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CITY OF PHILADELPHIA

Department of Public Health 

Environmental Protection Division 

Air Management Services 

InterOffice Memo 

To: File 

From: Kassahun Sellassie 

Date: January 25, 2016 

Subject: 1997 8-Hour RACT Analysis for Honeywell International, Frankford Plant 

Introduction: 

The Clean Air Act (CAA) requires that moderate (or worse) ozone nonattainment areas implement reasonably 

available control technology (RACT) controls on all major sources of Volatile Organic Compounds (VOC) and 

Nitrogen Oxides (NOx). Philadelphia County is part of the Philadelphia-Wilmington-Atlantic City moderate ozone 

nonattainment area for the 1997 8-hour ozone NAAQS. This document presents the findings of a RACT evaluation 

for the 1997 8-hour ozone standard for this facility. 

Company Description: 

Honeywell International (formerly Sunoco Chemical) – Frankford Plant owns and operates a chemical 

manufacturing facility located at 4700 Bermuda Street, Philadelphia, PA 19137-1193. The facility’s air emissions 

sources include two 260 MMBTU/hr boilers, one 381 MMBTU/hr boiler, one (1) 50 HP boiler, six (6) emergency 

generators, two (2) emergency fire pumps, one (1) non-emergency air compressor, distillation columns, condensers, 

oxidation processes, reactors, phenol and alpha-methyl styrene loading, and storage tanks. Control devices include 

scrubbers, charcoal absorbers, a thermal oxidizer, and four catalytic oxidizers. 

Applicability for NOx and VOC RACT: 

Honeywell is a major source of NOx due to having potential NOx emissions greater than 100 tons per year, the 

major source threshold in Philadelphia County that is applicable to NOx RACT. This facility is also a major source 

of VOC having potential VOC emissions greater than 50 tons per year, the major source threshold in Philadelphia 

County that is applicable to VOC RACT for the 1997 8-hour ozone NAAQS. The facility is a 1-hour RACT source 

and case-by-case RACT was determined for certain emissions units as specified in RACT permit (PA Permit 

Number 51-1551) dated July 27, 1999, and approved into the SIP by EPA on 10/30/2001 (66FR 54710). 

Process Descriptions: 

I. Boilers 

(1) Boiler #1: 260 MMBTU/hr, firing waste phenol residue, gas or #6 fuel oil 

(2) Boiler #2: 260 MMBTU/hr, firing waste phenol residue, gas or #6 fuel oil 

(3) Boiler #3: 381MMBTU/hr, firing gas or #6 fuel oil only 

(4) Boiler at barge loading facility: 50 HP (below 20 MMBTU/hr), firing #2 fuel oil. - 

II. Oxidation Processes: OX-501, OX-401, OX-301/302, OX-201/202. These units are used to 

manufacture synthetic organic chemicals. 

III. Distillation Columns: CL-101, CL-111, CL-112, CL113, CL-114, CL-120, CL-121, CL-200, CL-201, 

CL-203, CL-204, CL-205, CL-206, CL-208, CL-220, CL-300, CL-301, CL-302, CL-303, CL-304, CL305, CL-306, CL-308, CL-601, PF-201, PF-301. These units are used to manufacture synthetic organic 

chemicals. 

IV. Reactors: Decomposer Reactor:VT-208 and VT-307, Springer Reactor: VT-612, pH adjustment 

Reactor:VT-613, Plug Flow Reactors:PFR-1, PFR-2, PFR-3. These units are used to manufacture 

synthetic organic chemicals. 

V. Barge Loading 

VI. Tank Truck, Rail Car, and Drum Loading 
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VII. Storage Tanks: VT-609, VT-610, VT-332, VT-629, VT-630, VT-504, VT-119, VT-243, VT-117, VT-129, 

VT-131, VT-133, VT-229, VT-354, VT-355, VT-633, VT-234, VT-001, VT-002, VT-119, VT-121, 

VT-142, VT-143, VT-148, VT-229, VT-243, VT-244, VT-248, VT-248A, VT-249, VT-250, VT-332, 

VT-335, VT-650, VT-609, VT-610, VT-614, VT-617, VT-635, VT-610 

VIII. Fugitive Emission Sources: pumps, valves, flanges, compressors, pressure relief valves, and rupture disks 

IX. Rail Car Cleaning 

X. Wastewater Facilities 

XI. Emergency Generators (6) and Diesel Pumps (2): Each burns diesel. 

XII. Portable Air Compressor: 140 HP, burns diesel. 

RACT Analysis: 

Presumptive or CTG RACT requirements 

The following emissions units are subject to presumptive or CTG RACT requirements

I. Barge Loading Facility Boiler: The boiler at the barge loading facility is complying with presumptive 

RACT requirements of PA 129.93(c). This boiler has a capacity of less than 20 MMBTU/hr. 

