CITY OF PH ILADELPHIA 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 mode rate (or worse) ozone nonattainment areas implement reasonably available control technolo gy (RACT) controls on all major sources of Volatile Organic Compounds (VOC) and Nitrogen Oxid es (NOx). Philadelphia County is part of the Philadelphia-Wilmington-Atlantic City mode rate 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 Cam pus is located at 3401 North Broad Street, Philadelphia, PA 19140. The f acility’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, th e 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 th reshold in Philadelphia County that is applicable to VOC RACT for the 1997 8- hour ozone NAAQS. The f acility is subject to RACT under the 1-hour ozone standard, and is subj ect 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 Approva l (Permit ID. 8906) for the 1-hour ozone standard in December, 1999, based on th e facility’s RACT proposal. AMS’ RACT determination and resulting RACT plan approva l 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 St eam 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 re sult of the 1-hour RACT determination, the following requirements were approved as RACT:

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

 Boilers #1 and #3 to have fuel flow govern ing devices limiting the fuel input to 50 MMBTU/hr each, making them applicable to th e presumptive RACT requirements of 25 PA Code Section 129.93(b)(2).

 A medical waste incinerator that was applic able to the presumptive RACT requirements of 129.93(c)(4).



### Modification of RACT Sources After the 1-hour RACT plan approv al was issued, Temple Health discovered that installing the FGR was technically infeasible for Boiler #2. Th e FGR was not possible due to a number of issues that were specifically encountered by Temp le when attempting to engineer the application
of FGR on Boiler #2.

Achieving effective NOx control with FGR re quires accurate and re peatable control of combustion air temperature and oxy gen 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 ve locity of the flue gase s leaving the boiler is very low most of the time. Low flue gas velo city 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 t op of the boiler to purge potentially unburned gases from that otherwise stagnant zone (hence the term, “cross-drafted”). This deliberate cross-dr afting coupled with the leakage of ambient air through th e boiler casing and loos ely stacked brick refractory walls makes repeatable flue gas extraction im possible at anything less than 80% of full load when the flue gas velocities are high enough to achieve thorough mixi ng of the combustion gases with ambient air in the breeching (a point that woul d never be reached as long as al l three boilers in the plant are available). Combustion air temperat ure affects air density and, ther efore, 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 fr om 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 in to 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 consis tent or predictable. It varies with outside air temperature, boiler load and the length of time th at 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, ai r and flue gas flow to control combustion. However, due to the heating problem cited abov e, air flow measurement is complicated by the variable density of the combustion air. Exacerbat ing the problem of air flow measurement is the boilers’ characteristic, unalterable, low combustion air velocity which makes metering3 instruments that depend on pressure drop, positiv e displacement or vortex shedders impossible. An FGR retrofit on these boilers is also complicat ed by the fact that all three burners on each
boiler share a common windbox. Unifor m mixing and distribution of the flue gas to each one of
the three burners cannot be done with a commo n windbox. The original FGR retrofit designed by Benz Air discussed in the 1994 RACT analysis wa s 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 Pr eferred Utilities) addr essed this problem by providing two separate windboxes a nd 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 insta lled, 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 aci ds 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 a nd 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-Pl us design) avoids the problems upstream between the windbox and th e 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 f easible 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 do es not impinge on the furnace walls. The flame pattern with FGR is characteristic ally 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 installi ng a FGR retrofit system on Boiler #2, FGR was considered technically infeasible. Te mple 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 Bo iler #2 to utilize flue gas recirculation
and low excess air combustion with a re quirement 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 (NO
x ) 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 performe d 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 NO
x tempering system (water injection).

CCA estimated their burner modifications w ould reduce the NOx emission rate by around 30%, which is comparable to the estimated reduc tions from FGR (the 2010 Cleaver-Brooks Boiler
Emission Guide estimates 25-30% NOx reduction fo r standard fuel oils). Since the 1-hour
RACT did not have NOx emission limits in lb s/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 modifi cations. The natural gas limit took an AP-42 emission factor (Section 1.4, Table 1.4-1), redu ced it by 30%, and converted it to lbs/MMBTU using a standard BTU content of 1,050 BTU/scf fo r natural gas. The NOx emission limit for oil
used an AP-42 emission factor that included nitr ogen content as a variable (Section 1.3, Table 1.3-1 footnotes) as a starting point. This wa s 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 th e facility cannot contro l 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 appr oval 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 sta ndard 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 modifi ed 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 na tural 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 Octobe r 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 curt ailed 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 weathe r and the negligible risk of exceeding the National Ambient Ai r Quality Standard (NAAQS) fo r 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 modificati ons to the 1-hour RACT determination represent
RACT for the 1997 8-hour ozone sta ndard, an evaluation of the feas ibility of currently available controls has been perf ormed for each boiler.

The control strategies considered for case-by- case RACT analysis will evaluate emissions
reductions from the installation of additio nal controls in each of the boilers. To determine the
cost effectiveness of th e technically feasible c ontrol options, a cost analysis was conducted and is presented below.

- Selective catalytic reduction (SCR) - Selective non-catalyt ic reduction (SNCR) - Combustion System Modifications for Ultra-Low NOx Performance - Fuel Switching from No.6 and natu ral gas to No.2 and natural gas - Fuel switching to 100% natural gas only6 Detail analysis for each emission cont rol 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 is sues would need to be addre ssed 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 modificatio ns to the existing flue and ductwork design.
The ductwork would need to be directed outside the existing building, wher e the catalytic reactor would theoretically be housed, and then re-direc ted back inside the building to the downstream components. Additionally, any burni ng particles would have the poten tial to severely damage the catalyst. Finally, new fans to accommodate the greater pressure drop associated with the redesigned system would be required. The installa tion of SCR would impact the efficiency of the existing boilers, such that additiona l fuel would be required in orde r 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 re nders SCR a marginally available technology, due to the presence of “soot” in the fl ue gas which has the tendency to plug the catalyst without additional equipment modification.

