# 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 Associ ation is an association of ten state and local air pollution control agencies. MARAMA's mission is to strengthen the sk ills and capabilities of member agencies and to help them work togeth er to prevent and redu ce air pollution impacts in the Mid-Atlantic Region.

MARAMA provides cost-effective a pproaches to regional collabor ation by pooling resources to develop and analyze data, share ideas, and trai n staff to implement common requirements.

The following State and Local gove rnments 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, environmenta l and remedial construction industries. MACTEC provides premier management , technical, and professi onal services to help clients successfully manage complex businesses, projects, and facilitie s. Now operating with over 100 U.S. offices and 4,000 employees with speci alists in over 50 scient ific and engineering disciplines, MACTEC has the res ources 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 Ai r Management Association
711 West 40 th 

### 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 EngineerAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Page i

MACTEC Federal Programs, Inc. 

## ACKNOWLEDGEMENTS

MARAMA gratefully acknowledges the funding support pr ovided by the United States Environmental Protection Agency. This pr oject was funded by grants from the U.S. Environmental Protection Agency, Region II and Region III.

The following members of the Technical Over sight 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Page ii

MACTEC Federal Programs, Inc. 

## 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 REFINE RY 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 THERMA L 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 SO 2 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 .............................................................................................................2-23Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Page iii

MACTEC Federal Programs, Inc. 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................................................................4-12Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Page iv

MACTEC Federal Programs, Inc. 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 ......................................................................................................7-1Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Page v

MACTEC Federal Programs, Inc. 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................................................................................................................7-3 5
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 .........................................................................................................8-7Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Page vi

MACTEC Federal Programs, Inc. 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 Pr ocess..........................................................................................................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 RULESAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Page vii

MACTEC Federal Programs, Inc. 

### 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 Refi nery for 2009 (Accounting for Growth and Effects of On-the-Books and On-the-Way Requirements) Table 1-3 Recent Enforcement Settlements U nder EPA’s Petroleum Refinery Initiative

Table 2-1 Emission Invent ory for FCCUs and FCUs Table 2-2 Summary of MARAMA St ate Regulations for FCCUs/FCUs Table 2-3 Summary of Other Stat e 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 Inve ntory for Boilers/Heaters Table 3-2 Summary of NSPS Regulati ons for Boilers & Process Heaters Table 3-3 Summary of MA RAMA State Regulations Table 3-4 Summary of Ot her 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 MA RAMA State Regulations Table 6-3 Summary of Ot her State Regulations Table 6-4 Control Technology Options for Wastewater TreatmentAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Page viii

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### List of Tables (continued)

Table 7-1 Emission Invent ory for Storage Tanks Table 7-2 Properties of Group 1 Storage Vessels Table 7-3 Summary of MARA MA State Regulations Table 7-4 Summary of Ot her 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 MA RAMA State Regulations Table 8-3 Summary of Ot her 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 Cons ent Decrees and Model Rules - SO2 Emissions from Fluidized Catalytic Cracking Units Figure ES-2 Emission Reductions from Cons ent Decrees and Model Rules - NOx Emissions from Fluidized Catalytic Cracking Units Figure ES-3 Emission Reductions from Cons ent Decrees and Model Rules - PM Emissions from Fluidized Catalytic Cracking Units Figure ES-4 Emission Reductions from Cons ent Decrees and Model Rules - CO Emissions from Fluidized Catalytic Cracking Units Figure ES-5 Emission Reductions from Cons ent Decrees and Model Rules - VOC Emissions from Equipment Leaks Figure ES-6 Emission Reductions from Cons ent Decrees and Model Rules - SO2 Emissions from Flares Figure ES-7 Emission Reductions from Cons ent Decrees and Model Rules - NOx Emissions from Flares Figure ES-8 Emission Reductions from Cons ent 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 Refine ry Capacity and Emissions with Other StatesAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Page ix

MACTEC Federal Programs, Inc. 

### List of Figures (continued)

Figure 2-1 Diagram of a Fluidi zed 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 Wastewat er Collection and Treatment System Figure 6-2 Liquid Seal In sert 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 Exte rnal Floating Roof Tank Figure 7-4 Internal Floating Roof Tank Figure 7-5 Domed External Floating Roof Tank

Figure 8-1 Typical Claus Sulfur R ecovery 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 UnitAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Page x

MACTEC Federal Programs, Inc. 

## 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 PlantAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Executive Summary Page ES-1

MACTEC Federal Programs, Inc. 

## EXECUTIVE SUMMARY

This report was prepared for the Mid-Atla ntic Regional Air Mana gement Association (MARAMA) as part of an effort to assist stat es in developing State Implementation Plans (SIPs) for ozone, fine particles, and regional haze. MARAMA’s members re quested assistance in assessing control measure options for petroleum re finery emissions and in developing model rule provisions. The project was completed in three phases:

• 

### Phase I analyzed emissions from all refine ry processes, identified existing pollution control requirements, and a ssessed refinery processes in order of significance of emissions and the potential for additional emissi on 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 c ontain 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 boa rd, 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 (T SD) is intended to assist States in developing rules or other implementation mechanisms, as necessary and ap propriate, 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. Th e TSD does not attempt to define Reasonably Available Control Technology (RACT) or any othe r particular control le vel for the refinery processes it examines. With many jurisdictions in the Mid-Atlantic Region facing the need to
achieve additional emission reduc tions, 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 av ailable retrofit technol ogy (BART). MARAMA member States recognize that the determination of these control levels requires the consideration of site-specific factors. Thes e considerations will be addres s in individual State and local rulemaking and permitting processes.

Evaluation of Available Control Options

MACTEC, in consultation with the MARAMA Refinery Technica l Oversight Committee (TOC), reviewed the emission inventory and the existin g 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 measur es: 1) catalytic and thermal cracking units, 2)Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Executive Summary Page ES-2

MACTEC Federal Programs, Inc. 

### boilers and process heaters, 3) flares, 4) equipment leaks, 5) wastewater treatment, 6) storage tanks, and 7) sulfur recovery plants. These cat egories were chosen because they account for a large portion of the emission inventory and ther e is a potential for obtaining additional emission reductions. This study evaluate d emissions, existing requirements, and available control technology options and typical co sts. Table ES-1 presents the key findings regarding the emission inventory, existing requiremen ts, 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 cr acking 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 th e 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 fo r enhanced LDAR is generally based on the requirements of the recent consen t decrees, but with a lower l eak definition for valves. The model rule for flares is primarily based on th e 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 mini mization procedures, and flare monitoring.
Potential Impact of Model Rules
The assessment found that signif icant emission reductions will be achieved as a result of requirements already in place in recent Consent D ecrees for 10 of the 14 petroleum refineries in the MARAMA region. Adoption of the mode l rules would achieve additional emission
reductions at refineries where c onsent decrees have not been ne gotiated. These reductions would be modest, however, since the refineries in questio n are relatively small capacity facilities. Two
refineries without Consent Decrees are in northwe st Pennsylvania, and because of their location, modest reductions from these facilities may ha ve little impact on the nonattainment areas.
Significant reductions in emissions from fluidi zed 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 re quired to meet the NSPS limit of
1 lb/1000 lbs coke. The model ru le limit of 0.5 lbs/ 1000 lbs c oke 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 emi ssion reductions from FCCUs at refineries in the MARAMA region. Appendix A documents how th e emission reductions were calculated.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Executive Summary Page ES-3

MACTEC Federal Programs, Inc. 

### Implementation of the Consent Decrees enhanced leak detection will reduce VOC emissions significantly. Implementation of the model ru le will reduce emissions modestly beyond the levels established by the recently negotiated cons ent 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 w ould reduce refinery emi ssions beyond the levels established by the recently negotia ted consent decrees to some ex tent. 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 s hown that flare emissions are larg er 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 inve ntories, controlling flares may achieve more
sizable emission reductions in th e “real world” than are currently estimated based on the emission inventory.Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Executive SummaryPage ES-4MACTEC Federal Programs, Inc.Table ES-1 Key FindingsRefinery Process Emission Inventory Existing Requirements Available Control OptionsFluid CatalyticCracking Units(FCCUs)andFluid CokingUnits (FCUs)There are 12 FCCUs and one FCUin the MARAMA region. These 13emission units accounted for about78% of the SO2 and 29% of theNOx emitted from all refineryprocesses in 2002. As a result ofthe existing requirements inConsent Decrees, SO2 emissionsare expected to be reduced by 90%and NOx emissions by 38% by2009.Eight these FCCUs and the singleFCU are required to control SO2and NOx emissions as a result ofConsent Decrees which containmore stringent requirements thatexisting federal rules, State/localrules, or permit requirements. Fourother FCCUs are not affected by theConsent Decrees.SO2:1) Wet gas scrubber (or other technology) capableof meeting 25 ppmvd @ 0% O2based on 365-dayrolling average or 50 ppmvd @ 0% O2based on 7-day rolling average. Cost Effectiveness: $500-3,000/ton2) DeSOx additives capable of meeting 300 ppmvd.Cost Effectiveness*: $500-880/tonNOx:SCR or SNCR system (or other technology)capable of meeting 20 ppmvd, measured as a 365-day rolling average, and 40 ppmvd, measured as a7-day rolling average, @ 0% O2.NOx Cost Effectiveness*: $1520-2458/tonBoilersandProcessHeatersEmissions from these unitsrepresent the largest category ofNOx emission sources at refineriesand the second largest source ofSO2 emissions. Boilers and processheaters accounted for 63% of theNOx and 15% of the SO2 emittedfrom all refinery processes in 2002.As a result of the existingrequirements in Consent Decrees,SO2 emissions are expected to bereduced by 32% and NOxemissions by 36% by 2009.10 of the 14 refineries are requiredto control SO2 and NOx emissionsas a result of Consent Decrees thatcontain more stringent requirementsthat existing federal rules,State/local rules, or permitrequirements. The Consent Decreeswill generally require theelimination of fuel oil burning inboilers/heaters, compliance withNSPS Subpart J refinery gas H2Slimits, and installation of qualifyingcontrols to reduce NOx emissions.SO2:1) Eliminate or limit liquid fuel firing2) Limit sulfur content of liquid fuels;3) Limit hydrogen sulfide content of refinery fuelsto NSPS limit of 0.10 gr/dscf (162 ppm)SO2 Cost Effectiveness*: not quantifiedNOx:1) San Joaquin Rule 4306 limits of 0.0062 to 0.036lb/MMBtu for gaseous fuels and 0.052 lb/MMBtufor liquid fuels; Cost Effectiveness: to bedetermined.2) SNCR, SCR, Ultra-low NOx burners (or othertechnology) capable of meeting 0.04 lb/MMBtu;Cost Effectiveness*: $750-7402 per ton, dependingon size of unit and fuel typeAssessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Executive SummaryPage ES-5MACTEC Federal Programs, Inc.Refinery Process Emission Inventory Existing Requirements Available Control OptionsFlares Flares account for about 7% of theNOx, 4% of the SO2, and 10% ofthe VOC emitted at the 14 refineriesin 2002. Actual emissions areuncertain due to inadequatemonitoring of flare gas flow ratesand composition. Evidence fromCalifornia and Texas suggests thatemissions from flaring activities(and other nonroutine releases) maybe significantly underreported incurrent emission inventories.Requirements contained in theConsent Decrees are generally morestringent than existing state/localrules and permit requirements. TheConsent Decrees requirecompliance with NSPS emissionlimits and actions to prevent upsetsthat result in flaring.SO2, VOC, NOx, PM:Establish and follow flare minimization plan;Install analyzers to measure vent gas flow, higherheating value, and VOC/sulfur concentration;Conduct emissions reviews and root causeanalyses, and take corrective actions aftersignificant flaring events;Install flare gas recovery and treatment systems.Cost Effectiveness*: $4527-7063 per ton (totalSO2, NOx, VOC, and PM reduced).Equipment Leaks(FugitiveEmissions)Leaking equipment componentsaccount for 15% of the VOCemitted at the 14 refineries in 2002.Actual emissions are uncertain dueto difficulty in accuratelymonitoring thousands of individualcomponents.The Consent Decrees containrequirements for “enhanced” leakdetection and repair programs toreduce fugitive emissions;otherwise subject to NSPS orNESHAP requirementsVOC:“Enhanced” leak detection and repair programrequirements based on program elements containedin the Consent Decrees. Elements include: writtenLDAR procedures; training of assigned personnel;internal and third party audits; more stringent leakdefinitions; increased monitoring frequency;corrective action for “chronic leakers”; electronicstoring and reporting of data; additional QA/QCrequirements.Cost Effectiveness*: $1300/tonWastewaterTreatmentWastewater treatment accounts for21% of the VOC emitted at the 14refineries in 2002Many systems already subject toNSPS Subpart QQQ, NESHAPSubpart CC, or NESHAP SubpartFF requirements; Consent Decreesrequire review and verification ofcompliance status and correctiveactions to correct noncompliance.VOC:For wastewater collection systems, installingcovers and seals on the collection components toreduce fugitive VOC emissions,For wastewater treatment system, maintaining orinstalling a control device such as carbon canistersto destroy VOCs released during treatmentVOC Cost Effectiveness*: $1900-4200/tonAssessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Executive SummaryPage ES-6MACTEC Federal Programs, Inc.Refinery Process Emission Inventory Existing Requirements Available Control OptionsStorage Tanks Storage tanks account for 26% ofthe VOC emitted at the 14 refineriesin 2002Most tanks already subject to eitherNSPS, NESHAP, or staterequirementsVOC:Install floating roofs in fixed roof tanks; installdomed fixed roof on external floating roof tank;replace vapor-mounted primary seal with a liquidmounted primary seal; install secondary seals; usevapor recovery systems or incineration.VOC Cost Effectiveness*: not quantifiedSulfur RecoveryUnitsSulfur recovery plants accountedfor 2% of the SO2 emitted at the 14refineries in 2002; over half of allSO2 emissions from sulfur recoveryunit come from the GiantYorktown, VA, SRU.The Consent Decrees generallyrequire compliance with NSPSSubpart J and the elimination,control, and monitoring of sulfur pitemissions. The Giant Yorktownrefinery is required to install a tailgas unit or equivalent controltechnology. The ConocoPhillipsBayway refinery is to conduct anoptimization study and implementrecommendations.SO2:A variety of control technologies are availablewhich can meet the NSPS emission limit of 250ppmv, dry basis, corrected to zero percent oxygenSO2 Cost Effectiveness*: $167-449/ton* See Sections 2-8 for a discussion of the references used to determine the cost-effectiveness for each source category. The cost data provided in this table wereobtained from the published literature as referenced. In general,the percent reductions and cost data represent data for typical sources that are uncontrolled.Site-specific factors can affect the actual cost effectiveness.Incremental costs for sources thatalready have some level ofcontrol will likely be higher.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 Fluidize d 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 RulesSO2 (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

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2009 with CDs
2009 With Model RulesAssessment 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 Fluidize d 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 RulesNOx (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

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2009 with CDs
2009 With Model RulesAssessment 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 Fluidize d 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 RulesPM10 (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 particul ate emissions; reductions in PM2.5 are not available.



### Cracking Unit PM Emissions



### 0 200 400 600 800

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2009 w/ CDs
2009 w/ Model RulesAssessment 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 Fluidize d 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 RulesPM10 (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

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2009 with CDs
2009 With Model RulesAssessment 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 RulesVOC (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

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2009 w/ CDs 2009 w/ Model RulesAssessment 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 RulesSO2 (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

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2009 with CDs
2009 With Model RulesAssessment 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 RulesNOx (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

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ewellNOx (tpy) 2002 2009 with CDs 2009 With Model RulesAssessment 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 RulesVOC (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

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2009 with CDs
2009 With Model RulesAssessment 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 deta iled control measure analysis.

1.1 EMISSION INVENTORY
Figure 1-1 shows the location of th e 14 petroleum refineries in th e Mid-Atlantic States. This
section summarizes the emission i nventories for these sources.

Figure 1-1. Location of Petroleum Refineries in the Mid-Atlantic StatesAssessment 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 fo r each of the 14 refineries (note that the Sunoco Marcus Hook refinery is sp lit into two facilities in the inventory: one facility for the equipment located in Pennsylvania and another faci lity 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 ni trogen (NOx), particulate matter less than 2.5 microns (PM2.5), sulfur dioxide (SO2), a nd 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 de veloped 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 inventorie s 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 settleme nts. 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 fact ors 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 ar e 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 cu rrently 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 refi nery. Other causes fo r the decrease in SO2
emissions include the elimination of fuel oil combustion in boilers/heaters and installation of pollution controls at the catalytic cracki ng units at other refineries.

• 

### For NOx, refinery emissions are projected to decrease by 12 percent due to requirements currently on-the-books. Re ductions in NOx emissions are projected to result from
additional control of emissions from the boi lers/heaters and catalyt ic 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 82,000 a 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 82,000 a 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 co nsistent with the federal leak defin ition of 10,000 ppm. Emissions were recalculated using actual leak data and EPA correlation equations LeakDas so ftware, 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 emissi ons 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 bo iler 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 heater s are not expected to change much between 2002 and 2009 - anticipate d 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 projecte d 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. A bout 58 percent of the fine particulate is emitted from this group. Boil ers/heaters and flares ar e the other significant sources of PM2.5. PM2.5 emissions are projecte d 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 fr om the cracking/coking uni ts are anticipated to decline dramatically between 2002 and 2009, primar ily 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 fr om flares and the sulfur recovery plants are projected.

There are several significant sources of VOC em issions. Storage tanks containing crude oil, intermediate process feeds, and refined produc ts represent the larg est source of VOCs.
Wastewater collection and treatm ent 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 e quipment whenever components in the liquid or gas stream leak. Components such as pumps, va lves, 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 tr ucks. 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 Optionsfor Petroleum Refineries January 31, 2007Section 1 – Emission Inventory andExisting Requirements Page 1-6MACTEC Federal Programs, Inc.02,5005,0007,50010,00012,50015,000

Tons/yearCracking/Coking UnitsBoilers/HeatersFlares OtherFigure 1-2a NOx Emissions by Process010,00020,00030,00040,00050,000

Tons/yearCracking/Coking UnitsBoilers/HeatersFlares OtherFigure 1-2c SO2 Emissions by Process05001,0001,5002,0002,5003,000

Tons/yearCracking/Coking UnitsBoilers/HeatersFlares OtherFigure 1-2b PM2.5 Emissions by Process02505007501,0001,2501,5001,7502,0002,250

Tons/yearLeaks Tanks WasteWaterFlares Loading OtherFigure 1-2d VOC Emissions by Process■2002■2009■2002■2009■2002■2009■2002■2009Assessment 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 an d process, we also compared emissions from
all refineries in the MARAMA re gion 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 refi neries in the MARAMA region to the 13 refineries in the Midwest Regional Pl anning Organization (MRPO) region, 21 refineries in California, 17 refineries in Louisiana, and 26 refineries in Texas. The capacity data was obtained from the Energy Inform ation Administration, and the emi ssions 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 re fineries in the MARAMA region are generally consistent with the emissions data being reporte d for the refineries in CA, LA, and TX. For example, the 14 refineries in the MARAMA regi on have about the same crude distillation and catalytic cracking capacity as th e 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 larg e source of SO2 in 2002 and is considered an outlier compared to other refine ries. 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 PM2.5Capacity 100 Barrels/Day;Emissions tons/year MARAMA MRPO CA LA TX

Figure 1-3 Comparison of 2002 MARAMA Refinery Capacity and Emissions with Other StatesAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 1 – Emission Inventory and Existing Requirements Page 1-8

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### 1.1.4 Emission Uncertainties
For some refinery sources, such as boilers and cracking units, emissions are monitored continuously using sophisticated equipment that provi des a fairly accurate estimate of emissions. For other sources, emissions cannot easily be dir ectly 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 id entify leaking equipment.

Recently, there has been an increased concern ab out the potential underestimation of emissions from certain sources at refineries. For example, there is some evidence that emissions from nonroutine events (such as equipm ent breakdowns, startup, shutdown and maintenance) are not fully accounted for in the emission inventory, and that em issions from these events in some cases far exceed the annual emissions reported in the invent ory. 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 inventor y annual totals. The potential underestimation of
emissions from non-routine events should be considered during the selection of refinery processes for detailed control measur e analysis in th e MARAMA region.

1.2 EXISTING REQUIREMENTS
Petroleum refineries are governed by multiple fe deral and state/local re gulations under the Titles
I and III of the Clean Air Act. Refineries ar e also subject to contro l technology assessments anytime they construct a new or modify an existi ng major source. Recently, refineries have been the subject of an enforcement initiative to ensu re that the sources meet these regulatory and permitting requirements. Settlements from these enforcement actions will result in the installation of additional pollu tion control equipment. The following paragraphs generally describe the existing requirements for refineri es in the Mid-Atlantic region. The specific requirements from each of these programs are discu ss in detail in Sections 2-8 of this document.

1.2.1 Federal Regulations
Title I of the Clean Air Act imposes New S ource Performance Standards (NSPS) on certain specified categories of new and modified large st ationary sources. There are NSPS that affect the petroleum refining industry. Most of thes e standards were devel oped 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 fi nalized revisions to the NSPS for stationary
combustion turbines and boilers.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 1 – Emission Inventory and Existing Requirements Page 1-9

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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. Th ese Maximum Achievable Control Technology (MACT) standards apply to major sour ces of hazardous air pollutants (HAPs). The petroleum refinery MACT (Subpart CC) was promulgated in 1995, a nd most of its requirements affecting primarily organic HAP sources have al ready been implemented. Several other MACT
standards became effective in the 1990s that affect ed specific refinery pr ocesses 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 liqui ds distribution (nongasoline), reciprocating engines, stationary combustion turbines, and remediation sites. While designed to reduce HAP emissions, the require ments 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 emitt ing air pollutants that reduce visibi lity. The BART requirements of the regional haze rule apply to f acilities built between 1962 and 1977 th at have the potential to emit more than 250 tons a year of visibility-impairing pollutants. Those facilities fall into 26 categories, including petroleum refi neries. Some of these facili ties previously have not been subject to pollution control requir ements for these pollutants. U nder the final BART guidelines, states are required to co nduct source-by-source BART determinati ons to identify which facilities must install controls and the type of controls to be used.

A list is provided at the end of this sec tion 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 requiri ng local governments to adopt State Implementation Plans (SIPs) that set forth their strategy for achieving reductions in th e particular criteria pollutant(s) for which they are out of attainme nt. The SIP requirements includes Reasonably Available Control Technology (RAC T) 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 develope d regulations limiting emissions from refineries based in part on the Control Technique Gu idelines (CTGs) or Alternative Control Techniques (ACT) documents developed by EPA, or case-by-case RACTAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 1 – Emission Inventory and Existing Requirements Page 1-10

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### determinations. A list is provided at the end of this section identifying the CTGs and ACT documents that are potentially appl icable 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 tw enty-two states that co ntributed to 1-hour ozone
nonattainment in other states. Th e rule required aff ected 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, in cluding 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 modificati ons 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 evol ve 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 tec hnology evaluation requirement. Ne w Jersey has a State-of-theArt (SOTA) requirement for many type s 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 na tion'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 ag encies have negotiated settlements that will require significant investment in pollution co ntrol technology and will result in emission reductions in the future. The major refinery sour ces that are affected by the judicial settlements are: FCCUs/ (FCUs), process heaters and boilers , sulfur recovery plan ts, flare gas recovery, equipment leaks, and wastewater treatment.

Table 1-3 lists the recent enforcement settlement s under EPA’s Petroleum Re finery Initiative that affect petroleum refineries in the MARAMA re gion. Ten of the 14 refineries in the MARAMA region have been included.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 1 – Emission Inventory and Existing Requirements Page 1-11

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### Table 1-3 – Recent Enforcement Settlements U nder 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 sett lements 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 Co mmittee reviewed the emission inventory, the existing requirements for each source category, and the resources available for this project. Based on that review, the followi ng refinery processes were sele cted 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 fo r these seven categories is presented in the
remainder of this document.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 1 – Emission Inventory and Existing Requirements Page 1-12

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### 1.4 REFERENCES
Energy Information Administration, June 2005, “Petroleum Supply Annual 2004: Table 38 Capacity of Operable Petroleum Refine ries 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, Versio n 3 of the 2002 Point Source Emission Inventory, http://www.marama.org/visibility/Invento ry%20Summary/2002E missionsInventory.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 Ag ency, 2005, Draft Fina l Version of the 2 002 National Emission Inventory.