II. Oxidation Processes: These reactors shall be compliance with the regulation AMR V Section XVI (the 

VOC CTG for SOCMI). All VOC emissions for each oxidation process shall be controlled by an overall 

control efficiency of 98% or maintain a Total Resource Effectiveness (TRE) > 1. These are SOCMI 

sources use for cumene oxidation use for phenol, acetone, and alpha-methyl styrene production. 

III. Distillation Columns: These distillation columns shall be compliance with the regulation AMR V Section 

XVI (the VOC CTG for SOCMI). All VOC emissions for each distillation column shall be controlled by 

an overall control efficiency of 98% or maintain a TRE > 1. These are SOCMI sources use for phenol, 

acetone, and alpha-methyl styrene production. 

IV. Reactors: These Reactors shall be compliance with the regulation AMR V Section XVI (the VOC CTG 

for SOCMI). All VOC emissions for each reactor shall be controlled by an overall control efficiency of 

98% or maintain a 

TRE > 1 or operate with a vent stream flow rate less than 0.011 scm/min. These are SOCMI sources use 

for phenol, acetone, and alpha-methyl styrene production and decomposition. 

V. Storage Tanks: Besides storage tanks VT-609 and VT-610, all storage tanks are subject to and comply 

with 25 PA Code Section 129.56 or 129.57, which is the applicable VOC CTG RACT regulation. 

VI. Fugitive Emission Sources (Equipment Leaks): Fugitives from processes associated with synthetic 

chemical manufacturing are applicable to the Leak Detection and Repair (LDAR) requirements of the 

CTG regulation 25 Pa Code Section 129.71. Other fugitives are applicable to the LDAR requirements of 

the CTG regulation AMR V Section XIII (B). 

VII. Emergency Generators and Fire Pumps: Each unit shall be in compliance with the presumptive RACT 

requirements of 25 Pa Code Section 129.93(c)(5), which requires each to be installed, maintained, and 

operated in accordance with manufacturers specifications. Each unit is limited to operating less than 500 

hours per rolling 12-month period, as approved in Title V/State Operating Permit No. V95-047 for the 

emergency generators and Installation Permit Nos. 12095 & 12096 dated 8/22/12 for the emergency fire 

pumps. 

De Minimis Emissions Sources 

The following are considered sources with de minimis emissions of VOC, for which RACT will not be further 

evaluated: 

I. Truck, Rail, and Drum Loading: Truck, rail and drum loading at Honeywell are considered to be de 

minimis VOC sources. The VOC PTE for these processes is 1.6 tons per rolling 12-month. Adding 

controls to a source with this emission level is economically unreasonable. 

Other:- Non-Stationary Sources 
3    1/25/16

The 140 HP air compressor is a portable unit that is required by a permit condition in Installation Permit No. 

12016A to meet the definition of a nonroad engine 40 CFR 89.2, which includes not remaining at a location for 12 

consecutive months for a source that is not seasonal. It is not a stationary source under Federal regulations and is 

therefore not applicable to RACT. 

Case-by-Case RACT Analysis 

Barge Loading 

As approved in the 1-hour RACT determination, Honeywell shall not load any VOC with a vapor pressure in excess 

of 1.5 psia at 20 degrees Celsius without Air Management Services (AMS) approval. Due to the fact that the VOC 

potential to emit (PTE) for this unit is 4.2 tons per rolling 12-months, AMS determines that this is a de minims 

emission source that does not require further evaluation. AMS determines that the 1-hour RACT continue to 

represent RACT for the 1997 8-hour ozone standard. 

Storage Tanks VT-609 and VT-610

As approved in the 1-hour RACT determination, Honeywell shall install and maintain internal floating roofs on 

tanks VT-609 and VT-610. These tanks store phenol and wastewater which has a vapor pressure of less than 1.5 psi. 

AMS determines that these are de minimis emission sources that do not require any further evaluation. AMS 

determines that the 1-hour RACT continue to represent RACT for the 1997 8-hour ozone standard. 

Rail Car Cleaning 

As approved in the 1-hour RACT determination, rail car cleaning emissions shall not exceed 2.7 tons per rolling 12-

month period. AMS determines that this is a de minims emission source that does not require further evaluation. 

AMS determines that the 1-hour RACT continue to represent RACT for the 1997 8-hour ozone standard.

