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/0055833/01-09-07 
1.2 

• 

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-Q7 
3.0 

• 

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/0055833/01-09-07 
3.1.1 

• 

• 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/0055833/01-09-07 
3.1.4 

• 

• 

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 

Control Baseline NOx NOx Capital AJmual Total 

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

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

BL-703 Steam Boiler No. 3 381 SCR 85% 149.00 22.35 126.65 $3,141,900 $4,771,723 $5,12

ULNB+FGR 70% 44.70 104.30 $16,752,781 $269,416 $2,38

ERM 13 SUNOC
3.4.1 

• 

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 

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

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

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

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

ERM 16 SUNOCO FR
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 
• • 

Table 3-3 

Summary of Cost-Effectiveness for S02 Controls on Boiler (BL-703) at Sunoco Frankford Facility 

Post Control 

Control Baseline S02 S02 Capital Annual Total Aim

Source ID Source Na1ne Rated Capacity Control Efficiency Emissions Emissions Removed Cost O&M Cost 

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

BL-703 Stearn Boiler No. 3 381 Wet Scrubber 90% 347.00 34.70 312.30 $7,592,727 $113,891 $885,54

ERM 19 SUNOCO 
• • 

Table 3-4 

Summary of Cost for Visibility Improvement for S02 Controls on Boiler at Sunoco Frankford Facility 

Control Baseline Total Annual Baseline Controlled Impact C

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

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

BL-703 Steam Boiler No. 3 so2 Scrubber 90% 347.00 $885,546 0.1379 0.1078 0.0301 $2

--

ERM 20 SUNOCO FA
• 

• 

• 

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 Ann

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

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

BL-703 Steam Boiler No. 3 381 Baghouse 99.5% 23.98 0.12 23.86 $1,272,794 $114,746 $641,78

ERM 23 SUNOCO 
• • 

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 

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

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

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

ERM 24 SUNOCO F
• 

• 

• 

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/0055833/01-09-07 
5.0 

• 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/0055833/01-09-07 
6.0 

• 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/0055833/01·09-07 
8.0 

• 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, 

MACT 

and tanks beyond those required by applicable regulations such as 

(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-Q7 
12.0 

• 

• 

• 

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 EM

RIVER HILL POWER COMPANY LLC 

RIVER HILL POWER COMPANY, LLC 0.09 

mon

PA-0249 8/31/2006 AUXILIARY BOILER # 2 Fuel Oil Low Nox Burner and FGR aver

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 

BIOMASS ENERGY 

BIOMASS ENERGY, LLC-SOUTH POINT POWER AUXILIARY BOILER, 227 0.19 

OH-0269 8/1/2006 FUEL OIL # 2 Fuel Oil MMBtulhr None Ann

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 

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

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 

525 

POWER BOILER 16 Fuel Oil MMBtu/hr None 0.73 

59\ 

POWER BOILER 17 Fuel Oil MMBtu/hr None 0.73 

INTERNATIONAL PAPER- MANSFIELD MILL 900 

POWER BOILER 20 Fuel Oil MMBtu/hr None 0.20 

MANSFIELD MILL POWER BOILER #1 & #2, 645 

LA-0122 3/1712005 OIL Fuel Oil MMBtu/hr Low Nox Stage Burners 0.30 

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 
• • 

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 EMI

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 

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 

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 

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 0.04

DEGUSSA CORPORATION 

DEGUSSA CORPORATION 355 

AL-0104 9/12/2002 BOILER, FUEL OIL Fuel Oil MMBtu/hr Low Nox Burner with FGR 0.12 

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 
• 

• 

• 

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 

269.42 
Source 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 

Scrubber 
Cost 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 

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 
• • 

- ------

DESIGN PARAMETERS: 

Inlet pollutant concentration (free basis): 1.004E-04 OAQPS spreadsheet calculation 

Outlet pollutant concentration (free basis): J.004E-05 OAQPS spreadsheet calculation 

Out. eq. poll. cone. in absorbent., Xo* (op. line): 9.602E-07 Calculated from equilibrium data 

Theoretical operating line slope (Ls/Gs.min.): 94.0950 OAQPS spreadsheet calculation 

Ls/Gs adjustment factor: 1.5 Maximum value of range, per OAQPS 

Actual operating line slope (Ls/Gs, act.): 141.1425 OAQPS spreadsheet calculation 

Gas tlowrate, Gs (free basis, lb-moles/hr): 12328 OAQPS spreadsheet calculation 

Absorbent tlowrate. Ls (free basis, Jb-mol/hr): 1739938.35 OAQPS spreadsheet calculation 

