DAQ-2024-010892

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DAQC-1047-24
Site ID 10122 (B1)

MEMORANDUM

TO: FILE – BIG WEST OIL

THROUGH: Harold Burge, Major Source Compliance Manager

FROM: Jeremiah R. Marsigli, Environmental Scientist

DATE: October 9, 2024

SUBJECT: FULL COMPLIANCE EVALUATION (#4 of 4), Major, Davis County,
FRS ID# UT0000004901100008

INSPECTION DATE: September 12, 2024

SOURCE LOCATION: 333 West Center Street, North Salt Lake, Utah 84054

MAILING ADDRESS: 333 West Center Street, North Salt Lake, Utah 84054

SOURCE CONTACT(S): E. Faithe Schwartzengraber, Environmental Manager, [phone]
Ian Muller, Environmental Engineer, [phone]
Brady Miller, Environmental Engineer, [phone]

OPERATING STATUS: Operating

PROCESS DESCRIPTION: Big West Oil operates a refinery, which is capable of processing 30,000
barrels of crude oil per day. The crude oil is processed by fractionation,
reforming, cracking, alkylation, sulfur recovery, and other intermediate
and final blending processes into various fuel products. Other activities
include steam generation (boiler plant), equipment cooling (cooling
tower), wastewater treatment, and product storage and distribution.

Crude oil is piped into the crude unit, which heats the oil, and separates
(fractionate) it by boiling point. The reformer converts low octane
naphtha into high-octane gasoline and hydrogen. The millisecond
catalytic cracking unit (MSCC) cracks heavy gas oil feed (large
hydrocarbon chains) into higher quality gasoline blending components
and light gas oil (small hydrocarbon chains). The distillate de-waxing
(MDDW)/hydro-desulfurization (HDS) units do the same process as the
MSCC, but are used for heavy diesel fuels only. The cooling towers
circulate cooled water to equipment and products, which return hot water
to be cooled. The alkylation unit takes olefins and combines them with
isobutane in the presence of hydrofluoric acid to form gasoline range
hydrocarbons. The boiler plant produces steam to power turbines, heat
reboilers, tanks, and buildings.

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Sulfur recovery unit/sour water stripper (SRU - SWS plant): Water with
a high sulfur content is called sour water. Sour water from the crude unit
is stored in a waste tank. Sour water is then sent to the SWS. Acid gas
leaving the SWS is passed through the sour water scrubber (water
knockout). If the scrubber goes down, the SWS system shuts down. The
acid gas is then sent to the SRU.

Amine plant: Sour fuel gas is sent to the amine absorber where the sulfur
is removed. The amine solution is then sent through a regenerator and
recycled through the absorber until the amine solution is completely used
up or spent. Emissions from the amine plant are called amine acid gas
and are processed through a scrubber, and then the SRU. If the scrubber
goes down, the entire system will shut down (including the SRU).

SRU - SWS acid gas and amine acid gas are sent to the reactor furnace or
acid gas burner. 60% or more of the H2S is converted to sulfur in the
reactor furnace. The acid gas then vents to a waste heat reclaimer,
catalytic reactor, and three pass condenser where the remaining H2S is
converted to sulfur. The SRU tail gas incinerator burns any remaining
H2S in the gas stream. A flare system is installed inside the incinerator
stack and is available in the event of a process upset.

APPLICABLE
REGULATIONS: AO DAQE-AN101220081-24, dated May 6, 2024

SOURCE INSPECTION
EVALUATION:
SECTION I: GENERAL PROVISIONS
I.1 All definitions, terms, abbreviations, and references used in this AO conform to those used in the UAC R307 and 40 CFR. Unless noted otherwise, references cited in these AO conditions refer to those rules. [R307-101]
Status: This is not an inspection item.