Wastewater Facilities 

As approved in the 1-hour RACT determination, the thermal oxidizer will control VOC emissions from the air 

stripper at the wastewater facility and will have destruction efficiency not less than 95%. This requirement has been 

approved as RACT in the 1-hour RACT determination. Due to the fact that the VOC PTE for this unit is 1.6 tons per 

rolling 12 –month period, AMS determines that this is a de minims emission source that does not require further 

evaluation. AMS proposes that the 1-hour RACT continue to represent RACT for the 1997 8-hour ozone standard.

Boilers #1 and #2 

Units Description: 

Boiler #1: 260 MMBTU/hr, firing waste residue, gas or #6 fuel oil 

Boiler #2: 260 MMBTU/hr, firing waste residue, gas or #6 fuel oil 

The following case-by-case requirements are contained in Conditions 2A and 3A of the SIP-approved 1-hour RACT 

plan approval for Boilers #1 & #2: 

- During the period of May 1st through September 30th, Boiler #1 and #2 shall only burn natural gas and 

waste phenol residue except if there is a natural gas emergency. An emergency may include natural gas 

curtailment due to supply line failure into the plant or cases of a required environmental compliance-testing 

program. During such emergencies, #6 fuel oil may be used. 

- Honeywell shall operate Boilers #1 and #2 on phenol residue (a non-fossil fuel) at 51% or greater annual 

heat input based on BTU value. Boiler #1 and #2 each has a NOx emission limitation not to exceed 0.35 

pounds of NOx per MMBTU, and a combined NOx emissions limitation not to exceed 272 tons per year. 

- Honeywell shall perform, at a minimum, the annual combustion tuning specifications as cited in 25 PA 

129.93(b)(2) through (5). 

Source Modification: 
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Improved efficiencies at the facility have reduced the amount of waste phenol residue produced, making it harder for 

the facility to meet the 51% minimum annual heat input requirement from this fuel. As a result, Honeywell 

requested changing the condition to be able to burn waste phenol residue and natural gas combined in order to meet 

the 51% or greater limit and, when natural gas curtailments and test programs occur, #6 fuel oil could use up to 

49%. 

Under the Second Amendment to a Consent Decree between EPA, several states, the City of Philadelphia, and 

Sunoco, Inc. (Civil Action No.05-02866), Honeywell (at that time Sunoco Chemicals, which had common 

ownership with Sunoco, Inc.) was required to eliminate fuel oil burning in Boilers #1 and #2, except during natural 

gas curtailments, losses of supply, and during stack test programs. 

Under this amendment to the Consent Decree, oil usage was allowed during natural gas curtailments or other supply 

losses because it could significantly curtail or shut down the boilers if they were not allowed to burn No. 6 oil and 

there was not a sufficient supply of waste phenol residue at the time. This would cause the operation of the entire 

plant to be severely curtailed or shut down. 

Under this amendment to the Consent Decree, oil usage was allowed during stack test programs because it creates a 

larger range of emissions, which allows for better verification of CEMS performance during Relative Accuracy Test 

Audits (RATAs) and better combustion tuning. Better CEMS performance improves the monitoring of emissions 

and better combustion tuning helps reduce emissions. 

Because of the above items, Plan Approval No. 07163 dated January 23, 2013 was issued. The first two 

paragraphs of Condition 2A of the 1-hour RACT plan approval (the first two bullet points above) were 

replaced by the following: 

‐ Boiler #1 and Boiler #2 shall only burn natural gas and waste phenol residue except if there is a 

natural gas curtailments and other losses of supply (e.g. PGW supply line failure or maintenance 

activity) or during stack testing programs (e.g. annual CEM RATA testing, annual combustion 

tuning, and combustion performance testing, as required). During such events, No. 6 fuel oil may 

be used.

These modifications were never incorporated into the SIP. 

Proposed Modifications to the 1-hour RACT SIP

Based on a statistical analysis of CEM data from 1/1/13 through 11/1/14 and noting NOx emissions as high as 0.26 

lbs/MMBTU, AMS determined that Boilers #1 and #2 could meet a NOx emission limit of 0.28 lbs/MMBTU on a 

rolling 30-day average during normal operation (while burning natural gas, waste phenol residue, or a combination 

of the two) under their existing technologies. Thus, AMS has determined this NOx emission limit to be RACT for 

each boiler for burning natural gas, waste phenol residue, or a combination of the two fuels. AMS is also proposing 

to keep the existing 0.35 lbs/MMBTU limit for each boiler to apply when burning no. 6 oil. 

 

The limitation that only allows burning No. 6 oil during times of natural gas supply loss is more stringent than the 

implied maximum 49% No. 6 oil requirement from Plan Approval No. 07163. Additionally, AMS is removing the 

minimum 51% phenol waste limit from RACT and, for the reason mentioned above, is not replacing it with the 

maximum of 49% No. 6 oil limit in Plan Approval No. 07163. Because of the restriction on No. 6 oil use, residual 

phenol waste will be replaced with natural gas in all but limited occasions. CEMS data has shown lower emissions 

from burning natural gas than burning waste phenol residue, over 30% lower during a one-month sample period. 

