CITY OF PHILADELPHIA

Department of Public Health 

Environmental Protection Division 

Air Management Services 

InterOffice Memo 

To: File 

From: Rahel Gebrekidan 

Date: January 8, 2015 

Subject: RACT Modification Summary for Temple University – Health Sciences 

Campus 

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: 

Temple University – Health Sciences Campus is located at 3401 North Broad Street, 

Philadelphia, PA 19140. The facility’s air emission sources include three 76.4 MMBTU/hr 

boilers, two <2 MMBTU/hr boilers, and 20 emergency generators and fire pumps. The facility 

included a medical waste incinerator, but the unit was removed in 2008. 

Applicability for NOx and VOC RACT: 

Temple University – Health Sciences Campus 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 not a major source of VOC having potential 

VOC emissions less 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 subject to 

RACT under the 1-hour ozone standard, and is subject to a case-by-case RACT determination, as 

approved by EPA into PA SIP on 12/15/00 (65 FR 78418). 

1-hour RACT Determination: 

AMS determined RACT under the 1-hour ozone standard for this facility in 1999. The 

Facility was issued a RACT Plan Approval (Permit ID. 8906) for the 1-hour ozone 

standard in December, 1999, based on the facility’s RACT proposal. AMS’ RACT 

determination and resulting RACT plan approval were approved as part of the PA SIP 

by EPA on 12/15/00 (65 FR 78418). 
2 

Under the 1-hour ozone standard Boilers 1, 2, 3 and a medical waste incinerator are 

subject to NOx RACT The three Central Steam Plant (CSP) Boilers (Boilers 1, 2, and 

3) were originally installed in 1967 and are Keeler CP units with rated heat input of 

76.4 MMBTU/hr; all three boilers share a common stack and are allowed to combust 

both natural gas and #6 fuel oil. As a result of the 1-hour RACT determination, the 

following requirements were approved as RACT: 

 Boiler #2 to utilize flue gas recirculation and low excess air combustion (FGR). 

 Boilers #1 and #3 to have fuel flow governing devices limiting the fuel input to 50 

MMBTU/hr each, making them applicable to the presumptive RACT requirements of 25 

PA Code Section 129.93(b)(2). 

 A medical waste incinerator that was applicable to the presumptive RACT requirements 

of 129.93(c)(4). 

Modification of RACT Sources 

After the 1-hour RACT plan approval was issued, Temple Health discovered that installing the 

FGR was technically infeasible for Boiler #2. The FGR was not possible due to a number of 

issues that were specifically encountered by Temple when attempting to engineer the application 

of FGR on Boiler #2. 

Achieving effective NOx control with FGR requires accurate and repeatable control of 

combustion air temperature and oxygen content. This was not possible with these boilers because 

they are field-erected, balanced draft type with negatively pressurized, cross-drafted furnaces and 

relatively large exhaust breechings. As such, the velocity of the flue gases leaving the boiler is 

very low most of the time. Low flue gas velocity in the breeching causes stratification of 

combustion gases with ambient air which, by design, is drawn in through openings at the front of 

the boiler and across the top of the boiler to purge potentially unburned gases from that otherwise 

stagnant zone (hence the term, “cross-drafted”). This deliberate cross-drafting coupled with the 

leakage of ambient air through the boiler casing and loosely stacked brick refractory walls makes 

repeatable flue gas extraction impossible at anything less than 80% of full load when the flue gas 

velocities are high enough to achieve thorough mixing of the combustion gases with ambient air 

in the breeching (a point that would never be reached as long as all three boilers in the plant are 

available). Combustion air temperature affects air density and, therefore, the air fuel ratio which 

in turn affects boiler efficiency and NOx production. Combustion air temperature on these 

boilers varies due to the fact that combustion air travels from the fan through a waffle-like 

pathway of terracotta blocks under the furnace floor and into a common windbox at the front of 

the boiler where it is drawn through registers into all three burners. At low loads the air’s 

residence time under the furnace floor allows it to pick up enough heat to rise as much as 200 

degrees F in temperature. 

Unfortunately, this temperature change is not consistent or predictable. It varies with outside air 

temperature, boiler load and the length of time that the boiler has been on line and off line. With 

no way to control combustion air temperature, air flow measurement becomes a critical 

requirement for reliable combustion control. 

The boilers presently operate with a single-point positioning system circa 1966 for combustion 

control which would have to be replaced in an FGR retrofit with a fully-metered system using 

direct and continuous measurements of fuel, air and flue gas flow to control combustion. 

However, due to the heating problem cited above, air flow measurement is complicated by the 

variable density of the combustion air. Exacerbating the problem of air flow measurement is the 

boilers’ characteristic, unalterable, low combustion air velocity which makes metering 
3 

instruments that depend on pressure drop, positive displacement or vortex shedders impossible. 

