements 

Table 3-6 Control Technology Options for Boilers and Process Heaters 

Table 4-1 Emission Inventory for Flares 

Table 4-2 Summary of Recent Enforcement Settlements 

Table 4-3 Estimated Costs for Compliance with BAAQMD Rule 12 

Table 4-4 Estimated Costs for Compliance with SCAQMD Rule 1118 

Table 4-5 Control Technology Options for Flares 

Table 5-1 Emission Inventory for Equipment Leaks 

Table 5-2 Control Technology Options for Fugitive Equipment Leaks 

Table 6-1 Emission Inventory for Wastewater Treatment 

Table 6-2 Summary of MARAMA State Regulations 

Table 6-3 Summary of Other State Regulations 

Table 6-4 Control Technology Options for Wastewater Treatment 
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List of Tables (continued) 

Table 7-1 Emission Inventory for Storage Tanks 

Table 7-2 Properties of Group 1 Storage Vessels 

Table 7-3 Summary of MARAMA State Regulations 

Table 7-4 Summary of Other State Regulations 

Table 7-5 Control Technology Options for Storage Tanks 

Table 8-1 Emission Inventory for Sulfur Recovery Units 

Table 8-2 Summary of MARAMA State Regulations 

Table 8-3 Summary of Other State Regulations 

Table 8-4 Summary of Recent Enforcement Settlements 

Table 8-5 Control Technology Options for Sulfur Recovery Units 

List of Figures 

Figure ES-1 Emission Reductions from Consent Decrees and Model Rules - SO2 Emissions 

from Fluidized Catalytic Cracking Units 

Figure ES-2 Emission Reductions from Consent Decrees and Model Rules - NOx Emissions 

from Fluidized Catalytic Cracking Units 

Figure ES-3 Emission Reductions from Consent Decrees and Model Rules - PM Emissions 

from Fluidized Catalytic Cracking Units 

Figure ES-4 Emission Reductions from Consent Decrees and Model Rules - CO Emissions 

from Fluidized Catalytic Cracking Units 

Figure ES-5 Emission Reductions from Consent Decrees and Model Rules - VOC Emissions 

from Equipment Leaks 

Figure ES-6 Emission Reductions from Consent Decrees and Model Rules - SO2 Emissions 

from Flares 

Figure ES-7 Emission Reductions from Consent Decrees and Model Rules - NOx Emissions 

from Flares 

Figure ES-8 Emission Reductions from Consent Decrees and Model Rules - VOC Emissions 

from Flares 

Figure 1-1 Location of Petroleum Refineries in the Mid-Atlantic States 

Figure 1-2a NOx Emissions by Process 

Figure 1-2b PM2.5 Emissions by Process 

Figure 1-2c SO2 Emissions by Process 

Figure 1-2d VOC Emissions by Process 

Figure 1-3 Comparison of 2002 MARAMA Refinery Capacity and Emissions with Other 

States 
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List of Figures (continued) 

Figure 2-1 Diagram of a Fluidized Catalytic Cracking Unit 

Figure 2-2 EDV-Wet Scrubbing System 

Figure 2-3 Diagrams of HEV and JEV Scrubbers 

Figure 2-4 BOC Gase’s LoTOx Process 

Figure 2-5 SBS Injection Technology Process Diagram 

Figure 2-6 Typical TSS and FSS Arrangement 

Figure 4-1 Diagram of a Typical Steam-Assisted Elevated Flare 

Figure 4-2 Process Flow Diagram of a Flare Gas Recovery Unit 

Figure 6-1 Typical Refinery Wastewater Collection and Treatment System 

Figure 6-2 Liquid Seal Insert for Process Drain 

Figure 6-3 Diagram of Refinery Manhole 

Figure 6-4 Diagram of the Air Stripping Improvement 

Figure 7-1 Vertical Fixed Roof Tank 

Figure 7-2 Pontoon External Floating Roof Tank 

Figure 7-3 Double-Deck External Floating Roof Tank 

Figure 7-4 Internal Floating Roof Tank 

Figure 7-5 Domed External Floating Roof Tank 

Figure 8-1 Typical Claus Sulfur Recovery Unit Process Flow Diagram 

Figure 8-2 Diagram of a 3-Stage PROClaus Process 

Figure 8-3a Direct LO-CAT Tail Gas System 

Figure 8-3-b Indirect LO-CAT Tail Gas System 

Figure 8-4 Lurgi Emission Free Sulfur Recovery Unit 
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Acronyms and Abbreviations 

Acronym Description 

ACT Alternative Control Technique 

BACT Best Available Control Technology 

BART Best Available Retrofit Technology 

CO Carbon Monoxide 

CTG Control Technique Guideline 

EPA U.S. Environmental Protection Agency 

ESP Electrostatic Precipitator 

FCCU Fluid Catalytic Cracking Unit 

FCU Fluid Coking Unit 

FGD Flue Gas Desulfurization 

HAP Hazardous Air Pollutant 

LAER Lowest Achievable Emission Rate 

LDAR Leak Detection and Repair 

MACT Maximum Achievable Control Technology 

MANE-VU Mid-Atlantic/Northeast Visibility Union 

MARAMA Mid-Atlantic Regional Air Management Association 

NESHAP National Emission Standard for Hazardous Air Pollutants 

NH3 Ammonia 

NOx Oxides of nitrogen 

NSPS New Source Performance Standard 

NSR New Source Review 

PM10-PRI Particulate matter less than or equal to 10 microns in diameter that includes both the 

filterable and condensable components of particulate matter 

PM25-PRI Particulate matter less than or equal to 2.5 microns in diameter that includes both 

the filterable and condensable components of particulate matter 

PSD Prevention of Significant Deterioration 

RACT Reasonably Available Control Technology 

SCR Selective Catalytic Reduction 

SIP State Implementation Plan 

SNCR Selective non-Catalytic Reduction 

SO2 Sulfur dioxide 

SRU Sulfur Recovery Unit 

VOC Volatile organic compounds 

WGS Wet Gas Scrubber 

WWTP Wastewater Treatment Plant 
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EXECUTIVE SUMMARY 

This report was prepared for the Mid-Atlantic Regional Air Management Association 

(MARAMA) as part of an effort to assist states in developing State Implementation Plans (SIPs) 

for ozone, fine particles, and regional haze. MARAMA’s members requested assistance in 

assessing control measure options for petroleum refinery emissions and in developing model rule 

provisions. The project was completed in three phases: 

• Phase I analyzed emissions from all refinery processes, identified existing pollution 

control requirements, and assessed refinery processes in order of significance of 

emissions and the potential for additional emission reductions. Section 1 of this report 

presents the results of Phase I. 

• Phase II identified potential control measures for seven refinery processes and evaluated 

the cost and technical feasibility of controls. Sections 2-8 contain the analyses of control 

measure options for the seven refinery processes selected for evaluation. 

• Phase III involved the drafting of model rules for states to consider as they develop their 

SIPs. At the direction of the MARAMA board, model rules were developed for three 

processes: catalytic cracking units, equipment leaks, and flares. 

This Executive Summary presents the key findings of the assessments. 

This Technical Support Document (TSD) is intended to assist States in developing rules or other 

implementation mechanisms, as necessary and appropriate, as part of their control strategy 

analysis process for attaining the 8-hour ozone and fine particulate National Ambient Air Quality 

Standards (NAAQS) and regional haze goals. The TSD does not attempt to define Reasonably 

Available Control Technology (RACT) or any other particular control level for the refinery 

processes it examines. With many jurisdictions in the Mid-Atlantic Region facing the need to 

achieve additional emission reductions, MARAMA was asked by member States to analyze all 

refinery processes and determine where additional emission reductions were achievable. The 

TSD does not attempt to define RACT, best available control technology (BACT), lowest 

achievable emission rate (LAER), or best available retrofit technology (BART). MARAMA 

member States recognize that the determination of these control levels requires the consideration 

of site-specific factors. These considerations will be address in individual State and local 

rulemaking and permitting processes. 

Evaluation of Available Control Options 

MACTEC, in consultation with the MARAMA Refinery Technical Oversight Committee (TOC), 

reviewed the emission inventory and the existing requirements for each of the sources found at 

petroleum refineries. Based on that review, the TOC selected the following refinery processes 

for further evaluation of candidate control measures: 1) catalytic and thermal cracking units, 2) 
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boilers and process heaters, 3) flares, 4) equipment leaks, 5) wastewater treatment, 6) storage 

tanks, and 7) sulfur recovery plants. These categories were chosen because they account for a 

large portion of the emission inventory and there is a potential for obtaining additional emission 

reductions. This study evaluated emissions, existing requirements, and available control 

technology options and typical costs. Table ES-1 presents the key findings regarding the 

emission inventory, existing requirements, and available control options. 

Development of Model Rules 

After reviewing the draft TSD, MARAMA’s TOC instructed MACTEC to prepare three draft 

model rules for fluid catalytic cracking units, enhanced equipment leak detection and repair, and 

flares. While the recent consent decrees provide important air quality benefits, the MARAMA 

TOC decided to develop model rules to (a) to codify and perpetuate the requirements of the 

consent decrees, and (b) provide more stringent requirements where technologically feasible and 

cost-effective options have been identified. The model rule for the fluid catalytic cracking units 

is generally based on the requirements of the recent consent decrees, with a more stringent limit 

for carbon monoxide emissions. The model rule for enhanced LDAR is generally based on the 

requirements of the recent consent decrees, but with a lower leak definition for valves. The 

model rule for flares is primarily based on the requirements of the South Coast Air Quality 

Management District’s recently amended flare rule, which includes more stringent requirements 

for flare gas recovery systems, flare minimization procedures, and flare monitoring. 

Potential Impact of Model Rules 

The assessment found that significant emission reductions will be achieved as a result of 

requirements already in place in recent Consent Decrees for 10 of the 14 petroleum refineries in 

the MARAMA region. Adoption of the model rules would achieve additional emission 

reductions at refineries where consent decrees have not been negotiated. These reductions would 

be modest, however, since the refineries in question are relatively small capacity facilities. Two 

refineries without Consent Decrees are in northwest Pennsylvania, and because of their location, 

modest reductions from these facilities may have little impact on the nonattainment areas. 

Significant reductions in emissions from fluidized catalytic cracking units (FCCUs) will result 

from the implementation of the Consent Decrees. Some additional reductions in emissions from 

FCCUs may be possible, as a few refineries currently are only required to meet the NSPS limit of 

1 lb/1000 lbs coke. The model rule limit of 0.5 lbs/ 1000 lbs coke would reduce PM emissions 

for these refineries by 50 percent. The model rule also reduces the CO limit for the FCCUs. 

Figures ES-1 to ES-4 show the anticipated emission reductions from FCCUs at refineries in the 

MARAMA region. Appendix A documents how the emission reductions were calculated. 
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Implementation of the Consent Decrees enhanced leak detection will reduce VOC emissions 

significantly. Implementation of the model rule will reduce emissions modestly beyond the 

levels established by the recently negotiated consent decrees. Figure ES-5 shows the anticipated 

emission reductions from equipment leaks at refineries in the MARAMA region. 

Implementation of the model rules for flares would reduce refinery emissions beyond the levels 

established by the recently negotiated consent decrees to some extent. Figures ES-6, ES-7, and 

ES-8 show the anticipated emission reductions from flares at refineries in the MARAMA region. 

The flare rule will require better monitoring of flaring emissions, the development and 

implementation of flare monitoring and control of flare emissions. Recent studies at west coast 

refineries and in Texas have shown that flare emissions are larger than originally thought and 

likely larger than estimates contained in the current State emission inventories. As a result of the 

possible underestimation of emissions in the inventories, controlling flares may achieve more 

sizable emission reductions in the “real world” than are currently estimated based on the 

emission inventory. 
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Executive Summary Page ES-4 MACTEC Federal Programs, Inc. 

Table ES-1 Key Findings 

Refinery Process Emission Inventory Existing Requirements Available Control OptFluid Catalytic Cracking Units (FCCUs) and Fluid Coking Units (FCUs) 

There are 12 FCCUs and one FCU in the MARAMA region. These 13 emission units accounted for about 78% of the SO2 and 29% of the NOx emitted from all refinery processes in 2002. As a result of the existing requirements in Consent Decrees, SO2 emissions are expected to be reduced by 90% and NOx emissions by 38% by 2009. 

Eight these FCCUs and the single FCU are required to control SO2 and NOx emissions as a result of Consent Decrees which contain more stringent requirements that existing federal rules, State/local rules, or permit requirements. Four other FCCUs are not affected by the Consent Decrees. 

SO2: 

1) Wet gas scrubber (or of meeting 25 ppmvd @ 

rolling average or 50 pp

day rolling average. Co3,000/ton 2) DeSOx additives capCost Effectiveness*: $5NOx: 

SCR or SNCR system (capable of meeting 20 pday rolling average, and 7-day rolling average, @ 

NOx Cost Effectivenes

Boilers and Process Heaters 

Emissions from these units represent the largest category of NOx emission sources at refineries and the second largest source of SO2 emissions. Boilers and process heaters accounted for 63% of the NOx and 15% of the SO2 emitted from all refinery processes in 2002. As a result of the existing requirements in Consent Decrees, SO2 emissions are expected to be reduced by 32% and NOx emissions by 36% by 2009. 

10 of the 14 refineries are required to control SO2 and NOx emissions as a result of Consent Decrees that contain more stringent requirements that existing federal rules, State/local rules, or permit requirements. The Consent Decrees will generally require the elimination of fuel oil burning in boilers/heaters, compliance with NSPS Subpart J refinery gas H2S limits, and installation of qualifying controls to reduce NOx emissions. 

SO2: 

1) Eliminate or limit liq2) Limit sulfur content 3) Limit hydrogen sulfito NSPS limit of 0.10 gSO2 Cost EffectivenessNOx: 

1) San Joaquin Rule 43lb/MMBtu for gaseous for liquid fuels; Cost Efdetermined. 2) SNCR, SCR, Ultra-lotechnology) capable of Cost Effectiveness*: $7on size of unit and fuel 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Executive Summary Page ES-5 MACTEC Federal Programs, Inc. Refinery Process Emission Inventory Existing Requirements Available Control OptFlares Flares account for about 7% of the 

NOx, 4% of the SO2, and 10% of the VOC emitted at the 14 refineries in 2002. Actual emissions are uncertain due to inadequate monitoring of flare gas flow rates and composition. Evidence from California and Texas suggests that emissions from flaring activities (and other nonroutine releases) may be significantly underreported in current emission inventories. 

Requirements contained in the Consent Decrees are generally more stringent than existing state/local rules and permit requirements. The Consent Decrees require compliance with NSPS emission limits and actions to prevent upsets that result in flaring. 

SO2, VOC, NOx, PM:

Establish and follow flaInstall analyzers to meaheating value, and VOCConduct emissions revianalyses, and take corresignificant flaring eventInstall flare gas recoverCost Effectiveness*: $4SO2, NOx, VOC, and P

Equipment Leaks (Fugitive Emissions) 

Leaking equipment components account for 15% of the VOC emitted at the 14 refineries in 2002. Actual emissions are uncertain due to difficulty in accurately monitoring thousands of individual components. 

The Consent Decrees contain requirements for “enhanced” leak detection and repair programs to reduce fugitive emissions; otherwise subject to NSPS or NESHAP requirements 

VOC:

“Enhanced” leak detectrequirements based on pin the Consent Decrees. LDAR procedures; traininternal and third party definitions; increased mcorrective action for “chstoring and reporting of requirements. Cost Effectiveness*: $1

Wastewater Treatment 

Wastewater treatment accounts for 21% of the VOC emitted at the 14 refineries in 2002 

Many systems already subject to NSPS Subpart QQQ, NESHAP Subpart CC, or NESHAP Subpart FF requirements; Consent Decrees require review and verification of compliance status and corrective actions to correct noncompliance. 

VOC:

For wastewater collecticovers and seals on the reduce fugitive VOC emFor wastewater treatmeinstalling a control devito destroy VOCs releasVOC Cost Effectivenes
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Executive Summary Page ES-6 MACTEC Federal Programs, Inc. Refinery Process Emission Inventory Existing Requirements Available Control OptStorage Tanks Storage tanks account for 26% of 

the VOC emitted at the 14 refineries in 2002 

Most tanks already subject to either NSPS, NESHAP, or state requirements 

VOC:

Install floating roofs in domed fixed roof on exreplace vapor-mounted mounted primary seal; ivapor recovery systems VOC Cost Effectivenes

Sulfur Recovery Units 

Sulfur recovery plants accounted for 2% of the SO2 emitted at the 14 refineries in 2002; over half of all SO2 emissions from sulfur recovery unit come from the Giant Yorktown, VA, SRU. 

The Consent Decrees generally require compliance with NSPS Subpart J and the elimination, control, and monitoring of sulfur pit emissions. The Giant Yorktown refinery is required to install a tail gas unit or equivalent control technology. The ConocoPhillips Bayway refinery is to conduct an optimization study and implement recommendations. 

SO2:

A variety of control tecwhich can meet the NSPppmv, dry basis, correcSO2 Cost Effectiveness

* See Sections 2-8 for a discussion of the references used to determine the cost-effectiveness for each source category. The cost data probtained from the published literature as referenced. In general, the percent reductions and cost data represent data for typical sources t

Site-specific factors can affect the actual cost effectiveness. Incremental costs for sources that already have some level of control will l
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Executive Summary Page ES-7 

MACTEC Federal Programs, Inc. 

Figure ES-1 Emission Reductions from Consent Decrees and Model Rules 

SO2 Emissions from Fluidized Catalytic Cracking Units 

Cracking Units SO2 Emissions

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

2002 2009 with CDs 2009 With Model Rules

SO2 (tpy)

Giant Yorktown 

United Refining 

Sunoco Phila. PB 868

Sunoco Phila. GP 1232

ConocoPhillips Trainer

Sunoco Marcus Hook

ConocoPhillips/Bayway 

Amerada Hess 

Valero 

Sunoco Eagle Point

Premcor FCU

Premcor FCCU

Cracking Unit SO2 Emissions

0

2,500

5,000

7,500

10,000

12,500

15,000

17,500

20,000

Premcor FCCU

Premcor FCU

Sunoco Eagle Point

Valero 

Amerada Hess

ConocoPhillips/Bayway

Sunoco Marcus Hook

ConocoPhillips Trainer

Sunoco Phila. GP 1232

Sunoco Phila. PB 868

United Refining 

Giant Yorktown 

SO2 Tons/year

2002

2009 with CDs

2009 With Model Rules
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Executive Summary Page ES-8 

MACTEC Federal Programs, Inc. 

Figure ES-2 Emission Reductions from Consent Decrees and Model Rules 

NOx Emissions from Fluidized Catalytic Cracking Units 

Cracking Units NOx Emissions

0

1,000

2,000

3,000

4,000

5,000

6,000

2002 2009 with CDs 2009 With Model Rules

NOx (tpy)

Giant Yorktown 

United Refining 

Sunoco Phila. PB 868

Sunoco Phila. GP 1232

ConocoPhillips Trainer

Sunoco Marcus Hook

ConocoPhillips/Bayway 

Amerada Hess 

Valero 

Sunoco Eagle Point

Premcor FCU

Premcor FCCU

Cracking Unit NOx Emissions

0

200

400

600

800

1,000

1,200

1,400

1,600

Premcor FCCU

Premcor FCU

Sunoco Eagle Point

Valero

Amerada Hess

ConocoPhillips/Bayway 

Sunoco Marcus Hook

ConocoPhillips Trainer

Sunoco Phila. GP 1232

Sunoco Phila. PB 868

United Refining 

Giant Yorktown

NOx (tpy)

2002

2009 with CDs

2009 With Model Rules
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Executive Summary Page ES-9 

MACTEC Federal Programs, Inc. 

Figure ES-3 Emission Reductions from Consent Decrees and Model Rules 

PM Emissions from Fluidized Catalytic Cracking Units 

Cracking Units PM Emissions

0

500

1,000

1,500

2,000

2,500

3,000

2002 2009 w/ CDs 2009 w/ Model Rules

PM10 (tpy)

Giant Yorktown 

United Refining 

Sunoco Phila. PB 868

Sunoco Phila. GP 1232

ConocoPhillips Trainer

Sunoco Marcus Hook

ConocoPhillips/Bayway 

Amerada Hess 

Valero 

Sunoco Eagle Point

Premcor FCU

Premcor FCCU

This table shows reductions of total suspended particulate emissions; reductions in PM2.5 are not available. 

Cracking Unit PM Emissions

0

200

400

600

800

Premcor FCCU

Premcor FCU

Sunoco Eagle Point

Valero

Amerada Hess 

ConocoPhillips/Bayway 

Sunoco Marcus Hook

ConocoPhillips Trainer

Sunoco Phila. GP 1232

Sunoco Phila. PB 868

United Refining 

Giant Yorktown

PM10 (tpy)

2002

2009 w/ CDs

2009 w/ Model Rules
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Executive Summary Page ES-10 

MACTEC Federal Programs, Inc. 

Figure ES-4 Emission Reductions from Consent Decrees and Model Rules 

CO Emissions from Fluidized Catalytic Cracking Units 

Cracking Units CO Emissions

0

1,000

2,000

3,000

4,000

5,000

6,000

2002 2009 with CDs 2009 With Model Rules

PM10 (tpy)

Giant Yorktown 

United Refining 

Sunoco Phila. PB 868

Sunoco Phila. GP 1232

ConocoPhillips Trainer

Sunoco Marcus Hook

ConocoPhillips/Bayway 

Amerada Hess 

Valero 

Sunoco Eagle Point

Premcor FCU

Premcor FCCU

Cracking Unit CO Emissions

0

300

600

900

1,200

1,500

1,800

Premcor FCCU

Premcor FCU

Sunoco Eagle Point

Valero

Amerada Hess 

ConocoPhillips/Bayway 

Sunoco Marcus Hook

ConocoPhillips Trainer

Sunoco Phila. GP 1232

Sunoco Phila. PB 868

United Refining 

Giant Yorktown

PM10 (tpy)

2002

2009 with CDs

2009 With Model Rules
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Executive Summary Page ES-11 

MACTEC Federal Programs, Inc. 

Figure ES-5 Emission Reductions from Consent Decrees and Model Rules 

VOC Emissions from Equipment Leaks 

Equipment Leak VOC Emissions

0

200

400

600

800

1,000

1,200

1,400

1,600

2002 2009 w/ CDs 2009 w/ Model Rules

VOC (tpy)

Ergon Newell

Giant Yorktown 

United Refining 

Sunoco Philadelphia

American Refining 

ConocoPhillips Trainer

Sunoco Marcus Hook

ConocoPhillips/Bayway 

Chevron 

Amerada Hess 

CITGO Asphalt 

Valero 

Sunoco Eagle Point

Premcor 

Equipment Leak VOC Emissions

0

100

200

300

400

Premcor 

Sunoco Eagle Point

Valero

CITGO Asphalt 

Amerada Hess

Chevron

ConocoPhillips/Bayway 

Sunoco Marcus Hook

ConocoPhillips Trainer

American Refining 

Sunoco Philadelphia

United Refining 

Giant Yorktown 

Ergon Newell

VOC (tpy)

2002

2009 w/ CDs

2009 w/ Model Rules
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Executive Summary Page ES-12 

MACTEC Federal Programs, Inc. 

Figure ES-6 Emission Reductions from Consent Decrees and Model Rules 

SO2 Emissions from Flaring 

Flaring SO2 Emissions

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

2002 2009 with CDs 2009 With Model Rules

SO2 (tpy)

Ergon Newell

Giant Yorktown 

United Refining 

Sunoco Philadelphia

American Refining 

ConocoPhillips Trainer

Sunoco Marcus Hook

ConocoPhillips/Bayway 

Chevron 

Amerada Hess 

CITGO Asphalt 

Valero 

Sunoco Eagle Point

Premcor 

Flaring SO2 Emissions

0

200

400

600

800

1,000

1,200

Premcor 

Sunoco Eagle Point

Valero

CITGO Asphalt 

Amerada Hess

Chevron

ConocoPhillips/Bayway 

Sunoco Marcus Hook

ConocoPhillips Trainer

American Refining 

Sunoco Philadelphia

United Refining 

Giant Yorktown 

Ergon Newell

SO2 (tpy)

2002

2009 with CDs

2009 With Model Rules
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Executive Summary Page ES-13 

MACTEC Federal Programs, Inc. 

Figure ES-7 Emission Reductions from Consent Decrees and Model Rules 

NOx Emissions from Flaring 

Flaring NOx Emissions

0

200

400

600

800

1,000

1,200

1,400

1,600

2002 2009 with CDs 2009 With Model Rules

NOx (tpy)

Ergon Newell

Giant Yorktown 

United Refining 

Sunoco Philadelphia

American Refining 

ConocoPhillips Trainer

Sunoco Marcus Hook

ConocoPhillips/Bayway 

Chevron 

Amerada Hess 

CITGO Asphalt 

Valero 

Sunoco Eagle Point

Premcor 

Flaring NOx Emissions

0

200

400

600

800

1,000

1,200

Premcor 

Sunoco Eagle Point

Valero

CITGO Asphalt 

Amerada Hess

Chevron

ConocoPhillips/Bayway 

Sunoco Marcus Hook

ConocoPhillips Trainer

American Refining 

Sunoco Philadelphia

United Refining 

Giant Yorktown 

Ergon Newell

NOx (tpy)

2002

2009 with CDs

2009 With Model Rules
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Executive Summary Page ES-14 

MACTEC Federal Programs, Inc. 

Figure ES-8 Emission Reductions from Consent Decrees and Model Rules 

VOC Emissions from Flaring 

Flaring VOC Emissions

0

100

200

300

400

500

600

700

800

2002 2009 with CDs 2009 With Model Rules

VOC (tpy)

Ergon Newell

Giant Yorktown 

United Refining 

Sunoco Philadelphia

American Refining 

ConocoPhillips Trainer

Sunoco Marcus Hook

ConocoPhillips/Bayway 

Chevron 

Amerada Hess 

CITGO Asphalt 

Valero 

Sunoco Eagle Point

Premcor 

Flaring VOC Emissions

0

100

200

300

400

500

Premcor 

Sunoco Eagle Point

Valero

CITGO Asphalt 

Amerada Hess

Chevron

ConocoPhillips/Bayway 

Sunoco Marcus Hook

ConocoPhillips Trainer

American Refining 

Sunoco Philadelphia

United Refining 

Giant Yorktown 

Ergon Newell

VOC (tpy)

2002

2009 with CDs

2009 With Model Rules
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 1 – Emission Inventory and Existing Requirements Page 1-1 

MACTEC Federal Programs, Inc. 

1.0 EMISSION INVENTORY AND EXISTING REQUIREMENTS 

This section presents the results of the Phase I analysis of petroleum refinery emissions and 

existing pollution control requirements. We used this information to rank refinery processes in 

order of significance of emissions, assess the potential for additional emission reductions, and 

select refinery processes for detailed control measure analysis. 

1.1 EMISSION INVENTORY 

Figure 1-1 shows the location of the 14 petroleum refineries in the Mid-Atlantic States. This 

section summarizes the emission inventories for these sources. 

Figure 1-1. Location of Petroleum Refineries in the Mid-Atlantic States 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 1 – Emission Inventory and Existing Requirements Page 1-2 

MACTEC Federal Programs, Inc. 

1.1.1 Emissions by Refinery 

Table 1-1 summarizes the 2002 emission inventory for each of the 14 refineries (note that the 

Sunoco Marcus Hook refinery is split into two facilities in the inventory: one facility for the 

equipment located in Pennsylvania and another facility for the equipment located in Delaware). 

The tables shows the emissions most important to forming ozone and fine particles: carbon 

monoxide (CO), ammonia (NH3), oxides of nitrogen (NOx), particulate matter less than 2.5 

microns (PM2.5), sulfur dioxide (SO2), and volatile organic compounds (VOC). The 2002 

annual emissions serve as the baseline for future SIP development. The 2002 emissions were 

obtained from the 2002 inventories developed by MANEVU and VISTAS. 

Table 1-2 summarizes the projected emission inventory for 2009. The 2009 emissions were 

obtained from the MANEVU and VISTAS projection inventories that were developed to support 

modeling for SIP development. The 2009 inventories include the effects of anticipated growth 

as well as any planned controls that will result in emission reductions between 2002 and 2009 

due to new regulations or enforcement settlements. The growth factors used for projecting 

emissions from 2002 to 2009 came from the U.S. Environmental Protection Agency’s Economic 

Growth Analysis System (EGAS 5.0) and the U.S. Department of Energy’s Annual Energy 

Outlook (2005) projections. The controls factors for 2009 were derived either from data 

supplied that the State/local agencies or from MACTEC’s analysis of the requirements contained 

in the global enforcement settlements. 

Tables 1-1 and 1-2 show how emissions are projected to change between 2002 and 2009: 

• For SO2, refinery emissions are projected to decrease by 69 percent across the region 

between 2002 and 2009 due to requirements currently on-the-books. A primary reason 

for the decrease will be the installation of pollution controls on the catalytic cracking unit 

and fluid coking unit at the Delaware City refinery. Other causes for the decrease in SO2 

emissions include the elimination of fuel oil combustion in boilers/heaters and 

installation of pollution controls at the catalytic cracking units at other refineries. 

• For NOx, refinery emissions are projected to decrease by 12 percent due to requirements 

currently on-the-books. Reductions in NOx emissions are projected to result from 

additional control of emissions from the boilers/heaters and catalytic cracking units at 

some refineries. 

• For VOC and PM2.5, refinery emissions are not projected to change very much between 

2002 and 2009. 

• For CO, an increase in emissions is projected due to forecasts of increased production at 

the refineries. 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 1 – Emission Inventory and Existing Requirements Page 1-3 

MACTEC Federal Programs, Inc. 

Table 1-1 Capacity and Emissions by Refinery for 2002 

 Capacity (barrels/day) 2002 Annual Emissions (tons per year) 

State Refinery/City 

Crude 

Distillation 

Catalytic 

Cracking CO NH3 NOx PM2.5 SO2 VOC 

DE Valero 

Delaware City, DE 180,000 82,000a

 3,858 43 3,535 1,308 34,096 829 

DE SUNCO R M 

Claymont, DE 0 0 183 8 610 31 881 49 

NJ Sunoco Inc. (R&M) 

Westville, NJ 145,000 55,000 280 0 1,478 167 155 1,042 

NJ Valero Refining Co. 

Paulsboro, NJ 160,000 55,000 260 0 1,267 161 4,450 711 

NJ Citgo Asphalt 

Paulsboro, NJ 51,000 0 51 0 147 6 19 28 

NJ Amerada Hess Corp. 

Port Reading, NJ 0 62,500 159 0 406 33 75 344 

NJ Chevron Prods. Co. 

Perth Amboy, NJ 80,000 0 9 0 139 12 18 317 

NJ Conoco Phillips 

Linden (Bayway) NJ 230,000 145,000 332 0 2,213 143 958 430 

PA Sunoco Inc. (R&M) 

Marcus Hook, PA 175,000 105,000 959 5 2,291 302 4,403 489 

PA Conoco Phillips 

Trainer, PA 185,000 53,000 972 7 2,488 97 2,530 299 

PA American Refining 

Bradford, PA 10,000 0 96 0 258 6 1,336 148 

PA Sunoco Inc. (R&M) 

Philadelphia, PA 335,000 123,500 1,806 0 3,112 398 3,982 671 

PA United Refining Co. 

Warren, PA 65,000 26,000 311 24 412 90 2,911 411 

VA Giant 

Yorktown, VA 58,600 28,200 329 0 1,629 658 2,150 1,327 

WV Ergon 

Newell, Congo, WV 19,400 0 140 5 239 11 116 248 

MARAMA Total 1,694,000 653,200 9,745 92 20,224 3,423 58,080 7,343 

a) The Delaware City also has a fluid coking capacity of 46,500 barrels/day. 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 1 – Emission Inventory and Existing Requirements Page 1-4 

MACTEC Federal Programs, Inc. 

Table 1-2 Capacity and Emissions by Refinery for 2009 

(Accounting for Growth and Effects of On-the-Books and On-the-Way Requirements) 

 Capacity (barrels/day) 2009 Annual Emissions (tons per year) 

State Refinery/City 

Crude 

Distillation 

Catalytic 

Cracking CO NH3 NOx PM2.5 SO2 VOC 

DE Valero 

Delaware City, DE 180,000 82,000a

 4,358 38 2,078 806 1,331 742 

DE SUNCO R M 

Claymont, DE 0 0 54 2 158 12 818 37 

NJ Sunoco Inc. (R&M) 

Westville, NJ 145,000 55,000 298 0 684 182 49 761 

NJ Valero Refining Co. 

Paulsboro, NJ 160,000 55,000 344 0 1,076 200 1,339 915 

NJ Citgo Asphalt 

Paulsboro, NJ 51,000 0 55 0 156 7 20 33 

NJ Amerada Hess Corp. 

Port Reading, NJ 0 62,500 190 0 475 38 86 330 

NJ Chevron Prods. Co. 

Perth Amboy, NJ 80,000 0 11 0 180 16 24 145 

NJ Conoco Phillips 

Linden (Bayway) NJ 230,000 145,000 390 0 1,129 160 929 566 

PA Sunoco Inc. (R&M) 

Marcus Hook, PA 175,000 105,000 1,079 6 716 273 236 548 

PA Conoco Phillips 

Trainer, PA 185,000 53,000 1,120 9 1,391 108 542 280 

PA American Refining 

Bradford, PA 10,000 0 106 0 293 4 1,386 148 

PA Sunoco Inc. (R&M) 

Philadelphia, PA 335,000 146,000 1,841 19 2,738 354 1,484 383 

PA United Refining Co. 

Warren, PA 65,000 26,000 382 28 501 97 3,450 202 

VA Giant 

Yorktown, VA 58,600 28,200 336 0 653 247 145 1,466 

WV Ergon 

Newell, Congo, WV 19,400 0 152 6 159 11 117 201 

MARAMA Total 1,694,000 675,700 10,716 108 12,387 2,515 11,956 6,757 

a) The Delaware City refinery City also has a fluid coking capacity of 46,500 barrels/day. 

ConocoPhillips Bayway initially estimated a VOC emissions of 1,629 tons/year from equipment leaks using the "leak/no 

leak" method and AP-42 emission factors consistent with the federal leak definition of 10,000 ppm. Emissions were 

recalculated using actual leak data and EPA correlation equations LeakDas software, resulting in a downward revision to 

233 tons/year. 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 1 – Emission Inventory and Existing Requirements Page 1-5 

MACTEC Federal Programs, Inc. 

1.1.2 Emissions by Refinery Process 

Figures 1-2a through 1-2d show NOx, PM2.5, SO2, and VOC emissions by refinery process. 

Actual emissions for 2002 are shown along side of the projected emissions for 2009. 

The largest category of NOx emissions is the boiler and process heater group. About two-thirds 

of the refinery NOx emissions are from boilers and heaters. Other important NOx sources are 

the cracking/coking units and flares. NOx emissions from boilers and heaters are not expected to 

change much between 2002 and 2009 - anticipated reductions due to enforcement settlements 

and other planned controls appear to be offset by projected growth in fuel combustion. NOx 

emissions from cracking/coking units are projected to decrease by about 50 percent region wide 

due to planned installation of controls on these units. 

The largest category of PM2.5 emissions is the cracking/coking group. About 58 percent of the 

fine particulate is emitted from this group. Boilers/heaters and flares are the other significant 

sources of PM2.5. PM2.5 emissions are projected to remain relatively constant between 2002 

and 2009. 

The four primary sources of SO2 emissions are the cracking/coking units, boilers/heaters, flares, 

and sulfur recovery plants. SO2 emissions from the cracking/coking units are anticipated to 

decline dramatically between 2002 and 2009, primarily because of the installation of pollution 

controls at the Delaware City refinery as well as other refineries in the region. SO2 emissions 

from boilers and heaters are not expected to change much between 2002 and 2009 - anticipated 

reductions due to elimination of the use of fuel oil appears to be offset by projected growth in 

fuel combustion. Little change in SO2 emissions from flares and the sulfur recovery plants are 

projected. 

There are several significant sources of VOC emissions. Storage tanks containing crude oil, 

intermediate process feeds, and refined products represent the largest source of VOCs. 

Wastewater collection and treatment system units (process drains and collectors, oil-water 

separators, air flotation systems, and surface impound basins and ponds) generate VOC 

emissions. VOC emissions occur from process equipment whenever components in the liquid or 

gas stream leak. Components such as pumps, valves, pressure relief valves, and flanges are 

potential sources that can leak due to seal failure. A fourth source of VOC emissions is the 

loading of finished products into marine vessels, tank railcars, and tank trucks. Flaring activities 

also emit VOC. Other activities (cracking/coking units, boilers/heaters, cooling towers, process 

units) also emit VOC to a lesser degree. 

A more detailed breakdown of emissions by specific process at each refinery is contained in the 

control measure assessments in Sections 2-8 of this report.
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 1 – Emission Inventory and Existing Requirements Page 1-6 MACTEC Federal Programs, Inc. 

0

2,5005,0007,500

10,00012,50015,000

Tons/year

Cracking/

Coking Units

Boilers/Heaters

Flares Other

Figure 1-2a NOx Emissions by Process

0

10,00020,00030,00040,00050,000

Tons/year

Cracking/

Coking Units

Boilers/Heaters

Flares 

Figure 1-2c SO2 Emissions by Pr

0

500

1,0001,5002,0002,5003,000

Tons/year

Cracking/

Coking Units

Boilers/Heaters

Flares Other

Figure 1-2b PM2.5 Emissions by Process

0

250500750

1,0001,2501,5001,7502,0002,250

Tons/year

Leaks Tanks Waste

Water

Flares Loa

Figure 1-2d VOC Emissions by Pr

■ 2002 ■ 2009 

■ 2002 ■ 2009 

■ ■ 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 1 – Emission Inventory and Existing Requirements Page 1-7 

MACTEC Federal Programs, Inc. 

1.1.3 Comparison of MARAMA Emissions to Other States 

In addition to comparing emissions by refinery and process, we also compared emissions from 

all refineries in the MARAMA region to other areas of the country with large refining capacity. 

This was done to determine if there were any anomalies, unaccounted for sources, and 

unreasonable data in the MARAMA inventory. 

Figure 1-3 compares capacity and emissions data for the 14 refineries in the MARAMA region 

to the 13 refineries in the Midwest Regional Planning Organization (MRPO) region, 21 refineries 

in California, 17 refineries in Louisiana, and 26 refineries in Texas. The capacity data was 

obtained from the Energy Information Administration, and the emissions data was obtained from 

the EPA’s draft final version of the 2002 National Emission Inventory. 

Figure 1-3 shows that emissions data for the refineries in the MARAMA region are generally 

consistent with the emissions data being reported for the refineries in CA, LA, and TX. For 

example, the 14 refineries in the MARAMA region have about the same crude distillation and 

catalytic cracking capacity as the 21 refineries in California. The NOx, CO, VOC, and PM2.5 

emissions for these two areas are roughly the same. The exception is in the SO2 emissions. As 

mentioned previously, the Delaware City refinery was a very large source of SO2 in 2002 and is 

considered an outlier compared to other refineries. Once these emissions are controlled, this 

apparent anomaly in SO2 emissions will no longer exist. 

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

Crude Capacity Catalytic

Cracking

Capacity

SO2 NOX VOC PM2.5

Capacity 100 Barrels/Day; 

Emissions tons/year

MARAMA

MRPO

CA

LA

TX

Figure 1-3 Comparison of 2002 MARAMA Refinery Capacity and Emissions with Other States 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 1 – Emission Inventory and Existing Requirements Page 1-8 

MACTEC Federal Programs, Inc. 

1.1.4 Emission Uncertainties 

For some refinery sources, such as boilers and cracking units, emissions are monitored 

continuously using sophisticated equipment that provides a fairly accurate estimate of emissions. 

For other sources, emissions cannot easily be directly measured and the estimates of emissions 

from these sources are more uncertain. For example, VOC is emitted from small leaks in 

literally thousands of components (valve, flanges, pumps, seals, etc.). At present, it is not 

possible to continuously monitor each individual component to identify leaking equipment. 

Recently, there has been an increased concern about the potential underestimation of emissions 

from certain sources at refineries. For example, there is some evidence that emissions from nonroutine events (such as equipment breakdowns, startup, shutdown and maintenance) are not fully 

accounted for in the emission inventory, and that emissions from these events in some cases far 

exceed the annual emissions reported in the inventory. As the result of upsets, emissions are 

often routed to a flare or vented directly to the air and normal pollution controls are bypassed. 

Of 18 refineries studied in Texas and Louisiana, 10 had unreported upset releases amounting to 

more than 25 percent of their emission inventory annual totals. The potential underestimation of 

emissions from non-routine events should be considered during the selection of refinery 

processes for detailed control measure analysis in the MARAMA region. 

1.2 EXISTING REQUIREMENTS 

Petroleum refineries are governed by multiple federal and state/local regulations under the Titles 

I and III of the Clean Air Act. Refineries are also subject to control technology assessments 

anytime they construct a new or modify an existing major source. Recently, refineries have been 

the subject of an enforcement initiative to ensure that the sources meet these regulatory and 

permitting requirements. Settlements from these enforcement actions will result in the 

installation of additional pollution control equipment. The following paragraphs generally 

describe the existing requirements for refineries in the Mid-Atlantic region. The specific 

requirements from each of these programs are discuss in detail in Sections 2-8 of this document. 

1.2.1 Federal Regulations 

Title I of the Clean Air Act imposes New Source Performance Standards (NSPS) on certain 

specified categories of new and modified large stationary sources. There are NSPS that affect 

the petroleum refining industry. Most of these standards were developed during the 1980s, and 

may or may not be applicable to a particular refinery depending on whether it has been modified 

since the adoption of the NSPS. The U.S. EPA is in the process of revising and updating NSPS 

standards. For example, in 2006 U.S. EPA finalized revisions to the NSPS for stationary 

combustion turbines and boilers. 
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EPA has also published several final rules under Title III of the CAA to substantially reduce 

emissions of toxic air pollutants from petroleum refineries. These Maximum Achievable Control 

Technology (MACT) standards apply to major sources of hazardous air pollutants (HAPs). The 

petroleum refinery MACT (Subpart CC) was promulgated in 1995, and most of its requirements 

affecting primarily organic HAP sources have already been implemented. Several other MACT 

standards became effective in the 1990s that affected specific refinery processes such as cooling 

towers and fuel storage/transfer. 

Additional MACT standards may result in post-2002 emission reductions. These MACT 

standards include the petroleum refinery MACT II (Subpart UUU – catalytic cracking, catalytic 

reforming, sulfur plant units), industrial boilers and heaters, organic liquids distribution (nongasoline), reciprocating engines, stationary combustion turbines, and remediation sites. While 

designed to reduce HAP emissions, the requirements of the post-2002 MACT standard may 

require control technologies that reduce both the level of HAP emitted from affected sources and 

also the VOC and PM, and to a lesser extent, SO2 emissions. 

On June 15, 2005, EPA issued final amendments to its July 1999 regional haze rule. These 

amendments require emissions controls known as best available retrofit technology or BART for 

industrial facilities emitting air pollutants that reduce visibility. The BART requirements of the 

regional haze rule apply to facilities built between 1962 and 1977 that have the potential to emit 

more than 250 tons a year of visibility-impairing pollutants. Those facilities fall into 26 

categories, including petroleum refineries. Some of these facilities previously have not been 

subject to pollution control requirements for these pollutants. Under the final BART guidelines, 

states are required to conduct source-by-source BART determinations to identify which facilities 

must install controls and the type of controls to be used. 

A list is provided at the end of this section identifying the NSPS and NESHAP that are 

potentially applicable to a petroleum refinery. 

1.2.2 State/local Regulations 

Title I regulates criteria pollutants by requiring local governments to adopt State Implementation 

Plans (SIPs) that set forth their strategy for achieving reductions in the particular criteria 

pollutant(s) for which they are out of attainment. The SIP requirements includes Reasonably 

Available Control Technology (RACT) requirements, but more stringent requirements may be 

imposed depending on both the locale's degree of nonattainment with ambient air standards and 

the local air quality impacts. The MARAMA States have developed regulations limiting 

emissions from refineries based in part on the Control Technique Guidelines (CTGs) or 

Alternative Control Techniques (ACT) documents developed by EPA, or case-by-case RACT 
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determinations. A list is provided at the end of this section identifying the CTGs and ACT 

documents that are potentially applicable to a petroleum refinery. 

Another element of the SIP was finalized by EPA in the NOx SIP in 1998. The final version of 

the rule called for NOx emission reductions in twenty-two states that contributed to 1-hour ozone 

nonattainment in other states. The rule required affected states to amend their SIPs and limit 

NOx emissions. EPA set an ozone season NOx budget for each affected state, essentially a cap 

on emissions from May 1 to September 30 in the state. The cap results in about a 30 percent 

reduction from statewide baseline emissions. The first control period was scheduled for the 2004 

ozone season. States adopted a NOx emissions trading program and assigned 5-month ozone 

season NOx allowances for large ICI boilers in the NOx SIP call region, including units at a few 

refineries in MARAMA region. 

1.2.3 Permit Requirements 

Title I of the Clean Air Act also subjects new and modified large stationary sources that increase 

their emissions to permitting requirements that impose control technologies of varying levels of 

stringency (known as New Source Review, or NSR). NSR requires a control technology 

assessment for new plants and for plant modifications that result in a significant increase in 

emissions, subjecting them to Best Available Control Technology (BACT) in attainment areas 

and to the Lowest Achievable Emission Rate (LAER) in nonattainment areas. The control 

strategies that constitute BACT and LAER evolve over time and are reviewed on a case-by-case 

basis in state/local permitting proceedings. Some states, such as Pennsylvania and Virginia, also 

have a minor source control technology evaluation requirement. New Jersey has a State-of-theArt (SOTA) requirement for many types of modifications at refineries. 

1.2.4 Requirements for Enforcement Settlements 

EPA's national Petroleum Refinery Initiative is an integrated enforcement and compliance 

strategy to address air emissions from the nation's petroleum refineries. Since March 2000, the 

agency has entered into 17 settlements with U.S. companies that refine nearly 77 percent of the 

nation's petroleum. Both EPA and State/local agencies have negotiated settlements that will 

require significant investment in pollution control technology and will result in emission 

reductions in the future. The major refinery sources that are affected by the judicial settlements 

are: FCCUs/ (FCUs), process heaters and boilers, sulfur recovery plants, flare gas recovery, 

equipment leaks, and wastewater treatment. 

Table 1-3 lists the recent enforcement settlements under EPA’s Petroleum Refinery Initiative that 

affect petroleum refineries in the MARAMA region. Ten of the 14 refineries in the MARAMA 

region have been included. 
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Table 1-3 – Recent Enforcement Settlements Under EPA’s Petroleum Refinery Initiative 

Settlement Company Lodging 

Date 

Mid-Atlantic Refineries 

Affected by Action 

Sunoco 6/16/2005 Marcus Hook, PA/Claymont, DE 

Philadelphia, PA 

Valero Refining 6/16/2005 Paulsboro, NJ 

Conoco Phillips 1/27/2005 Linden (Bayway), NJ 

Trainer, PA 

CITGO 10/6/2004 Paulsboro, NJ 

Coastal Eagle Point 10/1/2003 Westville, NJ (purchased by Sonoco in 2004) 

Ergon 10/1/2003 Newell, WV 

Motiva Enterprises 3/21/2001 Delaware City, DE (purchased by Valero in 2005) 

BP Amoco 1/19/2001 Yorktown, VA (purchased by Giant Industries in 

2002) 

The specific requirements from the enforcement settlements are discuss in detail in Sections 2-8 

of this document. 

1.3 SELECTION OF SOURCE CATEGORIES FOR FURTHER EVALUATION 

The MARAMA Refinery Technical Oversight Committee reviewed the emission inventory, the 

existing requirements for each source category, and the resources available for this project. 

Based on that review, the following refinery processes were selected for further evaluation of 

candidate control measures: 

• Catalytic and thermal cracking units 

• Boilers and process heaters 

• Flares 

• Fugitive equipment leaks 

• Wastewater treatment 

• Storage Tanks 

• Sulfur recovery units 

The assessment of control technology options for these seven categories is presented in the 

remainder of this document. 
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1.4 REFERENCES 

Energy Information Administration, June 2005, “Petroleum Supply Annual 2004: Table 38 

Capacity of Operable Petroleum Refineries by State as of January 1, 2005”. 

Environmental Integrity Project, October 2002, “Accidents Will Happen: Pollution from Plant 

Malfunctions, Startups, and Shutdowns in Port Arthur, Texas”. 

Environmental Integrity Project, August 2004, “Gaming the System: How Off-the-Books 

Industrial Upset Emissions Cheat the Public of Clean Air”. 

Mid-Atlantic/Northeast Visibility Union (MANE-VU), 2006, Version 3 of the 2002 Point Source 

Emission Inventory, 

http://www.marama.org/visibility/Inventory%20Summary/2002EmissionsInventory.htm 

MACTEC Federal Programs, Inc., 2006, Draft Technical Support Document: Development of 

Emission Projections for 2009/2012/2018 NonEGU Point, Area, and Nonroad Sources in 

the MANE-VU Region. 

U.S. Environmental Protection Agency, 2005, Draft Final Version of the 2002 National Emission 

Inventory. 