I.2 The limits set forth in this AO shall not be exceeded without prior approval. [R307-401] Status: In compliance. No limit exceedances were found during this inspection.
I.3 Modifications to the equipment or processes approved by this AO that could affect the emissions covered by this AO must be reviewed and approved. [R307-401-1] Status: In compliance. No unapproved modifications were discovered. I.4 All records referenced in this AO or in other applicable rules, which are required to be kept by the owner/operator, shall be made available to the Director or Director's representative upon request, and the records shall include the two-year period prior to the date of the request. Unless otherwise specified in this AO or in other applicable state and federal rules, records shall be kept for a minimum of five (5) years. [R307-401-8] Status: In compliance. All requested records have been made available.
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I.5 At all times, including periods of startup, shutdown, and malfunction, owners and operators shall, to the extent practicable, maintain and operate any equipment approved under this AO,
including associated air pollution control equipment, in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Director which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. All maintenance performed on equipment authorized by this AO shall be recorded. [R307-401-4] Status: In compliance. The source appeared to be operated and maintained in a manner consistent with good air pollution control practices. Maintenance records are kept. All monitoring required by this permit is recorded. I.6 The owner/operator shall comply with UAC R307-107. General Requirements: Breakdowns. [R307-107] Status: In compliance. The company is aware of the breakdown rule and reports when necessary. I.7 The owner/operator shall comply with UAC R307-150 Series. Emission Inventories. [R307-150] Status: In compliance. Emission inventories have been submitted as required. Testing and monitoring requirements are addressed in more specific conditions below and in the
other partial compliance evaluations.
I.8 The owner/operator shall submit documentation of the status of construction of the new boilers (Boilers #7, #8, and #9) to the Director within 18 months from the date of this AO.
This AO may become invalid if construction is not commenced within 18 months from the
date of this AO or if construction is discontinued for 18 months or more. To ensure proper
credit when notifying the Director, send the documentation to the Director, attn.: NSR Section.[R307-401-18 ] Status: In compliance. Big West Oil has 18 months from the date of this AO to submit this notification.
SECTION II: PERMITTED EQUIPMENT
II.A THE APPROVED EQUIPMENT II.A.1 Big West Oil, LLC
Source Wide
II.A.2 H-101
FCC Heater
II.A.3 H-301 17.29 MMBtu/hr ALKY Heater supplies the Isostripper Column
II.A.4 H-402 #2 Crude Heater
II.A.5 H-403 Crude Preflash Heater

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II.A.6 H-404 #1 Crude Heater with Ultra-Low Nox Burners (ULNB)

II.A.7 H-601
32.4 MMBtu/hr Unifiner Heater

II.A.8 H-621, 622, 624
Reformer Heaters

II.A.9 H-1001
(MIDW) Heater

II.A.10 H-1002
HDS Reboiler

II.A.11 H-1003
HDS Heater
II.A.12 H-1102
Sulfur Removal Unit/Plant (SRU) and Tail Gas Incinerator
II.A.13 Caustic Fuel Gas Scrubber
Thiolex fiber-film contactor system
II.A.14 D-103 FCC Regenerator Combustion Gas Vent includes:
Pall Corporation flue gas blowback filter, 38,116 ACFM max flow rate, 198' stack as measured from the base of the stack II.A.15 #1 Boiler Retrofitted with ULNB
II.A.16 #6 Boiler Retrofitted with ULNB
II.A.17 Wabash Boiler Equipped with LNB and FGR (Unit is a long-term rental/replacement)
II.A.18 Plant Boilers Boilers #7, #8, and #9 Cleaver Brooks - Nebraska D-Type boilers Rating: 98.8 MMBtu/hr Control: low-NOx burners rated at 9 ppm.
II.A.19 Plant Flare #1
South Plant Flare
II.A.20 Plant Flare #2
North Plant Flare
II.A.21 Plant Flare #3 West Plant Flare

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II.A.22 VCU Railcar Loading Facility and Vapor Combustor Unit

Status: In compliance. No unapproved equipment was observed.
SECTION II: SPECIAL PROVISIONS
II.B REQUIREMENTS AND LIMITATIONS II.B.1 Conditions on Permitted Source II.B.1.a Unless otherwise designated in specific source subsections, visible emissions from the following emission points shall not exceed the following values while in operation:
1. Combustion sources without control facilities shall not exceed 10% opacity.
2. Fugitive emissions shall not exceed 15% opacity.
3. Refinery catalytic cracking units and Plant Flare #1 [South] shall not exceed 20% opacity.
4. Fugitive dust and all other sources shall not exceed 20% opacity.
Opacity observations of emissions from stationary sources shall be conducted in accordance with 40 CFR 60, Appendix A, Method 9.
[R307-201-3, R307-401-8(1)(a)]
Status: In compliance. No visible emissions were observed during this inspection. II.B.1.b The owner/operator shall use only plant gas and natural gas as fuels in the Amine Plant, Diesel Hydrotreater Unit, Distillate De-Waxing Unit, SRU Unit, and Boilers #7, #8, and #9. Fuel oil may be used as a backup fuel, but only during periods of natural gas curtailment.
The use of diesel fuel meeting the specifications of 40 CFR 1090.305 is allowed in standby or emergency equipment at all times.
If any other fuels are to be used, this AO shall be modified as required in accordance with R307-401, UAC.
[R307-401-8(1)(a), SIP Section IX.H.12.b.iv]

Status: In compliance. No fuel oil is used. II.B.1.c The sulfur content of any fuel oil burned shall not exceed 0.0015 percent by weight as determined by ASTM Method D-4294-89 or approved equivalent. The sulfur content shall be tested if directed by the Director. [R307-401-8(1)(a)] Status: In compliance. No fuel oil is used.

