shell c l. p., m saraland petroleum refining facility m …

SHELL CHEMICAL L. P., MOBILE SITE

SARALAND PETROLEUM REFINING FACILITY

MOBILE COUNTY, ALABAMA

FACILITY NO.: 503-4003

MAJOR SOURCE OPERATING PERMIT

THIRD TITLE V RENEWAL DRAFT AUGUST 5, 2021

(THIS PAGE LEFT BLANK INTENTIONALLY)

SHELL CHEMICAL L. P., MOBILE SITE

SARALAND PETROLEUM REFINING FACILITY MOBILE COUNTY, ALABAMA

FACILITY NO.: 503-4003

_____________________________________________________________________________

STATEMENT OF BASIS

The proposed second Title V Major Source Operating Permit renewal is issued under the provisions of

ADEM Admin. Code R. 335-3-16. The above named applicant has requested authorization to perform the

work or operate the facility shown on the application and drawings, plans, and other documents attached

hereto or on file with the Air Division of Alabama Department of Environmental Management, in

accordance with the terms and conditions of this permit.

Shell Chemical L. P., Mobile Site (Shell) was issued the existing MSOP on January 8, 2014, with expiration

date of January 7, 2019, for the Saraland Petroleum Refinery located at 400 Industrial Parkway Extension,

East Saraland, AL. Per ADEM Rule 335-3-16-.12(2), an application for permit renewal shall be submitted

at least six (6) months, but not more that eighteen (18) months, before the date of expiration of the

permit. The renewal application was received on July 3, 2018. The proposed MSOP will expire five (5)

years from the date of issuance of the Renewal.

Shell Chemical L.P., Mobile Site

Saraland Petroleum Refinery

Facility No. 503-4003

STATEMENT OF BASIS





STATEMENT OF BASIS

Page | 1

PROCESS DESCRIPTION

Crude oil and condensate are supplied to the 85,000 barrel per day refinery by truck, pipeline and barge and

is routed to a series of storage tanks prior to being refined. Crude charge is first routed through inlet desalters

and heaters on its way to one of two atmospheric distillation towers where it is distilled into light straight run

naphtha, heavy naphtha, kerosene, diesel and atmospheric tower bottoms. The light straight run naphtha,

heavy naphtha, kerosene, diesel and atmospheric tower bottoms streams are then sent to storage and to

further refining and/or treating and/or product blending. Water that originates in the steam stripping part of

the atmospheric distillation unit and the desalters becomes part of the atmospheric tower overhead stream

that is then cooled allowing both water and light straight run naphtha to condense. After separation from the

light straight run naphtha, the water is sent to the wastewater treatment plant.

Both atmospheric tower bottom streams are combined and are then reheated with waste heat exchangers

and a process heater prior to entry into the vacuum distillation tower. In the vacuum distillation tower, the

atmospheric tower bottoms are distilled while under a vacuum pressure into overhead gases, light vacuum

gas oils, heavy vacuum gas oils, and vacuum tower bottoms. The light gas oils and heavy gas oil are sent to

storage and/or further refining and/or treating and/or product blending, while the vacuum bottoms are sent

to storage and sales. Water that originates in the steam ejecters (used to create the vacuum) along with the

overhead gases is carried overhead and is condensed, separated from the gas oils and vent gas and is sent to

the wastewater treatment plant.

The light straight run naphtha streams leave the atmospheric towers and are combined and are then sent to

the debutanizer. The debutanizer overhead gases are sent to LPG treating where the hydrogen sulfide and

mercaptans are removed from the LPG gas. The sweetened LPG gas is then sent to the LPG fractionation unit

to be fractionated into various LPG products. The debutanizer bottoms are sent to the merox unit to convert

mercaptans into disulfides. The debutanizer bottoms are then sent to the naphtha splitter and isomerization

unit to attain a light olefin feed product.

The heavy naphtha streams leave the atmospheric towers and are combined and are sent to one of two

hydrodesulfurization units to remove the sulfur and nitrogen compounds along with trace metals. The

sweetened heavy naphtha then proceeds to one of two reforming units where it is converted to a higher

octane reformate. Both reformate streams are then combined and are sent to the reformate splitter to reduce

the benzene content of the finished gasoline product. Reformate then goes to gasoline blending for the

blending of the three gasoline fuel products. The overhead reformer gases go to facility fuel or LPG

fractionation.

The kerosene streams leave the atmospheric towers and are combined and are sent to either the bender

treating unit or the hydrotreating unit to remove sulfur compounds and to produce a sweetened jet fuel

product.

The diesel streams leave the atmospheric towers and are combined and are sent to the hydrotreating unit to

remove sulfur compounds and to produce a sweetened diesel fuel and/or heavy olefin product.

Sour off gases from the hydrodesulfurization unit, the light naphtha debutanizing unit, the hydrotreating unit,

deethanizing unit and isomerization unit are combined and sent to the sweetening unit to remove hydrogen

sulfide and provide a sweetened fuel gas. The acid gas leaving the sweetening unit regeneration tower is sent

to the sulfur recovery unit where the hydrogen sulfide is converted to an elemental sulfur product.

Process water is captured from various parts of the refinery and is transferred via underground pipes to a

collection sump and into inlet storage vessels for the wastewater treatment plant. The water is taken from

the inlet storage and is sent to an oil-water separator that removes the oil from the wastewater. The oil is




STATEMENT OF BASIS

Page | 2

sent to storage in the slop oil tank. The wastewater proceeds through the wastewater treatment plant prior

to being stored and disposed of in the city sewer system.

Heat is provided by fourteen (14) process heaters with a total heat input capacity of 964 MMBtu/Hour and

three (3) steam boilers with a total heat input capacity of 180 MMBtu/Hour along with numerous heat

recovery exchangers associated various processes.

Crude feed, intermediate and final product storage is provided via forty-five (45) storage tanks varying in size

from 210,000 gallons to 5,250,000 gallons of storage.

The refinery has a barge loading and unloading dock and a truck loading rack.

This facility is also equipped with two flares. One, called the OFH Flare, is used only when the Olefin Feed

Heating [OFH] Unit is being purged. The other, called the Low Pressure Refinery Flare [or Process Flare], is a

continuous flare that may combust any of the gases routinely produced in the refining process.




STATEMENT OF BASIS

Page | 3

FACILITY PERMITTING HISTORY

The initial permit applications for the 30,000 barrels per day (BPD) petroleum refinery were submitted on June

13, 1974 by the Louisiana Land and Exploration (LL&E) Company. Construction permits were issued on

October 1, 1974 for permit Nos. 503-4003-0001 through 0004 and 8401 through 8409. Temporary operating

permits were issued on November 6, 1975 and December 9, 1975. The official startup date for the plant was

December 25, 1975. Operating permits were issued on May 24, 1976 and July 1, 1976. The initial Major

Source Operating Permit (MSOP) was issued on January 9, 2002 and subsequent renewals were issued on June

22, 2007 and January 8, 2014.

Shell is currently operating under a MSOP and under the terms and conditions specified in the consent decree

No. 10-cv-01042 issued by EPA. Since the issuance of the most recent MSOP, the following permitting actions

have occurred:

PERMITTING

ACTION ACTION/ISSUANCE DATE SUMMARY OF PERMIT ACTION

Non-App Letter June 23, 2021

A no permit determination letter was issued for the installation of low NOx

burners on the existing 37 MMBtu/hr Vacuum Tower Pre-Heater (290-50-

8010). The unit’s heat input increased from 37 MMBtu/hr to 48 MMBtu/hr

and its source ID was changed to 220-50-8010 at the facility’s request.

Air Permit No.

X097

March 11, 2019

Permit issued for modifications made to both the Refinery Flare (Low

Pressure Flare) [Source ID No. 700-50-0100] and the Olefin Feed

Hydrotreater (OFH) Flare (High Pressure Flare) [Source ID No. 700-10-1002]

to demonstrate compliance with 40 CFR 60 Subpart Ja [NSPS Ja] instead of

NSPS J and install appropriate monitors; Applied MACT CC requirements to

the flares as a result of the RTR promulgated in December 2015.

Air Permit Nos.

X098-99

Permits were issued to demonstrate compliance with newly promulgated

permit requirements under 40 CFR 63, Subpart CC [MACT CC, Refinery

MACT I] for fenceline monitoring of benzene emissions and for

maintenance vents

Non-App Letter November 15, 2018

A no permit determination letter was issued for the 33,838 gallon, vertical

fixed roof, storage vessel [designated as T-114] installed to store

Naphthenic Spent Caustic.

Air Permit No.

X096 August 20, 2018

Permit issued for the installation of a low NOX burner on the existing 85

MMBtu/hr, natural gas fired, No. 3 steam boiler [Source ID No. 740-50-

1003].

Air Permit No.

X095 February 14, 2018

Permit issued for the installation of low NOx burners on the 50 MMBtu/hr,

Natural Gas Fired, No. 2 Steam Boiler [Source ID No. 740-50-1002] and the

175 MMBtu/hr, Natural Gas Fired, No. 2 Crude Heater [Source ID No. 210-

50-1030] to comply with the requirement of the consent decree to

install qualifying controls on specific heaters and boilers with a rating

greater than 40 MMBtu/hr.

Extension

Granted April 25, 2017

An extension request was granted to allow time to comply with the

requirements of MACT CC for maintenance vents.

Non-App Letter January 30, 2017

A no permit determination letter was issued for use of a temporary boiler

to supplement the steam system while boiler maintenance was being

performed; unit did not remain onsite for greater than six months.




STATEMENT OF BASIS

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PERMITTING

ACTION ACTION/ISSUANCE DATE SUMMARY OF PERMIT ACTION

Non-App Letter October 27, 2017

A no permit determination letter was issued for the piping installation for

marine loading of light olefin feed (LOF) at the existing North vapor

recovery unit (VRU)

EPA Approved

AMP October 27, 2015

EPA approved an alternative monitoring plan (AMP) for the flares’

continuous emissions monitoring systems (CEMS) for compliance with

§60.103a(h) of 40 CFR 60 Subpart Ja [NSPS Ja].




STATEMENT OF BASIS

Page | 5

NOTABLE CHANGES

During this renewal, several notable changes will be made to the renewal in order to demonstrate compliance

with new and/or modified federal and state requirements and recently permitted emission sources:

Boilers and Process Heaters Changes

Air Permit No. 503-4003-X095 will be incorporated into the MSOP during this renewal. This permit was issued

for the No. 2 Crude Heater and the No. 2. Boiler on February 14, 2014 after the issuance of the last renewal.

This permit was issued to demonstrate compliance with the consent decree and will remain in the permit after

termination of the consent decree.

The exiting 24.00 MMBtu/hr OFH Charge Heater [290-50-8020] was re-designated as the No. 1 Reformer

Stabilizer Reboiler [source ID 130-50-8020]. This change will be incorporated into the section for Emission

Sources Construct Prior to and Including 1981 Expansion and the section for Boiler and Process Heaters in the

permit.

Per the consent decree, several units were equipped with low nitrogen oxide (NOX) burner control technology

to reduce NOX emissions. Air Permit Nos. X095 and X096 were issued to include the control requirements for

NOX emissions. The requirements of these permits will be incorporated into the MSOP during this renewal.

In June 2021, Shell requested to add low NOX burners to the existing 37 MMBtu/hr Vacuum Tower Pre-heater

(290-50-8010). The addition of the burners on the unit is not expected to cause any changes to the existing

regulatory requirements for the heater and since the addition of control technology was not required by the

existing consent decree, a non-applicability determination letter was sent on June 23, 2021. The heat input

for the heater was increased from 37 MMBtu/hr to 48 MMBtu/hr, PM emissions were adjusted for the new

heat input, and the unit’s source ID in the permit will be changed from 290-50-8010 to 220-50-8010.

The heat input for several of the heaters were updated to match the heat inputs provided in the current MSOP

permit application.

Emergency Engine Changes

Updates will be made to the engine horsepower (HP) rating for the Sprint Emergency Generator Engine. The

unit was inadvertently identified as a 79 HP, compression ignition (CI) (diesel fired), generator engine instead

of a 67 HP engine. This change will result in changes to the emission limits in the permit; however, it will not

affects the unit’s applicability to any regulations.

Diesel fired engines are required to comply with smoke emission standards found in §89.113(a) during periods

acceleration modes, lugging mode, and during peaks in either acceleration mode or lugging mode. These

requirements apply only during those times; however, the state opacity standards found in ADEM Admin. r.

335-3-4-.01(a) and (b) will apply at all other times. References to the state opacity standards were previously

omitted; however, they will be incorporated in the MSOP during this renewal.

Facility Flare Changes

On June 15, 2016, the Department issued Consent Order No. 16-066-CAP to Shell for failure to comply with

40 CFR 60 Subpart Ja [NSPS Ja] after it was determined that the OFH High Pressure Flare had been modified

per NSPS Ja due to ties-ins made to the flare. Compliance with the subpart was required to be met by

November 11, 2015; however, Shell was not in compliance by the effective dates. A compliance schedule was

developed; however, no permitting action was completed to change the applicability for the OFH heater from

NSPS J to NSPS Ja.




STATEMENT OF BASIS

Page | 6

During this renewal, the sections for the flares will be combined into one section since both flares are now

subject to the requirements of NSPS Ja and to the new requirements for flares (discussed in further detail

below) applicable to 40 CFR 63 Subpart CC [MACT CC].

To comply with the hydrogen sulfide (H2S) concentration requirements under §60.103a(h) of NSPS Ja for both

Flares, Shell requested to utilize an alternative monitoring plan (AMP) as allowed per §60.103a(j) because of

the high concentration of H2S in the gas stream and the potential threat to Shell employees during audits. The

AMP was approved by EPA on October 27, 2015 (see approval letter found in Appendix C of the permit

application). Reference to the AMP will be incorporated into the MSOP as applicable during this renewal.

Shell uses a H2S monitor to comply with §60.103a(h), and they also use a total reduced sulfur (TRS) monitor

to comply with the sulfur monitoring requirement specified in §60.107a(e).

Storage Vessels Changes

There are no storage vessels that have requirements under 40 CFR 60 Subpart K [NSPS K]due to overlap with

MACT CC; however, the storage vessels are still subject to NSPS K; therefore, the section for storage vessels

subject to NSPS K will remain in the permit. Also these tanks are subject to the volatile organic compound

cumulative emissions limit for sources constructed during and prior to the 1981 Expansion.

The non-app issued for the 33,838 gallon T-114 tank will be added to the storage vessel section of the permit

to demonstrate compliance with MACT CC for Group 2 storage vessel. Also, the T-211 tank was incorrectly

designated as a Group 2 storage vessel instead of a Group 1 storage vessel in the current permit. This storage

vessel will be subject to the requirements under MACT CC instead of 40 CFR 60, Subpart Kb [NSPS Kb].

After April 29, 2016, applicability with 40 CFR 63 Subpart G [NESHAP G] as specified in §63.646 of MACT for

storage vessel shall no longer be met to comply with MACT CC (as discussed below). References to NESHAP

G will be removed from the permit for storage vessels using NESHAP G to comply with MACT CC.

Fugitive Equipment Leak Changes

Shell is currently subject to the requirements of NSPS GGG per the requirements of the consent decree;

however, during the last renewal, requirements for MACT CC were incorrectly included in the permit. Shell is

only required to comply with NSPS GGG for existing sources. Therefore, compliance with NSPS GGG would

satisfy the requirements of MACT CC, if necessary, as well as the consent decree.

Compliance Assurance Monitoring (CAM) Exemptions

Compliance Assurance Monitoring (CAM) requirements for the flares [NSPS Ja and MACT CC], sulfur recovery

unit with thermal oxidizer [MACT UUU], and gasoline loading rack [MACT UUU] will be removed and replaced

with monitoring requirements specified under the applicable New Source Performance Standards (NSPS) or

Maximum Achievable Control Technology (MACT) Standards. Per the exemption under §64.2(b)(1)(i) of 40

CFR 64, emission limitations or standards proposed after November 15, 1990 pursuant to section 111 or 112

of the Act are exempt from the requirements of CAM. References to CAM plans for the units specified above

will be removed from the permit during this renewal.

Petroleum Refinery Sector Rules (RSR) (including 40 CFR 63 Subpart CC [Refinery MACT I|MACT CC] and 40

CFR 63 Subpart UUU [Refinery MACT II|MACT UUU]) Changes

In December 2015, EPA issued amendments to the RSR because a Risk and Technology Review (RTR) was

conducted to evaluate these subparts. The RTR resulted in the following:

• New emission control for refinery storage tanks under MACT CC and for catalytic reforming units

(CRUs) under MACT UUU.




STATEMENT OF BASIS

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• Work practice standards to reduce emissions from atmospheric pressure relief devices and flares.

• Continuous monitoring of benzene (BZ) emissions through fenceline monitoring.

• The removal of start-up, shutdown, and malfunction (SSM) exemptions from emission limits for

uncontrolled releases.

The final rules became effective on February 1, 2016. Following promulgation of these rules, EPA received

and addressed petitions for reconsideration, and a final rule was issued on January 14, 2020.

Changes/Updates to 40 CFR 63 Subpart UUU[Refinery MACT 2/MACT UUU]

Bypass Lines for Catalytic Reforming Unit (CRU)/Sulfur Recovery Unit (SRU)

The startup, shutdown, malfunction (SSM) plan requirements were removed from 40 CFR 63 are Subpart UUU

[MACT UUU/ Refinery MACT UUU] for each affected source. Per Table 44 of 40 CFR 63 Subpart MACT UUU,

the SSM plan requirements under §63.6(e)(3) of Subpart A and the general duty requirement to minimize

emissions specified in §63.6(e)(1)(i) of Subpart A do not apply to units subject to MACT UUU. Reference to

these requirements will be removed from the permit during this renewal.

Revisions to the requirements specified in §63.1569 of MACT UUU for bypass lines on CRU and SRU vents will

be incorporated into the renewal permit.

Sulfur Recovery Unit (SRU)

The process vents associated with the SRU are required to meet operating limits and new work practice

standards to comply with MACT UUU. This subpart now requires that the SRU meets applicable operating

limits, prepare an operation, maintenance, and monitoring plan, to be operated at all times according to the

procedures in that plan, and it requires Shell to comply with one of three work practice standards options

provided during periods of startup and shutdown. These requirements will be added to the permit during this

renewal, and they will be addressed in detail in the unit specific section of this document for the SRU.

Changes/Updates to 40 CFR 63 Subpart CC [Refinery MACT 1/MACT CC]

After January 30, 2019, the requirements under MACT CC for flares at petroleum refineries must meet the

requirements of §63.670 and the monitoring requirements under §63.671 instead of those required in §60.18

of Subpart and/or §63.11 of Subpart A. These requirements were included in Air Permit No. X097, and they

will now be incorporated into the renewal permit.

The requirements for Fenceline Monitoring as specified in §63.658 of MACT CC were included in Air Permit

No. X098 and will be incorporated into the renewal permit.

The newly promulgated requirements for maintenance vents under miscellaneous process vents were

permitted in Air Permit No. X099. These requirements for maintenance vents will be incorporated as a new

section in the renewal permit and as specified in §63.643 of MACT CC since Shell is not equipped with Group

1 miscellaneous process vents.

The new requirements for Group 1 storage vessels found in §63.660 of MACT CC were added to the renewal

permit after the compliance dates in §63.640(h) of MACT CC. After the compliance dates, the requirements

found in §63.646 of MACT CC will no longer apply to storage vessels subject to MACT CC. Shell was required

to be in compliance with this subpart by April 29, 2016, except as allowed. The entire section of the current

MSOP has been rewritten to incorporate the new requirements for storage vessels under §63.660 of MACT

CC. Also Appendix E: Monitoring for Storage Vessels Handling HAPs will be removed from this permit during

the renewal because the requirements of in this appendix are for storage vessels subject to §63.646.




STATEMENT OF BASIS

Page | 8

For storage vessels that are subject to §63.660 of MACT CC either due to overlap with other storage vessel

regulations or by electing to comply with MACT CC, the requirements of 40 CFR 63 Subpart WW will be met

to demonstrate compliance with MACT CC. Shell has to the option to also utilize 40 CFR 63 Subpart SS as

allowed. Storage vessels that have become subject to the requirements of §63.660 will be incorporated into

the applicable section of the permit.

SHELL CHEMICAL L.P., MOBILE SITE

SARALAND PETROLEUM REFINERY

FACILITY NO. 503-4003

STATEMENT OF BASIS

Page | 9

FACILITY-WIDE EMISSION REQUIREMENTS

DESCRIPTION POLLUTANT EMISSION

LIMIT REGULATIONS

Petroleum Production Facility that handles gas

or refinery gas containing 0.10 grains of

H2S/scf

H2S Burn gas

20 ppbv offsite

Rule 335-3-5-.03(1)

Rule 335-3-5-.03(2)

Stationary Sources Opacity No more than one 6 min

avg. > 20%

AND

No 6 min avg. > 40%

Rule 335-3-4-.01(1)(a)

Rule 335-3-4-.01(1)(b)

Process unit turnaround at petroleum refining

sources

VOC Depressurization venting of

the process unit or vessel to

a vapor recovery system,

flare or firebox

AND

No emissions of VOC’s from a

process unit or vessel until its

internal pressure is 136 kPa

(19.6 psia) or less

Rule 335-3-6-.08(2) and (4)

Heaters, barge loading dock, truck loading

rack, storage vessels and process unit

equipment which were constructed prior to

and during the 1981 expansion

VOC < 1,781 tons per 12

consecutive months

Rule 335-3-14-.05(3)

[Non-attainment Avoidance]

The plant’s applicability to the state and federal regulations would be discussed in the following section.

STATE REGULATIONS

Applicability:

ADEM Admin. Code R. 335-3-4-.01(1)(a) and (b), “Visible Emissions” for Control of Particulate Emissions

These regulations control particulate emissions by restricting visible emissions from stationary sources.

These regulations would be applicable to the process heaters and boilers, engines, and the thermal oxidizer.

The specific monitoring and recordkeeping requirements shall be discussed in the individual sections. Flares

are not subject to this regulation since they are each subject to the federal opacity standards specified in

§63.670 and §63.671 of MACT CC.

EMISSION STANDARDS:

ADEM Admin. Code R. 335-3-4-.01(1) (a) states that except for one 6-minute period during any 60-minute

periods, stationary emission sources shall not discharge into the atmosphere particulate that results in an

opacity greater than 20%, as determined by a 6-minute average.

ADEM Admin. Code R. 335-3-4-.01(1) (b) states that at no time shall a stationary emission source discharge

into the atmosphere particulate that results in an opacity greater than 40%, as determined by a six minute

average.




STATEMENT OF BASIS

Page | 10

COMPLIANCE AND PERFORMANCE TEST METHODS AND PROCEDURES:

Provided that visible emissions in excess of the opacity standards are observed from a stationary emissions

source, a visible emissions observation (VEO) shall be conducted using the methods specified in EPA Method

9 or Method 22.

EMISSION MONITORING:

Opacity monitoring shall be complied with as specified in the individual emission source section.

RECORDKEEPING AND REPORTING REQUIREMENTS:

A record of each visible emissions observation conducted shall be maintained.

Applicability:

ADEM Admin. Code R. 335-3-5-.01(5), “Gas Sulfur Concentration” from Petroleum Refineries

This regulation applies to petroleum refineries.

EMISSION STANDARDS:

This regulation sets a sulfur concentration limit of 150 ppmv for each refinery gas stream to be combusted.

However, compliance with 40 CFR 60 Subpart J and/or 40 CFR 60 Subpart Ja will satisfy this regulation.


These procedures will be the same as those specified in 40 CFR 60 Subpart J and/ Subpart Ja.

Emission Monitoring:

Monitoring procedures will be the same as those specified in 40 CFR 60 Subpart J and/ Subpart Ja.

Recordkeeping and Reporting Requirements:

The records will be the same as those specified in 40 CFR 60 Subpart J and/ Subpart Ja.

Applicability:

ADEM Admin. Code r. 335-3-5-.03(1) and (2), “Petroleum Production”

ADEM Admin. Code r. 335-3-5-.03(1) applies to the control of sulfur compound emissions from each

petroleum production facility that handles gas or refinery gas that contains more than 0.10 grains of hydrogen

sulfide (H2S) per standard cubic foot (scf) (~160 ppmv).

ADEM Admin. Code r. 335-3-5-.03(1) states that no person shall cause or permit the emission of a process

gas stream containing more than 160 ppmv into the atmosphere unless it is properly burned to maintain the

ground level concentration of H2S at less than twenty (20) parts per billion beyond plant property limits,

average over a thirty (30) minute period.

The Saraland Refinery would handle sour gas that contains 0.10 grain of H2S/scf or more; therefore, the facility

would be subject to the applicable requirements of these regulations. Compliance with these regulations

shall be met by complying with the 40 CFR 60 subpart J for the process heaters, and boilers, complying with

40 CFR 60 subpart Ja for the flares, and complying with consent decree (CD) No. 10-cv-01042. The specific

requirements for each emissions source will be discussed in the individual sections.




STATEMENT OF BASIS

Page | 11

Applicability:

ADEM Admin. Code r. 335-3-6-.08(2) and (4) “Petroleum Refinery Sources”

This regulation is applicable to process unit turnaround at petroleum refining sources. A turnaround is a

procedure to shut a refinery unit down to perform necessary maintenance and repair work and placing the

unit back into service. During turnarounds, a procedure for depressurization venting of the process unit or

vessel to a vapor recovery system, flare or firebox shall be maintained. There shall be no emissions of VOC’s

from a process unit or vessel until its internal pressure is 136 kPa (19.6 psia) or less. Compliance with the

requirements of this subpart shall be met by compliance with MACT CC for the gasoline vapor recovery

system, flare, and thermal oxidizer per §63.640(q).

Applicability:

ADEM Admin. Code R. 335-3-6-.09, “Pumps & Compressors” at Petroleum Refineries in Mobile County

This regulation applies to pumps and compressors located at petroleum refineries located in Mobile County.

However, compliance with the federal Leak Detection and Repair [LDAR] standards in 40 CFR 63 Subpart CC

and/or 40 CFR 60 Subpart GGG will satisfy this regulation per §63.640(q).

EMISSION STANDARDS:

Hydrocarbon vapors from pump and compressor seals are to be captured and controlled. The federal LDAR

regulations contain the same requirement.


The test methods specified in the federal LDAR regulations should be used.


Monitoring procedures will be the same as those specified in the federal LDAR regulations.


The records will be the same as those specified in the federal LDAR regulations.

Applicability:

ADEM Admin. Code r. 335-3-14-.04 “Prevention of Significant Deterioration (PSD) Permitting”

Temporary operating permits for the boilers and heaters at the Saraland Refinery were issued on November

6, 1975, which was prior to PSD regulations being promulgated on June 19, 1978. However, a PSD application

was submitted for the refinery on August 7, 1978 for the addition of several emissions sources at the facility

(this project was referred to as the 1979 expansion). According to PSD regulations, a petroleum refinery is

listed as one of the 28 source categories found under this regulation. The major source threshold for criteria

pollutants from one of the 28 source categories would be 100 tons per year (TPY). To comply with the PSD

requirements, best available control technology (BACT) limits were placed on several process heaters and

boilers for nitrogen oxide (NOX) emissions.

A second expansion of the refinery occurred in 1981. A sulfur recovery plant, which is also one of the 28

source categories, was added to the refinery during this expansion. The 1981 expansion included a PSD

review for sulfur dioxide (SO2) and NOX emissions since the emissions from this project for both pollutants

were greater than the 40 TPY “de minims” levels under this subpart.

To comply with BACT limits for NOX emissions, the boilers and process heaters included in this expansion

were equipped with low NOX burners. To comply with the BACT limits for SO2 emissions from the proposed

process heaters and boilers during the expansion, the heat input for these units were limited to 1.2 Lbs




STATEMENT OF BASIS

Page | 12

SO2/MMBtu. This limit was achieved by burning a combination of refinery gas at 0.1 grains H2S/dscf (~160

ppmv) and No. 6 fuel oil with a maximum sulfur content of 3.5 mol% and maintaining a record of the volume

of fuel burned in each of the units. However, since the boilers and heaters are now subject to more stringent

standards in 40 CFR 60 subpart J [NSPS J] for fuel gas combustion devices, compliance with NSPS J

demonstrates compliance with the SO2 BACT limit.

Compliance with the SO2 limit is also met by meeting the requirements of consent decree (CD) No. 10-cv-

01042 which is later discussed in the individual sections. BACT SO2 emission limits for the sulfur recovery

plant installed during this expansion were met by complying with the requirements of NSPS J for sulfur

recovery plants with a design capacity greater than 50 long tons per day of sulfur and installing a tail gas

treatment unit on the sulfur recovery unit.