An FGR retrofit on these boilers is also complicated by the fact that all three burners on each 

boiler share a common windbox. Uniform mixing and distribution of the flue gas to each one of 

the three burners cannot be done with a common windbox. The original FGR retrofit designed by 

Benz Air discussed in the 1994 RACT analysis was fatally flawed because it failed to address 

this problem. 

The combined combustion control retrofit, including FGR, proposed in ERM’s 2006 RACT 

analysis (the “X-Plus” system designed by Preferred Utilities) addressed this problem by 

providing two separate windboxes and burners with independent controls. This FGR-capable 

burner design has never been proven in practice with FGR and the vendor readily admits that 

only three or four of these combustion systems have ever been installed, none of which are 

presently using FGR. 

Another reason why an FGR retrofit of these boilers is technically infeasible is acid precipitation. 

Flue gas from #6 oil combustion forms strong acids when the gas temperature falls below the 

dewpoint. Injecting flue gas at the combustion fan (as Benz proposed) would result in acid 

precipitation in the ductwork between the fan and the terracotta airway under the furnace. Even 

stainless steel ductwork and epoxy coatings have failed in a few short years of operation when 

exposed to flue gas acid. Injecting flue gas at the windbox (as in the X-Plus design) avoids the 

problems upstream between the windbox and the fan but does not eliminate windbox corrosion 

and, again, the benefit of this design has never been proven in practice. 

The final reason why FGR is not technically feasible on these boilers is perhaps the most 

significant. These boilers have an unusually short furnace which is why they include three 

burners to spread a broad short flame that does not impinge on the furnace walls. The flame 

pattern with FGR is characteristically elongated, so much so that it would impinge on the boiler 

walls causing high CO emissions, soot buildup and high opacity. 

Based on the significant technical issues in installing a FGR retrofit system on Boiler #2, FGR 

was considered technically infeasible. Temple also had difficulty maintaining the 50 

MMBTU/hr capacity limits on Boilers #1 and #3 due to past and planned future expansion of the 

campus. As a result, Temple proposed to modify the RACT requirements for the boilers in 2008. 

Since Temple Health could not comply with the 1-hour SIP approved RACT for the above 

reasons, the facility proposed the following modifications to address 1-hour RACT. 

1. To replace the requirement for Keeler Boilers #1 and #3 for a fuel governing 

device limiting each boiler to 50 MMBTU/hr with a requirement for Combustion 

Components Associates (CCA) burner modifications for each boiler. 

2. To replace the requirement for Keeler Boiler #2 to utilize flue gas recirculation 

and low excess air combustion with a requirement for CCA burner modifications 

which would achieve the same NOx emission reductions. 

AMS approved these modifications and issued Plan Approval No.05198 dated 04/16/2008 with 

the following requirements: 

1. Nitrogen Oxides (NOx)emissions from each boiler shall not exceed the following 

(a) 0.067 lbs/MMBTU while burning natural gas. 
4 

(b) 0.25 + (0.073059 / X) * (N-0.25), where the NOx limit is 0.25 lb 

NOx/MMBTU for values of N<0.25; while burning No.6 oil 

(c) Nitrogen Oxides (NOx) emissions from Boilers #1, #2, and #3 combined 

shall not exceed 56.3 lbs/hr. 

2. The combined heat input for Boilers #1, #2, and #3 shall not exceed 673,894 

MMBTU per rolling 12-month period. 

3. CCA burner modifications shall be performed on each boiler, including each of the 

following: 

(a) Installation of staged flame stabilizers (a.k.a. swirlers). 

(b) Redesign and replacement of the atomizers. 

(c) Replacement of the center-fired gas injection rings with gas manifolds 

having center-fired and poker gas injection. 

(d) Installation of a NOx tempering system (water injection). 

CCA estimated their burner modifications would reduce the NOx emission rate by around 30%, 

which is comparable to the estimated reductions from FGR (the 2010 Cleaver-Brooks Boiler 

Emission Guide estimates 25-30% NOx reduction for standard fuel oils). Since the 1-hour 

RACT did not have NOx emission limits in lbs/MMBTU, the NOx emission limits were derived 

from AP-42 emission factors and an assumed 30% reduction in NOx emissions, the estimated 

control level of FGR and the CCA burner modifications. The natural gas limit took an AP-42 

emission factor (Section 1.4, Table 1.4-1), reduced it by 30%, and converted it to lbs/MMBTU 

using a standard BTU content of 1,050 BTU/scf for natural gas. The NOx emission limit for oil 

used an AP-42 emission factor that included nitrogen content as a variable (Section 1.3, Table 

1.3-1 footnotes) as a starting point. This was done because nitrogen content affects NOx 

emissions through the conversion of nitrogen in the fuel to NOx emissions during the 

combustion process (known as “fuel NOx”) and the facility cannot control the nitrogen content 

of its No. 6 oil shipments. The formula for the emission limit was determined to be comparable 

to the AP-42 emission factor reduced by 30%, but added a variable for fuel oil BTU content 

instead of relying on a standard value. While this plan approval was issued by AMS, it was 

never incorporated into the SIP. 

Moving forward, AMS is revising the No. 6 oil limitation for each boiler from the 2008 

modification to a NOx emission limit of 0.40 lbs/MMBTU to make it easier to enforce. The 0.40 

lbs/MMBTU limit was determined using the No. 6 oil NOx emission limit formula from Plan 

Approval No. 05198, a nitrogen content of 0.57%, which is the highest historical nitrogen 

content of No. 6 oil for the facility, and a standard No. 6 oil BTU content of 0.15 MMBTU/gal. 

0.40 lb/MMBTU= 0.25+ (0.073059/X*(N-0.25)) 

N=0.57 % 

Temple's historical 

worst-case scenario 

X= 0.15 MMBTU/gal 

The proposed limit of 0.40 lb/MMBTU is based on the correlation of NOx emissions with 

nitrogen content (N) and the BTU content (x) of no. 6 fuel oil, as provided by the facility and 

approved in the 2008 modified Plan Approval. 
5 

As shown in the table below, these boilers have almost exclusively burned natural gas in recent 

years, with No. 6 oil burned on occasions when natural gas is interrupted. These interruptions 

typically occur during cold weather months. From 2011-2013, Boilers #1, #2, and #3 did not 

burn #6 oil during the April 1 through October 31 ozone season. As a result, AMS has 

determined that primarily burning natural gas during the ozone season and burning No. 6 oil only 

when the natural gas supply is interrupted or curtailed shall be NOx RACT for the 1997 8-hour 

ozone standard. This restriction has not been made for outside of the ozone season due to 

periodic spikes in the price of natural gas during cold weather and the negligible risk of 

exceeding the National Ambient Air Quality Standard (NAAQS) for ozone during this period. 

Table 1: Natural Gas vs. No. 6 Oil Usage

2013 2012 2011 2011‐

2013

% Tot.

MMBTU

Boiler

#1

Gas (MMCF) 109.6 219.8 180.7

Gas (MMBTU) 115,080 230,790 189,735 535,605 99.78%

Oil (gal) 2,110 2,180 3,580

Oil (MMBTU) 316.5 327 537 1180.5 0.22%

Total (MMBTU) 536,786

Boiler

#2

Gas (MMCF) 265.6 159.8 159.4

Gas (MMBTU) 278,880 167,790 167,370 614,040 99.85%

Oil (gal) 3,250 1,110 1,770

Oil (MMBTU) 487.5 166.5 265.5 919.5 0.15%

Total (MMBTU) 614,960

Boiler

#3

Gas (MMCF) 178.3 139.4 205.7

Gas (MMBTU) 187,215 146,370 215,985 549,570 99.97%

Oil (gal) 0 280 880

Oil (MMBTU) 0 42 132 174 0.03%

Total (MMBTU) 549,744

*Table uses fuel usage data from AMS’ emission inventory and assumes 1,050 BTU/SCF for 

natural gas and 0.15 MMBTU/gal for No. 6 oil. 

RACT EVALUATION: 

Evaluation of Additional Controls:

In order to determine if the above modifications to the 1-hour RACT determination represent 

RACT for the 1997 8-hour ozone standard, an evaluation of the feasibility of currently available 

controls has been performed for each boiler. 

The control strategies considered for case-by-case RACT analysis will evaluate emissions 

reductions from the installation of additional controls in each of the boilers. To determine the 

cost effectiveness of the technically feasible control options, a cost analysis was conducted and is 

presented below. 

- Selective catalytic reduction (SCR) 

- Selective non-catalytic reduction (SNCR) 

- Combustion System Modifications for Ultra-Low NOx Performance 

- Fuel Switching from No.6 and natural gas to No.2 and natural gas 

- Fuel switching to 100% natural gas only 
6 

Detail analysis for each emission control technology is shown below: 

Selective Catalytic Reduction (SCR):

The HSC-CSP boilers could theoretically be equipped with SCR systems for NOx control; 

however, a number of significant issues would need to be addressed to deem SCR a technically 

feasible alternative. 

There are physical size limitations for the SCR installation for the boilers. Because of the large 

size requirements of an SCR system and the lack of available space in the Central Steam Plant, 

SCR installation would require major modifications to the existing flue and ductwork design. 