II.B.1.d Stack testing to show compliance with the emission limitations for the sources in this AO shall be performed in accordance with 40 CFR 60, Appendix A; 40 CFR 51, Appendix M;
R307-305-3, UAC; and SIP Section IX.H.11.e.i.
Until such time as it is removed from service, the Wabash Boiler's NOx emissions shall be
monitored and recorded using a portable analyzer no less than once each month. The NOx emissions shall also be used to determine the NOx emission factor in accordance with II.B.9.d.2
and to calculate the plant-wide daily NOx emissions in accordance with II.B.9.d.1. [R307-150]
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II.B.1.d.1 A. Sample Location:
The emission point shall be designed to conform to the requirements of 40
CFR 60, Appendix A, Method 1, or other EPA-approved testing methods acceptable to the Director. Occupational Safety and Health Administration (OSHA)-approvable access shall be provided to the test location.
B. Volumetric Flow Rate:
40 CFR 60, Appendix A, Method 2, or EPA Test Method No. 19, "SO2 Removal & PM, SO2, NOx Rates from Electric Utility Steam Generators," or
other EPA-approved testing methods acceptable to the Director.
C. PM10:
40 CFR 51, Appendix M, Methods 201a and 202, or other EPA-approved testing methods acceptable to the Director. If a method other than 201a is used,
the portion of the front half of the catch considered PM10 shall be based on
information in Appendix B of the fifth edition of the EPA document, AP-42, or
other data acceptable to the Director.
D. PM2.5:
40 CFR 51, Appendix M, 201a and 202, or other EPA-approved testing methods acceptable to the Director. The back half of the condensables shall be used for compliance demonstration as well as for inventory purposes. If a
method other than 201a is used, the portion of the front half of the catch
considered PM2.5 shall be based on information in Appendix B of the fifth edition of the EPA document, AP-42, or other data acceptable to the Director.
E. SO2:
40 CFR 60 Appendix A, Method 6C, or other EPA-approved testing methods acceptable to the Director.
F. NOx:
40 CFR 60 Appendix A, Method 7E, or other EPA-approved testing methods acceptable to the Director. G. Calculations: To determine mass emission rates (lb/hr, etc.), the pollutant concentration as determined by the appropriate methods above shall be multiplied by the volumetric flow rate and any necessary conversion factors to give the results in the specified units of the emission limitation.
H. Protocol:
A stack test protocol shall be provided at least 30 days prior to the test. A pretest conference shall be held if directed by the Director.

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I. Production Rate:
The production rate during all compliance testing shall be no less than 90% of the maximum production rate achieved in the previous three (3) years. If the desired production rate is not achieved at the time of the test, the maximum
production rate shall be 110% of the tested achieved rate, but not more than
the maximum allowable production rate. This new allowable maximum production rate shall remain in effect until successfully tested at a higher rate. The owner/operator shall request a higher production rate when necessary. Testing at no less than 90% of the higher rate shall be conducted. A new maximum production rate (110% of the new rate) will then be allowed if the test is successful. This process may be repeated until the maximum allowable production rate is achieved.
[SIP Section IX.H.1, SIP Section IX.H.11]

Status: In compliance with stack testing requirements. CEM requirements are evaluated by DAQ’s CEM specialist. Stack testing requirements will be addressed where applicable in specific conditions below. II.B.1.e For all continuous monitoring devices, the following shall apply:
A. Except for system breakdown, repairs, calibration checks, and zero and span adjustments required under paragraph (d) 40 CFR 60.13, the owner/operator of an affected source shall continuously operate all required continuous monitoring systems and shall meet minimum frequency of operation requirements as outlined in R307-170 and 40 CFR 60.13. Flow measurement
shall be in accordance with the requirements of 40 CFR 52, Appendix E; 40
CFR 60, Appendix B; or 40 CFR 75, Appendix A.
B. The monitoring system shall comply with all applicable sections of R307-170; 40 CFR 13; and 40 CFR 60, Appendix B: Performance Specifications.
[SIP Section IX.H.11.f]
Status: Not evaluated. CEM requirements are evaluated by DAQ’s CEM specialist. II.B.2 Conditions on the SRU II.B.2.a The owner operator shall either:
1. install and operate a sulfur removal units/plant (SRU) that is at least 95% effective in removing sulfur from the streams fed to the unit; or
2. install and operate a SRU that meets the SO2 emission limitations listed in 40
CFR 60.102a(f)(1) or 60.102a(f)(2) as appropriate.
[SIP Section IX.H.1.g.iii.A.II]
Status: In compliance. Big West met the 95% removal efficiency during the 12-month period preceding this inspection. See condition II.B.2.c below for additional details.

