CITY OF PH ILADELPHIA Department of Public Health Environmental Protection Division Air Management Services



### InterOffice Memo To: File
From: Rahel Gebrekidan
Date: December 01, 2014 Subject: 1997 8-Hour RACT Analysis for Temple University-Main Campus



## Introduction:

The Clean Air Act (CAA) requires that moderate (or worse) ozone nonattainment areas implement reasonably available control technology (RACT) c ontrols on all major sources of Volatile Organic Compounds (VOC) and Nitrogen Oxides (NOx). Phila delphia County is part of the PhiladelphiaWilmington-Atlantic City moderate ozone nonatta inment area for the 1997 8-hour ozone National Ambient Air Quality Standard (NAAQS). This document presents the findings of a RACT evaluation for the 1997 8-hour ozone standard for this facility.

Company Description:

Temple University – Main Campus (Temple MC) is a multi-building educational institution in the City of Philadelphia. In order to provide needed utiliti es for maintaining heat, power (both backup and supplemental), and providing hot water, Temple MC operates a number of steam boilers, hot water boilers, and internal combustion e ngines to produce electricity. The facility’s air emissions sources include 16 Boilers and hot water heaters <20 MMBTU/hr, 5 Boilers >= 20 MMBTU/Hr and <50 MMBTU/Hr, 3 boilers > 50MMBTU/hr boilers, 10 Sta ndby Electric Generating units each 2250 HP, and 59 emergency generators and fire pum ps. Each standby generator is c ontrolled by two oxidation catalysts (20 oxidation catalysts total). The 63.9 MMBTU/hr Central Steam Plant Rental boiler currently listed in the Title V operating permit has been deactiv ated and is being removed from the facility.

Applicability for NOx and VOC RACT:

Temple Main is a major source of NOx due to havi ng 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 emissi ons less than 50 tons per year, the major source threshold in Philadelphia County that is applicab le to VOC RACT for the 1997 8-hour ozone NAAQS.

RACT Evaluation:

Case-by-case RACT sources: The following sections present detailed evaluation of a Case-by-Case RACT for the applicable sources.

Broad Street Main Campus Expansion Project Boilers (BMCEP The three BMCEP Boilers are each Victory Energy Models VS-4-68, with a natural gas heat input rating of 91.3 MMBTU/Hr and a #2 fuel oil heat input rating of 86.8 MMBTU/Hr. Each un it is an “O-type” watertube boiler and are currently equipped with Low NOx burners (LNB) and flue gas r ecirculation (FGR). These boilers are primarily used for heat during cold months and operate well below their annual capacity. These boilers have the following requirements per AMS Pre-Constructi on Plan Approval No. 07132 dated 11/27/2007;

### 1. NOx Emissions from each boiler sh all not exceed the following:

a) Nitrogen Oxides (NO x ) emissions from the three boilers combined shall not exceed 15.5 tons per rolling 12-month period.

b) Emissions from each boiler shall not exceed the following: i) NOx: 0.036 lbs/MMBTU while burning natural gas and ii) 0.110 lbs/MMBTU while burning No.2 fuel oil

2. Each boiler shall be equipped with Low NOx bur ners (LNB) and flue gas recirculation (FGR).

To comply with the above emission limits, Temple Main is operating the LNB and FGR on each boiler and performed initial stack test to show complian ce with the 0.036 lbs/MMB TU and 0.110lbs/MMBTU NOx emission limit.

Control Strategies that were considered for NOx RACT are as follows

 Selective Catalytic Reduction (SCR)

 Selective Non-Catalytic Reduction (SNCR)

 Water/Steam Injection

Selective Catalytic Reduction Selective catalytic reduction (SCR) is a technolog y whereby an ammonia or ammonia-based fluid (reducing agent) is injected into the exhaust air stre am upstream of a catalyst. Once the mixture comes in contact with the catalyst surface, a reduction reacti on occurs, breaking down the NOx (NO or NO2) and NH 3 into N 2 and H 2 O. Selective catalytic reduction is considered technically feasible.