To avoid a PSD review, several of the boilers and heaters have anti-PSD NOX and carbon monoxide (CO) limits

placed on them to maintain their emissions below 100 TPY for CO and 40 TPY for VOC. These limits are

specified in the boiler and heater section.

Applicability:

ADEM Admin. Code r. 335-3-14-.05(3) “Air Permits Authorizing Construction in or near Nonattainment

Areas”

At the time of the 1981 expansion, Mobile County was declared non-attainment for ozone. Because the

allowable VOC emissions from the new emissions sources under this expansion project were greater than

100 TPY, non-attainment avoidance limits were placed on the heaters, barge loading dock, truck loading rack,

storage vessels and process unit equipment which were constructed prior to and during the 1981 expansion.

During this period, the cumulative volatile organic compound (VOC) emissions from these emissions sources

were limited to 1,781 tons per 12 consecutive months (See Engineering Analysis dated April 24, 1981). The

facility installed secondary seals on the floating roof tanks, added a vapor collection and disposal system to

the barge loading facility and implemented a program of inspection and maintenance on the fugitive

equipment leaks of VOC emissions to comply with the VOC emission limit. The requirements for the emissions

sources subject to this regulation are discussed in the individual sections.

Applicability:

ADEM Admin. Code r. 335-3-16-.03, “Major Source Operating Permits” (MSOP)

The Saraland Refinery is a major source of criteria pollutants, HAPs and greenhouse gas emissions. Semi-

annual periodic monitoring reports (PMRs) are required to be submitted to the Department to demonstrate

whether there were deviations from the permit requirements during the reporting period. An annual

compliance certification (ACC) is required to be submitted annually, within 60 days of the date of issuance of

the MSOP, to the Department and to EPA.

FEDERAL REGULATION S

NEW SOURCE PERFORMANCE STANDARDS (NSPS)

Applicability:

40 CFR 60 Subpart A, “General Provisions”

Provided that the Saraland Refinery is subject to one of the applicable subparts found under this part, the

facility shall comply with this regulation as specified in that subpart.




STATEMENT OF BASIS

Page | 13

Applicability:

40 CFR 60 Subpart J, “Standards of Performance for Petroleum Refineries” (NSPS J)

This subpart is applicable to the following affected sources located at this refinery: fuel gas combustion

devices, except flares, which were constructed, reconstructed, or modified after June 11, 1973 and on or

before May 14, 2007 and each flare which commenced construction, reconstruction or modification after

June 11, 1973 and on or before June 24, 2008 (40 CFR §60.110(a) and (b)). Each boiler and process heater

will be subject to the requirements of this subpart as discussed in the individual sections for the process

heaters and boilers.

Applicability:

40 CFR 60 Subpart Ja, “Standards of Performance for Petroleum Refineries” (NSPS Ja)

This subpart would be applicable to both flares. According to §60.100a, a modification to a flare occurs if any

new piping from a refinery process unit, including ancillary equipment, or a fuel gas system is physically

connected to the flare. Piping changes and tie-ins occurred on the flares after the effective date for this

subpart; therefore, the high pressure OFH Flare and the low pressure Refinery flare would be subject to NSPS

Ja.

This subpart would also be applicable to the sulfur recovery plant. The sulfur recovery plant is also subject

to the requirements of this subpart due to a modification that occurred on August 1, 2011, after the May 14,

2007 effective date for this type of affected facility under this subpart. The modifications to the SRP were

completed during the February 2013-March 2013 Turnaround.

The applicable requirements of this subpart for the flares and the sulfur recovery plant will be discussed in

further detail in the individual sections.

Applicability:

40 CFR 60 Subpart GGG, “Standards of Performance for Equipment Leaks of VOC in Petroleum Refineries”

(NSPS GGG)

This subpart would be applicable to all equipment in VOC service at this facility. Further discussion on the

monitoring requirement will be included later in the applicable section of the permit.

NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS (NESHAP)

Applicability:

40 CFR 63, Subpart A, “General Provisions”

Provided that Saraland Refinery is subject to one of the applicable subparts found under this part, the facility

shall meet the requirements of this subpart as specified in that subpart.

Applicability:

40 CFR 63 Subpart CC, “National Emission Standards for HAPs from Petroleum Refineries” (MACT CC)

Except as specified in §63.640(d), this subpart is applicable to the following affected sources located at the

Saraland Refinery [40 CFR §63.640(c)(1)-(8)]:

• Maintenance vent requirements under Miscellaneous Process Vents from petroleum refining process

units (§63.643),

• Storage vessels associated with petroleum refining process units (§63.660),




STATEMENT OF BASIS

Page | 14

• Wastewater systems and treatment operations associated with petroleum reefing process units

(§63.647),

• Equipment leaks from petroleum refining units (§63.648),

• Gasoline loading racks (§63.650),

• Marine vessel loading operations located at a petroleum refinery (§63.651),

• Heat exchange systems associated with petroleum refining process units which are in organic

hazardous air pollutant (HAP) service (§63.654)

• Fenceline monitoring requirements

• Flare requirements (§63.670)

Applicability to MACT CC requirements for each of these units will be discussed in the individual unit sections.

Compliance with the reporting and recordkeeping requirements found in §63.655 shall be met to comply this

subpart.

Applicability:

40 CFR 63 Subpart UUU, “National Emission Standards for HAPs from Petroleum Refineries: Catalytic

Cracking Units, Catalytic Reforming Units, and Sulfur Recovery Units” (MACT UUU)

This subpart is applicable to catalytic cracking units, catalytic reforming units, and sulfur recovery units (SRU)

located at a major source of HAPs emissions. Shell is a petroleum refinery and it is equipped with a catalytic

reforming unit and a SRU. Each bypass line serving the catalytic reforming unit or sulfur recovery unit is also

an affected source except as specified in §63.1562(3)(4). The applicability requirements for each affected

source under this subpart will be discussed in the individual sections.

Applicability:

40 CFR 63 Subpart EEEE, “National Emission Standards for HAPs: Organic Liquid Distribution (Non-

Gasoline)” (OLD MACT)

This regulation contains requirements for storage vessels in organic liquid distribution (OLD, non-gasoline)

service. Organic liquids distribution (OLD) operation means the combination of activities and equipment used

to store or transfer organic liquids into, out of, or within a plant site regardless of the specific activity being

performed. Activities include, but are not limited to, storage, transfer, blending, compounding, and

packaging. The affected source subject to the OLD MACT is the collection of activities and equipment used

to distribute organic liquids into, out of, or within a facility that is a major source of HAP. This regulation

applies to affected sources associated with crude oil (as defined in §63.2406 for organic liquid (2)). The

affected source is composed of [§63.2338(b)]:

• All storage tanks storing organic liquids.

• All transfer racks at which organic liquids are loaded into or unloaded out of transport vehicles

and/or containers.

• All equipment leak components in organic liquids service that are associated with:

o Storage tanks storing organic liquids;

o Transfer racks loading or unloading organic liquids;




STATEMENT OF BASIS

Page | 15

o Pipelines that transfer organic liquids directly between two storage tanks that are subject to

this subpart;

o Pipelines that transfer organic liquids directly between a storage tank subject to this

subpart and a transfer rack subject to this subpart;

o Pipelines that transfer organic liquids directly between two transfer racks that are subject

to this subpart.

• All transport vehicles while they are loading or unloading organic liquids at transfer racks subject to

this subpart.

• All containers while they are loading or unloading organic liquids at transfer racks subject to this

subpart.

Storage tanks, transfer racks, transport vehicles, containers, and equipment leak components that are part

of an affected source covered under another 40 CFR part 63 national emission standards for hazardous air

pollutants (NESHAP (aka MACT) are excluded from affected sources [§63.2338(c)(1)].

The truck loading rack at the refinery would not be subject to the requirement of this subpart because it is

used to load gasoline, and this subpart applies to non-gasoline loading. Therefore, the truck loading rack

would not be subject to this subpart. The marine (barge) loading rack unloads crude oil at the refinery.

However, marine vessels are subject to the requirements of 40 CFR 63 Subpart CC (MACT CC) which requires

compliance with 40 CFR 63 Subpart Y. Therefore, this unit would not be subject to the requirements of this

subpart.

The refinery is subject to the fugitive equipment leak standards found in MACT CC; however, the refinery is

required to comply only with the equipment leak requirements found under 40 CFR 60, Subpart GGG [NSPS

GGG] as required by the Consent Decree for existing sources. After termination of the Consent Decree, new

sources of equipment leaks would be subject to MACT CC and excluded from compliance with this subpart.

Storage vessels at the refinery also store crude oil that is piped in from the nearby Blakley Island terminal or

unloaded via barge. Tanks storing crude oil would be classified as Group 2 Storage Vessels under MACT CC;

therefore, the tanks would be excluded from compliance with the subpart as well.

Since this refinery does not transport crude oil via tank cars (rail) nor does it transport crude oil via cargo

tanks (attached to a motor vehicle or truck trailer) at its loading rack, the refinery would be excluded from

the requirements under this subpart

40 CFR 64, “COMPLIANCE ASSURANCE MONITORING (CAM)”

This subpart is applicable to an emission source provided the source meets the following criteria: it is subject

to an emission limit or standard, it uses a control device to achieve compliance with the emissions limit or

standard, and it has pre-controlled emissions from a regulated air pollutants that are equal to or greater than

100 percent of the amount, in tons per year, required for a source to be classified as a major source [40 CFR

§64.2(a)].

The facility flares, thermal oxidizer, and gasoline loading racks were subject to the requirements of this

subpart; however, §64.2(b)(1)(i) allows an exemption for units covered under a MACT, NESHAP or NSPS that

was proposed after November 15, 1990 if there are applicable emission limits or standards. Therefore, these

units will no longer be required to comply with CAM.




STATEMENT OF BASIS

Page | 16

EPA CONSENT DECREE REQUIREMENTS

On March 31, 2010, Shell Chemical entered into a consent decree (CD) No. 10-cv-01042 with the United States

Environmental Protection Agency (USEPA) and the Alabama Department of Environmental Management

(ADEM) for its Saraland, Alabama refinery and also a refinery located in Louisiana. Only the requirements

discussed in the CD for the Saraland Refinery will be discussed in this renewal. The requirements of the

consent decree will be discussed in detail in the applicable sections of this document.

FACILITY-WIDE EMISSIONS

Facility wide potential emissions were obtained from the 2020 Fee Invoice for 2019 emissions. Greenhouse

Gas (GHG) emissions were obtained from the most recent renewal permit application. Potential emissions

from the refinery were obtained from the most recent MSOP renewal application.

FACILITY WIDE EMISSIONS FROM SARALAND REFINERY

(TPY)

EMISSIONS PM2.5/10 SO2 NOX CO VOC Total HAPs CO2e

METRIC TPY

2019 ACTUAL EMISSIONS 32.36 12.98 204.97 288.14 283.3 22.46 8,534,825

POTENTIAL EMISSIONS 39.95 165.70 578.44 400.51 734.95 21.98




STATEMENT OF BASIS

Page | 17

BOILERS AND PROCESS HEATERS REQUIREMENTS

Permitted Operating Schedule†: 24 Hours/Day x 365 Days/Year = 8,760 Hours/Year

†Except during leap year, Permitted Operating Schedule = 8,784 Hours/Year

Emissions Limitations:

EMISSION

POINT DESCRIPTION POLLUTANT

EMISSION

LIMIT/STANDARD REGULATIONS

Each Boilers and Process Heater Opacity No more than one 6 min avg>

20%

OR

No 6 min avg. > 40% in any sixty

(60) minute period

Rule 335-3-4.-01(1)(a)

Rule 335-3-4-.01(1)(b)

H2S Shall not burn any fuel gas

containing H2S in excess of 0.10

gr/dscf (~160 ppm) averaged

over a rolling 3–hour period in

any fuel gas combustion device

Shall burn natural gas or

refinery gas, except during

periods of curtailment or

supply interruption

During periods of curtailment,

may burn liquid fuel containing

0.05 wt% sulfur or lower liquid

CD No. 10-cv-01042

§60.104(a)(1)

§60.105(e)(3)(ii)

[NSPS J]

§63.7499(l); §63.7575

[Boiler MACT]

CD No. 10-cv-01042

Heaters, barge loading dock, truck loading rack, storage

vessels and process unit equipment constructed prior to

or during the 1981 expansion

VOC <1,781 Tons per 12

consecutive months

Rule 335-3-14-.05(3)

[Non-Attainment Avoidance

(NAA) Limit]

SOURCES CONSTRUCTED PRIOR TO AND INCLUDING 1981 EXPANSION:

110-50-1010 144 MMBtu/hr No. 1 Crude Heater PM

HAPs

22.3 Lb/hr

Work Practice Standards

Rule 335-3-4-.03(1)

§63.7500

Table 3 (No. 3) [Boiler MACT]

130-50-1101 35 MMBtu/hr No. 1 HDS Charge Heater PM

NOX

HAPs

10.1 Lb/hr

2.90 Lb/hr


Rule 335-3-4-.03(1)

Rule 335-3-14-.04 [Anti-PSD]

§63.7500


130-50-1102 250 MMBtu/hr No. 1 Reformer Heater PM

HAPs

30.4 Lb/hr


Rule 335-3-4-.03(1)

§

63.7500





STATEMENT OF BASIS

Page | 18

EMISSION


EMISSION


130-50-8020 24.0 MMBtu/hr No. 1 Reformer

Stabilizer Reboiler Heater w/ Low NOX

Burners

PM

NOX

HAPs

8.0 Lb/hr

2.76 Lb/hr


Rule 335-3-4-.03(1)

Rule 335-3-14-.04 [Anti-PSD]


210-50-1030 175 MMBtu/hr No. 2 Crude Heater

w/Low NOX Burners and CEMS

PM

NOX

CO

H

Aps

24.9 Lb/hr

7.0 Lb/hr

14.3 Lb/hr


Rule 335-3-4-.03(1)

Rule 335-3-14-.04 [Anti-PSD]

CD No. 10-cv-01042

Rule 335-3-14-.04 [Anti-PSD]

§63.7500


220-50-9501 85 MMBtu/hr No. 2 Vacuum Tower

Heater

PM

NOX

HAPs

16.1 Lb/hr

9.6 Lb/hr


Rule 335-3-4-.03(1)

Rule 335-3-14-.04 [Anti-PSD]

§63.7500


230-50-2010 123 MMBtu/hr No. 2 Reformer

(Heaters No. 1, 2 and 3)

PM

NOX

CO

HAPs

20.4 Lb/hr

13.28 Lb/hr

10.0 Lb/hr


Rule 335-3-4-.03(1)

Rule 335-3-14-.04 [Anti-PSD]

Rule 335-3-14-.04 [Anti-PSD]

§63.7500


230-50-2040 10.5 MMBtu/hr No. 2 HDS Charge

Heater

PM

NOX

HAPs

5.15 Lb/hr

1.13 Lb/hr


Rule 335-3-4-.03(1)

Rule 335-3-14-.04 [Anti-PSD]

§63.7500


230-50-2060 7.0 MMBtu/hr No. 2 Naphtha HDS

Stripper Heater

PM

NOX

HAPs

4.1 Lb/hr

0.84 Lb/hr


Rule 335-3-4-.03(1)

Rule 335-3-14-.04(9)

[BACT Limit]

§63.7500

Table 3 (No. 2)[Boiler MACT]

280-50-7010 17.5 MMBtu/hr DHT Charge Heater PM

NOX

HAPs

6.9 Lb/hr

2.10 Lb/hr


Rule 335-3-4-.03(1)

Rule 335-3-14-.04(9)

[BACT Limit]

§63.7500

Table 3 (No. 2)[Boiler MACT]

220-50-8010 48.0 MMBtu/hr Vacuum Tower Pre-

Heater

PM

NOX

HAPs

12.1 Lb/hr

4.44 Lb/hr


Rule 335-3-4-.03(1)

Rule 335-3-14-.04 [Anti-PSD]

§63.7500,





STATEMENT OF BASIS

Page | 19

EMISSION


EMISSION


740-50-1001 50 MMBtu/hr No. 1 Steam Boiler PM

HAPs

12.3 Lb/hr


Rule 335-3-4-.03(1)

§63.7500


740-50-1002 50 MMBtu/hr No. 2 Steam Boiler

w/Low NOX burner

PM

NOX

HAPs

12.3 Lb/hr

2.0 Lb/hr


Rule 335-3-4-.03(1)

Rule 335-3-14-.04(9)(b)

[BACT Limit]

§63.7500


SOURCES CONSTRUCTED AFTER 1981 EXPANSION:

130-50-7020 30 MMBtu/hr No. 1 Naptha Stripper

Reboiler

PM

NOX

HAPs

9.3 Lb/hr

2.50 Lb/hr


Rule 335-3-4-.03(1)

Rule 335-3-14-.04 [Anti-PSD]

Table 3 (No. 3) [B oiler MACT]

140-50-7150 30 MMBtu/hr Reformate Splitter

Heater

PM

NOX

HAPs

9.3 Lb/hr

2.9 Lb/hr


Rule 335-3-4-.03(1)

Rule 335-3-14-.04 [Anti-PSD]

§63.7500


290-50-8030 61.6 MMBtu/hr OFH Charge Heater

w/Low NOX Burners

PM

NOX

CO

HAPs

13.9 Lb/hr

2.4 Lb/hr

4.0 Lb/hr


Rule 335-3-4-.03(1)

Rule 335-3-14-.04 [Anti-PSD]

Rule 335-3-14-.04 [Anti-PSD]

§63.7500

Table 3 (No. 3) [Boiler MACT

740-50-1003 80 MMBtu/hr No. 3 Steam Boiler

w/Low NOX burners

PM

NOX

CO

HAPs

16.1 Lb/hr

3.40 Lb/hr

4.0 Lb/hr


Rule 335-3-4-.03(1)

Rule 335-3-14-.04 [Anti-PSD]

CD No. 10-cv-01042

Rule 335-3-14-.04 [Anti-PSD]

Table 3 (No. 3 & No. 4)

[Boiler MACT]

The following sections will discuss applicability for the process heaters and boilers at the refinery with State

and Federal regulations. The refinery is equipped with indirect heating equipment (fuel burning equipment)

sources that serve various heating purposes.




STATEMENT OF BASIS

Page | 20

STATE REGULATIONS

Applicability:


Each process heater and boiler would be subject to the 20%/40% opacity standards found under this

regulation. Compliance with this regulation is met by burning natural gas as their fuel source. Visible

emissions observations shall be conducted on these units using EPA Test Method 9 or 22 when visible

emissions in excess of the opacity standards are observed. Since natural gas will be the primary fuel source

for these units and the expected particulate emissions from burning natural gas should be negligible, no

opacity monitoring should be required. Records of each visible emission observation conducted on these

units shall be maintained.

Applicability:

ADEM Admin. Code R. 335-3-4-.03(1), “Fuel Burning Equipment” for Control of Particulate Emissions

This regulation applies to fuel burning equipment located in a Class I County. Mobile County is classified

as a Class I County under this regulation; therefore, the process heaters and boilers would be subject to

the applicable requirements found in ADEM Admin. Code R. 335-3-4-.03(1). However, compliance with

this subpart is met by complying with the requirement to burn only natural gas, refinery gas, or other gas

1 fuel except during periods of natural gas curtailment or supply interruption as specified in CD No. 10-cv-

01042.

If testing is required by the Department, particulate matter (PM) emission shall be determined in

accordance with Method 5 of 40 CFR 60, Appendix A.

Applicability:

ADEM Admin. Code R. 335-3-5-.01(1)(a) and 335-3-5-.01 (5), “Fuel Combustion”

ADEM Admin. Code R. 335-3-5-.01(1)(a) limits sulfur dioxide (SO2) emissions from fuel burning equipment

in Category I counties to 1.8 Lb/MMBtu. ADEM Admin. Code R. 335-3-5-.01(5) states that Saraland

Refinery shall not cause or permit the emission or combustion of any refinery process gas stream that

contain and H2S concentration greater than 150 ppm without removal of hydrogen sulfide (H2S) in excess

of this concentration. Each process heater and boiler would be subject to these emissions standard;

however, this facility is subject to the New Source Performance Standards (NSPS) found in 40 CFR 60

subpart J (NSPS J) and the requirements specified in CD No. 10-cv-01042. These regulations place a more

stringent SO2 emissions limit on the process heater and boilers than the state requirements. Compliance

with these regulations would be met by burning natural gas or refinery gas as fuel in the process heaters

and boiler as specified in NSPS J and CD No. 10-cv-01042.

Applicability:

ADEM Admin. Code R. 335-3-14-.04 “Prevention of Significant Deterioration (PSD) Permitting”

In 1979, the Saraland Refinery underwent a PSD review which included the addition of several boilers and

heaters. This review resulted in best available control technology (BACT) limits for nitrogen oxide (NOX)

being placed on the following boilers and heaters to comply with this regulation: 50 MMBtu/hr Steam




STATEMENT OF BASIS

Page | 21

Boiler No. 2 (740-50-1002), 17.50 MMBtu/hr DHT Charge Heater (280-50-7010) and 7.0 MMBtu/hr No. 2

HDS Stripper Heater (230-50-2010).

Since the refinery became a PSD source during the initial expansion in 1979, each project thereafter was

required to meet de minims levels (100 TPY for carbon monoxide (CO) and 40 TPY for NOX). To maintain

NOX and/or CO emissions below the de minims levels, anti-PSD limits were placed on the following boilers

and heaters: 130-50-1101, 130-50-7020, 140-50-7150, 210-50-1030, 220-50-9501, 230-50-2010, 230-50-

2040, 220-50-8010, 290-50-8020 (currently designated as Source ID unit No.: 130-50-8020), 290-50-8030,

and 740-50-1003.

EMISSION STANDARDS:

The following units use low NOX burners as BACT to limit NOX emissions from the unit to comply with PSD

regulations: 230-50-2010, 230-50-2060, 280-50-7010 and 740-50-1002. The limits for these units are

listed on the summary page for the boiler and process heaters.

Several units, as identified in the summary pages for the heaters and boilers, have anti-PSD NOX and/or

CO limits in place to avoid a review under PSD regulation. All limits are based on placing low NOX burners

on the units and burning natural gas as the primary fuel source for these units.


To demonstrate that the BACT NOX limits and the Anti-PSD NOX and/or CO emissions limits are being met

for process heaters Nos.: 210-50-1030, 220-50-9501, 230-50-2010, 290-50-8030, and boilers Nos. 740-50-

1002 and 740-50-1003, a performance test shall be performed on unit while utilizing the following

methods:

• 40 CFR 60 Appendix A, Method 1 or 1A to determine the sample and velocity traverses

• 40 CFR 60 Appendix A, Method 2 or 2A or 2B or 2C or 2D or 2E to determine the velocity and

volumetric flow rate

• 40 CFR 60 Appendix A, Method 3 or 3A or 3B or 3C to determine the gas analysis

• 40 CFR 60 Appendix A, Method 4 to determine the moisture in the stack gas

• 40 CFR 60 Appendix A, Method 7 or 7A or 7B or 7C or 7D or 7E to determine NOX emissions

• 40 CFR 60 Appendix A, Method 10 or 10A or 10B to determine CO emissions

• 40 CFR 60 Appendix A, Method 19 to determine NOX emission rates

The existing permit only requires that each process heater or boiler with a heat input 50 MMBtu/hr or

greater is tested. Therefore, no performance testing is required for the following units: 130-50-1101, 130-

50-7020, 140-50-7150, 230-50-2040, 230-50-2060, 280-50-7010, 220-50-8010, and 130-50-8020.

The fuel gas burned in the boiler and process heaters shall be analyzed using ASTM Analysis Method

D1826-77 or an equivalent method.




STATEMENT OF BASIS

Page | 22


Monitoring will be in the form of conducting a performance test consisting of three one hour runs on the

applicable process heaters and boilers no less than once every five years for units with a BACT NOX

emission limit and Anti-PSD NOX and/or CO emission limits.

The fuel gas shall be tested on a frequency of no less than once each six months for its H2S content and its

Btu heat content.


NOX and/or CO emissions shall be calculated using the emissions factors (Lbs/MMBtu) calculated during

the most recent performance test, the heat content of the fuel gas calculated once each six months, the

volume of fuel gas used in the heaters and boilers on a monthly basis, and the number of hours the unit

operated. These records should be recorded and maintained for each unit.

A semi-annual periodic monitoring report (PMR) would be required to be submitted to the Department in

order to demonstrate that the emissions limits are being met.

Applicability:


Areas”

The cumulative VOC emissions from the heaters and other emission sources constructed prior to and

during the 1981 expansion were limited because Mobile County was classified as non-attainment for VOC

emissions at that time. Emissions from process heaters Nos. 110-50-1010, 130-50-1101, 130-50-1102,

210-50-1030, 220-50-9501, 230-50-2010, 230-50-2040, 230-50-2060, 280-50-7010, 290-50-8010, and 130-

50-8020 and boilers Nos. 740-50-1001 and 740-50-1002 would be subject to this regulation. The total

emissions from process heaters listed above, the barge loading dock, the truck loading rack, storage

vessels, and process unit equipment were limited to 1,781 ton per 12 consecutive months of VOC. To

comply with this regulation, records of the fuel gas heat input (MMBtu/Month) and records of VOC

emissions shall be calculated and maintained for the affected process heaters.

Applicability:

ADEM Admin. Code R. 335-3-16-.03, “Major Source Operating Permits”

This facility is a major source of criteria pollutants, HAPs and GHG emissions. The process heaters and

boilers located at this facility would be subject to the requirements of this regulation. Compliance is met

by maintaining records, conducting performance test, calculating emissions and submitting PMR reports

of deviations from permit requirements. An annual compliance certification (ACC) is required to be

submitted annually, within 60 days of the date of issuance of the MSOP, to the Department and to EPA.

FEDERAL REGULATIONS


Applicability:


The process heaters and boilers would be subject to the applicable requirements of this subpart. The

applicable requirements to this subpart will be specified in the applicable subparts under Part 60.




STATEMENT OF BASIS

Page | 23

Applicability:

40 CFR 60 Subpart D, “Standards of Performance for Fossil-Fuel Fired Steam Generators for which

Construction is Commenced after August 17, 1971”

This subpart would not be applicable to the any of the boilers (steam generating units) located at the

plant because each units’ heat input rate would not be greater than 250 MMBtu/hr [§60.40(a)(1)]. This

subpart would not apply to process heaters because they are used for indirect heating, not steam

generation.

Applicability:

40 CFR 60 Subpart Db, “Standards of Performance for Industrial-Commercial-Institutional Steam

Generating Units” (NSPS Db)

This subpart is applicable to steam generating units constructed, modified, or reconstructed after June

19, 1984 and units that have a heat input capacity of greater than 100 MMBtu/hr [§60.40b(a)]. The No.

1 and No. 2 50 MMtu/hr boilers located at the plant would not be affected sources under this regulation

because they do not meet the heat input capacity requirements. This subpart would not apply to process

heaters because they are used for indirect heating, not steam generation.

Applicability:

40 CFR 60 Subpart Dc, “Standards of Performance for Small Industrial-Commercial-Institutional Steam

Generating Units” (NSPS Dc)

This subpart is applicable to steam generating units for which construction, modification, or

reconstruction commenced after June 9, 1989 and units that have a maximum design heat input capacity

greater than or equal to 10 MMBtu/hr but less 100 MMBtu/hr [40 CFR §60.40c(a)]. By definition this

subpart does not included process heaters. The 80 MMBtu/hr No. 3 Steam Boiler (740-50-1003) would

be an affected source under this subpart.

EMISSION STANDARDS:

There are no numerical emission standards for the 80 MMBtu/hr No. 3 steam boiler (740-50-1003) since

it burns primarily natural gas as its fuel source. Except during period of curtailment by its supplier; this

unit would only be allowed to burn purchased natural gas or refinery gas or any combination of both as

fuel [40 CFR §60.48c(g)(2)].


No testing is required under this subpart for this unit.


Monitoring would be in the form of monthly recordkeeping.


Records of the amount of each fuel combusted during each calendar month shall be recorded and

maintained for a period of two years following the date of such record for this unit [40 CFR §60.48c(g)(2)

and 40 CFR §60.48c(i)].




STATEMENT OF BASIS

Page | 24

Applicability:

40 CFR 60 Subpart J, “Standards of Performance for Petroleum Refineries” (NSPS J)

This subpart is applicable to fuel gas combustion devices, except flares, located at the plant which were

constructed, reconstructed, or modified after June 11, 1973 and on or before May 14, 2007. This subpart

would be subject to each process heater and boiler located at the Saraland Refinery since they are fuel

combustion devices. Compliance with this regulation will also satisfy ADEM Admin. Code R. 335-3-5-

.01(5).