Gas tlowrate, Gmol,i (Jb-moles/hr): 12329 OAQPS spreadsheet calculation 

Absorbent tlowrate, Lmol,i (Jb-moles/hr): 1739938.35 OAQPS spreadsheet calculation 

Outlet actual pollutant cone. in absorbent, Xo: 0.000001 OAQPS spreadsheet calculation 

Gas poll. cone. in eq. w/Xo (Yo*): 0.0001 Calculated from equilibrium data 

Outlet absorbent poll. cone. (mole fract. basis): 0.0000 OAQPS spreadsheet calculation 

Gas poll. cone., Yo* (mole fract. basis): 0.0001 OAQPS spreadsheet calculation 

Outlet gas poll. cone., yo (mole fract.): 1.004E-05 OAQPS spreadsheet calculation 

Slope of equilibrium line (m): 104.54307 OAQPS spreadsheet calculation 

Absorption factor (AF): 1.35 OAQPS spreadsheet calculation 

ABSCISSA (column diameter calculation): 2.859E+00 OAQPS spreadsheet calculation 

ORDINATE (column diameter calculation): 0.0057 OAQPS spreadsheet calculation 

Superficial gas tlowrate, Gsfr,i (Jb/sec-ft2) 0.1089 OAQPS spreadsheet calculation 

Flooding factor, f: 0.7 Maximum value of range, per OAQPS 

Column cross-sectional area. A (ft2): 1297.77 OAQPS spreadsheet calculation 

Superficial liquid tlowrate (lb/hr-ft2): 24132.79 OAQPS spreadsheet calculation 

Minimum liquid tlowrate (lb/hr-ft2): 2271 OAQPS spreadsheet calculation 

Column diameter, D (ft2): 40.649 OAQPS spreadsheet calculation 

Number of transfer units, Ntu: 4.643 OAQPS spreadsheet calculation 

Gas film transfer coefficient, Hg (ft): 1.245 OAQPS spreadsheet calculation 

Liquid film transfer coefficient, Hl (ft): 1.064 OAQPS spreadsheet calculation 

Height of a transfer unit (ft): 2.033 OAQPS spreadsheet calculation 

Packing depth (ft): 9.442 OAQPS spreadsheet calculation 

Column total height (ft): 57.49 OAQPS SJJreadsheet calculation 

Column surface area (ft2): 9937.3 OAQPS spreadsheet calculation Column gas pressure drop (in. w.c./ft packing): 0.027 OAQPS spreadsheet calculation 

Column liquid pressure drop (ft of H20): 60 Assumption (artifact of HCI calculation) 

Packing volume (ft3): 12253.2 OAQPS spreadsheet calculation 

Total Capital Investment($): 12,464,212 Data supplied by company 

============================================================ =========================== 

ANNUAL COST INPUTS: 

Operating factor (hr/yr): 8760 

Electricity price ($/kWhr): 0.06 

Absorbent material (caustic) price ($/ton): 20 

Absorbent caJTier ( water) price ($/I 000 gal): 0.20 

Wastewater t1tmt cost ($/1 000 gal): 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 
• • 

DESIGN PARAMETERS 

Gas-to-cloth ratio (acfm/ft2 cloth area): 

Shaker: 180 

Reverse-air· 180 

Pulse-jet: 6.08 

Cartrid2:e: 122 

Net cloth area required (ft2): 

Shaker: 49918 

Reverse-air: 49918 Pulse-iet: 14786 

Cnrtrid2e: 73707 Gross cloth area (ft2): 

Shaker: 55409 

Reverse-air: 55409 

Pulse-jet: 14786 

Cartride:e: 73707 

Areu per bag--reverse-air (ft2) (8-in. x 24-ft): 50.3 

Number of bags--reverse air: 1103 

Area per bag--shaker (ft2) (5-in x 8-ft): 10.5 

Number of ba2s--shaker 5292 

Area per bug--pulse jet (ft2): 

Small (4.5-in. x 8-ft) 9.42 

Lar•e (5.125-in. x 10-ft) 13.42 

Number of baos/ca•es (pulse-jet only): 

Small bae:s 1569 

Large bags 1103 

Area per bng--cartridge (ft2): 153 

Number of bags--cartridge: 482 

Bne: pressure drop (in. w.c.): 

Shaker· 199 

Reverse-air: 199 

Pulse-jet: 198 

Cartride:e: 1.35 

Baghouse drop (in. w.c.): 3.00 Ductwork pressure drop (in. w.c.): 4.00 

l CAPITAL COSTS Egtlij>tnem Costs ($): 

Item: Cost($)· 

Shaker T Rev-air I P-J (mod) P-J (com) P-J (cartrid•e) 