The calculations provided below compare the 1-hour RACT and 8-hour RACT potential emissions and show that 

these modifications will result in the same level of emissions (in terms of NOx PTE) due to the existing combined 

annual NOx limit of 272 tpy for these boilers. 

Emission Comparison between the 1 – hour RACT and the proposed modification (8-hour RACT) for Boiler #1 and 

Boiler #2(each boiler)

 1-hour RACT 8-hour RACT Change 

Heat Input Capacity (MMBTU/hr) 260 260 

Heat Input Capacity (MMBTU/yr) 2,277,600 2,277,600 

Heat Input Capacity for Waste 

Phenol (MMBTU/yr) 

1,161,5761 2,277,6002
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Waste Phenol NOx Emision Factor 

(lbs/MMBTU) 

0.283 0.28 

Waste Phenol NOx Emissions (tpy) 162.6 318.9 

Heat Input Capacity for No. 6 Oil 

(MMBTU/yr) 

1,116,0231 02

No. 6 Oil NOx Emission Factor 

(lbs/MMBTU) 

0.35 0.35 

No. 6 Oil NOx Emissions (tpy) 195.3 0 

Max. NOx Emissions per Boiler 

(tpy)4 

357.9 318.9 

NOx PTE (tpy)5 272 272 0 

1

Under 1-hour RACT, the worst-case emission scenario is burning 51% waste phenol and 49% No. 6 oil. 

2

Under 8-hour RACT, the normal worst-case emission scenario is burning 100% waste phenol. No. 6 oil can be 

burned during gas interruptions and testing programs, but would not increase the PTE due to the combined NOx 

limit for the boilers. 

3

This is not a Federally enforceable emission limit for waste phenol under 1-hour RACT, but represents the worstcase waste phenol emissions rate expected for this particular fuel. Based on the 1-hour RACT permit, the facility 

was allowed to emit up to 0.35 lbs/MMBTU of NOx form waste phenol burning. 4

Assumes emissions per boiler, without considering the combined NOx restriction. The combined NOx emissions 

limit for Boilers #1 and #2 is more stringent and would not allow this level of emissions. 

5

Representsthe combined NOx emission limit of 272 tpy for Boilers #1 and #2. 

The table shows there is no change in potential NOx emissions for these boilers. 

AMS is making the following changes to the 1-hr RACT determination for Boilers #1 and #2: 

The first two paragraphs of Condition 2A of the 1 hr RACT plan approval will be replaced by the 

following: 

 Boilers #1 and #2 shall only burn natural gas and waste phenol residue except if there is a natural 

gas curtailment, other loss of supply (e.g. PGW supply line failure or maintenance activity), or 

during stack testing programs (e.g. annual CEM RATA testing, annual combustion tuning, and 

combustion performance testing, as required). During such events No. 6 fuel oil may be used. 

Boiler #3 shall only burn natural gas and waste phenol residue except if there is a natural gas 

curtailment, other loss of supply, or during stack testing programs. During such events No. 6 fuel oil 

may be used. 

Condition 4A will be modified by revising the language below: 

 The emission rates for Boilers #1 and #2 

(1) Shall not exceed 0.28 pounds of NOx per MMBTU each, on a rolling 30-day average, while 

burning natural gas, waste phenol residue, or a combination of these fuels; 

(2) Shall not exceed and 0.35 pounds of NOx per MMBTU each while burning No. 6 oil; 

(3) The combined NOx emissions for Boiler #1 and Boiler #2 shall not exceed 272 tons per year. 

For clarity, the Boiler #3 emission limits will be moved to a new Condition 4B: 

 The emission rate of Boiler #3 shall not exceed 0.12 pounds of NOx per MMBTU on a rolling 30-

day average while burning natural gas or 0.3pounds of NOx per MMBTU while burning No. 6 oil. 

Testing, Monitoring, and Recordkeeping: Condition 7.B has been modified as follows (wording in bold 

underlined was added to the existing condition): 

B. The records shall provide sufficient data and calculations to clearly demonstrate that the requirements of 

§129.91-129.94 are met. These shall include: 
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(1) Continuous nitrogen oxides and oxygen monitor records for Boiler # 1, Boiler #2, and Boiler #3. 

(2) Fuel type and monthly fuel usage. 

(3) Monthly records demonstrating compliance with the combined tons per year NOx limit for Boilers 

#1 and Boiler #2 in Condition 4.A. 

(4) Records of each time No. 6 oil is burned and the reason why. 