EMISSION STANDARDS:

Fuel gas burned in any of the boilers or process heaters at the plant shall not contain hydrogen sulfide

(H2S) in excess of 0.10 gr/dscf (i.e. 160 ppmv) [§60.104(a)(1)].


The following methods and procedures shall be used to evaluate the H2S concentration in the fuel gas

[§60.105(a)(4)(iii)]:

• A performance evaluation for the H2S monitor under §60.13(c) shall use Performance

Specification 7 of 40 CFR part 60, Appendix B

• Methods 11, 15, 15A, or 16 shall be used for conducting the relative accuracy evaluations (RATA)

on the monitoring systems as specified in §60.106(e)(1)(i)-(iii)

• Continuous emissions monitoring system (CEMS) shall be calibrated, maintained, and operated

in accordance with the applicable requirements of 40 CFR part 60 Appendices A and F


Each fuel combustion device shall be continuously monitored by a system capable of monitoring and

recording the concentration (on a dry basis) of H2S in the fuel gas before being burned in the unit

[§60.105(a)(4)]. If there is a common fuel gas stream for the fuel gas combustion devices, only one

location is required to be monitored if it accurately represents the concentration of H2S in the fuel gas

burned [§60.105(a)(4)(ii)]. The Saraland Refinery is equipped with two H2S CEMS units on the No. 1 and

No. 2 Fuel Gas streams.


Periods of excess emissions shall be determined and reported for all periods in which the rolling 3-hour

periods during which the average concentration of H2S as measured by the H2S continuous monitoring

system exceeds 0.10 gr/dscf (i.e. 162 ppmv) [§60.105(e)(3)(ii)]. All averages, except opacity, shall be

determined as the arithmetic average of the applicable 1 hour averages, e.g., the rolling 3-hour average

shall be determined as the arithmetic average of three contiguous 1-hour averages. An Excess Emission

report is required to be submitted to the Department on a semi-annual basis and shall identify each

period in which the H2S concentration requirement was exceeded.




STATEMENT OF BASIS

Page | 25


Applicability:


The process heaters and boilers would be subject to the applicable requirements of this subpart as

specified in Table 10 of the Boiler MACT ( §63.7565).

Applicability:

40 CFR 63 Subpart DDDDD, “National Emissions Standards for Hazardous Air Pollutants from

Industrial, Commercial, and Institutional Boilers and Process Heaters” (Boiler MACT)

This subpart was promulgated on March 21, 2011 and is applicable to new, reconstructed, and existing

industrial, commercial, or institutional boilers or process heaters located at a major source of hazardous

air pollutants (HAPs) [§63.7485]. All boilers and heaters at this plant would be existing affected sources

under this subpart because they do not meet the definition of new (constructed after June 4, 2010) or

reconstructed unit [§63.7490(d)].

EMISSION STANDARDS:

Only natural gas, refinery gas or other gas 1 fuel may be burned in these units, except during periods of

natural gas curtailment or supply interruption as defined in §63.7575. The following applicable

requirements under the Boiler MACT shall be met for each boiler and process heater at all times, except

during periods of startup and shutdown [§63.7500(f)]:

• The applicable work practice standards found in Table 3, Boiler MACT shall be complied with

except as specified in §63.7500(b), (c), and (d) [§63.7500(a)(1)].

• Operate and maintain any affected source, including associated air pollution control equipment

and monitoring equipment, in a manner consistent with safety and good air pollution control

practices for minimizing emissions [§63.7500(a)(1)].

• During periods of startup, compliance with the requirements of Table 3 of Boiler MACT shall be

met [§63.7500(e)].


An initial tune-up on the existing boilers and process heaters was completed using the procedures

specified in §63.7540(a)(10)(i) through (vi). Also, the one-time energy assessment as specified in Table 3

No. 4 (a) through (h) was performed on the existing boilers and process heaters located at the refinery

[§63.7510(e)]. Subsequent tune-ups are conducted following the procedures specified in §63.7540(a)(10),

(11), or (12) depending on the heat input of the unit.


Monitoring will be in the form of performing subsequent tune-ups at the following frequency

§63.7515(e)):

• Annually, but no more than 13 months after previous tune-up for units with a heat input greater

than 10 MMBtu/hr [§63.7540(a)(10)(i)-(vi)].




STATEMENT OF BASIS

Page | 26

• Biennially, but no more than 25 months after the previous tune-up for units with a heat input

greater than or equal to 5 MMBtu/hr but less than 10 MMBtu/hr [§63.7540(a)(11)].

• Once every 5 years, but no more than 61 months after previous tune-up for units with a heat

input of less than 5 million Btu per hour (MMBtu/hr) [§63.7540(a)(12)].

• If the unit is not operating on the required date of the tune-up, the tune-up must be conducted

within one week of startup [§63.7540(a)(13)].


NOTIFICATIONS

The following notifications as specified in §63.7545 shall be submitted to the Department:

1. Notification requirements specified in 40 CFR 63 subpart A [§63.7545 (a)].

2. Notification of Alternative Fuel Use shall be submitted within 48 hours of the declaration of each

period of natural gas curtailment or supply interruption if you intend to use a fuel other than

natural gas, refinery gas, gaseous fuel subject to another subpart of this part, or other gas 1 fuel

in the affected unit. The information specified in §63.7545(f)(1)-(5) shall be included in this

notification.

REPORTS

A compliance report shall be submitted annually, biennially, or once every 5 years depending on the rating

of the unit and shall meet the requirements specified in §63.7550 (b). The compliance report shall include

the information specified in §63.7550 (c). The reports must be submitted electronically to EPA via CEDRI

and to the Department for tracking purposes.

RECORDS

Records as specified in §63.7555(a) and (h) must be maintained and kept for a duration of five years

following each occurrence as specified in §63.7560.

Applicability:

40 CFR 63 Subpart JJJJJJ, “National Emission Standards for Hazardous Air Pollutants for Industrial,

Commercial, and Institutional Boilers Area Sources”

This subpart is only applicable to boilers located at an area source of HAPs. Since the Saraland Refinery

is a major source of HAPs, it would not be subject to this subpart.

40 CFR 64, “Compliance Assurance Monitoring (CAM)”

The process heaters and boilers are required to meet an emission standard or work practice, they have

the potential to emit greater that 100 tons per year of a criteria pollutant as shown in the emissions

section, and several units are equipped with low NOX burners to control NOX emissions. However, low

NOX burners do not meet the definition of a control device per §64.1, since they are considered control

technology instead. Therefore, none of the units would be subject to the requirements of this subpart.




STATEMENT OF BASIS

Page | 27

CONSENT DECREE REQUIREMENTS

Section IV. Affirmative Relief/Environmental Projects

Section IV.A: NOX Emissions Reductions from Heaters and Boilers

Paragraph No. 11 of Consent decree (CD) No. 10-cv-01042 requires that by no later than October 28,

2018, Shell Chemical shall implement a nitrogen oxide (NOX) Control Plan which would reduce NOX

emissions from heaters and boilers with a heat input capacity of greater than 40 MMBtu/hr at the

Saraland Refinery. Compliance will be monitored through source testing, use of a continuous emission

monitor (CEMs), and/or use of a predictive emission monitoring (PEMS). Compliance can be accomplished

by installing NOX controls and accepting permit requirements to keep such controls, or controls which

result in the same or less NOX emission on the controlled units, or shutting down certain units and

relinquishing their permit to operate.

On February 22, 2011, Shell submitted a NOX Control Plan to the Department to address how they would

reduce emissions; however, no permitting action was required by the facility during the previous renewal

issued in 2014. As part of the negotiations to reduce NOX emissions, EPA allowed Shell to increase the

maximum heat input rating for heater No.: 130-50-1102 from 150 MMBtu/hr to 250 MMBtu/hr. This was

included in the NOX plan.

Shell was required to install qualifying controls such that units constituting at least 30% of its heat input

capacity of heaters and boilers greater than 40 MMBtu/hr are controlled. As of August 8, 2018, Shell has

satisfied the requirement of this subpart but equipping the following units with low NOX burners: 61.6

MMBtu/hr OFH Charge Heater, 50.0 MMBtu/hr No. 2 Boiler, 175 MMBtu/hr No. 2 Crude Heater, and 85

MMBtu/hr No. 3 Boiler.

Section IV.B: Control of SO2 Emissions and NSPS Applicability to Fuel Gas Combustion Devices

Paragraph No. 23 of CD No. 10-cv-01042 requires that Saraland Refinery shall not burn fuel oil in any

combustion unit at the refinery, except during periods of natural gas curtailment at the refinery. During

these periods, only low sulfur (0.05 wt% sulfur or lower) liquid fuel shall be burned in any combustion

unit. Shell’s current permit already restricts the use of fuel burned in the heaters and boilers to natural

gas, refinery gas or any combination of both fuels.

Paragraph No. 24 of CD No. 10-cv-01042 requires that all fuel combustion devices (except for flaring

devices) are subject to the requirements of 40 CFR 60 subpart J and the applicable requirements of

subpart A. Paragraph No. 25 of CD No. 10-cv-01042 requires that the plant comply with the H2S/SO2

monitoring requirements of subpart J and requires a CEMS to be installed, certified, calibrated,

maintained, and operated in accordance with the applicable provision of §60.13 of subpart A for CEMS

(excluding opacity monitoring system), 40 CFR 60 Appendices A and F, and the applicable performance

specification of 40 CFR 60 Appendix B.

Shell currently complies with subpart J in its current permit for all heaters and boilers and the plant is

equipped with two H2S monitors on the fuel gas system for the heaters and boilers.




STATEMENT OF BASIS

Page | 28

Section VIII. Reporting and Recordkeeping

Paragraph No. 131 of CD No. 10-cv-01042 requires that Shell retain all records required to be maintained

in accordance with this Consent Decree for a period of five (5) years or until Termination, whichever is

longer, unless applicable regulations require the records to be maintained longer.

Paragraph No. 132 of CD No. 10-cv-01042 requires that Shell submit to EPA and the Department a

Progress Report for the refinery on a semi-annual basis until termination of the Consent Decree.

The following recordkeeping and report requirements shall be included in each Progress Report:

• Implementation of the requirements specified under Section IV and a description of any

problems anticipated with respect to meeting the requirements of this section.

• The results of emissions tests and annual average CEMS or PEMS data, in ppmvd at 3% O2

lb/MMBtu and tones per year.

• A summary of annual emissions data for the prior calendar year shall be submitted on July 31 of

each year for the heaters and boilers specified under subparagraph No. 132 (b)(i) through (iii) .

o NOX, SO2, CO and PM emissions in tons per year for each heater and boilers greater than

40 MMBtu/hr maximum fired duty.

o NOX, SO2, CO and PM emissions in tons per year as a sum for all heater and boilers

greater than 40 MMBtu/hr maximum fired duty.

o NOX, SO2, CO and PM emissions in tons per year as a sum for all other emission units for

which emission information is required to be included in the annual emission summary

and are not identified in subparagraph No. 132(b)(i) through (iv).

o The basis for each estimate required for recordkeeping (e.g., stack tests, CEMS, PEMS,

etc.) and an explanation of methodology used to calculate the tons per year emitted.

• In each semi-annual report, Shell shall identify each exceedance of an emission limit required or

established by this Consent Decree that occurred during the previous semi-annual period. The

semi-annual report shall include the information specified in subparagraph No. 132 (c)(i)

through (ii).

• Each report shall be certified by the refinery.

Section XVII. Termination

Paragraphs 14, 19, and 20 of Section IV.A and Paragraphs 24 of Section IV. shall survive termination of

this consent decree for boilers and heaters as specified in Paragraph 213 of the consent decree.




STATEMENT OF BASIS

Page | 29

BOILERS AND PROCESS HEATER EMISSIONS

The following table summarizes emissions from process heater and boilers during the 2020 Fee Inventory

for 2019 Emissions for criteria and total HAPs emissions. Greenhouse Gas (GHG) emissions were obtained

from the most recent permit renewal application for the total carbon dioxide equivalent (CO2e) from all

process heater and boilers.

Source ID

BOILER AND HEATER EMISSIONS

(TPY)

PM2.5/PM10 SO2 NOX CO VOC

110-50-1010 1.01 1.43 37.54 7.07 1.87

130-50-1101 0.11 0.16 3.02 5.07 0.21

130-50-1102 1.30 1.84 39.82 164.18 2.40

130-50-7020 0.19 0.27 4.95 8.31 0.35

140-50-7150 0.10 0.02 4.78 4.63 0.19

210-50-1030 0.88 0.17 15.13 0.05 1.63

220-50-9501 0.53 0.10 13.35 23.38 0.98

230-50-2040 0.07 0.01 1.97 3.31 0.14

230-50-2060 0.06 0.01 1.49 2.51 0.10

230-50-2010 0.85 0.17 37.74 0.59 1.56

280-50-7010 0.11 0.16 3.01 5.06 0.21

290-50-8010 0.23 0.04 5.97 10.03 0.42

130-50-8020 OOS in 2019

290-50-8030 0.41 0.08 6.43 0.02 0.76

740-50-1001 0.32 0.10 10.75 14.05 0.92

740-50-1002 0.18 0.06 2.85 8.08 0.53

740-50-1003 0.26 0.08 4.89 1.12 0.48

BOILER/HEATER

EMISSIONS 6.63 4.71 193.70 257.47 12.76

Total HAP

TPY

CO2e

(Metric TPY, tonnes)

22.25 625,185.82




STATEMENT OF BASIS

Page | 30





STATEMENT OF BASIS

Page | 31

EMERGENCY ENGINE REQUIREMENTS

EMISSION


EMISSION

LIMIT REGULATIONS

EXISTING COMPRESSION IGNITION (CI) ENGINES < 500 HP [40 CFR 63, SUBPART ZZZZ]

900-20-0110

255 HP, CI, Fire Pump Driver

Emergency Engine

HAPs

Work Or Management Practices

Change oil and filter every 500

hours of operation or annually,

whichever comes first or

according to §63.6625(i)

Inspect air cleaner every 1,000

hours of operation or annually,

whichever comes first, and

replace as necessary;

Inspect all hoses and belts every

500 hours of operation or

annually, whichever comes first,

and replace as necessary.

§63.6602

Table 2c (No. 1),

[RICE MACT]

900-20-0400

900-20-0500

900-20-0600

(3) 420 HP, CI, Fire Pump

Driver Emergency Engine

NEW COMPRESSION IGNITION (CI) ENGINE > 500 HP [40 CFR 60, SUBPART IIII]

710-79-0901 1,493 HP, CI, Emergency

Generator Engine

NOX

CO

Hydrocarbons

Particulates

Opacity

22.72 Lb/hr

27.98 Lb/hr

3.30 Lb/hr

1.32 Lb/hr

During the following periods

20 percent during acceleration

mode

15 percent during lugging mode

50 percent during peaks in

either acceleration or lugging

modes

§60.4205(a) [NSPS IIII]

Table 1, NSPS IIII

§60.4211(b)(1)

§89.113(a)(1)-(3)

NEW COMPRESSION IGNITION (CI) ENGINE < 500 HP [40 CFR 60, SUBPART IIII]

Sprint Generator 67 HP, CI, Radio Tower

Emergency Generator

NOX + NMHC

CO

PM

Opacity

0.473 Lb/hr

0.148 Lb/hr

0.037 Lb/hr

During the following periods

20 percent during acceleration

mode

15 percent during lugging mode

50 percent during peaks in either

acceleration or lugging modes

§89.112(a), Table 1

§60.4202(a)(2),§60.4205(b)

[NSPS IIII]

§60.4211(c)

§89.113(a)(1)-(3)




STATEMENT OF BASIS

Page | 32

The following sections will discuss applicability for the emergency engines at the refinery with State and Federal

regulations. The refinery is equipped with six emergency generator compression ignition (CI), diesel fired

engines.

Each Engine listed above Opacity No more than one 6 min avg>

20%

OR

No 6 min avg. > 40% in any sixty

(60) minute period

Rule 335-3-4.-01(1)(a)

Rule 335-3-4-.01(1)(b)

STATE REGULATIONS

Applicability:

ADEM Admin. Code R. 335-3-4-.01, “Visible Emissions” for Control of Particulate Emissions

This regulation would be applicable to stationary sources. Each reciprocating internal combustion engine

(RICE) would be subject to the requirements of this regulation. Both the 1493 HP emergency generator

engine and the Sprint generator engine are also subject to smoke standards specified under 40 CFR 60

Subpart IIII [NSPS IIII] during acceleration mode, lugging mode, and during peaks in either acceleration or

lugging modes. During all other times, these two emergency generator engine must comply with state

opacity standards.

EMISSION STANDARDS:

The fire pump engines would be required to meet the 20% and 40% opacity requirement as specified in

ADEM Admin. Code R. 335-3-4-.01(1) (a) and (b).


Provided that visible emissions in excess of the opacity standards are observed from the fire pump engines,

a visible emissions observation (VEO) shall be conducted using the methods specified in EPA Method 9 or

Method 22.


If visible emissions are observed from these units in excess of the opacity standards, a VEO would be

required. Deviations of period when the opacity standards were exceed shall also be submitted to the

Department and included in the semi-annual PMRs.


A record of each visible emissions observation conducted when necessary would be maintained.

Applicability:


Engine No. 900-20-0110 was installed prior to PSD regulations being promulgated; therefore, this unit

would not be subject to the requirements of this subpart. Engines No.: 900-20-0400, 900-20-0500, and

900-20-0600 were installed in 2003. When these units were installed, the potential emissions from these

units for this project would have been greater than the significant emission rates found in Admin. Code r.

335-3-14-.04(2)(w). Since these were emergency units, their operating hours were not expected to exceed

500 hour per year; therefore, their potential emissions were based on this limitation and this project was

not subject to PSD review.




STATEMENT OF BASIS

Page | 33

When engine No. 710-79-0901 was installed, the potential emissions from this unit were expected to

exceed the significant emission rates; however, the emissions were limited below these rates based on

limits specified in 40 CFR 60 Subpart IIII. The hours of operation for this unit are also limited because it is

an emergency unit; therefore, this project did not require a PSD review. Potential emissions from the

installation of the emergency Sprint generator engine are not expected to exceed a significant emission

rate for any pollutants. Therefore, none of the engines are subject to the requirements of this subpart as

long as they are operating as emergency engines.

Applicability:


All engines located at this facility would be subject to the requirements of this regulation. Compliance is

met by maintaining records, conducting maintenance on the units, conducting performance test when

required, calculating emissions, and submitting a PMR. Semi-annual periodic monitoring reports (PMRs)

are required to be submitted to the Department to demonstrate whether there were deviations from the

permit requirements during the reporting period. An annual compliance certification (ACC) is required to

be submitted annually, within 60 days of the date of issuance of the MSOP, to the Department and to EPA.

FEDERAL REGULATIONS


Applicability:


The emergency generator engines are subject to the requirements of 40 CFR 60, Subpart IIII (NSPS IIII);

therefore, compliance with this subpart shall be met as specified in §60.4218 and Table 8 of NSPS IIII.

Applicability:

40 CFR 60 Subpart JJJJ, “New Source Performance Standards for Stationary Spark Ignition Internal

Combustion Engines” (NSPS JJJJ)

The engines located at this facility are compression ignition (diesel fired), not spark ignition; therefore, they

would not be subject to the requirements of this subpart.

Applicability:

40 CFR 60 Subpart IIII, “New Source Performance Standards for Stationary Compression Ignition Internal

Combustion Engines” (NSPS IIII)

The 1493 HP, electrical generator engine (No. 710-79-0901) would be subject to the requirements of this

subpart since it was constructed after July 11, 2005 and it was manufactured after April 1, 2006

[§60.4200(a)(2)(i)]. This unit was constructed on October 8, 2007 and it was manufactured on July 1, 2006.

The 67 HP, Sprint generator engine would also be subject to the requirements of this subpart. This engine

was manufactured in 2012, and it was constructed in March 2013.

The four fire-pump engines were constructed and manufactured prior to the effective dates for this

subpart; therefore, they would not be subject to the applicable requirements of this subpart.




STATEMENT OF BASIS

Page | 34

EMISSION STANDARDS:

Engine No. 710-79-0901 is used as an emergency engine. Since it is a pre-2007 model year unit, it is not a

fire pump engine, and it has a displacement of less than 10 liter per cylinder, it must comply with the

emission standards found in Table 1 of NSPS IIII [§60.4205(a)]. The table below summarizes the applicable

standards from Table 1 for this unit. The emissions shown in the summary table above are the limits on the

summary page for the engines converted into unit of pounds per hour.

Pollutants 40 CFR 60 Subpart IIII

Emission Limitations

VOC 1.0 g/HP-hr

NOX 6.9 g/HP-hr

CO 8.5 g/HP-hr

PM 0.40 g/HP-hr

The 67 HP (50 kW), Sprint generator engine would be used as an emergency generator. Since it is a 2007

or later model year unit, it has a maximum engine power less than or equal to 3,000 HP, it is not a fire pump

engine, and it has a displacement of less than 10 liters per cylinder; it must comply with the emission

standards specified in Table 1 from §89.112(a) [§60.4202(a)(2)]. The table below summarizes the applicable

emission limits. Non-Methane Hydrocarbons (NMHC) are also called VOCs.

Pollutants 40 CFR 60 Subpart IIII

Emission Limitations (§89.112(a))

NOX + NMHC 4.7 g/kW-hr (3.505 g/HP-Hr)

CO 5.0 g/kW-hr (3.728 g/HP-Hr)

PM 0.40 g/kW-Hr (0.298 g/HP-Hr)

Each emergency generator engine is required to burn non-road diesel fuel with a maximum sulfur content

of 15 parts per million (ppm) per gallon [§80.510(b)(1)(i)]. The diesel must meet a cetane index of at least

40 or a maximum aromatic content of 35 volume percent [§80.510(b)(2)(i) or (ii)) and §60.4207(b)].

The following opacity standards shall be met for each engine’s exhaust [§60.4205(b), §60.4211(a)(3), (b)(1)

and §89.113(a)]:

• During the acceleration mode, opacity shall not exceed 20%.

• During the acceleration mode, opacity shall not exceed 20%.

• During peaks in either the acceleration or lugging modes, opacity shall not exceed 50%.

Each engine holds a manufacturer’s certification that certifies that the unit can meet the requisite

emissions standards, as required by §60.4211(b) and (c). Shell shall continue to operate and maintain each

unit and its control device per the manufacturer’s specifications for the life of the unit, except as allowed

by §60.4211(f) [§60.4206], or as allowed by the manufacturer.


No test methods and procedures are required to demonstrate compliance with NOX, CO, VOC and PM

emissions limits since each of the emergency generator engines have been certified to meet the emission

standards under this subpart. However, Method 9 shall be used to demonstrate compliance with the

opacity standards if visible emissions occur.




STATEMENT OF BASIS

Page | 35


To demonstrate compliance with the monitoring requirements specified in §60.4211, engine No. 710-79-

0901 was certified by the manufacturer as allowed under §60.4211(b)(1), and the Sprint generator engine

was certified by the manufacturer as allowed under §60.4211(c) [§60.4209].


Recordkeeping will be in the form of maintaining a record of the hours the emergency engines were used

and the reason for the engines’ use during the periods of operation (i.e. maintenance testing, emergency,

non-emergency).


Applicability:


Each engine is subject to the requirements of 40 CFR 63 Subpart ZZZZ; however, since the engines are

emergency engines, they are not required to comply with this subpart [§63.6640(e)].

Applicability:

40 CFR 63 Subpart ZZZZ, “National Emission Standards for Hazardous Air Pollutant for Stationary

Reciprocating Internal Combustion Engines (RICE)” (RICE MACT)

This regulation would be applicable to any internal combustion engine that would be located at a major

source of HAPs emissions or an area source of HAPs emissions. A major source of HAPs would require 10

TPY or more of one HAP or 25 TPY or more of a combination of HAPs [§63.6585 (b)]. The Saraland Refinery

is classified as a major source of HAPs.

Engine Nos.: 900-20-0110, 900-20-0400, 900-20-0500, and 900-20-0600 each have a maximum engine

rating of less than or equal to 500 HP, and they were constructed prior to June 12, 2006; therefore, they

are classified as existing units under this subpart [§63.6590 (a)(1)(ii)].

Except for the initial notification requirements of §63.6645 (f), engine No.710-79-0901 does not have to

meet the requirements of this subpart and 40 CFR 63 Subpart A because it is subject to limited requirements

under the RICE MACT [§63.6590 (b)(1)]. Since the Sprint generator engine is subject to the requirements

under NSPS IIII, compliance with NSPS IIII satisfies the requirements of the RICE MACT[§63.6590 (c)(3)].

There are no further requirements under the RICE MACT for the emergency generator engines.

EMISSION STANDARDS:

The four fire pump engines are existing stationary RICEs with a site rating of less than or equal to 500 HP

located at a major source of HAP Emissions; therefore, they must meet the work practices specified in Table

2c (No. 1) and as follows [§63.6602]:

Perform the following routine maintenance:

• Change oil and filter every 500 hours of operation or annually, whichever comes first (you have

the option of utilizing an oil analysis program in order to extend the specified oil change

requirements as specified in 40 CFR §63.6625(i)).

• Inspect air cleaner every 1,000 hours of operation or annually, whichever comes first.




STATEMENT OF BASIS

Page | 36

• Inspect all hoses and belts every 500 hours of operation or annually, whichever comes first, and

replace as necessary.

During periods of startup, minimize the engine’s time spent at idle and minimize the engine’s startup time

at startup to a period needed for appropriate and safe loading of the engine, not to exceed 30 minutes,

after which time the non-startup emission limitations apply.

Sources can petition for alternative work practices pursuant to the requirements of 40 CFR §63.6(g).

Since the units subject to the requirements of this subpart are emergency units, the operating requirements

specified in §63.6640(f) would be applicable.


There are no numerical emissions or operating limitation, therefore, no performance testing would be

required on the fire pump engines.


The operation and maintenance requirements specified in §63.6605(b), §63.6625(e)(2), and §63.6625(i)

shall be met to comply with the RICE MACT.


There are no notification requirements for the fire pump engines because they are emergency engines

[§63.6645 (a)(5)]. There are also no reporting requirements.

The records specified in §63.6655(e) and (f) shall be maintained as specified in §63.6660 (a) through (c)

[§63.6655(e)(2) and (f)(1), (§63.6660)].


None of the emergency engines are equipped with control devices; therefore, they would not be subject to

the requirements of this subpart.




STATEMENT OF BASIS

Page | 37

ENGINE EMISSIONS

The allowable emissions from the emergency engines are based on 500 hours of non-emergency operation are

provided in the table below. Per 40 CFR 98.30, greenhouse gas emissions from emergency sources are not

required.

Source ID

ALLOWABLE ENGINE EMISSIONS

(TPY) (Metric TPY)

PM10 SO2 NOX CO VOC CH2O Total HAPS CO2e

900-20-0110 0.14 0.13 1.98 0.43 0.16 0.0002 0.0006 N/A

900-20-0400 0.03 0.22 3.26 0.60 0.26 0.0003 0.001 N/A

900-20-0500 0.03 0.22 3.26 0.60 0.26 0.0003 0.001 N/A

900-20-0600 0.03 0.22 3.26 0.60 0.26 0.0003 0.001 N/A

710-79-0901 0.33 0.77 5.67 6.99 0.82 0.001 0.0036 N/A

Sprint Generator 0.01 0.0001 0.14 0.04 0.14 0.0001 0.00054 N/A

ENGINE EMISSIONS 0.57 1.56 17.57 9.26 1.80 0.0022 0.0072 N/A




STATEMENT OF BASIS

Page | 38





STATEMENT OF BASIS

Page | 39

FLARE REQUIREMENTS

EMISSION


EMISSION

LIMIT/STANDARD† REGULATIONS

(700-50-0100) Refinery Flare

[Steam Assisted, Low-Pressure Flare]

(700-10-1002) Olefin Feed

Hydrotreater (OFH) Flare

[Steam Assisted, High-Pressure Flare]

H2S

HAPs

Burn Gas with 0.10 grains H2S per Scf

(gr/dScf)

<20 ppbv H2S offsite

Fuel gas <162 ppmv determined on a

3-hour rolling average basis

Pilot flame present at all times when

regulated material routed to the flare

Flare tip velocity must meet allowable

specified in §63.670(d)(1) or (2)

NHVcz operated and maintained at or

above 270 Btu/Scf based on a 15-

minute block period

Rule 335-3-5-.03(1)

Rule 335-3-5-.03(2)

CD No. 10-cv-01042

§60.103a(h)

[NSPS Ja]

§63.670 (b)

[MACT CC]

§63.670 (d)

[MACT CC]

§63.670 (e)

[MACT CC]

Opacity

Smokeless design capacity,

Except for five (5) minutes in a 2

consecutive hour period as allowed.

