January 10, 2007
Mr. Edward Wiener Environmental Engineer Source Registration Air Management Services 321 University Avenue Philadelphia, PA 19104 Re: BART Analysis Report Sunoco Chemicals, Frankford Plant Dear Mr. Wiener: 

# 0
2001 

### JAU 16 

### PH 

### 4: 16 Sunoco, Inc. Margaret & Bermuda Streets Philadelphia PA 19137-1193 215 533 3000

On June 9 of this year the Philadelphia Air Management Services (AMS) issued a letter explaining our options under the Best Available Retrofit Technology (BART) requirements. Enclosed is the BART engineering analysis report of control options. One of the factors included in this assessment is the cost of compliance for additional emission control technologies for Boiler 3. The cost factors developed in this report developed capital costs that were based on similar projects either recently completed or currently under construction at other Sunoco facilities. These costs were adjusted based on capacity differences to apply to the scale of the application at the Frankford plant. These costs are for screening purposes and do not include costs associated with limited boiler house space and other site specific design constraints. When considering the potential visibility improvements of additional controls based on the dispersion modeling along with the cost effectiveness, the analysis demonstrates that controls will not significantly contribute to a measurable degree in improved visibility. Sunoco therefore believes that current controls for all BART-eligible sources meet BART requirements and no additional controls are required. If you have any questions, please contact Paul Persing at (215) 807-8442.

# Sinc7~~**~({/** tr C- • 

### i3
. Christopher Bland Deleware Valley HES Manger Cc; Nancy Herb (PaDEP-Harrisburg)

# •

•

• R[PORT

Sunoco Inc. 

# Best Available Retrofit Technology (BART) Analysis 

# Frankford Facility
January 2007

Environmental Resources Management 350 Eagleview Blvd., Suite 200

Exton, Pennsylvania 19341

# •

•

• EXECUTIVE SUMMARY 1.0

2.0 INTRODUCTION AND BACKGROUND 1.1 DESCRIPTION OF BART RULE 1.2 BART APPLICABILITY TO SUNOCO FRANKFORD FACILITY 1.3 DESCRIPTION OF BART-ELIGIBLE SOURCES DETAILED BART ANALYSIS 2.1 SOURCES CONSIDERED FOR AVAILABLE RETROFIT CONTROL TECHNOLOGIES 1 2 3 3 5
5 3.0 AVAILABLE RETROFIT CONTROL TECHNOLOGIES FOR BOILER (BL-703) 6 3.1 NOx CONTROLS 

### 3.1.1 Water/Steam Injection 3.1.2 

### Flue Gas Recirculation (FGR) 3.1.3 

### 3.1.4 3.1.5 3.1.6 

### 3.1.7 Staged Combustion Air (SCA) Ultra Low-NOx Burners (ULNB) Selective Non-Catalytic Reduction (SNCR) Selective Catalytic Reduction (SCR)

Ultra Low-NOx Burners and FGR 3.2 ELIMINATE TECHNICALLY INFEASIBLE OPTIONS 3.3 EVALUATE CONTROL EFFECTIVENESS OF REMAINING CONTROL 6 7 7 7 8 8 9 

### 10 10
TECHNOLOGIES 10 3.4 EVALUATE IMPACTS AND DOCUMENT RESULTS 

### 3.4.1 Evaluate Visibility Impacts 3.4.2 

### Modeling Approach 3.5 SOz CONTROLS 3.5.1 

### Wet Scrubbing 3.5.2 

### Fuel Specification 3.5.3 

### Evaluate Impacts and Document Results 3.6 PM;o CONTROLS 3.6.1 

### Good Combustion Practice 3.6.2 

### Wet Scrubbing 3.6.3 

### Cyclone

ERM 12 14 14 

### 15 17 17 17 21 21 

### 21 21

SUNOCO FRANKFORD/0055833/01-09-07

# •

••

• 3.6.4 3.6.5 3.6.6 

### Dry/Wet Electrostatic Precipitation Fabric Filtration/Baghouse Evaluate Impacts and Document Results 3.7 VOC CONTROLS 

### 3. 

### 7.1 Good Combustion Practice 3. 7.2 

### Catalytic Oxidizer 3.7.3 

### Evaluate Impacts and Document Results 4.0 EMERGENCY GENERATORS 

### 21 21 22 

### 22 22 

### 25 25 

### 26 4.1 AVAILABLE RETROFIT CONTROL TECHNOLOGIES FOR EMERGENCY GENERATORS 

### 26 5.0 DISTILLATION COLUMNS 27 5.1 AVAILABLE RETROFIT CONTROL TECHNOLOGIES FOR DISTILLATION COLUMNS 27 6.0 OXIDATION PROCESS 28 6.1 AVAILABLE RETROFIT CONTROL TECHNOLOGIES FOR OXIDATION PROCESS 28 7.0 REACTORS 29 7.1 AVAILABLE RETROFIT CONTROL TECHNOLOGIES FOR REACTORS 29 8.0 BULK LOADING FACILITIES 30 8.1 AVAILABLE RETROFIT CONTROL TECHNOLOGIES FOR BULK LOADING FACILITIES 30 9.0 TANKS/VESSELS 31 9.1 AVAILABLE RETROFIT CONTROL TECHNOLOGIES FOR TANKS/VESSELS 31 10.0 COOLING TOWERS 32 10.1 AVAILABLE RETROFIT CONTROL TECHNOLOGIES FOR COOLING TOWERS 32 11.0 CONCLUSIONS 33

ERM 11 SUNOCO FRANKFORD/0055833/01-09-07

# •

•

• 12.0 REFERENCES

LIST OF APPENDICES APPENDIX A APPENDIXB
APPENDIXC

LIST OF TABLES SUMMARY OF RBLC SEARCHES COST-EFFECTIVENESS SUPPORTING DOCUMENTATION 34

BART LEITER FROM PHILADELPHIA AIR MANAGEMENT SERVICES (AMS)

TABLE 1-1 SUMMARY OF BART-ELIGIBLE SOURCES AT SUNOCO FRANKFORD FACILITY TABLE 3-1 SUMMARY OF COST EFFECTIVENESS FOR NOxCONTROLS ON BOILER (BL-703) AT SUNOCO FRANKFORD FACILITY TABLE 3-2 SUMMARY OF COST FOR VISIBILITY IMPROVEMENT FOR NOx CONTROLS ON BOILER AT SUNOCO FRANKFORD FACILITY TABLE 3-3 SUMMARY OF COST EFFECTIVENESS FOR S02 CONTROLS ON BOILER (BL-703) AT SUNOCO FRANKFORD FACILITY TABLE 3-4 SUMMARY OF COST FOR VISIBILITY IMPROVEMENT FOR S02 CONTROLS ON BOILER AT SUNOCO FRANKFORD FACILITY TABLE 3-5 SUMMARY OF COST EFFECTIVENESS FOR PM CONTROLS ON BOILER (BL-703) AT SUNOCO FRANKFORD FACILITY TABLE 3-6 SUMMARY OF COST FOR VISIBILITY IMPROVEMENT FOR PM CONTROLS ON BOILER AT SUNOCO FRANKFORD FACILITY

ERM 111 SUNCX:O FRANKFORD /0055833/iH -09-07

# •

•

• EXECUTIVE SUMMARY

ERM Sunoco Chemicals Frankford facility conducted a BART analysis as requested by the Philadelphia Air Management Services (AMS). The BART analysis was conducted in accordance with BART guidelines issued by the EPA, a letter issued by AMS in June 2006 and a subsequent letter dated November 2006 (Appendix C). The BART analysis addresses the five statutory factors required by the Clean Air Act (CAA). These factors are: the costs of compliance; the energy and non-air quality environmental impacts of compliance; any existing pollution control technology in use at the source; the remaining useful life of the source; and the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology. These factors were considered in preparing the BART analysis. Since Sunoco has no plans in the foreseeable future to retire or shutdown any BART-eligible sources at the facility, the remaining useful life of the equipment factor was not considered in the cost effectiveness analysis. For BART-eligible Boiler BL-703, additional controls were evaluated for cost effectiveness and visibility improvements. The visibility analysis was performed using the CALPUFF dispersion model 

### to determine visibility impacts on the applicable Class I Area (Brigantine National Wildlife Refuge). The Federal Rule 40 CFR Part 51 set threshold levels for both II contributing to" and II causing" visibility impairment at 0.5 and 1.0 deciviews, respectively. The modeling analysis yielded results significantly below both of the federal criteria. Furthermore, the modeling analysis demonstrated that additional addon controls such as ULNB /FGR, SCR, wet gas scrubber, or a baghouse will not significantly contribute to a measurable degree in improvement in visibility. The table below summarizes the visibility benefit and the cost of improving visibility for controls which were evaluated in this analysis
.

SUNOCO FRANKFORD/0055833/01-09-07

# •

•

ERM Control Technology Visibility Benefit Cost for Visibility (delta dv) Improvement ($/dv) SCR 0.0760 67,480,093 ULNB+FGR 0.0625 38,139,097 Wet Scrubber 0.0301 29,439,689

·Baghouse 0.0144 44,506,519

Given the degree improvement expected and the cost of compliance, additional add-on controls for the boiler are not viable or necessary. For BART -eligible sources such as emergency generators, the BART analysis determined that no additional controls are needed beyond existing controls. In accordance with the AMS letter from November 2006, Sunoco is not required to address potential control measures for sources that only emit VOC. Nevertheless, the BART-eligible VOC sources at Sunoco are regulated and controlled in accordance with the latest applicable requirements, for example, tanks are equipped with internal floating roofs. Therefore, these sources meet BART requirements and do not warrant additional controls. In conclusion, Sunoco believes the current controls for all BARTeligible sources at the Frankford facility meet BART requirements. Therefore, no additional controls are required under BART.

SUNOCO FRANKFORD/0055833/01-09-o?

### 1.0 

# •

•

• INTRODUCTION AND BACKGROUND

ERM The Sunoco Chemicals Frankford facility (Sunoco) operates a chemical manufacturing facility in Philadelphia, P A. Sunoco is a chemical processing plant primarily involved in the production of phenols, acetone, and alpha-methylstyrene, which are chemical intermediates from the refinery process. In June of 2006, the Philadelphia Air Management Services (AMS) notified Sunoco that certain units are subject to the Best Available Retrofit Technology (BART) requirements of the federal regional haze program. As requested by the AMS, Sunoco is required to submit a case-by-case BART proposal for each BART-eligible unit at the facility that emits a visibility impairing pollutant by January 10, 2007. This report fulfills the submittal requirement and the following sections contain the required analyses and documentation necessary to support Sunoco's BART proposal. The Sunoco facility is subject to a number of regulations which restrict the emissions of Volatile Organic Compounds (VOC) from Synthetic Organic Chemical Manufacturing Industry (SOCMI) facilities. These regulations include New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP). These regulations are applicable to a number of processes including distillation columns, reactors, tanks/vessels, etc. In particular, Sunoco complies with the requirements of 40 CPR, Part 63, Subpart G (§ 63.150) using the emission averaging provision in the rule. This provision establishes a facility-wide emission limit for all process vents, storage tanks, transfer racks, and wastewater streams rather than a source-specific emission limit. The emission reductions achieved by complying with the MACT rule are at least as stringent, if not more, than those required by the BART rule. The BART rule exempts additional controls for sources which are subject to the requirements of MACT rules as stated in the guidelines: "
... the states are unlikely to find controls more stringent than the MACT standards without identifying control options that would cost many thousands of dollars more per ton." The Frankford facility believes that the existing emission controls either meet or exceed the requirements of the BART rule for VOC sources. The following is the analysis that supports this conclusion
.

