DAQ-2024-008117

December 28,2023
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DEC 2 8 2023
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HF Sinclair Woods Cross Refining LLC
1070 W. 500 S, West Bountiful, UT 84087
801 -299-6600 | HFSinclair.com
Bryce Bird Hand Delivered & Email
Director, Division of Air Quality
Utah Dept. of Environmental Quality
195 North 1950 West
salt Lake city, utah 84116
RE: Serious Ozone Nonattainment Area Designation - Potential Impact to ffi Sinclair
RACT Submittal Response
IIF Sinclair Woods Cross Refining LLC
Dear Director Bird:
ln response to the Serious Ozone Nonattainment Area Designation - Potential Impact to HollyFrontier
Sinclair Woods Cross Refinery letter received on May 31,2023, tIF Sinclair Woods Cross Refining LLC
(HFSWCR) has prepared an updated Reasonable Available Control Technology (RACT) analysis. Please
find the attached RACT analysis as prepared by Trinity Consultants for IIFSWCR.
Please contact me at [e-mail] or 801-299-6623 if you have any questions.
Sincerely,
Eric Benson
Environmental Manager
ec: [e-mail]
cc: E. Benson (r) File 2.1.2.1.3
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REASONABLY AVAILABLE CONTROL
TECH NOLOGY ASSESSM ENT FOR
HF SINCLAIR WOODS CROSS REFINING LLC
AND HOLLY ENERGY PARTNERS OPERATING LP
WOODS CROSS TERMINAL
HF SINCI.AIR
UTAH DEPABTMENT OF
ENVIRONMENTAL OUAUTY
nf n )') rl.l il., L \.r
DIVISION OF AIR QUALITY
,.tttfsroctor
TRINITY CONSULTANTS
4525 Wasatch Blvd.
Suite 200
Salt Lake City, Utah
December 2023
Project 234501.0009
Tilnitvb
TABLE OF CONTENTS
1. INTRODUCTION 1-1
2. RACTMETHODOLOGY 2-l
2.L Top-Down RACT Analysis Steps..,.,.......rr..r .............. 2-1
3. SOURCES OF NOx EMISSIONS SUBJECT TO RACT REVIEW 3-13.1 Process Heaters and Boi1ers............... ....,3-1
3,1.1 Step 1 - Identify All Reasonably Auailable Control Technologies ..................3-1
3.1.2 Step 2 - Eliminate Technially Infeasible Control Technologies ...................3-6
3.1.3 Step 3 - Rank Remaining Control Technologies fused on Gpture and Control Efficiencies
3-7
3.1.4 Step 4 - Evaluate Remaining controlTechnologies on Economiq Energy, and
Environmental Feasibility. ..............3-11
3.1.5 Step 5 - Seled RACT. .......3-133.2 Flares .3-14
3.2.1 Step 1 - Identify All Reasonably Available Control Technologies ............... 3-15
3.2.2 Step 2 - Eliminate Technially Infeasible ControlTechnologies ............,....3-16
3.2.3 Step 3 - Rank Remaining ControlTechnologies Based on Qpture and Control Efficiencies
3-16
3.2.4 Step 4 - Evaluate Remaining ControlTechnologies on Economiq Energy, and
Environmental Feasibility. ...........,..3-16
3.2.5 Step 5 - Select RACT ........3-17
3.3 Sulfur Recovery Unit Tail Gas Incinerator ........ .....3-17
3.3.1 Step I - Identify All Reasonably,Available Control Technologies ............... 3-17
3.3.2 Step 2 - Eliminate Technially Infeasible ControlTechnologies .................3-17
3.3.3 Step 3 - Rank Remaining ControlTechnologies Based on Capture and Control Efficiencies
3-18
3.3.4 Step 4 - Evaluate Remaining Control Technologies on Economiq Energy, and
Environmental Feasibility. ..........,,,.3-18
3.3.5 Step 5 - Select RACT ........3-183.4 Fluidized Catalytic Cracking Unit (FCCU)............... ................. 3-19
3.4.1 Step 1 - Identify all Reasonably Available Control Technologies ................ 3-19
3.4.2 Step 2 - Eliminate Technically Infeasible ControlTechnologies .................3-19
3.4.3 Step 3 - Rank Remaining Control Technologies Based on Gpture and Control Efficiencies
3-19
3.4.4 Step 4 - Evaluate Remaining ControlTechnologies on Economiq Energy, and
Environmental Feasibility. ............3-21
3.4.5 Step 5 - Seled MCT ........3-223.5 Emergency Diesel Engines ...3-23
3.5.1 Step I - Identify all Reasonably Available Control Technologies ................ 3-23
3.5.2 Step 2 - Eliminate Technially Infeasible ControlTechnologies .................3-24
3.5.3 Step 3 - Rank Remaining ControlTechnologies Based on Gpture and Control Efficiencies
3-24
3.5.4 Step 4 - Eualuate Remaining ControlTechnologies on Economig Energy, and
Environmental Feasibility. ..............3-25
3.5.5 Step 5 - Select MCT ........3-26
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023
3.6 Emergency Natural Gas-Fired Engines,... ...............3-27
3.6.1 Step I - Identify All Reasonably Available Control Technologies ................ 3-27
3.6.2 Step 2 - Eliminate Technically Infeasible ControlTechnologies .3-28
3.6.3 Step 3 - Rank Remaining ControlTechnologies tused on Capture and Control Efficiencies
3-28
3.6.4 Step 4 - Eualuate Remaining ControlTechnologies on Economic, Energy, and
Environmental Feasibility. ..............3-28
3.6.5 Step 5 - *kt RACT ,.......3-29
4. SOURCES OF VOC EMISSIONS SUBJECT TO RACT REVIEW 4-L
4.1 Process Heaters and Boi1ers............... .....4-L
4.1.1 Step 1 - Identify All Reasonably Available Control T*hnologies ............,....,4-1
4.1.2 Step 2 - Eliminate Technially Infeasible Control Technologies ...4-2
4.1.3 Step 3 - Rank Remaining ControlTechnolqies fused on Capture and Control Efficiencies
4-3
4,1.4 Step 4 - Eualuate Remaining ControlTuhnologies on Economiq Energy, and
Environmental Feasibility. ................4-3
4.1.5 Step5-SelectMCT .........,4-4
Flares ...4'4
4.2.1 Step 1 - Identifi All Reasonably Available Control Tuhnologies .........,........4-4
4.2.2 Step 2 - Eliminate Technially Infeasible Control Technologies ...4-5
4.2.3 Step 3 - Rank Remaining ControlTxhnolqies fused on Capture and Control Efficiencies
4-5
4.2.4 Step 4 - Eualuate Remaining ControlTehnologies on Economiq Energy, and
Environmental Feasibility. ,.......,.......4-6
4.2.5 Step 5 - Sel&t MCT ........,.4-6
Cooling Towers .....4-7
4.3.1 Step 1 - Identify All Reasonably Available Control Tuhnologies ..................4-7
4.3.2 Step 2 - Eliminate Technically Infeasible Control Technologies ...4-7
4.3.3 Step 3 - Rank Remaining ControlTechnologies tusd on @pture and ControlEfficiencbs
4-7
4.3.4 Step 4 - Eualuate Remaining Control Technologies on Economiq Energy, and
Environmental Feasibility. ................4-7
4.3.5 Step 5 - Select MCT .........,4-8
Sulfur Reduction Unit Incinerator......... .....,.............4-8
4.4.1 Step 1 - Identify All Reasonably Auailable Control T*hnologies ..................4-8
4,4.2 Step 2 - Eliminate Technially Infeasible Control Technologies ...4-8
4.4.3 Step 3 - Rank Remaining Control Tuhnologies fused on Qpture and Control Efficiencies
4-8
4.4.4 Step 4 - Eualuate Remaining Control Txhnologies on Economig Energy, and
Environmental Feasibility. ................4-8
4.4.5 Step 5 - Select MCT ...........4-8
FCCU........ ..............4-9
4.5.1 Step 1 - Identify All Reasonably Available Control Technologies ..................4-9
4,5,2 Step 2 - Eliminate Technially Infeasible ControlTechnologies .4-10
4.5.3 Step 3 - Rank Remaining ControlTechnologies fused on Capture and ControlEfficiencies
4-10
4.5,4 Step 4 - Eualuate Remaining ControlTechnologies on Economiq Energy, and
Environmental Feasibility. ..............4-10
4.5.5 Step 5- klect RACT. ..........4-10
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023
4.2
4.3
4.5
4,6 Fixed Roof Storage Tanks ........r........ .,..4-10
4.6.1 Step 1 - Identify All Reasonably Available Control Technologies ................ 4-12
4.6.2 Step 2 - Eliminate Technically Infeasible ControlTechnologies .4-14
4.6.3 Step 3 - Rank Remaining ControlTechnologies tused on Gpture and Control Efficiencies
4-14
4.6.4 Step 4 - Evaluate Remaining ControlTechnologies on Economiq Energy, and
Environmental Feasibility. ............4-14
4.6.5 Step 5 - Select MCT ........4-17
4.7 Internal Floating Roof Storage Tanks.. .4-17
4.7.1 Step I - Identify All Reasonably Available Control Technologies ................ 4-18
4.7.2 Step 2 - Eliminate Technially Infeasible Control Technologies . 4-20
4.7.3 Step 3 - Rank Remaining Control Technologies tused on @pture and ControlEfl1ciencies4-
20
4.7.4 Step 4 - Evaluate Remaining ControlTechnologies on Economiq Energy, and
Environmental Feasibility. .............4-20
4.7.5 Step 5 - Select RACT ,.......4-21
4.8 External Floating Roof Storage Tanks ..4-21
4.8.1 Step 1 - Identify All Reasonably Available Control Technologies ..............., 4-24
4.8.2 Step 2 - Eliminate Technically Infeasible ControlTechnologies .4-24
4.8.3 Step 3 - Rank Remaining Control Technologies Based on Capture and Control Efficiencies4-
24
4.8.4 Step 4 - Evaluate Remaining ControlTechnologies on Eonomig Energy, and
Environmental Feasibility. ...,,......4-24
4.8.5 Step 5 - Select RACT ........4-25
4.9 Equipment Leaks........ ..,.......4-25
4.9,1 Step I - Identify All Reasonably Available Control Technologies. ............,.. 4-26
4.9.2 Step 2 - Eliminate Technically Infeasible ControlTechnologies .4-26
4.9.3 Step 3 - Rank Remaining Control Technologies Based on Capture and Control Efficiencies4-
26
4.9.4 Step 4 - Eualuate Remaining ControlTechnologies on Economic, Energy, and
Environmental Feasibility. ............4-26
4.9.5 Step 5 - Select RACT ........4-28
4.1O Wastewater Treatment P1ant........ ........4-29
4.10.1 Step I - Identify All Reasonably Available Control Txhnologies ................ 4-29
4.10.2 Step 2 - Eliminate Technically Infeasible ControlTechnolqies .................4-29
4.10.3 Step 3 - Rank Remaining Control Technologies fused on Capture and Control Efficiencies4-
29
4.10.4 Step 4 - Evaluate Remaining ControlTechnologies on Economig Energy, and
Environmental Feasibility... ,.,........4-30
4.10.5 Step 5 - Select MCT ........4-31
4.11 Product Loading ......r..r,...... ..4-32
4.11.1 Step 1 - Identify All Reasonably Available Control Technologies ................ 4-32
4.11.2 Step 2 - Eliminate Technically Infeasible ControlTechnologies ..............,.. 4-32
4.11.3 Step 3 - Rank Remaining Control Technologies Based on Capture and Control Efficiencbs4-
32
4.11.4 Step 4 - Evaluate Remaining ControlTechnologies on Economiq Energy, and
Environmental Feasibility. ....,........ 4-33
4.11.5 Step 5 - Select MCT .......4-33
4.12 Diese! Emergency Engines r......r...,..... ...4-34
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023
4.12.1 Step I - Identify All Reasonably Available Control Technologies. ........,....... 4-34
4.12.2 Step 2 - Eliminate Technically Infeasible Control Technologies .4-34
4.12.3 Step 3 - Rank Remaining Control Technologies Based on Capture and Control Efficiencies4-
34
4.12.4 Step 4 - Evaluate Remaining ControlTechnolqies on Economiq Energy, and
Environmental Feasibility. ..............4-35
4.12.5 Step 5 - Select MCT ..,.....4-35
4.13 Natural Gas Emergency Engines ...........4-36
4.13.1 Step 1 - Identify All Reasonably Available Control Technologies. ................ 4-36
4.13.2 Step 2 - Eliminate Technbally Infeasible ControlTechnologies .4-36
4.13.3 Step 3 - Rank Remaining Control Technologies Based on Capture and Control Efftciencies4-
36
4.13.4 Step 4 - Evaluate Remaining ControlTechnolqies on Economiq Energy, and
Environmental Feasibility. ..........,,..4-37
4.13.5 Step 5 - klect RACT ........4-37
5. ACTUAL AND POTENTIAL EMISSIONS
APPENDTX A. EQUTPMENT DESCRTPTIONS AND 2017 ACTUAL EMISSIONS
APPENDIX B. $/TON COST ANALYSES
APPENDIX C. HOLLY ENERGY PARTNERS RACT ANALYSIS
5-1
A-1
B-1
c-1
LIST OF TABLES
Table 3-1 Potential NOx ControlTechnologies for Refinery Process Heaters and Boilers
Table 3-2 NO, Control Efficiencies
Table 3-3 Process Heaters and Boilers at HF Sinclair Woods Cross Refinery
Table 3-4 Technically Feasible Control Options for NO, for Process Heaters and Boilers
Table 3-5 Current ControlTechnologies on HF Sinclair Process Heaters and Boilers
Table 3-6 LoTOxr" NOx Reduction Technology Installations
Table 3-7 Cost Effectiveness of Installing SCR on Emergency Diesel Engines for NO, Control
Table 4-1 VOC ControlTechnologies by Control Effectiveness
Table 4-2 Fixed Roof Tanks at HF Sinclair Woods Cross Refinery
Table 4-3 Internal Floating Roof Tanks at HF Sinclair Woods Cross Refinery
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023
3-2
3-8
3-9
3-10
3-L2
3-22
3-26
4-3
4-tL
4-18
Table 4-4 External Floating Roof Tanks at HF Sinclair Woods Cross Refinery 4-23
Table 4-5 SCAQMD Estimated Cost to Install a Dome Roof on an External Floating Roof Tank 4-24
Table 4-6 $/ton Estimate of VOC Reduced from Installation of Domed Roof Tanks on the External Floating
Roof Tank at HF Sinclair Woods Cross Refinery 4-25
Table 4-7 Repair Actions for Leaking Valves and Pumps 4-27
Tabfe 4-8 LDAR Monitoring Frequencies 4-28
Table 4-9 RACT Controls, VOC Emission Limits, and Monitoring Methods for Wastewater Treatment 4-3L
Table 4-10 Cost Effectiveness of Installing DOC on Emergency Diese! Engines for VOC Control 4-35
Table 5-1 HF Sinclair Woods Cross Refinery - NO" and VOC 2017 Actual Emissions 5-1
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023
1. INTRODUCTION
In a May 3t, 2023letter, the Utah Division of Air Quality (UDAQ) requested from HF Sinclair Woods Cross
Refining LLC, Woods Cross Refin€ry, d Reasonable Available Control Technology (RACD assessment for
sources of oxides of nitrogen (NOx) and Volatile Organic Compounds (VOCS) at the Woods Cross Refinery and
Holly Energy Partners - Woods Cross Terminal in support of the redesignation of the Northern Wasatch Front
moderate ozone nonattainment area to serious. This document provides the updated MCT assessment. A
previous MCT assessment as part of the moderate ozone non-attainment area demonstration was submifted
to the UDAQ on February 23,2023.
The HF Sinclair Woods Cross Refinery, situated on approximately 100 acres of fenced area, is a 60,000 barrel
per day (bbl) refinery that produces a variety of products including gasoline, natural gas liquids (NGL),
propane, butanes, jet fuels, fue! oils, and kerosene products. The refinery receives and distributes products
by tanker truck, rail car and pipeline. Holly Energy Partners - Operating LP operates the Woods Cross Terminal
which is an existing petroleum product loading facility. However, it has been established that the Termina!
and Woods Cross Refinery are considered one source. The RACT analysis for the Terminal has been submitted
under separate cover.
1.1 Background
The United States Environmental Protection Agency (EPA) designated the Wasatch Front as marginal
nonattainment for the 2015 eight-hour ozone standard on June 4,20L8. The portions of the Wasatch Front
affected by this designation have been divided into two areas: Northern Wasatch Front and Southern Wasatch
Front. The Nofthern Wasatch Front includes all or part of Salt Lake, Davis, Weber, and Tooele counties. The
Southern Wasatch Front includes paft of Utah County.
The Wasatch Front was required to attain the ozone standard by August 3,2021. Recent monitoring data
indicated that the Southern Wasatch Front nonattainment area attained the standard and UDAQ has initiated
the process for re-designation to attainment for this area. However, for the Northern Wasatch Front
nonattainment area, recent monitoring data indicated that this portion of the Wasatch Front did not attain the
ozone standard. On November 7,2022, the Environmental Protection Agency (EPA) reclassified the Northern
Wasatch Front from marginal nonattainment area to moderate.
The Northern Wasatch Front ozone nonattainment area is required to attain the ozone standard by August 3,
2024, for moderate classification based on data trom 202L,2022, and 2023. Monitoring data indicates the
Northern Wasatch Front nonattainment area will not attain the standards and as such will be reclassified to
serious status in February 2025. The HF Sinclair Woods Cross Refinery and Termina! are in Davis County, in
the Northern Wasatch Front ozone nonattainment area.
The UDAQ identified HF Sinclair Woods Cross Refining LLC facility and Holly Energy Paftners - Woods Cross
Terminal as a major stationary source located in the Northern Wasatch Front Ozone Nonattainment Area in
early 2018. A major stationary source in a moderate ozone nonattainment area is defined as any stationary
source that emits or has the potentia! to emit 100 tons per year or more of NO,, or VOCs. The Ozone
Implementation Rule requires the SIP to include MCT measures for all major stationary sources in
nonattainment areas classified as moderate or higher. Therefore, the upcoming reclassification to serious
nonattainment triggered a new review of the MCT requirements for HF Sinclair Woods Cross Refining LLC.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2Q23 1-1
2. RACT METHODOLOGY
Under the Clean Air Act, all areas designated Moderate and Serious nonattainment for the 2015 8-hour ozone
standard are required to implement RACT for al! existing major sources of VOCs or NO, as well as all VOC
sources subject to an EPA ControlTechnique Guideline (CfG). A RACT analysis requires implementation of
the lowest emission limitation that an emission source is capable of meeting by the application of a contro!
technology that is reasonably available, considerilp technologica! and economic feasibility. A RACT analysis
must include the latest information when evaluating controltechnologies. These technologies can range from
work practices to add-on controls. As part of the MCT analysis, current contro! technologies already in use
for VOCs or NOx sources were taken into consideration.
2.L Top-Down RACT Analysis Steps
To conduct the MCT analysis, a top-down analysis was used to rank al! control technologies. This approach,
as outlined by the UDAQI, consists of the following steps:
1. Identiff All Reasonably Available ControlTechnologies
2. Eliminate Technically Infeasible Control Technologies
3. Rank Remaining ControlTechnologies Based on Capture and Control Efficiencies
4. Evaluate Remaining ControlTechnologies on Economic, Energy, and Environmenta! Feasibility
5. Select MCT.
In Step 1 in a "top down" analysis, all available control options for the emission unit in question are identified.
Identiffing all potentia! available control options consists of those air pollution control technologies or control
techniques with a practical potential for application to the emission unit and the regulated pollutant being
evaluated.
In Step 2, the technical feasibility of the control options identified in Step 1 are evaluated and the control
options that are determined to be technically infeasible are eliminated. Technically infeasible is defined where
a control option, based on physica!, chemical, and engineering principles, would preclude the successful use
of the contro! option on the emissions unit under review due to technical difficulties. Technically infeasible
control options are then eliminated from further consideration in the RACT analysis.
The third step of the "top-down" analysis is to rank all the remaining control options not eliminated in Step 2,
based on capture and control effectiveness for the pollutant under review. If the MCT analysis proposes the
top contro! alternative, there would be no need to provide cost and other detailed information.
Once the control effectiveness is established in Step 3 for allfeasible controltechnologies identified in Step 2,
additional evaluations of each technology, based on economic impacts, energy, and environmental feasibility
are considered in Step 4.
The economic evaluation of the remaining control technologies is analyzed. The capital cost of each control
technology, including the cost of device and materials, the one-time costs of delivery, engineering, labor,
installation, startup, annualoperation and maintenance costs, and other indirect costs such as administration,
taxes, insurance are analyzed. The interest rates used are the current bank prime rate.
I https://deq.utah.gov/air-quality/reasonably-available-control-technology-ract-process-moderate-area-ozone-sip
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 2-L
The energy impact of each evaluated contro! technology which is the energy benefit or penalty resulting from
the operation of the control technology at the source will also be analyzed. The costs of the energy impacts,
such as additional fuel costs or the cost of lost power generation, impacts the cost-effectiveness of the control
technology.
The third evaluation to be reviewed for each control technology remaining in Step 4 is the environmental
evaluation. Non-air quality environmental impacts are evaluated to determine the cost to mitigate the
environmental impacts caused by the operation of a control technology.
In Step 5, RACT is selected for the pollutant and emission unit under review. MCT is the highest ranked
control technology not eliminated in Step 4.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 2-2
3. SOURCES OF NOx EMISSIONS SUBJECT TO RACT REVIEW
MCT were evaluated for oxides of nitrogen (NOx) emissions from ceftain emission units in operation or
proposed at the Woods Cross Refinery. These units include process heaters, boilers, flares, sulfur reduction
unit (SRU), fluidized catalytic cracking units (FCCU), and emergency diesel and natural gas-fired engines.
3.1 Process Heaters and Boilers
At the Woods Cross Refinery, there are 19 existing or proposed process heaters (4H1, 6H1, 6H2, 6H3,7HL,
7H3, 8H2,9H1, 9H2, 10H1, 11H1 , LZHL, 13H1, 19H1 , 20H2, 20H3, 24HL, 25HL), two (2) asphalt tank in-line
heaters (68H2 and 68H3), and 6 boilers (Boiler #4, #5, #8, #9, #10, and #11). The list of the ratings for
this equipment is presented in Appendix A.
3.1.1 Step 1 - Identify All Reasonably Available Control Technologies
Nitrogen oxides (NO,,) are formed during the combustion of fuels by oxidation of chemically bound nitrogen
in the fuel and by thermal fixation of nitrogen in the combustion air. There are three different formation
mechanisms: thermal, fuel, and prompt NOx. Thermal NO' is primarily temperature dependent (above
2000oF); fuel NO* is primarily dependent on the presence of fuel-bound nitrogen and the local oxygen
concentration. Prompt NOx is formed in relatively small amounts from the reaction of molecular nitrogen in
the combustion air with hydrocarbon radicals in the flame front.
There are a variety of options available for control of NO,. emissions from combustion sources. These include
equipment or modifications to equipment that reduce NO, formation, add-on control devices, or combinations
of both. Table 3-1 lists potential NO, control technologies for refinery heaters and boilers. Abbreviated
descriptions of each control technology are provided in Table 3-1.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-1
Table 3-1 Potential NO' ControlTechnologies for Refinery Process Heaters and Boilers
Control T
Low NO,, Burners (LNB)
Next generation and ultra-low NOx
burners (ULNB)
External flue gas recirculation (FGR)
Selective catalytic reduction (SCR)
Selective non-catalytic reduction
(sNcR)
Non-selective catalytic reduction
(NScR)
LNB + FGR
ULNB + FGR
LNB + SNCR
ULNB + SNCR
LNB + SCR
ULNB + SCR
EMr'"
LNB + EM,',
ULNB + EM,'"
Water/Steam injection
Low excess air
Staged Air/Fuel Combustion or
Overfire Air Injection (OFA)
CETEX
Reducing NO, emissions through burner design.
Reducing NOx emissions through burner design.
Flue gas is recirculated by a fan and external ducting and is
mixed with combustion air
Post combustion control. Injection of ammonia into a catalyst
bed within the flue gas path.
Post combustion control. Injection of ammonia directly into
the flue gas at a speciflc temperature.
Post combustion control. Precious metal catalysts promote
reactions that reduce most NO, in exhaust streams with low
oxygen content.
Combination of low NO, burners and flue gas recirculation.
Combination of ultra-low NO, burners and flue gas
recirculation.
Combination of low NO, burners and post-combustion add-on
SNCR.
Combination of ultra-low NO, burners and post-combustion
add-on SNCR.
Combination of low NO, burners and post-combustion add-on
SCR.
Combination of ultra-low NO, burners and post-combustion
add-on SCR
Post-combustion control. The EMx" system uses a coated
oxidation catalyst in the flue gas to remove both NO, and
other pollutants with a reagent such as ammonia.
Combination of low-NO' burners and post-combusUon add-
on EMx".
Combination of ultra-low NO, burners and post-combustion
add-on EMx'".
Decreases NOx formation by injecting steam with the
combustion air or fuel to reduce flame temperature.
Reduce excess air level by maintaining CO at minimum
threshold using in-situ CO analyzer in the flow gas stream.
A controlled portion of the total combustion-air flow,
typically t0-20o/o, is directed through over-fire ports located
above the highest elevation of burners in the furnace.
CETEX descales and coats tubes which reduces fire box
temperature by improving heat transfer in applications where
the tubes are externally scaled.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-2
3.7,7,7 Low NO, Burners
Low-NOx burner (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 staged 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
tota! 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. This technique reduces the formation of
thermal NO".
3.7.7.2 Ultra-Low NO, Burners
Ultra-low NO, burners (ULNB) recirculate hot, orygen-depleted flue gas from the flame or firebox back
into the combustion zone. This reduces the average Oz conC€ntration within the flame without
reducing the flame temperature below the ternperatures that are necessary for optima! combustion
efficiency. Reduced 02 concentrations in the flame have a strong impact on fuel NOx which makes
these burners effective for controlling NOr.
There are severaltypes of ULNB currently available. These burners combine two NOx reduction steps
into one burner, typically staged air with internal flue gas recirculation (IFGR) or staged fuel with
IFGR, without any external equipment. In staged air burners with IFGR, fuel is mixed with part of the
combustion air to create a fuel rich zone. High pressure atomization of the fuel creates recirculation.
Secondary air is routed into the burner block to optimize flame and complete combustion. This type
of design is usually used with liquid fuels.
In staged fuel burners with IFGR, fuel pressurc induces IFGR which creates a fuel lean zone and a
reduction in oxygen partial pressure. This design is predominantly used for gas fuel operations.
3.1,1,3 External Flue Gas Recirculation
In external flue gas recirculation (FGR), flue gas is recirculated using a fan and external ducting and
is mixed with the combustion air stream thereby reducing the flame temperature and decreasing NOx
formation. External flue gas recirculation only works with mechanical draft heaters with burners that
can accommodate increased gas flows. Achievable emission reductions are a function of the amount
of flue gas recirculated and is limited by efficiency losses and flame instability at higher recirculation
rates. Flue gas recirculation has not been demonstrated to function efficiently on process heaters that
are subject to highly variable loads and that burn fuels with variable heat value.
3.7.7.4 SCR
SCR is a process that involves the post combustion removal of NOx from flue gas with a catalytic
reactor. In the SCR process, ammonia injected into the exhaust gas reacts with nitrogen oxides and
oxygen to form nitrogen and water. The reaCtions take place on the surface of the catalyst. The
function of the catalyst is to effectively lower the activation energy of the NOx decomposition reaction.
Technical factors related to this technology include the catalyst reactor design, optimum operating
temperature, sulfur content of the fuel, catalyst de-activation due to aging, and the ammonia slip
emissions.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-3
The applicability of SCR is limited to heaters that have both a flue gas temperature appropriate for
the catalytic reaction and space for a catalyst bed large enough to provide sufficient residence time
for the reaction to occur. Optimum NOx reduction occurs at catalyst bed temperatures of 600"F to
750oF for vanadium or titanium-based catalysts and 470oF to 510oF for platinum catalysts2.
The sulfur content of the fuel can be of concern for systems that employ SCR. Catalyst systems
promote paftial oxidation of sulfur dioxide to sulfur trioxide which combined with water to form sulfuric
acid. Sulfur trioxide and sulfuric acid react with excess ammonia to form ammonia salts. These salts
may condense as the flue gas is cooled leading to increased particulate emissions.
The SCR process also causes the catalyst to deactivate over time. Catalyst deactivation occurs through
physical deactivation and chemical poisoning. To achieve high NOx reduction rates, SCR vendors
suggest a higher ammonia injection rate than stoichiometrically required which results in ammonia
slip. This slip leads to emissions trade-off between NOx and ammonia.
3.1.7.5 SNCR
Selective non-catalytic reduction (SNCR) is a post-combustion NOx contro! technology based on the
reactions of ammonia and NOx. SNCR involves injecting urea/ammonia into the combustion gas to
reduce the NOx to nitrogen and water. The optimum exhaust gas temperature range for
implementation of SNCR is 1,600 to 1,750oF for ammonia and from 1,000 to 1,900oF for urea-based
reagents. Operating temperatures below this range results in an ammonia slip which forms additional
NO*. In addition, the ammonia/urea must have sufficient residence time, approximately 3 to 5 seconds,
at the optimum operating temperatures for efficient NOx reduction. At optimum temperatures, NO*
destruction efficiencies range from 30 to 50o/o3.
SNCR reduces both therma! and fuel-derived NO,. The SNCR systems require rapid chemical diffusion
in the fue! gas. The injection point must be selected to ensure adequate flue gas residence time.
Unreacted ammonia in the emissions is known as slip and is potentially higher in SNCR systems than
in SCR systems due to higher reactant injection rates.
3.1.1.6 NSCR
Non-selective catalytic reduction (NSCR) is a flue gas treatment add-on NOx control technology for
exhaust streams with low oxygen (Oz) content. Precious metal catalysts are used to promote reactions
that reduce NOx, CO, and hydrocarbons (HC) to water, carbon dioxide, and nitrogen. One type of
NSCR system injects a reducing agent into the exhaust gas stream prior to the catalyst reactor to
reduce the NOx. A second type of NSCR system has an afterburner and two catalytic reactors (one
reduction catalyst and one oxidation catalyst). In this system, natural gas is injected into the
afterburner to combust unburned HC (at a minimum temperature of 1700oF). The gas stream is cooled
prior to entering the first catalytic reactor where CO and NOx or€ reduced. A second heat exchanger
cools the gas stream (to reduce any NOx reformation) before the second catalytic reactor where
remaining CO is convefted to COz.
2 Midwest Regional Planning Organization, Petroleum Refinery Best Available Retrofit Technology (BART) Engineering
Analysis, March 30, 2005.
3 EPA, 2003.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-4
The control efficiency achieved for NOx from NSCR ranges from 80 to 90 percent. The NO, reduction
efficiency is controlled by similar factors as for SCR, including the catalyst materia! and condition, the
space velocity, and the catalyst bed operating temperature. Other factors include the air-to-fuel (A/F)
ratio, the exhaust gas temperature, and the presence of masking or poisoning agents. The operating
temperatures for the NSCR system range from approximately 700o to 1500"F, depending on the
catalyst. For NOx reductions of 90 percent, the temperature must be between 800" to 1200oF. One
source indicates that the 02 concentration for NSCR must be less than 4 percent; a second source
indicates that the 02 concentration must be at or below approximately 0.5 percent.
3,1.1.7 Water/Steam fnjection
The injection of water or steam decreases NOx formation by reducing the flame temperature. Water
or steam is delivered either by injecting it dircctly into the root of the flame or by feeding it with
gaseous fuel. Water or steam injection can impact combustion unit operation by worsening flame
pattern, reducing unit efficiency, and affecting unit stability.
3,7,1,8 Low Excess Air
Minimizing the amount of excess air (i.e., oxyEen) during the initial stages of combustion decreases
the amount of NOx formed. However, redrcing the amount of oxygen can cause incomplete
combustion, which increases carbon monoxide (CO) emissions. The combustion unit can be operated
based on the CO concentration moderating the excess air and therefore, controlling the amount of
NOx generated. This CO level would be monitored by an in-situ CO analyzer in the flue gas stream.
This technique requires a high level of instrumentation and automation required for burner control
(e.9., actuators for draft & air control).
3.7.7,9 Overfire Air (Boilers only)
In this technique, which is only applicable to boilers, a controlled portion (typically L0-20o/o) of the
total combustion-air flow is directed through over-fire pofts located above the highest elevation of
burners in the furnace. The removal of the alr flow from the burners results in a fuel rich primary
combustion zone to limit the NOx formation. The combustion of the CO produced in the primary
combustion zone is completed using the air supplied by the over-fire air ports.
3.1.7.70 CETEX
Removing the scale and applying a coating to the heat transfer surfaces can reduce the firebox
temperature and decrease NO, formation by improving heat transfer. This technique applies in units
where the heat transfer tubes are externally scaled. Conversely, the layer of scaling acts as insulation
protecting the tubes from damage. Removing the scale to reduce emissions will also reduce the firing
rate.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-5
3.1.2 Step 2 - Eliminate Technically Infeasible Control Technologies
SNCR has been commercially installed throughout the world. Installations include coal-fueled heating
plant boilers, electric utility boilers, municipal waste incinerators, cement kilns and many package
boilers. The NO* reduction efficiency of SNCR processes depends on many factors including:
> Flue gas temperature in reaction zone> Uniformity of flue gas temperature in the reaction zone> Norma! flue gas temperature variation with load> Residence time> Distribution and mixing of ammonia/urea into the flue gases> Initial NOx conc€ntration> Ammonia/urea injection rate> Heater configuration, which affects location and design of injection nozzles.
The problem with the use of SNCR is that as the load changes, the optimum injectlon temperature
window moves. In petroleum refineries, the loads vary considerably depending, for example, upoh
product needs or feedstock run. If ammonia is injected at just the right temperature, then NO, can be
reduced by approximately 600lo. If ammonia is injected too hot, then more NO, is produced. If
ammonia is injected too cold, then ammonia does not react resulting in ammonia being emitted to the
atmosphere. The exhaust temperatures of the process heaters and boilers range from approximately
430oF to 1,000oF. Thus, no process control method has been developed that can match the
temperature and rate of ammonia injection with flue gas rate, temperature, and other variables to
ensure optimum emission control. Thus, SNCR was eliminated as not technically feasible for use as a
post-combustion control for NOx emissions from the process heaters and boilers.
NSCR is a flue gas treatment add-on NOx contro! technology for exhaust streams with low Oz content.
Efficient operation of the catalyst typically requires the exhaust gases contain no more than 0.5olo
oxygena' A second sources indicates that the NSCR technique is effectively limited to engines with
normal exhaust oxygen levels of 4 percent or less. Thus, NSCR was eliminated based on not having
lean burn furnaces.
The EMx" catalyst is the latest generation of SCONOx'M technology. EM,'" is a multi-pollutant catalyst
that does not require ammonia. The emissions of NOx are oxidized to NOz and then absorbed onto
the catalyst. A dilute hydrogen gas is passed through the catalyst periodically to regenerate the
catalyst. This gas absorbs the NOz from the catalyst and reduces it to Nz before it exits the stack.
EMx'" operates in a temperature range between 300oF to 700oF. The potassium carbonate coating
reacts with NOz to form potassium nitrites and nitrates, which are deposited onto the catalyst suface.
When al! the potassium carbonate coating on the suface of the catalyst has reacted to form nitrogen
compoundsT NOx con no longer be absorbed, and the catalyst must be regenerated.
a htto://www.meca.oro/resources/MECA stationarv IC enoine reoort 0515 final.pdf Accessed 2116120L7.
5 hftps://www3.eoa.oov/ttn/chief/ap42lch03/fi nal/c03s02.odf. Accessed 2l l6l20L7
HF Sinclair Woods Cross Refining LLC / Reasonable Avaihbb Control Technology Assessment
Trinity Consultants December 2023 3-6
The EMx'" system catalyst is subject to reduced performance and deactivation due to exposure to
sulfur oxides. The EMx" system is typically used to control emissions from natural gas-fired
combustion turbines, reciprocating engines, and industrial boilers in which the sulfur concentration in
the exhaust stream is low. The higher concentration of sulfur in the refinery gas will poison the EMx'"
catalyst.
EM,.'" has not been demonstrated on refinery fuel gas-fired process heaters or boilers since the
SCONOx" catalyst is sensitive to contamination by sulfur in the combustion fuel. This technology has
been demonstrated to function efficiently on combustion sources burning fuels like natural gas.
SCONOx'" systems have been installed at combined cycle and co-generation turbine plants with
capacities ranging from 5.2 to 32MW. Thus, since EMx" was not identified or has been demonstrated
for use on refinery process heaters or boilers, EMx" wds determined to be technically infeasible and
was eliminated for fufther consideration.
External flue gas recirculation (FGR) only works with mechanical draft heaters with burners that can
accommodate increased gas flows. All but one heater at the refinery is naturally drafted. Also, heaters
with burners closer than three feet cannot physically install FGR and associated piping. There is a
safety risk associated with FGR at the process heaters due to the potential for formation of explosive
gas mixtures if a heater tube should fail. Few applications have been made to refinery process heaters
due to this risk. Thus, external flue gas recirculation is not technically feasible for the process heaters
and boilers at the Woods Cross Refinery.
Water/steam injection can impact combustion unit operation by worsening flame pattern, reducing
unit efficiency, and affecting unit stability. The modest NOx reductions at the heater may be offset by
NOx emissions resulting from steam generation elsewhere. Also, minimal NO, reductions will be gained
in units already fitted with low NOx burners. Water/steam injection is predominantly used on gas
turbines.
No data could be found on the effectiveness of water/steam injection on process heaters and limited
data was found for use on boilers. Thus, steam injection was determined to be not technically feasible
for the process heaters or boilers at the Woods Cross Refinery.
Low access air was also considered technically infeasible for use on refinery heaters and boilers since
low oxygen operation results in longer flames that could cause flame impingement. Also, it is difficult
to maintain safe operating conditions at low o)cygen levels.
3.1.3 Step 3 - Rank Remaining Control Technologies Based on Capture and
Control Efficiencies
Table 3-2 presents a summary of the control efficiencies for the remaining NOx control technologies
that can be applied to process heaters and boilers.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-7
-r
Table 3-3 presenb a summary of tte permitted proess lreaterc and bolhrs at the HFSlndai/s Woods Cross
Refirery. Tatrb 34 presorts a summary d the potenthl tedrnlcally fesible options fu{*ar.ir,g NOx for eadr
pro@ss heater and boller at tfie Rellrnry. i
HF Sinclair Woods Cross Refining l."LC / Reasonable Available Conhol Technology Assessment
Trinity Consultants December 2023 3-8
Table 3-3 Process Heaters and Boilers at HF Sinclair Woods Cross Refinery
A.O.ID1
II.A.3
II.A.6
II.A.7
II.A.8
II.A.1O
II.A.11
II.A.13
II.A.15
II.A.16
II.A.18
II.A.2O
TT.A.22
il.A.24
II.A.3O
II.A.32
II.A.33
II.A.3B
II.A.40
II.A.46
fi.4.47
II.A.48
II.A.49
II.A.5O
II.A.51
II.A.64
II.A.65
Source ID
4H1
6H1
6H2
6H3
7Ht
7H3
BH2
9H1
9H2
10H1
11H 1
12H1
13H1
19H1
20H2
20H3
24Ht
25H1
Boil. #4
Boil. #5
Boil. #8
Boil. #9
Boil. #10
Boil. #11
68H2
68H3
Source Description
FCC Feed Heater
Reformer Reheat fumace
Prefractionator Reboi ler Heater
Reformer Reheat furnace
HF Alkylation RegeneraUon Furnace
HF Alkylation Dep{opanizer Reboiler
Crude Furnace # 1
DHDS Reactor Ch{rge Heater
DHDS Stripper Reboiler
Asphalt Mix Heat$
SRGP Depentanizer Reboiler
NHDS Reactor Chlrge Furnace
Isomerization Remtor Feed Furnace
DHT Reactor Charbe Heater
Fractionator Charge Heater
Fractionator Char$e Heater
Crude Unit Furnace
FCC F€ed Heater I
Boiler #4
Boiler #5 I
Boiler #8
Boiler #9 I
Boiler #10
Boiler #11 I
North In-tank Asphalt Heater
South In-tank
Status
I. S*"r*
In Seruice
In Service
In Seruice
In Service
In Service
In Service
In Service
In Service
In Seruice
In Seruice
In Service
In Seruice
In Service
In Service
In Service
In Seruice
In Service
In Seruice
In Service
In Service
In Service
In Seruice
In Seruie
In Seruice
In Seruice
Rating
(MMBtu/hr)
68.4139.9
(restricted to)
54.7
12.0
37.7
4.4
33.3
99.0
8.1
4.1
L3.2
24.2
s0.2
6.5
23.0
47.0
39.7
32.5
L7.7
35.6
70.0
92.7
89.3
89.3
89.3
0.8
0.8
l DAQE-AN101230057-23
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-9
Table 3-4 Technically Feasible Control Options for NO, for Process Heaters and Boilers
Source
ID
4H1
6H1
6H2
6H3
7HL
7H3
BH2
9Hl
9H2
10H1
11H1
12H1
13H1
NOx Reduction Technology
ULNB FGR SCR SNCR NSCR Steam Low CETEX
Injection Access
Air
Equipped No No3 No
No1 Nor Yes Yes No
No1 Nol No No3 No
No1 No1 No No3 No
Nol Nol No No3 No
No1 Nor No No3 No
Equipped No No3 No
Nol No1 No No3 No
Nol No1 No No3 No
Nol Nol No No3 No
Nor Nol No No3 No
Yes Equipped No No3 No
Nor Nol No No3 No
19H1 Equipped No No3 No
20H2 Equipped No No3 No
20H3 Equipped No No3 No
24Hl Equipped No No3 No
25H1 Equipped No No3 No
Boiler 4 Yes No Yes No
Boiler 5 Yes Yes No Equipped No
Boiler 8 Equipped Yes No Equipped No
Boiler 9 Yes Yes No Equipped No
Boiler 10 Yes Yes No Equipped No
Boiler 11 Equipped Yes No Equipped No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No2 No No No
No2 No No No
58H2 No2
58H3 No2
1 This option is only feasible if there is space in the firebox for larger burners.
2 LNB and ULNB are not available on such small (<1 mmBtu/hr) heaters.
3 Existing process heaters are naturally drafted.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-10
3.1.4 Step 4 - Evaluate Remaining control Technologies on Economic,
Energy, and Environmental Feasibility
Several sources of information were examined including EPA's RBLC MCT/BACI/IAER Clearinghouse,
state agency databases, vendor data, and published literature to identify the most effective NO*
control technologies, most stringent emissions limitations to compare against current RACT NOx
controls that have been or proposed to be implemented at the Woods Cross Refinery.
The top-ranked control option involves the use of LNB with SCR as the post-combustion control device
for process heaters and boilers. This option is typically applied to process heaters and boilers
approximately 100 MMBtu/hr or greater in rating. The NOx emission level achievable with this control
option is 0.0085 lblMMBtu based on a three-hour average although emission levels repofted in RBLC
range from 0.01 to 0.04 lb/MMBtu.
The second ranked option is the use of ULNB; the third highest ranking option is the use of LNB.
Emission levels for NOx reported by one refinery using ULNBs range from 0.050 to 0.031 lb/MMBtu.
Controlled NOx emissions of 0.025 lb/MMBtu have been repofted for the Selas ULNx@ burner. This
emission level is reported for natural gas firing and a firebox temperature of 1250oC (2280'F). A John
Zink burner for natural draft heaters was designed to meet 0.03 lb/MMBtu or 25 to 28 ppmv depending
on fuel composition. No additional controls were identified for small heaters such as the stab-in tank
heaters which are rated at 0.8 MMBtu/hr.
The boilers at HF Sinclair Woods Cross Refinery are chemically treated to remove scale on the boiler
heat tubes which improves boiler efficiency and reduces NOx emissions. Table 3-5 presents a list of
HF Sinclair's process heaters and boilers and the controltechnology being currently utilized.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-1 1
Source Description
4Ht
6H1
6H2
6H3
7Ht
7H3
BH2
9H1
9H2
10H1
11H 1
12H1
13H1
19H1
20H2
20H3
24Ht
25H1
Boil. #4
Boil. #5
Boil, #8
Boil. #9
Boil. #10
Boil. #11
68H2
LNB
GCP
GCP
GCP
GCP
GCP
ULNB
GCP
GCP
GCP
GCP
NGULNB
GCP
LNB
ULNB
ULNB
ULNB
ULNB
GCP
SCR
LNB + SCR
scR
SCR
LNB + SCR
GCP
FCC Feed Heater
Reformer Reheat Furnace
Prefractionator Reboi ler Heater
Reformer Reheat Fumace
HF Alkylation Regeneration Furnace
HF Alkylation Depropanizer Reboiler
Crude Furnace # 1
DHDS Reactor Charge Heater
DHDS Stripper Reboiler
Asphalt Mix Heater
SRGP Depentanizer Reboiler
NHDS Reactor Charge Furnace
Isomerization Reactor Feed Furnace
DHT Reactor Charge Heater
Fractionator Cha rge Heater
Fractionator Charge Heater
Crude Unit Furnace
FCC Feed Heater
Boiler #4
Boiler #5
Boiler #8
Boiler #9
Boiler #10
Boiler #11
North In-tank Asphalt Heater
Table 3-5 Current ControlTechnologies on HF Sinclair Process Heaters and Boilers
3.7.4.7 Energy and Environmental fmpacts
With the application of a SCR, additional adverse impacts are anticipated which include ammonia emissions
and the handling and disposal of spent catalysts as a solid waste stream. Ammonia that is injected in the SCR
system and exits the unit without pafticipating in the chemical reduction of NO, emissions leads directly to
emissions of ammonia and can lead indirectly to the formation of secondary pafticulate matter. These
problems are less severe when the SCR catalyst is new, and activity is greatest because the ammonia rate
can be set near-stoichiometric levels. As the catalyst ages, the activity decreases requiring a higher ammonia
injection rate to maintain the rate of NO* reduction required for continuous compliance with NOx emission
levels.
Besides an environmental and air quality impact, an adverse energy impact is expected due to the electrical
requirements of the SCR system operation and to the reduction in energy efficiency attributable to the power
drop across the SCR catalysts grid.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-t2
3,7,4.2 Economic Impact
According to EPA, SCR reduces NO* by 90 percent or greater in an uncontrolled mechanical draft process
heater. SCR systems require mechanical draft operation due to the pressure drop across the catalyst. The
only heater at HF Sinclair that is mechanically drafEd is 6H1. All other heaters are naturally drafted.
To use an SCR system or systems on the process heaters at HF Sinclair, the refinery would need to replace
all naturally draft heater with mechanical draft heaters which would not be economically feasible as well as
limit refinery operations for a lengthy period. Thus, SCR is eliminated as technically infeasible for use on the
naturally drafted heaters at HF Sinclair.
An analysis was performed to evaluate the technical feasibility and cost effectiveness of upgrading existing
process heaters with LNB or ULNB. In conversations with representatives from John Zin( when upgrading
the existing units to LNB or ULNB, the floor of each heater box would have to be reconstructed to inseft the
LNB or ULNB which are typically longer and wider than the existing burners. Also, LNB and ULNB have a lower
heating duty per burner than traditional burners; therefore, in some cases, will result in a need for additional
burners to achieve the firing rate needed for the process application. Most heaters at HF Sinclair are not
designed to accommodate additional burners and would need to be reconstructed all together. If additional
burners cannot be added and the heater is not reconstructed, then a process rate decrease would need to
take place.
An additional consideration with retrofitting existing heaters to LNB or ULNB is the flame pattern. LNB and
ULNB generally produce a longer flame in the fire box which can extend to contact process piping or the
convection section of the heater. Contact with process piping can result in coking of the inside of the process
pipes which results in a loss of heat transfer and eventual plugging. Flame extension into the convection
section can result in heat transfer not consistent with engineered design resulting in process coking,
inadequate heat transfer, heater box temperature, and loss of process control.
The cost to upgrade burners to ULNB was examined. On average, the price for an ULNB is approximately
$36,050 per burner. Testing and instdllation costs are approximately twice the cost of the actual burner for a
total of cost of $105,000 per burner. Each proces$ heater has multiple burners. Thus, it is not economically
feasible to reconstruct all existing process heaters. The application of ULNB on existing units (6H1, 6H2, 6H3,
7HL,7H3,gHL,9H2, 10H1, 11H1, 13H1) is not technically possible due to space limitations in the firebox,
lower heat duty, and a longer flame. Thus, for these reasons, retrofitting of existing process heaters with LNB
or ULNB has been determined to be technically and economically infeasible. See Appendix B for a detailed
cost analysis.
3.1.5 Step 5 - Select RACT
According to EPA, 7 ppmv of NO, should generally be considered as I-AER or the most stringent contro!
measure for NO, emissions from new refinery process heaters. Refiners can achieve this level of control
through a combination of combustion controls (LNB with internal flue gas recirculation) and SCR. For boilers
100 MMBtu/hr or greater, the most stringent control is a NOx limit of 5 ppm @ 3olo Oz using SCR. For boilers
< 20 MMbtu/hr, the most stringent control is a NOx limit of 9 ppm using LNB.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-13
The Bay Area Air Quality Management District (BAAQMD), South Coast Air Quality Management District
(SCAQMD), California Air Resources Board (CARB) MCT guidelines were reviewed for determining RACT
emission rates for the refinery heaters with a firing rate greater than 50 MMBtu/hr. NO, limits range from 5
ppmdv (the most stringent identified by SCAQMD) to 10 ppmdv, al! corrected to 3olo Oz. A 5 ppmdv emission
rate at 3o/o Oz equates to approximately 0.006 lb/MMbtu; a 10 ppmdv emission rate at 3o/o Oz equates to
approximately 0.012 lb/MMbtu. These limits were accomplished using SCR and LNB. These controls are not
practical for HF Sinclair for the reasons presented above (i.e., SCR requires mechanical draft) for the process
heaters. Thus, these more stringent emission limits for the process heaters at HF Sinclair are not considered
RACT.
The 8H2, 20H2,20H3,24HL, 25HL process heaters at HF Sinclair are equipped with LNB (20H2) or ULNB
(8H2, 20H3, 24H1,25H1) and have an emission limit of 0.04 lb/MMBtu. Manufacturer NOx emission guarantees
on these units are 0.03 lb/MMBtu (8H2 and 20H3) and 0.04 lblMMBtu (24HL and 25H1). Callidus provided a
NO, emission guarantee of 16 ppm corrected to3o/o Oz for 20Hz with LNB. Compliance with the emission limit
of 0.04 lb/MMBtu is/will be verified every three years through stack testing. This represents MCT for these
heaters.
For the stab-in heaters, only good combustion practices (GCP) were identified to contro! NOx emissions from
these smal! heaters which is considered MCT. Compliance for 58H2 and 68H3 is verified every three years
through stack testing.
The highest-ranking option, LNB and SCR, is used on Boilers #8 and #11. Boilers #5, #9, and #10 are
equipped with SCR. The NOx emission limit is 0.02 Ib/MMBTU for Boilers #s-#fl and represents MCT. Boiler
#5, equipped with SCR, has a NOx emission limit of 0.02 lblMMBtu which also represents MCT. Stack tests
are performed every three years to verify that these units are in compliance with the permissible limits. Boiler
#4 is a limited use boiler, and it was not technically or economically feasible to install a SCR on this unit.
The cost of installing and operating CEMS on each heater and boiler was examined. The estimated equipment
cost including a shelter and a NOz CEMS with affiliated equipment plus installation is approximately $254,016
per system. Total annual costs were estimated to be approximately $90,453. Using 2017 actual NO,, emissions
for the process heaters, the average cost-per-ton to monitor for NO, with a CEMS is $123,481. See Appendix
B for a detailed cost analysis.
3.2 Flares
Flares are used at petroleum refineries to destroy organic compounds in excess refinery fuel gas, purged
products, or waste gases released during startups, shutdowns, and malfunctions. Most flares have a natural
gas pilot flame and use the fuel value of the gas routed to the flare to sustain combustion.
There are two flare stack located at the Northwest corner of the refinery. During refinery upsets, process
equipment may experience over-pressures which are relieved through a spring-loaded pressure safety valve
CPSV'). Piping headers connect these devices to the flare stack, which is used to safely burn the released
hydrocarbons. A small, continuous flame of purchased natural gas acts as a pilot light to ignite the process
vapors as they enter the flare tip for final destruction.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-t4
With the installation of the flare gas recovery unit (FGRU), the Nofth (66-2) and South (66-1) flares became
an interconnected system. These interconnected flares handle relief gases from the Crude #2 Unit (Unit 24),
FCC #2 Unit (Unit 25), Poly Unit (Unit 26), Tank Farm (Unit 68), Rail Unloading (Unit 87), FCC Unit (Unit 4),
Reformer Unit (Unit 6), Alkylation Unit (Unit 7), Crude Unit (Unit 8), DHDS Unit (Unit 9), SDA Unit (Unit 10),
SRGP Unit (Unit 11), NHDS Unit (Unit 12), Isomerization Unit (Unit 13), Amine Treatment Unit (Unit 16), SRU
(Unit 17), SWS Unit (Unit 18), DHT Unit (Unit 19), GHC Unit (Unit 20), NaHS Sour Gas Treatment Unit (Unit
21), Sour water stripper/ASU (Unit 22), and BenZap Unit (Unit 23).
3.2.L Step 1 - Identify All Reasonably Available Control Technologies
For safe flare operation, the design of the flares requires the use of a pilot light. The combustion of natural
gas to fuel the pilot light and the combustion of refinery gases produces NO,.
A search of the RBLC, state databases, and emission control literature was conducted to find available control
technologies to control flare emissions. Flares operate primarily as air pollution control devices. The only
technically feasible control options for emissions of all pollutants from flares are:
> good combustion practices,
> conversion from air assisted to steam assisted, and
> flare gas recovery systems.
3.2.7,1 Proper Equipment Design and Work Practices
Proper equipment design and work practices include minimizing the quantity of gases combusted, minimizing
exit velocity, ensuring adequate heat value of contusted gases, and installing an automatic pilot reignition.
The flares at the Woods Cross Refinery are designed and operated in accordance with 40 CFR 60.18, genera!
contro! device requirements which always include a flame present, no visible emissions, and heat content and
maximum tip velocity specifications that meet the requirements of the rule. The use of pipeline-quality natural
gas to fuel the pilot lights will reduce NOx emissions.
3.2.7.2 Good Combustion Practices
A certain level of flame temperature control can be exercised for a flare by implementing fuel to air ratio
control. Generation of NO, is dependent on temperature. As the temperature rises, the generation rate of NO,
rises. Good combustion practices can be used to minimize emissions of NOr.
3.2,1,3 Conversion from Air Assisted to Steam Assisted
Flares produce lower flame temperatures when operating with low heating value gases at low combustion
efficiencies than when operating with high heating value gases at high combustion efficiencies. This leads to
reduced formation of NOx in the flame. In general, emissions were lower in steam assisted flare tests than in
air assisted flare tests conducted under similar conditions.
3,2.1,4 Flare Gas Recovery Systems
Flaring can be reduced by installation of a flare gas recovery system. A flare gas recovery system includes a
seal system to allow for recovery of process gases vented to the flare. Compressors recover the vapors and
route them to the fue! gas treatment system for HzS removal. After conditioning of the recovered vapors, the
gases are combined with other plant fuel gas sources and combusted in heaters, boilers, and other devices
that operate using fuel gas.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-15
If the pressure in the flare gas headers exceeds the seal system settings, excess flare gases are allowed to
flow to the flare for combustion. The pressure in the flare gas system increases due to additional process gas
flow that cannot be recovered by the flare gas compressors. Once the pressure drops and the excess gases
are combusted, the seal system re-establishes itself for continuous recovery of vapors.
The flare gas recovery system will not be sufficient to prevent flaring from process unit staftup and shutdown
events where large volumes of process gases will be sent to the flare. Also, during process upsets or
malfunctions, the flare gases may not be entirely recovered due to the constraints of the flare gas recovery
system. The flare gas recovery system will be sized for normal operating conditions.
3.2.2 Step 2 - Eliminate Technically Infeasible Control Technologies
None of the identified control options is considered technically infeasible for the flares at the Woods Cross
Refinery.
3.2.3 Step 3 - Rank Remaining Control Technologies Based on Capture and Control
Efficiencies
The top-ranking control option is the installation of a flare gas recovery system. Flare gas recovery systems
are achieved in practice. The second highest ranking control option includes proper equipment design and
work practices which includes good combustion practices. The destruction efficiency of a properly operated
flare is 98olo. The flares at the Woods Cross Refinery are steam assisted.
3.2.4 Step 4 - Evaluate Remaining ControlTechnologies on Economic, Energy, and
Envi ron mental Feasibility
HF Sinclair will install a flare gas recovery system to recover vent gas which is the highest ranked control
option.
Proper equipment design and work practices include minimizing exit velocity and the quantity of gases
combusted and ensuring adequate heat value of combusted gases. Because the flares are located at a
petroleum refinery, the flare must comply with the requirements and limitations presented in 40 CFR Part 60
Subpaft Ja and the design and work practice requirements of 40 CFR 60.18.
Emissions from the HF Sinclair Woods Cross Refinery flares under normal operation will consist only of the
emissions from the combustion of natural gas in the flare pilot flames and a small amount of purge gas that
is circulated through the flare system for safety reasons (i.e., to prevent air from entering the flare lines). In
addition, the HF Alkylation Unit bypasses the flare gas recovery system due to the potential of trace
hydrofluoric acid.
Proper equipment design and work practices include minimizing exit velocity and the quantity of gases
combusted and ensuring adequate heat value of combusted gases.
Flare management plans have been developed for both the north and south flares. These plans contain
procedures to minimize or eliminate discharges to the flare during staftups and shutdowns. To verify that the
procedures are followed, records are maintained.
The flares at the refinery are steam-assisted which leads to lower NO, formation in the flare flame.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-16
3.2.4.7 Energy, Environmental and Economic fmpacts
Since HF Sinclair has chosen the highest ranked control option, flare gas recovery, energy, environmental and
cost analyses are not required.
3.2.5 Step 5 - Select RACT
HF Sinclair is utilizing the following design elements and work practices as BACM for the flares:
accordance with manufacturer specifications,
> Implementation of good combustion, operating, and maintenance practices,
> Implementation of Flare Management Plans,
in 40 CFR Paft 60.18, and,
No more stringent measures were identified for the flares at the Woods Cross Refinery. The flare design
includes steam assisted combustion. The flares wil! be equipped with a flare gas recovery system for non-
emergency releases, and a continuous pilot light. Pilot and sweep fue! will be natural gas or treated refinery
gas. The north and south flares are equipped with flow meters and gas combustion monitors.
3.3 Sulfur Recovery Unit Tail Gas Incinerator
The SRU off gas is routed to the tail gas incinerator before venting directly to the atmosphere only during
emergency operations or during plant shutdown when both wet gas scrubbers are offline. Oxides of nitrogen
are formed during the combustion of natural gas in the incinerator by oxidation of chemically bound nitrogen
in the fuel and by thermal fixation of nitrogen in the combustion air.
3.3.1 Step 1 - Identify All Reasonably Available Control Technologies
The available control technologies for NO, control from the tail gas incinerator are the same technologies
listed in Table 3-2 above as well as the application of LoTOx'" which is a low temperature oxidation process
which utilizes ozone to oxidize insoluble NO and NOz to NzO (a highly soluble species of NO,) which can be
effectively removed by a variety of air pollution control equipment including wet scrubbers.
3.3.2 Step 2 - Eliminate Technically Infeasible Control Technologies
The only options that are technically feasible for an SRU tail gas incinerator is combustion control utilizing LNB
or ULNB and utilization of a LoTOx" system. The other technologies are either based on lowering flame
temperature, which is not compatible with the primary function of an incinerator, or add-on controls that have
not been demonstrated as technically feasible for a thermal oxidizer. There are significant technica! differences
between thermal oxidizers and the combustion sources for which these technologies have been demonstrated
in practice.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-17
3.3.3 Step 3 - Rank Remaining ControlTechnologies Based on Capture and Control
Efficiencies
Technically feasible NOx control technologies are combustion control utilizing LNB or ULNB fired on natural
gas and/or the application of a LoTOx'" system.
3,3.4 Step 4 - Evaluate Remaining Control Technologies on Economic, Energy, and
Environ mental Feasi bi IiW
The tail gas incinerator is a thermal incinerator that is used to facilitate the oxidation of the commonly reduced
sulfur compounds to SOz prior to release to the atmosphere. The incinerator combusts natural or refinery
gas which creates the NOx emissions. The tail gas incinerator is equipped with low NO, burners to reduce NOx
emissions that may form during the combustion of gaseous fuels.
During normal operation, the gases from the SRU tail gas incinerator which is equipped with LNBs are routed
to either Unit 4 or Unit 25 wet gas scrubbers. These wet gas scrubbers are configured to include the LoTOx'"
process which provides greater than 95o/o NOx reduction.
A review of the RBLC Clearinghouse identified two refineries, Sunoco Tulsa Refinery and Valero's St. Charles
Refinery, with NOx limits on the tail gas treatment units. These limits ranged from 0.14 lb/MMBtu or 1 lblhr
and 9.4 lb/hr and were met utilizing good combustion practices and proper equipment design. No indication
of burner type was presented for these tail gas treatment units.
3,3,4.1 Energy, Environmental and Economic Impacts
As mentioned above, the tail gas incinerator is a thermal incinerator that is used to facilitate the oxidation of
the common reduced sulfur compounds to SOz prior to release to the atmosphere. The incinerator combusts
natural or refinery gas which creates the NO,. emissions.
The tailgas incinerator on the SRU at HF Sinclair is equipped with LNBs which reduce NOx emissions that may
form during the combustion of gaseous fuels. There are energy and environmental impacts associated with
the use of the tail gas incinerator and pipeline natural gas. Additional energy and fuel are both required leading
to increased NOx emissions. However, emissions from the tail gas incinerator are controlled through one of
the FCCU wet scrubbers which utilizes LoTOx'" to further reduce NOx emissions.
Wet scrubbers generate waste in the form of a slurry. Typically, the slurry is treated to separate the solid
waste from the water. Once the water is removed, the remaining waste will be in the form of a solid which
can generally be landfilled. There are no other anticipated energy, environmental, or environmental impacts
associated with the use of the wet gas scrubbers during normal SRU operation.
3.3.5 Step 5 - Select RACT
During normal operations, emissions from the three-stage Claus SRU followed by a tail gas incinerator are
sent to one of the wet gas scrubbers. Thus, NO, RACT for the three-stage Claus SRU is the use of good
combustion practices, pipeline quality natural gas in tail-gas incinerator with proper equipment design, wet
scrubbing, and LoTOx'". No other measures were identified as more stringent to control NOx emissions. HF
Sinclair is meeting the NOx emission rates of 22.5 ppm NOx per 365-day rolling average and 40 ppm NOx per
7-day rolling average from Unit 4's wet gas scrubber, and 40 ppm NOx p€r 365-day rolling average and 80
ppm NO* per 7-day rolling average from Unit 25's wet gas scrubber.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3- 18
3.4 Fluidized Catalytic Cracking Unit (FCCU)
This MCT review was based on data summarized by EPA in the RBLC MCI/BACI/LAER Clearinghouse, review
of state databases and review of recent consent decrees. While the emission limits imposed by consent
decrees do not necessarily represent RACT or I-AER, they do represent the most stringent emissions limitations
placed upon FCCUS.
The two FCCU regenerators at HF Sinclair are fullturn units which are recognized by EPA as an inherently
low NO, design. The predominant NOx species insile an FCCU regenerator is NO that is further oxidized to
NOz upon release to the atmosphere. NOx in the regenerator can be formed by two mechanisms, thermal NOx
produced from the reaction of molecular nitrogen with oxygen and fuel NOx which is produced from the
oxidation of nitrogen-containing coke specie deposlted on the catalyst inside the reactor.
3.4.1 Step 1 - Identify all Reasonably Available Control Technologies
The following is a list of control technologies which were identified for controlling NO, emissions from the
FCCUs:
> Catalyst additives and low NO,combustion promoters.
3.4.2 Step 2 - Eliminate Technically Infeasible Control Technologies
All options are technically feasible.
3.4,3 Step 3 - Rank Remaining Control Technologies Based on Capture and Control
Efficiencies
The remaining control options were ranked in order of reduction:
3.4.3.1 SNCR
The SNCR system is a post-combustion control technology that reacts with urea or ammonia with flue gas
without the presence of a catalyst to produce Nz and HzO. The typical operating temperature range for an
SNCR is 1,600oF to 2,000oF. The SNCR temperature range is sensitive as the reagents can produce additional
NOx if the temperature is too high or removes too little NOx if the reaction proceeds slowly if the temperature
is too low. The NHr slip in SNCR applications can range from 10 to 100 ppmv. SNCR has been used
successfully with CO boilers but are typically not used with full burn units due to low NOx removal at
temperatures below 1,400oF. In full burn units, llke are utilized by HF Sinclair, the flue gas must be heated
to 1,600 to 1,800oF to achieve NOx r€ffiov?l rates of 50o/o and greater.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-19
3.4.3.2 SCR
Selective catalytic reduction is a post combustion control technology that injects ammonia in flue gas in the
presence of a catalyst (typically vanadium or tungsten oxides) to produce Nz and HzO. An SCR is like SNCR
with the exception that a catalyst is used to accelerate the reactions at lower temperatures. The ideal
temperature range for an SCR is 600"F to 750oF with guaranteed NO* removal rates of 90+o/o. Design
considerations include targeted NOx r€rTroval level, seruice life, pressure drop limitation, ammonia slip, space
limitation, flue gas temperature, composition and SOz oxidation limit. SCR suppliers typically guarantee the
pedormance of the unit for NOx r€ffioval, seruice life, pressure drop, ammonia slip and SOz oxidation.
Ammonia slip, referring to the amount of ammonia which passes through the process unreacted, is typically
guaranteed to 10 ppmv.
3,4.3.3 LoTOx"
The Belco LoTOx'" technology is a selective, low temperature technology that uses ozone, generated on
demand based on the amount of NO, in the flue gas, to oxidize NO, to water soluble nitric pentoxide (NzOs).
These higher oxides of nitrogen are highly soluble. Inside a wet gas scrubber, the NzOs forms nitric acid that
is subsequently scrubbed by the scrubber nozzles and neutralized by the scrubber's alkali reagent. Since the
process is applied at a controlled temperature zone in the wet gas scrubber, it can be used at any flue gas
temperature. The controlled temperature zone in the wet gas scrubber is below 300oF. Since the LoTOx'"
technology does not use a fixed catalyst bed, it can handle unit upsets without impacting overall reliability
and mechanical availability.
Emission reductions using this process have been estimated to range from 80 to 95olo using the LoTOxr"
technology.
3,4,3.4 Catalyst Additive and Combustion Promoters
Several vendors offer NOx reducing catalyst additives and combustion promoters. Current NO, additives affect
the availability of nitrogen species to be oxidized and reduced and the peformance of the additives is
dependent on the application. Grace Davison's XNOx is a combustion promoter additive that can reduce NO,
emission from 50-75o/o in the regenerator. Grace Davison's DENOX promoter can reduce NOx emissions up to
600lo. Engelhards CLEANNOx and OxyClean reduce NOx emissions by 45olo. INTERCAT's COP-NP can reduce
emissions from approximately 40-650/o. The NOx combustion promoters (catalysts and additives) are added
directly into the FCCU reactor and regenerator. These additives can withstand the harsh environment of the
regenerator but do not have the same life as catalyst.
A benefit associated with the use of additives is flexibility. Additives can be added and removed from the
operation depending on the refiner's needs but are more expensive than FCC catalysts with an average cost
approaching $180 per pound. The additional cost associated with the recommended usage rate of these
additives may triple the current catalyst cost resulting in negative process unit economics. Higher removal
rates may require more additives and that can impact yields, product quality and unit throughput.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-20
3.4.4 Step 4 - Evaluate Remaining Control Technologies on Economic, Energy, and
Envi ron menta I Feasi bi lity
SNCR is not feasible in this application because of the need to heat the flue gas to reach the optimum operating
levels of the SNCR. The amount of NOx reduction is also lower. Most EPA consent decree applications have
achieved a 5 to 30olo reduction with others in the industry achieving up to 70olo depending on process
conditions6. A drawback of using SNCR technology is the potential formation of ammonium sulfate salts and
resultant fouling. These salts will exist as small particulates.
A SCR system can achieve between 80-90o/o reductions on uncontrolled NO, emissions. SCRs operate in the
temperature range of FCC regenerator flue gas. This control technology has a high NO" reduction rate when
compared to other NOx control technologies. Although SCR offers high NO,, reduction rates, catalyst
deactivation can occur from salt formation on the catalyst surface, cracks of the catalyst from the substrate
material can occur from thermal stresses, and thermal degradation of the catalyst can occur at temperatures
greater than 800oF. Other items that can lead to catalyst deactivation include erosion of the catalyst due to
excessive catalyst fines loading and plugging of the catalyst system due to catalyst fines.
At the plants where SCR's have been installed, rnost of them have third stage separators or ESPs located
before the SCR catalyst bed to protect against upsets in the FCC regenerator.
LoTOx" in conjunction with wet scrubbing systems has been demonstrated to effectively reduce high Ievels
of NO" from a FCCU. The efficiency obtained from the combination of LoTOx" and wet gas scrubbing systems
is comparable to an SCR.
To apply SCR to the output of a wet gas scrubber with a LoTOx'" system is technically infeasible. The low
temperature of the exhaust stream combined with the concentration of NOx make further application of an
add-on control like SCR impractical.
Combustion promoters will not reduce the NOx emissions alone to meet NOx RACT levels.
A review of the literature and the EPA's RBLC indicate that SCRs or LoTO*" in conjunction with wet scrubbing
systems are used for the reduction of NOx in several FCCUs. BELCO, a subsidiary of DuPont, provided a list of
locations where the LoTOx '" technology has been installed in FCCU regenerator applications. Table 3-6
presents a list of a few of these facilities.
6 Advances in Fluid Catalytic Cracking, Chapter L7 , FCC NOx Emissions and Controls, Jeffrey A. Sexton, 2010.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-21
Table 3-6 LoTOx" NOx Reduction Technology Installations
Application Location Capacity Staft-up
2072,20t6
2010
2010
2010
2010
2009
2009
April2007
FCCU (New EDV Scrubber HF Sinclair
Woods Cross, UT ConfidentialLoTOx technology
FCCU (New EDV Scrubber PeUochina,Sichuan Confldential
West Pacific, Dalian Confidential
Valero, St. Charles, {
Valero, Delaware
city, DE 75'000 bPsd
Flint Hills, 9Put 45,ooo bpsdChristi, TX
Petrobras, REFAP'"''- ,r.l,i'-"" 7,000 m3/day
Valero, Houston,
rtexas 58,000 bpsd
LoTOx technology)
FCCU (New EDV Scrubber
LoTOx technology)
FCCU (Retrofitted LoTOx
echnology to existing EDV scrubber)
FCCU (Retrofitted LoTOx
to existing CANSOLV unit)
FCCU (ReEofitEd LoTOx
to existing D0(ON scrubber)
FCCU (New EDV Scrubber
LoTOx technology)
FCCU (New EDV scrubber
LoTOx technology)
3.4,4,7 Energy, Environmental, and Economic fmpacts
There are environmental and economic impacts associated with a wet gas scrubber. Wet scrubbers will
generate water vapor plumes, which during the winter months may reduce visibility. In addition, wet gas
scrubbers generate wastewater, which must be managed and disposed of at the refinery. Lastly, wet gas
scrubbers produce a significant amount of solid waste. Although wet gas scrubbers can be costly to install,
and annual operating costs can be comparatively high, wet gas scrubbers will be utilized to reduce NOx
emissions from the HF Sinclair FCCUS.
HF Sinclair is not proposing an SCR due to not being economically feasible because a third stage separator or
ESP would have to be installed to prevent catalyst fines from plugging the SCR's catalyst beds.
3.4.5 Step 5 - Select RACT
Thus, LoTOx'" systems in conjunction with wet gas scrubbers are utilized by HF Sinclair to reduce NOx
emissions in the regenerator flue gas from Units 4 and 25. The use of LoTOx'" in conjunction with wet gas
scrubbers has a comparable removal efficiency as a SCR for NOx.
The most stringent control identified as I-AER in the RBLC database was SCR that is being utilized at the Deer
Park Refinery with emission limits of 20 ppmvd @ 0olo Oz based on a 365-day rolling average and 4O-ppmvd
@0olo Oz based on a 3-hour average. According to HF Sinclair's Consent Decree, HF Sinclair designed the NO,,
Control system to achieve a NOx concentration of 20 ppmvd or lower on a three-hundred sixty-five (365) day
rolling average basis and 40 ppmvd on a seven (7) daV rolling average basis, each corrected to 0olo Oz.
The NO* limits for Unit 4 FCCU are 22.5 ppmvd at 0olo 02 (365 day) and 40 ppmdv (7 day). For Unit 25, the
NOx limits are 40 ppmvd (365 day) and 80 ppmvd (7 da$.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-22
Thus, the use of LoTOx" and a wet gas scrubber to achieve the above listed emission rates has been
determined to be RACT for the FCCUs operated by HF Sinclair.
3.5 Emergency Diesel Engines
Diesel emergency equipment at the Woods Cross nefinery consists of a 135-kW portable diesel generator at
the East Tank Farm, 224 HP diesel powered water well No. 3, 393 HP fire pump No. 1, 393 HP fire pump No.
2, 180 HP diese! fire pump, three 220 HP diese!-powered plant air backup compressors, 470 HP diesel standby
generator at the Boiler House, 380 HP diesel standby generator at the Central Control Room, and a 540 HP
diesel standby generator.
Diesel engines are classified as compression ignition (CI) internal combustion engines. In diesel engines, air
is drawn into a cylinder as the piston creates space for it by moving away from the intake valve. The piston's
subsequent upward swing then compresses the air, heating it at the same time. Next, fuel is injected under
high pressure as the piston approaches the top of its compression stroke, igniting spontaneously as it contacts
the heated air. The hot combustion gases expand, driving the piston downward. During its return swing, the
piston pushes spent gases from the cylinder, and the cycle begins again with an intake of fresh air.
The predominant mechanism for NOx formation from internal combustion engines is thermal NO, which arises
from the thermal dissociation and subsequent reaction of nitrogen and oxygen molecules in the combustion
air.
3.5.1 Step 1 - Identify all Reasonably Available Control Technologies
The following technologies were evaluated for controlling NOx emissions from the CI combustion engines.
They are categorized as combustion modifications and post-combustion controls. Combustion modifications
include ignition timing retard, air-to-fuel ratio, and derating. Post combustion controls include SCR, NSCR
catalyst, and NO, absorption systems.
3,5.1.1 fgnition Timing Retard
As described above, the injection of diesel fuel into the cylinder of a CI engine initiates the combustion process.
With ignition timing retard, this combustion modifkation lowers NOx emissions by moving the ignition event
to later in the power stroke when the piston is in the downward motion and combustion chamber volume is
increasing. Because the combustion chamber volume is not at its minimum, the peak flame temperature is
reduced which reduces the formation of thermal NO,.
3,5.1.2 Air-to-Fuel Ratio
Diesel engines are inherently lean-burn engines. The air-to-fuel ration can be adjusted by controlling the
amount of fuel that enters each cylinder. By reducing the air-to-fuel ratio to near stoichiometric, combustion
will occur under conditions of less excess oxygen and reduced combustion temperatures. Lower oxygen levels
and combustion temperature reduce NO, formation.
3.5.7.3 Derating
Derating involves restricting engine operation to lower than normal levels of power production. Derating
reduces cylinder pressure and temperatures which reduces NO, formation.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-23
3,5,1,4 Selective Catalytic Reduction
Selective catalytic reduction systems introduce a liquid reducing agent such as ammonia or urea into the
flue gas stream before the catalyst. The catalyst reduces the temperature needed to initiate the reaction
between the reducing agent and NO, 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. There are also
complications controlling the excess ammonia (ammonia slip) from SCR use.
3.5.1.5 Non-Selective Catalytic Reduction
Non-selective catalytic reduction systems are used to reduce emission from rich-burn engines that are
operated stoichiometrically or fuel-rich stoichiometric. In the engine exhaust, NSCR catalysts conveft NOx to
nitrogen and oxygen. NSCR catalytic reactions require that Oz levels be kept low and that the engine be
operated at fuel-rich air-to fuel-ratios. Lean-burn engines are characterized by an oxygen-rich exhaust which
minimizes the potential for NO, reduction.
3.5.7,6 NO, Adsorption Systems (Lean NOx Traps)
NOx absorber development is a new catalyst advance for removing NO, in a lean (i.e., oxygen rich) exhaust
environment for both diesel and gasoline lean-burn direct-injection engines.
With this technology, NO is catalytically oxidized to NOz and stored in an adjacent chemical trapping site as
nitrate. The stored NOx is removed in a two-step reduction step by temporarily inducing a rich exhaust
condition. NOx adsorbers (sometimes referred to as lean NOx traps) employ precious metal catalyst sites to
carry out the first NO to NOz conversion step. The NOz then is adsorbed by an adjacent alkaline eafth oxide
site where it chemically reacts and is stored as nitrate. When this storage media nears capacity, it must be
regenerated. This is accomplished by creating a rich atmosphere with injection of a small amount of diesel
fuel. The released NOx is quickly reduced to Nz by reaction with CO on a rhodium catalyst site or another
precious metal that is also incorporated into this unique single catalyst layer.
3.5.2 Step 2 - Eliminate Technically Infeasible Control Technologies
NSCR catalysts are effective to reduce NOx emission when applied to rich-burn engines fired on natural gas,
propane or gasoline. The proposed diesel engines are inherently lean-burn engines; thus, NSCR is eliminated
from fufther consideration.
In addition, NO, absorbers were eliminated from further consideration since NOx adsorbers are experimental
technology and no commercial applications of NO* absorbers were identified in state or EPA's RBLC
MCT/BACT/I-AER Clearinghouse databases as being employed on stationary emergency generators or fire
pumps. Also, the literature indicates that testing of these NO, absorbers has raised issues about sustained
peformance of the catalyst. Current lean NOx catalysts are prone to poisoning by both lube oil and fuel sulfur,
3.5.3 Step 3 - Rank Remaining Control Technologies Based on Capture and Control
Efficiencies
The remaining control options, combustion modifications and the post-combustion control, SCR will be
examined fufther. Combustion controls have been demonstrated to reduce NOx emissions from CI engines by
approximately 50o/o; the use of a SCR can reduce emissions in the range from 70 to 90olo.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-24
3,5.4 Step 4 - Evaluate Remaining Contro! Technologies on Economic, Energy, and
Environ mental Feasibility
The top control option, SCR, uses a reducing-agent like ammonia or urea (which is usually preferred) with a
special catalyst to reduce NO, in diesel exhaust to Nz. The SCR catalyst sits in the exhaust stream and the
reducing agent is injected into the exhaust ahead of the catalyst. Once injected the urea becomes ammonia
and the chemical reduction reaction between the ammonia and NO takes place across the SCR catalyst. With
the use of an SCR, there is the potential for some ammonia to "slip" through the catalyst.
SCR systems have two key operating variables that work together to achieve NOx reductions. These are the
exhaust temperature and the injection of urea or ammonia. The exhaust temperature must be between 260oC
and 540"C for the catalyst to operate properly. SCR systems will not begin injection of ammonia in the form
of urea until the catalyst has reached the minimum operating temperature. Urea is a critical component in
determining the contro! efficiency of the SCR. It must be injected in the exhaust stream upstream of the SCR
system. In the catalyst, it reacts to reduce NO, to from Nz and HzO. The reaction takes place because the
catalyst lowers the reaction temperature necessary for NOx.
Since SCR systems require an operating temperature between 260"C and 540oC, reaching these temperatures
may be difficult in routine maintenance and testing operations where the engine is typically operated at low
load for a short period of time. If the critical temperatures are not met while the engine is running, there will
be no NOx reduction benefit. To have NOx reduction benefit, the engine would need to be operated with higher
loads and for a longer period. This would be a challenge for HF Sinclair since each engine is limited to 100
operating hours per year.
Urea handling and maintenance must also be considered. Urea crystallization in the lines can damage the SCR
system and the engine itself. Crystallization in the lines is more likely in emergency standby engines due to
their periodic and low hours of usage.
3.5.4.1 Energy, Environmental, and Economic fmpacts
There are several downsides to using an SCR. First, an improperly functioning SCR system can create excess
ammonia emissions. SCR systems also add significant equipment to the engine system which increases the
possibility of failures and increases on-going maintenance costs.
Cost evaluations were prepared to determine the ost of control per ton of NO, removed from an SCR for the
emergency generators and fire water pump. SCR retrofit information was obtained from Wheeler Machinery
in Salt Lake City. Based on the current cost information provided by Wheeler, the calculated costs per ton of
NOx r€mov€d are presented in Table 3-7 and in Appendix B.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2Q23 3-25
Table 3-7 Cost Effectiveness of Installing SCR on Emergency Diesel Engines for NOx Control
Equipment
135 kW ge,le,"tor Gast tark fa"r)
224 HP (water well #3)
393 HP fire pump #1
393 HP flre pump #2
180 HP Detroit Diesel fire pump
220 HP plant air backup compressor #1
220 HP plant air backup compressor #2
220 HP plant air backup compressor #3
470 HP diesel generator (boiler house)
380 HP diesel generator (central control room)
540 HP
Cost
Effectiveness
on
$ 4,240,482
$ 724,675
$ 200,061
$ 235,774
$ t,02t,461
$ 267,2L3
$ 54,242
$ 18,206
$ 2,324,229
$ 703,430
651,315
In addition to the costs presented in Table 3-7, the cost of urea is $1.25 per KW and its shelf life is
approximately two years. This would increase the cost of operation of a SCR for emergency standby engines
since the low number of annual hours of operation could lead to the expiration of the urea. The urea would
have to be drained and replaced, creating an extra maintenance step and an increased cost to HF Sinclair.
3.5.5 Step 5 - Select RACT
According to HF Sinclair's approval order, the 135-kW poftable generator at the east tank farm is limited to
1,100 operating hours per year. ln20L7, the 135-kW portable generator ran 5.3 hours. Based on the economic
costs to install a SCR system, the likelihood that the engine would not be at proper operating temperature for
the SCR to be effective due to limited operating hours, and the extra maintenance and disposal costs if urea
were used, SCR has been eliminated from fufther consideration.
Currently, California has the most aggressive emission reduction standards for diesel engines. The MSM
identified includes the use of SCR systems to reduce NOx on diese! engines 1000 HP or greater. SCR systems
have not seen wide application on emergency standby engines less than 1000 HP. Maine Depaftment of
Environmental Protection requires non-emergency engines to install SCR technology for NOx control if their
potential annual NOx emissions exceed 20 tons as best available control technology.
Periodic maintenance is peformed on the engines in accordance with manufacturer specifications. For those
engines subject to Subpaft Z7AZ, oil is changed, and hoses/belts inspected every 500 hours or annually. Thus,
the only control technologies for the diesel emergency generators and fire pumps are the work practice
requirements to adhere to GCP and NOx Tier standard for each engine and the best practice of performing
periodic maintenance. These requirements have been determined to be MCT. These control strategies are
technically feasible and will not cause any adverse energy, environmental, or economic impacts.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-26
3.6 Emergency Natural Gas-Fired Engines
HF Sinclair operates two natural gas-fired spark ignition emergency standby generators, each at 142 kW, at
the Administration building. During combustion, the formation of NO,, is a result of thermal or fuel-bound
reactions. The thermal formation of NO, occurs when nitrogen and oxygen react at high temperatures. NOx
is also generated from the oxidation of nitrogen contained in the fuel. Since natural gas contains low
concentrations of nitrogen, emissions of NO* are primarily due to the thermal formation of NO, in the
combustion chamber.
3.6.1 Step 1 - Identify All Reasonably Available Control Technologies
Four (4) control technologies were identified to rcduce NOx emissions from spark ignition engines which
include:
> good combustion practices.
3,6,7,1 Selective Catalytic Reduction
Selective catalytic reduction is a post-combustion NOx control technology in which an aqueous urea solution
is injected in the exhaust air stream which evaporates into ammonia. The ammonia and NO, react on the
surface of the catalyst forming water and nitrogen. SCR reactions occur in the temperature range of 650oF to
750oF. Precious metalcatalysts are used to reduce NOx.
3.6. 1.2 Non-selective Catalytic Reduction
Non-selective catalytic reduction is a catalytic reactor that simultaneously reduces CO, NO*, and HC emissions.
The catalytic reactor is placed in the exhaust stream of the engine and requires fuel-rich air-to-fuel ratios and
low oxygen levels.
3,6,1.3 Lean Burn Technology
Combustion is considered "lean" when excess air is introduced into the engine along with the fuel. The excess
air reduces the temperature of the combustion process which reduces the amount of NOx produced. In
addition, since there is excess oxygen available, the combustion process is more efficient, and more power is
produced from the same amount of fuel.
3,6,1,4 Good Combustion Practices
Control of combustion temperature is the principa! focus of combustion process control in natural gas-fired
engines. There are combustion controltradeoffs, however. Higher temperatures favor complete consumption
of the fuel and lower residua! hydrocarbons and @ but result in increased NO, formation. Lean combustion
dilutes the fuel mixture and reduces combustion temperatures and therefore reduces NO* formation. This
allows a higher compression ratio or peak firing pressures resulting in higher efficiency. However, if the
mixture is too lean, misfiring, and incomplete combustion may occur.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
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Because the NO, produced is primarily thermal NOx, reducing the combustion temperature will result in less
NOx production. Thus, the main strategy for combustion contro! is to control the combustion temperature.
This is most easily done by adding more air than is required for complete combustion of the fuel. This raises
the heat capacity of the gases in the cylinder so that for a given amount of energy released in the combustion
reaction, the maximum temperature will be reduced,
3.6.2 Step 2 - Eliminate Technically Infeasible Control Technologies
The NSCR technique is effectively limited to engines with normal exhaust oxygen levels of 4 percent or less.
This includes 4-stroke rich-burn naturally aspirated engines and some 4-stroke rich burn turbocharged
engines. Engines operating with NSCR require tight air-to-fue! control to maintain high reduction effectiveness
without high hydrocarbon emissions. To achieve effective NOx reduction performance, the engine may need
to be run with a richer fuel adjustment than normal. This exhaust excess oxygen leve! would probably be
closer to 1 percent. Lean-burn engines could not be retrofitted with NSCR control because of the reduced
exhaust temperatures. Thus, the add-on combustion control of NSCR is deemed technically infeasible. In
addition, the operation of each generator is limited to 100 hours for testing (non-emergency) purposes. Since
it is unlikely that these units will achieve normal operating temperature for any period, the add-on control
using SCR, which requires a consistent operating temperature to be effective, is also technically infeasible.
3.6.3 Step 3 - Rank Remaining Control Technologies Based on Capture and Contro!
Efficiencies
The remaining control technologies, lean burn technology and good combustion practices are both effective
in reducing NOx emissions.
3.6.4 Step 4 - Evaluate Remaining Control Technologies on Economic, Energy, and
Environmental Feasibility
In lean burn engines, the combustion process is enhanced by pre-mixing the air and fuel upstream of the
turbocharger before introduction into the cylinder. This creates a more homogeneous mixture in the
combustion chamber. The microprocessor-based engine will regulate the fuel flow and air/gas mixture and
ignition timing to achieve efficient combustion.
Combustion controls are integral in the combustion process as they are designed to achieve an optimum
balance between thermal efficiency-related emissions (CO and VOC) and temperature related emissions (NOr.
Combustion controls will not create any energy impacts or significant environmental impacts. There are no
economic impact from combustion controls because they are part of the design for modern engines.
EPA describes natural gas generators as Stationary Spark Ignition Internal Combustion Engines (SI ICE).
Depending on the year of manufacture, natural gas generators are regulated by 40 CFR Part 60 Subpaft JJJJ
and 40 CFR Part 63, Subpart 2272. Here, the EPA provides emissions standards that manufacturers must
meet, emissions standards owners/operators must meet, EPA ceftification requirements, testing requirements,
and compliance requirements.
According to Subpart JJJJ, the NOx Emission Standards for stationary emergency engines >25 HP is 2.0 g/HP-
hr or 1 ppmvd @ 15olo Oz. The HF Sinclair natural gas fired emergency generators were manufactured in20t2
and as such, meet the Subpart JJJJ NOx emission standards.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 3-28
3.6.4.7 Energy, Environmental, and Economic fmpacts
There are no energy, environmental or economic impacts associated with the use of lean burn technology
and good combustion practices.
3.6.5 Step 5 - Select RACT
The most stringent controls identified is the use of natural gas, good combustion practices and maintenance
in accordance with manufacturer recommendations with an emission rate of 1 ppmvd @ 15olo Oz or 2.0 glHP-
hr. MCT for NOx emissions from 2012 model year SI ICE generators at HF Sinclair is the application of a lean
burn engine fired on natural gas, good combustion practices, limited operating hours, and operation in
accordance with manufacturer's recommendations. The generators are EPA certified and the manufacturer
lists a NOx emission rate of 2.0 g/HP-hr or 1 ppmvd @ 15olo Oz. The engines comply with the applicable
emission limits of 40 CFR Paft 60 Subpaft JJJJ and 40 CFR Paft 63 Subpaft Z7A-. Maintenance of the engines
will be performed in accordance with manufacturer specifications which includes inspection of the air cleaner.
The proposed controls and maintenance satisff MCT.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
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4. SOURCES OF VOC EMISSIONS SUBJECT TO RACT REVIEW
MCT were evaluated for volatile organic compound (VOC) emissions from ceftain emission units in operation
or proposed at the Woods Cross Refinery. These units include process heaters, boilers, flares, cooling towers,
SRU incinerator, FCCU, fugitive equipment, wastewater treatment, product loading/unloading, fixed, internal
floating and externa! floating roof tanks, and emergency diesel and natural gas-fired engines.
4.L Process Heaters and Boilers
Emissions of VOCs from process heaters and boilers result from incomplete combustion of the heavier
molecular weight components of the refinery gas fuel. Operating conditions such as low temperatures,
insufficient residence time, low oxygen levels due to inadequate mixing, and/or a low air-to-fuel ratio in the
combustion zone also result in VOC formation. In addition, VOC emissions are produced to some degree by
the reforming of hydrocarbon molecules in the combustion zone.
4.L.1 Step 1 - Identify All Reasonably Available Control Technologies
Control options for VOC generally consist of fue! specifications, combustion modification measures, or post-
combustion controls. Six control technologies were identified for controlling VOC emissions. These control
technologies are:
> Catalytic Oxidation
> ThermalOxidation
4,7,7,7 Good Combustion Practice
Combustion controls (proper design and operation) are the most typical means of controlling VOC emissions.
Implementation of proper burner design to achieve good combustion efficiency in heaters and boilers wil! also
minimize the generation of VOC.
Good combustion practice includes operationaland design elements to control the amount and distribution of
excess air in the flue gas. Good combustion efficiency relies on both hardware design and operating
procedures. A firebox design that provides proper residence time, temperature and combustion zone
turbulence, in combination with proper control of air-to-fuel ratio, is essentia! for low VOC emissions.
4,7,7,2 Fuel Specifrcations
Pipeline natural gas is a fuel predominantly comprised of methane. An odorant is added to allow easy leak
detection of the otherwise odorless gas. It is processed to meet ceftain specifications such that key combustion
parameters are relatively consistent throughout the United States. These parameters include percent
methane, heating value, and sulfur content.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
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Refinery fuel gas is a byproduct of the refining operations and is consumed on-site. It may contain significant
proportions of fuel components other than methane, such as hydrogen, ethane, propane, and butanes.
Because it is a byproduct of various refinery processes with varying compositions between streams, expected
VOC emissions for process heaters and boilers firing refinery gas may not be as low as expected for process
heaters and boilers firing natural gas.
4,7,7,3 Ultra-Low NO, Burners
ULNB technology has been developed to provide increasing lower levels of NO, emissions. However, when
operated using good combustion practices, ULNB can also provide significant reductions in VOC emissions.
4.7.7.4 Catalytic Oxidation
The formation of VOC in combustion units depends on the efficiency of combustion. Catalytic oxidation
decreases VOC emissions by allowing the complete oxidation to take place at a faster rate and a lower
temperature than is possible with thermal oxidation. In a typica! 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.
The optimal range for oxidation catalysts is approximately 850 to 1,100 oF,
4.7.7.5 Thermal Oxidation
Thermal oxidizers combine temperature, time, and turbulence to achieve complete combustion. Thermal
oxidizers are equivalent to adding another combustion chamber where more oxygen is supplied to complete
the oxidation of CO and VOC. The waste gas is passed through burners, where the gas is heated above its
ignition temperature. Thermal oxidation requires raising the flue gas temperature to 1,300 to 2,000oF in order
to complete the CO and VOC oxidation.
4,7,7.6 Emerachem (EMx*)
EMx* is the second generation of SCONOx NOx absorber technology. EMx'" is a catalyst-based post-combustion
control, which simultaneously oxidizes CO to CQ, VOC to COz and water, and NO to NOz, subsequently
adsorbing the NOz onto the suface of a catalyst where a chemical reaction removes it from the exhaust
stream.
4.t.2 Step 2 - Eliminate Technically Infeasible Control Technologies
Oxidation catalysts have traditionally been applied to the control of CO and to a lesser extent, VOC emissions
from natural gas fired combustion turbines. Refinery fuel gas contains sulfur as HzS, which when burned
oxidizes to SOz. Oxidation catalyst is not applied to sources where fuels containing sulfur are fired because
much of the SOz formed by the combustion process is further oxidized to SOs which readily becomes sulfuric
acid mist in the atmosphere. In addition, the precious metals which are the active components in oxidation
catalyst are subject to irreversible poisoning when exposed to sulfur compounds.
The only application of oxidation catalyst used by a refinery gas fired combustion device was identified as a
combustion turbine in Southern California which fired a mix of refinery gas and natural gas. No other
applications of oxidation catalyst applied to refinery process heaters was found. Thus, based on the issues
presented above with the use of oxidation catalysts with sulfur bearing fuels, this control option is not
considered technically feasible.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
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EMx" has only been demonstrated on natural gas fired combustion turbines and this technology has not been
demonstrated on units that fire refinery fuel gas. As such, EMx" is not considered to be demonstrated in
practice for refinery fuel gas fired process heaters and is considered technically infeasible.
4.1.3 Step 3 - Rank Remaining ControlTechnologies Based on Capture and Control
Efficiencies
Presented in Table 4-1 are the remaining contro! options ranked based on effectiveness.
Table 4-l VOC Control Technolosies by Contro! Effectiveness
Control Technology Control
ULNB 25-75o/o
GCP baseline
4.1.4 Step 4 - Evaluate Remaining Control Technologies on Economic, Energy, and
Environ mental Feasibility
The top control strategy identified is the use of therma! oxidation which has a VOC control effectiveness
ranging between 75 to 95olo.
The second ranking control strategy identified for the refinery fue! gas-fired process heaters and boilers is the
use of ultra-low NO* burners with a control adherence to good combustion practices.
Good combustion practice includes operationaland design elements to controlthe amount and distribution of
excess air in the flue gas. This ensures that there is enough oxygen present for complete combustion. If
sufficient combustion air supply, temperature, residence time, and mixing are incorporated in the combustion
design and operation, VOC emissions are minimized.
Good combustion practice and proper equipment design is the industry standard for control of VOC emissions
from refinery process heaters. VOC emissions are controlled by maintaining various operational combustion
parameters.
4,7,4,7 Energy, Environmental or Economic fmpact
Depending on specific furnace and thermal oxidizer operationa! parameters (fuel gas heating value, excess
oxygen in the flue gas, flue gas temperature, and oxidizer temperature) raising the flue gas temperature can
require an additional heat input of 10 to 25olo above the process heater heat input. In addition, depending on
the design of the thermal oxidizer, emissions of NO,, SOz and PMz.s GrD be 10 to 25olo higher than emissions
without a thermal oxidizer. Installation costs and operating costs for a therma! oxidizer (mostly from the 10
to 25o/o increase in fuel consumption) can be significant. Thus, since this technology was not determined to
meet MCT and causes adverse environmental impacts, the use of this technology has been determined to be
technically infeasible for VOC control on process heaters and has been eliminated from further consideration.
The cost to fire all process heaters on natural gas is $46.7 million which is cost prohibitive.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-3
The cost to upgrade burners from LNB to ULNB was examined. On average, the price for an ULNB is
approximately $36,050 per burner. Testing and installation costs are approximately twice the cost of the actual
burner for a total of cost of $105,000 per burner. Each process heater has multiple burners. The average cost
of control per ton of VOC removed to upgrade all above existing units where technically feasible with ULNB is
over $34.9 million dollars. Thus, it is not economically feasible to reconstruct all existing process heaters.
As mentioned previously, the application of LNB or ULNB on existing units (6H1, 6H2, 6H3, 7Ht,7H3,g{t,
9H2, 10H1, 11H1, and 13H1) is not technically possible due to space limitations in the firebox, lower heat
duty, and a longer flame. It is not economically feasible to reconstruct all existing process heaters. Thus, for
these reasons, retrofitting of existing process heaters with LNB or ULNB has been determined to be
economically and technically not feasible.
The use of good combustion practices will not cause adverse energy, environmental, or economic impacts.
4.1.5 Step 5 - Select RACT
HF Sinclair will follow good combustion practices which has been selected as RACT for contro! of VOC
emissions from the process heaters and boilers. Boiler #11 has an emission limit of Q.004 lb/MMBtu; process
heaters 20H3, 24Ht, and 25H1 have a VOC emissions limit of 0.0054 lb/MMBtu each. No more stringent
measures were identified to control VOC emissions from process heaters and boilers other than the use of
good combustion practices.
The cost of installing and operating CEMS on each heater and boiler was examined. The estimated equipment
cost including a shelter and a VOC CEMS with affiliated equipment plus installation is approximately $254,016
per system. Totalannualcosts were estimated to be approximately $90,453. Based on20L7 actualemissions
from the process heaters, the average cost-per-ton to monitor for VOCs with a CEMS is $720,057. See
Appendix B for a detailed cost analysis.
4.2 Flares
As mentioned previously, there are two flare stacks located at the Northwest corner of the refinery. During
refinery operating upsets, process equipment may experience over-pressures which are relieved through a
spring-loaded pressure safety valve ('PSV). Piping headers connect these devices to the flare stac( which is
used to safely burn the released hydrocarbons. A small, continuous flame of pipeline-quality natural gas
purchased from Dominion Energy acts as a pilot llght to ignite the process vapors as they enter the flare tip
for final destruction. Emissions from flaring may include unburned VOC'S and paftially burned and altered
hydrocarbons.
4.2.L Step 1 - Identify Al! Reasonably Available Control Technologies
For safe flare operation, the design of the flares requires the use of a pilot light. The combustion of natural
gas to fuel the pilot light and the combustion of refinery gases produce VOC.
A search of the RBLC, state databases, and emiss'rrn control literature was conducted to find available control
technologies to control flare emissions. Flares operate primarily as air pollution control devices. The only
technically feasible contro! options for emissions of all pollutants from flares are:
> good combustion practices,
> conversion from air assisted to steam assisted and
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-4
> flare gas recovery systems.
No add-on controls for VOC emissions from flares were identified.
4,2.7,7 Proper Eguipment Design and Work Practices
Proper equipment design and work practices include minimizing the quantity of gases combusted, minimizing
exit velocity, ensuring adequate heat value of combusted gases, and installing an automatic pilot reignition.
The flares at the Woods Cross Refinery are designed and operated in accordance with 40 CFR 60.18, general
controldevice requirements which always include a flame present at all times, no visible emissions, and heat
content and maximum tip velocity specifications that meet the requirements of the rule. The use of pipeline-
quality natural gas to fuel the pilot lights will reduce VOC emissions.
4.2.1,2 Good Combustion Practices
A ceftain leve! of flame temperature control can be exercised for a flare by utilizing steam which improves
mixing. Good combustion practices can be used to minimize emissions of VOC.
4.2.1.3 Conversion from Air Assisted to Steam Assisted
Flares produce lower flame temperatures when operating with low heating value gases at low combustion
efficiencies than when operating with high heating value gases at high combustion efficiencies. This leads to
reduced formation of VOC in the flame. In general, emissions are lower in steam assisted flare tests than in
air assisted flare tests conducted under similar conditions.
4,2,7.4 Flare Gas Recovery Systems
Flaring can be reduced by installation of a flare gas recovery system. A flare gas recovery system includes a
seal system to allow for recovery of process gases vented to the flare. Compressors recover the vapors and
vapors are sent to the fuel gas treatment system for HzS removal. After conditioning of the recovered vapors,
the gases are combined with other plant fue! gas sources and combusted in heaters, boilers, and other devices
that operate using fuel gas.
If the pressure in the flare gas headers exceeds the seal system settings, excess flare gases are allowed to
flow to the flare for combustion. The pressure in the flare gas system increases due to additiona! process gas
flow that cannot be recovered by the flare gas compressors. Once the pressure drops and the excess gases
are combusted, the seal system re-establishes itself for continuous re@very of vapors.
The flare gas recovery system will not be sufficient to prevent flaring from process unit startup and shutdown
events where large volumes of process gases will be sent to the flare. Also, during process upsets or
malfunctions, the flare gases may not be entirely recovered due to the constraints of the flare gas recovery
system. The flare gas recovery system will be sized for normal operating conditions.
4.2.2 Step 2 - Eliminate Technically Infeasible Contro! Technologies
None of the identified contro! options is considered technically infeasible for the flares at the Woods Cross
Refinery.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
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4.2.3 Step 3 - Rank Remaining ControlTechnologies Based on Capture and Control
Efficiencies
The top-ranking contro! option is the installation of a flare gas recovery system. Flare gas recovery systems
are achieved in practice. The second highest ranking contro! option includes proper equipment design and
work practices which includes good combustion practices. The combustion efficiency is the percentage of
hydrocarbon in the flare vent gas that is completely converted to COz and water vapor. Destruction efficiency
is the percentage of a specific pollutant in the flare vent gas that is converted to a different compound. The
destruction efficiency of a properly operated flare is 98o/o.
4.2.4 Step 4 - Evaluate Remaining Control Technologies on Economic, Energy, and
Environ mental Feasibility
HF Sinclair has installed a flare gas recovery system to recover vent gas which is the highest ranked control
option.
Proper equipment design and work practices include minimizing exit velocity and the quantity of gases
combusted and ensuring adequate heat value of combusted gases. Because the flares are located at a
petroleum refinery, the flare must comply with the requirements and limitations presented in 40 CFR Paft 60
Subpart Ja and the design and work practice requirements of 40 CFR 60.18.
Emissions from the HF Sinclair Woods Cross Refinery flares under normal operation will consist only of the
emissions from the combustion of natural gas in the flare pilot flames and a sma!! amount of purge gas that
is circulated through the flare system for safety reasons (i.e., to prevent air from entering the flare lines).
Proper equipment design and work practices include minimizing exit velocity and the quantity of gases
combusted and ensuring adequate heat value of combusted gases. Because the flares are located at a
petroleum refinery, the flare must comply with the requirements and limitations presented in 40 CFR Part 60
Subpart Ja and the design and work practice requirements of 40 CFR 60.18.
Flare management plans have been developed for both the north and south flares. These plans contain
procedures to minimize or eliminate discharges to the flare during staftups and shutdowns. To verify that the
procedures are followed, records are maintained.
The flares at the refinery are steam-assisted and have a destruction efficiency of 98o/o or greater.
4,2,4.7 Energy, Environmental, or Economic Impacts
Since HF Sinclair has chosen the highest ranked ontrol option, flare gas recovery, energy, environmental,
and economic costs analyses are not required to be addressed.
4.2.5 Step 5 - Select RACT
HF Sinclair is proposing the following design elements and work practices as RACT for the flares:
accordance with manufacturer specifications,
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
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> Implementation of Flare Management Plans,
in 40 CFR Part 60.18, and,
No other measures were identified to mntrolVOC emission from the flares at the Woods Cross Refinery. The
flare design includes steam-assisted combustion. The flares will be equipped with a flare gas recovery system
for non-emergency releases, and a continuous pilot light. Pilot and sweep fuel will be natura! gas or treated
refinery gas. The proposed controls satisfy MCT.
4.3 Cooling Towers
VOC emissions are due to the evaporation of VOC's that may be present in the cooling water due to equipment
or heat exchanger leaks. Small amounts of hydrocarbons may be present in the cooling water.
4.3.1 Step 1 - Identify Atl Reasonably Available Control Technologies
Only one control technology was identified for controlling VOC emissions from cooling towers which is the
implementation of a heat exchanger leak detection and repair (LDAR) program.
4.3.2 Step 2 - Eliminate Technically Infeasible Control Technologies
The implementation of a heat exchanger leak detection and repair program was determined to be technically
feasible.
4.3.3 Step 3 - Rank Remaining ControlTechnologies Based on Capture and Control
Efficiencies
The only identified, technically feasible control option is to implement a heat exchanger leak detection and
repair program for the cooling towers. In using this option, no significant energy, environmental, or economic
impacts are expected. This program involves monitoring cooling water for the presence of hydrocarbons and
finding and repairing leaks when hydrocarbons are found.
4.3.4 Step 4 - Evaluate Remaining ControlTechnologies on Economic, Energy, and
Environ mental Feasibility
Therefore, to satisfy MCT, HF Sinclair conducts monthly monitoring to identify leaK of strippable VOC from
heat exchange systems. A leak is a total strippable VOC concentration in the stripping gas of 3.1 ppmv or
greater for sources constructed after September 4, 2007 or 6.2 ppmv or greater for sources constructed
before September 4,2007. Monthly water samples are collected and analyzed from each cooling tower return
line to determine the total strippable VOC concentration using the Texas El Paso method as required by 40
CFR Subpaft CC. Monthly records kept including date of inspection, cooling tower/heat exchanger inspected,
total strippable VOC concentration, repairs, and follow up testing.
4.3.4.1 Energy, Environmental, or Economic fmpacts
Since HF Sinclair has chosen the highest ranked control option, LDAR; energy, environmental and cost
analyses are not required.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
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4.3.5 Step 5 - Select RACT
No more stringent measures than LDAR were determined to control VOC emissions from the cooling towers.
RACT is based on the implementation of a heat exchanger LDAR program and compliance with 40 CFR Part
63, Subpart CC. Monthly testing is conducted to determine total strippable VOC concentrations.
4.4 Sulfur Reduction Unit Incinerator
VOCs from the SRU incinerator result from incomflete fuel combustion of carbon and organic compounds in
the fuel gas.
4.4.1 Step 1 - Identify All Reasonably Available Control Technologies
Since the tail gas incinerator is a combustion device, the only VOC emission control techniques identified were
good combustion practices, engineering design, and use of clean burning fuels.
4.4.2 Step 2 - Eliminate Technically Infeasible Control Technologies
Good combustion practices, engineering design, and the use of clean burning fuels are all technically feasible.
4.4.3 Step 3 - Rank Remaining Contro! Technologies Based on Capture and Control
Efficiencies
The only technically feasible control options for VOC from the SRU tail gas incinerator are good combustion
practices and engineering design, and the use of clean-burning fuel.
4.4.4 Step 4 - Evaluate Remaining Control Technologies on Economic, Energy, and
Environ mental Feasi bility
Emissions from the SRU are sent to the tail gas incinerator followed by a wet gas scrubber.
4,4,4,7 Energy, Environmental, or Economic Impacts
Wet scrubbers generate waste in the form of a slurry. Typically, the slurry is treated to separate the solid
waste from the water. Once the water is removed, the remaining waste will be in the form of a solid which
can generally be landfilled. There is no other anticipated energy, environmental, or economic impacts
associated with the use of a wet scrubber to remove VOC from the effluent stream from the SRU during
normal operations.
Although natural gas is considered a clean fuel, natural gas combustion in the tail gas incinerator will result
in increased VOC combustion emissions. Economic impacts occur due to the cost to use natura! gas to fire the
tail gas incinerator. There are no other anticipated impacts associated with the use of the tail gas incinerator.
4.4.5 Step 5 - Select RACT
Emissions from the SRU tail gas incinerator are sent to one of the wet gas scrubbers. VOC MCT for the SRU
tail gas incinerator and wet gas scrubber is good combustion practices, engineering design, and use of clean
burning fuels utilizing natural gas. No other measures were identified to control VOC emissions from SRU tail
gas incinerators. Combustion is monitored using an process 02 analyzer.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
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4.5 FCCU
Fluidized catalytic cracking units are complex processing units at refineries that conveft heavy components of
crude oil into light, high-octane products that are required in the production of gasoline.
The FCCU consists of two vessels. In the reactor vesse!, the conversion reaction occurs in the presence of a
fine, powdered catalyst and steam, during which the catalyst becomes coated with petroleum coke. In the
regenerator vessel, this coke is removed from the suface of the spent catalyst by burning it off in the presence
of air so that the catalyst can be reused. The cracked products from the reactor vesse! are separated in a
fractionator column into intermediate streams for fufther processing. The catalyst regenerator exhaust
contains VOCs.
4.5.1 Step 1- Identify All Reasonably Available Control Technologies
Three available control technologies to controlVOC emissions from a full burn FCCU regenerator include:
4,5,1,1 Good Combustion Practices
Full burn regenerators operate with excess oxygen in the flue gas. The minimum excess oxygen required to
promote VOC oxidation is a function of bed temperature, gas residence time in the bed, and how efficiently
the regenerator design utilizes the available oxygen. Assuming that the full burn unit is properly designed,
and as long as sufficient oxygen is present, the oxidation of CO to COz should be complete, resulting in both
reduced CO and VOC concentrations. Thus, good combustion design and operation will effectively control VOC
emissions present in the FCCU regenerator exhaust gas.
4.5.7.2 Combustion Promoters
CO combustion promoters are an additive to the coke combustion process in the regenerator that hampers
the formation of NOx while enhancing the combustion of coke on the catalyst. The CO combustion promoters
are readily fluidized, mixing with the catalyst. They are added to the circulating fluid bed (CFB) regenerator
unit to improve the efficiency of VOC burning, reduce emissions of VOC and improve the efficiency of the unit.
The CO combustion promoter accumulates in, or just above, in the fast fluidized bed combustion zone of the
regenerator. There are several CO promoters that are available for use including Engelhard Corporations
OxyClean'", Intercat, and Grace Davison's XNOx all of which are effective in reducing VOC emissions while
controlling NOx emissions.
4.5.7.3 Catalytic Oxidation
Catalytic oxidation decreases VOC emissions by allowing the complete oxidation to take place at a faster rate
and a lower temperature. The oxidation reaction typically requires a temperature of 650 to 1000oF to achieve
optimal oxidation efficiencies. Catalytic oxidation cannot be used in waste streams with large amounts of
particulate matter since the particulate deposits foul the catalyst and inhibit the contro! efficiency.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-9
4.5.2 Step 2 - Eliminate Technically Infeasible Control Technologies
A review of the RBLC, state databases, and air perrnits did not identify the use of catalytic oxidizers to control
VOC emissions from an FCCU regenerator. The use of a catalytic oxidation system is not technically feasible
due to the relatively low temperatures of the FCCU exhaust stream. The process of reheating the flue gas
would result in the formation of additional combustion products including VOC. Thus, the use of this
technology to control VOC emissions from FCCU exhaust gas has been determined to be technically infeasible.
4.5,3 Step 3 - Rank Remaining ControlTechnologies Based on Capture and Control
Efficiencies
The remaining technologies include the use of good combustion practices and combustion promoters.
4.5.4 Step 4 - Evaluate Remaining Control Technologies on Economic, Energy, and
Environ mental Feasibility
The FCCU regenerators at HF Sinclair utilize full burn combustion technology which minimizes VOC emissions
to the fullest extent possible. The regenerative vent is continuously monitored through use of a CEMS to
ensure the CO (hence VOC) emissions are controlled to the maximum extent possible. The use of good
combustion practices to reduce VOC emissions from FCCU's has been achieved in practice and is used
throughout the industry.
4,5.4.7 Energy, Environmental, and Economic fmpacts
There are no anticipated environmental, energy, or economic impacts associated with use of good combustion
practices and a combustion promoter.
4.5.5 Step 5- Select RACT
The use of full burn technology for the FCCU regenerator, 9@d combustion practices, and a combustion
promoter are used by HF Sinclair to minimize VOC emissions from the FCCUS. Thus, the use of these
technologies is considered RACT for VOC. CO emissions are continuously monitored and are limited to 5500
ppmv based on a one-hour average at0o/o Oz. By ensuring CO emissions are within these limits, VOC emissions
will also be controlled.
4.6 Fixed Roof Storage Tanks
Fixed roof storage tanks are used at the HF Sinclair Woods Cross Refinery to store heavy distillates with low
vapor pressures. Emissions from fixed roof storage tanks are in the form of working and standing losses
Standing losses occur when the temperature fluctuates; working losses occur primarily then the liquid level
changes. The emissions from the fixed roof storage tanks include VOCs. The fixed roof tanks operated at the
Woods Cross Refinery that reported emissions in 20L7 are presented in Table 4-2.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
TriniW Consultants December 2023 4-10
Table 4-2Fixed Roof Tanks at HF Sinclair Woods Cross Refinery
Tank Tank Size Product Stored and Vapor Comment
Description (bbl) Pressure of
Tank 14
Tank 15
Tank 19
Tank 20
Tank 23
Tank 24
Tank 28
Tank 31
Tank 35
Tank 37
Tank 47
Tank 48
Tank 52
Tank 53
Tank 54
Tank 55
Tank 56
Tank 57
Tank 58
Tank 63
Tank 70
Tank77
Tank 78
Tank 79
Tank 86
Tank 99
Tank 103
Tank 127
Task 139
2,539
5,181
7,463
7,504
14,600
15,016
29,663
29,756
105,000
3,2L7
30,129
29,782
1,008
1,008
1,008
1,008
1,008
1,008
15,229
30,135
80,306
5,L4t
5,741
10,000
109,660
66,000
24,686
30,497
74,957
Kerosene (0.008 psia)
Fueloil(0.002 psia)
Ultra-Low Sulfur Stove Oil (0.008
psia)
Ulba-Low Sulfur
psia)
Ultra-Low Sulfur
psia)
Ultra-Low Sulfur
psia)
Ultra-Low Sulfur
psia)
Fuel Oil (0.002 psia)
Gas Oil (0.002 psia)
Gas Oil (0.002 psia)
Ultra-Low Sulfur Diesel (0.006
psia)
Ught Cycle Oil (1.13 psia)
Gas Oil (0.002 psia)
Gas Oil (0.002 psia)
Gas Oil (0.002 psia)
Gas Oil (0.002 psia)
Gas Oil (0.002 psia)
Gas Oil (0.002 psia)
Fuel Oil (0.002 psia)
Ultra-Low Sulfur Stove Oil (0.008
psia)
Gas Oil (0,002 psia)
Biodiesel (0.04 psia)
Biodiesel (0.04 psia)
Fuel Oil (0.002 psia)
Gas Oil (0.002 psia)
Ultra-Low Sulfur Diesel (0.006
psia)
Gas Oil (0.002 psia)
Ultra-Low Sulfur Diesel (0.006
psia)
SDA Charge (0.002 psia)
Tank installed prior to 1973
Tank installed prior to 1973
Tank installed prior to 1973
Tank installed prior to 1973
Vapor pressure <0.5 psi
Tank installed prior to 1973
Tank installed prior to 1973
Vapor pressure <0.5 psi
Vapor pressure <0.5 psi
Vapor pressure <0.5 psi
Tank installed prior to 1973
Tank installed prior to 1973
Tank installed prior to 1973
Tank installed prior to 1973
Tank installed prior to 1973
Tank installed prior to 1973
Tank installed prior to 1973
Tank installed prior to 1973
Tank installed prior to 1973
Tank installed prior to 1973
Tank installed prior to 1973
Vapor pressure <0.5 psi
Vapor pressure <0.5 psi
Vapor pressure <0.5 psi
Vapor pressure <0.5 psi
Vapor pressure <0.5 psi
Vapor pressure <0.5 psi
Tank installed prior to 1973
Tank installed prior to 1973
Stove Oil (0.008
Diesel (0.006
Diesel (0.006
Diesel (0.006
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-tt
4.6.t Step 1 - Identify All Reasonably Available Control Technologies
Available control technologies for fixed roofs tanks include:
> Thermal oxidation system,
4,6,7.7 Vapor Recovery Systems
The function of a vapor recovery system is to collect VOC emissions from storage tanks that can be routed to
a fuel gas system for combustion as fuel. Vapor recovery can be achieved through carbon adsorption,
condensation, or absorption.
Carbon adsorption is a common emission control technique in which VOC vapors become physically bound to
activated carbon, effectively removing them from the air stream. In multi carbon bed systems, once the first
carbon bed becomes saturated with VOCs that bed is taken off-line and regenerated, and the next bed will
adsorb the VOCs.
Condensation is performed by chilling or pressurizing VOC vapors to return them to a liquid state. This process
is most effective with VOCs whose boiling points are above 40oC (104oF) and whose vapor concentrations are
greater than 5000 ppm.
In absorption systems, the contaminated air stream is contacted with a liquid solvent in an absorption tower,
where VOCs are absorbed by the solvent. The absorber tower is designed to provide the necessary liquid-
vapor contact area to facilitate mass transfers. Packed bed towers and mist scrubbing systems are two types
of absorber towers that can remove 95olo to 98o/o of the incoming VOCs from the waste gas stream.
4.6.7.2 Thermal Oxidation System
A thermal oxidation system or thermal incinerator are combustion devices that control emissions by
combusting VOCs to carbon dioxide and water.
4.6.7.g Retrofit Tank with fnternal Ftoating Roof
Installation of an internal floating roof with seals inside a fixed roof tank will result in emission reductions in
standing evaporative losses.
4.6.7.4 Vapor Balancing
Vapor balancing is a method of collecting the vapors that are displaced when a tank is filled and is most
commonly used for filling tanks at gasoline stations. As the storage tank is filled, the expelled vapors are
collected in a tanker truck and then are transported to a vapor recovery system or combustion device.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-12
4.6,7,5 Application of Tank Standards
New Source Performance Standards (NSPS) for petroleum liquid storage vessels are covered by three separate
subpafts of 40 CFR Part 60. Subpaft K pertains to storage vessels constructed or modified after June ll, L973
but before May 19, 1978. Subpart Ka peftains to storage vessels constructed or modified after May 19, L978
but before July 23, 1984. Subpaft Kb peftains to storage vessels constructed or modified after July 23, L984.
Subpart K applies to petroleum liquid storage vessels with storage capacities greater than 40,000 gallons, as
well as storage vessels with capacities between 40,000 and 65,000 gallons that were constructed or modified
after March 8, L974, and before May 19, 1978. Storage vessels for petroleum or condensate stored, processed,
and/or treated at a drilling and production facility prior to custody transfer are exempt from this subpaft,
Subpaft K requires storage vessels that store petroleum liquids with true vapor pressures between 1.5 and
11.1 psia to be equipped with a floating roof and a vapor recovery system, or other equivalent equipment.
For petroleum liquids with a true vapor pressure greater than 11.1 psia, a vapor recovery system or equivalent
equipment is required.
Subpart Ka applies to petroleum liquid storage vessels with storage capacities greater than 40,000 gallons,
however storage vessels with storage capacities less than 420,000 gallons used for petroleum or condensate
stored, processed or treated prior to custody transfer are exempt. Storage vessels containing petroleum liquids
with true vapor pressures between 1.5 and 11.1 psia should be equipped with either an external floating roof,
a fixed roof with an internal floating type cover, a vapor recovery system that collects all VOC vapors and
discharged gases, or an equivalent system. Storage vessels containing petroleum liquids with true vapor
pressures greater than 11.1 should be equipped with a vapor recovery system to collect all discharged gases
and a vapor return or disposal system to reduce VOC emissions by at least 95olo by weight.
Subpaft Kb applies to volatile organic liquid (VOL) storage vessels, which includes petroleum liquid storage
vessels, with capacities greater than or equal to 75 m3. However, this subpaft excludes storage vessels with
capacities greater than 151 m3 storing a liquid with a maximum true vapor pressure less than 3.5 kPa or
vessels with capacities between 75 and 151 m3 storing a liquid with a maximum true vapor pressure less than
15.0 kPa. For storage vessels greater than 151 m3 in size containing a VOL with a maximum true vapor
pressure between 5.2 and 76.6 kPa and vessels sized between 75 and 151 m3 storing a VOL with a maximum
true vapor pressure between 27.6 and 76.6 kPa should be equipped with either a fixed roof with an internal
floating roof, an external floating roof, a closed vent system and control device, or an equivalent system.
Storage vessels with capacities greater than 75 m3 containing a VOL with a maximum true vapor pressure
greater than or equal to 766 kPa should be equipped with a closed vent system and contro! device or
equivalent system.
40 CFR 63 Subpaft WW applies to the control of air emissions from storage vessels for which another subpart
references the use of Subpaft \A/W for air emission control, EPA promulgated 40 CFR Part 63 Subpart WW as
paft of the generic MACT standards program. Subpart \trW was developed for the purpose of providing
consistent EFR and IFR requirements for storage vessels that could be referenced by multiple NESHAP
subpafts. Like the NSPS Subpart Kb standards for floating roof tanks, Subpart WW is comprised of a
combination of design, equipment, work practice, and operational standards. Both rules speciff monitoring,
recordkeeping, and repofting for storage vessels equipped with EFR and IFR and both include requirements
for inspections to occur within defined timeframes. The inspections required by Subpart WW are intended to
achieve the same goals as those inspections required by Subpaft Kb. Subpart WW allows for the visua!
inspection of the floating roof deck, deck fittings, and rim seals while the tank remains in seruice if physical
access is possible. Subpaft WW does not require the tank to be taken out of seruice to inspect the floating
roof, rim seals and deck fittings which is in contract to Kb requirements.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-t3
Utah Administrative Code R307-327 presents the requirements of petroleum liquid storage in ozone
nonattainment and maintenance areas. R307-3274 states (1) Any existing stationary storage tank, with a
capacity greater than 40,000 gallons (150,000 liters) that is used to store volatile petroleum liquids with a
true vapor pressure greater than 10.5 kilo pascals (kPa) (1.52 psia) at storage temperature shall be fitted with
control equipment that will minimize vapor loss to the atmosphere. Storage tanks, except for tanks erected
before January L, L979, which are equipped with external floating roofs, shall be fitted with an internal floating
roof that shall rest on the surface of the liquid contents and shall be equipped with a closure seal or seals to
close the space between the roof edge and the tank wall, or alternative equivalent controls. The owner/
operator shall maintain a record of the type and maximum true vapor pressure of stored liquid. (2) The
owner/operator of a petroleum liquid storage tank not subject to (1) above but containing a petroleum liquid
with a true vapor pressure greater than 7.0 kPa (1.0 psia), shall maintain records of the average monthly
storage temperature, the type of liquid, throughput quantities, and the maximum true vapor pressure.
4.6.2 Step 2 - Eliminate Technically Infeasible Control Technologies
The control option involving internal floating roof tank designs is not technically feasible for the asphalt/fuel
oil tanks (Tanks 58 and 79) due to the nature of the material being stored and due to the storage temperature
of the material.
4.6.3 Step 3 - Rank Remaining ControlTechnologies Based on Capture and Control
Efficiencies
The Mid-Atlantic Regional Air Management Association (MAMMA) report, The Assessment of Control
Technology Options for Petroleum Refineries in the Mid-Atlantic Region Final Repoft January 2007 summarizes
tank control technologies for reducing VOC emissions as follows:
Control
Vapor Recovery System 90 - 98o/o
Thermal Oxidizer i 95 - 99olo
Retrofit with IFR 60 - 99olo
Vapor Balancing I
Tank
80o/o
Varies
4.6.4 Step 4 - Evaluate Remaining Control Technologies on Economic, Energy, and
Envi ron menta I Feasi bility
Under NSPS regulations, control equipment is generally required when storing volatile organic liquids with
vapor pressures of 1.5 psia or greater. Tanks storing volatile organic liquids below the vapor pressure threshold
are required to keep records of types of products stored and their vapor pressures, periods of storage and
tank design specifications. The fixed roof tanks at HF Sinclair listed in Table 4-2 store volatile organic liquids
of less than 1.5 psia.
Tanks over 40,000 gallons and built, modified, or reconstructed between May 18, 1978 and July 23, 1984 are
required to operate in accordance with 40 CFR Part 60 Subpaft Ka. Tanks constructed after July 23, L984 are
required to operate in accordance with 40 CFR Part 60 Subpart Kb and are exempt from refinery MACT
requirements (63.640(n)).
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-t4
Tanks constructed before August 18, 1994 and storing volatile organic liquids containing HAPS are required
to meet the applicable Refinery MACT requirements of NESHAP 40 CFR 63 Subpart CC which refers to the
contro! standards of 40 CFR Part 63 Subpart G. For Group 1 storage vessels storing liquids for which the
maximum true vapor pressure of the total organic hazardous air pollutants in the liquid is less than 76.6
kilopascals, the use of fixed roof and interna! floating roof, an external floating roof, an external floating roof
convefted to an internal floating roof, a closed vent system and mntrol device, routing the emissions to a
process or a fue! gas system, or vapor balancing is required. No fixed roof tanK listed in Table 4-2 fall into
this category.
Compliance options for VOC emission controls on tanks includes using a fixed roof with an internal floating
roof, an external floating roof meeting certain design specification, and using a closed-vent system and control
device that meet the requirements of 40 CFR Part 60 Subpart Kb. For the tank listed in Table 4-2, the
applicable NSPS and/or NESHAP rules do not require any control of VOC emissions due to the low vapor
pressure (<0.5 psia) of these tank contents. Thus, fixed roof tank are appropriate for storage of these low
vapor pressure products.
In addition, Utah Administrative Code R307-327 presents the requirements of petroleum liquid storage in
ozone nonattainment and maintenance areas. R307-327-4 states (1) Any existing stationary storage tank,
with a capacity greater than 40,000 gallons (150,000 liters) that is used to store volatile petroleum liquids
with a true vapor pressure greater than 10.5 kilo pascals (kPa) (1.52 psia) at storage temperature shall be
fitted with control equipment that will minimize vapor loss to the atmosphere. Storage tanks, except for tank
erected before January I, L979, which are equipped with external floating roofs, shall be fitted with an internal
floating roof that shall rest on the sufface of the liquid contents and shall be equipped with a closure seal or
seals to close the space between the roof edge and the tank wal!, or alternative equivalent controls.
The owner/ operator shall maintain a record of the type and maximum true vapor pressure of stored liquid.
(2) The owner/operator of a petroleum liquid storage tank not subject to (1) above but containing a petroleum
liquid with a true vapor pressure greater than 7.0 kPa (1.0 psia), shall maintain records of the average monthly
storage temperature, the type of liquid, throughput quantities, and the maximum true vapor pressure. The
HF Sinclair Tanks listed in Table 4-2 meet the requirement of (2). Thus, records of the average monthly
storage temperature, the type of liquid, throughput quantities, and the maximum true vapor pressure are
maintained.
4,6.4.1 Energy, Environmental, and Economic fmpacts
The most effective control option of recovering vapors and routing them to a process or a fuel gas system via
hard piping such that the tank operated with no emissions would result in adverse energy and environmental
impacts due to the significant electrica! power demand of the required compression system. An economic
analysis was performed for gathering vapors discharged from cone-roof tanks and processing these vapors
for the recovery of condensable hydrocarbons by means of absorption which is the top-ranking control over
condensation, mechanical refrigeration, and adsorption using carbon beds for recovery of hydrocarbon vapors
from storage tanks. This requires extensive processing equipment, the most common method involving
compression, cooling, absorption, heating, stripping, and final condensation by cooling. This equipment must
be designed to operate under conditions of varying compositions of the vapors and fluctuating vapor flow
rates from the tank. The recovered liquid can be used as feed stock for fufther processing or stored in tanks.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-t5
For the vapor recovery process, vapors from each tank are gathered, pass through a pressure-control valve
into the main gathering header and are drawn into the suction of a compressor. After compression, the vapors
are discharged into the absorption chamber where they are absorbed in circulating lean oil. The lean oil,
enriched with these vapors pass from the bottom of the absorber and the recovered hydrocarbons from the
top of the stripper are cooled and condensed.
The highest control option is use of a closed vent system routed to a thermal oxidizer. The $/ton of VOC
reduced from the addition of a vapor recovely system such as an incinerator was estimated to be
approximately $4.598 million (see Appendix B). The 2017 emissions from the fixed roof tank were 0.49 tons.
With the use of this option, additional utilities are needed as well as extra labor costs to operate the system.
The $/ton of VOC reduced from the addition of a vapor control system such as carbon absorption was
estimated to be approximately $672,857 (see Appendix B). The 2017 emissions from the fixed roof tanks were
0.49 tons. With the use of this option, additional steam, electricity, and cooling water as utilities are needed,
as wel! as extra labor costs to operate the system.
The installation of a thermal oxidizer or carbon absorber would result in adverse energy and environmental
impacts due to the auxiliary fuels needs for the required thermal oxidizer and the additional combustion
emissions (NOz and VOC) that result from a thermal oxidizer. If activated carbon were used, solid waste could
also be generated.
The use of internal floating roof and dual rim seals does not result in any adverse energy or environmental
impacts. Because of the low volatility of the products being stored in fixed roof tanK, the installation of
internal floating roofs and seals is not warranted. The capitol cost to install an internal floating roof to a fixed
roof tank was estimated to be approximately $601,952 per tank. (See Appendix B). In 20L7, there were 33
fixed roof tanks that reported VOC emissions in SLEIS.
Closed vent systems with a control device have been eliminated from fufther consideration. In addition, since
the emissions from the proposed fixed roof tanks are not significant, i.e., 0.49 tons for 20t7, a floating roof
is not proposed for the lower vapor pressure product tank.
Vapor balancing can be accomplished through a network of vapor lines interconnecting the vapor spaces of
all tanks. Under the most favorable conditions of perfectly balanced pumping, where the input rate and the
output rate were equal, it is not possible to eliminate all filling losses. However, control of losses caused by
unbalanced pumping and breathing requires variable-space vapor storage with a capacity equal to the volume
of the maximum breathing plus unbalanced pumping. The primary operating consideration is the potentially
adverse effect of the interchange of vapors between tanks storing different products.
In the case where the pump-out rate is equal to the input rate, a simple interconnection pipe system would
only recover the filling losses estimates to be approximately 30o/o of the tota! loss. The addition of a vapor
tank prevents all vapor losses but adds an additional cost to the system. Other items to consider include the
size of the vapor recovery tank and if there is adequate space for the installation of this tank.
The estimated capital costs to install a vapor-balancing system with a network of interconnecting vapor lines
and a vapor tank are estimated to be approximate[ $a.70 million for 32 tanks. Annual operating costs are
estimated to be approximately $564,019. The $/ton of VOC reduced from a vapor balancing system was
estimated to be $1,438,824. Thus, the installation of a vapor balancing system to control less than 0.49 tons
of VOC emissions (20L7 actual) from 32 fixed roof tanks is not economically feasible.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-16
4.6.5 Step 5 - Select RACT
Based on the analyses presented above, the top options, vapor recovery from fixed roof tanks, installation of
a thermal oxidizer or utilization of carbon adsorption, vapor control systems for higher VOC product tank,
closed vent system and control device for fixed roof tank, and vapor balancing has been determined to be
not economically feasible.
The proposed RACT for refinery tank is compliance with the equipment design and work practices
requirements as set forth 40 CFR 60, Subpart Kb, in 40 CFR 63, Subpaft \A/W, and R307-327. The tank valves
are included in the LDAR program.
4.7 Internal Floating Roof Storage Tanks
Internal floating roof (IFR) tanks have two roofs, a permanent fixed roof above a floating roof. The fixed roof
poftion of the internal floating roof tank can be supported either by vertical columns within the tank or by a
self-supporting system without i nternal support colu mns.
The internal floating roof rises and falls with the stored liquid level and either rests directly on the liquid
suface (known as a contact deck) or rests on pontoons a few inches above the liquid surface (known as a
noncontact deck). The majority of vapor losses from IFR tanks comes from deck fittings, non-welded deck
seems, and the space between the deck and tank walls. All internal floating roof tank at HF Sinclair meet the
requirements of 40 CFR Paft 63 Subpaft CC; tank 323 meets the double standard of 40 CFR Part 63 Subpaft
CC and 40 CFR Part 60, Subpart Kb.
The IFR roof tank operated at the Woods Cross Refinery that reported emissions in 2017 are presented in
Table 4-3.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-17
Table 4-3 Internal Floating Roof Tanks at HF Sinclair Woods Cross Refinery
Tank Tank Size Product Stored and Vapor
Pressure of Product
Tank 12
Tank 71
Tank72
Tank 106
Tank 131
Tank 138
Tank 323
9,868
67,L55
106,811
24,524
65,159
44,247
1 Ethanol (0.87
Reformer Charge (1.24 psia)
Crude Oil He4vy (1.9 psia)
t
t
Gasoline (5.2 psia)
Gasoline, reSftar (5.2 psia)
l
I
Stove (0.008 psia)
Stove (0.008lpsia)
Comment
Tank installed prior to 1973,
MACT (Subpart CC) Group 1
tank
Tank installed prior to 1973,
MACT (Subpart CC) Group 1
tank
Tank installed prior to 1973,
MACT (Subpatt CC) Group 1
tank
Tank installed prior to 1973,
RMACT Group I tan( Tano
vaqJum breaker, gauge pole
sleeves
Tank installed prior to 1973
Tank installed prlor to 1973
40 CFR Part 60 Subpaft Kb
4.7.L Step 1 - Identify All Reasonably Available Contro! Technologies
Available control technologies for interna! floating roof tanks include:
> 40 CFR 63 Subpart CC controls,
> 40 CFR 63 Subpart CC (MACT CC RSR) controb,
> 40 CFR 63 Subpart \A/W controls,
4.7.1.7 40 CFR Part 6O Subpart Kb
Subpaft Kb applies to volatile organic liquid (VOL) storage vessels, which includes petroleum liquid storage
vessels, with capacities greater than or equa! to 75 m3. However, this subpart excludes storage vessels with
capacities greater than 151 m3 storing a liquid with a maximum true vapor pressure less than 3.5 kPa or
vessels with capacities between 75 and 151 m3 stbring a liquid with a maximum true vapor pressure less than
15.0 kPa. For storage vessels greater than 151 m3 in size containing a VOL with a maximum true vapor
pressure between 5.2 and 76.6 kPa and vessels slzed between 75 and 151 m3 storing a VOL with a maximum
truevapor pressure between 27.6and 76.5 kPa should be equipped with eithera fixed roof with an internal
floating roof, an external floating roof, a closed vent system and control device, or an equivalent system.
Storage vessels with capacities greater than 75 m3 containing a VOL with a maximum true vapor pressure
greater than or equal to 766 kPa should be equipped with a closed vent system and control device or equivalent
system.
HF Sinclair Woods Cross Refining LLC / Reasonable Avail6ble Control Technology Assessment
Trinity Consultants December 2023 4-18
4.7.1.2 40 CFR 63 Subpart CC
The National Emission Standards for Hazardous Air Pollutants for storage vessels are covered in 40 CFR Paft
63, Subpart CC, which applies to petroleum refinery storage tank. Under this subpart, Group 1 storage vessels
are required to comply with the requirements of 40 CFR Paft 63, Subpaft G (NESHAP for the synthetic organic
chemical manufacturing industry for process vents, storage vessels, transfer operations, and wastewater)
sections 63.119 through 63.12t. These sections provide control technology requirements, compliance
procedures, and alternative emission limits, respectively.
Section 63.119 requires that Group 1 storage vessels containing liquids with a maximum true vapor pressure
less than 76.6 kPa (10.87 psia) be equipped with either a fixed roof and internal floating roof, an external
floating roof, an externa! roof converted to an interna! roof, a closed vent system and control device, route
emissions to a process or fuel gas system, or perform regular vapor balances. On the other hand, those tanks
containing liquids with a maximum true vapor pressure greater than or equal to 75.6 kPa must be equipped
with either a closed vent system and control device, route emissions to a process or fuel gas system, or
perform regular vapor balances. Specific requirements for each of these controls are also spelled out in this
regulation. A range of compliance procedures are identified depending on the type of contro! technology used
to control emissions from the storage vessels, including visual inspections, gap measurements, design
evaluations, peformance tests, etc.
4.7.7.3 40 CFR 63 Subpart CC RSR Controls
Under the Residua! Risk and Technology Review (RTR), a new section within 40 CFR 63 Subpart CC (MACT
CC RSR) has been added at 40 CFR 63.660. This new section contains new and additiona! requirements for
floating roof seals, deck fitting controls, inspections, recordkeeping, and reporting. RSR requires that by
January 30,2026 or the next time the vesse! is emptied and degassed, whichever comes first, the tank needs
to be modified to meet the deck fitting controls of 40 CFR Subpart WW, which is the method of compliance
under 40 CFR 63.660. The deck fitting control upgrades for IFR tank from 40 CFR 63.646 to 40 CFR 63.660
compliance include:
> IFR wel! covers must be gasketed (i.e., deck openings other than for vents, drains, or legs) 1/8" max gap
criteria.
> Access hatches and gauge float well covers are required to be bolted and gasketed.
> IFR column wells must have gasketed cover or flexible fabric sleeve.
pole.
one of the following configurations:. A pole float in the slotted leg and pole wipers for both legs. The wiper or seal of the pole float must
be at or above the height of the pole wiper.. A ladder sleeve and pole wipers for both legs of the ladder.o A flexible enclosure device and either a gasketed or welded cap on the top of the slotted leg.
> Additionally, tank degassing emissions are controlled by portable combustion units, as required by the
Utah SIP Section IX.H Emission Limits and Operating Practices.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-t9
4.7.7.4 40 CFR Part 63 Subpart WW Controls
40 CFR Paft 63, Subpaft WW was written to be reference by other regulations to control air emissions from
storage vessels and is considered by EPA as the standard for EFR and IFR requirements under NESHAP.
Subpart WW was developed for the purpose of providing consistent EFR and IFR requirements for storage
vessels that could be referenced by multiple NESHAP subparts. Like the NSPS Subpart Kb standards for floating
roof tanks, Subpart WW is comprised of a combination of design, equipment, work practice, and operationa!
standards. Both rules specify monitoring, recordkeeping, and reporting for storage vessels equipped with EFR
and IFR and both include requirements for inspections to occur within defined timeframes. The inspections
required by Subpaft \A/W are intended to achieve tlrc same goals as those inspections required by Subpaft Kb.
Subpart \,VW allows for the visual inspection of the floating roof deck, deck fittings, and rim seals while the
tank remains in service if physical access is possibh. Subpaft \A/W does not require the tank to be taken out
of service to inspect the floating roof, rim seals and deck fittings which is in contract to Kb requirements.
4.7.1.5 Degassing Controls when Tanks are Taken Out of Seruice
Degassing is to be performed by liquid balancing (the opposite of vapor balancing) until the resulting liquid
vapor pressure is less than 0.5 psia or by venting the tank to a control device with a 90o/o minimum control
efficiency until the residual VOC concentration is less than 10,000 ppm.
4.7.7.6 fnsbllation of a Vapor Recovery System
The function of a vapor recovery system is to collect VOC emissions from storage tank that can be routed to
a fuel gas system for combustion as fuel. Vapor recovery can be achieved through carbon adsorption,
condensation, or absorption.
4.7.2 Step 2 - Eliminate Technically Infeasible Control Technologies
The above control technologies are technically feasible. The technical feasibility of meeting RSR (MACT CC)
controls varies by storage tank. Tanks L2, 72, and 138 have not been upgraded to include the MACT CC
required controls.
4.7.3 Step 3 - Rank Remaining Control Technologies Based on Capture and Control
Efficiencies
All of the above control options, RSR controls, degassing controls when storage tanks are taken out of seruice,
installation of a vapor recovery system and NSPS Kb controls have equivalent control efficiencies.
4.7.4 Step 4 - Evaluate Remaining Control Technologies on Economic, Energy, and
Environ mental Feasibility
Tanks constructed before August 18, 1994 and storing volatile organic liquids containing HAPS are required
to meet the applicable Refinery MACT requirements of NESHAP 40 CFR 63 Subpart CC which refers to the
control standards of 40 CFR Part 63 Subpart G. For Group 1 storage vessels storing liquids for which the
maximum true vapor pressure of the total organic hazardous air pollutants in the liquid is less than 76.6
kilopascals, the use of fixed roof and internal floaUng roof, an external floating roof, an external floating roof
convefted to an internal floating roof, a closed vent system and control device, routing the emissions to a
process or a fuel gas system, or vapor balancing is required.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-20
MACT CC RSR contains new and additiona! requirements for floating roof seals, deck fitting controls,
inspections, recordkeeping, and reporting. RSR requires that by January 30,2026 or the next time the vessel
is emptied and degassed, whichever comes first, the tank needs to be modified to meet the deck fitting
controls of 40 CFR Subpaft WW, which is the method of compliance under 40 CFR 63.660.
Utah Administrative Code R307-327 presents the requirements of petroleum liquid storage in ozone
nonattainment and maintenance areas. R307-327-4 states (1) Any existing stationary storage tank, with a
capacity greater than 40,000 gallons (150,000 liters) that is used to store volatile petroleum liquids with a true
vapor pressure greater than 10.5 kilo pascals (kPa) (1.52 psia) at storage temperature shal! be fitted with
control equipment that will minimize vapor loss to the atmosphere. Storage tanks, except for tanks erected
before January L, L979, which are equipped with externalfloating roofs, shal! be fitted with an interna!floating
roof that shall rest on the suface of the liquid contents and shall be equipped with a closure sea! or seals to
close the space between the roof edge and the tank wall, or alternative equivalent controls.
The owner/ operator shall maintain a record of the type and maximum true vapor pressure of stored liquid.
(2) The owner/operator of a petroleum liquid storage tank not subject to (1) above but containing a petroleum
liquid with a true vapor pressure greater than 7.0 kPa (1.0 psia), shall maintain records of the average monthly
storage temperature, the type of liquid, throughput quantities, and the maximum true vapor pressure. The
HF Sinclair Tanks listed in Table 4-3 meet the requirements of R307-327.
4.7.4.7 Energy, Environmental, or Economic fmpacts
Since HF Sinclair has chosen the highest-ranking controloptions, energy, environmentaland economic impact
analyses are not required.
4.7.5 Step 5 - Select RACT
Internal floating roof tanks currently meeting NSPS Kb is considered MCT. In addition, tanks that are currently
meeting RSR, MACT CC, and Subpaft WW controls are considered to meet MCT. Thus, the IFR tanks at HF
Sinclair meet RACT requirements. IFR tanks at HF Sinclair utilize dual seals and have welded deck. During
tank shutdown and degassing, a poftable combustion unit is used to control emissions. Tanks t2,72, and 138
are scheduled to be upgraded by January 30,2026 to meet RSR MACT CC requirements.
4.8 External Floating Roof Storage Tanks
External floating roof (EFR) tanks consist of an open cylindrical stee! shel! fitted with a roof that floats on the
surface of the stored liquid. There are two types of floating roofs, a double-deck roof and a pontoon roof.
Both types of roofs rise and fall with the liquid level in the tank. Emissions from externa! floating roof tanks
are due to standing storage losses from the rim sea! system and deck fittings and withdrawal losses from the
evaporation of exposed liquid on the tank walls.
MACT CC RSR requires that the next time the vessel is emptied and degassed or by January 30,2026,
whichever comes first, the tank is upgraded to meet the deck fitting controls of 40 CFR Subpart WW, which
is the method of compliance under 40 CFR 63.660. The deck fitting control upgrades (or commonly referred
to below as RSR Controls) for external floating roof tank from 40 CFR 63.646 to zl0 CFR 63.660 compliance
include:
criteria.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-21
Deck openings other than for vents must
Amss hatcfies and gauge float well@vers
Emergency roof drains must have seals
Guidepole wells must have gaskefted dec*
Unslotted guidepolc requlrcd to have a cap
Sbthd guidepohs must have an internalfloat
The EFR roof tanks operated at the Woods Cross
Table zl-4.
HF Sinclair Woods Cross Refining LLC / Reasonable
Trinity Consullants December 2023
into liquid.
be bofted and gasketed.
at least fio/o d the floafing roof dect opening.
and a pole wlper.
top of the pole.
equivalent.
that reported emissions in 20L7 arc presented in
4-22
Control Technology Assessment
Table 4-4 Externa! Floating Roof Tanks at HF Sinclair Woods Cross Refinery
Tank Tank Size Comment
Tank 100
Tank 101
Tank 102
Tank 104
Tank 105
Tank 106
Tank 107
Tank 108
Tank 109
Tank 121
Tank 126
Tank 128
Tank 129
Tank 132
Tank 135
Tank 145
Tank 146
bbl
53,372
53,564
52,990
24,435
24,501
24,524
24,501"
24,450
24,490
100,129
64,675
10,100
55,074
24,455
44,754
3,985
3,985
Product Stored and Vapor
Pressure of Product
Reformate (5.95 psia) Tank installed prior to 1973, RMACT
Group 1 tank, Tanco vacuum breaker,
gauge pole sleeves
Cat Gasoline (5.3 psia) Tank installed prior to 1973, RMACT
Group 1 tan( canister, gauge pole
sleeves
Crude Oil (2.6 psia) Tank installed prior to 1973, RMACT
Group 1 tank, canister, gauge pole
sleeves
Isomerate (10.5 psia) Tank installed prior lo L973, GEM Mobile
Treatment Combustor), RMACT Group 1
tank, gauge pole sleeves
Reformate (5.95 psia) Tank installed prior to 1973, RMACT
Group 1 tank, gauge pole sleeves
Gasoline, regular (5.2 Tank installed prior to 1973, RMACT
psia)Group 1 tank, canister, gauge pole
sleeves, dome
Gasoline, regular (5.2 Tank installed prior to t973, RMACT
psia)Group 1 tank, canister, gauge pole
sleeves
Gasoline, premium (5.2 Tank installed prior to 1973, RMACT
psia)
Alkylate (7.1 psia)
Crude Oil (4.91 psia)
Crude Oil (1.9 psia)
Group 1 tank, canister, gauge pole
sleeves
Tank installed prior to 1973, RMACT
Group 1 tank, canister, gauge pole
sleeves
Tank installed prior to 1973, RMACT
Group 1 tank, canister, gauge pole
sleeves
Tank installed prior to 1973, RMACT
Group 1 tank, Tanco vacuum breaker,
gauge pole sleeves
Gasoline, general (5.2 Tank installed prior to 1973, RMACT
psia)Group 1 tank, gauge pole sleeves
Naphtha HDS Charge 40 CFR Pad 60, Subpaft Kb, RMACT
(9.6 psia)Group 1 tank, Tanco vacuum breaker,
gauge pole sleeves
Gasoline, regular (5.2 Tank installed prior to L973, RMACTpsia) Group l tank, gauge pole sleeves
Cat Gasoline (9.5 psia) Tank installed prior to 7973, RMACT
Group 1 tank, gauge pole sleeves
Gasoline, regular (5.2 40 CFR 60 Subpart K, RMACT Group 1psia) tan( gauge pole sleeves
Gasoline, regular (5.2 40 CFR 60 Subpaft K, RMACT Group 1
sleeves
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-23
4.8.1 Step 1 - Identify All Reasonably Available Contro! Technologies
Available control technologies for internal floating roof tanks include:
> 40 CFR 63 Subpart CC (MACT CC RSR) controls,
4.8.2 Step 2 - Eliminate Technically Infeasible Control Technologies
The control technologies listed above are technically feasible.
4.8.3 Step 3 - Rank Remaining ControlTechnologies Based on Capture and Control
Efficiencies
The control options, NSPS Kb controls, existing and MACT CC RSR controls, and degassing controls when
storage tank are taken out of seruice, have equivalent control efficiencies, and will vary by tank. Calculations
done by the South Coast Air Quality Management District (SCAQMD) using TankESP Pro software storing crude
oil with RVPs ranging from 6 to 9 at 80oF with standard deck fitting and seals indicated a reduction of between
70 to 75o/o in standing losses of VOC with an addition of a dome to an external floating roof tank. A white
paper found at otcair.org titled VOC Stationary Above-Ground Storage Tanks-Deck fittings and Rim Seals,
Domes, Roof Landing Controls, Cleaning and Degassing Controls, and Inspections examined various control
technologies. This paper indicated that installing domes on external floating roof tanks can result in a 600lo
reduction of emissions after deck fittings upgraded.
4.8.4 Step 4 - Evaluate Remaining Control Technologies on Economic, Energy, and
Envi ron menta I Feasi bility
All tanks listed in Table 4-4 currently meet NSPS Subpart Kb or have been upgraded to include the MACT CC
and MACT CC RSR required controls.
A cost analysis performed by SCAQMD was conducted for external floating roof tanks with varying tank
diameters. The results of this cost analysis are presented in Table 4-5. According to SCAQMD, costs include
the cost for materials, installation, and shipping, but other construction costs may apply.
Table 4-5 SCAQMD Estimated Cost to Install a Dome Roof on an External Floating Roof Tank
Tank Diameter (feet) Cost
30 - 50 $4o,ooo - $65,000>50-1Oo i $65,000-$225,000
>1oo - 160 $225,000 - $450,000>160-2oO i $+5O,OOO-$715,000
>200 - 375 $715.000 - $1.400.000
HF Sinclair obtained costs to install domes on the external floating roof tanks at the Woods Cross Refinery.
The $/ton of VOC reduced from the addition of domes using a 70olo control efficiency and 2017 actual
emissions from the tanks is presented in Table 46.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-24
Table 4-6 $/ton Estimate of VOC Reduced from Installation of Domed Roof Tanks on the
1 No VOC emissions were reported for 2017 from Tank 128.
2 Cost based on median SCAQMD cost estimate for tanks with diameters between 30 - 50 feet.
Based on the $/ton costs presented in Table 4-6, the cost to install domes on all tanks was found to be
economically not feasible.
4.8.4,2 Energy, Environmental, or Economic fmpacts
Since HF Sinclair has chosen the highest-ranking control options of NSPS Kb controls, existing and MACT CC
RSR controls, and degassing controls when storage tanks are taken out of selice, energy, environmental and
economic impact analyses are not required.
4.8.5 Step 5 - Select RACT
All HF Sinclair EFR tanks are Group 1 emission points which are subject to al! applicable requirements of the
MACT (40 CFR 63 Subpaft CC) standard. All EFR tanks current meet NSPS Kb, MACT CC and/or MACT CC RSR,
and Subpaft WW controls which are considered to meet MCT. In addition, during tank shutdown and
degassing, a portable combustion unit is used to control emissions. All external floating roof tanks have been
upgraded at HF Sinclair to meet the requirements of the MACT CC RSR upgrades.
4.9 Equipment Leaks
The Wood Cross Refinery is required to monitor equipment in hydrocarbon service that is greater than 10olo
VOC. Equipment that is monitored includes pumps, valves, compressors, flanges, and pressure relief devices.
Numbered tags are used to identiff equipment included in the Leak Detection and Repair (LDAR) Program.
These components are sources of VOC emissions due to leakage.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023
Externa! Floating Roof Tanks at HF Sinclair Woods Cross Refinery
Tank Tank Diameter Vendor Cost Estimate $/ton VOC
100
101
102
104
105
106
t07
108
109
\2t
L26
128
129
L32
135
145
t46
110
110
110
70
70
70
70
70
70
150
114
48
L12
70
100
32
32
$304,101
$304,101
$304,101
$152,000
$152,000
Dome already installed on tank
$152,000
$152,000
$152,000
$454,357
$3L9,127
$7t,204
$307,000
$152,000
$273,000
$52,50G
$
$
$
$
$
$
$
$
$
$
$
$
$
$
270,072.14
119,386.76
1,279,62t,58
97,L42.95
234,438.4t
89,693.73
42,9%.27
283,L22.17
637,971.43
14L,9L5.07
NAl
46,044.58
8,725.55
22,694.94
40,030.67
4-25
The facility's leak detection and repair program is regulated under the Utah Administrative Code R307-326-9
(Ozone Nonattainment and Maintenance Areas: Control of Hydrocarbon Emissions in Petroleum Refineries),
40 CFR Part 60 Subparts GGG and GGGa (Standards of Performance for Equipment Leaks of VOC in Petroleum
Refineries), 40 CFR Part 63 Subpaft CC (Nationa! Emission Standards for Hazardous Air Pollutants from
Petroleum Refineries), and the July 2,2008 Consent Decree.
4.9.L Step 1 - Identify All Reasonably Available Control Technologies
Potential enhancements to a LDAR program work practice requirements include the following:
inteface. This has the potential of broadening the repair obligations for leaking components to include
components that would not normally require repair under NSPS or NESHAP rules.
components.
In addition, equipment specifications and maintenance practices are designed and implemented to reduce
leaks. For certain applications, components with inherently leakless features are available, These components
reduce VOC emissions. Some leakless designs include the following:
> Connectors welded around the entire circumference such that the joint cannot be disassembled by
unscrewing or unbolting the components.
Another control option would be to set an enforceable limit on the number of leaking components.
4.9.2 Step 2 - Eliminate Technically Infeasible Control Technologies
Each control option that was identified in Step 1 is technically feasible.
4.9.3 Step 3 - Rank Remaining Control Technologies Based on Capture and Control
Efficiencies
The most effective of the identified control options is a combination of each option. This includes an LDAR
program with enhanced work practices relative to the NSPS or NESHAP plus enforceable limits on leaking
components.
4.9.4 Step 4 - Evaluate Remaining Control Technologies on Economic, Energy, and
Environ mental Feasibi lity
The most effective control strategy listed above has been implemented by HF Sinclair at the Woods Cross
Refinery. The LDAR program at the refinery meets the requirements of NSPS, NESHAP, and consent decree
requirements.
The following leak rate goals have been set to be achieved through the LDAR program at the Woods Cross
Refinery: (1) A facility wide component leak rate goal has been set at less than or equal to 2.0o/o of total
components, and (2) Each process unit leak rate goal is less than or equal to 2.0o/o of total components.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-26
The following leak definitions are utilized at the refinery:
1. All units have a leak definition for recordkeeping, repofting, and repair of 2,000 ppm for pumps and
compressors and 500 ppm for valves.
2. Internal leak definitions for first attempt at repair is 200 ppm will be utilized for all valve components
subject to NSPS and NESHAP regulations.
EPA Method 21 is used to determine the presence of leaking sources. Monitoring and leak rate calculations
are divided into groups. Most of these groups are based on units, fluid types, and regulatory requirements.
Each month, the LDAR technicians complete the scheduled monitoring and results of monitoring are entered
into the LDAR database at the end of each shift. Work Requests for identified leaks that were not repaired by
the LDAR technician are initiated by the end of the monitoring shift. Operations personnel peform a visual
inspection of pumps subject to MACT and NSPS regulations each week. Any obserued leak are reported to
the facility LDAR Coordinator within 24 hours. Olfactory, visual and auditory leak checks are performed daily,
and repairs are repofted and fixed within 24 hours.
Leak are defined by the various regulatory requirements. The LDAR Technician will make an initia! attempt
to repair leaking components and leaking components are tagged. The VOC reading for each leaking
component is recorded on the tag by the technician. Table 4-7 defines actions for various leak rates.
Table 4-7 Repair Actions for Leaking Valves and Pumps
Component
Valves
Pumps
Requirement
Consent Decree
40 CFR GGGa
R307-326-9
Consent Decree
40 CFR GGGa
R307-326-9
Leak Rate
200-499
500-9,999
>9,999
>4gg
>9,999
2,000-9,999
>9,999
>1,ggg
Fina! Repair
-
30 days
15 days
15 days
15 days
30 days
30 days
15 days
Report as LeakFirst
5 days
5 days
5 days
5 days
5 days
5 days
5 days
5 days
5 15
No
No
Yes
Yes
Yes
No
Yes
Yes
Yes
Components are re-monitored within 5 days after a repair attempt. After the first attempt, valves with leaks
less than 500 ppm require no fufther action. For valves found to be leaking greater than 10,000 ppm that
cannot be repaired, a drill and tap repair or similarly effective repair method will be peformed, unless it can
be documented that there is a safety, mechanical, or major environmenta! concern with repairing the leak
with such a method. The initial repair attempt will be made within 15 days and a second, if necessary, within
30 days of identification of the leak, as stated in paragraph 132 (b) of the Consent Decree.
Gas/vapor and light liquid valves that leak, and are repaired, will be monitored for two consecutive months
before going back to quarterly monitoring. A chronic leaker is a valve that has leaked greater than 10,000
ppm at least twice in any 4 consecutive quarters. Chronic leaking, non-control valves, are replaced, repacked,
or similarly repaired at the next process unit turnaround.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-27
All process units are subject to R307-326-9, Leaks from Petroleum Refinery Equipment and 40 CFR Part 60
Subpart GGGa (Standards of Performance for Equipment Leaks of VOC in Petroleum Refineries). Those that
contain HAP are subject to 40 CFR Part 63 Subpart CC (National Emission Standards for Hazardous Air
Pollutants from Petroleum Refi neries).
4.9.4,1 Energy, Environmental, and Economic fmpacts
There are no anticipated energy, environmental, and economic impacts associated with the top ranking control
of operation of a LDAR program.
4.9.5 Step 5 - Select RACT
The LDAR program in operation at the HF Sinclair Woods Cross Refinery incorporates the effective control
technologies listed above and is considered the RACT. The LDAR program at the refinery meets the
requirements of NSPS, NESHAP, and consent deoee requirements. A LDAR program is the most stringent
controt measure identified at refineries for controlling VOC emissions from equipment leaks. Monitoring is
performed on components based on the requirements presented in Table 4-8. No more stringent controls
were identified other than the implementation of an effective LDAR program.
Table 4-8 LDAR Monitoring Frequencies
Equipment Type
Reouirements
State and Consent Decree
Federal*(7l2l08)
Leak Detection Monitorino
Comments
Valves
Pumps
Compressor
Drains
All
All
Light Liquid
Heavy Liquid
Gas
Plant Gas
Natural Gas
Light Liquid
Heavy Liquid
Seals
Process
Unsafe to
Monitor
Difficult to
Monitor
Monthly
As noticed
Monthly
Monthly
Exempt
Monthl{
As notic#
Auto-sensors
None
wnen oos{ute
Annual
Quarterly
Exempt
Quafterly
Quafterly
Exempt
Monthly
Exempt
Quarterly
NA
When possible
Annual
<10o/o VOC
>10o/o VOC
<10olo VOC
<10olo VOC
VisrAl Monltorins
Pumps
Drains
Light Liquid
Heavy Liquid
Process
<10o/o VOC
NSPS Suboart OOO
Weekly
None
Monthl$
NA
NA
NA
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-28
4.10 Wastewater Treatment Plant
The Wastewater Treatment Plant (WVWP) treats plant wastewater and storm water runoff from process areas.
Wastewater is collected and routed to a main process lift station. The main process lift station supplies process
wastewater to two American Petroleum Institute (API) separators. Oil is skimmed off the separators and
gravity fed to an API oil collection drum then to Tank 118. The sludge from the API separators is collected
and dewatered in a sludge thickening vessel and later sent for disposa!.
The effiuent water from the API separators is pumped to two equalization tank (Tanks 155 and 158). From
the equalization tank, wastewater is pumped into two dissolved gas floatation units (DGF). The DGFs work
to remove emulsified oil from the wastewater by adding a polymer and inducing small Nz bubbles into the
water to bring oil to the surface. This skimmed oil, or float, is gravity fed to a storage tank before being
pumped to the sludge thickening vessel.
Finally, the wastewater is sent to a series of moving bed bio-film reactors (MBBR) for biological polishing
before being discharged to the South Davis County Public Owned Treatment Work (POn /). All process tanks
and equipment at the \AM/TP are covered to control fugitive emissions.
4.10.1 Step 1 - Identify All Reasonably Available Control Technologies
Emission control technologies for control of VOC emissions from the wastewater treatment plant include
equipment design and work practice requirements that are set forth in the following regulations:
> 40 CFR Part 60, Subpart QQQ requires water seal controls or more effective controls for the wastewater
system drains and sumps and a floating roof or a closed-vent system and a control device, such as a
catalytic oxidizer for the API separators.
> 40 CFR Part 61, Subpart FF generally requires the same controls for the wastewater collection system
drains and sumps as 40 CFR Paft 60, Subpart QQQ.> 40 CFR Part 63, Subpaft CC requires compliance with the requirements of 40 CFR Part 61, Subpart FF.
Per the above regulations, identified controls include water seal controls on drains, wastewater stripping,
floating roofs for treatment vessels, and carbon absorption and incineration for remova! of VOC from vent
streams. Inspection and maintenance programs as wel! as performance-based work standards are also control
strategies that can be implemented to reduce VOC emissions.
4.LO.2 Step 2 - Eliminate Technically Infeasible Control Technologies
Water stripping, floating roofs, and incineration are technically infeasible for application to wastewater drains.
The requiremenb of Subpart QQQ and Subpart FF are technically feasible.
4.10.3 Step 3 - Rank Remaining Control Technologies Based on Capture and Control
Efficiencies
Equipment control strategies can require the installation of new equipment or devices or can include physical
changes to the wastewater system. Potential control strategies include:
percent. Potential emission control devices for wastewater collection systems (predominately junction box
vents) include carbon absorption, thermal oxidation, catalytic oxidation, and condensation.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-29
> Installing water seals on process drains and vents open to the atmosphere would help prevent emissions
from the downstream sewer lines from escapinE back out of the drain or vent opening. The overall control
efficiency of this method is 650lo and varies depending on the proper maintenance of the water sea!.
program to be effective. An effective I&M program is designed to inspect (on a regular basis), maintain
and repair (as necessary) the pertinent components of a pollution control system for proper operation.
drain or vent, equivalent emission reduction can be achieved without specifying a pafticular control
technology.
For wastewater treatment plant vessels, the most effective control strategy includes wastewater stripping to
reduce VOC concentrations in wastewater entering the API separators, floating roofs for the equalizations
tanks, and closed vent systems and oxidation of the VoC<ontaining vent streams from the API separators,
and dissolved gas floatation (DGF) units. Hard piping from the process units to the wastewater separator,
from process units to a drain box enclosure, from those process units identified as the largest contributors to
process drain emissions, or from junction boxes that are completely covered and sealed with no openings are
also most effective in reducing VOC emissions.
The less effective control options would omit the use of a wastewater stripper or use floating roofs rather
than closed vent systems and oxidation systems for the API separators and DGF units.
4.LO.4 Step 4 - Evaluate Remaining Control Technologies on Economic, Energy, and
Environ mental Feasibility
During wastewater treatment, volatilization/stripp{ng, sorption, and biodegradation primarily determine the
fate of VOCs. Of these, volatilization and stripping result in air emissions. Biodegradation and sorption onto
sludge serve to suppress air emissions. Stripping is the pollutant loss from the wastewater due to water
movement caused by mechanical agitation, head !oss, or air bubbles, while volatilization may be defined as
quiescent or wind-driven loss. The magnitude of emissions from volatilization/stripping depends on factors
such as the physical properties of the pollutants (vapor pressure, Henry's Law constants, solubility in water,
etc.), the temperature of the wastewater, and the design of the individual collection and treatment units
(including wastewater surface area and depth of the wastewater in the system). Wastewater unit design is
impoftant in determining the suface area of the alr-water interface and the degree of mixing occurring in the
wastewater.
In 2015, HF Sinclair upgraded their wastewater treatment system to include covered oil-water separators with
fixed roofs and venting VOC vapors that accumulate under the headspace of the fixed roofs through a closed
system to carbon absorption units, equipping new drains with a water seals, and covering new junction boxes.
Monthly visual inspections are performed on the individual drain systems and semi-annual inspections are
performed on the closed vent system and sealed junction boxes and oil/water separators. Carbon adsorber
monitoring is performed at interuals no greater than 20 percent of the design carbon replacement intervals.
The piping used for the new sewer lines associated with the upgrade are compliant with Subpart QQQ.
Performance based standards exist at the refinery with emission limits of 500 ppm above background for the
carbon adsorber and closed vent system. The closed vent systems are designed and operated with no
detectable emissions which are verified semi-anilually. Sealed junction boxes are also used and inspected
semi-annually.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-30
4.70,4.1 Energy, Environmental, and Economic fmpacts
There are no energy, environmental, and economic impacts anticipated with the top ranking control options
that have been utilized at the HF Sinclair wastewater treatment plant.
4.10.5 Step 5 - Select RACT
VOC emissions from the wastewater treatment system meet the requirements of Subpart QQQ and Subpart
FF. Emissions from the wastewater system control device comply with 40 CFR 60 Subpart QQQ and are
monitored in accordance with 40 CFR 60.595. 40 CFR Part 61, Subpart FF requires that the oil water separators
be equipped with a fixed roof and vapors directed to a control device which HF Sinclair has installed. No more
stringent requirements were found other than compliance with 40 CFR 60 Part QQQ and 40 CFR Part 61,
Subpart FF.
The proposed RACT controls, VOC emission limits, and monitoring methods conducted for the wastewater
treatment at the Woods Cross Refinery are summarized in Table 4-9.
Table 4-9 RACT Controls, VOC Emission Limits, and Monitoring Methods for Wastewater
Treatment
Control Technology
Carbon adsorber
Oosed vent system
Individual drain system water seal
Sealed junction boxes and oil-water
VOC Emission
Limit
500 ppm (above background)
500 ppm (above background)
None
None
Monitoring Methods
Monitored at interuals 320o/o of
design carbon replacement
interval
Method 21, semi-annual
inspections
Monthly visual inspections
Semiannual visual inspections
The most stringent measures identified for contro! of VOC emissions from wastewater treatment include
installing covers and seals on the collection components to reduce fugitive VOC emissions and maintaining or
installing a control device such as carbon canisters to destroy VOCs released during treatment. HF Sinclair has
included the most stringent measures for the design of their wastewater treatment unit, which satisfies MCT.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-3t
A,LL Product Loading
Unit 87 (AO Conditions II.A.157 and II.A.158) and II.A.159 Ethanol Unloading consists of truck and rail
loading/unloading operations. Truck loading and unloading operations consist of sixteen (16)
crude/gas/oil/NcL truck unloading bays, one (1) NaSH truck loading spot, two (2) NaHS/caustic rail car
loading/unloading spots, three (3) caustic truck unloading spots, two (2) sulfur truck loading arms, one (1)
fuel oil truck loading spot, one (1) fuel oil buck unloading spot, four (4) fuel oil/asphalt rail car
unloading/loading spots, four (4) oil/dieseUcaustic rail car loading/unloading and ethanol rail car unloading
spots, four (4) NGL rail car loading/unloading spots, five (5) NGUolefin rail car loading/unloading, one (1)
asphalt truck loading spot, one (1) diesel truck unloading spot, one (1) light cycle oil truck unloading spot,
two (2) propane truck loading spots, one (1) kerosene truck loading spot, one (1) gasoline truck unloading
spot, foufteen (14) fuel oil or asphalt loading spots, twenty-four (2a) lube oil loading spots, and, two (2)
dedicated ethano! unloading areas. Ethanol unloading consists of three (3) dedicated ethanol unloading areas
which include a 250 gallons per minute (gpm) pUffip, a 400 gpm LOD charge puffiP, a 250 gpm LOD charge
pump and four (4) unloading arms.
4.11.1 Step 1 - Identify All Reasonably Available Control Technologies
Several control technologies were identified to reduce product loading emissions. They include use of
submerged or bottom loading, installation of a vapor balance system and vapor recovery or destruction
technologies which include carbon adsorption, condensation, and incineration.
4.LL.2 Step 2 - Eliminate Technically Infeasible Contro! Technologies
All control technologies identified in Step 1 are technically feasible.
4.11.3 Step 3 - Rank Remaining ControlTechnologies Based on Capture and Control
Efficiencies
Vapor recovery through carbon adsorption or coMensation provides the most effective control of emissions
by collecting the vented materia! for recycle or reuse. Vapor destruction through incineration provides control
of emissions by combustion of the hydrocarbon to form COz and HzO vapor. Individually, each identified
control technology has approximately the same ontrol effectiveness. Each technology, when applied to the
exhaust stream from a loading rack will reduce VOC emissions in excess 98o/o.
The use of submerged or bottom loading as a means of control offers a low-cost way to control loading
emissions. A significant reduction in vapor generation is possible by decreasing the turbulence created when
liquid is introduced into a compartment. This can be done using bottom or submerged loading rather than
splash loading.
In vapor balancing, hydrocarbon vapors are collected from the compartment where the liquid is being loaded
and returned to the tank from which the liquid is being sent. Vapor balancing works since the volume of
displaced vapors is almost identical to the volume of liquid removed from the tank. This technique is most
effective when loading tank trucks from fixed roof tanks. Vapor balancing cannot be applied when loading
from floating roof tank since there is no closed vapor space in the tank to which vapors can be returned.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-32
4.tt.4 Step 4 - Evaluate Remaining Control Technologies on Economic, Energy, and
Environ mental Feasibility
VOC emissions from loading/unloading are a function of the vapor pressure of the liquid and the design of the
equipment. Liquids with very low vapor pressure, diesel, kerosene, caustic, NaSH, and asphalt will have limited
VOC emissions.
At the refinery, HF Sinclair only loads/unloads fuels such as fuel oil, gas oil, asphalt NaSH, kerosene, diesel,
and ethanol, all of which have low volatility. Most of the crude and refined products are brought in and shipped
out via pipeline which is a closed system. For products with low vapor pressures that are loaded at the rail
and truck spots, the reduction of VOC emissions from excess vapors is accomplished using submerged or
bottom loading as well as vapor balancing. For truck loading, control of VOC emissions is through vapor
balancing. For VOC emissions from LPG railcar unloading, a vapor recovery system consists of recovery of LPG
emissions by pumping back into the tank.
Gasoline, diesel, and jet fuel from the HF Sinclair Woods Cross Refinery are sent to the Holly Energy Partners
Terminal via pipeline. A loading rack is utilized to load these products into tanker trucks. The Terminal has
four loading bays for local sales of diesel, jet fuel, and gasoline. The Terminal is equipped with a John Zink
Model JZ[0L7886 VRU that captures and recovers hydrocarbon vapors that are displaced during bulk loading
operations at the Terminal. The VRU consists of two carbon collection beds operated and regenerated
alternately. The two beds vent to the atmosphere through a common stack. John Zink has provided a
guarantee to limit hydrocarbon emissions from exceeding 10 milligrams per liter of product loaded for any
consecutive six-hour period during norma! operation.
In the event the VRU is not operational, a natural gas fired John Zink VCU is also available as a backup to
control emissions of volatile hydrocarbons. Hydrocarbon vapors from gasoline truck loading flow to a
condensate collection tank. This tank is impoftant to the operation of the VCU. It allows any condensed liquid
and overfill of the transpoft vehicles to be removed prior to the combustion step. The design basis for the
VCU is based on a maximum truck loading rate of 4,500 gallons per minute (gpm), a maximum vapor flow to
the combustor of 601 standard cubic feet per minute (SCFM), ambient temperatures ranging from 20 to 100oF,
and a maximum hydrocarbon concentration of 60 volume percent. Available pressure at inlet of vapor
combustion is 12" W.C. The VCU operation is limited to 1,056 hours per year. Appendix C contains the RACT
analysis for the Terminal operations.
4.77,4,7 Energy, Environmental, and Economic Costs
Routing the emissions from low VOC products that are loaded or unloaded from trucks and railcars at the
refinery to a regenerative thermal oxidizer (RTO) was examined. Based on HF Sinclair's 2017 annua! emission
inventory VOC emissions from loading/unloading sulfur, asphalt, kerosene, stove oil, fuel oil, ethanol, crude,
and gas oil were approximately 4.51 tons per year. The cost effectiveness for installation of a regenerative
thermal oxidizer is approximately $112,737 $/ton VOC reduced. In addition, additional energy in the form of
natural gas will be needed to fuel the RTO leading to increased VOC emissions. The current price of natural
has is $8.69 per MSCF. Thus, it was determined that use of a RTO was not cost, energy, or environmentally
effective and was not considered RACT or this analysis.
4.11.5 Step 5 - Select RACT
RACT for HF Sinclair is the delivery of crude and high VOC products through pipeline and the use of a VRU
and VCU at the termina! loadout. RACT for the tanker and railcar loading and unloading at the Woods Cross
Refinery is the use of submerged or bottom loading as well as vapor balancing.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-33
The most stringent measures identified for prodr,rct loading for tank truck and rai! car loading includes a
submerged pipe fill and vapor collection system vented to a thermal incinerator with a destruction efficiency
>98.5olo. As mentioned above, the installation of a thermal incinerator would increase VOC emissions and is
not cost effective. Thus, the installation of a thermal incinerator does not represent RACT for emissions of
VOC from railcar and tanker truck loading/unloading at the Woods Cross Refinery.
4.L2 Diesel Emergency Engines
Diesel emergency equipment at the Woods Cross refinery consists of a 135 kW portable diesel generator at
the East Tank Farm, 224 HP diesel powered water well No. 3, 393 HP fire pump No. 1, 393 HP fire pump No.
2, 180 HP Detroit diesel fire puffip, three (3) 220 HP diesel-powered plant air backup compressors, 470 HP
diesel standby generator at the Boiler House, 380 HP diesel standby generator at the Central Control Room,
and 540 HP diesel standby generator.
VOC emissions are primarily the result of incomplete combustion of diesel fuel. These emissions occur when
there is a lack of available oxygen, the combustion temperature is too low, or if the residence time in the
rylinder is too short.
4.t2.t Step 1 - Identify All Reasonably Available Control Technologies
The following control options were evaluated for controlling VOC emissions from the CI combustion engines.
They include good combustion practices and the post-combustion contro! technologies of diesel oxidation
catalysts.
4, 12, 1, 1 Good Combustion Practices
Good combustion practices refer to the operation of engines at high combustion efficiency which reduces the
products of incomplete combustion. The emergency generators are designed to achieve maximum combustion
efficiency. The manufacturer provided operation and maintenance manuals that detail the required methods
to achieve the highest levels of combustion efficiency.
4, 72. 7.2 Diesel Oxidation Catalyst
A diesel oxidation catalyst (DOC) is a flow-through metal or ceramic substrate coated with platinum or other
precious metals. The diesel oxidation catalyst sits in the exhaust stream and all exhaust from the engine
passes through it. The catalyst promotes the oxidation of unburned CO and HC (as VOC) in the exhaust
producing COz and water. Diesel oxidation catalysts are commercially available and reliable for controlling VOC
emissions from diesel engines.
4.1.2.2 Step 2 - Eliminate Technically Infeasible Contro! Technologies
The control technologies identified in Step 1 are technically feasible.
4.L2.3 Step 3 - Rank Remaining Control Technologaes Based on Capture and Control
Efficiencies
The control effectiveness of each identified control technology is as follows:
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-34
4.L2.4 Step 4 - Evaluate Remaining Control Technologies on Economic, Energy, and
Environ mental Feasi bility
For diesel engines, oxidation catalysts are often combined with pafticulate filters. This can be done by applying
the catalysts, which are typically platinum based, to a pafticulate filter. Another common approach is to locate
the oxidation catalyst separately, upstream of the particulate filter. The oxidation catalyst creates heat by
oxidizing unburned hydrocarbons and shifts NOx, cr€otirg a favorable environment for the pafticulate filters
to regenerate.
4,72.4.7 Energy, Environmental, and Economic fmpacts
The highest-ranking control option, DOC, can reduce VOC emissions by up to 95olo. A cost effectiveness
evaluation for this top-ranking option, in costs per ton of VOC removed, is presented in Table 4-10 and in
Appendix B. Costs for DOCs were obtained from Wheeler Machinery and represent current costs.
Table 4-10 Cost Effectiveness of Insta DOC on Diesel E for VOC Control
As seen from Table 4-10, it is not cost effective to install DOC on the emergency diesel generators and has
been eliminated as MCT.
4.L2.5 Step 5 - Select RACT
The remaining control option, good combustion practices was determined to be MCT for the diesel emergency
generators operated at HF Sinclair. According to HF Sinclair's approval order, the 135-kW poftable generator
at the east tank farm is limited to 1,100 operating hours per year. In 2017, the 135-kW portable generator
was operated for 5.3 hours. All other emergency engines are limited to 100 operating hours per year for
testing and maintenance. Non-resettable hour meters are installed on each unit.
Based on the economic costs to install DOC on the emergency diesel generators, DOC has been eliminated
from further consideration.
Periodic maintenance is peformed on the engines in accordance with manufacturer specifications. For those
engines subject to Subpart ZZZZ, oil is changed, and hoses/belts inspected every 500 hours or annually. Thus,
the only control technologies for the diesel emergency generators and fire pumps (except the 135-kW
generator at the East Tank Farm) are the work practice requirements to adhere to GCP for each engine and
the best practice of performing periodic maintenance. These requirements have been determined to be RACT.
Equipment
135 kW generator Gast tank'farm)
224HP (water well #3)
393 HP fire pump #1
393 HP fire pump #2
180 HP Detroit Dieselfire pump
220 HP plant air backup compressor #1
220 HP plant air backup compressor #2
220 HP plant air backup compressor #3
470 HP diese! generator (boiler house)
380 HP dieselgenerator (centralcontrol room)
540 HP
Cost
Effectiveness
$ t7,155,778
$ 3,075,546
$ 846,226
$ 997,075
$ 4,287,L58
$ 1,131,071
$ 229,449
$ 77,034
$ 9,794,966
$ 2,976,394
752.0L9
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-35
These control strategies are technically feasible and will not cause any adverse energy, environmental, or
economic impacts.
4.L3 Natural Gas Emergency Engines
Combustion is a therma! oxidation process where carbon and hydrogen contained in the fue! combine with
oxygen in the combustion zone to form HzO and COz. VOCs are generated during the combustion process due
to incomplete thermal oxidation of the carbon contained in the fuel. In properly designed and operated
generators, low levels of VOCs are typically emitted.
4,13.1 Step 1 - Identify All Reasonably Available Control Technologies
Three potential control technologies were identified to reduce VOC emissions. They are:
> good combustion practices,
> oxidation catalysts, and
4. 73, 7,7 Good Combustion Practices
Optimization of the design, operation, and maintenance of an engine is one way to reduce VOC emissions by
maximizing the thermal oxidation of carbon which minimizes the formation of VOC.
4. 73. 7.2 Oxidation Catalysts
An oxidation catalyst is a flow through exhaust device that contains a honeycomb structure covered with a
layer of chemical catalyst. This layer contains small amounts of precious metal-usually platinum or palladium-
that interact with and oxidize pollutants in the exhaust stream (CO and unburned HCs), thereby reducing
emissions.
4. 13. 1.3 Non-Selective Catalytic Reduction
NSCR is a catalytic reactor that simultaneously reduces VOC emissions. The catalytic reactor is placed in the
exhaust stream of the engine and requires fuel-rich air-to-fuel ratios and low oxygen levels.
4.13.2 Step 2 - Eliminate Technically Infeasible Contro! Technologies
The NSCR technique is effectively limited to engines with normal exhaust oxygen levels of 4 percent or less.
This includes 4-stroke rich-burn naturally aspirated engines and some 4-stroke rich burn turbocharged
engines. Engines operating with NSCR require tight air-to-fuel control to maintain high reduction effectiveness
without high hydrocarbon emissions. To achieve effective VOC reduction peformance, the engine may need
to be run with a richer fuel adjustment than normal. This exhaust excess oxygen level would probably be
closer to 1 percent. Lean-burn engines cannot be retrofitted with NSCR control because of the reduced exhaust
temperatures. Thus, NSCR was eliminated from consideration since the engines operated by HHF Sinclair at
the administration building are designed for lean burning. The remaining control technologies are technically
feasible.
4.13,3 Step 3 - Rank Remaining ControlTechnologies Based on Capture and Control
Efficiencies
The use of an oxidation catalyst is the remaining top ranking control technology which provides a 90o/o control
efficiency for VOCs. Good combustion practice is the second ranking control technology for VOC reduction.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 4-36
4.L3.4 Step 4 - Evaluate Remaining Control Technologies on Economic, Energy, and
Environmental Feasi bi lity
Combustion controls are integral in the combustion process as they are designed to achieve an optimum
balance between thermal efficiency-related emissions (CO and VOC) and temperature related emissions
(NOx). Combustion controls will not create any energy impacts or significant environmental impacts. There
is no economic impact from combustion controls because they are part of the design for modern engines.
Natural gas generators are regulated by 40 CFR Part 60 Subpaft JJJJ and 40 CFR Part 63, SubpartZZZZ.
Here, the EPA provides emissions standards manufacturers must meet, emissions standards
owners/operators must meet EPA certification requirements, testing requirements, and compliance
requirements.
According to Subpart JJJJ, the VOC emission standards for stationary emergency engines >25 HP is 1.0 g/HP-
hr or 86 ppmvd @ 15olo Oz. The HF Sinclair natural-gas fired emergency generators were manufactured in
20L2 and as such, meet the Subpaft JJJJ VOC emission standard of 1.0 g/HP-hr.
4.73,4.7 Energy, Environmental, and Economic Costs
Catalytic oxidation is relatively expensive for the size of the engines and the frequency of their use at the
Woods Cross Refinery. The capitol cost to install an oxidation catalyst is approximately $74,6L7. Annual costs
are approximately $23,579. The cost in $/ton of VOC removed is estimated to be over $35 million dollars
based on 2017 actual emissions. (See Appendix B). Thus, it is not economically feasible to install oxidation
catalysts on the emergency natural-gas fired generators at the Woods Cross Refinery. There are no additional
energy or environmental costs associated with operating an oxidation catalyst on the natural gas fired
emergency generators. There is no fuel penalty associated with the use of an oxidation catalyst since this
controltechnology does not increase the fuel usage in an SI engine.
4.13.5 Step 5 - Select RACT
The most stringent control measure identified is the use of an oxidation catalyst achieving a VOC emission
rate of 0.15 g/bhp-hr. This emission rate has been achieved in practice.
RACT for VOC emissions from 2012 model year SI ICE generators at HF Sinclair is the application of a lean
burn engine fired on natural gas, good combustion practices, limited operating hours, and operation in
accordance to manufacturer's recommendations. The generators are EPA certified and the manufacturer lists
a VOC emission rate of 1.0 g/HP-hr or 86 ppmvd @ 15olo Oz. The engines are in compliance with the applicable
emission limits of 40 CFR Part 60 Subpaft JJJJ and 40 CFR Paft 63 Subpart ZZZ. The proposed controls
represent RACT.
HF Sinclair Woods Cross Refining LLC / Reasonable Avaihble Control Technology Assessment
Trinity Consultants December 2023 4-37
5. ACTUAL AND POTENTIAL EMISSIONS
A summary of the 2017 actual emissions for NOx and VOC emissions from the emissions inventory at HF
Sinclair is presented in Table 5-1, Details for the estimated actuals and potential to emit (PTE), where utilized
are presented in Appendix A.
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023
Table 5-1 HF Sinclair Woods Cross Refinery - NOx and VOC 2017 Actual Emissions
Unit ID 2017 Actuals
(TPY)
Equipment Description
FCC Feed Heater
4V82 FCC Scrubber
Reformer Reheat Furnace
Prefractionator Reboiler Heater
Reformer Reheat Furnace
HF Alkylation RegenaUon Furnace
HF Alkylation Depropanizer Reboiler
Crude Furnace #1
DHDS Reactor Charge Heater
DHDS Stripper Reboiler
Asphalt Mix Heater
SRGP Depentanizer Reboiler
SRGP Electric Compressor
NHDS Reactor Charge Furnace
DHT Reactor Charge Heater
Fractionator Charge Heater
Fractionator Charge Heater
Crude Unit Furnace
FCC Feed Heater
25FCC Scrubber
#4 Boiler
#5 Boiler
#8 Boiler
#9 Boiler
#10 Boiler
#11 Boiler
Cooling Tower #4
Cooling Tower #6
Cooling Tower #7
Cooling Tower #8
Cooling Tower #10
Cooling Tower #11
South Flare
North Flare
Burners derated to 39.9o'/2 MMBtu/hr
0.00
1.23
0,19
0.45
0.03
0.52
1.76
0.20
0.0s
0.18 2017 SLEIS says this unit is 10H2
0.33
0.62
0.05
0.22
0.84
0.35
0.63
0.00
0.00
0.25
0.17
0.79
1.47
1.50
a ^A PTE Emissions based on boiler
t 'z t rating of 89.3 MMBtu/hr
0.06 $htT #4
0.19 CWT #6
0.13 CWr #7
0.44 CWT #8
0.34 CWT#10
0.18
13.85
73.86
Comments
voc
4Ht
4V82
6H1
6H2
6H3
7HL
7H3
BH2
9H1
9H2
10H1
11H1
72Ht
13H1
19H1
20H2
20H3
24H1
25H1
25FCC
Boiler #4
Boiler #5
Boiler #8
Boiler #9
Boiler #10
Boiler #11
CWT #4
cwr #6
CY\ff #7
cwT #8
cwT#10
cwT #11
66-1
66-2
5.14
L6.27
21.40
3.34
7.76
0.53
9.04
9.83
3.40
0.8s
3.20
5.78
7.31
0.93
1.56
6.28
1.59
2.57
0.02
18.33
4.41
0.19
0.58
1.91
0.83
0.24
t.27
7.55
5-1
Table 5-1 (Continued) HF Sinclair Woods Cross Refinery - NO' and VOC 2017 Actual Emissions
Unit ID Equipment Description 2017 Actuals Comments
South In-Tank Asphalt Heater 0.07
ETF Portable Generator 1.20E-02
Diesel Powered Water Well No.3 1.07E-01
68H2
68H3
voc
3.96E-03
3.96E-03
1.00E-03
8.50E-03
5.42E-02
4.60E-02
4.90E-03
2.27E-02
1.12E-01
3.33E-01
5.60E-03
t.498-02
2.29E-02
3.00E-03
3.00E-03
0.04
4.47
0.00
0.00
58.34
0.00
28.t4
0.49
2.t4
2.60
4.44
13.1 1
3.10
0.00
0,53
0,00
0.00
0.00
0.30
24.81
0.34
0.00
ETF
Emergency Eq.
Emergency Eq.
Emergency Eq.
Emergency Eq.
Emergency Eq.
Emergency Eq.
Emergency Eq.
Emergency Eq.
Emergency Eq.
Emergency Eq.
Emergency Eq.
Emergency Eq.
Loading
Loading
Loading
Loading
Tanks
Tanks
Tanks
Tanks
Loading
Pipeline Valves
Pipeline Valves
Pipeline Valves
Pump Seals
Pump Seals
Seals
Loading
Loading
Tank
Wastewater
Pipeline Flanges
Relief Valves
Loading
Loading
Loading
Woods Cross
Terminal
Woods Cross
Terminal
Woods Cross
Terminal
Diesel Fire Pump No. 1
Diesel Fire Pump No. 2
Detroit Diesel Fire Pump
Plant Air Backup Compressor
Plant Air Backup Compressor
Plant Air Backup Compressor
6.80E-01
5.77E-0t
6.10E-02
2.85E-01
1.40E+00
4.18E+00
Boiler House Generator - Cummins 7.00E-02
Central Control Room Generator 1.87E-01
Generac Fire Water Pump North 2.87E-01
Administration NG Standby Gen. 1.02E-01
Administration NG Standby Gen. 1.03E-01
FuelOil
Ethanol
Kerosene
Gas Oil
External Floating Roof Tanks
HorizontalTanks
Internal FloaUng Roof Tanks
Vertical Fixed Roof Tanks
Terminal Submerged Loading 0.33
Gas/Vapor Streams
Light Liquid/Gas-Liquid Sfreams
PipeLine valves - HeaW Liquids
Light Liquid/Gas-Liquid Steams
HeaW Liquid Streams
Compressor Seals
Loading - Crude (86-2a)
Loading - Sulfur (17-2)
Tank 12
Wastewater System
Pipeline flanges
Vessel relief valves
Asphalt (45-5a)
Stove Oil (45-6a)
Kerosene (45-6b)
Loading Rack - Tanker Truck Fill 0.13
Equipment Leaks
Soil Remediation System 0.19
0.00
0.00
1.88
0.01
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 5-2
APPEITDI]X A.
HF Sinclair Woods Cross Refining [.LC / Reasonabh
Trinity Consultants December 2023
DESCRIPTIOIIS AilD 2OL7 AGTUAL
EMISSIONS
Control Technology Assessment
A-1
HF ilincblr
ilOrsd VOc sdE* only. o.on. slP RAcl
llF Sinchit
Norsd VOC SouE.3 Only - Ozon. SIP RACT
Datcrle0cn UtrD Rd|e Cffiitflt/llolt A.o Xor lroc ilor voc
14.38 )HT Reador Charo6 Heate,t9Hl 40.0 7nl o otq
,ntr wt De rcpaced m lgHz ffi raDng ot au
,TE B.d ld hh unt
a7 (o.uo2
o35 oma o oot
zJnl
lHl 6l
o.tr o.mo o-om
il-4.51 rt tl om o o50 omo
t-!
o25 o ot2 0 001
7 o(
U.5U
l9t o.oo5 U.UO4
IA6a l1 1 B6il.r Boil.rtll 89-3 MM8ffir o.2a 1.21
,oncr ratng ncrcased trom !9.3 to lco MMuu/hr tn zol9
lla.70 om I MF.M
I A11 n dn o/^o 19 521E-U
l a7)cw aT o oo20a lidxid ddi o 13 3-$E-M
fla7a cms o oo20/"liduid ddl 0.(1-21E{3
OI 9 32F-il
tla75 Cffi'11 0_m05%liouid fit 0.18
17 t 13.45 o.ooJ u.oa
)rth ln-T.nk Asphrh Heater
'uh ln.Tlnk kbhrft H.et.r
17 I
6AH3 U-
tau .a
o-l
Itt I
HF liincLi,
Nordd VOC SouE* Only - Ozon. SlP RACT
O.Grldoi lirllD idt!6mttito,lroc lto,toc
n 006
HP 1 n7Fn1 50Fi3 o ooo o ooo
I A))3 Fr. P0nb N6 I 66 D-13 393 HP 5 AOF{I 5 42E42 o oo2 o ooo
lla22!I.!Gl Fire PumD No.2 6SDla Eher. Eo.393 HP 5.77E{1 a.60E{2
Fir.A'lnBa6nM HP nm6
ll a ))1 ))o HP 2 isFi!) )7F4)o ooi o ooo
ll a223 {ahl Ar BrckuD Come.iid s*-la Emer Eo 2n HP l-a0E+00 1.12E41 0.00!0.000
I A))a ldil.r H60c. G.h.mtor - Crhhh.470 HP 7 00F-02 5 60F.03 o ooo o 000
1A223 )antal Cohaol Room Gah.rrtor 6M.l Emr Ed 380 HP ! 87Eit 1 lsE-02 0.001 0.000
11.A.223
i.n6y G.neralor (Gfferac Fire Wlter Pump
Ehcr. Eo.540 HP 2.A7E41 2.29E42 0.001 0.000
,a lt ln r 6rFit om0 o 600
ll a22a Ed l a2lo au MruMEfu I O3E{t 3 00E43 o ooo oom
!a
tdh..lil
Aa.mribnrt
20t, da .na.amnon aLAS tlad u&x dr.lva. h.lerir.l h ffirt-laoo
llOrlPtH brFr*ataiiei.ipxlod !,t7.'10
r{or0Pltil o*Lil(Ito)
APPENDTX B. $/TON COST ANALYSES
HF Sinclair Woods Cross Refining LLC / Reasonable Available Control Technology Assessment
Trinity Consultants December 2023 B-t
B..L tor Coat
Frctor
Sindair D.r CEM
1 O s8il 7o/" ol PE ba3ad o monilorino 6roerirn@
7 560 sor'" of PE baiad dl moniioino rxo6rirnco
189-3aa
atlon 42 336 15 ofPE(ba3ad dr monitoino oxD6den@
ltion lDll 42.336
fohl Dlnd Co.t (I)cl 2t i.6ao
ndinct ln.trlation Coatr
:ngin.cring and Poiccl Managcment,
lonslruclion end Field Expsnsca, Contncior
r6€s, Stertup Expens.s, P€rfomanco Tasts,
$42.336 15% of PE(E3iimal6 be!€d ff monitorino sx@rian@
fot l lndinct Cost 42.335
fobl lnstallcd Cost (TlC)254.015
, Lebor 3 36.500 iOO h6',^ ... vrar.t 6373/hi tin.hrd.r h.h.fir.)
Irw metadal3
t Parts $
142t
HF Sincl.ir Wood3 Cro3a Rclin.ry
CEtS lnd.ll.tion rnd Monitoring Cost. tor NOrrnd VOC
A!aumptlonr:
I EPA eltimat€ - SCR @st manual speadshrct 2016
Shrlter snd cquipment @sts provided by HF Sinclair
CPI - 1.26 lhrough Nov€mbcr 2023 (adiustld for inlletion using 2017 dollar3)
CElrlS - Co3t pc. ion monitorlng
HF Sinclair Woods Cross Refinery
Cost Analysis to lnstall and Operate lncinerator
lncinerator Factor Basis for Cost
and Factor
)irect Costs:
rased Eouioment:
)rimarv and Auxiliarv Eouioment (PE)$ 3.552.000 Median estimate from Table 7-5 MARAMA and CPI of 1.48lor 2007 lo 2023
ales Tax s 213.120 6% of PE oTC-LADCO 2008
:reioht s 177.600 5% of PE oTC-LADCO 2008
otal Purchased Eouioment Cost {PECI I 3-942.720
iract lnstallation
ilectrical. Pioino. lnsulation and Ductwork s 1.577.088 {0% of PEC oTC-LADCO 2008
Iotal Direct lnstallation (Dl)3 't.577.088
fotal Direct Cost (DC)s 5.519.808
ndireci lnstallation Costs
:nglneenng anO l.rojecl Management,
lonstruction and Field Expenses,
lontractor Fees, Startup Expenses,
)erformance Tests. Continoencies s 2.40s.059 i1% of PEC oTC-LADCO 2008
Iotal lndirect Cost $ 2.405.059
fotal lnstalled Cost (TlC)s 7.924.867
r'OC Emissions Before Control, tn/vr o.4 2017 SLEIS
i6nfr6l Ff6.iencv 1ol"\9!
/OC Emissions After Control, tn/yr o.oo:
r'OC Emission Reduction. tn/vr 0.4!
Annual Costs. S/vear (Direct + lndirectl
Direct Costs
oeratino Labor s 396.243 5% of caoitol cost
law materials 5
rcement Parts s 237.746 3% of caoitol cost
lotal Direct Costs. S/vear $633.989
ndirect Costs
Iverhead $ 237.746 l0% of labor costs
laxes. lnsurance. and Adminastration $ 316,995 4o/o of lolal installed cost
:aoitol Recoverv s 1.041.882 1Oo/.- 15 vears. CRF-.13147
fotal lndirect Costs. S/vear $ 1.596.623
otal Annual Cost s 2.230.612
]ost Effectiveness. S oer ton VOC reductior s 4.598.252.67
Assumption:
Used low end of cost investment estimate as presented in Assessment of Control Technology Options
For Petroleum Refineries in the Mid-Atlantic Region Final Report, January 2007
CPI - 1.48 lrom 2007 to 2023
HF Sinclair Woods Cross Reflnery
Cost Analysis to lnstall and Operate Vapor Recovey System - Carbon Adsoprtion
Assumptlon:
Used low end of cost investment estimate for purchased equipment to be conservative
CPI lnflation Calculator - https:/ ,vww.bls.gov/data/inflation_calctlator.hlm
CPI - 1.48 for January 2007 lo December 2023
vRs FactoI Basls for Cost
and Factor
)lfect u63ta:
)uchased EoulDment:
rimarv and Auxiliarv EouiDment (PE)$ 498.760 vledian estimate from Table 7-5 MARAMA and CPI of 1.48 for 2OO7 lo 2023
Sales Tax s 29.S26 60/o of PE OTC-LADCO 2OO8
:reioht $ 24,938 5olo of PE oTC-LADCO 2008
lotal Purchased Equlpment Cost (PECI $553.624
)lrect lnstallatlon
)al. Pioino. lnsulation and Ductwork $ 221.449 t0% of PEC OTC-LADCO 2OO8
l-ota! Diiect Installatlon (D!)22'.t.49
fotal Dlrect Cost IDC)775-O73
ndlrect Installatlon Costs
:ngineering and Project Management,
)onslruclion and Field Expenses,
]ontractor Fees, Startup Expenses,
)erformance Tests. Continoencies $ 337.710 1% of PEC oTo-LADCO 2008
fohl lndlrect Cost s 337.710
fotal lnstalled Cost filC)3 l.t t 2.783
/OC Emissions Before Control, tn/vr 0.49 2017 SLEIS
)ontrol Efficiencv (%)95
/OC Emissions After Control. trvvr 0.02
r'OC Emission Reduction. tn/vr o.47
Annu.l C6rls 3rvaar IDI?eel + lndliacll
olrect Costs
Coeratino Labor s 55.639 5olo of caDitol cost
Raw materials s
ReDlacement Parts $33.384 3% of caDitol cost
folal Dlrect Costs- 3lvear 3 89-023
lndlreci Costs
Sverhead $33,384 )0% of labor costs
Tares. lnsurance. and Adminisirelion $ 44,511 t% of total installed cost
3apitol Recoverv $146,298 'l0o/o. 1 5 vears. CRF-. 1 3147
fotal lndlrect Costs. llrvear 3 224.192
fotal Annual Cost s 313.215
lost Effectiveness. $ Der ton VOC reductior $ 672.E57.47
HF Sinclair
Cost to fire all units on natural 5as,2023
Purchased NaturalGas:
NG Cost: $9.99/MMBtu - company records
NG Cost: $8.69/MSCF (converted to MMscf using measured 1 149.42 BTU/SCF - purchased nat gas)
Usage: 5,375,864 MSCF (total refinery fuelgas and purchased naturalgas)
Usage: 6,179,125 MMBTU (based on a measured 1149.42 BTU/SCF - purchased nat gas)
Annual Cost: $46,716,258 (NG Cost $8.69/MSCF * Usage 5,375,864 MSCF = $46,716,258.2)
Emissions from 2017 Annual lnventory
Process Unit VOC TPY NOX TPY
4H1 0.719 5.14
6H1 1.229 21.40
6H2 0.192 3.34
6H3 0.445 7.76
7H1 0.033 0.53
7H3 0.519 9.04
8H2 1.760 9.83gHl 0.195 3.40
9H2 0.049 0.09
10H1 0.184 3.20
11Hl 0.332 5.78
12H1 0.623 7.31
13H1 0.053 0.93
19H1 0.945 7.01
20H2 0.838 6.28
20H3 0.347 1.59
24H1 0.628 2.57
25H1 0.003 0.02
Boiler 4 0.254 4.41
Boiler 5 0.174 0.19
Boiler 8 0.790 0.58
Boiler I 1.472 1.91
Boiler 10 1.498 0.83
Boiler 11 1.210 0.24
Total 14.49 103.37
3,223,522.1 451,935.2
Actual
Purchased
Actual
Burned
Actual
S/MMBTU
GL Account
Total $
GL Account
S/MMBTU
lan2023 173,80(16't,857 $54.68 $ 9,114,851 $ 52.44
Feb 153,70C 148,768,$ 13.96 $ 2.277.326 $ 14.82
Mar 79,80C 85,534 $ 5.99 $ 745,774 $ 9.35
Apr 163,50(155,471 $4.28 $ 715,700 g 4.38
May 141,50(149,176 $2.60 $639,263 $4.52
Jun 137,50(143,457 $ 2.71 $ 1 19,192 $ 0.87
Jul 167.00(167.1',t1 $ 3.92 $692,t43 $ 4.1s
Aug 174,50(151,714 $4.36 $656,480 $ 3.76
sep 122,00C 111,57e $3.45 $ 455,819 $ 3.74
Oct 114,00(153,79e $ 3.99 $539,554 $ 4.73
Nov #Dtv/o!
Dec #Dtv/o!
l-otal 1,427,30(.1,428,463,$9.9S $15,956,500.59 #Dtv/o!
Th@ghFn
- Sutu. Md.dla
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71.87 1.55
58.70 0.91
68.03 2.?6
66.s0 1.65
u.52 3.30
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67.'t5 1.40
10s.49 ,1.04
63.5 0m
80.16 3.a7
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56.67 7-@.
a3.n 205
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15.86 *2r7 r.61
14.97 26613 3.6,i
9,4 119',11 0.34
15.62 1',t034 Z2a
10.02 15810 0.93
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33,50 n880 L12
271 19007 5.6
20.15 15594 0.n
11.33 28630 rA2
1Z*5 24/lli;2 3,21
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21.22 2023 3.16
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15.94 1893 r.87
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225 NA
0.95 l.lA
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215 M
5,06 NA
0.79 NA
1.11 NA
3.32 NA
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9.53 NA
3.20 NA
17.13 NA
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304,101.00 1.1260
304,101.00 2.5472 5 119,386.76
304,101.00 0.2375 s 1,279,521.58
152,0@.00 1.5547 5 97,142.95
152,000.00 0.484 s 234,438.41
NA 2.4456 NA
1S2,@0.0O 1.5947 9 89,693.73
152,000.00 3.5352 s 42,996.27
152,000,00 0.5369 3 283,722.L7
454,357.00 0.7122 s 637,971.43
319,126.60 2.247 s 141,915.07
77,20.,20 0.0000
307,0@.00 d68 s 46044.58
152,000.00 2,2tt7 s 58,725.55
273,000.00 r2.o29L $ 22,694.94
52,5m.00 1.3115 $ /O,030.67
52,s@.00 0.9589 s s4,7A.38
$/ton VOC rcmval for Tanks 145 & 146 ba$d on SCAQMo avrra8. dom ard instalhtion @str (540,0@565,000) for tank with diamctrrs brtwan 30 - 50 f.ct.
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on {ffit $cu
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baclSit:1llMryddilh.nd
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kunpdoB:
r17 md Eddon Edmb
Cdlo lmd lFR otr FLd Rod
Rang6. $240,m0 - t480,m Refer.ncer Europ..n CmdBion, ldsgdd Poldd Pr.v6ilim .nd Contol Repod, Reforcnc. Documcnt on BBt Av.il.Ue T6chniw6 for lVlncrd Oi and t Rsfncn6, 2m3
Mc.n - 3m,4S m3S
Mdn- 3479.3S.$ 4175 m3doll.Etor.lldcdinIlT(CPl 1.33)
M6.n - ES1.951.S 2023$ 2m3.bllaEto r6i6d cdin 2023 (CPl 1.67)
HF Slnclair Woods Cross Refinery
Cost Analysls to lnstall and Operate Vapor Recovery System (Garbon Adsoprtlon)
Assumption:
Used low end of cost investment estimate for purchased equipment to be conservative
At upper end of cost investment estimate presented in Table 7-5, $ ton effectiveness is $4,368,103 $/ton VOC reduced
vRs Factor Basis for Cost
and Factor
L,rect gosts:
Puchased Eouioment:
)rimarv and Auxiliarv Eouioment (PE)$ 424.620 Median estimate -Table 7-5 MARAMA and CPI of 1.26 trom 2017 lo2023
Sales Tax s 25.477 8% of PE oTC-LADCO 2008
:reioht $ 21.231 5olo of PE OTC-LADCO 2OO8
fota! Purchased EouiDment Cost (PEG)$17'.t,328
Direct lnstallation
llectrical. Pioino. lnsulation and Ductwork $ 188.531 {0% of PEC oTC-LADCO 2008
fotal Direct lnstallation (Dll $ 1EE.531
fotal Direct cost (Dc)$659,859
ndirect lnstallation Costs
-ngineering and Project Management,
Sonstruction and Field Expenses,
Sontractor Fees, Startup Expenses,
)erformance Tesls- Continoencies $ 287.5't 0 i1% ot PEC orc-tADco 2008
lotal lndirect Gost s 287.510
fotal lnstalled Cost filc)$ 947.370
/OC Emissions Before Control. tn/Vr 0.4!2017 SLEIS
Sontrol Efficiencv (%)8C
'/6C trmiceiane Affar e^nlr l tnfur 0.1
r/OC Emission Reduction. tn/vr 0.3€
annlrtl (;6al*- srvett lLITecl + lndt?eell
Direct Costs
eratinq Labor s 47.368 5% of caoitol cost
Qaw malarialc $
leolacement Parts $ 28,421 i, of capitc cost
lotal Direct Costs. $rvear $75.790
ndlrect Costs
Jverhead $ 28.421 i0% o, labor costs
faxes. lnsurance. and Administration $ 37,895 t% of total installed cost
,itol Recovery s 124.5s1 l0%. 15 vears. CRF-.1 3147
Total lndirect Costs, $ryear 3 190.867
lotal Annual Cost s 266.656
lost Effectiveness. S oer ton VOC reduction s 6E0.245.27
Cort to R.trofit Emergency NG Englner wlth Oxld.tlon C.trlyit
HF Slnchlrwood! Croc. Rcfinery
Uncontnolled Conhlled EmLslm Reductlon Cott Effectlyenc.s
R.Ong OxcrtRefoltt Oxc.tRetroflt VOC2017 VOC 2017 YOC ($non)
Dler.l Em.tg.ncy Equlpm.nt (HP) Clpltol Co3t Annu.l Co.t TPY TPY TPY VOC
224HPG€neraeMclsoAdmlnistrationBldgEast 224.0 $ 74,617 $ 23,570 0.0030 0.0009 0.002 $ 36,032,129
224 HP Gonorac MG150 Administration Bldg l,\bsl 224.0 i 7,1.,617 $ 23,579 0.0030 0.000S 0.002 $ 35,872,79S
AGaumpdona:
Sourcs - Memorandom - Cmtrol Costs for Eiisting Siationay Sl Rico, June 29, 2010
Generac was unable/hesitant to pmvid6 adual cost €stimates.
Assumed maintenance and labor cosl6 to be unchanged
70olo control e{Iioioncy with CO oxidation catalyst (EPA)
lf td.lrCo.a. b ihar& lrlmo Uall{ txll
Aaa-laaaia:Mbnarjdtt,.iACdb-d6 U.iaQr*att060prhtwD.cddilFu*adi,lF8h.L,h2da id.+d/tu
HF Sinclair Woods Cross Refinery
NO, Cost Analysis to Upgrade Process Heaters to ULNB from LNB - 4Hl (39.9 MMBtu/hr)
ULNB Factor Basis for Cost
Upqrade and Factor
Direct Costs:
Puchased Eouioment:
Primarv and Auxiliarv Eouioment (PE)$ 468.650 Estimate - $36.050 per burner. 13 burners
Sales Tax $ 28.119 6% of PE oTC-LADCO 2008
Freioht $ 23.433 5% of PE oTC-LADCO 2008
fotal Purchased Eouioment Gost (PECI $ 520.202
Direct lnstallation
Electrical, Pipinq, lnsulation and Ductwork $ 208,081 4Ooh of PEC oTC-LADCO 2008
Iotal Direct lnstallation (Dll $ 208,081
Iotal Direct Cost (DC)s 728.282
lnd irect Installation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests. Continoencies $ 317,323 61 % of PEC oTC-LADCO 2008
Total lndirect Cost $ 317.323
Total lnstalled Cost (TlC)$ 1.045.605
NO, Emissions Before Control, lb/MMBtu o.0402
NO, Emissions Before Control, tn/yr 5.14 2017 SLEIS
Control Efficiencv (%)60
NO, Emissions After Control, tn/yr 2.06
NO" Emission Reduction, tn/yr 3.08
Annual Costs. $/vear (Direct + lndirectl
Direct Costs
Operatino Labor $ 31.368 3o/o of capitol cost
Raw materials $
Reolacement Parts $ 31,368 3% of capitolcost
Total Direct Costs. $/vear $ 62.736
lndirect Costs
Overhead $ 18.821 60% of labor costs
Taxes, lnsurance, and Administration $ 41.824 4% of total installed cost
Caoitol Recoverv $ 137,466 10o/o,15 years, CRI 13147
Total lndirect Costs. $/vear 198.111
fotalAnnua! Cost 260,847
Cost Effectiveness, $ per ton NO,, reductior $ 84,580.77
HF Sinclair Woods Cross Refinery
NO, Cost Analysis to Upgrade Process Heaterl to ULNB - GHl (54.7 MMBtu/hr)
ULNB Factor Basis for Cost
Upgrade and Factor
Direct Costs:
Puchased Equipment:
Primarv and Auxiliarv Equioment (PE)$ 432,600 Estimate - $36,050 per burner; 12 burners
Sales Tax $ 25,956 6% of PE OTC-LADCO 2OO8
Freioht $ 21,630 5o/o of PE oTC-LADCO 2008
Total Purchased Equipment Cost (PEC)$ 480.{86
Direct lnstallation
Electrical. Pioino. Insulation and Ductwork s 192.074 40% of PEC oTC-LADCO 2008
Total Direct lnstallation (Dl)$ 192,074
Total Direct Cost (DC)$ 672.260
lndirect lnstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Contingencies $ 292,913 61% of PEC oTo-LADCO 2008
Total lndirect Gost $ 292.913
Total lnstalled Cost (TlC)$ 965.174
NO, Emissions Before Control, lb/MMBtu 0.098
NO, Emissions Before Control, tn/yr 21.40 2017 SLEIS
Control Efficiencv (%)60
NO, Emissions After Control, tn/yr 8.56
NO, Emission Reduction, tn/yr 12.84
Annual Gosts. $/vear (Direct + lndirect)
Direct Costs
Ooeratino Labor $ 28,95s 3o/o of caoito! cost
Raw materials S
Replacement Parts $ 28,955 3o/o of caoitol cost
Total Direct Costs. $/year $ 57.910
lndirect Gosts
Overhead $ 17,373 60% of labor costs
Taxes. lnsurance. and Administration $ 38.607 4% ot total installed cost
Capitol Recovery $ 126,891 10o/o. 15 vears. CRF-. 1 3147
Total lndirect Costs. $/vear s 182.871
Total Annual Cost s 240.782
Cost Effectiveness, $ per ton NO* reductior $ 18,752.49
HF Sinclair Woods Cross Refinery
NO, Cost Analysis to Upgrade Process Heaters to ULNB - 6H2 (12 MMBtu/hr)
ULNB Factor Basis for Cost
Upqrade and Factor
Direct Costs:
Puchased Equipment:
Primarv and Auxiliarv Eouioment (PE)$ t 08,150 :stimate - $36,050 per burner; 3 burner
Sales Tax $ 6,489 6% of PE oTC-LADCO 2008
Freioht $ 5,408 5% of PE orc-LADco 2008
Total Purchased Eouioment Cost (PECI $ '120,047
Direct Insta!!ation
Electrical, Piping, !nsulation and Ductwork $ 48,019 40% of PEC oTC-LADCO 2008
Tota! Direct !nstallation (Dl)$ 48,019
Total Direct Cost (DCl $ 168,065
!ndirect lnstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Continqencies $ 73.228 61% of PEC oTC-LADCO 2008
Total lndirect Cost $73,228
Total lnstalled Cost fflC)$ 241.293
NO, Emissions Before Control, lb/MMBtu 0.098
NO, Emissions Before Control, tn/yr 3.34 2017 SLEIS
Control Efficiency (%)60
NO, Emissions After Control, tn/yr 1.34
NO,, Emission Reduction, tn/yr 2.00
Annua! Costs, $/year (Direct + lndirect)
Direct Costs
Coeratino Labor $ 7,239 3o/o of caoitol cost
Raw materials $
Reolacement Parts $ 7,239 3o/o of caoito!cost
Iotal Direct Costs. $/year $ 14,478
Indirect Costs
Overhead $ 4,343 60% of labor costs
Taxes, lnsurance, and Administration $ 9,652 4% of total installed cost
Capitol Recovery $ 31.723 10%. 15 vears. CRF-.1 3147
Total lndirect Costs, $/vear $ 46,718
Tota! Annua! Cost s 60.195
Cost Effectiveness, $ per ton NO, reductior $ 30,037.67
HF Sinclair Woods Cross Refinery
NO, Cost Analysis to Upgrade Process Heaters to ULNB - 6H3 (37.7 MMBtu/hr)
ULNB Factor Basis for Gost
Upqrade and Factor
Direct Costs:
Puchased Equioment:
Primarv and Auxiliarv Eouioment (PE)$ 144,200 Estimate - $36,050 per burner; 4 burners
Sales Tax $ 8,6s2 6% of PE oTC-LADCO 2008
Freioht $ 7.210 5% of PE oTC-LADCO 2008
Total Purchased Eouioment Gost (PECI $ 160.062
Direct lnstallation
Electrical, Piping, !nsulation and Ductwork $ 64.025 4O% of PEC orc-LADco 2008
Total Direct lnstallation (Dl)$64.025
Total Direct Cost (DC)$ 224.087
lnd irect I nstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Continqencies $ 97,638 61% of PEC oTC-LADCO 2008
Tota! lndirect Cost $ 97.638
Total lnstalled Cost fflC)$ 321,725
NO, Emissions Before Control, lb/MMBtu 0.098
NO, Emissions Before Control, tn/yr 7.76
Control Efficiencv (%)60
NO, Emissions After Control, tn/yr 3.10
NO, Emission Reduction, tn/yr 4.66
Annual Costs, $/year (Direct + lndirect)
Direct Costs
Ooeratino Labor $ 9.652 3o/o of capitol cost
Raw materials s
Replacement Parts $9,652 3% of capitol cost
fota! Direct Costs. $/vear $ 19.303
lndirect Costs
Overhead $ 5,791 60% of labor costs
Taxes, lnsurance, and Administration $ 12,869 4% of total installed cost
Capitol Recovery $ 42,297 10o/o,15 yeat s. CRF-.13147
Iotal lndirect Costs. $/year $60,957
fotalAnnual Cost $ 80,261
Cost Effectiveness, $ per ton NO, reductior $ 17,238.11
HF Sinclair Woods Cross Refinery
NO, Cost Anatysis to Upgrade Process Heaters to ULNB -7H1 (4.4 MMBtu/hr)
ULNB Factor Basis for Cost
Upqrade and Factor
Direct Costs:
Puchased Eouioment:
Primarv and Auxiliarv Eouioment (PE)$ 36,050 Estimate - $36,050 per burner; 1 burner
Sales Tax $ 2,163 6% ot PE oTC-LADCO 2008
Freioht $ 1,803 5% of PE oTC-LADCO 2008
Total Purchased Equipment Cost (PEC)$ 40.016
Direct !nstallation
Electrical, Pipinq, lnsulation and Ductwork $ 16,006 40% ot PEC oTC-LADCO 2008
Total Direct lnstallation (Dl)$ 16.006
Total Direct Cost (DC)$56,022
lnd irect I nstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Continqencies $ 24,409 61% of PEC OTC-LADCO 2OO8
fotal lndirect Cost $24,409
fotal lnstalled Cost (TlC)$80,431
NO, Emissions Before Control, !b/MMBtu 0.098
NO, Emissions Before Control, tn/yr 0.53 2017 SLEIS
Control Efficiencv (%)60
NO, Emissions After Control, tn/yr 0.21
NO, Emission Reduction, tn/yr 0.32
Annual Costs, $/year (Direct + lndirect)
Direct Costs
Operatinq Labor $ 2,413 3o/o of capitol cost
Raw materials $
Replacement Parts $ 2,413 3o/o of caoitol cost
fotal Direct Costs. $/vear $4,826
lndirect Costs
Overhead $ 1,448 60% of labor costs
faxes, lnsurance, and Administration $ 3.217 4% of total installed cost
Capitol Recovery $ 10.574 10%. 15 vears. CRF-.1 3147
Iota! lndirect Costs. $/vear $ 15.239
Total Annual Cost $ 20.065
Cost Effectiveness, $ per ton NO, reductior $ 63,097.99
HF Sinclair Woods Cross Refinery
NO, Cost Analysis to Upgrade Process Heaters to ULNB - 7H3 (33.3 MMBtu/hr)
ULNB Factor Basis for Cost
Upgrade and Factor
Direct Costs:
Puchased Equipment:
Primarv and Auxiliarv Equipment (PE)$ 144,200 :stimate - $36,050 per burner, 4 burnerr
Sales Tax $ 8,652 6% of PE oTC-LADCO 2008
Freiqht $ 7,210 5% of PE orc-LADCO 2008
Total Purchased Equipment Gost (PEC)$ 160,062
Direct Installation
Electrical. Pipinq. lnsulation and Ductwork $ 64,025 40% of PEC oTC-LADCO 2008
Total Direct lnstallation (Dl)$ 64,025
Total Direct Cost (DC)$ 224.087
lndirect lnstallation Gosts
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Contingencies $ 97,638 61% of PEC oTC-LADCO 2008
Total lndirect Cost $ 97.638
Total lnstalled Cost (TlC)$ 321,725
NO, Emissions Before Control, lb/MMBtu 0.098
NO, Emissions Before Control, tn/yr 9.04 2017 SLEIS
Control Efficiencv (%)60
NO, Emissions After Control, tn/yr 3.62
NO, Emission Reduction, tn/yr 5.42
Annual Gosts. $/vear (Direct + lndirect)
Direct Costs
Operatino Labor $ 9,652 3o/o of capitol cost
Raw materials $
Reolacement Parts $ e,652 3% of capitol cost
Tota! Direct Costs. $/vear $ 19,303
lndirect Costs
3verhead $ 5.791 60% of labor costs
Iaxes, lnsurance, and Administration $ 12,869 4o/o of total installed cost
3aoitol Recoverv $ 42.297 10%. 15 vears. CRF-.1 3147
Iotal lndirect Costs. $/vear $ 60,957
IotalAnnual Cost s 80.261
Oost Effectiveness, $ per ton NO* reductior $ 14,797.32
HF Sinclair Woods Cross Refinery
NO, Gost Analysis to Upgrade Process Heaters to ULNB - gHl (8.1 MMBtu/hr)
ULNB Factor Basis for Cost
Upqrade and Factor
Direct Costs:
Puchased Eouioment:
Primarv and Auxiliarv Eouioment (PE)$ 36,050 Estimate - $i t6.050 per burner: 1 burne
Sales Tax $ 2,163 6% of PE oTC-LADCO 2008
Freioht $ 1,803 5o/o of PE oTC-LADCO 2008
Total Purchased Eouioment Gost (PEC)$ 40,016
Direct lnstallation
Electrical, Piping, lnsulation and Ductwork $ 16.006 40% of PEC oTC-LADCO 2008
fota! Direct lnstallation (Dl)$ 16.006
fota! Direct Cost (DC)$ 56,022
lndirect lnstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Continqencies $ 24,409 61% of PEC oTC-LADCO 2008
fotal lndirect Cost $ 24,409
fotal lnstalled Cost fflCl $ 80,431
NO, Emissions Before Control, lb/MMBtu 0.098
NO, Emissions Before Control, tn/yr 3.40
3ontrol Efficiencv (%)60
NO, Emissions After Control, tn/yr 1.36
NO, Emission Reduction, tn/yr 2.04
Annual Costs. $/vear (Direct + lndirect)
Direct Gosts
Ooeratino Labor $ 2,413 3o/o of capitol cost
Raw materials s
Replacement Parts $ 2,413 3o/o of capitol cost
fotal Direct Costs. $/vear $ 4.826
lndirect Costs
Overhead $ 1.448 600/o of labor costs
faxes, lnsurance, and Administration $ 3.217 4% of total installed cost
Capitol Recovery $ 10.574 10%. 15 vears. CRF-. 1 3147
Total lndirect Costs, $/year $ 15.239
TotalAnnual Cost $ 20.065
Cost Effectiveness, $ per ton NO, reductior $ 9,835.86
HF Sinclair Woods Cross Refinery
NO, Cost Analysis to Upgrade Process Heaters to ULNB - 9H2 (4.1 MMBtu/hr)
ULNB Factor Basis for Cost
Upqrade and Factor
Direct Costs:
Puchased Eouioment:
Primarv and Auxiliary Equipment (PE)$ 36,050 Estimate - $36.050 per burner; 1 burnet
Sales Tax $ 2,163 6% of PE oTC-LADCO 2008
Freioht $ 1,803 5% of PE oTC-LADCO 2008
fotal Purchased Eouipment Cost (PEC)$ 40.016
Direct Installation
Electrical. Pioino. lnsulation and Ductwork $ 16,006 40o/o of PEC oTC-LADCO 2008
Total Direct lnstallation (Dl)$ 15,006
fotal Direct Cost (DC)$56,022
!ndirect lnstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Contingencies $ 24.409 61% of PEC oTC-LADCO 2008
Total lndirect Gost $24,409
Total lnstalled Cost (TlC)$ 80,431
NO, Emissions Before Control, lb/MMBtu 0.098
NO, Emissions Before Control, tn/yr 0.09 2017 SLEIS
3ontrol Efficiency (%)60
NO, Emissions After Control, tn/yr 0.04
NO, Emission Reduction, tn/yr 0.05
Annual Costs. $/vear (Direct + lndirect)
Direct Costs
Cperatino Labor $ 2,413 3o/o of capitol cost
Raw materials $
Replacement Parts $ 2,413 3o/o of capitol cost
fotal Direct Costs. $/year $4,826
ndirect Costs
Cverhead $ 1.448 60% of labor costs
faxes, lnsurance, and Administration s 3.217 4o/o of total installed cost
Capitol Recovery $ 10,574 10%. 15 vears. CRF-.1 3147
fotal lndirect Costs, $/year s 15.239
fotalAnnual Cost $20,065
Cost Effectiveness, $ per ton NO* reductior $ 371,577.04
HF Sinclair Woods Cross Refinery
NO, Cost Analysis to Upgrade Process Heaters to ULNB - 10Hl (13.2 MMBtu/hr)
ULNB Factor Basis for Cost
Upqrade and Factor
Direct Costs:
Puchased Equipment:
Primarv and Auxiliarv Eouioment (PE)$ 216,300 istimate - $36,050 per burner; 6 burner:
Sales Tax $ 12,978 60/o of PE oTC-LADCO 2008
Freioht $ 10,815 5% of PE OTC-LADCO 2OO8
Total Purchased Eouioment Cost (PEC)$ 240,093
Direct lnstallation
Electrical, Piping, lnsulation and Ductwork $ 96,037 40o/o of PEC oTC-LADCO 2008
Tota! Direct lnstallation (Dl)$ 96,037
Total Direct Cost (DCl $ 336,130
lnd irect lnstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Continqencies $ 146.457 61% of PEC oTC-LADCO 2008
Total lndirect Cost $ 146.457
Total lnstalled Cost (TlC)$ 482.587
NO, Emissions Before Control, lb/MMBtu 0.098
NO, Emissions Before Control, tn/yr 3.20 2017 SLEIS
Control Efficiencv (%)60
NO, Emissions After Control, tn/yr 1.28
NO, Emission Reduction, tn/yr 1.92
Annual Costs. $/vear (Direct + lndirect)
Direct Costs
Operatino Labor $ 14.478 3% of capitol cost
Raw materials B
Replacement Parts $ 14.478 3o/o of capitol cost
Total Direct Costs. $/vear $ 28.955
lndirect Costs
Cverhead $ 8,687 6OYo of labor costs
Taxes, lnsurance, and Administration $ 19,303 4o/o of total installed cost
Capitol Recovery $ 63,446 10o/o, 15 years, CRF-.1 3147
lotal lndirect Costs, $/year $ 91,436
IotalAnnualCost $ 120,391
Cost Effectiveness, $ per ton NO, reductior $ 62,703.63
HF Sinclair Woods Cross Refinery
NO, Cost Analysis to Upgrade Process Heaters to ULNB - 11Hl 124.2MMBtu/hr)
ULNB Factor Basis for Cost
Upqrade and Factor
Direct Costs:
Puchased Equioment:
Primarv and Auxiliarv Equipment (PE)$ 144.200 :stimate - $36,050 per burner; 4 burnen
Sales Tax $ 8.652 6% of PE OTC-LADCO 2OO8
Freioht $ 7,210 5o/o of PE oTC-LADCO 2008
Total Purchased Equipment Cost (PEC)$ 160.062
Direct lnstallation
Electrical. Pipino. lnsulation and Ductwork $ 64,025 40o/o of PEC oTC-LADCO 2008
Total Direct lnstallation (D!)$64,025
Total Direct Cost (DC)$ 224,087
!ndirect lnstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Contingencies $ 97.638 61% of PEC oTC-LADCO 2008
Total lndirect Cost $ 97.638
Total lnstalled Cost (TlC)$ 321,725
NO* Emissions Before Control, lb/MMBtu 0.098
NO, Emissions Before Control, tn/yr 5.78 2017 SLEIS
Control Efficiencv (%)60
NO, Emissions After Controt, tn/yr 2.31
NO, Emission Reduction, tn/yr 3.47
Annual Costs. $/vear (Direct + lndirect)
Direct Costs
Operatino Labor $ 9,652 3o/o of capitol cost
Raw materials $
Reolacement Parts $ 9,652 3o/o of capitol cost
Total Direct Costs. $/vear $ 19,303
lndirect Costs
Overhead $ 5.791 60% of labor costs
Taxes, lnsurance, and Administration $ 12.869 4o/o of total installed cost
Capitol Recovery $ 42.297 10%. 15 vears, CRF-.13147
Total lndirect Gosts. $/vear $ 60.957
TotalAnnual Cost $ 80.261
Cost Effectiveness, $ per ton NO, reductior $ 23,143.21
HF Sinclair Woods Cross Refinery
NO, Cost Analysis to Upgrade Process Heaters to ULNB - 13Hl (6.5 MMBtu/hr)
ULNB Factor Basis for Cost
Upqrade and Factor
Direct Costs:
Puchased Equipment:
Primary and Auxiliary Equipment (PE)$ 72,100 :stimate - $36,050 per burner; 2 burnerr
Sales Tax $ 4,326 6% of PE OTC-LADCO 2OO8
Freioht $ 3,605 5% of PE oTC-LADCO 2008
Total Purchased Equipment Cost (PECI $ 80.031
Direct Installation
Electrical. Pioino. lnsulation and Ductwork $ 32,012 40% of PEC orc-LADco 2008
Total Direct !nstallation (Dl)$ 32,012
Total Direct Cost (DCl $ 112,043
lndirect lnstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Contingencies $ 48,819 61% of PEC oTC-LADCO 2008
Total lndirect Cost $ 48,819
Total lnstalled Cost (TlC)$ 160,862
NO* Emissions Before Control, lb/MMBtu 0.098
NO* Emissions Before Control, tn/yr 0.93 20,17 SLEIS
Control Efficiencv (%)6C
NO, Emissions After Control, tn/yr 0.37
NO, Emission Reduction, tn/yr 0.5€
Annual Costs, $/year (Direct + lndirect)
Direct Costs
Operatinq Labor $ 4,826 3o/o of caoitol cost
Raw materials $
Reolacement Parts $ 4,826 3o/o of caoitol cost
Tota! Direct Costs, $/year $ 9.652
lndirect Costs
Overhead $ 2.896 60% of labor costs
Taxes. lnsurance. and Administration $ 6.434 4o/o of total installed cost
Caoitol Recovery $ 21.149 10%. 15 vears. CRF-.1 3147
Total lndirect Costs. $/vear $ 30.479
fotalAnnual Cost $ 40.130
Cost Effectiveness, $ per ton NO, reductior $ 71,918.14
HollyFrontier Woods Cross Refinery
NO, Cost Analysis to Upgrade Process Heaters to ULNB - 68H2 and 68H3 (0.8 MMBtu/hr)
ULNB Factor Basis for Cost
Upqrade and Factor
Direct Costs:
Puchased Equipment:
Primarv and Auxiliarv Equipment (PE)$ 36,050 Estimate - $36,050 per burner; 1 burnet
Sales Tax $ 2.163 6% of PE OTC-LADCO 2OO8
Freiqht $ 1,803 SYo of PE oTC-LADCO 2008
Total Purchased Equipment Cost (PEC)$ 40.0{6
Direct lnstallation
Electrical. Pipinq, lnsulation and Ductwork $ 16,006 40% of PEC oTC-LADCO 2008
Total Direct lnstallation (D!)$ 16.006
Tota! Direct Cost (DC)$ 56,022
lndirect lnstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Contingencies $ 24,409 61% of PEC oTC-LADCO 2008
Total lndirect Gost $24,409
Total lnstalled Cost filC)$ 80.431
NO, Emissions Before Control, lb/MMBtu 0.098
NO, Emissions Before Control, tn/yr 0.07 2017 SLEIS
Control Efficiency (%)60
NO, Emissions After Control, tn/yr 0.03
NO, Emission Reduction, tn/yr 0.04
Annual Costs. $/year (Direct + lndirect)
Direct Costs
Ooeratino Labor $ 2,413 3% of caoitol cost
Raw materials $
Replacement Parts $ 2,413 3%o of caoitol cost
Total Direct Costs. $/vear $4,826
lndirect Costs
Overhead $ 1,448 60% of labor costs
Taxes, lnsurance, and Administration $ 3,217 4% of total installed cost
Caoitol Recoverv $ 10.574 10%. 15 vears, CRF-. 1 3147
Total lndirect Costs, $/year $ 15.239
TotalAnnual Cost $20.065
Cost Effectiveness, $ per ton NO, reductior $ 477,741.91
VOC Cost Analysis to Upgrade Process Heaters to ULNB - 4Hl
39.9 MMBtu/hr
ULNB Factor Basis for Cost
Uoorade and Factor
Direct Costs:
Puchased Equipment:
Primarv and Auxiliarv Equioment (PE)$ 468,650 Estimate - $36,050 per burner; 13 burners
Sales Tax $ 28.119 6% of PE oTC-LADCO 2008
reioht $ 23,433 5% of PE oTC-LADCO 2008
Iotal Purchased Eouioment Cost (PEC)$ 520.202
Direct lnstallation
Electrical, Pipinq, lnsulation and Ductwork s 208.081 40o/o of PEQ oTC-LADCO 2008
fotal Direct lnstallation (Dl)$208,081
Iotal Direct Cost (DC)$728.282
lndirect lnstatlation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Continqencies $ 317,323 61% of PEC oTC-LADCO 2008
Iotallndirect Cost $ 317.323
Iotal lnstalled Cost (TlC)$ 1,045,605
/OC Emissions Before Control. lb/MMBtu 0.006
VOC Emissions Before Control. tn/vr o.72 2017 SLEIS
Control Efficiencv (%)10
VOC Emissions After Control. tn/vr 0.65
VOC Emission Reduction. tn/vr 0.07
Annual Costs. $/vear (Direct + Indirect)
Direct Costs
Operatinq Labor $ 31,368 3olo of caoitol cost
Raw materials $
Reolacement Parts $ 31.368 3% of capitol cost
fota! Direct Costs. $/vear $ 62.736
lndirect Costs
Cverhead $ 18.821 30% of labor costs
Taxes, lnsurance, and Administration $ 41.824 4% of lotal installed cost
CapitolRecovery $ 137,466 10o/o, 15 years, CRF-.13147
Iotal lndirect Costs. $/vear $ 198.111
lotal Annual Cost $260.847
Cost Effectiveness, $ per ton NO, reductior $ 3,622,876.15
VOC Cost Analysis to Upgrade Process Heaters to ULNB - 6Hl
54.7 MMBtu/hr
ULNB Factor Basis for Cost
Upqrade and Factor
Direct Costs:
Puchased Equipment:
Primarv and Auxiliarv Equipment (PE)$ 432,600 Estimate - $36050 per burner; 12 burners
Sales Tax $ 25,956 6% of PE oTC-LADCO 2008
Freiqht $ 21,630 5o/o of PE oTC-LADCO 2008
Total Purchased Eouioment Gost (PEC)s 480.186
Direct lnstallation
Electrical. Pioino. lnsulation and Ductwork $ 192.074 40% of PEC oTC-LADCO 2008
Total Direct lnstallation (Dl)$ 192.074
Total Direct Gost (DC)$ 672.260
lndirect lnstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Contingencies $ 292,913 61% of PEC oTC-LADCO 2008
Tota! lndirect Cost $ 292.913
Total lnstalled Cost filC)$ 965.174
VOC Emissions Before Control, lb/MMBtu 0.006
VOC Emissions Before Control, tn/vr 1.23 2017 SLEIS
Control Efficiencv (%)10
VOC Emissions After Control, tn/vr 1.11
VOC Emission Reduction, tn/vr 0.12
Annual Costs. $/vear (Direct + lndirectl
Direct Gosts
Operatino Labor $ 28.955 3o/o of capitol cost
Raw materials $
Replacement Parts $ 28,955 3o/o ol capitol cost
Total Direct Costs. $/vear $ 57.910
lndirect Costs
Overhead $ 17.373 60% of labor costs
Taxes. lnsurance. and Administration $ 38.607 4o/o ol total installed cost
Caoitol Recovery $ 126,891 10%. 15 vears, CRF-.1 3147
Total lndirect Costs, $/year s 182.871
TotalAnnual Cost $ 240.782
Cost Effectiveness, $ per ton NO, reductior $ 1,957,576.61
VOC Cost Analysis to Upgrade Process Heater$ to ULNB - 6H2
12 MMBtu/hr
ULNB Factor Basis for Cost
Uoorade and Factor
Direct Costs:
Puchased Eouioment:
Primarv and Auxiliarv Eouioment (PE)$ 108.150 Estimate -$36050 per burner: 3 burners
Sales Tax $ 6.489 6% of PE oTC-LADCO 2008
Freioht $ 5.408 5% of PE oTC-LADCO 2008
Total Purchased Eouioment Cost (PEC)$ 120.047
Direct !nstallation
Electrical. Pioino. lnsulation and Ductwork $ 48,019 40% ot PEC oTC-LADCO 2008
Tota! Direct lnstallation (Dl)$ 48,019
Tota! Direct Cost (DC)$ 168,065
lndirect lnstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests. Continoencies $ 73,228 61% of PEC oTC-LADCO 2008
Total lndirect Cost $73,228
Total lnstalled Cost (TlC)$ 241,293
VOC Emissions Before Control, lb/MMBtu 0.00€
VOC Emissions Before Control. tn/vr 0.1s 2017 SLEIS
Control Efficiencv (%)1C
VOC Emissions After Control. tn/vr 0.17
VOC Emission Reduction. tn/vr 0.02
Annual Costs. $/vear (Direct + lndirect)
Direct Gosts
Ooeratinq Labor $ 7,239 3o/o of caoitol cost
Raw materials $
Replacement Parts $ 7,239 3o/o of caoitol cost
fota! Direct Costs. $/vear $ 14.478
lndirect Costs
Overhead $ 4,343 60% of labor costs
Taxes, lnsurance, and Administration $ 9,652 4% of total installed cost
CapitolRecovery $ 31,723 10%. 15 vears. CRF-.1 3147
fotal lndirect Costs, $/year s 45.718
fotal Annual Cost $ 60.195
Cost Effectiveness, $ per ton NO, reductior $ 3,168,183.20
VOC Cost Analysis to Upgrade Process Heaters to ULNB - 6H3
37.7 MMBtu/hr
ULNB Factor Basis for Cost
Uoorade and Factor
Direct Costs:
Puchased Equipment:
Primarv and Auxiliarv Eouioment (PE)$ 144.200 Estimate -36050 Der burner: 4 burners
Sales Tax $ 8,652 6% of PE oTC-LADCO 2008
Freioht $ 7.210 5% of PE oTC-LADCO 2008
Tota! Purchased Equipment Gost (PEC)$ 160,062
Direct lnstallation
Electrical. Pioinq. lnsulation and Ductwork $ 64.025 40% of PEC oTC-LADCO 2008
fotal Direct Installation (D!)$64,025
Iotal Direct Cost (DC)s 224.087
lndirect lnstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Contingencies $ 97,638 61% of PEC oTC-LADCO 2008
Total lndirect Cost $ 97.638
Iotal lnstalled Cost (TlC)$ 321.725
VOC Emissions Before Control. lb/MMBtu 0.006
VOC Emissions Before Control. tn/vr 0.45 2017 SLEIS
Control Efficiencv (%)10
VOC Emissions After Control, tn/vr 0.41
VOC Emission Reduction, tn/yr 0.05
Annual Costs. $/vear (Direct + lndirect)
Direct Costs
Ooeratino Labor $ 9.652 3o/o of capitol cost
Raw materials s
Replacement Parts $ 9.652 3o/o of capitol cost
Total Direct Costs. $/vear $r9,303
lndirect Costs
Overhead $ 5,791 600/o ol labor costs
Taxes. lnsurance. and Administration $ 12.869 4% of total installed cost
Capitol Recovery $ 42,297 1oo/o. 15 vears. CRF-.1 31 47
Total lndirect Costs. $/vear $ 60.957
Tota! Annual Cost $ 80.261
Cost Effectiveness, $ per ton NO, reductior $ 1,783,569.80
VOC Cost Analysis to Upgrade Process Heaters to ULNB - 7H1
4.4 MMBtu/hr
ULNB Factor Basis for Cost
Uoqrade and Factor
Direct Costs:
Puchased Equipment:
Primarv and Auxiliarv Equipment (PE)$ 36,050 Estimate - $36050 per burner: 1 burner
Sales Tax $ 2,163 6% of PE oTo-LADCO 2008
Freioht s 1.803 5% of PE OTC-LADCO 2OO8
Total Purchased Eouioment Gost (PEC)$40.016
Direct !nstallation
Electrical. Pipino. lnsulation and Ductwork $ 16,006 40% ol PEC OTC-LADCO 2OO8
fohl Direct lnstallation (Dl)$16,006
fotal Direct Cost (DG)$ s6,022
lndirect lnstallation Gosts
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Continqencies $ 24.409 61% of PEC oTC-LADCO 2008
Iotal Indirect Cost $24,409
Total lnstalled Cost (TlC)s 80.431
VOC Emissions Before Control, lb/MMBtu 0.006
VOC Emissions Before Control. tn/vr 0.03 2017 SLEIS
Control Efficiencv (%)10
VOC Emissions After Control. tn/vr 0.03
VOC Emission Reduction, tn/vr 0.003
Annual Costs. $/vear (Direct + lndirectl
Direct Costs
Ooeratino Labor $ 2.413 3% of capitol cost
Raw materials $
Replacement Parts $ 2,413 3% of capitol cost
Iota! Direct Costs. $/vear $4,826
lndirect Costs
Overhead $ 1,448 l0% of labor costs
Taxes. lnsurance. and Administration $ 3.217 4% of total installed cost
CaoitolRecovery $ 10,574 10%, 15 years, CRF-.1 3147
fotal lndirect Costs. $/year s 15.239
Iotal Annual Cost s 20.065
Cost Effectiveness, $ per ton NO, reductior $ 6,688,386.75
VOC Cost Analysis to Upgrade Process Heaters to ULNB - 7H3
33.3 MMBtu/hr
ULNB Factor Basis for Cost
Uoorade and Factor
Direct Costs:
Puchased Equipment:
Primarv and Auxiliarv Eouioment (PE)$ 144,200 Estimate -;36050 per burner; 4 burner
Sales Tax $ 8.652 6% of PE orc-LADco 2008
Freioht $ 7,210 5% of PE oTC-LADCO 2008
Total Purchased Eouipment Gost (PECI $ 160.062
Direct Insta!lation
Electrical, Pipinq, lnsulation and Ductwork $ 64.025 40o/o of PEC orc-LADco 2008
Total Direct lnstallation (D!)$64.025
Total Direct Cost (DC)$ 224,087
lndirect lnstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Contingencies $ 97,638 61% of PEC OTC-LADCO 2OO8
Total lndirect Cost $ 97.638
Total lnstalled Cost (TlC)$ 321.725
VOC Emissions Before Control, lb/MMBtu 0.006
VOC Emissions Before Control. tn/vr 0.52 2017 SLEIS
Control Efficiencv (%)10
VOC Emissions After Control. tn/vr 0.47
VOC Emission Reduction, tn/yr 0.05
Annual Costs, $/year (Direct + lndirect)
Direct Costs
Ooeratino Labor $ 9,6s2 3% of capitolcost
Raw materials $
Replacement Parts $ 9,652 3% of caoitolcost
Iota! Direct Costs. $/vear $ 19.303
lndirect Costs
Cverhead $ 5.791 600/o of labor costs
faxes, lnsurance, and Administration $ 12,869 4o/o of total installed cost
Oapitol Recovery $ 42.297 10o/o. 15 vears. CRF-.1 3147
Total lndirect Costs. $/vear $ 60,957
Total Annual Cost s 80.261
Cost Effectiveness, $ per ton NO, reductio $ 1,543,473.86
VOC Cost Analysis to Upgrade Process Heaters to ULNB - 9Hl
8.1 MMBtu/hr
ULNB Factor Basis for Cost
Upqrade and Factor
Direct Costs:
Puchased Equipment:
Primarv and Auxiliarv Eouioment (PE)$36,050 Estimate -i36050 per burner; 1 burner
Sales Tax $ 2,163 6% of PE oTC-LADCO 2008
Freioht $ 1.803 5% of PE OTC-LADCO 2OO8
Iotal Purchased Equioment Gost (PEC)s 40.016
Direct lnstallation
Electrica!. Pipino. lnsulation and Ductwork $ t6,006 40% ot PEC oTo-LADCO 2008
Iotal Direct lnstallation (Dl)$ 16.006
lotal Direct Cost (DG)$56,O22
lndirect lnstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Contingencies $ 24,409 61% of PEC oTC-LADCO 2008
fotal lndirect Gost $24.409
Iotal lnstalled Cost fflC)$ 80.431
VOC Emissions Before Control, ]b/MMBtu 0.006
VOC Emissions Before Control. tn/vr 0.20 2017 SLEIS
ControlEfficiencv (%)10
VOC Emissions After Control. tn/vr 0.18
VOC Emission Reduction. tn/vr 0.02
Annua! Costs- $/vear (Direct + lndirectl
Direct Costs
Ooeratino Labor $ 2,413 3o/o ol caoitol cost
Raw materials $
Reolacement Parts $ 2.413 3o/o ol caoitol cost
Iotal Direct Costs. $/vear $4,826
ndirect Costs
Overhead $ 1.448 60% of labor costs
faxes. lnsurance. and Administration $ 3.217 4o/o of total installed cost
Capitol Recovery $ t 0,574 10o/o. 15 vears. CRF-. 1 3147
Iotal lndirect Costs. $/vear $ 15.239
lotal Annual Gost $ 20,06s
Cost Effectiveness, $ per ton NO, reductior $ 1,003,258.01
VOC Gost Analysis to Upgrade Process Heaters to ULNB - 9H2
4.1 MMBtu/hr
ULNB Factor Basis for Cost
Upqrade and Factor
Direct Costs:
Puchased Equipment:
Primarv and Auxiliarv Equipment (PE)$ 36.050 Estimate $36050 oer burner: 1 burner
Sales Tax $ 2,163 6% of PE OTC-LADCO 2OO8
Freiqht $ 1,803 5o/o of PE oTC-LADCO 2008
Iotal Purchased Eouioment Cost (PEC)$ 40,016
Direct lnstallation
Electrical, Pipinq, lnsulation and Ductwork $ 16,006 40o/o of PEC oTC-LADCO 2008
fotal Direct lnstallation (Dl)$ 16.006
Iotal Direct Cost (DG)$56,022
lndirect !nstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Contingencies $ 24,409 61% of PEC oTC-LADCO 2008
Total lndirect Cost $24.409
Tota! lnstalled Cost fflc)$ 80.431
VOC Emissions Before Control, lb/MMBtu 0.006
VOC Emissions Before Control, tn/yr 0.05 2017 SLEIS
Control Efficiencv (%)10
VOC Emissions After Control. tn/vr 0.05
VOC Emission Reduction, tn/yr 0.01
Annual Costs. $/vear (Direct + lndirect)
Direct Costs
Operatinq Labor $ 2.413 3o/o of capitol cost
Raw materials $
Reolacement Parts $ 2,413 3o/o of capitol cost
Total Direct Costs. $/vear s 4.826
lndirect Costs
Overhead s 1.448 50o/o of labor costs
Taxes. lnsurance. and Administration s 3.217 4o/o of total installed cost
CapitolRecovery $ 10,574 10o/o, 1 5 vears, CRF-. 1 31 47
Total lndirect Costs. $/vear $ 15.239
Total Annual Gost $20.065
Cost Effectiveness, $ per ton NO, reduction $ 4,013,032.05
VOC Cost Analysis to Upgrade Process Heaters to ULNB - {OHl
13.2 MMBtu/hr
ULNB Factor Basis for Cost
Upqrade and Factor
Direct Costs:
Puchased Equipment:
Primarv and Auxiliarv Eouioment (PE)s 216.300 Estimate -36050 per burner: 6 burners
Sales Tax $ 12,978 6% of PE oTC-LADCO 2008
Freioht $ 10.815 5% of PE OTC-LADCO 2OO8
Total Purchased Equipment Cost (PEC)$ 240,093
Direct lnstallation
Electrical, Pipinq, lnsulation and Ductwork $ 96.037 4Oo/o of PEC OTC-LADCO 2OO8
lotal Direct lnstallation (Dl|$96,037
lotal Direct Cost (DC)$ 336.130
lndirect lnstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Contingencies $ 146.457 61% of PEC oTC-LADCO 2008
Total !ndirect Cost $ 146,457
Tota! lnstalled Cost (TlC)$ 482.587
VOC Emissions Before Control, lb/MMBtu 0.00€
VOC Emissions Before Control. tn/vr 0.18 2017 SLEIS
Control Efficiencv (%)1C
VOC Emissions After Control, tn/vr 0.16
VOC Emission Reduction, tn/yr 0.02
Annual Costs. $/vear (Direct + lndirect)
Direct Gosts
Ooeratino Labor $ 14,478 3% of capitolcost
Raw materials $
Reolacement Parts $ 14.478 3o/o of caoitol cost
Iotal Direct Costs. $/vear $ 28.955
lndirect Costs
Overhead $ 8,687 50% of labor costs
Taxes, lnsurance, and Administration $ 19.303 4% of total installed cost
Caoitol Recovery $ 63,446 10%, 15 years, CRF-.13147
Iota! lndirect Costs. $/vear $ 91.436
Tota! Annual Cost $ 120,391
Cost Effectiveness, $ per ton NO" reductiot $ 6,688,386.75
VOC Cost Analysis to Upgrade Process Heaters to ULNB - 11Hl
24.2 MMBtu/hr
ULNB Factor Basis for Cost
Upqrade and Factor
Direct Costs:
Puchased Equioment:
Primarv and Auxiliarv Equipment (PE)$ 144.200 Estimate -036050 per burner: 4 burners
Sales Tax $ 8,652 6% of PE oTC-LADCO 2008
Freiqht g 7,210 5olo of PE OTC-LADCO 2OO8
fotal Purchased Equipment Gost (PEC)$ 160.062
Direct lnstallation
Electrical. Pioino. !nsulation and Ductwork s 64.025 40% of PEC oTG-LADCO 2008
Iota! Direct lnstallation (Dl)$ 64,025
fotal Direct Cost (DC)$ 224.087
lndirect lnstallation Gosts
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Continqencies $ 97.638 61% of PEC OTC-LADCO 2OO8
Iota! lndirect Cost $ 97,638
fotal lnstalled Cost filG)$ 321.725
VOC Emissions Before Control, lb/MMBtu 0.006
VOC Emissions Before Control. tn/vr 0.33 2017 SLEIS
Conirol Efficiencv (o/n)1C
VOC Emissions After Control. tn/vr 0.3c
VOC Emission Reduction. tn/vr 0.03
Annual Costs. $/vear (Direct + lndirect)
Direct Costs
Coeratino Labor $ 9,6s2 3o/o of caoitol cost
Raw materials $
Replacement Parts $ 9,6s2 3% ol caoitol cost
Total Direct Gosts. $/vear $ 19.303
lndirect Costs
Overhead $ 5,791 600/o of labor costs
Taxes, lnsurance. and Administration $ 12,869 4% of total installed cost
CaoitolRecoverv $ 42.297 10o/o. 15 vears. CRF-.1 31 47
Total lndirect Costs. $/vear $ 60,957
Tota! Annual Gost $80.261
Cost Effectiveness, $ per ton NO, reductior $ 2,432,140.63
VOC Gost Analysis to Upgrade Process Heaters to ULNB - 13Hl
6.5 MMBtu/hr
ULNB Factor Basis for Cost
Upqrade and Factor
Direct Costs:
Puchased Equipment:
Primarv and Auxiliarv Eouioment (PE)$ 72.100 Estimate - $36050 per burner; 2 burners
Sales Tax $ 4,326 6% of PE oTo-LADCO 2008
Freioht $ 3,605 5% of PE orc-LADco 2008
Total Purchased Equipment Cost (PEC)$ 80.031
Direct lnstallation
Electrica!, Pipinq, lnsulation and Ductwork $ 32,012 40% otPEC oTC-LADCO 2008
Total Direct lnstallation (Dll $ 32,012
Total Direct Cost (DC)$ 112.043
lndirect !nstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests. Continoencies $ +8,819 61% of PEC oTo-LADCO 2008
Total lndirect Cost $ 48.819
Total lnstalled Cost (TlC)$ 160.862
VOC Emissions Before Control, lb/MMBtu 0.006
VOC Emissions Before Control, tn/yr 0.05 2017 SLEIS
Control Efficiencv (%)10
VOC Emissions After Control, tn/yr 0.05
VOC Emission Reduction. tn/vr 0.01
Annual Costs. $/vear (Direct + lndirect)
Direct Costs
Ooeratinq Labor $ 4,826 3o/o of capitol cost
Raw materials $
Reolacement Parts $ 4,826 3% of capitol cost
Total Direct Gosts. $/vear $ 9.652
!ndirect Costs
Overhead $ 2,896 50% of labor costs
Taxes, lnsurance, and Administration $ 6,434 4% of total installed cost
Caoitol Recovery $ 21,149 10%, 15 years, CRF-.1 3147
Iotal Indirect Costs, $/year $30,479
Iotal Annual Cost $ 40.130
Cost Effectiveness, $ per ton NO, reductior $ 8,026,064.10
VOG Cost Analysis to Upgrade Process Heaters to ULNB - 68 H2 and 68H3
0.8 MMBtu/hr
ULNB Factor Basis for Cost
Uoorade and Factor
Direct Gosts:
Puchased Eouioment:
Primary and Auxiliarv Equipment (PE)$ 36.050 Estimate -;36050 oer burner: 1 burner
Sales Tax $ 2,163 6% of PE oTC-LADCO 2008
Freioht $ 1.803 5% of PE oTC-LADCO 2008
fotal Purchased Eouioment Cost (PECI $ +0,016
Direct !nstallation
Electrical, Pipinq, lnsulation and Ductwork $ 16.006 40% of PEC oTC-LADCO 2008
Iotal Direct lnstallation (Dl)$ t6.006
Tota! Direct Cost (DC)$56,022
lndirect lnstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Contingencies $ 24.409 61% of PEC oTo-LADCO 2008
Total Indirect Cost $24,409
Total lnstalled Cost fflCl $80,431
VOC Emissions Before Control, lb/MMBtu 0.006
VOC Emissions Before Control, tn/yr 3.96E-03 2017 SLEIS
Control Efficiencv (%)10
VOC Emissions After Control. tn/vr 3.56E-03
VOC Emission Reduction, tn/vr 3.96E-04
Annua! Costs. $/vear (Direct + lndirectl
Direct Costs
Ooeratino Labor s 2.413 3o/o of capitol cost
Raw materials $
Reolacement Parts $ 2.413 3% of capitolcost
Total Direct Costs. $/vear $4,826
lndirect Costs
Overhead $ 1.448 60% of labor costs
Taxes, lnsurance, and Administration $ 3.217 4o/o of total installed cost
Capitol Recovery $ 10,574 10%, 15 years, CRF-.1 3147
Tota! lndirect Costs. $/vear $ 15.239
Total Annual Cost $20.065
Cost Effectiveness, $ per ton NO" reductior $ 50,669,596.56
HF Sinclair Gost Analysis for lnstallation of RTO for Product Loading
Assumptions:
Cost based on2002 - Nov 2023 CPI
Based on 1000 scfm - estimated
RTO Factor Basis for Cost
and Factor
Direct Costs:
Puchased Equipment:
Primarv and Auxiliarv Eouioment (PE)$ 2s0.036 EPA1 - Based on2023 costs, 1000 scfm estimate
lnstumentation $ 25,004 10% of PE EPA
Sales Tax $ 7,501 3% of PE
Freioht $ 12.502 5% of PE
Total Purchased Eouipment Cost (PEC)$ 295,043
Direct !nstallation
Electrical, Pipinq, lnsulation and Ductwork $ 88,513 30% of PEC
Total Direct lnstallation (Dl)$ 88,513
Iotal Direct Cost (DC)$383.556
lnd irect lnstallation Costs
3onstruction and Field Expenses,
3ontractor Fees, Startup Expenses,
Performance Tests, Contingencies $ 182,926 620/o ol PEC
Iotal lndirect Cost $ 182.926
Iotal lnstalled Cost filC)$566,482
/OC Emissions Before Control, tn/yr 4.51 2017 actualemissions
Control Efficiencv (%)98
/OC Emissions After Control, tn/vr 0.0€
/OC Emission Reduction, tn/yr 4.42
Annual Costs. $/vear (Direct + lndirect)
Direct Costs
Coeratino Labor $ 16,994 3% of capitol cost
Ulaintenance $ 16.994 3% of capitol cost
Replacement Parts $ 16,994 3% of caoitol cost
NaturalGas $ 321,257 $3.30/kft3
Electricitv $ 1,708 0.006/K\ /h
fotal Direct Costs. $/vear $373.948
lndirect Costs
Overhead $ 27.191 t0% oi labor costs
faxes. lnsurance. and Administration $ 22,659 4% of total installed cost
CapitolRecovery $ 74.475 10o/o.15 vears, CRI -.13147
Iotal lndirect Costs, $/year $ 124,326
fotal Annual Cost $ 498-274
Cost Effectiveness, $ per ton VOC reductio s 112.736.71
EPA - CICA Fact Sheet Reqenerative Thermal Oxidizer; EPA Cost Manual
HF Sinclair Woods Cross Refinery
Cost Analysis For Vapor Balancing
Vapor balancinq Factor Basis for Cost
and Factor
Direct Costs:
Puchased Eouipment:
Primarv and Auxiliarv Eouioment (PE)$ 4.700.160
Table 7-5 MARAMA and 47% inflation
rate from 2007 to 2023 and 32 tanks
Sales Tax
Freiqht
Total Purchased Equioment Cost (PEC)$ 4.700.160
Direct lnsta!lation
Electrical. Pioino. lnsulation and Ductwork
Total Direct lnstallation (Dl)$
Tota! Direct Cost (DC)$ 4.700.160
lndirect lnstallation Costs
Engineering and Project Management,
Construction and Field Expenses,
Contractor Fees, Startup Expenses,
Performance Tests, Continqencies
Total lndirect Cost s
Total lnstalled Cost fflC)s 4.700.160
VOC Emissions Before Control, tn/vr 0.4s 2017 SLEIS
Control Efficiencv (%)8C
VOC Emissions After Control, tn/yr 0.1c
VOC Emission Redrlction tn/vr 0.3s
Annual Costs. $/vear (Direct + lndirect)
Direct Costs
Ooeratino Labor $ 235.008 5% of capitol cost
Raw materials s
Replacement Parts
Total Direct Costs. $/vear $235.008
lndirect Costs
Overhead $ 141,005 50% of labor costs
Iaxes, lnsurance. and Administration $ 188.006 4% of total installed cost
Caoitol Recoverv
Total lndirect Costs. $/year $ 329.011
fotal Annual Cost s 564.019
Cost Effectiveness, $ Der ton VOC reduction $ 1.438.824.49
Assumption:
lnvestment per tank $96,000 per Table 7-5. 32 fixed roof tanks.
Assessment of Control Technology Options for Petroleum Refineries, Section 7 - Storage Tanks, January 31, 2007
CPI lnflation calculator lrom 2007 lo 2023 applied to tank investment cost
APPENDIX C. HOLLY ENERGY PARTNERS RACT ANALYSIS
HF Sinclair Woods Cross Refining LLC / Reasonable Avaibbb Control Technology Assessment
TriniW Consultants December 2023 c-1
).q*
February L2,2O2L
Ms. Catherine Wyffels
Environmental Engineer
Utah Division of Air Quality
195 North 1950 West
Salt Lake City, Utah 84115
Sent Via Certified Mail and Email
70200640 0001 5860 6782
[e-mail]
Re:Moderate Ozone Nonattainment Area Classification
Holly Energy Partners
Woods Cross Terminal
Ms. Wyffels,
ln response to your emailon November 5,2020, to Mr. Eric Benson please find attached
the Reasonably Available Control Technology (RACD analysis for the Woods Cross Terminal in
the Wasatch Front.
lf you need further information or have questions regarding this submittal please contact me at
2L4-954-67 12 or via emai I at trevor. ba i rd @ ho I lyene rgy.co m.
Sincerely,
Trevor O. Baird, P.E.
Environmental Engineer lV
Holly Energy Partners
Corporate Offlce:
OperaUons Offlce:
2828 N. Harwood, Sulte 1300
1602 West Maln Street
Dallas, TX 752O4-L5O7 21lf€71€555
Artosla, ttM 88:110 57$7484000
F;...;
+q*&i
:tc
Holly Energy Partners
Woods Cross Terminal
Reasonably Available Control Technology
Review
February 10,2021
Project No.: 0550517
I/re /rrrslrress of srislall abiltty I I{ r"\i
HOLLY ENERGY PARTNERS
Reasonably Available Control Technology Review
CONTENTS
APPENDIX A
APPENDIX B
ACTUAL AND POTENTIAL EMISSIONS, NOX AND VOC
RBLC DATABASE REVIEW
CONTENTS
1.
2.
3.
4.
5.
TNTRODUCTTON ........ .............1
RACT TNFORMATTON REQUEST........... ....................2
TERMTNAL INFORMATION........... ...........3
3.1 Loading Rack........... ..........3
3.2 Equipment Leaks.......... .........................3
3.3 Soil Remediation System .......................4
ACTUAL AND POTENTIAL EMISSIONS ....................5
RACT APPROACH .............. .....................6
5.1 Petroleum Products Loading RACT Analysis ............6
5.1.1 Step 1: ldentify All Reasonably Available Control Techno|ogies............................6
5.1.2 Step 2: Eliminate Technically lnfeasible Control Techno1o9ies.............................. 8
5.1.3 Step 3: Rank Remaining Control Technologies Based on Capture and
ControlEfficiencies. ................9
5.1.4 Step 4: Evaluate Remaining ControlTechnologies on Economic, Energy,
and Environmental Feasibility............... ........................10
5.1.5 Step 5: Select RACT ............11
5.2 Equipment Leaks .......... ....................... 11
5.2.1 Step '1: ldentify All Reasonably Available Control Techno1o9ies.................. ........11
5.2.2 Step 2: Eliminate Technically lnfeasible Control Techno|ogies.................. ..........12
5.2.3 Step 3: Rank Remaining ControlTechnologies Based on Capture and
Control Efficiencies. ..............12
5.2.4 Step 4: Evaluate Remaining ControlTechnologies on Economic, Energy,
and EnvironmentalFeasibility.... ...............12
5.2.5 Step 5: Select RACT ............12
5.3 SoilRemediation System .....................12
RACT COMPLIANCE AND IMPLEMENTATION SCHEDULE ......................136.
List of Tables
Table 1. Woods Cross TerminalEmissions lnventory. .....................2
Table 2. Woods Cross TerminalEmissions lnventory. .....................3
Table 3: Woods Cross Terminal- NOx and VOC PTE and 2017 Actual Emissions. ..............5
Table 4. Truck Loading - Control Effectiveness. ................. ...........10
Table 5. RACT Compliance and lmplementation Schedule. ..........13
m.em.com Prcject No.: 0550517 Holly Energy Partners
HOLLY ENERGY PARTNERS
Reasonably Available Control Technology Review
INTRODUCTION
1.INTRODUCTION
The Utah Division of Air Quality (UDAO) is soliciting a reasonably available control technology (RACT)
analyses for the Holly Energy Partners (HEP) Woods Cross Terminal (Terminal). The RACT analysis is
being requested for emissions units that are source of oxides of nitrogen (NOx) and volatile organic
compounds (VOC)from the Terminal.
On June 4,2018, the United States Environmental Protection Agency (EPA) designated the Wasatch
Front as marginal nonattainment for the 2015 eight-hour ozone standard. The portions of the Wasatch
Front affected by this designation have been divided into two areas: Northern Wasatch Front and
Southern Wasatch Front. The Northern Wasatch Front includes all or part of Salt Lake, Davis, Weber, and
Tooele counties. The Southern Wasatch Front includes part of Utah County.
The Wasatch Front is required to attain the ozone standard by August 3,2021. Recent monitoring data
has indicated that the Southern Wasatch Front nonattainment area has attained the standard and UDAQ
has initiated the process for re-designation to attainment for this area. However, recent monitoring data
has indicated the Northern Wasatch Front nonattainment area will not attain the ozone standard and will
be bumped up to moderate classification in early 2022.The Terminalis located in Davis County, in the
Northern Wasatch Front.
This anticipated bump-up from marginal to moderate classification may trigger new control strategies
requirements for major sources in the Northern Wasatch Front nonattainment area. Specifically, UDAQ's
Ozone lmplementation Rule requires the State lmplementation Plan to include RACT measures for all
major stationary sources in nonattainment areas classified as moderate or higher.
A major stationary source in a moderate ozone nonattainment area is defined as any stationary source
that emits or has the potential to emit 100 tons per year or more of NOx or VOCs. The estimated potential
to emit (PTE) for each criteria air pollutant for the Terminal is currently significantly below the 100 tpy
major source threshold. However, recent permitting actions have established that the Terminal and the
Woods Cross Refinery are considered one stationary source and therefore Terminal is currently
considered a major source.
m.erm.sm Project No.; 0550517 Holly Energy Parlners
HOLLY ENERGY PARTNERS
Reasonably Available Control Technology Review
RACT INFORMATION REQUEST
2. RACT INFORMATION REQUEST
ln letter request DAQE-008-20, UDAQ provides a list of the specific information required to be submitted
as part of the RACT review. A list of the information requested by UDAQ and a reference to where the
specific information is located within this document is provided in Table 1 below.
UDAQ RACT Submittal Requirements Location of lnformation
A list of each NOx and VOCs emission unit at the facility. All emission units with a
potential to emit either NOx or VOCs must be evaluated.
A physical description of each emission unit and its operating characteristics,
including but not limited to: the size or capacity of each affected emission unit; types
of fuel combusted; and the types and quantities of materials processed or produced
in each affected emission unit.
Estimates of the potential and actual NOx and VOC emissions ftom each affected
source, and associated supporting documentation.
The proposed altemative NOx RACT requirement(s) or NOx RACT emissions
limitation(s), and/or the proposed VOC requirement(s) or VOC RACT emissions
limitation(s) (as applicable).
Supporting documentation for the technical and economic considerations for each
affected emission unit.
A schedule for completing implementation of the RACT requirement or RACT
emissions limitation, including start and completion of project and schedule for initial
compliance testing.
Proposed testing, monitoring, recordkeeping, and reporting procedures to
demonstrate compliance with the proposed RACT requirement(s) and/or limitation(s).
Additional information requested by DAQ necessary for the evaluation of the RACT
analyses.
Section 3
Section 3
Section 4
Section 5
Not Applicable
Section 6
Section 6
Not Applicable
Table 1. Woods Cross Terminal Emissions lnventory.
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TERMINAL INFORMATION
3. TERMINAL INFORMATION
The Terminal is an existing petroleum products loading facility located at 755 West 500 South, Woods
Cross, Utah 84087. The Terminal currently operates under approval order (AO) DAOE-AN0101230023B-
07 for the Loading Rack and AO DAQE-AN0101230034-10 for the soil remediation system. The bulk
Terminal is used by HEP to load gasoline and diesel products into tanker trucks. The Terminal receives
petroleum products (gasoline, diesel, and jet fuel) via pipeline from the HollyFrontier Woods Cross
Refinery. The petroleum products are loaded into tanker trucks for offsite transportation. The Terminal
does not have aboveground storage tanks for petroleum products. The equipment and associated
emissions inventory for the Terminal are provided in Table 2.
Table 2. Woods Cross Terminal Emissions Inventory.
Emission Unit
Name Emission Unit Description Permitted
Throughput Pollutants Control Equipment
lnstalled
Loading Rack -
Tanker Truck Fill
Loading bays used to load
gasoline, diesel, and jet fuel into
tanker trucks and to unload crude
4,500,000
bbl./year voc
Vapor Recovery Unit
(VRU)with a Vapor
Combustion Unit
(backup)
Equipment Leaks
Equipment in organic HAP service
as defined in 40 CFR 63.641:
pumps, compressors, pressure
relief devices, sampling
connection systems, open-ended
valves or lines, valves, or
instrumentation systems.
None voc None
Soil Remediation
System
Soil gas vapors from site
remediation activities None voc Thermal/catalytic
oxidizer
3.1 Loading Rack
The petroleum products loading rack is a primary source of VOC emissions from the Terminal. VOC
emissions are associated with the loading of petroleum products into tanker trucks for offsite transport.
The loading rack receives refined petroleum products (gasoline, diesel, etc.) from the adjacent Holly
Frontier refinery. The Terminal currently operates under an annual throughput limit of 4.5 million barrels
per 12-month period. VOC emissions generated during the loading of the tanker trucks are controlled by
an existing vapor recovery unit (VRU). The VRU operates under a VOC emission limit of 10 milligram of
VOC emissions per liter of gasoline loaded (mg/L) based on a 6-hour rolling average as required by 40
CFR 63 Subpart CC - National Emission Standards For Hazardous Air Pollutants From Petroleum
Refineries. The Terminal also operates a vapor combustion unit (VCU) to control VOC emissions from the
loading rack when the VRU is shut down for maintenance. The current AO limits the VCU operating hours
to 1,056 hours/year.
3.2 Equipment Leaks
The Terminal is a source of fugitive VOC emissions associated with any potential leaks from components
such as valves, connectors, pumps, etc. The annual VOC emissions from equipment leaks is primarily
dependent on the number of components, the liquid associated with the component, and the associated
leak rate. To minimize VOC emissions by detecting any component VOC leaks in a timely manner, the
Terminal has implemented a leak detection and repair (LDAR) program. The LDAR program consists of
monthly monitoring to detect and repair leaking components.
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TERMINAL INFORMATION
3.3 Soil Remediation System
HEP installed a Dual Phase Extraction (DPE) remediation system at the Terminalto address petroleum
related soil and groundwater impacts. Primary components of the DPE remediation system include below
grade extraction wells that will be used to extract groundwater and soilgas vapor. Extracted groundwater
is transferred by enclosed piping to a concrete sump or junction box from where it is piped to the Holly
Frontier Refinery's wastewater treatment system. Recovered soil gas VOC emissions from the DPE
remediation system are treated using a Flame Oxidation System (FOD). The FOD consists of a hybrid
thermal oxidation technology designed to treat high concentrations of VOCs without the need to add
significant amount of dilution air to the vapor stream prior to combustion. The FOD uses the recovered
soil gas as a fuel source, thereby reducing the amount of supplemental fuel required for the
combustion/destruction of the VOCs in the vapor stream. As concentrations in the soil vapor decrease,
supplementalfuel (i.e., natural gas) is added to maintain the necessary operating temperature. The FOD
is also equipped with a catalytic oxidation module which will allow the unit to operate as a natural gas
fired catalytic oxidizer once concentrations decline to appropriate levels (approximately less than 25
percent of the lower explosive limit).
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ACTUAL AND POTENTIAL EMISSIONS
4. ACTUAL AND POTENTIAL EIV4SSIONS
A summary of the PTE and the 2017 aclual emi$sions for NOx and VOC emissions from the emissions
inventory at the Terminal is provided in Table 3 below. For each emission unit, the table also includes the
applicable emission limits as referenced from tho Terminal's AO's. Details for the estimated actuals and
PTE for the Terminal are included in Appendix A.
Table 3: Woods Cross Terminal- NQx and VOC PTE and 2017 Actual Emissions.
1 The Loading Rack - Tanker Truck Fill is not a direct source of NOx emissions. NOx emissions are formed as a by-product during
the control of VOC emissions using the VCU.
2 The Soil Remediation System is not a direct source of NOx emissions. NOx emissions are formed as a by-product during the
conhol of VOC emissions using the thermal oxidizer.
Emission Unit Name Applicable VOC
Emission Limits
Potentia! to Emit 2017 Actual Emissions
voc NOx VOC NOx
Loading Rack - Tanker Truck Fill
't0 mg/L
(6-hour average)7.92tpy 1.90 tpyl 1.88 tpy 0.13 tpy
Equipment Leaks None 0.25 tpy None 0.25 tpy None
Soil Remediation System 0.96 ton/yr.0.96 tpy 0.63 tpy2 0.01 tpy 0. 19 tpy
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RACT APPROACH
5. RACT APPROACH
The approach used to develop the RACT is maintained consistent with UDAQ's recommended RACT
process. Steps associated with a typical 'top-down' RACT analysis are as follows
. Step 1: ldentify All Reasonably Available Control Technologies;
. Step 2: Eliminate Technically lnfeasible ControlTechnologies;
. Step 3: Rank Remaining ControlTechnologies Based on Capture and Control Efficiencies
. Step 4: Evaluate Remaining ControlTechnologies on Economic, Energy, and Environmental
Feasibility; and
. Step 5: Select RACT.
5.1 Petroleum Products Loading RACT Analysis
5.1.1 Step 1: ldentify All Reasonably Available Control Technologies
A RACT analysis must include the latest information when evaluating control technologies. Control
technologies evaluated for a RACT analysis can range from work practices to add-on controls. As part of
the RACT analysis, current control technologies already in use for VOCs sources can be taken into
consideration.
As required by the RACT review, an assessment of the available control options and associated work
practice standards was performed. The assessment focused primarily on the control of VOC emissions
from the loading rack, and specifically, for the control of VOC emissions generated during the loading of
petroleum products into the cargo tanks.
To support the available controltechnologies that are reasonably available, available US EPA and other
documentation were reviewed. This included:
. US EPA RACT, BACT, LAER (RBLC) Clearinghouse Database
o Control of Hydrocarbons from Tank Truck Gasoline Loading Terminals (EPA-450/2-77-026)
o US EPA AP-42: Compilation of Air Emissions Factors
o Other available information and literature
Search results from the EPA RBLC are included as reference in Appendix B.
Based on our review, reasonably available control options potentially available to reduce VOC emissions
during the tanker truck loading operations include:
5.1.1.1 No Control- Splash Fill
Splash fill simply transfers the petroleum product into the tanker trucks. The fill pipe is partially lowered
into the cargo truck while the petroleum product is dispensed thereby creating significant turbulence
during the filling operation. The turbulence creates a significant amount of vapor generation with
potentially entrained liquid. The generated vapors are displaced from the top of the cargo tank as the
cargo tank is filled.
5.1.1.2 Submerged Loading - Submerged Fill Pipe Loading
Compared to Splash Fill, Submerged Fill Pipe Loading is primarily intended to reduce the formation of
vapors and any entrained liquid as petroleum products are loaded into a tanker truck. ln Submerged Fill
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RACT APPROACH
Pipe Loading, the fill pipe extends beyond the level of the liquid and almost to the bottom of the cargo
tank. The petroleum product added to the cargo tank therefore enters the cargo vessel below the existing
liquid level to minimize splash and any associated turbulence during the filling operation and thereby
minimize the formation of vapors. The generated vapors are displaced from the top of the cargo tank as
the cargo tank is filled.
5.1.1.3 Submerged Loading - Bottom Fill Pipe Loading
Compared to splash fill, bottom fill pipe loading is primarily intended to reduce the formation of vapors and
any entrained liquid as petroleum products are loaded into a tanker truck. ln bottom fill Pipe Loading, a
permanent fill pipe is aftached to the cargo tank boftom. Petroleum products are loaded through an
opening in the tanker truck sidewall located at the bottom of the tank. The fill pipe opening is maintained
below the liquid surface level. Liquid turbulence is controlled significantly during submerged loading,
resulting in much lower vapor generation than encountered during splash loading.
5.1.1.4 Refrigerated Surface Condensers
Refrigerated surface condensers extract organic vapors emitted from the tank loading operation through
condensation, primary through saturation of the organic vapor and then through a phase change from
vapor to liquid. ln an organic vapor stream from a gasoline loading operations, the phase change is
primarily accomplished through lowering the temperature of the vapor stream to the dew point of the
vapor where the partial pressure of the organic compounds is equal to its vapor pressure. A non-contact
refrigeration system is typically used to lower the temperature of the vapor stream where the refrigerant
operates in a closed loop cycle and does not come into contact with the hydrocarbon laden vapor stream
from the cargo tank. Petroleum hydrocarbons collected as part of the condensation process are
recovered and returned back to the process.
5.1.1.5 Vapor Recovery Unit
Control of organic emissions using a VRU is accomplished primarily through the adsorption of the
organics on the surface of a media, typically activated carbon, zeolite, or polymers. As the organic
molecules are adsorbed onto the media surface, the bed becomes saturated where no additional
adsorption can occur leading to breakthrough. Effective and timely regeneration of the adsorption media
through steam, vacuum, or organic stripping is effective in maintaining the overall control efficiency.
Typically, most control systems will employ two separate beds, one in active operation while the other
bed is regenerated. Adsorption is effectively employed to remove VOCs from low to medium
concentration gas streams, when a stringent odtlet concentration must be met and/or recovery of the
VOC is desired.
5.1.1.6 Flare
Control of organic vapors from the gasoline loading operations is primarily achieved by capturing and
piping the vapor to a flare which supports the combustion of the organic vapors in an open flame or
enclosed. There are several factor that determine the effectiveness of the flare to control VOC emissions
such as flame temperature, residence time in the combustion zone, turbulent mixing of the components to
complete the oxidation reaction, and available oxygen. Flaring of organic compounds does produce other
by-products of combustion such as nitrogen oxides (NOx) and carbon monoxide (CO).
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5.1.2 Step 2: Eliminate Technically lnfeasible Control Technologies
5.1.2.1 No Control- Splash Fill
The splash fill option primarily designates the no control option. Petroleum products are transferred into
the tanker trucks through a partially lowered pipe creating significant turbulence and associated
generation of organic vapor and entrained liquid droplets. As for most gasoline loading rack, splash
loading is typically not supported by design (e.9., most gasoline loading terminals will use a'skully"
system to ensure proper connections are established) or will not be allowed by state or federal
regulations.
Considering the control option provides no control and may not be feasible to implement at the Terminal,
the splash fill control option is eliminated from further consideration.
5.1.2.2 Submerged Loading - Submerged Fill Pipe Loading
During submerged fill, the fill pipe extends beyond the surface of the liquid in the tanker truck and thereby
provides for reduced organic vapor generation associated with minimizing the turbulence during tanker
filling relative to splash fill loading. Although the option provides for a lesser generation of organic vapors
as compared to splash loading, any vapors generated are not further controlled but simply emitted to the
atmosphere. Further control of the organic vapors would be achieved by routing the vapors to an external
control device such as a flare or vapor recovery unit. As most gasoline loading rack designs, submerged
fill pipe loading may not be typically supported by design (e.9., most gasoline loading terminals will use a
"skully" system to ensure proper connections are established).
Considering the control option provides a small relative increase in control over splash fill, will require the
implementation of additional control to further reduce VOC emissions, and may not be feasible to
implement at the Terminal, the submerged fill pipe loading is eliminated from further consideration.
5.1.2.3 Submerged Loading - Bottom Fill Pipe Loading
During bottom fill pipe loading, a permanent fill pipe is attached to the bottom of the cargo tank and the
petroleum hydrocarbons are loaded directly below the surface of the liquid minimizing turbulence and
associated vapor generation. Although the option provides for a lesser generation of organic vapors when
compared to splash or submerged fill pipe loading, any vapors generated are not further controlled but
simply emitted to the atmosphere. Further control of the organic vapor would be achieved by routing the
vapors to an external control device such as a flare or vapor recovery unit.
Considering that the control option provides relatively increased control over splash fill and submerged
loading, the submerged loading - bottom fill pipe loading control option is retained for further
consideration.
5.1.2.4 Refrigerated Surface Condensers
Surface condensers support the extraction of the organic vapors from the exhaust stream from the tanker
trucks by condensing the entrained organic vapors and returning the condensed hydrocarbons back to
the storage tanks. Refrigeration is often employed for the condensation process and to support the
removal or control efficiency. The control efficiency achieved is also dependent on the characteristics of
the emissions stream including organic vapor concentration, types of hydrocarbons being condensed, the
type of refrigerant being used, etc. Typical condenser unit equipment for the recovery of gasoline based
hydrocarbon vapors include necessary pumps, compressors, condensers/evaporators, coolant reservoirs,
the VOC condenser unit and VOC recovery tank, precooler, instrumentation and controls, and piping.
Removal efficiencies of approximately 50 to 90 percent can be achieved with coolants such as chilled
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RACT APPROACH
water and brine solutions, and removal efficiencies above 90 percent can be achieved with ammonia,
liquid nitrogen, chlorofluorocarbons, hydrochlorofluorocarbons, or hydrofluorocarbons.3
Considering that the control option provides adequate control and can be reasonably implemented at
existing loading terminals for the control of VOC emissions, refrigerated surface condensers is retained
for further consideration.
5.1.2.5 Vapor Recovery Units - Carbon Adsorbers
Control of VOC emissions is primarily achieved by passing the organic vapors through a media typically
carbon, zeolite, or polymers where the organic \ftapors adsorb onto the surface of the media. VRU types
typically include fixed bed units, moving bed units, canister units, or fluid-bed adsorbers depending on
their configuration. Regeneration of the media is typically achieved by thermal, vacuum or, pressure
based regeneration. When properly designed, operated, and maintained, carbon adsorbers can achieve
high VOC removal efficiencies of 95 to 99 percent at input VOC concentrations of between 500 and 2,000
ppm in air. Removal efficiencies greater than 98 percent can be achieved for dilute waste streams.a
VOC emissions generated from the top of the tanker trucks are piped directly to the VRU for control and
recovery. Considering that the control option provides adequate control and can be reasonably
implemented at existing loading terminals for the control of VOC emissions, VRU (Carbon Adsorbers) is
retained for further consideration. lt should be noted that HEP currently operates and existing carbon
adsorber VRU for the control of VOC emissions during the loading of petroleum products into tankers.
5.1.2.6 Flare - Vapor Combustion Unit
Control of VOC emissions is primarily achieved through the combustion of VOC vapors assisted by
supplied natural gas and excess air. The amount of combustion gas and volume of air introduced into the
combustion chamber is adequately controlled to achieve the necessary control efficiency and VOC
emission rate at the combustor stack outlet. Control efficiencies are typically in excess of 98% but among
other factors dependent on the specific hydrocarbon in the vapors from the loading rack as well as the
inlet hydrocarbon concentration. Consideration is given to the fact that the destruction of VOC forms other
criteria pollutants such as NOx, CO, and HAPs.
VOC emissions generated from the top of the tanker trucks are piped directly to the VCU. Considering
that the control option provides adequate control and can be reasonably implemented at existing loading
terminals, the control of VOC using a VCU is retained for further consideration. lt should be noted that
HEP currently operates a VCU for the control of VOC emissions during the loading of petroleum products
into tankers. The VCU is a backup to the existing VRU and is typically operated when the VRU is shut
down for maintenance.
5.1.3 Sfep 3; Rank Remaining Control Technologies Based on Capture and
Control Efficiencies
A summary of the estimated control effectiveness for the control technologies retained as part of Step 2 of
the RACT review is provided in Table 4. The control effectiveness values are estimated based on
available literature as provided in Section 5.1.2. The control options have been listed in order of those
providing the highest to the lowest control effeciiveness.
3 EPA Air Pollrrtion Control Cost Manual, Section 3, Chaptcr 2, Refrigerated Controls (EPN452IB-02-OO1)
a EPA Ai, Pollution Control Cost Manual, Seclion 3, Chapter 1, Carbon Adsobers (EPN4521B-02-OO1)
HOLLY ENERGY PARTNERS
Reasonably Available Control Technology Review
RACT APPROACH
Table 4. Truck Loading - Control Effectiveness.
Control Option Capture Efficiency Control Efficiency
Vapor Recovery Units - Carlcon Adsorbers 100o/o 95 - 99%
Flare - Vapor Combustion Unit 100%>gg%5
Refrigerated Surface Condensers lOOYo
50 to 90% (chilled water/brine coolants)
>90% (ammonia, liquid nitrogen,
CFC,HCFC, HFC coolants)
Submerged Loading - Bottom Fill Pipe
Loading 1O0o/o 60%6
5.1.4 Step 4: Evaluate Remaining Control Technologies on Economic, Energy,
and Environmental Feasibility
5.1.4.1 Economic lmpacts
Typically, a thermal oxidation system such as a VCU is are considered less costprohibitive to purchase,
install, and operate as compared to a vapor recovery ffRU or refrigerated surface condensers). However,
the gasoline recoveries associated with a VRU or refrigerated surface condensers help offset the cost
difference such as the net annualized costs are typically lower for vapor recovery.T For the purposes of
this RACT analysis and considering that the site has existing control equipment installed a detailed
assessment of the economic impacts of install a VCU, VRU, or refrigerated surface condenser is not
provided.
5.1.4.2 Energy lmpacts
The energy impacts for the installation and operation of a VRU, VCU, or a refrigerated surface
condensers is not considered significant. Energy is required for the operation of the necessary
compressors, pumps, and other equipment for the proper operation of the control device. ln a VCU,
additional energy costs are associated with the use of gaseous fuel (usually natural gas) to support the
control of VOC emissions.
5. 1.4.3 Environmental lmpacts
There are no significant environmental impacts associated with the use of VRU's, VCU's, or refrigerated
surface condensers. For VRU's consideration may need to be given for use and disposal of spent carbon,
however, most current VRU systems support the in-place regeneration of activated carbon using dual
carbon beds. For VCU's, consideration will need to be given to the formation of criteria pollutants,
primarily NOx and CO, as a by-product of the combustion of gasoline vapors. Similar to the VRU, a
refrigerated surface condenser may need consideration of the overall environmental impacts considering
the type refrigerant used.
5 Besides other factors, control efficiency is dependent on the specific hydrocarbon in the vapors from the loading rack as well as
the inlet hydrocarbon concentration.
6 Control efficiency estimated based on the uncontrolled emissions factor for submerged loading (dedicated normal service) and
splash loading (dedicated normal service) as referenced from US EPA AP42, Section 5.2, Transportation and Marketing of
Petroleum Liquids (July 2008)
7 Control if Hydrocarbons from Tank Truck Gasoline Loading Terminals, EPA-450I2-77-026
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Reasonably Available Control Technology Review
5.1.5 Sfep 5; Selecf RACT
HEP is currently proposing either a VCU or VRU as RACT for the Terminal. Both control technologies
implemented considering the economic, environmental, andprovide equivalent controland can be
energy impacts.
Please note that HEP currently operates a and a VCU at the Terminal. The VRU is considered the
primarily control mechanism, with a emission limit of 10 mg-VOC/L (6-hour rolling average). The
VCU is only operated when the VRU is shut for maintenance. Considering that the Terminal
currently operates a VRU with a VCU as HEP contends that it has already implemented RACT
for VOC emissions from the truck loading
5.2 Equipment Leaks
5.2.1 Step 1; ldentify All Avai I a bl e C o ntrol Tech n ol ogi es
The Terminal is a source of small quantities VOC emissions associated with onsite equipment
components such as valves, flanges,, and piping. Typically, facilities that are source of such
fugitive VOC emissions implement onsite procedure to identify and eliminate equipment
leaks. Additionally, certain facilities may be lect to state or federal standards that may require the
implementation of a LDAR program to i and eliminate leaks, thereby further minimizing VOC
emrssrons.
A RACT analysis must include the latest when evaluating control technologies. Control
technologies evaluated for a RACT analysis range from work practices to add-on controls. As part of
already in use for VOCs sources can be taken intothe RACT analysis, current control
consideration.
As required by the RACT review, an of the available control options and associated work
practice standards was performed. The
from fugitive equipment leaks.
focused primarily on the control of VOC emissions
Based on a review of the US EPA's RBLC database, the database identified no control option for
reducing emissions from piping component fugilives. Therefore, based on our review of existing work
practices typically implemented to reduce fugitive VOC emissions, the following control options were
evaluated.
5.2.1.1 Leak Detection and Repair - Audio Visual Olfactory
The LDAR audio, video, olfactory (AVO) controloption typically includes conducting site surveys for
equipment leaks and relying on sight, sound, and smell to identify and locate equipment leaks and
qualitatively assess the concentration of the leak. Surveys can be completed at varied frequencies
considering a facility's maintenance schedule or the frequency may be driven by a regulatory
requirement.
5.2.1.2 Lead Detection and Repair - lnstrument Monitoring
An LDAR instrument based monitoring program typically includes conducting site survey for equipment
leaks using an instrument (flame ionization detector, photoionization detector, or infrared camera, etc.)to
identify and locate equipment leaks and quantitatively assess the concentration of the leak. Surveys can
be completed at varied frequencies considering a facility's maintenance schedule or the frequency may
be driven by a regulatory requirement.
RACT APPROACH
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Reasonably Avaalable Control Technology Review
5.2.2 Step 2: Eliminate Technically lnfeasible Control Technologies
lmplementation of a LDAR program using AVO or instrument based monitoring are considered technically
feasible and are therefore retained for further consideration.
5.2.3 Sfep 3; Rank Remaining Control Technologies Based on Capture and
Control Efficiencies
Based on best practices guidance developed by the US EPA, the control effectiveness of an LDAR
program can vary significantly (45 to 95 percent). Many factors attribute to this variability including the
type of LDAR program (monitoring frequency, leak rate definitions, types of components, etc.) and the
type of facility (refinery, chemical processing, etc.). Further, the control effectiveness of an AVO
inspection program is difficult to assess and is generally intended as a supplementary program only.
Therefore, a general control effectiveness has not been established for AVO inspection programs.
5.2.4 Step 4: Evaluate Remaining Control Technologies on Economic, Energy,
and Environ mental Feasibility
The implementation of an AVO or instrument based LDAR program have similar consideration in terms of
the economic investment made by HEP for implementation of the programs. Typically, both the AVO
based and instrument programs can be implemented by the facility itself. lnstrument based monitoring
program may require hiring external contractors to support the proper implementation of the program
considering personnel availability, training, instrumentation requirements, etc. Energy and environmental
feasibility are not given further consideration in this assessment considering the nature and type of
controls being considered.
5.2.5 Sfep 5; Select RACT
Considering the additional investment needed by the Terminalto support an instrument based LDAR
program either supported by external contractor or by site personnel, HEP is currently proposing an AVO
based LDAR program as RACT for the fugitive emissions from components.
It should be note that the Terminal is cunently considered an affected source under the requirements of
new source performance standard (NSPS) 40 CFR 60 Subpart Wa and has implemented an instrument
based LDAR program to identify and eliminate leaks to reduce VOC emissions. Considering that HEP
cunently implements an instrument based LDAR program at the Terminal, HEP contends that it has
already implemented RACT for fugitive VOC emissions equipment components.
5.3 Soil Remediation System
The DPE system is a source of VOC emissions. VOC emissions from the DPE system are controlled
using a FOD system which consists of a hybrid thermal oxidation technology designed to treat high
concentrations of VOCs and a catalytic oxidation module which will allow the unit to operate once
concentrations decline to appropriate levels (approximately less than 25 percent of the lower explosive
limit). Overall, the existing DPE system provide a 99o/o control of VOC emissions relative to the inlet
concentration.
Considering the control effectiveness of the FOD system, HEP contends that it has implemented an
effective form of VOC emissions control and therefore HEP contends that it has already implemented
RACT for VOC emissions the DPE system.
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6. RACT COMPLIANCE AND IMPLEMENTATION SCHEDULE
As requested by UDAQ, Table 5 includes information regarding proposed testing and monitoring as well
as a schedule for completing implementation of MCT.
Requested lnformation HEP Response
HOLLY ENERGY PARTNERS
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The proposed testing, monitoring, recordkeeping, and
reporting procedures to demonstrate compliance with
the proposed RACT requirement(s) and/or limitation(s).
A schedule for completing implementation of the RACT
requirement or RACT emissions limitations by late 2023,
including start and completion of project and schedde
for initial compliance testing
RACT COMPLIANCE AND IMPLEMENTATION SCHEDULE
HEP is not proposing any additional testing,
m on itorin g, recordkeeping, and reporti ng proced u res
to demonstrate compliance with the RACT
requirements or limitation. The requirements identified
in AO DAQE-AN01012300238-07 forthe Loading
Rack and AO DAQE-ANO101230034-10 for the DPE
system are considered adequate for compliance with
the RACT requirements.
With this RACT analysis, HEP asserts that the control
strategies proposed by HEP as RACT have already
been implemented at the Terminal and a schedule for
completing implementation of RACT, including any
initial compliance testing, is not required.
Table 5. RACT Complianoe and lmplementation Schedule.
m.em.@m Prcjet No.: 0550517 Holly Ensrgy Partm
APPENDIX A ACTUAL AND POTENTIAL EMISSIONS, NOx AND VOC
t
ND
ERMThe business of suslarTtability
ApFdt A - Actr.l .rd PIE
Exbthe ConlDL
Lo.dng Raot @o{n., d@1, ild lct tud
ab trnkar fkb ard io ,a.500.000 bbt
I,056 h@E/yr
(VCU only)
,l0.00 m/L v.por [e-mail] t,rtt (\,/RU)
f.por Cohb6lion t,nlt (VCU) (b..tup)a0 CFR 61, Sdpad xX 1.92W 1.90 tsy 1.88 hy 0.13 &y
dioc s d.fEd ln a0 CFR
3.641; p.ltrF6, @rnpl@,
rduc rallof ddl6.NMa Nme Lo.k lrupcctoB 0.25 Fy Not 0.25 byamdhC @me6-tq !y8iem8,
p*.nd.d Ekd 0 li@,
alv6. d iGtumntalid
Appll6ble
Soil R.mdi.dor
SB.m
idl g.! v.po6 iton 3lte
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Pmitt d VCU Amd Opaaling HNE =
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APPENDIX B RBLC DATABASE REVIEW
ERMThe business of susfarnability
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_I,IAH DEPARruENT OFENVIRO{MENTAL OIIATTTY
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DIVISION OF AIR QUAUTY
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