Visibility Improvement State and Tribal Association of the Southeast (VISTAS), 2005, Version 

Base 4f of the 2002, 2009, and 2018 Point Source Emission Inventory. 
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Attachment 1-1 – Potentially Applicable Requirements 

for the Petroleum Refining Industry 

Name Subpart Effective Date 

CONTROL TECHNOLOGY GUIDELINES (CTGs) 

Storage of Petroleum Liquids in Fixed Roof Tanks 1977 

Refinery Vacuum Producing Systems, Wastewater 

Separators, and Process Unit Turnarounds 

 1977 

Tank Truck Gasoline Loading Terminals 1977 

Leaks from Petroleum Refinery Equipment 1978 

Petroleum Liquid Storage in External Floating Roof Tanks 1978 

SOCMI Air Oxidation Processes 1984 

ALTERNATIVE CONTROL TECHNIQUES (ACT) DOCUMENTS 

Process Heaters 1993 

Stationary Gas Turbines 1993 

ICI Boilers 1994 

Utility Boilers 1994 

Internal Combustion Engines 1993 

NEW SOURCE PERFORMANCE STANDARDS (NSPS) PART 60 

General Provisions A 1970s 

Sulfuric Acid Production Plants Cd 1991 

Fossil Fuel Fired Steam Generators Constructed After 

8/17/71 

D 1977 

Electric Utility Steam Generating Units Constructed After 

9/18/79 

Da 1978 

ICI Steam Generating Units Db 1987 

Small ICI Steam Generating Units Dc 1990 

Sulfuric Acid Plants H 1977 

Petroleum Refineries J 1978 

Storage Vessels for Petroleum Liquids Constructed Between 

6/11/73 and 5/19/78 

K 1977 
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Name Subpart Effective Date 

NEW SOURCE PERFORMANCE STANDARDS (NSPS) PART 60 (continued)

Storage Vessels for Petroleum Liquids Constructed Between 

5/18/78 and 7/23/84 

Ka 1980 

Organic Liquid Storage Vessels (including Petroleum Liquid 

Storage Vessels) Constructed After 7/23/1984 

Kb 1987 

Stationary Gas Turbines GG 1978 

Asphalt Processing and Asphalt Roofing Manufacture UU 1982 

Equipment Leaks - SOCMI VV 1983 

Bulk Gasoline Terminals XX 1983 

Equipment Leaks of VOC in Petroleum Refineries GGG 1984 

VOC Emissions from SOCMI Air Oxidation Unit Processes III 1990 

VOC Emissions from SOCMI Distillation Operations NNN 1990 

VOC Emissions from Petroleum Refinery Wastewater 

Systems 

QQQ 1988 

VOC Emissions from SOCMI Reactor Processes RRR 1993 

Commercial and Industrial Solid Waste Incineration Units CCCC 2001 

NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS 

(NESHAP) PART 61 

General Provisions A 1973 

Equipment Leaks of Benzene J Mid-1980s 

Asbestos M 1984 

Equipment Leaks V Mid-1980s 

Benzene Storage Vessels Y Mid-1980s 

Benzene Transfer Operations BB Mid-1980s 

Benzene Waste Operations FF 1993 

NESHAP FOR SOURCE CATEGORIES PART 63 

General Provisions A 1994 

Control Technology Determinations B 1994 
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Name Subpart Effective Date 

SOCMI Industry F 1994 

SOCMI Industry for Process Vents, Storage Vessels, 

Transfer Operations, and Wastewater 

G 1994 

Equipment Leaks H 1994 

Certain Processes Subject to the Negotiated Regulation for 

Equipment Leaks 

I 1994 

Industrial Cooling Towers Q 1994 

Gasoline Distribution Facilities (Bulk Gasoline Terminals 

and Pipeline Breakout Stations) 

R 1994 

Halogenated Solvent Cleaning T 1994 

Marine Tank Vessel Loading Operations Y 1995 

Petroleum Refineries (MACT I) CC 1995 

Hazardous Waste Combustors EEE 1999 

Petroleum Refineries (MACT II – catalytic cracking, 

catalytic reforming, sulfur plant units) 

UUU 2002 

Asphalt Processing and Asphalt Roofing Manufacturing LLLLL 2003 

ICI Boilers and Process Heaters DDDDD 2004 

Site Remediation GGGGG 2003 

Organic Liquids Distribution (non gasoline) EEEE 2004 

Misc. Organic Chemical Manufacturing FFFF 2003 

Reciprocating Internal Combustion Engines ZZZZ 2004 

Stationary Combustion Turbines YYYY 2004 

 
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2.0 CATALYTIC AND THERMAL CRACKING UNITS 

At many petroleum refineries, fluid catalytic cracking units (FCCU) and fluidized coking units 

(FCU) are among the largest air emission sources at the refinery. Numerous technologies have 

been developed over the years for pollution control at cracking units. In 1980’s, the concern was 

primarily PM and SO2. Today, there is concern with NOx, CO, and VOCs as well as further 

control of PM and SO2. This Section presents an assessment of available control technology 

options for FCCUs and FCUs for states to consider as they undertake efforts to develop rules and 

State Implementation Plans (SIPs) for ozone, PM2.5, and regional haze. 

2.1 PROCESS DESCRIPTION 

Cracking units convert middle distillate, gas oil and residuum into primarily gasoline, jet and 

diesel fuels by using a series of processing steps that literally “crack” large, heavy molecules into 

smaller, lighter ones. Heat and catalyst are used to convert the heavier oils to lighter products. 

With fluid catalytic cracking (FCC), a fluidized catalyst is used to optimize the cracking process. 

Thermal crackers, often called coking units, such as delayed and fluid coking units, rely on 

thermal energy to promote cracking without the use of a catalyst. 

Typical FCC systems consist of a reactor, catalyst regenerator, and vent gas process equipment 

for energy recovery and/or emission control (see Figure 1-1). In the FCC process, preheated oil 

and oil vapors are introduced to the hot catalyst (usually zeolite supported by amorphous 

synthetic silica-alumina with metals) in the riser pipe. Due to the high reactivity of modern 

catalysts, most of the cracking takes place inside the riser pipe at temperatures between 880 and 

980oF. The fluidized catalyst and the reacted hydrocarbon vapor are then transferred to the 

reactor where they are separated mechanically in a cyclone system, sending the cracked oil 

vapors to a fractionation tower where desired fractions are separated, steam stripped, cooled, and 

collected. Slurry oil removed from the bottom of the fractionation tower is used either as wash 

oil and a quench for the hot reactor overhead vapors to prevent after-cracking, or filtered to 

remove catalyst fines, cooled, and sent to storage. The fluidized catalyst is transferred from the 

reactor to the catalyst regenerator. The catalytic cracking process deposits coke on the catalyst 

surface, reducing its effectiveness, therefore the coke is burned off at high temperatures in the 

regenerator, and then recycled back to the reactor. 

Catalyst regenerators operate in either full (complete) or partial combustion mode. In the full 

combustion mode, the regenerator is operated at temperatures around 1300o

F to oxidize all coke 

carbon to CO2 and not CO. In partial combustion mode, the regenerator is operated at lower 

temperatures, and CO oxidation is controlled by limiting the amount of combustion air available. 

The partial combustion mode avoids catalyst sintering problems with coke containing high metal 

content. 
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Figure 2-1. Diagram of a Fluidized Catalytic Cracking Unit 

SOURCE: http://www.refractorydepot.com/FCCU.gif

FCCU systems are the most widely used cracking process in the MARAMA region. One facility 

(Delaware City) operates both a FCCU and a FCU. Another facility (Valero) uses a delayed coking 

thermal cracking unit in addition to a FCCU to further breakdown the heaviest fractions from distillation 

bottoms. Air pollution control issues for fluid coking units are similar to those for fluidized catalytic 

cracking units, while delayed coking units do not have process emissions. The only emissions from 

delayed coking units are from the combustion of fuel in the associated process heater that provides the 

energy required for the thermal cracking reaction. 
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2.2 EMISSION INVENTORY 

Table 2-1 identifies the FCCUs and coking units in the MARAMA region, along with the 

capacity of each unit. Criteria pollutant emissions for each unit are shown for three years. The 

2002 annual emissions serve as the baseline for future SIP development. The 2002 emissions 

were obtained from the 2002 inventories developed by MANEVU and VISTAS. The 2003 

emissions were obtained directly from each state and represent the most currently quality assured 

data that is available. 

The 2009 emissions were obtained from the MANEVU and VISTAS projection inventories that 

were developed to support modeling for SIP development. The 2009 inventories include the 

effects of anticipated growth as well as any planned controls that will result in emission 

reductions between 2002 and 2009 due to new regulations or enforcement settlements. The 

growth factors used for projecting emissions from 2002 to 2009 came from the U.S. 

Environmental Protection Agency’s Economic Growth Analysis System (EGAS 5.0) and the 

U.S. Department of Energy’s Annual Energy Outlook (2005) projections. The controls factors 

for 2009 were derived either from data supplied that the State/local agencies or from MACTEC’s 

analysis of the requirements contained in the global enforcement settlements. 

The 2009 projected emissions for the Marcus Hook FCCU were calculated assuming that 

controls required by the Consent Decree would be in place by 2009. While the controls in fact 

are not required until 2013 in the Consent Decree, there are stipulated penalties if the controls are 

not installed by 2010. It is unlikely that the controls will be installed by 2009, and the 2009 

projected emissions will likely be higher than shown in Table 2-1. 

The 1232 FCCU at the Philadelphia refinery (Girard Point) was issued a permit on February 28, 

2006 to increase the daily feed rate to 100,000 barrels per any single day and 90,000 barrels per 

day on a rolling 365-day average while the 868 FCCU Philadelphia (Point Breeze) has a permit 

application under review to increase its daily feed rate to 58,000 barrels per any single day and 

56,000 barrels per day on a rolling 365-day average. The emissions for 2009 for the 1232 FCCU 

and the 868 FCCU reflect the permit limits that are expected to be in place in 2009. 

Table 2-1 shows that SO2 emissions for several FCCUs/FCUs are projected to be reduced by 

2009 as a result of the requirements of the enforcement settlements (to be discussed in more 

detail later), resulting in a region-wide reduction of about 90 percent for all units in the region. 

The region-wide NOx emission reductions are projected to be about 40 percent by 2009 as a 

result of the enforcement settlements and other on-the-books requirements. Smaller reductions 

in PM and VOC emissions are also projected as a result of compliance with the MACT 

standards. 
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Table 2-1 Emission Inventory for FCCUs and FCUs 

 Refinery/ Capacity Annual Emissions (tons per year) 

State Unit BBL/day Year CO NH3 NOx PM10 SO2 VOC 

DE Valero 82,000 2002 1,524 4 739 765 11,421 122 

EUID = 011/012 2003 1,883 12 1,119 541 14,407 112 

FCCU w/ CO Boiler 2009 1,640 5 411 390 361 131 

DE Valero 57,100 2002 1,209 3 624 496 19,461 97 

EUID = 001/002 2003 996 7 557 403 17,752 72 

Fluid Coker Unit w/CO Boiler 2009 1,291 4 690 334 174 100 

NJ Sunoco Eagle Point 67,650 2002 83 0 103 69 91 41 

EUID = U9 2003 93 0 58 62 68 37 

FCCU 2009 95 0 47 35 5 6 

NJ Valero Refining 55,000 2002 53 0 106 71 3,597 29 

EUID = U1 2003 43 0 90 43 3,844 15 

FCCU 2009 61 0 121 82 172 4 

NJ Amerada Hess 65,000 2002 130 0 359 44 71 51 

EUID = U1 2003 48 0 349 54 70 59 

FCCU 2009 148 0 409 50 81 7 

NJ ConocoPhillips Bayway 140,000 2002 99 0 1,036 128 65 12 

EUID = U4 2003 105 0 1,341 205 37 5 

FCCU w/ 2 CO Boilers 2009 113 0 475 128 75 2 

PA Sunoco Marcus Hook 115,000 2002 514 0 1,489 209 4,374 10 

EUID = 101 2003 453 0 1,651 217 5,246 4 

PLT 10-4 FCC w/ CO Boiler 2009 484 0 184 105 824 1 

PA ConocoPhillips Trainer 52,000 2002 .63 5 520 113 2,092 3 

EUID = 101 2003 67 5 543 116 1,874 3 

FCC w/ CO Boiler 2009 69 5 245 93 166 0 

PA Sunoco Philadelphia 73,500 2002 514 0 356 42 2,378 4 

EUID = 019 2003 514 0 464 57 2,187 0 

GP 1232 w/ CO Boiler 2009 634 19 208 170 363 8 

PA Sunoco Philadelphia 47,500 2002 52 0 182 70 475 0 

EUID = 539 2003 52 0 199 61 586 0 

PB 868 FCCU 2009 100 0 482 95 600 23 

PA United Refining Warren 24,000 2002 43 0 29 43 1,091 0 

EUID = 101A 2003 41 0 39 41 1,074 0 

FCCU 2009 49 0 33 49 1,245 0 

VA Giant Yorktown 36,000 2002 140e

 0 210 428 477 3 

EUID = 6 2003 44 e 0 212 428 629 3 

FCCU 2009 140 e 0 233 53 106 3 

MARAMA Totals 864,650 2002 4,421 12 5,770 2,478 47,566 372 

 2003 4,339 24 6,622 2,228 47,774 310 

 2009 4,824 33 3,538 1,548 4,172 285 

Notes: Dave Brown, PADEP indicates 2009 projections for Marcus Hook may be higher than shown since consent decree 

controls are not required until 2013; Keith Lemchak, AMS, provided revised 2009 emissions based on current permit limits and 

consent decree requirements.
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2.3 EXISTING REQUIREMENTS 

This section discusses the regulatory requirements which apply to cracking units. Four types of 

requirements are discussed: (1) Federal requirements such as the New Source Performance 

Standards (NSPS) and Maximum Achievable Control Technology (MACT) standards; (2) State 

regulations for both the MARAMA states as well as other State agencies; (3) source-specific 

permit requirements; and (4) new requirements from recent enforcement settlements. 

2.3.1 Federal Regulations 

Performance standards under NSPS apply to emissions exiting the FCCU catalyst regenerator. 

Particulate matter discharged from the catalyst regenerator should not exceed 2.0 lb/ton of coke 

burn-off, as well as 30% opacity, except for one 6-minute average during any 1-hour period. In 

addition, for discharged flue gas that passes through an incinerator or waste heat boiler, which 

burns liquid or solid fossil fuel, incremental PM emissions are limited to 0.10 lb/MMBtu. As for 

SO2 emissions, three options exist for compliance. First, if an add-on SO2 control device is 

present, SO2 emissions must be controlled by 90% or limited to 50 ppmv, whichever is less 

stringent. Second, if no control device is used, SO2 emissions must be limited to 20 lb/ton coke 

burn-off. The third option limits the sulfur content of fresh feed to the FCCU to 0.30% by 

weight. Subpart J also limits CO emissions from the catalyst regenerator to 500 ppmvd on a 1-

hour average. 

National Emission Standards for Hazardous Air Pollutants (NESHAP) were developed as part of 

section 112(d) of the Clean Air Act, which requires that major sources of HAP, those that have 

the potential to emit at least 10 tpy of any single HAP or 25 tpy of any combination of HAPs, 

meet standards reflecting the application of the maximum achievable control technology 

(MACT). The first NESHAP for petroleum refineries (40 CFR 63, Subpart CC) commonly 

referred to as the MACT I standard, covered the following sources: miscellaneous process vents, 

storage vessels, wastewater collection/treatment, and equipment leaks. The second NESHAP 

applying to petroleum refineries is the MACT II standard (40 CFR 63, Subpart UUU), which 

applies to catalytic cracking units, catalytic reforming units, sulfur recovery units, and bypass 

vents. 

Under Title 40, CFR, Part 63, Subpart UUU, for new and existing FCCUs subject to NSPS 

limits, PM emissions must not exceed 1.0 lb/1,000 lb of coke burn-off in the catalyst regenerator, 

and if the discharge gases pass through an incinerator or waste heat boiler, which burns liquid or 

solid fossil fuel, then the incremental rate of PM is limited to 0.10 lb/MMBtu, in addition to an 

opacity limit of 30%, except for a 6-minute average in any 1-hour period. For those FCCUs not 

subject to NSPS limitations, then four options exist for compliance with the MACT standard: (1) 

comply with the above stated PM emission limit, (2) limit PM emissions to 1.0 lb/1,000 lb coke 
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burn-off, (3) limit Nickel emissions to 0.029 lb/hr, or (4) limit Nickel emissions to 0.001 lb/1,000 

lb coke burn-off in the catalyst regenerator. 

2.3.2 State Regulations 

Table 2-2 lists the regulations for each of the MARAMA states for the control of PM, SO2, and 

CO. Most states limit PM emissions using process weight rate calculations, while none of the 

MARAMA states had regulations limiting NOx emissions. In Table 2-3, the regulations are 

listed for Louisiana, Texas, and California (from the Bay Area Air Quality Management District 

– BAAQMD and the South Coast Air Quality Management District – SCAQMD). Regulations 

from these states are presented because these states have a large number of refineries and 

generally have stricter emission limitations than the MARAMA states and the federal 

government. 

2.3.3 Permit Requirements 

See Table 2-4 for a list of all current permit requirements for FCCUs at petroleum refineries in 

the MARAMA region. Many units have requirements that are more stringent than the Federal or 

State regulations discussed in the previous section as a result of New Source Review permitting 

that required the installation of best available control technology (BACT). 

2.3.4 Requirements from Recent Enforcement Settlements 

The EPA and State/local agencies recently undertook an initiative to investigate physical 

modifications to FCCUs. Capacity increases and modifications should have triggered NSR 

permitting and pollution control requirements. There have being several instances identified 

where refineries have failed to obtain pre-construction and operating permits for physical 

construction that increased their capacity and emissions. Consent Decrees require petroleum 

refineries to install continuous emissions monitoring equipment so that facilities, EPA, and 

States can access real time emissions data. More importantly, Consent Decrees also require 

facilities to install and implement a suite of controls to reduce NOX, SO2, and PM emissions. 

Table 2-5 provides a list of recent enforcement settlements for FCCUs and coking units at 

petroleum refineries in the MARAMA region. 

For particulate emissions, the most stringent performance level specified in the Consent Decree 

requirements is 0.5 pounds PM per 1000 pounds coke burned on a 3-hour average basis. For 

SO2, the performance level is 25 ppmvd @ 0% oxygen based on 365-day rolling average 50 

ppmvd @ 0% oxygen based on 7-day rolling average. For NOx, the most stringent performance 

level is 20 ppmvd, measured as a 365-day rolling average, and 40 ppmvd, measured as a 7-day 

rolling average, @ 0% oxygen. For CO, the performance level is 200 ppmvd @ 0% oxygen 

based on 1-hr block average and 100 ppmvd @ 0% oxygen based on 365-day rolling average 
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Table 2-2: Summary of MARAMA State Regulations for FCCUs/FCUs 

Agency PM SO2 CO 

Delaware Reg. 5, Section 5: Process Weight 

Rate based on coke burn-off rate 

(7,000 lb coke burn-off/hr is 

equivalent to 50 lb/hr PM, while 

70,000 lb coke burn-off/hr is 

equivalent to 500 lb/hr PM for 

FCCUs and per Table 4 of Reg. 5 

for coking units) 

Reg. 8, Section 1: SO2 emissions 

should meet ambient air quality 

standards (80 μg/m3

 on annual 

basis, 365 μg/m3

 on 24-hr basis, 

1300 μg/m3

 on 3-hr basis) 

Reg. 11, Section 2: In New Castle 

County, CO emissions must be 

burned at 1300o

F for 0.3 seconds 

or greater in a direct flame 

afterburner or boiler 

New Jersey 7:27-6.2: 

The maximum allowable PM 

emission rate varies depending on 

the size of the source 

7:27-9.2: 

Maximum allowable % Sulfur in 

liquid fuels according to Table 1, 

or max sulfur emissions according 

to Table 2 

Pennsylvania 123.13: PM emissions shall not 

exceed the greater of 0.02 gr/dscf 

or the emissions calculated by 

A=0.76 (FxW)0.42, where A is the 

emissions limit (lb/hr), F is the 

Process Factor (40 lb/ton liquid 

feed for catalytic crackers), and W 

is the production rate (ton liquid 

feed/hr) 

123.21: 

≤ 500 ppmvd 

Philadelphia Reg. 2, Section 7: 

PM emissions should not exceed 

those listed in Table I of the 

regulation, where process weight 

rate (lb/hr) is compared with 

maximum PM emissions (lb/hr). 

The maximum allowable PM 

emission rate is 40 lbs/hr. 

Reg. 3, Section 2: 

(1) Emissions of SO2 should not 

exceed ground level 

concentrations of 3ppmv, 0.5 

ppmv for 15-min avg, and 0.1 

ppmv for 8-hr avg. 

(2) SO2 in exhaust streams ≤

0.05% by volume 

Reg. 8: Gases containing CO 

emissions should be incinerated at 

≥ 1400o

F for a period of not less 

than 0.5 seconds, or should be 

controlled by means of equal or 

greater efficiency: 

Virginia 9 VAC 5-40-260: 

(AQCR 1-6) Process weight rate 

applies: 

(1) E = 4.1(P0.67) for P < 30 tph; 

(2) E = 55(P0.11)-40 for P > 30 tph 

9 VAC 5-40-270: 

(AQCR 7) Process weight rate 

applies according to Table 4-4B 

9 VAC 5-40-1360: 

PM emissions from petroleum 

catalytic cracking units ≤ 0.05% 

of the rate of catalyst recirculation 

within the unit.

9 VAC 5-40-280: 

≤ 2,000 ppmv 

West Virginia 45-7-4: 

Process Weight Rate according to 

Table 45-7A 

45-10-4: 

≤ 2,000 ppmv 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 2 – Catalytic and Thermal Cracking Units Page 2-8 

MACTEC Federal Programs, Inc. 

Table 2-3: Summary of Other State Regulations for FCCUs and FCUs 

Agency PM SO2 NOx CO 

Louisiana Chapter 13, Subchapter A: 

PM emissions should follow 

the process weight rule; 

opacity ≤ 30% (except one 

6-min avg. in a 1-hr period) 

Chapter 15: 

≤ 2,000 ppm at 

standard conditions 

(3-hr avg) 

 Chapter 17, Subchapter C: 

CO emissions must be 

burned in a direct flame 

afterburner or boiler (or 

other control method 

approved by the state) 

Texas 111.151: 

≤ 0.045(q0.62), where q is the 

stack effluent flow rate 

(acfm), however, if the 

effective stack height (HE) < 

standard effective stack 

height (HSE), then the 

allowable emission rate is 

multiplied by (HE/HSE)

2

; 

Formulas for HE and HSE

are found in this rule. 

 117.206: 

In the Houston-Galveston 

ozone non-attainment area, 

catalytic cracking units 

(including CO boilers) must 

comply with one of the 

following: 

(1) ≤ 40 ppmvd @ 0% O2; 

(2) 90% NOx reduction from 

calculated June-Aug. 1997 

daily NOx emissions 

BAAQMD 6-310: 

(1) ≤ 0.15 gr/dscf and (2) 

follow process weight rate 

(E = 4.1(P0.67) ≤ 40 lb/hr) 

9-1-310: 

≤ 1,000 ppmv 

9-10-304: 

(1) ≤ 150 ppmvd @ 3% O2

(24-hr avg); OR 

(2) Operate an emissions 

control system that has a 

minimum control efficiency of 

50% by wt. 

9-10-305: 

≤ 400 ppmvd @ 3% O2

(24-hr avg) 

SCAQMD Rule 1105.1 Comply with 

one of the following: 

(1) 3.6 lb/hr; 

(2) 0.005 gr/dscf @ 3% O2; 

(3) 2.8 lb/thousand barrel 

fresh feed 

Rule 1105: 

132 lb/thousand 

barrel feed charged 

to FCCU 

 

 
Draft Assessment of Control Technology Options for Petroleum Refineries 

Section 2 – Catalytic and Thermal Cracking Units MACTEC Federal Programs, Inc. 

Table 2-4: Summary of Permit Requirements FCCUs and FCUs 

Refinery & Unit Required PM Control Technology or Emission Limitation Required SO2 Control Technology or Emission Limitation Required NOx Control Technology or Emission Limitation R

Valero Delaware City EUID = 011/012 FCCU w/ CO Boiler 

TSP - 1 lb/1000 lb of coke burned Company shall propose lb/hr and tpy PM10 and H2SO4 emission limits 

25 ppmvd or lower on a 365-day rolling avg, 50 ppmvd on a 7-day rolling avg basis, each corrected to 0% O2, and 361 tpy 

Reserved CO 

3,7CO 0.3 

Valero Delaware City EUID = 001/002 Fluid Coker Unit w/CO Boiler 

TSP - 47.1 lbs/hr and 206.3 tpy H2SO4 - 58 lbs/hr and 252.3 tpy PM10 - 133.1 lb/hr and 133.1 tpy 

25 ppmvd or lower on a 365-day rolling avg, 50 ppmvd on a 7-day rolling avg basis, each corrected to 0% O2, and 174 tpy 

Not exceed level to be established in accordance with Consent Decree (i.e., SNCR optimization study) Emission limit 689.8 tpy 

CocostuCO 0.3 

Sunoco Eagle Point EUID = U9 FCCU 

TSP - 11.4 lbs/hr H2SO4 - 15 lbs/hr PM10 - 30 lbs/hr 

EDV-6000 scrubber - Permittee/DEP will decide on appropriate parameter for maximum feed sulfur content or barrel per day feed rate SO2 emission limit 75 lbs/hr 

Emission limit 50 lbs/hr Em

Valero Refining EUID = U1 FCCU 

TSP – 120.4 tpy H2SO4 – 51.55 tpy PM10 – 120.4 tpy 

BELCO wet scrubber SO2 emission limit 172 tpy 

Emission limit 222.9 tpy Em

Amerada Hess EUID = U1 FCCU 

TSP – 0.02 gr/scf TSP – 22 lbs/hr H2SO4 – 12.86 lbs/hr PM10 – 36 lbs/hr 

Wet gas scrubber Sulfur content of fresh feed < 1% by weight Emission limit 80 lbs/hr or 141 ppmvd at 0% oxygen, whichever is lower 

Emission limit 160 lbs/hr or 328 ppmvd at 0% oxygen, whichever is lower 

Em30is 

ConocoPhillips Bayway EUID = U4 FCCU w/ 2 CO Boilers 

PM10 – 59.9 lbs/hr TSP – 50.2 lbs/hr Particulate – 0.02 grains per scf H2SO4 – 150 lbs/hr 

Sulfur content of fresh feed < 1% by weight Emission limit 25 ppm @ 7% oxygen Emission limit 77.6 lbs/hr Emission limit 261 tpy 

Emission limit 334.7 lbs/hr Emission limit 1,127.8 tpy 

Em50
Draft Assessment of Control Technology Options for Petroleum Refineries 

Section 2 – Catalytic and Thermal Cracking Units MACTEC Federal Programs, Inc. 

Table 2-4: Summary of Permit Requirements FCCUs and FCUs (continued) 

Refinery & Unit Required PM Control Technology or Emission Limitation Required SO2 Control Technology or Emission Limitation Required NOx Control Technology or Emission Limitation R

Sunoco Marcus Hook EUID = 101 PLT 10-4 FCC w/ CO Boiler 

0.02 grains per SCF 500 ppmv 0.0149 lbs/barrel of fresh feed Tw

CO reg50

ConocoPhillips Trainer EUID = 101 FCC w/ CO Boiler 

0.02 grains per SCF 500 ppmv 500 ppm No

Sunoco Philadelphia EUID = 019 GP 1232 w/ CO Boiler 

Wet gas scrubber; Filterable PM/PM10 (0.30 lb/1000 lb coke burn-off, 365-day rolling average, 0.50 lb coke burn-off, 3-run average); Filterable PM10 (0.014 gr/dscf @ 3% O2, 3-run average), Total PM/PM10 Filterable and Condensable (40.0 lbs/hr, 960 lbs/day, 175 tons/yr) 

Wet Gas Scrubber; 25 ppmvd @ 0% O2, 365-day rolling avg; 50 ppmdv @ 0% O2 based on 7-day rolling avg; (when CO boiler burns fuel with H2S>0.1 gr/dscf), 20 ppmdv @ 0% O2, 3-hr rolling avg. 

SCR system; 20 ppmvd @ 0% O2, 365-day rolling avg; 40 ppmdv @ 0% O2, 7-day rolling avg 

10av

Sunoco Philadelphia EUID = 539 PB 868 FCCU 

1 lb/1000 lb coke Comply with NSPS Subpart A and J 

Comply with NSPS Subpart A and J Comply with NSPS Subpart A and J 10

av

United Refining EUID 101A FCCU 

0.04 grain per SCF 285 lbs/hr 

1,248.3 tpy 

71 lbs/1000 barrels FCC feed No

Giant Yorktown EUID = 6 FCCU 

0.05% of the rate of catalyst recirculation within the unit, rolling 12-month basis COM measured opacity of 30% EPA Method 9 opacity of 20% 

2,000 ppm by volume, rolling 12-month basis 

Nothing specified No
Draft Assessment of Control Technology Options for Petroleum Refineries 

Section 2 – Catalytic and Thermal Cracking Units MACTEC Federal Programs, Inc. 

Table 2-4: Summary of Recent Enforcement Settlements for FCCUs and FCUs 

Refinery & Unit Required PM Control Technology or Emission Limitation Required SO2 Control Technology or Emission Limitation Required NOx Control Technology or Emission Limitation R

Valero Delaware City EUID = 011/012 FCCU w/ CO Boiler 

Comply with NSPS Subparts A and J Wet gas scrubber; 25 ppmvd or lower 

on a 365-day rolling avg, 50 ppmvd on a 7-day rolling avg basis, each corrected to 0% O2, and 361 tons/year 

Original consent decree specified catalyst additive trials followed by optimization. A subsequent amendment specified optimization of key CO boiler operating parameters. 

50

Valero Delaware City EUID = 001/002 Fluid Coker Unit w/CO Boiler 

Nothing Specified Wet gas scrubber; 25 ppmvd or lower 

on a 365-day rolling avg, 50 ppmvd on a 7-day rolling avg basis, each corrected to 0% O2, and 174 tons/year 

SNCR & NOx reducing catalyst additives; emission limits to be determined through optimization study 

No

Sunoco Eagle Point EUID = U9 FCCU 

0.50 lb/1,000 lb coke burned on a 3-hr rolling avg, 19 lbs/hr TSP, and 48 lbs/hr PM10 on a 1-hr block avg; wet 

gas scrubber upgrade, limit of 30 lbs/hr on 1-hr block avg. 

25 ppmvd or lower on a 365-day rolling avg, 50 ppmvd on a 7-day rolling avg basis, each corrected to 0% O2, and 67.4 lbs/hr on a 1-hr 

block avg 

Continued use of low NOx promoter Eliminox ; 75 ppmvd on a 3-hr rolling avg @ 0% O2 and 50 lbs/hr on a 1-hr 

block avg; Conduct NOx control technology study of SCR, LoTox, and others; install NOx controls by April 30, 2008 

10

rollimavIns

Valero Refining EUID = U1 FCCU 

Nothing Specified Wet gas scrubber; 25 ppmvd @ 0% 

O2 based on 365-day rolling avg or 50 

ppmvd @ 0% O2 based on 7-day 

rolling avg 

Optimization study of existing control system; 20 ppmvd, measured as a 365-day rolling avg, and 40 ppmvd, measured as a 7-day rolling avg, @ 0% O2

50

1-h

Amerada Hess EUID = U1 FCCU 

Not included in national petroleum refinery initiative 

ConocoPhillips Bayway EUID = U4 FCCU w/ 2 CO Boilers 

Wet gas scrubber (Continued Operation), 0.50 lb/1,000 lb coke burned on a 3-hr rolling avg 

Wet gas scrubber (Continued Operation); 25 ppmvd or lower on a 365-day rolling avg basis and 50 ppmvd or lower on a 7-day rolling avg basis @ 0% O2

Enhanced SNCR to reduce NOx as much as feasible 

50O2
Draft Assessment of Control Technology Options for Petroleum Refineries 

Section 2 – Catalytic and Thermal Cracking Units MACTEC Federal Programs, Inc. 

Table 2-5: Summary of Recent Enforcement Settlements (continued) 

Refinery & Unit Required PM Control Technology or Emission Limitation Required SO2 Control Technology or Emission Limitation Required NOx Control Technology or Emission Limitation R

Sunoco Marcus Hook EUID = 101 PLT 10-4 FCC w/ CO Boiler 

If a wet gas scrubber is installed, then must comply with either (1) continued operation of the ESP, (2) install new ESP, or (3) accept emission limit of 0.5 lb/1,000 lb coke burned; Otherwise, PM limit is 1.0 lb/1,000 lb coke burned 

Wet gas scrubber; 25 ppmvd @ 0% O2 based on 365-day rolling avg or 50 

ppmvd @ 0% O2 based on 7-day 

rolling avg 

SCR system; 20 ppmvd @ 0% O2

based on 365-day rolling avg and 40 ppmvd @ 0% O2 based on 7-day 

rolling avg 

50O2

Ins

ConocoPhillips Trainer EUID = 101 FCC w/ CO Boiler 

Wet gas scrubber, 0.5 lb/1,000 lb coke burned on a 3-hr rolling avg. 

Wet gas scrubber; 25 ppmvd @ 0% O2 based on 365-day rolling avg or 50 

ppmvd @ 0% O2 based on 7-day 

rolling avg 

Enhanced SNCR; emission limits to be determined through optimization study 

50O2

Op1-hIns

Sunoco Philadelphia EUID = 019 GP 1232 w/ CO Boiler 

If a wet gas scrubber is installed, then must comply with either (1) continued operation of the ESP, (2) install new ESP, or (3) accept emission limit of 0.5 lb/1,000 lb coke burned; Otherwise, PM limit is 1.0 lb/1,000 lb coke burned 

Wet gas scrubber; 25 ppmvd @ 0% O2 based on 365-day rolling avg or 50 

ppmvd @ 0% O2 based on 7-day 

rolling avg 

SCR system; 20 ppmvd @ 0% O2

based on 365-day rolling avg and 40 ppmvd @ 0% O2 based on 7-day 

rolling avg 

50O2

Ins

Sunoco Philadelphia EUID = 539 PB 868 FCCU 

Nothing Specified Nothing specified Nothing specified 10

@ 

Ins

United Refining EUID 101A FCCU 

Not included in national petroleum refinery initiative 

Giant Yorktown EUID = 6 FCCU 

ESP, 1 lb/1,000 lb coke burned SO2 Adsorbing Catalyst; 25 ppmvd 

(0% oxygen) 365-day rolling average; 80% reduction in uncontrolled SO2 

Nothing specified No
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 2 – Catalytic and Thermal Cracking Units Page 2-13 

MACTEC Federal Programs, Inc. 

2.4 AVAILABLE CONTROL TECHNOLOGIES 

Emissions from catalytic crackers are highly variable due to the wide variation of feed stocks, 

which contain varying amounts of nitrogen, sulfur, and metals, as well as operating conditions of 

the regenerator and waste heat boiler. A number of control technologies exist for controlling 

emissions from these units, and options include both process changes and add-on control 

equipment to target specific pollutants. The total emission contribution from a FCCU can 

comprise about 20 – 30% of SO2, 15 – 30% of NOx, and 30 – 40% of PM emissions on a total 

refinery wide basis. Both process changes and add-on control equipment are discussed below for 

SO2, NOx, and PM. 

2.4.1 SO2 Controls 

The quantity of SO2 emissions discharged from the FCCU depends upon the sulfur content of 

feed to the FCCU, as well as the applied control technology. In the FCCU reactor, about 70 – 

95% of incoming sulfur in the feed is transferred to the cat cracker products. The remaining 5 – 

30% is deposited along with coke on the catalyst surface, and is burned off during catalyst 

regeneration as SO2. Control options for reducing SO2 emissions include pre-treating the FCCU 

feed, applying specific additives to the catalyst regenerator, and the use of wet scrubbers. 

2.4.1.1 Wet Scrubbing 

Wet scrubbers have been successfully applied to many petroleum refinery FCCUs to control 

emissions of SO2 and PM. Recent enforcement settlements will require several refineries in the 

MARAMA region to install wet gas scrubbers over the next several years. Several designs of 

wet scrubbers are available, such as packed towers, plate (or tray) towers, spray chambers, and 

venturi scrubbers, and emissions control levels of 95 – 99.9% have been achieved for SO2

removal, and 85 – 95% for PM removal. With the inclusion of an additional treatment tower 

with the wet scrubber system, NOx emissions can also be controlled up to 70%, but may be costprohibitive in some cases. Examples of wet scrubbing systems are described below. 

BELCO Technologies EDV® Wet Scrubbing (Eagleson, 1999) 

The EDV® (electro-dynamic venturi) Wet Scrubbing system combines the techniques used in 

venturi scrubbers with electrostatic dust separation. The system houses a spray tower along with 

a set of filtering modules and set of droplet separators, as shown in Figure 1-2. The flue gas 

from the regenerator enters the spray tower and is immediately quenched to saturation by 

multiple levels of spray nozzles which remove coarse PM on impact with the water droplets, as 

well as removal of SO2 through absorption with the use of a scrubbing reagent, such as caustic 

soda, lime, or a new regenerative LASORBTM reagent (produced by BELCO). After leaving the 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 2 – Catalytic and Thermal Cracking Units Page 2-14 

MACTEC Federal Programs, Inc. 

spray tower, the flue gas is directed to the filtering module for removal of fine particulate 

through forced condensation and filtration with water sprays. Lastly, the flue gas passes through 

a set of cyclonic droplet separators, which removes any free water droplets from the gas before 

discharge out the stack. 

Figure 2-2. EDV-Wet Scrubbing System 

SOURCE: Eagleson, S.T. and E.H. Weaver, 1999, “Controlling FCCU Emissions – EDV® Wet Scrubbing,” 11th Refining 

Seminar, Dallas, TX. 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 2 – Catalytic and Thermal Cracking Units Page 2-15 

MACTEC Federal Programs, Inc. 

ExxonMobil Wet Gas Scrubbers (Sapre, 2003) 

The ExxonMobil Research and Engineering Company (EMRE) has developed two types of wet 

gas scrubbers, namely, the high-energy venturi (HEV) scrubber and the jet ejector venturi (JEV) 

scrubber. These two types of scrubbers are similar to traditional venturi scrubbers, in that water 

and a scrubbing liquid are introduced in the scrubber to collect PM and absorb SO2 from the flue 

gas stream before discharge into the atmosphere. The HEV scrubber is used when the flue gas 

stream has adequate pressure to provide the motive force for moving the gas and liquid through 

the venturi. The scrubbing liquid enters at the converging section of the venturi, and the liquid is 

atomized by the high velocity gas. In contrast, the JEV scrubber is used for low pressure flue gas 

streams, and the scrubbing liquid is used to move the flue gas through the scrubber. The liquid is 

atomized due to shear forces at the top of the venturi, and impacts the PM and absorbs the SO2

out of the gas phase. Figure 1-3 depicts the differences between these two scrubber systems. 

HEV Scrubber JEV Scrubber 

Figure 2-3. Diagrams of HEV & JEV Scrubbers 

SOURCE: Sapre, A.V., D.S. McCaffrey Jr., R.B. Redich, J.N. Iyengar, and H.P. Singh, 2003, “Leading Edge Technology to Abate 

Air Emissions,” Fairfax, Virginia. 

DIRTY FLUE GAS IN @ P1 

SCRUBBING LIQUID IN

PARTICULATE

LIQUID DROPLETS

SO

SO

SO SO SO

SO

SO

DIVERGING SECTION

CONVERGING SECTION

SCRUBBED FLUE GAS & LIQUID DROPLETS @ P2 

SULFUR DIOXIDE

NOTE P1 P2

LIQUID 

SCRUBBED FLUE GAS & LIQUID DROPLETS @ P2 

PARTICULATE

SCRUBBING LIQUID IN 

DIVERGING SECTION

CONVERGING SECTION

SULFUR 

NOTE: P2>P1 

DIRTY FLUE

BODY

LIQUID SPRAY NOZZLE
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 2 – Catalytic and Thermal Cracking Units Page 2-16 

MACTEC Federal Programs, Inc. 

Wellmann-Lord Flue Gas Desulfurization Process (DTI, 2003) 

The Wellmann-Lord Flue Gas Desulfurization (FGD) process removes SO2 from the flue gas 

with a control efficiency of about 98%. The flue gas enters the absorber and gas is scrubbed 

with an aqueous sodium sulfite solution. The clean flue gas exits the absorber, passes through a 

set of demisters, and is discharged to the atmosphere. A benefit of this process is that 

regeneration of the sodium sulfite solution produces concentrated SO2 streams which can be 

converted and sold as liquid SO2, sulfuric acid, or elemental sulfur. There are approximately 

forty Wellmann-Lord FGD units in Japan, the US, and Germany, however no new units have 

been built in recent years. 

Sea Water Scrubbing (IPPC, 2003) 

Sea Water Scrubbing takes advantage of the natural alkalinity of sea water to remove up to 99% 

of the SO2 in flue gas. After scrubbing, the water can be treated with air, and discharged back 

into the sea. This process is feasible for sites near large bodies of sea water, which first treat the 

flue gas with a particulate abatement technique. 

2.4.1.2 DeSOx Additives 

DeSOx additives are typically metal oxide catalysts that convert SO2 to SO3 inside the catalyst 

regenerator. The SO3 is adsorbed to a sulfate and then recycled back to the reactor with the 

FCCU catalyst, where it is reduced in the reactor to H2S, which is controlled by the refinery’s 

sulfur recovery plant. This three step process can remove between 20% and 60% of the SO2 in 

the flue gas, depending on the mode of combustion and flue gas SO2 concentration. 

2.4.1.3 Feed Hydrotreatment 

FCC feed hydrotreatment can significantly reduce inlet sulfur content to less than 0.1% to 0.5% 

by weight, depending on the initial feedstock concentration, which can in turn reduce SO2

emissions from the FCCU catalyst regenerator by up to 90%. Reductions in nitrogen compounds 

(up to 75 – 85%) and trace metal impurities are also achieved with the use of feed 

hydrotreatment. The hydrotreatment process takes place over a metal catalyst in a hydrogen 

atmosphere. This process has advantages including reduction in the amount of sulfur in final 

refinery products, as well as improvement of final products, thereby requiring less final 

processing. 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 2 – Catalytic and Thermal Cracking Units Page 2-17 

MACTEC Federal Programs, Inc. 

2.4.2 NOx Controls 

The quantity of NOx emissions discharged from the FCCU depends upon the nitrogen content of 

feed due to crude type and upstream conditions, as well as the combustion conditions inside the 

catalyst regenerator or CO-boiler. NOx reductions from the FCCU process can be achieved by 

modifying the combustion zone to reduce the amount of thermal NOx formed, or through the use 

of add-on post-combustion control equipment, to remove NOx present in the flue gas that has 

already been formed. Examples of available control systems are described below. 

BOC Gases’ LoTOx Process (EPA, 2005) 

BOC Gases’ LoTOx process uses industrial-grade oxygen in a non-thermal plasma reactor to 

reduce pollutants by first converting them to a higher-oxidized state. After oxidation, the 

pollutants are hydrolyzed and removed with a caustic scrubber. BOC is marketing this process 

primarily as a NOx control technology, with achieved emission reductions of 80 – 95%. This 

technology has been reviewed by the California Air Resources Board, and according to the EPA 

RBLC Database, this process is to be installed on FCCUs located at petroleum refineries in 

Arkansas and Texas. 

Figure 2-4. BOC Gases’ LoTOx Process 

SOURCE: United States Environmental Protection Agency, 2005, “Using Non-Thermal Plasma to Control Air Pollutants,” EPA456/R-05-001, Clean Air Technology Center, Research Triangle Park, North Carolina. 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 2 – Catalytic and Thermal Cracking Units Page 2-18 

MACTEC Federal Programs, Inc. 

Grace Davison’s XNOx & DENOX Promoters (Davey, 2000) 

XNOx is a non-platinum combustion promoter used to control CO emissions and unit afterburn, 

as well as reduce NOx emissions up to 50 – 75%. The XNOx promoter was developed as an 

alternative to the conventional platinum-base CO promoter used to control afterburn. The XNOx 

technology has been successfully tested in ten FCCUs worldwide. For FCCUs that do not use 

CO promoters for afterburn control, Grace Davison developed the DENOX promoter. In 

commercial tests of the DENOX promoter, NOx reductions of up to 60% were achieved without 

an increase in regenerator afterburn. 

Selective Non-Catalytic Reduction (SNCR) 

The SNCR system is a post-combustion control technology that reacts ammonia or urea with flue 

gas to convert NOx compounds into nitrogen and water without the use of a catalyst. Without 

the use of a catalyst, high temperatures of 1600 and 2000o

F are required for NOx conversion. 

However, this temperature range is sensitive, as the reagents will produce additional NOx if the 

temperature is too high, and the reaction will proceed slowly and permit the escape of unreacted 

ammonia if the temperature is too low. Additives, such as hydrogen, and carrier gases can be 

added to enhance the SNCR, allowing the reaction to take place at temperatures as low as 

1290oF. These systems have been successfully applied to boilers and process heaters, as well as 

FCCU CO boilers. Retrofit applications on refinery CO boilers have achieved NOx control 

efficiencies in the 40-50% range.. 

Selective Catalytic Reduction (SCR) 

The SCR system is a post-combustion control technology that injects ammonia in flue gas in the 

presence of a catalyst (e.g. titanium dioxide, vanadium pentoxide) to convert NOx compounds 

into nitrogen and water. The optimum operating temperature of SCR systems is between 480o

F 

and 800oF, depending on the catalyst, for NOx conversion. These systems have be been 

successfully applied to refinery furnaces and FCCUs, and have achieved NOx control 

efficiencies of 80 - 95%. 

ExxonMobil WGS+ (Sapre, 2003) 

Another control device developed by EMRE is an additive for use in existing wet gas scrubbers 

that will reduce NOx emissions. The additive is introduced in the disengaging drum of the 

scrubber to form aqueous sodium nitrate. The effectiveness of the additive is dependent upon 

contacting efficiency and other factors. In recent lab and field tests, NOx reduction ranged from 

40 – 60%. EMRE engineers indicate that with modifications to the wet gas scrubber in addition 

to using this additive, NOx reductions up to 90% can be achieved. The WGS+ technology was 

to be installed at an ExxonMobil refinery sometime in 2004; however no further information on 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 2 – Catalytic and Thermal Cracking Units Page 2-19 

MACTEC Federal Programs, Inc. 

WGS+ is available. The only drawback to the use of this additive is the potential effect of 

increased nitrates to the wastewater treatment system. 

2.4.3 PM Controls 

The main source of PM10 and PM2.5 emissions at petroleum refineries is FCCU catalytic 

regenerators because catalyst fines are released in the regenerator’s exhaust. PM10 is easily 

controlled using common control devices such as wet scrubbers, electrostatic precipitators (ESP), 

and third stage separators/cyclones. However, fine particulates and condensables, such as 

sulfuric acid mist, can be more difficult to control due to the size limitations of these control 

devices. A patented SBS injection technology has been developed to prevent the formation of 

sulfuric acid mist. Properly designed control systems can be effective at controlling both PM10

and PM2.5 size fractions. Specific performance data for particle size ranges in controlling 

FCCUs was not found. 

2.4.3.1 Wet Scrubbing 

As mentioned in section 2.4.1.1, wet scrubbers are capable or removing PM from flue gas, in 

addition to absorbing SO2 with the use of additives. Venturi scrubbers with high pressure drops 

are most effective for removing up to 90% of PM from flue gas emitted from FCCU 

regenerators. In cases where fine particulates are an issue, a traditional high efficiency venturi 

scrubber can be placed in series with a wet ESP to remove sulfuric acid mist and other fine 

condensables. BELCO (Eagleson 1999) reports that their wet scrubbing systems can control 

particulate below 0.5 lbs/1,000 of coke burn-off. 

2.4.3.2 Electrostatic Precipitators 

In ESPs, flue gas is passed between a high-voltage electrode and a grounded electrode, where 

particulates in the flue gas becomes charged, and are attracted and collected on the grounded 

electrode. Particles are removed from the grounded electrode by vibration (dry ESPs) or 

washing (wet ESPs). ESPs have been applied to FCCUs, and have achieved PM reductions up to 

95%. 

2.4.3.3 SBS Injection Technology 

Sulfuric acid mist contributes to fine particulate emissions from FCCU catalytic regenerators and 

can cause visible emissions and regional haze problems. Sulfuric acid mist is generated when 

SO3 present in the flue gas is quenched in a wet scrubber. After the sub-micron aerosol mist is 

formed, only a portion of it can be removed in the scrubber, and the rest is released to the 

atmosphere. The SBS injection technology requires injecting a solution of sodium bisulfite 

(SBS) into the flue gas within a temperature range of 250 – 800oF upstream of the wet scrubber. 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 2 – Catalytic and Thermal Cracking Units Page 2-20 

MACTEC Federal Programs, Inc. 

The SBS solution reacts quickly with SO3 in a gas-solid reaction producing dry sodium sulfate 

and sodium bisulfate particles which can be removed by a downstream ESP or wet scrubber. A 

process diagram of this technology setup is shown in Figure 2-5. 

Figure 2-5. SBS Injection Technology Process Diagram 

SOURCE: Weaver, Edwin H., and G.W. Billemeyer, 2003, “A Logical and Cost Effective Approach to the Reduction of Air 

Emissions from the FCCU Regenerator,” 5th Catalytic Cracking Conference, Sao Paulo, Brazil. 
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Section 2 – Catalytic and Thermal Cracking Units Page 2-21 

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2.4.3.4 Third Stage Separators 

Third Stage Separators (TSS) incorporate the basic principle of traditional PM cyclones by using 

multiple swirl tubes that are designed to separate catalyst fines and other PM from FCCU 

regenerator flue gas. Third stage separators are also sometimes paired with smaller fourth stage 

separators (FSS) or FSS filters to efficiently remove catalyst fines from the TSS underflow, as 

shown in Figure 2-6. Traditional cyclones are usually limited to removing larger particles, 

requiring the flue gas to be treated with a secondary control device, such as a scrubber or ESP. 

Testing of the TSS equipment has revealed that almost all PM above 2 μm has been removed, 

resulting in only fine particulates escaping the TSS. 

Figure 2-6. Typical TSS and FSS Arrangement 

SOURCE: Weaver, Edwin H., and G.W. Billemeyer, 2003, “A Logical and Cost Effective Approach to the Reduction of Air 

Emissions from the FCCU Regenerator,” 5th Catalytic Cracking Conference, Sao Paulo, Brazil. 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 2 – Catalytic and Thermal Cracking Units Page 2-22 

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2.4.4 CO Controls 

CO emissions at petroleum refineries are mainly associated with partial combustion catalyst 

regenerators, FCCUs, and coking units. Full combustion catalyst regenerators are also a source 

of CO emissions; however due to complete regeneration of the catalyst, CO emissions are 

significantly less, and usually don’t warrant CO emission controls. The most common control 

device is a CO boiler (or waste heat boiler) located after the FCCU regenerator. CO emissions 

can also be reduced by introducing CO combustion promoters in to the catalyst regenerator to 

oxidize CO to CO2. Four refineries in New Jersey have CO ppm limits ranging from 50-300 

ppmvd on an hourly basis, which is considerably lower than the 500 ppmvd limit specified in the 

recent Consent Decrees. 

2.4.4.1 CO Boilers 

CO boilers are used to combust the CO present in exhaust gases at high temperatures 

(approximately 1400o

F) in the presence of external combustion air, with the added advantage of 

generating steam for use at the petroleum refinery. CO boilers burn refinery fuel gas and/or 

natural gas to generate the necessary heat to oxidize CO to CO2. CO boilers are capable of 

oxidizing at least 95% or more of CO emissions present in the exhaust stream to CO2, while also 

oxidizing at least 90% of VOC emissions. 

2.4.4.2 CO Combustion Promoters 

CO combustion promoters are used in the catalyst regenerator primarily to oxidize CO to CO2, 

while in some cases the promoter will also reduce NOx emissions and limit afterburn in the 

regenerator. Afterburn occurs when CO in the regenerator is not completely oxidized to CO2 in 

the oxygen rich zone. When this happens, the oxidation of CO will continue into the oxygen 

deficient area of the regenerator, increasing the temperature of this area and potentially causing 

serious metallurgical damage to cyclones and flue-gas lines downstream. CO combustion 

promoters, such as Engelhard Corporation’s OxyCleanTM and Grace Davison’s XNOx 

(mentioned in section 2.4.2) are effective at reducing CO emissions while controlling NOx 

emissions at efficiencies greater than 45% and avoiding afterburn. Engelhard’s ProCat® and 

USPTM combustion promoters also reduce CO emissions, while controlling afterburn, however 

do not affect NOx emissions. These promoters contain platinum attached to a support made up 

of aluminum (USPTM) or silica (ProCat®) with strong chemical anchors to avoid afterburn while 

promoting CO combustion. The Albemarle Catalysts Company has also developed two types of 

CO promoters that reduce CO emissions while preventing afterburn. The first promoter, KOC, is 

a platinum additive on an alumina support, similar to Engelhard’s USPTM. Albemarle has also 

developed a CO combustion promoter called InSituPro, where platinum is impregnated onto the 

catalyst in varying concentrations to meet the needs of specific regenerators. 
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2.4.5 VOC Controls 

VOC emissions at petroleum refineries are mainly associated with fugitive releases, however 

they are also emitted from partial combustion catalyst regenerators. VOCs can be reduced by 

various control measures, however a CO boiler after a partial burn regenerator can reduce VOC 

emissions up to 90%, as discussed in section 2.4.4. 