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II.B.2.b The owner/operator shall install, calibrate, maintain, and operate a continuous emissions
monitoring system for monitoring the SO2 content of the gas from the sulfur plant incinerator
on the Claus Unit tail gas stream. The monitoring system shall comply with all applicable sections of R307-170-6, UAC; and 40 CFR 60, Appendix B, Specification 2. [R307-170] Status: Not evaluated. CEM requirements are evaluated by DAQ’s CEM specialist.
II.B.2.c The streams from the Amine plants (fuel gas desulfurization units) and the sour water overhead stripping operations shall be processed in the SRU. [R307-401] II.B.2.c.1 Operating Specification or Performance Requirements
1. Copies of the SRU Operating Instruction/Standard shall be made available to the Director upon request. [R307-401] II.B.2.c.2 The owner/operator shall comply with a 95% recovery efficiency requirement for all periods of operation except during periods of scheduled startup, scheduled shutdown or malfunction of the SRU. Recovery efficiency shall be determined on a rolling 30-day average basis. [Consent Decree, SIP Section IX.H.1.g.iii.C]
II.B.2.c.3 Director Authority
1. A request to determine SRU efficiency for any time period that may be questionable may be ordered by the Director.
2. All records of SRU performance shall be maintained for a minimum of two (2)
years. [R307-401]
Status: In compliance. H2S inputs from acid gas streams (sour water) and the amine unit are tested about every six months by a contractor, and flow is measured during operation. SO2 output from the Claus Unit is measured by CEM. Calculated sulfur removal efficiency during the rolling 30-day averaging period ending August 31, 2024, was 95.72%. Exceedances to this limit are reported to DAQ and in Consent Decree reports to US EPA. II.B.3 Conditions on the FCC Unit and Regenerator II.B.3.a Emissions of PM shall not exceed 0.5 lb/1000 lb of coke burned, on a 3-hour average basis, except during startup, shutdown, or malfunction. [40 CFR 60 Subpart J, Consent Decree, R307-401-8]
Status: In compliance. SIP section I.X.H.1.g.ii requires stack testing every three years to meet a higher limit of 1.0 lb/1000 lb of coke burn off. The consent decree requires stack testing annually (no later than October 31). After three passing subsequent tests, BWO may
petition US EPA for a lower stack test frequency (V.C.32 through 35). Stack testing was conducted December 15, 2023. Test results were submitted to DAQ and evaluated in
DAQC-101-24. DAQ calculated test results for PM were 0.085 lb/1000 lb coke burn-off.
BWO also has opacity and SO2 monitors on the MSCC (FCC Unit) and reports under DAQ’s CEM program.

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II.B.3.b CO emissions from the FCC Unit shall not exceed 500 ppm by volume (dry basis) one-hour average at 0% oxygen.
NOx emissions for the FCC Unit shall not exceed the following concentrations:
40 ppmvd at 0% O2 per 365-day rolling average; and
60 ppmvd at 0% O2 per 7-day rolling average
SO2 emissions for the FCC Unit shall not exceed the following concentrations:
25 ppmvd at 0% O2 per 365-day rolling average;
and 50 ppmvd at 0% O2 per 7-day rolling average
These limits are not applicable during periods of startup, shutdown, or malfunction.
[Consent Decree]
Status: Not evaluated. CEM requirements are evaluated by DAQ’s CEM specialist. II.B.3.c The owner/operator shall install, calibrate, maintain, and operate a continuous monitoring system to measure the effluent FCC Unit CO, O2, NOx, SO2, and CO2 emissions. The monitoring
system shall comply with all applicable sections of R307-170 and 40 CFR 60, Appendices A, B, and F.
In lieu of the requirements of 40 CFR 60 Appendix F Sections 5.1.1, 5.1.3, and 5.1.4, BWO must conduct either a Relative Accuracy Audit (RAA) or a Relative Accuracy Test Audit (RATA) on each CEMS at least once every three (3) years. BWO must also conduct Cylinder Gas Audits each calendar quarter during which a RAA or a RATA is not performed. [40 CFR 60 Appendix A, B, and F, R307-170]
Status: Not evaluated. CEM requirements are evaluated by DAQ’s CEM specialist. II.B.3.d The FCCU shall comply with an SO2 emission limit of 25 ppmvd @ 0% excess air on a 365-day
rolling average basis and 50 ppmvd @ 0% excess air on a 7-day rolling average basis.
[SIP Section IX.H.11.g.i.A.I] II.B.3.d.1 Compliance with the SO2 limit shall be determined using a CEM as outlined in II.B.1.e.
[SIP Section IX.H.11.g.i.A.II] Status: Not evaluated. CEM requirements are evaluated by DAQ’s CEM specialist. II.B.3.e The FCCU shall comply with an emission limit of 0.5 pounds PM per 1000 pounds coke burn-off. [Consent Decree] II.B.3.e.1 Compliance with the PM limit shall be determined by following the stack test protocol specified in 40 C.F.R. §60.106(b) to measure PM emissions on the FCCU. Stack tests shall be conducted at a minimum once every three (3) years. [SIP Section IX.H.11.g.i.B.II] Status: In compliance. Stack testing was conducted December 15, 2023. Test results were submitted to DAQ and evaluated in DAQC-101-24. DAQ calculated test results for PM were 0.085 lb/1000 lb coke burn-off. BWO also has opacity and SO2 monitors on the MSCC
(FCC Unit) and reports under DAQ’s CEM program.
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II.B.3.f Each owner or operator of an FCCU subject to NSPS Ja shall install, operate, and maintain a continuous parameter monitor system (CPMS) to measure and record operating parameters from
the FCCU and control devices as per the requirements of 40 CFR 60.105a(b)(1). Each owner or operator of an FCCU not subject to NSPS Ja shall install, operate, and maintain a continuous opacity monitoring system to measure and record opacity from the FCCU as per the requirements of 40 CFR 63.1572(b) and comply with the opacity limitation as per the requirements of Table 7 to Subpart UUU of Part 63. [SIP Section IX.H.11.g.i.B.III] Status: In compliance. 40 CFR 60.105a(b)(1) applies to facilities “that uses a control device other than fabric filter or cyclone”, and further specifies requirements for electrostatic precipitators and wet scrubbers. Big West Oil uses a Pall Filter and has installed COMS as required by the 2013 Consent Decree with USEPA. II.B.4 Plant Boilers II.B.4.a The plant boilers (#7, #8 and #9) are subject to the NOx emission limits and monitoring
requirements of R307-316. [R307-401-8(1)(a)] Status: Not evaluated. These boilers have not been constructed. R307-316 requires stack testing every three years, NOX CEM, combustion analysis as part of a regular maintenance schedule, or other EPA approved method acceptable to the director. II.B.5 Conditions on Plant Flare #3 [West Plant Flare] II.B.5.a The owner/operator shall use only natural gas as a primary fuel for the pilot light in Refinery Plant Flare #3 [West]. If any other fuel is to be used, an AO shall be required in accordance with R307-401, UAC. [R307-401-8(1)(a)] Status: In compliance. Only natural gas is used as a primary fuel.
II.B.5.b Plant Flare #3 [West] is subject to the flare requirements of 40 CFR 63 Subpart CC. [40 CFR 63 Subpart CC] Status: In compliance. The most recent flare management plan received by DAQ outlines baselines, flare minimization plans, monitoring requirements, sweep gas requirements, vent gas composition, and more. In addition, Subpart CC limits visible emissions from flares to no more than five minutes in any two-hour period. No visible emissions were observed during this inspection. Semi-annual Subpart CC reports include instances of pilot flame outage, visible emissions, operating limit exceedances, and flaring events meeting the criteria of Section 63.670(o)(3). II.B.6 Conditions on the Amine Unit II.B.6.a The Amine Plant shall reduce the H2S content for all refinery plant gas. The H2S content of
any plant gas exiting the Amine Plant shall not exceed 0.10 grains/dscf (162 ppmv) based on a rolling 3-hour average. [R307-401] Status: Not evaluated. CEM requirements are evaluated by DAQ’s CEM specialist. II.B.6.b The owner/operator shall reduce the H2S content of the refinery plant gas to 60 ppm or less, as
described in 40 CFR 60.102a. Compliance shall be based on a rolling average of 365 days. The owner/operator shall comply with the fuel gas monitoring requirements of 40 CFR 60.107a and the related recordkeeping and reporting requirements of 40 CFR 60.108a. As used herein, refinery "plant gas" shall have the meaning of "fuel gas" as defined in 40 CFR 60.101a and may be used interchangeably. [SIP Section IX.H.11.g.ii.A]
Status: Not evaluated. CEM requirements are evaluated by DAQ’s CEM specialist.

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II.B.6.c The entire Diesel Hydrotreater H2S gas stream shall be sent to the Amine or Caustic Scrubber unit to be treated with the plant fuel gas from other sources. [R307-401] Status: In compliance. This gas stream is sent to the Amine unit. II.B.6.d The owner/operator shall install, calibrate, maintain, and operate a continuous emission
monitoring system for monitoring the H2S content of the refinery plant gas located at the outlet
of the Amine and Caustic Scrubber units. The monitoring system shall comply with all applicable sections of R307-170-6, UAC; 40 CFR 60 Subpart J; and 40 CFR 60, Appendix B, Performance Specification 7. [R307-170] Status: Not evaluated. CEM requirements are evaluated by DAQ’s CEM specialist. II.B.6.e The owner/operator shall install and operate a caustic fuel gas scrubber system. This system shall be designed to treat a minimum of 10 MMSCFD of sour fuel gas. During periods of outage of either the amine unit or SRU, all plant sour fuel gas shall be treated by the caustic fuel gas scrubber. [R307-401-8] Status: In compliance. This system has been installed.
II.B.7 Conditions on the HDS Unit II.B.7.a Vessel relief valves from the HDS unit shall be vented into the plant flare system to control emissions from the units in the event of a process-upset condition. [R307-401]
Status: In compliance. Vessel relief valves from the HDS unit are vented into the plant flare system
to control emissions from the units in the event of a process-upset condition.
II.B.8 Miscellaneous SIP Requirements II.B.8.a The owner or operator shall comply with the requirements of 40 CFR 63.654 for heat exchange
systems in VOC service. The owner or operator may elect to use another EPA-approved method other than the Modified El Paso Method if approved by the Director. [SIP Section IX.H.11.g.iii]

II.B.8.a.1 The following applies in lieu of 40 CFR 63.654(b):
A heat exchange system is exempt from the requirements in paragraphs 63.654(c) through (g) if it meets any one (1) of the criteria in the following paragraphs one (1) through two (2) of this section.
1. All heat exchangers that are in VOC service within the heat exchange system that either:
a. Operate with the minimum pressure on the cooling water side at least 35 kilopascals greater than the maximum pressure on the process side; or
b. Employ an intervening cooling fluid, containing less than 10 percent by weight of VOCs, between the process and the cooling water. This intervening fluid must serve to isolate the cooling water from the process fluid and must not be sent through a cooling tower or discharged. For purposes of this section, discharge does not include emptying for maintenance purposes.
2. The heat exchange system cools process fluids that contain less than 10 percent by weight VOCs (i.e., the heat exchange system does not contain any heat exchangers that are in VOC service). [SIP Section IX.H.11.g.iii.A.I] Status: This is not an inspection item. As stated in the condition, the heat exchange system is exempt from the requirements of 40 CFR 63.654.
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II.B.8.b The owner/operator shall comply with the requirements of 40 CFR 60.590a to 60.593a.
For units complying with the Sustainable Skip Period, previous process unit monitoring results
may be used to determine the initial skip period interval provided that each valve has been
monitored using the 500-ppm leak definition. [SIP Section IX.H.11.g.iv]
Status: Not evaluated. These requirements are evaluated under the LDAR inspection.
II.B.8.c All hydrocarbon flares at petroleum refineries located in or affecting any PM2.5 nonattainment
area or any PM10 nonattainment or maintenance area within the State shall be subject to the
flaring requirements of NSPS Subpart Ja (40 CFR 60.100a-109a), if not already subject under the flare applicability provisions of Ja. [SIP Section IX.H.11.g.v.A] Status: In compliance. 60.107a applies to flares and requires fuel gas sulfur monitoring. These requirements are covered by Conditions II.B.1.e.and II.B.8.e.2. II.B.8.d All major source petroleum refineries in or affecting any PM2.5 nonattainment area or any PM10 nonattainment or maintenance area shall either
1) install and operate a flare gas recovery system designed to limit hydrocarbon flaring produced from each affected flare during normal operations to levels below the values listed in 40 CFR 60.103a(c), or
2) limit flaring during normal operations to 500,000 scfd for each affected flare.
Flare gas recovery is not required for dedicated SRU flare and header systems, or HF flare and header systems.
[SIP Section IX.H.11.g.v.B]
Status: In compliance. Big West Oil has submitted a flare gas management plan to the Utah Division of Air Quality. Flaring during normal operations is limited to 500,000 scfd or less. II.B.9 Daily and Annual SIP CAP Requirements II.B.9.a The owner/operator shall abide by all applicable requirements of Sections IX.H.1 and IX.H.11 of the Utah State Implementation Plan as most recently adopted by the Air Quality Board. [SIP Section IX.H.1, SIP Section IX.H.11]
Status: In compliance. See specific conditions below.

II.B.9.b Combined emissions of PM10 from all stationary emission points shall not exceed 1.037 tons per day (tpd). [SIP Section IX.H.2.a.i] II.B.9.b.1 Compliance with the source-wide PM10 Cap shall be determined for each day as follows:
A. For purposes of this subsection a "day" is defined as a period of 24- hours commencing at midnight and ending at the following midnight.
B. Total 24-hour PM10 emissions for the emission points shall be calculated by
adding the daily results of the PM10 emissions equations listed below for
natural gas, plant gas, and fuel oil combustion. These emissions shall be added to the emissions from the cooling towers and the FCCs to arrive at a
combined daily PM10 emission total.
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C. The equation used to determine emissions from these units shall be as
follows: Emission Factor (lb/MMscf) * Gas Consumption (MMscf/24
hrs)/(2,000 lb/ton)
The daily PM10 emissions from the FCC shall be calculated using the
following equation:
E = FR * EF
Where: E = Emitted PM10 FR = Feed Rate to Unit (kbbls/day) EF = emission factor (lbs/kbbl), established by the most recent stack test
D. Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that supply combustion sources.
E. Daily gas consumption shall be measured by meters that can delineate the flow of gas to the boilers, furnaces and the SRU incinerator.
F. Results shall be tabulated for each day, and records shall be kept which include the meter readings (in the appropriate units) and the calculated emissions.
[SIP Section IX.H.2.a.i.C]
II.B.9.b.2 For purposes of demonstrating compliance with the source-wide PM10 Cap, the following
default emission factors shall be used: These emission factors shall be applied to the relevant quantities of fuel combusted, unless adjusted by performance testing as discussed below.
A. Natural gas: Filterable PM10: 1.9 lb/MMscf
Condensable PM10: 5.7 lb/MMscf
B. Plant gas: Filterable PM10: 1.9 lb/MMscf
Condensable PM10: 5.7 lb/MMscf
C. Fuel Oil:
The PM10 emission factor shall be determined from the latest edition of AP-42
or other EPA-approved methods.
D. Cooling Towers:
The PM10 emission factor shall be determined from the latest edition of AP-42
or other EPA-approved methods.
E. FCC Stacks: The PM10 emission factor shall be established by stack test.
F. Where mixtures of fuel are used in a unit, the above factors shall be weighted according to the use of each fuel.
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G. The default emission factors listed above apply until such time as stack testing is conducted as outlined in Condition II.B.1.d.
H. PM10 stack testing on the FCC shall be performed initially no later than
January 1, 2019, and at least once every three (3) years thereafter. Stack testing shall be performed as outlined in Condition II.B.1.d.
[SIP Section IX.H.2.a.i.A, SIP Section IX.H.2.a.i.B]
Status: In compliance. Emissions calculations are performed and recorded daily. Emissions factors and calculations appeared correct. The daily maximum was not exceeded during the 12-month period preceding this inspection. II.B.9.c Combined emissions of PM2.5 from all stationary emission points shall not exceed 0.29 tons
per day and 72.5 tons per rolling 12-month period. [SIP Section IX.H.12.b.i]
II.B.9.c.1 Compliance with the source-wide PM2.5 Cap shall be determined for each day as follows:
A. For purposes of this subsection, a "day" is defined as a period of 24-hours commencing at midnight and ending at the following midnight.
B. Total 24-hour PM2.5 emissions for the emission points shall be calculated by
adding the daily results of the PM2.5 emissions equations listed below for
natural gas, plant gas, and fuel oil combustion. These emissions shall be
added to the emissions from the FCC to arrive at a combined daily PM2.5 emission total.
C. The equation used to determine emissions from these units shall be as follows:
Emissions = Emission Factor (lb/MMscf) * Gas Consumption (MMscf/24 hrs)/(2,000 lb/ton)
The daily PM2.5 emissions from the FCC shall be calculated using the
following equation:
E = FR * EF
Where: E = Emitted PM2.5 FR = Feed Rate to Unit (kbbls/day)
EF = emission factor (lbs/kbbl), established by the most recent stack test.
D. Daily gas consumption shall be measured by meters that can delineate the flow of gas to the boilers, furnaces, and the SRU incinerator.
E. Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that supply combustion sources.
F. Results shall be tabulated for each day, and records shall be kept that include the meter readings (in the appropriate units) and the calculated emissions.
[SIP Section IX.H.12.b.i.C]

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II.B.9.c.2 For purposes of demonstrating compliance with the source-wide PM2.5 Cap, the following default emission factors shall be used: These emission factors shall be applied to the relevant quantities of fuel combusted, unless adjusted by performance testing as discussed below.
A. Natural gas: Filterable PM2.5: 1.9 lb/MMscf
Condensable PM2.5: 5.7 lb/MMscf
B. Plant gas: Filterable PM2.5: 1.9 lb/MMscf
Condensable PM2.5: 5.7 lb/MMscf
C. Fuel Oil: The PM2.5 emission factors shall be determined from the latest
edition of AP-42 or other EPA-approved methods.
D. FCC Stacks: The PM2.5 emission factors shall be established by stack test.
E. Where mixtures of fuel are used in a Unit, the above factors shall be weighted according to the use of each fuel.
F. The default emission factors listed above apply until such time as stack testing is conducted as provided in Condition II.B.1.d.
G. PM2.5 stack testing on the FCC shall be performed initially no later than
January 1, 2019, and at least once every three (3) years thereafter. Stack testing shall be performed as outlined in Condition II.B.1.d.
[SIP Section IX.H.12.b.i.A, SIP Section IX.H.12.b.i.B]
Status: In compliance. Emissions calculations are performed and recorded daily. Emissions factors
and calculations appeared correct. The daily maximum and 12-month rolling limit were not exceeded during the 12-month period preceding this inspection.
II.B.9.d Combined emissions of NOx shall not exceed 0.80 tons per day (tpd) and 195 tons per
rolling 12-month period. [SIP Section IX.H.12.b.ii]

II.B.9.d.1 Compliance with the source-wide NOx Cap shall be determined for each day as follows:
A. For purposes of this subsection, a "day" is defined as a period of 24-hours commencing at midnight and ending at the following midnight.
B. Total 24-hour NOx emissions shall be calculated by adding the emissions
for each emitting unit.
C. The emissions for each emitting unit shall be calculated by multiplying the hours of operation of a unit, feed rate to a unit, or quantity of each fuel combusted at each affected unit by the associated emission factor and summing the results.
D. Daily plant gas consumption at the furnaces, boilers, and SRU incinerators shall be measured by flow meters.
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E. The equations used to determine emissions shall be as follows:
NOx = Emission Factor (lb/MMscf) * Gas Consumption (MMscf/24
hrs)/(2,000 lb/ton)
Where the emission factor is derived from the fuel used.
F. Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that supply combustion sources.
G. The daily NOx emissions from the FCC shall be calculated using a CEM
as outlined in Condition II.B.1.e.
H. Total daily NOx emissions shall be calculated by adding the results of the
above NOx equations for natural gas and plant gas combustion to the value
for the FCC.
I. Results shall be tabulated for each day, and records shall be kept that include the meter readings (in the appropriate units) and the calculated emissions.
[SIP Section IX.H.12.b.ii.C]
II.B.9.d.2 For purposes of demonstrating compliance with the source-wide NOx Cap, the following default
emission factors shall be used: These emission factors shall be applied to the relevant quantities of fuel combusted, unless adjusted by performance testing as discussed below.
A. Natural gas: shall be determined from the latest edition of AP-42 or other EPA-approved methods.
B. Plant gas: assumed equal to natural gas
C. Diesel fuel: shall be determined from the latest edition of AP-42 or other EPA-approved methods.
D. Where mixtures of fuel are used in a Unit, the above factors shall be weighted according to the use of each fuel.
E. The default emission factors apply until such time as stack testing is conducted as outlined in Condition II.B.1.d.
[SIP Section IX.H.12.b.ii.A, SIP Section IX.H.12.b.ii.B]
Status: In compliance. Emissions calculations are performed and recorded daily. Emissions factors and calculations appeared correct. The daily maximum and 12-month rolling limit were not exceeded during the 12-month period preceding this inspection. II.B.9.e Combined emissions of SO2 shall not exceed 0.60 tons per day and 140 tons per
rolling 12-month period. [SIP Section IX.H.12.b.iii]

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II.B.9.e.1 Compliance with the source-wide SO2 Cap shall be determined for each day as follows:
A. For purposes of this subsection, a "day" is defined as a period of 24-hours commencing at midnight and ending at the following midnight.
B. Total daily SO2 emissions shall be calculated by adding the daily SO2
emissions for natural gas and plant fuel gas combustion to those from the FCC and SRU stacks.
C. The daily SOx emissions from the FCC shall be calculated using a CEM
as outlined in Condition II.B.1.e.
D. Daily natural gas and plant gas consumption shall be determined through the use of flow meters.
E. Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that supply combustion sources.
F. Results shall be tabulated for each day, and records shall be kept that include CEM readings for H2S (averaged for each day), all meter readings (in the
appropriate units), fuel oil parameters (density and wt% sulfur for each day any fuel oil is burned), and the calculated emissions.
[SIP Section IX.H.12.b.iii.B]
II.B.9.e.2 For purposes of demonstrating compliance with the source-wide SO2 Cap, the emission factors
derived from the most current performance test shall be applied to the relevant quantities of fuel combusted. The default emission factors to be used are as follows:
A. Natural Gas: 0.60 lb. SO2/MMscf gas.
B. Plant Gas: The emission factor to be used in conjunction with plant gas combustion shall be determined through the use of a CEM as
outlined in Condition II.B.1.e.
C. SRUs: The emission rate shall be determined by multiplying the sulfur
dioxide concentration in the flue gas by the flow rate of the flue gas. The sulfur dioxide concentration in the flue gas shall be determined by CEM as outlined in Condition II.B.1.e.
D. Fuel oil: The emission factor to be used for combustion shall be calculated based on the weight percent of sulfur, as determined by ASTM Method D-4294-89 or EPA-approved equivalent acceptable to the Director, and the density of the fuel oil, as follows:
EF (lb SO2/k gal) = density (lb/gal) * (1000 gal/k gal) * wt.% S/100 * (64 lb
SO2/32 lbs)
E. Where mixtures of fuel are used in a Unit, the above factors shall be weighted according to the use of each fuel.
[SIP Section IX.H.12.b.iii.A]
Status: In compliance. Emissions calculations are performed and recorded daily. Emissions factors and calculations appeared correct. The daily maximum and 12-month rolling limit were not exceeded during the 12-month period preceding this inspection.

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EMISSION INVENTORY: Taken from DAQ’s 2023 emissions inventory:

Pollutant Tons/yr
PM10 ..................... 15.13
PM2.5 .................... 14.83
NOX .................... 112.98
SOX ...................... 70.54
CO ...................... 192.85
VOC ................... 295.84
NH3...................... 27.00

PREVIOUS ENFORCEMENT
ACTION: Warning, February 11, 2019 – Exceeding flare limit of no more than five
minutes of visible emissions in a two hour period.

NOV, October 18, 2021 – Exceeding flare limit of no more than five
minutes of visible emissions in a two hour period.

Warning, January 11, 2023 – Failed H2S audit.

NOV, July 19, 2024 – CEMS requirements including failure to maintain
adequate QA/QC plan, failure to make corrective actions following
calibration drift, and failing cylinder gas audit without prompt corrective
action

COMPLIANCE STATUS &
RECOMMENDATIONS: Big West Oil should be considered to be in compliance with the
regulations and AO conditions evaluated at the time of this inspection.

HPV STATUS: Not applicable

COMPLIANCE
ASSISTANCE: No

RECOMMENDATION FOR
NEXT INSPECTION: None

ATTACHMENT: VEO form