The ductwork would need to be directed outside the existing building, where the catalytic reactor 

would theoretically be housed, and then re-directed back inside the building to the downstream 

components. Additionally, any burning particles would have the potential to severely damage the 

catalyst. Finally, new fans to accommodate the greater pressure drop associated with the 

redesigned system would be required. The installation of SCR would impact the efficiency of the 

existing boilers, such that additional fuel would be required in order to achieve the same level of 

steam output currently recognized, in other words there would be an energy penalty associated 

with the use of SCR. In addition, the use of residual fuel oil renders SCR a marginally available 

technology, due to the presence of “soot” in the flue gas which has the tendency to plug the 

catalyst without additional equipment modification. 

Although the space availability in the Central Steam Plant is extremely limited to house an SCR 

unit which would be able to treat the flue gas for the boilers, SCR is considered a technically 

feasible option for the CSP boilers. 

Selective Non-Catalytic Reduction (SNCR)

SNCR systems require relatively high gas operating temperatures. Steady temperatures in the 

range of 1,600 to 2,000°F are required to operate an SNCR system effectively. The Temple 

boilers (as with most commercial boilers) experience variations in load, and therefore 

temperatures will change frequently, making it difficult to maintain temperature ranges suitable 

for an SNCR system. 

An additional concern with the theoretical application of SNCR to the Temple boilers relates to 

ash management. With SNCR, proportionally more ammonia or urea is injected for additional 

NOx control. With excessive ammonia, however, there is a potential for ammonia to condense 

onto to the fly ash. Fly ash contamination severely restricts ash management options. While 

physical size requirements are not as significant a concern with SNCR as compared to SCR, 

there are size limitations that would need to be addressed for the CSP boilers as addressed above 

for the SCR system. As with SCR, the installation of SNCR would impact the efficiency of the 

existing boilers, such that additional fuel would be required in order to achieve the same level of 

steam output currently recognized (i.e., energy penalty). 

SNCR is not considered a technically feasible option for the CSP boilers due to the fluctuating 

temperatures resulting from operation of the boilers, as well as the physical space availability 

constraints to house the necessary components of an SNCR system. 

 

Combustion System Modifications for Ultra-Low/Low NOx burner Performance 

Ultra Low-NOx burners can achieve NOx flue gas concentrations of 9 - 15 ppm through a 

combination of different burner modifications. However; the implementation of ULNB includes 
7 

burner modifications that create a long, lazy flame that increase the uniformity of temperature (to 

reduce thermal NOx) and increase the residence time. The following characteristics of the HSC 

Boilers make the installation of ULNB technically infeasible for these boilers: 

‐ Each of the HSC Boilers is a multi-burner, field-erected, water-tube unit. Through 

research (RBLC) and discussions with multiple boiler industry personnel, there are no 

currently implemented ULNB installations on multi-burner units of their size. In fact, a 

known vendor of ULNB retrofit technologies specifically excludes multi-burner units. 

‐ The construction of the HSC units (water-tube on brick refractory) leaves many areas of 

hot refractory surfaces between and around the tubes, which encourages the formation of 

thermal NOx. This avenue for the formation of thermal NOx cannot be addressed by a 

ULNB installation. 

‐ The upright orientation of the furnace creates an uncommonly short length for the 

furnace, thus, limiting the flame length, and preventing the “lazy” flame shape 

characteristic of low NOx burners. 

‐ ULNB is typically applied to single-burner arrangements on packaged boilers, which 

allow the desired flame length to be achieved. 

In order to attempt to implement ULNB at HSC, very significant modifications to not only the 

existing burners, but also to the windbox, fans, and process control systems would be required. 

Thus, AMS has determined that ULNB is not considered a technically feasible option for the 

CSP boilers. 

Fuel Switching from No.6 fuel oil and natural gas to No.2 fuel oil and natural gas 

In order for the boilers to burn distillate fuel oil (No. 2), each boiler would require a complete 

burner replacement. 

The NOx emission reduction for a given system configuration from #6 fuel oil to #2 fuel oil is 

approximately 65% (#6 Fuel oil at 0.3%-0.4%, #2 Fuel Oil <0.001%). The majority of the NOx 

emissions reduction is due to the reduction in fuel-bound nitrogen. Fuel Switching is considered 

to be a technically feasible option. 