8-hour RACT

AMS is evaluating other control technologies that could further reduce NOx emissions from Boilers #1 and #2 as 

RACT. The following NOx control technologies were evaluated for case-by-case RACT. 

 Selective Catalytic Reduction (SCR) 

 Selective Non-Catalytic Reduction (SNCR) 

 Low-NOx Burners (LNB) 

 Ultra Low NOx Burner (ULNB) 

 Fuel Switching 

 Flue Gas Recirculation (FGR) 

 Staged Combustion Air (SCA) 

Boiler #1 and Boiler #2 are each subject to a Carbon Monoxide (CO) emission limit of 100 ppm per EPA’s 

requirement in 40 CFR 63.1217(a) of the Hazardous Waste Combustor MACT regulation (40 CFR 63 Subpart 

EEE). This impacts the technological feasibility of some of the NOx control technologies. 

The following technologies were considered technologically infeasible: 

 SCR – There is not enough room in the boiler house to house an SCR unit capable of treating the flue gas 

for the boilers. There are also concerns that frequent load swings and low load operation (10-15% capacity 

for significant periods) makes placement of the catalyst difficult and makes it difficult to maintain a proper 

ammonia injection rate for the varying NOx emission levels. 

 SNCR – Load and NOx concentration variations with the boilers makes placement of the SCNR difficult 

and makes it difficult to maintain a proper ammonia injection rate. 

 ULNB, LNB, FGR & SCA – All of these technologies make it difficult to comply with the existing 100 

ppm CO limit. A representative from boiler manufacturer Babcock & Wilcox also expressed concern that 

these technologies would likely result in less complete combustion of the phenol residue. As required, 

Honeywell needs all burners in these boilers to be able to burn waste phenol residue, so it is not 

technologically feasible to compartmentalize burners and install these controls only for gas or oil burning. 

 Fuel Switching – The facility has already eliminated No. 6 oil burning under most situations. Eliminating 

waste phenol burning would have a harmful effect on the facility’s management of waste phenol residue 

and the overall operation of the facility. 

None of these technologies were considered technologically feasible. Thus, no additional controls are determined 

as RACT for Boilers # 1 and 2. 

Therefore, AMS determines that RACT for Boilers #1 and #2 for the 1997 8-hour ozone standard shall be as stated 

previously and summarized as follows: Boilers #1 and #2 shall only burn natural gas and waste phenol residue 

except if there is a natural gas curtailment, loss of supply, or during stack testing programs. In those cases No. 6 

fuel oil may be used. Honeywell shall also install and operate continuous nitrogen oxide and oxygen monitors and 

recorders on both boilers. In addition, RACT shall also include the following emission rates: (1) Boilers #1 and #2 

shall not exceed 0.28 lbs NOx per MMBtu, each, on a rolling 30-day average while burning natural gas, waste 

phenol residue, or any combination of those fuels; (2) Each boiler shall not exceed 0.35 lbs NOx per MMBtu while 

burning No. 6 fuel oil; and (3) The combined NOx emissions from both boilers shall not exceed 272 tons per year. 

Boiler #3 

Unit description: 381MMBTU/hr, firing gas or #6 fuel oil only 

The following case-by-case RACT requirements are contained in Conditions 2A and 3A of the SIP-approved 1-hour 

RACT plan approval for Boiler #3: 
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 Boiler #3: Honeywell shall maintain and operate the low NOX burners installed on Boiler #3 on May 31, 

1995. 

 Boiler #3 shall not exceed 0.3 pounds of NOx per MMBtu. 

 Honeywell shall perform, at a minimum, the annual combustion tuning specifications as cited in 25 PA 

129.93(b)(2) through (5). 

The 1-hour RACT proposal submitted July 1994 by Sunoco Frankford stated that the facility would install LNB and 

“wall ports” (characterized as Overfire Air at the time) on Boiler #3 in order to achieve the NOx RACT limit of 0.3 

lbs/MMBTU. AMS found the RACT proposal was adequate and determined these controls to satisfy RACT under 

the 1-hour ozone NAAQS. However, the RACT permit PA Permit Number 51-1551 dated July 27, 1999 mistakenly 

excluded the requirement to maintain and operate the wall ports as part of the RACT control requirement. AMS 

confirmed that the facility did install the wall ports along with the LNBs back at the time of the 1-hour RACT 

determination and both controls have been operated in order to comply with the NOx RACT limit. 

Under the Second Amendment to a Consent Decree the facility was required to eliminate fuel oil burning in Boiler 

#3, except during natural gas curtailments, other losses of supply, and during stack test programs. AMS is 

incorporating this requirement into the 8-hour RACT for Boiler #3. 

AMS is evaluating additional control technologies that could further NOx emissions from Boiler #3 as RACT. 