§63.670 (c)

[MACT CC]

PROCESS UNIT TURNAROUNDS VOC Depressure process unit or vessel to a

Vapor Recovery System, Flare, or

Firebox; VOCs shall not be emitted

from a process unit or vessel until its

internal pressure is 19.6 psia [5 psig],

or less

Rule 335-3-6-.08

†Limits for each Flare

UNITS CONTROLLED BY THE FLARES:

LP Flare HP Flare

Unit 110- No. 1 Crude Unit Unit 290-Olefin Hydrotreater (OFH) Unit

Unit 130- No. 1 Hydrodesulfurization Unit

Unit 140- Light Ends Fractionation Unit

Unit 150-Kerosene Treating Unit

Unit 160- Merox Treating Unit

Unit 210- No. 2 Crude Unit

Unit 220- Vacuum Unit

Unit 230- No. 2 Naphtha HDS & Reformer Unit

Unit 240-Deisobutanizer Unit

Unit 250- Naphtha Splitter Unit

Unit 260- Reformate Fractionator Unit

Unit 270- Acid Gas Treating Unit (Claus)

Unit 272-SCOT Process Unit

Unit 278-Sour Water Stripper Unit

Unit 280-Diesel Hydrotreater Unit

Unit 280- No. 2 Debutanizer Unit




STATEMENT OF BASIS

Page | 40

LP Flare HP Flare

Unit 290-Olefin Feed Hydrotreater Unit

Unit 600- LPG Storage Unit

Unit 600- Tank Farm Unit

Unit 630-Truck Rack Unit

Unit 780- Refinery Fuel Gas System

Shell is equipped with two flares. The OFH flare (700-10-1002), high pressure flare, is used to control emissions

from the Olefin Feed Hydrotreater. The Refinery Flare System (700-50-0100), low pressure flare is used to control

emergency releases of hydrocarbons and H2S emissions. The only gases allowed to be combusted in either flare

are the results of process upsets, startup, shutdown, and/or malfunctions, relief valve leakage and/or other

emergency malfunctions. The following section will discuss the flares’ applicability to State and Federal

Regulations.

STATE REGULATIONS

Applicability:


The flares are subject to the requirements of this regulation. However, because they are required to comply

with the recently promulgated flare requirements found in §63.670 and §63.671 of MACT CC, compliance

with the MACT CC opacity standards demonstrates compliance with this rule.

Applicability:

ADEM Admin. Code R. 335-3-5-.01(5), “Fuel Combustion” for Control of Sulfur Compound Emissions

This regulation prevents the facility from combusting or emitting a refinery process gas stream that contains

H2S in concentrations greater than 150 ppmv without removal of the hydrogen sulfide in excess of this

concentration. Compliance with NSPS Ja will satisfy the requirements of this regulation.

Applicability:

ADEM Admin. Code R. 335-3-5-.03(2), “Petroleum Production” for Control of Sulfur Compound Emissions

This regulation requires that all process gas streams containing at least 0.10 grains per standard cubic feet of

H2S (~160 ppmv) shall be burned such that the offsite H2S concentration is 20 ppbv or less, as averaged over

a 30-minute period. The flares would be subject to the requirements of this subpart; however, compliance

with NSPS Ja will demonstrate compliance with this regulation.

Applicability:

ADEM Admin. Code R. 335-3-6-.08, “Petroleum Refinery Source” for Control of Organic Emissions

This regulation is applicable to process unit turnarounds at petroleum refining sources. ADEM Admin. Code

R. 335-3-6-.08(4) requires that Shell develop a detailed procedure for minimizing VOC emissions during

process unit turnarounds. The procedure at a minimum shall provide for depressurization venting of the

process unit or vessel to a vapor recovery system, flare, or firebox; and no emission of VOCs from a process

unit or vessel until its internal pressure is 136 kPa (19.6 psia) or less. Compliance with the requirements of

this subpart shall be met by compliance with MACT CC for the gasoline vapor recovery system, flare, and

thermal oxidizer, per §63.640(q).




STATEMENT OF BASIS

Page | 41

Applicability:


The Saraland Refinery is a 100 TPY source with respect to PSD since it is a petroleum refinery. However, based

on the facility history detailed at the beginning of this document, none of the projects involving the flares

resulted in the units having to undergo a PSD review.

Applicability:


The flares would be subject to the major source requirements under this regulation. Compliance is met by

maintaining records, conducting maintenance on the units, conducting performance test when required,

calculating emissions, and submitting a PMR. Semi-annual periodic monitoring reports (PMRs) are required

to be submitted to the Department to demonstrate whether there were deviations from the permit

requirements during the reporting period. An annual compliance certification (ACC) is required to be


FEDERAL REGULATIONS


Applicability:


The facility will be subject to the requirements of this subpart as specified in NSPS Ja. Because the flares will

be used to control emissions from affected sources under an NSPS Ja, the flares are required to comply with

the applicable requirements of this subpart A as referenced in NSPS Ja or an applicable subpart under Part

60.

Applicability:

40 CFR 60 Subpart J, “Standards of Performance for Petroleum Refineries”

Both the OFH and the Refinery Flares have been modified since the issuance of the consent decree; therefore,

compliance with this subpart and the consent decree, which references this subpart, will be met by complying

with NSPS Ja.

Applicability:

40 CFR 60 Subpart Ja, “Standards of Performance for Petroleum Refineries”

The flares would be subject to the requirements of this subpart since both flare were modified after June 24,

2008. Both flares had been modified as a result of piping changes and tie-ins to the header system serving

the flares [§60.100a(b) and (c)(1)]. These flares are not emergency flare since they do not have a water seal

to meet the definition of an emergency flare under NSPS Ja [§60.101a]. The flares were required to comply

with the requirements of NSPS J as specified in the consent decree until November 11, 2015, and as explained

in §60.103a(f). However, Shell has elected to comply with the more stringent requirements of NSPS Ja

instead.




STATEMENT OF BASIS

Page | 42

EMISSION STANDARDS:

The requirements specified in §60.103a are required to be met in order to demonstrate compliance with NSPS

Ja for each flare:

• A written flare management plan (FMP) is required to be developed and implemented. The initially

FMP was submitted to the Department on November 11, 2015 and a revised plan was submitted to

the Department on August 22, 2017 and January 30, 2019.

• Except for the combustion in a flare of process upset gases or fuel gas that is released to the flare as

a result of relief valve leakage or other emergency malfunction, any fuel gas that contains H2S in

excess of 162 ppmv determined hourly on a 3-hour rolling average basis shall not be burn in the flares.

An alternative means of emission limitation as specified in §60.103a(j) may be requested to comply

with this emissions standard. An alternative monitoring plan (AMP) was requested by Shell and

approved by EPA on October 27, 2015 to comply with the H2S concentration requirements specified

in §60.103a(h). Except as specified in the AMP, Appendix F of Part 60 shall be complied with for daily

validations under the calibration drift (CD) section in Appendix F, quarterly accuracy audits, quarterly

cylinder gas audits (CGA) and alternative relative accuracy test audits (RATA).

• A root cause analysis (RCA) and a corrective action analysis (CAA) shall be conducted on each flare for

sulfur monitoring when one of the following conditions occur:

o Any time the sulfur dioxide (SO2) emissions exceeds 227 kilograms (kg) (500 lb) in any 24-hour

period

o Any discharge to the flare in excess of 14,160 standard cubic meters (m3) (500,000 standard

cubic feet) above the baseline flow in any 24-hour period determined as specified in

§60.103a(a)(4).

As of January 2019, the flow baseline was determined to be 333,000 standard cubic feet (Scf) in any

24-hour period for the OFH High Pressure Flare and 720,000 standard cubic feet (Scf) in any 24-hour

period for the Refinery Low Pressure Flare. A root cause analyses (RCA) and corrective action plan

will be triggered at a flow of 833,000 scf in any 24-hour period for the OFH Flare, at a flow of 1,220,000

scf in any 24-hour period for the Refinery Flare, or anytime SO2 emissions exceed 500 lbs in any 24-

hour period.


The following monitoring requirements shall be met to demonstrate compliance with NSPS Ja:

• When performance testing is conducted to determine the H2S concentration of the fuel gas for the

flares, the requirements specified in §60.8, §60.104a (a), §60.104a (j)(4), and §60.104a (j)(4)(iv) shall

be met.

• Monitoring to demonstrate compliance with the H2S concentration limit must comply with the

requirements specified in §60.107a(a)(2). Low-sulfur fuel gas streams as defined in §60.107a(a)(3)

are exempt from H2S monitoring as specified in §60.107a(b).

• Sulfur monitoring for assessing root cause analysis thresholds shall comply with the requirements

specified in §60.107a(e), except that flares specified in §60.107a(e)(4) are exempt from sulfur

monitoring requirements. Each RCA and CAA shall be completed as soon as possible but no later than

45 days after discharge. Corrective actions as specified in §60.103a(e) shall be implemented in the

CAA.




STATEMENT OF BASIS

Page | 43

• Except as specified in §60.107a(f)(2), a continuous parameter monitoring system (CPMS) shall be

installed, operated, calibrated, and maintained to measure and record the flow rate of gas discharged

to the flares.

• Flares having a common source of fuel gas may be monitored only at one location, if monitoring at

this location accurately represents the concentration of H2S in the fuel gas being burned in the

respective flare [§60.107a(a)(2)(vi)].

COMPLIANCE AND PERFORMANCE TEST REQUIREMENTS:

To demonstrate compliance with the H2S emission limit under NSPS Ja, an initial performance test and

subsequent performance tests ( if requested by the Department) shall comply with the methods and

procedures specified in §60.104a(j)(4)(i)-(iii). Provided that a H2S monitoring system is used to demonstrate

compliance with the H2S concentration limit, the methods and procedures specified in §60.107a(a)(2)(i)-(iii)

shall be met. Provided that a total reduce sulfur (TRS) monitor is used to demonstrate compliance with the

H2S emission limit, the methods and procedures specified in §60.107a(a)(2)(v) and §60.107a(e)(1)(ii) -(iii) shall

be met.

To demonstrate compliance with the sulfur monitoring requirements in NSPS Ja, one of the following methods

and procedures shall be elected and complied with: as specified in §60.107a(e)(1) for a TRS monitor, as

specified in §60.107a(e)(2) for a H2S monitor, or as specified in §60.107a(a) and §60.107a(e)(3) for a sulfur

dioxide (SO2) monitor. Flow monitors installed to comply with sulfur monitoring for an RCA or CAA are

required to be installed, calibrated, operated, and maintained according to manufacturer’s procedures and

specifications. Shell has elected to install a TRS monitor.


The following notifications, recordkeeping, and reporting requirements specified in §60.7 of subpart A and as

follows shall be met to demonstrate compliance with NSPS Ja:

• Notification of the specific monitoring provisions in §60.107a the facility intends to comply with shall

be submitted with notification of the initial startup.

• The following records shall be maintained: a copy of the FMP, a record of the specific exemption

determined to apply for each fuel stream meeting an exemption found under §60.107a(a)(3), records

of discharges greater than 500 Lbs SO2 in any 24-hour period from each flare, records of discharges

to each flare in excess of 500,000 Scf above baseline in any 24-hr period as required by §60.103a(c),

applicable information specified in §60.108a(c)(6)(i) through (xi) shall be recorded no later than 45

days following the end of a discharge exceeding the SO2 monitoring thresholds and records specified

in §60.108a(c)(7) shall be maintained for flares that elect to comply with sulfur monitoring

requirements by installing a H2S monitor.

• An Excess Emissions Report, containing the information specified in §60.108a(d)(1) through (7), shall

be submitted according to §60.7(c) for all periods of excess emissions for which a continuous

monitoring device is installed. The report shall be submitted on a semi-annual calendar basis within

30 days of the end of the reporting period.




STATEMENT OF BASIS

Page | 44

NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS [NESHAP]

Applicability:


Each flare is subject to the requirements of 40 CFR 63 Subpart CC; therefore, compliance with this subpart

shall be met as specified Table 6 of MACT CC [§63.1, §63.642(c)].

Applicability:

40 CFR 63 Subpart, CC “National Emission Standards for Hazardous Air Pollutants from Petroleum

Refineries” [MACT CC, Ref MACT I]:

The requirements under this subpart for flares were promulgated after the issuance of the previous MSOP

for flares used as control devices for emission points subject to this subpart. On January 30, 2019, all flares

at petroleum refineries that were previously subject to the requirements under §60.18 and §63.11 and

subject to MACT CC, were required to comply only with MACT CC [§63.640(s)].

EMISSION STANDARDS:

The requirements specified in §63.670 and §63.671 shall be met to comply with this subpart or an alternative

means of emissions limitation as specified §63.670(r) may be requested to comply with MACT CC. The

following emissions standards shall be met for the flares:

• A pilot flame must be present at all times when regulated material is route to each flare as specified

in §63.670(b).

• The smokeless design capacity of each flare must be specified, and each flare shall operate with no

visible emissions, except for period not to exceed a total of five minutes during any two consecutive

hours, when regulated material is routed to the flare and the flare vent gas flow rate is less than the

smokeless design capacity of the flare. [§63.670(c)].

• The flare tip velocity shall meet one of the following requirements when regulated material is

routed to the flare and the flare vent gas flow rate is less than the smokeless design capacity of the

flare [§63.670(d)]:

o The actual flare tip velocity (Vtip) must be less than 60 feet per second (ft/s) [§63.670

(d)(1)], or

o The Vtip must be less than 400 ft/s and also less than the maximum allowed flare tip velocity

(Vmax) as determined in §63.670(d)(2).

• The flare must be operated to maintain the net heating value of the flare combustion zone gas

(NHVcz) at or above 270 British thermal units per standard cubic feet (Btu/scf) as specified

§63.670(e).

• For flares with perimeter assist air, the dilution operating limits specified in §63.670(f) shall be met.

• The general requirements specified in §63.642(n) shall be met at all times.


The following test methods and procedures shall be met when applicable:

• To determine visible emissions, the methods and procedures specified in §63.670(h) shall be met.




STATEMENT OF BASIS

Page | 45

• To determine the actual flare tip velocity Vtip, the methods and procedures specified in §63.670(d)(1)

shall be met.

• To monitor the gas composition and determine the net heating value of the vent gas (NHVvg), the

methods and procedures specified in §63.670(d)(2) shall be met.

• To calculate the NHVcz, the methods and procedures specified in §63.670(m)

• To calculate the net heating value dilution (NHVdil) parameter, the methods and procedures specified

in §63.670(n) shall be met.


Pilot Monitoring

Shell has elected to equip each of the flares with an infrared sensor which will be used to continuously monitor

the presence of the pilot flame as allowed under §63.670(g). The LP Flare will also be equipped with three

acoustic monitors which will serve as a backup monitors during periods of infrared sensor downtime.

Visible Emission Monitoring

Shell has elected to equip the flares with a video surveillance camera to continuously record images of the

flare flame and a reasonable distance above the flare flame at an angle suitable for visual emissions

observations as allowed under §63.670(h)(2). §63.640(s) states that overlap of MACT CC with flares subject

to §60.18 or §63.11 requires that the flares comply only with the requirements in MACT CC. The existing

monitoring section for the flares found in Appendix B: Opacity Monitoring for Facility Flares will no longer be

applicable. This appendix will be replaced with the requirements specified in §63.670(h) of MACT CC in the

flare section of the permit.

Flare Vent Gas, Steam Assist and Air Assist Flow Rate Monitoring

A monitoring system capable of continuously measuring, calculating, and recording the volumetric flow rate

in the flare header or headers that feed the flare as well as any flare supplemental gas used shall be installed,

operated, calibrated and maintained. Since each of the flares are steam assisted, a monitoring system capable

of continuously measuring, calculating, and recording the volumetric flow rate of assist steam used with the

flare shall be installed, operated, calibrated and maintained. Flow monitoring system requirements and

acceptable alternatives are specified in §63.670(i)(1) through (6).

Flare Vent Gas Composition Monitoring

Shell has elected to use a gas chromatograph as the primary method to comply with the combustion zone

operating limit by continuously measuring the individual component concentrations present in the flare vent

gas as allowed under §63.670(j)(2).

Emergency Flare Monitoring

Emergency flaring provisions specified in §63.670(o) shall be met for any flare that has the potential to

operate above its smokeless capacity under any circumstances.

Flare monitoring systems installed on each flare to comply with MACT CC shall meet the requirements

specified under §63.671 of MACT CC. The continuous parameter monitoring system shall be operated as

specified in §63.671(a), and monitoring plan must be developed and implemented per §63.671(b), out of

control periods shall follow procedures specified in §63.671(c), CPMS data reductions shall follow the

procedures specified in in §63.671(d) and additional requirements for gas chromatographs shall be met as

specified in §63.671(e).




STATEMENT OF BASIS

Page | 46

RECORDKEEPING AND REPORTING

The records specified in §63.655(i)(9) and the reporting requirements specified in §63.655(g)(11) shall be

maintained for each of the flares [§63.670(p) and (q)]. Periodic reports are required to be submitted on a

semi-annual calendar basis to comply with this subpart. Each report shall be submitted within 30 days of the

end of the reporting period (to coincide with the refinery’s current reporting schedule).

Copies of all records and reports are required to be maintained for a period of at least five years, except as

specified in §63.655(i). The records shall be readily accessible within 24 hours and the may be maintained in

the forms specified in §63.655(i).



Section IV.B: Control of SO2 Emissions and NSPs Applicability to Fuel Gas Combustion Devices

Subpart Ja Applicability

Paragraph No. 27 of CD No. 10-cv-01042 states that if prior to termination of the consent decree, any heater,

boiler or other fuel gas combustion device becomes subject to NSPS Subpart Ja due to a modification, the

modified facility shall be subject to and comply with NSPS Subpart Ja in lieu of NSPS, Subpart J for a regulated

pollutant to which a standard applies as a result of the modification. Under NSPS J, a flare is defined as a fuel

combustion device. Therefore, the flares would be required to comply with NSPS Ja instead of NSPS J since

they were modified prior to termination of the consent decree.

Section IV.D: Flaring Devices-NSPS Applicability

NSPS Applicability

Paragraph No. 32 of CD No. 10-cv-01042 requires that both the Refinery Flare and the OFH flare comply with

the fuel gas combustion device requirements under 40 CFR 60, subparts A and NSPS J. Each flare may be used

as emergency control devices for the quick and safe release of gas generated as a result of startup, shutdown,

and/or malfunction. The requirements of the consent decree for modified flares under NSPS Ja will remain

even after the consent decree has been terminated.

Compliance Methods for Flaring Devices

Paragraph No. 33 of CD No. 10-cv-01042 requires that Shell use one or any combination of the methods

specified in Paragraph No. 33.a. through c to comply with NSPS J. Shell has elected to eliminate the routes of

continuous or intermittent, routinely-generated refinery fuel gases to each flare and operate the flare such

that it only receives process upset gases, fuel gas released as a result of relief valve leakage, or gases released

due to other emergency malfunctions.

Section IV. E: Control of Acid Gas Flaring Incidents and Tail Gas Incidents

Acid Gas Flaring Incident and Tail Gas Incidents

Paragraph No. 37 of CD No. 10-cv-01042 requires that Shell investigate the cause of Acid Gas Flaring Incidents

and Tailgas incidents (Flaring Incidents), take reasonable steps to correct the condition that cause or

contributed to such Flaring Incidents, and minimize the Flaring Incidents. Acid Gas and Tail Gas Flaring

Incidents are not expected to occur from the OFH Flare since gases from the sulfur plant are not routed to

this flare. Only Hydrocarbon Flaring Incidents could occur on the OFH Flare.




STATEMENT OF BASIS

Page | 47

Investigation and Reporting

Paragraph No. 38 of CD No. 10-cv-01042 requires that Shell conduct an investigation to identify the Root

Cause(s) of the Flaring Incident and record the findings of the investigations in a report (“Root Cause Failure

Analysis”) within 45 days of the Flaring Incident.

Corrective Action

Paragraph No. 39 of CD No. 10-cv-01042 requires that Shell take interim and/or long-term corrective actions

to minimize the likelihood of a recurrence of the root cause and all significant contributing causes of a Flaring

Incident.

Stipulated Penalties for Acid Gas Flaring and Tail Gas Incidents

Stipulated penalties as specified in Paragraph Nos. 40 through 46 and Paragraph No. 50 of CD No. 10-cv-01042

shall be applicable as required.

Emission Calculations

Paragraph No. 47.a of CD No. 10-cv-01042 requires that Shell calculate the quantity of SO2 emissions resulting

from a Acid Gas Flaring using the following equation:

Tons of SO2= [FR] [TD] [Conc H2S] [8.44 x 10-5]

where:

FR = Average Flow Rate to Flaring Device(s) during Flaring Incident in standard cubic feet per hour

TD = Total Duration of Flaring Incident in hours

ConcH2S = Average Concentration of Hydrogen Sulfide in gas during Flaring Incident (or immediately prior

to Flaring Incident if all gas is being flared) expressed as a volume fraction (scf H2S/scf gas)

8.44 x 10-5 = [lb mole H2S/379 scf H2S][64 lbs SO2/lb mole H2S][Ton/2000 lbs]

The quantity of SO2 emitted shall be rounded to one decimal point. For purposes of determining the

occurrence of, or the total quantity of SO2 emissions resulting from, an Acid Gas Flaring Incident that is

comprised of intermittent Acid Gas Flaring, the quantity of SO2 emitted shall be equal to the sum of the

quantities of SO2 flared during each 24-hour period starting when the Acid Gas was first flared.

Paragraph No. 47.b of CD No. 10-cv-01042 requires that Shell calculate the rate of SO2 emissions during Acid

Gas Flaring using the following equation:

ER = [FR][ConcH2S][0.169]

where:

ER = Emission Rate in pounds of SO2 per hour

FR = Average Flow Rate to Flaring Device(s) during Flaring Incident in standard cubic feet per hour;

the flow of gas to the Acid Gas Flaring Device(s) shall be as measured by the relevant low meter

or reliable flow estimation parameters

TD = Total Duration of Flaring Incident in hours

ConcH2S = Average Concentration of Hydrogen Sulfide in gas during Flaring Incident (or immediately prior

to Flaring Incident if all gas is being flared) expressed as a volume fraction (scf H2S/scf gas); the

hydrogen sulfide concentration shall be determined from the Sulfur Recovery Plant feed gas

analyzer, from knowledge of the sulfur content of the process gas being flared, by direct




STATEMENT OF BASIS

Page | 48

measurement by Tutwiler or Draeger tube analysis or by any other method approved by EPA or

the applicable State.

8.44 x 10-5 = [lb mole H2S/379 scf H2S][64 lbs SO2/lb mole H2S][Ton/2000 lbs]

0.169 = [lb mole H2S/379 scf H2S][1.0 lb mole SO2/1 lb mole H2S][64 lb SO2/1.0 lb mole SO2]

In the event that any of these data points are unavailable or inaccurate, the missing data point(s) shall be

estimated according to best engineering judgment.

Semi-Annual Reporting

Paragraph No. 48 of CD No. 10-cv-01042 required that Shell submit to EPA and the Department a semi-annual

report that includes copies of every report Acid Gas Flaring Incident that Shell was required to prepare for the

previous six month period. Each semi-annual report shall also include a summary of the Incidents including

the following:

• Date;

• Summary of Root Cause(s);

• Duration;

• Amount of SO2 released;

• Any associated penalties for each Incident;

• Whether Shell decided to take corrective action, and why, and, if corrective action is not already

completed, a schedule for its implementation, including proposed commencement and completion

date; and

• A list of all Acid Gas Flaring Incidents and Tail Gas Incidents for which corrective actions are still

outstanding.

• Each semi-annual report shall also include a summary analysis of any trends identified by Shell,

including the number, Root Cause, types of corrective action, and other relevant information

regarding Acid Gas Flaring Incidents and Tail Gas Incidents at the Refinery in the previous six-month

period.

Section IV. F: Control of Hydrocarbon Flaring Incidents

Paragraph No. 49 of CD No. 10-cv-01042 requires the following for Hydrocarbon Flaring Incidents:

• The investigative, reporting, and corrective action procedures specified in Paragraphs 38 and 39 for

Acid Gas Flaring Incident shall be followed for Hydrocarbon Flaring Incidents.

• Hydrocarbon Flaring Incident(s) report shall be submitted as part of the Semi-annual Progress Report.

• Stipulated penalties under Paragraphs 40 through 43 do not apply to Hydrocarbon Flaring Incidents.

• The equations used to calculate the quantity and rate of SO2 emissions during Acid Gas Flaring

Incidents shall be used to calculate the quantity and rate of SO2 emissions during Hydrocarbon Flaring

Incidents.

• The Hydrocarbon Flaring Incident investigation and corrective action procedures shall continue after

termination of the Consent Decree, but the reporting provisions of this Section shall not apply after

termination.




STATEMENT OF BASIS

Page | 49


Paragraph No. 131 of CD No. 10-cv-01042 requires that Shell retain all records required to be maintained in

accordance with this Consent Decree for a period of five (5) years or until Termination, whichever is longer,

unless applicable regulations require the records to be maintained longer.

Paragraph No. 132 of CD No. 10-cv-01042 requires that Shell submit to EPA and the Department a Progress

Report for the refinery on a semi-annual basis until termination of the Consent Decree.

The following recordkeeping and report requirements shall be included in each Progress Report:

• Implementation of the requirements specified under Section IV and a description of any problems

anticipated with respect to meeting the requirements of this section.

• A summary of annual emissions data for the prior calendar year shall be submitted on July 31 of

each year as specified under subparagraph No. 132 (b)(i) through (iii) .

o SO2 emissions in tons per year from all acid gas and tail gas incidents by each flare

o NOX, SO2, CO and PM emissions in tons per year as a sum for all other emission units for

which emission information is required to be included in the annual emission summary and

are not identified in subparagraph No. 132(b)(i) through (iv).

o The basis for each estimate required for recordkeeping (e.g., stack tests, CEMS, PEMS, etc.)

and an explanation of methodology used to calculate the tons per year emitted.

• In each semi-annual report, each exceedance of an emission limit required or established by this

Consent Decree that occurred during the previous semi-annual period shall be identified. The semi-

annual report shall include the information specified in subparagraph No. 132 (c)(i) through (ii).

• Each report shall be certified by the refinery.


Paragraph No. 37 of CD No. 10-cv-01042 states that after termination of the consent decree, the investigation

and corrective action procedures for Acid Gas Flaring Incidents shall survive the consent decree. The root

cause analysis and corrective action analysis required under NSPS Ja will serve to demonstrate compliance

with this requirement for the flares. The consent decree also states that the semi-annual reporting

requirement specified in Paragraph No. 48 and the stipulated penalty provisions found in Paragraph No. 40

shall not apply after termination of the consent decree. However, at the time that the consent decree was

written, Shell was not subject to NSPS Ja for either flare.

NSPS Ja requires that semi-annual reports be submitted to demonstrate compliance with this regulation.

Therefore, the reporting requirements will still be applicable as required under §60.108a(d) of NSPS Ja for the

flares after termination of the consent decree.

Paragraph 32 of Section IV.D, Paragraphs 37, 38 and 39 of Sections IV.E and Paragraph 49 of Section IV.F. of

CD No. 10-cv-01042 shall survive termination of the consent decree for the flares as specified in Paragraph

213 of the consent decree.




STATEMENT OF BASIS

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40 CFR 64, COMPLIANCE ASSURANCE MONITORING (CAM)

CAM will no longer be applicable to the flares. §64.2 (b)(i) exempts the flares from CAM requirements since

the flares are subject to emissions limitations or standards proposed after November 15, 1990 pursuant to

section 111 of the Act, in this case limitation and standards specified in MACT CC. All references to CAM will

be removed from the flare section of the MSOP and from Appendix A: Monitoring for Facility Flares.

FLARE EMISSIONS

The emissions from the flares are based on continuous burning of pilot gas in each flare. According to §98.3(d),

pilot gas emissions are not GHG reportable for flares. The potential emissions were obtained from the most

recent copy of the MSOP renewal application.

The consent decree requires that both flares be used only during process upsets, startup, shutdown, and/or

malfunctions, relief valve leakage and/or other emergency malfunctions. Since many of these events are

unplanned, emissions for the flares will vary year from to year. The 2019 Emission Fees from the 2020 accounts

for emission during these events.