Baghouse 0 293.ss7 1 144,916 108,221 0 

Bae:s--small OJ 41.5571 24.989 24,989 0 

--large 22.919 22,919 

Insulation 0 62.263 34.014 40.231 0 

Stainless 0 0 0 0 0 

Cages-small [51 0 0 9.388 9.388 0 

0 0 12.172 12,172 0 

0 89500 89,500 89.500 0 

-lan?:c 

Total--small I Sal oT 487,208 302,808 272.329 0 

" --lou·ge: 303.522 273.043 

PEC($ )-base: Ol 574,905 357,313 321.348 0 
• 

• 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 
• • 

RELATIONSHIP BETWEEN GROSS AND NET CLOTH AREA 

Net Cloth Area >i= (ft2): Gross/Net Area Ratio: 

I 2.000 

4001 1.500 

12001 1.250 

24001 1.170 

36001 1.125 

48001 1.110 

60001 1.100 

72001 1.090 

84001 1.080 

96001 1.070 

108001 1.060 

132001 1.050 

180001 1.040 

BAG PRICES (2nd quarter 1998 $/ft2) FOR SELECTED MATERIALS 

[excerpted from Table 5.8, Chapter 5] 

* *"' *"' "' ... * * *"' * ...... * * ** * *"' * ... * * * * * ... * * * * * * * * * ** * * * * * *"' * * * * * * * * * * *"'"' * * *"' *"'"' * ... * ** ** * * ... * ... "'"' ... "'"'"'"' ............ "'.,."' ... * ... * ... "'"' ...... * ...... "'"' "'* ...... * ... "'"' *"' ... "' ... * * "'"' * ...... "' * * * * * * "'"' * ... "'"' * * * * * * * ... * * * **>!:>I<  ... **  >I< ... *

Mech. Bag Diam. (in.) Polyethylene Polypropylene Nomex Homo-acrylic Fiberglas Cotton Tell on 

·----------------------------------------------------------------------------- ---------------------------------------------------------

Pulse jet--TR 4.5 to 5.125 0.75 0.81 2.17 1.24 1.92 NA 12.21 

6 to 8 0.67 0.72 1.95 1.15 1.60 NA 9.70 

Pulse jet-BBR 4.5 to 5.125 0.53 0.53 1.84 0.95 1.69 NA 12.92 

6 to 8 0.50 0.60 1.77 0.98 1.55 NA 9.00 

Pulse jet-cart. 4.875 2.95 NA 6.12 NA NA NA NA 

6.125 1.53 NA 4.67 NA NA NA NA 

Sh<lker·strap 5 0.63 0.88 1.61 1.03 NA 0.70 NA 

Shaker-loop 5 0.61 1.01 1.53 1.04 NA 0.59 NA 

Rev. air wirings 8 0.63 !.52 135 NA 1.14 NA NA 

11.5 0.62 NA 1.43 NA 1.01 NA NA 

Rev. nir w/o" 8 0.44 NA 1.39 NA 0.95 NA NA 

11.5 0.44 NA 1.17 NA 0.75 NA NA 
• 

• 

• 

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 PM10. 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 
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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 . 
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Sincerely, 

Edward Wiener 

Environmental Engineer 
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SUNOCO-FRANKFORD 

Tax_ID 

Facility_ID 1551 

Source_ID Source_Name 

70'_Cumene_Oxidizer 

70'_Cumene_Oxidizer 

56'_Cumene_Oxidizer 

56'_Cumene_Oxidizer 

Cumene_Fiash_Column Crude_Acetone_Column 

Multi-purpose_ Column 

Cumene_Recovery_Column 

Acetone_Refining 

AMS_Recovery 

AMS_Recovery 

Phenoi_Product 

Notes 

Phenoi_Product Phenoi_Residue_Stripping_Column Phenoi_Residue_Stripping_Column 

Boiler_#3 

Generic Stack 

2002 Actual Emissions 

Enclosure • 

CALPUFF Visibility Impact Estimates 

November 2006 

CALPUFF' • NWS Platform 

MAX 24-hour Impact versus 

Natural Background - 20% Best Days 

(Deciviews) 

NOx PM10 SOx VOC Class I Area Total S04 N03 PM 10 

20.6 17.4 73.4 brigwild 0.0141 0.0061 0.0057 0.0043 

brigwild 0.0141 0.0061 0.0057 0.0043 

(CALPUFF MMS modeled >90% of emissions in individual stacks: remainder modeled as "generic stack") 

Total for units that meet date requirements 20.6 17.4 73.4 brigwild 0.0281 0.0121 00115 0.0087 

CALPUFF • MM5 P

MAX 24

Natural 

(Decivie

Class I Are Total 

brigwild 0.0265 brigwild 0.0000 

brigw1ld 0.0265