2.5 COSTS AND AVAILABILITY 

Feasible control technologies for FCCUs and FCCU catalyst regenerators are summarized in 

Table 2-6. The table includes 

• Pollutant controlled 

• Name of technology 

• Origin for the level of control (rule, consent decree, permit) 

• Range of potential emission reductions from applying those controls 

• Performance level in terms of outlet concentration or emission rate 

• Cost effectiveness of the controls 

• Commercial status 

• Reference 

More detailed information on each technology was summarized in the previous sections and 

based on the information contained in the references for this Section. 

The cost data presented in the Table were obtained from the published literature as referenced. 

In general, the percent reductions and cost effectiveness data represent data for uncontrolled 

sources. Incremental reductions will be lower and costs will be higher for sources already have 

some level of control and will be required to meet the performance levels shown in the Table. 

Also, site-specific factors greatly influence the actual achievable performance level and control 

costs at a particular facility. These considerations must be addressed in State and local 

rulemaking and permitting processes. 
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Section 2 – Catalytic and Thermal Cracking Units Page 2-24 MACTEC Federal Programs, Inc. 

Table 2-6: Control Technology Options for FCCUs and FCUs 

Pollutant Technology 

Origin of 

Requirement 

Percent 

Reduction Performance Level 

Cost 

Effectiveness 

($/ton) 

Comm

Ava

SO2 Wet Scrubber Consent Decree 95 to 99.9 25 ppmvd @ 0% O2 based on 365-day 

rolling average or 50 ppmvd @ 0% O2

based on 7-day rolling average 

500 to 3,000 

DeSOx Additives 

NSPS 35 to 50 9.8 kg per 1000 kg of coke burned 

(normally translates to a FCC flue gas SOx concentration of approximately 300 ppmvd) 

499 to 880 

NOx SCR Consent Decree 85 to 90 20 ppmvd, measured as a 365-day 

rolling average, and 40 ppmvd, measured as a 7-day rolling average, @ 0% O2

2,364 to 2,458 

 LoTOx Consent Decree 80 to 95 20 ppmvd, measured as a 365-day 

rolling average, and 40 ppmvd, measured as a 7-day rolling average, @ 0% O2

1,700 to 1,950 To be 

unde

d

 SNCR Consent Decree 60 to 80 20 ppmvd, measured as a 365-day 

rolling average, and 40 ppmvd, measured as a 7-day rolling average, @ 0% O2

1,520 to 1,985 

Scrubber Based NOx Technology (SNERT) 

Consent Decree 40 to 60 20 ppmvd, measured as a 365-day 

rolling average, and 40 ppmvd, measured as a 7-day rolling average, @ 0% O2

Not available To be 

unde

d

PM Wet Scrubber Consent Decree 85 to 95 0.5 pounds PM per 1000 pounds coke 

burned on a 3-hour average basis 

Not available 

Electrostatic Precipitator 

Consent Decree or 

NSPS 

>95% 1.0 pounds PM per 1000 pounds coke 

burned on a 3-hour average basis 

3,500 to 6,600 

CO CO Boiler State Permits 95 200 ppmvd @ 0% O2 based on 1-hr 

block average and 100 ppmvd @ 0% O2 based on 365-day rolling average 

Not available 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 2 – Catalytic and Thermal Cracking Units Page 2-25 

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2.6 REFERENCES 

Albemarle Catalysts Company, “InSituPro: The Most Effective Way to Reduce Afterburn in 

your FCC Unit,” http://www.albemarle.com/TDS/FCC/INSITUPRO_MIB_8Nov05.pdf. 

Davey, S.W., 2000, “Environmental Fluid Catalytic Cracking Technology,” European Refining 

Technology Conference, Columbia, Maryland. 

Department of Trade and Industry, 2003, “Flue Gas Desulphurisation (FGD) Technologies for 

Coal-Fired Combustion Plant,” United Kingdom. 

Eagleson, S.T. and E.H. Weaver, 1999, “Controlling FCCU Emissions – EDV® Wet Scrubbing,” 

11th Refining Seminar, Dallas, Texas. 

Engelhard Corporation, 2002, “ProCat® and USPTM: FCC Additives for the Reduction of 

Regenerator Afterburn and CO Emissions,” Engelhard Corporation, 2003, “OxyCleanTM

CO Promoter Reduces NOx Emissions by 45%,” 

http://www.engelhard.com/documents/EC-7762Rev5-02.pdf. 

Engelhard Corporation, 2003, “OxyCleanTM CO Promoter Reduces NOx Emissions by 45%,” 

http://www.engelhard.com/documents/OxyClean%20case%20study.pdf. 

Engelhard Corporation, 2003, “OxyCleanTM: FCC Additive for the Reduction of Regenerator 

Afterburn, CO and NOx Emissions,” http://www.engelhard.com/documents/OxyClean%20 

datasheet.pdf. 

European Commission, Integrated Pollution Prevention & Control, 2003, “Reference Document on 

Best Available Techniques for Mineral Oil and Gas Refineries.” 

Friedman, M., 2006a, Email to E.J. Sabo (MACTEC Federal Programs, Inc.), January 23 2006, 

New Jersey Department of Environmental Protection, Trenton, New Jersey. 

Friedman, M., 2006b, Email to W. Gillespie (MARAMA), September 6, 2006, New Jersey 

Department of Environmental Protection, Trenton, New Jersey. 

Giles, K.A., “Fundamentals of Petroleum Refining,” 

http://www.pdhengineer.com/Course%20Files/ 

Completed%20Course%20PDF%20Files/FundamentalsPetroleumRefiningCourse.pdf. 

Her Majesty’s Inspectorate of Pollution, 1995, “Chief Inspector’s Guidance Note Series 2 (S2): 

Petroleum Processes: Oil Refining and Associated Processes,” Technical Guidance Branch, 

London, England. 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 2 – Catalytic and Thermal Cracking Units Page 2-26 

MACTEC Federal Programs, Inc. 

MACTEC Engineering and Consulting, Inc., 2005, “Petroleum Refinery Best Available Retrofit 

Technology (BART) Engineering Analysis”, 

http://www.ladco.org/Regional_Air_Quality.html 

McIlvaine Company, “Products and Services,” http://www.mcilvainecompany.com/RefineryAPC/ 

subscriber/text/prod&serv/prod&serv.htm. 

Refining Online, 2004, “Understand CO Oxidation Operating Variables to Prevent Afterburn,” 

http://www.refiningonline.com/EngelhardKB/crep/TCR5_46.htm. 

Sapre, A.V., D.S. McCaffrey Jr., R.B. Redich, J.N. Iyengar, and H.P. Singh, 2003, “Leading Edge 

Technology to Abate Air Emissions,” Fairfax, Virginia. 

Steltzer, B., 2005, Conference Call, December 7, Delaware Department of Natural Resources & 

Environmental Control, Air Quality Management, New Castle, Delaware. 

United States Environmental Protection Agency, 1995, “Petroleum Refining,” Pages 5.1-1 – 5.1-

16 in AP-42, Fifth Edition: Compilation of Air Pollutant Emission Factors, Volume 1: 

Stationary Point and Area Sources, http://www.epa.gov/ttn/chief/ap42/ch05/final/c05s01.pdf.

United States Environmental Protection Agency, 1998, “Petroleum Refineries Background 

Information for Proposed Standards: Catalytic Cracking (Fluid and Other) Units, Catalytic 

Reforming Units, and Sulfur Recovery Units,” EPA-453/R-98-003, Office of Air Quality 

Planning and Standards, Research Triangle Park, North Carolina. 

United States Environmental Protection Agency, 2005, “Using Non-Thermal Plasma to Control 

Air Pollutants,” EPA-456/R-05-001, Clean Air Technology Center, Research Triangle 

Park, North Carolina. 

United States Environmental Protection Agency, 2006, National Petroleum Refinery Initiative 

Web Site: http://www.epa.gov/compliance/resources/cases/civil/caa/oil/index.html 

Weaver, Edwin H., and G.W. Billemeyer, 2003, “A Logical and Cost Effective Approach to the 

Reduction of Air Emissions from the FCCU Regenerator,” 5th Catalytic Cracking 

Conference, Sao Paulo, Brazil. 

Weaver, Edwin H., Eagleson, S.T., and Confuorto, N., 1999, “LABSORB A Regenerative Wet 

Scrubbing Process for Controlling SO2 Emissions” Presented at Sulphur 99, October 17-

20, 1999, Calgary, Alberta, Canada. 
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3.0 BOILERS AND PROCESS HEATERS 

Boilers and process heaters are large sources of CO, NOx, PM, and SO2 emissions at petroleum 

refineries. Numerous control strategies (including fuel switching, combustion modification, and 

add-on control equipment) have been developed over the years for reducing emissions from 

refinery boilers and heaters. Further reducing emissions of NOx and SO2 from boilers and 

process heaters is the primary concern, as these pollutants are precursors for ozone and fine 

particulate formation. This Section presents an assessment of available control technology 

options for states to consider as they undertake efforts to develop rules and SIPs for ozone, 

PM2.5, and regional haze. 

3.1 PROCESS DESCRIPTION 

Most refineries have a utilities plant that supplies the steam necessary for the refinery. Steam is 

primarily used for heating and separating hydrocarbon streams. When used for heating, the 

steam usually heats the petroleum indirectly in heat exchangers and returns to the boiler. In direct 

contact operations, the steam can serve as a stripping medium or a process fluid. Steam may also 

be used in vacuum ejectors to produce a vacuum. The steam can be used to produce electricity by 

expansion through a turbine (some refineries may receive electricity from outside sources. 

Process heaters (furnaces) are used extensively in refineries to supply the heat necessary to raise 

the temperature of feed materials to reaction or distillation level. They are designed to raise 

petroleum fluid temperatures to a maximum of about 510°C (950°F). The fuel burned may be 

refinery gas, natural gas, residual fuel oils, or combinations, depending on economics, operating 

conditions, and emission requirements. Process heaters may also use CO-rich regenerator flue 

gas as fuel.

Boilers and process heaters are similar in that they are combustion devices which burn fuels such 

as natural gas, fuel oil, and refinery fuel gas (one refinery in northwestern Pennsylvania burns 

coal in one of its boilers). The main difference is that boilers are designed to burn fuels to 

generate steam for use throughout the refinery, while process heaters burn fuels to transfer heat 

directly to process materials. In the case of process heaters, combustion gases do not interact 

with process materials. Most control technologies developed for controlling emissions from 

boilers are also applicable to process heaters, and are discussed in the sections that follow. 

3.2 EMISSION INVENTORY 

Table 3-1 summarizes the emissions from petroleum refinery boilers and heaters in the 

MARAMA region. Criteria pollutant emissions for each refinery are shown for three years. The 

2002 annual emissions serve as the baseline for future SIP development. 
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Table 3-1: Emission Inventory for Boilers/Heaters 

 Annual Emission (tons/year) 

State Refinery Year SO2 NOx VOC CO PM10 PM2.5 NH3

DE Valero Delaware City 2002 2,446 2,032 26 173 248 208 35 

 2004 188 1,373 19 154 52 52 0 

 2009 38 926 21 152 81 81 31 

DE SUNCO R M 2002 116 548 12 167 25 24 8 

 2004 310 545 10 158 40 32 7 

 2009 1 91 3 38 6 6 2 

NJ Sunoco Eagle Point 2002 26 741 13 27 54 53 0 

 2003 24 660 52 81 59 59 0 

 2009 1 334 11 26 61 61 0 

NJ Valero Refining 2002 688 814 49 165 94 93 0 

 2003 916 1,059 16 146 117 117 7 

 2009 952 539 57 225 120 119 0 

NJ CITGO Asphalt 2002 19 147 5 46 6 6 0 

 2003 31 120 2 38 6 6 3 

 2009 20 155 5 49 7 6 0 

NJ Amerada Hess 2002 1 41 1 16 3 1 0 

 2003 2 60 2 34 3 3 0 

 2009 2 59 1 24 4 1 0 

NJ Chevron Products 2002 11 137 1 7 6 6 0 

 2003 10 129 1 3 13 13 3 

 2009 14 178 2 8 7 7 0 

NJ ConocoPhillips Bayway 2002 526 1,123 13 42 47 47 0 

 2003 454 1,157 1 19 55 44 0 

 2009 552a 589 13 44 49 49 0 

PA Sunoco Marcus Hook 2002 18 796 29 433 57 48 0 

 2004 2 514 21 298 36 36 0 

 2009 7 510 39 586 74 62 0 

PA ConocoPhillips Trainer 2002 394 1,953 43 671 59 38 2 

 2004 480 1,747 44 638 55 42 2 

 2009 18 1,086 46 730 63 42 3 

PA American Refining 2002 1,294 229 2 90 13 6 0 

 2003 1,269 245 2 95 13 6 0 

 2009 1,334 256 2 98 10 4 0 

PA Sunoco Philadelphia 2002 913 2,498 90 1,381 108 108 0 

 2003 992 2,495 87 1,319 128 128 0 

 2009 521b 2,048 b 74 b 1,107 b 84 b 84 b 0 

PA United Refining Warren 2002 1,808 355 12 193 137 88 4 

 2004 1,795 543 14 209 114 89 4 

 2009 2,191 437 15 247 156 96 4 

VA Giant Yorktown 2002 12 376 15 189 21 21 0 

 2004 12 368 15 188 21 21 0 

 2009 12 270 16 192 16 16 0 

WV Ergon 2002 31 179 11 125 11 11 5 

 2003 28 184 12 138 11 11 5 

 2009 34 94 12 136 12 11 6 

 MARAMA Totals 2002 8,306 11,968 322 3,724 889 757 55 

 2003/04 6,514 11,199 298 3,518 722 657 31 

 2009 5,688 7,592 317 3,660 747 644 46 

Notes: a) CD for Bayway requires large SO2 reductions by 2012; b) Keith Lemchak provided revised 2009 emissions based 

upon CD reductions; further reductions from the CD are schedule during 2010 and 2011.
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The 2002 emissions were obtained from the 2002 inventories developed by MANEVU and 

VISTAS. The 2003 or 2004 emissions were obtained directly from each state and represent the 

most currently quality assured data that is available. 

The 2009 emissions were obtained from the MANEVU and VISTAS projection inventories that 

were developed to support modeling for SIP development. The 2009 inventories include the 

effects of anticipated growth as well as any planned controls that will result in emission 

reductions between 2002 and 2009 due to new regulations or enforcement settlements. The 

growth factors used for projecting emissions from 2002 to 2009 came from the U.S. 

Environmental Protection Agency’s Economic Growth Analysis System (EGAS 5.0) and the 

U.S. Department of Energy’s Annual Energy Outlook (2005) projections. The controls factors 

for 2009 were derived either from data supplied that the State/local agencies or from MACTEC’s 

analysis of the requirements contained in the global enforcement settlements. 

Table 3-1 shows that SO2 emissions for a few refineries are projected to be reduced by 2009 as a 

result of the requirements of the enforcement settlements (to be discussed in more detail later). 

The region-wide NOx emissions in 2009 are projected to be about 10 percent lower than in 2002, 

and SO2 emissions in 2009 projected to be about 25 percent lower than in 2002. Further 

reductions in SO2 and NOx emissions are expected at the Philadelphia refinery beginning in 

2011. 

3.3 EXISTING REQUIREMENTS 

This section discusses the regulatory requirements which apply to boilers and process heaters. 

Four types of requirements are discussed: (1) Federal requirements such as the New Source 

Performance Standards (NSPS) and Maximum Achievable Control Technology (MACT) 

standards; (2) State regulations for both the MARAMA states as well as other State agencies; (3) 

source-specific permit requirements; and (4) new requirements from recent enforcement 

settlements. 

3.3.1 Federal Requirements 

The U.S. EPA has promulgated standards for emissions of PM, NOx, SO2, and CO, as well as 

toxic compounds from petroleum refinery boilers and heaters. 

The New Source Performance Standards (NSPS) apply to boilers and process heaters at 

petroleum refineries. Several Subparts to Title 40 CFR Part 60 apply to boilers and/or process 

heaters depending on unit capacity and fuels burned, and are summarized in Table 3-2. 
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Table 3-2: Summary of NSPS Regulations for Boilers & Process Heaters 

Heat Input 

(MMBtu/hr) 

NSPS 

Subpart 

Construction

Date 

Fuel 

Type 

PM Emission 

Limit 

(lb/MMBtu) 

SO2 Emission 

Limit 

(lb/MMBtu) 

NOx Emission 

Limit 

(lb/MMBtu) 

Gas 0.10 - 0.2 

Liquid 0.10 0.8 0.3 Boilers 

> 250 D 8/17/1971 

Solid 0.10 1.2 0.7 

Gas - 0.10 – 0.20 

Db, J 6/19/1984 Liquid 0.10 0.30 – 0.40 

Solid 0.051 – 0.20 

0.10 gr/dscf 

H2S 

(162 ppm) 0.5 – 0.8 

Db 7/9/1997 All 

Fossil - - 0.10 – 0.20 

ICI 

Boilers 

> 100 

Db 2/28/2005 All 

Fossil 0.03 

Gas - - - 

ICI Liquid - 0.50 - 

Boilers 

10 - 100 

Dc 6/9/1989 

Solid 0.051 – 0.10 

1.12 

(+ 90% 

Controlled) 

Process 

Heaters 

All Sizes 

J 

 All 

Fuels 

except 

natural 

gas 

- 

0.10 gr/dscf 

H2S 

(162 ppm) 

- 

Subpart D applies to fossil-fuel-fired steam generators with heat input capacities greater than 250 

MMBtu/hr that were constructed after August 17, 1971. Subpart Da applies to electric utility 

units and not to units at petroleum refineries. Subpart Db applies to industrial-commercialinstitutional (ICI) steam generating units greater than 100 MMBtu/hour. According to section 

60.40(c) of this subpart, only performance standards for PM and NOx from Subpart Db apply to 

boilers at petroleum refineries (SO2 emissions are subject to 40 CFR 60 Subpart J). Subpart Dc 

applies to small ICI steam generating units with heat input capacities between 10 and 100 

MMBtu/hr. The last set of performance standards that apply is the SO2 standards found in 

Subpart J, which apply to fuel gas combustion devices (boilers and process heaters) at petroleum 

refineries that were constructed or modified after June 11, 1973. 

NSPS: Heat Input Capacity > 250 MMBtu/hr 

Under Subpart D, for boilers with heat input capacities greater than 250 MMBtu/hr, PM 

emissions are limited to 0.10 lb/MMBtu burning fossil fuel, while opacity is limited to 20%, 

except for one 6-minute period per hour that is limited to 27% opacity. SO2 emissions are 

limited to 0.80 lb/MMBtu when firing liquid fossil fuel and 1.2 lb/MMBtu when firing solid 

fossil fuel, while NOx emissions are limited to 0.20 lb/MMBtu when firing gaseous fossil fuels 

and 0.30 lb/MMBtu when firing liquid fossil fuels. When multiple fuels are fired simultaneous, 
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an equation is used to determine the emission standards for SO2 and NOx using the total heat 

input from each type of fuel fired. 

NSPS: Heat Input Capacity Greater than 100 MMBtu/hr 

For boilers greater than between 100 MMBtu/hour at petroleum refineries, performance 

standards from Subpart Db apply for emissions of PM and NOx, while performance standards 

from Subpart J apply for emissions of SO2. Each of the following emission limits are based on 

the combination of fuels fired in the unit. For units firing coal or coal and other fuels, PM 

emissions are limited to 0.051 lb/MMBtu, or 0.10 lb/MMBtu if the facility combusts coal and 

other fuels with an annual capacity factor for the other fuels greater than 10%, or 0.20 lb/MMBtu 

if the facility combusts coal or coal and other fuels with an annual capacity factor of 30% or less 

and the unit began construction after June 19, 1984 and before November 25, 1986. NOx 

emissions from coal fired units vary between 0.50 and 0.80 lb/MMBtu depending on the type of 

boiler (e.g. mass-feed stoker, spreader stoker) and type of coal combusted (e.g. lignite, 

pulverized). For units firing oil, PM emissions are limited to 0.10 lb/MMBtu, while NOx 

emissions are limited to 0.30 lb/MMBtu with low heat release rates and 0.40 lb/MMBtu with 

high heat release rates. There is no PM emission limit for gas fired units, however, NOx 

emissions are limited to 0.10 lb/MMBtu with low heat release rates and 0.20 lb/MMBtu with 

high heat release rates. The SO2 performance standards from Subpart J require the hydrogen 

sulfide (H2S) concentration of fuel gas is limited to 0.10 gr/dscf (162 ppm). 

In September 1998, the NOX emission limit was changed to 0.20 lb/MMBtu heat input from the 

combustion of natural gas, oil, coal, or a mixture containing any of these fossil fuels; however, 

for low heat release rate units firing natural gas or distillate oil, the current NOX emission limit 

of (0.10 lb/MMBtu heat input is unchanged. The revised NOx limit only applies to units for 

which construction, modification, or reconstruction commenced after July 9, 1997. 

In February 2005, EPA revised the emission limits for SO2 and PM. For units at petroleum 

refineries, the Subpart J requirements still apply and have not been affected by the revised NSPS. 

The revised PM emission standard is consistent with the new source limits of 0.03 lb/MMBtu 

included in EPA’s recently issued national air toxics standards for boilers. The revised PM limit 

only applies to units for which construction, modification, or reconstruction commenced after 

February 28, 2005. 

NSPS: Heat Input Capacity between 10 and 100 MMBtu/hr 

Subpart Dc, regulates boilers with heat input capacities greater than 10 MMBtu/hr, but less than 

100 MMBtu. PM emissions for coal fired units are limited to 0.051 lb/MMBtu when burning 

coal or coal with other fuels with an annual capacity factor of 10% or less fuel or 0.10 lb/MMBtu 
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when firing coal with other fuels with an annual capacity factor for the other fuels greater than 

10%. Opacity is limited to 20%, except for one 6-minute period per hour that is limited to 27% 

opacity. SO2 emissions from coal burning units should be 90% controlled and should not exceed 

1.12 lb/MMBtu, while emissions from oil burning units are limited to 0.50 lb/MMBtu. For units 

that fire a combination of coal and oil with any other fuels, an equation is used to determine the 

emission limit based on the heat input from each fuel source. No NOx performance standards 

are listed under Subpart Dc. 

National Emission Standards for Hazardous Air Pollutants (NESHAP) Subpart DDDDD applies 

to industrial, commercial, and institutional boilers and process heaters located at facilities which 

are major sources of HAPs (potential to emit at least 10 tpy of any single HAP or 25 tpy of any 

combination of HAPs). This Subpart applies to new (constructed after January 13, 2003), 

reconstructed (modified after January 13, 2003), and existing boilers and process heaters. 

Emission limits vary depending on size of the unit (large, limited use, and small) and type of fuel 

fired (solid, liquid, or gas). 

Compliance with Title 40 CFR Part 63, Subpart DDDDD, can be achieved for boilers and 

process heaters by meeting limits set for PM or total selected metal emissions, in addition to 

meeting limits for hydrogen chloride (HCl), mercury (Hg), and carbon monoxide (CO). For new 

or reconstructed large, limited use, or small units firing solid fuel, emissions are limited to the 

following: PM of 0.025 lb/MMBtu (or total selected metals of 0.0003 lb/MMBtu), HCl of 0.02 

lb/MMBtu, and Hg of 0.000003 lb/MMBtu. A CO limit of 400 ppmvd at 7% O2 is also in effect, 

however, it does not apply to small units. For new or reconstructed large units firing liquid fuel, 

emissions are limited 0.03 lb/MMBtu for PM, 0.0005 lb/MMBtu for HCl, and 400 ppmvd at 3% 

O2 for CO. For limited use and small units firing liquid fuel, PM and CO emissions are the same 

as for the large units, however, HCl emissions are limited to 0.0009 lb/MMBtu. For new or 

reconstructed units firing gaseous fuel, only a CO emission limit of 400 ppmvd at 3% O2 applies. 

For existing large units firing solid fuels, PM is limited to 0.07 lb/MMBtu (or total selected 

metals of 0.001 lb/MMBtu), with HCl limited to 0.09 lb/MMBtu, and Hg limited to 0.000009 

lb/MMBtu. For existing limited use units firing solid fuels, PM is limited to 0.21 lb/MMBtu (or 

total selected metals of 0.004 lb/MMBtu). Subpart DDDDD also specifies operating limits for 

control equipment used to demonstrate compliance with PM emission limits. 

3.3.2 State Regulations 

Table 3-3 lists the regulations for each of the MARAMA states for the control of PM, SO2, and 

NOx. New Jersey is the only state with regulations for controlling CO and VOCs from boilers 

and process heaters. New Jersey limits CO emissions to 100 ppmvd @ 7% O2, while VOCs are 

limited to 50 ppmvd @ 7% O2 for units with heat inputs of 50 MMBtu/hr or more (NJDEP 
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Regulation 7:27-16.8). As part of the NOx SIP Call, States adopted a NOx emissions trading 

program and assigned 5-month ozone season NOx allowances for large boilers/heaters, including 

units at several refineries in MARAMA region. 

Table 3-4 lists the regulations for other states the control of PM, SO2, and NOx for refinery 

boilers and heaters. The regulations for the California air districts have more stringent 

requirements than the MARAMA state regulations, particularly for NOx. 

3.3.3 Permit Requirements 

Current permit requirements for boilers and process heaters at petroleum refineries vary widely 

in the MARAMA region depending on the size of the unit, date of construction, and type of fuel 

burned. For NOx, the emission limits range from 0.0033 lb/MMBtu for a 350MMBtu/hr unit 

burning refinery gas to 0.65 lbs/MMBtu for a 335 MMBtu/hr unit burning refinery fuel oil. 

3.3.4 Requirements from Recent Enforcement Settlements 

The EPA and state/local agencies recently undertook an initiative to investigate physical 

modifications to petroleum refineries. Capacity increases and modifications should have 

triggered NSR permitting and pollution control requirements. There have being several 

instances identified where refineries have failed to obtain pre-construction and operating permits 

for physical construction that increased their capacity and emissions. Consent Decrees require 

petroleum refineries to install continuous emissions monitoring equipment so that facilities, 

EPA, and States can access real time emissions data. 

The enforcement settlements for petroleum refineries in the MARAMA region focused mainly 

on control strategies to limit emissions of SO2 and NOx. Only the enforcement settlement for 

the Sunoco Eagle Point Facility included an emission limitation for PM, limiting emissions to 

0.00427 lb/MMBtu based on a 1-hour average. 

A listing of these requirements is found in Table 3-5. In general, the Consent Decrees require 

the refineries to select a qualifying control for NOx (SCR, SNCR, Ultra-low-NOx burners, any 

technology that can reduce NOx emissions to 0.04 lbs NOx / MMBtu). These requirements generally do 

not apply to all of a refinery’s heaters and boilers but to a small subset of heaters and boilers. For SO2, 

the Consent Decrees generally require the elimination of fuel oil burning and compliance with Subpart J 

refinery gas H2S limits. 
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Table 3-3: Summary of MARAMA State Regulations 

Agency PM SO2 NOx

Delaware 

Regulations 

Reg. 4: 

≤ 0.3 lb/MMBtu (max 2-hr 

avg.) 

Reg. 8: 

Distillate oil should have a sulfur 

content ≤ 0.3% by weight 

Reg. 12: 0.2 – 0.38 lb/MMBtu 

NOx depending on fuel type 

(gas, oil, coal) and firing type 

New Jersey 

Regulations 

7:27-4.2: 

PM emissions are extrapolated 

from a table that compares 

heat input (MMBtu) to 

maximum emission rates 

(lb/hr) 

7:27-7.2: 

≤ 2,000 ppm at standard conditions 

7:27-19.7: Non-Utility Boilers 

and Process Heaters 

Emissions limits (lb/MMBtu) 

vary depending on type of 

boiler/heater (tangential, face, 

or cyclone) 

No. 2 Fuel Oil: 0.12 

Other liquid fuel: 0.3 

Refinery fuel gas: 0.20 

Natural gas: 0.1 

Pennsylvania 

Regulations 

123.11: PM emissions from 

combustion units should 

comply with one of the 

following: 

(1) ≤ 0.4 lb/MMBtu for boiler 

heat input between 2.5 and 

50 MMBtu/hr; 

(2) ≤ 3.6(E-0.56) for E between 

50 and 600 MMBtu/hr; 

(3) ≤ 0.1 lb/MMBtu for E > 

600 MMBtu/hr 

123.21: % Sulfur in liquid fuels ≤

0.5% for No. 2 and lighter oils, and 

≤ 2.8% for No. 4, 5, 6, or heaver 

fuel oils. 

129.201: 

For units with heat inputs 

between 100 and 250 

MMBtu/hr 

Gas Fired: 

 ≤ 0.10 lb/MMBtu 

Liquid or Solid Fuel Fired: 

 ≤ 0.20 lb/MMBtu 

For units > 250 lb/MMBtu 

 ≤ 0.17 lb/MMBtu 

Philadelphia 

Regulations 

Reg. 2, Section 5: 

(1) ≤ 0.20 lb/MMBtu for 

existing units; 

(2) ≤ 0.10 lb/MMBtu for units 

constructed or installed 

after April 10, 1970. 

Reg. 3, Section 1: 

(1) % Sulfur in fuel oil ≤ 0.2% for 

No. 2 and lighter oils, ≤ 0.3% 

for No. 4, and ≤ 0.5% for No. 5, 

6, or heavier fuel oils; 

 (2) If the SO2 emission limit of ≤

0.30 lb/MMBtu firing No. 4, or 

0.52 lb/MMBtu firing No. 5, 6, 

or heavier, then %S restrictions 

do not apply. 

Reg. 7: NOx limits for 

combustion units with ≥ 250 

MMBtu/hr heat input are (1) 

0.20 lb/MMBtu (max 2-hr 

avg) when firing gaseous fuel; 

and (2) 0.30 lb/MMBtu (max 

2-hr avg) when firing liquid or 

solid fuel 

Virginia 

Regulations 

 9 VAC 5-40-280: 

(1) S = 2.64K (AQCR 1-6) 

S = allowable emission of sulfur 

dioxide (lb/hr) 

K = actual heat input at total 

capacity (MMBtu/hr) 

9 VAC 5-40-310: 

≤ 0.20 – 1.0 lb/MMBtu 

depending on fuel type (coal, 

oil, gas, combo) and firing 

method (face / tangential, 

cyclone, stoker) 

West Virginia 

Regulations 

 45-10-3: 

(1) S = 3.1K (Priority I & II 

Regions); 

(2) S = 3.2K (Priority III Region) 

(3) S = 1.6K (Region IV), however 

must be ≤ 5,500 lb/hr. , where 

K is the heat input (MMBtu/hr), 

and the resultant number is SO2

emissions (lb/hr) 
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Table 3-4: Summary of Other State Regulations

Agency PM SO2 NOx CO 

Louisiana 

Regulations 

Chapter 13, Subchapter C: 

≤ 0.60 lb/MMBtu 

Chapter 15: 

≤ 2,000 ppm at standard 

conditions (3-hr avg) 

Chapter 22: For Baton Rouge & 

the Region of Influence 

Process Heaters: 

≤ 0.18 lb/MMBtu (40 – 80 

MMBtu/hr); ≤ 0.08 

lb/MMBtu (> 80 MMBtu/hr) 

Industrial Boilers: 

≤ 0.20 lb/MMBtu (40 – 80 

MMBtu/hr); ≤ 0.10 

lb/MMBtu (> 80 MMBtu/hr) 

Texas 

Regulations 

111.153: 

(1) ≤ 0.3 lb/MMBtu for 

solid fuel fired units (2-

hr avg); 

(2) ≤ 0.1 lb/MMBtu for 

gas/oil fired units > 

2,500 MMBtu/hr (2-hr 

avg) 

112.8: ≤ 3.0 lb/MMBtu 

while burning solid 

fuels (3-hr avg) 

112.9: ≤ 440 ppmv at 

actual stack conditions 

while burning liquid 

fuels (3-hr avg); 

117.205b: 

(1) for gas fired boilers, NOx ≤

0.10 – 0.28 lb/MMBtu 

depending on boiler heat 

release and preheat temp.; 

(2) for liquid fuel fired boilers, 

NOx ≤ 0.30 lb/MMBtu; 

117.206: In the HoustonGalveston, catalytic cracking 

units (including CO boilers) 

must comply with: 

(1) ≤ 40 ppmvd @ 0% O2; 

(2) 90% NOx reduction from 

calculated June-Aug. 1997 

daily NOx emissions 

117.205f 

≤ 400 ppmvd @ 3% 

O2 for gas or liquid 

fuel-fired boilers or 

process heaters 

BAAQMD 

Regulations 

6-310: 

(1) ≤ 0.15 gr/dscf and (2) 

follow process weight rate 

(E = 4.1(P0.67) ≤ 40 lb/hr) 

9-1-304: 

Liquid fuels have a sulfur 

content of ≤ 0.5% by 

weight, while burning 

solid fuels results in ≤ 300 

ppm SO2 dry 

9-10-301: Refinery Wide 

Standards (excluding CO 

Boilers): ≤ 0.033 lb/MMBtu 

(24-hr avg) 

9-10-303: Refinery Wide 

Federal Requirements: 

≤ 0.20 lb/MMBtu (24-hr avg) 

9-10-304: Do not operate CO 

boilers unless NOx is 

controlled up to 50% or ≤ 150 

ppmvd @ 3% O2 (24-hr avg) 

9-10-305: 

≤ 400 ppmvd @ 3% 

O2 based on 24-hr 

avg. 

SCAQMD 

Regulations 

 Rule 1109: ≤ 0.03 lb/MMBtu @ 

max capacity 

SJV APCD 

Regulations 

Rule 4301: 

< 0.10 gr/dscf @ 12% CO2

 Rule 4306: Refinery Units 

(1) Gas Fired: 

5 – 65 MMBtu/hr: 30 ppmvd @ 

3% O2 or 0.031 lb/MMBtu 

65 – 110 MMBtu/hr: 25 ppmvd 

@ 3% O2 or 0.031 lb/MMBtu 

> 110 MMBtu/hr: 5 ppmvd @ 

3% O2 or 0.0062 lb/MMBtu 

(2) Liquid Fuel Fired: 40 ppmvd 

@ 3% O2 or 0.052 lb/MMBtu 

Rule 4352: Solid Fuel Fired 

< 0.20 lb/MMBtu (24-hr avg) 

Rule 4306: Refinery 

Units - 400 ppmvd 

@ 3% O2 

Rule 4352: Solid 

Fuel Fired Units: 

400 ppmvd @ 3% 

O2 or 310 ppmvd @ 

12% O2 or 310 

ppmvd @ 12% CO2
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Table 3-5: Summary of Recent Enforcement Settlements 

Refinery 

Unit 

Required SO2 Control 

Technologies & Emission 

Limitations 

Required NOx Control Technologies & Emission 

Limitations 

Valero Delaware City Cease burning liquid fuel 

in heaters and boilers 

except with NG supply is 

curtailed. 

Complete a program to reduce overall NOx from 

controlled heaters and boilers; 3rd addendum to the 

consent decree apportions 1,794 tons reductions to 

Premcor to be obtained by Dec. 2008 

Sunoco Eagle Point Elimination/reduction of 

fuel oil burning 

Implement a three-year program to reduce NOx

emissions through the installation of NOx controls and 

the acceptance and establishment of federallyenforceable emission limits so that the weighted 

average of individual heater and boiler permitted 

emissions at the Refinery are < 0.040 lb/MMBtu 

Valero Refining 

Heaters/Boilers 

(>40 MMBtu/hr) 

Discontinue burning fuel 

oil and comply with 

Subpart J 

0.060 lbs/MMBtu (interim system-wide weighted avg) 

by Dec. 31, 2009; 0.044 lbs/MMBtu (final system-wide 

weighted avg) by Dec. 31, 2011 

Citgo Asphalt Burning of fuel oil with a 

sulfur content of 0.05% 

prohibited (except during 

gas curtailments; Subject 

to NSPS Subparts A and J 

SCR, SNCR, Ultra-low-NOx burners, any technology 

that can reduce NOx emissions to 0.04 lbs NOx / 

MMBtu, single burner technology that can reduce 

emissions to 0.055 lbs/MMBtu if ultra-low-NOx 

burners are infeasible 

ConocoPhillips Bayway Upgrade refinery fuel gas 

system to ensure less than 

0.1 grains of H2S per dscf 

of fuel gas 

SCR, SNCR, Ultra-low-NOx burners, any technology 

that can reduce NOx emissions to 0.04 lbs NOx / 

MMBtu; install and operate SCR on crude pipestill 

heater to achieve at least a 90% control efficiency 

Sunoco Marcus Hook Elimination fuel oil 

burning 

Select a "Qualifying Control" to reduce NOx emissions 

from Refinery heaters and boilers greater than 40 

mmBTU/hr through the installation of NOx controls by 

June15, 2010 

ConocoPhillips Trainer Elimination fuel oil 

burning 

SCR or SNCR; Current Generation or Next Generation 

Ultra-Low NOx Burners; other technology that reduces 

emissions to 0.040 lbs per MMBtu or lower; or 

permanent shutdown 

Sunoco Philadelphia 

Heaters/Boilers (>40 

MMBtu/hr) 

Burning of fuel oil 

prohibited; Subject to 

NSPS 40CFR Part 60 

Subparts A and J 

Select a "Qualifying Control" to reduce NOx emissions 

from Refinery heaters and boilers greater than 40 

mmBTU/hr through the installation of NOx controls by 

June15, 2010 

Giant Yorktown Heaters 

and Boilers 

Burning of fuel oil 

prohibited; Subject to 

NSPS 40CFR Part 60 

Subparts A and J 

SCR or SNCR or Ultra-low NOx burners or other 

technologies or permanent shutdown, or use only 

during emergencies; 0.04 lb/MMBtu 

Ergon Refining Newell 

Boilers & Heaters 

Eliminate/Reduce fuel oil 

burning and restrict 

necessary fuel oil 

combustion to <0.5% S; 

Boiler A & B - Next generation ultra NOx burners 

Boiler C - 0.05 lb/MMBtu 

H-101 - 0.05 lb/MMBtu 

Vacuum Fraction Heater - Replace 4 conventional 

burners with ultra low NOx burners 
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3.4 AVAILABLE CONTROL TECHNOLOGIES 

Emissions from boilers and process heaters vary depending on the unit size, burner 

configuration, and fuels combusted. A number of control technologies exist for controlling 

emissions from these units, and options include both combustion modifications and add-on 

control equipment to target specific pollutants. Both of these control options are discussed 

below for SO2, NOx, and PM. Good combustion practice is the usual control method for CO and 

VOC emissions from boilers and process heaters, and therefore control devices for these 

emissions are not discussed in detail. 

3.4.1 SO2 Controls 

The quantity of SO2 emissions discharged from boilers and heaters located at petroleum 

refineries depends upon the sulfur content of the fuels combusted. The bulk of SO2 emissions 

from boilers and process heaters have been significantly reduced by limiting combustion units to 

burning low sulfur fuels, such as liquefied petroleum gas, natural gas, and refinery fuel gas. In 

the case of units permitted to burn coal and/or residual or distillate oils, usually the sulfur content 

of the fuel is limited, and in some cases, the annual capacity or operating hours of the boiler is 

limited. These limitations have come about from individual petroleum refinery permitting 

activities and/or from recent enforcement actions. In addition to limiting the fuels that can be 

burned, SO2 emissions can be reduced using wet, spray dry, and dry scrubbers. These types of 

scrubbers are discussed in detail in the following sections. 

3.4.1.1 Wet Scrubbers 

In wet scrubber systems, flue gas enters a spray tower, where it is impacted with aqueous slurry 

made up of limestone, lime, or other proprietary sorbent. SO2 is absorbed into slurry and falls to 

the bottom of the spray tower, where it is collected, then reacted and recycled back to the 

scrubber system or disposed of. The scrubbed flue gas is then processed by a mist-eliminator to 

remove any entrained water or slurry droplets. Wet scrubbers are capable of reducing SO2

emissions from coal and oil fired boilers between 90 and 98% depending on the sorbent used. A 

common side effect in wet scrubbers is the formation of gypsum (calcium sulfate) scale on the 

absorber due to the oxidation of the slurry sorbent. A new process called limestone forced 

oxidation (LSFO) reduces gypsum by reacting it with air, then removing the gypsum prior to 

recycling the slurry back to the absorber. Once the gypsum is removed, it can be sold 

commercially, instead of sending it to a landfill. 

3.4.1.2 Spray Dry Scrubbers 

Spray dry scrubbers are similar in design to wet scrubbers, however, they use slurry with much 

higher sorbent concentrations. Lime is typically the sorbent of choice in the slurry, and is 
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injected onto the flue gas using rotary atomizers or dual-fluid nozzles to create finer droplet 

sprays. When the flue gas interacts with the slurry solution, water is evaporated into the gas 

stream, while the SO2 is absorbed into the slurry. The process produces a dry waste product of 

slurry reacted with SO2 that is collected by conventional PM collection devices. The waste can 

be disposed of, sold as a by-product, or recycled back to the slurry. The lime spray dry scrubber 

is more sensitive to operating conditions and requires that the flue gas be within 20 to 50oF of the 

adiabatic saturation temperature in order to maximize SO2 removal, as well as prevent deposits 

of wet solids on the absorber and downstream equipment caused by excess moisture. 

Application of spray dryer scrubbers to boilers can realize SO2 removal efficiencies of 80 – 90%. 

3.4.1.3 Dry Scrubbers 

In dry scrubbers, powdered sorbent, typically consisting of calcium and sodium based alkaline 

reagents, is injected directly into the boiler or downstream ductwork. The injection location of 

the sorbent affects the ability of the sorbent to reduce SO2 emissions. When injecting the dry 

sorbent into the boiler, temperatures of 1740 to 1830oF are needed to decompose the sorbent into 

porous solids with high surface area, while when injected into down stream ductwork, 

temperatures of 300 to 350oF are necessary. Typical configurations consist of several injection 

ports in the boiler or duct walls. In some cases, water is injected further downstream to help 

increase SO2 removal. Dry scrubbers are usually followed by cyclones or ESPs to remove the 

dry waste product. These systems can achieve emission reductions of 50 – 80%, and are mostly 

applicable to small and medium sized boilers. 

3.4.2 NOx Controls 

The combustion of fuels results in two forms of NOx emissions: thermal NOx and fuel NOx. 

Thermal NOx is formed by the oxidation of nitrogen present in the combustion air, while fuel 

NOx is formed by oxidation of the nitrogen compounds in fuels such as coal and residual oils. 

Thermal NOx formation can be reduced by modifying the combustion zone through installation 

of low NOx burners, which can use air staging or fuel staging techniques to maximize NOx 

reduction. Fuel NOx can be reduced by burning fuels which don’t contain nitrogen, or through 

staging combustion air to limit the conversion of fuel nitrogen to NOx. If combustion 

modifications or fuel switching are not options for reducing NOx emissions, then post 

combustion controls such as SNCR, SCR, and flue gas recirculation can be used to reduce NOx 

already released in the flue gas. 

3.4.2.1 Low NOx Burners 

Low-NOx burners have been successfully applied to industrial boilers and process heaters and 

have achieved NOx reductions of 30% to 90%. Several low-NOx burner configurations are 

available to complement specific boilers and heaters which burn various fuels by using staged 
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air, staged fuel, and flame shape techniques. The staged air technique first introduces a small 

quantity of air with all the fuel, creating a fuel rich reducing atmosphere which generates N2

instead of fuel NOx due to the oxygen deficient conditions. Introduction of the rest of the 

combustion air down stream allows the combustion of the remaining fuel while limiting the 

formation of thermal NOx due to the presence of lower combustion temperatures. In staged-fuel 

designs, all of the combustion air is introduced in the primary combustion zone with a fraction of 

the fuel, and the remaining fuel is injected further downstream. This technique can only inhibit 

the formation of thermal NOx by combusting most of the fuel in an oxygen rich environment at 

lower temperatures. More recent low-NOx burner designs have incorporated changes to flame 

shape to accommodate various burner application, as well as further reduce NOx emissions. 

Several low-NOx burner configurations are discussed in more detail below. 

Callidus Ultra Blue Burner (CB&I, 2000) 

Callidus Technologies, Inc. has developed a new burner design applicable to gas-fired process 

heaters that will reduce NOx emissions at petroleum refineries. The Ultra Blue Burner uses 

reduced oxygen concentrations in the flame, which enables the flame to burn at a lower 

temperature without compromising burner efficiency. Testing of the burner resulted in measured 

NOx concentrations of less than 10 ppm, resulting in a 90% NOx reduction efficiency. This 

burner was scheduled to be installed at a major refinery in Houston in 2001 in response to stricter 

NOx SIPs in the Houston-Galveston area. 

Hamworthy’s Low-NOx Burners (Hamworthy) 

Hamworthy Combustion Engineering has developed the Enviromix 2000 low-NOx burner for 

process and petrochemical heaters to meet the low NOx emissions standards imposed on 

petroleum refineries. The NOx reduction is achieved through air staging using a fully adjustable 

windbox assembly with individual manual dampers to allow for alterations according to site 

conditions. The windbox design was developed using extensive flow modeling to achieve 

optimum air distribution throughout the burner, without compromising burner efficiency or 

increasing NOx formation. Hamworthy claims that the Enviromix 2000 is highly versatile with 

models available in natural and forced draft burner designs and capable of firing a wide range of 

gases and oils. 

Hamworthy has also developed a series of advance low-NOx burners, called Register Burners, to 

significantly reduce emissions of NOx and unburnt particles from boilers and process heaters 

with firing capacities between 17 and 307 MMBtu/hr. The DFL Range is a fixed geometry 

burner, which is internally staged, and operates in a low excess air environment, incorporating 

the air-staging techniques. This burner can be applied to most existing boiler designs and can 

fire liquid and gas fuels, including crude and heavy residual oils. NOx reductions of 60% are 
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achievable using this burner configuration, while reduction efficiencies up to 80% are possible 

when paired with flue gas recirculation. The DF Range is another fixed geometry burner that is 

suited for burning natural gas, liquid petroleum gas, and liquid and waste fuels at petroleum 

refineries. This burner design incorporates the techniques of low excess air, air staging, and can 

accommodate combustion air preheat. The LNOG Range is a variable configuration burner 

designed for operational flexibility, which incorporates an adjustable air-staging slide and 

rotatable gas lances to ensure burner performance meets specific site requirements. NOx 

reductions from LNOG burners are similar to reductions achieved by the DFL Range burners. 

The final burner, the M Range, is another variable geometry burner which can combust a variety 

of fuels, from gases to heavy oils, and can be used in various applications, from water tube 

boilers to hot gas generators. In this burner, the flame is controlled by curved air vanes, and fuel 

atomization is completed by pressure jets, air, or steam. 

A final set of burners, the Envirojet Series, has been developed by Hamworthy and fall under the 

category of new generation Ultra-low NOx burners, and are designed to provide the lowest 

possible emission levels. Envirojet burners were developed for industrial boilers firing oil and 

gas and have achieved NOx emissions of 45 – 160 mg/Nm3

 at 3% O2. Traditionally low NOx 

burners use flue gas recirculation (FGR) to help reduce NOx emissions, however, the Envirojet 

does not use FGR, but instead incorporates a windbox that provides air distribution that enables 

the burner’s low excess air performance. Several burner configuration options, such as flame 

direction, ignition type, and burner performance monitoring, are available to customize the 

Envirojet burner to specific boilers. 

Next Generation Ultra-low NOx Burners (John Zink Co., 2002) 

The John Zink Company has recently developed three new ultra-low NOx burner designs in 

response to Texas air quality SIPs for the Houston-Galveston area to reduce NOx emissions by 

90% at refineries and chemical plants, and to meet stricter NOx regulations in California. The 

burners were developed mainly for process heaters utilizing natural draft burners which burn 

various fuel compositions, often with high percentages of hydrogen. The first burner design, LM 

300, was developed for “round flame” applications that are capable of firing refinery and 

petrochemical fuel gas compositions. The LM 300 burner design uses three stages of fuel 

injection combined with internal furnace gas recirculation and lean “lifted” flame technology. 

Testing indicated that this burner achieves NOx emissions as low as 10 – 20 ppm depending on 

fuels burned and operating conditions. A second burner design, FPM-F is for flat flame 

applications, and utilizes part of the fuel to supply all of the combustion air through high 

efficiency venturi eductors (produces a lean premix primary flame) and the remainder of the fuel 

is injected through staged fuel injection tips. With this burner configuration, the staged fuel 

oxidizes under high temperatures with minimal oxygen presence, and therefore significantly 
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reduces both thermal and fuel NOx. Testing of this burner resulted in NOx concentrations of 9 – 

16 ppm, achieving emission reductions of around 90%. The most recent burner design 

developed is for another round flame burner, however this burner’s design is similar to the FPMF model using a lean premix primary flame with staged combustion. During initial testing, this 

burner has achieved NOx emissions of 6 – 8 ppm. 

Ultraclean, Low-Swirl Burner (Berkeley, 2003) 

Resulting from a project with the U.S. Department of Energy (DOE) and several burner 

manufacturers (Coen, CMC Engineering, John Zink, Maxon Corp, etc.), work was initiated on 

the development of a low excess air, ultra-low NOx, natural gas fired industrial burner. The goal 

of the project was to incorporate an ultra-low NOx burner that will emit less than 5 ppm NOx 

without reducing burner efficiency. One outcome of the project was the development of the 

Ultraclean Low-Swirl Combustion (UCLSC) technology developed by Berkeley Lab and in 

production by the Maxon Corporation. This combustion technology can reduce average NOx 

emissions to below 10 ppm. The Ultraclean Low-Swirl Burner (UCLSB) combusts lean, 

premixed fuels, in a detached flame configuration. Previously, the detached flame was 

considered inherently unstable, but according to research at Berkeley, the USLSB provides the 

most stable platform for a stable flame because the flame can exist in its natural state without 

interference from interactions of the flame with the burner components. Also, because the flame 

does not touch the burner, no energy is lost to the burner, therefore enabling high energy 

conversion. 

3.4.2.2 Combustion Air Modifications 

Low Excess Air 

Control systems that apply low excess air (LEA) techniques are able to optimize the amount of 

air available for combustion, while reducing fuel consumption and NOx formation. By 

decreasing the amount of oxygen available in the combustion zone, a reducing atmosphere is 

formed, which inhibits the formation of both thermal and fuel NOx. An additional benefit of this 

process is an increase in thermal efficiency because heat losses associated with pre-heating the 

excess air is eliminated, therefore allowing more heat to transfer to process fluids in process 

heaters per unit of energy input. The effectiveness of LEA systems depends on the long-term 

average maintained excess air level in the heater as well as the relationship between NOx 

emissions and oxygen in the heater. Previous testing has indicated that by reducing excess 

oxygen by 1% will result in a 6 – 9% decrease in the amount of NOx emitted from the heater. 

This technique is highly applicable to process heaters, however, it is considered impractical on 

packaged watertube and firetube boilers due to increased flame lengths and CO emissions, and 

can lead to rear wall flame impingement, especially when firing fuel oil. 
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Combustion Air Preheat 

Combustion air preheat (CAP) in process heaters increases the thermal efficiency of the heater 

upwards of 92%. However, this technique is associated with increased levels of thermal NOx 

formation due to the presence of higher temperatures. On the flip side, this technique has been 

implemented on radiant burners, and has resulted in decreased NOx emissions. 

3.4.2.3 SNCR 

SNCR has be been successfully applied to boilers and process heaters, with NOx control 

efficiencies as high as 75%. NOx emissions from SNCR are controlled by injection of ammonia 

or urea solutions in the presence of high temperatures to convert flue gas NOx to N2 and water. 