FLARE EMISSIONS

CRITERIA POLLUTANTS

(TPY)

GHG

(Metric TPY)

PM2.5/PM10 SO2 NOX CO VOC CO2e

TOTAL FLARE EMISSIONS (PILOT) 0.00 0.04 0.06 0.10 0.00 -

TOTAL 2019 FLARE EMISSIONS

(UPSET, SSM, RVL) 0.413 2.46 9.83 21.54 10.48 -

POTENTIAL EMISSIONS 1.92 2.03 5.33 21.98 9.92 -




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STATEMENT OF BASIS

Page | 51

SULFUR RECOVERY PLANT (SRP)/ THERMAL OXIDIZER REQUIREMENTS

EMISSION


EMISSION


30 LTD Sulfur Recovery Plant w/Tail Gas Treatment

Unit and Thermal Oxidizer [270-30-9020]

SO2

and

HAPS

250 ppmv (dry basis) SO2 @

0% excess air averaged over

a 12-hour period

§60.100a(a)

§60.102a(f)(1)(i)

[NSPS Ja]

§63.1568(a)(1)(i),

Table 29

[MACT UUU]

Thermal Oxidizer HAPs During startup or shutdown:

maintain the hourly average

combustion zone

temperature at or above

1200 oF

AND

maintain the hourly average

oxygen concentration in the

exhaust gas stream at or

above 2 volume percent

(dry basis)

§63.1568(a)(2),

Table 30, No. 6

MACT UUU

Opacity No more than one 6 min

avg> 20%

OR

No 6 min avg. > 40% in any

sixty (60) minute period

Rule 335-3-4.-01(1)(a)

Rule 335-3-4-.01(1)(b)

H2S

Burn each process gas

stream containing greater

than 0.10gr H2S/dScf (~160

ppm)

AND

< 20 ppbv offsite ground

level H2S concentration

averaged over 30 minutes

Rule 335-3-5-.03(2)

INDIVIDUAL PROCESS UNITS

SULFUR RECOVERY PLANT:

Claus sulfur recovery unit

SCOT Tail Gas Unit

Caustic unit

Thermal oxidizer

The purpose of the No. 1 sulfur recovery unit (SRU) is to convert hydrogen sulfide (H2S) gas to elemental sulfur

and to convert ammonia to nitrogen. The sulfur recovery plant (SRP) consists of the No. 1 sulfur recovery unit,

SCOT tail gas unit, and the tail gas incinerator (or thermal oxidizer). The sulfur recovery plant’s thermal oxidizer

is used control H2S emissions from the entire facility by combusting it and converting it to SO2. Produced

elemental sulfur recovered from the Claus unit is stored in a sulfur pit until sale or disposal offsite.




STATEMENT OF BASIS

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The following section will discuss applicability of the sulfur recovery plant (SRP) and thermal oxidizer to State

and Federal regulations.

STATE REGULATIONS

Applicability:


The thermal oxidizer would be subject to the 20%/40% opacity standards found under this regulation.

Compliance with this regulation is met by burning tail gas routed from the sulfur recovery plant to the thermal

oxidizer for combustion. Daily visual inspections of the thermal oxidizer for visible emissions are required to be

performed and recorded provided that the thermal oxidizer is being operated and facility operating personnel

is onsite. Provided that visible emissions in excess of the opacity standards are observed from the thermal

oxidizer at any time, a visible emissions observation shall be conducted on the thermal oxidizer using EPA Test

Method 9 or 22.

Applicability:

ADEM Admin. Code R. 335-3-5-.01(5), “Fuel Combustion” for Control of Sulfur Compound Emissions

This regulation prevents the facility from combusting or emitting a refinery process gas stream that contains

H2S in concentrations greater than 150 ppmv without removal of the H2S in excess of this concentration.

Compliance with 40 CFR 60 Subpart Ja [NSPS Ja] and the Consent Decree will satisfy this regulation.

Applicability:

ADEM Admin. Code R. 335-3-5-.03(2), “Petroleum Production” for Control of Sulfur Compound Emissions

This regulation requires that all process gas stream containing at least 0.10 grains per standard cubic feet of H2S

(~160 ppmv) be burned such that the offsite H2S concentration is 20 ppbv or less, as averaged over a 30-minute

period. The thermal oxidizer would be subject to the requirements of this subpart; however, compliance with

NSPS Ja will demonstrate compliance with this regulation.

Applicability:


Sulfur recovery unit No. 1 was originally permitted on July 25, 1981 as part of the 1981 expansion of the plant.

The facility was originally permitted with a design capacity of 50 long tons per day (LTD) of sulfur, and the unit

was determined to be subject to the requirements of NSPS J because the design capacity was expected to be

greater than 20 LTD. Because the emissions from the 1981 expansion exceeded the PSD threshold of 100 TPY

for this type of facility, the facility was required to undergo a PSD review for SO2 emissions. It was determined

that the best available control technology (BACT) for PSD was to install a tail gas treatment system to the sulfur

recovery unit to meet NSPS J (See PSD review dated April 24, 1981). However, since the plant’s design capacity

never reached 50 LTD, installation of the tail gas treatment system was unnecessary.

In 1992, the facility proposed the addition of a second sulfur recovery unit and the de-rating of the No. 1 SRU

from a design capacity of 50 LTD to 15 LTD of sulfur. This was part of the project to add the diesel hydrotreater

(DHT) unit. This also made this unit exempt from the requirements of NSPS J because the plant produced less

than 20 LTD. The facility proposed use of the second SRU as backup when the No. 1 unit was down for

maintenance. The No. 2 SRU design capacity was limited to 3 LTD of sulfur. Physical modifications were made




STATEMENT OF BASIS

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to the No. 1 SRU, which involved plugging tubes in the SRU. No PSD review was required for this project. It

should be noted that the No. 2 SRU was never built/operated.

In 1997, the facility proposed to increase the capacity of the No. 1 SRU from 15 LTD to 35 LTD of sulfur as part

of a refinery modification and to replace the No. 2 SRU with a caustic wash unit. This project was not required

to undergo a PSD review due to limiting the SO2 emissions from the SRU to 50 TPY. Per Shell’s letter dated

March 25, 1999, the facility elected not to increase the capacity of SRU No. 1 from 15 LTD to 35 LTD.

In 2001, Shell requested that they be allowed to upgrade the equipment associated with the No. 1 SRU by

increasing the design capacity from 15 LTD to 18 LTD of sulfur as part of a plant modification. No PSD review

was required for this project.

In 2010, per the Consent Decree, the SRU became subject to NSPS J and Subpart A.

In 2012, the facility requested that all physical restrictions placed on the SRU No. 1 be removed to allow the

unit to have a maximum design capacity of 30 LTD of sulfur. This project did not require a PSD review. However,

compliance with NSPS Ja was equivalent to best available control technology (BACT) for this unit.

Applicability:


The sulfur recovery plant would be subject to the major source requirements under this regulation. Compliance

is met by maintaining records, conducting performance testing, and calculating emissions. Semi-annual

periodic monitoring reports (PMRs) are required to be submitted to the Department to demonstrate whether

there were deviations from the permit requirements during the reporting period. An annual compliance

certification (ACC) is required to be submitted annually, within 60 days of the date of issuance of the MSOP, to

the Department and to EPA.

FEDERAL REGULATIONS


Applicability:


The sulfur recovery plant would be subject to the applicable requirements of this subpart. The applicable

requirements to this subpart will be specified in the applicable subparts under Part 60.

Applicability:

40 CFR 60 Subpart J, “Standards of Performance for Petroleum Refineries”

NSPS J applies to a sulfur recovery plant (SRP) (constructed, reconstructed or modified after October 4, 1976,

and on or before May 14, 2007) with a design capacity for sulfur feed of 20 LTD. SRU No. 1 commenced

operation between the effective dates for this subpart; however, the unit was modified on August 22, 2012.

The modification triggered compliance with NSPS Ja for the sulfur recovery unit because the design capacity for

the SRU increased to greater than 20 LTD. The unit is no longer an affected source subject to this subpart.




STATEMENT OF BASIS

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Applicability:

40 CFR 60 Subpart Ja, “Standards of Performance for Petroleum Refineries”

NSPS Ja is applicable to sulfur recovery plants (SRP) that are constructed, reconstructed or modified after May

14, 2007. The increase in the sulfur rate to the SRU to 30 LTD triggered applicability to NSPS Ja.

EMISSION STANDARDS:

The emission limitations for an SRU with an oxidation control system or reduction control system followed by

incineration shall be met as follows:

• Shell shall not discharge or cause to be discharged any gases into the atmosphere in excess of 250 ppm

by volume (dry basis) of SO2 at zero percent excess air. This emission standard shall not apply during

periods of maintenance on the sulfur pit [§60.102a(f)(1)(i), §60.102a(f)(3)].

• Periods of maintenance of the sulfur pit shall not exceed 240 hours per year [§60.102a(f)(3)]. During

periods of maintenance on the sulfur pit.

• The work practice standards specified in §60.103a(c)(3) requires that each time that the SO2 emissions

from the sulfur recovery plant are more than 500 lbs greater than the amount that would have would

have been emitted if the SO2 concentration was equal to 250 ppmv during one or more consecutive

periods of excess emissions or any 24-hour period (whichever is shorter), a Root Cause Failure Analysis

and a Corrective Action Analysis shall be conducted.

o The root cause analysis and corrective action analysis must be completed as soon as possible,

but no later than 45 days after a discharge.

o Special circumstances affecting the number of root cause analyses and/or corrective action

analyses are specified in §60.103a(d).

o Corrective action(s) identified in the corrective action analysis shall be implemented as

specified in §60.103a(e).

o An alternative means of emission limitation may be elected as specified in §60.103a(j).


The following methods and procedures shall be met to conduct a performance evaluation of the SO2 CEMS

[§60.106a(a)(1)(iii)]:

• Comply with the requirements specified in §60.13(c) of subpart A and Performance Specification 2 of

40 CFR Part 60 Appendix B.

• Method 6 or 6C of 40 CFR Part 60 Appendix A-4 and Method 3 or 3A of 40 CFR Part 60 Appendix A-2

shall be used to conduct a Relative Accuracy Test Audit (RATA) for certifying the oxygen (O2) monitor.

As an alternative to EPA Method 6 the ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,”

(incorporated by reference—see §60.17) may be used.

Compliance with the SO2 emission standard shall be determined using the methods and procedures specified in

§60.104a(h)(1)-(5):

• Method 1 of 40 CFR Part 60 Appendix A-1 for sample and velocity traverses.

• Method 2 of 40 CFR Part 60 Appendix A-1 for velocity and volumetric flow rate.




STATEMENT OF BASIS

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• Method 3, 3A, or 3B of 40 CFR Part 60 Appendix A-2 for gas analysis.

• Method 6, 6A, or 6C of 40 CFR Part 60 Appendix A-4 to determine SO2 concentration.

• Method 15 or 15A of 40 CFR Part 60 Appendix A-5 to determine the reduced sulfur compound and H2S

concentrations.

• Method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analysis,” (incorporated by reference-see

§60.17) is an acceptable alternative to EPA Method 3B of Appendix A-2, EPA Method 6 or 6A of

Appendix A-4, and EPA Method 15A of Appendix A-5.


To demonstrate compliance with the SO2 emission limit Shell installed a monitor to continuously monitor and

record the SO2 concentration (dry basis, zero percent excess air) of any SO2 emission into the atmosphere. An

O2 monitor is also required to correct the data for excess air [§60.106a(a)(1)]. Annual RATAs are performed on

the continuous emission monitoring system (CEMS) as required.

A performance test was conducted on the SRP to demonstrate initial compliance with the SO2 emission

standards according to §60.8 of subpart A and §60.104a(h)(5)(i)-(iv). Subsequent performance tests are

required on an annual basis.


The notification, recordkeeping and reporting requirements specified in §60.7 of subpart A shall be met.

Records of discharges greater than 500 lbs SO2 in excess of 250 ppmv allowable SO2 limit for the SRP shall be

maintained and recorded no later than 45 days following the end of a discharge exceeding the allowable

[§60.108a(c)(6)]. The recorded information shall include the following:

• Description of the discharge.

• Date and time the discharge was first identified and the duration of the discharge.

• Measured or calculated cumulative quantity of gas discharged over the discharge duration. If the

duration exceeds 24 hours, record the discharge quantity for each 24- hour period.

• SO2 discharged to atmosphere.

• Cumulative quantity of SO2 released into the atmosphere.

• Steps taken to limit the emission during discharge.

• Records as specified in §60.108a(c)(ix) of the root cause analysis and corrective action analysis

conducted.

• For corrective action analysis for which corrective actions are required, a description of the corrective

action(s) completed within the first 45 days following the discharge and for action(s) not already

completed, a schedule for implementation, including proposed commencement and completion

dates.

A record of the time periods during which the sulfur pit vents were not controlled and measures take to

minimize emission during these period must be documented [§60.102a(f)(3)].

An excess emission report shall be submitted semi-annually for all periods of excess emissions according to

§60.7(c), except that the report shall contain the following information [§60.108a(d)]:




STATEMENT OF BASIS

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• Date exceedance occurred.

• Explanation of the exceedance.

• Whether the exceedance was concurrent with startup, shutdown, or malfunction of an affected facility

or control system.

• Description of the action taken, if any.

• Discharge records in excess of the emission limit.

• For CMS downtime, any changes made in operation of the emission control system during the period

of data unavailability which could affect the ability of the system to meet the applicable emission limit.

Operations of the control system and affected facility during periods of data unavailability are to be

compared with operation of the control system and affected facility before and following the period of

data unavailability.

• A written statement, signed by a responsible official, certifying the accuracy and completeness of the

information contained in the report.


Applicability:

40 CFR 63 Subpart UUU, “National Emission Standards for HAPs from Petroleum Refineries: Catalytic Cracking

Units, Catalytic Reforming Units, and Sulfur Recovery Units”

40 CFR 63 Subpart UUU [MACT UUU, Refinery MACT II] is applicable to each new, reconstructed, or existing

process vent or group of process vents on Claus or other types of sulfur recovery units (SRUs) or tail gas

treatment units serving a sulfur recovery plant that is associated with sulfur recovery and is located at a

petroleum refinery that is a major source of HAPs emissions [§63.1561(a) and §63.1562(b)(3)]. Each bypass line

serving a new, existing, or reconstructed sulfur recovery unit is also subject to the requirements of this subpart,

except as specified in §63.1562(f)(4) [§63.1562(b)(4)]. The bypass lines are discussed later in the Bypass Line

Requirement section of this document.

MACT UUU was promulgated on April 11, 2002. Shell elected to comply with this regulation by adhering to the

standards specified in NSPS J even though the facility was not subject to NSPS J at that time. On August 22,

2012, Shell was issued Air Permit No.: 503-4003-X093 for modifications made to the sulfur recovery plant. This

modification resulted in the sulfur recovery plant becoming subject to NSPS Ja since the modification occurred

after May 14, 2007 and the feed capacity of the plant was modified to greater than 20 Long tons per day (LTD).

EMISSION STANDARDS:

Since the SRU is also subject to the sulfur dioxide (SO2) emission limitations found in §60.102a(f)(1) of NSPS Ja,

compliance with NSPS Ja would also satisfy the requirements of MACT UUU [§63.1568(a)(1)(i), Table 29 Item

No. 1a of MACT CC] for SO2 emission standards.

The following work practice standards must also be met to comply with MACT UUU:

• An operation, maintenance, and monitoring plan shall be prepared according to the requirements in

§63.1574(f), and the SRP with thermal oxidizer shall be operated at all times according to the

procedures in the plan [§63.1568(a)(2)].

• During periods of startup or shutdown of the SRP, Shell has elected to comply with the operating

limits by maintaining the hourly average combustion zone temperature at or above 1200 oF and by




STATEMENT OF BASIS

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maintaining the hourly average oxygen concentration in the exhaust gas stream at or above 2 percent

(dry basis) [Table 30, Item No. 6 of MACT UUU, §63.1568(a)(4)(iii)]].


Compliance with MACT UUU is met by complying with the test methods and procedures found in NSPS Ja for

SO2 emissions [§60.103a(c), (c)(3) and (d), Table 31, Item No. 1a, Table 40]. Subsequent performance test must

be conducted once every 12 months to determine SO2 emissions as specified in NSPS Ja. Performance elevations

of the SO2 CEMS and O2 monitoring must be conducted using the methods and procedures specified in NSPS

Ja.

The procedures in the operation, maintenance, and monitoring plan (OMMP) shall be followed to demonstrate

continuous compliance with MACT UUU [§63.1569(c)(2)].

EMISSION MONITORING

The operation, maintenance, and monitoring plan shall detail the operation, maintenance, and monitoring

procedures and shall include at a minimum the applicable information specified in §63.174(f)(2) for each CEMs.


Periodic monitoring will consist of ensuring that all bypass lines are closed during periods of normal operation,

and that records will be kept of any time the lines are opened [§63.1569(b) & (c), & Table Nos. 37, 38, & 39

from MACT UUU]. A flare selected as an option to comply with subpart must comply with the monitoring

requirements specified in §63.671.


This subpart is applicable to an emission source provided the source meets the following criteria: it is subject

to an emission limit or standard, it uses a control device to achieve compliance with the emissions limit or

standard, and it has pre-controlled emissions of a regulated air pollutants that are equal to or greater than 100

percent of the amount, in tons per year, required for a source to be classified as a major source [40 CFR

§64.2(a)]. The SRP has an SO2 emission limit, a work practice standard for hydrogen sulfide (H2S), the tail gas

unit and thermal oxidizer are used to control emissions from the SRP, and the pre-controlled emissions for SO2,

and H2S are greater than the major source threshold. The refinery is required to meet the offsite H2S

concentration of 20 ppbv. Compliance with this requirement is met by maintaining the SO2 emissions below

the allowable required under NSPS Ja. The facility is required to monitor the SO2 and oxygen concentration in

the emission stream continuously. Because the SRU is subject to SO2 emission standards found under NSPS Ja

and MACT CC, the exemption found in §64.2(b)(1)(i) would be applicable to the SRU. The SRU would no longer

be required to comply with a CAM plan. Compliance with NSPS Ja and MACT UUU would satisfy CAM.

The refinery is also required to burn any gas with an H2S concentration in excess of 160 ppmv. The requirement

to burn is considered to be a work practice standard. Even though the thermal oxidizer is subject to operational

limits during startup and shutdown, which require the firebox temperature and outlet oxygen concentration to

be maintained as specified in MACT UUU, a CAM plan for the thermal oxidizer is required for all other periods.

To comply with CAM, the facility is required to continuously operate the thermal oxidizer with a flare or spark

present at all times when a process gas stream may be sent to it.

The thermal oxidizer may be equipped with either a continuous sparking flame igniter that is monitored by an

amp meter or an equivalent device, or a continuously burning pilot light that is monitored with either a

thermocouple or any equivalent device or by visual observation. Provided that the there is no spark or flame




STATEMENT OF BASIS

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present at the burner tip when a gas stream could be vented to it in excess of 5% of the thermal oxidizer’s

operating time in a quarter, a QIP is required.



Section IV.C: Sulfur Recovery Plant

Paragraph No. 28 of CD No. 10-cv-01042 required that the SRP comply with the applicable requirements under

40 CFR 60 subparts A and J. However, the SRP became applicable to NSPS Ja prior to termination of the consent

order as a result of a modification. Therefore, the applicable requirements of NSPS Ja will be met instead of

NSPS J for the SRP. There is overlap between the requirements found in NSPS J and the consent decree with

NSPS Ja, so many of the requirements in NSPS Ja have already been addressed in both NSPS J and the consent

decree.

Paragraph No. 29 of CD No. 10-cv-01042 requires that sulfur pit emissions be routed or re-routed so that they

are eliminated, controlled, or included and monitored as part of the SRP’s emissions subject to the SO2 emission

limit specified in NSPS Ja [replaced NSPS J].

SRP Compliance with NSPS

Subparagraph No. 30a of CD No. 10-cv-01042 requires that the SO2 emission limit found under NSPS Ja [replaced

NSPS J] be met at all times except during periods of startup, shutdown or malfunction or during malfunction of

the tail gas unit (TGU). The “start-up/shutdown” provisions specified in 40 CFR 60 Subpart A apply.

Subparagraph No. 30b of CD No. 10-cv-01042 requires that at all times, including periods of startup, shutdown

and malfunction, Shell shall, to the extent practicable, operate and maintain the SRP and TGU and any

supplemental control devices, in accordance with good air pollution control practices as required in 40 C.F.R. §

60.11(d).

Subparagraph No. 30c of CD No. 10-cv-01042 requires that Shell monitor all emission points (stacks) to the

atmosphere from the SRP for tail gas emissions and monitor and report excess emissions as required by 40

C.F.R. § 60.7(c) and §60.13 of subpart A and §60.106a(a)(1) of NSPS Ja [replaced §60.105(a)(5, 6 and 7) of NSPS

J]. Shell shall conduct emission monitoring with a CEMS at each such emission point unless an alternative

monitoring procedure has been approved by EPA [§ 60.13(i) of subpart A].

Preventive Maintenance Operation Plan (PMO Plan)

Paragraph No. 31 of CD No. 10-cv-01042 required that Shell implement a PMO Plan for good air pollution control

practices and to minimize SO2 emissions. The PMO Plan shall be complied with at all times, including periods

of startup, shutdown and malfunction of its SRP. Any changes to the PMO Plans related to minimizing Acid Gas

Flaring and/or SO2 emission shall be summarized and reported to EPA and ADEM annually.

Section IV. E: Control of Acid Gas Flaring Incidents and Tail Gas Incidents

Acid Gas Flaring Incident and Tail Gas Incidents

Paragraph No. 37 of CD No. 10-cv-01042 requires that Shell investigate the cause of Acid Gas Flaring Incidents

and Tailgas Incidents (Flaring Incidents), take reasonable steps to correct the condition that caused or

contributed to such Flaring Incidents, and minimize the Flaring Incidents.

Investigation and Reporting

Paragraph No. 38 of CD No. 10-cv-01042 requires that Shell conduct an investigation to identify the Root

Cause(s) of the Flaring Incident and record the findings of the investigations in a report (“Root Cause Failure




STATEMENT OF BASIS

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Analysis”) within 45 days of the Flaring Incident. The root cause analysis required under §60.108a(c)(3) and (d)

of NSPS Ja and the record requirements specified under §60.108a(c)(6) of NSPS Ja will serve to demonstrate

compliance with this requirement.

Corrective Action

Paragraph No. 39 of CD No. 10-cv-01042 requires that Shell take interim and/or long-term corrective actions to

minimize the likelihood of a recurrence of the root cause and all significant contributing causes of a Flaring

Incident. The corrective action analysis required under §60.108a(e) of NSPS Ja, will serve to demonstrate

compliance with this requirement.

Stipulated Penalties for Acid Gas Flaring and Tail Gas Incidents

Stipulated penalties as specified in Paragraph Nos. 40 through 46 and Paragraph No. 50 of CD No. 10-cv-01042

shall be applicable as required.

Emission Calculations

If tail gas exceeding the 250 ppmvd (NSPS Ja limit) is emitted from a monitored SRP incinerator, Paragraph No.

47.c.ii of CD No. 10-cv-01042 requires that Shell calculate the quantity of SO2 emissions resulting from a Tail

Gas Incident using the following equation:

TDTGI

ERTGI = Σ [ FRInc.]i [Conc. SO2 - 250]i [0.169 x 10-6] [(20.9 - % O2)/20.9]i

i = 1

where:

ERTGI = Emissions from Tail Gas at the Sulfur Recovery Plant incinerator, SO2 lbs. 24 hour period

TDTGI = Total Duration (number of hours) when the incinerator CEMS exceeded 250 ppmvd SO2 corrected to 0%

O2 on a rolling twelve hour average, in each 24 hour period of the Incident

i = Each hourly average

FRInc. = Incinerator Exhaust Gas Flow Rate (standard cubic feet per hour, dry basis) (actual stack monitor data or

engineering estimate based on the acid gas feed rate to the SRP) for each hour of the Incident

Conc. SO2 = Each actual 12 hour rolling average SO2 concentration (CEMS data) that is greater than 250 ppm in

the incinerator exhaust gas, ppmvd corrected to 0% O2, for each hour of the Incident.

% O2 = O2 concentration (CEMS data) in the incinerator exhaust gas in volume % on dry basis for each hour of

the Incident

0.169 x 10-6 = [lbs. mole of SO2 / 379 SO2 ] [64 lbs SO2 / lbs. mole SO2 ] [1 x 10-6 ]

Semi-Annual Reporting

Paragraph No. 48 of CD No. 10-cv-01042 requires that Shell submit to EPA and the Department a semi-annual

report that includes copies of every report Tail Gas Incidents that Shell was required to prepare for the previous

six month period. Each semi-annual report shall also include a summary of the Incidents including the following:

• Date;

• Summary of Root Cause(s);




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• Duration;

• Amount of SO2 released;

• Any associated penalties for each Incident;

• Whether Shell decided to take corrective action, and why, and, if corrective action is not already

completed, a schedule for its implementation, including proposed commencement and completion

date; and

• A list of all Acid Gas Flaring Incidents and Tail Gas Incidents for which corrective actions are still

outstanding.

• Each semi-annual report shall also include a summary analysis of any trends identified by Shell, including

the number, Root Cause, types of corrective action, and other relevant information regarding Acid Gas

Flaring Incidents and Tail Gas Incidents at the Refinery in the previous six-month period.

After termination of the consent decree, only the reporting requirements specified in §60.108a of NSPS Ja will

be required to be maintained on a semi-annual basis.


Paragraph No. 131 of CD No. 10-cv-01042 requires that Shell retain all records required to be maintained in

accordance with this Consent Decree for a period of five (5) years or until Termination, whichever is longer,

unless applicable regulations require the records to be maintained longer.

Paragraph No. 132 of CD No. 10-cv-01042 requires that Shell submit to EPA and the Department a progress

report for the refinery on a semi-annual basis until termination of the Consent Decree.

• A summary of annual emissions data for the prior calendar year shall be submitted on July 31 of each

year and shall include SO2 emission in tons per year for the sulfur recovery plant.

• NOX, SO2, CO and PM emissions in tons per year as a sum for all other emission units for which emission

information is required to be included in Shell’s annual emission summary and are not identified in

Paragraph No. 132(b)(i) through (iv).

• The basis for each estimate required for recordkeeping (e.g., stack tests, CEMS, PEMS, etc.) and an

explanation of methodology used to calculate the tons per year emitted.

• In each semi-annual report, Shell shall identify each exceedance of an emission limit required or

established by the Consent Decree that occurred during the previous semi-annual period. The semi-

annual report shall include the information specified in Paragraph No. 132 (c)(i) through (ii).

• Each report shall be certified by Shell


Paragraph No. 37 of CD No. 10-cv-01042 states that after termination of the consent decree, the investigation

and corrective action procedures shall survive the consent decree. The root cause analysis and corrective action

analysis required under NSPS Ja will serve to demonstrate compliance with this requirement. The consent

decree also states that the reporting requirement specified in Paragraph No. 48 and the stipulated penalty

provisions found in Paragraph No. 40 shall not apply after termination of the consent decree. However, at the

time that the consent decree was written, Shell was not subject to NSPS Ja, which requires semi-annual

reporting. Therefore, the reporting requirements will still be applicable as required under §60.108a(d) of NSPS

Ja after termination of the consent decree.




STATEMENT OF BASIS

Page | 61

Paragraphs 28, 29, 30, 31 of Sections IV.C and Paragraphs 37, 38, and 39 of Sections IV.D. of CD No. 10-cv-01042

shall survive termination of the consent decree for the sulfur recovery plant as specified in Paragraph 213 of

the consent decree.

SRP/THERMAL OXIDIZER EMISSIONS

The following table summarizes emissions from the SRP during the 2020 Fee Inventory for 2019 Emissions for

criteria and total HAP emissions. Greenhouse Gas (GHG) emissions were obtained from the most recent permit

renewal application for the total carbon dioxide equivalent (CO2e) from the unit. Potential emissions were also

obtained from the most recent renewal application.