1 SUNOCO FRANKFORD/0055833/01-09-07

### 1.1



# •

•

• DESCRIPTION OF BART RULE

ERM On July 1, 1999 (40 CFR Part 51), EPA published the Regional Haze Rule which provides the regulations to improve visibility in 156 national parks, wilderness areas, and international parks which were in existence in 1977. One of the key elements of the Regional Haze rule addresses the installation of Best Available Control Technology (BACT) for certain source categories that were built and in operation between 1962 and 1977. BART is defined as "an emissions limitation based on the degree of reduction achievable through the application of the best system of continuous emission reduction for each pollutant which is emitted by a BART eligible source. The emissions limitation must be established on a case-by-case basis, taking into consideration the technology available, the cost of compliance, the energy and nonair quality environmental impacts of compliance, any pollution control equipment in use or in existence at the source, the remaining useful life of the source, and the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology". BART, also referred to as the "Clean Air Visibility Rule" (CA VR), requires states to identify "BART -eligible" sources. Sources need to meet all three criteria to be considered a "BART-eligible" source:
1. The source should belong to one of the 26listed source categories; these categories are same as those for Prevention of Significant Deterioration (PSD) applicability analysis; 2. The source should have been installed (constructed) and in operation between 1962 and 1977; and 3. The source should emit more than 250 tons per year of any one or all of the visibility impairing pollutants including sulfur dioxide (SOz), nitrogen oxide (NOz), or particulate matter (PM10). Volatile organic compounds (VOC) and ammonia (NH3) may be included depending on the state in which the source is located. Please note AMS considers VOC as visibility impairing pollutant thus VOC is included in the BART eligibility determination. The following section identified the BART eligible sources at Sunoco Frankford facility
.

2 SUNOCO FRANKFORD/0055833/01-09-071.2 

# •

1.3 

# •

• BART APPLICABILIIY TO SUNOCO FRANKFORD FACILITY The Sunoco Chemicals Frankford facility (Sunoco) located in Philadelphia, P A is an existing major source as defined by the PSD rule_ The facility currently operates under an existing Title V /State Operating Permit (V95-047)_ The operations at Sunoco belong to one of the 26 source categories identified in the BART rule (chemical process plants)- Some of the sources at Sunoco were constructed and began operations between 1962 and 1977. The potential to emit (PTE) for these sources is greater than 250 tpy' for one of the three visibility impairing pollutants (S02). Sunoco meets the three criteria identified above and therefore is subject to the BART rule.

DESCRIPTION OF BART-ELIGIBLE SOURCES

ERM AMS identified BART-eligible sources at Sunoco which were subject to the rule in its letter dated June 2006. In its letter, AMS identified all sources which were constructed in the time period between 1962 and 1977 and sources for which an installation date was not available_ The list of eligible units included emissions units such as boilers, process units, distillation columns, loading and unloading operations, ancillary support operations, tanks, etc. and control devices such as oxidizers. The information provided at that time was based on available information and institutional knowledge from the Title V permit. Based on the best information available, Sunoco has added three cooling towers (CLT-730, CLT-740, and CLT-750) to the list of BARTeligible sources for which the construction dates were not available. Based on best available information, Sunoco has revised the initial BART sources list as provided by AMS. The revised list of eligible units is presented in Table 1-1.

3 SUNOCO FRANKFORD/0055833/01-09-Q?Table I-I 

# • Summary of BART-Eligible Sources at SUJl()('O Frankford Facility
Source Group H Subjerl lo BART Source ID Sourc:t Namt' Installation Date Capacity Visibility lmparing Pollutants Analysis NOx PMIO 502 VOC Yrs No OJ Boilers BL-703 Steam Boiler No. 3 1964 381 MMBrulhr X X X X X EG-701 Boiler House Generator No.I 285 kW X X X X X 02 - Emergency Generators EG-702 Boiler House Generator No.2 250kW X X X X X EG-703 Boiler House Generator No.3 400kW X X X X X

CL300 Cumene Flash Colunm 1964 X X CL301 Crude Acetone Column 1964 X X CL-302 Multi-purpose Coluiilll 1964 X X 03 - Distillation Column CL303 Cumene Recovery Colunm 1964 X X CL-308 Acetone Refining 1964 X X CL-304 AMS Recovery 1964 X X CL-305 Phenol Product 1964 X X CL 306 Phenol Residue Stripping_ Column 1964 X X CL602 Acetone Scrubber 1964 X X X OX-501 70' Cumene Oxidizer 1975 X X VT 507 Aldehyde Drum 1975 X X 04 . Oxidation Process OX-401 56' Cumene Oxidizer 1970 X X VT -401 Aldehyde Drum 1970 X X VT-307 Unit 3

**Decol!!PQ~T** Reactor X X VT 147 Cumene Water Wash Tank 1964 11754

**~als** X X VT 148 Curnene Surge 1964 11754 gals X X VT 149 Cumene Water Scrubber Tank 1964 11754 als X X 05-Reactors VT 150 Cumene Caustic Wash Tank 1964 33852 gals X X VT246 RecyCle Cumene Tank 1963 55222 gals X X VT252 Cumene Surge X X VT323 Cumene Scrubber 1964 11754 gals X X VT324 Cumene Scrubber 1964 I 1754 gals X X 

# • PTLI Phenol Truck Loading X X 06 - Bulk Loading Facilities PB-1 Phenol BarJ!;e Loadin.2 X X ADa I Meth I Styrene Drumming X X ATLal -Methyl St)'I<ne Truck Loading X X HT 101 Process Waste Water Tank X X 1962 VT 105 Phenol Water Decanter 34558 gals VT233 Sprung Phenol 1963 25344 als X X VT 328 Oil Surge Tank 1964 1322 gals X X VT 332 CumeneFeed 1967 587478 gals X X VT 350 IX Acid Wash Water 1964 8760 gals X X VT 504 Brine Condenser Decanter 1976 2800 gals X X VT629 Refined Acetone 1964 146929 gals X X VT630 Refined Acetone 1964 146929 gals X X VT750 Brine Stora.2e Tank 1975 8816 <als X X OMS 801 Overhead Gas KO Drum. X X VT-121 Effluent Storage Tank 1970 228,503 gal_ X X 07- Tanks equipped with VT 332 Cumene Feed 1967 587,478 gals X X Internal Floatation Roofs VT 335 Refmed Acetone 1973 82,614 ••Is X X VT336 Refined Acetone 1973 82,614 gals X X VT-635 Off-spec Cumene Wastewater 1970 158,683 gal. X X Cooline: Towers CLT-730 X X CLT-740 X X CLT-750 X X 

# •

ERM 4 SUNOCO FRANKFORD I 0055833 I 1-9-07

### 2.0 

# •

•

2.1



# • DETAILED BART ANALYSIS

The BART rule requires the sources which are BART-subject to conduct a detailed case-by-case analysis. This analysis involves five steps, as follows: 1. Identify all available retrofit control technologies; 2. Eliminate technically infeasible options; 3. Evaluate control effectiveness of remaining control technologies; 4. Evaluate impacts and document the results; and 5. Evaluate visibility impacts. If a BART-eligible source has a control technology already in place which is the most stringent available, then steps 2 thru 5 of the case-bycase analysis are not necessary. The following sections describe the case-by-case analysis for each BART-eligible source and each visibility impairing pollutant. For streamlining of the control technology and cost effectiveness evaluation, sources using similar control technologies are grouped together.
SOURCES CONSIDERED FOR AVAILABLE RETROFIT CONTROL TECHNOLOGIES

ERM For completion of step 1 of the BART analysis, the following sources were relied upon to identify all available retrofit technologies: • EPA's New Source Review website, • U.S. EPA's RACT /BACT /LAER Clearinghouse (RBLC) Database, • Various state air quality regulations and websites, • Control technology vendors information, • Technical books and articles, and • State and federal guidance documents
.

5 SUNOCO FRANKFORD/0055833/0J-Q9-Q73.0



# •

3.1 

# •

• AVAILABLE RETROFIT CONTROL TECHNOLOGIES FOR BOILER (BL-703)

The following sections identified and described the available NOx retrofit control technologies for Boiler No.3 (BL-703), Group 1 of the BART -eligible units listed in Table 1-1. The boiler underwent the Reasonably Available Control Technology (RACT) determination process in 1995 under PA §129 requirements and is currently operating under the SIP approved RACT plan. Information from the previous analysis was used in this detailed analysis for BART with updated baseline emissions and cost analysis.
NOx 

### Controls

ERM The principal mechanism of NOx formation in gas combustion is thermal NOx. The thermal NOx mechanism occurs through the thermal dissociation and subsequent reaction of nitrogen (Nz) and oxygen (Oz) molecules in the combustion air. Most NOx formed through the thermal NOx mechanism occurs in the high temperature flame zone near the burners. Emission levels vary considerably with the type and size of burner design and with operating conditions (e.g., combustion air temperature, volumetric heat release rate, load, and excess oxygen level). The following is a list of control technologies identified for controlling NOx emissions from the fuel oil-fired boilers.
• Water /Steam Injection (WI),
• Flue Gas Recirculation (FGR),
• Staged Combustion Air (SCA),
• Ultra Low-NOx (ULNB),
• Selective Non-Catalytic Reduction (SNCR),
• Selective Catalytic Reduction (SCR), and
• Ultra Low-NOx Burners and FGR.

6 SUNOC:O FRANKFORD/0055833/01-09-073.1.1 

# •

• 3.1.2

3.1.3 

# • Water/Steam Injection Steam or water injection is used to reduce the flame temperature, thereby reducing the formation of thermal NOx. Water /steam injection is not effective in reducing fuel NOx formation. Another version of this technique is to inject a water-in-oil emulsion, which operates on a similar principle as water 

### I steam injection to reduce NOx. This technique introduces water into the combustion process by emulsifying water in the fuel oil prior to its injection. The water emulsified in fuel oil reduces the flame temperature in the combustion zone thereby reducing thermal NOx; however, water-in-oil emulsion is not effective in reducing fuel NOx. Steam injection is generally not employed in boilers because of a direct reduction in thermal efficiency and greater thermal losses from the stack resulting from increase in moisture content of the flue gas. Also, potentially unsafe combustion conditions result from poor fuel rate control. This method is used in reducing NOx emissions from gas turbines, reciprocating engines, and other internal combustion engines. Few full-scale retrofit or test trials of steam injection on boilers have been performed. For these reasons, steam/water injection is considered technically infeasible and is eliminated from further evaluation as a potential NOx control for the boiler. 

### Flue Gas Recirculation (FGR) Flue gas recirculation involves recycling a portion of the combustion gas to the boiler. The low oxygen combustion product, when mixed with combustion air, reduces the excess combustion air; thereby, reducing the peak flame temperature and thermal NOx formation. However, there is insignificant effect on fuel NOx. As a result, FGR is more effective with low nitrogen content fuels such as natural gas and distillate fuel oil rather than residual fuel oil. FGR is normally applied in combination with new low-NOx burners because the performance of many burners is adversely affected with the introduction of new inert gases in the combustion zone. 