Differences between injection of ammonia urea are discussed below. 

ExxonMobil Thermal DeNOx (Ammonia Injection) 

The ExxonMobil Thermal DeNOx process has been installed on several process heaters and 

boilers since 1975. The DeNOx system uses either aqueous or anhydrous ammonia, which is 

reacted with air before passing into the firebox through a number of injection nozzles. The 

firebox temperature must be between 1600 and 2000o

F in order for the NOx conversion reaction 

to proceed. In more recent applications, hydrogen (H2) may also be added to the ammonia to 

decrease the minimum operating temperature to 1400oF. The process is highly temperature 

dependent; temperatures below 1400oF can cause release of unreacted ammonia or ammonia slip, 

while temperatures above 2000oF can cause increased NOx production. 

Because SNCRs don’t use catalysts to increase the reaction rates between the ammonia and 

NOx, sufficient time for the reactants and flue gas to interact is necessary. Reaction rates and 

NOx conversion are also controlled by the ratio of ammonia injection to NOx present in the flue 

gas. This ratio should be 1 part ammonia to 1.5 parts NOx and must be consistent with flue gas 

temperature and residence time to achieve maximum NOx reduction. If too much ammonia is 

injected, the excess ammonia can create visible ammonia plumes and corrosive ammonium 

sulfite. Injection of the Thermal DeNOx reagent can reduce NOx emissions between 30% and 

75%, with industry averages around 60%. 

Nalco Fuel Tech NOxOUT (Urea Injection) 

The urea injection based SNCR was developed in the early 1980s, and has been installed mainly 

on coal, oil, and gas fired boilers. The NOxOUT process involves direct injection of an aqueous 

urea solution using air or steam to distribute the solution throughout the firebox. Because urea is 

nonvolatile, as compared with ammonia, more energy is needed when injecting the urea solution 

to obtain adequate distribution of the reagent to maximize NOx conversion. The urea interacts 
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with the flue gas and converts NO compounds to N2, water. The balanced chemical reaction 

indicates that 2 moles of NO are converted per 1 mole of urea solution, however greater 

quantities of urea can be injected to improve NOx reduction and increase the speed of reaction 

kinetics, however, incomplete thermal decomposition of excess urea can increase emissions of 

CO and cause ammonia slip. Nalco has made modifications to the original process which 

minimizes the required minimum reaction temperature to 1200o

F by adding H2, CO, and 

antifouling and storage stabilizing agents to the urea. As with ammonia injection, reaction 

temperature and residence time are the primary factors that influences NOx reduction. NOx 

reduction efficiencies vary 10 to 75%. 

3.4.3 Selective Catalytic Reduction (SCR) 

The SCR system, as discussed in section 2.3.2, can be applied to both boilers and process 

heaters, however application to process heaters is limited. SCR reductions can provide NOx 

reductions of 90% from boilers. 

3.4.4 PM Controls 

PM emissions are not of grave concern from boilers and process heaters at petroleum refineries, 

as most of these units burn natural gas and refinery fuel gas, which do not emit significant 

amounts of fine PM as a result of combustion. However, in the MARAMA region, there are still 

boilers and process heaters permitted to burn coal and oil, which emit PM as a result of fuel 

combustion. Common control devices used to reduce PM emissions from these units include wet 

scrubbers and electrostatic precipitators (ESP). Wet scrubbers are discussed in great detail in 

section 2.4.1, while benefits of ESPs are discussed in section 1.3.1. 

3.5 COSTS AND AVAILABILITY 

Feasible control technologies for FCCUs and FCCU catalyst regenerators are summarized in 

Table 3-6. The table includes 

• Pollutant controlled 

• Name of technology 

• Origin for the level of control (rule, consent decree, permit) 

• Range of potential emission reductions from applying those controls 

• Performance level in terms of outlet concentration or emission rate 

• Cost effectiveness of the controls 

• Commercial status 

• Reference 

More detailed information on each technology was summarized in the previous sections and 

based on the information contained in the references for this Section. 
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The cost data presented in the Table were obtained from the published literature as referenced. 

In general, the percent reductions and cost effectiveness data represent data for uncontrolled 

sources. Incremental reductions will be lower and costs will be higher for sources already have 

some level of control and will be required to meet the performance levels shown in the Table. 

Also, site-specific factors greatly influence the actual achievable performance level and control 

costs at a particular facility. These considerations must be addressed in State and local 

rulemaking and permitting processes. 
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Table 3-6: Control Technology Options for Boilers and Process Heaters 

Pollutant Technology 

Origin of 

Requirement Percent 

Reduction Performance Level 

Cost 

Effectiveness 

($/ton) 

Com

Av

SO2 Fuel Switching Consent Decree >95 Eliminate the combustion of fuel oil 

(>0.05% sulfur by weight) 

 

 Fuel Processing Consent Decree or 

NSPS Subpart J 

Limit hydrogen sulfide content of refinery fuels to 0.10 gr/dscf (162 ppm) 

 

 Scrubbers 90 to 99.9 Not specified 7,674 to 45,384 NOx Not Specified San Joaquin 

Rule 4306 

n/a Gaseous Fuel: 0.0062 to 0.036 

lb/MMBtu (depending on size) Liquid Fuel: 0.052 lb/MMBtu 

 

Ultra-low NOx Burners 

Consent Decree 75 to 85 0.02 to 0.04 lb/MMBtu 750 to 1,110 

 SCR Consent Decree 70 to 90 0.04 lb/MMBtu 2,444 to 7,402 

Low-NOx Burners Plus SNCR 

 50 to 89 1,560 to 7,101 

Low-NOx Burners 

 10 to 40 786 to 4,292 

CO NESHAP 

Subpart DDDDD 

 400 ppmvd @ 3% O2
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3.6 REFERENCES 

California Environmental Protection Agency, 2004, “Air Pollution Research,” Air Resources 

Board, California. 

Chen, A., 2003, “Low-Swirl Combustion Clears the Air,” Science Beat, 

http://www.lbl.gov/Science-Articles/Archive/EETD-low-swirl-combustion.html

Chicago Bridge & Iron Company (CB&I), 2000, “Callidus Technologies to Introduce Ultra-Low 

Emissions Burner, Plainfield, Illinois. 

Eastern Research Group, Inc., 2000, “Petroleum Refinery Tier 2 BACT Analysis Report: Final 

Report,” EPA (2223-A) Manufacturing Branch, Morrisville, North Carolina. 

European Commission, Integrated Pollution Prevention & Control, 2003, “Reference Document 

on Best Available Techniques for Mineral Oil and Gas Refineries.” 

Friedman, M., 2006, Email to E.J. Sabo (MACTEC Federal Programs, Inc.), January 23, New 

Jersey Department of Environmental Protection, Trenton, New Jersey. 

Hamworthy Combustion, “Envirojet Series: Ultra-Low NOx Burners,” Proven Combustion 

Solutions. 

Hamworthy Combustion, “Enviromix 2000: Low NOx Burners for Process & Petrochemical 

Heaters,” Proven Combustion Solutions. 

Hamworthy Combustion, “Register Burners: Advanced Low NOx Burners,” Proven Combustion 

Solutions. 

MACTEC Engineering and Consulting, Inc., 2005, “Petroleum Refinery Best Available Retrofit 

Technology (BART) Engineering Analysis”, 

http://www.ladco.org/Regional_Air_Quality.html 

Northeast States for Coordinated Air Use Management, 2000, “Status Report on NOx Controls 

for Gas Turbines, Cement Kilns, Industrial Boilers, Internal Combustion Engines: 

Technologies & Cost Effectiveness,” Boston, Massachusetts. 

Seebold, J.G., R.T. Waibel, and T.L. Webster, 2001, “Control Refinery NOx Emissions CostEffectively: Refiner uses new ultra low-NOx burner technology to control emission 

levels from major sources,” Hydrocarbon Processing, November, pp. 55-59. 

United States Department of Energy, 2003, “Ultra-Low NOx Burners with Flue Gas 

Recirculation and Partial Reformer,” Office of Energy Efficiency and Renewable Energy, 

Industrial Technologies Program, Washington, DC. 
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United States Environmental Protection Agency, 2003, “Air Pollution Control Technology Fact 

Sheet: Flue Gas Desulfurization (FGD) – Wet, Spray Dry, and Dry Scrubbers,” EPA452/F-03-034, http://www.epa.gov/ttn/catc/dir1/ffdg.pdf. 

United States Environmental Protection Agency, 1994, “Alternative Control Techniques 

Document – NOx Emissions from Industrial/Commercial/Institutional (ICI) Boilers,” 

EPA-453/R-94-022, Office of Air & Radiation, Research Triangle Park, North Carolina. 

United States Environmental Protection Agency, 1998, “Alternative Control Techniques 

Document – NOx Emissions from Process Heaters (Revised),” EPA-453/R-93-034, 

Office of Air & Radiation, Research Triangle Park, North Carolina. 

Waibel, R.T., R.R. Hayes, R. Poe, and M. Zimola, 2002, “Next Generation Ultra-low NOx 

Burners for Refinery and Petrochemical Process Heaters,” John Zink Company, Tulsa, 

Oklahoma. 
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4.0 FLARES 

Petroleum refinery flares are used to safely dispose of flammable waste gases from emergency 

process upsets as well as during start-up, shut-down and turnaround operations. The combustion 

of these gases can emit large quantities of NOx, SO2, and CO into the atmosphere. There is 

some uncertainty regarding the magnitude of emissions from flaring activities, as many refineries 

do not have formal flare monitoring and emissions recording procedures in-place. Based on data 

collected in California and Texas, there is a concern about the potential underestimation of 

reported emissions released during flaring events. There are opportunities to better quantify 

emissions from flaring events, as well as reducing emissions by safely limiting flare use or by 

installing a flare gas recovery unit. This Section presents a preliminary assessment of available 

control technology options for flaring activities for states to consider as they undertake efforts to 

develop rules and State Implementation Plans (SIPs) for ozone, PM2.5, and regional haze. 

4.1 PROCESS DESCRIPTION 

Flares at petroleum refineries are intended to be last-resort control devices for the destruction of 

vent gases released under emergency conditions or during process start-ups, shut-downs, and 

turnarounds. Elevated flares are the most common type of flare used, as they can handle larger 

capacities than ground flares. In elevated flares, the waste gas stream is combusted at the tip of 

the flare stack, usually between 33 and 330 feet above the ground. The elevated flare system 

consists of five components: a gas collection header to collect gases from various process units, a 

knockout drum to remove entrained liquids and condensables from the vapor stream, a 

proprietary seal, water seal, or purge gas supply to prevent flash back, a single or multiple-burner 

unit in the flare stack, and gas pilots and igniter. 

Figure 4-1 presents a schematic of a typical flare and the location of each of these components. 

In most cases, steam or blowing air is injected into the flare to create a smokeless flare. Without 

adequate steam, the presence of smoke is more likely. The presence of smoke usually arises 

from the combustion of heavy hydrocarbons, such as paraffins, olefins, and aromatics. Waste 

gases combusted at petroleum refineries usually consist of low molecular weight hydrocarbons, 

which burn without smoke, therefore not requiring steam injection. Flares normally dispose of 

low-volume continuous emissions but are designed to handle large quantities of waste gases that 

may be intermittently generated during plant emergencies. Flare gas volumes can vary from a 

few cubic meters per hour during regular operations up to several thousand cubic meters per hour 

during major upsets.
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Figure 4-1. Diagram of a Typical Steam-Assisted Elevated Flare 

SOURCE: United States Environmental Protection Agency, 1995, “Industrial Flares,” Pages 13.5-1 – 13.5-5 in AP-42, Fifth 

Edition: Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources, 

http://www.epa.gov/ttn/chief/ap42/ch13/final/c13s05.pdf.

 

4.2 EMISSION INVENTORY 

Emissions from flaring include carbon particles (soot), unburned hydrocarbons, CO, and other 

partially burned and altered hydrocarbons. Also emitted are NOx and, if sulfur-containing 

material such as hydrogen sulfide or mercaptans is flared, sulfur dioxide. The quantities of 

hydrocarbon emissions generated relate to the degree of combustion. The degree of combustion 

depends largely on the rate and extent of fuel-air mixing and on the flame temperatures achieved 

and maintained. Properly operated flares achieve at least 98 percent combustion efficiency in the 

flare plume, meaning that hydrocarbon and CO emissions amount to less than 2 percent of 

hydrocarbons in the gas stream.

Table 3-1 identifies the flaring units in the MARAMA region and criteria pollutant emissions for 

each unit for three years. The 2002 annual emissions serve as the baseline for future SIP 
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development. The 2002 emissions were obtained from the 2002 inventories developed by 

MANEVU and VISTAS. The 2003 emissions were obtained directly from each state and 

represent the most currently quality assured data that is available. 

The 2009 emissions were obtained from the MANEVU and VISTAS projection inventories that 

were developed to support modeling for SIP development. The 2009 inventories include the 

effects of anticipated growth as well as any planned controls that will result in emission 

reductions between 2002 and 2009 due to new regulations or enforcement settlements. The 

growth factors used for projecting emissions from 2002 to 2009 came from the U.S. 

Environmental Protection Agency’s Economic Growth Analysis System (EGAS 5.0) and the 

U.S. Department of Energy’s Annual Energy Outlook (2005) projections. The controls factors 

for 2009 were derived either from data supplied that the State/local agencies or from MACTEC’s 

analysis of the requirements contained in the global enforcement settlements. 

There is considerable uncertainty regarding the emissions from flaring activities, due to several 

factors. First, since flares are primarily designed to handle waste gases from process upsets, 

there is year-to-year and refinery-to-refinery variability in the number and duration of upsets. 

Another factor source of variability may be caused by the data available and methods used to 

estimate emissions. Accurate information on the amount and composition of the waste gas sent 

to the flare is necessary to accurately estimate emissions. Most refineries monitor the pilot gas 

flow rate, while the methods used to determine waste gas flow rates and composition vary 

widely. Finally, while properly operated flares achieve at least 98 percent combustion efficiency 

in the flare plume, there is some evidence that the actual efficiency may be less in practice. 
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Table 4-1: Emission Inventory for Flares 

 Refinery/ Annual Emission (tons/year) 

State Unit Year CO NOx PM10 PM2.5 SO2 VOC 

DE Valero Delaware City 2002 18.9 2.6 0.0 0.0 0.0 0.3 

 EUID = 080 2003 19.2 2.7 0.0 0.0 0.0 0.3 

 Flare System 2009 18.9 2.6 0.0 0.0 0.0 0.3 

DE Valero Delaware City 2002 112.4 2.1 0.0 0.0 222.5 0.6 

 EUID = 530 2003 40.7 1.0 0.0 0.0 282.6 0.0 

 Repower - Raw Gas Flare 2009 112.4 2.1 0.0 0.0 222.5 0.67 

DE Valero Delaware City 2002 798.3 20.2 0.0 0.0 15.5 13.4 

 EUID = 532 2003 501.8 12.7 0.0 0.0 26.9 0.0 

 Repower - Clean Gas Flare 2009 798.3 20.2 0.0 0.0 15.5 13.4 

DE SUNCO Inc Delaware 2002 15.5 62.0 1.3 1.3 765.2 1.2 

 EUID = 005 2003 19.0 76.0 0.0 0.0 74.8 1.5 

 Pipeline Flare 2009 16.5 66.2 1.4 1.3 817.2 0.5 

NJ Sunoco Eagle Point 2002 81.2 78.4 57.4 43.0 21.0 484.4 

 EUID = U52 2003 49.9 48.9 33.9 33.9 12.6 294.2 

 Refinery Plant Flare 2009 81.2 78.4 57.4 43.0 21.0 484.4 

NJ Valero Paulsboro 2002 2.3 8.5 0.7 0.5 5.6 0.1 

 EUID = U21 2003 2.4 1.0 0.7 0.7 5.9 0.1 

 South Plant Existing Flare 2009 2.3 8.5 0.7 0.5 5.6 0.1 

NJ Valero Paulsboro 2002 6.0 22.6 1.7 1.2 14.9 0.2 

 EUID = U22 2003 6.3 23.8 1.8 1.8 15.7 0.2 

 South Plant New Flare 2009 6.0 22.6 1.7 1.2 14.9 0.2 

NJ Valero Paulsboro 2002 2.5 9.3 0.7 0.5 61.3 0.1 

 EUID = U25 2003 2.6 9.8 0.7 0.7 64.6 0.1 

 North Plant Flare 2009 2.5 9.3 0.7 0.5 61.3 0.1 

NJ Citgo Asphalt 2002 4.8 0.7 0.2 0.1 0.0 0.1 

 EUID = U14 2003 3.8 0.7 0.1 0.1 0.0 0.1 

 Area 14 Emergency Flare 2009 4.8 0.7 0.2 0.1 0.0 0.1 

NJ Amerada Hess Port Reading 2002 11.1 2.1 0.2 0.2 1.3 4.2 

 EUID = U9 2003 13.9 2.6 0.4 0.4 3.2 5.2 

 Refinery Flare 2009 11.1 2.1 0.2 0.2 1.3 4.2 

NJ Chevron Products 2002 1.8 0.3 0.1 0.0 7.2 0.7 

 EUID = U7 2003 0.1 0.1 0.0 0.0 1.0 0.0 

 Area G Flares 2009 1.8 0.3 0.1 0.0 8.2 0.7 

NJ ConocoPhillips Bayway 2002 66.7 12.4 12.0 0.8 222.0 25.3 

 EUID = U9 2003 75.3 13.8 1.5 1.2 252.7 28.5 

 Flares 2009 66.7 12.4 12.0 0.8 10.8 2.5 
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Table 4-1: (continued) 

 Refinery/ Annual Emission (tons/year) 

State Unit Year CO NOx PM10 PM2.5 SO2 VOC 

PA Sunoco Marcus Hook 2002 4.3 0.9 1.4 1.4 5.3 1.6 

 EUID = 104 2003 5.3 0.5 1.7 1.7 6.2 0.3 

 12 Plant Flare 2009 4.3 0.9 1.4 1.4 5.3 1.6 

PA Sunoco Marcus Hook 2002 3.0 1.0 1.0 1.0 4.7 2.0 

 EUID = 105 2003 0.2 0.2 0.1 0.1 0.6 0.1 

 10 Plant Flare 2009 3.0 1.0 1.0 1.0 4.7 2.0 

PA ConocoPhillips Trainer 2002 237.1 43.6 0.1 0.1 15.1 89.7 

 EUID = 103 2003 210.0 38.6 0.1 0.1 10.5 79.5 

 Main Flare 2009 237.1 43.6 0.1 0.1 15.1 89.7 

PA American Refining Bradford 2002 3.3 14.6 2.3 0.0 20.7 1.2 

 EUID = 201 2003 3.3 14.6 2.3 0.0 20.7 1.2 

 Refinery Gas Flare 2009 3.3 14.6 2.3 0.0 20.7 1.2 

PA Sunoco Philadelphia 2002 46.6 8.6 0.0 0.0 6.4 17.6 

 EUID = 010, 014, 016 2003 54.0 9.9 0.0 0.0 4.4 20.5 

 GP Flares 433, 1231, 1232 2009 46.6 8.6 0.0 0.0 6.4 17.6 

PA Sunoco Philadelphia 2002 10.5 2.0 0.0 0.0 26.2 17.7 

EUID = 523, 590, 591, 592, 

600 2003 6.3 1.2 0.0 0.0 11.6 1.6 

PB Flares North, DEA, SWS, 

LPG 2009 10.5 2.0 0.0 0.0 26.2 17.7 

PA United Refining 2002 42.9 12.5 0.2 0.2 0.5 11.6 

 EUID = 102 2003 46.6 14.1 0.2 0.2 0.6 13.0 

 Blowdown System 2009 42.9 12.5 0.2 0.2 0.5 11.6 

VA Giant Yorktown 2002 0.0 1,042.7 340.7 327.0 984.3 49.5 

 EUID = 26 2003 0.0 77.8 364.0 364.0 425.9 61.2 

 Flare 2009 0.0 24.0 177.0 177.0 2.0 50.0 

WV Ergon West Virginia 2002 14.4 59.6 0.1 0.1 84.6 0.3 

 EUID = 014 2003 14.5 57.3 0.1 0.1 81.3 0.4 

 Plant Flares 2009 14.4 59.6 0.1 0.1 84.6 0.3 

 MARAMA Totals 2002 1,483 1,406 420 377 2,484 729 

 2003 1,075 408 408 405 1,302 510 

 2009 1,485 392.2 257 227 1,336 699 

Note 1: Flaring emissions in 2009 were originally projected using AEO2005 growth factors. These factors tended to 

overestimate the expected growth in emissions, so 2009 emission were calculated assuming no growth in flaring 

activity. MARAMA states are reviewing the latest guidance from EPA with respect to projecting emissions from 

nonEGU sources such as flares. 

Note 2: Emissions from Giant Yorktown includes flaring emissions from sour water stripper gas flaring and vacuum 

tower vent gas flaring that have been eliminated as a result of the refinery’s consent decree. The emissions also 

include process upset emissions from the SRU that will be corrected with the installation of a new SRU and sour 

water stripping system. Thus, emissions in 2009 will be substantially less than in 2002/2003. 
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4.3 EXISTING REQUIREMENTS 

This section discusses the regulatory requirements which apply to flares. Four types of 

requirements are discussed: (1) Federal requirements such as the New Source Performance 

Standards (NSPS) and Maximum Achievable Control Technology (MACT) standards; (2) State 

regulations for both the MARAMA states as well as other State agencies; (3) source-specific 

permit requirements; and (4) new requirements from recent enforcement settlements. 

4.3.1 Federal Requirements 

The U.S. EPA has promulgated standards for SO2 emissions, in addition to establishing 

requirements for performance testing and compliance assessments, for flares at petroleum 

refineries. 

New Source Performance Standards (NSPS) for refinery flares constructed or modified after 

June 11, 1973 are covered under 40 CFR Part 60, Subparts A and J. Subpart A applies to flares 

as general control devices, specifying design and operational criteria for new and modified 

flares. Requirements include operating the flare with no visible emission, monitoring the 

presence of the pilot flame with a thermocouple or equivalent device, and meeting heat content 

and maximum tip exit velocity specifications. Subpart J applies to flares at petroleum refineries, 

where flares are defined as fuel gas combustion devices, and are limited to burning fuel gas, for 

the maintenance of the pilot flame, containing hydrogen sulfide (H2S) in excess of 0.10 gr/dscf. 

This limitation does not apply during process upsets, relief valve leakage, or other emergency 

malfunctions, where vent gases or fuel gas are released to the flare. This subpart also requires 

that a continuous monitoring and recording device be installed to track emissions of SO2 or H2S 

from the flare, in addition to the installation of an oxygen monitor for correcting the emissions 

data for excess air. 

The National Emission Standards for Hazardous Air Pollutants (NESHAP) for flares are covered 

in 40 CFR Part 63, Subpart SS, which applies to closed vent systems, control devices, recovery 

devices and routing to a fuel gas system or process. Under the flare requirements of this subpart, 

flares are subject to compliance assessment and monitoring requirements. Compliance 

assessments include using EPA’s Method 22 to determine measure opacity, using Equation 1 (of 

40 CFR Part 63, Subpart SS) to determine the neat heating value of the gas being combusted, 

using EPA Method 2, 2A, 2C, 2D, 2F, or 2 G of 40 CFR Part 60 Appendix A to measure the 

volumetric flow rate, and using flame or pilot monitors during compliance assessments. Flare 

monitoring requirements indicate that a device (e.g. thermocouple, ultra-violet beam sensor, or 

infrared sensor) to detect the presence of the flare flame must be used at all times when the flare 

is in use. 
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4.3.2 State Regulations 

In general, the state regulations in the MARAMA region do not specifically limit emissions or 

specifying monitoring requirements for flares at petroleum refineries. In some cases, such as the 

Bayway refinery in New Jersey, have requirements in their Title V permit to install flow 

monitoring equipment on each of the flares. Texas, the Bay Area (BAAQMD), South Coast 

(SCAQMD), and San Joaquin Valley (SJVQPCD) all have requirements governing the operation 

and emissions from flares. The Texas regulations are not as strict as those in California that lay 

out monitoring, testing, recordkeeping, and reporting requirements for flares at petroleum 

refineries, in addition to prohibiting flaring unless the situation is allowed according to the 

facility’s flare minimization plan. Per the California regulations, each facility is required to have 

a flare minimization plan/monitoring and recording plan, which stipulates conditions for use of 

the flare, and what information must be reported after flaring events. Recent amendments to the 

BAAQMD and SCAQMD regulations are discussed further in section 4.4.2. 

4.3.3 Requirements from Recent Enforcement Settlements 

The EPA and state/local agencies recently undertook an initiative to investigate compliance with 

applicable Federal and State requirements for flaring. There have being several instances 

identified where refineries used flares for routine purposes instead of only to vent dangerous 

gases, as well as other problems with NSPS compliance. Consent Decrees have been developed 

to require facilities to: (1) meet new source standards at all flares (e.g. monitor all routinely 

generated refinery fuel gases that are combusted in a flare) and comply with applicable NSPS 

emission limits; (2) take action to reduce emissions from process upsets; and (3) implement a 

protocol to diagnose and prevent upsets that result in significant releases of SO2 and other gases 

(flaring). Table 4-2 provides a list of recent enforcement settlements for flares at petroleum 

refineries in the MARAMA region. 
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Table 4-2: Summary of Recent Enforcement Settlements 

State 

Refinery 

Unit Required Control Technology 

Required Emission 

Limitation 

DE Valero 

Flares & Flaring 

Meet "new source standards at all flares (e.g. monitor 

all routinely generated refinery fuel gases that are 

combusted in a flare) and comply with applicable 

NSPS emission limits. Take action to reduce 

emissions from process upsets. Reroute and eliminate 

sulfur pit emissions. Implement protocol to diagnose 

and prevent upsets that result in significant releases of 

SO2 and other gases (flaring). 

None Specified 

NJ Sunoco Eagle Point 

Flares & Flaring 

Action to Reduce Emissions from Process Upsets, 

Reroute/Eliminate Sulfur Pit Emissions, & Prevent 

Upsets That Result in Flaring 

Comply with NSPS 

Emission Limit 

NJ Valero Refining 

Flares & Flaring 

Action to Reduce Emissions from Process Upsets, 

Reroute / Eliminate Sulfur Pit Emissions, & Prevent 

Upsets That Result in Flaring 

Comply with NSPS 

Emission Limit 

NJ ConocoPhillips Bayway 

Flares & Flaring 

Action to Reduce Emissions from Process Upsets, 

Reroute / Eliminate Sulfur Pit Emissions, & Prevent 

Upsets That Result in Flaring 

Comply with NSPS 

Emission Limit 

PA Sunoco Marcus Hook 

Flares & Flaring 

Action to Reduce Emissions from Process Upsets, 

Reroute / Eliminate Sulfur Pit Emissions, & Prevent 

Upsets That Result in Flaring 

Comply with NSPS 

Emission Limit 

PA ConocoPhillips Trainer 

Flares & Flaring 

Action to Reduce Emissions from Process Upsets, 

Reroute / Eliminate Sulfur Pit Emissions, & Prevent 

Upsets That Result in Flaring 

Comply with NSPS 

Emission Limit 

PA Sunoco Philadelphia 

Flares & Flaring 

Action to Reduce Emissions from Process Upsets, 

Reroute / Eliminate Sulfur Pit Emissions, & Prevent 

Upsets That Result in Flaring 

Comply with NSPS 

Emission Limit 

VA Giant Yorktown 

Flares & Flaring 

None Specified None Specified 

WV Ergon Refining Newell 

F1-1 Flare & Sour Gas Flare 

40 CFR Part 60 Subparts A & J None Specified 

4.4 AVAILABLE CONTROL OPTIONS 

Under normal operating conditions, flares burn a small amount of gaseous fuel to keep the pilot 

flame lit in the event of an emergency waste gas release. Normal operations also include 

continuously burning sweep gas, which has a considerably greater flow rate than the pilot gas. 

Pressure relief valves, compressor seals, and analyzer purge lines also vent (either continuously 

or intermittently) to the flare. Emissions from flaring can include PM, CO, NOx, and SO2 if 

sulfur containing vent gases are flared. Emissions from flaring events are released due to 

oxidation of vent gases and incomplete combustion of fuel. Since emissions from flares are 

unpredictable, the BAAQMD and SCAQMD amended previous regulations to include increased 
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monitoring and reporting of process streams vented to flares in their Districts. A summary of the 

Texas flare rules are also provided for comparison to the California regulations to provide 

additional state control options. Add on control equipment is not practical for flares because gas 

combustion takes place in open air at the flare tip. In addition, most control devices are effective 

for steady state operations, a condition not found with the use of flares. Pollution control 

strategies for flares involve the installation of new equipment and/or physical changes to the flare 

system, such as adding flare gas recovery compressor systems, increasing gas storage capacity, 

and improving existing gas compressors and flare tip design. 

4.4.1 Flare Gas Recovery Units 

Flare gas recovery units reduce emissions from flares by recycling the gases vented during 

emergency releases instead of combusting them in flare. The vent gases are collected in the flare 

header, compressed, cooled, and returned for re-use in the refinery as fuel gas or process 

feedstock. The flare gas recovery system also has a safety feature built in that allows excess vent 

gas to be combusted in the flare in the event that the compressor system is at full capacity, but 

excess emissions are being vented. This incorporates the original safety features of the flare, 

limiting harmful gases that could be emitted into the atmosphere by combustion; however, the 

amount of emissions released due to flaring will be considerably reduced. Figure 3-2 shows the 

process diagram of a flare gas recovery system. 

Figure 4-2. Process Flow Diagram of a Flare Gas Recovery Unit 

SOURCE: http://www.johnzink.com/products/fgr/html/fgr_jz_procdiag.htm
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4.4.2 California Regulations 

In addition to implementation of control strategies at petroleum refineries, the BAAQMD and 

SCAQMD have recently updated their regulations to increase emission reductions from flares at 

petroleum refineries in California. 

4.4.2.1 BAAQMD 

On June 4, 2003, BAAQMD issued Rule 11 (part of Regulation 12: Miscellaneous Standards of 

Performance), which required monitoring and recording of emissions data for flares at petroleum 

refineries. This rule allowed the District to collect emissions data from refineries over the past 

two years to determine causes of specific flaring events, as well as estimate the quantity of 

emissions released during those events. The newest rule, Rule 12, was published on July 20, 

2005 and will become effective November 1, 2006 in response to the District’s findings under 

Rule 11. Rule 12 was created to reduce emissions from flares by minimizing the frequency and 

magnitude of flaring. The rule only allows flaring during emergency conditions and prohibits 

the use of refinery flares without the refinery first creating, following, and annually updating a 

Flare Minimization Plan (FMP) for each flare. It requires the submission of flaring reports when 

a flare releases more than 500,000 standard cubic feet of gas per calendar day (scf/day) and to 

identify the cause and to avoid flaring from that cause in the future, if possible. Also, the rule 

requires annual reports to the District evaluating flaring events that released less than 500,000 

scf/day, where the amount of SO2 emitted is more than 500 lbs. A final provision of this rule 

calls for continuous monitoring of the flare system’s knock-out drum water seal for leaks. The 

knock-out drum is essential to reduce flaring at refineries, as this seal keeps liquid from entering 

the flare stack, provides a barrier between the flare gas header and flare stack preventing air from 

interacting with the vent gases and causing a potentially explosive environment, and provides 

backpressure on the flare gas header for operation of the flare gas recovery compressor. 

4.4.2.2 SCAQMD 

The SCAQMD has recently published (on November 4, 2005) its proposed amendments to Rule 

1118, Emissions from Refinery Flares, that first adopted on February 13, 1998. Rule 1118 was 

originally promulgated to develop an accurate flare emission inventory and assess the need for 

requiring additional controls to minimize flare emissions. The emissions data collected between 

1999 and 2003 as a result of this rule was analyzed by staff that made recommendations for 

further strengthening emissions data gathering, monitoring, and reporting procedures. The 

proposed amendments will be implemented starting January 2006 and be fully implemented by 

January 2012. The new amendments prohibit flaring of vent gases except in emergency 

situations, or during specific operational needs such as startups, shutdowns, and turnarounds. 

The new rule also establishes operational requirements and practices to minimize flaring events, 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

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sets specific annual SO2 performance targets, requires that flares operate in a smokeless manner, 

and requires annual inspections of pressure relief devices directly connected to flares. New 

monitoring requirements call for the installation of analyzers to measure vent gas higher heating 

values, total sulfur concentration, and gas flow. The rule also contains provisions for refineries 

to give 24-hour advance notice for each large planned flaring activity, and to notify SCAQMD 

within 1-hour of unexpected flaring events, in addition to submitting quarterly reports detailing 

flow, emissions, and cause of each event. Refineries are also required to set up a 24-hour public 

telephone number for inquiries on flaring events. 

4.4.3 Texas Regulations 

The Texas Commission on Environmental Quality (TCEQ) has two air quality rules that pertain 

to the control of air emissions through flares. The first rule, found in Chapter 115, Subchapter D, 

Division 1, concerns the use of flares during process unit turnaround and on vacuum-producing 

systems at petroleum refineries. The rule requires that all vent gas streams controlled with a 

flare located in Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston 

areas, including Gregg, Nueces, and Victoria counties achieve 90% control efficiency or limit 

VOCs emitted to 20 ppmvd @ 3% O2 with a smokeless flare. 

The second TCEQ rule, Chapter 115, Subchapter H, Division 1, pertains to flares with the 

potential to emit highly-reactive VOCs (HRVOC) in the Houston/Galveston/Brazoria area. Each 

site located in this area is subject to a facility limit of 1,200 lbs HRVOC per 1-hr block period 

from any flare, vent, pressure relief valve, cooling tower, or any combination. This rule also 

outlines several monitoring specifications explicitly for flares. Each facility must install, 

calibrate, maintain, and operate a continuous flow monitoring system to measure the flow rate of 

gas to the flare and an on-line analyzer system capable of measuring the concentration of 

HRVOCs in addition to hydrogen, nitrogen, methane, carbon dioxide, and VOCs at least once 

every 15 minutes. Each monitoring system must operate at least 95% of the time the flare is 

operational, and if the continuous on-line analyzer is non-operational in excess of 8-hours, daily 

samples of vent gas sent to the flare must be taken and analyzed to determine all constituents. 

The average net heating value of combusted gas and the average actual exit velocity must be 

calculated for each 1-hr block and used in conjunction with the information collected by 

continuous monitors to calculate the hourly average HRVOC emission rate from the flare, 

assuming 99% control efficiency for ethylene and propylene, 98% control efficiency for all other 

HRVOCs, and 93% control efficiency when the calculated net heating value or exit velocity of 

the vent gas does not meet the limitations set forth by NSPS Subpart A. In addition, facilities 

must develop and implement a Quality Assurance Plan (QAP) and a Written Test Plan for the 

above monitoring requirements, in addition to maintaining records of all testing and monitored 

parameters. 
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4.5 COSTS AND AVAILABILITY 

4.5.1 Flare Gas Recovery Unit 

Based on cost estimates by SCAQMD and a plant-wide case study at the Houston Valero 

refinery, capital costs for flare gas recovery systems should range between $1.0 and $5.1 million, 

depending on needed system capacity. Even with the high capital investment, significant energy 

savings are realized from recycling vented gases for use as fuel or process feedstock. At the 

Houston refinery, the predicted fuel savings from the installation of a flare gas recovery unit 

amounts to about 130,000 MMBtu/yr heat input at a cost savings of $420,000/yr. At this rate, 

the flare gas recovery system pays for itself in two and a half years. The Shell Refinery in 

Martinez, California also installed a flare gas recovery system as part of an overall package of 

refinery improvements and expects a 2 year return on the recovery system. The typical payback 

period for flare gas recovery installations at other petroleum refineries is two to four years. 

Recently another flare gas recovery unit was installed at a refinery in Arkansas, which has 

resulted in reduced flaring and near-zero emission levels. No cost information was available for 

this installation. 

4.5.2 Compliance with SCAQMD Rule 1118 

The proposed amendments to Rule 1118 are expected to achieve emission reductions of 1.18 

tons/day of SO2 and 1.44 tons/day in total criteria pollutants (except CO) by December 31, 2012. 

According to estimates by SCAQMD staff, the cost effectiveness of the proposed amendments 

range from $5,524 to $8,620 per ton of SO2 reduced and from $4,527 to $7,063 per ton SO2, 

NOx, VOC, and PM10 reduced. These overall cost estimates include installation of flare gas 

recovery and treatment systems, installation of all required analyzers and flow meters, and the 

cost of man hours to produce annual surveys of all pressure relief devices and flaring events. 

Detailed cost analysis for these items can be found in Table 4-3. 

4.5.3 Compliance with BAAQMD Rule 12 

Estimated costs for implementing each requirement of Rule 12 at refineries in the Bay Area are 

summarized in Table 4-4. These estimates are conservative, as a few of the refineries have 

already installed control equipment to reduce flaring and many of the benefits of this rule have 

already been achieved, and therefore the associated costs have already been incurred by the 

refineries in the Bay Area. The BAAQMD staff determined the extremes of the expected costs, 

taking into account that some facilities had already taken steps to reduce flaring, while others 

have not made any changes to their systems. Overall cost effectiveness for implementation of 

Rule 12 is $818 - $1,298 on the low end, and $1,527 - $1,603 on the high end per ton of all 

pollutants reduced. 
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Table 4-4: Estimated Costs for Compliance with SCAQMD Rule 1118 

Rule Requirement Estimated Cost Notes 

Install Flare Gas Recovery 

& Treatment Systems 

Capital: $20,400,000 

O & M: $2,000,000 

Permit Fees: $28,932 

Annual Operating Fee: $2,950 

Total cost for four separate 

units to be installed by 

January 1, 2009 

Install Higher Heating 

Value (HHV) and Total 

Sulfur (TS) Analyzers 

Capital: HHV - $71,000, TS - $79,000 

O&M: HHV - $15,000, TS - $7,900 

Installation Cost (total): $79,000 

One-Time CEMS Certification: $7,693 

Assumed that 22 HHV and 

22 TS analyzers are needed 

to be installed at refinery 

flares; Costs presented are 

per flare. 

Install Vent Gas Flow 

Meter 

Capital: $10,000 

Accuracy Verification: $10,500/yr 

Install 2 Purge/Pilot Gas 

Meters 

Capital: $2,280 

O&M: $126.50 

Installation: $350 

Install Automated Sampler Capital: $4,500 

Installation: $500 

Assumed that 46 such 

meters and analyzers are 

needed to be installed by 

January 1, 2007 at refinery 

flares 

Annual Survey of Pressure 

Relief Devices $68,000 

Over all refineries, assumed 

1,360 hours total at $50 per 

person hour, to be in effect 

the beginning of 2006. 

Annual Flare Event Special 

Cause Analysis 

$800,000/yr 

Over all refineries, assumed 

200 investigations at 80 

hours per investigation and 

$50 per person hour, to be 

in effect the beginning of 

2006. 

Overall Cost Effectiveness: the cost effectiveness of the proposed amendments range from $5,524 to 

$8,620 per ton of SO2 reduced and from $4,527 to $7,063 per ton SO2, NOx, VOC, and PM10 reduced. 

SOURCE: Teszler, E., October 2005, “Final Staff Report for Proposed Rule 1118 – Control of Emissions from Refinery 

Flares,” South Coast Air Quality Management District, Diamond, California. 
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Table 4-3: Estimated Costs for Compliance with BAAQMD Rule 12 

Rule Requirement Estimated Cost Notes 

Development of a Flare Minimization 

Plan $100,000 Estimate for medium sized refinery 

Implementation of FMP 

Low End: 

High End: 

$120,000/yr 

$1,900,000/yr 

Low: facility only needs to perform 

minor modifications 

High: facility needs to install all flare 

gas recovery controls ($20,000,000 

project amortized over 20 years at 7%) 

Flaring Notification to the District 

(High End) 

$500/yr 

Assumes 67 notifications (number 

derived from monthly reporting), where 

vent gas released was greater than 

500,000 scf/day, assuming 15 minutes 

per phone call to the District at a rate of 

$30/person hour calling 

Determination & Reporting of Cause 

(High End) $40,200/yr Assuming $50 per person hour at 12 hours per event for 67 flaring events 

Annual Reports & FMP Updates $30,000/yr Less than 1/3 the cost of developing the 

FMP 

Water Seal Monitoring 

Low End: 

High End: 

$3,000/yr 

$9,000/yr 

Low: Accounts for annual maintenance 

costs 

High: Includes annual maintenance and 

partial upgrades amortized over 20 

years at 7% 

Overall Cost Effectiveness: The cost effectiveness for the high cost prevention measure would be $1,603 

per ton for the first year for all pollutants, $1,527 per ton thereafter. For the low cost prevention measure 

the cost effectiveness would be $1,298 per ton for all pollutants, and $818 per ton thereafter. 

SOURCE: Ezersky, A., 2005, “Staff Report: Proposed Regulation: Regulation 12, Miscellaneous Standards of Performance, 

Rule 12, Flares at Petroleum Refineries,” Bay Area Air Quality Management District, San Francisco, California. 

Feasible control technologies for flares are summarized in Table 4-6. The table includes 

• Pollutant controlled 

• Name of technology 

• Origin for the level of control (rule, consent decree, permit) 

• Range of potential emission reductions from applying those controls 

• Performance level in terms of outlet concentration or emission rate 

• Cost effectiveness of the controls 

• Commercial status 

• Reference 

More detailed information on each technology was summarized in the previous sections and 

based on the information contained in the references for this Section. 
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The cost data presented in the Table were obtained from the published literature as referenced. 

In general, the percent reductions and cost effectiveness data represent data for uncontrolled 

sources. Incremental reductions will be lower and costs will be higher for sources already have 

some level of control and will be required to meet the performance levels shown in the Table. 

Also, site-specific factors greatly influence the actual achievable performance level and control 

costs at a particular facility. These considerations must be addressed in State and local 

rulemaking and permitting processes. 
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Section 4 – Flares Page 4-16 MACTEC Federal Programs, Inc. 

Table 4-5: Control Technology Options for Flares 

Pollutant Technology 

Origin of 

Requirement Percent 

Reduction Performance Level 

Cost 

Effectiveness 

($/ton) 

Com

A

All Flare Gas 

Recovery Unit 

Consent 

Decree 

n/a NSPS limit on hydrogen sulfide content of 

refinery fuels to 0.10 gr/dscf (162 ppm) 

Cost Savings 

All Requirements 

contained in BAAQMD Rule 12 

BAAQMD 

Rule 12 

65 to 86 Development and implementation of flare 

minimization plan, continuous monitoring of knock-out drum water seal for leaks, determine and report the causes of each reportable flaring incident 

818 to 1,603 

All Requirements 

contained in SCAQMD Rule 1118 

SCAQMD 

Rule 1118 

53 Prohibits flaring except for emergencies, 

shutdowns and startups, turnarounds, and specific essential operational needs; establishes operational practices to minimize flaring events, sets annual SO2 performance targets, requires operation in a smokeless manner; increased inspections and monitoring 

4,527 to 8,620 
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4.6 REFERENCES 

Ezersky, A., 2005, “Staff Report: Proposed Regulation: Regulation 12, Miscellaneous Standards 

of Performance, Rule 12, Flares at Petroleum Refineries,” Bay Area Air Quality 

Management District, San Francisco, California. 

Fisher, P.W. and D. Brennan, 2002, “Minimize flaring with flare gas recovery,” Hydrocarbon 

Processing, June, pp. 83 – 85. 

John Zink Company, LLC, “Flare Gas Recovery Unit,” http://www.johnzink.com/products/fgr/ 

html/fgr_jz_procdiag.htm

Industry Professionals for Clean Air, May 23, 2005, “Reducing Emissions from Chemical Plants 

and Refineries: An Analysis of Industrial Flares’ Contribution to the Gulf Coast Region’s 

Air Pollution Problems”. 

Lawrence Berkeley National Laboratory, 2003, “Profile of the Petroleum Refining Industry in 

California: California Industries of the Future Program,” US Department of Energy 

Contract DE-AC03-76SF00098, Berkeley, California. 

Lieu, S., 2005, “Final Socioeconomic Report for Proposed Rule 1118 – Control of Emissions 

from Refinery Flares,” South Coast Air Quality Management District, Diamond, CA. 

Teszler, E., October 2005, “Final Staff Report for Proposed Rule 1118 – Control of Emissions 

from Refinery Flares,” South Coast Air Quality Management District, Diamond, CA. 

United States Department of Energy, 2005, “Valero: Houston Refinery Uses Plant-Wide 

Assessment to Develop an Energy Optimization and Management System,” Office of 

Energy Efficiency and Renewable Energy, Industrial Technologies Program, 

Washington, DC. 

United States Environmental Protection Agency, 1995, “Industrial Flares,” Pages 13.5-1 – 13.5-5 

in AP-42, Fifth Edition: Compilation of Air Pollutant Emission Factors, Volume 1: 

Stationary Point and Area Sources, 

http://www.epa.gov/ttn/chief/ap42/ch13/final/c13s05.pdf. 

Wallerstein, B.R., 2005, “Final Environmental Assessment for Proposed Amended Rule 1118 – 

Control of Emissions from Refinery Flares,” SCAQMD No. 102605MK, October 2005. 

Wallerstein, B.R., 2004, “Evaluation Report on Emissions from Flaring Operations at Refineries 

& Direct Staff to Initiate Amendment of Rule 1118,” Board Meeting: September 3, 2004, 

Agenda No. 33. 
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5.0 FUGITIVE EQUIPMENT LEAKS 

Equipment leaks contribute to plant-wide emission of fugitive VOCs at petroleum refineries. 

Equipment leaks are defined as emitters of organic hazardous air pollutants from pumps, 

compressors, pressure relief devices, sampling connection systems, open-ended or in-line valves, 

and instrumentation systems. Most petroleum refineries limit these fugitive emissions at their 

facilities by implementing leak detection and repair (LDAR) programs. Each refinery’s LDAR 

program specifies the frequency of monitoring for VOC leaks from these components, as well as 

specifying testing methods, recordkeeping, and reporting requirements. Recently, there has been 

renewed interest in developing cost effective solutions to further reduce VOC emissions from 

equipment leaks as states undertake efforts to develop rules and State Implementation Plans 

(SIPs) for ozone, PM2.5, and regional haze. 

5.1 PROCESS DESCRIPTION 

Equipment leaks normally encountered in an oil refinery include pipe flanges, threaded pipe 

connections, pump seals, compressor seals and valve packing. There are literally thousands of 

such potential leak sources in a typical oil refinery. Reasons for leaks can include normal wear 

and tear, poor quality or design of components, poor maintenance or improper choice of 

materials. Volatile hydrocarbons can then be leaked from the processing units into the ambient 

environment from any of the above mentioned sources. Leak detection and repair programs can 

reduce but not eliminate these fugitive emissions. 

5.2 EMISSION INVENTORY 

Table 5-1 identifies the fugitive VOC emission releases from refineries in the MARAMA region. 

VOC emissions for each facility are shown for three years. The 2002 annual emissions serve as 

the baseline for future SIP development. The 2002 emissions were obtained from the 2002 

inventories developed by MANEVU and VISTAS. The 2003 emissions were obtained directly 

from each state and represent the most currently quality assured data that is available. 

The 2009 emissions were obtained from the MANEVU and VISTAS projection inventories that 

were developed to support modeling for SIP development. The 2009 inventories include the 

effects of anticipated growth as well as any planned controls that will result in emission 

reductions between 2002 and 2009 due to new regulations or enforcement settlements. The 

growth factors used for projecting emissions from 2002 to 2009 came from the U.S. 

Environmental Protection Agency’s Economic Growth Analysis System (EGAS 5.0) and the 

U.S. Department of Energy’s Annual Energy Outlook (2005) projections. The controls factors 

for 2009 were derived either from data supplied that the State/local agencies or from MACTEC’s 

analysis of the requirements contained in the global enforcement settlements. 
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Table 5-1: Emission Inventory for Fugitive Equipment Leaks 

 Refinery/ Annual VOC Emissions (tons/year)

State Unit 2002 2003 2009 

DE Valero Delaware City 

 EUID = 083, 250 63.5 45.0 32.0 

DE SUNCO Inc Delaware 

 EUID = 006, 007, 026, 027 1.9 2.6 1.8 

NJ Sunoco Eagle Point 

 EUID = FG1 to FG28 41.6 63.9 21.0 

NJ Valero Paulsboro 

 EUID = FG2 to FG7 65.6 63.9 33.0 

NJ Citgo Asphalt 

 EUID = FG1 to FG4 10.0 10.0 5.0 

NJ Amerada Hess Port Reading 

 EUID = FG0 13.5 13.5 13.5 

NJ Chevron Products 

 EUID = FG0, FG1 9.5 11.5 9.5 

NJ ConocoPhillips Bayway 

 EUID = FG0 233.0a 126.0 116.5 

PA Sunoco Marcus Hook 

 EUID = 110, 114, 402 130.4 230.0 65.2 

PA ConocoPhillips Trainer 

 EUID = 108, 112, 116, 118 63.4 53.0 31.7 

PA American Refining Bradford 

 EUID = 206, 206A 129.9 129.9 129.9 

PA Sunoco Philadelphia 

 EUID = over 40 separate IDs 175.6 183.4 88.0 

PA United Refining 

 EUID = 109 167.0 176.4 167.0 

VA Giant Yorktown 

 EUID= 25, 26, 27, 30-33 310.3 203.1 155.1 

WV Ergon West Virginia 

 EUID = 017 45.4 44.3 22.7 

MARAMA Totals 1,460.6 1,356.5 891.9 

a) ConocoPhillips Bayway initially estimated a VOC emissions of 1,629 tons/year from equipment leaks using the 

"leak/no leak" method and AP-42 emission factors consistent with the federal leak definition of 10,000 ppm. 

Emissions were recalculated using actual leak data and EPA correlation equations LeakDas software, resulting in a 

downward revision to 233 tons/year. 
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5.3 EXISTING REQUIREMENTS 

This section discusses the regulatory requirements which apply to equipment leaks. Four types 

of requirements are discussed: (1) Federal requirements such as the New Source Performance 

Standards (NSPS) and Maximum Achievable Control Technology (MACT) standards; (2) State 

regulations for both the MARAMA states as well as other State agencies; (3) source-specific 

permit requirements; and (4) new requirements from recent enforcement settlements. 

5.3.1 Federal Regulations 

New Source Performance Standards (NSPS) for equipment leaks of VOCs at petroleum 

refineries are covered by 40 CFR Part 60, Subpart GGG. This subpart applies to affected 

facilities (compressors, valves, pumps, pressure relief devices, sampling connection systems, 

open-ended and in-line valves, flanges, or other connector in VOC service) at petroleum 

refineries that have undergone construction or modification since January 4, 1983. This subpart 

refers to 40 CFR Part 60, Subpart VV for all applicable monitoring, testing, recordkeeping and 

reporting standards. Subpart VV indicates that a piece of equipment is leaking when an 

instrument reading of 10,000 ppm or greater is measured using EPA Method 21 or when a visual 

inspection uncovers liquid dripping from the equipment. When leaks are detected, a first attempt 

repair should be made within 5 days after the leak is detected, and final repairs should be made 

within 15 days, unless an equipment shutdown is warranted. The subpart also lists out specific 

standards for each type of equipment (pumps, compressors, pressure relief devices, sampling 

connection systems, values, etc.) Please refer to 40 CFR Part 60, Subpart GGG for all applicable 

NSPS requirements.. 

National Emission Standards for Hazardous Air Pollutants (NESHAP) for equipment leaks from 

process equipment components in organic HAP service at petroleum refineries are found in 40 

CFR Part 63, Subpart CC, which indicates that the standards under 40 CFR Part 60 Subpart VV 

should be applied to existing sources, while the standards under 40 CFR Part 63 Subpart H 

should be applied to new sources. Subpart CC lists dates specific to petroleum refineries for 

owners/operators to demonstrate compliance specific emissions limit phases. Three phases were 

established, with the final phase taking effect on February 18, 2001, therefore the emission limit 

for leaks from new equipment should be consistent with Phase III. Just as defined in Subpart 

VV, Subpart H requires that an identification tag be affixed to leaking components upon 

detection, and stipulates that first attempt repairs to be made within 5 days after leak detection, 

while final repairs should be made within 15 days, unless an equipment shutdown is warranted. 

These subparts also identify specific standards for each type of equipment component. Please 

refer to 40 CFR Part 63, Subpart CC, 40 CFR Part 60 Subpart VV, and 40 CFR Part 63 Subpart 

H for all applicable NESHAP requirements. 
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Alternative Work Practices to Detect Leaks from Equipment were proposed by EPA on April 6, 

2006. This action proposes a voluntary alternative work practice for finding leaking equipment 

using optical gas imaging instead of monitoring using EPA Reference Method 21. Although 

optical gas imaging can potentially be useful as a method of leak detection and repair when 

operated in conjunction with Federal Reference Method 21 (“Method 21”), commenters have 

raised enforcement and technical concerns that must be addressed before promulgation. 

Revisions to the NSPS were proposed by EPA on November 7, 2006. These amendments 

increase the stringency of the leak definitions for pumps and valves. These amendments would 

increase the stringency of the leak definition for pumps in liquid service from 10,000 ppm to 

2,000 ppm and increase the stringency of the leak definition for valves in gas/vapor service or 

light liquid service from 10,000 ppm to 500 ppm. The new leak definitions would apply only to 

new sources that began construction, reconstruction, or modification after November 7, 2006. 

EPA’s analysis indicates that “even lower leak definitions would theoretically result in lower 

emissions, but available evidence to date does not support the selection of lower values”. EPA’s 

analysis indicates that lowering the leak detection definitions to 500 ppm for valves and 2,000 

ppm for pumps for petroleum refineries would have a cost effectiveness of $3,100 per ton 

removed. 

5.3.2 State Regulations 

Most states have detailed monitoring, testing, recordkeeping, and reporting requirements, with 

the exception of Virginia, which mimic the federal regulations. Please refer to the applicable 

state/local rules for applicable requirements: 

• Delaware Regulation No. 24, Section 29: Leaks from Petroleum Refinery Equipment 

• Philadelphia Regulation V, Section XIII: Process Equipment Leaks 

• Pennsylvania Section 129.58: Petroleum Refineries – Fugitive Sources 

• New Jersey 7:27-16.18: Leak Detection and Repair 

• Virginia 9 VAC 5-40-1420: Standard for Fugitive Dust/Emissions 

The regulations for other states (Louisiana, Texas) and California districts (Bay Area Air Quality 

Management District – BAAQMD, South Coast Air Quality Management District – SCAQMD, 

and San Joaquin Valley Air Pollution Control District - SJVAPCD) are generally more stringent 

(more frequent monitoring, lower leak definitions) than the MARAMA states and the federal 

government. 

5.3.3 Permit Requirements 

The permit requirements for most of the facilities follow the NSPS, NESHAP, or the state LDAR 

requirements. 
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5.3.4 Requirements from Recent Enforcement Settlements 

The EPA and state/local agencies recently undertook an initiative to investigate physical 

modifications to petroleum refineries. Capacity increases and modifications should have 

triggered NSR permitting and pollution control requirements. There have being several 

instances identified where refineries have failed to obtain pre-construction and operating permits 

for physical construction that increased their capacity and emissions. Consent Decrees require 

petroleum refineries to implement enhanced leak detection and repair systems to reduce fugitive 

VOC emissions. In general, the enforcement settles require leak detection and repair program 

enhancements, including the following: 

• Written refinery-wide LDAR program description 

• Training for any person (employee or contract employee) assigned LDAR program 

responsibilities 

• LDAR audits, including an initial compliance audit, third-party audits, and internal audits 

• Actions necessary to correct noncompliance resulting from audits 

• More stringent leak definitions for valves and pumps 

• Increased LDAR monitoring frequency 

• Electronic monitoring, storing, and reporting of LDAR data 

• QA/QC of LDAR data 

• Establish and maintain an LDAR coordinator with responsibility for LDAR management 

and authority to implement LDAR improvements 

• Establish a tracking program to ensure new valves and pumps are integrated into the 

LDAR program 

• Verification of “delay of repair” determinations 

• Calibration/calibration drift assessments 

• Chronic leaker identification and repair program 

• Recordkeeping and reporting requirements 

5.4 AVAILABLE CONTROL TECHNOLOGIES 

Fugitive VOC emissions from equipment leaks at petroleum refineries are difficult to costeffectively monitor and prevent using current LDAR methods given that emissions from these 

sources are highly random. Two new LDAR approaches have been recently introduced in an 

effort to reduce fugitive emissions from petroleum refineries. 

5.4.1 Enhanced LDAR 

Implementation of an enhanced LDAR program is required by the recent enforcement 

settlements enacted at the refineries in the MARAMA region. According to the individual 

Consent Decrees, several conditions are to be added to the current LDAR program in order to 

reduce fugitive VOC emissions from each facility. The Shell Oil Company has already enforced 

an enhanced LDAR program at its Deer Park Manufacturing Complex (TX) which has resulted 
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in a 1,200,000 pound (600 ton) reduction in toxic emissions released to the atmosphere. 

Enhanced LDAR program improvements include: 

• Training: Implement an annual training program for personnel assigned to LDAR 

responsibilities, including a separate training program for all other refinery personnel 

with instruction on relative aspects of the LDAR program, providing refresher courses on 

a 1-year or 3-year schedule. 

• LDAR Personnel: Establish a program to hold LDAR personnel accountable for LDAR 

performance at the refinery. 

• QA/QC: Develop and implement a QA/QC procedure for reviewing all monitoring data 

daily, including the number of components monitored per technician, time between 

monitoring events, and abnormal data patterns. 

• Leak Definition: The VOC leak detection limits are reduced from 10,000 ppm to 500 

ppm for valves, and 2,000 ppm for pumps. 

• Monitoring Frequency: Pumps should be monitored monthly, while valves should be 

monitored either quarterly with no ability to skip monitoring periods or according to the 

sustainable skip period program. 

• Data Collection: Requires use of dataloggers and/or electronic data collection devices to 

maintain an electronic database of LDAR monitoring results. 

• Calibration Drift Assessment: At the end of each monitoring shift, a calibration drift 

assessment should be conducted. If any drift after the initial calibration shows a negative 

drift of more than 10% from the previous calibration, then all valves with monitoring 

concentrations greater than 100 ppm and all pumps with concentrations greater than 500 

ppm should be retested. 

• Repairs: New repair regulations vary by consent decree, including regulations for “firstattempt” repairs to be made within 1-day of leak detection (Sunoco), and a 30-day limit 

to make repairs and re-monitor pumps and valves (Delaware City). The Consent Decrees 

also call for pumps and valves to be placed on a “Delay of Repair” list under proper 

documentation. Some Consent Decrees also allow refineries to monitor affected pumps 

and valves at process units after completing maintenance, startup, or shutdown activities 

without having to submit the results to the state. 

• Tracking Program: Establish a program to ensure that new valves and pumps installed 

during maintenance and construction projects are implemented into the LDAR program. 

• Recordkeeping & Reporting Requirements: Regular reports written to the state should 

include addition information on the new additions to the LDAR program (training 

program, audits, monitoring, QA/QC, etc.). 

• Audits: Requires alternating third-party and internal audits every two years. Audits 

include comparative monitoring of valves and pumps, review of records, tagging, and 

data management, and observation of LDAR technicians’ calibration and monitoring 

techniques. 
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5.4.2 Smart LDAR 

Both the current and enhanced LDAR programs require regular inspections of equipment using 

EPA Method 21 by placing a gas sampling probe at the surface of all piping component seals. 

This procedure requires extensive man hours to check every potential leaking source, and 

requires checking many sources whose fugitive emissions usually range from non-detect to 100 

ppm. According to a study conducted by the American Petroleum Institute (API), only 0.13% of 

the total sources monitored at petroleum refineries account for the largest source of fugitive 

emissions (leaks measured at concentrations greater than 10,000 ppm). The majority of the 

sources monitored indicated zero emissions when tested, while only 5% of the sources with 

initial leak concentrations greater than 1,000 ppm were found to repeatedly leak. This evidence 

suggests that more emphasis should be placed on the detection and repair of sources measured 

with high leak concentrations rather than using the EPA Method 21 to monitor all refinery 

components with the potential to develop an equipment leak. This can be accomplished using 

the second LDAR approach, called Smart LDAR, which seeks to efficiently locate and repair the 

small number of leaky components using visual imaging equipment. Several camera systems 

have been developed for this sort of task and employ detection methods such as infrared 

spectrometry, backscatter absorption, and lasers to pictorially represent major leaks from 

equipment as plumes of smoke on a portable screen. Listed below are some examples of the 

types of cameras available. 

Infrared Imaging Spectrometer (Pacific Advanced Technology, 2000) 

Pacific Advanced Technologies (PAT), under contract to the Department of Defense, developed 

a field portable infrared imagining spectrometer for defense related applications, such as 

detection of chemical weapons and missile plumes. This imaging system combines a diffractive 

optical system with state of the art image processing technology to allow real-time viewing of 

fugitive gas leaks. Recently, PAT has applied this technology to environmental monitoring for 

fugitive gas leaks, smoke stack emissions, and flares and has demonstrated this device can 

measure multiple species simultaneously, as well as handle the effects of atmospheric absorption 

and scattering. An added benefit of this instrument is its ability to identify elemental species 

present in the equipment leak without the use of an artificial illumination source. 

Backscatter Absorption Gas Imaging (Goers, Kulp, and McRae, 2000) 

The Backscatter Absorption Gas Imaging (BAGI) instrument uses an infrared laser to direct 

specific wavelengths of light towards suspected gas leaks. The gas will absorb the light and 

appear as a dark cloud on the screen of the imaging equipment. The BAGI instrument allows the 

simultaneous viewing of many potential emission points, while also being able to focus in on a 

single leaking source and estimate the leak flux more accurately than from single point 
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concentration measurements. The first field test of this equipment involved using a vehiclemounted BAGI instrument, which was found to be impractical due to the need to test areas of the 

refinery that had limited accessibility. Since the field test, work has been underway to develop a 

hand-held portable imaging device. 

Pulsed Laser Imager (US DOE, 2002) 

The Pulsed Laser Imager (PLI) developed by LaSen Inc. also uses infrared spectroscopy to 

detect and measure fugitive VOC leaks from refinery equipment. The main advantage of this 

imager is its ability to detect hydrocarbon leaks at a safe distance away (between 328 ft and 1.5 

miles), without requiring an air sample. Two versions of PLI have been developed, the Lidar 

and the NICE, and initially operate by firing an invisible pulsed laser towards a suspected leak. 

Then, the radiation is backscattered to a telescope and a sensor measures the hydrocarbon 

concentration in the Lidar imager, whereas the NICE imager converts the backscattered radiation 

into a false color image using video processing technology. 

5.5 COSTS AND AVAILABILITY 

A cost effective LDAR program should both maximize emission reductions while minimizing 

equipment and labor costs. Current LDAR programs requiring quarterly monitoring of primary 

pump seals and valves in liquid and gas service can cost between $54,000 and $1,075,000 per 

year depending on plant size and the number of required-to-monitor components. With an 80% 

VOC reduction, cost savings of $215/ton VOC abated can be achieved. Cost effectiveness of 

LDAR programs for pumps and compressors can range from $1,950 to $2,787 per ton VOC 

(ECIPPC, 2003). 

The smart LDAR option doesn’t include changing the defined leak emission limit, but instead 

changing the method of detecting leaks. Instead of using a hydrocarbon gas analyzer and 

following EPA Method 21 to determine leak concentrations at all applicable process 

components, it suggests using a gas imaging instrument that can visually located VOC leaks, so 

that refineries can focus on the major equipment leaks which contribute the most to high fugitive 

emissions. Gas imaging equipment, such as the Pulsed Laser Imager, costs between $1,500 to 

$25,000 for short range devices, and up to $100,000 for long range devices. Even though the 

upfront cost of the equipment is high, significant savings in labor costs can be attained, as the 

typical refinery spends approximately $1,000,000 a year on the manpower alone to support their 

LDAR programs. As part of a consent decree, the ExxonMobil refinery in Baytown, Texas has 

plans to implement a Smart LDAR program by December 31st, 2007, in order to demonstrate and 

evaluate gas imaging equipment, at an estimated cost of $250,000. No cost effectiveness data for 

this option is available at this time. 
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Revisions to the NSPS were proposed by EPA on November 7, 2006. These amendments would 

increase the stringency of the leak definition for pumps in liquid service from 10,000 ppm to 

2,000 ppm and increase the stringency of the leak definition for valves in gas/vapor service or 

light liquid service from 10,000 ppm to 500 ppm. EPA’s analysis indicates that lowering the 

leak detection definitions to 500 ppm for valves and 2,000 ppm for pumps for petroleum 

refineries would have a cost effectiveness of $3,100 per ton removed. 

Several of the refineries in the MARAMA region already have leak definitions that are more 

stringent than the NSPS for some process units. An enhanced LDAR program with a leak 

definition of 500 ppm will be less effective at reducing the emissions from refineries where the 

starting leak definition is 1,000 ppm than where the leak definition is 10,000 ppm. The costeffectiveness is likely to be high for refineries where the current leak definition is already lower 

than the Federal leak definition. We recognize that it’s the emission reduction estimates and 

cost-effectiveness will vary by refinery due to the differences in the current leak definitions at a 

particular refinery. We recommend that State’s further evaluate the refinery-specific baseline 

emissions, leak definitions, and potential emission reductions from lowering the leak definitions. 

Feasible control technologies for equipment leaks are summarized in Table 5-2, including:: 

• Pollutant controlled 

• Name of technology 

• Origin for the level of control (rule, consent decree, permit) 

• Range of potential emission reductions from applying those controls 

• Performance level in terms of outlet concentration or emission rate 

• Cost effectiveness of the controls 

• Commercial status 

• Reference 

The cost data presented in the Table were obtained from the published literature as referenced. 

In general, the percent reductions and cost effectiveness data represent data for uncontrolled 

sources. Incremental reductions will be lower and costs will be higher for sources already have 

some level of control and will be required to meet the performance levels shown in the Table. 

Also, site-specific factors greatly influence the actual achievable performance level and control 

costs at a particular facility. These considerations must be addressed in State and local 

rulemaking and permitting processes. 
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Table 5-2: Control Technology Options for Fugitive Equipment Leaks

Pollutant Technology 

Origin of 

Requirement Percent 

Reduction Performance Level 

Cost 

Effectiveness 

($/ton) 

Com

Av

VOC Enhanced 

LDAR 

Consent Decrees 50 Program enhancements beyond requirements 

of NSPS, NESHAP, and State Rules: Training of LDAR personnel; enhanced QA/QC; low leak definitions; electronic recording of LDAR monitoring results; thirdparty audits; chronic leaker identification and repair; other operational improvements 

1,300 

VOC Lower Leak 

Definitions 

Proposed 

Revisions to 

NSPS 

Not 

Quantified 

Increase the stringency of the leak definitions for pumps and valves; for pumps in liquid service from 10,000 ppm to 2,000 ppm and increase the stringency of the leak definition for valves in gas/vapor service or light liquid service from 10,000 ppm to 500 ppm. 

$3,100 

VOC Gas Imaging 

Technology 

EPA’s proposed 

alternative work 

standards 

Unknown Unknown Unknown Curr

Dem
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5.6 REFERENCES 

Coburn, J.B., 2002, “Identifying Cost-Effective Refinery Emission-Reduction Strategies,” 

Research Triangle Institute, Research Triangle Park, North Carolina. 

ENS, 2005, “ExxonMobil Agrees to $570 Million Clean Air Settlement,” Environmental News 

Service, October 11. 

European Commission, Integrated Pollution Prevention & Control, 2003, “Reference Document on 

Best Available Techniques for Mineral Oil and Gas Refineries.” 

Goers, U.B., T.J. Kulp, and T.G. McRae, “Backscatter Absorption Gas Imaging of VOC's and its 

use in Petrochemical Leak Detection,” published in the Proceedings of the 2000 Air and 

Waste Management Society Meeting, June 2000. 

Hermanson, B., 2002, “Smart LDAR: Status Report April 2002,” British Petroleum West Coast 

Products LLC, http://api-ep.api.org/filelibrary/hermanson.ppt. 

Pacific Advanced Technology, 2000, “IMSS Detects Methane Leaks: Infrared Imaging 

Spectroscopy used to Visualize Hydrocarbon Gas Leaks,” http://www.patinc.com/ 

press_room/pr-visualizing-gas-leaks.htm. 

Siegell, J.H., H.J. Taback, T.G. McRae, and T.J. Kulp, 2000, “Development of Smart LDAR for 

Fugitive Emissions Control,” Paper P0056. 

“Smart LDAR,” 2000, Valve World 2000 Conference, http://www.ldar.com/documents1/ 

SMARTLDAR-HAGUE2000.ppt. 

U. S. Department of Energy, Energy Efficiency and Renewable Energy, Office of Industrial 

Technologies, 2002, “Pulsed Laser Imager for Detecting Emissions of Hydrocarbons and 

Volatile Organic Compounds,” Petroleum Project Fact Sheet, Washington, D.C. 

U.S. Environmental Protection Agency, April 6, 2006, “Proposed Rule Amendment: Alternative 

Work Practice to Detect Leaks from Equipment”, 71 Federal Register 17401. 

U.S. Environmental Protection Agency, November 7, 2006, “Standards of Performance for 

Equipment Leaks of VOC in the Synthetic Organic Chemical Manufacturing Industry; 

Standards of Performance for Equipment Leaks of VOC in Petroleum Refineries: 

Proposed Rule”, 71 Federal Register 65302. 
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6.0 WASTEWATER TREATMENT 

The process of petroleum refining generates a significant amount of wastewater, contributing to 

emissions released to the atmosphere, nearby water bodies and the production of solid waste. 

This wastewater is then either recycled for specific use in the petroleum refinery or processed 

through a series of on-site collection and treatment units to reduce air and water emissions, as 

well as solid waste. Emissions to the air consist mainly of volatile organic carbons (VOCs) and 

hazardous air pollutants (HAPs) from wastewater collection and treatment units which are open 

to the atmosphere. Contaminants released into the water include hydrocarbons, organic, sulfur, 

and ammonia based compounds, and heavy metals. Solid waste generated from wastewater 

treatment systems is in the form of sludge, which can contain phenols, metals, oil, chemical 

coagulants, suspended solids, and spent lime. Owners of wastewater treatment systems are 

required to meet federal and state standards for controlling the release of contaminants into air, 

water, and solid waste. This section will only focus on air emissions from petroleum refinery 

wastewater collection and treatment systems, and provide control strategies to reduce VOC 

emissions from these facilities. Current state and federal standards require some of these 

collection and treatment systems to be covered and or controlled to minimize VOC releases to 

the atmosphere, however, not all systems are covered and/or controlled. Both equipment covers 

and pollution control equipment can be employed to further reduce VOC emissions from the 

wastewater treatment facilities at petroleum refineries in the MARAMA region. 

6.1 PROCESS DESCRIPTION 

Wastewater treatment systems at petroleum refineries treat cooling water, process water, storm 

water, and sanitary sewage water before discharging the treated water to a public owned 

treatment works (POTW) facility or to a nearby receiving water body. Wastewater treatment 

systems are divided into two sections; first a collection system followed by a treatment system. 

Collection systems consist of some or all of the following: process drains, manholes, reaches, 

junction boxes, weirs, trenches, sumps, and lift stations, while treatment system consist of some 

or all of the following: oil-water separators, equalization basins, dissolved air floatation 

(DAF)/dissolved nitrogen floatation (DNF) tanks, clarifiers, biological treatment basins, sludge 

digesters, treatment tanks, surface impoundments, and air and steam strippers. Figure 6-1 

depicts a typical refinery wastewater collection and treatment system. 

Collection system components are designed to collect wastewaters from various process units 

throughout the petroleum refinery and transport them to the treatment facility. Collection system 

components are defined as follows: Process drains are the connecting point between process 

sources and sewer lines, trenches, sumps, or ditches. Manholes provide entrances to sewer lines 

for sewer inspection and cleaning. Reaches are the lengths of sewer pipe between each manhole 
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or between other sewer components, such as lift stations or junction boxes. Junction boxes are 

the meeting points for several process sewer lines to combine the streams into one stream. Weirs 

act as dams in open channels to maintain constant water levels upstream. Trenches are an 

alternative to process drains and accommodate pad water runoff, water from equipment washes, 

and spill cleanups. Sumps are used for collection and equalization of wastewater flow from 

trenches. Lift stations provide sufficient pressure to transport collected wastewaters to the 

treatment system. 

Figure 6-1. Typical Refinery Wastewater Collection & Treatment System 

SOURCE: Dunn, T.X., D.M. Breen, and C. Pham, 2004, “Draft Technical Assessment Document: Potential Control Strategies 

to Reduce Emissions from Refinery Wastewater Collection and Treatment Systems,” California Air Resources 

Board and the Bay Area Air Quality Management District. 
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Treatment system components are responsible for removing oil, sludge, and other hazardous 

components from the wastewater stream before discharging the stream to a receiving body of 

water or other POTWs. Oil-water separators (also known as API separators) are the first step in 

wastewater treatment, which separates oil and suspended solids from wastewater based on the 

specific gravity of each liquid. Equalization basins are used to prevent fluctuations in the 

wastewater flow rate to downstream treatment processes. DAF/DNF tanks use floatation to 

separate oils, grease, scum and solids remaining in the wastewater, removing these pollutants 

using a surface skimmer. Clarifiers are used to remove sludge from wastewaters. Biological 

treatment basins are large aeration basins where microorganisms metabolize organic compounds 

through the use of mechanical aeration. Sludge digesters treat organic sludge through aeration 

with conventional air diffusers or surface aeration equipment. Treatment tanks, including 

biological treatment tanks and pH adjustment tanks, are used to treat wastewater before and/or 

after biological treatment. Surface impoundments are used for evaporation, polishing, 

equalization, storage, leachate collection, and as emergency surge basins. Air and steam 

stripping can be used to remove organic constituents in wastewater streams prior to secondary or 

tertiary treatment devices. Air stripping involves contacting wastewater with air to strip out 

VOCs, while steam stripping involves distillation of the wastewater through contact with steam 

to provide the necessary heat to vaporize VOCs present. 

6.2 EMISSION INVENTORY 

Table 6-1 identifies the wastewater treatment systems in the MARAMA region, along with the 

capacity of each unit. Criteria pollutant emissions for each unit are shown for three years. The 

2002 annual emissions serve as the baseline for future SIP development. The 2002 emissions 

were obtained from the 2002 inventories developed by MANEVU and VISTAS. The 2003 

emissions were obtained directly from each state and represent the most currently quality assured 

data that is available. The 2009 emissions were obtained from the MANEVU and VISTAS 

projection inventories that were developed to support modeling for SIP development. The 2009 

inventories include the effects of anticipated growth as well as any planned controls that will 

result in emission reductions between 2002 and 2009 due to new regulations or enforcement 

settlements. 
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Table 6-1: Emission Inventory for Wastewater Treatment 

 Refinery/ Annual VOC Emissions (tons/year)

State Unit 2002 2003 2009 

DE Valero Delaware City 

 EUID = 050 CPI&API Separator, Tanks 199.5 209.1 184.0 

 EUID = 051 Wastewater Treatment Plant 167.3 4.2 154.3 

DE SUNCO Inc Delaware 

 None listed in Inventory 0.0 0.0 0.0 

NJ Sunoco Eagle Point 

 EUID = U53 API System 60.6 64.8 69.2 

 EUID = U55 Aeration Basin 55.8 59.6 63.6 

NJ Valero Paulsboro 

 EUID = U53 Wastewater Treatment Plant 272.0 283.7 393.9 

NJ Citgo Asphalt 

 EUID = U9 Area 9 Waste Water Treatment 4.7 2.3 5.3 

NJ Amerada Hess Port Reading 

 EUID = U6 Waste Water Treatment 1.4 3.1 1.6 

NJ Chevron Products 

 EUID = U10 Area J Effluent Treatment Plant 41.2 24.6 47.0 

NJ ConocoPhillips Bayway 

 EUID = U10 35.1 50.5 51.0 

PA Sunoco Marcus Hook 

 EUID = 112 Process Drains 37.0 281.4 42.2 

PA ConocoPhillips Trainer 

 EUID = 106 Process Drains and Separator 18.6 16.3 21.2 

PA American Refining Bradford 

 EUID = 302/303 Oil/Water Separators 0.2 0.2 0.2 

PA Sunoco Philadelphia 

 EUID = 046 GP Separator 2 7.6 22.8 8.7 

 EUID = 047 GP Separator 4 7.5 15.5 8.6 

 EUID = 556 PB Wastewater Operations 24.4 24.4 27.8 

 EUID = 745 PB LDAR Process Drains 72.9 72.9 10.5 

 EUID = 905 GP LDAR Process Drains 49.9 49.9 7.2 

PA United Refining 

 EUID = 110 Wastewater Fugitive Emissions 184.4 191.6 72.3 

VA Giant Yorktown 

 EUID = 029 Below Grade Sewer 1.5 1.2 1.6 

WV Ergon West Virginia 

 EUID = 017 Waste Water Treatment 83.2 56.8 89.0 

MARAMA Totals 1,324.8 1,433.7 1,259.2 
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6.3 EXISTING REQUIREMENTS 

This section discusses the regulatory requirements which apply to wastewater treatment systems 

at petroleum refineries. Four types of requirements are discussed: (1) Federal requirements such 

as the New Source Performance Standards (NSPS) and Maximum Achievable Control 

Technology (MACT) standards; (2) State regulations for both the MARAMA states as well as 

other State agencies; (3) source-specific permit requirements; and (4) new requirements from 

recent enforcement settlements. 

6.3.1 Federal Requirements 

The U.S. EPA has promulgated standards to limit emissions of VOCs from petroleum refinery 

wastewater treatment facilities. 

New Source Performance Standards (NSPS) for wastewater treatment systems constructed or 

modified after May 4, 1987 are covered under 40 CFR Part 60, Subpart QQQ. This subpart 

applies to individual drain systems, oil-water separators, and aggregate wastewater treatment 

facilities at petroleum refineries. For individual drain systems, each drain should be equipped 

with water seal controls and be visually or physically inspected monthly for low water levels. 

Each drain system’s junction box should be equipped with a cover and tight seal around the 

edges and should be inspected semiannually for broken seals. In addition, sewer lines should be 

covered or enclosed with no visible gaps or cracks in joints, seals, or other emission interfaces 

and inspected semiannually. Alternative standards allow for the owner or operator to construct 

and operate a closed drain system with a control device with the Administrator’s approval. 

For oil-water separators, each oil-water separator tank, slop oil tank, storage vessel, and any 

other auxiliary equipment subject to this subpart should be equipped and operated with a fixed 

roof and visually inspected semiannually for cracks or gaps in the roof and wall, access doors, 

and roof seals. In addition, oil-water separator tanks or auxiliary equipment with a design 

capacity to treat more than 250 gallons of refinery wastewater per minute are also required to be 

equipped with a closed vent system and control device. Closed vent systems should be designed 

and operated with no detectable emissions (measured emissions less than 500 ppm) and be 

equipped with a flow indicator to ensure that all vapors are routed to the control device. Control 

device options include enclosed combustion devices with a 95% VOC control efficiency and a 

minimum residence time of 0.75 seconds at a minimum temperature of 1,500o

F, vapor recovery 

stems with a minimum 95% VOC control efficiency, and flares. Alternative standards allow the 

use of floating roof tanks on oil-water separators, slop oil tanks, storage vessels, and other 

auxiliary equipment with approval from the Administrator. As for monitoring requirements, 

Subpart QQQ requires using a temperature monitoring device for thermal or catalytic 
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incinerators to ensure proper VOC combustion, while carbon adsorption systems should be 

equipped with continuous emissions monitors to record VOC emissions in the exhaust. 

The National Emission Standards for Hazardous Air Pollutants (NESHAP) for wastewater 

treatment systems are covered in 40 CFR Part 63, Subpart CC, which applies to petroleum 

refinery wastewater streams and treatment operations. Under this subpart, wastewater treatment 

systems with an annual benzene loading of 11 tons/yr or greater are required to comply with the 

requirements of 40 CFR Part 61, Subpart FF (NESHAP for Benzene Waste Operations), which 

requires the removal of benzene from the wastewater stream by 99% or more on a mass basis, 

meet a 10 ppmw on a flow-weighted annual average basis final benzene concentration, or 

incinerate the waste in a combustion unit that achieves 99% destruction efficiency. 

6.3.2 State Regulations 

Table 6-2 lists the regulations for each of the MARAMA states for the control of VOCs from 

wastewater treatment systems. All regulatory agencies in the MARAMA region have 

regulations limiting the emissions of VOCs except for New Jersey. In Table 6-3, the regulations 

are listed for Louisiana, Texas, and California (from the Bay Area Air Quality Management 

District – BAAQMD, the South Coast Air Quality Management District – SCAQMD, and the 

San Joaquin Valley Air Pollution Control District – SJVAPCD). Regulations from these states 

are presented because these states tend to enforce stricter emission limitations than the 

MARAMA states and the federal government. 

6.3.3 Requirements from Recent Enforcement Settlements 

The Consent Decrees addressed noncompliance with the benzene waste (40 CFR Part 61, 

Subpart FF). The Consent Decrees require increased monitoring, regular laboratory and program 

audits, quarterly benzene balances, and replacement of carbon emission filters as soon as 

monitoring detects any benzene emissions above background levels. In general, the Consent 

Decrees require program benzene waste NESHAP enhancements, including the following: 

• Review and verification of compliance status 

• Implementation of corrective action plants to correct noncompliance 

• Requirements for use of carbon canister systems 

• Annual review of process information to ensure that all new benzene waste streams are 

included in the waste stream inventory 

• Audits of laboratories that perform analyses of NESHAP samples 

• Review of benzene spill data 

• Benzene waste sampling plans and training of technicians 

• Recordkeeping and reporting requirements 

The Consent Decrees required covering of the API separators in some cases. 
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Table 6-2: Summary of MARAMA State Regulations 

Agency Emission Standards 

Delaware Reg. 24, Section 28 

The owner or operator of any wastewater (oil/water) separator at a petroleum refinery shall: 

1. Provide covers and seals on all separators and forebays. 

2.Equip all openings in covers, separators, and forebays with lids or seals and keep the lids or seals in 

the closed position at all times except when in actual use. 

New Jersey 7:27-16.27

The provisions of this subchapter shall not apply to the emissions of VOC from the following source 

operations: 

4. Industrial wastewater treatment systems until November 15, 1994; 

5. All other wastewater treatment facilities until November 15, 1994: and 

Pennsylvania § 129.55. 

No person may permit the use of a compartment of a single or multiple compartment volatile organic 

compound wastewater separator which compartment receives effluent water containing 200 gallons a 

day or more of any volatile organic compound from equipment processing, refining, treating, storing or 

handling volatile organic compounds unless the compartment is equipped with one of the following 

vapor loss control devices—properly installed, in good working order, and in operation—as follows: 

1. A container having openings sealed and totally enclosing the liquid contents. Gauging and sampling 

devices shall be gas-tight except when gauging or sampling is taking place. 

2. A container equipped with a floating roof—consisting of a pontoon type roof, double-deck-type roof 

or internal floating cover—which will rest on the surface of the contents and be equipped with a 

closure seal or seals to close the space between the roof edge and container wall. Gauging and 

sampling devices shall be gas-tight except when gauging or sampling is taking place. 

Philadelphia Reg. 5, SECTION III. 

No person shall use any compartment of any single or multiple compartment oil-effluent water separator 

which may receive 200 gallons a day or more of organic materials or mixture of organic materials 

consisting of kerosene or more volatile organic materials unless one of the following organic material 

vapor control devices properly installed and well maintained, is in operation: 

1. A solid cover sealed and totally enclosing the liquid contents, and in addition, all gauging and 

sampling devices shall be gas-tight except when in use, or 

2. A floating roof resting on the surface of the liquid contents equipped with a closure seal or seals to 

close the space between the roof edge and wall, and in addition, all tank gauging and sampling 

devices shall be gas-tight except when in use, or 

3. A vapor recovery system capable of collecting the organic materials emitted from the separator and 

disposing of these emissions so as to prevent their emission to the atmosphere, and in addition, all 

tank gauging and sampling devices shall be gas-tight except when in use, or 

4. Other equipment equal or greater in efficiency to those devices listed above, and approved by the 

Department 

Virginia 9 VAC 5-40-1390. 

No owner or other person shall use or permit the use of any wastewater separator unless such separator is 

equipped with a vapor control system that will remove, destroy or prevent the discharge into the 

atmosphere of at least 95% by weight of volatile organic compound emissions.

9 VAC 5-40-1400. 

The control system (for wastewater separators) should consist of one of the following: 

1. A solid cover with all openings sealed and totally enclosing the liquid contents of that compartment; 

2. A floating pontoon or double-deck type cover, equipped with closure seals to enclose any space 

between the cover's edge and compartment wall; or 

3. Any system of equal or greater control efficiency to the system mentioned in this section, provided 

such system is approved by the board. 

West 

Virginia 

§45-21-25. Petroleum Refinery Sources.

The owner or operator of any wastewater (oil/water) separator at a petroleum refinery shall: 

1. Provide covers and seals on all separators and forebays; and 

2. Equip all openings in covers, separators, and forebays with lids or seals and keep the lids or seals in 

the closed position at all times except when in actual use. 
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Table 6-3: Summary of Other State Regulations 

Agency Emission Limitations 

BAAQMD 8-8-312 Controlled Wastewater Collection System Components at Petroleum 

Refineries: Effective January 1, 2006, all controlled wastewater collection system components at petroleum 

refineries shall be vapor tight except when in use for active inspection, maintenance, repair or sampling. A leak 

in any controlled wastewater collection system component that is not vapor tight must be minimized within 24 

hours and repaired within 7 days. 

8-8-313 Uncontrolled Wastewater Collection System Components at Petroleum 

Refineries: Petroleum refineries shall comply with either Section 8-8-313.1 or 313.2 below: 

313.1 Each uncontrolled wastewater collection system component must be equipped with a water seal or 

equivalent control according to the schedule in Section 8-8-403. Any uncontrolled collection system component 

that is not vapor tight must be minimized. Upon installation of a water seal or equivalent control, the provisions 

of Section 8-8-312 will apply; or 

313.2 Effective January 1, 2006 and until January 1, 2007, each uncontrolled wastewater collection system 

component must be inspected bi-monthly. Effective January 1, 2007, each uncontrolled wastewater system 

component must be inspected semi-annually. Any uncontrolled wastewater collection system component that is 

not vapor tight shall be identified, minimized within 24 hours and re-inspected every 30 days. The component 

may be returned to a semi-annual inspection schedule if it is vapor tight during three consecutive 30-day 

inspections. Any uncontrolled wastewater collection system component that is not vapor tight during any three 

inspections in a five-year period must be equipped with a water seal or equivalent control within 30 days after 

the third inspection. Upon installation of the water seal or equivalent control, the provisions of Section 8-8-312 

shall apply. Unless previously identified by the refinery, any wastewater system component discovered by the 

APCO not to be vapor tight must be minimized within 24 hours and repaired within 7 days. 

8-8-314 New Wastewater Collection System Components at Petroleum Refineries: 

Effective January 1, 2005, any new wastewater collection system component at a petroleum refinery shall be 

equipped with a water seal or equivalent control. 

Louisiana Section 2153 Subchapter M. 

1. The wastewater component shall meet the following requirements: 

a. all components shall be fully covered or be equipped with water seal controls; 

b. all openings shall be closed and sealed, except when the opening is in actual use for its intended purpose or 

the component is maintained at a pressure less than atmospheric pressure; 

c. all liquid contents shall be totally enclosed; 

d. for junction boxes and vented covers, the vent shall be equipped with either a control device or a vapor 

recovery system that maintains a minimum control efficiency of 90 percent VOC removal or a VOC 

concentration of less than or equal to 50 parts per million by volume (ppmv) (whichever is less stringent) or 

a closed system which prevents the flow of VOC vapors from the vent during normal operation; 

e. all gauging and sampling devices shall be vapor tight except during gauging or sampling; 

2. Any wastewater tank equipped with a floating roof or internal floating cover shall meet the following 

requirements: 

a. all openings in an internal or external floating roof shall provide a projection below the liquid surface and 

be equipped with a cover, seal, or lid. 

b. automatic bleeder vents shall be closed at all times except when the roof is floated off or landed on the roof 

leg supports; 

c. rim vents, if provided, shall be set to open only when the roof is being floated off the roof leg supports or at 

the manufacturer's recommended setting; 

d. any emergency roof drain shall be provided with a slotted membrane fabric cover that covers at least 90 

percent of the area of the opening; 

e. there shall be no visible holes, tears, or other openings in any seal or seal fabric; 

f. secondary seals shall be the rim-mounted type (i.e., the seal shall be continuous from the floating roof to the 

tank wall). The accumulated area of gaps that exceed 1/8 inch (0.32 cm) in width between the secondary 

seal and tank wall shall be no greater than 1.0 inch2 per foot (21 cm2 per meter) of tank diameter 

3. A properly operated biotreatment unit and wet weather retention basin shall meet the following requirements: 

a. the VOC content of the wastewater shall be reduced by 90 percent; and 

b. the average concentration of suspended biomass maintained in the aeration basin of the biotreatment unit 

shall equal or exceed 1.0 kilogram per cubic meter (kg/m3), measured as total suspended solids, or an 
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alternate parameter, as approved by the administrative authority, may be measured to ensure proper 

operation of the biotreatment unit. 

SCAQMD Rule 1176. 

1. Wastewater System Emissions: Wastewater systems and closed vent systems, except sump and wastewater 

separator covers shall not emit VOC emissions greater than 500 ppm above background levels 

2. Sumps and Wastewater Separators : 

A. Sumps and Wastewater Separators shall be provided with one of the following: 

i. A floating cover equipped with seals. 

ii. A fixed cover, equipped with a closed vent system vented to an APC device. 

iii. Any other alternate control measure which is demonstrated by the facility operator to be equivalent to, 

or more effective in reducing VOC emissions, and approved in writing by the Executive Officer. 

B. Sump and Wastewater Separator Covers, both fixed and floating, shall meet all of the following 

requirements: 

i. The cover material shall be impermeable to VOCs, and free from holes, tears, or openings. 

ii. Drains on covers shall be provided with a slotted membrane fabric cover, or equivalent, over at least 

90 percent of the open area. 

iii. Gauging or sampling openings on the separator shall be covered. 

iv. A floating cover shall be designed and maintained so that the gap between the separator or sump wall 

and the seal does not exceed 1/8 inch for a cumulative length of 97 percent of the perimeter of the 

separator. No gap between the wall and the seal shall exceed 1/2 inch. 

3. Sewer lines: All sewer lines shall be completely enclosed so that no liquid surface is exposed to the 

atmosphere, and all openings in the sewer line manhole covers shall be completely sealed. 

4. Process drains: Any new process drain installed after September 13, 1996, shall be equipped with water seal 

controls or any other alternative control measure which is demonstrated by the applicant to be equivalent, or 

more effective than water seal controls in reducing VOC emissions, as approved in writing by the Executive 

Officer. 

5. Junction boxes: Junction boxes shall be totally enclosed with a solid, gasketed, fixed cover or a manhole 

cover. Each fixed cover shall be allowed to have an open vent pipe no more than four inches in diameter and at 

least three feet in length. Each manhole cover on junction boxes shall be allowed to have openings totaling no 

more than 12 square inches. The manhole cover shall remain fully closed, except when opened for active 

inspection, maintenance, sampling, or repair. 

6. APC Devices shall meet one of the following requirements: 

A. An APC device receiving vapors from a closed vent system shall achieve a control efficiency of 95 percent 

by weight or greater of VOC. 

B. The outlet of the APC device shall not emit VOC emissions greater than 500 ppm above background. The 

frequency of monitoring shall be at least monthly 

SJV APCD Rule 4625 

1. A person shall not use any compartment of any vessel or device operated for the recovery of oil or tar from 

effluent water, from any equipment which processes, refines, stores or handles petroleum or coal tar products 

unless such compartments are equipped with one of the following vapor loss control devices, except when 

gauging or sampling is taking place: 

A. A solid cover with all openings sealed and totally enclosing the liquid contents of the compartment, except 

for such breathing vents as are structurally necessary; or 

B. A floating pontoon or double-deck type cover, equipped with closure seals that have no holes or tears, 

installed and maintained so that gaps between the compartment wall and seal shall not exceed one-eighth 

(1/8) inch for an accumulative length of 97 percent of the perimeter of the tank, and shall not exceed onehalf (1/2) inch for an accumulative length of the remaining three (3) percent of the perimeter of the tank. 

No gap between the compartment wall and the seal shall exceed one-half (1/2) inch; or 

C. A vapor recovery system with a combined collection and control efficiency of at least 90 percent by 

weight. 

2. Any gauging and sampling device in the compartment cover shall be equipped with a cover or lid. The cover 

shall be in a closed position at all times, except when the device is in actual use. 

3. All wastewater separator forbays shall be covered. 

4. Skimmed oil or tar removed from wastewater separating devices shall be either charged to process units with 

feed or transferred to a container with a control system with at least 90 percent control efficiency by weight. A 

control device must be under District permit. 
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Texas Rule 115.142 

1. For wastewater treatment components, including storage tanks, surface impoundments, drains, junction 

boxes, lift stations, weirs, and oil-water separators: 

A. All components shall be fully covered or be equipped with water seal controls 

B. For junction boxes and vented covers in the Dallas/Fort Worth and El Paso areas, vents shall be equipped 

with either a vapor control system which maintains a minimum control efficiency of 90% or a closed 

system which prevents the flow of VOC vapors from the vent during normal operation. In the 

Beaumont/Port Arthur and Houston/Galveston areas, vents shall be equipped with either a vapor control 

system which maintains a minimum control efficiency of 90% or a closed system which prevents the flow 

of VOC vapors from the vent during normal operation. 

C. All gauging and sampling devices shall be vapor-tight except during gauging or sampling. 

D. Any loading or unloading to or from a portable container by pumping shall be performed with a 

submerged fill pipe. 

2. If a wastewater component is equipped with an internal or external floating roof: 

A. All openings in an internal or external floating roof except for automatic bleeder vents and rim space vents 

shall provide a projection below the liquid surface or be equipped with a cover, seal, or lid. 

B. Automatic bleeder vents (vacuum breaker vents) shall be closed at all times except when the roof is being 

floated off or landed on the roof leg supports. 

C. Rim vents, if provided, shall be set to open only when the roof is being floated off the roof leg supports or 

at the manufacturer's recommended setting. 

D. Any roof drain that empties into the stored liquid shall be provided with a slotted membrane fabric cover 

that covers at least 90% of the area of the opening. 

E. There shall be no visible holes, tears, or other openings in any seal or seal fabric. 

F. For external floating roof storage tanks, the secondary seals shall be the rim-mounted type. The 

accumulated area of gaps that exceed 1/8 in. in width between the secondary seal and tank wall shall be no 

greater than 1.0 in2

/ft of tank diameter. 

3. In the Beaumont/Port Arthur and Houston/Galveston areas, each properly operated biotreatment unit shall 

meet the following requirements. 

A. The VOC content of the wastewater shall be reduced by 90% by weight; and 

B. The average concentration of suspended biomass maintained in the aeration basin of the biotreatment unit 

shall equal or exceed 1.0 kilogram per cubic meter (kg/m3

), measured as total suspended solids. 

6.4 AVAILABLE CONTROL TECHNOLOGIES 

Wastewater treatment systems mainly emit VOCs through volatilization of organic 

compounds at the liquid surface of uncovered wastewater collection and treatment units. 

The main strategies employed to limit VOC emissions from these primary treatment units 

include installing covers or seals over existing collection equipment, and using control 

devices to destroy VOCs that are released. A third, less researched, method includes 

reducing the available VOC in the wastewater stream before the wastewater enters 

collection and treatment systems. These strategies are discussed below, with several 

control options available to reduce VOC emissions from primary treatment units. For 

secondary treatment, proven control technologies include steam stripping, liquid phase 

carbon adsorption units, and doming tanks. These control technologies are discussed in 

Section 6.4.4. 
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6.4.1 Equipment Covers 

Controlling VOCs from wastewater collection systems can be achieved by various 

methods, including installing water seals on process drains and junction box vents, sealing 

manholes, enclosing open weirs, hard piping, and installing domed roofs on sludge storage 

tanks. Installation of these types of seals and covers on collection units currently open to 

the atmosphere will prevent volatilized emissions in the sewer lines from escaping. 

6.4.1.1 Water Seals on Drains and Junction Box Vents 

Water seals create a liquid barrier between the sewer line and the atmosphere to prevent air 

flow through the system. Water levels within the seal should be kept constant, as 

evaporation of the water will result in emissions of VOCs similar to the previously 

uncontrolled levels. There are two types of water seal configurations, the P-leg seal and 

the liquid seal inserts placed inside existing process drains or junction box vents (Figure 6-

3). By installing these seals on drains and vents, VOC emissions can be reduced on 

average by 65%, which varies depending on the maintenance of the seal. 

Figure 6-2. Liquid Seal Insert for Process Drain 

SOURCE: Dunn, T.X., D.M. Breen, and C. Pham, 2004, “Draft Technical Assessment Document: Potential Control 

Strategies to Reduce Emissions from Refinery Wastewater Collection and Treatment Systems,” California 

Air Resources Board and the Bay Area Air Quality Management District. 
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6.4.1.2 Sealing Manholes 

VOC emissions can be reduced an average of 65% by installing gasket seals on manholes 

and plugging holes in manhole covers. Although, by installing these seals, VOC emissions 

are still reported from manhole covers through cracks and gaps in the manhole chimney 

seal or cover ring. Figure 6-3 shows a typical design of a refinery sewer manhole. 

Figure 6-3. Design of Refinery Manhole 

SOURCE: Dunn, T.X., D.M. Breen, and C. Pham, 2004, “Draft Technical Assessment Document: Potential Control 

Strategies to Reduce Emissions from Refinery Wastewater Collection and Treatment Systems,” California 

Air Resources Board and the Bay Area Air Quality Management District. 
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6.4.1.3 Enclosing Weirs and Hard Piping 

Enclosing open weirs and lines with direct piping, a process referred to has hard piping, is 

considered one of the most stringent control options and could effectively eliminate VOC 

emissions from weirs and sewer lines. Enclosing weirs and lines with direct piping 

involves (1) hard piping process units to the wastewater separator and cap all process 

drains, (2) hard pipe process units to a drain box enclosure, (3) hard piping the process 

units that contribute the largest emissions to process drains, and (4) hard pipe covered and 

sealed junction boxes. This control option may eliminate VOC emissions, however, by 

enclosing all air emissions, there is an increased likeliness of safety issues from the trapped 

combustible VOCs. It is also unlikely that all components of the wastewater collection 

system will be enclosed due to the complexity of reconstructing the sewer system. 

6.4.1.4 Installing Domed Roofs on Sludge Tanks 

For refineries with activated sludge tanks, in some cases domed aluminum roofs can be 

installed to reduce VOC emissions from escaping by up to 95%. Domed roofs allow 

sufficient head space above the tanks liquid level for volatized organics to collect. These 

VOCs must then be piped to a control device for destruction. 

6.4.2 Pollution Control Equipment 

In addition to installing covers and seals to prevent the release of VOCs from the 

wastewater collection equipment, control equipment can be installed to reduce the VOCs 

released during collection and/or treatment operations. The common control devices used 

to reduce VOCs include air or steam strippers, gas or liquid phase carbon adsorption, and 

combustion devices. These control devices are discussed in detail below. 

6.4.2.1 Air & Steam Stripping 

Air strippers contact wastewater with large amounts of air in order to transfer VOCs from 

the water to the air. Steam stripping is similar to air stripping, but the wastewater is 

contacted with steam to distill the wastewater and remove VOCs. Removal efficiencies for 

both stripping processes vary between 50% and 99% depending on the volatility and 

solubility of the organic material in the wastewater. After the VOCs are stripped from the 

wastewater, the contaminated air stream must then be vented to a secondary control device, 

such as a combustion device (flare, incinerator, boiler, etc) or gas phase carbon adsorber. 

These stripping processes also hold some safety and equipment concerns. Concerns over 

air stripping include safety during refinery upsets when there is a potential for large 

amounts of hydrocarbons to be released to the wastewater treatment system resulting in 

explosive conditions, and equipment concerns due to fouling of the packing material due to 
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oil and grease, compounds that precipitate when reacted with oxygen, and fouling of 

carbon by hydrogen sulfide, thereby decreasing the VOC capture and destruction. Texaco 

developed an improvement to the air stripping process to address these safety and 

equipment concerns, which involves using nitrogen as the stripping gas, thus eliminating 

the presence of oxygen and the safety and equipment concerns. The main downside to this 

improvement, known as the AMCEC BRU (benzene recovery unit, depicted in Figure 6-4), 

is the high cost of nitrogen, however the gas can be recycled after it is cleaned by carbon 

adsorption. Concerns over steam stripping are similar and include equipment fouling due 

to oil and grease, fouling of packing material with salts, as well as high costs due to energy 

consumption. 

Figure 6-4. Diagram of the Air Stripping Improvement, AMCEC BRU 

SOURCE: Worrall, M. and I. Zuber, 1998, “Case Studies: Control VOCs in Refinery Wastewater,” Process 

Optimization Conference, Houston, TX. 

6.4.2.2 Carbon Adsorption 

Both gas phase and liquid phase carbon adsorption take advantage of compound affinities 

for activated carbon, however gas phase systems are used to treat contaminated air 

emissions from wastewater control equipment, whereas liquid-phase systems are used to 

remove VOCs from the wastewater. The most common gas phase carbon adsorption 

systems are fixed-bed carbon adsorbers and carbon canisters. Fixed-bed carbon adsorbers 

are used to remove VOCs from large contaminated air flows between 30 and 3,000 

m3

/min, while carbon canisters are usually installed to control air flows less than 3 m3/min. 
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Control efficiencies vary between 90 and 99% depending on the types of VOCs being 

removed, and in some cases using pollutant specific activated carbon. There are also two 

types of liquid phase carbon adsorbers, including fixed-bed and moving-bed systems. The 

fixed-bed system operates in batch mode, processing mainly low flow wastewater streams. 

The moving-bed system operates continuously allowing wastewater to flow countercurrent 

to regenerated carbon. Liquid phase carbon adsorbers are mainly used for wastewater 

streams with low concentrations of non-volatile components and for high concentrations of 

non-degradable compounds. They achieve control efficiencies between 90 and 99%, with 

efficiency varying with the contaminant’s affinity for the activated carbon. 

6.4.2.3 Combustion Devices 

VOC emission releases collected from wastewater collection and treatment systems can be 

vented to a combustion device for destruction. Common combustion devices include flares 

(discussed in Section 4.0), thermal or catalytic incinerators, and boilers (discussed in 

Section 3.0). These devices can reduce VOCs by combusting them at a specified 

minimum temperature for a specified residence time to ensure complete destruction. 

Typically vented gases can be combined with natural gas or fuel oil to supplement the fuel 

or used as an alternate fuel in cases where the vent gas has a high fuel value. However, in 

cases where the fuel value of the vented gases is very low, vent gases can be mixed with 

other fuels or combustion air. 

6.4.3 Reduce VOCs from Wastewater 

Several potential control measures have been identified by the BAAQMD as ways to 

reduce the concentration of VOCs entering the wastewater collection and treatment system. 

These measures include the following list. 

• Reduce the generation of tank bottoms 

• Minimize solids leaving the desalter unit 

• Minimize and/or segregate cooling tower blowdown condensate 

• Minimize fluid catalytic cracking unit decant oil sludge 

• Control heat exchanger cleaning solids and sludge 

• Minimize discharge of surfactants into wastewater collection system 

• Reduce use of open pits, tanks, and ponds 

• Remove unnecessary storage tanks from service 

• Segregate storm, process, and septic wastewater collection 

• Improve recovery of petroleum product from wastewater collection systems 

• Identify VOC sources and install upstream water treatment and/or separation 

• Use oily sludges as feedstock 

• Control and reuse FCCU and coke fines 

• Train personnel to reduce solids in sewers from sludge treatment 
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6.4.4 Secondary Treatment Control Options 

The approaches for controlling VOC emissions from secondary treatment units either 

remove VOCs from the wastewater stream prior to its entry to secondary treatment or 

reduce the stream’s exposure to the atmosphere. The BAAQMD recently completed a 

study to evaluate the VOC emission reductions to be achieved from control of secondary 

wastewater treatment components at refineries. The BAAQMD identified three control 

options: 

• Steam stripping is a proven technology to remove VOCs prior to secondary 

treatment. It requires proper venting to a secondary control device and monitoring 

to insure optimal operation. The BAAQMD estimates that the total cost to install, 

inspect and maintain a steam stripper at each refinery over a ten-year period ranges 

between $7.1 million and $17.9 million. The estimated VOC emission reductions 

are 0.14 tons per day (tpd) based on a 90% removal efficiency if the steam stripper 

is installed to treat wastewater that enters the biological treatment unit and 

channel/weir. 

• Liquid phase carbon adsorption may be used as a stand alone control device, but is 

also suitable as a secondary control device to reduce VOC emissions from gas 

phase vent streams from a steam stripper. The BAAQMD estimates that the total 

annual costs are comparable to that of a steam stripper. The BAAQMD estimates 

VOC emission reductions to be 0.14 tpd based on a 90% removal efficiency. Total 

annual costs for this technology are estimated to be $6.7 million to $24 million. A 

number of factors may limit the equipment’s effectiveness. For example, high 

suspended solids and oil and grease can foul the carbon and require extensive 

pretreatment. Refineries must continuously monitor the equipment to ensure that 

the carbon beds are regenerated. 

• Some activated sludge tanks may accommodate domed aluminum roofs to contain 

VOC emissions. The BAAQMD assumed a 95% VOC removal efficiency and 

estimated a total of 0.025 tpd reductions from two refineries’ activated sludge units. 

The District estimated that the total cost to install, operate and maintain the 

aluminum domes over a ten year period would range from $100,000 to $900,000 at 

the two refineries. This estimated cost does not include additional expenses to 

install and operate VOC abatement equipment. The BAAQMD also determined 

that two refineries have bermed aeration lagoons and ponds that cannot 

accommodate a dome. These refineries would have to install foundations and 

support structures to contain them or replace the lagoons and ponds with tanks. 

The BAAQMD concluded these measures decided not to implement these technologies 

because of the relatively small emission reductions compared to the present cost of 

implementing these known technologies. The BAAQMD estimated the cost-effectiveness 

to be over $1 million per ton for either a steam stripper or liquid phase carbon adsorption, 

and $25,000 per ton for enclosing the treatment tanks. 
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6.5 COSTS AND AVAILABILITY 

Feasible control technologies for primary and secondary wastewater treatment units are 

summarized in Table 6-4. The table includes 

• Pollutant controlled 

• Name of technology 

• Origin for the level of control (rule, consent decree, permit) 

• Range of potential emission reductions from applying those controls 

• Performance level in terms of outlet concentration or emission rate 

• Cost effectiveness of the controls 

• Commercial status 

• Reference 

More detailed information on each technology was summarized in the previous sections 

and based on the information contained in the references for this Section. 

The cost data presented in the Table were obtained from the published literature as 

referenced. In general, the percent reductions and cost effectiveness data represent data for 

uncontrolled sources. Incremental reductions will be lower and costs will be higher for 

sources already have some level of control and will be required to meet the performance 

levels shown in the Table. Also, site-specific factors greatly influence the actual 

achievable performance level and control costs at a particular facility. These 

considerations must be addressed in State and local rulemaking and permitting processes. 
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Section 6 – Wastewater Treatment Page 6-18 MACTEC Federal Programs, Inc. 

Table 6-4: Control Technology Options for Wastewater Treatment 

Pollutant Technology 

Origin of 

Requirement Percent Reduction 

Performance Level 

Cost Effectiveness 

($/ton)

Com

Av

Primary Treatment Processes VOC Install water seals on drains BAAQMD 

Rule 8 

65 n/a 1,900 to 4,200 

 Install water seals on 

junction box vents 

BAAQMD 

Rule 8 

65 n/a 1,900 to 4,200 

 Sealing manholes BAAQMD 

Rule 8 

65 n/a 1,900 to 4,200 

 Enclosing open weirs and 

lines with direct piping 

BAAQMD 

Rule 8 

100 n/a 1,900 to 4,200 

 Reduce VOCs to 

Wastewater 

BAAQMD 

Rule 8 

Depends on Prevention 

Measures Implemented 

n/a Cost Savings 

Secondary Treatment Processes VOC Install domed roofs on 

activated sludge tanks 

n/a 95 n/a 25,000 

 Air or Steam Stripper n/a 90 to 99 n/a 1.35 to 1.42 million  Liquid Phase Carbon 

Adsorption 

n/a 90 to 99 n/a 1.35 to 1.42 million 
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6.6 REFERENCES 

Broadbent, J.P., 2005, Memorandum to Chairperson Townsend and Members of the Board 

of Directors, November 9, Bay Area Air Quality Management District, San 

Francisco, California. 

European Commission, Integrated Pollution Prevention & Control (ECIPPC), 2003, 

“Reference Document on Best Available Techniques for Mineral Oil and Gas 

Refineries.” 

Dunn, T.X., D.M. Breen, and C. Pham, 2004, “Draft Technical Assessment Document: 

Potential Control Strategies to Reduce Emissions from Refinery Wastewater 

Collection and Treatment Systems,” California Air Resources Board and the Bay 

Area Air Quality Management District. 

Lau, V., 2005, “Workshop Staff Report: Further Study Measure 9 Refinery Wastewater 

Treatment Systems,” Bay Area Air Quality Management District, San Francisco, 

California. 

United States Environmental Protection Agency, 1995, “Waste Water Collection, 

Treatment, and Storage,” Pages 4. 3-1 – 4. 3-46 in AP-42, Fifth Edition: 

Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and 

Area Sources. 

Worrall, M. and I. Zuber, 1998, “Case Studies: Control VOCs in Refinery Wastewater,” 

Process Optimization Conference, Houston, Texas. 
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7.0 STORAGE TANKS 

Storage tanks at petroleum refineries containing volatile organic liquids (VOLs) such as 

petroleum and petroleum derivatives can emit up 40 percent of a refinery’s total VOCs 

emissions. These tanks emit fugitive volatile organic carbon (VOC) emissions as a result 

of vapor expansion and contraction due to changes in temperature and barometric pressure, 

vapor losses due to filling and emptying tanks, and vapor losses at tank roof seals. These 

types of losses can not be completely eradicated, however, various control devices can be 

implemented to limit the amount of VOCs released from storage tanks. 

7.1 PROCESS DESCRIPTION 

The level of VOC emissions escaping from storage tanks containing organic liquids varies 

depending on the tank’s roof design and vapor pressure of the stored liquid. There are six 

types of tank roofs, namely the fixed roof, external floating roof, domed external (or 

covered) floating roof, internal floating roof, variable vapor space, and pressure tanks. 

Each of these roof designs are discussed in detail below, including information on the 

specific mechanisms involved in VOC release. 

7.1.1 Fixed Roof Tanks 

Fixed roof tanks can be situated vertically or horizontally. The vertical fixed roof tank, as 

shown in Figure 7-1, is a cylindrical steel shell with a permanent fixed flat, dome, or cone 

shaped roof. Vertical fixed roof tanks can either be vented to the atmosphere or equipped 

with a pressure/vacuum vent to prevent vapor releases. Horizontal fixed roof tanks are 

constructed out of steel, steel with a fiberglass overlay, or fiberglass-reinforced polyester, 

and are usually equipped with pressure/vacuum vents, gauge hatches, sample wells, and 

manholes to provide access to the tank. These tanks can be built either above or below 

ground. Below ground tanks generally have storage capacities not exceeding 40,000 

gallons, while aboveground fixed roof tanks can be in excess of 1,000,000 gallons. Vapor 

losses from fixed roof vertical and above-ground horizontal tanks are mainly due to 

changes in atmosphere temperature and pressure as well as liquid levels changes inside the 

tank. As for underground fixed roof tanks, changes in the stored liquid level have the 

largest effect on VOC emissions because the earth limits the effect of atmospheric 

temperature and pressure changes on these tanks. 
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Figure 7-1. Vertical Fixed Roof Tank 

SOURCE: U.S. EPA, 1997, “Organic Liquid Storage Tanks,” Pages 7.1-1 – 7.1-102 in AP-42, Fifth Edition: 

Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources.

7.1.2 External Floating Roof Tanks 

External floating roof tanks consist of an open cylindrical steel shell fitted with a roof that 

floats on the surface of the stored liquid. There are two types of floating roofs, also known 

as decks: the pontoon roof, shown in Figure 7-2 and the double-deck roof shown in Figure 

7-3. Both types of floating decks rise and fall with the liquid level in the tank. This 

process is designed to reduce evaporative tank losses due to fluctuations in the stored 

liquid level and is facilitated through the use of a rim seal system which is attached to the 

deck perimeter and contacts the tank wall. Emissions associated with external floating roof 

tanks are due to standing storage losses from the rim seal system and deck fittings and 

withdrawal losses from the evaporation of exposed liquid on the tank walls. 
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Figure 7-2. Pontoon External Floating Roof Tank 

Figure 7-3. Double-Deck External Floating Roof Tank 

SOURCE: U.S. EPA, 1997, “Organic Liquid Storage Tanks,” Pages 7.1-1 – 7.1-102 in AP-42, Fifth Edition: 

Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources.
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7.1.3 Internal Floating Roof Tanks 

Internal floating roof tanks have two roofs, a permanent fixed roof above a floating roof. 

The fixed roof portion of the internal floating roof tank can be supported either by vertical 

columns within the tank or by a self-supporting system without internal support columns. 

The internal floating roof rises and falls with the stored liquid level, just as in the case of 

the external floating roof tank, and either rests directly on the liquid surface (known as a 

contact deck) or rests on pontoons a few inches above the liquid surface (known as a noncontact deck). A typical internal floating roof tank is shown in Figure 7-4. The majority 

of vapor losses from these tanks comes from deck fittings, non-welded deck seems, and the 

space between the deck and tank walls. Internal floating roof tanks are usually vented to 

the atmosphere at the top of the fixed roof portion of the tank, preventing build-up of 

combustible vapors. 

Figure 7-4. Internal Floating Roof Tank 

SOURCE: United States Environmental Protection Agency, 1997, “Organic Liquid Storage Tanks,” Pages 7.1-1 – 7.1-

102 in AP-42, Fifth Edition: Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and 

Area Sources.
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7.1.4 Domed External Floating Roof Tanks 

Domed external floating roof tanks are a combination of the external and internal floating 

roof tanks. This type of tank is equipped with a floating roof similar to those used in 

external floating roof tanks which is covered by a fixed roof similar to those used for 

internal floating roofs, as seen in Figure 7-5. These tanks are usually the result of 

retrofitting an external floating roof tank with a fixed roof. The fixed roof is usually a self 

supporting aluminum dome roof, whose function is to block the wind from causing 

evaporative losses. 

Figure 7-5. Domed External Floating Roof Tank 

SOURCE: United States Environmental Protection Agency, 1997, “Organic Liquid Storage Tanks,” Pages 7.1-1 – 7.1-

102 in AP-42, Fifth Edition: Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and 

Area Sources.
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7.1.5 Variable Vapor Space Tanks 

Variable vapor space tanks are equipped with expandable vapor reservoirs to accommodate 

vapor fluctuations due to atmosphere temperature and pressure changes. The most 

common types of variable vapor space tanks are the lifter roof tank and the flexible 

diaphragm tank. The lifter roof tank has a telescoping roof that loosely fits the outside of 

the main tank wall. The space between the roof and tank wall is filled with either a wet or 

dry seal. Flexible diaphragm tanks use flexible membranes, and can either be separate gas 

holder units or use a flexible coated fabric. The vapors collected in variable vapor space 

tanks are usually connected to the vapor space of fixed roof tanks. 

7.1.6 Pressure Tanks 

Pressure tanks are designed to store either low pressure (2.5 to 15 psig) or high pressure 

(greater than 15 psig) organic liquids and gases and equipped with a pressure/vacuum vent 

that is designed to prevent venting losses from daily atmospheric temperature and pressure 

changes. Tanks storing high-pressure liquids and gases can be operated so that virtually no 

evaporative losses (emissions due to temperature or pressure changes) or working losses 

(emissions due to changes in liquid levels) occur. However, low pressure tanks can have 

release VOCs atmospheric venting during tank filling. 

7.2 EMISSION INVENTORY 

Table 7-1 identifies the fugitive VOC emissions from storage tanks in the MARAMA 

region for each of the three years, along with the storage capacity of each unit. The 2002 

annual emissions serve as the baseline for future SIP development. The 2002 emissions 

were obtained from the 2002 inventories developed by MANEVU and VISTAS. The 2003 

emissions were obtained directly from each state and represent the most currently quality 

assured data that is available. The 2009 emissions were obtained from the MANEVU and 

VISTAS projection inventories that were developed to support modeling for SIP 

development. The 2009 inventories include the effects of anticipated growth as well as 

any planned controls that will result in emission reductions between 2002 and 2009 due to 

new regulations or enforcement settlements. 
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Table 7-1: Emission Inventory for Storage Tanks 

 Refinery/ Annual VOC Emissions (tons/year)

State Unit 2002 2003 2009 

DE Valero Delaware City 124.0 119.3 114.3 

DE SUNCO Inc Delaware 1.6 1.6 1.5 

NJ Sunoco Eagle Point 216.0 198.6 240.6 

NJ Valero Paulsboro 389.0 387.9 416.1 

NJ Citgo Asphalt 17.0 16.3 19.5 

NJ Amerada Hess Port Reading 235.8 203.1 252.3 

NJ Chevron Products 77.9 69.2 83.3 

NJ ConocoPhillips Bayway 325.7 266.1 347.2 

PA Sunoco Marcus Hook 151.0 152.6 172.0 

PA ConocoPhillips Trainer 76.7 74.7 87.6 

PA American Refining Bradford 12.5 12.5 13.3 

PA Sunoco Philadelphia 145.9 140.1 163.3 

PA United Refining 23.4 25.3 25.7 

VA Giant Yorktown 97.1 130.6 107.6 

WV Ergon West Virginia 23.7 21.4 8.7 

MARAMA Totals 1,793.3 1,700.0 2,053.0 

Note: Storage tank emissions in 2009 were projected using EGAS growth factors; these factors may tend to 

overestimate the expected growth in emissions. MARAMA states are reviewing the latest guidance from 

EPA with respect to projecting emissions from nonEGU sources such as storage tanks. 
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7.3 EXISTING REQUIREMENTS 

This section discusses the regulatory requirements which apply to storage tanks at 

petroleum refineries. Four types of requirements are discussed: (1) Federal requirements 

such as the New Source Performance Standards (NSPS) and Maximum Achievable 

Control Technology (MACT) standards; (2) State regulations for both the MARAMA 

states as well as other State agencies; (3) source-specific permit requirements; and (4) new 

requirements from recent enforcement settlements. 

7.3.1 Federal Requirements 

The U.S. EPA has promulgated standards for emissions of VOCs from petroleum refinery 

storage vessels. 

New Source Performance Standards (NSPS) for petroleum liquid storage vessels are 

covered by three separate subparts of 40 CFR Part 60. Subpart K pertains to storage 

vessels constructed or modified after June 11, 1973 but before May 19, 1978, Subpart Ka 

pertains to storage vessels constructed or modified after May 19, 1978 but before July 23, 

1984, and Subpart Kb pertains to storage vessels constructed or modified after July 23, 

1984. Requirements under each of these subparts are discussed below. 

Subpart K applies to petroleum liquid storage vessels with storage capacities greater than 

40,000 gallons, as well as storage vessels with capacities between 40,000 and 65,000 

gallons that were constructed or modified after March 8, 1974 and before May 19, 1978. 

Storage vessels for petroleum or condensate stored, processed, and/or treated at a drilling 

and production facility prior to custody transfer are exempt from this subpart. Subpart K 

requires storage vessels that store petroleum liquids with true vapor pressures between 1.5 

and 11.1 psia to be equipped with a floating roof and a vapor recovery system, or other 

equivalent equipment. For petroleum liquids with a true vapor pressure greater than 11.1 

psia, a vapor recovery system or equivalent equipment is required. 

Subpart Ka applies to petroleum liquid storage vessels with storage capacities greater than 

40,000 gallons, however storage vessels with storage capacities less than 420,000 gallons 

used for petroleum or condensate stored, processed or treated prior to custody transfer are 

exempt. Storage vessels containing petroleum liquids with true vapor pressures between 

1.5 and 11.1 psia should be equipped with either an external floating roof, a fixed roof with 

an internal floating type cover, a vapor recovery system that collects all VOC vapors and 

discharged gases, or an equivalent system. Storage vessels containing petroleum liquids 

with true vapor pressures greater than 11.1 should be equipped with a vapor recovery 
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system to collect all discharged gases and a vapor return or disposal system to reduce VOC 

emissions by at least 95% by weight. 

Subpart Kb applies to volatile organic liquid (VOL) storage vessels, which includes 

petroleum liquid storage vessels, with capacities greater than or equal to 75 m3

. However, 

this subpart excludes storage vessels with capacities greater than 151 m3

 storing a liquid 

with a maximum true vapor pressure less than 3.5 kPa or vessels with capacities between 

75 and 151 m3 storing a liquid with a maximum true vapor pressure less than 15.0 kPa. 

For storage vessels greater than 151 m3

 in size containing a VOL with a maximum true 

vapor pressure between 5.2 and 76.6 kPa and vessels sized between 75 and 151 m3

 storing 

a VOL with a maximum true vapor pressure between 27.6 and 76.6 kPa should be 

equipped with either a fixed roof with an internal floating roof, an external floating roof, a 

closed vent system and control device, or an equivalent system. Storage vessels with 

capacities greater than 75 m3

 containing a VOL with a maximum true vapor pressure 

greater than or equal to 766 kPa should be equipped with a closed vent system and control 

device or equivalent system. 

The National Emission Standards for Hazardous Air Pollutants (NESHAP) for storage 

vessels are covered in 40 CFR Part 63, Subpart CC, which applies to petroleum refinery 

storage vessels. Under this subpart, Group 1 storage vessels (defined in Table 7-2) are 

required to comply with the requirements of 40 CFR Part 63, Subpart G (NESHAP for the 

synthetic organic chemical manufacturing industry for process vents, storage vessels, 

transfer operations, and wastewater) sections 63.119 through 63.121. These sections 

provide control technology requirements, compliance procedures, and alternative emission 

limits, respectively. 

Table 7-2: Properties of Group 1 Storage Vessels 

Facility 

Design 

Capacity 

Stored-Liquid Maximum 

true vapor pressure 

Annual average HAP 

liquid concentration 

Existing Source ≥ 177 m3

≥ 10.4 kPa 

≥ 8.3 kPa (annual) 

> 4% by wt. 

New Source ≥ 151 m3 ≥ 3.4 kPa > 2% by wt. 

New Source 76 – 151 m3 ≥ 77 kPa > 2% by wt. 
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Section 63.119 requires that Group 1 storage vessels containing liquids with a maximum 

true vapor pressure less than 76.6 kPa be equipped with either a fixed roof and internal 

floating roof, an external floating roof, an external roof converted to an internal roof, a 

closed vent system and control device, route emissions to a process or fuel gas system, or 

perform regular vapor balances. On the other hand, those tanks containing liquids with a 

maximum true vapor pressure greater than or equal to 76.6 kPa must be equipped with 

either a closed vent system and control device, route emissions to a process or fuel gas 

system, or perform regular vapor balances. Specific requirements for each of these 

controls are also spelled out in this regulation. A range of compliance procedures are 

identified depending on the type of control technology used to control emissions from the 

storage vessels, including visual inspections, gap measurements, design evaluations, 

performance tests, etc. Control devices which perform equal to or better than the required 

control technology are also allowed under Administrative approval. 

7.3.2 State Regulations 

Table 7-3 lists the regulations for each of the MARAMA states for the control of VOCs 

from petroleum refinery storage tanks. In Table 7-4, the regulations are listed for 

Louisiana, Texas, and California (from the Bay Area Air Quality Management District – 

BAAQMD, the South Coast Air Quality Management District – SCAQMD, and the San 

Joaquin Valley Air Pollution Control District - SJVAPCD). Regulations from these states 

are presented because these states tend to enforce stricter emission limitations than the 

MARAMA states and the federal government. 

7.3.3 Requirements from Recent Enforcement Settlements 

There are no enforcement settlements for storage tanks at petroleum refineries in the 

MARAMA region. 
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Table 7-3: Summary of MARAMA State Regulations 

Agency Emission Limitations 

Delaware Regulation No. 24, Section 30: 

This Section applies to any petroleum liquid storage tank that is equipped with an external floating roof and that 

has a capacity greater than 40,000 gallons. No owner of a petroleum liquid storage vessel subject to this Section 

shall store a petroleum liquid in that tank unless: 

1. The tank has been fitted with a continuous secondary seal extending from the floating roof to the tank wall or a 

closure or other device that controls VOC emissions with an effectiveness equal to or greater than a secondary 

seal 

2. All seal closure devices meet the following requirements: (a) There are no visible holes, tears, or other openings 

in the seal(s) or seal fabric; (b) The seal(s) are intact and uniformly in place around the circumference of the 

floating roof between the floating roof and the tank wall; and (c) For vapor-mounted primary seals, the 

accumulated area of gaps exceeding 0.125 in. in width between the secondary seal and the tank wall shall not 

exceed 1.0 in.2

/ft of tank diameter 

3. All openings in the external floating roof, except for automatic bleeder vents, rim space vents, and leg sleeves, 

are equipped with: (a) Covers, seals, or lids in the closed position except when the openings are in actual use; 

and (b) Projections into the tank that remain below the liquid surface at all times 

4. Automatic bleeder vents are closed at all times except when the roof is being floated off or being landed on the 

roof leg supports. 

5. Rim vents are set to open when the roof is being floated off the leg supports or at the manufacturer's 

recommended setting. 

6. Emergency roof drains are provided with slotted membrane fabric covers or equivalent covers that cover at least 

90 percent of the area of the opening. 

Regulation No. 24, Section 31: 

This Section applies to any fixed roof petroleum liquid storage tank with a capacity greater than 40,000 gal. No 

owner or operator of a petroleum liquid storage tank subject to this Section shall store 

petroleum liquid in that tank unless: 

1. The tank is equipped with an internal floating roof equipped with a closure seal or seals to close the space 

between the roof edge and tank wall or an equally effective alternative control, approved by the Administrator 

of the U.S. EPA as part of a State Implementation Plan (SIP) or Federal Implementation Plan (FIP) revision. 

2. The tank is maintained such that there are no visible holes, tears, or other openings in the seal or any seal fabric 

or materials. 

3. All openings, except stub drains, are equipped with covers, lids, or seals such that: (a) The cover, lid, or seal is 

in the closed position at all times except when in actual use; (b) Automatic bleeder vents are closed at all times 

except when the roof is being floated off or being landed on the roof leg supports; and (c) Rim vents, if 

provided, are set to open when the roof is being floated off the roof leg supports or at the manufacturer's 

recommended setting. 

New Jersey 7:27-16.2 Storage of volatile organic compounds 

a. The provisions of this section shall apply to stationary storage tanks. 

b. No person shall cause, suffer, allow, or permit the following: 
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1. The storage of any applicable VOC in any stationary storage tank that has a maximum capacity of 2,000 

gallons or greater and is exposed to the rays of the sun unless: 

i. The external surface of the tank is painted and maintained white, except that this provision shall not apply to 

words and logos applied to the external surface of the storage tank for purposes of identification provided 

such symbols do not cover more than 20 percent of the external surface area of the tank's sides and top or 

more than 200 ft2

, whichever is less ; or 

ii. An equivalent method of emission control approved by the Department is used; or 

2. The storage of any applicable VOC in any stationary storage tank having a maximum capacity of 10,000 

gallons or greater unless such stationary storage tank is equipped with control apparatus as determined in 

accordance with the procedures for using Table 2A or as approved by the Department as being equally or more 

effective in preventing the emission of a VOC into the outdoor atmosphere. [Table 2A indicates type of 

control apparatus required (Range I: No control apparatus required under this subsection, Range II: 

Conservation vent required, or Range III: Floating roof required) depending on the stored liquid’s vapor 

pressure and the tank capacity.] 

c. No person shall cause, suffer, allow, or permit the storage of any VOC having a vapor pressure of greater than 

13.0 psia at the actual temperature existing at or near the liquid surface in any stationary storage tank having a 

maximum capacity of 1,000 gallons or greater unless such tank is equipped with a vapor control system to reduce 

the rate of VOC emissions to the outdoor atmosphere by at least 90% by weight of the uncontrolled VOC 

emissions from the tank. 

d. No person shall cause, suffer, allow, or permit the storage of any VOC in any stationary storage tank equipped 

with gauging and/or sampling systems unless such systems are vapor-tight except when gauging or sampling is 

taking place. 

e. Any stationary storage tank in Range III as determined from Table 2A, constructed or installed on or after 

December 17, 1979, shall be provided with a double seal floating roof or other control apparatus approved by the 

Department as being equally or more effective in preventing the emission of any VOC into the outdoor 

atmosphere. 

f. No person shall cause, suffer, allow, or permit the storage of any VOC in any stationary storage tank equipped 

with an external floating roof, unless any such storage tank containing a VOC having a vapor pressure of 1.0 psia 

or greater at standard conditions and having a maximum capacity of 20,000 gallons or greater is equipped with a 

double seal-envelope combination or equipment approved by the Department as being equally or more effective 

in preventing the emission of any VOC into the outdoor atmosphere. For the secondary seal, the gap area of gaps 

exceeding 1/8-inch in width between the seal and the tank wall shall not exceed 1.0 square inch per foot of tank 

diameter. Any secondary seal shall be intact, with no visible holes, tears or other openings. 

g. No person shall cause, suffer, allow, or permit the storage of any VOC in any stationary storage tank equipped 

with an external floating roof unless all openings in such roof, excluding emergency roof drains, are covered 

when not in active use. 

h. Any person responsible for the emission of any applicable VOC from any storage tank pursuant to this section 

shall maintain, for each tank, records specifying each VOC stored and the vapor pressure of each VOC at 

standard conditions. 

Pennsylvania § 129.56. Storage tanks greater than 40,000 gallons capacity containing VOCs. 

a. No person may permit the placing, storing or holding in a stationary tank, reservoir or other container with a 

capacity greater than 40,000 gallons of volatile organic compounds with a vapor pressure greater than 1.5 psia 

(10.5 kPa) under actual storage conditions unless the tank, reservoir or other container is a pressure tank capable 

of maintaining working pressures sufficient at all times to prevent vapor or gas loss to the atmosphere or is 

designed and equipped with one of the following vapor loss control devices: 

1. An external or an internal floating roof. This control equipment may not be permitted if the volatile organic 

compounds have a vapor pressure of 11 psia (76 kPa) or greater under actual storage conditions. 

2. Vapor recovery system. A vapor recovery system, consisting of a vapor gathering system capable of collecting 
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the volatile organic compound vapors and gases discharged and a vapor disposal system capable of processing 

such volatile organic vapors and gases so as to prevent their emission to the atmosphere. Tank gauging and 

sampling devices shall be gas-tight except when gauging or sampling is taking place. The vapor recovery 

system shall be maintained in good working order and recover at least 80% of the vapors emitted by such tank. 

b. An external floating roof shall be fitted with a primary seal and a continuous secondary seal extending from the 

floating roof to the tank wall (rim-mounted secondary seal). The external floating roof shall meet the following 

equipment requirements: 

1. Seal closure devices shall meet the following requirements: (a) There are no visible holes, tears or other 

openings in the seals or seal fabric; (b) The seals are intact and uniformly in place around the circumference of 

the floating roof between the floating roof and the tank wall; and (c) For tanks with vapor-mounted primary 

seals, the accumulated area of gaps exceeding 1/8 inch in width between the secondary seal and the tank wall 

shall not exceed 1 in2

/ft of tank diameter. 

2. Openings in the external floating roof, except for automatic bleeder vents, rim space vents and leg sleeves, are 

as follows: (a) Equipped with covers, seals or lids in the closed position except when the openings are in actual 

use, and (b) Equipped with projections into the tank which remain below the liquid surface at all times. 

3. Automatic bleeder vents are closed at all times except when the roof is floated off or landed on the roof leg 

supports. 

4. Rim vents are set to open when the roof is being floated off the leg supports or at the recommended setting of 

the manufacturer. 

5. Emergency roof drains are provided with slotted membrane fabric covers or equivalent covers which cover at 

least 90% of the area of the opening. 

c. An internal floating roof shall be fitted with a primary seal and shall comply with the following equipment 

requirements: 

1. A closure seal or seals, to close the space between the roof edge and tank wall is used. 

2. There are no holes, tears or other openings in the seal or a seal fabric or materials. 

3. Openings except stub drains are equipped with covers, lids or seals such that: (a) The cover, lid or seal is in the 

closed position at all times except when in actual use; (b) Automatic bleeder vents are closed at all times except 

when the roof is floated off or landed on the roof leg supports; and (c) Rim vents, if provided are set to open 

when the roof is being floated off the roof leg supports or at the recommended setting of the manufacturer. 

d. For the purposes of this section, the petroleum liquid storage vessels listed in this subsection comply with the 

equipment requirements of this section. These tanks shall comply with the maintenance, inspection and reporting 

requirements of this section. These petroleum liquid storage vessels are those either (a) Which contain a 

petroleum liquid with a true vapor pressure less than 4 psia (27.6 kPa) and which are of welded construction and 

which presently possess a metallic-type shoe seal, a liquid-mounted foam seal, a liquid mounted liquid filled type 

seal or other closure device of demonstrated equivalence approved by the Department; or (b) Which are of 

welded construction, equipped with a metallic-type shoe primary seal and has a secondary seal from the top of 

the shoe seal to the tank wall (shoe-mounted secondary seal). 

f. The owner or operator of a petroleum liquid storage vessel with a floating roof subject to this regulation shall: 

1. Perform routine inspections annually. The inspection shall include a visual inspection of the secondary seal 

gap when inspecting external floating roof tanks. 

2. For external floating roof tanks, measure the secondary seal gap annually when the floating roof is equipped 

with a vapor-mounted primary seal. 

3. Maintain records of the types of volatile petroleum liquids stored, the maximum true vapor pressure of the 

liquid as stored, and the results of the inspections performed. Copies of the records shall be retained by the 

owner or operator for a period of 2 years after the date on which the record was made and shall be made 

available to the Department upon written or verbal request at a reasonable time. 

g. For volatile organic compounds whose storage temperature is governed by ambient weather conditions, the 
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vapor pressure under actual storage conditions shall be determined using a temperature which is representative of 

the average storage temperature for the hottest month of the year in which the storage takes place. 

§ 129.57. Storage tanks less than or equal to 40,000 gallons capacity containing VOCs. 

The provisions of this section apply to above ground stationary storage tanks with a capacity equal to or greater 

than 2,000 gallons which contain volatile organic compounds with vapor pressure greater than 1.5 psia (10.5 kPa) 

under actual storage conditions. Storage tanks covered under this section shall have pressure relief valves which 

are maintained in good operating condition and which are set to release at no less than 0.7 psig (4.8 kPa) of 

pressure or 0.3 psig (2.1 kPa) of vacuum or the highest possible pressure and vacuum in accordance with state or 

local fire codes or the National Fire Prevention Association guidelines or other national consensus standards 

acceptable to the Department. 

Philadelphia Reg. 5, Section II. STORAGE TANKS 

A. No person shall place or store in any stationary storage tank or container of 40,000 gallon capacity or greater, 

any organic material having a vapor pressure of 1.5 psia or greater at actual storage conditions unless one of the 

following organic material vapor control devices properly installed and well maintained is in operation: 

1. A floating roof resting on the surface of the liquid contents equipped with a closure seal, or seals, to close the 

space between the roof edge and tank wall, and in addition, all tank gauging and sampling devices shall be gas 

tight except when in use, or 

2. A pressure tank system maintaining a pressure at all times so as to prevent organic material loss to the 

atmosphere, or 

3. A vapor recovery system capable of collecting the organic materials emitted from the tank and disposing of 

these emissions so as to prevent their emission to the atmosphere, and in addition, all tank gauging and 

sampling devices shall be gas-tight except when is use, or 

4. Other equipment equal or greater in efficiency to those devices listed above, and approved by the Department. 

B. No person shall place, or store in any stationary storage tank or container of 40,000 gallon capacity or greater, 

any organic material having a vapor pressure of 11.0 psia or greater at actual storage conditions unless one of the 

following organic material vapor control devices properly installed and well maintained, is in operation: 

1. A pressure tank system maintaining a pressure at all times so as to prevent organic material loss to the 

atmosphere, or 

2. A vapor recovery system capable of collecting the organic materials emitted from the tank and disposing of 

these emissions so as to prevent their emission to the atmosphere, and in addition, all tank gauging and 

sampling devices shall be gas-tight except when in use, or 

3. Other equipment equal or greater in efficiency to those devices listed above, and approved by the Department. 

Virginia 9 VAC 5-40-5220. Standard for volatile organic compounds. 

A. Petroleum liquid storage ─ fixed roof tanks. 

1. No owner or other person shall use or permit the use of any fixed roof tank of more than 40,000 gallons 

capacity for storage of petroleum liquids, unless such tank is equipped with a control method which will 

remove, destroy or prevent the discharge into the atmosphere of at least 90% by weight of volatile organic 

compound emissions. 

2. The owner of a fixed roof tank subject to these provisions shall: 

a. When the fixed roof tank is equipped with an internal floating roof, perform a visual inspection annually of 

the floating cover through roof hatches. (1) The cover should be uniformly floating on or above the liquid 

and there should be no visible defects in the surface of the cover or liquid accumulated on the cover, and (2) 

The seal must be intact and uniformly in place around the circumference of the cover between the cover and 

tank wall. 
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b. Perform a complete inspection of the cover and seal and record the condition of the cover and seal when the 

tank is emptied for non-operational reasons such as maintenance, an emergency, or other similar purposes. 

c. Maintain records of the throughput quantities and types of petroleum liquids stored, the average monthly 

storage temperature and true vapor pressure of the liquid as stored, and the results of the inspections. 

B. Petroleum liquid storage ─ floating roof tanks. 

1. No owner or other person shall use or permit the use of any floating roof tank of more than 40,000 gallons 

capacity for storage of petroleum liquids, unless such tank is equipped with a control method which will 

remove, destroy or prevent the discharge into the atmosphere of at least 90% by weight of volatile organic 

compound emissions. 

2. The owner of a floating roof tank subject to these provisions shall: 

a. Perform routine inspections annually which shall include a visual inspection of the secondary seal gap, and 

b. When the floating roof is equipped with a vapor-mounted primary seal, measure the secondary seal gap 

annually: (1) Physically measuring the length and width of all gaps around the entire circumference of the 

secondary seal in each place where a 1/8-inch uniform diameter probe passes freely (without forcing or 

binding against the seal) between the seal and tank wall; and (2) Summing the area of the individual gaps. 

c. Maintain records of the types of petroleum liquids stored, the maximum true vapor pressure of the liquid as 

stored, and the results of the inspections performed. 

West 

Virginia 

§45-21-27. Petroleum Liquid Storage in External Floating Roof Tanks. 

This section applies to any petroleum liquid storage tank that is equipped with an external floating roof and that 

has a capacity greater than 40,000 gallons. No owner of a petroleum liquid storage vessel subject to this section 

shall store a petroleum liquid in that tank unless: 

a. The tank has been fitted with either a continuous secondary seal extending from the floating roof to the tank 

wall (rim-mounted secondary seal); or a closure or other device that controls VOC emissions with an 

effectiveness equal to or greater than a secondary seal, and is approved by the Director and the U.S. EPA; and 

b. All seal closure devices meet the following requirements: (1) There are no visible holes, tears, or other openings 

in the seal(s) or seal fabric; (2) The seal(s) are intact and uniformly in place around the circumference of the 

floating roof between the floating roof and the tank wall; and (3) For vapor-mounted primary seals, the 

accumulated area of gaps exceeding 0.125 in. in width between the secondary seal and the tank wall shall not 

exceed 1.0 in2

/ft of tank diameter; and 

c. All openings in the external floating roof, except for automatic bleeder vents, rim space vents, and leg sleeves, 

should be equipped with covers, seals, or lids in the closed position except when the openings are in actual use; 

and equipped with projections into the tank that remain below the liquid surface at all times; 

d. Automatic bleeder vents are closed at all times except when the roof is being floated off or being landed on the 

roof leg supports; 

e. Rim vents are set to open when the roof is being floated off the leg supports or at the manufacturer's 

recommended setting; and 

f. Emergency roof drains are provided with slotted membrane fabric covers or equivalent covers which cover at 

least 90 percent of the area of the opening. 

Inspections. -- The owner or operator of a petroleum liquid storage tank with an external floating roof subject to 

this section shall perform routine inspections semiannually in order to ensure compliance (the inspections shall 

include a visual inspection of the secondary seal gap); and measure the secondary seal gap annually when the 

floating roof is equipped with a vapor mounted primary seal. 

§45-21-28. Petroleum Liquid Storage in Fixed Roof Tanks. 
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This section applies to any fixed roof petroleum liquid storage tank with a capacity greater than 40,000 gallons. 

No owner or operator of a petroleum liquid storage tank subject to this section 28. shall store petroleum liquid in 

that tank unless: 

a. The tank is equipped with either an internal floating roof equipped with a closure seal or seals to close the space 

between the roof edge and tank wall; or an equally effective alternative control, approved by the Director and the 

U.S. EPA; 

b. The tank is maintained such that there are no visible holes, tears, or other openings in the seal or any seal fabric 

or materials; and 

c. All openings, except stub drains, are equipped with covers, lids, or seals such that: (1) The cover, lid, or seal is 

in the closed position at all times except when in actual use; (2) Automatic bleeder vents are closed at all times 

except when the roof is being floated off or being landed on the roof leg supports; and (3) Rim vents, if provided, 

are set to open when the roof is being floated off the roof leg supports or at the manufacturer's recommended 

setting. 

Inspections. -- The owner or operator of a petroleum liquid storage tank with a fixed roof subject to this section 

shall: (1) Perform routine, semi-annual, visual inspections of the internal floating roof and its closure seal or seals 

through roof hatches; and (2) Perform a complete inspection of cover and seal whenever the tank is emptied for 

non-operational reasons or at least every 5 years, whichever is more frequent. 
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Table 7-4: Summary of Other State Regulations 

Agency Emission Limitations 

BAAQMD Reg. 8, Rule 5 

8-5-301 Storage Tanks Control Requirements: A person shall not store organic liquid in any storage tank 

unless such tank is equipped with a vapor loss control device that is specified by the table below for the tank 

capacity, or for a higher capacity, and for the true vapor pressure of the tank organic liquid contents, or for a 

higher true vapor pressure. 

Tank True Vapor Pressure of Tank Organic Contents 

Capacity > 0.5 to ≤ 1.5 psia > 1.5 to < 11 psia ≥ 11 psia 

≥ 264 gallons to 

≤ 9,906 gallons, 

aboveground only 

Submerged fill pipe, 

internal floating roof, 

external floating roof, 

or approved emission 

control system 

Pressure vacuum valve, 

internal floating roof, 

external floating roof, or 

approved emission 

control system 

Pressure tank or 

approved emission 

control system 

> 9,906 gallons to 

< 19,803 gallons, 

aboveground only 

Submerged fill pipe, 

internal floating roof, 

external floating roof, 

or approved emission 

control system 

Pressure vacuum valve, 

internal floating roof, 

external floating roof, or 

approved emission 

control system 

Pressure tank or 

approved emission 

control system 

≥ 19,803 gallons to 

< 39,626 gallons 

Submerged fill pipe, 

internal floating roof, 

external floating roof, 

or approved emission 

control system 

Internal floating roof, 

external floating roof, or 

approved emission 

control system 

Pressure tank or 

approved emission 

control system 

≥ 39,626 gallons Internal floating roof, 

external floating roof, 

or approved emission 

control system 

Internal floating roof, 

external floating roof, or 

approved emission 

control system 

Pressure tank or 

approved emission 

control system 

8-5-304 Requirements for External Floating Roofs: All external floating roofs must be equipped with a 

primary and secondary seal. The floating roof must rest on the surface of the liquid tank contents, must be 

properly installed and maintained, and must be in good operating condition. There shall be no liquid tank 

contents on top of either the primary or secondary seal, or on top of the floating roof. 

8-5-305 Requirements for Internal Floating Roofs: An internal floating roof must meet the following 

requirements: 

1. For a tank with seals installed on or before February 1, 1993, the tank must be equipped with either a liquid 

mounted primary seal, mounted in full contact with the liquid in the annular space between the tank shell 

and floating roof, a metallic shoe primary seal, or a vapor mounted primary and a secondary seal. If 

sections of seal with a total length equal to or greater than the diameter of the tank are replaced at one time, 

or if sections of seal with a total cumulative length equal to or greater than 50% of the total seal 

circumference are replaced over time, then the seal shall be considered to be newly installed and subject to 
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subsection 2. 

2. For a tank with seals installed after February 1, 1993, the tank must be equipped with a liquid mounted or 

metallic shoe primary seal and a secondary seal. 

3. Internal floating roof tanks which are placed into service or de-gassed after February 1, 1993 shall be 

equipped with at least 3 viewing ports in the fixed roof of the tank. 

4. The floating roof must rest on the surface of the liquid tank contents, must be properly installed and 

maintained, and must be in good operating condition. There shall be no liquid tank contents on top of either 

the primary or secondary seal, or on top of the floating roof. 

8-5-306 Requirements for Approved Emission Control Systems: An Approved Emission Control System 

must be gas tight. It must also provide an abatement efficiency of at least 95% by weight. 

8-5-320 Tank Fitting Requirements: The fittings on any floating roof storage tank subject to 

Section 8-5-304 or 305 shall meet the following conditions: 

1. All openings through the floating roof, except pressure-vacuum valves and vacuum breaker vents, shall 

provide a projection below the liquid surface to prevent belching of liquid and reduce escaping organic 

vapors. 

2. All openings through the floating roof, except floating roof legs, shall be equipped with a gasketed cover, 

seal or lid, which shall at all times be in a closed position and either (a) the gasketed cover, seal or lid shall 

have no measurable gap exceeding 1/8 in., except when the opening is in use, or for inaccessible openings 

on internal floating roof tanks, there shall be no visible gaps as viewed from the fixed roof man way or view 

ports, except when the opening is in use. 

3. Solid sampling or gauging wells, and similar fixed projections through a floating roof such as an antirotational pipe, shall: (a) the well shall provide a projection below the liquid surface; (b) the well shall be 

equipped with a cover, seal or lid, which shall at all times be in a closed position with no gap exceeding 1/8 

in., except when the well is in use, and (c) the gap between the well and the roof shall be added to the gaps 

measured to determine compliance of the secondary seal and in no case shall exceed 1/2 in. 

4. Slotted sampling or gauging wells, and similar fixed projections through a floating roof such as an antirotational pipe, shall: (a) The well shall provide a projection below the liquid surface, (b) the well shall be 

equipped with the following: a sliding cover, a cover gasket, a pole sleeve, pole wiper and an internal float 

and float wiper designed to minimize the gap between the float and the well, provided that the gap shall in 

no case exceed 1/2 in., or shall be equipped with a well gasket, a zero gap pole wiper seal and a pole sleeve 

that projects below the liquid surface, and (c) the gap between the well and the roof shall be added to the 

gaps measured to determine compliance of the secondary seal and in no case shall exceed 1.3 cm (1/2 in.). 

5. Any emergency roof drain shall be provided with a slotted membrane fabric cover, or equivalent, that 

covers at least 90% of the area of the opening. 

8-5-321 Primary Seal Requirements: A person shall not operate a storage tank equipped with a primary seal 

subject to the requirements of Section 8-5-304 or 305 unless such tank meets the following conditions: 

1. There shall be no holes, tears, or other openings in the primary seal fabric which allow the emission of 

organic vapors. 

2. The seal shall be either a metallic shoe or a liquid mounted type. 

3. Metallic-shoe-type seals shall be installed so that one end of the shoe extends into the stored liquid and the 

other end extends a minimum vertical distance of 24 in. for external floating roofs and 18 inches for internal 

floating roofs above the stored liquid surface. 

a. The geometry of the shoe shall be such that the maximum gap between the shoe and the tank shell is no 

greater than double the gap allowed by the seal gap criteria for a length of at least 18 in. in the vertical 

plane above the liquid surface. 

b. For welded tanks, no gap between the tank shell and the primary seal shall exceed 1-1/2 in. No 

continuous gap greater than 1/8 in. shall exceed 10% of the circumference of the tank. The cumulative 
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length of all primary seal gaps exceeding 1/2 in. shall be not more than 10% of the circumference, and the 

cumulative length of all primary seal gaps exceeding 1/8 in. shall be not more than 40% of the 

circumference. 

c. For riveted tanks, no gap between the tank shell and the primary seal shall exceed 2-1/2 in. The 

cumulative length of all primary seal gaps exceeding 1-1/2 in. shall be not more than 10% of the 

circumference. 

4. For resilient-toroid-seal equipped tanks, no gap between the tank shell and the primary seal shall exceed 

1/2 in. The cumulative length of all gaps exceeding 1/8 in. shall be not more than 5% of the circumference. 

8-5-322 Secondary Seal Requirements: A person shall not operate a storage tank equipped with a secondary 

seal subject to the requirements of Sections 8-5-304 or 305, unless such tank meets the following conditions: 

1. There shall be no holes, tears, or other openings in the secondary seal fabric which allow the emission of 

organic vapors. 

2. The secondary seal shall allow easy insertion of probes up to 1-1/2 in. in width in order to measure gaps in 

the primary seal. 

3. No gap between the tank shell and the secondary seal shall exceed 1/2 in. The cumulative length of all 

secondary seal gaps exceeding 1/8 in. shall be not more than 5% of the circumference of the tank. 

4. For riveted tanks, the secondary seal shall consist of at least two sealing surfaces, such that the sealing 

surfaces prevent the emission of organic compounds around the rivets. Serrated sealing surfaces are 

allowable if the length of serration does not exceed 6 in. 

5. For welded external floating roof tanks with seals installed after September 4, 1985 or welded internal 

floating roof tanks with seals installed after February 1, 1993, no gap between the tank shell and the 

secondary seal shall exceed 0.06 in. The cumulative length of all secondary seal gaps exceeding 0.02 in. 

shall be not more than 5% of the circumference of the tank excluding gaps less than 1.79 in. from vertical 

weld seams. If sections of seal with a total length equal to or greater than the diameter of the tank are 

replaced at one time, or if sections of seal with a total cumulative length equal to or greater than 50% of the 

total seal circumference are replaced over time, then the seal shall be considered to be newly installed for 

the purpose of this section. 

6. The secondary seal shall extend from the roof to the tank shell and shall not be attached to the primary seal. 

Louisiana Section 2103. 

§2103. Storage of Volatile Organic Compounds 

A. No person shall place, store, or hold in any stationary tank, reservoir, or other container of 250 – 40,000 

gallons nominal capacity any volatile organic compound, having a maximum true vapor pressure ≥ 1.5 psia 

at storage conditions, unless such tank, reservoir, or other container is designed and equipped with a 

submerged fill pipe or a vapor loss control system, or is a pressure tank capable of maintaining working 

pressures sufficient at all times under normal operating conditions to prevent vapor or gas loss to the 

atmosphere. 

B. No person shall place, store, or hold in any stationary tank, reservoir, or other container > 40,000 gallons 

nominal capacity any volatile organic compound having a maximum true vapor pressure ≥ 1.5 psia at 

storage conditions unless such tank, reservoir, or other container is a pressure tank capable of maintaining 

working pressures sufficient at all times under normal operating conditions to prevent vapor or gas loss to 

the atmosphere or is designed and equipped with a submerged fill pipe and one or more of the vapor loss 

control devices described in Subsections C, D, and E of this Section. 

C. Internal Floating Roof. An internal floating roof consists of a pontoon type roof, double deck type roof, or 

internal floating cover which will rest or float on the surface of the liquid contents and is equipped with a 

closure seal to close the space between the roof edge and tank wall. All tank gauging and sampling devices 

shall be gas tight except when gauging or sampling is taking place. If the organic compounds have a vapor 

pressure ≥ 11.0 psia under actual storage conditions, the requirements of Subsection F of this Section shall 
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supersede the requirements of this Subsection. In the parishes of Ascension, Calcasieu, East Baton Rouge, 

Iberville, Livingston, Pointe Coupee, and West Baton Rouge, the following additional requirements apply. 

1. The closure seal shall consist of either: (a) a liquid mounted seal consisting of a foam- or liquid-filled 

seal mounted in contact with the liquid between the wall of the storage vessel and the floating roof 

continuously around the circumference of the tank; (b) a mechanical shoe seal (metallic-type shoe seal) 

consisting of a metal sheet held vertically against the wall of the storage vessel by springs or weighted 

levers and connected by braces to the floating roof. A flexible coated fabric (envelope) spans the annular 

space between the metal sheet and the floating roof; or (c) two seals mounted one above the other so that 

each forms a continuous closure that completely covers the space between the wall of the storage vessel 

and the edge of the internal floating roof. The lower seal may be vapor-mounted, but both must be 

continuous. 

2. Each opening in the internal floating roof (except rim space vents and automatic bleeder vents) shall be 

provided with a projection below the liquid surface. In addition, each opening (except for leg sleeves, 

bleeder vents, rim space vents, column wells, ladder wells, sample wells, and stub drains) shall be 

provided with a cover equipped with a gasket. Automatic bleeder vents and rim space vents shall be 

gasketed and ladder wells shall be equipped with a sliding cover. 

D. External Floating Roof. An external floating roof consists of a pontoon type roof, double deck type roof, or 

external floating cover which will rest or float on the surface of the liquid contents and is equipped with a 

primary closure seal to close the space between the roof edge and tank wall and a continuous secondary seal 

(a rim mounted secondary) extending from the floating roof to the tank wall. In the parishes of Ascension, 

Calcasieu, East Baton Rouge, Iberville, Livingston, Pointe Coupee, and West Baton Rouge, the primary 

closure seal shall consist of a liquid mounted seal or a mechanical shoe seal 

1. A secondary seal is not required if (a) the tank is a welded tank storing a VOC with a vapor pressure at 

storage conditions < 4.0 psia and is also equipped with a liquid mounted seal, a mechanical shoe seal, or a 

seal deemed equivalent by the administrative authority; (b) the storage vessels are external floating roof 

tanks having nominal storage capacities ≤ 420,000 gallons used to store produced crude oil or condensate 

prior to lease custody transfer; (c) a mechanical shoe seal is used in a welded tank which also has a 

secondary seal from the top of the shoe seal to the tank wall (i.e., a shoe-mounted secondary); or (d) an 

alternate seal or seals can be used in lieu of the primary and secondary seals required herein provided the 

resulting emission is not greater than that which would have resulted if the primary and secondary seals 

were installed. 

2. The required seal closure devices shall: (a) have no visible holes, tears, or other openings in the seal(s) or 

seal(s) fabric; (b) be intact and uniformly in place around the circumference of the floating roof and the 

tank wall; (c) not have gap areas, of gaps exceeding 1/8 inch in width between the secondary seal and the 

tank wall, in excess of 1.0 in2

/ft of tank diameter; (d) not have gap areas, of gaps exceeding 1/8 inch in 

width between the primary seal and the tank wall, in excess of 10.0 in2

/ft of tank diameter; and (e) the 

secondary seals shall be visually inspected at least semiannually. The secondary seal gap measurements 

shall be made annually at any tank level provided the roof is off its legs. The primary seal gap 

measurements shall be made every five years at any tank level provided the roof is off its legs. 

3. Requirements for Covering Openings. All openings in the external floating roof, except for automatic 

bleeder vents, rim space vent, and leg sleeves, are to provide a projection below the liquid surface. Except 

for automatic bleeder vents, rim space vents, roof drains, and leg sleeves, each opening in the roof is to be 

equipped with a cover, seal, or lid that is to be maintained in a closed position at all times (i.e., no visible 

gap) except when the device is in actual use. Automatic bleeder vents must be closed at all times except 

when the roof is floated off or landed on the roof leg supports. Rim vents must be set to open when the 

roof is being floated off the roof leg supports or at the manufacturer's recommended setting. Any 

emergency roof drain must be equipped with a slotted membrane fabric cover or equivalent cover that 

covers at least 90 percent of the opening. In the parishes of Ascension, Calcasieu, East Baton Rouge, 

Iberville, Livingston, Point Coupee, and West Baton Rouge, all covers, seals, lids, automatic bleeder 

vents, and rim space vents are to be gasketed. 

4. Requirements for Guide Poles and Stilling Well Systems. Emissions from guide pole systems must be 

controlled for external floating roof storage tanks with a capacity > 40,000 gallons and which store a 
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liquid having a total vapor pressure ≥ 1.5 psia. The requirements of this Paragraph shall only apply in the 

parishes of Ascension, Calcasieu, East Baton Rouge, Iberville, Livingston, Pointe Coupee, and West 

Baton Rouge. 

a. Controls for non-slotted guide poles and stilling wells shall include pole wiper and gasketing between 

the well and sliding cover. Controls for slotted guide poles shall include a float with wiper, pole wiper, 

and gasketing between the well and sliding cover. 

b. Alternate methods of controls are acceptable if demonstrated to be equivalent and approved by the 

administrative authority. 

c. Control systems required by Paragraph D.4 of this Section shall be inspected semiannually for rips, 

tears, visible gaps in the pole or float wiper, and/or missing sliding cover gaskets. Any rips, tears, 

visible gaps in the pole or float wiper, and/or missing sliding cover gaskets shall be repaired in 

accordance with this Paragraph in order to avoid noncompliance. 

E. Vapor Loss Control System. A vapor loss control system consists of a gathering system capable of 

collecting the VOC vapors and a vapor disposal system capable of processing such organic vapors. All tank 

gauging and sampling devices shall be gas-tight except when gauging or sampling is taking place. 

1. The vapor loss control system shall reduce inlet emissions of total volatile organic compounds by 95 

percent or greater. 

2. If the vapor loss control system was installed on or before December 31, 1992, then the vapor loss 

control system shall reduce inlet emissions of total volatile organic compounds by 90 percent or greater. 

3. These specifications and requirements do not apply during periods of planned routine maintenance. 

Periods of planned routine maintenance of the vapor loss control system shall not exceed 240 hours per 

year. 

F. No person shall place, store or hold in any stationary tank, reservoir or other container > 40,000 gallons 

nominal capacity any VOC having a true vapor pressure ≥ 11 psia at storage conditions unless such tank, 

reservoir or other container is a pressure tank capable of maintaining working pressures sufficient at all 

times under normal operating conditions to prevent vapor or gas loss to the atmosphere or is designed and 

equipped with a submerged fill pipe and vapor loss control system. 

SCAQMD Rule 1178 

The rule applies to all aboveground storage tanks that have capacity ≥ 19,815 gallons, are used to store 

organic liquids with a true vapor pressure > 0.1 psia under actual storage conditions, and are located at any 

petroleum facility that emits > 20 tons per year of VOC in any emission inventory year starting with the 

emission inventory year 2000. 

External Floating Roof Tanks 

A. The operator of an external floating roof tank containing organic liquids having true vapor pressure of < 3 

psia at any petroleum facility with annual VOC emissions > 20 tons for emission inventory year 2000 shall: 

(1) Equip each access hatch and gauge float well with a cover that is gasketed and bolted; (2) Equip each 

gauge hatch/sample well with a cover that is gasketed; (3) Gasket or cover each adjustable roof leg with a 

VOC impervious sock at all times when the roof is floating; (4) Gasket each rim vent; (5) Gasket each 

vacuum breaker; (6) Equip each open floating roof drain with a slotted membrane fabric cover that covers 

at least 90 percent of the area of the opening; (7) Equip each unslotted guidepole well with a gasketed 

sliding cover and a flexible fabric sleeve or wiper; (8) Equip each unslotted guidepole with a gasketed cover 

at the end of the pole; (9) Equip each slotted guidepole with a gasketed cover, a pole wiper and a pole 

sleeve extended into the stored liquid, (10) Equip each slotted guidepole having a pole float with a gasketed 

cover, a pole wiper, and a pole float wiper; (11) Cover each slotted guidepole opening with a gasketed 

cover at all times; (12) Maintain the pole float in a condition such that it floats within the guidepole; (13) 

Except for vacuum breakers and rim vents, ensure that each opening in the external floating roof shall 

provide a projection below the liquid surface; and (14) Except for vacuum breakers, rim vents, roof drains, 

and leg sleeves, equip all other openings in the roof with a gasketed cover or seal which is closed at all 
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times, with no visible gaps, except when the cover or seal must be opened for access. 

B. The operator of an external floating roof tank containing organic liquids having true vapor pressure of < 3 

psia at any petroleum facility with annual VOC emissions > 20 tons for emission inventory year 2000 shall 

equip the tank with a rim seal system meeting the following requirements: 

1. The primary seal shall be a mechanical shoe or liquid mounted. 

2. The secondary seal shall be rim mounted and shall not be attached to the primary seal. 

3. Gaps between the tank shell and the primary seal shall not exceed 1/2 inch for a cumulative length of 

30% of the circumference of the tank, and 1/8 inch for 60% of the circumference of the tank. No gap 

between the tank shell and the primary seal shall exceed 1-1/2 inches. No continuous gap between the 

tank shell and the primary seal greater than 1/8 inch shall exceed 10% of the circumference of the tank. 

4. Gaps between the tank shell and the secondary seal shall not exceed 1/8 inch for a cumulative length of 

95% of the circumference of the tank. No gap between the tank shell and the secondary seal shall exceed 

1/2 inch. 

5. Mechanical shoe primary seals shall be installed so that one end of the shoe extends into the stored 

organic liquid and the other end extends a minimum vertical distance of 24 inches above the stored 

organic liquid surface. 

6. The geometry of the shoe shall be such that the maximum gap between the shoe and the tank shell is no 

greater than double the gap allowed by the seal gap criteria for a length of at least 18 inches in the vertical 

plane above the liquid surface. 

7. The primary seal envelope shall be made available for unobstructed inspection by the Executive Officer 

along its circumference. In the case of riveted tanks with resilient filled primary seals, at least 8 such 

locations shall be made available; for all other types of seals, at least 4 such locations shall be made 

available. If the Executive Officer deems it necessary, further unobstructed inspection of the primary seal 

may be required to determine the seal's condition along its entire circumference. 

8. The secondary seal shall be installed in a way that permits the Executive Officer to insert probes up to 1-

1/2 inches in width to measure gaps in the primary seal. 

9. There shall be no holes, tears or openings in the secondary seal or in the primary seal envelope 

surrounding the annular vapor space enclosed by the roof edge, seal fabric, and secondary seal. 

10. Except during the preventive maintenance, repair, or inspection periods that do not exceed 72 hours 

with prior notification to the Executive Officer, both the primary seal and the secondary seal shall cover 

the annular space between the external floating roof and the wall of the storage tank in a continuous 

fashion, with no visible gaps. 

11. The operator shall use a rim seal system that is identified on the current list of seals approved by the 

Executive Officer. 

C. In lieu of complying with the requirement of no visible gap, the operator of an external floating roof tank 

shall maintain all roof openings in a vapor tight condition at all times except during preventive maintenance, 

repair, or inspection periods. 

Domed External Floating Roof Tanks 

A. Phase I: The operator at any petroleum facility with annual VOC emissions > 20 tons for emission 

inventory year 2000 shall install domed roofs on all external floating roof tanks that contain organic liquids 

having true vapor pressure ≥ 3 psia for the emission inventory year 2000 according to the following 

schedule: 

1. All tanks subject to this provision by January 1, 2008. 

2. As an alternative, an operator may submit a compliance plan demonstrating that 75% of the tanks subject 

to this provision have domes installed by December 31, 2006, and 100% of such tanks shall have domes 

installed by December 31, 2008. 
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B. Phase II: For additional external floating roof tanks that are not identified under Phase I but contain 

organic liquids having true vapor pressure ≥ 3 psia for any emission inventory year after 2000, the operator 

who is subject to Phase I shall comply with these requirements no later than 2 years after becoming subject 

to the rule. 

C. In lieu of complying with the requirements in subparagraph B., the operator who is subject to Phase I shall 

accept permit conditions to limit the true vapor pressure of the organic liquids stored in the tanks to < 3 psia 

by the end of Phase I. 

D. The operator of a domed external floating roof tank shall equip the tank with a rim seal system consisting 

of a primary and a secondary seal 

E. The operator shall ensure that the concentration of organic vapor in the vapor space above a domed 

external floating roof shall not exceed 30% of its lower explosive limit (LEL) by the applicable compliance 

F. The operator shall submit to the Executive Officer an annual status report including at a minimum all of the 

following: 

1. A list of all external floating roof tanks subject to these requirements; 

2. A general description of each tank including information such as tank identification, District permit 

number or District device identification, tank type, tank capacity, type of liquid stored, and if applicable, 

number of representative samples, frequency of sampling, averaging method used to determine the 

monthly average true vapor pressure of waste stream or recovered oil tanks, and the results. 

3. A compliance status for each tank; and 

4. An estimated compliance date for each external floating roof tank that is not yet in compliance. 

Internal Floating Roof Tanks 

When an internal floating roof tank is scheduled for emptying and degassing, but no later than January 1, 

2007, the operator of an internal floating roof tank at any petroleum facility with annual VOC emissions > 20 

tons for emission inventory year 2000 shall: 

A. Equip each fixed roof support column and well with a sliding cover that is gasketed or with flexible fabric 

sleeves; 

B. Equip each ladder well with a gasketed cover. 

C. Equip the tank with a rim seal system consisting of either a primary seal, or a primary and a secondary 

seal; and 

D. Ensure that the concentration of organic vapor in the vapor space above the internal floating roof shall not 

exceed 50% of its lower explosive limit (LEL) for those installed prior to June 1, 1984 and 30% of its LEL 

for those installed after June 1, 1984. 

Fixed Roof Tanks 

A. No later than January 1, 2007, the operator of a fixed roof tank at any petroleum facility with annual VOC 

emissions > 20 tons for emission inventory year 2000 shall equip each fixed roof tank containing organic 

liquids with true vapor pressure > 0.1 psia with an emission control system meeting the following 

requirements: 

1. The tank emissions are vented to an emission control system with an overall control efficiency ≥ 95% by 

wt or the tank emissions are vented to a fuel gas system. 

2. Any tank gauging or sampling device on a tank shall be equipped with a vapor tight cover which shall be 

closed at all times, with no visible gaps, except during gauging or sampling. 

3. All openings on the roof shall be properly installed and maintained in a vapor tight condition at all times. 

4. The operator shall equip each fixed roof tank with pressure vacuum vents that shall be set to the lesser of 

10% below the maximum allowable working pressure of the roof or 0.5 psig. 

5. The operator shall maintain pressure-vacuum vents in a vapor tight condition at all times except when the 
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operating pressure of the fixed roof tank exceeds the manufacturer’s recommended setting. 

B. In lieu of complying with the requirement in subparagraph A., the operator may choose to convert the 

fixed roof tank to an external floating roof tank or an internal floating roof tank and meet the requirements 

for those types of roofs. 

General Tank Compliance Requirements 

The operator of any petroleum facility with annual VOC emissions > 20 tons for any emission inventory year 

subsequent to 2000 shall: 

A. Comply with the requirements for external floating roof tanks no later than 1 year after becoming subject 

to this rule. 

B. Comply with the requirements for domed external floating roof tanks no later than 6 years after becoming 

subject to this rule. Any external floating roof tank that later becomes subject to this requirement based on 

any subsequent emission inventory year, shall comply with the requirements no later than 2 years after 

becoming subject to this rule. 

C. Comply with the requirements for internal floating roof tanks when the tanks are scheduled for emptying 

and degassing, but no later than 5 years after becoming subject to this rule. 

D. Comply with the requirements for fixed roof tanks no later than 5 years after becoming subject to this rule. 

SJV APCD Rule 4623 

This rule applies to any tank with a capacity ≥ 1,100 gallons in which any organic liquid is placed, held, or 

stored. 

VOC Control System Requirements 

A. General VOC Control System Requirements: Except for small producers, an operator shall not place, 

hold, or store organic liquid in any tank unless such tank is equipped with a VOC control system identified 

in Table 1. 

Table 1 – General VOC Control System Requirements 

Tank Capacity True Vapor Pressure (TVP) of Organic Liquid 

(Gallons) 

0.5 psia to < 1.5 psia 1.5 psia to < 11 psia ≥ 11.0 psia 

(Group A) 

1,100 – 19,800 

Pressure-vacuum relief 

valve, or internal 

floating roof, or external 

floating roof, or vapor 

recovery system 

Pressure-vacuum relief 

valve, or internal 

floating roof, or external 

floating roof, or vapor 

recovery system. 

Pressure vessel or vapor 

recovery system 

(Group B) 

> 19,800 – 39,600 

Pressure-vacuum relief 

valve, or internal 

floating roof, or external 

floating roof, or vapor 

recovery system. 

Internal floating roof, or 

external floating roof, or 

vapor recovery system. 

Pressure vessel system 

or vapor recovery 

system. 

(Group C) 

> 39,600 

Internal floating roof, or 

external floating roof, or 

vapor recovery system. 

Internal floating roof, or 

external floating roof, or 

vapor recovery system. 

Pressure vessel or vapor 

recovery system. 
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B. Small Producer VOC Control System Requirements: A small producer shall not place, hold, or store crude 

oil in any tank unless such tank is equipped with a VOC control system identified in Table 2. 

Table 2 – Small Producer VOC Control System Requirements for Crude Oil Storage Tanks 

Tank Capacity True Vapor Pressure (TVP) of Organic Liquid 

(Gallons) 

0.5 psia to < 11 psia 

and a tank throughput 

of > 50 to < 150 barrels 

of crude oil per day 

0.5 psia to < 11 psia 

and a tank throughput 

of ≥ 150 barrels of 

crude oil per day 

≥ 11.0 psia and 

regardless of crude oil 

tank throughput 

(Group A) 

1,100 – 39,600 

Pressure-vacuum relief 

valve, or internal 

floating roof, or external 

floating roof, or vapor 

recovery system 

Pressure-vacuum relief 

valve, or internal 

floating roof, or external 

floating roof, or vapor 

recovery system. 

Pressure vessel or vapor 

recovery system 

(Group B) 

> 39,600 

Pressure-vacuum relief 

valve, or internal 

floating roof, or external 

floating roof, or vapor 

recovery system. 

Internal floating roof, or 

external floating roof, or 

vapor recovery system. 

Pressure vessel system 

or vapor recovery 

system. 

C. All tanks subject to the control requirements of this rule shall be maintained in a leak-free condition, 

except for (a) Primary seals and secondary seals of external floating roof tanks; (b) Primary seals and 

secondary seals of internal floating roof tanks; (c) Floating roof deck fittings; and (d) Floating roof 

automatic bleeder 

Specifications for External Floating Roof Tanks 

A. An external floating roof tank shall be: 

1. Equipped with a floating roof consisting of a pan type that is installed before December 20, 2001, 

pontoon-type, or double-deck type cover, that rests on the surface of the liquid contents; and 

2. Equipped with a closure device between the tank shell and roof edge consisting of two seals, one above 

the other; the one below shall be referred to as the primary seal, and the one above shall be referred to as 

the secondary seal. 

3. The floating roof shall be floating on the surface of the stored liquid at all times except during the initial 

fill until the roof is lifted off the leg supports and when the tank is completely emptied and subsequently 

refilled. 

B. Seal designs shall be submitted to the APCO and shall not be installed or used unless they are approved by 

the APCO as meeting the following criteria: 

1. Welded Tanks with Primary Metallic-Shoe Type Seal 

a. No gap between the tank shell and the primary seal shall exceed 1-1/2 inches. The cumulative length of 

all gaps between the tank shell and the primary seal > 1/2 inch shall not exceed 10% of the 

circumference of the tank. The cumulative length of all primary seal gaps >1/8inch shall not exceed 

30% of the tank circumference. No continuous gap > 1/8 inch shall exceed 10% of the tank 

circumference. 
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b. No gap between the tank shell and the secondary seal shall exceed 1/2 inch. The cumulative length of 

all gaps between the tank shell and the secondary seal, > 1/8 inch shall not exceed 5% of the tank 

circumference. 

c. Metallic-shoe-type seals shall be installed so that one end of the shoe extends into the stored liquid and 

the other end extends a minimum vertical distance of 24 inches above the stored liquid surface. 

d. The geometry of the metallic-shoe type seal shall be such that the maximum gap between the shoe and 

the tank shell is no greater than double the gap allowed by the seal gap criteria for a length of at least 

18 inches in the vertical plane above the liquid surface. 

e. There shall be no holes, tears, or openings in the secondary seal or in the primary seal envelope that 

surrounds the annular vapor space enclosed by the roof edge, seal fabric, and secondary seal. 

f. The secondary seal shall allow easy insertion of probes up to 1-1/2 inches in width in order to measure 

gaps in the primary seal. 

g The secondary seal shall extend from the roof to the tank shell and shall not be attached to the primary 

seal. 

2. Riveted Tank with Primary Metallic-Shoe Type Seal 

a. No gap between the tank shell and the primary seal shall exceed 2-1/2 inches. The cumulative length of 

all primary seal gaps > 1-1/2 inches shall be not exceed 10% of the circumference of the tank. The 

cumulative length of all gaps between the tank shell and the primary seal > 1/8 inch shall not exceed 

30% of the circumference of the tank. No continuous gap > 1/8 inch shall exceed 10% of the tank 

circumference. 

b. No gap between the tank shell and the secondary seal shall exceed 1/2 inch. The cumulative length of 

all gaps between the tank shell and the secondary seal > 1/8 inch shall not exceed 5% of the tank 

circumference. 

c. Metallic shoe-type seals shall be installed so that one end of the shoe extends into the stored liquid and 

the other end extends a minimum vertical distance of 24 inches above the stored liquid surface. 

d. There shall be no holes, tears, or openings in the secondary seal or in the primary seal envelope that 

surrounds the annular vapor space enclosed by the roof edge, seal fabric, and secondary seal. 

e. The secondary seal shall allow easy insertion of probes up to 2-1/2 inches in width in order to measure 

gaps in the primary seal. 

f. The secondary seal shall extend from the roof to the tank shell and shall not be attached to the primary 

seal. 

3. Tanks with Primary Resilient Toroid Seal: 

a. The primary resilient toroid seal shall be mounted on the perimeter of the roof such that it is in contact 

with the tank’s liquid contents at all times while the roof is floating. 

b. No gap between the tank shell and the primary seal shall exceed 1/2 inch. The cumulative length of all 

primary seal gaps > 1/8 inch shall not exceed 5% of the tank circumference. No continuous gap > 1/8 

inch shall exceed 10% of the tank circumference. 

c. No gap between the tank shell and the secondary seal shall exceed 1/2 inch. The cumulative length of 

all gaps between the tank shall and the secondary seal, > 1/8 inch shall not exceed 5% of the tank 

circumference. 

d. There shall be no holes, tears, or openings in the secondary seal or in the primary seal envelope that 

surrounds the annular vapor space enclosed by the roof edge, seal fabric, and secondary seal. 

e. The secondary seal shall allow easy insertion of probes up to 1/2 inch in width in order to measure gaps 

in the primary seal. 

f. The secondary seal shall extend from the roof of the tank to the shell and not be attached to the primary 
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seal. 

4. The following seal designs have been found to be equivalent to seals meeting the criteria set forth in 

Sections B.1 through B.3: 

a. When installed and maintained with zero gap: 

Manufacturer Model 

Republic Fabricators WeatherGuard Seal 

5.3.2.4.2 When installed and maintained to meet the gap criteria for primary and secondary seals set forth 

in Sections B.1 through B.3: 

Manufacturer Model 

“HMT” Dual/Multi Blade Wiper Seals 

Specifications for Internal Floating Roof Tanks 

A. Internal floating roof tanks shall be equipped with seals that meet the criteria set forth for external floating 

roof tanks, except for complying with the requirement specified metallic-shoe type seals. For internal 

floating roof, the metallic-shoe type seals shall be installed so that one end of the shoe extends into the 

stored liquid and the other end extends a minimum vertical distance of 18 inches above the stored liquid 

surface. 

B. The following seal designs have been found to be equivalent to seals meeting the criteria set forth for 

external floating roof tanks: 

1. When installed and maintained with zero gap: 

Manufacturer Model 

Ultraflote Single Ultraseal 

2. When installed and maintained to meet the gap criteria for primary and secondary seals: 

Manufacturer Model 

Ultraflote Dual Ultraseal 

Altech Double Wiper Seal 

C. The operator shall comply with the floating roof landing requirements 

Floating Roof Deck Fitting Requirements 

A. All openings in the roof used for sampling or gauging, shall provide a projection below the liquid surface 

to prevent belching of liquid and to prevent entrained or formed organic vapor from escaping from the 

liquid contents of the tank and shall be equipped with a cover, seal, or lid. The cover, seal, or lid shall at all 

times be in a closed position, with no visible gaps and leak-free, except when the device or appurtenance is 

in use for sampling or gauging. 

B. Tanks shall meet the following requirements: 

1. Requirements for Internal Floating Roof Deck Fittings 

a. Each opening in a non-contact internal floating roof except for automatic bleeder vents (vacuum 

breaker vents) and rim space vents shall provide a projection below the liquid surface. 
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b. Each opening in the internal floating roof except for leg sleeves, automatic bleeder vents, rim space 

vents, column wells, ladder wells, sample wells, combination man way/vacuum breakers, and stub 

drains shall be equipped with a cover, or a lid shall be maintained in a closed position at all times (i.e., 

no visible gap) except when the device is in use. The cover or lid shall be equipped with a gasket. 

Covers on each access hatch and automatic gauge float well shall be bolted in place except when they 

are in use. 

c. Automatic bleeder vents shall be equipped with a gasket and shall be closed at all times when the roof 

is floating except when the roof is being floated off or is being landed on the leg roof supports. 

d. Rim vents shall be equipped with a gasket and shall be set to open only when the internal floating roof 

is not floating or set to open at the manufacturer’s recommended setting. 

e. Each penetration of the internal floating roof for the purpose of sampling shall be a sample well. The 

well shall have a slit fabric cover that covers at least 90% of the opening. The fabric cover must be 

impermeable. 

f. Each penetration of the internal floating roof that allows for passage of a column supporting the fixed 

roof shall have a flexible fabric sleeve seal or a gasketed sliding cover. The fabric sleeve must be 

impermeable. 

2. Requirements for External Floating Roof Deck Fittings 

a. Except for automatic bleeder vents, rim vents, and pressure vacuum relief vents, each opening in a noncontact external floating roof shall provide a projection below the liquid surface. 

b. Except for automatic bleeder vents and rim vents, roof drains, and leg sleeves, each opening in the roof 

shall be equipped with a gasketed cover, seal, or lid that shall be maintained in a closed position at all 

times (i.e., no visible gap) except when in actual use. 

c. Automatic bleeder vents shall be equipped with a gasket and shall be closed at all times when the roof 

is floating except when the roof is being floated off or is being landed on the roof leg supports. 

d. Rim vents shall be equipped with a gasket and shall be set to open when the roof is being floated off 

the roof leg supports or at the manufacturer’s recommended setting. 

e. Each emergency roof drain shall be provided with a slotted membrane fabric cover that covers at least 

90% of the area of the opening. The fabric cover must be impermeable if the liquid is drained into the 

contents of the tanks. 

f. External floating roof legs shall be equipped with vapor socks or vapor barriers in order to maintain a 

leak-free condition so as to prevent VOC emissions from escaping through the roof leg opening. 

3. Solid Guidepole: Solid sampling or gauging wells, and similar fixed projections through a floating roof 

such as an anti- rotational pipe, shall meet the following requirements: 

a. The well shall provide a projection below the liquid surface. 

b. The well shall be equipped with a pole wiper and a gasketed cover, seal or lid which shall be in a 

closed position at all times (i.e., no visible gap) except when the well is in use. 

c. The gap between the pole wiper and the guidepole shall be added to the gaps measured to determine 

compliance with the secondary seal requirement, and in no case shall exceed 1/2 inch. 

4. Slotted Guidepole: Slotted sampling or gauging wells shall meet the following requirements: 

a. The well shall provide a projection below the liquid surface. 

b. The well on external floating roof shall be equipped with the following: a sliding cover, a well gasket, 

a pole sleeve, a pole wiper, and an internal float and float wiper designed to minimize the gap between 

the float and the well, and provided the gap shall not exceed 1/8 inch; or shall be equipped with a well 

gasket, a zero gap pole wiper seal and a pole sleeve that projects below the liquid surface. 

c. The gap between the pole wiper and the guidepole shall be added to the gaps measured to determine 
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compliance with the secondary seal requirement, and in no case shall exceed 1/8 inch. 

Specifications for Vapor Recovery Systems 

A. Fixed roof tanks shall be fully enclosed and shall be maintained in a leak-free condition. An APCOapproved vapor recovery system shall consist of a closed system that collects all VOCs from the storage 

tank, and a VOC control device. The vapor recovery system shall be maintained in a leak-free condition. 

The VOC control device shall be one of the following: 

1. A condensation or vapor return system that connects to one of the following: a gas processing plant, a 

field gas pipeline, a pipeline distributing Public Utility Commission quality gas for sale, an injection 

well for disposal of vapors as approved by the California Department of Conservation, Division of Oil 

Gas, and Geothermal Resources, or 

2. A VOC control device that reduces the inlet VOC emissions by at least 95% by wt 

B. Any tank gauging or sampling device on a tank vented to the vapor recovery system shall be equipped with 

a leak-free cover which shall be closed at all times except during gauging or sampling. 

C. All piping, valves, and fittings shall be constructed and maintained in a leak-free condition. 

Texas §115.112. Control Requirements. 

A. For all persons in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston, the 

following requirements shall apply: 

1. No person shall place, store, or hold in any stationary tank, reservoir, or other container any VOC unless 

such container is capable of maintaining working pressure sufficient at all times to prevent any vapor or 

gas loss to the atmosphere, or is equipped with at least the control device specified in Table I(a) for VOC 

other than crude oil and condensate, or Table II(a) for crude oil and condensate. 

2. For floating roof storage tanks subject to the provisions this subsection, the following requirements shall 

apply: 

a. All openings in an internal or external floating roof except for automatic bleeder vents (vacuum breaker 

vents) and rim space vents must provide a projection below the liquid surface or be equipped with a 

cover, seal, or lid. Any cover, seal, or lid must be in a closed (i.e., no visible gap) position at all times 

except when the device is in actual use. 

b. Automatic bleeder vents (vacuum breaker vents) are to be closed at all times except when the roof is 

being floated off or landed on the roof leg supports. 

c. Rim vents, if provided, are to be set to open only when the roof is being floated off the roof leg supports 

or at the manufacturer's recommended setting. 

d. Any roof drain that empties into the stored liquid shall be equipped with a slotted membrane fabric 

cover that covers at least 90% of the area of the opening. 

e. There shall be no visible holes, tears, or other openings in any seal or seal fabric. 
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Table I(a). REQUIRED CONTROL DEVICES FOR STORAGE TANKS FOR VOC 

OTHER THAN CRUDE OIL AND CONDENSATE 

True Vapor Pressure of 

Compound at Storage 

Conditions 

Nominal Storage Capacity Emission Control 

Requirements 

< 1.5 psia (10.3 kPa) Any None 

≤ 1,000 gal None 

> 1,000 gal and ≤ 25,000 gal 

Submerged fill pipe or 

vapor recovery system 

> 25,000 gal and ≤ 40,000 gal 

Internal or external 

floating roof (any type) or 

vapor recovery system 

≥ 1.5 psia (10.3 kPa) 

and 

< 11 psia (75.8 kPa) 

> 40,000 gal 

Internal floating roof or 

External floating roof with 

primary seal (any type) 

and secondary seal or 

vapor recovery system 

≤ 1,000 gal None 

> 1,000 gal and ≤ 25,000 gal Submerged fill pipe or 

≥ 11 psia (75.8 kPa) vapor recovery system 

> 25,000 gal Submerged fill pipe and 

vapor recovery system 

Table II(a). REQUIRED CONTROL DEVICES FOR STORAGE TANKS 

FOR CRUDE OIL AND CONDENSATE 

True Vapor Pressure of 

Compound at Storage 

Conditions 

Nominal Storage Capacity Emission Control 

Requirements 

< 1.5 psia (10.3 kPa) Any None 

≤ 1,000 gal None 

> 1,000 gal and ≤ 40,000 gal Submerged fill pipe or 

vapor recovery system ≥ 1.5 psia (10.3 kPa) 

and 

< 11 psia (75.8 kPa) > 40,000 gal 

Internal floating roof or 

External floating roof with 

primary seal (any type) 

and secondary seal or 

vapor recovery system 

≤ 1,000 gal None 

> 1,000 gal and ≤ 40,000 gal Submerged fill pipe or 

≥ 11 psia (75.8 kPa) vapor recovery system 

> 40,000 gal Submerged fill pipe and 

vapor recovery system 
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Table I(b). REQUIRED CONTROL DEVICES FOR STORAGE TANKS FOR 

VOC OTHER THAN CRUDE OIL AND CONDENSATE 

True Vapor Pressure of 

Compound at Storage 

Conditions 

Nominal Storage Capacity Emission Control 

Requirements 

< 1.5 psia (10.3 kPa) Any None 

≤ 1,000 gal None 

> 1,000 gal and ≤ 25,000 gal Submerged fill pipe or 

vapor recovery system 

≥ 1.5 psia (10.3 kPa) 

and 

< 11 psia (75.8 kPa) > 25,000 gal 

Internal or external floating 

roof (any type) or 

vapor recovery system 

≤ 1,000 gal None 

> 1,000 gal and ≤ 25,000 gal Submerged fill pipe or 

≥ 11 psia (75.8 kPa) vapor recovery system 

> 25,000 gal Submerged fill pipe and 

vapor recovery system 

f. For external floating roof storage tanks, secondary seals shall be the rim-mounted type (the seal shall be 

continuous from the floating roof to the tank wall). The accumulated area of gaps that exceed 1/8 inch in 

width between the secondary seal and tank wall shall be no greater than 1.0 in2

/ft of tank diameter. 

3. Vapor recovery systems used as a control device on any stationary tank, reservoir, or other container shall 

maintain a minimum control efficiency of 90%. 

B. For all persons in Gregg, Nueces, and Victoria Counties, the following requirements shall apply: 

1. No person shall place, store, or hold in any stationary tank, reservoir, or other container any VOC, unless 

such container is capable of maintaining working pressure sufficient at all times to prevent any vapor or 

gas loss to the atmosphere, or is equipped with at least the control device specified in Table I(a) for VOC 

other than crude oil and condensate or Table II(a) for crude oil and condensate. 

2. For floating roof storage tanks subject to the provisions of this subsection, the following requirements 

shall apply: 

a. All openings in an internal or external floating roof, except for automatic bleeder vents (vacuum breaker 

vents) and rim space vents, must provide a projection below the liquid surface or be equipped with a 

cover, seal, or lid. Any cover, seal, or lid must be in a closed (i.e., no visible gap) position at all times, 

except when the device is in actual use. 

b. Automatic bleeder vents (vacuum breaker vents) are to be closed at all times except when the roof is 

being floated off or landed on the roof leg supports. 

c. Rim vents, if provided, are to be set to open only when the roof is being floated off the roof leg supports 

or at the manufacturer's recommended setting. 

d. Any roof drain that empties into the stored liquid shall be equipped with a slotted membrane fabric 

cover that covers at least 90% of the area of the opening. 

e. There shall be no visible holes, tears, or other openings in any seal or seal fabric. 

f. For external floating roof storage tanks, secondary seals shall be the rim-mounted type (the seal shall be 

continuous from the floating roof to the tank wall). The accumulated area of gaps that exceed 1/8 inch in 

width between the secondary seal and tank wall shall be no greater than 1.0 in2

/ft of tank diameter. 
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C. For all persons in Aransas, Bexar, Calhoun, Matagorda, San Patricio, and Travis Counties, the following 

requirements shall apply. 

1. No person may place, store, or hold in any stationary tank, reservoir, or other container any VOC, other 

than crude oil or condensate, unless such container is capable of maintaining working pressure sufficient at 

all times to prevent any vapor or gas loss to the atmosphere, or is designed and equipped with at least the 

control device specified in Table I(b) for VOC other than crude oil and condensate. 

2. For floating roof storage tanks subject to the provisions of paragraph (1) of this subsection, the following 

requirements shall apply: 

a. There shall be no visible holes, tears, or other openings in any seal or seal fabric. 

b. All tank gauging and sampling devices shall be vapor-tight except when gauging and sampling is taking 

place. 

3. No person in Matagorda or San Patricio Counties shall place, store, or hold crude oil or condensate in any 

stationary tank, reservoir, or other container, unless such tank, reservoir, or other container is a pressure 

tank capable of maintaining working pressures sufficient at all times to prevent vapor or gas loss to the 

atmosphere or is equipped with one of the following vapor-loss control devices, properly maintained and 

operated: 

a. An internal floating cover or external floating roof. This control equipment shall not be permitted if the 

VOC has a true vapor pressure ≥ 11.0 psia (75.8 kPa). All tank-gauging and tank-sampling devices shall 

be vapor-tight, except when gauging or sampling is taking place; or 

b. A vapor recovery system. 
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7.4 AVAILABLE CONTROL TECHNOLOGIES 

The main mechanisms of evaporative VOC losses from storage tanks at petroleum 

refineries are breathing loss, standing storage loss and working loss. Breathing losses are 

due to fluctuations in atmosphere temperature and pressure causing the organic liquid to 

volatilize. Standing storage losses are a result of evaporative losses through rim seals, 

deck fittings, and/or deck seams. Working losses are due to changes in the stored liquid 

levels caused by to filling and draining operations. Emissions from each of the types of 

tanks mention in Section 7.2 can vary. Emissions from fixed roof tanks are a result of 

breathing and standing storage losses, with emissions from external and internal floating 

roof tanks resulting from standing storage and working losses, and variable vapor space 

tanks result from working losses. Because tank emissions vary based on the tank’s roof 

design and the mechanism of evaporative loss, controls for each of these types of tanks 

will be discussed separately below. 

7.4.1 Controls for Fixed Roof Tanks 

Several control techniques are available to limit emissions due to standing storage and 

working losses from fixed roof tanks. Control techniques include retrofitting the fixed 

tank to an internal floating roof tank and vapor balancing, as well as implementing a vapor 

recovery system or thermal oxidation system (discussed in Section 7.4.3). 

7.4.1.1 Install an Internal Floating Roof and Seals 

Installation of an internal floating roof with seals inside a fixed roof tank will result in 

emission reductions in standing evaporative losses. Depending on the type of roof and 

seals installed and liquid stored, control efficiencies of 60% to 99% can be achieved. 

7.4.1.2 Vapor Balancing 

Vapor balancing is a method of collecting the vapors that are displaced when a tank is 

filled liquid. This emission control technique is most common for filling tanks at gasoline 

stations. As the storage tank is filled, the expelled vapors are collected in the tanker truck 

and are then transported to a vapor recovery system or combustion device. If the collected 

vapors are subsequently controlled, control efficiencies of 90% to 98% can be achieved. 

7.4.1 Floating Roof Tanks 

Floating roof tanks experience most of their vapor losses through working losses and 

standing storage losses. In floating roof tanks, working losses occur when the floating roof 

is lowered, and residual liquid on the tank’s inner walls evaporate. The standing storage 

losses originate from rim seals and deck seems and fittings, and are highly affected by 
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wind. Options to reduce these vapor losses from floating roof tanks include installing 

weather shields and/or secondary seals. 

7.4.1.3 Weather Shields 

Weather conditions can be harsh on floating roof tank rims seals and cause deterioration of 

the fabric seal. Weather shields can provide protection to these rim seals, reducing the 

amount of VOCs released from standing storage losses. 

7.4.1.4 Secondary Seals 

Rim seals on floating roof tanks can consist of either a primary seal or a primary and 

secondary seal. Secondary seals can provide further protection from evaporative losses 

through the primary rim seal. For external floating roofs, secondary seals can either be 

shoe mounted or rim mounted. Rim mounted secondary seals cover the entire rim vapor 

space, while the shoe mounted secondary seal is held against the tank using a mechanical 

device. For internal floating roof tanks, the secondary seal is mounted to an extended 

vertical rim plate above the primary seal. Even though secondary seals can help reduce 

VOC emissions from floating roof tanks, a secondary seal can also limit the tank’s 

operating capacity in order to prevent the seal from interfering with the fixed roof. 

7.4.2 Vapor Recovery Systems 

The function of vapor recovery systems is to collect VOC emissions from storage tanks 

that can be routed to a fuel gas system for combustion as fuel. Vapor recovery can be 

achieved either through condensation, carbon adsorption, or absorption. Depending on the 

procedure used, the design of the vapor recovery unit, and composition of the vapors 

recovered, control efficiencies vary between 90% and 98%. An alternative to vapor 

recovery is to destroy the vapors in a thermal oxidation system, where the air/vapor 

mixture is combusted in an incinerator, with the ability to reduce VOCs 95% to 99%. 

7.4.2.1 Condensation 

Condensation is performed by chilling or pressurizing VOC vapors to return them to their 

liquid state. This process is most effect with VOCs whose boiling points are above 40oC 

(104o

F) and whose vapor concentrations are greater than 5000 ppm. Due to the nature of 

VOCs ability to combust, safety precautions must be implemented to prevent explosions. 

7.4.2.2 Carbon Adsorption 

Carbon adsorption, as discussed in Section 6.4.2, is a common emission control technique 

for waste gas streams contaminated with VOCs. The VOCs in the waste gas become 

physically bound to the activated carbon, effectively removing it from the air stream. In 
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multi carbon bed systems, once the first carbon bed becomes saturated with VOCs that bed 

is taken off-line and regenerated and the next bed will adsorb any VOCs. The downside to 

activated carbon adsorption systems is that activated carbon is a flammable substance, thus 

fire suppression systems are needed in the recovery system, and/or the activated carbon in 

these systems has been replaced with a hydrophobic zeolite. 

7.4.2.3 Absorption 

In absorption systems, the contaminated air stream is contacted with a liquid solvent in an 

absorber tower, where VOCs are absorbed by the solvent. The absorber tower is designed 

to provide the necessary liquid-vapor contact area to facilitate mass transfer. Packed bed 

towers and mist scrubbing systems are two types of absorber towers that can remove 95% 

to 98% of the incoming VOCs from the waste gas stream. One advantage of absorber 

systems is its ability to handle fluctuations in incoming VOC concentrations, which can 

vary between 500 and 5000 ppm. 

7.4.2.4 Incinerators 

One of the most popular control devices for destroying collected VOCs is an incinerator, 

either thermal or catalytic. Thermal incinerators combust VOCs at temperatures between 

1400oF and 2000oF for a required minimum residence time to oxidize 95 to 99% of the 

VOCs present in waste gas stream. They are most effective at reducing VOCs from waste 

gas streams with a VOC concentration between 100 and 2000 ppm. Catalytic oxidizers 

are similar to thermal oxidizers, however they use a catalyst in the presence of lower 

combustion temperatures, between 600oF and 900oF, to oxidize VOCs in the waste gas 

stream. 

7.4.3 More Stringent Standards 

The Bay Area Air Quality Management District (BAAQMD) in California is currently 

studying applicable control measures to further reduce VOC emissions from organic liquid 

storage tanks. Proposed changes to BAAQMD Regulation 8, Rule 5 include: 

(1) Applying tank standards to storage tanks containing liquids with true vapor 

pressures less than or equal to 0.5 psia. 

(2) Retrofit external floating roof tanks to internal floating roof tanks or domed 

external floating roof tanks 

(3) Implement more stringent tank cleaning standards 

(4) Vent vapor recovery systems to fuel gas systems 

(5) Include a maintenance program 
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Of these proposed changes, only items (1), (3), and (5) have yet to be discussed, and are 

discussed in more detail below. 

7.4.3.1 Vapor Pressure Criteria 

Currently, BAAQMD’s Regulation 8, Rule 5 does not address storage tanks containing 

liquids with true vapor pressures less than or equal to 0.5 psia. By applying the current 

tank standards to these tanks, VOC emissions would be reduced. Tanks storing low vapor 

pressure liquids inevitably generate fewer VOC emissions than tanks storing high vapor 

pressure liquids. For this reason, to implement control devices on storage tanks containing 

low vapor pressure emissions would not be cost effective. 

7.4.3.2 Tank Cleaning 

Current tank cleaning standards require that the insides of tanks be cleaned when either the 

accumulation of sludge inside the tank causes an unacceptable loss of tank capacity or 

when the sludge affects product quality. Given this guideline, most tanks are cleaned 

every 5 to 10 years, or prior to decommissioning. Tank cleaning first involves draining the 

tank, then removing any remaining product with a vacuum truck. After removing most of 

the liquid, the tank is degassed to lower the organic vapor concentration, and then the tank 

is ready to be cleaned. Under current standards, only tanks with storage capacities greater 

than 19,803 gallons are required to be degassed prior to tank cleaning and/or opening. 

Degassing is to be performed by liquid balancing (the opposite of vapor balancing) until 

the resulting liquid vapor pressure is less than 0.5 psia or by venting the tank to a control 

device with a 90% minimum control efficiency until the residual VOC concentration is less 

than 10,000 ppm. Under these regulations, the remaining 10,000 ppm of organics can be 

released to the atmosphere. Also under the current BAAQMD regulations, the control 

device must be tested annually, and tank sludge removal is not regulated. 

More stringent tank cleaning/degassing standards proposed by the BAAQMD include: 

• Lower the tank capacity (currently 19,803 gallons) which triggers required tank 

degassing 

• Reduce the current 10,000 ppm residual organic standard to 5,000 ppm 

• Increase the required minimum control efficiency of the control device from 90% 

to 95% 

• Increase control device monitoring from an annual test to continuous real-time 

monitoring during venting 

• Regulate the handling of sludge removal from tanks 
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7.4.3.3 Maintenance Programs 

No provisions currently exist under Regulation 8 Rule 5 requiring a maintenance program 

for tanks. Implementation of such a program would result in more frequent inspections 

and repairs of tank roof seals, similar to standards implemented for equipment leaks. 

7.5 COSTS AND AVAILABILITY 

Feasible control technologies for storage tanks are summarized in Table 7-5. The table 

includes 

• Pollutant controlled 

• Name of technology 

• Origin for the level of control (rule, consent decree, permit) 

• Range of potential emission reductions from applying those controls 

• Performance level in terms of outlet concentration or emission rate 

• Cost effectiveness of the controls 

• Commercial status 

• Reference 

More detailed information on each technology was summarized in the previous sections 

and based on the information contained in the references for this Section. 

The cost data presented in the Table were obtained from the published literature as 

referenced. In general, the percent reductions and cost effectiveness data represent data for 

uncontrolled sources. Incremental reductions will be lower and costs will be higher for 

sources already have some level of control and will be required to meet the performance 

levels shown in the Table. Also, site-specific factors greatly influence the actual 

achievable performance level and control costs at a particular facility. These 

considerations must be addressed in State and local rulemaking and permitting processes. 

7.6 REFERENCES 

Elliot, J., 2004, “Draft Technical Assessment Document: Further Study Measure 10, 

Organic Liquid Storage Tanks,” Bay Area Air Quality Management District, San 

Francisco, California. 

European Commission, Integrated Pollution Prevention & Control (ECIPPC), 2003, 

“Reference Document on Best Available Techniques for Mineral Oil and Gas 

Refineries.” 

van den Braken, A.M., “VOC Treatment: Don’t Change an Environmental Problem into a 

Safety Problem,” Akzo Nobel Safety Research Department, Deventer, The 

Netherlands.
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Section 7 – Storage Tanks Page 7-38 MACTEC Federal Programs, Inc. 

Table 7-5: Control Technology Summary for Storage Tanks 

Pollutant Technology 

Origin of 

Requirement Percent Reduction 

Performance Level Cost Data

Co

A

VOC Install internal floating 

roof in fixed roof tank 

NSPS/ 

NESHAP/ 

State Rule 

60 to 99 See applicable 

rule 

Investment: 

$240,000 - $480,900 

Operating: minor 

 Install domed fixed roof on 

a external floating roof tank 

NSPS/ 

NESHAP/ 

State Rule 

96 See applicable 

rule 

Avg. cost: 

$21,640 – $240,500 

 Replace a vapor-mounted 

primary seal with a liquidmounted primary seal 

NSPS/ 

NESHAP/ 

State Rule 

30 to 70 EFRT1

43 to 45 for IFRT1

See applicable rule 

Avg. cost: 

$5,530 - $18,155 

 Install secondary seals on 

floating roof tanks 

NSPS/ 

NESHAP/ 

State Rule 

75 – 95% See applicable 

rule 

Investment: 

$60,000 - $120,000 

Avg. cost: 

$4090 – $13,590 

 Vapor Balancing NSPS/ 

NESHAP/ 

State Rule 

80% See applicable 

rule 

Investment: 

$96,000/tank 

 Vapor Recovery Systems NSPS/ 

NESHAP/ 

State Rule 

80 – 99% See applicable 

rule 

Investment: 

$337,000 – $2,164,000 

Operating: 

$60,000 – $144,300 

 Incineration NSPS/ 

NESHAP/ 

State Rule 

95 – 99% See applicable 

rule 

Investment: 

$2.4 - $30 million 

Operating: 

$24,100 - $1,320,000 

 Apply tank standards to 

tanks storing organic liquids with vapor pressures 0.1 – 0.5 psia 

Varies $20,500 - $34,000 per 

ton VOC reduced 

(potential reduction of 

100 – 160 tons/yr) 

1 EFRT = external floating roof tank; IFRT = internal floating roof tank 
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Section 8 – Sulfur Recovery Units Page 8-1 

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8.0 SULFUR RECOVERY UNITS 

As discussed in the previous sections, SO2 is released from petroleum refinery FCCUs, 

boilers/process heaters, and flares as a result of firing fuels containing sulfur compounds. 

These emission units comprise approximately 81% of the total SO2 emissions from 

petroleum refineries, while emissions from sulfur recovery units (11%) and miscellaneous 

process equipment make up the remaining 19%. Typical sulfur recovery configurations at 

petroleum refineries entail the use of the Claus sulfur recovery process followed by a tail 

gas clean-up unit (TGCU) to maximize removal of H2S. Several process modifications are 

available to increase sulfur recovery from this process, however, they result in increased 

emissions of CO2 to the atmosphere. 

8.1 PROCESS DESCRIPTION 

Claus sulfur recovery units convert hydrogen sulfide (H2S), a by-product of refining crude 

oils to elemental sulfur through multistage catalytic oxidation. Each catalytic stage can 

only recover half to two-thirds of the incoming sulfur, therefore multiple stages (usually 

two or three) consisting of a gas reheater, catalyst chamber, and condenser are used to 

achieve about 95 – 97% sulfur recovery. The Claus reaction proceeds in two exothermic 

steps. The first reaction occurs in the reactor furnace, where a portion of the H2S reacts 

with air to form SO2. The second reaction takes place in catalytic reactors where the 

remaining H2S reacts with the SO2 produced in the first reaction to form elemental sulfur 

and water. Side reactions also occur, producing carbonyl sulfide (COS) and carbon 

disulfide (CS2). After the process stream passes through the final catalytic stage 

condenser, a tail gas treatment system is employed to recover any remaining sulfur. Figure 

8-1 is a process flow diagram of the typical Claus sulfur recovery unit. 

8.2 EMISSION INVENTORY 

Table 8-1 identifies the sulfur recovery units in the MARAMA region, along with the 

capacity of each unit. Criteria pollutant emissions for each unit are shown for three years. 

The 2002 annual emissions serve as the baseline for future SIP development. The 2002 

emissions were obtained from the 2002 inventories developed by MANEVU and VISTAS. 

The 2003 emissions were obtained directly from each state and represent the most 

currently quality assured data that is available. The 2009 emissions were obtained from 

the MANEVU and VISTAS projection inventories that were developed to support 

modeling for SIP development. The 2009 inventories include the effects of anticipated 

growth as well as any planned controls that will result in emission reductions between 

2002 and 2009 due to new regulations or enforcement settlements. 
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Figure 8-1. Typical Claus Sulfur Recovery Unit Process Flow Diagram 

SOURCE: United States Environmental Protection Agency, 1995, “Sulfur Recovery,” Pages 8.13-1 – 8.13-5 in AP-42, 

Fifth Edition: Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources, 

http://www.epa.gov/ttn/chief/ap42/ch08/final/c08s13.pdf. 
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Table 8-1: Emission Inventory for Sulfur Recovery Units 

 Refinery/ Annual SO2 Emissions (tons/year)

State Unit 2002 2003 2009 

DE Valero Delaware City 

 EUID = 010 Gasoline MEROX Plant 13.1 13.1 12.1 

 EUID = 016 Alkylation MEROX Plant 113.9 113.9 105.4 

 EUID = 017 Polymerization MEROX Plant 74.5 74.5 69.0 

 EUID = 027 Sulfur Recovery Unit 1 20.9 58.5 19.3 

 EUID = 028 Sulfur Recovery Unit 2 26.7 74.8 24.7 

DE SUNCO Inc Delaware 

 None Listed in Inventory 0.0 0.0 0.0 

NJ Sunoco Eagle Point 

 EUID = U48 SRU Thermal Oxidizer 12.9 22.6 14.7 

NJ Valero Paulsboro 

 EUID = U7 SRU Complex 0.1 0.1 0.1 

 EUID = U56 SRU Thermal Oxidizer 18.0 12.0 23.9 

NJ Citgo Asphalt 

 None Listed in Inventory 0.0 0.0 0.0 

NJ Amerada Hess Port Reading 

 None Listed in Inventory 0.0 0.0 0.0 

NJ Chevron Products 

 None Listed in Inventory 0.0 0.0 0.0 

NJ ConocoPhillips Bayway 

 EUID = U5 Sulfur Recovery Units 142.0 0.1 0.1* 

PA Sunoco Marcus Hook 

None listed in 2002/2003 inventory; installed 

in 2004 and located in Delaware 0.0 0.0 0.0 

PA ConocoPhillips Trainer 

 EUID = 102 Claus Sulfur Recov. Plt. 34.8 25.6 32.7 

PA American Refining Bradford 

 None Listed in Inventory 0.0 0.0 0.0 

PA Sunoco Philadelphia 

 EUID = 013 GP 532 SRU Incinerator 0.0 0.0 0.0 

 EUID = 522 PB 867 Unit SRU 9.9 11.5 9.3 

PA United Refining 

 EUID = 108 Claus Sulfur Plant #2 12.0 12.0 13.7 

VA Giant Yorktown 

 EUID = 7 Gas Treat/Sulfur Recovery 676.7 1,609.3 24.7* 

WV Ergon West Virginia 

 EUID = 025 Sulferox Unit 0.0 0.0 0.0 

MARAMA Totals 1,155.5 2,028.0 353.6 

* Bayway Claus units will be shut down and the refinery acid gas will be treated by the Spent Acid Regeneration 

Plant; Giant will have a new SRU and TGU. 
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8.3 EXISTING REQUIREMENTS 

This section discusses the regulatory requirements which apply to sulfur recovery units. 

Four types of requirements are discussed: (1) Federal requirements such as the New 

Source Performance Standards (NSPS) and Maximum Achievable Control Technology 

(MACT) standards; (2) State regulations for both the MARAMA states as well as other 

State agencies; (3) source-specific permit requirements; and (4) new requirements from 

recent enforcement settlements. 

8.3.1 Federal Requirements 

The U.S. EPA has promulgated standards for emissions of SO2 from petroleum refinery 

Claus sulfur recovery units. 

New Source Performance Standards (NSPS) for Claus sulfur recovery units constructed or 

modified after October 4, 1976 are covered under 40 CFR Part 60, Subpart J. This subpart 

applies to Claus sulfur recovery plants with capacities greater than 20 long tons per day at 

petroleum refineries. For units with an oxidation or reduction control system followed by 

incineration, SO2 emissions are limited to 250 ppmvd at 0% O2. For units with a reduction 

control system not followed by incineration, emissions of reduced sulfur compounds are 

limited to 300 ppmvd at 0% O2 and emissions of H2S are limited to 10 ppmvd at 0% O2, 

each calculated as SO2. Monitoring requirements are also specified under this subpart, 

requiring instruments to continuously monitor and record the concentration of SO2

emissions and O2 levels for data correction. 

The National Emission Standards for Hazardous Air Pollutants (NESHAP) for sulfur 

recovery units are covered in 40 CFR Part 63, Subpart UUU, which applies to petroleum 

refinery catalytic cracking units, catalytic reforming units, sulfur recovery units, and 

associated by-pass lines. Under the requirements of this subpart, new or existing Claus 

sulfur recovery units subject to NSPS requirements must comply with the emission limits 

set under NSPS. For new or existing units not subject to NSPS, units must comply with 

either the emission limits specified under NSPS or a total reduced sulfur (TRS) limit of 

300 ppmvd at 0% O2. 

8.3.2 State Regulations 

Table 8-2 lists the regulations for each of the MARAMA states for the control of SO2 from 

sulfur recovery units. All regulatory agencies in the MARAMA region have regulations 

limiting the emissions of SO2 except for Philadelphia. In Table 8-3, the regulations are 

listed for Louisiana, Texas, and California which tend to have stricter emission limitations 

than the MARAMA states and the federal government. 
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Table 8-2: Summary of MARAMA State Regulations 

Agency Emission Limitations 

Delaware Regulation No. 9, Section 3 

3.1 No person shall cause or allow the emission of sulfur dioxide in the tail gases from existing sulfur recovery 

operations to exceed either a concentration of 2,000 parts per million by volume or a mass emission rate as 

specified in Table 2. 

Table 2 

Allowable Mass Emission Rate of Sulfur Dioxide from Sulfur Recovery Operations 

Production Rate Mass Emission Rate 

(tons/day) (pounds/hr) 

50 425 

100 550 

200 800 

300 1050 

400 1300 

500 1550 

600 1800 

700 2050 

800 2300 

900 2550 

1000 2880 

3.2 Except as provided in Section 11 of Regulation No. 20, NSPS, no person shall cause or allow the emission of 

sulfur dioxide in the tail gases from new sulfur recovery operations to exceed either a concentration of 2,000 parts 

per million by volume or a mass emission rate as specified in Table 2.

New Jersey 7:27-7.2. Sulfur recovery plants which are engaged in recovering elemental sulfur from hydrogen sulfide. For 

such plants the concentration of SO2 in the gases being discharged from a stack or chimney shall not exceed 

15,000 ppm by volume at standard conditions. 

Pennsylvania 129.13. 

(a) No person may permit the emission into the outdoor atmosphere, at any time, from a plant used for recovering 

elemental sulfur from gases containing sulfur compounds, of sulfur oxides, expressed as SO2, in excess of the rate 

determined by the formula: 

A = 0.32E-.5 

where: A = Allowable emissions in pounds of sulfur oxides per pound of sulfur compounds, expressed as S, in the 

feed gases, and E = Recovery plant rating in long tons of sulfur per day. 

(b) Allowable emissions under this section are graphically indicated in Appendix A.
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Agency Emission Limitations 

Virginia Rule 4-22. No owner or other person shall cause or permit to be discharged into the atmosphere from any sulfur 

recovery operation any sulfur dioxide emissions in excess of a concentration of 8000 parts per million by volume 

and in excess of the mass emission rate specified in Table 4-22. 

Table 4-22 

Sulfur Maximum Allowable SO2

Production Rate Mass Emission Rate 

(tons/day) (lbs/hr) 

≤ 50 415 

100 830 

200 1660 

300 2490 

400 3320 

≥ 500 4150 

West 

Virginia 

45-10-4, 4.1.b. No person shall cause, suffer, allow or permit the emission of sulfur oxides, calculated as sulfur 

dioxide, from a sulfur recovery plant to exceed 0.06 pounds per pound of sulfur processed. 

Table 8-3: Summary of Other State Regulations 

Agency Emission Limitations 

BAAQMD 9-1-307 A person shall not emit, from any source in a sulfur recovery plant, effluent process 

gas containing sulfur dioxide in excess of 250 ppm by volume (dry) calculated at zero 

percent oxygen. Plants which emit less than 45 kg (100 lbs.) per day of sulfur dioxide shall 

not be subject to this limitation.

Louisiana Chapter 15, Rule 1503 B. The emission of sulfur oxides calculated as sulfur dioxide from a 

new sulfur recovery plant that commences construction or modification after October 4, 

1976, shall be limited to that specified in 40 CFR 60.104(a)(2), as incorporated by reference 

in LAC 33:III.Chapter 30. The emission of sulfur oxides calculated as sulfur dioxide from an 

existing plant shall be limited to a sulfur dioxide concentration of not more than 1,300 ppm 

by volume (three-hour average).

SCAQMD Subject to the requirements of Amended Rule 1118 as discussed in Section 3.4.2.2 and 

summarized in Appendix B. 

SJV APCD Rule 4801. A person shall not discharge into the atmosphere sulfur compounds, which 

would 

exist as a liquid or gas at standard conditions, exceeding in concentration at the 
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Agency Emission Limitations 

point of discharge: two-tenths (0.2) percent by volume calculated as sulfur dioxide 

(SO2), on a dry basis averaged over 15 consecutive minutes.

Texas Rule 112.7 

(a) No person may cause, suffer, allow, or permit emissions of sulfur dioxide (SO2) from any 

sulfur recovery plant to exceed the emission limits specified for stack effluent flow rates less 

than or equal to 4,000 standard cubic feet per minute (scfm) as determined by the equation: 

E = 123.4 + 0.091 q 

and the emission limits, specified for stack effluent flow rates in excess of 4,000 scfm, as 

determined by the equation: 

E = 0.614 q 0.8042 

Where: E = allowable emission rate in pounds per hour, and q = stack effluent flow rate in 

scfm 

(b) If a source has an effective stack height less than the standard effective stack height 

determined for stack 

effluent rates less than or equal to 4,000 scfm by the equation: 

then, the allowable emission limit in subsection (a) of this section must be reduced by 

multiplying it by the short-stack reduction factor. 
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8.3.3 Requirements from Recent Enforcement Settlements 

The enforcement settlements for sulfur recovery units at petroleum refineries in the 

MARAMA region generally require compliance with NSPS Subpart J. Specific 

requirements are shown in Table 8-4. 

Table 8-4: Summary of Recent Enforcement Settlements 

State Refinery Required Control Technology 

DE Valero Comply with NSPS Subparts A and J 

Route all sulfur pit emissions so that sulfur pit emissions 

either are eliminated or are included and monitored as 

part of the Sulfur Recovery Plant tail gas emissions 

NJ Sunoco Eagle Point Comply with NSPS Subparts A and J by no later than 

December 31, 2006 

Route all sulfur pit emissions so that sulfur pit emissions 

either are eliminated or are included and monitored as 

part of the Sulfur Recovery Plant tail gas emissions

NJ Valero Refining Comply with NSPS Subparts A and J 

By December 31, 2006, Valero shall replace the two 

existing Bevon-Stretford tail gas treatment units at the 

Paulsboro refinery with amine based tail gas treatment 

units. 

NJ ConocoPhillips Bayway Comply with NSPS Subparts A and J 

Eliminate, control, and/or monitor sulfur pit emissions 

Conduct optimization study of the Claus trains and 

implement recommendations 

PA Sunoco Marcus Hook Comply with NSPS Subparts A and J 

PA ConocoPhillips Trainer Comply with NSPS Subparts A and J 

Eliminate, control, and/or monitor sulfur pit emissions 

PA Sunoco Philadelphia Comply with NSPS Subparts A and J 

VA Giant Yorktown Install a TGU or equivalent control technology to ensure 

continuous compliance with the NSPS emission 

standards by no later than the planned refinery 

turnaround in 2006 

WV Ergon Refining Newell Nothing specified 
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8.4 AVAILABLE CONTROL TECHNOLOGIES 

Sulfur recovery units mainly emit SO2 and other sulfur containing compounds, in addition 

to CO2 and small quantities of NOx. The two main strategies employed to limit sulfur 

emissions from these units include increasing the capacity of the Claus unit to recover 

more sulfur and improving the efficiency of the tail gas scrubber. These two strategies are 

discussed below, with several control options available to improve sulfur recovery and 

reduce SO2 emissions. 

8.4.1 Increase Claus Unit Capacity 

The amount of sulfur recovered in a Claus unit varies based on the number of catalytic 

stages of the Claus unit, feed composition, stoichiometric balance of gaseous components 

at the inlet, operating temperature, and catalyst maintenance. The conversion of H2S to 

elemental sulfur is limited by the equilibrium reaction of H2S with SO2, which only 

recovers 90 – 96% with a two-stage unit and 95 – 98% with a three-stage unit of the 

incoming sulfur. The NSPS regulations require limiting SO2 emissions to 250 ppmv at 0% 

O2, which is equivalent to 99.8 – 99.9% control level of reduce sulfur compounds. These 

higher sulfur recoveries can be achieved by expanding the capacity of the existing sulfur 

recovery unit through the methods discussed below. 

8.4.1.1 Oxygen Enrichment 

For many petroleum refineries, it is considered cost effective to increase the capacity of the 

sulfur recovery unit by applying oxygen enrichment. Varying levels of oxygen enrichment 

are available depending on the desired capacity increase. The low-level oxygen 

enrichment design can increase capacity 20 – 25% of the original design of the sulfur 

recovery unit, and is accomplished by injecting pure oxygen or oxygen-rich air into the 

combustion air upstream of the reaction furnace burner. The medium-level oxygen 

enrichment design can increase capacity up to 75% of the unit’s original design, through 

direct injection of oxygen through separate nozzles into the furnace. This design calls for 

use of special burners designed to handle direct oxygen injection. The high-level oxygen 

enrichment design can increase capacity up to 150% of the unit’s original design. This 

design requires modification or replacement of the thermal section of the sulfur recovery 

unit. Three technologies exist which incorporate high-level oxygen enrichment, the 

“SURE” Double Combustion process, the Lurgi process, and the COPE process. The 

“SURE” Double Combustion process divides the combustion air into two stages with 

intermediate cooling of the combustion product, the Lurgi process uses a multi-staged 

burner to maintain the furnace temperature low enough for about 60% oxygen enrichment, 

and the COPE process, developed by GAA/Air Products, recycles cooled acid gas from the 
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first sulfur condenser to the furnace. Oxygen enrichment has several advantages including 

reducing the gas volume sent to the tail gas treatment system, keeping the combustion 

temperatures high, shortening the gas residence time requirements, ensuring complete 

destruction of undesired heavy hydrocarbons and ammonia, and reducing formation of the 

unwanted side products, COS and CS2, from the Claus reaction. 

8.4.1.2 Selectox Catalyst 

Use of the selectox catalyst was designed for systems with low H2S concentration acid gas 

streams (5 – 25 mole % H2S), and can handle acid gas concentrations up to 50 – 60 mole 

% H2S. The selectox catalyst is used in the first catalytic stage of the Claus sulfur 

recovery unit to promote selective oxidation of H2S to SO2 without the use of a flame. The 

selectox catalyst also promotes the reaction between H2S and SO2 to form elemental 

sulfur, recovering between 90 and 97%. Overall recovery is affected by the H2S 

concentration in the feed and the specific sulfur recovery process in place. Higher 

recovery efficiencies can be achieved using a tail gas cleanup unit. 

8.4.1.3 SUPERCLAUS® 

The Superclaus sulfur recovery unit is similar to the Claus unit. It contains a thermal 

stage, followed by three to four catalytic reaction stages. The first two or three catalytic 

reactors use the Claus catalyst, while the last reactor uses a selective oxidation catalyst. 

The catalyst in the last reactor oxidizes the H2S to sulfur at a very high efficiency, 

recovering 99% of the incoming sulfur. The use of this catalyst doesn’t allow the 

oxidation of H2S to SO2, as occurs in the Claus reaction. Using this process on rich H2S 

feed gas results in high sulfur recovery and reductions of current SO2 emissions by 50 – 

90%. 

8.4.2 Tail Gas Treatment 

Emissions of SO2 from sulfur recovery units can be reduced by treating the emissions from 

the Claus unit with a tail gas treatment unit. Several types of treatment processes have 

been developed that provide process variations to treat the specific conditions of the 

exhaust from the sulfur recovery unit. The expected sulfur recovery of using any of these 

tail gas treatment technologies is 98 – 99.99%. 

8.4.2.1 SCOT Tailgas Unit 

The Shell Claus Off-gas Treating (SCOT) unit is one of the most common tail gas 

treatment systems and uses a hydrotreating reactor followed by amine scrubbing to recover 

and recycle sulfur to the Claus unit. Tail gas from the Claus unit is contacted with 

hydrogen and reduced in a hydrotreating reactor to form H2S and water in the presence of a 
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cobalt/molybdenum on alumina catalyst. The gas is then cooled in a water contactor and 

enters an amine absorber where it is contacted with a MDEA or diisopropyl amine, 

generating a rich amine stream. The rich amine stream is then desorbed in a stripper, 

where a lean amine stream is generated and recycled to the absorber, while an H2S gas 

stream is sent back to the Claus unit. 

8.4.2.2 Sulfreen 

The Sulfreen process is a catalytic tail gas process that extends the Claus reaction with the 

addition of two or three Sulfreen reactors at the end of the Claus unit. An activated 

alumina catalyst is used to remove additional sulfur. A regenerator is used to remove 

accumulated sulfur from the catalyst, achieving sulfur recoveries up to 99.0%. Variations 

on the Sulfreen process include the Maxisulf, HydroSulfreen, and DoxoSulfreen. The 

Maxisulf design incorporates a one-stage (includes only one absorber and one regenerator) 

Sulfreen unit with an open regeneration loop. Instead of recycling the regeneration gas, it 

is fed together with the Claus tail gas to the absorber. The Maxisulf can achieve sulfur 

recoveries up to 98.5%. The HydroSulfreen process includes an additional catalyst stage 

upstream of the Sulfreen unit. The additional stage uses an activated titanium oxide Claus 

catalyst to hydrolyze COS and CS2 to increase sulfur recovery to 99.7%. The 

DoxoSulfreen process combines the HydroSulfreen process with a direct oxidation step. 

The goal of this process is to operate with an excess of H2S in the system to convert all the 

SO2 using the Sulfreen catalyst. The excess H2S leaving the Sulfreen unit is then oxidized 

in the final stage, recovering 99.9% of the incoming sulfur. A similar Sulfreen process 

known as Cold Bed Absorption (CBA) uses hot process steam from the first Claus reactor 

to regenerate the catalyst and recover more sulfur. The CBA process recovers about 99 – 

99.5% of the incoming sulfur. Figure 4-3 shows the typical configuration of these Sulfreen 

processes. 

8.4.2.3 Beaven Process 

The Beaven process uses a quinone solution to absorb the remaining H2S contained in the 

exhaust gas from the Claus sulfur recovery unit. The absorbed H2S is then oxidized to 

form a mixture of elemental sulfur and hydro-quinone. Air or oxygen is injected into this 

mixture to oxidize the hydro-quinone back to quinone. The remaining solution is then 

filtered to remove the sulfur, while the quinone is re-used. The Beaven process is can also 

eliminate SO2, COS, and CS2 in the exhaust by first converting the Claus reaction sideproducts into H2S using a cobalt molybdate catalyst in the presence of high temperatures 

before processing the exhaust in the Beaven unit. Sulfur recoveries achieved using the 

Beaven process range from 99 to 99.9%. 
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8.4.2.4 Stretford Process 

The Stretford Process (also referred to as the Beavon-Stretford Process) uses a 

hydrotreating reactor to first convert off-gas SO2 to H2S, and then contacts the H2S with 

Stretford solution in a liquid-gas absorber. The Stretford solution contains a mixture of 

vanadium salt, anthraquinone disulfonic acid (ADA), sodium carbonate, and sodium 

hydroxide. The vanadium salt acts as a catalyst to react the H2S stepwise with the sodium 

carbonate and ADA to produce elemental sulfur. Oxygen is then added to the solution to 

regenerate the reactants. The solution is then sent to one or more froth/slurry tanks where 

the sulfur product is skimmed from the solution. 

8.4.2.5 Clauspol 

The Clauspol process treats the Claus unit’s tail gas by first contacting the gas stream with 

a polyethylene glycol solvent, and then passing it over a dissolved catalyst of the sodium 

salt of an inorganic acid. The H2S and SO2 present in the tail gas are absorbed by the 

solvent and catalyst. Liquid sulfur is not soluble under these conditions and is separated 

from the mixture. This process is effective at recovering 99.5 – 99.9% of the incoming 

sulfur. 

8.4.2.6 PROClaus 

The Parsons RedOx Claus (PROClaus) unit is a dry catalytic process that proceeds in three 

steps, using the traditional first or second Claus stage followed by a selective reduction 

stage and a selective reduction stage. As in the traditional Claus process, the petroleum 

refinery’s acid gas is fed to the Claus unit and mixed with air or oxygen which converts a 

portion of the inlet H2S to SO2. The remaining inlet H2S is then reacted with the converted 

SO2 to produce elemental sulfur. The gases are then processed in a second converter 

where the remaining SO2 is reduced to elemental sulfur through a reaction with H2 and CO 

in the presence of a highly selective SO2 reduction catalyst developed by Lawrence 

Berkeley National Laboratory. This reaction is equivalent to the equilibrium reaction that 

takes place in a 2-stage Claus unit. After each converter, the process gases are cooled and 

elemental sulfur is removed before the gas phase is reheated. Finally, the gas enters a third 

converter where the remaining H2S is oxidized to form elemental sulfur in the presence of 

a Parsons Hi-Activity selective oxidation catalyst. After this stage, the remaining 

elemental sulfur is recovered, and the tail gas is sent to a thermal oxidizer. An overall 

sulfur recovery of 99.5% is possible utilizing the 3-stage PROClaus unit as depicted in 

Figure 4-4. 
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Figure 8-4. Diagram of a 3-stage PROClaus Process 

SOURCE: Rameshni, M. and R. Street, 2001, “PROClaus: The New Standard for Claus Performance,” Sulfur Recovery 

Symposium, Canmore, Alberta. 

8.4.2.7 LO-CAT®

LO-CAT is a liquid redox tail gas treatment system capable of achieving sulfur recoveries 

of 99.9+% with or without the use of a hydrogenation/hydrolysis reactor. The direct LOCAT tail gas method employs a proprietary Mobile Bed Absorber (MBA) where H2S and 

SO2 leaving the Claus system are absorbed into a circulating solution and the sulfide ions 

are converted to elemental sulfur in the presence of a chelated-iron catalyst. The solution 

leaving the MBA is then processed by an oxidizer where air is injected to regenerate the 

catalyst. Exhaust gas from the MBA is vented to the atmosphere with H2S concentrations 

below 10 ppm. The indirect LO-CAT tail gas method follows the same process steps as 

the direct method, however, the indirect method first passes the tail gas from the Claus 

system through a hydrogenation/hydrolysis catalytic reactor to convert all sulfur 

compounds to H2S. Figures 4-5a and 4-5b depict the equipment layout for these two LOCAT systems. 
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Figure 8-5a. Direct LO-CAT Tail Gas System 

SOURCE: Nagl, G.J., 2001, “Liquid Redox Enhances Claus Process,” Sulfur, Vol. May-June, No. 274. 

Figure 8-5b. Indirect LO-CAT Tail Gas System 

SOURCE: Nagl, G.J., 2001, “Liquid Redox Enhances Claus Process,” Sulfur, Vol. May-June, No. 274. 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

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8.4.2.8 FLEXSORB®

A number of FLEXSORB solvents were developed by the ExxonMobil Research and 

Engineering Co. as alternatives to the traditional MDEA amine used in tail gas treatment 

units. These solvents were designed for a broad range of natural gas and refinery 

applications and are capable of being used in new or retrofit units, as well as to help in 

debottlenecking tail gas units. The family of FLEXSORB solvents includes the SE, SE 

Plus, SE hybrid, and the PS solvents. These solvents are designed to provide the following 

characteristics: the SE solvent is designed to provide high H2S selectivity in the presence 

of CO2, the SE Plus solvent improves H2S selectivity by enhancing the solvent’s ability to 

regenerate, the SE hybrid solvent is used for H2S and organic sulfur removal, and the PS 

solvent is designed to remove all CO2, H2S and organic sulfur compounds from exhaust 

gases. The SE and SE Plus solvents are best for selective H2S removal from refinery tail 

gas treatment systems. In one refinery application, replacing the MDEA solvent used in 

the tail gas treatment system of a US refinery with the SE Plus solvent allowed the refinery 

to discontinue use of the Stretford tail gas unit providing annual savings in operating and 

maintenance costs. Use of these solvents in the proper application can result in sulfur 

recoveries of 99.9+%. 

8.4.2.9 Emission Free Claus Unit 

Catalytic tail gas treatment systems are only good for sulfur recoveries up to 99.9%. To 

achieve recovery efficiencies greater than 99.9%, selective chemical absorption is 

necessary to remove any remaining H2S and recycle it to the Claus feed gas. Lurgi OelGas-Chemie (Lurgi) has designed a few of these systems, which increase sulfur recovery 

and reduce exhaust gas H2S levels prior to incineration. One such design is an Emissionfree sulfur recovery unit. This process first cools the process gases leaving the Claus unit 

which results in hydrolyzing sulfur compounds to H2S and the precipitation of elemental 

sulfur. The gas stream goes through an absorber stage where the H2S in the stream is 

reduced to less than 10 ppm, and then recycled to the combustion chamber, where it is 

oxidized. Since the H2S is recycled and converted to other compounds within the system, 

the system is considered a flue gas-free process. Figure 4-5 gives the basic configuration 

of all equipment used in this process. 

8.4.2.10 Tail Gas Scrubbers & Incinerators 

Sulfur emissions from sulfur recovery units can be reduced by installing a scrubber or an 

incinerator at the end of the Claus unit. In general, there are two types of scrubbing 

processes: oxidation tail gas scrubbers and reduction tail gas scrubbers. The WellmanLord Scrubber is an oxidation tail gas scrubber. The scrubber uses a wet generative 
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Figure 8-5. Lurgi Emission Free Sulfur Recovery Unit 

SOURCE: Lurgi Oel-Gas-Chemie GmbH, “Lurgi Sulfur Management,” 

www.lurgi.de/deutsch/nbsp/main/infomaterial/lurgi_sulfur_management.pdf

process to reduce SO2 concentrations in the flue gas to levels below 250 ppmv. In the 

Wellman-Lord process, the tail gas is incinerated to oxidize all sulfur species to SO2. The 

concentrated SO2 stream is then reacted with a solution of sodium sulfite (Na2SO3) 

forming sodium bisulfite (Na2HSO3). The off-gas is vented to the atmosphere, while the 

sodium bisulfite still in solution is boiled in an evaporator-crystallizer, where sodium 

sulfite is crystallized and SO2 is released with water. The crystallized sodium sulfite is 

reused in the scrubber while the SO2 is recycled back to the Claus unit for further 

conversion to elemental sulfur. 

In reduction tail gas scrubbers, sulfur in the tail gas is converted to H2S by hydrogenation, 

and then the tail gas is cooled and sent to a scrubber to remove the H2S. The removed H2S 

can be recycled back to the Claus unit for further sulfur removal. In addition to scrubbers, 

incinerators can be employed to destroy sulfur containing compounds, with the side-effect 

of emitting SO2. In order to effectively reduce sulfur compounds, incinerators must 

operate at temperatures of 1,200o

F or higher. Incinerator stacks should have proper 

monitoring in place to measure SO2 emission levels. 

8.5 COSTS AND AVAILABILITY 

Numerous technologies are available for controlling sulfur emissions from sulfur recovery 

units at petroleum refineries. Table 8-5 summarizes the relevant information about these 

control techniques. More detailed information on each technology was summarized in the 

previous sections and based on the information contained in the references for this Section. 
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The cost data presented in the Table were obtained from the published literature as 

referenced. In general, the percent reductions and cost effectiveness data represent data for 

uncontrolled sources. Incremental reductions will be lower and costs will be higher for 

sources already have some level of control and will be required to meet the performance 

levels shown in the Table. Also, site-specific factors greatly influence the actual 

achievable performance level and control costs at a particular facility. These 

considerations must be addressed in State and local rulemaking and permitting processes. 
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Section 8 – Sulfur Recovery Units Page 8-15 MACTEC Federal Programs, Inc. 

Table 8-5: Control Technology Summary for Sulfur Recovery Units 

Pollutant Technology 

Origin of 

Requirement Percent 

Reduction Performance Level 

Cost 

Effectiveness 

($/ton) 

Com

A

SO2 Various 

Technologies described in Section 8.4 

Consent Decree/ NSPS/ NESHAP 

97 to 99.9 NSPS: For units with an oxidation or reduction 

control system followed by incineration, SO2 emissions are limited to 250 ppmvd at 0% O2. 

For units with a reduction control system not followed by incineration, emissions of reduced sulfur compounds are limited to 300 ppmvd at 0% O2 and emissions of H2S are limited to 10 

ppmvd at 0% O2, each calculated as SO2. 

MACT: for units not subject to NSPS, emission limit specified under NSPS or a total reduced sulfur (TRS) limit of 300 ppmvd at 0% O2

167 to 449 
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8.6 REFERENCES 

European Commission, Integrated Pollution Prevention & Control (ECIPPC), 2003, 

“Reference Document on Best Available Techniques for Mineral Oil and Gas 

Refineries.” 

Fedich, R.B., A.C. Woerner, and G.K. Chitnis, 2004, “Selective H2S Removal,” 

Hydrocarbon Engineering, Vol. 9, No. 5. 

Goar, Allison & Associates, Inc., 2000, http://www.goarallison.com/technology.htm. 

Lurgi Oel-Gas-Chemie GmbH, “Lurgi Sulfur Management,” 

www.lurgi.de/deutsch/nbsp/main/ infomaterial/lurgi_sulfur_management.pdf.

Lurgi Oel-Gas-Chemie GmbH, “Sulfur Recovery,” 

http://www.lurgi.de/deutsch/nbsp/main/ infomaterial/sulfur_recovery.pdf. 

Nagl, G.J., 2001, “Liquid Redox Enhances Claus Process,” Sulfur, Vol. May-June, No. 

274. 

Parsons E&C., “Sulfur Technology,” 

www.worleyparsons.com/v5/download.aspx?file=Sulfur Qualification.pdf. 

Praxair Technology, Inc., 1994, “Increase Claus Plant Capacity with Oxygen,” 

http://www.praxair. 

com/praxair.nsf/d63afe71c771b0d785256519006c5ea1/82453029186b3070852565

4f0009cdc0/$FILE/p7728.pdf. 

Rameshni, M., 2002, “Cost Effective Options to Expand SRU Capacity Using Oxygen,” 

Sulfur Recovery Symposium, Banlf, Alberta, Calgary. 

Rameshni, M. and R. Street, 2001, “PROClaus: The New Standard for Claus 

Performance,” Sulfur Recovery Symposium, Canmore, Alberta. 

United States Environmental Protection Agency, 1995, “Sulfur Recovery,” Pages 8.13-1 – 

8.13-5 in AP-42, Fifth Edition: Compilation of Air Pollutant Emission Factors, 

Volume 1: Stationary Point and Area Sources, 

http://www.epa.gov/ttn/chief/ap42/ch08/final/c08s13.pdf. 

United States Environmental Protection Agency, 1996, Study of Selected Petroleum 

Refining Residuals: Industry Study,” Office of Solid Waste, Hazardous Waste 

Identification Division, Washington, DC 
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APPENDIX A 

METHODOLOGY FOR ESTIMATING EMISSION REDUCTIONS 

FROM CONSENT DECREES AND MODEL RULES 

INTRODUCTION 

Through its refinery initiative, EPA and the States have established Consent Decrees with 

most of the refineries in the MARAMA region to reduce their air pollution emissions. The 

Consent Decrees are expected to produce significant criteria pollutant emission reductions 

by 2009. States in the MARAMA region are also considering model rules to obtain further 

emission reductions in and around their nonattainment areas. This Appendix describes 

how the provisions of the Consent Decrees provisions were translated into refinery and 

unit-specific emission reductions for fluid catalytic cracking units, flares, and equipment 

leaks. 

The general procedures for projecting emissions for refineries involved the application of 

growth factors (to account for changes in economic activity) and control factors (to 

account for emission reductions anticipated from the Consent Decrees and model rules). 

The procedures used are fully documented in Draft Final Technical Support Document: 

Development of Emission Projections for 2009, 2012, and 2018 for NonEGU Point, Area, 

and Nonroad Sources in the MANE-VU Region, December 7, 2006. These procedures 

were agreed to by the MARAMA states as part of the development of emission projections 

to support regional air quality modeling. 

We started with the 2002 emission inventories developed by the MANEVU and VISTAS 

states. The base year of 2002 was chosen since that is the base year States are required by 

EPA to use in developing State Implementation Plans for attaining the 8-hour ozone 

standard. The 2002 inventories are based almost exclusively on data submitted by industry 

to fulfill their Emission Statement reporting obligations. We recognize that there are yearto-year variations in emissions (due to variations in capacity utilization, availability and 

costs of fuels, etc.). However, it was beyond the scope of this study to develop a “typical 

year” inventory to account for fluctuations in emissions from year to year. The MARAMA 

States may consider more recent inventories (2003-2006) during their rulemaking process. 

We also recognize that, for some refinery processes, that there is considerable uncertainty 

in the baseline emission estimates. For example, the methods used to calculate flaring 

emissions are not consistent across the industry, resulting in a wide variations in the 

emissions reported at each refinery. Recent studies in Texas and California suggest the 
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emissions from flaring activities at refineries may be significantly underestimated. Also, 

the various mass emission estimating methodologies for equipment leaks yield 

approximations that vary by an order of magnitude for the same components. The 

MARAMA States would like to work with industry to improve the emission estimates 

from flaring activities and equipment leaks as time permits. 

The growth factors for refinery operations were developed using three sets of data: 

• The U.S. EPA’s Economic Growth and Analysis System Version 5.0 (EGAS 5.0); 

• The DOE’s Annual Energy Outlook 2005 (AEO2005) fuel consumption forecasts; 

• State-supplied employment and other emission projection data. 

The priority for applying these growth factors was to first use the state-supplied projection 

data (if available). If no state-supplied data are available, then we used the AEO2005 

projection factors for fuel consumption sources. If data from these two sources were not 

available, we used the EGAS 5.0 default SCC configuration. 

The EPA, as well as many states, uses the EGAS model to forecast emissions because it 

provides a consistent economic-based approach for develop growth factors for projecting 

emissions inventories. The EPA’s EGAS model estimated about a 14 percent growth in 

activity at refineries, which was applied to estimate 1 14 percent growth in emissions at 

non-fuel burning sources. For fuel-burning sources, Table 24 of the AEO2005 provides 

the following forecasts for energy consumption in the refining industry: 

Excerpts for AEO2005 Table 24: Refining Industry Energy Consumption 

Parameter 2002 2009 % Change 

Value of Shipments 163.66 195.71 19.6 

Energy Consumption (trillion Btu) 

 Still Gas 1399.4 1898.1 35.6 

 Oil 2008.7 2670.0 32.9 

 Natural Gas 807.8 862.8 6.8 

 Other 185.7 271.6 46.3 

 Total 3002.2 3804.4 26.7 

The growth procedures were chosen to represent anticipated growth in the refining industry 

across a broad geographic area for regional air quality modeling purposes. As such, they 

were not intended to represent particular changes at a specific process at a specific refinery 

for permitting purposes. We recognize that the use of these growth factors may over 

predict emissions for a given refinery process since a particular process may be constrained 
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by existing permit limits and would have to undergo NSR review to increase capacity. In 

cases where existing permit limits constrained emissions at large sources; we attempted to 

take into account those constraints. However, it was not feasible (given time and resource 

constraints) to account for permit limits at each of the thousands of emission points at the 

refineries being studied. 

Next, we reviewed the Consent Decrees and coordinated with State and local agencies to 

develop estimates of future year emission reduction based upon the settlements and recent 

permits that implement the provisions of those settlements. We focused on the controls 

that are likely to be in place by 2009 since that is the SIP attainment planning year. The 

controls factors for 2009 were derived either from data supplied that the State/local 

agencies or from MACTEC’s analysis of the requirements contained in the global 

enforcement settlements. The specific timing and extent of emission reductions resulting 

from the Consent Decrees are evolving over time as the specific implementation 

requirements and schedules are being developed. Thus, there remains some uncertainty 

regarding the time and extent of emission reductions associated with the Consent Decrees. 

FLUID CATALYTIC CRACKING UNITS 

For FCCUs/FCUs, the control requirements generally require the installation of wet gas 

scrubbers for SO2 control. Some of the units have already been permitted to include the 

control requirements. In those cases, specific emission limits for SO2 have already been 

established and were used as the best estimate of emission in 2009. In cases where specific 

emission limitation have not yet been specified in permits, a 90 percent SO2 control 

efficiency was assumed as a conservative estimate of the SO2 reductions from the 

installation of a wet gas scrubber. For units not affected by a Consent Decree, MACTEC 

assumed that the Model Rule would require a wet gas scrubber (or equivalent) that would 

result in a 90 percent reduction of SO2 emissions. Table A-1 shows the unit-by-unit 

emission reductions anticipated after implementation of the Consent Decrees and Model 

Rule. 

For NOx control, the Consent Decrees require selective catalytic reduction (SCR), 

selective non-catalytic reduction (SCNR), or optimization studies to reduce NOx 

emissions. Some of the units have already been permitted to include the control 

requirements. In those cases, specific emission limits for NOx have already been 

established and were used as the best estimate of emission in 2009. In cases where specific 

emission limitation have not yet been specified in permits, a 90 percent NOx control 

efficiency was assumed for SCR, and a 60 percent reduction was assumed from the 

installation of SNCR. For units not affected by a Consent Decree, MACTEC assumed that 
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the Model Rule would require SNCR-type controls, and the emission reduction was 

conservatively estimated to 60 percent. Table A-2 shows the unit-by-unit emission 

reductions anticipated after implementation of the Consent Decrees and Model Rule. 

For PM control, reductions from the model rule were calculated by comparing the unit’s 

permitted emission limitation (in lbs/1000 lbs coke burned) or limitation contained in the 

Consent Decree to the model rule emission limitation (0.5 lbs/1000 lbs coke burned). If 

the unit’s current limit is at or below 0.5 lbs/1000 lbs coke burned, no additional emission 

reductions were assumed. Table A-3 shows the unit-by-unit emission reductions 

anticipated after implementation of the Consent Decrees and Model Rule. 

For CO control, reductions from the model rule were calculated by comparing the unit’s 

emission limitation (in ppm) to the model rule emission limitation (200 ppm hourly 

average). If the unit’s current limit is below 200 ppm, no additional emission reductions 

were assumed. Table A-4 shows the unit-by-unit emission reductions anticipated after 

implementation of the Consent Decrees and Model Rule. 
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Table A-1 Emission Reductions from Consent Decrees and Model Rules: SO2 Emissions from Catalytic C

 SO2 Emissions (tons/year) State Refinery 2002 

2009 

with 

CDs 

2009 

With 

Model 

Rules 

Model Rule Reductions Emission Calculation Assumptions 

DE Premcor FCCU 11,421 361 361 0 Permit APC-81/0981 limit with Wet Gas ScrDE Premcor FCU 19,461 174 174 0 Permit APC-81/0829 limit with Wet Gas ScrNJ Sunoco Eagle Point 91 5 5 0 CD specifies Wet Gas Scrubber Upgrade; assNJ Valero 3,597 172 172 0 Permitted emission limit after installation of NJ Amerada Hess 71 81 8 73 Not affected by a CD; assume 90% reduction NJ ConocoPhillips/Bayway 65 75 75 0 Existing Wet Gas Scrubber in 2002; no additPA Sunoco Marcus Hook 4,374 824 824 0 CD specifies Wet Gas Scrubber; assume 80% PA ConocoPhillips Trainer 2,063 166 166 0 CD specifies Wet Gas Scrubber; new permit PA Sunoco Phila. GP 1232 2,378 363 363 0 Permit limit with Wet Gas Scrubber required PA Sunoco Phila. PB 868 475 600 120 480 Not affected by CD, assume 80 percent reducPA United Refining 1,091 1,245 125 1,121 Not affected by a CD; assume 90% reduction VA Giant Yorktown 477 106 106 0 CD specifies Wet Gas Scrubber; assume 80% 

MARAMA Region 47,566 4,172 2,499 1,673
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Table A-2 Emission Reductions from Consent Decrees and Model Rules: NOx Emissions from Catalytic C

 NOx Emissions (tons/year) State Refinery 2002 

2009 

with 

CDs 

2009 

With 

Model 

Rules 

Model Rule Reductions Emission Calculation Assumptions 

DE Premcor FCCU 739 411 411 0 2009 emissions estimated by DNREC DE Premcor FCU 624 690 690 0 Permit APC-81/0829 limit based on Consent NJ Sunoco Eagle Point 103 47 47 0 CD specifies NOx study; assume 60% controNJ Valero 106 121 121 0 CD requires optimization study of existing co

reductions assumed 

NJ Amerada Hess 359 409 164 245 Not affected by a CD; assume 60% reduction NJ ConocoPhillips/Bayway 1,036 475 475 0 CD specifies enhanced SNCR; assume 60% PA Sunoco Marcus Hook 1,489 184 184 0 CD specifies SCR; assume 90% control PA ConocoPhillips Trainer 537 245 245 0 CD specifies enhanced SNCR; assume 60% PA Sunoco Phila. GP 1232 356 208 208 0 Permit limit with SCR required by CD PA Sunoco Phila. PB 868 182 482 193 289 Not affected by CD; assume 60% reduction fPA United Refining 29 33 13 20 Not affected by a CD; assume 60% reduction VA Giant Yorktown 210 233 93 140 Nothing specified in CD; assume 60% reduc

MARAMA Region 5,770 3,538 2,844 694
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Table A-3 Emission Reductions from Consent Decrees and Model Rules: PM Emissions from Catalytic C

 PM Emissions (tons/year) State Refinery 2002x 

2009 

with 

CDs 

2009 

With 

Model 

Rules 

Model Rule Reductions Emission Calculation Assumptions 

DE Premcor FCCU 765 390 390 0 No limit specified in permit; no reductions asDE Premcor FCU 496 334 167 167 Current limit is 1 lb/1000 lbs coke; model ru

assume 50% reduction from model rule 

NJ Sunoco Eagle Point 69 35 35 0 CD required 0.5 lbs/1000 lbs coke; assume 5NJ Valero 71 82 82 0 No limit specified in permit; no reductions asNJ Amerada Hess 44 50 50 0 No limit specified in permit; no reductions asNJ ConocoPhillips/Bayway 128 128 128 0 Existing permit limit is equivalent to 0.5 lbs/PA Sunoco Marcus Hook 209 105 105 0 CD required 0.5 lbs/1000 lbs coke; assume 5PA ConocoPhillips Trainer 113 93 93 0 Permit limit PA Sunoco Phila. GP 1232 42 170 170 0 Permit limit, CD required 0.5 lbs/1000 lbs coPA Sunoco Phila. PB 868 70 95 48 47 Not affected by CD; current limit is 1 lb/100

0.5 lbs/1000 lbs coke; assume 50% reduction 

PA United Refining 43 49 25 25 Current limit is 1 lb/1000 lbs coke; model ru

coke; assume 50% reduction from model rule 

VA Giant Yorktown 428 53 26.5 26.5 Current limit is 1 lb/1000 lbs coke; model ru

coke; assume 50% reduction from model rule 

MARAMA Region 2478 1548 1283.5 265.5

This table shows reductions of total suspended particulate emissions; reductions in PM2.5 are not available. 
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Table A-4 Emission Reductions from Consent Decrees and Model Rules: CO Emissions from Catalytic Cr

 CO Emissions (tons/year) State Refinery 2002 

2009 

with 

CDs 

2009 

With 

Model 

Rules 

Model Rule Reductions Emission Calculation Assumptions 

DE Premcor FCCU 1,524 1,640 656 984 No ppm limit specified in permit; assume 60DE Premcor FCU 1,209 1,291 516 775 Current limit is 500 ppm; model rule limit is 

reduction 

NJ Sunoco Eagle Point 83 95 95 0 Current limit is 127 ppm; no additional reduc

lower than Model Rule limit 

NJ Valero 53 61 61 0 Current limit is 50 ppm; no additional reduct

lower than Model Rule limit 

NJ Amerada Hess 130 148 99 49 Current limit is 300 ppm; model rule limit is 

reduction 

NJ ConocoPhillips/Bayway 99 113 113 0 Current limit is 200 ppm; no additional reduc

lower than Model Rule limit 

PA Sunoco Marcus Hook 514 484 194 290 Current limit is 500 ppm; model rule limit is 

reduction 

PA ConocoPhillips Trainer 60 69 28 41 Current limit is 500 ppm; model rule limit is 

reduction 

PA Sunoco Phila. GP 1232 514 634 254 380 Current limit is 500 ppm (1-hr avg) 100 ppm

model rule limit is 200 ppm; assume 60% red

PA Sunoco Phila. PB 868 52 100 40 60 Current limit is 500 ppm (1-hr avg) 100 ppm

model rule limit is 200 ppm; assume 60% red

PA United Refining 43 49 20 29 Current limit is 500 ppm; model rule limit is 

reduction 

VA Giant Yorktown 140 140 56 84 Current limit is 500 ppm; model rule limit is 

reduction 

MARAMA Region 4,421 4,824 2,130 2,694
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EQUIPMENT LEAKS 

Substantial emission reductions are achievable by enhanced LDAR programs (e.g., 

reducing the defined leak concentration, increasing the monitoring frequency, other 

requirements). Our best estimate is a 50% reduction in VOC emissions as a result of 

implementing enhanced LDAR programs similar to those required in the recent Consent 

Decrees and the MARAMA model rule. 

Several of the refineries in the MARAMA region already have leak definitions that are 

more stringent than the NSPS for some process units. Thus, the emission reductions 

expected from lower leak definitions will vary by refinery due to the differences in the 

current leak definitions. Resource constraints did not allow us to make emission reduction 

estimates on a process unit by process unit basis. We recommend that State’s further 

evaluate the refinery-specific baseline emissions, leak definitions, and potential emission 

reductions from lowering the leak definitions. 

It should be noted that both the baseline VOC emissions from equipment leaks, as well as 

the estimated emission reductions, are highly uncertain. On-going research and field 

studies suggest that VOC emissions could be much higher than currently estimated. The 

MARAMA States should monitor on-going and imminent national and state studies to 

better quantify baseline emissions and potential emission reductions. 

FLARES 

The MARAMA model rule contains similar requirements to the recently amended 

SCAQMD Rule 1118. In the “Final Environmental Assessment for Proposed Amended 

Rule 1118”, SCAQMD estimated a 53% reduction in all vent gases, and the concurrent 

combustions emissions (e.g., NOx, VOC, CO, and PM10) will also be reduced by 53%. A 

similar reduction in SO2 emissions is anticipated. Since the MARAMA model rule is 

similar to SCAQMD Rule 1118, similar reductions would be expected from 

implementation of the MARAMA model rule. 

It should be noted that both the baseline emissions from flares, as well as the estimated 

emission reductions, are highly uncertain. On-going research and field studies suggest that 

emissions could be much higher than currently estimated. The MARAMA States should 

monitor on-going and imminent national and state studies to better quantify baseline 

emissions and potential emission reductions. 
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Table A-5 Emission Reductions from Consent Decrees and Model Rules: VOC Emissions from Equipmen

 VOC Emissions (tons/year) State Refinery 2002 

2009 

with 

CDs 

2009 

With 

Model 

Rules 

Model Rule Reductions Emission Calculation Assumptions 

DE Premcor 64 32 32 0 Enhanced LDAR in CD; assume 50% controNJ Sunoco Eagle Point 42 21 21 0 Enhanced LDAR in CD; assume 50% controNJ Valero 66 33 33 0 Enhanced LDAR in CD; assume 50% controNJ CITGO Asphalt 10 5 5 0 Enhanced LDAR in CD; assume 50% controNJ Amerada Hess 14 14 7 7 No CD; assume Model Rule's enhanced LDA

50% reduction 

NJ Chevron 9.5 9.5 4.7 4.8 No CD; assume Model Rule's enhanced LDA

50% reduction 

NJ ConocoPhillips/Bayway 233 117 117 0 Enhanced LDAR in CD; assume 50% controPA Sunoco Marcus Hook 130 65 65 0 Enhanced LDAR in CD; assume 50% controPA ConocoPhillips Trainer 63 32 32 0 Enhanced LDAR in CD; assume 50% controPA American Refining 130 130 65 65 No CD; assume Model Rule's enhanced LDA

50% reduction 

PA Sunoco Philadelphia 176 88 88 0 Enhanced LDAR in CD; assume 50% controPA United Refining 167 167 84 84 No CD; assume Model Rule's enhanced LDA

50% reduction 

VA Giant Yorktown 310 155 155 0 Enhanced LDAR in CD; assume 50% controWV Ergon Newell 45 23 23 0 Enhanced LDAR in CD; assume 50% contro

MARAMA Region 1,459 889 729 160

ConocoPhillips Bayway initially estimated a VOC emissions of 1,629 tons/year from equipment leaks using the "leak/no leak" method factors consistent with the federal leak definition of 10,000 ppm. Emissions were recalculated using actual leak data and EPA correlati

software, resulting in a downward revision to 233 tons/year.
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Table A-6 Emission Reductions from Consent Decrees and Model Rules: SO2 Emissions from Flares 

 SO2 Emissions (tons/year) State Refinery 2002 

2009 

with 

CDs 

2009 

With 

Model 

Rules 

Model Rule Reductions Emission Calculation Assumptions 

DE Premcor 238 238 112 126 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

NJ Sunoco Eagle Point 21 21 10 11 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

NJ Valero 82 82 38 43 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

NJ CITGO Asphalt 0 0 0 0 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

NJ Amerada Hess 1 1 1 1 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

NJ Chevron 7 7 3 4 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

NJ ConocoPhillips/Bayway 222 222 104 118 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

PA Sunoco Marcus Hook 10 10 5 5 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

PA ConocoPhillips Trainer 15 15 7 8 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

PA American Refining 21 21 10 11 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

PA Sunoco Philadelphia 33 33 15 17 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

PA United Refining 1 1 0 0 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

VA Giant Yorktown 984 2 2 2 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

WV Ergon Newell 85 85 40 45 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

MARAMA Region 1,719 737 347 391
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Table A-7 Emission Reductions from Consent Decrees and Model Rules: NOx Emissions from Flares 

 NOx Emissions (tons/year) State Refinery 2002 

2009 

with 

CDs 

2009 

With 

Model 

Rules 

Model Rule Reductions Emission Calculation Assumptions 

DE Premcor 25 25 12 13 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

NJ Sunoco Eagle Point 78 78 37 42 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

NJ Valero 40 40 19 21 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

NJ CITGO Asphalt 1 1 0 0 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

NJ Amerada Hess 2 2 1 1 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

NJ Chevron 0 0 0 0 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

NJ ConocoPhillips/Bayway 12 12 6 7 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

PA Sunoco Marcus Hook 2 2 1 1 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

PA ConocoPhillips Trainer 44 44 20 23 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

PA American Refining 15 15 7 8 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

PA Sunoco Philadelphia 11 11 5 6 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

PA United Refining 13 13 6 7 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

VA Giant Yorktown 1,043 24 11 11 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

WV Ergon Newell 60 60 28 32 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

MARAMA Region 1,345 326 153 173
Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 

Appendix A – Emission Estimation Methodology Page A-13

MACTEC Federal Programs, Inc. 

Table A-8 Emission Reductions from Consent Decrees and Model Rules: VOC Emissions from Flares 

 VOC Emissions (tons/year) State Refinery 2002 

2009 

with 

CDs 

2009 

With 

Model 

Rules 

Model Rule Reductions Emission Calculation Assumptions 

DE Premcor 7 7 3 4 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

NJ Sunoco Eagle Point 484 484 228 257 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

NJ Valero 0 0 0 0 NJ CITGO Asphalt 0 0 0 0 NJ Amerada Hess 4 4 2 2 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

NJ Chevron 1 1 0 0 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

NJ ConocoPhillips/Bayway 25 25 12 13 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

PA Sunoco Marcus Hook 4 4 2 2 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

PA ConocoPhillips Trainer 90 90 42 48 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

PA American Refining 1 1 1 1 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

PA Sunoco Philadelphia 35 35 17 19 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

PA United Refining 12 12 5 6 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

VA Giant Yorktown 50 50 23 26 SCAQMD estimated 53% reduction in vent g

amendments; similar reductions for MARAM

WV Ergon Newell 0 0 0 0 

MARAMA Region 713 713 335 378