SRP/THERMAL OXIDIZER EMISSIONS

(TPY) (Metric TPY)

Emission Source PM2.5/PM10 SO2 NOX CO VOC CO2e

2019 FEES 0.0227 5.29 0.597 1.01 0.042

5,997

POTENTIAL EMISSIONS 0.19 35.2 1.3 2.14 0.14




STATEMENT OF BASIS

Page | 62





STATEMENT OF BASIS

Page | 63

STORAGE VESSEL REQUIREMENTS

This facility is equipped with storage vessels of varying sizes that are in VOC and/or HAP service. While these

vessels are subject to different, sometimes non-overlapping regulations, the overall work practice and

monitoring strategies are very similar. Therefore, these requirements will be consolidated into a single section,

although they will be separated in the permit. Also, each tank is designed to be able to store any product at the

refinery (unless limited by vapor pressure constraints) and meet the regulatory requirements under this section.

The applicable state and federal regulations for the storage vessels will be addressed in the following section:

STATE REGULATIONS

EMISSION


EMISSION

LIMIT REGULATIONS

Barge loading dock, truck loading rack,

storage vessels, and process unit

equipment that were constructed prior

to and including 1981 expansion

VOC 1,781 Tons per 12

consecutive months

335-3-14-.05(3)

[Non-Attainment

Avoidance]

Applicability:


Areas”

The cumulative VOC emissions from the heaters and other emission sources constructed prior to and during

the 1981 expansion were limited because Mobile County was classified as non-attainment for VOC emissions

at that time. Emissions from the storage vessels listed below would be subject to this regulation. The total

emissions from affected storage vessels, the barge loading dock, the truck loading rack, and process unit

equipment are limited to 1,781 ton per 12 consecutive months of VOC. To comply with this regulation,

records of the tank throughput (gallons/year) and records of VOC emissions shall be calculated and

maintained for the affected storage vessels.

Petroleum Liquid Storage Vessels

T–101 T–204 T–803

T–102 T–205 T–804

T–107 T–206 T–805

T–108 T–207 T–806

T–201 T–208 T–807

T–202 T–209 T–808

T–203 T–210 T–103

T–501 T–212 T–105

T–502 T–110 T–106

T–503 T–111 T–109

T–504 T–211

T–505

T–506

T–507

T–508

T–801

T–802

T–104




STATEMENT OF BASIS

Page | 64

Applicability:


The storage tanks shall be subject to this regulation. Compliance with this subpart shall be meet by

maintaining records of the products stored and calculating emissions from the storage vessels. Semi-annual

periodic monitoring reports (PMRs) are required to be submitted to the Department to demonstrate

whether there were deviations from the permit requirements during the reporting period. An annual

compliance certification (ACC) is required to be submitted annually, within 60 days of the date of issuance

of the MSOP, to the Department and to EPA.

FEDERAL REGULATIONS


Applicability:


The storage vessels would be subject to the applicable requirements of this subpart. The applicable


Applicability:

40 CFR Part 60 Subpart K, “Standards of Performance for Storage Vessels from Petroleum Liquids” (NSPS

K)

STORAGE VESSELS W/ FIXED ROOF

T–104 210,000 gallons All Petroleum Products [NSPS K|Group 2 MACT CC] Comply w/MACT CC

T–204 1,050,000 gallons All Petroleum Products [NSPS K|Group 2 MACT CC] Comply w/MACT CC








STORAGE VESSELS W/ FIXED ROOF AND INTERNAL FLOATING ROOF




STORAGE VESSELS W/ EXTERNAL FLOATING ROOF














STATEMENT OF BASIS

Page | 65

NSPS K applies to VOC tanks (constructed, reconstructed, or modified after June 11, 1973 but before May

19, 1978) that store petroleum liquids and that have a design capacity of greater than 40,000 gallons. The

storage vessels at this plant that have a capacity greater than 65,000 gallons and were constructed or

modified after June 11, 1973 and prior to May 19, 1978 are subject to NSPS K.

The following storage tanks are subject to NSPS K; however, they are not subject to the control requirements

under NSPS K since they do not store a liquid with a true vapor pressure greater than 1.5 psia: T-104, T-204,

T-205, T-206, T-207, T-208, T-209, T-210, and T-212. There are no monitoring requirements for these tanks

under NSPS K provided that the Reid vapor pressure of the petroleum liquid stored is less than 1.0 psia and

the maximum true vapor pressure does not exceed 1.0 psia [§60.113(d)(1)]. These tanks are also classified

as Group 2 storage vessels under MACT CC. Overlap of NSPS K with MACT CC for Group 2 storage vessels

not subject to the control requirements under NSPS K are required to comply only with MACT CC

requirements [§63.640(n)(7)].

Each of the following tanks store petroleum liquids with a true vapor pressure greater than 1.5 psia but less

than 11.1 psia and are equipped with either an internal or external floating roof to comply with the control

requirements under NSPS K: T-201, T-202, T-203, T-501, T-502, T-503, T-504, T-505, T-506, T-507, T-508, T-

801 and T-802. These tanks are also classified under MACT CC as Group 1 storage vessels because of the

potential type of liquids stored in these tanks. All tanks that are subject to the control requirement under

NSPS K and are also classified as Group 1 storage vessels under MACT CC shall comply only with the

requirements found under MACT CC [§63.640(n)(5)].

The following tanks were previously subject to NSPS K; however, these units were modified and equipped

with internal floating roofs and are now subject to NSPS Kb as permitted under Air Permit No. X092: T-103,

T-105, T-106 and T-109.

After the compliance dates found in §63.640(h), there are no applicable requirements under this subpart for

NSPS K tanks, even though the tanks remain subject to this subpart. Compliance with §63.660 of MACT CC

shall satisfy the requirements of the subpart [§63.641(h), (n)].

Applicability:

40 CFR Part 60 Subpart Ka, “Standards of Performance for Storage Vessels from Petroleum Liquids”

(NSPS Ka)

STORAGE VESSELS W/ FIXED ROOF [NO CONTROLS]

T–807 3,360,000 gallon All Petroleum Product [NSPS Ka| Group 2 MACT CC]- Comply w/MACT CC

T–808 3,360,000 gallon All Petroleum Product [NSPS Ka| Group 2 MACT CC]- Comply w/MACT CC


T–110 210,00 gallon All Petroleum Product [NSPS Ka| Group 2 MACT CC]- Comply w/NSPS Ka

T–111 210,00 gallon All Petroleum Product [NSPS Ka| Group 2 MACT CC]- Comply w/NSPS Ka


T–101 210,00 gallon All Petroleum Product [NSPS Ka| Group 1 MACT CC]- Comply w/MACT CC





T–803 3,360,000 gallon All Petroleum Product [NSPS Ka| Group 1 MACT CC]-Comply w/MACT CC







STATEMENT OF BASIS

Page | 66

NSPS Ka applies to all petroleum liquid storage vessels with a capacity greater than 40,000 gallons and

constructed, reconstructed, or modified after May 18, 1978, but before July 23, 1984. To demonstrate

compliance with NSPS Ka, the emission standards found in §60.112a through §60.114a or the alternative

means of compliance found in 40 CFR 65 subpart C and as specified in §60.110a(c)(1) and (2) shall be met.

T-807 and T-808 meet the capacity requirements found under NSPS Ka; however, they are not expected to

contain a petroleum liquid with a maximum true vapor pressure (TVP) greater than 1.5 psia. According to

correspondence in the facility file, only vacuum oil is allowed to be stored in these tanks. Therefore, there

are no control requirements or monitoring requirements under this subpart for these tanks [§60.115a(d)(1)].

These tanks are also classified as Group 2 tanks under MACT CC. Overlap of MACT CC with NSPS Ka tanks

not subject to the control requirements under NSPS Ka, requires that the tanks comply only with the

requirements of §63.660 of MACT CC after the compliance date specified in §63.640(h) [§63.640(n)(7)]

Each of the following tanks stores petroleum liquids with a true vapor pressure greater than 1.5 psia but less

than 11.1 psia and is equipped with either an internal or an external floating roof to comply with the control

requirements under NSPS Ka: T-101, T-102, T-107, T-108, T-803, T-804, T-805, and T-806. These tanks are

also classified under MACT CC as Group 1 storage vessels. All tanks that are subject to NSPS Ka and classified

as Group 1 storage vessels under MACT CC shall comply only with the requirements found under MACT CC

[§63.640(n)(5)].

T-110 and T-111 are each equipped with an internal floating roof since the maximum TVP of the petroleum

liquid stored in these tanks is expected to be greater than or equal to 1.5 psia but less than 11.1 psia. The

requirements specified in §60.112a(a)(2) shall be met for these tanks. These tanks are also classified as

Group 2 tanks under MACT CC. Because there is overlap with MACT CC and NSPS Ka and the tanks are

subject to the control requirements under NSPS Ka, the facility is required only to comply with NSPS Ka

except as allowed under §63.640(n)(9)(i) through (iv) [§63.640(n)(6)].

Under NSPS Ka, storage vessels are required to comply with the emissions standards for VOC emissions found

in §60.112a, comply with the testing and procedures specified in §60.113a, when applicable, and comply

with the monitoring requirements specified in §60.115a. The refinery can also elect to comply with

alternative means of emission limitation as allowed under §60.114a.

A record of the liquid stored, period of storage, and the maximum true vapor pressure of the liquid during

the respective storage period shall be maintained for each tank [§60.115a(a)].

Compliance the requirements above and the applicable requirements specified in §63.640(n)(6), shall satisfy

compliance with NSPS Ka and MACT CC.

Applicability:

40 CFR Part 60 Subpart Kb, “Standards of Performance for Storage Vessels from Petroleum Liquids”

STORAGE VESSELS W/ FIXED ROOF [NO CONTROLS] | NEW SOURCES

T-1201 5,250,000 gallon All Petroleum Products [NSPS Kb| Group 2 MACT CC]- Comply w/MACT CC







STATEMENT OF BASIS

Page | 67

STORAGE TANKS CONSTRUCTED PRIOR TO OR DURING THE 1981 EXPANSION

STORAGE VESSELS W/ FIXED ROOF AND INTERNAL FLOATING ROOF| EXISTING SOURCES

T–103 210,000 gallon All Petroleum Products [NSPS Kb| Group 2 MACT CC]- Comply w/NSPS Kb

T–105 210,000 gallon All Petroleum Products [NSPS Kb| Group| 2 MACT CC]- Comply w/NSPS Kb



T–211 1,050,000 gallon All Petroleum Products [NSPS Kb| Group 1 MACT CC]- Comply w/MACT CC

NSPS Kb applies to all volatile organic liquid storage vessels with a capacity greater than or equal to 19,812.9

gallons and constructed, reconstructed, or modified after July 23, 1984. §60.110b(b) exempts storage

vessels with a capacity greater than 151 cubic meters (~39,890 gallons) storing a liquid with a maximum TVP

less than 3.5 kPa (~0.5 psia) from complying with the requirements of NSPS Kb. The following tanks have a

design capacity greater than or equal to 39,890 gallons: T-103, T-105, T-106, T-109, T-211, T-1201, T-1202,

T-1203, and T-1204. However, only the T-211, T-1201, T-1202, T-1203, and T-1204 could possibly meet

exemption from NSPS Kb as discussed below.

Existing tanks T-103, T-105, T-106, and T-109 are each expected to store a petroleum liquid with a maximum

TVP greater than or equal to 0.754 psia but less than 11.1 psia. As a result, these units are equipped with an

internal floating roof to comply with the control requirements found under §60.112b of NSPS Kb. After the

compliance dates specified in §63.640(h), overlap of these storage vessels with the Group 2 storage vessels

requirements under MACT CC shall require compliance with NSPS Kb, except as specified in §63.640(n)(8) of

MACT CC [§63.640(n)(1),(8)].

The T-1201, T-1202, T-1203, and T-1204 storage vessels are considered new sources since they were installed

in 1994 (the application does not specify if this was before or after the compliance date for new sources of

July 14, 1994) [§63.640(i), (n)(3)]. The liquids stored in tanks T-1201, T-1202, T-1203, and T-1204 were not

allowed to exceed a maximum TVP of 0.011 psia; therefore, no controls were required to comply with NSPS

Kb for these units. Provided that these tanks are new sources and subject to NSPS Kb, but are not required

to be equipped with controls, or if they are exempt from NSPS Kb, these storage vessels must comply with

MACT CC as Group 2 tanks [§63.640(n)(3)].

Depending on the max TVP of the liquid stored in Tank T-211, the tank could meet exemption under NSPS

Kb. Regardless of if Tank T-211 meets the exemption under §60.110b(b) of NSPS Kb or not, it would still

meet the definition of a Group 1 storage vessel part of an existing source as specified in §63.641 of MACT

CC. Overlap of MACT CC with NSPS Kb for Group 1 storage vessels part of an existing source requires that

the requirements of NSPS Kb are met except as specified in §63.640(n)(8) of MACT CC [§63.640(n)(1)] or the

requirements of MACT CC can be met [§63.640(n)(2),(8)]. Shell elected to comply with MACT CC for this

storage vessel.

To demonstrate compliance with NSPS Kb the emission standards found in §60.112b, testing and procedures

found in §60.113b, alternative means of emission limitations requirements found in §60.114b, reporting and

recordkeeping requirements found in §60.115b, and monitoring requirements found in §60.116b shall be

met. Applicability to the emission standards is based on the volume of liquid stored and the maximum true

vapor pressure (MVP) of the stored liquid.




STATEMENT OF BASIS

Page | 68


Applicability:


The storage vessels would be subject to the applicable requirements of this subpart. The applicable


Applicability:

40 CFR 63 Subpart CC, “National Emission Standards for HAPs from Petroleum Refineries”

EMISSION


EMISSION


VOLATILE ORGANIC LIQUID STORAGE VESSELS OHAP Closed vent system w/95%

OHAP reduction or Install

floating roof w/seals and

maintain seals

§63.660(a)

[MACT CC]

STORAGE VESSELS W/ FIXED ROOF

T–104 210,000 gallon All Petroleum Products [NSPS K| Group 2 MACT CC] -Comply w/MACT CC

T-114 33,838 gallon All Petroleum Products [Group 2 MACT CC] -Comply w/MACT CC

T–204 1,050,000 gallon All Petroleum Products [NSPS K| Group 2 MACT CC]- Comply w/MACT CC








T–807 3,360,000 gallon All Petroleum Products [NSPS Ka| Group 2 MACT CC]- Comply w/MACT CC

T–808 3,360,000 gallon All Petroleum Products [NSPS Ka| Group 2 MACT CC]- Comply w/MACT CC









T–101 210,00 gallon All Petroleum Products [NSPS Ka| Group 1 MACT CC]- Comply w/MACT CC




T–211 1,050,000 gallon All Petroleum Products [NSPS Kb| Group 1 MACT CC]- Comply w/MACT CC










STATEMENT OF BASIS

Page | 69











This regulation contains requirements for storage vessels associated with petroleum refining process units

located at a petroleum refinery that is a major source of HAPs [§63.640(a), & (c)(2)]. To determine whether

the storage vessels are part of a source to which MACT CC applies, the procedures specified in §63.640(e)

shall be used. Overlap of MACT CC with NSPS K, Ka and Kb for the tanks listed above has indicated that each

of these tanks are required to comply only with the requirements for storage vessels found in §63.660 of

MACT CC.

This regulation contains requirements for storage vessels associated with petroleum refining units and bulk

gasoline service located at a petroleum refinery that is a major source of HAPs [§63.640(a), & (c)(2) & (7)].

§63.641 defines Group 1 and Group 2 storage vessels based on when the tanks meet the definition, either

prior to February 1, 2016 or on or after that date. The definitions have been redefined since the last renewal.

Since the compliance dates specified in §63.640(h) have passed, the requirements of §63.646 no longer

apply. Group 1 tanks must now comply with §63.660 of MACT CC.

EMISSION STANDARDS:

Group 1 Storage vessels that are part of a new or existing source storing liquids with a maximum true vapor

pressure (TVP) less than 76.6 kilopascals (11.1 pounds per square inch) must comply with the requirements

of 40 CFR 63, Subpart WW, “National Emission Standards for Storage Vessels (Tanks)-Control Level 2”

[NESHAP WW] OR 40 CFR 63 Subpart SS, “National Emission Standards for Closed Vent Systems, Control

Devices, Recovery Devices and Routing to a Fuel Gas System or a Process” [NESHAP SS], as referenced in

MACT CC [§63.660, §63.660(a)-(i)]. Shell has elected to comply with the control requirements specified

under NESHAP WW.

For a Group 1 storage vessel that is part of a new or existing source storing liquid with a maximum true vapor

pressure greater than or equal to 76.6 kilopascals (11.1 pounds per square inch), the requirements specified

in NESHAP SS shall be met at all times according to the requirements specified in §63.660(a) through (i) of

MACT CC. Currently, Shell does not store any liquids that meet these requirements.

For an uncontrolled fixed roof storage vessel that commenced construction on or before June 30, 2014, and

that meets the definition of “Group 1 storage vessel”, paragraph (2), in §63.641 but not the definition of

“Group 1 storage vessel”, paragraph (1), in §63.641, the requirements of §63.982 of NESHAP SS and/or

§63.1062 of NESHAP WW do not apply until the next time the storage vessel is completely emptied and

degassed, or January 30, 2026, whichever occurs first.

Group 1 storage vessels with a maximum TVP less than 11.1 psia are equipped with either an internal or

external floating roof. The maximum true vapor pressure (TVP) of the liquid stored in each tank is expected

to be less than or equal to 11.1 psia. Shell has elected to comply with §63.1062 of subpart WW to comply

with MACT CC. The floating roofs must meet the design and operational requirements under §63.1063 of

subpart WW. The requirements of §63.1062 of Subpart WW do not apply until the next time the storage

vessel is completely emptied and degassed, or January 30, 2016 if the requirement specified in §63.660(d)




STATEMENT OF BASIS

Page | 70

of MACT CC are met for uncontrolled fixed roof storage tanks that commenced construction on or before

June 30, 2014.


Monitoring for internal floating roof tanks can be met by performing tank top visual inspections of the

floating roof at least once per year. Monitoring for the external floating roof tanks shall be met by conducting

inspections of the primary and secondary seals within 90 days after initial filling and by conducting seal gap

inspections of the secondary seal at least once per year and the primary seal at least every five years. Seal

gap inspections on external floating roof tanks must comply with the procedures specified in

§60.1063(d)(3)(i). Failure to perform inspections and monitoring is deemed a violation under this subpart.


Records of vessel dimensions and capacity, inspection results, and floating roof landings shall be maintained

for Group 1 tanks. Records specified in §63.1065(a) shall be maintained for Group 2 tanks. The records must

be maintained for 5 years and readily available for inspections.

Applicability:

40 CFR 63 Subpart SS, “National Emission Standards For Closed Vent Systems, Control Devices, Recovery

Devices And Routing To A Fuel Gas System Or A Process” [NESHAP SS]

The requirements of this subpart are applicable by reference as specified in MACT CC for Group 1 storage

vessels part of a new or existing source storing liquid with a maximum true vapor pressure (TVP) greater

than or equal to 76.6 kilopascals (11.1 pounds per square inch (psi)). These storage vessels shall comply with

the requirements specified in NESHAP SS according to the applicable requirements specified in §63.660(a)

through (i) of MACT CC. Since the maximum TVP of the liquid stored in any of the tanks at the refinery are

not greater than or equal to 11.1 psi, NESHAP WW will be used to comply with MACT CC.



“Group 1 storage vessel”, paragraph (1), in §63.641, the requirements of §63.982 of NEHAP SS do not apply

until the next time the storage vessel is completely emptied and degassed, or January 30, 2026, whichever

occurs first.

Applicability:

40 CFR 63, Subpart WW, “National Emission Standards for Storage Vessels (Tanks)-Control Level 2”

[NESHAP WW]

The requirements of this subpart are applicable by reference as specified in MACT CC for Group 1 storage

vessels part of a new or existing source storing liquid with a maximum true vapor pressure less than 76.6

kilopascals (11.1 pounds per square inch). These storage vessels shall comply with the requirements in

NESHAP WW according to the applicable requirements specified in §63.660(a) through (i) of MACT CC.



“Group 1 storage vessel”, paragraph (1), in §63.641, the requirements of §63.982 of NESHAP WW do not

apply until the next time the storage vessel is completely emptied and degassed, or January 30, 2026,

whichever occurs first.




STATEMENT OF BASIS

Page | 71

Applicability:

40 CFR 63, Subpart EEEE, “National Emission Standards for Hazardous Air Pollutants: Organic Liquids

Distribution (Non-Gasoline)”

The crude oil storage vessels are subject to Group 2 storage vessel requirements under MACT CC so they are

excluded from compliance with this subpart [§63.2338(c)(1)].

Applicability:

40 CFR 63 Subpart BBBBBB, “National Emission Standards for Hazardous Air Pollutants for Source

Category: Gasoline Distribution Bulk Terminals, Bulk Plants, and Pipeline Facilities”

This regulation contains requirements for storage vessels associated with gasoline service located at bulk

gasoline terminals, bulk gasoline plants, and pipeline facilities. However, per §63.11081(a)(1), facilities

subject to the requirements of 40 CFR 63 Subpart CC are exempt. Since this facility is subject to 40 CFR 63

Subpart CC, this regulation does not apply.


This subpart is applicable to an emissions source provided the source meets the following criteria: it is

subject to an emission limit or standard, it uses a control device to achieve compliance with the emissions

limit or standard, and it has pre-controlled emissions from a regulated air pollutants that are equal to or

greater than 100 percent of the amount, in tons per year, required for a source to be classified as a major

source (40 CFR §64.2(a)). However, per §64.1, a “control device” does not include the use of seals or roofs.

Therefore, these tanks are not subject to CAM.

STORAGE TANK EMISSIONS

Tank emissions were based on the type of liquid stored in the tanks at the time the 2020 Emissions Inventory

was complete for 2019 Emissions. The potential emissions were obtained from the most recent MSOP renewal

application.

STORAGE TANK EMISSIONS

(TPY) (Metric TPY)

VOC TOTAL HAP CO2e

ACTUAL 2019 EMISSION 46.6 2.27

7,901,550 POTENTIAL EMISSIONS 59.83 1.1




STATEMENT OF BASIS

Page | 72





STATEMENT OF BASIS

Page | 73

EQUIPMENT IN VOC AND HAPS SERVICE REQUIREMENTS

Emission

Point

Description Pollutant Emission

Limit

Regulations

Fugitive OHAP and VOC emitting pieces of equipment

including each valve, flange, pump, pressure relief device,

sampling connection system, open-ended valve or line,

flange or other connector constructed, reconstructed, or

modified between January 4, 1983 and November 7, 2006.

Individual Process Units include:

De-isopentanizing Unit

Gasoline Loading Rack & Tanks

Reformate Splitting Unit

Olefin Feed Hydrotreating Unit

Crude unit(s)

Hydrodesulfurization Unit(s)

Reforming Unit(s)

Vacuum Unit

De-isobutanizer Unit

Merox Unit

Naphtha Splitter Unit

Sour gas sweetening Unit

Sour Water Stripping Unit

LPG Treating Unit

KOH Caustic Unit

Bender Treating Unit

De-ethanizing Unit

Light ends Unit

Sulfur Conversion Unit

Scot Tail Gas Unit

Refinery Emergency Flare

OFH Emergency Flare

OHAP

&

VOC

LDAR Program

§60.590

[NSPS GGG]

§63.640(c)(4)

§63.640(p)(1)

[MACT CC/NSPS GGG]

Heaters, barge loading dock, truck loading rack, storage,

vessels and process unit equipment constructed prior to or

during the 1981 expansions. Process unit equipment

includes equipment from the following process units:

Crude unit(s)

Hydrodesulfurization Unit(s)

Reforming Unit(s)

Vacuum Unit

De-isobutanizer Unit

Merox Unit

Naphtha Splitter Unit

Sour gas sweetening Unit

Sour Water Stripping Unit

LPG Treating Unit

KOH Caustic Unit

Bender Treating Unit

De-ethanizing Unit

Light ends Unit

Sulfur Conversion Unit

Scot Tail Gas Unit

VOC

<1,781 TPY Rule 335-3-14-.05(3)

[Non-attainment Avoidance]




STATEMENT OF BASIS

Page | 74

STATE REGULATIONS

Applicability:

ADEM Admin. Code r. 335-3-6-.21 “Leaks from Petroleum Refinery Equipment”

This facility would be subject to the requirements of this regulation; however, the facility is also subject to

federal regulations found under NSPS GGG and MACT CC. Since the required monitoring and controls are

the same as those required by the federal regulations, compliance with the federal regulations will satisfy

this regulation as allowed under §63.640(q) of MACT CC.

Applicability:

ADEM Admin. Code R. 335-3-6-.09, “Pumps & Compressors” at Petroleum Refineries in Mobile Co.

This regulation applies to pumps and compressors located at petroleum refineries located in Mobile County.

However, compliance with the federal Leak Detection and Repair [LDAR] standards in MACT CC and/or NSPS

GGG will satisfy this regulation, per §63.640(q).

Applicability:


Areas”

As previously stated, at the time of the 1981 expansion, Mobile County was declared non-attainment for

ozone.

EMISSIONS STANDARDS:

To avoid non-attainment, a facility wide limit of 1,781 tons per 12 consecutive months of VOC emissions

was requested for the heaters, barge loading dock, truck loading rack, storage, vessels and process unit

equipment which were constructed prior to and during the 1981 expansion.

During the expansion, the facility implemented its own program of inspection and maintenance on the

fugitive equipment leaks of VOC emissions since NSPS GGG had not yet been promulgated. However, the

CD No. 10-cv-01042 now requires that the facility comply with the applicable leak detection and repair

(LDAR) requirements specified in NSPS GGG, 40 CFR 61, Subpart J and V, 40 CFR 63, Subparts F, H, and CC

and any state and local LDAR requirements that are federally enforceable or implemented.


One of the following methods and procedures shall be used to determine fugitive VOC emissions from

equipment leaks from equipment constructed prior to and during the 1981 expansion:

• Section 2.3.1 (Average Emission Factor Approach) of Chapter 2 in EPA’s “Protocol for Equipment

Leak Emission Estimates EPA-453/R-95-017, Nov 1995” document.

• Section 2.3.2 (Screening Ranges Approach) of Chapter 2 in EPA’s “Protocol for Equipment Leak

Emission Estimates EPA-453/R-95-017, Nov 1995” document.

• Section 2.3.3 (Correlation Approach) of Chapter 2 in EPA’s “Protocol for Equipment Leak

Emission Estimates EPA-453/R-95-017, Nov 1995” document.




STATEMENT OF BASIS

Page | 75

• Section 2.3.4 (Unit Specific Correlation Approach) of Chapter 2 in EPA’s “Protocol for Equipment

Leak Emission Estimates EPA-453/R-95-017, Nov 1995” document.

• Other methods approved by the Department.

EMISSIONS MONITORING:

Emission monitoring shall be met by complying with an applicable LDAR program.


To comply with the VOC emission limit, the facility is required to maintain a record of the VOC emissions

from each of the affected sources covered prior to and during the 1981 Expansion.

Applicability:


Equipment leaks from each affected piece of equipment located within each process unit shall be subject

to this regulation. Semi-annual periodic monitoring reports (PMRs) are required to be submitted to the

Department to demonstrate whether there were deviations from the permit requirements during the

reporting period. An annual compliance certification (ACC) is required to be submitted annually, within 60

days of the date of issuance of the MSOP, to the Department and to EPA.

FEDERAL REGULATIONS


Applicability:

40 CFR 60 subpart A, “General Provisions” (Subpart A)

The applicable requirements of subpart A, shall be met as specified in §60.486(k) of NSPS VV to comply with

NSPS GGG.

Applicability:

40 CFR 60 Subpart VV, “Standards of Performance for Equipment Leaks of VOC in the Synthetic Organic

Chemicals Manufacturing Industry” (NSPS VV)

Per §60.592, compliance with NSPS GGG shall be demonstrated by complying with the applicable

requirements under NSPS VV by reference, except as required by §60.593 of NSPS GGG.

Applicability:

40 CFR 60 Subpart GGG, “Standards of Performance for Equipment Leaks of Volatile Organic

Compounds (VOC) from Petroleum Refineries” (NSPS GGG)

The requirements of 40 CFR 60 Subpart GGG [NSPS GGG] apply to petroleum refineries constructed,

reconstructed, or modified between January 4, 1983 and November 7, 2006. Affected sources include each

compressor, valve, flange, pump, pressure relief device, sampling connection system, open-ended valve or

line, flange or other connector [§60.590]. The affected sources were constructed prior to promulgation of

this subpart; however, Section IV.K. of CD No. 10-cv-01042 now requires that the facility comply with the

requirements of NSPS GGG for fugitive emissions of VOC, benzene, volatile hazardous air pollutants (VHAP),




STATEMENT OF BASIS

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and organic hazardous air pollutants [OHAP] from valves and pumps in light liquid and/or gas/vapor service.

