### 1/25/16 CITY OF PH ILADELPHIA 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 an d operates a chemical manufacturing facility located at 4700 Bermuda Street, Phila delphia, 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-em ergency air compressor, distillation columns, condensers, oxidation processes, reactors, phenol an d alpha-methyl styrene loading, and st orage tanks. Control devices include scrubbers, charcoal absorbers, a therma l 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 appli cable 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 speci fied 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, CL 113, 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

### 2 1/25/16 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, co mpressors, 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 boile r 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 oxid ation 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 alph a-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 fo r 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 ar e subject to and comply with 25 PA Code Section 129.56 or 129.57, whic h is the applicable VOC CTG RACT regulation.

VI. Fugitive Emission Sources (Equipment Leaks): Fugitiv es from processes associated with synthetic chemical manufacturing are applicab le to the Leak Detection and Repa ir (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 sh all 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-Stat ionary Sources

### 3 1/25/16 The 140 HP air compressor is a portable unit that is re quired 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 no t 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. Du e 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, Honeyw ell 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 sour ces 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 dete rmination, 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 de termination, 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 Co nditions 2A and 3A of the SIP-approved 1-hour RACT plan approval for Boilers #1 & #2:

- During the period of May 1 st through September 30 th , 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 n o n

- f o s s i l f u e l ) 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:

### 4 1/25/16 Improved efficiencies at the facility ha ve reduced the amount of waste phenol re sidue produced, making it harder for the facility to meet the 51% minimum annual heat inpu t 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 C ity 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 th e boilers if they were not allowed to burn No. 6 oil and there was not a sufficient supply of wa ste 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 pr ograms 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 A pproval 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 c ould 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 comb ination 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) 1,161,576 1 2,277,600 2

### 5 1/25/16 Waste Phenol NOx Emision Factor (lbs/MMBTU) 0.28 3 0.28

Waste Phenol NOx Emissions (tpy) 162.6 318.9 Heat Input Capacity for No. 6 Oil (MMBTU/yr) 1,116,023 1 0 2

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 partic ular 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 co mbined NOx restriction. The combined NOx emissions limit for Boilers #1 and #2 is more stringent and would not allow this level of emissions.

5 Represents the 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). Duri ng 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 residu e, or a combinatio n 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 calculatio ns to clearly demonstrate that the requirements of §129.91-129.94 are met. These shall include:

### 6 1/25/16 (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 technologi es 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 placemen t of the catalyst difficult and makes it difficult to ma intain 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 comple te 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 NO

x 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 NO

x per MMBtu while burning No. 6 fuel oil; and (3) The combined NO

x 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:

### 7 1/25/16  Boiler #3: Honeywell shall maintain and operate the low NO X 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, whic h 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 us ed to reduce the flame temp erature, thereby reducing
the formation of thermal NO

x , it is not effective in reducing fuel NO

x formation. Water/steam injection is generally not employed in boilers because of a direct reduction in thermal effi ciency and greater losses from the stack resulting from increase in moisture conten t 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 temper ature for acceptable steam generation to prevent process upset. Furthermore, it is not effective in reducing fuel NO

x 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 o F, 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 tech nologically 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 es timated 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 determ ined 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 emissi on 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 emi ssions 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 lb s/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 NO

x 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 Recommendation s 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 NO X 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.

### 9 1/25/16 6 oil.

 Honeywell shall perform, at a minimum, the annual co mbustion 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 calcula tions to clearly demonstrat e 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 / 2 5 / 1 6

Edward Wiener, Chief of Source Registration Date



### Appendix

Detail Calculations Summary for Boiler #3

The following costs are calcula ted in order to evaluate the cost effectiv eness 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 (p resent 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 Ra te; n= control system lif e; Annual Cost = TCI x CRF

### 10 1/25/16 

### For the SCR Catalyst, The catalyst life is 5 year s. The annual cost is given by the sinking fund factor, the amount of money the fac ility will need to set aside each year to be able to replace the catalyst at the end of its life, based on the li fespan of the catalyst a nd the interest rate. Sinking Fund Factor (SFF) = Convert from F (Futur e) 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

2NH 3 

### + 2NO + 1/2O 2 

### 2N 2 

### + 3H 2 

### O

Ammonia Cost = (17/30 * 2moles of NH 3 /2 moles of NO *1.05 * NOx emission (tpy) *$410/ton x 1.55 (price escalation from 1999 to 2014)

NH 3 = Ammonia, NO = Nitric Oxide; O 2 = Oxygen; H 2 O = 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 Cost 2 $70,080 100kw @ $0.08/kwh, 8760 hrs/yr (PA DEP RACT State Implementation Plan (SIP) revision, Sep, 2006, page 18)

Maintenance 3 $80,121.00 1.5%*TCI

Ammonia 3 $189,288 17/30 * 2moles of NH 3 /2 moles of NO *1.05 * NOx emission (tpy) *$410/ton*1.55 Catalyst Cost 3 190,000 0.1638 Sinking Fund Factor

Annual Catalyst Replacement Cost I= 10%, n=5yrs 3 31,122 I= 10%, n=5yrs

Total Direct Annual
Cost $370,611

Indirect Annual Cost

Total Indirect Annual
Cost 3 $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 includesequipment 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% -OAQPS 1 A/P=0.1993

Annual Operating Costs

Direct Annual Cost

### 12 1/25/16 Electricity Cost 3 $70,080 100kw @ $0.08/kwh, 8760 hrs/yr

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

Supervisor 3 $2,463.75 15% of Operator

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

Material 3 $19,162.50 100% of Maintenance

Total Direct Annual Cost $127,294

Indirect Annual Cost

Overhead 3 $11,498 60% of maintenance-OAQPS 1

Administrative Charge 3 $472,420 2% of TCI-OAQPS 1

Property Taxes 3 $236,210 1% of TCI-OAQPS 1

Insurance 3 $236,210 1% of TCI-OAQPS 1

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 1 Office of Air Quality Planning an d 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 3 Cost calculations for each elements are from references: North East States for Coordinated Air Use Management

(NESCAUM), EPA' s Office of Air Qua lity 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 Po llution 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)