Selective Non-Catalytic Reduction Selective non-catalytic reduction (SCR) is a technol ogy whereby an ammonia or ammonia based fluid (reducing agent) is injected into the exhaust air stream. Once the mixture comes in contact with the catalyst surface, a reduction reaction occurs, breaki ng down the NOx (NO or NO2) and NH3 into N2 and H 2 O. Reductions in NOx flue gas concentrations are estimated to be between 20% and 50% for boilers, depending on the reducing chemical used and effective control of optimal operating conditions (exhaust gas temperature). SNCR systems require relatively hi gh gas operating temperatures. Steady temperatures in the range of 1,600 to 2,000°F are required to operate an SNCR system effectively. Selective non catalytic reduction is considered technically feasible

.
Water/Steam Injection The boiler fire box size does not provide sufficient mi nimum residence time for water injection at the combustion temperature for acceptable steam generation. Additionally, t he majority of NOx emissions from residual oil-fired boilers results from fuel NOx, not thermal NOx, and water/steam injection systems are not effective in reducing fuel NOx. Lite rature also indicates that the use of water/steam injection for NOx emissions reduction has a consider able drawback. Fuel and thermal efficiency is typically reduced by 10% for boilers (i.e., energy pe nalty). Water/steam injection has been primarily applied to gas-fired turbines. Due to the reasons listed, water/steam injection is not considered technically feasible for the boiler.

The following NOx controls were determined tec hnologically feasible for each boiler: SCR and SNCR. A summary of the cost-effectiveness of these controls is provided below.For purposes of cost calculations in this evaluation the allowable maximum emission limits of 15.5 tons per rolling twelve month period per boiler has been used. This limit is more stringent than the allowable 0.110 lb/MMBTU and reflects the maximum enforceable emission limits currently applicable for these boilers. Source Control Technology NOx Baseline Emissions (tpy) NOx Reduction (%) NOx Reduction (tpy) Total Annualized Cost ($/year) Cost Effectiveness ($/Ton)

Each BMCEP SCR 15.5 85 13.2 210,481 15,976 SNCR 15.5 20 3.1 59,518 19,199



### The SCR and SNCR are determined economically unreasonable . For more detailed calculations, please see the Appendix.

Conclusion; AMS has determined that the following existing emis sion limits, control technology, and monitoring and recordkeeping shall be considered NOx RACT fo r each boiler as approved on AMS Pre-Construction Plan Approval No. 07132 dated 11/27/2007. a) Nitrogen Oxides (NO x ) emissions from the three boilers combined shall not exceed 15.5 tons per rolling 12-month period. b) Each boiler shall be installed with low NOx burners and flue gas recirculation

. c) Emissions from each boiler shall not exceed the following: i) NOx: 0.036 lbs/MMBTU while burning natural gas and ii) 0.110 lbs/MMBTU while burning No.2 fuel oil

d) Temple Main shall perform stack test on each boilers every five year. e) Temple Main shall monitor and record th e monthly fuel usage for each boiler, the combined NOx emissions for the boilers per rolling 12-month period calculated monthly, the combined gas and the combined oil usage for the boilers in MMBTU for a rolling 12-month period calculated monthly

Standby Electric Generating Facility (SEGF) The Standby Electric Generating Facility (SEGF) is a collection of 10 Caterpillar 3516 engines. Each engine pair is rated at 2,250 brake- horsepower (bhp) and burns natural gas. Each engine pair is attached to a generator that can provide up to 1,600 kilowatts . These units were installed in October 1992. Two oxidation catalysts were installed on each standby gene rator in 2013 in order to comply with 40 CFR 63 Subpart ZZZZ generator has two oxidation catalysts installed These engines have the following requirements per AMS installation permit number 92087, dated October 2, 1992; [25 Pa Code §127.1]

NOx emissions from the standby electric generator are limited to the following a) NOx emission from each standby electric generator sh all be less than or equal to 2.00 g/bhp-hr; 

### b) Each Standby Electric Genera tor shall operate at a maxi mum of 500 hours per rolling 12- month period c) The Combined NOx hourly emission rate of less than or equal to 99 lb/hr



### To show compliance with the 2.00g/bhp-hr emissi on limits, Temple Main performed initial stack test on the engines.

Control Strategies that were considered for the NOx RACT for each generator are as follows - Installation of selective catalytic reduction (SCR) – 80% NOx control - Installation of non-selective catalytic reduction (SNCR) – 20% NOx control

Selective Catalytic ReductionSelective catalytic reduction is a technology whereb y an ammonia or ammonia-based fluid (reducing agent) is injected into the exhaust air stream upstr eam of a catalyst. Once the mixture comes in contact with the catalyst surface, a reduction reaction occurs , breaking down the NOx (NO or NO2) and NH3 into N2 and H2O. Any ammonia slip is reduced by ut ilizing an Oxidation Catalyst, which produce NO. The estimated overall NOx control efficiency of an SCR system is typically 80% or better.

In order to comply with the current 40 CFR Part 63, Subpart ZZZZ (RICE MACT) standard, each engine (20) is equipped with a Johnson-Matthey Modulex B catalyst designed specifically for CO emission reduction. The system can additionally be equipped with additional injection system and SCR catalyst downstream of the existing CO catalyst in order to implement an SCR system. Based on available information, the SCR system is technically feasible . There are several vendors capable of providing the catalyst and injection systems; however, based on the existing catalyst system, a Johnson-Matthey injection system with a SINOX high temperature catalyst is the unit under consideration. For this system, the reducing agent would be urea.

Selective Non-Catalytic Reduction Selective Non-Catalytic Reduction technology for NOx control on 4-stroke lean burn natural gas fired engines has not been installed as a retrofit in many so urces; and this technology is not widely available. This is likely due to insufficien t exhaust temperature to initiate the reduction reaction without the assistance of a catalyst. Without the catalyst, this emission control technology would require additional heat, resulting in higher operating costs, and potentiall y more air emissions. As a result, this option is technically infeasible.

* The baseline emissions are based on the maximum allowable emission limits of 2.00g/bhp-hr, and 2.47 tons per rolling twelve month period per engine. The cost-effectiveness of the SCR was evaluated. Source Control Technology NOx Baseline Emissions (per rolling twelve month period) NOx Reduction (%) NOx Reduction (tpy) Total Annualized Cost ($/year) Cost Effectiveness ($/Ton)

Each Standby Electric Generator SCR 2.47 80 1.97 80,880 40,931



### The SCR is determined economically unreasonable. For more detailed calculations, please see the Appendix.

Conclusion; AMS has determined that the following existing emis sion rates and monitoring and recordkeeping shall be considered RACT for these sources as approve d by AMS installation pe rmit 92087 dated 10/02/1992.

NOx emissions from the standby electric ge nerators are limited to the following: a) NOx emission from each standby electric generator sh all be less than or equal to 2.00 g/bhp-hr; 

### b) Each Standby Electric Genera tor shall operate at a maxi mum of 500 hours per rolling 12- month period c) The Combined NOx hourly emission rate shall be less than or equal to 99 lb/hr



### Work practice standard a) Each Standby Electric Genera ting Facility shall operate at a maximum of 500 hours per rolling 12-month period

### b) Each standby electric genera tor shall only burn natural gas

Testing requirement a) Temple Main shall conduct quarterly NOx por table analyzer test on each engine using AMS-approved procedure.

Monitoring and record keeping requirement a) The combined NOx emission per rolling 12-month period 

### calculated monthly to demonstrate compliance with the above NOx emission limits b) Stack test results for each boilers c) 

### Operating hours for each Standby Electric Gene rator per rolling twelve month period calculated monthly d) 

### Combined amount of fuel used for the Standby Electric Generator per month and e) 

### Portable analyzer test results for each engine

Presumptive RACT Sources The following sources meet the various presumptive RA CT emission limitations and criteria specified in 25 Pa. Code 129.93. Table 1-1 lists sources that meet the presumptive RACT requirements specified in 25 Pa Code 129.93(c)(5) [operation and maintenance of engines pe r manufacturer specifications and use limited to 500 hours per year or less;

Table 1-1 Source Description Capacity Fuel/Material Construction Date Alter Hall Emergency Generator #1 350 kW No. 2 Oil 2008

Anderson Hall Emergency Generator #1 125 kW Natural Gas 1974

Anderson Hall Emergency Generator #2 175 kW No. 2 Oil 1998

Annenberg (Tele) Emergency Generator 100 kW No. 2 Oil 1985

Barrack Building Emergency Generator 100 kW Natural Gas 2002

Bell Building Emergency Generator #1 1040 kW No. 2 Oil 1986

Bell Building Emergency Generator #2 125 kW No. 2 Oil 1986

Bio Life Emergency Generator 1,100 kW No. 2 Oil 1985

CEA Building Emergency Generator #1 170 kW Natural Gas 1976

CEA Building Emergency Generator #2 125 kW No. 2 Oil 1998

Central Heat Plant <50 kW Natural GasEmergency Generator Wachman Hall Emergency Generator 140 kW Natural Gas 1977

Conwell (Bldg) Emergency Generator 150 kW No. 2 Oil

Conwell(Tele) Emergency Generator 250 kW No. 2 Oil 1985

Conwell/Carnell Hall Emergency Generator 130 kW No. 2 Oil 1998

ECEC Building Emergency Generator 125 kW No. 2 Oil 2004

Gladfelter (Tele) Emergency Generator 100 kW No. 2 Oil 1985

Gladfelter (Bldg) Emergency Generator 150 kW Natural Gas 1973

Gladfelter Hall Emergency Generator 175 kW No. 2 Oil

Johnson/Hardwick Hall Emergency Generator #2 100kW 2 oil 2005

Klein Hall Emergency Generator #1 100 kW Natural Gas 1973

Klein Hall Emergency Generator #2 103 kW No. 2 Oil 1998

Liacouras Center Emergency Generator 1000 kW No. 2 Oil 1997

Liacouras Garage Emergency Generator 125 kW No. 2 Oil 1997

Paley Emergency Generator #2 100 kW No. 2 Oil 1998

Peabody Emergency Generator 125 kW No. 2 Oil 1998

Pearson (Bldg) Emergency Generator 100 kW Natural Gas

Ritter Annex (Bldg) Emergency Generator 100 kW Natural Gas 1973

Ritter Annex (Tele) Emergency Generator 100 kW No. 2 Oil 1985

SAC Emergency Generator 150 kW Natural Gas 2002

Student Pavillion Center Emergency Generator 30 kW natural gas 1999

Temple Towers Fire Pump 110 HP Diesel 2009

1300 C.B. Moore Generator 150 KW No. 2 Oil 2001

1800 Liacouras Walk Emergency Generator 80 kW No. 2 Oil 2005

1940 Liacouras Walk Emergency Generator 80 kW No. 2 Oil 1999Table 1-2 lists sources that meet the presumptive RACT requirements specified in 25 Pa Code 129.93(c), operation and maintenance of boilers per manufacturer specifi cations and maximum heat input ratings <20 MMBTU/Hr; and annua l combustion adjustment for maximum heat input ratings >=20 MMBTU/Hr but less than 50 MMBTU/Hr.