The consent order also makes all other affected facilities in VOC service subject to NSPS GGG.

Equipment leaks that are subject to NSPS GGG for equipment in VOC service and are also subject to MACT

CC for equipment in HAPs service are required to comply only with the provisions specified in MACT CC

[§63.640(c)(4) and §63.640(p)(1)]. After termination of the Consent Decree, equipment leaks must comply

with MACT CC requirements only.

EMISSION STANDARDS:

Except as specified in §60.593, the standards specified in §60.592 shall be met as follows:

• The requirements specified in §60.482-1 to §60.482-10 of 40 CFR 60 Subpart VV, “Standards of

Performance for Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing

Industry” [NSPS VV] shall be met.

• Valves in gas/vapor service and in light liquid service may elect to comply with the alternative

monitoring standards found in §60.592(b) of NSPS GGG instead of those found in §60.482-7.

• The facility may request to comply with an equivalence of means of emission limitation as specified

in §60.484 of NSPS VV.


Monitoring shall be conducted at the frequency specified in 60.482-1 to §60.482-10 of NSPS VV.

COMPLIANCE TEST AND PROCEDURES:

Except as specified in §60.593 of NSPS GGG, the test methods and procedures specified in §60.485 of NSPS

VV shall be met. EPA Method 21 shall be used to determine the presence of a leaking source.


The recordkeeping requirements specified in §60.486 of NSPS VV and the reporting requirements specified

in §60.487 of NSPS VV shall be met to demonstrate compliance with NSPS GGG.

Applicability:

40 CFR 60 Subpart GGGa, “Standards of Performance for Equipment Leaks of Volatile Organic

Compounds (VOC) from Petroleum Refineries”

The requirements of 40 CFR 60 Subpart GGGa [NSPS GGGa] apply to petroleum refineries constructed,

reconstructed, or modified after November 7, 2006. The sulfur recovery plant and refinery flare have been

modified after this date; however, the fugitive leak components associated with these units were not

modified during this project. Therefore, the equipment for these units will continue to be covered under

NSPS GGG.


Applicability:


This subpart is applicable to equipment leaks from petroleum refining units located at a major source and

that emit or have equipment containing or contacting one or more of the HAPs listed in Table 1 of MACT

CC [§63.640(c)(4)]. However, the refinery is subject to the requirements in NSPS GGG for fugitive




STATEMENT OF BASIS

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equipment leaks per the consent decree for existing sources. After termination of the consent decree,

compliance with the requirements under MACT CC will be required to be met [§63.640(p)(1)].

If affected facilities become subject to equipment leak standards under NSPS GGGa and they are subject to

MACT CC, compliance only with NSPS GGGa will be required except that pressure relief devices in organic

HAP service must only comply with the requirements in §63.648(j) [§63.640(p)(2)].


For a unit to be subject to CAM, it must have an emission limit, use a control device, and be considered a

major source. None of the individual equipment would be considered a major source of emissions;

therefore, CAM would not be applicable for these sources.


Section IV.K: Leak Detection and Repair Program

Section IV.K. A. Subparagraph 85 requires that Shell implement the requirements of CD No. 10-cv-01042 as

part of its leak detection and repair (LDAR) program to minimize or eliminate fugitive emissions of volatile

organic compound (VOCs), benzene, volatile hazardous air pollutants (VHAPs), and organic hazardous air

pollutants from valves and pumps in light liquid and/or gas/vapor service. This includes compliance with

40 CFR 60 Subparts VV and GGG; 40 CFR 61 Subparts J and V; 40 CFR 63 Subpart F, H, and CC and any

applicable state and local LDAR requirements that are federally enforceable or implemented by the

Department. The facility was required to implement the requirements of the consent decree on October

28, 2010 for all affected facilities under LDAR Regulations as of March 31, 2010. By September 30, 2010, all

existing facilities that were not already subject to the LDAR Regulations as of March 31, 2010 and all facility

subsequently added to the refinery are required to become an affected facility under 40 CFR 60 subpart

GGG and Section IV.K. of CD No. 10-cv-01042 regardless of whether such facilities have been constructed,

modified, or reconstructed prior to this date. All such facilities are required to remain affected facilities

after termination of the consent decree.

A written Refinery-Wide Leak Detection and Repair (LDAR) program that complies with the requirements

specified in Section IV.K of CD No. 10-cv-01042 was developed and implemented in accordance with the

schedule therein. (See plan submitted June 29, 2010 and the attached consent decree in Appendix D of the

permit).

FUGITIVE EMISSIONS

The fugitive emissions from all emission sources located at the facility are summarized in the table below for

2019 emissions. The potential to emit (PTE) VOC and Total HAP emissions were obtained from the most recent

renewal permit application.

TOTAL FUGITIVE EMISSIONS

(TPY) (Metric TPY)

VOC Benzene Ethyl

benzene Cyclohexane N-Hexane Toluene 1,2,4 TMB Xylene CO2e

4.42 0.223 0.0004 0.00 0.00 0.0122 0.00 0.002

370 181

PTE

1.95

Total HAPs PTE




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WASTEWATER REQUIREMENTS

This facility is equipped with a wastewater treatment plant (WWTP) which is designed to process wastewater

from any process unit at the facility.

STATE REGULATIONS

Applicability:

ADEM Admin. Code r. 335-3-6-.08(2) and (4) “Petroleum Refinery Sources”

This regulation requires all oil/water separators to be equipped with seals, lids, etc. to limit wastewater VOC

emissions. Since the required controls are the same as those required by NSPS QQQ, compliance with NSPS

QQQ will satisfy this regulation. This is allowed under 40 CFR §63.640(q).

FEDERAL REGULATIONS


Applicability:

40 CFR 60 Subpart QQQ, “Standards of Performance for VOC Emissions from Petroleum Refinery

Wastewater Systems” (NSPS QQQ)

This regulation is applicable to each individual drain system, oil-water separator, and aggregate facility

located at a petroleum refinery that was constructed, modified, or reconstructed after May 4, 1987. The

1200, DIB, and OFH Individual drain systems and the oil-water separating systems would be subject to the

requirements of this subpart. Storm water sewer systems, ancillary equipment which is physically separated

from the wastewater system and does not come in contact with or store oily wastewater, and non-contact

cooling water systems are not subject to the requirements of this subpart. However, compliance with these

exclusions shall be demonstrated as specified in §60.697 (h), (i) and (j) [§60.692-1 (d)(1)-(4)].

EMISSION STANDARDS:

The standards specified in §60.692-1 through §60.692-5 and in §60.693-1 and §60.693-2 shall be met except

during periods of startup, shutdown, or malfunction [§60.692-1]. The facility may elect to use the alternative

means of emission limitation to meet the requirements of §60.692-2 through §60.692-4 as provided in

§60.694. Per §60.692-3(d), storage vessels, including oil-water separation tanks subject to NSPS K, Ka, or Kb

are not subject to the requirements of §60.692-3 in NSPS QQQ.


Compliance with §60.692-1 to 60.692-5 and with §60.693-1 and 60.693-2 will be determined by review of

records and reports, review of performance test results, and inspections using the methods and procedures

specified in §60.696.


Provided that a control device is used to reduce VOC emissions, the monitoring requirements specified in

§60.695 shall be met.





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The recordkeeping requirements specified in §60.697 and the reporting requirements specified in §60.698

shall be met to demonstrate compliance with NSPS QQQ.


Applicability:

40 CFR 61, subpart FF “National Emission Standard for Benzene Waste Operations” (BWON/NESHAP FF)

Shell is subject to the requirement of this subpart by reference in the Consent Decree.

If the total annual benzene (TAB) from facility waste is less than 10 mega grams per year (Mg/yr)( ~11 tons

per year), the TAB waste quantity shall be determined annually as specified in §61.342(a). Shell has

demonstrated that their TAB is less than 10 Mg/yr. The facility is required to submit an annual TAB calculation

covering a 12-month period.

If the TAB quantity from facility waste is greater than or equal to 10 Mg/yr as determined in §61.342(a), the

facility waste shall be managed and treated as specified in §61.342(e) of NESHAP FF and as specified in Section

IV.I subparagraph 54 of CD No. 10-cv-01042. The emission monitoring requirements specified in §61.354 of

NESHAP FF and the test methods and procedures specified in §61.355 of NESHAP FF shall be complied with.

The reporting requirements specified in §61.357 (d) of NESHAP FF shall be met along with the requirements

in the consent decree.

After termination of the consent decree, Shell will be required to comply with the wastewater requirements

under MACT CC for Group 2 wastewater streams if it receives streams also subject to the wastewater

provisions under 40 CFR 63 Subpart G or continue to comply with the requirement under NSPS QQQ for Group

2 streams [§63.640(o), MACT CC].

Applicability:


This regulation is applicable to all wastewater stream and treatment operations associated with petroleum

refining process units that are located at a major source of HAPs and emit or come into contact with a

regulated HAP. Per §63.647, to comply with this subpart, the requirements in the BWON shall be met for

each Group 1 wastewater stream meeting the definition under §63.641. Storm water from segregated storm

water sewers are not affected sources under MACT CC.

Overlap of MACT CC with other wastewater regulations are discussed in §63.640(o) of MACT CC. Since the

wastewater streams at the refinery are only Group 2 wastewater streams under MACT CC, compliance with

NSPS QQQ is required to be met.. There are no requirements under MACT CC for Group 2 wastewater

streams unless they are included in emissions averaging. Group 1 wastewater streams are required to comply

only with the requirements under MACT CC; however, since there are no Group 1 water streams

requirements will not be discussed in further detail.


For a unit to be subject to CAM, it must have an emission limits, have a control device used to meet the

emissions limit, and be considered a major source. However, per §64.1, a “control device” does not include

the use of seals or roofs. Therefore, the wastewater treatment plant is not subject to CAM.




STATEMENT OF BASIS

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Section IV.I: Benzene Waste NESHAP Program

In addition to complying with the requirements of NESHAP FF, Shell is required to comply with the

requirements specified in Section IV.I of the consent decree to minimize or eliminate fugitive benzene waste

emissions. In the onetime review of the facility’s TAB required under Section IV.I subparagraph 55 of the

consent decree, the facility demonstrated that its TAB emissions are less than 10 Mg/yr (see Benzene Waste

NESHAP Compliance and Review and Verification Report Program dated March 29, 2011). However, if the

facility’s compliance status changes and the TAB emissions become greater than or equal to 10 Mg/yr, the

requirements specified in 40 C.F.R. § 61.342(e) (“6 BQ Compliance Option”) are required to be met as

specified in Section IV.I subparagraph 54 of the consent decree.

WASTEWATER EMISSIONS

The 2019 actual emissions from the overall wastewater treatment collection system are summarized in the table

below.

WASTEWATER TREATMENT PLANT EMISSIONS

(TPY)

SYSTEM VOC HAPS

TOTAL EMISSIONS 139.197 5.419




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HEAT EXCHANGE SYSTEM [COOLING TOWERS] REQUIREMENTS

EMISSION


EMISSION

LIMIT REGULATIONS

Closed-loop Recirculation Systems :

Cooling Tower

Heat exchangers serviced by that

cooling tower

All water lines to and from the heat

exchanger(s)

the heat exchanger(s)

OHAP Leaks from sampling

locations shall not exceed

the applicable leak action

levels:

For existing sources, the leak

leak action level is 6.2 ppmv

total strippable

hydrocarbon concentration

(as methane) in the stripping

gas

Or

3.1 ppmv total strippable

hydrocarbon concentration

(as methane) in the stripping

gas monitored quarterly

unless repair is delayed

For new sources, the leak

action level monitored

monthly is 3.1 ppmv total

strippable hydrocarbon

concentration (as methane)

in the stripping gas

§63.654(a), (c)(1), (4),

(5)

[MACT CC]

Individual Sources:

Cooling Tower #1/100



Cooling Towers are used to supply treated cooling water to the process coolers and condenser to remove heat

from the various process streams. They remove heat from the return water from the heat exchangers in order

to supply treated cooling water for the supply stream. The heat exchange systems at the Shell Plant consist of

three re-circulating cooling towers. Cooling Tower #2 has sampling performed on units 2A and 2B; however,

there is only one emission point for both units. Applicability to State and Federal regulation will be discussed

in the following section:

STATE REGULATIONS

Applicability:


The cooling towers would be subject the state 20%/40% opacity standards to control particulate emission.

PM emissions are not expected to exceed these standards; however, if this does occur, Method 9 or Method

22 of 40 CFR 60, appendix A shall be used to demonstrate compliance with the standards.

Applicability:




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ADEM Admin. Code R. 335-3-16, “Major Source Operating Permits”

The cooling towers are located at a facility that is a major source of criteria pollutant, a major source of HAPs,

and a major source of GHG. To comply with this regulation, a periodic monitoring report (PMR) is required

to be submitted on a semi-annual calendar basis to report deviations from permit requirements, and annual

emissions shall be submitted. An annual compliance certification (ACC) is required to be submitted annually

with 60 days of the issuance of the permit.

FEDERAL REGULATIONS


Applicability:

40 CFR 63 subpart A, “General Provisions” [Subpart A]

The requirements of this subpart shall be met as specified in Table 6, of MACT CC.

Applicability:


This regulation is applicable to affected sources that are located a petroleum refinery that is a major source

of HAPs and that have equipment containing or contacting one or more of the HAPs listed in Table 1 of this

subpart [§63.654]. The heat exchange system associated with the petroleum refining process units which

are in OHAP service would be subject to this subpart. The facility’s heat exchange system is a closed–loop

recirculation system. This system consists of a cooling tower, all heat exchangers serviced by that cooling

tower, and all water lines to and from the heat exchanger(s) sources [§63.641, §63.640(a)(1), (a)(2) and

(c)(8)].

EMISSION STANDARDS:

Except as specified in §63.654(b), each heat exchange system (cooling tower) shall meet the requirements

specified in §63.654 of MACT CC.


The “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) using a flame ionization detector (FID) analyzer for on-

site determination as described in Section 6.1 of the Modified El Paso Method shall be used to determine he

total strippable hydrocarbon concentration (in parts per million by volume (ppmv) as methane) at each

monitoring location [§63.654(c)(3)].

EMISSION MONITORING REQUIREMENTS:

The following monitoring requirements shall be met:

• For monitoring for each closed loop recirculating heat exchange system, collect and analyze a sample

from each cooling tower return line or any representative riser within the cooling tower prior to

exposure to air for each heat exchange system or selected heat exchanger exit line(s) so that each

heat exchanger or group of heat exchangers within a heat exchange system is covered by the

selected monitoring location(s) [§63.654(c)(1)].




STATEMENT OF BASIS

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• The monitoring frequency and leak action level for existing sources shall be met as follows

[§63.654(c)(4)]:

ο Monitor monthly using a leak action level defined as a total strippable hydrocarbon

concentration (as methane) in the stripping gas of 6.2 ppmv OR

ο Monitor quarterly using a leak action level defined as a total strippable hydrocarbon

concentration (as methane) in the stripping gas of 3.1 ppmv unless repair is delayed as

provided in §63.654(f), then monitor monthly.

• Shell is not currently equipped with any new sources, however, if new sources are installed the

monitoring frequency and leak action levels specified in §63.654(c)(5) shall be met.

• A leak is detected if a measurement value of the sample taken from the specified location equals or

exceeds the leak action level.

• Except as specified in §63.654(e) and (f), if a leak is detected, the leak must be repaired 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, unless the leak is from a non-HAP source. Repair to a leaking

heat exchanger may be delayed if the conditions in §63.654(f) are met.


The recordkeeping requirements specified in §63.655(i)(5) shall be met for each heat exchanger. Copies of

all records and reports are required to be maintained for a period of at least five years, except as specified

in §63.655(i)(5). The records shall be readily accessible within 24 hours and they may be maintained in the

forms specified in §63.655(i).


The cooling towers would not be subject to this regulation since they do not have uncontrolled emissions

that would exceed a major source threshold for any pollutant.

COOLING TOWER EMISSIONS

The 2019 emissions from the three cooling towers are summarized in the table below.

SOURCE ID

COOLING TOWER EMISSIONS

(TPY)

PM10 VOC

TOTAL EMISSIONS 5.91 44.31




STATEMENT OF BASIS

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MAINTENANCE VENT REQUIREMENTS

EMISSION


EMISSION


Maintenance Vents associated with:

No. 1 Crude Unit Area

No. 1 Reformer and HDS Area

No. 2 Reformed and HDS Area

Naphtha Splitter Area

Isomerization Area

Reformate Splitter Area

OHAPs/VOC

Prior to venting to atmosphere, process

liquids shall be removed from equipment

as much as practical and the equipment

depressured one of the following control

devices:

Use a flare meeting the requirements of

§63.670 to reduce OHAPs

OR

Use a control device that reduces OHAP

emissions by 98wt% or a concentration of

20 ppmv, dry basis, corrected to 3% O,

whichever is less stringent

OR

Route back to a fuel gas system

OR

Route back to a process until one of the

conditions specified in §63.643(c)(1)(i)-(v)

are met.

§63.643(c)

[MACT CC]

Shell determined that the vents at the refinery meet the definition of maintenance vents under miscellaneous

process vents. The following section will discuss applicability to state and federal regulations for maintenance

vents.

STATE REGULATIONS

Applicability:

ADEM Admin. Code R. 335-3-6-.08, “Petroleum Refinery Source” for Control of Organic Emissions

This regulation is applicable to process unit turnarounds a petroleum refining sources. ADEM Admin. Code R.

335-3-6-.08(4) requires that Shell develop a detailed procedure for minimizing VOC emissions during process

unit turnaround. The procedure at a minimum shall provide for depressurization venting of the process unit or

vessel to a vapor recovery system, flare, or firebox; and no emission of VOCs from a process unit or vessel until

its internal pressure is 136 kPa (19.6 psia) or less. Compliance with the requirements of this subpart shall be met

by compliance with MACT CC for the gasoline vapor recovery system, flare, and thermal oxidizer, per §63.640(q).

Applicability:


The maintenance vents shall be subject to this regulation. Semi-annual periodic monitoring reports (PMRs) are

required to be submitted to the Department to demonstrate whether there were deviations from the permit

requirements during the reporting period. An annual compliance certification (ACC) is required to be submitted

annually, within 60 days of the date of issuance of the MSOP, to the Department and to EPA.




STATEMENT OF BASIS

Page | 88

FEDERAL REGULATIONS


Applicability:

40 CFR 63 Subpart A, “General Provisions” [Subpart A]


Applicability:


Maintenance vents, as specified under the miscellaneous process vent section of MACT CC, are vents that are

used as a result of startup, shutdown, maintenance, or inspection of equipment where equipment is emptied,

depressurized, degassed, or placed into service. Shell was initially required to comply with this subpart by August

1, 2017; however, the facility was granted a one year compliance extension [§63.643(c), §63.6(i)]. By July 31,

2018, Shell was in compliance with all requirements for maintenance vents under MACT CC. Shell is not equipped

with any Group 1 miscellaneous process vents under this subpart.

EMISSION STANDARDS:

MACT CC requires that maintenance vents comply with the standards specified in §63.643 (c). Prior to venting

to the atmosphere, process liquids must be removed from equipment as much as practical and the equipment

depressurized to one of the following control devices: a flare meeting the requirements in §63.643(a)(1) and

§63.670; a control device meeting the requirement of §63.643(a)(2) to reduce emissions of organic HAPS by

98% weight-percent or a concentration of 20 part per million by volume, dry basis, corrected to 3% oxygen,

whichever is less stringent; route to a fuel gas system; or route back to the process until the conditions specified

in §63.643(c)(1)(i)-(v) are met [§63.643(c)(1)]. The requirements specified in §63.643(n) shall be met at all times.


Provided that a flare is used to comply with this subpart to reduce OHAP emissions, the procedures specified in

§63.670 shall be met [§63.643(a)(1)].

Provided that a control device specified under §63.643(a)(2) is used to reduce OHAP emissions, the procedures

specified in §63.645 shall be used to determine compliance by measuring either the OHAPs or total organic

compounds (TOCs) [§63.643(a)(2)].

The following methods and procedures shall be met for maintenance vents routed back to the process:

• For maintenance vents complying with lower explosive limits (LEL) or, if applicable, equipment pressure

limits, the LEL and equipment pressures must be determined according to manufacturer’s specifications

for calibration and maintenance procedures [§63.643(c)(2)].

• For maintenance vents complying with volatile organic compound (VOC) limits, equipment size may be

determined from equipment design specifications, and equipment content may be determined through

process knowledge [§63.643(c)(3)].


Flares used as control device shall comply with the monitoring requirements specified in §63.670 and §63.671.

Provided that maintenance vents are routed back to the process, the LEL or, if applicable, equipment pressures

must be determined using process instrumentation or portable measurement devices [§63.643(c)(2)] or the




STATEMENT OF BASIS

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mass VOC in the equipment serviced by the maintenance vent must be determined based on the equipment size

and contents after considering any contents drained or purged from the equipment [§63.643(c)(3)].


The records specified in §63.655(i)(12)(i) through (vi) for maintenance vent openings and when applicable

§63.643(d) and the reporting requirements specified in §63.655(g)(13)(i) through (iv) shall be met for each of

the maintenance vents. Semi-annual Periodic Reports are required to be submitted on a calendar basis to

comply with this subpart. Subsequent Periodic Reports shall be submitted within 60 days of the end of the six-

month reporting period.


specified in §63.655(i). The records shall be readily accessible within 24 hours and they may be maintained in

the forms specified in §63.655(i).


The miscellaneous process vents would not be subject to this regulation since they are subject to the

requirements of MACT CC. Per §64.2(b)(1)(i), since maintenance vents are subject to the applicable requirements

under MACT CC, they would be exempt from CAM requirements.

MAINTENANCE VENT EMISSIONS

Since emissions from maintenance vents are controlled by routing to a control device, routing back to the process

or routing to a fuel gas system, there would not be any emissions form maintenance vents.




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TRUCK GASOLINE LOADING RACK REQUIREMENTS

EMISSION


EMISSION

LIMIT REGULATIONS

Gasoline loading rack handling hazardous air

pollutants at a bulk gasoline terminal


rack, storage, vessels and process unit

equipment constructed prior to or during the

1981 expansions

TVOC

VOC

10 mg/L

gasoline loaded

Work Practice—Air Sticker

<1,781 tons per 12

consecutive months

§63.650

[MACT CC]

Rule 335-3-6-.06(3)

Rule 335-3-6-.20(4)

Rule 335-3-14-.05(.03)

[Non-Attainment Avoidance]

INDIVIDUAL SOURCES:

Truck gasoline loading rack with closed

vent system and carbon bed adsorption

unit

630-4001 VRU at Truck Loading Rack (North Unit)

630-1001 VRU at Truck Loading Rack (South Unit)

Truck loading emissions for gasoline products are controlled by two (2) vapor recovery units (VRUs). Originally,

the Gasoline Loading Rack was only equipped with a single Vapor Recovery Unit (VRU), now called the South

VRU. A second VRU, now called the North VRU, was installed in parallel with the original VRU in 2008. Both VRUs

are carbon absorption beds.

At the gasoline loading rack, trucks load gasoline for delivery to bulk gasoline terminals, or directly to gasoline

dispensing facilities. While trucks are loading, the truck vapors are absorbed by the carbon bed in the VRU. Once

the carbon bed is saturated, it is purged. The purged gas is captured and routed to the storage tanks. Normally,

only one VRU is in operation, while the other is being purged. The following section will discuss applicability to

state and/or federal regulations for this unit.

STATE REGULATIONS

Applicability:

ADEM Admin. Code r. 335-3-6-.06 “Bulk Gasoline Terminals”

Per Rule 335-3-6-.06(2), this regulation applies to bulk gasoline terminals and the ancillary equipment

necessary to load tank trucks or trailer compartments. Per Rule 335-3-6-.06(1)(a), a “bulk gasoline terminal”

means a gasoline storage facility which receives gasoline from its source primarily by pipelines, ships, and

barges, and delivers gasoline to bulk gasoline plants or to commercial or retail accounts primarily by tank trucks

and has an average throughput of more than 75,000 liters [20,000 gallons] in any calendar month.

The refinery meets this definition since its primary source is shipping gasoline to bulk gasoline plants or

commercial distribution facilities; therefore, this regulation applies. However, this same equipment is also

subject to MACT CC. Per §63.640(q), complying with the federal regulation will satisfy the state regulation,

with the exception of Rule 335-3-6-.06(3)(e), which requires all trucks loading gasoline to have a valid Air

Sticker per Rule 335-3-6-.20(4).




STATEMENT OF BASIS

Page | 92

Applicability:

ADEM Admin. Code R. 335-3-6-.20 “Leaks From Gasoline Tank Trucks and Vapor Collection Systems”

Per Rule 335-3-6-.20(4)(a), owners and operators of vapor collection systems subject to state regulations are

prohibited from loading, or allowing to load, any gasoline truck that is not displaying a current Air Sticker issued

by either the Department or the Jefferson County Department of Health. Air Stickers are issued to trucks that

have successfully passed an EPA Reference Method 27 vapor tightness test.

The Department has determined that each truck loading gasoline is to display a current Air Sticker as proof of

completing this test. Additionally, the facility is to have a system in place to ensure that each truck attempting

to load gasoline is checked for the state-required Air Sticker.

Applicability:


Areas”

As previously stated, at the time of the 1981 expansion, Mobile County was declared non-attainment for

ozone. To avoid non-attainment, a facility wide limit of 1,781 tons per 12 consecutive months of VOC emissions

was requested for the heaters, barge loading dock, truck loading rack, storage vessels and process unit

equipment which were constructed prior to and during the 1981 expansion. Records of the number of gallons

loaded through the truck gasoline loading rack during the month, the latest truck gasoline loading rack

emission factor determine during testing, number of gallons of non-gasoline truck loading during the month,

the non-gasoline loading rack emissions determined using AP-42 emission factors, and the truck loading rack

emissions shall be maintained.

Applicability:


The gasoline loading racks shall be subject to this regulation. Semi-annual periodic monitoring reports (PMRs)


permit requirements during the reporting period. An annual compliance certification (ACC) is required to be


FEDERAL REGULATIONS


Applicability:


The gasoline loading rack would be subject to the applicable requirements of this subpart. The applicable

requirements to this subpart will be specified in the applicable subparts under Part 60 by reference.




STATEMENT OF BASIS

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Applicability:

40 CFR Part 60 subpart XX, “Standards of Performance for Gasoline Terminals” [NSPS XX]

This regulation applies to gasoline loading racks and bulk gasoline terminal equipment leaks at bulk gasoline

terminals constructed or modified after December 17, 1980 [§60.500]. This facility would be subject to this

regulation since Temporary Operating Permits were issued on November 8, 1983 for the first gasoline loading

rack. A second unit was installed in 2009. However, per §63.640(r), a Group 1 gasoline loading rack (per

§63.641) with a throughput of greater than 20,000 gallons/day that is subject to both MACT CC and NSPS XX

is only required to comply with MACT CC. Therefore, the loading racks are only required to comply with MACT

CC. It should be noted that MACT CC references the standards of NSPS XX by way of 40 CFR 63 Subpart R

[NESHAP R] [§60.502, §63.422, §63.650].


Applicability:


The requirements of this subpart shall be met as specified in Table 6, of MACT CC and as specified §63.421 of

NESHAP R.

Applicability:

40 CFR 63 Subpart CC, “National Emission Standards for HAPs from Petroleum Refineries”[MACT CC]

This regulation contains requirements for gasoline loading racks and bulk gasoline terminal leaks from

equipment located at a petroleum refinery that is a major source of HAPs [§63.640(a), (c)(5), & (c)(7)]. Per

§63.640(h)(2), existing sources were to be in compliance with this regulation by August 18, 1998. The

requirements from this regulation apply to the gasoline loading rack. Per §63.650, compliance is to be

indicated by complying with §63.421, §63.422(a) through (c) and (e), §63.425(a) through (c) and (e) through

(i), §63.427(a) and (b), and §63.428(b), (c),(g)(1), (h)(1) through (3) and (k) of NESHAP R. NESHAP R references

the applicable requirements under NSPS XX that must be met to comply with this subpart.

EMISSION STANDARDS:

Except as specified in §60.502(b), (c), and (j) of NSPS XX, each loading rack that loads gasoline cargo tanks at

bulk gasoline terminals is required to be equipped with a vapor collection system that meets the requirements

specified in §60.502 [§63.422(a) of NESHAP R]. To comply with §60.502(e) of NSPS XX, the requirements

specified in §63.422(c) of NESHAP R shall be met for owners and operators of bulk gasoline terminals. As an

alternative to §60.502(h) and (i) of NSPS XX, the requirements specified in §63.422(e)(1) and (2) of NESHAP R

may be complied with.