Boiler #3, which has a capacity of 381 MMBTU/hr. Boiler #3 has a Low NOx burners and wall ports as well as a 

NOx emission limitation not to exceed 0.3 pounds of NOx per MMBTU. 

The following were considered possible NOx controls for Boiler # 3: 

 Flue Gas Recirculation (FGR) 

 Water/Steam Injection (WI) 

 Staged Combustion Air (SCA) 

 Ultra Low-NO Burners (ULNB) 

 Selective Non-Catalytic Reduction (SNCR) 

 Selective Catalytic Reduction (SCR) and 

 Ultra Low-NO Burners (ULNB) & Flue Gas Recirculation (FGR) 

Detail analysis for each emission control technology as shown below: 

 Flue Gas Recirculation (FGR) – FGR recirculates part of the boiler flue into the main combustion chamber. 

This reduces the peak combustion temperature, which reduces the formation of thermal NOx. Adding FGR 

to the existing burners is considered technically infeasible because they adversely affect the performance of 

older burners. 

 Water /Steam Injection – Water/steam injection is used to reduce the flame temperature, thereby reducing 

the formation of thermal NOx, it is not effective in reducing fuel NOx formation. Water/steam injection is 

generally not employed in boilers because of a direct reduction in thermal efficiency and greater losses 

from the stack resulting from increase in moisture content of the flue gas. It is also unsafe combustion 

conditions result from poor fuel rate control. The boiler configuration fire box does not provide sufficient 

minimum residence time for water injection at the current combustion temperature for acceptable steam 

generation to prevent process upset. Furthermore, it is not effective in reducing fuel NOx formation. For 

No. 6 fuel oil for Boiler #3, water/steam injection is not effective. This method is used in gas turbine, 

reciprocating engines, and other internal combustion engines. This technology is considered technically 

infeasible. 

 Staged Combustion Air (SCA)- Not considered retrofit to package boiler due to installation difficulties. 

This technology is considered technically infeasible.

 Selective Non-Catalytic Reduction (SNCR). This technology is intended for optimum exhaust gas 

temperature range of 1,200 o

F to 2,000 oF, however, the normal operational temperature of Boiler # 3 is 300 o

F. In addition, the residence time for ammonia also becomes a problem since the time required is 3 to 5 

seconds. This technology is considered technically infeasible.

 SCR – This technology considered technically feasible. 

 ULNB + FGR– ULNB is a description sometimes given to burners that emit very low levels of NOx. They 

typically have a longer flame than LNB, which increases the uniformity of temperature and reduces thermal 

NOx emissions. These technologies considered technically feasible.
8    1/25/16

Further Analysis for SCR and ULNB +FGR: 

SCR and ULNB and FGR combined were determined technologically feasible for Boiler No. 3 and a summary of 

the cost-effectiveness for each control option is provided below. The assumed NOx emissions baseline for Boiler 

#3 when burning No. 6 oil is 500.6 tons per year (tpy) and was determined based on the rated capacity of 381 

MMBTU/hr, operating for 8,760 hours per year, with the 0.3 lbs/MMBTU NOx RACT emission limit (this is the 

worst case scenario, assuming natural gas is interrupted for the entire year). AMS finds that both control options 

are economically unreasonable as estimated below for number 6 oil burning. For more detailed calculations, 

please see the Appendix. 

Source Control 

Technology 

Baseline NOx 

Emissions (tpy) 

NOx 

Reduction (%) 

NOx Reduction 

(tpy) 

Total 

Annualized 

Cost 

Cost 

Effectiveness 

($/Ton) 

Boiler #3 SCR 500.6 80 400 $2,499,693 $6,249 

ULNB +FGR 500.6 45 225 $5,791,297 $25,739 

After reviewing CEMS data for Boiler #3, AMS has determined that the 0.3 lbs/MMBTU NOx emission limit is still 

appropriate as RACT for Boiler #3 under existing technology (LNB and wall ports) while burning No. 6 oil. AMS 

has determined that Boiler #3 can achieve a NOx emission limit of 0.12 lbs/MMBTU on a rolling 30-day average 

when burning natural gas, based on the existing technology. This NOx limit in addition to the restriction for burning 

No. 6 oil will result in additional reductions of NOx emissions for Boiler #3. For cost-effectiveness purposes, AMS 

notes that if the assumed emissions baseline was based on the natural gas NOx emissions rate of 0.12 lbs/MMBTU, 

the cost effectiveness in $/ton would double. All of these control options have been determined economically 

unreasonable for Boiler #3. 

