HomeMy WebLinkAboutDAQ-2025-0024711
DAQC-436-25
Site ID 10119 (B1)
MEMORANDUM
TO: FILE – CHEVRON PRODUCTS COMPANY – Salt Lake Refinery
THROUGH: Harold Burge, Major Source Compliance Manager
FROM: Joe Rockwell, Environmental Scientist
DATE: April 30, 2025
SUBJECT: PARTIAL COMPLIANCE EVALUATION (PCE #3 of #4) – WWTP, Process
Venting, and Flare – Major, Davis County, FRS #UT0000004901100003
DATE OF INSPECTION: April 22-24, 2025
SOURCE LOCATION: 2351 North 1100 West, North Salt Lake, Utah
MAILING ADDRESS: 685 South Chevron Way, North Salt Lake, UT 84054
SOURCE CONTACT: Lauren Vander Werff, Environmental Team Lead, 801-539-7386
lvanderwerff@chevron.com
OPERATING STATUS: Operating
PROCESS DESCRIPTION:
Chevron Refinery produces propane, jet fuel, gasoline, and diesel fuel at this facility. Crude oil is pipelined
and trucked to the refinery and stored in storage tanks. From the storage tanks, the crude oil is sent through
a desalter and then heated in the crude unit heater. The crude oil is then separated into fractions in the
distillation tower and vacuum tower. These fractions of oil are further refined through physical, thermal,
catalytic, and chemical processes.
The liquid propane gas (LPG) and gasoline are sent to the Gas Recovery Unit which further separates the
streams. The gasoline is sent to storage tanks and the LPG is further processed through the Ionic Liquid
Alkylation Unit and then onto propane storage tanks.
Jet fuel and diesel fuel are transferred from the fractionation column and sent directly to storage tanks.
Some diesel fuel is processed through the Hydrodesulfurization Unit (HDS) to remove additional sulfur
components.
Gas oil from the vacuum column is fed to the Fluid Catalytic Cracker (FCC Unit) which exposes the
product to a catalyst that further breaks down the heavy gas oil into more marketable products such as
gasoline, jet fuel, and diesel fuel.
2
Residual oil from the bottom of the distillation tower is fed to the Coker Unit. The Coker Unit heats the
bottom oil to very high temperatures and then fractionates the products in a distillation tower and produces
coke which is sold by rail car.
The following is a brief description of the main process equipment operated at Chevron Refinery:
Crude Unit:
Crude oil is heated in furnaces and sent through an atmospheric distillation column for separation.
The "bottoms" from the atmospheric column feed a vacuum distillation unit for further
fractionation. Process streams are either sent directly to product storage or sent to other units for
further processing.
Fluid Catalytic Cracker (FCC) Unit:
Oil is received from the Crude Unit vacuum column and Coker that has been hydrotreated in the VGO and
HDN, which is heated in two furnaces. The oil is heated to high temperatures and exposed to a catalyst that
"cracks" the oil into smaller hydrocarbon chains. After the cracking process, the oil is separated into
fractions and sent to product storage or onto other units for further processing. The FCC is equipped with a
catalyst regenerator which burns off the coke deposited onto the catalyst during the cracking process.
Emissions from the unit are routed through cyclones and an electrostatic precipitator and then discharged to
the atmosphere through the precipitator stack.
Reformer Unit:
Low octane hydrocarbons are sent through a series of furnaces and catalytic reactors to form higher octane
molecules for blending into gasoline. The gas stream is sent through a distillation tower for separation after
leaving the reformer.
Isomerization Unit:
Butane is exposed to a catalyst to produce isobutane which is required in the alkylation process.
Alkylation Unit:
Isobutane and propylene or butene is exposed to a catalyst ionic liquid. The reaction produces several
blending components of motor gasoline.
Coker Unit:
The "heavy" oil from the Crude Unit vacuum column and FCC are heated, fractionated in a distillation
tower, and "cracked" into coke. Any product recovered by the fractionation and cracking process is sent
through other units for further processing or to product storage tanks. The remaining product is a solid coke
product which is formed in the large coke vessels. The coke is removed from the vessels with a
high-pressure water drill and stored on train cars until it is shipped to the customer.
3
Hydrodenitrification (HDN) and Hydrodesulfurization (HDS) Units:
Liquid feed from the coker and diesel fuel are fed to these units where they are exposed to a catalyst and
hydrogen gas. This exposure creates a chemical reaction that separates the nitrogen and sulfur products
from the feed stream. The sulfur and nitrogen form hydrogen sulfide and ammonia rich streams which are
fed to the Amine unit and sour water stripper for processing.
Amine Unit:
Sour gas from all process units are combined and exposed to amine which absorbs the hydrogen sulfide
from the fuel gas. The hydrogen sulfide is then stripped off of the amine with steam and sent to the Sulfur
Recovery Unit for processing. The sweet gas (contains little or no hydrogen sulfide) is sent back to the
V-113 mixing drum and used as plant gas.
Sour Water Stripper:
Water streams containing ammonia and hydrogen sulfide are sent through a packed column tower where
high pressure steam strips the ammonia and hydrogen sulfide from the water streams. The ammonia and
hydrogen sulfide are sent to the Sulfur Recovery Unit for processing and the water stream is sent to the
Wastewater Treatment Plant.
Sulfur Recovery Units (SRU):
The ammonia and hydrogen sulfide acid gas streams from the Amine Unit and the Sour Water Stripper are
fed to a thermal reactor and heated to high temperatures. The high temperatures destroy the ammonia and
transform some of the hydrogen sulfide into sulfur dioxide. The hydrogen sulfide/sulfur dioxide stream is
sent through a series of catalytic reactors and condensers where the sulfur compounds are converted into
liquid elemental sulfur. The liquid sulfur flows into the sulfur pit and the acid gas remaining is sent through
the Sulfur Recovery Unit incinerator where it is oxidized.
Wastewater Treatment Plant:
All wastewater and storm water from the refinery property is sent through a series of tanks, oil/water
separators, biological treatment disks, and filters for cleaning. Some emissions from this facility are vented
to a thermal oxidizer and incinerated.
Boiler Plant:
There are three boilers that produce steam for the processes described above. The boilers operate on natural
gas or plant gas.
APPLICABLE REGULATIONS:
40 CFR 63 Subpart A – NESHAP - General Provisions
40 CFR 63 Subpart CC – NESHAP for Petroleum Refineries
40 CFR 61 Subpart FF – NESHAP for Benzene Wastewater
40 CFR 60 Subpart QQQ – NSPS for Petroleum Refinery Wastewater Systems
40 CFR 63 Subpart UUU – NESHAP for HAP for Petroleum Refineries: Catalytic Cracking Units; Catalytic
Reforming Units; and Sulfur Recovery Units (MACT II)
40 CFR 63 Subpart DDDDD – MACT for Industrial, Commercial, and Institutional Boilers and Process
Heaters
4
SOURCE INSPECTION EVALUATION:
40 CFR 63 Subpart A – NESHAP General Provisions
63.6(e) Operation and maintenance requirements.
Status: In compliance – Incident reports are submitted. Corrective actions are included in the
reports. All reported incidents and breakdowns fall under the UAC Rule (R) 307-170 and other
Federal Regulations.
63.6(e)(3) Startup, shutdown, and malfunction plan (SSMP).
Status: In compliance – Operation Maintenance Monitoring Plans (OMMP), Startup, Shutdown,
and Malfunction Plans were available for each process unit. OMMPs are reviewed and updated
every couple of years. Records are kept to demonstrate compliance.
63.8 Monitoring requirements.
Status: Not evaluated – CEM requirements are evaluated by DAQ’s CEM specialist.
63.10(d) General reporting requirements
Status: In compliance – Periodic (semiannual) reports were submitted as required for Subpart CC.
See regulations below for review status.
63.11 Control device requirements.
Status: In compliance – No visible emissions were observed from any of the flares during the
inspection. Flares 1 and 2 have a flare gas recovery system. Flare 3 does not have a flare gas
recovery system. All three flares are monitored by CEMs and CPMs. CEMs include H2S, SO2,
NOx, and TS. CPMs include flow, heat values, tip velocity, and IR camera surveillance. The camera
surveillance detects for the presence of a pilot flame, located at the top of the flares.
40 CFR 63 Subpart CC – NESHAP for Petroleum Refineries
63.640 Applicability
Status: In compliance – Chevron is a major existing source. All subparts have reporting
requirements.
63.640(n) Overlap of subpart CC with other regulations for storage vessels.
Status: In compliance – The provisions of 40 CFR 60 Subpart Kb partially apply.
63.640(o) Overlap of this subpart CC with other regulations for wastewater.
Status: In compliance – 40 CFR 61 Subpart FF and Subpart QQQ apply and are evaluated below.
5
63.640(p) Overlap of subpart CC with other regulations for equipment leaks.
Status: In compliance – The source is required to comply only with this subpart. As required in
63.648, the source follows 40 CFR 60 subpart VV (60.480–489) for leak detection and repair
(LDAR) program requirements. See the LDAR inspection memo for evaluation of equipment leaks
standards.
63.642 General Standards
Status: In compliance – A Title V Operating Permit application has been submitted for 30 years.
Records are kept onsite for at least five years and are archived. All records are available in either
hard copy or computer readable form at time of the inspection. All reports appeared to have been
submitted for this evaluation period. The source is complying with 63.642(k) and 63.642(k)(1).
63.643 Miscellaneous process vent provisions
Status: In compliance – Flares are used to control emissions from group I miscellaneous process
vents. Thus, the source is reducing emissions by complying with (a)(1).
63.644 Monitoring provisions for miscellaneous process vents
Status: In compliance – Miscellaneous process vents are controlled by flares. All vents, at Chevron,
go to the flares and flare gas recovery systems, as applicable, regardless of grouping. Flares have
three thermocouples installed to detect the flame, and an IR camera installed to detect the pilot
flames. Each flare has an alarm set point. No bypass lines are installed to divert the gas streams
away from the flares, thus, (c) does not apply. Flares 1, 2, and 3 have a calorimeter, Btu meter, and
hydrogen meter. The control room monitors and controls the flares, using the above technologies.
At the time of this inspection, the flares appeared to be operating properly.
63.645 Test methods and procedures for miscellaneous process vents
Status: N/A – The source is complying with provision 63.643 by using flares.
63.647 Wastewater provisions
Status: In compliance – Chevron operates a Group I wastewater stream and must comply with 40
CFR 61 Subpart FF. See review of Subpart FF below for compliance status.
63.654 Heat exchange systems.
63.654(c)
The owner or operator must perform monitoring to identify leaks of total strippable volatile organic
compounds (VOC) from each heat exchange system subject to the requirements of this subpart according
to the procedures in paragraphs (c)(1) through (6) of this section.
63.654(c)(1) Monitoring locations for closed-loop recirculation heat exchange systems.
6
63.654(c)(1)(i)
Each cooling tower return line or any representative riser within the cooling tower prior to exposure to air
for each heat exchange system.
Status: In compliance – Outside contractor MPE PSC performs monitoring on the cooling towers
once per month using the El Paso Method to identify leaks at prescribed locations listed above. The
leak definition is > 6.2 ppmv and records indicated that the readings are normally not above 1
ppmv. No leaks have been recorded during calendar year 2024 and calendar 2025, to date.
However, a leak was detected on April 16, 2024, which was > 6.2 ppmv. Cooling tower leak
information can be found in the monthly reports and the Semiannual MACT Subpart CC report.
The last Semiannual MACT Subpart CC Periodic report for the second half of 2024, was received
on March 25, 2025.
63.654(d)
If a leak is detected, the owner or operator must repair the leak to reduce the measured concentration to
below the applicable action level as soon as practicable, but no later than 45 days after identifying the
leak, except as specified in paragraphs (e) and (f) of this section. Repair includes re-monitoring at the
monitoring location where the leak was identified according to the method specified in paragraph (c)(3)
of this section to verify that the measured concentration is below the applicable action level. Actions that
can be taken to achieve repair include but are not limited to:
Status: In compliance – The leak that was detected on April 16, 2024, was repaired by the Chevron
Refinery and re-monitored by HydroChem PSC on May 9, 2024.
63.654(d)(1)
Physical modifications to the leaking heat exchanger, such as welding the leak or replacing a tube;
63.654(d)(2)
Blocking the leaking tube within the heat exchanger;
63.654(d)(3)
Changing the pressure so that water flows into the process fluid;
63.654(d)(4)
Replacing the heat exchanger or heat exchanger bundle; or
63.654(d)(5)
Isolating, bypassing, or otherwise removing the leaking heat exchanger from service until it is otherwise
repaired.
Status: In compliance – The leak that was detected on April 16, 2024, was repaired by the Chevron
Refinery, within the allotted 45-day period. Cooling tower leaks are tracked in the maintenance
database Maximo.
7
63.654(e)
If the owner or operator detects a leak when monitoring a cooling tower return line under paragraph
(c)(1)(i) of this section, the owner or operator may conduct additional monitoring of each heat exchanger
or group of heat exchangers associated with the heat exchange system for which the leak was detected as
provided under paragraph (c)(1)(ii) of this section. If no leaks are detected when monitoring according to
the requirements of paragraph (c)(1)(ii) of this section, the heat exchange system is considered to meet the
repair requirements through re-monitoring of the heat exchange system as provided in paragraph (d) of
this section.
Status: N/A – No return line leaks were detected, during calendar years 2024, and calendar year
2025, to date.
63.654(f)
The owner or operator may delay the repair of a leaking heat exchanger when one of the conditions in
paragraph (f)(1) or (f)(2) of this section is met and the leak is less than the delay of repair action level
specified in paragraph (f)(3) of this section. The owner or operator must determine if a delay of repair is
necessary as soon as practicable, but no later than 45 days after first identifying the leak.
63.654(f)(1)
If the repair is technically infeasible without a shutdown and the total strippable hydrocarbon
concentration is initially and remains less than the delay of repair action level for all monthly monitoring
periods during the delay of repair, the owner or operator may delay repair until the next scheduled
shutdown of the heat exchange system. If, during subsequent monthly monitoring, the delay of repair
action level is exceeded, the owner or operator must repair the leak within 30 days of the monitoring
event in which the leak was equal to or exceeded the delay of repair action level.
63.654(f)(2)
If the necessary equipment, parts, or personnel are not available and the total strippable hydrocarbon
concentration is initially and remains less than the delay of repair action level for all monthly monitoring
periods during the delay of repair, the owner or operator may delay the repair for a maximum of 120
calendar days. The owner or operator must demonstrate that the necessary equipment, parts, or personnel
were not available. If, during subsequent monthly monitoring, the delay of repair action level is exceeded,
the owner or operator must repair the leak within 30 days of the monitoring event in which the leak was
equal to or exceeded the delay of repair action level.
63.654(f)(3)
The delay of repair action level is a total strippable hydrocarbon concentration (as methane) in the
stripping gas of 62 ppmv. The delay of repair action level is assessed as described in paragraph (f)(3)(i) or
(f)(3)(ii) of this section, as applicable.
63.654(f)(3)(i)
For once- through heat exchange systems for which the inlet water feed is monitored as described in
paragraph (c)(2)(ii) of this section, the delay of repair action level is exceeded if the difference in the
measurement value of the sample taken from a location specified in paragraph (c)(2)(i) of this section and
the measurement value of the corresponding sample taken from the location specified in paragraph
(c)(2)(ii) of this section equals or exceeds the delay of repair action level.
8
63.654(f)(3)(ii)
For all other heat exchange systems, the delay of repair action level is exceeded if a measurement value of
the sample taken from a location specified in either paragraphs (c)(1)(i), (c)(1)(ii), or (c)(2)(i) of this
section equals or exceeds the delay of repair action level.
Status: N/A – There was no delay of repair, regarding the April 16, 2024, leak.
63.654(g)
To delay the repair under paragraph (f) of this section, the owner or operator must record the information
in paragraphs (g)(1) through (4) of this section.
63.654(g)(1)
The reason(s) for delaying repair.
63.654(g)(2)
A schedule for completing the repair as soon as practical.
63.654(g)(3)
The date and concentration of the leak as first identified and the results of all subsequent monthly
monitoring events during the delay of repair.
63.654(g)(4)
An estimate of the potential strippable hydrocarbon emissions from the leaking heat exchange system or
heat exchanger for each required delay of repair monitoring interval following the procedures in
paragraphs (g)(4)(i) through (iv) of this section.
63.654(g)(4)(i)
Determine the leak concentration as specified in paragraph (c) of this section and convert the stripping gas
leak concentration (in ppmv as methane) to an equivalent liquid concentration, in parts per million by
weight (ppmw), using equation 7-1 from “Air Stripping Method (Modified El Paso Method) for
Determination of Volatile Organic Compound Emissions from Water Sources” Revision Number One,
dated January 2003, Sampling Procedures Manual, Appendix P: Cooling Tower Monitoring, prepared by
Texas Commission on Environmental Quality, January 31, 2003 (incorporated by reference—see § 63.14)
and the molecular weight of 16 grams per mole (g/mol) for methane.
63.654(g)(4)(ii)
Determine the mass flow rate of the cooling water at the monitoring location where the leak was detected.
If the monitoring location is an individual cooling tower riser, determine the total cooling water mass
flow rate to the cooling tower. Cooling water mass flow rates may be determined using direct
measurement, pump curves, heat balance calculations, or other engineering methods. Volumetric flow
measurements may be used and converted to mass flow rates using the density of water at the specific
monitoring location temperature or using the default density of water at 25 degrees Celsius, which is 997
kilograms per cubic meter or 8.32 pounds per gallon.
9
63.654(g)(4)(iii)
For delay of repair monitoring intervals prior to repair of the leak, calculate the potential strippable
hydrocarbon emissions for the leaking heat exchange system or heat exchanger for the monitoring interval
by multiplying the leak concentration in the cooling water, ppmw, determined in (g)(4)(i) of this section,
by the mass flow rate of the cooling water determined in (g) (4)(ii) of this section and by the duration of
the delay of repair monitoring interval. The duration of the delay of repair monitoring interval is the time
period starting at midnight on the day of the previous monitoring event or at midnight on the day the
repair would have had to be completed if the repair had not been delayed, whichever is later, and ending
at midnight of the day the of the current monitoring event.
63.654(g)(4)(iv)
For delay of repair monitoring intervals ending with a repaired leak, calculate the potential strippable
hydrocarbon emissions for the leaking heat exchange system or heat exchanger for the final delay of
repair monitoring interval by multiplying the duration of the final delay of repair monitoring interval by
the leak concentration and cooling water flow rates determined for the last monitoring event prior to the
re-monitoring event used to verify the leak was repaired. The duration of the final delay of repair
monitoring interval is the time period starting at midnight of the day of the last monitoring event prior to
remonitoring to verify the leak was repaired and ending at the time of the re-monitoring event that
verified that the leak was repaired. [74 FR page 55686, Oct. 28, 2009, as amended at 75 FR page 37731,
June 30, 2010; 78 FR page 37146, June 20, 2013]
Status: N/A – There was no delay of repair, regarding the April 16, 2024, leak.
40 CFR 61 Subpart FF - NESHAP for Benzene Waste Operations
61.340 Applicability
Status: In compliance – In October 2003, Chevron signed a Consent Decree with EPA which
obligated the source to reinstate control requirements for benzene waste. In addition, Subpart CC
requires Group 1 wastewater streams to comply with this subpart. Chevron has submitted TAB
reports which indicate that the Total Benzene Quantity (TBQ) has been below the 6.0 mega grams
per year (Mg/yr) compliance limit. Quarterly BWON reports are also submitted. The 2024 TAB
report, dated April 2, 2025, was received on April 7, 2025. The last Quarterly BWON report, for
the 4th quarter of 2024, was received on January 30, 2025.
61.342 Standards: General
Status: In compliance – This regulation applies. Chevron exceeds the 10 Mg/yr TAB threshold.
Chevron complied by the compliance date. Chevron is choosing to manage and treat the facility
under the alternative listed in 61.342(e). This alternative limit of uncontrolled benzene quantity in
waste to 6.0 Mg/yr and uses calculation procedures in 61.355(k).
61.344 Standards: Surface Impoundments
Status: In compliance – Chevron had been counting the lime pond as uncontrolled emissions.
However, the lime pond was associated with the old Alky Unit which has been removed. The lime
pond is currently only collecting rain water.
10
61.345 Standards: Containers
Status: In compliance – The waste storage/transportation and vacuum trucks used for onsite
transferring must comply with this subpart. All containers that hold waste are inspected weekly.
BWON weekly container inspection sheets are kept as hardcopies and are not considered to be part
of the SkyBridge LDAR database. Submerged fill is used to transfer waste from vacuum trucks to
waste containers. Method 21 is performed on larger containers (over 111 gallons) prior to shipping.
Barrels with covers are used for off-site disposal.
61.346 Standards: Individual Drain Systems
Status: In compliance – Emissions from the drain system and collection junction boxes are
controlled at the collection boxes by venting to the regenerative thermal oxidizer (RTO). Annual
LDAR is performed with a leak definition of 500 ppm, by the LDAR crew. The LDAR data is
entered into the SkyBridge database. See Subpart QQQ.
61.347 Standards: Oil water separators
Status: N/A – The Chevron refinery does not have an oil water separator. The oil and water
separation process is done by three surge or storage tanks (107, 108, 109), which control the flow of
water into the WWTP. These surge tanks are not regulated under this subpart.
61.348 Standards: Treatment Processes
Status: N/A – The source is meeting the 6.0 Mg/yr standard. Chevron is therefore not required to
treat benzene down to the 10-ppm level.
61.349 Standards: Closed vent systems and control devices
Status: In compliance – Chevron has refurbished and operates a regenerative thermal oxidizer
(RTO) as a control device. The RTO was originally approved under the AO issued December 16,
2005. The position of the bypass valve and temperature, of the RTO, are monitored. The bypass
valve is chained shut so no manual bypass by operators or automatic bypass can occur. Bypass
valve information such as RTO three-hour average for temperature is found in the Quarterly
BWON reports. If the temperature of the RTO is < 1,350 degrees F the bypass opens automatically.
61.350 Standards: Delay in repair
Status: In compliance – No delay of repairs has occurred since the last inspection conducted August
13-15, 2024.
61.352 Alternative standards for oil water separators
Status: N/A – See 61.347 Standards: Oil water separators.
61.353 Alternative means of emission limitation
Status: N/A
11
61.354 Monitoring of operations
Status: In compliance – A temperature monitoring device has been installed and provides real time
monitoring by way of Data Historian. The minimum setpoint is 1,350 degrees F. The RTO bypass
line is continuously monitored for valve positioning, temperature, and flow. The carbon canisters
are monitored weekly to determine if canister replacement is required.
61.355 Test methods, procedures, and compliance provisions
Status: In compliance – The TAB is determined annually in accordance with this section.
61.356 Recordkeeping requirements
Status: In compliance – Records were made available for review at time of inspection.
61.357 Reporting requirements
Status: In compliance – Quarterly BWON and Annual TAB reports have been submitted and
indicate compliance. Total uncontrolled benzene quantity during calendar year 2024 was 1.3 Mg/yr.
40 CFR 60 Subpart QQQ NSPS for Petroleum Refinery Wastewater Systems
60.690 Applicability
Status: In compliance – Chevron is currently complying with this subpart as a conservative
measure (more stringent than required).
60.692-2 Standards: Individual drain systems
Status: In compliance – Visual water seal inspections are performed and recorded monthly by
using the IntelaTrac database. This data base is not considered to be part of the SkyBridge LDAR
database. Drain repairs are tracked in the maintenance database Maximo. Semiannual Subpart
QQQ reports are submitted. The last Semiannual Subpart QQQ report for the second half of 2024,
was received February 25, 2025.
60.692-3 Oil water separators
Status: N/A – The Chevron refinery does not have an oil water separator.
60.692-5 Closed vent systems and control devices
Status: In compliance – See subpart CC and FF evaluations.
60.692-6 Delay in repair
Status: In compliance – No delay of repairs has occurred since the last inspection conducted August
13-15, 2024.
12
60.692-7 Delay of Compliance
Status: N/A – See 60.692-6 delay in repair.
60.697 Recordkeeping requirements
Status: In compliance – Records appeared to be maintained as required.
60.698 Reporting
Status: In compliance – Semiannual Subpart QQQ reports are submitted as required.
40 CFR 63 Subpart UUU – NESHAP for HAP for Petroleum Refineries: Catalytic Cracking Units;
Catalytic Reforming Units; and Sulfur Recovery Units
63.1561 Am I subject to this subpart?
Status: In compliance – Chevron is subject to this subpart because it is a major source of HAPs.
Process units are listed as the sources subject to the NESHAP. While the type of vents associated
with the process units are subject to the emission limits and standards.
63.1562 What parts of my plant are covered by this subpart?
Status: In compliance – Chevron’s FCCU, CRU, and two SRUs are sources subject to this rule. The
FCCU, CRU, and SRU Unit #1 are existing sources (commenced construction before September 11,
1998). SRU Unit #2 is a new source (commenced construction after September 11, 1998).
63.1563 When do I have to comply with this subpart?
Status: In compliance – Chevron had to comply no later than April 11, 2005, for existing sources
and no later than 150 days after start-up for SRU #2.
63.1564 What are my requirements for metal HAP emissions from FCCU?
Status: In compliance – This condition redirects to 40 CFR 60, Subpart J. 60.102a(1) requires a
particulate limit of 1.0 lb/1000 lbs of coke burn-off and is stack tested every three years.
Chevron stack tested the FCCU for PM2.5 on August 16, 2023, and for PM10 on December 19,
2023. Results were submitted to the DAQ. DAQ calculated results for PM were 0.7 lb/1000 lb coke
burn-off. The next PM stack test will be conducted in August 2026.
Source wide combined PM10 emissions stack testing is no longer conducted. The last source wide
PM10 stack testing was last conducted in 2017. See condition II.B.1.f of Main Refinery AO.
63. 1565 What are my requirements for organic HAP emissions from catalytic cracking units?
Status: In compliance – This condition is included in the Main Refinery Approval Order
DAQE-AN101190107-24 issued December 3, 2024, and in inspection memo 4 of 4.
13
63.1566 What are my requirements for organic HAP emission from catalytic reforming units?
Status: In compliance – Organic HAP limits only apply during initial catalyst depressurization and
catalyst purging operations [63.1562(a)(2)]. Chevron is choosing option 1 by venting emissions of
TOC to a flare that meets the control device requirements of 63.11(b). Flare sensors/cameras are
used to detect a pilot flame. Regeneration is the continuous type. Coke burn off happens once
roughly every 6 months. Initial compliance is achieved by venting to a flare and keeping visible
emission below a total of 5 minutes during any 2 consecutive hours. Photos of flare tips are taken
every 15 seconds and reviewed every six months. Flare photo records, for flares 1, 2, and 3, are kept
in electronic folders for review. Flare information can be found in the Semiannual MACT CC
report. The last Semiannual MACT Subpart CC Periodic report for the second half of 2024, was
received on March 25, 2025.
63.1567 What are my requirements for inorganic HAP emissions from CRU’s?
Status: In compliance – Chevron replaced the fixed bed absorber with an internal scrubber for
control of inorganic HAP. Chevron must measure and record the HCl during a regeneration cycle
using a colormetric tube sampling system. Draeger tubes were utilized to measure HCL during the
most recent regeneration on November 19, 2024. HCL Draeger tube sample results were all 0 ppm.
63.1568 What are my requirements for HAP emissions from SRU’s?
Status: N/A – Chevron is complying by using a SO2 CEM. These requirements are evaluated by
DAQ’s CEM specialist.
63.1569 What are my requirements for HAP emissions from bypass lines?
Status: N/A – SRU #1 and #2 have no bypass lines. They connect to the flare gas recovery system to
meet the requirements of this subpart. The Reformer CRU has a bypass line.
63.1570 What are my general requirements for complying with this subpart?
Status: In compliance – Chevron appeared to be in compliance with the non-opacity and opacity
standards at the time of this inspection. Instances in which a limit was not met including Startup
Shutdown Malfunction (SSM) appear to be reported in accordance with this condition. Deviations
are evaluated on a case-by-case basis. Semiannual MACT Subpart UUU Compliance reports are
submitted as required. The last report was received on January 31, 2025, for the second half of
2024.
63.1571 How and when do I conduct a performance test or other initial compliance demonstration?
Status: In compliance – Performance tests have been conducted. Stack tests are not required for the
SRUs or CRU (MACT UUU). Stack test are only conducted for the FCCU.
63.1572 What are my monitoring installation operation, and maintenance requirements?
Status: Not evaluated – This is a CEM requirement and CEM regulations are evaluated by DAQ’s
CEM specialist.
14
63.1573 What are my monitoring alternatives?
Status: N/A
63.1574 What notifications must I submit and when?
Status: In compliance – The notification to construct or reconstruct is not applicable. The
notification of compliance status (NCS) for the FCCU and SRU was submitted on September 12,
2005. The OMMP was revised on January 27, 2025, for the FCCU. The SRUs and CRU are
currently in the review process. The NCS for the CRU was submitted on March 8, 2006. A new
NCS for the #1 SRU was submitted on October 10, 2006. The #2 SRU NCS report was submitted on
February 15, 2011. The OMMP was included with each NCS report. Performance test notifications
were submitted on time and are in the source file.
What reports must I submit and when?
Status: In compliance – Periodic reports for Subpart UUU were submitted semi-annually. The
reports covered the required information. Deviations were reported in accordance with this section.
Semiannual MACT Subpart UUU Compliance reports are submitted as required. The last report
was received on January 31, 2025, for the second half of 2024.
§ 63.1575 What reports must I submit and when?
Status: In compliance – Semiannual reports have been submitted as required. The majority of
reporting requirements are contained in the State Electronic Data Report (SEDR), which is
reviewed by the CEM specialist.
63.1575(d) For each deviation from an emission limitation and for each deviation from the requirements
for work practice standards that occurs at an affected source where you are not using a continuous opacity
monitoring system or a continuous emission monitoring system to comply with the emission limitation or
work practice standard in this subpart, the compliance report must contain the information in paragraphs
(c)(1) through (3) of this section and the information in paragraphs (d)(1) through (3) of this section.
63.1575(d)(1) The total operating time of each affected source during the reporting period.
63.1575(d)(2) Information on the number, duration, and cause of deviations (including unknown cause, if
applicable), as applicable, and the corrective action taken.
63.1575(d)(3) Information on the number, duration, and cause for monitor downtime incidents (including
unknown cause, if applicable, other than downtime associated with zero and span and other daily
calibration checks).
Status: In compliance – Items required in (1)-(3) above are referenced in the CEMS reports.
63.1575(f) You also must include the information required in paragraphs (f)(1) through (2) of this section
in each compliance report, if applicable.
15
63.1575(f)(1) A copy of any performance test done during the reporting period on any affected unit. The
report may be included in the next semiannual report. The copy must include a complete report for each
test method used for a particular kind of emission point tested. For additional tests performed for a similar
emission point using the same method, you must submit the results and any other information required,
but a complete test report is not required. A complete test report contains a brief process description; a
simplified flow diagram showing affected processes, control equipment, and sampling point locations;
sampling site data; description of sampling and analysis procedures and any modifications to standard
procedures; quality assurance procedures; record of operating conditions during the test; record of
preparation of standards; record of calibrations; raw data sheets for field sampling; raw data sheets for
field and laboratory analyses; documentation of calculations; and any other information required by the
test method.
63.1575(f)(2) Any requested change in the applicability of an emission standard (e.g., you want to change
from the PM standard to the Ni standard for catalytic cracking units or from the HCl concentration
standard to percent reduction for catalytic reforming units) in your periodic report. You must include all
information and data necessary to demonstrate compliance with the new emission standard selected and
any other associated requirements.
Status: In compliance – Other information as required by this subsection is listed in the
Semiannual MACT Subpart UUU Compliance reports. The last report was received on January 31,
2025, for the second half of 2024.
63.1575(g) You may submit reports required by other regulations in place of or as part of the compliance
report if they contain the required information.
Status: Not evaluated – The FCCU, SRU #1, and SRU #2, are included in the CEMS reports. This
data is reviewed by the DAQ CEM specialist.
63.1575(h) The reporting requirements in paragraphs (h)(1) and (2) of this section apply to startups,
shutdowns, and malfunctions:
63.1575(h)(1) When actions taken to respond are consistent with the plan, you are not required to report
these events in the semiannual compliance report and the reporting requirements in §§63.6(e)(3)(iii) and
63.10(d)(5) do not apply.
63.1575(h)(2) When actions taken to respond are not consistent with the plan, you must report these
events and the response taken in the semiannual compliance report. In this case, the reporting
requirements in §§63.6(e)(3)(iv) and 63.10(d)(5) do not apply.
Status: N/A
63. 1576 What records must I keep, in what form, and for how long?
Status: In compliance – The required records were kept and made available for review at time of
the inspection. All Continuous Parameter Monitors (CPMS) records are maintained in real time by
Data Historian.
16
40 CFR 63 Subpart DDDDD
63.7540(a)(10) - If your boiler or process heater has a heat input capacity of 10 million Btu per hour or
greater, you must conduct an annual tune-up of the boiler or process heater to demonstrate continuous
compliance as specified in paragraphs (a)(10)(i) through (vi) of this section.
Status: In compliance – Chevron completed annual boiler and furnace tune-ups in calendar year
2024. The Annual MACT Subpart DDDDD Compliance report lists the most recent boiler tune-up
dates. The 2025 report is due at the end of January 2026. The 2024 report, dated January 27, 2025,
was received on January 31, 2025.
63.7545(e) – Initial tune-up and energy assessment.
Status: In compliance – Chevron completed the required initial tune-ups for all of the boilers and
process heaters covered by this subpart according to 63.7540(a)(10)(i) and has had an energy
assessment, dated December 2015, performed according to 63.7530(e) (See NOC report received
March 24, 2016, in source file).
63.7550 – Reports.
Status: In compliance – Chevron is required to submit the Annual MACT Subpart DDDDD
Compliance reports detailing boiler tune-ups. The reports are submitted as required. The last
report was received on January 31, 2025.
EMISSION INVENTORY: Chevron Product Company’s 2024 annual emission
inventory was received, by the DAQ, on April 9, 2025.
PREVIOUS ENFORCEMENT
ACTIONS: None within the previous five years.
17
COMPLIANCE STATUS &
RECOMMENDATIONS: Chevron Products Company should be considered to be
in compliance with the WWTP requirements under 40
CFR 63 Subpart FF and 40 CFR 60 Subpart QQQ. Also,
FCCU, CRU, and SRUs requirements under 40 CFR
63Subpart UUU. Finally, boiler requirements under
Subpart DDDD at time of the inspection.
HPV STATUS: N/A
COMPLIANCE ASSISTANCE: None
RECOMMENDATION FOR
NEXT INSPECTION: Inspect as usual.
ATTACHMENT: VEO Form