Visibility Improvement State and Tribal Association of the Sout heast (VISTAS), 2005, Version Base 4f of the 2002, 2009, and 20 18 Point Source Emission Inventory.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 1 – Emission Inventory and Existing Requirements Page 1-13

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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 Exte rnal 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 Gene rators 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 1977Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 1 – Emission Inventory and Existing Requirements Page 1-14

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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 Di stillation 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 1994Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 1 – Emission Inventory and Existing Requirements Page 1-15

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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 Faciliti es (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 (MAC T 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 2004Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 2 – Catalytic and Ther mal Cracking Units Page 2-1

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## 2.0 CATALYTIC AND THERMAL CRACKING UNITS

At many petroleum refineries, fl uid catalytic cracking units (F CCU) and fluidized coking units (FCU) are among the largest air emission sources at the refinery. Numer ous technologies have been developed over the years for pollution control at cracking units. In 1980’s, the concern was primarily PM and SO 2 

### . Today, there is concern with NO x, CO, and VOCs as well as further
control of PM and SO 2 

### . This Section presents an asse ssment of available control technology options for FCCUs and FCUs for states to consider as they undertake effo rts to develop rules and State Implementation Plans (SIPs) for ozone, PM 2.5 

### , and regional haze.

2.1 PROCESS DESCRIPTION
Cracking units convert middle dis tillate, gas oil and residuum into primarily gasoline, jet and diesel fuels by using a series of processing steps that literally “cr ack” 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, su ch as delayed and fluid coking units, rely on thermal energy to promote cracking w ithout the use of a catalyst.

Typical FCC systems consist of a reactor, catalys t 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 catalys t (usually zeolite s upported by amorphous synthetic silica-alumina with metals) in the rise r pipe. Due to the hi gh reactivity of modern catalysts, most of the cracking takes place inside the riser pipe at temperatures between 880 and
980 o 

### F. 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 frac tions are separated, steam stripped, cooled, and collected. Slurry oil removed fr om the bottom of the fractionation tower is used either as wash oil and a quench for the hot reactor overhead va pors 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 regenerato r. The catalytic cracking proce ss 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 (com plete) or partial combustion mode. In the full combustion mode, the regenerator is operated at temperatures around 1300 o 

### F to oxidize all coke
carbon to CO 2 

### 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 w ith coke containing high metal

content.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 2 – Catalytic and Ther mal Cracking Units Page 2-2

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

SOURCE: http://www.refractor ydepot.com/FCCU.gif

FCCU systems are the most widely used cracki ng 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 furt her breakdown the heaviest fractions from distillation bottoms. Air pollution control issues for fluid coking un its are similar to those for fluidized catalytic cracking units, while delayed coki ng 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 2 – Catalytic and Ther mal Cracking Units Page 2-3

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### 2.2 EMISSION INVENTORY

Table 2-1 identifies the FCCU s and coking units in the MARAMA region, along with the capacity of each unit. Criteria po llutant 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 MANE VU and VISTAS projecti on inventories that were developed to support modeling for SIP de velopment. 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 regul ations or enforcement settlements. The growth factors used for projecting emissions from 2002 to 2009 came from the U.S. Environmental Protection Agency’s Economic Gr owth Analysis System (EGAS 5.0) and the U.S. Department of Energy’s Annual Energy Outl ook (2005) projections. The controls factors for 2009 were derived either from data supplied th at the State/local agenci es 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 Co nsent 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 (Gir ard Point) was issued a permit on February 28, 2006 to increase the daily feed rate to 100,000 ba rrels per any single da y 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 fe ed rate to 58,000 barrels per any single day and 56,000 barrels per day on a rolling 365-day aver age. The emissions for 2009 for the 1232 FCCU and the 868 FCCU reflect the permit limits th at are expected to be in place in 2009.

Table 2-1 shows that SO 2 

### emissions for several FCCUs/FCUs are projected to be reduced by 2009 as a result of the requirement s of the enforcement settlements (to be discussed in more detail later), resulting in a re gion-wide reduction of about 90 percent for a ll units in the region. The region-wide NOx emission reductions are pr ojected to be about 40 percent by 2009 as a
result of the enforcement settlements and othe r on-the-books requirements. Smaller reductions
in PM and VOC emissions are also projected as a result of compliance with the MACT
standards.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 2 – Catalytic and Ther mal Cracking Units Page 2-4

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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 NH 3 NOx PM 10 SO 2 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 140 e 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 hi gher than shown since consent decree controls are not required until 2013; Keit h Lemchak, AMS, provided revised 2009 em issions based on current permit limits and consent decree requirements.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 2 – Catalytic and Ther mal Cracking Units Page 2-5

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### 2.3 EXISTING REQUIREMENTS

This section discusses th e regulatory requirements which apply to cracking units. Four types of requirements are discussed: (1) Federal requi rements such as the New Source Performance Standards (NSPS) and Maximum Ac hievable Control Technology (M ACT) 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 emissi ons exiting the FCCU catalyst regenerator. Particulate matter discharged from the catalyst regenerator should not ex ceed 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 thro ugh 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
SO 2 

### emissions, three options exist for compliance. First, if an add-on SO 2 

### control device is present, SO 2 

### emissions must be controlled by 90% or limited to 50 ppmv, whichever is less stringent. Second, if no control device is used, SO 2 

### emissions must be limited to 20 lb/ton coke burn-off. The third option limits the sulfur c ontent of fresh feed to the FCCU to 0.30% by weight. Subpart J also limits CO emissions fr om the catalyst regenerator to 500 ppmvd on a 1- hour average.

National Emission Standards for Ha zardous Air Pollutants (NESHAP) were developed as part of section 112(d) of the Clean Air Act, which require s that major sources of HAP, those that have the potential to emit at least 10 tpy of any singl e 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 th e following sources: misce llaneous process vents, storage vessels, wastewater co llection/treatment, and equipmen t leaks. The second NESHAP applying to petroleum refineri es is the MACT II standard (40 CFR 63, Subpart UUU), which applies to catalytic cracking un its, catalytic reforming units, su lfur recovery units, and bypass

vents.
Under Title 40, CFR, Part 63, Subpart UUU, fo r 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 th rough an incinerator or waste he at 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 averag e in any 1-hour period. For those FCCUs not subject to NSPS limitations, then four options ex ist 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 cokeAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 2 – Catalytic and Ther mal Cracking Units Page 2-6

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### burn-off, (3) limit Nickel emissions to 0.029 lb/hr, or (4) limit Nickel em issions 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, SO 2 

### , and CO. Most states limit PM emissions using proce ss 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 Qualit y Management District – BAAQMD and the South Coast Air Quality Ma nagement District – SCAQMD). Regulations from these states are presented because these states have a large num ber 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 requi rements 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 se ction 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 und ertook an initiative to investigate physical modifications to FCCUs. Cap acity increases and modificatio ns should have triggered NSR permitting and pollution control requirements. Th ere 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 mon itoring equipment so that facilities, EPA, and
States can access real time em issions data. More importantly, Consent Decrees also require facilities to install and impleme nt a suite of controls to reduce NOX, SO2, and PM emissions. Table 2-5 provides a list of recent enforcemen t settlements for FCCUs and coking units at petroleum refineries in the MARAMA region.

For particulate emissions, the mo st stringent performance level specified in the Consent Decree requirements is 0.5 pounds PM per 1000 pounds c oke 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 rollin g 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 averageAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 2 – Catalytic and Ther mal Cracking Units Page 2-7

MACTEC Federal Programs, Inc. 

### Table 2-2: Summary of MARAMA St ate Regulations for FCCUs/FCUs

Agency PM SO 2 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: SO 2 emissions should meet ambient air quality standards (80 μ g/m 3 on annual basis, 365 μ g/m 3 on 24-hr basis, 1300 μ g/m 3 on 3-hr basis) Reg. 11, Section 2: In New Castle County, CO emissions must be
burned at 1300 o 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 SO 2 should not exceed ground level concentrations of 3ppmv, 0.5 ppmv for 15-min avg, and 0.1 ppmv for 8-hr avg. (2) SO 2 in exhaust streams ≤ 0.05% by volume Reg. 8: Gases containing CO
emissions should be incinerated at
≥ 1400 o 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(P 0.67 ) for P < 30 tph; (2) E = 55(P 0.11 )-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 ppmvAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 2 – Catalytic and Ther mal Cracking Units Page 2-8

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### Table 2-3: Summary of Other Stat e Regulations for FCCUs and FCUs

Agency PM SO 2 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(q 0.62 ), where q is the stack effluent flow rate (acfm), however, if the effective stack height (H E ) < standard effective stack height (H SE ), then the allowable emission rate is multiplied by (H E /H SE ) 2 ; Formulas for H E and H SE 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% O 2 ; (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(P 0.67 ) ≤ 40 lb/hr) 9-1-310: ≤ 1,000 ppmv 9-10-304: (1) ≤ 150 ppmvd @ 3% O 2 (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% O 2 (24-hr avg)

SCAQMD Rule 1105.1 Comply with one of the following: (1) 3.6 lb/hr; (2) 0.005 gr/dscf @ 3% O 2 ; (3) 2.8 lb/thousand barrel fresh feed Rule 1105: 132 lb/thousand barrel feed charged to FCCUDraft Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Section 2 – Catalytic and ThermalCracking Units Page 2-9MACTEC Federal Programs, Inc.Table 2-4: Summary of PermitRequirements FCCUs and FCUsRefinery & UnitRequired PM Control Technologyor Emission LimitationRequired SO2Control Technologyor Emission LimitationRequired NOx Control Technologyor Emission LimitationRequired CO Control Technologyor Emission LimitationValero Delaware CityEUID = 011/012FCCU w/ CO BoilerTSP - 1 lb/1000 lb of coke burnedCompany shall propose lb/hr and tpyPM10 and H2SO4 emission limits25 ppmvd or lower on a 365-dayrolling avg, 50 ppmvd on a 7-dayrolling avg basis, each corrected to0% O2, and 361 tpyReserved CO emission limit 500 ppmv and3,768 tpyCO burned at no less than 1300F for0.3 seconds in the CO boilerValero Delaware CityEUID = 001/002Fluid Coker Unit w/COBoilerTSP - 47.1 lbs/hr and 206.3 tpyH2SO4 - 58 lbs/hr and 252.3 tpyPM10 - 133.1 lb/hr and 133.1 tpy25 ppmvd or lower on a 365-dayrolling avg, 50 ppmvd on a 7-dayrolling avg basis, each corrected to0% O2, and 174 tpyNot exceed level to be established inaccordance with Consent Decree (i.e.,SNCR optimization study)Emission limit 689.8 tpyCompany shall propose limit inconjunction with SNCR optimizationstudyCO burned at no less than 1300F for0.3 seconds in the CO boilerSunoco Eagle PointEUID = U9FCCUTSP - 11.4 lbs/hrH2SO4 - 15 lbs/hrPM10 - 30 lbs/hrEDV-6000 scrubber - Permittee/DEPwill decide on appropriate parameterfor maximum feed sulfur content orbarrel per day feed rateSO2 emission limit 75 lbs/hrEmission limit 50 lbs/hr Emission limit 75 lbs/hrValero RefiningEUID = U1FCCUTSP – 120.4 tpyH2SO4 – 51.55 tpyPM10 – 120.4 tpyBELCO wet scrubberSO2 emission limit 172 tpyEmission limit 222.9 tpy Emission Limit 150.5 tpyAmerada HessEUID = U1FCCUTSP – 0.02 gr/scfTSP – 22 lbs/hrH2SO4 – 12.86 lbs/hrPM10 – 36 lbs/hrWet gas scrubberSulfur content of fresh feed < 1% byweightEmission limit 80 lbs/hr or141 ppmvd at 0% oxygen, whicheveris lowerEmission limit 160 lbs/hr or328 ppmvd at 0% oxygen, whicheveris lowerEmission limit 160 lbs/hr or300 ppmvd at 0% oxygen, whicheveris lowerConocoPhillips BaywayEUID = U4FCCU w/ 2 CO BoilersPM10 – 59.9 lbs/hrTSP – 50.2 lbs/hrParticulate – 0.02 grains per scfH2SO4 – 150 lbs/hrSulfur content of fresh feed < 1% byweightEmission limit 25 ppm @ 7% oxygenEmission limit 77.6 lbs/hrEmission limit 261 tpyEmission limit 334.7 lbs/hrEmission limit 1,127.8 tpyEmission limit 872 lbs/hr and500 ppmvd at 7% oxygenDraft Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Section 2 – Catalytic and ThermalCracking Units Page 2-10MACTEC Federal Programs, Inc.Table 2-4: Summary of Permit Requirements FCCUs and FCUs (continued)Refinery & UnitRequired PM Control Technologyor Emission LimitationRequired SO2Control Technologyor Emission LimitationRequired NOx Control Technologyor Emission LimitationRequired CO Control Technologyor Emission LimitationSunoco Marcus HookEUID = 101PLT 10-4 FCC w/ COBoiler0.02 grains per SCF 500 ppmv 0.0149 lbs/barrel of fresh feed Two CO Boilersinstalled to controlCO emissions from catalystregenerator500 ppm, dry basisConocoPhillips TrainerEUID = 101FCC w/ CO Boiler0.02 grains per SCF 500 ppmv 500 ppm Nothing specifiedSunoco PhiladelphiaEUID = 019GP 1232 w/ CO BoilerWet gas scrubber; FilterablePM/PM10 (0.30 lb/1000 lb cokeburn-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/PM10Filterable and Condensable (40.0lbs/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 withH2S>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 avg100 ppmdv @ 0% O2, 365-day rollavg; 500 ppmvd @ 0% O2, 1-hr avgSunoco PhiladelphiaEUID = 539PB 868 FCCU1 lb/1000 lb cokeComply with NSPS Subpart A and JComply with NSPS Subpart A and J Comply with NSPS Subpart A and J 100 ppmdv @ 0% O2, 365-day rollavg; 500 ppmvd @ 0% O2, 1-hr avgUnited RefiningEUID 101AFCCU0.04 grain per SCF 285 lbs/hr1,248.3 tpy71 lbs/1000 barrels FCC feed Nothing specifiedGiant YorktownEUID = 6FCCU0.05% of the rate of catalystrecirculation within the unit, rolling12-month basisCOM measured opacity of 30%EPA Method 9 opacity of 20%2,000 ppm by volume, rolling 12-month basisNothing specified Nothing specifiedDraft Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Section 2 – Catalytic and ThermalCracking Units Page 2-11MACTEC Federal Programs, Inc.Table 2-4: Summary of Recent Enforcement Settlements for FCCUs and FCUsRefinery & UnitRequired PM Control Technologyor Emission LimitationRequired SO2Control Technologyor Emission LimitationRequired NOx Control Technologyor Emission LimitationRequired CO Control Technologyor Emission LimitationValero Delaware CityEUID = 011/012FCCU w/ CO BoilerComply with NSPS Subparts A and JWet gas scrubber; 25 ppmvd or loweron a 365-day rolling avg, 50 ppmvdon a 7-day rolling avg basis, eachcorrected to 0% O2, and 361 tons/yearOriginal consent decree specifiedcatalyst additive trials followed byoptimization.A subsequentamendment specified optimization ofkey CO boiler operating parameters.500 ppmv (dry bsis)Valero Delaware CityEUID = 001/002Fluid Coker Unit w/COBoilerNothing Specified Wet gas scrubber; 25 ppmvd or loweron a 365-day rolling avg, 50 ppmvdon a 7-day rolling avg basis, eachcorrected to 0% O2, and 174 tons/yearSNCR & NOx reducing catalystadditives; emission limits to bedetermined through optimizationstudyNothing SpecifiedSunoco Eagle PointEUID = U9FCCU0.50 lb/1,000 lb coke burned on a 3-hr rolling avg, 19 lbs/hr TSP, and 48lbs/hr PM10on a 1-hr block avg; wetgas scrubber upgrade, limit of 30lbs/hr on 1-hr block avg.25 ppmvd or lower on a 365-dayrolling avg, 50 ppmvd on a 7-dayrolling avg basis, each corrected to0% O2, and 67.4 lbs/hr on a 1-hrblock avgContinued use of low NOx promoterEliminox ; 75 ppmvd on a 3-hr rollingavg @ 0% O2and 50 lbs/hr on a 1-hrblock avg;Conduct NOx control technologystudy of SCR, LoTox, and others;install NOx controls by April 30,2008100 ppmvd @ 0% O2on a 365-dayrolling avg basis and current NJDEPlimit of 72.5 lbs/hr on a 1-hr blockavgInstall a CO & O2CEMSValero RefiningEUID = U1FCCUNothing Specified Wet gas scrubber; 25 ppmvd @ 0%O2based on 365-day rolling avg or 50ppmvd @ 0% O2based on 7-dayrolling avgOptimization study of existing controlsystem; 20 ppmvd, measured as a365-day rolling avg, and 40 ppmvd,measured as a 7-day rolling avg, @0% O2500 ppmvd (@ 0% O2) measured as a1-hr block avgAmerada HessEUID = U1FCCUNot included in national petroleumrefinery initiativeConocoPhillips BaywayEUID = U4FCCU w/ 2 CO BoilersWet gas scrubber (ContinuedOperation), 0.50 lb/1,000 lb cokeburned on a 3-hr rolling avgWet gas scrubber (ContinuedOperation); 25 ppmvd or lower on a365-day rolling avg basis and 50ppmvd or lower on a 7-day rollingavg basis @ 0% O2Enhanced SNCR to reduce NOx asmuch as feasible500 ppmvd on a 1-hr block avg @ 0%O2Draft Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Section 2 – Catalytic and ThermalCracking Units Page 2-12MACTEC Federal Programs, Inc.Table 2-5: Summary of Recent Enforcement Settlements (continued)Refinery & UnitRequired PM Control Technologyor Emission LimitationRequired SO2Control Technologyor Emission LimitationRequired NOx Control Technologyor Emission LimitationRequired CO Control Technologyor Emission LimitationSunoco Marcus HookEUID = 101PLT 10-4 FCC w/ COBoilerIf a wet gas scrubber is installed, thenmust comply with either (1)continued operation of the ESP, (2)install new ESP, or (3) acceptemission limit of 0.5 lb/1,000 lb cokeburned; Otherwise,PM limit is 1.0lb/1,000 lb coke burnedWet gas scrubber; 25 ppmvd @ 0%O2based on 365-day rolling avg or 50ppmvd @ 0% O2based on 7-dayrolling avgSCR system; 20 ppmvd @ 0% O2based on 365-day rolling avg and40 ppmvd @ 0% O2based on 7-dayrolling avg500 ppmvd on a 1-hr block avg @ 0%O2Install a CO & O2CEMSConocoPhillips TrainerEUID = 101FCC w/ CO BoilerWet gas scrubber, 0.5 lb/1,000 lbcoke burned on a 3-hr rolling avg.Wet gas scrubber; 25 ppmvd @ 0%O2based on 365-day rolling avg or 50ppmvd @ 0% O2based on 7-dayrolling avgEnhanced SNCR; emission limits tobe determined through optimizationstudy500 ppmvd on a 1-hr block avg @ 0%O2;Optional 100 ppmvd @ 0% O2 on a1-hr block avg limitInstall a CO & O2CEMSSunoco PhiladelphiaEUID = 019GP 1232 w/ CO BoilerIf a wet gas scrubber is installed, thenmust comply with either (1)continued operation of the ESP, (2)install new ESP, or (3) acceptemission limit of 0.5 lb/1,000 lb cokeburned; Otherwise,PM limit is 1.0lb/1,000 lb coke burnedWet gas scrubber; 25 ppmvd @ 0%O2based on 365-day rolling avg or 50ppmvd @ 0% O2based on 7-dayrolling avgSCR system; 20 ppmvd @ 0% O2based on 365-day rolling avg and40 ppmvd @ 0% O2based on 7-dayrolling avg500 ppmvd on a 1-hr block avg @ 0%O2Install a CO CEMSSunoco PhiladelphiaEUID = 539PB 868 FCCUNothing Specified Nothing specified Nothing specified 100 ppmvd on a 365-day rolling avg@ 0% O2Install a CO CEMSUnited RefiningEUID 101AFCCUNot included in national petroleumrefinery initiativeGiant YorktownEUID = 6FCCUESP, 1 lb/1,000 lb coke burned SO2Adsorbing Catalyst; 25 ppmvd(0% oxygen) 365-day rolling average;80% reduction in uncontrolled SO2Nothing specified Nothing SpecifiedAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 2 – Catalytic and Ther mal Cracking Units Page 2-13

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### 2.4 AVAILABLE CONTROL TECHNOLOGIES
Emissions from catalytic crackers are highly variab le 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 incl ude both process changes and add-on control equipment to target specific pollutants. The total emission contri bution from a FCCU can comprise about 20 – 30% of SO 2 

### , 15 – 30% of NOx, and 30 – 40% of PM emissions on a total refinery wide basis. Both process changes a nd add-on control equipment are discussed below for
SO 2 

### , NOx, and PM.

2.4.1 SO 2 

### Controls

The quantity of SO 2 

### emissions discharged from the FCCU depends upon the sulfur content of feed to the FCCU, as well as the applied cont rol technology. In the F CCU 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 cata lyst surface, and is burned off during catalyst regeneration as SO 2 

### . Control options for reducing SO 2 

### emissions include pr e-treating the FCCU feed, applying specific additives to the catalys t 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 SO 2 

### and PM. Recent enforcement settlements will require several refineries in the MARAMA region to install wet gas scrubbers over the next severa l years. Several designs of wet scrubbers are available, such as packed towers, plate (or tr ay) towers, spray chambers, and venturi scrubbers, and emissions control leve ls of 95 – 99.9% have been achieved for SO 2 

### removal, and 85 – 95% for PM removal. With the inclusion of an additional treatment tower with the wet scrubber system, NOx emissions can al so be controlled up to 70%, but may be costprohibitive in some cases. Examples of wet scrubbing systems are described below.