Temple Health also proposed, in the alternative, that during ozone season (April 1 through 

October 31), the facility could use No. 2 fuel oil as a primary fuel with natural gas as a backup 

and during non-ozone season the facility could use No. 6 fuel oil as a primary fuel with natural 

gas as a backup. AMS considered Temple’s alternative but we ultimately rejected the idea 

because of the following reasons: Ozone season lasts a total of 214 days, during the non-ozone 

season Temple can currently use 395,105 MMBTU Natural gas and 278,789 MMBTU #6 fuel oil 

(based on the 673,894 MMBTU/yr limits). When we calculated the emission differences between 

#2 oil and natural gas during ozone season, [Total emission from natural gas = 0.067 lb/MMBTU 

x 395,105 MMBTU/ozone season = 26,472 lbs/ozone season = 13.236 tons/ozone season. Total 

emission from #2 oil = 0.20 lb/MMBTU x 395,105 MMBTU/ozone season= 79,021 lbs/ozone 

season= 39.51 tons/ozone season.] there is a difference of 26.27 tons/ozone season (39.51 tons - 

13.236 ton). This is an increase of NOx emission during ozone season, the peak time of year for 

the formation of ozone. 

Fuel Switching to Only Natural Gas 

As previously discussed, all three boilers already have the ability to burn both natural gas and 

No. 6 fuel oil. This means that this particular “fuel switching” option would not require Temple 

Health to install any new equipment; Temple would merely stop burning No. 6 fuel oil all 
8 

together. Therefore, Fuel Switching to Natural Gas Only is considered to be a technically 

feasible option. 

As the three boilers already have the ability to burn natural gas, the only cost normally associated 

with this control option is the differential cost in fuel. However, because Temple Health is a 

Joint Commission-certified healthcare facility, the three boilers must have a backup fuel 

available at all times in order to prevent loss of use of life-critical equipment should the primary 

fuel supply be interrupted. In order to implement this scenario and maintain certification, 

Temple would be required to upgrade the contracted supply of natural gas from interruptible 

service to firm service and ensure that the supply has no potential for interruption, due to Joint 

Commission requirements.

As Temple has no operational control regarding the availability of natural gas at any given time; 

 upgrading to “firm” natural gas supply does not provide assurance that natural gas will be 

available to Temple 100% of the time. Regardless, Temple Health is still required to have both a 

primary and a backup fuel source at all times in order to maintain Joint Commission certification. 

Should the facility be restricted to only one fuel source the hospital would loose Joint 

Commission certification resulting in economic loss. Therefore, Fuel Switching to Natural Gas 

Only is considered to be an economically unreasonable option. 

The following NOx controls were determined technologically feasible for the Boilers: SCR and 

fuel switching from No. 2 oil and natural gas to No. 6 oil and natural gas. A summary of the 

cost-effectiveness of each control option is provided below. Boilers #1, #2 & #3 share a common 

stack and were evaluated as combined. 

Table 2: Techincally Feasible Control Options

Source Control 

Technology 

Baseline 

NOx (tpy) 

NOx 

Reduction 

(%) 

NOx 

Reduction 

(tpy) 

Total 

Annualized 

Cost 

Cost 

Effectiveness 

($/Ton) 

Boilers 

#1, #2 & 

#3 

SCR 134..7781 80 107.82 $1,300,042 12,058 

Fuel 

switching 

from No.6 to 

No.2 fuel oil 

205.8 65 133.77 $8,937,031 66,809 

1

 The baseline for this option was based on the combined 673,894 MMBTU/yr limit and the 0.25 + (0.073059 / X) * 

(N-0.25) lbs/MMBTU NOx emission limit for No. 6 oil from Plan Approval No, 05198 while burning No. 6 oil, 

historical worst case %N = 0.57, and standard X=0.15 MMBTU/gal which is 0.40 lb/mmbtu. 

Emission= 0.40 lb/MMBTU x 673,894 mmbtu/yr = 134.778 ton/yr 

For more detailed calculations, please see Appendix. 

SCR and fuel switching from No. 6 to No. 2 oil are determined economically unreasonable.

1997 8-HOUR RACT 

AMS has determined the following shall be RACT for Boilers #1, #2 and #3 for the 1997 8-hour 

ozone standard: 

1. Nitrogen Oxides (NOx) emissions from each boiler shall not exceed the following 

(a) 0.067 lbs/MMBTU while burning natural gas. 
9 

(b) 0.40 lbs/MMBTU while burning No.6 fuel oil. 

(c) Nitrogen Oxides (NOx) emissions from Boilers #1, #2, and #3 combined 

shall not exceed 56.3 lbs/hr. 

2. The combined heat input for Boiler #1, #2, and #3 shall not exceed 673,894 

MMBTU per rolling 12-month period. 

3. CCA burner modifications shall be performed on each boiler, including each of 

the following: 

(a) Installation of staged flame stabilizers (a.k.a. swirlers). 

(b) Redesign and replacement of the atomizers. 

(c) Replacement of the center-fired gas injection rings with gas manifolds 

having center-fired and poker gas injection. 

(d) Installation of a NOx tempering system (water injection). 

4. During the ozone season (April 1 – October 31), each boiler shall burn natural gas 

as the primary fuel. Each boiler may only burn No. 6 fuel oil during periods of gas 

curtailment or gas supply interruption.

The following table provides an emission comparison between the 1-hour RACT requirements 

and the proposed modification. The proposed limitations reduce the combined hourly NOx 

emissions for the boilers by over 30% and annual NOx emissions by over 60% of the 1-hour 

RACT approved limits. These reductions assume the boilers will always burn No. 6 oil, which is 

the worst-case emission scenario. Under 8-hour RACT, the boilers will be required to burn 

natural gas during the ozone season, except during gas interruptions or curtailments, which will 

reduce NOx emissions even further. The table below demonstrates that the proposed revision 

provides more stringent/equivalent emission reductions in accordance with CAA section 110(1). 

Emission comparison between the 1-hour RACT and the proposed modification (8-hr 

RACT) 

 

Table 3: Pre-change Emission (1-hr Approved RACT) 

Boiler # 

1

Boiler #2 

with FGR Boiler # 3 Combined Comments 

Emission Factor for 

No. 6 Oil (lb/mmbtu)1 0.53 0.37 0.53 N/A 

Hourly Heat Input 

(MMBTU/Hr) 50 76.4 50 176.4 1-hour RACT requires Boilers #1 to limit 

heat input to 50MMBTU/hr 

Hourly Emissions 

(lb/hr) 26.68 28.54 26.68 81.90 Based on maximum capacity or heat input limits. 

Annual Heat Input 

(MMBTU/yr) 438,000 669,264 438,000 1,545,264 Assuming 8760 hours of operation at full 

capacity of boilers. 

Annual Emissions 

(tpy) 116.86 125.00 116.86 358.72 Based on No. 6 fuel oil operation at 8760 hour 

of operation and at full capacity of boilers. 1 EF from AP-42 (Table 1.3-1, footnote d) (((20.54+104.39*N)/1000)/X) in lbs/MMBTU, N=0.57% Temple’s 

highest historical N content and X=0.15 MMBTU/gal (Standard) 1-hour RACT requires Boiler 2 to have FGR; 

which is expected to achieve 30% NOx reductions. Thus, a factor of (1-0.3) was multiplied to AP-42 factor for 

Boiler 2. 

Table 4: RACT Modification (proposed 8-hr RACT)

Boiler #1 Boiler #2 Boiler # 3 Combined Comments 

NOx Limit for No. 6 

Oil (lb/mmbtu) 0.40 0.40 0.40 0.40 

Hourly Heat Input 

(MMBTU/Hr) 76.4 76.4 76.4 229.2 Hourly heat input per boiler represents the maximum rating of each. 

Hourly Emissions 30.56 30.56 30.56 56.31 Hourly emissions per boiler are based on
10 

(lb/hr NOx) the No. 6 oil limit and rated capacity. 

Annual Heat Input 

(MMBTU/yr) 669,264 669,264 669,264 673,8942 

Annual heat input per boiler based on 

maximum capacity of each boiler during 

8760 hours of operation. 

Annual Emissions 

(tpy NOx) 133.85 133.85 133.85 134.783 

Annual emissions per boiler based on the 

annual heat input capacity and the NOx 

limit (lb/mmbtu) for No. 6 oil. 1

 This limit is a combined hourly permit condition and ensures that no more than one boiler can burn No. 6 oil at the 

same time (at full capacity). 

2

 The combined annual heat input is a permit limitation. 

3

 Annual emissions for the combined boilers based on the combined annual heat input limit and the NOx limit 

(lb/mmbtu) for No. 6 oil. This is more stringent than the annual emissions for the combined boilers based on the 

56.3 lbs/hr combined NOx limit and 8,760 hrs/yr. 

Changes in Emissions 

Boiler #1 Boiler #2 Boiler # 3 Combined Comments 

Hourly Emissions 

(lb/hr) -25.60 

Annual Emissions 

(tpy) -223.94 

These tables show the significant decrease in potential emissions in comparison to the current 

SIP approved case-by-case 1-hr RACT that has a potential to emit 349.46 tpy of NOx emission. 

As noted above, while the 8-hour RACT potential emission calculations assume the boilers will 

always burn No. oil, they will only be allowed to burn No. 6 oil during limited times during the 

ozone season. In addition to the overall emission reduction per rolling twelve month period, the 

proposed RACT modification includes a 56.3 lbs/hr combined NOx hourly limit for all boilers 

and, a combined heat input limit of 673,894 MMBTU per rolling 12 month period. Since the 

proposed emission limit is more stringent than the currently approved 1-hour RACT, AMS is 

proposing these limits and control technology shall be NOx RACT. 

