DAQ-2024-008126

1/23/24, 11:45 AM State of Utah Mail - Serious Ozone Nonattainment Area RACT Analysis - UOU
https://mail.google.com/mail/u/0/?ik=539c285453&view=pt&search=all&permmsgid=msg-f:1786568924097441149&simpl=msg-f:17865689240974411…1/1
Ana Williams <[e-mail]>
Serious Ozone Nonattainment Area RACT Analysis - UOU
Briana Kistler <[e-mail]>Thu, Dec 28, 2023 at 4:08 PM
To: Ana Williams <[e-mail]>, Jon Black <[e-mail]>
Cc: Michael Brehm <[e-mail]>, Chantelle Russell <[e-mail]>, Brian Mensinger
<[e-mail]>
Ana, et el,

Attached is the Ozone RACT submittal for the University of Utah, as required in the letter sent by your department on May 31, 2023
addressing the redesignation of the Northern Wasatch Front ozone nonattainment classification from moderate to serious. Please reply
to confirm you have successfully received the attached report.

Please feel free to reach out with any questions you might have or if additional information is required.

Happy New Year!

Thank you,
Briana Kistler, E.I.T.
Environmental Engineer
Office: (801)-581-3906

Compiled UofU 2023 Ozone RACT Anaylsis 2023-1228 v4.0.pdf
1217K
OZONE SERIOUS NONATTAINMENT SIP
RACT Analysis

University of Utah

Prepared By:
Trinity Consultants
4525 Wasatch Boulevard, Suite 200
Salt Lake City, UT 84124
801-272-3000

December 2023

Project 234502.0032

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TABLE OF CONTENTS
1. EXECUTIVE SUMMARY 1-1
2. INTRODUCTION 2-1
2.1 Description of Facility .............................................................................................. 2-1
2.2 Emission Profile ....................................................................................................... 2-2
2.3 University Efforts to Reduce Emissions .................................................................... 2-2
3. REASONABLY AVAILABLE CONTROL TECHNOLOGIES BACKGROUND 3-1
3.1 RACT Methodology................................................................................................... 3-1
3.1.1 Step 1 – Identify All Reasonably Available Control Technologies ................................... 3-2
3.1.2 Step 2 – Eliminate Technically Infeasible Options ........................................................ 3-2
3.1.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness ....................... 3-2
3.1.4 Step 4 – Evaluate Most Effective Controls and Document Results ................................. 3-2
3.1.5 Step 5 – Select RACT ................................................................................................ 3-3
4. UCHTWP BOILERS 4-1
4.1 UCHTWP NOX Technologies ...................................................................................... 4-1
4.1.1 UCHTWP NOX Step 1 ................................................................................................ 4-1
4.1.2 UCHTWP NOX Step 2 ................................................................................................ 4-2
4.1.3 UCHTWP NOX Step 3 ................................................................................................ 4-4
4.1.4 UCHTWP NOX Step 4 ................................................................................................ 4-4
4.1.5 UCHTWP NOX Step 5 ................................................................................................ 4-5
4.2 UCHTWP VOC Technologies ..................................................................................... 4-5
4.2.1 UCHTWP VOC Step 1 ................................................................................................ 4-5
4.2.2 UCHTWP VOC Step 2 ................................................................................................ 4-6
4.2.3 UCHTWP VOC Steps 3-5 ........................................................................................... 4-7
5. LCHTWP BOILERS 5-1
5.1 LCHTWP NOX Technologies ...................................................................................... 5-1
5.1.1 LCHTWP NOX Step 1 ................................................................................................. 5-1
5.1.2 LCHTWP NOX Step 2 ................................................................................................. 5-3
5.1.3 LCHTWP NOX Steps 3-5 ............................................................................................ 5-4
5.2 LCHTWP VOC Technologies ...................................................................................... 5-5
6. LCHTWP TURBINE WITH WASTE HEAT RECOVERY 6-1
6.1 Turbine and WHRU NOX Technologies ...................................................................... 6-1
6.1.1 Turbine and WHRU NOX Step 1 ................................................................................. 6-1
6.1.2 Turbine and WHRU NOX Step 2 ................................................................................. 6-3
6.1.3 Turbine and WHRU NOX Step 3 ................................................................................. 6-5
6.1.4 Turbine and WHRU NOX Step 4 ................................................................................. 6-5
6.1.5 Turbine and WHRU NOX Step 5 ................................................................................. 6-5
6.2 Turbine and WHRU VOC Technologies ...................................................................... 6-5
6.2.1 Turbine and WHRU VOC Step 1 ................................................................................. 6-5
6.2.2 Turbine and WHRU VOC Step 2 ................................................................................. 6-6
6.2.3 Turbine and WHRU Steps 3-5 .................................................................................... 6-7
7. DUAL FUEL BOILERS 7-1
7.1 Dual Fuel Boilers NOX Technologies ......................................................................... 7-2

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7.1.1 Dual Fuel Boilers NOX Step 1 ..................................................................................... 7-2
7.1.2 Dual Fuel Boilers NOX Step 2 ..................................................................................... 7-3
7.1.3 Dual Fuel Boilers NOX Steps 3-5 ................................................................................. 7-6
7.2 Dual Fuel Boilers VOC Technologies ......................................................................... 7-7
7.2.1 Dual Fuel Boilers VOC Step 1 ..................................................................................... 7-7
7.2.2 Dual Fuel Boilers VOC Step 2 ..................................................................................... 7-7
7.2.3 Dual Fuel Boilers VOC Steps 3-5 ................................................................................ 7-8
8. BACKUP DIESEL BOILER 8-1
8.1 Backup Diesel Boiler NOX ......................................................................................... 8-1
8.1.1 Backup Diesel Boiler NOX Step 1 ................................................................................ 8-1
8.1.2 Backup Diesel Boiler NOX Step 2 ................................................................................ 8-2
8.1.3 Backup Diesel Boiler NOX Steps 3-5............................................................................ 8-3
8.2 Backup Diesel Boiler VOC Emissions ........................................................................ 8-3
9. OTHER SMALL NATURAL GAS BOILERS 9-1
9.1 Other Small Natural Gas Boilers NOX Technologies................................................... 9-1
9.1.1 Other Small Natural Gas Boilers NO X Step 1 ................................................................ 9-2
9.1.2 Other Small Natural Gas Boilers NO X Step 2 ................................................................ 9-2
9.1.3 Other Small Natural Gas Boilers NO X Steps 3 - 5 ......................................................... 9-3
9.2 Other Small Natural Gas Boilers VOC Technologies .................................................. 9-4
10. DIESEL-FIRED EMERGENCY GENERATORS 10-1
10.1 Diesel Fired Engines NOX and VOC Technologies .................................................... 10-1
10.1.1 Diesel-Fired Engines Step 1 ..................................................................................... 10-1
10.1.2 Diesel-Fired Engines Step 2 ..................................................................................... 10-2
10.1.3 Diesel-Fired Engines Step 3 ..................................................................................... 10-4
10.1.4 Diesel Fired Engines Step 4 ..................................................................................... 10-4
10.1.5 Diesel-Fired Engines Step 5 ..................................................................................... 10-5
11. NATURAL GAS EMERGENCY GENERATORS 11-1
11.1 Natural Gas Fired Engines NOX and VOC Technologies ........................................... 11-1
11.1.1 Natural Gas Emergency Generators Step 1 ............................................................... 11-1
11.1.2 Natural Gas Emergency Generators Step 2 ............................................................... 11-1
11.1.3 Natural Gas Emergency Generators Steps 3 – 5 ........................................................ 11-3
12. VOC FUGITIVES AND INSIGNIFICANT ACTIVITIES 12-1
12.1 Fugitive VOC Technologies ..................................................................................... 12-1
12.1.1 VOC Fugitives Step 1 .............................................................................................. 12-1
12.1.2 VOC Fugitives Step 2 .............................................................................................. 12-1
12.1.3 VOC Fugitives Step 3-5 ........................................................................................... 12-2
12.2 Storage Tanks ........................................................................................................ 12-2
12.2.1 Storage Tanks Step 1 ............................................................................................. 12-3
12.2.2 Storage Tanks Steps 2 – 4 ...................................................................................... 12-3
12.2.3 Storage Tanks Step 5 ............................................................................................. 12-3
13. CONCLUSIONS 13-1
APPENDIX A. DETAILED COST CALCULATIONS A-1

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1. EXECUTIVE SUMMARY
On May 31, 2023, the Utah Division of Air Quality (UDAQ) sent a letter to The University of Utah (University)
which identified the University as a major stationary source within the Northern Wasatch Front (NWF)
Ozone Nonattainment Area (NAA). This letter indicated that UDAQ anticipates that the U.S. Environmental
Protection Agency (EPA) will reclassify the NAA as serious by February 2025. In order to prepare for the
reclassification UDAQ has requested that a Reasonably Available Control Technology (RACT) analysis be
submitted by January 2, 2024. Section 110 of the Clean Air Act (CAA) defines the requirements for the
development of State Implementation Plans (SIPs), and Section 7511a specifies the requirements of a
serious nonattainment SIP, which includes a Reasonably Available Control Technology (RACT) analysis for all
major sources.

The precursors to ozone are oxides of nitrogen (NOX) and volatile organic compounds (VOCs). As a result,
the enclosed RACT analysis focuses on the emission sources at the University that emit these pollutants.
The University has the potential to emit 50 tons per year (tpy) or more of NOX classifying it as a major
source subject to SIP requirements.

Based on further information provided by UDAQ the following elements have been requested for each RACT
analysis:

► A list of each of the NO X and VOC emission units at the facility;
► A physical description of each emission unit, including its operating characteristics;
► Estimates of the potential and actual NOX and VOC emission rate from each affected source;
► The proposed NOX and/or VOC RACT requirement or emission limitation (as applicable); and
► Supporting documentation for the technical and economic consideration for each affected emission unit.1

Per UDAQ’s request, the University is submitting this RACT analysis no later than January 2, 2024.

1 Ozone SIP Planning RACT Analysis forms provided by Ana Williams, Utah Department of Environmental Quality on January 9, 2023

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2. INTRODUCTION
2.1 Description of Facility
The University is a public higher education institution with air emissions primarily due to the operation of
boilers, comforting heating equipment, and emergency generators located in Salt Lake City. The University
is operating as a stationary source under Title V Operating Permit Number #3500063004 and an approval
order (AO), DAQE-AN103540030-22. This analysis focuses on main campus which includes higher education
buildings, research facilities, student housing, sports arenas, the main hospital along with the Huntsman
Cancer center and supporting operations. Specifically, this includes the following equipment:

► Upper Campus High Temperature Water Plant (UCHTWP) boilers, otherwise known as Building 302
boilers;
► Lower Campus High Temperature Water Plant (LCHTWP) boilers, otherwise known as Building 303
boilers;
► LCHTWP cogeneration unit, which includes a turbine and waste heat recovery unit (WHRU) duct burner,
► Hospital dual fuel and diesel boilers:
• Ambulatory Care Complex (ACC) Boilers,
• Backup Diesel Boiler in the Rehabilitation Hospital (Rehab),
• Main hospital boilers, and
• Huntsman cancer center boilers;
► Miscellaneous small primary and backup boilers;
► Diesel generator engines; and
► Miscellaneous VOC sources including the paint booth, fuel storage tanks, and various parts washers.

Each of these emission sources will be discussed in a subsequent section. All correspondence regarding this
submission should be addressed to:

Mr. Michael Brehm, P.E.
The University of Utah
Associate Director,
Environmental Management & Code Compliance
125 South Fort Douglas Blvd
Salt Lake City, Utah 84112
Phone: [phone]
Email: [e-mail]
Ms. Briana Kistler, E.I.T
The University of Utah
Environmental Engineer
125 South Fort Douglas Blvd
Salt Lake City, Utah 84112
Phone: [phone]
Email: [e-mail]

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2.2 Emission Profile
Through recent permitting actions the University has established the following Potential to Emit (PTE)
profile. A full explanation of calculation methods and inputs can be found within the permitting files.
Table 2-1. University’s Potential to Emit
Unit Group
Potential Annual Emissions Estimate
Tons per year (tpy)
NOX VOC UCHTWP 14.42 1.47 LCHTWP Boilers 2.04 1.18 LCHTWP Turbine and WHRU 30.06 4.59 ACC and Rehab 4.37 0.37 Main Hospital Boilers 6.55 0.35 Huntsman Cancer Center Boilers 3.99 0.21 All Other Primary Boilers 1.90 0.22 All Other Backup Boilers 0.83 0.05 Current Generator Inventory 62.34 3.22 Misc. VOC 0.00 1.71 Totals PTE 126.50 13.35
Emissions from 2017 were utilized in initial SIP planning and are included as a reference within this report.
Subsequent years are recorded within UDAQ’s State and Local Emission Inventory System (SLEIS).
Table 2-2. University’s 2017 Actual Emissions
Unit Group Actual Annual Emissions Estimate (tpy)
NOX VOC Total 2017 Emission Rate 41.49 8.15
2.3 University Efforts to Reduce Emissions
The University was established in 1850 and has committed to reducing the environmental impact of the
University through its sustainability programs. While the University’s sustainability programs have a broad
set of initiatives and focus primarily on Greenhouse Gas (GHG) emissions, the effect of this commitment
translates through the University’s emission profile. This is evidenced through the following actions:
►Ceased operation of LCHTWP Boilers 3 and 4 in 2018 and 2019 respectively
•Boilers 3 and 4 were 105 MMBtu/hr pre-NSPS units with an individual NOX emission rate of 187 parts
per million (ppm ). These units were replaced by Unit 9, a single 72 MMBtu/hr unit, meeting an
emission limit of 9 ppm. The reduction in supplied heat load was possible through campus energy
saving initiatives and lowered the LCHTWP PTE by approximately 38 tpy of NOX.
►Decommissioning of the print plant and flash ironmaking processes in 2018
►Reduced heat load and natural gas usage on UCHTWP to 530 MMscf/yr
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•The UCHTWP historically provided for the heating needs of a variety of hospital buildings. The
hospital was expanded in 2019 and is now semi-independent of the UCHTWP. The new units installed
in the Ambulatory Care Center (ACC) support the existing hospital buildings as well as the ACC
expansion with less natural gas. This reduction in heat load represented an actual decrease in the
natural gas usage of the older UCHTWP boilers, resulting in a reduction of annual emissions.
►Ethylene Oxide Sterilizer
•This unit has been decommissioned and removed from campus on October 12, 2023. Further
discussion of decommissioning will be addressed in a forthcoming permit action.
►Investing in Leadership in Energy and Environmental Design (LEED) certified building designs
•The University continues to expand and construct new buildings which support the primary
initiatives of the University. Each of the new buildings constructed is LEED certified and thus
exemplifies advancements in planning, construction, maintenance, and operations that result in less
energy, less water usage, and reduction in greenhouse gas emissions.2 These advancements allow for
the installation of smaller and more efficient supporting units, such as boilers and emergency
generators. Additionally, the University strives to install the unit with the lowest emission rating
possible while meeting project scope and budget. Smaller more efficient units burn less fuel and
thus produce less NOX and VOC.
►Wherever feasible the University is installing electrical systems and battery packs to replace the need for
diesel fired emergency generators.
2 See this webpage for further information: LEED Buildings | Sustainability (utah.edu)

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3. REASONABLY AVAILABLE CONTROL TECHNOLOGIES BACKGROUND
A RACT analysis has been conducted for each source addressed in Approval Order No. DAQE-AN103540030-
22 and Title V permit #3500063004 in the following sections. The University has organized the RACT
analysis by emission unit group and addressed NO X and VOC precursor in this analysis in accordance with
U.S. EPA’s “top-down” procedures per UDAQ guidance.3
3.1 RACT Methodology
EPA has defined RACT as follows:
The lowest emission limitation that a particular source is capable of meeting by the
application of control technology that is reasonably available considering
technological and economic feasibility.4

RACT for a particular source is determined on a case-by-case basis considering the
technological and economic circumstances of the individual source.5
In EPA’s State Implementation Plans; General Preamble for Proposed Rulemaking on Approval of Plan
Revisions for Nonattainment Areas – Supplement (on Control Techniques Guidelines), it provided a
recommendation to states which says:
…each [Control Technique Guideline] CTG contains recommendations to the States
of what EPA calls the “presumptive norm” for RACT, based on EPA’s current
evaluation of the capabilities and problems general to the industry. Where the States
finds the presumptive norm applicable to an individual source or group of sources,
EPA recommends that the State adopt requirements consistent with the presumptive
norm level in or to include RACT limitations in the SIP.6
The University has referenced the published CTG’s as well as Utah Administrative Code (UAC) for Air Quality
(R307), and proposed rules which establish a current presumptive norm specific to the NWF NAA. The
preamble goes on to state:
…recommended controls are based on capabilities and problems which are general
to the industry; they do not take into account the unique circumstances of each
facility. In many cases appropriate controls would be more or less stringent. States
are urged to judge the feasibility of imposing the recommended control on particular
sources, and adjust the controls accordingly.
3 UDAQ Ozone SIP Planning RACT Analysis, provided January 9, 2023 4 EPA articulated its definition of RACT in a memorandum from Roger Strelow, Assistant Administrator for Air and Waste Management, to Regional Administrators, Regions I-X, on Guidance for determining Acceptability of SIP Regulations in Non-Attainment Areas,” Section 1.a (December 9,1976). 5 Federal Register/Vol. 44. No. 181/Monday, September 17,1979/Proposed Rules – State Implementation Plan; General Preamble for Proposed Rulemaking on Approval of Plan Revisions for Nonattainment Areas – Supplement (on Control Techniques Guidelines). 6 IBID.

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Guidance provided by UDAQ for this RACT analysis states that this analysis is to be conducted using the
“top-down” method.7 In a memorandum dated December 1, 1987, the EPA detailed its preference for a
“top-down” analysis which contains five (5) steps.8 If it can be shown that the most stringent level of
control is technically, environmentally, or economically infeasible for the unit in question, then the next most
stringent level of control is determined and similarly evaluated. This process continues until the RACT level
under consideration cannot be eliminated by any substantial or unique technical, environmental, or
economic objections. Presented below are the five basic steps of a “top-down ” RACT review as identified by
the EPA.
3.1.1 Step 1 – Identify All Reasonably Available Control Technologies
Available control technologies are identified for each emission unit in question. The following methods are
used to identify potential technologies: 1) researching the RACT/BACT/LAER Clearinghouse (RBLC)
database, 2) surveying regulatory agencies, 3) drawing from previous engineering experience, 4) surveying
air pollution control equipment vendors, and/or 5) surveying available literature. Additionally, current CTG’s
as well as UAC R307, and proposed rules were reviewed to establish a current presumptive norm specific to
the NWF NAA.
3.1.2 Step 2 – Eliminate Technically Infeasible Options
To ensure the presumptive norm established applies to the emission source in question a full review of
available control technologies is conducted in the second step of the RACT analysis. In this step each
technology is reviewed for technical feasibility and those that are clearly technically infeasible are
eliminated. EPA states the following with regard to technical feasibility:9
A demonstration of technical infeasibility should be clearly documented and should
show, based on physical, chemical, and engineering principles, that technical
difficulties would preclude the successful use of the control option on the emissions
unit under review.
3.1.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness
Once technically infeasible options are removed from consideration, the remaining options are ranked based
on their control effectiveness. If there is only one remaining option or if all the remaining technologies could
achieve equivalent control efficiencies, ranking based on control efficiency is not required.
3.1.4 Step 4 – Evaluate Most Effective Controls and Document Results
Beginning with the most effective control option in the ranking, detailed economic, energy, and
environmental impact evaluations are performed. If a control option is determined to be economically
feasible without adverse energy or environmental impacts, it is not necessary to evaluate the remaining
options with lower control effectiveness.

The economic evaluation centers on the cost effectiveness of the control option. Costs of installing and
operating control technologies are estimated and annualized following the methodologies outlined in the
7 UDAQ Ozone SIP Planning RACT Analysis, provided January 9, 2023. 8 U.S. EPA, Office of Air and Radiation. Memorandum from J.C. Potter to the Regional Administrators. Washington, D.C. December 1, 1987. 9 U.S. EPA, New Source Review Workshop Manual (Draft): Prevention of Significant Deterioration and Nonattainment Area Permitting, October 1990.

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EPA’s OAQPS Control Cost Manual (CCM) and other industry resources.10 Note that the purpose of this
analysis is not to determine whether controls are affordable for a particular company or industry, but
whether the expenditure effectively allows the source to meet pre-established presumptive norms.
3.1.5 Step 5 – Select RACT
In the final step the lowest emission limitation is proposed as RACT along with any necessary control
technologies or measures needed to achieve the cited emission limit. This proposal is made based on the
evaluations from the previous step.
10 Office of Air Quality Planning and Standards (OAQPS), EPA Air Pollution Control Cost Manual, Sixth Edition, EPA 452-02-001 (https://www.epa.gov/economic-and -cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution), Daniel C. Mussatti & William M. Vatavuk, January 2002.

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4. UCHTWP BOILERS
The upper campus high temperature water plant (UCHWTP), located in Building 302, has three (3) dual fuel
boilers, 1, 3, and 4 that are each rated at 87.5 million British thermal units per hour (MMBtu/hr) equipped
with 15% flue gas recirculation (FGR). These units are primarily natural gas-fired; however, diesel is used as
a backup fuel during periods of natural gas curtailment or natural disaster. These boilers supplement the
needs of the University Hospital’s Level 1 Trauma Center. The unique demands of a Level 1 trauma center,
dictate the need for these units to have dual fuel capabilities, and in turn, creates some barriers to certain
control technologies as described in further detail in the following sections. Recently, the University installed
several new, highly efficiency dual fuel boilers, with low NO X burners. This allowed the University to commit
to a SIP limit of 530 MMscf/yr of natural gas .
4.1 UCHTWP NOX Technologies
The NO X that will be formed during combustion is from two (2) major mechanisms: thermal NOX and fuel
NOX. Since natural gas is relatively free of fuel-bound nitrogen, the contribution of this second mechanism
to the formation of NOX emissions in natural gas-fired equipment is minimal, leaving thermal NOX as the
main source of NOX emissions. Thermal NOX formation is a function of residence time, oxygen level, and
flame temperature, and can be minimized by controlling these elements in the design of the combustion
equipment.
4.1.1 UCHTWP NOX Step 1
The University has reviewed the following sources to ensure all available control technologies have been
identified:

► Proposed UDAQ rule R307-316, NO X Emission Controls for Natural-Gas Fired Boilers greater than 5
MMBtu/hr;
► EPA’s RACT/BACT/LEAR Clearinghouse (RBLC) Database for Natural Gas External Combustion Units
(process type 13.310);11
► EPA’s Air Pollution Technology Fact Sheets;
► EPA’s Clean Air Technology Center (CATC) Alternative Control Techniques Document – NOX Emissions
from Utility Boilers;
► National Emission Standards for Hazardous Air Pollutants (NESHAP) DDDDD – Major Sources: Industrial,
Commercial, and Institutional Boilers and Process Heaters;
► NESHAP JJJJJJ – Industrial, Commercial, and Institutional Boilers at Area Sources;
► New Source Performance Standards (NSPS ) Subpart Dc - Standards of Performance for Small Industrial-
Commercial-Institutional Steam Generating Units12
► South Coast Air Quality Management District (SCAQMD) Lowest Achievable Emission Rate (LAER)/BACT
Determinations;
► San Joaquin Valley Air Pollution Control District (SJVAPCD) BACT Clearinghouse;
► Bay Area Air Quality Management District (BAAQMD) BACT/TBACT Workbook;
► Texas Commission of Environmental Quality (TCEQ) BACT workbook; and
► Permits available online.
The control technologies identified through this search are listed in Table 4-1.
11 Database accessed November 10, 2023. 12 Boilers applicable to NSPS Subpart Dc do not have NOX emission limitations for Natural Gas Fired Boilers.

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Table 4-1. Medium Natural Gas Boilers NOX Controls and Emission Rates from RBLC13

The technologies identified as possible NOX reduction technologies are shown in the table below.

Pollutant Control Technologies
NOX Low NO X Burners (LNB)
Ultra-Low NO X Burners (UNLB)
Flue Gas Recirculation (FGR)
Selective Catalytic Reduction (SCR)
Good Combustion Practices (GCP)

No presumptive norm specifically addresses NOX emissions from dual fuel boilers . Therefore, control
effectiveness, technical, and economical feasibility is compared to the presumptive norm established for
natural gas combustion units in UDAQ rule R307-316, NOX Emission Controls for Natural-Gas Fired Boilers
greater than 5 MMBtu/hr as they apply to the UCHTWP, which requires the following:

► NOX Emission Rate of 9 ppm v; and
► Operate and Maintain (O&M) in accordance with manufacturer's instruction.
4.1.2 UCHTWP NOX Step 2
To demonstrate a complete analysis, the University has evaluated the following technologies including both
replacement burners and add-on controls.
13 The facilities were selected based on process type and purpose of equipment as well as location within similar Non-attainment areas and the application of SIP/PSD BACT.
RBLCID Facility/Agency Name State Permit/Document Issued Control Method Averaging Time Case-by-Case
MD-0041 CPV ST. CHARLES MD 04/23/2014 &nbsp;ACT 93 MMBTU/H
EXCLUSIVE USE OF NATURAL GAS, ULTRA LOW-
NOX BURNERS, AND FLUE GAS RECIRCULATION
(FGR)
0.011 LB/MMBTU 3-HOUR AVERAGE LAER
MD-0046 KEYS ENERGY CENTER MD 10/31/2014 &nbsp;ACT 93 MMBTU/H
EFFICIENT BOILER DESIGN WITH ULTRA LOW
NOX BURNER, EXCLUSIVE USE OF PIPELINE
QUALITY NATURAL GAS, AND APPLICATION OF
GOOD COMBUSTION PRACTICES
0.01 LB/MMBTU 3-HOUR BLOCK
AVERAGE BACT-PSD
MI-0424 HOLLAND BOARD OF PUBLIC
WORKS - EAST 5TH STREET MI 12/05/2016 &nbsp;ACT 83.5 MMBTU/H Low NOx burners/Internal flue gas
recirculation and good combustion practices.0.05 LB/MMBTU TEST PROTOCOL WILL
SPECIFY AVG TIME BACT-PSD
OH-0381 NORTHSTAR BLUESCOPE
STEEL, LLC OH 09/27/2019 &nbsp;ACT 88 MMBTU/H Use of natural gas, use of low NOx burners,
good combustion practices and design 6.16 LB/H NA BACT-PSD
PA-0310 CPV FAIRVIEW ENERGY
CENTER PA 09/02/2016 &nbsp;ACT 92.4 MMBtu/hr Ultra low NOx burners, FGR, good combustion
practices 0.011 LB/MMBTU AVG OF 3 1-HR TEST
RUNS LAER
*PA-0319 RENAISSANCE ENERGY
CENTER PA 08/27/2018 &nbsp;ACT 88 MMBtu/hr
Lo-NOx burners, Flue Gas Recirculation, good
combustion practices, proper operation and
maintainance.
0.02 LB/MMBTU HR LAER
TX-0713 TENASKA BROWNSVILLE
GENERATING STATION TX 04/29/2014 &nbsp;ACT 90 MMBTU/H ultra low-NOx burners, limited use 9 PPMVD @15% O2 BACT-PSD
-BAAQMD CA 8/4/2010 ≥50 MMB tu/hr Ultra Low NOx Burners & FGR NA BACT
-SJVAPCD CA 11/30/2022 ≥20 MMBtu/hr Assumed SCR 0.003 LB/MMBTU NA BACT
-SCAQMD CA 12/2/1999 33.9 MMBtu/hr SCR 7 ppm NA BACT
-SCAQMD CA 3/22/2016 39.9 MMBtu/hr SCR 5 ppm 15 mins LAER
-SCAQMD CA 5/19/2004 39 MMBtu/hr Ultra-Low NOx Burner & FGR 9 ppm NA BACT
-TCEQ TX 10/1/2018 >40 MMBtu/hr Low NOx Burners & SCR 0.01 LB/MMBTU NA BACT
Emission LimitThroughput
NA

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Low NOX Burners
LNB technology uses advanced burner design to reduce NOX formation through the restriction of oxygen,
flame temperature, and/or residence time. There are two (2) general types of LNB: staged fuel and staged
air burners. In a stage fuel LNB, the combustion zone is separated into two regions. The first region is a
lean combustion region where a fraction of the fuel is supplied with the total quantity of combustion air.
Combustion in this zone takes place at substantially lower temperatures than a standard burner. In the
second combustion region, the remaining fuel is injected and combusted with leftover oxygen from the first
region. A staged air burner begins with full fuel but only partial combustion air, and then adds the remaining
combustion air in the second combustion region. These techniques reduce the formation of thermal NOX.
This technology is listed in the RBLC search as a technically feasible control technology.
Ultra Low NOX Burners
ULNB technology uses internal FGR which involves recirculating the hot O2 depleted flue gas from the heater
into the combustion zone using burner design features and fuel staging to reduce NOX. A ULNB most
commonly uses an internal induced draft to reach the desired emission limitations. This technology is listed
in the RBLC search as a technically feasible control technology. A ULNB can achieve an emission rate of
approximately 9 ppm or 0.011 pounds per million British thermal units (lb/MMBtu) when used in conjunction
with FGR.
Flue Gas Recirculation
FGR is frequently used with both LNB and ULNB burners. FGR involves the recycling of post-combustion air
into the air-fuel mixture to reduce the available oxygen and help cool the burner flame. External FGR
requires the use of ductwork to route a portion of the flue gas in the stack back to the burner windbox; FGR
can be either forced draft (where hot side fans are used) or induced draft. This technology is listed in the
RBLC search as technically feasible and is paired with LNB for the BACT determined control technology.
Currently, the UCHTWP boilers use this technology.
Selective Catalytic Reduction
SCR has been applied to stationary source, fossil fuel-fired, combustion units for emission control since the
early 1970s. It has been applied to large (>250 MMBtu/hr) utility and industrial boilers, process heaters, and
combined cycle gas turbines. SCR can be applied as a stand-alone NOX control or with other technologies
such as combustion controls. The reagent reacts selectively with the flue gas NOX within a specific
temperature range and in the presence of the catalyst and oxygen to reduce the NOX into molecular
nitrogen (N2) and water vapor (H2O).14 The optimum operating temperature is dependent on the type of
catalyst and the flue gas composition. Generally, the optimum temperature ranges from 480°F to 800°F.15 In
practice, SCR systems operate at efficiencies in the range of 70% to 90%.16

SCR is listed in the RBLC search as technically feasible. In some cases, this control technology is listed in
combination with LNB and FGR. As previously mentioned, BAAQMD defines BACT as the combination of
SCR, LNB, and FGR.

14 EPA Air Pollution Control Technology Fact Sheet, Selective Catalytic Reduction (SCR) 15 OAQPS, EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/424/B-02-001 (https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution); January 2002 16 OAQPS, EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/424/B-02-001 (https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution)); January 2002

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The ammonia “slip” associated with the SCR is a documented problem. The increased ammonia emissions
(currently zero) from the implementation of this technology would offset the marginal air quality benefits
the SCR option would provide from NOX emissions reduction. Additionally, ammonia slip emissions have the
potential to increase secondary PM2.5 levels which would impact the surrounding PM2.5 serious
nonattainment area and it is anticipated that the increase in particulate would offset any anticipated NOX
emissions. Storage and handling of ammonia poses significant safety risks when applied at the University of
Utah. Ammonia is toxic if swallowed or inhaled and can irritate or burn the skin, eyes, nose, or throat. It is a
commonly used material that is typically handled safely and without incident. However, there are potential
health and safety hazards associated with the implementation of this technology. The UCHTWP is located in
a densely-packed area with other public facilities including student dormitories and the Red Butte
Amphitheater, and a significant number of University staff, students, and the general public potentially in
harm's way. Locating ammonia tanks in these premises poses significant health risks for students, faculty,
patients, family members and the general public if a leak were to occur.

The exhaust stream entering the SCR will require additional heat to meet the SCR operating temperature
requirements (minimum of 480°F). This increase in exhaust temperature would require an additional
combustion device, also increasing NOX, SO2, VOC, and PM2.5 emissions.

Furthermore, there is a physical space issue concerning this technology. Building 302, where the UCHTWP
boilers are housed, is confined by other buildings in the immediate proximity and may not provide the space
required to physically install an SCR. The location of the boilers within the building also presents a space
challenge when installing an SCR. That being said, the costs of installing an SCR would likely be higher than
that presented in Step 4 below due to the limited amount of space under the current configuration.
Though there are obvious physical limitations, public safety concerns, and additional pollutants being
emitted to use this add-on control technology, the control device is being evaluated for cost feasibility.
Good Combustion Practices
The use of good combustion practices usually includes the following components: (1) proper fuel mixing in
the combustion zone; (2) high temperatures and low oxygen levels in primary zone; (3) overall excess
oxygen levels high enough to complete combustion while maximizing boiler efficiency, and (4) sufficient
residence time to complete combustion. Good combustion practices are accomplished through boiler design
as it relates to time, temperature, turbulence, and boiler operation as it relates to excess oxygen levels.
4.1.3 UCHTWP NOX Step 3
Based on an RBLC search the following technologies are currently being used for boilers less than or equal
to 100 MMBtu/hr. These are ranked based on which technology can achieve the lowest emission rate. Note,
an ULNB has not been proven with an SCR based on RBLC review.
1. LNB + SCR = 5 ppm or 0.004 lb/MMBtu17
2. ULNB = 9 ppm or 0.008 lb/MMBtu
3. LNB = 30 ppm or 0.036 lb/MMBtu
4. FGR = 42 ppm or 0.05 lb/MMBtu
4.1.4 UCHTWP NOX Step 4
The UCHTWP boilers are currently using 15% FGR and achieve an emission rate of 0.05 lb/MMBtu. To
achieve the presumptive norm established, an emission rate of 9 ppm, an SCR may be installed on each
17 This emissions rate is representative of LAER.

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boiler. The University conducted a cost analysis following the method described in EPA Cost Control Manual
Section 4 Chapter 2 Selective Catalytic Reduction Costs. Key to this analysis is the reduction removal
efficiency and interest rate. For this analysis the University has used a reduction rate equivalent to a
decreased emission rate of 9 ppm NO X.

Since the actual nominal interest rate for a project of this type is not readily available to the University,
additional resources were reviewed to determine appropriate nominal interest rates for this industry sector
and project type. One such resource was the Office of Management and Budget (OMB). For economic
evaluations of the impact of federal regulations, the OMB uses an interest rate of 7%.18 A nominal interest
rate of 7% has been referenced in EPA’s Cost Manual and has been commonly relied upon for control
technology analyses for several decades as a representative average over time.

Based on a 9 ppm emission rate and 7% interest rate the cost per ton removed is $63,911.19 Calculations
are shown in Appendix A and are based on EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic
Reduction Costs and Section 1 Chapter 2 Cost Estimation: Concepts and Methodology. The cost per ton of
NOX removed is beyond acceptable cost control effectiveness levels and therefore, the University has
determined that this technology is economically infeasible for these units.

The University also reviewed replacing the current burner with an UNLB with an emission rate of 9 ppm NO X
or less. Using a manufacture supplier total equipment cost and 7% interest rate, it would cost $46,956/ton
of NO x removed to achieve the 9 ppm emission rate. The cost per ton of NOX removed is beyond acceptable
cost control effectiveness levels and therefore, the University is considering this burner technology
economically infeasible for these units. Detailed cost calculations for this control technology for the UCHTWP
are provided in Appendix A. Installation of a lower efficiency burner, i.e. LNB technology, is not expected to
decrease the capital investment substantially. Therefore, the University has assumed replacing the current
burner with a LNB is also economically infeasible.
4.1.5 UCHTWP NOX Step 5
The boilers in the UCHWTP employ FGR and O&M in accordance with manufacturer’s instruction which
meets RACT. The University completes O&M in accordance with manufacturer recommendations, however
replacement of the burner or the addition of SCR is economically infeasible. As a result, the University
proposes that an emission rate of 0.05 lb/MMBtu using 15% FGR, limited natural gas consumption, and
appropriate O&M meet RACT.
4.2 UCHTWP VOC Technologies
4.2.1 UCHTWP VOC Step 1
The University has reviewed the following sources to ensure all available control technologies have been
identified:

► EPA’s RBLC Database for Natural Gas External Combustion Units (process type 13.310);20
► EPA’s Air Pollution Technology Fact Sheets;
► EPA’s CATC Alternative Control Techniques Document – NOX Emissions from Utility Boilers;
► NESHAP DDDDD – Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters;
18 OMB Circular A-4, https://obamawhitehouse.archives.gov/omb/circulars_a004_a-4/ 19 Based on a vendor cost estimate. 20 Database accessed November 10, 2023.

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► NESHAP JJJJJJ – Industrial, Commercial, and Institutional Boilers at Area Sources;
► SCAQMD LAER/BACT Determinations;
► SJVAPCD BACT Clearinghouse;
► BAAQMD BACT/TBACT Workbook21;
► TCEQ BACT Workbook; and
► Permits available online.

The technologies identified as possible VOC reduction technologies are shown in the table below.

Pollutant Control Technologies VOCs Thermal Oxidizer/Afterburner Regenerative Thermal Oxidizer (RTO) Catalytic Oxidation Good Combustion Practices

No presumptive norm has been established for VOC emissions from combustion sources due to the low
emission rate of units.
4.2.2 UCHTWP VOC Step 2
To demonstrate a complete analysis, the University has evaluated the following technologies:
Simple Thermal Oxidizer or Afterburner (TO)
In a simple TO or afterburner, the flue gas exiting the boiler is reheated in the presence of sufficient oxygen
to oxidize the VOC present in the flue gas. A typical TO is a flare and is not equipped with any heat recovery
device. A TO will require additional fuel to heat the gas stream starting from 280°F to at least 1,600°F and
which will generate additional emissions. Additionally, a TO is no different from the combustion chamber of
the boiler. Therefore, there would be little expected reduction in VOC with an increase in other combustion
pollutants for the required heating of the exhaust stream. Therefore, the TO is not considered further.
Regenerative Thermal Oxidizer (RTO)
A RTO is equipped with ceramic heat recovery media (stoneware) that has large surface area for heat
transfer and can be stable to 2,300°F. Operating temperatures of the RTO system typically range from
1,500°F to 1,800°F with a retention time of approximately one second. The combustion chamber of the RTO
is surrounded by multiple integral heat recovery chambers, each of which sequentially switches back and
forth from being a preheater to a heat recovery chamber. In this fashion, energy is absorbed from the gas
exhausted from the unit and stored in the heat exchange media to preheat the next cycle of incoming gas.
An RTO will require additional fuel to heat the gas stream from 280°F to at least 1,500°F and which will
generate additional emissions; therefore, the RTO is not considered further.
Catalytic Oxidation
Catalytic oxidation allows complete oxidation to take place at a faster rate and a lower temperature than is
possible with thermal oxidation. Oxidation efficiency depends on exhaust flow rate and composition.
Residence time required for oxidation to take place at the active sites of the catalyst may not be achieved if
exhaust flow rates exceed design specifications. Also, sulfur and other compounds may foul the catalyst,
21 BAAQMD BACT/TBACT Workbook - BACT(2) for POC is GCP

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leading to decreased efficiency. In a typical catalytic oxidizer, the gas stream is passed through a flame area
and then through a catalyst bed at a velocity in the range of 10 to 30 feet per second (fps). Catalytic
oxidizers typically operate at a narrow temperature range of approximately 600°F to 1100°F. A catalytic
oxidizer will require additional fuel to heat the gas stream from 280°F to at least 600°F and which will
generate additional emissions; therefore, catalytic oxidation is not considered further.
Good Combustion Practices and Use of Clean Burning Fuels
Good combustion practices for VOCs include adequate fuel residence times, proper fuel-air mixing, and
temperature control. As it is imperative for process controls, the University will maintain combustion optimal
to their process. Most results in RBLC determined that this was sufficient controls for VOC. Additionally,
BAAQMD and SCAQMD did not provide BACT determinations for VOC.
4.2.3 UCHTWP VOC Steps 3-5
Steps 3 and 4 are not necessary since all control technologies not currently being used have been
determined technically infeasible. Since no presumptive norm has been established for VOC emissions and
all technically and economically feasible controls are currently utilized, the University proposes that good
combustion practices and the use of a clean burning fuel meets RACT.

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5. LCHTWP BOILERS
The lower campus high temperature water plant (LCHTWP) provides the heating and cooling necessary for
the lower (western) portion of campus and is located in Building 303. The LCHWTP has three natural gas-
fired boilers and a cogeneration unit which consists of a turbine and a waste heat recovery unit.

This section focuses on the two (2) units rated at 50 MMBtu/hr each (Units 6 and 7) and the one (1) unit
rated at 72 MMBtu/hr (Unit 9). Table 5-1 below summarizes the operating characteristics and installation
date for each boiler.
Table 5-1. Operating Characteristics and Installation Date
Boiler
Number
Input
Capacity
(MMBtu/hr)
Installed/Operating
Characteristics Installation Date
Unit 6 50 - Utilize LNB + FGR - 9 ppm Installed in 2016 Unit 7 50 - Utilize LNB + FGR - 9 ppm Installed in 2016 Unit 9 72 - Utilize ULNB - 9 ppm Installed in 2019

Startup and shutdown emissions are anticipated to be less than or equal to emissions during normal
operations on the boilers at the LCHTWP.
5.1 LCHTWP NOX Technologies
The NO X that will be formed during combustion is from two major mechanisms: thermal NOX and fuel NOX.
Since natural gas is relatively free of fuel-bound nitrogen, the contribution of this second mechanism to the
formation of NOX emissions in natural gas-fired equipment is minimal, leaving thermal NOX as the main
source of NO X emissions. Thermal NO X formation is a function of residence time, oxygen level, and flame
temperature, and can be minimized by controlling these elements in the design of the combustion
equipment.
5.1.1 LCHTWP NOX Step 1
The University has reviewed the following sources to ensure all available control technologies have been
identified:

► Proposed UDAQ rule R307-316, NOX Emission Controls for Natural-Gas Fired Boilers greater than 5
MMBtu/hr;
► EPA’s RBLC Database for Natural Gas External Combustion Units (process type 13.31);22
► EPA’s Air Pollution Technology Fact Sheets;
► EPA’s CATC Alternative Control Techniques Document – NOX Emissions from Utility Boilers;
22 Database accessed November 10, 2023

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► NESHAP DDDDD – Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters;
► NESHAP JJJJJJ – Industrial, Commercial, and Institutional Boilers at Area Sources;
► SCAQMD LAER/BACT Determinations;
► SJVAPCD BACT Clearinghouse;
► BAAQMD BACT/TBACT Workbook; and
► Permits available online.

The results of these searches are summarized in the table below:
Table 5-2. Medium Natural Gas Boilers NOX Controls and Emission Rates from RBLC23

The technologies identified as possible NOX reduction technologies are shown in the table below.

Pollutant Control Technologies NOX Low NOX Burners Ultra-Low NOX Burners Flue Gas Recirculation Selective Catalytic Reduction Good Combustion Practices

23 Database accessed November 10, 2023
RBLCID Facility/Agency Name State Permit/Document Issued Control Method Averaging Time Case-by-Case
AK-0083 KENAI NITROGEN OPERATIONS AK 01/06/2015 &nbsp;ACT 50 MMBTU/H Selective Catalytic Reduction 7 PPMV 3-HR AVG @ 15 % O2 BACT-PSD
AR-0155 BIG RIVER STEEL LLC AR 11/07/2018 &nbsp;ACT 53.7 MMBTU/HR
LOW NOX BURNERS COMBUSTION OF
CLEAN FUEL GOOD COMBUSTION
PRACTICES
0.035 LB/MMBTU NA BACT-PSD
AR-0167 LION OIL COMPANY AR 12/01/2020 &nbsp;ACT 75 MMBtu/hr Ultra-low NOx burners and good
combustion practice 3.5 LB/HR 3-HOUR AVERAGE BACT-PSD
FL-0367 SHADY HILLS COMBINED CYCLE
FACILITY FL 07/27/2018 &nbsp;ACT 60 MMBtu/hour low-NOx burners 0.05 LB/MMBTU NA BACT-PSD
IN-0263 MIDWEST FERTILIZER COMPANY LLC IN 03/23/2017 &nbsp;ACT 70 MMBTU/HR GOOD COMBUSTION PRACTICES 12.611 LB/H 3 HOUR AVERAGE BACT-PSD
IN-0359 NUCOR STEEL IN 03/30/2023 &nbsp;ACT 50 MMBtu/hr low NOx burners 0.035 LB/MMBTU BACT-PSD
KY-0110 NUCOR STEEL BRANDENBURG KY 07/23/2020 &nbsp;ACT 54 MMBtu/hr
Low-Nox Burner (Designed to maintain
0.15 lb/MMBtu in flameless mode and 0.25
lb/MMBtu in flame mode); and a Good
Combustion and Operating Practices
(GCOP) Plan.
158 LB/MMSCF FLAMELESS MODE BACT-PSD
KY-0115 NUCOR STEEL GALLATIN, LLC KY 04/19/2021 &nbsp;ACT 50.4 MMBtu/hr
The permittee must develop a Good
Combustion and Operating Practices
(GCOP) Plan. Also equipped with low-NOx
burners.
35 LB/MMSCF NA BACT-PSD
KY-0116 NOVELIS CORPORATION - GUTHRIE KY 07/25/2022 &nbsp;ACT 53 MMBtu/hr
(total)
Good Combustion & Operation Practices
(GCOP) Plan 5.3 LB/HR MONTHLY AVERAGE BACT-PSD
*LA-0315 G2G PLANT LA 05/23/2014 &nbsp;ACT 61 MMBTU/HR Ultra-Low NOx Burners (ULNB)2.44 LB/H HOURLY MAXIMUM BACT-PSD
MI-0447 LBWL--ERICKSON STATION MI 01/07/2021 &nbsp;ACT 50 MMBTU/H
Low NOx burners (LNB) or flue gas
recirculation (FGR) along with good
combustion practices.
30 PPM AT 3% O2; HOURLY BACT-PSD
NY-0103 CRICKET VALLEY ENERGY CENTER NY 02/03/2016 &nbsp;ACT 60 MMBTU/H flue gas recirculation with low NOx
burners 0.0085 LB/MMBTU 1 H LAER
PA-0307 YORK ENERGY CENTER BLOCK 2
ELECTRICITY GENERATION PROJECT PA 06/15/2015 &nbsp;ACT 62.04 MCF/hr Good combustion practices, Ultra-Low NOx
burners, FGR 0.0086 LB/MMBTU NA LAER
TX-0851 RIO BRAVO PIPELINE FACILITY TX 12/17/2018 &nbsp;ACT 71.3 MMBTU/HR Low NOx burners and good combustion
practices.0.162 LB/MMBTU NA BACT-PSD
VA-0321 BRUNSWICK COUNTY POWER
STATION VA 03/12/2013 &nbsp;ACT 66.7 MMBTU/H Dry Low NOx burner.9 PPMVD NA BACT-PSD
-BAAQMD CA 8/4/2010 ≥50 MMBtu/hr Ultra Low NOx Burners & FGR NA BACT
-SJVAPCD CA 11/30/2022 ≥20 MMBtu/hr Assumed SCR 0.003 LB/MMBTU NA BACT
-SCAQMD CA 12/2/1999 33.9 MMBtu/hr SCR 7 ppm NA BACT
-SCAQMD CA 3/22/2016 39.9 MMBtu/hr SCR 5 ppm 15 mins LAER
-SCAQMD CA 5/19/2004 39 MMBtu/hr Ultra-Low NOx Burner & FGR 9 ppm NA BACT
-TCEQ TX 10/1/2018 >40 MMBtu/hr Low NOx Burners & SCR 0.01 LB/MMBTU NA BACT
Throughput Emission Limit
NA

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The control efficiencies along with technical and economic feasibility are compared to the presumptive norm
established in proposed UDAQ rule R307-316, NO X Emission Controls for Natural-Gas Fired Boilers greater
than 5 MMBtu/hr as they apply to the LCHTWP, which requires the following:

► NOX Emission Rate of 9 ppmv; and
► Operate and Maintain (O&M) in accordance with manufacturer's instruction.
5.1.2 LCHTWP NOX Step 2
To demonstrate a complete analysis, the University has evaluated the following technologies including both
replacement burners and add-on controls.
Low NOX Burners
LNB technology uses advanced burner design to reduce NOX formation through the restriction of oxygen,
flame temperature, and/or residence time. There are two general types of LNB: staged fuel and staged air
burners. In a stage fuel LNB, the combustion zone is separated into two regions. The first region is a lean
combustion region where a fraction of the fuel is supplied with the total quantity of combustion air.
Combustion in this zone takes place at substantially lower temperatures than a standard burner. In the
second combustion region, the remaining fuel is injected and combusted with leftover oxygen from the first
region. A staged air burner begins with full fuel but only partial combustion air, and then adds the remaining
combustion air in the second combustion region. These techniques reduce the formation of thermal NOX.
This technology is listed in the RBLC search as a technically feasible control technology.
Ultra Low NOX Burners
ULNB technology uses internal FGR which involves recirculating the hot O2 depleted flue gas from the heater
into the combustion zone using burner design features and fuel staging to reduce NOX. An ULNB is most
commonly using an internal induced draft to reach the desired emission limitations. This technology is listed
in the RBLC search as a technically feasible control technology. An ULNB can achieve an emission rate of
approximately 9 ppm or 0.011 lb/MMBtu. UDAQ has established this as the NOX emission standard through
proposed boiler rules R307-315 and 316 as the use of an ULNB is the most common method utilized to meet
a 9 ppm emission guarantee.24 Currently, unit 9 uses this technology.
Flue Gas Recirculation
FGR is frequently used with both LNB and ULNB burners. FGR involves the recycling of post-combustion air
into the air-fuel mixture to reduce the available oxygen and help cool the burner flame. External FGR
requires the use of ductwork to route a portion of the flue gas in the stack back to the burner windbox; FGR
can be either forced draft (where hot side fans are used) or induced draft. This technology is listed in the
RBLC search as technically feasible and is paired with LNB for the BACT determined control technology.
Currently, Units 6 and 7 utilize use this technology.
Selective Catalytic Reduction
SCR has been applied to stationary source, fossil fuel-fired, combustion units for emission control since the
early 1970s. It has been applied to utility and industrial boilers, process heaters, and combined cycle gas
turbines. SCR can be applied as a stand-alone NOX control or with other technologies such as combustion
controls. The reagent reacts selectively with the flue gas NOX within a specific temperature range and in the
presence of the catalyst and oxygen to reduce the NOX into molecular nitrogen (N2) and water vapor
24 Effective July 10, 2023

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(H2O).25 The optimum operating temperature is dependent on the type of catalyst and the flue gas
composition. Generally, the optimum temperature ranges from 480°F to 800°F.26 In practice, SCR systems
operate at efficiencies in the range of 70% to 90%.27

SCR is listed in the RBLC search as technically feasible. In some cases, this control technology is listed in
combination with LNB and FGR.

The ammonia "slip" associated with the SCR is a documented problem. The increased ammonia emissions
(currently zero) from the implementation of this technology would offset the marginal air quality benefits
the SCR option would provide from NOX emissions reduction. Additionally, ammonia slip emissions have the
potential to increase secondary PM2.5 levels which would impact the surrounding PM2.5 serious
nonattainment area and it is anticipated that the increase in particulate would offset any anticipated NOx
emissions. Storage and handling of ammonia poses significant safety risks when applied at the University of
Utah. Ammonia is toxic if swallowed or inhaled and can irritate or burn the skin, eyes, nose, or throat, it is a
commonly used material that is typically handled safely and without incident. However, there are potential
health and safety hazards associated with the implementation of this technology. The LCHTWP is located in
a densely-packed area with other public facilities and a significant number of University staff, students, and
the general public potentially in harm's way. Locating ammonia tanks in these premises poses significant
health risks for students, faculty, patients, family members and the general public if a leak were to occur.
The exhaust stream entering the SCR will require additional heat to meet the SCR operating temperature
requirements (minimum of 480°F). This increase in exhaust temperature would require an additional
combustion device, also increasing NOX, SO2, and PM2.5 emissions.

Furthermore, there is a physical space issue concerning this technology. Building 303, where the LCHTWP
boilers are housed, is confined by other buildings in the immediate proximity and currently does not provide
the space required to physically install an SCR. The location of the boilers within the building also presents a
space challenge when installing an SCR. The physical space restriction within Building 303 is more confined
than the physical space in Building 302 as discussed in Section 4. Therefore, the SCR is considered
technically infeasible for the boilers located in Building 303 due to physical limitations, public safety
concerns, and additional pollutants being emitted to use this add-on control technology.
Good Combustion Practices
The use of good combustion practices usually includes the following components: (1) proper fuel mixing in
the combustion zone; (2) high temperatures and low oxygen levels in primary zone; (3) Overall excess
oxygen levels high enough to complete combustion while maximizing boiler efficiency, and (4) sufficient
residence time to complete combustion. Good combustion practices are accomplished through boiler design
as it relates to time, temperature, and turbulence, and boiler operation as it related to excess oxygen levels.
5.1.3 LCHTWP NOX Steps 3-5
Based on an RBLC search the following technologies are currently being used and are ranked based on
which technology can achieve the lowest emission rate.

1. ULNB or LNB + FGR = 9 ppm or 0.011 lb/MMBtu
25 EPA Air Pollution Control Technology Fact Sheet, Selective Catalytic Reduction (SCR) 26 OAQPS, EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/424/B-02-001 (https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution); January 2002 27 OAQPS, EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/424/B-02-001 (https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution); January 2002

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2. LNB = 30 ppm or 0.036 lb/MMBtu
3. FGR = 187 ppm or 0.23 lb/MMBtu

Units 6 and 7 currently utilize LNB and FGR and have a permitted NOX emission rate of 9 ppm (0.25 lb/hr),
each.28 Unit 9, utilizes ULNB technology and achieves an emission rate of 9 ppm. The presumptive norm for
the units in question is 9 ppmv, and O&M in accordance with manufacturer’s instructions. Since these units
meet the presumptive norm, the University proposes they meet RACT.
5.2 LCHTWP VOC Technologies
This RACT analysis has well established, after reviewing a variety of control techniques, for various sizes and
fuels, that the proposed RACT is good combustion practices since all control technologies not currently
being used have been determined technically infeasible.
28 AO AN103540025-13, Permit Condition II.B.2.c

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6. LCHTWP TURBINE WITH WASTE HEAT RECOVERY
The University has a natural gas-fired turbine cogeneration plant which includes both a turbine and waste
heat recovery unit (WHRU) with duct burner. This combination is also known as a combined cycle turbine.
The turbine model is a Solar Taurus 70 T7800S equipped with Solar’s SoLoNOxTM technology. The
SoLoNOxTM technology uses lean-premixed combustion technology to ensure uniform air/fuel mixture, thus
reducing formation of regulated pollutants. The unit is rated to 7.23 megawatts (MW) and de-rated to 6.5
MW based on altitude. The turbine has a heat input of 72.78 MMBtu/hr. The recycled waste heat from the
gas turbine is sent to a Rentech waste heat recovery boiler. The supplemental duct burner is rated at 85
MMBtu/hr.

The WHRU is a part of the combined cycle turbine system. The WHRU cannot operate without the turbine.
For general practice the WHRU and turbine operate together and therefore have been evaluated as one
unit. This unit is subject to the requirements of NSPS Subpart KKKK.

The following sections detail potential controls and operating conditions necessary to achieve the required
emissions for each pollutant. The review will detail controls as they apply to normal operations. Startup and
shutdown operations manage emission rates by minimizing the duration of startup and shutdown.
Therefore, the University during a startup will bring the turbine to the minimum load necessary to achieve
compliance with the applicable NOX emission limits as quickly as possible, consistent with the equipment
manufacturers’ recommendations and safe operating practices. During a shutdown, once the turbine
reaches a load that is below the minimum load necessary to maintain compliance with the applicable NOX
emission limits, reduce the turbine load to zero as quickly as possible, consistent with the equipment
manufacturers’ recommendations and safe operating practices.

Startup and shutdown emissions are anticipated to be less than or equal to emissions during normal
operations on the turbine and WHRU at the LCHTWP.
6.1 Turbine and WHRU NOX Technologies
The NO X that will be formed during combustion by two major mechanisms: thermal NOX and fuel NOX. Since
natural gas is relatively free of fuel-bound nitrogen, the contribution to the formation of NOX emissions in
natural gas-fired equipment is minimal and thermal NOX is the chief source of NOX emissions. Thermal NOX
formation is a function of residence time, oxygen level, and flame temperature, and can be minimized by
controlling these elements in the design of the combustion equipment.

The turbine is permitted for an emission rate of 9 ppm NOX at 15% O2 and 2.65 pounds per hour (lbs/hr).29
The combined turbine and WHRU duct burner is permitted for an emission rate of 15 ppm NOX at 15% O2
and 18.97 lb/hr.30
6.1.1 Turbine and WHRU NOX Step 1
Potential control technologies were identified through the review of the following:

► SCAQMD LAER/BACT Determinations;
► BAAQMD BACT/TBACT Workbook;
29 Title V Operating Permit #3500063004 Condition II.B.4.a. 30 Ibid.

University of Utah / Ozone Non-attainment SIP – RACT Analysis
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► SJVAPCD BACT Clearinghouse;
► EPA’s RBLC Database for Combined Cycle Turbines (16.210);31
► EPA Alternative Control Techniques Document – NO X Emissions from Stationary Gas Turbines;
► NSPS KKKK – Standards of Performance for Stationary Combustion Turbines; and
► TCEQ BACT Requirements.

The results are as follows:
Table 6-1. NOX Turbine Controls and Emission Rates from RBLC32

The technologies identified as possible NOX reduction technologies for small combustion, combined cycle
and cogeneration turbines are shown in the table below.

Pollutant Control Technologies NOX Dry Low NOX Combustors/Low NOX Burner Selective Catalytic Reduction (SCR) EMx (formerly SCONOx) System Water/Steam Injection Natural Gas Usage and Good Combustion Practices
Control technologies included in this table are those that have been shown in
practice for use in one of the previously listed databases.

UDAQ has not established state specific emission limits for combined cycle turbines. As a result, the
University proposes the presumptive norm is consistent with NSPS Subpart KKKK which establishes NOX
emission limits.
31 Database accessed November 10, 2023. 32 Database accessed November 10, 2023.
RBLCID Facility/Agency Name State Permit/Document Issued Control Method Averaging Time Case-by-Case
AK-0086 KENAI NITROGEN
OPERATIONS AK 03/26/2021 &nbsp;ACT 102.1 MMBtu/hr Selective Catalytic Reduction and
SoLoNOx Technology on Turbines 5 PPMV AT 15% O2 THREE-HOUR
AVERAGE BACT-PSD
IN-0173 MIDWEST FERTILIZER
CORPORATION IN 06/04/2014 &nbsp;ACT 283 MMBTU/H,
EACH DRY LOW NOX COMBUSTORS 22.65 PPMVD AT 15%
OXYGEN
3-HR AVERAGE AT >
50% PEAK LOAD BACT-PSD
IN-0173 MIDWEST FERTILIZER
CORPORATION IN 06/04/2014 &nbsp;ACT 218.6 MMBTU/H,
EACH
LOW NOX BURNERS, FLUE GAS
RECIRCULATION 20.4 LB/MMCF 3-HR AVERAGE BACT-PSD
IN-0180 MIDWEST FERTILIZER
CORPORATION IN 06/04/2014 &nbsp;ACT 283 MMBTU/H,
EACH DRY LOW NOX COMBUSTORS 22.65 PPMVD AT 15%
OXYGEN
3-HR AVERAGE AT >
50% PEAK LOAD BACT-PSD
IN-0180 MIDWEST FERTILIZER
CORPORATION IN 06/04/2014 &nbsp;ACT 218.6 MMBTU/H,
EACH
LOW NOX BURNERS, FLUE GAS
RECIRCULATION 20.4 LB/MMCF 3-HR AVERAGE BACT-PSD
LA-0295 WESTLAKE FACILITY LA 07/12/2016 &nbsp;ACT 159.46 MMBTU/HR
Dry low NOx combustor (SoLoNOx)
and good combustion practices,
including good equipment design,
use of gaseous fuels for good
mixing, and proper combustion
techniques (see notes below)
14.25 LB/HR HOURLY MAXIMUM BACT-PSD
MA-0041 MEDICAL AREA TOTAL
ENERGY PLANT MA 07/01/2016 &nbsp;ACT 203.4 MMBTU/H Dry Low NOx Combustor & Selective
Catalytic Reduction 2 PPMVD@15% O2
1 HR BLOCK
AVG/EXCLUDING SS,
NG FIRING
OTHER CASE-
BY-CASE
MA-0043 MIT CENTRAL UTILITY
PLANT MA 06/21/2017 &nbsp;ACT 353 MMBtu/hr Dry Low NOx combustor for CTG &
Selective Catalytic Reduction 2 PPMVD@15% O2
1 HR BLOCK
AVG/EXCLUDING SS,
NG FIRING
OTHER CASE-
BY-CASE
-SCAQMD CA 03/08/18 547.5 MMBtu/hr SCR 2 PPMV 1 hour BACT
-SCAQMD CA 02/05/21 490 MMBtu/hr SCR 2.3 PPMV@15% O2 1 hour BACT
-SCAQMD CA 01/30/04 525 MMBtu/hr Dry Low-NOx 2 PPMVD@15% O2 1 hour BACT
Throughput Emission Limit

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6.1.2 Turbine and WHRU NOX Step 2
Dry Low NOX Combustors/Low NOX Burner (Turbine Only)
Although dry low NOX (DLN) combustors designed by different manufacturers may vary, they all employ the
strategies of fuel and air pre-mixing and staged combustion to minimize NOX formation in combustion
turbines. The combustors burn a lean, pre-mixed fuel and air mixture to avoid localized high temperature
regions. A lean air-to-fuel ratio approaching the lean flammability limit is maintained, and the excess air acts
as a heat sink to lower combustion temperatures, which lowers thermal NO X formation. A pilot flame is used
to maintain combustion stability in this fuel-lean environment. Other techniques, such as variable geometry,
fuel staging, or combustion staging, are also incorporated in DLN combustor design. The turbine currently
includes this control technology, also known as the SoLoNOxTM technology.
Ultra-Low NOX Burner (WHRU Only)
ULNB technology combines internal flue gas recirculation (FGR), a low NOX burner and advanced
engineering principle to further optimize oxygen concentrations, flame temperature, and/or residence time
which involves recirculating the hot O2 depleted flue gas from the heater into the combustion zone using
burner design features and fuel staging to reduce NOX. Based on an inquiry with the duct burner
manufacturer, the duct burner has NOX emission guarantee for 0.08 lbs/MMBtu High Heat Value (HHV)
(equivalent to 66 ppm). The duct burner manufacturer does not have a burner that can offer lower
emissions which is available for retrofit, thus the use of an ULNB is technically infeasible.
Selective Catalytic Reduction
SCR refers to the process in which NOx is reduced by ammonia over a heterogeneous catalyst in the
presence of oxygen. SCR can be applied as a stand-alone NO X control or with other technologies such as
combustion controls. The SCR process requires a reactor, a catalyst, and an ammonia storage and injection
system. The effectiveness of an SCR system is dependent on a variety of factors, including the inlet NOx
concentration, the exhaust temperature, the ammonia injection rate, and the type of catalyst. According to
EPA, the optimum temperature range over which SCR is effective is dependent on the type of catalyst and
the flue gas composition. In general, the optimum temperature range is between 480 and 800˚F.33 SCR
units typically achieve 70 - 90% NOx reduction.34 However, if the upstream NOX concentration is already
low, as is the case with these units, it is difficult to achieve these control efficiencies.

The ammonia "slip" associated with the SCR is a documented problem. The increased ammonia emissions
(currently zero) from the implementation of this technology would offset the marginal air quality benefits
the SCR option would provide from NOX emissions reduction. Additionally, ammonia slip emissions have the
potential to increase secondary PM2.5 levels which would impact the surrounding PM2.5 serious
nonattainment area and it is anticipated that the increase in particulate would offset any anticipated NOX
emissions. Storage and handling of ammonia poses significant safety risks when applied at the University of
Utah. Ammonia is toxic if swallowed or inhaled and can irritate or burn the skin, eyes, nose, or throat. It is a
commonly used material that is typically handled safely and without incident. However, there are potential
health and safety hazards associated with the implementation of this technology. The LCHTWP (Bldg 303) is
located in a densely-packed area, adjacent to the TRAX line, the Huntsman Event Center, The Utah Museum
of Fine Arts, and other public facilities, with a significant number of University staff, students, and the
33 L.M. Campdell, D.K. Stone, and G.S. Shareef, Sourcebook: NOx Control Technology Data, EPA/600/S2-91/029, 1991. 34 OAQPS, EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/424/B-02-001 (https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution); January 2002

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Trinity Consultants 6-4
general public potentially in harm's way. Locating ammonia tanks in these premises poses significant health
risks for students, faculty, patients, family members, and the general public if a leak were to occur.
The exhaust stream entering the SCR will require additional heat to meet the SCR operating temperature
requirements (minimum of 480°F). This increase in exhaust temperature would require an additional
combustion device, also increasing NOX, SO2, and PM2.5 emissions.

Furthermore, there is a physical space issue concerning this technology and the current location. Building
303, where the LCHTWP boilers and the turbine are housed, is confined by other buildings in the immediate
proximity and currently does not provide the space required to physically install an SCR. The location of the
turbine within the building also presents a space challenge when installing an SCR. The physical space
restriction within Building 303 is more confined than the physical space in Building 302 as discussed in
Section 4. Therefore, the SCR is considered technically infeasible for the turbine and WHRU located in
building 303 due to physical limitations, public safety concerns, and additional pollutants being emitted to
use this add-on control technology.
SCONOx (EMx)
SCONOx is a catalytic oxidation and absorption technology that uses a single catalyst for the removal of
NOX, CO, and VOC. This technology has been used since the late 1990s and is proven for use on combined
cycle turbines, lean burn reciprocating engines, diesel vehicles, and refineries. This technology has several
advantages over an SCR including:

► Provides control for several pollutants - lowering overall reported emissions of NOX, CO, VOC, and PM;
► No use of ammonia;
► Requires lower exhaust temperatures; and
► Available on a range of emission unit sizes – installed on units as small as 1 MW.

Estimates of control system efficiency vary. However, EMx Design information indicates testing showing
emission reduction as much as 99.5%.35 Commercially quoted NOX emission rates for the SCONOx system
range from 2.0 ppm on a 3-hour average basis, representing a 78% reduction, to 1.0 ppm with no
averaging period specified (96% reduction).

The control technology has specific requirements for use and may be added as a retrofit technology or may
require a new turbine to install the technology. Based on physical space constraints as discussed in the SCR
section, the University has deemed this control technically infeasible as well.
Water/Steam Injection
Combustion control using water or steam lowers combustion temperatures, which reduces thermal NOX
formation. Water or steam, treated to quality levels comparable to boiler feedwater, is injected into the
combustor and acts as a heat sink to lower flame temperatures. This control technique is available for all
new turbine models and can be retrofitted to most existing installations. Although uncontrolled emission
levels vary widely, the range of achievable controlled emission levels using water or steam injection is
relatively small. Controlled NOX emission levels range from 25 to 42 ppmv for natural gas fuel.36
35 Reduction shown in PowerPoint presentation sent to Beth Ryder, Trinity Consultants from Josh Gillespie, EmeraChem LLC. 36 Alternative Control Techniques Document— NOX Emissions from Stationary Gas Turbines

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Good Combustion Practices
Good combustion practices involve controlling the operating parameters of the combustors for temperature
and turbulence, excess oxygen levels, and air/fuel mixing to ensure continual operation as close to optimum
(i.e., minimum emission) conditions as possible.
6.1.3 Turbine and WHRU NOX Step 3
SoLoNOxTM technology (DLN combustor), water/steam injection, and good combustion practices are all
considered technically feasible. The turbine currently has the SoLoNOxTM technology installed and achieves
an emission rate of 9 ppm. The water/steam inject states it is only able to achieve emission levels as low as
25 ppm. As such, the water/steam injection is removed from further consideration. The remaining
technologies are ranked based on their lowest achievable emission rate:

1. SoLoNOxTM Technology– 9 ppm for Turbine alone 37
2. Good Combustion Practices

For the WHRU, based on inquiry with the duct burner manufacturer, the current burner is the best available
NOX guarantee for the application that is available.
6.1.4 Turbine and WHRU NOX Step 4
The turbine is currently equipped with SoLoNOxTM technology for combustion control on the turbine and the
WHRU duct burner is using good combustion practices. These are the most effective controls available for
the unit.
6.1.5 Turbine and WHRU NOX Step 5
The turbine and WHRU function as a combined cycle turbine which meets NSPS subpart KKKK which the
University proposes is the presumptive norm. The NOX emission limit established in NSPS KKKK is met
through the use of SoLoNOxTM currently installed and the University proposes this control method meets
RACT.
6.2 Turbine and WHRU VOC Technologies
6.2.1 Turbine and WHRU VOC Step 1
The University has reviewed the following sources to ensure all available control technologies have been
identified:

► EPA’s RBLC Database for Natural Gas External Combustion Units (process type 13.310);38
► EPA’s Air Pollution Technology Fact Sheets;
► SCAQMD LAER/BACT Determinations;
► SJVAPCD BACT Clearinghouse;
► BAAQMD BACT/TBACT Workbook; and
► Permits available online.

The sources with VOC limits and most closely related processes were as follows:
37 Title V Operating Permit #3500063004 Condition II.B.4.a. 38 Database accessed November 10, 2023.

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Table 6-2. VOC Turbine Controls and Emission Rates from RBLC 39

The technologies identified as possible VOC reduction technologies for small combustion, combined cycle
and cogeneration turbines are shown in the table below.

Pollutant Control Technologies VOCs Catalytic Oxidation Thermal Oxidation Good Combustion Practices

No presumptive norm has been established for VOC emissions from combustion sources due to the low
emission rate of units.
6.2.2 Turbine and WHRU VOC Step 2
Catalytic Oxidation
Catalytic oxidation allows complete oxidation to take place at a faster rate and a lower temperature than is
possible with thermal oxidation. Oxidation efficiency depends on exhaust flow rate and composition.
Residence time required for oxidation to take place at the active sites of the catalyst may not be achieved if
exhaust flow rates exceed design specifications. Also, sulfur and other compounds may foul the catalyst,
leading to decreased efficiency. In a typical catalytic oxidizer, the gas stream is passed through a flame area
and then through a catalyst bed at a velocity in the range of 10 to 30 feet per second (fps). Catalytic
oxidizers typically operate at a narrow temperature range of approximately 600°F to 1100°F. A catalytic
oxidizer will require additional fuel to heat the gas stream at least 600°F and which will generate additional
emissions; therefore, the catalytic oxidation is not being considered further.
39 Database accessed November 10, 2023.
RBLCID Facility/Agency Name State Permit/Document Issued Control Method Averaging Time Case-by-Case
AK-0086 KENAI NITROGEN
OPERATIONS AK 03/26/2021 &nbsp;ACT 102.1 MMBtu/hr Good Combustion Practices 0.0036 LB/MMBTU THREE-HOUR AVERAGE BACT-PSD
IN-0173 MIDWEST FERTILIZER
CORPORATION IN 06/04/2014 &nbsp;ACT 283 MMBTU/H,
EACH
GOOD COMBUSTION PRACTICES
AND PROPER DESIGN 2.5 PPMVD AT 15%
OXYGEN 1-HR AVERAGE BACT-PSD
IN-0173 MIDWEST FERTILIZER
CORPORATION IN 06/04/2014 &nbsp;ACT 218.6 MMBTU/H,
EACH
GOOD COMBUSTION PRACTICES
AND PROPER DESIGN 5.5 LB/MMCF 3-HR AVERAGE BACT-PSD
IN-0180 MIDWEST FERTILIZER
CORPORATION IN 06/04/2014 &nbsp;ACT 283 MMBTU/H,
EACH
GOOD COMBUSTION PRACTICES
AND PROPER DESIGN 2.5 PPMVD AT 15%
OXYGEN 1-HR AVERAGE BACT-PSD
IN-0180 MIDWEST FERTILIZER
CORPORATION IN 06/04/2014 &nbsp;ACT 218.6 MMBTU/H,
EACH
GOOD COMBUSTION PRACTICES
AND PROPER DESIGN 5.5 LB/MMCF 3-HR AVERAGE BACT-PSD
LA-0295 WESTLAKE FACILITY LA 07/12/2016 &nbsp;ACT 159.46 MMBTU/HR
Good combustion practices,
including good equipment design,
use of gaseous fuels for good
mixing, and proper combustion
techniques consistent with the
manufacturer's recommendations
to maximize fuel efficiency and
minimize emissions (see notes
below)
1.64 LB/H HOURLY MAXIMUM BACT-PSD
MA-0041 MEDICAL AREA TOTAL
ENERGY PLANT MA 07/01/2016 &nbsp;ACT 203.4 MMBTU/H Oxidation Catalyst 1.7 PPMVD@15% O2 1 HR BLOCK AVG/EXCLUDING
SS, NG FIRING
OTHER CASE-
BY-CASE
MA-0043 MIT CENTRAL UTILITY
PLANT MA 06/21/2017 &nbsp;ACT 353 MMBtu/hr Oxidation Catalyst 1.7 PPMVD@15% O2 1 HR BLOCK AVG/EXCLUDING
SS, NG FIRING
OTHER CASE-
BY-CASE
-SCAQMD CA 03/08/18 547.5 MMBtu/hr Oxidation Catalyst 2 PPMVD@15% O2 1 hour BACT
Throughput Emission Limit

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Simple Thermal Oxidizer or Afterburner
In a simple TO or afterburner, the flue gas exiting the turbine and WHRU duct burner is reheated in the
presence of sufficient oxygen to oxidize the VOC present in the flue gas. A typical TO is a flare and is not
equipped with any heat recovery device. A TO will require additional fuel to heat the gas stream starting
from 280°F to at least 1,600°F and which will generate additional emissions. Therefore, there would be little
expected reduction in VOC with an increase in other combustion pollutants for the required heating of the
exhaust stream. Therefore, the TO is not being considered further.
Good Combustion Practices
Good combustion practices refer to the operation of engines at high combustion efficiency which reduces
the products of incomplete combustion. The turbine installed has been designed to achieve maximum
combustion efficiency. The University follows all instructions given in the operation and maintenance
manuals that detail the required methods to achieve the highest levels of combustion efficiency.
6.2.3 Turbine and WHRU Steps 3-5
Since other add on control technologies require additional combustion units and therefore pollutant
emissions, good combustion practices are the control for VOC emissions on a natural gas turbine and WHRU
duct burner. Since no presumptive norm has been established for VOC emissions and all technically and
economically feasible controls are utilized, the University proposes that good combustion practices and the
use of a clean burning fuel meets RACT.

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7. DUAL FUEL BOILERS
The University hospital is an Adult Level I Trauma Center which cares for patients across the spectrum of
health care, from routine screenings to trauma emergencies including trauma surgery. The University’s
hospital as well as the associated Huntsman Cancer Institute have recently undergone expansions. The
boiler installations were selected in consideration of both the design and accreditation requirements of the
hospital and the BACT requirements established by UDAQ. In addition, the boiler installations were selected
based on the energy efficient design of the new building, allowing the University to optimize heat load and
sizing for the most efficient operation of utility equipment.

As a Level I trauma center, the University Hospital maintains accreditation from the Det Norske Veritas
(DNV) Healthcare, Inc. DNV is approved by the Centers for Medicare and Medicaid Services (CMS) to deem
hospitals in compliance with the CMS Conditions of Participation (CoPs). To meet accreditation
requirements, the hospital’s expansion project’s design is based upon the following:

► 2010 Facility Guidelines Institute (FGI) Guidelines for Design and Construction of Health Care Facilities,
which includes design codes from the following national organizations:
• American Society of Heating and Air-Conditioning Engineers (ASHRAE); and
• American Institute of Architects (AIA).

► DNV, the certifying body, follows the Ambulatory Care Complex Construction National Integrated
Accreditation for Healthcare Organization (NIAHO) standards while integrating ISO 9001 with Medicare
conditions.

Relative to the boiler installations selected for the University Hospital’s ACC and Rehab expansions, ASHRAE
and AIA standards require reserve capacity for heating sources and essential accessories both in number
and arrangement that are sufficient to accommodate facility needs even when any one of the heat sources
is not operating due to breakdown or routine maintenance.40,41 Furthermore AIA design code specifies, “…
the capacity of remaining sources shall be sufficient to provide for sterilization and dietary purposes and
provide heating for operating, delivery, birthing, labor, recovery, emergency, intensive care, nursery, and
inpatient rooms.”42 Additionally in consideration of these standards, changeover timing is critical to ensure
hot water and steam can be adequately supplied.

To meet the aforementioned standards, the University Hospital has installed boilers that are dual fuel (i.e.,
both natural gas and back up fuel oil) to provide reserve capacity during breakdowns, natural gas
curtailment, or maintenance activities. Specifically, to offer application flexibility and to meet changeover
requirements, a dual fuel burner provides reliable steam and hot water supply.43
40 FGI 2010 Guidelines: ASHRAE 170 Part 2.1-8.2.6.1 41 FGI 2010 Guidelines: AIA (2001) Annex B, Part 6.1.2 Reserve Heating and Cooling Sources. 42 Ibid. 43 As specified in NESHAP Subpart JJJJJJ, (NESHAP for Industrial, Commercial, and Institutional Boilers Area Sources), typically boilers, intended to be normally operated on gaseous fuels are subject to gaseous fuels requirements, despite a limited allowance to burn liquid fuel for periodic testing of liquid fuel, maintenance, or operator training, not to exceed a combined total of 48 hours during any calendar year. Per these standards, burning liquid fuel during periods of gas curtailment or gas supply interruptions of any duration (emphasis included) are also included in this definition. In these regulations, a Period of gas curtailment or supply interruption means a period of time during which the supply of gaseous

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Natural gas is the second most-consumed fuel source in the United States, comprising 27% of the nation's
energy consumption. Technology and equipment innovations have improved dramatically, along with
gaseous fuel and system reliability, however, the need still remains for backup fuel systems when natural
gas supply is interrupted due to curtailment and unplanned conditions like storms, floods, natural disasters,
or extreme cold temperatures. Diesel fuel offers a high thermal efficiency and is a proven and reliable
technology for power generation applications. Additionally, diesel fuel is stable when stored and offers a
relatively safe storage option in a populated location, such as the University Hospital.
7.1 Dual Fuel Boilers NOX Technologies
In addition to the UCHTWP dual fuel boilers, the University has a handful of other boilers that also serve
essential Hospital functions, these boilers are all primarily natural gas fired and only use diesel fuel as a
back-up, in times of natural gas curtailment or natural disaster. This functionality is essential to maintaining
the status and capacity of a Level 1 Trauma Center, and in turn, creates some barriers to certain control
technologies, as detailed throughout this analysis.

The NO X formed during combustion is from two major mechanisms: thermal NOX and fuel NOX. Since
natural gas is relatively free of fuel-bound nitrogen, the contribution of this second mechanism to the
formation of NOX emissions in natural gas-fired equipment is minimal, leaving thermal NOX as the main
source of NO X emissions. Thermal NO X formation is a function of residence time, oxygen level, and flame
temperature, and can be minimized by controlling these elements in the design of the combustion
equipment.
7.1.1 Dual Fuel Boilers NOX Step 1
The University has reviewed the following sources to ensure all available control technologies have been
identified:

► Proposed UDAQ rule R307-315, NOX Emission Controls for Natural-Gas Fired Boilers between 2 and 5
MMBtu/hr
► EPA’s RBLC Database for Natural Gas External Combustion Units (process type 13.310);44
► EPA’s RBLC Database for Distillate Fuel Oil External Combustion Units (process type 13.220);45
► EPA’s Air Pollution Technology Fact Sheets;
► EPA’s CATC Alternative Control Techniques Document – NOX Emissions from Utility Boilers;
► NESHAP DDDDD – Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters;
► NESHAP JJJJJJ – Industrial, Commercial, and Institutional Boilers at Area Sources;
► NSPS Subpart Dc - Standards of Performance for Small Industrial-Commercial-Institutional Steam
Generating Units46
► SCAQMD LAER/BACT Determinations;
► SJVAPCD BACT Clearinghouse;
► BAAQMD BACT/TBACT Workbook47; and
► Permits available online.
fuel to an affected boiler or process heater is restricted or halted for reasons beyond the control of the facility. Similar to the question we raise concerning emergency engines, should the PTE from these units, which normally fire a gaseous fuel, be based upon 48 hours of intended testing, maintenance or training as allowed by the regulation. However, the University only proposes to operate 8 hours per year of fuel oil similar to other units on the campus. 44 Database accessed November 10, 2023. 45 Database accessed November 10, 2023. 46 Boilers applicable to NSPS Subpart Dc do not have NOX emission limitations for Natural Gas Fired Boilers. 47 BACT(1) for NOX and CO (achieved using LNB+FGR+SCR and GCP) is 25 ppmvd NOX @3%O2

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The technologies identified as possible NOX reduction technologies for small dual fuel boilers are shown in
the table below.

Pollutant Control Technologies
NOX Low NO X Burners (LNB)
Ultra-Low NO X Burners (UNLB)
Flue Gas Recirculation (FGR)
Selective Catalytic Reduction (SCR)
Good Combustion Practices (GCP)

No presumptive norm specifically addresses NOX emissions from dual fuel boilers. Therefore, control
effectiveness, technical, and economical feasibility is compared to the presumptive norm established for
natural gas combustion units proposed in UDAQ rule R307-315 NO X Emission Controls for Natural Gas-Fired
Boilers 2.0-5.0 MMBtu and R307-316, NOX Emission Controls for Natural-Gas Fired Boilers greater than 5
MMBtu/hr as they apply to the hospital dual fuel boilers, which require the following:

► NOX Emission Rate of 9 ppmv; and
► Operate and Maintain (O&M) in accordance with manufacturer's instruction.
7.1.2 Dual Fuel Boilers NOX Step 2
SCR
SCR has been applied to stationary source, fossil fuel-fired, combustion units for emission control since the
early 1970s. It has been applied to large (>250 MMBtu/hr) utility and industrial boilers, process heaters, and
combined cycle gas turbines. SCR can be applied as a stand-alone NOX control or with other technologies
such as combustion controls. The reagent reacts selectively with the flue gas NOX within a specific
temperature range and in the presence of the catalyst and oxygen to reduce the NOX into molecular
nitrogen (N2) and water vapor (H2O).48 The optimum operating temperature is dependent on the type of
catalyst and the flue gas composition. Generally, the optimum temperature ranges from 480°F to 800°F.49 In
practice, SCR systems operate at efficiencies in the range of 70% to 90%.50

SCR is listed in the RBLC search as technically feasible. In some cases, this control technology is listed in
combination with LNB and FGR. However, in reviewing permits issued by the South Coast Air Management
District, this control method is not considered BACT for boilers of this size which are located at hospitals.
The ammonia "slip" associated with the SCR is a documented problem. The increased ammonia emissions
(currently zero) from the implementation of this technology would offset the marginal air quality benefits
the SCR option would provide from NOX emissions reduction. Additionally, ammonia has recently been
designated as a precursor in Salt Lake County. Ammonia slip emissions have the potential to increase
secondary PM2.5 levels in the area more than the SCR controlled NOX mass. The exhaust stream entering the
SCR will require additional heat to meet the SCR operating temperature requirements (minimum of 480°F).
48 EPA Air Pollution Control Technology Fact Sheet, Selective Catalytic Reduction (SCR) 49 OAQPS, EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/424/B-02-001 (https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution); January 2002 50 OAQPS, EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/424/B-02-001 (https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution); January 2002

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This increase in exhaust temperature would require an additional combustion device, also increasing NOX,
SO2, and PM2.5 emissions.

More importantly storage and handling of ammonia poses significant safety risks when applied at the
hospital. Ammonia is toxic if swallowed or inhaled and can irritate or burn the skin, eyes, nose, or throat.
While ammonia is a commonly used material that is typically handled safely and without incident, vapors
emitted due to slippage present a health and safety hazard. By definition the hospital cares for people
seeking medical attention and the inhalation of ammonia vapors has the potential to compound the effects
of other illnesses or pre-existing conditions. Locating ammonia tanks in these premises poses an amplified
health risk which is unacceptable at a hospital therefore SCR is not further considered.
ULNB and LNB
As indicated in the name ULNB and LNB rely on burner design features and fuel staging to reduce NOX.
Nozzle construction is the limiting component when establishing combustion efficiency and NOX production
for both of these technologies.

The nozzle which maximizes combustion efficiency and minimizes NOX when burning natural gas is designed
to finely disperse natural gas into the combustion chamber. This type of nozzle is not possible when burning
diesel due to the viscosity of the fuel, therefore the diesel nozzles produce larger droplets which then mix
with air and ignite in the combustion chamber. In this case the hospital boilers must be dual fueled.
Achieving this dual fuel specification can be accomplished in one of three ways:

► One burner with interchangeable nozzles specific to fuel type;
► Two burners, one with nozzles specific to natural gas and the other with nozzles specific to diesel; or
► One burner with dual fuel compatible nozzles.

The most common design for a dual fuel boiler is to install nozzles compatible with diesel combustion which
are covered with a fine mesh like material for combustion of natural gas. This allows the boiler to achieve
ultra- low NO X emissions while firing natural gas; however, in order to allow the boiler to be fueled with
diesel this mesh must be removed. Changeover will likely take an extended time, beyond 2 hours, to
account for cool down of the boiler and burner assembly for a safe work environment. As previously
mentioned, the University’s hospital operates as a Level I trauma center and in the event of a regional
emergency, patients will likely be directed to the University’s hospital. Boilers proposed as part of the
hospital provide hot water and steam for patient critical services such as autoclaves, humidification, backup
hot domestic water, and other hospital equipment. To be accredited as a Level 1 trauma center, ASHRAE
and AIA standards require backup systems to be available for the previously mentioned health care needs.
Due to the critical nature of the services provided by these boilers a change-over period is unacceptable,
and this boiler design is not further considered for RACT.

Another option is to install two completely independent burners, one with nozzles specific to natural gas and
the other with nozzles specific to diesel. This technology is used at the UCHTWP. This option significantly
increases the combustion chamber size and the space allocated for the boilers. However, the current
available space is not large enough to accommodate this design; therefore, this option is not technically
feasible.

The remaining option is to install one burner with dual fuel compatible nozzles. These nozzles are designed
to accommodate the viscosity of diesel fuel while maximizing combustion efficiency for natural gas. The
multiflam® 3LN version burners installed for the ACC have been designed to further reduce NOX emissions
below the level which can be achieved by standard mixing head. These additional reductions are

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accomplished by using special mixing assembly applying fuel distribution principles. Combustion values also
depend on combustion chamber geometry as well as volumetric loading and boiler design. Certain
conditions such combustion chamber dimensions, measurement tolerances, temperature, humidity, etc.
must be verified in order to guarantee emission levels. This design represents RACT and allows the
manufacturer to guarantee a NOX emission rate of 30 ppm.
FGR
FGR involves the recycling of post-combustion air into the air-fuel mixture to reduce the available oxygen
and help cool the burner flame. External FGR requires the use of ductwork to route a portion of the flue gas
in the stack back to the burner wind box; FGR can be either forced draft (where hot side fans are used) or
induced draft. This technology is listed in the RBLC search as technically feasible and is often paired with
LNB for the BACT determined control technology.

The low NO X emission rate guaranteed by the manufacturer for ACC boilers is achieved by increased
recirculation of combustion gases. The 3LN multiflam® version Low NOX - Oil/ Gas/ Dual fuel burner
proposed is equipped with multiflam mixing head for the most stringent emission requirements. The low
NOX emission is achieved by fuel distribution principle. Compliance to certain emission requirement is also
dependent on combustion chamber geometry, volume loading and design of the combustion system.
Although not traditional FGR, the burners have been designed with a mixing head for low NOX emissions
and are feasible for a dual fuel purpose.
Comparison to South Coast Air Management District
In an effort to review all possible control technologies specific to dual fueled hospital boilers the University
conducted a search for Level I trauma centers in air quality districts with similar air quality concerns . Upon
review the University identified several Level I trauma centers in the South Coast Air Management District
(SCAQMD).

Since 2005 these Level I trauma centers have permitted a variety of small dual fuel boilers; however, rather
than using diesel as the alternative fuel to natural gas these hospitals have permitted the use of AMBER®
363-II FUEL (Amber 363). Amber 363 was originally developed as a stand-by fuel with the emission
requirements of SCAQMD Regulation 1146, which establishes NOX emission limits, in mind. This fuel has
been designed as a replacement for #2 diesel, and little, if any, capital investment is required to change to
this clean stand-by fuel alternative. Depending on the specific boiler/burner configuration, NOX emissions in
the range of 10-30 ppm can be achieved. The table below summarizes the SCAQMD Hospital permits
reviewed:

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Table 7-1. SCAQMD Hospital Inventory
Level I Trauma Center Permit ID
Number
Permit
Date Boiler Size NOX Limit
Keck Hospital of USC R-G3304
A/N497889
9/25/2012 5 MMBtu/hr 12 ppm on Natural
Gas
40 ppm on Amber 363
Keck Hospital of USC G21317
A/N531671
11/2/2012 8.5 MMBtu/hr 9 ppm on Natural Gas
40 ppm on Amber 363
Santa Monica – UCLA
Medical Center
G30649
A/N519089
4/9/2014 16.3 MMBtu/hr 9 ppm on Natural Gas
40 ppm on Amber 363
NME Hospitals Inc. USC
University Hospital
F79855
A/N448805
12/20/2005 5 MMBtu/hr 12 ppm on Natural
Gas
40 ppm on Amber 363

In order to achieve the bifurcated emission rates cited above two completely independent burners must be
installed, one with nozzles specific to natural gas and the other with nozzles specific to Amber 363. As
previously discussed with a secondary diesel burner, this option significantly increases the combustion
chamber size and the space allocated for the boilers is not large enough to accommodate this design;
therefore, this option is not technically feasible.

Additionally, Amber 363 is the proprietary product of Amber Industrial Services which is primarily located in
California. While Amber 363 could be shipped to the University via truck or railcar it is not readily available
in the state of Utah and potential shipping complications represent an unacceptable risk to patient care.
7.1.3 Dual Fuel Boilers NOX Steps 3-5
The remaining, technically feasible options are ranked based on which can achieve the lowest emission rate.

1. LNB = 30 ppm or 0.036 lb/MMBtu; and
2. FGR = 42ppm or 0.05 lb/MMBtu.

The University has installed units which met the most stringent emission standards possible at the time of
installation. The presumptive norm for the units in question is 9 ppmv and O&M in accordance with
manufacturer’s instruction. While the various dual fueled hospital boilers do not meet this presumptive norm
all other control methods have been eliminated as technically infeasible options.51 As a result, the University
proposes the use of specialized mixing heads, mixing assemblies, and advanced use of fuel distribution
principles meet RACT.

51 Replacement of dual fueled boiler burners was deemed economically infeasible for the UCHTWP in section 4. It is assumed that a similar cost per ton removed would result from a similar analysis for a smaller unit.

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7.2 Dual Fuel Boilers VOC Technologies
7.2.1 Dual Fuel Boilers VOC Step 1
The University has reviewed the following sources to ensure all available and potentially applicable control
technologies have been identified:

► EPA’s RBLC Database for Natural Gas External Combustion Units (process type 13.310);52
► EPA’s RBLC Database for Distillate Fuel Oil External Combustion Units (process type 13.220);53
► EPA’s Air Pollution Technology Fact Sheets;
► EPA’s CATC Alternative Control Techniques Document – NOX Emissions from Utility Boilers;
► NESHAP DDDDD – Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters;
► NESHAP JJJJJJ – Industrial, Commercial, and Institutional Boilers at Area Sources;
► SCAQMD LAER/BACT Determinations;
► SJVAPCD BACT Clearinghouse;
► BAAQMD BACT/TBACT Workbook54; and
► Permits available online.

The technologies identified as possible VOC reduction technologies for small dual fueled boilers are shown in
the table below.

Pollutant Control Technologies VOCs Thermal Oxidizer/Afterburner Regenerative Thermal Oxidizer (RTO) Catalytic Oxidation Good Combustion Practices

No presumptive norm has been established for VOC emissions from combustion sources due to the low
emission rate of the units.
7.2.2 Dual Fuel Boilers VOC Step 2
To demonstrate a complete analysis, the University has evaluated the follow technologies:
Simple Thermal Oxidizer or Afterburner (TO)
In a simple TO or afterburner, the flue gas exiting the boiler is reheated in the presence of sufficient oxygen
to oxidize the VOC present in the flue gas. A typical TO is a flare and is not equipped with any heat recovery
device. A TO will require additional fuel to heat the gas stream starting from 280°F to at least 1,600°F and
which will generate additional emissions. Additionally, a TO is no different from the combustion chamber of
the boiler. Therefore, there would be little expected reduction in VOC with an increase in other combustion
pollutants for the required heating of the exhaust stream. Therefore, the TO is not considered further.
52 Database accessed November 10, 2023. 53 Database accessed November 10, 2023. 54 BAAQMD BACT/TBACT Workbook - BACT(2) for POC is GCP

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Regenerative Thermal Oxidizer (RTO)
A RTO is equipped with ceramic heat recovery media (stoneware) that has large surface area for heat
transfer and can be stable to 2,300°F. Operating temperatures of the RTO system typically range from
1,500°F to 1,800°F with a retention time of approximately one second. The combustion chamber of the RTO
is surrounded by multiple integral heat recovery chambers, each of which sequentially switches back and
forth from being a preheater to a heat recovery chamber. In this fashion, energy is absorbed from the gas
exhausted from the unit and stored in the heat exchange media to preheat the next cycle of incoming gas.
An RTO will require additional fuel to heat the gas stream from 280°F to at least 1,500°F and which will
generate additional emissions; therefore, the RTO is not considered further.
Catalytic Oxidation
Catalytic oxidation allows complete oxidation to take place at a faster rate and a lower temperature than is
possible with thermal oxidation. Oxidation efficiency depends on exhaust flow rate and composition.
Residence time required for oxidation to take place at the active sites of the catalyst may not be achieved if
exhaust flow rates exceed design specifications. Also, sulfur and other compounds may foul the catalyst,
leading to decreased efficiency. In a typical catalytic oxidizer, the gas stream is passed through a flame area
and then through a catalyst bed at a velocity in the range of 10 to 30 feet per second (fps). Catalytic
oxidizers typically operate at a narrow temperature range of approximately 600°F to 1100°F. A catalytic
oxidizer will require additional fuel to heat the gas stream from 280°F to at least 600°F and which will
generate additional emissions; therefore, the catalytic oxidation is not considered further.
Good Combustion Practices and Use of Clean Burning Fuels
Good combustion practices for VOCs include adequate fuel residence times, proper fuel-air mixing, and
temperature control. As it is imperative for process controls, the University will maintain combustion optimal
to their process. Most results in RBLC determined that this was sufficient controls for VOC. Additionally,
BAAQMD and SCAQMD did not provide BACT determinations for VOC.
7.2.3 Dual Fuel Boilers VOC Steps 3-5
Steps 3 and 4 are not necessary since all control technologies not currently being used have been
determined technically infeasible. Since no presumptive norm has been established for VOC emissions and
all technically and economically feasible controls are utilized, the University proposes that the use good
combustion practices and natural gas during regular operation, while having the capability to fire on diesel
during natural gas curtailment or an emergency, meets RACT.