Table 1-2 Source Description Capacity Fuel/Material Construction Date Central Steam Plant Boiler #1 41.24 MMBtu/hr No. 6 oil Natural gas 1962

Central Steam Plant Boiler #2 41.24 MMBtu/hr No. 6 oil Natural gas 1962

Central Steam Plant Boiler #3 41.24 MMBtu/hr No. 6 oil Natural gas 1962

Central Steam Plant Boiler #4 43.84 MMBtu/hr No. 6 oil Natural gas 1969

Liacouras Center Boiler #4 20.92 MMBtu/hr Natural Gas October 1999

White Hall Residence Boiler #1 1.9 MMBTU/hr Natural gas After 1970

White Hall Residence Boiler #2 1.9 MMBTU/hr Natural gas After 1970

White Hall Residence Boiler #3 1.9 MMBTU/hr Natural gas After 1970

Liacouras Center Boiler #1 9.996 MMBTU/hr No. 2 Oil Natural gas 1996

Liacouras Center Boiler #2 9.996 MMBTU/hr No. 2 Oil Natural gas 1996

Liacouras Center Boiler #3 9.996 MMBTU/hr No. 2 Oil Natural gas 1996

Edberg-Olsen Boiler 2.396 MMBtu/hr No. 2 Oil Natural Gas September 2000 Edberg-Olsen Water Heater #1 0.60 MMBtu/hr Natural Gas September 2000 Edberg-Olsen Water Heater #2 0.60 MMBtu/hr Natural Gas September 2000 Edberg-Olsen Water Heater #3 0.60 MMBtu/hr Natural Gas September 2000 Student Pavillion Boiler 2.887 MMBtu/hr No. 2 Oil Natural Gas September 2002 Temple Towers Pool Heater 0.85 MMBtu/hr Natural Gas

1 / 9 / 1 5

Edward Wiener, Chief of Source Registration Date

## Appendix

Detailed Calculations Summary The following costs are calculated in order to ev aluate the cost effectiveness of each emission control technology:

‐ Total Capital Investment (TCI)

‐ NOx Emission Reduction (tons/yr)

‐ Cost Effectiveness ($/ton)

‐ Capital Recovery = Convert from P (present) to A( Annual amount), A=P(A/P,i%,n),

1 ) 1 ( ) 1 (

  

 n n


### i i i CR 

### 15% interest and 20 yrs = A/ P=0.1598; Annual Cost = TCI x CRF

For the Catalyst , The catalyst life is 5 years. The annual cost is given by th e sinking fund factor, the amount of money the facility will need to set aside each year to be able to replace the catalyst at the end of its life, based on the lifespan of the catalyst and the interest rate. Sinking Fund Factor (SFF) = Convert from F (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

Cost of the Ammonia in SCR and SNCR (Based on EPA cost manual) 2NH 3 

### + 2NO + 1⁄2 O 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)

NH 3 

### = Ammonia, NO = Nitric Oxide; O 2 

### = Oxygen; H 2 

### O = Water; 1.05= Ammonia slip and excess ammoniaAppendix Costs are provided in 2014 US $. SCR

BMCEP Boiler 91.3 MMBTU/hr each

Total Capital Investment Cost (TCI) 1 $812,363 Based on EPA Cost Control Manual of $6000/MMBTU/Hr. (section 4, Chapter 2 page 149) Escalate 1997 $ using the Marshall and swift Index Capital Recovery 1 $76,687 0.1993 (A/P) CRF*TCI; n=10yrs i=15% CFR=0.1993
Electricity Cost 1 $45,552 65kw @ $0.08/kwh, 8760 hrs/yr
Maintenance 1 $12,185.44 1.5%*TCI

Total catalyst Replacement Cost 1 $28,283 0.1638 (A/F) SFF x Catalyst Catalyst Cost= $172,667; Cost; SFF=0.1638

Ammonia Cost 1 $3,781 NOx emission 15.5 tpy = (17/30 * 2moles of NH 3 /2 moles of NO *1.05 * NOx emission 15.5 (tpy) *$410/ton

Total Direct Annual Cost $89,802
Indirect Annual Cost
Overhead 1 $11,498 60% of maintenanceOAQPS 1
Administrative Charge 1 $16,247 2% of TCI 1
Property Taxes 1 $8,124 1% of TCI- 1

Insurance 1 $8,124 1% of TCI Capital Recovery 1 $76,687 0.0966 20 yrs @7% 1 A/p=0.0944

Total Indirect Annual Cost $120,680 Total Annual Operating Costs $210,481 NOx Emission Reduction (TPY) 13.2 85 % reduction. Based on allowable 15.5 tons per rolling 12 month period Cost Effectiveness ($/ton NOx removed) $15,976Costs are provided in 2014 US $. BMCEP Boiler 91.3 MMBTU/hr Total
SNCR Total Capital Direct Cost (DCI) 1 ( 

### SNCR system equipment, instrumentation, sales tax and freight. It also includes direct in stallation costs such as auxiliary equipment (e.g., ductwork, compressor), foundations and supports, handling and erection, electrical, piping, insulation and painting) $369,188 Based on EPA Cost Control Manual Section 4.2 . Escalate 1998 $ using the Marshall and Swift Index

Total Capital Indirect Cost (CIC) ( 

### includes costs such as; construction and contractor fees, startup and testing, inventory capital, and any process and project) $73,838 EPA Cost Manual

Contingency $66,454 EPA Cost Manual 1.5*TCI Total Capital Investment Cost $509,480 DCI+CCI

1 Electricity Cost $2,102.4 3kw @ $0.08/kwh, 8760 hrs/yr

1 Maintenance $7,642 1.5% of TCI

1 Ammonia Cost $2,139 Based on annual NOx emission of 15.5 tpy Ammonia cost =(17/30 * 1.05 *2 mole of Ammonia/2 mole of NO *NOx emission (tpy)(15.5 tons) *$410/ton Total Direct Annual Cost $11,423

Indirect Annual CostOverhead $0 0% of maintenanceOAQPS 1
Administrative Charge $0 0 %f TCI- 1 Property Taxes $0 0 %f TCI- 1
Insurance $0 0 %f TCI- 1

1 Capital Recovery $48,095 0.0944 CRF * TCI; n=20 yrs i=7% A/p=0.0944 Total Indirect Annual Cost $48,095

Total Annual Operating Costs $59,518NOx Baseline Emissions (TPY) 15.5 Based on maximum allowable NOx emissions NOx Emission Reduction (TPY) 3.1 Based on 20 % reduction. Cost Effectiveness ($/ton NOx removed) $19,199/ton

Costs are provided in 2014 US $. SCR

Standby-Engine Generators 2250 HP

Total Capital Investment Cost (TCI) $417,081 Based EPA Cost Control Manual of $125/hp-Hr. Escalate 1997 $ using the Marshall and swift Index

Annual Operating Costs
Direct Annual Cost Electricity Cost $400 10kw @ $0.08/kwh, 500 hrs/yr

1 Maintenance $6,256.21 1.5%*TCI

Total catalyst Replacement Cost $14,021 0.1638 (A/F) SFF x Catalyst Catalyst Cost= $85,000; Cost; SFF=0.1638, n=5 i=10% , Ammonia Cost $393 NOx emission 2.47 tpy Ammonia cost =(17/30 * 1.05 *2 mole of Ammonia/2 mole of NO *NOx emission (tpy)(2.47 tons) *$410/ton Total Direct Annual Cost $21,070

Indirect Annual Cost
Overhead 3 $656 60% of maintenance-OAQPS 1

Administrative Charge $8,342 2% of TCI- 1 Property Taxes $4,171 1% of TCI- 1
Insurance $4,171 1% of TCI- 1 Capital Recovery $39,372 0.0944 CRF * TCI; n=20 yrs i=7%

Total Indirect Annual Cost $59,809

Total Annual Operating Costs $80,880

NOx Emission Reduction (TPY) 1.97 80% reduction Based on Maximum allowable NOx emissions of 2.47 tons per rolling twelve months Cost Effectiveness ($/ton NOx removed) $40,931

References:

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.