Emissions to atmosphere from a vapor collection and processing system, due to the loading of gasoline cargo

tanks, shall not exceed 10 milligrams of total organic compounds per liter of gasoline loaded (mg/L) [§63.422(b)

of NESHAP R].


The facility is required to implement a system that ensures that no truck without a current vapor tightness test

loads gasoline [§63.422]. Per NESHAP R, each truck is required to have an annual vapor tightness test using

EPA Reference Method 27.




STATEMENT OF BASIS

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Prior to February 25, 1999, monitoring for the existing VRU consisted of an annual emissions test and a

continuous VOC concentration monitor. It was assumed that the reading on the monitor was a sufficient

indicator of compliance. However, as a result of the test conducted on November 10, 1998, the Department

determined that this was not sufficient. Therefore, on February 25, 1999, the Department sent Shell a letter

instructing them to follow the monitoring approach listed below. This approach was extended to the new VRU

as well. Periodic monitoring for VOCs and HAPs will consist of continuously monitoring the VOC concentration

from the operating VRU and checking the trucks for vapor tightness [§63.427(a)(1)].

Every two years, each VRU is to be tested for VOC emissions in order to demonstrate compliance with the 10

mg of total organic compound/L gasoline loaded limit. The test results are then correlated to a concentration

that indicates continuous compliance with the standard. Each continuous monitor is to be installed, operated,

and maintained appropriately.


To demonstrate compliance with the 10 mg of total organic compound/ L of gasoline loaded emission limit,

the test methods and procedures specified in §63.425(a) of NESHAP R shall be met. A monitored operating

parameter value for the vapor processing system shall be determined using the procedures specified in

§63.425(b) of NESHAP R. For performance tests conducted after the initial test, reasons for any change in the

operating parameter value since the previous test shall be documented.

An annual certification test shall be conducted utilizing the test methods and procedures specified in

§63.425(e) of NESHAP R or utilizing the railcar bubble leak test procedures specified in §63.425(i) of NESHAP

R. A leak detection test shall be performed utilizing the procedures specified in §63.425(f) of NESHAP R. A

nitrogen pressure decay field test shall be performed on cargo tanks with manifolded product lines using the

test methods and procedures specified in §63.425(g) of NESHAP R. A continuous performance pressure decay

test shall be conducted utilizing the test methods and procedures specified in §63.425(h) of NESHAP R.


The recordkeeping and reporting requirements specified in §63.428(b), (c), (g)(1), h(1) through (3), and (k) of

NESHAP R shall be maintained [§63.650(a) and §63.655(b)]. No additional requirements are necessary unless

a loading rack is included in an emission average.

During the performance test required to demonstrate that the 10 mg VOC/L gasoline loaded limit has not been

exceeded, the following parameters are to be recorded: 1) the captured vapor volume (L), 2) the approximate

vapor volume density (mg/L), 3) the total volume of petroleum products loaded (L), and 4) the total volume of

gasoline loaded (L). Additionally, during the test, a RATA will be conducted on each VRU concentration

monitor.

Instantaneous Compliance: The emissions during the test would then be calculated by multiplying the vapor

volume by its density and dividing by the volume of gasoline loaded.

Continuous Compliance Indicator: The continuous compliance indicator is calculated according to the following

steps:

1. Dividing the captured vapor volume (converted to standard cubic feet (scf)) by the total volume of

petroleum products loaded (converted to gallons (gal)) to get a ratio of scf/gal.

2. Averaging the current year’s ratio with the ratio from the three preceding years’ ratios to get an

average ratio (scf/gal).




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3. Calculating the new indicator (per VRU) as follows:

Indicator

(ppmv) =

0.1337 (Scf/Gal) 5,381 ppmv

Average Ratio (Scf/Gal)

where,

0.1337 = the standard conversion from Scf to gallons

5,381 ppmv= the maximum VRU concentration that was derived on July 29, 1999 using the following

equation.

10 mg C3H8 L Gasoline 106 Lb C3H8

Lb-mol C3H8 380 Scf C3H8 = 5,381 Scf C3H8

L Gasoline 0.03531 Scf Gasoline 106 453590 mg C3H8 44.09 lbs. C3H8 Lb-mol C3H8 106 Scf Gasoline

5,381 Scf C3H8 1 ppmv = 5,381 ppmv

106 Scf Gasoline 1 Scf C3H8/106 Scf Gasoline

Note:

1. The equation above assumes VOC = 100% propane

2. 0.03531= the standard conversion for Scf to L

3. Equation multiplied by 106/106 to cancel out part of the ppmv conversion

4. 1 ppmv = 1 scf C3H8/106 scf Gasoline

5. 380 lbmol/Scf is based on an average molar volume for propane

A new indicator must be established once every 2 years to demonstrate whether compliance with the emission limit is

met.

Applicability:

40 CFR 63, Subpart R, “NESHAP for Gasoline Distribution Facilities (Bulk Gasoline Terminals and Pipeline

Breakout Stations” [NESHAP R]

This subpart applies to bulk gasoline terminals and bulk gasoline plants that are major sources of HAPs

[§63.420(a)]. However, per §63.420(i), this regulation does not apply to a facility located within a contiguous

area or under common control with a petroleum refinery complying with 40 CFR 63 Subpart CC. This refinery

is only required to comply with the applicable requirements under this subpart as referenced in MACT CC.

Applicability:

40 CFR 63, Subpart EEEE, “National Emission Standards for Hazardous Air Pollutants: Organic Liquids

Distribution (Non-Gasoline)”

The truck loading rack will be used to load gasoline instead of organic liquids distribution (OLD) (non-gasoline);

therefore, this loading rack would not be required to comply with this subpart [§63.2330].




STATEMENT OF BASIS

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Applicability:

40 CFR 63 Subpart BBBBBB, “NESHAP for Gasoline Distribution Bulk Terminals, Bulk Plants, and Pipeline

Facilities”

This regulation contains requirements for storage vessels associated with gasoline service located at bulk

gasoline terminals, bulk gasoline plants, and pipeline facilities. However, per §63.11081(a)(1), facilities subject

to the control requirements of MACT CC are not subject to this subpart. Since this facility is subject to 40 CFR

63 Subpart CC, this regulation does not apply.


Since the truck gasoline loading racks have a VOC emission standard to comply with, the vapor recovery units

(VRU) are used as control devices to comply with the standards, and the potential uncontrolled VOC emissions

from the gasoline loading rack would be greater than 100 Ton/yr, CAM would be applicable to the gasoline

loading racks. However, since the truck loading rack is subject to the applicable requirements of MACT CC, it

is exempt from CAM requirements [§64.2(b)(1)(i)].

TRUCK GASOLINE LOADING RACK EMISSIONS

The controlled emissions from the overall truck loading system provided in the table below were obtained for

2019 Emission Fees. The facility VRU absorbers are used to control emissions from the truck loading racks.

TRUCK GASOLINE LOADING RACK CONTROLLED EMISSIONS

(TPY)

VOC HAPS

CONTROLLED 2.29 0.006




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MARINE BARGE LOADING SYSTEM REQUIREMENTS

EMISSION


EMISSION

LIMIT REGULATIONS

Barge Loading Dock Marine vessel loading

operations handling

hazardous air pollutants

OHAP

Maintain the tons per year

(TPY) of HAPs and loading

throughput below levels

that would trigger

applicability during marine

loading operations.

*Existing Source with:

<10 TPY of one HAP

<25 TPY of all HAPs

<10 M Barrels of Gasoline Per

year

<200 M Barrels of Crude Oil

per year

§63.651

[MACT CC]

§63.560(a)(2), (b)(2)*

§63.560(a)(3)

[NESHAP Y]


rack, storage vessels and process unit

equipment constructed prior to or during the

1981 expansions

VOC <1,781 tons per 12

consecutive months

Rule 335-3-14-.05(.03)

[Non-Attainment Avoidance]

The following sections will discuss the marine loading racks’ applicability to state and/or federal regulations:

STATE REGULATIONS

Applicability:

ADEM Admin. Code r. 335-3-14-.05(3), “Air Permits Authorizing Construction in or near Nonattainment Areas”

As previously stated, at the time of the 1981 expansion, Mobile County was declared non-attainment for ozone.

To avoid non-attainment, a facility wide limit of 1,781 tons per 12 consecutive months of VOC emissions was

requested for the heaters, barge loading dock, truck loading rack, storage, vessels and process unit equipment

which were constructed prior to and during the 1981 expansion. Records of the number of gallons of each

product loaded from the dock, AP-42 emission factors for each product loaded from the dock, and barge loading

dock emissions shall be maintained to comply with this regulation.

Applicability:


The marine barge loading shall be subject to this regulation. Semi-annual periodic monitoring reports (PMRs)


permit requirements during the reporting period. An annual compliance certification (ACC) is required to be





STATEMENT OF BASIS

Page | 98

FEDERAL REGULATIONS


Applicability:


The requirements of this subpart shall be met as specified in Table 6, of MACT CC and as specified in §63.560(c)

Table 1, NESHAP Y.

Applicability:


This regulation contains requirements for marine loading operations located at a petroleum refinery that is a

major source of HAPs [§63.640(a), & (c)(6)]. Per §63.640(h)(2), existing sources were to be in compliance with

this regulation by August 18, 1998. Per §63.651(a), marine loading terminals are required to meet the standards

in §63.560 through §63.568 from 40 CFR 63, Subpart Y [NESHAP Y], as discussed below. Per §63.651(b), terms

not defined in §63.641 are defined in §63.561, except that the term “affected source” from MACT CC applies.

Per §63.655(c), the only records required are those specified in NESHAP Y.

Applicability:

40 CFR 63 Subpart Y, “National Emissions Standards for Marine Tank Vessel Loading Operations” [NESHAP

Y]

The standards of this regulation apply to marine tank vessel loading operations that meet certain throughput

and emissions criteria. This regulation contains both Maximum Achievable Control Technology [MACT] and

Reasonably Achievable Control Technology [RACT] standards.

Per EPA Guidance, loading operations of HAPs emissions are to be examined independently of the rest of the

facility’s operations. Thus, if the marine loading operations emit less than 10 Ton/year of a single HAP and/or

less than 25 Ton/year of all HAPs, then the loading terminal would be considered an area source of HAPs. Based

on the emission section for the barge loading dock, the loading HAPs emissions are less than these thresholds.

Additionally, the marine terminal qualifies as an existing source. Existing sources must also meet the submerged

standard of 46 CFR 153.288 [§63.560(a)(4)]. Per §63.560(a)(2), existing area sources are not subject to the

NESHAP Requirements in §63.562(b) and (d).

Per §63.560(b)(2), since the marine terminal loads less than 10 million barrels of gasoline, on a 24-month

average, and less than 200 million barrels of crude oil, averaged on a 24-month basis, it is exempt from the

RACT requirements in §63.562(c) and (d). Per §63.560(a)(3), the marine terminal is subject to the recordkeeping

requirements found under §63.567(j)(4).


CAM would not apply to the marine loading rack, since it is subject to the requirements under MACT CC. The

exemption specified under §64.2(b)(1)(i) shall apply.




STATEMENT OF BASIS

Page | 99

MARINE LOADING EMISSIONS

Marine loading or refinery dock product loading emissions are uncontrolled emissions. Emissions from the

marine loading system provided in the table below are from 2019 Emissions Fees.

MARINE LOADING EMISSIONS

(TPY)

VOC HAPS

59.7 1.59




STATEMENT OF BASIS

Page | 100





STATEMENT OF BASIS

Page | 101

CATALYTIC REFORMING UNIT PROCESS VENT REQUIREMENTS

The following section will address the CRU process vents applicability requirement for state and/or federal

regulations.

STATE REGULATIONS

Applicability:


CRU vents shall be subject to this regulation. Semi-annual periodic monitoring reports (PMRs) are required to

be submitted to the Department to demonstrate whether there were deviations from the permit requirements

during the reporting period. An annual compliance certification (ACC) is required to be submitted annually,

within 60 days of the date of issuance of the MSOP, to the Department and to EPA.

FEDERAL REGULATIONS


Applicability:


The requirements of this subpart shall be met as specified in Table 44, of MACT UUU [§63.1577].

FEDERAL REGULATIONS


Applicability:

40 CFR 63 Subpart UUU, “National Emission Standards for HAPS From Petroleum Refineries: Catalytic

Cracking Units, Catalytic Reforming Units, And Sulfur Recovery Units” [MACT UUU]

Process vents or groups of process vents on catalytic reforming units that are located at a petroleum refinery

that is a major source of HAPs and that are associated with regeneration of the catalyst used in the unit are

subject to the requirements of this subpart [§63.1561 and §63.1562(b)(2)]. The catalytic reforming unit (CRU)

EMISSION


EMISSION


CATALTYIC REFORMING UNITS (CRU)

[Semi-Regenerative CRU]

Train No. 1 and No. 2 CRU Process Vents

During initial catalyst de-pressuring and

purging operations

Organic HAP

Emissions

(TOC)

Burn in flare meeting the

requirements of §63.670 and

§60.671 of MACT CCC

§63.1566(a)(1)(i)

Table 15, No. 1, MACT

UUU

During coke burn-off and rejuvenation Inorganic HAP

emissions

(HCl)

Reduce to a concentration of 30

ppmv or less(dry) @ 3% O2

§63.1567(a)(1)(ii)

Table 22, No. 1, MACT

UUU




STATEMENT OF BASIS

Page | 102

was issued operating permit No. 503-4003-0007 on August 1, 1979; therefore, it would be considered an

existing source under this subpart.

This regulation targets organic HAPs (OHAP) produced during initial catalyst de-pressuring and purging

operation and HCL emissions during coke burn-off and catalyst regeneration.

EMISSION STANDARDS:

For control of organic HAP (OHAP) emissions from catalytic reforming units process vents, the emission

standards found in §63.1566 shall be complied with during initial catalyst de-pressuring and purging operations

and when the reactor pressure is greater than 5 psig. The facility has elected to comply with this subpart by

routing OHAP emissions to the facility flare for combustion. The flare must meet the requirements specified

in §63.670 and §63.671 of MACT CC [63.1566(a)(1)(i)].

For control of inorganic HAP emissions from catalytic reforming units process vents, the emission standards

found in §63.1567 shall be complied with during coke burn-off and catalyst rejuvenation. The facility has

elected to comply with the hydrogen chloride (HCl) concentration limitation of less than 30 ppmv (dry basis)

corrected to 3% O2.


For control of OHAP emissions from catalytic reforming units process vents, the testing requirements specified

in §63.1566(b)(2) shall be complied with.

For control of inorganic HAP emissions from catalytic reforming units process vents, the testing requirements

specified in §63.1567(b)(2) shall be complied with. The following test methods and procedures shall be used

during the initial and subsequent performance tests:

• Method 1 OR Method 1A of 40 CFR 60 Appendix A shall be used to determine the sampling point

• Method 2 OR Method 2A OR Method 2C OR Method 2D OR Method 2F OR Method 2G of 40 CFR 60

Appendix A shall be used to determine the exhaust gas velocity and volumetric flowrate

• Method 3 OR Method 3A OR Method 3B shall be used to determine the exhaust gas molecular weight

• Method 4 shall be used to determine the exhaust gas moisture content

• Method 26A of 40 CFR 60 Appendix A shall be used if an internal scrubbing system is used to determine

the HCl concentration in the exhaust gas

The operating HCl limitation shall be established using data from the continuous parameter monitoring system

(CPMS).

The performance test must comply with the requirements specified in §63.1571. Subsequent testing must be

conducted once every five years or during the first regeneration event following the fifth year anniversary of

the previous performance test on the regeneration vent.


For control of OHAP emissions from catalytic reforming units process vents, the monitoring requirements

specified in §63.1566(b)(1) shall be complied with. The flare has to be equipped with a thermocouple,

ultraviolet beam sensor, or infrared sensor to continuously detect the presence of a pilot flame. Visible

emissions from the flare are monitored as specified in the flare section.

For control of organic HAP missions from catalytic reforming units process vents, the monitoring requirements

specified in §63.1567(b)(1) shall be complied with. If the catalytic reforming unit is equipped with an internal

scrubbing system or no control device, a colormetric tube sampling system must be used to measure the HCl




STATEMENT OF BASIS

Page | 103

concentration in the catalyst regenerator exhaust gas during coke burn-off and catalyst rejuvenation. The

colormetric tube sampling system must meet the requirements specified in §63.1567(b)(1) and Table No. 41

of 40 CFR 63 Subpart UUU.

Each continuous monitoring system shall be installed, operated, and maintained according to the

requirements specified in §63.1572. Data must be monitored and collected as specified in §63.1572(d).


For control of OHAP emissions from catalytic reforming units process vents, the recordkeeping and reporting

requirements specified in §63.1566(c)(1) shall be complied with. A record of each 1-hour period showing

whether the monitor was continuously operating and a record of each 1-hour period showing whether the

pilot light was continuously lit shall be maintained for the flare.

For control of inorganic HAP emissions from catalytic reforming units process vents, the recordkeeping and

reporting requirements specified in §63.1567(c)(1) shall be complied with. The following records shall be

maintained:

• Records of the HCl concentration shall be recorded at least 4 times during a regeneration cycle (equally

spaced in time) or every 4 hours, whichever is more frequent, using a colormetric tube sampling

system

• Records of the calculated daily average HCl concentration as an arithmetic average of all samples

collected in each 24-hour period from the start of the coke burn-off cycle or for the entire duration of

the coke burn-off cycle if the coke burn-off cycle is less than 24 hours

• Record of the daily average HCl concentration below the applicable operating limit

Records of the information specified in §63.1576 shall also be maintained. The records shall be maintained as

specified in §63.1567(g) and (h).

Monitoring reports shall be submitted as specified in §63.1575. A periodic monitoring report (PMR) shall also

be submitted semi-annually and shall include all other deviations from the permit requirements.


The catalytic reforming units are subject to an emission limitation, they use a control device to comply with

the emission standard; however, they do not have uncontrolled emissions that would exceed a major source

threshold. Therefore, the CRU is not subject to the requirements of this subpart.

CATALYTIC REFORMING UNIT EMISSIONS

The emissions from a CRU would be routed to the flare for combustion; therefore, there would not be any

emissions attributed to the CRU.




STATEMENT OF BASIS

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STATEMENT OF BASIS

Page | 105

BYPASS LINE REQUIREMENTS

EMISSION


EMISSION


BYPASS LINES ASSOCIATED WITH THE FOLLOWING UNITS

Sulfur Recovery System

No. 1 Catalytic Reformed Unit

No. 2 Catalytic Reformed Unit

HAPS WORK PRACTICE

STANDARDS

Use a Manual Lock System

OR

Comply with other options

allowed under this subpart

§63.1569(a)(1)(ii)

[MACT UUU]

§63.1569(a)(1) or (2)

Table 36., MACT UUU

Bypass lines vent systems serving a new, existing, or reconstructed catalytic reforming unit (CRU) or sulfur

recovery unit (SRU) will be discussed in the following sections. The SRU incinerator bypass will only be used in

the event of an incinerator trip to divert gas while re-lightning the incinerator burner. Applicability to state and/or

federal regulations will be addressed.

STATE REGULATIONS

Applicability:


The bypass lines associated with an SRU and CRU shall be subject to this regulation. Semi-annual periodic

monitoring reports (PMRs) are required to be submitted to the Department to demonstrate whether there

were deviations from the permit requirements during the reporting period. An annual compliance certification

(ACC) is required to be submitted annually, within 60 days of the date of issuance of the MSOP, to the

Department and to EPA.

FEDERAL REGULATIONS


Applicability:


The requirements of this subpart shall be met as specified in Table 44, of MACT UUU [§63.1577].

Applicability:

40 CFR 63 Subpart UUU, “National Emission Standards For HAPS From Petroleum Refineries: Catalytic

Cracking Units, Catalytic Reforming Units, And Sulfur Recovery Units” [MACT UUU]

Each bypass line serving a catalytic reforming unit and sulfur recovery unit that could divert an affected vent

stream away from a control device that is located at a petroleum refinery that is a major source of HAPs is

subject to the requirements of this subpart [§63.1561 and §63.1562(b)(4)]. The catalytic reforming unit and

the sulfur recovery unit at the refinery will be subject to this subpart.




STATEMENT OF BASIS

Page | 106

EMISSION STANDARDS:

The work practice standards specified in §63.1569(a) shall be met for bypass lines. The facility has elected to

either use a manual lock system or seal the bypass line to comply with this subpart. This subpart does not

apply to equipment associated with bypass lines such as low leg drains, high point bleed, analyzer vents, open-

ended valves or lines, or pressure relief valves needed for safety reasons and equipment subject to the

equipment leak standards [§63.1562(f)(4)].


No compliance testing is required if a manual lock system is installed on the bypass line or if the bypass line is

sealed [§63.1569(b)].


Provided that a manual lock system is used to comply with this subpart, at least once each month a visual

inspection of the seal or closure mechanism on the car-seal or the lock-and-key device must be conducted as

specified in Table 39 of MACT UUU.


The following recordkeeping and reporting requirements shall be met as specified in §63.1576. Records, as

specified below, shall be maintained for a period of five years following each occurrence or measurements.

• Provided that a manual lock system is installed, a record of whether the bypass line valve is

maintained in the closed position and a record of whether flow is present in the line shall be

maintained as specified in Table No. 39 of MACT UUU.

• A copy of all notifications and reports submitted per MACT UUU, including for start-ups,

shutdowns, and malfunctions shall be maintained.

• The applicable records specified in §63.1576(a)(2)(i) through (iv) shall be maintained.

• A current copy of the operations, maintenance, and monitoring plan shall be maintained

onsite and available for inspection.

• Records to document conformance with the procedures in the operation, maintenance, and

monitoring plan shall be maintained.

A Compliance Report is required to be submitted semi-annually according to requirements in §63.1575. The

report shall include the applicable information specified in §63.1575(c)(1)-(4), §63.1575(d) or (e) for each

deviation from an emission limitation, and the in §63.1575(f).


CAM would not apply to bypass lines associated with the CRU and SRU vents. Since bypass lines are subject to

standards under MACT UUU, the exemption found in §64.2(b)(1)(i) would be applicable.

BYPASS LINE EMISSIONS

Provided that bypass lines remain in the closed positions as required under MACT UUU, there would not be any

emissions from bypass lines.




STATEMENT OF BASIS

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FENCE LINE MONITORING FOR BENZENE EMISSIONS

EMISSION


EMISSION


Fenceline monitoring along the facility

property boundary

Benzene (BZ)

Annual average benzene

concentration (Δc) below the

determined action level

§63.658

[MACT CC]

This section will summarize potential regulatory applicability requirements for Fenceline Monitoring:

STATE REGULATIONS

Fenceline benzene monitors are located at a facility that is a major source of criteria pollutant, a major source of

HAPs, and a major source of GHG. To comply with this regulation, a periodic monitoring report (PMR) is required

to be submitted on a semi-annual calendar basis to report deviations from permit requirement, and annual

emissions submitted. An annual compliance certification (ACC) is required to be submitted annually with 60 days

of the issuance of the permit.

FEDERAL REGULATIONS

NATIONAL EMISSION STANDARDS OF HAZARDOUS AIR POLLUTANTS [NESHAP]

Applicability:



Applicability:

40 CFR Part 63 Subpart CC “National Emission Standard for Hazardous Air Pollutants (HAPs) from Petroleum

Refineries” [Refinery MACT 1/MACT CC]

Compliance with the requirements of this subpart for benzene fence line monitoring was required by January

30, 2018. Fenceline monitoring is required to be conducted along the facility property boundary.

EMISSION STANDARDS

The applicable requirements for fenceline monitoring specified in §63.658 of MACT CC shall be met at all

times as specified in §63.642(k)(1) or §63.642(l)(2).

• The action level for the benzene concentration is 9 micrograms per cubic meter (µg/m3) on an annual

average basis [§63.658(f)(3)].

o If the annual average benzene concentration (Δc) is less than or equal to 9 µg/m3, the

concentration is below the action level.

o If the annual average Δc is greater than 9 µg/m3, the concentration is above the action level, and

a root cause analysis and corrective actions must be conducted as specified in §63.658(g).

Applicability:

ADEM Admin. Code R. 335-3-16, “Major Source Operating Permits”




STATEMENT OF BASIS

Page | 108

• A root cause analysis shall be performed to determine the cause of an exceedance of the action level

for the Δc and to determine the appropriate corrective action.

• A corrective action plan, when required, shall be developed as specified in §63.658(h) of MACT CC.

• A site-specific monitoring plan to account for offsite upwind sources or onsite sources excluded under

§63.640(g) of MACT CC may be requested from the Department as specified in §63.658(i)(1) through

(4) of MACT CC.

• At all times any affected source, including associated air pollution control equipment and monitoring

equipment, must be operated and maintained, in a manner consistent with safety and good air

pollution control practices for minimizing emissions as specified in §63.642(n).

COMPLIANCE AND PERFORMANCE TESTING

Collected samples are required to be analyzed according to the methods and procedures specified in

§63.658(a). An alternative test method may be requested as long as the conditions specified in §63.658(k)

are met. Passive monitor locations shall be determined in accordance with the methods and procedures

specified in §63.658(c), and meteorological data shall be collected and analyzed in accordance with the

methods and procedures specified in §63.658(d).

EMISSION MONITORING

Benzene is the target analyte. The sampling period and sampling frequency shall comply with the

requirements specified in §63.658(e), (f), and (g). A corrective action plan is required to be developed if the

conditions specified in §63.658(h) are met.

RECORDKEEPING AND REPORTING

The records specified in §63.655(i)(8)(i) though (x) and the reporting requirements specified in

§63.655(h)(8)(i) through (viii) shall be maintained for fenceline monitoring. Quarterly reports are required

to be electronically submitted to EPA’s Compliance and Emission Data Reporting Interface (CEDRI) by

accessing it through EPA’s Central Data Exchange (CDX) (htps://cdx.epa.gov/). The first quarterly report was

submitted to EPA on May 14, 2019. MACT CC did not require a copy of the report to be submitted to the

Department; however, beginning in 2020, a summary of the report submitted to EPA was requested by the

Department. Subsequent quarterly reports are required to be submitted electronically on a calendar basis

with a summary being submitted to the Department as well. Reports are required to be submitted within 45

days of the end of the reporting period.


specified in §63.655(i). The records shall be readily accessible within 24 hours and they may be maintained

in the forms specified in §63.655(i).


CAM would not apply because a control device is not being used to comply with emission standards, and

benzene emissions are not expected to exceed a major source threshold.

FENCE LINE MONITORING EMISSIONS

Any emissions from the fenceline monitoring would be fugitive emissions. Since these emissions are not

captured, any emissions from sources near sampling locations throughout the refinery should be accounted

for under equipment leaks emissions covered under NSPS GGG.




STATEMENT OF BASIS

Page | 109

ENVIRONMENTAL JUSTICE

The Department completed EJSCREEN mapping at 1, 3, and 5-mile radius around the refinery. The results of the

mapping is summarized in Appendix B.

RECOMMENDATIONS

Based on the information provided in the Shell Chemical L.P. Mobile Site Major Source Operating Permit renewal

application for the Saraland Refinery, I recommend that, pending the 30-day public comment period and 45-day

EPA review period, Major Source Operating Permit 503-4003 be issued to Shell Chemical. If the Title V conditions

are adhered to by Shell Chemical, the facility should be in compliance with all applicable State and Federal Air

Pollution regulations and the terms of the Consent Decree No. 10-cv-01042.

_____________________________ August 5, 2021

Harlotte M. Bolden-Wright Draft Date

Industrial Minerals Section

Energy Branch

Air Division




STATEMENT OF BASIS

Page | 110





STATEMENT OF BASIS

Page | 111

APPENDIX A: DRAFT PROVISOS




STATEMENT OF BASIS

Page | 112





STATEMENT OF BASIS

Page | 113

APPENDIX B: EJSCREEN MAPPING REPORTS




STATEMENT OF BASIS

Page | 114

1-MILE RADIUS




STATEMENT OF BASIS

Page | 115




STATEMENT OF BASIS

Page | 116




STATEMENT OF BASIS

Page | 117

3-MILE RADIUS




STATEMENT OF BASIS

Page | 118




STATEMENT OF BASIS

Page | 119




STATEMENT OF BASIS

Page | 120

5-MILE RADIUS




STATEMENT OF BASIS

Page | 121




STATEMENT OF BASIS

Page | 122




STATEMENT OF BASIS

Page | 123

APPENDIX C: CONSENT DECREE

shell c l. p., m saraland petroleum refining facility m …

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