Although the space availability in the Central Stea m Plant is extremely limited to house an SCR
unit which would be able to trea t 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 opera ting 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) ex perience 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 fo r ammonia to condense onto to the fly ash. Fly ash contamination seve rely restricts ash mana gement 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 installati on of SNCR would impact the efficiency of the existing boilers, such that additiona l fuel would be required in orde r to achieve the same level of steam output currently recogni zed (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 physi cal 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 includes7 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 un its (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-bur ner arrangements on packaged boilers, which allow the desired flame length to be achieved.

In order to attempt to implement ULNB at HSC, very significant modifi cations to not only the existing burners, but also to the windbox, fans, and process control syst ems 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 natu ral 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 confi guration 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 th e reduction in fuel-bound nitrogen. Fuel Switching is considered to be a technically feasible option

.

Temple Health also proposed, in the altern ative, 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 N o. 6 fuel oil as a primary fuel with natural gas as a backup. AMS considered Temple’s a lternative but we ultimat ely 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, [Tot al emission from natural gas = 0.067 lb/MMBTU x 395,105 MMBTU/ozone season = 26,472 lbs/ozone se ason = 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 di fference 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 thr ee boilers already have the abilit y 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 all8 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 bu rn natural gas, the only cost normally associated with this control option is the differential cost in fuel. However, becau se Temple Health is a
Joint Commission-certified health care facility, the th ree boilers must have a backup fuel available at all times in order to prevent loss of use of life-critical equi pment should the primary fuel supply be interrupted. In order to implem ent this scenario and maintain certification, Temple would be required to upgrade the contra cted supply of natural gas from interruptible
service to firm service and ensu re that the supply has no potentia l for interruption, due to Joint Commission requirements.

As Temple has no operational contro l regarding the availa bility 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 restri cted to only one fuel source the hospital woul d 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 tec hnologically 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 contro l option is provided below. Bo ilers #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..778 1 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 fro m 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 (NO
x ) 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 perf ormed 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 NO
x 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 comp arison 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 a nnual NOx emissions by over 60% of the 1-hour RACT approved limits. These reductions assume th e 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 seas on, except during gas interruptions or curtailments, which will
reduce NOx emissions even further. The table below demonstrates that the proposed revision provides more stringent/equivale nt emission reductions in acco rdance with CAA section 110(1).

Emission comparison between the 1-hour RA CT 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 Modificati on (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 56.3 1 Hourly emissions per boiler are based on10 (lb/hr NOx) the No. 6 oil limit and rated capacity.

Annual Heat Input

(MMBTU/yr) 669,264 669,264 669,264 673,894 2 Annual heat input per boiler based on maximum capacity of each boiler during 8760 hours of operation.

Annual Emissions (tpy NOx) 133.85 133.85 133.85 134.78 3 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 pot ential 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 emissi on 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 contro l technology shall be NOx RACT.

Conclusions and Recommendations: AMS determines that the following emission lim itations 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 natura l 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 fu el 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 (NO
x ) emissions from Boilers #1, #2, and #3 combined
shall not exceed 56.3 lbs/hr.
2. The combined heat input for Boile r #1, #2, and #3 shall not exceed 673,894 MMBTU per rolling 12-month period.
3. CCA burner modifications shall be perf ormed 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 manifolds11 having center-fired and poker gas injection. (d) Installation of a NO
x 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 ve rification of compliance with the NOx emission limits. Compliance with the NOx limit shall be based on AMS approved stack test data; or other AM S-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 reas oning of burning fuel oil during the ozone season (April 1 – October 31),

6. Temple shall monitor and record the combin ed heat input of th e boilers per rolling 12-month period.
7. Temple shall keep all stack test results.



### Presumptive RACT Sources:

Small Boilers (heat inpu t capacity <2 MMBTU/hr ) Table 5 lists sources that meet the presumptiv e RACT requirements specified in 25 Pa Code 129.93(c)(1) [operation and mainte nance 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 0.94 7 MMBTU/hr Natural Gas After 1970

Emergency Generators and Fire Pumps Table 6 lists sources that meet the presumptiv e RACT requirements specified in 25 Pa Code 129.93(c)(5) [operation and maintena nce of engines per manufactur er 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 199712 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 / 1 513 Edward Wiener, Chief of Source Registration Date

Appendix

Summary of Cost-Effectiveness Calculations The following were calculated in order to eval uate 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 Invest ment 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 cataly st 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 (Futur e) to A(Annual amount), A=F(A/F,i%,n),



### 1 ) 1 (



 

n 

### i i SFF

Where i= Annual interest Rate (1 0%); 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 2NH 3 + 2NO + 1⁄2 O 2 2N 2 + 3H 2 O

Ammonia cost =(17/30 * 1.05 *2 mole of A mmonia/2 mole of NO *NOx emission (tpy) *$410/ton)

NH 3 = Ammonia (1.05 is assuming 5% ammonia slip)
NO = Nitric Oxide
O 2 = Oxygen
H 2 O = Water15 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% -OAQPS 1 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) $12,05816 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, 6 th 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: