DAQ-2024-008125

ANWgY"
Dean Anderson
Vice President
Tesoro Refining &
Marketing Company LLC
A subsidiary of Marathon Petroleum Corporation
474 W 900 N
Salt Lake City, UT 84103
UTAH DEPARTMENT OF
ENVIRONMENTAL QUAUTY
AP[i - I :il!,'l
tt
H an I c(et i t/erecl
DIVISION OF AIR QUALIT\"
April4,2024
Utah Division of Air Quality
Attn: Jon L. Black
195 North 1950 West
P.O. Box 144820
Salt Lake City, Utah 84116
Re: Serious Ozone Nonattainment SIP
Reasonably Available Control Technology (RACT) Analysis for
Tesoro Refining & Marketing Company LLC Refinery and Tesoro Logistics Operations
LLC's Remote Tank Farm
Dear Mr. Black,
Tesoro Refining & Marketing Company LLC dlbla Marathon Salt Lake City (Marathon) submits the
attached Reasonably Available Control Technology (RACT) assessment per the Utah Department of
Environmental Quality Division of Air Quality (UDAQ) request dated May 31,2023.
If you have any questions regarding this submittal, please contact Brian Mitchell at
Dean Anderson
Vice President
Tesoro Refining & Marketing Company LLC
Attachment l: RACT Analysis Report
Mr. Was Waida - SLC
Mr. Chris Kaiser - SLC
Mr. Brian Mitchell - SLC
Ms. Michelle Bujdoso - Marathon Corporate
Ozone Serious Nonotloinmenl
Slqle lmplemenlotion Plon
Reoson obly Availoble Confrol lech nology Anolysis
Prepored for
Morothon Solt Loke City Refinery
April4,2024
UTAH DEPARI MENT OF
E i\lvl Ro l{MENTAL gqALlIf
APR - B 2024
-D'''''C)N 'F A'- OUA
Reosonobly Avoiloble Control Technology Anolysis
April 3,2024
Contents
RACT Methodology -7
2.1.1 Step 1 - ldentify all Available Control Techno|ogies...................,........,.,,.,,.,..7
2.1.2 Step 2 - Eliminate Technically lnfeasible ControlTechnologies....................... .............7
2.1.3 Step 3 - Rank Technically Feasible Technologies by Control Effectiveness ..............8
2.1.4 Step 4 - Evaluate Technically Feasible Control Techno1o9ies...................... ..................8
Overview of Available Control Technologies .........1 3
RACT for Fluidized Catalytic Cracking Unit (FCCU) and Carbon Monoxide Boiler (COB) .....................16
4.1.1 Step 1 - ldentify All Available Control Techno1o9ies....................... ................................17
4.1.2 Step 2 - Technical Feasibility of Control Techno|o9ies....................... ............................17
4.1.3 Step 3 - Effectiveness of Feasible Control Techno1o9ies...................... .........................18
4.1.4 Step 4 - Evaluation of Feasible ControlTechnologies....................... ..............................18
4.2.1 Step 1 - ldentify All Available Control Techno1o9ies....................... ................................18
4.2.2 Step 2 - Technical Feasibility of Control Techno1o9ies....................... ............................1 8
4.2.3 Step 3 - Effectiveness of Feasible Control Technologies ......................1 9
4.2.5 Step 5 - RACT Selection....
RACT for Process Heaters.........
19
)i
i
5.2 ProcessHeatersNOxEmissions.....................................................21
6.1.3 Step 3 - Effectiveness of Feasible Control Technologies ...............................26
6.1.5 Step 5 - RACT Selection..
6.2.4 Step 4 - Evaluation of Feasible Control Technologies..........,..,.28
8.1.1
8.1.2
8.1.3
8.1.4
8.1.5
Step 4 - Evaluation of Feasible Control Technologi ..........................33
Step 5 -MCT Selection
MCT for Refinery Wastewater System
9.1 Refinery Wastewater VOC Emissions .............................34
9.1.5 Step 5 -RACT Selection................35
10.1 RefineryDrainsVOC Emissions..............
10.1.5 Step 5 - RACT Selection........37
1 1.1.5 Step 5 - RACT Selection
11.2.4 Step 4 - Evaluation of Feasible Control Techno1o9ies................................41
34
12.1 SRU Flare NOx Emissions..
12.1.2 Step 2 - Technical Feasibility of Control Technologies
12.1.5 Step 5 - RACT Selection ..............43
13 RACT for Cooling Towers...............45
14 RACT for Loading Racks.................47
14.1.1 Step 1 - ldentify All Available Control Techno1o9ies.......................47
14.2.5 Step 5 - RACT Selection....................49
15.1.1 Step 1 - ldentify All Available Control Techno1o9ies....................... ................................50
tv
15.1.4 Step 4 - Evaluation of Feasible ControlTechnologies..............................................5 1
15.2 K1 Compressors VOC Emissions 51
15.2.2 Step 2 - Technical Feasibility of Control Techno1o9ies...................51
15.2.3 Step 3 - Effectiveness of Feasible Control Technologies ...................... .........................52
15.2.4 Step 4 - Evaluation of Feasible Control Techno1o9ies.....................q,
15.1 Fixed Roof Tanks VOC Emissions ....................54
16.1.2 Step 2 - Technical Feasibility of Control Techno1o9ies................................
15.1.3 Step 3 - Effectiveness of Feasible ControlTechnologies...................... .........................55
16.1.4 Step 4 - Evaluation of Feasible Control Techno1o9ies........................................55
16.1.5 Step 5 - RACT Selection................59
17.1 lFRTanksVOC Emissions.........-..-......
18.1.1 Step 1 - ldentify All Available Control Technologies .,..,.,..,u
18.1.3 Step 3 - Effectiveness of Feasible Control Technologies ..................................65
19.2.5 Step 5 - RACT Selection
20.2.5 Step 5 - RACT Selection............................73
70
Table 1-1
Table 1-2
Table 1-3
Table 2-1
fade2-2
Table 3-1
Table 3-2
Table 4-1
Table 4-2
Table 4-3
Table 4-4
Table 5-1
Table 5-2
Table 5-3
Table 5-4
Table 5-5
Table 6-1
Table 6-2
Table 6-3
Table 5-4
Table 7-1
TableT-2
Table 7-3
TableT-4
Table 8-1
Table 8-2
Table 9-1
Table 9-2
Table 10-1
Table 10-2
Table 10-3
Table 1 1-1
Table 1 1-2
Table 1 1-3
Table 1 1-4
Table 12-1
List of Tobles
DEQ Requirement lncorporation ..............1
Summary of Emission Units and Pollutants subject to RACT................
Summary of Emission Unit Limits... ..........3
RACT Cost-Effectiveness Determinations.................... ......................... 10
Summary of Control Technology Guidelines... ..........12
Available NOX Emission Control Techno1o9ies....................... ...........13
Available VOC Emission Control Techno1o9ies....................... ...........14
Technical Feasibility of NOx ControlTechnologies for FCCU and CO8......................................17
Control Effectiveness Ranking of NOx Control Technologies for FCCU and COB.................. 18
Technical Feasibility of VOC Control Technologies for FCCU and COB ............ 19
Control Effectiveness Ranking of VOC Control Technologies for FCCU and CO8................. 19
Technical Feasibility of VOC Control Technologies for Process Heaters ..........20
Control Effectiveness Ranking of VOC Control Technologies for Process Heaters...............21
Technical Feasibility of NOx Control Technologies for Process Heaters with ULNB
lnstalled (H-101, F-1, F-580/F-681)................ ................22
Technical Feasibility of NOx Control Technologies for Process Heaters with LNB
Control Effectiveness Ranking of NOx Control Technologies for Process Heaters................23
Technical Feasibility of NOx Control Technologies for Cogeneration Units.............................26
Technical Feasibility of VOC Control Technologies for Cogeneration Units............................27
Control Effectiveness Ranking of VOC Control Technologies for Cogeneration Units........28
Cost Evaluation of VOC Control Technologies for Cogeneration Units. ...........28
Technical Feasibility of NOx Control Technologies for SRU
Control Effectiveness Ranking of NOx Control Technologies for SRU....... ........30
Technical Feasibility of VOC Control Technologies for SRU .........31
Control Effectiveness Ranking of VOC Control Technologies for SRU ..............31
Technical Feasibility of VOC Control Technologies for Fugitive Equipment............................33
Control Effectiveness Ranking of VOC Control Technologies for Fugitive Equipment........33
Technical Feasibility of VOC Control Technologies for Refinery Wastewater System.......... 34
Control Effectiveness Ranking of VOC Control Technologies for Refinery Wastewater
Technical Feasibility of VOC Control Technologies for Refinery Drains.....................................36
Control Effectiveness Ranking of VOC Control Technologies for Refinery Drains.................37
Cost Evaluation of VOC Control Technologies for Refinery Drains............ .........37
Technical Feasibility of NOx Control Technologies for North and South F|ares.....................39
Control Effectiveness Ranking of NOx ControlTechnologies for North and South Flares.40
Technical Feasibility of VOC Control Technologies for North and South Flares ....................41
Control Effectiveness Ranking of VOC ControlTechnologies for North and South Flares 41
Technical Feasibility of NOx Control Technologies for SRU Flare
29
vil
,..,..,.,..42
Table 12-Z
Table 12-3
Table 12-4
Table 13-1
Table 13-2
Table 14-1
Table 14-2
Table 14-3
Table 14-4
Table 15-1
Table 15-2
Table 15-3
Table 15-4
Table 15-5
Table 15-6
Table 16-1
Table 16-2
Table 17-1
Table 17-2
Table 18-1
Table 18-2
Table 19-1
Table 19-2
Table 19-3
Table 19-4
Table 20-1
Table 20-2
Appendix A
Appendix B
Control Effectiveness Ranking of NOx ControlTechnologies for SRU F|are.............................43
Technical Feasibility of VOC Control Technologies for SRU F|are............... ........43
Control Effectiveness Ranking of VOC Control Technologies for SRU F|are............................44
Technical Feasibility of VOC Control Technologies for Cooling Towers....................................45
Control Effectiveness Ranking of VOC Control Technologies for Cooling Towers................45
Technical Feasibility of VOC Control Technologies for Loading Racks ......................................47
Control Effectiveness Ranking of VOC Control Technologies for Loading Racks..................47
Technical Feasibility of VOC Control Technologies for Loading Racks
Control Effectiveness Ranking of VOC Control Technologies for Loading Racks..................48
Technical Feasibility of NOx Control Technologies for K1 Compressors ..........50
Control Effectiveness Ranking of NOx Control Technologies for K1 Compressors...............51
Cost Evaluation of NOx Control Technologies for K1 Compressors............................................51
Technical Feasibility of VOC Control Technologies for K1 Compressors ..........52
Control Effectiveness Ranking of VOC Control Technologies for K1 Compressors...............52
Cost Evaluation of VOC Control Technologies for K1 Compressors ...........................................52
Technical Feasibility of VOC Control Technologies for Fixed Roof Tanks................................. 54
Control Effectiveness Ranking of VOC Control Technologies for Fixed Roof Tanks.............55
Technical Feasibility of VOC Control Technologies for IFR Tanks............. ..........61
Control Effectiveness Ranking of VOC Control Technologies for IFR Tanks............................62
Technical Feasibility of VOC Control Technologies for EFR Tanks............. .........65
Control Effectiveness Ranking of VOC Control Technologies for EFR Tanks...........................55
Technical Feasibility of NOx Control Technologies for Emergency En9ines.............................68
Control Effectiveness Ranking of NOx Control Technologies for Emergency Engines ........69
Technical Feasibility of VOC Control Technologies for Emergency En9ines............................69
Control Effectiveness Ranking of VOC Control Technologies for Emergency Engines........70
Technical Feasibility of NOx Control Technologies for Temporary Boi1ers...............................72
Control Effectiveness Ranking of NOx Control Technologies for Temporary Boilers.... .......73
List of Appendices
Utah Petroleum Association Letter to Environmental Protection Agency
Control Cost Evaluations
48
vu
I Execulive Summory
The Utah Division of Air Quality (UDAQ sent a letter to Tesoro Refining & Marketing Company LLC
Oesoro) dlb/a Marathon Salt Lake City (Marathon) dated May 31, 2023 regarding submission of a
Reasonably Available Control Technology (RACT) analysis for the Marathon Salt Lake City Refinery
(Agency lD 10335) and Tesoro Logistics Operations LLC's Truck Loading Rack and Remote Tank
Farm (Agency lD 15659 - Truck Loading Rack and Remote Tank Farm are owned by Tesoro Logistics
Operations LLC). Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC are
both subsidiaries of Marathon Petroleum Corporation. UDAQ is providing an opportunity for Tesoro and
Tesoro Logistics Operations LLC to re-evaluate the MCT analysis submitted for the Truck Loading Rack
OLR) and Remote Tank Farm (RTF) and perform a new RACT analysis for NOx and VOCs for the Marathon
Salt Lake City Refinery. These requirements of the May 31, 2023, letter have been addressed in the report
in the locations outlined in Table 1-1 below.
Ioble l-l DEQ Requlremenl lncorporolion
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 l
characteristics, including but not limited to: the size or capacity of each
affected emission unig types of fuel combusted; the types and quantities
ofmaterialsprocessedorproducedineachaffectedemissionunit
'Sections 4 to 20
PTE Available Through Submitted
Title V Application (2015)
Estimates of the potential and actual NOx and VOC emissions from each
affected source, and associated supporting documentation.
PTE Available Through Submitted
Title V Application (2015)
The actual proposed altemative NOx RACI requkement(s) or NOx RACI
emissions limitation(s), and/or the actual proposed VOC requirement(s) or
VOC RACI emissions limitation(s) (as appticable).
Supporting documentation for the technical and economic considerations
for each affected emission unit.
Appendix B: Cost-Effectiveness
Calculations
A schedule for completing implementation of the RACT requirement or
RACT emissions limitation by May of 2026, including start and completion
of project and schedule for initiaicompliance testin!.
Proposed testing, monitoring, recordkeeping, and reporting procedures to
demonstrate compliance with the proposed MCT requirement(s) andlor
limitation(s).
Table 1-3
Additional information requested by DAQ necessary for the evaluation of
the RACT anallnes.
The Ozone lmplementation Rule requires the State lmplementation Plan (SlP) to include RACT measures
for all major stationary sources in nonattainment areas classified as moderate or higher. Therefore, this
serious nonattainment classification triggers RACT requirements at the Marathon facilities. This document
serves as the updated RACT assessment for the facility. For purposes of this submittal, Marathon has
included emission units within the Marathon Salt Lake City Refinery and RTF. A RACT evaluation for
emission units located at the TLR will be submitted under separate cover. The MCT assessment will assist
UDAQ in determining reasonably available technically and economically feasible pollution controls as
necessary by a serious designation for ozone by performing an evaluation of existing emission units
emitting the following:
o Oxides of nitrogen (NOx)
o Volatile organic compounds (VOC)
Table 1-2 lists the project-related emission units and pollutants that have been included in the RACT
assessment.
Ioble l -2 Summory of Emission Unlts ond Pollulonts subjecl lo RACI
NO)c VOCFCCU/CO Boiler
H-l01 Crude Unit Furnace NOx, VOC
F-1 Ultraformer Unit Furnace NO)c VOC
F-1 5 Ultraformer Regeneration Fumace NO)c VOC
F-680 DDU Furnace NOx, VOC
F-681 DDU Fumace NOTVOC
F-701 GHT Furnace NOx, VOC
Cogeneration Units (2)No:&VOC
Sulfur Recovery Unit (SRU)NOr VOC
Fugitive Equipment voc
Refinery Wastewater System voc
Refinery Drains voc
North and South Flares NOr VOC
SRU Flare Nq(,VOC
Reformer Regeneration Vent VOC
Cooling Tower UU2 voc
Cooling Tower UU3 voc
Transport Loading Rack (1)voc
This RACT analysis follows EPA's five-step top-down approach, as specified in the U.S. EPA's draft New
Source Review Workshop Manual, (October 1990) and outlined by UDAQ.1,2
. Step 1 - ldentify All Available Control Technologies
. Step 2 - Eliminate Technically lnfeasible Options
. Step 3 - Rank Remaining Control Technologies by Control Effectiveness
. Step 4 - Evaluate Most Effective Control Technologies and Document Results
. Step 5 - Select RACT
Table 1-3 below summarize RACT for each project-related emission unit and pollutant and control
technologies.
Ioble l -3 Summory of Emission Unit limits
1 The workhop manual can be found at U.S. EPA's website
h ttp ://www. e pa. g ovlN S R/tt n n s r0 1 /g e n/wks h p m a n. pd f .
2 The UDAQ Ozone SIP Overview and Schedule presentation is available at:
https://documents.deq.utah.gov/air-quality/planning/technical-analysis/DAQ-2021-000242.pd1
FCCU Regenerator &
CO Boiler
Wet gas scrubber with
use of LoTOx add-on &
refinery-wide NOx limit.
(007s-18) II.B.1.9,
II.B.4.a,lI.B.4.f, &
II.B.7.a Current operations
meet MCT, no
further action
warranted.
Process Heaters and
Boilers
Nox
LNB & ULNB required
on various units, &
refinerywide NOx limit
(0075-18) ILB.1.g,
ILB.3.a, & ILB.7.a Cunent operations
meet MCT, no
further action
warranted.voc
Good combustion
practices, no additional
controls.
(007s-18) r.s
Cogeneration Turbines
NOx
Good combustion
practices, use of
gaseous fuels, &
refinery-wide NOx limit.
SCR installation
required under the
moderate SIP.
(007s-18) II.B.1.g &
II.B.7.a
Installation of SCR
thatmeetsa5ppm
NOx limit by
October 1,2028.
Required by the
moderate SIP
Section X, Part
H.32j.voc
Good combustion
practices, no additional
controls.
(007s-18) r.5
SRU NOx
Good combustion
practices & refinery-
wide NOx limit
(0075-18) [.B.1.g
Current operations
meet MCT, no
further action
warranted.
Cooling Towers voc
MACT Subpart CC
requirements on
cooling towers
servicing high VOC heat
exchangers.
(007s-18) r.s
Current operations
meet MCT, no
further action
warranted.
Fugitive emissions voc
Low leak LDAR
requirements of NSPS
Subpart GGGa.
(007s-18) r.s
Current operations
meet MCT, no
further action
warranted.
Tanks voc
Submerged fill
operations, and tank
degassing requirements
- eventual compliance
with NSPS Subpart Kb
or MACT Subpart CC.
Secondary seal
installation on Tank 321
required under the
moderate SIP.
(0075-18) rr.B.9
Installation of
secondary seal on
Tank 321 by May 1,
2026. Required by
the moderate SIP
Section IX, Part
H.32j. All other
current operations
meet MCT, no
further action
warranted.
Wastewater Sptem
API separator unit with
fixed cove[ installation
of closed vent system
to carbon adsorption
required
(007s-18) 15
Installation of a
closed vent system
to carbon
adsorption by
December 31, 2025
in compliance with
NSPS Subpart QQQ.
Required by the
moderate SIP
Section X Part
H.32j.
Refinery Flares
Evaluated through
control of flare gases,
not through individual
pollutants, requirement
to meet Subpart Ja for
flares.
(0075-18) rr.B.1.f
Current operations
meet MCT, no
further action
warranted.
Standby Emergency
Engines
Proper maintenance
and operation, and
compliance with
applicable NSPS or
MACT requirements.
(007s-18) r.s
Current operations
meet MCT, no
further action
warranted.
K1 Compressors
(natural gas engines)
Catalytic converters,
proper maintenance
and operation, &
refinerywide NOx limit.
(007s-18) r.s (007s-
18) ILB.4.a, II.B.7.a, &
II.B.7.c
Current operations
meet RACT, no
further action
warranted.
Marathon has completed and committed to future significant emissions reductions since 2017. These
emissions reductions are achieved by significant investments in emissions control technologies. These
projects include:
FCCU/CO Boiler - Wet gas scrubber and LoTOx
F-1 Ultraformer Unit Furnace - Ultra-Low NOx Burners
Sulfur Recovery Unit (SRU) - Tail gas treatment unit
North and South flares - Flare gas recovery with compressor availability limits, combustion
efficiency requirements, and flare caps
Reduced emissions from storage tanks by installing guidepole controls, retrofitting storage tanks
with lFRs, replacing tanks, and by controlling degassing emissions with a portable thermal
oxidizer.
. Marathon will replace the existing refinery wastewater API separator and DAF unit equipped with
a closed vent system to carbon adsorption in 2025 and will comply with NSPS Subpart QQQ.
o Marathon will install a secondary seal on Tank 321 by May 1,2026.
o Marathon will install selective catalytic reduction (SCR) on the Cogeneration Units by October 1,
2028.
2 RACT Methodology
RACT is defined as devices, systems, process modifications, or other apparatus or techniques that are
reasonably available taking into account social, environmental and economic impacts as well as the
necessity of imposing such controls in order to attain and maintain a national ambient air quality
standard.3
2.1 Top-Down RACT Approoch
This RACT analysis has been conducted in accordance with Section 165(a) (4) of the Clean Air Act (at 40
CFR Part 52.210), and 40 CFR 51.1010(a). RACT technologies have been selected using the "top-down"
approach specified in U.S. EPA's draft New Source Review Workshop Manual, (October 1990),4 using the
five-step process.
2.1.1 Step I - ldentity oll Avoiloble Conhol Technologies
All available control technologies are identified for each emission unit. A control technology is considered
available for a specific pollutant if it could practically be applied to the specific emission unit. To identify
all available control technologies, the following sources were consulted:
o U.S. EPA's RACT/BACT/LAER Clearinghouse (RBLC)
. U.S. EPA's New Source Review (NSR) website
. U.S. EPA draft permit review comments on recent PSD permits
o State/local agency air quality permits and the associated agency review documents
o Permit applications and BACT reports for recent projects
o Air pollution control technology vendors and consultants
o Manufacturer'srecommendations
o Technicaljournals, reports, webinars, conferences, and seminars
2.1.2 Step 2 - Eliminote Technicolly lnfeosible Control Technologies
Each control technology identified in Step 1 is evaluated, using source-specific factors, to determine if it is
technically feasible. lf physical, chemical and engineering principles demonstrate that a technology could
not be successfully used on the emission unit, then that technology is determined to be technically
3 The definition for RACT is set forth in 40 CFR 51.100(o).
l The workshop manual can be found at U.S. EPA's website htto://www.epa.gov/NSR/ttnnsr01/gen/wkshpman.pdf.
infeasible. Economics are not considered in the determination of technical feasibility. Technologies which
are determined to be infeasible are eliminated from further consideration.
2.1.3 Slep 3 - Ronk Technicqlly Feosible Technologies by Control
Effecliveness
All technically feasible technologies are ranked in order of overall control effectiveness. Rankings are
based on the level of emission control expressed as emissions per unit of production, emissions per unit
of energy used, the concentration of a pollutant emitted from the source, control efficiency, or a similar
measure. The control effectiveness listed will be representative of the level of emission control which can
be achieved by the control technology at the operating conditions of the emission unit being reviewed. lf
the most effective control technology is selected as RACT, then Step 4 need not be completed.
2.1.4 Step 4 - Evoluote Technicolly Feosible Conlrol Technologies
The economic, environmental, and energy impacts of each technically feasible control technology are
evaluated. Step 4 is only required if the most effective control technology is not proposed as MCT.
Economic impacts were analyzed using the procedures found in the EPA Air Pollution Control Cost
Manual - Seventh and Sixth Editions (EPA 45218-02-001) as applicable. Vendor cost estimates for this
project were used when available. lf project specific cost data was not readily available, cost data from
other recent comparable projects was used with adjustments for inflation and size. Marathon used
historical vendor information from previous Marathon projections, subject matter expert opinions, and
engineering estimates. With the limited timeframe required for resubmission of this report, Marathon was
unable to use site-specific cost estimates for all emission units. Therefore, Marathon reserves the right to
revisit this evaluation and subsequent resulting conclusions if new information becomes available.
Cost effectiveness is evaluated on a dollar-per-ton ($/ton; basis using the annual operating cost ($/yr)
divided by the annual emission reduction achieved by the control device (ton/yr). A control technology is
considered economically infeasible if the control cost on a dollar-per-ton basis exceeds the amount that
other sources in the same industrial classification have incurred. The EPA provides guidance for
completing economic impact analyses in the draft New Source Review Workshop Manual (October 1990).
Chapter B, Section lV.D.2. states:
"Cost effediveness (dollors per ton of pollutont reduced) volues obove the levels experienced by
other sources of the some type ond pollutont, ore token os on indicotion thot unusuol ond
persuasive differences exist with resped to the source under review. ln oddition, where the cost of a
control olternotive for the specific source reviewed is within the ronge of normol costs for thot
control olternotive, the olternotive, in certain limited circumstonces, moy still be eligible for
eliminotion. To justify eliminotion of on olternotive on these grounds, the opplicont should
demonstrote to the satisfoction of the permitting agency thot costs of pollutant removol ore
disproportionately high when compored to the cost of control for thot porticulor pollutant ond
source in recent...determinations. lf the circumstonces of the differences ore odequately documented
ond explained in the opplicotion ond are occeptoble to the reviewing ogency they moy provide o
bask for eliminoting the control alternotive."
The definitions of MCT, both at the state and federal level, include a clause considering the impacts on air
quality. The definitions of best available control technology (BACT), both at the state and federal level,
more narrowly look at the best control technology regardless of the impacts on air quality. Because BACT
excludes the clause considering the impacts on air quality, the cost-effectiveness threshold is necessarily
higher than RACT, assuming that the impacts on air quality are not substantial.
The EPA does not publish RACT and BACT cost-effectiveness thresholds. However, states have established
thresholds in SlPs and NSR permitting actions, and in some cases, EPA has provided direction to the states
on the cost-effectiveness thresholds. For example, EPA indicated to the State of Utah that they needed to
consider a higher cost threshold for BACT for the 2019 Serious Area SIP than for MCT that was used for
the 2014 Moderate Area SIP:
EPA did not estoblish o specific fixed $/ton cost threshold for economic feosibility determinotions,
but indicated thot stotes would need to consider emission redudion meosures with higher costs per
ton when ossessing the economic feosibility of BACM/BACT controk os compared to the criteria
opplied in the RACM/RACT onolysis for the some nonottoinment oreo.s
Readily available MCT cost-effectiveness thresholds are provided in Table 2-1. RACT cost effectiveness
thresholds are commonly between $2,500/ton and $5,500/ton.
s Utah's 2019 State lmplementation Plan Control Measures for Area and Point Sources, Fine Particulate
Matter, Serious Area PMz.s SIP for Salt Lake City UT, Nonattainment Area. Note that Utah did not clearly
establish cost effectiveness thresholds in either version of the SIP containing RACT and BACT reviews.
Toble 2-l RACI Cost-Efiecliveness Delermlnollons
EPA-R03-OAR-201H657: FRL-100'14-53-Region 3
"Responses to Freouently Asked Questions" Final Rulemaking Additional RACT Requirements for Major Sources of Nox and VOCS 25 Pa. Code
Chapters 12'l and 129 46 Pa. 8.2036 (April 23.2016)
Order ofthe State ofWisconsin Natural Resource Board Amending and Creating Rules. State Imolementation Plan
DAR-20:Economic and Technical Analysis for Reasonablv Available Control Technology (RACI Networks (August 8. 2013)
IEPA-R05-OAR-2020-0097: EPA-R05-OAR-2020-O199; EPA-R05-OAR-2020-0200: FRL-1001 1-90-Region 5l
IEPA-R05-OAR-2007-0587; EPA-R05-OAR-2009-0732; FRL-920$€1
Detailed control cost evaluations are enclosed as Appendix B to this report. ln addition to the costs
presented, installation of emissions controls by May 1, 2026, may require an unscheduled shutdown. An
increase in costs would occur due to significant loss of production. The EPA Control Cost Manual confirms
that such costs- including the costs of lost production-are appropriately considered when assessing
economic feasibility:
Lost Production. The shut-down for installation of a control device into the system should be a
well-planned and anticipated event, and typically occurs during routine, scheduled outages. As
such, its cost should be considered a part of the indirect installation cost (start-up). However,
unanticipated problems with the installation due to retrofit-related conditions if they happen
could impose significant costs on the system. Retrofit factors should be reserved for those items
directly related to the demolition, fabrication, and installation of the control system. . . . lf the
t1I
tzt
t3I
t41
tsI
t6I
lllinois - Environmental Protection Agency
2020
2,500 - 3,000
Threshold
1
2016 2
2007 2,500 3
1
:,?016;2
New York - Department of Environmental
Conservation
2020
5.000 - 5,500
Threshold
1
2016 2
1994 3,000 4
I
il
::.2
3
Pennsylvania - Department of Environmental
Protection
2020
2,800 Threshold
1
2016 2
202A.
,.r..ll'-l:..trir :: - r.l
,,-r,i ri.,lt',:;it.i::,, i ..'iiir-\t:i i..r.iii rr,. . l.r'.1:.:l':r". 1. i,.
- r: 25fi) r Threshold
5
2016 2
:.ysygrrilr
6
20f7 3
l0
shut-downs do not occur in a well planned and routine manner, any additional foregone
production of goods and products would need to be included as a private cost attributable to the
retrofit cost.
Marathon reserves the right to provide additional details regarding lost production in the event that
UDAQ determines that any new emissions control technology is required to meet MCT.
The environmental impact analysis assesses collateral environmental impacts associated with control of
the regulated pollutant in question. lmpacts considered may include solid or hazardous waste generation,
wastewater discharges from a control device, visibility impacts, collateral increases in emissions of other
criteria or non-criteria pollutants, increased water consumption, and land use. The environmental impact
analysis is conducted based on consideration of site-specific circumstances.
The energy impact analysis considers whether use of an emission control technology results in any
significant or unusual energy penalties or benefits. Energy use may be evaluated on an energy used per
unit of production basis; energy used per ton of pollutant controlled or total annual energy use. Energy
impacts may consider whether or not use of an emission control technology will have an adverse impact
on local energy supplies due to increased fuel consumption or the loss of fuel production or power
generation.
2.1.5 Siep 5 - Selecl RACT
Based on technical considerations and economic, environmental and energy impacts the proposed RACT
for each emissions unit will include:
A pollutant-specific emission control technology as MCT, a combination of controls, or facility
wide emissions cap (refer to Appendix A) when appropriate
o The definition of RACT does not preclude the use of emission caps. RACT is defined,
in pertinent part, to mean, "devices, systems, process modifications, or other apparatus or
techniques that are reasonably available taking into account ... [t]he necessity of imposing
such controls in orderto attain and maintain a national ambient air quality standard
....6 This definition does not indicate any limitation on emission averaging as part of
RACT. ln fact, the definition contemplates accounting for the "necessity of imposing such
controls" so as to achieve the ultimate objective of attaining and maintaining the
NAAQS. This prudential consideration comports with the notion ol reosonoble
availability 40 CFR 5 51.100(oX1).
Document approach is consistent with applicable Control Technology Guidelines.
640 cFR s 51.100(oX1).
Control technology guidelines applicable to petroleum refineries are summarized below in Table 2-2.
Existing refinery controls are at least as stringent as the Control Technology Guidelines.
Toble2-2 SummoryofConhollechnologyGuldellnes
Control of Volatile Organic Emissions
From Bulk Gasoline Plants
Loading Rack voc Submerged or bottom fill;
Vapor balancing
N/A :,;r;
Design Criteria For Stage I Vapor
Control Systems Gasoline Service
Stations
N/A - no gasoline
dispensing at the refinery N/A N/A
lontrol of l-lydrocarbons From [ani ,
Truck Gasoline Loading Terminals
'voc
Control Of Volatile Organic Compound
Leak From Petroleum Refinery
Equipment
Fugitives voc Leak Detection and Repair
Control Of Refinery Vacuum Producing
Systems, Wastewater Separatos and
Process Unit Tumarounds ' ., : , '
voc
API separator cover .
Flari4g of process'vints
Combustion of vacuum
producing $niems ' i
Control of Volatile Organic Emissions
from Petroleum Liquid Storage in EFR
Tanks
EFR Tanks voc Secondary seal and fitting
requirements
Conlrot of Volatite.Organic Emisiionf trt'ii
trom Storage of Petroleum Liquiaiin.fit
Fixed-RoofTank - " .' I' :i1..:.r:..a;-:iltr
. voc
IFR or closed vent s)6tem
wten {p,00-0 9al!91s aqd
storing gasoline or crude
with a TVP > 1.5 psia
t2
3 Overview of Avqiloble Conlro! Technologies
Available emission control technologies for the Ozone SIP pollutants evaluated in this report are listed in
Table 3-1. This table summarizes the results of Step 1 of the RACT analysis to identify all available control
technologies. Further evaluation of these control technologies for each emissions unit is completed in the
remainder of this report.
Ioble 3-l Avoiloble NOX Emlsslon Conhollechnologles
l3
Toble 3-2 Avoiloble VOC Emlsslon Conlrollechnologies
CO Boiler (COB) with Good Combustion Practices
. _i.\ !i.: i. t::: " I i.GtafititConrol
Catalytic Oxidation
Thermal Oxidation
Vapor Recovery System
Flare
Carbon;Msorption
CO Promoter Catalyst Additive
VOC Promoterwr'th ESP
Good Design Methods and Operating Procedures
Use of Natural Gas
LDAR Program
Enhanced IDAR Program
Maintenance Vent Monitoring
API Separator Floating Covers
API Separator Floating Roof Covers meeting QQQ Standards
Replace uncontrolled drains
Retrofit drains with controls
Flare Gas Recovery with compressor availability requirements
Ftare Management Plan
Flare Cap
Flare Combustion Efficienqy
Comply with emergency engine requirements ol MACT 7777
Replace engine with Tier 4 engine
Compliance with 40 CFR Part 63, Subpart CC
Lorrr emifting drift eliminators
Electrictrify Motor
Compliance with NSPS Subpart Kb forTank
Compliance with 40 CFR 63 Subpart CC for Tanks
l5
4 RACT for Fluidized Cotolytic Crocking Unit (FCCU)
qnd Corbon Monoxide Boiler (COB)
ln the FCCU process, coke is formed on the FCCU catalyst and must be removed in the regenerator to
maintain catalyst performance. ln the regenerator, combustion air is added to burn off the coke in the
catalyst. The regenerator is operated in partial burn mode, in which the regenerator is operated to
produce Carbon Monoxide (CO), which fuels the downstream CO Boiler (COB). Regenerator off-gas is
analyaed by 02, CO, and CO2 continuous emission monitoring systems (CEMS) prior to entry to the COB.
Spare CO, 02, and COZ analyzers are also installed and can be switched to at any time to minimize CEMS
downtime.
The COB is used to recover residual heat from the FCCU Regenerator and create steam, while also
oxidizing CO from the regenerator. To support the FCCU Reactor, residual coke from the circulated FCCU
catalyst is burned off in the FCCU Regenerator so the catalyst can be reused in the reactor. The flue gas
from this regeneration process is fed to the COB and is mixed with flue gases from combustion of refinery
fuel gas. This mixture heats boiler feed water to create high-pressure steam. Emissions are directed out
the top of the COB to the Electrostatic Precipitator (ESP) for particulate removal. The ESP acts as a control
device to remove particulate matter from the COB exhaust. The ESP utilizes an electric field to impact
negative charge on the catalyst fines which then attach to positively charged grids. These fines are
periodically removed from the grids.
Marathon installed a wet gas scrubber (WGS) and LoTOxrM systems downstream of the ESP. The system
was operationalstarting in January 2018. The LoTOxrM system injects ozone into the FCCU/CO Boiler
exhaust stream within the WGS. NOx compounds are oxidized with ozone to form compounds that are
removed from the flue gas in the WGS. SO2 is removed from the FCCU/CO Boiler exhaust gas stream by
contacting the exhaust gas with water, buffered with a sodium reagent (either sodium hydroxide, NaOH
or soda ash or Na2CO), in the spray tower. These same liquid sprays also remove particulates from the
flue gas. Liquid containing these compounds is collected and purged from the scrubber. lt is then
processed by a Purge Treatment Unit (PTU), which separates and dewaters the particulate. The system is
designed to discharge a neutral pH liquid stream. The final effluent is low in total suspended solids (ISS),
and contains up to 10% total dissolved solids ODS) from sodium sulfate and sodium nitrate. The LoTOx
system is only effective during normal operations. The varying operational parameters associated with
startup and shutdown result in inconsistent performance at these times.
There is a bypass stack located upstream of the COB that enables emissions from the FCCU Regenerator
to be discharged directly to the atmosphere, bypassing the COB and ESP, during process upset
conditions. Flue gas from the regenerator enters the F-54 seal tank which contains an exhaust stem that
connects to the COB and a separate connection to the F-55 Seal Tank. The F-55 seal tank contains an
exhaust stem that routes emissions to the COB/ESP Bypass Stack. Each of the two seal drums can be filled
with water to create a water seal that prevents flue gas from escaping up the exhaust stem. The bypass is
used only for operating scenarios (e.9., hot startup) that result in high temperature exhaust (1,300 F) to
l6
exit the regenerator. This temperature is too extreme for the downstream controls to handle requiring a
bypass for equipment preservation. The bypass is not used during normal operations.
4.1 FCCU ond COB NOx Emissions
NOx emissions are the result of catalyst regeneration and combustion in the CO Boiler. Marathon installed
a LoTOx unit along with a Wet Gas Scrubber prior to January 1, 2018.
4.1.1 Step I - ldentity All Avoiloble Conlrol Technologies
Potential control technologies for NOx emissions from a review of available information are listed in
Table 3-1.
4.1.2 Step 2 - Technicol Feosibility of Control Technologies
The technical feasibility of potential control options for NOx emissions are summarized in Table 4-1. The
following sections provide additional detail.
Ioble 4-l lechnicol Feoslbility of NOx Conkollechnologies for FCCU ond COB
Marathon does not have the required process equipment to operate a feed hydrotreatment unit and
therefore a hydrotreatment unit is not considered further for analysis.
As indicated by multiple vendors, NOx reduction additives are not effective reducing agents in partial
combustion FCCU's. As Marathon operates a partial combustion FCCU, NOx reduction additives are not
feasible and are not considered further for analysis.
Most NOx emissions from the COB are due to the oxidation of reduced nitrogen compounds entering the
COB in the catalyst regenerator off gas. Low NOx Burners (LNB) in the COB have no effect on fuel-based
NOx formation, and therefore are not considered further for analysis.
4.1.3 Step 3 - Effecliveness of Feosible Conlrol Technologies
The technically feasible control options are ranked in Table 4-2, according to their control effectiveness.
Toble 4-2 Conhol Eflectlveness Ronklng of NOx Conhollechnologles for FCCU ond COB
4.1.4 Step 4 - Evoluotion of Feosible Conlrol Technologies
The economic, environmental and energy impacts of technically feasible control options are not required,
as the top feasible control option is selected.
4.1.5 Step 5 - RACT Selection
RACT for NOx emissions from the FCCU and COB is a LoTOx unit representing the top performing
technology.
4.2 FCCU ond COB VOC Emissions
VOC is the result of catalyst regeneration. Currently, Marathon operates a COB to reduce the VOC
emissions.
4.2.1 Step I - ldenlify All Avoiloble ConlrolTechnologies
Potential control technologies for VOC emissions from a review of available information are listed in
Table 3-1.
4.2.2 Step 2 - Technicol Feosibility of Conlrol Technologies
The technical feasibility of potential control options for VOC emissions are summarized in Table 4-3. The
following sections provide additional detail.
l8
Toble 4-3 Iechnlcol Feoslblllty of VOC Conhol Technologles for FCCU ond COB
A VOC Promoter with an ESP works well with full burn regeneration, however since Marathon uses partial
burn regeneration this technology is infeasible and is not considered for further analysis. Also, a CO
promoter catalyst additive can only be used in full burn FCCU catalyst regenerators, a CO promoter is
infeasible and not considered further as Marathon uses partial burn regeneration.
The COB effectively acts as a VOC control device for the FCCU, and the WGS would remove any remaining
soluble VOCs from the gas stream. Due to the extremely low concentration of VOCs in the exhaust stream
following the COB, ESP, and the WGS, add on catalytic control is not technically feasible and is not
considered for further analysis. Additionally, catalytic control has not been demonstrated on the outlet of
an FCCU/COB.
4.2.3 Step 3 - Effecliveness of Feosible Conlrol Technologies
The technically feasible control options are ranked in Table 4-4, according to their control effectiveness.
Ioble 4-4 Conhol Effecliveness Ronking of VOC Control Technologies for FCCU ond COB
4.2.4 Step 4 - Evqluolion of Feqsible Conlrol Technologies
The economic, environmental, and energy impacts of technically feasible control options are not required,
as the top feasible control option is already installed.
4.2.5 Step 5 - RACT Seleclion
RACT for VOC emissions from the FCCU is operation of a COB with good combustion practices and a
WGS. During unit startup or shutdown, good combustion practices will be followed to minimize VOC
emissions.
5 RACT for Process Heqlers
Refinery process heaters combust refinery fuel gas and/or natural gas to heat or vaporize hydrocarbon
mixtures for processing in downstream units including distillation, reforming, and hydrotreating. The
refinery has six fired process heaters:
o H-101 Crude Unit Furnace
. F-1 Ultraformer Unit Furnace
o F-15 Ultraformer Regeneration Heater
. F-680/F-681 DDU Heaters
. F-701 GHT Unit Heater
Emissions from process heaters are from fuel combustion.
5.1 Process Heoters VOC Emissions
VOC emissions from the process heaters are a result of incomplete combustion of the refinery fuel gas.
5.1.1 Step I - ldentity All Avoiloble Control Technologies
Potential cOntrol technologies for VOC emissions from a review of available information are listed in
Table 3-1.
5.1.2 Step 2 - Technicol Feosibility of Conlrol Technologies
The technical feasibility of potential control options for VOC emissions are summarized in Table 5-1. The
following sections provide additional detail.
Ioble 5-l lechnicol Feosibility of VOC Conhol Technologles for Process Heolers
All VOC control techniques seek to oxidize products of incomplete combustion, with excess oxygen
typically present.
Marathon contacted vendors regarding VOC removal by catalytic oxidation. Vendors have indicated that
saturated hydrocarbon removal can only be achieved at temperatures above 800'F, which will be above
the normal operating range of the boiler, making catalytic oxidation infeasible for VOC control. AP-42
20
Table 1.4-3 shows factors of individual hydrocarbons, indicating that >99% of the hydrocarbons known to
be present are saturated.
The application of thermal oxidation is also technically infeasible. Required outlet concentrations for
thermal oxidation systems are typically 20 ppmv. The concentration in process heater exhaust streams are
estimated to be below 13 ppm, making thermal oxidation ineffective.
5.1.3 Step 3 - Etfecliveness of Feosible Conlrol Technologies
The technically feasible control options are ranked in Table 5-2, according to their control effectiveness.
Toble 5-2 Conlrol Effecllveness Ronklng of VOC Controllechnologles for Process Heolers
5.1.4 Step 4 - Evoluotion of Feoslble Conlrol Technologies
The economic, environmental and energy impacts of technically feasible control options are not required,
as the top feasible control option is selected.
5.1.5 Step 5 - RACT Seleclion
RACT for VOC from the process heaters is using good design methods and operating procedures. During
unit staftup or shutdown, good operating practices will be followed in order to minimize VOC emissions.
5.2 Process Heolers NOx Emissions
There are three mechanisms by which NOx production occurs during combustion including thermal, fuel,
and prompt NOx formation. ln the case of gaseous fuel combustion, the primary mechanism of NOx
formation is through thermal NOx formation. The H-101, F-1, and F-680/681 process heaters have ULNB
currently installed to assist with reducing NOx formed from the fuel. Process heaters F-15 and F-701 have
LNB currently installed.
5.2.1 Step I - ldentity All Avoiloble ConlrolTechnologies
Potential control technologies for NOx emissions from a review of available information is listed in
Table 3-1.
5.2.2 Step 2 - Technicol Feosibility of Conlrol Technologies
The technical feasibility of potential control options for NOx emissions are summarized in Table 5-3 and
Table 5-4. The following sections provide additional detail.
Good Design Methods
and Operating Procedures
AP-42Table 1.4-2
21
Toble 5-3 lechnlcol Feoslblllty of NOx Conlrollechnologles lor Process Heoters wlth UINB
lnstolled (H-101, F-1, F-680/F-681)
SNCR is not technically feasible for heaters due to the following considerations. As part of the PMz.s SlP,
SNCR was eliminated by UDAQ based on a lack of load responsiveness. First, it requires flue gas remain in
a relatively stable, high, narrow temperature range, typically between 1,550'F and 1,950'F, to function
effectivelyT. Second, SNCR also requires low concentrations of CO in the flue gas, as research shows CO
suppresses SNCR by competing for the hydroryl free radicals that are required for NO to be converted to
Nz8. As such, this technology is not appropriate for many refinery process heaters and boilers, which
typically have average flue gas temperatures of less than 700'F and higher than optimal CO concentration
in the flue gas because they have no flue gas CO treatment.
There is limited plot space available for an SCR reactor at H-101 or F-1. Marathon is limited by railtracks
and the Salt Lake City sewer line easement restrictions in the immediate area where an SCR reactor would
be placed. SCR would have to be built vertical and above process equipment. Further technical evaluation
would be required to confirm technical feasibility, and installation could not occur prior to May 2026. For
purposes of this RACT analysis, Marathon has assumed installation is technically feasible and evaluated it
further.
7 EPA Air Pollution Control Cost Manual, Section 4, Chapter 1 - SNCR, 2019, Figure 1.4, pg. 1-14.
https://www. ep a. g ovls ites/d efa u lt/f i I es/20 1 7-
1 2/documents/sncrcostmanualchapterTthedition20 1 6201 Trevisions.pdf..
8 EPA Air Pollution Control Cost Manual, Section 4, Chapter 1 - SNCR, 2019, pg.1-20.
htt ps : //www. e p a. g ovls i tes/d ef a u I t/f i I e s /20 1 7 -
1 2/documents/sncrcostmanualchaoterTthedition20l 6201 Trevisions.pdf
22
Ioble 5-4 lechnlco! Feoslblllty of NOx ConholTechnologles for Process Heoters wlth LNB
Inslolled (F-l 5, F-701 )
As F-15 and F-701 both use Low NOx burners, it may be theoretically feasible to upgrade the burners to
ULNB. Marathon reviewed and determined that ULNB cannot be installed due to flame impingement.
As described above, SNCR is not technically feasible.
5.2.3 Step 3 - Effecliveness of Feosible Control Technologies
The technically feasible control options are ranked in Table 5-5, according to their control effectiveness.
Ioble 5-5 Conhol Effectlveness Ronking of NOx Conlrol Technologles for Process Heqlers
5.2.4 Step 4 - Evoluolion of Feosible Conlrol Technologies
Refer to Appendix B for supporting details of SCR economic feasibility for process heaters. The average
control cost effectiveness ($/ton) ranges from $128,000 to $425,000. Therefore, the installation of SCR at
the process heaters is not economically feasible. ln addition to the high costs, the use of SCR inherently
results in ammonia slip which causes additional condensable PM emissions to be released to the
atmosphere which is a concern for the surrounding community classified as a PM2.5 Serious
Nonattainment area Additional solid waste is generated from the periodic replacement of the catalyst.
1 Alt SCR 0.005 lblMMBtu RBLC
2 F-1
ULNB
0.065lb/tvlMBtu Existing limit
2 H-101 0.04|b/MMBtu Existing limit
2 F-680/F-
581
Existing limit
2 F-1 5
LNB
0.087 lb/MMBtu Stack Test
2 F-701 0.074]b/MMBtu Stack test
23
5.2.5 Slep 5 - RACT Seleclion
NOx from process heaters is the existing burner configuration because upgrades are economically
infeasible. Additionally, the technical feasibility would require further evaluation even if SCR was deemed
economically feasible.
24
6 RACT for Cogenerotion Unils
The Cogeneration system consists of two turbine trains, designated as the East and West Cogen system
trains. Each turbine burns both natural gas and SRU Sweet Gas; natural gas serves as the primary fuel for
the combustion turbines while supplemental refinery fuel gas consists of up to 30o/o of the mixture. The
combustion exhaust drives a turbine to produce electricity for the refinery and electrical grid, and is then
sent to the heat recovery steam generators (HRSG). The HRSG produces steam for the refinery. The HRSG
is fired with refinery fuel gas. There are no add-on or tail gas emission controls. Passive NOx control on
the turbine is accomplished by the SoLoNOx lean pre-mix combustion technology during normal
operations. SoLoNOx lean pre-mix combustion technology is not feasible and does not operate during
startup.
Marathon reviewed the CTGs to identify any additional control technologies.s EPA includes an evaluation
of the following technologies for NOx emissions from turbines:
o Steam/waterinjection
. Dry Low-Nox combustion (e.9., SoLoNOx technology)
. SCR
o SNCR
EPA does not make any conclusions regarding the minimum level of MCT in its CTG, citing site-specific
factors driving the overall cost-effectiveness of these technologies. Marathon has completed a site-
specific evaluation of RACT as detailed below.
6.1 Cogenerotion Uniis NOx Emissions
There are three mechanisms by which NOx production occurs during combustion including thermal, fuel,
and prompt NOx formation. ln the case of gaseous fuel combustion, the primary mechanism of NOx
formation is through thermal NOx formation. The Cogen turbines utilize SoLoNOxrM controls to reduce
the NOx emissions by a lean-premix technology to optimize the air/fuel mixture. Additionally, Marathon is
required to install SCR under the moderate ozone SlP.
6.I.I Step I - ldenlity All Avoilqble Control Technologies
Potential control technologies for NOx emissions from a review of available information are listed in
Table 3-1.
t https://www3.epa.gov/airouality/ctg act/199301 nox epa453 r-93-007 gas turbines.pdf
25
6.1.2 Step 2 - Technicol Feosibility of Conlrol Technologies
The technical feasibility of potential control options for NOx emissions are summarized in Table 5-1. The
following sections provide additional detail.
Toble 6-l lechnlcol Feosibility of NOx Conkollechnologles for Cogenerolion Unils
SNCR is not technically feasible because the exhaust temperature of the turbines is less than the
temperature required for this control technology to operate. ln addition, Marathon is not aware of any
turbines of this size that used this as a control technology, which indicates that SNCR has not been
demonstrated in practice and is inferior to the proposed RACT controls. Further, SNCR controls are not
effective when NOx levels are less than 200 ppm10. NOx levels exiting the combustion turbines are
significantly lower.
Marathon contacted the manufacturer of the Cogens to determine if steam/water lnjection may be
feasible. This control system is not available for Marathon's Solar Cogens and is therefore considered
technically infeasible.
6.I.3 Step 3 - Etfecliveness of Feosible Control Technologies
Marathon is selecting the top control option of SCR and SoLoNOx technology.
6.1.4 Step 4 - Evoluolion of Feosible Conlrol Technologies
Marathon is selecting the top control option of SCR and SoLoNOx technology.
6.1.5 Step 5 - RACT Seleclion
Marathon is selecting the top control option of SCR and SoLoNOx technology.
10 U.S. Environmental Protection Agency. Air Pollution ControlTechnology Fact Sheet Selective Non-
Catalytic Reduction (SNCR). 2003.
26
6.2 Cogenerolion Units VOC Emissions
VOC emissions from the Cogens are a result of incomplete combustion of the natural gas and fuel gas.
Marathon reviewed the CTGs to identify any additional control technologies.ll EPA states that "emissions
from gas turbines are considerably lower than from reciprocating engines" and that "control of large-bore
engines is only necessary when volatile organic compounds are increased as a result of control
technologies for other emissions..." Therefore, there are no CTGs for VOC emissions.
6.2.1 Step I - ldentify All Avoiloble ConlrolTechnologies
Potential control technologies for VOC emissions from a review of available information are listed in
Table 3-1.
6.2.2 Step 2 - Technicol Feosibility of Control Technologies
The technical feasibility of potential control options for VOC emissions are summarized in Table 6-2. The
following sections provide additional detail.
Ioble 6-2 Technicol Feoslbllity of VOC Conhol lechnologies for Cogenerolion Unlls
All VOC control techniques seek to oxidize products of incomplete combustion, with excess oxygen
typically present.
The application of thermal oxidation following the Cogens is not technically feasible. Thermal oxidation
has been shown to be ineffective below VOC concentrations of 100 ppm. The concentration in the Cogen
exhaust streams are estimated to be below 13 ppm, making thermal oxidation technically infeasible.
The use of a clean fuel, natural gas, instead of refinery fuel gas is not feasible for Marathon. lmporting
natural gas for exclusive combustion in the turbines and HRSGs would result in diversion of the excess
fuel gas to the flare, which may result in flow rates to the flares in excess of the permitted refinery flare
cap and no facility-wide net reduction in emissions. Also, the operation of the Cogen units to burn fuel
gas is listed as a flaring minimization measure in the refinery's Flare Management Plans.
11 httos://www3.epa.gov/airouality/ctg actl197805 voc epa450 2-78-022 stationary sources.pdf. See Section 4.13.2. Turbines were
not included in a more recent CTG at https://www3.epa.govlairquality/ctg_actl199504_voc_epa453_r-95-
0 1 0_beyond_voc_ract_ctg.pdf .
27
6.2.3 Step 3 - Etfecliveness of Feosible ConlrolTechnologies
The technically feasible control options are ranked in Table 6-3, according to their control effectiveness.
Ioble 6-3 Conhol Effecllveness Ronking of VOC Conlrollechnologles for Cogenerotlon Unlls
6.2.4 Step 4 - Evqluqtion of Feqsible Conlrol Technologies
The economic feasibility of the control options are summarized in Table 5-4.
Ioble 6-4 Cosi Evoluollon of VOC Conhol technologles for Cogenerolion Unlls
Based on the above data, the installation of Catalytic Oxidation at the Cogens is not considered an
economically feasible control option for control of VOC emissions.
6.2.5 Step 5 - RACT Selection
RACT for VOC from the Cogens is using good design methods and operating procedures.
28
7 RACT for Sulfur Recovery Unit (SRU)
The Sulfur Recovery Unit (SRU) complex reduces sulfur emissions from refinery processes by removing H2S
from the refinery sour water and sour fuel gas systems and converting it into elemental sulfur. ln the SRU
process, the sour water stripper acid gas and amine acid gas are sent to a burner to convert some of the
HzS to SOz and all of the ammonia to nitrogen. The heated gas mixture is fed to the first of three reactor
stages, where the SOz/HzS mixture is converted to sulfur vapor over a catalyst bed, generating heat in the
process. The elemental sulfur vapor is condensed via cooling and separated, while the remaining mixture
is reheated through a heat exchanger. The cycle of gas reheated, passing the mixture over a catalyst
reactor stage, and condensing the sulfur is repeated a total of three times; the remaining gas vapor,
known as tail gas, is directed to the Tail Gas Treating Unit (|-GTU). The liquid sulfur that is isolated from
the acid gas is drained through sealed legs to a sulfur pit, where it is stored and sold as elemental sulfur
product. ln the TGTU, the tail gas is reduced to HzS for additional capture by an amine absorber and
recycling to the front of the SRU. The outlet stream from the TGTU is routed to a thermal oxidizer to
control reduced sulfur emissions. The oxidizer uses refinery fuel gas as a fuel source.
7.1 SRU NOx Emissions
There are three mechanisms by which NOx production occurs during combustion including thermal, fuel,
and prompt NOx formation. ln the case of Claus sulfur recovery, the SRU reaction furnace is operated in a
reducing environment, where ammonia in the acid gas feed is reduced to Nz. A negligible amount of NOx
is formed from thermal or fuel formation mechanisms.
7.1.1 Step I - ldentity All Avoiloble Conlrol Technologies
Potential control technologies for NOx emissions from a review of available information are listed in
Table 3-1.
7.1.2 Slep 2 - Technicol Feosibility of Conlrol Technologies
The technical feasibility of potential control options for NOx emissions are summarized in Table 7-1. The
following sections provide additional detail.
Ioble 7-l lechnlcol Feoslbility of NOx ConholTechnologles lor SRU
The HF-Sinclair refinery in Salt Lake City utilizes LoTOx and a Wet Gas Scrubber to control NOx emissions
from their FCCU and SRU combined. However, this is not technically feasible at Marathon's refinery. The
Wet Gas Scrubber was not designed with sufficient capacity to handle the exhaust stream from the SRU.
Good Design Methods and Operating Procedures
LoTOx and Wet Gas Scrubber
29
NOx is assumed to be present in low concentrations within the outlet stream of the SRU unit, lower than
add-on control technology is able to achieve. Therefore, add-on NOx control technology is infeasible and
is not considered further.
7.1.3 Step 3 - Effecliveness of Feoslble Control Technologies
The technically feasible control options are ranked in Table 7-2, according to their control effectiveness.
Ioble 7-2 Conhol Effecliveness Ronking ol NOx Conkol Technologies for SRU
7.1.4 Step 4 - Evoluolion of Feosible Conlrol Technologies
The economic, environmental, and energy impacts of technically feasible control options are not required,
because Marathon selects the top control option.
7.1.5 Step 5 - RACT Seleclion
RACT for NOx from the SRU is using good design methods and operating procedures. During unit startup
or shutdown, good operating practices will be followed in order to minimize NOx emissions.
7.2 SRU VOC Emissions
VOCs are introduced into the SRU from the in the acid gas feed streams. VOC emissions from the SRU are
a result of incomplete combustion of the fuel in the incinerator.
7.2.1 Step 1 - ldenlify AllAvoilqble ConlrolTechnologies
Potential control technologies for VOC emissions from a review of available information are listed in
Table 3-1.
7.2.2 Step 2 - Technicol Feosibility of Conlrol Technologies
The technical feasibility of potential control options for VOC emissions are summarized in Table 7-3. The
following sections provide additional detail.
EEP,Section5-Process
Vents, Table 5-7
30
Ioble 7-3 Technlco! Feoslbllliy of VOC Conlrol Technologles for SRU
All VOC control techniques seek to oxidize products of incomplete combustion, with excess oxygen
typically present.
The application of catalytic oxidation technology is not feasible, as sulfur levels in the TGTU exhaust can
poison oxidation catalysts.
The use of a clean fuel, natural gas, instead of refinery fuel gas is not feasible for Marathon. lmporting
natural gas for combustion in the incinerator would result in diversion of the excess fuel gas to the flare,
which may result in flow rates to the flares in excess of the permitted refinery flare cap and no facility-
wide net reduction in emissions.
7.2.3 Step 3 - Etfecliveness of Feosible ControlTechnologies
The technically feasible control options are ranked in Table 7-4, according to their control effectiveness.
Ioble 7-4 Conkol Effecliveness Ronking of VOC Conlro! Technologies for SRU
7.2.4 Step 4 - Evoluolion of Feosible Conlrol Technologies
The economic, environmental, and energy impacts of technically feasible control options are not required,
as the top feasible control option is selected.
7.2.5 Step 5 - RACT Seleclion
RACT for VOC from the SRU is using the tail gas incinerator with good design methods and operating
procedures. During unit startup or shutdown, good operating practices will be followed in order to
minimize VOC emissions.
Thermal Oxidation (Iail Gas lncinerator)
Good Design Methods and Operating Procedures
EEP,Section5-Process
Vents, Table 5-7
3l
8 RACT for Fugitive Equipmenl
8.1 Fugilive Equipment VOC Emissions
Control strategies for volatile organic compound emissions from fugitive components are based on LDAR
program work practice requirements, which identify and then reduce emissions from process equipment
components. Marathon's LDAR program consists of requirements from 40 CFR 50 Subpart GGGa,
40 CFR 63 Subpart CC, Utah R307-326, and a consent decree. The consent decree requires an enhanced
LDAR program, which requires Marathon to:
o Maintain a written facility-wide LDAR program with annual updates
o Provide LDAR training to new and existing employees with LDAR related responsibilities and/or
maintain copies of contractor training records.
o Conduct LDAR audits every other year and alternate between internal and third party, and
implement corrective action plans.
o Calibrate LDAR monitoring equipment prior to each monitoring day, and a drift assessment is
required at the end of each monitoring day.
. Sign off on delays of repair must by the plant manager or responsible official. Drill and tap repairs
must also be attempted where feasible.
. Purchase certified low-leak technology (CLLT) valves for new and replacement equipment.
o Use a tracking program or MOC when equipment is placed in LDAR service or removed from
LDAR service.
. lmplement a QA/QC program.
As part of the Refinery Sector Rule (RSR) finalized on December 1, 2015, a new type of regulated process
vent referred to as "maintenance vent" was added within 40 CFR 63 Subpart CC at 40 CFR 63.6a3(c). A
maintenance vent is a process vent that is only used as a result of startup, shutdown, maintenance, or
inspection of equipment where equipment is emptied, depressurized, degassed, or placed into service.
Marathon complies with the maintenance vent requirements under Subpart CC.
8.1.1 Step I - ldenlify AII Avqiloble Conirol Technologies
Potential control technologies for VOC emissions from a review of available information are listed in
Table 3-1.
8.1.2 Step 2 - Technicol Feosibility of Control Technologies
The technical feasibility of potential control options for VOC emissions are summarized in Table 8-1. The
following sections provide additional detail.
32
Toble 8-l Technicol Feoslblllty of VOC Conhol lechnologles for Fugliive Equlpmenl
8.1.3 Step 3 - Effecliveness of Feosible Conirol Technologies
The technically feasible control options are ranked in Table 8-2, according to their control effectiveness.
Ioble 8-2 Control Effecliveness Ronking of VOC Conlrollechnologies for Fugitive Equipment
8.1.4 Step 4 - Evoluotion of Feosible Conlrol Technologies
The economic, environmental, and energy impacts of technically feasible control options are not required,
as the top feasible control option is selected.
8.1.5 Step 5 -RACT Seleclion
MCT for VOC emissions from fugitive equipment is an enhanced LDAR program, as required by 40 CFR
Part 60 Subpart GGGa and the facility's Consent Decree. Compliance with the maintenance vent
requirements of 40 CFR 63 Subpart CC also meets RACT.
33
I RACT for Refinery Woslewoler System
9.1 Refinery Woslewoter VOC Emissions
All wastewater and storm water streams within the refinery is treated in the Wastewater Treatment Plant
(VVVfIP). Oil is recovered from the WWTP and is stored and/or reprocessed in the refinery. The API
separator is fitted with a dual-seal floating roof cover.
9.1.1 Slep I - ldentify AllAvoiloble ControlTechnologies
Potential control technologies for VOC emissions from a review of available information are listed in
Table 3-1.
9.1.2 Step 2 - Technicol Feosibility of Conlrol Technologies
The technical feasibility of potential control options for VOC emissions are summarized in Table 9-1. The
following sections provide additional detail.
Ioble 9-l lechnlcol Feoslblllty of VOC Conlrol Technologles for Reflnery Wostewoler Syslem
The API separator was upgraded from a single-seal to dual-seal cover as part of the PMz.s Serious SlP.
Marathon is installing a new API separator with a closed vent system to carbon adsorption in 2025 and
will comply with NSPS Subpart QQQ. Due to the pending replacement of the API separator, other controls
(vapor combustion unit or carbon adsorption) are not technically feasible on the existing API separator.
9.1.3 Step 3 - Etfeciiveness of Feosible Control Technologies
The technically feasible control options are ranked in Table 9-2, according to their control effectiveness.
Ioble 9-2 Conhol Effecliveness Ronklng ol VOC Conirollechnologies for Refinery
Woslewoler Syslem
API Floating Separator Dual-seal cover,
Good design methods and operating practices
34
9.1.4 Step 4 - Evoluotion of Feosible ConlrolTechnologies
The economic, environmental, and energy impacts of technically feasible control options are not required,
as the top feasible control option is selected.
9.1.5 Step 5 - RACT Selectlon
RACT for VOC from the wastewater treatment plant is API dual-seal floating separator covers with good
design methods and operating practices.
As noted above, Marathon is installing a closed vent system to carbon adsorption by December 31, 2025,
and will comply with NSPS Subpart QQQ.
35
10 RACT for Refinery Drqins
I0.l Refinery Droins VOC Emissions
All wastewater and storm water streams within the refinery are collected and drained to the plant sewer
system. The wastewater is then directed to the Wastewater Treatment Plant (VVVWP) for treatment. Drains
within the refinery are either controlled or uncontrolled. Controlled drains (water seal or closed system)
meeting NSPS QQQ standards were installed when the DDU, GHT, BSU, TGTU and FGR were constructed.
Other miscellaneous drains in the refinery are also controlled. Uncontrolled drains exist throughout the
refinery in process units built prior to the NSPS QQQ standards. Currently, emissions from all drains are
monitored on an annual basis per Utah Rule R307-326-9, with a leakthreshold of 10,000 ppm and a 15-
day repair timeframe.
l0.l .l Step I - ldentity All Avoilqble Control Technologies
Potential control technologies for VOC emissions from a review of available information are listed in
Table 3-1.
l0.l .2 Step 2 - Technicol Feosibility of Conlrol Technologies
The technical feasibility of potential control options for VOC emissions are summarized in Table 10-1.
following sections provide add itional detail.
Toble t0-l lechnlcol Feoslblllty of VOC Controllechnologles for Reflnery Drolns
Marathon employs several good operating practices to minimize emissions from process drains. For
example, during maintenance activities, there are procedures which prohibit sending oils to the sewer.
Benzene waste is minimized and tracked as required under 40 CFR 61 Subpart FF.
The replacement of individual drains is technically infeasible. The refinery sewer system located in process
areas which existed prior to NSPS QQQ standards are not able to be upgraded due to the age and
location around process equipment.
lnstalling retrofit controls (i.e. p-trap inserts) limits the flow capacity of the drains. The effective open area
of a drainpipe would be cut in half to create the water seal inside the drain insert, which may backup and
cause standing water issues during firefighting conditions. The inserts may also cause drain cup overflows
36
when large amounts of fluids need to be removed quickly from process vessels during upsets or
preparations for turnarounds. A complete refinery hydraulic study would need to be completed prior to
installing the retrofit controls to ensure process safety issues were not created with the individual retrofit
installations. Upon completion of the study it may be determined that some drains can be retrofitted with
controls. lt is not feasible to complete a refinery wide hydraulic study, design, install, and operate these
retrofit controls prior to May 2026. However, for the purposes of this analysis, Marathon has considered
retrofits technically feasible.
10.1.3 Siep 3 - Etfecliveness of Feosible Control Technologies
The technically feasible control options are ranked in Table 10-2, according to their control effectiveness.
Ioble l0-2 Conhol Effecliveness Ronking of VOC Conlrollechnologies for Refinery Droins
10.1.4 Step 4 - Evoluolion of Feosible Conlro! Technologies
The economic feasibility of the control options are summarized in Table 10-3.
Ioble l0-3 Cosl Evoluolion of VOC Conlrollechnologles for Refinery Droins
Based on the above data, the drain retrofits are not an economically feasible control option for control of
VOC emissions. Emissions from uncontrolled refinery drains are significantly lower than default emission
factors in AP-42 because the facility uses actual monitoring data. Marathon is unaware of adverse
environmental or energy impacts without completing a hydraulic study.
10.1.5 Step 5 - RACT Seleciion
RACT for VOC emissions for all drains is LDAR monitoring per Utah R307-326-9. RACT for VOC emissions
from uncontrolled refinery drains is good operating practices. RACT for VOC emissions from refinery
drains at the DDU, GHT, BSU, TGTU, and FGR is compliance with NSPS Subpart QQQ.
37
l1 RACT for Norlh ond South Flqres
Process gases are routed to the North and South Flare Gas Recovery (FGR) Seal Drums. During normal
operations, gases are routed to the FGR compressors and directed to the amine absorber prior to being
routed to the refinery fuel gas system. The North and South Flare are subject to the following flare caps
for waste gas12 combustion:
o 181,003 SCFD (365-day rolling average)
o 271,505 SCFD (30-day rolling average)
Marathon implements Flare Minimization Practices to avoid flaring by preventing breaking the FGR water
seals or venting fuel gas and to minimize flaring when these events occur.
Marathon is required to ensure one FGR compressor is available for operation to recover flare gas 98o/o of
the time over a rolling 8,750 clock hour (1 year) period. ln addition, two compressors must be available
for operation (or in operation) to recover flare gas 95%o of the time over a rolling 8,760 clock hour (1 year)
period. Marathon maintains a spare flare gas compressor in addition to the two available for operation or
in operation.
Marathon implements the following Good Air Pollution Control Practices including during periods of
startup, shutdown, and/or malfunction to minimize flare emissions:
o A continuous flare pilot shall be maintained at all times.
o The presence of a flare pilot flame shall be continuously monitored. lf an alarm indicates that the
pilot flame is lost, operations personnel are to promptly attempt to reignite the pilot, document
any corrective actions taken.
o Flares are operated without visible emissions, while minimizing the flare Steam/y'ent Gas (S/VG)
ratio to 3 or less.
. Flare operating personnel monitor flare operation using the flare video monitoring system. lf
smoke is detected by the operators, or by other technical or operations personnel, adhere to the
practice outlined in Section 7 below.
Marathon is not permitted to allow the flares to smoke nor have visible emissions at any time. lf visible
emissions are observed either firsthand or through the video monitoring system:
. Operators increase steam flow to the flare until the visible emissions are eliminated while
minimizing the flare Steam/Vent Gas (S/VG) ratio to 3 or less.
12 Refer to the consent decree for the definition of waste gas and related exclusions.
38
r Operators address the cause of visible emissions
. Operators initiate Method 22 observations
Marathon is required to maintain destruction efficiency of at least 98% under 40 CFR 63 Subpart CC. This
is demonstrated by requirements to monitor flare tip velocity, net heating values, and dilution parameters,
as well as maintaining a Flare Management Plan and a Continuous Parameter Monitoring System Plan.
Subpart CC mandates a Net Heating Value of the Combustion Zone (NHVCZ) > 270 Blu/scfl based on a
1S-minute block average, when regulated material is sent to the flare for at least 15 minutes. To meet this
requirement, continuous direct measurements of refinery vent gas are made.
During non-routine operations, the process gases from the process vessels are discharged to the North
and South flare systems. When the flow of gas exceeds the capacity of the FGR compressors, gas breaks
through the water seal and is routed to the flare stack for combustion. Waste gas flared during these
periods is included in the flare cap limitations.
The flares are operated in compliance with the applicable standards at 40 CFR 60.18, 40 CFR 63.11, 40 CFR
60.100a-109a, and the facility's Consent Decree.
t 1.1 Norlh ond Soulh Flores NOx Emissions
There are three mechanisms by which NOx production occurs during combustion including thermal, fuel,
and prompt NOx formation. ln the case of gaseous fuel combustion, the primary mechanism of NOx
formation is through thermal NOx formation.
I l.l.l Step I - ldenlity All Avoiloble Conlrol Technologies
Potential control technologies for NOx emissions from a review of available information are listed in
Table 3-1.
11.1.2 Step 2 - Technicol Feosibility of Conlro! Technologies
The technical feasibility of potential control options for NOx emissions are summarized in Table 11-1. The
following sections provide additional detail.
Toble I l -l lechnicol Feosibility of NOx Conhol lechnologies for Norlh ond Soulh FIores
Add on NOx control is not technically feasible as it is not possible to enclose a safety flare tip.
Flare Gas Recovery operation consistent with compressor availability requirements
Flare Cap
Flare Management Plan
Add-on NOx control
39
I1.1.3 Step 3 - Effecliveness of Feosible Conlrol Technologies
The technically feasible control options are ranked in Table 11-2, according to their control effectiveness.
Ioble I l -2 Conhol Effectlveness Ronklng of NOx Conlrol Technologles for Norlh ond Soulh
Flores
I1.1.4 Slep 4 - Evoluolion of Feosible Conlrol Technologies
The economic, environmental, and energy impacts of the technically feasible control options is not
required, as the top feasible control option is selected.
I1.1.5 Step 5 - RACT Seleclion
RACT for NOx from the North and South flares is a flare gas recovery system with operation consistent
with compressor availability requirements, flare cap, and flare management plan. During periods of
startup and shutdown, the flare management plan will be used in conjunction with good operating
procedures to minimize flaring.
11.2 North ond South Flores VOC Emissions
VOCs from the North and South flares are a result of incomplete combustion of the vent gas.
11.2.1 Step I - ldeniity All Avqiloble Conlrol Technologies
Potential control technologies for VOC emissions from a review of available information are listed in
Table 3-1.
11.2.2 Step 2 - Technicol Feosibility of Control Technologies
The technical feasibility of potential control options for VOC emissions are summarized in Table 11-3.
following sections provide additional detail.
Flare Gas Recovery operation consistent with
compressor availability requirements
Flare Cap
Flare Management Plan
Consent decree
NSPS Subpart Ja
MACT Subpart CC
AP-42 Section 13.5
40
Ioble I l -3 Technlco! Feoslblllty of VOC Conhol lechnologles for Norlh ond Soulh Flores
Add on VOC control is not technically feasible as it is not possible to enclose a safety flare.
I 1.2.3 Step 3 - Etfectiveness of Feosible Contro! Technologies
The technically feasible control options are ranked in Table 1 1-4, according to their control effectiveness.
Ioble I l -4 Conkol Effecllveness Ronklng of VOC Control Technologles for Norlh ond Soulh
Flores
11.2.4 Step 4 - Evoluotion of Feosible Conlrol Technologies
The economic, environmental, and energy impacts of the technically feasible control options is not
required, as the top feasible control option is selected.
I 1.2.5 Step 5 - RACT Seleclion
RACT for VOC from the North and South flares is a flare gas recovery system, flare caps, flare
management plan, use of natural gas for pilot, compressor availability limits and flare combustion
efficienry requirements. During periods of startup and shutdown, the flare management plan will be used
in conjunction with good operating procedures to minimize flaring.
Flare Gas Recovery operation consistent with
compressor availability requirements
Flare Cap
Flare Management Plan
Flare Combustion Efficiency Requirements
Consent decree
NSPS Subpart Ja
MACT Subpart CC
AP-42 Section 13.5
41
12 RACT for SRU Flore
During startup, shutdown, and malfunction events, process gases from the sour water stripper and amine
treatment units may be sent directly to a flare knockout drum and routed to the SRU flare stack for
combustion. Natural gas is burned at the flare tip as pilot and purge gases, however there is no routine
waste gas venting to the SRU flare.
The SRU Flare is not subject to 40 CFR 60.18 or 40 CFR 63.1 1, and cannot feasibly comply with those
standards due to the nature of acid gas combustion. Marathon implements a Flare Management Plan
which include flare minimization per the standards of NSPS Subpart Ja for the SRU Flare. Sulfur shedding
is also implemented throughout the refinery in the event of an acid gas flaring event.
12.1 SRU Flore NOx Emissions
NOx emissions from the SRU flare are due to the combustion of the vent gas.
12.1.1 Step I - ldentity All Avqilqble Conlrol Technologies
Potential control technologies for NOx emissions from a review of available information are listed in
Table 3-1.
12.1.2 Step 2 - Technicol Feosibility of Conlrol Technologies
The technical feasibility of potential control options for NOx emissions are summarized in Table 12-1. The
following sections provide additional detail.
Ioble l2-l lechnlcol Feoslblllty of NOx ConlrolTechnologles for SRU Flore
Add-on NOx controls are not feasible, as it is not feasible to enclose a flare tip to capture the NOx
generated. A flare gas recovery compressor is not feasible because the SRU flare is used only during
startup and shutdown of the SRU which normally received all of the acid gases, and there are no alternate
processing methods. The flare management plan includes provisions for shutting down the sour water
stripper and storing of the sour water when feasible until the SRU is back online.
12.1.3 Step 3 -Effectiveness of Feosible Conlrol Technologies
The technically feasible control options are ranked in Table 12-2, according to their control effectiveness.
42
Toble l2-2 Conlrol Eflecllveness Ronking of NOx Conhollechnologles lor SRU Flore
12.1.4 Step 4 - Evqluolion of Feosible Conlrol Technologies
The economic, environmental, and energy impacts of technically feasible control options are not required,
as the top feasible control option is selected.
12.1.5 Step 5 - RACT Seleclion
RACT for NOx from the SRU flare is the implementation of a flare management plan for normal, startup,
and shutdown operation.
12.2 SRU Flore VOC Emissions
VOCs from the SRU flare are a result of incomplete combustion of the vent gas.
12.2.1 Step I - ldentity All Avoiloble ControlTechnologies
Potential control technologies for VOC emissions from a review of available information are listed in
Table 3-1.
12.2.2 Step 2 - Technicol Feosibility of Conlrol Technologies
The technical feasibility of potential control options for VOC emissions are summarized in Table 12-3. The
following sections provide additional detail.
Toble l2-3 Technico! Feosibility of VOC Conho! Technologles for SRU Flore
Add-on VOC controls are not feasible, as it is not feasible to enclose a flare tip to capture the VOCs
generated. A flare gas recovery compressor is not feasible because the SRU flare is used only during
startup and shutdown or malfunction of the SRU which normally received all of the acid gases, and there
are no alternate processing methods. The flare management plan includes provisions for shutting down
the sour water stripper and storing of the sour water when feasible until the SRU is back online.
43
12.2.3 Step 3 - Effectiveness of Feosible Conlrol Technologies
The technically feasible control options are ranked in Table 12-4, according to their control effectiveness.
Toble l2-4 Conhol Eftecllveness Ronklng of VOC Conlrol Technologles for SRU Flore
12.2.4 Step 4 - Evoluotion of Feqsible Control Technologies
The economic, environmental, and energy impacts of technically feasible control options are not required,
as the top feasible control option is selected.
12.2.5 Step 5 - RACT Seleclion
RACT for VOC from the SRU flare is the implementation of a flare management plan for normal, startup,
and shutdown operation, and use of exclusively natural gas for pilot and purge gases.
44
l3 RACT for Cooling Towers
Utilities Unit #2 (UU2) and Utilities Unit #3 (UU3) are cooling towers which reduce the temperature of
cooling water that serve heat exchangers throughout the refinery process units. Water is cooled in the
cooling tower when it is trickled past flowing air; cooling occurs as a portion of the water is evaporated to
the atmosphere. Potential emissions include particulate matter, due to minerals in the water, and VOCs
during unplanned heat exchanger leaks into the cooling water.
Marathon complies with the 40 CFR 63 Subpart CC requirements applicable to all cooling towers servicing
heat exchangers in VOC service. These requirements are basically leak detection and repair programs that
apply specifically to cooling towers by checking for the presence of VOCs in the cooling water on a
periodic basis. lf detected, then service or repair of the relevant heat exchanger is required to repair the
leak
13.1 Cooling Tower VOC Emissions
VOC emissions from cooling towers result from leaks of process fluid into the cooling water stream.
13.1.1 Step I - ldentify All Avoiloble ConlrolTechnologies
Potential control technologies for VOC emissions from a review of available information are listed in
Table 3-1.
13.1.2 Slep 2 - Technicol Feosibility of Conlrol Technologies
The technical feasibility of potential control options for VOC emissions are summarized in Table '13-1. The
following sections provide additional detail.
Toble l3-l Technlcol Feoslblllty of VOC Conhol Technologles for Coollng lowers
13.1.3 Step 3 - Etfecliveness of Feqsible Control Technologies
The technically feasible control options are ranked in Table 13-2, according to their control effectiveness.
Toble l3-2 Conhol Effecliveness Ronking of VOC Conhollechnologles for Coollng Towers
45
I3.1.4 Step 4 - Evoluotion of Feosible Control Technologies
The economic, environmental, and energy impacts of technically feasible control options are not required,
as the top feasible control option is selected.
13.1.5 Step 5 - RACT Seleclion
RACT for VOC emissions from cooling towers is complying with 40 CFR Part 53, Subpart CC, which
requires monitoring for hydrocarbons in the cooling water return and repair when leaks are detected.
16
14 RACT for Loqding Rocks
14.1 Tronsporloiion Rock VOC Emissions
Marathon operates a transportation loading rack the BCLR, for loading gasoline blending components
into railcars. VOC vapors are discharged from the tankers as they are filled. The loading rack is operated
with a vapor recovery unit with carbon adsorption as the control device.
l4.l.t Step I - ldentity AllAvoiloble ConholTechnologies
Potential control technologies for VOC emissions from a review of available information are listed in
Table 3-1.
14.1.2 Step 2 - Technicol Feosibility of Conhol Technologies
The technical feasibility of potential control options for VOC emissions are summarized in Table 14-1. The
following sections provide additional detail.
Ioble 14-l lechnlcol Feoslblllty of VOC ConholTechnologles for loodlng Rocks
All control options are technically feasible.
14.1.3 Step 3 - Etfectiveness of Feosible Conlrol Technologies
The technically feasible control options are ranked in Table 14-2, according to their control effectiveness.
Toble l4-2 Control Effecllveness Ronklng of VOC Conirollechnologles for looding Rocks
14.1.4 Step 4 - Evoluqtion of Feosible Conlrol Technologies
The use of a flare/thermal oxidizer results in additional combustion related emissions from the controlled
VOC. ln comparison, a carbon adsorption unit recovers product which would otherwise be emitted and
results in no collateral emissions. Therefore, a carbon adsorption unit is considered the top feasible
control option in this case. The economic and energy impacts of technically feasible control options are
not required, as the top feasible control option is selected.
47
14.1.5 Step 5 - RACT Seleclion
RACT for VOC from the transport loading rack is a vapor recovery unit with carbon adsorption.
14.2 LPG Looding Rock VOC Emissions
The Salt Lake City Refinery operates two liquefied petroleum gases (LPG) racks: a 6-bay rail loading and
offloading rack and a single-bay truck loading and offloading rack The rack utilizes arms for liquid and
vapor loading and unloading. Following loading/unloading operations, LPG is recovered from the arms
using a compressor and then the remaining vapors in the arms are vented to the FGR system.
14.2.1 Step I - ldentity AllAvoiloble ConholTechnologies
Potential control technologies for VOC emissions from a review of available information are listed in
Table 3-1.
14.2.2 Step 2 - Technicol Feosibility of Conlrol Technologies
The technical feasibility of potential control options for VOC emissions are summarized in Table 14-3. The
following sections provide additional detail.
Ioble l4-3 Technlcol Feoslblllty of VOC Conlrol Technologles for looding Rocks
Carbon adsorption is not technically feasible, as the LPG being loaded contains low molecular weight
compounds which are not effectively captured by activated carbon.
14.2.3 Step 3 - Etfectiveness of Feosible Control Technologies
The technically feasible control options are ranked in Table 14-4, according to their control effectiveness.
Toble l4-4 Conhol Effecilveness Ronklng of VOC Conlrol lechnologles for Loodlng Rocks
14.2.4 Step 4 - Evoluolion of Feosible Conlrol Technologies
The economic and energy impacts of technically feasible control options are not required, as the top
feasible control option is selected.
18
14.2.5 Step 5 - RACT Selection
RACT for VOC from the LPG loading rack is routing the recovered LPG to the North and South Flares with
a Flare Gas Recovery System. Refer to Section 11.2.5.
49
l5 RACT for KI Compressors
The K1 compressors are two compressors operated in parallel to rerycle hydrogen into the UFU
desulfurization reactor. They are each driven by a 4-stroke rich burn (4RSB) internal combustion engine
fired by natural gas. The exhaust goes through a catalytic converter that controls NOx emissions prior to
release to the atmosphere.
l5.l Kl Compressors NOx Emissions
There are three mechanisms by which NOx production occurs during combustion including thermal, fuel,
and prompt NOx formation. ln the case of gaseous fuel combustion, the primary mechanism of NOx
formation is through thermal NOx formation.
l5.l .l Step 1 - ldentify All Avoiloble Conlrol Technologies
Potential control technologies for NOx emissions from a review of available information are listed in
Table 3-1.
15.1.2 Step 2 - Technicol Feosibility of Conlrol Technologies
The technical feasibility of potential control options for NOx emissions are summarized in Table 15-1. The
following sections provide additional detail.
Toble l5-l lechnlcol Feoslblllty ol NOx Conlrollechnologles for Kl Compressors
Replacing both compressors with electric motors may not be technically feasible due to space constraints.
However, for purposes of this evaluation, Marathon has completed the remainder of the evaluation to
determine if the change is economically feasible.
SCR is not technically feasible for 4SRB engines. 4SRB engines are built to operate close to a stochiometric
air-fuel ratio which causes the exhaust oxygen levels for rich-burn engines to be relatively low. For this
reason, 4SRB engines are not typically controlled using an SCR. ln addition, AP-42 Section 3.2 does not list
an SCR as an available control technology.
15.1.3 Step 3 - Effecliveness of Feosible Control Technologies
The technically feasible control options are ranked in Table 15-2, according to their control effectiveness.
50
Ioble l5-2 Conlrol Effecllveness Ronklng of NOx ConholTechnologles for Kl Compressors
l5.l .4 Step 4 - Evoluolion of Feosible Conlrol Technologies
The economic feasibility of the control options are summarized in Table 15-3.
Toble t5-3 Cosl Evoluolion of NOx ConholTechnologies for Kl Compressors
Based on the above data, electric motors are not an economically feasible control option for control of
NOx emissions. Marathon is unaware of adverse environmental impacts of electric motors. Electric motors
will require increased electrical demand for the facility and infrastructure upgrades for the additional
power required to operate the electric compressors. These costs are currently estimated. Marathon
reserves the right to revisit this cost effectiveness evaluation if the threshold established by UDAQ results
in electrifying the K1 compressors determined to be cost effective.
15.1.5 Step 5 - RACT Selection
RACT for NOx from the K1 Compressors is the use of a catalytic converter, natural gas and good operating
practices. Additional controls are not technically or economically feasible as MCT.
15.2 Kl Compressors VOC Emissions
VOC emissions from the furnaces are a result of incomplete combustion of the refinery fuel gas. Marathon
utilizes a catalytic converter for VOC control on the compressors.
15.2.1 Step I - ldentity AllAvoiloble ConlrolTechnologies
Potential control technologies for VOC emissions from a review of available information are listed in
Table 3-1.
15.2.2 Step 2 - Technicol Feosibility of Conlrol Technologies
The technical feasibility of potential control options for VOC emissions are summarized in Table 15-4. The
following sections provide additional detail.
5l
Toble l5-4 lechnlcol Feoslblllty of VOC ConlrolTechnologles for Kl Compressors
Replacing both compressors with electric motors may not be technically feasible due to space constraints.
However, for purposes of this evaluation, Marathon has completed the remainder of the evaluation to
determine if the change is economically feasible.
15.2.3 Step 3 - Etfecliveness of Feosible ConlrolTechnologies
The technically feasible control options are ranked in Table 15-5, according to their control effectiveness.
Toble l5-5 Conlrol Effecllveness Ronklng of VOC Conhollechnologles for Kl Compressors
15.2.4 Step 4 - Evqluolion of Feosible Conlrol Technologies
The economic feasibility of the control options is summarized in Table 15-6.
Toble 15-6 Cost Evoluolion of VOC ConholTechnologies for Kl Compressors
52
Based on the above data, neither control technology is economically feasible for control of VOC
emissions. Marathon is unaware of adverse environmental impacts of electric motors. Electric motors will
require increased electrical demand for the facility as described in Section 1 5.1.4. 3-way catalysts increase
waste disposal.
15.2.5 Step 5 - RACT Seleclion
MCT for VOC from the K1 compressors is a catalytic converter, natural gas and good operating practices.
53
l6 RACT for Fixed Roof Tonks
I6.l Fixed Roof Tonks VOC Emissions
Fixed roof tanks are either vented with a gooseneck or have a pressure/vacuum vent. Emissions from fixed
roof tank are in the form of working losses and standing losses. Standing losses occur through tank
temperature fluctuations, while working losses occur primarily from liquid level changes. Fixed roof tanks
are only used to store liquids with low vapor pressures such as diesel, kerosene, and other heavy oils
given the low potential for emissions generation.
I6.l.l Step I - ldentify All Avoiloble Conhol Technologies
Potential control technologies for VOC emissions from a review of available information are listed in
Table 3-1.
16.1.2 Step 2 - Technicol Feosibility of Conlrol Technologies
The technical feasibility of potential control options for VOC emissions are summarized in Table 16-1. The
following sections provide add itional detail.
Ioble l6-l lechnlcol Feoslbllity of VOC ConholTechnologles for Flxed Roof Tonks
Although adding a vapor recovery system or venting to a control device may be feasible, it is not feasible
to design, install, and begin operating either of these control technologies prior to May 2026. However,
Marathon assumes for this analysis that a vapor recovery system and venting to a control device is
considered technically feasible.
As a part of the 2015 update to MACT Subpart CC, referred to as the Refinery Sector Rule (RSR), it was
required to determine whether any fixed roof tanks previously classified as Group 2 tanks must be
reclassified as Group 1 tanks due to the change in definition. Any fixed roof tanks reclassified as a Group 1
storage tank require that a closed vent system with a control device be installed or the tank be converted
to an IFR tank at the next opportunity where the tank is emptied and degassed, but no later than January
30,2026.
54
Fixed roof tanks may be retrofitted to include an IFR for emissions control purposes. This is limited to
vertical fixed roof tanks with a diameter greater than 15.5' to maintain buoyancy of the lFR. Horizontal
fixed roof tank cannot be retrofitted with an IFR due to their geometry. ln addition, installing an IFR will
decrease a fixed roof tank's capacity. This may not be technically feasible for any tanks at the facility due
to impacts on refinery operations. However, Marathon assumes for this analysis that this technology is
technically feasible.
16.1.3 Step 3 - Effecliveness of Feqsible Conlrol Technologies
The technically feasible control options are ranked in Table 16-2, according to their control effectiveness.
Ioble l6-2 Conhol Effecliveness Ronklng of VOC ConlrolTechnologles for Flxed Roof Tonks
16.1.4 Step 4 - Evoluotion of Feosible Conlrol Technologies
Additional details regarding the scope of the upgrades is included below.
Retrofit to IFR
The primary technical drawback with retrofitting a fixed roof tank with an IFR is that storage tanks lose
approximately 5-8 ft of working capacity, including 3-5 feet at the top of the tank to support the
installation and operations of the lFR, and approximately 3 feet at the bottom of the tank to ensure that
landing of the IFR does not occur (resulting in excess emissions). The loss of capacity is significant at 19-
43% considering the dimensions of the storage tanks at the refinery and RTF. This loss of tank capacity
could potentially require installation of additional storage tank to support operational requirements.
Further engineering review would be required to confirm.
lnstallation includes the following:
Outer pontoon style roof, single deck with primary & secondary seal
Ladder, roof negotiator, and fixed roof hatch
Verticality survey,
Door sheet,
55
. Gauge pole and gauge pole cover,
o Floating roof leg covers and
o Hydrotesting.
Marathon considered controls for each fixed roof tank. The cost-effectiveness ranged from $92,300 -
$3,100,000 per ton of VOC controlled, which is not economically feasible. Details of the cost evaluation are
included in Appendix B.
Closed Vent System
To add a closed vent system to an existing fixed roof tank the tank shell must be rated for the increased
pressures associated with the vapor recovery system. lf the tank pressure ratings are insufficient, then
significant modifications to the tank structure, tank shell courses, and foundation would likely be required,
which would also require cleaning and degassing the tank.
Tanks at each of the locations considered (refinery and RTF) are spread out over multiple diked-in areas
and have a multitude of underground conduits and pipes that would need to be identified and avoided
during any construction activities in these areas. There is no infrastructure in place today at the tanks to
handle the vapors and air that will need to be collected from the tanks, nor is there sufficient electrical or
natural gas service available in the area where a vapor control device would have to be installed at the
RTF.
lnstallation of a vapor recovery system would require installation at a minimum of the following items
regardless of the control technology selected:
Vapor piping from each tank to a main header that would direct vapors to a common point. A
vapor blower to pull and direct vapors to the control devices.
Detonation Arrestors at specific designed locations to ensure any significant detonation event
could not transverse back to a product tank.
Pressure sensing and control equipment at each tank to ensure pressure in the atmospheric tanks
is maintained within design parameters.
Proper supports and foundations to hold the vapor piping, blower(s), and electrical conduit and
equipment across the tank farm areas.
Electrical supply infrastructure including new utility feeds and distribution equipment.
A bladder tank to handle the surges of air flow and to condition that air flow into the Vapor
Control device.
There is a significant potential for cost and project delays associated with the air and construction
permits that will likely be required for this type of project. Permit issuance on average is
approximately one year.
56
A vapor recovery system is not a stand-alone control option, but is a necessary component for both the
thermal oxidizer and carbon adsorbers. Additional detail is included below.
Thermol Oxidizer
The air displaced from the tank head space will be very lean with little to no VOC content for the vast
majority of the time due to consideration of controls on tanks with materials with low volatility (i.e., those
below the MACT Subpart CC thresholds). This, coupled with the large volume of air being displaced
during tank filling and transfer operations means that a Thermal Oxidizer OO) is likely not a viable option
since large amounts of natural gas would be consumed to generate the heat required to meet minimum
temperature requirements. The natural gas adds significant costs to operations while at the same time
increasing greenhouse gas emissions for minimal reductions in potential VOC emissions.
ln addition to the equipment noted for the vapor recovery system, a TO would require the following items
to be procured and installed:
o Natural gas supply added to the RTF.
. Work with the local utility provider to ensure there is sufficient fuel supply to the RTF or if service
modifications are required.
o Piping from the natural gas supply point to the site of the TO skid.
o An electricalfeed.
r Extra power distribution and significant runs of conduit and wire.
o lnstallation of a smaller concrete pad and footer to place the TO skid on.
. The TO would be purchased from a 3rd party vendor.
Marathon considered controls for each tank individually, and a combined control system for the collection
of tanks at the refinery and the collection of tanks at the RTF. Overall, costs are based upon the following:
. Vapor recovery system installation for a combined control system based upon engineering
estimates developed from similar installations within Marathon.
. Piping costs to and from each tank are based upon estimated distances using aerial imagery and
RSMeans cost estimation tools for steel piping (10" for vapor recovery, 2" for natural gas feed).
. Thermal oxidizer capital and operating costs are estimated using EPA's control cost manual for
individual tanks. The combined tanks thermal oxidizer is based on engineering estimates from
similar installations within Marathon.
o Electrical and natural gas infrastructure upgrades at the RTF are based upon engineering
estimates developed from similar installations within Marathon.