Thus, for Boiler #3, AMS determines that RACT for the 1997 8-hour ozone standard shall be the following emission 

limits: For No. 6 oil – not to exceed 0.3 lbs/MMBtu; for natural gas – 0.12 lbs/MMBtu on a rolling 30-day average. 

In addition, Honeywell shall install and operate continuous nitrogen oxide and oxygen monitors and recorders. AMS 

is amending the RACT permit to specify the existing control requirement to maintain and operate the low NOx

burners and wall ports. AMS finds that the existing RACT requirement to perform annual combustion tuning should 

still continue to meet RACT under the 1997 8-hour ozone standard. 

Conclusions and Recommendations for Boilers #1, #2, and #3: 

AMS determines 1-hour RACT plus the modifications described above as NOx RACT for the 1997 8-hour ozone 

standard for Honeywell Boilers #1, #2, and #3. This includes the following requirements: 

 Boilers #1 and #2 shall only burn natural gas and waste phenol residue except if there is a 

natural gas curtailments and other losses of supply (e.g. PGW supply line failure or 

maintenance activity) or during stack testing programs (e.g. annual CEM RATA testing, annual 

combustion tuning, and combustion performance testing, as required). During such events No. 6 

fuel oil may be used. Boiler #3 shall only burn natural gas except if there is a natural gas 

curtailment, other loss of supply, or during stack testing programs. During such events No. 6 

fuel oil may be used. 

 Boiler #3: Honeywell shall maintain and operate the low NOX burners and wall ports on Boiler #3. 

 The emission rates for Boilers #1 and #2 

(1) Shall not exceed 0.28 pounds of NOx per MMBTU each, on a rolling 30-day average, 

while burning natural gas, waste phenol residue, or a combination of these fuels; 

(2) Shall not exceed and 0.35 pounds of NOx per MMBTU each while burning No. 6 oil; 

(3) The combined NOx emissions for Boiler #1 and Boiler #2 shall not exceed 272 tons per 

year. 

 The emission rate of Boiler #3 shall not exceed 0.12 pounds of NOx per MMBTU on a rolling 

30-day average while burning natural gas or 0.3pounds of NOx per MMBTU while burning No. 
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6 oil. 

 Honeywell shall perform, at a minimum, the annual combustion tuning specifications as cited in 25 PA 

129.93(b)(2) through (5) for Boilers #1, #2, and #3. 

 Continuous nitrogen oxides and oxygen monitors and recorders shall be operated on Boiler # 1, Boiler 

#2, and Boiler #3 in order to measure and record the concentrations of these gases emitted from the 

boiler stack. 

 The records shall provide sufficient data and calculations to clearly demonstrate that the requirements 

of §129.91-129.94 are met. These shall include: 

o Continuous nitrogen oxides and oxygen monitor records for Boiler # 1, Boiler #2, and Boiler 

#3.

o Fuel type and monthly fuel usage. 

o Monthly records demonstrating compliance with the combined tons per year NOx limit for 

Boiler #1 and Boiler #2 in Condition 4.A. 

o Records of each time No. 6 oil is burned in Boilers #1, #2, or #3 and the reason why. If the 

reason is gas curtailment or other loss of supply, it shall be reported to AMS. 

1/25/16

Edward Wiener, Chief of Source Registration Date 

Appendix 

Detail Calculations Summary for Boiler #3 

The following costs are calculated in order to evaluate the cost effectiveness of each emission control technology: 

‐ Total Capital Investment (TCI) 

‐ Direct Annual Cost (DAC) ($/yr) 

‐ NOx Emission Reduction (tons/yr) 

‐ Cost Effectiveness ($/ton) 

o Capital Recovery = Convert from P (present Value) to A(Annual amount), 

A=P(A/P,i%,n), (1 ) 1

(1 )

 

  n

n

i

i i CR 15% interest and 10 yrs = A/P=0.1993 

Where i= Annual interest Rate; n= control system life; Annual Cost = TCI x CRF 
10    1/25/16

For the SCR Catalyst, The catalyst life is 5 years. The annual cost is given by the sinking fund 

factor, the amount of money the facility will need to set aside each year to be able to replace the 

catalyst at the end of its life, based on the lifespan of the catalyst and the interest rate. 