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8. BACKUP DIESEL BOILER
The University currently utilizes one (1) 4.3 MMBtu/hr diesel boiler in the Rehabilitation Hospital. This boiler
was selected in consideration of environmental requirements and sustainability, patient health, heating load,
and engineering best practices for hospital design. While technology and equipment innovations for natural
gas have improved dramatically, the need still remains for backup fuel systems when natural gas supply is
interrupted due to curtailment and unplanned conditions like storms, floods or extreme cold temperatures.
Diesel fuel offers a high thermal density and is a proven and reliable technology for backup power
generation applications. Additionally, diesel fuel is stable when stored and offers a relatively safe storage
option in a populated location, such as the University Hospital. The diesel unit will only be fired during
emergencies or natural gas curtailment.
8.1 Backup Diesel Boiler NOX
8.1.1 Backup Diesel Boiler NOX Step 1
As previously discussed, the NOX formed during combustion is from two major mechanisms: thermal NOX
and fuel NOX. Diesel contains a negligible amount of fuel bound nitrogen 55, therefore the contribution of this
second mechanism to the formation of NOX emissions in diesel fired equipment is minimal, leaving thermal
NOX as the main source of NOX emissions. Thermal NOX formation is a function of residence time, oxygen
level, and flame temperature, and can be minimized by controlling these elements in the design of the
combustion equipment.

In review of documentation produced by air quality governing bodies with similar air quality designations,
the University found that the South Coast Air Management District (SCAQMD) most directly addressed
emergency use diesel boilers.56 In an effort to establish BACT and be consistent in BACT implementation the
SCAQMD has published BACT Guidelines. In these guidelines SCAQMD states:
“If special handling or safety considerations preclude the use of the clean fuel [e.g.,
natural gas], the SCAQMD has allowed the use of fuel oil as a standby fuel in boilers
and heaters, fire suppressant pump engines and for emergency standby generators.”
The use of these fuels must meet the requirements of SCAQMD rule 1146.1 which limits NOX for boilers,
steam generators, and process heaters that are greater than 2 MMBtu/hr and less than 5 MMBtu/hr rated
heat input capacity used in any industrial, institutional, or commercial operation.57 The requirements are as
follows:
“On or after September 5, 2008, the owner or operator of any unit subject to
subdivision (a) shall operate such unit so that it discharges into the atmosphere no
more than 30 ppm of NOX emissions or for natural gas fired units 0.037 pound
NOX per million Btu of heat input, as specified in the permit to operate.”58
55 AP-42 Section 1.3 56 Bay Area Air Quality Management District (BAAQMD) and Texas Commission on Environmental Quality (TCEQ) were also reviewed. 57 SCAQMD 1146.1(a) 58 SCAQMD 1146.1(c)(1)

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NOX limits are typically met through the implementation of a control strategy. EPA’s RBLC Database for
Distillate Fuel External Combustion Units (process type 13.220) cited only good combustion practices as
BACT.59 EPA’s AP-42 Section 1.3, Air Pollution Technology Fact Sheets, and CATC Alternative Control
Techniques Document – NOX Emissions from Utility Boilers list FGR and LNB as potential control techniques
for diesel units but no size or specific fuel requirements are given. For completeness the University has
considered good combustion practices, FGR, and LNB as potentially applicable control technologies below.60
Table 8-1. Diesel Boiler NOX Controls and Emission Rates from RBLC

Based on the review conducted the University proposes that the presumptive norm for small, backup, diesel
fired boilers is a NOX emission rate of 30 ppm, limited firing, and good combustion practices.
8.1.2 Backup Diesel Boiler NOX Step 2
Good Combustion Practices
The boiler uses a flexible water tube design which separates the heat transfer medium (water) from the
furnace (combustion chamber). Good combustion practices for this type of equipment can be split into two
categories: combustion chamber design and maintenance.

Good combustion chamber design minimizes flame temperature, oxygen availability, and/or residence time
at high temperatures as each of these variables has the potential to increase NOX production.61 The
combustion chamber design proposed has considered each of these design variables to minimize the level of
NOX produced.

Good combustion practices will be ensured through an appropriate maintenance program. An appropriate
maintenance program would include manufacturer recommendations as well as an in-depth 5 year tune up
as required by NESHAP JJJJJJ.62
FGR
FGR involves the recycling of post-combustion air into the air-fuel mixture to reduce the available oxygen
and help cool the burner flame. External FGR requires the use of ductwork to route a portion of the flue gas
in the stack back to the burner wind box; FGR can be either forced draft (where hot side fans are used) or
induced draft. The diesel unit proposed is equipped with an induced flue gas recirculation line and a forced
draft, flame retention head type burner which allows for efficient combustion.
59 Database accessed November 10, 2023. 60 Note, during review of available control technology through RBLC and other databases, an SCR was not listed for any source less than 26 MMBtu/hr. Therefore, this control technology was not evaluated for use on the boilers in this section. 61 AP-42 Section 1.3, Section 1.3.3.3 Nitrogen Oxide Emissions 62 Table 2 to Subpart JJJJJJ of Part 63, line 13
RBLCID Facility/Agency Name State Permit/Document Issued Control Method Averaging Time Case-by-Case
*WA-0349 HANFORD WA 04/04/2013 &nbsp;ACT Low NOx burners 0.09 LB/MMBTU 24-HR BACT-PSD
WI-0270 DAIRYLAND POWER
COOP ALMA STATION WI
06/13/2016 &nbsp;ACT 83.8 mmBTU/hr
Limit nitrogen oxides
emissions to 0.21
pounds per MMBTU 0.21 LB/MMBTU
BACT-PSD
-BAAQMD CA 8/4/2010 < 33.5 MMB tu/Hr
Ultra Low NOx
Burners & FGR NA BACT
-SCAQMD CA 9/2/2022 8.4 MMB tu/hr Low NOx Burner 7 PPMV 15 min BACT
Throughput Emission Limit
NA
NA

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Low NOX Burners
As with natural gas unit LNB technology applied to diesel units uses advanced burner design to reduce NOX
formation through the restriction of oxygen, flame temperature, and/or residence time. These techniques
reduce the formation of thermal NOX. The unit proposed is equipped with a low NO X burner which the
manufacturer guarantees will emit no more than 30 ppm of NOX.
8.1.3 Backup Diesel Boiler NOX Steps 3-5
The diesel, backup boiler has a manufacturer guarantee of 30ppm and it assumed that either a LNB or FGR
was utilized in the design. The University proposes emission guarantee of 30 ppm , limited firing, and good
combustion practices meets RACT.
8.2 Backup Diesel Boiler VOC Emissions
This RACT analysis has well established, after reviewing a variety of control techniques, for various sizes and
fuels, that the proposed RACT is good combustion practices since all control technologies not currently
being used have been determined technically infeasible.

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9. OTHER SMALL NATURAL GAS BOILERS
The University operates several other boilers around campus to support individual building needs. All boilers
combust natural gas. A complete list of these boilers is contained in in the Table 9-1.
Table 9-1. Other Small Boilers at the University

Startup and shutdown emissions are anticipated to be less than or equal to emissions during normal
operations on the additional small boilers.
9.1 Other Small Natural Gas Boilers NOX Technologies
The NO X that will be formed during combustion is from two major mechanisms: thermal NOX and fuel NOX.
Since natural gas is relatively free of fuel-bound nitrogen, the contribution of this second mechanism to the
Location Operating
Scenario
Capacity
(MMBtu/hr)
Fuel Type
Building
Number Building Name Primary
33 Clark Football Center Primary 5.25 Natural Gas
151 Sorenson Biotechnology Bldg. -
USTAR Backup 20.67 Natural Gas
306 Buildings and Grounds Primary 8 Natural Gas
523 Moran Eye Center Backup 8.2 Natural Gas
565 Emma-Eccles-Jones Medical
Research Center Backup 19 Natural Gas
581 School of Pharmacy Building Backup 17 Natural Gas
587 CMC unit 1 Primary 10.7 Natural Gas
587 CMC unit 2 Primary 10.7 Natural Gas
701/702
Medical Plaza North
Tower/Medical Plaza South Tower
unit 1
Primary 5.5 Natural Gas
701/702
Medical Plaza North
Tower/Medical Plaza South Tower
Unit 2
Primary 5.5 Natural Gas
865 Williams Building Regular Use 10 Natural Gas
Misc. Mis. Primary Less than 5
Each Natural Gas

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formation of NOX emissions in natural gas-fired equipment is minimal, leaving thermal NOX as the main
source of NO X emissions. Thermal NO X formation is a function of residence time, oxygen level, and flame
temperature, and can be minimized by controlling these elements in the design of the combustion
equipment.
9.1.1 Other Small Natural Gas Boilers NOX Step 1
Step 1 for other small natural gas boiler is the same used for LCHTWP and the same sources were
reviewed. The technologies identified as possible NOX reduction technologies are shown in the table below.

Pollutant Control Technologies NOX Low NOX Burners Ultra-Low NOX Burners Flue Gas Recirculation Selective Catalytic Reduction Good Combustion Practices

The control efficiencies, as well as technical and economic feasibility are compared to the presumptive norm
established for natural gas combustion units proposed in UDAQ rule R307-315 NO X Emission Controls for
Natural Gas-Fired Boilers 2.0-5.0 MMBtu and R307-316, NOX Emission Controls for Natural-Gas Fired Boilers
greater than 5 MMBtu/hr as they apply to the miscellaneous small natural gas boilers listed here, which
require the following:

► NOX Emission Rate of 9 ppmv;63 and
► Operate and Maintain (O&M) in accordance with manufacturer's instruction.64
9.1.2 Other Small Natural Gas Boilers NOX Step 2
To demonstrate a complete analysis, the University has evaluated the follow technologies including both
replacement burners and add-on controls.
Low NOX Burners
LNB technology uses advanced burner design to reduce NOX formation through the restriction of oxygen,
flame temperature, and/or residence time. BAAQMD lists typical technology for BACT for NOX using a
combination of SCR, LNB, and FGR. SCAQMD used LNB plus SCR as the BACT determined control
methodology for the US Government, Veteran Affairs Medical Center boiler rated at 39.9 MMBtu/hr in 2016.
As shown in Section 4.1.4, the cost per ton removed is beyond acceptable cost control effectiveness levels
and therefore, the University is considering this burner technology economically infeasible for these units.
Ultra-Low NOX Burners
ULNB technology uses internal FGR which involves recirculating the hot O2 depleted flue gas from the heater
into the combustion zone using burner design features and fuel staging to reduce NOX. BAAQMD lists typical
technology for BACT for NOX using a combination of ULNB and FGR. SCAQMD used ULNB as the BACT
determined control methodology for the Fullerton College boiler rated at 10 MMBtu/hr in 2003. An ULNB can
63 UDAQ’s proposed rules are intended for new installations and not retrofitting existing boilers. 64 Neither R307-315 or 316 require the retrofit of existing units to meet the established standards.

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achieve an emission rate of approximately 9 ppm or 0.011 pounds per million British thermal units
(lb/MMBtu) when used in conjunction with FGR.
Flue Gas Recirculation
FGR is frequently used with both LNB and ULNB burners. FGR involves the recycling of post-combustion air
into the air-fuel mixture to reduce the available oxygen and help cool the burner flame. As previously
discussed, both SCAQMD and BAAQMD have combined this technology with others to determine BACT.
Currently, the UCHTWP boilers use this technology. This control technology is technically infeasible for
retrofitting existing boilers due to the small spaces the other small boilers are located.
Selective Catalytic Reduction
SCR is listed in the RBLC search as technically feasible. In some cases, this control technology is listed in
combination with LNB and FGR. As previously mentioned, BAAQMD defines BACT as the combination of
SCR, LNB, and FGR.

The ammonia "slip" associated with the SCR is a documented problem. The increased ammonia emissions
(currently zero) from the implementation of this technology would offset the marginal air quality benefits
the SCR option would provide from NOX emissions reduction. Ammonia slip emissions have the potential to
increase secondary PM2.5 levels in the area more than the SCR controlled NOX mass. Storage and handling
of ammonia poses significant safety risks when applied at the University of Utah. Ammonia is toxic if
swallowed or inhaled and can irritate or burn the skin, eyes, nose, or throat. It is a commonly used material
that is typically handled safely and without incident. However, there are potential health and safety hazards
associated with the implementation of this technology. The other small boilers are located in a densely
packed area with other public facilities including student dormitories, and a significant number of University
staff, students, and the general public potentially in harm's way. Locating ammonia tanks in these premises
poses significant health risks for students, faculty, patients, family members and the public if a leak were to
occur.

Furthermore, there is a physical space issue concerning this technology. The space required to physically
install an SCR is not available for boilers located within buildings. As a result, SCR is considered technically
infeasible.
Good Combustion Practices
The use of good combustion practices usually includes the following components: (1) proper fuel mixing in
the combustion zone; (2) high temperatures and low oxygen levels in primary zone; (3) Overall excess
oxygen levels high enough to complete combustion while maximizing boiler efficiency, and (4) sufficient
residence time to complete combustion. Good combustion practices are accomplished through boiler design
as it relates to time, temperature, and turbulence, and boiler operation as it relates to excess oxygen levels.
9.1.3 Other Small Natural Gas Boilers NOX Steps 3 - 5
Based on an RBLC search the following technologies are currently being used for boilers less than or equal
to 25 MMBtu/hr. These are ranked based on which technology can achieve the lowest emission rate.

1. ULNB = 9 ppm or 0.011 lb/MMBtu
2. LNB = 30 ppm or 0.036 lb/MMBtu
3. FGR = 42 ppm or 0.05 lb/MMBtu

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The University has installed units which met the most stringent emission standards possible at the time of
installation. The presumptive norm for the units in question is 9 ppmv and O&M in accordance with
manufacturer’s instruction. In reviewing the proposed rules, R307-315 and 316, no retrofit requirements are
established. Additionally, the retrofit of technologies reviewed have been established as technically or
economically infeasible.65 As a result, the University proposes the implementation of GCP as RACT.
9.2 Other Small Natural Gas Boilers VOC Technologies
This RACT analysis has well established, after reviewing a variety of control techniques, for various sizes and
fuels, that the proposed RACT is good combustion practices since all control technologies not currently
being used have been determined technically infeasible.
65 Replacement of dual fueled boiler burners was deemed economically infeasible for the UCHTWP in section 4. It is assumed that a similar cost per ton removed would result from a similar analysis for a smaller unit.

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10. DIESEL-FIRED EMERGENCY GENERATORS
Diesel-fired engines are classified as compression ignition (CI) internal combustion engines (ICE). The
primary pollutants in the exhaust gases include NOX and VOC. The diesel-fired engines installed at the
University are for emergency use only (except for readiness testing and maintenance) and will use diesel
fuel meeting the requirements of 40 CFR 1090.305 for non-road diesel fuel (i.e., a maximum sulfur content
of 15 ppm and either a minimum cetane index of 40 or a maximum aromatic content of 35 percent by
volume).

The University has multiple diesel-fired emergency generators permitted in Approval Orders (AO
AN103540030-22), as well as Title V Permit No. 3500063004. In total the University has the following units:

► Small diesel-fired emergency generator engines that are each rated less than 600 hp and having a
combined total capacity of up to 11,809 HP.
► Large diesel-fired emergency generator engines that are each rated greater than 600 HP and having a
combined total capacity of up to 55,226 HP.

U.S. EPA’s RBLC was queried to identify controls for other similar-sized emergency generator engines. The
RBLC shows that most diesel-fired emergency generator engines have RACT emission limits or permitted
emission limits under other regulatory programs at the promulgated 40 CFR Part 60 Subpart IIII Standards
of Performance for Stationary Compression Ignition Internal Combustion Engines (NSPS Subpart IIII). The
purpose and use of the engine are important considerations if an engine goes beyond NSPS Subpart IIII
standards. Presented below are the five steps of the top-down RACT review for diesel-fired emergency
generator engines.
10.1 Diesel Fired Engines NOX and VOC Technologies
10.1.1 Diesel-Fired Engines Step 1
The least stringent emission rate allowable for RACT is any applicable limit under either New Source
Performance Standards (NSPS – Part 60,) or National Emission Standards for Hazardous Air Pollutants
(NESHAP – Part 63). Emission limits for diesel-fired engines are limited by EPA’s Tier program established in
40 CFR 1039, and are referenced by NSPS Subpart IIII, Standards of Performance for Stationary
Compression Ignition Internal Combustion Engines.66 Under these regulations EPA requires manufacturers
to reduce the emissions from engines produced after certain dates in a tiered fashion, based on the size and
model year. In general, the higher the tier rating, the lower the emissions produced.

The engines evaluated under this RACT analysis are rated for emergency use only. Per NSPS Subpart IIII
section 60.4202, EPA only requires emergency use engines to meet Tier 2 or Tier 3 standards based on the
size of the unit.67 EPA established Tier 3 standards for all units rated between 50 BHP and 750 BHP and Tier
2 standards for all units rated above 751 BHP.

66 Non-Emergency regulated per 40 CFR 60.4201, Emergency regulated by 40 CFR 60.4202, and General Requirements regulated per 40 CFR 60.4203. 67 Emergency egines are regulated in 40 CFR 60.4202 which sites only 40 CFR 1039.104, 1039.105, and 1039.15. Tier 4 final and Tier 4 interiem standards are given in 40 CFR 1039.101 and 1039.102, respectively, which are not referenced.

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It is the manufacturer’s responsibility to ensure that these units meet the established emission limitations or
Tier rating. In order to ensure these emission limitations are met manufacturers often incorporate design
elements, such as turbochargers, aftercoolers, positive crankcase ventilation, and high-pressure fuel
injection. The incorporation of these design elements allows the units to meet minimum RACT standards
and are therefore not further considered in this analysis.

In order to identify additional control technologies applied to emergency use engines the following sources
were reviewed:

► EPA’s RBLC Database for Diesel Generators (process types 17.110 Large Internal Combustion Engines
[>500 Hp] burning Fuel Oil and 17.210 Small Internal Combustion Engines [<500 Hp] burning Fuel
Oil);68
► EPA’s Air Pollution Technology Fact Sheets;
► SCAQMD Example Permits;
► TCEQ’s BACT combustion workbook; and
► BAAQMD Nonroad BACT Assessments.

The following control methods have been identified as potentially feasible for control of emissions from
emergency generator engines:

Pollutant Control Technologies VOC & NOX Limited Hours of Operation Good Combustion Practices Use of Ultra-Low Sulfur Fuel Exhaust Gas Recirculation Diesel Oxidation Catalyst (DOC) Selective Catalyst Reduction (SCR)

10.1.2 Diesel-Fired Engines Step 2
Limited Hours of Operation
One of the options to control the emissions of all pollutants released from emergency generator engines is
to limit the hours of operation for the equipment. Due to the designation of this equipment as emergency
equipment, only 100 hours of operation for maintenance and testing are permitted per NSPS Subpart IIII.
Therefore, limiting hours of operation is considered technically feasible.
Good Combustion Practices
GCP refers to the operation of engines at high combustion efficiency, which reduces the products of
incomplete combustion, such as VOC and CO. Emergency generator engines are designed to achieve high
combustion efficiency when maintained and operated according to the manufacturer’s written instructions.
GCP are considered technically feasible.

68 Database accessed November 10, 2023.

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Exhaust Gas Recirculation
NOX reduction can be achieved through recirculating exhaust into the engine. EPA tests have demonstrated
NOX reduction up to 50 percent if the engine timing is retarded, but test results are accompanied by an
increase in particulates.69 Computer based control schemes can assist in NOX reduction with associated
timing retardation, but EGR can also result in heat rejection, reduced power density, and lower fuel
economy. Exhaust gas recirculation is considered technically infeasible.
Diesel Oxidation Catalyst
A DOC utilizes a catalyst such as platinum or palladium to oxidize VOC emissions in the engine’s exhaust to
carbon dioxide (CO2) and water. Use of a DOC can result in approximately 90 percent reduction in VOC
emissions.70 In addition to controlling VOC, a DOC also has the potential to reduce PM emissions by 30
percent (based on the concentration of soluble organics).71 However, the full reduction potential requires a
minimum operating temperature of 150 ºC (300 ºF).72 Similarly, U.S. EPA recommends if an engine emits
extremely high levels of PM and/or idles for long periods of time, an exhaust backpressure monitoring and
operator notification system may be installed to notify the operator when maintenance is needed.73 For this
reason, DOC control efficiencies are expected to be relatively low during the first 20 - 30 minutes after
engine start up, in fact U.S. EPA considered this method of aftertreatment to be generally unsuitable for
backup use.74 Since operation of emergency engines typically only includes short duration runs and at the
University does not require the engine to be brought to full load for monthly maintenance and testing, DOC
is considered technically ineffective for maintenance and testing.75

DOC is typically installed by manufacturers on prime engines and thus is considered technically infeasible for
emergency operation.
Selective Catalytic Reduction
SCR systems introduce a liquid reducing agent such as ammonia or urea into an engine’s flue-gas stream
prior to a catalyst. The catalyst reduces the temperature needed to initiate the reaction between the
reducing agent and NOX to form nitrogen and water. Additional variations including non-selective catalytic
reduction (NSCR) and selective non-catalytic reduction (SNCR) may be used but are not considered standard
industry practice and are not listed in the RBLC, thus SCR remains the focus of this technical analysis.

For SCR systems to function effectively, exhaust temperatures must be high enough (480 °F to 800 °F) to
enable catalyst activation, which will be accounted for in operation.76 For this reason, SCR control
69 U.S. EPA Control of Heavy-Duty Diesel NOX Emissions by Exhaust gas recirculation, Office of Mobile Source Air Pollution Emissions Control Technology Division, August 1985 70 U.S. EPA, Alternative Control Techniques Document: Stationary Diesel Engines, March 5, 2010, p. 41. (https://www.epa.gov/sites/production/files/2014-02/documents/3_2010_diesel_eng_alternativecontrol.pdf) 71 Response to Public Comments on Notice of Reconsideration of National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines and New Source Performance Standards for Stationary Internal Combustion Engines, EPA Docket EPA-HQ-OAR-2008-0708, June 16, 2014 72 U.S. EPA’s Technical Bulletin for Diesel Oxidation Catalyst Installation, Operation, and Maintenance, EPA-420-F-10-030 published in May 2010. 73 Ibid. 74 Response to Public Comments on Notice of Reconsideration of Nation al Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines and New Source Performance Standards for Stationary Internal Combustion Engines, EPA Docket EPA-HQ-OAR-2008-0708, Page 85, June 16, 2014 75 Annual testing requires the engines being brought to full load, but this is a small percentage of the overall maintenance and testing operation time. 76 EPA Air Pollution Control Technology Fact Sheet for Selective Catalytic Reduction (SCR), EPA-452/F-03-032

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efficiencies are expected to be relatively low during the first 20 - 30 minutes after engine start up. Since
operation of emergency engines typically only includes short duration runs for maintenance and testing, SCR
is considered technically ineffective for maintenance and testing on small engine.

Furthermore, for emergency engines under 600 HP, the use of an SCR is generally considered experimental.
Due to the low emission reduction potential on an emergency unit of this size these controls are not
standard practice for manufacturers.77 This leads to compromised equipment design and high potential for
failure.

Based on the technical considerations presented above a SCR is considered technically feasible for
emergency operation of units with a power rating greater than 600 HP.
10.1.3 Diesel-Fired Engines Step 3
Effective control technologies for diesel engines are listed in the following table:
Table 10-1. Emergency Engine Controls Feasibility
Control
Technically
Feasible under
600 HP?
(Yes/No)
Technically
Feasible above
600 HP?
(Yes/No)
Limited Hours of Operation Yes Yes
GCP Yes Yes
EGR No No
DOC No No
SCR No Yes

All emergency engines installed after 2006 at the University meet the NSPS standards. For generators that
were installed prior to 2006, they met the EPA tier rating required at the time of installation. Additionally, all
units proposed will operate for limited hours, using good combustion practices, and fueled by ultra-low
sulfur diesel.
10.1.4 Diesel Fired Engines Step 4
As SCR control technology is technically feasible for emergency operation of units over 600 HP, the
University has conducted a cost analysis using the similar size generators (rated at 1,341 HP) as a baseline.
Because of the negligible difference in engine size, the cost analysis is expected to be representative of all
engines over 600 HP.
SCR
This cost analysis focused on NOX as the reduction potential for this pollutant is greater than all other
criteria pollutants. After considering economic factors and other annual costs the calculated cost per ton
removed is $142,797 per ton removed.78 The University proposes that this is not cost effective and was not
further considered. A full cost analysis is included in Appendix A.
77 Call conducted with engine manufacturer on April 13, 2022 78 Cost estimate based on estimates from several vendors, sizes, and costs were provided and a linear interpolation was applied.

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10.1.5 Diesel-Fired Engines Step 5
The University uses all technically and economically feasible controls which generally include engine design
consistent with NSPS IIII (post-2006), EPA Tier rating, limited hours of operation, good combustion
practices and/or use of ultra-low sulfur fuel. Exact emission rates, reflecting this RACT, are included in the
emission calculations submitted during recent permitting actions.

In the case of the emergency units located at the Hospital, despite the experimental nature of additional
controls for engines under 600hp, additional cost of the control equipment, maintenance, and structural
modifications, DPF filters are used. This decision was made to protect sensitive receptors in the vicinity of
the engines. The University proposes that this strategic decision goes above and beyond RACT
requirements.

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11. NATURAL GAS EMERGENCY GENERATORS
The University currently operates four (4) natural gas-fired emergency generator to maintain critical systems
during an emergency, the engine total 1000kW.
11.1 Natural Gas Fired Engines NOX and VOC Technologies
11.1.1 Natural Gas Emergency Generators Step 1
The following sources were reviewed to identify available control technologies:

► SCAQMD LAER/BACT Determinations;
► SJVAPCD BACT Clearinghouse;
► BAAQMD BACT/TBACT Workbook
► TCEQ BACT Requirements;
► EPA’s RACT/BACT/LAER Clearinghouse RBLC Database79 for Natural Gas Generators (process type
17.230 Small Internal Combustion Engines [<500 hp] – Natural Gas)80; and
► EPA’s Air Pollution Control Technology Fact Sheets.

Available control technologies for natural gas-fired emergency generator engines include the following:

► Limited Hours of Operation;
► Routine Maintenance;
► Good Combustion Practices;
► Use of Natural Gas;
► Lean Burn Technology;
► Selective Catalytic Reductions (SCR); and
► Non-Selective Catalyst Reduction (NSCR).

The following step evaluates the technical feasibility of each of these options.
11.1.2 Natural Gas Emergency Generators Step 2
Limited Hours of Operation
One available way to control the emissions of all pollutants released from a natural gas-fired emergency
generator engine is to limit the hours of operation for the equipment. Under New Source Performance
Standards (NSPS) Subpart JJJJ81, only 100 hours of operation for maintenance and testing are allowed for
generators designated as emergency. It is conservatively estimated that the emergency generator will run
for no more than 100 hours per year for testing and maintenance. This option is considered technically
feasible.
79 Reasonably Available Control Technology (RACT)/Best Available Control Technology (BACT)/Lowest Achievable Emission Rate (LAER) 80 Database accessed November 10, 2023. 81 40 CFR 60.4243(d)(2)

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Routine Maintenance
Routine maintenance ensures the engine is working properly and as efficiently as possible, which, in turn,
helps reduce emissions. For spark ignition internal combustion engines, 40 CFR 60 Subpart JJJJ requires
that owners and operators of EPA-certified engines operating and maintain the engine consistent with the
manufacturer’s emissions-related written instructions. Routine maintenance is considered technically
feasible.
Good Combustion Practices
Good combustion practices refer to the operation of engines at high combustion efficiency, which reduces
the products of incomplete combustion. The natural gas-fired emergency generator engines at the
University are designed to achieve maximum combustion efficiency. The manufacturer has provided
operation and maintenance manuals that detail the required methods to achieve the highest levels of
combustion efficiency for the proposed unit. Use of good combustion practices is considered technically
feasible.
Use of Natural Gas
Natural gas is the cleanest fossil fuel and is a highly efficient form of energy. It is composed mainly of
methane and its combustion results in less NOx in comparison to other fossil fuels. Use natural gas for the
proposed emergency generator engine is considered technically feasible.
Lean Burn Technology
With lean burn combustion technology, excess air is introduced into the engine along with the fuel. In lean
burn engines, the air-to-fuel ratio may be as lean as 65:1 by mass. Excess air, in turn, reduces the
temperature of the combustion process and combusts more of the fuel which ultimately can result in fewer
hydrocarbons being emitted. Lean burn engines are used at the University and therefore are considered
technically feasible.
Selective Catalytic Reduction
SCR systems introduce a liquid reducing agent such as ammonia or urea into the flue gas stream prior to a
catalyst. The catalyst then reduces the temperature needed to initiate the reaction between the reducing
agent and NOX to form nitrogen and water.

For SCR systems to function effectively, exhaust temperatures must be high enough (200°C to 500°C) to
enable catalyst activation. For this reason, SCR control efficiencies are expected to be relatively low during
the first 20 to 30 minutes after engine start up, especially during maintenance and testing. Generally,
engine loads during maintenance and testing for emergency engines are very low, which also reduces
exhaust temperatures, resulting in low SCR control efficiencies. Controlling the excess ammonia (ammonia
slip) from SCR use can also be difficult. Although SCR has been implemented on large (greater than one
megawatt (MW) diesel-fired emergency generators, it has not been demonstrated on smaller emergency
engines or natural gas-fired units.82 Since SCR is anticipated to have a relatively low control efficiency
during maintenance and testing due to short periods of operation, low loads, and frequent starts/stops,
implementing SCR technology for the emergency engine is not considered technically feasible.
82 https://ww2.arb.ca.gov/sites/default/files/barcu/regact/2010/atcm2010/atcmappb.pdf

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Nonselective Catalytic Reduction
NSCR is an add-on NOX control technology for exhaust streams with low oxygen content. NSCR uses a
catalyst reaction to simultaneously reduce NOX, CO, and hydrocarbon to water, carbon dioxide, and
nitrogen. The catalyst is usually a noble metal.83 Although NSCR has some of the same operational issues as
an SCR, this technology has been demonstrated only on smaller rich burn engines and is, therefore,
considered technically infeasible.
11.1.3 Natural Gas Emergency Generators Steps 3 – 5
The University proposes that RACT for the natural gas-fired emergency generator engines is operating and
maintaining the engine in accordance with good combustion practices, which will include routine
maintenance being performed on the units in accordance with the NSPS Subpart JJJJ requirements and
combusting only natural gas. The hours of operation will be limited to 100 hours for maintenance and
testing per year in accordance with NSPS Subpart JJJJ and RICE NESHAP Subpart ZZZZ.
83 https://www3.epa.gov/ttnchie1/mkb/documents/B_16a.pdf

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12. VOC FUGITIVES AND INSIGNIFICANT ACTIVITIES
Fugitive VOC emissions result from the spray paint booth and parts washers at the University, cumulatively
these sources are limited to 5 tpy of VOC emissions. The spray paint booth is used to paint a variety of
objects used in building and facility maintenance. The parts washers are used in the equipment
maintenance shops to removed grease from machine parts during the repair and preventative maintenance
processes.
12.1 Fugitive VOC Technologies
12.1.1 VOC Fugitives Step 1
The University has reviewed the following sources to ensure all available and potentially applicable control
technologies have been identified:

► R307-335 Degreasing;
► EPA’s Air Pollution Technology Fact Sheets;
► EPA’s Alternative Control Technology Paper “Control Techniques for Volatile Organic Compound
Emissions from Stationary Sources” published in December of 1992;
► TCEQ BACT Guidelines for control technologies specific to painting and degreasing operations;
► BAAQMD BACT/TBACK Workbook; and
► Permits available online.

The technologies identified as possible VOC reduction technologies for fugitive VOC sources are shown in
the table below.

Pollutant Control Technologies
VOCs Alternative Chemical Properties
Good Housekeeping Practices
Add on Control Technologies

The presumptive norm for the parts washers is defined in R307-335 which requires the units to be operated
in accordance with good housekeeping practices. While no presumptive norm has been established for the
paint booth, other UDAQ rules stipulate the maximum VOC or vapor pressure of the materials to be used or
the operation of an add-on control.
12.1.2 VOC Fugitives Step 2
Alternative Chemical Properties
Alternative chemical properties prevent VOC emissions through a reduced organic material composition or
lower vapor pressure which in turn limited the potential for the material to emit. One common method is to
use alternative materials with chemical properties that are less likely to result in VOC emissions. Chemical
properties that are likely to result in low VOC emissions include materials with a low VOC content and low
vapor pressure.

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Good Housekeeping Practices
Good housekeeping measures ensure that VOC containing materials are not permitted to evaporate
unnecessarily or used in excess of process requirements . Examples of good housekeeping practices include
covering containers containing VOC material, enclosing waste material with VOC containing material,
diminishing exposure to heat and open atmosphere as much as the process allows.
Add on Controls
Add on controls would be accomplished through the use of control techniques that oxidize, combust or
otherwise change VOC emissions produced from a process into less harmful pollutants or a less harmful
form of the pollutant. Any control system that destroys VOC emissions from a process has two fundamental
components. The first is the containment or capture system, which is a single device or group of devices
whose function is to collect the pollutant vapors and direct them into a duct leading to a control device. The
second component is the control device, which reduces the quantity of the pollutant emitted to the
atmosphere.84

The sources described in this section are small sources with minor emissions per source located throughout
the University. Creating a capture system that spans this much area is technically infeasible therefore no
destruction control techniques have been further evaluated.
12.1.3 VOC Fugitives Step 3-5
Alternative chemical properties (1st) and good housekeeping practices (2nd) are both technically feasible and
are incorporated in conjunction with one another to ensure practically low VOC emissions. The highest
ranked control measures are currently being implemented; therefore, no economic, energy, or
environmental analysis was conducted. The University proposes these two activities as RACT as described
below.
Paint Booth
When possible, the University utilizes low VOC inks, cleaners, solvents, and water-based paints. Additionally,
the University implements work practice standards to reduce emissions, including: 1) utilizing fitting covers
for open tanks; and 2) keeping cleaning materials, used shop towels, and solvent wiping cloths in closed
containers. The University proposes these practices as RACT for the Paint Booth.
Parts Washer
When possible, the University utilizes low VOC solvents and degreasers. Additionally, the parts washers
throughout the University are subject to UAC Rule R307-335, Degreasing and Solvent Cleaning Operations.
This regulation requires the University to meet several good housekeeping related requirements as detailed
in Condition II.B.19.a of the Title V Operating Permit (Permit Number 3500063004). The University proposes
these practices as RACT for the Parts Washer.
12.2 Storage Tanks
The University maintains several large storage tanks and a variety of small storage tanks:

► Three (3) diesel tanks with a capacity of 25,000 gallons,
84 EPA's Alternative Control Technology Paper "Control Techniques for Volatile Organic Compound Emissions from Stationary Sources" published in December of 1992.

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► Two (2) diesel tanks with a capacity of 12,000 gallons
► One (1) diesel tank with a capacity of 35,000 gallons,
► One (1) jet fuel tank with a capacity of 10,000 gallons, and
► Various small tanks capacity of 10,000 gallons or less.
12.2.1 Storage Tanks Step 1
Emissions from fixed roof storage tanks result from displacement of headspace vapor during filling
operations (working losses) and from diurnal temperature and heating variations (breathing losses).85 The
University reviewed a variety of available sources, including but not limited to the RBLC 86 and NSPS Kb,
Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for which Construction,
Reconstruction, or Modification Commenced after July 23, 1984.87 The identified control methods for tanks
of this size and vapor pressure included good operating and maintenance practices and submerged filling.
12.2.2 Storage Tanks Steps 2 – 4
Good Operating and Maintenance Practices
As demonstrated by the emission calculations losses due to changes in temperature or barometric pressure
are minimal for these tanks . Where possible the University has placed tanks indoors, in a basement, or
buried underground which minimizes the temperature changes. Additionally, the diesel fuel is used as a
backup, these are low throughput tanks, only storing fuel for use in the case of an emergency, minimizing
the frequency of filling, and the associated emissions. The University uses good operating and maintenance
on all tanks.
Submerged Filling
During submerged loading, the fill pipe opening is below the liquid surface level and liquid turbulence is
controlled significantly, resulting in much lower vapor generation than encountered during splash loading.88
Due to the very low emission rate it has been assumed that the retrofit of this technology will be
economically infeasible. The University is in the process of replacing tanks throughout campus as they have
reached the end of their useful life. During the procurement of replacement tanks the University will request
the addition of submerged filling as project scope and budget allow.
12.2.3 Storage Tanks Step 5
The University has considered emissions from these storage tanks negligible and proposes good operating
and maintenance practices meets RACT.
85 EPA, Emission Factor Documentation for AP-42 Section 7.1 Organic Liquid Storage Tanks, September 2006. 86 Database accessed November 10, 2023. 87 Per the Universities Title V Operating Permit #3500063003 – Reviewer comments #5 - historical comments/modifications made to the Universities AO (DAQE-AN0354014-06), 10/26/06; removed NSPS Subpart Kb as an applicable requirement since tanks meet the size and vapor pressure requirements of 40 CFR 60.110b (b) and (c). 88 EPA AP-42 Section 5.2 Transportation and Marketing of Petroleum Liquids

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13. CONCLUSIONS
Based on the information presented and reviewed above, the following conclusions we’re determined regarding feasibility and RACT
selections:
Table 13-1. Boilers NOX Summary Table
Technology UCHTWP
(Section 4)
LCHTWP
(Section 5)
Dual Fuel
(Section 7)
Diesel
(Section 8)
Small NG
(Section 9)
LNB Eliminated in Step 4 Selected as RACT
and In Use
Selected as RACT
and In Use
Selected as RACT
and In Use
Eliminated in Step 4
ULNB Eliminated in Step 4 Selected as RACT
and In Use
Eliminated in Step 4 Eliminated in Step 1 Eliminated in Step 4
FGR Selected as RACT
and In Use
Selected as RACT
and In Use
Eliminated in Step 2 Selected as RACT
and In Use
Eliminated in Step 2
SCR Eliminated in Step 4 Eliminated in Step 2 Eliminated in Step 2 Not Considered Eliminated in Step 4
GCP Selected as RACT
and In Use
Selected as RACT
and In Use
Selected as RACT
and In Use
Selected as RACT
and In Use
Selected as RACT
and In Use

Since a variety of control techniques are considered for the other equipment onsite the conclusions have been presented in a different
format. All technologies are considered in step one. As technologies are eliminated, they are shown crossed out in the step that serves as
elimination. Once eliminated, the technology is no longer considered in further steps. Technology that is not eliminated in steps 1-5 have
been selected as RACT.

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Table 13-2. Other Sources Summary Table
RACT
Step
Turbine & WHRU
(Section 6)
Diesel Emergency Generators
(Section 10)
Natural Gas Generators Fugitives
(Section 12)
NOX VOC VOC & NOX VOC & NOX VOC
Step 1 - Dry Low NOX/ ULNB
- SCR
- EMx
- Water Injection
- GCP
- CO
- TO
- GCP
- Limited Hours of Operation
- GCP
- Ultra-Low Sulfur
- Exhaust Gas Recirculation
- DOC
- SCR
- Limited Hours of Operation
- Routine Maintenance
- GCP
- Use of Natural Gas
- Lean Burn Technology
- SCR
- NSCR
- Alternative Chemical Properties
- Good Housekeeping Practices
- Work Practices and Solvent
Cleaning Requirements identified in
R307-355
- Add on Controls
Step 2 - Dry Low NOX/ ULNB
- SCR
- EMx
- Water Injection
- GCP
- CO
- TO
- GCP
- Limited Hours of Operation
- GCP
- Ultra-Low Sulfur Fuel
- Exhaust Gas Recirculation
- DOC
- SCR
- Limited Hours of Operation
- Routine Maintenance
- GCP
- Use of Natural Gas
- Lean Burn Technology
- SCR
- NSCR
- Alternative Chemical Properties
- Good Housekeeping Practices
- Work Practices and Solvent
Cleaning Requirements identified in
R307-355
- Add on Controls

Step 3 - Dry Low NOX
- Water Injection
- GCP

- GCP - Limited Hours of Operation
- GCP
- Ultra-Low Sulfur Fuel
- SCR
- Routine Maintenance
- GCP
- Use of Natural Gas
- Lean Burn Technology
-
- Alternative Chemical Properties
- Good Housekeeping Practices
- Work Practices and Solvent
Cleaning Requirements identified in
R307-355
Step 4 - Dry Low NOX
- GCP
- GCP - Limited Hours of Operation
- GCP
- Ultra-Low Sulfur Fuel

- Routine Maintenance
- GCP
- Use of Natural Gas
- Lean Burn Technology

- Alternative Chemical Properties
- Good Housekeeping Practices
Step 5
- Dry Low NOX (In
Use)
- GCP (In Use)

- GCP
(In
Use)
- Limited Hours of Operation
(In Use)
- GCP (In Use)
- Ultra-Low Sulfur Fuel (In
Use)
- DPF
- Routine Maintenance
- GCP
- Use of Natural Gas
- Lean Burn Technology

- Alternative Chemical Properties (In
Use)
- Good Housekeeping Practices (In
Use)
Detailed in Rule R307-335 and R307-
351

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APPENDIX A. DETAILED COST CALCULATIONS
Cost Analyses
Table A-1. RACT Control Cost Evaluation for ULNB Replacement - General Information
Parameter Value Notes
Heat Input 87.5 MMBTU/hr per unit
Current Emission Rate 4.51 TPY, per unit, Using lb/MMBtu emission rates and a total of 530 MMscf/yr for all three (3)
units
Estimated Control Efficiency 60%
Estimated using the EPA's Technical Bulletin, Nitrogen Oxides, Why and How They are
Controlled (EPA456/F-99-006R). The LNB+FGR represents approximately the same control
efficiency as the ULNB for ICI Boilers fired on Natural Gas.
Estimated Emission Rate 1.80 TPY, per unit, Using lb/MMBtu emission rates and a total of 530 MMscf/yr for all three (3)
units
Operator ($/hour)$28.50
Utah Department of Workforce Services, Occupational Wages by Region, Median Annual
Wage for Installation/Maintenance/Repair, Machinery cited $59,300. Assumed a standard
working year contains 2,080 hours.
Maintenance ($/hour)$28.50
Utah Department of Workforce Services, Occupational Wages by Region, Median Annual
Wage for Installation/Maintenance/Repair, Machinery cited $59,300. Assumed a standard
working year contains 2,080 hours.
Equipment Life Expectancy
(Years)10
U.S. EPA's Alternative Control Techniques Document -- NOx Emissions from
Industrial/Commercial/Institutional (ICI) Boilers, Section 6.1.3 Total Annualized Cost and
Cost Effectiveness
Interest Rate (%)7.00%U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and
Methodology
Process Information
Labor Costs
Economic Factors
University of Utah Trinity Consultants
Cost Analyses
Table A-2. RACT Control Cost Evaluation for ULNB Replacement - Capital Investment
Parameter Value Notes
Total Equipment Cost $112,100 Cost estimate based on communication with Holbrook Servco December 2023, several sizes
and costs were provided and a linear interpolation was applied.
Direct Installation Costs $109,500 Cost estimate based on communication with Holbrook Servco December 2023, several sizes
and costs were provided and a linear interpolation was applied.
Contingency $27,375
This cost was added as the total equipment cost was obtained anonymously and based on
a linear correlation between equipment sizes, additionally it did not account for the duel
fuel nature of the unit. 25% of the direct and indirect capital costs was recommended by
U.S. EPA's Alternative Control Techniques Document -- NOX Emissions from
Industrial/Commercial/Institutional (ICI) Boilers, Section 6.1.1.4 Contingencies.
Freight $5,605 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and
Methodology, Table 2.4
Sales Tax $3,363 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and
Methodology, Table 2.4
Instrumentation $11,210 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and
Methodology, Table 2.4
Total Increase in Capital
Investment ($)$269,153 Sum of total equipment, direct installation, indirect installation, contingency, freight, sales
tax, and instrumentation costs.
Capital Recovery Factor (CRF)0.1424 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and
Methodology, Equation 2.8a
Capital Recovery Cost (CRC)$38,321 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and
Methodology, Equation 2.8
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Cost Analyses
Table A-3. RACT Control Cost Evaluation for ULNB Replacement - Annual Operating, Insurance, Tax, and Other Costs
Parameter Value Notes
Operating Labor $15,604 Assumed 0.5 hours per 8-hour shift
Supervisory Labor $2,341 Assumed to be 15% of operating Labor, EPA Cost Control Manual Section 1, Chapter 2 Cost
Estimation: Concepts and Methodology, Section 2.6.5.2
Maintenance Labor $15,604 Assumed 0.5 hours per 8-hour shift
Maintenance Materials $15,604 Assumed the same as Maintenance Labor per U.S. EPA Cost Control Manual Section 1,
Chapter 2 Cost Estimation: Concepts and Methodology, Section 2.6.5.3
Total Direct Operating Costs $49,152 Sum of Direct Operating Costs on an Annual Basis
Overhead $29,491 Assumed to be 60% of there total Direct Operating Costs, U.S. EPA Cost Control Manual
Section 1, Chapter 2 Cost Estimation: Concepts and Methodology, Section 2.6.5.7
Administrative Charges $4,980 Assumed to be 2% of the Total Capital Investment, U.S. EPA Cost Control Manual Section
1, Chapter 2 Cost Estimation: Concepts and Methodology, Section 2.6.5.8
Property Tax $2,490 Assumed to be 1% of the Total Capital Investment, U.S. EPA Cost Control Manual Section
1, Chapter 2 Cost Estimation: Concepts and Methodology, Section 2.6.5.8
Increase in Insurance $2,490 Assumed to be 1% of the Total Capital Investment, U.S. EPA Cost Control Manual Section
1, Chapter 2 Cost Estimation: Concepts and Methodology, Section 2.6.5.8
Total Insurance, Tax, and Other
Annual Costs $39,450 Sum of Insurance, Tax, and Other Annual Costs
Table A-4. RACT Control Cost Evaluation for ULNB Replacement - Total Annual Cost & Cost per Ton Removed
Parameter Value Notes
Total Annual Cost $126,923 Sum of Capital Recovery Cost, Total Direct Operating Costs, Insurance, Tax and Other
Annual Costs.
NOX Removed (tpy)2.70
Cost per Ton of NOX Removed
($/ton)$46,956
1. While this cost analysis sites the U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology, the cost estimates used for a
retrofit are consistent in U.S. EPA's Alternative Control Techniques Document -- NOx Emissions from Industrial/Commercial/Institutional (ICI) Boilers, Section 6.1.2
Annual Operations and Maintenance (O&M) Costs.
Direct Operating Costs
Insurance, Tax, and Other Annual Costs1
NOX Cost Per Ton Removed
University of Utah Trinity Consultants
Cost Analyses
Table A-5. RACT Control Cost Evaluation for SCR Addition to Existing Unit - General Information
Parameter Value Notes
Heat Input 87.5 MMBTU/hr per unit
Current Emission Rate 4.38 TPY, per unit, See Emissions Information
Estimated Removal Efficiency 0.70 Assumes the estimated removal efficiency is based on a 30 ppm to 9 ppm reductions in emissions.
Estimated Emission Rate 1.31
Estimated Ammonia Usage 1.19 lb/hr, Calculated using U.S. EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic Reduction
Costs equation 2.35
Cost of Ammonia Reagent 0.27 $/lb, quote from Thatcher ($1.38/gallon for 19% ammonia)
Cost of Catalyst $227.00
$/ft3, U.S. Environmental Protection Agency (EPA). Documentation for EPA’s Power Sector Modeling
Platform v6 Using the Integrated Planning Model. Office of Air and Radiation. May 2018. Available at:
https://www.epa.gov/airmarkets/documentation-epas-power-sector-modeling-platform-v6.
Operator ($/hour)$28.50
Utah Department of Workforce Services, Occupational Wages by Region, Median Annual Wage for
Installation/Maintenance/Repair, Machinery cited $59,300. Assumed a standard working year contains
2,080 hours.
Equipment Life Expectancy
(Years)23 U.S. EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic Reduction Costs average life
expectancy for industrial boilers
Interest Rate (%)7.00%OMB Circular A-4, https://obamawhitehouse.archives.gov/omb/circulars_a004_a-4/
Table A-6. RACT Control Cost Evaluation for SCR Addition to Existing Unit - Capital Investment
Parameter Value Notes
Total Increase in Capital
Investment ($)$568,000 Cost estimate based on communication with CECO Environmental December 2023, several sizes and
costs were provided and a linear interpolation was applied.
Direct Installation Costs $170,400 U.S. EPA's Alternative Control Techniques Document -- NOx Emissions from
Industrial/Commercial/Institutional (ICI) Boilers, Section 6.1.1.2 Direct Installation Costs
Indirect Installation Costs $187,440 U.S. EPA's Alternative Control Techniques Document -- NOx Emissions from
Industrial/Commercial/Institutional (ICI) Boilers, Section 6.1.1.3 Indirect Installation Costs
Contingency $142,000 This cost was added as the total equipment cost was obtained anonymously and a minimum
equipment cost was provided.
Freight $28,400 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology, Table
2.4
Sales Tax $17,040 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology, Table
2.4
Instrumentation $56,800 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology, Table
2.4
Capital Recovery Factor (CRF)0.0895 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology,
Equation 2.8a
Capital Recovery Cost (CRC)$104,766 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology,
Equation 2.8
Process Information
Labor Costs
Economic Factors
University of Utah Trinity Consultants
Cost Analyses
Table A-7. RACT Control Cost Evaluation for SCR Addition to Existing Unit - Annual Operating, Insurance, Tax, and Other Costs
Parameter Value Notes
Operating Labor $35,369
U.S. EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic Reduction Costs estimates 4
hours per day of Operating and Supervisory Labor. The estimate presented utilizes Section 1, Chapter
2's assumption tat 15% of operating labor is supervisory labor
Supervisory Labor $6,242 Assumed to be 15% of operating Labor, U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost
Estimation: Concepts and Methodology, Section 2.6.5.2
Maintenance Labor and Materials $2,840 U.S. EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic Reduction Costs estimates
maintenance costs to be 0.5 percent of the total capital investment.
Annual Reagent Costs $652 U.S. EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic Reduction Costs equation 2.58,
assumed 2,000 hours of operation consistent with the reduced heat load
Annual Catalyst Costs $6,810 Catalyst size calculated based on information provided in U.S. EPA's Air Pollution Control Technology
Fact Sheet for SCR (EPA-452/F-03-032). Assumed Catalyst life of 5 years.
Total Direct Operating Costs $51,912 Sum of Direct Operating Costs on an Annual Basis
Overhead $26,670 Assumed to be 60% of there total Direct Operating Costs, U.S. EPA Cost Control Manual Section 1,
Chapter 2 Cost Estimation: Concepts and Methodology, Section 2.6.5.7
Property Tax $5,680 Assumed to be 1% of the Total Capital Investment, U.S. EPA Cost Control Manual Section 1, Chapter 2
Cost Estimation: Concepts and Methodology, Section 2.6.5.8
Increase in Insurance $5,680 Assumed to be 1% of the Total Capital Investment, U.S. EPA Cost Control Manual Section 1, Chapter 2
Cost Estimation: Concepts and Methodology, Section 2.6.5.8
Administrative Charges $1,095 U.S. EPA Cost Control Manual Section 4, Chapter 2, Equation 2.69.
Total Insurance, Tax, and Other
Annual Costs $39,125 Sum of Insurance, Tax, and Other Annual Costs
Table 8. RACT Control Cost Evaluation for Diesel Fired Emergency Generator - Total Annual Cost & Cost per Ton Removed
Parameter Value Notes
Total Annual Cost $195,803 Sum of Capital Recovery Cost, Total Direct Operating Costs, Insurance, Tax and Other Annual Costs.
NOX Removed (tpy)3.06
Cost per Ton of NOX Removed $63,911
NOX Cost Per Ton Removed
Direct Operating Costs
Insurance, Tax, and Other Annual Costs
University of Utah Trinity Consultants
Cost Analyses
Table A-9. Control Cost Evaluation for SCR on an Emergency Use Engine - General Information
Parameter Value Notes
Duty (kW)543 Mid-range generator size for units over 600hp
Duty (bhp)728 Approximate conversion from kW to hp is 1.341 hp/kW
Tier II Emission NOx Rate
(g/kW-hr)6.4
U.S. EPA Office of Transportation and Air Quality (U.S. EPA-420-B-16-022) published March 2016,
Emission rate for NMHC+NOx was the published form, NMHC is anticipated to be a minor component of
the emission factor.
Tier II Emissions NOX (tpy)0.38 Total emission rate based on a maximum of 100 hr per year.
Tier IV Emission NOx Rate
(g/kW-hr)4.00
U.S. EPA Office of Transportation and Air Quality (U.S. EPA-420-B-16-022) published March 2016, Interim
Standard used as it is in the same form as the Tier II published standard, NMHC is anticipated to be a
minor component of the emission factor.
Tier IV Final Emissions NOX (tpy)0.24 Controlled emissions provided by Tier IV Final Nonroad Compression-Ignition Engines: Exhaust Emission
Standards for NOX.
Equipment Life Expectancy (Years)15 Exemption to replacement engine provisions codified in 40 CFR 60.4210(i)
Interest Rate (%)7.00%OMB Circular A-4, https://obamawhitehouse.archives.gov/omb/circulars_a004_a-4/
Table A-10. Control Cost Evaluation for SCR on an Emergency Use Engine - Capital Investment
Parameter Value Notes
Total Capital Investment ($)$142,000 Cost estimate based on estimates from several vendors, sizes, and costs were provided and a linear
interpolation was applied. Cost in 2023 dollars.
Capital Recovery Factor (CRF)0.1098 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology, Equation
2.8a
Capital Recovery Cost (CRC)$15,591 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology, Equation
2.8
Process Information
Economic Factors
University of Utah Trinity Consultants
Cost Analyses
Table A-11. Control Cost Evaluation for SCR on an Emergency Use Engine - Annual Operating Costs
Parameter Value Notes
Operating Labor, Maintenance,
Brake Specific Fuel Consumption,
and Catalyst Maintenance
$4
$/hp, U.S. EPA Alternative Control Techniques Document: Stationary Diesel Engines (U.S. EPA Contract
No. EP-D-07-019) Published March 5, 2010, Cost values are cited to be from 2005 and have been
lowered to match a run time of 100 hours.
Inflation Factor 1.69 Based on U.S. Bureau of Labor Statistics CPI Inflation Calculator from January of 2003 to October of
2023. https://www.bls.gov/data/inflation_calculator.htm
Total Direct Operating Costs $4,922
Table A-12. BACT Control Cost Evaluation for Diesel Fired Emergency Generator - Annual Operating, Insurance, Tax, and Other Costs
Parameter Value Notes
Total Annual Cost $20,513 Sum of Capital Recovery Cost, Total Direct Operating Costs, Insurance, Tax and Other Annual Costs.
NOX Removed (tpy)0.14
Cost per Ton of NOX Removed
($/ton)$142,797
Direct Operating Costs
NOX Cost Per Ton Removed
University of Utah Trinity Consultants