57
The cost-effectiveness ranged from $140,000 - $5,500,000,000 per ton of VOC controlled, which is not
economically feasible. Details of the cost evaluation are included in Appendix B. ln addition to the high
costs, the use of thermal oxidation inherently results in NOx emissions to the atmosphere.
Corbon Adsorber
Due to the large air volumes, the existing vapor recovery unit (VRU) will not be able to handle the tank
vapors and air movements. A new adsorber system would consequently need to be installed at the
refinery and at the RTF.
ln addition to the equipment noted for the vapor recovery system, carbon adsorbers would require the
following items to be procured and installed:
r lnert gas supply added to the RTF.
o Piping from the inert gas supply point to the site of the VRU skid.
o An electricalfeed.
o Extra power distribution and significant runs of conduit and wire.
o lnstallation of a smaller concrete pad and footer to place the adsorber skid on.
o The adsorber would be purchased from a 3rd party vendor.
Overall, costs are based upon the following:
. Vapor recovery system installation for a combined control system based upon engineering
estimates developed from similar installations within Marathon.
o Piping costs to and from each tank are based upon estimated distances using aerial imagery and
RSMeans cost estimation tools for steel piping (10" for vapor recovery,2" lor natural gas feed).
. Carbon adsorber capital and operating costs are estimated using EPA's control cost manual for
individual tanks. The combined tanks carbon adsorber is based on engineering estimates from
similar installations within Marathon.
. Electrical and inert gas infrastructure upgrades at the RTF are based upon engineering estimates
developed from similar installations within Marathon.
Marathon considered controls for each tank individually, and a combined control system for the collection
of tanks at the refinery and the collection of tanks at the RTF. The cost-effectiveness ranged from $95,000
- $17,000,000 per ton of VOC controlled, which is not economically feasible. Details of the cost evaluation
are included in Appendix B.
58
16.1.5 Step 5 - RACT Seleclion
RACT for VOC emissions from fixed roof tanks is good design methods and operating procedures, as
additional control technology is not feasible.
59
17 RACT for IFR Tqnks
17.1 IFR Tonks VOC Emissions
An IFR tank has a permanent roof with a floating roof on the inside floating on the surface of the liquid.
Emissions from a floating roof tank come from both withdrawal losses and standing losses. Withdrawal
losses are generally due to liquid level fluctuations, and standing storage losses originate from the rim
seal, deck fittings, and the deck seam. All IFR tanks are subject to 40 CFR Part 50 Subpart Kb and 40 CFR
Part 63 Subpart CC (Existing MACT CC).
Some of the IFR tank have been upgraded to meet controls required by recent revisions to Subpart CC
under RSR. Under RSR, 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 additional requirements for floating roof seals, deck fitting
controls, inspections, recordkeeping, and reporting.
RSR requires that the next time the vessel is emptied and degassed or by February 1 , 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 53.650. The deck fitting control upgrades (or commonly referred to
below as Upgrades to RSR Controls) for IFR tanks from 40 CFR 63.646 to 40 CFR 53.660 compliance
include:
IFR well covers must be gasketed (i.e., deck openings other than for vents, drains, or legs) 1/8"
max gap criteria.
lFRvents to be gasketed (vacuum breakers, rim vents) 1/8" max gap criteria.
Deck openings other than for vents must project into liquid.
Access hatches and gauge float well covers are required to be bolted and gasketed.
Emergenry roof drains must have seals covering at least 90o/o of the floating roof deck opening.
IFR column wells must have gasketed cover or flexible fabric sleeve.
Unslotted guidepoles required to have a pole wiper at the deck fitting and a gasketed cap at the
top of the pole.
Slotted guidepoles must have an external pole wiper and an internal pole float or equivalent.
Each opening through a floating roof for a ladder having at least one slotted leg shall be
equipped with one of the following configurations:
o 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.
o A ladder sleeve and pole wipers for both legs of the ladder.
60
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 lX.H Emission Limits and Operating Practices.
17.1.1 Step I - ldentity All Avoiloble Conlrol Technologies
Potential control technologies for VOC emissions from a review of available information are listed in
Table 3-1.
17.1.2 Step 2 - Technicol Feosibility of Conlrol Technologies
The technical feasibility of potential control options for VOC emissions are summarized in Table 17-1. The
following sections provide additional detail.
Ioble 17-l lechnicol Feosibility of VOC Conkollechnologies for IFR lonks
Marathon does not view closed vent systems as technically feasible, but will evaluate them further in this
report for completeness. Closed vent systems (vapor recovery) on IFR tanks has not been demonstrated in
practice. Because it has not been demonstrated in practice, there are unknown operational drawbacks to
using vapor recovery. Conventional vapor recovery systems require vapor collection from a closed system,
so IFR tanks would need to be closed/sealed. Adding a vapor recovery system to an existing floating roof
tank that is equipped with a geodesic dome roof would require the tank owner to degas and clean the
tank, remove the existing floating roof and geodesic dome rool then install a new fixed roof. The refinery
does operate some IFR tank with geodesic dome roofs.
lnstalling a secondary seal will decrease an IFR roof tank's ability to move up and down by approximately
2 feet. This may not be technically feasible for any tanks at the facility due to impacts on refinery
operations. However, Marathon assumes for this analysis that this technology is technically feasible.
6l
17.1.3 Step 3 - Effectiveness of Feosible Conlrol Technologies
The technically feasible control options are ranked in Table 17-2, according to their control effectiveness.
Toble l7-2 Conhol Effecliveness Ronking of VOC Conlrollechnologies for IFR Tonks
17.1.4 Step 4 - Evoluotion of Feosible Conlrol Technologies
Additional details regarding the scope of upgrades is included below.
Closed Venl System
The same requirements outlined in Section 16.1.4 to install a closed vent system to fixed roof tanks apply
to the lFRs. ln addition, IFR geodesic domes would need to be replaced or lFRs with fixed roofs may also
require replacement if not rated for appropriate pressure tolerances.
A vapor recovery system is not a stand-alone control option, but is a necessary component for both the
thermal oxidizer and carbon adsorbers. Additional detail is included below.
Thermol Oxidizer
The same requirements outlined in Section 16.1.4 to install a thermal oxidizer apply to the lFRs. Marathon
considered controls for each tank individually, and a combined control system for the collection of tanks
at the refinery and the collection of tanks at the RTF. The cost-effectiveness ranged from $97,000 -
$6,200,000 per ton of VOC controlled, which is not economically feasible. Details of the cost evaluation are
included in Appendix B. ln addition to the high costs, the use of thermal oxidation inherently results in
NOx emissions to the atmosphere.
Corbon Adsorber
The same requirements outlined in Section 16.1.4 to install a carbon adsorber applyto the lFRs. Marathon
considered controls for each tank individually, and a combined control system for the collection of tanks
at the refinery and the collection of tanks at the RTF. The cost-effectiveness ranged from $97,000 -
$1,900,000 per ton of VOC controlled, which is not economically feasible. Details of the cost evaluation are
included in Appendix B.
Closed Vent System to Thermal Oxidizer
Closed Vent System to Carbon Adsorber
Compliance with NSPS Kb (where applicable)
Compliance with 40 CFR 63 Subpart CC
Degassing controls when storage tank are taken out of service.
Good design methods and operating procedures
Varies by tank N/A - Base Case
62
Secondory Seols
Marathon evaluated the costs associated with the installation of secondary seals. The cost-effectiveness
ranged from $72,000 - $1,400,000 per ton of VOC controlled, which is not economically feasible. Details of
the cost evaluation are included in Appendix B.
17.I.5 Step 5 - RACT Seleclion
RACT for VOC emissions from IFR tanks is as follows:
. For Tank 321 installation of a secondary seal was considered RACT under the moderate SlP.
. For tanks currently meeting NSPS Kb, meeting NSPS Kb is RACT.
r For tanks currently meeting MACT CC requirements, meeting RSR is MCT.
r For tanks that don't meet either NSPS Kb or RSR requirements, the existing MACT CC controls
and good design methods and operating procedures are RACT.
During tank shutdowns and degassing, a portable combustion unit will continue to be used to control
emissions.
63
18 RACT for EFR Tonks
l8.l EFR Tonks VOC Emissions
An EFR tank is an open topped tank with a roof floating on the surface of the liquid. Emissions from a
floating roof tank come from both withdrawal losses and standing losses. Withdrawal losses are generally
due to liquid level fluctuations, and standing storage losses originate from the rim seal and deck fittings.
All EFRs currently meet the double seal standard from 40 CFR Part 60 Subpart Kb or 40 CFR Part 63
Subpart CC.
Some of the tanks have been upgraded to meet RSR controls. Refer to Section 17.1 for additional
background on compliance with RSR.
RSR requires that the next time the vessel is emptied and degassed or by February 1 , 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 Upgrades to RSR Controls) for EFR tanks from 40 CFR 63.U6 to 40 CFR 63.660 compliance
include:
. EFR well covers must be gasketed (i.e. deck openings other than for vents, drains, or legs) 1/8"
max gap criteria.
o EFR vents to be gasketed (vacuum breakers, rim vents) 1/8" max gap criteria.
. Deck openings other than for vents must project into liquid.
o Access hatches and gauge float well covers must be bolted and gasketed.
o Emergency roof drains must have seals covering at least 90o/o of the floating roof deck opening.
. Guidepole wells must have gasketed deck cover and a pole wiper.
o Unslotted guidepoles required to have a cap at the top of the pole.
. Slotted guidepoles must have an internal float or equivalent.
Additionally, tank degassing emissions are being now controlled by portable combustion units, as
required by the Utah SIP Section lX.H Emission Limits and Operating Practices.
l8.l.l Step I - Identify All Avoiloble ConlrolTechnologies
Potential control technologies for VOC emissions from a review of available information are listed in
Table 3-1.
64
l8.l .2 Step 2 - Technicol Feosibility of Conlrol Technologies
The technical feasibility of potential control options for VOC emissions are summarized in Table 18-1. The
following sections provide additional detail.
Ioble l8-l Technlcol Feosibility of VOC Conhol Technologles for EFR Ionks
18.1.3 Step 3 - Effectiveness of Feosible Conlrol Technologies
The technically feasible control options are ranked in Table 18-2, according to their control effectiveness.
Ioble l8-2 Conhol Effecllveness Ronking of VOC ConholTechnologles for EFR lonks
18.1.4 Step 4 - Evoluolion of Feosible Conlrol Technologies
Additional details regarding the scope of the upgrades is included below.
Closed Venl System
The same requirements outlined in Section 16.1.4 to install a closed vent system to fixed roof tanks apply
to the EFRs. ln addition, a fixed roof would need to be installed on the EFR. A vapor recovery system is not
a stand-alone control option, but is a necessary component for both the thermal oxidizer and carbon
adsorbers. Additional detail is included below.
Closed Vent System to Thermal Oxidizer
Closed Vent Sptem to Carbon Adsorber
Compliance with NSPS Kb (wh*e iipficaUiel . ,
Compliance with 40 CFR 53 Sibpart CC . ,. : ,
Degassing controls when storage tank are taken out of service.
Good design methods and operating procedures
N/A - Base Case
,,: l
65
Thermol Oxidizer
The same requirements outlined in Section 16.1.4 to install a thermal oxidizer apply to the EFRs. Marathon
considered controls for each tank individually, and a combined control system for the collection of tanks
at the refinery and the collection of tanks at the RTF. The cost-effectiveness ranged from $65,000 -
$36,000,000 per ton of VOC controlled, which is not economically feasible. Details of the cost evaluation
are included in Appendix B. ln addition to the high costs, the use of thermal oxidation inherently results in
NOx emissions to the atmosphere.
Corbon Adsorber
The same requirements outlined in Section 16.1.4 to install a carbon adsorber apply to the EFRs. Marathon
considered controls for each tank individually, and a combined control system for the collection of tanks
at the refinery and the collection of tanks at the RTF. The cost-effectiveness ranged from $93,000 -
$24,000,000 per ton of VOC controlled, which is not economically feasible. Details of the cost evaluation
are included in Appendix B.
Dome Retrofil
Marathon evaluated these known costs associated with the installation of geodesic domes on external
floating roof tanks:
. lnstallation Cost with Fire Suppression System, Cleaning and Degassing
. Additional retrofit costs include fitting/accessibility modifications, contractor coordination,
contract inspection, confined space emergency response, blinding, stripping, touch-up painting,
tank dike re-grading, project overhead, and fuel.
. Prope0 taxes, insurance, and administrative charges assumes 4% of the total capital investment
per EPA Control Cost Manual cost procedures.
Costs not included in the analysis relate to individual tank feasibility assessments. lnstalling a geodesic
dome to an existing floating roof tank will add weight to the shell of the tank. Older storage tanks can
settle over time which may result in the top of the tank to become out-of-round and out-of-
plane. Depending on the severity of these structural deformations, retrofitting of a new geodesic dome
can become significantly more costly or technically not feasible. Marathon was not able to perform this
level of individual tank detailed engineering analysis given the short amount of time to submit this
analysis. Marathon reserves the right to revisit this evaluation and subsequent resulting conclusions if
new information becomes available.
Additionally, costs were not included for storage tanks which do not have a scheduled outage before the
implementation date of May 1,2026. Significant additional costs would be incurred to complete the
installation of geodesic domes outside of a scheduled outage.
The cost-effectiveness (known costs) ranged from $380,000 - $19,000,000 per ton of VOC controlled,
which is not economically feasible. Details of the cost evaluation are included in Appendix B.
66
18.1.5 Step 5 - RACT Selection
RACT for VOC emissions from the EFR tank is as follows:
r For tanks currently meeting NSPS Kb, meeting NSPS Kb is MCT.
r For tank currently meeting MACT CC requirements, meeting RSR is MCT.
o For tank that don't meet either NSPS Kb or RSR requirements, the existing MACI CC controls
and good design methods and operating procedures are RACT.
During tank shutdowns and degassing, a portable combustion unit will continue to be used to control
emissions,
67
l9 RACT for Emergency Engines
Marathon operates four compression ignition emergency engines: one at the wastewater treatment plant,
two fire water pumps, and one at the firehouse. These engines are designated as emergency engines, with
usage limited to 500 hours per year. These emergency engines are used to provide power for critical
equipment in emergency situations, when electric power from the public utilities is interrupted.
Emergenry engines are also typically operated weekly or monthly at zero or low loads for regular
maintenance and testing to ensure proper engine operations. All engines are subject to the Part 53,
Subpart 7772 standards. The Firehouse Engine was installed in 2011, and is therefore subject to Part 60,
Subpart llll standards.
l9.I Emergency Engine NOx Emissions
NOx emissions from the emergency engines result from the combustion of the diesel fuel.
l9.l.l Step 1 - ldentity All Avoiloble Conlrol Technologies
Potential control technologies for NOx emissions from a review of available information are listed in Table
3-1.
19.1.2 Step 2 - Technicol Feosibility of Conlrol Technologies
The technicalfeasibility of potential control options for NOx emissions are summarized in Table 19-1. The
following sections provide additional detail.
Ioble l9-l lechnlcol Feoslblllty ol NOx Conlrol lechnologies for Emergency Englnes
Although it may be feasible to replace the emergenry engines with engines meeting EPA Tier 4
requirements, such a change would not be able to be engineered and implemented prior to May 2026.
Therefore, the replacements of the emergency engines are considered technically infeasible.
19.1.3 Step 3 - Etfectiveness of Feosible Conirol Technologies
The technically feasible control options are ranked in Table 19-2, according to their control effectiveness.
68
Ioble l9-2 Conlrol Eflecllveness Ronking of NOx ConholTechnologles for Emergency Englnes
19.1.4 Step 4 - Evoluolion of Feosible Conlrol Technologies
Emissions from emergency engines are minimal because normal operations include only weekly testing,
which results in annual operations of much less than 50 hours per year. Emissions are therefore less than
0.5 tpy per unit. The emissions reduction from replacement of an existing engine with a Tier 4 engine is
therefore minimal, and the control cost is not economically feasible.
19.1.5 Step 5 - RACT Seleclion
RACT for NOx emissions from the emergency engines is using good combustion practices, and
compliance with MACT ZZZZ. Replacement of the engine with a Tier 4 engine is not economically feasible.
19.2 Emergency Engine VOC Emissions
VOC emissions from the emergency engines are the result of diesel combustion.
19.2.1 Step I - ldentity AMvoiloble ConlrolTechnologies
Potential control technologies for VOC emissions from a review of available information are listed in Table
3-1.
19.2.2 Step 2 - Technicol Feosibility of Conlrol Technologies
The technical feasibility of potential control options for VOC emissions are summarized in Table 19-3. The
following sections provide additional detail.
Toble l9-3 Technicol Feosibility of VOC Conhol Technologies for Emergency Englnes
Although it may be feasible to replace the emergency engines with engines meeting EPA Tier 4
requirements, such a change would not be able to be engineered and implemented prior to May 2026.
Therefore, the replacements of the emergency engines are considered technically infeasible.
Comply with Emergency Engine requirements of MACI 1777
Replace engine with Tier 4 Engine
69
19.2.3 Step 3 - Etfecliveness of Feosible Control Technologies
The technically feasible control options are ranked in Table 19-4, according to their control effectiveness.
Ioble l9-4 Control Effecllveness Ronklng of VOC Conhol Technologles for Emergency
Engines
19.2.4 Step 4 - Evqluolion of Feqsible ControlTechnologies
Emissions from emergency engines are minimal because normal operations include only weekly testing,
which results in annual operations of much less than 50 hours per year. Emissions are therefore less than
0.5 tpy per unit. The emissions reduction from replacement of an existing engine with a Tier 4 engine is
therefore minimal, and the control cost is not economically feasible.
19.2.5 Step 5 - RACT Seleclion
RACT for VOC emissions from the emergenry engines is using good combustion practices, and
compliance with MACT ZZZ. Replacement of the engine with a Tier 4 engine is not economically feasible.
70
20 RACT for Temporory Boilers
Marathon generates steam used in the refinery in the heat recovery steam generators (HRSGs) at the
Cogen Units and waste heat boilers located in the process units. Marathon does not have any backup
boilers on site, and rents package boilers to produce steam on a temporary basis for the refinery as
needed when the HRSG or other waste heat steam producers are out of service and the online steam
production capacity is insufficient to meet refinery steam demand.
During refinery wide process unit and total steam producer outages temporary boilers may be needed to
supply steam for heating various tanks and provide steam to the North and South Flare for safety
purposes. These temporary boilers are typically placed in the tank farm beyond utility availability and are
fired with liquid fuels.
This practice produces less emissions than an unplanned or planned startup and shutdown of all or some
process units. Once these units are back in service and operating in a stable manner, operation of the
package boilers ceases. Situations requiring the use of temporary package boilers are relatively infrequent;
so, it is more economical to use rental equipment than installing backup boilers which would rarely be
used.
Temporary boiler emissions are limited by:
o The use of natural gas for fuel or diesel fuel meeting the specifications of 40 CFR 80.510
. The boilers are operated only on an as needed basis.
. Time on site is limited to 180 days or less per 40 CFR 60.41 b.
The emissions from these Temporary Boilers are discussed in total in the sections which follow.
20.1 Temporory Boilers VOC Emissions
VOC emissions from the Temporary Boilers are a result of incomplete combustion. Temporary boilers
operate on the same fuels as the refinery process heaters except for refinery wide process unit and total
steam producer outages. ln addition, combustion conditions in a temporary boiler are similar to those in
Marathon's process heaters. RACT for temporary boilers is therefore the same as the Process Heater RACT.
See Section 5.1 for the Process Heater VOC RACT analysis.
20.2 Temporory Boilers NOx Emissions
There are three mechanisms by which NOx production occurs during combustion including thermal, fuel,
and prompt NOx formation. ln the case of gaseous fuel combustion, the primary mechanism of NOx
formation is through thermal NOx formation.
Temporary boilers are operated on natural gas and diesel for refinery wide process unit and total steam
producer outages .
71
20.2.1Step I - ldentity All Avoiloble Conlrol Technologies
Potential control technologies for NOx emissions from a review of available information is listed in
Table 3-1.
20.2.2Step 2 - Technicol Feosibility of Conhol Technologies
The technical feasibility of potential control options for NOx emissions are summarized in Table 20-1. The
following sections provide additional detail.
Ioble 20-l Iechnlcol Feoslblllty of NOx Conkol lechnologles for lemporory Bollers
The NOx performance of temporary boilers is limited by the availability boilers in the rental fleet at the
time when the temporary boilers are needed onsite at the refiners. lf temporary boilers are available with
ULNB and/or SC& the cost may be far greater, which affects the economic feasibility of their use. ln
communication with one large nationwide boiler rental company, they stated, "Our 20+ mmBtu steam
boilers are rated for 30 ppm NOx on natural 9as."tr Considering the composition of refinery fuel gas as
discussed above, temporary boilers would have even higher NOx levels when burning refinery fuel gas
instead of natural gas. As a result, Marathon cannot determine that emissions controls at a particular
performance level is technically feasible in all cases.
Marathon will use natural gas fuel whenever possible except during refinery wide process unit and total
steam producer outages when it is not technically feasible.
20.2.3 Step 3 - Etfecliveness of Feosible Control Technologies
The technically feasible control options are ranked in Table 20-2, according to their control effectiveness.
13 Email communication from Alex Taylor, National Account Representative, WARE, to Marise Textor, 24
October 9,2022.
72
Ioble 20-2 Conhol Effecliveness Ronklng of NOx Conkol Technologies for lemporory Bollers
20.2.4 Step 4 - Evoluotion of Feosible ConlrolTechnologies
The economic, environmental, and energy impacts of technically feasible control options are not required.
The top technically feasible control for each boiler based upon current control technology is selected.
20.2.5 Step 5 - RACT Seleclion
RACT for NOx from Temporary Boilers is:
. Use of natural gas when feasible and diesel fuel meeting the specifications of 40 CFR 80.510.
. Limited use of temporary boilers while onsite and limit time on site to 180 days or less.
As noted above, the NOx performance of rental boilers is limited by the boilers in the rental company's
fleet and the availability of boilers during the time when Marathon needs them on site. So, the NOx
performance of temporary boilers cannot be guaranteed at all times a temporary boiler is needed.
Marathon will limit temporary boiler use time periods as they are needed to meet refinery steam demand
when Cogen HRSGs and other waste heat steam generating capacity is out of service and during
transition periods when operation of the boilers for plant reliability is required. Marathon limits the time
onsite for temporary boilers to 180 days or less per the requirements of 40 CFR 60.41b.
Use of gaseous fuels (when it is feasible)
NOx performance is limited
by rental boiler availabilityOperate boiler on temporary basis per 40 CFR
60.41b
73
Appemdie es
Appendix A
Utoh Petroleum Associolion Letter lo Environmentol Proleclion
Agency
Appendlx A Utoh Petroleum Assoclollon letler to Environmentol Proteclion Agency
6905 S. 1300 E fr288, Gottonwood Heights, UT t4047-1817
FUELIHG UTAH'S GROWTH & PROSPERITY
December 28,2022
Scott Jackson
Chief, Air Quality Planning Branch
Environmental Protection Agency, Region 8
1595 Wynkoop Street
Denver, CO 80202
Sent via email: [e-mail]
Dear Mr. Jackson:
The Utah Petroleum Association ('UPA') is writing to seek clariflcation regarding the
appropriateness of utilizing emissions averaging as an expression of RACT requirements in
Utah's ozone SlP. As you know, Utah is in the process of developing its package of RACT
controls for its upcoming ozone SIP submittal. Based on recent discussions with members of
Utah's Division of Air Quality ('UDAQ"), we understand that the U.S. Environmental Protection
Agency, Region I has raised some concerns pertaining to the inclusion of emission averaging in
the form of emission caps in Utah's SlP. ln view of the fact that a number of sources, including
several refineries that are UPA's member companies, are in the process of compiling their RACT
submissions and are planning to include emission caps for groups of certain emission units (for
example, heaters and boilers) as part of the RACT determination, we are seeking clarification on
the appropriateness of this approach.
UPA is a statewide oil and gas trade association established in 1958 representing companies
involved in all aspects of Utah's oil and gas industry. UPA members range from independent
producers to midstream and service providers, to major oil and natural gas companies widely
recognized as industry leaders responsible for driving technology advancement resulting in
environmental and efficiency gains. Five member companies each operate a petroleum refinery
in the Northern Wasatch Front ozone nonattainment area. Our member refineries provide fuels
not only for the state of Utah but the intermountain west. Two product pipelines carry refined
petroleum product out of Utah, one to supply markets in the Northwest including ldaho, eastern
Washington, and Oregon, and the other to supply product to Cedar City and on to Las Vegas,
Nevada.
Following is a brief summary of our understanding of the RACT requirement relative to the issue
of emission averaging. This is not an extensive legal analysis since we believe the issues are
fairly discrete and readily resolved based on EPA rules and guidance. We are offering this
correspondence to, hopefully, resolve areas of misunderstanding, identify areas of agreement
and areas that might benefit from additional discussion.
Rikk! Hrenko-Browning, President, Utah Fetroleum Association to Scott Jackson, Chief, Air Quality Planning Branch,
Environmental Protection Agency Region 8; December 28,2022.
Of course, we understand that there are a number of RACT criteria beyond those addressed in
this letter and that concurrence on any particular point by EPA is not a final determination on the
yet to be submitted RACT plan. We are simply trying to make sure that we are on the same page
as EPA/UDAQ with respect to the potential use of emission caps as an expression of RACT for
some sources.l From UPA's perspective, such caps are consistent with the applicable regulatory
requirements and provide an effective approach to controlling emissions while, at the same time,
allowing for a measure of flexibility to sources to achieve compliance with RACT.
The definition of RACT does not preclude the use of emission caps. RACT is defined, in
pertinent part, to mean, "devices, systems, process modifications, or other apparatus or
techniques that are reasonably available taking into account ... [t]he necessity of imposing such
controls in order to attain and maintain a national ambient air quality standard ....2 This definition
does not indicate any limitation on emission averaging as part of RACT. ln fact, the definition
contemplates accounting for the "necessity of imposing such controls" so as to achieve the
ultimate objective of attaining and maintaining the NAAQS. This prudential consideration
comports with the notion of reasonable availability.
EPA's guidance and rules and the courts support the use of averaging across emission
unifs as an appropriate way of satisfying the RACT requirement. ln promulgating the rule for
implementing the 2008 ozone NAAQS, EPA explicitly rejected the notion that MCT "requires
each individual source to apply control technology to achieve the lowest emission limitation that
each particular source is capable of meeting considering technology and economic feasibility."3
Furthermore, EPA explained that the RACT requirement may be satisfied by emission-averaging
approaches in lieu of source-specific emission limits. ln justifying such approaches, the Agency
explained that,
The EPA believes that the statute, as interpreted by the court in NRDC v. EPA, provides
a state with the option of demonstrating that its program achieves RACT level reductions
by showing emission reductions greater than or equal to reductions that would be
achieved through a source-specific application of RACT in the nonattainment area.a
As a general proposition, and consistent with the notion of the states' role in designing SIP control
strategies described below, this acknowledges that the states are to be accorded maximal
discretion in their control strategy choices. More specifibally, lhe emission-cap RACT approach
that Utah sources are looking towards are fully consistent with the averaging choice endorsed by
the 2015 rulemaking.
And least there be any doubt regarding its legality, the Court of Appeals for the DC Circuit
unequivocally rejected challenger's assertion that averaging approaches to satisfying RACT
"violatefl the clear terms of the Clean Air Act, which require each individual source to meet the
1 We understand that Region 8 has also expressed some concerns regarding the reliance of emission
caps in the context of Utah's PMz.s BACT SlP. While we do have some questions regarding those
concerns, we are not raising those questions in this letter. ln other words, our question on the use of
emission caps is limited to the ozone SIP RACT context.
2 40 cFR $ 51 .100(o)(1).
3 80 Fed. Reg. 12264, 1228013 (lmplementation of the 2008 National Ambient Air Quality Standards for
O zo n e : State I m ple m e ntat i o n Pl a n Re q u i re me nts).
4 80 Fed. Reg. at 1228013.
Fage 2 of 5
Rikkl Hrenko-Browning, President, Utah Petroleum Association to Scott Jackson, Chief, Air Ouality Planning Branch,
Environmental Protection Agency Region 8; December 28,2Q22
NOx RACT requirement," concluding that, "[t]he statute does not specify that'each one of the
individual sources within the category of 'all' 'major sources' must implement MCT.'s
EPA reiterated and again endorsed these averaging approaches in the implementation
rulemaking for the 2015 ozone NAAQS:
The EPA's adopted RACT approach includes our longstanding policy with respect to "area
wide average emission rates." This policy recognizes that states may demonstrate as part
of their NOx RACT SIP submission that the weighted average NOx emission rate of all
sources in the nonattainment area subject to RACT meets NOx RACT requirements;
states are not required to demonstrate RACT-level controls on a source-by-source basis.6
As EPA notes, its policy endorsing the use of averaging for satisfying RACT is "longstanding."
EPA specifically endorsed an averaging approach similar to what some sources in Utah now wish
to utilize in the 1992 guidance referred to as the NOx Supplement to the General Preamble.T After
identifying unit specific NOx emission limits for several different boiler types, EPA explained that
it:
expects States, to the extent practicable, to demonstrate that the variety of emissions
controls adopted are consistent with the most effective level of combustion modification
reasonably available for its individual affected sources. However, EPA encourages
Sfafes to structure their RACT requirements to inherently incorporate an emissions
averaging concept (i.e., installing more stringent controls on some units in exchange for
lesser control on others). Therefore, in the interest of simplifying State RACT
determinations and enhancing the ability of States to adopt market-based trading systems
for NOx, the State may allow individual owners/operators in the nonattainment area ... to
have emission limits which result in greater or lesser emission reductions so long as the
areawide average emission rates described above are met on a Btu-weighted basis.s
As noted, this is the approach that some Utah sources subject to RACT wish to pursue. Of course,
the averaging (or emission-cap) approach would be supported by appropriate and enforceable
monitoring, recordkeeping, and reporting.
Emission averaging to achieve RACT is consisfent with the Economic lncentive Program
("ElP'). While the emission averaging approach that some Utah sources wish to utilize is fully
consistent and approvable under the policy and regulatory provisions that govern RACT, it is
worth noting that such an approach is independently supported by - and even encouraged by -
the economic incentive provisions of the CAA and implementing regulations. The use of economic
incentives is explicitly allowed for in the general SIP requirementse and the general provisions for
nonattainment SlPs.10 The ElP "may be directed toward stationary, area, and/or mobile sources,
5 Soufh Coast Air Quality Management District v. EPA,882 F.3d 1 138, 1 154 (D.C. Cir. 2018) (hereinafter
referred to as Soufh Coast ll)
6 83 Fed. Reg. 62998, 63007 (Dec. 6, 2018).
7 Sfafe lmplementation Plans; Nitrogen Oxrdes Supplement to the General Preamble for the
lmplementation of Title I of the Clean Air Act Amendments of 1990,57 Fed. Reg. 55620 (Nov. 25, 1992).
8 /d. at 55625 (emphasis added).
e CAuA 110(a)(2)(A).
10 CAA 172(c)(6).
Fage 3 of 5
Rikki Hrenko-Browning, President, Utah Petroleum Association to Scott Jackson. Chief, Air Quaiity Planning Branch,
Environmental Protection Agency Region 8; December 28,2422.
to achieve emissions reductions milestones, to attain and maintain ambient air quality standards,
and/or to provide more flexible, lower-cost approaches to meeting environmental goals."l1
ln promulgating the regulations to implement the ElP, EPA explained that, "An EIP may allow
sources subject to the RACT requirement to attain RACT-level emissions reductions in the
aggregate, and thereby trade among themselves."l2 ln fact, in elaborating on the use of EIP's in
the context of RACT, EPA recounted its (and the courts) approval of the RACT emission-cap
approach that some sources in Utah now seek to take:
Under the EPA's interpretation, the application of the requirement to impose RACT upon
"existing sources" meant that RACT applied in the aggregate, as opposed to source by
source. This interpretation ... was upheld in MIDC v. EPA,33 ERC 1657 (4th Cir. 1991),
an unpublished decision. There, the Court of Appeals for the Fourth Circuit upheld as
reasonable EPA's approval of a Maryland SIP revision for the American Cyanamid
Company relaxing the SIP limit on several lines in exchange for tighter limits on other
lines. The EPA reasoned that the RACT requirement was met by the subject lines in the
aggregate.l3
It is noteworthy that the emission averaging example that EPA recounts was prior to, and therefore
not dependent on, the ElP. ln any event the overall tenor of the EIP is consistent with the RACT
emission cap approach.
A sfa(e's RACT determination should be accorded significant deference. The CAA created
a federal/state partnership in which states have the primary role in designing their SlPs, while
EPA has an important, but lesser role in approving or disapproving the control measures states
put in their SlPs. As Congress determined in enacting the statute, "air pollution prevention ... at
its source is the primary responsibility of States and local governments."la ln discussing the
federal/state partnership under the CAA, the D.C. Circuit Court of Appeals stated:
The Clean Air Act creates a partnership between the states and the federal government.
The state proposes, the EPA disposes. The federal government through the EPA
determines the ends - the standards of air quality - but Congress has given the states the
initiative and a broad responsibility regarding the means to achieve those ends through
state implementation plans and timetables of compliance.... The Clean Air Act is an
experiment in federalism, and the EPA may not run roughshod over the procedural
prerogatives that the Act has reserved to the states, ... especially when, as in this case,
the agency is overriding state policy.... F-lhe 1990 amendments did not alter the division
of responsibilities between EPA and the states in the section 1'10 process.... Congress
did not give EPA authority to choose the control measures or mix of measures states
would put in their implementation plans.ls
11 40 CFR S 51.491 (definition of "Economic lncentive Program," in pertinent part).
12 59 Fed. Reg. 16690, 16695/3 (Economic lncentive Program Rules).
13 ld. at 1670312.
14 42 U.S.C. S 7a01(a)(3); 42 U.S.C. S7407(a) ("Each state shall have the primary responsibility for
assuring air quality within the entire geographic area comprising such State ....").
15 Commonwealth of Virginiav. EPA,108 F.3d 1397, 1408-10 (D.C. Cir. 1997) (citing Bethlehem Steel
Corp. v. Gorsuch,742 F .2d 1028 (7th Cir. 1984)).
Page 4 of 5
Rikki Hrenko-Browning, President, Utah Petroleum Association to Scott Jackson, Chief, Air Quality Planning Branch,
Environmental Protection Agency Region 8; December 28,2022.
ln frequently cited language, the Supreme Court described this arrangement as follows:
[EPA] is plainly charged by the Act with the responsibility for setting the national ambient
air standards. Just as plainly, however, it is relegated by the Act to a secondary role in
the process of determining and enforcing the specific, source-by-source emission
limitations which are necessary if the national standards it has set are to be met.... The
Act gives the Agency no authority to question the wisdom of a State's choices of emission
limitations if they are part of a plan which satisfies those standards [of the CAA].16
Accordingly, EPA should be appropriately deferential to Utah's RACT control strategy, including
reliance on caps, unless there is a compelling reason, and not merely a preference, against such
an approach.
ln summary, we believe that the emission cap approach that some regulated sources and UDAQ
are considering is fully consistent with the Clean Air Act, implementing regulations, EPA policy,
and precedent. As a practical matter, we think such an approach is effective in limiting emissions
while providing sources with a modicum of flexibility. We respectfully request that EPA consider
this information when evaluating Utah's RACT submittal. We look forward to discussing these
matters further with you.
cc:Ryan Bares - [e-mail]
Bryce Bird - [e-mail]
Jon Black - [e-mail]
Michael Boydston - [e-mail]
Becky Close - [e-mail]
Gail Fallon - [e-mail]
John Jenks - [e-mail]
Monica Morales - [e-mail]
Crystal Ostigaard - [e-mail]
Ana Williams - [e-mail]
16 Train v. Natural Res. Def. Council, |nc.,421 U.S. 60, 79 (1975)', see Union Electric Co. v. EPA,427
U.S. 246, 250 (1 976); Florida Power & Light Co. v. Costle, 650 F.2d 579, 586 (Sth Cir. 1981).
Page 5 of 5
Appendix B
Control Cost Evoluotions
Appendix B ConkolCost Evoluoiions
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lnlct wlumctrlc flow Ete(qwi) at 77'F.nd 1.tm.
Oxylen Content of tas dream
Fan Porcr Consumptlon (FP)
q,.
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T.mp€Eture of mstc Bas at wtlct to prchcater (fs)
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Heat lnput of mne gas (-Ahd)
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ls the clculated auxiliary fuel sufficient to stabilize combustion?
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= 1oo - (!Ir x 1oo/101 x 0.2G, =
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=: (-ahd) r,
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= 59( r Total Energy lnput = 0.05 r pi x qr x qd x fli - Td) =
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89,lDZ scftr
auxiliary fuel energy input > 5X ofTotal Energy lnput, then the auxilary fuel is sufficient,)
Auxlllaryfuelflow (Qaf) at n'F and l atm. =
Total volumettic Throughput (qd) at Z'F and 1 atm.=A{=qF+4.+ad=qd+a.r=
Volumetrlc Flow Rate at 60 'F and 1 atm (qr)
Catalyst Volume (Vold)
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= Od x (519)/(77 'F + a60) =
=aJo
(Calculated uslng Equatlon 2.27 ln Chapter 2 ofthe Cost Manual)
85,106 sfrr
172.2t fi,
898'F
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where n =llt! and i= lntrrest iate
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Oron€ RACT: Cost Evaluatlon for StoEte Tenks
Notls for Rrflnery Analysls
E!!!@Ei ydEi ilotes:
Capital Recovery Factor (cRF) = 0.1057
where: n = Equipment Life and i= lnterest Rate
Current Prime Bank Rate 8,50
Expeded Equipment Life 20
Linear Piping Cost Factor 5268 per f@t, 10 inch diameter from RSMeans
ElbowcostFactor S1,329 perelbow,loinchdiameter. Assumedcostofelbowrepresentscostof3o'145'l@'l9o'
turns. From RSMeans
Aggregate Pipe/Fitting Cost Safety Factort 2@6
To Destruction Efficiency 99X
carbon voc capture efficiency 9896
Rol Rctrodt C6ts:
Retrofit cost: refer to analysis of installation of domes on EFRs
Steel r@f/Geodom€ Cost Factor; 209{ Cost for geodesic dome installation. Add factor of 2096 for additional cost of steel fixed
roof.
Cleaning and degassing costs 588,000 Engineering estimate based upon actual costs at another facility
Rmfpaintingcosts S20 /sqftdlameteroftank.
Geodesic Dome demolition cost 5150,000 engineering estimate
Annual Transportation Cost S 1,/40 Site-speclflc records twice peryear.
Annual Waste Container Cleanout S 600 Site-sp€cific records twice per year.
Annualwasteclassification S 650 Site-speclficrecordstwiceperyear.
Annual Disposal cost S 0.50 /lb hazardous waste.
Estimated Carbon Usage Rate (for estimating carbon usSe peryear)507 lb C/ton VOC to Carbon Gnister
Carbon required for system: 8O,000 lb carbon/ton VOC controlled.
IFRT+VFRT 1,25q0ff lbcarbon/yr
Allranks 4o@,ooo lbcarbon/Yr
Carbonboxcapaclty 12,500 lb&ox
CarbonchangeoutsperYear(FRT+VFRT) 1m boxes/yr
CarbonchangeoutsperYear{AllTanks) 325 boxes/W
Costs per Carbon Box:
Rental S 3,600 /boi4-monthrentalassumed
Transportation S 740 /box, based on site-specific records.
Containercleanout S 3m /box,basedonsite-specificrecords.
waste classmcation S 325 /box, based on site-specific records.
Annual Hazardous Waste Disposl Costs:
Disposal Cost Rate: S 0.50 /lb hazardous waste, based on site-specific records.
IFRT+VFRT S 62s,000 /Yr
AllTanks S 2,030,000 /yr
l{otcs:
emissions are identified in th€ "Adjusted RY2017 Actual Emisions with RSR Controls (tpy)" column.
Storage tanks T103, T241, and T248 were installed/replaced afer 2017. Actual emisions for these tanks were represented using potential emisions instead of actual emissions.
emissions from each tank.
new tank. Marathon is conseruativeh using RY2O17 emissions from the old tank, which are greater than expected for the new tank.
carbon systems for individual tanks are based on carbon canisters, which are replaced in whole. These are identified as "case one" in this workbook.
workbook.
Calculation for Pipe Cost includ€s +2096 safety factor to account for changes in elewtion, detailed fittin8 connections at tank and control device.
Assumed combined case (Case Two) involves 50% oftotal pipe length required for sum of piping required for indlvidual cases.
Page 2 of 7
to actual emissions.
T.nl S.n i.r
nY:!01,
Actnl
Embeloc
ltut
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,hvml
Max Annual
EmlstbnriorTo
CortEitln t (ipy
vffl
AnNalL.d
ccmC.rbdr
Cost
'186 fellow Wax Crude 0.57 109 s 121.m4 0.0 1.fi s 32,697
n41
tUL Gasoline (RVP
13.0)3.30 No scheduled ti s 106.37'1.O s.0(167.@4
1325 13.5)L2.74 No scheduled ti s 99.055 5.0(1S.0(s 595.841
Use linear Regression to estimate annuallzed Carbon Canlster cost as a fundion of annual VOC emisions to Carbon Can:
Y = mx+b
where:
Y = Annualized carbon Cost (S/yr) Calculated
m =Slope: 48,538
x = Annual Emi$ions (tpy) Tank-specifc
b = lntercept: 5,52L-74
Cost Considerations for Combined vapor Recovery Unit - all costs to be prorated from 13 (RTF basis) to numb€r oftank in applicable equipment.
Prcject kope (Common for VRU or lO):
lnstollotion of Vopot Control lor @nfiol of tank heod spoe vdpors would require irctollotlon ot o mlnlmun ol the lolbwing items rcgordles of the contol technology sleded:
1) Vopot piping frcm eoch tonk to o moin heodet thot would direct vopo6 to o common point, A wpor blowet to pull ond dircct wpo6 to the contol devices.
2) Detondtion Anesto6 ot specilic designed locations to ensurc ony signifi@nt detonotion .vent could not l,orye6e bock to o ptodud tonk.
3) Prcsure seElng ond contrcl equipment ot eoch tonk to ensure prc$urc in the otmospherlc tonks ls mointoined within design porometeE.
4) Propet supports ond JoundotioB to hold the wpq piping, blowds), ond eleddcol condult ond equlpnent octo$ the tonk fom offi.
5) Eledrlcol supply infrostrudure including new utility Jeeds ond distribution equipmeoL
6) A bloddet tonk to hondb the suryes oJ oit fiow ond to condition that oi flow into the vopor control device.
overcge is dpptoximdtely one yeot.
Cost considerutions:
The following cost considerutions ore engineeinq estimotes lrom similot Motothon prcjeds. MPC relinery, remote tonk form, or truck looding mck sites wuld n.ed on in4epth
ilrcys to detemine needed distibution upgrodes ond utility impods, to\k mowment xhedules ond fill/tronslet rctes to detemine mox vopor llows ond concentrctioat etc. ft is
estimoted thot the common inlrustrudurc costs would likely be btween 51.5 - 2.5MM per site regordles ol whot technology ls used to contrcl the vopots.
Additional Cost Considerations for Combined Vepor Recovery Unit - all costs to b€ prorated from 13 to number of tanks in applicable equlpment.
Additional Cost Considerations for Combined Vapor Recovery lJnit - all costs to be proEted from 13 to number oftanks in applicable equipment.
ln addition to the common project scope, a VRU would require the following items to be procured and installed:
1) Gasol;ne supply and retum plping to an exlsting tank and a back-up tank s that it could be opeEted when the prlmary tank is out for lnspectlon or repalr.
2) The plping may requlr€ the tank to have hot taps performed or the tank to be taken out of service to connect the piping.
3) Centrifugal pumps and motors to deliver gasoline to the VRU.
4) A large (400 Amp or larger) electrlcal seruice will need to be supplied to the location ofthe VRU.
5) Significant runs of conduit and wire will be required to get the necessary power from the distribution point to the VRU skid.
6) A larSe concrete footer and pad will need to be created to place the vRU skid and carbon ve$els on.
7) The vRU itself will need to be purchased from a 3rd party vendor.
8) Supply chaln l$ues associated with procuring all equlpment will need to be incorporated into schedule.
Cost considerations:
The following cost consideations are engineering estimates from similar Marathon proJeds. MPC reflner remote tank farm, or trck loading Eck sites would need an in-depth study
needed distribution uFgrades and utilaty impads, tank morement schedules and fill^ransfer rates to detemine max vapor flows and concentEtions, etc.
cost up to S1MM cost per site to upgEde. The estimated increase ln electrlcal uste per slte wlth the VRU is expected to be on the order of 5175 - S2@M per year in ongoing costs.
Total Estimated costs for vRU System = S4.5MM - S5.5MM plus S175M-S200M in utlllty cost per slte
The estimates for product recovery with a VRU are very minimal. MPC does not have data to ascertain with certainty that any rtrovered gallons of product would be per year kom a
VRU system but based on the lean wpor/ air mixture expected in the tank head spaces above the floating roof, the recovered gallons are not expected to provide a return that would
economi6llyjustify the cost ofthe prc.iect to install an adequate syst€m.
The estimated cpital cost for a VRU that serves the IFRTS and VFRTS ls based on the low estimate of each range. For an aggregated system that controls all lFRTs, EFRTS, and VFRTS, an
Page 3 of 7
Addltlonal Cost Consid€ratlons for Combined Thermal oxldation System - all costs to be proratcd ftom 13 to number oftanks in applicable equipment.
ln addition to the common prciect sope, a prcject *ope for a TO lnstallation would includ€ the following additional effons:
1) NatuElSas supply rculd llkely need to be added to the facility.
2) Work with the lcal utility provider would ned to be done to ensure the volume r€quired on-site is aEilable or if *ilice modifidtions are required.
3) Piping from the natural gas supply point would nced to be installed to the sitr ofth. TO skid.
4) An electrlcal fed will need to be provlded.
5) A concrete pad and footer will need to be created to pl.ce the TO skid on.
7) The To itselfwill need to be purchased from a 3rd party vendor.
8) Supply chaln i$ues asciated with procuring all .quipment wlll need to b. lncorpomted into schedule.
A To is enimated to cost approximately S750M. The natural 8as pipinS and serdc€ uptEdes are likely to cost S250M per site plus SlsoM additional in electrical and site prep
charges. The natural gas usge will be slSnlflcant and is estlmated at S300-50OM per year ongoin& per slte to maintain minimum temperatures ln the TO.
Total Estimated @sts for TO System = S2.15MM - 53.15MM plus $(,oM-SsoOM in utillty cost per site
Theestimated@pitalcostforaTOthatseryesthelFRTsandVFRT5isbasedonthelowestlmateofeach€nge. ForanaSgreSatedrystemthatcontrolsalllFRTS,EFRTS,andVFRTS,the
high-side estimate ls used. Furthemore, roof retroflt costs are assumed for all EFRTS to undergo conversion to utilize a VFRT in included in the latter aggregate system cost.
Page 4 of 7
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Salt Lakc clty Rcflnery - Rcmotc Tank Fam
Orono RACI: Cost Ev.luatlon for Stoate Tankt
Not6 for Rcmot€ Tank Farm Analysis
Paramete6:
Capital Recovery Faclor (CRF) =
where: n = Equipment Life and i= lnterest Rate
Current Prime Bank Rate
Expected Equipment Life
Linear Piping Cost Factor
Elbow Cost Factor
ASgregate P|FE/Fitting Cost Safety Factor:
TO Oestruction Efficiency
Carbon VOC capture efficiency
Rof Re{rofrt C6tr:
Retrollt cost: refer to analysis of installation of domes on EFR5
Steel roof/Geodome Cost Factor;
Cleaning and dega$lng costs
Roof painting costs
Geodeslc Oome demolition cost
20% Cost for Seodesic dome installation. Add factor of 20% for additional cost of steel fixed roof.
S88,(m engineerlng estimate
S20 /sq ft diameterof tank.
5150,000 englneering estimate
Vrlue: Noter:
0.1057
8.50
20
5268 per f@t, 10 inch diameter ftom RSMeans
31,329 perelbow,l0inchdiameter. Assumedcostofelbowrepresentscostof30'145'160'l9()'tutn' FromRSMeans
2Vo
9996
98%
Annual Transportation Cost 5 1,/40 Site-specific records twice per year
Annual waste Container Cleanout S 600 Site-speciflc records twlce per year
Annualwasteclassification S 650 Site-specificrecordstwiceperyear
Annual Disposal cost S 0.50 /lb hazardous waste.
Carbon required for system: 80,000 lb carbon/ton vOC controlled.
IFRT+VFRT 370,m lbcarbon/yr
AllTanl6 1,73q0m lbcarbon/yr
Carbon boxcapacity 12,500 lb/box
GrbonchangeoutsperYear(FRl+VFRT) 30 boxes/yr
GrbonchangeoutsperYear(AllTank) 138 boxes/yr
Costs per Carbon Box:
Rental S 3,500 /box,+monthrentala$umed
TEnsportation S 740 /box, based on site-specific records.
Containercleanout S 3m Aox,basedonsite-specificrecords.
waste cla$ification S 325 /box, based on sitFspecific records.
Annual Hazardous Waste Disposal Costs:
Disposal Cost Rate: S 0.50 /lb hazardous waste, based on site-specific records.
IFRT+VFRT S 185,000 /yr
AllTanks S 865,000 /yr
ilotrs:
emissions are identifled in the "Adjusted RY2017 Actual Emlsions with RSR Controls (tpy)" column.
Carbon systems for individual tanks are based m 6rbon canisters, which are replaced in whole. These are identilied as "Case One" in this workbook.
workbook.
Calculation for Pipe Cost includes +209( safety factor to account for changes in elevation, detailed fitting connedions at tank and control device.
A$umed combined case (Case Two) involres 50% oftotal pipe length required for sum of piplng required for individual cases.
Cost Considerations for Combined Vapor Recovery unit - all costs to be prorated ftom 13 to number of tanks in applicable equipment.
Page 6 of 7
Prcjed Scope (Common lot VRU ot TO):
lnstollotion ol Vopot Contrcl for contrcl of tonk heod spw voporc would rcgulre lnstollotlon dt d minimun ol the lolbwing itcms rego,dhs d the coottol technology seleded:
1) Vopor piping tlom coch tonk to o moin header thot would direcl vopo6 to o common point. A wpot bbwt to pull ond dircct vopo6 to the contrcl devices.
2) Dctonotioa Afresto6 ot specilic designed lodtions to ensurc ony signifrcont detonation cvent could not t/o,IMe bock to o ptoduct tdaL
3) Pre$urc sensing ond contrcl cqulpment ot edch tonk to cnsure Nesure ln the otmosphctk tonks ls mointoincd wlthia dcslgn porcmeters.
4) Prcpq suppotts ond foundotions to hold the wpot piping, blowr(s), ond electhol conduit ond cquipment octo$ the tonk lom orc6.
5) Eledrl@l supply lnfudstruAurc lncludlng new utilW lceds dnd dlsttlbutbn equlpment.
6) A blodder tonk to hondle the suryes oJ olr fiow ond to @ndftion thot oit flow lnto the Vopor Contrcl devlce.
is opprcximotely one yeor.
Cost corcAerutions:
The following cost considerutions orc engineeilng estimotes lrom similot Motothon prcjects. MPC rcfinery, remote tonk fom, ot truck l@ding Nck skes wuld need on in-depth
engineedng study to determine wpot piping siziog, numhet ol pipe/conduf suppotts, surey of undcrrund obstrdio6, soil sureys to determine l@tet dslgns, powet utillzotion
sureeys to determine needed disttibution up-grod.s ond utilv lmpdcts, tdnk movemcnt schedules ond lilvtronsfet rutes to detemine mu wpor llow ond concenttotlo6, etc. lt k
estimoted thot the common inlrostructurc cons wuld likely be b€tween 51.5 - 2.5MM pet site regotdle$ ol whot technolory is uftd to contrcl the vdpoR.
Additional cost considerations for combined Vapor Recovery Unit - all costs to be prorated ftom 13 to number oftanks in appliable equipment.
ln oddition to the common prcied fope, o VRU wuld reguirc the lollowing item to be prcured ond instolled:
7) Gomline supply ond retum piping to dn disting tonk ond d bock-up tonk e thot k could be operoted when the pilmory tonk h out Jot i6pedion or rcpoir.
4 };he piping moy require the tonkto hove hottops petomed ot the tonkto be token out of seruice to connedthe piping.
3) Centilugol pumps dnd moto6 to deliver gosoline to the VRU.
4) A laee U(n Amp ot loruet) eledrkdl sevice will need to be supplied to the lo@tion ol the VRU.
S) Signifrcdnt runs of conduit ond wirc will be rcquircd to get the neewry powr from thc disttibution point to the VnU skid.
6) A lorye conilete l@tet ond pod will need to be creoted to ploce the vRU skid and cotbon ve*ls on.
7) The VRU itftt will need to be purchosed lrom o 3d potty vendot.
8) Supply choin i$ues oseioted with ptmuring oll equipment will need to be lncorporoted into schedule.
Cost considerutions;
fhe lollowing cost considerotions or engineeing estimotes lrm similor Mdrthon projeds. MPC refner rmote tonk fom, ot truck l@ding rock sites would need on in4epth study to
needed disttibution ufgrcdes ond utility impocts, tonk movement schedules and fill/ttonsler rctes to detemine mu vopor flow ond concenttotioB, etc,
A VRU would likely con opptoxlmotely 57.5 MM. There wlll be rcughly Ssof,M ol costs in gofline piping ond sitc prep wrk pct site. The cleddcol lnfostrudure ond utiw feeds could
cost up to STMM con pet site to upgrcdc. fhe estimat2d incredse in .lecttkdl ufigc pct site with the VRU is cxpeded to bc on the otdet of $175 - $2O0M per ycor in onqoinq c6ts.
Totol Estimoted costs lor VRLt System = $4.5MM - S5.5MM plus 5175M-S20OM ln utility cost pet site
The estimqtes for prcduct rccovery wlth o WIJ orc vcry mlnlmol. MPC does not hove doto to oxettoin with certointy thot ony recovered gollo6 ol Ptodud would be pet yeot from o VRU
system but bd*d on thc leon vopot / oi mixture expeded in the tonk heod spoces obove the floating rcol, the recovcrcd gollons ore not erpeded to provide o rctuh thot would
economicolly lusw thc cost ol the projed to instoll on odequote system.
Th. estimoted upitdl @st lot a VRI) thot sNes thc IFRTS ond WRTS is bosed on the low estimot ol coch runge. Fot on oggrcgoted sFtem thot controk oll lFRTs, EFRTS, dnd VFRTS, on
Additional Cost Considerations for Combined Thermal Oxidation S!6tem - all costs to be proEted from 13 to number oftank5 in applicable equipment.
ln oddition to the @mmon prcjed scope, o prcjed scope Jor o TO lrctollotion would include the following odditiondl elforts:.
7) Ndtutol gos supply wuld likely need to be odded to the focility,
2) Wo* with the locdl utility prcvidet wuld need to be done to ensurc the volume rcquircd on-site is Noiloble ot il trruke modificotions are required.
3) Piping fum the noturol gos supply point would need to be instolled to the site ol the TO skid.
4) An elefikol leed will need to be provided.
5) This is llkely not loe? enough to require frice upgrddes lrm the utiw but will rquite exttd power disttibution ond signilicant rns ol conduit ond wire much llke the VRU fope.
6) A concrete pod ond lootet will need to be ileoted to ploce the TO skid on.
7) fhe fO itselt wilt need to bc purchosed lrcm d 3d porty vendor.
8) Supply choin isues owioted with pwuring oll equlpment will need to be incoryoruted into nhedule.
A TO ls estlmoted to cost opptoximately S75OM. fhe naturcl gos piplng ond ftruke upgrcdes orc likely to c6t $250M pct site plus S75OM oddftlonol ln cledricol ond sfte prcp
chotges. The noturcl gos usoge will be significant ond is estimoted ot S30O50OM pet yeot ongoing, pet site to mointoin minimum tempcrctutes in the TO.
lotul Enimoted c6ts lot TO System . S2.15MM - 53,15MM plus S3@M-SSAOM ih utility @st pet site
The estlmotcd copitol c6t for o TO thot seryes the IFRTS ond VFRTS ls bosed on the low estimqtc ol &ch ronge- Fot on oggrcrot d system thot contrls oll lFRTs, EFRTS, ond VFRTS, the
huh-sidc cnimote k uscd. Furthermorc, MI rctrofit costs orc ossumcd lot oll EFRTS to und.rqo conveEion to utilizc o WRf in includcd in the lolter oggreqote system cost.
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