### Staged Combustion Air (SCA)

ERM Staged combustion involves injecting a portion of the total combustion air downstream of the fuel-rich primary combustion zone. This can be achieved by using secondary over-fire air (OFA), side-fired air ports, or the burner out of service (BOOS) technique. SCA is not considered a viable option for retrofit to package boiler units due to installation difficulties.
7 SUNOCO FRANKFORD/0055833/01-09-073.1.4 

# •

•

3.1.5



# • Ultra Low-NOx Burners (ULNB) Combustion controls reduce NOx emissions by controlling the combustion temperature or the availability of oxygen. These are referred to as "low-NOx burners" or "ultra low-NOx burners." There are several designs of low /ultra low-NOx burners (ULNB) currently available. These burners combine two NOx reduction steps into one burner, typically staged air or staged fuel, without any external equipment. In staged air burners, the division of the combustion air reduces the oxygen concentration in the primary combustion zone, lowering the amount of NO formed and increasing the amount of NO reducing agents. Secondary and tertiary combustion downstream of the primary burner complete the remaining combustion, thereby reducing the peak temperature and reducing thermal NOx formation. In some cases, staged air combustion is used with internal recirculation of combustion products further reducing the formation of NOx. In staged fuel burners, the fuel is introduced in steps and is divided into primary and secondary streams. The peak flame temperature is reduced because of the fuel-lean combustion. In addition, the high excess air further quenches the flame temperature and results in formation of inert gases which further reduce the NOx formation. These burners are predominantly applied to process heaters rather than boilers. This design is predominately used for fuel gas applications. Selective Non-Catalytic Reduction (SNCR)

ERM Selective non-catalytic reduction (SNCR) is a post-combustion NOx control technology based on the reaction of NH3 and NOx. SNCR involves injecting urea/NH3 into the combustion gas path to reduce the NOx to nitrogen and water. This reaction is described by the following chemical equation:

The optimum exhaust gas temperature range for implementation of SNCR is 1,200°F to 2,000°F. Operation at temperatures below this range results in NH3 slip, while operation above this temperature range results in oxidation of NH3, forming additional NOx. In addition, the urea/ ammonia must have sufficient residence time,

8 SUNOCO FRANKFORD/0055833/01-09-07• 3.1.6



# •

• approximately 3 to 5 seconds, at the optimum operating temperatures for efficient NOx reduction
. 

### Selective Catalytic Reduction (SCR)

ERM SCR is a process that involves post combustion removal of NOx from flue gas with a catalytic reactor. In the SCR process, ammonia injected into the exhaust gas reacts with nitrogen oxides and oxygen to form nitrogen and water. The reactions take place on the surface of a catalyst. The function of the catalyst is to effectively lower the activation energy of the NOx decomposition reaction. Technical factors related to this technology include the catalyst reactor design, optimum operating temperature, sulfur content of the fuel, catalyst de-activation due to aging, ammonia slip emissions, and design of the NH3 injection system. Reduction catalysts are divided into two groups: platinum and base metal (primarily vanadium or titanium). Both groups exhibit advantages and disadvantages in terms of operating temperature, reducing agent/NOx ratio, and optimum oxygen concentration. A disadvantage common to both platinum and base metal catalysts is the narrow range of temperatures in which the reactions will proceed. Platinum group catalysts have the advantage of requiring lower ignition temperature, but have been shown also to have a lower maximum operating temperature. Operating above the maximum temperature results in oxidation of**N~** to either nitrogen oxides (thereby actually increasing NOx emissions) or ammonium nitrate. Sulfur content of the fuel can be a concern for systems that employ SCR. Catalyst systems promote partial oxidation of sulfur dioxide (from trace sulfur in gas and the mercaptans used as an odorant) to sulfur trioxide (S03), which combines with water to form sulfuric acid. Sulfur trioxide and sulfuric acid reacts with excess ammonia to form ammonium salts. These ammonium salts may condense as the flue gases are cooled or may be emitted from the stack as increased emissions of PM10. Fouling may eventually lead to increased system pressure drop over time and decreased heat transfer efficiencies. The SCR process also is subject to catalyst deactivation over time. Catalyst deactivation occurs through two primary mechanisms: physical deactivation and chemical poisoning. Physical deactivation is generally the result either of prolonged exposure to excessive temperatures or masking of the catalyst due to entrainment of particulate from ambient air or internal contaminants. Chemical poisoning is caused by the irreversible reaction of the catalyst with a
9 SUNCX::O FRANKFORD/0055833/01-09-07

# •

3.1.7



### 3.2 

# •

3.3 

# • contaminant in the gas stream and is a permanent condition. Catalyst suppliers typically only guarantee a 3-year lifetime to very low emission level, high performance catalyst systems . SCR manufacturers typically estimate 10 to 20 ppm of unreacted ammonia emissions (ammonia slip) when making guarantees at very high efficiency levels. To achieve high NOx reduction rates, SCR vendors suggest a higher ammonia injection rate than stoichiometrically required, which results in ammonia slip. Thus, an emissions trade off between NOx and ammonia occurs in high NOx reduction applications. Ultra Low-NOx Burners and FGR This is most commonly used NOx control technique for fuel oil-fired boilers. Also, it is more often feasible for installing FGR along with ULNB, rather than FGR alone.
ELIMINATE TECHNICALLY INFEASIBLE OPTIONS All the control methods identified are considered technically feasible except for water 

### I steam injection, and Staged Combustion Air (SCA) for controlling the NOx emissions from the boiler. Steam injection is predominately used with gas turbines. There is little data available to document the effectiveness of water 

### I steam injection for boilers and no application of this type could be found in the literature search. Additionally, there are operating issues concerning flame stability using low-NOx burners with steam injection; therefore, it is considered infeasible for this analysis. Installation difficulties associated with SCA makes it technically infeasible.
EVALUATE CONTROL EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

ERM Based on information review, the following table presents typical control effectiveness of the technically feasible control options;

10 SUNOCO FRANKFORD/0055833/01-09-07

# •

•

•

ERM Control Technology Control Efficiency (%)'
FGR 40
ULNB** 50

SNCR 72
SCR 85
ULNB + FGR** 60 *"Alternative Control Techniques Document- NOx Emissions from Industrial/Commercial/Institutional Boilers," March 1994, USEPA. **Values in ACT document reported are for LNB; values for ULNB will be higher than LNB.
Based on the information provided in the EPA document, "Alternative Control Techniques (ACT) Document- NOx Emissions from Industrial/ Commercial/ Institutional Boilers," March 1994, the optimal temperature range for a SNCR is 1,650°F through 2000°F. The normal operational temperature of the boiler at Frankford is 300°F, which is significantly below the optimal SNCR temperature range. At these exhaust temperatures, the NOx reduction efficiency is expected to be very low using an SNCR because of low reaction rates. The low reduction rates expected from the SNCR make it economically infeasible. The EPA document states that FGR is rarely applied without installation of a new LNB because performance of the existing burners will be adversely affected by the installation of a FGR. Therefore, ULNB with FGR and SCR are the control technologies which were further evaluated for the cost effectiveness determination. The total capital cost estimates for ULNB/FGR and SCR technology were estimated based on Sunoco's direct experience in the installation of different air pollution control equipment, boiler burner installation from completed projects, and projects currently under construction at the Frankford facility and other facilities owned and operated by Sunoco. The total capital costs used are more representative of actual costs than the methodology provided by "EPA Air Pollution Control Cost Manual" because in recent years there has been significant cost escalation in these types of installations and the cost structures for the chemical manufacturing industry throughout the country. The annualized costs for the technically feasible technologies were then estimated based on methodology in "EPA Air Pollution Control Cost Manual", along with site specific information in accordance with the BART guidance. Since Sunoco has no plan in the foreseeable future to 11 SUNOCO FRANKFORD/0055833/01-09-Q?

# •

3.4 

# •

• retire or shutdown any BART -eligible sources at the facility, the remaining useful life of the equipment factor was not considered in the cost effectiveness analysis
. Average cost effectiveness in dollar per ton removed is determined using the following formulas: Control option annualized cost (baseline annual emissions- annual emissions with control options) Table 3-1 summarizes the cost effectiveness determination for BARTeligible boiler. A detailed cost analysis is provided in Appendix A.
EVALUATE IMPACTS AND DOCUMENT RESULTS

ERM As shown in Table 3-1, the cost effectiveness associated with SCR is $ 40,495 

### I ton and is well above the cost of combustion controls (ULNB+ FGR) alone. The incremental cost from combustion control alone to SCR is $122,745 /ton. Additionally, potential environmental impacts associated with the use of ammonia in the SCR system are summarized below:

• Unreacted ammonia would be emitted to the atmosphere (ammonia slip); ammonia is a PM10 (and PM2.s) precursor;
• Small amounts of ammonium would also combine with NOx and S02 to form ammonia salts, which would be emitted to the atmosphere as PM10; and
• There are significant safety issues associated with the transportation, handling, and storage of aqueous and anhydrous ammonia. For these reasons, SCR is not considered a viable BART control option for the boiler. The cost effectiveness of using combustion control (LNB and FGR) to achieve an emission level of 0.09lb/MMBtu heat input is $9,108 /ton. The boiler is currently equipped with a low-NOx burner (as required by RACT) and is limited to 0.3lb/MMBtu of NOx. The improvements in visibility impacts associated with both control options are discussed below
.



### 12 SUNOCO FRANKFORD/0055833/01-09-Q7• • , •

Table 3-1 Smmnary

of Cost-Effectiveness for NOx Controls on Boiler (BL-703) at Sunoco Frankford Facility

Post Control Incremental

Control

Baseline NOx NOx Capital AJmual Total AJmual Cost Cost

Source

ID Source Name Ratecl Capacity Control Efficiency Emissions Emissions Removed Cost O&M Cost Effectiveness Effectiveness

(MMBtu/hr)

Option (%) (tpy) (tpy) (tpy) ($) ($) ($) ($/ton) ($/ton)

BL-703

Steam Boiler No. 3 381 SCR 85% 149.00 22.35 126.65 $3,141,900 $4,771,723 $5,128,487 40,495 122,745

ULNB+FGR

70% 44.70 104.30 $16,752,781 $269,416 $2,385,219 25,453

ERM 13 SUNOCO FRANKFORD/0055833/1-9-073.4.1 

# •

3.4.2 

# •

• Evaluate Visibility Impacts Sunoco conducted the final step in the BART analysis; an evaluation of the impacts of installing control technology on improvement in visibility in Class I areas. The purpose of the BART rule is to identify and install retrofit controls which will reduce the quantity of visibility impairing pollutants which in turn would reduce the visibility impacts in Class I areas. Therefore, it is important to evaluate the benefits to visibility derived from possible retrofit controls for all visibility impairing pollutants. This section describes the methodology adopted by Sunoco to evaluate improvements in visibility resulting from retrofit technologies for the boiler. 

### Modeling Approach

ERM In this modeling analysis, the CALPUFF dispersion model was used. CALPUFF is a lagrangian puff model recommended for use in regulatory applications including modeling analyses related to New Source Review (NSR) regulations. The CALPUFF modeling system includes numerous related programs used to create inputs for the model and to extract and analyze model outputs. One key related program is CALMET, which is the meteorological processor that creates three-dimensional wind fields for the dispersion model CALPUFF. The post-processing is done using a program called CALPOST, which calculates the visibility impacts using CALPUFF predicted particulate concentrations (including particulate sulfate, particulate nitrate, and direct emissions of PM2.s). The meteorological data for the modeling was the same as used by NESCAUM in its regional scale mode.ling analysis for MANE-VU. CALMET was used to develop the data set, which was based on MMS data for the year 2002 developed by University of Maryland. The MMS data was supplemented with precipitation data from National Weather Service (NWS) stations. In the CALMET setup, the wind fields from MMS were used for both surface and upper air data; the precipitation data is the only data which was supplemented to the CALMET input files. The extent of the domain is 2,500 kilometers in east-west direction and 2,000 kilometers in north-south direction, with 12 kilometer grid spacing. The domain consisted of eleven vertical layers extending up to 3 kilometers above the ground
.


### 14 SUNOCO FRANKFORD/0055833/0Hl9-07

# •

•

3.5 

# • Hourly ozone concentration data for CALPUFF was obtained from EPA's Technology Transfer Network Air Quality System, with a total of 1,500 ozone stations used in the analysis (http: 

### I lwww.epa.gov 

### I ttnlairsl airsaqsl detaildata 

### I downloadaqsdata. htm). The sources considered in this modeling analysis were those for which the cost-effectiveness was evaluated as described in the section above. Modeling scenarios reflected the targeted level of control (reduction achieved) using the ULNB and the ULNBISCR cases. The modeling analysis was conducted for the pre-and post-control emissions cases for the boiler. S02, NOx, and PM1o were included in the modeling analysis, although improvements in visibility impacts were due only to decreases in NOx emissions. The model predicted concentrations of particulate species due to· emissions of S02, NOx, and PM10 were used to estimate visibility impairment. The visibility impairment was calculated as the change from natural background in units of deciviews. The maximum change in deciviews was used to measure the visibility degradation contributed by the source. The visibility impairment with and without the selected control option indicates the benefits of installing the control device on improvements in visibility in the Class I area modeled. The benefit of installing controls using ULNB plus FGR and ULNB/SCR is presented in Table 3-2. Table 3-2 also presents the corresponding cost associated with the improvement in visibility using a given control option. It can be seen that there is an insignificant impact on visibility as a result of the additional NOx controls to the boiler. · Therefore, based on the cost effectiveness determination and the insignificant visibility improvement, Sunoco concludes that no additional control beyond the NOx emissions reduction required by RACT is necessary to meet BART requirements for the boiler.
SOz CONTROLS

ERM S02 emissions are a direct function of amount of sulfur in the fuel. Nearly all sulfur in the fuel is converted to S02 during the combustion process. The following is a list of available control technologies identified for controlling SOz emissions from the boilers.

• Wet Scrubbing • Fuel Specification



### 15 SllNOC:O FRANKFORD/0055833/01-09-07• • •

Table 3-2
Summary of Cost for Visibility Improvement for NOx Controls on Boiler at Sunoco Frankford Facility

Control Baseline Total Annual Baseline Controlled Impact Cost for

Source ID Source Name Pollutant Control Efficiency Emissions Cost Impact Impact Benefit Improvement

Controlled Option (%) (tpy) ($) (delta dv) (delta dv) (delta dv) ($/dv)

BL-703 Steam Boiler No. 3 NO. SCR 85% 149.00 $5,128,487 0.1379 0.0619 0.0760 $67,480,093

NO. UNLB+FGR 70% $2,385,219 0.1379 0.0753 0.0625 $38,139,097

ERM 16 SUNOCO FRANKFORD/0055833/1-9-07

### 3.5.1 

# •

3.5.2 

# •

3.5.3


# • Wet Scrubbing Wet gas scrubbers chemically remove S02 emissions by absorption /neutralization and partial oxidation to calcium sulfate using an aqueous solution. The absorption of S02 with caustic is the simplest method of flue gas desulfurization. In this scrubbing system, the flue gas and a caustic solution flow counter-current to each other. A dual alkali scrubber system utilizes a solution of sodium sulfite (Na203S) and sodium hydroxide (NaOH) to provide absorption and neutralization of S02 within the spray tower. The S02

**~eacts** with the caustic solution and is stripped out of the flue gas stream. Since both sodium sulfite and sodium hydroxide are soluble in water, no precipitation occurs within the scrubber. However, water contamination issues arise with the disposal of large volumes of sodium sulfite and sodium sulfate solution. Lime or limestone is added to the scrubber effluent along with additional sodium hydroxide or soda ash to precipitate the sulfite/sulfate ions and regenerate the sodium hydroxide. Wet scrubbing is a widely used control technology because it is low-cost option relative to comparable technologies, and a high level of removal efficiency can be achieved. 

### Fuel Specification Sulfur in fuel directly impacts the quantity of S02 produced and emitted into the atmosphere. Reducing the sulfur content in.the fuel by switching to low-sulfur fuel has been used as an alternative to installing expensive emission controls. This control methodology may not be technically and economically feasible in all cases. 

### Evaluate Impacts and Document Results

ERM A review of the RBLC database for industrial boilers fired on fuel oil indicated that good combustion practices and limiting the sulfur content of fuel oil were used in most applications. There were no applications where a wet scrubber was used to control S02 emissions from a fuel oil-fired boiler. In addition, there is absolutely no space available in the boiler house at Frankford for installation of a scrubber. If space were available, significant modifications and site preparations would have to be made for the installation of the scrubber. These include but are not limited to:
• Site preparation including: excavation, remediation of soil, and laying a foundation capable of supporting the scrubber;



### 17 SUNOCO FRANKFORD/0055833/0Hl9-07

# •

•

•

ER.M • Piping and duct work (about 1,000 feet and leading up to an elevation of 75 feet);

• Erecting support and access steel structure for duct work and p1pmg;

• Installing a heavy duty blower and the electrical work associated with the blower; and

• Installing noise mitigation measures to reduce noise pollution resulting from the installation of the scrubber. The cost effectiveness estimate presented above was based on the cost estimate for a scrubber installation for a fluid catalytic cracking unit (FCCU) at Sunoco's Philadelphia refinery in 2006. A detailed cost evaluation incorporating all of the elements above was not conducted in this analysis. Sunoco believes that a detailed cost analysis would result in higher cost estimate than that presented in this analysis. Sunoco conducted an analysis of the cost associated with the installation of a wet scrubber on the boiler using EPA's cost calculations spreadsheets. Based on the analysis, the cost effectiveness of installing a wet scrubber for so2 control was estimated to be $2,836/ton of S02 (see Table 3-3). However, the water impacts and annualized cost associated with a wet scrubbing system is generally cost prohibitive. Sunoco evaluated the impacts of installing S02 controls on visibility in Brigantine NWR using the methodology described in Section 3.4.2. In this case, only the benefits derived from S02 controls were evaluated, though the modeling analysis included S02, NOx, and PM emissions. The benefits of installing a wet scrubber (if space was available) on the boiler along with the cost associated with the improvement in visibility using this control option is presented in Table 3-4. It can be seen that there is an insignificant improvement in visibility impacts resulting from the installation of a wet scrubber on the boiler. Based on the lack of space, technical challenges associated with installation of the scrubber, the cost effectiveness evaluation, and the insignificant improvement in visibility derived by installation of a wet scrubber on the boiler, Sunoco concludes that no additional controls are required for reducing so2 emissions from the boiler.



### 18 SUNOCO FRANKFORD/0055833/01-09-07•••Table3-3SummaryofCost-EffectivenessforS02ControlsonBoiler(BL-703)atSunocoFrankfordFacilityPostControlControlBaselineS02S02CapitalAnnualTotalAimualCostSourceIDSourceNa1neRatedCapacityControlEfficiencyEmissions EmissionsRemovedCostO&MCostEffectiveness(MMBtu/hr)Option(%)(tpy) (tpy)(tpy)($) ($)($)($/ton)BL-703StearnBoilerNo.3381WetScrubber90%347.0034.70312.30$7,592,727$113,891$885,5462,836ERM19SUNOCOFRANKFORD/0055833/1-9-07• • •

Table 3-4
Summary of Cost for Visibility Improvement for S0

2 Controls on Boiler at Sunoco Frankford Facility

Control Baseline Total Annual Baseline Controlled Impact Cost for

Source

ID Source Name Pollutant Control Efficiency Emissions Cost Impact Impact Benefit Improvement

Controlled

Option (%) (tpy) ($) (delta dv) (delta dv) (delta dv) ($/dv)

BL-703 Steam Boiler No. 3 so 2 Scrubber 90% 347.00 $885,546 0.1379 0.1078 0.0301 $29,439,689

-- ERM 20 SUNOCO FAANKFORD/0055833/1-9-07

# •

•

• 3.6 PM1oCONTROLS The following is a list of available control technologies identified for controlling 

### PMw emissions from the boiler_
• Good Combustion Practice,
• Wet Scrubbing,
• _ Cyclone,
• Dry /Wet Electrostatic Precipitation, and
• Fabric Filtration/Baghouse. 

### 3.6.1 Good Combustion Practice



### 3.6.2

3.6.3 By maintaining the boiler in good working order per manufacturer's specifications, emissions of PM1o are reduced_ 

### Wet Scrubbing A wet scrubber uses gas/liquid contact to remove particles by inertial impaction and/ or condensation of liquid droplets on particles in gas stream_ 

### Cyclone A cyclone operates on the principle of centrifugal separation_ The exhaust enters the top and spirals toward the bottom of the cyclone_ As the particles, in a spinning motion, proceed downward the heavier material hits the outside wall and drops to the bottom and is collected_ The cleaned gas escapes through an inner tube_ 

### 3.6.4 Dry/Wet Electrostatic Precipitation



### 3.6.5 Electrostatic precipitators (ESPs) involve a high voltage electrode and a grounded electrode. As the flue gas passes between the electrodes, particles become charged and are collected at the grounded electrode_ These particulates are removed either by vibration ("dry" ESPs) or by washing ("wet" ESPs). 

### Fabric Filtration/Baghouse

ERM Fabric filtration removes particles from a gas stream with a baghouse_ An air stream flows through a number of parallel filter bags, where 

### 21 SUNOCO FRANKFORD/0055833/01-09-07

### • 3.6.6



# • 3.7 particulate collects on the fabric. Baghouses are commonly used in industrial applications. 

### Evaluate Impacts and Document Results A review of the RBLC database indicated that good combustion practice and baghouses are used in controlling PM emissions from fuel oil-fired boilers; no application of wet scrubber, ESP, and cyclone technologies on boilers were found. Sunoco evaluated the costeffectiveness of installing a baghouse for controlling PM emissions from the boiler using EPA's cost calculation spreadsheets. A summary of the cost analysis is presented in Table 3-5. Based on the analysis, the cost effectiveness of installing a baghouse for PM control was estimated to be $26,894/ton of PM. In addition to the cost effectiveness analysis, the benefit of installing a baghouse on the boiler to the visibility improvement in Brigantine NWR was evaluated. A summary of the modeling results is presented in Table 3-6. It can be seen from Table 3-6 that there is insignificant improvement in visibility impacts as a result of the additional PM controls on the boiler. Therefore, Sunoco concludes good combustion practices meets BART requirements for PM10 emissions from the boiler.


### VOC CONTROLS The formation of VOC in combustion units depends primarily on the efficiency of combustion. Inefficient combustion leads to the formation of aldehydes, aromatic carbon compounds, and various other organic compounds. The following is a list of available control technologies identified for controlling VOC emissions from boilers. • Good Combustion Practice, and
• Catalytic Oxidation. 3.7.1 

### Good Combustion Practice 

# •

ERM Good combustion practice includes operational and design elements to control the amount and distribution of excess air in the flue gas. This ensures that there is enough oxygen present for complete combustion, thus VOC emissions are minimized
.

22 SUNOCO FRANKFORD/0055833/01.09-07• • •

Table 3-5
Smnmary of Cost-Effectiveness for PM Controls ou Boiler (BL-703) at Sunoco Frankford Facility

Post Control Control Baseline PM PM Capital Annual Total Annual Cost

Source ID Source Name Rated Capacity Coutrol Efficieucy Emissions Emissions Removed Cost O&M Cost Effectiveness

(MMBtu/hr) Option (%) (tpy) (tpy) (tpy) ($) ($) ($) ($/ton)

BL-703 Steam Boiler No. 3 381 Baghouse 99.5% 23.98 0.12 23.86 $1,272,794 $114,746 $641,784 26,894

ERM 23 SUNOCO FRANKFORD/0055833/1-9-07• • •

Table 3-6
Summary of Cost for Visibility Improvement for PM Controls on Boiler at Sunoco Frankford Facility

Control Baseline Total Annual Baseline Controlled Impact Cost for

Source ID Source Name Pollutant Control Efficiency Emissions Cost Impact Impact Benefit Improvement

Controlled Option (%) (tpy) ($) (delta dv) (delta dv) (delta dv) ($/dv)

BL-703 Steam Boiler No. 3 PM10 Baghouse 99.50% 23.98 $641,784 0.1379 0.1235 0.0144 $44,506,519

ERM 24 SUNOCO FRANKFORD/0055833/1-9-07

# •

•

• 3.7.2 

### Catalytic Oxidizer Catalytic oxidation is based on destruction of VOC emissions from a process by oxidation in the presence of a catalyst. The catalyst accelerates the rate of oxidation and enables oxidation at much lower temperatures than conventional thermal oxidation units. Typical temperatures for a catalytic oxidation process is in the range of 320° to 540°C (600° to 1,000°F) by using a solid catalyst. 3.7.3 

### Evaluate Impacts and Document Results

ERM A review of the RBLC database indicated that there are no applications of VOC control in the form of catalytic oxidation technology for fuel oil-fired boilers. The exhaust temperature from the boiler is in the range of 320°F, which is well below the operational temperature range of 600 through 1000°F for the oxidizer. Therefore, Sunoco concludes that good combustion practices meets BART requirements for VOC emissions from the boiler
.

25 SUNOCO FRANKFORD/0055833/01-09-07

### 4.0 

# • 4.1



# •

• EMERGENCY GENERATORS

AVAILABLE RETROFIT CONTROL TECHNOLOGIES FOR EMERGENCY GENERATORS

ERM A review of different databases for existing controls on emergency generators indicated that no control options were found for reducing NOx, SOz, and VOC emissions from emergency generators. The emergency generators at Frankford (Group 02) are intended to be operated only during emergency situations which would mean situations where the normal power supply to the facility is rendered inoperable. The emergency generators at Frankford are limited to less than 500 hours of operation per year. Good combustion practice was observed to be the most common emission reduction strategy for PM emission control. The emergency generators at Frankford are currently operated as per manufacturer's recommendation and using good combustion practices. Therefore, no additional controls are proposed for the emergency generators at Frankford
.



### 26 SUNOCO FRANKFORD/0055833/01-09-075.0 

# • 5.1



# •

• DISTILLATION COLUMNS

AVAILABLE RETROFIT CONTROL TECHNOLOGIES FOR DISTILLATION COLUMNS

ERM The distillation columns (Group 03) at Frankford are subject to the requirements of 40 CFR, Part 63, Subpart NNN (NSPS for SOCMI Distillation Operations) and 40 CFR Part 63, Subpart G (NESHAP for SOCMI units). The emissions from these sources (CL-300, CL-304, CL305, CL-306, CL-301, CL-302, and CL-303) are controlled by routing to four catalytic oxidizers. Sunoco is not aware of any new technology applicable to control emissions from distillation columns which would be more stringent than the existing controls at the facility. Catalytic oxidation can be considered BART -equivalent controls and hence no additional controls are proposed for the BART-eligible distillation columns at Frankford. Some of the distillation columns which were BART -eligible emit acetone, which is de-listed as a VOC and therefore is not a regulated pollutant. These sources include CL-301, CL-302, and CL-602 and should be exempt from BART analysis
.

27 SUNC:X:O FRANKFORD/0055833/01-09-076.0 

# • 6.1



# •

• OXIDATION PROCESS

AVAILABLE RETROFIT CONTROL TECHNOLOGIES FOR OXIDATION PROCESS

ERM The oxidization process (Group 04) at Frankford is subject to the requirements of 40 CFR, Part 60, Subpart III (NSPS for SOCMI Oxidation Unit Processes) and 40 CFR Part 63, Subpart G (NESHAP for SOCMI units). The emissions from the oxidation process at Frankford are reduced to a Total Organic Content (TOC) of less 20 ppmvd. The emissions from the oxidizers, OX-401 and OX-501, are controlled using a carbon adsorber system. Sunoco is not aware of any new technology applicable to control emissions from the oxidation process which would be more stringent than the existing controls at the facility. The existing controls for the oxidation process are considered equivalent to BART and hence no additional controls are proposed
.



### 28 SUNOCO FRANKFORD/0055833/0l.Q9-07

### 7.0 

# • 7.1



# •

• REACTORS

AVAILABLE RETROFIT CONTROL TECHNOLOGIES FOR REACTORS

ERM The reactors (Group 05) at Frankford are subject to the requirements of 40 CFR, Part 60, Subpart RRR (NSPS for SOCMI Reactors) and 40 CFR Part 63, Subpart G (NESHAP for SOCMI units). In addition, many of the BART -eligible reactors were subject to the RACT control requirements. The facility complies with the NSPS requirements by either reducing the outlet TOCby 98% by weight or an outlet concentration of less than 20 ppmvd. Alternatively, the facility can maintain a Total Resource Effectiveness (IRE) of greater than 1.0, if a control device is not used; in which case, the emissions will be insignificant. The existing control options at Frankford ensure compliance with the NESHAP and NSPS rules and hence can be deemed equivalent to BART controls. Sunoco is not aware of any new technology applicable to control emissions from reactors which would be more stringent than the existing controls at the facility. Therefore, no additional controls are proposed for the reactors at Frankford to comply with BART
.



### 29 SUNOCO FRANKFORD/0055833/01·09-078.0 

# • 8.1



# •

• BULK LOADING FACILITIES

AVAILABLE RETROFIT CONTROL TECHNOLOGIES FOR BULK LOADING FACILITIES

ERM The bulk loading facility (Group 06) is subject to the requirements of the NESHAP standards for transfer operations at a SOCMI facility (40 CFR, Part 63, Subpart G). The regulation divided transfer racks into two categories: Group 1 and Group 2. Group 1 transfer racks are those which transfer annual loads of greater than 0.65 million liters of liquid products with a true vapor pressure greater than 10.3 kilopascal (kPa). A transfer rack which is not a Group 1 transfer rack is categorized as a Group 2 transfer rack. All the transfer racks at Frankford are Group 2 transfer racks, which are subject to the record keeping requirements of the Rule only. In addition, the VOC RACT permit limits the emissions from the transfer racks. Sunoco is not aware of any new technology applicable to control emissions from bulk loading facilities which would be more stringent than the existing controls under the NESHAP at the facility. Therefore, no additional controls are proposed for the bulk loading facilities-at Frankford

.



### 30 SUNOCO FRANKFORD/0055833/01-09-07

### 9.0 

# • 9.1



# •

• TANKS/VESSELS

AVAILABLE RETROFIT CONTROL TECHNOLOGIES FOR TANKS/VESSELS

ERM All storage tanks greater than 40,000 gallons (Group 07) are subject to the requirements of 25 PA Code 129.56, which requires the tanks to be equipped with either an external floating root internal floating root or a vapor recovery system. The BART -eligible tanks at Frankford which are greater than 40,000 gallon include VT-121, VT-332, and VT-635. The tanks VT-121, VT-332, and VT-635 are equipped with internal floating roofs. The existing controls on the tanks can be considered BART -equivalent. Some of the storage tanks at Frankford store Acetone which was de-listed as a VOC and therefore is not a regulated pollutant. These tanks include VT-629 and VT-630. The actual emissions from tanks VT-504 and HT -005 are believed be insignificant ( <0.01 tpy) and therefore no emission controls are required. The storage tanks/vessels (Group 07) have stringent levels of control; Sunoco is not aware of any new technology which would be more. stringent than the existing controls. Therefore, no additional controls are proposed for the tanks/vessels at Frankford
.

31 SUNCX:O FRANKFORD/0055833/01-09-07

# •

•

• 10.0 COOLING TOWERS

10.1 AVAILABLE RETROFIT CONTROL TECHNOLOGIES FOR COOLING TOWERS

ERM The cooling towers at Frankford were not included in the original list of BART -eligible sources identified by AMS. Sunoco identified these cooling towers (CL-730, CLT-740, and CL-750) as likely BART-eligible sources based on construction dates. The cooling towers at Sunoco are subject to the requirements of 40 CPR Part 63, Subpart G (NESHAP for SOCMI units). Based on the information reviewed, no retrofit controls were available for cooling towers. Proper maintenance of the cooling towers will minimize emissions of 

### PMw from the cooling towers. No additional control technology is proposed for the cooling towers to meet BART
.

32 SUNOCO FRANKFORD/0055833/01-09-Q?11.0 

# •

•

• CONCLUSIONS

ERM Sunoco Chemicals Frankford facility conducted the BART analysis as required by EPA's BART guidelines. The conclusions of this analysis are summarized below:
• No additional controls are required for BART-eligible sources such as distillation columns, oxidizers, reactors, bulk loading facilities, and tanks beyond those required by applicable regulations such as MACT (40 CFR Part 63, Subpart G) and NSPS (40 CFR, Part 60); • Additional retrofit controls on boiler BL-703 for NOx, S02, and PM10 are either technically infeasible, cost ineffective, and/ or cause insignificant improvement in visibility based on modeling analysis; and
• For cooling towers and emergency generators, existing controls in place represent the best available control for a similar class of sources. In conclusion, Sunoco Chemicals believes that no additional controls are necessary to meet BART requirements

.

33 SUNCX::O FRANKFORD/0055833/0I-09-Q712.0 

# •

•

• REFERENCES

ERM Sunoco, Inc., 2005 "Sunoco Chemicals Frankford Plant, Title VI State Operating Permit No. V95-047." USEPA, 1994. "Alternative Control Techniques Document- NOx Emissions From Industrial/Commercial/Institutional (ICI) Boilers (EPA -453 

### I R -94-022). II USEPA, 2006. "USEPA Technical Bulletins (TBs) and Air Pollution Technology Fact Sheets (FS) (http:/ /www.epa.gov /ttncatcl/products.html)."

34 SUNCX:O FRANKFORD/0055833/01-09-07

# • Appendix A 

# Summary of RBLC Searches



# •

•• • •

Appendix A

RBLC

Summary- Industrial Boilers > 250 MMBtu/hr Firing Liquid Fuel (NOx Controls)

DATE DETERMINATION
COMPANY IF ACILITY RBLCID LAST UPDATED PROCESS NAME FUEL CAPACITY CONTROL DESCRIPTION EMISSION LIMIT CASE-BY-CASE BASIS

RIVER HILL POWER COMPANY LLC
RIVER

HILL POWER COMPANY, LLC 0.09 lb/MMBtu, 12 month

rolling

PA-0249

8/31/2006 AUXILIARY BOILER # 2 Fuel Oil Low Nox Burner and FGR average Other Case by Case

OMAHA

PUBLIC POWER DISTRICT OPPD-

NEBRASKA CITY STATION NE-0031 8/30/2006 AUXILIARY BOILER 2 Distillate Fuel Oil None

MIRA NT MID-ATLANTIC, LLC EMERGENCY GENERATOR

Distillate Fuel Oil None

DICKERSON MD-0032 4/12/2005 AUXILARY BOILER- FO 60 MMBtulhr None

TEMPLE

INLAND INC. INLAND

PAPERBOARD AND PACKAGING, INC. RECOVERY FURNACE, 850

ROME

LINERBOARD MILL GA-0114 5/31/2005 FUEL OIL Fuel Oil MMBtu/hr None

PROCTOR

& GAMBLE/MEHOOPANY PROCTOR

& GAMBLE/MEHOOPANY PA-0242 3115/2005 BOILERS (3) # 6 Fuel Oil Low Nox Burner 31 0 tons/year Other Case by Case

BIOMASS

ENERGY BIOMASS

ENERGY, LLC-SOUTH POINT POWER AUXILIARY BOILER, 227 0.19 lb/MMBtu,

OH-0269

8/1/2006 FUEL OIL # 2 Fuel Oil MMBtulhr None Annual Average SIP

COLUMBIA

ENERGY CENTER COLUMBIA

ENERGY CENTER 550

SC-0091

7/23/2004 BOILER, FUEL OIL Fuel Oil MMBtu/hr Low Nox Burner with FGR 0.12 lb/MMBtu BACT-PSD

THOROUGHBRED

GENERATING COMPANY,

LLC THOROUGHBRED GENERATING STATION BOILER,

AUXILIARY, 300 Good combustion practice,

KY-0084

8/30/2006 DIESEL Diesel MMBtu/hr Operating Limit: 500 hr/yr 0.12\b/MMBtu BACT-PSD

DAYTON

POWER AND LIGHT ENERGY LONGVIEW

FIBRE COMPANY 444
POWER

BOILERS 12 MMBtulhr

WA-0303

8/10/2005 AND 13 Fuel Oil each None 0.73 Jb/MMBtu Other Case by Case

525
POWER BOILER 16 Fuel Oil MMBtu/hr None 0.73 lb/MMBtu Other Case by Case

59\
POWER BOILER 17 Fuel Oil MMBtu/hr None 0.73 lb/MMBtu Other Case by Case

INTERNATIONAL

PAPER- MANSFIELD MILL 900
POWER

BOILER 20 Fuel Oil MMBtu/hr None 0.20 lb/MMBtu Other Case by Case

MANSFIELD

MILL POWER BOILER #1 & #2, 645

LA-0122

3/1712005 OIL Fuel Oil MMBtu/hr Low Nox Stage Burners 0.30 lb/MMBtu BACT-PSD

COLUMBIA

ENERGY LLC COLUMBIA

ENERGY LLC Low Nox Burners with FGR

350

and Good Combustion

SC-0061

8/3l/2006 BOILERS, FUEL OIL (2) # 2 Fuel Oil MMBtu/hr Practices 0.12 lb/MMBtu BACT-PSD• • •

Appendix A

RBLC

Summary- Industrial Boilers > 250 MMBtu/hr Firing Liquid Fuel (NOx Controls)

DATE DETERMINATION COMPANY/FACILITY RBLCID LAST UPDATED PROCESS NAME FUEL CAPACITY CONTROL DESCRIPTION EMISSION LIMI1 CASE-BY -CASE BASIS

COLUMBIA

ENERGY CENTER COLUMBIA

ENERGY CENTER I-26 & US HWY Low Nox Burners with FGR

21

SOUTH BOILER, AUXILIARY, 350 and Good Combustion

SC-0071

8/31/2006 FUEL OIL, (2) # 2 Fuel Oil MMBtulhr Practices 0.12 lb/MMBtu BACT-PSD

GRAYS

FERRY COGEN PARTNERSHIP GRAYS

FERRY COGEN PARTNERSHIP AUXILIARY BOILER, 1119

PA-0187

8/28/2006 FUEL OIL # 2 Fuel Oil MMBtu/hr Low Nox Burners 0.15 lb/MMBtu BACT-PSD

Mobile

Energy LLC HOG

BAYOU ENERGY CENTER 378

AL-0160

12/2/2002 BOILER, BACKUP OIL Natural Gas MMBtu/hr Low Nox Burner with FGR 0.15 lb/MMBtu BACT-PSD

SANTA

MONICA -UCLA MEDICAL CENTER
SANTA

MONICA- UCLA MEDICAL CENTER 16.3

CA-0941

6/30/2003 BOILER, AMBER 363 LowNox Fuel MMBtulhr Low Nox Burner with FGR 0.049 lb/MMBtu LAER

DEGUSSA

CORPORATION DEGUSSA

CORPORATION 355

AL-0104

9/12/2002 BOILER, FUEL OIL Fuel Oil MMBtu/hr Low Nox Burner with FGR 0.12 lb/MMBtu BACT-PSD

RA

YONIER SPECIALTY PULP PRODUCTS

RA

YONIER SPECIALTY PULP PRODUCTS 338

GA-0084

6/9/2003 BOILER (OIL) # 2 Fuel Oil MMBtu/hr Low Nox Burner with FGR 0.10 lb/MMBtu BACT-PSD

# •

•

• Appendix B Cost-Effectiveness Supporting Documentation

# •

•

• Appendix B Data Sources 1. Actual capital cost rrom past projects performed at Sunoco facility. 2. EPA's OAQPS Cost Control Manual 3. Alternative Control Technique Document (1994) for ICI Boilers 4. EPA's Control Technology Fact Sheet for SCR in 1999 dollars. Assumptions and Calculations 1. The post-control emission rate for ULNB/FGR is 0.09 lb/MMBtu. For SCR. a control efficiency of 85% is assumed.

The control efficiency for each source is calculated as the required efficiency to reduce emissions. The control efficiency for the scrubber was assumed to be 90%. The control efficiency for the baghouse was assumed to be 99.5%. 2. Life of Equipment

Life of equipment for ULNB+FGR Life of equipment for SCR Life of catalyst Life of equipment for scrubber Life of equipment for baghouse Life of filter 3. Calculation of Chemical Usage and Cost 10 years 20 years 5 years 20 years 20 years 2 years
Ammonia usage in the SCR is calculated based on the quantity of ammonia required to remove NOx emissions. Molar ratio of ammonia to NOx is used in the equation, i.e
.. A 5% excess ammonia is used in the calculations. Ammonia Used= 17/46 *1.05* NO, emissions Cost of Ammonia is assumed to be 410 $/ton

4. Rated Capacity of the boiler was based on the information presented in the Title V permit. 5. Capital Cost of Equipment

Total Capital Investment (TCI) for the SCR was based on SCR installation cost ($19.2 MM and 550,000 acfm or $34.91/acrrn) on FCCU unit at the Philadelphia refinery. The SCR cost for the boiler was apportioned based on the boiler's exhaust rate (acfm) and cost data rrom the FCCU SCR project.

# •

•

• Cost Effectiveness for FGR/ULNB

# •

•

• Cost Effectiveness Calculation for LNBIFGR on BL-703 Source Steam Boiler No.3 Rated Heat Input 381 Baseline Emissions 149.0 Control Efficiency 70.0%
COST COMPONENT:

DIRECT COSTS Purchased Equipment Costs (Included in TC]) Initial Equipment Costs Instrumen ta lion Freight Taxes Subtotal

- Purchased Equipment Costs Direct Installation Costs (Included in TC]) Foundations & supports; handling & erection; electrical; piping; etc. Site Preparation I Buildings Subtotal- Direct Installation Costs TOTAL DIRECT COSTS (TDC) INDIRECT INSTALLATION COSTS Engineering Costs (included in TCI) Construct. & Field Expenses (included in TCI) Contractor Fees (included in TCI) Start-up (included in TCI) Performance Test (included in TCI) Contingency (included in TCI) TOTAL INDIRECT COSTS TOTAL CAPITAL INVESTMENT (TCI)

Page 1 of 3 COST (x $1000)

16,752.78

# •

•

• Source Steam Boiler No.3 Rated Heat Input 381 Baseline Emissions 149.0 Control Efficiency 70.0%

COST COMPONENT:
ANNUAL DIRECT COSTS Operation and Maintenance Labor Operating Labor (0 hr I shift) O&M Supervision (0 hr /day) Maintenance labor and materials (2.75% of PECj' Subtotal- Operation and Maintenance Labor and Materials

Utilities No. 6 Oil, Natural Gas, and Combustion Gases
Subtotal

- Utilities TOTAL ANNUAL DIRECT COSTS" • PEC = TCI/1.71 (based on information in the OAQPS Cost Manual) b Assumed no change in annual operating costs of ULNB+FGR vs current burners
.

Page 2 of 3 COST (x $1000)

0.00 0.00 269.42 269.42

0.00

0.00 269.42Source Steam Boiler No.3 Rated Heat Input 381 Baseline Emissions 149.0 

# • Control Efficiency 70.0%

COST COMPONENT: COST (x $1000)

INDIRECT COSTS Overhead (not applicable) 0.00 Property Tax (not applicable) 0.00 Insurance (negligible) 0.00 Administration (not applicable) 0.00 TOTAL INDIRECT COSTS 0.00 TOTAL ANNUAL O&M COSTS 269.42 CAPITAL RECOVERY FACTOR Equipment Life (years)= 10 Interest Rate(%) = 7 Capital Recovery Factor 0.1424 CAPITAL RECOVERY COSTS TOTAL CAPITAL REQWREMENT 16752.78 

# • TOTAL ANNUAL CAPITAL REQUIREMENT 2385.22
TOTAL ANNUALIZED COST 2654.64 (Total annual O&M cost and annualized capital cost)
TONS OF POLLUTANT REMOVED PER YEAR (baseline *control efficiency) 104.30 COST-EFFECTIVENESS ENVIRONMENTAL BASIS ($ per ton pollutant removed) $25,453


# •
Page 3 of 3

# •
Cost Effectiveness for SCR



# •

•

# •

•

• Cost Effectiveness Calculation for SCR on BL-703 Source Steam Boiler No.3 Rated Heat Input 381 Baseline Emissions 149.0 Control Efficiency 85.0%
COST COMPONENT:

DIRECT COSTS Purchased Equipment Costs (Included in TCJ) Initial Equipment Costs Instrumentation Freight Taxes Subtotal

- Purchased Equipment Costs Direct Installation Costs (Included in TCJ) Foundations & supports; handling & erection; electrical; piping; etc. Site Preparation I Buildings Subtotal- Direct Installation Costs TOTAL DIRECT COSTS (TDC) INDIRECT INSTALLATION COSTS Engineering Costs (included in TCI) Construct. & Field Expenses (included in TCI) Contractor Fees (included in TCI) Start-up (included in TCI) Performance Test (included in TCI) Contingency (included in TCI) TOTAL INDIRECT COSTS TOTAL CAPITAL INVESTMENT (TCI)

Page 1 of 3 COST (x $1000)

3141.90

# •

•

• Source Steam Boiler No.3 Rated Heat Input 381 Baseline Emissions 149.0 Control Efficiency 85.0%

COST COMPONENT:
ANNUAL DIRECT COSTS Operation and Maintenance Labor Operating Labor (0 hr I day) O&M Supervision (0 hr I day) Maintenance Labor and Material (1.5% of TCJ) Subtotal- Operation and Maintenance Labor and Materials

Utilities Electricity Ammonia Subtotal- Utilities TOTAL ANNUAL DIRECT COSTS

Page 2 of 3 COST (x $1000)

0.00 0.00 47.13 47.13

4700.89

23.70 4724.59 4771.72

# •

•

• Source Steam Boiler No.3 Rated Heat Input 381 Baseline Emissions 149.0 Control Efficiency 85.0%

COST COMPONENT:

INDIRECT COSTS Overhead (does not apply) Property Tax (does not apply) Insurance (does not apply) Administration (does not apply) TOTAL INDIRECT COSTS TOTAL ANNUAL O&M COSTS ANNLTAL CATALYST REPLACEMENT
Future Worth Factor Equipment Life (years)= Interest Rate(%)=
ANNUAL CATALYST REPLACEMENT COST
CAPITAL RECOVERY FACTOR Equipment Life (years)= Interest Rate(%)= Capital Recovery Factor CAPITAL RECOVERY COSTS TOTAL CAPITAL REQWREMENT TOTAL ANNUAL CAPITAL REQUIREMENT
TOTAL ANNUALIZED COST (Total annual O&M cost and annualized capital cost)

TONS OF POLLUTANT REMOVED PER YEAR (baseline* control efficiency) COST-EFFECTIVENESS ENVIRONMENTAL BASIS ($ per ton pollutant removed)

Page 3 of 3 COST (x $1000)

0.00 0.00 0.00 0.00 0.00 4771.72
5 10 0.1638 60.19

20

7 0.0944
3141.90 296.57
5128.49

126.65

$40,495

# •

•

• Cost Effectiveness for Wet ScrubberCost Effectiveness Ca1culation for S02 Scrubber on BL-703

• Source Steam Boiler No.3



# •

• Rated Heat Input 381 Baseline Emissions 347.0 Control Efficiency 90.0%
COST COMPONENT:

DIRECT COSTS Purchased Equipment Costs (Included in TCJ) Initial Equipment Costs Instrumentation Freight Taxes Subtotal -Purchased Equipment Costs Direct Installation Costs(lncluded in TCJ) Foundations & supports; handling & erection; electrical; piping; etc. Site Preparation I Buildings Subtotal

- Direct Installation Costs TOTAL DIRECT COSTS (TDC) INDIRECT INSTALLATION COSTS Engineering Costs (included in TCI) Construct. & Field Expenses (included in TCI) Contractor Fees (included in TCI) Start-up and Performance Test (included in TCI) Contingency (included in TCI) TOTAL INDIRECT COSTS TOTAL CAPITAL INVESTMENT (TCI) COST (x $1000)

7,592.73

# •

•

• Source Steam Boiler No.3 Rated Heat Input 381 Baseline Emissions 347.0 Control Efficiency 90.0%

COST COMPONENT:
ANNUAL DIRECT COSTS Operation and Maintenance Labor Operating Labor (0 hr I day) O&M Supervision (0 hr I day) Maintenance Labor and Material (1.5% of TCI) Subtotal

- Operation and Maintenance Labor and Materials
Utilities Electricity Water Wastewater Subtotal- Utilities TOTAL ANNUAL DIRECT COSTS COST (x $1000)

0.00 0.00 113.89 113.89

51.91 0.15 2.89 54.96 168.85

# •

•

• Source Steam Boiler No.3 Rated Heat Input 381 Baseline Emissions 347.0 Control Efficiency 90.0%

COST COMPONENT:

INDIRECT COSTS Overhead (does not apply) Property Tax (does not apply) Insurance (does not apply) Administration (does not apply) TOTAL INDIRECT COSTS TOTAL ANNUAL O&M COSTS

CAPITAL RECOVERY FACTOR Capital Recovery Factor CAPITAL RECOVERY COSTS TOTAL CAPITAL REQUIREMENT Equipment Life (years) = Interest Rate(%)=

TOTAL ANNUAL CAPITAL REQUIREMENT
TOTAL ANNUALIZED COST (Total annual O&M cost and annualized capital cost)

TONS OF POLLUTANT REMOVED PER YEAR (baseline* control efficiency) COST-EFFECTIVENESS ENVIRONMENTAL BASIS ($per ton pollutant removed) COST (x $1000)

0.00 0.00 0.00 0.00 0.00 168.85

20

7 0.0944
7592.73 716.70
885.55

312.30

$2,836• • •

Stream parameters: Inlet waste gas flowrate (acfm): 90,000 Calculated from stack parameters used in modeling

Inlet waste gas temJJ_erature (of): 140 Assumed value. Would need to install heat exchange equipment to get to this level.

Inlet waste _gas pressure (atm.): I

Pollutant in waste gas: Sulfur dioxde

Inlet gas poll. cone., yi (mole fraction): 1.004E-04 Calculated based on annual emissions of 347 tons -----

Pollutant removal efficiency (fraction): 0.90 Assumed value

Absorbent: Water

Inlet pollutant cone. in absorbent: 0 Assumes no 502 in water

Waste gas molecular weight (lb/lb-mole): 28.90 Assumed value

Absorbent molecular weight (lb/lb-mole): 18.00 MW of water

**---------~--**

Inlet waste gas density (lb/ft3): 0.0660 OAQPS spreadsheet calculation

Absorbent density (lb/ft3): 62.4 Density of water

Absorbent specific gravity: 1.00 Specific gravity of water

Waste gas viscosity@ inlet temp. (lb/ft-hr): 0.044 Assumption (artifact of HCI calculation)

Absorbent viscosity@ inlet temp. (lb/ft-hr): 2.16 Assum]Jtion (ar1ifact of HCI calculation)

Minimum wetting rate (ft2/hr): 1.3 Assumption

Pollutant diffusivity in air (ft2/hr): 0.598 Calculated based on HCI and molecular· weights of HCI and 502

Pollutant diffusivity in absorbent (ft2/hr): 0.000102 Assumption (a1tifact of HCI calculation)

Packing parameters: Assumption

2-in. ceramic

Packing type: Raschig 1ings

Packing factor, Fp: 65

Packing constant, alpha: 3.82

Packing constant, beta: 0.41

Packing constant, gamma: 0.45

Packing constant, phi: 0.0125

Packing constant, b: 0.22

Packing constant, c: 0.24

Packing constant, j: 0.17

Surface area-to-volume ratio, a (ft2/ft3): 28•••-------DESIGNPARAMETERS:Inletpollutantconcentration(freebasis):1.004E-04OAQPSspreadsheetcalculationOutletpollutantconcentration(freebasis):J.004E-05OAQPSspreadsheetcalculationOut.eq.poll.cone.inabsorbent.,Xo*(op.line):9.602E-07CalculatedfromequilibriumdataTheoreticaloperatinglineslope(Ls/Gs.min.):94.0950OAQPSspreadsheetcalculationLs/Gsadjustmentfactor:1.5Maximumvalueofrange,perOAQPSActualoperatinglineslope(Ls/Gs,act.):141.1425OAQPSspreadsheetcalculationGastlowrate,Gs(freebasis,lb-moles/hr):12328OAQPSspreadsheetcalculationAbsorbenttlowrate.Ls(freebasis,Jb-mol/hr):1739938.35OAQPSspreadsheetcalculationGastlowrate,Gmol,i(Jb-moles/hr):12329OAQPSspreadsheetcalculationAbsorbenttlowrate,Lmol,i(Jb-moles/hr):1739938.35OAQPSspreadsheetcalculationOutletactualpollutantcone.inabsorbent,Xo:0.000001OAQPSspreadsheetcalculationGaspoll.cone.ineq.w/Xo(Yo*):0.0001CalculatedfromequilibriumdataOutletabsorbentpoll.cone.(molefract.basis):0.0000OAQPSspreadsheetcalculationGaspoll.cone.,Yo*(molefract.basis):0.0001OAQPSspreadsheetcalculationOutletgaspoll.cone.,yo(molefract.):1.004E-05OAQPSspreadsheetcalculationSlopeofequilibriumline(m):104.54307OAQPSspreadsheetcalculationAbsorptionfactor(AF):1.35OAQPSspreadsheetcalculationABSCISSA(columndiametercalculation):2.859E+00OAQPSspreadsheetcalculationORDINATE(columndiametercalculation):0.0057OAQPSspreadsheetcalculationSuperficialgastlowrate,Gsfr,i(Jb/sec-ft2)0.1089OAQPSspreadsheetcalculationFloodingfactor,f:0.7Maximumvalueofrange,perOAQPSColumncross-sectionalarea.A(ft2):1297.77OAQPSspreadsheetcalculationSuperficialliquidtlowrate(lb/hr-ft2):24132.79OAQPSspreadsheetcalculationMinimumliquidtlowrate(lb/hr-ft2):2271OAQPSspreadsheetcalculationColumndiameter,D(ft2):40.649OAQPSspreadsheetcalculationNumberoftransferunits,Ntu:4.643OAQPSspreadsheetcalculationGasfilmtransfercoefficient,Hg(ft):1.245OAQPSspreadsheetcalculationLiquidfilmtransfercoefficient,Hl(ft):1.064OAQPSspreadsheetcalculationHeightofatransferunit(ft):2.033OAQPSspreadsheetcalculationPackingdepth(ft):9.442OAQPSspreadsheetcalculationColumntotalheight(ft):57.49OAQPSSJJreadsheetcalculation...·-·--Columnsurfacearea(ft2):9937.3OAQPSspreadsheetcalculationColumngaspressuredrop(in.w.c./ftpacking):0.027OAQPSspreadsheetcalculationColumnliquidpressuredrop(ftofH20):60Assumption(artifactofHCIcalculation)Packingvolume(ft3):12253.2OAQPSspreadsheetcalculationTotalCapitalInvestment($):12,464,212Datasuppliedbycompany=======================================================================================ANNUALCOSTINPUTS:Operatingfactor(hr/yr):8760Electricityprice($/kWhr):0.06Absorbentmaterial(caustic)price($/ton):20AbsorbentcaJTier(water)price($/I000gal):0.20Wastewatert1tmtcost($/1000gal):3.80

# •

•

•

# •
Cost Effectiveness for Baghouse



# •

•• • •

TOTAL ANNUAL COST SPREADSHEET PROGRAM--FABRIC FILTERS

INPUT PARAMETERS: Calculated from

swck parmneters

Inlet stream tlowrate (acfm): 89853 used in modeling

Based on stack

Inlet stretun temperature (oF): 296 parameter

Inlet stream **temper<~ture. adjusted~-pulse**  jet only (oF): 275

Dust type: based on limit of

Inlet dustloadin,g (gr/ft3)· 0.05 0.1 \b/MMBtu

Dust mass median diameter (microns): 7

Filtration time (min): 30 OAQPS guidance **Dust_3J~i<:_re_sist,mc.:_(in.H2QI!Pmllb/ft2):** 15

GIC mtio factors (shaker & reverse-air):

A: 2.0

B: 0.9

C: 1.0

GIC ratio factors (pulse-jet):

Mate1ial: 9.0

Applicntion: 0.8

GIC ratio factors (cartridge filters):

A: 2.1

B 0.8

C: 0.75

D: 0.9

E: 1075 **Cle<min~res~ure~Jsigjpu~e-j_~** onl1): 100

Fraction of bags cle::med (shaker & rev-air)· 0.1

Insulation required? ('yes'= I ;'no'=O): 1

Stainless steel **req~ired'!** ('yes'= I ;'no'=O): 0

**B~111aterial:** Fiberal<tSS

Fabric effective residual dra,g (in. **H20~11):** 11

Bug prices ($/ft2):

Cleanin_g Mech. Ba2 Diam. (in.) Price ($/ft2)

Puls<:jet--BBR 4.5 to 5.125 1.69

6 to 8 1.55

Pulse jet--cart. 4 875 0.00 6.125 0.00

**Shaker--su~** 5 0.00

Shaker--loop 0.00

Reverse air w/o rings 0.95

11.51 0 75

Cost of **Hllxili;.~nent** (ductwork. fun. stack. etc.).($): 89500•••DESIGNPARAMETERSGas-to-clothratio(acfm/ft2clotharea):Shaker:180Reverse-air·180Pulse-jet:6.08Cartrid2:e:122Netclotharearequired(ft2):Shaker:49918Reverse-air:49918Pulse-iet:14786Cnrtrid2e:73707Grossclotharea(ft2):Shaker:55409Reverse-air:55409Pulse-jet:14786Cartride:e:73707Areuperbag--reverse-air(ft2)(8-in.x24-ft):50.3Numberofbags--reverseair:1103Areaperbag--shaker(ft2)(5-inx8-ft):10.5Numberofba2s--shaker5292Areaperbug--pulsejet(ft2):Small(4.5-in.x8-ft)9.42Lar•e(5.125-in.x10-ft)13.42Numberofbaos/ca•es(pulse-jetonly):Smallbae:s1569Largebags1103Areaperbng--cartridge(ft2):153Numberofbags--cartridge:482Bne:pressuredrop(in.w.c.):Shaker·199Reverse-air:199Pulse-jet:198Cartride:e:1.35Baghousedrop(in.w.c.):3.00Ductworkpressuredrop(in.w.c.):4.00lCAPITALCOSTSEgtlij>tnemCosts($):Item:Cost($)·ShakerTRev-airIP-J(mod)P-J(com)P-J(cartrid•e)Baghouse0293.ss71144,916108,2210Bae:s--smallOJ41.557124.989 24,9890--large22.91922,919Insulation062.26334.01440.2310Stainless00000Cages-small[51009.3889.38800012.17212,172008950089,50089.5000-lan?:cTotal--smallISaloT487,208302,808272.3290"--lou·ge:303.522273.043PEC($)-base:Ol574,905357,313321.3480

# •

•

0 0 0



# •• • •

ANNUAL COST INPUTS· Operatin•

factor (hr/yr): 8640

Operatin•

labor rate (Mu): 29.14

Maintenance

labor rate ($/hr): 27.87

Operatin•

labor factor (hr/sh): 2

Maintenance

labor factor (hr/sh)·. I

Electricity

price ($/kWhr): 0.0600

Compressed

air ($/1000 set} 0.25

Dust

disposal ($/ton): 25

Annual

interest rate (fraction): 0.07

Control

system life (years): 20

Capital

recovery factor: 0.0944

Bag

life (years): 2

Capital

recovery facwr (baO's): 0.5531

Taxes.

insurance. Hdmin. factor: 0.04 ANNUAL COSTS ($/vr):

Item

Shaker Reverse-a1r P-J (moduhu P-J (common P-.1 (cartridcre)

Oper. labor 0 62.942 62.942 62,942 0

Supv.

labor 0 9.441 9.441 9.441 0

Mnint.

labor 0 30.100 30,100 30.100 0

Maint.

matl. 0 30.100 30.100 30.100 0

Electricity

0 227,878 75,709 75,709 0

Compr. **;:~ir** 0 0 23.290 23.290 0

Bag_rCjJI.

0 31,625 26,984 26,984 0

Dust

dispos 0 4,492 4,492 4,492 0

Overlle;Jd

0 79.550 79,550 79,550 0

Tax,ins.,;.Jdm

0 50,912 31.642 28.458 0

Cap,

recov. 0 114,746 70,065 62.550 0

Total

Annual 0 641,784 444,316 433,615 0•••RELATIONSHIPBETWEENGROSSANDNETCLOTHAREANetClothArea>i=(ft2):Gross/NetAreaRatio:I2.00040011.500120011.250240011.170360011.125480011.110600011.100720011.090840011.080960011.0701080011.0601320011.0501800011.040BAGPRICES(2ndquarter1998$/ft2)FORSELECTEDMATERIALS[excerptedfromTable5.8,Chapter5]**"'*"'"'...***"'*......******"'*...*****...*****************"'***********"'"'***"'*"'"'*...*******...*..."'"'..."'"'"'"'............"'.,."'...*...*..."'"'......*......"'"'"'*......*..."'"'*"'..."'...**"'"'*......"'******"'"'*..."'"'*******...*****>!:>I< ...** >I<...****"'*>I<****,f< >I<** ***"'.·I•:1••I'Mech.BagDiam.(in.)PolyethylenePolypropyleneNomexHomo-acrylicFiberglasCottonTellonP84RytonNextel·--------------------------------------------------------------------------------------------------------------------------------------------Pulsejet--TR4.5to5.1250.750.812.171.241.92NA12.214.062.8720666to80.670.721.951.151.60NA9.703.852.62NAPulsejet-BBR4.5to5.1250.530.531.840.951.69NA12.923.602.4216.676to80.500.601.770.981.55NA9.003.512.30NAPulsejet-cart.4.8752.95NA6.12NANANANANANANA6.1251.53NA4.67NANA NANANANANASh<lker·strap50.630.881.611.03NA0.70NANANANAShaker-loop50.611.011.531.04NA0.59NANANANARev.airwirings80.63!.52135NA1.14NANANANANA11.50.62NA1.43NA1.01NA NANANA NARev.nirw/o"80.44NA1.39NA0.95NANANANANA11.50.44NA1.17NA0.75NANANANANA

# •

•

• Appendix C 

# BART Letter from Philadelphia Air Management Services (AMS)

# •

•

• Mr. Paul Persing Sunoco, Inc. 

# CITY OF PHILADELPHIA

Margaret & Bermuda Streets Philadelphia, PA 19137-1193 PLID: 1551 RE: BART Requirements Dear Mr. Persing, DEPARTMENT OF PUBLIC HEALTH Carmen I. Paris Interim Health Commissioner Air Management Services Morris Fine Director Source Registration 321 University Avenue, 2nd Floor Philadelphia, PA 19104 Telephone (215) 685-7572 Fax (215) 685-7593

November 27, 2006

Air Management Services (AMS) notified you by letter of June 9, 2006 that certain units at your facilities are subject to the Best Available Retrofit Technology (BART) requirements of the federal regional haze program. As explained in the June 9, 2006letter, you have the option to take permit limitations to restrict the combined emissions from the date eligible units to below 250 tons per year for each visibility impairing pollutant or to conduct and submit a BART proposal based on an engineering analysis of control options for each BART -eligible unit at the facility for each visibility impairing pollutant. AMS wishes to clarify information relating to volatile organic compounds (VOCs) and de minimis emission levels. Regarding VOCs, although VOCs may contribute to visibility impairment, the Pennsylvania Department of Environmental Protection (PA DEP) and AMS do not currently have the technical capacity to determine the extent of contribution by individual sources of VOCs. Therefore, the BART analysis does not need to address potential VOC control measures. Regarding de minimis emission levels, PA DEP has concluded it will not require the analysis to include pollutants for which the combined potential to emit of the BART -eligible units is below the U.S. Environmental Protection Agency (EPA) suggested de minimis levels of 40 tons per year of NOx or S02 or 15 tons per year of PM 10 . AMS will follow this policy. To assist owners and operators of affected facilities with the BART engineering analysis, Pennsylvania participated in a regional effort coordinated by the Northeast States for Coordinated Air Use Management (NESCAUM) to quantify the visibility impact of BART sources using CALPUFF. Two sets of CALPUFF results were generated for each BART source using two

# •

•

• meteorological data sets: National Weather Service (NWS) observation data and MM5 data. Please see the enclosed table displaying summary results of 24-hour maximum visibility impact from the affected units at your facility. You may use the enclosed model results to help satisfy the requirement to consider the fifth factor (visibility improvement) in the BART analysis. However, it appears that the modeling does not include all BART -eligible sources at your facility and may have incorrect emissions for some sources, so your facility may need to do additional modeling. If you need or elect to conduct additional modeling, we will review results you provide. Because the NESCAUM CALPUFF modeling was not conducted in accordance with the EPA protocol for modeling exemptions, it cannot be used to support a modeling exemption demonstration. One major difference is that average annual emissions were modeled rather than the highest 24-hour average actual emission rate recommended by EPA as reflecting steady-state operating conditions. This simplification could have the effect of understating a source's impact on vi-sibility. Another significant difference is that the NESCAUM modeling was conducted using one year of meteorology data rather than the three to five years recommended by the BART rule. Although the modeling is not acceptable to support a modeling exemption, it is acceptable for use in consideration of the fifth factor (visibility improvement) in the BART analysis. The BART analysis should be conducted in accordance with the BART Guidelines issued by the EPA and available at http://www.epa.gov/air/visibility/actions.html#bartl. The BART analysis should address each of the five statutory factors required by the Clean Air Act (CAA). These factors are: the costs of compliance; the energy and non-air quality environmental impacts of compliance; any existing pollution control technology in use at the source; the remaining useful life of the source; and the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology. For sources subject to a Maximum Achievable Control Technology (MACT) standard, consistent with the BART Guidelines, you may streamline the analysis for the MACT regulated pollutant if no new technologies have been developed subsequent to the MACT standard by including a discussion of the applicable MACT standard. Please submit the BART proposal to: Source Registration Air Management Services 321 University Avenue Philadelphia, PA 19104 Department of Environmental Protection Bureau of Air Quality RCSOB

- 1ih Floor Attention: Nancy Herb 400 Market Street Harrisburg, PA I 7 I 0 I
The BART proposal based on an engineering analysis of control options for all BART-eligible units at your facility should be received by AMS by January 10, 2007. Following AMS review of your BART proposal, AMS will establish enforceable emission limitations and compliance schedules that ensure that BART controls, if warranted by the BART determination process, will be installed and in effect by 2013. AMS and PA DEP will submit them to EPA as a revision to the State Implementation Plan, pursuant to the requirements of the federal CAA and federal regional haze regulations. You may contact me at (215) 685-9426 or edward.wiener@phila.gov with any questions about the BART requirements
.

# •

•

• Sincerely,

Edward Wiener Environmental Engineer•SUNOCO-FRANKFORDTax_IDFacility_ID1551Source_IDSource_Name70'_Cumene_Oxidizer70'_Cumene_Oxidizer56'_Cumene_Oxidizer56'_Cumene_OxidizerCumene_Fiash_ColumnCrude_Acetone_ColumnMulti-purpose_ColumnCumene_Recovery_ColumnAcetone_RefiningAMS_RecoveryAMS_RecoveryPhenoi_ProductNotesPhenoi_ProductPhenoi_Residue_Stripping_ColumnPhenoi_Residue_Stripping_ColumnBoiler_#3GenericStack2002ActualEmissions•EnclosureCALPUFFVisibilityImpactEstimatesNovember2006CALPUFF'•NWSPlatformMAX24-hourImpactversusNaturalBackground-20%BestDays(Deciviews)NOxPM10SOxVOCClassIAreaTotalS04N03PM1020.617.473.4brigwild0.01410.00610.00570.0043brigwild0.01410.00610.00570.0043(CALPUFFMMSmodeled>90%ofemissionsinindividualstacks:remaindermodeledas"genericstack")Totalforunitsthatmeetdaterequirements20.617.473.4brigwild0.02810.0121001150.0087•CALPUFF•MM5PlatformMAX24-hourImpactversusNaturalBackground•20%BestDays(Deciviews)ClassIAreTotal504N03PM10brigwild0.02650.00910.01120.0089brigwild0.00000.00000.00000.0000brigw1ld0.02650.00910.01120.0089