Sinking Fund Factor (SFF) = Convert from F (Future) to A(Annual amount), A=F(A/F,i%,n), 

(1 ) 1  n i

i SFF 10% interest and 5 yrs = A/F=0.1638 

Where i= Annual interest Rate (10%); n= catalyst system life (5 years); 

Catalyst Annual Cost = SFF x Catalyst Cost 

2NH3 + 2NO + 1/2O2 2N2 + 3H2O 

Ammonia Cost = (17/30 * 2moles of NH3/2 moles of NO *1.05 * NOx emission (tpy) *$410/ton x 1.55 (price 

escalation from 1999 to 2014) 

NH3 = Ammonia, NO = Nitric Oxide; O2 = Oxygen; H2O = Water; 1.05= 5% of Ammonia slip & waste Ammonia 

Honeywell Boiler #3 

Table 1 Detail Calculations for Honeywell Boiler #3 SCR 

BOILER # 3 381 MMBTU/hr 

 Total capital Cost

Total Capital Investment 

Cost (TCI) 

$5,341,400 3,142,000 TCI from the January 2007 Best Available Retrofit 

Technology (BART) submittal plus inflation adjustment 

to 2014 US dollars. The TCI includes equipment cost 

estimates from vendor-supplied estimates for similar units 

or industry data gathered for similar projects. This was 

used because it is similar to RACT analysis and it is more 

recent. See Attachment A, which includes the relevant 

cost information from the BART submittal. 

Capital Recovery $1,064,541 0.1993 10 yrs @15% - A/p=0.1993

 

Annual Operating 

Costs 

 

Direct Annual Cost 
11    1/25/16

Electricity Cost2 $70,080 100kw @ $0.08/kwh, 8760 hrs/yr (PA DEP RACT State 

Implementation Plan (SIP) revision, Sep, 2006, page 18) 

Maintenance3 $80,121.00 1.5%*TCI 

Ammonia3 $189,288 17/30 * 2moles of NH3/2 moles of NO *1.05 * NOx 

emission (tpy) *$410/ton*1.55 

Catalyst Cost3 190,000 0.1638 Sinking Fund Factor 

Annual Catalyst 

Replacement Cost I= 

10%, n=5yrs3

 

31,122 I= 10%, n=5yrs 

Total Direct Annual 

Cost 

$370,611 

 

Indirect Annual Cost 

 

Total Indirect Annual 

Cost3

$1,064,541 CFR x TCI 

 

Total Annual 

Operating Costs 

$2,499,693 

 

NOx Emission 

Reduction (TPY) 

400 

Cost Effectiveness 

($/ton NOx removed) 

$6,249 

Table 2 Detail Calculations for Honeywell ULNB + FGR 

Boiler #3 381 MMBTU/hr 

 Total capital Cost 

Total Capital Investment Cost 

(TCI) 

$23,621,000 TCI from the 2006 Best Available Control 

Technology (BART) submittal plus 

inflation adjustment. The TCI includes 

equipment cost estimates from vendorsupplied estimates for similar units or 

industry data gathered for similar projects. 

This was used because it is similar to 

RACT analysis and it is more recent. See 

Attachment A, which includes the relevant 

cost information form the BART submittal. 

Capital Recovery $4,707,665 0.1993 10 yrs @15% -OAQPS1 A/P=0.1993 

Annual Operating Costs 

Direct Annual Cost 
12    1/25/16

Electricity Cost3 $70,080 100kw @ $0.08/kwh, 8760 hrs/yr 

Operator3 $16,425 0.5hr/shift, 3 shift/day, $30/hr 

Supervisor3 $2,463.75 15% of Operator 

Maintenance3 $19,162.50 0.5hr/shift, 3 shift/day, $35/hr 

Material3 $19,162.50 100% of Maintenance 

Total Direct Annual Cost $127,294 

Indirect Annual Cost 

Overhead3 $11,498 60% of maintenance-OAQPS1

Administrative Charge3 $472,420 2% of TCI-OAQPS1

Property Taxes3 $236,210 1% of TCI-OAQPS1

Insurance3 $236,210 1% of TCI-OAQPS1

            

Total Indirect Annual Cost $956,338 

 

Total Annual Operating Costs $5,791,297 

NOx Emission Reduction (TPY) 225 

Cost Effectiveness ($/ton NOx 

removed) 

$25,739 

References: 

o 1Office of Air Quality Planning and standards (OAQPS) Environmental Protection Agency (EPA) Air Pollution 

Control Manual, Six Edition, EPA/452/B-02-001, January 2002. 

o 2 Electricity cost: A.1 Vendor Information, A-2 Cost Calculation

o 3Cost calculations for each elements are from references: North East States for Coordinated Air Use Management 

(NESCAUM), EPA' s Office of Air Quality Planning and standards (OAQPS) edition 6, 2002; Cost analysis and 

engineering economics book (Michael R. Lindeburg), from Facility, 1

Office of Air Quality Planning and standards 

(OAQPS) Environmental Protection Agency (EPA) Air Pollution Control Manual, Six Edition, EPA/452/B-02-001, 

January 2002 (page 2-27(2.5.5), I-52 table 1.13, Appendix A) and other States US Bureau of Labor Statics, Cost 

analysis and engineering economics book (Michael R. Lindeburg)