BELCO Technologies EDV® We t Scrubbing (Eagleson, 1999)

The EDV® (electro-dynamic vent uri) Wet Scrubbing system combines the techniques used in
venturi scrubbers with electrost atic dust separation. The system houses a spray tower along with a set of filtering modules and set of droplet sepa rators, 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 coar se PM on impact with the water droplets, as
well as removal of SO 2 

### through absorption with the use of a scrubbing reagent, such as caustic soda, lime, or a new regenerative LASORB TM 

### reagent (produced by BELCO). After leaving theAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 2 – Catalytic and Ther mal Cracking Units Page 2-14

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### spray tower, the flue gas is directed to the filtering module for remova l of fine particulate through forced condensation and filtration with wa ter sprays. Lastly, th e flue gas passes through a set of cyclonic droplet separators, which removes any free wa ter 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 Emi ssions – EDV® Wet Scrubbing,” 11 th Refining
Seminar , Dallas, TX.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 2 – Catalytic and Ther mal Cracking Units Page 2-15

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### ExxonMobil Wet Gas Scrubbers (Sapre, 2003)

The ExxonMobil Research and Engineering Compa ny (EMRE) has developed two types of wet gas scrubbers, namely, the high-energy venturi (H EV) scrubber and the jet ejector venturi (JEV) scrubber. These two types of scrubbers are simila r to traditional venturi scrubbers, in that water and a scrubbing liquid are introduced in th e scrubber to collect PM and absorb SO 2 

### from the flue gas stream before discharge into the atmosphere. The HEV scrubbe r 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 en ters at the converging section of the venturi, and the liquid is atomized by the high velocity gas. In contrast, th e 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 th e venturi, and impacts th e PM and absorbs the SO 2 

### out of the gas phase. Figure 1-3 depicts the differences between thes e two scrubber systems.

HEV Scrubber JEV Scrubber

Figure 2-3. Diagrams of HEV & JEV Scrubbers

SOURCE: Sapre, A.V., D.S. McCaf frey Jr., R.B. Redich, J.N. Iye ngar, and H.P. Singh, 2003, “L eading Edge Technology to Abate Air Emissions,” Fairfax, Virginia. DIRTY FLUE GAS IN @ P 1

SCRUBBING LIQUID IN PARTICULATE

LIQUID DROPLETS SO SO SO SO SO

SO SO

DIVERGING SECTION CONVERGING SECTION

SCRUBBED FLUE GAS & LIQUID DROPLETS @ P 2 SULFUR DIOXIDE

NOTE P 1 P 2 LIQUID

SCRUBBED FLUE GAS & LIQUID DROPLETS @ P 2 PARTICULATE SCRUBBING LIQUID IN

DIVERGING SECTION

CONVERGING SECTION SULFUR

NOTE: P 2 >P 1 DIRTY FLUE

BODY LIQUID SPRAY NOZZLEAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 2 – Catalytic and Ther mal Cracking Units Page 2-16

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### Wellmann-Lord Flue Gas Desulf urization Process (DTI, 2003)

The Wellmann-Lord Flue Gas Desulf urization (FGD) process removes SO 2 

### from the flue gas with a control efficiency of about 98%. The fl ue 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 at mosphere. A benefit of this process is that regeneration of the sodium sulfite solution produces concentrated SO 2 

### streams which can be converted and sold as liquid SO 2 

### , 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 SO 2 

### in flue gas. After scrubbing, the water can be treated with air, and discharged back into the sea. This process is f easible 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 catalyst s 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 pr ocess can remove between 20% and 60% of the SO 2 

### in the flue gas, depending on the m ode of combustion and flue gas SO 2 

### concentration.

2.4.1.3 

### Feed Hydrotreatment

FCC feed hydrotreatment can sign ificantly reduce inlet sulfur c ontent to less than 0.1% to 0.5% by weight, depending on the initial feedstock concentration, which can in turn reduce SO 2 

### emissions from the FCCU catalys t regenerator by up to 90%. Re ductions in nitrogen compounds (up to 75 – 85%) and trace metal impurities are also achieved with the use of feed hydrotreatment. The hydrotreatment process ta kes place over a metal catalyst in a hydrogen atmosphere. This process has advantages includi ng 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 Ther mal Cracking Units Page 2-17

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### 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 reductio ns from the FCCU process can be achieved by modifying the combustion zone to reduce the am ount 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 availa ble control systems are described below.

BOC Gases’ LoTOx Process (EPA, 2005)

BOC Gases’ LoTOx process uses industrial-gr ade 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 caus tic 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 Bo ard, and according to the EPA RBLC Database, this process is to be installed on FCCUs located at pe troleum 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 Ther mal Cracking Units Page 2-18

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### 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 conven tional platinum-base CO promoter us ed 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 Da vison developed the DENOX promoter. In commercial tests of the DENOX pr omoter, 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 t echnology that reacts ammoni a 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 2000 o 

### 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 proc eed slowly and permit the escape of unreacted ammonia if the temperature is too low. Additiv es, such as hydrogen, and carrier gases can be added to enhance the SNCR, allowing the reaction to take place at temperatures as low as
1290 o 

### F. These systems have been successfully applie d to boilers and process heaters, as well as FCCU CO boilers. Retrofit appl ications 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 tec hnology that injects ammoni a 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 operatin g temperature of SCR systems is between 480 o 

### F and 800 o 

### F, depending on the catalyst, for NOx co nversion. 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. Th e effectiveness of the additive is dependent upon contacting efficiency and other factors. In r ecent lab and field tests, NOx reduction ranged from 40 – 60%. EMRE engineers indicate that with m odifications 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 so metime in 2004; however no further information onAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 2 – Catalytic and Ther mal 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 wa stewater treatment system.

2.4.3 PM Controls

The main source of PM 10 

### and PM 2.5 

### emissions at petroleum refi neries is FCCU catalytic regenerators because catalyst fines are re leased in the regenerator’s exhaust. PM 10 

### is easily controlled using common control devices such as wet scrubbers, electrosta tic 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 PM 10 

### and PM 2.5 

### size fractions. Specific performance data for particle size rang es 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 SO 2 

### 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 tr aditional 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-vo ltage electrode and a gr ounded electrode, where particulates in the flue gas becomes charge d, and are attracted and collected on the grounded electrode. Particles are removed from the gr ounded electrode by vibr ation (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 probl ems. Sulfuric acid mist is generated when
SO 3 

### 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 th e scrubber, and the rest is released to the atmosphere. The SBS injection technology requir es injecting a solution of sodium bisulfite (SBS) into the flue gas within a temperature range of 250 – 800 o 

### F upstream of the wet scrubber.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 2 – Catalytic and Ther mal Cracking Units Page 2-20

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### The SBS solution reacts quickly with SO 3 

### in a gas-solid reaction producing dry sodium sulfate and sodium bisulfate particles which can be re moved by a downstream ESP or wet scrubber. A process diagram of this technol ogy 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 L ogical 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 Ther mal Cracking Units Page 2-21

MACTEC Federal Programs, Inc. 2.4.3.4 

### Third Stage Separators
Third Stage Separators (TSS) incorporate the basi c principle of traditiona l PM cyclones by using multiple swirl tubes that are designed to sepa rate catalyst fines and other PM from FCCU regenerator flue gas. Third stag e 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 treate d with a secondary control device, such as a scrubber or ESP. Testing of the TSS equipment has rev ealed that almost all PM above 2 μ m has been removed, resulting in only fine par ticulates escaping the TSS.

Figure 2-6. Typical TSS and FSS Arrangement

SOURCE: Weaver, Edwin H., and G.W. Billemeyer, 2003, “A L ogical 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 Ther mal Cracking Units Page 2-22

MACTEC Federal Programs, Inc. 

### 2.4.4 CO Controls

CO emissions at petroleum refineries are main ly associated with partial combustion catalyst regenerators, FCCUs, and coking uni ts. Full combustion catalyst re generators are also a source of CO emissions; however due to complete regeneration of th e catalyst, CO emissions are significantly less, and usually don’t warrant CO emission cont rols. The most common control device is a CO boiler (or waste he at boiler) located afte r the FCCU regenerato r. CO emissions can also be reduced by introducing CO combustion promoters in to the ca talyst regenerator to
oxidize CO to CO 2 

### . 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 pres ent in exhaust gases at high temperatures (approximately 1400 o 

### F) in the presence of external combus tion air, with the added advantage of generating steam for use at the petroleum refiner y. CO boilers burn refinery fuel gas and/or natural gas to generate the necessary heat to oxidize CO to CO 2 

### . CO boilers are capable of oxidizing at least 95% or more of CO emi ssions present in the exhaust stream to CO 2 

### , while also oxidizing at least 90% of VOC emissions.

2.4.4.2 

### CO Combustion Promoters

CO combustion promoters are used in the cataly st regenerator primarily to oxidize CO to CO 2 

### , while in some cases the promoter will also re duce NOx emissions and limit afterburn in the regenerator. Afterburn occurs when CO in the regenerator is not completely oxidized to CO 2 

### in the oxygen rich zone. When this happens, the oxidation of CO will continue into the oxygen deficient area of the regenerato r, 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 OxyClean TM 

### 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
USP TM 

### combustion promoters also reduce CO emi ssions, while controlling afterburn, however do not affect NOx emissions. These promoters c ontain platinum attached to a support made up of aluminum (USP TM 

### ) or silica (ProCat ® 

### ) with strong chemical anchor s to avoid afterburn while promoting CO combustion. The Albemarle Cataly sts Company has also developed two types of CO promoters that reduce CO emissions while pr eventing afterburn. The first promoter, KOC, is a platinum additive on an alumina support, similar to Engelhard’s USP TM 

### . Albemarle has also developed a CO combustion promoter called InSi tuPro, where platinum is impregnated onto the catalyst in varying concentrations to m eet the needs of specific regenerators.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 2 – Catalytic and Ther mal Cracking Units Page 2-23

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### 2.4.5 VOC Controls

VOC emissions at petroleum refineries are main ly 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 disc ussed in section 2.4.4.

2.5 COSTS AND AVAILABILITY

Feasible control technologies for FCCUs and FC CU catalyst regenerators are summarized in
Table 2-6. The table includes

• Pollutant controlled

• Name of technology

• Origin for the level of contro l (rule, consent decree, permit)

• Range of potential emission reductio ns from applying those controls

• Performance level in terms of outle t 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 publis hed literature as referenced. In general, the percent reductions and cost eff ectiveness data represen t data for uncontrolled
sources. Incremental reductions will be lower an d costs will be higher fo r sources already have some level of control and will be required to m eet 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 consider ations must be addressed in State and local rulemaking and permitting processes.Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Section 2 – Catalytic and Thermal Cracking Units Page 2-24MACTEC Federal Programs, Inc.Table 2-6: Control Technology Options for FCCUs and FCUsPollutant TechnologyOrigin ofRequirementPercentReduction Performance LevelCostEffectiveness($/ton)CommerciallyAvailable?ReferenceSO2 Wet Scrubber Consent Decree 95 to 99.925 ppmvd @ 0% O2based on 365-dayrolling average or 50 ppmvd @ 0% O2based on 7-day rolling average500 to 3,000 YesWeaver,1999DeSOxAdditivesNSPS 35 to 509.8 kg per 1000 kg of coke burned(normally translates to a FCC flue gasSOx concentration of approximately300 ppmvd)499 to 880 YesDavey,2000NOx SCR Consent Decree 85 to 9020 ppmvd, measured as a 365-dayrolling average, and 40 ppmvd,measured as a 7-day rolling average,@ 0% O22,364 to 2,458 YesECIPPC,2003LoTOx Consent Decree 80 to 9520 ppmvd, measured as a 365-dayrolling average, and 40 ppmvd,measured as a 7-day rolling average,@ 0% O21,700 to 1,950To be installedunder consentdecreeUSEPA,2005SNCR Consent Decree 60 to 8020 ppmvd, measured as a 365-dayrolling average, and 40 ppmvd,measured as a 7-day rolling average,@ 0% O21,520 to 1,985 YesECIPPC,2003ScrubberBased NOxTechnology(SNERT)Consent Decree 40 to 6020 ppmvd, measured as a 365-dayrolling average, and 40 ppmvd,measured as a 7-day rolling average,@ 0% O2Not availableTo be installedunder consentdecreePM Wet Scrubber Consent Decree 85 to 950.5 pounds PM per 1000 pounds cokeburned on a 3-hour average basisNot available YesElectrostaticPrecipitatorConsent Decree orNSPS>95%1.0 pounds PM per 1000 pounds cokeburned on a 3-hour average basis3,500 to 6,600 YesECIPPC,2003CO CO Boiler State Permits 95200 ppmvd @ 0% O2based on 1-hrblock average and 100 ppmvd @ 0%O2based on 365-day rolling averageNot available YesFriedman(2006b)Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 2 – Catalytic and Ther mal 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/TD S/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. Weav er, 1999, “Controlling FCCU Emissi ons – EDV® Wet Scrubbing,”
11 th 

### Refining Seminar , Dallas, Texas.

Engelhard Corporation, 2002, “ProCat ® 

### and USP TM 

### : FCC Additives for the Reduction of Regenerator Afterburn and CO Emissions,” Engelhard Corporat ion, 2003, “OxyClean TM 

### CO Promoter Reduces NOx Emissions by 45%,” http://www.engelhard.com/docu ments/EC-776 2Rev5-02.pdf

. Engelhard Corporatio n, 2003, “OxyClean TM 

### CO Promoter Reduces NOx Emissions by 45%,” http://www.engelhard.com/document s/OxyClean%20case%20study.pdf

. Engelhard Corporatio n, 2003, “OxyClean TM 

### : FCC Additive for the Re duction of Regenerator Afterburn, CO and NOx Emissions,” http://www.engelhard.com/ documents/OxyClean%20 datasheet.pdf

. European Commission, Integrated Pollution Preventi on & Control, 2003, “Ref erence Document on Best Available Techniques for Mi neral Oil and Gas Refineries.”

Friedman, M., 2006a, Email to E.J. Sabo (MACTEC Federal Pr ograms, Inc.), January 23 2006, New Jersey Department of Environmen tal Protection, Trenton, New Jersey.

Friedman, M., 2006b, Email to W. Gillespie (MARAMA), Se ptember 6, 2006, New Jersey Department of Environmental Pr otection, Trenton, New Jersey.

Giles, K.A., “Fundamentals of Petroleum Refining,” http://www.pdhengineer.com/Course%20Files/ Completed%20Course%20PDF%20Files/Fund amentalsPetroleumRefiningCourse.pdf

. Her Majesty’s Inspectorate of Pollution, 1995, “Chi ef Inspector’s Guidance Note Series 2 (S2):
Petroleum Processes: Oil Refi ning and Associated Processes,” Technical Guidance Branch, London, England.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 2 – Catalytic and Ther mal Cracking Units Page 2-26

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### MACTEC Engineering and Consulting, Inc., 2005, “Petroleum Refinery Best Available Retrofit Technology (BART) En gineering Analysis”, http://www.ladco.org/Reg ional_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/En gelhardKB/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 Emi ssions,” 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 Agenc y, 1995, “Petroleum Refining,” Pages 5.1-1 – 5.1- 16 in AP-42, Fifth Edition: Compilation of Ai r 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 Agen cy, 1998, “Petroleum Re fineries 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. Bille meyer, 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 Conf uorto, N., 1999, “LABSORB A Regenerative Wet Scrubbing Process for Controlling SO2 Emi ssions” Presented at Sulphur 99, October 17- 20, 1999, Calgary, Alberta, Canada.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-1

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## 3.0 BOILERS AND PROCESS HEATERS

Boilers and process heaters are la rge sources of CO, NOx, PM, and SO 2 

### emissions at petroleum
refineries. Numerous control strategies (including fuel swit ching, combustion modification, and add-on control equipment) have been develope d over the years for reducing emissions from refinery boilers and heaters. Furt her reducing emissions of NOx and SO 2 

### from boilers and process heaters is the primary concern, as thes e pollutants are precursors for ozone and fine particulate formation. This Section presents an assessment of ava ilable control technology options for states to consider as they undertak e efforts to develop rules and SIPs for ozone,
PM 2.5 

### , and regional haze.

3.1 PROCESS DESCRIPTION
Most refineries have a utilities pl ant that supplies the steam necessa ry for the refinery. Steam is primarily used for heating and separating hydroc arbon streams. When used for heating, the steam usually heats the petroleum i ndirectly in heat exchangers and returns to the boiler. In direct contact operations, the steam can serve as a stripp ing medium or a proce ss 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 material s to reaction or dist illation 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, re sidual fuel oils, or combinati ons, depending on economics, operating conditions, and emission requirements. Process h eaters may also use CO-rich regenerator flue gas as fuel.

Boilers and process heaters are si milar in that they are combusti on devices which burn fuels such as natural gas, fuel oil, and refinery fuel gas (one refinery in northw estern Pennsylvania burns coal in one of its boilers). The main differenc e 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 discusse d in the sections that follow.

3.2 EMISSION INVENTORY
Table 3-1 summarizes the emissions from petr oleum 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 baseli ne for future SIP development.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-2

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### Table 3-1: Emission In ventory for Boilers/Heaters Annual Emission (tons/year) State Refinery Year SO 2 NOx VOC CO PM 10 PM 2.5 NH 3 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 552 a 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 521 b 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 provi ded revised 2009 emissions based upon CD reductions; further reductions fro m the CD are schedule during 2010 and 2011.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-3

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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 st ate and represent the most currently quality assured data that is available.

The 2009 emissions were obtained from the MANE VU and VISTAS projecti on inventories that were developed to support modeling for SIP de velopment. 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 regul ations or enforcement settlements. The growth factors used for projecting emissions from 2002 to 2009 came from the U.S. Environmental Protection Agency’s Economic Gr owth Analysis System (EGAS 5.0) and the U.S. Department of Energy’s Annual Energy Outl ook (2005) projections. The controls factors for 2009 were derived either from data supplied th at the State/local agenci es or from MACTEC’s analysis of the requirements contained in the global enforcement settlements.

Table 3-1 shows that SO2 emissions for a few refi neries are projected to be reduced by 2009 as a result of the requirements of the enforcement sett lements (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 expect ed at the Philadelphia refinery beginning in
2011.

3.3 EXISTING REQUIREMENTS

This section discusses th e 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 Maximu m Achievable Control Technology (MACT) standards; (2) State regulations for both the MARA MA states as well as other State agencies; (3) source-specific permit require ments; and (4) new requirements from recent enforcement
settlements.

3.3.1 Federal Requirements
The U.S. EPA has promulgated standards for em issions of PM, NOx, SO2, and CO, as well as toxic compounds from petroleum re finery 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 bur ned, and are summariz ed in Table 3-2.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-4

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### Table 3-2: Summary of NSPS Regula tions for Boilers & Process Heaters

Heat Input (MMBtu/hr) NSPS Subpart Construction Date Fuel Type PM Emission Limit (lb/MMBtu) SO 2 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 Liquid 0.10 0.30 – 0.40 Db, J 6/19/1984 Solid 0.051 – 0.20 0.10 gr/dscf H 2 S (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 - - - Liquid - 0.50 - ICI 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 H 2 S (162 ppm) -



### Subpart D applies to fossil-fuel-f ired 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 genera ting units greater than 100 MMBtu/hour. According to section 60.40(c) of this subpart, only performance standard s for PM and NOx from Subpart Db apply to boilers at petroleum refineries (SO2 emissions are subject to 40 CFR 60 S ubpart J). Subpart Dc applies to small ICI steam generating units with heat input capaci ties between 10 and 100 MMBtu/hr. The last set of performa nce standards that apply is the SO 2 

### standards found in Subpart J, which apply to fuel gas combustion devi ces (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 i nput capacities greater than 250 MMBtu/hr, PM emissions are limited to 0.10 lb/MMBtu burning fo ssil fuel, while opacity is limited to 20%, except for one 6-minute period per hour that is limited to 27% opacity. SO 2 

### emissions are limited to 0.80 lb/MMBtu when firing liquid foss il 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,Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-5

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### an equation is used to determ ine the emission standards for SO 2 

### 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 be tween 100 MMBtu/hour at petrol eum refineries, performance standards from Subpart Db apply for emissions of PM and NOx, while performance standards from Subpart J apply for emissions of SO 2 

### . 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/MMB tu, or 0.10 lb/MMBtu if the facility combusts coal and other fuels with an annual capacity factor for th e other fuels greater than 10%, or 0.20 lb/MMBtu if the facility combusts coal or coal and other fuels with an a nnual capacity factor of 30% or less and the unit began construc tion 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, sp reader stoker) and type of coal combusted (e.g. lignite, pulverized). For units firing oil, PM emi ssions are limited to 0.10 lb/MMBtu, while NOx
emissions are limited to 0.30 lb/MMBtu with lo w 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 lo w heat release rates and 0.20 lb/MMBtu with high heat release rates. The SO 2 

### performance standards from Subpart J require the hydrogen sulfide (H 2 

### S) concentration of fuel gas is limited to 0.10 gr/dscf (162 ppm).

In September 1998, the NOX emission limit was cha nged to 0.20 lb/MMBtu heat input from the combustion of natural gas, oil, coal, or a mixtur e 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, modificat ion, or reconstruction comme nced after July 9, 1997.

In February 2005, EPA revised the emission limit s for SO2 and PM. For units at petroleum refineries, the Subpart J requireme nts 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, mo dification, or reconstr uction 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 w ith an annual capacity factor of 10% or less fuel or 0.10 lb/MMBtuAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-6

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### when firing coal with other fuels with an annual capacity factor for the ot her fuels greater than 10%. Opacity is limited to 20%, except for one 6-minute period per hour th at is limited to 27% opacity. SO 2 

### emissions from coal burning units shoul d 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 Ha zardous Air Pollutants (NESHAP) Subpart DDDDD applies to industrial, commercial, and in stitutional 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 applie s to new (constructed after January 13, 2003), reconstructed (modified after January 13, 2003), and existing boile rs and process heaters. Emission limits vary depending on size of the unit (l arge, limited use, and small) and type of fuel fired (solid, liquid, or gas).

Compliance with Title 40 CFR Part 63, Subpa rt 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), me rcury (Hg), and carbon monoxide (CO). For new or reconstructed large, limited use, or small un its firing solid fuel, emissions are limited to the following: PM of 0.025 lb/MMBtu (or total sele cted 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% O 2 

### 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%
O 2 

### 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 emissi ons are limited to 0.0009 lb/MMBtu. For new or reconstructed units firing gaseous fuel, onl y a CO emission limit of 400 ppmvd at 3% O 2 

### applies. For existing large units firing solid fuels, PM is limited to 0.07 lb/MMB tu (or total selected metals of 0.001 lb/MMBtu), with HCl limite d to 0.09 lb/MMBtu, and Hg limited to 0.000009 lb/MMBtu. For existing limited use units firing so lid 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 demonstrat e 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, SO 2 

### , and NOx. New Jersey is the only st ate with regulations for contro lling CO and VOCs from boilers and process heaters. New Jersey lim its CO emissions to 100 ppmvd @ 7% O 2 

### , while VOCs are limited to 50 ppmvd @ 7% O 2 

### for units with heat inputs of 50 MMBtu/hr or more (NJDEPAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-7

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### Regulation 7:27-16.8). As part of the NOx SIP Call, States a dopted a NOx emissions trading program and assigned 5-month ozone season NOx a llowances 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, SO 2 

### , and NOx for refinery boilers and heaters. The regulations for the California air district s 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 re fineries 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 refi neries. Capacity increases and modifications should have triggered NSR permitting and pollution control requirements. There have being several
instances identified where refineries have faile d to obtain pre-construction and operating permits for physical construction that in creased 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 refine ries in the MARAMA region focused mainly on control strategies to limit emissions of SO 2 

### 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 Tabl e 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 lb s 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-8

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### Table 3-3: Summary of M ARAMA State Regulations

Agency PM SO 2 NO x 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 SO 2 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 SO 2 emissions (lb/hr)Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-9

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### Table 3-4: Summary of Other State Regulations

Agency PM SO 2 NO x 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% O 2 ; (2) 90% NOx reduction from calculated June-Aug. 1997 daily NOx emissions 117.205f ≤ 400 ppmvd @ 3% O 2 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(P 0.67 ) ≤ 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 SO 2 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% O 2 (24-hr avg) 9-10-305: ≤ 400 ppmvd @ 3% O 2 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% CO 2 Rule 4306: Refinery Units (1) Gas Fired: 5 – 65 MMBtu/hr: 30 ppmvd @ 3% O 2 or 0.031 lb/MMBtu 65 – 110 MMBtu/hr: 25 ppmvd @ 3% O 2 or 0.031 lb/MMBtu > 110 MMBtu/hr: 5 ppmvd @ 3% O 2 or 0.0062 lb/MMBtu (2) Liquid Fuel Fired: 40 ppmvd @ 3% O 2 or 0.052 lb/MMBtu Rule 4352: Solid Fuel Fired < 0.20 lb/MMBtu (24-hr avg) Rule 4306: Refinery Units - 400 ppmvd @ 3% O 2

Rule 4352: Solid Fuel Fired Units: 400 ppmvd @ 3% O 2 or 310 ppmvd @ 12% O 2 or 310 ppmvd @ 12% CO 2Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-10

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### Table 3-5: Summary of R ecent 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 andthe 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 NO

x emissions from Refinery heaters and boilers greater than 40 mmBTU/hr through the installation of NO

x controls by June15, 2010 ConocoPhillips Trainer Elimination fuel oil burning SCR or SNCR; Current Gene ration 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 NO

x emissions from Refinery heaters and boilers greater than 40 mmBTU/hr through the installation of NO

x 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 burnersAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-11

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### 3.4 AVAILABLE CONTROL TECHNOLOGIES
Emissions from boilers and process heater s 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 incl ude both combustion modifications and add-on control equipment to target specific pollutants. Both of these control options are discussed
below for SO 2 

### , NOx, and PM. Good combustion practice is the usual control method for CO and VOC emissions from boilers and process heater s, and therefore cont rol devices for these
emissions are not discussed in detail.

3.4.1 SO2 Controls
The quantity of SO 2 

### emissions discharged from boilers and heaters located at petroleum refineries depends upon the sulfur content of the fuels combusted. The bulk of SO 2 

### emissions from boilers and process heaters have been si gnificantly reduced by limiting combustion units to burning low sulfur fuels, such as liquefied petroleum gas, natural ga s, 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 a nnual 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, SO 2 

### emissions can be reduced using wet, spray dry, and dry scrubbers. These types of
scrubbers are discussed in deta il 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. SO 2 

### is absorbed into slurry and falls to the bottom of the spray tower, where it is coll ected, 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 droplet s. Wet scrubbers are capable of reducing SO 2 

### emissions from coal and oil fired boilers betw een 90 and 98% depending on the sorbent used. A
common side effect in wet scrubbers is the form ation of gypsum (calcium sulfate) scale on the
absorber due to the oxidation of the slurry sorbent. A new pr ocess 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. Li me is typically the sorbent of choice in the slurry, and isAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-12

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### injected onto the flue gas using rotary atomizer s 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 SO 2 

### is absorbed into the slurry. The process produces a dry waste product of slurry reacted with SO 2 

### that is collected by conventional PM collection devices. The waste can be disposed of, sold as a by-produc t, or recycled back to the slu rry. The lime spray dry scrubber is more sensitive to operating conditions and re quires that the flue gas be within 20 to 50 o 

### F of the adiabatic saturation temperature in order to maximize SO 2 

### removal, as well as prevent deposits
of wet solids on the absorber and downstr eam equipment caused by excess moisture. Application of spray dryer scr ubbers to boilers can realize SO 2 

### removal efficiencies of 80 – 90%.

3.4.1.3 

### Dry Scrubbers
In dry scrubbers, powdered sorben t, typically consisting of calci um 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 SO 2 

### emissions. When injecting the dry sorbent into the boiler, temperatures of 1740 to 1830 o 

### F are needed to decompose the sorbent into porous solids with high surface area, while when injected into down stream ductwork, temperatures of 300 to 350 o 

### F are necessary. Typical configura tions consist of several injection ports in the boiler or duct walls. In some cases, water is inject ed further downstream to help
increase SO 2 

### removal. Dry scrubbers are usually followed by cyclones or ESPs to remove the dry waste product. These systems can achieve em ission 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 nitrog en 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 modi fying the combustion zo ne 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 fu els which don’t contai n nitrogen, or through staging combustion air to limit the conversion of fuel nitrogen to NOx. If combustion modifications or fuel switching are not op tions 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 an d process heaters and have achieved NOx reductions of 30% to 90%. Several low-NOx burner configurations are available to complement specifi c boilers and heaters which burn various fuels by using stagedAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-13

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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 fu el, creating a fuel rich reduci ng atmosphere which generates N 2 

### instead of fuel NOx due to the oxygen deficien t conditions. Introduction of the rest of the
combustion air down stream allows the combusti on 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 com bustion zone with a fraction of the fuel, and the remaining fuel is injected furt her 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 recen t low-NOx burner designs have in corporated changes to flame shape to accommodate various burner applicatio n, as well as further reduce NOx emissions. Several low-NOx burner configurations ar e discussed in more detail below.

Callidus Ultra Blue Burner (CB&I, 2000)

Callidus Technologies, Inc. has de veloped a new burner design app licable to gas-fired process heaters that will reduce NOx emissions at petrol eum 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, result ing in a 90% NOx reduction efficiency. This
burner was scheduled to be installe d 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 deve loped 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 st aging using a fully adjustable windbox assembly with individual manual dampers to allow for alterations according to site conditions. The windbox design wa s developed using extensive flow modeling to achieve optimum air distribution throughout the burner, without compromising burner efficiency or increasing NOx formation. Hamworthy claims th at the Enviromix 2000 is highly versatile with
models available in natural and forced draft burne r designs and capable of firing a wide range of gases and oils.

Hamworthy has also developed a series of advanc e 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 existi ng boiler designs and can fire liquid and gas fuels, including crude and heavy residual oils. NOx reductions of 60% areAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-14

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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 in corporates 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 incor porates an adjustable air-staging slide and rotatable gas lances to ensure burner performance meets specif ic site requirements. NOx
reductions from LNOG burners are similar to re ductions achieved by the DFL Range burners. The final burner, the M Range, is another variable geometry bur ner 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 controll ed by curved air vanes, and fuel atomization is completed by pr essure jets, air, or steam.

A final set of burners, the Envirojet Series, ha s been developed by Hamworthy and fall under the category of new generation Ultra-low NOx burne rs, and are designed to provide the lowest possible emission levels. Enviroje t burners were developed for i ndustrial boilers firing oil and gas and have achieved NOx emissions of 45 – 160 mg/Nm 3 

### at 3% O 2 

### . Traditionally low NOx burners use flue gas recircula tion (FGR) to help reduce NOx em issions, however, the Envirojet does not use FGR, but instead in corporates a windbox that provide s air distributi on that enables the burner’s low excess air performance. Severa l burner configuration opt ions, such as flame direction, ignition type, and burner performan ce monitoring, are available to customize the Envirojet burner to specific boilers.

Next Generation Ultra-low NO x 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 H ouston-Galveston area to reduce NOx emissions by 90% at refineries and chemical pl ants, and to meet stricter NOx regulations in California. The burners were developed mainly for process heat ers utilizing natural dr aft burners which burn various fuel compositions, often with high perc entages 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 re circulation and lean “lifted” flame technology. Testing indicated that this bur ner achieves NOx emissions as low as 10 – 20 ppm depending on fuels burned and operating conditions. A s econd 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 prem ix 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 significantlyAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-15

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### reduces both thermal and fuel NO x. Testing of this burner resulte d in NOx concentrations of 9 – 16 ppm, achieving emission reductions of ar ound 90%. The most recent burner design developed is for another round fl ame burner, however this burner’s design is similar to the FPMF model using a lean premix primary flame with staged combustion. Duri ng 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. Depa rtment of Energy (DOE) and several burner manufacturers (Coen, CMC Engineering, John Zi nk, Maxon Corp, etc.), work was initiated on the development of a low excess air, ultra-low NO x, natural gas fired indus trial 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 efficienc y. One outcome of the project was the development of the Ultraclean Low-Swirl Combustion (UCLSC) te chnology 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 Be rkeley, the USLSB provides the most stable platform for a stable flame because the flame can exist in it s 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, therefor e 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 consump tion and NOx formation. By decreasing the amount of oxygen available in th e combustion zone, a reducing atmosphere is formed, which inhibits the formation of both therma l and fuel NOx. An additional benefit of this process is an increase in thermal efficiency be cause heat losses associat ed with pre-heating the excess air is eliminated, therefore allowing more h eat to transfer to pro cess fluids in process heaters per unit of energy input. The effectiv eness of LEA systems depends on the long-term average maintained excess air le vel 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 impingeme nt, especially when firing fuel oil.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-16

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### Combustion Air Preheat

Combustion air preheat (CAP) in pr ocess heaters increases the ther mal efficiency of the heater upwards of 92%. However, this technique is as sociated with increased levels of thermal NOx formation due to the presence of higher temperatur es. 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 boi lers and process heaters, with NOx control efficiencies as high as 75%. NOx emissions fr om SNCR are controlled by injection of ammonia or urea solutions in the presence of high te mperatures to convert flue gas NOx to N 2 

### 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 eith er aqueous or anhydrous ammonia, which is reacted with air before passing into the fire box through a number of injection nozzles. The firebox temperature must be between 1600 and 2000 o 

### F in order for the NOx conversion reaction to proceed. In more rece nt applications, hydrogen (H 2 

### ) may also be added to the ammonia to decrease the minimum operating temperature to 1400 o 

### F. The process is highly temperature dependent; temperatures below 1400 o 

### F can cause release of unreacte d ammonia or ammonia slip, while temperatures above 2000 o 

### F can cause increased NOx production.

Because SNCRs don’t use catalysts to increase the reaction rates be tween the ammonia and NOx, sufficient time for the react ants 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 c onsistent with flue gas temperature and residence time to achieve maxi mum NOx reduction. If too much ammonia is injected, the excess ammonia can create visi ble ammonia plumes and corrosive ammonium sulfite. Injection of the Thermal DeNOx reag ent 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, a nd has been installed mainly on coal, oil, and gas fired boilers. The NOxOUT pr ocess involves direct injection of an aqueous urea solution using air or steam to distribute the solution thro ughout the firebox. Because urea is nonvolatile, as compared with ammonia, more ener gy is needed when injecting the urea solution to obtain adequate distribution of the reagent to maximize NOx conversion. The urea interactsAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-17

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### with the flue gas and converts NO compounds to N 2 

### , water. The balanced chemical reaction
indicates that 2 moles of NO are converted per 1 mole of urea so lution, however greater quantities of urea can be injected to improve NOx reduction and increase the speed of reaction kinetics, however, incomplete thermal decompos ition 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 1200 o 

### F by adding H 2 

### , CO, and antifouling and storage stabilizi ng agents to the urea. As w ith ammonia injection, reaction temperature and residence time are the primary factors that influen ces 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 heat ers 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 boile rs 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 redu ce PM emissions from these units include wet scrubbers and electrostatic precip itators (ESP). Wet scrubbers are discussed in great detail in section 2.4.1, while benefits of E SPs are discussed in section 1.3.1.

3.5 COSTS AND AVAILABILITY
Feasible control technologies for FCCUs and FC CU catalyst regenerators are summarized in
Table 3-6. The table includes

• Pollutant controlled

• Name of technology

• Origin for the level of contro l (rule, consent decree, permit)

• Range of potential emission reductio ns from applying those controls

• Performance level in terms of outle t 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-18

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### The cost data presented in the Table were obtained from the publis hed literature as referenced. In general, the percent reductions and cost eff ectiveness data represen t data for uncontrolled
sources. Incremental reductions will be lower an d costs will be higher fo r sources already have some level of control and will be required to m eet 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 consider ations must be addressed in State and local rulemaking and permitting processes.Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Section 3 – Boilers and Process Heaters Page 3-19MACTEC Federal Programs, Inc.Table 3-6: Control Technology Options for Boilers and Process HeatersPollutant TechnologyOrigin ofRequirementPercentReductionPerformance LevelCostEffectiveness($/ton)CommerciallyAvailable?ReferenceSO2 Fuel Switching Consent Decree >95Eliminate the combustion of fuel oil(>0.05% sulfur by weight)YesFuel ProcessingConsent Decree orNSPS Subpart JLimit hydrogen sulfide content ofrefinery fuels to 0.10 gr/dscf (162 ppm)YesScrubbers 90 to 99.9 Not specified 7,674 to 45,384 YesMACTEC,2005NOx Not Specified San JoaquinRule 4306n/aGaseous Fuel: 0.0062 to 0.036lb/MMBtu (depending on size)Liquid Fuel: 0.052 lb/MMBtuRule 4306Ultra-low NOxBurnersConsent Decree 75 to 85 0.02 to 0.04 lb/MMBtu 750 to 1,110 YesMACTEC,2005SCR Consent Decree 70 to 90 0.04 lb/MMBtu 2,444 to 7,402 YesMACTEC,2005Low-NOxBurners PlusSNCR50 to 89 1,560 to 7,101 YesMACTEC,2005Low-NOxBurners10 to 40 786 to 4,292 YesMACTEC,2005CO NESHAPSubpart DDDDD400 ppmvd @ 3% O2Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-20

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### 3.6 REFERENCES
California Environmental Protection Agency, 2004, “Air Pollution Research,” Air Resources Board, California.

Chen, A., 2003, “Low-Swirl Combusti on Clears the Air,” Science Beat, http://www.lbl.gov/Science-Articles/Ar chive/EETD-low-swirl-combustion.html

Chicago Bridge & Iron Company (CB&I), 2000, “C allidus 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 Br anch, Morrisville, North Carolina.

European Commission, Integrated Pollution Prev ention & Control, 2003, “Reference Document on Best Available Techniques for Mi neral Oil and Gas Refineries.”

Friedman, M., 2006, Email to E.J. Sabo (MACTEC Federal Programs, Inc.), January 23, New Jersey Department of Environmen tal Protection, Trenton, New Jersey.

Hamworthy Combustion, “Envirojet Series: Ul tra-Low NOx Burners,” Proven Combustion
Solutions.

Hamworthy Combustion, “Enviromix 2000: Low NOx Burners for Process & Petrochemical Heaters,” Proven Combustion Solutions.

Hamworthy Combustion, “Register Burners: Ad vanced Low NOx Burners,” Proven Combustion
Solutions.

MACTEC Engineering and Consulting, Inc., 2005, “Petroleum Refinery Best Available Retrofit Technology (BART) En gineering Analysis”, http://www.ladco.org/Reg ional_Air_Quality.html

Northeast States for Coordinated Air Use Ma nagement, 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 tec hnology 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 3 – Boilers and Process Heaters Page 3-21

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### United States Environmental Protection Agen cy, 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 Ag ency, 1994, “Alternative Control Techniques Document – NOx Emissions from Industrial/Commercial/Institutional (ICI) Boilers,” EPA-453/R-94-022, Office of Air & Radiation, Re search Triangle Park, North Carolina.

United States Environmental Protection Ag ency, 1998, “Alternative Control Techniques
Document – NOx Emissions from Pro cess Heaters (Revis ed),” 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 Pr ocess Heaters,” John Zink Company, Tulsa,
Oklahoma.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 4 – Flares Page 4-1

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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, SO 2 

### , and CO into the atmosphere. There is some uncertainty regarding the magnitude of emi ssions from flaring activities, as many refineries
do not have formal flare monitori ng and emissions recording proce dures in-place. Based on data
collected in California and Texa s, there is a concern about th e potential underestimation of reported emissions released during flaring events . There are opportunitie s to better quantify emissions from flaring events, as well as reduc ing emissions by safely limiting flare use or by installing a flare gas recovery unit. This Secti on presents a preliminary assessment of available control technology options for flarin g activities for states to consid er as they undertake efforts to develop rules and State Implementation Plans (SIPs) for ozone, PM 2.5 

### , and regional haze.

4.1 PROCESS DESCRIPTION
Flares at petroleum refineries ar e intended to be last-resort contro l devices for the destruction of vent gases released under emer gency conditions or during proce ss start-ups, shut-downs, and
turnarounds. Elevated flares are the most common type of flare us ed, as they can handle larger capacities than ground flares. In el evated flares, the waste gas str eam 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 head er 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 ga s pilots and igniter.

Figure 4-1 presents a schematic of a typical flar e and the location of each of these components. In most cases, steam or blowing air is injected in to 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 usuall y consist of low molecular weight hydrocarbons, which burn without smoke, therefor e not requiring steam injection. Flares normally dispose of
low-volume continuous emissions but are designed to handle large qua ntities of waste gases that may be intermittently generated during plant emergencies. Flare gas volumes can vary from a few cubic meters per hour duri ng regular operations up to severa l thousand cubic meters per hour during major upsets.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 4 – Flares Page 4-2

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

SOURCE: United States Environm ental 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 partic les (soot), unburned hydr ocarbons, CO, and other partially burned and altered hydr ocarbons. Also emitted are NO x 

### and, if sulfur-containing material such as hydrogen sulfide or mercaptans is flared, sulfur dioxi de. The quantities of hydrocarbon emissions generated relate to the degree of combustion. The degree of combustion depends largely on the rate and ex tent of fuel-air mixing and on the flame temperatures achieved and maintained. Properly operated flares achieve at least 98 percen t 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 uni ts in the MARAMA region and criteria pollutant emissions for each unit for three years. The 2002 annual emi ssions serve as the baseline for future SIPAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 4 – Flares Page 4-3

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### development. The 2002 emissions were obtai ned from the 2002 inventories developed by
MANEVU and VISTAS. The 2003 emissions were obtained directly fr om each state and represent the most currently quality a ssured data that is available.

The 2009 emissions were obtained from the MANE VU and VISTAS projecti on inventories that were developed to support modeling for SIP de velopment. 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 regul ations or enforcement settlements. The growth factors used for projecting emissions from 2002 to 2009 came from the U.S. Environmental Protection Agency’s Economic Gr owth Analysis System (EGAS 5.0) and the U.S. Department of Energy’s Annual Energy Outl ook (2005) projections. The controls factors for 2009 were derived either from data supplied th at the State/local agenci es or from MACTEC’s analysis of the requirements contained in the global enforcement settlements.

There is considerable uncertainty regarding the em issions from flaring activities, due to several factors. First, since flares are primarily desi gned 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 variab ility may be caused by the data available and methods used to
estimate emissions. Accurate information on th e amount and composition of the waste gas sent to the flare is necessary to accurately estimate em issions. 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 op erated 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 4 – Flares Page 4-4

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### Table 4-1: Emission Inventory for Flares

Refinery/ Annual Emission (tons/year) State Unit Year CO NOx PM 10 PM 2.5 SO 2 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 2.5Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 4 – Flares Page 4-5

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### Table 4-1: (continued)

Refinery/ Annual Emission (tons/year) State Unit Year CO NOx PM 10 PM 2.5 SO 2 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 em ission were calculated assuming no growth in flaring activity. MARAMA states are reviewing the latest guidan ce 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 4 – Flares Page 4-6

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### 4.3 EXISTING REQUIREMENTS
This section discusses the regul atory requirements which apply to flares. Four types of requirements are discussed: (1) Federal requi rements such as the New Source Performance Standards (NSPS) and Maximum Ac hievable Control Technology (M ACT) 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 SO 2 

### emissions, in addition to establishing requirements for performance testing and compli ance 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, Subpart s 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 fl are with no visible emi ssion, monitoring the presence of the pilot flame with a thermocouple or equivalent de vice, and meeting heat content and maximum tip exit velocity specif ications. Subpart J applies to flares at petroleum refineries,
where flares are defined as fuel gas combustion devices, and are li mited to burning fuel gas, for the maintenance of the pilot flam e, containing hydrogen sulfide (H 2 

### S) 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 rel eased to the flare. This subpart also requires that a continuous monitoring and recording devi ce be installed to track emissions of SO 2 

### or H 2 

### S from the flare, in addition to the installation of an oxygen mon itor for correcting the emissions
data for excess air.

The National Emission Standards fo r Hazardous Air Pollutants (NESHAP) for flares are covered in 40 CFR Part 63, Subpart SS, which applies to cl osed 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 assessmen t and monitoring requirements. Compliance assessments include using EPA’s Method 22 to de termine measure opacity, using Equation 1 (of 40 CFR Part 63, Subpart SS) to determine the n eat 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 th at a device (e.g. thermocouple, ultra-violet beam sensor, or infrared sensor) to detect the presence of the flar e flame must be used at all times when the flare
is in use.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 4 – Flares Page 4-7

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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 ar e not as strict as those in California that lay out monitoring, testing, recordk eeping, and reporting requirements for flares at petroleum refineries, in addition to prohi biting flaring unless the situatio n is allowed according to the facility’s flare minimization plan. Per the Californ ia regulations, each facility is required to have a flare minimization plan/monitoring and recordi ng plan, which stipulates conditions for use of the flare, and what information must be reported after flaring events. Re cent amendments to the BAAQMD and SCAQMD regulations ar e discussed further in section 4.4.2.

4.3.3 Requirements from Recent Enforcement Settlements

The EPA and state/local agencies recently undert ook an initiative to inve stigate compliance with applicable Federal and State re quirements for flaring. There have being several instances
identified where refineries used flares for r outine purposes instead of only to vent dangerous gases, as well as other problems with NSPS comp liance. Consent Decrees have been developed to require facilities to : (1) meet new source standards at a ll 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 emissi ons from process upsets; and (3) implement a protocol to diagnose and prevent upsets that result in significant releases of SO 2 

### and other gases (flaring). Table 4-2 provides a list of recent enforcement settlements for flares at petroleum refineries in the MARAMA region.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 4 – Flares Page 4-8

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### Table 4-2: Summary of R ecent 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 SO 2 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, flar es 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 consider ably greater flow rate than the pilot gas. Pressure relief valves, compressor seals, and anal yzer purge lines also vent (either continuously or intermittently) to the flare. Emissions from flaring can include PM, CO, NOx, and SO 2 

### if sulfur containing vent gases are flared. Emissi ons from flaring events are released due to oxidation of vent gases and incomplete combusti on of fuel. Since emissions from flares are unpredictable, the BAAQMD and SCAQMD amended pr evious regulations to include increasedAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 4 – Flares Page 4-9

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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 compar ison to the California regulations to provide additional state control options. Add on control e quipment 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 comp ressor 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 fl are. The vent gases ar e collected in the flare header, compressed, cooled, and returned for re-u se 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 th at the compressor system is at full capacity, but excess emissions are being vented. This incorporat es 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.htmAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 4 – Flares Page 4-10

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### 4.4.2 California Regulations
In addition to implementation of control strate gies at petroleum refi neries, the BAAQMD and SCAQMD have recently updated thei r regulations to increase emissi on 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 record ing of emissions data fo r 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 flari ng events, as well as estimate the quantity of emissions released during those events. Th e 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 wit hout the refinery first creating, following, and annually updating a Flare Minimization Plan (FMP) for each flare. It requires the s ubmission of flaring reports when a flare releases more than 500,000 standard cubic feet of gas per calenda r day (scf/day) and to identify the cause and to avoid fl aring from that cause in the futu re, if possible. Also, the rule requires annual reports to the District evaluating flaring even ts that released less than 500,000 scf/day, where the amount of SO 2 

### 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 re fineries, as this seal keeps liquid from entering the flare stack, provides a barrier between the flar e gas header and flare st ack preventing air from interacting with the vent gases and causing a potentially explosive environment, and provides backpressure on the flare gas header for operati on of the flare gas recovery compressor.

4.4.2.2 

### SCAQMD
The SCAQMD has recently published (on Novemb er 4, 2005) its proposed amendments to Rule 1118, Emissions from Refinery Flares, that fi rst 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 anal yzed by staff that made recommendations for further strengthening emissions data gather ing, monitoring, and reporting procedures. The proposed amendments will be implemented starting January 2006 and be fully implemented by January 2012. The new amendments prohibit fl aring of vent gases except in emergency situations, or during specific operational needs such as startups, shutdowns, and turnarounds. The new rule also establishes operational requirem ents and practices to minimize flaring events,Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 4 – Flares Page 4-11

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### sets specific annual SO 2 

### performance targets, requires that flares operate in a smokeless manner, and requires annual inspections of pressure relief devices direc tly connected to flares. New monitoring requirements call for the installation of analyzers to m easure vent gas higher heating values, total sulfur concentration, and gas flow. The rule also cont ains provisions for refineries to give 24-hour advance noti ce for each large planned flari ng 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. Refine ries 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 (T CEQ) has two air quality rules that pertain
to the control of air emissions through flares. The fi rst 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 requi res 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 coun ties achieve 90% control efficiency or limit VOCs emitted to 20 ppmvd @ 3% O 2 

### 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/Galv eston/Brazoria area. Each
site located in this area is s ubject to a facility limit of 1,200 lbs HRVOC per 1-hr block period from any flare, vent, pressure relief valve, cool ing 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 syst em capable of measuri ng the concentration of HRVOCs in addition to hydrogen, nitrogen, meth ane, 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-operationa l 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 av erage 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 calc ulated net heating value or exit velocity of the vent gas does not meet the limitations set fo rth 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 ma intaining records of a ll testing and monitored parameters.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 4 – Flares Page 4-12

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### 4.5 COSTS AND AVAILABILITY

4.5.1 Flare Gas Recovery Unit
Based on cost estimates by SCAQMD and a plan t-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 invest ment, significant energy savings are realized from recycling vented gases for use as fuel or process feedstock. At the Houston refinery, the predicted fu el savings from the installati on 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 installe d 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 instal lations at other petroleum refine ries is two to four years. Recently another flare gas recovery unit was inst alled 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 e xpected to achieve emission reductions of 1.18 tons/day of SO 2 

### and 1.44 tons/day in total criteria pollu tants (except CO) by December 31, 2012. According to estimates by SCAQMD staff, the co st effectiveness of the proposed amendments range from $5,524 to $8,620 per ton of SO 2 

### reduced and from $4,527 to $7,063 per ton SO 2 

### , NOx, VOC, and PM 10 

### reduced. These overall cost estimate s include installation of flare gas recovery and treatment systems, installation of all required analyzers a nd flow meters, and the cost of man hours to produce annual surveys of al l pressure relief device s 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 c onservative, 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 associat ed costs have already been incurred by the refineries in the Bay Area. The BAAQMD staff de termined the extremes of the expected costs, taking into account that some f acilities 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 4 – Flares Page 4-13

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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 SO 2 reduced and from $4,527 to $7,063 per ton SO 2 , NOx, VOC, and PM 10 reduced.

SOURCE: Teszler, E., October 2005, “Fin al Staff Report for Proposed Rule 1118 – Control of Emissions from Refinery Flares,” South Coast Air Quality Mana gement District, Diamond, California.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 4 – Flares Page 4-14

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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 co st 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 fo r all pollutants, and $818 per ton thereafter.

SOURCE: Ezersky, A., 2005, “Staff Report: Proposed Regulation: Regulation 12, Mi scellaneous Standard s 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 contro l (rule, consent decree, permit)

• Range of potential emission reductio ns from applying those controls

• Performance level in terms of outle t 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 4 – Flares Page 4-15

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### The cost data presented in the Table were obtained from the publis hed literature as referenced. In general, the percent reductions and cost eff ectiveness data represen t data for uncontrolled
sources. Incremental reductions will be lower an d costs will be higher fo r sources already have some level of control and will be required to m eet 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 consider ations must be addressed in State and local rulemaking and permitting processes.Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Section 4 – FlaresPage 4-16MACTEC Federal Programs, Inc.Table 4-5: Control Technology Options for FlaresPollutant TechnologyOrigin ofRequirementPercentReductionPerformance LevelCostEffectiveness($/ton)CommerciallyAvailable?ReferenceAllFlare GasRecovery UnitConsentDecreen/aNSPS limit on hydrogensulfide content ofrefinery fuels to 0.10 gr/dscf (162 ppm)Cost Savings YesAllRequirementscontained inBAAQMD Rule12BAAQMDRule 1265 to 86Development and implementation of flareminimization plan, continuous monitoring ofknock-out drum water seal for leaks,determine and report the causes of eachreportable flaring incident818 to 1,603 YesEzersky,2005AllRequirementscontained inSCAQMD Rule1118SCAQMDRule 111853Prohibits flaring except for emergencies,shutdowns and startups, turnarounds, andspecific essential operational needs;establishes operational practices to minimizeflaring events, sets annual SO2 performancetargets, requires operation in a smokelessmanner; increased inspections and monitoring4,527 to 8,620 YesWallerstein,2005Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 4 – Flares Page 4-17

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### 4.6 REFERENCES
Ezersky, A., 2005, “Staff Report: Proposed Regulati on: Regulation 12, Misc ellaneous Standards of Performance, Rule 12, Flares at Pe troleum Refineries,” Bay Area Air Quality Management District, San Francisco, California.

Fisher, P.W. and D. Brennan, 2002, “Minimize fl aring 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 Flar es’ Contribution to the Gulf Coast Region’s
Air Pollution Problems”.

Lawrence Berkeley National Laboratory, 2003, “Prof ile of the Petroleum Refining Industry in
California: California Industr ies of the Future Program,” US Department of Energy Contract DE-AC03-76SF00098, Berkeley, California.

Lieu, S., 2005, “Final Socioeconomic Report fo r Proposed Rule 1118 – Control of Emissions from Refinery Flares,” South Coast Air Quality Management District, Diamond, CA.

Teszler, E., October 2005, “Fin al Staff Report for Proposed Ru le 1118 – Control of Emissions from Refinery Flares,” South Coast Air Quality Management District, Diamond, CA.

United States Department of Energy, 2005, “Val ero: Houston Refinery Uses Plant-Wide Assessment to Develop an Energy Optimizati on and Management System,” Office of Energy Efficiency and Renewable Ener gy, Industrial Technologies Program, Washington, DC.

United States Environmental Protection Agenc y, 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 Fl ares,” SCAQMD No. 102605MK, October 2005.

Wallerstein, B.R., 2004, “Evaluation Report on Emissions from Flari ng Operations at Refineries
& Direct Staff to Initiate Amendment of Rule 1118,” Board Meeting: September 3, 2004, Agenda No. 33.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 5 – Fugitive Equipment Leaks Page 5-1

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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 c onnection systems, open-ended or in-line valves, and instrumentation systems. Most petroleum re fineries limit these fugitive emissions at their facilities by implementing leak detection and repa ir (LDAR) programs. Each refinery’s LDAR program specifies the frequency of monitoring fo r VOC leaks from these components, as well as specifying testing methods, recordkeeping, and re porting requirements. Recently, there has been renewed interest in developing cost effective solutions to fu rther reduce VOC emissions from equipment leaks as states undertake efforts to develop rules and Stat e Implementation Plans (SIPs) for ozone, PM2.5, and regional haze.

5.1 PROCESS DESCRIPTION
Equipment leaks normally encountered in an oil re finery include pipe flanges, threaded pipe connections, pump seals, compressor seals and va lve packing. There are literally thousands of such potential leak sources in a typical oil refinery. Reasons fo r leaks can include normal wear and tear, poor quality or design of component s, poor maintenance or improper choice of materials. Volatile hydrocarbons can then be le aked from the processing units into the ambient environment from any of the above mentioned s ources. 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 rel eases from refineries in the MARAMA region. VOC emissions for each facility are shown for th ree years. The 2002 annual emissions serve as the baseline for future SIP development. The 2002 emissions were obtained from the 2002 inventories developed by MANE VU and VISTAS. The 2003 emi ssions were obtained directly from each state and represent the most currently quality assured data that is available.

The 2009 emissions were obtained from the MANE VU and VISTAS projecti on inventories that were developed to support modeling for SIP de velopment. 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 regul ations or enforcement settlements. The growth factors used for projecting emissions from 2002 to 2009 came from the U.S. Environmental Protection Agency’s Economic Gr owth Analysis System (EGAS 5.0) and the U.S. Department of Energy’s Annual Energy Outl ook (2005) projections. The controls factors for 2009 were derived either from data supplied th at the State/local agenci es or from MACTEC’s analysis of the requirements contained in the global enforcement settlements.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 5 – Fugitive Equipment Leaks Page 5-2

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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 233.0 a 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 federa l leak definition of 10,000 ppm. Emissions were recalculated using actua l leak data and EPA correlation equa tions LeakDas software, resulting in a downward revision to 233 tons/year.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 5 – Fugitive Equipment Leaks Page 5-3

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### 5.3 EXISTING REQUIREMENTS

This section discusses th e 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 Ac hievable Control Technology (M ACT) 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 ot her connector in VOC se rvice) at petroleum refineries that have undergone construction or modification sin ce January 4, 1983. This subpart refers to 40 CFR Part 60, Subpart VV for all ap plicable monitoring, tes ting, recordkeeping and reporting standards. Subpart VV indicates th at a piece of equipment is leaking when an instrument reading of 10,000 ppm or greater is m easured using EPA Method 21 or when a visual inspection uncovers liquid dripping from the equipm ent. When leaks are detected, a first attempt repair should be made within 5 da ys after the leak is detected, a nd 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 Ha zardous Air Pollutants (NESHAP) for equipment leaks from process equipment components in organic HAP serv ice 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 lis ts dates specific to petroleum refineries for owners/operators to demonstrat e compliance specific emissions limit phases. Three phases were established, with the final phase taking eff ect 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 identificati on tag be affixed to leaking components upon detection, and stipulates that firs t attempt repairs to be made with in 5 days after leak detection, while final repairs should be made within 15 da ys, 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 5 – Fugitive Equipment Leaks Page 5-4

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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 alternativ e work practice for finding leaking equipment using optical gas imaging instead of mon itoring using EPA Refere nce Method 21. Although optical gas imaging can potentially be useful as a method of leak dete ction and repair when operated in conjunction with Fe deral Reference Method 21 (“Me thod 21”), commenters have
raised enforcement and technica l concerns that must be addr essed 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 th e 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 pp m to 500 ppm. The new leak de finitions would apply only to new sources that began constr uction, reconstruction, or modifi cation 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 selec tion of lower values”. EPA’s analysis indicates that lowering the leak dete ction definitions to 500 ppm for valves and 2,000 ppm for pumps for petroleum refineries woul d have a cost effectiveness of $3,100 per ton
removed.

5.3.2 State Regulations

Most states have detailed mon itoring, 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: L eaks from Petroleum Refinery Equipment

• Philadelphia Regulation V, Secti on XIII: Process Equipment Leaks

• Pennsylvania Section 129.58: Petroleu m 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, Texa s) and California district s (Bay Area Air Quality Management District – BAAQMD , South Coast Air Quality Mana gement District – SCAQMD, and San Joaquin Valley Air Pollution Control Dist rict - SJVAPCD) are generally more stringent (more frequent monitoring, lower leak definition s) than the MARAMA st ates and the federal government.

5.3.3 Permit Requirements
The permit requirements for most of the faciliti es follow the NSPS, NESHAP, or the state LDAR requirements.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 5 – Fugitive Equipment Leaks Page 5-5

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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 refi neries. Capacity increases and modifications should have triggered NSR permitting and pollution control requirements. There have being several
instances identified where refineries have faile d to obtain pre-construction and operating permits for physical construction that in creased 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 sett les require leak detec tion and repair program enhancements, including the following:

• 

### Written refinery-wide LDAR program description

• 

### Training for any person (employee or cont ract employee) assigned LDAR program responsibilities

• 

### LDAR audits, including an initial compliance au dit, third-party audits, and internal audits

• 

### Actions necessary to correct nonco mpliance resulting from audits

• 

### More stringent leak defin itions 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 coordinato r 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 identifica tion 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 give n 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 progr am is required by the recent enforcement
settlements enacted at the refineries in th e MARAMA region. Accord ing to the individual Consent Decrees, several conditions are to be ad ded 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 resultedAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 5 – Fugitive Equipment Leaks Page 5-6

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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 trai ning 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 pro cedure 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 detecti on limits are reduced from 10,000 ppm to 500 ppm for valves, and 2,000 ppm for pumps.

• 

### Monitoring Frequency: Pump s 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 calib ration shows a negative drift of more than 10% from the previous calibration, then all va lves with monitoring concentrations greater than 100 ppm and all pumps with conc entrations greater than 500 ppm should be retested.

• 

### Repairs: New repair regulati ons vary by consent decree, in cluding 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 valv es (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 al low 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 en sure that new valves and pumps installed during maintenance and construction projects are implemented into the LDAR program.

• 

### Recordkeeping & Reporting Requirements: Re gular 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 a nd pumps, review of records, tagging, and data management, and observation of LDAR technicians’ calibr ation and monitoring techniques.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 5 – Fugitive Equipment Leaks Page 5-7

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### 5.4.2 Smart LDAR
Both the current and enhanced LDAR programs re quire 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 exte nsive man hours to check every potential leaking source, and requires checking many sources whose fugitive em issions usually range from non-detect to 100 ppm. According to a study conducted by the Amer ican Petroleum Institute (API), only 0.13% of the total sources monitored at petroleum refine ries account for the largest source of fugitive emissions (leaks measured at concentrations gr eater 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 great er than 1,000 ppm were found to re peatedly leak. This evidence suggests that more emphasis should be placed on the detection and repair of sources measured with high leak concentrations rather than us ing the EPA Method 21 to monitor all refinery components with the potential to develop an eq uipment leak. This can be accomplished using the second LDAR approach, called Smart LDAR, whic h 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 absorp tion, and lasers to pictoriall y represent major leaks from equipment as plumes of smoke on a portable scr een. Listed below are some examples of the types of cameras available.

Infrared Imaging Spectrometer (P acific Advanced Technology, 2000)

Pacific Advanced Technologies (PAT), under contra ct to the Department of Defense, developed a field portable infrared imagining spectromete r 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 pr ocessing technology to allo w real-time viewing of fugitive gas leaks. Recently, PAT has applied this technology to environmental monitoring for fugitive gas leaks, smoke stack emissions, and fl ares 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 instru ment is its ability to identify elemental species present in the equipment leak without the us e of an artificial illumination source.

Backscatter Absorption Gas Imag ing (Goers, Kulp, and McRae, 2000)

The Backscatter Absorption Gas Imaging (BAGI) inst rument uses an infrared laser to direct specific wavelengths of light towards suspected ga s leaks. The gas will absorb the light and appear as a dark cloud on the screen of the imag ing equipment. The BAGI instrument allows the simultaneous viewing of many potential emission point s, while also being able to focus in on a single leaking source and estimate the leak fl ux more accurately than from single pointAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 5 – Fugitive Equipment Leaks Page 5-8

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### concentration measurements. The first field te st of this equipment involved using a vehiclemounted BAGI instrument, which was found to be impr actical due to the need to test areas of the refinery that had limited accessibility. Since the fi eld 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 La Sen Inc. also uses infrared spectroscopy to detect and measure fugitive VOC leaks from refi nery equipment. The main advantage of this imager is its ability to detect hydrocarbon leaks at a safe dist ance 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 te lescope and a sensor measures the hydrocarbon concentration in the Lidar imager, whereas the NI CE 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 prog rams 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-monito r 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. In stead of using a hydro carbon gas analyzer and following EPA Method 21 to determine leak co ncentrations 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 fo r 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 31 st 

### , 2007, in order to demonstrate and evaluate gas imaging equipment, at an estimate d cost of $250,000. No cost effectiveness data for this option is available at this time.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 5 – Fugitive Equipment Leaks Page 5-9

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### Revisions to the NSPS were proposed by EPA on November 7, 2006. These amendments would increase the stringency of th e 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 pp m 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 e ffectiveness of $3,100 per ton removed.

Several of the refineries in the MARAMA region already have leak defi nitions 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 emissi ons from refineries where the starting leak definition is 1,000 pp m than where the leak definition is 10,000 ppm. The costeffectiveness is likely to be hi gh 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 refi nery due to the differences in th e 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 contro l (rule, consent decree, permit)

• Range of potential emission reductio ns from applying those controls

• Performance level in terms of outle t concentration or emission rate

• Cost effectiveness of the controls

• Commercial status

• Reference The cost data presented in the Table were obtained from the publis hed literature as referenced. In general, the percent reductions and cost eff ectiveness data represen t data for uncontrolled
sources. Incremental reductions will be lower an d costs will be higher fo r sources already have some level of control and will be required to m eet 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 consider ations must be addressed in State and local rulemaking and permitting processes.Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Section 5 – Fugitive Equipment LeaksPage 5-10MACTEC Federal Programs, Inc.Table 5-2: Control Technology Options for Fugitive Equipment LeaksPollutant TechnologyOrigin ofRequirementPercentReductionPerformance LevelCostEffectiveness($/ton)CommerciallyAvailable?ReferenceVOCEnhancedLDARConsent Decrees 50Program enhancements beyond requirementsof NSPS, NESHAP, and State Rules:Training of LDAR personnel; enhancedQA/QC; low leak definitions; electronicrecording of LDAR monitoring results; thirdparty audits; chronic leaker identification andrepair; other operational improvements1,300 YesCoburn,2002VOCLower LeakDefinitionsProposedRevisions toNSPSNotQuantifiedIncrease the stringency of the leak definitionsfor pumps and valves; for pumps in liquidservice from 10,000 ppm to 2,000 ppm andincrease the stringency of the leak definitionfor valves in gas/vapor service or light liquidservice from 10,000 ppm to 500 ppm.$3,100 YesUSEPANov. 72006VOCGas ImagingTechnologyEPA’s proposedalternative workstandardsUnknown Unknown UnknownCurrently BeingDemonstratedUSEPAApr. 62006Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 5 – Fugitive Equipment Leaks Page 5-11

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### 5.6 REFERENCES
Coburn, J.B., 2002, “Identifying Cost-Effective Refinery Emission-Reduction Strategies,” Research Triangle Institute, Resear ch Triangle Park, North Carolina.
ENS, 2005, “ExxonMobil Agrees to $570 Million Cl ean Air Settlement,” Environmental News Service, October 11.

European Commission, Integrated Pollution Preventi on & Control, 2003, “Ref erence Document on Best Available Techniques for Mi neral Oil and Gas Refineries.”

Goers, U.B., T.J. Kulp, and T.G. McRae, “Back scatter Absorption Gas Imaging of VOC's and its use in Petrochemical Leak Detection,” publis hed 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/fi lelibrary/hermanson.ppt

. Pacific Advanced Technology, 2000, “IMSS Det ects 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, Nove mber 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 si gnificant amount of wastewater, contributing to emissions released to the atmosphere, nearby wa ter bodies and the production of solid waste. This wastewater is then either recycled for sp ecific use in the petroleu m refinery or processed through a series of on-site collection and treatm ent units to reduce air and water emissions, as
well as solid waste. Emissions to the air consis t mainly of volatile or ganic carbons (VOCs) and hazardous air pollutants (HAPs) fr om 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, wh ich 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 c ontrolling the release of contaminants into air, water, and solid waste. This section will only focus on air emissions from petroleum refinery
wastewater collection and treatm ent systems, and provide cont rol 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 cove red and/or controlled. Both equipment covers and pollution control eq uipment can be employed to further reduce VOC emissions from the wastewater treatment facilities at petr oleum refineries in the MARAMA region.

6.1 PROCESS DESCRIPTION
Wastewater treatment systems at petroleum refine ries treat cooling water, process water, storm water, and sanitary sewage water before di scharging the treated water to a public owned treatment works (POTW) facility or to a nearby receiving wa ter body. Wastewater treatment systems are divided into two sect ions; 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 st ations, while treatment system consist of some or all of the following: oil-water separators , equalization basins, di ssolved air floatation (DAF)/dissolved nitrogen floatati on (DNF) tanks, clarifiers, biol ogical treatment basins, sludge digesters, treatment tanks, surface impoundments, and air and steam strippers. Figure 6-1 depicts a typical refinery wastewat er collection and treatment system.

Collection system components are designed to collect wastewater s from various process units throughout the petroleum refinery a nd transport them to the treatment facility. Collection system components are defined as follows: Process dr ains are the connecting point between process sources and sewer lines, trenches, sumps, or ditches. Manholes pr ovide entrances to sewer lines for sewer inspection and cleaning. Reaches are th e lengths of sewer pipe between each manholeAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 6 – Wastewater Treatment Page 6-2

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### or between other sewer components, such as lift stations or junction box es. 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 cons tant 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 collectio n and equalization of wa stewater flow from trenches. Lift stations provide sufficient pres sure to transport collected wastewaters to the treatment system.

Figure 6-1. Typical Refinery Wastewa ter 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 6 – Wastewater Treatment Page 6-3

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### Treatment system components are responsible fo r 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-wate r separators (also known as API se parators) are the first step in wastewater treatment, which separates oil and suspended solids from wastewater based on the specific gravity of each liquid. Equalization basi ns 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 remaini ng in the wastewater, removing these pollutants using a surface skimmer. Clarifiers are used to remove sludge from wa stewaters. Biological treatment basins are large aer ation basins where microorgani sms metabolize organic compounds through the use of mechanical aer ation. Sludge digesters treat organic sludge through aeration
with conventional air diffusers or surface aera tion equipment. Treatment tanks, including biological treatment tanks and pH adjustment tanks , are used to treat wastewater before and/or after biological treatment. Surface impoundme nts are used for evaporation, polishing, equalization, storage, leachate collection, and as emergency surge basins. Air and steam stripping can be used to remove organic constituen ts in wastewater streams prior to secondary or tertiary treatment devices. Air stripping involves cont acting wastewater with air to strip out VOCs, while steam stripping involve s distillation of the wastewat er 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 po llutant 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 th at 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 a nd 2009 due to new regulations or enforcement
settlements.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 6 – Wastewater Treatment Page 6-4

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### Table 6-1: Emission Invent ory 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 1,259.2Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 6 – Wastewater Treatment Page 6-5

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### 6.3 EXISTING REQUIREMENTS
This section discusses the regul atory requirements which apply to wastewater treatment systems at petroleum refineries. Four t ypes of requirements are discussed: (1) Federal requirements such
as the New Source Performance Standards (NSPS) and Maximum Achievable Control Technology (MACT) standards; (2) State regulati ons 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 syst ems, oil-water separators, and aggregate wastewater treatment facilities at petroleum refineries. For indivi dual drain systems, each drain should be equipped with water seal controls and be visually or phys ically inspected monthly for low water levels. Each drain system’s junction box should be equi pped with a cover and tight seal around the edges and should be inspected semiannually for broke n seals. In addition, sewer lines should be covered or enclosed with no visible gaps or crack s in joints, seals, or other emission interfaces and inspected semiannually. Alternative standard s allow for the owner or operator to construct and operate a closed drain system with a cont rol device with the Administrator’s approval.

For oil-water separators, each oil-water separa tor tank, slop oil tank, storage vessel, and any other auxiliary equipment subject to this subpa rt should be equipped a nd operated with a fixed roof and visually inspected semiannually for crac ks or gaps in the roof and wall, access doors, and roof seals. In addition, oil-water separa tor tanks or auxiliary equipment with a design capacity to treat more than 250 gallo ns 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 (m easured 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 devi ces with a 95% VOC control efficiency and a minimum residence time of 0.75 seconds at a minimum temperature of 1,500 o 

### F, vapor recovery stems with a minimum 95% VOC control efficienc y, and flares. Alternat ive standards allow the use of floating roof tanks on oil-water separato rs, slop oil tanks, storage vessels, and other auxiliary equipment with approval from the Admi nistrator. As for monitoring requirements, Subpart QQQ requires using a temperature mon itoring device for thermal or catalyticAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 6 – Wastewater Treatment Page 6-6

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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 fo r 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 operati ons. Under this subpart, wastewater treatment systems with an annual benzene loading of 11 tons/y r or greater are required to comply with the requirements of 40 CFR Part 61, Subpart FF (NES HAP for Benzene Waste Operations), which requires the removal of benzene from the wastew ater stream by 99% or more on a mass basis, meet a 10 ppmw on a flow-weighted annual aver age basis final benzen e 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 regulat ory 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 Califor nia (from the Bay Area Air Quality Management District – BAAQMD, the South Coast Air Qual ity Management District – SCAQMD, and the San Joaquin Valley Air Pollution C ontrol District – SJVAP CD). Regulations from these states are presented because these st ates tend to enforce stricter emission limitations than the
MARAMA states and th e 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 incr eased monitoring, regular laboratory and program audits, quarterly benzene balances, and repla cement of carbon emission filters as soon as monitoring detects any benzene emissions above background levels. In general, the Consent Decrees require program benzene waste NES HAP 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 ensu re 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 6 – Wastewater Treatment Page 6-7

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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/w ater) 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 c ontaining 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 or ganic materials or mixtur e 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 su rface 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 separato rs) 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-de ck type cover, equi pped with closure seal s 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/w ater) 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 6 – Wastewater Treatment Page 6-8

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### Table 6-3: Summary of Other State Regulations

Agency Emission Limitations BAAQMD 8-8-312 Controlled Wastewater Coll ection 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 Collect ion 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 co mponent 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 uncontro lled 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 Coll ection System Components at Petroleum Refineries: Effective January 1, 2005, any new wastewater collectio n 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 ro of 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 inch 2 per foot (21 cm 2 per meter) of tank diameter 3. A properly operated biotreatment unit and wet weathe r 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/m 3 ), measured as total suspended solids, or anAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 6 – Wastewater Treatment Page 6-9

MACTEC Federal Programs, Inc. alternate parameter, as approved by the administ rative authority, may be measured to ensure proper operation of the biotreatment unit. SCAQMD Rule 1176. 1. Wastewater System Emissions: Wast ewater systems and closed vent sy stems, 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 fi xed 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 cumulativ e length of 97 percent of the perimeter of the separator. No gap between the wall an d the seal shall exceed 1/2 inch. 3. Sewer lines: All sewer lines shall be completely en closed 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 cont rols 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 ve nt 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 sy stem 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 em issions 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, refi nes, stores or handles petroleum or coal tar products unless such compartments are equipp ed 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 ar e 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 s eal shall exceed one-half (1/2) inch; or C. A vapor recovery system with a combined collecti on 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 pe rcent control effici ency by weight. A control device must be under District permit.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 6 – Wastewater Treatment Page 6-10

MACTEC Federal Programs, Inc. Texas Rule 115.142 1. For wastewater treatment com ponents, including storage tanks, su rface 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 cont rol 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 wi th 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 sh all 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 in 2 /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/m 3 ), measured as total suspended solids.



### 6.4 AVAILABLE CONTROL TECHNOLOGIES
Wastewater treatment systems mainly em it VOCs through volatilization of organic compounds at the liquid surface of uncovered wa stewater collection and treatment units. The main strategies employed to limit VOC emissions from these primary treatment units include installing covers or seals over exis ting collection equipment, and using control devices to destroy VOCs that are released. A third, le ss researched, method includes reducing the available VOC in the wastewater stream before the wastewater enters collection and treatment system s. These strategies are discussed below, with several control options available to reduce VOC emissions from primary treatment units. For secondary treatment, proven control technol ogies include steam stripping, liquid phase carbon adsorption units, and doming tanks. Thes e control technologies are discussed in
Section 6.4.4.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 6 – Wastewater Treatment Page 6-11

MACTEC Federal Programs, Inc. 

### 6.4.1 Equipment Covers
Controlling VOCs from wastewater collec tion systems can be achieved by various methods, including installing water seals on pro cess drains and junction box vents, sealing manholes, enclosing open weirs, hard piping, and installing domed r oofs on sludge storage tanks. Installation of these types of seals a nd covers on collection uni ts currently open to the atmosphere will prevent volatilized em issions 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 th e sewer line and the atmosphere to prevent air flow through the system. Wate r levels within the seal s hould be kept constant, as evaporation of the water will result in emi ssions of VOCs similar to the previously uncontrolled levels. There are two types of wa ter 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 seal s 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 In sert for Process Drain

SOURCE: Dunn, T.X., D.M. Breen, and C. Pham, 2004, “Draft Technical Asse ssment 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 6 – Wastewater Treatment Page 6-12

MACTEC Federal Programs, Inc. 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. Althoug h, by installing these seals, VOC emissions are still reported from ma nhole 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 Asse ssment 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 6 – Wastewater Treatment Page 6-13

MACTEC Federal Programs, Inc. 6.4.1.3 

### Enclosing Weirs and Hard Piping
Enclosing open weirs and lines wi th direct piping, a process re ferred to has hard piping, is considered one of the most stringent contro l options and could effectively eliminate VOC
emissions from weirs and sewer lines. Encl osing weirs and lines with direct piping involves (1) hard piping proce ss units to the wastewater se parator and cap all process drains, (2) hard pipe process units to a dr ain 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 opti on may eliminate VOC emissions, however, by enclosing all air emissions, there is an increase d 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 leve l for volatized organics to collect. These VOCs must then be piped to a c ontrol 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 equi pment 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 st eam strippers, gas or liquid phase carbon adsorption, and
combustion devices. These control devi ces are discussed in detail below.

6.4.2.1 

### Air & Steam Stripping
Air strippers contact wastewater with large am ounts of air in order to transfer VOCs from
the water to the air. Steam stripping is similar to air stri pping, but the wastewater is
contacted with steam to disti ll 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 materi al in the wastewater. After the VOCs are stripped from the wastewater, the contaminated air stream must th en be vented to a secondary control device, such as a combustion device (fla re, incinerator, boiler, etc) or gas phase carbon adsorber.

These stripping processes also hold some safety and equipmen t concerns. Concerns over air stripping include safety dur ing refinery upsets when th ere is a potential for large amounts of hydrocarbons to be re leased to the wastewater treatment system resulting in explosive conditions, and equipmen t concerns due to fouling of the packing material due toAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 6 – Wastewater Treatment Page 6-14

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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 stripp ing process to address these safety and equipment concerns, which involves using nitrog en as the stripping gas, thus eliminating the presence of oxygen and the safety and equi pment concerns. The main downside to this improvement, known as the AMCEC BRU (benzene recovery unit, depict ed 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 ar e 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 Improve ment, AMCEC BRU

SOURCE: Worrall, M. and I. Zuber, 1998, “Case Studie s: Control VOCs in Refine ry 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 system s are used to treat contaminated air emissions from wastewater control equipment, whereas liquid-phase systems are used to
remove VOCs from the wastewater. The mo st 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 c ontaminated air flows between 30 and 3,000

m 3 

### /min, while carbon canisters are usually inst alled to control air flows less than 3 m 3 

### /min.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 6 – Wastewater Treatment Page 6-15

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### Control efficiencies vary between 90 a nd 99% depending on the types of VOCs being removed, and in some cases using pollutant sp ecific activated carbon. There are also two types of liquid phase carbon adsorbers, includi ng fixed-bed and moving-bed systems. The fixed-bed system operates in batch mode, proces sing 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-volatil e components and for high concentrations of non-degradable compounds. They achieve cont rol 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 destructi on. Common combustion devices include flares (discussed in Section 4.0), thermal or catal ytic incinerators, and boilers (discussed in Section 3.0). These devices can reduce VOCs by combusting them at a specified minimum temperature for a specified residen ce time to ensure complete destruction. Typically vented gases can be combined with na tural gas or fuel oil to supplement the fuel
or used as an alternate fuel in cases where th e 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 meas ures have been identified by the BAAQMD as ways to reduce the concentration of VOCs entering the wastewater collection a nd treatment system. These measures include the following list.

• Reduce the generation of tank bottoms

• Minimize solids leaving the desalter unit

• Minimize and/or segregate cool ing tower blowdown condensate

• Minimize fluid catalytic crack ing unit decant oil sludge

• Control heat exchanger cl eaning solids and sludge

• Minimize discharge of surfactants in to 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 upstr eam water treatment and/or separation

• Use oily sludges as feedstock

• Control and reuse FCCU and coke fines

• Train personnel to re duce solids in sewers from sludge treatmentAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 6 – Wastewater Treatment Page 6-16

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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 prio r 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 compone nts at refineries. The BA AQMD identified three control options:

• Steam stripping is a proven technolo gy to remove VOCs prior to secondary treatment. It requires proper venting to a secondary control device and monitoring to insure optimal operation. The BAAQMD estim ates 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. Th e estimated VOC emission reductions are 0.14 tons per day (tpd) based on a 90% re moval 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 stripp er. The BAAQMD estimates that the total annual costs are comparable to that of a steam stripper. Th e BAAQMD estimates VOC emission reductions to be 0.14 tpd base d 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 accomm odate 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 add itional expenses to install and operate VOC abatement equi pment. 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 decide d not to implement these technologies because of the relatively small emission reductions compared to the present cost of implementing these known technologies. Th e 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 6 – Wastewater Treatment Page 6-17

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### 6.5 COSTS AND AVAILABILITY
Feasible control technologies for primary a nd secondary wastewater treatment units are
summarized in Table 6-4. The table includes

• Pollutant controlled

• Name of technology

• Origin for the level of contro l (rule, consent decree, permit)

• Range of potential emission reductio ns from applying those controls

• Performance level in terms of outle t 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 da ta represent data for
uncontrolled sources. Incremental reductions w ill 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-s pecific factors greatly influence the actual achievable performance level and control co sts at a particular facility. These
considerations must be addressed in State a nd local rulemaking and pe rmitting processes.Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Section 6 – Wastewater TreatmentPage 6-18MACTEC Federal Programs, Inc.Table 6-4: Control TechnologyOptions for Wastewater TreatmentPollutant TechnologyOrigin ofRequirement Percent ReductionPerformanceLevelCost Effectiveness($/ton)CommerciallyAvailable? ReferencePrimary Treatment ProcessesVOC Install water seals on drains BAAQMDRule 865 n/a 1,900 to 4,200 Yes Dunn, 2004Install water seals onjunction box ventsBAAQMDRule 865 n/a 1,900 to 4,200 Yes Dunn, 2004Sealing manholes BAAQMDRule 865 n/a 1,900 to 4,200 Yes Dunn, 2004Enclosing open weirs andlines with direct pipingBAAQMDRule 8100 n/a 1,900 to 4,200 Yes Dunn, 2004Reduce VOCs toWastewaterBAAQMDRule 8Depends on PreventionMeasures Implementedn/a Cost Savings Yes Dunn, 2004Secondary Treatment ProcessesVOCInstall domed roofs onactivated sludge tanksn/a 95 n/a 25,000 Yes Broadbent,2005Air or Steam Stripper n/a 90 to 99 n/a 1.35 to 1.42 million Yes Broadbent,2005Liquid Phase CarbonAdsorptionn/a 90 to 99 n/a 1.35 to 1.42 million Yes Broadbent,2005Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 6 – Wastewater Treatment Page 6-19

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### 6.6 REFERENCES
Broadbent, J.P., 2005, Memorandum to Chairper son Townsend and Members of the Board of Directors, November 9, Bay Area Ai r Quality Manageme nt District, San Francisco, California.

European Commission, Integrated Pollu tion Prevention & Control (ECIPPC), 2003,
“Reference Document on Best Availabl e 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,” Calif ornia Air Resources Board and the Bay Area Air Quality Management District.

Lau, V., 2005, “Workshop Staff Report: Furthe r Study Measure 9 Refinery Wastewater Treatment Systems,” Bay Area Air Quality Management District, San Francisco,
California.

United States Environmental Protecti on 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 Fact ors, 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-1

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## 7.0 STORAGE TANKS

Storage tanks at petroleum refi neries containing volatile orga nic liquids (VOLs) such as petroleum and petroleum derivatives can em it 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 cha nges in temperature and barometric pressure, vapor losses due to filling a nd emptying tanks, and vapor losses at tank roof seals. These types of losses can not be completely eradi cated, 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 stor age tanks containing organic liquids varies depending on the tank’s roof de sign 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 vertic al fixed roof tank, as shown in Figure 7-1, is a cylindrical steel shel l with a permanent fixed flat, dome, or cone shaped roof. Vertical fixed roof tanks can eith er be vented to the at mosphere 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 fi berglass-reinforced polyester, and are usually equipped with pressure/vacuum vents, gauge hatches, sample wells, and manholes to provide access to the tank. Thes e 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-g round 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, ch anges 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-2

MACTEC Federal Programs, Inc. 

### Figure 7-1. Vertical Fixed Roof Tank

SOURCE: U.S. EPA, 1997, “Organic Liquid Storage Ta nks,” 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 cons ist of an open cylindrical steel shell fitted with a roof that floats on the surface of the stored liquid. Ther e 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 facilit ated through the use of a rim seal system which is attached to the deck perimeter and contacts the tank wall. Emi ssions 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 evaporati on of exposed liquid on the tank walls.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-3

MACTEC Federal Programs, Inc. 

### Figure 7-2. Pontoon Extern al Floating Roof Tank

Figure 7-3. Double-Deck Ext ernal 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-4

MACTEC Federal Programs, Inc. 

### 7.1.3 Internal Floating Roof Tanks
Internal floating roof tanks ha ve two roofs, a permanent fixe d roof above a floating roof. The fixed roof portion of the in ternal 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 th e stored liquid level, just as in the case of the external floating roof tank, and either re sts directly on the liqui d surface (known as a contact deck) or rests on pontoons a few inch es above the liquid surface (known as a noncontact deck). A typica l internal floating roof tank is s hown 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 Liqu id 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-5

MACTEC Federal Programs, Inc. 

### 7.1.4 Domed External Floating Roof Tanks
Domed external floating roof tanks are a combin ation 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 covere d by a fixed roof similar to those used for internal floating roofs, as seen in Figure 7-5. These tanks are us ually the result of retrofitting an external floating roof tank with a fixed roof. Th e fixed roof is usually a self supporting aluminum dome roof, whose func tion is to block the wind from causing evaporative losses.

Figure 7-5. Domed Extern al Floating Roof Tank

SOURCE: United States Environmental Protection Agency, 1997, “Organic Liqu id 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-6

MACTEC Federal Programs, Inc. 

### 7.1.5 Variable Vapor Space Tanks
Variable vapor space tanks are equipped with expandable vapor reservoirs to accommodate vapor fluctuations due to atmosphere temp erature 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 tele scoping roof that loosel y fits the outside of the main tank wall. The space between the roof a nd 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 th e 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 fr om 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 temperatur e or pressure changes) or working losses (emissions due to changes in liquid levels) occu r. However, low pressure tanks can have release VOCs atmospheric venting during tank filling.

7.2 EMISSION INVENTORY
Table 7-1 identifies the fugitive VOC emissi ons 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 fu ture SIP development. The 2002 emissions
were obtained from the 2002 inventories developed by MANEVU and VISTAS. The 2003 emissions were obtained directly from each st ate and represent the most currently quality
assured data that is available. The 2009 emissions were obtained from the MANEVU and VISTAS projection inventorie s 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-7

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### Table 7-1: Emission Inve ntory 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. MA RAMA states are reviewing the latest guidance from EPA with respect to projecting emissions from nonEGU sources such as storage tanks.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-8

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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 requireme nts are discussed: (1) Federal requirements
such as the New Source Performance St andards (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 J une 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 vessel s constructed or modi fied 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 vessel s with capacities between 40,000 and 65,000 gallons that were constructe d or modified after March 8, 1974 and before May 19, 1978. Storage vessels for petroleum or condensate st ored, processed, and/or treated at a drilling and production facility prior to custody transfer are exempt fr om 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 r oof and a vapor recovery system, or other equivalent equipment. For petroleum liquids with a true vapor pre ssure greater than 11.1 psia, a vapor recovery system or equivalent equipment is required.

Subpart Ka applies to petroleu m liquid storage vessels with st orage capacities greater than 40,000 gallons, however storage vessels with storage capacities less than 420,000 gallons used for petroleum or condensate stored, proces sed or treated prior to custody transfer are exempt. Storage vessels cont aining 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 reco very system that collects all VOC vapors and discharged gases, or an equi valent system. Storage vessels containing petroleum liquids with true vapor pressures gr eater than 11.1 should be equipped with a vapor recoveryAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-9

MACTEC Federal Programs, Inc. 

### system to collect all discharged gases and a va por 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 cap acities greater than or equal to 75 m 3 

### . However, this subpart excludes storage vessel s with capacities greater than 151 m 3 

### storing a liquid with a maximum true vapor pressure less than 3.5 kPa or vessels with capacities between
75 and 151 m 3 

### storing a liquid with a maximum true vapor pressure less than 15.0 kPa. For storage vessels greater than 151 m 3 

### 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 m 3 

### 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 inte rnal floating roof, an external floating roof, a closed vent system and control device, or an equivalent system. Storage vessels with capacities greater than 75 m 3 

### containing a VOL with a ma ximum 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 fo r 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 i ndustry for process vents, storage vessels, transfer operations, and wastewater) sections 63.119 through 63.121. These sections provide control technology requirements, comp liance 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 m 3 

### ≥ 10.4 kPa

≥ 8.3 kPa (annual) > 4% by wt.

New Source ≥ 151 m 3 

### ≥ 3.4 kPa > 2% by wt.

New Source 76 – 151 m 3 

### ≥ 77 kPa > 2% by wt.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-10

MACTEC Federal Programs, Inc. 

### Section 63.119 requires that Group 1 storage ve ssels containing liquids with a maximum true vapor pressure less than 76.6 kPa be equi pped with either a fixe d roof and internal floating roof, an external floating roof, an exte rnal roof converted to an internal roof, a closed vent system and control device, route em issions to a process or fuel gas system, or perform regular vapor balances. On the othe r 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 devi ce, 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 t echnology used to control emissions from the storage vessels, including visual inspec tions, gap measurements, design evaluations, performance tests, etc. Control devices which perform equal to or better than the required control technology are also allowe d 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 Califor nia (from the Bay Area Air Qual ity Management District – BAAQMD, the South Coast Air Quality Mana gement District – SCAQMD, and the San Joaquin Valley Air Pollution Cont rol District - SJVAPCD). Re gulations from these states are presented because these st ates tend to enforce stricter emission limitations than the
MARAMA states and th e federal government.

7.3.3 Requirements from Recent Enforcement Settlements

There are no enforcement settlements for stor age tanks at petroleum refineries in the MARAMA region.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-11

MACTEC Federal Programs, Inc. 

### 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 th at 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) Th e seal(s) are intact and uniformly in place around the circumference of the floating roof between the floating ro of and the tank wall; and (c) For vapor-mounted primary seals, the accumulated area of gaps exceeding 0.12 5 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 clos ed position except when the openings are in actual use; and (b) Projections in to the tank that remain belo w 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 st orage tank with a capacity gr eater 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 eff ective 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 hol es, 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:Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-12

MACTEC Federal Programs, Inc. 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 maintain ed white, except that this provision shall not apply to

words and logos applied to the extern al surface of the storage tank for pu rposes of identification provided such symbols do not cover more than 20 percent of th e external surface area of the tank's sides and top or more than 200 ft 2 , 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 th e 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 st orage 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 w ith 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 in to the outdoor atmosphere. For the s econdary seal, the gap area of gaps exceeding 1/8-inch in width between the seal and the tank wall sh all 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, record s 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, re servoir 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 collectingAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-13

MACTEC Federal Programs, Inc. 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 primar y 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 th e following requirements: (a) There ar e no visible holes, tears or other

openings in the seals or seal fabric; (b) The seals are in tact and uniformly in place ar ound 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 in 2 /ft of tank diameter. 2. Openings in the external floating roof, except for automatic bleeder vent s, rim space vents and leg sleeves, are

as follows: (a) Equipped with covers, seals or lids in th e 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 membra ne 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 prim ary 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 sha ll 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 vesse l with a floating roof subject to this regulation shall:

1. Perform routine inspections annually. The inspection sh all include a visual inspec tion 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, theAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-14

MACTEC Federal Programs, Inc. vapor pressure under actual storage conditions shall be de termined using a temperature which is representative of the average storage temperature fo r 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 sta tionary 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 se t 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 highes t possible pressure and vacuum in accordance with state or local fire codes or the National Fire Prevention Associ ation 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 storag e 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 add ition, all tank gauging and sampling devices shall be gas tight except when in use, or 2. A pressure tank system maintaining a pressure at a ll times so as to prevent organic material loss to the

atmosphere, or 3. A vapor recovery system capable of collecting the or ganic 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 storag e 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 a ll times so as to prevent organic material loss to the

atmosphere, or 2. A vapor recovery system capable of collecting the or ganic 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 unifor mly in place around the circumference of the cover between the cover and tank wall.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-15

MACTEC Federal Programs, Inc. b. Perform a complete inspection of the cover and seal and record the condition of th e 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 includ e a visual inspection of th e 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 unifo rm 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 seco ndary 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) Th e seal(s) are intact and uniformly in place around the circumference of the floating roof between the floating ro of and the tank wall; and (3) For vapor-mounted primary seals, the accumulated area of gaps exceeding 0.12 5 in. in width between the secondary seal and the tank wall shall not exceed 1.0 in 2 /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 cl osed position except when the openings are in actual use; and equipped with projec tions 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 se condary seal gap); and measure the se condary 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-16

MACTEC Federal Programs, Inc. This section applies to any fixed roof petroleum liquid st orage tank with a capacity gr eater 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 ro of equipped with a closure seal or seals to close the space between the roof edge and tank wall; or an equally effectiv e alternative control, approved by the Director and the U.S. EPA;

b. The tank is maintained such that there are no visible hol es, 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 inspectio n of cover and seal whenever the tank is emptied for non-operational reasons or at least every 5 years, whichever is more frequent.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-17

MACTEC Federal Programs, Inc. 

### 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.

True Vapor Pressure of Tank Organic Contents Tank 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 re st on the surface of the liquid tank contents, must be properly installed and maintained, and must be in goo d 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 th e 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 ta nk are replaced at one time, or if sections of seal with a total cumulative lengt h equal to or greater than 50% of the total seal circumference are replaced over time, then the seal sha ll be considered to be newly installed and subject toAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-18

MACTEC Federal Programs, Inc. 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 se rvice or de-gassed after Fe bruary 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. Ther e 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 ab atement 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 pos ition 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 proj ection 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 complian ce 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 sha ll 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 crite ria 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 sh ell 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 cumulativeAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-19

MACTEC Federal Programs, Inc. 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 exceedin g 1/8 in. shall be not more than 40% of the circumference. c. For riveted tanks, no gap betw een the tank shell and the primary seal shall exceed 2-1/2 in. The

cumulative length of all primary seal gaps exceedin g 1-1/2 in. shall be not more than 10% of the circumference. 4. For resilient-toroid-seal equipped tanks, no gap be tween 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 s eal 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 surf aces, 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 leng th 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 e qual to or greater than the diameter of the tank are replaced at one time, or if sections of seal with a tota l cumulative length equal to or greater than 50% of the total seal circumference are replaced ov er time, then the seal shall be co nsidered to be newly installed for the purpose of this section. 6. The secondary seal shall extend from the roof to the ta nk 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 ho ld in any stationary tank, reservoir, or other containe r 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 ho ld 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 conten ts 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 shallAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-20

MACTEC Federal Programs, Inc. 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 li quid 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 th e 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 cove rs 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 (excep t rim space vents and automatic bleeder vents) shall be

provided with a projection below the liquid surface. In addition, eac h opening (except for leg sleeves, bleeder vents, rim space vents, column wells, ladde r wells, sample wells, and stub drains) shall be provided with a cover equipped w ith 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 conten ts 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 mo unted 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 sh oe 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 uni formly in place around the circumfe rence 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 in 2 /ft of tank diameter; (d) not have gap areas, of gaps exceeding 1/8 inch in width between the primary seal and th e tank wall, in excess of 10.0 in 2 /ft of tank diameter; and (e) the secondary seals shall be visually inspected at leas t 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 ve nts, roof drains, and leg sleeves, e ach 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. Automa tic 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 Syst ems. Emissions from guide pole systems must be

controlled for external floating roof storage tanks with a capacity > 40,000 gallons and which store aAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-21

MACTEC Federal Programs, Inc. 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 we lls 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 ar e 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 exce pt 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 hol d 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 th e 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 guidepo le 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 co ndition 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 allAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-22

MACTEC Federal Programs, Inc. times, with no visible gaps, except when th e 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 great er 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 betwee n 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 criteri a for a length of at least 18 inches in the vertical plane above the liquid surface. 7. The primary seal envelope shall be made availabl e for unobstructed inspectio n 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 th e 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 complia nce 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-23

MACTEC Federal Programs, Inc. B. Phase II: For additional external floating roof ta nks 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 comp ly with these requirements no late r than 2 years after becoming subject to the rule. C. In lieu of complying with the requirements in subpara graph B., the operat or who is subject to Phase I shall

accept permit conditions to limit th e true vapor pressure of the organic liq uids 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 concentratio n of organic vapor in the vapor space above a domed

external floating roof shall not excee d 30% of its lower explosive limit (LEL) by the applicable compliance F. The operator shall submit to the Ex ecutive 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 inform ation 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 suppo rt column and well with a sliding cover that is gasketed or w ith 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 th e 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, th e 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 theAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-24

MACTEC Federal Programs, Inc. operating pressure of the fixed roof tank exceeds the manufacturer’s recommended setting. B. In lieu of complying with the requirement in su bparagraph 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 facil ity 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 fl oating roof tanks no later than 6 years after becoming

subject to this rule. Any external floating roof tank th at 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 floatin g 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: Excep t 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

True Vapor Pressure (TVP) of Organic Liquid Tank Capacity (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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-25

MACTEC Federal Programs, Inc. B. Small Producer VOC Control System Requirements: A small producer sh all not place, hold , or store crude oil in any tank unless such tank is equipped w ith a VOC control system identified in Table 2. Table 2 – Small Producer VOC Control System Requirements for Crude Oil Storage Tanks

True Vapor Pressure (TVP) of Organic Liquid Tank Capacity (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 th is rule shall be maintained in a leak-free condition,

except for (a) Primary seals and secondary seals of external floatin g 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-de ck type cover, that rests on th e 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 pr imary seal, and the one above shall be referred to as the secondary seal. 3. The floating roof shall be floatin g 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 sha ll 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 s eal shall exceed 1-1/2 inches. The cumulative length of

all gaps between the tank shell and the primar y 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-26

MACTEC Federal Programs, Inc. 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 allowe d 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 th e roof edge, seal fabric, and secondary seal. f. The secondary seal shall allow easy insertion of prob es 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 th e 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 s eal 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 she ll and the primary seal > 1/8 inch shall not exceed 30% of the circumference of the tank. No contin uous 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 th e 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 th e 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 th e 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 primaryAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-27

MACTEC Federal Programs, Inc. 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 s eals that meet the criteria se t 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 th e gap criteria for primary and secondary seals:

Manufacturer Model

Ultraflote Dual Ultraseal

Altech Double Wiper Seal

C. The operator shall comply with th e floating roof landing requirements Floating Roof Deck Fitting Requirements A. All openings in the roof used for sampling or ga uging, shall provide a proj ection 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 co ver, 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 floati ng roof except for automatic bleeder vents (vacuum

breaker vents) and rim space vents shall pr ovide a projection below the liquid surface.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-28

MACTEC Federal Programs, Inc. b. Each opening in the internal floating roof excep t 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 floa t well shall be bolted in place except when they are in use. c. Automatic bleeder vents shall be equipped with a gask et 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 prov ide 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 gask et 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 no t 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 determineAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-29

MACTEC Federal Programs, Inc. compliance with the secondary seal requirement, and in no case shall exceed 1/8 inch. Specifications for Vapor Recovery SystemsA. 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 cl osed 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 in let 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. Co ntrol Requirements.

A. For all persons in the Beaumont/Port Arthur, Dalla s/Fort Worth, El Paso, and Houston/Galveston, the following requirements shall apply:

1. No person shall place, store, or hold in any stationary tank, reservoi r, or other container any VOC unless

such container is capable of maintaining working pressu re sufficient at all times to prevent any vapor or gas loss to the atmosphere, or is equipped with at least the control device speci fied 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 projectio n 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 time s 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-30

MACTEC Federal Programs, Inc. 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 vapor recovery system ≥ 11 psia (75.8 kPa) > 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 vapor recovery system ≥ 11 psia (75.8 kPa) > 40,000 gal Submerged fill pipe and vapor recovery systemAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-31

MACTEC Federal Programs, Inc. 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 vapor recovery system ≥ 11 psia (75.8 kPa) > 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). Th e 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 in 2 /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, reservoi r, or other container any VOC, unless

such container is capable of maintaining working pressu re sufficient at all times to prevent any vapor or gas loss to the atmosphere, or is equipped with at least the control device speci fied 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 projec tion 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 time s 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). Th e 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 in 2 /ft of tank diameter.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-32

MACTEC Federal Programs, Inc. C. For all persons in Aransas, Bexar, Calhoun, Matago rda, San Patricio, and Travis Counties, the following requirements shall apply. 1. No person may place, store, or ho ld 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 atmos phere, or is designed and eq uipped 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 Pa tricio 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-33

MACTEC Federal Programs, Inc. 

### 7.4 AVAILABLE CONTROL TECHNOLOGIES
The main mechanisms of evaporative VOC losses from storage tanks at petroleum refineries are breathing loss, standing storag e loss and working loss. Breathing losses are due to fluctuations in atmosphere temperat ure and pressure causing the organic liquid to volatilize. Standing storage losses are a resu lt of evaporative losses through rim seals, deck fittings, and/or deck seams. Working lo sses are due to change s in the stored liquid levels caused by to filling and draining operati ons. Emissions from each of the types of tanks mention in Section 7.2 can vary. Emissi ons from fixed roof ta nks are a result of breathing and standing storage losses, with emi ssions from external and internal floating roof tanks resulting from standing storage a nd 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 ar e available to limit emissions due to standing storage and working losses from fixed roof tanks. C ontrol techniques include retrofitting the fixed tank to an internal floating roof tank and va por balancing, as well as implementing a vapor recovery system or thermal oxidation sy stem (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 lo sses. Depending on the type of roof and seals installed and liquid stored, control e fficiencies of 60% to 99% can be achieved.

7.4.1.2 

### Vapor Balancing
Vapor balancing is a method of collecting th e 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 e xpelled vapors are collected in the tanker truck and are then transported to a va por recovery system or combus tion device. If the collected vapors are subsequently contro lled, 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 floa ting roof tanks, working losses occur when the floating roof is lowered, and residual liquid on the tank’s inner walls evapor ate. The standing storage losses originate from rim seals and deck s eems and fittings, and are highly affected byAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-34

MACTEC Federal Programs, Inc. 

### wind. Options to reduce these vapor losses fr om 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 ri m 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 fl oating 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, th e secondary seal is mounted to an extended vertical rim plate above the primary seal. Even though sec ondary 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 se al 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 fo r combustion as fuel. Vapor recovery can be achieved either through condensation, carbon ad sorption, or absorption. Depending on the procedure used, the design of the vapor r ecovery 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 pressu rizing VOC vapors to return them to their liquid state. This process is most effect with VOCs whose boiling points are above 40 o 

### C (104 o 

### 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. InAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-35

MACTEC Federal Programs, Inc. 

### 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 act ivated carbon is a flammable substance, thus fire suppression systems are needed in the rec overy system, and/or th e 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 th e solvent. The absorber tower is designed to provide the necessary liquid-vapor contact ar ea to facilitate mass transfer. Packed bed towers and mist scrubbing systems are two type s of absorber towers that can remove 95% to 98% of the incoming VOCs fr om the waste gas stream. One advantage of absorber systems is its ability to handle fluctuations in incoming VOC con centrations, which can vary between 500 and 5000 ppm.

7.4.2.4 

### Incinerators
One of the most popular control devices for de stroying collected VOCs is an incinerator, either thermal or catalytic. Thermal incinerators combust VOCs at temperatures between
1400 o 

### F and 2000 o 

### F 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 concen tration between 100 and 2000 ppm. Catalytic oxidizers are similar to thermal oxidizers, however th ey use a catalyst in the presence of lower combustion temperatures, between 600 o 

### F and 900 o 

### F, to oxidize VOCs in the waste gas

stream.

7.4.3 More Stringent Standards
The Bay Area Air Quality Management Distri ct (BAAQMD) in Calif ornia is currently studying applicable control measures to furt her 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 li quids 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 programAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-36

MACTEC Federal Programs, Inc. 

### 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 doe s not address storage tanks containing liquids with true vapor pressu res less than or equal to 0.5 psia. By applying the current tank standards to these tanks, VOC emissions would be reduced. Ta nks storing low vapor pressure liquids inevitably generate fewer VOC emissions than tanks storing high vapor pressure liquids. For this reason, to impleme nt control devices on storage tanks containing low vapor pressure emissions woul d not be cost effective.

7.4.3.2 

### Tank Cleaning
Current tank cleaning standards re quire that the insides of tank s be cleaned when either the accumulation of sludge inside the tank cause s an unacceptable loss of tank capacity or when the sludge affects product quality. Gi ven this guideline, most tanks are cleaned every 5 to 10 years, or prior to decommissi oning. 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 or ganic vapor concentra tion, and then the tank is ready to be cleaned. Unde r current standards, only tanks with storage capacities greater than 19,803 gallons are required to be degasse d prior to tank clean ing and/or opening. Degassing is to be performed by liquid balanc ing (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, th e 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 cleani ng/degassing standards proposed by the BAAQMD include:

• Lower the tank capacity (currently 19,803 ga llons) which triggers required tank degassing

• Reduce the current 10,000 ppm residua l organic standa rd to 5,000 ppm

• Increase the required minimum control effi ciency of the control device from 90% to 95%

• Increase control device m onitoring from an annual test to continuous real-time monitoring during venting

• Regulate the handling of sl udge removal from tanksAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 7 – Storage Tanks Page 7-37

MACTEC Federal Programs, Inc. 7.4.3.3 

### Maintenance Programs
No provisions currently exist under Regulati on 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 ta nks are summarized in Table 7-5. The table
includes

• Pollutant controlled

• Name of technology

• Origin for the level of contro l (rule, consent decree, permit)

• Range of potential emission reductio ns from applying those controls

• Performance level in terms of outle t 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 da ta represent data for
uncontrolled sources. Incremental reductions w ill 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-s pecific factors greatly influence the actual achievable performance level and control co sts at a particular facility. These
considerations must be addressed in State a nd local rulemaking and pe rmitting 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 Pollu tion Prevention & Control (ECIPPC), 2003,
“Reference Document on Best Availabl e 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.Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Section 7 – Storage TanksPage 7-38MACTEC Federal Programs, Inc.Table 7-5: Control Technology Summary for Storage TanksPollutant TechnologyOrigin ofRequirement Percent ReductionPerformanceLevelCost DataCommerciallyAvailable? ReferenceVOC Install internal floatingroof in fixed roof tankNSPS/NESHAP/State Rule60 to 99See applicableruleInvestment:$240,000 - $480,900Operating: minorYes ECIPPC,2003Install domed fixed roof ona external floating rooftankNSPS/NESHAP/State Rule96See applicableruleAvg. cost:$21,640 – $240,500Yes ECIPPC,2003Replace a vapor-mountedprimary seal with a liquidmounted primary sealNSPS/NESHAP/State Rule30 to 70 EFRT143 to 45 for IFRT1See applicableruleAvg. cost:$5,530 - $18,155Yes ECIPPC,2003Install secondary seals onfloating roof tanksNSPS/NESHAP/State Rule75 – 95%See applicableruleInvestment:$60,000 - $120,000Avg. cost:$4090 – $13,590Yes ECIPPC,2003Vapor Balancing NSPS/NESHAP/State Rule80%See applicableruleInvestment:$96,000/tankYes ECIPPC,2003Vapor Recovery Systems NSPS/NESHAP/State Rule80 – 99%See applicableruleInvestment:$337,000 –$2,164,000Operating:$60,000 – $144,300Yes ECIPPC,2003Incineration NSPS/NESHAP/State Rule95 – 99%See applicableruleInvestment:$2.4 - $30 millionOperating:$24,100 - $1,320,000Yes ECIPPC,2003Apply tank standards totanks storing organicliquids with vaporpressures 0.1 – 0.5 psiaVaries$20,500 - $34,000 perton VOC reduced(potential reduction of100 – 160 tons/yr)Yes Elliot,20041EFRT = external floating roof tank;IFRT = internal floating roof tankAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 8 – Sulfur Recovery Units Page 8-1

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## 8.0 SULFUR RECOVERY UNITS

As discussed in the previous sections, SO 2 

### is released from petroleum refinery FCCUs, boilers/process heaters, and flares as a result of firing fuels containing sulfur compounds. These emission units comprise a pproximately 81% of the total SO 2 

### emissions from petroleum refineries, while emissions from su lfur recovery units (11%) and miscellaneous process equipment make up the remaining 19%. Typical sulfur recovery configurations at petroleum refineries entail the use of the Clau s sulfur recovery process followed by a tail gas clean-up unit (TGCU) to maximize removal of H 2 

### S. Several process modifications are available to increase sulfur recovery from th is process, however, they result in increased
emissions of CO 2 

### to the atmosphere.

8.1 PROCESS DESCRIPTION
Claus sulfur recovery units convert hydrogen sulfide (H 2 

### S), a by-product of refining crude oils to elemental sulfur through multistage ca talytic oxidation. Each catalytic stage can only recover half to two-thirds of the incomi ng 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. Th e Claus reaction proceeds in two exothermic steps. The first reaction occurs in th e reactor furnace, where a portion of the H 2 

### S reacts with air to form SO 2 

### . The second reaction takes place in catalytic reactors where the remaining H 2 

### S reacts with the SO 2 

### produced in the first reacti on to form elemental sulfur
and water. Side reactions also occu r, producing carbonyl sulfide (COS) and carbon disulfide (CS 2 

### ). After the process stream passe s through the final catalytic stage condenser, a tail gas treatment system is empl oyed 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 sulf ur 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 inve ntories 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 invent ories that were developed to support modeling for SIP development. The 2009 invent ories include the eff ects of anticipated growth as well as any planned controls that will result in emissi on reductions between 2002 and 2009 due to new regulations or enforcement settlements.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 8 – Sulfur Recovery Units Page 8-2

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### Figure 8-1. Typical Claus Sulfur Rec overy Unit Process Flow Diagram

SOURCE: United States Environmental Pr otection Agency, 1995, “Sulfur Recovery ,” Pages 8.13-1 – 8.13-5 in AP-42, Fifth Edition: Compilation of Air Pollutant Emission F actors, Volume 1: Stationary Point and Area Sources
, http://www.epa.gov/ttn/chief /ap42/ch08/final/c08s13.pdf

.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 8 – Sulfur Recovery Units Page 8-3

MACTEC Federal Programs, Inc. 

### Table 8-1: Emission Inventor y 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 8 – Sulfur Recovery Units Page 8-1

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### 8.3 EXISTING REQUIREMENTS
This section discusses the regul atory 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 re quirements; and (4) new requirements from
recent enforcement settlements.

8.3.1 Federal Requirements
The U.S. EPA has promulgated standards for emissions of SO 2 

### from petroleum refinery Claus sulfur recovery units.

New Source Performance Standards (NSPS) for Claus sulfur recove ry units constructed or modified after October 4, 1976 are covered unde r 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 oxi dation or reduction cont rol system followed by incineration, SO2 emissions are limited to 250 ppmvd at 0% O 2 

### . For units with a reduction control system not followed by incineration, emissions of reduced sulfur compounds are limited to 300 ppmvd at 0% O 2 

### and emissions of H 2 

### S are limited to 10 ppmvd at 0% O 2 

### , each calculated as SO 2 

### . Monitoring requirements are al so specified under this subpart, requiring instruments to continuously mon itor and record the concentration of SO 2 

### emissions and O 2 

### levels for data correction.

The National Emission Standards fo r 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 requireme nts of this subpart, new or existing Claus sulfur recovery units subject to NSPS require ments must comply with the emission limits set under NSPS. For new or existing units no t subject to NSPS, units must comply with either the emission limits specified under NSPS or a total reduced su lfur (TRS) limit of 300 ppmvd at 0% O 2


### .

8.3.2 State Regulations
Table 8-2 lists the regulations for each of the MARAMA states for the control of SO 2 

### from sulfur recovery units. All regulatory agenci es in the MARAMA region have regulations limiting the emissions of SO 2 

### except for Philadelphia. In Table 8-3, the regulations are listed for Louisiana, Texas, and California whic h tend to have stricter emission limitations than the MARAMA states and the federal government.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 8 – Sulfur Recovery Units Page 8-2

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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 SO 2 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 at mosphere, at any time, from a plant used for recovering elemental sulfur from gases containing sulfur compounds, of sulfur oxides, expressed as SO 2 , 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 indicat ed in Appendix A.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 8 – Sulfur Recovery Units Page 8-3

MACTEC Federal Programs, Inc. 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 SO 2

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 th e 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 diox ide 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 co nditions, exceeding in co ncentration at theAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 8 – Sulfur Recovery Units Page 8-4

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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 (SO 2 ) 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 effl uent 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.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 8 – Sulfur Recovery Units Page 8-5

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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 complia nce with NSPS Subpart J. Specific requirements are shown in Table 8-4.

Table 8-4: Summary of R ecent 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 ar e 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 ar e 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 specifiedAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 8 – Sulfur Recovery Units Page 8-6

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### 8.4 AVAILABLE CONTROL TECHNOLOGIES
Sulfur recovery units mainly emit SO 2 

### and other sulfur containing compounds, in addition
to CO 2 

### and small quantities of NOx. The two ma in strategies employed to limit sulfur
emissions from these units include increasi ng the capacity of the Claus unit to recover more sulfur and improving the efficiency of th e tail gas scrubber. These two strategies are discussed below, with several control options available to improve sulfur recovery and
reduce SO 2 

### emissions.

8.4.1 Increase Claus Unit Capacity

The amount of sulfur recovere d in a Claus unit varies base d on the number of catalytic stages of the Claus unit, feed composition, st oichiometric balance of gaseous components at the inlet, operating temper ature, and catalyst maintena nce. The conversion of H 2 

### S to elemental sulfur is limited by the equilibrium reaction of H 2 

### S with SO 2 

### , which only recovers 90 – 96% with a tw o-stage unit and 95 – 98% with a three-stage unit of the incoming sulfur. The NSPS regulations require limiting SO 2 

### emissions to 250 ppmv at 0%
O 2 

### , which is equivalent to 99.8 – 99.9% contro l level of reduce sulf ur 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 co st effective to increase the capacity of the sulfur recovery unit by applying oxygen enrich ment. Varying levels of oxygen enrichment are available depending on the desired cap acity 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 inje cting pure oxygen or oxyge n-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 orig inal design, through direct injection of oxygen through separate nozzl es into the furnace. This design calls for use of special burners designed to handle di rect 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 sec tion of the sulfur recovery unit. Three technologies exist which inco rporate high-level oxygen enrichment, the “SURE” Double Combustion process, the Lurgi process, and the COPE process. The “SURE” Double Combustion process divides th e combustion air into two stages with intermediate cooling of the combustion produc t, 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 Pr oducts, recycles cooled acid gas from theAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 8 – Sulfur Recovery Units Page 8-7

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### first sulfur condenser to the furnace. Oxygen enrichment has several advantages including reducing the gas volume sent to the tail ga s treatment system, k eeping the combustion temperatures high, shortening the gas reside nce time requirements, ensuring complete destruction of undesired heavy hydrocarbons an d ammonia, and reducing formation of the unwanted side products, COS and CS 2 

### , from the Claus reaction.

8.4.1.2 

### Selectox Catalyst
Use of the selectox catalyst was designed for systems with low H 2 

### S concentration acid gas streams (5 – 25 mole % H 2 

### S), and can handle acid gas concentrations up to 50 – 60 mole
% H 2 

### S. The selectox catalyst is used in th e first catalytic stage of the Claus sulfur recovery unit to promote selective oxidation of H 2 

### S to SO 2 

### without the use of a flame. The selectox catalyst also promotes the reaction between H2S and SO 2 

### to form elemental sulfur, recovering between 90 and 97%. Ov erall recovery is affected by the H2S concentration in the feed and the specific sulfur recovery process in place. Higher recovery efficiencies can be achie ved using a tail gas cleanup unit.

8.4.1.3 

### SUPERCLAUS®
The Superclaus sulfur recovery unit is simila r to the Claus unit. It contains a thermal stage, followed by three to four catalytic reaction stages. Th e first two or three catalytic reactors use the Claus catalyst, while the last reactor uses a select ive oxidation catalyst. The catalyst in the last reactor oxidizes th e H2S to sulfur at a very high efficiency, recovering 99% of the incoming sulfur. Th e use of this catalyst doesn’t allow the
oxidation of H 2 

### S to SO 2 

### , as occurs in the Claus reacti on. Using this process on rich H 2 

### S feed gas results in high sulfur reco very and reductions of current SO 2 

### emissions by 50 –
90%.

8.4.2 Tail Gas Treatment

Emissions of SO 2 

### 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 variati ons to treat the speci fic conditions of the exhaust from the sulfur recovery unit. The e xpected sulfur recovery of using any of these tail gas treatment t echnologies is 98 – 99.99%.

8.4.2.1 

### SCOT Tailgas Unit
The Shell Claus Off-gas Treating (SCOT) un it is one of the most common tail gas treatment systems and uses a hydrotreating r eactor 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 hydrot reating reactor to form H 2 

### S and water in the presence of aAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 8 – Sulfur Recovery Units Page 8-8

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### cobalt/molybdenum on alumina catalyst. The gas is then cooled in a water contactor and
enters an amine absorber wh ere it is contacted with a MD EA 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 H 2 

### S gas
stream is sent back to the Claus unit.

8.4.2.2 

### Sulfreen
The Sulfreen process is a catalytic tail gas pr ocess 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 Maxisu lf, HydroSulfreen, and DoxoSulfreen. The Maxisulf design incorporates a one-stage (includes only one ab sorber and one regenerator) Sulfreen unit with an open regeneration loop. Instead of recycling th e regeneration gas, it is fed together with the Claus tail gas to th e absorber. The Maxisulf can achieve sulfur recoveries up to 98.5%. The HydroSulfreen pr ocess includes an additional catalyst stage upstream of the Sulfreen unit. The additional stage uses an activated titanium oxide Claus catalyst to hydrolyze COS and CS 2 

### to increase sulfur recovery to 99.7%. The DoxoSulfreen process combines the HydroSulfr een process with a direct oxidation step. The goal of this process is to operate with an excess of H 2 

### S in the system to convert all the
SO 2 

### using the Sulfreen catalyst. The excess H 2 

### S leaving the Sulfreen unit is then oxidized in the final stage, recovering 99.9% of the in coming sulfur. A similar Sulfreen process known as Cold Bed Absorption (CBA) uses hot process steam from the first Claus reactor to regenerate the catalyst a nd 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 so lution to absorb the remaining H 2 

### S contained in the exhaust gas from the Claus sulfur recovery unit. The absorbed H 2 

### S is then oxidized to
form a mixture of elemental su lfur 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 SO 2 

### , COS, and CS 2 

### in the exhaust by first conve rting the Claus reaction sideproducts into H 2 

### S 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%.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 8 – Sulfur Recovery Units Page 8-9

MACTEC Federal Programs, Inc. 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 SO 2 

### to H 2 

### S, and then contacts the H 2 

### S with Stretford solution in a liquid-ga s absorber. The Stretford so lution 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 stepwi se with the sodium carbonate and ADA to produce elemental sulfur. Oxygen is then added to the solution to regenerate the reactants. The so lution is then sent to one or more froth/slurry tanks where the sulfur product is skimme d from the solution.

8.4.2.5 

### Clauspol
The Clauspol process treats the Claus unit’s ta il 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 H 2 

### S and SO 2 

### 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 effec tive 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 th at proceeds in three steps, using the traditional first or second Claus stage fo llowed by a select ive 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 H 2 

### S to SO 2 

### . The remaining inlet H 2 

### S is then reacted with the converted
SO 2 

### to produce elemental sulfur. The gases are then processed in a second converter where the remaining SO 2 

### is reduced to elemental sulfur through a reaction with H 2 

### and CO in the presence of a highly selective SO 2 

### reduction catalyst developed by Lawrence Berkeley National Laboratory. This reaction is equivalent to the equi librium 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 H 2 

### S is oxidized to form elementa l 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 utilizi ng the 3-stage PROClaus unit as depicted in Figure 4-4.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 8 – Sulfur Recovery Units Page 8-10

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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 fo r Claus Performance,” Sulfur Recovery Symposium , Canmore, Alberta.

8.4.2.7 

### LO-CAT ®



### LO-CAT is a liquid redox tail gas treatment sy stem 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 proprietar y Mobile Bed Absorber (MBA) where H 2 

### S and
SO 2 

### leaving the Claus system are absorbed into a circulating solution and the sulfide ions are converted to elemental sulfur in the pres ence of a chelated-iron catalyst. The solution leaving the MBA is then proce ssed 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 met hod first passes the tail gas from the Claus system through a hydrogenation/hydrolysis ca talytic reactor to convert all sulfur compounds to H 2 

### S. Figures 4-5a and 4-5b depict th e equipment layout for these two LOCAT systems.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 8 – Sulfur Recovery Units Page 8-11

MACTEC Federal Programs, Inc. 

### Figure 8-5a. Direct LO-CAT Tail Gas System

SOURCE: Nagl, G.J., 2001, “Liquid Re dox Enhances Claus Process,” Sulfur , Vol. May-June, No. 274.



### Figure 8-5b. Indirect LO-CAT Tail Gas System

SOURCE: Nagl, G.J., 2001, “Liquid Re dox Enhances Claus Process,” Sulfur , Vol. May-June, No. 274.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 8 – Sulfur Recovery Units Page 8-12

MACTEC Federal Programs, Inc. 8.4.2.8 

### FLEXSORB ®



### A number of FLEXSORB solvents were developed by the ExxonMobil Research and Engineering Co. as alternatives to the tradit ional 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 so lvents are designed to provide the following
characteristics: the SE solven t is designed to provide high H 2 

### S selectivity in the presence
of CO 2 

### , the SE Plus solvent improves H 2 

### S selectivity by enhancing the solvent’s ability to regenerate, the SE hybrid solvent is used for H 2 

### S and organic sulfur removal, and the PS solvent is designed to remove all CO 2 

### , H 2 

### S and organic sulfur compounds from exhaust gases. The SE and SE Plus so lvents are best for selective H 2 

### S removal from refinery tail gas treatment systems. In one refinery app lication, 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 Stre tford tail gas unit providing an nual 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 th an 99.9%, selective chemical absorption is necessary to remove any remaining H 2 

### S and recycle it to the Claus feed gas. Lurgi OelGas-Chemie (Lurgi) has designed a few of thes e systems, which increase sulfur recovery and reduce exhaust gas H 2 

### S levels prior to incineration. One such design is an Emissionfree sulfur recovery unit. This process firs t cools the process gases leaving the Claus unit which results in hydrolyzing sulfur compounds to H 2 

### S and the precipitation of elemental sulfur. The gas stream goes thr ough an absorber stage where the H 2 

### S in the stream is reduced to less than 10 ppm, and then recycl ed to the combustion chamber, where it is
oxidized. Since the H 2 

### S is recycled and converted to other compounds with in the system, the system is considered a flue gas-free proc ess. 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 inst alling 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 a nd reduction tail gas scrubbers. The WellmanLord Scrubber is an oxidation tail gas sc rubber. The scrubber uses a wet generativeAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 8 – Sulfur Recovery Units Page 8-13

MACTEC Federal Programs, Inc. 

### Figure 8-5. Lurgi Emission Free Sulfur Recovery Unit

SOURCE: Lurgi Oel-Gas-Chemie Gm bH, “Lurgi Sulfur Management,” www.lurgi.de/deutsch/nbsp/main/infoma terial/lurgi_sulf ur_management.pdf



### process to reduce SO 2 

### concentrations in the flue gas to levels below 250 ppmv. In the Wellman-Lord process, the tail gas is inci nerated to oxidize all sulfur species to SO 2 

### . The
concentrated SO 2 

### stream is then reacted with a solution of sodium sulfite (Na 2 

### SO 3 

### ) forming sodium bisulfite (Na 2 

### HSO 3 

### ). 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 SO 2 

### is released with water. The crystallized sodium sulfite is
reused in the scrubber while the SO 2 

### is recycled back to the Claus unit for further
conversion to elemental sulfur.

In reduction tail gas scru bbers, sulfur in the tail gas is converted to H 2 

### S by hydrogenation, and then the tail gas is cooled and sent to a scrubber to remove the H 2 

### S. The removed H2S can be recycled back to the Claus unit for furthe r sulfur removal. In addition to scrubbers, incinerators can be employed to destroy sulf ur containing compounds, with the side-effect of emitting SO 2 

### . In order to effectively reduce su lfur compounds, incinerators must operate at temperatures of 1,200 o 

### F or higher. Incinerator stacks should have proper monitoring in place to measure SO 2 

### emission levels.

8.5 COSTS AND AVAILABILITY
Numerous technologies are availa ble for controlling sulfur emi ssions from sulfur recovery units at petroleum refineries. Table 8-5 summarizes the rele vant information about these control techniques. More detailed informa tion on each technology was summarized in the previous sections and based on the information contained in the references for this Section.Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 8 – Sulfur Recovery Units Page 8-14

MACTEC Federal Programs, Inc. 

### The cost data presented in the Table were obtained from the published literature as referenced. In general, the percent reductions and cost effectiveness da ta represent data for
uncontrolled sources. Incremental reductions w ill 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-s pecific factors greatly influence the actual achievable performance level and control co sts at a particular facility. These
considerations must be addressed in State a nd local rulemaking and pe rmitting processes.Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Section 8 – Sulfur Recovery Units Page 8-15MACTEC Federal Programs, Inc.Table 8-5: Control Technology Summary for Sulfur Recovery UnitsPollutant TechnologyOrigin ofRequirementPercentReductionPerformance LevelCostEffectiveness($/ton)CommerciallyAvailable?ReferenceSO2VariousTechnologiesdescribed inSection 8.4ConsentDecree/NSPS/NESHAP97 to 99.9NSPS: For units with an oxidation or reductioncontrol system followed by incineration, SO2emissions are limited to 250 ppmvd at 0% O2.For units with a reduction control system notfollowed by incineration, emissions of reducedsulfur compounds are limited to 300 ppmvd at0% O2and emissions of H2S are limited to 10ppmvd at 0% O2, each calculated as SO2.MACT: for units not subject to NSPS,emission limit specified under NSPS or a totalreduced sulfur (TRS) limit of 300 ppmvd at0% O2167 to 449 YesECIPPC,2003Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Section 8 – Sulfur Recovery Units Page 8-16

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### 8.6 REFERENCES
European Commission, Integrated Pollu tion Prevention & Control (ECIPPC), 2003,
“Reference Document on Best Availabl e Techniques for Mineral Oil and Gas
Refineries.”

Fedich, R.B., A.C. Woerner, and G.K. Chitnis, 2004, “Selective H 2 

### S 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/ info material/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 Enha nces Claus Process,” Sulfur , Vol. May-June, No.
274.

Parsons E&C., “Sulfur Technology,” www.worleyparsons.com/v5/download.asp x?file=Sulfur Qualification.pdf

. Praxair Technology, Inc., 1994, “Increase Cl aus 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, “PRO Claus: The New Standard for Claus Performance,” Sulfur Recovery Symposium , Canmore, Alberta.

United States Environmental Protection Ag ency, 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/chie f/ap42/ch08/final/c08s13.pdf

.


### United States Environmental Protection Agency, 1996, Study of Selected Petroleum Refining Residuals: Industry Study,” O ffice of Solid Waste, Hazardous Waste
Identification Divisi on, Washington, DCAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Appendix A – Emission Estimat ion Methodology Page A- 1

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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 St ates have established Consent Decrees with most of the refineries in the MARAMA region to reduce their air pollu tion 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 nonatta inment areas. This Appendix describes how the provisions of the Consent Decrees pr ovisions 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 Technica l 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 invent ories 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 Implemen tation Plans for attaining the 8-hour ozone
standard. The 2002 inventories are based almo st exclusively on data submitted by industry to fulfill their Emission Statement reporting ob ligations. We recognize that there are yearto-year variations in emissions (due to variations in capaci ty utilization, av ailability 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 inventorie s (2003-2006) during their rulemaking process.

We also recognize that, for some refinery processes, that ther e is considerable uncertainty in the baseline emission estimates. For example, the methods used to calculate flaring
emissions are not consistent across the industr y, resulting in a wide variations in the emissions reported at each refinery. Recent studies in Texas and California suggest theAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Appendix A – Emission Estimat ion Methodology Page A- 2

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### emissions from flaring activities at refineries may be significantly underestimated. Also, the various mass emission estimating me thodologies 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 An alysis 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 factor s was to first use the state-supplied projection data (if available). If no st ate-supplied data are availabl e, 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 m odel 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 repres ent 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 pa rticular 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 constrainedAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Appendix A – Emission Estimat ion Methodology Page A- 3

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### by existing permit limits and would have to unde rgo NSR review to increase capacity. In cases where existing permit limits constrained em issions at large sources; we attempted to
take into account those constrai nts. However, it was not feas ible (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 re duction based upon the settlements and recent permits that implement the provisions of thos e 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 cont ained in the global enforcement settlements. The specific timing and extent of emission reductions resulting from the Consent Decrees are evolving ove r time as the specific implementation requirements and schedules are being develope d. Thus, there remains some uncertainty regarding the time and extent of emission redu ctions associated with the Consent Decrees.

FLUID CATALYTIC CRACKING UNITS

For FCCUs/FCUs, the control requirements gene rally 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, specifi c 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 speci fied 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 C onsent Decree, MACTEC assumed that the Model Rule would require a wet gas scrubber (or e quivalent) that would result in a 90 percent reduction of SO2 em issions. Table A-1 shows the unit-by-unit emission reductions anticipated after impleme ntation of the Consent Decrees and Model
Rule.

For NOx control, the Consent Decrees requi re selective catalytic reduction (SCR), selective non-catalytic reduc tion (SCNR), or optimizati on 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 speci fied 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 un its not affected by a Consent Decree, MACTEC assumed thatAssessment of Control Technology Options for Petroleum Refineries January 31, 2007 Appendix A – Emission Estimat ion Methodology Page A- 4

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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 cal culated by comparing the unit’s permitted emission limitation (in lbs/1000 lbs co ke burned) or limitation contained in the
Consent Decree to the model rule emission lim itation (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 show s the unit-by-unit emission reductions anticipated after implementation of th e Consent Decrees and Model Rule.

For CO control, reductions from the model rule were cal culated by comparing the unit’s emission limitation (in ppm) to the mode l rule emission limitation (200 ppm hourly average). If the unit’s current limit is be low 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.Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Appendix A – Emission Estimation Methodology Page A-5MACTEC Federal Programs, Inc.Table A-1 Emission Reductions from Consent Decrees and Model Rules: SO2 Emissions from Catalytic Cracking UnitsSO2 Emissions (tons/year)State Refinery 20022009withCDs2009WithModelRulesModelRuleReductionsEmission Calculation AssumptionsDE Premcor FCCU 11,421 361 361 0 Permit APC-81/0981 limit with Wet Gas ScrubberDE Premcor FCU 19,461 174 174 0 Permit APC-81/0829 limit with Wet Gas ScrubberNJ Sunoco Eagle Point 91 5 5 0 CD specifies Wet Gas Scrubber Upgrade; assume 90% reductionNJ Valero 3,597 172 172 0 Permitted emission limit after installation of BELCO scrubberNJ Amerada Hess 71 81 8 73 Not affected by a CD; assume 90% reduction from Wet Gas ScrubberNJ ConocoPhillips/Bayway 65 75 75 0 Existing WetGas Scrubber in 2002; noadditional reductionsPA Sunoco Marcus Hook 4,374 824 824 0 CD specifies Wet Gas Scrubber; assume 80% reductionPA ConocoPhillips Trainer 2,063 166 166 0 CD specifies Wet Gas Scrubber; new permit limit is 165.8 tons per yearPA Sunoco Phila. GP 1232 2,378 363 363 0 Permit limit with Wet Gas Scrubber required by CDPA Sunoco Phila. PB 868 475 600 120 480 Not affected by CD, assume 80 percent reduction from Wet Gas ScrubberPA United Refining 1,091 1,245 125 1,121 Not affectedby a CD; assume 90% reduction from Wet Gas ScrubberVA Giant Yorktown 477 106 106 0 CD specifies Wet Gas Scrubber; assume 80% reductionMARAMA Region 47,566 4,172 2,499 1,673Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Appendix A – Emission Estimation Methodology Page A-6MACTEC Federal Programs, Inc.Table A-2 Emission Reductions from Consent Decrees and Model Rules: NOx Emissions from Catalytic Cracking UnitsNOx Emissions (tons/year)State Refinery 20022009withCDs2009WithModelRulesModelRuleReductionsEmission Calculation AssumptionsDE Premcor FCCU 739 411 411 0 2009 emissions estimated by DNRECDE Premcor FCU 624 690 690 0 Permit APC-81/0829 limit based on Consent DecreeNJ Sunoco Eagle Point 103 47 47 0 CD specifies NOx study; assume 60% controlNJ Valero 106 121 121 0 CD requires optimization study of existing control system; no additionalreductions assumedNJ Amerada Hess 359 409 164 245 Not affected by aCD; assume 60% reduction from SNCR-type controlsNJ ConocoPhillips/Bayway 1,036 475 475 0 CD specifies enhanced SNCR; assume 60% control;PA Sunoco Marcus Hook 1,489 184 184 0 CD specifies SCR; assume 90% controlPA ConocoPhillips Trainer 537 245 245 0 CD specifies enhanced SNCR; assume 60% control;PA Sunoco Phila. GP 1232 356 208 208 0 Permit limit with SCR required by CDPA Sunoco Phila. PB 868 182 482 193 289 Not affectedby CD; assume 60% reduction from NOx controlPA United Refining 29 33 13 20 Not affected by aCD; assume 60% reduction from SNCR-type controlsVA Giant Yorktown 210 233 93 140 Nothing specified inCD; assume 60% reduction from SNCR-type controlsMARAMA Region 5,770 3,538 2,844 694Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Appendix A – Emission Estimation Methodology Page A-7MACTEC Federal Programs, Inc.Table A-3 Emission Reductions from Consent Decrees and Model Rules: PM Emissions fromCatalytic Cracking UnitsPM Emissions (tons/year)State Refinery 2002x2009withCDs2009WithModelRulesModelRuleReductionsEmission Calculation AssumptionsDE Premcor FCCU 765 390 390 0 No limit specified in permit; no reductions assumedDE Premcor FCU 496 334 167 167 Current limit is 1 lb/1000lbs coke; model rule limit is 0.5 lbs/1000 coke;assume 50% reduction from model ruleNJ Sunoco Eagle Point 69 35 35 0 CD required 0.5 lbs/1000 lbs coke; assume 50 % reduction from CDNJ Valero 71 82 82 0 No limit specified in permit; no reductions assumedNJ Amerada Hess 44 50 50 0 No limit specified in permit; no reductions assumedNJ ConocoPhillips/Bayway 128 128 128 0 Existing permitlimit is equivalent to 0.5 lbs/1000 lbs cokePA Sunoco Marcus Hook 209 105 105 0 CD required 0.5 lbs/1000 lbs coke; assume 50 % reduction from CDPA ConocoPhillips Trainer 113 93 93 0 Permit limitPA Sunoco Phila. GP 1232 42 170 170 0 Permit limit, CD required 0.5 lbs/1000 lbs cokePA Sunoco Phila. PB 868 70 95 48 47 Not affected by CD; current limit is 1 lb/1000 lbs coke; model rule limit is0.5 lbs/1000 lbs coke; assume50% reduction from model rulePA United Refining 43 49 25 25 Current limit is 1 lb/1000 lbs coke; model rule limit is 0.5 lbs/1000 lbscoke; assume 50% reduction from model ruleVA Giant Yorktown 428 53 26.5 26.5 Current limit is 1 lb/1000 lbs coke; model rule limit is 0.5 lbs/1000 lbscoke; assume 50% reduction from model ruleMARAMA Region 2478 1548 1283.5 265.5This table shows reductions of total suspended particulate emissions; reductions in PM2.5 are not available.Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Appendix A – Emission Estimation Methodology Page A-8MACTEC Federal Programs, Inc.Table A-4 Emission Reductions from Consent Decrees and Model Rules: CO Emissions fromCatalytic Cracking UnitsCO Emissions (tons/year)State Refinery 20022009withCDs2009WithModelRulesModelRuleReductionsEmission Calculation AssumptionsDE Premcor FCCU 1,524 1,640 656 984 No ppm limit specified in permit; assume 60% reductionDE Premcor FCU 1,209 1,291 516 775 Current limit is500 ppm; model rule limit is 200 ppm; assume 60%reductionNJ Sunoco Eagle Point 83 95 95 0 Current limit is 127 ppm; no additional reductionssince current limit islower than Model Rule limitNJ Valero 53 61 61 0 Current limit is 50 ppm; noadditional reductions since current limit islower than Model Rule limitNJ Amerada Hess 130 148 99 49 Current limit is 300ppm; model rule limit is 200 ppm; assume 33%reductionNJ ConocoPhillips/Bayway 99 113 113 0 Current limit is 200ppm; no additional reductionssince current limit islower than Model Rule limitPA Sunoco Marcus Hook 514 484 194 290 Current limit is 500 ppm; model rulelimit is 200 ppm; assume 60%reductionPA ConocoPhillips Trainer 60 69 28 41 Current limit is500 ppm; model rule limit is 200 ppm; assume 60%reductionPA Sunoco Phila. GP 1232 514 634 254 380 Current limit is 500ppm (1-hr avg) 100 ppmvd (365-day rolling avg.);model rule limit is 200ppm; assume 60% reductionPA Sunoco Phila. PB 868 52 100 40 60 Current limit is 500ppm (1-hr avg) 100 ppmvd (365-day rolling avg.);model rule limit is 200ppm; assume 60% reductionPA United Refining 43 49 20 29 Current limit is 500ppm; model rule limit is 200 ppm; assume 60%reductionVA Giant Yorktown 140 140 56 84 Current limit is 500ppm; model rule limit is 200 ppm; assume 60%reductionMARAMA Region 4,421 4,824 2,130 2,694Assessment of Control Technology Options for Petroleum Refineries January 31, 2007 Appendix A – Emission Estimat ion Methodology Page A- 9

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### EQUIPMENT LEAKS

Substantial emission reductions are achi evable 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 emi ssions as a result of implementing enhanced LDAR programs simila r to those required in the recent Consent
Decrees and the MARAMA model rule.

Several of the refineries in the MARAMA re gion already have leak definitions that are more stringent than the NSPS for some pro cess units. Thus, the emission reductions expected from lower leak definitions will vary by refinery due to the differences in the
current leak definitions. Resource constraint s did not allow us to make emission reduction estimates on a process unit by process unit ba sis. We recommend that State’s further evaluate the refinery-specific baseline emi ssions, 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 emi ssions could be much higher th an currently estimated. The MARAMA States should monitor on-going a nd 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 Environm ental 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, a nd PM10) will also be reduced by 53%. A
similar reduction in SO2 emissions is antic ipated. Since the MA RAMA model rule is similar to SCAQMD Rule 1118, similar re ductions would be expected from implementation of the MARAMA model rule.

It should be noted that both the baseline em issions from flares, as well as the estimated emission reductions, are highly unc ertain. On-going research a nd field studies suggest that emissions could be much higher than curren tly estimated. The MARAMA States should monitor on-going and imminent national and st ate studies to better quantify baseline emissions and potential emission reductions.Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Appendix A – Emission Estimation Methodology Page A-10MACTEC Federal Programs, Inc.Table A-5 Emission Reductions from Consent Decrees and Model Rules: VOC Emissions from Equipment LeaksVOC Emissions (tons/year)State Refinery 20022009withCDs2009WithModelRulesModelRuleReductionsEmission Calculation AssumptionsDE Premcor 64 32 32 0 Enhanced LDAR in CD; assume 50% controlNJ Sunoco Eagle Point 42 21 21 0 Enhanced LDAR in CD; assume 50% controlNJ Valero 66 33 33 0 Enhanced LDAR in CD; assume 50% controlNJ CITGO Asphalt 10 5 5 0 Enhanced LDAR in CD; assume 50% controlNJ Amerada Hess 14 14 7 7 No CD; assume Model Rule's enhanced LDAR requirements achieve a50% reductionNJ Chevron 9.5 9.5 4.7 4.8 No CD; assume Model Rule's enhanced LDAR requirements achieve a50% reductionNJ ConocoPhillips/Bayway 233 117 117 0 Enhanced LDAR in CD; assume 50% controlPA Sunoco Marcus Hook 130 65 65 0 EnhancedLDAR in CD; assume 50% controlPA ConocoPhillips Trainer 63 32 32 0 Enhanced LDAR in CD; assume 50% controlPA American Refining 130 130 65 65 No CD; assume Model Rule's enhanced LDAR requirements achieve a50% reductionPA Sunoco Philadelphia 176 88 88 0 Enhanced LDAR in CD; assume 50% controlPA United Refining 167 167 84 84 No CD; assume ModelRule's enhanced LDAR requirements achieve a50% reductionVA Giant Yorktown 310 155 155 0 Enhanced LDAR in CD; assume 50% controlWV Ergon Newell 45 23 23 0 Enhanced LDAR in CD; assume 50% controlMARAMA Region 1,459 889 729 160ConocoPhillips Bayway initially estimated a VOC emissions of 1,629tons/year from equipment leaks using the "leak/no leak" method and AP-42 emissionfactors consistent with the federal leak definition of 10,000 ppm. Emissions were recalculated using actual leak data and EPAcorrelation equations LeakDassoftware, resulting in a downward revision to 233 tons/year.Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Appendix A – Emission Estimation Methodology Page A-11MACTEC Federal Programs, Inc.Table A-6 Emission Reductions from Consent Decreesand Model Rules: SO2 Emissions from FlaresSO2 Emissions (tons/year)State Refinery 20022009withCDs2009WithModelRulesModelRuleReductionsEmission Calculation AssumptionsDE Premcor 238 238 112 126 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleNJ Sunoco Eagle Point 21 21 10 11 SCAQMD estimated53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleNJ Valero 82 82 38 43 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleNJ CITGO Asphalt 0 0 0 0 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleNJ Amerada Hess 1 1 1 1 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleNJ Chevron 7 7 3 4 SCAQMD estimated 53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleNJ ConocoPhillips/Bayway 222 222 104 118 SCAQMD estimated53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model rulePA Sunoco Marcus Hook 10 10 5 5 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model rulePA ConocoPhillips Trainer 15 15 7 8 SCAQMD estimated53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model rulePA American Refining 21 21 10 11 SCAQMD estimated53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model rulePA Sunoco Philadelphia 33 33 15 17 SCAQMD estimated53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model rulePA United Refining 1 1 0 0 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleVA Giant Yorktown 984 2 2 2 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleWV Ergon Newell 85 85 40 45 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleMARAMA Region 1,719 737 347 391Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Appendix A – Emission Estimation Methodology Page A-12MACTEC Federal Programs, Inc.Table A-7 Emission Reductions from Consent Decreesand Model Rules: NOx Emissions from FlaresNOx Emissions (tons/year)State Refinery 20022009withCDs2009WithModelRulesModelRuleReductionsEmission Calculation AssumptionsDE Premcor 25 25 12 13 SCAQMD estimated 53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleNJ Sunoco Eagle Point 78 78 37 42 SCAQMD estimated53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleNJ Valero 40 40 19 21 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleNJ CITGO Asphalt 1 1 0 0 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleNJ Amerada Hess 2 2 1 1 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleNJ Chevron 0 0 0 0 SCAQMD estimated 53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleNJ ConocoPhillips/Bayway 12 12 6 7 SCAQMD estimated53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model rulePA Sunoco Marcus Hook 2 2 1 1 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model rulePA ConocoPhillips Trainer 44 44 20 23 SCAQMD estimated53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model rulePA American Refining 15 15 7 8 SCAQMD estimated53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model rulePA Sunoco Philadelphia 11 11 5 6 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model rulePA United Refining 13 13 6 7 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleVA Giant Yorktown 1,043 24 11 11 SCAQMD estimated53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleWV Ergon Newell 60 60 28 32 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleMARAMA Region 1,345 326 153 173Assessment of Control Technology Optionsfor Petroleum Refineries January 31, 2007Appendix A – Emission Estimation Methodology Page A-13MACTEC Federal Programs, Inc.Table A-8 Emission Reductions from Consent Decreesand Model Rules: VOC Emissions from FlaresVOC Emissions (tons/year)State Refinery 20022009withCDs2009WithModelRulesModelRuleReductions Emission Calculation AssumptionsDE Premcor 7 7 3 4 SCAQMD estimated 53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleNJ Sunoco Eagle Point 484 484 228 257 SCAQMD estimated53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleNJ Valero 0 0 0 0NJ CITGO Asphalt 0 0 0 0NJ Amerada Hess 4 4 2 2 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleNJ Chevron 1 1 0 0 SCAQMD estimated 53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleNJ ConocoPhillips/Bayway 25 25 12 13 SCAQMD estimated53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model rulePA Sunoco Marcus Hook 4 4 2 2 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model rulePA ConocoPhillips Trainer 90 90 42 48 SCAQMD estimated53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model rulePA American Refining 1 1 1 1 SCAQMD estimated53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model rulePA Sunoco Philadelphia 35 35 17 19 SCAQMD estimated53% reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model rulePA United Refining 12 12 5 6 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleVA Giant Yorktown 50 50 23 26 SCAQMD estimated 53%reduction in vent gases from recent Rule 1118amendments; similar reductions for MARAMA model ruleWV Ergon Newell 0 0 0 0MARAMA Region 713 713 335 378