Conclusions and Recommendations: 

AMS determines that the following emission limitations and work practice standards represent 

NOx RACT for these boilers for the 1997 8-hour ozone standard: 

1. Nitrogen Oxides (NOx) emissions from each boiler shall not exceed the following 

(a) 0.067 lbs/MMBTU while burning natural gas. Compliance shall be 

determined based on stack test and shall be the average of three one hour 

separate test runs for each source.

(b) 0.40 lbs/MMBTU while burning No.6 fuel oil. Compliance shall be 

determined based on stack test and shall be the average of three one hour 

separate test runs for each source.

(c) Nitrogen Oxides (NOx) emissions from Boilers #1, #2, and #3 combined 

shall not exceed 56.3 lbs/hr. 

2. The combined heat input for Boiler #1, #2, and #3 shall not exceed 673,894 

MMBTU per rolling 12-month period. 

3. CCA burner modifications shall be performed on each boiler, including each of 

the following: 

(a) Installation of staged flame stabilizers (a.k.a. swirlers). 

(b) Redesign and replacement of the atomizers. 

(c) Replacement of the center-fired gas injection rings with gas manifolds 
11 

having center-fired and poker gas injection. 

(d) Installation of a NOx tempering system (water injection). 

4. During the ozone season (April 1 – October 31), each boiler shall burn natural gas 

as the primary fuel. Each boiler may only burn No. 6 fuel oil during periods of gas 

curtailment.

Testing requirement 

1. Temple University – Health Sciences Campus shall conduct a NOx performance 

test on one of the three boilers every five years orand whenever requested by 

AMS while burning No.6 fuel oil and natural gas. 

Monitoring and record keeping requirement 

1. Temple shall monitor and record the monthly fuel usage for each boiler 

2. The Permittee shall monitor and record verification of compliance with the NOx 

emission limits. Compliance with the NOx limit shall be based on AMS approved 

stack test data; or other AMS-approved emission factors. 

3. Temple shall keep records of the fuel manifests documenting the nitrogen content 

of No. 6 fuel oil. 

4. Temple shall keep hourly records of NOx emissions from the boilers calculated 

on a weekly basis. 

5. Temple shall keep records of the reasoning of burning fuel oil during the ozone 

season (April 1 – October 31), 

6. Temple shall monitor and record the combined heat input of the boilers per rolling 

12-month period. 

7. Temple shall keep all stack test results. 

Presumptive RACT Sources: 

Small Boilers (heat input capacity <2 MMBTU/hr ) 

Table 5 lists sources that meet the presumptive RACT requirements specified in 25 Pa Code 

129.93(c)(1) [operation and maintenance of boilers per manufacturer specifications and 

maximum heat input ratings <20 MMBTU/Hr; 

Table 5 Small Boilers

Source Description Capacity Fuel/Material Construction 

Date 

3525 Germantown Boiler #1 1.01 MMBTU/hr No.2 Oil After 1970 

 

3511 N. 13th Street Boiler 0.947 MMBTU/hr Natural Gas After 1970 

Emergency Generators and Fire Pumps 

Table 6 lists sources that meet the presumptive RACT requirements specified in 25 Pa Code 

129.93(c)(5) [operation and maintenance of engines per manufacturer specifications and use 

limited to 500 hours per year or less]. 

 Table 6 Emergency generators and Fire pumps

Source Description Capacity Fuel/Material Construction 

Date 

Pharmacy Allied Health 

Emergency Generator 

340 kW Natural Gas 1974 

Pharmacy School Emergency 

Generator Fire Pump 

100 kw No. 2 Oil 1997 
12 

Dental School Emergency 

Generator 

155 kW No. 2 Oil 1990 

GSB Emergency Generator 5 kW Natural Gas 1978 

Jones Hall Generator Fire 

Pump 

250 kW No. 2 Oil 1995 

Old Medical School 

Emergency Generator 

28 kW No. 2 Oil 1950 

Old Medical School 

Emergency Generator 

300 kW No. 2 Oil 1999 

Faculty Student Union 

Emergency Generator 

150 kW Natural Gas 1975 

Medical Office Building 

Emergency Generator 

(Outside) 

125 kW No. 2 Oil 2008 

Hospital Emergency 

Generator A 

1000 kW No. 2 Oil 1997 

Hospital Emergency 

Generator B 

1000 kW No. 2 Oil 1998 

Hospital Emergency 

Generator C 

450 kW No. 2 Oil 1998 

TUH-FP Fire Pump 187 bhp No. 2 Oil 1984 

Ambulatory Care Center 

Emergency Generator 

1000 kW (1480 bhp) No. 2 Oil 2005 

Kresge West Emergency 

Generator 

<400 kW No. 2 Oil 1999 

Kresge Science Hall 

Emergency Generator 

250 kW 

(314 bhp) No. 2 Oil 1997 

Kresge Science Hall 250 kW No. 2 Oil 1997 

Emergency Generator (314 bhp) 

Medical Research Building 

Emergency Generator 

350 bhp No. 2 Oil 1999 

Boyer (Formerly TUCMC) 

Emergency Generator 

1250 kW No. 2 Oil 1998 

Boyer (Formerly TUCMC) 300 kW No. 2 Oil 1998 

New Medical School 

Emergency Generator 

1000 kW No. 2 fuel oil 2008 

New Medical School Fire 

Pump (Inside, lower floor) 

175 bhp No. 2 fuel oil 2008 

HSC Steam Plant 

Emergency Generator 

350 kW No. 2 Oil 1998 

1/9/15
13 

Edward Wiener, Chief of Source Registration Date 

Appendix

Summary of Cost-Effectiveness Calculations

The following were calculated in order to evaluate the cost effectiveness of each emission 

control technology: 

‐ Total Capital Investment (TCI) ($) 

‐ Annualized Capital Investment or Capital Recovery ($/yr) 

‐ Total Annual Cost (TAC) ($/yr) 

‐ Baseline NOx Emissions (tons/yr) 

‐ NOx Emission Reduction (tons/yr) 

‐ Cost Effectiveness ($/ton) 

Capital Recovery 

To convert from P (present Value) to A(Annual amount), A=P(A/P,i%,n), 

 (1 ) 1

(1 )

 

  n

n

i

i i CRF 

Where i= Annual interest Rate; n= control system life; 

Annualized Capital Investment cost = TCI x CRF 

i= 10% interest and n=15 yrs 

CRF=0.1315 

Cost of the Catalyst in SCR 

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. The catalyst life is 5 years. 

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

(1 ) 1  n i

i SFF 

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

For i=10% and n=5 yrs; SFF=0.1638 

Catalyst Annual Cost = SFF x Catalyst Cost 

Cost of the Ammonia in SCR and SNCR (Based on EPA cost manual)
14 

2NH3 + 2NO + 1⁄2 O2 2N2 + 3H2O 

Ammonia cost =(17/30 * 1.05 *2 mole of Ammonia/2 mole of NO *NOx emission (tpy) 

*$410/ton) 

NH3 = Ammonia (1.05 is assuming 5% ammonia slip) 

NO = Nitric Oxide

O2 = Oxygen 

H2O = Water 
15 

 

Appendix 

Boilers #1, #2, & #3 SCR (673,894 mmbtu/yr) and boilers capacity of 76.4 MMBTU/hr 

 Total capital Cost

 

Total Capital Investment Cost 

(TCI) 

$679,786 Based on EPA Cost Control Manual of 

$6000/MMBTU/Hr. Escalated using the Marshall and 

Swift Index 1997 to 2014 

Capital Recovery $108,630 0.1598 20 yrs @15% -OAQPS1 A/p=0.1598

 

Annual Operating Cost 

Direct Annual Cost 

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

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

Maintenance $10,196.79 1.5% x TCI 

Ammonia 

$50,963 

 Ammonia cost =(17/30 * 1.05 *2 mole of Ammonia/2 

mole of NO *NOx emission (tpy)(68.6 tons) 

*$410/ton*1.55 

Catalyst Cost 518,000 0.1638 Sinking Fund Factor n=5 yrs, i=10% 

Annual Catalyst Replacement 

Cost 

 

84,848 

Total Direct Annual Cost $216,088 

Total Indirect Annual Cost $108,630 CFR * TCI (Capital Recovery 

 

Total Annual Operating 

Costs for one source 

$433,347 

 

Total Annual Operating 

Costs for all three source 

$1,300,042 3 

NOx Emission Reduction 

(TPY) 

107.82 

Cost Effectiveness ($/ton 

NOx removed) 

$12,058 
16 

Fuel Switching Cost Analysis for Boiler #1 

#6 fuel oil #2 fuel oil 

MMBtu/year 669264 669264 

Heat Value, MMBtu/gal 0.15 0.14 

Gallons/yr 4480457 4780457 

$/Gal 

 

*$2.60 

 

**$3.06 

$/yr $ 11,649,188 $14,628,198 

Increased Cost 

each boiler $ 2,979,010 

Increase cost for 

three boilers $8,937,031 

Baseline 

Emissions 

205.8 tons per 

rolling twelve 

month period 

 Based on 

proposed 

emission 

limit

Emission 

Reduction 133.77 

65% 

reduction 

Cost 

Effectiveness $ 66,809/ton 

References: 

1

EPA Cost Manual, 6th Edition , Jan 2002, Appendix A.2.3 

* U.S. Energy Information Administration, Short Term Energy Outlook, April 2014: 

** U.S. Energy Information Administration, Short Term Energy Outlook, April 2014: